A Techno-Economic Approach to Optimizing CCS Fiscal Parameters in Indonesia: A Case Study of Integrated Oil and Gas Development in CO2-Rich Areas - Najeela Faza Ramadhani; Dedy Irawan; Sudono; Prasandi Abdul Aziz (Testing Center for Oil and Gas LEMIGAS, 2025)
This study introduces a techno-economic approach to optimizing storage fees for CCS integrated with oil and gas development. The analysis adopts the production sharing contract cost recovery model in accordance with the implementation of Ministerial Regulation of Energy and Mineral Resources No. 16 of 2024, which addresses CCS-related parameters. Technical assessment confirms the studied reservoir’s suitability for long-term CO₂ injection through 5 injection wells, while oil and gas development are supported by 10 oil wells and 8 gas wells. The project’s economic viability under baseline conditions shows an IRR of 10.14% and POT of 15.73 years. Sensitivity analysis across fiscal parameters, such as investment credit, FTP, contractor split, CCS service fee and storage fee, CAPEX, royalty, and tax, identifies the storage fee as the most influential factor for viability. To achieve a commercially viable IRR of 15%, the project requires a minimum CCS service fee of 55 US/MT and a storage fee of at least 35 US/MT. The study underscores the need for clear regulations on fiscal incentives, CO₂ pricing, storage fees, and PSC integration to enhance CCS economic viability, while also offering a replicable framework for CO₂ assessments under dynamic fiscal regimes.