In order to improve oil recovery efficiency in low-permeability reservoirs, this study developed amphiphilic Janus-SiO₂ nanoparticles to prepare polymer gel microspheres for enhanced oil recovery (EOR). Firstly, Janus-SiO₂ nanoparticles were synthesized via surface modification using (3-aminopropyl)triethoxysilane and α-bromoisobutyryl bromide. Fourier-transform infrared spectroscopy (FTIR) and scanning electron microscopy (SEM) characterization confirmed the successful grafting of amino and styrene chains, with the particle size increasing from 23.8 nm to 32.9 nm while maintaining good dispersion stability. The Janus nanoparticles exhibited high interfacial activity, reducing the oil–water interfacial tension to 0.095 mN/m and converting the rock surface wettability from oil-wet (15.4°) to strongly water-wet (120.6°), thereby significantly enhancing the oil stripping efficiency. Then, polymer gel microspheres were prepared by reversed-phase emulsion polymerization using Janus-SiO₂ nanoparticles as emulsifiers. When the concentration range of nanoparticles was 0.1–0.5 wt%, the particle size range of polymer gel microspheres was 316.4–562.7 nm. Polymer gel microspheres prepared with a high concentration of Janus-SiO₂ nanoparticles can ensure the moderate swelling capacity of the particles under high-temperature and high-salinity conditions. At the same time, it can also improve the mechanical strength and shear resistance of the microspheres. Core displacement experiments confirmed the dual synergistic effect of this system. Polymer gel microspheres can effectively plug high-permeability zones and improve sweep volume, while Janus-SiO₂ nanoparticles enhance oil displacement efficiency. Ultimately, this system achieved an incremental oil recovery of 19.72%, exceeding that of conventional polymer microsphere systems by more than 5.96%. The proposed method provides a promising strategy for improving oil recovery in low-permeability heterogeneous reservoir development.

The economic loss caused by fracture leakage accounts for 90% of all leakage costs; thus, it is necessary to find the factors that affect the leakage and to study the leakage laws of fractured strata. The advantage of this article is that we introduced fracture index deformation and fracture tortuosity parameters to characterize fracture roughness and fracture characteristic parameters using the logging data analysis method. To explore the mechanism of leakage in essence, this paper, based on fluid mechanics, improves the radial leakage model by adopting the Herschel-Bulkey (H-B) flow type drilling fluid with high calculation accuracy and comprehensively considering the factors such as drilling fluid performance parameters, fracture roughness characteristic parameters, pressure difference between the wellbore and formation, and radial extension length of the drilling fluid. The advantage of the model is that it is solved in an absolutely stable backward Euler difference format. The numerical simulation is carried out by MATLAB. The simulation results revealed that the leakage rate increased as the fracture index deformation coefficient and the fracture opening increased. The leakage rate also increased as the fracture tortuosity parameters decreased and as the fracture smoothened. However, the leakage rate decreased as the drilling fluid consistency coefficient increased. Drilling fluid dynamic shear force had a minor effect on the leakage rate. The higher the pressure difference between the wellbore and the formation, the higher the leakage rate. As the drilling fluid intrusion depth increased, the leakage rate decreased until it reached 0. Two parameters were mainly controlled in order to control the degree of leakage: differential pressure and fracture static width, which has important guiding for adjusting the drilling fluid density and predicting leaks in the field. The solution method of the model in this paper has a certain reference value for the solution of other models in the future. The conclusion can provide reference for numerical simulation, laboratory test, and field application in the future.

Reservoir rocks of the Pearl River Mouth Basin’s Lufeng Sag have low porosity (average porosity 12.6%) and low permeability (average permeability 16.5 mD), requiring hydraulic fracturing to obtain economic production of oil and gas. To contribute to the understanding of these reservoirs, and to promote successful production in the region, we analyzed the mechanical properties of tight sandstone. Moreover, we introduced the shear/tensile strength factor, in combination with the fracture toughness and horizontal stress difference coefficient, as an innovative approach to characterize the ease of forming a complex fracture network after reservoir fracturing. Based on this, we established a fracability evaluation model suitable for offshore low-permeability sandstone reservoirs by an analytic hierarchy process from the perspective of whether the reservoir can form an effective transformation volume and complex fracture network after fracturing. The results indicate that the primary minerals of the target reservoir are quartz and clay minerals, and the natural fractures are not developed. The mechanical properties exhibit a high Young’s modulus (ranging from 30.4 to 34.4 GPa) and high compressive strength (with cohesion between 41 and 45 MPa and an angle of internal friction between 31.0 and 33.5°). The relatively low tensile strength and fracture toughness values are conducive to fracture initiation and extension during the fracturing process. Through the fracability evaluation model constructed in this paper, the depth interval at 4155.1–4172.1 m is identified as a high-quality fractured layer. The results of this study not only provide theoretical guidance for target well and formation selection in the Lufeng Sag, but also have important practical implications for increasing oil and gas production from tight sandstone reservoirs.

The deformation of a thick-walled cylinder under pressure is a classic elastic mechanics problem with various engineering applications. In this study, the displacement of a viscoelastic thick-walled cylinder under internal pressure is investigated via analytical as well as numerical modelling. The fractional Maxwell model is initially introduced to describe the creep deformation of high-strength Q460 steel. Subsequently, an analytical solution to the creep deformation of the thick-walled cylinder under both internal and external pressures is deduced with the corresponding principle. The analytical solution is examined with a numerical simulation that incorporates the fractional Maxwell model by a user-defined subroutine. The numerical simulation agrees well with the analytical solution. The limitations of the current study are also discussed.

The microscopic characteristics and mechanical properties of rocks change after the action of acid on deep shale, which affects the fracturing effect. Accordingly, we designed and conducted indoor experiments related to the changes in macro and microscopic characteristics after the interaction of acid with the shale of Wujiaping Formation, based on which the characteristic law of fracture volume modification after acid fracturing was studied using numerical simulation. The results demonstrate that the pores and fractures are enlarged and the structure is significantly loosened after the acid immersion. And a 15% concentration of hydrochloric acid can effectively dissolve shale. Furthermore, the degree of acid-etching reaction is highly variable because of the different carbonate content, which reveals the strong inhomogeneity of the shale system in the Wujiaping Group reservoir section. After the acid interacted with the shale rock samples, the triaxial compressive strength, elastic modulus, and Poisson’s ratio of shale decreased. Moreover, the evaluation of the effect after acid fracturing simulated by fracturing software revealed that the smaller the value of elastic modulus in shale-based reservoirs, the more favorable the fracture volume modification. This discovery not only provides a theoretical basis for the expansion and extension patterns of acid-fracturing in carbonaceous shale formations but also offers research methods and theoretical insights for the fundamental exploration of other deep-seated oil and gas resources.

To elucidate the lost circulation mechanism in naturally fractured shale, this study employs fluid seepage theory and fracture deformation theory, assumes the polymer-based drilling fluid system behaves as a Herschel–Bulkley (H–B) fluid, and develops a calculation model for lost circulation pressure that comprehensively incorporates fracture geometry, fracture stress state, drilling fluid properties, and the pressure differential between the wellbore and the formation. Research shows that the lost circulation rate of drilling fluid increases with greater initial fracture width, fracture deformation index, fluid consistency coefficient, yield stress, and pressure differential between the wellbore and the formation, while it decreases with increasing fracture radial extension length, fracture roughness, drilling fluid density, and normal stress on the fracture surface. The initial fracture width, fracture radial extension length, and fluid consistency coefficient have a significant influence on the lost circulation rate of drilling fluid. In contrast, the effects of the fracture deformation index and dynamic yield stress are relatively minor, indicating that they are not the primary controlling factors of fracture-induced lost circulation.