Projected Add-On Control Options for CO2 Reductions at a Coal-Fired Generating Unit

1. Some Projected Add-On Control Options for CO2 Reductions at a Coal-Fired Generating Unit Kevin Johnson URS Corporation Raleigh-Durham, North Carolina NC DENR/DAQ CO2 Workshop April 21, 2004

2. Presentation Overview • CO2 capture issues • CO2 capture technologies’ overview • Conventional amine absorption • Advanced amine absorption • Gas separation membranes • Temperature swing adsorption • Regenerable CO2 sorbents • Development status and projected costs • Potential next steps

3. Coal-Fired CO2 Capture Issues (1) • Chemical absorption using amines is only technique used commercially to date to capture CO2 from flue gas. • Amine degradation via oxidation and reaction with SO2 and other flue gas constituents. • Lower amine concentration results in larger equipment, higher solvent circulation rates, and increased energy requirements for CO2 regeneration from the rich amine stream. • Only a few small plants (<<1000 tpd CO2 removal, or about <50-100 MW) in commercial operation.

4. Coal-Fired CO2 Capture Issues (2) • Conventional MEA absorption/stripping estimated to increase electricity costs by over 50%, and consume ~30% of plant’s output.* • Global Climate Change Initiative goals are 90% CO2 capture and <10% increase in cost of energy services (net of any value-added benefits, e.g., EOR, CO2 credit trading, etc.) • DOE Carbon Sequestration R&D program goal is to achieve carbon capture/geologic sequestration at an incremental cost of $10/ton CO2 emissions avoided. *National Coal Council, “R&D Needs and Deployment Issues for Coal-Related GHG Management”, May 2003. *EPRI, “Evaluation of Innovative Fossil Fuel Power Plants with CO2 Removal”, December 2000.

5. Advanced Amine Absorption (1) • Proprietary oxidation inhibitors, other additives, membranes, custom solvent formulations/amines, contactor designs. • Various commercial vendors pursuing process improvements: • Fluor • Praxair • Kvaerner • MHI • ABB Lummus Crest • Current cost range ~$30-40/ton CO2. • R&D development goal ~$20/ton CO2

6. Advanced Amine Absorption (2) • Advanced amine absorption processes hold promise for intermediate-term CO2 capture, with incremental (i.e., not breakthrough) reductions in cost. • Critical need for large-scale pilot plant demonstration(s) on SO2-/NOx-laden coal-fired flue gas. • DOE Regional Sequestration Partnership program planning Phase II pilot validation tests in the 2007-2010 time period.

7. Gas Separation Membranes • Gas-liquid or catalyzed liquid membrane separators/reactors. • Potentially used in conjunction with unique physical solvents. • Several process vendors actively involved in technology development: • Kvaerner • Carbozyme (catalyzed enzyme) • Electrocore (natural enzyme)

8. Temperature Swing Adsorption • Use of custom-designed sorbents that adsorb CO2 at lower temperature, and then desorb CO2 at higher temperature. • Zeolites, synthetic zeolites, activated carbon, etc. • Adsorption Research, Inc./DOE.

9. Regenerable Sorbents • Absorption step of CO2 removal, followed by sorbent regeneration step where CO2 is off-gassed. • Alkali- and alkaline-earth metals (e.g., K2CO3 and CaO) deposited on a substrate support are focus of research experiments. • Advantages over amine-based liquid systems include no large quantities of water involved in capture step, and additional energy savings due to lower gas/solid pressure drop. • Research Triangle Institute/DOE.

10. Development Status and Projected Costs • Except for amine absorption technologies, all CO2 capture technologies still at the laboratory, bench-scale development level. • Based on lab results, several vendors (Carbozyme, ARI) “claiming” projected full scale cost performances on the order of $5-15/ton CO2. • These, and other, potential “breakthrough” CO2 capture technologies warrant further investigation and research investments.

11. Potential Next Steps (1) • NC program could proactively participate in DOE Regional Sequestration Partnership (SE). • Characterize regional sources and sinks, environmental and monitoring/verification requirements, and life cycle impacts. • Pilot validation tests not until 2007-2010. • Based on current public commitments, more economic CO2 capture technology will not be commercially available for coal plants before the end of the decade.

12. Potential Next Steps (2) • NC could provide cost share/co-funding to CO2 capture technology pilot field demonstration and testing. • Attempt to address conflicting motivations of voluntary GHG program elements, GHG registry program development needs, and potential CO2 follow-up response to CSA.