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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]

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]

The injection of solid stabilized water-in-crude oil emulsion to displace heavy crude oil is a new EOR method. Although high emulsion stability, which is essential for achieving the maximum process efficiency, can be obtained using nanoparticles, developing an inexpensive and environmentally friendly technique that improves emulsion stability is highly beneficial to this method. Magnetic field and magnetized water technologies have such capabilities. Contact angle reduction on solid surfaces is among the modifications that occur in the properties of water due to the magnetization. Although studies show that using these technologies might be amenable for enhanced oil recovery, there has been no investigation into their use to alter conventional and solid stabilized water-in-crude oil emulsion stability. In this study, the magnetized water, prepared with distilled water, is used in the process of emulsion preparation and the resulting emulsion stability is compared to that prepared with normal water. Our findings show that using magnetized water improves the stability of solid stabilized emulsion made with fumed silica and iron oxide nanoparticles, while it does not impact the stability of conventional emulsions. Lower three-phase contact angle in case of using magnetized water compared to that of normal water implies that the hydrophobic nanoparticles more rigidly stick to the oil-water interface and more energy is required in order to detach them from the interface. This results in more stable solid stabilized emulsion. Results indicate that applying the magnetic field to a prepared conventional emulsion makes it a bit less stable. The reorientation of asphaltene molecules and resulting disturbance of the interface layer, along with the oil viscosity reduction, which accelerates the coalescence of dispersed water droplets, results in less stable emulsions. Although applying the magnetic field to the solid stabilized emulsion, prepared with fumed silica nanoparticles, has no effect on its stability, it significantly reduces the stability of the iron oxide nanoparticle stabilized emulsion. The magnetic force that exists between the magnets and the iron oxide nanoparticles, forcibly separates them from the interface and leads to emulsion breakage. The findings of this study could help in better understanding of the mechanisms involved in the stability of solid stabilized emulsions. Besides, a new field, in which the magnetized water can be successfully applied, is introduced. • The contact angle of water on solid surfaces reduces due to magnetization. • Using magnetized water results in a more stable SSE than normal water. • Applying a magnetic field on a conventional emulsion makes it slightly less stable. • Applying a magnetic field on an iron oxide made SSE causes severe instability. [ABSTRACT FROM AUTHOR]