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).

The development of tight oil depends on the characteristics of complicated pore throat parameters. In this study, the tight oil samples obtained from the Yanchang group of Ordos basin (China) are tested using the constant rate mercury intrusion technique to quantitatively determine the size of pore and throat parameters, as well as analyze the key parameters that control the quality of tight oil reservoir. The pore radius of sample analogously distributes in 100–200 μm and average pore radius varies from 103.7 to 139.74 μm. When the permeability is less than 1 × 10⁻³ μm², the throat peak radius and the average throat radius will be less than 1 μm; furthermore, the variation of throat distribution is in the range of 0.2–0.5 and 0.2–1.0 μm. On the contrary, if the permeability is greater than 1 × 10⁻³ μm², the average throat radius will be greater than 1 μm and the distribution range of throat will spread from 0.2–3.4 to 0.2–8.8 μm. As for the eleven samples, the main flow throat radius lies in the range of 0.41–3.71 μm, the throat quantity changes wildly from 1324 to 4271 number/cm³, the average pore throat ratio varies from 503.59 to 86.11, the pore mercury saturation alters in 17.65–55.95 % and the throat mercury saturation distributes in 13.44–27.6 %. It can be learned that there is no obvious difference in pore parameters for tight oil reservoir. Therefore, the difference of pore throat structure mainly existed in throat parameters, and the throat parameters are the key factors that affect the physical properties and recovery results.