Drilling Optimization in Deep Tight Gas Field

Abstract

In the Sultanate of Oman, a high temperature and high pressure deep tight gas exploration field required dedicated drilling optimization to reduce the substantial drilling cost incurred. The initial well delivery was an estimate of 30 days for the 12.25 in. section (~ 2800 m interval) and 55 days for the 8.375 in. section (~ 1800 m interval) reaching a total depth of 5000 m. The 12.25 in. section's challenges were mainly a result of the vast variation of the unconfined compressive strengths (UCS) of the corresponding formations. The laminations of shale, dolomite, limestone, and sandstone with a UCS varying from 3 KPsi to 33 KPsi resulted in lower rates of penetration (ROP), numerous bit runs and thus incremental trip times. A non-optimized design for the bottom hole assembly (BHA) was one of the causes of getting twist offs. Reactive shales resulted in bit balling. Tight holes resulted in mechanical stuck pipe events. The 8.375 in. section's challenges were mainly associated to drilling the hard abrasive rock formations. The corresponding formations inhibited a high static temperature of 170 deg C and a high pressure drilling environment where a mud weight of 15.6 KPa/m was required to maintain an over-balanced drilling; yet posing pressure limitations on the drillstring. A team comprised of the operator representative, the directional drilling services provider, and the bit vendor, was set to launch a campaign to optimize the drilling performance. The main objective of the campaign was to reach engineered solutions optimizing the well design, BHA, and bit design including the cutter size, guage length, blade count, and other bit features. Special analysis on formation abrasiveness and compressive strengths was performed to design the right bits that allow drilling through laminated formations. Polycrystalline Diamond Compact (PDC) bits with enhanced cutting structures were used. Measurements While Drilling (MWD) tool was included in the BHA to monitor the drilling mechanics, shock and vibrations, and stick/slip to mitigate drillstring failure. Optimum drilling paramaters were used to eradicate the negative energy and boost the ROP instead. Bit horse power per square inch (HSI) was optimized to counteract the sticky formations and avoid bit balling. An oil-based mud system (OBM) was used to work against the reactive shales. Two PDC bits with 16 mm cutters, 3 in gauge length, and 6 blades and backup cutters were used to drill the 12.25 in. section. The 8.375 in. section drilling program included PDC bits with 16 mm cutters, 2 in gauge length, 8 blades and backup cutters. The rest of the 8.375 in. section was drilled with highly abrasive resistant impreg bits and turbines. A total of 6 runs were required to finish this section. Results of the drilling optimization campaign were a 15 day saving while drilling the 12.25 in. section, and a 10 day saving drilling the 8.375 in. section. The total saving was 25 days per well equivalent to 1.25 Million USD for each well drilled. This paper is a benchmark for similar projects with high temperature and high pressure tight gas drilling environment where cost is a concern and a technical solution is required.