Water-blocking can be a serious problem, causing a low gas production rate after hydraulic fracturing; a result of the strong capillarity in the tight sandstone reservoir aggravating the spontaneous imbibition. Fortunately, chemicals added to the fracturing fluids can alter the surface properties and thus prevent or reduce the water-blocking issue. We designed a spontaneous imbibition experiment to explore the possibility of using novel chemicals to both mitigate the spontaneous imbibition of water into the tight gas cores and measure the surface tensions between the air and chemical solutions. A diverse group of chemical species has been experimentally examined in this study, including a cationic surfactant (C12TAB), two anionic surfactants (O242 and O342), an ionic liquid (BMMIM BF4), a high pH solution (NaBO2), two nanofluids (Al2O3 and SiO2), and a series of house-made deep eutectic solvents (DES3-7, 9, 11, and 14). Experimental results indicate that the anionic surfactants (O242 and O342) contribute to low surface tensions, but cannot ease the water-blocking issue due to yielding a more water-wet surface. The high pH solution (NaBO2), ionic liquid (BMMIM BF-4), and brine (NaCl) significantly decrease the volume of water imbibed to the tight sand core through wettability alteration, and the cationic surfactant (C12TAB) leads to both surface tension reduction and an oil-wet rock surface, helping to prevent water-blocking. The different types of DESs and nanofluids exhibit distinctly different effects on expelling gas from the tight sand cores through water imbibition. This preliminary research will be useful in both selecting and utilizing proper chemicals in fracturing fluids to mitigate water-blocking problems in tight gas sands.