Liquid uptake of gas shales: A workflow to estimate water loss during shut-in periods after fracturing operations

The imbibition of fracturing fluid into the shale matrix is identified as one of the possible mechanisms leading to high volumes of water loss to the formation in hydraulically fractured shale reservoirs. In an earlier study (Makhanov et al, 2012), several spontaneous imbibition experiments were conducted using actual shale core samples collected from Fort Simpson, Muskwa and Otter Park formations, all belonging to the Horn River shale basin. This study provides additional experimental data on how imbibition rate depends on type and concentration of salt, surfactants, viscosifiers and sample orientation with regard to the bedding plane. The study also proposes and applies a simple methodology to scale up the laboratory data for field-scale predictions.

The data show that an anionic surfactant reduces the imbibition rate due to the surface tension reduction. The imbibition rate is even further reduced when KCl salt is added to the surfactant solution. Surprisingly, viscous XG solutions show a considerable spontaneous imbibition rate when exposed to organic shales, although their viscosity is much higher than water viscosity. This observation indicates that water uptake of clay-rich organic shales is mainly controlled through preferential adsorption of water molecules by the clay particles, and high bulk viscosity of the polymer solution can only partly reduce the rate of water uptake.

The field scale calculations show that water loss due to the spontaneous imbibition during the shut-in period is a strong function of fluid/shale properties, fracture-matrix interface, and soaking time. The presented data and analyses can be used to explain why some fractured horizontal wells completed in gas shales show poor water recovery and an immediate gas production after extended shut-in periods.