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Deep saline aquifers are promising locations for carbon sequestration, but the impact of the CO2injection on rock properties requires careful investigation. This study will examine the effects of CO2-saturated brine injection on limestone, specifically analyzing how pore pressure influences wormhole formation and subsequent changes in the petrophysical and geomechanical properties. Four Indiana limestone samples, each with dimensions of 1.5 in. in diameter and 3 in. in length, were utilized. These samples exhibited an average porosity of 15.7% and an average permeability of 2.6 mD. During the experiments, the samples were subjected to one of selected pore pressure values (4000, 3000, 2000, and 1500 psi) and a temperature of 60 °C, with a brine concentration of 120,000 ppm mixed with CO2at a ratio of 70:30. Notice that the pressure was kept in the accumulator at 1200 psi initially before compressing it to the desired pressure to maintain the same mass of CO2in all experiments. An injection rate of 1 cm3/min was employed for the coreflooding experiments. Before and after coreflooding, Young’s modulus (YM) and Poisson’s ratio of the samples were measured at various confining pressures. Additionally, the porosity, permeability, and surface hardness of the treated samples were assessed. A micro-CT scan was employed to visualize the generated wormholes and quantify their volumes. Our study demonstrated that among the four tested injection pressures, 2000 psi yielded the lowest pore volume to breakthrough (PVBT). No clear trend was observed between PVBT and pore pressure. However, a strong correlation emerged between the mechanical properties of the treated samples and pore pressure values. The investigation established that increasing injection pressure results in greater damage to the core, as evidenced by reductions in both surface hardness and dynamic YM.

Excessive water production in the oil industry is a persistent challenge, impacting operational costs and environmental concerns related to water disposal. Fractures and channels are widely recognized as significant sources of water production in reservoirs produced under a water drive mechanism. Recent investigations have shown the efficiency of nanosilica gel in mitigating water production in high-permeability formations. However, these studies have not thoroughly evaluated its performance in addressing fractures as potential pathways for water migration. Therefore, this study investigates the performance of nanosilica gel in fractures and channels, which are major sources of water production. Four carbonate core samples of 1.5-inch diameter and 3-inch length were utilized: two containing an induced fracture and the other featuring an open channel. Core samples underwent core flooding experiments, computed tomography (CT) scans, and nuclear magnetic resonance (NMR) T2measurements. The coreflooding system was utilized to treat carbonate samples with two gels: a nanosilica gel solution comprising 75 (wt %) nanosilica and 25 (wt %) activator, and polyacrylamide/polyethylenimine (PAM/PEI) gel of (9/1) wt %. The injection of a sufficient volume of the gel ensured successful placement and curing at a high temperature of 200 °F. The nanosilica demonstrated exceptional plugging efficiency, with a remarkable 100% reduction in permeability and enduring durability under varying differential pressures, reaching up to 1000 psi. This performance was at the same level of plugging efficiency obtained with PAM/PEI gel with 9/1 (wt %) concentration. CT scans and NMR analysis further confirm the uniform distribution of both gels and the successful displacement of brine from the fractures and channels.

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.

Global climate change is one of the most pressing environmental challenges facing the world, and numerous efforts are currently being undertaken to mitigate and reverse the effects. Carbon dioxide (CO2) is a major contributor to greenhouse gas emissions, totaling 76% of emissions. Hence, numerous methods have been proposed and utilized to convert, utilize, or permanently store CO2. A typical example is the dual application of CO2for enhanced oil recovery (EOR) and subsequent storage, which is highly required in the oil and gas industry due to the widespread availability of marginal fields and depleted oil reservoirs. Nonetheless, the injection of pure CO2into underground geologic formations faces some challenges owing to its high mobility, which can cause early breakthrough of the injected gas. As a result of these challenges, a significant amount of hydrocarbon is bypassed during the EOR process, which leads to poor sweep efficiency. To address these challenges, the utilization of CO2foam for EOR and subsequent storage is being examined. Foam enhances storage capacity by increasing a reservoir’s sweep efficiency and minimizing early breakthrough, which allows more CO2to fill the empty pore spaces. In this paper, the application of CO2foam for EOR and CO2geological storage (geo-storage) is reviewed. First, an overview of the CO2foam flooding process is provided. Moreover, the trapping mechanism of CO2geo-storage by foam is discussed. Besides, existing experimental studies on improving the storage capacity of CO2are analyzed. Finally, the technical challenges facing the application of CO2foam are identified, and recommendations for future research are offered.