Experimental study on characteristics of water imbibition and ion diffusion in shale reservoirs

During the soaking process of shale gas reservoirs, due to the imbibition of fracturing fluid and the dissolution of solid substances in the reservoir, the flowback rate is low, and the salinity of the flowback fluid increases. The effects of different salt solutions, surfactants, and boundary conditions on spontaneous imbibition and ion diffusion were studied through comparative experiments. Forced imbibition experiments were conducted to investigate the effect of external pressure. The results show that the pressure applied to the fluid can increase the imbibition rate, but has little effect on ion diffusion. In the same concentration of salt solution, K+ has a stronger inhibitory effect on imbibition and ion diffusion than Na+. Both sodium alcohol ether sulfate (AES, anionic surfactant) and alcohol ethoxylate (AEO-9, non-ionic surfactant) will inhibit imbibition and ion diffusion. The controlled experiments show that AEO-9 inhibits imbibition more obviously, and the ion pair ionized by AES inhibits ion diffusion. Compared with the two-ends-closed (TEC) and two-ends-open (TEO) boundary conditions, all-faces-open (AFO) has the largest exposed areas and is the most favorable for imbibition and ion diffusion. The imbibition and the ion diffusion rates of the 15 cores are roughly linearly correlated, and the ion diffusion is a synchronous process with imbibition. Compared with previous experiments on spontaneous imbibition and ion diffusion of sandstone and hydrate sediment in distilled water, the imbibition rates of shale are the slowest, and the ion diffusion rates are between hydrate sediment and sandstone. This study is of great significance for understanding the mechanism of soaking stimulation in shale gas reservoirs.