Impact of rock fabric on water imbibition and salt diffusion in gas shales

• Imbibition and diffusion anisotropy are intrinsic properties of gas shales.
• Confining the shale samples reduces water imbibition rate.
• Initial water saturation decreases water imbibition rate but hardly affects oil imbibition.
• Water imbibition can induce tensile stress and expand the shale samples.
• Shale porosity can be either in organic or inorganic materials.

Understanding water uptake of gas shales is critical for designing fracturing and treatment fluids. Previous imbibition experiments on unconfined gas shales have led to several key observations. The water uptake of dry shales is higher than their oil uptake. Furthermore, water imbibition results in sample expansion and microfracture induction. This study provides additional experimental data to understand the effects of rock fabric, complex pore network, clay swelling and osmotic potential on imbibition behavior.We systematically measure and compare the imbibition rates of deionized water and oil into wet/dry and confined/unconfined rock samples from different shale members of the Horn River Basin. We also measure the ion diffusion rate from shale into water during imbibition experiments. The results show that initial water saturation decreases the water uptake of shale samples. However, it has no effect on oil imbibition rates. The liquid imbibition and ion diffusion rates along the lamination are higher than those against the lamination. The results also suggest that confining the shale samples decreases the water imbibition rate, parallel to the lamination. However, it has a negligible effect on water uptake, perpendicular to the lamination. Furthermore, confining does not significantly affect the ion diffusion rates. The comparative study suggests that, for both confined and unconfined samples, water uptake is higher than oil uptake. However, previous experiments on crushed shale samples show that the oil uptake of crushed packs is higher than their water uptake (Xu and Dehghanpour, 2014). The data suggest that the connected pore network of the intact samples is water wet while the majority of rock including poorly connected pores is oil wet. This argument is backed by BSE images and complete spreading of oil on fresh break surfaces of the rock.