Fracturing fluid retention in shale gas reservoir from the perspective of pore size based on nuclear magnetic resonance

Abstract

Shale gas development requires large-scale hydraulic fracturing, but a large amount of the slickwater fracturing fluid injected into the reservoir cannot be brought back to the surface. In this study, spontaneous imbibition and reverse displacement experiments were carried out on shale core to simulate fracturing fluid imbibition into the matrix during the fracturing stage of a shale gas reservoir and the displacement of fracturing fluid by reservoir gas during the flowback stage. With the help of low-field nuclear magnetic resonance technology to dynamically monitor the volume change in the liquid in the shale core throughout the entire process, the volume distribution of the liquid in the pores of the different scales were calculated at each time. The reason for the low flowback efficiency of shale gas reservoirs from the perspective of pore size was studied, and the influence of the fracturing fluid’s salinity on the flowback process was analyzed. The research results show that there is a certain pore size threshold in the shale gas reservoir. When the fracturing fluid enters pores smaller than this size threshold, it is difficult to displace it during flowback. The relative volume of the fracturing fluid entering the pores smaller than the size threshold determines the flowback efficiency. The higher the proportion of this part of the fracturing fluid to the total volume, the lower the flowback efficiency. Using a fracturing fluid with a higher salinity can reduce the volume of liquid entering the pores less than the pore threshold to a certain extent, thereby increasing the flowback efficiency. This research is important for gaining a better understanding the low flowback efficiency in shale gas reservoirs and for evaluating the safety of groundwater resources.