Patent Publication Number: US-2012031671-A1

Title: Drill Bits With Rolling Cone Reamer Sections

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     Not applicable. 
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not Applicable. 
     BACKGROUND 
     1. Field of the Invention 
     The invention relates generally to earth-boring bits used to drill a borehole for the ultimate recovery of oil, gas or minerals. More particularly, the invention relates to drill bits for enlarging the diameter of an earthen borehole. Still more particularly, the invention relates to rolling cone underreamers used to open a hole below a restriction so that the opened hole is larger than the restriction itself. 
     2. Background of the Technology 
     In the drilling of oil and gas wells, concentric casing strings are installed and cemented in the borehole as drilling progresses to increasing depths. Each new casing string is supported within the previously installed casing string, thereby limiting the annular area available for the cementing operation. Further, as successively smaller diameter casing strings are suspended, the flow area for the production of oil and gas is reduced. Therefore, to increase the annular space for the cementing operation, and to increase the production flow area, it is often desirable to enlarge the borehole below the terminal end of the previously cased borehole. By enlarging the borehole, a larger annular area is provided for subsequently installing and cementing a larger casing string than would have been possible otherwise. Accordingly, by enlarging the borehole below the previously cased borehole, the bottom of the formation can be reached with comparatively larger diameter casing, thereby providing more flow area for the production of oil and gas. 
     Drill bits which drill holes through earth formations where the hole has a larger diameter than the bit&#39;s pass-through diameter (the diameter of an opening through which the bit can freely pass) are known in the art. Early types of such bits included so-called “underreamers”, which were essentially a drill bit having an axially elongated body and extensible arms on the side of the body which reamed the wall of the hole after cutters on the end of the bit had drilled the earth formations. Mechanical difficulties with the extensible arms limited the usefulness of underreamers. 
     More recently, so-called “bi-centered” drill bits have been developed. A typical bi-centered drill bit includes a “pilot” section located at the end of the bit, and a “reaming” section which is typically located at some axial distance from the end of the bit (and consequently from the pilot section). Bi-centered bits drill a hole larger than their pass through diameters because the axis of rotation of the bit is displaced from the geometric center of the bit. This arrangement enables the reaming section to cut the wall of the hole at a greater radial distance from the rotational axis than is the radial distance of the reaming section from the geometric center of the bit. In many conventional bi-centered bits, the pilot section comprises a fixed cutter or PDC bit attached to the end of the bit. The reaming section is usually axially spaced away from the end of the bit, and is disposed to one side of the bit. The reaming section typically includes a number of PDC inserts on blades on the side of the bit body in the reaming section. 
       FIGS. 1 and 2  illustrate an example of a conventional PDC bi-center bit  10  that includes a bit body  11  with a threaded pin  12  at one end for connection to a drill string, and a pilot section  20  defining an operating end face  13  opposite pin  12 . Pilot section  20  includes a plurality of pilot blades  21  having a plurality of cutter elements  22  mounted thereon, and includes gauge pads  23  at the ends of the pilot blades  21  distal the lower end of the bit  10 . A reamer section  30  is integrally formed with the body  11  between the pin  12  and the pilot section  20 . Reaming section  30  includes a plurality of reaming blades  31  that are eccentrically positioned above pilot section  20 . Reamer blades  31  also have cutter elements  32  mounted thereon and gauge pads  33  similar to those on the pilot section  20 . 
     Cutter elements  22 ,  32  are typically formed of extremely hard materials. In the typical PDC bi-center bits, each cutter element comprises an elongate and generally cylindrical tungsten carbide support member which is received and secured in a pocket formed in the surface of one of the several blades. The cutter element typically includes a hard cutting layer of polycrystalline diamond (PD) or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide (meaning a tungsten carbide material having a wear-resistance that is greater than the wear-resistance of the material forming the substrate) as well as mixtures or combinations of these materials. For convenience, as used herein, reference to “PDC cutter element” refers to a cutter element employing a hard cutting layer of polycrystalline diamond or other superabrasive material. 
     Blades  31  radiate from the bit body  11  but are only positioned about a selected portion or quadrant of bit  10  when viewed in end cross section. Accordingly, bit  10  may be tripped into a hole marginally greater than a pass through diameter D pt , yet be able to drill an enlarged borehole having a diameter D b  that is substantially greater than the pass through diameter D pt . 
     For most conventional PDC bi-center bits, the reamer section represents the portion of the bit most susceptible to pre-mature wear and damage. Specifically, to achieve a pass through diameter that is less than the diameter of the enlarged hole to be drilled, the reamer blades are only positioned about a selected portion or quadrant of the bit body. In other words, the reamer blades are not disposed about the entire circumference of the bit. Due to such space limitations, most conventional PDC bi-centered bits only include two to four reamer blades. Consequently, the total space available on all the reamer blades for mounting cutter elements is also limited, and hence, for a given sized cutter element, the number of cutter elements in the reamer section is also limited. Furthermore, the cutter elements on the reamer blades continuously engage the formation as the bit is rotated. Due to the limited number of cutter, the cutting loads experienced by reamer section is spread out among fewer total cutter elements, thereby tending to increase the cutting load experienced by each cutter element in the reamer section as well as the associated wear. 
     Without regard to the type of bit, the cost of drilling a borehole for recovery of hydrocarbons may be very high, and is proportional to the length of time it takes to drill to the desired depth and location. The time required to drill the well, in turn, is greatly affected by the number of times the drill bit must be changed before reaching the targeted formation. This is the case because each time the bit is changed, the entire string of drill pipe, which may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. As is thus obvious, this process, known as a “trip” of the drill string, requires considerable time, effort and expense. Accordingly, it is desirable to employ drill bits which will drill faster and longer, and which are usable over a wider range of formation hardness. 
     The length of time that a drill bit may be employed before it must be changed depends upon a variety of factors. These factors include the bit&#39;s rate of penetration (“ROP”), as well as its durability or ability to maintain a high or acceptable ROP. 
     Increasing ROP while simultaneously increasing the service life of the drill bit will decrease drilling time and allow valuable oil and gas to be recovered more economically. Accordingly, drill bits for enlarging a borehole diameter that enable increased ROP and longer bit life would be particularly desirable. 
     BRIEF SUMMARY 
     These and other needs in the art are addressed in one embodiment by a drill bit for drilling a borehole in earthen formations. In an embodiment, the bit comprises a bit body having a central bit axis, a first end adapted to be connected to a drillstring, and a second end opposite the first end. In addition, the bit comprises a pilot bit extending from the second end of the bit body. Further, the bit comprises a reamer section extending radially from the bit body and axially positioned between the first end of the bit body and the pilot bit. The reamer section comprises a rolling cone cutter rotatably mounted to a journal shaft extending from the bit body. Moreover, the rolling cone cutter has a cone axis of rotation, a backface proximal the bit body, and a nose opposite the backface and distal the bit body. 
     These and other needs in the art are addressed in another embodiment by a drill bit for drilling a borehole in earthen formations. In an embodiment, the bit comprises a bit body having a central bit axis, a first end adapted to be connected to a drillstring, and a second end opposite the first end. In addition, the bit comprises a pilot bit extending from the second end of the bit body. Further, the bit comprises a reamer section extending radially from the bit body and axially positioned between the first end of the bit body and the pilot bit. The reamer section comprises a plurality of outwardly facing rolling cone cutters, each rolling cone cutter rotatably mounted to a journal shaft extending from the bit body. 
     These and other needs in the art are addressed in another embodiment by a method for drilling a wellbore in an earthen formation. In an embodiment, the method comprises (a) rotating a drill bit coupled to a lower end of a drillstring, wherein the drill bit comprises a bit body having a bit axis. In addition, the method comprises (b) forming a pilot borehole having a diameter D 1  with a pilot bit disposed at a lower end of the bit body. Further, the method comprises (c) forming an enlarged borehole having a diameter D 2  with a reamer section extending from radially the bit body. The reamer section is positioned axially above the pilot bit. Operation (c) comprises rotating a plurality of reamer rolling cone cutters, each reamer cone cutter depending from a journal extending from the bit body. Moreover, each reamer rolling cone cutter comprises a central axis, a backface, and a nose positioned proximal the diameter D 2 . 
     Thus, embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more detailed description of the preferred embodiment of the present invention, reference will now be made to the accompanying drawings, wherein: 
         FIG. 1  is a side view of a conventional bi-center bit; 
         FIG. 2  is an end view of the drill bit of  FIG. 1 ; 
         FIG. 3  is a side view of an embodiment of a bi-center drill bit in accordance with the principles described herein; 
         FIG. 4  is a perspective view of the drill bit of  FIG. 3 ; 
         FIG. 5  is a bottom end view of the drill bit of  FIG. 3 ; 
         FIG. 6  is a cross-sectional view of the drill bit of  FIG. 3 ; 
         FIG. 7  is an enlarged cross-sectional view of one rolling cone cutter of the drill bit of  FIG. 3 ; 
         FIG. 8  is a schematic bottom end view of the drill bit of  FIG. 3  illustrating the reamer cone cutters as they are positioned in the borehole; 
         FIG. 9  is a side view of an embodiment of a speed drill bit in accordance with the principles described herein; 
         FIG. 10  is a bottom end view of the drill bit of  FIG. 9 ; 
         FIG. 11  is an enlarged cross-sectional view of one rolling cone cutter of the drill bit of  FIG. 9 ; 
         FIG. 12  is a side view of an embodiment of a bi-center drill bit in accordance with the principles described herein; 
         FIG. 13  is a bottom end view of the drill bit of  FIG. 12 ; 
         FIG. 14  is an enlarged cross-sectional view of one rolling cone cutter of the pilot bit of  FIG. 12 ; 
         FIG. 15  is a side view of an embodiment of a speed drill bit in accordance with the principles described herein; 
         FIG. 16  is a bottom end view of the drill bit of  FIG. 15 ; 
         FIG. 17  is a side view of an embodiment of a bi-center drill bit in accordance with the principles described herein; 
         FIG. 18  is a perspective view of the drill bit of  FIG. 17 ; 
         FIG. 19  is a bottom end view of the drill bit of  FIG. 17 ; 
         FIG. 20  is a side view of an embodiment of a speed drill bit in accordance with the principles described herein; and 
         FIG. 21  is a perspective view of the drill bit of  FIG. 20 . 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     The following discussion is directed to various exemplary embodiments of the present invention. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. In addition, one skilled in the art will understand that the following description has broad application, and 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. 
     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 figures 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. 
     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 connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. 
     Referring now to  FIGS. 3-6 , an embodiment of a bi-center bit  100  adapted for drilling through formations of rock to form a borehole is shown. Bit  100  has a central axis  111  about which bit  100  rotates in the cutting direction represented by arrow  118 . In addition, bit  100  generally includes a bit body  112 , a shank  113 , and a threaded connection or pin  114  for connecting bit  100  to a drill string (not shown), which is employed to rotate the bit in order to drill the borehole. Although bit body  112  is shown in  FIG. 6  as comprising two components that are coupled together, in general, bit body  112  may be monolithic (i.e., a single, unitary piece) or formed of a plurality of components coupled together. At the lower end of bit  100  opposite pin  114 , bit body  112  includes a pilot section or pilot bit  120  including an end face  121  that supports a pilot cutting structure  122 . A reamer section  160  extends radially outward from body  112  and is axially disposed between pin  114  and pilot bit  120 . Reamer section  160  includes a reamer cutting structure  162 . As will be described in more detail below, in this embodiment, reamer section  160  includes a plurality of rolling cone cutters  171 ,  172 . 
     Body  112  may be formed in a conventional manner using powdered metal tungsten carbide particles in a binder material to form a hard metal cast matrix. Alternatively, the body can be machined from a metal block, such as steel, rather than being formed from a matrix. 
       FIG. 6  shows a cross-sectional view of bit  100  taken in a vertical plane containing bit axis  111  and passing between cone cutters  171 ,  172  of reamer section  160 . As best seen in  FIG. 6 , body  112  includes a central longitudinal bore  116  permitting drilling fluid to flow from the drill string into bit  100 . A plurality of flow passages  117  extend through bit body  112  from bore  116 . Passages  117  include outlet ports  119  disposed at their ends. Together, passages  117  and ports  119  serve to distribute drilling fluids around cutting structures  122  and  162  to flush away formation cuttings during drilling and to remove heat from bit  100 . 
     Referring briefly to  FIG. 5 , bit  100  has a minimum pass through diameter D pt , which represents the minimum diameter hole or bore through which bit  100  may be tripped. Further, pilot bit  120  defines a pilot gage diameter D pb  determined by the radially outermost reaches of pilot cutting structure  122 . In general, the borehole formed by pilot bit  120 , also referred to herein as the “pilot borehole,” has a diameter equal to pilot gage diameter D pb . Reamer section  160  defines a reamer diameter D rs  determined by the radially outermost reaches of reamer cutting structure  162 . In general, the borehole formed by reamer section  160 , also referred to herein as the “enlarged borehole,” has a diameter equal to reamer diameter D rs . Pilot diameter D pb  is less pass through diameter D pt , however, reamer diameter D rs  is greater than pass through diameter D pt . Thus, bit  100  may be tripped through a hole that is smaller than the diameter D rs  of the enlarged borehole formed by reamer section  160 . 
     Referring again to  FIGS. 3-5 , in this embodiment, pilot bit  120  is coaxially aligned with bit body  112 . In other words, pilot bit  120  and bit body  112  share the same central axis  111 . In this embodiment, pilot bit  120  comprises a fixed cutter bit including a plurality of blades which extend from bit face  121 . Specifically, cutting structure  122  includes a plurality of angularly spaced-apart primary blades  131 ,  132  and a plurality of angularly spaced apart secondary blades  133 ,  134 . In this embodiment, the plurality of blades (e.g., primary blades  131 ,  132  and secondary blades  133 ,  134 ) are uniformly angularly spaced on bit face  121  about bit axis  111 —the two primary blades  131 ,  132  are uniformly angularly spaced about 180° apart, and the two secondary blades  133 ,  134  are uniformly angularly spaced about 180° apart. In other embodiments (not specifically illustrated), one or more of the blades may be spaced non-uniformly about bit face  121 . Still further, primary blades  131 ,  132 , and secondary blades  133 ,  134  are circumferentially arranged in an alternating fashion. In other words, one secondary blade  133 ,  134  is disposed between each pair of circumferentially adjacent primary blades  131 ,  132 . Although bit  100  is shown as having two primary blades  131 ,  132  and two secondary blades  133 ,  134 , in general, bit  100  may comprise any suitable number of primary and secondary blades. 
     In this embodiment, primary blades  131 ,  132  and secondary blades  133 ,  134  are integrally formed as part of, and extend from, bit body  112  and bit face  121 . Primary blades  131 ,  132  and secondary blades  133 ,  134  extend generally radially along bit face  121  and then axially along a portion of the periphery of pilot bit  120 . In particular, primary blades  131 ,  132  extend radially from proximal central axis  111  toward the periphery of pilot bit  120 . Thus, as used herein, the term “primary blade” may be used to refer to a blade that extends generally radially along the bit face from proximal the bit axis. However, secondary blades  133 ,  134  are not positioned proximal bit axis  111 , but rather, extend radially along bit face  121  from a location that is distal bit axis  111  toward the periphery of pilot bit  120 . Thus, as used herein, the term “secondary blade” may be used to refer to a blade that extends from a radial location distal the bit axis. Primary blades  131 ,  132  and secondary blades  133 ,  134  are separated by drilling fluid flow courses  119 . 
     Referring still to  FIGS. 3-5 , each primary blade  131 ,  132  includes a cutter-supporting surface  142  for mounting a plurality of cutter elements, and each secondary blade  133 ,  134  includes a cutter-supporting surface  152  for mounting a plurality of cutter elements. Specifically, a plurality of cutter elements  140 , each having a cutting face  144 , are mounted to each primary blade  131 ,  132  and mounted to each secondary blade  133 ,  134 . 
     Each cutter element  140  comprises an elongated and generally cylindrical support member or substrate which is received and secured in a pocket formed in the surface of the blade to which it is fixed. In general, each cutter element may have any suitable size and geometry. Cutting face  144  of each cutter element  140  comprises a disk or tablet-shaped, hard cutting layer of polycrystalline diamond or other superabrasive material is bonded to the exposed end of the support member. Further, each cutter element  140  is mounted such that each cutting face  144  is generally forward-facing. As used herein, “forward-facing” may be used to describe the orientation of a surface that is substantially perpendicular to, or at an acute angle relative to, the cutting direction of the bit (e.g., cutting direction  118  of bit  100 ). For instance, a forward-facing cutting face (e.g., cutting face  144 ) may be oriented perpendicular to the cutting direction of bit  100 , may include a backrake angle, and/or may include a siderake angle. The cutting faces are preferably oriented perpendicular to the direction of rotation of bit  10  plus or minus a 45° backrake angle and plus or minus a 45° siderake angle. In addition, each cutting face  144  includes a cutting edge adapted to engage and remove formation material with a shearing action. Such cutting edge may be chamfered or beveled as desired. In this embodiment, cutting faces  144  are substantially planar, but may be convex or concave in other embodiments. 
     As one skilled in the art will appreciate, variations in the number, size, orientation, and locations of the blades (e.g., primary blades, secondary blades, etc.), and the cutter elements (e.g., cutter elements  140 ) are possible. 
     Pilot bit  120  further includes gage pads  151  disposed about the circumference of pilot bit  120  at angularly spaced locations. Specifically, a gage pad  151  intersects and extend from each blade  131 ,  132 ,  133 ,  134 . Gage pads  151  are integrally formed as part of the bit body  112 . Gage pads  151  can help maintain the size of the pilot borehole formed by pilot bit  120  by a rubbing action when primary cutter elements  140  wear slightly under gage. Thus, gage pads  151  define diameter D pb  of pilot bit  120 . In addition, the gage pads also help stabilize the bit against vibration. In other embodiments, one or more of the gage pads (e.g., gage pads  151 ) may include other structural features. For instance, wear-resistant cutter elements or inserts may be embedded in gage pads and protrude from the gage-facing surface or forward-facing surface. 
     As previously described, cutter elements  140  and associated forward-facing cutting faces  144  are mounted to the cutter-supporting surface  142  of each blade. In general, cutter elements  140  may be mounted in any suitable arrangement on the blades. Examples of suitable arrangements may include, without limitation, radially extending rows, arrays or organized patterns, sinusoidal pattern, random, or combinations thereof. With weight-on-bit applied to bit  100  and rotation of bit  100  in the cutting direction represented by arrow  118 , cutting faces  144  engage the formation and enable bit  100  to proceed to drill a pilot borehole. 
     As shown in  FIGS. 3-5 , in this embodiment, reamer section  160  comprises a plurality of rolling cone cutters  171 ,  172 . In particular, each cone cutter  171 ,  172  is mounted on a pin or journal extending from bit body  112 , and is adapted to rotate about a cone axis of rotation  175 . In this embodiment, cone axis  175  of each cone  171 ,  172  is oriented generally downwardly and outwardly away from bit axis  111  and the center of bit  100 . 
     Referring now to  FIG. 7 , an enlarged cross-section taken in a plane that contains axis  175  of exemplary cone  171  and is parallel to bit axis  111  is shown. Although only cone cutter  171  is shown in  FIG. 7 , cone  172  is similarly configured. Each cutter  171 ,  172  is secured on a journal  174  by locking balls  176 . Radial thrusts and axial thrusts are absorbed by a journal sleeve and a thrust washer. Lubricant may be supplied from a reservoir (not shown) to the bearings by apparatus and passageways that are omitted from the figures for clarity. The lubricant is sealed in the bearing structure, and drilling fluid excluded therefrom, by means of one or more annular seals which may take many forms. As shown in  FIG. 7 , the enlarged borehole created by reamer section  160  generally includes sidewall  105 , corner portion  106  and bottom  107 . 
     Referring now to  FIGS. 4 and 7 , each cutter  171 ,  172  includes a generally planar backface  180  and nose  181  generally opposite backface  180 . In this embodiment, backface  180  and nose  181  are both perpendicular to cone axis  175 . Unlike most conventional rolling cone cutters, in this embodiment, each reamer cone cutter  171 ,  172  is oriented such that backface  180  is proximal bit body  112  and bit axis  111 , and nose  181  is distal bit body  112  and bit axis  111 . In general, a rolling cone cutter (e.g., cone cutter  171 ,  172 ) oriented with its backface (e.g., backface  180 ) proximal the bit central axis (e.g., bit axis  111 ) and its nose (e.g., nose) distal the bit axis may be referred to herein as an “outwardly facing” cone cutter, whereas a rolling cone cutter oriented with its backface distal the bit central axis and its nose proximal the bit axis may be referred to herein as an “inwardly facing” cone cutter. Thus, each cone cutter  171 ,  172  is an outwardly facing cone cutter, and most conventional cone cutters are inwardly facing cone cutters. 
     Adjacent to backface  180 , cone cutters  171 ,  172  further include a generally frustoconical surface  182  that may be referred to herein as the “heel” surface of cone cutters  171 ,  172 . Extending between heel surface  182  and nose  181  is a generally frustoconical cone surface  183  adapted for supporting a plurality of cutting elements. Heel surface  182  and cone surface  183  converge in an annular shoulder  184 . 
     As best shown in  FIG. 7 , moving axially relative to axis  175  from nose  181  to backface  180 , cone surface  183  is divided into a plurality of annular frustoconical regions  185   a - e , generally referred to as “lands”, which are employed to support and secure the cutting elements as described in more detail below. Each frustoconical land  185   a - e  is disposed at a cone surface angle β relative to cone axis  175 . Thus, as used herein, the phrase “cone surface angle” refers to the angle of a surface of a cone cutter relative to the cone axis as viewed in a plane that contains the cone axis and is parallel with the bit axis. In this embodiment, moving along surface  183  from nose  181  to backface  180 , each successive lands  185   a - e  is oriented at a smaller angle β relative to cone axis  175 . Thus, for example, land  185   e  is oriented at a cone surface angle β 185e  relative to cone axis  175 , and land  185   a  is oriented at an angle β 185a  that is greater than angle β 185e . Consequently, cone surface  183  is slightly bowed outward or convex between backface  180  and nose  181 . 
     Referring still to  FIG. 7 , for each reamer cone cutter (e.g., cone cutter  171 ,  172 ), each portion of the cone surface between the nose and backface (e.g., each portion of cone surface  182 ) is preferably oriented at a cone surface angle β between 45° and 90°, and more preferably between 45° and 75°. In this embodiment, each portion of surface  183  (e.g., each land  185   e - e ) is oriented at an angle β between 45° and 75°. In addition, each reamer cone cutter  171 ,  172  has a maximum outer diameter D c  and a length L c  measured axially relative to axis  175  from backface  180  to nose  181 . In embodiments described herein, each outwardly facing cone cutter (e.g., cone cutter  171 ,  172 ) is preferably sized such that the ratio of the maximum cone diameter D c  to the cone axial length L c  is between 2.0 and 4.0, and more preferably between 2.0 and 3.0. In this embodiment, the ratio of the cone diameter D c  to the cone axial length L c  of each cone cutter  171 ,  172  is 2.5. As compared to most conventional rolling cone cutters, embodiments of reamer cone cutters described herein (e.g., reamer cone cutters  171 ,  172 ) a flatter. In other words, the ratio of the cone diameter (e.g., diameter D c ) to the cone axial length (e.g., length L c ) of embodiments of reamer cone cutters described herein are greater than the ratio of the cone diameter to the cone axial length of most conventional rolling cone cutters. The purpose of the generally flatter reamer cones is to allow formation of an enlarged borehole having the desired profile. In particular, the flatter reamer cones cut a relatively smooth single curve profile similar to a fixed cutter reamer. If the if the cone diameter to cone axial length were smaller, the reamer cones would create more of a ledge in the borehole where it transitions from pilot diameter to reamer diameter as opposed to the smooth profile of the flatter cone mounted at a high journal angle. 
     In bit  100  illustrated in  FIGS. 3-7 , each cone cutter  171 ,  172  includes a plurality of wear resistant inserts or cutting elements  186 . These cutting elements each include a generally cylindrical base portion having a central axis, and a cutting portion that extends from the base portion and includes a cutting surface for engaging and cutting formation material. The cutting surface may be symmetric or asymmetric relative to the central axis. All or a portion of the base portion is secured by interference fit into a mating socket formed in the surface of the cone cutter. Thus, as used herein, the term “cutting surface” is used to refer to the surface of the cutting element that extends beyond the surface of the cone cutter. The extension height of the insert or cutting element is the distance from the cone surface to the outermost point of the cutting surface of the cutting element as measured perpendicular to the cone surface. 
     Referring specifically to  FIG. 7 , exemplary cone  171  includes a plurality of cutting elements  186  extending from surface  183 . Specifically, in this embodiment, cutting elements  186  are arranged in a plurality of axially spaced circumferential rows relative to cone axis  175 , each row disposed along one land  185   a - e . In this embodiment, no cutter elements or inserts are provided on heel surface  182 . However, in other embodiments, cutter elements may be provided on the heel surface. 
     Referring still to  FIG. 7 , cone axis  175  extends down and away from bit axis  111 . As viewed in a plane that contains cone axis  175  and is parallel to bit axis  111  (e.g.,  FIG. 7 ), cone axis  175  is oriented at a “cone axis angle” angle α measured upwardly from bit axis  111  to cone axis  175 . Thus, as used herein, the phrase “cone axis angle” refers to the angle measured upwardly from the bit axis to the cone axis in a plane that contains the cone axis and is parallel to the bit axis. In embodiments described herein, each outwardly facing cone cutter is preferably oriented with a cone axis angle α between 30° and 90°, more preferably between 45° and 90°, and even more preferably between 60° and 90°. In the embodiment shown in  FIGS. 3-7 , each outwardly facing cone cutter  171 ,  172  is oriented with a cone axis angle α of 75°. 
     Referring now to  FIGS. 5 and 8 , in this embodiment, reamer section  160  includes two outwardly facing cone cutters  171 ,  172 . In particular, cone cutters  171 ,  172  are circumferentially adjacent each other and eccentrically positioned to one side of bit body  112 . In other words, cone cutters  171 ,  172  are not uniformly angularly or circumferentially spaced about bit body  112 . In general, a bit having a reamer section with a plurality of cone cutters or blades that are non-uniformly distributed about the circumference of the bit body (e.g., bit  100 ) may be referred to as a “eccentric” or bi-center bit. As best shown in  FIG. 8 , a maximum cone separation angle θ defines the angle between the rotational axes of the circumferentially outermost cone cutters of the reamer section of a bi-center bit (e.g., cone cutters  171 ,  172  of reamer section  160  of bit  100 ) in end view. In other words, maximum cone separation angle θ is the angle between the axes of the reamer section cone cutters of a bi-center bit that are circumferentially furthest from each other. For bi-center bits (e.g., bit  100 ), angle θ is preferably between 90° and 150°, and more preferably between 110° and 130°. In this embodiment, only two cone cutters  171 ,  172  are provided in reamer section  160 , and thus, maximum cone separation angle θ is the angle measured between axes  175  of cone cutters  171 ,  172 . Angle θ between cone cutters  171 ,  172  is 120°. Although reamer section  160  includes two cone cutters  171 ,  172  in this embodiment, in general, the reamer section (e.g., reamer section  160 ) may include one, two, or more cone cutters (e.g., cone cutters  171 ,  172 ). 
     Referring still to  FIG. 8 , “offset” is a term used to describe the orientation of a cone cutter (e.g., cone  171 ) and its axis (e.g., cone axis  175 ) relative to the bit axis (e.g., bit axis  111 ). More specifically, a cone is “offset,” and thus a bit may be described as having “cone offset,” when a projection of the cone axis does not intersect or pass through the bit axis, but instead passes a distance away from the bit axis. As shown in the end view along bit axis  111  of  FIG. 8 , cone offset may be defined as the distance “d” measured perpendicularly from the projection of the cone axis  175  and a line “L” that is parallel to the projection of the cone axis and intersects the bit axis  111 . Thus, the larger the distance “d”, the greater the offset. Thus, as used herein, the phrase “cone offset distance” refers to the distance, in end view (i.e., as viewed from the borehole bottom along the bit axis), measured perpendicularly from a projection of a cone axis, and a line parallel to the projection of the cone axis and intersecting the bit axis. 
     Cone offset may be positive or negative. With negative offset, the region of contact of the cone cutter with the borehole sidewall (e.g., sidewall  105 ) is behind or trails the cone&#39;s axis of rotation (e.g., axis  175 ) with respect to the direction of rotation of the bit (e.g., direction of rotation  118 ). On the other hand, with positive offset, the region of contact of the cone cutter with the borehole sidewall is ahead or leads the cone&#39;s axis of rotation with respect to the direction of rotation of the bit. 
     In a bit having cone offset (positive or negative), a rolling cone cutter is prevented from rolling along the hole bottom in what would otherwise be its “free rolling” path, and instead is forced to rotate about the centerline of the bit along a non-free rolling path. This causes the rolling cone cutter and its cutter elements to engage the borehole bottom in motions that may be described as skidding, scraping, dragging, and sliding. These motions apply a plowing and shearing type cutting force to the borehole bottom (e.g., bottom  107 ). Without being limited by this or any other theory, it is believed that in certain formations, these motions can be a more efficient or faster means of removing formation material, and thus enhance ROP, as compared to bits having no cone offset (or relatively little cone offset) where the cone cutter predominantly cuts via compressive forces and a crushing action. In general, the greater the offset distance, whether positive or negative, the greater the formation removal and ROP. However, it should also be appreciated that such shearing cutting forces arising from cone offset accelerate the wear of cutter elements, especially in hard, more abrasive formations, and may cause cutter elements to fail or break at a faster rate than would be the case with cone cutters having no offset. Consequently, the magnitude of cone offset may be limited. 
     Referring still to  FIG. 8 , in this embodiment, cone  172  has a positive offset, and thus, the region of contact R 172  of cone cutter  172  with the borehole sidewall  105  is ahead of its respective cone axis  175  relative to the direction of rotation  118  of bit  100 . Further, in this embodiment, cone  171  has a negative offset, and thus, the region of contact R 171  of cone cutter  171  with the borehole sidewall  105  is behind of its respective cone axis  175  relative to the direction of rotation  118  of bit  100 . Moreover, in this embodiment, each cone cutter  171 ,  172  has substantially the same magnitude cone offset distance d. In other embodiments of eccentric or bi-center drill bits including a reamer section with rolling cone cutters, each rolling cone cutter of the reamer section (e.g., each cone  171 ,  172  of reamer section  160 ) may have negative offset or positive offset, select cones may have negative offsets and other(s) positive offset, two or more cones may have a different magnitude cone offsets, or combinations thereof. 
     Varying the magnitude of the offsets among the cone cutters provides a bit designer the potential to improve ROP and other performance criteria of the bit. In the embodiments of bi-center bits described herein (e.g., bit  100 ), one cone cutter (e.g., cone cutter  172 ) preferably has a positive cone offset and one cone cutter (e.g., cone cutter  171 ) preferably has a negative cone offset. Such configuration offers the potential for the ROP and durability advantages below and provides a geometry best suited for allowing the bit to fit through the pass through. 
     For relatively large bits, a third reamer cone may be provided between the reamer cone with positive cone offset and the reamer cone with negative cone offset. Such a third cone may have positive, negative, or no cone offset. Further, for embodiments of bi-center drill bits including roller cones in the reamer section (e.g., bit  100 ), each reamer section cone cutter (e.g., each cone cutter  171 ,  172  of reamer section  160 ) preferably has a cone offset distance between 0.25 in. and 4.00 in., more preferably between 0.50 in. and 3.00 in., and even more preferably between 0.500 in. and 2.00 in. 
     As each cone cutter  171 ,  172  rotates about its axis  175  and bit  100  rotates about bit axis  111 , cutter elements  186  mounted to cone cutters  172 ,  172  repeatedly move into and out of engagement with the formation. Due to the negative offset of cone cutter  171 , during rotation of cone cutter  171  about axis  175 , cutting elements  186  mounted thereto (a) engage the sidewall  105  as they move downward from their uppermost axial position relative to bit axis  111  (i.e., as they move downward from top dead center) toward their lowermost axial position relative to bit axis  111  (i.e., bottom dead center); (b) transition from engagement with sidewall  105  to engagement with bottom  107  as they approach their lowermost axial position relative to bit axis  111 ; (c) engage bottom  107  as they sweep through their lowermost axial position relative to bit axis  111 ; and (d) move out of engagement with the formation and bottom  107  as they move upward from their lowermost axial position relative to bit axis  111  and away from bottom  107 . In other words, as cone cutter  171  rotates, cutters  186  mounted to cone cutter  171  repeat the following cycle—engagement with sidewall  105 , followed by engagement with bottom  107 , and then move out of engagement with the formation. 
     Due to the positive offset of cone cutter  172 , as cone cutter  172  rotates about axis  175 , cutting elements  186  mounted thereto (a) engage bottom  107  as they sweep through their lowermost axial position relative to bit axis  111  (i.e., as they sweep through bottom dead center); (b) transition from engagement with bottom  107  to engagement with sidewall  105  as they move upward from their lowermost axial position; (c) engage the sidewall  105  as move upward from their lowermost axial position relative to bit axis  111  to their uppermost axial position relative to bit axis  111 ; and (d) move out of engagement with the formation and sidewall  105  as sweep through their uppermost axial position relative to bit axis  111 . In other words, as cone cutter  172  rotates, cutters  186  mounted to cone cutter  172  repeat the following cycle—engagement with bottom  107 , followed by engagement with sidewall  105 , and then move out of engagement with the formation. 
     As previously described, the cutter elements mounted to the reamer blades of conventional reamer sections continuously engage the formation as the drill bit is rotated. However, in embodiments described herein that include rolling cone cutters in the reamer section (e.g., cone cutters  171 ,  172  in reamer section  160 ), the reamer section cutting elements (e.g., cutting elements  186  mounted to cone cutters  171 ,  172 ) do not continuously engage the formation. Rather, the cutting elements mounted to the cone cutters in the reamer section cyclically move into and out of engagement with the formation. Moreover, the use of rolling cone cutters in the reamer section offers the potential to increase the available surface area for mounting cutting elements as compared to similarly sized conventional reamer blades. Accordingly, for a given sized cutting element, embodiments described herein offer the potential for an increased cutting element count in the reamer section as compared to similarly sized conventional reamer sections including reamer blades. The combination of increased cutting element count, and periodic engagement with the formation offers the potential to enhance load sharing among the cutting elements in the reamer section, reduce wear, and enhance overall bit durability. 
     Referring now to  FIGS. 9-11 , an embodiment of a drill bit  200  adapted for drilling through formations of rock to form a borehole is shown. Bit  200  is similar to bit  100  previously described. Namely, bit  200  has a central axis  211  about which bit  200  rotates in the cutting direction represented by arrow  218 . In addition, bit  200  generally includes a bit body  212 , a shank  213 , and a threaded connection or pin  214  for connecting bit  200  to a drill string (not shown), which is employed to rotate the bit in order to drill the borehole. At the lower end of bit  200  opposite pin  214 , bit body  212  includes a pilot bit  120  as previously described. In addition, a reamer section  260  extends radially from bit body  212  and is axially positioned between pin  214  and pilot bit  120 . Reamer section  260  includes a reamer cutting structure  262 . However, unlike bit  100  previously described, in this embodiment, reamer section  260  includes three uniformly angularly and circumferentially spaced rolling cone cutters  271 ,  272 ,  273 . 
     Referring still to  FIGS. 9-11 , each cone cutter  271 ,  272 ,  273  is configured substantially the same as cone cutters  171 ,  172  previously described. Namely, each cone cutter  271 ,  272 ,  273  is mounted on a pin or journal  274  extending from bit body  212 , and is adapted to rotate about a cone axis of rotation  275 . In addition, cone axis  275  of each cone  271 ,  272  is oriented generally downwardly and outwardly away from bit axis  211  and the center of bit  200 . Further, each cutter  271 ,  272 ,  273  includes a generally planar backface  280  and nose  281  opposite backface  280 . Backface  280  and nose  281  of each cone cutter  271 ,  272 ,  273  are perpendicular to cone axis  275 . As with cones  171 ,  172  previously described, each reamer cone cutter  271 ,  272 ,  273  is an outwardly facing cone cutter (i.e., each cone cutter  271 ,  272 ,  273  is oriented with backface  280  is proximal bit axis  111  and nose  281  distal bit axis  211 ). Adjacent to backface  280 , cutters  271 ,  272 ,  273  further include a generally frustoconical heel surface  282  and a generally frustoconical cone surface  283  that supports a plurality of cutting elements  186  as previously described. 
     As best shown in  FIG. 11 , each portion of cone surface  283  is preferably oriented at a cone surface angle β between 45° and 90°, and more preferably between 45° and 75°. In this embodiment, each portion of surface  283  is oriented at an angle β between 45° and 75°. In addition, each reamer cone cutter  271 ,  272 ,  273  is preferably sized such that the ratio of the cone diameter D c  to the cone axial length L c  is between 2.0 and 4.0, and more preferably between 2.0 and 3.0. In this embodiment, the ratio of the cone diameter D c  to the cone axial length L c  is 2.5. Still further, each cone  271 ,  272 ,  273  is preferably oriented with a cone axis angle α between 30° and 90°, more preferably between 45° and 90°, and even more preferably between 60° and 90°. In the embodiment shown in  FIGS. 9-11 , each outwardly facing cone cutter  271 ,  272 ,  273  is oriented with a cone axis angle α of 75°. Although only cone cutter  271  is shown in  FIG. 10 , cone cutters  272 ,  273  are similarly configured. 
     Referring now to  FIGS. 9 and 10 , in this embodiment, reamer section  260  includes three cone cutters  271 ,  272 ,  273 . Further, unlike reamer section  160  previously described, in this embodiment, cone cutters  271 ,  272 ,  273  are uniformly angularly and circumferentially spaced about bit body  212 . Thus, in this embodiment, the three cone cutters  271 ,  272 ,  273  are uniformly angularly spaced 120° apart about bit axis  211 . In general, a bit having a reamer section with a plurality of cone cutters or blades uniformly distributed about the circumference of the bit body (e.g., bit  200 ) may be referred to as a “concentric” or “speed drill” bit. Thus, bit  200  may be described as a concentric or speed drill bit as opposed to an eccentric of bi-center bit. 
     As best shown in  FIG. 10 , pilot bit  120  defines pilot gage diameter D pb  determined by the radially outermost reaches of pilot cutting structure  122 , and reamer section  260  defines a reamer diameter D rs  determined by the radially outermost reaches of cutting structure  262  and cone cutters  271 ,  272 ,  273 . Thus, the enlarged borehole formed by reamer section  260  has the same diameter D rs . Further, bit  200  has a minimum pass through diameter D pt , which represents the minimum diameter of a hole or bore through which bit  200  may be tripped. Pilot diameter D pb  is less pass through diameter D pt  and reamer diameter D rs , however, for concentric and speed drill bits such as bit  200 , minimum pass through diameter D pt  is equal to reamer diameter D rs . Thus, bit  200  cannot be tripped through a hole that is smaller than the diameter D rs  of the borehole formed by reamer section  260 . However, embodiments of concentric and speed drill bits described herein including reamer rolling cone cutters offer the potential for enhanced ROP and durability. In particular, without being limited by this or any particular theory, the pilot bit (e.g., pilot bit  120 ) both drills the pilot borehole and creates stress fractures in the portion of the formation immediately surrounding the pilot borehole. Such stress fractures generally weaken the portion of the formation immediately surrounding the pilot borehole, thereby reducing the loads that the reamer section and associated cutting structure must apply to the formation surrounding the pilot borehole in order to form the enlarged borehole. 
     As best shown in  FIG. 10 , in this embodiment of speed drill bit  200 , each cone cutter  271 ,  272 ,  273  has a negative cone offset. Thus, the region of contact of each cone cutter  271 ,  272 ,  273  with the enlarged borehole sidewall is behind or trails the cone&#39;s axis  175  with respect to the direction of rotation  218  of bit  200 . Further, in this embodiment, each cone cutter  271 ,  272 ,  273  has the same magnitude cone offset distance. In other words, in end view along axis  211 , the cone offset distance measured perpendicularly from a projection of axis  275  of each cone cutter  271 ,  272 ,  273  and a line parallel to the projection and passing through bit axis  211  is the same. For embodiments of concentric drill bits including roller cones in the reamer section (e.g., bit  200 ), each reamer section cone cutter (e.g., each cone cutter  271 ,  272 ,  273  of reamer section  260 ) preferably has a cone offset distance between 0.25 in. and 4.00 in., more preferably between 0.50 in. and 3.00 in., and even more preferably between 0.50 in. and 2.00 in. Although reamer cone cutters  271 ,  272 ,  273  each have negative cone offset and the same cone offset distance in this embodiment, in other embodiments of concentric or speed drill bits including a reamer section with rolling cone cutters, each rolling cone cutter of the reamer section (e.g., each cone  271 ,  272 ,  273  of reamer section  260 ) may have negative offset or positive offset, select cones may have negative offsets and other(s) positive offset, two or more cones may have a different magnitude cone offsets, or combinations thereof. 
     Due to the negative offset of cone cutters  271 ,  272 ,  273 , during rotation of each cone cutter  271 ,  272 ,  273  about its axis  175 , cutting elements  186  mounted thereto (a) engage the enlarged borehole sidewall as they move downward from their uppermost axial position relative to bit axis  211  (i.e., as they move downward from top dead center) toward their lowermost axial position relative to bit axis  211  (i.e., bottom dead center); (b) transition from engagement with the enlarged borehole sidewall to engagement with the enlarged borehole bottom as they approach their lowermost axial position relative to bit axis  211 ; (c) engage the enlarged borehole bottom as they sweep through their lowermost axial position relative to bit axis  211 ; and (d) move out of engagement with the formation and the enlarged borehole bottom as they move upward from their lowermost axial position relative to bit axis  211 . In other words, as each cone cutter  271 ,  272 ,  273  rotates, cutters  186  mounted thereto repeat the following cycle—engagement with the enlarged borehole sidewall, followed by engagement with the enlarged borehole bottom, and then move out of engagement with the formation. Thus, unlike the reamer blades of conventional reamer sections which continuously engage the formation as the drill bit is rotated, embodiments of concentric and speed drill bits described herein that include rolling cone cutters in the reamer section (e.g., cone cutters  271 ,  272 ,  273  in reamer section  260 ), the reamer section cutting elements (e.g., cutting elements  186 ) do not continuously engage the formation. Rather, the cutting elements mounted to the cone cutters in the reamer section cones (e.g., cutting elements  186 ) cyclically move into and out of engagement with the formation. Moreover, the use of rolling cone cutters (e.g., cone cutters  271 ,  272 ,  273 ) in the reamer section (e.g., reamer section  260 ), offers the potential to increase the available surface area for mounting cutting elements as compared to similarly sized conventional reamer sections that include reamer blades. Accordingly, for a given sized cutting element, embodiments described herein offer the potential for an increased cutting element count in the reamer section as compared to similarly sized conventional reamer sections including reamer blades. The combination of increased cutting element count, and periodic engagement with the formation offers the potential to enhance load sharing among the cutting elements in the reamer section, reduce wear, and enhance overall bit durability. 
     Referring now to  FIGS. 12 and 13 , an embodiment of an eccentric or bi-center drill bit  300  adapted for drilling through formations of rock to form a borehole is shown. Bit  300  is similar to bit  100  previously described. Namely, bit  300  has a central axis  311  about which bit  300  rotates in the cutting direction represented by arrow  318 . In addition, bit  300  generally includes a bit body  312 , a shank  313 , and a threaded connection or pin  314  for connecting bit  300  to a drill string (not shown), which is employed to rotate the bit in order to drill the borehole. At the lower end of bit  300  opposite pin  314 , bit body  312  includes a pilot section or pilot bit  320  including an end face  321  that supports a pilot cutting structure  322 . A reamer section  160  as previously described extends radially outward from body  312  and is axially disposed between pin  314  and pilot bit  320 . Reamer section  160  includes cone cutters  171 ,  172  configured, sized, and oriented as previously described with respect to  FIGS. 3-8 . However, unlike bit  100  previously described, in this embodiment, pilot bit  320  is not a fixed cutter bit, rather, pilot bit  320  is a rolling cone drill bit. 
     Referring briefly to  FIG. 13 , bit  300  has a minimum pass through diameter D pt , which represents the minimum diameter hole or bore through which bit  300  may be tripped. Further, pilot bit  320  defines a pilot gage diameter D pb  determined by the radially outermost reaches of pilot cutting structure  322 . Reamer section  160  defines a reamer diameter D rs  determined by the radially outermost reaches of reamer cutting structure  162 . Pilot diameter D pb  is less pass through diameter D pt , however, reamer diameter D rs  is greater than pass through diameter D pt . Thus, bit  300  may be tripped through a hole that is smaller than the diameter D rs  of the enlarged borehole formed by reamer section  160 . 
     Referring again to  FIGS. 12-14 , pilot bit  320  is coaxially aligned with bit body  312 , and thus, pilot bit  320  and bit body  312  share the same central axis  311 . In this embodiment, pilot bit  320  comprises a rolling cone drill bit including a plurality of inwardly facing rolling cone cutters  371 ,  372 ,  373  which are rotatably mounted on bearing shafts that depend from the bit body  312 . In this embodiment, rolling cone pilot bit  320  comprises three sections or legs  321  that are welded together to form the lower portion of bit body  312 . Rolling cone pilot bit  320  further includes a plurality of ports or nozzles  319  that are provided for directing drilling fluid toward the bottom of the borehole and around cone cutters  371 ,  372 ,  373 . 
     Referring still  FIGS. 12-14 , each cone cutter  371 ,  372 ,  373  is mounted on a pin or journal  374  extending from bit body  312 , and is adapted to rotate about a cone axis of rotation  375  oriented generally downwardly and inwardly toward the center of the bit  300  and axis  311 . In this embodiment, cones  371 ,  372 ,  373  are oriented such that a projection of each cone axis  375  intersects bit axis  311 . However, in other embodiments, one or more of the pilot bit rolling cone cutters (e.g., rolling cone cutters  371 ,  372 ,  373 ) may have a positive or negative cone offset. As shown in  FIG. 14 , the pilot borehole created by pilot bit  300  includes sidewall  305 , corner portion  306  and bottom  307 . 
     In the embodiment shown, radial and axial thrust are absorbed by roller bearings  328 ,  330 , thrust washer  331  and thrust plug  332 . The bearing structure shown is generally referred to as a roller bearing; however, the invention is not limited to use in bits having such structure, but may equally be applied in a bit where cone cutters  371 ,  372 ,  373  are mounted on pin  374  with a journal bearing or friction bearing disposed between the cone cutter and the journal pin  374 . In both roller bearing and friction bearing bits, lubricant may be supplied from a lubricant reservoir to the bearings by apparatus and passageways that are omitted from the figures for clarity. The lubricant is sealed in the bearing structure, and drilling fluid excluded therefrom, by means of an annular seal  334  which may take many forms. 
     Referring still to  FIGS. 12-14 , each cone cutter  371 ,  372 ,  373  includes a generally planar backface  340  and nose portion  342  opposite backface  340 . Adjacent to backface  340 , cutters  371 ,  372 ,  373  further include a generally frustoconical surface  344  that is adapted to retain cutter elements that scrape or ream the sidewalls of the borehole as the cone cutters rotate about the borehole bottom. Frustoconical surface  344  will be referred to herein as the “heel” surface of cone cutters  371 ,  372 ,  373 . It is to be understood, however, that the same surface may be sometimes referred to by others in the art as the “gage” surface of a rolling cone cutter. 
     Extending between heel surface  344  and nose  342  is a generally conical surface  346  adapted for supporting cutter elements that gouge or crush the borehole bottom  307  as cone cutters  371 ,  372 ,  373  rotate about the borehole. Frustoconical heel surface  344  and conical surface  346  converge in a circumferential edge or shoulder  350 . Although referred to herein as an “edge” or “shoulder,” it should be understood that shoulder  350  may be radiused to various degrees such that shoulder  350  will define a transition zone of convergence between frustoconical heel surface  344  and the conical surface  346 . Conical surface  346  is divided into a plurality of generally frustoconical regions or bands  348  generally referred to as “lands” which are employed to support and secure the cutter elements as described in more detail below. Grooves  349  are formed in cone surface  346  between adjacent lands  348 . 
     In the bit shown in  FIGS. 12-14 , each cone cutter  371 ,  372 ,  373  includes a plurality of wear resistant cutter elements in the form of inserts which are disposed about the cone and arranged in circumferential rows in the embodiment shown. More specifically, rolling cone cutter  371  shown in  FIG. 14  includes a plurality of heel inserts  360  that are secured in a circumferential heel row  360   a  in the frustoconical heel surface  344 . Cone cutter  371  further includes a circumferential row  380   a  of gage inserts  380  secured to cone cutter  371  in locations along or near the circumferential shoulder  350 . Each insert  380  extends to pilot gage diameter D pb . The cone cutter  371  further includes inner row inserts  381 ,  382 ,  383  secured to cone surface  346  and arranged in concentric, spaced-apart inner rows  381   a ,  382   a ,  383   a , respectively. Heel inserts  360  generally function to scrape or ream the borehole sidewall  305  to maintain the borehole at pilot gage diameter D pb  and prevent erosion and abrasion of the heel surface  344 . Gage inserts  380  function primarily to cut the corner  306  of the borehole Inner row cutter elements  381 ,  382 ,  383  of inner rows  381   a ,  382   a ,  383   a  are employed to gouge and remove formation material from the remainder of the borehole bottom  307 . Inner rows  381   a ,  382   a ,  383   a  are arranged and spaced on rolling cone cutters  371  so as not to interfere with rows of inner row cutter elements on the other cone cutters  372 ,  373 . Cone  371  is further provided with relatively small “ridge cutter” cutter elements  384  in nose region  342  which tend to prevent formation build-up between the cutting paths followed by adjacent rows of the more aggressive, primary inner row cutter elements from different cone cutters. Cone cutters  372  and  373  have heel, gage and inner row cutter elements and ridge cutters that are similarly, although not identically, arranged as compared to cone  371 . The arrangement of cutter elements differs as between the three cones in order to maximize borehole bottom coverage, and also to provide clearance for the cutter elements on the adjacent cone cutters. For instance, in some embodiments, inner row inserts  381 ,  382 ,  383  are arranged and spaced on each cone cutter  371 ,  372 ,  373  so as to intermesh, yet not interfere with the inner row inserts  381 ,  382 ,  383  of the other cone cutters  371 ,  372 ,  373 . In such embodiments, grooves  349  on each cone  371 ,  372 ,  373  allow the cutting surfaces of certain bottomhole cutter elements  381 ,  382 ,  383  of adjacent cone cutters  371 ,  372 ,  373  to intermesh, without contacting the cone steel or surface of cones  371 ,  372 ,  373 . 
     In the embodiment shown, inserts  360 ,  370 ,  380 - 383  each include a generally cylindrical base portion, a central axis, and a cutting portion that extends from the base portion, and further includes a cutting surface for cutting the formation material. The base portion is secured into a mating socket formed in the surface of the cone cutter. The base portion may be secured within the mating socket by any suitable means including, without limitation, an interference fit, brazing, or combinations thereof. The “cutting surface” of an insert is defined herein as being that surface of the insert that extends beyond the surface of the cone cutter. Further, it is to be understood that the extension height of an insert or cutter element is the distance from the cone surface to the outermost point of the cutting surface of the cutter element as measured substantially perpendicular to the cone surface. 
     Referring now to  FIGS. 14 and 15 , an embodiment of a concentric or speed drill bit  400  adapted for drilling through formations of rock to form a borehole is shown. Bit  400  includes aspects similar to both bits  200 ,  300  previously described. Namely, bit  400  has a central axis  411  about which bit  400  rotates in the cutting direction represented by arrow  418 . In addition, bit  400  generally includes a bit body  412 , a shank  413 , and a threaded connection or pin  414  for connecting bit  400  to a drill string (not shown), which is employed to rotate the bit in order to drill the borehole. At the lower end of bit  400  opposite pin  414 , bit body  412  includes a pilot bit  320  as previously described with respect to  FIGS. 12-14 . In addition, bit  400  includes a reamer section  260  as previously described with respect to  FIGS. 9-11 . Reamer section  260  extends radially from bit body  412  and is axially positioned between pin  414  and pilot bit  320 . Reamer section  260  includes cone cutters  271 ,  272 ,  273  configured, sized, and oriented as previously described with respect to  FIGS. 9-11 . 
     Referring now to  FIGS. 17-19 , an embodiment of an eccentric or bi-center bit  500  adapted for drilling through formations of rock to form a borehole is shown. Bit  500  is similar to bit  300  previously described. Namely, bit  500  has a central axis  511  about which bit  500  rotates in the cutting direction represented by arrow  518 . In addition, bit  500  generally includes a bit body  512 , a shank  513 , and a threaded connection or pin  514  for connecting bit  500  to a drill string (not shown), which is employed to rotate the bit in order to drill the borehole. At the lower end of bit  500  opposite pin  514 , bit body  512  includes a pilot bit  520 . In addition, bit  500  includes a reamer section  160  as previously described. Reamer section  160  extends radially from bit body  512  and is axially positioned between pin  514  and pilot bit  520 . Reamer section  160  includes cone cutters  171 ,  172  configured, sized, and oriented as previously described with respect to  FIGS. 3-8 . However, unlike bit  300  previously described, which includes pilot bit  320  with inwardly facing rolling cone cutters  371 ,  372 ,  373 , pilot bit  520  of bit  500  includes a plurality of outwardly facing rolling cone cutters  571 ,  572 . 
     Referring still to  FIGS. 17-19 , pilot bit  520  is coaxially aligned with bit body  512 , and thus, pilot bit  520  and bit body  512  share the same central axis  511 . In this embodiment, pilot bit  520  comprises a rolling cone drill bit including a plurality of outwardly facing rolling cone cutters  571 ,  572 . Each cone cutter  571 ,  572  is rotatably mounted on a pin or journal extending from bit body  512 , and is adapted to rotate about a cone axis of rotation  575 . In this embodiment, cone axis  575  of each cone  571 ,  572  is oriented generally downwardly and outwardly away from bit axis  511  and the center of bit  500 . Rolling cone pilot bit  520  further includes a plurality of ports or nozzles  519  that are provided for directing drilling fluid toward the bottom of the borehole and around cone cutters  571 ,  572 . 
     Each cone cutter  571 ,  572  is substantially the same as outwardly facing cone cutters  171 ,  172  previously described. Namely, each cutter  571 ,  572  is secured on its respective journal by locking balls. Radial thrusts and axial thrusts are absorbed by a journal sleeve and a thrust washer. Lubricant may be supplied from a reservoir (not shown) to the bearings by apparatus and passageways that are omitted from the figures for clarity. The lubricant is sealed in the bearing structure, and drilling fluid excluded therefrom, by means of one or more annular seals which may take many forms. Further, each cutter  571 ,  572  includes a generally planar backface  580  and nose  581  generally opposite backface  580 . In this embodiment, backface  580  and nose  581  are both perpendicular to cone axis  575 . Each reamer cone cutter  571 ,  572  is oriented such that backface  580  is proximal bit body  512  and bit axis  511 , and nose  581  is distal bit body  512  and bit axis  511 . 
     Adjacent to backface  580 , cone cutters  571 ,  572  further include a generally frustoconical heel surface  582 . Extending between heel surface  582  and nose  581  is a generally frustoconical cone surface  583  adapted for supporting a plurality of cutting elements. As best shown in  FIG. 19 , moving axially relative to axis  175  from nose  581  to backface  580 , each cone surface  583  is divided into a plurality of annular frustoconical regions  585   a - e  employed to support and secure the cutting elements as described in more detail below. In this embodiment, moving along surface  583  from nose  581  to backface  580 , each successive lands  585   a - e  is oriented at a smaller angle β relative to cone axis  575 . For each cone cutter  571 ,  572 , each portion of the cone surface  583  is preferably oriented at a cone surface angle β between 45° and 90°, and more preferably between 45° and 75°. In this embodiment, each portion of surface  583  (e.g., each land  585   e - e ) is oriented at an angle β between 45° and 75°. In addition, each reamer cone cutter  571 ,  572  is preferably sized such that the ratio of the cone diameter D c  to the cone axial length L c  is between 2.0 and 4.0, and more preferably between 2.0 and 3.0. In this embodiment, the ratio of the cone diameter D c  to the cone axial length L c  of each cone cutter  571 ,  572  is 2.5. 
     In bit  500  illustrated in  FIGS. 17-19 , each outwardly facing pilot cone cutter  571 ,  572  includes a plurality of wear resistant inserts or cutting elements  186  as previously described extending from surface  583 . Specifically, in this embodiment, cutting elements  186  are arranged in a plurality of axially spaced circumferential rows relative to cone axis  575 , each row disposed along one land  585   a - e . In this embodiment, no cutter elements or inserts are provided on heel surface  582 . However, in other embodiments, cutter elements may be provided on the heel surface. 
     As best shown in  FIG. 17 , each cone axis  575  extends down and away from bit axis  511 . In particular, each outwardly facing pilot cone cutter  571 ,  572  is preferably oriented with a cone axis angle α between 30° and 90°, more preferably between 45° and 90°, and even more preferably between 60° and 90°. In the embodiment shown in  FIGS. 17-19 , each outwardly facing pilot cone cutter  571 ,  572  is oriented with a cone axis angle α of 75°. 
     Referring now to  FIG. 19 , in this embodiment, pilot section  560  includes two outwardly facing cone cutters  571 ,  572 . Cone cutters  571 ,  572  are uniformly angularly and circumferentially spaced about bit body  512 . Thus, in this embodiment, the two pilot cone cutters  571 ,  572  are uniformly angularly spaced 180° apart about bit axis  511 . Further, in this embodiment, each pilot cone cutter  571 ,  572  has a positive cone offset, and thus, the region of contact of each cone cutter  571 ,  572  with the borehole sidewall is ahead or leads the cone&#39;s axis of rotation  575  with respect to the direction of rotation of bit  500 . Moreover, in this embodiment, each cone cutter  571 ,  572  has substantially the same magnitude cone offset distance. In other embodiments of drill bits including a pilot section with outwardly facing rolling cone cutters, each outwardly facing cone cutter of the pilot section (e.g., each cone  571 ,  572  of pilot section  520 ) may have negative offset or positive offset, select cones may have negative offsets and other(s) positive offset, two or more cones may have a different magnitude cone offsets, or combinations thereof. For example, the cone offset of different cone cutters may be selected such that some of the cone cutters engage the formation with a more crushing action and other cone cutters engage the formation with a more shearing action. Such a combination may offer the potential to improve efficiency in tougher formations. For embodiments of drill bits including outwardly facing roller cones in the pilot section (e.g., bit  500 ), each pilot section cone cutter (e.g., each cone cutter  571 ,  572  of pilot section  520 ) preferably has a cone offset distance between 0.25 in. and 4.00 in., more preferably between 0.50 in. and 3.00 in., and even more preferably between 0.50 in. and 2.00 in. In this embodiment, each cone cutter  571 ,  572  has a cone offset of 1.1 in. 
     As each cone cutter  571 ,  572  rotates about its axis  575  and bit  500  rotates about bit axis  511 , cutter elements  186  mounted to cone cutters  572 ,  572  repeatedly move into and out of engagement with the formation. Due to the positive offset of each cone cutter  571 ,  572 , as cone cutter  571 ,  572  rotates about its axis  575 , cutting elements  186  mounted thereto (a) engage the pilot borehole bottom as they sweep through their lowermost axial position relative to bit axis  511  (i.e., as they sweep through bottom dead center); (b) transition from engagement with pilot borehole bottom to engagement with pilot borehole sidewall as they move upward from their lowermost axial position; (c) engage the pilot borehole sidewall as move upward from their lowermost axial position relative to bit axis  511  to their uppermost axial position relative to bit axis  511 ; and (d) move out of engagement with the formation and pilot borehole sidewall as sweep through their uppermost axial position relative to bit axis  511 . In other words, as cone cutter  571 ,  572  rotates, cutters  186  mounted to cone cutter  172  repeat the following cycle—engagement with pilot borehole bottom, followed by engagement with pilot borehole sidewall, and then move out of engagement with the formation. 
     Referring now to  FIGS. 20 and 21 , an embodiment of a concentric or speed drill bit  600  adapted for drilling through formations of rock to form a borehole is shown. Bit  600  includes aspects similar to both bits  200 ,  500  previously described. Namely, bit  600  has a central axis  611  about which bit  600  rotates in the cutting direction represented by arrow  618 . In addition, bit  600  generally includes a bit body  612 , a shank  613 , and a threaded connection or pin  614  for connecting bit  600  to a drill string (not shown), which is employed to rotate the bit in order to drill the borehole. At the lower end of bit  600  opposite pin  614 , bit body  612  includes a pilot bit  520  as previously described. Pilot bit  520  includes outwardly facing cone cutters  571 ,  572  configured, sized, and oriented as previously described with respect to  FIGS. 17-19 . In addition, bit  600  includes a reamer section  260  as previously described with respect to  FIGS. 9-11 . Reamer section  260  extends radially from bit body  412  and is axially positioned between pin  414  and pilot bit  320 . Reamer section  260  includes cone cutters  271 ,  272 ,  273  configured, sized, and oriented as previously described with respect to  FIGS. 9-11 . 
     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 invention. 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.