Several researchers employed N2 to augment CH4 recovery efficiency and CO2 sequestration during the Enhanced Gas Recovery (EGR) process in consolidated rocks. To our knowledge, there has been limited data backing the reason why CO2 experienced a more extended breakthrough during the EGR process in the presence of N2 gas. This study inves-tigated CO2 and N2 behaviour during the core flooding experiment by CO2 injection in Bentheimer core plug. N2 was used as the continuous phase during the core flooding process, while CO2 was the dispersed phase. The experiment was designed with varying injection rates at 30 and 40 0C temperature points. The experimental findings showed that the dispersion and diffusion coefficient, CO2 storage, concentration profile and breakthroughs were highly influenced by temperature change, especially at lower injection rates. However, at high injections, those properties are less sensitive to change in temperature, with most of the curves overlapping in the concentration profile. The highest and most negligible dispersion and diffusion coefficients were recorded at the highest and lowest injection rates respec-tively. These results agree with those reported by several researchers for sandstone rocks. Thus, higher temperatures have a more substantial effect on dispersion and diffusion coefficient, which eventually led to higher mixing between CO2 and N2. The breakthrough time decreases with an increase in reservoir temperature, confirming the diffusion and dispersion coefficients are temperature dependent. The experiment at 30 0C recorded an extended breakthrough time over that at 40 0C. The maximum breakthrough time at 0.52 PV was recorded at 30 0C at the lowest injection rate. The concentration profile highlighted the trend between the displacing and displaced gas during the core flooding experiment. From the range of injections and temperatures tested, the CO2 PV stored decreases as the rate of injection increases from 0.4 – 1.2 ml/min. However, the CO2 stored was more promising at higher rates, corresponding with high differential pressure, due to flow resistance within the tortuous flow channels in the porous medium.
