Characterizing long-term CO 2 –water–rock reaction pathways to identify tracers of CO 2 migration during geological storage in a low-salinity, siliciclastic reservoir system Kyle N. Horner a,b, ⁎, Ulrike Schacht a,c , Ralf R. Haese a,d a CRC for Greenhouse Gas Technologies, Ground Floor, NFF House, 14-16 Brisbane Ave., Barton, ACT 2600, Australia b Geoscience Australia, GPO Box 378, Canberra 2601, Australia c Australian School of Petroleum, University of Adelaide, Adelaide, SA 5005, Australia d Peter Cook Centre for Carbon Capture and Storage Research, School of Earth Sciences, The University of Melbourne, Parkville, Victoria 3010, Australia abstract article info Article history: Accepted 29 September 2014 Available online xxxx Editor: David R. Hilton Keywords: Carbon dioxide Sequestration CCS Low-salinity Surat Basin Given the prevailing use of saline reservoirs for geological CO 2 storage projects, limited data are available on the geochemical evolution of formation water chemistry during geological CO 2 storage in low-salinity formations. The low-salinity (total dissolved solids b 3000 mg/L) middle to lower Jurassic sequence in Australia's Surat Basin has been characterized as a potential reservoir system for geological CO 2 storage, comprising three major siliciclastic formations with distinctly different mineral compositions. Contrasts in the geochemical responses of Jurassic sequence core samples have been identified during short-term CO 2 –water–rock experiments conduct- ed under CO 2 storage conditions (Farquhar et al., in this issue). If persistent, such contrasts may serve as geo- chemical tracers of CO 2 migration within the Surat Basin. Here we use a combined batch experiment and numerical modeling approach to characterize the long-term response of the Jurassic succession to storage and migration of CO 2 and to assess reaction pathway sensitivity to CO 2 partial pressure. Reservoir system mineralogy was characterized for 66 core samples from Geological Survey of Queensland stratigraphic well Chinchilla 4, and six representative samples were powdered and reacted with synthetic formation water and high-purity CO 2 for up to 27 days at a range of pressures. Formation water alkalinity offers limited buffering at elevated CO 2 pressures and pH rapidly declines resulting in sustained enhancement of mineral dissolution rates. Batch reactor results ex- hibit regional groundwater-like 87 Sr/ 86 Sr values (0.7048–0.7066), less radiogenic than whole-rock results (N 0.7085) indicating incongruent dissolution of the reservoir matrix. Carbonate and authigenic clay dissolution are expected to be the primary reaction pathways regulating long-term formation water composition during geo- logical CO 2 storage in the Surat Basin, with lesser contributions from dissolution of the clastic matrix. Crown Copyright © 2014 Published by Elsevier B.V. All rights reserved. 1. Introduction Carbon capture and storage (CCS) is a relatively new technology for mitigating anthropogenic climate change by separating CO 2 from indus- trial flue gas, transporting it to and storing it in a subsurface geological reservoir. Depleted oil and gas fields, coal seams and deep aquifers have been identified as suitable reservoirs for geological CO 2 storage, in principle (Bachu and Adams, 2003; Gunter et al., 2004; Benson and Cole, 2008). However, such prospective storage reservoirs may either contain potable water or be located adjacent to other reservoirs that contain potable water. As CO 2 –water–rock interactions can impact for- mation water composition, some regulators have restricted geological CO 2 storage to reservoirs containing saline water. Where restrictions are imposed, minimum reservoir salinity thresholds for geological CO 2 storage range from 3000 mg/L to 10,000 mg/L of total dissolved solids (TDS) depending on jurisdiction (Bachu et al., 2007; USEPA, 2010; EUCA, 2011). Minimum reservoir salinity threshold values generally do not apply to geological CO 2 storage projects in Australia (e.g. GGGSA, 2008). Therefore several prospective Australian reservoir systems have lower salinity than is typical of storage reservoirs in other countries (Carbon Storage Taskforce, 2009). One such reservoir system is the Jurassic sequence within the Queensland portion of the Surat Basin (Fig. 1) where formation water salinity is b 3000 mg/L (Bradshaw et al., 2011; Grigorescu, 2011a; Hodgkinson and Grigorescu, 2012; Feitz et al., 2014). CO 2 –water–rock interactions in saline formations have been exten- sively examined (e.g. Johnson et al., 2004; Allen et al., 2005; Druckenmiller and Maroto-Valer, 2005; Xu et al., 2005; Zerai et al., Chemical Geology xxx (2014) xxx–xxx ⁎ Corresponding author at: New South Wales Environment Protection Authority, Sydney, NSW 2000, Australia. E-mail address: kyle.horner@epa.nsw.gov.au (K.N. Horner). CHEMGE-17363; No of Pages 11 http://dx.doi.org/10.1016/j.chemgeo.2014.09.021 0009-2541/Crown Copyright © 2014 Published by Elsevier B.V. All rights reserved. Contents lists available at ScienceDirect Chemical Geology journal homepage: www.elsevier.com/locate/chemgeo Please cite this article as: Horner, K.N., et al., Characterizing long-term CO 2 –water–rock reaction pathways to identify tracers of CO 2 migration during geological storage in a low-salinity, siliciclastic..., Chem. Geol. (2014), http://dx.doi.org/10.1016/j.chemgeo.2014.09.021