Petroleum Development Oman (PDO) “M” gas field provides an unique set of challenges while drilling the 12.25 in intermediate hole section which include severe lateral vibrations, stick & slip, impact damage, limited bit life and low penetration rates. As a result, 3 BHA's were historically needed to complete the section totaling 16 days on average. A collaborated effort between Schlumberger and PDO was initiated, with the ultimate goal to reduce the number of days to drill the section. To achieve this goal a Petro Technical Engineering Center (PTEC) process was established to develop a system engineered BHA solution. This process was introduced to the field over several wells and resulted in drilling the entire section in one run and reducing the drilling time from 16 days to 7 days. The well profile is a 12.25in vertical hole typically drilled from +/− 1000m to +/−3400m MD, through highly interbedded formations ranging from 5-30 kpsi UCS and varying levels of abrasiveness. In a hard rock environment a system engineered approach is valuable to reduce the number of design iterations required compared to a trial and error method, due to the significant amount of time a well takes to drill. To complete this, a three phased approach was executed. Phase 1 –To identify the most stable bit and BHA combination to use in the 1st trial test, a time domain integrated FEA model1 was used determine the best suited bit combination. From this analysis it was concluded that a 5 blade 16 mm bit driven by a motorized rotary steerable system would provide the most stable option to pursue in the trial test. Along with the modeling a detailed parameter roadmap was generated from the collaborative efforts of both PDO's and Schlumberger's drilling teams. The roadmap was coupled with a ROP optimization application2 which provided real-time RPM and WOB drilling parameter recommendations to maximize ROP within the operational envelope defined on a per formation basis. Phase 2 – Building on the lessons learnt from Phase 1, a time domain Integrated FEA Model2 was used to fine tune the BHA and recommeneded removing the motor from the system would provide a more stable BHA in this application as well a switching to a less aggressive cutting structure in a 6 Blade 16 mm design. The model was also used to optimize the BHA design so that it generated limited vibrations enabling an aggressive strategy to reduce cost by removing the MWD, surface system and personnel. Thanks to its capability to keep a precise vertical control in automatic mode without the need to over-regulate the drilling parameters. This was implemented and resulted in the first shoe to shoe run in the field. Phase 3 – A new bit technology incorporating a conical diamond element3 was strategically placed in the center of the baseline PDC bit. It was then modeled using the same time domain integrated FEA model used in Phase 2 and selected for a trial test. The drilling system was run again and resulted in another successful shoe to shoe run with a further increase in penetration rate of 14.4%, and more improvements on following wells. The engineered solutions supported by the team effort and simulations made significant improvement in subsequent wells and are ongoing.

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.