A Workflow to Evaluate Mineralogy, Porosity, TOC, and Hydrocarbon Volume in the Eagle Ford Shale

Abstract

The Eagle Ford Shale hydrocarbon-fluid properties depend on the source rock maturity and, within the formation, occur in varying degrees of gas, gas condensate, and oil. Using conventional logs and pyrolysis data, several log-core regressions, such as delta log R, density, and uranium, can be derived to predict total organic carbon (TOC). TOC can be used with geochemical elemental measurements for a more accurate assessment of the formation kerogen and mineralogy, as well as hydrocarbon volumes. Nuclear magnetic resonance (NMR) porosity measures an apparent total porosity in the organic shale plays, measuring only the fluids present and excludes the kerogen. The complex refractive index method (CRIM) with the mineralogy log data can be used to compute accurate dielectric porosities, which exclude both kerogen and hydrocarbon. Integrating the core TOC, predicted TOC, mineral analysis, NMR, and dielectric information, a final verification of the kerogen volume, porosity, hydrocarbon content, and mineral analysis can be assessed. This paper will describe the integration of conventional logs, a geochemical log, an NMR log, and dielectric to predict TOC, kerogen volume, and hydrocarbon volume, as well as total porosity and mineralogy. The log data is compared to core data from three Eagle Ford wells. Based on the results from these three wells, a comprehensive workflow is developed for unconventional source rock reservoir interpretation. The workflow is then applied to two additional Eagle Ford wells and the results are compared to core data. While the workflow is demonstrated with Eagle Ford data it is believed that it will be applicable in other unconventional source rock reservoirs. It will be demonstrated how the proposed approach will help eliminate some coring operations and can be used to help make decisions on optimum lateral placement.