CO2 dissolution in formation water as dominant sink in natural gas fields

A primary concern facing Carbon Capture and Storage (CCS) technology is the proven ability to safely store and monitor injected CO2 in geological formations on a long-term basis. However, it is extremely challenging to assess the long-term consequences of CO2 injection into the subsurface from decadal observations of existing CO2 disposal sites. Noble gases are conservative tracers within the subsurface, and combined with carbon stable isotopes, have proved to be extremely useful in determining both the origin of CO2 and how the CO2 is stored within natural CO2 reservoirs from around the world [1,2]. This presentation will identify and quantify the principal mechanism of CO2 phase removal in nine natural gas fields in North America, China and Europe. These natural gas fields are dominated by a CO2 phase and provide a natural analogue for assessing the geological storage of CO2 over millennial timescales. Our study highlights 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 major sink for CO2 [2]. This pH range is obtained by modelling the carbon isotope fractionation that results from dissolution of CO2(g) to varying proportions of H2CO3(aq) and HCO3-(aq). This is a major breakthrough as accurate subsurface pH measurements are notoriously difficult to obtain. In two fields with siliciclastic reservoir lithologies, some CO2 loss through precipitation as carbonate minerals cannot be ruled out, but this is minor compared to the amount of CO2 lost to dissolution in the formation water within the same fields. Our findings imply mineral fixation is a minor CO2 trapping mechanism within natural reservoirs and hence suggests long-term models of geological CO2 storage should consider the potential mobility of CO2 dissolved in water.