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Abstract Dissolution trapping is one of the most dominant mechanisms for CO2 storage in subsurface porous media saturated with brine. The CO2 dissolution rate and overall fluid flow dynamics in subsurface formations can vary significantly based on permeability variation. Although some numerical simulations have focused on these factors, detailed flow behavior analysis under nonuniform permeability distribution needs further study. For this purpose, we conduct simulations on the flow behavior of CO2-dissolved brine in two different heterogeneous media. The spatial permeability variations in the cell enable the analysis of complex subsurface storage phenomena, such as changes in finger morphology and preferential dissolution path. Finally, the amount of CO2 dissolved was compared between each case, based on which we draw informed conclusions about CO2 storage sites. The results demonstrated a preferential movement of CO2-dissolved regions toward high permeability regions, whereas a poor sweep efficiency was observed due to minimum dissolution in areas with lower permeability. Furthermore, simulation results also reveal uneven CO2 concentration inside the convective fingers. This study provides fundamental insight into the change in flow behavior at heterogeneous regions, which could be translated into saline aquifer conditions. The proposed workflow in this study could be extended further to analyze complex heterogeneous storage systems at different flow regimes. 

Abstract Large-scale geo-sequestration of anthropogenic carbon dioxide (CO2) is one of the most promising methods to mitigate the effects of climate change without significant stress on the current energy infrastructure. However, the successful implementation of CO2 sequestration projects in suitable geological formations, such as deep saline aquifers and depleted hydrocarbon reservoirs, is contingent upon the optimal selection of decision parameters constrained by several key uncertainty parameters. This study performs an in-depth parametric analysis of different CO2 injection scenarios (water-alternating gas, continuous, intermittent) for aquifers with varying petrophysical properties. The petrophysical properties evaluated in this study include aquifer permeability, porosity, relative permeability, critical gas saturation, and others. Based on the extensive data collected from the literature, we generated a large set of simulated data for different operating conditions and geological settings, which is used to formulate a proxy model using different machine learning methods. The injection is run for 25 years with 275 years of post-injection monitoring. The results demonstrated the effectiveness of the machine learning models in predicting the CO2 trapping mechanism with a negligible prediction error while ensuring a low computational time. Each model demonstrated acceptable accuracy (R2 >0.93), with the XGBoost model showing the best accuracy with an R2 value of 0.999, 0.995, and 0.985 for predicting the dissolved, trapped, and mobile phase CO2. Finally, a feature importance analysis is conducted to understand the effect of different petrophysical properties on CO2 trapping mechanisms. The WAG process exhibited a higher CO2 dissolution than the continuous or intermittent CO2 injection process. The porosity and permeability are the most influential features for predicting the fate of the injected CO2. The results from this study show that the data-driven proxy models can be used as a computationally efficient alternative to optimize CO2 sequestration operations in deep saline aquifers effectively.