Carbonated water injection (CWI) might be an efficient alternate to CO₂injection technique. In CWI, CO₂exists as a dissolved phase and not as a free phase; thus, it eliminates some challenges encountered in CO₂injection such as poor sweep efficiency and gravity segregation. In CWI, the density and viscosity of water become higher than normal due to the CO₂dissolution, thereby reducing the gravity segregation and channeling effect. This article is a comprehensive review on how carbonated water flooding has evolved over the time and captured salient features on the mechanisms involved in its role in enhanced oil recovery. The aspects reviewed in this article include a brief comparison of conventional CO₂injection and carbonated water injection and the benefits thereof. Solubility of CO₂in water, brine and oil phases is discussed in detail with valid correlations. A brief history of the development of CWI in the laboratory and field information is captured from 1905s to the present followed by the possible mechanisms and principle of CWI reported by various authors. This article also captured the latest findings on the beneficial effect of hybridizing CWI with smart water technologies.

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.