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Deep saline aquifers are good candidates for CO2sequestration because of their huge reserves, wide distribution, cost-effectiveness, and relatively high security. The impact of CO2sequestration on the rock's mechanical and petrophysical properties is a complex issue that depends on a number of factors, such as salinity. This study provides insights into the potential changes in rock petrophysical and geomechanical properties due to the reactivity of CO2-saturated brine with limestone. Specifically, this article provides insights into the impact of salinity on wormhole generation and the corresponding changes in rock properties. Three Indiana limestone samples with a 1.5-inch diameter and 3-inch length, 15% average porosity, and 2 mD average permeability were used. The samples were flooded at 1 mL/min, 2000 psi, and 60 °C with different brine concentrations mixed with CO2at a 70:30 ratio. To examine the impact of salinity, CO2was mixed with brine concentrations of 40,000 ppm, 120,000 ppm, and 200,000 ppm for the coreflooding experiments. The samples' Young's modulus (YM) and Poisson's ratio at different confining pressures were measured before and after coreflooding. A medical CT scan was also used to visualize the generated wormholes and quantify their volumes. Results showed that it took only 14.3 pore volumes (PVs) to create a wormhole at 40,000 ppm, while 24.8 and 25.6 PVs at 120,000 ppm and 200,000 ppm, respectively. Lower salinity live brine generated a thicker wormhole compared to the other salinities. The reduction in rock strength in terms of YMs was the highest at 200,000 ppm, followed by the 120,000 ppm and then the 40,000 ppm cases. This study demonstrates that wormhole generation can substantially increase CO2storage capacity in low-salinity aquifers; however, an increase in CO2relative permeability indicates that it will accumulate primarily beneath the caprock. In addition, this study reveals that fresh carbonated water or water with a low salinity can be used for acid stimulation.

Utilization of CO2foam in well-stimulation operations is a realistic practice to reduce carbon emissions by injecting CO2into subsurface formations. The viscosity and stability of CO2and N2acidic foamed fluid is impacted by additives such as corrosion inhibitor and chelating agent and conditions such as pressure. In this study, the apparent foam viscosity was determined using a high pressure - high temperature foam rheometer at a temperature of 150 °C, pressure ranging from 1000–4000 psi, and different shear rates 100-2000 1/s. A foam analyzer was furthermore utilized to characterize foam properties such as foamability, foam stability, and bubble structures at 100 °C and 1000 psi. Different surfactants were used due to their ability to generate stable and viscous foam; Duomeen TTM, Ethoduomeen T13, Armovis VES, and the combination of Duomeen TTM and Armovis VES. Among all surfactants, Duomeen TTM provided the highest foam viscosity with CO2at both low and high shear rate. Once the surfactant solution was mixed with 1.5 wt% of CI, the foam viscosity dropped sharply. However, the synergic surfactants (i.e., Duomeen TTM and Armovis VES) obtained the highest viscosity once mixed with CI. Also, the effect of CO2and N2at different pressures on the viscosity of generated foam was investigated. When the CO2pressure was raised to 2000 psi, the viscosity of CO2foam increased by 55% at both low and high shear. In comparison, the N2foam viscosity increased by 12% at 100 1/s shear rate and by 32% at 1500 1/s. According to the findings, the influence of CI increased as the pH of the foam fluid declined, and thus reduced the foam viscosity. Finally, foam properties such as foamability, foam stability, and bubble structure were determined. N2foam generated higher foam stability than CO2foam. The findings of this study can help for a better understanding of the effect of corrosion inhibitor on CO2and N2foam viscosity at high temperature and pressure.