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.

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