Alternatives to Minimize Scale Precipitation in Carbonate Cores Caused by Alkalis in ASP Flooding in High Salinity/High Temperature Applications

Abstract

Abstract Studying formation damage caused by chemical enhanced oil recovery (EOR) in a high-temperature/high-salinity (HT/HS) reservoir will help in developing guidelines to improve EOR performance during alkaline/surfactant/polymer (ASP) flooding by minimizing negative interactions between chemicals and reservoir components. Formation brines that have high concentrations of Ca2+ and Mg2+ can interact with injected fluid and cause precipitation and loss of injectivity. Operators during some ASP field studies have noticed negative interactions between injected chemicals with formation rock and fluids that resulted in scaling after initiation of ASP flooding. Several alkalis were evaluated to assess their scaling potential in high salinity formation brines and seawater as mixing brine at high temperatures. Four alkalis were evaluated; three inorganic alkalis sodium hydroxide, sodium carbonate, and sodium metaborate, and one organic alkali. In this study we evaluate the application of two novel alkalis and include scale inhibitor in the chemical slug to minimize precipitation of the sodium carbonate (alkali) when mixed with formation brine. Using organic alkali eliminates the need to soften the mixing brine and will result in expanding the ASP application to more challenging applications and reduce the softening cost for the mixing water. Including the scale inhibitor did assist in reducing the permeability loss as expected.