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A critical issue for geologic carbon sequestration is the ability to detect CO2 in the vadose zone. Here we present a new process‐based approach to identify CO2 that has leaked from deep geologic storage reservoirs into the shallow subsurface. Whereas current CO2concentration‐based methods require years of background measurements to quantify variability of natural vadose zone CO2, this new approach examines chemical relationships between vadose zone N2, O2, CO2, and CH4 to promptly distinguish a leakage signal from natural vadose zone CO2. The method uses sequential inspection of the following gas concentration relationships: 1) O2 versus CO2to distinguish in‐situ vadose zone background processes (biologic respiration, methane oxidation, and CO2 dissolution) from exogenous deep leakage input, 2) CO2 versus N2 to further distinguish dissolution of CO2 from exogenous deep leakage input, and 3) CO2 versus N2/O2 to assess the degree of respiration, CH4 oxidation and atmospheric mixing/dilution occurring in the system. The approach was developed at a natural CO2‐rich control site and successfully applied at an engineered site where deep gases migrated into the vadose zone. The ability to identify gas leakage into the vadose zone without the need for background measurements could decrease uncertainty in leakage detection and expedite implementation of future geologic CO2 storage projects.

Using CO2 in enhanced oil recovery (CO2-EOR) is a promising technology for emissions management because CO2-EOR can dramatically reduce sequestration costs in the absence of emissions policies that include incentives for carbon capture and storage. This study develops a multiscale statistical framework to perform CO2 accounting and risk analysis in an EOR environment at the Farnsworth Unit (FWU), Texas. A set of geostatistical-based Monte Carlo simulations of CO2-oil/gas-water flow and transport in the Morrow formation are conducted for global sensitivity and statistical analysis of the major risk metrics: CO2/water injection/production rates, cumulative net CO2 storage, cumulative oil/gas productions, and CO2 breakthrough time. The median and confidence intervals are estimated for quantifying uncertainty ranges of the risk metrics. A response-surface-based economic model has been derived to calculate the CO2-EOR profitability for the FWU site with a current oil price, which suggests that approximately 31% of the 1000 realizations can be profitable. If government carbon-tax credits are available, or the oil price goes up or CO2 capture and operating expenses reduce, more realizations would be profitable. The results from this study provide valuable insights for understanding CO2 storage potential and the corresponding environmental and economic risks of commercial-scale CO2-sequestration in depleted reservoirs.

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[1] At Cranfield, Mississippi, United States, a large-scale carbon dioxide (CO 2 ) injection through an injection well (3,080 m deep) was continuously monitored using U-tube samplers in two observation wells located 68 and 112 m east of the injector. The Lower Tuscaloosa Formation injection zone, which consists of amalgamated fluvial point-bar and channel-fill deposits, presents an interesting environment for studying fluid flow in heterogeneous formations. Continual fluid sampling was carried out during the first month of CO 2 injection. Two subsequent tracer tests using sulfur hexafluoride (SF 6 ) and krypton were conducted at different injection rates to measure flow velocity change. The field observations showed significant heterogeneity of fluid flow and for the first time clearly demonstrated that fluid flow evolved with time and injection rate. It was found the wells were connected through numerous, separate flow pathways. CO 2 flowed through an increasing fraction of the reservoir and sweep efficiency improved with time. The field study also first documented in situ component exchange between brine and gas phases during CO 2 injection. It was found that CH 4 degassed from brine and is enriched along the gas-water contact. Multiple injectate flow fronts with high CH 4 concentration arrived at different times and led to gas composition fluctuations in the observation wells. The findings provide valuable insights into heterogeneous multiphase flow in rock formations and show that conventional geological models and static fluid flow simulations are unable to fully describe the heterogeneous and dynamic flow during fluid injection.

This study developed a multicomponent geochemical model to interpret responses of water chemistry to introduction of CO2 into six water-rock batches with sedimentary samples collected from representative potable aquifers in the Gulf Coast area. The model simulated CO2 dissolution in groundwater, aqueous complexation, mineral reactions (dissolution/precipitation), and surface complexation on clay mineral surfaces. An inverse method was used to estimate mineral surface area, the key parameter for describing kinetic mineral reactions. Modeling results suggested that reductions in groundwater pH were more significant in the carbonate-poor aquifers than in the carbonate-rich aquifers, resulting in potential groundwater acidification. Modeled concentrations of major ions showed overall increasing trends, depending on mineralogy of the sediments, especially carbonate content. The geochemical model confirmed that mobilization of trace metals was caused likely by mineral dissolution and surface complexation on clay mineral surfaces. Although dissolved inorganic carbon and pH may be used as indicative parameters in potable aquifers, selection of geochemical parameters for CO2 leakage detection is site-specific and a stepwise procedure may be followed. A combined study of the geochemical models with the laboratory batch experiments improves our understanding of the mechanisms that dominate responses of water chemistry to CO2 leakage and also provides a frame of reference for designing monitoring strategy in potable aquifers.

Storage of CO2 in deep saline reservoirs has been proposed to mitigate anthropogenically forced climate change. If injected CO2 unexpectedly migrates upward in shallow groundwater resources, potable groundwater may be negatively affected. This study examines the effects of an increase in pCO2 (partial pressure of CO2) on groundwater chemistry in a siliclastic-dominated aquifer by comparing a laboratory batch experiment and a field single-well push-pull test on the same aquifer sediment and groundwater. Although the aquifer mineralogy is predominately siliclastic, carbonate dissolution is the primary geochemical reaction. In the batch experiment, Ca concentrations increase until calcite saturation is reached at ~500 h. The concentrations of the elements Ca, Mg, Sr, Ba, Mn, and U are controlled by carbonate dissolution. Silicate dissolution controls Si and K concentrations and is ~2 orders of magnitude slower than carbonate dissolution. Changing pH conditions through the experiment initially mobilize Mo, V, Zn, Se, and Cd; sorption reactions later remove these elements from solution and concentrations drop to pre-experiment levels. The EPA's primary and secondary MCL's are not exceeded except for Mn, which exceeded the EPA's secondary standard of 0.05 mg/L. Push-pull results also identify carbonate and silicate dissolution reactions ~2 orders of magnitude slower than batch experiments.

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