A good estimate of porosity can be derived from the density log based on the simple tool physics, if key variables such as fluid density (of the invaded zone) and matrix density are known. Sandstone dominates mineralogy in the Niger Delta area and its density is known within an acceptable uncertainty, based on abundant availability of core measurements. However, the uncertainties associated with in-situ fluid density values are more drastic (0.2 − 1.1g/cc), depending on the formation fluid density, the drilling mud density and degree of invasion. In evaluating the porosity of the formation, estimation of actual fluid density to be used, especially across light hydrocarbon zones, has always been a major source of uncertainty and different methods have evolved over the years for tackling this challenge. This paper examines some of the methods that have been used over the years and provides a simple, robust and auditable method for providing a good estimate of formation porosity that does not depend on an independent estimation of fluid density, and as such, it is not affected by the presence or otherwise of light hydrocarbons. It uses a combination of the density and neutron logs, with volume of shale calculated from the same log sets as a compensator.

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