• Assesses CO 2 storage potential of the Cambrian Formation in Southwestern Ontario. • Guides pressure-limited CO 2 storage assessment in data-scarce geological settings. • Integrates formation-scale, single-well, and multi-well pressure-constrained analyses. • Examines the role of reservoir layering in defining practical storage performance. • Evaluates horizontal wells and brine production as viable enhancement strategies. The Cambrian Formation beneath Southwestern Ontario is a regionally extensive and geologically viable reservoir for CO 2 storage, yet its practical capacity remains highly uncertain due to severe limitations in reliable subsurface data. Despite its proximity to major industrial emission sources, the absence of detailed geological and pressure information has hindered the development of defensible storage estimates. This study establishes pressure-constrained estimates for formation-scale CO 2 storage capacity and defines a defensible single-well injection benchmark grounded in plausible regional property ranges and layered geological realizations, while evaluating how multi-well deployment and enhancement strategies can expand pressure-limited performance.A sequential workflow combining formation-scale volumetric assessment, analytical pressure-limited injection modeling, and dynamic numerical simulation is used to evaluate how storage potential contracts under realistic pressure integrity constraints. Results indicate that enforcing pressure limits reduces the formation’s effective CO 2 storage capacity to 0.62–1.15 Gt (central estimate ≈ 0.85 Gt). Across the full envelope of geological and operational properties considered, sustainable single-well injection rates span 0.06–1.65 Mt yr −1 , while layered realizations indicate that practical performance commonly remains below 0.5 Mt yr −1 , demonstrating that vertical heterogeneity is a first-order control on injectivity and placing Southwestern Ontario toward the lower end of reported industrial storage benchmarks. Enhancement analyses show that horizontal wells substantially expand the injectivity window, providing up to 233% improvement for a 3 km lateral, while controlled brine production further stabilizes pressure and sustains injection under constrained conditions. This study applies a stepwise estimation framework that links formation-scale capacity to pressure-limited single-well performance and then extends the benchmark to multi-well and enhanced injection scenarios. Uncertainty in reservoir properties and geomechanical pressure limits is explicitly propagated to define scale-consistent performance bounds and to clarify how targeted well design and pressure management can mitigate pressure-limited storage behavior in data-scarce settings, providing a practical basis for screening, benchmarking, and early-stage project design in Southwestern Ontario.
Firoozmand et al. (Sat,) studied this question.