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Geochemistry and Origin of Formation Waters From the Lower Eagle Ford Shale, South Central Texas

Abstract

The lower Eagle Ford Shale is one of the most productive tight oil and shale gas plays in the United States but few associated produced waters data and minimal interpretation have been published. This effort focuses on results from compositional and isotopic data (δ2H, δ18O, δ11B, and 87Sr/86Sr) from 40 produced water samples collected from single and two-well configurations producing from the lower Eagle Ford Shale in south central Texas. To minimize influence from injection fluid, samples were collected from wells that had been in production for at least 3 months. The depth of the Eagle Ford Shale increases by approximately 1 km across the study area, from northwest (2.9 km) to southeast (3.9 km). Associated increases in calculated reservoir temperature (125-165 °C), development of reservoir over-pressuring (400-800 bars total pressure), and increased thermal maturity (heavy oil to gas condensate) also occur along this trend. Produced water salinity starts at nearly 100 g/L in the shallowest samples and decreases linearly with depth to <35 g/L (seawater salinity). Results for δ2H and δ18O from the produced water samples (–19 to –11‰ and +5.1 to +8.4‰, respectively) are isotopically heavier than local meteoric water, and show increasing δ18O and decreasing δ2H with depth. This trend in isotope compositions can be attributed to changes in fractionation during O and H exchange between seawater and illite (~20-25% of Eagle Ford Shale by volume) with increasing temperature. Decreasing salinity with depth and thermal maturity in the Gulf Coast Basin have previously been shown to be a result of dilution from water vapor condensing from the gas phase with increased over-pressuring. Finally, acetate concentrations increase along this same trend from 117 to 1,360 mg/L, which is consistent with the decarboxylization of kerogen with increased reservoir temperature. Thus, initial interpretations suggest that a combination of physical (kerogen breakdown and water vapor condensation) and chemical (water-rock interactions between paleoseawater and reservoir minerals) processes appears to dominate the composition of formation waters from the Eagle Ford Shale in the study area.