Title of Invention: Rotary Drill Bits with Gage Pads Having Improved Steerability and Reduced Wear Abstract: A rotary drill bit having blades with gage pads disposed on exterior portions thereof to improve steerability of the rotary drill bit during formation of a directional wellbore without sacrifice of lateral stability. One or more of the gage pads may include radially tapered exterior portions and/or cut out portions to assist with reducing wear of the associated gage pad. For some applications, a rotary drill bit may be formed having blades with gage pads having a relatively uniform exterior surface. Hard facing material and/or buttons may be disposed on exterior portions of the gage pad to form a radially tapered portion to improve steerability, reduce wear of the gage pad and/or improve ability of the rotary drill to form a wellbore having a generally uniform inside diameter, particularly during directional drilling of the wellbore. Detailed Description: RELATED APPLICATION This application claims the benefit of provisional patent application entitled “Rotary Drill Bit with Gage Pads Having Improved Steerability and Reduced Wear,” Provisional Application Ser. No. 60/940,906 filed May 30, 2007. The contents of this application is incorporated herein in its entirety by this reference. TECHNICAL FIELD The present disclosure is related to rotary drill bits and particularly to fixed cutter drill bits having blades with cutting elements and gage pads disposed therein and also roller cone drill bits. BACKGROUND OF THE DISCLOSURE Various types of rotary drill bits, reamers, stabilizers and other downhole tools may be used to form a borehole in the earth. Examples of such rotary drill bits include, but are not limited to, fixed cutter drill bits, drag bits, PDC drill bits, matrix drill bits, roller cone drill bits, rotary cone drill bits and rock bits used in drilling oil and gas wells. Cutting action associated with such drill bits generally requires weight on bit (WOB) and rotation of associated cutting elements into adjacent portions of a downhole formation. Drilling fluid may also be provided to perform several functions including washing away formation materials and other downhole debris from the bottom of a wellbore, cleaning associated cutting elements and cutting structures and carrying formation cuttings and other downhole debris upward to an associated well surface. Some prior art rotary drill bits have been formed with blades extending from a bit body with a respective gage pad disposed proximate an uphole edge of each blade. Gage pads have been disposed at a positive angle or positive taper relative to a rotational axis of an associated rotary drill bit. Gage pads have also been disposed at a negative angle or negative taper relative a rotational axis of an associated rotary drill bit. Such gage pads may sometimes be referred to as having either a positive “axial” taper or a negative “axial” taper. See for example U.S. Pat. No. 5,967,247. The rotational axis of a rotary drill bit will generally be disposed on and aligned with a longitudinal axis extending through straight portions of a wellbore formed by the associated rotary drill bit. Therefore, the axial taper of associated gage pads may also be described as a “longitudinal” taper. Gage pads formed with a positive axial taper may increase steerability of an associated rotary drill bit. Drag torque may also be reduced as a result of forming a gage pad with a positive axial taper. However, lateral stability of an associated rotary drill bit relative to a longitudinal axis extending through a wellbore being formed by the rotary drill bit may be reduced. Also, the ability of the associated rotary drill bit to maintain a generally uniform inside diameter of the wellbore may be reduced. For other applications gage pads have been offset a relatively uniform radial distance from adjacent portions of a wellbore formed by a associated rotary drill bit. Exterior portions of such gage pads may be generally disposed approximately parallel with an associated bit rotational axis and adjacent portions of a straight wellbore. The amount of offset between exterior portions of such gage pads and adjacent portions of a straight wellbore will typically be relatively uniform. For some applications gage pads have been formed with a relatively uniform radial offset or uniform reduced outside diameter between approximately 1/64 of an inch to 4/64 of an inch as compared to a nominal diameter of the associated rotary drill bit. Providing gage pads with an offset from an associated nominal bit diameter or undersizing gage pads may increase steerability of an associated rotary drill bit. However, lateral stability relative to a longitudinal axis of an associated wellbore and ability of the rotary drill bit to ream or form the wellbore with a generally uniform inside diameter may be reduced. SUMMARY OF THE DISCLOSURE In accordance with teachings of the present disclosure, a rotary drill bit may be formed with a plurality of blades having a respective gage portion or gage pad disposed on each blade. At least one gage pad may have an exterior tapered portion and/or an exterior recessed portion incorporating teachings of the present disclosure. Gage pads designed in accordance with teachings of the present disclosure may experience reduced wear and erosion while forming a wellbore, particularly non-vertical and non-straight wellbores. Gage pads incorporating teachings of the present disclosure may improve steerability of an associated rotary drill bit while maintaining desired lateral stability of the rotary drill bit. Gage pads incorporating teachings of the present disclosure may also improve the ability of an associated rotary drill bit to form a wellbore with a more uniform inside diameter. A rotary drill bit formed in accordance with teachings of the present disclosure may often form a wellbore having a relatively uniform inside diameter which may generally correspond with an associated nominal diameter of the rotary drill bit. One aspect of the present disclosure may include designing rotary drill bits in accordance with teachings of the present disclosure having respective gage pads disposed on blades of a fixed cutter rotary drill bit or support arms of a roller cone drill bit to optimize downhole drilling performance. For some applications such gage pads may have exterior configurations which cooperate with other features of the associated rotary drill bit to improve steerability, particularly during formation of non-vertical or non-straight wellbores without sacrificing lateral stability of the rotary drill bit. For other applications such gage pads may improve ability of an associated rotary drill bit to ream a wellbore or form a wellbore with a more uniform inside diameter, particularly during formation of a non-vertical or non-straight wellbore. BRIEF DESCRIPTION OF THE DRAWINGS A more complete and thorough understanding of the present embodiments and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings, in which like reference numbers indicate like features, and wherein: FIG. 1A is a schematic drawing in section and in elevation with portions broken away showing examples of wellbores which may be formed by a rotary drill bit incorporating teachings of the present disclosure; FIG. 1B is a schematic drawing in section and in elevation with portions broken away showing another example of a rotary drill bit incorporating teachings of the present disclosure; FIG. 2 is a schematic drawing showing an isometric view with portions broken away of a rotary drill bit; FIG. 3 is a schematic drawing showing an isometric view of another example of a rotary drill bit; FIG. 4 is a schematic drawing in section with portions broken away showing still another example of a rotary drill bit; FIG. 5 is a schematic drawing in section with portions broken away showing an enlarged view of a gage portion of one blade on the rotary drill bit shown in FIG. 4; FIG. 6A is a schematic drawing in section showing one example of a prior art blade and associated gage pad on a rotary drill bit; FIG. 6B is a schematic drawing showing an isometric side view of the gage pad of FIG. 6A; FIG. 7A is a schematic drawing in section with portions broken away showing one example of a blade and associated gage pad with a positive radial taper angle disposed on a rotary drill bit in accordance with teachings of the present disclosure; FIG. 7B is a schematic drawing in section with portions broken away showing another example of a blade and associated gage pad with a positive radial taper angle disposed on a rotary drill bit in accordance with teachings of the present disclosure; FIG. 7C is a schematic drawing in section with portions broken away showing a further example of a blade and associated gage pad with a negative radial taper angle disposed on a rotary drill bit in accordance with teachings of the present disclosure; FIG. 7D is a schematic drawing in section with portions broken away showing still another example of a blade and associated gage pad with a negative radial taper angle disposed on a rotary drill bit in accordance with teachings of the present disclosure; FIG. 8A is a schematic drawing in section with portions broken away showing one example of a blade and associated gage pad which may be disposed on a rotary drill bit in accordance with teachings of the present disclosure; FIG. 8B is a schematic drawing in section with portions broken away showing another example of a blade and associated gage pad which may be disposed on a rotary drill bit in accordance with teachings of the present disclosure; FIG. 9A is a schematic drawing showing a side view of one example of a gage pad incorporating teachings of the present disclosure; FIG. 9B is a schematic drawing in section taken along lines 9B-9B of FIG. 9A; FIG. 9C is a schematic drawing showing a side view of another example of a gage pad incorporating teachings of the present disclosure; FIG. 9D is a schematic drawing in section taken along lines 9D-9D of FIG. 9C; FIG. 10A is a schematic drawing showing a side view of one example of a gage pad having a generally positive radial taper angle and a generally positive axial taper angle incorporating teachings of the present disclosure; FIG. 10B is a schematic drawing taken along lines 10B-10B of FIG. 10A; FIG. 100 is a schematic drawing in section taken along lines 10C-10C of FIG. 10A; FIG. 10D is a schematic drawing in section taken along lines 10D-10D of FIG. 10A; FIG. 10E is a schematic drawing in section taken along lines 10E-10E of FIG. 10A; FIG. 10F is a schematic drawing showing a side view of one example of a gage pad having a generally negative radial taper angle and a generally negative axial taper angle incorporating teachings of the present disclosure; FIG. 10G is a schematic drawing taken along lines 10G-10G of FIG. 10F; FIG. 10H is a schematic drawing in section taken along lines 10H-10H of FIG. 10F; FIG. 10I is a schematic drawing in section taken along lines 10I-10I of FIG. 10F; FIG. 10J is schematic drawing in section taken along lines 10J-10J of FIG. 10F; FIG. 11A is a schematic drawing showing a side view of one example of a gage pad incorporating teachings of the present disclosure; FIG. 11B is a schematic drawing in section taken along lines 11B-11B of FIG. 11A; FIG. 11C is a schematic drawing in section taken along lines 11C-11C of FIG. 11A; FIG. 11D is a schematic drawing showing a side view of another example of a gage pad incorporating teachings of the present disclosure; FIG. 11E is a schematic drawing in section taken along lines 11E-11E of FIG. 11D; FIG. 11F is a schematic drawing in section taken along lines 11F-11F of FIG. 11D; FIG. 12A is a schematic drawing showing a side view of still another example of a gage pad incorporating teachings of the present disclosure; FIG. 12B is a schematic drawing in section taken along lines 12B-12B of FIG. 12A; FIG. 12C is a schematic drawing in section taken along lines 12C-12C of FIG. 12A; FIG. 12D is a schematic drawing showing a side view of a further example of a gage pad incorporating teachings of the present disclosure; FIG. 12E is a schematic drawing in section taken along lines 12E-12E of FIG. 12D; and FIG. 12F is a schematic drawing in section taken along lines 12F-12F of FIG. 12D. DETAILED DESCRIPTION OF THE DISCLOSURE Preferred embodiments of the disclosure and its advantages are best understood by reference to FIGS. 1-12F wherein like number refer to same and like parts. The term “bottom hole assembly” or “BHA” be used in this application to describe various components and assemblies disposed proximate a rotary drill bit at the downhole end of a drill string. Examples of components and assemblies (not expressly shown) which may be included in a bottom hole assembly or BHA include, but are not limited to, a bent sub, a downhole drilling motor, a near bit reamer, stabilizers and downhole instruments. A bottom hole assembly 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 such 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. The terms “cutting element” and “cutting elements” may be used in this application to include, but are not limited to, various types of cutters, compacts, buttons, inserts and gage cutters satisfactory for use with a wide variety of rotary drill bits. Impact arrestors may be included as part of the cutting structure on some types of rotary drill bits and may sometimes function as cutting elements to remove formation materials from adjacent portions of a wellbore. Polycrystalline diamond compacts (PDC) and tungsten carbide inserts are often used to form cutting elements. Various types of other hard, abrasive materials may also be satisfactorily used to form cutting elements. The term “cutting structure” may be used in this application to include various combinations and arrangements of cutting elements, impact arrestors and/or gage cutters formed on exterior portions of a rotary drill bit. Some rotary drill bits may include one or more blades extending from an associated bit body with cutters disposed of the blades. Such blades may also be referred to as “cutter blades”. Various configurations of blades and cutters may be used to form cutting structures for a rotary drill bit. The terms “downhole” and “uphole” may be used in this application to describe the location of various components of a rotary drill bit relative to portions of the rotary drill bit which engage the bottom or end of a wellbore to remove adjacent formation materials. For example an “uphole” component may be located closer to an associated drill string or bottom hole assembly as compared to a “downhole” component which may be located closer to the bottom or end of the wellbore. The term “gage pad” as used in this application may include a gage, gage segment, gage portion or any other portion of a rotary drill bit incorporating teachings of the present disclosure. Gage pads may be used to define or establish a generally uniform inside diameter of a wellbore formed by an associated rotary drill bit. A gage, gage segment, gage portion or gage pad may include one or more layers of hardfacing material. One or more gage cutters, gage inserts, gage compacts or gage buttons may be disposed on or adjacent to a gage, gage segment, gage portion or gage pad in accordance with teachings of the present disclosure. Gage pads incorporating teachings of the present disclosure may be disposed on a wide variety of rotary drill bit and other components of a bottom hole assembly and/or drill string. Rotating and non-rotating sleeves associated with directional drilling systems may also include such gage pads. The term “rotary drill bit” may be used in this application to include various types of fixed cutter drill bits, drag bits, matrix drill bits, steel body drill bits, roller cone drill bits, rotary cone drill bits and rock bits operable to form a wellbore extending through one or more downhole formations. Rotary drill bits and associated components formed in accordance with teachings of the present disclosure may have many different designs, configurations and/or dimensions. The terms “axial taper” or “axially tapered” may be used in this application to describe various portions of a gage pad disposed at an angle relative to an associated bit rotational axis. During drilling of a straight, vertical wellbore, an axial taper may sometimes be described as a “longitudinal” taper. An axially tapered portion of a gage pad may also be disposed at an angle extending longitudinally relative to adjacent portions of a straight wellbore. Prior art axially tapered gage pads typically have an uphole edge disposed at a first, generally uniform radius extending from an associated bit rotational axis and a downhole edge disposed at a second, generally uniform radius extending from the associated bit rotational axis. An axially tapered gage pad formed in accordance with teachings of the present disclosure may include an uphole edge and/or a downhole edge which do not include a generally uniform radius extending from an associated bit rotational axis. As discussed later in more detail, for some embodiments the uphole edge and/or downhole edge of a gage pad may be formed with a variable radius or nonuniform radius extending from an associated bit rotational axis. A positive axial taper of a gage pad may result at least in part from a first radius of an uphole edge of the gage pad being smaller than a second radius of the downhole edge of the gage pad. A negative axial taper of a gage pad may result at least in part from the first radius of an uphole edge of the gage pad being larger than a second radius of the downhole edge of the gage pad. See for example FIGS. 4 AND 5. Additional examples of gage pads with generally positive axial taper angles are shown in FIGS. 10D and 10E. Additional examples of gage pads with generally negative axial taper angles are shown in FIGS. 10I and 10J. Exterior portions of prior art gage pads may be disposed at a generally uniform angle, either positive, negative or parallel, relative to adjacent portions of a straight wellbore. The uphole edge of such prior art gage pads with a positive axial taper will generally be located further from adjacent portions of a straight wellbore. The downhole edge of prior art gage pads with a positive axial taper will generally be located closer to adjacent portions of the straight wellbore. The uphole edge of prior art gage pads with a negative axial taper angle will generally be located closer to adjacent portions of a straight wellbore. The downhole edge of prior art gage pads with a negative taper angle will be generally located at a greater distance from adjacent portions of a straight wellbore. The terms “radially tapered”, “radial taper” and/or “tangent taper” may be used in this application to describe exterior portions of a gage pad disposed at varying radial distances from an associated bit rotational axis. Each radius associated with radially tapered or tangent tapered exterior portions of a gage pad may be measured in a plane extending generally perpendicular to the associated bit rotational axis and intersecting the radially tapered or tangent tapered exterior portion of the gage pad. Examples of gage pads with generally positive radial taper angles are shown in FIGS. 7A and 7B. Examples of gage pads with generally negative radial taper angles are shown in FIGS. 7C and 7D. Teachings of the present disclosure may be used to optimize the design of various features of a rotary drill bit including, but not limited to, the number of blades or cutter blades, dimensions and configurations of each cutter blade, configuration and dimensions of one or more support arms of a roller cone drill bit, configuration and dimensions of cutting elements, the number, location, orientation and type of cutting elements, gages (active or passive), length of one or more gage pads, orientation of one or more gage pads and/or configuration of one or more gage pads. Rotary drill bits formed in accordance with teachings of the present disclosure may have a “passive gage” and an “active gage”. An active gage may partially cut into and remove formation materials from adjacent portions or sidewall of an associated wellbore or borehole. A passive gage will generally not remove formation materials from the sidewall of an associated wellbore or borehole. During directional drilling of a wellbore, active gages frequently remove some formation materials from adjacent portions of a non-straight wellbore. A passive gage may plastically or elastically deform formation materials in a sidewall, particularly during directional drilling of an associated wellbore. Various computer programs and computer models may be used to design gage pads, compacts, cutting elements, blades and/or associated rotary drill bits in accordance with teachings of the present disclosure. Examples of such methods and systems which may be used to design and evaluate performance of cutting elements and rotary drill bits incorporating teachings of the present disclosure are shown in copending U.S. patent applications entitled “Methods and Systems for Designing and/or Selecting Drilling Equipment Using Predictions of Rotary Drill Bit Walk,” application Ser. No. 11/462,898, filing date Aug. 7, 2006; copending U.S. patent application entitled “Methods and Systems of Rotary Drill Bit Steerability Prediction, Rotary Drill Bit Design and Operation,” application Ser. No. 11/462,918, filed Aug. 7, 2006 and copending U.S. patent application entitled “Methods and Systems for Design and/or Selection of Drilling Equipment Based on Wellbore Simulations,” application Ser. No. 11/462,929, filing date Aug. 7, 2006. The previous copending patent applications and any resulting U.S. patents are incorporated by reference in this application. Various aspects of the present disclosure may be described with respect to rotary drill bits 100 and 100a as shown in FIGS. 1-5. Rotary drill bits 100 and 100a may also be described as fixed cutter drill bits. Various aspects of the present disclosure may also be used to design roller cone or rotary cone drill bits for optimum downhole drilling performance. Rotary drill bits 100 and/or 100a may be modified to include various types of gages, gage segments, gage portions and/or gage pads incorporating teachings of the present disclosure. Also, a wide variety of rotary drill bits may be formed with gages, gage pads, gage segments and/or gage portions incorporating teachings of the present disclosure. The scope of the present disclosure is not limited to rotary drill bits 100 or 100a. The scope of the present disclosure is also not limited to gage pads such as shown in FIGS. 7A-12F. FIG. 1A is a schematic drawing in elevation and in section with portions broken away showing examples of wellbores or bore holes which may be formed by rotary drill bits incorporating teachings of the present disclosure. Various aspects of the present disclosure may be described with respect to drilling rig 20 rotating drill string 24 and attached rotary drill bit 100 to form a wellbore. Various types of drilling equipment such as a rotary table, mud pumps and mud tanks (not expressly shown) may be located at well surface or well site 22. Drilling rig 20 may have various characteristics and features associated with a “land drilling rig.” However, rotary drill bits incorporating teachings of the present disclosure may be satisfactorily used with drilling equipment located on offshore platforms, drill ships, semi-submersibles and drilling barges (not expressly shown). For some applications rotary drill bit 100 may be attached to bottom hole assembly 26 at an extreme end of drill string 24. Drill string 24 may be formed from sections or joints of generally hollow, tubular drill pipe (not expressly shown). Bottom hole assembly 26 will generally have an outside diameter compatible with exterior portions of drill string 24. Bottom hole assembly 26 may be formed from a wide variety of components. For example components 26a, 26b and 26c may be selected from the group consisting of, but not limited to, drill collars, rotary steering tools, directional drilling tools and/or downhole drilling motors. The number of components such as drill collars and different types of components included in a bottom hole assembly will depend upon anticipated downhole drilling conditions and the type of wellbore which will be formed by drill string 24 and rotary drill bit 100. Drill string 24 and rotary drill bit 100 may be used to form a wide variety of wellbores and/or bore holes such as generally vertical wellbore 30 and/or generally horizontal wellbore 30a as shown in FIG. 1A. Various directional drilling techniques and associated components of bottomhole assembly 26 may be used to form horizontal wellbore 30a. For example lateral forces may be applied to rotary drill bit 100 proximate kickoff location 37 to form horizontal wellbore 30a extending from generally vertical wellbore 30. Such lateral movement of rotary drill bit 100 may be described as “building” or forming a wellbore with an increasing angle relative to vertical. Bit tilting may also occur during formation of horizontal wellbore 30a, particularly proximate kickoff location 37. Wellbore 30 may be defined in part by casing string 32 extending from well surface 22 to a selected downhole location. Portions of wellbore 30 as shown in FIG. 1A which do not include casing 32 may be described as “open hole”. Various types of drilling fluid may be pumped from well surface 22 through drill string 24 to attached rotary drill bit 100. The drilling fluid may be circulated back to well surface 22 through annulus 34 defined in part by outside diameter 25 of drill string 24 and inside diameter 31 of wellbore 30. Annulus 34 may also be defined by outside diameter 25 of drill string 24 and inside diameter 31 of casing string 32. Inside diameter 31 may sometimes be referred to as the “sidewall” of wellbore 30. Inside diameter 31 may often correspond with a nominal diameter or nominal outside diameter associated with rotary drill bit 100. However, depending upon downhole drilling conditions, the amount of wear on one or more components of a rotary drill bit and variations between nominal diameter bit and as build dimensions of a rotary drill bit, a wellbore formed by a rotary drill bit may have an inside diameter which may be either larger than or smaller than the corresponding nominal bit diameter. Therefore, various diameters and other dimensions associated with gage pads formed in accordance with teachings of the present disclosure may be defined with respect to an associated bit rotational axis and not the inside diameter of a wellbore formed by an associated rotary drill bit. Nominal bit diameter may sometimes be referred to as “nominal bit size” or “bit size.” The American Petroleum Institute (API) publishes various standards related to nominal bit size, clearance diameters and casing dimensions. Formation cuttings may be formed by rotary drill bit 100 engaging formation materials proximate end 36 of wellbore 30. Drilling fluids may be used to remove formation cuttings and other downhole debris (not expressly shown) from end 36 of wellbore 30 to well surface 22. End 36 may sometimes be described as “bottom hole” 36. Formation cuttings may also be formed by rotary drill bit 100 engaging end 36a of horizontal wellbore 30a. As shown in FIG. 1A, drill string 24 may apply weight to and rotate rotary drill bit 100 to form wellbore 30. Inside diameter or sidewall 31 of wellbore 30 may correspond approximately with the combined outside diameter of blades 130 and associated gage pads 150 extending from rotary drill bit 100. Rate of penetration (ROP) of a rotary drill bit is typically a function of both weight on bit (WOB) and revolutions per minute (RPM). For some applications a downhole motor (not expressly shown) may be provided as part of bottom hole assembly 26 to also rotate rotary drill bit 100. The rate of penetration of a rotary drill bit is generally stated in feet per hour. In addition to rotating and applying weight to rotary drill bit 100, drill string 24 may provide a conduit for communicating drilling fluids and other fluids from well surface 22 to drill bit 100 at end 36 of wellbore 30. Such drilling fluids may be directed to flow from drill string 24 to respective nozzles provided in rotary drill bit 100. See for example nozzle 56 in FIG. 3. Bit body 120 will often be substantially covered by a mixture of drilling fluid, formation cuttings and other downhole debris while drilling string 24 rotates rotary drill bit 100. Drilling fluid exiting from one or more nozzles 56 may be directed to flow generally downwardly between adjacent blades 130 and flow under and around lower portions of bit body 120. The term “roller cone drill bit” may be used in this application to describe any type of rotary drill bit having at least one support arm with a cone assembly rotatably mounted thereon. Roller cone drill bits may sometimes be described as “rotary cone drill bits,” “cutter cone drill bits” or “rotary rock bits”. Roller cone drill bits often include a bit body with three support arms extending therefrom and a respective cone assembly rotatably mounted on each support arm. However, teachings of the present disclosure may be satisfactorily used with rotary drill bits having one support arm, two support arms or any other number of support arms and associated cone assemblies. FIG. 1B is a schematic drawing in elevation and in section with portions broken away showing one example of roller cone drill bit incorporating teachings of the present disclosure disposed in a wellbore. Roller cone drill bit 40 as shown in FIG. 1B may be attached with the end of drill string 24 extending from well surface 22. Roller cone drill bits such as rotary drill bit 40 typically form wellbores by crushing or penetrating a formation and scraping or shearing formation materials from the bottom of the wellbore using cutting elements which often produce a high concentration of fine, abrasive particles. Bit body 61 may be formed from three segments which include respective support arms 50 extending therefrom. The segments may be welded with each other using conventional techniques to form bit body 61. Only two support arms 50 are shown in FIG. 1B. Each support arm 50 may be generally described as having an elongated configuration extending from bit body 61. Each support arm may include a respective spindle (not expressly shown) with a respective cone assembly 80 rotatably melded thereon. Each support arm 50 may include respective leading edge 131a and trailing edge 132a. Each support arm 150 may also include a respective gage pad 150a formed in accordance with teachings of the present disclosure. Cone assemblies 80 may have an axis of rotation corresponding generally with the angularly shaped relationship of the associated spindle and respective support arm 50. The axis of rotation of each cone assembly 80 may generally correspond with the longitudinal axis of the associated spindle. The axis of rotation of each cone assembly 80 may be offset relative to the longitudinal axis or bit rotational axis associated with roller cone drill bit 40. For some applications a plurality of compacts 95 may be disposed on backface 94 of each cone assembly 90. Compacts 95 may reduce wear of backface 94. Each cone assembly 80 may include a plurality of cutting elements 98 arranged in respective rows disposed on exterior portions of each cone assembly 80. Compacts 95 and cutting elements 98 may be formed from a wide variety of materials such as tungsten carbide or other hard materials satisfactory for use in forming a roller cone drill bit. For some applications compacts 95 and/or inserts 96 may be formed at least in part from polycrystalline diamond-type materials and/or other hard, abrasive materials. FIGS. 2 and 3 are schematic drawings showing additional details of rotary drill bit 100 which may include at least one gage, gage portion, gage segment or gage pad incorporating teachings of the present disclosure. Rotary drill bit 100 may include bit body 120 with a plurality of blades 130 extending therefrom. For some applications bit body 120 may be formed in part from a matrix of very hard materials associated with rotary drill bits. For other applications bit body 120 may be machined from various metal alloys satisfactory for use in drilling wellbores in downhole formations. Examples of matrix type drill bits are shown in U.S. Pat. Nos. 4,696,354 and 5,099,929. Bit body 120 may also include upper portion or shank 42 with American Petroleum Institute (API) drill pipe threads 44 formed thereon. API threads 44 may be used to releasably engage rotary drill bit 100 with bottomhole assembly 26 whereby rotary drill bit 100 may be rotated relative to bit rotational axis 104 in response to rotation of drill string 24. Bit breaker slots 46 may also be formed on exterior portions of upper portion or shank 42 for use in engaging and disengaging rotary drill bit 100 from an associated drill string. An enlarged bore or cavity (not expressly shown) may extend from end 41 through upper portion 42 and into bit body 120. The enlarged bore may be used to communicate drilling fluids from drill string 24 to one or more nozzles 56. A plurality of respective junk slots or fluid flow paths 140 may be formed between respective pairs of blades 130. Blades 130 may spiral or extend at an angle relative to associated bit rotational axis 104. One of the benefits of the present disclosure may include designing at least one gage pad based on parameters such as blade length, blade width, blade spiral, axial taper, radial taper and/or other parameters associated with rotary drill bits. Various features of such gage pads may be defined relative to the bit rotational axis of an associated rotary drill bit and not the inside diameter of a wellbore formed by the associated rotary drill bit. Gage pads incorporating teachings of the present disclosure may be disposed on various components of rotary drill string such as, but not limited to, sleeve, reamers, bottomhole assemblies and other downhole tools. Various features of such gage pad may also be defined relative to an associated rotation axis or longitudinal axis. A plurality of cutting elements 60 may be disposed on exterior portions of each blade 130. For some applications each cutting element 60 may be disposed in a respective socket or pocket formed on exterior portions of associated blades 130. Impact arrestors and/or secondary cutters 70 may also be disposed on each blade 130. See for example, FIG. 3. Cutting elements 60 may include respective substrates (not expressly shown) with respective layers 62 of hard cutting material disposed on one end of each respective substrate. Layer 62 of hard cutting material may also be referred to as “cutting layer” 62. Each substrate may have various configurations and may be formed from tungsten carbide or other materials associated with forming cutting elements for rotary drill bits. For some applications cutting layers 62 may be formed from substantially the same hard cutting materials. For other applications cutting layers 62 may be formed from different materials. Various parameters associated with rotary drill bit 100 may include, but are not limited to, location and configuration of blades 130, junk slots 140 and cutting elements 60. Each blade 130 may include respective gage portion or gage pad 150. For some applications gage cutters may also be disposed on each blade 130. See for example gage cutters 60g. Additional information concerning gage cutters and hard cutting materials may be found in U.S. Pat. Nos. 7,083,010, 6,845,828, and 6,302,224. Additional information concerning impact arrestors may be found in U.S. Pat. Nos. 6,003,623, 5,595,252 and 4,889,017. Rotary drill bits are generally rotated to the right during formation of a wellbore. See respective arrows 28 in FIGS. 2, 3, 4, 6A, 7A-7D. 8A and 8B. Cutting elements and/or blades may be generally described as “leading” or “trailing” with respect to other cutting elements and/or blades disposed on the exterior portions of an associated rotary drill bit. For example blade 130a as shown in FIG. 2 may be generally described as leading blade 130b and may be generally described as trailing blade 130e. In the same respect cutting elements 60 disposed on blade 130a may be described as leading corresponding cutting element 60 disposed on blade 130b. Cutting elements 60 disposed on blade 130a may be generally described as trailing cutting elements 60 disposed on blade 130e. Rotary drill bit 100a as shown in FIGS. 4 and 5 may be described as having a plurality of blades 130a with a plurality of cutting elements 60 disposed on exterior portions of each blade 130a. For some applications cutting elements 60 may have substantially the same configuration and design. For other applications various types of cutting elements and impact arrestors (not expressly shown) may also be disposed on exterior portions of blades 130a. Exterior portions of blades 130a and associated cutting elements 60 may be described as forming a “bit face profile” for rotary drill bit 100a. Bit face profile 134 of rotary drill bit 100a as shown in FIG. 4 may include recessed portions or cone shaped segments 134c formed on rotary drill bit 100a opposite from shank 42a. Each blade 130a may include respective nose portions or segments 134n which define in part an extreme end of rotary drill bit 100a opposite from shank 42a. Cone shaped segments 134c may extend radially inward from respective nose segments 134n toward bit rotational axis 104. A plurality of cutting elements 60c may be disposed on recessed portions or cone shaped segments 134c of each blade 130a between respective nose segments 134n and rotational axis 104a. A plurality of cutting elements 60n may be disposed on nose segments 134n. Each blade 130a may also be described as having respective shoulder segment 134s extending outward from respective nose segment 134n. A plurality of cutting elements 60s may be disposed on each shoulder segment 134s. Cutting elements 60s may sometimes be referred to as “shoulder cutters.” Shoulder segments 134s and associated shoulder cutters 60s may cooperate with each other to form portions of bit face profile 134 of rotary drill bit 100a extending outward from nose segments 134n. A plurality of gage cutters 60g may also be disposed on exterior portions of each blade 130a proximate respective gage pad 150a. Gage cutters 60g may be used to trim or ream inside diameter or sidewall 31 of wellbore 30. As shown in FIGS. 4 and 5 each blade 130a may include respective gage pad 150a. Various types of hardfacing and/or other hard materials (not expressly shown) may be disposed on exterior portions of each gage pad 150a. Each gage pad 150a may include generally positive axial taper 146 or generally negative axial taper 148 as shown in FIG. 5. Various types of gage pads may be disposed on one or more blades of rotary drill bits 100 and 100a. FIGS. 6A and 6B show one example of a prior art gage pad which may be formed on blades 130 or 130a. FIGS. 7A-12F show examples of blades and gage pads incorporating teachings of the present disclosure which may be disposed on rotary drill bit 100, rotary drill bit 100a or other rotary drill bit as desired to improve performance of such drill bits. Gage pads may be formed on rotary drill bit 100, rotary drill bit 100a or other rotary drill bits in accordance with teachings of the present disclosure. Gage pads generally include respective uphole edge 151 disposed generally adjacent to an associated upper portion or shank. See for example upper portion 42 in FIG. 3 or upper portion 42a in FIG. 4. Gage pads generally include respective downhole edge 152. For some applications downhole edge 152 may be clearly defined such as downhole edge 152 as shown on blade 130a in FIG. 5. For other applications downhole edge 152 associated with gage pad 150 may represent a change from a generally non-curved surface to a curved surface disposed on exterior portion of each blade 130. See dotted line 152 in FIG. 3. Gage pads may also include respective leading edge 131 and trailing edge 132 extending downhole from associated uphole edge 151. Leading edge 131 of each gage pad 150 or 150a may extend from corresponding leading edge 131 of associated blade 130 or 130a. Trailing edge 132 of each gage pad 150 or 150a may extend from corresponding trailing edge 132 of associated blade 130 or 130a. For purposes of describing various features of a gage pad, reference may be made to four points or locations (51, 52, 53 and 54) disposed on exterior portions of the gage pad. Point 51 may generally correspond with the intersection of respective uphole edge 151 and respective portions of leading edge 131. Point 53 may generally correspond with the intersection of respective uphole edge 151 and respective portions of trailing edge 132. Point 52 may generally correspond with the intersection of respective downhole edge 152 and respective portions of leading edge 131. Point 54 may generally correspond with respective downhole edge 152 and respective portions of trailing edge 132. FIGS. 6A and 6B are schematic drawings which may be used to describe a rotary drill bit including, but not limited to, rotary drill bit 100 having conventional or prior art gage pads 150 disposed on respective blades 130. Gage pads 150 may be formed with substantially no axial taper, no radial taper and no radial offset relative to bit rotational axis 104 and adjacent portions of a straight wellbore formed by rotary drill bit 100. Exterior surface 154 of gage pad 150 may be defined by radius 161 extending from associated bit rotation axis 104. Circle 31a as shown in FIG. 6A may represent nominal bit size or nominal bit diameter (Db) of rotary drill bit 100 relative to bit rotational axis 104. Arrow 28 may represent the direction of rotation of rotary drill bit 100 during formation of a wellbore. Circle 31a as shown in FIG. 6A may often correspond generally with inside diameter 31 of wellbore 30 adjacent to kickoff location 37. See FIG. 1A. Circles 31a as shown in FIGS. 6A, 7A, 7B, 7C, 7D, 8A and 8B may often represent the nominal bit diameter of the associated rotary drill bit measured relative to respective bit rotational axis 104. As previously noted, the inside diameter of a wellbore formed by a rotary drill bit may sometimes have an inside diameter larger than or smaller than the nominal diameter or nominal size of the rotary drill bit. One or more components in bottomhole assembly 26 may direct or guide rotary drill bit 100 to form horizontal wellbore 30a extending laterally from wellbore 30 proximate kickoff location 37. Arrow 38 may indicate the direction of lateral penetration of rotary drill bit 100 required to form wellbore 30a extending from kickoff location 37. Dotted line 31a as shown in FIG. 6A may represent incremental lateral movement during one revolution of rotary drill bit 100 to form non-straight or curve segments of wellbore 30a. Such lateral movement of rotary drill bit 100 will typically result in increased contact between exterior portion 154 of gage pad 150 adjacent to trailing edge 132 as compared with contact occurring at leading edge 131. For some applications, the amount of penetration of gage pad 154 at leading edge 131 may be assumed to be approximately equal to zero. Exterior portions 154 of gage pad 150 adjacent to trailing edge 132 may penetrate adjacent portions of a wellbore during each revolution of rotary drill bit 100 by distance 90 as shown in FIG. 6A during lateral penetration of a wellbore. Such increased lateral penetration across exterior portion 154 of gage pad 150 may frequently increase wear on exterior portion 154 of gage pad 150 adjacent to uphole edge 151 and trailing edge 132. See for example wear zone 154w in FIG. 6B. The following formula may be used to estimate engagement depth of a gage pad resulting from side cutting or lateral penetration of a wellbore by an associated rotary drill bit. For a given lateral rate of penetration (ROPlat), revolutions per minute (RPM), drill bit size or nominal bit diameter (Db) and gage pad width (W), the following formula may be used to calculate estimated engagement depth of point 54 on downhole edge 152 of gage pad 150 during engagement and disengagement with the wellbore 31. See FIGS. 6A and 6B. Δ = ROP lat × dt dt = 1 ( 6 × RPM ) × W π   D b A more accurate estimate of engagement depth of gage pad 150 into adjacent portions of the sidewall of a wellbore during one revolution of an associated rotary drill bit may be obtained by using actual dimensions of exterior 154 measured relative to respective bit rotational axis 104. If ROPlat equals 15 ft/hr, nominal bit diameter (Db) equals 12.5 inches and gage pad width equals 2.5 inches, the engagement depth of PB may equal 0.0032 inches or 0.0081 mm. Inspection of rotary drill bits having convention gage pads often show increased wear at location corresponding with wear zone 154w extending from point 53 and adjacent portions of downhole edge 152 and trailing edge 132. See FIG. 6B. Gage pad width (W) may correspond approximately with the distance between the leading edge and the trailing edge of a gage pad measure relative to a plane extending perpendicular to a associated bit rotational axis and intersecting exterior portions of the associated gage pad. For example, the width of gage pad 150 along downhole edge 152 as shown in FIGS. 2 and 3 may correspond generally with the distance between associated point 52 and 54. For some applications respective widths of a gage pad measured relative to an associated downhole edge and an associated uphole edge may generally be equal to each other. For other applications the width of a gage pad formed in accordance with teachings of the present disclosure may vary when measured along an associated downhole edge as compared with a width measured along an associated uphole edge. Lateral movement of rotary drill bit 100 in the direction of arrow 38 may gradually increase across exterior portion 154 of gage pad 150 between leading edge 131 and trailing edge 132. As a result, prior art gage pads having approximately zero taper such as gage pads 150 as shown in FIGS. 2, 3, 6A and 6B may experience also increased wear adjacent to trailing edge 132. Tilting of an associated rotary drill bit during formation of a directional or non-straight wellbore may also result in portions of exterior surface 154w adjacent to trailing edge 132 and uphole edge 151 having increased contact with adjacent portions of the directional or non-straight wellbore as compared with portions of exterior surface 154 adjacent to leading edge 131. Forming a rotary drill bit with gage pads having one or more tapered surfaces and/or recessed portions in accordance with teachings of the present disclosure may substantially minimize and/or reduce wear on exterior portions of the associated gage pads. For embodiments such as shown in FIGS. 7A-12F uphole edge 151, downhole edge 152, leading edge 131 and trailing edge 132 may be generally described as forming a parallelogram. However, gage pads formed in accordance with teachings of the present disclosure may have perimeters with a wide variety of configurations including, but not limited to, square, rectangular or trapezoidal. The present disclosure is not limited to gage pads having configurations such as shown in FIGS. 7A-12F. For some applications gage pads incorporating teachings of the present disclaimer may include leading edge 131 with relative uniform first radius 161 extending from bit rotation axis 104 between the associated uphole edge and downhole edge (not expressly shown). Trailing edge 132 of such gage pads may also have relatively uniform second radius 162 extending from bit rotational axis 104 between the associated uphole edge and downhole edge (not expressly shown). For other applications segments of leading edge 131 and/or trailing edge 132 of a gage pad incorporating teachings of the present disclosure may have varying radii extending from bit rotational axis 104. See for example FIGS. 7A, 7B, 7C, 7D, 8A, 8B, 10B, 10C, 10G and 10H. Gage pads formed in accordance with teachings of the present disclosure may be active gages or passive gages as desired to optimize performance of an associated rotary drill bit. For some applications gage pads may be formed with respective leading edges having gage cutters, compacts, buttons and/or inserts operable to contact and remove formations materials from adjacent portions of a wellbore. Such gage pads may sometimes be referred to as “active gages”. Examples of such active gage pads are shown in FIGS. 7C, 7D, 8A, 8B, 10E-10G, 11D, 11E, 12D and 12E. Steerability of a rotary
{'application_number': '<application-reference appl-type="utility">\n<document-id>\n<country>US</country>\n<doc-number>12600832</doc-number>\n<date>20080527</date>\n</document-id>\n</application-reference>', 'publication_number': '<publication-reference>\n<document-id>\n<country>US</country>\n<doc-number>20100163312</doc-number>\n<kind>A1</kind>\n<date>20100701</date>\n</document-id>\n</publication-reference>', 'source_file': './application/2010/ipa100701.xml', 'source_data': 'USPTO-Application'}