1. Jerimiah C. Forsythe April 23, 2012 Amine-Functionalized Ceramic Materials for Enhanced Gas Absorption

2. Oil 1% Base Case 2009 Coal 45% Other 0% Natural Gas 23% Renewable 11% Nuclear 20% Nuclear 18% Renewable 14% Other 0% Coal 44% Natural Gas 23% Reference Case 2030 Oil 1% DOE/NETL CO 2 Capture Update, May 2011 http://www.eia.gov/tools/faqshttp://www.eia.gov/tools/faqs, Accessed April 2012 1 Introduction: The CO 2 Problem Power generation by fuel type in the United States: Coal 34% Oil 43% Natural Gas 23% 2009 CO 2 emissions by fuel type: Overall power requirements for the US: 313 GW of power produced 600 coal-fired power plants in the US ~ 850 million tons of coal burned annually ~ 4 million L of CO 2 produced annually

3. Introduction: The CO 2 Problem 2 http://www.eia.gov/tools/faqshttp://www.eia.gov/tools/faqs, Accessed April 2012 http://www.esrl.noaa.gov/gmd/ccgg/trends/, Accessed April 2012ccgg/trends/, Accessed April 2012 280 ppm CO 2 from pre-industrial ages (1832) 1.9 ppm CO 2 average increase per year Projected CO 2 for 2030: 420 ppm Clearly, we will be producing CO 2 for the long-term to meet our energy demands We need systems in place to assist in addressing the overall CO 2 concentrations in the immediate future

4. Flue Gas Composition and Regulations 3 Component N2N2 70% CO 2 13-16 % H2OH2O5-7 % O2O2 3-4 % HCl10-100 ppm SO 2 100-1200 ppm SO 3 1-40 ppm NO x 300-1000 ppm Hg1 ppb Fly Ash10% Lu, D. Y.; Granatstein, D. L.; Rose, D. J. Ind. Eng. Chem. Res. 2004, 43, 5400-5404 Granite, E. J., personal communication Already removed before entering exhaust stack EPA issued ruling for removal in 4 years 25 years for EPA to regulate Hg emissions from power plants, expected to increase price by 0.1 ¢ per KWh EPA just issued regulations for CO 2 emissions, final announcements on December 2012 Expected to double overall cost of electricity with current carbon capture technology

5. Outstanding issue of cost and corrosive nature of amines Current CO 2 Removal Systems 4 Post-combustion capture systems with aqueous solvent absorption http://www.co2crc.com.au/aboutccs/cap_absorption.htmlhttp://www.co2crc.com.au/aboutccs/cap_absorption.html, Accessed April 2012 Comment solvents: amines, carbonates, or bicarbonates Monoethanolamine (MEA) Diglycolamine (DGA)Diethanolamine (DEA) pKa = 9.6pKa = 9.0pKa = 8.6 High heat (> 100 °C) required for unloading Corrosive at 0.4 mol CO 2 per 1 mol amine Rapid reaction rate with CO 2 Low reaction rates Corrosive at 0.4 mol CO 2 per 1 mol amine Low volatility Rapid reaction rate with CO 2 Corrosive at 0.4 mol CO 2 per 1 mol amine Volatile, loss in absorber overhead Current amine standard: Fluor’s Econamine using MEA

6. Post-Combustion CO 2 Capture Systems DOE/NETL CO 2 Capture Update, May 2011 http://www.mhi.co.jp/en/products/detail/km-cdr_process.htmlhttp://www.mhi.co.jp/en/products/detail/km-cdr_process.html, Accessed April 2012 http://www.eia.gov/tools/faqs, Accessed April 2012 PerformerLocation Capture Technology Capture Rate Ton/yr Start Date NRG Energy Thompsons, TX Amine550,0002015 American Electric Power New Haven, WV Chilled Ammonia 1,650,0002015 5 Mitsubishi Heavy Industries has been operating several carbon capture facilities on natural gas using Kansai Mitsubishi Carbon Dioxide Recovery (KM-CDR) technology with KS-1™ Test operations on 25 MW coal-fired plant in Al since 2011 Additional efforts in pre-combustion capture and oxy-combustion capture, coming on-line between 2014-2016

7. CO 2 Absorption in Aqueous Systems 6 CO 2 + H 2 O Carbonic acid formation and equilibria H 2 CO 3 pKa at 25 °C = 6.352 Gibbons, B. H. J. Biol. Chem. 1963, 238, 3502 McCann, N. J. Phys. Chem. A 2009, 113, 5022-5029 or above pH = 7 and 25 °C CO 2 + HO – HCO 3 – pKa at 25 °C = 10.329 So, overall: H 2 CO 3 + B HCO 3 – + HB pK H 2 CO 3 at 25 °C = 3.7 Predominate species in solution will be HCO 3 – at any pH ≥ 6 H 2 CO 3 + RNH 2 Two feasible pathways for amine with carbonic acid: RNHCO 2 H + H 2 O HCO 3 – + RNH 2 RNHCO 2 – + H 2 O Or...we can have direct interactions with CO 2 (aq)

8. CO 2 Absorption in Aqueous Systems 7 Three proposed interactions with amines: 1. Carbamate Intermediate 1 2. Zwitterion Intermediate 2 3. Single-Step 3 Arstad, B. J. Phys. Chem. A 2007, 111, 1222-1228 McCann, N. J. Phys. Chem. A 2009, 113, 5022-5029 CO 2 + R 1 R 2 NHR 1 R 2 NHCOOH R 1 R 2 NHCOOH + B R 1 R 2 NHCOO – + BH + CO 2 + R 1 R 2 NHR 1 R 2 NH + CO 2 – R 1 R 2 NH + CO 2 – + BR 1 R 2 NCO 2 – + BH + 2nd order reaction Carbamic acid formation rate determing Rapid proton transfer assumed Assumed rapid deprotonation Mechanistically favored from kinetic data Termolecular reaction for carbamate formation B = base acting as proton acceptor/donor (water or amine) Reaction rates are very rapid with unstable intermediates Difficult to determine exact reaction mechanism Carbamate product stable and easily detected

9. Project Aims and Goals Primary Goal: To functionalize alumina foams with amines to enhance the absorption of CO 2 by solution based-amines 8 Specific Aim: What effect does calcinated α-alumina (Al 2 O 3 ) have on our test system? Specific Aim: What effect does APTES functionalized calcinated α-alumina (Al 2 O 3 ) have on our test system? Ultimate Goal: To insert functionalized alumina foams into the absorber for enhanced CO 2 removal

10. Project Aims and Goals 9 Tower packing to increase gas-liquid surface area and gas absorption Current use of either trays or packing material (e.g. Raschig Rings) Type and design depends on application and solution viscosity, operating temperature, and pressure conditions However, if we can select a material that can accept functionalization by chemical groups, we can enhance the surface properties and make the absorption process more effective Alumina foam (Al 2 O 3 )

11. 50-25 mL Amine/Water solution Gas dispersion tube Gas collection tube Mass Flow Controller #1 13% CO 2 /N 2 Tank “simulated flue gas” Line Purge N 2 Tank N 2 Purge Purge Rotameter Purge IR Detector N 2 Dilution 0.2 L min -1 0.8 L min -1 0.2 L min -1 1.0 L min -1 Mass Flow Controller #2 Instrumental Set-up 10

12. 30% (w/w) DGA in water Water “ blank ” Bubbler System Trials 25 mL of 30% (w/w) DGA in water with 220 mL min -1 “simulated flue gas” 11

13. Bubbler System Trials 50 mL of 30% (w/w) DGA in water with 220 mL min -1 “simulated flue gas” 30% (w/w) DGA in water + 5 g alumina +10 g alumina Alumina itself has an effect on the total loading of CO 2 Competition with amines for acid/base chemistry α-alumina (Al 2 O 3 ), calcinated, 125-350 mesh pKa measured to be 5.5 12

14. (3- aminopropyl)triethoxysilane (APTES) 3% H 2 O in EtOH (v/v) pH = 5.0, 5 min, RT Hydrolysis + H-bond formation Silanol condensation H-bond formation with surface -OH groups 2 hour contact time with 1.0 g of Al 2 O 3 powder Condensation - H 2 O EtOH wash, cure at 110 °C for 30 min. 13 Surface Functionalization with APTES

15. TGA Analysis CO 2 Loss: 0.04 mg CO 2 Loss: 0.02 mg APTES Loss: 0.02 mg APTES Loss: 0.04 mg Functionalized Alumina Post-bubbler Alumina Ramp rate: 10 °C min -1 from 250 to 650 °C under Ar Amine and water catalysis removing APTES from surface 14

16. 30% (w/w) DGA in water + 1 g APTES Alumina + 1 g alumina APTES Functionalized Alumina 15

17. Conclusions 16 Acidic alumina lowers the CO2 loading capacity of the DGA solutions due to acid/base equilibria competition APTES functionalization of alumina is ineffective for generating significant surface coverages APTES is easily removed from alumina surface by catalysis via water and amines Increase surface coverage of surface-bound amines while minimizing bond catalysis by surrounding water/amine solution Future Work Demonstrate effectiveness of surface amines in CO 2 capture when coupled with circulating amine solutions

18. Acknowledgments 17 Funding: US Department of Energy (DOE) Schlumberger Prof. George Hirasaki Prof. Michael Wong Prof. Ed Billups Sumedh Warudkar