Geochemistry of oils and condensates from the lower Eagle Ford Formation, south Texas. Part 2: Molecular characterization

Abstract

Fifty-five petroleum samples from unconventional wells in the self-sourced lower Eagle Ford Shale were analyzed using routine geochemical methods. The samples are broadly distributed, geographically and vertically, and range in maturity from mid-oil to wet gas. Their physical and chemical properties span most of the range observed in the entire play. Two source facies are identified: west of San Marcos Arch is a marine marl facies deposited under anoxic to euxinic conditions containing abundant type II/IIS kerogen and east of the Arch is a marine shale to marl facies deposited under mostly oxic to anoxic conditions that received an additional input of terrigenous organic matter. The unconventional oils are too mature to detect any subtle differences that could distinguish a marl from a pure carbonate source facies. Saturated and aromatic biomarkers rapidly decrease with depth and are at or near the limits of detection below ∼9,000 feet. Condensates >13,500 ft show evidence of advanced hydrocarbon cracking. All properties and molecular parameters that are dependent on thermal maturity for oils/condensates west of the San Marcos Arch exhibit two trends with true vertical depth (TVD). One is defined by samples between the Karnes Trough area and the Maverick Basin; the other trend defined by samples near the Karnes Trough is offset with equivalent maturity occurring at deeper depths. This ∼2,000 ft offset is likely due to differences in the amount of uplift and erosion experienced in the two regions after the source rocks achieved their maximum maturity.