Abstract
Shale pore wettability controls fluid flow and storage behavior within pores, which is of great significance for shale oil development and geological sequestration of CO₂/hydrogen. However, the quantitative characterization of wettability remains challenging due to the low porosity and permeability as well as the complex pore structure of shale, and traditional methods are mostly limited to qualitative or indirect characterization. This study proposes a quantitative characterization method for shale pore wettability based on alternating spontaneous imbibition and nuclear magnetic resonance (NMR) fluid quantification technology. Experiments consisting of four stages—oil imbibition (SI-O), water imbibition (SI-W), second oil imbibition (SI-2O), and second water imbibition (SI-2W)—were conducted, with T₂ (transverse relaxation time) and T₁–T₂ (simultaneous longitudinal and transverse relaxation times) NMR techniques applied to dynamically monitor fluid distribution, thereby revealing the evolution of fluid content and distribution during the imbibition process. The results indicate that shale pores can be classified into three categories: oil-wet, water-wet, and mixed-wet. The SI-O and SI-W stages represent a fluid filling process, during which pores are rapidly saturated by the fluid corresponding to the wetting phase. The SI-2O and SI-2W stages involve fluid exchange, where the total fluid content remains unchanged, but fluid substitution still occurs in mixed-wet pores. Based on wettability differences, an alternating spontaneous imbibition model for shale was established, and its accuracy was validated through T₂ spectrum analysis and fluid content variation patterns. Using this model, the volume content of the three types of wettability pores was quantitatively evaluated. In conjunction with the wettability index, a quantitative characterization of the bulk wettability of the shale samples was achieved at a macroscopic scale. At the microscopic level, the pore size distribution of these different wettability pores was further analyzed by separating their respective T₂ distributions from the T₁–T₂ spectrum. The results show that the primary peak for water-wet pores is centered at about 100 nm, the primary peak for oil-wet pores is near 700 nm, and the mixed-wet pores are concentrated in the 200–300 nm range. This study develops a pore-scale quantitative evaluation method applicable to porous media with complex wettability, filling the gap in quantitative wettability and pore-size characterization in tight reservoirs such as shale, and providing key parameters for engineering geological applications such as unconventional oil and gas development, CO₂-enhanced oil recovery and storage, and underground hydrogen storage.
Paper Information：
Changqi Yu, Min Wang , Junyang Chen, Jinbu Li, Yulong Tang, Yan Wu, Yidong Jia, Tingjuan Li, 2025. Quantitative assessment of pore-scale wettability: An approach combining alternating oil/water spontaneous imbibition and NMR. Engineering Geology, https://doi.org/10.1016/j.enggeo.2025.108434
