Reservoir Characterization of the Terumbu and Arang Formations Using Model-Based Seismic Inversion in the East Natuna Basin - Adham Syahputra, Guntur; Haris, Abdul; Wibowo, Ricky Adi; Wijanarko, Edy (Scientific Contributions Oil and Gas, 2026)
The Miocene carbonate buildup and fine-grained clastic sequence constitute the main reservoir and sealing intervals in the East Natuna Basin. This study characterizes the reservoirs of the Terumbu and Arang Formations using an integrated workflow that includes petrophysical analysis, sensitivity analysis, depth structure mapping, and model-based seismic inversion. Well-log interpretation shows clear lithological contrasts between the two formations. The Terumbu carbonates exhibit very low gamma-ray values (18 to 24 API) and high porosity, ranging from 28 to 37%, with neutron–density crossovers indicating gas-bearing intervals, particularly in the GADO-3 well, where resistivity values range from 852 to 1958 Ω·m. In contrast, the Arang Formation is characterized by high gamma-ray values (102 to 148 API), higher clay volume (30 to 44%), and low porosity (<10%). P-impedance–density cross-plots distinguish carbonate rocks (4,500 to 10,000 g/cc·m/s; 1.7 to 2.35 g/cc) from shale and shaly sand with higher impedance and density. Depth structure mapping reveals a central–northern structural high that is favorable for reef development and fault-related trapping. Model-based seismic inversion further reveals low-to-moderate impedance (4,100 to 6,156 g/cc·m/s), low density, and high inverted porosity within the Top Terumbu interval, indicating excellent reservoir quality. Overall, the results indicate that the Terumbu Formation forms the primary carbonate reservoir, while the Arang Formation mainly acts as an effective regional seal in the petroleum system of the East Natuna Basin