Surfactant/polymer flood design for a hard brine limestone reservoir

Abstract

A limited number of laboratory studies and pilot programs have been reported in chemical Enhanced Oil Recovery (EOR) flooding of carbonate reservoirs (Adams & Schievelbein, 1987). Fewer still have involved surfactants in limestone reservoirs. No surfactant/polymer flood on a field wide basis of a carbonate reservoir has ever been documented in the literature (Manrique, Muci, & Gurfinkel, 2010). This void represents a colossal opportunity given that nearly a third of the 32 billion barrels of oil consumed in the world each year come from carbonate reservoirs (Sheng, 2011, pp. 1, 254).

This thesis is based on experiments with a high hardness (~5,000 ppm divalent ions) carbonate field. Phase behavior, aqueous stability, and core flood experiments were performed using polymer and various surfactants and co-solvents. Both commercially available and laboratory synthesized surfactants were tested. The objective was to optimize the chemical injection design in order to lower interfacial tension between water and oil in the reservoir. Research was also done with alkali intended for use with hard brines.

The main challenges when working with hard brine were poor solubilization and low aqueous stability limits. However, highly propoxylated and ethoxylated surfactants mixed with internal olefin sulfonates, hydrophilic sulfates, and sec-butanol were observed to have very high solubilization ratios, fast phase behavior equilibration times, negligible viscous macroemulsion effects, and excellent aqueous stability. Spinning drop interfacial tensiometer tests confirmed low IFT values were obtained for a range of acceptable salinities with hard brine.

Three core floods were performed using one of the surfactant formulations developed. One flood was done with field core, brine, and crude oil and failed to meet expectations because of high levels of heterogeneity (vugs) within the core that lead to an elongated oil bank and low and slow oil recovery. The other floods were done with Estillades Limestone. The first Estillades flood used hard synthetic field brine and had better mobility but poor oil recovery. The last core flood had good mobility and recovered 90% of the residual oil to water flooding, but only after a total of 1.1 pore volumes of 1.0 wt% surfactant solution were injected. The results provided in this thesis constitute proof of concept that S/P flooding can be done in high salinity and hardness reservoirs.