Experimental and modeling study of water imbibition and flowback in shale: Prediction of relative permeability and capillary pressure curves

Abstract

Understanding the invasion and flowback processes of water, as the main source of hydraulic fracking fluid, is crucial for the proper evaluation and development of complex gas shale formations. Direct measurements of full gas-water relative permeability and capillary pressure curves by steady-state or unsteady-state techniques are not feasible in ultralow permeability shales. Therefore, the objective of this study is to investigate the dynamic rock-fluid properties of a Mancos shale sample by mimicking water imbibition and flowback experiments. To do so, a water injection experiment was done and tried to measure the flowback. After that, history matching on the experimental data of the water injection and flowback process was done to predict gas-water relative permeability data and capillary pressure curves. Low water flowback was observed, which insists on water entrapment in shale rocks. The results show a high threshold pressure and meaningful relative permeability of water, which can reduce the gas production rate dramatically. The saturation profiles show a high percentage of water in the invaded zone (>75%); however, the continuous imbibition of water with time (increase in shut-in time) helps the front of the invasion zone to move further deep into the shale, which enhances gas production. The S-shape gas relative permeability curve most likely represents the actual trend of the curve. An optimum shut-in time was predicted, which enables us to avoid delays in starting production operations.