1. Optimization of IGCC power plant Samantha Chase David Granum Ming Chen Tang Irena Vankova Sung Yoon Five Gasifiers

2. Project Definition  Improvements to existing Integrated Gasification Combined Cycle (IGCC)  Optimize an air separation unit (ASU) Decrease energy consumption in the current simulation Develop air separation alternatives  Minimize water usage in the overall process Decrease water requirements in the current simulation Suggest cooling alternatives

3. Integrated Gasification Combined Cycle COAL OXYGEN SYNGAS GASIFICATION Ignition ELECTRICITY AIR SEPARATION AIR NITROGEN POWER GENERATION

4. Outline  Air separation unit optimization  Optimization of existing unit  Cryogenic air separation alternatives  Non-cryogenic air separation alternatives  Water usage minimization  Water usage analysis  Process cooling alternatives  Economics  ASU comparison  Water versus air cooling  Environmental permitting  Future work

5. Optimization of the Air Separation Unit

6. 12.0 MW O2 Compression Inlet Air Compression 0.85 atm 9.19 atm N2 Product Stream -180 °C 4.42 atm N2 Compression 4.42 atm -176 °C 2.18 atm -188 °C 2.18 atm 60 MW 12.3 MW 38.5 MW 16.5 MW O2 Product Stream -167 °C 4.42 atm

7. AIR 12.04 atm 430 °C N2 20.07 atm 167 °C SYNGAS 19.73 atm 40 °C 12.04 atm 1310 °C 5.06 atm 1052 °C 215.2 MW 2.13 atm 761 °C 192.84MW 0.90 atm 579 °C 159.4 MW 5.06 atm 1139 °C 207.7 MW 2.13 atm 906 °C 173.7 MW 0.90 atm 561 °C 157 MW 259 MW N2 2.13 atm 37.5 °C 219 MW 12.04 atm 1410 °C

8. Overall Results  ASU electricity improvements:  Original ASU electricity usage: -85.0 MW  New ASU electricity usage: -54.6 MW  30.4 MW Improvement  Gas turbine improvements:  Original electricity production: 309 MW  New electricity production: 319 MW  10.0 MW improvement  Overall: 40.4 MW Improvement  407 MW 447.4 MW sent to grid

9. Alternative Energy Source  Wind Synergy  Wind turbines to power compressors  Adjacent Wind Farm  Wind turbines that send electricity to a power grid

10. Ion Transport Membrane (ITM)  Novel technology – Air Products, Praxair  Pilot plant 5 TPD of O 2  Mixed conducting non-porous ceramic membranes  100% oxygen selectivity  Single stage air separation – compact design  Savings on the ASU  35% on capital cost  37% on power requirements  Easy integration into the current process

11. 800-900 °C High Partial Pressure Low Partial Pressure

12. Minimization of Water Usage

13. Water Profile by Block GASIFIER STEAM GENERATION COOLING TOWER AIR SEPARATION UNIT GAS TURBINE Boiling Feed Water Slurry Makeup Moisture in Cooling Air Cooling Water Makeup Moisture in Coal (28%) Cooling Water Evaporation Cooling Water Blowdown Moisture in Vent Moisture in Air Nitrogen Oxygen SyngasExhausted Flue Gas

14. Overall Water Balance WATER INWATER OUT Location Flow Rate (m 3 /hr) LocationFlow Rate (m 3 /hr) Raw Water 997 Ash Handling Blowdown2.2 Water with Slag0 Water Loss in COS Hydrolysis0.01 Sour Water Blowdown0.1 Cooling Tower Blowdown185 Cooling Tower Evaporation 809 Syngas Combustion in Gas Turbine218 Gas Turbine Flue Gas220 Combustion Air for Gas Turbine1.3 Moisture in Coal53Water Lost in Gasification53 Air Moisture to ASU0.5Moisture from ASU Vent0.5 TOTAL1269TOTAL1269

15. Raw Water Feed to the Plant

16. Water Usage and Heat Exchanger  Why? Most of water for heat exchanger  Shell-and-tube exchanger (default) WATER- CONSUMING… ROBUST!

17. Air Fin – Cooling Alternative  Atmospheric air is a cooling medium

18. Economics

19. Basis for Economic Evaluation  Project period: 20 years  Discount factor: 10%  Inflation: 4%  Installation factor: 504%  Working capital: 20% of fixed capital investment (FCI)  Tax rate: 35%  Costs: positive  Disregard constants common for all alternatives  e.g. Oxygen product constant for all ASUs  Compare net present values (NPV)  No internal rate of return (IRR) or payback period

20. ASU Capital Cost Comparison

21. ASU Utility Cost Comparison

22. NPV10 Sensitivity – ASU Capital Cost

23. NPV10 Sensitivity – ASU Utility Cost

24. Evaluation of Cooling Alternatives

25. Shell-and-Tube vs. Air Fin – Econ Analysis Shell-and-TubeAir Fin Fixed Capital Investment $ 1,900,000$ 8,800,000 Variable Cost $ 400,000$ 0  Construct incremental cash flow (CF): 1)Case 01: Incremental CF = Shell-and-Tube CF – Air Fin CF 2)Case 02: Incremental CF = Air Fin CF – Shell-and-Tube CF Case 01 (CW) Case 02 (AF) NPV10$ 1,800,000- $ 1,800,000

26. Environmental Permitting  Solid Waste-permit acquired through Wyoming’s DEQ Solid & Hazardous Waste Division  Sludge is regulated as ‘solid waste’; products of SO 2, Hg, and acid gas removal ‘hazardous waste’  Air Emissions-Title V operating permit acquired through DEQ Air Quality Division  Process meets all emission regulations for coal plants 0.0008 lb SO 2 << 0.3 lb SO 2 / 10 6 BTU  Recently (March 2011), EPA announced it will regulate mercury and acid gas in coal State of Wyoming is currently suing the EPA  Potential for future CO 2 regulations Process contains CO 2 removal and compression unit

27. Conclusions & Future Work  Conclusions  Improved cryogenic ASU design  Air fins instead of water cooling  Suggestions for future work  Heat integration  Continue to monitor ASU technology improvements Argon separation Membrane separation

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