Geological CO₂ sequestration in shallow and deep aquifers is governed by coupled thermo-hydro-mechanical-chemical (THMC) processes that control injectivity, plume migration, and the effectiveness of trapping and containment. This contribution summarizes recent advances in cyclic gas (CO₂) injection in low-permeability hydrocarbon reservoirs to extract transferable lessons for aquifer CO₂ storage. CO₂ injection/soaking experiments on intact and fractured mudrocks and siltstones under high-pressure (≈14 MPa) and high-temperature (≈70 °C) conditions were conducted across multiple cycles, paired with core-scale simulations. These experimental and modeling data documented fracture conductivity and compressibility hysteresis as well as phase-dependent (gas vs. liquid) fracture conductivity and relative permeability between multiple cycles.

Two findings were directly relevant to groundwater–CO₂ systems. First, matrix–fracture conductivity contrast was strongly phase-sensitive: gas-phase fracture conductivity was significantly, by up to an order of magnitude, larger than liquid-phase fracture conductivity, implying faster CO₂ pressure diffusion and preferential fracture migration during injection. Second, fracture compressibility and stress path induced dynamic aperture changes that manifested as fracture conductivity and compressibility hysteresis, possibly altering injectivity and the stability of residual CO₂ trapping through the injection/pressure-falloff sequence. Compositional data analysis across multiple cycles revealed pressure- and temperature-dependent hydrocarbon partitioning that analogously governs CO₂–brine–rock interactions in aquifers (e.g., dissolution and wettability shifts). Microscale imaging (scanning electron microscopy coupled with elemental analysis) indicated chemo-mechanical effects on wettability that, in turn, control flow pathways and effective relative permeability.

Translating these results to aquifer storage, a customized THMC modeling framework is proposed that (1) treats fracture transmissivity as stress- and phase-dependent and (2) includes hysteresis in fracture transmissivity and relative permeability for injection and pressure-falloff sequences. Insights from the core-scale CO₂ injection experiments and modeling suggest practical designs for pulse scheduling, pressure ramping, and fracture-sensitive monitoring, to optimize the injectivity–containment trade-off while enhancing residual, solubility, and (where relevant) mineral trapping.

By bridging cyclic CO₂ injection with groundwater storage physics, this contribution demonstrates how core-scale experimental and modeling data can calibrate predictive THMC models for CO₂ sequestration in aquifers, ultimately supporting safer, and more efficient carbon storage strategies.

References

Ghanizadeh et al. 2021. Experimental and computational evaluation of cyclic solvent injection in fractured tight hydrocarbon reservoirs. Nature Scientific Reports, 11 (1), 9497.

Ghanizadeh et al. 2023. Evaluation of Produced Hydrocarbons Composition During Cyclic CO₂ Injection (Huff-N-Puff) in Artificially-Fractured Shale Core Sample. SPE Canadian Energy Technology Conference and Exhibition, Calgary, Alberta, Canada, March 2023. Paper Number: SPE-212720-MS.

Ghanizadeh et al. 2025. Natural Fracture Compressibility and Permeability Hysteresis: Liquid vs. Gas. SPE Canadian Energy Technology Conference and Exhibition, Calgary, Alberta, Canada, March 2025. Paper Number: SPE-223996-MS.