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Gas injection is a well-known method for enhancing oil recovery (EOR). The utilization of greenhouse gases, such as carbon dioxide (CO2) or flue gas, offers the dual advantage of reducing greenhouse gas emissions while potentially enhancing the sweep efficiency in oil recovery. Nevertheless, one of the notable challenges encountered when using these gases is the precipitation and deposition of asphaltenes, leading to formation damage and a decrease in reservoir permeability, particularly in the case of light oil reservoirs. In this study, CO2 and flue gas were injected into an elongated core sample comprising four individual core plugs under reservoir conditions to displace the light live oil. The recovery factor and asphaltene deposition along the core holder were assessed and compared as two crucial parameters within the gas injection scenario. Our results indicate a significantly higher recovery factor of 86% achieved with CO2 injection compared to 36% with flue gas injection, attributable to differences in their interfacial tension and miscibility. However, the CO2 injection method exhibits more pronounced formation damage. Individual assessment of each core plug reveals that permeability impairment is most acute in the initial two core plugs, situated closer to the injection face of the extended core. These findings enhance our understanding of the mechanisms contributing to permeability impairment resulting from asphaltene deposition during CO2 and flue gas injection for EOR. [ABSTRACT FROM AUTHOR]

Base gas replacement by a cheap gas is one of the approved methods to reduce the cost of investment in underground gas storage process. Maximizing the amount of replaceable base gas is an attractive issue. However, the amount of base gas replacement can be reduced due to some limiting factors. By changing the composition of the candidate base gas, it is possible to obtain a smart gas with an optimized composition through which all limiting factors are simultaneously satisfied. In the present study, the feasibility of this idea is investigated in a real depleted gas reservoir by flue gas as the candidate gas with the aid of GEM compositional simulator and proxy model. The proxy model and Excel Solver optimization tools are used to improve the speed and accuracy in determining the optimum composition of flue gas composition. In addition, the effect of flue gas composition on the reservoir pressure and gas deviation factor is analyzed during gas storage cycles. The results show that when the CO2 content of the flue gas exceeds a specific value, carbon dioxide effect is dominant, which increases the wetting effect of the flue gas. In this case, the simultaneous injection of flue gas and storage gas in odd cycles reduces the reservoir pressure and the reservoir gas deviation factor. The results indicate that it is possible to replace 28.4% of the base gas and reach an enhanced gas recovery of about 18.55% in the reservoir under study using the optimized replacing gas composition of 17.24% CO2 and 82.76% N2. [ABSTRACT FROM AUTHOR]

Base gas is considered as an important factor in the storage operation as it remains permanently in the reservoir and maintains the reservoir pressure along the production cycle. Depending on the reservoir under consideration, base gas may occupy as little as 15% or as much as 75% of the total underground gas storage (UGS) reservoirs. Providing and injecting the cushion gas has the most contribution to the cost of the storage operations. Therefore, part of the base gas can be replaced by a cost-effective gas such as nitrogen, flue gas or air to reduce the costs of the investment. Some degree of mixing takes place when two miscible gases come into contact with one another that affects the quality of the produced natural gas. Therefore, the process needs to be studied and controlled. In this study, the feasibility of underground gas storage and the substitution of the base gas by a cheaper gas, i.e., nitrogen, flue gas, and air, are investigated in a partially depleted dry gas reservoir with very low initial pressure. To do so, a comparative study is performed among nitrogen, flue gas and air as the alternative gases to the base gas. In addition, the effect of flue gas composition on the performance of base gas replacement and ultimate gas recovery is investigated. Pure CO2 is considered as flue gas with zero mole% N2. In the end, the effect of the reservoir properties on mixing between the gases is studied. The results indicated that it is possible to substitute 24.8% of the base gas by nitrogen to obtain a 16.2% increase in the gas recovery of the reservoir. In this case, the ultimate recovery reaches 50.90%. Using flue gas as the alternative gas, the results showed a 15.6% increase in the gas recovery of the reservoir, obtained by substituting 23.9% of the base gas. The ultimate recovery using flue gas is 50.31%. According to the results, flue gas can be used as an appropriate option to replace the base gas of the UGS reservoir under consideration, and hence, there would be no more need for separation and purification of N2 and CO2. Increasing the CO2 composition in the flue gas up to 46.6 mole% leads to a decrease in the base gas replacement amount. When the composition increases above 46.6 mole%, the amount of the replaced gas does not change. However, in this composition range, more flue gas is injected into the reservoir, which has environmental advantages. The highest injection rate of the flue gas is obtained when the flue gas contains 100 mole% of CO2. The main problem in using air as the base gas is the high viscosity of air which requires a high injection pressure. According to the results, using air as the replacement gas, 21.3% of the base gas is substituted by air. In this case, gas recovery increases by 13.9% with respect to the reservoir depletion scenario and the ultimate recovery reaches 48.62%. [ABSTRACT FROM AUTHOR]