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The Northern Viking Graben area in the Norwegian North Sea was studied in order to investigate the petroleum formation characteristics of the Upper Jurassic Draupne Formation. In this area, the organofacies of the Draupne Formation, and consequently its petroleum generation characteristics, show significant variations. These variations represent a major risk, particularly in the context of basin modelling studies. Therefore, tar-mat asphaltenes, oil asphaltenes and sourcerock samples from this area were studied in order to evaluate the use of migrated asphaltenes from petroleum reservoirs and tar mats in basin modelling. The samples were studied using bulk kinetic analysis, open-system pyrolysis -gas chromatography and elemental analyses, and the results were integrated into a basin modelling study. The results from these different sample materials were compared both to each other and to natural petroleum, in order to assess their significance for future petroleum exploration activities.We show that in cumulative petroleum systems, the transformation characteristics of the asphaltenes incorporate those of the individual source rock intervals which have contributed to the relevant reservoir system. Thus, the petroleum formation window predicted by the use of asphaltene kinetics is broad, and covers the majority of the formation windows predicted from the individual source rock samples. In addition, the molecular characteristics of asphaltene-derived hydrocarbons show that compositional characteristics, such as aromaticity, correspond more closely to natural oils than to the respective source-rock products.Our results confirm that the heterogeneous nature of the Draupne Formation results in a significantly broader petroleum formation window than is conventionally assumed. We propose that oil and tar-mat asphaltenes from related reservoirs represent macromolecules which account for this heterogeneity in the source rock, since they represent mixtures of charges from the different organofacies. One conclusion is that the use of oil and tar-mat asphaltenes in kinetic studies and compositional predictions may significantly improve definitions of petroleum formation characteristics in basin modelling.

Unconventional Liquid Rich Shale (LRS) and shale gas (SG) plays are self-charged continuous systems relying on their indigenous organic matter as the source of hydrocarbons. The residual pore space of fine-grained organic rich sediments themselves or similarly tight deposits in their close vicinity act as the reservoirs. Pressure (P) and temperature (T) can significantly increase during burial of the sediments and can likewise undergo a substantial instant P but time-deferred T decrease during erosion and uplift. These changes in P and T strongly influence the phase behaviour of the generated and trapped hydrocarbons (HC), thereby affecting the retention capacity of the source rock, the HC flow properties, potential migration routes, and the predicted HC volumes initially in place (GIIP/OIIP). Shell's integrated Cauldron Shale Gas Simulator calculates resource density on a regional to basin scale, typically during the opportunity identification and screening phase of a project. Informed decision-making in exploring for unconventional opportunities relies on the integration of all available (i.e., sometimes scarce) data and their associated uncertainties for basin scale physical elements and processes into a working geologic model.

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