Fractured lost circulation management is a critical challenge in drilling engineering, and existing methods often rely on empirical designs with limited effectiveness. This laboratory-scale study, utilizing modified PPT equipment and nut shell-based rigid particles in simplified linear fractures, systematically investigated the bridging and sealing effect of compounded multi-sized rigid lost circulation material (LCM) through physical experiments. It clarified the mechanism by which the proportion of multi-sized plugging particles and the total concentration influence the sealing effect after compounding. A set of quantitative compounding relationships for multi-sized rigid LCM was established based on the particle size-to-fracture width ratio (R = D50/w, where D50 is median particle diameter and w is fracture width). Experimental results show that when using particles with specific R (e.g., R = particle size/fracture width) values, approximately R1 = 0.7, R2 = 0.45~0.3, and R3 = 0.08, in a 1:1:1 ratio, and the total concentration is around 4%, high-efficiency plugging can be achieved. The plugging formulation based on this design principle can effectively seal medium-scale lost circulation fractures, providing a theoretical basis for the scientific design of rigid LCM in fractured formations.

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.