AbstractThe geometry of the depositional facies and the sandbody continuity in turbidite and fluvial reservoirs controls the stratigraphic heterogeneity, and therefore controls permeability structure. This has implications for CO2 injectivity from localized pressure build up around injection wells, and migration pathways due to dispersive flow, which results in CO2 contacting more of the rock volume than would be the case in a homogenous system.This reservoir simulation study is an investigation of the impact of geological heterogeneity in channelized sandstone formations on pressure buildup during CO2 injection. Four geological models of fluvial and turbidite depositional systems were constructed, typical of those which occur in the Southern North Sea and the Central North Sea regions. Model grid cells were reduced to less than 10 m in places to properly represent the individual channel structures and 2 m near wellbores. This presented a challenge for simulation to capture the impact of injectivity accurately with high resolution for a basin-scale model. Sensitivity studies were carried out in two groups with different net to gross (NTG) ratios and mean permeabilities.The simulation results showed that connectivity to sand-body volumes, through the individual fluvial channel interconnections, may be poor, and so CO2 does not readily access the entire volume. Furthermore, if the mean permeability is less than 10 mD, only NTG, or the volume fraction of high permeability channels, affects the injectivity; the facies type, i.e. fluvial or turbidite, does not affect strongly the minimum injectivity for all models with 80% sand.