<p>Shale gas reservoirs typically display dual-pore and dual-permeability characteristics, along with non-saturated water–gas phases. Neglecting two-phase fluid behavior and the non-saturated state in dual-pore and dual-permeability shale gas reservoirs can yield inaccurate wellbore stability predictions. Therefore, this paper presents a fully coupled dual-pore dual-permeability two-phase fluid hydro-mechanical model, incorporating adsorption–diffusion mechanisms and fracture-matrix cross-flow characteristics to assess wellbore stability. The differences in pressure, stress around the wellbore, and wellbore instability evolution law are analyzed, compared to single-pore single-permeability non-saturated model and dual-pore dual-permeability saturated model. Finally, we study the impact of factors such as wellbore pressure, formation initial water saturation in matrix and fracture, and formation permeability in matrix and fracture on wellbore stability. Key findings include the following: (1) The drilling fluid density design is relatively conservative in both single-pore single-permeability non-saturated model and the dual-porosity dual-permeability saturated formations, with the former being 13.5% higher than the latter. (2) As the wellbore pressure increases, fracture pore pressure propagates more rapidly, while low-permeability matrix can effectively slow down pressure transmission; and under near-equilibrium drilling conditions, increasing wellbore pressure can improve wellbore stability. (3) Higher initial water saturation, particularly in the shale matrix, corresponding to lower capillary pressure and a weaker spontaneous embedding effect, reduces effective stress and wellbore instability risk. (4) Increased matrix permeability reduces effective stress, raising wellbore instability risk, while the variation of fracture permeability has a lesser impact, approximately 1%. These results underscore the necessity of accounting for non-saturated conditions and dual-pore dual-permeability characteristics in shale gas reservoirs. This model confirmed that the higher risk of wellbore instability in non-saturated shale gas formations with dual-pore dual-permeability property is associated with higher permeability and initial water saturation in the matrix. These findings are beneficial for the wellbore stability prediction in non-saturated shale gas reservoirs with microfracture development.</p>