T. B. Abay1*, D. A. Karlsen1, B. Lerch1, S. Olaussen2, J. H. Pedersen3 and K. Backer-Owe1

1 Department of Geosciences, University of Oslo, P.O. Box 1047 Blindern, 0316 Oslo, Norway.

2 Department of Arctic Geology, University Centre in Svalbard, P.O. Box 156, 9171, Longyearbyen, Norway.

3 Lundin Norway As, Lysaker, Norway

* Author for correspondence, t.b.abay@geo.uio.no

Key words: Arctic, Svalbard Archipelago, organic geochemistry, migrated oils, petroleum groups, depositional environment, maturity, hydrocarbon inclusion, thermogenic gas.

The presence of migrated petroleum in outcropping rocks on Spitsbergen (Svalbard archipelago) has been known for several decades but the petroleum has not been evaluated by modern geochemical methods. This paper presents detailed organic geochemical observations on bitumen in outcrop samples from central and eastern Spitsbergen. The samples comprise sandstones from the Lower Cretaceous Carolinefjellet Formation, the Upper Triassic – Middle Jurassic Wilhelmøya Subgroup and the Upper Triassic De Geerdalen Formation; a limestone from the De Geerdalen Formation; and carbonates from the Middle Jurassic – Lower Cretaceous Agardhfjellet Formation. In addition a palaeo-seepage oil was sampled from a vug in the Middle Triassic Botneheia Formation. This data is integrated with the results of analyses of C1–C4 hydrocarbon fluid inclusions trapped in quartz and calcite cements in these samples.

Organic geochemical data suggest that the petroleum present in the samples analysed can be divided into two compositional groups (Group I and Group II). Group I petroleums have distinctive biomarker characteristics including Pr/Ph ratios of about 1.3–1.5, high tricyclic terpanes relative to pentacyclic terpanes, and relatively high methyl-dibenzothiophenes compared to methyl-phenanthrenes. By contrast Group II petroleums have low tricyclic terpanes relative to pentacyclic terpanes and low methyl-dibenzothiophenes compared to methyl-phenanthrenes, and most Pr/Ph ratios range from 1.90 to 2.57. The petroleum in both groups was derived from marine shale source rocks deposited in proximal to open marine settings.

Group I petroleums, present in the sandstones of the Wilhelmøya Subgroup and the De Geerdalen Formation and as a palaeo-seepage oil in the vug in the Botneheia Formation, are likely to have been sourced from the Middle Triassic Botneheia Formation. Group II petroleums found in the sandstone of the Carolinefjellet Formation, the limestone from the De Geerdalen Formation and in carbonates of the Agardhfjellet Formation, are inferred to have been generated from the Jurassic-Cretaceous Agardhfjellet Formation.

The analysis of biomarker and aromatic hydrocarbons in the petroleums indicate three relative maturation levels, equivalent to expulsion at vitrinite reflectances of about 0.7–0.8%Rc, 0.8–0.9%Rc and 1.0–1.6%Rc. On average, Triassic host rocks contain petroleum of higher maturity compared to the Jurassic and Cretaceous host rocks.

The fluid inclusion data suggest that gaseous hydrocarbons from the sandstones of the Wilhelmøya Subgroup are thermogenic, and are of similar maturity to the petroleum in extracts from these sandstones, suggesting that the gas was generated together with oil in the oil window. By contrast the inclusion gases from carbonate rocks analysed have a mixed (thermogenic / biogenic) origin. The outcropping rocks in which these oils occur are analogous to offshore reservoirs on the Norwegian Continental Shelf. The study may therefore improve our understanding of the subsurface offshore petroleum systems in the Barents Sea and possibly also in other circum-Arctic basins.

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