Terumbu and Arang Formation Characterization by Using Model Based Seismic Inversion In The East Natuna Basin

Abstract

The East Natuna Basin is characterized by Miocene carbonate build-ups and fine-grained clastic sequences that form the primary reservoir and sealing intervals in the region. Within this framework, reservoir characterization of the Terumbu and Arang formations was conducted through the integration of petrophysical interpretation, sensitivity analysis, depth structure mapping, and model-based seismic inversion. Well-log analysis reveals distinct lithological contrasts between the two formations. The Terumbu carbonates exhibit very low gamma-ray values (18–24 API) and high porosity ranging from 28–37%, locally reaching 31% in the GANG-4 well. Pronounced neutron–density crossovers indicate gas-bearing intervals, particularly at depths of 6808–6831 ft and 6908–6941 ft in the GADO-3 well, where deep resistivity values increase significantly (852–1958 Ω·m). In contrast, the Arang Formation is characterized by high gamma-ray values (102–148 API), elevated clay volume (30–44%), and substantially lower porosity (<10%). P-impedance–density cross-plots show carbonate clusters within impedance values of 4500–10,000 g/cc·m/s and density ranges of 1.7–2.35 g/cc, whereas shale and shaly sand plot at higher impedance (9000–17,500 g/cc·m/s) and density (2.45–2.80 g/cc). Depth structure mapping identifies a central–northern structural high that favors reef development and fault-controlled trapping. Model-based seismic inversion highlights low-to-moderate impedance values (4100–6156 g/cc·m/s), low density (1.57–1.77 g/cc), and high inverted porosity (0.37–0.52, locally up to 0.70) within the upper Terumbu interval, confirming excellent reservoir quality. The deeper Arang interval exhibits increasing impedance and density with porosity below 11%, indicating poor reservoir potential.