Investigating the Role of Plastic and Poroelastoplastic Effects in Wellbore Strengthening Using a Fully Coupled Hydro-Mechanical Model

Wellbore instability during drilling in soft formations often leads to unwanted hydraulic fractures and lost circulation, resulting in non-productive time and elevated costs. The fracture initiation pressure (FIP) and fracture propagation pressure (FPP) are critical for managing these risks, particularly in narrow mud weight windows, yet industrial models overlook post-plugging stress behaviors at plug locations, where changes in stress concentration may initiate secondary fractures. This study introduces a fully coupled hydro-mechanical plane-strain (KGD) finite element model to examine fluid diffusion and deformation in fractured formations, emphasizing plastic and poroelastoplastic effects for wellbore strengthening. Fluid flow in the fracture follows lubrication theory for incompressible Newtonian fluids, while Darcy’s law governs porous media diffusion. Rock deformation adheres to Biot’s effective stress principle, extended to poroelastoplasticity via the Mohr–Coulomb criterion with associative flow. Simulations yield fracture dimensions, fluid pressures, in situ stress changes, and principal stresses during propagation and plugging, for both plastic and poroplastic cases. A new yield factor is proposed, derived from the Mohr–Coulomb criterion, that quantifies the risk of failure and reveals that fracture tips resist propagation through plastic and poroelastoplastic deformation, with the poroelastoplastic coupling amplifying back-stresses and dilation after plugging. Pore pressure evolution critically influences the fracture growth and plugging efficiency. These findings advance wellbore strengthening by optimizing lost circulation material plugs, bridging the gaps from elastic and poroelastic models, and offer practical tools for safer and more efficient plugging in soft rocks through modeling.