AUTHOR=Wu Shuai , Wu Jianfa , Liu Yong , Yang Xuefeng , Zhang Juan , Zhang Jian , Zhang Deliang , Zhong Bing , Liu Dongchen TITLE=Lattice Boltzmann modeling of the coupled imbibition-flowback behavior in a 3D shale pore structure under reservoir condition JOURNAL=Frontiers in Earth Science VOLUME=11 YEAR=2023 URL=https://www.frontiersin.org/journals/earth-science/articles/10.3389/feart.2023.1138938 DOI=10.3389/feart.2023.1138938 ISSN=2296-6463 ABSTRACT=

Imbibition and flowback of fracturing fluid usually occur in the shale matrix after hydraulic fracturing, which significantly impacts shale gas production and environmental protection. The rocks of deep shale gas reservoirs are under high-temperature and high-temperature conditions. There are rich micro-nano pores with various pore structures in deep shale. In addition, the flowback behavior is significantly affected by the imbibition behavior because the flowback begins after the end of the imbibition. Therefore, an accurate pore-scale description of the coupled imbibition-flowback behavior is crucial to understand the flowback mechanism and its impacts. In this paper, a pseudo-potential lattice Boltzmann method is employed to simulate the coupled imbibition-flowback behavior in a digital shale core, where the digital core is reconstructed by Markov Chain-Monte Carlo method based on scanning microscope images of deep shale cores. The microcosmic mechanism of the imbibition and flowback is studied under deep shale conditions. The influence of some factors, such as pore structure, fluid viscosity, wettability, and flowback pressure difference, on the flowback behavior of fracturing fluid is investigated. It is found that the fracturing fluid advances almost uniformly throughout the pore space during the imbibition process. The fracturing fluid is easy to adsorb on the pore wall, and the shale gas is located in the middle of the pore space. The viscous fingering is clearly observed during the flowback process, where shale gas flows through large pores to form a flow channel, and the fracturing fluid stays in tiny pores. The flowback rate increases gradually with the flowback time and eventually tends to be almost constant. The wettability, flowback pressure difference, and pore structure significantly influence the flowback behavior, while the fracturing fluid viscosity has a smaller effect on the flowback process.