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Estimating the Effect of Rock Mineral Composition on Reservoir Quality: Application in the Spraberry and Wolfcamp Formations, Permian Basin, Texas and New Mexico
Estimation of the mineral and fluid composition of rock formations is important for petrophysical and rock physics analysis. One method of estimating rock composition is by solving a system of linear equations that relate a class of geophysical log measurements to the petrophysical properties of known minerals and fluids as an inverse problem. This method has proven useful for carbonate rocks having complex mineralogies. In this study, we develop a new workflow for estimating the rock mineralogy as an inverse problem and examine the relationship between the rock composition and porosity. We apply the workflow to well log data spanning the Spraberry Formation in the Permian Basin and estimate the volumes of quartz, calcite, and clays. Within the study area, an increase in calcite can be observed to correspond to a decrease in porosity indicating the effect of calcite cementation. An increase in quartz content can be observed to correspond to an increase in porosity. In general, an increase in clay content corresponds to a decrease in porosity indicating the clay may be pore filling. The results indicate that areas having less calcite and less clay minerals also have better reservoir quality. Petrophysical composition maps generated from the results will help reduce the risk in unconventional petroleum exploration.
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