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.
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.
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.
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
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 (
In some embodiments, such as shown in
In additional embodiments, as shown in
In some embodiments, the drill bit 10 may include one or more rubbing inserts 52, as shown in
As shown in
In slide mode operations, as shown in
In rotate mode operations, as shown in
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
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.
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.
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Number | Date | Country | |
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20170022763 A1 | Jan 2017 | US |
Number | Date | Country | |
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61248777 | Oct 2009 | US |
Number | Date | Country | |
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Parent | 12898451 | Oct 2010 | US |
Child | 15095538 | US |