Abstract:
A drill bit includes a bit body having a face on which two different types of cutters are disposed, the first type being cutting elements suitable for drilling at least one subterranean formation and the second type being at least one of an abrasive cutting structure and an abrasive cutting element suitable for drilling through a casing shoe, reamer shoe, casing bit, casing or liner string and cementing equipment or other components, as well as cement. Methods of forming earth-boring tools include disposing at least one abrasive cutting structure or element on the earth-boring tool. Methods of drilling with earth-boring tools including drilling with at least one abrasive cutting structure or element.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    The present application is a divisional of U.S. patent application Ser. No. 12/030,110, filed Feb. 12, 2008 and titled “Cutting Structures for Casing Component Drillout and Earth-Boring Drill Bits Including Same,” pending, which application claims the benefit of U.S. Provisional Patent Application Ser. No. 60/976,968, filed Oct. 2, 2007 and titled the same as above, the disclosure of each of which is incorporated herein by reference in its entirety. 
         [0002]    This application is related to U.S. patent application Ser. No. 12/129,308, filed May 29, 2008, pending, which is a divisional of U.S. patent application Ser. No. 10/783,720, filed Feb. 19, 2004, now U.S. Pat. No. 7,395,882, issued Jul. 8, 2008; U.S. patent application Ser. No. 11/928,956, filed Oct. 30, 2007, now U.S. Pat. No. 7,748,475, issued Jul. 6, 2010 which is a continuation of U.S. patent application Ser. No. 11/234,076, filed Sep. 23, 2005, now U.S. Pat. No. 7,624,818, issued Dec. 1, 2009; U.S. patent application Ser. No. 12/624,311, filed Nov. 23, 2009 which is a divisional of U.S. application Ser. No. 11/747,651, filed May 11, 2007, now U.S. Pat. No. 7,621,351, issued Nov. 24, 2009, pending, which claims the benefit of U.S. Provisional Patent Application Ser. No. 60/800,621; U.S. patent application Ser. No. 11/524,503, filed Sep. 20, 2006, pending; U.S. patent application Ser. No. 11/764,008, filed Jun. 15, 2007, now U.S. Pat. No. 7,836,978, issued Nov. 23, 2010; U.S. patent application Ser. No. 10/916,342, filed Aug. 10, 2004, now U.S. Pat. No. 7,178,609, issued Feb. 20, 2007; and U.S. patent application Ser. No. 11/166,471, filed Jun. 24, 2005, now U.S. Pat. No. 7,757,784 issued Jul. 20, 2010. 
     
    
     TECHNICAL FIELD 
       [0003]    Embodiments of the present invention relate generally to drilling a subterranean borehole. More specifically, some embodiments relate to drill bits and tools for drilling subterranean formations and having a capability for drilling out structures and materials which may be located at, or proximate to, the end of a casing or liner string, such as a casing bit or shoe, cementing equipment components and cement before drilling a subterranean formation. Other embodiments relate to drill bits and tools for drilling through the sidewall of a casing or liner string and surrounding cement before drilling an adjacent formation. 
       BACKGROUND 
       [0004]    Drilling wells for oil and gas production conventionally employs longitudinally extending sections, or so-called “strings,” of drill pipe to which, at one end, is secured a drill bit of a larger diameter. After a selected portion of the borehole has been drilled, a string of tubular members of lesser diameter than the borehole, known as casing, is placed in the borehole. Subsequently, the annulus between the wall of the borehole and the outside of the casing is filled with cement. Therefore, drilling and casing according to the conventional process typically requires sequentially drilling the borehole using drill string with a drill bit attached thereto, removing the drill string and drill bit from the borehole, and disposing and cementing a casing into the borehole. Further, often after a section of the borehole is lined with casing and cemented, additional drilling beyond the end of the casing or through a sidewall of the casing may be desired. In some instances, a string of smaller tubular members, known as a liner string, is run and cemented within previously run casing. As used herein, the term “casing” includes tubular members in the form of liners. 
         [0005]    Because sequential drilling and running a casing or liner string may be time consuming and costly, some approaches have been developed to increase efficiency, including the use of reamer shoes disposed on the end of a casing string and drilling with the casing itself. Reamer shoes employ cutting elements on the leading end that can drill through modest obstructions and irregularities within a borehole that has been previously drilled, facilitating running of a casing string and ensuring adequate well bore diameter for subsequent cementing. Reamer shoes also include an end section manufactured from a material that is readily drillable by drill bits. Accordingly, when cemented into place, reamer shoes usually pose no difficulty to a subsequent drill bit to drill through. For instance, U.S. Pat. No. 6,062,326 to Strong et al. discloses a casing shoe or reamer shoe in which the central portion thereof may be configured to be drilled through. However, the use of reamer shoes requires the retrieval of the drill bit and drill string used to drill the borehole before the casing string with the reamer shoe is run into the borehole. 
         [0006]    Drilling with casing is effected using a specially designed drill bit, termed a “casing bit,” attached to the end of the casing string. The casing bit functions not only to drill the earth formation, but also to guide the casing into the borehole. The casing string is, thus, run into the borehole as it is drilled by the casing bit, eliminating the necessity of retrieving a drill string and drill bit after reaching a target depth where cementing is desired. While this approach greatly increases the efficiency of the drilling procedure, further drilling to a greater depth must pass through or around the casing bit attached to the end of the casing string. 
         [0007]    In the case of a casing shoe, reamer shoe or casing bit that is drillable, further drilling may be accomplished with a smaller diameter drill bit and casing string attached thereto that passes through the interior of the first casing string to drill the further section of the borehole beyond the previously attained depth. Of course, cementing and further drilling may be repeated as necessary, with correspondingly smaller and smaller tubular components, until the desired depth of the wellbore is achieved. 
         [0008]    However, where a conventional drill bit is employed and it is desired to leave the bit in the well bore, further drilling may be difficult, as conventional drill bits are required to remove rock from formations and, accordingly, often include very drilling-resistant, robust structures typically manufactured from materials such as tungsten carbide, polycrystalline diamond, or steel. Attempting to drill through a conventional drill bit affixed to the end of a casing may result in damage to the subsequent drill bit and bottom-hole assembly deployed. It may be possible to drill through casing above a conventional drill bit with special tools known as mills, but these tools are generally unable to penetrate rock formations effectively to any great distance and, so, would have to be retrieved or “tripped” from the borehole and replaced with a drill bit. In this case, the time and expense saved by drilling with casing would have been lost. 
         [0009]    To enable effective drilling of casing and casing-associated components manufactured from robust, relatively inexpensive and drillable iron-based materials such as, for example, high-strength alloy steels, which are generally non-drillable by diamond cutting elements as well as subsequent drilling through the adjacent formation, it would be desirable to have a drill bit or tool offering the capability of drilling through such casing or casing-associated components, while at the same time offering the subterranean drilling capabilities of a conventional drill bit or tool employing superabrasive cutting elements. 
       BRIEF SUMMARY 
       [0010]    Various embodiments of the present invention are directed toward an earth-boring tool for drilling through casing components and associated material. In one embodiment, an earth-boring tool of the present invention may comprise a body having a face at a leading end thereof. The face may comprise a plurality of generally radially extending blades. A plurality of cutting elements may be disposed on the plurality of blades over the body. At least one elongated abrasive cutting structure may be disposed over the body and may extend radially outward along at least one of the plurality of blades in association with at least some of the plurality of cutting elements. The at least one elongated abrasive cutting structure may have a greater relative exposure than the plurality of cutting elements. 
         [0011]    In other embodiments, an earth-boring tool may comprise a body having a face at a leading end thereof, and a plurality of generally radially extending blades over the face. A plurality of cutting elements may be disposed on the plurality of blades. A plurality of abrasive cutting structures may be disposed over at least one of the plurality of blades in association with at least some of the plurality of cutting elements. The plurality of abrasive cutting structures may have a greater relative exposure than the plurality of cutting elements, and the plurality of abrasive cutting structures may comprise a composite material comprising a plurality of carbide particles in a matrix material. The plurality of carbide particles may comprise substantially rough or sharp edges. 
         [0012]    Other embodiments of the present invention comprise methods of forming an earth-boring tool. The method may comprise forming a bit body comprising a face at a leading end thereof. The face may comprise a plurality of generally radially extending blades thereon. A plurality of cutting elements may be disposed on the plurality of blades. At least one abrasive cutting structure may be disposed on at least one of the plurality of blades in association with at least one of the plurality of cutting elements. The at least one abrasive cutting structure may comprise a composite material comprising a plurality of hard particles with substantially rough surfaces in a matrix material. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0013]      FIG. 1  shows a perspective view of an embodiment of a drill bit of the present invention; 
           [0014]      FIG. 2  shows an enlarged perspective view of a portion of the embodiment of  FIG. 1 ; 
           [0015]      FIG. 3  shows an enlarged view of a face of the drill bit of  FIG. 1 ; 
           [0016]      FIG. 4  shows a perspective view of a portion of another embodiment of a drill bit of the present invention; 
           [0017]      FIG. 5  shows an enlarged view of a face of a variation of the embodiment of  FIG. 4 ; 
           [0018]      FIG. 6  shows a schematic side cross-sectional view of a cutting element placement design of a drill bit according to the embodiment of  FIG. 1  showing relative exposures of cutting elements and cutting structures disposed thereon; 
           [0019]      FIG. 7  shows a schematic side cross-sectional view of a cutting element placement design of a drill bit according to the embodiment of  FIG. 4  showing relative exposures of cutting elements and a cutting structure disposed thereon. 
           [0020]      FIG. 8  shows a perspective view of another embodiment of a drill bit of the present invention; 
           [0021]      FIG. 9  shows an enlarged perspective view of a portion of the drill bit of  FIG. 8 ; 
           [0022]      FIG. 10A  is a perspective view of one embodiment of a cutting element suitable for drilling through a casing bit and, if present, cementing equipment components within a casing above the casing bit,  FIG. 10B  is a front elevational view of the cutting element of  FIG. 10A , and  FIG. 10C  is a side elevational view of the cutting element of  FIG. 10A ; and 
           [0023]      FIG. 11  shows a schematic side cross-sectional view of a cutting element placement configuration of the drill bit of  FIG. 8  showing relative exposures of first and second cutting element structures disposed thereon. 
       
    
    
     DETAILED DESCRIPTION 
       [0024]    The illustrations presented herein are, in some instances, not actual views of any particular cutting element, cutting structure, or drill bit, but are merely idealized representations, which are employed to describe the present invention. Additionally, elements common between figures may retain the same numerical designation. 
         [0025]      FIGS. 1-5  illustrate several variations of an embodiment of a drill bit  12  in the form of a fixed-cutter or so-called “drag” bit, according to the present invention. For the sake of clarity, like numerals have been used to identify like features in  FIGS. 1-5 . As shown in  FIG. 1-5 , drill bit  12  includes a body  14  having a face  26  and generally radially extending blades  22 , forming fluid courses  24  therebetween extending to junk slots  35  between circumferentially adjacent blades  22 . Body  14  may comprise a tungsten carbide matrix or a steel body, both are well-known in the art. Blades  22  may also include pockets  30 , which may be configured to receive cutting elements of one type such as, for instance, superabrasive cutting elements in the faun of polycrystalline diamond compact (PDC) cutting elements  32 . Generally, such a PDC cutting element may comprise a superabrasive (diamond) mass that is bonded to a substrate. Rotary drag bits employing PDC cutting elements have been employed for several decades. PDC cutting elements are typically comprised of a disc-shaped diamond “table” formed on and bonded under an ultra high-pressure and high-temperature (HPHT) process to a supporting substrate formed of cemented tungsten carbide (WC), although other configurations are known. Drill bits carrying PDC cutting elements, which, for example, may be brazed into pockets in the bit face, pockets in blades extending from the face, or mounted to studs inserted into the bit body, are known in the art. Thus, PDC cutting elements  32  may be affixed upon the blades  22  of drill bit  12  by way of brazing, welding, or as otherwise known in the art. If PDC cutting elements  32  are employed, they may be back raked at a common angle, or at varying angles. By way of non-limiting example, PDC cutting elements  32  may be back raked at 15° within the cone of the bit face proximate the centerline of the bit, at 20° over the nose and shoulder, and at 30° at the gage. It is also contemplated that cutting elements  32  may comprise suitably mounted and exposed natural diamonds, thermally stable polycrystalline diamond compacts, cubic boron nitride compacts, or diamond grit-impregnated segments, as known in the art and as may be selected in consideration of the hardness and abrasiveness of the subterranean formation or formations to be drilled. 
         [0026]    Also, each of blades  22  may include a gage region  25 , which is configured to define the outermost radius of the drill bit  12  and, thus the radius of the wall surface of a borehole drilled thereby. Gage regions  25  comprise longitudinally upward (as the drill bit  12  is oriented during use) extensions of blades  22 , extending from nose portion  20  and may have wear-resistant inserts or coatings, such as cutting elements in the form of gage trimmers of natural or synthetic diamond, hardfacing material, or both, on radially outer surfaces thereof as known in the art. 
         [0027]    Drill bit  12  may also be provided with abrasive cutting structures  36  of another type different from the cutting elements  32 . Abrasive cutting structures  36  may comprise a composite material comprising a plurality of hard particles in a matrix. The plurality of hard particles may comprise a carbide material such as tungsten (W), Ti, Mo, Nb, V, Hf, Ta, Cr, Zr, Al, and Si carbide, or a ceramic. The plurality of particles may comprise one or more of coarse, medium or fine particles comprising substantially rough, jagged edges. By way of example and not limitation, the plurality of particles may comprise sizes selected from the range of sizes including ½-inch particles to particles fitting through a screen having 30 openings per square inch (30 mesh). Particles comprising sizes in the range of ½-inch to 3/16-inch may be termed “coarse” particles, while particles comprising sizes in the range of 3/16-inch to 1/16-inch may be termed “medium” particles, and particles comprising sizes in the range of 10 mesh to 30 mesh may be termed “fine” particles. The rough, jagged edges of the plurality of particles may be formed as a result of forming the plurality of particles by crushing the material of which the particles are formed. In some embodiments of the present invention the hard particles may comprise a plurality of crushed sintered tungsten carbide particles comprising sharp, jagged edges. The tungsten carbide particles may comprise particles in the range of ⅛ inch to 3/16 inch, particles within or proximate such a size range being termed “medium-sized” particles. The matrix material may comprise a high-strength, low-melting point alloy, such as a copper alloy. The material may be such that in use, the matrix material may wear away to constantly expose new pieces and rough edges of the hard particles, allowing the rough edges of the hard particles to more effectively engage the casing components and associated material. In some embodiments of the present invention, the copper alloy may comprise a composition of copper, zinc and nickel. By way of example and not limitation, the copper alloy may comprise approximately 48% copper, 41% zinc, and 10% nickel by weight. 
         [0028]    A non-limiting example of a suitable material for abrasive cutting structures  36  includes a composite material manufactured under the trade name KUTRITE® by B &amp; W Metals Co., Inc. of Houston Tex. The KUTRITE® composite material comprises crushed sintered tungsten carbide particles in a copper alloy having an ultimate tensile strength of 100,000 psi. Furthermore, KUTRITE® is supplied as composite rods and has a melting temperature of 1785° F., allowing the abrasive cutting structures  36  to be foinied using oxyacetylene welding equipment to weld the cutting structure material in a desired position on the drill bit  12 . The abrasive cutting structures  36  may, therefore, be formed and shaped while welding the material onto the blades  22 . In some embodiments, the abrasive cutting structures  36  may be disposed directly on exterior surfaces of blades  22 . In other embodiments, pockets or troughs  34  may be formed in blades  22 , which may be configured to receive the abrasive cutting structures  36 . 
         [0029]    In some embodiments, as shown in  FIGS. 1-3 , abrasive cutting structures  36  may comprise a protuberant lump or wear knot structure, wherein a plurality of abrasive cutting structures  36  are positioned adjacent one another along blades  22 . The wear knot structures may be formed by welding the material, such as from a composite rod like that described above with relation to the KUTRITE®, in which the matrix material comprising the abrasive cutting structures is melted onto the desired location. In other words, the matrix material may be heated to its melting point and the matrix material with the hard particles is, therefore, allowed to flow onto the desired surface of the blades  22 . Melting the material onto the surface of the blade  22  may require containing the material to a specific location and/or to manually shape the material into the desired shape during the application process. In some embodiments, the wear knots may comprise a pre-formed structure and may be secured to the blade  22  by brazing. Regardless whether the wear knots are pre-formed or formed directly on the blades  22 , the wear knots may be formed to comprise any suitable shape, which may be selected according to the specific application. By way of example and not limitation, the wear knots may comprise a generally cylindrical shape, a post shape, or a semi-spherical shape. Some embodiments may have a substantially flattened top and others may have a pointed or chisel-shaped top as well as a variety of other configurations. The size and shape of the plurality of hard particles may form in a surface that is rough and jagged, which may aid in cutting through the casing components and associated material, although, the invention is not so limited. Indeed, some embodiments may comprise surfaces that are substantially smooth and the rough and jagged hard particles may be exposed as the matrix material wears away. 
         [0030]    In other embodiments, as shown in  FIGS. 4 and 5 , abrasive cutting structures  36  may be configured as single, elongated structures extending radially outward along blades  22 . Similar to the wear knots, the elongated structures may be formed by melting the matrix material and shaping the material on the blade  22 , or the elongated structures may comprise pre-foamed structures, which may be secured to the blade  22  by brazing. Furthermore, the elongated structures may similarly comprise surfaces that are rough and jagged as well as surfaces that may be substantially smooth. The substantially smooth surface being worn away during use to expose the rough and jagged hard particles. 
         [0031]    It is desirable to select or tailor the thickness or thicknesses of abrasive cutting structures  36  to provide sufficient material therein to cut through a casing bit or other structure between the interior of the casing and the surrounding formation to be drilled without incurring any substantial and potentially damaging contact of cutting elements  32  with the casing bit or other structure. In embodiments employing a plurality of abrasive cutting structures  36  configured as wear knots adjacent one another ( FIGS. 1-3 ), the plurality of abrasive cutting structures  36  may be positioned such that each abrasive cutting structure  36  is associated with and positioned rotationally behind a cutting element  32 . The plurality of abrasive cutting structures  36  may be substantially uniform in size or the abrasive cutting structures  36  may vary in size. By way of example and not limitation, the abrasive cutting structures  36  may vary in size such that the cutting structures  36  positioned at more radially outward locations (and, thus, which traverse relatively greater distance for each rotation of drill bit  12  than those, for example, within the cone of drill bit  12 ) may be greater in size or at least in exposure so as to accommodate greater wear. 
         [0032]    Similarly, in embodiments employing single, elongated structures on the blades  22 , abrasive cutting structures  36  may be of substantially uniform thickness, taken in the direction of intended bit rotation, as depicted in  FIG. 4 , or abrasive cutting structures  36  may be of varying thickness, taken in the direction of bit rotation, as depicted in  FIG. 5 . By way of example and not limitation, abrasive cutting structures  36  at more radially outward locations may be thicker. In other embodiments, the abrasive cutting structures  36  may comprise a thickness to cover substantially the whole surface of the blades  22  behind the cutting elements  32 . 
         [0033]    In some embodiments, a plurality of discrete cutters  50  may be positioned proximate the cutting structures  36 . Embodiments of the present invention may comprise discrete cutters  50 , which rotationally “lead” the cutting structures  36  as illustrated in  FIG. 5 , rotationally “follow” the cutting structures  36 , or which are disposed at least partially within or surrounded by the cutting structures  36 . The discrete cutters  50  may comprise cutters similar to those described in U.S. Patent Publication 2007/0079995, the disclosure of which is incorporated herein in its entirety by this reference. Other suitable discrete cutters  50  may include the abrasive cutting elements  42  ( FIGS. 8-10C ) described in greater detail below. In some embodiments, the discrete cutters  50  may be disposed on blades  22  proximate the cutting structures  36  such that the discrete cutters  50  have a relative exposure greater than the relative exposure of cutting structures  36 , such that the discrete cutters  50  come into contact with casing components before the cutting structures  36 . In other embodiments, the discrete cutters  50  and the cutting structures  36  have approximately the same relative exposure. In still other embodiments, the discrete cutters  50  have a relative exposure less than the relative exposure of cutting structures  36 . In embodiments having a lower relative exposure than the cutting structures  36 , and in which the discrete cutters  50  are disposed within the cutting structures  36 , the discrete cutters  50  may be at least partially covered by the material comprising cutting structures  36 . 
         [0034]    Also as shown in  FIGS. 1-5 , abrasive cutting structures  36  may extend along an area from the cone of the drill bit  12  out to the shoulder (in the area from the centerline L ( FIGS. 6 and 7 ) to gage regions  25 ) to provide maximum protection for cutting elements  32 , which are highly susceptible to damage when drilling casing assembly components. Cutting elements  32  and abrasive cutting structures  36  may be respectively dimensioned and configured, in combination with the respective depths and locations of pockets  30  and, when present, troughs  34 , to provide abrasive cutting structures  36  with a greater relative exposure than superabrasive cutting elements  32 . As used herein, the term “exposure” of a cutting element generally indicates its distance of protrusion above a portion of a drill bit, for example a blade surface or the profile thereof, to which it is mounted. However, in reference specifically to the present invention, “relative exposure” is used to denote a difference in exposure between a cutting element  32  and a cutting structure  36  (as well as an abrasive cutting element  42  described below). More specifically, the term “relative exposure” may be used to denote a difference in exposure between one cutting element  32  and a cutting structure  36  (or abrasive cutting element  42 ) which, optionally, may be proximately located in a direction of bit rotation and along the same or similar rotational path. In the embodiments depicted in  FIGS. 1-5 , abrasive cutting structures  36  may generally be described as rotationally “following” superabrasive cutting elements  32  and in close rotational proximity on the same blade  22 . However, abrasive cutting structures  36  may also be located to rotationally “lead” associated superabrasive cutting elements  32 , to fill an area between laterally adjacent superabrasive cutting elements  32 , or both. 
         [0035]    By way of illustration of the foregoing,  FIG. 6  shows a schematic side view of a cutting element placement design for drill bit  12  showing cutting elements  32 ,  32 ′ and cutting structures  36  as disposed on a drill bit (not shown) such as an embodiment of drill bit  12  as shown in  FIGS. 1-3 .  FIG. 7  shows a similar schematic side view showing cutting elements  32 ,  32 ′ and cutting structure  36  as disposed on a drill bit (not shown) such as an embodiment of drill bit  12  as shown in  FIGS. 4 and 5 . Both  FIGS. 6 and 7 , show cutting elements  32 ,  32 ′ and cutting structures  36  in relation to the longitudinal axis or centerline L and drilling profile P thereof, as if all the cutting elements  32 ,  32 ′, and cutting structures  36  were rotated onto a single blade (not shown). Particularly, cutting structures  36  may be sized, configured, and positioned so as to engage and drill a first material or region, such as a casing shoe, casing bit, cementing equipment component or other downhole component. Further, the cutting structures  36  may be further configured to drill through a region of cement that surrounds a casing shoe, if it has been cemented within a well bore, as known in the art. In addition, a plurality of cutting elements  32  may be sized, configured, and positioned to drill into a subterranean formation. Also, cutting elements  32 ′ are shown as configured with radially outwardly oriented flats and positioned to cut a gage diameter of drill bit  12 , but the gage region of the cutting element placement design for drill bit  12  may also include cutting elements  32  and cutting structures  36 . The present invention contemplates that the cutting structures  36  may be more exposed than the plurality of cutting elements  32  and  32 ′. In this way, the cutting structures  36  may be sacrificial in relation to the plurality of cutting elements  32  and  32 ′. Explaining further, the cutting structures  36  may be configured to initially engage and drill through materials and regions that are different from subsequent materials and regions than the plurality of cutting elements  32  and  32 ′ is configured to engage and drill through. 
         [0036]    Accordingly, the cutting structures  36  may comprise an abrasive material, as described above, while the plurality of cutting elements  32  and  32 ′ may comprise PDC cutting elements. Such a configuration may facilitate drilling through a casing shoe or bit, as well as cementing equipment components within the casing on which the casing shoe or bit is disposed as well as the cement thereabout with primarily the cutting structures  36 . However, upon passing into a subterranean formation, the abrasiveness of the subterranean formation material being drilled may wear away the material of cutting structures  36  to enable the plurality of PDC cutting elements  32  to engage the formation. As shown in  FIGS. 1-5 , one or more of the plurality of cutting elements  32  may rotationally precede the cutting structures  36 , without limitation. Alternatively, one or more of the plurality of cutting elements  32  may rotationally follow the cutting structures  36 . 
         [0037]    Notably, after the material of cutting structures  36  has been worn away by the abrasiveness of the subterranean formation material being drilled, the PDC cutting elements  32  are relieved and may drill more efficiently. Further, the materials selected for the cutting structures  36  may allow the cutting structures  36  to wear away relatively quickly and thoroughly so that the PDC cutting elements  32  may engage the subterranean formation material more efficiently and without interference from the cutting structures  36 . 
         [0038]    In some embodiments, a layer of sacrificial material  38  ( FIG. 7 ) may be initially disposed on the surface of a blade  22  or in optional pocket or trough  34  and the tungsten carbide of one or more cutting structures  36  disposed thereover. Sacrificial material  38  may comprise a low-carbide or no-carbide material that may be configured to wear away quickly upon engaging the subterranean formation material in order to more readily expose the plurality of cutting elements  32 . The sacrificial material  38  may have a relative exposure less than the plurality of cutting elements  32 , but the one or more cutting structures  36  disposed thereon will achieve a total relative exposure greater than that of the plurality of cutting elements  32 . In other words, the sacrificial material  38  may be disposed on blades  22 , and optionally in a pocket or trough  34 , having an exposure less than the exposure of the plurality of cutting elements  32 . The one or more cutting structures  36  may then be disposed over the sacrificial material  38 , the one or more cutting structures  36  having an exposure greater than the plurality of cutting elements  32 . By way of example and not limitation, a suitable exposure for sacrificial material  38  may be two-thirds or three-fourths of the exposure of the plurality of cutting elements  32 . 
         [0039]    Recently, new cutting elements configured for casing component drillout have been disclosed and claimed in U.S. Patent Publication 2007/0079995, referenced above.  FIGS. 8 and 9  illustrate several variations of an additional embodiment of a drill bit  12  in the form of a fixed-cutter or so-called “drag” bit, according to the present invention. In these embodiments, drill bit  12  may be provided with, for example, pockets  40  in blades  22 , which may be configured to receive abrasive cutting elements  42  of another type, different from the first type of cutting elements  32  such as, for instance, tungsten carbide cutting elements. It is also contemplated, however, that abrasive cutting elements  42  may comprise, for example, a carbide material other than tungsten (W) carbide, such as a Ti, Mo, Nb, V, Hf, Ta, Cr, Zr, Al, and Si carbide, or a ceramic. Abrasive cutting elements  42  may be secured within pockets  40  by welding, brazing or as otherwise known in the art. Abrasive cutting elements  42  may be of substantially uniform thickness, taken in the direction of intended bit rotation. In other embodiments, and similar to cutting structures  36  above, abrasive cutting elements  42  may be of varying thickness, taken in the direction of bit rotation, wherein abrasive cutting elements  42  at more radially outwardly locations (and, thus, which traverse relatively greater distance for each rotation of drill bit  12  than those, for example, within the cone of dill bit  12 ) may be thicker to ensure adequate material thereof will remain for cutting casing components and cement until they are to be worn away by contact with formation material after the casing components and cement are penetrated. It is desirable to select or tailor the thickness or thicknesses of abrasive cutting elements  42  to provide sufficient material therein to cut through a casing bit or other structure between the interior of the casing and the surrounding formation to be drilled, without incurring any substantial and potentially damaging contact of superabrasive cutting elements  32  with the casing bit or other structure. 
         [0040]    Also as shown in  FIGS. 8 and 9 , like the abrasive cutting structure  36  described above, abrasive cutting elements  42  may be placed on the blades  22  of a drill bit  12  from the cone of the drill bit  12  out to the shoulder to provide maximum protection for cutting elements  32 . Abrasive cutting elements  42  may be back raked, by way of non-limiting example, at an angle of 5°. Broadly, cutting elements  32  on face  26 , which may be defined as surfaces up to 90° profile angles, or angles with respect to centerline L, are desirably protected. Abrasive cutting elements  42  may also be placed selectively along the profile of the face  26  to provide enhanced protection to certain areas of the face  26  and for cutting elements  32  thereon, as well as for cutting elements  32 ′, if present on the gage regions  25 . 
         [0041]      FIGS. 10A-10C  depict one example of a suitable configuration for abrasive cutting elements  42 , including a cylindrical body  100 , which may also be characterized as being of a “post” shape, of tungsten carbide or other suitable material for cutting casing or casing components, including a bottom  102 , which will rest on the bottom of pocket  40 . Cylindrical body  100  may provide increased strength against normal and rotational forces as well as increased ease with which a cutting element  42  may be replaced. Although body  100  is configured as a cylinder in  FIGS. 10A-10C , and thus exhibits a circular cross-section, one of ordinary skill in the art will recognize that other suitable configurations may be employed for body  100 , including those exhibiting a cross section that is, by way of example and not limitation, substantially ovoid, rectangular, or square. 
         [0042]    In a non-limiting example, the cylindrical body  100  extends to a top portion  104  including a notched area  106  positioned in a rotationally leading portion thereof. The top portion  104  is illustrated as semi-spherical, although many other configurations are possible and will be apparent to one of ordinary skill in the art. Notched area  106  comprises a substantially flat cutting face  108  extending to a chamfer  110  that leads to an uppermost extent of top portion  104 . Cutting face  108  may be formed at, for example, a forward rake, a neutral (about 0°) rake or a back rake of up to about 25°, for effective cutting of a casing shoe, reamer shoe, casing bit, cementing equipment components, and cement, although a specific range of back rakes for cutting elements  42  and cutting faces  108  is not limiting of the present invention. Cutting face  108  is of a configuration relating to the shape of top portion  104 . For example, a semi-spherical top portion  104  provides a semicircular cutting face  108 , as illustrated. However, other cutting face and top portion configurations are possible. By way of a non-limiting example, the top portion  104  may be configured in a manner to provide a cutting face  108  shaped in any of ovoid, rectangular, tombstone, triangular etc. 
         [0043]    Any of the foregoing configurations for an abrasive cutting element  42  may be implemented in the form of a cutting element having a tough or ductile core covered on one or more exterior surfaces with a wear-resistant coating such as tungsten carbide or titanium nitride. 
         [0044]    In some embodiments of the present invention, a drill bit, such as drill bit  12 , may employ a combination of abrasive cutting structures  36  and abrasive cutting elements  42 . In such embodiments, the abrasive cutting structures  36  and abrasive cutting elements  42  may have a similar exposure. In other embodiments, one of the abrasive cutting structures  36  and abrasive cutting elements  42  may have a greater relative exposure than the other. For example, a greater exposure for some of cutting structures  36  and/or abrasive cutting elements  42  may be selected to ensure preferential initial engagement of same with portions of a casing-associated component or casing sidewall. 
         [0045]    While examples of specific cutting element configurations for cutting casing-associated components and cement, on the one hand, and subterranean formation material on the other hand, have been depicted and described, the invention is not so limited. The cutting element configurations as disclosed herein are merely examples of designs, which the inventors believe are suitable. Other cutting element designs for cutting casing-associated components may employ, for example, additional chamfers or cutting edges, or no chamfer or cutting edge at all may be employed. Examples of some suitable non-limiting embodiments of chamfers or cutting edges are described in U.S. Patent Publication 2007/0079995, referenced above. Likewise, superabrasive cutting elements design and manufacture is a highly developed, sophisticated technology, and it is well-known in the art to match superabrasive cutting element designs and materials to a specific formation or formations intended to be drilled. 
         [0046]      FIG. 11  shows a schematic side view of a cutting element placement design similar to  FIGS. 6 and 7  showing cutting elements  32 ,  32 ′ and  42 . Particularly, a plurality of abrasive cutting elements  42  may be sized, configured, and positioned so as to engage and drill downhole components, such as a casing shoe, casing bit, cementing equipment component, cement or other downhole components. In addition, a plurality of cutting elements  32  may be sized, configured, and positioned to drill into a subterranean formation. Also, cutting elements  32 ′ are shown as configured with radially outwardly oriented flats and positioned to cut a gage diameter of drill bit  12 , but the gage region of the cutting element placement design for drill bit  12  may also include cutting elements  32  and abrasive cutting elements  42 . Embodiments of the present invention contemplate that the plurality of abrasive cutting elements  42  may be more exposed than the plurality of cutting elements  32 . In this way, the one plurality of cutting elements  42  may be sacrificial in relation to the another plurality of cutting elements  32 , as described above with relation to abrasive cutting structures  36  and cutting elements  32  in  FIG. 4 . Therefore, the plurality of abrasive cutting elements  42  may be configured to initially engage and drill through materials and regions that are different from subsequent material and regions that the plurality of cutting elements  32  are configured to engage and drill through. 
         [0047]    Accordingly, and similar to that described above with relation to  FIGS. 1-5 , the plurality of abrasive cutting elements  42  may be configured differently than the plurality of cutting elements  32 . Particularly, and as noted above, the plurality of abrasive cutting elements  42  may be configured to comprise tungsten carbide cutting elements, while the plurality of cutting elements  32  may comprise PDC cutting elements. Such a configuration may facilitate drilling through a casing shoe or bit, as well as cementing equipment components within the casing on which the casing shoe or bit is disposed as well as the cement thereabout with primarily the plurality of abrasive cutting elements  42 . However, upon passing into a subterranean formation, the abrasiveness of the subterranean formation material being drilled may wear away the tungsten carbide of the abrasive cutting elements  42 , and the plurality of PDC cutting elements  32  may engage the formation. As shown in  FIGS. 8 and 9 , one or more of the plurality of cutting elements  32  may rotationally precede one or more of the one plurality of abrasive cutting elements  42 , without limitation. Alternatively, one or more of the plurality of cutting elements  32  may rotationally follow one or more of the one plurality of abrasive cutting elements  42 , without limitation. 
         [0048]    Notably, after the abrasive cutting elements  42  have been worn away by the abrasiveness of the subterranean formation material being drilled, the PDC cutting elements  32  are relieved and may drill more efficiently. Further, it is believed that the worn abrasive cutting elements  42  may function as backups for the PDC cutting elements  32 , riding generally in the paths cut in the formation material by the PDC cutting elements  32  and enhancing stability of the drill bit  12 , enabling increased life of these cutting elements and consequent enhanced durability and drilling efficiency of drill bit  12 . 
         [0049]    While certain embodiments have been described and shown in the accompanying drawings, such embodiments are merely illustrative and not restrictive of the scope of the invention, and this invention is not limited to the specific constructions and arrangements shown and described, since various other additions and modifications to, and deletions from, the described embodiments will be apparent to one of ordinary skill in the art. Thus, the scope of the invention is only limited by the literal language, and legal equivalents of the claims, which follow.