We present the first experiments of dissolution-driven convection of carbon dioxide (CO2) in a confined brine-saturated porous medium at high pressures. We designed a novel Hele-Shaw cell that allows for both visual and quantitative analyses, and address the effects of free-phase CO2 and brine composition on convective dissolution. The visual examination of the gas volume combined with the measurement of pressure, which both evolve with dissolution, enable us to yield insights into the dynamics of convection in conditions that more closely reflect the geologic conditions. We find and analyze different dissolution events, including diffusive, early and late convection, and shutdown regimes. Our experiments reveal that in intermediate regime, a so-called "quasi-steady" state actually never happens. Dissolution flux continuously decreases in this regime, which is due to a negative feedback loop: the rapid reduction of pressure following convective dissolution, in turn, decreases the solubility of CO2 at the gas-brine interface and thus the instability strength. We introduce a new scaling factor that not only compensates the flux reduction but also the nonlinearities that arise from different salt types. We present robust scaling relations for the compensated flux and for the transition times between consecutive regimes in systems with NaCl (Ra ∼ 3271-4841) and NaCl+CaCl2 mixtures (Ra ∼ 2919-4283). We also find that NaCl+CaCl2 mixtures enjoy a longer intermediate period before the shut-down of dissolution, but with a lower dissolution flux, as compared to NaCl brines. The results provide a new perspective into how the presence of two separate phases in a closed system as well as different salt types may affect the predictive powers of our experiments and models for both the short-and long-term dynamics of convective dissolution in porous media. * brostami@ut.ac.ir

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The deep geothermal energy project at Soultz-sous-Forêts is located in the Upper Rhine Graben, France. As part of the Multidisciplinary and multi-contact demonstration of EGS exploration and Exploitation Techniques and potentials (MEET) project, this study aimed to evaluate the possibility of extracting higher amounts of energy from the existing industrial infrastructure. To achieve this objective, the effect of reinjecting fluid at lower temperature than the current fluid injection temperature of 70 °C was modeled and the drop in the production wellhead temperature for 100 years of operation was quantified. Two injection-production rate scenarios were considered and compared for their effect on overall production wellhead temperature. For each scenario, reinjection temperatures of 40, 50, and 60 °C were chosen and compared with the 70 °C injection case. For the lower production rate scenario, the results show that the production wellhead temperature is approximately 1–1.5 °C higher than for the higher production rate scenario after 100 years of operation. In conclusion, no significant thermal breakthrough was observed with the applied flow rates and lowered injection temperatures even after 100 years of operation.