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PDC bit configurations

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Various Polycrystalline Diamond Compact (PDC) bit configurations are discussed below.

Diamond bits

The term “diamond bit” normally refers to bits incorporating surface-set natural diamonds as cutters. This bit type, which has been used for many years, was the predecessor to PDC bits and continues to be used in certain drilling environments. Diamond bits are used in abrasive formations. They drill by a high-speed plowing action that breaks the cementation between rock grains. Fine cuttings are developed in low volumes per rotation. To achieve satisfactory rate of penetrations (ROPs) with diamond bits, they must be rotated at high speeds.

Diamond bits are described in terms of:

  • The profile of their crown.
  • The size of diamond stones (stones per carat).
  • Total fluid area incorporated into the design.
  • Fluid course design (radial or cross flow).

Diamonds do not bond with other materials. They are held in place by partial encapsulation in a matrix bit body. Diamonds are set in place on the drilling surfaces of bits (Fig. 1).

Impregnated bits

Impregnated bits are a PDC bit type in which diamond cutting elements are fully imbedded within a PDC bit body matrix (Fig. 2)

Impregnated bit bodies are PDC matrix materials that are similar to those used in cutters. The working portions of impregnated bits are unique, however: matrix impregnated with diamonds.

Both natural and synthetic diamonds are prone to breakage from impact. When embedded in a bit body, they are supported to the greatest extent possible and are less susceptible to breakage. However, because the largest diamonds are relatively small, cut depth must be small and ROP must be achieved through increased rotational speed. Thus, impregnated bits do not perform well in rotary drilling, because of relatively low rotary speeds. They are most frequently run in conjunction with turbodrills and high-speed positive displacement motors that operate at several times normal rotational velocity for rotary drilling (500 to 1500 rpm).

For cutting and gauge protection purposes, impregnated bits use combinations of:

  • Natural diamond
  • Synthetic diamond
  • PDC
  • TSP

They are designed to provide complete diamond coverage of the well bottom with only diamonds touching the formation. Variations in diamond size and the ratio of diamond to matrix volumes allow optimization of performance in terms of aggressiveness and durability. Varying diamond distribution also affects the ratio of diamond to matrix with similar effects on aggressiveness and durability.

During drilling, individual diamonds in a bit are exposed at different rates. Sharp, fresh diamonds are always being exposed and placed into service.

Dual-diameter bits

Dual-diameter bits have a unique geometry that allows them to drill and underream. To achieve this, the bits must be capable of passing through the ID of a well casing and then drilling an oversized (larger than casing diameter) hole. State-of-the-art dual-diameter bits are similar to conventional PDC drill bits in the way that they are manufactured. They typically incorporate a steel body construction and a variety of PDC and/or diamond-enhanced cutters. They are unitary and have no moving parts (Fig. 3).

Dual-diameter bits can provide drilling flexibility through:

  • Well diameter control.
  • Directional aptitude.
  • Reduction of drop tendencies.

They are functional in vertical and directional wells and in a wide range of formations. Maximum benefit is realized in swelling or flowing formations in which the risk of sticking pipe can be reduced by drilling an oversized hole. They are commonly used in conjunction with applications requiring increased casing, cement, and gravel-pack clearance; they also can eliminate the need for extra trips and avoid the risk of moving part failure in mechanical underreamers in high-cost intervals. When a well is deepened below existing casing, they reduce the need for additional underreamer runs and increase clearance for smooth casing run in curve sections. With this flexibility, they are also useful in exploratory wells, in which they provide for maximum casing diameters.

Dual-diameter bit drilling method

Fig. 4 shows the maximum dual-diameter bit diameter that can be tripped through casing without problems (left). On the opposite side of the reaming section, the pilot section is significantly removed from the casing pass-through diameter, and the centerline of the bit is similarly to the left (in the image) of casing/hole centerline. The only contact area between the bit and the casing pass-through diameter is at the small side of the reaming section. There is no cutter contact with casing during drillout, and neither the casing nor the bit cutting structure is damaged by tripping.

During drilling, the bit is centered on the hole, and the large sides of the reaming and pilot sections are in contact with the hole (right).

Dual-diameter bits are possible largely because of sophisticated modern engineering. Because of the unique geometry of dual-diameter bits, many obstacles and challenges must be overcome. To drill properly, this type of bit must be stable. If a conventional PDC bit becomes unstable during drilling, it will drill an oversized hole. If, on the other hand, a dual-diameter bit becomes unstable during drilling, the pilot section will drill an oversized hole that will, in turn, cause the reaming section to drill undersize, and hole diameter goals will not be achieved. To drill with optimal hole-opening ability, a dual-diameter bit must rotate purely around the bit axis. Stability is achieved with bit features and through careful engineering. The bits are force and mass balanced. Without care, dual-diameter bits could have a large turning moment between the pilot and reamer sections because of the axial separation of loading. Excessive torque contributes to poor bit stability, which adversely affects hole condition.

Designs must ensure that gauge cutters are prevented from contacting the casing, even in extreme applications. Dual-diameter designs must perform similarly to conventional PDC drill bits and produce a high-quality, larger hole.

Dual-diameter bits are often configured for drillout. Drillout cutting structures are more aggressive than those that will eventually serve rotating and sliding modes, but are generally more durable during drillout than most bits, even though the bits eventually perform other functions besides drillout.

Dual-diameter bit hydraulics requires special attention. Fluids provided to the pilot must fully clean the pilot section. Much of the total flow must be reserved for and directed to the full-gauge section from which a much higher volume of cuttings removal is required. Excessive flow to the pilot risks washout to the hole bottom, whereas insufficient flows to the gauge cutting area will provide inadequate cuttings removal and poor ROP or even binding of the drillstring. Dual-diameter bits require a special geometric relationship between reamer nozzles and the bit profile that minimizes flow scatter and maximizes available hydraulic energy across the reamer cutters. This layout works with pilot section hydraulics and deep junk slots to ensure high overall cleaning efficiency.


See also

Rotary drill bits

PDC bit classification

PDC bit profile

PDC bit design

PEH:Introduction to Roller-Cone and Polycrystalline Diamond Drill Bits

Noteworthy papers in OnePetro

Hertzler III, G.J., and Wankier, J.T. 1996. Unique PDC Bit Configuration Dramatically Improves Hole Cleaning, Drilling Efficiency in Low Hydraulic Applications, SPE/IADC Drilling Conference, 12-15 March. 35109-MS.

Allamon, J.P.B, McKown, T., Hill, D., Brooks, B.A., Bayoud, B.B., and Winters, W.J. 1987. Diamond Bit Handling and Operation, SPE/IADC Drilling Conference, 15-18 March. 16144-MS.

Abtahi A., Butt S., Molgaard J., and Arvani F. 2011. Wear Analysis And Optimization On Impregnated Diamond Bits In Vibration Assisted Rotary Drilling (VARD), 45th U.S. Rock Mechanics / Geomechanics Symposium, June 26 - 29. 11-266

External links

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