Patent Publication Number: US-11396779-B2

Title: Hybrid drill bit gauge configuration

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a U.S. national stage patent application of International Patent Application No. PCT/US2018/040379, filed on Jun. 29, 2018, the benefit of which is claimed and the disclosure of which is incorporated herein by reference in its entirety. 
     BACKGROUND 
     Various types of downhole drilling tools including, but not limited to, rotary drill bits, reamers, and core bits, have been used to form wellbores in associated geologic formations, e.g., for forming oil and gas wells. Examples of rotary drill bits that may be used in downhole drilling include, but are not limited to, fixed cutter drill bits, drag bits, polycrystalline diamond compact (PDC) drill bits, and matrix drill bits. 
     Drill bits generally include a plurality of cutting elements thereon, which mechanically scrape the geologic formations surrounding wellbores, causing pieces of rock to separate from the geologic formations. The cutting elements may be provided on leading faces of the drill bit that engage the bottom surface of the wellbore to extend the borehole along a trajectory. Drill bits often also include gauge pads on circumferential surfaces of the drill bit that engage a circumferential sidewall of the borehole. Gauge pads may include a plurality of gauge elements that have some, little or no cutting capability, but enhance drill bit stability during both linear and non-linear drilling. By enhancing the drill bit stability, any inclination for unintended side cutting by the drill bit is reduced, resulting in fewer ledges formed in the circumferential sidewall of the wellbore, which could otherwise frustrate the installation of casing or other equipment in the wellbore. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The following figures are included to illustrate certain aspects of the present disclosure, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, without departing from the scope of this disclosure. 
         FIG. 1  is an elevation view of a drilling system including a rotary drill bit for drilling a wellbore in accordance with some embodiments of the present disclosure. 
         FIG. 2  is a perspective view of the drill bit of  FIG. 1  illustrating a plurality of cutting elements and gauge pads disposed on a bit body of the rotary drill bit. 
         FIG. 3A  is a schematic view of the drill bit of  FIG. 2  in operation in the wellbore illustrating a plurality of moveable gauge elements extending through a circumferential engagement surface of a gauge pad having a relieved gauge arrangement. 
         FIG. 3B  is a schematic view of a drill bit in operation in the wellbore illustrating a plurality of moveable gauge elements extending through a circumferential engagement surface of a gauge pad. 
         FIG. 4  is a graphical view of an engagement force of the various gauge elements according to an axial position of the gauge elements on the bit body. 
         FIG. 5A  is a perspective view of one example of one of the gauge elements coupled to a cylinder with a retaining ring to define a gauge pad subassembly. 
         FIG. 5B  is a cross-sectional perspective view of the gauge pad subassembly of  FIG. 5A  illustrating the gauge element biased to an extended configuration by a biasing mechanism constructed as stack of Belville springs. 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure is directed to a rotary drill bit including movable gauge elements extending through a circumferential engagement surface of a gauge pad. The gauge elements are biased to protrude radially from the circumferential engagement surface such that radial faces of the engagement elements define the “full gage” or radially outermost surfaces of gauge section of the drill bit. The radial faces of the gauge elements engage the surrounding formation to provide stability to the drill bit, e.g., while drilling a straight hole. When entering a sliding or steering drill phase, a steering force is applied to the drill bit to induce a change in direction. The steering force causes the gauge elements to retract into the bit against the formation. At least one of the radial faces may become flush with the circumferential engagement surface of the gauge pad such that the circumferential engagement surface engages the formation, or the movable gauge elements may not retract fully such that the circumferential engagement surface remains spaced from a sidewall of the borehole by the gauge elements. Thus, the circumferential surface of the gauge pad may engage the formation on at least one side of the drill bit in operation. The gauge elements may be arranged to provide uniform engagement forces, or may be arranged to provide a decreasing engagement force according to an axial position on the drill bit. The gauge elements may be fixed directly to a bit body, or may be housed in a pre-assembled, spring-loaded cylinder, which may be affixed to the bit body. 
       FIG. 1  is an elevation view of a drilling system  100  including a rotary drill bit  101  for drilling wellbores  114   a ,  114   b  (generally or collectively wellbore  114 ) in accordance with some embodiments of the present disclosure. Drilling system  100  may include a well site at a surface location  106 . Various types of drilling equipment such as a rotary table, drilling fluid pumps and drilling fluid tanks (not expressly shown) may be located at the surface location  106 . For example, a drilling rig  102  may be provided with various features associated with terrestrial drilling operations with a “land drilling rig.” However, teachings of the present disclosure may be satisfactorily applied in offshore drilling operations, e.g., operations with drilling equipment located on offshore platforms, drill ships, semi-submersibles and drilling barges (not expressly shown). 
     Drilling system  100  may also include a drill string  103  associated with the drill bit  101  for forming a wide variety of wellbores  114  such as generally vertical wellbore  114   a , generally horizontal wellbore  114   b , and/or wellbores having any other orientation. Various directional drilling techniques and associated components of a bottom hole assembly (BHA)  120  coupled within the drill string  103  may be used to form deviated wellbores such as the horizontal wellbore  114   b . For example, lateral forces may be applied to BHA  120  proximate kickoff location  113  to steer the drill bit  101  and form a curved portion  115   a  and a generally straight portion  115   b  of the generally horizontal wellbore  114   b . The term “directional drilling” may be used to describe drilling a wellbore or portions of a wellbore that extend at a desired angle or angles relative to vertical. The desired angles may be greater than normal variations associated with vertical wellbores. Directional drilling may also be described as drilling any wellbore deviated from vertical. 
     BHA  120  may include a wide variety of components configured to form wellbore  114 . For example, the BHA  120  may include the drill bit  101 , and components  122   a ,  122   b  and  122   c  (generally or collectively components  122 ) coupled in the drill string  103  above the drill bit  101 . The components  122  of the BHA  120  may include, but are not limited to, drill collars, rotary steering tools, directional drilling tools, downhole drilling motors, reamers, hole enlargers, stabilizers etc. The number and types of components  122  included in BHA  120  may depend on anticipated downhole drilling conditions and the type of wellbore  114  that will be formed by drill string  103  and rotary drill bit  101 . BHA  120  may also include various types of well logging tools (not expressly shown) and other downhole tools associated with directional drilling of a wellbore. Examples of logging tools and/or directional drilling tools may include, but are not limited to, acoustic, neutron, gamma ray, density, photoelectric, nuclear magnetic resonance, rotary steering tools and/or any other commercially available well tool. Further, BHA  120  may also include a rotary drive (not expressly shown) connected to components  122  that rotates at least part of drill string  103 , e.g., parts of the drill string including the drill bit  101  and the components  122 . 
     Wellbore  114  may be defined in part by casing string  110  that may extend from surface location  106  to a selected downhole location. Portions of wellbore  114  illustrated in  FIG. 1  that do not include casing string  110  may be described as “open hole.” Various types of drilling fluid, or “mud,” may be pumped from the surface location  106  through drill string  103 . The drilling fluids may be expelled from the drill string  103  through nozzles (depicted as nozzles  156  in  FIG. 2 ) passing through rotary drill bit  101 . The drilling fluid may be circulated back to surface location  106  through an annulus  108 ,  116  defined between an outside diameter  112  of the drill string  103  and a surrounding structure. For example, an open hole annulus  116  is defined between the drill string  103  and an inside diameter  118  of the wellbore  114   a . The inside diameter  118  may be referred to as the “sidewall” or a circumferential wall of the wellbore  114   a . A cased annulus  108  may also be defined between the drill string  103  and the casing string  110 . 
     The drill bit  101 , discussed in further detail below, may include one or more blades  126 , with respective junk slots or fluid flow paths  140  ( FIG. 2 ) disposed there between. The blades  126  may project or extend outwardly from exterior portions of a rotary bit body  124 . Drill bit  101  may rotate with respect to bit rotational axis  104  in a direction defined by directional arrow  105 . One or more cutting elements  128  may be disposed outwardly from exterior portions of each blade  126 , and at least some of the blades  126  may also include gauge pads  111  defined on circumferential surfaces thereof. The drill bit  101  may be designed and formed in accordance with teachings of the present disclosure and may have many different designs, configurations, and/or dimensions according to the particular application of drill bit  101 . 
       FIG. 2  is a perspective view of the drill bit  101  of  FIG. 1  illustrating a plurality of fixed cutting elements  128  and gauge pads  111  disposed on the bit body  124 . Although drill bit  101  is illustrated generally as a fixed cutter drill bit  101 , in other embodiments, drill bit  101  may be any of various other types of rotary drill bits, including, roller cone drill bits, coring bits, polycrystalline diamond compact (PDC) drill bits, drag bits, matrix drill bits, and/or steel body drill bits operable to form a wellbore (e.g., wellbore  114  as illustrated in  FIG. 1 ) extending through one or more downhole formations. 
     Drill bit  101  defines a leading end  151  that generally arranged for physical contact with the geologic formation and a trailing end  150  for coupling the drill bit  101  to a drill string  130  ( FIG. 1 ). At the leading end  151 , drill bit  101  may include one or more blades  126  (e.g., blades  126   a - 126   g ) that define exterior portions of the bit body  124 . Blades  126  define junk slots  140  therebetween, and may be any suitable type of projections extending radially outwardly from a rotational axis  104 . Blades  126  may have a wide variety of configurations including, but not limited to, substantially arched, generally helical, spiraling, tapered, converging, diverging, symmetrical, and/or asymmetrical. Each of the blades  126  may have respective leading surfaces  130  in the direction of rotation of the drill bit  101  and trailing surfaces  132  located opposite leading surfaces  130 . In some embodiments, blades  126  may be positioned along bit body  124  such that they have a spiral configuration relative to bit rotational axis  104 . In other embodiments, blades  126  may be positioned along bit body  124  in a generally parallel configuration with respect to each other and bit rotational axis  104 . 
     Cutting elements  128  are generally arranged along the leading surfaces  130  of the blades  126  and may include various types of cutters, compacts, buttons, inserts, and gauge cutters satisfactory for use with a wide variety of drill bits  101 . Cutting elements  128  may include respective substrates  164  with a layer of hard cutting material (e.g., cutting table  162 ) disposed on one end of each respective substrate  164 . The substrates  164  of the cutting elements  128  may be constructed materials such as tungsten carbide, and the hard layer  162  of cutting elements  128  be constructed of materials including polycrystalline diamond (PCD) materials. The hard layer  162  may provide a cutting surface that engages adjacent portions of a downhole formation to form wellbore  114  ( FIG. 1 ). Blades  126  may include recesses or bit pockets  166  that may be configured to receive cutting elements  128 . For example, bit pockets  166  may be concave cutouts on blades  126 . 
     Blades  126  include the gauge pads  111  disposed on radially outer circumferential surfaces  170  of the blades  126 . The gauge pads  111  may include abrasion resistant materials such as tungsten carbide and PCD materials, and may be arranged to contact a geologic formation tangentially such that the gauge pads perform little or no cutting of the geologic formation. In some embodiments, portions of the gauge pads  111  may be angled scrape against a geologic formation to perform a significant cutting function. The gauge pads  111  may extend from the bit rotational axis  104  a radial distance slightly greater or slightly smaller than a radial distance cut by cutting elements  128 . The gauge pads  111  may define radially outermost surfaces of the drill bit  101  along an axial gauge pad region  172  wherein the gauge pads  111  are located. 
     The gauge pads  111  include a plurality of movable gauge elements  177  spaced from one another along a direction of the bit rotation axis  104 . The gauge elements  177  are biased to extend a greater radial distance from the bit rotational axis  104  than a circumferential engagement surface  178  of the gauge pads  111 , and may be retractable into the bit body  124  to be flush with the circumferential engagement surface  178 . Thus the gauge elements  177  may define radially outermost surfaces of the drill bit  101  along the axial gauge pad region  172  when the gauge elements  177  are extended, and the gauge elements  177  together with the engagement surfaces  178  may define the radially outermost surfaces when the gauge elements are retracted. In some embodiments, the engagement surfaces  178  include an abrasion resistant plate material distinct from the bit body  124 , and in other embodiments, the engagement surfaces  178  may be integrally formed with the bit body  124 . 
     The trailing end  150  of drill bit  101  may include shank  152  having a drill string connector such as drill pipe threads  155  formed thereon. Threads  155  may releasably engage with corresponding threads (not shown) on BHA  120  ( FIG. 1 ) such that the drill bit  101  may be rotated relative to bit rotational axis  104 . Drilling fluids may be communicated from the BHA  120  to the drill bit  101 , and the drilling fluids may be expelled through one or more nozzles  156 . 
       FIG. 3A  is a schematic view of the drill bit  101  in operation in the wellbore  114 . The moveable gauge elements  177  extend through the circumferential engagement surface  178  to define a relieved gauge arrangement. The movable gauge elements  177  are illustrated in an extended configuration such that radial faces  180  of the movable gauge elements  177  define a radially-outermost surface of the drill bit  101  within the axial gauge pad region  172 . As illustrated, when each of the movable gauge elements is in the extended configuration, the radial faces  180  are aligned along an axis  181  generally parallel to the rotational bit axis  104 . In other embodiments (not shown) the radial faces  180  may each be arranged to extend a different distance from the rotational bit axis  104 . A radial relief distance  182  is defined between the axis  181  of the radial faces  180  and an outermost cutting element  128  or the sidewall  118  of the wellbore  114 . In some embodiments, the radial relief distance  182  may be between about 1 mm and about 3 mm. 
     Each of the movable gauge elements  177  is biased radially outward beyond the engagement surfaces  178  of the gauge pad  111  by an individual biasing mechanism  184 . In some embodiments, the individual biasing mechanisms  184  may be a helical compression springs, wave springs, stacks of Bellville washers (see  FIG. 5B ), resilient elastomeric members or other recognized biasing mechanisms. The biasing mechanisms  184  each exert an individual biasing force to the respective gauge element  177 , with which the gauge element engages the formation in operation. In some embodiments, the biasing mechanisms  184  provide the same engagement force to the respective gauge elements  177 , and in some embodiments, the biasing elements  184  provide a variable or decreasing engagement force to the respective gauge elements  177  along an axial direction of the bit body  124 . The variation in engagement force may be provided by selection and/or arrangement of the biasing mechanisms  184 . For example, a spring rate of each if the biasing mechanisms  184  may be selected to decrease along the axial direction of the drill bit. 
     The decreasing engagement forces, may permit the gauge elements  177  to effectively provide stability to the drill bit  101  without unduly counteracting a steering force applied to the drill bit  101  from a drill string  103  ( FIG. 1 ). For example, if a steering torque  186  is applied to the drill bit, engagement forces of the gauge elements  177  most distant from the steering torque  186  may be greater than the engagement forces applied by the gauge elements  177  less distant from the steering torque  186 . Thus, gauge elements  177  the sidewall  118  on a side opposite the turning direction will more easily permit the drill bit  101  to pivot and change direction. 
       FIG. 3B  is a schematic view of a drill bit  201  in operation in the wellbore  114 . The moveable gauge elements  177  extend through a stepped circumferential engagement surface  208  to define a stepped gauge arrangement. In their extended configuration, the radial faces  180  of the movable gauge elements  177  are aligned along an axis  218 , which is generally parallel to a rotational bit axis  204  and which extends along a first step  220  of the engagement surface  208 . The first step  220  is disposed a first radial distance R 1  from the rotational bit axis  204 , which is greater than a second radial distance at which a second step  222  is disposed from the rotational bit axis, which is greater than a third radial distance R 3  at which a third step  224  is disposed from the rotational bit axis  204 . Each of the first, second and third steps  220 ,  222 ,  224  of the circumferential engagement surface  208  is disposed successively a greater axial distance from a leading end  230  of the drill bit  201 . As illustrated in  FIG. 3B , no movable gauge elements  177  extend through the first step  220 , a first pair  232  of movable gauge elements  177  extend through the second step  222 , and a second pair  234  of movable gauge elements  177  extend through the third step. In a retracted configuration, faces  180  of the first pair  232  of movable gauge elements  177  may be flush with the second step  222  and faces  180  of the second pair  234  may be flush with the third step  224 . 
     In other embodiments (not shown), more or fewer steps may be provided, and more or fewer movable gauge elements  177  may extend through each of the steps. In still other embodiments, a tapered circumferential engagement surface may be provided. The circumferential engagement surface may exhibit any diminishing, or reduced profile with respect to a major gauge diameter (e.g., defined at R) of the drill bit, or any variable-diameter profile along an axial length of the drill bit. An axis through the faces  180  of the movable gauge elements  177  may be arranged obliquely with respect to a rotational bit axis in some embodiments. 
       FIG. 4  is a graphical representation of the engagement force provided by the movable gauge elements as a function of axial position along the bit body  224  ( FIG. 2 ). Four axial positions P 1 , P 2 , P 3  and P 4  for movable gauge elements  177  ( FIG. 3A ) are illustrated along the horizontal axis at increasing axial distances from a trailing end  150  of a drill bit  101  ( FIG. 2 ). An engagement force to be provided by a movable gauge element at each of the axial positions P, P 2 , P 3  and P 4  is represented along the vertical axis. In some embodiments, a uniform engagement force may be provided along the axial positions as illustrated by curve  302 . In other embodiments, the engagement force may decrease along a generally linear curve  304  or exponential curve  306 . In still other embodiments, as illustrated by curve  308 , movable gauge elements  177  at adjacent axial positions may provide similar engagement forces, while the overall engagement force decreases along a stepped profile. Each of these arrangements may provide stability to the drill bit  101  in various circumstances without unduly frustrating a steering force applied to the drill bit  101 . 
       FIG. 5A  is a perspective view of one of the gauge elements  177  coupled to a housing or cylinder  408  with a retaining ring  410 . The face  180  of the movable gauge element  177  includes a rounded edge  412 , which is blunt and may be arranged to perform little or no cutting of geologic formations. The face  180  may be constructed of PDC or other abrasion resistant materials, and protrudes from a forward end  414  of the cylinder  408 . A slot  420  is defined in the forward end  414  to facilitate assembly of the retaining ring  410 , which may be a C-ring or similar device. The cylinder  188  may represent a portion the bit body  124  ( FIG. 2 ) and/or may be a separate component that may be coupled to the bit body  124 , e.g., by brazing the cylinder  408  into a pocket defined in the bit body  124 . Where the cylinder  408  is a separate component, a gauge element subassembly  422  is defined by the cylinder  408 , movable gauge element  177 , retaining ring  410  a biasing element  184  ( FIG. 5B ) disposed within the cylinder  408 . The gauge element subassembly  422  may be preassembled to provide a particular engagement force to facilitate construction of a drill bit  101  ( FIG. 2 ). 
       FIG. 5B  is a cross-sectional perspective view of the gauge pad subassembly  422  illustrating the movable gauge element  177  biased to an extended configuration by biasing mechanism  184 . The biasing mechanism  184  may include any number of mechanisms including a pressurized fluid, resilient members such as coiled compression springs, elastomeric springs, leaf springs, etc. As illustrated, biasing mechanism  184  is constructed as stack of Belville washers or springs  428 . The Belville springs  428  are disposed within a cavity  430  defined in the cylinder  408 . The number and orientation of the Belville springs  428  may be varied to provide various engagement forces to the gauge element  177 . For example, in some embodiments, non-resilient spacers (not shown) may be substituted for some of the Belville springs  428  such that a relatively low engagement force may be provided. 
     The Belville springs  428  bias the movable gauge element  177  toward the forward end  414  of the cylinder  408 , and the retaining ring  410  engages an inwardly-facing surface  432  of the cylinder  408  to retain the movable gauge element  177  within the cylinder  408 . A gap  434  defined between the retaining ring  410  and an outwardly-facing surface  436  of the cylinder  408  defines a radial distance that the movable gauge element  177  is permitted to move within the cavity  430 . The gap  434  may be greater than a distance  440  that the face  180  of the movable gauge element  177  protrudes from the forward end  414  of the cylinder, or other circumferential engagement surface  178  of a gauge pad  111  ( FIG. 2 ). Thus, the movable gauge element  177  may move into the cavity  430  against the bias of the Belville springs  428  at least until the face  180  of the movable gauge element  177  is flush with the forward end  414  of the cylinder  408 . 
     The aspects of the disclosure described below are provided to describe a selection of concepts in a simplified form that are described in greater detail above. This section is not intended to identify key features or essential features of the claimed subject matter, nor is it intended to be used as an aid in determining the scope of the claimed subject matter. 
     In one aspect, the disclosure is directed to a drill bit for forming a wellbore through a geologic formation. The drill bit includes a bit body defining a leading end, a trailing end and a longitudinal axis extending between the leading end and the trailing end. At least one cutting element is defined at the leading end of the bit body, and a drill string connector is defined at the trailing end of the bit body. At least one gauge pad is defined on the bit body axially between the at least one cutting element and the drill string connector, and the at least one gauge pad defines a circumferential engagement surface thereon. A plurality of movable gauge elements extend through the engagement surface. Each movable gauge element is biased to a radially extended position wherein a face of the movable gauge element protrudes radially outward from the engagement surface, and each movable gauge element is movable to a retracted position wherein the face of the movable gauge element is flush with the engagement surface. 
     In one or more example embodiments, the drill further includes a plurality of biasing mechanisms including a respective biasing mechanism associated with each of the movable gauge elements. The respective biasing mechanisms provide a decreasing engagement force according along an axial direction of the bit body from the leading to trailing end. The engagement force may decrease linearly, exponentially or along a stepped profile along the axial direction. In some example embodiments, the biasing mechanisms include a plurality of resilient members disposed within a cavity within the bit body. 
     In some example embodiments, the radial face of each of the each of the movable gauge elements is aligned along an axis generally parallel to the rotational bit axis when each of the movable gauge elements are in the extended configuration. In some embodiments, the engagement surface defines a variable-diameter profile along an axial length of the drill bit. 
     In some embodiments the radial faces of the movable gauge elements include a rounded edge therearound. In some embodiments, the drill bit further includes a plurality of cylinders coupled to the bit body, wherein each of the movable gauge elements is movably retained with a respective cylinder along with a biasing mechanism. The cylinders may defines inward and outward surfaces therein that engage a retaining ring coupled to the movable gauge elements to limit the motion of the movable gauge elements within the cylinder. 
     In another aspect, the disclosure is directed to a drill bit including a bit body defining a rotational bit axis, a plurality of blades projecting radially outwardly from the rotational bit axis and defining radially outer circumferential surfaces thereon, a gauge pad defined on radially outer circumferential surfaces of one of the blades, the gauge pad defining a circumferential engagement surface thereon, and a plurality of movable gauge elements extending through the engagement surface. Each of the movable gauge elements is biased radially outward by an individual biasing mechanism and movable radially inwardly against a bias of the biasing mechanism to a retracted position where radial face of the movable gauge elements is flush with the circumferential engagement surface. 
     In some embodiments, the biasing mechanisms provide a decreasing engagement force along an axial direction of the bit body from a leading end to a trailing end of the bit body. Each of the biasing mechanisms may include a resilient member retained within a cavity in the bit body, and a spring rate of each of each resilient member decreases along the axial direction of the bit body. 
     In one or more example embodiments, the movable gauge elements are disposed in a pre-assembled gauge element subassembly including a cylinder defining a cavity therein, the biasing mechanism and the gauge elements retained within the cavity. The radial faces of the movable gauge element may be recessed from an outermost cutting element defined on the bit body. In some embodiments, a radial face of each of the movable gauge elements is generally parallel to the rotational bit axis. In some embodiments, the circumferential engagement surface may be constructed of tungsten carbide or PCD materials. 
     In another aspect, the disclosure is directed to a method of drilling a wellbore with a drill bit. The method includes (a) conveying the drill bit into a wellbore on a drill string, (b) engaging a sidewall of the wellbore with a plurality of movable gauge elements extending through a circumferential engagement surface of a gauge pad defined on a bit body of the drill bit, and (c) applying a steering force to the drill bit through the drill string, thereby causing at least some of the movable gauge elements to retract into the bit body such that a radial face of the retracted movable gauge elements is flush with the circumferential engagement surface of the gauge pad. 
     In some embodiments, the method may further include drilling a straight portion of the wellbore with the movable gauge elements in an extended configuration such that the circumferential engagement surface of the gauge pad is spaced from the sidewall of the wellbore. Also, in some embodiments, the method further includes drilling a curved portion of the wellbore with the movable gauge elements in a retracted configuration such that the circumferential engagement surface of the gauge pad engages the sidewall of the wellbore on one side of the drill bit. 
     In some embodiments, the method further includes engaging the sidewall with a first one of the movable gauge elements at a first axial distance from a leading end of the bit body with a first radial engagement force, and also engaging the sidewall with a second one of the movable gauge elements at a second axial distance from the leading end of the bit body with a second radial engagement force. The second axial distance may be great greater than the first axial distance and the second radial engagement force may be less than the first radial engagement force. 
     The Abstract of the disclosure is solely for providing the United States Patent and Trademark Office and the public at large with a way by which to determine quickly from a cursory reading the nature and gist of technical disclosure, and it represents solely one or more examples. 
     While various examples have been illustrated in detail, the disclosure is not limited to the examples shown. Modifications and adaptations of the above examples may occur to those skilled in the art. Such modifications and adaptations are in the scope of the disclosure.