A Workflow to Evaluate Porosity, Mineralogy, and TOC in the Utica-Point Pleasant Shale Play

Abstract

Abstract Porosity is a key reservoir property used in petrophysical evaluations. Obtaining realistic porosity estimates in unconventional reservoirs is challenging using only conventional logs. Conventional log porosity measurements are affected by the presence of kerogen in organic-rich reservoirs. Techniques such as ΔLogR can be used to predict total organic carbon (TOC) which can be converted to kerogen volume. The kerogen volume can then be used to apply corrections to conventional porosity measurements. However, these techniques require prior knowledge of thermal maturity or core measurements such as vitrinite reflectance (Ro). The predicted TOC can also be used in conjunction with geochemical elemental measurements for a more accurate assessment of formation kerogen and mineralogy, as well as for hydrocarbon volumes. Nuclear magnetic resonance (NMR) logs measure only the fluids present and represent a total porosity unaffected by solid components such as kerogen and bitumen. Recent observations in numerous unconventional resource plays indicate that NMR log porosity provides the best match to core porosity and does not require corrections for kerogen. NMR log porosity is available in real time as an input to the petrophysical model long before core measurements can be completed. The complex refractive index method (CRIM) in conjunction with mineralogy log data can be used to compute accurate dielectric porosities, which exclude both kerogen and hydrocarbon. Integrating 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. Based on previous work in the Eagle Ford Shale, a comprehensive workflow was developed for unconventional source rock reservoir interpretation. The workflow integrates conventional logs, a geochemical log, an NMR log, and a dielectric log to predict TOC, kerogen volume, mineralogy, total porosity, and hydrocarbon volume. This paper will show results from the Eagle Ford wells upon which this workflow is based. Then, we apply the workflow to the Utica-Point Pleasant Shale Play and compare those results to core measurements.