Effectiveness and time variation of induced fracture volume: Lessons from water flowback analysis

Characterizing the induced fracture network is crucial for evaluating and optimizing fracturing operations and for forecasting hydrocarbon production. In our previous paper [1], we developed a closed-tank material balance model to estimate effective fracture volume using rates and pressure data measured during early-time water flowback. In this paper, we extend this model to an open-tank model to estimate fracture-matrix interface area using rates and pressure data measured during late-time water flowback. We verify the proposed model against a 2D numerical model solved by a commercial software, and demonstrate the application of the proposed model to an eight-well pad completed in the gas shales of the Horn River Basin. Finally, we conduct a comparative analysis to investigate the time variation of effective fracture volume during water flowback. The results show that up to 30% of the effective fracture volume is lost due to pressure depletion and fracture closure during early-time water flowback. The rate of fracture volume reduction decreases during late-time flowback when gas from the matrix kicks into the fracture network and provides sufficient pressure support. However, the estimated fracture-matrix interface area is relatively low and cannot be explained by the estimated fracture volume. This result suggests that although a large fracture network is created by hydraulic fracturing operations, only a small fraction of the fracture network receives gas influx from the matrix. Overall, the results suggest that a large fraction of the fractures induced in gas shales does not contribute to hydrocarbon production due to fracture closure, permeability jail effect, and water blockage.