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A Petrophysical Model to Distinguish Water-Wet and Oil-Wet Fractions of Unconventional Reservoir Systems Using Triple-Combo Log Suites


It is commonly recognized that mixed wetting occurs in unconventional oil reservoir systems. There are no published petrophysical methodologies to differentiate between the oil-wet and water-wet fractions using commonly available log suites. This presentation builds on our unconventional reservoir petrophysical model (Holmes 2014). Four porosity components are defined, namely total organic carbon, clay porosity, effective porosity, and newly-defined “free shale porosity.” Electrical responses of the effective porosity fraction are then compared with those of the free shale porosity fraction. As wettability to oil increases, the Archie saturation exponent (n) also increases (Keller 1953, Sweeney and Jennings 1960, Ransom 1995). Results of this study suggest that the difference between saturation exponent and Archie cementation exponent (m), when n > m, is also an indication of oil-wet conditions. Critical to this interpretation is the recognition of data alignment on porosity/resistivity cross plots. For intervals of irreducible water saturation, the slope of the aligned data is a direct measure of saturation exponent relative to cementation exponent, and satisfies the Buckles (1965) relationship: Porosity × Irreducible water saturation = constant Porosity/resistivity plots are constructed for the effective porosity and for the free shale porosity. Effective porosity plots clearly indicates water-wet conditions with cementation exponent values close to 2.0 and saturation exponent values equal to or less than 2.0. Conversely, the free shale porosity plots indicate cementation exponents mostly significantly greater than 2.0. Additionally, the plots suggest low to very low values of cementation exponent, ranging from 1.0 to 1.5. This suggests linear flow paths. Free shale porosity is generated in the thermal maturation process, as the kerogen expands and liberates liquid oil. This mechanism also explains the oil-wet nature of the free shale porosity. Applications include a better understanding of the geochemical history of the reservoir and quantification of the magnitude of water-wet vs. oil-wet porosity for reservoir simulation. The technique described offers links to microscopic investigations of rock samples and to engineering applications of fluid flow. Examples from the Bakken of Montana and North Dakota, the Niobrara of Colorado, and the Wolfcamp and Spraberry of Texas are presented.