Geochemical Evolution of Flowback and Produced Water from Marcellus Shale Wells in southwest Pennsylvania
Rowan, Elisabeth L.; Engle, Mark; Kraemer, Thomas F.
Time-series samples of flowback, or produced water, were collected at four Marcellus Shale gas wells in southwest Pennsylvania to characterize the geochemistry of its major elements and selected trace elements. Samples were collected daily for the first week following hydraulic fracturing, then at increasing intervals for up to 2 years. The time-series allowed us to determine the timing of the geochemical and isotopic transition from the composition of the injected water to a stable composition over the long term, or time frame of the study. The results shed light on the origin of the salinity, and suggest that the Na-Cl-Br system, and isotopes of O, H, and Ra can serve as natural tracers to identify water originating from the Marcellus Shale.
The injected fluids had relatively low initial salinities of about 50,000 mg/L TDS. During the first week of flowback, salinities increased rapidly, followed by a more gradual approach to a stable plateau near 165,000 mg/L TDS over 3-6 months. Radium activities increased approximately in parallel with salinity, also reaching a stable plateau. Radium activities together with the ratio, 228Ra/226Ra, appear capable of discriminating between waters sourced from the Marcellus Shale versus sandstone reservoirs.
The produced waters are strongly Br-enriched relative to seawater, consistent with a highly evaporated seawater source for salinity. In the wells for which we have time-series O and H isotopic ratios, a marked shift occurs in the first days of flowback from the meteoric signature of the injected water, to the isotopically heavier ratios of deep formation water. This shift provides independent evidence that the flowback is not adequately explained as injected water with additional salinity acquired by dissolution of evaporites or other minerals.
We hypothesize that most of the water injected under pressure is imbibed into shale pores, and retained by capillary forces. The initial large volume of flowback may consist predominantly of the injected water remaining in and near the well bore. The simultaneous rapid increase in salinity and decline in produced water volume may reflect replacement of the injected water with natural formation water. Small volumes of formation water released from the shale into the induced fracture network, and draining into the well bore, may represent the source of the produced water produced when its composition has stabilized, and would be consistent with the observed chemistry.
AAPG Search and Discovery Article #90163©2013AAPG 2013 Annual Convention and Exhibition, Pittsburgh, Pennsylvania, May 19-22, 2013