Abstract: Rock wettability governs the occurrence state and flow behavior of crude oil within pores and is critical for enhancing oil recovery. However, shale oil rocks typically contain micro/nanoscale pore throats and are characterized by strong tightness and heterogeneity. This leads to significant limitations in traditional laboratory methods for determining wettability (e.g., the Amott method), including substantial measurement errors and difficulty in characterizing wettability at the pore scale. To address these issues, this study established a NMR Amott method by improving the traditional approach based on nuclear magnetic resonance (NMR) technology. This method accurately quantifies the volumes of spontaneously imbibed and displaced fluids via T₂ spectra, significantly improving measurement accuracy and enabling the quantitative evaluation of macroscopic wettability. In parallel, a new NMR T₁–T₂ spectra spontaneous imbibition method was proposed to characterize the microscopic wettability of rocks at the pore scale. These two methods were employed to conduct wettability determination experiments on 12 core samples from four blocks of the interbedded shale oil in the Chang 7 Member of the Ordos Basin. The results demonstrate that the NMR Amott method is more reliable than the traditional method. The NMR T₁–T₂ spectra spontaneous imbibition method reveals that the proportions of oil-wet, water-wet, and mixed-wet pores in the experimental cores are 55.62%, 23.00%, and 21.39%, respectively, indicating an overall oil-wet mixed wettability, which is consistent with the NMR Amott method's findings. Furthermore, the study confirms that rock wettability is co-controlled by mineral composition and pore structure. These research findings further enrich the technical system for evaluating shale oil rock wettability and provide important support for the characterization of shale oil rock wettability and the optimization of development technologies.