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 paper is to study the potential of waterflooding in Eagle Ford shale formation through water imbibition experiments on reservoir rock samples and simulation study using Eagle Ford shale published data. In the experimental study, distilled water and 2% KC1 brine solutions were examined to recover oil from different Eagle Ford shale reservoir samples. 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 of the studied samples varied from 1% to 5%. Second, we studied the spontaneous imbibition of the different used samples in distilled water and 2% KG for one week. During the spontaneous imbibition, the maximum oil recovery was 19% from the samples placed in distilled water against 12% from the samples placed in 2% KCl brine solution. The higher recovery achieved by the distilled water was due to cracking from clay swelling which was not observed with the 2% KCl brine solution. The samples exposed to distilled water for one week during the spontaneous imbibition experiment showed more tendency to break down when low confining pressure was applied due to clay swelling. The simulation study using Eagle Ford reservoir fluid and rock data along with completion data revealed a good potential for waterflooding using closer spacing between the oil producer and the water injector fractures that forced the injected water to invade the hydraulic created fractures, natural fractures, and the reservoir matrix as well, which maximized the oil recovery. Collectively, our experimental and simulation study showed a good potential of waterflooding in Eagle Ford shale formation.