The interaction of the drilling fluid with the formation rock is a key factor that determines the time-dependent stability of wellbores in shale formations. The analysis of wellbore stability in shales requires modelling of various coupled processes that are dependent on the relative properties of the drilling fluid and formation pore fluid. These processes include mud pressure penetration, thermal diffusion, chemical potential mechanism and poroelasticity. These processes affect the formation pore pressure, stresses and deformation. The critical drilling fluid properties include mud type, weight, temperature, and type and concentration of free ions.

Numerical simulations are conducted to model the effect of coupling the various processes on wellbore stability in shales. The simulations used a finite element code SHALESTAB that solves the specific coupled differential equations which describe these processes. It is found that the use of a cooler drilling fluid with a higher salt concentration and the appropriate mud density, viscosity and surface tension reduces the formation pore pressure and helps to enhance the stability while the use of a hotter drilling fluid with a lower salt concentration and less favourable mud physical characteristics has the reverse effect. The coupled simulations show that incorporating the chemical potential and mud pressure penetration mechanisms, depending on the mud properties, can reduce the formation pore pressure. For an effective assessment of wellbore stability in shales, the analyses need to take into account these complex coupled time-dependent processes.

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