Geochemistry of oils and condensates from the lower Eagle Ford formation, south Texas. Part 1: Crude assay measurements and SimDist modeling. (May 2022)

• Record Type: Journal Article
• Authors: Zhang, Tongwei; Sun, Xun; Walters, Clifford C.; Sundaram, Anantha; Calla, Jason T.
• Is Part Of: Marine and petroleum geology. Volume 139(2022)
• Publication Date: 2022-05
• Subjects: Crude oil -- Condensate -- Petroleum geochemistry -- Thermal maturity -- Eagle Ford -- Unconventional resources; Submarine geology -- Periodicals; Petroleum -- Geology -- Periodicals; Géologie sous-marine -- Périodiques; Pétrole -- Géologie -- Périodiques; Petroleum -- Geology; Submarine geology; Periodicals; Electronic journals; 551.468
• DOI: 10.1016/j.marpetgeo.2022.105576
• Languages: English
• ISSNs: 0264-8172

Abstract

Abstract: 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 C15+ 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 % C15+ saturates, % C15+ aromatics and % C15+ 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. Highlights: 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.