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

Injecting CO2 into deep geological strata is proposed as a safe and economically favourable means of storing CO2 captured from industrial point sources. It is difficult, however, to assess the long-term consequences of CO2 flooding in the subsurface from decadal observations of existing disposal sites. Both the site design and long-term safety modelling critically depend on how and where CO2 will be stored in the site over its lifetime. 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 timescales. 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.