Investigating the Fate of Hydraulic Fracturing Fluid in Shale Gas Formations Through Two-Phase Numerical Modelling of Fluid Injection

Abstract:

The process of hydraulic fracturing in shale gas formations typically involves the injection of large quantities of water-based fluid (2×10⁷L typical) into the shale formations in order to fracture the rock. A large proportion of the fracturing fluids injected into shale gas wells during hydraulic fracturing does not return out of the well once production begins. The percentage of water returning varies within and between different shale plays, but is generally around 30%. The large proportion of the fluid that does not return raises the possibility that it could migrate out of the target shale formation and potentially toward aquifers and the surface through pathways such as the created hydraulic fractures, faults and adjacent wells. A leading hypothesis for the fate of the remaining fracturing fluid is that it is spontaneously imbibed from the hydraulic fractures into the shale rock matrix due to the low water saturation and very high capillary pressure in the shale. The imbibition hypothesis is assessed using numerical modeling of the two-phase flow of fracturing fluid and gas in the shale during injection. The model incorporates relevant two-phase physical phenomena such as capillarity and relative permeability, including hysteretic behavior in both. Modeling scenarios for fracturing fluid injection were assessed under varying conditions for shale reservoir parameters and spatial heterogeneities in permeability and wettability. The results showed that the unaccounted fracturing fluid may plausibly be imbibed into the shale matrix under certain conditions, and that significant small-scale spatial heterogeneity in the shale permeability likely plays an important role in imbibing the fracturing fluid.