From Bureau of Economic Geology, The University of Texas at Austin (www.beg.utexas.edu).
For more information, please contact the author.

AAPG Annual Convention, Calgary, Alberta, Canada, June 19–22, 2005

Effect of Calcite Cement on Reservoir Properties in Permian Deepwater Sandstones, Delaware Basin, West Texas

Shirley P. Dutton, and William A. Flanders

Abstract:

Sandstones of the Upper Permian Bell Canyon Formation in the Delaware Basin of west Texas were deposited by turbidity currents in a basin-floor setting. The sandstones were deposited in channel-levee systems that terminated in broad lobes; overbank splays filled topographically low interchannel areas. Diagenesis and reservoir quality of the sandstones were examined in core from East Ford field, which is undergoing a CO2 flood. The reservoir is a well-sorted, very fine grained arkose. Calcite is the most abundant authigenic mineral, having an average volume of 7 percent and ranging from 0 to 30 percent. Authigenic chlorite averages 1 percent. Calcite cement is concentrated mainly in zones ranging from 5 to 40 cm in thickness and is more abundant along the sandstone margins. Core-plug porosity ranges from 4.5 to 24.6 percent, and permeability to air from 0.01 to 78 mD. Because the sandstones have a narrow grain-size range and contain no detrital clay, volume of calcite cement is the dominant control on porosity and permeability.

Production data suggest that some of the calcite occurs in laterally continuous layers and not as isolated concretions. In a new infill well, initial production was of a high gas volume that contained a high concentration of CO2 from the interval beneath several low-permeability, calcite-cemented zones. The CO2 was most likely from an injector well and was trapped below calcite layers. Geophysical log correlations support the interpretation that some calcite layers are laterally continuous over a distance of at least 300 m, causing vertical compartmentalization in the reservoir.