Summary: Various types of temporary plugging agents are used in hydraulic fracturing to promote the uniform propagation of multicluster hydraulic fractures and increase the complexity of hydraulic fractures. However, the plugging behavior of these agents in hydraulic fractures has not yet been fully clarified, making the optimization of temporary plugging formulas challenging. In this study, dozens of plugging experiments were carried out to reveal the plugging behavior of pure fiber, pure particle, and fiber-particle combination materials in hydraulic fractures. The results indicate that the high fiber concentration and long fibers are beneficial to obtaining high maximum plugging pressures. However, the low tensile strength of fibers makes it difficult to form stable plugging layers under high pressure, especially for wide fractures. For particle plugging agents, the high rigidity of the particles prevents them from compacting tightly within the plugging layer, resulting in high permeability and low temporary plugging pressure. Excessive particle diameter and concentration tend to cause rapid blockage at the fracture entrance, leading to poor plugging performance. In contrast, the fiber-particle composite plugging scheme can form a stable and tight plugging layer at lower concentrations of both fibers and particles. Moreover, replacing single-size particles in composite with multisize particles can further enhance the plugging effect, allowing for a higher plugging pressure with a lower dosage of temporary plugging agents. Comprehensively considering the effects of material concentration and size on the plugging effect, the critical plugging quantitative characterization equations for pure fiber, pure particle, and fiber-particle combination plugging schemes are established respectively, with fracture width as the independent variable and the product of material concentration and size as the dependent variable. The temporary plugging schemes for various hydraulic fracture widths can be preliminarily determined using these equations. Based on the principle of economic optimization, the optimal temporary plugging schemes with consideration of the plugging pressure requirements were selected, which have shown good field application performance.

The conventional liquid acid has several shortcomings in the acidizing process of fractured-vuggy carbonate reservoirs, including high filtration loss, fast reaction rate, high friction resistance, and difficult flowback. To address these issues, a new atomizing acid acidizing technology is proposed, combining the gas injection development practice from the fractured-vuggy carbonate reservoir in the Tahe oilfield. The laboratory experiments were conducted to optimize the type and concentration of atomized acid, iron ion stabilizer, corrosion inhibitor, and atomization stabilizer. The acid atomization rate was evaluated under different combinations of gas and liquid injection flows using a self-made atomized acid well migration simulator, and the best atomization scheme was selected. Furthermore, a kinetic experiment for the acid–rock reaction was carried out to evaluate the retarding performance of the atomized acid. The optimized formula for the atomizing acid system consists of 15~25% hydrochloric acid, 0.005% atomizing stabilizer (AEO-7), 1% iron ion stabilizer (EET), 1.5% corrosion inhibitor (EEH-160), and water. The optimal gas and acid injection scheme is gas injection at 2m3/min and acid injection at 10 mL/min, which maintains an atomization rate of over 80% after the acid mist migrates through the wellbore. Compared with gelling acid, the acid–rock reaction rate of atomized acid is 8.5, 9.1, and 10.6 times slower under acid concentrations of 15%, 20%, and 25% respectively. The retarding effect of atomized acid is superior, facilitating etching and initiating underdeveloped gas drive channels and thereby increasing the probability of gas communication with new reservoirs. The research findings presented in this paper establish a theoretical foundation for the practical implementation of the atomized acid acidizing process in the field.

Proppant transport in complex fracture networks strongly influences the effectiveness of volumetric hydraulic fracturing in deep shale reservoirs; however, experimental investigations remain limited by the scale and structural complexity of existing laboratory models. In this study, large-scale physical experiments were conducted using a self-designed fracture system consisting of a main fracture and multi-level tertiary branch fractures to investigate proppant transport and placement behavior under different operational conditions. Twelve experimental cases were performed by varying injection rate, fracturing fluid viscosity, proppant concentration, proppant type, and particle-size pumping sequence. The results show that increasing the injection rate and fluid viscosity improves the proppant transport capacity and promotes proppant migration into tertiary branch fractures, increasing the proppant distribution ratio by 6.58%, while the placement proportion in the main fracture decreases by 15.92%. Increasing the proppant concentration enhances proppant placement in all fracture levels, with the placement ratio of quartz sand increasing by 10–15%, but excessive concentration causes accumulation and bridging near the fracture entrance. Under identical conditions, ceramic proppant exhibits better overall placement performance than quartz sand, with a 22.81% higher placement ratio in the main fracture. In addition, the pumping sequence significantly affects proppant distribution; the large–small–large particle-size sequence achieves the highest placement ratio of 74.52%. These results provide quantitative experimental evidence for optimizing proppant injection strategies and fracturing parameters in deep shale reservoirs.

Interbedded shale reservoirs commonly contain multiple lithologies, such as shale and limestone, resulting in heterogeneous long-term fracture conductivity under identical proppant conditions. This lithological heterogeneity introduces uncertainty into proppant design and may lead to uneven stimulation effectiveness. This study investigates the effects of lithology, proppant size, and proppant areal concentration on the evolution of propped fracture conductivity and develops lithology-dependent empirical correlations to quantitatively describe long-term conductivity evolution within the tested parameter ranges. Conductivity experiments were performed using shale and limestone rock plates under simulated reservoir conditions of 80 °C and 40 MPa closure stress, with a long-term loading duration of 50 h. The results indicate that propped fracture conductivity exhibits strong stress sensitivity and time-dependent degradation. Continuous compaction of the proppant pack and reduction in effective flow channels are considered possible mechanisms contributing to conductivity loss during long-term loading. Under identical proppant parameters, limestone fractures generally exhibit higher long-term conductivity, while the difference in conductivity retention depends on proppant conditions rather than shale fractures, with the lithological difference becoming more pronounced under low-proppant-concentration and small-proppant-size conditions. Within the directly comparable conditions of 5 and 7.5 kg/m², increasing proppant size and areal concentration generally reduced the conductivity difference observed between shale and limestone fractures. For shale fractures, the experiments covering 5, 7.5, and 10 kg/m² further showed that the effect of areal concentration depended on proppant size. Based on the experimental data, lithology-dependent empirical correlations were established for shale and limestone fractures and evaluated using leave-one-condition-out cross-validation. The correlations provide a quantitative description of conductivity evolution within the tested parameter ranges. This study identifies lithology-dependent conductivity responses within the investigated proppant conditions and provides experimental evidence for adapting proppant design to heterogeneous interbedded shale reservoirs.