This project documents a large dataset of 172 produced oils and 59 core plugs from the across thirteen counties of the STACK and SCOOP petroleum systems with respect to their maturity, composition, distribution, source rocks, and producibility. Studied intervals include the Woodford Shale, the Mississippian Group, and the Springer Group of the Anadarko Basin, Oklahoma.

A principal component analysis (PCA) thermal maturity model was developed from sixteen maturity parameter inputs. The methylphenanthrene index was the best measure of thermal maturity across all plays and showed a strong covariance with depth with calculated vitrinite reflectance equivalent (Rc%) ranged from 0.74-1.43%. With increasing Rc%, the absolute concentration of biomarkers in the oils samples were observed to decline exponentially, and the rate of exponential decline was related to the biomarker complexity and stability.

Geochemical variations in produced oils were found to correspond to four organic facies which were mapped across STACK and SCOOP. Oils produced from Woodford and Mississippian Group reservoirs were generated from three organic facies across the large-scale Woodford depositional system ranging from sediment starved restricted marine in the Northwest Extension of STACK (STACK West), shallow open marine in the core of STACK (STACK East), and clay-rich open marine in SCOOP. In contrast, SCOOP oils produced from Springer Group reservoirs were generated from a single organic facies deposited in a clay-rich open marine depositional environment, probably the Caney or Goddard shales.

Three additional novel findings were made regarding the secondary subsurface mechanics and processes. First, a narrow zone of deep, volatile oil production in STACK West associated with H2S production contained high concentrations of thiophenic sulfur characteristic of thermochemical sulfate reduction (TSR) reactions. The same oils also contain high concentrations of methyldiamantanes only observed in high maturity condensates suggesting that deep TSR-affected fluids have migrated updip and mixed with lower maturity oils. Second, two separate trends were identified between Rc% and initial producing gas-oil ratios (IP GOR) for overpressured and normally pressured wells. Normally pressured wells exhibited IP GOR upwards of an order of magnitude higher than overpressured wells at any given Rc%, possibly due to mixing with methane sourced from deeper in the basin. Third, residual oil extracted from the Meramec and Osage core within the overpressured portion of the basin show that the oil is heterogeneous and not well-mixed within a vertical profile. The maturity of the fluid was found to be inversely proportional to the amount of extractable organic matter (EOM) per gram of rock, believed to be an approximation for porosity in an oil saturated reservoir. This new and exciting finding may provide a quick an effective way to predict reservoir quality and gain new insight into its charge history.