A novel method for evaluation of the spontaneous imbibition process in tight reservoir rocks: Mathematical model and experimental verification

Spontaneous imbibition driven by capillary forces is essential for the development of oil and gas resources because it can significantly influence the oil recovery of tight reservoirs. But limited by traditional experimental methods, the existing mathematical models lack applicability to complex tight reservoir rocks. Therefore, to better predict water imbibition in tight reservoirs, this paper proposes a new spontaneous imbibition model based on modifications of the classical Handy model. Two important parameters, the average capillary pressure, and the imbibition permeability are derived using a nuclear magnetic resonance spectroscopy method to quantify the macroscopic driving force and percolation ability of the complex pore network. Furthermore, combined experiments of co-current spontaneous imbibition experiments and transverse relaxation time analysis on four shale core plug samples are conducted to verify the new model. Results show the imbibition process can be modeled successfully before the imbibition volume reaches 85% of the maximum imbibition volume, and two continuous stages: the early/free imbibition stage and the later/limited imbibition stage, are then subdivided according to the applicability of our model. Considering the heterogeneity of the pore network in shale samples, it can be inferred that an uneven imbibition front occurred during the imbibition process. In all, this model enriches the classical imbibition theory and provides a new approach to analyzing the imbibition of fracturing fluids in complex tight reservoirs.