High-pressure brine overflow can cause stratification and precipitation of drilling fluid, degrading its performance and leading to serious accidents such as pipe sticking. The conventional practice to prevent and control brine overflow is to increase the drilling fluid density. However, this may induce severe lost circulation in weak formations, resulting in decreased wellbore pressure and further aggravated brine inflow. Controlled pressure drainage is a technique that gradually discharges brine and reduces formation pressure without increasing drilling fluid density. In this paper, the contamination of drilling fluid by brine during controlled pressure drainage is experimentally investigated. After adding 10%–60% brine, the drilling fluid density, viscosity, yield point, fluid loss, lubricity coefficient, and sedimentation stability were systematically evaluated to determine the allowable limits for drilling fluid maintenance and discharge. The results show that as the brine invasion increases from 10% to 60%, the density, viscosity, and gel strength of the drilling fluid gradually decrease, whereas fluid loss and lubricity coefficient increase, and sedimentation stability deteriorates, consistent with a dilution mechanism. It is proposed that the allowable brine invasion for drilling fluid treatment should not exceed 20%, which can be determined in the field by measuring a density reduction of 5%–10%. This experimental study on drilling fluid contamination enriches the understanding of controlled pressure drainage and provides a basis for safe drilling in high-pressure brine formations and the treatment of brine overflow.