The plugging performance and degradation properties of temporary plugging agents remain critical challenges in diverting fracturing technology for deep, high-temperature reservoirs. Conventional particle–fiber systems are constrained by strict size-matching requirements and poor thermal stability, often failing to achieve reliable plugging in complex, high-temperature reservoirs. To overcome these limitations, this study presents a gel–fiber composite plugging strategy based on in situ gelation. This method employs a pre-gel solution as a carrier for fibers, with elevated temperatures inducing in situ polymerization to form a fiber-reinforced gel. Results demonstrate that the optimized pre-gel solution maintains low viscosity during surface preparation and wellbore flow, while rapidly gelling within 0.33 h at 180 ℃, ensuring good injectability and controllable gelation. The incorporation of fibers significantly enhances the mechanical properties of the gel, increasing the elastic modulus from 180 Pa to over 3300 Pa and maintaining stability under cyclic shear strains ranging from 10% to 200%. In simulated fracture sealing experiments, the composite system achieved a sealing pressure gradient exceeding 49 MPa·m⁻¹ for 2–3 mm fractures, representing a 2.8-fold increase compared to the pure gel system. Moreover, all components degrade into low-viscosity fluids under high-temperature conditions, facilitating flowback. This study provides a novel temporary plugging strategy for deep, high-temperature unconventional reservoirs, featuring high strength, degradability, and broad adaptability for efficient diverting fracturing.

During oil displacement, surfactants often encounter challenges such as emulsion instability and channeling, which can compromise their efficiency. To address these issues, polymer microspheres were synthesized via reverse microemulsion polymerization using acrylamide, 2-methyl-2-acrylamidopropane sulfonic acid, and stearyl methacrylate as monomers, with N,N-methyl-enebisacrylamide as the crosslinker. The microspheres were then combined with sodium alkyl alcohol polyoxyethylene ether carboxylate to enhance emulsion stability and expand the swept volume of surfactant. A stable reverse microemulsion system was prepared using the maximum water solubilization rate as the indicator, and microspheres were synthesized based on this system. The ability of the microspheres to enhance emulsion stability was systematically evaluated. The plugging performance and enhanced oil recovery (EOR) efficiency of the microsphere/surfactant composite system were assessed through core seepage and oil displacement experiments. The experimental results demonstrated that microspheres were successfully prepared in a water-in-oil reverse microemulsion system with a solubilization rate of 42%. The emulsion stability was evaluated under an oil-to-water ratio of 7:3, a temperature of 80 °C, and a salinity of 44,592 mg/L, by manually shaking the test tube five times. It was observed that the complete phase separation time of the emulsion increased from 10 to 120 min after the addition of microspheres. Under different permeability conditions (100 × 10⁻³, 300 × 10⁻³, 500 × 10⁻³ μm²), the recovery efficiency of the composite system increased by 4.5%, 8.3%, and 4.8%, respectively, compared to a single surfactant system. The microspheres developed in this study enhanced emulsion stability and increased the swept volume of surfactant within the formation, significantly boosting its oil recovery efficiency.

During CO₂ transportation and storage, metal equipment such as oilfield pipelines suffers from severe CO₂ corrosion, especially in harsh downhole injection equipment. In this study, we investigated the corrosion behavior of oil well tubing in a high-temperature, high-pressure (HTHP) CO₂-containing environment. The evolution of the corrosion scale was also examined under different flow regimes. The results reveal a lower corrosion rate at 150 ℃ compared to 80 ℃ under different flow regimes, with localized corrosion intensifying as temperature and rotational speeds (v_rs) increase. The temperature also induces the corrosion scale conversion of aragonite-type CaCO₃ (80 ℃) to calcite-type CaCO₃ (150 ℃). Specifically, the variation of the corrosion rate and the corrosion scale evolution can be attributed to the vortices within the reactor. The intact vortex cells enhance mass transfer while also promoting nucleation and growth of CaCO₃. However, when v_rs exceeds the critical Reynolds number, the vortex cells are disrupted, resulting in viscous dissipation and a reduced corrosion rate.