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Impact of oil polarity on the mixing time at the pore scale in low salinity waterflooding

Mohammadi, S ; Sharif University of Technology | 2020

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  1. Type of Document: Article
  2. DOI: 10.1021/acs.energyfuels.0c01972
  3. Publisher: American Chemical Society , 2020
  4. Abstract:
  5. The efficiency of low salinity waterflooding, particularly during tertiary mode injection, is highly controlled by in situ mixing between the stagnant regions holding high salinity water (HSW) and the flowing regions containing low salinity water (LSW) because it impacts directly the electrokinetics of wettability alteration and the time scale of the low salinity effect. This study aims to address the effects of oil polarity and charged rock surfaces on the time scale of mixing and transport under two-phase flow conditions. A systematic series of micromodel experiments were performed. The micromodels were first saturated with high salinity formation brine and oil (both model and crude oil); thereafter, HSW and LSW were injected sequentially and the mixing time was carefully monitored. Besides, the polarity of model oils was manipulated by adding oleic acid as the representative for the acidic functional groups of crude oil. In addition to the experimental work, conceptual computational fluid dynamics (CFD) simulations were performed to get further insights into the experimental observations and to identify the dominant parameters on the time scale of mixing in stagnant regions. The experimental results show that the time scale of ionic transport in stagnant regions can be slowed down 10-16 times by the increase of the polar fractions of oil, where the time scale cannot be simply described by the Fickian diffusion. It is postulated that the stronger electrical field established in the water film by the increase of oil polarity lowers the solute transport rate according to the Poisson-Nernst-Planck theory. The results were further verified by using crude oil which is highly polar and contains complex types of polar components such as resins/asphaltenes. Experimental results clearly indicated the electrokinetics effect as the time scale was increased even further. Nevertheless, the mixing time does not vary linearly with the polar group fraction and follows a rather logarithmic trend. The CFD simulation confirms that the effective diffusion coefficient (which is influenced by the oil polarity and the induced electric field) is the predominant parameter determining the time scale of mixing. Other parameters such as film thickness/film length and salinity gradient have comparatively a lesser effect on the time scale of mixing in the stagnant regions. ©
  6. Keywords:
  7. Computation theory ; Computational fluid dynamics ; Crude oil ; Electrodynamics ; Electrohydrodynamics ; Electromagnetic fields ; Electroosmosis ; Mixing ; Petroleum transportation ; Secondary recovery ; Solute transport ; Time measurement ; Two phase flow ; Acidic functional groups ; Computational fluid dynamics simulations ; Effective diffusion coefficients ; Induced electric fields ; Low-salinity water ; Poisson-Nernst-Planck theories ; Solute transport rate ; Wettability alteration ; Oil well flooding
  8. Source: Energy and Fuels ; Volume 34, Issue 10 , 16 September , 2020 , Pages 12247-12259
  9. URL: https://pubs.acs.org/doi/10.1021/acs.energyfuels.0c01972