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Reservoir characterization and fluid discrimination based on seismic reflection amplitude play important roles in seismic exploration industry. Stable fluid-sensitive attributes from seismic data can help reduce uncertainties of hydrocarbon prediction in interwell locations and increase the reliability of drilling plans. In this study, in combination with seismic AVO inversion impedance and the rock physics template analysis, we proposed a new attribute (DI) to discriminate the hydrocarbon-associated anomalies and predict the reservoir parameters including porosity and water saturation quantitatively in Upper Gumai formation of W field, South Sumatra Basin. The new attribute (DI) is constructed using a set of combined impedances derived from prestack seismic inversion with the constraint of rock physics. Numerical modelling based on patchy-saturated model was implemented to test the sensitivity and stability of the new attribute and results showed that the DI attribute can predict the existence of hydrocarbon-filled sands with less ambiguity. With known well log data in W field, a feasibility study including cross-plotting and histogram methods was carried out and concluded that the DI attribute contributes higher resolution in distinguishing the hydrocarbon-filled sands from the background trend. In the process of quantitative interpretation, the DI attribute shows a good regression relationship with porosity and water saturation properties within the hydrocarbon sands with the correlation coefficients reaching 92% and 85%, respectively. By using seismic AVO inversion impedance, combining the application of the DI attribute and Vp/Vs ratio for lithology and fluid contents discrimination was conducted to improve the reservoir prediction accuracy in the field. Application results show that low values of the DI attribute (<18,000 m/s.g/cc) was indicative of hydrocarbon-filled sands effectively while Vp/Vs ratio presented a higher resolution in separating wet sand, dry-sand from shale. By using the linear regression relationship derived from cross-plotting analysis with well data, we calculated the volumes of porosity and water saturation from DI attribute and successfully screened out the hydrocarbon accumulation distribution, which reveals the potential zones of exploration interest in South Sumatra Basin.

The gas slippage phenomenon under dry conditions has been investigated extensively both numerically and experimentally. However, very limited research has focused on gas slippage behavior under wet conditions. Unlike conventional formation, the influence of water on the gas transport process cannot be neglected in tight formations due to the comparable amount of thin water film attached along the rock surface. It is found experimentally that the gas slippage factor is positively related to water saturation if the water saturation is small, while it decreases with water saturation if it is larger than a critical value. Most of the existing models failed to capture the measured downtrend of the gas slippage factor with increasing water saturation, which resulted from water blocking or gas trapping phenomenon. In this work, a pore-scale network model is proposed to look at the water distribution characteristic and investigate the effect of water on the gas slippage factor. The proposed pore-scale model incorporates the capillary dominated multiphase fluid distribution, real gas effect, and gas transport mechanisms at pore scale. On the basis of our pore network model, the effect of pore structure characteristics including the frequency of mean pore radius, size of mean pore radius, aspect ratio, and coordination number on the gas slippage behavior are investigated and discussed in detail. Similar to previous experimental observations, the simulated gas slippage factor shows a non-monotonic increase trend with water saturation; it starts to decrease under high water saturation, and the critical water saturation depends on the pore structure factors. It increases with the mean pore radius and coordination number but decreases with the aspect ratio. We used the pore network model to investigate the effect of the water phase on the gas slippage behavior at the pore scale for the first time. It emphasized the predominance of water blocking and the gas trapping phenomenon in the estimation of the gas slippage factor at high water saturation.