Mechanical Response of Tight Sandstone to Spatially Nonuniform Pore Pressure During Fluid Invasion

During fluid invasion of tight gas sandstone, low permeability and capillary effects can sustain spatially nonuniform pore-pressure distributions, potentially altering the mechanical response of the reservoir rock. Conventional analyses often focus on pore-pressure magnitude, while the influence of spatial pressure heterogeneity remains insufficiently characterized. This study develops a numerical model in COMSOL Multiphysics by incorporating pore-pressure distributions associated with core water-injection experiments and stress–strain data from triaxial compression tests. The model evaluates the effects of pore-pressure level, fluid-invasion extent, and rock properties on peak stress and the corresponding strain. The results indicate that increasing pore pressure reduces both peak stress and peak strain under the investigated conditions. With increasing fluid-invasion extent, both parameters initially decrease and subsequently increase, with minimum peak stress and peak strain occurring at approximately 20% and 30% invasion, respectively. The predicted reductions vary among the five specimen-specific models, reflecting their combined material properties rather than independently isolated effects of porosity, elastic modulus, or strength. Nonuniform pore pressures also produce heterogeneous effective-stress distributions and localized plastic deformation. These findings highlight the importance of accounting for spatial pore-pressure heterogeneity when evaluating the mechanical response of fluid-invaded tight sandstone.