Contents

Cover

Title page

Copyright page

Preface

Chapter 1: Enthalpies of Carbon Dioxide-Methane and Carbon Dioxide-Nitrogen Mixtures: Comparison with Thermodynamic Models

1.1 Introduction
1.2 Enthalpy
1.3 Literature Review
1.4 Calculations
1.5 Discussion
1.6 Conclusion
References

Chapter 2: Enthalpies of Hydrogen Sulfide-Methane Mixture: Comparison with Thermodynamic Models

2.1 Introduction
2.2 Enthalpy
2.3 Literature Review
2.4 Calculations
2.5 Discussion
2.6 Conclusion
References

Chapter 3: Phase Behavior and Reaction Thermodynamics Involving Dense-Phase CO₂ Impurities

3.1 Introduction
3.2 Experimental
3.3 Results and Discussion
References

Chapter 4: Sulfur Recovery in High Density CO₂ Fluid

4.1 Introduction
4.2 Literature Review
4.3 Methodology
4.4 Results and Discussion
4.5 Conclusion and Future Directions
References

Chapter 5: Carbon Capture Performance of Seven Novel Immidazolium and Pyridinium Based Ionic Liquids

5.1 Introduction
5.2 Experimental Work
5.3 Modeling
5.4 Results and Discussion
5.5 Conclusion
Acknowledgements
References

Chapter 6: Vitrisol^® a 100% Selective Process for H₂S Removal in the Presence of CO₂

6.1 Introduction
6.2 Case Definition
6.3 “Amine-Treated” Cases by PPS
6.4 Vitrisol^® Process Extended with Regeneration of Active Component
6.5 Results
6.6 Discussion
6.7 Conclusions
6.8 Notation
References
Appendix 6-A: H&M Balance of Case 1 (British Columbia shale) of the Amine Process
Appendix 6-B H&M Balance of Case 2a (Barnett shale) of the Amine Process with Stripper Promoter
Appendix 6-C H&M Balance of Case 3 (Barnett shale) of the Amine Process (MEA)
Appendix 6-D: H&M Balance of Case 1 (British Columbia shale) of the Vitrisol^® process
Appendix 6-E H&M Balance of Case 2 (Barnett shale) of the Vitrisol^® Process

Chapter 7: New Amine Based Solvents for Acid Gas Removal

7.1 Introduction
7.2 Chemicals and Materials
7.3 Liquid-Liquid Equilibria
7.4 Densities and Heat Capacities of Ternary Systems {NMPD – H₂O – Glycol}
7.5 Vapor-Liquid Equilibria of Ternary Systems {NMPD – TEG – H₂O – CO₂}
7.6 Enthalpies of Solution
7.7 Discussion and Conclusion
Acknowledgments
References

Chapter 8: Improved Solvents for CO₂ Capture by Molecular Simulation Methodology

8.1 Introduction
8.2 Physical and Chemical Models
8.3 Molecular-Level Models and Algorithms for Thermodynamic Property Predictions
8.4 Molecular-Level Models and Methodology for MEA–H₂O–CO₂
Acknowledgements
References

Chapter 9: Strategies for Minimizing Hydrocarbon Contamination in Amine Acid Gas for Reinjection

9.1 Introduction
9.2 Amine Sweetening Process
9.3 Hydrocarbons in Amine
9.4 Effect of Hydrocarbons on the Acid Gas Reinjection System
9.5 Effect of Hydrocarbons on the Amine Plant
9.6 Minimizing Hydrocarbon Content in Amine Acid Gas
References

Chapter 10: Modeling of Transient Pressure Response for CO₂ Flooding Process by Incorporating Convection and Diffusion Driven Mass Transfer

10.1 Introduction
10.2 Model Development
10.3 Results and Discussion
10.4 Conclusions
Acknowledgments
References

Chapter 11: Well Modeling Aspects of CO₂ Sequestration

11.1 Introduction
11.2 Delivery Conditions
11.3 Reservoir and Completion Data
11.4 Inflow Performance Relationship (IPR) and Injectivity Index
11.5 Equation of State (EOS)
11.6 Vertical Flow Performance (VFP) Curves
11.7 Impact of the Well Deviation on CO₂ Injection
11.8 Implication of Bottom Hole Temperature (BHT) on Reservoir
11.9 Impact of CO₂ Phase Change
11.10 Injection Rates, Facility Design Constraints and Number of Wells Required
11.11 Wellhead Temperature Effect on VFP Curves
11.12 Effect of Impurities in CO₂ on VFP Curves
11.13 Concluding Remarks
Conversion Factors
References

Chapter 12: Effects of Acid Gas Reinjection on Enhanced Natural Gas Recovery and Carbon Dioxide Geological Storage: Investigation of the Right Bank of the Amu Darya River

12.1 Introduction
12.2 The Amu Darya Right Bank Gas Reservoirs in Turkmenistan
12.3 Model Development
12.4 Simulation Model
12.5 Results and Discussion
12.6 Conclusions
12.7 Acknowledgments
References

Index

End User License Agreement

List of Illustrations

Chapter 1

Figure 1.1 Experimental and calculated enthalpies at 10 °C using BWR (Lee & Mather, 1972).
Figure 1.9 Experimental and calculated enthalpies at 40 °C using BWR (Lee & Mather, 1970).
Figure 1.10 Experimental and calculated enthalpies at 10 °C using LK (Lee & Mather, 1972).
Figure 1.18 Experimental and calculated enthalpies at 40 °C using LK (Lee & Mather, 1970).
Figure 1.19 Experimental and calculated enthalpies at 10 °C using SRK (Lee & Mather, 1972).
Figure 1.27 Experimental and calculated enthalpies at 40 °C using SRK (Lee & Mather, 1970).
Figure 1.28 Experimental and calculated enthalpies at 10 °C using PR (Lee & Mather, 1972).
Figure 1.35 Experimental and calculated enthalpies at 80 °C using PR (Lee & Mather, 1972).
Figure 1.36 Experimental and calculated enthalpies at 40 °C using PR (Lee & Mather, 1970).
Figure 1.37 Experimental and calculated enthalpies at 10 °C using AQUAlibrium (Lee & Mather, 1972).
Figure 1.44 Experimental and calculated enthalpies at 80 °C using AQUAlibrium (Lee & Mather, 1972).
Figure 1.45 Experimental and calculated enthalpies at 40 °C using AQUAlibrium (Lee & Mather, 1970).

Chapter 2

Figure 2.1 Experimental and calculated enthalpies at 293.15 K using Lee-Kesler (Barry et al., 1982).
Figure 2.3 Experimental and calculated enthalpies at 313.15 K using Lee-Kesler (Barry et al., 1982).
Figure 2.4 Experimental and calculated enthalpies at 293.15 K using Benedict-Webb-Rubin (Barry et al., 1982).
Figure 2.5 Experimental and calculated enthalpies at 305.15 K using Benedict-Webb-Rubin (Barry et al., 1982).
Figure 2.6 Experimental and calculated enthalpies at 313.15 K using Benedict-Webb-Rubin (Barry et al., 1982).
Figure 2.7 Experimental and calculated enthalpies at 293.15 K using Soave-Redlich-Kwong (Barry et al., 1982).
Figure 2.9 Experimental and calculated enthalpies at 313.15 K using Soave-Redlich-Kwong (Barry et al., 1982).
Figure 2.10 Experimental and calculated enthalpies at 293.15 K using Redlich-Kwong (Barry et al., 1982).
Figure 2.12 Experimental and calculated enthalpies at 313.15 K using Redlich-Kwong (Barry et al., 1982).
Figure 2.13 Experimental and calculated enthalpies at 293.15 K using Peng-Robinson (Barry et al., 1982).
Figure 2.15 Experimental and calculated enthalpies at 313.15 K using Peng-Robinson (Barry et al., 1982).
Figure 2.18 Experimental and calculated enthalpies at 313.15 K using AQUAlibrium (Barry et al., 1982).
Figure 2.19 Effect of mole fraction of methane on the error in excess enthalpy prediction for Lee-Kelser at 293.15 K, 305.15 K, and 313.15 K.

Chapter 3

Figure 3.1 The p-x diagram for SO₂(2) + CO₂(1) at T = –10 and 60.06 °C. o, Lachet et al. [3]; •, Caubet et al. [5]; —, estimated binary mixing parameters combined with high-accuracy equations-of-state —, optimized binary mixing parameters from this work combined with high accuracy reduced Helmholtz EOS.
Figure 3.2 The apparent molar volume for CS₂(3) dissolved in dense phase CO₂(1) investigated for p ≤ 35MPa, (o), denotes experimental data from this work.

Chapter 4

Figure 4.1 Simplified schematic of the proposed sulfur recovery process.
Figure 4.2 Schematic of in-house built sulfur solubility measurement apparatus.
Figure 4.3 Sulfur dew-point based on the Mesmer CO₂ model.

Chapter 5

Figure 5.1 Schematic of the gravimetric microbalance.
Figure 5.2 Experimental density of pure ionic liquids.
Figure 5.3 CO₂ solubility in seven promising ionic liquids at temperature of 313.15 K [17, 18].
Figure 5.4 CO₂ solubility in seven promising ionic liquids at 323.15 K [17, 18].
Figure 5.5 CO₂ solubility in seven promising ionic liquids studied in this work at 333.15 K [17, 18].
Figure 5.6 Comparison of solubility in four ionic liquids with the same anion to illustrate the effect of the cation at 313 K.
Figure 5.7 Comparison of CO₂ solubility in [TDC] and [bmim] cations with same anion at 313 K [18, 21].
Figure 5.8 Comparison of CO₂ solubility at 60 °C with different cations paired with [TF2N] anion at 333.15 K and about 12 to 14.97 bar.
Figure 5.9 Comparison of the reported solubility data of CO₂ in the seven ionic liquids at 313.15 K.

Chapter 6

Figure 6.1 PFD of the amine process with regeneration.
Figure 6.2 PFD of the Vitrisol^® process with regeneration for Case 1.
Figure 6.3a PFD of the Vitrisol^® process with regeneration for Case 2 (H₂S removal section).
Figure 6.3b PFD of the CO₂ removal process for Case 2.
Figure 6.4 H₂S content of the gas exiting the stripper as a function of the H₂S concentration in the feed gas.
Figure 6.5 H₂S content of gas entering the amine absorber (feed) and of gas exiting the amine stripper (out) as a function of packing height in the Vitrisol^® absorber.

Chapter 7

Figure 7.1 Schematic representation of the CO₂ separation process [3]; (a) classical alkanolamine based absorbents; (b) demixing solvents.
Figure 7.2 Overall experimental setup of liquid-liquid equilibrium cells for solutions containing dissolved gas.
Figure 7.3 Phase diagram, temperature versus mole fraction, for ternary mixtures of (a), {CO₂ –NMPD – H₂O} and (b), {CO₂ –2MPD – H₂O}, at constant loading charges: opened circle, α = 0 [10, 11] and filled circle, α = 0.2. Solid lines are smooth fitting lines.
Figure 7.4 LLE of the ternary systems: □, {NMPD – H₂O – TEG} and ∇, {2MPD – H₂O – TEG}.
Figure 7.5 Phase diagram, temperature versus loading charge, for quaternary mixtures of {CO₂ – NMPD – TEG – H₂O}: •, {CO₂ – NMPD (20) – TEG (0) – H₂O (80)}; □: {CO₂ – NMPD (20) – TEG (20) – H₂O (60)} and ∇, {CO₂ – NMPD (20) – TEG (30) – H₂O (50)}. Numbers in brackets denote the weight percent of each mixture component. Dash lines are smooth fitting lines.
Figure 7.6 Densities of the ternary systems {NMPD (w %) – TEG (w %) – H₂O (w%)}. O, {NMPD (20) – TEG (0) – H₂O (80)}; ∇, {NMPD (20) – TEG (20) – H₂O (60)}; □ {NMPD (20) – TEG (30) – H₂O (50)}; Δ, {NMPD (20) – TEG (80) – H₂O (0)}. Numbers in brackets denote the weight percent of each mixture component. Dash lines are smooth fitting.
Figure 7.7 Specific Heat Capacities as a function of temperature for the ternary systems {NMPD (w %) – TEG (w %) – H₂O (w %)}. O, {NMPD (20) – TEG (0) – H₂O (80)}; ∇, {NMPD (20) – TEG (20) – H₂O (60)}; □, {NMPD (20) – TEG (30) – H₂O (50)}; Δ, {NMPD (20) – TEG (80) – H₂O (0)}. Numbers in brackets denote the weight percent of each mixture component. Dash lines are smooth fitting lines.
Figure 7.8 Equilibrium pressure as a function of CO₂ loading charge for the system {NMPD (14) – TEG (17) – H₂O (69)} at 313 K. Numbers in brackets denote the weight percent of each mixture component.
Figure 7.9 Enthalpy of solution (–Δ_solH) versus CO₂ loading charge for an aqueous solution {NMPD (20) – TEG (20) – H₂O (60)}at T = 313 K and p= 1.0 MPa. (a) Δ_solH/ (kJ.mol^–1 of CO₂), straight lines show the average values for the enthalpies of solution at low loadings (α < 0.5); (b) Δ_so1nH/(kJ.mol^–1 of NMPD).

Chapter 8

Figure 8.1 CO₂ capture by amine scrubbing. (Reproduced with permission from the PhD thesis of Mickael Simond [19].)
Figure 8.2 Primary alkanolamines based on the structure N–C–C–O. (Reproduced with permission from the PhD thesis of Micka’el Simond [19].

Chapter 9

Figure 9.1 Generic Amine Plant.
Figure 9.2 Amines Contaminated with Varying Degrees of Hydrocarbon.
Figure 9.3 Free Hydrocarbons in Amine.
Figure 9.4 Soluble Hydrocarbons Concentrated in Reflux Water.
Figure 9.5 Emulsified Hydrocarbons in Amine.
Figure 9.6 Foaming Tendency of Hydrocarbon Contaminated Amine.
Figure 9.7 Black shoe polish on rich amine filters.
Figure 9.8 Leaking exchanger gaskets.
Figure 9.9 Typical Inlet Gas Separator.
Figure 9.10 Regen skimmings (left), Regen bottoms (right).
Figure 9.11 Reflux water with skimmable hydrocarbon.
Figure 9.12 Amine plant with hydrocarbon stripping column.
Figure 9.13 Amine system with hot flash vessel.

Chapter 10

Figure 10.1 Schematics of a reservoir undergoing CO₂ flooding
Figure 10.3 Flowchart for calculating the solutions to the pressure diffusion and mass transfer models.
Figure 10.4 Type curves of the transient pressure model for CO₂ miscible flooding considering mass transfer process (Ra = 10 m, Re = 150 m, Q = 0.01 m³/s, C_t = 1e-8, k = 10 mD, μ = 4.7 cP).
Figure 10.5 (a) CO₂ Concentration and (b) Oil Viscosity distributions across the miscible zone (R_a = 10 m, R_e = 150 m, Q = 0.01 m³/s, C_t = 10^–8 Pa^–1, k = 10 mD, μ = 4.7 cP).
Figure 10.6 The effect of mass transfer process on dimensionless pressure and dimensionless pressure derivative.
Figure 10.7 The effect of CO₂ bank size on dimensionless pressure and pressure derivative.
Figure 10.8 The effect of reservoir outer boundary size on the dimensionless pressure and pressure derivative curves.

Chapter 11

Figure 11.1 Phase envelope of pure CO₂ with delivery conditions and the conditions on which the sensitivities were performed.
Figure 11.2 Comparison of the reservoir simulation data and the calculated IPR using Prosper for the vertical well and ERD well.
Figure 11.3 Comparison of phase diagrams of Peng-Robinson and Span & Wagner equations.
Figure 11.4 Comparison of errors and densities calculated from PR, PR with volume shift and Span & Wagner equations for WHP pressure of 110 Bara for pure CO₂.
Figure 11.5 Comparison of viscosities and errors associated for pure CO₂ for WHP pressure of 110 Bara.
Figure 11.6 Density of a mixture: CO₂ (91%) and N₂ (9%) showing experimental data (Carroll and Roberts, 2013) and predictions from PR EOS of PROSPER. The continuous lines are the calculated values.
Figure 11.7 Phase diagram of the compositions used in well engineering analysis for pure of CO₂ and CO₂ with 5% contaminants.
Figure 11.8 The VFP curves for the vertical well showing the gas rate of 6.5 MSm³/d (4.3 Mtpa) at WHP of 110 Bara, WHT of 35 degrees C and reservoir pressure of 138 Bara.
Figure 11.9 The VFP curves for ERD well showing the designed rate of 3 Mpta (4.5 MSm³/d) and full potential of 3.37 Mtpa (5.45 MSm³/d) at WHP of 110 Bara, WHT of 35 degrees C and reservoir pressure of 128 Bara.
Figure 11.10 Comparison of gas rate for the vertical and ERD wells for WHT temperature of 11 degrees C, 30 degrees C and 35 degrees C and for WHP of 110 Bara.
Figure 11.11 Pressure losses in the vertical well and ERD well at an injection temperature of 11 degrees C.
Figure 11.12 Change in properties along the wellbore in vertical and ERD wells at an injection temperature of 35 degrees C and WHP of 110 Bara.
Figure 11.13 Change in pressure and temperature along the wellbore with reference to phase envelope.
Figure 11.14 Effect of well deviation on VFP curves for an injection temperature of 35 degrees C and WHP of 110 Bara.
Figure 11.15 BHT as function of gas rates for different temperatures for vertical and ERD wells.
Figure 11.16 Effect of injection temperature on VFP curves for the Vertical and ERD wells.
Figure 11.17 Effect of impurities on wellhead pressures and injection rates.

Chapter 12

Figure 12.1 Synthetic histogram of the Callovian-Oxfordian of the Sam53-1 well in this study [28, 29].
Figure 12.2 The relative permeability relationship diagram for the Callovian-Oxfordian in the study area [21].
Figure 12.3 Time-dependent diagram of reservoir pressure and gas saturation.
Figure 12.4 The geological model in the study area (a: 3D view; b: sectional view).
Figure 12.5 Time-dependent reservoir pressure diagram.
Figure 12.6 Time-dependent diagram of the total amount of gas sequestration.
Figure 12.7 (a) Time-dependent diagram of the amounts of CO₂ sequestration and H₂S sequestration, (b) zooming into (a) by shortening the Y-axis.
Figure 12.8 (a) Time-dependent diagram for the daily production, (b) zooming into (a) by shortening the Y-axis.
Figure 12.9 Time-dependent diagram of the acid gas production of the production well over 15~18 years in model 7.
Figure 12.10 The CO₂ plume in the 18th year of model 7.
Figure 12.11 The H₂S plume in the 18th year of model 7.
Figure 12.12 Time-dependent diagram of the acid gas production of the production well over 15~18 years in model 9.
Figure 12.13 The CO₂ plume in the 18th year of model 9.
Figure 12.14 The H₂S plume in the 18th year of model 9.
Figure 12.15 Time-varying diagram of recovery ratio of models 7 and 9.
Figure 12.16 (a) Time-dependent diagram of the recovery percentage of models 7 and 9, (b) zooming into (a) by shortening the Y-axis.

List of Tables

Chapter 1

Table 1.1 Summary of experimental data of enthalpy of carbon dioxide mixtures.
Table 1.2 Absolute average difference in excess enthalpies for methane and nitrogen mixtures using the different models.
Table 1.3 Absolute average error in excess enthalpies for methane and nitrogen mixtures using the different models.
Table 1.4 Absolute average difference in enthalpy departure for methane mixtures using the different models.
Table 1.5 Absolute average error in enthalpy departure for methane mixtures using the different models.

Chapter 2

Table 2.1 AAD, AAE, maximum difference and maximum error using the six different thermodynamic models for the hydrogen sulfide-methane mixture

Chapter 3

Table 3.1 Chemical name, purities, source and analysis method.
Table 3.2 Impurity concentrations in CO₂ and the conditions studied.
Table 3.3 The Helmholtz EOS model used to describe the pure component fluid.

Chapter 5

Table 5.1 Characteristics of ionic liquids used in this work.
Table 5.2 Temperature-dependent density correlations for the studied ionic liquids.
Table 5.3 Critical properties of ionic liquids.
Table 5.4 Henry’s law constants and enthalpies and entropies of absorption for CO₂ in the studied ionic liquids [17, 18].
Table 5.5 Standard deviations PR-EoS for the ionic liquids + CO₂ system.

Chapter 6

Table 6.1 Case Specifications.
Table 6.2 Case specifications.
Table 6.3 Utility consumptions of cases 1 and 2 of the amine process.
Table 6.4 Utility consumptions of Cases 1 and 2 of the Vitrisol^® process.
Table 6.5a Absorber and stripper dimensions.
Table 6.5b Utility Consumptions of Cases 2b and 3 of the Amine Process.
Table 6.6 Utility consumptions of cases 1 and 2 of the amine process.
Table 6.7 Utility consumptions of cases 1 and 2 of the Amine process.

Chapter 7

Table 7.1 Suppliers, CAS numbers and stated purities (mass fraction w) of chemicals used in this study.
Table 7.2 Characteristics of the visual cells used for cloud point measurements.
Table 7.3 Composition of the ternary systems {NMPD – H₂O – TEG} and temperature range investigated in the density study.

Chapter 9

Table 9.1 Hydrocarbon reduction case study.

Chapter 10

Table 10.1 Physical properties and operating conditions of the base case.

Chapter 11

Table 11.1 Reservoir and completion data.
Table 11.2 Critical points of the cases considered.

Chapter 12

Table 12.1 Physical reservoir properties.
Table 12.2 The differences of the nine development models.

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Library of Congress Cataloging-in-Publication Data
ISBN 978-1-118-93866-9

Preface

The Sixth International Acid Gas Injection Symposium (AGIS VI) was held in Houston, Texas, in September 2016. As with previous Symposia, the focus of AGIS VI was the injection of acid gas (CO₂, H₂S, and mixtures of these components) for the purposes of disposal or for enhanced oil and/or gas recovery. This book contains select papers from the Symposium in Houston.

The capture of carbon dioxide from flue gas and its disposal into a subsurface geological formation remains a viable option for the clean use of hydrocarbon fuels. The related technology is acid gas injection. Here the H₂S and CO₂ are removed from raw natural gas. This volume contains papers directly related to these two topics ranging from the physical properties of the gas mixtures, evaluation of new and existing solvents, and subsurface engineering aspects of the process. Furthermore, contributors came from Canada, Europe, and China, as well as from the host country, the United States. And this is reflected in the papers in this volume.

On a very sad note, Marco Satyro passed away on September 8, 2016, just prior to the Symposium. Marco was a good friend of AGIS being an active member of the Technical Committee for many years. He contributed many papers and encouraged many others to participate. At the first AGIS he presented the paper “The Performance of State of the Art Industrial Thermodynamic Models for the Correlation and Prediction of Acid Gas Solubility in Water” and this paper appeared in the first volume of the Advances in Natural Gas Engineering. He also was the coauthor of several other contributions to the Series and they are listed below. This volume is dedicated to the memory of Dr. Satyro.

References – papers of M.A. Satyro from the Advances in Natural Gas Engineering series.

M.A. Satyro, and J. van der Lee, “The Performance of State of the Art Industrial Thermodynamic Models for the Correlation and Prediction of Acid Gas Solubility in Water”, pp. 21–34, Acid Gas Injection and Related Technologies, Y. Wu and J.J. Carroll (eds.), Scrivener Publishing (2011).

H. Motahhari, M.A. Satyro, and H.W. Yarranton, “Acid Gas Viscosity Modeling with the Expanded Fluid Viscosity Correlation”, pp. 41–52, Carbon Dioxide Sequestration and Related Technologies, (2011), Y. Wu, J.J. Carroll, and Z. Du (eds.), Scrivener Publishing (2011).

J. van der Lee, J.J. Carroll, and M.A. Satyro, “A Look at Solid CO₂ Formation in Several High CO₂ Concentration Depressuring Scenarios”, pp. 117–128, Sour Gas and Related Technologies, Y. Wu, J.J. Carroll, and W. Zhu (eds), Scrivener Publishing (2012).

M.A. Satyro, and J.J. Carroll, “Phase Equilibrium in the Systems Hydrogen Sulfide + Methanol and Carbon Dioxide + Methanol”, pp. 99–109, Gas Injection for Disposal and Enhanced Recovery, Y. Wu, J.J. Carroll, and Q. Li (eds.), Scrivener Publishing (2014).

A.R.J. Arendsen, G.F. Versteeg, J. van der Lee, R. Cota, and M.A. Satyro, “Comparison of the Design of CO₂-capture Processes using Equilibrium and Rate Based Models”, pp. 155–174, Gas Injection for Disposal and Enhanced Recovery, Y. Wu, J.J. Carroll, and Q. Li (eds.), Scrivener Publishing (2014).

M.A. Satyro and H.W. Yarranton, “A Simple Model for the Calculation of Electrolyte Mixture Viscosities”, pp. 95–104, Acid Gas Extraction for Disposal and Related Topics, Y. Wu, J.J. Carroll, and W. Zhu (eds.), Scrivener Publishing (2016).