Article pubs.acs.org/est
Predicting Possible Effects of H2S Impurity on CO2 Transportation and Geological Storage Xiaoyan Ji*,† and Chen Zhu‡ †
Division of Energy Science/Energy Engineering, Lulea University of Technology, 97187 Lulea, Sweden Department of Geological Sciences, Indiana University, Bloomington, Indiana 47401, United States
‡
ABSTRACT: For CO2 geological storage, permitting impurities, such as H2S, in CO2 streams can lead to a great potential for capital and energy savings for CO2 capture and separation, but it also increases costs and risk management for transportation and storage. To evaluate the cost−benefits, using a recently developed model (Ji, X.; Zhu, C. Geochim. Cosmochim. Acta 2012, 91, 40−59), this study predicts phase equilibria and thermodynamic properties of the system H2S−CO2−H2O− NaCl under transportation and storage conditions and discusses potential effects of H2S on transportation and storage. The prediction shows that inclusion of H2S in CO2 streams may lead to two-phase flow. For H2S−CO2 mixtures, at a given temperature, the bubble and dew pressures decrease with increasing H2S content, while the mass density increases at low pressures and decreases at high pressures. For the CO2−H2S− H2O system, the total gas solubility increases while the mass density of the aqueous solution with dissolved gas decreases. For the CO2−H2S−H2O−NaCl system, at a given temperature, pressure and NaCl concentration, the solubility of the gas mixture in aqueous phase increases with increasing H2S content and then decreases, while the mass density of aqueous solution decreases and may be lower than the mass density of the solution without gas dissolution.
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Bachu and Bennion8 conducted solubility measurements in H2S−CO2−brine system representing the field conditions at an injection site into the Keg River Formation in Northern Alberta at 334.15 K, 135 bar, and with a salinity of 118 950 mg/L, but their experimental data collection was incomplete and their data are not sufficient for obtaining the equilibrium composition.2 Density is essential to reservoir/aquifer simulation applications. The dissolution of CO2 in aqueous solutions under most reservoir conditions results in an increase in the density of the solution, which can induce a free convection.6,9,10 Meanwhile, other properties (e.g., viscosity) of the H2O-rich phase are also strongly dependent on density, which varies greatly with temperature, pressure, gas concentration, and salinity.11 However, experimental data of density for the CO2−H2S−H2O−NaCl and its subsystems are even scarcer than those of the solubility data. 5,12−14 Since experimental measurements are time-consuming and expensive, because of the corrosiveness of H2S, it is desirable to have a predictive model to obtain estimates of properties that are consistent with limited experimental data.
INTRODUCTION CO2 storage in deep saline aquifers is a promising option to limit the continuing buildup of greenhouse gases in the atmosphere. In general, CO2 streams from power stations and other CO2 intensive industries are mixtures, and the separation of CO2 from gas mixtures is the main cost for CO2 capture and storage. In fact, it is estimated that 3/4 of the cost is used for CO2 separation from gas streams.1 H2S is one of the most common components in natural gas and products derived from oil processing and production, and it is also one of the main impurities of flue gas streams from thermal power plants. The injection of H2S−CO2 mixtures can lead to potentials for great capital and energy savings in capture, but it may also seriously increase the costs and risks of CO2 transportation and storage. For example, the inclusion of H2S will increase the risk of pipeline corrosion1 and the dissolution of H2S into the brine in the reservoirs seriously alters the geochemistry.2 To understand the effects of H2S in CO2 transportation and geological storage, it is critical to know the thermodynamic properties and phase equilibria for the system CO2−H2S−H2O−NaCl, as NaCl is usually the main salt in saline aquifers. Experimental data of CO2 solubility in H2O and in aqueous NaCl solutions and of the solubility of H2S in H2O and in aqueous NaCl solutions have been determined in a wide temperature and pressure range.3−5 CO2 solubility in brine with other salts was also measured.6,7 However, there are almost no experimental data on the solubility of H2S−CO2 mixtures. © 2012 American Chemical Society
Special Issue: Carbon Sequestration Received: Revised: Accepted: Published: 55
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by fitting to the liquid-density and vapor-pressure data of a pure component.2 NaCl was considered to be completely dissociated into a cation (Na+) and an anion (Cl−). Each ion was modeled as a spherical species exerting repulsive, dispersive, and Coulomb forces. The transferable parameters of Na+ and Cl− were determined by fitting to the activity coefficients of a group of single electrolytes in water.26 For mixtures, the mixing rules in our previous work13,25−27,29,30 were followed. To account for the special interaction between H2S and H2O, between CO2 and H2O, and between H2S and CO2, cross association interaction was assigned with parameters ε and κ. In addition, cross parameter kij was used to adjust the cross-dispersion energy between two different segments of molecules, that is,
Numerous models have been proposed to represent phase equilibria for CO2−H2O−(NaCl)3,4,15−18 and H2S−H2O− (NaCl)19−23 systems. For the more complicated quaternary CO2−H2S−H2O−NaCl system, the lack of experimental data has generally prevented the development of models which rely on fitting parameters. TMGAS, based on the Peng−Robinson (PR) equation of state (EoS), was proposed, fortuitously, to represent the equilibrium composition and thermophysical properties of gas mixtures in NaCl brine.24 However, in that model, (H 2 O + NaCl) was considered as a brine pseudocomponent. The model parameters of water were different in the two phases. Two sets of binary interaction coefficients were used for nonaqueous and aqueous phases, respectively, and some of them were related to the molalilty of NaCl. The model verification for CO2−H2S is unclear. In addition, the density of the aqueous phase was independent of PR EoS, which means that thermodynamic properties and phase equilibria cannot be represented with the same EoS. We have conducted extensive work on using statistical associating fluid theory (SAFT) to develop thermodynamic models that represent phase equilibria and thermodynamic properties for NaCl−H2O,25−30 CO2−H2O−NaCl,13 and H2S−H2O23 systems. In those SAFT-based models, one set of parameters was used for both nonaqueous and aqueous phases, and the equilibrium composition, as well as the density at equilibrium or in a single phase region, was calculated without any additional parameters. The modeling results have been verified extensively by available experimental data for binary and ternary systems. Because of the firm statisticalmechanics basis of the SAFT-based model, we were able to develop an EoS for the quaternary CO2−H2S−H2O−NaCl system that was built upon previous work and parameters from its subsystems.2 To further illustrate the application of our model to evaluating the effects of H2S on the properties of CO2 streams during transportation and the geologic carbon sequestration process, we evaluated the thermodynamic properties of CO2− H2S−H2O−NaCl system under conditions pertinent to H2S− CO2 mixture transportation and geological storage. Density, bubble/dew pressures and equilibrium composition were calculated for CO2 streams containing amounts of H2S under typical coinjection conditions, that is, at temperatures from 303.15 to 383.15 K, pressures up to 400 bar, H2S is from 0 to 80% (mole fraction), and CO2 is from 100% to 20% (mole fraction).
uij =
(2)
These cross parameters (ε, κ and kij) were determined by fitting to binary or ternary data, specifically, cross parameters of H2S−CO2 from H2S−CO2 system, of H2S−H2O from H2S− H2O system, of H2S−NaCl from H2S−H2O−NaCl system, of CO2−H2O from CO2−H2O system, and of CO2−NaCl from CO2−H2O−NaCl system.
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RESULTS AND DISCUSSION The details of the model development were discussed in our previous publication.2 Here, we focus on the H2S effects on the thermodynamic properties and phase equilibria related to transportation and storage processes when a CO2 stream contains H2S. 1. Mixture of CO2−H2S. In general, the reservoir temperature varies from 30 to 110 °C (303.15 to 383.15 K), the pressure changes from 6.6 to 35.9 MPa (66 to 359 bar), and the composition of the injected gas can be from 2 to 83% of H2S (mole fraction) and 95 to14% of CO2 (mole fraction).31 Considering pressures for CO2 transportation (40 bar),32 the discussion focuses on temperatures from 30 to 110 °C (303.15 to 383.15 K), pressures from 4 to 40 MPa (40 to 400 bar), H2S from 0 to 80%, and CO2 from 100 to 20%. 1.1. Phase State. Phase state is an important parameter for transportation and injection process because two-phase flow in the pipeline could cause cavitation and pressure peaks, and would most likely damage the pipeline.33 Two-phase flow is also problematic in the operation of pumps, as well as compressors and injection wells.34 In addition, fluid properties depend on phase state. For example, the densities of a pure fluid in the liquid and vapor phases are completely different at the same temperature and saturation pressure. For a pure fluid, the phase state depends on temperature and pressure. For CO2, the critical temperature (T) and pressure (P) are 31.04 °C and 73.8 bar, respectively; for H2S, they are 100 °C and 89.4 bar. Due to the different critical properties, CO2 and H2S can exist in different states under the same conditions. For example, in the temperature range of 30 to 110 °C, with increasing pressure starting from 40 bar, the pure CO2 changes from gaseous to liquid (region a) or to supercritical fluid (region b+c+d) while pure H2S is still liquid (region a+b) or changes from gas to liquid phase (region c) or from gas to supercritical fluid (region d), as shown in Figure 1. For a CO2−H2S mixture, the phase state depends on T, P, and composition. To determine the phase state of this mixture, the equilibrium composition x/y (mole fraction for aqueous/
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MODELING For SAFT2, the dimensionless residual Helmholtz energy is defined as a ̃res = a ̃hs + a disp + a chain + a ̃ion ̃ + a assoc ̃ ̃
uiuj (1 − kij)
(1)
where the superscripts refer to terms accounting for the residual, hard-sphere repulsive, dispersive, associative, chain, and ionic (Coulomb) interactions, respectively. Each term in the left side of eq 1 was described elsewhere.13,25−27,29,30 For CO2, H2S, and H2O, each substance was modeled with a maximum 6 parameters. These were segment number m, segment volume voo, segment energy u/K, and the reduced range of the potential well λ, and, for molecules with association interactions, the well depth of the association site−site potential ε and the parameter related to the volume available for bonding κ were used to characterize the associative interaction. The parameters of each substance were determined 56
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the dew and bubble pressures at different temperatures were calculated and are listed in Table 1. At a given temperature, Pb and Pd decrease with increasing H2S, which implies a decrease in the minimum operation pressure for a high-pressure CO2 gas pipeline. At a given H2S ratio, Pb and Pd increase with increasing temperature, which requires an increase of the pressure level for high-pressure transportation in order to avoid two-phase flow. On the other hand, increase of temperature avoids phase split in a wide range of H2S concentrations, which is important for transportation and gas injection operations. 1.2. Density. The density of the (supercritical) gas phase (ρ) is an important property as it reflects the amount of the fluid that can be stored at a fixed volume in subsurface conditions, as well as the transportation capacity. In addition, ρ is related to buoyancy force that could dominate the migration of a CO2 plume in a geological reservoir such as Sleipner.35 ρ is a function of temperature, pressure, composition, and phase state. To calculate ρ in this study, the phase state was first determined from temperature, pressure, and composition as described in section 1.1. If the phase state is in a two-phase region, ρ relates to the equilibrium density in both phases. Thus, in this study, the equilibrium density in both phases at 303.15, 323.15, 343.15, and 363.15 K was calculated and illustrated in Figure 2b. It is shown that at a given temperature, the equilibrium density of the liquid phase decreases while the equilibrium density of the vapor phases increases with increasing pressure. At the critical pressure, the density becomes one value. To further illustrate the effect of H2S on the density of CO2− H2S mixtures, ρ was predicted at pressures from 40 to 400 bar and at temperatures at 303.15, 323.15, 343.15, 363.15, and 383.15 K. At 303.15 K, pure CO2 goes from vapor to compressed liquid. Due to the inclusion of H2S, there will be a phase split in a certain range of pressure, which is depicted as dash lines in Figure 3, and the fluid changes from vapor to vapor−liquid coexistence and then to compressed liquids with increasing pressure. For the mixture with 80% H2S, within the pressure range of interest, it is always a compressed liquid because the bubble pressure is lower than 40 bar. At 303.15 K, the mole density of the fluid increases with increasing H2S, while the mass density increases at low pressure but decreases at high pressure as shown in Figure 3a and b, respectively. In general, mass is used to account the amount of
Figure 1. Phase diagram for pure CO2 and H2S. Region a: Temperature (T) is from 30 to 31.04 °C. Region b: T is from 31.04 °C to saturation temperature of pure H2S at 40 bar. Region c: T is from saturation temperature of pure H2S at 40 bar to 100 °C. Region d: T is higher than 100 °C. Pressure (P) for regions a, b, c, and d is higher than 40 bar.
nonaqueous phases; the same symbol used hereafter) was calculated at 303.15, 323.15, 343.15, and 363.15 K. The results are shown in Figure 2a. At 303.15 K, there is always a phase split throughout the whole concentration range because the critical temperature of CO2 is higher than 303.15 K. With increasing temperature, the phase split will only occur when the H2S composition exceeds a certain value specific to a given temperature, which is noted as critical composition; the corresponding pressure is noted as critical pressure. For example, at 323.15 K when the mole fraction of H2S is less than 0.315, there is no phase split and the corresponding critical pressure is 89.29 bar. The critical compositions and pressures at different temperatures are listed in Table 1. For CO2−H2S mixtures, at a certain temperature and composition, the phase state also depends on pressure P. If P < dew pressure Pd, the fluid is in the vapor phase; if P > bubble pressure Pb, the fluid is in a compressed liquid state; and if Pd < P < Pb, the fluid is in a two-phase region. In the current study,
Figure 2. Equilibrium compositions and densities at 303.15, 323.15, 343.15, and 363.15 K for CO2−H2S system. x/y, mole fractions in aqueous/ nonaqueous phases; P, pressure in bar; Pd, dew pressure; Pb, bubble pressure; ρ, density in kg/m3. 57
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Table 1. Critical Composition, Critical Pressure, and Bubble (Pb)/Dew (Pd) Pressures at 303.15, 323.15 343.15, and 363.15 K with H2S at 20, 40, 60, and 80% (Mole Fraction) 323.15 K
343.15 K
critical composition
303.15 K
0.315
0.585
0.805
critical pressure, bar
89.29
97.85
102.30
Pb/Pd, bar 20% 40% 60% 80%
H2S H2S H2S H2S
363.15 K
Pb
Pd
Pb
Pd
Pb
Pd
65.61 58.11 49.68 39.07
63.47 50.04 37.15 28.05
84.87 72.28 57.12
79.40 59.12 44.92
97.56 79.48
92.44 67.76
Pb
Pd
to bubble pressure at a certain temperature. To illustrate the effect of H2S, the solubility of gas mixtures and the corresponding density of the aqueous solution were calculated at mole fraction of H2S from 0 to 80% in the liquid phase and at various bubble pressures. As the effect of NaCl concentration on the gas solubility has been discussed in our previous publication,2 the NaCl concentration was set to be zero in this work. The solubility of gas mixtures and the corresponding aqueous solution mass density are illustrated in Figure 4a−f at 323.15, 348.15, and 373.15 K. It is shown that with increasing H2S, the solubility of gas mixture increases because H2S is more soluble (Figure 4a), and the corresponding mass density of the aqueous solution decreases (Figure 4b). Since a decrease of mass density will provide negative effect on the gas storage process, the inclusion of H2S is unfavorable. However, as discussed in the preceding text, the inclusion of H2S will increase mass density of gas mixtures at low pressures and then lead to an increase in the amount of the gas storage at a fixed volume in subsurface conditions, as well as be favorable for transportation and storage. In addition, the cost for the separation of H2S from CO2 is related to the purity of CO2 as products. Therefore, there should be a balance between separation and CO2 storage and transportation. To investigate further the effect of H2S on the dissolution of CO2, as well as the mass density of the aqueous phase, one example is investigated in detail at 348.15 K, 135 bar, and mNaCl = 2 mol/kgH2O. The results are illustrated in Figure 5. At a given T and P, with increasing H2S: (1) the CO2 solubility decreases, the H2S solubility increases, and the total gas solubility increases and then decreases (Figure 5a), all nonlinearly, due to the interaction between H2S and CO2 or the nonideal mixing. If the mixture of CO2 and H2S can be assumed as ideal mixing, the solubility of gas mixture will follow the dash line in Figure 5a, and the solubility for both CO2 and H2S will decrease and increase linearly with increasing H2S, respectively; (2) the corresponding aqueous solution density decreases (Figure 5b); (3) in the vapor phases, the mole fraction of H2S increases while the mole fraction of CO2 decreases (Figure 5c), both nonlinearly, which again implies the nonideal mixing behavior; and (4) the mole fraction of H2S in the vapor phase is lower than that in the liquid phase because H2S is more soluble (Figure 5d). In other words, H2S is partitioned favorably into the aqueous phase when compared to the vapor phase. The inclusion of H2S will decrease the mass density of the aqueous solution. If the mass density is less than the density of the aqueous solution without dissolved gas, it will not cause natural convection anymore and then the CO2 dissolution process will be slowed down considerably. Meanwhile, the brine can be subject to buoyancy-driven migration. As shown in
gas that can be transported or stored. Therefore, mass density is used here to illustrate the modeling results at temperatures other than 303.15 K as shown in Figure 3c−f. With increasing temperature, the inclusion of a certain amount of H2S will not cause phase split, for example, at 323.15 K with 20% H2S, and at 343.15 K with 20% and 40% H2S, as shown in Figure 3c and d. When the temperature is high enough, such as at 363.15 K, no phase split occurs at all within the H2S range of interest. When H2S goes up to 80%, it is always in one phase region. At 383.15 K, since it is higher than the critical temperature of H2S, there is no phase split. In addition, with increasing H2S%, the mass density of the fluid increases at low pressures and decreases at high pressures. Density is related to the transportation/storage capacity. Because of the inclusion of H2S, the mass density increases at low pressures, which means that the volume of the mixture decreases, leading to an increase in the amount of the gas that can be stored in a fixed volume in the reservoirs. Thus, the inclusion of H2S in this low pressure range is favorable for CO2 geological storage with respect to gas volume. With increasing temperature, the pressure range in which the mass density increases with the inclusion of H2S becomes wider, which implies that the favorite operation range is wider. Finally, the solid curves in Figure 3 represent the possible operation conditions to avoid two-phase flow. 2. Effects of H2S on CO2 Solubility and Aqueous Phase Density. In geologic carbon sequestration, it is well-known that gas solubility in brine is crucial not only to solubility trapping, but also to modeling the reactions of dissolved gas with minerals. Another property of particular importance to CO2 sequestration is the density of brine (aqueous solution) containing dissolved gas. If dissolution of gas into brine causes an increase of brine density and this density difference may also be large enough to trigger Rayleigh instability, which can strongly enhance dissolution processes due to mixing.36 However, if the dissolution of gas into the brine decreases the brine mass density, the brine can be subject to buoyancydriven migration (and potential escape from formation) associated with separate gas phase.36 Therefore, in this section, the effect of H2S on CO2 solubility as well as on mass density of the aqueous solution with dissolved gas is presented. For systems with two components in equilibrium, the equilibrium composition in both phases depends on temperature and pressure, while for systems with more than two components in equilibrium, the equilibrium composition in both phases depends on the temperature, pressure, and other conditions, such as the gas injected and the water amount in reservoir. If we assume that the injected gas will ultimately be dissolved completely into aqueous solution, the mole ratio of H2S to CO2 will be the same as that in the injected gas, and the maximum amount of gas that can be dissolved will correspond 58
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Figure 3. Density (ρ) of (CO2 + H2S) in which H2S is from 0 to 80% (mole fraction) at 303.15, 323.15, 343.15, 363.15, and 383.15 K and at pressures from 40 to 400 bar. Dash lines: VLE coexistence. Solid curves: Single-phase. Curve with red color: Density of CO2.
driven. Since, the separation of H2S will increase the cost considerably, and the inclusion of H2S may be favorable for transportation and storage capacity but provide a negative effect on dissolution trapping mechanism, it always necessary to find out the balance between CO2 capture (separation) and geological sequestration.
Figure 5b, dissolution of (CO2 + H2S) will result in a density of the aqueous solution higher than the density of aqueous NaCl solutions (1051 kg/m3 at 348.15 k, 135 bar, and mNaCl = 2 mol/ kgH2O, dash line in Figure 5b), but with increasing H2S, the density of the aqueous solution with dissolved gas can be lower than the density of pure NaCl solution. When H2S goes to 65%, the mass densities of aqueous solution with or without dissolved gases are equal, which represents the maximum H2S content to keep the advantage of natural convection in the dissolution trapping mechanism and avoid brine buoyancy-
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ENVIRONMENTAL IMPLICATIONS
In this study, we used our recently developed model for the CO2−H2S−H2O−NaCl system to evaluate the effects of H2S 59
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Figure 4. Solubility of gas mixture and equilibrium mass density of aqueous solutions for CO2−H2S−H2O system at 323.15, 348.15, and 373.15 K, bubble pressures up to 400 bar, and the mole fraction of H2S is from 0% to 80%. Curve with red color: solubility of CO2 in H2O and the corresponding aqueous solution density with dissolved CO2, respectively.
on the properties of CO2 streams during transportation and geological storage. The investigation shows that the inclusion of H2S in CO2 streams (1) may lead to two-phase flow and then cause problems for the operation of pumps and compressors, as well as injection wells; (2) the mass density of the gas mixture increases and then decreases with increasing pressures; (3) the solubility of the gas mixture in aqueous phase increases while the corresponding aqueous solution mass density decreases;
and (4) at a certain temperature, pressure, and NaCl concentration, the solubility of the gas mixture in aqueous phase increases and then decreases while the mass density of aqueous solution decreases and may be lower than the mass density of the solution without gas dissolution. Therefore, the inclusion of H2S will positively or negatively affect the subsequent transportation and storage processes, depending on the concentration. For example, two-phase flow and the 60
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Figure 5. Equilibrium composition for CO2−H2S−H2O-NaCl at 348.15 K, 135 bar, mNaCl = 2 mol/kgH2O and the mass density of aqueous solutions with dissolved gas. Solid curves: model prediction; dash line in (a) total gas solubility for the ideal mixing; dash line in (b) density of aqueous solution without dissolved gas; dash line in (d) yH2S/(yH2S + yCO2) = xH2S/(xH2S + xCO2).
from the Norwegian Center of Excellence Subsurface CO2 Storage−Critical Elements and Superior Strategy (SUCCESS), and a Fulbright scholarship to Norway. Editorial assistance from Laura Brant is appreciated.
reduction of mass density for gas mixtures and for aqueous solutions with dissolved gas are negative to CO2 transportation/sequestration processes, while the high gas solubility in aqueous phases, as well as the increase in mass density, are favorable to them. Concerning the cost for the separation of H2S, a balance between separation and CO2 transportation/ sequestration should be found, and the results from this work provide a scientific basis on the thermophysical properties of the mixtures for evaluating the cost versus the benefits for CO2 geological storage with H2S impurities in the CO2 streams.
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REFERENCES
(1) Metz, B.; Davidson, O.; de Coninck, H. C.; Loos, M.; Meyer, L. A. IPCC Special Report on Carbon Dioxide Capture and Storage; Cambridge University Press: Cambridge, U.K., 2005. (2) Ji, X. Y.; Zhu, C. A SAFT equation of state for the quaternary H2S−CO2−H2O−NaCl system. Geochim. Cosmochim. Acta 2012, 91, 40−59. (3) Ji, Y. H.; Ji, X. Y.; Feng, X.; Liu, C.; Lu, L. H.; Lu, X. H. Progress in the study on the phase equilibria of the CO2−H2O and CO2− H2O−NaCl systems. Chin. J. Chem. Eng. 2007, 15 (3), 439−448. (4) Duan, Z. H.; Sun, R.; Liu, R.; Zhu, C. Accurate thermodynamic model for the calculation of H2S solubility in pure water and brines. Energy Fuels 2007, 21 (4), 2056−2065. (5) Yan, W.; Huang, S. L.; Stenby, E. H. Measurement and modeling of CO2 solubility in NaCl brine and CO2-saturated NaCl brine density. Int. J. Greenhouse Gas Control 2011, 5 (6), 1460−1477. (6) Yang, C. D.; Gu, Y. G. Accelerated mass transfer of CO2 in reservoir brine due to density-driven natural convection at high
AUTHOR INFORMATION
Corresponding Author
*Phone: +46-920-492837. Fax: +46-920-491074. E-mail:
[email protected]. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS X. Ji thanks the Swedish Research Council for the financial support, and CZ acknowledges the support of the U.S. Department of Energy grant DE-FE0004381, the support 61
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dx.doi.org/10.1021/es301292n | Environ. Sci. Technol. 2013, 47, 55−62
