No abstract

Surfactant flooding is one of the most promising chemical enhanced oil recovery techniques. However, this technique has been mainly applied in sandstone rocks with limited applications in carbonates. In this study, we present a comprehensive review on surfactant flooding for carbonates under harsh conditions of high temperature and high salinity. This review starts with highlighting the underlying mechanisms of surfactant flooding. Surfactant types, screening studies, and surfactant retention are then discussed. Laboratory and modeling works as well as field applications are also summarized. In addition, other surfactant applications such as surfactant-polymer, alkaline-surfactant-polymer, low salinity-surfactant as well as foams are presented. At the end of this paper, a list of recommendations and conclusions for better implementation of surfactants flooding are also discussed. This paper gives more insight into surfactant flooding aspects and its different applications in the petroleum industry. The literature review shows that a field-scale application of surfactant flooding in carbonates under high temperature and high salinity conditions is feasible. Also, this paper is considered as a guide for implementing potential projects on surfactant flooding in carbonates under harsh conditions.

No abstract

Low salinity/engineered water injections (LSWI/EWI) have gained popularity as effective techniques for enhancing oil recovery. Surfactant flooding is also a well-established and commercially-available technique in the oil and gas industry. In this paper, a numerical 2D simulation model was developed to investigate the effect of hybrid surfactant-LSWI/EWI on oil recovery from carbonate cores under harsh conditions. The developed simulation model was validated by history-matching recently conducted surfactant corefloods in the secondary mode of injection. Oil recovery, pressure drop, and surfactant concentration data were utilized. The surfactant flooding model was then coupled with a geochemical model that captures different reactions during LSWI/EWI. The geochemical reactions considered include aqueous, dissolution/precipitation, and ion-exchange reactions. Different simulation scenarios were considered and compared including waterflooding, surfactant flooding, engineered water injection, hybrid surfactant-EWI, and hybrid surfactant-LSWI. Additionally, sensitivity analysis was performed on the hybrid surfactant-EWI process through capturing changes in surfactant injected concentration and adsorption. For the case of LSWI/EWI, wettability alteration was considered as the main mechanism underlying incremental oil recovery. However, both wettability alteration and interfacial tension reduction mechanisms were considered for surfactant flooding depending on the type of surfactant used. The results showed that the hybrid surfactant-EWI altered the wettability and achieved higher oil recovery than that of surfactant-LSWI and other techniques. This highlights the importance of selecting the right combinations of potential ions for a certain reservoir to maximize oil recovery rather than a simple water dilution. The results also highlight the importance of surfactant adsorption and surfactant concentration for the hybrid surfactant-EWI technique. This work provides insights into the application of hybrid surfactant-LSWI/EWI on oil recovery especially in carbonates. The novelty of this work is further expanded through comparing surfactant-LSWI with surfactant-EWI and understanding the controlling parameters of surfactant-EWI through sensitivity analysis.

Carbon Capture and Storage (CCS) is one of the promising techniques to mitigate carbon dioxide emissions and move towards net zero targets. The efficiency of a geological storage process is, however, a complex function of CO2/rock/brine interactions. In particular, the effect of geochemical interactions among CO2/rock/brine systems in an aquifer and its associated impact on wetting behavior has not been rigorously investigated before. In this work, we study the effect of the critical parameters affecting the CO2/rock/brine system wettability from a geochemical perspective. In particular, we study the effect of temperature, pressure, and salinity on the wettability of the CO2/calcite/brine system. The wettability was assessed based on the disjoining pressure, which was calculated from calcite surface potential. The geochemical simulator used is based on surface complexation modeling and takes dissolution and precipitations reactions of the minerals and aqueous species into account. The results show that increasing pressure decreases the concentration of calcite surface species >CaOH2+ and >CO3−, while it increases the calcite surface species >CaCO3−. However, increasing temperature increases the concentration of calcite surface species >CaCO3− and >CO3−, while it slightly decreases the calcite surface species >CaOH2+. The results also show higher calcite surface potential and disjoining pressure at higher temperatures and lower salinity, which reflects an increase in water wettability (or a decrease in CO2-wetness) and greater CO2 storage potential in calcite-rich aquifers at these conditions. This paper provides insight into the effect of different influencing parameters on the CO2/rock/brine interactions and CO2/rock/brine wettability, which can help understand the geochemical processes involved in CCS projects under a wide range of operating conditions.