Summary Associated gas needs to be handled properly, especially if the gas is deemed to be uneconomical, as flaring emerges as the first “ad-hoc solution” and, in many cases, prolongs for a long time. Such flaring practices are exercised even more for the gas streams with undesirable compositions such as high carbon dioxide (CO2), as the separation costs could be significant. When the daily amount reaches significant numbers such as ~60 MMscf/D, the impact in terms of greenhouse gas emissions, air pollution, and waste of resources becomes significant. In this study, we introduce new approaches for zero gas flaring coupled with supplemental CO2/gas injection, not only for mitigating flaring but also for recovery improvement. The feasibility of gas reinjection was assessed using real field data. Input data were evaluated using experimental information as well as numerical and custom-made machine learning models. Reservoir fluid characterization, based on the available pressure/volume/temperature (PVT) reports from two oil production wells and one shut-in gas injection well, was used to develop the equation-of-state (EOS) model in use. Moreover, the combination of produced gases and supplemental CO2 was evaluated in terms of solubility/swelling, miscibility, and compatibility with the in-situ reservoir fluids. The performance of gas reinjection was evaluated and optimized using the final calibrated reservoir simulation model for the gas injection process. This study quantifies the amount of incremental oil recovery and improved field performance from the reinjection of produced gas into an offshore high-temperature reservoir (270°F). Produced gas is intended to increase reservoir energy through repressurizing the reservoir and displacing the remaining oil with the optimized injection gas compositions, reducing the oil viscosity due to swelling, and lowering interfacial tension, which increases local displacement efficiency. Furthermore, the gas reinjection process relaxes the gas/oil ratio (GOR) constraints from 2,000 scf/STB up to 4,000 scf/STB, as excess gas can be utilized in the injection process. The placement of new gas injectors was optimized considering the existing gas injector location and by injecting into the gas cap near the gas/oil contact, while targeting the best rock types locally to ensure sustained injectivity. The outcome of this coupled process demonstrated enhancement in the reservoir energy management by mitigation of the gas coning due to the movement of the secondary gas cap toward the producers and ensuring optimal utilization of the natural reservoir energy in combination with the injection process. Furthermore, injecting gas updip in the formation and into the gas cap with an optimal injection rate yielded stable gas sweep efficiency with the help of gravity forces. In this study, reinjection of the produced gas considering reservoir heterogeneity, optimal injection gas compositions (including CO2 enhancement options), and a limiting injection pressure of 5,500 psi (below fracturing pressure) resulted in improved oil recovery (IOR) while reducing the gas emission and ensuring optimal utilization of reservoir energy. In this paper, we present guidelines for mitigating gas flaring by reinjecting the produced gas along with supplemental gas (where available), thereby reducing emissions.
Mondr Altownisi (Mon,) studied this question.