Wellbore stability is one of the major challenges during drilling operations in shale gas formations. Drilling fluid seepage can significantly alter the pore pressure around the wellbore, thereby inducing wellbore instability. In this study, the Darcy pore fluid flow model was applied to both the mud cake and wellbore to predict pore pressure, which helps improve the accuracy of calculating collapse pressure and fracture pressure. Shale samples were collected from the Puguang Gas Reservoir, and their composition and physicochemical properties were systematically analyzed. The results indicate that the clay content in the formation can reach up to 35.5%, with distinct hydrophilic characteristics, and the maximum hydration expansion rate of the shale is 5.79%. The permeabilities of shale and mud cake were measured via the pore pressure transmission test. Specifically, shale samples from Sub-layer 1 exhibit the highest permeabilities for both rock and mud cake, which are 8.27 × 10−18 m2 and 2.07 × 10−20 m2, respectively. In contrast, samples from Sub-layer 3 show the lowest permeability values, being 2.76 × 10−20 m2 and 1.66 × 10−22 m2. The borehole tensile breakdown pressure and compressive collapse pressure were calculated using a poro-mechanical coupling model. The Sub-layer with the lowest cohesion strength after drilling fluid immersion presents the narrowest mud density window of 0.04 g/cm3, making it the most susceptible to wellbore stability failures; furthermore, the maintenance of wellbore stability requires strict control of the drilling mud density within the range. This study can provide guidance for accurate prediction of mud density window during drilling operations in shale formations.
Gao et al. (Sat,) studied this question.