--> --> Deciphering Oil Mixing from Jurassic, Triassic and Paleozoic Source Rocks in the Hammerfest Basin, SW Barents Sea

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Deciphering Oil Mixing from Jurassic, Triassic and Paleozoic Source Rocks in the Hammerfest Basin, SW Barents Sea

Abstract

The Hammerfest Basin (HB) is a relevant area for oil and gas exploration in the southwestern Norwegian Barents Sea. It is characterized by hydrocarbon mixtures due to the occurrence of several source rocks of differing ages and a complex history of petroleum generation, migration and trapping. The main source rock is the Upper Jurassic Hekkingen Formation, but some intervals in the Middle-Lower Jurassic, Triassic and upper Paleozoic also have petroleum generation potential. This study focuses on a detailed assessment of thermal maturity and mixtures of hydrocarbons from the HB, based on biomarkers, PAHs, light hydrocarbons and compound-specific stable carbon (δ13C) and hydrogen (δD) isotopic compositions. The δ13C of n-alkanes for hydrocarbons with small thermal maturity variations, suggest mixtures of two or more end-member oils derived from different source rocks in the HB. Oils from Middle Triassic and Middle Jurassic reservoirs in the Goliat and Snøhvit fields, respectively, show the lightest δ13C values of branched- and short-chain (≤C14) n-alkanes and the lightest δD values of n-alkanes, whereas condensates from the Askeladd and Alke fields show heavier δ13C and δD in the same target compounds, suggesting inputs mainly from Triassic and Jurassic source rocks. Mixing is also supported by biomarkers, which indicate hydrocarbons derived from predominantly type-II and type-III kerogen-rich source rocks. The Goliat and Snøhvit oils also have a greater content of higher-plant biomarkers. Moreover, long-chain n-alkanes (≥C15) are 13C-depleted (δ13C= −30 to −34‰), suggesting contribution from a source as old as late Paleozoic. Paleozoic-derived oils from carbonate source rocks were evidenced in the Snøhvit field, not only by a slight even over odd predominance of n-alkanes (C20-C25) but also by lower concentrations of tricyclic terpanes above C26 as compared with their C21-C25 homologs and the highest DBT/Phen ratio. Most HB hydrocarbons represent mixtures with small maturity variations, generally at the main oil generation stage. However, some samples from the Goliat field showed a relatively larger variation in several maturity parameters, interpreted as mixtures of hydrocarbons formed from multiple stages of generation. Several diamondoid hydrocarbon indexes, DMAI-1, TMAI-1 and EAI, cover a maturity range from 1.9 to 2.8% Ro, implying an influx of wet and dry gas to the HB petroleum system.