A new experimental system was designed to measure the solubility of CO 2 at pressures and temperatures (150 bar, 323.15-423.15 K) relevant to geologic CO 2 sequestration. At 150 bar, new CO 2 solubility data in the aqueous phase were obtained at 323.15, 373.15, and 423.15 K from 0 to 6 mol kg-1 NaCl(aq) for the CO 2-NaCl-H 2 O system. A ߛ െ ߮ (activity coefficientfugacity coefficient) type thermodynamic model is presented for the calculation of both the solubility of CO 2 in the aqueous phase and the solubility of H 2 O in the CO 2-rich phase for the CO 2-NaCl-H 2 O system. Validation of the model calculations against literature data and other models (MZLL2013, AD2010, SP2010, DS2006, and OLI) show that the proposed model is capable of predicting the solubility of CO 2 in the aqueous phase for the CO 2-H 2 O and CO 2-NaCl-H 2 O systems with a high degree of accuracy (AAD < 3.9%) at temperatures from 273.15 to 573.15 K and pressures up to 2000 bar. A comparison of modeling results with experimental values revealed a pressure-bounded "transition zone" in which the CO 2 solubility decreases to a minimum then increases as the temperature increases. CO 2 solubility is not a monotonic function of temperature in the transition zone but outside of that transition zone, the CO 2 solubility is decrease or increase monotonically in response to increased temperature. A link of web-based CO 2 solubility computational tool can be provided by sending a message to Haining Zhao at
A numerical model was developed with the use of reactive transport code CrunchFlow to estimate porosity, permeability and mineral composition changes of Mount Simon sandstone under typical geological carbon sequestration conditions (P=23.8 MPa and T=85 o C). The model predicted a permeability decrease from 1.60 mD to 1.02 mD for the Mount Simon sandstone sample in a static batch reactor after 180 days of exposure to CO 2-saturated brine, which is consistent with measured permeability results. Model-predicted solution chemistry results were also consistent with laboratory-measured solution chemistry data. SiO 2 (am) was the primary mineral that causes permeability decrease, followed by kaolinite. Both SiO 2 (am) formation and kaolinite formation were attributed to the dissolution of quartz and feldspar. This study shows that the formation of SiO 2 (am) and kaolinite in the pore space of host rock is possible under typical CO 2 sequestration conditions. SiO 2 (am) and kaolinite precipitation at the CO 2 plume extent could reduce the permeability of host rock and improve lateral containment of free-phase CO 2 , contributing to overall security of CO 2 storage.
CO2 solubility data in the natural formation brine, synthetic formation brine, and synthetic NaCl+CaCl2 brine were collected at the pressures from 100 to 200 bar, temperatures from 323 to 423 K. Experimental results demonstrate that the CO2 solubility in the synthetic formation brines can be reliably represented by that in the synthetic NaCl+CaCl2 brines. We extended our previously developed model (PSUCO2) to calculate CO2 solubility in aqueous mixed-salt solution by using the additivity rule of the Setschenow coefficients of the individual ions (Na(+), Ca(2+), Mg(2+), K(+), Cl(-), and SO4(2-)). Comparisons with previously published models against the experimental data reveal a clear improvement of the proposed PSUCO2 model. Additionally, the path of the maximum gradient of the CO2 solubility contours divides the P-T diagram into two distinct regions: in Region I, the CO2 solubility in the aqueous phase decreases monotonically in response to increased temperature; in region II, the behavior of the CO2 solubility is the opposite of that in Region I as the temperature increases.
The US DOE-funded National Risk Assessment Partnership (NRAP) has developed an integrated assessment model (NRAP-IAM-CS) that can be used to simulate carbon dioxide (CO 2) injection, migration, and associated impacts at a geologic carbon storage site. The model, NRAP-IAM-CS, incorporates a system-modeling-based approach while taking into account the full subsurface system from the storage reservoir to groundwater aquifers and the atmosphere. The approach utilizes reduced order models (ROMs) that allow fast computations of entire system performance even for periods of hundreds to thousands of years. The ROMs are run in Monte Carlo mode allowing estimation of uncertainties of the entire system without requiring long computational times. The NRAP-IAM-CS incorporates ROMs that realistically represent several key processes and properties of storage reservoirs, wells, seals, and groundwater aquifers. Results from the NRAP-IAM-CS model are used to quantify risk profiles for selected parameter distributions of reservoir properties, seal properties, numbers of wells, well properties, thief zones, and groundwater aquifer properties. A series of examples is used to illustrate how the risk under different storage conditions evolves over time, both during injection, in the near-term post injection period, and over the long term. It is also shown how results from NRAP-IAM-CS can be used to investigate the importance of different parameters on risk of leakage and risk of groundwater contamination under different storage conditions.
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