Some of Iranian oil reservoirs suffer from operational problems due to asphaltene precipitation during natural depletion, so widely investigation on asphaltene precipitation is necessary for these reservoirs. In this study, a reservoir that is candidate for CO 2 gas injection process is selected to investigate asphaltene precipitation with and without CO 2 injection. In this case, asphaltene precipitation is monitored at various pressures and reservoir temperature. Then, a series of experiments are carried out to evaluate the amount of precipitated asphaltene by injection different molar concentrations (25%, 50%, and 75%) of CO 2 . The results show that during primary depletion the amount of precipitated asphaltene increases with pressure reduction until bubble point pressure. Below the bubble point the process is reversed (i.e., the amount of precipitated asphaltene at bubble point pressure is maximum). The behavior of asphaltene precipitation versus pressure for different concentrations of CO 2 is similar to primary depletion. Asphaltene precipitation increases with CO 2 concentration at each pressure step. In the modeling part, solid model and Peng-Robinson equation of state are employed which show a good match with experimental results.

The oil recovery improvement by low-salinity waterflooding (LSWF) must be achieved with minimal formation damage. The asphaltic fractions of crude oil can be destabilized when in contact with incompatible injection brines resulting in organic formation damage. Due to the lack of fundamental understanding about the potential effect of rock presence on this phenomenon, in this study, the simultaneous effect of brine salinity and calcite rock presence on asphaltene instability in an emulsified system was investigated by developing a new experimental protocol. In this method, calcite rock is dispersed in different brines with total salinity ranging from 0−189,365 ppm and then mixed with oil to find the rock and brine effect on asphaltene and emulsion stability. UV−vis spectroscopy is performed on the supernatant oil phase before and after contact with brine to assess quantitatively asphaltene instability. Oil/water IFT measurements before and after contact and microscopic analysis of the water droplet size were conducted to evaluate the water/oil interface behavior. Besides, the zeta-potential for suspended calcite particles in different brines was measured to evaluate the electrokinetics of rock-oil interaction. The results show increased asphaltene instability when oil makes contact with the brine in an emulsified system. This highly depends on the brine type, and the maximum precipitation occurred at an intermediate salinity with two-times diluted seawater. While the trend of before-contact IFT and the water-in-oil emulsion size at different salinities is consistent, the UV−vis absorbance of bulk oil shows a reverse tendency with the after-contact IFT. Asphaltene deposition generally increased when solid calcite particles were present in the emulsified system, and at higher salinities, more asphaltene adsorption on the rock surface occurred due to a larger attractive force between rock and asphaltene. This trend is consistent with the results of the zeta-potential measurements. These novel findings can help avoid unrepresentative results regarding organic damage in LSWF.