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Field experience shows that extending shut-in periods are conducive to increasing tight oil production after fracturing operations. Understanding the regularity of pressure decay is helpful to establish an appropriate shut-in time. However, the characteristics and influencing factors of pressure decay are unclear. This paper studies the porosity, permeability, mineral composition, and pore structure of samples in six different blocks. The pressure decay regularity is tested according to an independently designed indoor shut-in experimental device, and the oil distribution of experimental samples is monitored using nuclear magnetic resonance technology. The results show that the fracturing fluid enters the matrix pores under the action of percolation to slowly drive out the oil, causing the well pressure to decay over time. There are three types of pressure decay characteristics: concave type, fluctuation type, and quadratic type. Compared with conventional sandstone, the pressure decay rate of tight reservoirs is slower, and the pressure decay characteristics are more complicated. Clay mineral-rich reservoirs will swell when exposed to water. As a result, the strength of the framework will be weakened and collapsed. What’s more, it will cause blockage of the throat, blocking the flow of oil and the decay of pressure. In addition, the rate of pressure decay is also related to the volume of fracturing fluid, initial borehole pressure, and formation closure stress. At a certain proppant thickness (fracture width), the larger the fracturing fluid volume, the larger the fracture surface area and the faster the pressure decay rate; Moreover, the greater the initial shut-in pressure, the greater the pressure difference and the faster the decay rate; the formation closure stress causes the core porosity and the permeability to decrease, resulting in a decrease in the decay rate. The experimental results are of great significance for establishing a proper shut-in time and enhancing the oil recovery of tight reservoirs.

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