Drill bits and tools for subterranean drilling, methods of manufacturing such drill bits and tools and methods of directional and off center drilling

A drill bit may include a bit body including at least one blade extending 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 and a rubbing zone within the cone region of the at least one blade, wherein cutting structures within the rubbing zone have a reduced average exposure. Additionally, a method of directional drilling may include positioning a depth-of-cut controlling feature of a drill bit away from a formation to prevent substantial contact between the depth-of-cut controlling feature and 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 into contact with the formation to control the depth-of-cut and rotating the drill bit on-center to form a substantially nonlinear borehole segment.

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 foamed 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.

DETAILED DESCRIPTION OF THE INVENTION

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 inFIG. 1, a drill bit10may have a bit body12that includes a plurality of blades14thereon. Each blade14may be separated by fluid courses18, which may include fluid nozzles20positioned therein. Each blade14may include a blade face22with cutting structures mounted thereto. For example, each blade14may include a plurality of PDC cutters24positioned within cutter pockets formed in the blade14along a rotationally leading edge thereof. A portion of each cutter24may extend out of its respective cutter pocket beyond the blade face22. The extent to which each cutter24extends beyond the blade face22defines the exposure of each cutter24. For example, one or more cutters24may be mounted relatively deeper within a pocket, such that the cutter24exhibits a reduced exposure. As another example, one or more cutters24may be mounted relatively shallower within a cutter pocket, such that the cutter24exhibits an increased exposure. As a practical matter, such relatively deeper or shallower exposure may be achieved by forming the cutter pockets to hold the cutters24at desired depths to achieve desired exposures in the blade leading end face during manufacture of the drill bit10.

The blades14and cutters24may define a face of the bit10that may include a cone region26, a nose region28, a shoulder region30and a gage region32(FIG. 2). The cone region26may be generally shaped as an inverted cone and is generally located at a central axis34of the drill bit10and centrally located on the face of the drill bit10. At least one blade36,38may extend at least partially over the cone region26of the face of the drill bit10and include a rubbing zone39, which may be utilized as a depth-of-cut controlling feature, in the cone region26of the blade36,38wherein cutters40,42within the rubbing zone39have a reduced average exposure.

In some embodiments, such as shown inFIG. 2, a cutter profile44defined by the plurality of cutters24includes a concavity48within the rubbing zone39, which may, in combination with the use of more deeply inset cutters24of the same diameter as shown, result in a reduced average exposure of the cutters40,42within the rubbing zone39. In additional embodiments, such as shown inFIG. 3, one or more blades36,38may include a protrusion50within the rubbing zone39, which may also, in combination with cutters40,42set at a reduced average height when compared to flanking cutters24, result in a reduced average exposure of the cutters40,42within the rubbing zone39. In further embodiments, one or more blades36,38may include a protrusion50within the rubbing zone39, which may also, in combination with cutters40,42set to the same depth as radially flanking cutters24of the same diameter, result in a reduced average exposure of the cutters40,42within the rubbing zone39. In yet additional embodiments, one or more blades36,38may include an optional rubbing insert52positioned within the rubbing zone39, as indicated inFIG. 1.

FIG. 2illustrates what is known in the art as a cutter profile44of the drill bit10, and shows a cross-section of the blade36. Each of the overlapping circles shown inFIG. 2represents the position that would be occupied on the blade36by the cutting face of a cutter24if each of the cutters24were rotated circumferentially about the central longitudinal axis34of the drill bit10to a position on the blade36. As seen inFIG. 2, cutting edges of the cutters24may define a cutter profile44, which is approximately represented. In such embodiments, where the cutter profile44has a concavity48within the cone region26, as shown inFIG. 2, the rubbing zone39may be located on the blade36rotationally following the cutters40,42having a reduced exposure and forming the concavity48of the cutter profile44. As shown, the concavity48may be defined by more than one cutter24, for example the concavity48may be defined by two cutters40,42, and may radially extend, relative to the central longitudinal axis34of the drill bit10, greater than the width of any single cutter24defining the cutter profile44. While the cutter profile44may exhibit a concavity48, the blade surface22of the blade36may not exhibit a concavity, and the cutters40,42defining the concavity48in the cutter profile44may have a reduced average exposure relative to other cutters24within the cone region26of the bit face and may have a reduced average exposure relative to cutters in the nose region28and the shoulder region30. In such an embodiment, the rubbing zone39may extend over regions of the cutter faces22that rotationally trail the concavity48in the cutter profile44and the regions of the cutter faces22within the rubbing zone39may provide a depth-of-cut controlling feature.

In additional embodiments, as shown inFIG. 3, the cutter profile44of a drill bit10may not include a concavity48and one or more blades36,38may include a protrusion50in the cone region26. As one or more blades36,38may include a protrusion50, and the cutter profile44may not exhibit a protrusion, the cutters40,42rotationally preceding the protrusion50may have a reduced average exposure relative to other cutters24within the cone region26of the bit body10and may have a reduced average exposure relative to cutters24in the nose region28and the shoulder region30. In such an embodiment, the rubbing zone39may extend over the protrusions50of the cutter faces22of the blades36,38and the protrusions50of the cutter faces22may provide a depth-of-cut controlling feature.

In some embodiments, the drill bit10may include one or more rubbing inserts52, as shown inFIG. 1, which may be located within the rubbing zone39within the cone region26of the drill bit10. The rubbing inserts52may comprise an abrasion resistant material and may be positioned on and coupled to one or more blades36,38. For example, the rubbing inserts52may be formed of tungsten carbide and may be brazed into pockets formed in the blade faces22of the blades36,38. In some embodiments, the rubbing inserts52may be configured and positioned within the blades36,38to protrude from the blade faces22and may define protrusions, such as protrusion50(FIG. 3), from the blade faces22. In additional embodiments, the rubbing inserts52may be configured and positioned within the blades36,38and a surface of the rubbing inserts52may substantially align with the blade faces22and may be positioned within a rubbing zone39rotationally trailing a concavity48in the cutter profile44, each rubbing insert52positioned rotationally trailing a cutting insert40,42having a reduced exposure, such as shown inFIGS. 1 and 2. Rubbing inserts52may provide several advantages, for example, rubbing inserts52may extend the useful life of the drill bit10and prevent excessive wearing of the blade faces22. For another example, the rubbing inserts52may be removed and replaced, to extend the useful life of the drill bit10and to provide a more flexible design for the drill bit10, as the height of the rubbing insert52may be changed, and thus the rubbing contact of the rubbing insert52may be changed as desired and the exposure of the rotationally preceding cutters24may also be changed. In embodiments having rubbing inserts52, the rubbing zone39may extend over the rubbing inserts52and the rubbing inserts52may provide a depth-of-cut controlling feature.

As shown inFIGS. 4 and 5, the drill bit10may also include a shank60attached to a bit body62and the shank60may be attached to a drill string64. For directional drilling applications, as shown inFIGS. 3 and 4, the drill bit10may be coupled to a downhole motor66, which may be positioned beneath a bent sub68. The drill string64may be coupled to a drilling rig (not shown) located at the top of the borehole70,72which may rotate the drill string64and may direct fluid (i.e., drilling mud) through the drill string64. In view of this, the entire drill string64may be rotated (i.e., rotate mode) and the drill bit10may be rotated along an axis of rotation73that is different than the central longitudinal axis34of the drill bit10, or “off-center,” and may form a substantially straight borehole segment70, as shown inFIG. 5. Alternatively, the bent sub68and the drill string64above the bent sub68may not be rotated and the drill bit10may be rotated by the downhole motor66alone, substantially along its central longitudinal axis34, or “on-center,” below the bent sub68. As the drill bit10is rotated on-center, the drill bit10may drill a generally arcuate or other nonlinear borehole segment72(i.e., slide mode), as shown inFIG. 4, in a direction generally following that of the bend in the bent sub68.

In slide mode operations, as shown inFIG. 4, a depth-of-cut controlling feature within the rubbing zone39in the cone region of the drill bit10may be positioned into effective rubbing contact with a formation74. 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 blades36,38rotationally trailing the cutters40,42having the reduced average exposure, may effectively rub against the formation74and may inhibit excessive penetration of the cutting structures24cutting into the formation74. In other words, as the weight on bit increases, the rate of penetration of the drill bit10may be controlled and remain substantially the same or be predictably and controllably increased, when compared to a drill bit10without 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 segment72may be formed during a slide mode operation and the path of the borehole segment72may be more accurately predicted and controlled.

FIGS. 6, 7 and 8show the predicted rubbing area76for the drill bit10shown inFIGS. 1 and 2at different depths-of-cut during slide mode operation.FIG. 6shows a predicted rubbing area76for a depth-of-cut of about zero (0) inches per revolution; as shown, it is predicted that about 10% of the rubbing zone39will contact the formation74(FIGS. 4 and 5).FIG. 7shows a predicted rubbing area76for a depth-of-cut of about 0.1 inch per revolution; as shown, it is predicted that about 25% of the rubbing zone39will contact the formation74(FIGS. 4 and 5).FIG. 8shows a predicted rubbing area76for a depth-of-cut of about 0.2 inch per revolution; as shown, it is predicted that about 50% of the rubbing zone39will contact the formation74(FIGS. 4 and 5). As shown inFIGS. 6, 7 and 8, the rubbing between the formation74(FIGS. 4 and 5) and the drill bit10during slide mode operation may be substantially limited to the rubbing zone39and the depth-of-cut control feature within the cone region26(FIGS. 2 and 3) of the drill bit10. 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 inFIG. 5, it may not be desirable to utilize the depth-of-cut controlling feature. When the drill bit10is rotated off-center to form a substantially straight borehole segment70is formed it may be more efficient to have an increased depth-of-cut and a reduced rubbing, as a reliable substantially straight borehole segment70may be maintained at a higher depth-of-cut and reduced rubbing may result in a more efficient drilling of the substantially straight borehole segment70. As the rubbing zone39and depth-of-cut control feature may be positioned within the cone region26of the drill bit10, the depth-of-cut controlling feature may be located away from the formation74by slight cavitation of the drill bit10due to the presence of the bent sub68, which may prevent more than incidental contact between the depth-of-cut controlling feature and the formation74during rotate mode operations, as shown inFIG. 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 formation74and 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 face22in the cone region26and the central longitudinal axis34of the drill bit10, may also be adjusted in combination with providing a depth-of-cut control feature in the cone region26to 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 region26to be removed from contact with the formation74during off-center drilling operations (i.e., rotate mode operations) for drilling a substantially straight borehole segment.

In view of the foregoing, drill bits10as described herein may be utilized to reduce detrimental rubbing during off-center drilling operations, such as shown inFIG. 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.