FIXED CUTTER DRILL BITS WITH TAILORED GAGE PADS FOR DIRECTIONAL DRILLING

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001]This application claims benefit of U.S. provisional patent application Ser. No. 63/700,396 filed Sep. 27, 2024, and entitled “Fixed Cutter Drill Bits with Tailored Gage Pads for Directional Drilling,” which is hereby incorporated herein by reference in its entirety for all purposes.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0002]Not applicable.

FIELD

[0003]The present disclosure relates generally to earth-boring bits used to drill a borehole for the ultimate recovery of oil, gas or minerals. More particularly, the present disclosure relates to fixed cutter drill bits with gage pads having geometries tailored for increased side-cutting in slide mode while maintaining sufficient hold or tracking in rotate mode in direction drilling applications.

BACKGROUND

[0004]An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. The borehole thus created has a diameter generally equal to the diameter or “gage” of the drill bit.

[0005]Fixed cutter bits, also known as rotary drag bits, are one type of drill bit commonly used to drill boreholes. Fixed cutter bit designs include a plurality of blades angularly spaced about a bit face. The blades generally project radially outward along the bit face and form flow channels therebetween. Cutter elements are typically grouped and mounted on the blades. The configuration or layout of the cutter elements on the blades may vary widely, depending on a number of factors. One of these factors is the formation itself, as different cutter element layouts engage and cut the various strata with differing results and effectiveness.

[0006]While the bit is rotated, drilling fluid is pumped through the drill string and directed out of the face of the drill bit. The fixed cutter bit typically includes nozzles or fixed ports spaced about the bit face that serve to inject drilling fluid into the passageways between the several blades. The drilling fluid exiting the face of the bit through nozzles or ports performs several functions. In particular, the fluid removes formation cuttings (for example, rock chips) from the cutting structure of the drill bit. Otherwise, accumulation of formation cuttings on the cutting structure may reduce or prevent the penetration of the drill bit into the formation. In addition, the fluid removes formation cuttings from the bottom of the hole. Failure to remove formation materials from the bottom of the hole may result in subsequent passes by cutting structure to essentially re-cut the same materials, thereby reducing the effective cutting rate and potentially increasing wear on the cutting surfaces of the cutter elements. The drilling fluid flushes the cuttings removed from the bit face and from the bottom of the hole radially outward and then up the annulus between the drill string and the borehole sidewall to the surface. Still further, the drilling fluid removes heat, caused by contact with the formation, from the cutter elements to prolong cutter element life.

[0007]It has become increasingly common in the oil and gas industry to use “directional drilling” techniques to drill horizontal and other non-vertical wellbores, to facilitate more efficient access to and production from larger regions of subsurface hydrocarbon-bearing formations than would be possible using only vertical wellbores. In directional drilling, specialized drill string components and “bottomhole assemblies” (BHAs) are used to induce, monitor, and control deviations in the path of the drill bit, so as to produce a wellbore of desired non-vertical configuration.

[0008]Directional drilling is typically carried out using a “downhole motor” (alternatively referred to as a “mud motor”) incorporated into the drill string immediately above the drill bit. A typical mud motor generally includes a top sub adapted to facilitate connection to the lower end of a drill string, a power section comprising a positive displacement motor of well-known type with a helically-vaned rotor eccentrically rotatable within a stator section, a drive shaft enclosed within a drive shaft housing, with the upper end of the drive shaft being operably connected to the rotor of the power section, and a bearing section comprising a cylindrical mandrel coaxially and rotatably disposed within a cylindrical housing, with an upper end coupled to the lower end of the drive shaft, and a lower end adapted for connection to a drill bit. The mandrel is rotated by the drive shaft, which rotates in response to the flow of drilling fluid under pressure through the power section, while the mandrel rotates relative to the cylindrical housing, which is connected to the drill string. Directional drilling allows the well to be drilled out at an angle. A bent housing motor is used to form a curved well path. The bent housing is often located above the bearing section and below the power section.

[0009]During directional drilling, the driller will typically alternate between a “rotate mode” and a “slide mode” to drill a borehole along a predetermined, generally non-linear or curved trajectory. In the rotate mode, the drill bit is rotated by rotating the drill string (and optionally rotating the downhole bent housing motor), and in the slide mode, the drill bit is rotated exclusively by the downhole bent housing motor (i.e., without rotating the drill string). In the rotate mode, with the drillstring, bent housing motor, and drill bit rotating simultaneously, the drill bit generally drills the borehole along a straight or linear trajectory. However, in the slide mode, with only the drill bit rotating, the drill bit drills the borehole along a trajectory oriented at an acute angle relative to the drill string due to the fixed orientation of the drill bit relative to the drill string (at the acute angle) due to the bent housing motor.

BRIEF SUMMARY

[0010]Embodiments of fixed cutter drill bits for drilling boreholes in earthen formations are disclosed herein. In one embodiment, a fixed cutter drill bit for drilling a borehole in an earthen formation comprises a bit body having a central axis and a bit face. The bit body is configured to rotate about the central axis in a cutting direction of rotation. The bit face comprises a concave cone region extending radially from the central axis, a convex shoulder region extending radially from the cone region, a nose at the intersection of the cone region and the shoulder region, and a gage region extending radially from the shoulder region to a full gage diameter of the drill bit. In addition, the drill bit comprises a cutting structure disposed on the bit face. The cutting structure comprises a primary blade extending radially from proximal the bit axis through the cone region and the shoulder region to the gage region. The blade has a leading side relative to the cutting direction of rotation, a trailing side relative to the cutting direction of rotation, and a cutter-supporting surface extending from the leading side to the trailing side. Further, the drill bit comprises a plurality of cutter elements mounted to the cutter-supporting surface of the primary blade in the cone region, the shoulder region, and the gage region. Still further, the drill bit comprises a gage pad disposed in the gage region and extending axially from the primary blade. The gage pad has a central axis, an uphole end distal the primary blade, a downhole end integral with the primary blade, a leading lateral side relative to the cutting direction of rotation, a trailing lateral side relative to the cutting direction of rotation, and a formation facing surface configured to slidingly engage a sidewall of the borehole during drilling. The formation facing surface of the gage pad extends axially from the uphole end to the downhole end of the gage pad, and wherein the formation facing surface extends laterally from the leading side of the gage pad to the trailing side of the gage pad. The gage pad comprises a surface area reducing feature positioned along a middle portion of the gage pad that is axially positioned between and axially spaced from the uphole end of the gage pad and the downhole end of the gage pad. The surface area reducing feature comprises a first recess extending from the formation facing surface toward the bit body.

[0011]In another embodiment, a fixed cutter drill bit for drilling a borehole in an earthen formation comprises a bit body having a central axis and a bit face. The bit body is configured to rotate about the central axis in a cutting direction of rotation. The bit face includes a concave cone region extending radially from the central axis, a convex shoulder region extending radially from the cone region, a nose at the intersection of the cone region and the shoulder region, and a gage region extending radially from the shoulder region to a full gage diameter of the drill bit. The drill bit also comprises a cutting structure disposed on the bit face. The cutting structure includes a primary blade extending radially from proximal the bit axis through the cone region and the shoulder region to the gage region. The blade has a leading side relative to the cutting direction of rotation, a trailing side relative to the cutting direction of rotation, and a cutter-supporting surface extending from the leading side to the trailing side. In addition, the drill bit comprises a plurality of cutter elements mounted to the cutter-supporting surface of the primary blade. Further, the drill bit comprises a gage pad disposed in the gage region and extending axially from the primary blade. The gage pad has a central axis, an uphole end distal the primary blade, a downhole end integral with the primary blade, a leading lateral side relative to the cutting direction of rotation, a trailing lateral side relative to the cutting direction of rotation, and a formation facing surface configured to slidingly engage a sidewall of the borehole during drilling. The formation facing surface of the gage pad extends axially from the uphole end to the downhole end of the gage pad. The gage pad is I-shaped in side view perpendicular to the central axis of the gage pad.

[0012]Embodiments described herein comprise a combination of features and characteristics intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical characteristics of the disclosed embodiments in order that the detailed description that follows may be better understood. The various characteristics and features described above, as well as others, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes as the disclosed embodiments. It should also be realized that such equivalent constructions do not depart from the spirit and scope of the principles disclosed herein.

BRIEF DESCRIPTION OF THE DRAWINGS

[0013]For a detailed description of various exemplary embodiments, reference will now be made to the accompanying drawings in which:

[0014]FIG. 1 is a schematic view of a drilling system including an embodiment of a fixed cutter drill bit in accordance with the principles described herein;

[0015]FIG. 2 is a perspective view of the drill bit of FIG. 1;

[0016]FIG. 3 is an end view of the drill bit of FIG. 2;

[0017]FIG. 4 is a partial cross-sectional schematic view of the bit shown in FIG. 2 with the blades and the cutting faces of the cutter elements rotated into a single composite profile;

[0018]FIG. 5 is an enlarged side view of one of the gage pads of the drill bit of FIG. 2;

[0019]FIG. 6 is a graphical illustration of the formation contact surface area of the formation facing surfaces of the gage pads of the drill bit of FIG. 2 and the formation contact surface area of the formation facing surfaces of conventional gage pads at different tilt angles of the corresponding drill bits;

[0020]FIG. 7 is a schematic side view of an embodiment of a gage pad in accordance with principles described herein;

[0021]FIG. 8 is a schematic side view of an embodiment of a gage pad in accordance with principles described herein;

[0022]FIG. 9 is a schematic side view of an embodiment of a gage pad in accordance with principles described herein;

[0023]FIG. 10 is a schematic side view of an embodiment of a gage pad in accordance with principles described herein; and

[0024]FIG. 11 is an enlarged partial rear view of an embodiment of a gage pad of fixed cutter drill bit in accordance with the principles described herein.

DETAILED DESCRIPTION

[0025]The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.

[0026]Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing FIGS. are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

[0027]Unless the context dictates the contrary, all ranges set forth herein should be interpreted as being inclusive of their endpoints, and open-ended ranges should be interpreted to include only commercially practical values. Similarly, all lists of values should be considered as inclusive of intermediate values unless the context indicates the contrary.

[0028]In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct engagement between the two devices, or through an indirect connection that is established via other devices, components, nodes, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a particular axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to a particular axis. For instance, an axial distance refers to a distance measured along or parallel to the axis, and a radial distance means a distance measured perpendicular to the axis. Any reference to up or down in the description and the claims is made for purposes of clarity, with “up”, “upper”, “upwardly”, “uphole”, or “upstream” meaning toward the surface of the borehole and with “down”, “lower”, “downwardly”, “downhole”, or “downstream” meaning toward the terminal end of the borehole, regardless of the borehole orientation. As used herein, the terms “approximately,” “about,” “substantially,” and the like mean within 10% (i.e., plus or minus 10%) of the recited value. Thus, for example, a recited angle of “about 80 degrees” refers to an angle ranging from 72 degrees to 88 degrees.

[0029]As previously described, for directional drilling, the driller will typically alternate between the rotate mode and the slide mode to drill the borehole along a predetermined path including both linear and non-linear section(s). In general, the gage pads disposed at the full gage diameter of the drill bit perform different functions in the rotate mode and the slide mode. More specifically, in the rotate mode, the gage pads preferably slidingly engage and bear against the borehole sidewall without cutting into the borehole sidewall to limit lateral movement of the drill bit, which generally results in the drill bit drilling along a substantially straight or linear trajectory. Without being limited by this or any particular theory, the greater the surface area of the gage pads that contacts the borehole sidewall in the rotate mode, the greater the ability of the gage pads to limit the lateral movement of the drill bit and thereby maintain a substantially straight or linear drilling trajectory. On the other hand, in the slide mode, the gage pads preferably cut into the borehole sidewall to build an angle along the borehole and drill along an angled or curved trajectory. Without being limited by this or any particular theory, the lower the surface area of the gage pads that contacts the borehole sidewall in the rotate mode, the greater the ability of the gage pads to cut into the borehole sidewall and thereby build an angle along the borehole to drill along an angled or curved trajectory. Accordingly, embodiments described herein are directed to fixed cutter drill bits including gage pads having tailored geometries to substantially maintain or enhance the contact surface area with the borehole sidewall during the rotate mode (e.g., as compared to similarly sized conventional gage pads), while reducing the contact surface area with the borehole sidewall during the slide mode (e.g., as compared to similarly sized conventional gage pads).

[0030]Referring now to FIG. 1, an embodiment of a directional drilling system 10 is shown. Drilling system 10 is generally configured for drilling a borehole 16 in an earthen formation 5. In the embodiment of FIG. 1, system 10 includes a drilling rig 20 disposed at the surface, a drillstring 21 extending downhole from rig 20, a bottomhole assembly (BHA) 30 coupled to the lower end of drillstring 21, and a drill bit 100 attached to the lower end of BHA 30. A surface or mud pump 23 is positioned at the surface and pumps drilling fluid or mud through drillstring 21. Additionally, rig 20 includes a rotary system 24 for imparting torque to an upper end of drillstring 21 to thereby rotate drillstring 21 in borehole 16. In this embodiment, rotary system 24 comprises a rotary table located at a rig floor of rig 20; however, in other embodiments, rotary system 24 may comprise other systems for imparting rotary motion to drillstring 21, such as a top drive. A downhole mud motor 35 is provided in BHA 30 for facilitating directional drilling (i.e., for drilling of deviated portions of borehole 16). Moving downward along BHA 30, motor 35 includes a hydraulic drive or power section 40, a driveshaft assembly 45, and a bearing assembly 50. In some embodiments, the portion of BHA 30 disposed between drillstring 21 and motor 35 can include other components, such as drill collars, measurement-while-drilling (MWD) tools, reamers, stabilizers and the like.

[0031]Power section 40 of BHA 30 converts the fluid pressure of the drilling fluid pumped downward through drillstring 21 into rotational torque for driving the rotation of drill bit 100. Driveshaft assembly 45 and bearing assembly 50 of mud motor 35 transfer the torque generated in power section 40 to bit 100. With force or weight applied to the drill bit 100, also referred to as weight-on-bit (“WOB”), the rotating drill bit 100 engages the earthen formation and proceeds to form borehole 16 along a predetermined path toward a target zone. The drilling fluid or mud pumped down the drillstring 21 and through BHA 30 passes out of the face of drill bit 100 and back up the annulus 18 formed between drillstring 21 and the sidewall 19 of borehole 16. The drilling fluid cools the bit 100, and flushes the cuttings away from the face of bit 100 and carries the cuttings to the surface.

[0032]Mud motor 35 of BHA 30 includes bent sub or bend 55 along mud motor 35. In this embodiment, bend 55 is provided along bearing assembly 50. Due to bend 55, a deflection or bend angle θ is formed between a central or longitudinal axis 105 of drill bit 100 and the longitudinal axis 25 of drillstring 21. It should also be appreciated that drillstring 21 is substantially coaxially aligned with the central axis of borehole 16, and thus, due to bend 55, central axis 105 of drill bit 100 is oriented at a “resultant” or “tilt” angle relative to the central axis of borehole 16 and the portion of sidewall 19 radially adjacent drill bit 100 that is similar to bend angle θ but may deviate from bend angle θ depending on drilling dynamics.

[0033]To drill a linear or straight section of borehole 16, directional drilling system 10 (and in particular, drillstring 21, BHA 30, and drill bit 100) are operated in a “rotate mode” by rotating drillstring 21 from rig 20 with a rotary table or top drive to rotate BHA 30 and drill bit 100 coupled thereto (mud motor 35 may optionally also be used to rotate drill bit 100). In other words, drillstring 21, BHA 30, and drill bit 100 generally rotated together. In the rotate mode, drillstring 21 and BHA 30 generally rotate about the longitudinal axis 25 of drillstring 21, and thus, drill bit 100 is also forced to rotate about the longitudinal axis 25 of drillstring 21. With bit 100 disposed at bend angle θ, the lower end of drill bit 100 distal BHA 30 seeks to move in an arc about longitudinal axis 25 of drillstring 21 as it rotates, however, such arc remains substantially coaxially aligned with axis 25, thereby enabling drilling of borehole 16 along a linear trajectory. Due to dynamics of movement during rotation of drillstring 21 in rotate mode (e.g., flexion of drillstring 21), the tilt angle of drill bit 100 relative to the central axis of borehole 16 and the portion of sidewall 19 radially adjacent drill bit 100 is greater than 0° but may be slightly less than bend angle θ.

[0034]To build an angle along borehole 16 for drilling a non-linear or curved section of borehole 16, directional drilling system 10 (and in particular, drillstring 21, BHA 30, and drill bit 100) are operated in a “slide mode” by rotating drill bit 100 exclusively with mud motor 35 such that drill string 21 and BHA 30 do not rotate. Accordingly, in the slide mode, drill bit 100 rotates about its central axis 105 relative to drillstring 21 and BHA 30. As previously described, central axis 105 of drill bit 100 is oriented at bend angle θ relative to central axis 25 of drillstring 21 and the sidewall 18 of borehole 16 adjacent drill bit 100, and thus, drill bit 100 generally seeks to drill into sidewall 18 of borehole 16 at a tilt angle that is substantially the same as bend angle θ. In general, the tilt angle of drill bit 100 relative to central axis 25 of drillstring 21 and the sidewall 18 of borehole 16 adjacent drill bit 100 in slide mode is closer to bend angle θ than the tilt angle of drill bit 100 relative to central axis 25 of drillstring 21 and the sidewall 18 of borehole 16 adjacent drill bit 100 in rotate mode. Consequently, the tilt angle of drill bit 100 in slide mode is greater than the tilt angle of drill bit 100 in rotate mode.

[0035]In rotate mode, it is generally preferred to increase the contact surface area between the gage pads and the sidewall 18 of borehole 16 to maintain tracking (i.e., a generally linear drilling trajectory along axis 25 of drillstring 21) by reducing the ability of drill bit 100 to drill laterally into the sidewall 18 of borehole 16; however, in slide mode, it is preferred to decrease the contact surface area between the gage pads and the sidewall 18 of borehole 16 to reduce resistance to the lateral movement of the drill bit 100, thereby enabling drill bit 100 to more easily drill into the sidewall 18 of borehole 16 and build angle more quickly (i.e., a generally non-linear trajectory along axis 25 of drillstring 21). Accordingly, embodiments described herein are directed to drill bits and gage pads thereof that advantageously (i) maintain relatively large contact surface areas with the sidewall of the borehole as compared to conventional gage pads of similar axial lengths at relatively small tilt angles (e.g., during rotate mode) but (ii) provide reduced contact surface areas with the sidewall of the borehole as compared to conventional gage pads of similar axial lengths at relatively large tilt angles (e.g., during slide mode). For purposes of clarity and further explanation, the contact surface area between one or more gage pads of a drill bit and the sidewall of the borehole being drilled by the drill bit may also be referred to herein as the “formation contact surface area.”

[0036]Referring now to FIGS. 2 and 3, drill bit 100 is a fixed cutter bit, sometimes referred to as a drag bit, and is designed for drilling through formation 5 to form borehole 16 (FIG. 1). Bit 100 has a central or longitudinal axis 105, a first or uphole end 100a, and a second or downhole end 100b. Bit 100 rotates about axis 105 in the cutting direction represented by arrow 106. In addition, bit 100 includes a bit body 110 extending axially from downhole end 100b, a threaded connection or pin 120 extending axially from uphole end 100a, and a shank 130 extending axially between pin 120 and body 110. Pin 120 couples bit 100 to a drill string (e.g., drillstring 21 shown in FIG. 1). Bit body 110, shank 130, and pin 120 are coaxially aligned with axis 105, and thus, each has a central axis coincident with axis 105.

[0037]The portion of bit body 110 that faces the formation at downhole end 100b includes a bit face 111 provided with a cutting structure 140. Cutting structure 140 includes a plurality of blades that extend from bit face 111. As best shown in FIG. 3, in this embodiment, cutting structure 140 includes three angularly spaced-apart primary blades 141 and three angularly spaced-apart secondary blades 142. Further, in this embodiment, the plurality of blades (e.g., primary blades 141 and secondary blades 142) are uniformly angularly spaced on bit face 111 about bit axis 105. In particular, the three primary blades 141 and the three secondary blades 142 (a total of five blades 141, 142) are uniformly angularly spaced about 60° apart. In other embodiments, one or more of the blades may be spaced non-uniformly about bit face 111. Still further, in this embodiment, each secondary blade 142 is disposed between a pair of circumferentially-adjacent primary blades 141. Although bit 100 is shown as having three primary blades 141 and three secondary blades 142, in general, bit 100 may comprise any suitable number of primary and secondary blades. As one example only, bit 100 may comprise two primary blades and four secondary blades, or three primary blades and two secondary blades.

[0038]Referring still to FIGS. 2 and 3, in this embodiment, primary blades 141 and secondary blades 142 are integrally formed as part of, and extend from, bit body 110 and bit face 111. Primary blades 141 and secondary blades 142 extend generally radially along bit face 111 and then axially along a portion of the periphery of bit 100. In particular, primary blades 141 extend radially from proximal central axis 105 toward the periphery of bit body 110. Primary blades 141 and secondary blades 142 are separated by drilling fluid flow courses 143. Each blade 141, 142 has a leading edge or side 141a, 142a, respectively, and a trailing edge or side 141b, 142b, respectively, relative to the cutting direction of rotation 106 of bit 100.

[0039]Each blade 141, 142 includes a cutter-supporting surface 144 that generally faces the formation during drilling and extends circumferentially from the leading side 141a to the trailing side 142 of the corresponding blade 141, 142. A plurality of cutter elements 150 are fixably attached to each blade 141, 142 and extend from cutter-supporting surface 144 of each blade 141, 142. In this embodiment, on each secondary blade 142, cutter elements 150 are generally arranged adjacent one another in a radially extending row proximal the leading side 142a; and on each primary blade 141, a first plurality of cutter elements 150 are generally arranged adjacent one another in a radially extending row proximal the leading side 141a, and a second plurality of cutter elements 150 are generally adjacent one another in a radially extending row circumferentially positioned between the first plurality of cutter elements 150 and the trailing side 141b. Thus, on each primary blade 141, the first plurality of cutter elements 150 define a “leading” row and the second plurality of cutter elements 150 define a “trailing” row relative to the direction of bit rotation 106. However, in other embodiments, the cutter elements (e.g., cutter elements 150) may be arranged differently.

[0040]Each cutter element 150 is received and secured in a mating pocket formed in cutter-supporting surface 144 of the corresponding blade 141, 142 to which it is mounted. More specifically, each cutter element 150 includes an elongated and generally cylindrical support base or substrate 151 and a cylindrical disk or tablet-shaped, hard cutting layer 152 bonded to the exposed end of substrate 151. Each substrate 151 is seated in a corresponding pocket in cutter-supporting surface 144 of the corresponding blade 141, 142 and fixably mounted to the corresponding blade 141, 142 (e.g., via brazing). Each cutting layer 152 is disposed at the leading end of the corresponding substrate 151. Substrates 151 are made of a carbide material such as tungsten carbide, and cutting layers 152 are made of polycrystalline diamond or other superabrasive material. The cylindrical disc, hard cutting layer 152 defines a cutting face 153 of the corresponding cutter element 150. In this embodiment, each cutting face 153 is the same and is planar. However, in other embodiments, one or more cutting faces (e.g., cutting faces 153) may not be completely planar, but rather, be non-planar. As used herein, the phrase “non-planar”may be used to refer to a cutting face that includes one or more curved surfaces (for example, concave surface(s), convex surface(s), or combinations thereof), a plurality of distinct planar surfaces that intersect at distinct edges along the cutting face, or both.

[0041]In the embodiments described herein, each cutter element 150 is mounted such its central axis is oriented substantially parallel to or at an acute angle relative to the cutting direction of the bit (for example, cutting direction 106 of bit 100). Such orientation results in the corresponding cutting face 153 being generally forward-facing relative to the cutting direction of the bit (for example, cutting direction 106 of bit 100). The portion of cutting face 153 of each cutter element 150 positioned furthest from the cutter-supporting surface 144 of the corresponding blade 141, 142 as measured perpendicular to the corresponding cutter-supporting surface 144 defines a cutting tip of cutting face 153. Each cutter element 150 has an exposure or extension height measured perpendicularly from cutter-supporting surface 144 of the corresponding blade 141, 142 to the corresponding cutting tip.

[0042]Referring still to FIGS. 2 and 3, bit body 110 further includes gage pads 200 of substantially equal axial length measured generally parallel to bit axis 105. Gage pads 200 are circumferentially-spaced about the radially outer surface of bit body 110. Specifically, one gage pad 200 intersects and extends from the uphole end of each blade 141, 142. In this embodiment, gage pads 200 are integrally formed as part of the bit body 110. Gage pads 200 function to maintain the size of the borehole 16, stabilize bit 100 against vibration, maintain the linear trajectory of drill bit 100 in rotate mode, and cut laterally into sidewall 18 of borehole 16 (FIG. 1) to build an angle in borehole 16 (i.e., to drill a non-linear or curved portion of borehole 160) in slide mode.

[0043]Referring now to FIG. 4, an exemplary profile of blades 141, 142 (right side of FIG. 4) and an exemplary profile of cutting faces 153 (left side of FIG. 4) are shown as each would appear with blades 141, 142 and cutting faces 153 rotated into a single rotated profile. In rotated profile view, blades 141, 142 form a combined or composite blade profile 148a generally defined by cutter-supporting surfaces 144 of blades 141, 142, and the cutting tips of cutting faces 153 form a combined or composite cutting face profile 148b generally defined by a line passing through the cutting tips of cutting faces 153. In this embodiment, the profiles of surfaces 144 of blades 141, 142 are generally coincident with each other, thereby forming a single composite blade profile 148a; and the cutting tips of cutting faces 153 on different blades 141, 142 are generally disposed along the generally smooth and continuous cutting profile 148b. As shown in FIG. 4, profiles 148a, 148b have a similar shape and are generally parallel to each other when rotated into a single profile.

[0044]Composite blade profile 148a and bit face 111 may generally be divided into three regions conventionally labeled cone region 149a, shoulder region 149b, and gage region 149c. Cone region 149a is the radially innermost region of bit body 110 and composite blade profile 148a that extends from bit axis 105 to shoulder region 149b. In this embodiment, cone region 149a is generally concave. Adjacent cone region 149a is generally convex shoulder region 149b. The transition between cone region 149a and shoulder region 149b, referred herein to as the nose 149d, occurs at the axially outermost portion of composite blade profile 148a (relative to bit axis 105) where a tangent line to the blade profile 148a has a slope of zero. Moving radially outward, adjacent shoulder region 149b is the gage region 149c, which extends substantially parallel to bit axis 105 at the outer radial periphery of composite blade profile 148a. As shown in composite blade profile 148a, gage pads 200 generally define the gage region 149c and the outer radius R₁₁₀ of bit body 110. Gage pads 200 and outer radius R₁₁₀ extend to and defines the full gage diameter of bit 100.

[0045]Referring briefly to FIGS. 3 and 4, moving radially outward from bit axis 105, bit 100 and bit face 111 include cone region 149a, shoulder region 149b, and gage region 149c as previously described. Primary blades 141 extend radially along bit face 111 from within cone region 149a proximal bit axis 105 toward gage region 149c and outer radius R₁₁₀. Secondary blades 142 extend radially along bit face 111 from cone region 149a proximal nose 149d toward gage region 149c and outer radius R₁₁₀. Thus, in this embodiment, each primary blade 141 and each secondary blade 142 extends substantially to gage region 149c. Although a specific embodiment of bit body 110 has been shown in described, one skilled in the art will appreciate that numerous variations in the size, orientation, and locations of the blades (for example, primary blades 141, secondary blades, 142, etc.), cutter element assemblies (for example, cutter elements 150), and cutter elements (e.g., cutter elements 230′) are possible.

[0046]Bit 100 includes an internal plenum extending axially from uphole end 100a through pin 120 and shank 130 into bit body 110. The plenum allows drilling fluid to flow from the drill string into bit 100. Body 110 is also provided with a plurality of flow passages extending from the plenum to downhole end 100b. As best shown in FIGS. 2 and 3, a nozzle 108 is seated in the lower end of each flow passage. Together, the plenum, passages, and nozzles 108 serve to distribute drilling fluid around cutting structure 140 to flush away formation cuttings and to remove heat from cutting structure 140, and more particularly cutter elements 150 during drilling.

[0047]Referring now to FIG. 5, one gage pad 200 will be described, it being understood the other gage pads 200 are the same. As previously described, gage pad 200 extends radially outwardly from bit body 110. In this embodiment, gage pad 200 has a central or longitudinal axis 205, a first or uphole end 200a, a second or downhole end 200b, a pair of circumferentially-spaced lateral sides 201, 202 extending axially (relative to pad axis 205) from uphole end 200a to downhole end 200b, and a radially outer (relative to pad axis 205) formation facing surface 210 generally distal bit body 110. In general, gage pad 200 may be oriented parallel to bit axis 105 such that central axis 205 of gage pad 200 is parallel to bit axis 105 as viewed perpendicular to formation facing surface 210 (i.e., in side as shown in FIG. 5), or gage pad 200 may be oriented at an acute angle α relative to bit axis 105 as viewed perpendicular to formation facing surface 210 (i.e., in side as shown in FIG. 5). In the embodiment of gage pad 200 shown in FIG. 5, central axis 205 of gage pad 200 is oriented at an acute angle α relative to bit axis 105 as viewed perpendicular to formation facing surface 210 (i.e., in side as shown in FIG. 5).

[0048]In this embodiment, uphole end 200a is defined by a planar surface 203 extending generally radially outward and axially downward (relative to bit axis 105) from bit body 110 to formation facing surface 210, and downhole end 200b is contiguous and integral with the uphole end of the corresponding blade 141. Central axis 205 of blade 200 intersects planar surface 203. Relative to the direction of rotation 106, lateral side 201 leads lateral side 202, and thus, lateral side 201 may also be referred to as leading side 201 and lateral side 202 may be described as trailing side 202. Each side 201, 202 extends radially outward (relative to bit axis 105) from bit body 110 to formation facing surface 210. In this embodiment, lateral sides 201, 202 are defined by planar surfaces oriented parallel to each other. In addition, in this embodiment, a convex (bowed outwardly) transition surface is provided at the intersection of each side 201, 202 and formation facing surface 210, and a concave (bowed inwardly) transition surface is provided at the intersection of each side 201, 202 and bit body 110.

[0049]Referring still to FIG. 5, formation facing surface 210 extends circumferentially (relative to bit axis 105) from leading side 201 to trailing side 202, and extends axially (relative to pad axis 205) from uphole end 200a to downhole end 200b. During drilling operations, formation facing surface 210 generally engages, slides across, and bears against the sidewall 18 of borehole 16 (FIG. 1). Gage pad 200 and formation facing surface 210 may be described as having a length L₂₀₀ measured axially (relative to pad axis 205) from uphole end 200a to downhole end 200b, and a width W₂₀₀ measured circumferentially (relative to bit axis 105) and laterally (relative to pad axis 205) in side view (as viewed perpendicular to formation facing surface 210) from leading side 201 to trailing side 202.

[0050]In this embodiment, gage pad 200 includes a plurality of recesses 221, 222 disposed along formation facing surface 210. Each recess 221, 222 extends radially (relative to bit axis 105) from formation facing surface 210 toward bit body 110. As compared to a gage pad that is identical to gage pad 200 but not including recesses 221, 222, the total surface area of formation facing surface 210 of blade 200 is reduced due to the presence of recesses 221, 222, and in particular, is reduced along the axial sections or portions of formation facing surface 210 where recesses 221, 222 are positioned. Accordingly, each recess 221, 222 may also be described as a “surface area reducing feature.”

[0051]In this embodiment, one recess 221, 222 is disposed along each lateral side 201, 202, respectively. Namely, recess 221 is disposed along leading side 201 and recess 222 is disposed along trailing side 202. Each recess 221, 222 is axially positioned (relative to pad axis 205) between ends 200a, 200b, extends laterally (relative to pad axis 205) from side 201, 202, respectively, toward central axis 205 in side view (FIG. 5), and extends radially (relative to bit axis 105) from formation facing surface 210 toward bit body 110. In this embodiment, recesses 221, 222 are positioned proximal the middle of gage pad 200 (relative to pad axis 205 and axial length L₂₀₀) and are substantially equidistant from each end 200a, 200b. In other words, in this embodiment, recesses 221, 222 are axially centered (relative to pad axis 205 and axial length L₂₀₀) along blade 205.

[0052]In this embodiment, each recess 221, 222 is generally rectangular and is defined by an uphole planar surface 223a proximal uphole end 200a, a downhole planar surface 223b proximal downhole end 200b, and a base planar surface 223c extending axially (relative to bit axis 105) from uphole planar surface 223a to downhole planar surface 223b. Each planar surface 223a, 223b extends laterally from the corresponding lateral side 201, 202 toward central axis 205 in side view, and extends radially (relative to bit axis 105) and perpendicularly from formation facing surface 210 toward bit body 110. Base planar surfaces 223c extend radially (relative to bit axis 105) and perpendicularly from formation facing surface 210 toward bit body 110. In this embodiment, a concave (bowed inwardly) transition surface is provided at the intersection of each planar surface 223a, 223b and the corresponding base surface 223c.

[0053]As recesses 221, 222 extend into formation facing surface 210, recesses 221, 222 reduce the total surface area of formation facing surface 210 along the portion or region of gage pad 200 where recesses 221, 222 are positioned as previously described. In this embodiment, recesses 221, 222 are axially disposed along a middle portion of gage pad 200 between ends 200a, 200b, and thus, reduce the surface area of such axially middle portion of gage pad 200 (as compared to the identical gage pad without recesses 221, 222). More specifically, gage pad 200 may be described as including a first or uphole portion 230 extending axially (relative to pad axis 205) from upper end 200a to recesses 221, 222, a second or downhole portion 231 extending axially (relative to pad axis 205) from lower end 200b to recesses 221, 222, and a middle portion 232 containing recesses 221, 222 and extending axially (relative to pad axis 205) from uphole portion 230 to downhole portion 231. As previously described, recesses 221, 222 are equidistant from ends 200a, 200b, and thus, middle portion 232 is axially centered along gage pad 200 and length L₂₀₀. Due to the position of recesses 221, 222 along middle portion 232 of gage pad 200, the width W₂₀₀ of formation facing surface 210 and gage pad 200 is reduced along middle portion 232 as compared to uphole portion 230 and downhole portion 231, and thus, formation facing surface 210 and gage pad 200 have generally I-shaped or dog bone shaped geometries in side view. In addition, due to the position of recesses 221, 222 along middle portion 232, the surface area per unit axial length L₂₀₀ of formation facing surface 210 is the same along uphole portion 230 and downhole portion 231, but is reduced along middle portion 232.

[0054]As previously described, embodiments described herein are directed to drill bits and gage pads thereof that advantageously (i) maintain relatively large formation contact surface areas as compared to similarly sized conventional gage pads at relatively small tilt angles (e.g., during rotate mode) but (ii) provide reduced formation contact surface areas as compared to similarly sized conventional gage pads at relatively large tilt angles (e.g., during slide mode). More specifically, in this embodiment, formation facing surface 210 of each gage pad 200 of drill bit 100 is oriented parallel to central axis 105 and entirely disposed at the full gage diameter of drill bit 100, and thus, engage the sidewall 18 of borehole 16 while drilling in both rotate mode and slide mode. Due to the tilt angle of drill bit 100 in both rotate mode and slide mode, varying portions of formation facing surfaces 210 of gage pads 200 will contact the sidewall 18 (depending, at least in part, on the tilt angle of drill bit 100 and the rotational position of the gage pad 200 at any given time). Inclusion of surface area reducing features such as recesses 221, 222 along middle portions 232 of gage pads 200 (as opposed to uphole and downhole portions 230, 231 of gage pads 200) offer the potential to advantageously (i) maintain substantially the same formation contact surface area as compared to an identical gage pad without recesses 221, 222 at relatively low tilt angles of drill bit 100 during rotate mode, and (ii) reduce the formation contact surface area as compared to an identical gage pad without recesses 221, 222 at relatively high tilt angles of drill bit 100 during slide mode. For example, drilling simulations of drill bit 100 and a conventional drill bit that was the same as drill bit 100 but without any contact surface area reducing features (i.e., without recesses 221, 222) were run at different tilt angles. During the simulations, at each tilt angle, the total formation contact surface area between formation facing surfaces 210 of gage pads 200 was determined, and the total formation contact surface area between the formation facing surfaces of gage pads of the conventional bit was determined. FIG. 6 illustrates the results of the simulations, and in particular, illustrates (a) the total formation contact surface area of formation facing surfaces 210 of gage pads 200 of drill bit 100 at each tilt angle; (b) the total formation contact surface area between the formation facing surfaces of the gage pads of the conventional bit at each tilt angle; and (c) the % difference between the total formation contact surface area of formation facing surfaces 210 of gage pads 200 and the total formation contact surface area between the formation facing surfaces of the gage pads of the conventional bit at each tilt angle. As shown in FIG. 6, at the relatively low tilt angles simulated (ranging from 0.1° to 0.2°), which are typical of tilt angles during rotate mode, the total formation contact surface area of formation facing surfaces 210 of gage pads 200 was substantially the same as the total formation contact surface area of the formation facing surfaces of the gage pads of the conventional drill bit; however, at the relatively high tilt angles simulated (ranging from 0.3° to 1.0°), which are typical of tilt angles during slide mode, the total formation contact surface area of formation facing surfaces 210 of gage pads 200 was increasingly less than the total formation contact surface area of the formation facing surfaces of the gage pads of the conventional drill bit as the tilt angle increased.

[0055]In the embodiment of drill bit 100 previously described, lateral sides 201, 202 of each gage pad 200 are defined by parallel planar surfaces, and the contact surface area reducing features disposed along middle portion 232 of gage pads 200 comprise recesses 221, 222 extending laterally from lateral sides 201, 202 and radially from formation facing surface 210. However, in other embodiments, the gage pads and/or the contact surface area reducing features may have different geometries. For example, referring now to FIG. 7, an embodiment of a gage pad 300 that can be used in place of any one or more gage pads 200 on bit 100 is shown. Gage pad 300 is substantially the same as gage pad 200 previously described with the exception of the orientations of the planar surfaces defining the lateral sides. In particular, gage pad 300 has a central or longitudinal axis 305, a first or uphole end 300a, a second or downhole end 300b, a pair of lateral sides 301, 302 extending axially (relative to axis 305) from uphole end 300a to downhole end 300b, and a radially outer formation facing surface 310 distal the bit body of the corresponding drill bit on which gage pad 300 is disposed. In addition, gage pad 300 includes a plurality of surface area reducing features comprising recesses 321, 322 disposed along formation facing surface 310 and extending radially (relative to the bit axis) from formation facing surface 310 toward the bit body of the corresponding drill bit on which gage pad 300 is disposed. Ends 300a, 300b, formation facing surface 310, and recesses 321, 322 are the same as ends 200a, 200b, formation facing surface 210, and recesses 221, 222, respectively, as previously described. In addition, sides 301, 302 are substantially the same as sides 201, 202 as previously described with the exception that the planar surfaces defining sides 301, 302 are not oriented parallel to each other, but rather, taper away each other moving axially from uphole end 300a to downhole end 300b. Accordingly, the width of gage pad 300 measured perpendicular to central axis 305 between sides 301, 302 in side view generally increases moving axially from uphole end 300a to downhole end 300b.

[0056]Due to the foregoing geometry of gage pad 300 and similar to gage pad 200 previously described, gage pad 300 may be described as including a first or uphole portion 330 extending axially from upper end 300a to recesses 321, 322, a second or downhole portion 331 extending axially from lower end 300b to recesses 321, 322, and a middle portion 332 containing recesses 321, 322 and extending axially from uphole portion 330 to downhole portion 331. Gage pad 300 generally functions similar to and offers the potential to provide similar benefits as gage pad 200 previously described.

[0057]Referring now to FIG. 8, an embodiment of a gage pad 400 that can be used in place of any one or more gage pads 200 on bit 100 is shown. Gage pad 400 is substantially the same as gage pad 300 previously described with the exception that the planar surfaces defining the lateral sides taper toward each other moving from the uphole end to the downhole end. In particular, gage pad 400 has a central or longitudinal axis 405, a first or uphole end 400a, a second or downhole end 400b, a pair of lateral sides 401, 402 extending axially (relative to axis 405) from uphole end 400a to downhole end 400b, and a radially outer formation facing surface 410 distal the bit body of the corresponding drill bit on which gage pad 400 is disposed. In addition, gage pad 400 includes a plurality of surface area reducing features comprising recesses 421, 422 disposed along formation facing surface 410 and extending radially (relative to the bit axis) from formation facing surface 410 toward the bit body of the corresponding drill bit on which gage pad 400 is disposed. Ends 400a, 400b, formation facing surface 410, and recesses 421, 422 are the same as ends 300a, 300b, formation facing surface 310, and recesses 321, 322, respectively, as previously described. In addition, sides 401, 402 are substantially the same as sides 301, 302 as previously described with the exception that the planar surfaces defining sides 401, 402 taper toward each other moving axially from uphole end 400a to downhole end 400b. Accordingly, the width of gage pad 400 measured perpendicular to central axis 405 between sides 401, 402 in side view generally decreases moving axially from uphole end 400a to downhole end 400b.

[0058]Due to the foregoing geometry of gage pad 400 and similar to gage pad 200 previously described, gage pad 400 may be described as including a first or uphole portion 430 extending axially from upper end 400a to recesses 421, 422, a second or downhole portion 431 extending axially from lower end 400b to recesses 421, 422, and a middle portion 432 containing recesses 421, 422 and extending axially from uphole portion 430 to downhole portion 431. Gage pad 400 generally functions similar to and offers the potential to provide similar benefits as gage pad 200 previously described.

[0059]Referring now to FIG. 9, an embodiment of a gage pad 500 that can be used in place of any one or more gage pads 200 on bit 100 is shown. Gage pad 500 is substantially the same as gage pad 200 previously described with the exception that gage pad 500 includes a surface area reduction feature different from recesses 221, 222. In particular, gage pad 500 has a central or longitudinal axis 505, a first or uphole end 500a, a second or downhole end 500b, a pair of lateral sides 501, 502 extending axially (relative to axis 505) from uphole end 500a to downhole end 500b, and a radially outer formation facing surface 510 distal the bit body of the corresponding drill bit on which gage pad 500 is disposed. Ends 500a, 500b, formation facing surface 510, and lateral sides 501, 502 are the same as ends 200a, 200b, formation facing surface 210, and lateral sides 201, 202, respectively, as previously described. However, in this embodiment, gage pad 500 does not include recesses 221, 222 extending laterally from sides 501, 502. Rather, in this embodiment, gage pad 500 includes a surface area reducing feature comprising a single recess 521 extending radially (relative to the bit axis and central axis 505) from formation facing surface 510 toward the bit body of the bit on which gage pad 500 is disposed. In this embodiment, recess 521 is axially positioned between and axially spaced apart from ends 500a, 500b, and is laterally positioned between and laterally spaced apart from sides 501, 502. Thus, recess 521 does not does not extend from or intersect latera sides 501 502.

[0060]Due to the foregoing geometry of gage pad 500 and similar to gage pad 200 previously described, gage pad 500 may be described as including a first or uphole portion 530 extending axially from upper end 500a to recess 521, a second or downhole portion 531 extending axially from lower end 500b to recess 521, and a middle portion 532 containing recess 521 and extending axially from uphole portion 530 to downhole portion 531. Gage pad 500 generally functions similar to and offers the potential to provide similar benefits as gage pad 200 previously described.

[0061]Referring now to FIG. 10, an embodiment of a gage pad 600 that can be used in place of any one or more gage pads 200 on bit 100 is shown. Gage pad 600 is substantially the same as gage pad 200 previously described with the exception that gage pad 600 includes a surface area reduction feature different from recesses 221, 222. In particular, gage pad 600 has a central or longitudinal axis 605, a first or uphole end 600a, a second or downhole end 600b, a pair of lateral sides 601, 602 extending axially (relative to axis 605) from uphole end 600a to downhole end 600b, and a radially outer formation facing surface 610 distal the bit body of the corresponding drill bit on which gage pad 600 is disposed. Ends 600a, 600b, formation facing surface 610, and lateral sides 601, 602 are the same as ends 200a, 200b, formation facing surface 210, and lateral sides 201, 202, respectively, as previously described. However, in this embodiment, gage pad 600 does not include recesses 221, 222 extending laterally from sides 601, 602. Rather, in this embodiment, gage pad 600 includes a surface area reducing feature comprising a plurality of recesses 621 extending radially (relative to the bit axis and central axis 605) from formation facing surface 610 toward the bit body of the bit on which gage pad 600 is disposed. In this embodiment, recesses 621 are axially positioned between and axially spaced apart from ends 600a, 600b, and are laterally positioned between and laterally spaced apart from sides 601, 602. Thus, none of recesses 621 extend from or intersect latera sides 601 602.

[0062]Due to the foregoing geometry of gage pad 600 and similar to gage pad 200 previously described, gage pad 600 may be described as including a first or uphole portion 630 extending axially from upper end 600a to recesses 621, a second or downhole portion 631 extending axially from lower end 600b to recess 621, and a middle portion 632 containing recess 621 and extending axially from uphole portion 630 to downhole portion 631. Gage pad 600 generally functions similar to and offers the potential to provide similar benefits as gage pad 200 previously described.

[0063]In the embodiment of drill bit 100 previously described, formation facing surface 210 of each gage pad 200 extends to the full gage diameter, and in particular, formation facing surface 210 of each gage pad 200 is oriented parallel to central axis 105 of drill bit 100 and extends to the full gage diameter of bit 100 along the entire axial length L₂₀₀ of the gage pad 200. As a result, the entirety of the formation facing surface 210 of each gage pad 200 is disposed at the same radius relative to bit axis 105. However, in other embodiments, the formation facing surface of one or more gage pads (e.g., formation facing surface 210 of one or more gage pad 200) may taper radially inwardly relative to the bit axis (e.g., bit axis 105) such that the formation facing surface is not oriented parallel to the central axis of the corresponding drill bit and the entirety of the formation facing surface is not disposed at the full gage diameter of the bit, and thus, is not disposed at the same radius relative to the bit axis. For example, referring now to FIG. 11, an embodiment of a gage pad 700 of a fixed cutter drill bit having a bit body 110 and central axis 105 as previously described is shown. In general, gage pad 700 can be used in place of one or more gage pads 200 of drill bit 100. Gage pad 700 is the same as gage pad 200 previously described with the exception that the formation facing surface 210 of gage pad 200 tapers radially inward, and thus, formation facing surface 210 is not oriented parallel to central axis 105 of the corresponding drill bit and the entirety of formation facing surface 210 is not disposed at the full gage diameter of the bit. More specifically, as shown in FIG. 11, formation facing surface 210 of gage pad 700 extends circumferentially (relative to bit axis 105) from leading side 201 to trailing side 202, and extends axially (relative to pad axis 205) from uphole end 200a to downhole end 200b and a corresponding blade 141. However, in this embodiment, formation facing surface 210 slopes or tapers radially inwardly (relative to bit axis 105) moving axially (relative to pad axis 205) from downhole end 200b to uphole end 200a. As a result, formation facing surface 210 is oriented at an acute angle β relative to bit axis 105 as shown in the rear view of gage pad 210 perpendicular to trailing surface 202 of FIG. 5. In embodiments described herein where the formation facing surface of the gage pad (e.g., formation facing surface 210 of gage pad 700) slopes or taper radially inwardly toward the bit axis (e.g., bit axis 105), the acute angle β measured between the formation facing surface of the gage pad and the bit axis in front or rear view of the gage pad perpendicular to the leading or trailing side of the gage pad (e.g., leading side 201 or trailing side 202) is greater than 0° and less than 10°. Accordingly, at or proximal downhole end 200b, formation facing surface 210 is disposed at the full gage diameter of the corresponding drill bit, however, at uphole end 200a, formation facing surface 210 is radially offset or spaced from the full gage diameter of the corresponding drill bit.

[0064]Gage pad 700 generally functions in the same manner as gage pad 200 previously described by advantageously (i) maintaining relatively large formation contact surface areas as compared to similarly sized conventional gage pads at relatively small tilt angles (e.g., during rotate mode) but (ii) providing reduced formation contact surface areas as compared to similarly sized conventional gage pads at relatively large tilt angles (e.g., during slide mode). Formation facing surface 210 of gage pad 700 engages the sidewall 18 of borehole 16 while drilling in both rotate mode and slide mode. However, due to formation facing surface 210 being oriented at acute angle β relative to bit axis 105, the change in the surface area of formation facing surface 210 of gage pad 700 that engages the sidewall 18 as the corresponding drill bit transitions between relatively small tilt angles (e.g., during rotate mode) and relatively large tilt angles (e.g., during slide mode) is more gradual.

[0065]While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the disclosure. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.