Polymer flooding has been established as an effective enhanced oil recovery (EOR) technique and can be utilized in large-scale field expansions. With high success rates and efficiency, polymer flooding operates by increasing the viscosity of water, promoting greater sweep efficiency and resulting in higher oil recovery beyond conventional waterflooding. Predicting viscosity has been established by numerous researchers as an essential tool to study polymers behavior under varying conditions. Previous model has proven a link between polymer viscosity and zero shear rate viscosity, relaxation time, hardness, and many other factors. This research initially reviews different types of polymers that can be applied successfully in EOR, demonstrate conditions that can alter polymer viscosity in porous medium, and analyze models that predict polymer bulk and in situ viscosity. The research then discusses a novel modification of the power law model to predict HPAM (SAV10) viscosity in a wide range of shear rates based on polymer concentration, fluid salinity, and divalent content. A polymer rheology study was carried out on SAV10 at various concentrations (750–5000 ppm) and brine salinities (43–210 k ppm). Results show the effectiveness of the model and the ability to predict viscosity accurately in low to medium shear rates, while in high shear rate, a slight deviation was noticeable.

Low polymer retention is essential in polymer flooding to minimize environmental impact and ensure accurate project design. Among the factors influencing retention, wettability remains critical yet insufficiently understood, particularly in carbonate formations. Most prior studies focus on sandstones and rarely assess wettability effects under static adsorption conditions. Moreover, the precision of polymer retention quantification varies across analytical techniques. This study investigates the influence of wettability on polymer retention through static and dynamic experiments using an ATBS-based polymer in carbonate lithology. Wettability alteration was induced by controlled aging at varying durations (8 h, 3 days, and 14 days at 90 °C) for both cores and rock powder. Polymer flooding was performed on five Indiana limestone cores at 167,114 ppm salinity and 50 °C, in both oil-presence and oil-free conditions. Dynamic polymer retention was quantified using effluent viscosity, UV–Vis spectroscopy, and TOC-TN analysis for inter-method comparison. The Amott wettability index to water ( δ _w ) decreased from 0.20 after 8 h of aging to 0.09 and 0.08 after 3 and 14 days, respectively, indicating a progressive reduction in water-wetness and a shift toward near-neutral/mixed-wet conditions with an increasing oil-wet tendency. Dynamic retention in the presence of oil decreased by 35–51% relative to oil-free conditions, with cores exhibiting more pronounced oil-wet tendencies showing up to an additional 21% decline (≈6 µ g/g-rock lower retention). Conversely, static adsorption values remained significantly higher (305–337 µ g/g-rock), showing negligible dependence on wettability changes or the presence of oil. The deviation between dynamic retention values obtained from the analytical techniques within each individual coreflooding test ranged from 6.82 to 8.27% under single-phase conditions and increased to 11.10–11.60% in two-phase experiments, primarily due to oil traces and shear-induced viscosity degradation, which are known to affect UV–Vis absorbance and rheology-based calculations. Consequently, TOC–TN results were adopted as the reference for comparative analyses due to their lower sensitivity to these interferences and their robustness in oil-bearing effluents. Overall, the findings highlight how wettability ranging from weakly water-wet to near-neutral/mixed-wet conditions with increasing oil-wet tendency influences both static and dynamic tests and emphasize the importance of selecting appropriate analytical methodologies for accurate polymer retention measurements in carbonate systems.