Developing phase interaction models to apply noble gases to the problem of carbon dioxide sequestration

Within the framework of simple hydrodynamic models and phase interactions, key quantitative information can be gained from noble gases about deep fluid systems. Examples include the volume and age of groundwater systems, the origin of different fluids, and the extent and the relative timing of phase interactions. This is exactly the information required to ensure safe geological disposal of anthropogenic CO2. Recent work on coalbed methane systems, a proposed target for CO2 injection, highlights the importance of considering the effect of both dynamic systems and non-groundwater sources of atmosphere-derived noble gases in constructing a quantitative fluid interaction model (Zhou et al., 2005). New data from four CO2-dominated natural gas fields provides an important natural analogue for understanding the detailed subsurface behavior of CO2. These fields are associated with the volcanism related to the Colorado Uplift, USA (Bravo Dome, NM; St John’s Dome, AZ; Sheep Mountain, CO; McElmo, CO). CO2/3He ratios indicate the origin of the CO2 to be dominantly magmatic and provide CO2 residence information. Groundwater-derived 20Ne/presup36Ar ratios are not achievable through single stage gas/water solubility equilibrium processes. We model this as a two stage process in which CO2 filling of the reservoir dynamically strips the ground-water system of noble gases. Subsequent re-equilibration of the gas field with noble gas-stripped water then accounts for all the groundwater-derived noble gases, allows us to quantify the re-dissolution of noble gases and identify open system behavior. A key parameter is identifying the mechanism of CO2 undersaturation that results in concomitant CO2 loss relative to 3He. Changes in ?13C(CO2) only identify precipitation to cause partial CO2 undersaturation in one field. Changing reservoir conditions (temperature-pressure) resulting in CO2 undersaturation combined with groundwater migration is the dominant control. CO2/3He ratio variations suggest that CO2 re-dissolution may result in between 50% and 90% loss of the original field CO2 gas charge. The challenge is now how to transfer this conceptual framework to real time sequestration targets, such as three phase (oil–water–gas) depleted oil reservoirs. This will constrain the temporal/dynamic controls of phase interaction and quantify the role of the groundwater contact as an additional CO2 sink or possible migration pathway (Mackintosh et al., 2006).