Integrated Formulation Optimization and Core Flood Validation of Surfactant–Polymer Flooding in High-Temperature Anhydrite-Rich Dolomite Reservoirs

Abstract

This study performs a laboratory investigation of the technical feasibility and formulation optimization of surfactant–polymer (SP) flooding in high-temperature, anhydrite-rich dolomite reservoirs containing high-sulfate formation brines. The objective is to develop thermally stable, scale-compatible chemical formulations; quantify surfactant adsorption and polymer rheological stability under reservoir conditions; and validate incremental oil recovery through systematic, reservoir-representative coreflood experiments to support potential field-scale implementation in challenging carbonate systems. Reservoir core plugs were characterized using X-ray diffraction and petrographic analysis to confirm mineral composition and quantify anhydrite content. Formation brine was filtered and evaluated for microbial activity, including sulfate-reducing and iron-related bacteria. Polymer candidates were screened for thermal stability and viscosity retention at 90°C, leading to selection of a lower molecular weight anionic polyacrylamide. Approximately 20 surfactants were evaluated for brine compatibility, precipitation, and thermal stability, followed by more than 100 phase behavior tests to identify optimal internal olefin sulfonate (IOS)-dominated blends. Static adsorption testing using UV–Vis spectroscopy quantified retention after 13 days at reservoir temperature. Coreflood experiments were conducted using 1.0 PV and 0.5 PV SP slugs with varying polymer concentrations. Mineralogical analysis confirmed significant anhydrite content, eliminating sodium carbonate buffering options due to scaling risks and necessitating formulation redesign. Phase behavior screening identified IOS-dominated blends capable of forming stable middle-phase microemulsions in high-sulfate brines without precipitation or gel formation at 90°C. Polymer testing demonstrated acceptable viscosity retention and injectivity under reservoir conditions. Static adsorption measurements showed surfactant retention ranging from 18% to 52%, depending on blend composition and rock–fluid interactions. Coreflood experiments demonstrated meaningful incremental oil recovery beyond baseline waterflooding. A 1.0 PV SP slug containing 5000 ppm polymer and 3 GPT optimized surfactant blend yielded 19% additional oil recovery in higher-permeability cores (Φ·K = 3.55). A 0.5 PV slug achieved 7% incremental recovery in lower-permeability cores (Φ·K = 0.93). Further optimization reducing polymer concentration to 2000 ppm in 0.5 PV slugs resulted in incremental recoveries of 29% and 16% in cores with Φ·K values of 0.95 and 0.34, respectively. A surfactant-only flood yielded 10% incremental recovery in intermediate-permeability cores. Pressure profiles indicated stable injectivity with no severe plugging or permeability impairment. This work presents a comprehensive, end-to-end evaluation of SP flooding in anhydrite-rich carbonate systems under high-temperature and high-sulfate conditions. The integrated workflow, combining mineralogical screening, microbial assessment, large-scale formulation optimization, adsorption quantification, and systematic coreflood validation—provides field-relevant design criteria and performance benchmarks. The results offer actionable formulation strategies and recovery expectations for deploying chemical EOR in challenging carbonate reservoirs where scaling, sulfate content, and thermal stability constraints are critical.