This invention relates generally to drill bits used in drilling oil and gas wells. Drill bits in general are well known in the art. In recent years a good number of bits have been designed using blades with affixed PDC cutter elements as cutting or shearing elements. The cutting elements or cutters are mounted on a rotary bit and oriented so that each of the PDC cutters engages the rock face at a desired angle. The bit is typically cleaned and cooled during drilling of the flow of drilling fluid (sometimes referred to as mud) out of one or more nozzles on the bit face. The drilling fluid is pumped down the drill string, flows across the bit face, removing cuttings and cooling the bit, and then flows back to the surface through the annulus between the drill string and the borehole wall.
It has been common practice in the drill bit industry to include gage wear pads on the outer surface of the drill bit which is at the diameter of the bit and establishes the drill bit's size. Thus, an 8″ bit will have the gage at approximately 4″ from the center of the bit.
A drill bit known in the prior art is shown in FIG. 1. Bit 10 is a fixed cutter bit adapted for drilling through formations of rock to form a borehole. Bit 10 generally includes a bit body having shank 13, and a threaded connection or pin 16 for connecting bit 10 to a drill string (not shown) which is employed to rotate the bit for drilling the borehole. Bit 10 further includes a central axis 11 and a cutting structure on the face 14 of the drill bit, preferably including blades with affixed PDC cutter elements 40. Also shown in FIG. 1 is a gage pad 12, the outer surface of which is at the diameter of the bit and establishes the bit's size. Thus, a 12″ bit will have the gage pad at approximately 6″ from the center of the bit.
As best shown in FIG. 2, illustrating in a different view the drill bit of FIG. 1, the drill bit 10 includes a face region 14 and a gage pad region 12 for the drill bit. The face region 14 includes a plurality of cutting elements 40 from a plurality of blades, shown overlapping in rotated profile. The action of cutter elements 40 drills the borehole while the drill bit body 10 rotates. Downwardly extending flow passages 21 have nozzles or ports 22 disposed at their lowermost ends. Bit 10 includes six such flow passages 21 and nozzles 22. The flow passages 21 are in fluid communication with central bore 17. Together, passages 21 and nozzles 22 serve to distribute drilling fluids around the cutter elements 40 for flushing formation cuttings from the bottom of the borehole and away from the cutting faces of cutter elements 40 when drilling.
However, the Applicant has discovered that it can be very advantageous, especially in the drilling of highly deviated wellbores, that the borehole be drilled overgage, making it easier for making sharper turns in the borehole than could be easily accomplished when drilling at the gage of the drill bit. Accordingly, the Applicant has discovered that it would be advantageous to make drill bits in which the ability to drill overgate is not inhibited by gage wear pads, or other dedicated gage retention mechanisms. Moreover, PDC cutter elements may be installed in a longer, continuous path which goes nearly to the shank of the bit, and well past the point typically located in the prior art, as is described in detail hereinafter.