Nanofluids are considered promising agents for enhanced oil recovery in low-permeability reservoirs, but their application is often restricted by poor thermal and saline resistance and high costs. Moreover, limited studies have addressed the imbibition depth and oil migration processes during nanofluid imbibition in low-permeability reservoirs. In this work, a magnetic core–shell structured nanoparticle Fe₃O₄–TiO₂ was synthesized using inexpensive Fe₃O₄ nanoparticles and tetrabutyl titanate. The synthesized nanoparticles exhibited excellent thermal and saline resistance as well as recyclability. Their structure and functional properties were characterized. The nuclear magnetic resonance technology was applied to investigate the imbibition depth and the oil migration process during magnetic nanofluid imbibition. Results showed that the magnetic nanofluid possessed interfacial activity, wettability alteration capability, and strong thermal and saline resistance. At 80 ℃, the imbibition recovery of magnetic nanofluid reached 32.19%, 3.59% higher than that of SiO₂ nanofluid. The recycle rate of magnetic nanofluid was 81.31%, effectively reducing operational costs. The final imbibition depth of magnetic nanofluid reached 18.82 mm, with an average imbibition rate of 3.14 mm/d, which is 21.97% higher than that of the SiO₂ nanofluid and 39.10% higher than that of the simulated formation water. The imbibition process of magnetic nanofluid was dominated by capillary forces, with oil in micropores displaced into macropores. We expect that this study can contribute to the effective development of low-permeability reservoirs and provide theoretical guidance for field applications.

Conventional slickwater fracturing fluids undergo severe thermal degradation in high-temperature reservoirs, significantly impairing their drag reduction efficiency and proppant transport capability. To address this limitation, this study presents a novel temperature-resistant slickwater system by incorporating aminated nano-silica with an acrylamide-2-acrylamido-2-methylpropane sulfonic acid copolymer and a flowback aid/clay stabilizer. Macroscopic experiments and molecular dynamics simulations reveal that the system achieves a drag reduction rate of 69.7% at 150 ℃, a 10-percentage-point improvement over the non-reinforced system. It also reduces the proppant settling area by 21.2%, facilitating more uniform proppant distribution toward the fracture distal end, and retains 77.8% of its initial viscosity after thermal aging. Nanoparticles in the system exhibit a synergistic dual-reinforcement mechanism: Their surface adsorption smooths wall roughness and thickens the elastic boundary layer, suppressing turbulence and mitigating energy dissipation; hydrogen bonding and electrostatic interactions between the amino groups of nanoparticles and the moieties of copolymer form an interfacial network, effectively restricting the segmental mobility of the copolymer. This method increases the glass transition temperature of the system by 57.5 ℃, markedly enhancing its thermal stability. Molecular simulations confirm an 18.7% increase in hydrogen bond density and a 23.5% reduction in segmental mobility, collectively stabilizing the polymer against thermal degradation. This study provides valuable insights for developing high-performance fracturing fluids suitable for deep reservoirs.

A gel based on polyacrylamide, exhibiting delayed crosslinking characteristics, emerges as the preferred solution for mitigating degradation under conditions of high temperature and extended shear in ultralong wellbores. High viscosity/viscoelasticity of the fracturing fluid was required to maintain excellent proppant suspension properties before gelling. Taking into account both the cost and the potential damage to reservoirs, polymers with lower concentrations and molecular weights are generally preferred. In this work, the supramolecular action was integrated into the polymer, resulting in significant increases in the viscosity and viscoelasticity of the synthesized supramolecular polymer system. The double network gel, which is formed by the combination of the supramolecular polymer system and a small quantity of Zr-crosslinker, effectively resists temperature while minimizing permeability damage to the reservoir. The results indicate that the supramolecular polymer system with a molecular weight of (268–380) × 10⁴ g/mol can achieve the same viscosity and viscoelasticity at 0.4 wt% due to the supramolecular interaction between polymers, compared to the 0.6 wt% traditional polymer (hydrolyzed polyacrylamide, molecular weight of 1078 × 10⁴ g/mol). The supramolecular polymer system possessed excellent proppant suspension properties with a 0.55 cm/min sedimentation rate at 0.4 wt%, whereas the 0.6 wt% traditional polymer had a rate of 0.57 cm/min. In comparison to the traditional gel with a Zr-crosslinker concentration of 0.6 wt% and an elastic modulus of 7.77 Pa, the double network gel with a higher elastic modulus (9.00 Pa) could be formed only at 0.1 wt% Zr-crosslinker, which greatly reduced the amount of residue of the fluid after gel-breaking. The viscosity of the double network gel was 66 mPa s after 2 h shearing, whereas the traditional gel only reached 27 mPa s.

Fracturing fluid property play a critical role in developing unconventional reservoirs. Deep eutectic solvents (DESs) show fascinating potential for property improvement of clean fracturing fluids (CFFs) due to their low-price, low-toxicity, chemical stability and flexible designability. In this work, DESs were synthesized by mixing hydrogen bond acceptors (HBAs) and a given hydrogen bond donor (HBD) to explore their underlying influence on CFF properties based on the intermolecular interactions. The hydrogen-bonding, van der Waals and electrostatic interactions between DES components and surfactants improved the CFF properties by promoting the arrangement of surfactants at interface and enhancing the micelle network strength. The HBD enhanced the resistance of CFF for Ca²⁺ due to coordination-bonding interaction. The DESs composed of choline chloride (ChCl) and malonic acid show great enhancement for surface, rheology, temperature resistance, salt tolerance, drag reduction, and gel-breaking performance of CFFs. The DESs also improved the gel-breaking CFF-oil interactions, increasing the imbibition efficiencies to 44.2% in 74 h. Adjusting HBAs can effectively strengthen the intermolecular interactions (e.g., HBA-surfactant and HBD-surfactant interactions) to improve CFF properties. The DESs developed in this study provide a novel strategy to intensify CFF properties.

The traditional multi-process to enhance tight oil recovery based on fracturing and huff-n-puff has obvious deficiencies, such as low recovery efficiency, rapid production decline, high cost, and complexity, etc. Therefore, a new technology, the so-called fracturing-oil expulsion integration, which does not need flowback after fracturing while making full use of the fracturing energy and gel breaking fluids, are needed to enable efficient exploitation of tight oil. A novel triple-responsive smart fluid based on “pseudo-Gemini” zwitterionic viscoelastic surfactant (VES) consisting of N-erucylamidopropyl-N,N-dimethyl-3-ammonio-2-hydroxy-1-propane-sulfonate (EHSB), N,N,N′, N′-tetramethyl-1,3-propanediamine (TMEDA) and sodium p-toluenesulfonate (NaPts), is developed. Then, the rheology of smart fluid is systematically studied at varying conditions (CO₂, temperature and pressure). Moreover, the mechanism of triple-response is discussed in detail. Finally, a series of fracturing and spontaneous imbibition performances are systematically investigated. The smart fluid shows excellent CO₂-, thermal-, and pressure-triple responsive behavior. It can meet the technical requirement of tight oil fracturing construction at 140 ℃ in the presence of 3.5 MPa CO₂. The gel breaking fluid shows excellent spontaneous imbibition oil expulsion (~40%), salt resistance (1.2 × 10⁴ mg/L Na⁺), temperature resistance (140 ℃) and aging stability (30 days).

Zero-dimensional (0D) carbon dots exhibit excellent potential as a new oil-displacing agent for unconventional reservoir development. However, the difficulty in size/surface properties control and unclear mechanism hinder their further applications. In this study, amino-modified carbon dots (am-CDs) for oil displacement were facilely synthesized through the rapid polymerization of D-glucose (D-Glc) and 3-aminopropyltriethoxysilane (APTES). The size of am-CDs could be precisely controlled by the reaction condition and quenching achieved by adjusting the pH value to neutral. The surface amine groups endow am-CDs with excellent hydrophilicity and dispersion stability. The 0.30 wt.% nanofluid based on am-CDs with an average size of 2.6 ± 0.040 nm showed remarkable oil recovery efficiency (54.09%) without the addition of surfactant. The oil recovery efficiency of am-CDs is much higher than those of water flooding (30.25%), nano-SiO₂ flooding (36.45%), and amino-free carbon dots (af-CDs) flooding (37.80%). Experimental and theoretical results reveal that am-CDs can be favorably adsorbed on the core surface to modulate the micro-scale wettability, changing the surface from oil-wet to relatively uniform water-wet. Meanwhile, am-CDs can effectively reduce the adhesion force between alkanes and sandstone surfaces, contributing to oil droplets peeling off and oil displacement. This study provides a new strategy for developing efficient carbon dots-based nanofluids for enhanced oil recovery.