Perpustakaan Digital ITB

Gas flaring in oil and gas production facilities significantly contributes to greenhouse gas emissions, representing both an environmental and economic loss. One promising mitigation strategy is to utilize flare gas as an injection fluid in miscible gas flooding enhanced oil recovery (MGF-EOR). This study compares the technical feasibility of flare gas injection to conventional CO? injection by estimating the Minimum Miscibility Pressure (MMP) using a tie-line length approach. A thermodynamic computational model was implemented in Python, applying Peng–Robinson (PR) and Soave–Redlich–Kwong (SRK) equations of state for vapor–liquid equilibrium calculations via flash analysis. Simulations were performed on a synthetic 11-component reservoir oil at four temperatures (50°C, 70°C, 90°C, and 110°C) for two injection scenarios: pure CO? and flare gas (91% CH?, 9% C?H?). Results indicate that CO? consistently achieves miscibility at lower pressures (7.6–12.9 MPa) compared to flare gas (>20 MPa), with shorter tie-line lengths and narrower two-phase regions. While flare gas shows technical potential, its high MMP requirement limits applicability in reservoirs with moderate pressures unless gas enrichment or pressure enhancement is applied. The findings align with literature and experimental slim tube data, supporting PR EoS as the preferred model for stability and accuracy in cubic EoS-based MMP estimation.