Drill bits are used as part of a drill string to advance a borehole in the earth. The drill string is rotated from the topside of the operation or by a downhole motor or both. As the bit is rotated, discrete cutting elements (“cutters”) on the face of the bit fail rock at the surface of the borehole with the cutters scraping or shearing the formation. Each cutter of a rotary drag bit is positioned and oriented on a face of the drag bit to engage the earth formation of the borehole as the bit is being rotated. The cutters are typically installed on a blade of the bit with each cutter in a recess of the blade.
Drilling fluid is pumped down the drill string, into a central passageway formed in the center of the bit, and then out through nozzles in the face of the bit. The drill fluid cools the cutters and helps to remove and carry cuttings from the junk slots between the blades.
A typical cutter is cylindrical with a forward working surface that contacts and fails the rock of the borehole. The typical cutter can be made from a layer of polycrystalline diamond (“PCD”) in the form of a polycrystalline diamond compact (“PDC”) mounted to a substrate. A common substrate is cemented tungsten carbide. The substrate, while not as hard, is tougher than the PDC, and thus has higher impact resistance.
The cutter is made by mixing the polycrystalline diamond in powder form with one or more powdered metal catalysts and other materials in a mold the proximate shape of the finished cutter. The mold and raw materials are consolidated using extreme heat and pressure. Cobalt or an alloy of cobalt is the most common catalyst included in the substrate material. During processing, the cobalt infiltrates the diamond crystals and act as a catalyst to form diamond-to-diamond bonds between adjacent diamond grains to create an ultrahard cutting face to engage the rock.
The blades of a bit can extend from the nose portion over a shoulder portion of the bit. Cutters can be mounted on the leading edge of a blade of the bit and create a cutting profile of the bit. In general, the nose cutters advance the borehole and the shoulder cutters widen the borehole. Above this shoulder section is the gage section which can receive cutters and/or gaging inserts. The inserts prevent the body of the bit, which is typically softer than the PDC cutters, from contacting the borehole and being abraded or eroded by the contact. The gage inserts are generally mounted to the body of the bit or a radial face of the blade. The gage inserts can be mounted behind cutters in the gage section. The cutters and inserts limit erosive contact and maintain a nominal diameter of the bit body. The inserts can be tungsten carbide similar to the substrates of the cutters and are referred to as TCIs or tungsten carbide inserts.
Customized cutters are often mounted in the gage section and/or shoulder of the bit. These cutters are configured to have limited engagement with the borehole while maintaining the ability to fail portions of rock. These are usually cylindrical cutters that are trimmed or shaped to remove portions of the cutter table and substrate. Trimming brittle and hard diamond tables can result in cracking of the table making the cutter unusable and incurring substantial cost.
USPTO Backgrounds
USPTO Backgrounds