Thesis (M.Eng.)--Chulalongkorn University, 2009

Gas condensate reservoirs encounter a condensate blockage problem when the pressure around the wellbore falls below the dew point pressure. The amount of the liquid dropout depends on the composition of the reservoir fluid. If the percentage of liquid increases, it will restrict the production. Gas injection is the effective method to solve this problem and help increase recovery of the valuable condensate liquid. The objective of this study is to evaluate the effect of different reservoir fluid compositions on carbon dioxide injection in a gas condensate reservoir. Ten sets of reservoir compositions were selected. A compositional reservoir simulation was used to simulate the performance of carbon dioxide injection. The results show that composition of reservoir fluid has a significant effect on the optimum starting time for carbon dioxide injection. In order to maximize condensate recovery, the time to start carbon dioxide injection is the latest time that carbon dioxide injection can revaporize liquid dropout before carbon dioxide concentration reaches the limit. When the dew point pressure is high or maximum liquid dropout is low, the most optimum time of injection will be quite early. In the case that the initial reservoir pressure is equal to the dew point pressure, carbon dioxide injection rate has to be higher than the production rate in order to maximize condensate recovery. The higher injection rate will keep the reservoir pressure high. Thus, liquid dropout around the wellbore can be completely revaporized. However, if the injection rate is too high, early carbon dioxide breakthrough at the producer will cause an early abandonment of the production due to high carbon dioxide content in the produced gas. When the maximum liquid dropout is low, the most optimum injection rate will generally be high.