To construct the in-situ emulsification and viscosification system that is suitable for low permeability oil reservoirs characterized by high-temperature and high-salt, the amphiphilic Janus SiO₂ nanoparticles and Tween 60/Imidazoline oleate surfactant system were combined. The mechanism of in-situ emulsification and viscosification system was elucidated from two aspects: The dynamic adsorption and phase conversion of surfactant, and the unique bridge structure of Janus nanoparticle stabilized emulsion. The successful synthesis of Janus SiO₂ nanoparticles with varying degrees of hydrophilicity and hydrophobicity was achieved through regulating the reaction conditions. Based on emulsion stability, the optimization of the modification degree of Janus SiO₂ nanoparticles was achieved. The in-situ emulsification and viscosification system was constructed by introducing Tween 60/Imidazoline oleate as dispersion aid agent and emulsifier. Notably, the in-situ emulsification and viscosification system can be stably dispersed for more than 12 hours in high-temperature and high-salt. The dispersion stability of the in-situ emulsification and viscosification system was evaluated qualitatively by visual inspection, Turbiscan stability index and monitoring particle size. The emulsification ability, emulsion stability and rheological properties of the systems with different concentrations were evaluated at 90 ℃ and a salinity of 35,000 ppm. It was found that the in-situ emulsification and viscosification system with the concentration of 0.64 wt% shows better profile control and enhanced recovery performance. This study presents a new approach for profile control using amphiphilic Janus nanoparticles and provides a promising prospect for applying nanoparticles in the field of enhanced oil recovery.

Fine particle detachment and subsequent migration can lead to severe pore plugging and consequent permeability decline. Therefore, it is crucial to quantify the critical condition when fine particle detachment occurs. The frequently observed deviations or even contradictions between experimental results and theoretical predictions of fines detachment arise from an insufficient understanding of adhesion force that can be highly influenced by salinity and temperature. To clarify the intrinsic influence of salinity and temperature on fines detachment, adhesion forces between carboxyl microspheres and hydrophilic silica substrates in an aqueous medium were measured at various salinities and temperatures using atomic force microscopy (AFM). The AFM-measured adhesion force decreases with increasing salinity or temperature. Trends of mean measured adhesion forces with temperature and salinity were compared with the DLVO and XDLVO theories. DLVO theory captured the trend with temperature via the impact of temperature on electric double layer interactions, whereas XDLVO theory captured the observed trend with salinity via the impact of salinity on the repulsive hydration force. Our results highlight the significance of hydration force in accurately predicting the fate of fines in porous media.

Inadequate strength and stability of active crude oil emulsions stabilized by conventional surfactants always lead to a limited plugging rate of plugging agents. Thus, to address this issue, the synthesis of amphiphilic Janus nanosheets was effectively carried out for enhancing the system performances and subsequently characterized. Based on the outcomes of orthogonal tests, an assessment was conducted on the nanosheet and surfactant formulations to optimize the enhancement of emulsion properties. The experimental demonstration of the complex system has revealed its remarkable emulsifying capability, ability to decrease interfacial tension and improve rheological behavior at high temperature (80 ℃) and high salinity (35,000 ppm) conditions. Involving probable mechanism of the system performance enhancement is elucidated by considering the synergistic effect between surfactants and nanosheets. Furthermore, variables including water-to-oil ratio, salinity, temperature and stirring intensity during operation, which affect the properties of prepared emulsions, were investigated in detail. The efficacy and stability of the complex system in obstructing medium and high permeability cores were demonstrated. Notably, the core with a high permeability of 913.58 mD exhibited a plugging rate of 98.55%. This study establishes the foundations of medium and high permeability reservoirs plugging with novel active crude oil plugging agents in severe environments.

Emulsification is one of the important mechanisms of surfactant flooding. To improve oil recovery for low permeability reservoirs, a highly efficient emulsification oil flooding system consisting of anionic surfactant sodium alkyl glucosyl hydroxypropyl sulfonate (APGSHS) and zwitterionic surfactant octadecyl betaine (BS-18) is proposed. The performance of APGSHS/BS-18 mixed surfactant system was evaluated in terms of interfacial tension, emulsification capability, emulsion size and distribution, wettability alteration, temperature-resistance and salt-resistance. The emulsification speed was used to evaluate the emulsification ability of surfactant systems, and the results show that mixed surfactant systems can completely emulsify the crude oil into emulsions droplets even under low energy conditions. Meanwhile, the system exhibits good temperature and salt resistance. Finally, the best oil recovery of 25.45% is achieved for low permeability core by the mixed surfactant system with a total concentration of 0.3 wt% while the molar ratio of APGSHS:BS-18 is 4:6. The current study indicates that the anionic/zwitterionic mixed surfactant system can improve the oil flooding efficiency and is potential candidate for application in low permeability reservoirs.

Conformance control and water plugging are a widely used EOR method in mature oilfields. However, majority of conformance control and water plugging agents are unavoidable dehydrated situation in high-temperature and high-salinity low permeability reservoirs. Consequently, a novel conformance control system HPF-Co gel, based on high-temperature stabilizer (CoCl₂·H₂O, CCH) is developed. The HPF-Co bulk gel has better performances with high temperature (120 °C) and high salinity (1×10⁵ mg/L). According to Sydansk coding system, the gel strength of HPF-Co with CCH is increased to code G. The dehydration rate of HPF-Co gel is 32.0% after aging for 150 d at 120 °C, showing excellent thermal stability. The rheological properties of HPF gel and HPF-Co gel are also studied. The results show that the storage modulus (G′) of HPF-Co gel is always greater than that of HPF gel. The effect of CCH on the microstructure of the gel is studied. The results show that the HPF-Co gel with CCH has a denser gel network, and the diameter of the three-dimensional network skeleton is 1.5–3.5 μm. After 90 d of aging, HPF-Co gel still has a good three-dimensional structure. Infrared spectroscopy results show that CCH forms coordination bonds with N and O atoms in the gel amide group, which can suppress the vibration of cross-linked sites and improve the stability at high temperature. Fractured core plugging test determines the optimized polymer gel injection strategy and injection velocity with HPF-Co bulk gel system, plugging rate exceeding 98%. Moreover, the results of subsequent waterflooding recovery can be improved by 17%.

Nanotechnology has been increasingly applied in the petroleum industry in recent years. In particular, dispersions consisting of nanoparticles and surfactants have been widely investigated. The imbibition system compounded by nanoparticle and surfactant was found to display a high efficiency in enhancing oil recovery. This paper briefly reviews the factors influencing imbibition efficiency. At the same time, the application and mechanism of the imbibition system of nanoparticle-surfactant dispersion in the field of enhanced oil recovery are introduced. Additionally, the limitations and challenges that the imbibition system of nanoparticle-surfactant dispersions may face in enhanced oil recovery applications are put forward. The current work reveals that the imbibition system with nanoparticle-surfactant dispersion is an ideal candidate for enhanced oil recovery in tight and low-permeability reservoirs.

Tight conglomerate reservoirs are featured with extremely low permeability, strong heterogeneity and poor water injectivity. CO₂ huff-n-puff has been considered a promising candidate to enhance oil recovery in tight reservoirs, owing to its advantages in reducing oil viscosity, improving mobility ratio, quickly replenishing formation pressure, and potentially achieving a miscible state. However, reliable in-house laboratory evaluation of CO₂ huff-n-puff in natural conglomerate cores is challenging due to the inherent high formation pressure. In this study, we put forward an equivalent method based on the similarity of the miscibility index and Grashof number to acquire a lab-controllable pressure that features the flow characteristics of CO₂ injection in a tight conglomerate reservoir. The impacts of depletion degree, pore volume injection of CO₂ and soaking time on ultimate oil recovery in tight cores from the Mahu conglomerate reservoir were successfully tested at an equivalent pressure. Our results showed that oil recovery decreased with increased depletion degree while exhibiting a non-monotonic tendency (first increased and then decreased) with increased CO₂ injection volume and soaking time. The lower oil recoveries under excess CO₂ injection and soaking time were attributed to limited CO₂ dissolution and asphaltene precipitation. This work guides secure and reliable laboratory design of CO₂ huff-n-puff in tight reservoirs with high formation pressure.