Hydraulic fracturing and commingle production of multiple layers are extensively adopted in unconventional tight gas reservoirs. Accurate determination of parameters of individual layers in multilayered tight gas reservoirs is essential for well performance evaluation and development strategy optimization. However, most analytical models for fractured vertical wells in stratified gas reservoirs focus on fully penetrated hydraulic fractures, neglecting the influence of partial penetration of hydraulic fractures. This paper presents a semi-analytical model to investigate the transient pressure behavior of vertically fractured wells in dual porosity multi-layered tight gas reservoirs. The partial penetration of hydraulic fracture, the vertical heterogeneities of layer properties, the differences between hydraulic fracture lengths in each layer and the stress sensitivity are all incorporated in the proposed model. The point-source solution, Laplace transformation, Fourier transformation, Pedrosa's transformation, perturbation technique, and the superposition principle are applied to obtain the analytical solution of transient pressure responses. The proposed model is validated against a commercial software, and the transient pressure behavior of vertically fractured wells in multi-layered tight gas reservoirs are analyzed. Based on the characteristics of the type curves, seven flow regimes can be identified, including wellbore storage, transitional flow period, reservoir linear flow period, vertical pseudo-radial flow in fracture system, inter-porosity flow period, late-time pseudo-radial flow period, and the boundary-dominated flow period. Sensitivity analyses reveal that the penetration ratio of hydraulic fracture has primary influence on early-time transient pressure behavior and production contribution, while the stress sensitivity mainly affects the late-time transient pressure behavior. Gas production at the initial stage is mainly contributed by the high-pressure/high-permeability layer, and gas backflow will occur during initial production stage for obviously unequal initial formation pressures. Finally, two field cases are conducted to illustrate the applicability of the proposed model. The model and corresponding conclusions can provide technical support for performance analysis of tight gas reservoirs.

Shale gas is an important component of unconventional oil and gas resources. Studying the imbibition behavior is helpful to optimize flowback parameters and enhance gas recovery. Recent imbibition studies have focused on shale matrix, and the pressure conditions discussed were mostly atmospheric. The initial imbibition behavior begins from propped fractures to matrix, but there are few studies working on explaining the imbibition behavior in propped fractures or the phenomenon of many shale wells exhibit higher productivity after a “soaking” period. Therefore, propped fracture samples were designed for imbibition and migration experiments. In order to accurately study the mechanism and main influencing factors of fracturing fluid imbibition and migration in propped and unpropped shale fractures under high temperature and high pressure, a series of experiments based on nuclear magnetic resonance (NMR) were carried out. Results showed that NMR T₂ spectra of all samples exhibited a bimodal distribution. The final imbibition volume of fracturing fluid was positively related to pressure and fracture width. The imbibition effect of fracturing fluid was more evident in matrix pores under high pressure. In the migration during soaking stage, the fracturing fluid gradually migrated from large pores to small pores and gradually displaced the shale gas from the matrix, thus allowing the water blocking in propped fractures to self-unlock to some extent. Gas permeability decreased in the imbibition stage, while it recovered in the migration stage to some extent.