<p>Significant amounts of residual oil can remain trapped after primary and secondary recovery stages, which can be effectively recovered using tertiary gas injection processes. While tertiary gas injection in water-swept reservoirs has been widely studied, the characterization of tertiary enriched gas injection following secondary lean gas injection remains underexplored. One critical challenge is the lack of gas–oil relative permeability and capillary pressure functions specific to this process, which play a key role in controlling multiphase flow behavior and oil mobilization. To address this gap, a series of coreflood experiments was performed by injecting lean gas followed by enriched gas into a low-permeability carbonate core. The CMG/GEM compositional simulator, coupled with the Design Exploration Controlled Evolution (DECE) history-matching algorithm, was used to match experimental data, including oil recovery, cumulative gas production, and pressure drop. Relative permeability and capillary pressure curves for tertiary enriched gas injection were derived from these simulations. Results showed the ultimate oil recovery increased by 12%. Analysis of ternary diagrams and produced fluid composition indicated that residual oil was mobilized primarily through a combined vaporizing–condensing mechanism. This study demonstrates the potential of tertiary enriched gas injection as an effective recovery strategy for reservoirs subjected to prior lean gas flooding.</p>