Numerical Modeling of Continuous Gas Injection Under Immiscible and Near-Miscible Conditions in Tight, Transition Zone Carbonates – The Role of Relative Permeability

Abstract

Abstract Significant volumes of light oil are stranded in tight, thin and transition zone carbonate reservoirs. Waterflooding in these fields is not feasible due to poor water injectivity, and hence lack of pressure support required for commercial production. Continuous gas/CO2 injection (CGI) has the potential to unlock these volumes as it can offer better injectivity and higher recovery factors. However, the low reservoir pressure of these reservoirs would result in gas injection under immiscible or near-miscible conditions. The modeling of this process is challenging due to the high sensitivity of oil recovery to relative permeability curves. In addition, the injected gas will be displacing water as well because of the presence of mobile water in the reservoirs, which impacts the oil mobility. This study presents a numerical simulation of CGI in tight, thin carbonate reservoirs, where the entire oil column is in the transition zone. Fine-scale pattern models were developed to account for reservoir heterogeneity and minimize numerical artifacts. The numerical model was run using commercial compositional simulator, with the EOS model based on advanced PVT experiments to capture all mass transfer effects between injected gas and oil. An oil-water relative permeability hysteresis model was applied to accurately model water mobility in the transition zone. Additionally, an IFT-dependent oil-gas relative permeability model was implemented to consider the changes in relative permeability with IFT. The PVT and relative permeability models were calibrated to laboratory data and the forecast was validated against field production data under depletion and waterflood trials. Various injected gas types, including CO2 and hydrocarbon (HC) gases with different compositions, were tested to examine their impact on recovery factors and net gas utilization factors (NGU). The oil-water hysteresis model successfully replicated the low water-cut behavior observed in the field despite high initial water saturation. Field-scale results demonstrated that IFT-dependent relative permeability was important for evaluating recovery factors for different gas injectants, as each gas type exhibits different miscibility and IFTs during injection. The numerical model proved that gas could deliver higher injection rates than waterflood, which led to oil production acceleration. Moreover, gas injection resulted in higher oil recovery when injected near-miscible conditions. To our knowledge, this is the first paper to present a calibrated numerical model combining IFT-dependent relative permeability and hysteresis during CGI under near-miscible/immiscible conditions in the transition zone. The model's validation against field production/injection data and coreflood experiments demonstrated the robustness of the modeling methodology. Additionally, this study highlights the significance of proper relative permeability measurements for gas flooding under such conditions. The study also highlights the viability of gas injection under near-miscible conditions to unlock unconventional oil in thin and tight formations.

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