Modeling Flowback Chemistry at Marcellus Shale Hydraulic Fracturing

Balashov, Victor N.; Brantley, Susan L.; Engelder, Terry

Data on hydraulic fracturing of Marcellus shale show that within the first 90 days 1000 - 3000 m3 of salty aqueous fluid is returned to the surface per each horizontally fractured well. Flowback volume corresponds to approximately 10 - 20 %, but sometimes up to 50 %, of the injected water. The salt concentration of flowback solution increases with time and after 90 days reaches up to 270 kg/m3. Assuming an initial shale matrix porosity equal to 2% that is initially filled by brine pore solution, a back-of-the-envelope mass balance calculation shows that all the salt in the flowback fluid collected within 90 days corresponds to just 0.1 - 0.2% of the total salt in the brine in the shale accessed in a well. These estimates were used to develop a simple model to explain the increase in salt concentration in flowback water by attributing it to diffusion of salt from pore brine to the hydraulic fractures (initially filled by injected water). The model, parameterized using reasonable values of transport properties for shale, successfully fits the observed variation in salt concentrations in flowback waters after hydraulic fracturing of the shale.

AAPG Search and Discovery Article #90163©2013AAPG 2013 Annual Convention and Exhibition, Pittsburgh, Pennsylvania, May 19-22, 2013