Movement of generated hydrocarbons from a thermally maturing source rock along carrier beds to more porous and permeable reservoir facies been observed for decades. More recently, the nature of fluid movement within and external to source-rock reservoirs has been investigated by us and other colleagues through advances in organic geochemical laboratory and interpretation methods and the availability of rock, oil and gas samples from laterals drilled within the reservoirs (Curiale and Curtis, 2016). Stable carbon isotope and biomarker (chemical fossils) analyses of produced oils and bitumen extracts, and stable carbon isotope data from co-produced gases have been combined with source-rock TOC and pyrolysis data to better characterize these unconventional petroleum systems. Oil thermal maturity estimates were made based on biomarker compositions and/or alkyl aromatic ratios. The estimates are reported as %VRE (Vitrinite Reflectance Equivalent). These values from oils, which mirror the thermal maturity of source organic matter at time of expulsion (primary migration), were compared with %VRE values calculated from C1–C3 carbon isotope values of the gases and from source-rock pyrolysis Tmax and/or HI values. Hydrocarbons containing more mature biomarkers than the host source-rock reservoir facies have been interpreted in the context of the petroleum systems present in multiple study areas. Four examples of fluid movement within and into more "pure" source-rock reservoirs and within hybrid source-rock reservoir systems are illustrated in this study:

  1. The calculated maturities of laterally co-produced oils and gases (0.8–1.3% VRE) from the organic-rich Late Devonian Woodford Formation of the Anadarko Basin, OK generally concur with a few exceptions. Both anomalous positive methane carbon isotopes and high diamondoid concentrations were detected in some lower maturity black oils, suggesting the addition of high maturity fluids migrating from more mature sources.

  2. Migration of oils and gases is evident from co-produced organically-lean Middle Bakken & Three Forks reservoirs in northern Divide Co., ND that are generated from more mature, down-dip Upper & Lower Late Devonian Bakken black shales to the south (~10–20 miles). Comparison of maturities of the corresponding source rock, oil & gas are: gas > oil > local source rock. Oils, gases, and source rocks are ~equivalent in maturity in McKenzie Co. to the south near the most mature Williston Basin depocenter.

  3. Surprisingly, charging of Late Cretaceous Niobrara chalk and Codell sandstone reservoirs in the Denver Basin in Weld Co., CO by organic-rich facies of the overlying Sharon Springs Formation of the Pierre Shale (down-dip) appears to have occurred in some areas rather than charging from inter-bedded Niobrara organic-rich marls.

  4. Permian Wolfcamp shales and Spraberry reservoirs in the Midland Basin of Texas contain migrated oils with more mature biomarkers hosted within immature sediments.

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