Multiple hydrocarbon charging events in Kuh-e-Mond oil field, Coastal Fars: Evidence from biomarkers in oil inclusions

Abstract

<jats:title>Abstract</jats:title><jats:p>Oil inclusions were retrieved from dolomite and calcite fracture fills in upper, middle and lower reservoir zones in <jats:styled-content style="fixed-case">K</jats:styled-content>uh‐e‐<jats:styled-content style="fixed-case">M</jats:styled-content>ond <jats:styled-content style="fixed-case">F</jats:styled-content>ield, <jats:styled-content style="fixed-case">Z</jats:styled-content>agros <jats:styled-content style="fixed-case">B</jats:styled-content>asin, <jats:styled-content style="fixed-case">I</jats:styled-content>ran. They are assumed to be persevered samples of primary oil; hence, their biomarkers were analysed to determine the maturity gradient and source facies of petroleum at the time of migration. A variety of specific parameters were obtained including n‐alkanes, hopanes, steranes from aromatic hydrocarbons in oil inclusions and reservoir hydrocarbons petroleum. The Pr/Ph ratio varies from 0.5 to 1, which is indicative of dominant reducing conditions during source rock deposition. The fluid inclusion oils with dibenzothiophene/phenanthrene ratios ranging from 0.68 to 1.4, Pr/Ph ratios from 0.8 to 1.2 and with C<jats:sub>34</jats:sub>/C<jats:sub>35</jats:sub> ratios of homohopanes in the range from 1.1 to 1.76, suggest regional variations of organic facies in their source rocks. Biomarker parameters obtained from fluid inclusion oils differ slightly from those of reservoired oil. The biomarker data indicate that the reservoir oil in the <jats:styled-content style="fixed-case">K</jats:styled-content>uh‐e‐<jats:styled-content style="fixed-case">M</jats:styled-content>ond <jats:styled-content style="fixed-case">F</jats:styled-content>ield was generated and expelled predominantly from carbonate–marly sources deposited in anoxic environments. A terrestrial material source seems plausible here, and the presence of C<jats:sub>29</jats:sub>/C<jats:sub>27</jats:sub> ααα 20R steranes supports this finding. The maturity levels of fluid inclusion oils inferred from C<jats:sub>12+</jats:sub> parameters are slightly higher in the dolomite and calcite cements from the upper reservoir zone, which may be due to continuous reservoir filling.</jats:p>