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.

The intensive development of tight reservoirs has positioned them as a strategic alternative to conventional oil and gas resources. Existing enhanced oil recovery (EOR) methods struggle to effectively exploring reservoir oil, resulting in low recovery rates. Novel and effective means of developing tight reservoirs are urgently needed. Nanomaterials have shown promising applications in improving water flooding efficiency, with in-depth research into mechanisms that lower injection pressure and increase water injection volumes. However, the extent of improvement remains limited. In this study, a silicon quantum dots (Si-QDs) material was synthesized via a hydrothermal synthesis method and used to prepare a nanofluid for the efficient recovery of tight reservoir. The Si-QDs, with an approximate diameter of 3 nm and a spherical structure, were surface functionalized with benzenesulfonic acid groups to enhance the performance. The developed nanofluid demonstrated stability without aggregation at 120 ℃ and a salinity of 60000 mg/L. Core flooding experiments have demonstrated the attractive EOR capabilities of Si-QDs, shedding light of the EOR mechanisms. Si-QDs effectively improve the wettability of rocks, enhancing the sweeping coefficient of injected fluids and expanding sweeping area. Within this sweeping region, Si-QDs efficiently stripping adsorbed oil from the matrix, thus increasing sweeping efficiency. Furthermore, Si-QDs could modify the state of pore-confined crude oil, breaking it down into smaller particles that are easier to displacement in subsequent stages. Si-QDs exhibit compelling EOR potential, positioning them as a promising approach for effectively developing tight oil reservoirs.

Nanoparticles (NPs) have gained significant attention as a functional material due to their ability to effectively enhance pressure reduction in injection processes in ultra-low permeability reservoirs. NPs are typically studied in controlled laboratory conditions, and their behavior in real-world, complex environments such as ultra-low permeability reservoirs, is not well understood due to the limited scope of their applications. This study investigates the efficacy and underlying mechanisms of NPs in decreasing injection pressure under various injection conditions (25–85 ℃, 10–25 MPa). The results reveal that under optimal injection conditions, NPs effectively reduce injection pressure by a maximum of 22.77% in core experiment. The pressure reduction rate is found to be positively correlated with oil saturation and permeability, and negatively correlated with temperature and salinity. Furthermore, particle image velocimetry (PIV) experiments (25 ℃, atmospheric pressure) indicate that the pressure reduction is achieved by NPs through the reduction of wall shear resistance and wettability change. This work has important implications for the design of water injection strategies in ultra-low permeability reservoirs.

Slickwater fracturing fluids have gained widespread application in the development of tight oil reservoirs. After the fracturing process, the active components present in slickwater can directly induce spontaneous imbibition within the reservoir. Several variables influence the eventual recovery rate within this procedure, including slickwater composition, formation temperature, degree of reservoir fracture development, and the reservoir characteristics. Nonetheless, the underlying mechanisms governing these influences remain relatively understudied. In this investigation, using the Chang-7 block of the Changqing Oilfield as the study site, we employ EM-30 slickwater fracturing fluid to explore the effects of the drag-reducing agent concentration, imbibition temperature, core permeability, and core fracture development on spontaneous imbibition. An elevated drag-reducing agent concentration is observed to diminish the degree of medium and small pore utilization. Furthermore, higher temperatures and an augmented permeability enhance the fluid flow properties, thereby contributing to an increased utilization rate across all pore sizes. Reduced fracture development results in a lower fluid utilization across diverse pore types. This study deepens our understanding of the pivotal factors affecting spontaneous imbibition in tight reservoirs following fracturing. The findings act as theoretical, technical, and scientific foundations for optimizing fracturing strategies in tight oil reservoir transformations.

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).

Due to the low porosity and low permeability in unconventional reservoirs, a large amount of crude oil is trapped in micro-to nano-sized pores and throats, which leads to low oil recovery. Nanofluids have great potential to enhance oil recovery (EOR) in low permeability reservoirs. In this work, the regulating ability of a nanofluid at the oil/water/solid three-phase interface was explored. The results indicated that the nanofluid reduced the oil/water interfacial tension by two orders of magnitude, and the expansion modulus of oil/water interface was increased by 77% at equilibrium. In addition, the solid surface roughness was reduced by 50%, and the three-phase contact angle dropped from 135° (oil-wet) to 48° (water-wet). Combining the displacement experiments using a 2.5D reservoir micromodel and a micro-channel model, the remaining oil mobilization and migration processes in micro-to nano-scale pores and throats were visualized. It was found that the nanofluid dispersed the remaining oil into small oil droplets and displaced them via multiple mechanisms in porous media. Moreover, the high strength interface film formed by the nanofluid inhibited the coalescence of oil droplets and improved the flowing ability. These results help to understand the EOR mechanisms of nanofluids in low permeability reservoirs from a visual perspective.