Using clay microporosity to improve formation evaluation in potential residual oil zones: Cypress Sandstone, Illinois Basin

Abstract

Clay microporosity in sandstones can cause erroneously high water saturation calculations if not properly accounted for and reduces effective pore space when evaluating a formation. We conducted a petrographic study to characterize and quantify the clay mineral microporosity of the fluvial facies of the Mississippian Cypress Sandstone in the Illinois Basin. This data helped achieve more accurate saturation calculations through core and well log analyses in potential Cypress residual oil zones. Petrographic thin sections were analyzed by scanning electron microscopy with backscatter imaging and energy dispersive X-ray spectroscopy. Clay mineral species identified included pore-filling kaolinite books, blocks, and vermicules; chlorite clusters; illite mats; illite-smectite webs; grain-coating inherited chlorite rims; and pore-bridging illite hairs. Volume percentages of microporosity particular to clay mineral species were determined by image analysis. Average microporosity values in kaolinite, chlorite, illite, and illite-smectite were 41%, 57%, 67%, and 65%, respectively. Effective clay mineral volumes, including microporosity, showed a >2-fold increase over estimates determined by X-ray diffraction, constituting an average volume of 4%. Comparing these volumes with gamma-ray log estimates proved Stieber’s work to predict clay volume most accurately. Clay volumes were used as input parameters in the dual-water method for determining water saturation, resulting in greater residual oil saturations than those predicted from Archie’s equation. Accounting for clay microporosity in helium porosimetry measurements of total porosity resulted in an ~11% decrease to effective porosity. Results from this research improve estimates of water saturation and porosity and highlight the importance of studying microscale mineralogical properties during reservoir characterization.