Uncertainty in static CO 2 storage capacity estimates: Case study from the North Sea, UK

We used a sub‐salt Rotliegend Group sandstone saline aquifer in the North Sea as a case study site for Monte‐Carlo‐based CO 2 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 CO 2 storage. Such data scarcity leads to uncertainty regarding the complex trap geometries and ultimate CO 2 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‐km-super-2 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 >10-super-4 to >10-super-9 tonnes CO 2 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.