Shale reservoirs with multistage hydraulic fractures are commonly characterized by analyzing long-term gas production data, but flowback data is usually not included in the analysis. However, this work shows there can be benefits to including flowback data in well analysis. The flowback period is dominated by water flow. Field data indicate that only 15-30% of the frac water is recovered after the flowback. Past publications have suggested that the lost water is trapped in the natural fracture or imbibed into the rock matrix near the fracture face. In this paper, lost water scenarios are tested and examples are presented for including flowback and production data in the analysis of shale gas wells.

A gas-water model was constructed for simulating the flowback and long-term production periods. Various physical assumptions were investigated for the saturations and properties in the fracture/matrix system that exists after hydraulic fracturing. The results of these simulations were compared with data from actual wells. The result of these comparisons led to certain conclusions and procedures that describe possible well/reservoir conditions after hydraulic fracturing and during production.

In this work, the challenge of simulating a natural fracture with trapped water without imbibition is solved using a new hybrid relative permeability jail. This concept was tested for the period of flowback, shut-in and production. Natural fracture spacing could be a possible explanation of the lost water. In addition, this paper shows the benefits of combining flowback and long-term water production data in the analysis of shale gas wells. In some cases the time shift on diagnostic plots changes the apparent flow regime identification of the early gas production data. This leads to different models of the fracture/matrix system. The presented work encourages the engineer to collect flowback data in order to include it in the long-term production analysis.

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