Water blockage severely restricts gas transport in deep shale reservoirs, while effective mitigation requires a precise balance of multiple operational variables. This study utilizes core-flooding experiments to optimize the treatment processes of an amphiphobic fluorinated copolymer, focusing on the coupled roles of surfactant concentration, injected volume, and shut-in duration. The results show that permeability damage decreases rapidly with surfactant concentration, optimizing at 0.5 wt.%. Conversely, excessive liquid retention beyond a critical injection threshold of 1.0 PV triggers secondary water-blocking. Extending the shut-in duration to 8 days facilitates surfactant redistribution and interfacial equilibrium, gradually reversing rock wettability to a stable amphiphobic state. Crucially, the concurrent reduction in interfacial tension markedly lowers capillary resistance, allowing trapped water to detach and flow back under significantly lower driving pressures. This optimization effectively minimizes the energetic barrier for fluid displacement and creates a gas-preferential flow environment. The proposed laboratory operational window balances surfactant dosage, injection volume, and shut-in duration under the tested conditions, providing an experimental reference for optimizing post-fracturing cleanup, controlling liquid retention, and improving early-time gas flowback in shale gas reservoirs.
Yang et al. (Thu,) studied this question.
Synapse has enriched 5 closely related papers on similar clinical questions. Consider them for comparative context: