Pore structure evolution in organic-rich shale during thermal maturation: Insights from hydrous pyrolysis of two lacustrine kerogens

• Kerogen type controls pore evolution: Type I outperforms Type II. • Supercritical water boosts porosity by 2.9–5.5 times versus non-hydrous. • Water pressure both generates and compacts pores, depending on lithology. • Bitumen infilling causes up to 86% porosity loss in non-hydrous systems. • New shale-water-pressure framework predicts shale gas/oil “sweet spots”. Accurately predicting the evolution of pore networks under realistic thermo-hydro-mechanical conditions remains a critical challenge, limiting the reliable identification of hydrocarbon “sweet spots” in mature shale basins. This study aims to decouple the synergistic controls of thermal maturity, shale composition, water, and pressure on pore development. We conducted systematic, sequential high-pressure hydrous pyrolysis experiments on two compositionally distinct lacustrine shales, immature Huadian (Type II kerogen, high TOC, illite–smectite mixed-layer clay-rich) and Fushun (Type I kerogen, low TOC, siderite-rich) shales. Integrated geochemical analyses (vitrinite reflectance, Rock-Eval pyrolysis, TOC) and pore structure characterization (low-pressure N 2 /CO 2 adsorption, SEM) revealed that thermal maturity is the primary driver for pore development, but its expression is fundamentally mediated by composition. Kerogen type dictates the evolutionary pathway, and TOC dominates the porosity magnitude. Minerals further modulate pore evolution, with carbonate dissolution regenerating porosity and clay stability determining pore integrity. Water is the most critical environmental factor, enhancing porosity by facilitating hydrocarbon expulsion, inhibiting pore-filling, and promoting mineral dissolution. Pressure exerts a dual role, with internal pore pressure promoting porosity, outweighing external compaction in our closed system. Notably, water pressure results in an additional 1.9–4.5-fold increase in pore volume during the wet gas cracking stage compared to non-hydrous conditions. These results establish a novel, integrated shale-water-pressure framework that advances beyond traditional maturity-centric models by quantitatively distinguishing the roles of and interactions between key controlling factors, providing a mechanistic basis for predicting reservoir quality, although its field application requires calibration to account for basin-specific geological complexity.