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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. • Hydrocarbon composition was measured on lower Eagle Ford unconventional oils/condensates. • Two source facies, separated by the San Marcos Arch, are identified – carbonate-enriched mudstone and distal marine shale. • Nearly all compositional variance in the western oils is attributed to thermal maturation. • All maturity-sensitive properties and parameters show regional trends with depth. • The trend in the region near the Karnes Trough is offset by ∼2,000 ft compared to the region to the west. [ABSTRACT FROM AUTHOR]

Fifty-five oils and condensates produced from unconventional reservoirs in lower Eagle Ford Shale were characterized. Most of the samples are from the play area east of the Maverick Basin and west of the San Marcos Arch, while five samples are from wells east of the Arch. Crude assay measurements (API gravity, wt% sulfur, wt% nitrogen, viscosity at 25 and 40 °C, pour point, simulated distillation [SimDist] and C 15+ chemical group-type fractionation) were conducted on dead oil samples using standard methods. All bulk properties were found to correlate well with each other. Relationships between crude assay measurement and production depth suggest that thermal maturation accounts for most of the variance in composition; however, different depth trends are observed in oils from the Karnes Trough area compared to locations west of that region. Refinery valuation and process models rely heavily on the fractional composition of crude feedstock defined by boiling point distribution. We constructed a model using seven crude assay parameters (API gravity, % S, % N, viscosity at 40 °C, and % C 15+ saturates, % C 15+ aromatics and % C 15+ resins) as inputs for predicting SimDist boiling point curves. Using optimized parameters derived from this model, we found that SimDist curves can be modeled with nearly the same degree of accuracy using only API gravity and %S because of their strong correlation with the other bulk properties. This offers the prospect for refiners to identify wells producing specific grades of crude across the entire lower Eagle Ford play. The ability to construct a SimDist predictive model based only on the most basic assay measurements suggest that the compositional variations are due mostly to thermal maturity and the heterogeneity in source facies is insignificant in the lower Eagle Ford west of the San Marcos Arch. The SimDist predictive model is specific to the Eagle Ford shale oils and condensates, but the methodology could be used to construct formation specific models in other unconventional plays. • Basic crude assays were made on 55 oils and condensates produced from unconventional reservoirs of the lower Eagle Ford. • All bulk properties exhibit systematic trends attributed mostly to thermal maturation. • Correlations of bulk parameters with true vertical depth (TVD) differ regionally in the play. • SimDist can be accurately modeled using seven assay measurements (API gravity, %S, %N, viscosity, and SARA data) as input. • SimDist can be modeled at nearly the same accuracy using only API gravity, %S. [ABSTRACT FROM AUTHOR]

• Reduction of CH 4 sorption capacity of shale depends largely on the types of pore fluids. • The effect of pore fluids on CH 4 sorption capacity increases as the order: water < mobile oil < asphaltene. • The OM–hosted pores are preferentially coated by asphaltenes, then by the mobile oil. • The clay-mineral-hosted pores are preferentially occupied by water. • Pyrobitumen formation leads to significant increase of the sorption sites. Compositional variation and distribution of pore fluids (water, oil, and asphaltenes) as a function of thermal maturity can greatly affect methane sorption in organic-rich shales. Five Lower Bakken organic-rich shale samples with varied thermal maturity from marginal maturity to oil-to-gas cracking were used in this study to assess this effect. Pore fluids were extracted from samples at four sequential stages: as–received, oven–dried, pentane–extracted, and dichloromethane–extracted; Four aliquots for each sample were used to quantify the effect of water, mobile oil, and asphaltenes on gas sorption. CH 4 sorption isotherms were measured at 35 °C, 50 °C, and 65 °C. The results show that presence of pore fluid reduces the CH 4 sorption capacity of shale, and the extent of this reduction depends largely on the types of pore fluids. The reduction of CH 4 sorption capacity basically follows a linear correlation with moisture content. The effect of mobile oil is 4–5 times greater than that of water. Asphaltenes have no effect on methane sorption capacity for the marginally mature–mature samples but cause a drastic decrease of sorption capacity at the early oil–to–gas cracking. The surfaces of OM–hosted pores are probably coated by asphaltenes, while mobile oil is distributed in the center of the pores, and water mainly occupies the clay-mineral-hosted pores. The sorption sites will increase significantly once oil cracking to gas starts, which is probably associated with pyrobitumen formation. The affinity of CH 4 for sorption on pyrobitumen is stronger than that on residual kerogen. [ABSTRACT FROM AUTHOR]