The current explosive limit chart using in the oil and gas industry published with unclear condition of safety factor and consequence of overexposing temperature and time, resulting in many published papers disclose the possibility of expanding the safe-operating envelope of HMX. HMX is preferable because it typically provides deeper penetration than HNS but less stability at high temperature. Therefore, this study aims to maximize use of HMX for hollow gun perforation in typical environment in the GOT. The explosive temperature limit depends on two parameters, exposure time and temperature. The maximize use of HMX could achieve by, either ways, reducing the exposure time or extending the temperature limit line. Firstly, the operating time optimization is doable by using statistic record of the depth perforated by HNS and practical running speed together with a 20% safety margin. Secondly, expanding the temperature limit of HMX is a precise task because the HMX once exceeding the stability temperature, the perforating performance losses and explosion hazard arises due to thermal decomposition. However, this could be creditable by integrating the published explosive testing results over the current operating-envelope and applying a safety margin. The represented operating time, counting from running in hole to tool on surface, for perforation with E-line unit in the high-temperature environment could reduce by an hour. This operating time allows the temperature limit of HMX increasing by only 7 F, which considering as insignificant. The integrating result of three published paper indicated no explosive deflagration happens if the temperature is below the "Fiasco line" – introduced by a company, however, the operating time longer than 200 hours is not incorporated. By applying safety margin, the new operating envelope of HMX in the hollow carrier proposes between the typical and the Fiasco line. Combing time optimization and the new line, the HMX temperature limit extends from 375 F to 394 F for 2.2 operating hours. This new criterion has been applied successfully since 2018; 325 m of HMX achieved perforation condition without an indication of misfire or catastrophic self-detonation, resulting in reduce 50% of HNS consumption. In conclusion, the new temperature cutoff is valid for maximizing the use of HMX with a reasonable safety margin.

In 2016, the gas monobore-completion wells were executed P&A as a pilot campaign to evaluate the technical feasibility and cost in the PTTEP’s setting. By following DMF’s guideline and PTTEP’s regulation, the cement bullheading uses as a method to isolate all hydrocarbon strata up to 30 m above the previous casing shoe. The gas-tight cement recipe is specifically designed for each well condition, then tested in the laboratory and approved by PTTEP prior proceeding the operation. After pumping job, the well shut-in for cement curing and developing strength. The cement must achieve the hydro test at 2,500 psi surface pressure. Otherwise, the contingency plan must be applied i.e. set two metal plugs above the topmost perforation and cover with 30 m of dumped cement. In the first two wells, the pumping operations were completed as plan but failed the hydro test even surface samples had cured and shut-in longer than the testing time in the lab. The re-injectivity test was performed but not enough to redo cement bullheading. The contingency plan was applied to regain well integrity for P&A. It spent an extra 2 days and 100k USD per well. After revisited the cement design, the cause of failure is suspected by the temperature criterion in cement’s testing. Previously, the cement was tested in bottom hole static temperature (BHST) of the bottommost perforation which 45 °C higher than the BHST at the topmost perforation. It is possible that the cement at the top of perforation had not developed sufficient strength prior the test. Hence, the cement’s design criteria are revised. The UCS/UCA tests in BHST at the top perforation while the rest test in bottom hole circulating temperature (BHCT). The lab test reveals that cement rheology is quite thick but still pumpable. Furthermore, some wells require to shut-in up to 3 days before gaining the strength. So, the shut-in period after pumping is customized according to the lab test result. After applying this approach in 17 wells, 100% of cement bullheading jobs achieve the surface test and no need to apply the contingency plan. This contributes the cost saving 1.7 MMUSD over the campaign. There are approximately 400 wells of PTTEP in the Gulf of Thailand that have high-temperature gradient and long reservoir section. These wells exactly require this approach to get success in cement bullheading, so the potential cost saving based on the previous price is about 40 MMUSD in the future.