Integration of Fluid and Rock Geochemical Parameters to Constrain Thermal Maturity Indicators in Paleozoic Organic-Rich Source Intervals

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Maturity estimates from Paleozoic petroleum systems that are derived from organofacies containing elevated hydrogen-rich kerogen (in excess of 700 mgHC/gTOC), total organic carbon (TOC) values above 7.0 percent, and complex burial histories may be difficult to adequately constrain. This is primarily due to reliance on source rock pyrolysis geochemical parameters (hydrogen index HI, TMAX, etc.) both measured and calculated vitrinite reflectance (%VRo) values, and thermally induced color changes in spores and conodonts. All of these methods can be compromised by high molecular weight (HMW) compounds being included in the convertible kerogen S2 pyrolysis peak, bitumen coatings retarding reflectance and color measurements, and misidentification of bitumen particles as vitrinite macerals. Integration of geochemical parameters, color and reflectance measurements, kinetic transformation of organic matter in burial history modeling, along with fluid/extract geochemical analyses provides a comprehensive framework in maturity assessments. Oils and extracts from the New Albany Shale, Illinois Basin were analyzed via detailed gas chromatography/mass spectrometry (GC-MS) for selected aromatic markers (naphthalenes, phenanthrenes and dibenzothiophenes) and biomarkers. These fluids were analyzed using the same standards, instrument, and preparation process so that a quantitative comparison of selected markers could be evaluated with increasing thermal maturity. In addition, extracts were analyzed from immature (< 0.4 %VRo eq) samples to ascertain the initial composition and relative concentration of the selected markers and biomarkers. This allows the tracking of relative concentration with an increase in thermal stress. There exists a significant correlation in concentration with increasing thermal stress in selected tetramethylnapthalenes, methylphenanthrenes, triaromatic steroids, and homohopane isomerization in extracts and oils from the New Albany Shale. This allows the development of a maturity framework which incorporates geochemical parameters, fluid maturity signatures and basin modeling. Maturity indicators and modeling suggest that in portions of the Illinois Basin, the New Albany Shale is presently within the volatile oil window. It is more thermally mature than generally recognized as a result of the integration of both fluid and rock maturity indicators.
Original languageEnglish (US)
Title of host publication2019 AAPG Annual Convention and Exhibition, San Antonio, Texas
StatePublished - 2019


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