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Solubility trapping in formation water as dominant CO2 sink in natural gas fields

Abstract

Injecting CO2 into deep geological strata is proposed as a safe and economically favourable means of storing CO2 captured from industrial point sources1,2,3. It is difficult, however, to assess the long-term consequences of CO2 flooding in the subsurface from decadal observations of existing disposal sites1,2. Both the site design and long-term safety modelling critically depend on how and where CO2 will be stored in the site over its lifetime2,3,4. Within a geological storage site, the injected CO2 can dissolve in solution or precipitate as carbonate minerals. Here we identify and quantify the principal mechanism of CO2 fluid phase removal in nine natural gas fields in North America, China and Europe, using noble gas and carbon isotope tracers. The natural gas fields investigated in our study are dominated by a CO2 phase and provide a natural analogue for assessing the geological storage of anthropogenic CO2 over millennial timescales1,2,5,6. We find that in seven gas fields with siliciclastic or carbonate-dominated reservoir lithologies, dissolution in formation water at a pH of 5–5.8 is the sole major sink for CO2. In two fields with siliciclastic reservoir lithologies, some CO2 loss through precipitation as carbonate minerals cannot be ruled out, but can account for a maximum of 18 per cent of the loss of emplaced CO2. In view of our findings that geological mineral fixation is a minor CO2 trapping mechanism in natural gas fields, we suggest that long-term anthropogenic CO2 storage models in similar geological systems should focus on the potential mobility of CO2 dissolved in water.

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Figure 1: CO2/3He variation plotted against 20Ne from CO2-rich natural gas fields.
Figure 2: CO2/3He in CO2-rich natural gas fields shows strong anticorrelation with 4He.
Figure 3: Plot of δ13C(CO2) against CO2/3He for Bravo dome and McElmo dome.

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Acknowledgements

S.M.V.G. was supported by a Natural Environmental Research Council (NERC)-funded PhD studentship in Manchester and a NERC-funded postdoctoral position, grant NE/C516479/1 in Edinburgh and Glasgow, and UK Energy Research Centre grant NE/C513169/1. Manchester work was further partly funded by NERC grants NE/D004292 and NE/F002823. Toronto work was further partly funded by an Natural Sciences and Engineering Research Council of Canada Discovery grant to B.S.L. We thank the field operators for permission to sample the US gas reservoirs and support in the field, particularly L. Nugent (Sheep Mountain), T. Muhic and D. Miller and G. Grove (McCallum dome) and T. White (St Johns dome). S.M.V.G. would like to thank R. S. Haszeldine and Z. Shipton for supporting this work. Review by R. H. Worden is appreciated.

Author Contributions S.M.V.G., C.J.B. and B.S.L. designed the study, analysed the samples, interpreted the data and wrote the paper. G.H., D.B., Z.D., Z.Z. and G.L.-C. assisted with sample analysis and interpretation of the data. S.S., M.S. and M.C. assisted with sample collection and provided comments on the manuscript.

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Correspondence to Stuart M. V. Gilfillan.

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This file contains Supplementary Table 1, Supplementary References and Supplementary Figures S1-S8 with Legends. Supplementary Table 1 was replaced on 10 September 2009, and again on 08 October 2009. (PDF 315 kb)

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Gilfillan, S., Lollar, B., Holland, G. et al. Solubility trapping in formation water as dominant CO2 sink in natural gas fields. Nature 458, 614–618 (2009). https://doi.org/10.1038/nature07852

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