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Integrating Basin and Reservoir Quality Modeling for Improved Prediction of Porosity and Permeability in the Deepwater Wilcox Formation, Gulf of Mexico, U.S.A.

Abstract

Porosity and permeability predictions impact the resource and deliverability estimates that support exploration, appraisal, and development decisions. These predictions require constrained assumptions to describe how porosity and permeability are likely to vary both with depth and spatially away from often limited well control. Predicting reservoir quality (ϕ, k) in the deepwater Wilcox formation, Gulf of Mexico, can be particularly challenging, as permeability can vary 3-4 orders of magnitude for a given porosity. This is in part because the Wilcox contains poorly-sorted, argillaceous, very-fine grained (<125 µm) turbidite facies that comprise a ductile grain framework. The Wilcox is especially sensitive to mechanical compaction and, therefore, it is critical to understand its pore pressure and effective stress history over time. Variable overpressures and salt’s elevated thermal conductivity and complex emplacement history can significantly affect Wilcox temperature and effective stress histories, influencing reservoir quality in ways that challenge the suitability of simple depth-dependent correlations.

Here, we present results of an integrated and physically constrained workflow that resolves reservoir quality trends across the scale of a single subsalt Wilcox field. The field is located beneath a complex overburden containing variable amounts of salt. The distance between the Wilcox and the base salt varies by several thousand feet, as does the depth to the 300o F isotherm. These geological attributes translate into spatially variable temperature and effective stress histories across the scale of this single field, which are resolved by physically constrained, high-resolution basin models calibrated to available well control. Spatially-resolved temperature and effective stress histories are then linked to predictions of compaction, quartz cementation, and reservoir quality using Touchstone™/T>Map™ software. Across this single Wilcox field, modeling results resolve spatially varying porosity degradation rates that are independent of facies. Predicted degradation rates range from as low as <1 porosity unit per 1000’ in the most salt-influenced settings, to as high as >3 porosity units per 1000’ in less salt influenced areas. Importantly, these results indicate that a single spatially uniform porosity-depth relationship does not satisfactorily describe the variation in reservoir quality we can expect in the subsurface from first principles.