An improved model calculating CO2 solubility in pure water and aqueous NaCl solutions from 273 to 533 K and from 0 to 2000 bar

Duan, Zhenhao; Sun, Rui

doi:10.1016/s0009-2541(02)00263-2

Cited by 1,341 publications

(1,005 citation statements)

References 29 publications

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“…We have previously reviewed several activity coefficient models to compute values of γ CO 2 (Spycher and Pruess 2005), and highlighted the Pitzer models adopted by Rumpf et al (1994) and Duan and Sun (2003), which are essentially similar although formulated somewhat differently. We also pointed out that the activity coefficient model of Duan and Sun (2003) does not yield "true" activity coefficients (because of model simplifications regarding the gas phase), but instead gives the ratio of CO 2 concentrations in pure and saline water.…”

Section: Salt Effectsmentioning

confidence: 99%

“…We also pointed out that the activity coefficient model of Duan and Sun (2003) does not yield "true" activity coefficients (because of model simplifications regarding the gas phase), but instead gives the ratio of CO 2 concentrations in pure and saline water. As such, we previously used, as-is, the activity coefficient expression and parameters of Duan and Sun to compute the CO 2 solubility in saline water from its solubility in pure water (Spycher and Pruess 2005).…”

Section: Salt Effectsmentioning

confidence: 99%

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A Phase-Partitioning Model for CO2–Brine Mixtures at Elevated Temperatures and Pressures: Application to CO2-Enhanced Geothermal Systems

2009

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Correlations are presented to compute the mutual solubilities of CO 2 and chloride brines at temperatures 12-300 • C, pressures 1-600 bar (0.1-60 MPa), and salinities 0-6 m NaCl. The formulation is computationally efficient and primarily intended for numerical simulations of CO 2 -water flow in carbon sequestration and geothermal studies. The phase-partitioning model relies on experimental data from literature for phase partitioning between CO 2 and NaCl brines, and extends the previously published correlations to higher temperatures. The model relies on activity coefficients for the H 2 O-rich (aqueous) phase and fugacity coefficients for the CO 2 -rich phase. Activity coefficients are treated using a Margules expression for CO 2 in pure water, and a Pitzer expression for salting-out effects. Fugacity coefficients are computed using a modified Redlich-Kwong equation of state and mixing rules that incorporate asymmetric binary interaction parameters. Parameters for the calculation of activity and fugacity coefficients were fitted to published solubility data over the P-T range of interest. In doing so, mutual solubilities and gas-phase volumetric data are typically reproduced within the scatter of the available data. An example of multiphase flow simulation implementing the mutual solubility model is presented for the case of a hypothetical, enhanced geothermal system where CO 2 is used as the heat extraction fluid. In this simulation, dry supercritical CO 2 at 20 • C is injected into a 200 • C hot-water reservoir. Results show that the injected CO 2 displaces the formation water relatively quickly, but that the produced CO 2 contains significant water for long periods of time. The amount of water in the CO 2 could have implications for reactivity with reservoir rocks and engineered materials.

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Section: Salt Effectsmentioning

confidence: 99%

Section: Salt Effectsmentioning

confidence: 99%

A Phase-Partitioning Model for CO2–Brine Mixtures at Elevated Temperatures and Pressures: Application to CO2-Enhanced Geothermal Systems

2009

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“…Na + and Cl are the main components in natural water [42], and it is a must to study not only the CO 2 -H 2 O system, but also the effect of ions on the properties of this solution. Therefore, the CO 2 solubility in aqueous NaCl solutions is surveyed, and the available experimental data are summarized in Table 3.…”

Section: Co 2 -H 2 O-nacl Systemmentioning

confidence: 99%

“…(3) Duan and Sun [42] calculated the solubility of CO 2 in aqueous NaCl solutions at temperatures from 273 to 533K, pressures from 0 to 200MPa, and ionic strength from 0 to 4.3mol·L 1 by an improved model. The model was based on a specific particle interaction theory for the liquid phase and an accurate equation of state for the vapour phase.…”

Section: Co 2 -H 2 O-nacl Systemmentioning

confidence: 99%

“…SAFT1-RPM theory used by Ji et al [51] is one sample, but it still cannot describe the phase behavior and density at high temperatures and pressures for the CO 2 -H 2 O-NaCl system accurately. Moreover, natural waters often contain ions more than Na + and Cl , for example, K + , Ca 2+ , Mg 2+ , 2 4 SO − , 2 3 CO − [42], which requires to study the phase equilibrium and densities of aqueous solutions with CO 2 and multi-ions under the geological conditions. Some improvements may be made by using the SAFT EOS coupling other EOS or activity coefficient models.…”

Section: Co 2 -H 2 O-nacl Systemmentioning

confidence: 99%

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Progress in the Study on the Phase Equilibria of the CO2-H2O and CO2-H2O-NaCl Systems

Feng

et al. 2007

Chinese Journal of Chemical Engineering

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To study the feasibility of CO 2 geological sequestration, it is needed to understand the complicated multiple-phase equilibrium and the densities of aqueous solution with CO 2 and multi-ions under wide geological conditions (273.15 473.15K, 0 60MPa), which are also essential for designing separation equipments in chemical or oil-related industries. For this purpose, studies on the relevant phase equilibria and densities are reviewed and analyzed and the method to improve or modify the existing model is suggested in order to obtain more reliable predictions in a wide temperature and pressure range. Besides, three different models (the electrolyte non random two-liquid (ELECNRTL), the electrolyte NRTL combining with Helgeson model (ENRTL-HG), Pitzer activity coefficient model combining with Helgeson model (PITZ-HG)) are used to calculate the vapor-liquid phase equilibrium of CO 2 -H 2 O and CO 2 -H 2 O-NaCl systems. For CO 2 -H 2 O system, the calculation results agree with the experimental data very well at low and medium pressure (0 20MPa), but there are great discrepancies above 20MPa. For the water content at 473.15K, the calculated results agree with the experimental data quite well. For the CO 2 -H 2 O-NaCl system, the PITZ-HG model show better results than ELECNRTL and ENRTL-HG models at the NaCl concentration of 0.52mol·L 1 . Bur for the NaCl concentration of 3.997mol·L 1 , using the ELECNRTL and ENRTL-HG models gives better results than using the PITZ-HG model. It is shown that available experimental data and the thermodynamic calculations can satisfy the needs of the calculation of the sequestration capacity in the temperature and pressure range for disposal of CO 2 in deep saline aquifers. More experimental data and more accurate thermodynamic calculations are needed in high temperature and pressure ranges (above 398.15K and 31.5MPa).

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Rapid porosity and permeability changes of calcareous sandstone due to CO₂‐enriched brine injection

Lamy-Chappuis

Angus

Fisher

et al. 2014

Geophysical Research Letters

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Reservoir injectivity and storage capacity are the main constraints for geologic CO 2 sequestration, subject to safety and economic considerations. Brine acidification following CO 2 dissolution leads to fluid-rock interactions that alter porosity and permeability, thereby affecting reservoir storage capacity and injectivity. Thus, we determined how efficiently CO 2 -enriched brines could dissolve calcite in sandstone cores and how this affects the petrophysical properties. During computerized tomography monitored flow-through reactor experiments, calcite dissolved at a rate largely determined by the rate of acid supply, even at high flow velocities which would be typical near an injection well. The porosity increase was accompanied by a significant increase in rock permeability, larger than that predicted using classical porosity-permeability models. This chemically driven petrophysical change might be optimized using injection parameters to maximize injectivity and storage.

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An improved model calculating CO2 solubility in pure water and aqueous NaCl solutions from 273 to 533 K and from 0 to 2000 bar

Cited by 1,341 publications

References 29 publications

A Phase-Partitioning Model for CO2–Brine Mixtures at Elevated Temperatures and Pressures: Application to CO2-Enhanced Geothermal Systems

A Phase-Partitioning Model for CO2–Brine Mixtures at Elevated Temperatures and Pressures: Application to CO2-Enhanced Geothermal Systems

Progress in the Study on the Phase Equilibria of the CO2-H2O and CO2-H2O-NaCl Systems

Rapid porosity and permeability changes of calcareous sandstone due to CO₂‐enriched brine injection

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An improved model calculating CO2 solubility in pure water and aqueous NaCl solutions from 273 to 533 K and from 0 to 2000 bar

Cited by 1,341 publications

References 29 publications

A Phase-Partitioning Model for CO2–Brine Mixtures at Elevated Temperatures and Pressures: Application to CO2-Enhanced Geothermal Systems

A Phase-Partitioning Model for CO2–Brine Mixtures at Elevated Temperatures and Pressures: Application to CO2-Enhanced Geothermal Systems

Progress in the Study on the Phase Equilibria of the CO2-H2O and CO2-H2O-NaCl Systems

Rapid porosity and permeability changes of calcareous sandstone due to CO2‐enriched brine injection

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Rapid porosity and permeability changes of calcareous sandstone due to CO₂‐enriched brine injection