Performance analysis of chemical flooding in fractured shale and tight reservoirs

To enhance the oil recovery in fractured shale and tight oil reservoirs, many efforts have been made to add surfactants in injection water and fracturing fluid. Most of the efforts were to conduct experiments to screen surfactants. To the best of our knowledge, there is no paper to provide numerical analysis of the surfactant performance in fractured shale and tight reservoirs. In particular, how the fracture network affects chemical flooding performance has not been addressed. This paper is to use numerical simulation approach to analyze the performance of chemical additives (alkali and surfactant) in fractured shale and tight rocks. The base simulation model is based on history-matching an experiment. The effects of wettability alteration, interfacial tension (IFT), capillary pressure, and pressure gradients are investigated. To aid our understanding and interpret the results, the results from high-permeability models are compared with shale and tight models. We found that if the rock is oil-wet, it is very slow for a chemical to diffuse into the shale or tight matrix to alter wettability, so the oil recovery is not very sensitive to the value of capillary pressure. In shale and tight reservoirs, using surfactants to achieve ultralow IFT may not be effective, because the surfactant solution with ultra-low IFT cannot enter the matrix and will break though producers, and oil in the matrix will be bypassed. And increasing the pressure gradient may not be effective because a high-pressure gradient will aid breakthrough, instead of enhancing injected fluid invasion into the matrix.