Experimental Study on Spontaneous Imbibition Characteristics of Fracturing Fluid at Cores from Different Layers in Fuling Shale Gas Reservoir

Abstract

With low porosity and low permeability, shale reservoirs cannot be mined economically without large-scale hydraulic fracturing operation. However, abundant fracturing fluid will enter the reservoirs during the process of fracture. Nevertheless, there have not been specific research findings on the imbibition law of Fuling shale gas reservoir in China. In this study, an imbibition experiment was carried out on the shale core of Jiaoshiba block of Fuling shale gas reservoir to learn spontaneous imbibition characteristic of Fuling shale gas reservoir. Based on the experimental results, the imbibition process of Fuling shale gas reservoir fracturing fluid is divided into two stages. During the first stage, i.e., the former 30 hours, imbibition velocity is high, with the cumulative imbibition occupying more than 70% of the total imbibition; during the second stage, i.e., the latter 30 hours, the imbibition velocity substantially drops towards balance. There is a typical power function relationship between the average imbibition velocity and imbibition time, and this function relationship runs throughout the whole imbibition process. Nonetheless, the imbibition process of shale core cannot be described directly by the Handy equation. The imbibition velocity is closely related to clay mineral content and pore structure characteristics of shale core. The higher the clay mineral content, the higher the imbibition velocity. According to the relationship between the average imbibition velocity and imbibition time, we derived the estimation equation of fracture area formed by fractured shale gas well to estimate the fracture scale formed by shale gas well fracturing.