Tracking the interaction between injected CO2 and reservoir fluids using noble gas isotopes in an analogue of large-scale carbon capture and storage. (March 2017)

• Record Type: Journal Article
• Authors: Györe, Domokos; Gilfillan, Stuart M.V.; Stuart, Finlay M.
• Is Part Of: Applied geochemistry. Volume 78(2017:Mar.)
• Page Start: 116
• Page End: 128
• Publication Date: 2017-03
• Subjects: Carbon capture and storage -- Geological storage -- Geochemical tracing -- Carbon isotope -- Noble gas isotope -- Mass spectrometry; Environmental geochemistry -- Periodicals; Water chemistry -- Periodicals; Geochemistry -- Social aspects -- Periodicals; Geochemistry -- Periodicals; 551.9
• DOI: 10.1016/j.apgeochem.2016.12.012
• Languages: English
• ISSNs: 0883-2927

Abstract

Abstract: Industrial scale carbon capture and storage technology relies on the secure long term storage of CO2 in the subsurface. The engineering and safety of a geological storage site is critically dependent on how and where CO2 will be stored over the lifetime of the site. Hence, there is a need to determine how injected CO2 is stored and identify how injected CO2 interacts with sub-surface fluids. Since July 2008 ∼1 Mt of CO2 has been injected into the Cranfield enhanced oil recovery (EOR) field (MS, USA), sourced from a portion of the natural CO2 produced from the nearby Jackson Dome CO2 reservoir. Monitoring and tracking of the amount of recycled CO2 shows that a portion of the injected CO2 has been retained in the reservoir. Here, we show that the noble gases ( 20 Ne, 36 Ar, 84 Kr, 132 Xe) that are intrinsic to the injected CO2 can be combined with CO2 / 3 He and δ 13 CCO2 measurements to trace both the dissolution of the CO2 into the formation water, and the interaction of CO2 with the residual oil. Samples collected 18 months after CO2 injection commenced show that the CO2 has stripped the noble gases from the formation water. The isotopic composition of He suggests that ∼0.2%, some 7 kt, of the injected CO2 has dissolved into formation water. The CO2 / 3 He and δ 13 CCO2 values imply that dissolution is occurring at pH = 5.8, consistent with the previous determinations. δ 13 CCO2 measurements and geochemical modelling rule out significant carbonate precipitation and we determine that the undissolved CO2 after 18 months of injection (1.5 Mt) is stored by stratigraphic or residual trapping. After 45 months of CO2 injection, the noble gas concentrations appear to be affected by CO2 -oil interaction, overprinting the signature of the formation water. Highlights: Non-radiogenic noble gases reveal CO2 – reservoir fluid interaction history. Helium isotopic ratios allow quantification of CO2 loss by dissolution. CO2 / 3 He and δ 13 C(CO2 ) quantifies the pH of dissolution in a CO2 -EOR field.