Enhancement Mechanisms of Multi-Scale Huff-and-Puff in Horizontal Wells for Tight Sandstone Reservoirs‑A Case Study of the Chang 63 Formation in the Wuqi Block, Ordos Basin.

Hydraulic fracturing is the primary method for developing tight sandstone reservoirs. In particular, horizontal well staged fracturing huff-n-puff is the main technique for enhancing oil recovery in tight sandstones. To clarify the remaining oil distribution and oil displacement mechanism under this technological background, this paper starts from the microscopic seepage mechanism and conducts systematic research by combining microscopic experiments, macroscopic displacement analysis, and numerical simulation. The simple capillary number model is improved for tight reservoirs, revealing that the core mechanism of imbibition is capillary force. To study the coupled imbibition-displacement mechanism in tight reservoirs, visualization oil displacement experiments using glass etching models were carried out, and the oil-water migration under coupled imbibition-displacement was analyzed. The results show that the sweep range of imbibition is much smaller than that of displacement, and the higher the water-wetness, the less the remaining oil during displacement and imbibition replacement. Based on this, conventional imbibition experiments were conducted using real oil-wet thin cores (0.5 cm), confirming that gravity is the main driving force for imbibition in real oil-wet cores, and the larger the contact area between the core and the liquid, the higher the imbibition rate. To eliminate the influence of gravity and analyze the effect of imbibition area, end-face imbibition and full-surface imbibition experiments were performed using thin cores (0.5 cm) and long cores (7.5 cm). The results indicate that imbibition in horizontal cores is mainly horizontal, and the relationship between contact area and imbibition rate was quantified. To analyze the displacement-imbibition oil enhancement in mixed-wet cores from multiple angles and by multiple means, digital rock technology was used to simulate the imbibition experiments on real cores. The main controlling factor for imbibition was identified as displacement pressure: under capillary imbibition and low-pressure drive, the oil displacement efficiency by imbibition is low, but the flowback ratio is high; under higher injection pressure, the imbibition efficiency increases while the flowback ratio decreases. Guided by the microscopic experimental mechanisms, a macroscopic model of horizontal well multistage fracturing was established using numerical simulation to analyze the factors influencing huff-n-puff and imbibition oil enhancement. The results show that after fracturing and well soaking in the study area, high-pressure drive is the main mechanism for oil-water replacement; the optimal well soaking time is 3-4 months; for reservoirs with relatively low oil saturation, imbibition replacement during well soaking is the main means to enhance oil recovery.