What is the fate of fracture fluid during shale gas production?

Shale gas fluids geochemical reactivity is important to understand if we are to sustainably produce shale gas and also to reduce the risk of scaling during production. To assess the reason for the increase in salt concentration in the flowback water and to predict the scaling tendency during the whole process, a shale gas geochemical study has been carried out. Additionally, to better understand the transportation mechanisms for fluids within shale system and to match the volume of flowback water occurring in observed shale gas cases, some fractured shale gas models have been developed. According to the geochemical study, the conclusion is drawn that the scaling risk could be very serious due to the high salinity of the typical flowback water and the mixing between fracture fluid and formation water can account for the evolving salinity of the water that flows back. From this shale modelling study it can be shown that when the fracture fluid can propagate within the reservoir (either through the secondary fractures or the natural fracture network), there will be less fracture fluid produced back and there will be greater mixing with the in situ brine.