Dry Gas Eagle Ford Appraisal Program and Reservoir Characterization
Michael J. Handke, H. D. Bello, and C. E. Yokoyama
South Texas Asset Team, Pioneer Natural Resources, Irving, Texas
We present an integrated petrophysical and geophysical approach used to appraise a large acreage position in the dry gas window of the Cretaceous Eagle Ford shale in South Texas. In the study area, the Eagle Ford formation is between 200 and 350 feet thick, the base of which ranges between 14,000 and 15,000 feet TVD. Wells drilled in this area are some of the deepest, hottest, and most thermally mature wells in Pioneer’s Eagle Ford acreage. Six pilot wells were drilled and logged, and 350 feet of core was collected across the full Eagle Ford interval. The Lower Eagle Ford target reservoir is characterized by interbedded carbonate marls and shales with high (>10%) effective porosity. Lithofacies associated with high-porosity intervals include mixed mudstone and mixed carbonate mudstone, whereas low-porosity intervals are more homogeneous.
Pre-stack and post-stack seismic inversion and geostatistical mapping were used to predict rock properties away from the pilot wells and throughout the study area. Seismic attribute volumes were generated to predict regional reservoir characteristics such as porosity, kerogen volume, brittleness, Poisson’s ratio, and Young’s modulus. Examples of attribute maps and cross sections will be presented that highlight the impact and accuracy of this approach. By identifying porosity sweet spots, we were able to high-grade our development plan and refine well placement. Finally, well performance data (including EUR estimates) are tied back to the geologic data and seismic attribute maps in order to evaluate the key performance drivers in the dry gas region.
AAPG Search and Discovery Article #90164©2013 AAPG Southwest Section Meeting, Fredericksburg, Texas, April 6-10, 2013