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

Domokos Györe,Stuart M.V Gilfillan,Finlay M Stuart

doi:10.1016/j.apgeochem.2016.12.012

Domokos Györe, Stuart M.V Gilfillan + Show 1 more

Open Access

https://doi.org/10.1016/j.apgeochem.2016.12.012

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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 (20Ne, 36Ar, 84Kr, 132Xe) that are intrinsic to the injected CO2 can be combined with CO2/3He and δ13CCO2 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 CO2/3He and δ13CCO2 values imply that dissolution is occurring at pH = 5.8, consistent with the previous determinations. δ13CCO2 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

Geological storage of CO2, either in dedicated storage sites or via the utilisation of CO2 for enhanced oil recovery (EOR), has the potential to achieve significant reduction of CO2 emissions (IPCC, 2005)
We find that measurements of 20Ne, 36Ar, CO2/3He and d13CCO2 combined with 84Kr, 132Xe measurements from the Cranfield EOR field provides an excellent analogue of how similar techniques could be applied to quantify the fate of CO2 injected into an engineered CO2 storage site
The non-radiogenic noble gases (20Ne, 36Ar, 84Kr, 132Xe) in well gases collected after 18 months of CO2 injection from the Cranfield EOR field originate from the formation water, and have been extracted by different degrees of CO2-formation water interaction, governed by the effectiveness of CO2ewater contact

Summary

Introduction

Geological storage of CO2, either in dedicated storage sites or via the utilisation of CO2 for enhanced oil recovery (EOR), has the potential to achieve significant reduction of CO2 emissions (IPCC, 2005). There is a need to resolve the mechanisms by which injected CO2 is stored, quantify the efficiency and identify how injected CO2 interacts with in-situ subsurface fluids. This demands the development of CO2 monitoring and verification techniques (Haszeldine et al, 2005; Scott et al, 2013). Whilst the majority of monitoring studies have relied on seismic surveys to image the free phase CO2 plume, the technique cannot resolve the amount of CO2 dissolved into the formation reservoir within a storage site (Scott et al, 2013). A wide range of geochemical tracing techniques have been developed to track the movement and storage of injected CO2 (Humez et al, 2014), yet there is an outstanding need to develop a robust tool which can resolve the amount of CO2 dissolved into the formation water within a storage site

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