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.
Unconventional reservoirs have burst with considerable force in oil and gas production worldwide. Shale Gas is one of them, with intense activity taking place in regions like North America. To achieve commercial production, these reservoirs should be stimulated through massive hydraulic fracturing and, frequently, through horizontal wells as a mean to enhance productivity.
In sedimentary terms, shales are fine-grained clastics rocks formed by consolidation of silts and clays. In log interpretation of conventional reservoirs, it is very common to observe that the clay parameters used to correct porosity and resistivity logs for clay effects are in fact read in shaly intervals rather than in pure clay. Although no considerable deviation have been observed in shaly sandstones, anyway these concepts and procedures must be reviewed to run log analysis in shale gas. Organic matter deposited with shales containing kerogen that matured as a result of overburden pressure and temperature, giving rise to source rocks that have yielded and expulsed hydrocarbons. Shale gas reservoir type is a source rock that has retained a portion of the hydrocarbon yielded during its geological history so that to evaluate the current hydrocarbon storage and production potential it is necessary to know the kerogen type and the level of TOC - total organic carbon - in the rock. Produced gas comes from both adsorbed gas in the organic matter and "free" gas trapped in the pores of the organic matter and in the inorganic portions of the matrix, i.e. quartz, calcite, dolomite.
In these unconventional reservoirs, gas volumes are estimated through a combination of geochemical analysis and log interpretation techniques. TOC, desorbed total gas content, adsorption isotherms, and kerogen maturity among other things can be measured in cores, sidewall samples and cuttings, in the laboratory. These data are used to estimate total desorbed gas content and adsorbed gas content which is part of the total gas. Also in laboratory, porosity, grain density, water saturation, permeability, mineral composition and elastic modules of the rock are measured. Laboratory measurement uncertainty is high and consistency between different providers appears to be low, with serious suspicions that procedures followed by different laboratories are the source of such differences. The permeability is one of the most important parameters, but at the same time, one of the most difficult to measure reliably in a shale gas. Core calibrated porosity, mineral composition, water saturation and elastic modules can be obtained through electric and radioactive logs. All these information is used to estimate log derived total gas volume which results are also subject to a high degree of uncertainty that must be overcome.
Once this key information is obtained, it is possible to estimate different gas in-situ volumes. Indeed, an estimate of porosity-resistivity based total gas in-situ and, on the other hand, geochemical based adsorbed gas in-situ can be performed. Log total gas in-situ can be, and it is advisable to do, compared with adsorbed gas estimations and also with another gas measurement called direct method - total gas desorption performed on formation samples. The difference between log total gas in-situ and adsorbed gas in situ should be the "free" gas in situ. Free gas occupies the pores of kerogen and matrix; also it can be stored in open natural fractures if such fractures are present.