# Hybrid Engineered Water-Polymer Flooding in Carbonates: A Review of Mechanisms and Case Studies
## 4 Hybrid Engineered Water-Polymer Flooding (EWFF)
### Recovery Mechanisms
#### 4.2.5 Enhanced Polymer Stability using EW  
The HPAM properties are strongly dependent on the makeup brine salinity, hardness, pH, and ionic composition. HPAM polymers are the cheapest and most widely used polymers, however they start losing viscosity and behave more like Newtonian fluids under high-salinity and high-temperature conditions, thus limiting their application in such formations [119]. Low pH conditions promote HPAM adsorption due to the coiling of polymer chains as more molecules are adsorbed onto an available surface area. Similarly, high salinity conditions result in the charge screening effect, reducing the polymer viscosity and stability. Ca\({}^{2+}\) ions promote HPAM precipitation, which can have a detrimental effect on the rock permeability and polymer degradation. The recommended Ca\({}^{2+}\) concentration in EW should be below 200 ppm [175]. In contrast, SO\({}_{4}\)\({}^{2-}\) ions, being negatively charged, promote the  
Figure 8: Effects of the potential determining ions (PDIs) and the pH of water on (**a**) oil recovery and (**b**) wettability alteration using EW [135]. stability of the anionic HPAM polymer in carbonate formations. A number of studies on polymer rheology have shown \(\sim\)30-50% reductions in the polymer concentration [15; 176; 177; 178; 119; 120] were needed in order to achieve the target viscosity when low-salinity makeup brine was used (Figure 9). Data for Figure 9 are given in Table S4 in the Supplementary Materials. [PERSON] et al. [179] developed a comprehensive database based on detailed rheological experiments using HPAM polymers. This database clearly demonstrates the higher polymer viscosity and enhanced stability caused by reducing the brine salinity and hardness. [PERSON] and [PERSON] [119] performed coreflooding experiments to assess the impact of LSW on the polymer concentration and incremental oil recovery, showing a 50% reduction in the polymer concentration needed to attain the desired viscosity, mainly because of the improved polymer stability and reduced coiling in LSW (Figure 10). The cost savings will be even higher in high-salinity formations. Considering a high-salinity and high-temperature scenario in an Arabian carbonate reservoir with slightly heavy oil (25 \({}^{\circ}\)API), [PERSON] et al. [139] showed the positive effects of LSW on polymer the rheological properties and thermal resistance. The smart water (7000 ppm TDS) resulted in a \(\sim\)30% decrease in the polymer concentration needed to maintain the target viscosity and also improved the thermal tolerance of the polymer (Figure 11) as compared to the injection water (70,000 ppm TDS). Figure 10: Reductions in HPAM concentrations using LSW as the makeup brine [119]. Figure 9: Studies showing reductions in the required polymer concentrations using LSW compared to high salinity water (HSW). The improved polymer stability in LSW spiked with SO4\({}^{2-}\) ions (2935 ppm TDS with 1155 ppm SO4\({}^{2}\)) was confirmed by [PERSON] et al. [15]. The target viscosity of 3 centipoise (cp) was achieved at a relatively lower polymer concentration (2500 ppm) using LSW compared to high-salinity brines (polymer concentration 4000 ppm). This resulted in a \(\sim\)37% reduction in polymer consumption in reservoir conditions. Similarly, the LS polymer solution also retained 94% of its original viscosity after 188 days of aging at reservoir temperature, showing the better thermal stability of the polymer in low-salinity makeup water (Figure 12). The results of his work showed that a carefully designed low-salinity polymer (LSP) solution can provide both improved polymer stability and the required viscosity needed for efficient oil displacement at high temperatures, as well as the desired molecular weight needed for better polymer injectivity in low-permeability carbonate formations. Hence, the PF application envelope can be extended to severe reservoir conditions using LSW, which otherwise may not be technically or economically viable using high-salinity formation water.