New PDC Technology Delivers Significant Savings in Oman

Abstract

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 97340, “An Alternate Approach: Utilizing New PDC Technology for Drilling Deep LNG Wells Delivers Significant Savings for Major Operator in Oman,” by P. Teasdale, SPE, N. Riley, and P. Mackinnon, ReedHycalog, prepared for the 2005 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Dubai, UAE, 12–14 September. A major operator has been drilling deep gas wells for several years in central Oman. These wells are drilled vertically through a complex geological sequence that provides a significant challenge to bit performance. Historically, these wells have been drilled in 90 days with tungsten-carbide-insert (TCI) bits on packed rotary assemblies to the 9⅝-in. casing shoe and diamond-impregnated bits on turbine assemblies with occasional TCI-bit runs in the 8⅜-in. section. A detailed study of the wells focused on optimizing drilling performance in each of the three hole sizes in a typical well profile. The findings suggested that the introduction of new polycrystalline-diamond compact (PDC) -bit technology was viable over much of the intervals and that significant savings in terms of time and cost could be achieved. Trial Well 1 The initial trial well began in August 2003. Performance had been benchmarked and objectives were established for each hole section. Top 17½-in. Hole. The following objectives were agreed upon. - Complete 950-m interval in single run. - Rate of penetration (ROP) greater than 14-m/h benchmark. A premium Intl. Assn. of Drilling Contractors (IADC) code 415 TCI bit with a total flow area (TFA) of 7.19 cm2 was run on a rotary pendulum assembly with a single stabilizer positioned 27 m above the bit. The TCI bit features an extremely durable roller bearing for extended life and an optimized geometric hydraulic design with precisely angled nozzles to prevent bit balling and increase ROP. The section was completed in 14 days compared to the planned 6 days, with 6½ days of lost time spent curing losses. A total of 16 trips and 9 bit runs was required to complete the interval because of hole problems. The 415-type bit drilled the 944-m interval as planned with an average ROP of 13.2 m/h that was slightly lower than the 14-m/h target established before the run. At surface, the bit was balled up but in good condition and was graded 2-2-CT-A-E-I-NO-TD. Consideration of the controlled parameters applied in the upper section to minimize the risk of losses, and the excellent performance achieved in the lower section where flow rates were optimized and ROP increased to more than 20 m/h demonstrated the potential for better performance in this section.