Abstract Multi-stage horizontal wells play an important role in the development of domestic shale-gas resources. The completion strategy for shale-gas wells commonly includes hydraulic fracturing that utilizes large volumes of fresh (and recycled water) complimented by the addition of assorted chemicals. A general observation from the completion of shale-gas wells is that a large fraction of the injected water remains in the formation after flowback, and that the fluid loss from any single well can exceed 50% of the original injected volume. In this work, we study spontaneous imbibition of water into shale samples from the Appalachian Basin in order to explore the role of capillarity in the fluid-loss mechanism. We investigate the imbibition characteristics for a range of shale samples encompassing the mineralogy and petrophysical properties that can be observed along the vertical column of a gas play. Imbibition experiments are performed on shale cubes, whereby one face of the sample is exposed to water in order to mimic the invasion characteristics of the fracturing fluid from the main hydraulic fracture through the micro-fracture network into the shale matrix. In most of the experiments we observe a distinct transition from an initial linear rate (vs. square root of time) to a much slower imbibition rate at later times. This transition is attributed to the complex, multi-porosity nature of the shale samples which are characterized by a micro-fracture network imbedded in the sample matrix. Based on a scaling argument, we demonstrate that the fluid loss during hydraulic fracturing can be explained, at least in part, by the imbibition processes.