An experimental investigation of spontaneous imbibition in gas shales

Multi-stage horizontal wells find common use today in the development of shale-gas resources. The completion strategy for such wells includes hydraulic fracturing that utilizes large volumes of water complimented by the addition of assorted chemicals. A large fraction of this water remains in the formation after the well is allowed to flow back, with fluid loss often exceeding 50% of the injected volume. In this work, we study the spontaneous imbibition of water and surfactant solutions into shale samples from the Appalachian Basin in order to explore the role of capillarity in the fluid-loss mechanism. In the experiments we observe a distinct transition from an initial imbibition rate that depends linearly on the square root of time, to a lower rate at later times. This transition is attributed to the complex multi-porosity nature of the shale samples that are characterized by a micro-fracture network embedded in the sampleʹs matrix. Based on scaling arguments, we demonstrate that the fluid loss during hydraulic fracturing can be explained, at least in part, by the imbibition processes. We investigate, in addition, the application of wettability altering surfactants and demonstrate a clear potential for reducing the current fluid loss.