Nanofluids as an EOR technique are reported to enhance oil recoveries. Among all the nanomaterial silica with promising lab results, economic and environmental acceptability are an ideal material for future applications. Despite the potential to enhance recoveries, understanding the two-fold impact of parameters such as concentration, salinity, stability, injection rate, and irreproducibility of results has arisen ambiguities that have delayed field applications. This integrated study is conducted to ascertain two-fold impacts of concentration and salinity on recovery and stability and evaluates corresponding changes in the recovery mechanism with variance in the parameters. Initially, silica nanofluids’ recovery potential was evaluated by tertiary flooding at different concentrations (0.02, 0.05, 0.07, 0.1) wt. % at 20,000 ppm salinity. The optimum concentration of 0.05 wt. % with the highest potential in terms of recovery, wettability change, and IFT reduction was selected. Then nano-flooding was carried out at higher salinities at a nanomaterial concentration of 0.05 wt. %. For the mechanism’s evaluation, the contact angle, IFT and porosity reduction, along with differential profile changes were analyzed. The recovery potential was found at its highest for 0.05 wt. %, which reduced when concentrations were further increased as the recovery mechanisms changed and compromised stability. Whereas salinity also had a two-fold impact with salinity at 30,000 ppm resulting in lower recovery, higher salinity destabilized the solution but enhanced recoveries by enhancing macroscopic mechanisms of pore throat plugging.

This study presents the utilisation of Propylene Carbonate (PC), along with an alkali-based solution, to modify the Hydroxyethyl Methyl Cellulose (HEMC) polymer to mitigate the thermal degradation of cellulose ether. The experimental results from FTIR and XRD analysis confirmed the addition of a new function group to the HEMC backbone and the formation of a new organic carbonate-based cellulose ether. Shear viscosity experiments were conducted at concentrations of 0.50-wt.% to 2-wt.% at ambient and elevated temperatures ranging from 80°C-110°C using a rheometer. All polymeric solutions exhibited shear-thinning behaviour, and the viscosity of polymeric solutions was enhanced by increasing the concentration of modified HEMC solutions. The modified HEMC solutions exhibited higher viscosity at 1000 s-1 shear rate at 110ºC compared to the native HEMC solutions, confirming the enhanced thermal stability of the PC-based modified HEMC solution. Alkali-based modified HEMC solution exhibited low shear viscosity at ambient temperature. The alkali-based polymeric solution’s viscosity was increased by 48% at a high shear rate at 110ºC. In conclusion, 0.50-wt.% and 01-wt.% concentration of alkali-based PC-modified HEMC solution proved efficient in maintaining viscosity under ambient conditions, increasing solubility and exhibiting improved thermal stability at geothermal conditions for oil field applications.

Enhanced Oil Recovery (EOR), when aligned with Carbon Capture and Storage (CCS) objectives, increases oil production while addressing climate concerns through geological CO₂ storage. Water Alternating-Gas (WAG) is considered an effective enhanced oil recovery (EOR) technique in oil mobilizing and CO₂ storage. The study focuses on identifying variable settings for the optimum trade-off between recovery and storage in the case of immiscible WAG-EOR. The Taguchi-based coreflooding experimental design was conducted to investigate the impact of variable operating parameters on both oil recovery and CO₂ storage efficiency, facilitating a structured analysis of key variables with fewer experimental runs. The experimental design included four control variables: the injector rate, pressure, WAG ratio, and brine salinity, each tested at three levels: 0.15–0.50 mL/min, 650–850 psi, 1:1–2:1, and 20,000–30,000 ppm, respectively. The regression analysis, Signal-to-Noise (S/N) ratios, and an Overall Performance Index (OPI) were employed to evaluate oil recovery and CO₂ storage, both as separate responses and in combination. The findings outlined a clear trade-off between the two objectives: higher injection rates increased oil recovery, whereas lower rates favored CO₂ storage. The WAG ratio had a limited effect on oil recovery but consistently enhanced CO₂ storage, particularly at a 1:2 ratio. Salinity demonstrated a secondary yet positive influence, improving the overall performance, while pressure showed the least noticeable impact. Statistical ranking identified the injection rate as the most influential parameter, followed by salinity, WAG ratio, and pressure. Both the injection rate and WAG ratio were found to have a strong impact on responses. According to the OPI-based optimization results, the most favorable operating conditions were an injection rate of 0.15 mL/min, pressure of 850 psi, salinity of 30,000 ppm, and a WAG ratio of 1:2. In addition, predictive regression models forecasted oil recovery and CO₂ storage across different operating conditions, offering valuable guidance for future experiments and field applications. Overall, the findings highlight the significance of injection rate and WAG ratio in determining immiscible WAG performance, offering practical insights for enhancing EOR-CCS optimization.