One of the basic design factors in porous media enhanced geothermal systems exploiting hot (warm) saline liquids is the time that the system starts to operate until significant thermal breakthrough occurs, i.e., the reservoir lifetime. This study is focused on a sedimentary enhanced geothermal system (SEGS) located in the Williston Basin, a sub-basin of the Western Canada Sedimentary Basin (WCSB). Variables such as the doublet distance and the injection/production flow rate are investigated to assess the effect of the growth of the heat transfer area with and without a high-permeability fracture. For instance, the modeling results illustrate that with short doublet distances, the production temperature of a fractured reservoir with high injection rates is higher than that of a nonfractured system with very same properties, whereas decreasing the injection rate leads to opposite outcomes. The stress changes are also estimated as fluid flows over time at the reservoir scale, since they impact fracture aperture in a highly non-linear manner. The dominant phenomenon is tension development in the entire domain, except in the injection well. The computational platform used is a finite element based model and a 30-year project timescale is considered.

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