Polycrystalline Diamond Bits

A new generation of bit technology began in 1973 when General Electric Co. introduced the Stratapax® drill blank. This technology has been licensed to virtually all drill bit manufacturers who now produce their own proprietary PDC (polycrystalline diamond compact) bits. The names generally applied to these bits are PDC or Stratapax.®

Drill blanks consist of a layer of polycrystalline, man-made diamond and cemented tungsten carbide produced as an integral blank by a high-temperature, high-pressure technique (Fig. 7-29). The resulting blank has nearly the hardness and greater abrasion resistance of natural diamond and is complemented by the strength and impact resistance of cemented tungsten carbide. Blanks are used as drag cutting elements attached to bits for drilling and mining applications (Fig. 7-30).

Blank

Blank

Brazing alloy

Brazing alloy

Tungsten carbide cylinder

Tungsten carbide cylinder

Fig. 7-29 Drill blank components (Courtesy Stratapax)

PDC bits have several significant design features that enhance their ability to drill:

  • The lack of internal moving parts reduces bit failure potential.
  • Since it fails the rock by shearing, less drilling effort is required than the cracking, grinding principles used in roller bits.
  • High bit weights are not required. (This feature allows these bits to be used in deviation control in some cases.)
  • The combination of low weight requirements and no internal moving parts makes them well suited for turbine drilling.

As more experience is gained with the bit, enhanced design features will probably further improve a product that currently is innovative and well proven.

Bit manufacturers integrate the PDC blank into their respective bit designs (Fig. 7-31). Variations in designs include number and placement of the blanks, jet structure, and watercourse development. In sonic applications, PDC bits will drill 3-4 times the footage of a conventional roller bit at 2-3 times the drill rate if sticky formations do not pose problems. For example, 18,000-20,000-ft wells in South Texas are now typically completed in 70-80 days using PDC bits vs 120-130 days with conventional roller bits.

PDC designs are generally based on high or low RPM applications, i.e., turbine vs rotary drilling. Turbine applications use more blanks to compensate for friction-related wear considerations. The bit is tapered to allow placement of the cutters. PDC bits for rotary applications have fewer cutters and a somewhat flat design.

Pdc Bit Cuttings

Fig, 7-30 Formation cutting with the blank

Polycrystalline Diamond Bits

Fig. 7-31 NL Hycalog's DS-23 diamond bit (Courtesy NL Hycalog)

Rotary-designed PDC bits often use nozzles to allow fluid circulation for cuttings removal and cooling of the bit. Manufacturers may vary number and distribution of the nozzles. A tendency for applications in water-based muds is to use small jets to achieve high fluid velocities. This feature does not appear to be as significant in oil-based muds applications.

PDC bits are manufactured with a machined, steel body or a matrix body process. The matrix process is similar to the manufacturing of diamond bits. The cutters arc attached to the bit by proprietary techniques. Matrix bodies appear to be more erosion resistant.

Shape of the PDC cutters is becoming an important consideration. Most manufacturers use the original circular design. However, effort is being given to research and development of alternate shapes to enhance the design and improve drilling performance.

PDC bit technology is an area experiencing dynamic changes and improvements in the drilling industry. As an example, the recently introduced leached compact technology provides a thermally stable cutter and low wear rates, and opens the door for improved compact-to-bit attachment procedures.

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