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AAPG Bulletin, V.
Rock classification in the Eagle Ford Formation through integration of petrophysical, geological, geochemical, and geomechanical characterization
1Enhanced Oil Recovery Business Unit, Occidental Petroleum Corporation, Houston, Texas; [email protected]
2Veratek Design, Escondido, California; [email protected]
3Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, Texas; [email protected]
4Department of Geology and Geophysics, Texas A&M University, College Station, Texas; [email protected]
Integration of geomechanical, geological, geochemical, and petrophysical characterization is critical to enhance production from organic-rich mudrocks. This paper introduces an integrated rock classification method in the Eagle Ford Formation shales and marls in southern Texas, consisting of organic-rich fossiliferous marine shale deposited during the Late Cretaceous. A joint inversion of triple-combo, spectral gamma-ray, and elemental capture spectroscopy logs was initially conducted to estimate volumetric concentrations of minerals, porosity, and fluid saturation. Effective elastic properties such as Young’s modulus and Poisson’s ratio as well as minimum horizontal stress were then estimated as a function of depth. Rock classification was finally performed based on geologic texture and geochemical properties, as well as well-log–based estimates of petrophysical and geomechanical properties.
The introduced method was applied to two wells located in the oil window of the Eagle Ford Formation (average gas–oil ratio of less than 2000 SCF/STB). The results of the integrated rock classification demonstrated similar organic richness and petrophysical properties in both wells. However, the geomechanical rock classification as derived from in situ stress profiles suggests higher proportions of the rock class with better completion quality (55% of net thickness in one well vs. 34% in the other well). A 90-day report on the cumulative oil production of this well shows an additional 11,000 bbl (i.e., 20% more oil production) compared to the second well. This observation was accounted for by geomechanical properties and the distribution of rock classes that differentiate reservoir quality and production.
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