The objective of this work was to develop and apply integrated geological and experimental workflows to enable a holistic evaluation of the reservoir quality and potential producibility of a prospective shale oil play - the Toolebuc Formation (Eromanga Basin), Australia. Tight oil reservoirs are notoriously difficult to characterize; routine analytical and experimental methods developed for tight reservoir characterisation are prone to providing contradicting observations depending on the complexity of the reservoir. This paper explores the data collection methods and results from a calcareous, organic-rich shale and demonstrates the benefits of combing multiple analytical techniques in the early stages of resource appraisal.

The Toolebuc Formation is within a late early oil to early peak oil window at the key well sites which, provide access to the most thermogenically mature material recovered for testing in the play to date. Routine shale core analysis data indicate significant gas-filled porosity, which is inconsistent with the anticipated fluid profiles for the optically determined thermal maturity window. Isotopic data collected on mud gas during drilling indicate biogenic signatures within the light-end hydrocarbon fractions; however, this isotopic signature was not present in the headspace gas of low-temperature hydrous pyrolysis (LTHP) experiments. These observations raise questions regarding the maturation pathway and associated fluid evolution for this source rock reservoir and whether apparent in-situ fluid volatility may enhance the exploitation of this resource in lower thermal maturity windows. This research work provides unique opportunities to advance the fundamental understanding of hydrocarbon generation and production in calcareous organic‐rich shales from a prospective Australian Basin, with potential implications for other similar organic‐rich shale plays globally.

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