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.

CO₂ injection into geological formations has been proven to be an effective approach for carbon storage. When dissolved in formation water, CO₂ forms carbonic acid that induces mineral dissolution at pore surfaces under acidic conditions. Comprehensive understanding of geochemical interaction between carbonic acid and reservoir rocks is crucial for assessing environmental impact on geological formations. This study focuses on a tight oil sandstone reservoir. After characterizing basic petrophysical properties and mineral composition of rock samples, a series of carbonic acid corrosion experiments with both core and corresponding pure mineral samples were carried out, respectively. Dissolution solutions collected during the experiments were analyzed to examine the variations of ion concentrations in both core and pure mineral solutions. The carbonic acid–pure mineral corrosion kinetics were investigated. The correlations between carbonic acid with core and pure mineral corrosion scenarios were established from the sample mass, reaction rate, and ion concentration. The results show that after corrosion, the mass of calcite and dolomite in the rock sample decreased by 66.7% and 27.3%, respectively. When the corrosion was stabilized, the concentrations of Ca²⁺ and Mg²⁺ in the core solution were 72.9 and 74.4 mg/L, respectively, which was 40.5–41.3 times higher than that of Na⁺. The reaction kinetics analysis of carbonic acid–rock revealed a two-stage reaction in the pure mineral corrosion process, rapid reaction stage, and slow reaction stage, with different reaction rate constants and reaction orders for each ion. With the correlation between carbonic acid reaction with core and pure minerals, an effective and rapid evaluation method with pure minerals for the carbonic water–rock reaction is established, which costs a shorter time and is easier to investigate. This study provides a simple and faster method to evaluate the carbonic acid corrosion reaction during geological carbon storage.