Estimate CO2 storage capacity of the Johansen formation: numerical investigations beyond the benchmarking exercise |
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| Authors: | Lingli Wei Fredrik Saaf |
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| Institution: | 1. Shell International Exploration and Production BV, Kesslerpark 1, 2288 GS, Rijswijk (ZH), The Netherlands
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| Abstract: | In this paper, Shell’s in-house reservoir simulator MoReS is applied to a recently introduced CO2 sequestration benchmark problem entitled “Estimation of the CO2 Storage Capacity of a Geological Formation” (Class et al. 2008). The principal objective of this benchmark is the simulation of CO2 distribution within a modeling region, and leakage of CO2 outside of it, for a period of 50 years. This study goes beyond the benchmarking exercise to investigate additional factors
with direct relevance to CO2 storage capacity estimations: water and gas relative permeabilities, permeability anisotropy, presence of sub-seismic features
(conductive fractures, thin shale layers), regional hydrodynamic gradient, CO2-enriched brine convection (due to brine density differences), and injection rates. The effects of hydrodynamic gradients
and gravitationally induced convection only become significant over 100 s of years. This study has thus extended simulation
time to 1,000 years. It is shown that grid resolution significantly impacts results. Vertical-grid refinement results in larger
and thinner CO2 plumes. Lateral-grid refinement delays leakage out of the model domain and reduces injection pressure for a given injection
rate. Sub-seismic geological features such as fractures/faults and shale layers are demonstrated to have impact on CO2 sequestration. Fractures located up-dip from the injector may lead to more leakage while the opposite may happen in the presence
of fractures perpendicular to the dip. Thin shale layers produce stacked CO2 blankets. They should be explicitly represented instead of being upscaled using a reduced vertical to horizontal permeability
ratio. Results are seen to be far more sensitive to gas relative permeability and hysteresis than to variations in the water
relative permeability models used. For a multi-injectors project, there is scope to optimize the phasing of injections to
avoid potential fracturing near injectors. |
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