Patent Publication Number: US-11649681-B2

Title: Fixed-cutter drill bits with reduced cutting arc length on innermost cutter

Description:
RELATED APPLICATIONS 
     This application is a U.S. National Stage Application of International Application No. PCT/US2018/059648 filed Nov. 7, 2018, which designates the United States. 
     TECHNICAL FIELD 
     The present disclosure relates generally to fixed-cutter drill bits. 
     BACKGROUND 
     Wellbores are most frequently formed in geological formations using rotary drill bits. Various types of rotary bits exist, but all of them experience some type of wear or fatigue from use that limits the overall life of the bit or the time it may spend downhole in the wellbore before being returned to the surface. The materials used in the bit and their ability to effectively cut different types of formations encountered as the wellbore progresses also sometimes necessitate removing the bit from the wellbore, replacing bit or components of it, and returning it downhole to resume cutting. 
     Particularly as wellbores reach greater lengths, the process of removing and returning a bit becomes increasingly time consuming and costly. Those who design, manufacture, and operate earth-boring drill bits and their components have an interest in improving the life of drill bit and their components. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       A more complete understanding of the present disclosure and its features and advantages thereof may be acquired by referring to the following description, taken in conjunction with the accompanying drawings, which are not necessarily to scale, in which like reference numbers indicate like features, with the addition of a, b, c, indicting variations of like features, −1 indicating a particular subset feature, and i, ii, etc. indicating additive parts of a feature, and wherein: 
         FIG.  1    is a schematic diagram of a drilling system in which a fixed-cutter drill bit in which the cutting arc length of the innermost cutter is reduced may be used; 
         FIG.  2    is an isometric view of a fixed-cutter drill bit with in which the cutting arc length of the innermost cutter is reduced; 
         FIG.  3    is a bit profile of the fixed-cutter drill bit of  FIG.  2   . 
         FIG.  4    is another bit profile of a fixed-cutter drill bit such as that of  FIG.  2   . 
         FIG.  5 A  is a schematic cutting view diagram of an innermost cutter of the fixed-cutter drill bit of  FIG.  2   , with a relieved cutting surface. An example cutting arc length of the relieved cutting surface is illustrated along with a comparative cutting arc length of a similar cutter without a relieved cutting surface. 
         FIG.  5 B  is a schematic cross-sectional diagram of the cutter of  FIG.  4 A . 
         FIG.  6 A  is a schematic cutting view diagram of another innermost cutter that may be used in the of the fixed-cutter drill bit of  FIG.  2   , with a relieved cutting surface. An example cutting arc length of the relieved cutting surface is illustrated along with a comparative cutting arc length of a similar cutter without a relieved cutting surface. 
         FIG.  6 B  is a schematic cross-sectional diagram of the cutter of  FIG.  6 A  on side A as indicated in  FIG.  6 A . 
         FIG.  6 C  is a schematic cross-sectional diagram of the cutter of  FIG.  6 A  on side B as indicated in  FIG.  6 A . 
         FIG.  6 D  is a schematic elevation diagram of the cutter of  FIG.  6 A . 
         FIG.  7    is a schematic cutting view diagram of another innermost cutter that may be used in the of the fixed-cutter drill bit of  FIG.  2   , with a relieved cutting surface. An example cutting arc length of the relieved cutting surface is illustrated along with a comparative cutting arc length of a similar cutter without a relieved cutting surface. 
         FIG.  8    is a schematic cutting view diagram of another innermost cutter that may be used in the of the fixed-cutter drill bit of  FIG.  2   , with a relieved cutting surface. An example cutting arc length of the relieved cutting surface is illustrated along with a comparative cutting arc length of a similar cutter without a relieved cutting surface. 
         FIG.  9    is a schematic cutting view diagram of another innermost cutter that may be used in the of the fixed-cutter drill bit of  FIG.  2   , with a relieved cutting surface. An example cutting arc length of the relieved cutting surface is illustrated along with a comparative cutting arc length of a similar cutter without a relieved cutting surface. 
         FIG.  10    is a schematic cutting view diagram of another innermost cutter that may be used in the of the fixed-cutter drill bit of  FIG.  2   , with a relieved cutting surface. An example cutting arc length of the relieved cutting surface is illustrated along with a comparative cutting arc length of a similar cutter without a relieved cutting surface. 
         FIG.  11    is a schematic cutting view diagram of another innermost cutter that may be used in the of the fixed-cutter drill bit of  FIG.  2   , with a relieved cutting surface. An example cutting arc length of the relieved cutting surface is illustrated along with a comparative cutting arc length of a similar cutter without a relieved cutting surface. 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure relates to fixed-cutter drill bits in which the cutting arc length of the innermost cutter is reduced, as well as systems for using such fixed-cutter drill bits to drill a wellbore in a geological formation. 
     The present disclosure may be further understood by referring to  FIGS.  1 - 11   , where like numbers are used to indicate like and corresponding parts. 
       FIG.  1    is a schematic diagram of a drilling system  100  configured to drill into one or more geological formations to form a wellbore  107 , sometimes also referred to as a borehole. Drilling system  100  may include a fixed-cutter drill bit  101  according to the present disclosure. 
     Drilling system  100  may include well surface or well site  106 . Various types of drilling equipment such as a rotary table, mud pumps and mud tanks (not expressly shown) may be located at a well surface or well site  106 . For example, well site  106  may include drilling rig  102  that may have various characteristics and features associated with a “land drilling rig.” However, fixed-cutter drill bits  101  according to the present disclosure may be satisfactorily used with drilling equipment located on offshore platforms, drill ships, semi-submersibles and drilling barges (not expressly shown). 
     Drilling system  100  may include drill string  103  associated with fixed-cutter drill bit  101  that may be used to rotate fixed-cutter drill bit  101  in radial direction  105  around bit rotational axis  104  of form a wide variety of wellbores  107  such as generally vertical wellbore  107   a  or generally horizontal wellbore  107   b  as shown in  FIG.  1   . Various directional drilling techniques and associated components of bottom hole assembly (BHA)  120  of drill string  103  may be used to form generally horizontal wellbore  107   b . For example, lateral forces may be applied to drill bit  101  proximate kickoff location  113  to form generally horizontal wellbore  107   b  extending from generally vertical wellbore  107   a . Wellbore  107  is drilled to a drilling distance, which is the distance between the well surface and the furthest extent of wellbore  107 , and which increases as drilling progresses. 
     BHA  120  may be formed from a wide variety of components configured to form a wellbore  107 . For example, components  121   a ,  121   b  and  121   c  of BHA  120  may include, but are not limited to fixed-cutter drill bit  101 , drill collars, rotary steering tools, directional drilling tools, downhole drilling motors, reamers, hole enlargers or stabilizers. The number of components such as drill collars and different types of components  121  included in BHA  120  may depend upon anticipated downhole drilling conditions and the type of wellbore that will be formed by drill string  103  and fixed-cutter drill bit  101 . 
     Wellbore  107  may be defined in part by casing string  110  that may extend from well site  106  to a selected downhole location. Various types of drilling fluid may be pumped from well site  106  through drill string  103  to attached drill bit  101 . Such drilling fluids may be directed to flow from drill string  103  to respective nozzles (item  156  illustrated in  FIG.  2 A ) included in fixed-cutter drill bit  101 . The drilling fluid may be circulated back to well surface  106  through annulus  108  defined in part by outside diameter  112  of drill string  103  and inside diameter  111  of casing string  110 . 
       FIG.  2    is an isometric view of fixed-cutter drill bit  101  oriented upwardly in a manner often used to model or design fixed-cutter drill bits. Fixed-cutter drill bit  101  may be designed and formed in accordance with teachings of the present disclosure and may have many different designs, configurations, and/or dimensions according to the particular application of drill bit  101 . 
     Uphole end  204  of fixed-cutter drill bit  101  may include shank  210  with drill pipe threads  211  formed thereon. Threads  211  may be used to releasably engage fixed-cutter drill bit  101  with BHA  120  (as shown in  FIG.  1   ), whereby fixed-cutter drill bit  101  may be rotated relative to bit rotational axis  104 . Downhole end  209  of fixed-cutter drill bit  101  may include a plurality of blades  202   a - 202   g  with respective junk slots or fluid flow paths disposed therebetween. Additionally, drilling fluids may be communicated to one or more nozzles  156 . 
     The plurality of blades  202  (e.g., blades  202   a - 202   g ) may be disposed outwardly from the exterior of bit body  201  of fixed-cutter drill bit  101 . Bit body  201  may be generally cylindrical and blades  202  may be any suitable type of projections extending outwardly (i.e. in a radial direction from rotational axis  104 ) from bit body  201 . For example, a portion of blade  202  may be directly or indirectly coupled to the exterior of bit body  201 , while another portion of blade  202  is projected away from the exterior of bit body  201 . Blades  202  may have a wide variety of configurations including, but not limited to, substantially arched, helical, spiraling, tapered, converging, diverging, symmetrical, and/or asymmetrical. 
     In some cases, one or more blades  202  may have a substantially arched configuration extending from proximate bit rotational axis  104  of fixed-cutter drill bit  101 . The arched configuration may be defined in part by a generally concave, recessed shaped portion extending from proximate bit rotational axis  104 . The arched configuration may also be defined in part by a generally convex, outwardly curved blade portion disposed between the concave, recessed blade portion and outer portions of each blade which correspond generally with the outside diameter of the rotary drill bit. 
     Blades  202   a - 202   g  may include primary blades disposed about the bit rotational axis. 
     For example, in  FIG.  2   , blades  202   a ,  202   c , and  202   e  may be primary blades or major blades because respective inner ends  212   a  of each of blades  202   a ,  202   c , and  202   e  may be disposed closely adjacent to the bit rotational axis  104  and closer to associated bit rotational axis  104  than the remainder for the respective blades. Blades  202   a - 202   g  may also include at least one secondary blade disposed between the primary blades. Blades  202   b ,  202   d ,  202   f , and  202   g  shown in  FIG.  2    on fixed-cutter drill bit  101  may be secondary blades or minor blades because respective inner ends  212   b  may be disposed on downhole end  209  a distance from associated bit rotational axis  104 . For example, the closest of inner ends  212   b  may have a closest distance from bit rotational axis  104  that is at least 1.5 times, at least 2 times, at least 3 times, or between 1.5 and 5 times, between 2 and 5 times, or between 3 and 5 times, inclusive, of the distance of the farthest of inner ends  212   a  from bit rotational axis  104 . The number and location of secondary blades and primary blades may vary such that fixed-cutter drill bit  101  includes fewer or greater secondary and primary blades than are shown in  FIG.  2   . Blades  202  may be disposed symmetrically or asymmetrically with regard to each other and bit rotational axis  104  where the disposition may be based on the downhole drilling conditions of the drilling environment. 
     Inner ends  212   a  of blades  202   a ,  202   c , and  202   e , are disposed closely adjacent to bit rotational axis  104 . Inner ends  212   a , along with a portion of bit body  201 , form a central bit surface  213 . During drilling, formation downhole of central bit surface  213  may either fracture and degrade with the surrounding formation during drilling, or it may form a short column of uncut formation. If a column of uncut formation is formed, it may then contacted by central bit surface  213  and crushed or destroyed as drilling progresses. The column of uncut formation is not retained by fixed-cutter drill bit  101  and may not be removed to the surface of wellbore  107  using fixed-cutter drill bit  101  or drill string  103 . 
     Central bit surface  213  may be adapted to limit wear if it crushes or destroys uncut formation or as a result of drilling fluid flow. For example, portions of central bit surface  213 , such as inner ends  212   a , a portion of bit body  201 , or an outer portion of a nozzle  156 , may formed from or coated with a wear-resistant material, such as polycrystalline diamond or tungsten carbide. 
     Any two, a plurality of, or all of inner ends  212   a  may have a longest distance from one another through bit rotational axis  104  that is between 0.000 inches and 0.500 inches. Alternatively, any two, a plurality of, or all of inner ends  212   a  may have a longest distance from one another through bit rotational axis  104  that is between 0 and 1/12 the total diameter of bit  101 . 
     In fixed-cutter drill bits  101  that do not have primary and secondary blades, all inner ends  212  may be treated in the same manner as inner ends  212   a  as described herein. 
     Blades  202  and fixed-cutter drill bit  101  may rotate about bit rotational axis  104  in a direction defined by directional arrow  105 . Each blade  202  may have a leading (or front) surface disposed on one side of the blade in the direction of rotation of fixed-cutter drill bit  101  and a trailing (or back) surface disposed on an opposite side of the blade away from the direction of rotation of fixed-cutter drill bit  101 . Blades  202  may be positioned along bit body  201  such that they have a spiral configuration relative to bit rotational axis  104 . Alternatively, blades  202  may be positioned along bit body  201  in a generally parallel configuration with respect to each other and bit rotational axis  104 . 
     Blades  202  include one or more cutters  203  disposed outwardly from outer portions of each blade  202 . For example, a portion of a cutter  203  may be directly or indirectly coupled to an exterior portion of blade  202  while another portion of the cutter  203  may be projected away from the exterior portion of blade  202 . Cutters  203  may be any suitable device configured to cut into a formation, such as various types of compacts, buttons, inserts, and gage cutters satisfactory for use with a wide variety of fixed-cutter drill bits  101 . 
     One or more of cutters  203  may include a substrate with a layer of hard cutting material  219  disposed on one end of the substrate  220 . The layer of hard cutting material  219  may be a compact, such as a polycrystalline diamond compact. The substrate may be a carbide, such as tungsten carbide. The layer of hard cutting material  219  may provide a cutting surface  214  of cutter  203 , a portion of which may engage adjacent portions of the formation to form wellbore  107 . The contact of the cutting surface  214  with the formation may form a cutting zone associated with each of cutter  203 . The edge of the cutting surface  214  located within the cutting zone may be referred to as the cutting edge of a cutter  203 . If cutter  203  has a cutting surface that is circular or circular in cross-section, then the cutting edge will have an arced portion referred to as the cutting arc. The length of the arced portion of the cutting edge is referred to as the cutting arc length. Cutter  203  may also include a side surface  215 . 
       FIG.  3    and  FIG.  4    are bit profiles for fixed-cutter drill bits both having a cutter profile  204 , corresponding to the cutters  203  prior to use of the bit to form a wellbore. The bit profiles also illustrate blade profiles  205 , which correspond to the exterior surfaces  206  of blades  202  near cutters  203 . 
     Innermost cutter  203 - 1 , which may also be referred to a cutter number one, is the single cutter, among all of the cutters  203  on the fixed-cutter drill bit  101 , located closest to the bit rotational axis  104 . Innermost cutter  203 - 1  may have a relief that is located within and interrupts its cutting arc so that the cutting arc has at least two portions located at opposite ends of the relief. In addition, innermost cutter  203 - 1  has a reduced cutting arc length as compared to a flat circular cutting arc length of a similar cutter with a cutting surface that is both flat and entirely circular. As a result, fixed-cutter drill bit  201  may have a track diagram in which the profile of innermost cutter  203 - 1  is reduced on the side adjacent bit rotational axis  104 , as shown in  FIG.  3    or in  FIG.  4   . 
     As shown in  FIG.  3   , the profile of innermost cutter  203 - 1  may be circular throughout the majority of the profile, but linear in an area corresponding to the relief on the side adjacent bit rotational axis  104  and generally parallel to bit rotational axis  104 , such that the linear profile may form an angle of within +/−2° of bit rotational axis  104 . 
     As shown in  FIG.  4   , the profile of innermost cutter  203 - 1  may be linear in an area corresponding to the relief on the side adjacent bit rotational axis  104  and may form an acute angle with the uphole end of bit rotational axis  104 . The acute angle may be greater than 2° and less than and inclusive of 20°, or greater than 2° and less than and inclusive of 10°. 
     If innermost cutter  203 - 1  has a non-linear profile in the area corresponding to the relief, then a generally linear approximation of the non-linear profile may have the same properties as the linear profile illustrated in  FIG.  3    and  FIG.  4   . 
     Innermost cutter  203 - 1  may also have a non-linear profile in an area corresponding to the relief on the side adjacent the bit rotational axis which may be generally linearly approximated. For example, the profile may be wavy, angular, or curved on the side adjacent bit rotational axis  104  in manner that is reduces the surface area of the profile as compared to if it were circular over the entire profile. For example, it may reduce the surface area by at least 5%, at least 10%, at least 20%, or by between 5% and 45%, between 5% and 30%, between 5% and 20%, between 10% and 45%, between 10% and 30%, between 20% and 30%, between 20% and 45%, or between 20% and 30%, inclusive. 
     The closest distance  207  between the innermost cutter  203 - 1  and the bit rotational axis  104  may be between −0.01 inch and +0.25 inch, inclusive. 
       FIG.  5 A  and  FIG.  5 B  show an innermost cutter  203 - 1   a  with a relieved cutting surface  214   a . Relieved cutting surface  214   a  is flattened and circular or oval over the majority of cutting surface  214   a , with the exception of relief  216   a , which is linear and which is located within and interrupts the cutting arc of the innermost cutter  203 - 1   a . Alternatively, cutting surface  214   a  might be ovoid. Cutting surface  214   a  may exhibit a profile as shown in  FIG.  3    or  FIG.  4   , depending on its orientation in fixed-cutter dill bit  101 . Cutting surface  214   a  has a cutting arc length  217   a  which is the sum of the length of the two circular portions  217   a - i  and  217   a - ii . Cutting arc length  217   a  is less than a flat circular or oval cutting arc length  218  that would be exhibited if the cutting surface  214   a  were entirely circular or oval. Cutting arc length  217   a  may be reduced as compared to flat circular (if cutting surface  214   a  is circular) or oval (if cutting surface  214   a  is oval) cutting arc length  218  by at least 5%, at least 10%, at least 20%, or by between 5% and 45%, between 5% and 30%, between 5% and 20%, between 10% and 45%, between 10% and 30%, between 20% and 30%, between 20% and 45%, or between 20% and 30%, inclusive. 
     As shown in  FIGS.  6 A,  6 B,  6 C,  6 D,  7 ,  8 ,  9 ,  10 , and  11   , for innermost cutter  203 - 1  also having a flattened cutting surface  214 , relief  216  may also be wavy, angled, or curved. Also as shown in  FIGS.  6 A- 11   , innermost cutter  203 - 1  may have more than one reliefs  216 , allowing the cutter to be rotated in a pocket in the fixed-cutter drill bit  101  once worn on one side and used to continue to drill without replacement of innermost cutter  203 - 1 . For simplicity, only one cutting arc length  217  is illustrated in  FIGS.  6 A- 11   . If innermost cutter  203 - 1  were rotated so that another a relief  216  were in the cutting area, then that relief  216  would then have an associated and similar cutting arc length. Typically, if multiple reliefs  216  are present, then they will be similar or identical in geometry and will be placed at regular intervals around the circumference of innermost cutter  203 - 1 , such as with centers on opposite sides of the cutting surface  214  (spaced radially 180 degrees from one another) as illustrated in  FIGS.  6 A- 7 ,  9  and  11   , or with centers spaced radially 120 degrees from one another, as illustrated in  FIGS.  8  and  10   . 
     As illustrated in  FIG.  6 A , relief  216   b  may have a wavy profile that extends inward from where the boundaries of flattened cutting surface  214   b  would be if the cutting surface were entirely circular or oval. As illustrated in  FIGS.  7  and  8   , reliefs  216   c  and  216   d  may both have a linear profile as in  FIGS.  5 A and  5 B , but two reliefs  216   c  with centers on opposite sides of the cutting surface  214   d  ( FIG.  7   ) or three reliefs  216   d  with centers spaced radially 120 degrees from one another on the cutting surface  214   d  ( FIG.  8   ) may be present. As illustrated in  FIGS.  9  and  10   , reliefs  216   e  and  216   f  may have a curved profile that extends inward from where the boundaries of cutting surface  214  would be if it were entirely circular or oval, with two reliefs  216   e  with centers on opposite sides of the cutting surface  214   e  ( FIG.  9   ) or three reliefs  216   f  with centers spaced radially 120 degrees from one another on the cutting surface  214   f  ( FIG.  10   ) being present. As illustrated in  FIG.  11   , reliefs  216   g  may be angled, with two linear portions that meet at an angle within where the boundaries of cutting surface  214   g  would be if it were entirely circular or oval. The angle may be between 100 degrees and 170 degrees inclusive. 
     As shown in  FIGS.  5 A- 11   , relief  216  may reduce the surface area of flattened cutting surface  214  as compared to what the surface area would be if cutting surface were entirely circular or oval. In particular, the surface area of cutting surface  214  may be reduced by at least 5%, at least 10%, at least 20%, or by between 5% and 45%, between 5% and 30%, between 5% and 20%, between 10% and 45%, between 10% and 30%, between 20% and 30%, between 20% and 45%, or between 20% and 30%, inclusive. 
     Relief  216  may have a maximum radial distance  221  from a circular or oval cutting surface edge that would be present if the cutting surface  214  were entirely circular or oval that is at between ⅕ and ⅘ inclusive, or between ⅓ and ⅘, inclusive of the radius or major axis of the cutting surface  214  absent the relief. 
     Although the innermost cutters  203 - 1  described in  FIGS.  5 - 11    have flattened cutting surfaces  214  for which the cutting arc length  217  or the surface area may be compared to what it would be if the cutting surface were absent the relief and, thus, a circle or oval, other regular flattened cutting surface shapes, such as a polygon having less than ten sides, may be used in place of a circle or an oval for comparison in some cutters. Other innermost cutters  203 - 1  may have an irregular flattened cutting surface  214  with reduced cutting arc length  217  or a reduced surface area. The cutting arc length  217  for such innermost cutters  203 - 1  may be compared to what it would be as calculated using a best fit cutting arc length of a best fit circle, oval, or polygon with less than ten sides for the flattened cutting surface absent the relief. For all of these above comparisons, the cutting arc length or surface area of the flattened cutting surface  214  may be reduced by at least 5%, at least 10%, at least 20%, or by between 5% and 45%, between 5% and 30%, between 5% and 20%, between 10% and 45%, between 10% and 30%, between 20% and 30%, between 20% and 45%, or between 20% and 30%, inclusive as compared to the surface area of the best fit circle, oval, or polygon with less than ten sides absent the relief or reliefs. 
     Relief  216  may extend laterally only through a portion of the layer of hard cutting material  219  (not shown), or it may extend laterally through all of the hard cutting material  219  (as illustrated particularly in  FIGS.  5 B,  6 B,  6 C, and  6 D ). If relief  216  extends laterally through all of hard cutting material  219 , it may then extend laterally through none (not shown), a portion of (particularly as illustrated in  FIGS.  5 B,  6 B,  6 C, and  6 D ), or all (not shown) of substrate  220 . In general, lateral extension of relief  216  through at most a portion of substrate  220  may facilitate attachment of innermost cutter  203 - 1  to fixed-cutter drill bit  101  by allowing the use of a circular pocket if the innermost cutter  203 - 1  is circular in radial cross-section. However, extension of relief  216  through all of substrate  220 , coupled with a pocket having a wall that matches the shape of relief  216 , may facilitate proper placement of innermost cutter  203 - 1  with respect to bit rotational axis  104 . Relief  216  may extend linearly and axially through innermost cutter  203 - 1 , so that it is at an approximately ninety degree angle with respect to cutting surface  214 . Relief  216  may also extend linearly at an obtuse angle with respect to cutting surface  214 , as illustrated by relief  216   a  in  FIG.  5 B . Relief  216  may also extend non-linearly in a shape, such as a curve, which generally forms an obtuse angle with respect to cutting surface  214 , as illustrated by reliefs  216   b  in  FIGS.  6 C and  6 D . 
     In an embodiment A, the present disclosure provides a fixed-cutter drill bit including a bit body defining a bit rotational axis, a plurality of blades each having an inner end that is radially closer to the bit rotational axis than a remainder of the respective blade, a central bit surface, and a plurality of cutters disposed on the blades and including an innermost cutter located closest among all of the plurality of cutters to the bit rotational axis and having a flattened cutting surface, a cutting arc, and a relief having ends which is located within and interrupts the cutting arc such that the cutting arc includes at least two portions located on opposite ends of the relief. 
     The present disclosure further provides in embodiment B a system for drilling a wellbore in a formation in which the system includes a drill string, a fixed-cutter drill bit as described in embodiment A attached to the drill string, and a surface assembly to rotate the drill string and bit during use of the bit to drill a wellbore in a formation. 
     Embodiments A and B may be further characterized by the following additional features, which may be combined with one another unless clearly mutually exclusive (e.g. the relief cannot be both linear and non-linear): 
     i) the cutting surface may be flattened; 
     ii) the relief may be linear; 
     ii-a) the innermost cutter may have a track diagram profile containing linear portion in an area corresponding to the relief, and the linear portion may be parallel to the bit rotational axis or form an acute angle with an uphole portion of the bit rotational axis of greater than 2° and less than and inclusive of 20°; 
     iii) the relief may be non-linear; 
     iii-a) the innermost cutter may have a track diagram profile containing a non-linear portion in an area corresponding to the relief for which there is a linear approximation, and the linear approximation may be parallel to the bit rotational axis or form an acute angle with an uphole portion of the bit rotational axis of greater than 2° and less than and inclusive of 20°. 
     iii-b) the relief may be wavy, angular, or curved; 
     iv) the cutting surface may include two or three reliefs; 
     v) the relief may extends linearly and axially through the innermost cutter such that a linear best fit for the relief forms a ninety degree angle or an obtuse angle with respect to the flattened cutting surface; and 
     vi) the relief may be offset from the bit rotational axis from −0.25″-+0.25″. 
     Although the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions and alternations can be made herein without departing from the spirit and scope of the disclosure as defined by the following claims. For example, although the present disclosure describes the configurations of blades and cutting elements with respect to drill bits, the same principles may be used to control the depth of cut of any suitable drilling tool according to the present disclosure. It is intended that the present disclosure encompasses such changes and modifications as fall within the scope of the appended claims.