Crude oil reservoirs have different temperatures, compositions, and pressures, therefore oil recovery performance by CO 2 injection varies from one case to another. Furthermore, it is predicted that lower interfacial tension between injected CO 2 and reservoir fluid results in more oil recovery. In this study, we investigate the effect of temperature on the equilibrium interfacial tension between CO 2 and three different oil fluids at different pressures. Also minimum miscible pressure (MMP) is measured by the vanishing interfacial tension (VIT) technique to determine the temperature effect on the CO 2 miscible gas injection. The results on different pure and mixtures of hydrocarbon fluids show that for pressures up to 5.2 MPa, the higher the temperature was, the lower was the interfacial tension (IFT) measured. However, for the cases with pressure higher than 5.2 MPa, as the temperature was increased, the IFT increased too. In addition the VIT technique is used to measure the MMP of CO 2 and pure paraffin; the heavier paraffin was, the higher was the MMP noticed. Also, we have learned that paraffin groups have an important effect on multicomponent interfacial tension behavior.

In this study, interfacial tension measurement (IFT) is utilized to assess the impact of temperature, pressure, and paraffin type on a nitrogen injection process as an efficient enhanced oil recovery method. The pure and equilibrium densities of oil in contact with nitrogen are examined to find IFT behavior and gas solubility in oil. The minimum miscible pressure (MMP) of different systems has been measured using the vanishing interfacial tension technique. The experimental results show that IFT decreases linearly with pressure, with two different slopes. The results indicate that IFT values decrease linearly with temperature at different pressure conditions. The obtained IFT values for (hexadecane + N 2 ) and (diesel fuel + N 2 ) systems are close to each other. The variation in IFT of nitrogen−paraffin systems by pressure shows a similar slope to that of the N 2 and oil mixture (diesel fuel) system. The MMP of different systems was observed to decrease with increasing temperature. The results of this work show that nitrogen injection would be an effective enhanced oil recovery process in high-pressure and high-temperature oil reservoirs.

Oil displacement and recovery efficiency during gas injection depends on the competition between driving forces and capillary resistance that is governed by gas−oil interfacial behavior. Detailed study of the interfacial forces during gas injection is the main objective of this research work. The effects of injecting gas composition and the possibility of asphaltene precipitation in a wide pressure range were determined through comprehensive experimental study. This was performed by measurement of interfacial tension of a highly asphaltenic Iranian crude oil in three surrounding gas mediums. The results showed that as pressure increases, the rate to reach miscibility reduces in the vicinity of the asphaltene precipitation onset. As the surface coverage of the asphaltene at the gas−oil interface exceeded a threshold value the rate was reduced furthermore. Component extractions, noncondensable gas film formation, asphaltene precipitation, and asphaltene accumulation at the interface are found to be the main parameters affecting the miscibility. The observations showed that miscible displacement is practically impossible for this asphaltenic crude oil. Dimensional analysis proved that pressure increase in N 2 and flue gas injection is not effective in improving oil recovery; however, CO 2 tests revealed the presence of optimum pressure range with highest gravity drainage potential and minimum capillary resistance.

Oil production from asphaltenic oil reservoirs has always encountered difficulties, such as plugging and unpredictable fluid properties. To physically recognize the aspects of asphaltene deposition, several dynamic and static asphaltene deposition tests were designed and performed on one of the giant south Iranian oil reservoirs using dead and live crude oil and real core samples. Moreover, the effects of fluid velocity on the extent of damage were investigated. It was found that surface deposition of asphaltene particles is the main source of formation damages in the porous media and the resulting permeability impairment obeys an exponential behavior. All of the experiments confirm that pore-throat plugging causes permeability reduction of the cores linearly with time until a new mechanism of pore-throat opening comes into effect. Decreasing fluid velocity, i.e., approaching the stagnant condition, extensively raises the asphaltene uptake, indicating that the amount of asphaltene existing for deposition increases and approaches the initial amount of precipitation. A three-phase, four-component black-oil simulator was developed and coupled with a deposition model. Subsequently, the simulator was verified by the experimental results and used for evaluation of different asphaltene deposition parameters. It was found that the pore-throat plugging mechanism is not properly included in the models, and therefore, the ability of current deposition models is under question. The results of this work elucidate some less addressed shadows of the asphaltene-related issues in porous media and could be a better framework for developing new models of deposition in porous media.

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