Abstract The sensitivity of shale pore structure and wettability to external fluids directly influences reservoir quality and stimulation performance. In this study, felsic shale cores were subjected to high‐temperature and high‐pressure experiments with different external fluids: low‐viscosity slickwater, high‐viscosity slickwater, gum‐breaking solution, acid and alkali solutions CO 2 , and a composite system. Porosity sensitivity was characterized using two‐dimensional (2D) nuclear magnetic resonance (NMR), permeability was measured with an overburden permeability apparatus, and wettability was quantified by the imbibition‐derived wettability index across micro‐, small, meso‐, and large pores. The results show that porosity increased after exposure to all fluids, with acid exerting the strongest enhancement (about 59%) due to mineral dissolution, while CO 2 caused almost no change (about 4%). Permeability was most enhanced by acid treatment, while the gum breaking solution caused a reduction in permeability due to residue blockage. Wettability responses were strongly scale dependent. Acid decreased overall hydrophilicity by shifting small pores toward oil‐wetness (0.55–0.6 to below 0.4) but enhanced water‐wetness in mesopores from 0.5. Alkali slightly improved hydrophilicity, dominated by micropores and large pores. CO 2 reduced wettability indices across all pore sizes ranges by approximately 0.05–0.1, leading to neutral conditions; while slickwater, guar breaker, and the composite system produced only weak or negligible changes. These findings highlight the complexity of fluid–rock interactions in shale, where improvements in porosity and permeability may be offset by unfavourable wettability shifts. The study provides pore‐scale evidence for evaluating shale sensitivity to external fluids and practical guidance for shale oil development.
Fu et al. (Wed,) studied this question.