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.

The conventional gravel pack sand control completion (High Rate Water Pack / Extension Pack) was the primary sand control method for PTTEPI, Myanmar Zawtika field since 2014 for more than 80 wells. Although the completion cost of gravel pack sand control was dramatically reduced around 75 percent due to the operation performance improvement along 5 years, the further cost reduction still mandatory to make the future development phase feasible. In order to tackle the well economy challenge, several alternative sand control completion designs were reviewed with the existing Zawtika subsurface information. The Chemical Sand Consolidation (CSC) or resin which is cost-effective method to control the sand production with injected chemicals is selected to be tested in 3 candidate wells. Therefore, the first trial campaign of CSC was performed with the Coiled Tubing Unit (CTU) in March to May 2019 with positive campaign results. The operation program and lesson learned were captured in this paper for future improvement in term of well candidate selection, operation planning and execution. The three monobore completion wells were treated with the CSC. The results positively showed that the higher sand-free rates can be achieved. The operation steps consist of 1) Perform sand cleanout to existing perforation interval or perforate the new formation interval. 2) Pumping pre-flush chemical to conditioning the formation to accept the resin 3) Pumping resin to coating on formation grain sand 4) Pumping the post-flush chemical to remove an excess resin from sand 5) Shut in the well to wait for resin curing before open back to production. However, throughout the campaign, there were several lessons learned, which will be required for future cost and time optimization. In operational view, the proper candidate selection shall avoid operational difficulties e.g. available rathole. As well, detailed operation plan and job design will result in effective CSC jobs. For instance, the coil tubing packer is suggested for better resin placement in the formation. Moreover, accommodation arrangement (either barge or additional vessel) and logistics management still have room for improvement. These 3 wells are the evidences of the successful applications in Zawtika field. With good planning, lesson learned and further optimization, this CSC method can be beneficial for existing monobore wells, which required sand control and also will be the alternative sand control method for upcoming development phases. This CSC will be able to increase project economic and also unlock the marginal reservoirs those will not justify the higher cost of conventional gravel pack.