Porous rocks containing fluids are sometimes also found in nature with additional kerogen, bitumen, and other classically soluble or insoluble hydrocarbons which are lumped here for practical purposes under a generic term, solid hydrocarbons. It is long recognized that NMR will measure porosity deficit in environments contaminated with solid hydrocarbons when compared to corresponding traditional bulk density porosity computations. An NMR porosity deficit is well established as a flag for presence of solid hydrocarbons which are generally seen as silent to tool response. However, volumetrically speaking, which porosity is correct? Bulk density porosity? NMR total fluid porosity? Technically speaking, the answer derived here is neither. This paper rigorously defines a new and innovative porosity term to deterministically solve for fluid and solid phase pore volume fractions. The sum of these pore volume phase constituents is termed in this context paleo porosity. Paleo porosity implies the bulk pore volume fraction of rock available for fluids prior to solid hydrocarbon formation.
In addition to a simultaneous bulk density and NMR solution presented, this paper also considers an alternative solution which employs routine Total Organic Carbon (TOC) measurements to discriminate solid from liquid phase hydrocarbons. When combined with bulk density measurements, classic TOC pore modeling can describe paleo porosity.
Applications for these paleo porosity models are far reaching and include log and core analysis in any environment that exhibits pore volume either completely or partially occluded by solid hydrocarbons. The introduction of paleo porosity here offers multiple petroleum engineering disciplines a powerful concept to model beyond basins and predict reservoir properties which include or are related to rock porosity.