ALBERT

Description: Between 2005 and 2014 in Pennsylvania, about 4000 Marcellus wells were drilled horizontally and hydraulically fractured for natural gas. During the flowback period after hydrofracturing, 2 to $$4\times {10}^{3}\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{m}}^{3}$$ (7 to $$14\times {10}^{4}\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{ft}}^{3}$$ ) of brine returned to the surface from each horizontal well. This Na-Ca-Cl brine also contains minor radioactive elements, organic compounds, and metals such as Ba and Sr, and cannot by law be discharged untreated into surface waters. The salts increase in concentration to $$\sim 270\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }\mathrm{kg}/{\mathrm{m}}^{3}$$ ( $$\sim 16.9\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }\mathrm{lb}/{\mathrm{ft}}^{3}$$ ) in later flowback. To develop economic methods of brine disposal, the provenance of brine salts must be understood. Flowback volume generally corresponds to ~10% to 20% of the injected water. Apparently, the remaining water imbibes into the shale. A mass balance calculation can explain all the salt in the flowback if 2% by volume of the shale initially contains water as capillary-bound or free Appalachian brine. In that case, only 0.1%–0.2% of the brine salt in the shale accessed by one well need be mobilized. Changing salt concentration in flowback can be explained using a model that describes diffusion of salt from brine into millimeter-wide hydrofractures spaced 1 per m (0.3 per ft) that are initially filled by dilute injection water. Although the production lifetimes of Marcellus wells remain unknown, the model predicts that brines will be produced and reach 80% of concentration of initial brines after ~1 yr. Better understanding of this diffusion could (1) provide better long-term planning for brine disposal; and (2) constrain how the hydrofractures interact with the low-permeability shale matrix.