BHURISA THITAKAMOL AND AMORNVADEE VEAWAB

1. CHARACTERIZATION OF FOAMING BEHAVIOR IN AMINE-BASED CO2 CAPTURE PLANTS Research Review Meeting January 10 – 11, 2008 University of Texas at Austin, Texas BHURISA THITAKAMOL AND AMORNVADEE VEAWAB Faculty of Engineering, University of Regina CANADA

2. 1 OUTLINE • Introduction • Objectives • Experiment • Results and discussions • Foam model • Conclusions • Future works • Acknowledgements

3. 5 INTRODUCTION Foaming problem in the CO2 absorption process One of the most severe operational problems causing extra expenditures • Occurring in both an absorber and a regenerator during plant start-up and operation • Causing many adverse impacts on the plant operation Impacts based on plant experiences • Excessive loss of alkanolamine solvents • Premature flooding • Reduction in plant throughput • Off-spec products • High alkanolamine carryover to downstream plants

4. 6 Current foaming knowledge in the CO2 absorption process for a coal-fired power plant is limited: • The application of the CO2 absorption process is relatively new for a coal-fired power plant. • No reports of plant experiences and research work has published. INTRODUCTION 9 Research on foaming problem: For the CO2 absorption process in gas treating services

5. 7 OBJECTIVES • To obtain comprehensive foaming information from bench-scale experiments under well-simulated environments. • To reveal the parametric effects as listed below on foaming • Gas flow rate • Solution volume • CO2 loading • Alkanolamine concentration • Solution temperature • Degradation product • Corrosion inhibitor • Alkanolamine type • To establish the foam model to predict a steady-state pneumatic foam height (H) from the physical properties and operating conditions

6. 8 EXPERIMENTS The pneumatic method modified from the standard ASTM D892 (ASTM, 1999) Recorded foam volume

7. 9 o (average steady foam volume) • The foaminess coefficient () (Bikerman, 1973) ; o = Average foam volume (cm3) G = Gas flow rate (cm3/min) EXPERIMENTS • Recorded data: Foam volume (cm3) vs. Time (min) for each minute during the 25-minute blowing time Raw data

8. 10 Working flow rate at 94 cm3/min RESULTS AND DISCUSSIONS EFFECT OF GAS FLOW RATE ,  • At 20 – 80 cm3/min, N2 flow rate ,  CONSTANT • At 80 – 110 cm3/min, N2 flow rate MEA MEA (Test condition: 2.0 & 5.0 kmol/m3 MEA, 400 cm3 solution volume, 0.40 mol/mol CO2 loading and 40oC)

9. 11 RESULTS AND DISCUSSIONS EFFECT OF SOLUTION VOLUME ,  • At 200 – 400 cm3, solution volume ,  CONSTANT • At 400 – 700 cm3, solution volume Working Volume at 400 cm3 (Test condition: 2.0 kmol/m3 MEA, 94 cm3/min N2, 0.40 mol/mol CO2 loading and 40oC)

10. 12 RESULTS AND DISCUSSIONS EFFECT OF MONOETHANOLAMINE (MEA) CONCENTRATION • MEA concentration ,  initially and then Surface tension of CO2-unloaded aqueous MEA solution replotted from experimental data [Vázquez et al., 1997] Increased bulk liquid viscosity Decreased surface tension (Test condition: MEA, 94 cm3/min N2, 400 cm3 solution volume, absorber top: 0.20 mol/mol CO2 loading/ 40oC & absorber bottom: 0.40 mol/mol CO2 loading/ 60oC) Predicted viscosity of CO2-loaded aqueous MEA solutions from correlation [Weiland et al., 1998]

11. 13 RESULTS AND DISCUSSIONS EFFECT OF CO2 LOADING • CO2 loading ,  initially and then Surface tension of CO2-loaded aqueous MEA solution measured by Spinning Drop Interfacial Tensiometer Model 510 Increased bulk liquid viscosity Decreased surface tension (Test condition: 5.0 kmol/m3 MEA, 94 cm3/min N2, 400 cm3 solution volume and 40, 60 and 90oC) Predicted viscosity of 5.0 kmol/m3 MEA solution from correlation [Weiland et al., 1998]

12. 14 RESULTS AND DISCUSSIONS EFFECT OF SOLUTION TEMPERATURE • Solution temperature ,  Reduced bulk viscosity 0.20 mol CO2/mol MEA 0.40 mol CO2/mol MEA Decreasing  Predicted viscosity of 5.0 kmol/m3 MEA solution from correlation [Weiland et al., 1998] (Test condition: 5.0 kmol/m3 MEA, 94 cm3/min N2, 400 cm3 solution volume and 0.20 & 0.40 mol/mol CO2 loading)

13. 15 RESULTS AND DISCUSSIONS EFFECT OF DEGRADATION PRODUCT • Most degradation products added into aqueous MEA solution induce foam. (Test condition: 10,000 ppm of degradation product, 5.0 kmol/m3 MEA, 94 cm3/min N2, 400 cm3 solution volume, 0.40 mol/mol CO2 loading and 60oC)

14. 16 RESULTS AND DISCUSSIONS EFFECT OF CORROSION INHIBITOR • Corrosion inhibitors added into aqueous MEA solution enhance . Surface tension of 5.0 kmol/m3 MEA solutions containing no CO2 loading at 25oC with/without 1000 ppm corrosion inhibitor (measured by KrÜss Tensiometer K100 using the Wihelmy plate’s principle) (Test condition: 1,000 ppm of corrosion inhibitor, 5.0 kmol/m3 MEA, 94 cm3/min N2, 400 cm3 solution volume, 0.40 mol/mol CO2 loading and 60oC)

15. 17 RESULTS AND DISCUSSIONS EFFECT OF ALKANOLAMINE TYPE • Foam formation in MEA and MDEA but not in DEA and AMP solutions • Only small amount of foam in AMP+MEA solution with the mixing ratio of 1:2 mol/mol Viscosity of CO2-unloaded aqueous alkanolamine solution at 60o replotted from experimental data (Test condition: 4.0 kmol/m3total alkanolamine conc., 94 cm3/min N2, 400 cm3 solution volume, 0.40 mol/mol CO2 loading, 60oC and mixing ratio of blended solution = 1:1, 2:1 and 1:2 (mole:mole)) Predicted viscosity of the CO2-unloaded aqueous blended alkanolamine solution (4.0 kmol/m3 total alkanolamine conc. and 60oC) from Grunberg and Nissan’s equation (Mandal et al., 2003))

16. 18 FOAM MODEL: LITERATURE

17. FOAM MODEL: DEVELOPMENT 19 Pilon et al (2001)

18. 20 FOAM MODEL: RESULTS Foaming height equation INSIGNIFICANT where Pout = Pdispersion + Pfoam + P* when when when

19. 21 FOAM MODEL: RESULTS

20. 22 CONCLUSION • Solution volumeaffects when it is small. Increasing the solution volume to a certain quantity • results in a constant foam volume or . • An increase in gas flow ratedecreases . The gas flow rate can lead to a constant when • increases to a certain value. • Ranges of solution volume and gas flow ratethat lead to a constant  were found for the CO2- • aqueous alkanolamines. These ranges enable the generation of foam data that do not depend • on solution volume, gas flow rate, pore size of gas disperser, and dimension of test cell. • Variations in MEA concentration, CO2 loading and solution temperatureaffect . • An increase in temperature decreases . • increases and then declines with increasing MEA concentration and CO2 loading. • Most degradation products and corrosion inhibitorsenhance . • MEA, MDEA and AMP + MEA (1:2 mixing mole ratio)generate apparent foams • FOAM MODEL is established to predict the steady-state pneumatic foam height from the • physical properties and operating conditions and also to identify the important dimensionless • numbers for a scaling-up hydrodynamic experiment. 31

21. 23 FUTURE WORK FOAM MODEL • Sensitivity analysis of input parameters on the predicted foam height. • Model improvement by incorporating the minimum superficial gas velocity predicted • based on the one-dimensional drift-flux model (Pilon and Viskanta, 2004) HYDRODYNAMIC • Study the foaming behavior occurred in the packed absorber during absorption • process based on dimensionless numbers in terms of the foaming tendency and the • foam stability by measuring  and foam half-life, respectively. • Investigate the effect of foaming on the hydrodynamic parameter s (e.g., pressure • drop, liquid holdup and flooding point) of the packed CO2 absorption column based • on dimensionless numbers. FOAMING CHART

22. ACKNOWLEDGEMENT 24 • Faculty of Graduate Studies and Research (FGSR), University of Regina • Faculty of Engineering, University of Regina • The Natural Sciences and Engineering Research Council (NSERC)