Shale oil is one of the world’s most important strategic energy reserves. The microscopic kerogen and matrix structure plays an important role in fluid flow and diffusion processes. The oil flow time in the shale reservoir is determined by the pore spatial scale. An accurate shale reservoir flow model must consider these factors. In this research, fluid flow, Fick’s diffusion in consideration of the time delay effect, desorption, as well as the absorption are considered using the molecular momentum correlation and the partial pressure law of the components. The effect of the above-mentioned factors on the time scale contribution of the well rate is discussed. The spatial distribution diagram of the time scale is constructed and analyzed. The results show that the production process is composed of five periods. The time delay effect is reflected by fluctuations in the production at periods 1–3. The time scale corresponds to different mediums. The oil mainly flows through the outer boundary of the stimulated region through surface diffusion. The time scale spatial distribution diagram also shows that the oil flows into the endpoint of the hydraulic fracture at an early stage. Moreover, the outer boundary needs a longer time to be exploited. The proposed model improves the simulation of shale oil flow, and therefore, would be favorable in designing a more suitable working system.

Understanding the flow time scale in a tight reservoir has tremendous implications for theoretical studies and production system optimization. However, both the imbibition and dynamic coupling exert a significant effect on the fluid flow time scale and performance of the well during fracture and soaking, which is an effective way to develop a tight reservoir. In the present work, a multiple temporal scale flow model in a tight reservoir is established. A time scale analysis is conducted on the flow of fluid using Laplace transformation, finite-element method, and characteristic line method. The impact of imbibition and dynamic coupling on the temporal scale of the wellbore pressure is predicted. The results show that the wellbore pressure fluctuates when the time lag is considered or when the cross-flow coefficient from the matrix to the natural fracture is low. The imbibition is more evident for the case with higher capillary pressure and a tighter unstimulated region. The right-hand side peaks on the time scale diagram adequately reflect the water saturation propagation and fluid flow inside the unstimulated region. The effects of reservoir microstructure and imbibition on fluid flow in a porous medium may be better reflected by a time scale analysis. Results from this study can be helpful in optimizing the soaking duration, fracture scheme, and capillary pressure for the effective development of tight reservoirs.