| Popis: |
In order to study the effects of heat transfer, solute diffusion, seepage and water diffusion, formation properties and wellbore stress state changes on wellbore stability, a multi-field coupling model of the time dependent wellbore instability for shale formations is built based on the constitutive equations including phenomenological equation and Darcy’s law. The model results show that using drilling fluid with high density, low temperature, low activity and low solute diffusion coefficient is more beneficial for maintaining the stability of the horizontal wellbore of the shale formations. Chemical potential energy and hydraulic potential energy have significant effects. Moreover, temperature, thermal diffusivity and thermal permeability coefficient all have effects on pore pressure. Therefore, the influence of temperature potential energy should be considered. Using field data in modeling can get results which show that the delayed time of the wellbore instability are respectively 2.5 and 8 days during horizontal drilling with the finely dispersed polymer drilling fluid and compound salt drilling fluid with the density of 1.2 g/cm3, and the wellbore enlargement ratio after 10-day soaking is only 9% when oil-based drilling fluids with the same density is used. When the delayed time is more than 10 days the oil-based drilling fluid is the best choice. |
