Shale gas reservoirs are unconventional resources with great potential to help meet energy demands. Horizontal drilling and hydraulic fracturing have been extensively used for the exploitation of these unconventional resources. According to engineering practice, some shale gas wells with low flowback rate of fracturing fluids may obtain high yield which is different from the case of conventional sandstone reservoirs, and fracturing fluid absorbed into formation by spontaneous imbibition is an important mechanism of gas production. This paper integrates NMR into imbibition experiment to examine the effects of fractures, fluid salinity, and surfactant concentration on imbibition recovery and performance of shale core samples with different pore-throat sizes acquired from the Longmaxi Formation in Luzhou area, the Sichuan Basin. The research shows that the right peak of T₂ spectrum increases rapidly during the process of shale imbibition, the left peak increases rapidly at the initial stage and changes gently at the later stage, with the peak of the left peak shifting to the right. The result indicates that water first enters the fracture system quickly, then enters the small pores near the fracture wall due to the effect of the capillary force, and later gradually sucks into the deep and large pores. Both imbibition rate and capacity increase with increased fracture density, decreased solution salinity, and decreased surfactant concentration. After imbibition flowback, shale permeability generally increases by 8.70–17.88 times with the average of 13.83 times. There are also many microcracks occurring on the end face and surface of the core sample after water absorption, which may function as new flowing channels to further improve reservoir properties. This research demonstrates the imbibition characteristics of shale and several relevant affecting factors, providing crucial theory foundations for the development of shale gas reservoirs.

Inter-well interference in multi-well pad development is a critical factor influencing the recovery efficiency of shale gas reservoirs. This study presents a comprehensive semi-analytical model to characterize the transient pressure behavior and interference mechanisms of multi-well multi-stage fractured horizontal wells (MFHWs). Utilizing point source functions and the principle of superposition, the model accounts for complex shale gas transport mechanisms, including gas desorption, diffusion, and real-gas compressibility via pseudo-pressure transformation. The proposed model is validated against the industrial standard numerical simulator KAPPA-Saphir, showing an excellent match across most flow regimes, with a maximum relative error of 3.2% and an average relative error of less than 1% across the entire production period. The results identify five distinct flow stages: fracture linear flow, fracture radial flow, compound linear flow, compound radial flow, and boundary-dominated flow. Sensitivity analysis reveals that decreasing the inter-well spacing significantly shortens the fracture radial flow duration, while longitudinal staggering of wellbore centers effectively mitigates early-time interference and promotes more uniform reservoir drainage. Furthermore, it is observed that in multi-well systems, inner wells suffer from more severe energy competition and faster pressure depletion than peripheral wells. Based on these findings, it is proposed that the inter-well spacing should exceed four times the fracture half-length, and a staggered fracture arrangement (the relative positions in the x-direction of the fractures between the wells are not the same) should be prioritized. This work provides a robust theoretical framework and practical guidelines for optimizing well spacing and infill drilling strategies in shale gas reservoirs.