Injection of fracturing fluids into shales during hydraulic stimulation can result in various chemical reactions involving the injected fluid and host shale rock. Differences in chemical composition between the injected fluids and fractured rock can result in mineral precipitation along shale fractures and within the shale matrix, potentially affecting long-term gas recovery from the shale. Our prior research showed that mineral precipitation and dissolution occur along freshly-generated fractures, and within the shale matrix, during core flood experiments in which laboratory-fractured Marcellus Shale was exposed to simulated hydraulic fracturing fluids. Many of the mineral precipitation reactions were hypothesized to occur due to the inability for antiscaling compounds in the fracturing fluids to control mineral precipitation at elevated temperature and pressure. In some locations along the fracture, proppant was cemented to shale surfaces through secondary mineral precipitates. The present study focuses on core flood experiments using fresh core and site hydraulic fracturing fluid from the Marcellus Shale Energy and Environmental Laboratory site (MSEEL; Morgantown, WV) at reservoir pressure and temperature conditions. The objectives of this study are to evaluate the reproducibility of the earlier experiments using fresh core, and to identify causes for any observed differences with the prior outcrop-based experiments.
Introduction of fracturing chemicals into shale formations can initiate chemical reactions that result in shale mineral dissolution and precipitation of secondary minerals within the shale matrix and along newly-generated fractures. These reactions can affect matrix and fracture permeability by generating new flow pathways in the case of mineral dissolution. Secondary mineral precipitation could be both beneficial and detrimental to gas flow within the reservoir, as depending on the mineral morphology and location, precipitation could result in additional propping of fractures, or could reduce matrix and fracture permeabilities. Recent attention to fracturing chemical-mineral reactions that could affect gas production have shown that both the formation mineralogy and injected fluid chemistry have a significant influence on the overall chemical changes during hydraulic fracturing. Barite has been of interest in the Marcellus Shale due to elevated concentrations of barium measured in produced waters and the shale. Barite scale in the wrong locations within the system can present a significant challenge for sustained long-term production as barite dissolution and removal are difficult and potentially costly.