This study presents an integrated inorganic and organic geochemistry method to characterize Permian organic rich mudstones in the Midland Basin, to understand controls on organic carbon richness, such as primary productivity, depositional environments, sediment supply, and bottom water preservation conditions, and its implications on petroleum generation /charge and on shale oil development. A high frequency sampling of core samples from a thick sequence (~1000 ft) of argillaceous mudstones, organic-rich mudstones, siliceous mudstones, and carbonate mudstones in the Midland basin were characterized for elemental concentrations and source rock geochemistry, and for high resolution gas chromatography and biomarkers on extracts. The small maturity differences (~0.05 ﹪ VRo) from the top to the bottom of this 1000 ft section and limited migration of hydrocarbons into the rock pore space due to low permeability and high capillary entry pressure allows us to interpret the extract geochemistry fingerprints to compositions of the source rock kerogen and its in-situ generated bitumen. Geologic, petrophysical, and elemental analysis have divided the section into many depositional packages (chemozones) with distinct signatures. This has suggested cycles of para-sequences with varied sediment (clastic vs carbonate) supply and preservation conditions. Source rock characters respond to these depositional environmental variations with changes in total organic carbon contents and HI /OI values. Depositional environment dependent biomarker parameters (Pr /Ph, DBT /Phen, etc.) from core extracts also show systematic changes reflecting variations in bottom water oxygen conditions and source rock facies. This integrated approach greatly enhances our description of Permian age resource play petroleum systems, which in turn helps with sweetspot mapping and lateral landing zone definition.
Successful shale oil development relies on good understanding of geological properties as well as sound artificial fracturing and stimulation programs. Geologic factors include minerology and petrophysical properties which in turn determine unconventional reservoir porosity, permeability, brittleness, pressure, and fracability. Shale organic matter types, richness, and maturity will impact hydrocarbon types, fluid properties, phase behavior, and kerogen porosity generation. Together these geological parameters will affect hydrocarbon storage capacity, producibility, and drive mechanisms in unconventional systems.