The fate of the fracturing fluid in shale reservoirs is still a controversial issue. Despite the low recovery observed in field reports, neither the fate nor the impact of these trapped fluids is well-understood. The combination of the large surface area, mild reactive nature of shale and the massive trapped volume of fracturing fluids raises a question on the impact that geochemical interactions have on load recovery, well performance and reservoir characteristics, which is the focus of this study.

A fit-for-purpose model is built where a hydraulic fracture stage is modelled using LG-LR-DK model. The initial conditions are simulated by injecting the fracturing fluid, then shutting-in the well to allow the fluids to be soaked into the formation. Different relative permeability sets are used for high and low salinity water since the fluid's mobility is affected by its salinity. Actual connate water composition from Haynesville shale is used to study the impact of connate composition on geochemical coupling. The formation mineralogy and fracturing fluid composition impact on gas and load recovery is investigated.

The introduction of the oxygenated, low salinity, fracturing fluid to a reducing environment would definitely catalyze both precipitation and dissolution reactions depending on the formation mineralogy. The dissolution and precipitation rates show a positive correlation with the carbonate content of the rock. Interestingly, the incorporation of the dependence of relative permeability on ion exchange and fluid salinity might reveal the fate of the fracturing fluid. Overestimation of both gas and load recovery is observed when geochemical coupling is neglected. In addition, sea water shows an enhanced performance suggesting a good alternative fracturing fluid. Surprisingly, better performance is observed for less saline connate water cases. The carbonates reactions outweigh the clays reactions in most cases. Also, treating carbonates as only calcite results in more reactions compared to the dolomite case. Sensitivity analysis suggests that the concentration of SO4, K and Na ions in the fracturing fluid, and illite and calcite mineral content of the rock, along with the reservoir temperature are the main key factors affecting well performance. It is worth noting that the salinity contrast between the injected fluid and the formation brine shows a negative correlation with well performance.

In conclusion, the incorporation of the geochemical coupling in simulating fracturing fluid dynamics, and their impact on the load recovery and well performance, is essential. Therefore, careful selection of a fracturing fluid suitable for formation mineralogy will enhance well performance.

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