The reservoir fluid flow is characterized by relative permeability data, whose measurements are conventionally made in the laboratory on the cores acquired downhole of different rock types. The major drawback of such conventional core (SCAL) studies is their inability to capture the native wettability and in-situ reservoir fluid flow characteristics. Moreover, this lab based relative permeability data is sometimes unavailable, which requires one to estimate the relative permeability curves based on understanding of the reservoir or public literature and further tune the curves to match the actual pressure and production history of the reservoir during dynamic modelling. This process also incurs additional cost and requires additional time and efforts. Hence, an attempt has been made in this study to develop a novel workflow to estimate the relative permeability curves downhole using formation testers. This new method for interpreting relative permeability curves will complement the already existing conventional methods like SCAL and can also be used directly in the absences of lab data. In this approach, the Single Probe (PS), Pump Out (PO), and Fluid Analyzer (FA) modules of the Modular Formation Dynamic Tester (MDT) tool were assembled and set at the desired depth. Subsequently, the PO module was used to draw out the fluids from the formation and aid in recording the production and pressure drawdown data. The relative permeability of both oil and water phases were estimated at endpoint saturation using steady state approach, and the JBN method was applied after breakthrough and during transition phase using the displacement data (production and pressure data). The advanced well logs were used to interpret the other reservoir properties like porosity, permeability, and etc.