Understanding the fate of residual hydraulic fracturing fluids and the mechanisms that control flowback fluid composition are necessary components to the environmentally sustainable development of shale gas reservoirs. Fracturing fluids contain an array of chemical additives that will influence mineral dissolution reactions and water imbibition at the shale fracture/matrix interface. This presentation will summarize results from a series of experimental studies that examined the impact of acid and surfactants commonly used in slickwater fracturing fluids with respect to their ability to mobilize contaminants from and influence water imbibition into the shale matrix, respectively. The addition of acid has the potential to drive mineral dissolution and promote leaching of trace contaminants commonly found in shales. However, this dissolution can also create microporous regions along fracture flow pathways that may ultimately limit continued dissolution of reactive mineral phases. Here, core-flooding experiments were coupled with 2D reactive transport modeling to evaluate how pyrite dissolution, and concomitant release of arsenic, may be limited by slow diffusion within calcite-depleted regions adjacent to shale fractures. Surfactants used in fracturing fluids can alter wettability in micro- and nano-scale pores within the shale matrix. Such a shift in wettability will effect water imbibition into the shale and production of natural gas from the shale. Small and ultra-small angle neutron scattering were used to investigate water imbibition into shale pores with radiuses between 10 nm to 100 μm under varying concentrations (0.1 mM to 8 mM) of 1:1 mixed cationic/anionic surfactants. It was found that at higher surfactant concentrations (&gt; 0.43 mM) pores with radius less than 250 nm became less accessible to the fracturing fluids, suggesting that imbibed water would remain in the larger pores and microfractures within the shale matrix. Investigations into the role that shale composition will play in determining how surfactants will effect water imbibition into the shale matrix are ongoing. Shale mineralogy and surface charge distribution are being mapped in 3D at the scale of 5-10 μm using a combined image technique that pairs scanning electron microscopy and Kelvin probe force microscopy. This 3D analysis of shale composition may help to inform future modeling efforts examining water imbibition and counter-current gas flow in nanoporous shales.

Influence of slickwater additives on fate of residual fracturing fluids and flowback composition in shale gas reservoirs

2019 Spring National Meeting

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