The failure of water-based fracturing fluids in unconventional reservoirs, especially those with high clay content, led to the development of CO₂ fracturing technology (Zhao et al., 2021). With CO₂ fracturing, the reservoir rock and formation fluids undergo a variety of physical and chemical reactions. As a result of these reactions, reservoirs may become more porous and permeable, and the flow of natural gas commences. Gas recovery factor is enhanced and CO₂ is permanently stored in the geological formations (Tao et al., 2021). Tight reservoirs and other unconventionals are characterized by high temperature especially when the depth exceeds 1000 m where the temperature and pressure are above the critical point of CO₂ (31.1 C, 7.38 MPa, respectively). These formation conditions make CO₂ attain the supercritical state exhibiting superior properties such as low viscosity, strong diffusion, much higher density than gas, and almost no surface tension (He et al., 2022). CO₂ fracturing is significantly superior as it lowers the pressure required to initiate a fracture, connect micro-fractures, and create intricate fracture networks appropriate for rock formations with low pressure, low permeability, and high-water sensitivity. Additionally, liquid CO₂ can be used as a fracturing fluid and has several benefits over others, including quick well cleanup, removal of formation damage, and low cost. However, the widespread use of CO₂ fracturing fluids has been constrained by inadequate proppant transfer, significant friction loss, and high pump displacement associated with low fluid viscosity (Middleton et al., 2015).

Due to CO₂ poor mobility control, phase segregation, and extremely low viscosity, gas has the propensity to finger and break through into production wells easily bypassing unswept oil zones (Dai et al., 2017). To address these challenges and improve sweep efficiency, CO₂-responsive gels were developed to plug and divert CO₂ into oil zones. These chemicals have special functional groups (amines, amidines, guanidines, and carboxylic acids) on either surfactant or polymer chains that activate their responses based on the pH change caused by the presence of CO₂ (Yang, He, Sui, He, & Li, 2019). The interaction of CO₂ and water in the formation produces carbonic acid leading to protonation of the responsive tertiary amines, electrostatic repulsion among the polymer particles, and an increase in the particle size (Du D. et al., 2022). The injection of N₂ induces a reversible reaction by changing the pH of the system leading to CO₂ release and gel particle shrinkage (Y. Liu & Liu, 2022).

(Shen et al., 2021) investigated CO2-responsive worm-like micelles (WLMs) called N, N-dimethyl erucamide tertiary amine (DMETA) as a novel plugging agent where a recovery factor was enhanced by 21.7%. Furthermore (Wang et al., 2021), reported the ternary system comprising of cetyltrimethylammonium bromide (CTAB), sodium salicylate (NaSal), and N, N-dimethylcyclohexylamine (DMCA) as plugging agent with improved gas recovery. Their mechanism involved protonating DMCA by CO₂ injection to induce a structural change from spherical micelles to WLM, reverting to a spherical state upon addition of NaOH Although this technology has been successful, its effectiveness is hindered by surfactant/polymer loss caused by surface adsorption, retention, thermal degradation, and precipitation in a high-temperature and saline environment (Massarweh & Abushaikha, 2022).

In tight reservoirs, CH₄ is found adsorbed to organic matter and clay minerals, in a free state in fractures and pores, and trace amounts as a dissolved gas in the liquid phase. Initially, quick gas is produced from free-state gas while the remaining gas (85%) is accessed by other advanced EGR techniques, like a gas CO₂ injection (S. Liu, Sun, Xu, Li, & Wang, 2020). For technical and economic reasons, CO₂ injection for enhancing gas recovery is coupled with CO₂ sequestration in geological formations. Geological sequestration of CO₂ in depleted reservoirs is widely considered as one of the most effective techniques to reduce greenhouse gas emissions (Du X. et al., 2022). This is due to the fact that kerogen and formation minerals have higher adsorption capacity to CO₂ (Ma, Yue, Li, Xu, & Niu, 2019). The adsorption capacity of CO₂ and CH₄ can be estimated by using experimental and simulation results and then fitted in various isothermal models (Langmuir) (Bemani, Baghban, Mohammadi, & Andersen, 2020). Most findings indicated that more than 60% of the injected CO₂ was adsorbed and the pre-adsorbed CH₄ ejected as shown in Figure 1B. However, the efficacy of CO₂-CH₄ competitive adsorption is still limited by both the reservoir and surrounding environments such as the amount of TOC, kerogen, pressure, and high temperature Adsorption increases with increasing pressure to the optimum level and a higher amount of kerogen since it contains more surface adsorption sites (Kang, Zhang, Kang, Guo, & Zhao, 2020).