Uneven Distribution of Asphaltene Deposits in CO₂ Flooding Path: Interpretation by Combining Thermodynamic and Micro-CT 3D Geological Porous Models

Abstract

Postcore flood analysis was conducted on a tertiary-mode CO2 flooding test under reservoir conditions. A composite carbonate core was retrieved to extract remaining hydrocarbons via Dean-stark distillation, and asphaltenes were measured in the extracted oil from each plug core using the IP-143 method. The analysis revealed uneven variation of asphaltene mass along plug cores: more asphaltenes were collected from the inlet-side core. To understand the mechanism of uneven in situ asphaltene-deposition, two numerical models were adopted that were based on thermodynamic and three-dimensional geological porous transport. The outcomes of thermodynamic modeling, using a cubic-plus-association model to estimate asphaltene precipitation as a function of CO2 concentration, proposed a scenario causing the uneven asphaltene distribution by incorporating vaporizing-gas-drive (VGD) into an asphaltene-destabilizing mechanism. This means more asphaltene deposition was predominantly caused when purer CO2 was in contact with fresh reservoir oil. The vaporized intermediate hydrocarbons in front, extracted through VGD, might dilute the injected CO2 concentration in the gas phase. This briefly caused the CO2 concentration to be higher in the inlet-side cores and lower in the outlet-side cores. Using a micro-CT scanned core, a 3D geological transport model was generated to estimate in-depth penetration of asphaltene particles in porous media. Three particle sizes (0.59–17.6 μm) were modeled as per visual inspection of destabilized asphaltene particles/aggregates that grew as oil was mixed with higher CO2 concentration (average particle diameters of 2.5, 3.6, and 17.6 μm for 0, 20, and 40 mol % CO2 addition). The setting of model particle sizes also considered the pore throat size distribution of the 3D geological transport model. The 3D transport model results propose a subsequent scenario in which smaller asphaltene spheres penetrate more deeply in porous media.

A Minireview of the Influence of CO2 Injection on the Pore Structure of Reservoir Rocks: Advances and Outlook

“…Khather et al 75 studied asphaltene precipitation during the CO 2 -EOR process in carbonate reservoirs and believed that with the increase of CO 2 concentration, asphaltene/resin precipitation increased, and more asphaltene precipitation was observed in higher-permeability samples. Yonebayashi et al 76 used the thermodynamic method and the micro-CT to comprehensively analyze the nonuniform distribution of asphaltene precipitation during CO 2 flooding, and the particle size of CO 2 -induced asphaltene grew with increasing CO 2 concentration. Recently, Huang et al 77 proposed that when the injection volume of CO 2 increased, the asphaltene precipitation showed a rapid increase first and then a slow increase, and the permeability damage rate increased.…”

Virtual Special Issue of the 21st International Conference on Petroleum Phase Behavior and Fouling (PetroPhase2020)

“…Okuno and coworkers 44 report a study of low-tension polymer flooding using novel short-hydrophobe surfactants for heavy oil recovery. Yonebayashi et al 45 report the uneven distribution of asphaltene deposits in CO 2 flooding paths, with interpretation by combining thermodynamic and micro computed tomography (micro-CT) three-dimensional (3D) geological porous models. Franco, Corteś, and co-authors 46 report a study on the injection of nanofluids with fluorosurfactant-modified nano- particles dispersed in a flue gas stream for EOR in tight gas− condensate reservoirs.…”

Effect of Wettability and CO2 on Asphaltene Precipitation in Shale Oil Reservoir

“…Pan et al 21 conducted research on asphalt precipitation generated by CO 2 injection in low-temperature oil reservoirs, introducing a new initial K-value evaluation method to modify the calculated fugacity value of PR-EOS, improving model robustness and reducing the calculation time of phase stability testing. Yonebayashi et al 22 studied the precipitation behavior of asphaltene with different mole fractions of CO 2 by the Soave−Redlich−Kwong equation of state (SRK-EOS) and cubic addition correlation model (CPA) for fluid characterization. In a shale reservoir, due to the nonuniformity of fluid density caused by the interaction between fluid molecules and pore wall, the traditional equation of state is not accurate in predicting the phase behavior of shale reservoir under the confined effect, so the above thermodynamic models are not applicable to the study of asphaltene precipitation in shale reservoir.…”