The distribution of beddings varies greatly in shale reservoirs. The influence of beddings on hydraulic fracture propagation has often been studied using simplified geological models, i.e., uniformly distributed bedding models. However, the propagation processes of hydraulic fractures in shale reservoirs with complicated distributed beddings remains unclear. In this research, an outcrop-data-based bedding model of a continental shale formation in the Ordos Basin, China, is built. A mathematical model for fracture propagation is built using the discrete element method and is then verified by a hydraulic fracturing experiment. Reservoir-scale simulations are employed to investigate the influence of geological factors and engineering factors on fracture geometry. The study finds that beddings have significant inhibitory effects on fracture height growth; hydraulic fractures have difficulty in breaking through zones with densely distributed beddings. If a hydraulic fracture encounters a bedding plane with a larger aperture, it is more likely to be captured and expand along the weak interface. High vertical stress difference and a high fluid injection rate can promote the vertical penetration of hydraulic fractures through beddings and activate the bedding system to yield a complex fracture network. Increments in fluid viscosity can increase the resistance of fracture propagation, thereby reducing fracture complexity.

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.

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.

Oil sands drilling frequently contaminates water-based xanthan gels with highly viscous asphaltenes, collapsing their three-dimensional network and causing barite sag, high fluid loss and poor cuttings transport. Nitrogen-functionalized carbon quantum dots (N-CQDs) were hydrothermally synthesised from citric acid and 1-hexadecylamine and characterised by means of FT-IR, TEM and TGA. The concentration-dependent influence of N-CQDs (0–1.2 wt%) on gel viscoelasticity, microstructure and filtration properties was evaluated through rheometry, API and fluid-loss tests. At 0.01 wt% N-CQDs, the viscosity of the adsorbed oil phase dropped by 50% and the mean droplet diameter decreased from 247.7 µm to <100 µm. Consequently, the xanthan gel exhibited a significant enhancement in its mechanical strength and fluid loss performance. Wax-crystal growth was simultaneously inhibited, lowering the pour point by 6 °C. N-CQDs act as nanospacers that disrupt π-stacking of asphaltenes and hydrogen-bond to the polymer backbone, thereby restoring gel strength and sealing capacity. The work provides a sustainable, low-toxicity route to rejuvenate gel-based drilling fluids contaminated by heavy oil and facilitates their reuse in oil sands reservoirs.

Mechanical sand-control screens are core completion components for maintaining sand retention and flow conductivity in oil, gas, geothermal, hydrate, and underground gas storage wells. This review summarizes recent progress in the plugging mechanisms, diagnostic indicators, and plugging-removal technologies of mechanical sand-control screens. The reviewed studies show that screen plugging is a multi-mechanism process controlled by external sand bridging, internal fines invasion, drilling/completion fluid residues, chemical scaling, organic deposition, and their coupled cementation effects. External plugging is mainly associated with slot- or pore-entrance bridging and filter-cake compaction, whereas internal plugging is controlled by fines retention in mesh layers, prepacked gravel, or tortuous porous media. Pressure drop, permeability damage/recovery, produced-sand particle-size distribution, and microstructural characterization are key indicators for evaluating plugging severity and treatment effectiveness. Hydraulic jetting, mechanical vibration, ultrasonic treatment, acidizing, oxidizing systems, thermochemical treatment, and physical–chemical combined methods are compared in terms of mechanisms and applicability. The analysis indicates that single treatments are usually insufficient for strongly cemented multicomponent plugging; a sequential strategy of chemical weakening followed by physical stripping and flowback is more suitable for complex field conditions. Future work should focus on green and selective chemical systems, downhole diagnosis-guided treatment selection, and integrated sand-control designs combining plugging prevention, monitoring, and removal.