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The application of wellbore strengthening treatment has less effect on shale formations. Several numerical studies were developed to describe the mechanism, which promoted the development of wellbore strengthening theory. Previous studies explored the mechanism mainly by considering the seepage flow. Therefore, multi-field coupled models were established to analyze the solute transmission, thermal convection, and heat conduction on wellbore strengthening by introducing the theory of multi-field coupling into physical model. First, the fracture width distribution and wellbore tangential stress were investigated to research the interaction of thermal and chemical effects with different gradients. Then, the concrete mechanism of temperature and solute concentration gradient was analyzed based on the distribution of pore pressure and stress field. Results show that the prediction of hoop stress and fracture aperture may not be accurate without considering the influence of solute transfer, thermal convection, and heat conduction, because stress state is mainly affected by temperature field and the pore pressure varies greatly under different chemical gradients. Additionally, the lower temperature and larger solute concentration improve the wellbore strengthening effect of drilling fluid.

Drilling fluid with proper rheology, strong shale, and hydrate inhibition performance is essential for drilling ultralow temperature (as low as −5 °C) wells in deepwater and permafrost. In this study, the performance of drilling fluids together with additives for ultralow temperature wells has been evaluated by conducting the hydrate inhibition tests, shale inhibition tests, ultralow temperature rheology, and filtration tests. Thereafter, the formulation for a highly inhibitive water-based drilling fluid has been developed. The results show that 20 wt % NaCl can give at least a 16-h safe period for drilling operations at −5 °C and 15 MPa. Polyalcohol can effectively retard pore pressure transmission and filtrate invasion by sealing the wellbore above the cloud point, while polyetheramine can strongly inhibit shale hydration. Therefore, a combination of polyalcohol and polyetheramine can be used as an excellent shale stabilizer. The drilling fluid can prevent hydrate formation under both stirring and static conditions. Further, it can inhibit the swelling, dispersion, and collapse of shale samples, thereby enhancing wellbore stability. It has better rheological properties than the typical water-based drilling fluids used in onshore and offshore drilling at −5 °C to 75 °C. In addition, it can maintain stable rheology after being contaminated by 10 wt % NaCl, 1 wt % CaCl2, and 5 wt % shale cuttings. The drilling fluid developed in this study is therefore expected to perform well in drilling ultralow temperature wells.