Laboratory Study of Injection Strategy for Low-Tension-Gas Flooding in High Salinity, Tight Carbonate Reservoirs

Abstract

Abstract It has been experimentally observed 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 improves 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 can make this process economically challenging. In order to optimize the LTG process, an injection strategy has been designed such that the oil recovery can be maximized, using a minimum amount of the injected gas and the surfactant, thereby ensuring a more economically-viable recovery process. A low-permeable (<10 md) Middle Eastern limestone reservoir with a high formation brine salinity (~200,000 ppm and hardness 19,000 ppm) is the target reservoir of this study. Surfactant injection strategy was optimized by varying the concentration and pore volumes of the surfactant slug injected. Nitrogen gas was co-injected during select time periods throughout the entire chemical 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 dynamic adsorption data for each of the three classes of surfactants used.