Lithofacies-Based Corrections to Density-Neutron Porosity in a High-Porosity Gas- and Oil-Bearing Turbidite Sandstone Reservoir, Erha Field, OPL 209, Deepwater Nigeria

A high-porosity confined slope channel complex sandstone reservoir is currently undergoing a 24 well development in the Erha Field, OPL 209, deepwater Nigeria. Three conventional cores have been acquired in the field, but none in gas-bearing section. Formation porosities derived from conventional log data were calibrated to the conventional core in oil and water sections only. Historically, it has been assumed that standard density-neutron porosities approximate true formation porosities in gas-bearing section at Erha. There is conclusive evidence, however, that porosities from gas-bearing sections at Erha are not accurately approximated by using a standard density-neutron technique. Computed formation porosities in the gas zones are often much larger than porosities in oil-and water-bearing sections. A statistical lithofacies prediction model based upon log and core data has proven useful to highlight large discrepancies in formation porosity from gas-, oil- and water-bearing sections. The predictions rely heavily on total porosities that are calculated from the density and neutron logs through the standard density-neutron technique. The use of these data in the prediction model commonly results in predictions that overestimate the fraction of low quality reservoir facies in intervals where high quality reservoir facies are expected. Crossplots of density-neutron porosity versus shale volume have been constructed to investigate the relationship between formation porosity in gas-bearing section and porosities calculated in oil- and water-bearing section. In all of the wells at Erha, formation porosities in gas-bearing section exhibit distinct trends in porosity versus shale volume that are different from the trends observed in oil and water sections. All of these porosity trends converge at a shale point of 100% shale volume. From the crossplots, correction factors have been calculated that vary directly with shale volume. These corrections remove artificial gas effects that are not fully compensated by the standard density-neutron technique. Subsequent use of the corrected porosity in lithofacies predictions has yielded more accurate and geologically reasonable results. The facies predictions from the statistical model are used as direct inputs to the final geologic and reservoir simulation models for the field. Using facies inputs dominated by low quality facies commonly results in lower average formation permeability and hydrocarbon volume estimates. Therefore, it is imperative to accurately calculate total porosity to yield the most accurate lithofacies predictions. By doing so, the reserve potential and performance of the field are characterized with much less uncertainty.