Lab and Field Scale Modeling of Near Miscible CO2 Injection in Different Porous Mediums

The main purpose of this investigation is to study the effect of near miscible CO2 injection in different porous mediums on both lab and field scales. This effect can be traced by the change of two-phase gas-oil relative permeability curves. In this work, the experiments have been performed on three rock types (i.e. sandstone, dolomite, and artificial fractured sandstone) based on an incremental pressure algorithm approaching a near miscible condition. Lab-scale inverse modeling has been used to calculate relative permeability curves. Based on the experimental results, 85%of minimum miscibility pressure was defined as the near miscible pressure. Comprising the relative permeability curves in immiscible and near-miscible conditions, the results show that this change has become less significant from sandstone core type to artificial fractured. In other words, near miscible CO2 injection would be recommended in rock types with a lower RQI. In addition, it was concluded that in the case of artificial fractured, simple conventional relative permeability methods obtain the same results as sophisticated inverse modeling method. Furthermore, in order to validate the lab scale results, the field scale modeling of the candidate reservoir was done using the 3D compositional reservoir simulator. 83% of minimum miscibility pressure was defined as near miscible pressure. Moreover, the simulation results confirmed lab-scale data regarding the recovery factor in different rock types. Additionally, the economic evaluation (NPV analysis) showed that use of near miscible CO2 injection in lower RQI reservoirs was more economical rather than the other scenarios.