Comparison of Reservoir Quality from La Luna, Gacheta and Eagle Ford Shale Formations

Abstract

A large fraction of all whole core samples recovered today come from shale (mudstone) reservoirs. The primary reason for this is that shale petrophysical models require rigorous core calibration to provide reliable data for reservoir quality, hydrocarbon-in-place and hydraulic fracturing potential. However the uncertainty in interpreting shale well log data is sometimes matched or exceeded by the uncertainty observed in traditional methods of analyzing core samples. High-quality organic-rich shales usually have permeability lower than 0.001 mD. This extreme low permeability creates substantial challenges for existing methods and has contributed to the rapid rise of a new approach to shale reservoir evaluation, Digital Rock Physics (DRP). DRP merges 3 key technologies that have evolved rapidly over the last decade. One is a high-resolution diagnostic imaging method that permits detailed examination of the internal structure of rock samples over a wide range of scales. The second is advanced numerical methods for simulating complex physical phenomenon. The third is high-speed, massively parallel computation using powerful graphical processing units (GPU's), originally developed for computer graphics and animation. This presentation describes an integrated DRP process for analyzing rock properties of shale reservoirs at multiple scales. The process begins with whole core samples, progresses to smaller plug size samples, then ultimately to high-resolution 3D imaging of the pore space. This imaging, combined with unique proprietary fluid flow algorithms allows us to compute shale reservoir properties and provide clear 3D renderings of the pore structure. Core samples were available from 4 wells in the Eagle Ford formation. Results from these wells are compared to La Luna and Gacheta formation cores from the Litoteca Nacional Bernardo Taborda, Colombia. In summary: A multi-scale rock properties analysis process was applied to the analysis of shale reservoir properties in the La Luna and Gatcheta formations. Key results: Porosity and permeability are comparable to or better than those from the Eagle Ford formation; Permeability in horizontal plane is 10 to 100 times greater than in the vertical direction; Porosity assoc. with organic matter varies from 100% of total to less than 10% of total depending on specific formation and depth; The transformation ratio for kerogen to porosity ranges from about 20 to 40%.

AAPG Datapages/Search and Discovery Article #90189 © 2014 AAPG Annual Convention and Exhibition, Houston, Texas, USA, April 6–9, 2014