Waters that are flowed back from unconventional reservoirs that have been hydraulically fractured contain information about the nature of the stimulated reservoir. The chemical character of that water is governed by several processes that involve the interaction of the injected water with reservoir rock and fluids. The proposed model suggests that the volume recovered from the induced hydraulic fracture has a different chemical signature than water recovered from the stimulated natural fracture network.
The application of hydraulic fracture stimulation and horizontal wellbores to tight unconventional reservoirs for the production of gas and liquid rich gas has been highly successful. Despite completely changing the oil and gas supply situation in North America, many aspects of these producing unconventional reservoirs remain poorly characterized.
Mineback and coring studies of hydraulic stimulations have shown that there are complex interactions with natural discontinuities in the rock. Although the extents of the stimulated reservoir volume can be reasonably determined from the application of microseismic monitoring, proppant tracers, offset pressure changes and fluid hits of offset wells, the extent and geometry of the producing fracture network is poorly understood.
Low recoveries of slickwater fracturing fluid and chemical fluid tracers suggest that much of the stimulated fracture network does not clean-up. Furthermore, production analysis techniques and reservoir simulations indicate that the effective producing fracture network is significantly smaller than the stimulated fracture network. Inherent in these analyses and simulations are assumptions about the geometry of the producing fracture network and the relative permeability of the contacted matrix surface area. Knowledge of the chemical properties of flowback and the processes that control the chemistry can provide insight into plausible stimulated fracture geometries.