Water flooding is the economical secondary recovery method that has been used for more than seventy years in conventional oil reservoirs. However, few studies focused on water flooding viability in unconventional shale formations. The objective of this study is to improve the performance of waterflooding in shale formations by enhancing spontaneous imbibition through optimizing hydraulic fracturing fluid and fracture orientation. Core samples of Eagle Ford, Mancos, Barnett, and Marcellus shales were used in this study. Fractures were generated by cutting the core samples into two halves; some are along bedding planes and others across bedding planes. Shales usually have natural micro-fractures, (e.g. Eagle Ford Shale) and acid may enhance micro-fracture conductivity, so we want to investigate the impact of using low concentrations of HCl in the hydraulic fracturing process on spontaneous imbibition. Some of the samples were immersed in different HCl solutions to create etched fractures. We measured the porosity and the oil recovery in both the acid-treated and non-treated samples during spontaneous water imbibition for the samples with different fracture orientation. The mechanical properties of the acid-treated and non-treated samples were measured using different acid concentrations (1-3 wt%) at 200°F. The samples were 2.54 and 3.81 cm in diameter and 2.54 to 5.08 cm in length. The measured porosities were 1-3% for the non-treated samples and 1.3-10.5% for the treated samples. We observed that the oil recovery factors of the spontaneous imbibition for the samples treated with acid were 47% from Eagle Ford, 53% from Mancos, 28% from Barnett, and 38% from Marcellus. The recovery factors from the non-treated samples were 12% from Eagle Ford, 4% from Mancos, 13% from Barnett, and 3% from Marcellus. Furthermore, we observed that fracture orientation affects spontaneous imbibition in all of the studied rock formations, especially for Marcellus shale formation where the recovery factors varied from 4% for the samples cut across bedding planes to 38% for the samples cut along bedding planes. Eagle Ford samples showed the greatest reduction in Young's Modulus ranging from 25-82% when exposed to 1-3 wt% HCl solutions and 75% when exposed only to 5 wt% NaCl saline solution at 200°F. Our results showed that imbibition in unconventional shale oil formations could be improved by using low pH fracturing fluids and optimization of fracturing orientation.