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Pressure solution, a mechanism that involves tight coupling between the geometry and thermal-hydro-mechanical-chemical (THMC) processes, plays an important role in diagenesis. In this study, we make the first attempt to conduct microscale THMC modeling to understand and quantify the impacts of geometry and temperature on pressure solution, taking natural salt rock as an example. This modeling capability is achieved by expanding a novel MC code that we developed previously (Hu et al. J Geophys Res: Solid Earth 126:e2021JB023112, 2021) to include temperature effects. We first conduct a simulation of an example that involves a single brine inclusion within a single halite grain and find that the temperature impact is limited for that case. We then extract geometry from an image of a natural salt rock and conduct simulations with different cases: (A) only temperature and no stress, (B) only stress and no temperature, and (C) with both stress and temperature. These different cases result in quite different phenomena. In case A, dissolution and precipitation occur across the entire system due to isolated pore space reaching a localized mass balance between dissolution, precipitation, and diffusion. In case B, intense geometric features (e.g., major asperities, inclusions) in one area undergo stress concentration, thus dominating pressure solution in that area. In case C, pressure solution is spread out at contacting highly stressed geometric features close to the hotter side. We conclude that geometric features dominate stress distribution, thus dominating pressure solution in a natural salt rock that may be affected by the temperature if a sufficient temperature gradient is applied.

The effectiveness of Carbon Capture and Storage (CCS) as an imperative decarbonization technology relies on the sealing capacity of a fine-grained caprock to permanently store CO2 deep underground. Uncertainties in assessing the caprock sealing capacity increase with the spatial and temporal scales and may delay CCS deployment at the gigatonne scale. We have developed a computationally efficient transport model to capture the dynamics of basin-wide upward CO2 migration in a multi-layered setting over geological time scales. We find that massive capillary breakthrough and viscous flow of CO2, even through pervasively fractured caprocks, are unlikely to occur and compromise the storage security. Potential leakage from the injection reservoir is hampered by repetitive layering of overlying caprocks. This finding agrees with geologic intuition and should be understandable by the public, contributing to the development of climate policies around this technology with increased confidence that CO2 will be indefinitely contained in the subsurface.

The widespread development of geothermal energy is deemed to accelerate the transition to a low-carbon future. Hot Sedimentary Aquifers (HSA) provide cost-effective and non-intermittent geothermal resources. However, HSA development has reportedly been associated with seismic events, harming the public perception of exploiting these resources. This work digs deeper into thermo-hydro-mechanical (THM) mechanisms raised by water circulation in a HSA and their control on fault reactivation. We numerically simulate the problem by a 2D plane-strain model. The model consists of a porous and permeable hot aquifer sandwiched between the tight seal and base rocks and laterally bounded by two normal faults, representative of extensional tectonic environments. The horizontal injection-production well pairs are spaced 500 m apart at the middle of the aquifer, and the faults are located on each side of the doublet at a distance of 1 km. We consider two scenarios: low-permeability faults, mimicking a compartmentalized reservoir, and high-permeability faults, across which fluid flow takes place with further ease. We show that the fault permeability governs the hydraulic response of the reservoir. While the pore pressure slightly increases around the injector and decreases around the producer for the case of high-permeability faults, the compartmentalized reservoir experiences a global pore pressure decline. The latter is supported by the fact that the injected cold water is denser than the extracted hot water and occupies less space in the pore system. As soon as the thermal breakthrough occurs, which is after 12 years in the current setting, a more uniform temperature distribution across the doublet is established and the pressure begins to increase in the vicinity of the injector. Provided the high permeability of the reservoir rock, pore pressure and poroelastic stress perturbations impose rapid but minor effects on the fault stability. On the contrary, the cooling front formed

Deep geothermal energy (DGE) represents an opportunity for a sustainable and carbon-free energy supply. One of the main concerns of DGE is induced seismicity that may produce damaging earthquakes, challenging its widespread exploitation. It is widely believed that the seismicity risk can be controlled by using doublet systems circulating water to minimize the injection-induced pressure changes. However, cold water reinjection may also give rise to thermal stresses within and beyond the cooled region, whose potential impacts on fault reactivation are less well understood. Here, we investigate by coupled thermo-hydro-mechanical modeling the processes that may lead to fault reactivation in a hot sedimentary aquifer (HSA) in which water is circulated through a doublet. We show that thermal stresses are transmitted much ahead of the cooled region and are likely to destabilize faults located far away from the doublet. Meanwhile, the fault permeability mainly controls the fault reactivation timing, which entails the importance of employing appropriate characterization methods. This investigation is crucial for understanding the mechanisms controlling induced seismicity associated with DGE in a HSA and allows the success of future DGE projects.