Asphaltene aggregation onset during high-salinity waterflooding of reservoirs (a molecular dynamic study)

TL;DR

This study uses molecular dynamics simulations to show that high-salinity brine delays asphaltene aggregation during waterflooding by reducing water miscibility in oil, contrasting with low-salinity effects.

Contribution

It provides new molecular-level insights into how high salinity influences asphaltene aggregation onset during reservoir waterflooding.

Findings

High salinity delays asphaltene aggregation onset.

High salinity reduces water miscibility in oil at reservoir conditions.

Salt-in effect varies across different asphaltenic oils.

Abstract

The primary objective of this study is to establish an understanding of the role of high-salinity brine on the intensity of asphaltene aggregation onset during waterflooding of petroleum reservoirs. We already have shown that asphaltenes have a high tendency to form aggregates during waterflooding process when pure- and low salinity-water are injected into reservoirs. To fulfill the present objective, molecular dynamic simulations are performed on asphaltenic-oil/aqueous systems. The oil phase consists of asphaltenes and ortho-xylene, in which asphaltene molecules are completely soluble. Our simulations results reveal that the salt-in effect of high-salinity brine on seven different model asphaltenic oils causes a significant reduction of the onset of asphaltene aggregation as compared with pure-water. Such salt-in effect is primarily due to a considerable reduction of water miscibility in the oil phase at high pressure and temperature.