Geochemistry of oils and condensates from the lower Eagle Ford formation, South Texas. Part 3: Basin modeling

Abstract

Maturity-dependent bulk properties and molecular compositions of oils and condensates produced from the lower Eagle Ford shales exhibit two distinct regional trends with production depth. Samples west of 98.6 West longitude form a trend that is offset upwardly by ∼2000 ft compared to samples near the Karnes Trough area. This offset is unlikely due to variations in source facies or regional heat flow. To test whether the offset is the result of different amounts of uplift and overburden removal, a psuedo 3D basin model was constructed for the Eagle Ford Formation using standard geologic methods and rock-calibrated 1D burial histories. Present-day thermal maturity was found to correlate with reconstructed maximum burial depth (MBD). When maturity-dependent geochemical parameters are plotted versus MBD, the trends show significantly greater fidelity than when plotted versus true vertical depth; however, the regional offsets are still evident, suggesting that the basin model could be refined. Petroleum samples can be used to calibrate basin models provided they reflect the current maturity of their source. This criterium may be met by unconventional fluids provided the producing strata is charged with the latest generated hydrocarbons from very limited, localized fetch area – conditions believed to be present in the lower Eagle Ford. API gravity from initial production, the only oil property reported for all wells, generally correlates with molecular maturity parameters but can be influenced by other processes. To compensate for these extraneous influences, trends of API gravity versus TVD were plotted for 0.2° longitudinal segments across the Eagle Ford play and used to model the relative amount of uplift and erosion needed to yield oil with the same API gravity and by inference the same maturity. Calculated MDB's from the API gravity oil-based model were found to agree well with those determined by the rock-based basin model and yielded more coherent depth trends with the measured maturity parameters. Both the rock-based and oil-based models find that the amount of Neogene uplift and overburden removal to be no more than ∼500 ft in the area near the San Marcos Arch and increases to the west, reaching ∼6500 ft in Maverick County. This finding strongly supports, if not proves, Cander's (2013) model for petroleum retention/production in the Eagle Ford shales and that the produced petroleum is a near-instantaneous, rather than a cumulative charge, of the latest generated hydrocarbons. This implies that unconventional continuous source petroleum systems are suitable for oil-based calibration of basin models. In many ways, the Eagle Ford petroleum system is ideal in its simplicity for the application of type of calibration.