Pengusahaan minyak dan gas (migas) di Indonesia menggunakan Production Sharing Contract (PSC) dengan skema Cost Recovery sejak tahun 1966 sampai akhir Desember 2016 diberlakukan berdasarkan Peraturan Pemerintah Nomor 79 tahun 2010 yang bertujuan agar sumber daya migas kepemilikannya tetap dikuasai oleh negara. Pada tanggal 16 januari 2017 Kementrian ESDM melalui Peraturan Pemerintah Nomor 27 Tahun 2017 melakukan perubahan P S C d a r i Cost Recovery menjadi Gross Split untuk mengefisienkan anggaran belanja Kontraktor. Pada skema cost recovery bagi hasil minyak antara Pemerintah dan Kontraktor adalah 85%:15% sedangkan untuk gas adalah 70%:30%. Khusus untuk Pertamina sebagai Perusahaan Migas Nasional, diberikan bagi hasil minyak dan gas dengan perbandingan 60%:40%. Bagi hasil tersebut merupakan bagi hasil bersih setelah dikurangi biaya-biaya yang dikeluarkan oleh Kontraktor. Pada skema Gross Split bagi hasil antara Pemerintah dan Kontraktor adalah 57%:43% (base split) untuk produksi minyak. Untuk produksi gas adalah 52%:48% dengan Pemerintah tidak menanggung biaya-biaya yang diperlukan untuk produksi migas. Penelitian dilaksanakan dengan tujuan untuk mengevaluasi keekonomian, kelebihan dan kekurangan kedua jenis PSC tersebut dengan mengambil contoh kasus pada Lapangan Gas offshore. Hasil penelitian diharapkan dapat memberikan gambaran mengenai tantangan penerapan skema Gross Split dan Cost Recovery bagi pelaku industry hulu migas. Kegiatan penelitian mencakup telaah pustaka, analisis pendahuluan, pengambilan data KKKS, pemodelan tekno-ekonomi skema Gross split dan Cost recovery serta analisis hasil perhitungan yang diperoleh. Hasil penelitian menunjukan bahwa indikator keekonomian hulu pada skema Gross Split menunjukan hasil yang kurang aktraktif jika dibandingkan dengan skema Cost Recovery pada pengembangan Lapangan Frontier namun nilai tersebut sensitive perubahannya terhadap peningkatan produksi dan efisiensi biaya yang dapat dilakukan Kontraktor. Peningkatan daya tarik bagi investor hulu migas khususnya pada pengembangan Lapangan Frontier dengan skema Gross Split masih lebih menarik dengan pemberian insentif jika terjadi risiko dry hole atau pemberian data eksplorasi yang lebih banyak yang dilakukan peneliti.
To meet the rapidly growing demand and to provide secure base load power supply, Indonesia's power sector is seeing a growing share of coal in its generation mix. However, increased coal-based generation contributes to increased CO2 emissions. This study aims to define and evaluate the conditions under which coal-based generation could be deemed as carbon capture and storage ready. It considers the technical and economic implications of CO2 capture and storage for two candidate coal power plants in South Sumatera and West Java. A carbon capture storage of a couple of scenarios are evaluated for each power plant based on separation of 90%, 45% and 22.5% of CO2 from the power plant flue gas with an amine scrubbing process, supported by flue gas cleaning processes, and liquefaction of the captured CO2 for transportation to geological storage locations. The carbon capture storage operation would also run for 20 years, 15 years and 10 years, while the power plant design life is 25 years. The potential to sell captured CO2 for enhanced oil recovery in South Sumatera is also assessed. Results of this study will help Indonesia to identify a way to reduce CO2 emissions from the coal-based power sector in the long run and will contribute significantly to putting the country's energy sector on a sustainable development path.
CO2 injection into subsurface with the purpose to increase incremental oil production had been popularized in 1970s in US. Nowadays, this type of EOR methods not only offers more oil but also utilizing reservoir as CO2 storage in the context of CO2 emission abatement. The objective of this research is to produce simple and efficient worksheet on EXCEL base in order to asses and screen out quickly the potential of implementation of CO2 EOR sequestration in depleted oil fields in Indonesia.Key elements of this worksheet comprise engineering aspect and economical aspect. A sequence workflow of technical performance of CO2 flooding was done using streamline simulator in which outstanding output from simulator needs robust data preparation and cautious parameter set up. For the case studied here, total incremental oil recovery at the end of the project is 4.52% from original oil in place (IOIP) or about 6.23 MMSTB. “Prophet” was used to simulate CO2 sequestration during CO2 EOR incorporating residual trapping. The amount of CO2 trapped in reservoir was acquired by subtracting the total injected CO2 with CO2 produced. The total capital expenditure for sequestration CO2 EOR studied here is estimated $48.3 MM. It is expected that $16.5 MM will be placed in service by 1st year with the remaining $31.7 MM to be placed in service by 2nd year. Annual average operating cost was estimated to be $5.4 MM. As for fiscal terms, the following assumptions have been incorporated into the economic evaluations: (1) FTP 10%, (2) Investment Credit 17%, (3) Contractor Oil Split 26.6018%, (4) Government Split 73.3982%, and (5) Tax 44%. The economic analyses were carried out based on the project life time 7 years and the sales of incremental oil amount 5.6 MMSTB with an assumption that price for oil was $68 per barrel based on monthly average OPEC Basket Price during April-09 until March-10. Economic results of the development with discount factor 7 percent as indicated has a Contractor DCF Rate of Return 53.3 percent, Contractor Net Present Value $31.3 MM, and revenue to the Government of Indonesia $188.2 MM. With this economic indicator, the project of Sequestration CO2 EOR is economically feasible. The developed worksheet enables to do quick judgment on the viability a CO2 EOR sequestration project hence make it easier to someone who wants to screen out a large number of reservoirs rather than using detailed numerical simulator. It will much more saved time and decrease works intensity.
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