Proper Nozzle Location, Bit Profile, and Cutter Arrangement Affect PDC-Bit Performance Significantly
- D. Garcia-Gavito (Inst. Mexicano del Petroleo) | J.J. Azar (U. of Tulsa)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- September 1994
- Document Type
- Journal Paper
- 167 - 175
- 1994. Society of Petroleum Engineers
- 1.14 Casing and Cementing, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.9.2 Geothermal Resources, 1.6 Drilling Operations, 1.10 Drilling Equipment, 1.5.4 Bit hydraulics, 1.5 Drill Bits, 1.11.5 Drilling Hydraulics, 1.15 Fundamental Research in Drilling, 5.3.4 Integration of geomechanics in models, 4.3.4 Scale, 1.5.1 Bit Design
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An experimental study comparing the effects of PDC bit design features on the dynamic pressure distribution at the bit-rock interface was conducted on a full-scale lab drilling rig. The design features examined include: nozzle location, bit profile and cutter arrangement. The dynamic pressure distributions underneath each of nine different bits were measured and correlated to the rate of penetration. Four 6 3/4" and five 8 1/2" PDC drill bits were used.
The dynamic pressure distributions at the bit-rock interface were measured through capillary glass tubes embedded in a lab made rock samples and recorded using a high speed automated data acquisition system. These pressures were correlated with the hydraulic energy expended at the hole pressures were correlated with the hydraulic energy expended at the hole bottom and the rate of penetration that led to the following conclusions: 1) lab measurement of pressure distribution underneath the bit have shown that the bottom hole cleaning and therefore, drilling rates improve significantly when proper nozzle location, bit profile and/or cutter arrangement am used, 2) the ability of knowing dynamic pressure distribution at the bit-rock interface is a useful and reliable approach for better understanding and designing bit hydraulics, and 3) drilling rate correlations of results have shown that the hydraulic horsepower criterion is a better indicator for describing bottom hole cleaning than nozzle velocity, impact force and impact pressure criteria for PDC bits.
During the past twenty years, the drilling industry has been looking to new technology to halt the exponentially increasing costs of oil gas, and geothermal well drilling. This technology includes bit design innovations to improve the overall drilling performance and reduce drilling costs. Among these innovations, drag bits utilizing Polycrystalline Diamond Compact (PDC) cutters also called PDC bits, have been developed and used to drill long continuous intervals of soft to medium hard formations more economically than the conventional tricone roller cone bits. This cost advantage is the result of higher penetration rates and longer bit life obtained when using PDC bits instead of roller cone bits.
Drilling rate and bit life are two factors that considerably affect the drilling cost per foot which is a tangible measurement of drilling bit performance. For instance, an increase of 100% in drilling rate or bit performance. For instance, an increase of 100% in drilling rate or bit life may reduce drilling cost by 50% or 11% respectively. Therefore, any parameter that can be modified to increase drilling rate and/or bit life parameter that can be modified to increase drilling rate and/or bit life will further improve drilling performance and thus reduce drilling costs.
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