Lattice Boltzmann modeling of the coupled imbibition-flowback behavior in a 3D shale pore structure under reservoir condition

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.

Distribution Characteristics and Backflow Flow Pattern of a Slickwater Fracturing Fluid in Shale Based on Low-Field Nuclear Magnetic Resonance

“…In this case, the goal is to compare the relative effects of multiple independent variables on the dependent variable. Therefore, standardized regression coefficients are used. , Typically, a significance value below 0.05 is considered statistically significant, indicating that the linear regression is valid. Due to operational errors and uncontrollable physicochemical influencing factors in practical experiments, it is challenging to achieve ideal experiment results.…”

“…Yang et al found through shale soaking experiments that a large amount of a high-salinity water film is attached between the crystal layers of shale clay minerals. When low-salinity fluids from the outside invade the shale reservoir, the high-salinity water film on the surface of the clay minerals will quickly dilute. , There are three main mechanisms for the hydration of clay minerals in shale after encountering water, − namely, surface hydration, ion hydration, and osmotic hydration. The distribution of fracturing fluids in shale pores is closely related to factors such as minerals, ion concentration in the aqueous phase, and the external environment .…”

The Effect of Slickwater on Shale Properties and Main Influencing Factors in Hydraulic Fracturing

“…The relevant research results indicate that due to the high content of clay minerals in shale, microfractures will occur in the shale after the invasion of fracturing fluid. At the same time, the entry of the liquid phase will change the occurrence environment of shale gas, which will accelerate the desorption and flow of shale gas [11,12]. The relevant molecular simulation results show that invading water will merge with shale gas to form water-soluble gas, which promotes shale gas migration and leads to a decrease in flowback rate [13,14].…”