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Thirty-three oil/condensate samples, representing most of the known petroleum accumulations in the Haltenbanken region, were analysed by a comprehensive geochemical scheme to determine possible genetic relationships. The organic geochemistry of the samples is comparatively invariate if one excludes the characteristics attributed to maturity differences and phase-induced fractionation. On this basis, in a gross sense, the C 10+ fractions of most of the petroleum samples are suggested to be derived from the Spekk Formation. However, the ratio of pristane to phytane and the stable carbon isotope composition of the petroleums proved useful to differentiate this picture. The database was subjectively divided into three main genetic groups which show dependence on the geographical location of the fields. Group 1, comprising the samples from Njord, Smørbukk Sør well 6506/12-5, Tyrihans N, Tyrihans S, Trestakk and the 6506/12-3 DST 6 sample above the Smørbukk Sør main reservoir, is clearly differentiated from Group 2, comprising samples from Midgard, 6407/2-2 DST 1 and from Alve 6507/3-1 DST 3. Group 3, comprising samples from Draugen, Heidrun, Mikkel plus the Smørbukk Sør petroleum 6506/12-3 DST 1, forms an intermediate population between Groups 1 and 2. In general, Group 2 is confined to the easterly, more proximal part of the basin, while Group 1 fields have drainage areas in distal, more deeply buried regions of the basin. Available data on the geochemistry of the two major source rocks in the region, the Spekk Formation and the deeper Åre Formation, lead us to conclude that the C 15+ fractions of the Group 1 petroleums are derived predominantly from a distal marine anoxic facies of the Spekk Formation. Group 2 forms the other end member, supposedly sou rced mainly from more terrestrially influenced proximal marine (partly dysaerobic?) isotopically heavier shales of the Spekk Formation. Group 3 contains characteristics of both source-rock facies. We see no evidence in biomarker distributions of the current database for significant contributions to the heavy ends of the reservoired petroleums from Åre coals. However, we cannot, based on our limited source-rock database, exclude contributions in some localities from Åre Formation shales. Furthermore, we have no evidence to exclude contributions to the light hydrocarbon range from the Åre Formation, e.g. condensate/gas contributions. We feel that the Spekk Formation varies significantly in geochemistry, both laterally and vertically, i.e. according to Walters law, and that this formation is less homogeneous with respect to geochemistry and the depositional and early diagenetic environment than commonly described. The metal composition of the petroleums generally substantiates these interp retations on laterally varying dysaerobic/anoxic conditions of the Spekk Formation, even if it proved difficult in cases to compare metal distributions in petroleums with drastically different gas/oil ratios. Because most fields, despite overall similarities, contain petroleum with specific singular minor characteristics, we suggest that, with the exception of the Draugen and Midgard Fields, lateral migration has been predominantly short- to medium-range with respect to intra-field distances. A core extract from well 6609/11-1 (Helgeland basin) deserves special attention, as our data suggest that this core at 2561 m contains a zone of terrestrially derived oil, possibly lacushine, most likely sourced from a Triassic or Palaeozoic formation.

Thermogenic dry gas flowed from Jurassic sections in the DH5R research well drilled onshore in Adventdalen, central Spitsbergen, Arctic Norway. The DH5R gas originates from the organic-rich units of the mudstone-dominated Middle Jurassic to Lower Cretaceous Agardhfjellet Formation, which is the onshore equivalent to the Fuglen Formation and the prolific oil and gas generating Hekkingen Formation in the southern Barents Shelf. Low-permeable, low-porosity sandstones from the Upper Triassic De Geerdalen Formation of the neighbouring DH4 well were oil-stained and gas was also collected from this interval. Gas from the two stratigraphic intervals have different compositions; the gas from the Agardhfjellet Formation is drier and isotopically heavier than the gas from the Upper Triassic succession. Both gases originated from source rocks of maturity near the end of the oil window (1.1 < Ro < 1.4% Ro). Maceral analyses of the Agardhfjellet Formation indicate that the more silty parts contain a high percentage of vitrinite-rich type III kerogen, whereas the clay-dominated parts are rich in liptinitic type II kerogen. The Agardhfjellet Formation has therefore the potential to generate both oil and gas. Several simulations based on pressure data and flow rates from the DH5R well were run to evaluate if the gas accumulation in the Agardhfjellet Formation is producible, i.e., can it be commercial shale gas. The models demonstrate how changes in the drainage area size and form, well types (vertical versus horizontal), number and length of induced fractures and thickness of the Agardhfjellet Formation affect gas production rates and producible volumes. Despite uncertainties in the input data, simulations indicate that the shale gas accumulation characterised in Adventdalen is producible. This gas can have major environmental benefits as an alternative for local power generation compared to coal.

A new petroleum charge model is presented for the sand-dominated Paleocene channel system known as the Siri Fairway in the Central Graben of the North Sea. The Siri Fairway is located in the platform area along the Danish -Norwegian border and extends from the Norwegian palaeo shelf into the Tail-End Graben and Søgne Basin. The nearest known expelling source rocks are located in the Central Graben. The discovery of the Siri oilfield and later the Cecilie and the Nini fields proves that petroleum has migrated through these Paleocene sandstones for up to 70 km, which is a considerable distance in the North Sea. If the Siri Fairway has acted as a "pipeline" for petroleum migrating from the Graben to the platform area, the chemical composition of the hydrocarbons discovered in the Graben and within the Fairway itself should be similar in terms of maturity and organic facies signature. This study shows this not to be the case. The Graben oils have a mature signature, whereas the oils from the Siri field have an early mature signature and are mixed with biogenic gas generated in situ. The biogenic gas "signature", which was inherited from gas which accumulated in the trap before the arrival of the oil charge, should have disappeared if petroleum had continuously been introduced to the Fairway. It therefore appears that hydrocarbon charging to the Fairway ceased for some reason before the source rocks in the Graben entered the main oil window; the Siri Fairway therefore represents an aborted migration route, and limited charging of the Paleocene sandstone deposits in the platform has occurred.The chemical composition of the oils from the Siri field indicates that the Fairway was charged from two different basins with different subsidence histories. The Siri-2 trap is thus interpreted to have been filled with the same oil as that found in Siri-1 and Siri-3, but this oil was later partly displaced by oil generated in a shallower sub-basin.The sandstones in the Siri Fairway were deposited as turbidites and/or gravity slides in the Late Paleocene, and consist of stacked interfingering sandstone lobes which are encased to varying degrees in fine-grained sediments. Although long distance migration through the sandstones has been proved to occur, connectivity between individual sandlobes may be problematic. The number of dry wells drilled in the Fairway and the early-mature character of the analysed oils, together with the general absence of more mature later petroleum, indicate that migration routes in this region are limited and difficult to predict.

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