Traditional absolute pore space concept considers the whole pore volume within the reservoir rock. Total porosity accounts for the entire pore space, so the maximum fluid saturation in rock related to this value. The structural complexity of pores in rocks especially in carbonates frequently results in isolated pores creation. These stagnant pores contribute to the absolute porosity of the rock, but are not involved in the flow of fluids through the rock. The intercommunicating pore spaces that maintain the flow of fluids make up the effective porosity. As fluid transport in porous media is controlled by the available amount of pores for flow, so this is the effective pore space not absolute one, in which real reservoir flow process occurs. In this study, play based hydrocarbon exploration procedure for an area followed. This region is surrounded by the gas discoveries in different reservoir horizons on the adjacent blocks. Complexity of geological structures and sequence of terrigenous-carbonates facies' change had led to drilling of seventeen dry wildcats. Aiming to reinvestigate the hydrocarbon potential, integrated petrophysical and seismic interpretation designed to identify hydrocarbon accumulation on the basis of regional studies. By analysis of core and well log data, static petrophysical properties calculated, reservoir horizons characterized and afterward the effective porosity was estimated using adaptive well log interpretation. The effective porosity estimations imported as an input for genetic inversion procedure to determine its distribution over the targeted formation. The effective porosity cube presented anomalies in areas where seismic attenuation attribute confirms possibility of gas accumulation. Successful implementation of shared-earth model using close interpretation of seismic and well data led to identifying a stratigraphic prospect with an acceptable probability of success.
