Thesis (M.Eng.)--Chulalongkorn University, 2008

Increasing condensate recovery in a gas condensate reservoir is a challenging task. When the reservoir pressure falls below the dew point, retrograde condensate condenses and accumulates in the pore system, causing a blockage problem. Furthermore, some of the valuable condensate will be left in the reservoir as residual oil. One of the most effective methods of solving this problem is to injecting gas into the formation. Gas injection allows enhanced condensate recovery by reservoir re-pressurization and liquid re-vaporization. The injected gas can be natural gas or other inert gases, depending on availability. The use of CO2 as injected gas also achieves the purpose of CO2 sequestration into geological storage. In this study, a compositional simulator was used to simulate CO2 injection in a hypothetical gas condensate reservoir. The simulation results show that CO2 injection does effectively maintain reservoir pressure above the dew point pressure, preventing condensate dropout within the reservoir. When injecting CO2 after condensate accumulates, CO2 can still re-vaporize liquid drop-out around the wellbore. The simulation results also demonstrate that gas production and CO2 injection rate do not have significant effect on oil and gas recovery. However, the starting time for CO2 injection has important effects on hydrocarbon recovery. To obtain the maximum oil recovery, the injection should start shortly after the bottomhole pressure drops below the dew point pressure.