This paper addresses the problems identified in current shale reservoir characterization practices. We also provide alternative approaches with relevant reflections on the determination of volumes in-place. Rock properties in unconventional reservoirs such as shales is of paramount importance. By comparison with conventional reservoirs, fluids are present not only in the intergranular porous media but also within the fine texture of the rock matrix (Clays, Kerogen and
Micro-Fractures) which usually are only recoverable with the aid of suitable stimulation and completion technologies. This paper questions current engineering practices related with the assumption of unrealistic cut-offs in the petrophysical
analyses which in turn may result in dangerously misleading estimates of in place volumes and thus inadequate development decisions being made.
The adsorption capacity of clays has been documented with observations on the correlations between the percentages of clay minerals in the rock and Langmuir volume (VL) determined in laboratory measurements of gas content from core
samples by means of Langmuir isotherms. Therefore it should be no surprise that clays in shale gas reservoirs are known to adsorb hydrocarbon gases and may contribute to the production when properly stimulated. We therefore recommend
that corrections for clay effects should not be arbitrarily applied in the petrophysical analysis of electric logs. The use of a total porosity-total water saturation model will help to avoid shortcomings in total gas in-place determination. Additional
reasons for the avoidance of clay porosity corrections; include the fact that there are no tools capable of differentiating between free gas and adsorbed gas.
Total porosity and water saturation methods give rise to total gas content determination with the appropiate model. Adsorbed gas content estimate, may be obtained by correlating geochemical data based on gas content from laboratory experiments and rock density measured on core and or logs.