2015 GSA Annual Meeting in Baltimore, Maryland, USA (1-4 November 2015)

Paper No. 275-8
Presentation Time: 10:10 AM


STEWART, Brian W. and CAPO, Rosemary C., Department of Geology & Planetary Science, University of Pittsburgh, Pittsburgh, PA 15260, bstewart@pitt.edu

Hydraulic fracturing of black shales for gas extraction involves injection of large volumes of water (up to 25,000 m3 per well) into the target formation, of which a portion is returned to the well head. The chemistry of the returned water changes from that of the injected fluid to a saline brine over a matter of days to weeks, concomitant with a significant decrease in flow rate. Within 2-4 weeks of flowback, the flow stabilizes at a low rate, producing Na-Ca-Cl brines with total dissolved solids (TDS) levels often exceeding 200,000 mg/L. These late-stage waters share some characteristics with conventional oil and gas well produced waters, but their origin has not been resolved. Hypotheses to explain the high-TDS produced waters from the Marcellus Shale in the eastern United States include dissolution of salts by injected waters (Blauch et al., 2009, SPE 125740), mobilization of water trapped in fractures and sandy facies within the shale (Rowan et al., 2015, AAPG Bull. 99, 181-206), migration of water from adjacent formations (Stewart et al., 2015, Appl. Geochem. 60, 78-88), and extraction of capillary-bound brines by hydraulic fracturing (Balashov et al., 2015, AAPG Bull. 99, 143-154). Unique characterization of produced waters and their potential migration in hydrologically complex systems with multiple fluid-bearing units, including freshwater aquifers, requires geochemical and isotopic tracers combined with fluid-rock modeling, as well as an understanding of potential pathways for solute introduction to both shallow and deep water-bearing units.