Experimental study of injection strategy for Low-Tension-Gas flooding in low permeability, high salinity carbonate reservoirs

Abstract

Previous experimental studies have proven that Low-Tension-Gas (LTG) flooding can be a suitable enhanced oil recovery (EOR) method for low-permeability carbonate reservoirs with high salinity and hard formation brine. LTG flooding was observed to improve oil recovery by combining two effects: a reduction of the interfacial tension (IFT) between oil and water and mobility control through the formation of in-situ foam with an injected gas. However, the high cost of chemicals and/or the limited supply of gas could make this process economically challenging.In this study, the primary goal was to reduce the amount of injected gas and surfactant to make the LTG process more economically feasible. A low-permeable (<10 mD) limestone reservoir with a high formation brine salinity (>200,000 ppm and hardness 19,000 ppm) and temperature 69 °C was the target reservoir of this study. Effect of varying the concentration and pore volumes of the ultra-low IFT inducing surfactant slug injected on oil recovery was studied. Nitrogen gas was co-injected during selected time periods throughout the entire surfactant injection in order to identify the significance of mobility control during the crucial phases of the LTG flooding. The coreflood results emphasized the significance of the injection of gas, even at lower foam quality, for the maintenance of mobility control. Ultimate oil recovery of over 60% (residual oil post waterflood) was achieved, even after reducing the surfactant concentration by 75% and inducing a different in-situ salinity profile as compared to earlier studies. An innovative method for measuring surfactant adsorption using Liquid Chromatography and Mass Spectrometry (LC-MS) was developed, which could provide individual surfactant transport data for each of the three classes of surfactants used.