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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...

This thesis has been submitted to the Department of Geoscience at the University of Oslo in accordance with requirements for dissertation for the degree of Philosophiae Doctor. The work that forms the basis for this Ph.D. thesis was conducted under the supervision of Prof. Dr. Dag Arild Karlsen and financed by NORECO ASA. Although first drillings were conducted during the early 1980ies, the Barents Sea is still considered a frontier area for petroleum exploration. Despite extensive research on the geologic evolution, sedimentology and stratigraphy, geochemical studies reporting on petroleum systems are scarce. It has been suggested relatively early in the exploration history that oils and condensates in the region could be regarded as being mixtures of more than one filling event. Variable results in the early part of the exploration phase are undoubtedly related to the complexities of the region. It is commonly accepted that several phases of uplift, erosion and glacial events during the Cenozoic had great impact on petroleum system elements, but also on already accumulated petroleum. Generation from miscellaneous source rocks, changes in pressure-volume-temperature conditions, secondary inreservoir alteration, large scale remigration and entrapment mechanisms, and leakage of petroleum are among the processes that impede petroleum system investigation. The purpose of this work was to provide systematic evaluations of the degree to which oils and condensates are "blends", or of singular source rock origin, and to evaluate potential variations in maturity signatures, biodegradation, migration induced phase-fractionation and source rock facies. Realizing that petroleum geochemical studies in the Barents Sea may be complicated due to extensive alteration and blends of oils in traps, an attempt was made to decipher the complex signatures: A full geochemical fingerprint of each sample in terms of thermal maturity, secondary alteration effects, age, paleo depositional environments and organic matter input had to be created. Therefore, systematic analysis of three hydrocarbon compound classes has been applied: (1) light hydrocarbon C 4-C 8 compounds, (2) medium range C 10-C 20 compounds, and (3) biomarker range C 20+ compounds. The results indicate petroleum generation from the early oil window to the late oil/ condensate window. Phase fractionated condensates and oils have been observed in the western part of the Hammerfest Basin. Petroleum mixtures have been identified by varying thermal maturities among the three different compound classes, and paleo biodegradation signatures in combination with fresh, unaltered charges. This indicates at least two migration events of highly variable maturity and/or even source rock facies signatures. Similar geochemical characteristics and use of multivariate statistical analysis led to classification of four petroleum families: (1) Family A: Permian/Triassic sourced, (2) Family B: Carboniferous sourced, (3) Family C: Jurassic sourced, and (4) Family D: Triassic and Jurassic sourced...

Rock-Eval and total organic carbon (TOC) analyses of 144 samples representing Triassic–Lower Cretaceous intervals from the SW Barents Sea (the Svalis Dome, the Nordkapp and Hammerfest basins, and the Bjarmeland Platform) and Svalbard demonstrate lateral variations in source rock properties. Good to excellent source rocks are present in the Lower–Middle Triassic Botneheia and Steinkobbe, and Upper Jurassic Hekkingen formations, 1 – 7 wt% and 6 – 19 wt% TOC, respectively. Hydrogen indices of 298 – 609 mg HC/g TOC in the Botneheia Formation from Svalbard, and 197 – 540 mg HC/g TOC in the Steinkobbe Formation of Svalis Dome suggest Type II (oil-prone) and Type II/III (oil/gas-prone) kerogens, respectively. The Kobbe Formation (Botneheia/Steinkobbe-equivalent) is organic-lean and generally gas-prone (Type III kerogen) on the Bjarmeland Platform and in the Nordkapp Basin, and is a good source rock with Type III/II kerogen in the Hammerfest Basin. In the investigated wells, the Hekkingen Formation is more oil-prone on the Bjarmeland Platform than in the Nordkapp Basin, while Lower Cretaceous samples have poor potential for oil. Upper Triassic samples show potential mainly for gas; however, coal/coaly-shale samples in well 7430/07-U-01 (Bjarmeland Platform) are oil/gas-prone. Most samples analysed are immature to early mature; thus, the variation in petroleum potential and kerogen type is a function of organic facies rather than maturity levels.

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