Modeling of gas flooding in high pressure reservoir using a compositional reservoir simulator

In this thesis, three phase relative permeability model and miscible fingering model were implemented into a compositional simulator. Two dimensional homogeneous reservoir simulations were performed using four different gases, and the performance and reservoir properties were compared after different gas flooding. The results show that CH4 injection, 96% CH4 + 4% C2 injection, and CO2 injection have high oil recovery of about 95%, while N2 injection leads to less than 60% oil recovery. N2 breakthrough the fastest and CO2 breakthrough the slowest. The reason is that N2 has the lowest viscosity while CO2 has the highest viscosity. In each of the four cases, recovery rate increases with time, possibly because the viscosity decreases as more gas dissolves in oil hence the overall viscosity decrease with time. Gas injecting from the top tends to have earlier breakthrough because the gravity assists the gas drainage process, but the ultimate recoveries are the same. The effect of flooding direction, swept orientation and well spacing on oil recovery were investigated. Swept orientation has the most significant effect on the oil recovery compared since swept orientation determines the areal swept efficiency. Diagonal sweeping has much higher areal swept efficiency than vertical sweeping since it sweeps larger area. Well spacing has more significant effect on oil recovery when the swept is vertical than diagonal, and larger well spacing leads to lower recovery since smaller area can be swept. Large well spacing also postpones the breakthrough time, especially for diagonal sweeping cases. Comparing the result of N2 flooding with and without fingering model, it can be seen that near miscible viscous fingering tends to lead to low recovery and earlier breakthrough.