Summary
Hydraulic fracturing can create a large fracture network that makes hydrocarbon production from low‐permeability reservoirs economical. However, water can invade the rock matrix adjacent to the created fractures and generate water blockage that impairs production. Using surfactants as fracturing‐fluid additives is a promising method to enhance the fluid flowback, and thus mitigate the water blockage caused by invasion. It is imperative to understand how surfactants work during the fracturing and production stages, so as to maximize their effectiveness in production enhancement. In this study, an experimental investigation is conducted using a “chipflood” sequence that simulates fluid invasion, flowback, and hydrocarbon production from hydraulically fractured reservoirs. All experiments are conducted in a 2.5D glass micromodel that provides direct observation of in‐situ phase changes when different Winsor types of microemulsions formed in the porous medium. The results provide direct evidence of the impact of the matrix–fracture interaction as well as water removal when surfactants are used. They further elucidate why surfactants under different Winsor‐type conditions perform differently in mitigating the water blockage. This helps to clarify the screening criteria for optimizing flowback surfactant in hydraulic fracturing.
