Low-permeability oil and gas reservoirs, which account for roughly 38% of global fields and 46% of those in China, present formidable challenges for extraction. These formations often lack sufficient natural energy and resist conventional water injection, resulting in low recovery rates. For China, effective development of such reservoirs carries strategic weight in sustaining domestic oil and gas production.
CO₂ flooding has emerged as a favored enhanced oil recovery (EOR) technique in these environments. Its appeal lies in CO₂’s high solubility and strong extraction capability, which help reduce crude oil viscosity, improve mobility ratios, expand oil volume, and lower interfacial tension. Yet, the method is hampered by the tendency of CO₂ to channel through high-permeability zones, particularly in fractured formations. This channeling bypasses large portions of the reservoir, diminishing sweep efficiency.
Conventional countermeasures—such as water-alternate-gas (WAG) injection, foam plugging, and polymer gel barriers—often suffer from one-time effectiveness, leaving persistent channeling unaddressed. Recent research has focused on CO₂-responsive materials (CRMs), which change their physical structure upon contact with CO₂, enabling dynamic and repeatable plugging of flow paths.
The principle is straightforward: in a CO₂-saturated environment, amine-containing compounds either spontaneously form or combine with surfactant molecules to create worm-like micelles (WLMs). These elongated micelles increase solution viscosity, delivering precise blockage in fractures, throats, and pores.
One class of CRMs is CO₂-responsive foams. Laboratory work by Lv et al. demonstrated a foam system with pronounced shear-thinning behavior and viscoelasticity far exceeding conventional foams—its foam composite index (FCI) was over eleven times higher. Li et al. identified ODPTA, a surfactant with an amine group and an 18-carbon chain, as particularly effective. In acidic conditions induced by dissolved CO₂, ODPTA’s amine group protonates, forming ion pairs that yield a foam capable of maintaining high resistance factors—up to 274—even under extreme conditions of 7.8 MPa and 160°C.
CO₂-responsive surfactants offer another route. Su et al. prepared an anionic WLM system using sodium octadecyl sulfate and N,N-dimethylethanolamine (DMAE) at 60°C. Under CO₂ stimulation, DMAE protonates and electrostatically binds with the surfactant to form WLMs, dramatically increasing viscosity. Injecting nitrogen reverses the process, returning viscosity to baseline, and this cycle can be repeated multiple times without significant deviation. Shen et al. found that N,N-Dimethyl Erucamide tertiary amine (DMETA) formed stable WLMs in CO₂-rich solutions, effectively reducing gas flow in fractured cores while withstanding high temperatures. The self-repairing nature of these micelles preserved residual resistance even after channeling events.
CO₂-responsive gels extend the concept into three-dimensional network structures. These gels address the poor acid resistance of conventional HPAM polymers. Upon CO₂ treatment, cross-linking increases viscosity and volume, maintaining stability in acidic conditions. Dai et al. developed a gel system combining small molecule amine DMTA with a modified long-chain alkyl anionic surfactant (NADS). Electron microscopy revealed a transformation from lamellar arrangements to interconnected networks, while NMR confirmed amine-mediated bridging between surfactant molecules. Core flooding experiments showed over 90% blocking efficiency, expanding sweep volume and boosting recovery.
Across foams, surfactants, and gels, the underlying mechanism remains consistent: CO₂ triggers molecular reconfiguration, forming micellar or gel structures that sharply increase viscosity. Before gelling, these solutions exhibit low viscosity—around 1–2 mPa·s—facilitating injection. Once in place, CO₂ exposure rapidly transforms them into high-viscosity barriers capable of withstanding harsh reservoir conditions, including elevated temperatures and salinity.
Compared to traditional plugging agents, CRMs offer a more adaptable and repeatable approach, particularly suited to tight, fractured reservoirs. By tailoring surfactant and amine types, concentrations, and CO₂ injection parameters, engineers can fine-tune these systems for specific reservoir characteristics. Current research emphasizes developing low-cost, high-tolerance CRMs to enhance production capacity and economic returns from challenging formations.