Mathematical Modeling and Numerical Simulation of Water-Rock Interaction in Shale Under Fracturing-Fluid Flowback Conditions

Water-rock interaction cannot be ignored for shale reservoirs with high-salinity formation brine and complex rock composition, and stimulated by massive slick-water fracturing treatment. However, there have been few studies on the flowback model fully coupled with different effects of water-rock interaction. This paper presents the development of a coupled hydro-chemical-mechanical model for modeling water-rock interaction in fractured shale during the post-fracturing flowback period. The model considers distinguishing water-rock interaction phenomena, that is, mineral dissolution, clay swelling and chemical osmosis, and accounts for multi-phase flow in a fractured shale reservoir. The coupling and solution method and a numerical simulator were developed. Numerical simulation indicates that the swelling volume of clay minerals occupies the pores and leads to a decline in matrix porosity, while mineral dissolution increases both the matrix porosity and the solute concentration in the aqueous phase in matrix pores. Clay swelling mainly affects the shape of the porosity ratio profiles. The effect of mineral dissolution becomes increasingly stronger as flowback progresses. Mineral dissolution mainly affects the relative positions of the porosity ratio curves with the progress of flowback. The water-rock interaction coupled flowback modeling and the numerical simulation results in this study quantify the effects of chemical osmosis, clay swelling and mineral dissolution. Results from this study provide new insights into the mechanisms of fracturing-fluid flowback and value to flowback transient analysis.

Automated summary

This study developed a coupled hydro-chemical-mechanical model to simulate water-rock interaction in fractured shale during the post-fracturing flowback period. Numerical simulations showed that clay mineral swelling and mineral dissolution affect porosity and solute concentration, with chemical osmosis becoming stronger as flowback progresses. The results provide new insights into fracturing-fluid flowback mechanisms and have value for flowback transient analysis.