Abstract
The potential difference of hydraulic pressure, solute concentration and temperature between the drilling fluid and the formation fluid can induce the flow of solvent and cause changes in the pore pressure during drilling a tight formation, which may result in wellbore instability. According to the continuity equation of fluid, the pore pressure calculation model considering the effect of thermochemical coupling is established and the solution of the pore pressure in the Laplace domain is given. Using this model, the effects of the temperature, solute concentration and viscosity of drilling fluid on the pore pressure around the wellbore are simulated. The results show that, when the wellbore pressure is higher than the formation pressure and the solute concentration of the drilling fluid is larger than that of the formation fluid, the near-wellbore pore pressure will decrease first and then increase during drilling a tight formation, and increasing the drilling fluid temperature will decrease the pore pressure. Increasing the solute concentration of the drilling fluid can inhibit the increase of the pore pressure.
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