Spatiotemporal distribution characteristics of fracturing fluid in multiscale pore structure of deep marine shale gas reservoirs

Deep marine shale exhibits a higher proportion of nano-scale pores and limited natural fractures, necessitating the utilization of hydraulic fracturing for effective stimulation. However, a substantial retained fracturing fluid may lead to a sharp decrease in shale gas production due to formation damage of aqueous phase trapping. The aqueous phase distribution and flowing behaviors in the deep marine shale are required to be spatiotemporally analyzed. The aqueous phase exhibits distinct flowing behaviors after hydraulic fracturing, encompassing both fracture flowing at the millimeter scale and matrix pore flowing spanning from micron to nano scales. Aqueous phase in fractures could rapidly flowback with a mobile water saturation of 69 % and an effective permeability recovery of 75.49 %. According to the experimental results of the low-field nuclear magnetic resonance, aqueous phase is imbibed in the shale matrix during the rapid imbibition (0 similar to 2 h) and dynamically balanced imbibition (>2 h), while flowback for 8 h with a total flowback ratio of 28.27%. 91.62 % of aqueous phase in the pore space with a diameter exceeding 100 nm (>100 nm) could flowback, while 78.52% of aqueous phase is retained in the pore spaces with a pore diameter less than 100 nm (<100 nm) as the pore water and crystal water in the shale matrix. Aqueous phase is retained in shale matrix through adsorption onto the surface of clay minerals, imbibition into nano-scale pores, and entrapment in shale matrix when pore throats are obstructed by clay mineral hydration. Clarifying the aqueous phase flowing behaviors is crucial for enhancing deep marine shale gas production by alleviating the aqueous phase trapping damage and optimizing stimulation.