Developing ultra-high-temperature geothermal resources is challenging, as traditional drilling fluids, including foam systems, lack thermal stability above 160 °C. To address this key technical bottleneck, this study delves into the screening principles for high-temperature-resistant foaming agents and foam stabilizers. Through high-temperature aging experiments (foaming performance evaluated up to 240 °C and rheological/filtration properties evaluated after aging at 200 °C), specific additives were selected that still exhibit good foaming and foam-stabilizing performance under high-temperature and high-salinity conditions. Building on this, the foam drilling fluid system formulation was optimized using an orthogonal experimental design. The optimized formulations were systematically evaluated for their density, volume, rheological properties (apparent viscosity and plastic viscosity), and filtration properties (API fluid loss and HTHP fluid loss) before and after high-temperature aging (at 200 °C). The research results indicate that specific formulation systems exhibit excellent high-temperature stability and particularly outstanding performance in filtration control, with the selected foaming agent FP-1 maintaining good performance up to 240 °C and optimized formulations demonstrating excellent HTHP fluid loss control at 200 °C. This provides an important theoretical basis and technical support for further research and field application of foam drilling fluid systems for deep high-temperature geothermal energy development.

The instability of wellbore in hard and brittle shale formations is a key bottleneck constraining the safety and efficiency of drilling engineering. Traditional studies focused on drilling fluid density, particle plugging, and chemical inhibition; however, there is a lack of in-depth analysis on the precise control mechanism of wellbore stability by the rheological properties of drilling fluids. Specifically, while traditional methods are limited in addressing mechanical instability in hard brittle shales with pre-existing micro-fractures, rheological control offers a potential solution by influencing pressure transmission within these fractures. To address this research gap, this study aims to reveal the influence of drilling fluid rheological parameters (specifically viscosity and yield point) on the pressure transmission behavior of the micro-fracture network in hard and brittle shale and to clarify the intrinsic mechanism by which rheological properties stabilize the wellbore. Micro-structure analysis confirmed interconnected micro-fractures (0.5–30 μm). A micro-fracture flow model and simulations evaluated viscosity and yield point effects on pressure transmission. A higher viscosity significantly increased the pressure drop (ΔP) near the wellbore, with limited transmission distance effects. The yield point was minimal. The study reveals that optimizing rheology, particularly increasing viscosity, can suppress pore pressure, reduce collapse pressure, and improve stability. The findings support rheological parameter optimization for safer, economical drilling. In terms of rheological parameter optimization design, this study suggests emphasizing the increase in drilling fluid viscosity to effectively manage wellbore stability in hard brittle shale formations.

Accurate determination of the physico-mechanical parameters of rock and soil masses is fundamental to the quantitative stability analysis and engineering mitigation of open-pit mine slopes. However, existing studies often rely on generalized parameters and lack systematic empirical data based on full-hole in situ core sampling to quantitatively verify the link between microscopic mineralogy and macroscopic instability. To address this gap, this study investigates the mineral composition, microstructure, and hydro-mechanical behavior of geotechnical materials, using the XG Open-pit Coal Mine in Inner Mongolia as a case study. Field drilling and sampling with a cumulative depth of 1500.7 m were conducted, combined with systematic laboratory tests. The results reveal significant lithological heterogeneity within the mining area. Specifically, hard rocks (e.g., fine sandstone) constitute the stable framework of the slope, whereas mudstones rich in hydrophilic clay minerals, along with low-strength coal seams, form potential weak sliding interfaces. Quantitative X-ray Diffraction (XRD) analysis reveals that the weak mudstone layers contain up to 32.4% hydrophilic expansive minerals (montmorillonite and illite/smectite). Scanning Electron Microscopy (SEM) and slake durability tests demonstrate that the mudstone is characterized by well-developed micropores (1–2 μm) and loose cementation. Theoretical analysis indicates that upon saturation, the strength of these weak layers is reduced by over 40%, causing the factor of safety (FoS) to drop from a stable 1.48 to a critical 0.89. Based on these findings, the slope instability mechanism driven by “Stiffness Mismatch and Hydro-Weakening” is elucidated. Consequently, targeted reinforcement and drainage measures are proposed to provide a scientific basis for safe mining operations.

To address the critical challenges of wellbore instability in deep coal seam drilling operations, this investigation developed an innovative organic–inorganic composite nanosealing agent (NS) through chemical modification of nano-silica. Advanced characterization techniques including Fourier Transform Infrared Spectroscopy, laser particle size analysis, and Scanning Electron Microscopy revealed that the optimized NS possessed a uniform particle distribution (mean diameter 86 nm) and enhanced surface hydrophobicity, effectively mitigating particle agglomeration. Systematic experimental evaluation demonstrated the material’s multifunctional performance: the NS-enriched drilling fluid achieved an 88.7% reduction in sand bed invasion depth and 76.4% decrease in filtrate loss at optimal concentration. Notably, comparative inhibition tests showed the NS outperformed conventional KCl and KPAM inhibitors, achieving 91.2% shale rolling recovery rate and 65.3% lower swelling rate than deionized water baseline. Core flooding experiments further confirmed superior sealing capability, with 2% NS addition attaining 88% sealing efficiency for low-permeability cores (0.5 mD) and establishing a 10 MPa breakthrough pressure threshold. Field implementation in the SSM1 well at Shenmu Huineng Liangshui Coal Mine validated the technical efficacy, the NS-enhanced drilling fluid system achieved 86.7% coal seam encounter rate with zero wellbore collapse incidents, while core recovery rate improved by 32.6% to 90.4% compared to conventional systems. This research breakthrough provides a scientific foundation for developing next-generation intelligent drilling fluids, demonstrating significant potential for ensuring drilling safety and enhancing gas recovery efficiency in deep coalbed methane reservoirs.

Driven by the extreme high temperatures (≥150 °C) and high salinities of deep wellbore environments, the corrosion failure of drill strings in water-based drilling fluids (WBDFs) is becoming increasingly severe. This study systematically investigates the corrosion behaviors and underlying mechanisms of N80 steel in simulated WBDFs under varying temperatures (80–180 °C), inorganic salts (NaCl, CaCl₂, KCl), dissolved oxygen (DO) levels, and hydrodynamic conditions, utilizing weight-loss tests, SEM, and XRD. Results reveal that the corrosion kinetics are synergistically governed by temperature and salt concentration, exhibiting a non-linear “increase-then-decrease” trend with a peak at 120–150 °C. The aggressiveness of the inorganic salts ranks as NaCl > CaCl₂ > KCl. Specifically, highly penetrative free Cl⁻ in the ultra-high-concentration NaCl system induces severe interconnected localized pitting. Conversely, high-concentration Ca²⁺ in weakly alkaline environments couples with carbonate to form a protective inorganic scale, serving as a physical barrier. Although the “salting-out effect” of high-concentration salts effectively reduces the DO level, the synergy between residual oxygen and active Cl⁻ in dynamic flow fields still triggers highly concealed deep under-deposit pitting. At the extreme high temperature of 180 °C, background salt ions dictate the competitive interfacial film formation: the NaCl system undergoes oxygen depolarization to generate a porous Fe₃O₄ layer, whereas K/Ca-containing systems promote CO₃²⁻ adsorption, forming a dense and thermodynamically stable FeCO₃ film. This study elucidates the fundamental mechanisms of uncontrolled pitting induced by extreme HTHP environments, providing vital theoretical guidance for the anti-corrosion design of deep-well drilling engineering.

Lost circulation in fractured formations remains a critical challenge in petroleum engineering, significantly hindering drilling efficiency and increasing operational risks. To overcome the limitations of conventional plugging materials under high-temperature and complex fracture conditions, a nanomaterial L-modified thermally expandable thixotropic gel system was developed. By incorporating a nanomaterial with strong thixotropic characteristics and multifunctional monomers, multiscale network regulation and interfacial enhancement were achieved. Systematic rheological and performance evaluations were conducted to optimize the formulation, enabling a balanced combination of flowability, structural recovery, and plugging performance. Experimental results demonstrate that the gel exhibits pronounced shear-thinning behavior and excellent thixotropic recovery, ensuring superior injectability under high shear and strong structural integrity under low-shear conditions. The system also maintains good thermal stability below 150 °C and achieves effective plugging across varying fracture scales. In addition, moderate salinity enhances network strength, whereas excessive salt concentration weakens structural stability and recovery capability. This study provides a novel design strategy for nanomaterial-regulated thermally expandable gels and offers a promising solution for lost circulation control in complex fractured formations.