Roman Y. Makhnenko

Permanent containment of injected CO2 remains central to the effectiveness and safety of geologic carbon storage. Yet, uncertainties in coupled hydromechanical and multiphase processes limit assessment of leakage through fractured caprocks. Here, we integrate laboratory measurements of two-phase and hydromechanical properties of fractured shales into field-scale simulations to improve evaluation of CO2 leakage potential. Regardless of the caprock sealing capacity, CO2 migration remains strongly localized along fractures, while its rate and extent are governed by non-local interactions with surrounding formations. Despite fracture breakthrough, CO2 discharge into the overlying aquifer is limited. The high-permeability aquifer promotes rapid pressure dissipation and CO2 dissolution, restricting formation of a secondary mobile plume. We conclude that reliable assessment of CO2 leakage likelihood and severity hinges on system-scale resolution of coupled hydromechanical processes. The developed framework will enable reliable integration of advances in experimental fracture characterization into site-specific modeling efforts and, where necessary, remediation design.

Accurate quantification of fluid saturation is essential for characterising hydrogen distribution during its underground storage. The unique properties of hydrogen – high compressibility, low molecular weight, and diffusivity – limit the direct transfer of experience from carbon dioxide or natural gas storage, motivating tailored laboratory investigations. This study applies a poroelastic framework that infers fluid saturation from the undrained hydro-mechanical response through the calculation of the Skempton’s B coefficient. This approach is grounded in direct measurements of the isothermal effective bulk modulus of water–hydrogen mixtures under different fluid pressures (9–15 MPa) and water:hydrogen ratios (0·9:0·1–0·1:0·9). Comparison with mixing laws shows that Reuss bound accurately captures the reduction in the effective fluid bulk modulus with increasing hydrogen fraction, whereas Voigt and Brie bounds produce significant deviations, particularly for water saturations below 0·8. Closed-form relations between the Skempton’s B coefficient and fluid saturation are evaluated for consistency with relative permeability data available for Berea sandstone, confirming that Reuss-based estimation agrees with the results obtained by way of the scanning methods. This research introduces a practical alternative where imaging techniques are limited by resolution and signal constraints, offering direct insights into hydrogen occupancy in pore space under in situ multiphase flow conditions.

This study examines the effect of CO ₂ treatment duration on the poroviscoelastic properties of sedimentary rock, including sandstone, limestone, and shale. A hydro‐mechanical‐chemical (HMC) coupling framework is employed to evaluate the time‐dependent response of fluid‐saturated rock subjected to CO ₂ exposure. Laboratory experiments are performed on pristine specimens and those treated for 1–3 weeks, using a modified hydrostatic compression system. Carbonate mineral dissolution plays a key role in altering poroviscoelastic properties, especially in limestone and calcite‐bearing shales, leading to an increase in their porosity and Skempton's B coefficient, and a decrease in their bulk and solid moduli, as well as bulk viscosity. These changes enhance the time‐dependent deformation and influence the porosity evolution. The HMC model, calibrated with the experimental data, predicts CO ₂ injection‐induced porosity changes by accounting for the competing processes of chemical dissolution and time‐dependent compaction. This study highlights the need to incorporate the coupled effects to accurately predict rock behavior during CO ₂ storage and to support realistic assessments of long‐term reservoir and caprock performance.

Geologic carbon storage is widely recognized as a critical strategy for mitigating atmospheric carbon dioxide (CO₂) levels, yet its effectiveness is contingent upon the integrity of caprock formations that prevent CO₂ leakage. This study investigates the sealing potential of three representative caprock formations—Eau Claire Shale, Maquoketa Shale, and Opalinus Clay—by employing a comprehensive set of experimental approaches. Laboratory assessments include permeability tests, stepwise CO₂ injection, imbibition experiments, and porosimetry‐based estimation to evaluate the sealing potential of heterogeneous geomaterials. It appears that within each formation, sand‐rich specimens exhibit significantly higher permeability and lower breakthrough pressures compared to their clay‐rich counterparts, underscoring the influence of the lithological variation. An indirect method based on pore structure analysis tends to underestimate the sealing capacity, highlighting discrepancies caused by the confinement, pore structure anisotropy, and variations in geochemical interactions. A statistical analysis based on the data set from this study and the literature reveals that CO₂ breakthrough pressure is positively correlated with the clay content, negatively correlated with the permeability and dominant pore size, and independent of its porosity. The sealing number is introduced to provide a quantitative framework for evaluating the sealing integrity of the tested caprock formations to withstand buoyant forces. This study highlights the critical role of heterogeneities in determining caprock sealing potential and emphasizes the importance of direct measurements, particularly the use of the stepwise method, for accurate assessment. Advanced imaging and geophysical monitoring, coupled with multi‐scale experiments, are recommended to enhance the reliability of heterogeneous caprock integrity assessments.

Subsurface fluid injection stimulates complex hydromechanical interaction, necessitating the integration of geomechanical data across spatial and temporal scales to consider the sophisticated behavior. Induced seismic response is usually associated with the complex reservoir architecture and pre‐existing features that are three‐dimensional, such as local stratigraphy, fractures, faults, and other discontinuities. This study encompasses laboratory characterization of the coupled hydromechanical response of cores extracted from rock formations in Illinois Basin: reservoir ‐ Mt. Simon sandstone, basal seal ‐ Argenta sandstone, and crystalline basement ‐ Precambrian rhyolite. High‐resolution numerical modeling allows considering the three‐dimensional complexity of the Illinois Basin Decatur Project with spatial resolution comparable to one of the active seismic surveys. A detailed reconstruction of the evolving state of stress in formations lacking direct stress measurements is achieved by numerical modeling that integrated laboratory‐derived hydromechanical properties, a porosity‐permeability relationship, active seismic data, and an inverted three‐dimensional porosity distribution. It appears that the microseismic clusters, mainly observed in the crystalline basement during the injection, are linked to zones experiencing more critically stressed conditions prior to injection. These zones have a potential for reactivation during the injection and are attributed to the specific local stratigraphy of the injection site, as well as transfer of triggering perturbations during the injection.

Subsurface fluid injection stimulates complex hydromechanical interaction, necessitating the integration of geomechanical data across spatial and temporal scales to consider the sophisticated behavior. The induced seismic response is usually associated with reservoir architecture and pre-existing features that are three-dimensional, such as local stratigraphy, fractures, faults, and discontinuities. This study encompasses laboratory characterization of coupled hydromechanical response of rock cores extracted from reservoir - Mt. Simon sandstone, basal seal - Argenta sandstone, and crystalline basement - Precambrian rhyolite - formations in the Illinois Basin. High-resolution numerical modeling allows to consider the three-dimensional complexity of the injection site for Illinois Basin Decatur Project with spatial resolution comparable to one of the active seismic surveys. The laboratory-based porosity-permeability relation is combined with a three-dimensional porosity distribution developed from an inversion of active seismic data resulting in a detailed reconstruction of the evolution of the state of stress in formations where stress measurements are not performed. It appears that the microseismic clusters, mainly observed in the crystalline basement during the injection, are linked to zones experiencing more critically stressed conditions prior to injection. These zones have a potential for reactivation during the injection and are attributed to the specific local stratigraphy of the injection site, as well as transfer of triggering perturbations during the injection.