Petrographic and petrophysical characterization of the Eagle Ford Shale in La Salle and Gonzales counties, Gulf Coast Region, Texas

Abstract

The Eagle Ford Shale is an organic-rich marine carbonate-dominated mudrock located in the Gulf Coast Region, Texas. This mudrock was deposited during the Late Cretaceous and is composed of two main members: the lower and the upper Eagle Ford, which are associated to marine transgression and regression episodes respectively. Petrographic analysis of two cores from wells located in Gonzales (Well #1) and La Salle (Well #2) counties indicates that the Eagle Ford Shale has a strong cyclic character. Eight different facies and six microfacies were recognized at different well depths. A paleontologic study was carried out to better characterize the Eagle Ford Shale, where both benthonic and planktonic microfossils were identified. The most abundant microorganisms are foraminifera, although echinoderms, bivalves, fish bones, radiolaria, coccoliths and calcispheres are also present. This diversity in microfossils reinforces the cyclic character of the Eagle Ford. Contrary to the commonly believed idea that marine transgression implies deep marine anoxic conditions, this study indicates that it is not necessarily true. Instead, marine transgression may also lead to shallow marine conditions where benthonic organisms are abundant, similar to what is observed in the lower Eagle Ford at Well #2. Pore system was characterized at both well locations by combining water immersion porosimetry (WIP), mercury injection capillary pressure (MICP) and scanning electron microscopy (SEM). Total porosity results indicated that WIP overstates the total porosity when clay content is above 50 wt. %. MICP shows more reliable total porosity values where mineralogy does not apparently affect the experiment final results. Total porosity ranges between 0.32-10.27 percent, where most pore throats diameters fall within the nanopore to micropore size range. Intraparticle pores within the organic matter are dominant in the Eagle Ford, especially in Well #2 where thermal maturity is higher compared to Well #1. Hydrocarbon potential was studied by using both the Basic/Bulk-Rock and Institut Français du Pétrole Energies Nouvelles (IFPEN) Shale Play Rock-Eval pyrolysis methods. The IFPEN Shale Play method allows to a better quantification of the hydrocarbons in unconventional plays compared to the Basic/Bulk-Rock method. The average increase in hydrocarbons quantification using the new method is 25.69 percent. The intervals with higher hydrocarbons content are the lower Eagle Ford at Well #2 location (6.68-22.69 mg HC/g rock) and the lower portion of the upper Eagle Ford at Well #1 location (6.74-8.22 mg HC/g rock). Pyrolysis analysis was coupled with petrographic study on SEM. Detrital and secondary organic matters were recognized in both well locations, where secondary organic matter is dominant. A strong correlation between hydrocarbon potential and foraminifera test chamber cementation was found. Well intervals where foraminifera test chambers are filled with kaolinite and secondary organic matter present higher oil-in-place (OIP) compared to those intervals where the test chambers are cemented with calcite. Likewise, intraparticle organic matter porosity is denser at those intervals with higher potential in terms of OIP.