Foam injection has been promoted as a reliable method for improving the sweep efficiency in heterogeneous carbonate reservoirs by modifying the properties of the injected gas and hence, providing mobility control effect. However, the conditions of the Middle Eastern carbonate reservoirs are quite detrimental to foam performance, leading to unoptimized mobility control. This challenge has motivated the improvement and development of different foaming agent formulations that can withstand the harsh conditions in carbonate reservoirs of high temperature and high salinity. In this study, the effect of different amphoteric and switchable surfactants on bulk foam performance were investigated and later the optimum formulation was evaluated in carbonate porous media for EOR under high salinity and temperature conditions. For this purpose, the solutions containing different commercial amphoteric and amine-based switchable surfactants were prepared in high salinity brine (20 wt%) at high temperature conditions (80 °C). Initial screening was performed by conducting series of foamability and foam stability tests at high temperature. Foam generation and endurance were also investigated in the presence of crude oil. Foam performance was evaluated in carbonate core samples under different foam qualities and at reservoir conditions. After selecting the optimal foam quality for effective foam generation, the oil recovery experiment was then performed to recover the remaining oil after secondary N2-gas flood. The results from bulk foam experiments demonstrated the superior properties of betaine-based surfactant (B-1235), in which the highest foam generation and foam stability performance were achieved. Foam endurance of B-1235 was also found comparable to the foam produced by switchable diamine (DTTM) surfactant; however, DTTM surfactant showed poorer foamability performance. In the presence of crude oil, B-1235 surfactant was able to maintain the foam properties, compared to other tested surfactants. The optimum concentrations for B-1235 in the absence and presence of crude oil were found to be 0.25 wt% and 0.5 wt%, respectively. The injection of foam stabilized by the B-1235 was able to pronouncedly increase the mobility reduction factor (MRF) at all the tested foam qualities under high-pressure and high-temperature conditions. Coreflood investigations indicated an optimal foam quality at 70% for all tested surfactant concentrations. The cumulative oil recovery after foam injection was found to be 67%, including 25% tertiary incremental oil recovery by foam flooding. The overall performance of the tested betaine-based surfactant is promising as an effective mobility control during foam EOR process and promotes further application in difficult Middle Eastern carbonate reservoir conditions.

Foam injection has been acknowledged as a promising technology to control gas mobility by establishing the flow resistance during gas enhanced oil recovery (EOR) processes. For applications in challenging carbonate formations, the development of well-matched foaming agents is required. In this paper, the foam performance established by different switchable and zwitterionic surfactants along with their combinations in controlling gas mobility and displacing the residual oil is investigated. The stable solutions of commercial amine-based and/or zwitterionic surfactants were prepared in 20 wt % salinity. A series of foamability and foam stability tests were conducted as initial screening at high temperatures in the presence and absence of crude oil. Foam texture and foam stability were also investigated at different gas/liquid fractions under high-temperature and high-pressure conditions. The best-performing formulation at optimum foam quality was evaluated in coreflooding experiments in terms of mobility reduction factor (MRF) and residual oil recovery. Bulk foam results demonstrated the superior foamability and foam stability of a betaine (B1235) surfactant. Foam endurance of B1235 was found comparable to the diamine (DTTM) produced foam; however, the DTTM surfactant showed insignificant foamability. Among all tested surfactants and their mixtures, B1235 was found most effective in maintaining foam properties in a crude oil environment, and no synergistic effect was observed in the use of surfactant mixtures. The optimum concentrations for B1235 with and without crude oil were 0.25 and 0.5 wt %, respectively. The results obtained from the experiments in a pressurized view cell indicated a prolonged decay profile at 90% gas fraction in bulk. During dynamic flow in carbonate rocks, the optimum quality of foam stabilized by the selected surfactant was found at 70%. At this quality, the pregenerated foam injection pronouncedly increased the MRF to 48. The cumulative oil recovery after foam injection was 67%, providing 25% incremental recovery. The overall performance of the betaine-based surfactant-stabilized foam in high-salinity carbonates was found effective in controlling the gas mobility during the foam EOR process.

Foam injection is designed to reduce the effects of high reservoir heterogeneities and fluid viscosity contrasts during gas flooding, and hence, improve sweep efficiency. However, harsh reservoir conditions in the Middle Eastern reservoirs pose a serious problem to foam stability, leading to a poor mobility control for foam injection. In this study, different surfactant types and their combinations were tested to screen and optimize foam performance in harsh salinity (20 wt%) at high pressure and high temperature (HPHT) conditions (1000 psi and 80 °C) based on series of bulk foam experiments. For this purpose, different commercial amphoteric and amine-based switchable surfactants were utilized and their compatibility in 20 wt% brine were ensured at HPHT conditions. Initial screening was performed by conducting series of foam stability and foaming ability tests at high temperature. The surface tension and surfactant solution rheology tests were performed to analyze foam behavior. The mixtures of amphoteric and amine-based surfactants were then investigated to improve bulk foam performance. Foam stability and foam texture at different foam qualities under HPHT conditions were also studied. Bulk foam experiments showed that betaine (B-1235) surfactant outperformed other surfactant types through achieving the highest foam generation with excellent foam stability performance. Betaine foam endurance was found to be comparable to that of viscoelastic diamine surfactant. However, poor foam generation was observed when diamine was used as a single surfactant. The optimum concentration for betaine surfactant was found to be 0.25 wt%. A mixture of betaine and amine-based surfactant improved the latter foam properties and its performance was found to be higher than that of single surfactant. The foam stability of mixed surfactant was approximately 8 folds higher than that of single amine-based surfactant. Furthermore, foam texture directly controls foam decay profile, and the optimum foam quality based on static pressurized foam cell test was found to be 90% due to the formation of uniform and closely packed bubbles. This research identified high performing individual as well as a mixed surfactant systems for designing foam EOR projects for Middle Eastern harsh reservoir conditions.