The combination of extreme formation pressure, significant burial depth, and dense lithology in deep and ultra-deep reservoirs results in abnormal fracturing pressure behavior. This phenomenon elevates operational pressures during fracturing acidizing treatments while amplifying associated engineering risks. Precise prediction of both reservoir fracturing pressure and pump injection pressure has become imperative under current technological constraints to ensure operational safety and successful reservoir stimulation. This study establishes a comprehensive fracturing pressure prediction framework through: Developing rock fracturing pressure models for open-hole and perforated completions based on near-wellbore stress distribution characteristics. Investigating fracture initiation mechanisms and corresponding computational models for perforation-altered stress fields. Deriving damage-adapted calculation models that account for stress variations in both completion types under formation impairment conditions. Numerical simulations demonstrate critical findings revealed that perforated completions reduce reservoir fracturing pressure by 10–15% compared to open-hole configurations, proving effective for pressure management. Formation damage induces stress redistribution, increasing fracturing pressure by 8–12%—a crucial factor for treatment design optimization. Maximum pressure reduction (18–22%) occurs when perforation orientation aligns within ± 40° of the maximum horizontal stress direction, beyond which fracture deviation triggers abrupt pressure escalation. Perforation density shows linear correlation with pressure reduction (3–5% decrease per 2 shots/m increase), while perforation dimensions exhibit limited impact (< 1% variation). The developed multi-completion prediction methodology provides dual engineering benefits: It enhances operational safety for hydraulic fracturing in deep reservoirs through reliable pressure forecasting, while serving as a strategic optimization tool for completion design—particularly in maximizing hydrocarbon recovery from challenging deep formations. This approach establishes a critical technical foundation for economically viable development of deep petroleum resources.

Geothermal energy, recognized as a sustainable and clean resource, is playing an increasingly critical role in the global shift toward low-carbon energy systems. Nevertheless, the exploitation of fractured geothermal reservoirs is often impeded by severe lost circulation during drilling, where conventional plugging materials fail under high-temperature, high-salinity, and high-pressure conditions due to inadequate mechanical strength, poor thermal resistance, and lack of self-adaptive sealing behavior. In response, self-healing materials have emerged as an innovative strategy for developing intelligent lost circulation control technologies. Herein, we report a novel self-healing gel (XFFD) synthesized via inverse emulsion polymerization using acrylamide (AM), acrylic acid (AA), p-nitroblue tetrazolium (PNBT), and modified silica nanoparticles (PAS). The resulting material exhibits exceptional thermal stability, with decomposition onset above 356 °C, as determined by thermogravimetric analysis. Rheological and mechanical assessments reveal outstanding viscoelasticity, moderate swelling capacity (4.17-fold in deionized water), and a high self-recovery efficiency of 91.15%, accompanied by a bearing strength of 3.65 MPa. Mechanistic investigations indicate that the autonomous repair capability stems from dynamic non-covalent interactions—primarily hydrogen bonding and ionic associations—enabled by amide and carboxyl groups within the polymer network. Sand bed filtration tests under simulated geothermal conditions (150 °C, 8% salinity) demonstrate that XFFD forms a robust sealing barrier with significantly shallower invasion depth compared to conventional materials such as sulfonated asphalt and calcium carbonate. This work presents an effective self-healing gel system that ensures reliable wellbore strengthening and fluid loss control in challenging high-temperature, high-salinity geothermal drilling operations.

The deep-water area of the Qiongdongnan basin is currently a hot topic for exploration. The discovery of gas fields in the Baodao sag confirms its abundant oil and gas resources and potential, making it of significant economic and strategic importance. The complexity of sedimentary structural evolution within the Baodao sag makes the process of oil and gas accumulation in the area extremely complex, and the law of natural gas enrichment is difficult to grasp, resulting in unclear exploration directions. Therefore, this study focuses on the third member of the Lingshui Formation in the Paleogene of the Baodao sag. Based on the abundant thin section, scanning electron microscopy, 3D seismic and geochemical analysis data in the area, through analyzing the density of natural gas, the proportion of hydrocarbon and non-hydrocarbon components, the dryness coefficient carbon, and the isotopic characteristics, combined with the deep natural gas genesis discrimination chart, the types and genesis types of natural gas and organic matter in the sag are clarified. In addition, combined with the package and BasinMod 2009 software, the filling period and reservoir-filling process were clarified and restored. At the same time, the reservoir formation characteristics of the different fault-step zones inside the sag were dissected and the primary and secondary migration of natural gas were analyzed in order to clarify the types and characteristics of different fault-step zone transport systems. Finally, the research findings indicate that there are two reservoir formation modes developed within the depression, as follows: “multiple hydrocarbon generation and control sources—continuous vertical control of large faults—lateral sand body convergence (T + Z-type transport)—multiple cap layer closure” and “mixed-source hydrocarbon supply—continuous vertical control of large faults—short lateral sand body convergence (Z-type transport)—multiple cap layer closure”, providing an important basis for the next exploration of the basin.

Semi-open hydrous pyrolysis experiments on coal-measure source rocks in the Xihu Sag were conducted to investigate the carbon isotope evolution of kerogen, bitumen, generated expelled oil, and gases with increasing thermal maturity. Seven corresponding experiments were conducted at 335 °C, 360 °C, 400 °C, 455 °C, 480 °C, 525 °C, and 575 °C, while other experimental factors, such as the heating time and rate, lithostatic and hydrodynamic pressures, and columnar original samples were kept the same. The results show that the simulated temperatures were positive for the measured vitrinite reflectance (Ro), with a correlation coefficient (R²) of 0.9861. With increasing temperatures, lower maturity, maturity, higher maturity, and post-maturity stages occurred at simulated temperatures (Ts) of 335–360 °C, 360–400 °C, 400–480 °C, and 480–575 °C, respectively. The increasing gas hydrocarbons with increasing temperature reflected the higher gas potential. Moreover, the carbon isotopes of kerogen, bitumen, expelled oil, and gases were associated with increased temperatures; among gases, methane was the most sensitive to maturity. Ignoring the intermediate reaction process, the thermal evolution process can be summarized as kerogen₀(original) + bitumen₀(original)→kerogen_r (residual kerogen) + expelled oil (generated) + bitumen_n+r (generated + residual) + C₂₊(generated + residual) + CH₄(generated). Among these, bitumen, expelled oil, and C_2-5 acted as reactants and products, whereas kerogen and methane were the reactants and products, respectively. Furthermore, the order of the carbon isotopes during the thermal evolution process was identified as: δ¹³C₁ < ¹³C_2-5 < δ¹³C_{expelled oil} < δ¹³C_bitumen < δ¹³C_kerogen. Thus, the reaction and production mechanisms of carbon isotopes can be obtained based on their changing degree and yields in kerogen, bitumen, expelled oil, and gases. Furthermore, combining the analysis of the geochemical characteristics of the Pinghu Formation coal–oil-type gas in actual strata with these pyrolysis experiments, it was identified that this area also had substantial development potential. Therefore, this study provides theoretical support and guidance for the formation mechanism and exploration of oil and gas based on changing carbon isotopes.

Migration of hydrocarbons along fault strike remains poorly understood, and its underlying mechanisms have not been fully clarified. Taking the Pinghu slope belt in the Xihu Sag, East China Sea Basin, as a case study, this study investigates the migration process, efficiency, and controlling factors of natural gas migration along fault strike using three-dimensional physical sandbox simulation experiments. The results show that: (1) under strong fault sealing conditions, hydrocarbons rarely migrate vertically across fault planes and instead preferentially migrate laterally along structural ridges developed on the hanging wall, forming stable migration pathways; (2) structural ridges serve as dominant conduits for efficient hydrocarbon transport, guiding hydrocarbons toward structurally elevated positions where accumulation and enrichment occur; and (3) the simulated migration patterns are consistent with exploration discoveries in the study area, where hydrocarbon accumulations are concentrated in ridge-controlled favorable zones. These findings indicate that the coupling between structural ridge development and fault sealing capacity is the key factor controlling hydrocarbon migration, accumulation, and enrichment in the Pinghu slope belt, providing theoretical support for hydrocarbon exploration in fault-controlled basins.