Experimental and Theoretical Studies on Foam Flooding in Tight Reservoirs

Abstract

Enhanced oil recovery for tight reservoirs with extremely low permeability and porosity is becoming the new routine for reservoir engineering research. Foam flooding has already been proven as an effective and potential approach to enhance the oil recovery in conventional reservoirs. However, limited research has been done on the phenomena and mechanism of foam performance in tight porous media. In this study, both experimental and theoretical approaches are utilized to study the foam flooding process in tight reservoirs. In the experimental part of this study, a series of core flooding tests are performed to investigate foam performance in the absence and presence of oil in tight core samples with different permeabilities, varying from 0.1mD to 3.3 mD. The foam resistance factor, mobility reduction factor, and mobility of the displacing fluid are investigated by comparing the foam flooding processes with waterflooding and the co-injection processes of brine and gas. The effectiveness of applying foam flooding as a tertiary recovery method is studied by comparing the production data, pressure drop data, and mobility of displacing fluid between foam flooding and waterflooding. The fractional flow theory of the foam process is applied to study the relation between the fractional flow of gas and water to present how gas is trapped in porous media by foam. The experimental results show the effectiveness of foam on reducing mobility compared with waterflooding and the co-injection of brine and gas. An additional 15 to 22% oil recovery factor is achieved by introducing foam flooding after waterflooding is completed. The foam mobility is lowered by one order of magnitude compared with waterflooding in the presence of oil. In the theoretical part of the study, a theoretical model is established to predict the dynamic performance of surfactant-alternating-gas (SAG) flooding by considering the major mechanisms in this process, such as gas channeling caused by an unfavorable mobility ratio, gravity segregation, and the instability of foam. Oil production estimated by the proposed theoretical model is compared with numerical simulation and field production data collected from the Ganguyi project in China, and the growth trend of oil production agrees well with them. The proposed model provides a fast approach to predict the dynamic performance of surfactant-alternating-gas flooding, and it can be used as a tool to optimize the operational parameters.