Fluid penetration from water-based drilling fluids into shale formations results in swelling and subsequent borehole instability. Generally, inorganic or organic salts are used to generate necessary chemical osmotic pressure to inhibit shale hydration and swelling. However, the relationship between salt ions and shale osmotic pressure is not clear. In this study, a dynamic model is proposed to determine osmotic pressure of Longmaxi shale, Southwest China. In addition, the model considers the pressure changes under actual working conditions and the influence of the solution seepage process in shale pores. The osmotic pressure and discipline of Longmaxi shale with NaCl, KCl, CaCl₂ and HCOONa were analyzed. Results indicate that the osmotic pressure of KCl and HCOONa decreases with increasing salinity, and the osmotic pressure of NaCl first decreases and then increases with increasing salinity. Calculated results and experimental results have been compared in the study, and the reliability of the model for Longmaxi shale has been proved. The Longmaxi shale has the lowest osmotic pressure value at a salinity of about 0.25 for NaCl solution. Moreover, experimental and theoretical calculation results indicate that the osmotic pressure in Longmaxi shale is lower than 0.2 MPa and is not enough to have a decisive effect on borehole stability. However, the KCl solution with a high concentration can reduce the osmotic pressure by 1.8 MPa as CEC is 0.3 meq/g. The established model with different salt ions can provide theoretical and technical support for low-clay shale gas development.