## 1 Introduction
The CA method, a standard technique in the petroleum industry, provides a direct and quantitative means of assessing the wettability of reservoir rocks. However, as a localized measurement, it may not represent the overall wettability of the sample and is susceptible to variations due to surface roughness, cleanliness, and mineral heterogeneity, which can complicate the achievement of reliable results [16; 17]. Spontaneous imbibition, often used to mitigate this limitation, involves the spontaneous displacement of the non-wetting phase by the wetting phase through capillary action. However, this experiment only characterizes the average wettability of a sample, rather than the wettability of pore surfaces across different pore sizes [18; 19]. NMR offers an effective alternative for evaluating reservoir wettability, providing distinct advantages by detecting fluid signals from different pore sizes, enabling a more rapid and accurate assessment of wettability [20]. Advancements in ESEM technology have enabled the direct observation and measurement of pore wall wettability, providing a reliable method for characterizing micro-scale wettability in tight sandstone [21; 22]. [PERSON] et al. (2019) conducted a series of ESEM experiments and established the criteria for identifying wettability on rock pore walls [23]. They have developed quantitative methods for measuring mixed wettability states by using Automatic Mineral Identification and Characterization System (AMICS) scanning to determine the spatial distribution of rock minerals on a two-dimensional (2D) surface and analyze the contact relationships among minerals and between minerals and pores. By statistically analyzing the mineral proportions around sample pores, they observed the condensation water characteristics on mineral surfaces under ESEM, reflecting the wettability at the pore-scale in tight sandstone reservoirs [13]. [PERSON] et al. (2019) analyzed the 1D and 2D NMR \(T2\) spectra of pores in organic-rich tight oil samples under different wettability conditions [19]. The study revealed the coexistence of water-wet, mixed-wet, and oil-wet pores, noting that completely water-wet inorganic pores displayed a \(T2\) relaxation time of approximately 13.64 ms. Oil within highly hydrocarbon-wetting organic pores exhibited the fastest NMR relaxation, with a peak transverse relaxation time of approximately 0.13 ms. [PERSON] et al. (2023) conducted a comprehensive experimental study on the wettability of tight sandstone reservoir cores from the Yanchang Formation in the Ordos Basin, utilizing CA measurements, NMR experiments, and Controlled Rate Mercury Injection (CRMI) tests [12]. They revealed the intricate dynamics of oil-water distribution in the reservoir pore structure when the wettability was altered from water-wet to oil-wet conditions, highlighting the significant effects on relative permeability and the efficiency of water-driven oil recovery processes. [PERSON] et al. (2022) employed a multi-technique approach, incorporating micro-X-ray CT imaging, CA assessments, SI experiments, and physical simulations of oil migration, to examine the wettability characteristics of tight sandstone reservoir samples from the Dongying Depression in the Bohai Bay Basin [8]. The study emphasized the pivotal role of wettability in modulating capillary forces, thereby controlling the migration and accumulation patterns of oil and gas. Recognizing the inherent limitations of individual methods in assessing the wettability of tight sandstone, we introduced a comprehensive approach to characterize the wettability of tight sandstone from the Bonan Sag, the Bohai Bay Basin. The approach commences with high-resolution ESEM imaging to examine the rock surface microstructure and determine pore-scale wettability via the condensation patterns of water vapor on pore walls. Subsequently, CA measurements are employed to quantitatively evaluate the mesoscopic wettability characteristics of the tight sandstone surface.