Modelling of Effects of Drilling Fluid Temperature on Wellbore Stability

Abstract

Abstract A numerical thermo-poro-elasticity model which can model time-dependent changes in stresses and pore fluid pressure induced by thermal and fluid diffusion has been developed. The model results agree well with analytical solutions for the instantaneous fluid injection of a poro-elastic medium. The results of some simple numerical experiments show that the computed changes in effective stresses, strains and pore pressure satisfy the constitutive equations for the thermo-poroelastic medium used in the model. The model results showed that difference in temperature between drilling fluid and formation can induce significant changes in pore fluid pressure and effective stresses around the wellbore wall. The extent of the effects vary significantly with thermal diffusivity of the formation. In general, cooling the formation tend to increase the stability of the wellbore while the reverse applies to heating of the formation. The results also show the importance of considering the geothermal gradient, and thermal and fluid transport properties of shales in wellbore stability analysis and development of recommendations to manage instability. P. 471