Objectives/Scope: Understanding that capillary forces will act to limit petroleum fluid saturations in water-wet fine-grained rocks, including organic rich source rocks, dates back at least to Hubbert (1953). Likewise, Philippi (1965) noted relationships identifying sorption in/on organic matter as a significant storage mechanism in organic-rich rocks. Contrast these early insights with current unconventional reservoir evaluation, where we observe a disconnect between in situ (core exhumed to surface) measured total water saturations vs. the produced cumulative water volumes from a given stimulated rock volume. Water-free production in gas shales, from gas-wet organic matrix pores, created an early impression that unconventional plays don't produce water. So, in more liquid-rich plays, water cuts were initially under-appreciated: e.g. >80% in the Wolfcamp (stock-tank basis). If measured Sw is so low (core-based calibration), where is the water coming from; or is there an alternative method to more accurately relate in situ to produced water and petroleum production?
Methods/Procedures/Process: Adapting organic sorption models from the 80's, we can split total hydrocarbon volatiles into sorbed and, by difference, non-sorbed (fluid phase) yields. Converting to volumes and adding back dissolved gas using a formation volume factor (FVF) we can estimate the bulk volume fluid phase. This new approach then yields observations regarding remaining water-filled pore volume versus sorbed and non-sorbed hydrocarbon volume explaining the high water cuts in the Permian Basin stratigraphy; and additionally may indicate sweet spots in pore systems in different parts of the rock compared to alternatively derived saturations.
Results/Observations/Conclusions: The final piece of the puzzle comes from basin modeling of petroleum charging in the 90's. Some scientists applied conventional reservoir relative permeability to fine-grained rocks, but new research predicted that progressively finer grained rocks with higher irreducible water should be able to flow oil at progressively higher Sw: at 100nD, both oil and water should flow at Sw > 80%. Lower petroleum phase saturations and adjusted relative permeability curves may better explain observed production behaviors and profoundly alter our view of recovery factor and stimulated rock volume.
Applications/Significance/Novelty: The method offers an alternate and independent method to Dean-Stark-based core / SWC saturation analysis and its pitfalls. Saturation patterns after removal of immobile sorbed oil are different to those derived using the Dean-Stark based method, implying sweet spots / landing zones can be further optimized even in maturing shale plays. Lower oil-in-place – representing only the potentially mobile fluid phase petroleum – means that fracture stimulation has a higher recovery factor than previously thought, with profound effects on the infill volumes / opportunities for future field developments and therefore ultimately for US – and global – oil supply projections.
Interdisciplinary Components: Cross-over technology from organic geochemistry to petrophysics to reservoir engineering.