High-temperature steam injection is a primary method for viscosity reduction and recovery in heavy oil reservoirs. However, due to the high mobility of steam, channeling often occurs within the reservoir, leading to reduced thermal efficiency and challenges in enhancing oil production. Foam fluids, with their dual advantages of selective plugging and efficient oil displacement, are widely used in steam-injection heavy oil recovery. Nonetheless, conventional foams tend to destabilize under high-temperature conditions, resulting in poor stability and suboptimal plugging performance, which hampers the efficient development of heavy oil resources. To address these technical challenges, this study introduces a foam system reinforced with Janus nano-graphite, a high-temperature stabilizer characterized by its small particle size and thermal resistance. The foaming agents used in the system are sodium α-olefin sulfonate (AOS), an anionic surfactant, and octadecyl hydroxylpropyl sulfobetaine (OHSB), a zwitterionic surfactant. Under conditions of 250 °C and 5 MPa, the foam system achieved a half-life of 47.8 min, 3.4 times longer than conventional foams. Janus nano-graphite forms a multidimensional network structure in the liquid phase, increasing internal friction and enhancing shear viscosity by 1.2 to 1.8 times that of conventional foams. Furthermore, the foam gel system demonstrated effective steam-channeling control in heterogeneous heavy oil reservoirs, particularly in reservoirs with permeability differentials ranging from 3 to 9. These findings suggest that the Janus nano-graphite reinforced foam system holds significant potential for steam-channeling mitigation in heavy oil reservoirs.

To address the problem of serious gas channeling during CO₂ flooding in low-permeability reservoirs, which leads to poor oil recovery, this study developed a CO₂-resistant gel using a novel CO₂-responsive polymer (ADA) for gas channel control. The ADA polymer was synthesized via free-radical copolymerization of acrylamide (AM), dimethylaminopropyl methacrylamide (DMAPMA), and 2-acrylamido-2-methylpropanesulfonic acid (AMPS), which introduced protonatable tertiary-amine groups and sulfonate moieties into the polymer backbone. Comprehensive characterizations confirmed the designed structure and adequate thermal stability of the ADA polymer. Rheological tests demonstrated that the ADA polymer solution exhibits significant CO₂-triggered viscosity enhancement and excellent shear resistance. When crosslinked with phenolic resin, the resulting ADA gel showed outstanding CO₂ tolerance under simulated reservoir conditions (110 °C, 10 MPa). After 600 s of CO₂ exposure, the ADA gel retained over 99% of its initial viscosity, whereas a conventional HPAM-based industrial gel degraded to 61% of its original viscosity. The CO₂-resistance mechanism involves protonation of tertiary amines to form quaternary ammonium salts, which electrostatically interact with sulfonate groups, creating a reinforced dual-crosslinked network that effectively protects the gel from H⁺ ion attack. Core flooding experiments confirmed its ability to enhance oil recovery by plugging high-permeability channels and diverting flow, achieving a final recovery of up to 48.5% in heterogeneous cores. This work provides a novel gel system for improving sweep efficiency and storage security during CO₂ flooding in low-permeability reservoirs.

Unconventional low-permeability reservoirs present significant production challenges due to the poor imbibition and displacement efficiency of conventional polymer fracturing fluids. The injection of nanoparticle (NP) compounds into polymer fracturing fluid base systems, such as linear gels or slickwater, has garnered significant research interest due to their superior performance. However, previous studies have primarily focused on evaluating the fluid’s properties, while its imbibition and oil displacement mechanisms within reservoirs remain unclear. Herein, the imbibition mechanism of nanoparticle composite polymer fracturing fluid was systematically investigated from macro and micro perspectives using low-field nuclear magnetic resonance (LF-NMR), atomic force microscopy (AFM), interfacial rheology, and other technical means. The results showed that the imbibition recovery using polymer fracturing fluid was 10.91% higher than that achieved with conventional slickwater. Small and medium pores were identified as the primary contributors to oil drainage. Nanoparticles can be adsorbed on the rock wall in the deep reservoir to realize wettability reversal from oil-wet to water-wet, reducing crude oil adhesion. Furthermore, a strong interaction between the adsorbed NPs and cleanup agents at the oil–water interface was observed, which reduces interfacial tension to 0.95 mN·m⁻¹, mitigates the Jamin effect, and enhances interfacial film deformability. NPs increase the interfacial dilatational modulus from 6.0 to 14.4 mN·m⁻¹, accelerating fluid exchange and oil stripping. This work provides a consolidated mechanistic framework linking NP-induced interfacial modifications to enhanced pore-scale drainage, offering a scientific basis for designing next-generation fracturing fluids. We conclude that NP-compound systems hold strong potential for low-permeability reservoir development, and future efforts must focus on optimizing NP parameters for specific reservoir conditions and overcoming scalability challenges for field deployment.

CO₂ flooding is an effective technique for enhancing oil recovery in low-permeability reservoirs. However, it is often hindered by severe CO₂ channeling. This challenge is particularly pronounced in near-wellbore regions with large pressure differentials and in fractured reservoirs, where high CO₂ injection rates and rapid breakthrough require channel blocking systems with high mechanical strength and excellent CO₂-resistant performance. In this work, a smart responsive polymer was synthesized and subsequently crosslinked with a highly active phenolic resin crosslinking agent to develop a smart responsive polymer gel channel blocking system. The resulting gel exhibits CO₂-responsive strength enhancement and excellent CO₂-resistant performance. The static and dynamic gelation behaviors, nonlinear rheological properties, CO₂-resistant performance, channel blocking, and enhanced oil recovery performance of the smart responsive polymer gel were systematically investigated. The results demonstrate that the polymer gel maintains good structural stability during dynamic transport in the reservoir and does not undergo significant strength degradation under shear conditions. Moreover, the smart responsive polymer gel exhibits excellent CO₂-resistant performance within a temperature range of 80–110 °C, salinity up to 10 × 10⁴ mg/L, and pressure up to 20 MPa. Moreover, the system shows a significant enhancement in channel blocking and enhanced oil recovery performance, highlighting its promising potential for effective CO₂ flooding channel blocking in low-permeability reservoirs.