Salt precipitation has emerged as a critical factor affecting injectivity, reservoir stability, and the potential to trigger near-wellbore microseismic activity during geological CO ₂ sequestration. While previous studies have primarily focused on the brine acidification induced by CO ₂ injection, triggering geochemical reactions in carbonate rocks and leading to mechanical degradation, the mechanical behavior associated with salt precipitation in drying zones, particularly the failure mechanisms, remains poorly understood. In this work, we designed a reservoir-condition displacement system to mimic near-wellbore drying process and further investigated the rock failure modes due to salt precipitation in red sandstone samples. Our study demonstrates that, despite the densification of the pore structure due to salt precipitation, the overall mechanical performance of the rock undergoes significant deterioration. More importantly, for the first time, we observe a distinct transition of failure mode from shear-to tensile-dominated under uniaxial compression. Microstructural analysis further shows that the growth of polycrystalline and bulk crystals induces microcrack initiation and propagation, with the failure mechanism of rocks subjected to salt precipitation primarily characterized by intercrystalline damage at weak bonding interfaces under external loading.

Hypothesis: Interface dynamics, such as Haines jumps, are crucial in multi-phase flow through porous media. However, the role of intrinsic surface wettability in pore-filling events remains unclear, and the pressure response requires further study. This work evaluates the impact of wettability on interface stability and pressure dynamics. Experiments and simulations: We performed microfluidic experiments and level-set simulations of two-phase flow. Water displaced air or Fluorinert in a PDMS micro-model with controlled wettability (contact angles: 60^∘, 95^∘, 120^∘). Three injection velocities covered capillary- to viscous-dominated flow regimes. High-resolution imaging and synchronized pressure recordings linked interface curvature with capillary pressure changes. Findings: At low capillary numbers, wettability strongly affects burst pressure and pinning. Its influence decreases at higher capillary numbers. We observed an apparent wettability shift due to hysteresis and a capillary pressure barrier linked to pore-wall slope variations. Simulations replicated experimental trends, confirming the role of wettability in pore-scale displacement. These findings provide critical insights for improving pore-network models and understanding wettability effects in porous media.

Carbon dioxide capture and storage in subsurface geological formations is a potential solution to limit anthropogenic CO₂ emissions and combat global warming. Depleted gas fields offer significant CO₂ storage volumes; however, injection of CO₂ into these reservoirs poses some potential challenges for the injectivity, containment and well/facility integrity due to low temperatures caused by isenthalpic expansion of CO₂. A key injectivity risk is due to possible formation of hydrates at the low expected temperatures. This study aims to address main causes of CO₂ hydrate formation and its impact on permeability of porous media. This review highlights the current state of knowledge in the literature while emphasizing the need to bridge existing gaps in derisking CO₂ injection into (depleted) low-pressure gas reservoirs. In summary, according to the existing literature, the potential for hydrate formation is assessed to be credible. Current industry solutions exist to manage this risk; however, they are costly and energy intensive. Future research will be needed to provide capabilities to manage this risk more efficiently.

Low salinity water flooding is a common technique for enhancing oil recovery; however, the mechanism behind the low-salinity effect, positive or negative, is still not fully understood. In the proposed mechanisms, osmosis and emulsification are considered as two potential reasons for explaining the oil remobilization, but the specific contributions on the remobilization are not well studied at pore-scale. In this article, we performed a series of microfluidic experiments to investigate the movement of constrained oil between invading low-salinity brine and residual high-salinity brine. We find that various salinity contrasts over oil films cause different water fluxes through the oil and swelling areas of the trapped brine, resulting in the relocation of oil phases within the pore spaces. A higher salinity contrast (1.7-170 g/L salt concentrations) provides a faster water penetration in oil phases. In the presence of an oil-soluble surfactant, spontaneous emulsification occurs at the interface of low-salinity brine/oil, which enhances almost 100 times the water flux in two oil phases (n-heptane and n-dodecane). We directly observe pore-scale spontaneous emulsification at the low-salinity brine/oil interface but not at the high-salinity brine/oil interface. Furthermore, two scenarios for explaining water transport through the oil phase are proposed: water diffusion due to chemical potential gradient and water transport via reverse micelle or microemulsions movement.