Fully coupled two-phase hydro-mechanical model for wellbore stability analysis in tight gas formations considering the variation of rock mechanical parameters

Tight gas reservoirs are typically characterized by the unsaturated case that contains both water and gas fluids. However, previous wellbore stability analysis usually assumes that the porous rock is only saturated with a single fluid, thereby failing to describe the two-phase seepage behavior and the change in water content on the me-chanical properties of the unsaturated rock, resulting in inaccurate mud weight predictions from wellbore sta-bility analysis. Therefore, this paper aims to propose a fully coupled two-phase hydro-mechanical model that is available to obtain the change in water saturation and incorporates the variation of rock mechanical parameters with water saturation into the coupling relationship to assess the wellbore stability. By comparing five models representing the saturated and various unsaturated conditions, the influences of two-phase seepage and rock mechanical parameters on the evolution of pore pressure, stresses and wellbore stability are clarified. Finally, the influences of wellbore pressure, initial water saturation, porosity, and permeability on wellbore stability are discussed. The results show that the unsaturated pore pressure is influenced not only by the compressibility and viscosity of the fluid, but also by the saturation level and wellbore pressure. The difference in effective stresses is explained by the difference in poroelastic effect between saturated and unsaturated conditions. The decrease in elastic modulus and Poisson's ratio affects the effective tangential stress, while the increase in Biot's coefficient affects the effective radial stress. The prediction result of the present model that considers the combined effects of the two-phase hydro-mechanical coupling and the variation of all five mechanical parameters with water content is more consistent with the real borehole diameter curve. In the field case of the presented tight gas reservoir, the excessive overbalanced pressure is detrimental to wellbore stability, even worse than the underbalanced pres-sure. A near-balanced pressure may be the most beneficial for maintaining wellbore stability and protecting tight gas reservoirs. The higher risk of wellbore instability may correspond to formations with relatively high permeability, high porosity and high gas saturation.