Synergistic impacts of fracture–matrix system on recovery rate during spontaneous imbibition in tight sandstones

Abstract

Hydraulic fracturing is considered a promising technology for enhancing the recovery rate from tight oil/gas reservoirs. However, the hydraulic fracturing process inevitably leaves a portion of the fracturing fluid in the reservoir. This causes a noticeable decrease in the recovery rate of oil/gas. Thus, the flow mechanism of fracturing fluids in fracture–matrix system remains unclear. In this study, spontaneous imbibition (SI) experiments were conducted on sandstone samples with different fracture widths. Subsequently, magnetic resonance imaging (MRI) was used to monitor the displacement of the imbibition leading edge at the fracture edges. Finally, the recovery rate was quantified using the T2 spectra of multi-scale pores during the SI process. The experimental results revealed the following: (1) A significant contribution from the pre-rapid growth stage was observed during the SI process. (2) The heterogeneity of sandstone sample resulted in a rough imbibition leading edge and a decreasing gradient in fluid saturation over time. (3) The increase of distilled water in multi-scale pores during the SI process varied, specifically a preferential increase in micropores, followed by mesopores and macropores. (4) When the sandstone sample had a wider fracture, the synergistic effect between the fracture-matrix system was significantly enhanced, and a higher recovery rate was observed.