In fractured reservoirs, the efficiency of water flood is governed by spontaneous imbibition of water into oil-containing matrix blocks. When the matrix is oil-wet or mixed-wet, little oil can be recovered by imbibition. The objective of this work is to identify chemicals that can be added to the injection water that can induce imbibition into an originally mixed-wet, tight, fractured sandstone reservoir. Several surfactants were evaluated for their aqueous stability at the reservoir temperature and salinity. Contact angles were measured on a clay-rich sandstone. Spontaneous imbibition tests were conducted on the reservoir rocks. It is shown that the use of dilute (0.1 wt %) anionic surfactant solution with a large number of ethoxy groups can alter the wettability from oil-wet toward more water-wet conditions on the mineral plates. Incremental oil recovery as high as 68% original oil in place is obtained through spontaneous imbibition experiments performed on tight (similar to 10 mu D) oil-wet/mixed-wet sandstone reservoir cores. A three-dimensional fine grid mechanistic simulator was used to perform lab-scale validation and parametric analysis. Parametric studies show that the rate of oil recovery increases with increasing wettability alteration, increasing fracture density, and decreasing oil viscosity.