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Effect of sediment source on source rock hydrocarbon potential; An example from the Kimmeridgian and Tithonian-aged source rocks of the central ridge, off-shore Newfoundland, Canada

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  • John B. Gordon, Husky Energy, University of Calgary
  • ,
  • Hamed Sanei
  • Omid H. Ardakani, University of Calgary, Natural Resources Canada
  • ,
  • Per K. Pedersen, University of Calgary

This study presents an integrated approach using organic geochemistry and incident-light organic petrographic microscopy techniques to characterize kerogen type, hydrocarbon potential, thermal maturity, and the effect depositional environment has on five wells from Upper-Jurassic Kimmeridgian and Tithonian-aged source rock intervals in the Central Ridge area offshore Newfoundland, Canada. The results show that hydrocarbon potential in these organic-rich marine mudrocks is mainly dependent on depositional environment and present-day burial depth of the sediments. Oscillations and transitions between (i) rocks with dominant allochthonous organic matter (OM) (including primary/reworked vitrinite and inertinite macerals) representing high influence by continental sediments (e.g., deltaic and littoral depositional environment) and (ii) rocks with dominant autochthonous OM (fluorescing liptinites such as alginite and their degraded remains) indicating more distal, productive marine continental shelf depositional environment. The latter is of main interest to this study as it is the only rock type that has the capability to generate oil while the former has very little contribution to oil generation potential due to the abundance of hydrogen-poor organic matter. The secondary maceral, solid bitumen, occurs within the mature section in the deeper part of the basin. Measured %VRo on vitrinite macerals ranges from 0.62 to 0.82% on four of the five wells studied indicating early oil window to oil window thermal maturity due to the mixing of the organic matter types mentioned above. Integrating Fluorescent Red/Green (R/G) quotient measurements from high intensity fluorescing alginite range from 0.77 to 0.86. Conversion of these values to %VRo equivalent range 0.58–0.66% indicates that thermal maturity has not yet reached the primary oil generation window. Vitrinite reflectance equivalent derived from solid bitumen (%BRo) in the deepest buried well ranges 1.10–1.16% indicating wet gas thermal maturity.

Original languageEnglish
Article number104965
JournalMarine and Petroleum Geology
Volume127
Number of pages18
ISSN0264-8172
DOIs
Publication statusPublished - May 2021

    Research areas

  • Central ridge offshore newfoundland, Organic geochemistry, Organic petrology, Red green quotient, Thermal maturity

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