ROCK CLASSIFICATION IN THE EAGLE FORD SHALE THROUGH INTEGRATION OF PETROPHYSICAL, GEOLOGICAL, AND GEOCHEMICAL CHARACTERIZATION

摘要

Formation evaluation and production design is often challenging in organic-rich mudrocks due to complexities in petrophysical and compositional properties, and post-depositional hydrocarbon generating mechanisms such as thermal maturation over time. Petrophysical parameters such as porosity, permeability and fluid saturations are important, but not sufficient to fully characterize organic-rich mudrocks. Integration of petrophysical, geochemical and geomechanical data is therefore required for a reliable rock classification in source rocks. This paper focuses on integrated rock classification in the Eagle Ford Shale in South Texas, consisting of organic-rich fossiliferous marine shale deposited in Late Cretaceous.We first performed joint inversion of triple-combo, spectral gamma ray and elemental capture spectroscopy (ECS) logs to estimate depth-by-depth volumetric concentration of minerals, porosity, and fluid saturations. In the absence of acoustic measurements, concentrations and shape (i.e., aspect ratio) of minerals were used as inputs to the Self-consistent Approximation (SCA) model, to estimate depth-by-depth effective elastic properties such as Young's Modulus (YM) and Poisson's Ratio (PR). We then classified the rocks based on geologic texture and geochemical properties, as well as well-log based estimates of petrophysical and geomechanical parameters.We successfully applied a well-log based rock classification to two wells located in the oil window of Eagle Ford formation. Well no. 1 produced an additional 20% of hydrocarbons in the first 90-day of its production. Through the analysis of the results, we observed similar petrophysical properties and organic content of the reservoir quality classes in both wells. However, we noticed differences in estimates of elastic parameters such as Young’s Modulus and Poisson’s Ratio between the two wells. For the interbedded wackestone-limestone facies, YM average estimate in well no. 1 was approximately 10% higher than well no. 2, which can be the reason for the difference in their production.