The Enhancement and Optimization of CO₂ Sequestration in Saline Aquifers

Abstract

Geological storage of carbon dioxide in saline aquifers is widely recognized as a key strategy for achieving long-term emission reduction. Its effectiveness depends on the accurate estimation of storage capacity and the ability to enhance and optimize that capacity through engineering design. Yet these objectives remain challenging due to geological heterogeneity, limited subsurface data, and the need to manage reservoir pressure within safe operational limits. Reliable evaluation therefore requires methods that integrate geological characterization with pressure behavior and injectivity constraints while also identifying strategies that expand storage potential without compromising formation integrity. This thesis develops an integrated framework for evaluating, enhancing, and optimizing CO₂ storage in saline aquifers through a combination of conceptual, analytical, and numerical methods. The research begins by developing a systematic approach for generating credible CO₂ storage estimates that progress from regional-scale capacity to scenario-specific storage potential under any level of data availability. Existing estimation techniques are organized into a six-tier framework that connects static, analytical, and numerical methods within a single adaptive workflow. Designed as a practical decision-support tool, the framework guides users in selecting appropriate methods, inputs, and model complexity based on available geological and operational data. This structure enables early-stage screening and iterative refinement as more detailed geological and operational information becomes available. Application to the Nisku Formation in Alberta (Canada) validated the methodology and confirmed that pressure-constrained, uncertainty-aware estimates can be obtained from limited data and progressively refined toward realistic operational outcomes. Building on this foundation, an analytical optimization model was developed to extend analytical methods to coupled injection and brine production, allowing direct technical and economic assessment of storage enhancement through pressure relief. The model incorporates transient pressure behavior and economic parameters to evaluate how well spacing, the number of wells, the production-to-injection ratio, and carbon revenue together influence storage capacity and project net revenue. Since the interaction among these parameters is complex, the model serves as a rapid diagnostic tool for understanding their combined effects and for testing different design configurations under varying geological and economic conditions. Validation against numerical simulations for both multi-well injection and brine-production scenarios confirmed that the model provides a fast and reliable means of screening and comparing sequestration project designs. The thesis next evaluates horizontal injection as another means of enhancing CO₂ storage efficiency in saline aquifers. Numerical simulations were performed to examine how horizontal wells influence pressure distribution, plume evolution, and overall injectivity across different geological and design conditions. Results show that longer horizontal wells improve lateral CO₂ distribution, reduce near-wellbore pressure buildup, and delay plume contact with the caprock, thereby increasing effective storage capacity. However, the gains in capacity and pressure control diminish beyond a certain lateral length, indicating an economic threshold for well extension. Simulation results also indicate that formation permeability, anisotropy, and thickness strongly influence the magnitude of achievable improvement over vertical wells, with the most significant gains occurring in low-permeability and thin aquifers These findings provide practical guidance for optimizing well design to achieve efficient and stable storage performance. Finally, the tools and insights developed in this research were applied to the Cambrian Formation in Southwestern Ontario (Canada), a regionally extensive but data-scarce potential storage target near major emission sources. The framework structured the workflow for estimating capacity under data limitations, while the optimization and enhancement studies informed the treatment of injectivity and pressure constraints. The analysis progresses from formation-scale capacity estimation to single-well performance evaluation and the application of enhancement strategies, providing a clear understanding of both inherent and improved storage potential. Results indicate an effective regional capacity of about 0.6–1.1 Gt of CO₂, limited by pressure tolerance and a single-well storage potential below 0.5 Mt per year. Incorporating optimized horizontal wells and controlled brine production shows that these strategies can be highly effective in this region, where single-well performance remains below established industrial benchmarks. Together, these contributions provide an integrated pathway for the evaluation, enhancement, and optimization of CO₂ storage in saline aquifers. The research bridges theoretical estimation and practical implementation, offering defensible capacity ranges, efficient design-screening tools, and clear strategies for managing pressure and injectivity in support of secure, large-scale geological storage deployment.