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We used a sub-salt Rotliegend Group sandstone saline aquifer in the North Sea as a case study site for Monte-Carlo-based CO2 geostorage capacity assessment. In the area of interest, this unit is characterized by sparse, low resolution, subsurface data typical of the margins of global petroleum provinces, favored for CO2 storage. Such data scarcity leads to uncertainty regarding the complex trap geometries and ultimate CO2 storage capacity. The Rotliegend reservoir, estimated to have porosity and permeability ranges of 11-27% and 0.2 mD-125 mD, respectively, is sealed by Zechstein salt. The salt, predominantly halite, is a proven hydrocarbon seal in the central and southern North Sea hosting oil and gas columns of >140 m (>450 ft) and >150 m (>500 ft). Utilizing 2D-seismic data, boreholes and analogues, we estimate the pore volume of a 5-km2 4-way dip-closed structure through Monte-Carlo-based capacity simulations. We estimated storage capacity using published methodologies and compared this against a theoretical total storage calculation analogous to the gas in place equation used in the petroleum industry. We found that different methods yield a capacity range of <104 to >109 tonnes CO2 where sensitivity analysis indicates variability in reservoir properties to be the dominant control. Thus static estimates based upon Monte-Carlo calculations present no advantage over theoretical pore volume estimations. This leaves 3D dynamic modeling of storage capacity populated by 3D seismic data and direct down-hole measurement of reservoir properties to improve confidence in capacity estimations as the recommended method. [ABSTRACT FROM AUTHOR]

North Sea oil is overwhelmingly generated in shales of the Upper Jurassic – basal Cretaceous Kimmeridge Clay Formation. Once generated, the oil is expelled and ultimately migrates to accumulate in sandstone or carbonate reservoirs. The source rock shales, however, still contain the portion of the oil that was not expelled. As a consequence such shales and juxtaposed non-source lithofacies can form the targets for the exploration of ‘unconventional oil’. In this paper, we examine part of the Kimmeridge Clay Formation as a hybrid shale resource system within which ‘Hot Shale’ and organic-lean sandstone and siltstone intervals are intimately interbedded. This hybrid system can contain a greater volume of oil because of the increased storage capacity due to larger matrix porosities of the sand-silt interbeds, together with a lower adsorptive affinity in the interbedded sandstone. The relationship between the estimated volume percentages of sand and mudstone and free oil determined from Rock-Eval ® S1 yields is used to place limits on the drainage of oil from source mudstone to reservoir sand at the decimeter scale. These data are used to determine oil saturations in interbedded sand-mudstone sequences at peak oil maturity. Higher values of free hydrocarbon (as evidenced by the S1 value in mudstone) suggest that more oil is being retained in the mudstone, while higher S1 values in the interbedded sands suggest the oil is being drained to saturate the larger pore spaces. High silica content in the interbeds confirms the brittleness in this mudstone–sandstone lithofacies – an important factor to be considered for fracture stimulation to successfully work in a hybrid system. The key points of this hybrid unconventional system are the thickness, storage capacity and the possibility to capture a portion of the expelled, as well as retained oil. [ABSTRACT FROM AUTHOR]