Patent Publication Number: US-9890597-B2

Title: Drill bits and tools for subterranean drilling including rubbing zones and related methods

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of U.S. patent application Ser. No. 12/898,451, filed Oct. 5, 2010, now U.S. Pat. No. 9,309,723, issued Apr. 12, 2016, which claims the benefit of U.S. Provisional Patent Application Ser. No. 61/248,777, filed Oct. 5, 2009, titled “DRILL BITS AND TOOLS FOR SUBTERRANEAN DRILLING, METHODS OF MANUFACTURING SUCH DRILL BITS AND TOOLS AND METHODS OF DIRECTIONAL AND OFF-CENTER DRILLING,” the disclosure of each of which is hereby incorporated herein in its entirety by this reference. 
    
    
     TECHNICAL FIELD 
     Embodiments of the invention relate to drill bits and tools for subterranean drilling and, more particularly, embodiments relate to drill bits incorporating structures for enhancing contact and rubbing area control and improved directional and off-center drilling. 
     BACKGROUND 
     Boreholes are formed in subterranean formations for various purposes including, for example, extraction of oil and gas from subterranean formations and extraction of geothermal heat from subterranean formations. Boreholes may be formed in subterranean formations using earth-boring tools such as, for example, drill bits. 
     To drill a borehole with a drill bit, the drill bit is rotated and advanced into the subterranean formation under an applied axial force, commonly known as “weight on bit,” or WOB. As the drill bit rotates, the cutters or abrasive structures thereof cut, crush, shear, and/or abrade away the formation material to form the borehole, depending on the type of bit and the formation to be drilled. A diameter of the borehole drilled by the drill bit may be defined by the cutting structures disposed at the largest outer diameter of the drill bit. 
     The drill bit is coupled, either directly or indirectly, to an end of what is referred to in the art as a “drill string,” which comprises a series of elongated tubular segments connected end-to-end that extends into the borehole from the surface of the formation. Often various subs and other components, such as a downhole motor, a steering sub or other assembly, a measuring while drilling (MWD) assembly, one or more stabilizers, or a combination of some or all of the foregoing, as well as the drill bit, may be coupled together at the distal end of the drill string at the bottom of the borehole being drilled. This assembly of components is referred to in the art as a “bottom hole assembly” (BHA). 
     The drill bit may be rotated within the borehole by rotating the drill string from the surface of the formation, or the drill bit may be rotated by coupling the drill bit to a down-hole motor, which is also coupled to the drill string and disposed proximate to the bottom of the borehole. The downhole motor may comprise, for example, a hydraulic Moineau-type motor having a shaft, to which the drill bit is mounted, that may be caused to rotate by pumping fluid (e.g., drilling fluid or “mud”) from the surface of the formation down through the center of the drill string, through the hydraulic motor, out from nozzles in the drill bit, and back up to the surface of the formation through an annulus between the outer surface of the drill string and the exposed surface of the formation within the borehole. As noted above, when a borehole is being drilled in a formation, axial force or “weight” is applied to the drill bit (and reamer device, if used) to cause the drill bit to advance into the formation as the drill bit drills the borehole therein. 
     It is known in the art to employ what are referred to as “depth-of-cut control” (DOCC) features on earth-boring drill bits which are configured as fixed-cutter, or so-called “drag” bits, wherein polycrystalline diamond compact (PDC) cutting elements, or cutters, are used to shear formation material. For example, U.S. Pat. No. 6,298,930 to Sinor et al., issued Oct. 9, 2001, discloses rotary drag bits that including exterior features to control the depth of cut by PDC cutters mounted thereon, so as to control the volume of formation material cut per bit rotation as well as the reactive torque experienced by the bit and an associated bottom-hole assembly. The exterior features may provide sufficient bearing area so as to support the drill bit against the bottom of the borehole under weight-on-bit without exceeding the compressive strength of the formation rock. However, such depth-of-cut control features may not be well suited for drilling all borehole segments during directional drilling applications. For example, when drilling in slide mode (i.e., on-center drilling and directional drilling) to form a non-linear borehole segment, it may be desirable to maintain a relatively small depth of cut to improve steerability; however, conventional depth-of-cut control features may hinder efficient drilling in rotate mode (i.e., off-center drilling and vertical drilling) wherein a higher rate of penetration (ROP) is desirable. 
     In view of the foregoing, improved drill bits for directional drilling applications, improved methods of manufacturing such bits and improved methods of directional and off-center drilling applications would be desirable. 
     BRIEF SUMMARY 
     In some embodiments, a drill bit for subterranean drilling may have a cutter profile comprising a concavity radially extending greater than a width of any single cutter defining the cutter profile. 
     In further embodiments, a drill bit for subterranean drilling may include a bit body including a plurality of blades, and at least one blade of the plurality of blades may extend at least partially over a cone region of the bit body. Additionally, the drill bit may include a plurality of cutting structures mounted to the at least one blade extending at least partially over the cone region, and the drill bit may include a rubbing zone within the cone region of the at least one blade, wherein cutting structures have a reduced average exposure. 
     In additional embodiments, a method of directional drilling may include positioning a depth-of-cut controlling feature of a drill bit to prevent more than incidental contact between the depth-of-cut controlling feature and the formation being drilled while rotating the drill bit off-center to form a substantially straight borehole segment. The method may also include positioning the depth-of-cut controlling feature of the drill bit for effective rubbing contact with the formation to control the depth-of-cut while rotating the drill bit on-center to form a nonlinear, such as a substantially arcuate, borehole segment. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  shows the face of a drill bit according to an embodiment of the present invention. 
         FIG. 2  shows a cutter profile of the drill bit of  FIG. 1 , having a concavity in a cone region. 
         FIG. 3  shows a cutter profile of another bit, having a blade protrusion in a cone region, according to another embodiment of the present invention. 
         FIG. 4  shows a drill bit according to an embodiment of the present invention attached to a drill string in operated in slide mode. 
         FIG. 5  shows the drill bit and drill string of  FIG. 4  operated in rotate mode. 
         FIG. 6  shows a predicted rubbing area superimposed on the face of the drill bit of  FIG. 1  at a depth-of-cut of about zero inches per revolution in slide mode. 
         FIG. 7  shows a predicted rubbing area superimposed on the face of the drill bit of  FIG. 1  at a depth-of-cut of about 0.1 inch per revolution in slide mode. 
         FIG. 8  shows a predicted rubbing area superimposed on the face of the drill bit of  FIG. 1  at a depth-of-cut of about 0.2 inch per revolution in slide mode. 
     
    
    
     DETAILED DESCRIPTION 
     Illustrations presented herein are not meant to be actual views of any particular drill bit or other earth-boring tool, but are merely idealized representations which are employed to describe the present invention. Additionally, elements common between figures may retain the same numerical designation. 
     The various drawings depict embodiments of the invention as will be understood by the use of ordinary skill in the art and are not necessarily drawn to scale. 
     In some embodiments, as shown in  FIG. 1 , a drill bit  10  may have a bit body  12  that includes a plurality of blades  14  thereon. Each blade  14  may be separated by fluid courses  18 , which may include fluid nozzles  20  positioned therein. Each blade  14  may include a blade face  22  with cutting structures mounted thereto. For example, each blade  14  may include a plurality of PDC cutters  24  positioned within cutter pockets formed in the blade  14  along a rotationally leading edge thereof. A portion of each cutter  24  may extend out of its respective cutter pocket beyond the blade face  22 . The extent to which each cutter  24  extends beyond the blade face  22  defines the exposure of each cutter  24 . For example, one or more cutters  24  may be mounted relatively deeper within a pocket, such that the cutter  24  exhibits a reduced exposure. As another example, one or more cutters  24  may be mounted relatively shallower within a cutter pocket, such that the cutter  24  exhibits an increased exposure. As a practical matter, such relatively deeper or shallower exposure may be achieved by forming the cutter pockets to hold the cutters  24  at desired depths to achieve desired exposures in the blade leading end face during manufacture of the drill bit  10 . 
     The blades  14  and cutters  24  may define a face of the bit  10  that may include a cone region  26 , a nose region  28 , a shoulder region  30  and a gage region  32  ( FIG. 2 ). The cone region  26  may be generally shaped as an inverted cone and is generally located at a central axis  34  of the drill bit  10  and centrally located on the face of the drill bit  10 . At least one blade  36 ,  38  may extend at least partially over the cone region  26  of the face of the drill bit  10  and include a rubbing zone  39 , which may be utilized as a depth-of-cut controlling feature, in the cone region  26  of the blade  36 ,  38  wherein cutters  40 ,  42  within the rubbing zone  39  have a reduced average exposure. 
     In some embodiments, such as shown in  FIG. 2 , a cutter profile  44  defined by the plurality of cutters  24  includes a concavity  48  within the rubbing zone  39 , which may, in combination with the use of more deeply inset cutters  24  of the same diameter as shown, result in a reduced average exposure of the cutters  40 ,  42  within the rubbing zone  39 . In additional embodiments, such as shown in  FIG. 3 , one or more blades  36 ,  38  may include a protrusion  50  within the rubbing zone  39 , which may also, in combination with cutters  40 ,  42  set at a reduced average height when compared to flanking cutters  24 , result in a reduced average exposure of the cutters  40 ,  42  within the rubbing zone  39 . In further embodiments, one or more blades  36 ,  38  may include a protrusion  50  within the rubbing zone  39 , which may also, in combination with cutters  40 ,  42  set to the same depth as radially flanking cutters  24  of the same diameter, result in a reduced average exposure of the cutters  40 ,  42  within the rubbing zone  39 . In yet additional embodiments, one or more blades  36 ,  38  may include an optional rubbing insert  52  positioned within the rubbing zone  39 , as indicated in  FIG. 1 . 
       FIG. 2  illustrates what is known in the art as a cutter profile  44  of the drill bit  10 , and shows a cross-section of the blade  36 . Each of the overlapping circles shown in  FIG. 2  represents the position that would be occupied on the blade  36  by the cutting face of a cutter  24  if each of the cutters  24  were rotated circumferentially about the central longitudinal axis  34  of the drill bit  10  to a position on the blade  36 . As seen in  FIG. 2 , cutting edges of the cutters  24  may define a cutter profile  44 , which is approximately represented. In such embodiments, where the cutter profile  44  has a concavity  48  within the cone region  26 , as shown in  FIG. 2 , the rubbing zone  39  may be located on the blade  36  rotationally following the cutters  40 ,  42  having a reduced exposure and forming the concavity  48  of the cutter profile  44 . As shown, the concavity  48  may be defined by more than one cutter  24 , for example the concavity  48  may be defined by two cutters  40 ,  42 , and may radially extend, relative to the central longitudinal axis  34  of the drill bit  10 , greater than the width of any single cutter  24  defining the cutter profile  44 . While the cutter profile  44  may exhibit a concavity  48 , the blade surface  22  of the blade  36  may not exhibit a concavity, and the cutters  40 ,  42  defining the concavity  48  in the cutter profile  44  may have a reduced average exposure relative to other cutters  24  within the cone region  26  of the bit face and may have a reduced average exposure relative to cutters in the nose region  28  and the shoulder region  30 . In such an embodiment, the rubbing zone  39  may extend over regions of the cutter faces  22  that rotationally trail the concavity  48  in the cutter profile  44  and the regions of the cutter faces  22  within the rubbing zone  39  may provide a depth-of-cut controlling feature. 
     In additional embodiments, as shown in  FIG. 3 , the cutter profile  44  of a drill bit  10  may not include a concavity  48  and one or more blades  36 ,  38  may include a protrusion  50  in the cone region  26 . As one or more blades  36 ,  38  may include a protrusion  50 , and the cutter profile  44  may not exhibit a protrusion, the cutters  40 ,  42  rotationally preceding the protrusion  50  may have a reduced average exposure relative to other cutters  24  within the cone region  26  of the bit body  10  and may have a reduced average exposure relative to cutters  24  in the nose region  28  and the shoulder region  30 . In such an embodiment, the rubbing zone  39  may extend over the protrusions  50  of the cutter faces  22  of the blades  36 ,  38  and the protrusions  50  of the cutter faces  22  may provide a depth-of-cut controlling feature. 
     In some embodiments, the drill bit  10  may include one or more rubbing inserts  52 , as shown in  FIG. 1 , which may be located within the rubbing zone  39  within the cone region  26  of the drill bit  10 . The rubbing inserts  52  may comprise an abrasion resistant material and may be positioned on and coupled to one or more blades  36 ,  38 . For example, the rubbing inserts  52  may be formed of tungsten carbide and may be brazed into pockets formed in the blade faces  22  of the blades  36 ,  38 . In some embodiments, the rubbing inserts  52  may be configured and positioned within the blades  36 ,  38  to protrude from the blade faces  22  and may define protrusions, such as protrusion  50  ( FIG. 3 ), from the blade faces  22 . In additional embodiments, the rubbing inserts  52  may be configured and positioned within the blades  36 ,  38  and a surface of the rubbing inserts  52  may substantially align with the blade faces  22  and may be positioned within a rubbing zone  39  rotationally trailing a concavity  48  in the cutter profile  44 , each rubbing insert  52  positioned rotationally trailing a cutting insert  40 ,  42  having a reduced exposure, such as shown in  FIGS. 1 and 2 . Rubbing inserts  52  may provide several advantages, for example, rubbing inserts  52  may extend the useful life of the drill bit  10  and prevent excessive wearing of the blade faces  22 . For another example, the rubbing inserts  52  may be removed and replaced, to extend the useful life of the drill bit  10  and to provide a more flexible design for the drill bit  10 , as the height of the rubbing insert  52  may be changed, and thus the rubbing contact of the rubbing insert  52  may be changed as desired and the exposure of the rotationally preceding cutters  24  may also be changed. In embodiments having rubbing inserts  52 , the rubbing zone  39  may extend over the rubbing inserts  52  and the rubbing inserts  52  may provide a depth-of-cut controlling feature. 
     As shown in  FIGS. 4 and 5 , the drill bit  10  may also include a shank  60  attached to a bit body  62  and the shank  60  may be attached to a drill string  64 . For directional drilling applications, as shown in  FIGS. 3 and 4 , the drill bit  10  may be coupled to a downhole motor  66 , which may be positioned beneath a bent sub  68 . The drill string  64  may be coupled to a drilling rig (not shown) located at the top of the borehole  70 ,  72  which may rotate the drill string  64  and may direct fluid (i.e., drilling mud) through the drill string  64 . In view of this, the entire drill string  64  may be rotated (i.e., rotate mode) and the drill bit  10  may be rotated along an axis of rotation  73  that is different than the central longitudinal axis  34  of the drill bit  10 , or “off-center,” and may form a substantially straight borehole segment  70 , as shown in  FIG. 5 . Alternatively, the bent sub  68  and the drill string  64  above the bent sub  68  may not be rotated and the drill bit  10  may be rotated by the downhole motor  66  alone, substantially along its central longitudinal axis  34 , or “on-center,” below the bent sub  68 . As the drill bit  10  is rotated on-center, the drill bit  10  may drill a generally arcuate or other nonlinear borehole segment  72  (i.e., slide mode), as shown in  FIG. 4 , in a direction generally following that of the bend in the bent sub  68 . 
     In slide mode operations, as shown in  FIG. 4 , a depth-of-cut controlling feature within the rubbing zone  39  in the cone region of the drill bit  10  may be positioned into effective rubbing contact with a formation  74 . As used herein, the term “effective rubbing contact” means contact, which may be substantially constant or may be intermittent, that is effective to limit a depth-of-cut of cutters proximate to the rubbing zone while drilling. As the bit is rotated, the depth-of-cut controlling feature, such as the region of the blades  36 ,  38  rotationally trailing the cutters  40 ,  42  having the reduced average exposure, may effectively rub against the formation  74  and may inhibit excessive penetration of the cutting structures  24  cutting into the formation  74 . In other words, as the weight on bit increases, the rate of penetration of the drill bit  10  may be controlled and remain substantially the same or be predictably and controllably increased, when compared to a drill bit  10  without a depth-of-cut controlling feature. By controlling the depth-of-cut, more specifically by providing a substantially consistent depth-of-cut, a more consistent and accurate nonlinear borehole segment  72  may be formed during a slide mode operation and the path of the borehole segment  72  may be more accurately predicted and controlled. 
       FIGS. 6, 7 and 8  show the predicted rubbing area  76  for the drill bit  10  shown in  FIGS. 1 and 2  at different depths-of-cut during slide mode operation.  FIG. 6  shows a predicted rubbing area  76  for a depth-of-cut of about zero (0) inches per revolution; as shown, it is predicted that about 10% of the rubbing zone  39  will contact the formation  74  ( FIGS. 4 and 5 ).  FIG. 7  shows a predicted rubbing area  76  for a depth-of-cut of about 0.1 inch per revolution; as shown, it is predicted that about 25% of the rubbing zone  39  will contact the formation  74  ( FIGS. 4 and 5 ).  FIG. 8  shows a predicted rubbing area  76  for a depth-of-cut of about 0.2 inch per revolution; as shown, it is predicted that about 50% of the rubbing zone  39  will contact the formation  74  ( FIGS. 4 and 5 ). As shown in  FIGS. 6, 7 and 8 , the rubbing between the formation  74  ( FIGS. 4 and 5 ) and the drill bit  10  during slide mode operation may be substantially limited to the rubbing zone  39  and the depth-of-cut control feature within the cone region  26  ( FIGS. 2 and 3 ) of the drill bit  10 . These rubbing area percentages are provided as non-limiting examples. Rubbing area percentages will vary based on several bit design factors, including: the size of the bit, the number of blades the rubbing zone is applied to, the cutter density, and the geometry of the concavity. 
     In rotate mode operations, as shown in  FIG. 5 , it may not be desirable to utilize the depth-of-cut controlling feature. When the drill bit  10  is rotated off-center to form a substantially straight borehole segment  70  is formed it may be more efficient to have an increased depth-of-cut and a reduced rubbing, as a reliable substantially straight borehole segment  70  may be maintained at a higher depth-of-cut and reduced rubbing may result in a more efficient drilling of the substantially straight borehole segment  70 . As the rubbing zone  39  and depth-of-cut control feature may be positioned within the cone region  26  of the drill bit  10 , the depth-of-cut controlling feature may be located away from the formation  74  by slight cavitation of the drill bit  10  due to the presence of the bent sub  68 , which may prevent more than incidental contact between the depth-of-cut controlling feature and the formation  74  during rotate mode operations, as shown in  FIG. 5 , resulting in a deeper depth of cut and higher ROP. Any incidental contact may be intermittent and may not result in substantial forces between the formation  74  and the depth-of-cut controlling feature, unlike rubbing contact. 
     In additional embodiments, a cone angle, which may be defined by an angle between the blade face  22  in the cone region  26  and the central longitudinal axis  34  of the drill bit  10 , may also be adjusted in combination with providing a depth-of-cut control feature in the cone region  26  to provide the desired removal of contact of the depth-of-cut control feature with the formation during substantially straight drilling with a directional drilling BHA. For example, a cone angle may be chosen, in combination with the placement and of the depth-of-cut control feature, which effectively enables the depth-of-cut feature within the cone region  26  to be removed from contact with the formation  74  during off-center drilling operations (i.e., rotate mode operations) for drilling a substantially straight borehole segment. 
     In view of the foregoing, drill bits  10  as described herein may be utilized to reduce detrimental rubbing during off-center drilling operations, such as shown in  FIG. 5 , while providing desirable depth-of-cut control during on-center drilling operations. 
     Although this invention has been described with reference to particular embodiments, the invention is not limited to these described embodiments. Rather, the invention is limited only by the appended claims, which include within their scope all equivalent devices and methods according to principles of the invention as described.