An Integrated Geophysical Approach for Porosity and Facies Determination: A Case Study of Tamag Field of Niger Delta Hydrocarbon Province

Petro physics, rock physics and multi-attribute analysis have been employed in an integrated approach to delineate porosity variation across Tamag Field of Niger Delta Basin. Gamma and resistivity logs were employed to identify sand bodies and correlated across the field. Petro physical analysis was undertaken. Rock physics modelling and multi-attribute analysis were carried out. Two hydrocarbon reservoir sands (A and B) were delineated across the field. Reservoir A is a relatively clean sand, characterized with high average porosity of 0.28 while Reservoir B is also a relatively clean sand with lower average porosity of 0.24. Reservoir A is a replica of Friable Sand Model while reservoir B mirrors the Constant Cement Model. Acoustic impedance attributes serve as good predictors of lateral changes in porosity across the reservoirs. The internal fabric of Reservoir sand A is that of a clean high porosity sands implying that there are few or no diagenetic cement and the stiffness of the rock is weakly affected. This reservoir is relatively good quality due to its good porosity and sorting even at deeper depths. This unconsolidated sandstone reservoir is associated with high permeability but highly susceptible to sand production, which causes severe operational problem for oil and gas explorers. Reservoir B has good porosity but relatively lower that of Reservoir A. This conforms to the results of the petro physical analysis which shows that reservoir sand A with average porosity 0.28 is more porous than reservoir sand B with average porosity 0.24.