Knowledge of mineralogy and clay is fundamental for accurate formation evaluation. In clastics reservoirs, clay characterization from logs is critical because this influences the computation of important petrophysical properties such as porosity, permeability and water saturation.

The formations of the Niger Delta region are predominantly part of facies successions of open marine shelf and wave dominated shoreface environments. The clay minerals in these formations are mainly mixtures of kaolinite, smectite, and illite with traces of feldspars, pyrite and carbonate. The use of traditional measurements based on naturally occurring gamma ray radiation over estimates clay volume. In many of these situations, a combination of neutron and density data yields a better clay volume, but in the presence of gas or light hydrocarbons this approach is less quantitative. Moreover, for both the techniques (gamma ray or neutron-density combination, selection of clean-sand and clay end-points is subjective leading to more error in clay volume computation.

To achieve a more accurate clay volume and porosity, wireline spectroscopy tool, along with other open hole logs and Nuclear Magnetic Resonance (NMR was run in a few wells. Spectroscopy aids in a much improved clay volume and in so doing, a more accurate porosity can be computed. The spectroscopy supported porosities (total, clay bound and capillary bound and permeability are in good agreement with NMR results. This in turn helps to build a better petrophysical model for historical wells.

Spectroscopy also helped in correlating petrophysical answers with depositional environment. By combining with core and magnetic resonance data, probabilistic mineral analysis showed that the sands with lowest feldspars have the highest permeability. These sands with large grain sizes were deposited in the high-energy upper shore-face environment and also explain the wide variation (20 to 70 API observed in the gamma-ray response of reservoir sands.

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