The increased viscosity effect for fracturing fluid imbibition in shale. (15th March 2021) - Zhang, Linyang
Highlights: An effective viscosity model for water imbibition in shale formations is proposed. Factors that affect the effective viscosity of nanoconfined water are analyzed. The model can be used for nanopores in shale when initial water films exist. Abstract: Understanding water imbibition behaviors in shale formations plays an essential role in shale gas development. The effective viscosity of water in shale nanopores is usually different from that of the bulk phase because of confined conditions. In this work, a model considering interactions between water and a solid surface is proposed to predict the effective viscosity of water at the nanoscale, which is inserted into the classic Lucas-Washburn (L-W) model to describe the water imbibition behavior in shale formations. This model is derived based on a molecular kinetic theory and incorporates the disjoining pressure. Published experimental data is used to validate the model. It is demonstrated that the effective viscosity of water in hydrophilic nanopores is much higher than that of the bulk phase because of strong interactions between water and a solid surface, and the deviation significantly increases when the separation is below 10 nm. For a hydrophilic capillary tube with a diameter of 10 nm, the water effective viscosity is approximately 2.5 times higher than that of the bulk phase. Moreover, this deviation is larger for a capillary tube compared with a capillary channel, because of the curvature effect. Besides, the effective viscosity for water under a hydrophobic condition is smaller than that of the bulk phase water, because the structural repulsive force dominates under a hydrophobic condition. This work establishes a theoretical foundation to calculate the effective viscosity for water flow at the nanoscale. Furthermore, it helps to understand fracturing fluid imbibition behavior in shale gas reservoirs, which will benefit the simulation of fluid flow at the reservoir scale.