Yousif Kharaka, U. S. Geological Survey (United States)
David Cole, Oak Ridge National Laboratory (United States)
Thomas Bullen, U. S. Geological Survey (United States)
Kevin Knauss, Lawrence Berkeley National Laboratory (United States)
Susan Hovorka, Bureau of Economic Geology (United States)
Global warming and the resulting climate changes are arguably the most important environmental challenges facing the world in this century. This warming results primarily from increased concentrations of atmospheric greenhouse gases (GHG), especially CO2, emitted from the burning of fossil fuels. The amount of CO2 currently added to the atmosphere is ∼30 Gt/yr, and this could double by 2050. Capture and sequestration of CO2 in deep geological formations-depleted petroleum fields and saline aquifers-is the most plausible option to reduce GHG emissions and mitigate global warming. Geochemical studies, culminating in solute transport modeling, are essential for successful sequestration as they provide an understanding of CO2-brine-mineral interactions that determine the long-term storage security and reservoir performance. Reservoir capacity and integrity are strongly affected by the CO2 trapping mechanisms: 1) As a supercritical and buoyant fluid below a cap rock, hydrodynamic trapping, and in the pores of reservoir rocks, residual trapping; 2) dissolved in formation water as H2CO3o, HCO3- and other species, solution trapping; and/or 3) precipitated as calcite, magnesite and siderite, mineral trapping. Calculations indicate that the bulk of CO2 will be stored initially as supercritical fluid, because target reservoirs are likely to have T and P values higher than 31°C and 74 bar, the critical values for CO2. Formation water contacting the injected CO2 will rapidly dissolve it to saturation-3-5% of brine weight, depending on its chemical composition and reservoir conditions. Mineral trapping would be slower, but more permanent. Geochemical methods, some novel, were used in the Frio Brine Pilot tests near Houston, Texas to investigate the potential for the storage of CO2 in saline aquifers. Detailed chemical and isotopic analyses of brine, associated gases, and added tracers proved powerful tools in: 1- Tracking the flow of the injected CO2 in the injection zone (C-sand); 2- showing that injected CO2 was not detected in shallow groundwater or at ground level; 3- detecting that some CO2 leaked into the overlying B-sand that is separated from C by 15 m of shale and siltstone; 4- showing major mobilization of metals (Fe, Pb, etc) and toxic organic compounds (BTEX, PAHs, etc) following CO2 injection; 5- showing major changes in chemical and isotopic compositions of formation water , including a dramatic drop in calculated brine pH (from 6.3 to 3.0) following CO2 injection. Geochemical modeling, chemical data and Fe isotopes indicate rapid dissolution of minerals, especially calcite and Fe-oxyhydroxides, and show that some of the Fe and other metal increases were caused by corrosion of well pipe. Geochemical techniques, which have more sensitive natural and added chemical and isotopic tracers than geophysical methods, are recommended for CO2 injection sites both to assure selection of safe sites and to monitor injection performance.