Quantifying the extent of flowback of hydraulic fracturing fluids using chemical and isotopic tracer approaches. (June 2018)

• Record Type: Journal Article
• Authors: Osselin, F.; Nightingale, M.; Hearn, G.; Kloppmann, W.; Gaucher, E.; Clarkson, C.R.; Mayer, B.
• Is Part Of: Applied geochemistry. Volume 93(2018)
• Page Start: 20
• Page End: 29
• Publication Date: 2018-06
• Subjects: Hydraulic fracturing -- Flowback fluids -- Wastewater -- Shale gas -- Montney formation -- Water isotopes; Environmental geochemistry -- Periodicals; Water chemistry -- Periodicals; Geochemistry -- Social aspects -- Periodicals; Geochemistry -- Periodicals; 551.9
• DOI: 10.1016/j.apgeochem.2018.03.008
• Languages: English
• ISSNs: 0883-2927

Abstract

Abstract: Hydraulic fracturing technologies have facilitated the rapid development of shale gas and other unconventional hydrocarbon resources throughout the world. Following hydraulic fracturing operations, a large quantity of water flows back to the surface. Understanding the provenance and composition of this returned water is therefore of paramount importance in order to optimize the recycling and reuse of the millions of litres of wastewater generated by hydraulic fracturing and to reduce freshwater consumption. Here we report flowback and produced fluids data obtained from a horizontal well in a low permeability reservoir within the Montney formation in Alberta, Canada. The reservoir was fractured with a mixture of nitrogen and water and the returned water was sampled 24 times during the first week of flowback and once after more than one year of production. The samples were analyzed for concentrations of major ions and for the stable isotope composition of water. The TDS (total dissolved solids) of the samples increased rapidly from 395 mg/L for the injected water to 50, 000 mg/L after two days and 96, 000 mg/L at the end of the first week of flowback. At the same time, δ 2 H values increased from −142‰ to −113‰ and δ 18 O values increased from −18.3‰ to −9.8‰. After more than one year, TDS reached 204, 000 mg/L while δ 2 H and δ 18 O values further increased to −68‰ and + 2.7‰. The salinity of the returned water is shown to be the result of the mixing between the highly saline formation water initially present in the reservoir before hydraulic fracturing, with the fresh water used for hydraulic fracturing. The presented mathematical model allows the calculation of the amount of fracturing fluid recovered as well as the quantity of saline formation water produced and reveals that most of the injected water is imbibed in the host rock of the producing formation. After a week of flowback, only 18% of the injected water had been recovered, while the recovery of fracturing fluids after 14.5 months is estimated at 36% of the total volume injected. Highlights: Increasing flowback salinity due to mixing of injected fluids with formation brine. Flowback quantity determined using conservative chemical and isotopic parameters. Two thirds of injected fracturing fluids were rapidly imbibed in the formation. Only one third of the injected water is expected to return to the surface.