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. It is hoped that this paper will stimulate further discussion on the subject and prompt industry to revise current practices.

It is widely recognized that the accurate estimation of rock properties in unconventional reservoirs such as shales is of paramount importance. These property estimates are used for original fluid in place determination, reconciling recoverable volumes of forecast production, well spacing, completion design and many other applications. 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 in the literature together 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.

There are additional reasons for the avoidance of clay porosity corrections; these include the fact that we have no reliable method to establish clay conductivity at reservoir conditions and we have no tools capable of differentiating between free gas and adsorbed gas. Both of these problems are limiting factors in the correct selection of porosity and water saturation parameters.

Total porosity and water saturation methods give rise to total gas content estimates using the appropriate volumetric model. Adsorbed gas content estimates may be obtained by correlating geochemical data based on gas content from laboratory experiments (which will include both kerogen and clay contributions) and rock density measured on core and or logs. When total porosity and total water saturation models are properly used in shale gas reservoirs characterization, the amount of free gas will be obtained as the difference between total gas content and adsorbed gas content.

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