Imbibition and Oil Recovery Mechanism of Fracturing Fluids in Tight Sandstone Reservoirs

The fracturing fluid residing in a reservoir undergoes spontaneous imbibition. Here, to explore the mechanism of fracturing fluid imbibition and oil displacement, experiments on the spontaneous imbibition of fracturing fluid under different influencing factors were conducted on a core sample from the Ordos Basin of the Chang 8 formation. Combined with nuclear magnetic resonance technology, we quantitatively evaluated the degree of oil production of different pores during the fracturing fluid displacement process. Experimental results show that fracturing fluid salinity, fracturing fluid interfacial tension, and crude oil viscosity are negatively correlated with oil recovery. The phenomenon of microscale imbibition oil displacement occurs in pores of various scales in the core. The imbibition scale was between 0.10 and 1608.23 ms. The degree of crude oil production in the pores at each scale increased with increasing imbibition time. Moreover, the crude oil viscosity, fracturing fluid salinity, and fracturing fluid interfacial tension are negatively correlated with the degree of oil production at various pore scales. Decreasing crude oil viscosity significantly improves the degree of small-pore (0.1-16.68 ms) crude oil production; the low interfacial tension possesses a higher degree of oil production in the large pores (>16.68 ms), and the increment in the degree of oil production under different salinities of the small pores (0.1-16.68 ms) is greater than that of the large pores (>16.68 ms).