Geochemical Investigation of Surfactant-Polymer Flooding in Carbonate Under Harsh Conditions

Abstract Surfactant-polymer (SP) flooding has emerged as a promising enhanced oil recovery (EOR) technique for carbonate reservoirs characterized by high-temperature and high-salinity (HTHS) conditions. These reservoirs, often defined by their low permeability, heterogeneity, and predominantly oil-wet nature, pose significant challenges to conventional recovery methods. This study explores the potential of combining a zwitterionic carboxybetaine surfactant with an ATBS-based polymer to improve mobility control, enhance sweep efficiency, and optimize flow dynamics within carbonate reservoirs. Comprehensive coreflooding experiments were conducted on Indiana limestone cores under controlled laboratory conditions. The influence of surfactant concentration, polymer addition, and brine salinity on pressure drop, rheology, and geochemical interactions was investigated. Resistance factor (RF) enhancements observed during SP flooding were substantial, particularly at reduced salinity, with RF values increasing from 3.46 at seawater salinity to 10.06 at 10-times diluted seawater (10DSW). Effluent analyses highlighted the critical role of geochemical interactions, such as ion exchange and mineral dissolution. Calcium and magnesium ions, released during rock-fluid interactions, actively influenced the equilibrium, promoting favorable changes in flow dynamics. Rheological evaluations revealed the ATBS polymer's thermal resilience, with the solutions retaining effective viscosities at reservoir-relevant temperatures (70°C) and showing only moderate reductions at 90°C. The presence of surfactants in SP formulations did not compromise polymer stability, ensuring robust viscosifying performance. Furthermore, low-salinity brines not only enhanced polymer viscosity but also reduced polymer retention, as evidenced by residual resistance factors (RRF) consistently below 1.35 across all injection scenarios. This highlights the SP system's ability to maintain injectivity while delivering significant mobility control benefits. This study demonstrates the potential of surfactant-polymer flooding as a transformative EOR approach tailored to carbonate reservoirs under HTHS conditions. The findings underscore the importance of salinity optimization, chemical formulation tuning, and the integration of rheological and geochemical insights to maximize recovery efficiency. Future work will focus on extending these laboratory findings to field-scale applications, ensuring cost-effectiveness and operational feasibility in diverse reservoir environments.