Multiphase relative permeability describes the ability of different fluid phases (e.g., oil, water, and gas) to flow simultaneously through a porous medium. It is defined as the ratio of a phase’s effective permeability to the absolute permeability of the rock. The principle is based on the fact that when multiple fluids coexist, they compete for pore space, affecting flow behavior. Relative permeability is a function of fluid saturation, meaning that as the saturation of one phase increases, the permeability of the other phase decreases. Wettability plays a crucial role, determining which phase preferentially occupies the smaller pores. Capillary pressure also influences fluid distribution, impacting flow resistance. Additionally, residual saturation occurs when a portion of a phase remains trapped due to capillary forces, limiting complete displacement. Experimental determination of relative permeability is conducted through core flooding tests, where fluids are injected into rock samples under controlled conditions, and flow rates are measured. Empirical models such as Corey’s equations and the Brooks-Corey model help predict permeability variations.