Waterflooding is the cheapest and most profitable secondary recovery method that has been used for more than seventy years for conventional oil reservoirs. However, few studies have been done on its viability on unconventional tight formations especially shales. The objective of this study is to investigate the potential of water imbibition in different shale formations. In this study, distilled water, 2% KCl brine, 30% KCl brine, low pH HCl solutions, and high pH alkaline solutions were examined to recover oil from different shale formations. Reservoir core samples from Eagle Ford and outcrop samples from Mancos, Barnett, and Marcellus shales were used in this study. The samples were 2.54 to 3.81 cm in diameter and 0.762 to 5.08 cm in length. First, we studied the porosity of samples using CT Scanning. The average porosity was 2.7% for Mancos, 2.5% for Eagle Ford, 2.2% for Marcellus, and 5.6% for Barnett shale samples. Second, we studied the rock stability and spontaneous imbibtion of the different used samples in distilled water, different saline solutions (2-30 wt% KCl), low pH solutions (1-3 wt% HCl), and high pH alkaline solutions (0.1-2 wt% NaOH). During the spontaneous imbibition, the maximum oil recovery was 59% for Mancos using distilled water, 44% for Eagle Ford using 2 wt% NaOH and fresh water, 24% for Barnett using distilled water, and 4% for Marcellus using 2 wt% NaOH and 2 eq wt% of KCl. The low pH solutions improved natural fractures connectivity by matrix and cementing material dissolutions. The higher oil recoveries of Mancos samples were correlated with clay swelling in distilled water. Eagle Ford recovered more oil when exposed to NaOH solutions due to favorable mineral dissolution without affecting the cores' stability. On the other hand, Barnett was partially damaged when exposed to higher alkaline solutions (2 wt% NaOH) and Marcellus was very tight to allow any fluid imbibition. Collectively, our study showed a great potential of waterflooding in unconventional shale reservoirs.