GREENIDGE MULTI-POLLUTANT 

CONTROL PROJECT 

Final Report of Work Performed 

May 19, 2006 – October 18, 2008 

 

Principal Author 

Daniel P. Connell 

April 2009 

U.S. Department of Energy Cooperative Agreement 

DE-FC26-06NT41426 

CONSOL Energy Inc. 

Research & Development 

4000 Brownsville Road 

South Park, PA 15129 

AES Greenidge LLC 

590 Plant Road 

Dresden, NY 14441 

Babcock Power Environmental Inc. 

5 Neponset Street 

Worcester, MA 01606
 i

DISCLAIMER

This report was prepared as an account of work sponsored by an agency of the United States 

Government. Neither the United States Government nor any agency thereof, nor any of their 

employees, makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed, or represents that its use would not infringe privately owned 

rights. Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States Government or any agency thereof. The 

views and opinions of authors expressed herein do not necessarily state or reflect those of the 

United States Government or any agency thereof. 

NOTICE

The drawing titled “AES Greenidge #4, Dresden, New York, NOxOUT Utility System, System 

Overview Sheet 1” in Appendix B is Copyright © 2009 Fuel Tech, Inc. This paper was written 

with the support of the U.S. Department of Energy under Contract No. DE-FC26-06NT41426. 

The Government reserves for itself and others acting on its behalf a royalty-free, nonexclusive, 

irrevocable, worldwide license for Governmental purposes to publish, distribute, translate, 

duplicate, exhibit, and perform this copyrighted paper. 
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ABSTRACT 

The Greenidge Multi-Pollutant Control Project was conducted as part of the U.S. Department of Energy’s 

Power Plant Improvement Initiative to demonstrate an innovative combination of air pollution control 

technologies that can cost-effectively reduce emissions of SO2, NOx, Hg, acid gases (SO3, HCl, and HF), 

and particulate matter from smaller coal-fired electric generating units (EGUs). There are about 400 units 

in the United States with capacities of 50-300 MW that currently are not equipped with selective catalytic 

reduction (SCR), flue gas desulfurization (FGD), or mercury control systems. Many of these units, which 

collectively represent more than 55 GW of installed capacity, are difficult to retrofit for deep emission 

reductions because of space constraints and unfavorable economies of scale, making them increasingly 

vulnerable to retirement or fuel switching in the face of progressively more stringent environmental 

regulations. The Greenidge Project sought to confirm the commercial readiness of an emissions control 

system that is specifically designed to meet the environmental compliance requirements of these smaller 

coal-fired EGUs by offering a combination of deep emission reductions, low capital costs, small space 

requirements, applicability to high-sulfur coals, mechanical simplicity, and operational flexibility. 

The multi-pollutant control system includes a NOxOUT CASCADE®

 hybrid selective non-catalytic 

reduction (SNCR) / in-duct SCR system for NOx control and a Turbosorp®

 circulating fluidized bed dry 

scrubbing system (with a new baghouse) for SO2, SO3, HCl, HF, and particulate matter control. Mercury 

removal is provided as a co-benefit of the in-duct SCR, dry scrubber, and baghouse, and by injection of 

activated carbon upstream of the scrubber, if required. The multi-pollutant control system was installed 

and tested on the 107-MWe, 1953-vintage AES Greenidge Unit 4 by a team including CONSOL Energy 

Inc. as prime contractor, AES Greenidge LLC as host site owner, and Babcock Power Environmental Inc. 

as engineering, procurement, and construction contractor. About 44% of the funding for the project was 

provided by the U.S. Department of Energy, through its National Energy Technology Laboratory, and the 

remaining 56% was provided by AES Greenidge. Project goals included reducing high-load NOx

emissions to ≤0.10 lb/mmBtu; reducing SO2, SO3, HCl, and HF emissions by at least 95%; and reducing 

Hg emissions by at least 90% while the unit fired 2-4% sulfur eastern U.S. bituminous coal and co-fired 

up to 10% biomass. 

This report details the final results from the project. The multi-pollutant control system was constructed in 

2006, with a total plant cost of $349/kW and a footprint of 0.4 acre – both substantially less than would 

have been required to retrofit AES Greenidge Unit 4 with a conventional SCR and wet scrubber. Start-up 

of the multi-pollutant control system was completed in March 2007, and the performance of the system 

was then evaluated over an approximately 18-month period of commercial operation. Guarantee tests 

conducted in March-June 2007 demonstrated attainment of all of the emission reduction goals listed 

above. Additional tests completed throughout the performance evaluation period showed 96% SO2

removal, 98% mercury removal (with no activated carbon injection), 95% SO3 removal, and 97% HCl 

removal during longer-term operation. Greater than 95% SO2 removal efficiency was observed even 

when the unit fired high-sulfur coals containing up to 4.8 lb SO2/mmBtu. Particulate matter emissions 

were reduced by more than 98% relative to the emission rate observed prior to installation of the 

technology. The performance of the hybrid SNCR/SCR system was affected by problems with large 

particle ash, ammonia slip, and nonideal combustion characteristics, and high-load NOx emissions 

averaged 0.14 lb/mmBtu during long-term operation. Nevertheless, the system has reduced the unit’s 

overall NOx emissions by 52% on a lb/mmBtu basis. 

The commercial viability of the multi-pollutant control system was demonstrated at AES Greenidge Unit 4. 

The system, which remains in service after the conclusion of the project, has enabled the unit to satisfy its 

permit requirements while continuing to operate profitably. As a result of the success at AES Greenidge 

Unit 4, three additional deployments of the Turbosorp®

 technology had been announced by the end of the 

project. 
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TABLE OF CONTENTS 

1. EXECUTIVE SUMMARY ....................................................................................... 1

2. INTRODUCTION ................................................................................................... 3

2.1 The Power Plant Improvement Initiative ....................................................................................... 3

2.2 Project Motivation ........................................................................................................................... 3

2.3 Project Overview ............................................................................................................................. 5

2.4 Project Goals ................................................................................................................................... 6

2.5 Purpose of this Report ................................................................................................................... 6

3. PROJECT MANAGEMENT .................................................................................. 6

3.1 Schedule .......................................................................................................................................... 7

3.2 Budget .............................................................................................................................................. 8

3.3 Earned Value Management .......................................................................................................... 10

3.4 Communications ........................................................................................................................... 12

3.5 Risk Management .......................................................................................................................... 13

3.6 Safety .............................................................................................................................................. 13

4. TECHNOLOGY OVERVIEW ............................................................................... 14

4.1 Process Concept ........................................................................................................................... 14

4.1.1 NOx Control ................................................................................................................................. 14

4.1.2 SO2, SO3, HCl, HF, and Particulate Matter Control .................................................................... 18

4.1.3 Mercury Control ........................................................................................................................... 20

4.2 Key Design Features ..................................................................................................................... 21

4.2.1 Deep Emission Reductions ......................................................................................................... 21

4.2.2 Low Capital Costs ....................................................................................................................... 22

4.2.3 Small Space Requirements ......................................................................................................... 22

4.2.4 Applicability to High-Sulfur Coals ................................................................................................ 23

4.2.5 Low Maintenance Requirements ................................................................................................. 23

4.2.6 Operational Flexibility .................................................................................................................. 24

4.3 Design Considerations ................................................................................................................. 25

4.3.1 Coal and Ash Characteristics ...................................................................................................... 25

4.3.2 Baseline NO Concentration ......................................................................................................... 27

4.3.3 Temperature Profile in the Furnace ............................................................................................ 27

4.3.4 Flue Gas Residence Time and Flow Profile in the Furnace ....................................................... 27
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4.3.5 CO Concentrations in the Furnace.............................................................................................. 27

4.3.6 Available Space Between the Economizer and Air Heater ......................................................... 27

4.3.7 Flue Gas Temperature at the Economizer Outlet ....................................................................... 28

4.3.8 Flue Gas Homogeneity at the SCR Inlet ..................................................................................... 28

4.3.9 Large Particle Ash ....................................................................................................................... 28

4.3.10 Amount of Allowable Ammonia Slip ........................................................................................... 29

4.3.11 Approach to Adiabatic Saturation in the Absorber Vessel ......................................................... 29

4.3.12 Hydrated Lime Supply ................................................................................................................ 30

4.3.13 Increased Solids Loading to the Baghouse ............................................................................... 30

4.3.14 Pressure Drop Across the System ............................................................................................. 31

4.4 Developmental Status ................................................................................................................... 31

5. HOST SITE ......................................................................................................... 33

6. PROCESS DESIGN ............................................................................................ 35

6.1 Design Basis .................................................................................................................................. 35

6.2 Description by Major Process Component ................................................................................ 36

6.2.1 Selective Non-Catalytic Reduction System ................................................................................. 36

6.2.2 In-Duct Selective Catalytic Reduction Reactor ........................................................................... 39

6.2.3 Activated Carbon Injection System ............................................................................................. 42

6.2.4 Turbosorp® Circulating Fluidized Bed Dry Scrubber ................................................................... 43

6.2.5 Process Water System ................................................................................................................ 45

6.2.6 Lime Storage, Hydration, and Injection System .......................................................................... 46

6.2.7 Baghouse .................................................................................................................................... 48

6.2.8 Ash Recirculation System ........................................................................................................... 50

6.2.9 Booster Fan ................................................................................................................................. 50

6.3 Balance of Plant Considerations ................................................................................................. 51

6.3.1 Ductwork ..................................................................................................................................... 51

6.3.2 Civil and Structural ...................................................................................................................... 52

6.3.3 Instruments and Controls ............................................................................................................ 54

6.3.4 Electrical ...................................................................................................................................... 54

6.3.5 Other Utilities ............................................................................................................................... 55

6.3.6 Byproducts .................................................................................................................................. 56

6.3.7 Out-of-Scope Modifications ......................................................................................................... 57

6.3.7.1 Combustion Modifications ...................................................................................................... 57

6.3.7.2 Air Preheater Basket Modifications ........................................................................................ 58

7. PERMITTING ...................................................................................................... 58

8. CONSTRUCTION, START-UP, AND COMMISSIONING ................................... 60

8.1 Pre-Outage Construction Activities ............................................................................................ 60

8.2 Tie-In Outage ................................................................................................................................. 66

8.3 Start-Up and Commissioning ....................................................................................................... 68

9. PERFORMANCE TESTING ................................................................................ 71
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9.1 Approach ........................................................................................................................................ 72

9.1.1 Plant Operating Data ................................................................................................................... 72

9.1.2 Special Test Series ..................................................................................................................... 73

9.1.2.1 Baseline Testing ..................................................................................................................... 73

9.1.2.2 Guarantee Testing ................................................................................................................. 74

9.1.2.2.1 Sampling Campaign on March 28-30, 2007 ................................................................... 74

9.1.2.2.2 Sampling Campaign on May 1-4, 2007 ........................................................................... 75

9.1.2.2.3 Sampling Campaign on May 30-June 1, 2007 ................................................................ 75

9.1.2.2.4 Sampling Campaign on June 20-21, 2007 ..................................................................... 76

9.1.2.3 Process Performance Testing ................................................................................................ 76

9.1.2.3.1 Sampling Campaign on October 2-5, 2007 .................................................................... 77

9.1.2.3.2 Sampling Campaign on October 8-11, 2007 .................................................................. 77

9.1.2.3.3 Sampling Campaign on November 13-16, 2007 ............................................................. 78

9.1.2.3.4 Sampling Campaign on March 10-13, 2008 ................................................................... 79

9.1.2.3.5 Sampling Campaign on May 19-22, 2008 ...................................................................... 80

9.1.2.3.6 Sampling Campaign on June 16-19, 2008 ..................................................................... 81

9.1.2.4 Follow-Up Testing .................................................................................................................. 82

9.2 Experimental .................................................................................................................................. 82

9.2.1 Flue Gas Measurements ............................................................................................................. 82

9.2.1.1 Sampling Locations ................................................................................................................ 82

9.2.1.1.1 Economizer Outlet ........................................................................................................... 83

9.2.1.1.2 SCR Inlet ......................................................................................................................... 84

9.2.1.1.3 SCR Outlet ...................................................................................................................... 85

9.2.1.1.4 Air Heater Inlet ................................................................................................................ 85

9.2.1.1.5 Air Heater Outlet ............................................................................................................. 86

9.2.1.1.6 Baghouse Outlet ............................................................................................................. 87

9.2.1.1.7 Stack ............................................................................................................................... 88

9.2.1.2 Sampling and Analytical Methods .......................................................................................... 89

9.2.1.2.1 Oxides of Nitrogen .......................................................................................................... 89

9.2.1.2.2 Carbon Monoxide ............................................................................................................ 89

9.2.1.2.3 Ammonia ......................................................................................................................... 90

9.2.1.2.4 Sulfur Dioxide .................................................................................................................. 91

9.2.1.2.5 Mercury ........................................................................................................................... 91

9.2.1.2.5.1 Ontario Hydro Method .............................................................................................. 91

9.2.1.2.5.2 U.S. EPA Method 30B.............................................................................................. 93

9.2.1.2.6 Sulfur Trioxide ................................................................................................................. 94

9.2.1.2.7 Hydrogen Chloride, Hydrogen Fluoride, and Particulate Matter ..................................... 95

9.2.1.3 Quality Assurance and Quality Control .................................................................................. 96

9.2.1.3.1 Oxides of Nitrogen Measurements ................................................................................. 96

9.2.1.3.2 Carbon Monoxide Measurements ................................................................................... 96

9.2.1.3.3 Ammonia Measurements ................................................................................................ 96

9.2.1.3.4 Sulfur Dioxide Measurements ......................................................................................... 97

9.2.1.3.5 Mercury Measurements .................................................................................................. 97

9.2.1.3.5.1 Ontario Hydro Method .............................................................................................. 97

9.2.1.3.5.2 U.S. EPA Method 30B.............................................................................................. 98

9.2.1.3.5.3 Mercury Material Balance ........................................................................................ 99

9.2.1.3.6 Sulfur Trioxide Measurements ...................................................................................... 101

9.2.1.3.7 Hydrogen Chloride and Hydrogen Fluoride Measurements ......................................... 102

9.2.2 Solid and Liquid Process Sample Analyses .............................................................................. 102

9.2.2.1 Sampling Methodologies ...................................................................................................... 102

9.2.2.1.1 Coal Samples ................................................................................................................ 102

9.2.2.1.2 Biomass Samples ......................................................................................................... 103

9.2.2.1.3 Fly Ash Samples ........................................................................................................... 103

9.2.2.1.4 Turbosorp® Product Ash Samples ................................................................................ 103

9.2.2.1.5 Pebble Lime Samples ................................................................................................... 103
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9.2.2.1.6 Hydrated Lime Samples ................................................................................................ 104

9.2.2.1.7 Activated Carbon Samples ........................................................................................... 104

9.2.2.1.8 Urea Samples ............................................................................................................... 104

9.2.2.2 Analytical Methods ............................................................................................................... 104

9.2.2.2.1 Solid Samples ............................................................................................................... 104

9.2.2.2.2 Liquid Samples .............................................................................................................. 107

9.3 Results ......................................................................................................................................... 108

9.3.1 Emissions of Nitrogen Oxides ................................................................................................... 108

9.3.2 Urea Utilization .......................................................................................................................... 119

9.3.3 Ammonia Slip ............................................................................................................................ 123

9.3.4 SO2-to-SO3 Conversion across the SCR Catalyst .................................................................... 131

9.3.5 Mercury Oxidation across the SCR Catalyst ............................................................................. 132

9.3.6 Sulfur Dioxide Removal Efficiency ............................................................................................ 134

9.3.7 Lime Utilization .......................................................................................................................... 142

9.3.8 Mercury Removal Efficiency ...................................................................................................... 147

9.3.9 Sulfur Trioxide Removal Efficiency ........................................................................................... 153

9.3.10 Hydrogen Chloride Removal Efficiency .................................................................................... 158

9.3.11 Hydrogen Fluoride Removal Efficiency ..................................................................................... 161

9.3.12 Particulate Matter Emissions .................................................................................................... 162

10. OPERATING AND MAINTENANCE EXPERIENCE ......................................... 165

10.1 Routine Operating and Maintenance Requirements ............................................................... 165

10.2 Operating and Maintenance Challenges and Solutions .......................................................... 167

10.2.1 Large Particle Ash ..................................................................................................................... 167

10.2.2 Turbosorp® System and Ancillary Equipment ........................................................................... 180

10.2.2.1 Lime Hydration System ...................................................................................................... 180

10.2.2.2 Turndown ........................................................................................................................... 182

10.2.2.3 Cold Weather Problems ..................................................................................................... 182

10.2.2.4 Baghouse ........................................................................................................................... 183

10.2.2.5 Ash Recirculation System .................................................................................................. 183

10.2.2.6 Miscellaneous .................................................................................................................... 184

10.3 Operating and Maintenance Labor Requirements ................................................................... 185

10.4 Byproduct Disposal .................................................................................................................... 185

11. PROCESS ECONOMICS .................................................................................. 189

11.1 Capital Costs ............................................................................................................................... 190

11.2 Fixed Operating and Maintenance Costs ................................................................................. 191

11.3 Variable Operating and Maintenance Costs ............................................................................. 192

11.4 Levelized Costs ........................................................................................................................... 195

12. COMMERCIALIZATION ................................................................................... 201

13. CONCLUSIONS AND RECOMMENDATIONS ................................................. 203
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REFERENCES ............................................................................................................ 209

PROJECT BIBLIOGRAPHY ....................................................................................... 212

ACRONYMS AND ABBREVIATIONS ........................................................................ 214

CHEMICAL SYMBOLS ............................................................................................... 219

APPENDIX A – PROJECT SCHEDULE 

APPENDIX B – ENGINEERING DRAWINGS 

APPENDIX C – LIST OF MAJOR EQUIPMENT 

APPENDIX D – PROJECT LOG 

APPENDIX E – FLUE GAS SAMPLING SCHEDULES FROM SPECIAL TEST SERIES 

APPENDIX F – PHOTOGRAPHS OF FLUE GAS SAMPLING LOCATIONS 

APPENDIX G – CLEAN AIR ENGINEERING TESTING REPORTS 

APPENDIX H – FIELD SAMPLING DATA SHEETS AND SAMPLING DATA 

 REDUCTION WORKSHEETS 

APPENDIX I – LABORATORY ANALYSIS RESULTS FOR FLUE GAS SAMPLES 

APPENDIX J – SOLID AND LIQUID PROCESS SAMPLE ANALYSIS RESULTS 

APPENDIX K – MERCURY MATERIAL BALANCES 

APPENDIX L – BULK CHEMICAL ANALYSIS OF LPA AND ASH SAMPLES 

 COLLECTED IN AND AROUND THE SCR REACTOR IN DECEMBER 

 2007 
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LIST OF FIGURES 

Figure 1. Map of operating coal-fired EGUs in the United States with capacities of 50-300 MWe. ............. 4

Figure 2. Cumulative monthly Planned Value, Actual Cost, and Earned Value for the Greenidge 

Multi-Pollutant Control Project. ...................................................................................................... 11

Figure 3. Cumulative monthly Schedule Performance Index and Cost Performance Index for the 

Greenidge Multi-Pollutant Control Project. ..................................................................................... 12

Figure 4. Schematic of the multi-pollutant control process that was demonstrated as part of the 

Greenidge Project. ......................................................................................................................... 15

Figure 5. Conceptual depiction of the effect of temperature on urea utilization and ammonia slip in 

SNCR, and the implications of this effect for hybrid SNCR/SCR design. ...................................... 16

Figure 6. Conceptual illustration of the Delta WingTM static mixing technology. ......................................... 17

Figure 7. Schematic of the Turbosorp® circulating fluidized bed dry scrubbing system. Red, blue, 

and green arrows indicate the paths of solids, liquids, and gases, respectively, through 

the system. ..................................................................................................................................... 19

Figure 8. Operating strategy for the hybrid NOx control system that was demonstrated as part of 

the Greenidge Project. ................................................................................................................... 25

Figure 9. Aerial photograph of the AES Greenidge plant, as viewed from the south prior to the 

multi-pollutant control project. ........................................................................................................ 34

Figure 10. Photograph showing several of the SNCR Zone 1 injectors at AES Greenidge Unit 4. ........... 37

Figure 11. Photograph showing one of the two multiple nozzle lances installed at AES Greenidge 

Unit 4. ............................................................................................................................................. 37

Figure 12. Example of CFD modeling results used in the design of the hybrid NOx control system 

for AES Greenidge Unit 4 (Boiler 6). Shown are temperature and velocity profiles for a 

case in which the unit is operating at 103% of its MCR. ................................................................ 37

Figure 13. Photograph showing the urea storage tank and HFD module at AES Greenidge Unit 4. ......... 38

Figure 14. Photograph showing the SNCR Zone 2 distribution module at AES Greenidge Unit 4. .......... 39

Figure 15. Photograph of the physical flow model used to design the in-duct SCR reactor 

(courtesy of Ruscheweyh Consult GmbH). .................................................................................... 41

Figure 16. Schematic of the large particle ash removal system that was installed above the induct SCR reactor at AES Greenidge Unit 4. .................................................................................. 41

Figure 17. Photograph of the in-duct SCR reactor at AES Greenidge Unit 4. .......................................... 42

Figure 18. Photograph of the activated carbon injection system at AES Greenidge Unit 4. ..................... 43

Figure 19. Photograph of the Turbosorp® circulating fluidized bed dry scrubbing system, 

including ancillary equipment, at AES Greenidge Unit 4. .............................................................. 44

Figure 20. Process control schematic showing major control loops for the Turbosorp® circulating 

fluidized bed dry scrubber at AES Greenidge Unit 4. Lime injection control is shown in 

green; water injection control is shown in blue; solid product recycle control is shown in 

red; and solid product rejection control is shown in orange. .......................................................... 45
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Figure 21. Photograph showing the Turbosorp® water injection lance (in service). .................................. 46

Figure 22. Photograph of the lime hydrator at AES Greenidge. The chute in the foreground (with 

the red door) is used to convey hydrated lime from the cyclone to the hydrated lime silo. ........... 47

Figure 23. Photograph showing part of the lime hydration system at AES Greenidge Unit 4. The 

hydrated lime classifier, cyclone, pebble lime weigh feeder, and bottom of the pebble lime 

storage silo are all visible. .............................................................................................................. 47

Figure 24. Photograph showing the system that is used to feed hydrated lime to the Turbosorp®

vessel at AES Greenidge Unit 4. ................................................................................................... 48

Figure 25. Photograph showing the inside of the baghouse penthouse at AES Greenidge Unit 4. .......... 49

Figure 26. Photograph of one of the air slide conveyers at AES Greenidge Unit 4.................................... 50

Figure 27. Photograph of the booster fan at AES Greenidge Unit 4. ........................................................ 51

Figure 28. Photograph taken prior to the start of construction of the site for the outdoor portion of 

the multi-pollutant control system, as viewed from the southwest. ................................................ 53

Figure 29. Photograph showing structural steel being erected for the baghouse support structure 

on April 6, 2006. ............................................................................................................................. 61

Figure 30. Photograph showing several baghouse modules and a partially assembled 

Turbosorp®

 absorber section in the lay-down area in early May 2006. ......................................... 62

Figure 31. Photograph showing one of the baghouse modules being lifted into place in mid-May 

2006. .............................................................................................................................................. 62

Figure 32. Photograph showing assembly of the Turbosorp® inlet and venturi sections in early 

June 2006. ..................................................................................................................................... 63

Figure 33. Photograph showing installation of the roof of the Turbosorp® absorber during the first 

week of July 2006. The first pieces of structural steel for the baghouse penthouse are 

also visible. ..................................................................................................................................... 64

Figure 34. Photograph showing one of the air slides being lifted into place on August 16, 2006. ............ 65

Figure 35. Photograph showing the quicklime silo being set in place in September 2006. ....................... 65

Figure 36. Photograph taken on October 27, 2006, at the start of SCR reactor construction. .................. 67

Figure 37. Photograph showing catalyst modules being loaded into the SCR reactor in November 

2006. .............................................................................................................................................. 68

Figure 38. Photograph showing the installation of the new ductwork used to transport the 

hydrator exhaust to the inlet of the Turbosorp®

 vessel. ................................................................. 71

Figure 39. Schematic showing the locations where flue gas sampling was performed during 

performance testing of the multi-pollutant control system at AES Greenidge Unit 4. .................... 83

Figure 40. Schematic of the stack sampling location at AES Greenidge Unit 4, including 

dimensions and traverse points. .................................................................................................... 88

Figure 41. Schematic of the Ontario Hydro Method sampling train in a Method 17 configuration. ........... 92

Figure 42. Schematic of the U.S. EPA Method 30B sampling train. .......................................................... 93

Figure 43. NOx emission rate and total urea flow rate observed during guarantee testing of the 

multi-pollutant control system between 8:00 and 20:00 eastern standard time (EST) on 
 x

March 28, 2007. The average unit load during this period was 105 MWg. NOx emissions 

were measured by the unit's stack CEM. The urea flow rate was measured by the SNCR 

system’s flow meters and represents the flow of 50% (w/w) urea solution. ................................ 110

Figure 44. NOx emission rate and total urea flow rate observed during guarantee testing of the 

multi-pollutant control system between 8:00 and 20:00 EST on May 1, 2007. The 

average unit load during this period was 106 MWg. NOx emissions were measured by the 

unit's stack CEM. The urea flow rate was measured by the SNCR system’s flow meters 

and represents the flow of 50% (w/w) urea solution. ................................................................... 110

Figure 45. NOx emission rate and total urea flow rate observed during guarantee testing of the 

multi-pollutant control system between 8:00 and 20:00 EST on June 20, 2007. The 

average unit load during this period was 106 MWg. NOx emissions were measured by the 

unit's stack CEM. The urea flow rate was measured by the SNCR system’s flow meters 

and represents the flow of 50% (w/w) urea solution. ................................................................... 111

Figure 46. Comparison of NOx emissions from AES Greenidge Unit 4 measured during August 

2007-September 2008, following installation of the multi-pollutant control system, with 

those measured during August 2004-September 2005, prior to installation of the system. 

Data were obtained from the unit’s stack CEM. The average NOx emission rate is plotted 

as a function of gross unit load. The percent NOx reduction computed from these data for 

each unit load is also shown. Data are not shown for loads that have fewer than 10 

observations in either period. ....................................................................................................... 112

Figure 47. Thirty-day rolling average permit limits and NOx emission rates for AES Greenidge 

Unit 4 from January 2008 through September 2008. ................................................................... 113

Figure 48. NOx emission rate and total urea flow rate observed between 7:19 and 10:09 EST on 

March 10, 2008. NOx emissions were measured by the unit's stack CEM. The urea flow 

rate was measured by the SNCR system’s flow meters and represents the flow of 50% 

(w/w) urea solution. ...................................................................................................................... 114

Figure 49. NOx emission rate and total urea flow rate observed between 14:55 and 18:27 EST on 

March 13, 2008. The drop in NOx emissions around 16:40 occurred when biomass cofiring was discontinued, temporarily upsetting the system. NOx emissions were 

measured by the unit's stack CEM. The urea flow rate was measured by the SNCR 

system’s flow meters and represents the flow of 50% (w/w) urea solution. ................................ 114

Figure 50. NOx emission rate and total urea flow rate observed between 8:01 and 10:31 EST on 

May 21, 2008. NOx emissions were measured by the unit's stack CEM. The urea flow 

rate was measured by the SNCR system’s flow meters and represents the flow of 50% 

(w/w) urea solution. ...................................................................................................................... 115

Figure 51. NOx emission rate and total urea flow rate observed between 4:07 and 6:22 EST on 

May 22, 2008. NOx emissions were measured by the unit's stack CEM. The urea flow 

rate was measured by the SNCR system’s flow meters and represents the flow of 50% 

(w/w) urea solution. ...................................................................................................................... 115

Figure 52. Summary of NOx removal efficiencies computed from NOx concentrations measured 

at the SCR inlet and outlet sampling grids on March 28, 2007 (average of the three tests 

reported in Table 13). Each sampling grid consisted of 24 measurement points. The 

graph shows the NOx removal achieved by the SCR as a function of location on the 

catalyst cross section. For purposes of this graph, any points with negative NOx removal 

efficiencies were set equal to 0% removal efficiency. .................................................................. 118

Figure 53. Summary of NOx removal efficiencies computed from NOx concentrations measured 

at the SCR inlet and outlet sampling grids on June 20, 2007, between 20:00 and 20:47 

Eastern Daylight Time (EDT). Each sampling grid consisted of 24 measurement points. 
 xi

The graph shows the NOx removal achieved by the SCR as a function of location on the 

catalyst cross section. .................................................................................................................. 118

Figure 54. Summary of NOx removal efficiencies computed from NOx concentrations measured 

at the SCR inlet and outlet sampling grids on May 21, 2008, between 7:12 and 9:59 EDT. 

Each sampling grid consisted of 24 measurement points. The graph shows the NOx

removal achieved by the SCR as a function of location on the catalyst cross section. For 

purposes of this graph, any points with negative NOx removal efficiencies were set equal 

to 0% removal efficiency. Invalid measurements were replaced with the average of 

surrounding valid measurements. ................................................................................................ 119

Figure 55. Summary of NOx removal efficiencies computed from NOx concentrations measured 

at the SCR inlet and outlet sampling grids on May 21, 2008, between 3:12 and 5:59 EDT. 

Each sampling grid consisted of 24 measurement points. The graph shows the NOx

removal achieved by the SCR as a function of location on the catalyst cross section. For 

purposes of this graph, any points with negative NOx removal efficiencies were set equal 

to 0% removal efficiency. Invalid measurements were replaced with the average of 

surrounding valid measurements. ................................................................................................ 120

Figure 56. Summary of NOx removal efficiencies computed from NOx concentrations measured 

at the SCR inlet and outlet sampling grids on May 22, 2008, between 0:48 and 5:35 EDT. 

Each sampling grid consisted of 24 measurement points. The graph shows the NOx

removal achieved by the SCR as a function of location on the catalyst cross section. For 

purposes of this graph, any points with negative NOx removal efficiencies were set equal 

to 0% removal efficiency. Invalid measurements were replaced with the average of 

surrounding valid measurements. ................................................................................................ 120

Figure 57. Total flow rate of 50% w/w urea solution (sum of all three SNCR zones) as a function 

of gross unit load between August 2007 and September 2008. Urea measurements were 

made by the SNCR system’s online flow meters. The solid line indicates the mean flow 

rate at each load, and the dashed lines represent ± 2 standard deviations from the mean. 

Computations were performed using hourly data. ....................................................................... 122

Figure 58. NH3 concentrations measured at the air heater inlet sampling location between 

October 2007 and June 2008. The shading indicates the highest numbered (coolest 

temperature) zone of urea injection that was in operation during each test. ............................... 127

Figure 59. Ammonia slip as a function of gross unit load and urea injection regime at AES 

Greenidge Unit 4. Data were obtained during process performance testing at AES 

Greenidge in November 2007 and May 2008. The columns represent the mean 

ammonia concentration observed at each condition, and the error bars represent ± 1 

standard deviation. The relative flow rate of urea being injected into each zone of the 

SNCR system is also shown. ....................................................................................................... 127

Figure 60. Scatter plot showing ammonia slip at the air heater inlet vs. the total flow rate of 50% 

w/w urea solution being injected into the SNCR system, with simple linear regression 

results. Data were taken from tests during October 2007-June 2008 that were conducted 

while urea was being injected into Zones 2 and 3 of the SNCR system and the pressure 

drop across the SCR catalyst was ≤2 iwc. ................................................................................... 128

Figure 61. Time series of the ammonia content of fly ash samples collected at the air heater 

outlet and the daily average pressure drop observed across the in-duct SCR catalyst at 

AES Greenidge Unit 4. The red arrows indicate the timing of outages during which the 

SCR catalyst was cleaned or replaced. ....................................................................................... 129

Figure 62. Scatter plot showing the ammonia content of fly ash samples collected at the air 

heater outlet vs. the daily average pressure drop measured across the SCR catalyst, with 

simple linear regression results. .................................................................................................. 130
 xii

Figure 63. Scatter plot showing the ammonia content of fly ash samples collected at the air 

heater outlet vs. the daily average gross unit load, with simple linear regression results. .......... 130

Figure 64. Scatter plot showing the ammonia content of fly ash samples collected at the air 

heater outlet vs. the daily average flow rate of 50% w/w urea solution to the SNCR 

system, with simple linear regression results. ............................................................................. 131

Figure 65. Hourly SO2 rates (lb/mmBtu) determined at the air heater outlet (upstream of the 

Turbosorp® system) and stack (downstream of the Turbosorp® system) during August 

2007 – September 2008. SO2 was measured by the dilution extractive-type SO2 analyzer 

that is permanently installed at the air heater outlet and by the unit’s stack CEM. ..................... 136

Figure 66. Five-minute average SO2 rates (lb/mmBtu) and gross unit load observed at AES 

Greenidge Unit 4 between 1000 and 2100 EST on October 3, 2007. SO2 was measured 

by the dilution extractive-type SO2 analyzer that is permanently installed at the air heater 

outlet (upstream of the Turbosorp® system) and by the unit’s stack CEM (downstream of 

the Turbosorp®

 system). .............................................................................................................. 139

Figure 67. Five-minute average Turbosorp® outlet temperatures, gross unit loads, and SO2

removal efficiencies observed at AES Greenidge Unit 4 between 0300 and 0900 EST on 

June 18, 2008. These data indicate the effect of interruptions in water injection on the 

performance of the Turbosorp®

 system. SO2 was measured by the dilution extractivetype SO2 analyzer that is permanently installed at the air heater outlet (upstream of the 

Turbosorp®

 system) and by the unit’s stack CEM (downstream of the Turbosorp®

system). ........................................................................................................................................ 140

Figure 68. Thirty-day rolling average SO2 emission rates and permit limit for AES Greenidge Unit 

4 from January 2008 through September 2008. .......................................................................... 141

Figure 69. Average SO2 removal efficiency and Turbosorp® outlet temperature as a function of 

gross unit load, based on hourly data collected during August 2007 – September 2008. 

SO2 was measured by the dilution extractive-type SO2 analyzer that is permanently 

installed at the air heater outlet (upstream of the Turbosorp® system) and by the unit’s 

stack CEM (downstream of the Turbosorp® system). .................................................................. 142

Figure 70. Five-minute average gross unit loads, SO2 removal efficiencies, Turbosorp® outlet 

temperatures, and hydrated lime rotary feeder percent outputs observed at AES 

Greenidge Unit 4 between June 16, 2008, at 2030 EST and June 17, 2008, at 0230 EST. 

These data illustrate the performance of the Turbosorp®

 system in response to a load 

swing. SO2 was measured by the dilution extractive-type SO2 analyzer that is 

permanently installed at the air heater outlet (upstream of the Turbosorp®

 system) and by 

the unit’s stack CEM (downstream of the Turbosorp®

 system). .................................................. 143

Figure 71. Calcium-to-sulfur molar ratios determined during parametric testing of the Turbosorp®

system at AES Greenidge Unit 4 in October 2007. Ratios were derived from process 

data and from the chemical analysis of Turbosorp®

 product ash samples using the 

procedures described in the text. Relevant plant operating conditions are also shown. ............ 145

Figure 72. Calcium-to-sulfur molar ratios determined during parametric testing of the Turbosorp®

system at AES Greenidge Unit 4 in June 2008. Ratios were derived from the chemical 

analysis of Turbosorp®

 product ash samples using the procedures described in the text. 

Relevant plant operating conditions are also shown. .................................................................. 146

Figure 73. Summary of coal-to-stack Hg removal efficiencies measured at AES Greenidge Unit 4 

between March 2007 and June 2008. For bars labeled “>” the Hg concentration at the 

stack was below the method detection limit, and the removal efficiency was greater than 

the value shown. .......................................................................................................................... 148
 xiii

Figure 74. Scatter plot showing the coal-to-stack Hg removal efficiency vs. the carbon content of 

fly ash samples collected at the air heater outlet, with simple linear regression results. 

Data were collected during tests in October 2007-June 2008. .................................................... 152

Figure 75. Scatter plot showing Hg removal efficiencies computed from Hg measurements at the 

air heater outlet and stack vs. Hg removal efficiencies computed from Hg measurements 

in the coal and at the stack. Measurements were conducted during tests in March, 

October, and November 2007. ..................................................................................................... 153

Figure 76. Comparison of the average coal-to-stack Hg removal efficiency observed during 

baseline testing in November 2004, prior to installation of the multi-pollutant control 

system, with the average removal efficiency observed during performance testing in 

March 2007-June 2008, after installation of the system. Error bars represent ±1 standard 

deviation. ...................................................................................................................................... 155

Figure 77. Scatter plot showing SO3 removal efficiencies vs. SO2 removal efficiencies observed 

across the Turbosorp®

 system during tests in May 2007 – June 2008, with simple linear 

regression results. ........................................................................................................................ 157

Figure 78. Scatter plot showing SO3 removal efficiencies across the Turbosorp® system vs. 

corresponding SO3 concentrations measured at the air heater outlet (Turbosorp®

 inlet) 

during tests in May 2007 – June 2008. ........................................................................................ 157

Figure 79. Scatter plot showing HCl removal efficiencies vs. SO2 removal efficiencies observed 

across the Turbosorp®

 system during tests in March 2007 – June 2008, with simple linear 

regression results. ........................................................................................................................ 159

Figure 80. Scatter plot showing HCl removal efficiencies vs. SO3 removal efficiencies observed 

across the Turbosorp®

 system during tests in March 2007 – June 2008, with simple linear 

regression results. ........................................................................................................................ 160

Figure 81. Summary of mean primary particulate matter emission rates measured at the AES 

Greenidge Unit 4 stack before and after installation of the multi-pollutant control system. 

The baseline testing emission rate is based on two measurements made using U.S. EPA 

Method 5 in November 2004. The performance testing emission rate is based on 59 

measurements made using U.S. EPA Method 17 in March 2007 – June 2008. Error bars 

represent ± 1 standard deviation. ................................................................................................ 163

Figure 82. Summary of mean primary particulate matter rates measured at the air heater outlet 

(upstream of the Turbosorp® system) and stack (downstream of the Turbosorp®

 system) 

during 43 tests in March 2007 – June 2008. Sampling was conducted simultaneously at 

the two locations using U.S. EPA Method 17. Data are presented on a logarithmic scale. 

Error bars represent +1 standard deviation. ................................................................................ 164

Figure 83. Photograph taken on November 10, 2007, showing large particle ash accumulation in 

the in-duct SCR catalyst at AES Greenidge Unit 4. ..................................................................... 168

Figure 84. Photograph from February 3, 2007, showing the accumulation of fly ash on top of the 

in-duct SCR reactor at AES Greenidge Unit 4. The buildup of fly ash appeared to be 

caused by pieces of LPA that blocked the catalyst channels. ..................................................... 168

Figure 85. Time series plot (EST) showing the average hourly pressure drops measured across 

the SCR catalyst and LPA screen at AES Greenidge Unit 4 between June 21, 2007, and 

September 30, 2008. The maximum gross unit load observed each day during this 

period is also plotted. ................................................................................................................... 170
 xiv

Figure 86. Photograph of a partially plugged catalyst module (viewed from the inlet end) that was 

removed from the in-duct SCR reactor at AES Greenidge Unit 4 in late December 2007. 

A test catalyst element was removed near the center of the module. ......................................... 173

Figure 87. Photograph of a portion of the outlet end of the SCR catalyst taken during the 

December 2007 outage at AES Greenidge Unit 4. Weak agglomerates of fly ash can be 

seen protruding from some of the catalyst channels. .................................................................. 174

Figure 88. Photograph of a portion of the catalyst screen taken during the November 2007 

outage at AES Greenidge Unit 4. Small pieces of LPA (surrounded by fly ash) are visibly 

lodged in the screen. The white coloration is color “washout” from the photographic flash, 

and it does not represent the actual color of the ash. .................................................................. 175

Figure 89. Summary of results from the dissection of a catalyst element pulled from the in-duct 

SCR reactor during the November 9-12, 2007 outage. The catalyst element was cut into 

18 sequentially numbered wafers, with wafer 1 taken from the outlet end and wafer 18 

taken from the inlet end. The plot shows the number of plugged cells observed in each 

wafer (there were 324 total cells per wafer), as well as the cumulative number of LPA 

pieces found between the outlet end of the catalyst and each wafer. ......................................... 176

Figure 90. Photograph comparing the original LPA screen that was installed in May 2007 (right) 

with the new, smaller-pitch LPA screen that was installed in May 2008. .................................... 176

Figure 91. Photograph showing one of the catalyst modules that was removed from the SCR 

reactor in May 2008. Catalyst erosion (likely caused by the rake soot blower) and some 

LPA plugging are evident in the picture. ...................................................................................... 177

Figure 92. Photograph from the May 2008 outage showing the new LPA screen (installed) and 

the new hinged seal connecting the two LPA screen sections. ................................................... 177

Figure 93. Plot comparing the rates of increase in pressure drop across the SCR catalyst at AES 

Greenidge Unit 4 following the outages in August 2007 (navy blue), September 2007 

(magenta), December 2007 (light blue), and May 2008 (red). For each case, the plot 

shows the high-load pressure drop across the SCR catalyst as a function of the 

cumulative MWh of operation since the conclusion of the outage. The high-load pressure 

drop includes all hourly average pressure drops measured when the unit was operating 

at ≥90 MWg. .................................................................................................................................. 179

Figure 94. Photograph of the product ash, including a mixture of scrubber byproduct and fly ash, 

produced by the Turbosorp®

 process at AES Greenidge Unit 4. ................................................. 186

Figure 95. Scatter plot showing the mass flow rate of scrubber byproduct (excluding fly ash) 

produced by the Turbosorp process vs. the mass flow rate of SO2 removed by the 

process, with simple linear regression results. Data were derived from the material 

balances performed for each of the 34 mercury tests conducted at AES Greenidge 

between March 2007 and June 2008. .......................................................................................... 186

Figure 96. Projected effect of coal sulfur content on SO2 control costs for 95% SO2 removal 

efficiency. ..................................................................................................................................... 199

Figure 97. Effect of SO2 removal efficiency on SO2 control costs for a 3.6 lb SO2/mmBtu coal. 

Costs were derived from the results of parametric testing of the Turbosorp®

 system on 

June 16-18, 2008. ........................................................................................................................ 200
 xv

LIST OF TABLES 

Table 1. Summary of major project tasks. The organization with primarily responsibility for 

completing each task is indicated. ................................................................................................... 7

Table 2. Greenidge Project milestone plan showing planned and actual completion dates for 

critical path project milestones. ........................................................................................................ 9

Table 3. Overall project budget and actual project cost through October 2008. ......................................... 9

Table 4. Characteristics of existing Turbosorp® installations on coal-fired EGUs and of the AES 

Greenidge design. .......................................................................................................................... 32

Table 5. Assumed fuel characteristics (as fired) for the design case. ........................................................ 35

Table 6. Emission performance targets for the design case. ..................................................................... 36

Table 7. Water requirements for operation of the multi-pollutant control system at AES Greenidge. ........ 55

Table 8. Projected composition of the fly ash / scrubber byproduct discharged from the baghouse. ........ 56

Table 9. Permits required for construction and operation of the multi-pollutant control system at 

AES Greenidge Unit 4. ................................................................................................................... 59

Table 10. Chemical composition of typical coal samples collected at AES Greenidge Unit 4 

during the Operation and Testing Phase. .................................................................................... 109

Table 11. Average NOx emission rates measured during August 2004 – September 2005, prior to 

the installation of the multi-pollutant control system, and during August 2007 – September 

2008, following installation of the system, for various unit load ranges. Averages are 

shown for all unit loads (≥42 MWg) and for three load ranges corresponding to the unit’s 

current permit limits. ..................................................................................................................... 112

Table 12. Average NOx emission rates observed with and without urea injection during tests on 

March 10, March 13, May 21, and May 22, 2008. These data were used to compute the 

NOx removal efficiency achieved by the hybrid SNCR/SCR system. .......................................... 116

Table 13. Average NOx emission rates measured by Clean Air Engineering at the SCR inlet and 

SCR outlet sampling grids during tests in March 2007, May 2007, June 2007, and May 

2008. The NOx removal efficiencies computed from these data are also shown, as are 

relevant unit operating data. ........................................................................................................ 116

Table 14. Estimated normalized stoichiometric ratio and urea utilization during the guarantee test 

periods on March 28, May 1, and June 20, 2007. Relevant process data are also 

summarized. ................................................................................................................................. 121

Table 15. Estimated normalized stoichiometric ratio and urea utilization during tests conducted 

on March 10, March 13, May 21, and May 22, 2008. Relevant process data are also 

summarized. ................................................................................................................................. 123

Table 16. Ammonia concentrations measured by CONSOL at the SCR outlet and air heater inlet 

sampling locations on March 28 and May 1, 2007. Relevant process data are also 

summarized. ................................................................................................................................. 124

Table 17. Ammonia concentrations measured by CONSOL and Clean Air Engineering at the air 

heater inlet sampling location on May 31 and June 1, 2007. Relevant process data are 

also summarized. ......................................................................................................................... 124
 xvi

Table 18. Ammonia concentrations measured by CONSOL at the air heater inlet sampling 

location on June 20-21, 2007. Relevant process data are also summarized. ............................ 125

Table 19. Ammonia concentrations measured by CONSOL at the air heater inlet sampling 

location during process performance testing and follow-up testing between October 2007 

and June 2008. Relevant process data are also summarized. ................................................... 126

Table 20. Summary of SO2-to-SO3 conversion rates determined from testing around the SCR 

reactor in October 2007, March 2008, and June 2008. Relevant process data are also 

summarized. ................................................................................................................................. 132

Table 21. Summary of gas-phase mercury speciation determined from testing around the SCR 

reactor in October 2007, March 2008, May 2008, and June 2008. Relevant process data 

are also summarized. ................................................................................................................... 134

Table 22. Average gas-phase mercury speciation around the SCR reactor, computed for three 

subsets of the measurements presented in Table 21. Paired t-tests were performed on 

each subset of measurements to assess the statistical significance of the change in 

mercury oxidation across the reactor. .......................................................................................... 135

Table 23. Summary of the SO2 removal efficiency across the Turbosorp® system determined 

during guarantee testing on March 29, 2007. .............................................................................. 135

Table 24. Summary of the long-term SO2 removal performance of the Turbosorp® system, based 

on hourly data collected from August 2007 through September 2008. ....................................... 137

Table 25. SO2 concentrations, and implied removal efficiency across the Turbosorp® system, 

determined as part of SO3 tests conducted at the air heater outlet and stack using the 

controlled condensation method between October 2007 and June 2008. .................................. 138

Table 26. Average calcium-to-sulfur molar ratio estimated for the 14-month period from August 

2007 through September 2008 using lime delivery (truck weight) data and SO2 data from 

the plant’s online analyzers. ......................................................................................................... 147

Table 27. Results of Hg tests performed at AES Greenidge Unit 4 during March 2007-June 2008. 

Relevant process conditions are also summarized. .................................................................... 149

Table 28. Summary of average mercury removal efficiencies observed during tests with and 

without activated carbon injection in March 2007 and October 2007. ......................................... 150

Table 29. Mercury speciation determined as part of Ontario Hydro Method testing at the air 

heater outlet and stack in March, October, and November 2007. Speciation results at the 

air heater outlet were affected by a sampling artifact that leads to artificially high particlebound and/or oxidized mercury concentrations, and artificially low elemental and/or 

oxidized mercury concentrations. ................................................................................................ 154

Table 30. Results of SO3 tests performed around the Turbosorp® system at AES Greenidge Unit 

4 during May 2007-June 2008. Relevant process conditions are also summarized. ................. 156

Table 31. Results of HCl tests performed around the Turbosorp® system at AES Greenidge Unit 

4 during March 2007-June 2008. Relevant process conditions are also summarized. .............. 158

Table 32. Results of HF tests performed around the Turbosorp® system at AES Greenidge Unit 4 

during March 2007-June 2008. .................................................................................................... 162

Table 33. Summary of outages at AES Greenidge Unit 4 during which actions were taken in and 

around the SCR reactor to address the LPA problem. ................................................................ 169
 xvii

Table 34. Synthetic Precipitation Leaching Procedure results for sixteen Turbosorp® product ash 

samples collected at AES Greenidge Unit 4 between November 2007 and June 2008. ............ 187

Table 35. Average results from the chemical analysis of Turbosorp® product ash samples 

collected during follow-up testing at AES Greenidge Unit 4 on June 10-13, 2008. ..................... 188

Table 36. Base plant performance assumptions used in the economic analysis of the multipollutant control system at AES Greenidge Unit 4. ...................................................................... 190

Table 37. Capital costs for the multi-pollutant control system at AES Greenidge Unit 4. Costs are 

expressed in 2005 dollars. ........................................................................................................... 190

Table 38. Estimated fixed operating and maintenance costs for the multi-pollutant control system 

at AES Greenidge Unit 4. ............................................................................................................. 192

Table 39. Unit prices used in variable O&M cost calculations (as of early 2007). ................................... 193

Table 40. Performance assumptions used to compute the variable O&M costs and levelized 

costs associated with the multi-pollutant control system at AES Greenidge Unit 4..................... 193

Table 41. Estimated variable operating and maintenance costs for the multi-pollutant control 

system at AES Greenidge Unit 4. ................................................................................................ 195

Table 42. Financial assumptions used for levelized capital cost calculations. ........................................ 196

Table 43. Estimated levelized costs for the multi-pollutant control system at AES Greenidge Unit 

4. Costs are expressed in constant 2005 dollars. ....................................................................... 196

Table 44. Estimated levelized costs for the hybrid NOx control system (including the combustion 

modifications) at AES Greenidge Unit 4. Costs are expressed in constant 2005 dollars. .......... 196

Table 45. Estimated levelized costs for the circulating fluidized bed dry scrubbing system at AES 

Greenidge Unit 4. Costs are expressed in constant 2005 dollars. ............................................. 197

Table 46. Estimated levelized costs for the activated carbon injection system at AES Greenidge 

Unit 4. Costs are expressed in constant 2005 dollars. ............................................................... 197

Table 47. Turbosorp® projects at coal-fired electric generating units in the United States, as of 

October 2008. .............................................................................................................................. 201
 1

1. Executive Summary 

As part of the Greenidge Multi-Pollutant Control Project, CONSOL Energy Inc. (CONSOL), AES Greenidge LLC, 

and Babcock Power Environmental Inc. (BPEI) installed and tested an innovative, integrated combination of air 

pollution control technologies on one of the nation’s smaller existing coal-fired power plants - the 107-MWe AES 

Greenidge Unit 4. The overall goal of the project, which was conducted in 2006-2008, was to demonstrate that 

this multi-pollutant control system, including a NOxOUT CASCADE®

 hybrid selective non-catalytic reduction 

(SNCR) / selective catalytic reduction (SCR) system and a Turbosorp®

 circulating fluidized bed dry scrubbing 

system, can cost-effectively reduce emissions of nitrogen oxides (NOx), sulfur dioxide, mercury, particulate 

matter (PM), and acid gases, including sulfur trioxide, hydrogen chloride, and hydrogen fluoride, from coal-fired 

electric generating units (EGUs) with capacities of 50 MWe to 600 MWe. The project was conducted as part of 

the U.S. Department of Energy’s (DOE’s) Power Plant Improvement Initiative (PPII), which is managed by its 

National Energy Technology Laboratory (NETL). 

Although the multi-pollutant control system at AES Greenidge is applicable to units with capacities of 50-600 

MWe, its potential benefits are greatest for units in the lower half of this size range. There are about 400 coalfired units operating in the United States with capacities of 50-300 MWe that currently are not equipped with SCR 

or flue gas desulfurization (FGD) systems. These smaller units, which represent more than 55 GW of installed 

generating capacity, are increasingly vulnerable to retirement or fuel switching as a result of progressively more 

stringent state and federal environmental regulations. The Greenidge Project sought to demonstrate the 

commercial readiness of an emissions control system that is particularly suited, because of its deep emission 

reduction capabilities, low capital and maintenance costs, small space demands, applicability to high-sulfur coal, 

and operational flexibility, to meet the requirements of this large group of existing electric generating units. 

The Greenidge Multi-Pollutant Control Project was funded by the DOE and by AES Greenidge. The project 

aspired to be the first to demonstrate: 

• Full-load NOx emissions of ≤0.10 lb/mmBtu using a NOxOUT CASCADE®

 hybrid SNCR/SCR system, in 

combination with low-NOx combustion technology, on a unit firing >2%-sulfur coal and biomass 

• SO2 and acid gas (SO3, HCl, HF) removal of ≥95% using a Turbosorp®

 circulating fluidized bed dry scrubber 

on a unit firing >2%-sulfur U.S. bituminous coal 

• Mercury reduction of ≥90% via the co-benefits afforded by the in-duct SCR and Turbosorp®

 (with baghouse) 

systems and by activated carbon injection, if needed 

NOx control is the first step in the multi-pollutant control process and is accomplished using combustion 

modifications (installed outside of the scope of the DOE project) and urea-based SNCR in the furnace, followed 

by a single-layer SCR reactor that is installed in a modified section of the ductwork between the unit’s 

economizer and air heaters. The SCR process is fed by ammonia slip from the SNCR process; static mixers 

located just upstream of the SCR are used to homogenize the flue gas before it enters the catalyst. Emissions of 

SO2 and other acid gases are reduced in the Turbosorp®

 circulating fluidized bed dry scrubbing system, which is 

installed downstream of the air heaters. In the Turbosorp®

 system, water and dry hydrated lime, which is 

supplied from an onsite hydrator installed as part of the project, are injected separately into a fluidized bed 

absorber, where the flue gas is evaporatively cooled and brought into intimate contact with the hydrated lime 

reagent in a fast fluidized bed. The hydrated lime reacts with the acidic constituents of the flue gas (i.e., SO2, 

SO3, HCl, and HF) to form dry solid products, which are separated from the flue gas in a new pulse-jet baghouse 

and recycled to the absorber via air slides at a high ratio to the inlet solids in order to maximize pollutant removal 

and lime utilization. Mercury removal is provided as a co-benefit of the in-duct SCR, dry scrubber, and 

baghouse, and by injection of activated carbon upstream of the scrubber, if required. A new booster fan was 

installed to overcome the pressure drop added by the multi-pollutant control equipment. The design includes 

turndown capabilities for the SNCR and Turbosorp®

 systems, enabling continued emissions reduction at reduced 

loads. 

The multi-pollutant control system started up in early 2007, and its performance was then evaluated over an 

approximately 18-month period of commercial operation while AES Greenidge Unit 4 fired mid- or high-sulfur 

coal and co-fired up to 5% biomass (waste wood). Major conclusions of the project were as follows: 

• The multi-pollutant control system achieved the performance target of ≥95% SO2 removal efficiency during 

both short-term and long-term testing. The average SO2 removal efficiency observed during 14 months of 
 2

commercial operation (August 2007 – September 2008) was 96.3%. The inlet SO2 rate averaged 3.6 

lb/mmBtu during this period; however, SO2 removal efficiencies ≥95% were achieved for coals containing up 

to 4.8 lb SO2/mmBtu. Performance tests showed that the system required a calcium-to-sulfur (Ca/S) molar 

ratio of 1.6-1.7 to achieve 95% SO2 removal efficiency under design conditions. 

• The multi-pollutant control system achieved the performance target of ≥90% Hg removal efficiency during 

both short-term and long-term testing. No activated carbon injection was required to achieve this removal 

efficiency. The average coal-to-stack Hg removal efficiency measured during 29 tests without activated 

carbon injection between March 2007 and June 2008 was 98%. 

• The multi-pollutant control system achieved the performance target of ≥95% SO3 and HCl removal efficiency 

during both short-term and long-term testing. The average SO3 removal efficiency observed during 42 tests 

between May 2007 and June 2008 was 95.3%, and the average HCl removal efficiency observed during 30 

tests between March 2007 and June 2008 was 96.7%. HF concentrations measured at the Turbosorp® inlet 

and stack were too low to demonstrate attainment of the performance target of ≥95% HF removal efficiency. 

• Replacement of the unit’s old electrostatic precipitator (ESP) with the Turbosorp®

 system, which includes a 

new baghouse, reduced its PM emissions by 98%, to <0.001 lb/mmBtu. 

• The multi-pollutant control system achieved the performance target for high-load NOx emissions of ≤0.10 

lb/mmBtu during short-term (guarantee) testing, but it did not meet this goal during long-term operation. The 

average high-load NOx emission rate observed during 14 months of commercial operation (August 2007 – 

September 2008) was 0.14 lb/mmBtu. The increase in NOx emissions between the guarantee tests and the 

long-term evaluation period occurred because AES Greenidge had to reduce the aggressiveness of low-NOx

firing in order to attain suitable combustion characteristics for routine operation. Nevertheless, overall NOx

emissions (lb/mmBtu) were reduced by about 52% relative to the pre-project baseline. 

• Operation of the multi-pollutant control system was hindered by the accumulation of large particle ash (LPA) 

in the in-duct SCR catalyst, which caused numerous outages for catalyst cleaning during the first year of 

operation. However, the severity of the problem was reduced by the installation of an LPA removal system 

(outside of the scope of the DOE project), including a screen, soot blowers, and vacuum ports. Additional 

operating experience is needed to confirm the long-term effectiveness of this system. 

• Ammonia slip from the hybrid SNCR/SCR system was generally greater than expected during the first yearand-a-half of operation. Although the targeted ammonia slip of ≤2 ppmvd @ 3% O2 was demonstrated 

during guarantee testing, ammonia concentrations averaged 4.6 ppmvd over the course of 26 ammonia slip 

measurements that were performed at intermediate or high loads between October 2007 and June 2008. 

The higher-than-expected ammonia slip has not significantly affected plant operations, however. 

• The retrofit difficulty associated with the installation of the multi-pollutant control system at AES Greenidge 

Unit 4 was low. The system required a footprint of only ~ 0.4 acre and was able to be integrated with the unit 

during a seven-week tie-in outage. No major problems were encountered during construction. 

• The multi-pollutant control system affords lower capital costs in exchange for somewhat greater variable 

operating and maintenance (O&M) costs relative to conventional technologies that are capable of achieving 

deep reductions in NOx and SO2. The capital cost ($2005) for the multi-pollutant control system at AES 

Greenidge Unit 4 (including the combustion modifications and LPA removal system, which were installed 

outside of the DOE scope) was ~$349/kWnet, which is about 40% less that the estimated cost to retrofit the 

unit with conventional SCR and wet FGD systems. Fixed and variable O&M costs for the multi-pollutant 

control system total ~$7.95/MWh, and the costs for urea, lime, and waste disposal, which figure into the 

unit’s dispatch calculations, are ~$5.58/MWh. Mercury, acid gas, and primary particulate matter control are 

co-benefits of the NOx and SO2 control systems and add no incremental cost. 

• Operation and maintenance of the multi-pollutant control system were handled by existing AES Greenidge 

plant personnel. AES is able to run Unit 4, including the multi-pollutant control system, with 3-4 operators 

per shift, as was the case prior to the project. Apart from the LPA problem, most of the maintenance 

requirements during the first year-and-a-half of operation involved the lime hydration system and the ash 

disposal and recirculation system. These were usually resolved without impacting operation of the 

Turbosorp®

 system, and actions have been taken to minimize their recurrence. 

• No major problems were encountered with byproduct disposal. The only significant byproduct from the 

multi-pollutant control system is the product ash from the Turbosorp®

 system. AES Greenidge generally 

disposes of the product ash at a landfill adjacent to the plant site, although 3,500 tons were provided for use 

as fill material in a local construction project. 

The commercial viability of the multi-pollutant control system was demonstrated during more than a year-and-ahalf of routine operation at AES Greenidge Unit 4. The system, which remains in service after the conclusion of 

the project, has enabled the unit to satisfy its permit requirements while continuing to operate profitably. As a 

result of the success at AES Greenidge, three additional deployments of the Turbosorp®

 technology had been 

announced by the end of the project.
 3

2. Introduction 

The Greenidge Multi-Pollutant Control Project was conducted under U.S. Department of Energy 

Cooperative Agreement No. DE-FC26-06NT41426 to demonstrate the full-scale, retrofit 

application of a multi-pollutant control system that is designed to reduce emissions of NOx, SO2, 

Hg, particulate matter, and acid gases, including SO3, HCl, and HF, from coal-fired units with 

capacities of 50–600 MWe. The multi-pollutant control system, which includes the combination 

of a NOxOUT CASCADE® hybrid selective non-catalytic reduction / selective catalytic reduction 

system and a Turbosorp® circulating fluidized bed dry scrubbing system with baghouse ash 

recycling and activated carbon injection, was installed and tested on the coal-fired, 107 MWe

AES Greenidge Unit 4 (Boiler 6) in Dresden, New York. The project was part of the DOE’s 

Power Plant Improvement Initiative, with an overall objective of demonstrating that the 

combination of technologies installed at AES Greenidge provides an affordable means for 

achieving deep reductions in the emissions of a number of pollutants from smaller coal-fired 

electric generating units, allowing these units to continue to produce low-cost, reliable electricity 

in an environment of increasingly stringent air emissions regulations. 

2.1 The Power Plant Improvement Initiative 

The Power Plant Improvement Initiative was established on October 11, 2000, under U.S. 

Public Law 106-291 to foster the commercial demonstration of coal-based technologies capable 

of improving the efficiency, cost-competitiveness, and environmental performance of new and 

existing electric generating facilities in the United States. A follow-on to the Clean Coal 

Technology Demonstration Program (CCTDP) that was implemented successfully in the 1980s 

and 1990s, the PPII is a cost-shared collaboration between government and industry, supported 

by $95 million in federal funding transferred from the CCTDP program, that seeks to help 

ensure the reliability of the nation’s energy supply. The Greenidge Multi-Pollutant Control 

Project was one of eight projects selected for negotiation under the PPII solicitation issued in 

February 2001, and one of five that were awarded cooperative agreements by the DOE. All of 

these projects focused on technologies that can be quickly commercialized and are applicable 

to energy systems that utilize at least 75% coal, and all included participant cost shares of 50% 

or greater. The DOE’s National Energy Technology Laboratory manages the PPII projects. 

2.2 Project Motivation 

The Greenidge Multi-Pollutant Control Project responded to the objectives of the PPII by 

demonstrating a technology that is intended to help ensure the continued availability of reliable, 

low-cost electricity from the nation’s large asset base of smaller existing coal-fired power plants. 

Although the technology being demonstrated at AES Greenidge is applicable to units with 

capacities of 50-600 MWe, its potential benefits are greatest for units in the lower half of this size 

range. Figure 1 presents a map showing all of the coal-fired electric generating units with 

capacities of 50-300 MWe that are currently operating in the United States. There are currently 

about 400 operating coal-fired EGUs in this size range that are equipped with neither flue gas 

desulfurization nor selective catalytic reduction technologies, and a majority of these units have 

not announced plans for air pollution control retrofits. These 400 smaller coal-fired units 

represent more than 55 GW of installed electric generating capacity; hence, curtailment or loss 
 4

of their generation would further exacerbate electricity and natural gas supply and distribution 

problems throughout the United States. However, these EGUs are subject to progressively 

more rigorous environmental regulations at the state and federal levels. Conventional control 

technologies being installed on newer, larger EGUs, such as selective catalytic reduction and 

wet flue gas desulfurization, are capable of achieving the emission rates set forth in these 

regulations, but entail large capital investments and large space requirements that make them 

unattractive for this fleet of older, smaller EGUs. Hence, there is a strong need to demonstrate 

and commercialize technologies specifically designed to meet the environmental compliance 

requirements of these smaller coal-fired units. The Greenidge Multi-Pollutant Control Project 

seeks to demonstrate the commercial readiness of an emissions control system that is 

particularly suited, because of its relatively low capital and maintenance costs and compact 

size, to satisfy these requirements. 

Figure 1. Map of operating coal-fired EGUs in the United States with capacities of 50-300 MWe.

As discussed above, the multi-pollutant control system being demonstrated as part of the 

Greenidge Project comprises an innovative, integrated combination of technologies, including a 

NOxOUT CASCADE® hybrid SNCR/SCR system and a Turbosorp® circulating fluidized bed dry 

scrubbing system with a new baghouse, solid product recycling system, and activated carbon 

injection system. Both of these technologies were developed and tested individually at a 

sufficient scale prior to the project to provide an adequate level of confidence concerning their 

mechanical operability. However, the Greenidge Project is unique in that it represents the first 

application in which a hybrid SNCR/SCR system and a circulating fluidized bed dry scrubbing 

system were combined to form an integrated multi-pollutant control system, as well as the first 

application of either of these technologies to a unit firing >2%-sulfur eastern U.S. bituminous 

coal. Demonstrating the cost and emissions reduction performance of the multi-pollutant control 

system when applied to a unit firing high-sulfur coal was an essential component of the project, 

as more than 80% of the 400 smaller coal-fired EGUs referenced above are located east of the 

Mississippi River, where eastern U.S. bituminous coal is a likely fuel source, and where it is 

often economically attractive for scrubbed units to fire high-sulfur coals. Moreover, the NOxOUT 

CASCADE® and Turbosorp® systems at AES Greenidge were designed to achieve greater NOx
 5

and SO2 removal efficiencies, respectively, than any previous installations of these 

technologies, enabling them to better satisfy the emission reduction needs of smaller coal-fired 

EGUs in the face of increasingly stringent environmental regulations. 

Thus, the Greenidge Multi-Pollutant Control Project was motivated by the need to resolve 

uncertainties regarding the performance of the hybrid SNCR/SCR and Turbosorp® systems 

when combined in an integrated multi-pollutant control process, as well as the technical and 

economic performance of these systems when applied with ambitious performance targets to a 

unit firing eastern U.S. bituminous coals containing greater than 2% sulfur. It is hoped that, by 

resolving these uncertainties, the project will lead to wide commercial acceptance of the 

demonstration technology, which could significantly reduce emissions and help to extend the 

lives of many of the 400 smaller existing coal-fired EGUs identified above. 

2.3 Project Overview 

As part of the Greenidge Project, the multi-pollutant control system was retrofitted to AES 

Greenidge Unit 4, and its performance was demonstrated for more than a year-and-a-half of 

operation while the unit fired >2%-sulfur eastern U.S. bituminous coals in order to confirm its 

commercial viability. (The system continues to operate commercially at AES Greenidge 

following the conclusion of the DOE project). AES Greenidge Unit 4 is a 107 MWe (Energy 

Information Administration net winter capacity), 1953-vintage, tangentially-fired, reheat unit that 

fires pulverized eastern U.S. bituminous coal as its primary fuel. As such, it is representative of 

many of the 400 smaller coal-fired units identified above. Unit 4 can also co-fire biomass at up 

to 10% heat input, and the demonstration program included an evaluation of the effect of 

biomass co-firing on the performance of the multi-pollutant control system. Prior to the 

installation of the multi-pollutant control system, AES entered into a consent decree with the 

State of New York in which it was mandated that AES Greenidge must install technology to 

reduce NOx and SO2 emissions from Unit 4, repower the unit, or retire the unit. Whereas the 

installation of conventional SCR and wet FGD technologies would have been cost-prohibitive for 

the 107-MWe unit, the technologies installed as part of the Greenidge Multi-Pollutant Control 

Project provided AES with an affordable means for reducing emissions, enabling Unit 4 to 

continue to operate while reducing its environmental impact. 

The scope of the Greenidge Project encompassed the design, permitting, procurement, 

construction, start-up, operation, and performance testing of the multi-pollutant control system. 

Design work commenced in 2005; the system started up in early 2007, and the testing and 

operation period concluded in October 2008. The project was conducted by a team including 

CONSOL Energy Inc., AES Greenidge LLC, and Babcock Power Environmental Inc. CONSOL 

was the prime contractor under the DOE Cooperative Agreement and was responsible for 

managing and administering the overall project, testing and evaluating the performance of the 

multi-pollutant control system, and reporting project results. AES Greenidge, the host site, was 

a subcontractor to CONSOL and was responsible for site management, environmental 

permitting, and operation of the demonstration facility. BPEI was a subcontractor to AES 

Greenidge and was responsible for engineering, procurement, and construction (EPC) of the 

multi-pollutant control facility. The NOxOUT CASCADE® hybrid SNCR/SCR technology was 

supplied by Fuel Tech under subcontract to BPEI; the SCR reactor was supplied by BPEI, and 

the Turbosorp® circulating fluidized bed dry scrubbing technology was supplied by BPEI under 

license from Austrian Energy and Environment. All funding for the project was provided by the 

DOE (43.8%) and by AES Greenidge (56.2%). 
 6

2.4 Project Goals

As discussed above, the overall objective of the Greenidge Multi-Pollutant Control system was 

to demonstrate a multi-pollutant control system that can cost-effectively reduce emissions of 

NOx, SO2, Hg, SO3, HCl, HF, and particulate matter from smaller coal-fired EGUs. The specific 

goals of the project were to: 

• Demonstrate that the NOxOUT CASCADE® hybrid SNCR/SCR system, in combination with 

combustion modifications that were installed outside of the scope of the DOE cooperative 

agreement, can reduce high-load NOx emissions from the 107-MWe AES Greenidge Unit 4 

to ≤0.10 lb/mmBtu (a reduction of ≥60% following the combustion modifications) while the 

unit is firing >2%-sulfur coal and co-firing up to 10% biomass. 

• Demonstrate that the Turbosorp® circulating fluidized bed dry scrubber can remove ≥95% of 

the SO2 emissions from AES Greenidge Unit 4 while the unit is firing >2%-sulfur coal and 

co-firing up to 10% biomass. 

• Demonstrate ≥90% mercury removal via the co-benefits achieved by the SNCR/SCR and 

circulating fluidized bed dry scrubber (with baghouse) systems and, as required, carbon or 

other sorbent injection. 

• Demonstrate ≥95% removal of acid gases (SO3, HCl, and HF) by the Turbosorp® circulating 

fluidized bed dry scrubber. 

• Evaluate process economics and performance to demonstrate the commercial readiness of 

an emission control system that is suitable for meeting the emission reduction requirements 

of boilers with capacities of 50 MWe to 600 MWe. 

2.5 Purpose of this Report 

This final report is intended to serve as a stand-alone document that summarizes all of the 

publicly available information generated as part of the Greenidge Multi-Pollutant Control project. 

As such, it covers all facets of the project and incorporates information from the project’s 

quarterly progress reports, public design reports, and other topical reports, as well as additional 

performance testing results and other data that have not been previously presented. The report 

culminates with the overall conclusions of the project, which assess the extent to which the 

project succeeded in meeting the goals set forth above. 

3. Project Management 

As discussed in Section 2.3, CONSOL Energy Inc. was responsible for the overall management 

and administration of the Greenidge Multi-Pollutant Control Project. Site operations were 

managed by AES Greenidge, a subcontractor to CONSOL, and the engineering, procurement, 

and construction of the multi-pollutant control system were managed by Babcock Power 

Environmental Inc., a subcontractor to AES Greenidge. The National Energy Technology 

Laboratory managed the project for the U.S. Department of Energy and oversaw all project 

activities. 
 7

The project was organized into three phases and two budget periods. The first budget period 

included the Design and Procurement Phase (Phase 1) and the Construction Phase (Phase 2). 

The second budget period included the Operation and Testing Phase (Phase 3). Table 1 below 

summarizes the major project tasks under each phase and the organization primarily 

responsible for completing each task. 

Table 1. Summary of major project tasks. The organization with primarily responsibility for completing 

each task is indicated.

Budget Period 1 

 

 Phase 1. Design and Procurement 

 Pre-Award Activities CONSOL, AES Greenidge, BPEI 

 Task 1.1 Phase 1 Project Management CONSOL 

 Task 1.2 Total Process Definition and Design BPEI 

 Task 1.3 Equipment Procurement BPEI 

 Task 1.4 Environmental/Regulatory/Permitting AES Greenidge 

 Task 1.5 Environmental Information Volume CONSOL 

 Task 1.6 Baseline Testing CONSOL 

 Phase 2. Construction 

 Task 2.1 Phase 2 Project Management CONSOL 

 Task 2.2 General Civil/Structural Construction BPEI 

 Task 2.3 Process System Construction BPEI 

 Task 2.4 Plant Start-Up and Commissioning BPEI 

 

Budget Period 2 

 Phase 3. Operation and Testing 

 Task 3.1 Phase 3 Project Management CONSOL 

 Task 3.2 Plant Operations AES Greenidge 

 Task 3.3 Testing and Evaluation CONSOL 

 Task 3.4 Final Reporting CONSOL 

A project kickoff meeting was held at NETL in Pittsburgh on July 27, 2006, shortly after the 

signing of the cooperative agreement, during which representatives from DOE, CONSOL, AES, 

and BPEI reviewed the project’s work plan. Project status meetings were held at AES 

Greenidge periodically throughout the project performance periods to evaluate project progress 

and discuss any problems or changes in plans. These meetings included a review of important 

project management items, including schedule, budget, communications, and safety. Moreover, 

the project team employed earned value management and risk management methodologies, as 

required by DOE, to objectify the project status evaluation process, inform project decisionmaking, and identify potential problems for mitigation. These project management topics are 

described in more detail in the following subsections. 

3.1 Schedule 

Appendix A presents the overall project schedule for the Greenidge Multi-Pollutant Control 

Project, which indicates both the baseline start and end dates and the actual start and end 

dates for major project tasks and selected subtasks. The schedule for design, procurement, 

and construction activities was driven largely by AES Greenidge’s major outage in OctoberNovember 2006, during which tie-in of the multi-pollutant control system to the existing plant 

was completed. The timing of that outage was motivated by AES Greenidge’s consent decree 
 8

with the State of New York and by their dispatch obligations during peak power seasons. 

Hence, although the cooperative agreement between the U.S. Department of Energy and 

CONSOL Energy Inc. for the project was executed on May 19, 2006, a substantial amount of 

work was performed prior to the signing of that agreement in accordance with pre-award 

authorizations granted by the DOE. (These authorizations allowed the project team to incur 

costs associated with certain tasks under the cooperative agreement at its own risk, prior to the 

signing of the agreement, such that DOE would only reimburse those costs at the agreed-upon 

cost share if the parties succeeded in executing the agreement). This pre-award work included 

completion of environmental assessments required by the National Environmental Policy Act 

(NEPA), which culminated in the issuance of a Finding of No Significant Impact (FONSI) in 

December 2004, completion of baseline testing at AES Greenidge in November 2004, and 

commencement of design, procurement, and certain construction activities in 2005. As shown 

in Appendix A, site preparation work for the multi-pollutant control system began in late 2005, 

and process system construction began during the first quarter of 2006. The tie-in outage was 

completed on schedule on November 18, 2006. However, start-up and commissioning of the 

multi-pollutant control system took longer than expected, delaying the start of performance 

testing by about 2.5 months (until March 26, 2007). The project’s Testing and Evaluation task 

(Task 3.3) included three major test series: the Guarantee Tests (designed to evaluate whether 

the multi-pollutant control system satisfied its performance guarantees), the Process 

Performance Tests (designed to evaluate the performance of the multi-pollutant control system 

as a function of changes in unit operating conditions), and the Follow-Up Tests (designed to 

evaluate the performance of the multi-pollutant control system after a year of routine operation). 

The completion of the Guarantee Tests (and commencement of the Process Performance 

Tests) was further delayed when several re-tests were required to demonstrate attainment of 

the performance guarantee for ammonia slip, and the Process Performance Tests were delayed 

on several occasions by problems resulting from the accumulation of large particle ash in the induct SCR reactor. (These problems and their resolution are discussed in detail later in this 

report). Nevertheless, the delayed Process Performance Test campaigns were able to be 

completed during the approximately year-long period between the Guarantee Tests and FollowUp Tests, and field sampling for the Follow-Up Tests was completed in June 2008 as originally 

planned. The project concluded on October 18, 2008, according to schedule. 

Prior to the signing of the cooperative agreement, six milestones (two per calendar year) were 

selected from the project’s critical path to serve as a baseline for tracking overall project 

progress. These critical path project milestones are identified in Table 2. As shown in the table, 

all of the critical path project milestones were met on or ahead of schedule, leading to the timely 

completion of the project. 

3.2 Budget 

Table 3 summarizes the overall project budget for the Greenidge Project and the actual project 

cost through the end of October 2008. The total budgeted cost for Budget Period 1 (i.e., the 

Design and Procurement Phase and the Construction Phase) was $28,390,348, and the total 

budgeted cost for Budget Period 2 (i.e., the Operation and Testing Phase) was $4,352,628, for 

a total planned project cost of $32,742,976. The U.S. Department of Energy contributed 43.8% 

of these costs, and AES Greenidge contributed the remaining 56.2%. 

As shown in the table, actual project expenditures through the end of October 2008 were 

$1,866,851 greater than the total budgeted project cost. This variance arose largely because 
 9

costs for consumables (i.e., lime and urea) during the Operation and Testing Phase 

substantially exceeded the originally budgeted cost, owing to significant price escalation that 

occurred after the baseline cost plan was developed. There was $4,371 of available DOE 

funding remaining at the end of October 2008. These funds were reserved for completing the 

final report for the project. 

Table 2. Greenidge Project milestone plan showing planned and actual completion dates for critical path 

project milestones.

Critical Path 

Project 

Milestone 

Project Duration - Start: 5/19/06 End: 10/18/08 

Planned 

Date 

Actual 

Date 

2006 2007 2008

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 

Initiate scrubber 

system installation A P 9/30/06 5/30/06 

Commence tie-in 

outage A P 12/31/06 9/29/06 

Begin guarantee / 

performance testing P 

A 3/31/07 3/28/07 

Begin routine plant 

operation and data 

collection for longterm testing 

 P 

A 6/30/07 6/21/07 

Begin follow-up 

testing P A 6/30/08 6/10/08 

Complete analyses 

of process 

performance and 

economics 

 P 

A 9/30/08 9/30/08 

NOTE: “A” indicates actual completion; “P” indicates planned completion. 

Table 3. Overall project budget and actual project cost through October 2008. 

Budgeted Cost Total Actual Cost 

(through 

Budget Period 1 Budget Period 2 Total 10/2008) 

DOE Share $12,434,972 $1,906,451 $14,341,423 $14,337,052 

AES Greenidge Share $15,955,376 $2,446,177 $18,401,553 $20,272,775 

TOTAL $28,390,348 $4,352,628 $32,742,976 $34,609,827 

The budgeted cost for Budget Period 1, which included engineering, procurement, and 

construction of the multi-pollutant control system, is less than the total plant cost presented in 

the Process Economics section (Section 11) of this report. This discrepancy arose because 

certain costs (e.g., for the combustion modifications, large particle ash removal system, and 

several subcontracts) were excluded from the DOE budget but included in the reported capital 

cost because they were considered to be essential to the successful installation of the multipollutant control system. Hence, the process economics presented in Section 11 of this report 

are more indicative of the costs associated with the multi-pollutant control system at AES 

Greenidge than are the budget data presented in Table 3. 
 10

3.3 Earned Value Management 

The project’s schedule and budget performance were evaluated routinely throughout the project 

using earned value management methodology. Earned value management is a project 

management tool that provides an objective, integrated means for measuring schedule and 

financial progress, as compared to the initial project plan. As such, it provides project managers 

with visibility into cost and schedule performance and enables them to more effectively measure 

and manage project performance. It is based on the following principles (U.S. DOE, 2005): 

• All work is planned to completion. 

• The work is broken down into finite product-oriented components that can be assigned 

to a responsible organization. 

• The scope, schedule, and cost objectives are integrated into a plan by which progress 

can be measured. 

• Actual costs are recorded. 

• Performance is objectively measured. 

• Variances and deviations are analyzed, impacts are forecasted, and estimates at 

completion are based on the actual performance to date. 

• Changes to the performance measurement baseline are controlled. 

• Earned Value information is employed in the organization’s management process. 

Earned value management practices were implemented soon after the cooperative agreement 

for the Greenidge Project was signed. The project’s scope, schedule, and budget were 

integrated, such that the schedule set forth a plan for completing each task in the scope of work, 

and broke these tasks into measurable, product-oriented subtasks. (In many cases, milestones 

were used to provide measurable subtasks). The anticipated cost associated with each subtask 

– i.e., its Planned Value (PV) - was then determined, such that the sum of the PV for all 

subtasks equaled the total project budget. In this way, a baseline cost and schedule plan was 

developed that established the relationships between costs, time, and work products. 

Each month during the project period, the Actual Cost (AC) incurred during that month (i.e., the 

total of the funds actually spent for work that was completed) was determined from the 

participants’ accounting systems. In addition, the Earned Value (EV) was derived by computing 

the originally budgeted value of the work actually accomplished during that month. (For 

example, envision a hypothetical scenario in which $10,000 was originally budgeted for a 

particular subtask during the month of March. If the subtask was only 75% complete at the end 

of March, and $8,000 was spent on that subtask during March, then that subtask would have a 

Planned Value of $10,000, an Actual Cost of $8,000, and an Earned Value of $7,500 for March). 

The project’s cost performance and schedule performance were evaluated using the Planned 

Value, Actual Cost, and Earned Value data. The Schedule Performance Index (SPI) and Cost 

Performance Index (CPI) were computed as follows: 

 SPI = EV / PV (1) 

 CPI = EV / AC (2) 

By utilizing the concept of earned value, these indices are able to separate the effects of budget 

variances from the effects of schedule variances. If the SPI equals one, then the project is on 

schedule. An SPI greater than one indicates that the project is ahead of schedule, and an SPI 

less than one indicates that the project is behind schedule. Similarly, if the CPI equals one, 
 11

then the project is on budget. A CPI greater than one indicates that the project is under budget, 

and a CPI less than one indicates that the project is over budget. (Hence, in the example 

above, the subtask’s SPI for March would be $7,500 / $10,000 = 0.75, and the subtask’s CPI for 

March would be $7,500 / $8,000 = 0.94, indicating that the subtask is progressing at only 75% 

of the planned rate and getting only $0.94 of work accomplished for every $1.00 spent). 

Earned value management calculations were performed each month by CONSOL using a 

spreadsheet-based system. Trends and variances in the SPI and CPI were evaluated, and the 

results were reported to DOE. Figure 2 shows the project’s cumulative monthly PV, AC, and EV 

for the entire project period, and Figure 3 shows its cumulative monthly SPI and CPI for the 

same period. (The earned value management system was implemented in July 2006 using May 

2006 data; however, calculations were performed retrospectively through October 2005, when 

much of the design, procurement, and construction work under the EPC contract began). 

$0

$5,000,000

$10,000,000

$15,000,000

$20,000,000

$25,000,000

$30,000,000

$35,000,000

$40,000,000

Sep-05Oct-05Nov-05Dec-05Jan-06Feb-06Mar-06Apr-06May-06Jun-06Jul-06Aug-06Sep-06Oct-06Nov-06Dec-06Jan-07Feb-07Mar-07Apr-07May-07Jun-07Jul-07Aug-07Sep-07Oct-07Nov-07Dec-07Jan-08Feb-08Mar-08Apr-08May-08Jun-08Jul-08Aug-08Sep-08

Planned Value Actual Cost Earned Value

Figure 2. Cumulative monthly Planned Value, Actual Cost, and Earned Value for the Greenidge MultiPollutant Control Project. 

As illustrated in these figures, the Greenidge Project fell behind schedule in late 2005 and early 

2006, as the project participants were working to finalize the DOE cooperative agreement. The 

schedule performance improved during the spring and summer of 2006, when much of the 

construction work was completed, and it was about 96% on schedule during the heart of the tiein outage in October 2006. The project fell behind schedule again during the first half of 2007, 

when start-up and commissioning of the multi-pollutant control system took longer than 

expected and performance testing activities were delayed by the large particle ash and 

ammonia slip issues referenced in Section 3.1. The delayed activities were accomplished 
 12

during 2007 and early 2008, however, and the SPI returned to 1.00 by September 2008, 

consistent with the on-schedule completion of the project in October 2008. 

0.75

0.80

0.85

0.90

0.95

1.00

1.05

1.10

1.15

1.20

1.25

Sep-05Oct-05Nov-05Dec-05Jan-06Feb-06Mar-06Apr-06May-06Jun-06Jul-06Aug-06Sep-06Oct-06Nov-06Dec-06Jan-07Feb-07Mar-07Apr-07May-07Jun-07Jul-07Aug-07Sep-07Oct-07Nov-07Dec-07Jan-08Feb-08Mar-08Apr-08May-08Jun-08Jul-08Aug-08Sep-08

Schedule Performance Index Cost Performance Index

Figure 3. Cumulative monthly Schedule Performance Index and Cost Performance Index for the 

Greenidge Multi-Pollutant Control Project. 

The cost performance index remained close to one throughout the project period, because the 

EPC contract, which represented a large portion of the total project cost, was paid on the basis 

of fixed price milestones. The project was slightly under budget during the design, procurement, 

and construction periods, but it ran slightly over budget during the operation and testing period 

in 2007 and 2008, owing to the cost overruns for consumables that were discussed in Section 

3.2. The project was about 6% over budget when it concluded in October 2008. 

3.4 Communications 

The success of the Greenidge Project depended in part upon effective communication among 

the project team. The project’s status, accomplishments, problems, and results were 

communicated to the DOE and to project team members by way of weekly, monthly, and 

quarterly reports. Moreover, as discussed above, earned value management results were 

communicated on a monthly basis, and project status meetings were held periodically to 

promote open dialogue among project participants. 

Project results were also communicated to the public via several topical reports, including the 

Preliminary Public Design Report (issued in May 2007), Guarantee Testing Report (issued in 
 13

March 2008), and Final Public Design Report (issued in November 2008). The project team 

published a magazine article on the project and presented project results at 12 technical 

conferences. These publications and conference proceedings are listed in the Project 

Bibliography included at the end of this report. Finally, press releases were issued to publicize 

the project; tours were conducted at AES Greenidge to showcase the project to parties with an 

interest in acquiring the demonstration technology, and technical presentations were given at 

several luncheon meetings to raise awareness of the project. This Final Report is the last and 

most comprehensive piece of the project’s communication plan. 

3.5 Risk Management 

To identify and mitigate potential project problems, the project team employed risk management 

practices. The Project Risk Assessment was developed and maintained by the DOE Federal 

Project Manager, with input from DOE, CONSOL, and AES Greenidge. Specific project risks 

were identified in the following six areas: 

1. Financial 

2. Cost / schedule 

3. Technical / scope 

4. Management, planning, and oversight 

5. Environmental, safety, and health 

6. External influences 

For each identified risk, the degree of risk (low, moderate, or high) was determined by 

considering the probability of occurrence and potential impact, and response and mitigation 

strategies were developed. An overall project risk potential was also determined by scoring the 

overall risk associated with each of the six areas listed above and aggregating these scores. 

Project risks were identified and mitigation strategies were developed during meetings among 

DOE, CONSOL, and AES Greenidge in June 2006, September 2006, November 2006, 

February 2007, May 2007, September 2007, January 2008, and August 2008. (The frequency 

of these risk discussions decreased during the latter portion of the project, as the number, 

probability, and potential impact of project risks declined). This risk management framework 

helped to ensure that project risks and mitigation strategies were updated to reflect project 

progress and were transparent to the entire project team. 

3.6 Safety 

Safety was a top priority during the Greenidge Multi-Pollutant Control Project. Contractors were 

not permitted to work at the AES Greenidge site until they completed the plant’s contractor 

safety training program. Annual renewal of this safety training was required. AES Greenidge 

monitored contractor safety performance throughout the construction period, and any deviations 

from the plant’s safety policies were corrected immediately. In November 2007, BPEI trained all 

AES Greenidge personnel in the safe operation and maintenance of the multi-pollutant control 

system. Plant personnel reviewed project safety issues during weekly safety meetings that 

were held routinely throughout the project period. Prior to each field sampling campaign at AES 

Greenidge, CONSOL held a preparation meeting during which safety policies and procedures 

were reviewed with all members of the sampling team. 
 14

During the construction period in 2006, there were two recordable incidents associated with the 

project, one of which was a lost time accident. The lost time accident occurred when a 

construction worker bumped his knee. The other recordable incident occurred when a welder, 

who was wearing all required safety equipment, was struck in the head by a pry bar and needed 

stitches. During the operation and testing period in 2007 and 2008, there were three recordable 

incidents associated with the project. None of these were lost time accidents. (The recordable 

incidents in 2007 and 2008 did not occur within the scope of the DOE funding, but all were 

related to the multi-pollutant control system). The first recordable incident during the Operation 

and Testing Phase occurred when a contractor hit his forehead on a steel lug while changing 

the catalyst in the SCR reactor. The second incident occurred when a worker’s finger was 

pinched by an automatically operated air cylinder, resulting in a laceration that required stitches. 

The third incident occurred when a worker who was wearing proper eye protection sustained a 

possible eye laceration caused by a particle of lime that fell through the grating near the lime 

hydration system. All recordable incidents were properly reported; causes were identified, and 

corrective actions were implemented to prevent recurrence. 

4. Technology Overview

As discussed in Section 2, the multi-pollutant control system that was demonstrated as part of 

the Greenidge Project comprises an innovative combination of technologies that were applied in 

a unique way and integrated for the first time at AES Greenidge Unit 4. This section provides a 

general, comprehensive overview the demonstration technology, covering important design 

features and considerations as well as the developmental status of the technology prior to the 

Greenidge Project. The specifics of the design for the AES Greenidge Unit 4 application are 

covered in Section 6 of this report. 

4.1 Process Concept 

Figure 4 presents a schematic of the multi-pollutant control process that was demonstrated as 

part of the Greenidge Multi-Pollutant Control Project. The process integrates three major 

components: NOx control via a NOxOUT CASCADE® hybrid SNCR/SCR system; SO2, SO3, HCl, 

HF, and particulate matter control via a Turbosorp® circulating fluidized bed dry scrubbing 

system with a baghouse and solid product recycling; and mercury control via activated carbon 

injection and the co-benefits afforded by the NOx control and Turbosorp® systems. General 

process chemistry and engineering concepts for each of these components are described 

below. 

4.1.1 NOx Control 

NOx control is the first step in the multi-pollutant control process and is accomplished using 

urea-based, in-furnace selective non-catalytic reduction followed by a single-layer, in-duct 

selective catalytic reduction reactor that is fed by ammonia slip from the SNCR process. 

Although not an essential component of the multi-pollutant control process, for certain 

applications, such as that on AES Greenidge Unit 4, it may be advantageous to complement the 
 15

hybrid SNCR/SCR system with combustion modifications designed to achieve further reductions 

in NOx emissions and to improve the performance of the hybrid SNCR/SCR system. 

Urea 

Dilution / 

Distribution 

Modules

APH

Boiler

Urea Tank

Baghouse

Quick 

Lime 

Silo

Hydrated 

Lime

Silo Hydrator

Activated

Carbon

Bin

H2O

Stack

Dry Residue

SCR

1 Bed

SNCR

Air

Dilution

Water

Fluidized

Bed

Absorber

To 

Disposal

Clean Flue 

Gas

Flue Gas Recycle (Reduced Loads)

Booster 

Fan

Existing 

ID Fans

Coal 

Biomass

Urea 

Dilution / 

Distribution 

Modules

APH

Boiler

Urea Tank

Baghouse

Quick 

Lime 

Silo

Hydrated 

Lime

Silo Hydrator

Activated

Carbon

Bin

H2O

Stack

Dry Residue

SCR

1 Bed

SNCR

Air

Dilution

Water

Fluidized

Bed

Absorber

To 

Disposal

Clean Flue 

Gas

Flue Gas Recycle (Reduced Loads)

Booster 

Fan

Existing 

ID Fans

Coal 

Biomass

Figure 4. Schematic of the multi-pollutant control process that was demonstrated as part of the 

Greenidge Project.

In the SNCR process, aqueous urea (CO(NH2)2) is atomized and injected into the furnace above 

the combustion zone. The relatively high temperatures in the furnace promote dissociation of 

the urea into reactive radicals (e.g., NH2, NCO), which react with nitrogen oxide and oxygen to 

form molecular nitrogen, carbon dioxide, and water, according to the following overall reaction: 

 CO(NH2)2 + 2 NO + 1⁄2 O2 → 2 N2 + CO2 + 2 H2O (3) 

The performance of a urea-based SNCR system can be quantified by computing its urea 

utilization, which is defined as: 

Urea Utilization (%) = [NOx Reduction (%)] ÷ NSR, (4)

where NSR is the normalized stoichiometric ratio, computed as: 

 NSR = 2 · [moles urea] ÷ [moles inlet NOx] (5) 

Hence, if the system achieves a NOx reduction that is stoichiometrically equivalent to the 

amount of urea injected (i.e., if the number of moles of NOx removed is twice the number of 

moles of urea injected), then the urea utilization is 100%. If the NOx removal is less than 
 16

stoichiometrically equivalent to the amount of urea injected, then the urea utilization is 

correspondingly less than 100%. 

In practice, urea utilization by SNCR systems is typically much less than 100% (e.g., 30 – 60 %, 

Albanese et al., 2005), in part because of restrictions on the amount of allowable ammonia slip 

from these systems. NOx reduction according to reaction (3) occurs over a temperature range 

of approximately 1400 °F to 2200 °F; however, the reaction is temperature-sensitive within this 

range, as illustrated in Figure 5. Ammonia is a byproduct of urea-based SNCR; the amount of 

ammonia produced by the process decreases as temperature increases. Because the amount 

of allowable NH3 slip is generally limited to 2-10 ppmv or less for coal-fired EGU applications, 

conventional stand-alone SNCR installations are typically designed to operate at relatively high 

temperatures that produce low amounts of ammonia slip. At these high temperatures, though, 

SNCR performance is adversely affected by competing reactions that consume the urea 

reagent or oxidize reagent to form additional NOx, resulting in less-than-optimal urea utilization. 

In a hybrid SNCR/SCR system, greater levels of ammonia slip from the SNCR process are 

actually desirable, as the ammonia produced via SNCR serves as the reagent to effectuate 

additional NOx removal in the downstream SCR reactor. As a result, the SNCR system in a 

hybrid process can be designed to operate at lower temperatures (e.g., 1650-1900 °F) than a 

stand-alone SNCR system would, resulting in improved urea utilization and greater NOx removal 

by the SNCR system, as well as sufficient NH3 slip to permit additional NOx reduction via SCR. 

Lower-temperature urea injection is accomplished in the hybrid SNCR/SCR system by including 

some injectors in upper sections of the furnace and in the convective pass. 

1300 1500 1700 1900 2100 2300

Temperature (o

F)

NOx Removal / Urea Injected Ammonia Slip

SNCR/SCR SNCR

1300 1500 1700 1900 2100 2300

Temperature (o

F)

NOx Removal / Urea Injected Ammonia Slip

SNCR/SCR SNCR

Figure 5. Conceptual depiction of the effect of temperature on urea utilization and 

ammonia slip in SNCR, and the implications of this effect for hybrid SNCR/SCR 

design.

The flue gas exiting the furnace, which contains unreacted NOx (primarily NO) and NH3

produced by the SNCR process, next flows through a compact SCR reactor containing a single 

catalyst layer that is installed in a modified section of the ductwork between the unit’s 

economizer and air heater. The single-layer, in-duct SCR operates with the same process 

chemistry as a standard full-size SCR. Nitrogen oxides in the flue gas are reduced by ammonia 
 17

(or by isocyanic acid, HNCO, which is also formed as part of the SNCR process) in the 

presence of a catalyst to form molecular nitrogen and water according to the following reactions: 

4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (6) 

NO + NO2 + 2 NH3 → 2 N2 + 3 H2O (7) 

4 NO + 4 HNCO + O2 → 4 N2 + 4 CO2 + 2 H2O (8) 

Because the SCR is fed by NH3 slip resulting from SNCR, it does not require the NH3 storage 

and handling system and NH3 injection grid that are typically needed for stand-alone SCR 

installations. Otherwise, the in-duct SCR utilizes the same technology as a standard full-size 

SCR, except that it is installed in a modified section of the ductwork between the unit’s existing 

economizer and air heater(s), where flue gas temperatures (approximately 650 °F for the AES 

Greenidge Unit 4 application at full load) are in the optimum range for the SCR reactions to 

occur. Because of its small size, the amount of NOx reduction achievable by the in-duct SCR is 

less than the amount achievable by a stand-alone SCR. However, unlike a stand-alone SCR, 

the purpose of the in-duct SCR in the hybrid system is to consume ammonia slip in order to 

permit enhanced NOx reduction by the upstream SNCR, while also affording incremental NOx

reduction. 

To maximize performance of the relatively small, in-duct SCR system, BPEI’s Delta WingTM 

static mixing technology is installed in the ductwork just upstream of the SCR reactor. As 

illustrated conceptually in Figure 6, the Delta WingTM technology utilizes stationary obstructions 

oriented at a slant to the direction of flow to create a zone of large, violent vortices that 

homogenize the velocity, temperature, and composition of the flue gas across the crosssectional area of the duct. For the in-duct SCR reactor, homogeneity in the distribution of NOx

and NH3 throughout the flue gas is desired to maximize the utilization of the available catalyst 

surface, thereby maximizing NOx reduction and minimizing NH3 slip. In addition, the static 

mixers are designed to maintain ash entrainment and distribution across the cross-sectional 

area of the reactor, minimizing catalyst deactivation and pressure drop via fly ash plugging. For 

units such as AES Greenidge Unit 4 that produce large particle ash, a screen and/or other LPA 

removal equipment is also required upstream of the SCR reactor in order to prevent LPA from 

accumulating in the catalyst. 

Static Mixer Vortex Circulation

Flue Gas

Figure 6. Conceptual illustration of the Delta WingTM static 

mixing technology.
 18

Major process components for the hybrid SNCR/SCR system include urea storage equipment, 

urea delivery, metering, and distribution equipment, urea injection equipment, static mixers, LPA 

removal equipment (if required), SCR catalyst, duct modifications and catalyst support, and 

miscellaneous process control equipment. In addition, sonic horns and/or rake soot blowers are 

used to prevent ash buildup on top of the SCR catalyst. For the AES Greenidge Unit 4 

installation, flue gas bypasses are not required around the economizer or the SCR catalyst, 

simplifying the design and operation of the system. 

4.1.2 SO2, SO3, HCl, HF, and Particulate Matter Control 

After exiting the SCR reactor and passing through the plant’s existing air heater(s), the flue gas 

is sent to the Turbosorp® circulating fluidized bed dry scrubbing system for removal of SO2, SO3, 

HCl, HF, and particulate matter. In the Turbosorp® system, the flue gas first enters the absorber 

vessel through a venturi nozzle. (The inlet to the absorber vessel may contain either a single 

venturi nozzle or multiple venturi nozzles, depending upon the volume of flue gas being treated). 

Water and hydrated lime (Ca(OH)2) are separately injected into the absorber above the venturi 

section. 

In the absorber vessel, the pollutant-laden flue gas is cooled in a fast fluidized bed of moistened 

particles, which include the injected hydrated lime as well as fly ash and reaction products. As 

the flue gas passes through the bed of particles, intimate contact is provided between the 

alkaline particles of hydrated lime and the acid gases contained in the flue gas. The surface 

moisture of these lime particles provides for liquid phase diffusion of the acid gases and contact 

with the lime in solution. This is a quick absorption mechanism and the one mainly responsible 

for neutralization of the acid gases. The large surface area of the particles in the bed also 

provides for rapid heat transfer. Thus, the particles are quickly dried as the flue gas passes 

through the bed, and the flue gas is evaporatively cooled to within 45 °F of its adiabatic 

saturation temperature. 

The acid gas constituents of the flue gas (SO2, SO3, HCl, HF, and to a lesser extent, CO2) are 

removed by reaction with hydrated lime. Each of these acid gas constituents produces a 

calcium-based salt and excess water when contacted with the alkaline Ca(OH)2 reagent. Sulfur 

dioxide and trioxide form calcium sulfite and sulfate hydrates. The halides, HCl and HF, form 

calcium chloride and fluoride, respectively. Some CO2 reacts to form calcium carbonate. These 

reactions are summarized below: 

Ca(OH)2 + SO2 ↔ CaSO3 · 1⁄2 H2O + 1⁄2 H2O (9) 

Ca(OH)2 + SO3 ↔ CaSO4 · 1⁄2 H2O + 1⁄2 H2O (10) 

CaSO3 · 1⁄2 H2O + 1⁄2 O2 ↔ CaSO4 · 1⁄2 H2O (11) 

Ca(OH)2 + 2 HCl ↔ CaCl2 + 2 H2O (12) 

Ca(OH)2 + 2 HF ↔ CaF2 + 2 H2O (13) 

Ca(OH)2 + CO2 ↔ CaCO3 + H2O (14) 

After exiting the absorber vessel, the dry, solid products (i.e., fly ash, unreacted hydrated lime, 

CaSO3, CaSO4, CaCO3, CaCl2, and CaF2) are separated from the flue gas in a baghouse, which 

is an integral part of the Turbosorp® system. (Although water is injected into the absorber 

vessel and formed by the reactions in the absorber, the flue gas remains unsaturated). To 

maximize acid gas removal and reagent utilization, most (e.g., ≥95%) of these solids are 

recycled via gravity to the absorber vessel using air slides. Upon reentering the absorber, the 
 19

sulfite-coated surfaces of partially reacted Ca(OH)2 particles are moistened, causing the calcium 

sulfite to form needle-like crystals. This crystallization exposes fresh Ca(OH)2 surface, 

permitting additional reaction with acid gases and hence greater reagent utilization. Recycle of 

the baghouse solids provides ample residence time for sorbent reactivation and reaction with 

Ca(OH)2 according to this mechanism. 

In addition to removing the acid gas constituents of the flue gas, the circulating fluidized bed dry 

scrubbing system enhances removal of particulate matter. For plants that are currently 

equipped with an electrostatic precipitator, installation of a baghouse is expected to improve fine 

particulate matter (PM2.5) capture efficiency. Moreover, the fluidized particle bed in the absorber 

vessel promotes particle agglomeration via collisions among particles, resulting in larger 

particles that can be captured more easily in the baghouse. Agglomeration is further enhanced 

by the water that is injected for flue gas humidification, which tends to increase the cohesion of 

the particles. 

 

Major components of the Turbosorp® system include the absorber vessel, hydrated lime storage 

and injection system, water storage and injection system, baghouse, solid product recycle and 

disposal system, and miscellaneous process control equipment. An onsite lime hydrator can be 

included as part of the installation to produce the required hydrated lime reagent from pebble 

lime, or the hydrated lime can be delivered to the site for direct use in the process. In addition, 

as shown in Figure 4, a flue gas recycle system may be included to provide sufficient flue gas 

flow to maintain a fluidized bed in the absorber at low load operation. Figure 7 presents a 

schematic of the Turbosorp® system highlighting the flow of solids, liquids, and gases through 

the process. 

Hydrated 

Lime

Water

Flue Gas

To Disposal

To Stack Hydrated 

Lime

Water

Flue Gas

To Disposal

To Stack

Figure 7. Schematic of the Turbosorp® circulating fluidized bed dry 

scrubbing system. Red, blue, and green arrows indicate the paths 

of solids, liquids, and gases, respectively, through the system.

The process is totally "dry", meaning that it introduces the reagent as a dry, free-flowing powder 

and produces a dry, free-flowing disposal product. The absorber operates not only as a 
 20

chemical reactor but also as an evaporative cooler. Surface humidity of particles within the 

fluidized bed is held nearly constant by introducing the water independently from the 

recirculated solids and fresh hydrated lime. This reduces the potential for scaling relative to wet 

and semi-dry processes. Water injection, reagent injection, and bed recirculation are 

independent unit operations. Thus, the process allows reagent injection rates that are a 

function of pollutant loading and emission targets. 

4.1.3 Mercury Control 

Mercury control in the multi-pollutant control system is accomplished via the co-benefits 

afforded by the in-duct SCR, circulating fluidized bed dry scrubber, and baghouse and, if 

required, by the injection of activated carbon just upstream of the scrubber. 

From a mercury control perspective, the Greenidge multi-pollutant control process is very similar 

to a conventional air pollution control configuration comprising an SCR, spray dryer, and 

baghouse. Measurements have demonstrated that this configuration, when applied to plants 

firing bituminous coal, achieves a high level of mercury removal (i.e., 89-99%) without the need 

for any mercury-specific control technology (Withum, 2006; Miller et al., 2006). This high level 

of removal likely results from a combination of factors, including the conversion of elemental 

mercury (Hg0

) to oxidized mercury (Hg2+) across the SCR catalyst (Presto and Granite, 2006), 

the removal of Hg2+ (a Lewis acid) via chemisorption by moistened, basic Ca(OH)2 particles in 

the scrubber (Lancia et al., 1993; Ghorishi and Gullett, 1998), and the removal of Hg2+ and 

possibly some Hg0

 via adsorption onto carbon-containing fly ash and Ca(OH)2 at low 

temperatures in the baghouse (CEA, 2005), which facilitates contact between gaseous mercury 

and carbon or other sorbent contained in the “dust cake” that accumulates on its numerous filter 

bags. The Greenidge multi-pollutant control process includes all of these components, and 

hence, it is expected that its combination of an in-duct SCR, Ca(OH)2-based scrubber, and 

baghouse will generally result in high mercury removals without any activated carbon injection 

when applied to bituminous coal-fired units. Prior to the Greenidge Project, however, it was 

uncertain whether Hg0

 would be oxidized effectively across the SCR catalyst at the abnormally 

high space velocities resulting from the single-layer, in-duct design. Determining the extent of 

Hg oxidation and its effect on overall Hg removal was one of the objectives of the project’s 

testing program. 

To ensure high mercury removal efficiencies, the multi-pollutant control system also includes an 

activated carbon injection system. Activated carbon, which adsorbs both Hg0

 and Hg2+ (CEA, 

2005), is injected into the flue gas just upstream of the Turbosorp® absorber vessel. Very 

effective utilization of the activated carbon and high mercury capture are expected to result from 

the long solids residence time provided by the circulating fluidized bed scrubbing system’s high 

solids recycle ratio. The relatively low temperatures (~160 °F) in the Turbosorp® system and the 

thorough contact facilitated by caking of the carbon sorbent on the baghouse filter bags are also 

expected to result in a high capacity for mercury capture by the activated carbon, as compared 

to simple duct injection. Moreover, the Turbosorp® system may help to promote mercury 

capture by removing SO3, which has been shown to compete with Hg for active binding sites on 

the activated carbon particles (Presto and Granite, 2007). The activated carbon injection 

system includes a carbon storage silo, carbon feed and injection system, and miscellaneous 

process control instrumentation. The baghouse is used to remove spent carbon from the flue 

gas. 
 21

4.2 Key Design Features 

As discussed in the Introduction, the multi-pollutant control system that was demonstrated as 

part of the Greenidge Project was designed with the overall goal of providing an integrated 

process that is well suited for reducing emissions of a number of pollutants from smaller (i.e., 

50-300 MWe) coal-fired EGUs. Therefore, the design included several key features that are 

consistent with the needs of these smaller units. These key design features, which are 

synonymous with the advantages of the multi-pollutant control system over technologies that 

have conventionally been applied to smaller coal-fired units, are identified and discussed in the 

subsections below. 

4.2.1 Deep Emission Reductions 

Conventional low-capital-cost air pollution control options for smaller coal-fired units, such as 

low-NOx burners or stand-alone SNCR to reduce NOx emissions and combustion of low-sulfur 

coal or use of sorbent injection in the furnace or ductwork to limit SO2 emissions, in most cases 

do not produce emission rates consistent with the low levels established in environmental 

regulations that recently have been promulgated or proposed. Hence, units employing these 

options are increasingly vulnerable to volatile allowance costs or even retirement as new 

regulations are enacted. Thus, it was essential that the Greenidge multi-pollutant control 

process be designed to achieve deeper emissions reductions than these conventional lowcapital-cost options and to meet or exceed applicable state and federal regulatory requirements 

for air emissions. 

The process demonstrated at AES Greenidge is well suited for achieving NOx emission 

reductions of about 50-75%, compared with the 20-35% reduction typically achievable by SNCR 

(Pfaff and Abrams, 2006). It also is designed to achieve greater than 95% removal of SO2, 

comparable to the 95-98% removals characteristic of today’s best available wet scrubbing 

technologies for larger coal-fired units (DePriest and Gaikwad, 2003). Furthermore, the multipollutant control system is designed to achieve greater than 90% capture of mercury, meeting or 

exceeding the performance of state-of-the art mercury control technologies, and to reduce 

emissions of SO3, HCl, and HF by at least 95%. NOx, SO2, and mercury are the focus of many 

state and federal environmental actions. SO3, HCl, and HF contribute to the formation of acid 

aerosols, and emissions of these compounds must be reported to the U.S. Environmental 

Protection Agency (EPA) as part of the national Toxics Release Inventory (TRI) program. 

Elevated concentrations of SO3 in flue gas can also result in the formation of visible emissions 

(i.e., “blue plumes”), which are often particularly problematic for coal-fired power plants with 

SCR systems because SO3 can be generated by oxidation of SO2 across the SCR catalyst. 

Although the Greenidge multi-pollutant control process includes an SCR reactor, the 

downstream circulating fluidized bed dry scrubber is designed for deep SO3 removal, eliminating 

the potential for plume visibility problems due to SO3. Finally, as discussed above, for plants 

currently using an ESP to control particulate matter emissions, installation of the circulating 

fluidized bed dry scrubber and baghouse is expected to afford a substantial improvement in PM 

control, especially for fine particles. 
 22

4.2.2 Low Capital Costs 

There are commercially-available conventional technologies, such as full-scale SCR systems 

and limestone forced oxidation wet scrubbers, that are capable of achieving or exceeding the 

deep emissions reductions targeted for the Greenidge multi-pollutant control process. However, 

operators of smaller coal-fired EGUs, which are penalized by economies of scale, often cannot 

afford the large capital costs associated with these technologies. Hence, the multi-pollutant 

control process that was demonstrated at AES Greenidge was designed to achieve deep 

emission reductions while offering substantially reduced capital costs compared to these 

conventional state-of-the-art technologies. 

By using a compact, single-layer SCR reactor that is installed in a modified section of ductwork 

between the unit’s economizer and air heater, the hybrid SNCR/SCR system avoids many of the 

capital costs associated with the multi-layer reactor, structural support steel, foundations, and 

new ductwork runs required for a conventional stand-alone SCR system. Also, unlike wet FGD 

systems, the Turbosorp® system does not produce saturated flue gas, and therefore is 

constructed from carbon steel rather than from the expensive corrosion-resistant materials 

required for wet scrubbers. For the same reason, use of the Turbosorp® system also does not 

entail the installation of a new corrosion-resistant stack (or flue gas reheat system), which is 

commonly required for wet scrubber retrofits. Because of these factors, as well as the 

mechanical simplicity of the Turbosorp® system relative to wet scrubbers, the capital cost of the 

multi-pollutant control system installed at the 107-MWe AES Greenidge Unit 4 is estimated to be 

about 40% less than the capital cost would have been to retrofit the unit with a conventional 

system comprising a stand-alone SCR and wet limestone forced oxidation scrubber (as 

discussed in greater detail in Section 11). 

In exchange for its substantially reduced capital costs, the Greenidge multi-pollutant control 

system has higher variable operating costs (because of its lower reagent utilization or use of 

more expensive reagent) and lower NOx removal efficiency (SCRs are capable of achieving 80-

90% or greater NOx reduction) relative to a conventional stand-alone SCR / wet FGD system. 

Whereas this tradeoff may be unattractive for large coal-fired EGUs, it is consistent with the 

needs of the owners of smaller units, which in many cases cannot justify or afford the large 

capital costs (per unit of electrical output) needed to retrofit with conventional technologies for 

deep emissions reductions. 

4.2.3 Small Space Requirements 

The relatively large amount of space required to install conventional SCR and wet FGD systems 

further prevents these technologies from being widely applied to smaller coal-fired EGUs. Many 

smaller coal-fired units are located in built-up areas and do not have sufficient physical space to 

easily accommodate both an SCR and wet scrubber; this increases the difficulty, and hence the 

capital cost, of retrofitting these technologies. Therefore, an objective in designing the 

Greenidge multi-pollutant control system was to minimize its required footprint. 

The SNCR portion of the multi-pollutant control process requires only a small amount of space 

for a urea storage tank, a small shed containing the urea circulation module, and several small 

urea distribution skids located around the boiler. Unlike a conventional stand-alone SCR 

reactor, the single-layer SCR reactor requires essentially no new land area, as it is installed in a 

modified ductwork section between the economizer and air heater and needs only a few new 
 23

support beams. The arrangement of the circulating fluidized bed dry scrubber, baghouse, and 

associated equipment is also compact. The various pieces of equipment are vertically tiered to 

permit gravity-assisted transport of solids where possible, and as a result, require less than 0.5 

acre of land for a 110 MWe installation. The layout of the multi-pollutant control system for the 

AES Greenidge Unit 4 installation is discussed in greater detail in Section 6.3.2 of this report. 

4.2.4 Applicability to High-Sulfur Coals 

As discussed in the Introduction, greater than 80% of the coal-fired units that are candidates for 

the demonstration technology are located east of the Mississippi River, where high-sulfur 

eastern U.S. bituminous coal is a candidate fuel source. The dispatch economics of these units 

can improve significantly with the installation of low-cost SO2 removal systems that allow the 

use of higher-Btu, higher-sulfur, less-expensive coals with a net reduction in SO2 emissions and 

a corresponding reduction in the need for purchasing allowances. Hence, an important design 

objective for the Greenidge multi-pollutant control system was that it be able to achieve deep 

SO2 emission reductions when applied to units firing high-sulfur (i.e., >2%-sulfur) coals. 

Lime spray dryers provide a relatively low-capital-cost means for achieving deep reductions in 

SO2 emissions, as does the Turbosorp® circulating fluidized bed dry scrubber that was installed 

as part of the multi-pollutant control process at AES Greenidge. However, it is more difficult to 

treat high-sulfur flue gases and to achieve very high SO2 removal efficiencies with a spray dryer 

than with a circulating fluidized bed dry scrubber. In spray dryer systems, lime and water are 

injected into the absorber vessel together as a slurry, rather than separately as in the 

Turbosorp® system. As a result, increasing the lime injection rate (i.e., to accommodate a 

higher inlet SO2 loading or to increase the SO2 removal efficiency) may require a corresponding 

increase in the water injection rate to maintain the solids content of the slurry within acceptable 

limits. For sufficiently high SO2 loadings and removal efficiencies, the slurry injection scheme 

imposes a limit on the amount of lime that can be injected, because excess water could lead to 

scaling in the absorber vessel, plugging and binding of baghouse bags, and plugging of 

discharge feeders and conveyers. As a result, spray dryer installations are typically limited to 

applications that require 95% or lower SO2 removal efficiency and to units that fire coals with 

sulfur contents of about 2% (~3 lb SO2/mmBtu) or less. As discussed in Section 4.1.2 above, in 

the Turbosorp® system, water injection and hydrated lime injection are carried out separately, 

such that the Ca(OH)2 injection rate is controlled solely by the pollutant loading and desired 

emission reduction, without being limited by the temperature or moisture content of the flue gas. 

As a result, the Turbosorp® system can be operated to achieve deep emission reductions (i.e., 

98% or greater) for a wide range of fuels, including high-sulfur coals (i.e., up to 5 lb SO2/mmBtu 

or more). 

4.2.5 Low Maintenance Requirements 

Insofar as the PPII seeks to improve the reliability of the nation’s energy supply, minimization of 

maintenance requirements was an objective in the design of the Greenidge multi-pollutant 

control system, such that system maintenance will not adversely affect unit availability. A 

drawback of both wet scrubbers and lime spray dryers is their use of slurries to introduce the 

limestone or lime into the system, resulting in high maintenance requirements and potential for 

operational problems. Problems arising from the use of slurries can include pipe plugging, 

nozzle plugging, solids build-up, and erosion and abrasion of pumps, pipes, and vessels. Wet 
 24

scrubbers in particular are relatively complex, as they produce a slurry product and require 

pumps for slurry recirculation as well as maintenance-intensive dewatering equipment. 

The Turbosorp® circulating fluidized bed dry scrubber that is part of the Greenidge multipollutant control system is expected to afford substantially reduced maintenance requirements 

compared to these more conventional FGD technologies. In the Turbosorp® process, lime is 

injected into the absorber as a dry hydrate rather than as a slurry. A blower is used to 

pneumatically convey the dry hydrated lime to the absorber for injection. The solids collected in 

the baghouse are also completely dry and are recycled to the absorber using air slides. Gravity 

provides the motive force for injection via the differential height between the bottom of the 

baghouse and the injection point on the absorber tower. Apart from the lime hydration system 

(if included), the system’s only pump is used to inject liquid water into the absorber vessel. 

Hence, the process avoids the problems with plugging, erosion, abrasion, and scaling that can 

result from pumping and handling slurries in other types of scrubbing systems. The Turbosorp®

system also includes comparatively few moving parts, and as implied in Section 4.2.4, is less 

likely to cause plugging and binding of fabric filter bags than a spray dryer is. 

4.2.6 Operational Flexibility 

Unlike larger baseload units, many smaller coal-fired EGUs routinely cycle their loads in 

response to electricity demand. Hence, a multi-pollutant control system designed for these 

smaller units should feature turndown capabilities to permit continued emissions reductions at 

reduced operating loads. The Greenidge multi-pollutant control system includes these 

capabilities. 

For conventional SCR systems, low-load operation is constrained by reduced flue gas 

temperatures, which can cause incomplete ammonia consumption across the SCR catalyst, 

resulting in high ammonia slip and ammonium bisulfate fouling in the air heater (see Section 

4.3.1). At sufficiently low temperatures, catalyst plugging and deactivation can also occur via 

the formation of salts in the SCR reactor. These constraints are particularly stringent for units 

that fire high-sulfur coals. Stand-alone SCR installations typically employ an economizer gas 

bypass and/or water flow circuit modifications to raise the flue gas temperature at the SCR inlet 

during low-load operation. However, because of the hybrid NOx control strategy included as 

part of the Greenidge multi-pollutant control process, NOx removal capabilities are available to 

some extent at lower operating loads without the need for any such modifications. The 

operating strategy for the hybrid system is shown conceptually in Figure 8. 

As illustrated in the figure, operation of the system varies with generator load, resulting in three 

distinct operating ranges: a high-load range in which NOx reduction is accomplished via SCR, 

SNCR, and low-NOx combustion (if applicable); an intermediate-load range in which NOx

reduction is accomplished via SNCR and low-NOx combustion (but not SCR), and a low-load 

range in which NOx reduction is accomplished via low-NOx combustion (but not SCR or SNCR). 

At generator loads that produce economizer outlet temperatures below the minimum operating 

temperature for the SCR reactor, urea injection into the upper (cooler) region of the furnace, 

which is used to generate ammonia slip for the SCR, is discontinued. However, the lower zones 

of urea injection continue to operate until the minimum SNCR operating temperature is reached, 

resulting in continued NOx removal via SNCR. Below the minimum SNCR operating 

temperature, which is the minimum economizer outlet temperature at which it is safe to 

introduce very small amounts of ammonia into the SCR catalyst, urea injection into the furnace 
 25

is discontinued. However, NOx emissions may continue to be controlled via the unit’s low-NOx

combustion system, if applicable. Hence, for smaller units that regularly cycle loads based upon 

peak and off-peak demands, the load following capabilities of the hybrid SNCR/SCR process 

can help to contribute to lower NOx emission averages. 

Generator Load (MW)

NOx at Stack (lb/mmBtu)

Low-NOx Combustion

SNCR

SCR

Minimum SNCR Operating Temperature

Minimum SCR Operating Temperature

Minimum 

Load

Maximum 

Generator Load (MW) Load

NOx at Stack (lb/mmBtu)

Low-NOx Combustion

SNCR

SCR

Minimum SNCR Operating Temperature

Minimum SCR Operating Temperature

Minimum 

Load

Maximum 

Load

Figure 8. Operating strategy for the hybrid NOx control system that was demonstrated as part of 

the Greenidge Project. 

The circulating fluidized bed dry scrubber is also capable of operating at reduced loads. As 

discussed in Section 4.1.2, depending upon the extent of turndown that is desired, a flue gas 

recycle system may be required to provide sufficient flow to the absorber so that a fluidized bed 

can be maintained at the low end of the operating range. 

4.3 Design Considerations

In addition to the overarching factors established in the preceding section, a number of unit- and 

application-specific factors affect the design of the multi-pollutant control process. Important 

design considerations for the process are discussed in the following subsections. 

4.3.1 Coal and Ash Characteristics 

Characteristics of a candidate unit’s coal (and other secondary fuels if applicable) and the fly 

ash produced by its combustion impact the design of many aspects of the multi-pollutant control 

system. 

Certain elemental chemical components of the coal, including arsenic and alkali metals, can 

poison the SCR catalyst by reacting with its active sites, causing deactivation (Wu, 2002). For 
 26

an in-duct SCR reactor, which includes a limited catalyst volume, catalyst deactivation can have 

an appreciable impact on NOx removal performance. 

Coal sulfur content can also affect the operation of the hybrid NOx control system. As 

mentioned in Section 4.2.1, the SCR catalyst promotes oxidation of a small percentage of SO2

in the flue gas to SO3, according to the following reaction: 

SO2 + 1⁄2 O2 → SO3 (15) 

This SO3 can then react with Ca to form CaSO4, which deactivates the catalyst by plugging its 

pores, or it can react with NH3 at sufficiently low temperatures to form NH4HSO4 or (NH4)2SO4

according to the reactions below, causing catalyst plugging or air heater fouling. 

 SO3 + NH3 + H2O → NH4HSO4 (16) 

 NH3 + NH4HSO4 → (NH4)2SO4 (17) 

Hence, for mid- and high-sulfur coals, the SO2-to-SO3 conversion rate is an important 

consideration in the selection of an SCR catalyst. 

The fly ash content of the flue gas must also be considered as part of the SCR system design, 

because greater ash loadings augment the potential for fly ash plugging, which causes catalyst 

deactivation and increased pressure drop. Thus, specification of a rake soot blower, sonic horn 

system, or other catalyst cleaning system is important to prevent deteriorations in SCR 

performance resulting from accumulation of fly ash in the catalyst. 

For the circulating fluidized bed dry scrubbing system, the coal sulfur content affects the amount 

of hydrated lime reagent that must be injected to achieve a given level of SO2 removal. 

Although the Turbosorp® circulating fluidized bed dry scrubber is capable of achieving deep SO2

emission reductions across a wide range of coal sulfur contents, higher sulfur coals require 

greater hydrated lime injection rates than do lower sulfur coals for a given percentage of SO2

removal. This, in turn, increases the amount of solid byproduct generated by the process and 

affects the design of solids handling and storage equipment. Coal chlorine content also affects 

the performance of the circulating fluidized bed dry scrubber. CaCl2 is deliquescent. Hence, as 

the chlorine content increases, the process must be operated further from the adiabatic 

saturation temperature in order to avoid caking in the absorber vessel and plugging in the 

downstream equipment. 

Finally, the composition of the coal and fly ash can affect the mercury removal performance of 

the system. For example, as coal chlorine content increases, the percentage of mercury in the 

flue gas that is present as Hg2+ (e.g., HgCl2) as opposed to Hg0

 increases (CEA, 2005). Greater 

Hg2+ concentrations improve the potential for mercury removal as a co-benefit of the circulating 

fluidized bed dry scrubber and baghouse. This potential also increases as the amount of 

unburned carbon in the fly ash increases, because unburned carbon can adsorb gaseous 

mercury, especially at the low temperatures (Fenger and Winschel, 2006) afforded by the 

circulating fluidized bed dry scrubber, and can also serve as a mercury oxidation catalyst in the 

presence of sufficiently high chlorine concentrations (Niksa and Fujiwara, 2005; Presto and 

Granite, 2006). Hence, coal and ash characteristics may play a role in determining whether 

activated carbon injection is required for Hg control and, if so, what injection rate is needed. 
 27

4.3.2 Baseline NO Concentration 

The kinetics for NOx reduction via SNCR are a function of the initial concentration of NO, one of 

the reactants in the process and one of the products of the high-temperature reactions involving 

oxidation of reagent to form NO. Hence, the amount of NOx removal achievable in the SNCR 

process depends on the concentration of NO leaving the combustion system. Baseline NO 

concentrations vary considerably from unit-to-unit, as they are a function of factors such as fuel 

nitrogen content, fuel volatile matter content, flame temperature, and combustion zone 

stoichiometry and residence time. 

4.3.3 Temperature Profile in the Furnace 

As discussed in Section 4.1.1, the performance of SNCR depends strongly on the temperature 

at which the process operates. Hence, the temperature profile in the furnace, which is specific 

to each application, strongly influences the design of the urea injection strategy. Computational 

fluid dynamics (CFD) are used to model the furnace temperature profile at various loads, and 

chemical kinetic modeling (CKM) is used to simulate the effect of temperature on the SNCR 

reactions. Modeling results form the basis for the design of the number, type, and placement of 

the urea injectors, as well as the urea injection strategy as a function of operating load. 

4.3.4 Flue Gas Residence Time and Flow Profile in the Furnace 

In order to optimize SNCR performance, a urea injection strategy must be developed that 

provides for thorough mixing of the reagent with the flue gas and sufficient residence time of 

urea and flue gas in the temperature regions of the furnace where the desired reactions 

between urea and NO occur. Reagent distribution and residence time are affected by the flue 

gas flow profile in the furnace. As with temperature, CFD and CKM are used to model the flow 

profile in the furnace and its effect on the SNCR reactions, and the results are used to inform 

the design of the urea injection strategy. 

4.3.5 CO Concentrations in the Furnace 

Carbon monoxide significantly impacts SNCR chemistry, with net effects of reducing ammonia 

slip, promoting the oxidation of reagent to form additional NO, and lowering the optimal 

temperature for NO reduction (Brouwer et al., 1996). Hence, local CO concentrations must be 

considered when modeling and designing the urea injection system. 

4.3.6 Available Space Between the Economizer and Air Heater 

The amount of incremental NOx removal and ammonia slip control achievable by the SCR 

reactor is limited by the residence time of the flue gas in the catalyst. Residence time is the 

inverse of space velocity (flue gas volumetric flow rate ÷ catalyst volume), and for a given flue 

gas flow rate, it increases with increasing catalyst volume. For the in-duct SCR reactor that is 

part of the Greenidge multi-pollutant control system, the volume of catalyst that can be installed, 

and hence the level of NOx removal that can be achieved via SCR, is restricted by the amount 
 28

of available space between the candidate unit’s economizer and air heater. For a given 

catalyst, oxidation of Hg, which is a desired co-benefit of SCR, and conversion of SO2 to SO3, 

which is undesired, are also expected to decrease with decreasing catalyst volume. The 

geometry between the economizer and air heater also affects the catalyst face velocities (flue 

gas volumetric flow rate ÷ catalyst cross-sectional area) that can be achieved. High and low 

face velocities can each present problems; high face velocities contribute to increased catalyst 

erosion, whereas low face velocities can lead to ash deposition within the catalyst. For the 

retrofit application of an in-duct SCR reactor, the reactor cross-sectional area will often be 

limited by unit geometry, resulting in face velocities that are greater than normal. The effects of 

these elevated face velocities must be considered as part of the catalyst and reactor designs. 

4.3.7 Flue Gas Temperature at the Economizer Outlet 

Catalyst activity is a function of temperature, and within the acceptable temperature window for 

SCR operation, the rate of NOx removal increases as temperature increases. Hence, the 

catalyst specification and the amount of NOx removal achievable in the single-layer in-duct SCR 

reactor both depend on a unit’s economizer outlet temperature. Variations in this temperature 

with unit load are a primary factor in establishing the turndown ranges for the SCR and SNCR 

systems, as illustrated in Figure 8. Per the discussion in Section 4.2.6, an economizer bypass 

can be installed to increase the temperature of the flue gas entering the SCR at reduced 

operating loads, increasing its turndown capability; however, the potential benefits afforded by 

this option must be weighed against its resultant effects on cost and operating complexity, and it 

was not selected for this project. 

4.3.8 Flue Gas Homogeneity at the SCR Inlet 

As discussed in Section 4.1.1, in order to maximize performance of the relatively small in-duct 

SCR reactor, it is essential that the temperature, composition, and velocity of the flue gas are 

homogeneous across the cross-sectional area of the catalyst. Localized deviations in 

composition (i.e., NH3/NOx mole ratio), temperature, or velocity from target values can result in 

decreased NOx removal efficiency and increased ammonia slip, and localized deviations in 

velocity from target values can also result in catalyst erosion or ash deposition. Hence, static 

mixers are used to homogenize the flue gas upstream of the in-duct SCR reactor. Because flue 

gas flows are unique to each candidate unit, physical flow modeling must be performed on a 

case-by-case basis to optimize the design of the static mixing system. 

4.3.9 Large Particle Ash 

If the candidate unit produces large particle ash (even if only in small quantities), then this LPA 

must be removed from the flue gas upstream of the SCR reactor in order to prevent it from 

plugging the catalyst. Large particle ash, which consists of pieces of slag that in many cases 

are too large to pass through the catalyst, poses a potential problem for many conventional 

SCR installations. If it is not captured ahead of the SCR, the LPA can become lodged in the 

catalyst and promote subsequent accumulation and bridging of fly ash, eventually plugging a 

substantial portion of the catalyst. This in turn causes an increase in the pressure drop across 

the SCR reactor (potentially straining downstream fans and ductwork), as well as decreased 

NOx removal efficiency, increased ammonia slip, and increased catalyst erosion. In 
 29

conventional installations, potential LPA problems are often easily mitigated by installing a 

screen and hopper at a 90° bend in the ductwork upstream of the SCR reactor. However, 

physical constraints associated with the in-duct SCR design that is employed by the hybrid 

SNCR/SCR system can make the installation of an LPA removal system more challenging. The 

design of the LPA removal system varies by unit and is dependent upon factors such as the 

amount of available space between the economizer and SCR reactor, the presence or absence 

of a 90o bend in the ductwork upstream of the reactor, the presence or absence of obstructions 

that could interfere with the screen, and the feasibility of utilizing hoppers to remove the 

captured LPA. The application at AES Greenidge Unit 4 was particularly challenging in that it 

involved vertically downward flow between the economizer and SCR, with obstructions (i.e., 

static mixers and an expansion joint), limited space, and no 90o bends or hoppers. This 

required the development of a unique LPA removal system, which is described in Section 6.2.2. 

When selecting an LPA screen, important considerations include the pitch (which affects both 

the LPA capture efficiency and the pressure drop) and the material of construction (which 

affects the durability of the screen). The catalyst pitch can also be increased to reduce the 

likelihood of LPA accumulation, although this reduces the NOx removal efficiency achievable by 

the SCR system. 

4.3.10 Amount of Allowable Ammonia Slip 

In spite of its use of an in-duct SCR reactor to consume ammonia slip from the SNCR process, 

the design of the hybrid SNCR/SCR system is nevertheless constrained to some extent by 

ammonia slip. Obviously, the design level of ammonia slip from the SNCR process can be no 

greater than the sum of the amount of ammonia consumed in the SCR reactor and the amount 

of allowable ammonia slip from the overall hybrid system. As the SCR catalyst deactivates, its 

capacity to consume ammonia decreases; hence, limits on ammonia slip constrain the useful 

operating life of the catalyst. Moreover, at operating loads below the minimum SCR operating 

load, limits on ammonia slip restrict SNCR operation, resulting in less-than-optimal urea 

utilization and NOx removal. Constraints on ammonia slip typically become more stringent as 

coal sulfur content increases, because the resultant greater concentrations of SO3 in the flue 

gas provide a greater driving force for the formation of ammonium bisulfate (NH4HSO4) from any 

ammonia that is present. For units firing lower-sulfur coals, constraints may be also imposed by 

regulatory limits on NH3 emissions or concerns about NH3 contamination of the baghouse 

solids, which makes disposal or use of these solids more difficult. 

4.3.11 Approach to Adiabatic Saturation in the Absorber Vessel 

The Ca/S molar ratio (i.e., the number of moles of hydrated lime reagent injected per mole of 

inlet SO2) required to achieve a given level of SO2 removal in the circulating fluidized bed dry 

scrubber depends on the proximity of the temperature in the absorber vessel to the adiabatic 

saturation temperature of the flue gas. In general, for a given Ca(OH)2 injection rate, SO2

removal efficiencies improve as the operating temperature approaches the adiabatic saturation 

temperature. However, the approach to adiabatic saturation is limited by concerns about 

condensation, which can cause corrosion, deposition of solids in the absorber, binding and 

plugging of baghouse bags, and problems with the solids recirculation system. Hence, the 

absorber operating temperature must be carefully selected to maximize SO2 removal efficiency 

while avoiding any potential for condensation. Also, because the circulating fluidized bed dry 

scrubbing system operates at temperatures near the adiabatic saturation temperature of the flue 
 30

gas, thorough insulation of the system is important, especially in colder climates, in order to 

minimize the potential for condensation. Per the discussion in Section 4.3.1, as the Cl content 

of the flue gas increases, the scrubber must be operated further from adiabatic saturation in 

order to avoid condensation. (The presence of Cl improves SO2 capture efficiency, however, 

approximately negating any effect of the higher operating temperature on the required Ca/S 

molar ratio). 

4.3.12 Hydrated Lime Supply 

As discussed in Section 4.1.2, the multi-pollutant control system can be installed with or without 

a lime hydration system. Inclusion of a hydrator allows the plant to produce hydrated lime 

reagent onsite from purchased pebble lime. Otherwise, hydrated lime must be purchased for 

direct use in the process. On a mass basis, hydrated lime costs about 25% more (excluding 

delivery) and contains 24% less Ca than pebble lime. Hence, the cost per mole of Ca 

(excluding delivery) is about 65% greater for hydrated lime than for pebble lime, and the use of 

purchased hydrated lime substantially increases the multi-pollutant control system’s variable 

operating and maintenance costs. Nevertheless, some operators may choose to purchase 

hydrated lime in order to avoid the capital investment and maintenance requirements associated 

with a lime hydration system. Even if a hydrator is included, the design should provide 

capability for accepting delivery of hydrated lime so that the hydrator can be taken offline for 

maintenance without affecting operation of the Turbosorp® scrubber. 

4.3.13 Increased Solids Loading to the Baghouse 

Because a large portion of the solids that are removed from the flue gas in the baghouse are 

recycled back to the Turbosorp® absorber vessel, the particle loading in the flue gas that is sent 

to the baghouse from the absorber vessel is substantially greater than it would have been with 

no circulating fluidized bed dry scrubber installed. As a result, the baghouse must be designed 

to accommodate this increased particle loading. Design modifications may include reducing the 

air-to-cloth ratio (i.e., ft3

/min flue gas ÷ ft2 bag surface area), increasing the bag spacing, and 

increasing the baghouse inlet volume and depth of the drop-out zone beneath the bags. 

The substantially increased particle loading resulting from solids recirculation is one reason why 

a unit’s existing particulate control device typically cannot be used for PM removal in a 

circulating fluidized bed dry scrubber installation. (The existing particulate control device can be 

retained ahead of the scrubber to capture fly ash separately from the solid scrubber products. 

This arrangement may be economically attractive if the fly ash can be sold; however, a second 

particulate control device would still be required as part of the circulating fluidized bed dry 

scrubber). Conceptually, a new ESP could be used instead of a new baghouse with the 

Turbosorp® system; however, baghouses are preferred because the coating of sorbent material 

that accumulates on their filter bags promotes additional removal of SO2, acid gases, and 

mercury downstream of the absorber vessel, improving reagent utilization and overall pollutant 

removal efficiency. 

Particle loading also affects the amount of compressed air required by the baghouse. A 

candidate unit’s compressed air capacity must be assessed and increased if necessary in order 

to ensure that it is sufficient to satisfy the baghouse demand. 
 31

4.3.14 Pressure Drop Across the System 

Addition of the static mixing devices, LPA screen (if included), in-duct SCR catalyst, fluidized 

bed absorber, baghouse, and longer ductwork runs causes increased flue gas pressure drop. 

Hence, most applications of the multi-pollutant control system will require installation of a 

booster fan and/or modifications to the unit’s existing ID fans to overcome this pressure drop. 

The amount of pressure drop and required modifications depend upon flue gas flow rate, 

equipment sizing and design, and existing ID fan capacity, and must be assessed on a case-bycase basis. The effect of increased pressure drop on the operating costs of the system must be 

considered as part of the design. 

4.4 Developmental Status 

As discussed in Section 2.2, all of the technologies that were demonstrated as part of the 

Greenidge Multi-Pollutant Control Project were developed and tested individually at a sufficient 

scale before the project to provide an adequate level of confidence concerning their mechanical 

operability. However, the Greenidge Project was unique in that it represented the first 

application in which a hybrid SNCR/SCR system and a circulating fluidized bed dry scrubbing 

system were combined to form an integrated multi-pollutant control system, as well as the first 

application of either of these technologies to a unit firing >2%-sulfur eastern U.S. bituminous 

coal. 

Prior to the Greenidge Project, the Turbosorp® circulating fluidized bed dry scrubber had been 

applied to four European coal-fired power plants, but it had not been demonstrated on a coalfired EGU in the United States. Table 4 shows design targets for these European installations, 

as well as design capabilities for the AES Greenidge installation. As these data indicate, the 

Turbosorp® unit at AES Greenidge was designed for a greater flue gas SO2 concentration and 

greater level of SO2 removal than any previous installation. Circulating fluidized bed dry 

scrubbers similar to the Turbosorp® system were installed on two smaller coal-fired EGUs in the 

United States before the Greenidge Project (Westmoreland Energy’s Roanoke Valley Unit 2 in 

North Carolina and Black Hills Power’s Neil Simpson Unit 2 in Wyoming); however, both of 

these units fire less than 2%-sulfur coal and are less than 100 MWe in size. 

Before the Greenidge Project, the hybrid SNCR/SCR system was tested on the equivalent of 80 

MWe of flue gas from the PSE&G Mercer Unit 2, which fired coal with a sulfur content of less 

than 1%. The SCR configuration involved horizontal flow through two 5-foot-thick banks of plate 

catalyst. Relative to operation using only SNCR, the hybrid SNCR/SCR system improved 

overall NOx reduction from 37% to 71% and overall urea utilization from 31% to 62% (for a 

constant urea feed rate) at full load, with less than 10 ppm of ammonia slip (Albanese et al., 

1995). Hybrid SNCR/SCR was also demonstrated at commercial scale on the former 147 MWe

GPU Generation Seward Unit 5, which fired bituminous coal containing about 1.5% sulfur. The 

system was designed to achieve 55% NOx reduction from a baseline of about 0.78 lb/mmBtu, 

with the in-duct SCR contributing about 6% reduction at full load. The demonstration confirmed 

the feasibility of the hybrid SNCR/SCR concept, but its performance was limited by temperature 

stratification in the SCR and arsenic poisoning of the catalyst (Urbas, 1999). Hence, the 

Greenidge demonstration marked the greatest targeted NOx removal efficiency for a 

commercial-scale hybrid SNCR/SCR system on a coal-fired boiler in the United States, as well 

as the first application of the hybrid system to a unit firing >2%-sulfur eastern U.S. bituminous 

coal. It also marked the first installation of the hybrid SNCR/SCR system on a coal-fired unit in 
 32

which the flue gas flows vertically downward through the in-duct SCR catalyst with no upstream 

economizer hopper or ductwork bend to capture large ash particles. (The Seward installation 

had vertical, downward flow through the catalyst, but it included a 90o bend and an economizer 

hopper upstream of the reactor). 

Table 4. Characteristics of existing Turbosorp® installations on coal-fired EGUs and of the AES 

Greenidge design. 

Plant Country Coal Type 

Flue gas

flow rate

[m3

/h]a

Approx. 

SO2

concentr.

[mg/m3]

b

SO2

removal 

efficiency

[%] 

Approx. 

HCl 

concentr. 

[mg/m3

]

b

HCl 

removal 

efficiency

[%] 

Date 

of 

startup 

Kraftwerk 

Zeltweg Austria lignite / 

bituminous 600,000 2,300 91 100 >90 1994 

Kraftwerk 

St. Andrä Austria lignite / 

bituminous 450,000 2,500 92 100 >90 1994 

Heiz-KW 

Strakonice 

Czech 

Republic lignite 261,000 4,200 85 30 >75 1999 

REA 

Siekierki Poland bituminous 250,000 3,300 85 250 >95 2002 

AES 

Greenidge USA bituminous 450,000 5,000 95 100 >95 2007 

a

At standard temperature and pressure, wet; bAt standard temperature and pressure, dry 

Thus, the principal uncertainties, and the motivation for the Greenidge Multi-Pollutant Control 

Project, included the performance of the hybrid SNCR/SCR and Turbosorp® systems when 

combined in an integrated multi-pollutant control process, as well as the technical and economic 

performance of these systems when applied with ambitious performance targets to a unit firing 

eastern U.S. bituminous coals containing greater than 2% sulfur. As discussed above, the 

demonstration program also included an evaluation of the effect of biomass co-firing on the 

performance of the multi-pollutant control system. Specific project uncertainties included: 

• Control and performance of the combined combustion modifications, SNCR, and in-duct 

SCR, especially during load swings/cycling 

• Catalyst performance, life, and replacement cost for an in-duct single catalyst layer installed 

on a unit firing greater than 2%-sulfur eastern U.S. bituminous coal 

• Extent of ash accumulation in the catalyst for an in-duct SCR reactor with vertical downward 

flow and no upstream hoppers or ductwork bends 

• Effect of ammonia slip from the hybrid SNCR/SCR on unit operability for a unit firing greater 

than 2%-sulfur coal 

• Extent of Hg oxidation at high space velocities across the single catalyst layer and its effect 

on Hg removal performance 

• SO2 capture and required Ca/S ratio in the Turbosorp® for a high-sulfur U.S. bituminous coal 

• Amount of Hg removal achievable in the Turbosorp® system and required activated carbon 

injection rate 

• SO3, HCl, and HF removal as a function of SO2 control conditions 

• Effect of biomass co-firing on NOx, Hg, and acid gas removal 

• Effects of ammonia slip and carbon injection on solid waste management 

• Economics of the combined system for a relatively small (~110 MWe) unit firing greater than 

2%-sulfur eastern U.S. bituminous coal 
 33

The Greenidge Project was conducted to resolve these uncertainties so that the technical and 

economic viability of the integrated multi-pollutant control process could be proven, thereby 

advancing commercial deployment of the technology. 

5. Host Site 

AES Greenidge served as the host site for demonstrating the multi-pollutant control system. 

Most major project activities, including installation, operation, and testing of the system, took 

place there. AES Greenidge is a 161-MWe (Energy Information Administration net winter 

capacity) coal-fired electric power plant located in Dresden, Yates County, New York, along the 

western shore of Seneca Lake. It is a merchant plant that dispatches when its variable cost of 

producing electricity is less than the market price of electricity. (AES Greenidge sells its power 

into the New York Independent System Operator’s day-ahead and hour-ahead markets). The 

plant, which is situated on a 153-acre site, currently comprises two electric generating units: the 

54-MWe (net) Unit 3 and the 107-MWe (net) Unit 4. Unit 4 is a reheat unit; Unit 3 is not. The 

Unit 3 steam turbine is served by Boilers 4 and 5, each a pulverized coal-fired boiler having a 

maximum heat input of 380 mmBtu/h. The Unit 4 steam turbine is served by Boiler 6, a 

pulverized coal-fired boiler with a maximum heat input of 1,117 mmBtu/h. Coal and other 

materials are delivered to the plant via train or truck. Fly ash generated by the facility is hauled 

to the 143-acre Lockwood Landfill, which is located just west-southwest of the plant site. 

Figure 9 shows an aerial photograph of the AES Greenidge site, as viewed from the south prior 

to the commencement of the multi-pollutant control project. The plant’s two original units, which 

were constructed for the New York State Electric & Gas Corporation (NYSEG) in the late 1930s, 

were retired and removed from the plant in the 1980s; however, their idle stacks still stand 

adjacent to the boiler building. AES acquired the plant, including the still-operational Units 3 

and 4, from NYSEG in 1999. 

The multi-pollutant control system was installed on Unit 4 (Boiler 6), which was commissioned in 

1953. As shown in Figure 9, the unit and its associated equipment are housed in or adjacent to 

the western end of the boiler building. Boiler 6 is a Combustion Engineering dry bottom, 

tangentially-fired, balanced draft, pulverized coal boiler designed for 780,000 lb/h steam flow at 

1465 psig. Primary and reheat steam temperatures are 1005 °F. The boiler is served by two 

single-speed forced draft (FD) fans, two induced draft (ID) fans, and two Ljungstrom air 

preheaters. The Unit 4 turbine is a General Electric tandem compound reheat steam turbine, 

which drives a General Electric hydrogen-cooled electrical generator that is rated at 13,800 

volts. 

Eastern U.S. bituminous coal is the primary fuel for Boiler 6. The furnace is equipped with four 

levels of pulverized coal burners, with four burners per level (one in each corner of the furnace). 

Boiler 6 is also permitted to fire clean, unadulterated wood as a supplement to bituminous coal 

(percent by weight of fuel is unrestricted) or waste wood from a particle board furniture 

manufacturing process (restricted to 30% by weight of the total fuel); this biomass fuel is 

prepared and fed to the boiler separately from the coal. AES Greenidge occasionally uses 

wood to provide up to 10% of the heat input to Boiler 6. In addition to the potential economic 

benefits afforded by diversifying the plant’s fuel portfolio, biomass co-firing can help to reduce 

emissions of SO2 and NOx as well as net emissions of CO2 (Fernando, 2002). In 1996, the 

boiler was outfitted with a natural gas reburn system that is capable of providing up to about 

20% of its heat input; however, the reburn system currently is not in use. 
 34

The 1996 combustion modifications to Boiler 6 included the installation of separated overfire air 

(SOFA) ports, which served as the boiler’s primary means for NOx control. The system was 

capable of achieving full-load NOx emissions of about 0.3 lb/mmBtu. Prior to the installation of 

the multi-pollutant control system, an electrostatic precipitator was used to control particulate 

matter emissions from Boiler 6, and the unit did not have any existing equipment for controlling 

SO2 emissions; fuel sulfur content was restricted (via the use of medium-sulfur coal and 

biomass co-firing) in order to meet its permitted limit of 3.8 lb SO2/mmBtu. 

Unit 4 (Boiler 6) Unit 4 Stack

Unit 4 ESP

Figure 9. Aerial photograph of the AES Greenidge plant, as viewed from the south prior to the multipollutant control project.

In addition to installing the multi-pollutant control system that is the topic of this report, AES 

Greenidge undertook several other projects to help ensure a 20-30 year life extension for Unit 4. 

These included a major turbine overhaul, replacement of the unit’s high-temperature 

superheater elements, miscellaneous boiler maintenance, and upgrades to the unit’s distributed 

control system (DCS), air preheaters, and ash handling system. As mentioned above, 

modifications were also made to the combustion system for Boiler 6, including both its firing 

system and its SOFA system. Although these combustion modifications are not included in the 

scope of the DOE cooperative agreement, they are discussed in this report insofar as they 

helped to optimize the performance of the multi-pollutant control system that was demonstrated 

thereunder. 
 35

6. Process Design 

Having already reviewed the general concepts, key features, design considerations, and 

uncertainties associated with the multi-pollutant control technology in Section 4, this section 

focuses specifically on the system design for the AES Greenidge Unit 4 application. The 

project’s detailed design and engineering tasks were led by Babcock Power Environmental Inc. 

As shown in the project schedule in Appendix A, process design work commenced in mid-2005, 

and it was largely complete by the summer of 2006. 

Appendix B contains engineering drawings, including process flow diagrams, piping and 

instrument diagrams (P&IDs), and general arrangement drawings, that summarize the design of 

the multi-pollutant control system at AES Greenidge Unit 4. Appendix C presents a list of the 

major equipment items required for the system. The design is described in the subsections 

below. The quantitative information concerning system performance that is presented in this 

section represents the expected performance at the time of design; actual performance results 

from the project’s Operation and Testing Phase are presented in Section 9 of this report. 

6.1 Design Basis 

The multi-pollutant control system at AES Greenidge Unit 4 was designed to operate effectively 

while the unit fires eastern U.S. bituminous coals containing 2-4% sulfur and co-fires waste 

wood at 0-10% of the heat input to the furnace. The design case was based on the use of a 

2.9%-sulfur coal with approximately 10% biomass co-firing at the unit’s maximum continuous 

rating (MCR). Design fuel characteristics are summarized in Table 5. 

Table 5. Assumed fuel characteristics (as fired) for the design case. 

Coal Wood Blended Fuel 

Higher Heating Value (Btu/lb) 13,097 8,592 12,426 

Carbon (% w/w) 72.17 45.13 68.14 

Hydrogen (% w/w) 4.79 5.78 4.94 

Nitrogen (% w/w) 1.36 2.8 1.57 

Chlorine (% w/w) 0.1 0.22 0.12 

Sulfur (% w/w) 2.9 0.2 2.5 

Oxygen (% w/w) 5.04 38.72 10.05 

Moisture (% w/w) 5.8 6.3 5.87 

Ash (% w/w) 7.85 0.82 6.8 

The assumed chemical compositions of the quicklime and activated carbon reagents used by 

the process are summarized in the stream tables provided with the process flow diagrams in 

Appendix B. The NOxOUT® reagent used by the SNCR process is an aqueous solution 

containing approximately 50% (w/w) urea, as well as additives to prevent scaling and corrosion. 

Table 6 lists the emission performance targets for the design case. The targeted NOx emission 

rate of ≤0.10 lb/mmBtu at full load represents a NOx removal efficiency by the combined 

combustion modifications, SNCR, and in-duct SCR of ≥67% relative to a pre-installation 

baseline NOx emission rate of approximately 0.30 lb/mmBtu, or a removal efficiency by the 

hybrid SNCR/SCR system of ≥60% relative to the targeted rate of 0.25 lb/mmBtu leaving the 

new combustion system. 
 36

Table 6. Emission performance targets for the design case. 

Parameter Design Target 

NOx ≤0.10 lb/mmBtu (full load) 

NH3 ≤2 ppmvd @ 3% O2 (air heater inlet) 

SO2 ≥95% removal 

SO3 ≥95% removal 

HCl ≥95% removal 

HF ≥95% removal 

Hg ≥90% removal 

6.2 Description by Major Process Component 

Major components of the multi-pollutant control process at AES Greenidge Unit 4 include the 

selective non-catalytic reduction system, in-duct selective catalytic reduction reactor, activated 

carbon injection system, Turbosorp® scrubber, process water system, lime hydration and 

injection system, baghouse, ash recirculation system, and booster fan. 

6.2.1 Selective Non-Catalytic Reduction System 

The urea-based SNCR system, which was supplied by Fuel Tech, is designed to operate 

synergistically with the in-duct SCR reactor to reduce NOx emissions from AES Greenidge Unit 

4. At full load operation, the SNCR system is designed to reduce NOx by about 42%, from 0.25 

lb/mmBtu (190 ppmvd, corrected to 3% O2) leaving the combustion zone to 0.144 lb/mmBtu 

(110 ppmvd, corrected to 3% O2) at the economizer outlet, and to supply a controlled amount of 

ammonia slip (~47 ppmvd, corrected to 3% O2) as a feed to the downstream in-duct SCR 

reactor to permit additional NOx reduction there. Per the discussion in Section 4.2.6, for gross 

generator loads below about 86 MWe, which produce economizer outlet temperatures below the 

minimum SCR operating temperature of 600 °F, the SNCR is designed to reduce NOx

emissions by 20-25% while producing less than 2 ppmvd of ammonia slip. Because of 

concerns about formation of ammonium salts in the SCR catalyst, SNCR operation is 

discontinued when the economizer outlet temperature is less than 528 °F, which occurs when 

the gross generator load falls below about 54 MWe. 

The SNCR system design includes three separate zones of urea injection into the boiler, as 

illustrated in drawing No. 575P-M01-02 in Appendix B. In Zones 1 and 2, diluted urea reagent is 

injected via air-cooled wall injectors that are installed through penetrations in the waterwall. The 

Zone 1 injectors, which are located closest to the combustion zone, are mounted on retract 

mechanisms that allow them to be withdrawn from the furnace when not in use, preventing 

damage that could otherwise result from high furnace temperatures. In Zone 3, diluted urea 

reagent is injected through two 14-15 ft, retractable multiple nozzle lances (MNLs) into the 

superheater section. The MNLs are cooled using plant condensate water. Figure 10 shows 

several of the Zone 1 injectors at AES Greenidge Unit 4, and Figure 11 shows one of the MNLs. 

Because SNCR performance depends strongly on temperature and reagent distribution, as 

discussed in Sections 4.3.3 and 4.3.4, the optimal placement and spray patterns for injectors 

and lances were determined based on CFD and CKM results. Figure 12 provides an example 

of the CFD modeling results that were used in the design of the hybrid NOx control system for 

AES Greenidge Unit 4; both the temperature and velocity profiles (shown here for a case in 
 37

which the unit is operating at 103% of its MCR) were utilized to inform the design of the urea 

injectors. 

Figure 10. Photograph showing several of the

SNCR Zone 1 injectors at AES Greenidge Unit 4.

Figure 11. Photograph showing one of the two 

multiple nozzle lances installed at AES 

Greenidge Unit 4.

 

Figure 12. Example of CFD modeling results used in the design of the 

hybrid NOx control system for AES Greenidge Unit 4 (Boiler 6). Shown are 

temperature and velocity profiles for a case in which the unit is operating at 

103% of its MCR.
 38

The use of multiple urea injection zones is necessary to ensure thorough coverage of the 

reagent throughout the flue gas and to allow injection of urea into different temperature regions 

of the furnace, which is critical to the load-following capabilities of the hybrid SNCR/SCR 

system. At high load, when greater levels of ammonia slip are desired to feed the in-duct SCR 

reactor, urea can be injected into lower temperature regions of the furnace (i.e., by using the 

Zone 2 injectors and Zone 3 MNLs) that promote greater NOx removal via SNCR and greater 

ammonia slip. At reduced loads, however, when ammonia slip from the SNCR is limited to <2 

ppmvd, urea injection is restricted to higher temperature regions of the furnace (i.e., by using 

only the Zone 1 or Zone 2 injectors). 

The liquid, urea-based NOxOUT® reagent used by the SNCR process is delivered to site via 

tank truck and stored in a 15,000-gallon, fiberglass reinforced plastic tank. The tank is heated 

and insulated to maintain its temperature above 80 °F in order to prevent the urea from 

crystallizing and precipitating out of the solution, and it is installed on a curbed concrete 

foundation for spill containment. 

A high flow delivery and circulation (HFD) module is used to supply filtered urea-based reagent 

from the storage tank to the process. The HFD module includes two 100% capacity, 5-hp 

centrifugal pumps (Pump 1A and Pump 1B in drawing No. 100276-SK081706-05) to circulate 

the urea solution and provide it to the injector zone metering (IZM) module, the next step in the 

urea injection process. The HFD module is contained in a heated enclosure located next to the 

urea storage tank; all piping interconnecting the SNCR system components is heat traced and 

insulated to prevent urea crystallization. Figure 13 presents a photograph of the urea storage 

tank and HFD module at AES Greenidge Unit 4. 

HFD Module

Urea Storage Tank

Figure 13. Photograph showing the urea storage tank and HFD module at AES 

Greenidge Unit 4. 

Upon entering the IZM module, which is skid-mounted and installed inside the boiler building, 

the urea solution is diluted with water and distributed to the SNCR system’s three injection 

zones. Dilution water is pressurized and provided to the IZM module by a dilution water 

pressure control module consisting of a pair of 5-hp, skid-mounted stainless steel pumps. The 

IZM module consists of pressure and flow control valves that independently meter the flow and 

concentration of urea solution sent to each injection zone. Four distribution modules, including 
 39

two for Zone 1, one for Zone 2, and one for Zone 3 (the MNLs), are then used to meter the flow 

of diluted urea reagent and atomizing air to the individual injectors in response to the demands 

of the system. Figure 14 presents a photograph of the Zone 2 distribution module. 

Figure 14. Photograph showing the SNCR Zone 2 distribution 

module at AES Greenidge Unit 4.

Urea injection by the SNCR system is controlled automatically based on the boiler load, furnace 

temperature, and NOx emission rate at the stack. The primary control loop utilizes a 

feedforward boiler steam flow rate signal, which is fine-tuned as needed using the furnace 

temperature (measured using an air-cooled optical pyrometer supplied with the SNCR system). 

A feedback control loop is used to trim the SNCR system operation to achieve the desired NOx

emission rate, which is measured by the stack continuous emission monitor (CEM). 

6.2.2 In-Duct Selective Catalytic Reduction Reactor 

Following the SNCR process, the flue gas flows to the in-duct SCR reactor, which is designed to 

further reduce NOx emissions from AES Greenidge Unit 4 to ≤0.10 lb/mmBtu (≤76 ppmvd, 

corrected to 3% O2), with ≤2 ppmvd (corrected to 3% O2) of ammonia slip, when the unit is 

operating at high load. A P&ID of the SCR system is provided as drawing No. 100276-

SK4900050 in Appendix B. All ammonia reagent required for NOx reduction across the SCR 

catalyst is generated by the upstream SNCR process; hence, ammonia storage and injection 

systems are not required. As discussed in Section 6.2.1, the minimum operating temperature 

for the SCR catalyst is 600 °F. Because the SCR design for AES Greenidge does not include 

an SCR bypass, flue gas continues to flow through the catalyst even when temperatures are 

below this value. However, the amount of ammonia fed to the SCR reactor by the upstream 

SNCR process is restricted to ≤2 ppmvd for economizer outlet temperatures between 528 °F 

and 600 °F, and it is restricted to zero (i.e., SNCR operation is discontinued) for economizer 

outlet temperatures below 528 °F, to prevent problems that could otherwise result from 

ammonia slip and ammonium bisulfate formation. 
 40

Per the discussion in Section 4.3.6, the size of the in-duct SCR reactor, and hence the amount 

of catalyst that can be installed to effect NOx removal, is constrained by the available space in 

the plant between the economizer outlet and the air heater inlet. As shown in drawings 100276-

GA200-01, 100276-GA100-01, and 100276-GA101-01 in Appendix B, the SCR system for AES 

Greenidge Unit 4 is designed to fit within the existing boiler building in a space with horizontal 

dimensions of 52’ x 27’ 2” and a vertical height of 23’ 1/2”. The design must account for an 8’ 4-

1/16” offset between the center of the economizer outlet and the center of the air heater inlet. 

This geometry allows for the installation of a single layer of catalyst in a reactor with a horizontal 

cross section measuring 45’ x 14’. The flue gas flows vertically downward through the reactor, 

which is designed to accommodate a volumetric flow rate of about 490,000 acfm at full load. 

The catalyst layer is 1330 mm (4.36 ft) deep and consists of 26 modules of honeycomb catalyst 

(Cormetech) in a 13 x 2 arrangement. The catalyst specified for AES Greenidge Unit 4 is a 

titanium/tungsten-based material that is formulated to provide ≥31% NOx removal efficiency, ≤2 

ppmvd NH3 slip, and <1.0% SO2-to-SO3 conversion over a 3-year operating life. 

In addition to the SCR catalyst and new reactor ductwork, the SCR system includes Delta 

WingTM static mixers, a sonic horn system (see drawing No. 100276-SK4900065 in Appendix 

B), and a catalyst loading facility. Delta WingTM static mixers are used by Riley Power Inc., a 

Babcock Power Inc. company, in domestic SCR installations under an exclusive license from 

Balcke-Durr, GmbH. The previous demonstration of in-duct SCR at GPU Generation Seward 

Unit 5 highlighted the importance of achieving uniform distributions of temperature, velocity, 

composition, and fly ash loading across the reactor cross section (Urbas, 1999) in order to 

maximize NOx reduction, minimize NH3 slip and ammonium bisulfate formation, and prevent fly 

ash plugging. Given these results, the in-duct SCR design for AES Greenidge Unit 4 includes a 

carefully designed system of Delta WingTM static mixers to homogenize the flue gas before it 

enters the SCR reactor. The number, size, and orientation of the static mixers were determined 

on the basis of physical flow modeling, which was conducted by Ruscheweyh Consult GmbH 

using the physical model shown in Figure 15. 

The four sonic horns are used to prevent ash buildup on top of the SCR catalyst. The catalyst 

loading facility is used for manual replacement of deactivated catalyst modules with new 

modules at the end of the catalyst’s useful operating life. It includes a 2-ton electric hoist for 

raising and lowering catalyst modules to the loading platform, as well as a manual hoist, trolley, 

and catalyst loading cart for moving modules between the loading platform and the reactor. 

The SCR system at AES Greenidge Unit 4 originally did not include a large particle ash removal 

system, because LPA was not expected to be a problem with this unit. However, soon after 

start-up, it became apparent that LPA was accumulating in the in-duct SCR catalyst, and the 

SCR was modified to include an LPA removal system, which is now considered to be an 

essential part of the system design. As discussed in Section 4.3.9, the development of an 

effective LPA removal system for AES Greenidge Unit 4 was particularly challenging, because 

the flue gas flows vertically downward between the economizer and SCR reactor, with no 

available 90° bends or hoppers that can be used for inertial capture of the LPA. The LPA 

removal system was initially installed in May 2007, and several improvements have been made 

since then (most recently in May 2008). Figure 16 illustrates the final design. 
 41

Figure 15. Photograph of the physical flow 

model used to design the in-duct SCR reactor 

(courtesy of Ruscheweyh Consult GmbH).

Flue Gas & LPA

from Economizer

SCR Catalyst

LPA to 

Disposal

rake soot blower

static mixers

vacuum ports

LPA screen

hinged seal

expansion joint

rotary soot 

blower 

coverage

Flue Gas & LPA

from Economizer

SCR Catalyst

LPA to 

Disposal

rake soot blower

static mixers

vacuum ports

LPA screen

hinged seal

expansion joint

rotary soot 

blower 

coverage

Figure 16. Schematic of the large particle ash removal system that was installed above 

the in-duct SCR reactor at AES Greenidge Unit 4.
 42

A sloped screen was installed in the ductwork between the economizer and the catalyst, 

intersecting the Delta WingTM static mixers, to capture the LPA from the flue gas. The screen 

consists of perforated carbon steel sheets that are coated with a protective material. The 

perforations are hexagonal; opposing walls of each hexagon are separated by a distance of 

4.00 mm. The screen crosses an expansion joint, and it is therefore installed in two sections 

that are connected by a hinged seal so that it can move with the ductwork. Four rotary soot 

blowers are located beneath the screen to help transport the collected LPA to the base of the 

screen, where it is removed by eight vacuum ports. A rake soot blower was also installed above 

the SCR catalyst to aid the sonic horns in resuspending accumulated fly ash. The rake consists 

of ~350 blow holes that discharge steam at a 45o

 angle relative to the catalyst surface. The 

operating pressure of the rake is adjustable, but it is typically operated at 60 psig. 

Figure 17 shows a photograph of the in-duct SCR reactor at AES Greenidge Unit 4. The LPA 

removal system’s vacuum ports are visible to the right of the reactor. 

Figure 17. Photograph of the in-duct SCR reactor at AES Greenidge 

Unit 4.

6.2.3 Activated Carbon Injection System 

Powdered activated carbon (PAC) can be injected into the flue gas downstream of the air 

heaters, before the Turbosorp® absorber vessel, to adsorb mercury. As discussed in Section 

4.1.3, activated carbon injection is part of an overall mercury control strategy that also includes 

co-benefits afforded by the in-duct SCR, circulating fluidized bed dry scrubber, and baghouse. 

Very effective utilization of the activated carbon and high mercury capture are expected to result 

from the large solids recycle ratio, long residence time, and low temperatures provided by the 

circulating fluidized bed and baghouse. The activated carbon injection system is designed to 

inject 89.3 lb/h of PAC at full load, which corresponds to an injection rate of 3.5 lb PAC / mmacf 

flue gas; however, as discussed in Section 9, performance tests conducted since start-up of the 

multi-pollutant control system have indicated that no PAC is required for 90% Hg capture. 
 43

The activated carbon injection system includes a PAC storage silo and a PAC feed system, as 

shown in drawing No. 100276-SK4900090 in Appendix B. The 750-ft3

 storage silo discharges 

to a feed hopper, from which PAC is metered to an eductor via a screw feeder. An 80 scfm 

blower is used to pneumatically convey the PAC to the duct for injection through a single port. 

The PAC injection rate is controlled based on the flue gas flow rate measured at the stack. 

Figure 18 presents a photograph of the activated carbon injection system at AES Greenidge 

Unit 4. 

Figure 18. Photograph of the 

activated carbon injection system 

at AES Greenidge Unit 4.

6.2.4 Turbosorp® Circulating Fluidized Bed Dry Scrubber 

The flue gas next flows to the Turbosorp® circulating fluidized bed dry scrubbing system, which 

is designed to remove ≥95% of the SO2, SO3, HCl, and HF contained in the flue gas when the 

unit is firing the design fuel. 

The Turbosorp® scrubber at AES Greenidge Unit 4 includes a single absorber vessel that is 

constructed from carbon steel. The vessel, which is 105’ 9-1/2” tall, consists of a venturi inlet 

section and a cylindrical reaction chamber with a diameter of 23’ 9-1/2”. The reactor is 

designed to treat 277,807 scfm (423,700 acfm) of incoming flue gas at ~300 °F. At the inlet of 

the absorber vessel, the flue gas passes through a horizontal duct and a 90o

 turn in the gas 

path (a hopper collects any ash that falls out of the gas at this bend). Once flowing in the 

vertical direction, the flue gas passes through a single venturi nozzle, which accelerates the gas 

just prior to the injection of water, hydrated lime, and recycled solids, thereby supporting the 

fluidized bed in the reaction chamber above. The entire vessel is thoroughly insulated to 

prevent condensation, per the discussion in Section 4.3.11. 

The lime hydration and injection system, process water system, baghouse, and ash recirculation 

system, which are described in subsequent sections, are integral parts of the circulating 

fluidized bed dry scrubbing system. The interconnection among these systems is depicted in 
 44

drawing No. 100276-SK4900095 in Appendix B. Dry hydrated lime reagent (containing ~95% 

w/w Ca(OH)2) is injected into the absorber at a rate of ≤8,623 lb/h (design conditions, full load) 

to react with the SO2, SO3, HCl, and HF in the flue gas. (The projected Ca/S molar ratio for the 

design fuel was ~1.6-1.7, based on the number of moles of SO2 entering the absorber). Water 

is separately injected to evaporatively cool the flue gas to ~162 °F and to moisten the surfaces 

of the particles in the absorber, enhancing the capture of SO2, SO3, HCl, and HF. Finally, >95% 

of the solids captured in the baghouse are recycled to the absorber vessel via the ash 

recirculation system. These recycled solids enable a fast fluidized bed to be established in the 

absorber; the high recycle rate increases the hydrated lime utilization, helping to minimize the 

variable O&M costs associated with the process. Figure 19 presents a photograph showing the 

Turbosorp® absorber vessel and ancillary equipment at AES Greenidge Unit 4. 

Turbosorp®

Absorber 

Vessel

Baghouse

Lime 

Hydration 

System

Quicklime 

Silo

~0.4 acre

Booster 

Fan

Turbosorp®

Absorber 

Vessel

Baghouse

Lime 

Hydration 

System

Quicklime 

Silo

~0.4 acre

Booster 

Fan

Figure 19. Photograph of the Turbosorp® circulating fluidized 

bed dry scrubbing system, including ancillary equipment, at AES 

Greenidge Unit 4. 

Major control loops for the Turbosorp® process are shown in Figure 20. The control strategy 

includes separate PID (proportional-integral-derivative) control loops for each of the four major 

process operations: hydrated lime injection, water injection, solid product recycle, and solid 

product rejection. The hydrated lime injection rate is controlled on the basis of SO2
 45

concentrations measured at the Turbosorp® system inlet and at the stack. Inlet SO2

concentrations are measured using a dilution extractive-type SO2 analyzer installed between the 

air heater outlet and the Turbosorp® absorber inlet; stack SO2 concentrations are measured 

using the unit’s CEM. As inlet SO2 concentrations increase, more hydrated lime is added to the 

Turbosorp® absorber. The hydrated lime injection rate is fine-tuned by a feedback control loop 

based on the stack SO2 measurement. The temperature in the Turbosorp® absorber and the 

flue gas flow rate at the stack control the amount of cooling water that is injected into the 

absorber. The fluid bed density within the absorber (measured as the pressure drop across the 

absorber vessel) controls the amount of ash and scrubber reaction products that are recycled to 

the absorber vessel. Finally, the level of ash and reaction products in the air slides controls the 

rate at which these solids are rejected from the system for disposal. 

Clean Gas 

Outlet

Hydrated 

Lime

Silo

Gas Inlet

Water

Baghouse

To Disposal

A

B

S

O

R

B

E

R

SO2

SO2

∆P

Flow

T

Level

Clean Gas 

Outlet

Hydrated 

Lime

Silo

Gas Inlet

Water

Baghouse

To Disposal

A

B

S

O

R

B

E

R

SO2

SO2

∆P

Flow

T

Level

Figure 20. Process control schematic showing major control loops for the Turbosorp® circulating fluidized 

bed dry scrubber at AES Greenidge Unit 4. Lime injection control is shown in green; water injection 

control is shown in blue; solid product recycle control is shown in red; and solid product rejection control 

is shown in orange.

The Turbosorp® system at AES Greenidge also includes a flue gas recycle stream to enable 

turndown for continued operation at low generator loads. The system was designed to achieve 

≥95% removal of SO2, SO3, HCl, and HF when the unit is operating at any point between its 

minimum load (42 MWg) and full load. As shown in drawing No. 100276-SK101206-03 in 

Appendix A, at minimum load, 43,766 scfm of flue gas is recycled from the booster fan outlet to 

the absorber inlet, increasing the gas flow to the absorber vessel from 136,808 scfm to 180,574 

scfm (250,239 acfm). This flue gas flow rate, which is 65% of the full-load flow rate of 277,807 

scfm, is required to maintain a fluidized bed in the absorber vessel. 

6.2.5 Process Water System 

The process water system is designed to inject about 89 gpm into the Turbosorp® absorber 

vessel at full load operation. Process water from the plant is supplied to a 6,300-gallon heated 

storage tank. This water is then fed to the absorber vessel by a 150-gpm capacity, high-
 46

pressure centrifugal pump and injected through a single lance. The pump and injection lance 

are provided in duplicate to ensure reliability. The P&ID for the process water system is 

provided as drawing No. 100276-SK400093 in Appendix B. Figure 21 shows the process water 

injection lance installed in the Turbosorp® absorber vessel. 

Figure 21. Photograph showing the Turbosorp® water injection 

lance (in service). 

6.2.6 Lime Storage, Hydration, and Injection System 

Because of the high cost of directly purchasing hydrated lime for use in the Turbosorp® system, 

the multi-pollutant control system at AES Greenidge includes a dedicated outdoor lime hydration 

system to produce hydrated lime from quicklime (CaO). For AES Greenidge, the delivered cost 

of hydrated lime is 55-60% greater per mole of Ca than the delivered cost of quicklime. The 

lime hydration and injection system, which is depicted in drawing No. 100276-SK4900091 in 

Appendix B, consists of a quicklime storage silo, commercially available lime hydration system, 

hydrated lime classification and milling system, and hydrated lime storage silo and injection 

system. 

Quicklime is delivered to the AES Greenidge site by truck and pneumatically unloaded into a 

7,500-ft3

 storage silo. This silo is visible in Figure 19. A weigh feeder is used to supply 

quicklime (~6,600 lb/h at design conditions) from the silo to the hydrator, where it is mixed with 

water (~8 gpm at design conditions) and agitated. The quicklime reacts exothermically with the 

water to form raw, dry hydrated lime. Figure 22 shows a photograph of the hydrator at AES 

Greenidge. The original design included a wet scrubber to treat the hydrator exhaust (which 

includes air, steam, and lime dust) and a milk of lime circuit that was partially fed by the wet 

scrubber and was used to supply water to the hydrator. However, these components have 

since been removed from the process (see Section 8.3); the hydrator exhaust is sent to the 

Turbosorp® scrubber rather than to a separate wet scrubber for cleaning, thereby simplifying the 

process and eliminating the potential need to treat and dispose of alkaline milk of lime overflow. 
 47

A bucket elevator is used to deliver the raw hydrated lime from the hydrator to an air classifier, 

which separates out coarse hydrated lime particles and sends them to a ball mill for grinding. 

About 3 gpm of water is required to cool the ball mill bearings. The ground hydrated lime 

leaving the ball mill is returned to the classifier, which is shown in Figure 23. The hydrator, 

classifier, and ball mill are sized for a capacity of 10 short ton/h of solids. Operation of the lime 

hydration system is controlled using a programmable logic controller (PLC) with local operator 

interface units. 

Figure 22. Photograph of the lime hydrator at AES Greenidge. 

The chute in the foreground (with the red door) is used to convey 

hydrated lime from the cyclone to the hydrated lime silo. 

Figure 23. Photograph showing part of the lime hydration 

system at AES Greenidge Unit 4. The hydrated lime classifier, 

cyclone, pebble lime weigh feeder, and bottom of the pebble lime 

storage silo are all visible. 
 48

The powdered hydrated lime leaving the classifier is captured using a cyclone and sent to a 

2,200-ft3

 hydrated lime silo, where it is stored before being sent for injection into the Turbosorp®

absorber vessel. As shown in drawing No. 100276-SK4900092 in Appendix B, a screw 

conveyer delivers hydrated lime from the silo to a distribution hopper, and a rotary feeder is 

used to meter the hydrated lime from the hopper to the Turbosorp® system. A 630-acfm blower 

pneumatically conveys the powdered hydrated lime from the silo to the absorber vessel. The 

hydrated lime feed system is shown in Figure 24. The design also includes the capability to 

accept hydrated lime directly from a delivery truck, enabling continued operation of the 

Turbosorp® system in the event of a problem with the hydrator. 

Figure 24. Photograph showing the system that is used to feed 

hydrated lime to the Turbosorp®

 vessel at AES Greenidge Unit 4. 

6.2.7 Baghouse 

The multi-pollutant control system includes a new pulsejet fabric filter (baghouse) to remove 

particulate matter from the flue gas after it exits the Turbosorp® absorber vessel. A new 

particulate control device was required for AES Greenidge Unit 4 because the unit’s existing 

ESP was not capable of handling the increased particle loading in the flue gas that results from 

the solids recycling that is part of the circulating fluidized bed dry scrubbing process. The 

existing ESP was retired in place. A baghouse was selected for particulate control because it is 

expected to promote better removal efficiencies for SO2, acid gases, mercury, and fine 

particulate matter than an ESP would, as discussed in Section 4.3.13. Key design parameters 

are summarized below. 

Inlet Flue Gas Flow Rate – 371,440 acfm (full load, normal operation) 

Inlet Flue Gas Particle Loading – 244 gr/dscf (full load, normal operation) 

Flue Gas Temperature – 162 °F (full load, normal operation) 

Flue Gas Temperature Range – 150 °F to 350 °F 

Number of Compartments – 8 

Number of Bags – 3168 

Bag Material – Ryton®
 49

Nominal Air-to-Cloth Ratio – 3 (ft3

/min)/ft2

The baghouse is shown in drawing No. 100276-SK4900095 in Appendix B, and it is visible in 

the photograph in Figure 19. Dust laden flue gas from the Turbosorp® absorber enters the top 

of the baghouse and flows through the inlet plenum, vertically upward through the filter bags, 

and through the outlet plenum. Particulate matter is collected on the outside of the filter bags. 

The filter bags are cleaned on-line using pulsejets, which use high-pressure air to cause ash 

that has accumulated on the bags to fall into the hoppers at the bottom of the baghouse. 

Baghouse cleaning is controlled by a local PLC, which is capable of providing data to the plant’s 

DCS. The baghouse design includes inlet baffling and extra space below the bags to improve 

flow distribution, as well as greater-than-normal bag spacing to reduce can velocity (the upward 

velocity component of the dust-laden flue gas as it passes between the filter bags). The 

reduced can velocity promotes settling of dust particles during bag cleaning. Although the 

temperature of the flue gas entering the baghouse is projected to be about 162 °F when the 

multi-pollutant control system is operating normally, temperatures as great as 350 °F may be 

encountered if the Turbosorp® scrubber is not in service. Ryton® bags were specified because 

of their ability to withstand flue gas temperatures of up to 400 °F and their resistance to abrasion 

and acid attack. The entire baghouse is thoroughly insulated, and the baghouse hoppers are 

heated to prevent condensation, which could otherwise cause plugging and corrosion. 

The baghouse is designed for continued operation with only seven of its eight compartments in 

service. Each compartment is equipped with inlet and outlet dampers that can be closed to 

isolate the compartment for on-line bag maintenance. Filter bags are accessed from the top of 

the baghouse. The baghouse structure includes a penthouse to accommodate the bag access 

area, valve actuators and cleaning air manifolds, and PLC. Figure 25 shows the inside of the 

baghouse penthouse. 

Figure 25. Photograph showing the inside of the baghouse 

penthouse at AES Greenidge Unit 4.

In spite of the increased particle loading arising from the multi-pollutant control system, the 

baghouse is designed to achieve particulate emission rates of about 0.01 gr/dscf across all 

generator operating loads. This is about 67% less than the emission rate of 0.03 gr/dscf 

measured from the existing ESP during baseline testing at AES Greenidge. 
 50

6.2.8 Ash Recirculation System 

The solids that are collected in the eight baghouse hoppers are fed into two air slide conveyers 

(one per set of four hoppers) that are collectively designed to process 517,658 lb/h of material at 

full load operation. P&IDs for the air slides are provided as drawing No. 100276-SK4900097 

and drawing No. 100276-SK4900098 in Appendix B. Each air slide conveyer consists of a 

sloped piece of ductwork with a thick fabric material dividing the upper portion of the duct from 

the lower portion. A blower provides air along the bottom portion of each air slide, thereby 

fluidizing the solids on top of the fabric and allowing them to flow by gravity back toward the 

Turbosorp® absorber vessel. The design includes three 891 icfm blowers, each sized to provide 

100% of the fluidizing air flow required for a single slide. (Hence, at any given time, two of the 

blowers will be operating, with the third in standby). The air slides are heated and insulated to 

prevent moisture from condensing on the solids. Figure 26 presents a photograph showing one 

of the air slide conveyers at AES Greenidge Unit 4. 

Figure 26. Photograph of one of the air slide conveyers at AES Greenidge Unit 4.

As discussed above, greater than 95% of the solids are recycled back into the absorber. 

Dosing valves are used to control the solids recycle rate, based on the pressure drop across the 

Turbosorp® reactor. Excess solids are fed through rotary feeders to a pair of ash disposal silos 

(one per air slide), each having a capacity of 720 ft3

, which are tied into the plant’s existing 

pneumatic vacuum ash disposal system. 

6.2.9 Booster Fan 

The multi-pollutant control system at AES Greenidge includes a new flue gas booster fan and 

motor to overcome the increased pressure drop created by the addition of the static mixers, 

SCR catalyst, circulating fluidized bed dry scrubber, baghouse, and longer ductwork runs. The 
 51

plant’s existing ID fans do not afford sufficient capacity to overcome this pressure drop. The 

booster fan also provides the motive force for flue gas recirculation to the Turbosorp® inlet at 

low load operation, as required to maintain adequate fluidizing velocity. The 2068-bhp booster 

fan, which is shown in drawing No. 100276-SK4900096 in Appendix B and pictured in Figure 

27, is installed downstream of the baghouse; its discharge is connected to the suction of the 

existing ID fans. The flue gas recirculation duct is connected between the booster fan and ID 

fans; dampers are used to control the amount of flue gas (if any) that is returned to the absorber 

vessel. The design also includes a booster fan bypass system, consisting of a bypass duct with 

shut-off dampers and actuators, to aid in the plant start-up practice normally employed with the 

existing ID fans. 

Figure 27. Photograph of the booster fan at AES Greenidge 

Unit 4. 

6.3 Balance of Plant Considerations 

6.3.1 Ductwork 

To provide for interconnection among various components of the multi-pollutant control system 

and tie-in of the system to the existing plant, several existing sections of ductwork were 

demolished, and several new sections were installed. Specifically, the design required 

demolition of the section of existing ductwork connecting the economizer to the air heaters in 

order to accommodate the new in-duct SCR reactor, as well as demolition of the sections of 

existing ductwork connecting the air heaters to the ESP and the ESP to the ID fans to allow for 

tie-in of the Turbosorp® system and associated equipment to the existing plant. (As discussed 

in Section 6.2.7, the existing ESP was retired in place). Asbestos insulation had to be properly 

removed and disposed of prior to demolition; this was conducted outside of the scope of the 

DOE project. The general arrangement drawings included in Appendix B illustrate the ductwork 

layout for the AES Greenidge installation. New ductwork sections, which were fabricated from 

1⁄4” carbon steel plate and were insulated and lagged in accordance with design standards, are 

as follows: 
 52

• Economizer outlet to air heater inlet, including SCR reactor ductwork 

• Air heater outlet to Turbosorp® absorber inlet 

• Turbosorp® absorber outlet to baghouse inlet 

• Baghouse outlet to booster fan inlet 

• Booster fan bypass (from baghouse outlet duct to booster fan outlet duct) 

• Booster fan outlet to ID fan inlet 

• Flue gas recirculation duct (from booster fan outlet duct to absorber inlet duct) 

All new ductwork was designed to limit loads imposed on new and existing equipment. 

Supports and expansion joints were included to limit stresses and movement to those specified 

by equipment suppliers and by good engineering practice. 

6.3.2 Civil and Structural 

The general arrangement drawings provided in Appendix B illustrate the layout and structural 

requirements for the multi-pollutant control system installation at AES Greenidge. Per the 

discussion in Section 4.2.3, a strength of the multi-pollutant control system is the relatively small 

amount of space required for its installation. As shown in drawing No. 100276-GA200-01 in 

Appendix B, for the AES Greenidge Unit 4 installation, most of the components of the multipollutant control system are located outdoors in an approximately 125’ x 150’ plot just west of 

the boiler building. Figure 28 shows a photograph of this area taken prior to the start of 

construction. The area is constrained by the boiler building to the east, by a railroad bridge to 

the north, and by embankments to the south and west. The plant’s existing pyrites silo and 

hydrogen dock are also visible in the photo. The system components installed in this area 

include the urea storage tank, urea HFD module, activated carbon injection system, Turbosorp®

scrubber, process water system, lime storage, hydration, classification, and injection system, 

baghouse, ash recirculation system, and booster fan. Hence, only about 0.43 acre of land area 

was required outside of the boiler building to accommodate the multi-pollutant control system for 

the 107-MWe AES Greenidge Unit 4 installation. 

The relatively small acreage required for the Greenidge multi-pollutant control system results 

from a combination of its use of a single-layer, in-duct SCR reactor rather than a full-size, standalone SCR reactor, and its use of a vertically-tiered arrangement for the Turbosorp® system, 

baghouse, and lime storage and hydration system to promote gravity-assisted transport of 

solids (e.g., for recycling baghouse solids to the Turbosorp® vessel, transporting solids from the 

recycle loop to the ash disposal silos, and transporting solids within the lime hydration process). 

This is evident in drawings 100276-GA100-01, 100276-GA101-01, 100-276-ISO100-01, and 

100276-ISO101-01 in Appendix B, as well as in the photographs presented in Figures 17 and 

19. As discussed in Section 6.2.2, the SCR system for AES Greenidge Unit 4 was designed to 

fit within the existing boiler building in a space with horizontal dimensions of 52’ x 27’ 2” and a 

vertical height of 23’ 1/2”. The only other space required in the boiler building is for six SNCR 

dilution and distribution modules and for electrical equipment, which can be flexibly located, as 

well as for the catalyst loading facility and the retract mechanisms for the MNLs. The baghouse 

is elevated to allow for solids recirculation via the air slides; for the AES Greenidge Unit 4 

installation, the bottoms of the baghouse hoppers are about 75’ above ground level and the top 

of the baghouse penthouse is about 150’ above ground level. 
 53

Figure 28. Photograph taken prior to the start of construction of the site for the outdoor 

portion of the multi-pollutant control system, as viewed from the southwest.

Equipment arrangement requirements dictated, to a great extent, the structural design for the 

multi-pollutant control system. Outside of the plant, foundations and structural steel were 

required for each of three primary support structures: 

• Lime storage and hydration system support structure 

• Turbosorp® reactor support structure 

• Baghouse support structure 

These support structures were designed in accordance with all applicable codes and 

incorporate all necessary handrails, access stairs, ladders, floors, and platforms. The 

Turbosorp® reactor and baghouse support structures must be located adjacent to one another 

to facilitate solid product recycle via the air slides. Process constraints on the location of the 

lime storage and hydration system structure are less stringent; however, for the AES Greenidge 

retrofit, the lime structure was able to be situated immediately beside the Turbosorp® structure, 

an ideal location for simplifying transport of the hydrated lime to the Turbosorp® vessel for 

injection. 

Inside the plant, several new horizontal steel beams were required to construct a frame for 

supporting the SCR reactor. The frame was tied into the plant’s existing support columns, 

which were reinforced as needed to accommodate the added load. A new access platform was 

also provided to facilitate catalyst loading and unloading. No new foundations were required for 

the SCR installation. 
 54

A detailed discussion of the civil engineering design for the multi-pollutant control system 

installation at AES Greenidge is beyond the scope of this report. However, the design included 

the following: 

• Site survey 

• Geotechnical study 

• Civil engineering demolition design, including plans for the removal and relocation of 

existing equipment and utilities 

• Civil engineering site design, including site clearing, grubbing, grading, and drainage 

plans 

• Erosion and sedimentation control design 

• Underground utilities design 

• Landscaping design 

• Foundation engineering, including shallow foundations, slabs, or pads for equipment and 

components (e.g., water tank, water pumps, urea tank, HFD module, activated carbon 

silo, duct supports, piping, cable tray, stairway footings, etc.) 

• Protective coatings for exposed structures 

A new paved unloading facility was also provided south of the baghouse to accommodate 

receipt of urea and quicklime deliveries. 

6.3.3 Instruments and Controls 

Process control philosophies for major components of the multi-pollutant control process were 

discussed in Section 6.2. The multi-pollutant control system design included all field 

instrumentation required for operation and control of the system. Much of this instrumentation is 

shown in the P&IDs that are included in Appendix B. In addition to standard temperature, 

pressure, level, and flow sensors and various control valves, this instrumentation includes the 

optical pyrometer required for control of the SNCR system (Section 6.2.1) and the dilution 

extractive-type SO2 analyzer that is used to measure absorber inlet SO2 concentrations for 

control of the Turbosorp® system (Section 6.2.4). 

The SNCR system, lime hydration system, activated carbon injection system, and baghouse are 

each controlled locally by programmable logic controllers with local operator interface units. 

Input/output is hardwired to local junction boxes for interface with the plant’s distributed control 

system. As discussed in Section 5, AES Greenidge upgraded its Unit 4 DCS simultaneously to, 

but outside of the scope of, the multi-pollutant control project. The DCS is an Emerson 

Ovation® system. All other components of the multi-pollutant control system (i.e., sonic horns, 

Turbosorp® system, ash recirculation system, booster fan) are controlled through the DCS. 

6.3.4 Electrical 

The electrical design provided for tie-in of the new equipment to the plant’s existing 2400V 

electrical system and included a new 2400V motor control center (MCC), 2400V/480V 

transformer, and 480V MCC. 2400 VAC power was required for the booster fan motor, and 480 

VAC power was required for the SNCR system pumps, catalyst hoist, activated carbon blower, 
 55

water booster pumps, hydrator, bucket elevator, air classifier, ball mill, hydrated lime blower, 

baghouse bridge crane, baghouse hopper heater panel, air slide blowers, etc. 120 VAC 

electrical connections were also required for instruments and controls, lighting, pipe heat 

tracing, etc. 

Power is fed to the new 2400V MCC and to the new 2400V/480V transformer and 480V MCC 

from two existing 1200A breakers that previously were used for two of the plant’s coal 

pulverizers. The new 2400V MCC includes starters for these pulverizers as well as for the 

booster fan motor. The new 480V MCC includes starters for all other motors associated with 

the multi-pollutant control system. 

The total estimated parasitic power requirement for full-load operation of the multi-pollutant 

control system at AES Greenidge Unit 4 is about 1875 kW (about 1.8% of the unit’s net 

electrical output). The majority of this auxiliary load arises from the approximately 1475 kW net 

increase in fan power brought about by installation of the booster fan to supplement the unit’s 

existing ID fans in overcoming the pressure drop created by installation of the multi-pollutant 

control system. 

6.3.5 Other Utilities 

Water and compressed air requirements for the multi-pollutant control system are summarized 

in drawing No. 100276-SK4900099 in Appendix B. 

The multi-pollutant control system requires water for the SNCR system, hydrator, and 

Turbosorp® water injection system, as well as for cooling various pieces of equipment. Table 7 

summarizes the water requirements for operation of the system. With the exception of the 

condensate that is used for MNL cooling, plant service water (i.e., filtered water obtained from 

Seneca Lake) is the source of all water consumed by the system. The plant’s existing service 

water system had sufficient capacity to meet the demands of the multi-pollutant control system. 

Table 7. Water requirements for operation of the multi-pollutant control system at AES Greenidge.

Operation Source of Water Required Flow Rate (gpm)a

Urea Dilution Plant Service Water 32 

MNL Cooling Condensate 60 

Turbosorp® Water Injection Plant Service Water 89 

Lime Hydration Plant Service Water 8 

Ball Mill Cooling Plant Service Water 3 

Booster Fan Cooling Plant Service Water 16 

a

At full-load operation. 

Compressed air is also required throughout the multi-pollutant control system for actuators, as 

well as for various process operations, including: 

• Urea atomization 

• Sonic horns 

• Baghouse pulsejet cleaning 

Most of the compressed air demand results from baghouse cleaning. The plant’s existing 

compressed air system originally was expected to afford sufficient capacity for satisfying the 

compressed air requirements added by the multi-pollutant control system. However, the 
 56

compressed air demand for baghouse cleaning was greater than anticipated, forcing the plant to 

install additional compressor capacity (outside of the scope of the DOE project). The baghouse 

requires about 600 scfm of compressed air during normal operation. During start-up, however, 

the compressed air demand can be as large as 1200 scfm. 

6.3.6 Byproducts 

The major byproduct generated by the multi-pollutant control system is the solid product 

resulting from the Turbosorp® process. As shown in drawing No. 100276-SK081706-05 in 

Appendix B, the solid reaction products and unreacted reagent resulting from the Turbosorp®

system increase the amount of solids sent from the plant’s particulate control device for disposal 

by a factor of about 3.8, adding about 13,174 lb/h to the approximately 4,676 lb/h of fly ash 

produced when firing the design fuel at full load. (The mass added by activated carbon injection 

is very small, accounting in the original design for ≤89 lb/h, or ≤0.7%, of the 13,174 lb/h of new 

solid byproduct. No activated carbon was used in practice at AES Greenidge Unit 4). AES 

Greenidge modified its pneumatic ash handling system outside of the scope of the DOE-funded 

project to provide sufficient capacity (including a reasonable margin) for accommodating the 

extra solids produced by the multi-pollutant control process. The projected composition of the 

combined solid product is summarized in Table 8. 

Table 8. Projected composition of the fly 

ash / scrubber byproduct discharged 

from the baghouse.

Component Weight 

Percent 

CaSO3 · 1⁄2 H2O 34.1 

Fly Ash 26.2 

CaCO3 13.3 

CaSO4 · 1⁄2 H2O 12.8 

Ca(OH)2 9.5 

CaCl2 1.0 

H2O 1.0 

CaO 0.3 

CaF2 0.2 

Other Solids 1.6 

AES Greenidge landfills this byproduct in its Lockwood Landfill, located near the plant. 

However, as discussed further in Section 10.4, the composition of the material, which resembles 

spray dryer byproduct in that it is dry, has a moderate fly ash content, and contains unreacted 

hydrated lime (Ca(OH)2), makes it a candidate for use as a structural or flowable fill, as a 

neutralizing agent, or as a feedstock for manufactured aggregate production. This may help to 

improve process economics in certain installations of the multi-pollutant control technology (i.e., 

if the plant is situated geographically near an application that can utilize the byproduct). 

Gaseous and liquid waste streams from the multi-pollutant process are minimal. The only 

continuous sources of wastewater are the cooling water stream discharges from the ball mill 

and booster fan, which produce a combined 19 gpm (maximum) of wastewater that is sent to 

drain. As shown in Table 6, the multi-pollutant control process is designed to reduce air 

emissions of a number of pollutants from AES Greenidge Unit 4. The hybrid SNCR/SCR 

process produces ammonia; however, the design limits emissions to ≤2 ppmvd at all operating 
 57

loads. Any SO3 formed from oxidation of SO2 across the SCR catalyst is removed from the flue 

gas in the Turbosorp® system. Also, although the Turbosorp® process and activated carbon 

injection increase the solids loading of the flue gas, the baghouse is expected to reduce the 

unit’s overall particulate matter emission rate. The lime hydration system generates a new 

gaseous exhaust stream containing dust, steam, and lime; however, as discussed in Section 

6.2.6, this stream is sent to the Turbosorp® scrubber and baghouse for cleaning, and it is not 

expected to have a measurable impact on air emissions. 

6.3.7 Out-of-Scope Modifications 

As discussed in Section 5, AES Greenidge undertook a number of projects outside of the scope 

of the DOE-funded multi-pollutant control project to help ensure a 20-30 year life extension for 

Unit 4. Several of these projects, although not included in the scope of the project covered by 

this report, nevertheless warrant coverage here because they were necessary to allow for 

installation of the multi-pollutant control system or to enable it to perform more optimally. These 

projects include the asbestos insulation removal discussed in Section 6.3.1, the DCS upgrade 

discussed in Section 6.3.3, the compressed air capacity expansion discussed in Section 6.3.5, 

and the ash handling system modifications discussed in Section 6.3.6, as well as combustion 

modifications and air preheater basket modifications, which are described in more detail below. 

6.3.7.1 Combustion Modifications 

The combustion modifications at AES Greenidge Unit 4 were designed to complement and 

enhance the performance of the hybrid SNCR/SCR system. Per the discussion in Section 6.1, 

the combustion modifications play an integral role in achieving the targeted NOx emission rate of 

≤0.10 lb/mmBtu, as they are expected to reduce NOx by ~17% (to ~0.25 lb/mmBtu) from the 

plant’s baseline NOx emission rate of ~0.30 lb/mmBtu. Moreover, the combustion modifications 

are designed to enable the SNCR system to operate more optimally by affording more stable 

NOx concentrations in the furnace and reducing CO concentrations in the furnace. As 

discussed in Section 4.3.5, CO concentrations significantly impact SNCR chemistry. 

The combustion modifications include modified burner assemblies and modifications to the 

Boiler 6 SOFA system to improve furnace air staging. The boiler’s existing coal nozzles, 

combustion air nozzles, and overfire air nozzles were replaced. The modified replacement 

combustion air nozzle tips provide an arrangement that offers internal main windbox air staging 

and maintains air penetration into the furnace when the SOFA ports are in use. Internal staging 

is accomplished by redesign of the air nozzle tips to increase the separation of the air streams 

around the fuel streams entering the boiler from each burner windbox. In addition, the design 

includes modified windbox compartment dampers to improve the control of secondary air flow. 

The SOFA system was modified to provide improved jet penetration, and it features nozzles 

with both tilt and yaw adjustment capability, which enable better mixing in the upper furnace and 

reduced CO concentrations during staged, low-NOx firing, thereby creating more ideal 

conditions for SNCR. 
 58

6.3.7.2 Air Preheater Basket Modifications 

As discussed in Section 6.2.2, the in-duct SCR that was installed as part of the Greenidge multipollutant control system is designed to limit ammonia slip to <2 ppmvd (corrected to 3% O2) and 

SO2-to-SO3 conversion to <1.0 % in order to minimize the potential for ammonium bisulfate 

fouling in the unit’s air preheaters. In spite of these stringent performance targets, there 

remains some risk of ammonium bisulfate fouling, especially because the unit fires mid-to-high 

sulfur coals and because the multi-pollutant control system relies on a relatively shallow, single 

catalyst layer to consume almost all ammonia slipped from the SNCR. This risk increases as 

the catalyst ages and its activity decreases. 

Prior to the multi-pollutant control project, the two Unit 4 air preheaters employed a three-layer 

basket configuration, consisting of hot end, intermediate, and cold end layers. This 

configuration is susceptible to ammonium bisulfate fouling, because there is a possibility that 

ammonium bisulfate deposits will bridge across the cold end and intermediate layers, rather 

than being limited to the cold end layer. Bridging of the deposits across layers decreases the 

effectiveness of on-line cleaning and enhances the rate of ammonium bisulfate accumulation. 

As a result, AES Greenidge decided to replace and modify the configuration of the Unit 4 air 

preheater baskets while the multi-pollutant control system was being installed. The 

modifications entailed replacing the three-layer basket arrangement with a two-layer 

arrangement. The existing layer of cold end elements was replaced with a layer of deeper, 

enamel-coated, closed channel elements, and the existing layers of intermediate and hot end 

elements were replaced with a single layer of corrosion-resistant, low-alloy steel elements. This 

reconfiguration helps to ensure that any ammonium bisulfate formed is condensed on the coldend elements, which can be effectively cleaned via soot blowing. The enamel coating on these 

elements helps to prevent adhesion of ammonium bisulfate deposits, facilitate removal of these 

deposits, and resist corrosion. The modifications also included removal of the cold end element 

support screen to allow for more effective soot blowing. 

7. Permitting 

Several permits and permit modifications were required to allow the construction and operation 

of the multi-pollutant control system at AES Greenidge Unit 4. For this project, permit 

requirements were driven in part by the consent decree between AES Greenidge and the State 

of New York, as well as by local, state, and federal requirements. AES Greenidge oversaw the 

project’s permitting tasks. 

Table 9 summarizes the permits required for the project. All permits needed for construction of 

the multi-pollutant control system were obtained in 2005. AES Greenidge obtained a building 

permit for the multi-pollutant control facility from the Town of Torrey on August 10, 2005, and 

worked with the New York State Department of Environmental Conservation (DEC) to determine 

that a Storm Water Discharge Permit was not required for construction of the facility, given the 

size of the construction site. AES Greenidge’s consent decree with the State of New York 

authorized them to proceed with construction and operation of the multi-pollutant control facility 

without a pre-construction permit from the State or any changes to their existing Title V permit. 

The Title V permit was modified as part of its regularly scheduled renewal process, however, in 

order to reflect the emission requirements set forth in the consent decree. The plant’s existing 
 59

Title V permit expired on September 7, 2006, and it was renewed during the project period. 

AES Greenidge received a Notice of Complete Application for its Title V permit from the New 

York State DEC during the second calendar quarter of 2007, and the permit was issued in final 

form by the DEC on November 5, 2007. This newly renewed permit is valid through November 

4, 2012. On February 28, 2008, the DEC approved the curve that establishes the permitted 

NOx emission rate for AES Greenidge Unit 4 as a function of unit load. 

Table 9. Permits required for construction and operation of the multi-pollutant control system at AES 

Greenidge Unit 4.

Permit / Approval 

Approving 

Authority Responsible Party Status 

Building Permit 

Town of 

Torrey AES Greenidge Permit issued 8/10/05. 

Consent Decree 

State of New 

York AES Greenidge Signed 1/11/05. 

Storm Water Discharge 

Permit for Construction 

New York 

State DEC 

Babcock Power 

Environmental Inc. 

Not required because of size 

of construction site. 

Applicable Permits for 

Material Transportation Various 

Babcock Power 

Environmental Inc. Obtained as required. 

Air Title V Facility (8-5763-

00004/00013) 

New York 

State DEC AES Greenidge Permit renewed 11/5/07. 

SPDES NY0001325 - AES 

Greenidge LLC 

New York 

State DEC AES Greenidge 

Permit expired 5/1/07. 

Application for renewal 

submitted. 

SPDES NY0107069 - 

Lockwood Ash Disposal Site 

New York 

State DEC AES Greenidge 

Permit expires 11/30/10. 

Application for renewal 

submitted. 

Solid Waste (8-5736-

00005/00003) 

New York 

State DEC AES Greenidge Permit renewed 9/5/08. 

AES Greenidge also worked throughout the project period to complete all required renewals to 

the State Pollutant Discharge Elimination System (SPDES) permits for the plant and Lockwood 

Landfill (where AES Greenidge disposes its ash) and to the solid waste permit for the Lockwood 

Landfill. Any relevant modifications resulting from the installation of the multi-pollutant control 

system were incorporated during the renewal process. The SPDES permit for the AES 

Greenidge plant expired in May 2007; AES Greenidge submitted a Request for Information 

application to the New York State DEC for that permit in 2007 and is operating under an 

“administratively renewed” permit while the renewal process is completed. The solid waste 

permit for the Lockwood Landfill expired on March 12, 2007, and a renewed permit was issued 

on September 5, 2008. (This permit is valid through September 4, 2018). The existing SPDES 

permit for the Lockwood Landfill expires in November 2010, and AES Greenidge has applied for 

renewal. 

In addition to the permitting requirements discussed above, the DOE cooperative agreement 

required that the project comply with the National Environmental Policy Act. CONSOL prepared 

an Environmental Information Volume for the project and submitted it to DOE on October 27, 

2003. DOE prepared an Environmental Assessment (DOE/EA-1493) and issued a Finding of 

No Significant Impact for the project on December 3, 2004. This completed the NEPA process 

for the project. 
 60

8. Construction, Start-Up, and Commissioning

As shown in Table 1, Babcock Power Environmental Inc. was responsible for the project’s 

construction, start-up, and commissioning tasks. Much of the construction work was performed 

by Nicholson and Hall Corporation (Buffalo, New York), the project’s mechanical contractor, and 

by O’Connell Electric Co. (Victor, New York), the project’s electrical contractor. 

The entire multi-pollutant control system was constructed in less than one year. 

Groundbreaking at AES Greenidge occurred in late December 2005, and the tie-in outage was 

completed on November 18, 2006. Much of the construction was able to be completed while 

Unit 4 was still online, such that the tie-in outage lasted for only about 7 weeks. As discussed in 

Section 3.1, the project’s construction activities were completed on schedule. Start-up and 

commissioning of the system then took approximately 4.5 additional months to complete. 

Per the discussion in Section 6.3.2, the multi-pollutant control system required only 0.43 acre of 

land area was outside of the boiler building to accommodate the Turbosorp® system (including 

all ancillary equipment), the booster fan, and the urea storage tank and HFD module, as well as 

a small amount of space inside the boiler building for the in-duct SCR reactor, SNCR skids and 

MNLs, and electrical equipment. During the construction period, additional space was needed 

for equipment lay-down, construction trailers, and cranes. Prior to the start of construction, 

Nicholson and Hall Corporation developed a site layout plan for the construction period. Two 

lots located west of the boiler building, adjacent to the construction site, were designated as laydown areas. These had a combined area of 0.55 acres. In addition, space was designated for 

two cranes (one to the north and one to the south of the site), as well as six office trailers, two 

tool trailers, and one toilet trailer. 

The project schedule in Appendix A indicates the general progression of construction, start-up, 

and commissioning activities at AES Greenidge. These activities are further described in the 

Project Log, which is included as Appendix D (see the entries for January 2002 through March 

2007). The project’s construction, start-up, and commissioning activities occurred during three 

main stages: the pre-outage construction stage, the tie-in outage stage, and the start-up and 

commissioning stage. These stages are discussed in more detail below. 

8.1 Pre-Outage Construction Activities

A large portion of the multi-pollutant control system was able to be constructed without 

interrupting operation of AES Greenidge Unit 4. Hence, a substantial amount of construction 

was completed prior to the start of the fall tie-in outage in September 2007. Construction 

activities that were wholly or partially completed prior to the outage included: 

• Site excavation outside of the boiler building 

• Construction of foundations and structural steel for the Turbosorp® reactor, baghouse, 

and lime storage and hydration system support structures 

• Construction of ductwork foundations and piers 

• Installation of the Turbosorp® absorber vessel (excluding tie-in to the air heater outlet) 

• Installation of the baghouse 

• Installation of the ash recirculation system 

• Installation of the lime storage, hydration, and injection system 
 61

• Installation of the process water system 

• Installation of the activated carbon injection silo (excluding the injection pipe) 

• Installation of the booster fan (excluding tie-in to the existing ID fans) 

• Installation of the urea storage tank, HFD module, skid-mounted modules, and piping for 

the SNCR system (excluding penetrations into the boiler) 

• Installation of grating and handrails in the Turbosorp®, baghouse, and lime storage and 

hydration system support structures 

• Installation of ductwork interconnecting new pieces of equipment (excluding tie-in 

ductwork) 

• Installation of insulation, lagging, and cladding on outdoor pieces of equipment 

• Assembly of the 2300V/480V transformer and the 480V and 2300V motor control 

centers 

• Installation of conduit, junction boxes, cable tray, and lighting 

In October 2005, CONSOL received pre-award authorization from DOE to mobilize for 

construction and begin civil construction work. The civil subcontractor began mobilizing in late 

December 2007, and trenching and excavation of the site was completed by February 2006. 

DOE further authorized CONSOL in January 2006 to proceed with certain process system 

construction activities. Process system construction began with the installation of structural 

steel for the baghouse in March 2006. Figure 29 shows the progress that had been made as of 

early April 2006. 

Figure 29. Photograph showing structural steel being erected for the baghouse 

support structure on April 6, 2006.

Much of the pre-outage construction work centered on the erection of the Turbosorp® system 

and its ancillary equipment. Figures 30-35 illustrate the progression of major construction 

activities related to the Turbosorp® system. Sections of the Turbosorp® absorber vessel and 

baghouse modules were delivered to site in April 2006 and partially assembled in the lay-down 
 62

area (Figure 30). The baghouse modules and hoppers had been raised into place by the end of 

May 2006. The structural steel frame for the Turbosorp® was also erected in May, and the 

Turbosorp® vessel was raised into place and welded in June (with the exception of the roof, 

which was installed during the first week of July, after work on the inside of the vessel was 

complete). Figure 31 shows one of the baghouse modules being set into place in mid-May. 

Figure 32 shows the assembly of the Turbosorp® inlet duct and venturi in early June, and Figure 

33 shows the Turbosorp® absorber vessel roof being lifted into place in early July. 

Figure 30. Photograph showing several baghouse modules and a partially assembled 

Turbosorp® absorber section in the lay-down area in early May 2006. 

Figure 31. Photograph showing one of the baghouse modules being lifted 

into place in mid-May 2006. 
 63

The water injection pump skid for the process water system was set in place in mid-August 

2006, and both air slides for the ash recirculation system were lifted into place between August 

18 and August 25. Figure 34 presents a photograph showing the installation of one of the air 

slides. Work on installing the penthouse atop the baghouse and on insulating, cladding, siding, 

and roofing the absorber vessel and baghouse continued into September 2006. Also, during 

September, contractors finished installing the approximately 3,200 baghouse bags and cages, 

and they installed the poppet valve actuators and cleaning air headers in the baghouse. The 

baghouse outlet duct was lifted into place during the week ending September 22. 

Figure 32. Photograph showing assembly of the Turbosorp® inlet 

and venturi sections in early June 2006. 
 64

Figure 33. Photograph showing installation of the roof of the Turbosorp® absorber 

during the first week of July 2006. The first pieces of structural steel for the baghouse 

penthouse are also visible. 

The lime storage, hydration, and injection system was constructed beside the Turbosorp®

absorber vessel. First-tier structural steel for the system was erected in July 2006, and the 

hydrated lime silo and ball mill were set in place during that month. Second-tier steel erection 

for the system continued into August. The lime hydrator was lifted into place during the week 

ending August 4, and the quicklime silo was lifted into place on September 22, as shown in 

Figure 35. This was the last major component of the outdoor portion of the multi-pollutant 

control system to be set in place. Other work in the lime hydration structure during September 

included the installation of auxiliary equipment (e.g., bucket elevator, screw conveyer, etc.), 

grating, and handrails. 

The number of contractors on site at AES Greenidge increased from about 35-40 in April 2006 

to 160-170 by the end of September 2006. (These numbers include some contractors who 

were performing work outside of the DOE scope on the projects described at the end of Section 

5). Construction activities intensified significantly in August and September. In addition to the 

work being performed on the Turbosorp® system, lime hydration system, and baghouse, 

contractors worked throughout August and early September on assembling the booster fan for 

the multi-pollutant control system. In addition, several pre-outage construction tasks for the 

SNCR system were completed. Structural steel was installed for the six SNCR skid-mounted 

modules, and these modules were set in place in the boiler building. Installation of piping for the 

SNCR system (e.g., stainless steel tubing from the distribution modules, condensate cooling 

water line to the multiple nozzle lances) also commenced. Outside of the boiler building, the 

urea storage tank and HFD module were set in place during late August and early September. 
 65

Figure 34. Photograph showing one of the air slides being lifted into place on August 

16, 2006. 

Figure 35. Photograph showing the quicklime silo being set in place in September 2006.
 66

Finally, substantial progress was made with the installation of electrical equipment. The 2300V / 

480V transformer and the 480V and 2300V motor control centers were assembled and set in 

place in the plant by the beginning of September. During September, electricians finished 

installing cable tray in the plant and began pulling cable, including the feeder cables for the 

2300V transformer and 480V motor control center and the cables for the booster fan motor. 

Electricians also worked during August and September on installing conduit, junction boxes, and 

lighting, especially in the baghouse structure. 

No major problems were encountered during the pre-outage construction period. As of the end 

of September 2006, construction of the multi-pollutant control system had progressed 

sufficiently to allow the tie-in outage to begin. 

8.2 Tie-In Outage 

The tie-in outage began on September 29, 2006, one day ahead of schedule. Most remaining 

construction activities were completed during this outage, which lasted for 50 days. During the 

outage period, the number of contractors on site at AES Greenidge ranged from 210-250. 

(Again, this number includes some contractors who were performing work outside of the DOE 

scope on the projects described at the end of Section 5). Major construction activities during 

the outage included: 

• Installation of the urea injectors and lances for the SNCR process 

• Demolition of ductwork between the economizer and air heaters, between the air heaters 

and existing ESP, and between the existing ESP and ID fans 

• Installation of the in-duct SCR reactor 

• Tie-in of the Turbosorp® system, baghouse, ash recirculation system, and booster fan to 

the existing plant 

• Completion of various electrical installation tasks 

Demolition work was carried out during the first half of October 2006 to enable the SNCR 

injectors and the SCR reactor to be installed. Contractors erected scaffolding around Boiler 6 

during the first week of October, and they removed lagging and insulation during that week from 

areas where the SNCR injectors would be installed. Demolition of ductwork between the 

economizer outlet and air heater inlet also was completed during the first two weeks of the 

month to allow for installation of the in-duct SCR reactor. By October 21, workers had finished 

modifying the Boiler 6 water wall to create penetrations for the multiple nozzle lances and urea 

injection nozzles for the SNCR system. 

Installation of the SNCR injectors and multiple nozzle lances was completed by mid-November. 

All piping required for the SNCR system was in place by November 17, and workers finished reinstalling insulation and lagging on that day as well. 

Installation of the in-duct SCR system, which was the critical path activity of the tie-in outage, 

was completed on schedule. During the month of October, support steel for the SCR reactor 

was erected in the boiler building; the expansion joint at the economizer outlet was installed, 

and construction of the SCR reactor casing commenced. Construction was completed during 

the first half of November. The Delta Wing static mixers had been installed by November 11, 

and workers loaded catalyst into the reactor and finished seal welding the reactor casing during 

the week of November 12. The sonic horns, catalyst hoist, and access platforms were also 
 67

installed, and the SCR reactor was insulated and lagged. Figure 36 presents a photograph 

taken on October 27, when construction of the SCR reactor was just beginning. Figure 37 

shows the catalyst modules being loaded into the reactor on November 10. 

Figure 36. Photograph taken on October 27, 2006, at the start of SCR reactor 

construction.

Construction work during the outage also included tie-in of the Turbosorp® system and 

associated equipment into the existing plant. Demolition of ductwork from around the existing 

ESP was completed by October 17 to allow for tie-in of the Turbosorp® system, and installation 

of the ductwork (and associated expansion joints) connecting the air heater outlet duct to the 

inlet of the Turbosorp® vessel was completed during the week of November 12. In addition, the 

last section of ductwork connecting the new booster fan to the existing ID fans was installed in 

mid-October. 

 

All major electrical equipment wiring for the multi-pollutant control system had been completed 

by the end of October 2006. During that month, electricians set the control panel and variable 

frequency drive panel for the hydrator in place, pulled cable in the baghouse penthouse, 

modified the old 2400V motor control centers to allow for connection of the new motor control 

centers, finished all remaining terminations for the 480V switchgear, completed hi-pot testing of 

the 2300V feeder cables, and successfully energized the 2300V transformer and bumped the 

booster fan motor. The 480V motor control center was energized during the first week of 

November. 

Also during the outage, miscellaneous remaining construction activities related to the 

Turbosorp® system, baghouse, lime hydration system, ash recirculation system, and activated 

carbon injection system were completed. For example, workers finished installing the activated 

carbon feed and injection system, the heating system for the ash recirculation air slides, the 
 68

water spray nozzles for the Turbosorp® system, and the baghouse plenum doors. They also 

finished installing piping for the lime hydration system. The air slides and various ductwork 

sections were insulated and lagged, and piping tie-ins (e.g., for service air, instrument air, 

potable water, fire protection, etc.) were completed. The 200-ton crane was disassembled and 

removed from the AES Greenidge site during the first half of November, and civil work for the 

quicklime and urea unloading area, which had been delayed until the demobilization of this 

crane, was completed. 

Figure 37. Photograph showing catalyst modules being loaded into the SCR 

reactor in November 2006.

The tie-in outage ended on schedule on November 18, when BPEI released Boiler 6 to AES 

Greenidge. As with the pre-outage construction activities, no significant problems were 

encountered during the tie-in outage. 

8.3 Start-Up and Commissioning 

Start-up and commissioning activities at AES Greenidge commenced during the summer of 

2006, prior to the completion of construction. AES Greenidge and BPEI met during the week 

ending August 18, 2006, to begin planning for start-up and commissioning of the multi-pollutant 

control system. BPEI’s start-up and commissioning manager arrived on site in late August to 

prepare the turnover and training packages. The operating and maintenance manuals for the 

multi-pollutant control system were completed in October 2006, and on November 2-3 and 6-7, 

BPEI held training sessions for AES Greenidge employees regarding operation and 

maintenance of the multi-pollutant control system. 
 69

Most of the start-up and commissioning work, however, was completed between mid-November 

2006 and late March 2007. Hence, it occurred during the winter months, which allowed cold 

weather-related problems (e.g., involving heat tracing, insulation, etc.) to be identified and 

resolved. Start-up and commissioning activities were finished about two months behind 

schedule, largely because of delays arising from the following issues: 

• Late completion of the Unit 4 turbine outage (outside of the scope of the DOE project) 

• Problem with the booster fan soft start 

• Modification of the lime hydration system 

• Accumulation of large particle ash in the in-duct SCR reactor 

These issues, as well as other minor problems that were encountered and resolved during the 

start-up and commissioning period, are described in more detail in the paragraphs below. 

As discussed above, BPEI released Boiler 6 to AES Greenidge for operation on November 18. 

However, two issues delayed start-up of Unit 4 and of the multi-pollutant control system. 

First, the Unit 4 turbine outage, which was conducted by AES Greenidge simultaneously to the 

tie-in outage (but outside of the scope of the DOE project), ran several days behind schedule. 

The turbine was released to AES Greenidge on the evening of November 22, but problems with 

the turbine supervisory instrumentation and the hydraulic trip circuit delayed start-up by another 

week. These problems were resolved, however, and the Unit 4 generator was synchronized to 

the power grid on November 30. 

Further delays arose from a problem with the soft start for the booster fan, which was within the 

scope of the DOE project. On November 24, an attempted start-up of the fan caused activation 

of the station service differential protection relay, blacking out the entire plant. Subsequent 

testing of the station service transformer and differential protection relay indicated no problems, 

and power to the plant was restored. AES Greenidge was able to operate Unit 4 at reduced 

load while bypassing the booster fan, but actual start-up of the multi-pollutant control system 

could not occur until the fan was operational. BPEI, Industry and Energy Associates, and 

Rockwell Automation worked throughout late November and early December to resolve the 

problem, and they succeeded in doing so on December 4, when workers discovered that the 

soft start controller was not properly grounded, corrected the problem, and started the fan. 

While these problems were being resolved, the baghouse filter bags were pre-coated, and 

commissioning tasks were performed successfully for a number of equipment items (e.g., air 

slide blowers, various SNCR system components, process water pump, etc.) associated with 

the multi-pollutant control system. Start-up and commissioning activities proceeded normally 

throughout the rest of December. After synchronizing Unit 4 to the power grid on December 7, 

AES Greenidge gradually ramped up the unit’s load while Babcock Power commissioned the 

new combustion system. Although it was conducted outside of the DOE scope, this combustion 

system work had to be completed before start-up of the hybrid SNCR/SCR system could occur. 

As of late December, Unit 4 was operating at full load, and the new low-NOx burners were 

achieving a NOx emission rate of about 0.27 lb/mmBtu, close to the target rate of 0.25 

lb/mmBtu. Regarding pollution control equipment within the DOE scope, the baghouse was in 

service throughout the month of December, and various commissioning activities were 

completed for the SNCR system, Turbosorp® system, and lime hydration system, although none 

of these systems started up during the month. On December 15, workers established a 

fluidized bed in the Turbosorp® absorber using accumulated fly ash (no hydrated lime was 
 70

injected) and successfully operated the Turbosorp® system for a time with water injection and 

baghouse ash recycling while Unit 4 was running at about 65 MW. On December 20, the first 

shipment of pebble lime was delivered to the Greenidge site; BPEI was working at the end of 

the month to improve the lime unloading system in response to several problems that were 

encountered while transporting the lime from the delivery truck to the storage silo. 

Initial optimization of the combustion system was completed in January 2007, and Fuel Tech 

representatives returned to the AES Greenidge site during the week of January 22 to begin 

start-up of the SNCR system. The first load of urea was delivered to the site on January 23. 

Urea injection tests were performed beginning on January 26, and on February 6, the hybrid 

SNCR/SCR system was operated in “cascade” mode (i.e., such that the SNCR is used to 

generate ammonia slip for the SCR) for the first time. This initial, approximately three-hour test 

run was successful. The system was able to maintain stable emissions below the target rate of 

0.10 lb/mmBtu throughout the test while Unit 4 was operating at ~108 MWgross. Testing and 

optimization of the hybrid SNCR/SCR system at full load and at reduced load continued 

throughout the month of February. Tuning of the system was hindered in late February by high 

CO concentrations in the furnace, which are indicative of less-than-optimal combustion and can 

adversely affect SNCR performance. Adjustments were made to the unit’s combustion system 

to correct this problem, and tuning of the system was completed during the first half of March. 

Start-up of the lime hydration system commenced on January 12. However, it was quickly 

determined that modifications to the system were required to prevent excessive overflow of milk 

of lime. As discussed in Section 6.2.6, the system originally included a wet scrubber to remove 

particulate matter from the hydrator exhaust gas and a milk of lime circuit that was fed partially 

by the scrubber bottom liquid; the modifications involved eliminating the wet scrubber and milk 

of lime circuit from the process (although these pieces of equipment have not been physically 

removed from the lime hydration structure) and routing the hydrator exhaust to the Turbosorp®

system. Figure 38 presents a photograph showing installation of the new ductwork used to 

transport the hydrator exhaust to the inlet of the Turbosorp® absorber vessel. The water 

required for lime hydration is now fed directly to the hydrator. BPEI completed these 

mechanical modifications during the second half of January, and they made corresponding 

required modifications to the control system for the lime hydration system during late January 

and the first half of February. The lime hydration system was successfully started up during the 

week of February 19. 

While the modifications to the lime hydration system were being made, AES Greenidge 

purchased hydrated lime to allow start-up of the Turbosorp® system to proceed. Hydrated lime 

and water injection tests were performed beginning on January 13. The Turbosorp® system 

was operated for short periods of time on January 15 and 16, and then it was operated during a 

series of tests throughout the rest of January as BPEI and Austrian Energy worked to tune its 

performance. SO2 removal efficiencies between 90% and 100% were achieved consistently 

during these optimization tests. Progress on optimization of the Turbosorp® system was 

hampered during early February by frigid temperatures and weather protection problems that 

caused frozen lines and valves. These problems were resolved by February 8, and the 

Turbosorp® system was operated occasionally during the next few weeks using purchased 

hydrated lime (at a limited injection rate to reduce cost). 

The plant also experienced a problem during February with failing baghouse cleaning valve 

diaphragms. Dustex, the baghouse supplier, remedied the problem by replacing the failed 

diaphragms at no cost to AES, and the valves have since operated normally. 
 71

Figure 38. Photograph showing the installation of the new ductwork used to transport 

the hydrator exhaust to the inlet of the Turbosorp®

 vessel. 

Finally, problems caused by large particle ash accumulation in the in-duct SCR reactor delayed 

start-up and commissioning activities. As a result of the LPA, Unit 4 had to be taken offline on 

February 2-4, March 2-4, and March 22-24 so that the SCR catalyst could be cleaned and 

inspected. (The catalyst was also cleaned during outages on January 3-7 and February 9-10 

that were not directly caused by the LPA). These outages for catalyst cleaning interfered with 

start-up activities. The LPA problem is discussed in detail in Section 10 of this report. 

On February 27, AES Greenidge successfully operated all of the components of the multipollutant control system, with the exception of the activated carbon injection system, while Unit 

4 was running at about 91 MW. The activated carbon injection system was commissioned 

during the week of March 19. Hence, by the end of March 2007, all of the components of the 

multi-pollutant control system had been commissioned successfully and were ready for 

operation. 

9. Performance Testing

Following the completion of start-up of the multi-pollutant control system in March 2007, the 

project entered an approximately 18-month operation and testing period during which the 

performance of the system was evaluated. The project’s performance testing tasks were led by 

CONSOL Energy Inc. Research & Development. This section details the design of the project’s 

testing program, the sampling and analytical methods that were employed, and the performance 

testing results. 
 72

9.1 Approach

The performance testing program was designed to evaluate both the short-term performance of 

the multi-pollutant control system while it operated under design conditions and the longer-term 

performance of the system while it ran under a range of conditions characteristic of routine 

commercial operation. The performance was evaluated using operating data that were 

collected routinely by the plant, as well as data that were collected during several special test 

series conducted by CONSOL at AES Greenidge. The design of the test program is described 

in more detail in the subsections below. 

9.1.1 Plant Operating Data

Operating data from AES Greenidge Unit 4 and from the multi-pollutant control system were 

collected continuously throughout the 18-month performance evaluation period using the plant’s 

online instrumentation. These data were used to evaluate the long-term, day-to-day 

performance of the multi-pollutant control system (e.g., for NOx emissions, urea consumption, 

SO2 removal efficiency, pressure drop across the SCR catalyst, etc.) and to provide information 

concerning plant operations during the special test series. CEM data, including SO2 and NOx

emission rates, percent CO2 in the flue gas, stack flow rate, unit load, and heat input, were 

compiled using the CEM system’s data acquisition and handling system (DAHS). Other plant 

data (i.e., data from the unit’s DCS) were compiled using a PI system. These data included: 

• Ambient conditions (temperature, pressure, relative humidity) 

• Unit load (net, gross, station service) 

• Coal feed rates 

• Steam temperatures, pressures, and flow rate at multiple locations 

• Combustion system data 

• Urea flow rates 

• Other SNCR system data 

• Flue gas temperatures at the SCR inlet and outlet 

• Pressure drop across the SCR reactor (catalyst and catalyst + LPA screen) 

• Pressure drop across the air heaters 

• SO2 concentration at the Turbosorp® inlet 

• Temperature and pressure at the Turbosorp® inlet and outlet 

• Lime hydration system operating conditions 

• Process water system operating conditions 

• Baghouse temperatures and pressures 

• Booster fan data (e.g., amperage) 

• CEM data (SO2, NOx, CO2, stack flow rate) 

Hourly average CEM data and PI data were provided to CONSOL by AES Greenidge on a 

monthly basis. CEM data were provided between January 2007 and September 2008. PI data 

were provided between June 2007 (when the PI system was implemented) and September 

2008. During the special test series, data with a higher resolution (i.e., 1-, 2-, or 5-minute 

averages) were provided. (For test series conducted before June 2007, data were obtained 

directly from the plant’s data historian). 
 73

In addition to the continuously collected data, lime delivery tonnages were recorded by AES 

Greenidge and provided to CONSOL between January 2007 and September 2008 for use in 

tracking long-term sorbent utilization in the Turbosorp® system. AES Greenidge also 

determined the ammonia content of fly ash collected approximately once every three days (on 

average) between June 4, 2007, and September 29, 2008. These data were provided to 

CONSOL for use in evaluating the performance of the hybrid SNCR/SCR system. 

Finally, CONSOL obtained 2005 CEM data from AES Greenidge Unit 4 for use in representing 

the unit’s NOx and SO2 emissions prior to the project. 

9.1.2 Special Test Series

The special test series were conducted to determine the performance of the multi-pollutant 

control system for pollutants (i.e., Hg, SO3, HCl, HF, NH3, and particulate matter) that are not 

measured by the plant’s CEM, and to enable an evaluation of the performance of the system 

under controlled conditions (e.g., fuel, unit load, scrubber operating conditions). Four special 

test series were conducted as part of the project: the baseline tests, the guarantee tests, the 

process performance tests, and the follow-up tests. Each test series consisted of one or more 

field sampling campaigns at AES Greenidge, during which flue gas and solid and liquid process 

samples were collected under a prescribed set of unit operating conditions. The samples were 

then submitted to the laboratory for chemical or physical analysis, and the resulting data were 

reduced and analyzed to determine the results of the test. The flue gas sampling schedules 

from all of the field sampling campaigns at AES Greenidge are provided in Appendix E. The 

objectives of the special test series, and the work performed during each sampling campaign, 

are described in more detail in the subsections below. The sampling locations, sampling and 

analytical methods, and quality control procedures that were employed for the tests are 

discussed in Section 9.2, and the results of the tests are presented in Section 9.3. 

9.1.2.1 Baseline Testing 

The baseline tests were conducted at AES Greenidge Unit 4 on November 17-18, 2004, prior to 

the installation of the multi-pollutant control system, in order to obtain data for use in designing 

the multi-pollutant control system and to establish a baseline against which the performance of 

the system could be compared. The tests were conducted while Unit 4 fired eastern U.S. 

bituminous coal containing 1.9-2.1% (dry basis) sulfur (2.7-3.0 lb SO2/mmBtu). With the 

exception of two SO3 tests at the air heater outlet, all tests were conducted while the unit was 

operating at or near full load. The following flue gas measurements were completed: 

• Three Hg tests at the stack (full load) 

• Three SO3 tests with simultaneous sampling at the air heater inlet, air heater outlet, and 

stack (full load) 

• Two SO3 tests at the air heater outlet (low load) 

• Three HCl and HF tests at the stack (full load) 

• Three PM tests at the stack (full load, conducted as part of the HCl and HF tests) 

Solid process samples, including coal, bottom ash, economizer hopper ash, and ESP hopper 

ash, were also collected for analysis during the sampling period in order to supplement the flue 

gas testing results. 
 74

9.1.2.2 Guarantee Testing 

Guarantee testing was conducted at AES Greenidge Unit 4 between March 2007 and June 

2007. The purpose of the guarantee tests was to determine whether the multi-pollutant control 

system could achieve its performance targets while the unit operated at or near design 

conditions. The initial sampling campaign for guarantee testing occurred on March 28-30, 2007. 

This campaign was designed to evaluate all of the performance targets associated with the 

multi-pollutant control system. However, the testing results for ammonia slip, SO3 removal, HCl 

removal, and HF removal obtained during the March sampling campaign were either 

inconsistent with the performance targets or inconclusive. Hence, additional sampling 

campaigns were required on May 1-4 (for SO3, HCl, HF, and ammonia slip), May 30-June 1 (for 

ammonia slip), and June 20-21 (for ammonia slip) to demonstrate attainment of these 

performance targets. These sampling campaigns are described below. 

9.1.2.2.1 Sampling Campaign on March 28-30, 2007

The tests on March 28-30, 2007, were designed to evaluate the performance targets for NOx

emissions, SO2 removal efficiency, Hg removal efficiency, SO3 removal efficiency, HCl removal 

efficiency, HF removal efficiency, and ammonia slip. The tests were conducted while AES 

Greenidge Unit 4 operated at or near full load and fired eastern U.S. bituminous coal containing 

2.5-2.8% (dry basis) sulfur (3.6-4.0 lb SO2/mmBtu). The following flue gas measurements were 

completed: 

• Three NOx tests with simultaneous sampling at the SCR inlet and outlet sampling grids 

• Three ammonia slip tests at the SCR outlet 

• Three SO2 tests with simultaneous sampling at the air heater outlet and baghouse outlet 

• Three Hg tests with simultaneous sampling at the air heater outlet and stack (no 

activated carbon injection) 

• Three Hg tests with simultaneous sampling at the air heater outlet and stack (with 

activated carbon injection) 

• Three SO3 tests with simultaneous sampling at the air heater outlet and stack 

• Three SO3 tests with simultaneous sampling at the SCR inlet and outlet 

• Three HCl and HF tests with simultaneous sampling at the air heater outlet and stack 

• Nine PM tests with simultaneous sampling at the air heater outlet and stack (conducted 

as part of the Hg tests and the HCl and HF tests) 

The grid point NOx measurements at the SCR inlet and outlet and the SO2 measurements at the 

air heater outlet and baghouse outlet were performed by Clean Air Engineering (CAE); all other 

measurements were performed by CONSOL. In addition to the manual flue gas measurements, 

NOx and SO2 emissions were measured continuously throughout the testing period by the unit’s 

stack CEM, and SO2 concentrations at the Turbosorp® inlet were measured using the dilution 

extractive-type SO2 analyzer that is permanently installed between the air heaters and 

Turbosorp® system. 

Solid and liquid process samples, including coal, pebble lime, hydrated lime, Turbosorp®

product ash, Turbosorp® hopper ash, activated carbon, and urea, were also collected 

throughout the testing period to allow for an assessment of system performance during the 

period and for the completion of Hg mass balances. Finally, AES Greenidge and BPEI 

monitored urea, lime, and carbon consumption rates and the pressure drop across system 
 75

components to determine whether performance guarantees associated with these parameters 

were satisfied. 

9.1.2.2.2 Sampling Campaign on May 1-4, 2007

The sampling campaign on May 1-4, 2008, was conducted to repeat the guarantee tests for 

ammonia slip, SO3 removal efficiency, HCl removal efficiency, and HF removal efficiency. (As 

discussed above, the results for these parameters obtained during the March sampling 

campaign were either inconsistent with the performance targets or inconclusive). Again, AES 

Greenidge Unit 4 operated at or near full load during the test period, and it fired eastern U.S. 

bituminous coal containing 3.1-3.4% (dry basis) sulfur (4.4-4.9 lb SO2/mmBtu). The following 

flue gas measurements were completed: 

• Four ammonia slip tests with simultaneous sampling at the SCR outlet and air heater 

inlet 

• Three SO3 tests with simultaneous sampling at the air heater outlet and stack 

• Two HCl and HF tests with simultaneous sampling at the air heater outlet and stack 

The methods used to sample ammonia slip and SO3 were modified for the May tests in order to 

improve the representativeness and sensitivity of the measurements (see the discussion in 

Section 9.2). In addition to the manual flue gas measurements, NOx and SO2 emissions were 

measured continuously throughout the testing period by the unit’s stack CEM, and SO2

concentrations at the Turbosorp® inlet were measured using the dilution extractive-type SO2

analyzer that is permanently installed between the air heaters and Turbosorp® system. Various 

plant operating data and process samples (i.e., coal and fly ash from the air heater outlet) were 

also collected during the test period and analyzed to aid the interpretation of the flue gas 

sampling results. 

9.1.2.2.3 Sampling Campaign on May 30-June 1, 2007 

The ammonia slip tests performed during the May 1-4 testing campaign still did not demonstrate 

attainment of the performance target of ≤2 ppmvd (corrected to 3% O2) ammonia slip. As 

discussed in Section 10.2.1, AES Greenidge installed a new large particle ash removal system 

and a fresh SCR catalyst layer during an outage on May 17-25, 2008; it was suspected that LPA 

accumulation in the catalyst could have affected the ammonia slip testing results in early May. 

Therefore, on May 30-June 1, following the outage, CONSOL and Clean Air Engineering 

performed additional ammonia slip, NOx, and CO testing around the in-duct SCR reactor. The 

objectives of this series of measurements were to determine the effects of the newly installed 

LPA screen on the NOx removal performance of the in-duct SCR and to determine whether 

installation of the screen and replacement of the catalyst enabled the hybrid SNCR/SCR system 

to achieve its ammonia slip target. Unit 4 operated at or near full load and fired eastern U.S. 

bituminous coal containing 2.7-2.8% (dry basis) sulfur (3.9-4.1 lb SO2/mmBtu) during the test 

period. 

Grid-point NOx, CO, CO2, and O2 measurements at the SCR inlet and outlet sampling grids 

were performed throughout the day on May 30 and May 31 as personnel from BPEI and Fuel 

Tech worked to tune the Unit 4 combustion system and the SNCR system. CONSOL and Clean 
 76

Air Engineering conducted side-by-side ammonia slip sampling at the air heater inlet on the 

evening of May 31 (1 test) and during the first half of the day on June 1 (2 tests). CONSOL also 

simultaneously sampled for ammonia at the economizer outlet during each test. Various plant 

operating and emissions data, including urea flow rates and NOx emissions measured by the 

stack CEM, were collected throughout the test period to aid with the interpretation of the 

ammonia slip results. The testing indicated that the system still was not meeting its 

performance target for ammonia slip. 

9.1.2.2.4 Sampling Campaign on June 20-21, 2007 

CONSOL performed additional ammonia slip sampling at AES Greenidge on June 20 and 21, 

2008. The purpose of these tests, which were conducted after BPEI and Fuel Tech completed 

additional tuning of the hybrid SNCR/SCR system during the first half of June, was to determine 

whether this tuning enabled the multi-pollutant control system to satisfy its performance 

guarantee for ammonia slip. Unit 4 operated at or near full load and fired eastern U.S. 

bituminous coal containing ~2.5% (dry basis) sulfur (3.6 lb SO2/mmBtu) during the test period. 

(Clean Air Engineering was also on site during the test period, outside of the scope of the DOE 

cooperative agreement, to perform NOx and CO grid point sampling. Data from two of the grid 

traverses on June 20 were provided by AES Greenidge for use in this report). 

Three ammonia slip tests were completed at the air heater inlet on June 20; the third of these 

tests demonstrated attainment of the ammonia slip guarantee. Two additional ammonia slip 

tests were performed on June 21 while AES Greenidge, BPEI, and Fuel Tech worked to 

establish a set of acceptable boiler operating conditions for routine operation of the NOx control 

system. Various plant operating and emissions data, including urea flow rates and NOx

emissions measured by the stack CEM, were also collected throughout the test period to aid 

with the interpretation of the ammonia slip results. 

9.1.2.3 Process Performance Testing 

The process performance tests were conducted to build upon the results of the guarantee tests 

by establishing the performance of the multi-pollutant control system as a function of changes in 

various plant operating conditions. The process performance test series included six sampling 

campaigns between October 2007 and June 2008. These sampling campaigns, which were 

conducted on October 2-5, October 8-11, November 13-16, March 10-13, May 19-22, and June 

16-19, were designed to examine the effects of changes in unit load, fuel (e.g., coal sulfur 

content, biomass co-firing), urea injection scheme, and Turbosorp® process operating 

conditions (i.e., calcium-to-sulfur ratio, approach to adiabatic saturation temperature) on the 

performance of the system. In addition to pollutant removal efficiencies and emission rates, 

performance metrics such as reagent utilization, ammonia slip, SO2-to-SO3 conversion across 

the SCR catalyst, and Hg oxidation across the SCR catalyst were evaluated during the process 

performance tests. The six process performance test sampling campaigns are described in the 

subsections below. 
 77

9.1.2.3.1 Sampling Campaign on October 2-5, 2007 

The tests on October 2-5, 2007, were conducted to evaluate the performance of the multipollutant control system while AES Greenidge Unit 4 fired a higher-than-normal sulfur coal. 

During the test period, Unit 4 operated at or near full load, and it fired eastern U.S. bituminous 

coal containing 3.1-3.4% (dry basis) sulfur (4.4-4.9 lb SO2/mmBtu). NOx and SO2

concentrations at the stack were measured continuously during the test period using the unit’s 

CEM, and SO2 concentrations at the Turbosorp® inlet were measured using the dilution 

extractive-type SO2 analyzer that is permanently installed between the air heaters and 

Turbosorp® system. The following manual flue gas measurements were also completed: 

• Three Hg tests with simultaneous sampling at the SCR inlet, SCR outlet, air heater 

outlet, and stack (no activated carbon injection) 

• Two Hg tests with simultaneous sampling at the air heater outlet and stack (with 

activated carbon injection) 

• Two SO3 tests with simultaneous sampling at the air heater outlet and stack 

• Four SO3 tests with simultaneous sampling at the SCR inlet and SCR outlet 

• Two HCl and HF tests with simultaneous sampling at the air heater outlet and stack 

• Seven PM tests with simultaneous sampling at the air heater outlet and stack 

(conducted as part of the Hg tests and the HCl and HF tests) 

In addition to the flue gas measurements, various plant operating data and solid and liquid 

process samples (i.e., coal, bottom ash, fly ash from the air heater outlet, pebble lime, hydrated 

lime, Turbosorp® product ash, activated carbon, urea, and process water) were collected during 

the test period for use in evaluating the performance of the multi-pollutant control system. 

 

As discussed in Section 10.2.2.1, the lime hydration system was often unable to keep up with 

the increased hydrated lime demand resulting from the higher-sulfur coal fired during the 

October 2-5 test period. The hydrated lime classifier plugged numerous times on October 3 and 

October 4, causing the lime hydration system to trip. This hindered the tests that were planned 

for those days; however, AES Greenidge was diligent in unplugging the hydrator and in taking 

deliveries of hydrated lime to allow the tests to proceed. 

9.1.2.3.2 Sampling Campaign on October 8-11, 2007 

The tests on October 8-11, 2007, were conducted to examine the effects of changes in the Ca/S 

molar ratio and approach to adiabatic saturation temperature on the multi-pollutant removal 

performance of the Turbosorp® system. During these tests, Unit 4 operated at or near full load 

and fired eastern U.S. bituminous coal containing 2.8-2.9% (dry basis) sulfur (4.0-4.3 lb 

SO2/mmBtu). NOx and SO2 concentrations at the stack were measured continuously throughout 

the test period using the unit’s CEM, and SO2 concentrations at the Turbosorp® inlet were 

measured using the dilution extractive-type SO2 analyzer that is permanently installed between 

the air heaters and Turbosorp® system. 

The Turbosorp® system was operated with a different targeted Ca/S molar ratio on each of 

October 8, October 9, and October 10, while all other relevant set points were held constant. 

(The Ca/S was changed by putting the SO2 trim control in manual mode and varying the trim 

multiplier setting). The Turbosorp® outlet temperature set point was maintained at 160 oF on 

these three test days. On each day, the following tests were completed: 
 78

• One Hg test with simultaneous sampling at the air heater outlet and stack (no activated 

carbon injection) 

• One SO3 test with simultaneous sampling at the air heater outlet and stack 

• One HCl and HF test with simultaneous sampling at the air heater outlet and stack 

• Two PM tests with simultaneous sampling at the air heater outlet and stack (conducted 

as part of the Hg test and the HCl and HF test) 

(Coal mill problems on October 9 caused early termination of the Hg test on that day). 

On October 11, the plan was to replicate the settings from October 8 and then increase the 

Turbosorp® outlet temperature set point by 5 °F (to 165 °F). However, the SO2 removal 

efficiency was lower on October 11 than on October 8 under these settings, and the 

temperature could not be raised by 5 °F while still maintaining SO2 emissions within the plant's 

permit limit. As a result, the tests on October 11 were conducted with a 165 °F Turbosorp®

outlet temperature set point, but with the hydrated lime injection set to control automatically to a 

0.2 lb/mmBtu SO2 emission rate. (SO2 emissions on October 8 averaged <0.05 lb/mmBtu). 

One Hg and PM test and one SO3 test, each including simultaneous sampling at the air heater 

outlet and stack, were completed under these conditions. 

Finally, during each day of testing between October 8 and October 11, an ammonia slip test 

was conducted at the air heater inlet. Various plant operating data and solid and liquid process 

samples (i.e., coal, bottom ash, fly ash from the air heater outlet, pebble lime, hydrated lime, 

Turbosorp® product ash, activated carbon, urea, and process water) were also collected 

throughout the test period for use in evaluating the performance of the system. 

9.1.2.3.3 Sampling Campaign on November 13-16, 2007 

The tests on November 13-16 were designed to evaluate the performance of the multi-pollutant 

control system when AES Greenidge Unit 4 operated at reduced loads (resulting in varied urea 

injection schemes) and when it co-fired biomass with coal. During the test period, the unit fired 

eastern U.S. bituminous coal containing 2.5-2.8% (dry basis) sulfur (3.7-4.4 lb SO2/mmBtu). 

Moreover, during the tests on November 16, it co-fired waste wood from a furniture 

manufacturing process, which had a higher heating value of 7500-7600 Btu/lb (as fired) and a 

sulfur content of 0.2-0.3 lb SO2/mmBtu. 

During the overnight period on November 13-14, Unit 4 operated at low load (~56 MWg) and 

fired 100% coal. CONSOL completed three ammonia slip tests at the air heater inlet, three SO3

tests with simultaneous sampling at the air heater outlet and stack, and two Hg and PM tests at 

the stack under these conditions. All three ammonia slip tests were conducted while urea was 

only being injected into Zone 1 of the SNCR system. 

During the overnight period on November 14-15, Unit 4 operated at intermediate loads (~79-84 

MWg) and fired 100% coal. CONSOL completed four ammonia slip tests at the air heater inlet, 

three SO3 tests with simultaneous sampling at the air heater outlet and stack, and two Hg and 

PM tests at the stack under these conditions. One of the ammonia slip tests was conducted 

while urea was being injected into Zones 1 and 2 of the SNCR system; two ammonia slip tests 

were conducted while urea was being injected into Zones 2 and 3, and the final ammonia slip 
 79

test was conducted while urea was injected into all three SNCR zones (the urea injection 

scheme changed partway through this test). 

AES Greenidge Unit 4 began co-firing waste wood on November 15 in preparation for the tests 

on November 16; however, one of the hydrated lime classifier fan bearings failed that day, 

forcing the plant to take the hydrator offline. Biomass co-firing was discontinued, and the tests 

were delayed until sufficient deliveries of hydrated lime could be secured to enable full-load 

operation of the Turbosorp® system. Biomass co-firing resumed at about 10:30 am on 

November 16, and the unit operated near full load (102-103 MWg) during the tests on that day. 

(The plant had no means for measuring the biomass feed rate, so it was estimated as 5% of the 

total heat input for purposes of this report). CONSOL completed three ammonia slip tests at the 

air heater inlet, two SO3 tests with simultaneous sampling at the air heater outlet and stack, and 

one Hg and PM test with simultaneous sampling at the air heater outlet and stack under these 

conditions. All three ammonia slip tests were conducted while urea was being injected into 

Zones 2 and 3 of the SNCR system. 

As with the tests in October, NOx and SO2 concentrations at the stack were measured 

continuously throughout the November 13-16 test period using the unit’s CEM, and SO2

concentrations at the Turbosorp® inlet were measured using the dilution extractive-type SO2

analyzer that is permanently installed between the air heaters and Turbosorp® system. Various 

plant operating data (e.g., load, urea flow rates) and solid and liquid process samples (i.e., coal, 

wood, fly ash from the air heater outlet, pebble lime, hydrated lime, Turbosorp® product ash, 

urea, and process water) also were collected for use in the performance evaluation. 

9.1.2.3.4 Sampling Campaign on March 10-13, 2008 

The tests on March 10-13, 2008, were designed to further evaluate the performance of the 

multi-pollutant control system while AES Greenidge Unit 4 co-fired biomass with coal. The 

biomass used during the March 2008 tests was waste wood from a sawmill. This waste wood 

had a lower heating content (~5000-6900 Btu/lb, as fired) than the furniture manufacturing 

waste wood used during the November 2007 process performance tests. During the tests on 

March 10-13, Unit 4 fired eastern U.S. bituminous coal containing 2.3-2.5% (dry basis) sulfur 

(3.4-3.6 lb SO2/mmBtu), and it co-fired the sawmill waste wood at ~1.8-3.2% of the total heat 

input. (The waste wood feed rate was estimated from screw feeder data from the biomass 

processing system. These data were then multiplied by a correction factor derived by 

comparing long-term screw feeder data with delivery truck weigh slips). The unit operated at or 

near full load during the tests. NOx and SO2 concentrations at the stack were measured 

continuously during the test period using the unit’s CEM, and SO2 concentrations at the 

Turbosorp® inlet were measured using the dilution extractive-type SO2 analyzer that is 

permanently installed between the air heaters and Turbosorp® system. The following manual 

flue gas measurements were also completed: 

• Four Hg tests with simultaneous sampling at the economizer outlet, air heater inlet, air 

heater outlet, and stack (no activated carbon injection) 

• Four SO3 tests with simultaneous sampling at the economizer outlet, air heater inlet, air 

heater outlet, and stack 

• Four HCl and HF tests with simultaneous sampling at the air heater outlet and stack 

• Eight PM tests at the stack (conducted as part of the Hg tests and the HCl and HF tests), 

and four PM tests at the air heater outlet (conducted as part of the HCl and HF tests) 
 80

• Four ammonia slip tests at the air heater inlet 

On March 10 and 13, several tests also were conducted without urea injection in order to 

establish the NOx emission rate from the unit’s low-NOx combustion system, without the hybrid 

SNCR/SCR system in service. (No manual flue gas sampling was performed during these 

tests; NOx emissions were measured by the unit’s stack CEM). 

In addition to the flue gas measurements, various plant operating data and solid and liquid 

process samples (i.e., coal, wood, bottom ash, fly ash from the air heater outlet, pebble lime, 

hydrated lime, Turbosorp® product ash, urea, and process water) were collected during the test 

period for use in evaluating the performance of the multi-pollutant control system. 

9.1.2.3.5 Sampling Campaign on May 19-22, 2008 

The tests on May 19-22, 2008, were designed to generate additional information about 

the performance of the multi-pollutant control system at reduced unit loads, and in particular, to 

thoroughly characterize the performance of the NOx control system (i.e., ammonia slip, NOx and 

CO concentration profiles around the SCR) as a function of load. During the test period, AES 

Greenidge Unit 4 fired eastern U.S. bituminous coal containing 2.0-2.4% (dry basis) sulfur (3.0-

3.6 lb SO2/mmBtu). 

During the overnight period on May 19-20, CONSOL completed two Hg tests at low unit load 

(56-57 MWg), each of which included simultaneous sampling at the economizer outlet, air heater 

inlet, and stack. PM was also measured as part of the tests at the stack. 

During the overnight period on May 20-21, CONSOL completed four ammonia slip tests at the 

air heater inlet at intermediate unit loads (80-91 MWg). Two of these tests were performed with 

urea injection into Zones 1 and 2 of the SNCR system, and two were performed with urea 

injection into Zones 2 and 3 of the SNCR system. In addition, two SO3 tests and two HCl, HF, 

and PM tests, each including simultaneous sampling at the air heater outlet and stack, were 

completed during this period. Clean Air Engineering measured NOx concentrations at the SCR 

inlet and outlet sampling grids and CO concentrations at the SCR inlet sampling grid while 

Zones 1 and 2 of the SNCR system were in operation.

On the morning of May 21, three additional ammonia slip tests were performed at the air heater 

inlet while Unit 4 operated at full load (108-110 MWg). Urea was being injected into Zones 2 

and 3 of the SNCR system during this period. Clean Air Engineering measured NOx

concentrations at the SCR inlet and outlet sampling grids and CO concentrations at the SCR 

inlet sampling grid during these tests. Urea injection was briefly discontinued at the end of the 

test period in order to establish the NOx emission rate from the unit’s low-NOx combustion 

system at full load, without the hybrid SNCR/SCR system in service. 

 

Finally, during the overnight period on May 21-22, CONSOL completed three ammonia slip tests 

at the air heater inlet at low unit load (56 MWg), while urea was only being injected into SNCR 

Zone 1. Again, Clean Air Engineering measured NOx concentrations at the SCR inlet and outlet 

sampling grids and CO concentrations at the SCR inlet sampling grid while these tests were 

being conducted. Urea injection was briefly discontinued at the end of the test period in order to 

establish the NOx emission rate from the unit’s low-NOx combustion system at low load, without 

the hybrid SNCR/SCR system in service. In addition, three SO3 tests and three HCl, HF, and 
 81

PM tests, each including simultaneous sampling at the air heater outlet and stack, were 

completed while Unit 4 operated at low load.

 

NOx and SO2 concentrations at the stack were measured continuously throughout the May 19-

22 test period using the unit’s CEM, and SO2 concentrations at the Turbosorp® inlet were 

measured using the dilution extractive-type SO2 analyzer that is permanently installed between 

the air heaters and Turbosorp® system. Various plant operating data (e.g., load, urea flow 

rates) and solid and liquid process samples (i.e., coal, fly ash from the air heater outlet, pebble 

lime, hydrated lime, Turbosorp® product ash, and urea) also were collected for use in the 

performance evaluation. 

9.1.2.3.6 Sampling Campaign on June 16-19, 2008 

The tests on June 16-19, 2008, were designed to further evaluate the effects of changes in the 

Ca/S molar ratio and approach to adiabatic saturation temperature on the multipollutant removal performance of the Turbosorp® system. During the test period, AES 

Greenidge Unit 4 operated at or near full load and fired eastern U.S. bituminous coal containing 

2.5-2.6% (dry basis) sulfur (3.5-3.7 lb SO2/mmBtu). 

The Turbosorp® operating conditions were altered for each of the four test days. On June 16, 

17, and 18, the scrubber was operated with SO2 emission rate set points of 0.28 lb/mmBtu, 0.17 

lb/mmBtu, and 0.066 lb/mmBtu, respectively (corresponding to SO2 removal efficiencies of 

approximately 92%, 95%, and 98%), while its outlet temperature set point was maintained at 

160 oF. Then, on June 19, the SO2 emission rate set point was maintained at 0.18 lb/mmBtu 

(corresponding to ~95% removal efficiency) while the outlet temperature set point was raised to 

165 oF. (The strategy of allowing the system to automatically control to a specified SO2

emission rate produced more stable, predictable data than the strategy employed during the 

October 8-11, 2007, sampling campaign, which attempted to specify the Ca/S molar ratio rather 

than the SO2 emission rate). 

NOx and SO2 concentrations at the stack were measured continuously during the test period 

using the unit’s CEM, and SO2 concentrations at the Turbosorp® inlet were measured using the 

dilution extractive-type SO2 analyzer that is permanently installed between the air heaters and 

Turbosorp® system. The following manual flue gas measurements were also completed on 

each test day: 

• One Hg test at the stack (no activated carbon injection) 

• Three SO3 tests with simultaneous sampling at the air heater outlet and stack 

• Two HCl and HF tests with simultaneous sampling at the air heater outlet and stack 

• Two PM tests with simultaneous sampling at the air heater outlet and stack (conducted 

as part of the HCl and HF tests) 

At the end of each day, after the system had been allowed to line out for at least 6.5 hours 

under the prescribed operating conditions, Turbosorp® product ash samples were collected in 

duplicate for use in determining the Ca/S molar ratio. Other process samples (i.e., coal, fly ash 

from the air heater outlet, pebble lime, and hydrated lime) and plant operating data were also 

collected on each test day for use in this determination. 
 82

9.1.2.4 Follow-Up Testing 

The follow-up tests were designed to reevaluate the performance of the multi-pollutant 

control system under guarantee test conditions after it had operated commercially for more than 

one year. These tests were completed during a single sampling campaign on June 10-13, 

2008. During the follow-up testing period, AES Greenidge Unit 4 operated at or near high load 

and fired eastern U.S. bituminous coal containing 2.4-2.6% (dry basis) sulfur (3.3-3.7 lb 

SO2/mmBtu). (The coal sulfur content during the follow-up testing period was slightly lower than 

it had been during the guarantee tests; however, CONSOL, DOE, and AES Greenidge agreed 

to proceed with the tests using this coal). 

NOx and SO2 concentrations at the stack were measured continuously during the test period 

using the unit’s CEM, and SO2 concentrations at the Turbosorp® inlet were measured using the 

dilution extractive-type SO2 analyzer that is permanently installed between the air heaters and 

Turbosorp® system. The following manual flue gas measurements were also completed: 

• Four Hg tests with simultaneous sampling at the economizer outlet, air heater inlet, and 

stack (no activated carbon injection) 

• Four SO3 tests with simultaneous sampling at the economizer outlet, air heater inlet, air 

heater outlet, and stack 

• Four HCl and HF tests with simultaneous sampling at the air heater outlet and stack 

• Eight PM tests at the stack (conducted as part of the Hg tests and the HCl and HF tests), 

and four PM tests at the air heater outlet (conducted as part of the HCl and HF tests) 

• Four ammonia slip tests at the air heater inlet 

In addition to the flue gas measurements, various plant operating data and solid and liquid 

process samples (i.e., coal, bottom ash, fly ash from the air heater outlet, pebble lime, hydrated 

lime, Turbosorp® product ash, and urea) were collected during the test period for use in 

evaluating the performance of the multi-pollutant control system. 

9.2 Experimental

All flue gas sampling, solid and liquid process sample collection, laboratory analysis, and data 

reduction was conducted or overseen by CONSOL Energy Inc. Research & Development. 

Samples were collected and analyzed using standard methods published by the U.S. 

Environmental Protection Agency or ASTM International (ASTM), whenever applicable. The 

methods and procedures used for sample collection, laboratory analysis, and quality assurance 

and quality control (QA/QC) are described in the subsections below. 

9.2.1 Flue Gas Measurements

9.2.1.1 Sampling Locations 

Figure 39 presents a schematic showing the locations where flue gas sampling was conducted 

during the guarantee tests, process performance tests, and follow-up tests at AES Greenidge 

Unit 4. These sampling locations are described below. Appendix F presents photographs 

showing the flue gas sampling locations. 
 83

During the baseline tests, the stack sampling location was the same as described below. 

However, the air heater inlet and air heater outlet locations differed from those described below, 

owing to a different ductwork configuration prior the installation of the multi-pollutant control 

system. During the baseline tests, SO3 sampling at the air heater inlet was conducted at a 

single point in the “A” duct between the economizer and the air heater inlet, and SO3 sampling 

at the air heater outlet was conducted using two points: one in the “A” duct and one in the “B” 

duct between the air heater outlet and the ESP inlet. Samples were collected at a constant 

sampling rate for 30-36 minutes at the air heater inlet, and for 40 minutes (20 minutes per point) 

at the air heater outlet. 

Urea 

Dilution / 

Distribution 

Modules

APH

Boiler

Urea Tank

Baghouse

Quick 

Lime 

Silo

Hydrated 

Lime

Silo Hydrator

Activated

Carbon

Bin

H2O

Stack

Dry Residue

SCR

1 Bed

SNCR

Air

Dilution

Water

Fluidized

Bed

Absorber

To 

Disposal

Clean Flue 

Gas

Flue Gas Recycle (Reduced Loads)

Booster 

Fan

Existing 

ID Fans

Coal 

Biomass

1

2

3

4

5

6

7

1. Economizer Outlet

2. SCR Inlet

3. SCR Outlet

4. Air Heater Inlet

5. Air Heater Outlet

6. Baghouse Outlet

Urea 7. Stack

Dilution / 

Distribution 

Modules

APH

Boiler

Urea Tank

Baghouse

Quick 

Lime 

Silo

Hydrated 

Lime

Silo Hydrator

Activated

Carbon

Bin

H2O

Stack

Dry Residue

SCR

1 Bed

SNCR

Air

Dilution

Water

Fluidized

Bed

Absorber

To 

Disposal

Clean Flue 

Gas

Flue Gas Recycle (Reduced Loads)

Booster 

Fan

Existing 

ID Fans

Coal 

Biomass

1

2

3

4

5

6

7

1. Economizer Outlet

2. SCR Inlet

3. SCR Outlet

4. Air Heater Inlet

5. Air Heater Outlet

6. Baghouse Outlet

7. Stack

Figure 39. Schematic showing the locations where flue gas sampling was performed during performance 

testing of the multi-pollutant control system at AES Greenidge Unit 4.

9.2.1.1.1 Economizer Outlet

NH3, Hg, and SO3 tests were conducted at the economizer outlet sampling location. This 

location consists of four, four-inch ports located downstream of the economizer but upstream of 

the in-duct SCR catalyst, static mixers, and large particle ash screen. Two of these ports 

(labeled E-1 and E-3) are located on the eastern wall of the economizer outlet duct, and the 

other two (labeled W-1 and W-3) are located on the western wall of the duct. On both the 

eastern and western sides of the economizer outlet, a support beam level with the sampling 

ports is located inside the duct at a depth of several feet. These support beams prevented the 

performance of isokinetic traverses of the economizer outlet duct. Hence, all sampling through 

the ports at the economizer outlet was conducted at a constant sampling rate (even if the 
 84

method called for isokinetic sampling) at the deepest point that could be reached using a 10-12 

foot probe. (In some instances, the probe was inserted at an angle to allow it to pass under the 

support beam). 

During the NH3 tests on May 31–June 1, 2007, a composite sample was extracted from all four 

ports. During the 60-minute ammonia slip test on May 31, each of these ports was sampled for 

15 minutes. During the 40-minute ammonia slip tests on June 1, each port was sampled for 10 

minutes. 

During the Hg tests on March 11, March 12, May 19-20, June 12, and June 13, 2008, a 

composite sample was extracted from all four ports. In general, each port was sampled for 30 

minutes, resulting in a total test time of 120 minutes. (The first test on March 12 was 105 

minutes long). Because the primary objective of the tests was to determine gas-phase Hg 

speciation, the sampling train nozzle was oriented away from the direction of flow to minimize 

the collection of particulate matter. 

In general, during the SO3 tests on March 10, March 13, June 10, and June 11, 2008, a 

composite sample was extracted from all four ports. Each port was sampled for 15 minutes, 

resulting in a 60-minute total test. However, because of problems with leaks in the sample train 

during the June 2008 test period, only three ports were sampled during the first test on June 10 

(one port was sampled for two 15-minute intervals), and only two ports were sampled during the 

second test on June 11 (each port was sampled for 25 minutes, for a total test time of 50 

minutes). 

9.2.1.1.2 SCR Inlet

NOx, CO, Hg, and SO3 tests were conducted at the SCR inlet sampling location. The eastern 

wall of the SCR inlet duct is outfitted with four, four-inch flange ports, each of which contains six 

permanent sampling tubes. The six tubes installed through each of the four ports terminate at 

different depths in the duct, creating a 24-point grid of sample points covering the cross section 

of the duct. In addition, a single, four-inch port is located at approximately the center of the 

eastern wall of the SCR inlet duct (below the Delta Wing static mixers, but above the SCR 

catalyst). Manual flue gas sampling can be conducted through this port, although conventional 

probes can only cover about 20-25% of the 45-foot duct width at this location. 

Clean Air Engineering performed NOx testing on March 28, 2007, and NOx and CO testing on 

May 30-31, 2007, June 20, 2007, and May 21-22, 2008, using an automated sampling system 

that sequentially extracted samples from the 24-point permanent sampling grid at the SCR inlet. 

Each of the 24 grid points was sampled for a one-minute interval during each 24-minute test. A 

diagram showing the locations of the SCR inlet grid sampling points is provided in the CAE 

reports that are included in Appendix G to this report. 

During the Hg tests on October 2 and 3, 2007, sampling was conducted using a 10-foot probe 

inserted at a constant depth through the four-inch sampling port in the center of the eastern wall 

of the SCR inlet duct. The sampling was conducted at an isokinetic sampling rate; test times 

ranged from 100-120 minutes. 

During the SO3 tests on March 30, October 4, and October 5, 2007, sampling was conducted 

using an 8- or 12-foot probe inserted at a constant depth through the four-inch sampling port in 

the center of the eastern wall of the SCR inlet duct. The sampling was conducted at a constant 
 85

rate. Each test on March 30 was 40 minutes in duration. The test on October 4 was terminated 

early because the sampling train glassware failed. The tests on October 5 were each 60 

minutes in duration. 

9.2.1.1.3 SCR Outlet

NOx, CO, NH3, Hg, and SO3 tests were conducted at the SCR outlet sampling location. As with 

the SCR inlet duct, the eastern wall of the SCR outlet duct is outfitted with four, four-inch flange 

ports, each of which contains six permanent sampling tubes. The six tubes installed through 

each of the four ports terminate at different depths in the duct, creating a 24-point grid of sample 

points covering the cross section of the duct. In addition, two four-inch ports are located on the 

eastern wall of the SCR outlet duct, downstream of the SCR outlet sampling grid, which can be 

used for manual sampling. One of these ports is located closer to the northern side of the duct 

wall, and the other is located closer to the southern side. 

Clean Air Engineering performed NOx testing on March 28, 2007, and May 21-22, 2008, and 

NOx and CO testing on May 30-31, 2007, and June 20, 2007, using an automated sampling 

system that sequentially extracted samples from the 24-point permanent sampling grid at the 

SCR outlet. Each of the 24 grid points was sampled for a one-minute interval during each 24-

minute test. A diagram showing the locations of the SCR outlet grid sampling points is provided 

in the CAE reports that are included in Appendix G to this report. 

During the NH3 tests on March 28, 2007, samples were drawn through the northernmost of the 

two four-inch ports downstream of the SCR outlet sampling grid; the port was traversed to a 

depth of approximately 10 feet using three sample points. Each test was 60 minutes in 

duration. During the NH3 tests on May 1, 2007, samples were drawn through both the northern 

and southern ports downstream of the SCR outlet sampling grid; each port was sampled for 30 

minutes per test using a three-point traverse to a depth of approximately 10 feet. All ammonia 

samples at the SCR outlet were drawn at an isokinetic sampling rate. 

During the Hg tests on October 2 and 3, 2007, samples were drawn isokinetically using a 10-

foot probe inserted through the northernmost of the two four-inch ports downstream of the SCR 

outlet sampling grid. Test times ranged from 90-120 minutes. 

During the SO3 tests on March 30, October 4, and October 5, 2007, sampling was conducted 

using an 8- or 12-foot probe inserted at a constant depth through the northernmost of the two 

four-inch ports downstream of the SCR outlet sampling grid. Each test on March 30 was 40 

minutes in duration, and each test on October 4-5 was 60 minutes in duration. 

9.2.1.1.4 Air Heater Inlet 

NH3, Hg, and SO3 tests were conducted at the air heater inlet sampling location. All sampling at 

the air heater inlet was conducted through two ports located immediately upstream of the unit’s 

two air heaters. One port is located at approximately the center (horizontal dimension) of the 

south wall of the eastern air heater inlet duct, and the other port is located at approximately the 

center of the south wall of the western air heater inlet duct. (These ports are downstream of the 

SCR outlet sampling ports described above). For all of the tests conducted at the air heater 

inlet as part of the project, the south wall of the boiler building prevented the use of a probe 
 86

capable of reaching the exact center (in the north/south dimension) of the duct. Hence, 

samples were drawn from a point located as close as possible to the center of the duct. 

During the NH3 tests on May 1, 2007, samples were drawn at a constant rate from a single point 

located near the center of each of the eastern and western ducts. Each 60-minute test 

consisted of 30 minutes of sampling in the eastern duct and 30 minutes of sampling in the 

western duct, resulting in a composite sample representing the average concentration in both 

ducts. During each NH3 test on May 31 and June 1, 2007, CONSOL and Clean Air Engineering 

simultaneously performed NH3 sampling through the air heater inlet ports. During the first half 

of each test, one group sampled the eastern duct while the other group sampled the western 

duct. The groups then exchanged positions for the second half of the test, such that each 

collected a composite sample representing the average concentration in both ducts. Both 

groups drew samples at a constant rate from a single point located near the center of each duct. 

The test on May 31 was 60 minutes in duration, and the tests on June 1 were each 40 minutes 

in duration. During each NH3 test on June 20 and 21, 2007, CONSOL used two sampling trains 

to simultaneously extract separate samples from the eastern and western air heater inlet ducts. 

Each sample was drawn at a constant rate from a single point located near the center of the 

duct. With the exception of the first test in the western duct, which lasted 50 minutes, all of the 

tests on June 20 and 21 were 40 minutes in duration. During all remaining NH3 tests (i.e., on 

October 8-11, 2007, November 13-16, 2007, March 10 and 13, 2008, May 20-22, 2008, and 

June 12-13, 2008), samples were drawn at a constant rate from a single point located near the 

center of each of the eastern and western ducts, resulting in a composite sample representing 

the average concentration in both ducts. Sampling was conducted for either 40 minutes (i.e., 20 

minutes in each duct) or 60 minutes (i.e., 30 minutes in each duct), as indicated in the Field 

Sampling Data Sheets provided in Appendix H. 

During the Hg tests on March 11-12, May 19-20, and June 12-13, 2008, samples were drawn at 

a constant rate from a single point located near the center of each of the eastern and western 

ducts, resulting in a composite sample representing the average concentration in both ducts. All 

tests were 120 minutes in duration, with 60 minutes of sampling in each duct, except for the 

second test on March 12, which was 108 minutes long. Because the primary objective of the 

tests was to determine gas-phase Hg speciation, the sampling train nozzle was oriented away 

from the direction of flow to minimize the collection of particulate matter. 

During the SO3 tests on March 10, March 13, and June 10-11, 2008, samples were drawn at a 

constant rate from a single point located near the center of each of the eastern and western 

ducts, resulting in a composite sample representing the average concentration in both ducts. All 

tests were 120 minutes in duration, with 60 minutes of sampling in each duct. 

9.2.1.1.5 Air Heater Outlet 

SO2, Hg, SO3, HCl, HF, and PM tests were conducted at the air heater outlet sampling location. 

This location is situated along a stretch of horizontally-oriented ductwork (i.e., such that the flue 

gas flows parallel to the ground) between the air heater outlet and Turbosorp® inlet. The duct is 

rectangular with dimensions of approximately 12 ft by 9.5 ft. Sampling was conducted through 

three vertically-oriented (i.e., positioned perpendicular to the ground) four-inch flange ports and 

through two vertically-oriented two-inch ports located just downstream of the four-inch ports. 

The dilution extractive-type SO2 analyzer that is permanently installed at the air heater outlet is 

located in line with the two-inch ports. 
 87

During the SO2 tests on March 29, 2007, sampling was conducted by Clean Air Engineering 

using a CEM inserted through one of the two-inch ports described above. For the first two tests 

on that day, the sample was drawn from a single point in this port. For the third test, a threepoint traverse was performed through the same port. Each SO2 test was 60 minutes in duration. 

All other SO2 measurements at the air heater outlet were performed using the plant’s dilution 

extractive-type SO2 analyzer. 

During the Hg tests at the air heater outlet (i.e., on March 28 and 30, 2007, October 2-3, 2007, 

October 5, 2007, October 8-11, 2007, November 16, 2007, and March 11-12, 2008), samples 

were drawn by traversing the duct through all three four-inch flange ports. Each port was 

sampled at three points of varying depth, resulting in a nine-point traverse. (Several tests had 

to be terminated early, precluding the completion of all nine traverse points). With the exception 

of the test on October 9, 2007, which was discontinued when coal mill problems forced the unit 

to derate, all of the Hg tests at the air heater outlet were 100-126 minutes in duration. The tests 

on March 11-12, 2008, were conducted at a constant sampling rate, with the nozzle oriented 

away from the direction of flow to minimize the collection of particulate matter. All other Hg tests 

at the air heater outlet were conducted isokinetically and included simultaneous particulate 

matter sampling. (A cyclone was employed during the first test on October 3, 2007, in an 

attempt to minimize the amount of particulate matter that accumulated on the sampling train 

filter). 

During the SO3 tests at the air heater outlet (i.e., on March 29, 2007, May 2, 2007, October 4-5, 

2007, October 8-11, 2007, November 13-16, 2007, March 10 and 13, 2008, May 21-22, 2008, 

June 10-11, 2008, and June 16-19, 2008), sampling was conducted at one or more points 

through either the four-inch ports or the two-inch ports. For the testing on March 29, 2007, 

samples were drawn at a constant rate from a single point through one of the four-inch ports. 

For the testing on May 2, 2007, samples were drawn via a twelve-point traverse through the 

three four-inch flange ports. For all subsequent SO3 tests, samples were generally drawn from 

1-3 points through each of the two two-inch ports. All SO3 sampling was performed at a 

constant rate. Test durations ranged from 40-70 minutes, although most tests were 60 minutes 

long. 

During the HCl and HF tests at the air heater outlet (i.e., on March 29, 2007, May 4, 2007, 

October 4-5, 2007, October 8-10, 2007, March 10 and 13, 2008, May 21-22, 2008, June 10-11, 

2008, and June 16-19, 2008), samples were drawn by traversing the duct through all three fourinch flange ports. For the tests on May 4, 2007, each port was sampled at four points of varying 

depth, resulting in a twelve-point traverse. For all other tests, each port was sampled at three 

points of varying depth, resulting in a nine-point traverse. (Several tests had to be terminated 

early, precluding the completion of all traverse points). With the exception of the May 4, 2007, 

tests, all of the HCl and HF tests at the air heater outlet included simultaneous particulate matter 

measurements. Test durations ranged from 53-63 minutes. All sampling was performed 

isokinetically. 

9.2.1.1.6 Baghouse Outlet

SO2 tests were conducted at the baghouse outlet sampling location. During the SO2 tests on 

March 29, 2007, sampling was conducted by Clean Air Engineering using a CEM inserted 

through a single port located in the vertically oriented ductwork between the baghouse outlet 

and the booster fan inlet. For the first two tests on that day, the sample was drawn from a 
 88

single point in this port. For the third test, a three-point traverse was performed through the 

same port. Each SO2 test was 60 minutes in duration. 

9.2.1.1.7 Stack 

NOx, SO2, Hg, SO3, HCl, HF, and PM tests were conducted at the stack sampling location. All 

NOx and SO2 measurements at the stack were made using the unit’s CEM. The manual 

sampling (i.e., for Hg, SO3, HCl, HF, and PM) was performed through some or all of the four 

four-inch ports located at the 83-ft level platform. The stack has an inner diameter of 13 ft; the 

four ports are located at 90-degree intervals about its circumference. Figure 40 presents a 

schematic showing the stack sampling location. 

83.0ft.

18.5ft.

13.0ft.

227ft.

SAMPLING

PORT LEVEL

Traverse

Point

Location

(in.)

1

2

3

4

5.0

16.4

30.3

50.4

 4 Sample Access Ports

 4 Traverse Points per Port

16 Total Sample Traverse Points

Figure 40. Schematic of the stack sampling location at AES Greenidge Unit 4, 

including dimensions and traverse points. 

The Hg tests at the stack were performed using either the Ontario Hydro Method or U.S. EPA 

Method 30B. During the Ontario Hydro Method tests (i.e., on March 28 and 30, 2007, October 

2-3, 2007, October 8-11, 2007, November 13-16, 2007, March 11-12, 2008, May 19-20, 2008, 

and June 12-13, 2008), samples were drawn by traversing the duct through all four ports. Each 

port was sampled at four points of varying depth, resulting in a sixteen-point traverse. With the 

exception of the test on October 9, 2007, which was discontinued when coal mill problems 
 89

forced the unit to derate, all of the Hg tests at the stack were 116-128 minutes in duration (most 

were 120 minutes long). All of the Ontario Hydro tests at the stack were conducted 

isokinetically and included simultaneous particulate matter sampling. During the Method 30B 

tests (i.e., on June 12-13 and 16-19, 2008), samples were drawn from a single point through 

one of the four ports. The tests on June 12-13 were each 180 minutes in duration, and the tests 

on June 16-19 were each 360 minutes in duration. All of the Method 30B tests at the stack 

were conducted at a constant sampling rate. 

During the SO3 tests at the stack (i.e., on March 29, 2007, May 2, 2007, October 4-5, 2007, 

October 8-11, 2007, November 13-16, 2007, March 10 and 13, 2008, May 21-22, 2008, June 

10-11, 2008, and June 16-19, 2008), sampling was conducted at one or more points through the 

four-inch ports at the 83-ft level. For the testing on March 29, 2007, samples were drawn from a 

single point through one of the four ports. For the testing on May 2, 2007, samples were drawn 

via a sixteen-point traverse using all four ports. For all subsequent SO3 tests, samples were 

generally drawn from 1-4 points through one of the four ports at the 83-ft level. All SO3

sampling was performed at a constant rate. Each SO3 test at the stack on May 2 was 90 

minutes in duration; all other SO3 tests at the stack were 60 minutes in duration. 

During the HCl and HF tests at the stack (i.e., on March 29, 2007, May 4, 2007, October 4-5, 

2007, October 8-10, 2007, March 10 and 13, 2008, May 21-22, 2008, June 10-11, 2008, and 

June 16-19, 2008), samples were drawn by traversing the duct through three or four of the 

sampling ports located at the 83-ft level platform. (For some tests, only three of the four ports 

were used in order to facilitate simultaneous SO3 sampling). Each port was sampled at four 

points of varying depth, resulting in a twelve- or sixteen-point traverse. With the exception of 

the May 4, 2007, tests, all of the HCl and HF tests at stack included simultaneous particulate 

matter measurements. Test durations ranged from 60-72 minutes (most tests were 64 minutes 

long). All HCl and HF sampling was performed isokinetically. 

9.2.1.2 Sampling and Analytical Methods

9.2.1.2.1 Oxides of Nitrogen 

NOx measurements at the SCR inlet and SCR outlet were performed by Clean Air Engineering 

using U.S. EPA Method 7E, modified to incorporate the use of CAE’s Multipoint Automated 

Sampling System (MASS). A complete description of the methodology is provided in the Clean 

Air Engineering reports that are included as Appendix G to this report. NOx measurements at 

the stack were made using the unit’s stack CEM. 

9.2.1.2.2 Carbon Monoxide 

All CO measurements were performed by Clean Air Engineering using U.S. EPA Method 10, 

modified to incorporate the use of CAE’s Multipoint Automated Sampling System. A complete 

description of the methodology is provided in the Clean Air Engineering reports that are included 

as Appendix G to this report. 
 90

9.2.1.2.3 Ammonia 

CONSOL and Clean Air Engineering both performed ammonia sampling using a modified 

version of U.S. EPA Conditional Test Method (CTM) 027. A complete description of the 

methodology followed by CAE is provided in Appendix G to this report. The methodology 

followed by CONSOL is described below. 

Because of space constraints at the sampling locations, complete isokinetic traverses could not 

be completed as specified in CTM 027 (as discussed above, sampling was conducted using an 

incomplete traverse at an isokinetic sampling rate at the SCR outlet and at a constant sampling 

rate at the air heater inlet and economizer outlet), and a heated Teflon sample line was required 

to connect the sampling probe to the impingers. Given the presence of SO2 and SO3 in the flue 

gas and the temperature of the heated line (~250 oF), some of the collected ammonia was 

expected to condense out of the sample stream as ammonium bisulfate in the Teflon line, 

before reaching the impingers. Hence, the contents of line were collected by rinsing with 

deionized water or 0.1 normal (N) H2SO4, and this line rinse was analyzed to account for the 

ammonia collected there. The sampling procedure is described in more detail below. 

Samples were collected by pulling flue gas through an in-stack filter assembly containing a 

quartz fiber filter and a temperature-controlled quartz-lined probe that was heated to a 

temperature of 250 oF. Upon exiting the probe, the flue gas passed through a heated Teflon 

sample line (maintained at ~250 oF) to the impinger train, where it flowed through a series of 

chilled impingers. The first two impingers were of Greenburg-Smith design, each containing 

100 mL of a 0.1 N H2SO4 solution. The third impinger, also containing 0.1 N H2SO4, was a 

Greenburg-Smith type with the tip removed and was used to evaluate NH3 breakthrough. The 

final impinger, a Greenburg-Smith type without the tip, was filled with approximately 200 g of 

silica desiccant for moisture removal. After exiting the impingers, the gas sample passed 

through a dry test meter where its volume was measured. The O2 concentration in the gas 

exiting the meter was monitored using a Teledyne Max V portable electrochemical O2 analyzer. 

Prior to sampling, the system was leak checked under a vacuum of approximately 10“ Hg. The 

sample probe was placed at the proper location in the sample port; the sample port opening 

was sealed, and gas was sampled for 40-60 minutes. The following data were recorded: (1) 

starting gas volume, (2) interval gas volume, (3) final gas volume, (4) probe temperature, (5) 

heated line temperature, (6) meter differential pressure setting, (7) dry test meter temperature, 

(8) system vacuum, (9) exit gas O2 concentration, (10) barometric pressure, and (11) sampling 

time. Copies of the field data sheets are provided in Appendix H. After sampling, the probe 

was removed from the duct and leak checked under a vacuum equal to or greater than the 

highest vacuum observed during testing, and the train components were disassembled for 

sample recovery. The sample train components were recovered in the following manner: 

 

Sample Probe and In-Stack Filter Assembly - The quartz probe liner was rinsed with deionized 

water or 0.1 N H2SO4, and the rinse was collected in an approved sample container. The filter 

was collected, but not analyzed, and the filter assembly was cleaned with deionized water. (The 

filter assembly rinse was not recovered). The probe rinse was diluted to a known volume and 

refrigerated until analysis. 

Heated line - The heated Teflon line was rinsed with deionized water or 0.1 N H2SO4, and the 

rinse was collected in an approved sample container. The rinse was then diluted to a known 

volume and refrigerated until analysis. 
 91

Impingers - The contents of the first three impingers and connecting glassware (including rinses 

of these sample train components with deionized water) were collected in approved sample 

containers. These samples were then diluted to known volumes and refrigerated until analysis. 

The samples were analyzed for ammonium ion by ion chromatography (IC), which is the method 

specified in CTM 027, or by ion selective electrode (ISE), which is not specified in CTM 027 but 

allows for the rapid, onsite determination of test results. Samples collected on March 28, 2007, 

May 1, 2007, October 8-11, 2007, November 13-16, 2007, March 10 and 13, 2008, May 20-22, 

2008, and June 12-13, 2008, were analyzed by IC. Samples collected on May 31-June 1, 2007, 

were analyzed by both IC and ISE, and samples collected on June 20-21, 2007, were analyzed 

by ISE. The ISE analyses were performed in accordance with Standard Method (SM) 4500-NH3

D, using a Thermo Scientific Orion Model 95-12 ammonia gas-sensing ion specific electrode 

coupled with an Oakton model pH 2100 pH/ion meter. The laboratory analysis results are 

provided in Appendix I. 

For both the ISE and the IC analyses, the concentration of ammonia in the flue gas was 

calculated based on the mass of ammonium ion collected (sum of masses determined in the 

probe, heated line, and impingers) and the volume of flue gas sampled during the test. 

9.2.1.2.4 Sulfur Dioxide

SO2 measurements performed by Clean Air Engineering at the air heater outlet and baghouse 

outlet were conducted using U.S. EPA Method 6C. A complete description of the methodology 

is provided in the CAE report that is included as Appendix G to this report. In addition, SO2

measurements were made at the air heater outlet using the plant’s dilution extractive-type SO2

analyzer that is permanently installed there, and at the stack using the unit’s stack CEM. 

9.2.1.2.5 Mercury

Flue gas Hg measurements were performed using the Ontario Hydro Method (ASTM D6784-02) 

or U.S. EPA Method 30B. These methods are described below. 

9.2.1.2.5.1 Ontario Hydro Method 

With the exception of the U.S. EPA Method 30B tests at the stack on June 12-13 and 16-19, 

2008, all Hg measurements performed as part of the project were conducted using the Ontario 

Hydro Method. (The tests at the stack on June 12-13 included side-by-side sampling via the 

Ontario Hydro Method and U.S. EPA Method 30B). During each Ontario Hydro Method test, 

gas was extracted from the flue gas stream through an in-stack filter assembly, heated glasslined probe, and heated sample line. (The baseline tests on November 17-18, 2004, used a 

heated, out-of-stack filter rather than the in-stack filter and heated sample line). Mercury 

collected in the filter was assumed to be particle-bound Hg (Hgpart). The flue gas exited the 

sample line and passed through a series of chilled impingers. The first three impingers were 

filled with 100 mL of a 1 M potassium chloride (KCl) solution. Mercury captured in these 

impingers and in the probe and sample line, which were rinsed with HNO3 and HCl, was 

reported as oxidized Hg (Hg2+). The next impinger was filled with 100 mL of 5% nitric acid and 
 92

10% H2O2 solution to remove SO2 from the flue gas and preserve the oxidizing strength of the 

subsequent permanganate impingers. The next two impingers were filled with 100 mL of an 

acidic potassium permanganate (KMnO4) solution. Mercury captured in the nitric acid impinger 

and the potassium permanganate impingers was reported as elemental mercury (Hg0

). The 

next impinger was blank to catch any excess moisture. The gas exited the impinger train 

through a silica gel-filled impinger that removed uncondensed moisture from the sample gas 

and then flowed through a vacuum pump and a dry gas meter. Oxygen readings were 

monitored at the outlet of the sampling train using a Teledyne Max V portable electrochemical 

O2 analyzer. Figure 41 presents a schematic of the Ontario Hydro Method sampling train. 

Copies of the field data sheets from the Ontario Hydro tests are provided in Appendix H. 

Figure 41. Schematic of the Ontario Hydro Method sampling train in 

a Method 17 configuration. 

All of the Ontario Hydro Method tests at the stack, SCR inlet, and SCR outlet, and most of the 

tests at the air heater outlet, were conducted at an isokinetic sampling rate as specified in the 

method. In addition to measuring Hg, the isokinetic tests at the air heater outlet and stack 

included the determination of particulate matter according to U.S. EPA Method 17. The Ontario 

Hydro Method was modified, however, for the tests at the air heater outlet on March 11-12 and 

for all of the tests at the economizer outlet and air heater inlet. Because the primary objective of 

these tests was to determine gas-phase Hg speciation (i.e., Hg0

 and Hg2+), sampling was 

conducted at a constant, reduced rate, with the sampling train nozzle oriented away from the 

direction of flue gas flow, to minimize the collection of particulate matter. Hg speciation results 

determined using the Ontario Hydro Method can be biased in high-dust locations by adsorption 

of Hg onto the particulate (fly ash) that is collected on the sample filter or by reaction of Hg with 

that fly ash (Feeley et al., 2003). This can lead to artificially high particle-bound and/or oxidized 

mercury concentrations, and artificially low elemental and/or oxidized mercury concentrations. 
 93

The Hg concentration of the individual impinger solutions and sampling component rinses was 

determined by cold vapor atomic absorption spectroscopy (CVAAS) or cold vapor atomic 

fluorescence spectroscopy (CVAFS) as specified in the Ontario Hydro Method. CVAAS was 

used for the tests on November 17-18, 2004, and March 28 and 30, 2007, and CVAFS was 

used for all subsequent tests in order to provide a lower method detection limit. The 

concentration of Hg on the filter solids was determined according to the procedures described in 

ASTM D6414 or ASTM D6722. The laboratory analysis results are provided in Appendix I. 

9.2.1.2.5.2 U.S. EPA Method 30B 

Hg measurements at the stack on June 12-13 and 16-19, 2008, were performed using U.S. EPA 

Method 30B "Determination of Total Vapor Phase Mercury Emissions from Coal-Fired 

Combustion Sources Using Carbon Sorbent Traps.” (As discussed above, the tests at the stack 

on June 12-13 included side-by-side sampling via the Ontario Hydro Method and U.S. EPA 

Method 30B). The sorbent trap sampling train schematic is shown in Figure 42. 

Figure 42. Schematic of the U.S. EPA Method 30B sampling train. 

During each Method 30B test, flue gas was extracted from the stack through paired, in-stack, 

two-section, iodated carbon sorbent traps at a constant sampling rate. During the tests on June 

12-13, sampling was conducted for a period of 180 minutes at a sampling rate of approximately 

1.85 dry standard liters per minute. During the tests on June 16-19, sampling was conducted 

for a period of 360 minutes at a sampling rate of either 1.85 or 0.95 dry standard liters per 

minute. The sorbent trap temperature was maintained at stack temperature. After exiting the 

sorbent traps, the flue gas passed through a series of chilled impingers (used to dry the flue 

gas) and a dry gas meter. 
 94

Prior to each test, the sampling train was assembled, pre-heated, and checked for leaks. After 

passing the leak-check procedure, the sampling probe was inserted into the stack and sampling 

was initiated. Oxygen readings were monitored at the outlet of the sampling train using a 

Teledyne Max V portable electrochemical O2 analyzer to verify continued leak-free sample train 

operation. At regular intervals during the sampling period, the following data were recorded: (1) 

time, (2) sample flow rate, (3) gas meter reading, (4) stack temperature, (5) gas meter 

temperatures, (6) sampling system vacuum readings, and (7) temperature of the last impinger. 

Copies of the field data sheets are provided in Appendix H. 

The sampling flow rate was adjusted as necessary to maintain it within 20% of the targeted flow 

rate. At the completion of the sampling period, the sample train was checked for leaks and then 

disassembled. 

The mercury concentration in the individual trap beds was determined by cold vapor atomic 

fluorescence spectroscopy as specified in Method 30B. The laboratory analysis results are 

provided in Appendix I. 

9.2.1.2.6 Sulfur Trioxide 

Flue gas SO3 concentrations were determined using a controlled condensation method 

originally developed by the U.S. EPA and modified by CONSOL (DeVito and Smith, 1991; Oda 

and DeVito, 1998). In this method, flue gas is pulled through a temperature-controlled quartzlined probe that is fitted with a quartz wool plug to remove particulate matter. The probe 

temperature is maintained at ~550 oF to minimize SO3 condensation and SO2 oxidation. After 

exiting the probe, the gas sample passes through a 140 oF, temperature-controlled condenser 

that is loosely packed with glass wool. Essentially all of the SO3 is collected in the condenser. 

The sample gas exits the condenser and enters a series of miniature impingers. The first two 

impingers contain a 3% H2O2 solution, which captures the SO2. The gas next passes through 

an empty impinger, and finally through a silica gel-filled impinger for moisture removal. The gas 

is then conveyed through a rotameter, a vacuum pump, and a dry test meter. The O2

concentration in the gas exiting the dry test meter is monitored using a Teledyne Max V portable 

electrochemical O2 analyzer. 

Prior to sampling, the system is leak checked under a vacuum of 10" of Hg. The sample probe 

is then positioned at the proper location and gas is sampled for at least 30 minutes. The 

following data are recorded: (1) starting gas volume, (2) interval gas volume, (3) final gas 

volume, (4) probe temperature, (5) condenser temperature, (6) water bath temperature, (7) flue 

gas duct temperature, (8) dry test meter temperature, (9) flow meter setting, (10) system 

vacuum, (11) exit gas O2 concentration, (12) barometric pressure, and (13) sampling time. 

Copies of the field data sheets are provided in Appendix H. After sampling, the probe is 

removed from the duct, leak checked under a vacuum of 10" of Hg, and purged with ambient air 

for 10 minutes, and the train components are disassembled for sample recovery. 

During the SO3 tests on November 17-18, 2004, and March 29 and 30, 2007, the sample train 

contents were recovered using isopropyl alcohol (IPA) rinses and analyzed by BaCl2 titration. 

The quartz plug was removed from the probe tip, placed in a glass bottle, and extracted with 20 

mL of isopropyl alcohol. The solids were filtered and the filtrate was diluted to a known volume 

prior to analysis. The quartz probe liner was rinsed with IPA into a glass bottle and diluted to a 

known volume. The condenser interior was also rinsed (via three complete rinses) with IPA into 

a glass bottle and the rinses were diluted to a known volume prior to analysis. Each of these 
 95

samples was analyzed for sulfate by a BaCl2 titration to a thorin endpoint as described in EPA 

Method 6. The quartz plug contains SO3 that was absorbed onto the solid particles prior to 

collection in the sampling train. The gas-phase SO3 value is the sum of the probe and 

condenser rinses. In most cases, the majority of the gas-phase SO3 is found in the condenser 

rinse. The SO3 values are reported in ppmvd at duct conditions and at 3% oxygen. 

Ammonia resulting from the SNCR system likely interfered with the BaCl2 titration results for the 

tests on March 29 and 30, 2007, as discussed in EPA Method 8. To avoid possible NH3

interference and improve the sensitivity of the method for determining the low-level SO3

concentrations encountered at the stack, all subsequent SO3 samples were analyzed for sulfate 

by ion chromatography rather than by BaCl2 titration. IPA poses a problem for the IC analysis; 

hence, the filter plug extraction, probe rinse, and condenser rinse were performed using 

deionized water instead of IPA. All other aspects of the method remained unchanged. The 

laboratory analysis results are provided in Appendix I. 

The concentration of SO2 in the flue gas can also be determined from the controlled 

condensation train by analyzing the H2O2 impinger solutions (and rinse of the tubing connecting 

the condenser to the impingers) for sulfate by ion chromatography or BaCl2 titration. This was 

done for most of the SO3 tests at AES Greenidge Unit 4, and results were used in the data 

analyses whenever no other SO2 measurements were available (e.g., at the SCR inlet and SCR 

outlet sampling locations). 

9.2.1.2.7 Hydrogen Chloride, Hydrogen Fluoride, and Particulate Matter 

Flue gas HCl, HF, and particulate matter measurements were conducted using a combined U.S. 

EPA Method 17/26A sampling train or a combined U.S. EPA Method 5/26A sampling train. The 

Method 5/26A train was used for the baseline tests on November 17-18, 2004, and the Method 

17/26A train was used for all other measurements. (As discussed above, particulate matter 

measurements were also conducted during many of the Ontario Hydro Hg tests using a U.S. 

EPA Method 17 configuration. Particulate matter was not determined during the HCl and HF 

tests on May 4, 2007). In the Method 17/26A configuration, gas is extracted isokinetically from 

the flue gas stream through an in-stack filter assembly, heated glass-lined probe, and heated 

sample line. In the Method 5/26A configuration, gas is extracted isokinetically from the flue gas 

stream through a heated glass-lined probe and heated quartz filter. Probe, line, and filter 

temperatures (where applicable) are maintained at ~250 °F. 

The flue gas exits the sample line and passes through a series of chilled impingers. The first 

two impingers are Greenburg-Smith design, each containing 100 mL of a 0.1 N H2SO4 solution 

that collects the hydrogen halide portion of the sample, which is solubilized in the acidic solution 

and forms chloride (Cl-

) and fluoride (F-) ions. Because emissions of Cl2 were not targeted in 

the program at AES Greenidge, the Method 26A impinger train was altered to exclude the 

impingers specified for capturing that compound. The next impinger is initially empty to catch 

any excess moisture. The gas exits the impinger train through a silica gel-filled impinger that 

removes uncondensed moisture from the sample gas, and it then flows through a vacuum pump 

and a dry gas meter. 

The sampling train design results in the following collection sequence: 
 96

Sampling Train Component Species Measured

Filter Particulate Matter 

Probe and Sample Line Rinse HCl & HF 

Impingers HCl & HF 

Sampling was performed isokinetically. Oxygen readings were monitored at the outlet of the 

sampling train using a Teledyne Model Max 5 portable electrochemical O2 analyzer. Copies of 

the field data sheets are provided in Appendix H. The Cl-

 and F- concentrations of the impinger 

solutions were determined by ion chromatography as specified in EPA Method 26A. The 

laboratory analysis results are provided in Appendix I. 

9.2.1.3 Quality Assurance and Quality Control 

The CONSOL field sampling team used standard EPA-type sampling equipment that conformed 

to all applicable test codes. Most of the equipment used in the manual sampling methods was 

obtained from Thermo-Andersen (formerly known as Andersen Instruments, Graseby-Nutech, 

and Nutech). CONSOL used a Mettler electronic balance for pre- and post-test dust weights. 

This balance was checked daily with class "S" calibration weights. 

All sampling trains were leak checked prior to each test and again at the end of each test. All 

sample trains, with the exception of CTM 027 sample trains, were purged with air for ten 

minutes and then disassembled and transported to the lab trailer for recovery. 

A Teledyne Max V portable gas analyzer was used for determining flue gas composition at the 

sample train discharge. The meter operator used the readings to assess the operation of the 

sampling train and the unit operation. Past experience has indicated that the accuracy of the 

oxygen determination by this analyzer is equal to or better than that of a manual Orsat analyzer. 

9.2.1.3.1 Oxides of Nitrogen Measurements

Quality assurance / quality control information for the NOx measurements at the SCR inlet and 

outlet is provided in the Clean Air Engineering reports that are included in Appendix G to this 

report. 

9.2.1.3.2 Carbon Monoxide Measurements 

Quality assurance / quality control information for the CO measurements at the SCR inlet and 

outlet is provided in the Clean Air Engineering reports that are included in Appendix G to this 

report. 

9.2.1.3.3 Ammonia Measurements 

As discussed above, CONSOL and Clean Air Engineering both performed ammonia sampling at 

AES Greenidge Unit 4. Quality assurance / quality control information for the NH3
 97

measurements made by CAE is provided in Appendix G to this report. The quality assurance / 

quality control procedures followed by CONSOL are described below. 

For the ISE analyses, at the beginning of each analytical day, fresh calibration standards with 

concentrations of 0.1, 1.0, 10, and 100 mg/L ammonia as nitrogen (NH3-N) were prepared. 

These were used to develop a standard semilogarithmic curve relating concentrations of NH3-N 

to the ion meter’s millivolt readings. Blank samples of the deionized water and 0.1 N H2SO4

reagents used for sample recovery were run to confirm that they were not contaminated. 

For the ion chromatography analyses, although not required by method, randomly selected 

samples were run in duplicate. The average result for each sample was reported. In all cases, 

the duplicate results had a relative percent difference (RPD) of ≤10%. An independent quality 

control standard with a concentration of approximately the midpoint of the calibration curve 

range was run immediately after calibration and after every 10 samples. In all cases, recovery 

of the quality control standard was between 90% and 110%. Randomly selected samples from 

each batch were spiked at 2 mg/L NH3-N to assess any possible matrix issues; none were 

discovered. Blank samples of the deionized water and 0.1 N H2SO4 reagents used for sample 

recovery were also run to confirm that they were not contaminated. 

In addition to the standard QA/QC procedures specified in CTM 027, blank samples were 

obtained after one of the tests on each of June 1, June 20, October 10, November 13, and 

November 15 by performing a second rinsing of the probe and line that were used for sampling 

at the air heater inlet. This was done to ensure that: (1) the initial rinses succeeded in 

recovering all of the ammonia collected in the probe and line, and (2) there was no residual 

ammonia from the test that could affect the results of a subsequent test. The blank rinses were 

analyzed for ammonium. The ammonium concentrations in the probe rinse blanks were less 

than or equal to the ammonium concentrations in blank deionized water or H2SO4 solutions that 

were used to perform the rinses, and the amount of ammonium recovered in the line rinse 

blanks was ≤12% of the amount recovered in the original line rinses (or below the detection 

limit). Moreover, during the May 31-June 1 testing period, the impingers from a blank CTM 027 

train were recovered in the field and analyzed for ammonium; ammonium concentrations in all 

three field blank impingers were less than the IC limit of detection (0.1 mg/L NH3-N). 

9.2.1.3.4 Sulfur Dioxide Measurements

Quality assurance / quality control information for the SO2 measurements at the air heater outlet 

and baghouse outlet is provided in the Clean Air Engineering Report that is included as 

Appendix G to this report. 

9.2.1.3.5 Mercury Measurements 

9.2.1.3.5.1 Ontario Hydro Method 

Samples were prepared and analyzed as outlined in ASTM D6784-02 (Ontario Hydro Method). 

The samples from November 2004 and March 2007 were analyzed using a Thermo Unicam 969 

CVAAS, which had a detection limit of 0.14 μg/L. All subsequent samples were analyzed using 

a Tekran 2600 CVAFS, which had a detection limit of 0.1 ng/L. R2

 values for all instrument 

calibration curves were >0.999. A sample of National Institute of Standards and Technology 
 98

(NIST) Standard Reference Material (SRM) 1641D was analyzed immediately after calibration. 

If recovery of Hg in the NIST standard was not within 100±10%, then the analyzer was recalibrated before proceeding. An independent calibration verification (ICV) sample was 

analyzed at the beginning of each run and after every 10th sample; if recovery of Hg in the ICV 

was not within 100±10%, then the run was stopped, the analyzer was recalibrated, and the 

affected samples were reanalyzed. All samples were run in duplicate with an acceptance 

criterion of 10% relative percent difference. (Four samples were slightly above 10% RPD). One 

in 10 samples was analyzed in triplicate with an acceptance criterion of 10% relative standard 

deviation (RSD). Matrix spikes were included at a 1-in-10 sample frequency with an acceptance 

criterion of 100±10% spike recovery. Although not required by ASTM D6784-02, digestion 

duplicates and digestion spikes also were included periodically to assess the efficiency of the 

digestions. 

Particulate-impregnated filters and blank filter thimbles were digested according to ASTM 

D6414 and then analyzed in duplicate with an acceptance criterion of 10% relative percent 

difference. Matrix spikes were included at a 1-in-10 sample frequency, with an acceptance 

criterion of 100±10% spike recovery. NIST SRM 1633B was digested and analyzed with the 

batch of filters; recovery of Hg in the SRM was required to be 100±10%. Loose particulate from 

filter thimbles was analyzed according to ASTM D6722. One out of every ten samples was 

analyzed in duplicate with an acceptance criterion of 10% relative percent difference. Again, a 

sample of NIST SRM 1633B was analyzed with the batch of samples; 100±10% recovery of Hg 

in the SRM was required. 

9.2.1.3.5.2 U.S. EPA Method 30B 

Samples were prepared and analyzed as outlined in U.S. EPA Method 30B. (Although specified 

in the method, the field recovery test was not performed as part of the sampling at AES 

Greenidge). The samples were analyzed using a Tekran 2600 CVAFS, which had a detection 

limit of 0.1 ng/L. R2

 values for all instrument calibration curves were >0.99, and all calibration 

standards were recovered to within 10% of their true values. An ICV standard was analyzed at 

the beginning of each run, and a continuing calibration verification (CCV) standard was 

analyzed after every 10th sample. Recoveries for the ICV and CCV were required to be 

100±10%; if this criterion was not satisfied, then the run was stopped, the analyzer was 

recalibrated, and the affected samples were reanalyzed. Blanks, duplicates, matrix spikes, and 

digestion spikes were also included as part of the analytical run (at a frequency of approximately 

one out of every ten samples) in order to assess the performance of the method. The 

acceptance criterion for spike recovery was 100±10%, and the acceptance criterion for 

duplicates was ≤10% relative percent difference. 

As discussed in Section 9.2.1.2.5.2, each Method 30B sampling train contained paired sorbent 

traps. Each trap contained two sections; the second section is used to assess Hg 

breakthrough. Method 30B requires that the paired sorbent trap agreement is ≤10% relative 

deviation (RD) for Hg concentrations >1 μg/dscm and ≤20% RD (or ≤0.2 μg/dscm absolute 

difference) for Hg concentrations ≤1 μg/dscm. All eight test runs performed at AES Greenidge 

Unit 4 satisfied this criterion. The method also requires that the Hg breakthrough in the second 

sorbent trap section is ≤10% of the section 1 Hg mass for Hg concentrations >1 μg/dscm and 

≤20% of the section 1 Hg mass for Hg concentrations ≤1 μg/dscm. Eleven of the sixteen 

sorbent traps analyzed as part of the eight Method 30B tests at AES Greenidge did not satisfy 

this criterion. However, the mass of Hg determined in the first and second sections of these 

traps, which ranged from 1.05-14.1 ng, was on the same order as the mass of Hg determined in 
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blank sorbent trap sections, which ranged from 1.6-4.5 ng. Hence, the failure to satisfy the 

breakthrough criterion likely resulted from extremely low flue gas Hg concentrations (i.e., 0.01 – 

0.05 μg/dscm) rather than from actual breakthrough, and test results are reported as valid 

results in this report even if the breakthrough criterion was not satisfied. 

9.2.1.3.5.3 Mercury Material Balance 

Mercury material balances were performed to confirm the quality of all coal-to-stack mercury 

removal efficiencies determined during the project. These material balances, which were 

performed independently for each test run, compare the total amount of mercury leaving the 

process during the test with the total amount of mercury entering the process during the test. 

The mercury material balance closure is the total mercury output from the process divided by 

the total mercury input, expressed as a percentage. 

During the baseline tests, which were conducted prior to installation of the multi-pollutant control 

system, mercury entered the process in the coal. Potential mercury output streams included the 

bottom ash, ESP ash, and stack flue gas. (The methodologies used to collect and analyze solid 

and liquid process samples are described in Section 9.2.2, and analytical results for these 

samples are presented in Appendix J). 

For all other tests, which were conducted after installation of the multi-pollutant control system, 

potential mercury input streams included the coal, urea, activated carbon (on March 30 and 

October 5, 2007), process water, and hydrated lime. Potential mercury output streams included 

the bottom ash, Turbosorp® hopper ash, Turbosorp® product ash, and stack flue gas. 

For purposes of the Hg material balances, the amount of mercury entering or exiting the 

process via the urea, activated carbon, process water, bottom ash, and Turbosorp® hopper ash 

streams was assumed to be negligible. Based on mercury concentrations determined in the 

urea samples that were collected during the tests in March 2007, October 2007, November 

2007, March 2008, May 2008, and June 2008 (all less than the analytical detection limit of 0.35 

μg/L), the average urea feed rate recorded by the plant during these test (53 gal/h, or 201 L/h), 

and the average total Hg input computed for these tests (0.00745 lb/h, or 3.38 g/h), the urea 

contributed less than 0.01% of the total Hg input to the process. The activated carbon also 

contributed less than 0.01% of the total Hg input, based on the Hg concentration of 0.005 ppm 

determined in activated carbon samples collected during testing in March 2007 and October 

2007 and on the design carbon injection rate of 89 lb/h. Process water samples were collected 

during the test series in October 2007, November 2007, March 2008, and June 2008; the 

mercury concentration determined in every process water sample collected as part of the 

project was less than the analytical detection limit of 0.35 μg/L. Hence, assuming the design 

process water flow rate of 121 gpm (combination of urea dilution water and water injected into 

the Turbosorp® system), the process water contributed less than 0.3% of the total Hg input to 

the process. Bottom ash samples were collected during the baseline testing at AES Greenidge 

in November 2004, and it was determined that the bottom ash contained less than 0.1% of the 

total Hg output from the unit. Bottom ash samples collected during the test series in October 

2007, March 2008, and June 2008 had mercury concentrations that were less than or equal to 

the average concentration observed in the bottom ash during the baseline tests. Hence, 

mercury output in the bottom ash during the guarantee tests, process performance tests, and 

follow-up tests was assumed to be negligible. Finally, the flow rate of ash leaving the 

Turbosorp® hopper (beneath the inlet to the absorber vessel) is not known, but it is insignificant 
 100

relative to the flow rate of Turbosorp® product ash leaving the process. The concentration of Hg 

in the Turbosorp® hopper ash was also only about 35% as great as that in the Turbosorp®

product ash during the March 2007 guarantee tests. Hence, it is reasonable to assume that the 

urea, activated carbon, process water, bottom ash, and Turbosorp® hopper ash were not 

significant sources or sinks of mercury. 

Methods used to measure or estimate the amount of mercury fed to or removed from the 

system via the remaining process streams are summarized below. 

Mercury Input from Coal

Coal feed rates during the tests were recorded and provided by the plant. Coal samples were 

collected at approximately the beginning and middle of each test; the samples from each test 

were composited and analyzed for mercury. The mercury input from coal was computed as the 

product of the coal feed rate and the mercury concentration in the coal. 

Mercury Input from Hydrated Lime (Guarantee, Process Performance, and Follow-Up Tests)

The mass flow rate of hydrated lime being fed to the Turbosorp® absorber vessel was estimated 

for each test by performing a calcium balance around the Turbosorp® system. The mass flow 

rate of Ca entering the Turbosorp® system via the fly ash was estimated from the coal feed rate, 

coal ash content, and coal ash composition; per the assumptions made during baseline testing, 

which were based on historic plant data, it was assumed that 90.5% of the coal ash is converted 

to fly ash. The mass flow rate of Ca exiting the Turbosorp® system via the product ash was 

estimated from the product ash mass flow rate (estimated as described below) and the Ca 

content of the product ash sample(s) collected during the test. The required mass flow rate of 

Ca in the hydrated lime stream was then calculated by subtracting the flow rate of Ca in the fly 

ash stream from the flow rate of Ca in the product ash stream, and the total mass flow rate of 

hydrated lime was computed by dividing this result by the weight percentage of Ca determined 

in the hydrated lime sample collected during the test. To compute the mercury input from 

hydrated lime, the mercury concentration determined in the hydrated lime sample was multiplied 

by the estimated hydrated lime mass flow rate. 

Mercury Output via Bottom Ash and ESP Ash (Baseline Tests)

The mass flow rates of bottom ash and ESP ash leaving the plant were calculated based on 

data collected by the U.S. Department of Energy, Energy Information Administration (EIA). 

During 2001, 2002, and 2003, the EIA data indicate that 9.5% of the total ash produced at AES 

Greenidge was bottom ash, and 90.5% of the total ash produced there was ESP ash. (As 

discussed above, there are two coal-fired units at Greenidge; it was assumed that the split 

between the bottom ash and ESP ash generated from both units was similar). The mass flow 

rates of bottom ash and ESP ash were calculated based on the coal firing rates provided by the 

plant, the ash content of the coal, the moisture, carbon, and ash contents of the bottom ash and 

ESP ash, and the split between the bottom ash and the ESP ash. The ESP hoppers were 

sampled individually; the ash production split was assumed to be 90% in the first hopper row 

and 10% in the second hopper row, based on information from plant operating personnel. The 

ESP ash analyses for moisture, ash, carbon, and mercury represent a weighted average based 

on this split. To compute the mercury output from the bottom ash or ESP ash, the mercury 

concentration determined in the bottom ash or ESP ash sample was multiplied by the estimated 

bottom ash or ESP ash mass flow rate. 

Mercury Output via Product Ash (Guarantee, Process Performance, and Follow-Up Tests)

The mass flow rate of Turbosorp® product ash being discharged from the process was 

estimated for each test by performing a sulfur balance around the Turbosorp® system. The 
 101

mass flow rate of sulfur entering the Turbosorp® system was estimated from the coal feed rate 

and coal sulfur content measured during the test, and the mass flow rate of sulfur exiting the 

system via the stack flue gas was calculated using the average stack flue gas flow rate and SO2

concentration measured during the test. (SO2 concentrations were obtained from the plant’s 

stack CEM, and flue gas flow rates were computed as the average of values measured by the 

stack CEM and by CONSOL. Plant flow rate measurements were converted to a dry basis 

using flue gas moisture concentrations determined by CONSOL during each test). The required 

mass flow rate of sulfur in the product ash stream was then calculated by subtracting the flow 

rate of sulfur in the stack flue gas stream from the flow rate of sulfur entering the Turbosorp®

system, and the total mass flow rate of product ash was computed by dividing this result by the 

weight percentage of sulfur determined in the product ash sample(s) collected during the test. 

To compute the mercury output via product ash, the mercury concentration determined in the 

product ash sample(s) was multiplied by the estimated product ash mass flow rate. 

Mercury Output via Stack Flue Gas

The mercury output via the stack flue gas was measured using the Ontario Hydro Method or 

U.S. EPA Method 30B. For cases in which the concentration of mercury in the flue gas was 

less than the method detection limit (i.e., the tests on March 28 and 30, 2007), the Hg 

concentration was assumed to be equal to the detection limit value. 

Appendix K summarizes the Hg material balance results for each test. CONSOL’s QA/QC 

criterion for material balance closure for a single test is 100±30%. The first test on November 

17, 2004, had a material balance closure of 145%, owing largely to an abnormally high 

measured stack gas mercury content; that test is considered to be invalid. The other two Hg 

tests from the baseline testing series had material balance closures of 87% and 102%, 

satisfying the QA/QC criterion. All 34 tests conducted during the guarantee, process 

performance, and follow-up testing series satisfied the 100±30% criterion. Mercury material 

balance closures for these tests ranged from 73-123%, with a mean closure of 105%. 

Material balances were also completed for SiO2 and Al2O3 for each test to further validate the 

results of the Hg material balances. The methodology was the same as described above for the 

Hg material balances. For the two valid tests from the baseline testing series, material balance 

closures were 101% and 100% for SiO2 and 95% (both tests) for Al2O3. For the 34 tests 

conducted during the guarantee, process performance, and follow-up testing series, the material 

balance closures for SiO2 ranged from 73-125%, with a mean closure of 102%, and the material 

balance closures for Al2O3 ranged from 76-125%, with a mean closure of 102%. Hence, all of 

the SiO2 and Al2O3 material balances also satisfied the 100±30% QA/QC criterion, supporting 

the validity of the methodology that was used to perform the Hg material balances. 

9.2.1.3.6 Sulfur Trioxide Measurements 

For the IC analyses, immediately after calibration of the ion chromatograph, an independent 

calibration verification sample was analyzed in duplicate. Sample analysis proceeded only if 

recovery of the ICV sample was 100±10% and the duplicate results had a RPD of ≤5%. An 

independent, secondary QC standard was analyzed in duplicate after every 10th sample. In all 

cases, recovery of the secondary QC standard was 100±10%, and replicate results agreed 

within 5%. All samples were run in duplicate. If duplicate results were within 5% of each other, 

then the average of the duplicates was reported. If results did not agree within 5%, the samples 

were run again in duplicate and the average of the four replicates was reported. Blank samples 
 102

of the H2O2 impinger solution and the deionized water used for sample recovery were also 

analyzed to verify that background SO4

2- concentrations were low. 

For the BaCl2 titrations, a blank 3% H2O2 solution and a blank IPA sample were titrated with 

each batch using the same BaCl2 titrant used for sample analysis. Blanks required 0.05 mL (the 

smallest increment readable with the microburette) to cause a color change. 

9.2.1.3.7 Hydrogen Chloride and Hydrogen Fluoride Measurements 

HCl and HF samples were analyzed per EPA Method 26A. Immediately after calibration of the 

ion chromatograph, an ICV sample was analyzed in duplicate. The analysis proceeded only if 

recovery was 100±10% for both Cl- and F-, and the duplicate results had relative percent 

differences of ≤5% for both species. An independent, secondary QC sample was analyzed in 

duplicate after every 10 samples. Results were accepted if the recovery of Cl-

 and F- in the 

secondary QC standard was 100±10% and the duplicate results agreed within 5%. All samples 

were run in duplicate. If duplicate results agreed within 5%, then the average of the duplicates 

was reported. If results were not within 5% of one another, the samples were run again in 

duplicate and the average of the 4 replicates was reported, per Method 26A. Although not 

required by method, randomly selected samples were spiked at 2 mg/L Cl-

 and 2 mg/L F- to 

assess any possible matrix issues. Blank samples of the 0.1 N H2SO4 impinger solution were 

also analyzed by ion chromatography to confirm that this solution was not contaminated; blank 

values in excess of the detection limit (0.2 mg/L for both Cl-

 and F-) were subtracted from the 

HCl and HF analysis results, as permitted by EPA Method 26A. 

9.2.2 Solid and Liquid Process Sample Analyses

9.2.2.1 Sampling Methodologies 

Samples of coal, biomass, fly ash, Turbosorp® product ash, pebble lime, hydrated lime, 

activated carbon, and urea were routinely collected during the guarantee tests, process 

performance tests, and follow-up tests. The methods used to collect these samples are 

described in the subsections below. In addition to the routinely collected samples, AES 

Greenidge occasionally provided samples of bottom ash, ESP hopper ash (baseline tests only), 

Turbosorp® hopper ash, and process water for use in the Hg material balances described in 

Section 9.2.1.3.5.3. 

9.2.2.1.1 Coal Samples 

Coal samples were collected from the unit’s four coal mill feeders. Each coal sample collected 

during the project was a composite sample containing an approximately equal portion of coal 

from each feeder that was in operation during the time of sample collection. Each composite 

sample had a total volume of approximately five gallons. Samples were stored and transported 

in plastic buckets with lids that contained o-ring seals to limit contact with outside air. During 

most of the Ontario Hydro Method testing periods, in order to improve the representativeness of 

the coal samples, each mill feeder was sampled twice – once at the beginning of the test and a 

second time after one hour of testing – and these sub-samples were combined to form a five-
 103

gallon composite sample. (During several Ontario Hydro tests, however, separate five-gallon 

composite samples were collected at the beginning and middle of the test). 

9.2.2.1.2 Biomass Samples 

Biomass (waste wood) samples were collected during the test series in November 2007 and 

March 2008 that included biomass co-firing. Samples were taken from the metering bin located 

downstream of the biomass hammer mill, and hence they represented the processed waste 

wood that was being sent to the boiler. Between two and five gallons of waste wood were 

collected for each sample. Samples were stored and transported in plastic buckets with lids that 

contained o-ring seals to limit contact with outside air. 

9.2.2.1.3 Fly Ash Samples 

Fly ash samples were generally collected using the plant’s CEGRIT Automatic Flyash Sampler 

that is permanently installed at a fixed position in the ductwork between the air heater outlet and 

Turbosorp® inlet. The fly ash was collected isokinetically during a several-hour sampling period, 

resulting in a total sample volume of approximately 250-500 mL. Each sample was then 

transferred from the glass sampling jar to a plastic sample bottle (polyethylene / polypropylene) 

for transport and storage. 

In several instances (e.g., the guarantee tests in March 2007), fly ash samples were not 

available from the CEGRIT sampler. In these cases, fly ash samples were obtained from the 

particulate collected as part of Ontario Hydro Method or Method 17/26A sampling at the air 

heater outlet. 

9.2.2.1.4 Turbosorp® Product Ash Samples 

During the guarantee tests in March 2007, samples of product ash from the Turbosorp® process 

were collected from ports located at the interconnection of the air slides and the Turbosorp®

absorber vessel. To facilitate sample collection, all subsequent samples were collected from 

ports installed at the base of the product ash silos. Between two and five gallons of product ash 

were collected for each sample. Samples were stored and transported in plastic buckets with 

lids that contained o-ring seals to limit contact with outside air. 

9.2.2.1.5 Pebble Lime Samples 

Pebble lime samples were collected from the weigh belt that feeds the pebble lime to the 

hydrator. Between one and two gallons of pebble lime were collected for each sample. In most 

cases, samples were first sealed in plastic zip-lock bags, and the bags were then stored and 

transported in plastic buckets with lids that contained o-ring seals, in order to limit contact with 

outside air. (If proper precautions are not taken, lime can react with CO2 and moisture in the air, 

altering its composition). 
 104

9.2.2.1.6 Hydrated Lime Samples

Hydrated lime samples were collected from the chute that transports the hydrated lime from the 

cyclone to the hydrated lime storage silo. Between one and two gallons of hydrated lime were 

collected for each sample. In most cases, samples were first sealed in plastic zip-lock bags, 

and the bags were then stored and transported in plastic buckets with lids that contained o-ring 

seals, in order to limit contact with outside air. (If proper precautions are not taken, lime can 

react with CO2 and moisture in the air, altering its composition). 

9.2.2.1.7 Activated Carbon Samples

Activated carbon samples were collected during the tests that included activated carbon 

injection – i.e., on March 30, 2007, and October 5, 2007. Samples were drawn from the PAC 

feed system. Each sample had a total volume of approximately 250-500 mL. Samples were 

transferred to plastic sample bottles (polyethylene / polypropylene) for transport and storage. 

9.2.2.1.8 Urea Samples

Urea samples were collected from a valve in the SNCR system’s HFD module. Samples were 

drawn directly into 500 mL plastic sample bottles (polyethylene / polypropylene) for transport 

and storage. 

9.2.2.2 Analytical Methods 

9.2.2.2.1 Solid Samples 

Most solid process samples analyses were performed by the CONSOL Energy Inc. Research & 

Development analytical laboratory. Solid samples were analyzed using the following methods, 

as applicable: 

ASTM D2013: Preparing Coal Samples for Analysis. This standard practice covers the 

reduction and division of gross or divided samples up to and including the individual portions 

used for laboratory analysis. 

ASTM D5142: Proximate Analysis of the Analysis Sample of Coal and Coke by Instrumental 

Procedures. Moisture, volatile matter, and ash are determined sequentially in a single 

instrumental procedure by establishing the loss in mass of the analysis specimen when heated 

under rigidly controlled conditions of temperature, time, atmosphere, and specimen mass. 

ASTM D5373: Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory 

Samples of Coal and Coke. Carbon, Hydrogen, and Nitrogen are determined concurrently in a 

single instrumental procedure. The conversion of the subject materials in each sample occurs 

during combustion of the sample at an elevated temperature in an atmosphere of purified 

oxygen. For pebble lime, hydrated lime, and product ash samples, the instrument was 

calibrated using NIST SRM 88B (dolomitic limestone) rather than with 

ethylenediaminetetraacetic acid (EDTA), which is typically used. 
 105

ASTM D4239: Sulfur in the Analysis Sample of Coal and Coke Using High-Temperature 

Combustion and Infrared Absorption. The test specimen is heated in a tube furnace in a stream 

of oxygen to oxidize the sulfur to sulfur dioxide. The gas stream containing the sulfur dioxide is 

passed through a cell where it is measured at a precise wavelength by an infrared absorption 

detector. 

ASTM D5865: Gross Calorific Value of Coal and Coke. A weighed sample of coal is burned 

under controlled conditions in an oxygen bomb calorimeter. The higher heating value is 

calculated from the temperature rise of the water in the calorimeter vessel and the effective heat 

capacity of the system. Corrections are made for the heat released by the ignition of the fuse 

and the thermochemical reactions forming nitric and sulfuric acids. 

ASTM D6721: Determination of Chlorine by Oxidative Hydrolysis Microcoulometry. A weighed 

sample is combusted with tungsten accelerator in a humidified oxygen gas flow, at 900 °C. 

Halogens are oxidized and converted to hydrogenated halides, which are flushed into a titration 

cell where they accumulate. Chlorine is converted to hydrochloric acid. Once the chloride is 

captured in the electrolyte of the titration cell, it can be quantitatively determined by 

microcoulometry. 

ASTM D6349: Determination of Major and Minor Elements in Coal, Coke, and Solid Residues 

from Combustion of Coal and Coke by Inductively Coupled Plasma-Atomic Emission 

Spectrometry. The sample to be analyzed is ashed under standard conditions and ignited to a 

constant weight. The ash is digested in a mixture of hydrofluoric, nitric, and hydrochloric acids. 

The solution is then analyzed by ICP-AES, in which characteristic line emission spectra are 

produced by a radio-frequency inductively coupled plasma. The intensity of these emissions is 

proportional to the concentration of analyte in the sample. For pebble lime, hydrated lime, and 

product ash samples, which contain substantially more calcium than coal samples, the 

instrument was calibrated using NIST SRM 88B (dolomitic limestone) rather than with NIST 

SRM 1633A (coal fly ash), which is typically used. 

ASTM D3302: Standard Test Method for Total Moisture in Coal. All of the moisture in and on a 

sample of coal is determined based on the loss of weight in a coal sample in an air atmosphere 

under rigidly controlled conditions of temperature, time, and air flow. 

ASTM D5987: Total Fluorine in Coal and Coke by Pyrohydrolytic Extraction and Ion 

Chromatography. A weighed sample is subjected to pyrohydrolytic combustion conditions. 

Fluorine is quantitatively released from the sample matrix and retained in the pyrohydrolysate 

that is gravimetrically processed. The total concentration in the sample is then determined by 

ion chromatography. 

ASTM D6722: Total Mercury in Coal and Coal Combustion Residues by Direct Combustion 

Analysis. The analysis sample is heated under oxidative conditions and chemically 

decomposed. Flowing oxygen carries the decomposition products to a gold amalgamator that 

selectively traps mercury. The amalgamator is rapidly heated, releasing mercury vapor that is 

carried through an atomic absorption spectrophotometer. Mercury concentration is measured as 

a function of absorbance peak area. 

ASTM D5967 Digestion with ASTM D6357 Analysis for the Determination of Se. A weighed 

sample is subjected to pyrohydrolytic combustion conditions. Selenium is quantitatively released 

from the sample matrix and subsequently analyzed by inductively coupled plasma-mass 

spectrometry (ICP-MS). 
 106

ASTM C25, Section 19: Loss on Ignition. The sample is ignited at 1000°C to a constant weight. 

The release of free moisture, bound water, carbon dioxide, sulfur dioxide, and volatile pyrolytic 

products of any organic material that may be present results in a sample weight loss, or loss on 

ignition. 

ASTM C25, Section 20: Free Moisture in Hydrated Lime. The sample is heated to 115 °C under 

an atmosphere of CO2-free air until the sample reaches a constant weight. The weight loss of 

the sample is the free moisture, or the water released at 115°C. 

ASTM C25, Section 28: Available Lime Index. An aliquot of sample is slaked and dispersed 

with water. The lime is solubilized by reaction with sugar to form calcium sucrate, which is then 

determined by titration against hydrochloric acid using a phenolphthalein indicator. The 

available calcium is calculated as CaO for pebble lime and as Ca(OH)2 for hydrated lime. 

ASTM C110, Section 19: Apparent Loose Density of Hydrated Lime, Pulverized Quicklime, and 

Limestone. A sample of lime is sifted through a five-inch diameter flour sifter equipped with 

mesh openings of 1mm into a density cup of known volume. The sifting continues until the cup 

has been overfilled and a cone of excess material remains. The excess material is removed by 

sliding the edge of a spatula over the density cup. The loose density is then calculated as the 

ratio of the weight sample remaining to the volume of the density cup. 

ASTM C110, Section 20: Apparent Packed Density of Hydrated Lime, Pulverized Quicklime, 

and Limestone. Twenty-five grams of lime are transferred to a graduated cylinder and the initial 

volume is recorded. The cylinder is gently tapped on a desktop one hundred times and the 

volume is recorded. The tapping continues until the compaction volume change is less than 

0.5mL per one hundred repetitions. The packed density is then calculated as the ratio of the 

initial sample weight to the final sample volume. 

EPA Method 1312: Synthetic Precipitation Leaching Procedure. An extraction fluid is prepared 

by adding a 60/40 weight percent mixture of sulfuric/nitric acids to reagent-grade water until the 

solution has reached a pH of 4.2. The sample and extraction fluid are placed in a zero 

headspace leaching vessel, secured in a rotary extractor device, and rotated at 30 rpm for a 

period of 18 hours. The extraction fluid is then separated from the sample by filtration through a 

glass fiber filter. The filtrate is analyzed for mercury by cold vapor atomic absorption 

spectroscopy or cold vapor atomic fluorescence spectroscopy. 

CONSOL In-House Method: Ammonia in Fly Ash. A five-gram sample is placed in a volumetric 

digestion vessel. The digestion vessel is filled to 50 mL with reagent grade water, closed, and 

gently agitated for a period of one hour. The liquid portion is subsequently analyzed using an 

ammonia ion-selective electrode. Using the sample weight, the ammonia concentration is 

converted from units of ppm in solution to units of ppm in the ash. 

CONSOL In-House Method: Paste pH. A five-gram sample is placed in a 50mL beaker. 

Reagent grade water is slowly added to the sample until a thick paste is formed. A handheld pH 

meter is immersed in the resulting paste and the pH measurement is recorded. 

In addition to the solid sample analyses performed by CONSOL, selected hydrated lime 

samples from the October 2007 and November 2007 test series were analyzed by RJ Lee 

Group, Inc., for BET surface area (nitrogen physisorption, single point), and selected hydrated 
 107

lime, pebble lime, and product ash samples from the March 2007, March 2008, and June 2008 

test series were analyzed by CTL Group using the following methods: 

Pebble Lime

Available CaO ASTM C25, Section 28 

Slaking Rate/Residue ASTM C110-05, Section 11 

Hydrated Lime

Density ASTM C110, Sections 19 and 20 

Particle Size Distribution Laser Diffraction (wet dispersion in isopropanol) 

Surface Area BET (N2, single point) 

Product Ash

Particle Size Distribution Laser Diffraction (wet dispersion in isopropanol) 

Surface Area BET (N2, single point) 

Additional details regarding these analyses can be found in the RJ Lee Group and CTL Group 

reports that are included in Appendix J to this report. 

9.2.2.2.2 Liquid Samples 

Liquid process samples (i.e., urea and process water) were analyzed by CONSOL using the 

following methods, as applicable: 

SM 4500-H B for the Determination of pH. The activity of hydrogen ions is determined by 

potentiometric measurement using a standard hydrogen electrode and a reference electrode. 

SM 2540D for the Determination of Total Suspended Solids. A well mixed sample is filtered 

through a weighed standard glass-fiber filter and the residue retained on the filter is dried to a 

constant weight. The increase in the weight of the filter represents the total suspended solids. 

SM 4500-NH3 E for the Determination of Ammonia. An ammonia selective electrode equipped 

with a hydrophobic gas permeable membrane separates the sample solution from an electrode 

internal solution of ammonium chloride. Ammonia diffuses through the membrane and 

potentiometric measurements are subsequently made by an ion selective electrode. 

SM 3112B for the Determination of Mercury. The mercury in an aqueous sample is reduced to 

vaporous elemental mercury and is determined by cold vapor atomic absorption or by cold 

vapor atomic fluorescence. 

SM 4110B for the Determination of Anions by Ion Chromatography. Phosphate in a portion of 

test solution is determined by ion chromatography with chemical suppression of eluent 

conductivity. 

Density using the Paar Digital Density Meter DMA35. The sample is passed through a vibrating 

tube. The sample density is proportional to the period of vibration in the tube. 
 108

9.3 Results

The plant operating data and special test series data were analyzed by CONSOL to evaluate 

the performance of the multi-pollutant control system during the Operation and Testing Phase. 

The evaluation determined whether the performance targets for pollutant emission rates and 

removal efficiencies (see Section 2.4) were satisfied, and it also included an assessment of 

important performance indicators such as urea utilization, lime utilization, ammonia slip, SO2-toSO3 conversion across the SCR catalyst, and Hg oxidation across the SCR catalyst. Key 

results are presented and discussed in the subsections below. (Complete results for the flue 

gas measurements conducted during the special test series can be found in Appendices G, H, 

and I, and complete results for the solid and liquid process sample analyses conducted during 

these tests can be found in Appendix J). 

Throughout the Operation and Testing Phase, AES Greenidge Unit 4 generally fired eastern 

U.S. bituminous coals containing 2-4% sulfur (although it also co-fired Powder River Basin coal 

at up to 25% by weight of the total fuel for a time during September 2008 and co-fired biomass 

at less than 5% of the total heat input at times during November 2007 and February-April 2008). 

Table 10 presents chemical analysis results for representative coal samples collected during the 

special test series. (Complete results for all of the coal samples collected during the project are 

included in Appendix J). Other relevant operating conditions during the Operation and Testing 

Phase are discussed where appropriate in the subsections below. 

9.3.1 Emissions of Nitrogen Oxides 

The hybrid NOx control system significantly reduced the NOx emissions from AES Greenidge 

Unit 4, but it fell slightly short of the project’s performance target for NOx during long-term 

operation. 

As discussed in Section 9.1.2.2, guarantee testing of the multi-pollutant control system at AES 

Greenidge Unit 4 was completed in March-June 2007. During the guarantee testing campaigns, 

the combustion system and SNCR system were configured to operate as closely as possible to 

design conditions, and the project team demonstrated on several occasions that the hybrid NOx

control system could maintain high-load NOx emissions below the targeted emission rate of 0.10 

lb/mmBtu. Figures 43, 44, and 45 provide examples of this. These figures show the NOx

emission rates measured by the unit’s stack CEM during 12-hour periods on March 28, 2007, 

May 1, 2007, and June 20, 2007, respectively. (The total flow rate of 50% w/w urea solution 

being fed to the SNCR system is also plotted on each graph). The performance guarantee for 

NOx emissions (≤0.10 lb/mmBtu at high load) was officially satisfied on March 28, 2007, when 

the hybrid NOx control system attained an average NOx emission rate of 0.096 lb/mmBtu over 

12 hours while the unit was operating at approximately 105 MWg. Similar performance was 

observed on May 1 and June 20, when the system achieved 12-hour average NOx emission 

rates of 0.097 lb/mmBtu and 0.096 lb/mmBtu, respectively, while the unit operated at about 106 

MWg. Hence, the project’s goal for NOx emissions was achieved reproducibly during short-term 

operation under design conditions. 

AES Greenidge was unable to achieve the targeted emission rate in the long term, however, 

while also maintaining acceptable combustion characteristics, sufficiently high steam 

temperatures, and sufficiently low ammonia slip for routine operation. During the guarantee test 

periods, a substantial amount of overfire air was required in order to achieve a NOx emission 
 109

rate of ≤0.10 lb/mmBtu. As a result, the unit did not have sufficient windbox pressure to avoid 

flame attachments, and several burners were damaged by flame attachments during the testing. 

The low pressure also increased the risk for a windbox fire, although none occurred. Moreover, 

steam temperatures were lower than desired during the guarantee tests. Hence, after the 

ammonia slip guarantee was satisfied on June 20, 2007 (see Section 9.3.3), plant personnel 

reduced the aggressiveness of low-NOx firing in order to achieve more suitable combustion 

characteristics and sufficiently high steam temperatures for routine, long-term operation. The 

change in turn caused boiler conditions to deviate from the design basis for the SNCR system, 

promoting less-than-optimal performance of that system. Tuning of the combustion system and 

SNCR system for long-term operation continued through July 2007. The NOx control problems 

were exacerbated by the accumulation of large particle ash in the in-duct SCR catalyst (see 

Section 10.2.1), which caused periodic deteriorations in the performance of the SCR reactor, 

making it more difficult to achieve the performance target for NOx emissions while maintaining 

sufficiently low ammonia slip. As a result, the unit generally has operated with high-load NOx

emissions of 0.10-0.15 lb/mmBtu since the guarantee testing period. 

Table 10. Chemical composition of typical coal samples collected at AES Greenidge Unit 4 during the 

Operation and Testing Phase. 

Sample Collection Date 3/28/2007 10/4/2007 11/16/2007 3/10/2008 5/20/2008 6/11/2008

Analytical Number 20071797 20076586 20077319 20081017 20082479 20083362

Total Moisture (%) 6.54 5.63 7.89 7.21 5.71 4.46 

As Determined Moisture 

(%) 1.43 1.70 1.41 1.44 1.24 1.45 

Volatile Matter (% dry) 39.92 40.81 34.39 35.73 29.80 38.71 

Ash (% dry, ignited @ 

750 °C) 7.99 8.50 13.46 9.61 12.06 7.45 

Carbon (% dry) 75.86 75.97 71.57 75.77 74.61 77.20 

Hydrogen (% dry) 5.01 5.29 5.36 5.14 4.60 5.40 

Nitrogen (% dry) 1.44 1.40 1.45 1.57 1.78 1.67 

Sulfur (% dry) 2.57 3.27 2.84 2.43 2.03 2.56 

Chlorine (% dry) 0.074 0.069 0.096 0.100 0.088 0.084 

Mercury (ppm dry) 0.097 0.102 0.262 0.117 0.102 0.076 

Fluorine (ppm dry) 70.6 54.1 70.8 72.6 42.2 

Higher Heating Value 

(Btu/lb dry) 13916 13768 13028 13704 13340 14107 

Major Ash Elements (% of ash, dry) 

SiO2 44.62 39.90 48.59 47.82 49.82 41.93 

Al2O3 22.46 20.78 24.78 23.00 27.56 22.50 

TiO2 0.99 0.84 1.05 1.05 2.13 1.01 

Fe2O3 20.52 24.30 18.60 18.04 11.32 21.15 

CaO 4.59 5.63 2.05 3.16 2.81 5.76 

MgO 0.92 0.97 0.97 0.74 0.70 1.14 

Na2O 0.81 0.89 0.40 0.63 0.53 1.14 

K2O 1.57 1.33 2.41 1.54 1.62 1.26 

P2O5 0.48 0.25 0.35 0.43 0.34 0.28 

SO3 3.78 4.62 1.99 3.14 2.46 6.53 
 110

0.000

0.050

0.100

0.150

0.200

3/28/07

7:59

3/28/07

10:23

3/28/07

12:47

3/28/07

15:11

3/28/07

17:35

3/28/07

19:59

NOx Emission Rate (lb/mmBtu)

0.0

10.0

20.0

30.0

40.0

50.0

60.0

Total Urea Flow Rate (gph)

NOx Emission Rate Urea Flow Rate

Average = 0.096 lb/mmBtu

Average = 47.5 gph

Figure 43. NOx emission rate and total urea flow rate observed during guarantee 

testing of the multi-pollutant control system between 8:00 and 20:00 eastern 

standard time (EST) on March 28, 2007. The average unit load during this period 

was 105 MWg. NOx emissions were measured by the unit's stack CEM. The urea 

flow rate was measured by the SNCR system’s flow meters and represents the flow 

of 50% (w/w) urea solution.

0.000

0.050

0.100

0.150

0.200

5/1/07

7:59

5/1/07

10:23

5/1/07

12:47

5/1/07

15:11

5/1/07

17:35

5/1/07

19:59

NOx Emission Rate (lb/mmBtu)

0.0

10.0

20.0

30.0

40.0

50.0

60.0

Total Urea Flow Rate (gph)

NOx Emission Rate Urea Flow Rate

Average = 0.097 lb/mmBtu

Average = 48.2 gph

Figure 44. NOx emission rate and total urea flow rate observed during guarantee 

testing of the multi-pollutant control system between 8:00 and 20:00 EST on May 1, 

2007. The average unit load during this period was 106 MWg. NOx emissions were 

measured by the unit's stack CEM. The urea flow rate was measured by the SNCR 

system’s flow meters and represents the flow of 50% (w/w) urea solution. 
 111

0.000

0.050

0.100

0.150

0.200

6/20/07

7:59

6/20/07

10:23

6/20/07

12:47

6/20/07

15:11

6/20/07

17:35

6/20/07

19:59

NOx Emission Rate (lb/mmBtu)

0.0

10.0

20.0

30.0

40.0

50.0

60.0

Total Urea Flow Rate (gph)

NOx Emission Rate Urea Flow Rate

Average = 0.096 lb/mmBtu

Average = 47.5 gph

Figure 45. NOx emission rate and total urea flow rate observed during guarantee 

testing of the multi-pollutant control system between 8:00 and 20:00 EST on June 

20, 2007. The average unit load during this period was 106 MWg. NOx emissions 

were measured by the unit's stack CEM. The urea flow rate was measured by the 

SNCR system’s flow meters and represents the flow of 50% (w/w) urea solution. 

Figure 46 shows average NOx emissions from AES Greenidge Unit 4 as a function of gross 

generator load during August 2007 – September 2008, following installation of the multipollutant control system, and compares these with average NOx emissions measured during 

August 2004 – September 2005, prior to installation of the system. Table 11 summarizes the 

overall average NOx emission rates measured during each of these periods, as well as the 

average NOx emission rates computed for several load ranges defined in the unit’s current 

permit. These data illustrate the NOx control performance of the multi-pollutant control system 

during routine, long-term operation. As illustrated in Figure 46, installation of the multi-pollutant 

control system reduced the unit’s NOx emission rate by ~25-50% at low generator loads and by 

~50-60% at mid and high generator loads. As discussed in Sections 4.1.1 and 4.2.6, greater 

NOx removal is expected at high generator loads than at low generator loads, because injection 

of urea into low-temperature regions of the furnace and operation of the SCR reactor must be 

discontinued at low load. (Low-temperature urea injection and operation of the SCR system 

both promote improved NOx removal efficiency). The average high-load NOx emission rate 

measured between August 2007 and September 2008 was 0.14 lb/mmBtu. Hence, the hybrid 

NOx control system did not achieve the project’s performance target for NOx emissions during 

long-term operation. Nevertheless, the multi-pollutant control system significantly reduced the 

unit’s NOx emissions. The overall NOx emission rate of 0.15 lb/mmBtu measured during August 

2007 – September 2008 represents a 52% reduction from the overall emission rate of 0.32 

lb/mmBtu measured prior to the project in August 2004 – September 2005. 

As shown in Table 11, the NOx emission limit specified in the permit for AES Greenidge Unit 4 

varies according to the turndown strategy for the hybrid NOx control system. The permitted NOx

emission rate is 0.15 lb/mmBtu for gross generator loads above 68 MW, but it increases to 0.28 

lb/mmBtu when the gross generator load is between 53 and 68 MW and to 0.35 lb/mmBtu when 

the gross generator load is between 43 and 52 MW. Compliance with the permit is determined 

on a 30-day rolling average basis. The limit for a given day is computed as the heat-inputweighted average of the permit limits applicable to each hour of that day (based on the load 

ranges defined above), and the 30-day rolling average permit limit is computed as the heat-
 112

input-weighted average of the limits for the most recent 30 days. Hence, the permit limit varies 

from day-to-day, depending upon the unit’s load profile. The 30-day rolling average NOx

emission rate is computed similarly from hourly NOx emission and heat input data. Figure 47 

shows the 30-day rolling average permit limits and 30-day rolling average NOx emission rates 

for AES Greenidge Unit 4 from January 2008 through September 2008. As illustrated in the 

figure, the combustion modifications and hybrid SNCR/SCR system have enabled AES 

Greenidge Unit 4 to satisfy its permit limit for NOx, despite falling short of the project’s NOx

emission performance target during long-term operation. 

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5

50 60 70 80 90 100 110

Gross MW

Average NOx Emission Rate (lb/mmBtu)

0%

10%

20%

30%

40%

50%

60%

70%

NOx Reduction

8/1/04 - 9/30/05

8/1/07 - 9/30/08

Reduction

Figure 46. Comparison of NOx emissions from AES Greenidge Unit 4 measured during August 2007-

September 2008, following installation of the multi-pollutant control system, with those measured during 

August 2004-September 2005, prior to installation of the system. Data were obtained from the unit’s 

stack CEM. The average NOx emission rate is plotted as a function of gross unit load. The percent NOx

reduction computed from these data for each unit load is also shown. Data are not shown for loads that 

have fewer than 10 observations in either period. 

Table 11. Average NOx emission rates measured during August 2004 – September 2005, prior to the 

installation of the multi-pollutant control system, and during August 2007 – September 2008, following 

installation of the system, for various unit load ranges. Averages are shown for all unit loads (≥42 MWg) 

and for three load ranges corresponding to the unit’s current permit limits. 

Load Range 

NOx Emission Rate 

August 2004 – 

September 2005 

(lb/mmBtu) 

NOx Emission Rate 

August 2007 – 

September 2008 

(lb/mmBtu) 

Reduction in 

NOx Emission 

Rate 

(%) 

Current 

Applicable 

Permit Limita

(lb/mmBtu) 

All 0.322 0.153 52.4 

≥69 MWg 0.311 0.142 54.4 0.15 

53-68 MWg 0.388 0.234 39.6 0.28 

43-52 MWg 0.410 0.255 37.7 0.35 a

Compliance with the permit limits is assessed on a 30-day rolling average basis, as described in the text. 
 113

As discussed earlier, the reduction in NOx emissions arising from the multi-pollutant control 

system includes reductions contributed by the combustion modifications, SNCR system, and 

SCR system. The combustion modifications were designed to reduce NOx emissions to 0.25 

lb/mmBtu at high load; the SNCR system was designed to reduce NOx by ~42% from the 

emission rate leaving the combustion system, and the SCR system was designed to further 

reduce NOx by ~31% from the emission rate leaving the SNCR system. (Hence, the hybrid 

SNCR/SCR system was expected to reduce NOx emissions by 60% relative to the emission rate 

achieved by the new combustion modifications). 

0.000

0.050

0.100

0.150

0.200

0.250

1/1/08 2/1/08 3/1/08 4/1/08 5/1/08 6/1/08 7/1/08 8/1/08 9/1/08 10/1/08

lb/mmBtu

30-Day NOx Rate, lb/mmBtu 30-Day NOx Limit, lb/mmBtu

Figure 47. Thirty-day rolling average permit limits and NOx emission rates for AES Greenidge 

Unit 4 from January 2008 through September 2008. 

 

Several tests were conducted in an effort to isolate the performance of the individual 

components of the hybrid NOx control system. On March 10, March 13, and May 21, 2008, urea 

injection was temporarily shut off while Unit 4 operated at or near full load (106-110 MWg) in 

order to determine the baseline NOx emission rate being achieved by the combustion system 

and the percent reduction in NOx emissions contributed by the hybrid SNCR/SCR system. 

(Biomass was being co-fired with coal during the first half of the test on March 13). Figures 48-

50 show the NOx emission rates and urea flow rates measured during the tests on these three 

days. (When in service, urea injection occurred in Zones 2 and 3 of the SNCR system). Table 

12 summarizes the NOx emission rates observed with and without urea injection for each test 

and the percent NOx removal efficiency determined from these data for the hybrid SNCR/SCR 

system. (NOx emission rates were computed using one-minute average data. The emission 

rate with urea injection is based on data from the one-hour period immediately before the urea 

was shut off, and the emission rate without urea injection is based on data from the period of 

stable NOx emissions that occurred while the urea injection system was not in service. Biomass 

co-firing was discontinued about 30 minutes after the urea was shut off on March 13; only data 

collected while biomass was being co-fired are included in the averages for that day’s test). 

During all three tests, NOx emissions from the combined combustion modifications, SNCR 

system, and SCR system averaged greater than the performance target of 0.10 lb/mmBtu. As 
 114

shown in Table 12, this resulted in part because the combustion system was unable to attain its 

targeted emission rate of 0.25 lb/mmBtu. NOx emissions from the combustion system, without 

the hybrid SNCR/SCR system in service, were 0.26-0.27 lb/mmBtu. (Although it did not meet 

the target, this emission rate nevertheless represents an improvement over the average NOx

emission rate of 0.30 lb/mmBtu observed at loads of 106 and 110 MWg between August 2004 

and September 2005, prior to the installation of the multi-pollutant control system). The hybrid 

SNCR/SCR system also fell short of its target of 60% NOx removal efficiency. That system 

contributed 51% NOx removal on March 10, 52% removal on March 13, and 42% removal on 

May 21. 

0.000

0.050

0.100

0.150

0.200

0.250

0.300

03/10/2008

06:43

03/10/2008

07:40

03/10/2008

08:38

03/10/2008

09:36

03/10/2008

10:33

NOx Emission Rate (lb/mmBtu)

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

Total Urea Flow Rate (gph)

NOx Emission Rate Total Urea Flow Rate

Figure 48. NOx emission rate and total urea flow rate observed between 

7:19 and 10:09 EST on March 10, 2008. NOx emissions were measured 

by the unit's stack CEM. The urea flow rate was measured by the SNCR 

system’s flow meters and represents the flow of 50% (w/w) urea solution. 

0.000

0.050

0.100

0.150

0.200

0.250

0.300

03/13/2008

14:24

03/13/2008

15:36

03/13/2008

16:48

03/13/2008

18:00

03/13/2008

19:12

NOx Emission Rate (lb/mmBtu)

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

Total Urea Flow Rate (gph)

NOx Emission Rate Total Urea Flow Rate

Figure 49. NOx emission rate and total urea flow rate observed between 

14:55 and 18:27 EST on March 13, 2008. The drop in NOx emissions 

around 16:40 occurred when biomass co-firing was discontinued, 

temporarily upsetting the system. NOx emissions were measured by the 

unit's stack CEM. The urea flow rate was measured by the SNCR 

system’s flow meters and represents the flow of 50% (w/w) urea solution.
 115

To evaluate the performance of the combustion modifications and SNCR system at low load, 

urea injection was temporarily shut off on May 22, 2008, while Unit 4 was operating at 56 MWg. 

Figure 51 shows the NOx emission rates and urea flow rates measured during this test. (When 

in service, urea injection occurred in Zone 1 of the SNCR system). The average NOx emission 

rates observed with and without urea injection are shown in Table 12. (These averages were 

computed using the same methodology that is described above for the full-load tests). The 

combustion modifications alone achieved a baseline NOx emission rate of 0.366 lb/mmBtu 

during the test, which is slightly lower than the average emission rate of 0.41 lb/mmBtu 

observed at 56 MWg between August 2004 and September 2005, prior to the project. The 

SNCR system further reduced NOx emissions by 37.5%, surpassing the 20-25% removal 

efficiency that was expected at low load operation. 

0.000

0.050

0.100

0.150

0.200

0.250

0.300

05/21/2008

07:40

05/21/2008

08:38

05/21/2008

09:36

05/21/2008

10:33

05/21/2008

11:31

NOx Emission Rate (lb/mmBtu)

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

Total Urea Flow Rate (gph)

NOx Emission Rate Total Urea Flow Rate

Figure 50. NOx emission rate and total urea flow rate observed between 

8:01 and 10:31 EST on May 21, 2008. NOx emissions were measured by 

the unit's stack CEM. The urea flow rate was measured by the SNCR 

system’s flow meters and represents the flow of 50% (w/w) urea solution. 

0.000

0.050

0.100

0.150

0.200

0.250

0.300

0.350

0.400

05/22/2008

03:50

05/22/2008

04:33

05/22/2008

05:16

05/22/2008

06:00

05/22/2008

06:43

NOx Emission Rate (lb/mmBtu)

0.0

5.0

10.0

15.0

20.0

25.0

30.0

Total Urea Flow Rate (gph)

NOx Emission Rate Total Urea Flow Rate

Figure 51. NOx emission rate and total urea flow rate observed between 

4:07 and 6:22 EST on May 22, 2008. NOx emissions were measured by 

the unit's stack CEM. The urea flow rate was measured by the SNCR 

system’s flow meters and represents the flow of 50% (w/w) urea solution. 
 116

Table 12. Average NOx emission rates observed with and without urea injection during tests on March 

10, March 13, May 21, and May 22, 2008. These data were used to compute the NOx removal efficiency 

achieved by the hybrid SNCR/SCR system. 

Date / Time 

(EST) 

Unit Load 

(MWg) 

Average NOx

Emission Rate 

Without Urea 

Injection 

(lb/mmBtu) 

Average NOx

Emission Rate 

With Urea 

Injection 

(lb/mmBtu) 

NOx Removal 

Efficiency by 

Hybrid 

SNCR/SCR 

(%) 

3/10/08 0719-0858 106 0.259 0.128 50.5 

3/13/08 1455-1636 106 0.267 0.129 51.7 

5/21/08 0801-0917 110 0.265 0.155 41.5 

5/22/08 0407-0519 56 0.366 0.229 37.5 

As discussed in Section 9.1.2, Clean Air Engineering performed NOx measurements at the SCR 

inlet and SCR outlet sampling grids on March 28, 2007, May 30-June 1, 2007, June 20, 2007, 

and May 21-22, 2008, to evaluate the performance of the in-duct SCR reactor. Table 13 

summarizes the average NOx emission rates measured at the SCR inlet and SCR outlet during 

each test, as well as the apparent SCR NOx removal efficiencies computed from these data. (A 

more complete presentation of the SCR grid point sampling results is included in the Clean Air 

Engineering reports in Appendix G). The data in Table 13 suggest that the SCR reactor met or 

exceeded its targeted NOx removal efficiency of ≥31% during all but two of the full-load tests 

conducted in March 2007-May 2008. Those tests had apparent removal efficiencies of about 

27% across the SCR reactor. 

Table 13. Average NOx emission rates measured by Clean Air Engineering at the SCR inlet and SCR 

outlet sampling grids during tests in March 2007, May 2007, June 2007, and May 2008. The NOx removal 

efficiencies computed from these data are also shown, as are relevant unit operating data. 

Test Date / Timea

 

(EDT) 

Unit Load 

(MWg) 

Mean NOx

Emission 

Rate at 

SCR Inletb

(lb/mmBtu) 

Mean NOx

Emission 

Rate at SCR 

Outletb

(lb/mmBtu) 

Apparent 

SCR NOx

Removal 

Efficiency 

(%) 

NOx 

Emission 

Rate from 

Stack CEM 

(lb/mmBtu) 

3/28/07 0912-1023 105 0.126 0.072 43.1% 0.096 

3/28/07 1112-1223 105 0.118 0.072 38.9% 0.095 

3/28/07 1248-1359 106 0.115 0.068 40.8% 0.095 

3/30/07 1112-1135 108 0.126 0.073 41.9% 0.104 

5/31/07 1736-1759 104 0.142 0.069 51.3% 0.086 

5/31/07 1800-1911 105 0.146 0.078 46.4% 0.103 

6/1/07 1024-1111 108 0.130 0.079 39.6% 0.100 

6/1/07 1200-1247 108 0.128 0.093 26.8% 0.103 

6/20/07 2000-2047 104 0.141 0.080 42.9% 0.099 

5/21/08 0312-0559 81 0.153 0.104 31.9% 0.151 

5/21/08 0712-0959 109 0.133 0.097 27.3% 0.144 

5/22/08 0048-0535 56 0.178 0.172 3.4% 0.239 

a

Each complete traverse of the SCR sampling grids took 24 minutes to complete. For tests with 

durations longer than 24 minutes, data represent the average of multiple traverses. b

Clean Air 

Engineering reported the average NOx concentration at each grid point, corrected to 3% O2. To compute 

the mean NOx emission rate, all valid grid point NOx concentrations measured during the time period of 

interest were arithmetically averaged, and the average concentration was converted to a heat input basis 

using an oxygen-based fuel factor (Fd) of 9780 scf/mmBtu. 
 117

The validity of these SCR grid sampling results is called into question, however, by the 

appreciable disparity between the average NOx emission rates computed from the grid point 

measurements at the SCR outlet and the NOx emission rates reported by the unit’s continuous 

emissions monitor. As shown in Table 13, the mean NOx emission rates at the SCR outlet were 

consistently 9-33% lower than the emission rates reported by the CEM. The cause of this 

discrepancy is unknown. Possible causes include measurement error or flow stratification at the 

SCR outlet. Measurement error is unlikely, because both the Clean Air Engineering NOx

analyzer and the unit’s stack CEM were calibrated during the test periods. Regarding possible 

flow stratification, all grid point measurements were weighted equally when computing the 

average NOx concentrations at the SCR outlet. NOx concentrations were inhomogeneous 

across the SCR outlet grid, though (see Appendix G). Hence, if significant flow stratification 

existed, the use of unweighted average NOx concentrations at the SCR outlet could have 

caused the mean NOx emission rates determined there to be biased relative to the emission 

rates measured at the stack. The direction of the bias suggests that areas of low NOx

concentration at the SCR outlet were given too much weight in the averages and that areas of 

high NOx concentration were given too little weight. Space limitations around the SCR reactor 

prevented the performance of a manual traverse to determine the velocity profile at the SCR 

outlet in order to confirm or refute this explanation. Any flow stratification would likely also bias 

the average NOx removal efficiencies computed from the NOx grid point measurements; 

therefore, the data presented in Table 13 must be interpreted cautiously. 

The NOx tests at the SCR inlet and outlet sampling grids enabled an evaluation of the spatial 

distribution of NOx removal efficiencies over the cross section of the reactor. As discussed in 

Section 4.1.1, the SCR reactor includes static mixers to homogenize the velocity, composition, 

and temperature of the flue gas across the catalyst. If such homogeneity is achieved, then NOx

removal should be relatively uniform across the catalyst cross section (assuming uniform 

catalyst activity). However, the SCR grid sampling results suggested significant stratification in 

the NOx removal efficiency across the cross section of the SCR reactor. This was particularly 

evident during the tests on March 28, 2007, as shown in Figure 52. During those tests, very 

high NOx removal efficiencies (>90%) were observed in the northeastern and northwestern 

corners of the reactor, while much lower removal efficiencies (<20%) were observed in the 

center of the reactor, particularly toward the south wall. 

This stratification in NOx removal efficiencies could have resulted from the flow stratification 

contemplated above. Areas of high flow would have relatively low flue gas residence time in the 

reactor, promoting low NOx removal efficiency, whereas areas of low flow would have relatively 

high flue gas residence time, allowing greater NOx removal efficiency (assuming an even 

distribution of NOx and NH3 entering the reactor). Alternatively, it could have resulted from 

unevenness in the NH3-to-NOx ratio at the SCR inlet. Regions with more NH3 would have 

greater NOx removal efficiencies, and regions with less NH3 would have comparatively lower 

NOx removal efficiencies. Either of these scenarios could result in high ammonia slip (i.e., 

because the residence time was too low to allow all of the ammonia to react, or because 

ammonia was fed in excess of the amount that could be consumed by reaction with NOx across 

the reactor), and high ammonia slip was observed during the tests on March 28 (see Section 

9.3.3). Tuning was conducted throughout the rest of the guarantee test period in an effort to 

lessen ammonia slip by reducing deviations in flow and composition across the SCR reactor. 

Figure 53 shows the NOx removal profile measured across the reactor on June 20, 2007, when 

the ammonia slip guarantee was satisfied, and Figure 54 shows the profile measured on May 

21, 2008, after more than a year of routine commercial operation of the hybrid SNCR/SCR 

system. These figures indicate some improvement in the distribution of NOx removal 

efficiencies across the reactor cross section, although stratification is still evident. 
 118

0

20

40

60

80

100

N

SCR – Top View Removal

(%)

Figure 52. Summary of NOx removal efficiencies computed from NOx

concentrations measured at the SCR inlet and outlet sampling grids on 

March 28, 2007 (average of the three tests reported in Table 13). Each 

sampling grid consisted of 24 measurement points. The graph shows the 

NOx removal achieved by the SCR as a function of location on the catalyst 

cross section. For purposes of this graph, any points with negative NOx

removal efficiencies were set equal to 0% removal efficiency. 

0

20

40

60

80

100

SCR – Top View Removal

(%)

N

Figure 53. Summary of NOx removal efficiencies computed from NOx

concentrations measured at the SCR inlet and outlet sampling grids on June 

20, 2007, between 20:00 and 20:47 Eastern Daylight Time (EDT). Each 

sampling grid consisted of 24 measurement points. The graph shows the 

NOx removal achieved by the SCR as a function of location on the catalyst 

cross section. 
 119

0

20

40

60

80

100

SCR – Top View

N

Removal

(%)

Figure 54. Summary of NOx removal efficiencies computed from NOx

concentrations measured at the SCR inlet and outlet sampling grids on May 

21, 2008, between 7:12 and 9:59 EDT. Each sampling grid consisted of 24 

measurement points. The graph shows the NOx removal achieved by the 

SCR as a function of location on the catalyst cross section. For purposes of 

this graph, any points with negative NOx removal efficiencies were set equal 

to 0% removal efficiency. Invalid measurements were replaced with the 

average of surrounding valid measurements.

Figures 55 and 56 show the NOx removal profiles measured in May 2008 when AES Greenidge 

Unit 4 was operating at intermediate load (81 MWg) and at low load (56 MWg), respectively. 

During the intermediate load test on May 21, urea was being injected into Zones 1 and 2 of the 

SNCR system, rather than into Zones 2 and 3, and the flue gas temperature at the SCR inlet 

was about 60oF cooler than it was during the full load test (109 MWg) performed later that day. 

In spite of this, the NOx removal efficiency across the SCR reactor did not decrease at 

intermediate load. (The areas of high and low removal efficiency in the NOx removal profile 

shifted, however). As expected, NOx removal efficiencies were near-zero across the entire SCR 

cross section when the unit operated at low load (56 MWg) and no urea was injected into the 

zones of the SNCR system (i.e., Zones 2 and 3) that are designed to generate ammonia slip for 

the SCR reactor. 

9.3.2 Urea Utilization 

The variable operating costs of the hybrid SNCR/SCR system depend strongly upon the amount 

of urea that is required to achieve a given level of NOx removal. As discussed in Section 4.1.1, 

urea consumption is normally expressed in terms of the normalized stoichiometric ratio 

(Equation 5) and the urea utilization (Equation 4). The normalized stoichiometric ratio compares 

the amount of urea actually being injected with the amount that would be required to 

stoichiometrically react with all of the NOx at the SNCR inlet. The urea utilization is the 

percentage of injected urea that is actually consumed by reaction with NOx. As discussed by 

Albanese et al. (2005), in commercial practice, stand-alone SNCR systems typically operate 

with an NSR of 0.6-2.0 and a urea utilization of 30-60%. 
 120

0

20

40

60

80

100

SCR – Top View

N

Removal

(%)

Figure 55. Summary of NOx removal efficiencies computed from NOx

concentrations measured at the SCR inlet and outlet sampling grids on May 

21, 2008, between 3:12 and 5:59 EDT. Each sampling grid consisted of 24 

measurement points. The graph shows the NOx removal achieved by the 

SCR as a function of location on the catalyst cross section. For purposes of 

this graph, any points with negative NOx removal efficiencies were set equal 

to 0% removal efficiency. Invalid measurements were replaced with the 

average of surrounding valid measurements. 

0

20

40

60

80

100

SCR – Top View

N

Removal

(%)

Figure 56. Summary of NOx removal efficiencies computed from NOx

concentrations measured at the SCR inlet and outlet sampling grids on May 

22, 2008, between 0:48 and 5:35 EDT. Each sampling grid consisted of 24 

measurement points. The graph shows the NOx removal achieved by the 

SCR as a function of location on the catalyst cross section. For purposes of 

this graph, any points with negative NOx removal efficiencies were set equal 

to 0% removal efficiency. Invalid measurements were replaced with the 

average of surrounding valid measurements.
 121

The NSR and urea utilization were estimated using data collected during the 12-hour guarantee 

test periods on March 28, May 1, and June 20, 2007. The NOx emission rates and urea flow 

rates (50% w/w solution) observed during these test periods are shown in Figures 43-45. The 

NSR and urea utilization estimated for each period, as well as key process data used in the 

derivation of these metrics, are presented in Table 14. The average unit load, average heat 

input, and NOx emission rate were computed using one-minute or five-minute average data from 

the unit’s CEM and DCS. The baseline NOx emission rate leaving the new combustion system 

was not measured during the March 28, May 1, or June 20 test periods; hence, the design rate 

of 0.25 lb/mmBtu was assumed in the NSR and urea utilization calculations. The density of 

urea was assumed to be 9.5 lb/gal, consistent with the measured density of urea samples 

collected during the March 2007 tests. 

Table 14. Estimated normalized stoichiometric ratio and urea utilization during the guarantee test periods 

on March 28, May 1, and June 20, 2007. Relevant process data are also summarized. 

Date/Time 

(EST) 

Average 

Unit 

Loada

(MWg) 

Average 

Heat 

Inputa

(mmBtu/h) 

Assumed 

NOx Rate 

at SNCR 

Inlet 

(lb/mmBtu)

Flow 

Rate of 

50% Urea 

Solutionb

(gph) 

NOx

Removal 

by 

SNCR/SCRc

(%) NSR 

Urea 

Utilization 

(%) 

3/28/07 

0800-2000 105 1020 0.25 47.5 61.6 1.36 45.4 

5/1/07 

0800-2000 106 1023 0.25 48.2 61.1 1.37 44.5 

6/20/07 

0800-2000 106 1027 0.25 47.5 61.6 1.35 45.7 

a

Computed using one-minute or five-minute CEM data provided by AES Greenidge. bComputed using 

one-minute or five-minute DCS data provided by AES Greenidge. c

Computed from the assumed NOx rate 

at the SNCR inlet and the average NOx rate measured by the unit’s stack CEM. 

As shown in the table, the SNCR performance was very consistent across the three guarantee 

test periods. The average flow rate of 50% w/w urea solution was about 48 gph during all three 

periods. The estimated normalized stoichiometric ratio ranged from 1.35-1.37, and the 

estimated urea utilization ranged from 44.5-45.7% during these tests. These values are all near 

the middle of the typical ranges cited above for SNCR systems. 

This performance was not sustained during long-term operation of the system, however. Figure 

57 summarizes the urea flow rates observed between August 2007 and September 2008, 

following the completion of guarantee testing. These flow rates, which represent the combined 

flow of 50% w/w urea solution to all three SNCR injection zones, were derived from hourly 

average measurements made by the SNCR system’s online flow meters. The data are plotted 

as a function of gross unit load; the mean urea flow rate at each load is indicated by the solid 

line, and the interval representing ±2 standard deviations from the mean is indicated by the 

dashed lines. Approximately 95% of the hourly urea flow rates fell within this interval. 

As shown in Figure 57, the total urea flow rate increased with increasing unit load. This is the 

expected trend, because the number of moles of NOx leaving the combustion system and the 

desired NOx removal efficiency both increase as load increases. However, the long-term 

average urea flow rates were considerably greater than the flow rates observed during 

guarantee testing. During the period from August 2007 through September 2008, the total urea 

injection rate averaged 60.1-60.8 gph (with a standard deviation of 5.6-5.8 gph) when the unit 

operated at 105-106 MWg. Hence, urea consumption was about 20-25% greater than it was 

during the tests in March-June 2007. As shown in Section 9.3.1, the average NOx removal 
 122

efficiency at 105-106 MWg was also substantially lower in August 2007 – September 2008 than 

it was during the guarantee tests. These data suggest that the changes made to the 

combustion system and SNCR system after guarantee testing caused a significant decrease in 

the urea utilization of the hybrid SNCR/SCR system. 

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

50 60 70 80 90 100 110

Gross MW

Total Urea Flow Rate (gph)

Figure 57. Total flow rate of 50% w/w urea solution (sum of all three SNCR zones) 

as a function of gross unit load between August 2007 and September 2008. Urea 

measurements were made by the SNCR system’s online flow meters. The solid 

line indicates the mean flow rate at each load, and the dashed lines represent ± 2 

standard deviations from the mean. Computations were performed using hourly 

data. 

The tests conducted on March 10, March 13, May 21, and May 22, 2008, were used to quantify 

the NSR and urea utilization achieved by the SNCR system during the period of long-term 

operation following the guarantee tests. As discussed in the preceding section, the baseline 

NOx emission rate from the combustion system was measured during these tests by temporarily 

discontinuing the flow of urea to the SNCR system and observing the resulting emission rate 

measured by the unit’s stack CEM (see Figures 48-51 and Table 12). The NOx emission rate 

with the hybrid SNCR/SCR system in service and the urea injection rate required to achieve this 

NOx emission rate were computed from data collected during the one-hour period immediately 

before the urea was shut off. Again, the average unit load, average heat input, and NOx

emission rates were computed using one-minute average data from the unit’s CEM and DCS, 

and the density of urea (50% w/w solution) was assumed to be 9.5 lb/gal. 

Table 15 shows the NSR and urea utilization estimated for the four tests in March and May 

2008. The urea flow rates observed during these tests were generally similar to the long-term 

average flow rates shown in Figure 57 at the corresponding unit loads. The full-load tests on 

March 10, March 13, and May 21, 2008, had substantially greater normalized stoichiometric 

ratios and lower urea utilization than the tests in March-May 2007, indicating a decline in the 

performance of the hybrid SNCR/SCR system following the guarantee test period. The urea 

utilization determined at full load in March and May 2008 ranged from 24.6 – 36.9%, near or 

below the bottom of the 30-60% range referenced above for typical stand-alone SNCR systems. 

By contrast, the SNCR system performed commendably at low load operation (56 MWg), 

achieving a urea utilization of 50.3% during the test on May 22, 2008. 
 123

Table 15. Estimated normalized stoichiometric ratio and urea utilization during tests conducted on March 

10, March 13, May 21, and May 22, 2008. Relevant process data are also summarized. 

Date/Time 

(EST) 

Average 

Unit 

Loada

(MWg) 

Average 

Heat 

Inputa

(mmBtu/h) 

NOx Rate 

at SNCR 

Inletb

(lb/mmBtu)

Flow 

Rate of 

50% Urea 

Solutionc

(gph) 

NOx

Removal by 

SNCR/SCRd

(%) NSR 

Urea 

Utilization 

(%) 

3/10/08 

0719-0858 106 1061 0.259 60.0 50.5 1.59 31.7 

3/13/08 

1455-1636 106 1058 0.267 54.3 51.7 1.40 36.9 

5/21/08 

0801-0917 110 1077 0.265 66.3 41.5 1.69 24.6 

5/22/08 

0407-0519 56 592 0.366 22.1 37.5 0.75 50.3 

a

Computed using one-minute CEM data provided by AES Greenidge. bComputed from one minute CEM 

data collected after urea injection was discontinued during the second portion of the test. c

Computed 

using one-minute DCS data provided by AES Greenidge. dComputed from the average NOx rates 

measured by the unit’s stack CEM during the periods with and without urea injection. 

9.3.3 Ammonia Slip 

Ammonia slip from the hybrid SNCR/SCR system at AES Greenidge Unit 4 was generally 

greater than the target of 2 ppmvd @ 3% O2 during the first year-and-a-half of operation. 

As discussed in Section 9.1.2.2, several attempts were required before attainment of the 

ammonia slip guarantee could be demonstrated, and even then, the guarantee was just 

narrowly satisfied. During guarantee testing on March 28, 2007, ammonia slip measurements 

were conducted at the SCR outlet sampling location. All three measurements that day indicated 

ammonia concentrations greater than 2 ppmvd @ 3% O2. It was hypothesized that the greaterthan-expected ammonia slip might have arisen because sampling was conducted close to the 

northeastern wall of the SCR reactor, near the region of locally high NOx removal efficiency (and 

potential excess ammonia) that is visible in Figure 52. As a result, on May 1, 2007, ammonia 

slip sampling was conducted at the air heater inlet location, as well as at the SCR outlet 

location, in an effort to improve the representativeness of the measurements. (The differences 

between these sampling locations are detailed in Sections 9.2.1.1.3 and 9.2.1.1.4). Although 

neither location allowed for a complete traverse of the ductwork downstream of the SCR 

reactor, the air heater inlet location enabled points to be sampled near the center of the 

ductwork on both the eastern and western sides of the reactor, likely resulting in samples that 

were more characteristic of the average conditions across the reactor. Results from the 

ammonia slip tests on March 28 and May 1, 2007, are shown in Table 16. The ammonia 

concentrations measured at the air heater inlet on May 1 were consistently lower than the 

corresponding concentrations measured at the SCR outlet, although all were still greater than 

the performance target of 2 ppmvd @ 3% O2. 

All subsequent ammonia slip measurements performed as part of the project were conducted at 

the air heater inlet sampling location. The next round of ammonia slip tests occurred on May 

31-June 1, 2007. During those tests, CONSOL and Clean Air Engineering simultaneously 

sampled for ammonia at the air heater inlet while BPEI and Fuel Tech worked to tune the 

combustion system and SNCR system. As stated in Section 9.2.1.1.4, during the first half of 

each test, one group sampled the eastern air heater inlet duct while the other group sampled 
 124

the western duct. The groups then exchanged positions for the second half of the test, such 

that each collected a composite sample representing the average concentration in both ducts. 

Each group also analyzed the collected samples using both an ion selective electrode in the 

field and ion chromatography in the laboratory. Results are summarized in Table 17. With the 

exception of two ammonia concentrations determined by Clean Air Engineering using ion 

chromatography, all of the ammonia concentrations measured during the tests exceeded 2 

ppmvd @ 3% O2. Whereas the IC and ISE results determined by CONSOL exhibited 

reasonable agreement for all three tests (the relative percent difference between the two 

methods was less than 25% for each test), the IC and ISE results determined by Clean Air 

Engineering exhibited poor agreement (the relative percent difference between the two methods 

was greater than 120% in all cases). Moreover, neither the CAE IC results nor the CAE ISE 

results agreed well with the CONSOL IC and ISE results. Some disparity between the 

CONSOL and Clean Air Engineering measurements may be expected to result from random 

error and from minor methodological differences, including the fact that the groups sampled the 

eastern and western ducts at different points in time and that CONSOL used a slightly longer 

probe than CAE, allowing CONSOL to extract samples from deeper points in the duct (closer to 

the center). However, the large unexplained disparity between the Clean Air Engineering IC 

and ISE results, which bracket the CONSOL IC and ISE results, call the validity of these CAE 

results into question. The Clean Air Engineering report (included in Appendix G) identifies 

exceptions to QA/QC guidelines, including the guidelines for sample hold time and sample 

storage temperature, that might have contributed to the discrepancies among the results. 

Because of these exceptions and the inconsistency between the ISE and IC results, the Clean 

Air Engineering ammonia slip measurements from May 31 and June 1 were considered to be 

invalid. The ammonia slip guarantee was not achieved during the May 31-June 1 test period. 

Table 16. Ammonia concentrations measured by CONSOL at the SCR outlet and air heater inlet 

sampling locations on March 28 and May 1, 2007. Relevant process data are also summarized.

Date/Time (local) 

Unit Load 

(MWg) 

NOx Emissions 

(lb/mmBtu) 

NH3 Concentration (ppmvd @ 3% O2) 

SCR Outlet Air Heater Inlet 

3/28/07 0914-1014 105 0.095 4.6 - 

3/28/07 1115-1215 105 0.095 11.4 - 

3/28/07 1300-1400 105 0.095 13.5 - 

5/1/07 0903-1006 106 0.092 11.6 3.6 

5/1/07 1121-1235 106 0.096 9.7 5.1 

5/1/07 1335-1438 106 0.097 14.3 4.0 

5/1/07 1530-1635 106 0.102 9.8 4.2 

Table 17. Ammonia concentrations measured by CONSOL and Clean Air Engineering at the air heater 

inlet sampling location on May 31 and June 1, 2007. Relevant process data are also summarized.

Date/Time 

(local) 

Unit Load 

(MWg) 

NOx

Emissions 

(lb/mmBtu) 

Sampling 

Group 

NH3 Concentration 

(ppmvd @ 3% O2) RPDa

IC ISE (%) 

5/31/07 

1804-1914 105 0.103 CONSOL >2.5b

 >2.5b 0.0 

CAE 1.4 6.2 126 

6/1/07 

1020-1108 108 0.099 CONSOL 4.9 4.2 15 

CAE 2.0 8.1 122 

6/1/07 

1205-1252 108 0.103 CONSOL 4.7 3.8 21 

CAE 2.4 10.9 128 a

RPD = 100 x | IC – ISE | / ((IC + ISE)/2) bA portion of the sample line rinse was spilled during sample 

recovery. Hence, the actual amount of NH3 present in the flue gas was greater than the amount 

determined from the recovered sample. 
 125

CONSOL conducted additional ammonia slip testing at the air heater inlet on June 20 and 21, 

2007, after BPEI and Fuel Tech completed further tuning of the hybrid NOx control system. As 

discussed in Section 9.2.1.1.4, for each of these tests, the eastern and western air heater inlet 

ducts were sampled independently using separate trains for the full duration of each test, 

thereby generating data regarding the distribution of ammonia between the two ducts. Table 18 

summarizes the results. Measured ammonia concentrations decreased throughout the day on 

June 20 as BPEI tuned the combustion system and SNCR system. The third test performed on 

that day indicated 2 ppmvd NH3 @ 3% O2 (to one significant digit) while the Unit 4 NOx emission 

rate was ≤0.10 lb/mmBtu, consistent with the performance target for ammonia slip. The testing 

on June 21 was performed to support tuning activities focused on establishing a set of 

acceptable boiler operating conditions for routine operation of the NOx control system under its 

permitted high-load NOx emission rate of 0.15 lb/mmBtu. Hence, NOx emissions during the NH3

slip tests on June 21 were greater than 0.10 lb/mmBtu. The average ammonia slip measured at 

the air heater inlet during the two tests on June 21 was 2.3 ppmvd @ 3% O2. 

 

Table 18. Ammonia concentrations measured by CONSOL at the air heater inlet sampling location on 

June 20-21, 2007. Relevant process data are also summarized.

Date / Time (local) 

Unit 

Load 

(MWg) 

NOx

Emissions 

(lb/mmBtu) 

NH3 Concentration (ppmvd @ 3% O2) 

East Duct West Duct Average 

6/20/07 0935-1035 108 0.101 3.4 7.8 5.6 

6/20/07 1755-1836 104 0.100 3.9 2.9 3.4 

6/20/07 2002-2047 104 0.099 1.6 3.1 2.4 

6/21/07 1109-1150 108 0.161 1.3 3.0 2.1 

6/21/07 1517-1557 108 0.138 1.6 3.4 2.5 

All of the ammonia slip tests performed during the guarantee test period occurred while Unit 4 

was firing 100% coal and operating at or near full load, with urea being injected into Zones 2 

and 3 of the SNCR system. In order to track ammonia slip from the hybrid SNCR/SCR system 

during longer-term operation, and to evaluate the effects of changes in operating conditions on 

the amount of ammonia slip, ammonia measurements were performed at the air heater inlet 

during the process performance tests and follow-up tests in October 2007, November 2007, 

March 2008, May 2008, and June 2008. A total of 32 additional ammonia slip tests were 

completed during these periods. Figure 58 shows the ammonia concentrations measured 

during these tests. Table 19 provides additional detail about the tests, including a summary of 

relevant process conditions observed during each measurement period. With the exception of 

tests conducted at low load, when urea was only being injected through Zone 1 of the SNCR 

system, the measured ammonia slip was generally greater than the target of 2 ppmvd @ 3% O2

regardless of unit operating conditions. Of the 26 tests conducted at intermediate and high 

load, when urea was being injected into Zone 2 of the SNCR system (as well as either Zone 1 

or Zone 3), only two had ammonia slip concentrations below 2 ppmvd @ 3% O2. Both of these 

occurred on May 21, 2008. Ammonia concentrations measured during the 26 tests ranged from 

1.6 to 7.3 ppmvd @ 3% O2, with a mean concentration of 4.6 ppmvd @ 3% O2. Hence, the 

hybrid SNCR/SCR system fell short of its performance target for ammonia slip during long-term 

operation. 
 126

Table 19. Ammonia concentrations measured by CONSOL at the air heater inlet sampling location 

during process performance testing and follow-up testing between October 2007 and June 2008. 

Relevant process data are also summarized.

Test Date/Time 

(local) 

NH3

Concentration 

(ppmvd 

@ 3% O2) 

Unit 

Load 

(MWg) 

Biomass 

Co-Firing

Active 

Urea 

Injection 

Zones 

SCR 

Inlet 

Temp 

(oF) 

SCR 

dP 

(iwc) 

NOx

Emissions 

(lb/mmBtu)

10/8/07 0840-0940 3.5 107 No 2/3 672 1.8 0.126 

10/9/07 0807-0909 2.6 109 No 2/3 670 2.0 0.128 

10/10/07 0802-0904 4.0 109 No 2/3 668 1.9 0.127 

10/11/07 0812-0912 4.8 108 No 2/3 669 2.1 0.127 

11/13/07 2323-0027 0.3 56 No 1 572 1.1 0.214 

11/14/07 0117-0221 0.2 56 No 1 581 1.1 0.232 

11/14/07 0356-0500 0.2 56 No 1 583 1.3 0.230 

11/14/07 2311-2355 4.1 84 No 2/3 627 1.6 0.130 

11/15/07 0052-0135 6.5 84 No 2/3 636 1.5 0.146 

11/15/07 0347-0430 4.2 79 No 1/2 632 1.5 0.131 

11/15/07 0502-0545 4.9 80 No 1/2/3 635 1.5 0.141 

11/16/07 1240-1326 6.6 102 Yes 2/3 698 2.0 0.161 

11/16/07 1412-1457 5.6 103 Yes 2/3 702 2.0 0.162 

11/16/07 1642-1726 6.4 102 Yes 2/3 685 2.0 0.141 

3/10/08 1440-1550 5.5 108 Yes 2/3 678 2.3 0.133 

3/13/08 0900-1005 6.4 107 Yes 2/3 660 2.6 0.130 

3/13/08 1150-1255 6.3 108 Yes 2/3 673 2.6 0.143 

3/13/2008 1420-1525 5.4 108 Yes 2/3 673 2.6 0.155 

5/20/08 2313-0011 3.2 90 No 2/3 638 0.7 0.172 

5/21/08 0100-0145 3.6 91 No 2/3 649 1.0 0.200 

5/21/08 0328-0416 2.8 80 No 1/2 617 1.1 0.143 

5/21/08 0453-0545 1.9 81 No 1/2 626 1.2 0.161 

5/21/08 0708-0753 4.4 108 No 2/3 676 1.2 0.126 

5/21/08 0801-0856 1.6 109 No 2/3 682 1.2 0.142 

5/21/08 0912-0957 3.1 110 No 2/3 686 1.2 0.156 

5/22/08 0103-0158 0.2 56 No 1 563 0.9 0.240 

5/22/08 0207-0258 0.2 56 No 1 565 0.8 0.246 

5/22/08 0458-0555 0.1 55 No 1 555 0.7 0.230 

6/12/08 1010-1115 6.1 107 No 2/3 642 1.6 0.137 

6/12/08 1355-1510 7.3 106 No 2/3 642 1.6 0.144 

6/13/08 1030-1135 4.4 109 No 2/3 651 1.8 0.141 

6/13/08 1505-1615 5.5 108 No 2/3 648 1.8 0.131 

The amount of ammonia slip observed at the air heater inlet appeared to depend strongly upon 

the zones through which urea was being injected and upon the pressure drop across the in-duct 

SCR catalyst. The process performance tests in November 2007 and May 2008 included 

parametric tests to determine the relationships among unit load, urea injection scheme, and 

ammonia slip for the hybrid SNCR/SCR system. The results of these tests are summarized in 

Figure 59. 
 127

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

10/8/0710/9/07

10/10/0710/11/0711/13/0711/14/0711/14/0711/14/0711/15/0711/15/0711/15/0711/16/0711/16/0711/16/07

3/10/083/13/083/13/083/13/085/20/085/21/085/21/085/21/085/21/085/21/085/21/085/22/085/22/085/22/086/12/086/12/086/13/086/13/08

Ammonia Slip (ppmvd @ 3% O2)

Zone 1 Zone 2 Zone 3

Figure 58. NH3 concentrations measured at the air heater inlet sampling location 

between October 2007 and June 2008. The shading indicates the highest numbered 

(coolest temperature) zone of urea injection that was in operation during each test. 

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

Low Load

(56 MW)

Mid Load

(80 MW)

Mid Load

(87 MW)

High Load

(106 MW)

NH3 Slip (ppmvd @ 3% O2)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

Relative Urea Flow Rate

Ammonia Urea Zone 1 Urea Zone 2 Urea Zone 3

Figure 59. Ammonia slip as a function of gross unit load and urea 

injection regime at AES Greenidge Unit 4. Data were obtained during 

process performance testing at AES Greenidge in November 2007 and 

May 2008. The columns represent the mean ammonia concentration 

observed at each condition, and the error bars represent ± 1 standard 

deviation. The relative flow rate of urea being injected into each zone of 

the SNCR system is also shown. 

As shown in the figure, the ammonia slip was well within the 2 ppmvd target at low unit load, 

when urea was only being injected into Zone 1 of the SNCR system, but it increased rapidly 
 128

upon introduction of urea into Zone 2 (cooler-temperature zone) at intermediate load. A less 

pronounced rise in ammonia slip was observed as urea was introduced into Zone 3 (coolest 

temperature zone). Ammonia slip concentrations observed at both mid and high loads 

averaged greater than the target of 2 ppmvd @ 3% O2. Figure 59 combines data from the 

November 2007 and May 2008 test series. However, the ammonia concentrations measured in 

November were greater than those measured in May. In May 2008, the average ammonia slip 

at the air heater inlet was 2.3-3.4 ppmvd at intermediate loads and 3.0 ppmvd at high load, 

whereas in November 2007, the average ammonia slip was 4.2-5.3 ppmvd at intermediate loads 

and 6.2 ppmvd at full load. The difference in ammonia concentrations likely resulted from the 

fact that the SCR catalyst was cleaner in May than it was in November. 

While the amount of ammonia slip at the air heater inlet appeared to depend upon which SNCR 

injection zones were in operation, no association was observed between the flow rate of urea 

and the ammonia slip for a given injection scheme. This is evident in Figure 60, which shows 

ammonia slip plotted against the total flow rate of 50% w/w urea solution for tests conducted 

when urea was being injected through Zones 2 and 3 of the SNCR system and the pressure 

drop across the SCR catalyst was ≤2 iwc. 

y = -0.0096x + 5.1784

R2

 = 0.0021

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

30.0 40.0 50.0 60.0 70.0 80.0

Total Urea Flow Rate (gph)

NH3 Slip (ppmvd @ 3% O2)

Figure 60. Scatter plot showing ammonia slip at the air heater 

inlet vs. the total flow rate of 50% w/w urea solution being 

injected into the SNCR system, with simple linear regression 

results. Data were taken from tests during October 2007-June 

2008 that were conducted while urea was being injected into 

Zones 2 and 3 of the SNCR system and the pressure drop 

across the SCR catalyst was ≤2 iwc. 

The data presented in Table 19 suggest some association between the ammonia slip at the air 

heater inlet and the pressure drop across the in-duct SCR catalyst. This association is much 

clearer, however, using the fly ash ammonia concentrations determined by AES Greenidge 

throughout the Operation and Testing Phase. The fly ash samples were collected using the 

CEGRIT sampler in the ductwork downstream of the air heaters (see Section 9.2.2.1.3) on an 

approximately 1-in-3 day frequency; the ammonia content of this fly ash was used as a 

surrogate for ammonia slip. Figure 61 shows the fly ash ammonia concentrations over time, as 
 129

well as the 24-hour average pressure drops observed across the in-duct SCR catalyst. As 

shown in the figure, the ammonia content of the ash tended to increase as the pressure drop 

across the catalyst increased. The increase in pressure drop occurred because of large particle 

ash accumulation in the catalyst (see Section 10.2.1). This promotes ammonia slip by 

decreasing both the effective surface area of the catalyst and the flue gas residence time in 

unplugged catalyst channels, thereby decreasing the conversion of NH3 and NOx across the 

catalyst. Both the pressure drop and the ammonia content of the fly ash decreased abruptly 

after outages were conducted to clean or replace the catalyst, as indicated by the red arrows in 

Figure 61. Figure 62 presents a scatter plot showing the daily ammonia-in-ash and pressure 

drop data. For a given level of catalyst plugging, the pressure drop across the catalyst varies 

with unit load. The urea injection scheme and urea injection rate are also related to unit load, as 

discussed above. To ensure that the association between pressure drop and the ammonia 

content of the fly ash did not arise from collinearity with unit load or urea injection rate, the 

associations between these variables were also explored. Results are shown in Figures 63-64; 

no significant associations were found. Hence, these data suggest that the high ammonia slip 

observed throughout the project arose in part from the large particle ash problem that affected 

the in-duct SCR reactor. This was not the sole cause, though, because ammonia 

concentrations >2 ppmvd @ 3% O2 were observed even when the unit was operating with a 

clean catalyst (e.g., during the process performance tests in May 2008). 

0

100

200

300

400

500

600

700

08/01/07 09/20/07 11/09/07 12/29/07 02/17/08 04/07/08 05/27/08 07/16/08 09/04/08

Ammonia in Fly Ash (mg/kg)

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

Average Catalyst dP (iwc)

Ammonia in Ash Average Catalyst dP

Figure 61. Time series of the ammonia content of fly ash samples collected at the air heater outlet and 

the daily average pressure drop observed across the in-duct SCR catalyst at AES Greenidge Unit 4. The 

red arrows indicate the timing of outages during which the SCR catalyst was cleaned or replaced. 

The higher-than-expected ammonia slip has not significantly affected unit operations. 

Ammonium bisulfate fouling promoted by ammonia slip has likely added to the normal rate of 

increase in pressure drop across the air heaters. Plant personnel reported that they have had 

to soot blow the air heaters more frequently since the multi-pollutant control system was 

installed in order to prevent the pressure drop from increasing too rapidly. AES Greenidge also 

washed the air heater baskets during several outages in 2007 and 2008, although air heater 

fouling was never the cause of an outage. The air heater basket modifications described in 

Section 6.3.7.2 have likely helped to minimize the extent of ammonium bisulfate accumulation in 

the air heaters. The ammonia slip also has not affected byproduct handling. AES Greenidge 

will continue to monitor ammonia slip after the conclusion of the project (via the ammonia 

content of the fly ash) to look for possible effects of decreasing catalyst activity. 
 130

y = 73.16x + 49.747

R2

 = 0.4989

0

100

200

300

400

500

600

700

012345

Average Catalyst dP (iwc)

Ammonia in Fly Ash (mg/kg)

Figure 62. Scatter plot showing the ammonia content of 

fly ash samples collected at the air heater outlet vs. the 

daily average pressure drop measured across the SCR 

catalyst, with simple linear regression results. 

y = -0.374x + 265.04

R2

 = 0.0009

0

100

200

300

400

500

600

700

60 80 100

Average Gross Unit Load (MW)

Ammonia in Fly Ash (mg/kg)

Figure 63. Scatter plot showing the ammonia content of fly 

ash samples collected at the air heater outlet vs. the daily 

average gross unit load, with simple linear regression 

results. 
 131

y = -1.0312x + 277.07

R2

 = 0.0054

0

100

200

300

400

500

600

700

20 40 60 80

Average Urea Flow Rate (gph)

Ammonia in Fly Ash (mg/kg)

Figure 64. Scatter plot showing the ammonia content of 

fly ash samples collected at the air heater outlet vs. the 

daily average flow rate of 50% w/w urea solution to the 

SNCR system, with simple linear regression results. 

9.3.4 SO2-to-SO3 Conversion across the SCR Catalyst 

As discussed in Section 4.3.1, the catalyst in the hybrid SNCR/SCR system fosters the 

oxidation of a small portion of flue gas SO2 to SO3. The catalyst installed at AES Greenidge 

Unit 4 was designed to limit the SO2-to-SO3 conversion rate to less than 1%. This target was 

established in an effort to minimize ammonium bisulfate fouling in the air heaters, because high 

SO3 concentrations, when coupled with ammonia slip, promote ammonium bisulfate formation. 

To determine the SO2-to-SO3 conversion rate, SO2 and SO3 concentrations were measured just 

upstream and just downstream of the SCR reactor (at either the SCR inlet and SCR outlet 

sampling locations or the economizer outlet and air heater inlet sampling locations) during 

performance testing of the multi-pollutant control system on March 30, 2007, October 4-5, 2007, 

March 10 and 13, 2008, and June 10-11, 2008. All of the tests were performed while Unit 4 was 

operating at or near full load, when the conversion rate is expected to be maximal. The tests on 

March 30, 2007, were invalid because of possible ammonia interference with the analytical 

results, and the test on October 4, 2007, was invalid because the sampling train glassware 

broke partway through the test. In addition, the second test on October 5, 2007, and the first 

test on June 11, 2008, were considered to be invalid because SO2 concentrations determined 

as part of the controlled condensation train were dramatically lower than the concentrations 

expected from the coal, indicating a probable sampling problem. Results from the valid tests 

are summarized in Table 20. The average SO2-to-SO3 conversion rate measured during these 

tests was 0.54%, which satisfies the performance target of ≤1.0%. All but one of the nine 

individual tests met this target. No strong associations were observed between the SO2-to-SO3

conversion rate and SCR operating conditions (e.g., SCR operating temperature, pressure drop 

across the catalyst). 
 132

Table 20. Summary of SO2-to-SO3 conversion rates determined from testing around the SCR reactor in 

October 2007, March 2008, and June 2008. Relevant process data are also summarized.

Test 

Date/Time 

(local) 

Unit 

Load 

(MWg) 

Average SO2

Concentrationa

(ppmvd @ 3% O2) 

SO3 Concentration 

(ppmvd @ 3% O2) SO2-to-SO3

Conversionc

(%) 

SCR 

dP 

(iwc) 

SCR 

Inlet 

Temp 

(oF) 

SCR 

Inletb

SCR 

Outletb

10/5/07 

0840-0950 108 2079 11.0 21.8 0.52% 1.6 662 

10/5/07 

1405-1505 108 2162 10.2 14.5 0.20% 1.7 679 

3/10/08 

1440-1604 108 1572 8.5 20.8 0.78% 2.3 677 

3/13/08 

0900-1026 107 1543 11.2 19.5 0.54% 2.6 663 

3/13/08 

1149-1308 108 1531 12.2 18.6 0.42% 2.6 672 

3/13/08 

1420-1539 108 1641 8.6 14.7 0.37% 2.6 674 

6/10/08 

1325-1541 105 2107 9.4 34.4 1.19% 1.5 640 

6/11/08 

1149-1320 107 1733 12.9 20.7 0.45% 1.6 639 

6/11/08 

1502-1705 105 2048 15.8 23.0 0.35% 1.6 637 

a

Computed from the SO2 concentrations determined as part of the controlled condensation 

measurements upstream and downstream of the SCR reactor. b

Sampling on October 5, 2007, was 

conducted at the SCR inlet and SCR outlet locations; sampling on all subsequent dates was conducted at 

the economizer outlet and air heater inlet locations. cComputed from the SO3 concentrations measured at 

the SCR inlet (or economizer outlet) and SCR outlet (or air heater inlet) and the average SO2

concentration measured at these locations. 

For eight of the nine tests shown in Table 20, SO3 concentration measurements were also made 

just downstream of the air heater. On average during these tests, the SO3 concentration 

decreased from 21.7 ppmvd @ 3% O2 to 10.7 ppmvd @ 3% O2 across the air heater. The 

significant decrease in the measured SO3 concentration between the SCR outlet and air heater 

outlet may reflect the formation of ammonium bisulfate in the air heaters, especially since the 

ammonia slip from the SCR reactor has generally been greater than the target of 2 ppmvd @ 

3% O2. It may also result simply from the condensation of SO3 as sulfuric acid on the air heater 

baskets, which can lead to corrosion, and its subsequent loss to the incoming combustion air. 

In any event, the appreciable loss of SO3 across the air heater illustrates the importance of 

maintaining a low SO2-to-SO3 conversion rate in the SCR reactor. 

9.3.5 Mercury Oxidation across the SCR Catalyst 

Per the discussion in Section 4.1.3, in addition to reducing NOx emissions, the in-duct SCR 

reactor is expected to contribute to the Hg removal performance of the multi-pollutant control 

system by converting some of the elemental mercury in the flue gas to oxidized mercury, which 

is more easily captured downstream in the circulating fluidized bed dry scrubber and baghouse. 

Hg oxidation is often observed across conventional SCR reactors, but the extent to which Hg 

would be oxidized across the comparatively small in-duct SCR at AES Greenidge Unit 4 was 

uncertain when the process was being designed. 
 133

To investigate Hg oxidation across the in-duct SCR catalyst, concentrations of Hg0

 and Hg2+

were measured just upstream and just downstream of the SCR reactor (at either the SCR inlet 

and SCR outlet sampling locations or the economizer outlet and air heater inlet sampling 

locations) during performance testing on October 2-3, 2007, March 11-12, 2008, May 19-20, 

2008, and June 12-13, 2008. The tests in May 2008 were performed while Unit 4 was 

operating at low load (56 MWg), and all of the other tests were performed while Unit 4 was 

operating at or near full load (106-109 MWg). The first test on October 3, 2007, was invalid 

because of a back-flush in the sampling train at the SCR outlet, which prevented the 

determination of Hg speciation at that location. 

As discussed in Section 9.2.1.2.5.1, all of the mercury speciation measurements around the 

SCR reactor were conducted using the Ontario Hydro Method. Several methodological issues 

must be understood when interpreting these measurements. First, Hg speciation results 

determined using the Ontario Hydro Method can be biased in high-dust locations by adsorption 

of Hg onto the fly ash that is collected on the sample filter. The fly ash can also promote Hg 

oxidation. These artifacts are expected to be minimal, however, at the high temperatures 

around the SCR. To further reduce the likelihood of bias, during the tests in March, May, and 

June 2008, sampling was performed at a constant, reduced flow rate, with the nozzle oriented 

away from the direction of flow to reduce the uptake of particulate matter. Mercury 

concentrations in the fly ash collected during sampling at the economizer outlet, SCR inlet, SCR 

outlet, and air heater inlet were very low, ranging from 0.003 to 0.034 μg/g. (By contrast, Hg 

concentrations in the fly ash collected in October 2007 and March 2008 during sampling at the 

air heater outlet, where temperatures are considerably cooler, ranged from 0.53 to 1.28 μg/g). 

Hence, the fly ash did not appear to interfere with the Hg measurements around the SCR 

reactor. Second, the Ontario Hydro Method has not been validated for high-temperature 

testing; however, flue gas conditions were similar at the SCR inlet and outlet, reducing the 

probability of relative measurement bias between those locations. Finally, physical constraints 

prevented the performance of complete traverses of the ductwork upstream and downstream of 

the SCR reactor, introducing some possibility of error if Hg speciation was stratified over the 

cross section of the reactor. 

Results from the valid tests are summarized in Table 21. For ten of the twelve tests, the 

proportion of mercury present as Hg2+ was greater at the SCR outlet than at the SCR inlet. This 

was true even for one of the two tests conducted at low load, when the SCR inlet temperature 

(564 oF) was less than the minimum operating temperature for the SCR catalyst (600 oF). The 

other low-load test showed no change in mercury oxidation across the catalyst, and the full-load 

test on October 2 showed a decrease in mercury oxidation across the catalyst. A significant 

disparity between the total Hg concentrations at the SCR inlet and SCR outlet was observed for 

several of the tests, indicating possible measurement error (such as that which could result from 

stratification of Hg concentration across the reactor). 

Table 22 summarizes average mercury oxidation results for three cases: one in which all of the 

tests from Table 21 are included, one in which only the results of the full-load tests (>100 MWg) 

are included, and one in which only the results of the full-load tests with less than 20% RPD 

between the total gas-phase Hg concentration at the SCR inlet and SCR outlet are included. As 

shown in the table, the proportion of Hg present in oxidized form increased, on average, from 

64-69% at the SCR inlet to 87-90% at the SCR outlet. Paired t-tests performed on each of the 

three subsets of measurements all indicated a statistically significant increase in the percentage 

of oxidized mercury across the SCR reactor. These results strongly suggest that the single-
 134

layer, in-duct SCR reactor was effective in oxidizing mercury, although this conclusion must be 

interpreted in the context of the methodological limitations discussed above. 

Table 21. Summary of gas-phase mercury speciation determined from testing around the SCR reactor in 

October 2007, March 2008, May 2008, and June 2008. Relevant process data are also summarized.

Test Date / 

Time 

(local) 

Unit 

Load 

(MWg) 

Hg (μg/dscm @ 3% O2) Hg2+/HgTOT

SCR 

Inlet 

(%) 

Hg2+/HgTOT

SCR 

Outlet 

(%) 

SCR 

dP 

(iwc) 

SCR 

Inlet 

Temp 

(oF) 

Hg2+ 

SCR 

Inleta 

HgTOT

SCR 

Inleta 

Hg2+

SCR 

Outleta

HgTOT

SCR 

Outleta

10/2/07 

1505-1715 109 2.74 4.98 2.31 6.54 55.0% 35.3% 1.5 673 

10/3/07 

1555-1756 107 3.43 4.85 3.32 4.30 70.7% 77.2% 1.5 661 

3/11/08 

0928-1157 107 5.69 6.89 7.49 7.83 82.6% 95.7% 2.4 666 

3/11/08 

1325-1628 107 4.07 6.42 8.69 8.93 63.4% 97.3% 2.4 667 

3/12/08 

0945-1147 109 5.05 6.95 7.58 7.96 72.7% 95.2% 2.5 673 

3/12/08 

1350-1616 107 4.54 7.44 5.89 6.27 61.0% 93.9% 2.5 674 

5/19/08 

2331-0143 56 10.09 12.20 13.13 13.65 82.7% 96.2% 0.9 564 

5/20/08 

0305-0517 56 9.21 11.24 10.21 12.41 81.9% 82.3% 0.8 572 

6/12/08 

0940-1145 106 2.39 3.46 5.71 6.11 69.1% 93.5% 1.6 641 

6/12/08 

1330-1538 106 2.42 3.62 5.55 5.88 66.9% 94.4% 1.6 642 

6/13/08 

1000-1211 109 4.10 5.28 6.09 6.39 77.7% 95.3% 1.8 651 

6/13/08 

1441-1657 108 2.49 7.92 6.03 7.17 31.4% 84.1% 1.8 648 

a

Sampling on October 2-3, 2007, was conducted at the SCR inlet and SCR outlet locations; sampling on 

all subsequent dates was conducted at the economizer outlet and air heater inlet locations. HgTOT is the 

total gas-phase mercury concentration, defined as the sum of Hg0

 and Hg2+. 

9.3.6 Sulfur Dioxide Removal Efficiency 

The Turbosorp® system at AES Greenidge Unit 4 consistently met or exceeded its performance 

target for SO2 removal efficiency during the Operation and Testing Phase of the project. 

Guarantee testing for SO2 removal efficiency was completed on March 29, 2007. Three 

approximately 60-minute-long tests were performed while AES Greenidge Unit 4 fired eastern 

U.S. bituminous coal containing about 2.7% sulfur (dry basis), or about 3.8 lb SO2/mmBtu, and 

operated near full load. SO2 concentrations at the air heater outlet were determined by Clean 

Air Engineering using U.S. EPA Method 6C, and SO2 emissions at the stack were determined 

by the unit’s CEM. Results are summarized in Table 23. The average SO2 removal efficiency 

observed during the three tests was 96.0%, achieving the performance target of ≥95%. (Clean 

Air Engineering also measured SO2 concentrations at the baghouse outlet sampling location 

during the tests on March 29. Results of those measurements are provided in Appendix G. The 
 135

average emission rate measured at the baghouse outlet was slightly higher than that measured 

by the stack CEM, resulting in an average SO2 removal efficiency of 94.1% calculated from the 

air heater outlet to the baghouse outlet. The cause of the discrepancy is unknown. However, 

because the unit’s permit limit for SO2 and the controls for the Turbosorp® system are both 

based on the SO2 emission rate measured by the stack CEM, this emission rate was used to 

determine attainment of the performance target for SO2 emissions). 

Table 22. Average gas-phase mercury speciation around the SCR reactor, computed for three subsets 

of the measurements presented in Table 21. Paired t-tests were performed on each subset of 

measurements to assess the statistical significance of the change in mercury oxidation across the 

reactor. 

Casea

Average Hg (μg/dscm @ 3% O2) Hg2+/HgTOT

SCR 

Inlet 

(%) 

Hg2+/HgTOT

SCR 

Outlet 

(%) 

Paired t-test 

Hg2+ 

SCR 

Inletb

HgTOT

SCR 

Inletb

Hg2+ 

SCR 

Outletb

HgTOT

SCR 

Outletb

Mean 

Differencec p-valued

All 

measurements 

(N = 12) 

4.69 6.77 6.83 7.79 69.2 87.8 18.8 0.005 

Full-load 

measurements 

(N = 10) 

3.69 5.78 5.87 6.74 63.9 87.1 21.1 0.007 

Full-load 

measurements 

with <20% 

RPD between 

Inlet and 

Outlet HgTOT 

(N = 6) 

4.22 6.56 6.07 6.65 64.3 91.2 24.2 0.016 

a

N is the number of observations. bThe SCR inlet includes measurements made at the economizer outlet 

and SCR inlet sampling locations, and the SCR outlet includes measurements made at the SCR outlet 

and air heater inlet sampling locations. HgTOT is the total gas-phase mercury concentration, defined as 

the sum of Hg0

 and Hg2+. cMean of the differences between Hg2+/HgTOT (%) at the SCR outlet and 

Hg2+/HgTOT (%) at the SCR inlet for the individual tests. dA p-value less than 0.05 indicates that the mean 

difference was significantly different from zero at the 95% confidence level. 

Table 23. Summary of the SO2 removal efficiency across the Turbosorp® system determined during 

guarantee testing on March 29, 2007. 

Test 

Date/Time 

(local)

Unit 

Load 

(MWg) 

Air Heater Outleta Stack 

SO2

Rateb

(lb/mmBtu) 

SO2

Removal 

Efficiency

(%) 

SO2

Concentration 

(ppmvd)

CO2

Concentration 

(%, dry)

SO2

Rate 

(lb/mmBtu)

3/29/07 

0959-1100 105 1410 11.54 3.65 0.137 96.2 

3/29/07 

1216-1317 105 1398 11.61 3.60 0.128 96.4 

3/29/07 

1513-1613 106 1381 11.52 3.58 0.173 95.2 

AVERAGE 105 1396 11.56 3.61 0.146 96.0 

a

Measurements made by Clean Air Engineering. bMeasured by the unit’s stack CEM. 
 136

The Turbosorp® system continued to exhibit a high level of performance during longer-term 

operation. To illustrate the long-term SO2 removal efficiency of the system, Figure 65 shows the 

hourly SO2 rates measured at the air heater outlet (Turbosorp® inlet) by the unit’s online dilution 

extractive-type SO2 analyzer and the hourly SO2 rates measured at the stack (Turbosorp®

outlet) by the unit’s CEM during August 2007 through September 2008. (SO2 concentrations at 

the air heater outlet are measured on a wet basis. However, moisture and CO2 are not 

continuously measured at the air heater outlet. Hence, for purposes of expressing the SO2

concentrations on a heat input basis, the moisture at the air heater outlet was assumed to equal 

8.4%, and the CO2 concentration at the air heater outlet was assumed to equal 1.062 times the 

stack CO2 concentration. These assumptions are based on the average moisture and CO2

concentrations measured by CONSOL during mercury, HCl, and HF testing between March 

2007 and June 2008). During this 14-month period, AES Greenidge Unit 4 primarily fired 

eastern U.S. bituminous coals, although it fired a blend of eastern bituminous coal and Powder 

River Basin (PRB) coal (at up to 25% by weight of the total fuel) for a time during September 

2008 and co-fired biomass (at less than 5% of the total heat input) at times during November 

2007 and February-April 2008. Table 24 summarizes the average long-term performance of the 

Turbosorp® system. Between August 1, 2007, and September 30, 2008, the system reduced 

SO2 emissions from 3.62 lb/mmBtu to 0.13 lb/mmBtu, resulting in an average removal efficiency 

of 96.3%. This surpassed the project’s performance target of 95% SO2 removal efficiency. 

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00

8/1/07 9/20/07 11/9/07 12/29/07 2/17/08 4/7/08 5/27/08 7/16/08 9/4/08

SO2 Rate (lb/mmBtu)

Air Heater Outlet Stack

Figure 65. Hourly SO2 rates (lb/mmBtu) determined at the air heater outlet (upstream of the Turbosorp®

system) and stack (downstream of the Turbosorp®

 system) during August 2007 – September 2008. SO2

was measured by the dilution extractive-type SO2 analyzer that is permanently installed at the air heater 

outlet and by the unit’s stack CEM. 
 137

Table 24. Summary of the long-term SO2 removal performance of the Turbosorp® system, based on 

hourly data collected from August 2007 through September 2008. 

Meana Rangeb

SO2 at Air Heater Outlet (lb/mmBtu) 3.62 2.56 – 4.88 

SO2 at Stack (lb/mmBtu) 0.134 0.000 – 4.407 

SO2 Removal Efficiency (%) 96.3 -3.7 – 100.0 a

Computed as the heat input-weighted mean of hourly average SO2 rates. bRepresents the minimum and 

maximum hourly average values observed during the period. 

SO2 concentrations determined as part of SO3 testing at the air heater outlet and stack provide 

an independent measure of the SO2 removal performance of the Turbosorp® system. As 

discussed in Section 9.2.1.2.6, the concentration of SO2 in the flue gas can be determined by 

analyzing the H2O2 impingers from the controlled condensation sampling train that is used for 

SO3 measurements. SO2 concentrations were determined in this way as part of 39 SO3 tests 

conducted between October 2007 and June 2008. Results are summarized in Table 25. The 

average SO2 removal efficiency computed from these test results was 95.1%, again satisfying 

the performance target. (During several of the controlled condensation tests, the Turbosorp®

system was intentionally being operated to achieve SO2 removal efficiencies above or below 

95%). 

As discussed in Sections 2.2, 2.4, and 4.2.4, an important objective of the Greenidge MultiPollutant Control Project was to prove that the Turbosorp® system could achieve high SO2

removal efficiencies while AES Greenidge Unit 4 fired high-sulfur (i.e., >2%-sulfur) coal. This 

objective was demonstrated during guarantee testing, when 96% SO2 removal was achieved 

with a 2.7% sulfur coal, as well as during long-term testing, when 96% removal was achieved 

over a 14-month period with a similar average sulfur loading. (The average SO2 rate at the 

Turbosorp® inlet was 3.61 lb/mmBtu during the guarantee tests and 3.62 lb/mmBtu during the 

August 2007-September 2008 period). Hourly average SO2 rates at the Turbosorp® inlet ranged 

from 2.56 to 4.88 lb/mmBtu between August 2007 and September 2008; high SO2 removal 

efficiencies were observed even when the inlet SO2 was at the top end of this range. Figure 66 

shows five-minute average SO2 rates measured upstream and downstream of the Turbosorp®

system on October 3, 2007, when the greatest inlet SO2 loadings were observed. This day 

occurred within the October 2-5, 2007, process performance testing campaign, which was 

designed to evaluate the performance of the multi-pollutant control system while AES 

Greenidge Unit 4 fired higher-than-normal sulfur coal (see Section 9.1.2.3.1). The coal sulfur 

content on October 3 averaged 3.3% (4.8 lb SO2/mmBtu), and the Turbosorp® system 

succeeded in reducing SO2 emissions by 96.5% over an 11-hour period of full-load (108 MWg) 

operation with this fuel. Similarly high removal efficiencies were observed during the other days 

of the testing campaign. Hence, the project succeeded in confirming the applicability of the 

Turbosorp® system to units that fire high-sulfur coal. 

AES Greenidge routinely operates the Turbosorp® system with an SO2 emission rate set point of 

0.10 lb/mmBtu, which is below its permitted emission rate of 0.19 lb/mmBtu, in order to provide 

a margin for transient upsets in system performance. These upsets, which are evidenced by 

the occasional spikes in stack SO2 emission rate in Figure 65, can be caused either by routine 

operating and maintenance activities or by unexpected equipment problems. 
 138

Table 25. SO2 concentrations, and implied removal efficiency across the Turbosorp® system, determined 

as part of SO3 tests conducted at the air heater outlet and stack using the controlled condensation 

method between October 2007 and June 2008. 

Test Date / Time (local) 

SO2 at Air Heater 

Outlet 

(ppmvd @ 3% O2) 

SO2 at Stack 

(ppmvd @ 3% O2) 

SO2 Removal 

Efficiency 

(%) 

10/4/2007 1520-1641 1819 85 95.3 

10/5/2007 0840-0950 1899 44 97.7 

10/8/2007 1530-1634 1349 21 98.4 

10/9/2007 1040-1150 1363 157 88.5 

10/10/2007 1040-1144 1809 162 91.1 

10/11/2007 1230-1335 1793 145 91.9 

11/13/2007 2325-0047 1885 69 96.3 

11/14/2007 0135-0240 2122 48 97.8 

11/14/2007 0405-0510 1989 106 94.7 

11/14/2007 2305-0010 2075 59 97.2 

11/15/2007 0105-0210 2196 35 98.4 

11/15/2007 0430-0535 1991 114 94.3 

11/16/2007 1215-1328 1963 16 99.2 

11/16/2007 1427-1533 2139 53 97.5 

3/10/2008 1440-1622 1673 86 94.9 

3/13/2008 0902-1017 1543 84 94.6 

3/13/2008 1148-1254 1426 86 94.0 

3/13/2008 1420-1534 1631 76 95.4 

5/21/2008 0040-0146 1820 41 97.8 

5/21/2008 0350-0535 2120 95 95.5 

5/21/2008 2300-0010 1920 296 84.6 

5/22/2008 0125-0225 2132 38 98.2 

5/22/2008 0410-0510 2146 84 96.1 

6/10/2008 1325-1535 2048 27 98.7 

6/11/2008 0900-1003 2150 73 96.6 

6/11/2008 1149-1251 2056 83 96.0 

6/11/2008 1502-1637 2039 59 97.1 

6/16/2008 1132-1232 2205 167 92.4 

6/16/2008 1415-1515 2224 178 92.0 

6/16/2008 1620-1721 2093 193 90.8 

6/17/2008 1130-1230 1995 130 93.5 

6/17/2008 1350-1450 1828 94 94.9 

6/17/2008 1545-1645 2015 104 94.8 

6/18/2008 1210-1312 1553 51 96.7 

6/18/2008 1400-1500 1787 40 97.7 

6/18/2008 1555-1655 2151 78 96.4 

6/19/2008 1150-1250 2233 136 93.9 

6/19/2008 1356-1458 2191 145 93.4 

6/19/2008 1540-1646 2024 107 94.7 

AVERAGE 1933 94 95.1 
 139

0.00

1.00

2.00

3.00

4.00

5.00

6.00

10/03/2007 10:00 10/03/2007 13:00 10/03/2007 16:00 10/03/2007 19:00 SO2 Rate (lb/mmBtu)

0.00

20.00

40.00

60.00

80.00

100.00

120.00

Gross Unit Load (MW)

Air Heater Outlet SO2 Stack SO2 Unit Load

Average Inlet SO2 = 4.70 lb/mmBtu

Average Stack SO2 = 0.17 lb/mmBtu

Average SO2 Removal = 96.5%

Average Load = 108 MWg

Figure 66. Five-minute average SO2 rates (lb/mmBtu) and gross unit load observed at AES Greenidge 

Unit 4 between 1000 and 2100 EST on October 3, 2007. SO2 was measured by the dilution extractivetype SO2 analyzer that is permanently installed at the air heater outlet (upstream of the Turbosorp®

system) and by the unit’s stack CEM (downstream of the Turbosorp® system). 

Figure 67 provides an example of each type of cause. This figure shows 5-minute average SO2

removal efficiencies, gross unit loads, and Turbosorp® outlet temperatures observed between 

3:00 and 9:00 EST on June 18, 2008. During this period, plant personnel changed the 

Turbosorp® water injection lance at about 5:10 EST, temporarily interrupting the supply of water 

to the absorber vessel. Later, at about 7:05 EST, the water injection pump tripped, again 

causing a short interruption in the water supply. In both cases, the discontinuation of water 

injection into the absorber vessel caused the temperature at the Turbosorp® outlet to rise from 

about 160 oF (its normal operating point) to about 230 oF. As a result, SO2 removal efficiency, 

which depends strongly upon the proximity of the temperature in the absorber to the adiabatic 

saturation temperature of the flue gas (see Section 4.3.11), decreased dramatically from more 

than 95% to less than 30%, causing a spike in SO2 emissions. The SO2 removal efficiency 

returned to normal (i.e., >95%) about 45 minutes after water injection resumed. As discussed in 

Section 10.1, plant personnel change the water injection lance about once every week as part of 

their routine maintenance regimen, accounting for a number of the spikes in stack SO2

emissions observed in Figure 65. The other spikes are generally attributable to unexpected 

equipment problems, such as interruptions in water or hydrated lime injection (possibly resulting 

from problems with the lime hydration system), freezing of valves or pressure transmitters 

during periods of cold weather, etc. (See Section 10.2.2 for additional details). 
 140

0

50

100

150

200

250

6/18/08 2:24 6/18/08 3:36 6/18/08 4:48 6/18/08 6:00 6/18/08 7:12 6/18/08 8:24 6/18/08 9:36

Turbosorp Outlet Temperature (oF)

0.0

20.0

40.0

60.0

80.0

100.0

120.0

Gross Unit Load (MW)

or SO2 Removal (%)

Outlet Temperature Gross Unit Load SO2 Removal

water lance 

change

water pump

trip

Figure 67. Five-minute average Turbosorp® outlet temperatures, gross unit loads, and SO2 removal 

efficiencies observed at AES Greenidge Unit 4 between 0300 and 0900 EST on June 18, 2008. These 

data indicate the effect of interruptions in water injection on the performance of the Turbosorp®

 system. 

SO2 was measured by the dilution extractive-type SO2 analyzer that is permanently installed at the air 

heater outlet (upstream of the Turbosorp®

 system) and by the unit’s stack CEM (downstream of the 

Turbosorp® system).

Such upsets occurred infrequently, however, and the Turbosorp® system proved capable of 

maintaining SO2 emissions within the unit’s permit limit during long-term operation. This is 

exemplified in Figure 68. As with the permit limit for NOx emissions, compliance with the permit 

limit for SO2 emissions is determined on a 30-day rolling average basis. Unlike the NOx permit 

limit, however, the SO2 permit limit remains constant at 0.19 lb/mmBtu over the entire range of 

normal unit operating loads. As shown in Figure 68, with the exception of a few days at the 

beginning of January when the 30-day rolling average SO2 emission rate was near 0.19 

lb/mmBtu, the Turbosorp® system maintained SO2 emissions well below the permit limit during 

the first nine months of 2008, achieving 30-day rolling average SO2 emission rates as low as 

0.09 lb/mmBtu. 

Figure 69 shows the average SO2 removal efficiency across the Turbosorp® system as a 

function of gross unit load. Averages were computed for 10-MW load ranges using the hourly 

data collected during the August 2007 – September 2008 time period. As shown in the figure, 

the SO2 removal efficiency averaged greater than 95% when the unit operated above 60 MWg, 

and it averaged close to 97% for unit loads greater than 90 MWg. Somewhat lower removal 

efficiencies were observed at the bottom end of the unit’s operating range, with an average of 

93% removal for loads below 60 MWg. The slight decline in SO2 removal efficiency at lower unit 

loads likely reflects the fact that plant personnel tended to derate the unit when problems arose 

with the Turbosorp® system in order to minimize the impact of the resulting elevated SO2

emissions on the 30-day rolling average emission rate. SO2 removal was highly variable at low 

unit loads, consistent with the prevalence of upsets in system performance at those loads. 

Although not depicted in Figure 69, the relative standard deviation among hourly SO2 removal 

efficiencies was 15.3% for unit loads below 60 MWg, versus only 1.4% for unit loads above 110 
 141

MWg. The variation in SO2 removal efficiency with unit load was also strongly correlated with 

the Turbosorp® outlet temperature, as shown in Figure 69. As expected, lower average SO2

removal efficiencies were observed at loads with higher average Turbosorp® outlet 

temperatures. These higher temperatures are indicative of water lance changes (typically 

conducted at reduced load) and other upsets involving water injection and temperature control 

in the Turbosorp® system. 

0.000

0.050

0.100

0.150

0.200

0.250

1/1/08 2/1/08 3/1/08 4/1/08 5/1/08 6/1/08 7/1/08 8/1/08 9/1/08 10/1/08

lb/mmBtu

30-Day SO2 Rate, lb/mmBtu 30-Day SO2 Limit, lb/mmBtu

Figure 68. Thirty-day rolling average SO2 emission rates and permit limit for AES Greenidge Unit 4 from 

January 2008 through September 2008.

Load swings had only a minimal impact on the SO2 removal performance of the Turbosorp®

system. This is illustrated in Figure 70, which summarizes system performance during a 

relatively extreme load swing that occurred on June 16-17, 2008. As shown in the figure, the 

gross unit load increased from about 50 MWg to about 105 MWg between 2300 EST on June 16 

and 0000 EST on June 17, and it then returned to around 50 MWg by 0100 EST on June 17. As 

the unit load began to increase, the quantity and temperature of flue gas being fed to the 

Turbosorp® absorber vessel also increased. This caused an approximately 10 oF rise in the 

temperature at the Turbosorp® outlet, leading to a drop in SO2 removal efficiency from about 

96% to about 87% as the approach to adiabatic saturation in the absorber vessel widened. The 

hydrated lime feed increased in response to the rising SO2 emissions, as evidenced by the 

increase in rotary feeder output, and the water injection rate also increased to counteract the 

rising flue gas temperature. As a result, when the unit load abruptly began to drop at 0000 EST 

on June 17, bringing about a corresponding drop in the quantity and temperature of flue gas to 

be treated, the Turbosorp® system was left with an excess of hydrated lime and water injection. 

The Turbosorp® outlet temperature quickly fell to 155 oF, and the SO2 removal increased to 

100%. This extremely high removal efficiency continued for about an hour while the drop in 

load was completed and the hydrated lime and water injection rates adjusted to the new set of 

conditions. Overall, the load swing had little impact on the unit’s SO2 emissions. In spite of the 

relatively rapid changes in process conditions, the Turbosorp® system was able to maintain an 

average SO2 removal efficiency of 95% during the two-hour period containing the load swing. 
 142

91%

92%

93%

94%

95%

96%

97%

98%

< 60 60-69 70-79 80-89 90-99 100-109 ≥ 110

Unit Load (MWg)

Average SO2 Removal 

Efficiency

158

159

160

161

162

163

164

165

Average Turbosorp Outlet 

Temperature (oF)

SO2 Removal Temperature

Figure 69. Average SO2 removal efficiency and Turbosorp® outlet temperature as a function of gross unit 

load, based on hourly data collected during August 2007 – September 2008. SO2 was measured by the 

dilution extractive-type SO2 analyzer that is permanently installed at the air heater outlet (upstream of the 

Turbosorp® system) and by the unit’s stack CEM (downstream of the Turbosorp® system). 

9.3.7 Lime Utilization

The variable operating costs of the Turbosorp® process depend strongly on the amount of 

hydrated lime that is required to achieve a given level of SO2 removal. Lime utilization in the 

Turbosorp® process is typically expressed in terms of the calcium-to-sulfur molar ratio, defined 

as the number of moles of available CaO being fed to the scrubber divided by the number of 

moles of sulfur present as SO2 or SO3 in the flue gas at the inlet to the scrubber. Per the 

discussion in Section 4.3, the Ca/S molar ratio is expected to vary with several other operating 

conditions, including the SO2 removal efficiency and approach to adiabatic saturation 

temperature in the absorber vessel. In general, greater Ca/S molar ratios are expected as the 

SO2 removal efficiency or scrubber operating temperature increases. The projected Ca/S molar 

ratio for AES Greenidge Unit 4 under design conditions (4.0 lb SO2/mmBtu fuel, 95% SO2

removal efficiency, ~160 oF scrubber operating temperature) was 1.6-1.7, as cited in Section 

6.2.4. 
 143

45.00

55.00

65.00

75.00

85.00

95.00

105.00

6/16/08 19:12 6/16/08 21:36 6/17/08 0:00 6/17/08 2:24 6/17/08 4:48

Gross Unit Load (MW)

80

85

90

95

100

105

SO2 Removal Efficiency (%)

Gross Unit Load SO2 Removal

150

155

160

165

170

175

6/16/08 19:12 6/16/08 21:36 6/17/08 0:00 6/17/08 2:24 6/17/08 4:48

Turbosorp Outlet Temperature ( oF)

0

10

20

30

40

50

60

Hydrate Rotary Feeder Output (%)

Outlet Temperature Rotary Feeder Output

Figure 70. Five-minute average gross unit loads, SO2 removal efficiencies, Turbosorp® outlet 

temperatures, and hydrated lime rotary feeder percent outputs observed at AES Greenidge Unit 4 

between June 16, 2008, at 2030 EST and June 17, 2008, at 0230 EST. These data illustrate the 

performance of the Turbosorp®

 system in response to a load swing. SO2 was measured by the dilution 

extractive-type SO2 analyzer that is permanently installed at the air heater outlet (upstream of the 

Turbosorp®

 system) and by the unit’s stack CEM (downstream of the Turbosorp® system).

Per the discussion in Sections 9.1.2.3.2 and 9.1.2.3.6, the process performance testing 

campaigns on October 8-11, 2007, and June 13-16, 2008, were designed to enable an 

evaluation of the Ca/S molar ratios required for various scrubber operating conditions (i.e., for 

changes in SO2 removal efficiency and operating temperature). Operating conditions were 

varied each day during these testing campaigns. For the tests in October 2007, the Ca/S ratios 

were calculated from the pebble lime feed rate, change in hydrated lime silo level, and SO2

loading at the scrubber inlet, and they also were determined independently by chemically 
 144

analyzing samples of the product ash produced by the Turbosorp® system. (The hydrated lime 

injection rate is not directly measured at AES Greenidge Unit 4). The hydrated lime silo level 

monitor malfunctioned during the June 2008 tests; hence, Ca/S molar ratios could only be 

determined from the product ash analysis for those tests. 

When process data were used to determine the Ca/S molar ratio, the number of moles of 

calcium was computed by multiplying the estimated hydrated lime feed rate by the available 

Ca(OH)2 content of hydrated lime samples collected on that day, and dividing by the molecular 

weight of Ca(OH)2. The hydrated lime feed rate was estimated using the pebble lime feed rate 

and hydrated lime silo level data recorded by the unit’s PI system, as well as chemical 

composition and density results from pebble and hydrated lime samples collected that day. 

Available Ca(OH)2 was determined in accordance with ASTM C25, as described in Section 

9.2.2.2.1. The number of moles of sulfur was computed as 95% of the sulfur fed with the coal 

(U.S. EPA, 1995), which was determined from the coal feed rates reported by the plant and the 

sulfur content of coal samples collected that day. 

When Turbosorp® product ash samples were used to determine the Ca/S molar ratio, samples 

of product ash, coal, hydrated lime, and fly ash (drawn upstream of the scrubber) were collected 

during the test period for use in the determination. These samples were analyzed for Ca, S, Al, 

and Si by inductively coupled plasma-atomic emission spectroscopy. The hydrated lime 

samples were also analyzed for available Ca(OH)2 (per ASTM C25). Ca/S molar ratios were 

then computed from the concentrations of Ca and S determined in the product ash samples. 

Finally, these ratios were corrected to remove the Ca and S that are attributable to coal fly ash 

(the Ca, S, Al, and Si data from the product ash and fly ash samples were used to perform 

these corrections), to adjust for the available Ca(OH)2 content of the hydrated lime being used in 

the process, and to base them on moles of inlet sulfur as opposed to moles of sulfur removed. 

(For this final correction, inlet sulfur was estimated as 95% of the sulfur fed with the coal, and 

sulfur removal was computed by subtracting the sulfur emissions determined by the stack CEM 

from the estimated inlet sulfur). 

Figure 71 shows the Ca/S molar ratios determined during the October 8-12, 2007, testing 

campaign. Data are also shown for two days from the preceding week (October 2 and 5, 2007), 

during which testing was performed with higher-sulfur coal. (The Ca/S ratios for these two 

additional days were computed using the same methods described above). As shown in the 

figure, the ratios determined from the product ash analysis exhibited less variability than those 

computed from process data, likely owing to the long residence time of solids in the system and 

the relatively short periods of stable operation under the desired conditions (as little as 4 hours 

on some days), which made it difficult to obtain representative samples. Hence, the processdata-based Ca/S ratios are likely more reflective of day-to-day variations in hydrated lime 

consumption for the October tests, although it is important to recognize that these ratios depend 

upon a number of measurements and therefore are susceptible to several sources of error. The 

process-data-based Ca/S ratios generally varied according to expectation. Process conditions 

on October 9 and 10 (coal sulfur content = 4.1 lb SO2/mmBtu, SO2 removal efficiency = 95%, 

Turbosorp® outlet temperature = 160 oF) were very similar to the design specification for AES 

Greenidge Unit 4; the average Ca/S molar ratio computed from process data on these days was 

1.68, consistent with the projected range of 1.6-1.7 referenced above. Higher Ca/S molar ratios 

(average = 2.0) were required on October 2 and 5, when the SO2 removal efficiency (average = 

97%) and coal sulfur content (average = 4.6 lb SO2/mmBtu) were greater than design 

conditions, and on October 12, when the scrubber outlet temperature was raised by 5 oF from 

its typical set point of 160 oF. The estimated approach to adiabatic saturation temperature in 

the Turbosorp® absorber vessel on this last day of testing was 45 oF, which is at least 6 oF 
 145

greater than the approach temperatures of 34-39 oF estimated for the other five days. Although 

the scrubber outlet temperature remained constant at 160 oF on October 8-10, the estimated 

approach temperature on October 8 was about 3 oF less than the estimated approach 

temperatures on October 9 and 10, possibly explaining why such a high SO2 removal efficiency 

was observed with a relatively low Ca/S molar ratio on that day. 

1.00

1.20

1.40

1.60

1.80

2.00

2.20

mol Ca / mol S (inlet)

Process Data Product Ash Analysis

Inlet SO2 (lb/mmBtu)

Scrubber Temp (°F)

SO2 Removal (%)

4.7

159

97

4.5

160

96

4.1

160

99

4.1

160

94

4.1

160

95

4.2

165

93

10/2/07

10/5/07

10/8/07

10/9/07

10/10/07

10/11/07

Figure 71. Calcium-to-sulfur molar ratios determined during parametric testing of the Turbosorp® system 

at AES Greenidge Unit 4 in October 2007. Ratios were derived from process data and from the chemical 

analysis of Turbosorp®

 product ash samples using the procedures described in the text. Relevant plant 

operating conditions are also shown. 

As discussed in Section 9.1.2.3.6, scrubber operating conditions were more stable and 

predictable during the June 16-19, 2008, testing campaign than they were during the October 8-

12, 2007, campaign, providing a better scenario for parametrizing the performance of the 

Turbosorp® system. In the absence of hydrated lime silo level data for use in computing 

process-data-based Ca/S molar ratios, extra care was taken to ensure that representative 

product ash samples could be obtained to determine these ratios. On the morning of each test 

day, after the unit reached full load, the desired set points were established, and the system 

was allowed to approach steady state. It was then operated at apparent steady state for at least 

6.5 hours. Product ash samples were not collected until the end of the period of steady-state 

operation, in order to ensure that they would be mostly comprised of material generated during 

that period. (In contrast, during the October 2007 tests, product ash samples were collected 

throughout the period of steady-state operation). Moreover, to verify the representativeness of 

the samples, the first five gallons of product ash drawn from the system was discarded, and 

five-gallon samples were then drawn in duplicate for analysis. In all cases, the concentrations 

of Ca and S determined in the duplicate samples from a given test day agreed within 5% 

(relative percent difference). Figure 72 shows the Ca/S molar ratios that were determined from 

the product ash samples collected during the June 16-19 tests, as well as relevant scrubber 
 146

operating data from each test day. The coal sulfur content during the June 16-19 test period 

was 3.5-3.7 lb SO2/mmBtu. During the first three test days, the Turbosorp® operating 

temperature was held constant at 160 oF while the SO2 removal efficiency was increased from 

92% to 98%. As expected, the Ca/S ratio increased with increasing SO2 removal efficiency, 

varying from about 1.3 at 92% SO2 removal to about 1.9 at 98% SO2 removal. The Ca/S molar 

ratio was 1.60 for 95% SO2 removal efficiency with a 160 oF scrubber operating temperature. 

This is consistent with the projected range of 1.6-1.7 for 95% removal efficiency under design 

conditions. On the last day of testing, the SO2 removal efficiency was held at 95% while the 

Turbosorp® operating temperature was raised by 5 oF to 165 oF. (The estimated approach to 

adiabatic saturation temperature in the Turbosorp® absorber vessel on this last day was 42 oF, 

about 5 oF greater than the estimated approach temperature of 37 oF on June 17). As 

anticipated, increasing the operating temperature (and, hence, moving further from the adiabatic 

saturation temperature in the fluidized bed absorber) caused an increase in the Ca/S ratio that 

was required to achieve 95% SO2 removal. 

0.80

1.00

1.20

1.40

1.60

1.80

2.00

mol Ca / mol S (inlet)

6/16/08

6/17/086/18/086/19/08

Inlet SO2 (lb/mmBtu)

Scrubber Temp (oF)

SO2 Removal (%)

3.7

160

92

3.7

160

95

3.5

160

98

3.6

165

95

Figure 72. Calcium-to-sulfur molar ratios determined during parametric testing of the Turbosorp® system 

at AES Greenidge Unit 4 in June 2008. Ratios were derived from the chemical analysis of Turbosorp®

product ash samples using the procedures described in the text. Relevant plant operating conditions are 

also shown.

The parametric tests in October 2007 and June 2008 provided an indication of the short-term 

lime utilization in the Turbosorp® system under controlled operating conditions. To assess the 

longer-term performance of the system, sorbent utilization was analyzed independently over the 

fourteen-month period between August 1, 2007, and September 30, 2008, using lime delivery 

data (i.e., truck weights) and SO2 data from the plant’s online analyzers. Results are 

summarized in Table 26. As discussed in Section 9.3.6, during this period, the average inlet 

SO2 rate was 3.62 lb/mmBtu, and the average SO2 removal efficiency was 96.3%. The 

temperature at the outlet of the Turbosorp® absorber vessel averaged 161.7 oF, just slightly 
 147

above the normal set point of 160 oF. Lime consumption (measured as available CaO) totaled 

22,969 tons, and the amount of SO2 fed to the scrubber totaled 15,148 tons, resulting in an 

average Ca/S molar ratio of 1.73. (For purposes of this calculation, any missing values in the 

inlet SO2 concentration data were replaced with values obtained by linear interpolation from the 

nearest valid concentrations). This is slightly greater than the design ratio of 1.6-1.7; however, 

some deviation from the design might be expected, because the fourteen-month lime total 

includes excess lime that was wasted during periods when SO2 emissions were over-controlled 

(16.5% of the one-hour periods during August 2007 – September 2008 had SO2 removal 

efficiencies of ≥99%) or when lime was overfed to the scrubber to compensate for temperature 

upsets resulting from load swings or maintenance activities (e.g., change-out of the water 

injection lance). The calculation is also susceptible to a number of sources of measurement 

error, including errors in the truck weights, stack flow rate measurements, available CaO 

measurements, and SO2 measurements. 

Table 26. Average calcium-to-sulfur molar ratio estimated for the 14-month period from August 2007 

through September 2008 using lime delivery (truck weight) data and SO2 data from the plant’s online 

analyzers. 

Average Process Conditions 

 SO2 Rate at Turbosorp® Inlet (lb/mmBtu)a 3.62 

 Turbosorp® Outlet Temperature (oF) 161.7 

 SO2 Removal Efficiency (%) 96.3 

Lime Consumption 

 Total Pebble Lime Deliveries (tons)b 24,683 

 Total Hydrated Lime Deliveries (tons)b 1,593 

 Average Pebble Lime Available CaO (% w/w)c 88.6 

 Average Hydrated Lime Available CaO (% w/w)c 68.8 

 Total Available CaO Consumed (tons) 22,969 

 Total Available CaO Consumed (lbmol) 820,311 

Sulfur Fed to Turbosorp® System 

 Total SO2 Fed to Turbosorp® System (tons)a 15,148 

 Total SO2 Fed to Turbosorp System (lbmol)a 473,364 

Estimated Ca/S Molar Ratio 1.73 

a

SO2 was measured by the dilution extractive-type SO2 analyzer that is permanently installed at the air 

heater outlet (upstream of the Turbosorp®

 system). Concentrations were converted to a mass basis using 

the assumptions described in Section 9.3.6. Any missing values were replaced with values obtained by 

linear interpolation from the nearest valid data. b

Sum of delivery truck weights between July 31, 2007, 

and September 29, 2008. c

Based on the available CaO (or available Ca(OH)2 x 56/74) content of pebble 

lime or hydrated lime samples collected during the sampling campaigns in October 2007 – June 2008. 

Available CaO and available Ca(OH)2 were determined according to ASTM C25. 

Nevertheless, these long-term data, coupled with the results of the process performance tests 

on October 9-10, 2007, and June 17, 2008, provide strong evidence that the Turbosorp® system 

at AES Greenidge achieved the targeted sorbent utilization during more than a year of 

commercial operation. The October 2007 and June 2008 parametric tests also confirmed that 

the required Ca/S ratio generally varied as expected with changes in scrubber operating 

conditions. 

9.3.8 Mercury Removal Efficiency

The multi-pollutant control system at AES Greenidge Unit 4 consistently exceeded its 

performance target of ≥90% Hg removal efficiency on a coal-to-stack basis. A total of 34 tests 
 148

were conducted between March 2007 and June 2008 as part of the guarantee tests, process 

performance tests, and follow-up tests to determine the coal-to-stack mercury removal efficiency 

achieved by the multi-pollutant control system. As discussed in Section 9.2, for each test, Hg 

concentrations at the stack were determined using the Ontario Hydro Method (ASTM D 6784-

02) or U.S. EPA Method 30B, and Hg concentrations in the coal were determined by ASTM D 

6722. Results are summarized in Figure 73 and in Table 27. (The tests on June 12-13, 2008, 

included simultaneous sampling via the Ontario Hydro Method and Method 30B. The Hg 

removal efficiencies determined from the Ontario Hydro Method measurements were less than 

those determined from the 30B measurements. Hence, the Ontario Hydro Method results are 

shown to be conservative). Attainment of the performance target for Hg removal was officially 

demonstrated during the tests on March 28 and 30, 2007. Greater than 90% coal-to-stack 

removal efficiency was observed during each of the six tests conducted on those two days, with 

a six-test average removal efficiency of >94.6%. (For the guarantee tests on March 28 and 30, 

Hg was determined in the Ontario Hydro Method samples using cold vapor atomic absorption 

spectroscopy, and all Hg concentrations at the stack were below the method detection limit. 

Cold vapor atomic fluorescence spectroscopy was employed for subsequent tests so that stack 

Hg concentrations could be detected). Very high Hg removal efficiency continued to be 

observed during all subsequent tests conducted as part of the project. Coal-to-stack removal 

efficiencies ranged from 92.7% to 99.8% for the 28 Hg measurements completed as part of 

process performance and follow-up testing between October 2007 and June 2008. The overall 

average removal efficiency during these tests was 98.6%. As discussed in section 9.2.1.3.5.3, 

mercury material balances were performed for all 34 Hg tests conducted during the project’s 

Operation and Testing Phase, and all of these balances had closures of 100±30%, giving 

credence to the test results. Thus, the performance target for mercury removal efficiency was 

satisfied without exception. 

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

80.0%

90.0%

100.0%

3/28/073/28/073/28/073/30/073/30/073/30/0710/2/0710/3/0710/3/0710/5/0710/5/0710/8/0710/9/07

10/10/0710/11/0711/13/0711/14/0711/14/0711/15/0711/16/07

3/11/083/11/083/12/083/12/085/19/085/20/086/12/086/12/086/13/086/13/086/16/086/17/086/18/086/19/08

Hg Removal, Coal-to-Stack

Full load, no ACI Full load, with ACI Reduced load, no ACI

> > > > > >

Figure 73. Summary of coal-to-stack Hg removal efficiencies measured at AES Greenidge Unit 4 

between March 2007 and June 2008. For bars labeled “>” the Hg concentration at the stack was below 

the method detection limit, and the removal efficiency was greater than the value shown.
 149

Table 27. Results of Hg tests performed at AES Greenidge Unit 4 during March 2007-June 2008. Relevant process conditions are 

Date/Time (local) 

Sampling / 

Analytical 

Method 

Hg In 

from 

Fuel 

(lb/TBtu) 

Hg at 

Stack 

(lb/TBtu) 

Hg 

Removal, 

Coal-toStack 

Hg 

Material 

Balance 

Closure 

(out/in) 

Unit 

Load 

(MWg) 

Coal S 

Content 

(lb SO2 / 

mmBtu) 

SO2

Removal 

Efficiency 

Turbosorp 

Outlet 

Temp 

(oF) 

Coal Cl 

Content 

(% w/w 

dry) 

3/28/2007 0905-1133 OH/CVAAS 7.34 <0.32 >95.6% 99.9% 105 3.89 95.5% 163.2 0.07 3/28/2007 1243-1507 OH/CVAAS 8.19 <0.34 >95.9% 92.6% 106 3.90 95.4% 163.3 0.08 3/28/2007 1558-1817 OH/CVAAS 6.86 <0.38 >94.5% 108.3% 105 3.77 94.0% 162.8 0.07 3/30/2007 0855-1110 OH/CVAAS 6.92 <0.40 >94.2% 118.1% 105 3.72 92.9% 162.1 0.08 3/30/2007 1243-1502 OH/CVAAS 6.45 <0.41 >93.7% 118.7% 105 3.80 95.3% 161.9 0.08 3/30/2007 1552-1805 OH/CVAAS 6.38 <0.42 >93.5% 120.0% 105 3.80 95.5% 161.7 0.07 10/2/2007 1505-1725 OH/CVAAS 7.64 0.17 97.8% 94.1% 109 4.70 96.8% 158.6 0.07 10/3/2007 1230-1439 OH/CVAAS 7.42 0.12 98.4% 107.5% 107 4.87 96.8% 158.7 0.09 10/3/2007 1555-1807 OH/CVAAS 7.43 0.09 98.7% 105.1% 107 4.75 96.2% 159.1 0.07 10/5/2007 1110-1320 OH/CVAAS 7.33 0.53 92.7% 109.2% 108 4.51 96.2% 160.4 0.11 10/5/2007 1400-1642 OH/CVAAS 6.87 0.24 96.6% 121.1% 108 4.42 96.0% 160.0 0.10 10/8/2007 1112-1307 OH/CVAAS 7.47 0.40 94.6% 118.8% 108 4.12 99.0% 159.9 0.09 10/9/2007 1545-1640 OH/CVAAS 7.11 0.26 96.3% 114.7% 106 4.03 99.1% 160.2 0.10 10/10/2007 1040-1245 OH/CVAAS 7.94 0.07 99.2% 106.7% 108 4.24 93.5% 160.5 0.09 10/11/2007 1230-1435 OH/CVAAS 9.21 0.05 99.5% 107.8% 108 4.30 94.6% 165.2 0.08 11/13/2007 2325-0131 OH/CVAAS 10.98 0.07 99.4% 86.1% 56 3.78 97.7% 160.4 0.08 11/14/2007 0347-0555 OH/CVAAS 10.02 0.10 99.0% 93.1% 56 3.67 96.8% 160.3 0.08 11/14/2007 2300-0107 OH/CVAAS 12.83 0.03 99.8% 90.1% 84 3.98 97.7% 160.9 0.11 11/15/2007 0345-0554 OH/CVAAS 13.67 0.04 99.7% 80.2% 80 3.70 95.4% 159.7 0.10 11/16/2007 1635-1855 OH/CVAAS 19.42 0.05 99.7% 72.8% 102 4.15 97.6% 160.2 0.11 3/11/2008 0932-1155 OH/CVAAS 7.03 0.09 98.7% 108.7% 106 3.31 96.7% 159.0 0.10 3/11/2008 1330-1544 OH/CVAAS 7.07 0.09 98.8% 123.1% 107 3.40 96.4% 159.3 0.09 3/12/2008 0945-1206 OH/CVAAS 6.30 0.05 99.3% 123.0% 109 3.27 98.7% 159.1 0.10 3/12/2008 1350-1614 OH/CVAAS 6.99 0.04 99.5% 117.6% 107 3.39 98.6% 159.1 0.09 5/19/2008 2330-0147 OH/CVAAS 7.15 0.13 98.2% 109.5% 56 3.52 96.2% 161.0 0.10 5/20/2008 0305-0514 OH/CVAAS 7.17 0.15 97.9% 115.7% 57 3.38 99.8% 160.9 0.09 6/12/2008 0942-1157 OH/CVAAS 5.01 0.09 98.2% 101.8% 106 3.31 97.3% 160.2 0.08 6/12/2008 1330-1547 OH/CVAAS 5.73 0.12 97.9% 100.1% 106 3.65 97.3% 160.3 0.09 6/13/2008 1000-1328 OH/CVAAS 5.66 0.04 99.3% 101.3% 109 3.55 97.6% 160.0 0.08 6/13/2008 1450--1702 OH/CVAAS 5.34 0.06 98.9% 99.0% 108 3.50 97.0% 159.8 0.10 6/16/2008 1130-1730 30B/CVAFS 7.40 0.02 99.7% 102.7% 108 3.66 92.0% 159.8 0.10 6/17/2008 1130-1730 30B/CVAFS 6.05 0.05 99.2% 97.6% 108 3.68 95.2% 160.0 0.09 6/18/2008 1130-1730 30B/CVAFS 5.40 0.01 99.8% 107.2% 109 3.53 97.7% 160.2 0.08 6/19/2008 1130-1730 30B/CVAFS 5.29 0.02 99.5% 110.2% 108 3.62 95.0% 165.0 0.10 

Notes: OH = Ontario Hydro Method, 30B = U.S. EPA Method 30B. aAssumed. 
 150

As discussed earlier, the multi-pollutant control system at AES Greenidge Unit 4 includes an 

activated carbon injection (ACI) system that can be used, if necessary, to promote mercury 

capture in the Turbosorp® scrubber and baghouse. To evaluate the effect of activated carbon 

injection on the mercury removal performance of the multi-pollutant control system, the 

guarantee testing campaign on March 28-30, 2007, and the process performance testing 

campaign on October 2-5, 2007, included Hg tests both with and without ACI. For the tests with 

activated carbon injection, a relatively low-cost, untreated, lignite-derived, powdered activated 

carbon sorbent (Super HOK) was injected at a nominal rate of 3 lb/mmacf of flue gas. The 

results are summarized in Table 28. During both test campaigns, the measurements conducted 

while activated carbon was being injected ahead of the Turbosorp® system exhibited a lower 

average coal-to-stack Hg removal efficiency than the measurements conducted with no ACI. It 

is unlikely that the activated carbon inhibited mercury removal. Rather, the apparent 

discrepancy probably resulted from several factors, including the lower coal Hg content during 

the tests with activated carbon injection (as shown in Table 28), variations in operating 

conditions between the tests with carbon injection and the tests without carbon injection (these 

tests were conducted on different days during both the March and October campaigns), and 

measurement error, which is especially likely at the low Hg concentrations observed at the 

stack. As illustrated in Table 28, the average mercury material balance closure was closer to 

100% for the tests without ACI than it was for the tests with ACI, suggesting greater error in the 

results of the latter tests. In any event, the project definitively confirmed that the multi-pollutant 

control system at AES Greenidge Unit 4 can achieve >90% Hg removal efficiency without any 

activated carbon injection. Twenty-nine of the 34 mercury tests shown in Figure 73 were 

conducted while the activated carbon injection system was not in service; the average coal-tostack mercury removal efficiency observed during these tests was 98.4%. The tests performed 

in March and October 2007 suggest that activated carbon injection cannot contribute any 

additional, measurable Hg removal efficiency to the already-high level achieved by the other 

components of the multi-pollutant control system. Hence, apart from these two test periods, 

AES Greenidge has operated the multi-pollutant control system without any activated carbon 

injection. 

Table 28. Summary of average mercury removal efficiencies observed during tests with and without 

activated carbon injection in March 2007 and October 2007. 

Number 

of 

Tests 

Average Hg in 

Coal 

(lb/TBtu) 

Average Hg at 

Stack 

(lb/TBtu) 

Average Hg 

Removal 

(%) 

Average Hg 

Material 

Balance 

Closure 

(%) 

March 28-30, 2007 

 No ACI 3 7.46 <0.35 >95.4 100 

 With ACI 3 6.58 <0.41 >93.8 119 

October 2-5, 2007 

 No ACI 3 7.50 0.13 98.3 102 

 With ACI 2 7.10 0.25 96.5 107 

Table 27 summarizes relevant plant operating conditions observed during each of the 34 

mercury tests that were conducted during the Operation and Testing Phase of the project. High 

mercury removal efficiency was observed irrespective of these operating conditions. During all 

of the test periods, AES Greenidge Unit 4 fired typical eastern U.S. bituminous coals containing 

5.0 – 19.4 lb Hg/TBtu, 3.3 – 4.9 lb SO2/mmBtu, and 0.07 – 0.11% Cl. For the five tests on 

November 16, 2007, and March 11-12, 2008, it also co-fired waste wood at less than 5% of the 

total heat input. The gross generator load during the reduced-load tests on November 13-15, 

2007, and May 19-20, 2008, ranged from 56 to 84 MW; during the other 28 tests, the unit 
 151

operated between 102 and 109 MWg. The SO2 removal efficiency across the Turbosorp®

system varied between 92% and 100% during the tests, and the Turbosorp® outlet temperature 

varied between 159 and 165 oF. None of these variables had an observable effect on the coalto-stack mercury removal efficiency over the range of conditions encountered during the tests. 

AES Greenidge Unit 4 produces fly ash with appreciable amounts of unburned carbon. The 

carbon content of fly ash samples collected at the air heater outlet, upstream of the Turbosorp®

system, during each of the 34 mercury tests was in all cases greater than 9%. The average fly 

ash carbon content observed during these tests was 18.6%. As discussed in Section 4.3.1, 

unburned carbon in the fly ash can adsorb gaseous mercury, especially at low temperatures 

such as those encountered in the Turbosorp® system. (Based on coal and fly ash chemical 

composition data from the tests in October 2007 – June 2008, the ash had already captured 

about 23% of the coal Hg by the time it reached the air heater outlet, upstream of the 

Turbosorp® system). Hence, it is possible that the high mercury removal efficiencies observed 

at AES Greenidge Unit 4 were in part attributable to the high unburned carbon content of the fly 

ash. The tests conducted during the Operation and Testing Phase of the project were unable to 

confirm or refute this possibility. As shown in Figure 74, no association was observed between 

the mercury removal efficiencies and fly ash unburned carbon contents measured during these 

tests. (The tests in March 2007, which had stack Hg concentrations below the detection limit, 

are excluded from the plot). However, the fly ash unburned carbon content at AES Greenidge 

may have been too high throughout the tests to enable such an association to be discovered. 

(Assuming that there is an association between mercury removal efficiency and fly ash carbon 

content, once sufficient carbon is present to achieve 90-100% Hg capture, any further increase 

in carbon content might not be expected to bring about a measurable improvement). 

Alternatively, the high level of mercury removal observed at AES Greenidge could have resulted 

largely from another mechanism, such as capture by Ca(OH)2 in the scrubber and baghouse. 

Thus, it is unclear whether the multi-pollutant control system would be able to achieve high Hg 

removal efficiencies without any activated carbon injection when applied to units having lower fly 

ash unburned carbon contents (e.g., <4%). The Hg removal performance of the system is 

especially uncertain for units that fire PRB coal, as these units have lower fly ash unburned 

carbon content and lower coal Cl concentrations than bituminous coal-fired units. (As discussed 

in Section 4.3.1, coal Cl helps to oxidize Hg, making it easier to capture). Additional testing is 

recommended to elucidate these uncertainties. 

As discussed in Section 9.3.5, the in-duct SCR catalyst at AES Greenidge Unit 4 was effective 

in converting some of the Hg0

 in the flue gas to Hg2+, potentially making this mercury easier to 

capture in the downstream Turbosorp® system. On average, the mercury at the SCR outlet was 

about 90% oxidized. The air heater can contribute additional Hg oxidation. Mercury 

measurements were performed at the air heater outlet during the guarantee tests in March 2007 

and the process performance tests in October 2007 and November 2007 using the Ontario 

Hydro Method. (Measurements were also performed at the air heater outlet during the March 

2008 testing campaign, but particle-bound mercury concentrations were not determined for 

those tests). Mercury removal efficiencies computed from the air heater outlet to the stack 

agreed well with those measured from the coal to the stack, as shown in Figure 75. However, 

mercury speciation measurements at the air heater outlet were affected by the aforementioned 

artifact by which fly ash collected on the sampling train filter adsorbs and/or oxidizes Hg. This 

leads to artificially high particle-bound and/or oxidized mercury concentrations, and artificially 

low elemental and/or oxidized mercury concentrations. (The direction of the bias in the oxidized 

mercury results depends upon the extent to which mercury is adsorbed as opposed to oxidized 

by the fly ash). Table 29 shows the mercury speciation results at the air heater outlet and stack 

for the 16 tests in March-November 2007 that included simultaneous sampling at these 
 152

locations. The particle-bound mercury at the air heater outlet, which averaged 53% of the total 

mercury at that location, was definitely biased high by adsorption of gas-phase mercury as it 

passed through the particulate on the sampling train filter. During the tests in October – 

November 2007, the mercury concentration in the particulate catch from the sampling train 

(average = 0.86 ppm) was about three times as great as the mercury concentration in 

particulate samples collected by the plant’s online fly ash sampler at the air heater outlet 

(average = 0.27 ppm). (Fly ash samples were not available at the air heater outlet during the 

March 2007 tests). The Turbosorp® system was very effective in removing oxidized mercury, 

given the greater-than 90% coal-to-stack removal efficiency observed during all of the Hg tests 

and the fact that at least 90% of the mercury going into the scrubber was present as Hg2+ or 

Hgpart (based on the results of the mercury speciation measurements at the SCR outlet). The 

data in Table 29 also suggest that the system removed elemental mercury. Given the nature of 

the sampling artifact at the air heater outlet, the Hg0

 concentrations at that location were at least 

as great as the values reported in Table 29. Concentrations of Hg0

 (expressed on a standard 

oxygen basis of 3%) decreased across the Turbosorp® system for all 14 tests that had 

detectable concentrations at the air heater outlet. (Concentrations of Hg0

 at the air heater outlet 

were below the detection limit for the first two tests on March 30, 2007). However, this finding 

must be interpreted cautiously in light of the low Hg0

 concentrations observed at both the air 

heater outlet and stack and the possibility that even a small amount of measurement error could 

significantly impact results at these low concentrations. 

y = -0.0065x + 0.9856

R2

 = 0.0005

92.0%

93.0%

94.0%

95.0%

96.0%

97.0%

98.0%

99.0%

100.0%

101.0%

0.0% 5.0% 10.0% 15.0% 20.0% 25.0% 30.0% 35.0%

Fly Ash Carbon Content (%)

Mercury Removal Efficiency (%)

Figure 74. Scatter plot showing the coal-to-stack Hg removal 

efficiency vs. the carbon content of fly ash samples collected at the 

air heater outlet, with simple linear regression results. Data were 

collected during tests in October 2007-June 2008. 

In addition to reducing Hg by >90% on a coal-to-stack basis, the multi-pollutant control system 

at AES Greenidge Unit 4 achieved more than 90% mercury capture over and above the 

baseline removal efficiency that had been achieved prior to the project by the unit’s ESP. As 

shown in Figure 76, during baseline testing at AES Greenidge in November 2004, mercury was 

reduced from an average of 9.82 lb/TBtu in the coal to 6.89 lb/TBtu at the stack, suggesting 
 153

about 30% capture in the ESP. (As discussed in Section 9.2.1.3.5.3, the first test on November 

17, 2004, was invalid, because it did not satisfy the quality control criterion for mercury material 

balance closure. That test is not included in the results shown in Figure 76). This Hg removal 

likely resulted from adsorption of some Hg onto unburned carbon in the fly ash, as discussed 

above, and its subsequent removal in the particulate collection device. The carbon content of 

the fly ash during the baseline tests averaged 12.4%. In light of the baseline testing results, the 

98% Hg removal achieved by the multi-pollutant control system represents a 97% reduction 

from the mercury emissions that could be achieved prior to the project by the unit’s existing 

ESP. (That is, for a given fuel, the mercury emission rate after installation of the multi-pollutant 

control system was about 97% less than the emission rate before installation of the system). 

Hence, the system succeeded in all respects from a mercury control perspective. 

y = 0.9862x + 0.0126

R2

 = 0.9844

92.0%

94.0%

96.0%

98.0%

100.0%

92.0% 94.0% 96.0% 98.0% 100.0%

Coal-to-Stack Hg Removal (%)

Air Heater Outlet-to-Stack Removal (%)

Figure 75. Scatter plot showing Hg removal efficiencies computed 

from Hg measurements at the air heater outlet and stack vs. Hg 

removal efficiencies computed from Hg measurements in the coal and 

at the stack. Measurements were conducted during tests in March, 

October, and November 2007. 

9.3.9 Sulfur Trioxide Removal Efficiency 

The Turbosorp® system demonstrated attainment of its performance target for sulfur trioxide 

removal efficiency during the Operation and Testing Phase of the project. A total of 42 valid 

SO3 tests, each including simultaneous sampling at the air heater outlet (upstream of the 

Turbosorp® system) and stack (downstream of the Turbosorp® system) were completed at AES 

Greenidge Unit 4 between May 2007 and June 2008. (As discussed in Section 9.2.1.2.6, 

additional SO3 tests were performed on March 29, 2007, but those tests were invalid because of 

probable ammonia interference with the analytical results). Table 30 summarizes the results of 

these tests. On average, the Turbosorp® scrubber and baghouse reduced SO3 in the flue gas 

from 14.1 ppmvd @ 3% O2 to 0.7 ppmvd @ 3% O2, resulting in an overall removal efficiency of 

95.3%. This satisfied the performance target of ≥95% removal efficiency. 
 154

Table 29. Mercury speciation determined as part of Ontario Hydro Method testing at the air 

heater outlet and stack in March, October, and November 2007. Speciation results at the 

air heater outlet were affected by a sampling artifact that leads to artificially high particlebound and/or oxidized mercury concentrations, and artificially low elemental and/or oxidized 

mercury concentrations. 

Date/Time (local) 

Concentration at 

Air Heater Outlet 

(μg/dscm @ 3% O2) 

Concentration at 

Stack 

(μg/dscm @ 3% O2) 

Hgpart Hg2+ Hg0 Hgpart Hg2+ Hg0

3/28/2007 0905-1133 5.32 3.72 0.63 <0.00 <0.21 <0.25 

3/28/2007 1243-1507 3.72 6.12 0.40 <0.00 <0.23 <0.25 

3/28/2007 1558-1817 4.89 4.79 0.60 <0.00 <0.27 <0.26 

3/30/2007 0855-1110 4.41 4.77 <0.41 <0.00 <0.30 <0.29 

3/30/2007 1243-1502 4.83 4.36 <0.43 <0.00 <0.30 <0.29 

3/30/2007 1552-1805 4.13 4.11 0.70 <0.00 <0.32 <0.28 

10/2/2007 1505-1725 4.10 5.00 0.46 0.00 0.17 0.07 

10/3/2007 1230-1439 2.58 7.10 0.15 0.00 0.09 0.07 

10/3/2007 1555-1807 5.89 3.65 0.18 0.00 0.09 0.04 

10/5/2007 1110-1320 6.56 3.95 0.16 0.00 0.67 0.08 

10/5/2007 1400-1642 5.43 4.14 0.25 0.00 0.29 0.05 

10/8/2007 1112-1307 4.55 6.18 0.12 0.04 0.49 0.04 

10/9/2007 1545-1640 5.99 5.57 0.14 0.00 0.26 0.10 

10/10/2007 1040-1245 7.76 3.95 0.11 0.00 0.07 0.02 

10/11/2007 1230-1435 8.59 3.12 0.12 0.00 0.05 0.01 

11/16/2007 1635-1855 14.00 5.64 0.33 0.00 0.04 0.02 

The performance guarantee for SO3 removal efficiency was officially satisfied on the basis of the 

three tests conducted on May 2, 2008. The average removal efficiency observed during those 

tests was 97.1%. Similar performance was observed more than a year later during the followup tests on June 10-11, 2008, when the SO3 removal efficiency averaged 96.1%. During both 

of these test series, the unit was operating near full load (105-109 MWg); however, the coal 

sulfur content and SO3 concentration at the Turbosorp® inlet were greater during the guarantee 

tests than during the follow-up tests. 

SO3 removal efficiencies measured during the process performance tests, which were 

conducted in October 2007 – June 2008, varied considerably. The minimum SO3 removal 

efficiency observed during these tests was 78.8%, and the maximum SO3 removal efficiency 

was 99.4%. Changes in SO3 removal efficiency hypothetically could result from changes in the 

performance of the Turbosorp® system. Scrubber operating conditions varied during the course 

of the process performance tests. For example, as shown in Table 30, the Turbosorp® outlet 

temperature ranged from 159 oF to 170 oF. As discussed earlier, during the tests on October 8-

11, 2007, and June 16-19, 2008, conditions in the Turbosorp® system were intentionally altered 

to determine their effect on its pollutant removal performance. However, no associations were 

discovered between scrubber operating conditions and SO3 removal efficiency. As shown in 

Figure 77, SO3 removal efficiency did not correlate with SO2 removal efficiency, which is 

expected to be a good surrogate for the overall performance of the Turbosorp® system. (During 

the Turbosorp® parametric tests on June 16-19, 2008, ≥95% SO3 removal efficiency was 

observed for all four sets of scrubber operating conditions that were studied. However, contrary 
 155

to expectation, the greatest SO3 removal efficiency was observed under the set of conditions 

that produced the lowest SO2 removal efficiency, and vice versa). 

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Coal Stack Emission Coal Stack Emission

Baseline Tests (11/04) Performance Tests (3/07-6/08)

Hg, lb/TBtu

30% removal 30% removal 98% removal 98% removal

97% reduction over baseline

Figure 76. Comparison of the average coal-to-stack Hg removal efficiency 

observed during baseline testing in November 2004, prior to installation of the 

multi-pollutant control system, with the average removal efficiency observed during 

performance testing in March 2007-June 2008, after installation of the system. 

Error bars represent ±1 standard deviation. 

It is more likely that the variation in SO3 removal efficiency resulted from changes in the SO3

concentrations at the inlet to the Turbosorp® system and from random error in the SO3

measurements at the stack. SO3 concentrations at the Turbosorp® inlet ranged from 4.7 to 28.7 

ppmvd @ 3% O2 during the course of the 42 tests shown in Table 30. Such variation can arise 

from a number of factors, including fluctuations in fuel sulfur content, boiler operating conditions, 

SO2-to-SO3 conversion across the SCR catalyst, and SO3 removal across the air heater (either 

by condensation of SO3 on the air heater baskets and its subsequent loss to the incoming 

combustion air, or by reaction of SO3 with ammonia slip to form ammonium bisulfate, as 

discussed in Section 9.3.4). As shown in Figure 78, there was some correlation between the 

SO3 removal efficiency and the SO3 concentration measured just upstream of the Turbosorp®

system. Removal efficiencies of <93% were only observed when the inlet SO3 concentration 

was relatively low (<11 ppmvd @ 3% O2). Demonstrating ≥95% removal efficiency from such a 

low starting concentration would require the ability to accurately measure very small 

concentrations of SO3 at the stack. For example, 95% removal from an inlet concentration of 11 

ppmvd gives a stack concentration of 0.55 ppmvd, and 95% removal from an inlet concentration 

of 4.7 ppmvd gives a stack concentration of 0.24 ppmvd (all concentrations expressed on a 3% 

O2 basis). These stack concentrations are near or below the detection limit for the controlled 

condensation method (0.15-1.5 ppm or more; Wiza, 2008). All 42 stack SO3 concentrations 

measured during the Operation and Testing Phase of the project were ≤1.7 ppmvd @ 3% O2, 

and 38 of the 42 stack concentrations were ≤1.0 ppmvd @ 3% O2. Hence, these 

measurements are expected to contain substantial random error, likely affecting the calculated 
 156

SO3 removal efficiencies across the Turbosorp® system. Nevertheless, the SO3 measurements 

presented in Table 30 show that installation of the Turbosorp® system has resulted in very low 

SO3 emissions from AES Greenidge Unit 4. 

Table 30. Results of SO3 tests performed around the Turbosorp® system at AES Greenidge Unit 4 during 

May 2007-June 2008. Relevant process conditions are also summarized.

Test Date / Time 

(local) 

SO3 

(ppmvd @ 3% O2) Turbosorp®

SO3

Removal 

Efficiency 

Unit 

Load 

(MWg) 

Turbosorp®

Inlet SO2

(lb/mmBtu) 

Turbosorp®

Outlet 

Temp 

(oF) 

SO2

Removal 

Efficiency 

Biomass 

CoFiring 

Air 

Heater 

Outlet Stack 

5/2/07 1044-1215 25.5 0.8 96.7% 109 4.40 160 88.5% 0.0% 

5/2/07 1312-1443 28.7 0.8 97.2% 108 4.67 160 91.4% 0.0% 

5/2/07 1517-1648 25.4 0.7 97.4% 108 4.53 160 92.0% 0.0% 

10/4/07 1520-1641 21.0 1.0 95.2% 109 4.63 160 97.0% 0.0% 

10/5/07 0840-0950 8.8 0.8 91.0% 108 4.47 160 98.3% 0.0% 

10/8/07 1530-1634 9.4 0.5 95.2% 108 3.92 160 99.4% 0.0% 

10/9/07 1040-1150 8.0 0.5 93.1% 109 3.95 160 93.2% 0.0% 

10/10/07 1040-1144 7.5 1.6 78.8% 108 4.25 160 93.9% 0.0% 

10/11/07 1230-1335 10.1 0.6 94.2% 107 3.95 165 93.8% 0.0% 

11/13/07 2325-0047 4.7 0.7 84.1% 56 4.03 160 97.8% 0.0% 

11/14/07 0135-0240 9.2 0.9 90.5% 56 4.01 160 98.5% 0.0% 

11/14/07 0405-0510 13.6 0.4 97.1% 56 4.00 160 96.9% 0.0% 

11/14/07 2305-0010 5.6 0.2 95.8% 84 3.75 161 97.5% 0.0% 

11/15/07 0105-0210 8.7 0.8 90.8% 84 3.78 160 98.6% 0.0% 

11/15/07 0430-0535 10.9 1.7 84.2% 80 3.76 160 95.3% 0.0% 

11/16/07 1215-1328 13.1 0.5 96.4% 103 3.43 160 99.4% 0.0% 

11/16/07 1427-1533 7.5 0.3 95.9% 103 3.51 161 97.9% 5.0%a

3/10/08 1440-1622 9.3 0.7 92.4% 108 3.38 159 96.8% 1.8% 

3/13/08 0902-1017 5.9 0.9 85.0% 107 3.28 159 96.2% 3.2% 

3/13/08 1148-1254 7.3 0.6 92.2% 108 3.29 159 96.6% 3.2% 

3/13/08 1420-1534 8.3 0.7 91.7% 108 3.36 159 96.6% 3.2% 

5/21/08 0040-0146 20.8 0.6 97.4% 91 3.62 161 98.3% 0.0% 

5/21/08 0350-0535 16.9 0.3 98.4% 81 3.71 161 96.3% 0.0% 

5/21/08 2300-0010 5.9 0.4 94.0% 56 3.77 170 85.8% 0.0% 

5/22/08 0125-0225 14.6 0.2 98.4% 56 3.82 161 98.6% 0.0% 

5/22/08 0410-0510 8.0 0.3 95.8% 55 3.85 161 96.4% 0.0% 

6/10/08 1325-1535 15.1 0.4 97.2% 105 3.27 160 99.1% 0.0% 

6/11/08 0900-1003 14.9 0.6 95.9% 107 3.32 160 96.1% 0.0% 

6/11/08 1149-1251 16.9 1.2 92.8% 107 3.30 159 96.3% 0.0% 

6/11/08 1502-1637 14.0 0.2 98.6% 105 3.29 160 97.4% 0.0% 

6/16/08 1132-1232 24.4 0.1 99.4% 108 3.43 160 92.1% 0.0% 

6/16/08 1415-1515 22.7 0.4 98.3% 108 3.44 160 92.0% 0.0% 

6/16/08 1620-1721 22.9 1.5 93.6% 109 3.46 159 90.9% 0.0% 

6/17/08 1130-1230 17.8 0.7 95.9% 108 3.54 160 95.1% 0.0% 

6/17/08 1350-1450 18.2 0.8 95.9% 108 3.52 160 94.6% 0.0% 

6/17/08 1545-1645 27.8 0.7 97.6% 108 3.50 160 95.1% 0.0% 

6/18/08 1210-1312 12.5 0.5 95.9% 109 3.55 161 97.5% 0.0% 

6/18/08 1400-1500 11.2 0.7 93.8% 110 3.56 160 98.1% 0.0% 

6/18/08 1555-1655 16.1 0.6 96.0% 109 3.61 160 97.0% 0.0% 

6/19/08 1150-1250 12.2 0.6 95.2% 108 3.65 165 94.5% 0.0% 

6/19/08 1356-1458 15.4 0.7 95.7% 109 3.66 164 94.3% 0.0% 

6/19/08 1540-1646 17.2 0.7 95.7% 108 3.67 165 95.9% 0.0% a

Assumed. 
 157

y = -0.0976x + 1.0353

R2

 = 0.0044

70.0%

75.0%

80.0%

85.0%

90.0%

95.0%

100.0%

105.0%

80.0% 85.0% 90.0% 95.0% 100.0% 105.0%

SO2 Removal Efficiency (%)

SO3 Removal Efficiency (%)

Figure 77. Scatter plot showing SO3 removal efficiencies vs. SO2

removal efficiencies observed across the Turbosorp®

 system during 

tests in May 2007 – June 2008, with simple linear regression results.

70.0%

75.0%

80.0%

85.0%

90.0%

95.0%

100.0%

105.0%

0.0 5.0 10.0 15.0 20.0 25.0 30.0

SO3 at Turbosorp Inlet (ppmvd @ 3% O2)

SO3 Removal Efficiency (%)

Figure 78. Scatter plot showing SO3 removal efficiencies across the 

Turbosorp®

 system vs. corresponding SO3 concentrations measured 

at the air heater outlet (Turbosorp® inlet) during tests in May 2007 – 

June 2008. 
 158

9.3.10 Hydrogen Chloride Removal Efficiency

The Turbosorp® system also demonstrated attainment of its performance target for hydrogen 

chloride removal efficiency during tests performed in 2007 and 2008. Thirty valid HCl tests were 

completed at AES Greenidge Unit 4 between March 2007 and June 2008. (One additional test 

on March 29, 2007, was considered to be invalid because of chloride contamination in the 

sampling trains). Each test included simultaneous sampling at the air heater outlet (upstream of 

the Turbosorp® system) and stack (downstream of the Turbosorp® system). The results are 

summarized in Table 31. On average, the Turbosorp® scrubber and baghouse reduced HCl in 

the flue gas from 38.4 ppmvd @ 3% O2 to 1.3 ppmvd @ 3% O2, resulting in an overall removal 

efficiency of 96.7%. This satisfied the performance target of ≥95% HCl removal efficiency. 

Table 31. Results of HCl tests performed around the Turbosorp® system at AES Greenidge Unit 4 during 

March 2007-June 2008. Relevant process conditions are also summarized.

Test Date / Time 

(local) 

HCl 

(ppmvd @ 3% O2) Turbosorp®

HCl 

Removal 

Efficiency 

Unit 

Load 

(MWg) 

Coal Cl 

Content 

(%, dry) 

Turbosorp®

Outlet 

Temp 

(oF) 

SO2

Removal 

Efficiency 

Biomass 

CoFiring 

Air 

Heater 

Outlet Stack 

03/29/07 1220-1344 36.0 2.8 92.4% 107 0.073 163 95.2% 0.0% 

03/29/07 1515-1637 38.6 1.1 97.1% 106 0.076 163 94.8% 0.0% 

05/04/07 0831-0940 40.4 1.3 96.8% 107 0.066 161 95.9% 0.0% 

05/04/07 1015-1130 39.9 1.0 97.5% 103 0.096 159 97.1% 0.0% 

10/04/07 1520-1637 32.7 2.2 93.2% 109 0.069 161 97.1% 0.0% 

10/05/07 0840-0959 29.0 0.3 99.1% 108 0.085 160 98.1% 0.0% 

10/08/07 1530-1640 33.8 2.6 92.2% 108 0.090 160 99.4% 0.0% 

10/09/07 1040-1150 31.9 0.7 98.0% 109 0.097 160 93.2% 0.0% 

10/10/07 1440-1553 33.2 1.4 95.9% 109 0.089 160 94.1% 0.0% 

03/10/08 1443-1610 44.8 2.1 95.3% 108 0.098 159 96.7% 1.8% 

03/13/08 0902-1042 39.0 1.3 96.6% 107 0.100 159 96.3% 3.2% 

03/13/08 1147-1304 45.5 0.7 98.4% 108 0.100 159 96.5% 3.2% 

03/13/08 1417-1533 48.6 0.7 98.5% 108 0.100 159 96.7% 3.2% 

05/21/08 0044-0230 40.9 2.4 94.1% 89 0.085 161 98.8% 0.0% 

05/21/08 0350-0547 41.3 1.6 96.2% 81 0.085 161 96.3% 0.0% 

05/21/08 2300-0017 35.4 <0.2 >99.4% 56 0.090 169 86.4% 0.0% 

05/22/08 0129-0250 26.1 <0.2 >99.3% 56 0.090 161 98.8% 0.0% 

05/22/08 0410-0527 27.9 2.9 89.5% 55 0.090 161 96.9% 0.0% 

06/10/08 1327-1528 37.5 <0.1 >99.7% 105 0.078 160 99.1% 0.0% 

06/11/08 0902-1025 41.6 <0.1 >99.8% 107 0.083 160 96.4% 0.0% 

06/11/08 1145-1300 42.4 <0.1 >99.8% 107 0.083 159 96.3% 0.0% 

06/11/08 1455-1610 40.3 <0.1 >99.8% 105 0.083 160 97.0% 0.0% 

06/16/08 1130-1250 44.1 4.0 91.0% 108 0.098 160 92.3% 0.0% 

06/16/08 1415-1533 45.1 2.0 95.7% 108 0.098 160 92.1% 0.0% 

06/17/08 1129-1242 45.2 1.4 97.0% 108 0.085 160 95.1% 0.0% 

06/17/08 1349-1515 35.1 1.1 96.8% 108 0.085 160 94.9% 0.0% 

06/18/08 1135-1242 37.8 1.7 95.5% 108 0.083 160 97.0% 0.0% 

06/18/08 1350-1500 40.0 0.9 97.8% 110 0.083 160 98.2% 0.0% 

06/19/08 1148-1255 39.0 0.7 98.2% 108 0.100 165 94.5% 0.0% 

06/19/08 1450-1557 38.4 0.7 98.2% 109 0.100 165 94.7% 0.0% 

The performance guarantee for HCl removal efficiency was officially satisfied on the basis of the 

four valid tests conducted on March 29 and May 4, 2008. The average removal efficiency 

observed during those tests was 96.0%. Even better performance was observed more than a 
 159

year later during the follow-up tests on June 10-11, 2008, when the HCl removal efficiency 

averaged 96.1%. During both the guarantee tests and the follow-up tests, AES Greenidge Unit 

4 operated at an average load of 106 MWg and fired eastern U.S. bituminous coal containing 

about 0.08% w/w Cl. 

HCl removal efficiency was measured across a variety of scrubber and unit operating conditions 

during process performance testing of the multi-pollutant control system in October 2007 – June 

2008. During these tests, the unit load ranged from 55 to 110 MWg; the fuel Cl content ranged 

from 0.07 to 0.10%; the Turbosorp® outlet temperature ranged from 159 to 169 oF, and the SO2

removal efficiency across the Turbosorp® system ranged from 86.4 to 99.4%. The average HCl 

removal efficiency measured during the process performance tests under these varying 

conditions was 96.2%, about the same as the removal efficiency observed during guarantee 

testing. As with SO3 removal efficiency, HCl removal efficiency showed no apparent association 

with scrubber operating conditions and did not correlate with SO2 removal efficiency (Figure 79). 

Moreover, as shown in Figure 80, HCl removal efficiency did not correlate with SO3 removal 

efficiency, based on the results of 24 tests during which SO3 sampling was conducted 

simultaneously with HCl sampling. 

y = -0.0415x + 1.0061

R2

 = 0.0015

85.0%

90.0%

95.0%

100.0%

105.0%

80.0% 85.0% 90.0% 95.0% 100.0% 105.0%

SO2 Removal Efficiency (%)

HCl Removal Efficiency (%)

Figure 79. Scatter plot showing HCl removal efficiencies vs. SO2

removal efficiencies observed across the Turbosorp®

 system during 

tests in March 2007 – June 2008, with simple linear regression 

results.

HCl removal efficiencies ranged from 89.5% to 99.8% during the 30 tests reported in Table 31. 

Given the lack of an association with scrubber operating conditions, the variability in these 

removal efficiencies likely resulted from measurement error at the stack. In some cases, the 

same sampling train components that were used for Ontario Hydro Method sampling, which 

utilizes an HCl rinse, had to be used for subsequent HCl sampling. Although the components 

were thoroughly rinsed, it was difficult to avoid a small amount of chloride contamination. While 

this background concentration is insignificant at the relatively large flue gas HCl concentrations 

(26-49 ppmvd @ 3% O2) observed at the air heater outlet, it can introduce significant error (on a 
 160

percentage basis) at the low flue gas concentrations (0.1-4 ppmvd @ 3% O2) encountered at 

the stack. The coefficient of variation (mean ÷ standard deviation, expressed as a percentage), 

which provides a metric for quantifying the variability of data, was 77.5% for the 30 HCl 

concentration measurements at the stack, versus only 14.3% for the 30 HCl concentration 

measurements at the air heater outlet. (For comparison, the coefficient of variation for the 42 

SO3 concentrations measured at the stack was 52.8%, and the coefficient of variation for the 42 

SO3 concentrations measured at the air heater outlet was 46.5%). During several tests, the 

probe and line rinses at the air heater outlet and stack were checked for the presence of 

residual chloride by precipitation with silver nitrate. In general, several additional rinses were 

required to reduce the chloride concentration below a detectable level, indicating low-level 

contamination. A small amount of chloride background would be expected to cause a slight 

downward bias in the removal efficiencies reported in Table 31. Such bias would not detract 

from the conclusion that the Turbosorp® system attained its performance target for HCl removal 

efficiency. 

y = -0.1873x + 1.1448

R2

 = 0.0415

85.0%

90.0%

95.0%

100.0%

105.0%

80.00% 85.00% 90.00% 95.00% 100.00% 105.00%

SO3 Removal Efficiency (%)

HCl Removal Efficiency (%)

Figure 80. Scatter plot showing HCl removal efficiencies vs. SO3

removal efficiencies observed across the Turbosorp® system during 

tests in March 2007 – June 2008, with simple linear regression 

results.

It is also noteworthy that the amount of HCl measured at the air heater outlet was less than the 

amount that would be expected under the assumption that all of the coal chlorine forms HCl. 

Based on the coal feed rate and chlorine content measured during the 30 valid HCl tests, about 

63.9 lb/h of HCl would be anticipated at the air heater outlet, on average, under this assumption. 

However, the flue gas measurements at the air heater outlet indicated an average of just 38.6 

lb/h of HCl. Fly ash samples were collected at the air heater outlet during 25 of the 30 tests and 

analyzed for Cl; these samples accounted for only 1.3 lb/h of the additional 25 lb/h of expected 

HCl. The bottom ash contained even less Cl (lb/h) than the fly ash, based on five samples 

collected between October 2007 and June 2008. (A similar, but smaller, bias was observed 

during the baseline tests in November 2004, prior to installation of the multi-pollutant control 

system. During those tests, the average HCl emission rate at the stack was 61 lb/h, and the 
 161

HCl emission rate predicted from the coal feed rate and chlorine content was 72 lb/h. Again, the 

amount of Cl in the ESP ash and bottom ash was insufficient to account for the 11 lb/h 

discrepancy). The reason for the inconsistency between the coal chlorine and the HCl 

measured at the air heater outlet is unknown. Such an inconsistency could result if gaseous Cl 

was present in a form other than HCl (e.g., Cl2) at the air heater outlet, if Cl was accumulating 

somewhere in the system, or if the measurements at the air heater outlet were biased (e.g., 

because of failure to collect a representative flue gas or fly ash sample). The second potential 

cause (accumulation of Cl) is improbable. The first potential cause would not impact that data 

presented in Table 31. In the case of the third potential cause, assuming that the stack HCl 

measurements were not subject to a similar bias, the HCl removal efficiency across the 

Turbosorp® system would be at least as great as the values reported in Table 31 (and possibly 

greater if the bias was present in the flue gas HCl concentration measurements rather than in 

the fly ash measurements). 

9.3.11 Hydrogen Fluoride Removal Efficiency

As discussed in Section 2.4, the Greenidge Project sought to demonstrate ≥95% removal of 

hydrogen fluoride across the Turbosorp® system. However, the HF tests conducted as part of 

the Operation and Testing Phase of the project were inconclusive with respect to this 

performance target. Table 32 summarizes the results of the 31 HF tests that were completed at 

AES Greenidge Unit 4 between March 2007 and June 2008. Each test included simultaneous 

sampling at the air heater outlet (upstream of the Turbosorp® system) and stack (downstream of 

the Turbosorp® system). (As discussed in Section 9.2.1.2.7, HF and HCl were determined from 

a common sampling train by U.S. EPA Method 26A). For 30 of the 31 tests, the HF 

concentration determined in the flue gas at the stack was below the detection limit. However, all 

HF concentrations measured at the air heater outlet were also near or below the detection limit. 

HF was detectable at the air heater outlet during 15 tests. HF concentrations during these tests 

averaged 1.07 ppmvd @ 3% O2 at the air heater outlet and <0.18 ppmvd @ 3% O2 at the stack, 

resulting in an average removal efficiency of >83.5% across the Turbosorp® system. The 

greatest removal efficiency observed during a single test was >91.8%. (Because of the low 

concentration upstream of the Turbosorp® system and the limitation imposed by the method 

detection limit at the stack, it was impossible to demonstrate 95% HF removal efficiency). 

During the remaining 16 tests, the HF concentration at the air heater outlet was below the 

method detection limit, precluding the calculation of a removal efficiency. Hence, the HF 

removal performance of the Turbosorp® system was indeterminate. 

The amount of HF measured at the air heater outlet was appreciably less than the amount 

expected from the coal fluorine content. As shown in Table 32, if it is assumed that all of the 

coal fluorine forms HF, then about 3.5 to 5.4 lb/h of HF would be anticipated upstream of the 

Turbosorp® system. However, HF mass flow rates determined at the air heater outlet during the 

tests in March 2007 through May 2008 averaged <10% of the expected amount, ranging from 

<0.12 lb/h to 1.2 lb/h. This discrepancy is similar to the one described in Section 9.3.10 

between the coal chlorine content and the HCl measured at the air heater outlet. Again, the 

cause of the discrepancy is unknown. Possible causes include measurement error or the 

presence of gas-phase fluorine in a form other than HF. In addition to the coal and flue gas 

measurements, fluorine concentrations were determined in fly ash and Turbosorp® product ash 

samples collected during 20 of the 31 HF tests. All of these tests were conducted while the unit 

was operating near full load (i.e., 105-110 MWg). On average during these 20 tests, the HF 

measured in the flue gas at the air heater outlet accounted for <11.2% of the fluorine fed with 
 162

the coal, and the fluorine in the fly ash at that location accounted for an additional 8.5%, leaving 

an 80.3% gap in the material balance closure. Moreover, the sum of the mass flow rates of 

fluorine in the product ash and stack flue gas (from HF) was more than twice as great as the 

mass flow rate of fluorine at the air heater outlet (from HF and fly ash), but only about half as 

much as the mass flow rate of fluorine in the coal. (In the absence of actual product ash flow 

rate measurements, the design flow rate of 17,850 lb/h was assumed for the purpose of this 

comparison). These disparities indicate substantial uncertainty in the HF testing results. 

Table 32. Results of HF tests performed around the Turbosorp® system at AES Greenidge Unit 4 during 

March 2007-June 2008.

Test Date / Time 

(local) 

HF 

(ppmvd @ 3% O2) 

Turbosorp®

HF Removal 

Efficiency 

Unit 

Load 

(MWg) 

Coal F 

Content 

(ppm, 

dry) 

HF Mass 

Flow 

Predicted 

from Coal 

(lb/h) 

HF Mass 

Flow at 

Air Heater 

Outlet 

(lb/h) 

Air 

Heater 

Outlet Stack 

3/29/07 1000-1125 <0.34 <0.20 Indeterminate 105 63.51 5.08 <0.21 

3/29/07 1220-1344 <0.34 <0.23 Indeterminate 107 63.83 5.09 <0.21 

3/29/07 1515-1637 <0.35 <0.21 Indeterminate 106 66.23 5.29 <0.21 

5/4/07 0831-0940 <0.25 <0.16 Indeterminate 107 <0.14 

5/4/07 1015-1130 <0.21 <0.16 Indeterminate 103 <0.12 

10/4/07 1520-1637 1.31 <0.17 >87.0% 109 54.10 4.35 0.87 

10/5/07 0840-0959 1.23 <0.15 >87.8% 108 53.60 4.30 0.77 

10/8/07 1530-1640 0.87 <0.16 >81.6% 108 59.10 4.75 0.50 

10/9/07 1040-1150 1.05 <0.17 >83.8% 109 55.70 4.53 0.63 

10/10/07 1440-1553 1.55 <0.15 >90.3% 109 48.50 3.93 0.92 

3/10/08 1443-1610 1.87 <0.19 >89.8% 108 69.03 5.39 1.09 

3/13/08 0902-1042 1.16 <0.15 >87.1% 107 67.58 5.20 0.68 

3/13/08 1147-1304 1.95 <0.17 >91.3% 108 67.58 5.20 1.13 

3/13/08 1417-1533 2.07 <0.17 >91.8% 108 67.58 5.23 1.20 

5/21/08 0044-0230 0.97 <0.38 >60.8% 89 74.45 4.89 0.41 

5/21/08 0350-0547 0.48 <0.24 >50.0% 81 74.45 4.62 0.21 

5/21/08 2300-0017 <0.72 <0.35 Indeterminate 56 82.15 3.68 <0.22 

5/22/08 0129-0250 <0.66 0.41 Indeterminate 56 82.15 3.70 <0.21 

5/22/08 0410-0527 <0.56 <0.34 Indeterminate 55 82.15 3.72 <0.18 

6/10/08 1327-1528 <0.44 <0.20 Indeterminate 105 42.20 3.24 <0.24 

6/11/08 0902-1025 <0.28 <0.17 Indeterminate 107 42.35 3.31 <0.16 

6/11/08 1145-1300 <0.26 <0.17 Indeterminate 107 42.35 3.30 <0.14 

6/11/08 1455-1610 <0.26 <0.19 Indeterminate 105 42.35 3.30 <0.15 

6/16/08 1130-1250 <0.27 <0.18 Indeterminate 108 50.75 4.04 <0.16 

6/16/08 1415-1533 0.42 <0.14 >66.7% 108 50.75 4.02 0.24 

6/17/08 1129-1242 0.47 <0.13 >72.3% 108 44.60 3.55 0.28 

6/17/08 1349-1515 0.37 <0.15 >59.5% 108 44.60 3.51 0.22 

6/18/08 1135-1242 0.31 <0.13 >58.1% 108 45.85 3.66 0.18 

6/18/08 1350-1500 <0.32 <0.14 Indeterminate 110 45.85 3.66 <0.19 

6/19/08 1148-1255 <0.33 <0.12 Indeterminate 108 48.65 3.91 <0.19 

6/19/08 1450-1557 <0.23 <0.15 Indeterminate 109 48.65 3.87 <0.13 

9.3.12 Particulate Matter Emissions 

Installation of the Turbosorp® system, including a new baghouse, at AES Greenidge Unit 4 

resulted in a substantial reduction in primary (non-condensable) particulate matter emissions 

from the unit. 
 163

As discussed earlier, prior to the installation of the multi-pollutant control system, an 

electrostatic precipitator was used to control PM emissions from Unit 4. The particulate matter 

emission rate achieved by the ESP was characterized during baseline testing in November 

2004. As shown in Figure 81, the average emission rate observed during two valid tests 

conducted using U.S. EPA Method 5 was 0.063 lb/mmBtu. (A third test was performed using 

Method 5 on November 17, 2004. However, an unusually high grain loading was observed for 

that test, and the sample filter contained a large amount of very coarse, carbon-like particulate 

matter that was not present during any of the other baseline tests at the stack. Hence, the 

results of the test were considered to be invalid). 

0

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09

0.1

Baseline Tests

(11/04)

Performance Tests

(3/07-6/08)

Particulate Matter Emissions

(lb/mmBtu)

Figure 81. Summary of mean primary particulate matter emission 

rates measured at the AES Greenidge Unit 4 stack before and after 

installation of the multi-pollutant control system. The baseline testing 

emission rate is based on two measurements made using U.S. EPA 

Method 5 in November 2004. The performance testing emission rate 

is based on 59 measurements made using U.S. EPA Method 17 in 

March 2007 – June 2008. Error bars represent ± 1 standard 

deviation. 

Following the installation of the multi-pollutant control system, particulate matter emission rates 

were determined as part of all of the tests conducted at the stack using the Ontario Hydro 

Method or U.S. EPA Method 26A. (In both methods, sampling was performed using a U.S. EPA 

Method 17 configuration for the particulate matter determination). Fifty-eight valid PM 

measurements were completed between March 2007 and June 2008. (One additional 

measurement on October 5, 2007, was invalid because the particle filter broke during sampling). 

The average PM emission rate ascertained from these measurements was <0.001 lb/mmBtu, as 

shown in Figure 81. This represents a more-than 98% reduction over the PM emission rate 

observed during baseline testing. The improvement in PM emissions occurred in spite of the 
 164

substantial increase in flue gas particulate loading brought about by the hydrated lime, reaction 

products, and high solids recycle rate in the Turbosorp® system. (No PM measurements were 

performed between the Turbosorp® absorber vessel and baghouse. However, design 

calculations projected that the Turbosorp® system would increase the particulate loading from 2 

gr/dscf at the absorber vessel inlet to 244 gr/dscf at the baghouse inlet). It resulted largely from 

the superior performance of the baghouse relative to the unit’s old electrostatic precipitator. 

Particle agglomeration in the fluidized bed absorber may also have contributed to the improved 

PM capture efficiency, although no tests were performed to confirm or refute this hypothesis. 

A number of the particulate matter tests included simultaneous sampling at the air heater outlet 

and stack. (In several cases, the Ontario Hydro Method sampling train at the air heater outlet 

was altered such that it did not enable a valid particulate matter measurement). These tests 

produced 43 pairs of valid PM measurements upstream and downstream of the Turbosorp®

system. The results are summarized in Figure 82 (notice the logarithmic y-axis scale). On 

average, the PM rate was reduced from 5.81 lb/mmBtu at the air heater outlet to <0.001 

lb/mmBtu at the stack, indicating >99.9% removal efficiency across the Turbosorp® system. 

(Again, the actual removal efficiency across the baghouse was even greater than this, given the 

substantial increase in particle loading across the fluidized bed absorber). Hence, the 

Greenidge Project demonstrated that the Turbosorp® system, when installed with a new 

baghouse, is a highly effective particulate control device. 

0.0001

0.0010

0.0100

0.1000

1.0000

10.0000

Air Heater Outlet Stack

Particulate Matter Rate

(lb/mmBtu)

Figure 82. Summary of mean primary particulate matter 

rates measured at the air heater outlet (upstream of the 

Turbosorp® system) and stack (downstream of the 

Turbosorp®

 system) during 43 tests in March 2007 – June 

2008. Sampling was conducted simultaneously at the two 

locations using U.S. EPA Method 17. Data are presented on 

a logarithmic scale. Error bars represent +1 standard 

deviation. 
 165

10. Operating and Maintenance Experience 

During the Operation and Testing Phase of the Greenidge Project, AES Greenidge gained more 

than a year-and-a-half of commercial operating experience with the multi-pollutant control 

system. Throughout this time, plant personnel developed an understanding of the routine 

operating and maintenance requirements associated with the system. As expected with a 

demonstration project, they also encountered unexpected challenges related to the operation of 

the system and worked to resolve these. The subsections below summarize the key O&M 

lessons learned during the project. (Certain aspects of system operations, including 

requirements for electricity, water, compressed air, urea, and lime, have already been discussed 

in Sections 6.3.4, 6.3.5, 9.3.2, and 9.3.7, and are not covered further in this section). Additional 

details concerning O&M can be found in the Project Log in Appendix D, which provides a history 

of the monthly operating experience at AES Greenidge Unit 4. 

10.1 Routine Operating and Maintenance Requirements 

The day-to-day operating and maintenance requirements associated with the multi-pollutant 

control system were able to be satisfied by the plant’s existing staff, with little added burden. As 

discussed in Section 6.3.3, a number of the components of the multi-pollutant control system 

were integrated into the unit’s distributed control system. These components are monitored and 

controlled by the same control room operator who is responsible for Unit 4. (Hence, a single 

control room operator is able to control the entire unit, including the multi-pollutant control 

system). Two-to-three auxiliary operators are staffed at all times to monitor equipment and 

operate manual controls associated with Unit 4; these operators have also been able to 

accommodate all additional routine operating requirements resulting from the multi-pollutant 

control system (e.g., operation of equipment items that are controlled by programmable logic 

controllers with local interface units). In addition, plant operations personnel perform the 

following duties on a regular basis to monitor for problems and prevent interruptions in system 

performance: 

• Walk down the system and visually check equipment (2-4 times per day) 

• Make miscellaneous adjustments to the multi-pollutant control system (1 time per day) 

• Clean the vents on the Turbosorp® product ash disposal silos (2-6 times per day) 

• Clean the ball mill magnets (2 times per day) 

• Clean the butterfly vent valve at the hydrator exhaust (2-4 times per day) 

• Operate the LPA vacuum ports (1 time per day) 

• Accept pebble lime deliveries (2 times per day) 

• Accept urea deliveries (1-2 times per week) 

• Change out and clean the Turbosorp® process water injection lance (1 time per week) 

• Change out and clean the process water strainers (1 time per week) 

• Shut down and restart the lime hydrator (1 time per week) 

• Clean the weir box at the entrance to the premixer of the lime hydrator (1 time per week) 

• Clean the hydrated lime classifier fan (1 time per week) 

AES Greenidge also routinely hires a vacuum truck to remove ash from the hopper at the 

Turbosorp® inlet (beneath the venturi nozzle) and to clean fugitive ash and lime from the area 

around the Turbosorp®, lime hydration, and ash disposal systems. The Turbosorp® inlet hopper 

is vacuumed about twice per month, and the other vacuuming is performed as needed. 
 166

In addition to the O&M activities that are performed regularly while Unit 4 is operating, certain 

routine and preventative maintenance activities are performed during outages, when plant 

personnel can access the internals of the multi-pollutant control system and safely service 

equipment items. Some or all of the following tasks are typically performed during planned and 

unplanned outages: 

• Inspect and service the SNCR urea injectors (to repair damaged tips, heat shields, etc.) 

• Vacuum fly ash and large particle ash from the SCR catalyst, catalyst screen, and LPA 

screen 

• Clean the SCR catalyst using an air lance 

• Inspect equipment items (e.g., internals of SCR reactor, Turbosorp® absorber vessel, 

and baghouse) 

• Service miscellaneous equipment items (e.g., pumps, valves, motors, etc.), as needed 

The amount of work performed during a given outage depends upon the duration of the outage, 

the amount of time that has passed since the previous outage, and the nature of any problems 

affecting the multi-pollutant control system prior to the outage. 

Finally, it is anticipated that the SCR catalyst and the baghouse bags and cages will have to be 

replaced every several years. This work will also be performed during outages, when the unit is 

offline. 

As discussed in Section 6.2.2, the SCR catalyst at AES Greenidge was designed for a 3-year 

operating life. This life expectancy was based upon the anticipated decline in catalyst activity 

over time and the effect of this decreased activity on the ability of the catalyst to continue meet 

its performance targets for NOx removal and NH3 slip. However, during the Operation and 

Testing Phase of the Greenidge Project, it was discovered that the operating life of the catalyst 

was constrained predominantly by plugging and erosion that resulted from the LPA problem 

discussed in Section 10.2.1, rather than by decreasing activity. Once sufficient large particle 

ash and fly ash have accumulated in the catalyst channels, it becomes too difficult to clean the 

catalyst in place using a vacuum and air lance, and the catalyst modules must be sent offsite for 

professional cleaning. Hence, to avoid prolonged outages, AES Greenidge has found it 

necessary to always keep a spare catalyst layer, so that one layer can be sent for cleaning 

while the other is in service. In addition to the limitation imposed by declining catalyst activity, 

erosion (resulting from the rake soot blower and from areas of high flue gas velocity) may limit 

the number of times that the catalyst can be cleaned and reused. During the approximately 22-

month period between December 2006 and October 2008, the catalyst was changed out three 

times (in May 2007, December 2007, and May 2008). (The in-duct SCR reactor was in service 

during the start-up and commissioning period as well as during the Operation and Testing 

Phase). The original catalyst layer, which was in service from December 2006-May 2007 and 

from January 2008-May 2008, was too severely damaged after its second period of service to 

be cleaned and reused. However, this catalyst was subjected to relatively harsh operating 

conditions before the LPA mitigation system was fully implemented in May 2008, and AES 

Greenidge anticipates a longer catalyst life and less frequent need for catalyst cleanings going 

forward. As of the end of the project in October 2008, plant personnel were working to develop 

a catalyst management plan based on the experience gained during the Operation and Testing 

Phase. They currently anticipate that they will have to replace the catalyst with a new or 

rejuvenated layer every two years. (Additional operating time is required to determine whether 

the catalyst can be rejuvenated for reuse after two years in service). Based on the experience 
 167

gained during the project, the catalyst can be completely changed out (including removal of the 

old catalyst layer and installation of the new catalyst layer) during a 2-to-3-day outage. 

The baghouse bags and cages are expected to last for approximately 5 years before failing from 

mechanical wear. The Operation and Testing Phase of the Greenidge Project was not long 

enough to enable an evaluation of the actual operating lives of the bags and cages. However, 

no bags or cages had to be replaced during the approximately 22-month period of operation 

between December 2006 and October 2008. (As with the in-duct SCR reactor, the baghouse 

was in service throughout both the start-up and commissioning period and the Operation and 

Testing Phase, resulting in 22 months of operating experience). 

10.2 Operating and Maintenance Challenges and Solutions 

For the most part, the multi-pollutant control system at AES Greenidge Unit 4 ran without 

problem during its first year-and-a-half of commercial operation. However, as expected with a 

first-of-a-kind installation, the project team encountered several unanticipated challenges that 

periodically hindered the operation and performance of the system. These challenges, and the 

solutions that were devised to address them, are discussed in the subsections below. (Certain 

operating challenges that were specific to the project’s performance targets, including the 

challenges associated with maintaining high-load NOx emissions below 0.10 lb/mmBtu and 

ammonia slip below 2 ppmvd @ 3% O2, have already been covered in Sections 9.3.1 and 9.3.3 

and are not addressed any further in this section). 

10.2.1 Large Particle Ash 

The most troublesome problem encountered during operation of the multi-pollutant control 

system at AES Greenidge was the accumulation of large particle ash in the in-duct SCR reactor. 

Figure 83 presents a photograph showing LPA that collected on the surface and in the channels 

of the SCR catalyst during a portion of the Operation and Testing Phase of the project. LPA 

consists of porous slag pieces of varying shape and size that are likely formed in the upper 

furnace or on heat exchange surfaces in the convective pass (Ryan and St. John, 2003). In 

many cases, these LPA pieces are too large to pass through the honeycomb catalyst. Hence, 

unless the LPA is captured upstream of the SCR, it will accumulate on the top (inlet) of the 

catalyst and become lodged in the catalyst channels. This can then promote subsequent 

accumulation of fly ash within and on top of the catalyst, as illustrated in Figure 84. Plugging of 

the in-duct SCR catalyst in this way led to various operational problems at AES Greenidge Unit 

4, as discussed below. 

The effect of large particle ash on the operation of the multi-pollutant control system began to be 

realized in early January 2007, less than a month after the in-duct SCR reactor entered service. 

On January 2, plant personnel reported concerns about increasing pressure drop across the 

SCR catalyst. As a result, they decided to take Unit 4 offline for its steam turbine screen outage 

on January 3, several days earlier than planned, to enable an inspection of the SCR internals. 

This inspection indicated that the buildup in pressure drop was caused by refractory and 

miscellaneous construction debris that remained in the boiler after the tie-in outage and had 

blocked portions of the catalyst surface, as well as by LPA that had accumulated on the 

catalyst. The debris and ash were removed, and the unit returned to service on January 7. It 

operated normally until January 30, when plant personnel again observed an increase in 
 168

pressure drop across the catalyst. The catalyst was cleaned and inspected on February 2-4; 

LPA was identified as the cause of the increase in pressure drop. 

Figure 83. Photograph taken on November 10, 2007, showing 

large particle ash accumulation in the in-duct SCR catalyst at 

AES Greenidge Unit 4. 

Figure 84. Photograph from February 3, 2007, showing the accumulation of fly ash on top of the 

in-duct SCR reactor at AES Greenidge Unit 4. The buildup of fly ash appeared to be caused by 

pieces of LPA that blocked the catalyst channels. 

The large particle ash problem affected the operation of AES Greenidge Unit 4 throughout much 

of the project’s Operation and Testing Phase. As shown in Table 33, the in-duct SCR reactor 
 169

was inspected, cleaned, or modified because of LPA accumulation during 17 outages between 

January 2007 and October 2008. The LPA problem was the primary cause of nine of these 

outages. Per the discussion in Section 4.3.9, accumulation of large particle ash in the SCR 

catalyst may cause a deterioration in SCR performance, including decreased NOx removal 

efficiency and increased ammonia slip. The association between increased catalyst plugging 

(presumably caused by LPA) and increased ammonia slip at AES Greenidge was illustrated in 

Section 9.3.3. (No association was discovered between catalyst plugging and NOx emissions, 

likely owing to the importance of other factors such as the performance of the combustion 

system and SNCR system in determining the NOx emission rate). LPA accumulation in the 

SCR catalyst can also pose other problems for unit operations, including increased pressure 

drop that strains downstream ductwork and requires an increase in fan power. 

Table 33. Summary of outages at AES Greenidge Unit 4 during which actions were taken in and around 

the SCR reactor to address the LPA problem. 

Outage Dates Outage Cause Actions Taken in/around SCR Reactor 

January 3-7, 2007 Steam turbine screen LPA, fly ash, and construction debris cleaned 

from SCR 

February 2-4, 2007 SCR cleaning LPA and fly ash cleaned from SCR 

February 9-10, 2007 Superheater tube leak LPA and fly ash cleaned from SCR 

March 2-4, 2007 SCR cleaning LPA and fly ash cleaned from SCR 

March 22-24, 2007 SCR cleaning LPA and fly ash cleaned from SCR 

April 19-22, 2007 SCR cleaning LPA and fly ash cleaned from SCR 

May 17-25, 2007 Catalyst change / LPA 

removal system 

installation 

Catalyst layer changed; LPA screen, eight 

vacuum ports, and two soot blowers installed to 

capture and remove LPA upstream of the SCR 

June 15-17, 2007 Tube leak LPA and fly ash cleaned from SCR 

July 12-14, 2007 ID fan cable failure LPA and fly ash cleaned from SCR 

August 10-12, 2007 SCR cleaning LPA and fly ash cleaned from SCR 

September 4-10, 2007 LPA removal system 

modification 

Two LPA soot blowers replaced with four rotary 

soot blowers; spring seal installed to close gap 

between LPA screen sections; rake soot blower 

installed above catalyst; LPA and fly ash cleaned 

from SCR 

September 18-21, 2007 Oil leak LPA and fly ash (minimal) cleaned from SCR 

November 9-12, 2007 SCR cleaning LPA and fly ash cleaned from SCR; spring seal 

repaired 

December 27, 2007 – 

January 3, 2008 

Catalyst change Catalyst layer changed; gaps in LPA screen 

patched; samples collected for evaluation 

May 2-10, 2008 Planned spring outage LPA screen replaced with smaller-pitch screen; 

LPA screen spring seal replaced with hinged seal; 

catalyst layer changed; catalyst test modules 

installed; rake soot blower discharge angle 

changed from 90o to 45o 

July 4-6, 2008 Economizer tube leak LPA and fly ash cleaned from SCR 

October 3-6, 2008 Damaged coal burners LPA and fly ash cleaned from SCR 

During the first half of 2007, the timing of outages for SCR cleaning was driven by the need to 

maintain a clean catalyst for purposes of guarantee testing. Hence, outages were held 

whenever the pressure drop across the SCR catalyst reached ~2.5 iwc at full load. The 

baseline pressure drop across the catalyst is ~1.1 iwc at full load. 
 170

After the guarantee tests were completed, however, it became less important to achieve optimal 

SCR performance as the unit was able to satisfy its permit limit for NOx emissions even when 

the catalyst was partially plugged. Hence, AES Greenidge began to tolerate larger pressure 

drops across the SCR reactor in order to avoid the undesirable economic consequences of 

frequent outages. The amount of tolerable pressure drop was then limited by the need to 

maintain less than 18 iwc of vacuum downstream of the air preheaters in order to avoid the risk 

of ductwork collapse. (As discussed in Section 9.3.3, increases in the pressure drop across the 

air preheaters, possibly resulting from ammonium bisulfate fouling, also contribute to the 

vacuum present in the downstream ductwork. LPA accumulation may promote ammonium 

bisulfate fouling by causing increased ammonia slip from the SCR reactor). Figure 85 shows 

the hourly average pressure drops measured across the SCR catalyst between June 2007 and 

September 2008, following the completion of guarantee testing, as well as the hourly average 

gross unit loads during this period. As illustrated in the figure, AES Greenidge was able to 

tolerate up to nearly 5 iwc of pressure drop across the catalyst before taking an outage to clean 

the SCR reactor. At times (i.e., prior to the outages beginning on September 4, 2007, 

November 9, 2007, December 27, 2007, and May 2, 2008), plant personnel also derated the 

unit to reduce the pressure drop and extend the period of operation between outages. 

0

1

2

3

4

5

6

6/21/07 8/10/07 9/29/07 11/18/07 1/7/08 2/26/08 4/16/08 6/5/08 7/25/08 9/13/08

Pressure Drop (iwc)

0

20

40

60

80

100

120

Gross Unit Load (MW)

Catalyst dP LPA Screen dP Daily Max Unit Load

Figure 85. Time series plot (EST) showing the average hourly pressure drops measured across the SCR 

catalyst and LPA screen at AES Greenidge Unit 4 between June 21, 2007, and September 30, 2008. 

The maximum gross unit load observed each day during this period is also plotted. 

The frequency of outages for SCR cleaning also decreased as a result of the implementation of 

a large particle ash removal system. (The LPA removal system was installed outside of the 

scope of the DOE cooperative agreement, but it is discussed here because it was essential to 

the successful operation of the multi-pollutant control system). The final design of that system, 

and the challenges associated with installing it in the tight ductwork configuration upstream of 

the in-duct SCR reactor, have already been described in Section 6.2.2. The development of an 

effective LPA removal system required several iterations between May 2007 and May 2008, 

however. The operating experience that led to the final design is discussed here. 

The large particle ash removal system was originally installed during an outage on May 17-25, 

2007. The initial design included a sloped screen above the SCR catalyst to capture LPA from 

the flue gas, eight vacuum ports (visible in Figure 17) to remove captured LPA from the base of 

the screen, and two soot blowers beneath the screen to aid in transporting the LPA to the 

vacuum ports. As with the final screen design described in Section 6.2.2, the original screen 

consisted of coated carbon steel sheets with hexagonal perforations. However, the perforations 
 171

were considerably larger than those in the final design; opposing walls of each hexagon were 

separated by a distance of 5.83 mm. Also during the May 2007 outage, the original SCR 

catalyst, which had been in service since start-up of the in-duct SCR reactor in December 2006, 

was removed from the reactor and replaced with a new catalyst layer. The original layer was 

too severely plugged to continue in service without first being sent offsite for professional 

cleaning. 

After returning to service, the system operated for less than a month before plant personnel 

observed increasing pressure drop across both the LPA screen and the SCR catalyst. The 

SCR reactor was inspected during a tube leak outage on June 15-17, 2007; the inspection 

indicated that the soot blowers were missing several areas of the LPA screen, allowing LPA to 

accumulate in those areas. Another inspection during an ID fan cable failure outage in July 

confirmed that the soot blowers were not affording adequate coverage to keep the LPA screen 

clean. Figure 85 includes a plot of the pressure drop across just the LPA screen (excluding the 

catalyst). Small increases in the pressure drop across the screen are evident during JuneAugust 2007, coinciding with this less-than-optimal soot blower performance. Moreover, in spite 

of the presence of the screen, AES Greenidge observed that some LPA was still reaching the 

catalyst, presumably by passing through the small gap between the two sections of the LPA 

screen. (As described in Section 6.2.2, because the top of the screen is affixed to the ductwork 

above an expansion joint, the screen was installed in two sections to allow it to move with the 

duct as furnace temperatures change – e.g., during start-up and shut-down). A short outage 

was held on August 10-11, 2007, to allow for the removal of LPA that had accumulated on the 

screen and catalyst. The pressure drop across the SCR (including both the catalyst and the 

screen) returned to normal following the outage, but it was again increasing as of the end of 

August, eventually forcing AES Greenidge to derate Unit 4. 

AES Greenidge completed an outage in early September 2007 to modify the large particle ash 

removal system in response to the problems identified in June-August. During the outage, 

which lasted from September 4 through September 10, the two soot blowers that had been 

installed in May to clean the LPA screen were replaced with four rotary soot blowers to provide 

improved cleaning coverage, and a spring seal was installed to close the gap between the two 

sections of the LPA screen. The plant also installed a rake soot blower containing ~350 blow 

points immediately above the catalyst to aid in resuspending any fly ash that accumulates on its 

surface. (The rake was expected to keep the catalyst cleaner than the existing sonic horns). 

The new rotary soot blowers proved to be effective in preventing LPA from accumulating on the 

LPA screen. As shown in Figure 85, the increases in pressure drop that had been observed 

across the screen during June-August 2007 were not observed during September 2007-

Septemeber 2008, and inspections conducted during this latter period did not indicate any 

appreciable buildup of LPA on the screen. 

The pressure drop across the SCR catalyst began to increase again soon after the September 

2007 outage, however. The plant took several actions in October 2007 to try to alleviate this 

problem, including increasing the discharge pressure and frequency of operation of the rake 

soot blower above the catalyst and resuming operation of the sonic horn system (which had 

initially been discontinued after the installation of the rake), but these were unsuccessful in 

reversing the trend. As of the end of October, Unit 4 was derated in order to maintain sufficient 

pressure downstream of the reactor to avoid risk of ductwork collapse. The unit was further 

derated in early November to allow it to continue to operate while AES completed an outage at 

another of its New York power plants. 
 172

Then, on November 9-12, 2007, AES Greenidge held an outage to inspect and clean the in-duct 

SCR reactor. Upon entering the reactor, plant personnel discovered a substantial amount of 

modestly sized large particle ash distributed relatively evenly over the surface of the catalyst. 

(They did not observe mounding of ash as they had during previous outages, likely owing to the 

effect of the rake soot blower). Some of the LPA was small enough to have passed directly 

through the mesh of the LPA screen, and some LPA also likely reached the catalyst by passing 

through gaps where the screen meets the duct walls. In addition, the spring seal that was 

installed in September to close the gap between the upper and lower sections of LPA screen did 

not flex as it was designed to, creating another gap for LPA to penetrate. Large particle ash 

was vacuumed from the surface of the catalyst, and a temporary fix for the spring seal was 

installed. When the unit returned to service, the pressure drop across the SCR catalyst was 

greater than the normal baseline, likely because some LPA was lodged deep within the catalyst 

and could not be removed as part of the cleaning. 

The pressure drop across the SCR catalyst increased relatively rapidly following the midNovember 2007 outage, and Unit 4 was derated for much of December in order to maintain 

sufficient pressure downstream of the reactor. At the end of December, AES Greenidge held 

another outage to inspect and clean the SCR reactor. Plant personnel thoroughly patched gaps 

in the LPA screen while the unit was offline. Also during this outage, the existing, plugged SCR 

catalyst layer was replaced with the original catalyst layer, which had been removed from the 

reactor in May 2007 (as discussed above) and professionally cleaned. Figure 86 presents a 

photograph of one of the plugged catalyst modules that was removed from the SCR reactor in 

December 2007. The outage began on December 27, and the work in the SCR reactor was 

completed successfully by December 30, but a problem with the unit’s distributed control system 

(unrelated to the multi-pollutant control system) prevented it from returning to service until 

January 3, 2008. 

The pressure drop across the SCR catalyst returned to its baseline value of ~1.1 iwc in early 

January 2008, following the outage. However, this pressure drop again increased throughout 

January-April, consistent with LPA and fly ash accumulation in the catalyst. The rate of 

increase in pressure drop was slower than the rate observed after previous outages; we suspect 

that AES's efforts to thoroughly patch gaps in the LPA screen during the December 2007 

outage, along with the installation of freshly cleaned catalyst during that outage, helped to slow 

the rate of catalyst plugging. Moreover, Unit 4 was derated because of coal quality issues for a 

time in February and early March 2008, which may have helped to reduce the rate of LPA 

accumulation in the catalyst. At the end of March, however, the pressure drop across the SCR 

catalyst was nearly 4 iwc, and plant personnel had to derate Unit 4 to avoid the risk of ductwork 

collapse downstream of the air heaters. The unit continued to be derated throughout April 2008 

so that it could continue to operate until its planned spring outage in early May. Elevated 

pressure drop across the air heaters, possibly resulting in part from ammonium bisulfate 

formation on the air heater baskets, also contributed to this derate. 
 173

Figure 86. Photograph of a partially plugged catalyst module (viewed from the inlet end) that was 

removed from the in-duct SCR reactor at AES Greenidge Unit 4 in late December 2007. A test catalyst 

element was removed near the center of the module. 

Meanwhile, the project team worked to diagnose the cause of the catalyst plugging problem and 

to develop a solution for overcoming the problem. Upon inspecting the SCR reactor in late 

December 2007, plant personnel observed weak agglomerates of fine ash adhering to 

structures above the catalyst and protruding from the bottom of the catalyst (see Figure 87). 

Some of the catalyst channels also appeared to be plugged by “sticky” fly ash. These 

observations led the project team to hypothesize that a chemical mechanism could be 

contributing to ash accumulation in the catalyst. To investigate this possibility, samples of the 

various types of ash and other deposits found in and around the SCR reactor were collected 

during the December outage and sent to CONSOL for bulk chemical analysis and to Lehigh 

University for X-ray diffraction (XRD) analysis. 

Results of the bulk chemical analyses were discussed during a project status review meeting 

including representatives from CONSOL, AES Greenidge, and DOE on January 17, 2008, and 

results of the bulk chemical analyses and XRD analyses were discussed during a meeting 

including representatives from Lehigh, AES Greenidge, DOE, CONSOL, Fuel Tech, and 

Cormetech on February 19, 2008. The bulk chemical analysis results, which are included in 

Appendix L to this report, did not indicate any chemical mechanisms of plugging, although 

several interesting observations were noted with respect to the sulfur, ammonia, iron, and 

carbon content of the samples. Apart from typical ash components (e.g., Fe2O3, Al2O3, SiO2), 

XRD analysis identified calcium sulfate, sodium nitrate, and calcium urate hexahydrate (a 

possible product of urea decomposition) in some of the samples from the SCR reactor; 

however, the abundance of these components was small relative to the ash components, and 

no clear evidence of a chemical mechanism of catalyst plugging was discovered. 

 
 174

Figure 87. Photograph of a portion of the outlet end of the SCR catalyst 

taken during the December 2007 outage at AES Greenidge Unit 4. Weak 

agglomerates of fly ash can be seen protruding from some of the catalyst 

channels. 

Hence, the team concluded that the continued catalyst plugging was likely being caused 

predominantly by pieces of LPA that were small enough to pass through the LPA screen but 

large enough to lodge in the catalyst. The LPA in the catalyst channels would then promote 

subsequent accumulation and bridging of fly ash, especially in areas of reduced flue gas 

velocity. (Accumulation of LPA and/or fly ash also contributes to an altered velocity profile 

across the catalyst). This physical mechanism of plugging was supported by observations of 

LPA lodged in the catalyst and catalyst screen during the November and December 2007 

outages, as shown in Figures 83 and 88. (The catalyst screen is located below the LPA screen, 

just above and parallel to the surface of the catalyst). It was also supported by BPEI’s 

dissection of a catalyst element that was pulled from the SCR reactor during the outage in 

November 2007. As part of this dissection, the catalyst element, which was 53% plugged, was 

cut into eighteen sequentially numbered wafers of approximately equal thickness, such that the 

first wafer was taken from the outlet end of the catalyst and the eighteenth was taken from the 

inlet end. Each wafer was probed to determine the number of plugged channels and the 

number of LPA particles (defined by visual inspection or as any particle not passing a 3.4 mm 

screen) contained within the channels. As illustrated in Figure 89, analysis of the resulting data 

indicated a strong correspondence between the number of plugged cells in any given wafer and 

the cumulative total number of LPA pieces found in all wafers between the given wafer and the 

outlet end of the catalyst. This observation is consistent with the hypothesis that LPA was the 

root cause of the catalyst plugging. It suggests that as relatively large pieces of LPA became 

lodged within the catalyst channels, they provided a foundation for the accumulation of fly ash 

and smaller LPA particles in the space above, thereby plugging these channels. In some cases, 

hardened fly ash was discovered at the inlet end of the catalyst channels. It is believed that this 

hardened ash, which was distinctly different from LPA, may have resulted from the compaction 

and wetting of fly ash that had already accumulated in these channels as a result of 

downstream LPA. 
 175

Figure 88. Photograph of a portion of the catalyst screen taken during the 

November 2007 outage at AES Greenidge Unit 4. Small pieces of LPA 

(surrounded by fly ash) are visibly lodged in the screen. The white 

coloration is color “washout” from the photographic flash, and it does not 

represent the actual color of the ash. 

Based on the analyses performed in early 2008, AES Greenidge decided to address the catalyst 

plugging problem mechanically (i.e., by taking further action to prevent LPA from penetrating the 

screen and lodging in the catalyst), and they implemented additional modifications to the LPA 

removal system during the unit’s planned spring outage on May 2-10, 2008. These 

modifications resulted in the final LPA removal system design described in Section 6.2.2. The 

May 2008 outage marked the first time that Unit 4 was out of service since January 3, 2008. 

Upon inspecting the SCR reactor at the start of the outage, plant personnel reported that the 

catalyst was plugged with substantial amounts of LPA and fly ash, and the catalyst was also 

severely eroded in places, presumably because of the rake soot blower. It also appeared that 

one of the rotary soot blowers on the western side of the LPA screen and one of the LPA 

vacuum ports were not functioning properly prior to the outage, based on observations of 

accumulated LPA near those pieces of equipment. These issues were attended to. 

During the outage, the existing LPA screen above the in-duct SCR reactor was removed and 

replaced with a new, smaller-pitch LPA screen, in order to improve the capture efficiency for 

small pieces of LPA. Figure 88 presents a side-by-side comparison of the new screen and the 

original screen. In addition, the existing catalyst modules, which were severely eroded and 

plugged with fly ash and LPA, were removed and replaced with clean catalyst modules. Figure 

89 illustrates the condition of one of the catalyst modules that was taken out of the SCR reactor 

during the May 2008 outage. Most of the replacement modules had been in service at AES 

Greenidge Unit 4 prior to its late December 2007 outage, and they were sent for professional 

cleaning before being reinstalled in the reactor. However, eight of the 26 modules were refitted 

with larger-pitch catalyst (seven were refitted with honeycomb catalyst, and one was refitted 

with corrugated catalyst) so that the performance of this catalyst (i.e., its susceptibility to 

plugging) could be evaluated. Also during the outage, the rake soot blower was modified so 

that it blows at a 45-degree angle rather than perpendicularly to the catalyst surface (the 

discharge pressure of the rake was also reduced to lessen catalyst erosion), and a new seal 
 176

was installed to close the gap between the two sections of the LPA screen. The seal, which is 

shown in Figure 92, consists of a plate that is attached with hinges to each of the two screen 

sections; this design was expected to perform better than the spring seal that was installed 

previously. 

0

20

40

60

80

100

120

140

160

0 5 10 15 20

N

Count

Cumulative LPA Pieces in Wafers 1-N

Plugged Cells in Wafer N

catalyst 

outlet

catalyst

inlet

Figure 89. Summary of results from the dissection of a 

catalyst element pulled from the in-duct SCR reactor during 

the November 9-12, 2007 outage. The catalyst element was 

cut into 18 sequentially numbered wafers, with wafer 1 taken 

from the outlet end and wafer 18 taken from the inlet end. 

The plot shows the number of plugged cells observed in 

each wafer (there were 324 total cells per wafer), as well as 

the cumulative number of LPA pieces found between the 

outlet end of the catalyst and each wafer. 

Figure 90. Photograph comparing the original LPA 

screen that was installed in May 2007 (right) with the 

new, smaller-pitch LPA screen that was installed in 

May 2008. 

 
 177

Figure 91. Photograph showing one of the catalyst modules that was removed from the SCR reactor in 

May 2008. Catalyst erosion (likely caused by the rake soot blower) and some LPA plugging are evident 

in the picture. 

Figure 92. Photograph from the May 2008 outage showing the 

new LPA screen (installed) and the new hinged seal connecting 

the two LPA screen sections. 

Immediately following the May 2008 outage, the full-load pressure drop across the SCR catalyst 

returned to its normal, clean catalyst baseline value of ~1.1 iwc. This pressure drop then began 

to increase gradually at the end of May, and by June 19, it had risen to ~ 2.4 iwc. That day, 

plant personnel realized that the operating pressure of the rake soot blower had been set to just 

20 psi rather than the desired 60 psi. Upon increasing the pressure and operating the soot 

blower, the pressure drop across the SCR catalyst decreased to 1.4-1.5 iwc, illustrating the 

importance of the rake soot blower in keeping the catalyst clean. (The abrupt decrease in 

pressure drop across the catalyst on June 19 is clearly visible in Figure 85). Plant personnel 

were able to maintain a relatively constant pressure drop across the SCR catalyst for the rest of 

June by operating the rake soot blower four times per day at 60 psi. 
 178

On the evening of July 4, 2008, AES Greenidge unexpectedly had to take Unit 4 offline to repair 

an economizer tube leak. Although unrelated to the multi-pollutant control system, the outage 

gave plant personnel an opportunity to inspect the in-duct SCR reactor and gauge the 

performance of the LPA removal system. Just prior to the outage, the pressure drop across the 

SCR catalyst rose to about 1.7 iwc at full load. Upon inspecting the reactor, plant personnel 

found that the large particle ash screen and catalyst screen were partially plugged with wet fly 

ash and some LPA. It is unclear how much the tube leak contributed to this plugging. Some 

catalyst channels were plugged, but these were fairly well distributed across the cross section of 

the catalyst. There were no piles of fly ash on top of the catalyst screen, as had been observed 

during some previous outages, and the extent of catalyst plugging appeared to be less than it 

would have been in the past after ~8 weeks of operation. Plant personnel vacuumed the LPA 

screen and catalyst screen (they did not remove the catalyst screen to vacuum the catalyst 

directly), and the unit returned to service on the morning of July 6. 

The high-load pressure drop across the SCR catalyst remained relatively constant at 1.5-2.0 iwc 

through the end of September 2008. (AES Greenidge generally continued to operate the rake 

soot blower four times per day at 60 psi, although they raised the operating pressure several 

times in late August in order to correct an apparent slight increase in pressure drop). AES 

Greenidge Unit 4 was derated by several megawatts throughout much of August and 

September 2008, because two coal burners were damaged by flame attachments and had to be 

taken out of service. The unit was further derated by about 3-7 MW during several weeks in 

September while it co-fired Powder River Basin coal with Northern Appalachian coal. (The 

derate was required because of the high moisture content of the PRB coal). These derates may 

have contributed to a slower rate of LPA accumulation in the catalyst. 

AES Greenidge held an outage on October 3-6, 2008, to repair the damaged coal burners. 

During the outage, plant personnel inspected the in-duct SCR reactor. Although some LPA had 

accumulated in the LPA screen, catalyst screen, and catalyst, the amount of accumulation 

appeared to be much less than was typically observed prior to May 2008, when the original, 

larger-pitch LPA screen was in service. Based on a visual inspection, the larger-pitch 

honeycomb catalyst test modules appeared to be less plugged than the smaller-pitch 

honeycomb catalyst modules or the corrugated catalyst test module. Plant personnel 

vacuumed LPA from the catalyst screen (they did not remove the screen to access the catalyst 

directly) and cleaned the catalyst from above using an air lance. The pressure drop across the 

SCR catalyst was about 1.7 iwc at high loads following the outage. 

The improvements made to the LPA removal system during the outages in September 2007, 

December 2007, and May 2008 all appeared to be effective in reducing the severity of the 

catalyst plugging problem. This is illustrated in Figure 93, which shows the rate of increase in 

the high-load pressure drop across the SCR reactor following each of these outages. The 

pressure drop data are plotted as a function of cumulative megawatt-hours of operation after 

each outage. Data collected after the August 2007 SCR cleaning outage are also included to 

provide a baseline for comparison. 

As shown in the figure, the rate of increase in pressure drop across the SCR catalyst became 

less severe with each successive improvement to the LPA removal system. Following the 

August 10-12, 2007, outage, which occurred prior to the installation of the rake soot blower, the 

high-load pressure drop across the catalyst increased from 1.1 iwc to 3 iwc after only ~25,000 

MWh of operation. The rake soot blower was installed during the outage on September 4-10, 

2007, as were the spring seal and rotary soot blowers for the LPA screen. Following that 
 179

outage, ~80,000 MWh of operation were logged before the pressure drop across the SCR 

catalyst reached 3 iwc. The SCR catalyst was not changed out during the August 10-12 or 

September 4-10 outages. A fresh catalyst layer was installed during the outage on December 

27, 2007 – January 3, 2008, though, and plant personnel thoroughly patched gaps in the LPA 

screen during that outage. This substantially slowed the rate of increase in pressure drop 

across the SCR reactor. As shown in Figure 93, ~170,000 MWh of operation were logged 

before the pressure drop reached 3 iwc. Finally, during the May 2-10, 2008, outage, the 

catalyst was again changed, and the smaller-pitch LPA screen and hinged seal were installed. 

The pressure drop across the SCR catalyst never reached 3 iwc during about 290,000 MWh of 

operation following this outage. However, the change in soot blowing pressure in June, the 

economizer tube leak (and associated SCR cleaning) in July, and the derates in August and 

September make it difficult to ascertain the extent of improvement in performance afforded by 

the smaller-pitch LPA screen. Nevertheless, the pressure drop across the catalyst remained 

below 2 iwc during more than 170,000 MWh of continuous operation between early July and 

late September 2008, without any indication of an exponentially increasing trend. (By 

comparison, in all previous cases, the pressure drop had surpassed 3 iwc after ≤170,000 MWh 

of uninterrupted operation). This suggests that the smaller-pitch LPA screen brought about 

some reduction in the severity of the SCR plugging problem. 

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

5.5

0 50,000 100,000 150,000 200,000 250,000 300,000

Cumulative Gross MWh of Operation

Pressure Drop Across Catalyst (iwc)

8/12/07-9/4/07

9/10/07-11/9/07

1/3/08-5/2/08

5/10/08-9/30/08

Rake soot

blower pressure 

increased Economizer 

tube leak 

outage

Figure 93. Plot comparing the rates of increase in pressure drop across the SCR 

catalyst at AES Greenidge Unit 4 following the outages in August 2007 (navy 

blue), September 2007 (magenta), December 2007 (light blue), and May 2008 

(red). For each case, the plot shows the high-load pressure drop across the SCR 

catalyst as a function of the cumulative MWh of operation since the conclusion of 

the outage. The high-load pressure drop includes all hourly average pressure 

drops measured when the unit was operating at ≥90 MWg. 

In summary, the project team made substantial progress in mitigating the large particle ash 

problem during the Operation and Testing Phase of the project. The data presented above 

indicate that, while the LPA screen was clearly a central part of the solution, the rake soot 

blower also played a very important role in reducing catalyst plugging. Additional operating 
 180

experience is required to confirm the rate of catalyst plugging with the smaller-pitch LPA screen 

and to determine the long-term durability of the screen in the hot, particle-laden environment 

upstream of the SCR reactor. In the meantime, AES Greenidge continues to explore options for 

further mitigation of the LPA problem. As of the end of the project, they were evaluating the 

possibility of using alternative catalyst designs (e.g., plate-type catalyst) that may be less 

susceptible to plugging. 

10.2.2 Turbosorp® System and Ancillary Equipment 

As discussed in Section 4.2.5, the Turbosorp® system is mechanically simple relative to many 

alternative FGD technologies, and therefore, it is expected to afford low maintenance 

requirements. This was generally true at AES Greenidge during the Operation and Testing 

Phase of the project. All of the challenges encountered with the Turbosorp® process had 

significantly less impact on the operation of the multi-pollutant control system than the LPA 

problem discussed above. Nevertheless, the Turbosorp® system and its ancillary equipment at 

times required non-routine O&M attention, and the lessons learned from this O&M experience 

may help to improve the design of future installations of the Turbosorp® technology. 

10.2.2.1 Lime Hydration System

The majority of the O&M requirements associated with the Turbosorp® process during its first 

year-and-a-half of operation involved the lime hydration system, which is the most mechanically 

complex part of the process. 

Most of the problems occurred in the hydrated lime milling and classification system. During 

August-November 2007, plant personnel endured several episodes of plugging in the hydrated 

lime classification loop. The most noteworthy episode occurred in early October, when Unit 4 

was firing a higher-than-normal sulfur coal (i.e., containing approximately 4.4 - 4.9 lb 

SO2/mmBtu) for performance testing, resulting in increased hydrated lime demand for the 

scrubber. Although this demand was well within the design limits for the lime hydration system, 

the hydrated lime classifier plugged numerous times on October 3 and 4, causing the lime 

hydration system to trip. AES Greenidge personnel were diligent in unplugging the lime 

hydration system and in taking deliveries of hydrated lime to allow the unit to continue to 

operate during this period, and the problems subsided when the unit returned to firing coal with 

more typical sulfur content (i.e., 4.0 - 4.3 lb SO2/mmBtu). After additional sporadic plugging in 

November, plant personnel slowed the speed of one of the rotary feeders in the classification 

system, because they believed that the feeder previously was operating too rapidly to allow its 

pockets to fill, causing fines to build up in the system. This modification reduced the severity of 

the problem. In addition, since the end of the project in October 2008, AES Greenidge installed 

a new soft start on the classifier fan, which has significantly improved the reliability of the lime 

hydration system. 

Another recurring problem involved the escape of balls from the ball mill. This first occurred in 

July 2007, when several escaped balls caused minor damage to the lime hydration system, 

forcing it offline for repair. Similar problems were encountered during the first quarter of 2008. 

On several occasions, balls escaped from the ball mill and jammed the rotary feeder that 

removes heavies from the hydrated lime classifier. Moreover, in mid-March 2008, an escaped 

ball caused the screw conveyer at the classifier outlet to fail, again forcing the lime hydration 
 181

system offline. Plant personnel installed magnets at the inlet and outlet of the bucket elevator to 

capture escaped balls before they can reach the classifier, and this has helped to mitigate the 

problem. They also recently recharged the ball mill with less-brittle balls, because the original 

balls were breaking too frequently, allowing metal fragments to escape the mill and interfere 

with operation of the system. 

Other non-routine problems encountered with the lime hydration system, and the actions taken 

to solve them, were as follows: 

• On May 3, 2007, the water feed rate to the lime hydrator was out of limits, causing the 

hydrator to plug and require cleaning. The control logic for the hydrator was modified to 

prevent this problem from occurring again in the future. 

• During the week of August 20, 2007, the lime hydration system had to be taken offline 

because the bucket elevator shaft failed. Plant maintenance personnel repaired the 

problem, and the system returned to service. 

• In mid-November 2007, one of the hydrated lime classifier fan bearings failed. The lime 

hydration system was taken offline while the problem was repaired. 

• On January 15, 2008, a bolt fell out of the ball mill, allowing balls to spill on the ground. 

The lime hydration system was taken offline while the problem was addressed. 

• The original hydrated lime classifier eroded severely during the first year of operation. A 

new, ceramic-lined classifier was installed during the unit’s May 2008 outage to provide 

resistance to erosion. 

• On June 19, 2008, the hydrated lime silo level transmitter failed, causing the hydrator 

(which is controlled automatically based on the silo level) to produce hydrated lime at a 

slower rate than required to keep up with demand. The level transmitter was not able to 

be repaired onsite, and the lime hydration system was operated for several days by 

taking periodic, manual hydrate silo level measurements and adjusting the hydrator 

output accordingly. The level transmitter was repaired and returned to service the 

following week; however, the problem recurred in mid-July. The silo level 

measurements also appeared to be affected by dust interferences. As of the end of the 

project, plant personnel were evaluating options for improving the reliability of these 

measurements. 

• The hydrator mixer plugged soon after returning to service following the Unit 4 outage on 

October 3-6, 2008. Plant personnel cleared the hydrator and worked through problems 

with lime buildup in the pebble lime belt feeder, and the lime hydration system returned 

to service on the evening of October 7. 

Many of the problems with the lime hydration system required that it be taken out of service for 

maintenance or repair. This can be accomplished without impacting operation of the 

Turbosorp® process if there is a sufficient inventory of hydrated lime available to satisfy the 

demand from the scrubber. However, the hydrated lime storage silo that was installed as part of 

the multi-pollutant control system, which has a capacity of 2,200 ft3

, only holds enough hydrated 

lime for about six hours of operation at full load, assuming design conditions. For longer 

hydrator outages, this inventory can be replenished by taking deliveries of hydrated lime, 
 182

allowing continued operation of the Turbosorp® system. Deliveries often required greater than 

six hours to arrive, though, and Unit 4 had to be derated during several of the hydrator outages 

because of insufficient hydrated lime supply. During the fourth quarter of 2007, AES Greenidge 

began renting a temporary storage tanker to enable them to maintain a larger onsite inventory of 

hydrated lime. As of the end of the project, they were procuring a 10,000 ft3

 silo to significantly 

increase their hydrate storage capacity. This will afford much more flexibility for performing 

offline maintenance on the hydrator without adversely affecting the operation of Unit 4. 

10.2.2.2 Turndown 

Per the discussion in Section 6.2.4, the Turbosorp® system at AES Greenidge Unit 4 was 

installed with a flue gas recirculation system to preserve the unit’s turndown capability. The 

recirculation system was designed to recycle flue gas from the booster fan outlet duct (upstream 

of the ID fans) to the Turbosorp® inlet duct in order to maintain sufficient fluidizing velocity in the 

absorber vessel at low unit loads. In practice, however, the flue gas recirculation system has 

behaved unstably when it is operated in automatic control mode. At times, this has resulted in 

adverse pressure gradients that create the potential for reverse flow through the recirculation 

duct (i.e., such that flue gas could potentially bypass the Turbosorp® system by traveling 

through this duct). 

Thus, AES has generally operated Unit 4 so that the flue gas flow rate upstream of the 

Turbosorp® system is adequate to maintain a fluidized bed in the absorber vessel without 

having to use the flue gas recirculation system. This has reduced the unit’s maximum turndown 

by about 8 MWn, increasing its minimum operating load from about 37 MWn prior to the project 

to about 45 MWn after the project. AES is able to operate the flue gas recirculation system in 

manual mode when necessary, such as during start-up of the unit. 

The problems with automatic control of the flue gas recirculation system likely could have been 

avoided if the recycle stream was taken from the discharge of the ID fans rather than from the 

discharge of the booster fan. This approach was not taken at AES Greenidge, because it would 

have been necessary to move the ID fans to accommodate tie-in of the recirculation duct. In 

retrospect, given the loss of turndown, it may have been better to replace the two existing ID 

fans with two larger-capacity fans, rather than installing the booster fan, and to take the flue gas 

recycle stream from the discharge of these new ID fans. This option should be considered in 

future installations of the Turbosorp® technology. 

10.2.2.3 Cold Weather Problems

As discussed earlier, the Turbosorp® system at AES Greenidge is located in an open structure 

outside of the boiler building, and it is therefore exposed to ambient weather conditions. AES 

Greenidge generally experiences cold winters (ambient temperatures as low as 1 oF were 

observed at the plant during the winter of 2007-2008), and these cold temperatures at times 

caused problems with operation of the Turbosorp® system. As discussed in Section 8.3, frozen 

lines and valves resulting from frigid weather hampered start-up of the Turbosorp® system in 

February 2007. The following year, in February 2008, plant personnel again encountered 

problems with freezing lines and valves in the lime hydration system and with freezing and 

clogging of the dosing valves in the Turbosorp® system during periods of cold weather. They 

succeeded in overcoming these problems by cleaning, heating, and/or insulating the problem 
 183

areas, and they were able to operate the Turbosorp® system with a low set point for SO2

emissions to make up for the higher-than-normal emissions encountered during the problem 

period. In early March 2008, AES Greenidge encountered problems with frozen pressure 

transmitters in the Turbosorp® system, which caused them to lose the fluidized bed in the 

absorber vessel several times. Plant personnel thawed the transmitters, and the scrubber 

returned to normal operation. 

Harsh weather conditions, including cold temperatures, wind, and icing, also made it more 

difficult for plant O&M personnel to service the Turbosorp® equipment at times during winter. In 

light of these experiences, consideration should be given to enclosing the Turbosorp® system in 

locations that commonly experience cold weather. 

As discussed in Section 4.3.11, because the Turbosorp® system operates near the adiabatic 

saturation temperature of the flue gas, there is a potential for condensation and ash deposition if 

the absorber vessel is not well insulated. This potential increases in cold climates. The inside 

of the Turbosorp® vessel was inspected during an outage in May 2008, following more than a 

year of operation, and no evidence of any significant ash deposition was discovered. Plant 

personnel again inspected the absorber vessel internals in October 2008 and reported that 

while the inlet cone was clean, there appeared to be some small deposits higher in the vessel. 

These deposits were too minor to warrant further action, however. Hence, in spite of cold 

weather conditions, no major condensation issues were encountered in the Turbosorp®

absorber vessel at AES Greenidge. 

10.2.2.4 Baghouse

As discussed in Section 6.3.5, the compressed air demand from the baghouse exceeded 

expectations. It was originally anticipated that the baghouse would require about 300 scfm of 

compressed air; however, the actual demand was about 600 scfm during normal operation and 

as much as 1200 scfm during start-up. As a result, AES Greenidge had to install additional 

compressor capacity (outside of the scope of the DOE project) to handle the excess demand. 

In addition, the valves at the inlet to the baghouse modules did not work properly, preventing 

plant personnel from being able to isolate the individual modules for online maintenance. An 

inspection of the baghouse near the end of the project in October 2008 revealed significant ash 

accumulation around these valves, suggesting that some condensation had occurred. Plant 

personnel cleaned the ash from one of the eight modules, and they planned to clean the other 

seven modules during a future outage. The valves should be exercised frequently as part of 

normal operating practice to maintain their mobility. 

No other problems were encountered with operation of the baghouse. As stated in Section 

10.1, no baghouse bags or cages failed during the Operation and Testing Phase of the project. 

In addition, no problems were encountered with plugging or binding of the bags. 

10.2.2.5 Ash Recirculation System

On a few occasions, short-lived problems with the ash recirculation system required non-routine 

maintenance and/or hindered operation of the Turbosorp® system. These minor problems 

included the following: 
 184

• During the weekend of January 19-20, 2008, Unit 4 had to be derated for several hours 

when one side of the ash disposal system plugged. The problem appeared to result 

from the control strategy for disposing ash from the ash recirculation system, which 

biased the entire ash disposal to one of the air slides. AES considered modifications to 

the control scheme for the ash disposal system to prevent this problem from recurring. 

• During April 2008, plugging occurred around the rotary air locks and in the ash disposal 

lines that are located between the air slides and the product ash silos. On at least one 

occasion, the plugging appeared to be caused by rain leakage around the knife gate 

valves downstream of the air slides. Plant personnel were able to resolve all of the 

plugging issues without having to derate Unit 4. 

• On June 15 and 16, 2008, concrete-like deposits formed in one side of the ash disposal 

system, forcing one of the ash silos out of service. Plant personnel were able to 

continue to operate the Turbosorp® system using the other silo while they cleared the 

deposits. 

• In September 2008, plant personnel found it difficult for a time to maintain an inventory 

of product ash in one of the air slides, but they overcame this problem by adjusting set 

points associated with the air slide level control. 

An important design feature of the ash recirculation and disposal system is the ability for either 

side of the system (i.e., either of the two air slides or either of the two ash disposal silos) to 

handle 100% of the required throughput of product ash. This significantly reduced the severity 

of impact from problems that involved only one side of the system. To improve the performance 

of the ash recirculation system, AES Greenidge installed larger motors on the air slide blowers 

in May 2008. These new, 30-hp motors were expected to reduce the likelihood that the system 

would trip because of high air slide ash levels. They also now operate the rotary air locks above 

the ash disposal silos on a regular basis (at least once every 15 minutes) to prevent them from 

plugging. 

10.2.2.6 Miscellaneous 

Other minor problems encountered with the Turbosorp® process during the Operation and 

Testing Phase of the project included the following: 

• In May 2008, the SO2 analyzer upstream of the absorber vessel malfunctioned. This 

analyzer, which provides one of the inputs to the control loop that governs how much 

hydrated lime is injected into the absorber, was out of service for several days while AES 

Greenidge waited for a replacement part. During that time, plant personnel had to 

operate the Turbosorp® scrubber with the hydrated lime injection control system in 

manual mode. (They had trouble scaling back the hydrated lime injection rate during 

drops in load, and they likely overfed hydrate in trying to ensure that the unit’s SO2

emissions remained within its permit limit). The inlet SO2 analyzer was repaired, and the 

hydrated lime injection control system returned to normal, automatic operation. 

• In September 2008, AES Greenidge experienced some minor problems with plugging in 

the hydrated lime feed pipe. The Turbosorp® system was able to continue to operate in 

spite of this plugging. The timing of the problem coincided with misty weather conditions 
 185

at the plant. Plant personnel took advantage of the unit’s outage on October 3-6, 2008, 

to thoroughly clean the feed pipe. 

10.3 Operating and Maintenance Labor Requirements 

AES Greenidge was able to operate and maintain the multi-pollutant control system without 

adding any new O&M personnel. As discussed in Section 10.1, AES is able to run Unit 4, 

including the multi-pollutant control system, with three-to-four operators per shift (one control 

room operator plus two-to-three auxiliary operators). This is the same level of staffing that was 

required prior to installation of the multi-pollutant control system. Maintenance staffing per shift 

also did not change as a result of the installation of the multi-pollutant control system. 

Quantification of the O&M labor requirements associated with the multi-pollutant control system 

was complicated, however, by the fact that the plant’s other unit – Unit 3 – operated much less 

frequently in 2007 and 2008 than it did prior to installation of the multi-pollutant control system. 

As a result, O&M time that would have been spent on Unit 3 could instead be spent attending to 

the multi-pollutant control system, with no net increase in staffing requirement. Plant personnel 

estimate that, if Unit 3 had continued its pre-project level of operation, four additional full-time 

positions (two operators and two maintenance personnel) would have been required to 

accommodate the increase in O&M work arising from the multi-pollutant control system. This 

estimate appears to be conservative based on experience during the first year-and-a-half of 

operation. For example, plant operations personnel tracked their hours by task during MarchOctober 2008, and on average, only six operator hours per day (as opposed to the 12 hours per 

day implied by the estimate above) were spent on the multi-pollutant control system. However, 

much of the additional time in the estimate is intended to account for the occasional overtime 

and increased staffing needed to handle non-routine O&M requirements such as those 

described in the preceding section. Moreover, O&M labor requirements are expected to 

increase over the life of the system as the multi-pollutant control equipment ages and requires 

more attention. 

10.4 Byproduct Disposal

As discussed in Section 6.3.6, the only major solid or liquid byproduct produced by the multipollutant control system is the product ash from the Turbosorp® system. The product ash, which 

is pictured in Figure 94, is a fine, dry, powdery material consisting of a mixture of fly ash and 

scrubber byproduct (i.e., reaction products and unreacted hydrated lime). AES Greenidge does 

not directly measure the mass flow rate of product ash that is discharged from the Turbosorp®

process; however, this flow rate was estimated as part of the material balances that were 

performed for each of the 34 mercury tests conducted between March 2007 and June 2008 (see 

Section 9.2.1.3.5.3 and Appendix K). The material balances indicated that, on average, about 

20,540 lb/h of product ash (including fly ash) was produced at full load. (This is based on the 

results of the 28 tests conducted when the unit was operating at greater than 100 MWg). If the 

mass contributed by fly ash is excluded, about 13,260 lb/h of scrubber byproduct was produced 

on average. This compares closely with the projected rate of 13,174 lb/h discussed in Section 

6.3.6. Figure 95 shows the relationship between the mass of scrubber byproduct generated in 

the Turbosorp® process and the mass of SO2 removed by the process, based on the results of 

the 34 material balances. On average, about 3.4 lb of scrubber byproduct (excluding fly ash) 

was produced for every lb of SO2 removed. 
 186

Figure 94. Photograph of the product ash, including a mixture of 

scrubber byproduct and fly ash, produced by the Turbosorp®

 process at 

AES Greenidge Unit 4. 

y = 3.4082x

R2

 = 0.7929

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

0 1,000 2,000 3,000 4,000 5,000 6,000

SO2 Removed (lb/h)

Byproduct Produced (lb/h)

Figure 95. Scatter plot showing the mass flow rate of scrubber 

byproduct (excluding fly ash) produced by the Turbosorp®

 process vs. 

the mass flow rate of SO2 removed by the process, with simple linear 

regression results. Data were derived from the material balances 

performed for each of the 34 mercury tests conducted at AES 

Greenidge between March 2007 and June 2008. 
 187

As discussed earlier, AES Greenidge disposes of the Turbosorp® product ash in a landfill 

located near the plant. The product ash is transported from the plant to the landfill via truck. 

Installation of the Turbosorp® system has caused a significant increase in the quantity of 

material that must be transported and the rate at which the landfill is occupied. In addition, plant 

personnel reported that the product ash is more difficult to condition with the plant’s paddle 

mixer and results in more fugitive dust than pure fly ash. Overall, however, no major problems 

have been encountered with disposal of the product ash. 

The mercury that is captured by the Turbosorp® process resides in the product ash. To 

determine the potential for leaching of this mercury, sixteen product ash samples collected 

during the testing campaigns in November 2007, March 2008, May 2008, and June 2008 were 

analyzed by the Synthetic Precipitation Leaching Procedure (SPLP), as described in Section 

9.2.2.2.1. This procedure is designed to evaluate the mobility of metals in properly engineered 

landfills that do not include municipal waste. It uses leaching solution with a pH of 4.2 to 

simulate the type of acid precipitation that may be encountered east of the Mississippi River. 

Results are shown in Table 34. The leachates from the November 2007 samples were 

analyzed for Hg by cold vapor atomic absorption spectroscopy, and the leachates from all 

subsequent samples were analyzed for Hg by cold vapor atomic fluorescence spectroscopy, 

which has a lower detection limit. All of the SPLP tests indicated a very low potential for Hg 

leaching from the product ash. For the three tests that used CVAAS, the concentration of Hg in 

the leachate was below the analytical detection limit of 0.35 μg/L. For the remaining 13 tests 

that used CVAFS, the mean concentration of Hg in the leachate was 0.036 μg/L. (By 

comparison, the U.S. EPA drinking water standard for Hg is 2 μg/L). These tests indicated that, 

on average, only 0.13% of the Hg in the product ash was leached. 

Table 34. Synthetic Precipitation Leaching Procedure results for sixteen Turbosorp® product ash 

samples collected at AES Greenidge Unit 4 between November 2007 and June 2008. 

Sample Collection 

Date / Time (local) 

Hg Concentration 

in Leachate 

(μg/L) 

Total Hg in 

Product Ash 

(μg/g) 

Hg Leached from 

Product Ash 

(μg/g) 

Hg Leached 

from Product 

Ash 

(%) 

11/14/07 0145 <0.35 0.469 <0.01 <1.49% 

11/15/07 0600 <0.35 0.608 <0.01 <1.15% 

11/16/07 1945 <0.35 0.673 <0.01 <1.04% 

03/10/08 1530 0.008 0.439 0.0002 0.04% 

03/11/08 1645 0.011 0.458 0.0002 0.05% 

03/12/08 1630 0.019 0.422 0.0004 0.09% 

03/13/08 1600 0.032 0.453 0.0006 0.14% 

05/20/08 0520 0.073 0.357 0.0004 0.10% 

05/21/08 0500 0.065 0.369 0.0003 0.09% 

05/22/08 0200 0.047 0.355 0.0002 0.07% 

06/12/08 1700 0.032 0.312 0.0006 0.21% 

06/13/08 1700 0.042 0.337 0.0008 0.25% 

06/16/08 1730 0.053 0.486 0.0011 0.22% 

06/17/08 1745 0.026 0.356 0.0005 0.14% 

06/18/08 1800 0.025 0.314 0.0005 0.16% 

06/19/08 1800 0.037 0.320 0.0007 0.23% 

NOTE: The SPLP leachates from November 2007 were analyzed using CVAAS; all other leachates were 

analyzed using CVAFS. 
 188

The chemical composition of the Turbosorp® product ash was determined throughout the 

Operation and Testing Phase of the Greenidge Project by analyzing samples collected during 

the special test series in March 2007 through October 2008. The results from all of these 

analyses are included in Appendix J. Table 35 shows the average chemical composition of 

product ash samples collected during follow-up testing on June 10-13, 2008, when Unit 4 and 

the multi-pollutant control system were operating near design conditions. Noteworthy 

characteristics of the product ash include the low moisture content (<1%), the moderate 

concentration of fly ash, and the presence of unreacted lime. Moreover, product ash samples 

from March 2007 and June 2008 were analyzed to determine physical properties, including 

particle size distribution and surface area. These analyses indicated that the product ash has a 

median particle diameter of ~6-7 μm and a surface area of ~6 m2

/g. 

Table 35. Average results from the chemical analysis of 

Turbosorp®

 product ash samples collected during follow-up 

testing at AES Greenidge Unit 4 on June 10-13, 2008. 

Moisture (%) 0.92 

Ash (% dry, ignited @ 750 °C) 82.81 

Carbon (% dry) 11.51 

Chlorine (% dry) 0.34 

Mercury (ppm dry) 0.322 

Fluorine (ppm dry) 90.90 

Ammonia (ppm dry) 28.75 

Paste pH 12.80 

Available Ca(OH)2 (%) 4.15 

Major Ash Elements (% of total sample, dry)a

 SiO2 13.61 

 Al2O3 6.90 

 TiO2 0.31 

 Fe2O3 4.87 

 CaO 32.12 

 MgO 0.61 

 Na2O 0.39 

 K2O 0.40 

 P2O5 0.09 

 SO3 24.93 a

Elemental results are reported in oxide form by convention. 

The chemical and physical properties of the Turbosorp® product ash, which are similar to those 

of spray dryer ash, make it a candidate for use in several commercial applications. According to 

the most recent statistics available from the American Coal Ash Association (ACAA), about 8% 

of the byproduct generated by dry scrubbers (e.g., spray dryers) in the United States is utilized 

in various engineering, construction, and agricultural applications (ACAA, 2008). These 

applications typically take advantage of the acid neutralization capability and cementitious 

characteristics of the byproduct. Mining applications are the largest consumer of dry scrubber 

byproduct, accounting for 74% of the total utilization. The byproduct is typically used for mine 

reclamation and can be used to fill surface mine voids, fill underground voids to prevent 

subsidence, or prevent and neutralize acid mine drainage. Dry scrubber byproduct is also used 

in concrete products (14% of the total utilization), as flowable fill (8%), in agricultural 

applications (2%), in waste stabilization/solidification (1%), as structural fill (<1%), and in soil 
 189

modification/stabilization (<1%). In addition to the uses identified in the ACAA survey, CONSOL 

and Universal Aggregates, LLC, demonstrated the viability of producing manufactured 

aggregates (e.g., for use in masonry block or roadway construction) from spray dryer scrubbing 

byproducts (Wu et al., 2005; Wu and Yuran, 2007). Given the similarities between Turbosorp®

product ash and spray dryer byproduct, the Turbosorp® product ash could potentially be used in 

any of these applications. The composition of the product ash is expected to vary from unit to 

unit, based on differences in factors such as the coal ash content and composition, the coal 

sulfur content, the fly ash unburned carbon content, and the SO2 removal efficiency. Hence, the 

suitability of the product ash for reuse will have to be evaluated on a unit- and applicationspecific basis. 

During the Operation and Testing Phase of the Greenidge Project, AES actively pursued 

opportunities for beneficial reuse of the Turbosorp® product ash. They succeeded in supplying 

3,500 tons of product ash for use as fill material in a nearby construction project, thereby 

avoiding the cost associated with landfilling this ash. In most cases, however, potential users of 

the product ash were located at a significant distance from the plant, and high transportation 

costs prevented utilization of the ash. This is consistent with the relatively low rate of dry 

scrubber byproduct utilization identified in the ACAA survey, and suggests that beneficial reuse 

of the Turbosorp® product ash will be limited to niche applications having attractive economics. 

11. Process Economics 

As discussed earlier, the multi-pollutant control system that was demonstrated at AES 

Greenidge Unit 4 was designed to provide an affordable emissions control option for smaller 

coal-fired EGUs. As such, the system was expected to offer lower capital costs and fixed O&M 

costs (in exchange for somewhat higher variable O&M costs) than conventional emissions 

control retrofit technologies, consistent with the needs of these smaller units. 

This section summarizes the estimated capital costs and fixed and variable O&M costs 

associated with the multi-pollutant control system at AES Greenidge Unit 4. Process economics 

were derived using common cost estimating practices as well as design, performance, and cost 

information from the AES Greenidge installation. In the absence of project-specific information, 

cost estimating and financing assumptions were generally taken from NETL’s Quality Guidelines 

for Energy System Studies (McGurl et al., 2004). Costs are expressed in constant 2005 dollars, 

consistent with the start of construction at AES Greenidge Unit 4. 

Assumptions regarding the performance of the base plant were taken from the design basis for 

AES Greenidge Unit 4. Key assumptions are highlighted in Table 36. A capacity factor of 80% 

was assumed in accordance with the NETL Quality Guidelines for Energy System Studies. (For 

the estimates presented here, all of the unit’s operating time was assumed to be at full load, 

such that turndown of the hybrid SNCR/SCR system was not modeled). Capital costs were 

based on the actual cost to install the multi-pollutant control system at AES Greenidge Unit 4. 

Fixed operating and maintenance costs were based on the O&M experience described in 

Section 10 and on common cost estimating assumptions. Variable O&M costs were computed 

in two ways: first using the projected performance at the time of design (as described in Section 

6), and then using the actual performance observed during the Operation and Testing Phase of 

the project (as described in Section 9). 
 190

The estimated capital costs, fixed O&M costs, variable O&M costs, and levelized costs 

associated with the multi-pollutant control system are presented in the following subsections. 

Table 36. Base plant performance assumptions used in the economic analysis of the multi-pollutant 

control system at AES Greenidge Unit 4. 

 Maximum capacity (MWe, net) 107 

 Fuel feed rate (lb/h) 85,692 

 Fuel HHV (Btu/lb) 12,426 

 Fuel sulfur content (%, w/w) 2.5 

 Fuel Hg content (ppmw) 0.1 

 Baseline NOx emission rate (lb/mmBtu) 0.30 

 Flue gas flow rate at air heater outlet (acfm) 423,700 

 Annual capacity factor (%) 80 

11.1 Capital Costs

Table 37 summarizes the capital costs for the multi-pollutant control system at AES Greenidge 

Unit 4. Costs are summarized for the overall plant, and they are also broken down by major 

project subsystem. Costs for the hybrid NOx control system include the costs for the 

combustion modifications, SNCR system, in-duct SCR system, static mixers, sonic horns, large 

particle ash removal system, and all supporting equipment. (Even though the combustion 

modifications and large particle ash removal system were not part of the scope of the DOE 

project, they are included in this cost estimate because they are essential to the performance 

and operability of the installation at AES Greenidge Unit 4. The costs for the LPA removal 

system reflect the final design as of May 2008.) Costs for the circulating dry scrubbing system 

include the costs for the absorber vessel, process water system, lime storage, hydration, and 

injection system, baghouse, ash recirculation system, booster fan, and all supporting 

equipment. (The entire booster fan cost was included with the circulating dry scrubbing system 

because this system accounts for a majority of the pressure drop added by the multi-pollutant 

control system). 

Table 37. Capital costs for the multi-pollutant control system at AES Greenidge Unit 4. Costs are 

expressed in 2005 dollars. 

Total Plant 

Cost 

Total Plant 

Investment 

Total Capital 

Requirement 

$MM $/kWnet $MM $/kWnet $MM $/kWnet

Hybrid NOx Control System 12.2 114 12.5 117 12.9 120 

Circulating Dry Scrubber System 24.5 229 25.1 234 26.1 244 

Activated Carbon Injection System 0.6 6 0.6 6 0.6 6 

TOTAL 37.3 349 38.2 357 39.6 370 

Capital costs are expressed as total plant cost (TPC), total plant investment (TPI), and total 

capital requirement (TCR). The total plant costs presented in Table 37 are the EPC capital 

costs for the AES Greenidge Unit 4 installation and include the costs to design, procure, 

fabricate, deliver, install, and commission the multi-pollutant control system. TPI was computed 

by multiplying TPC by a factor of 1.0235 to account for interest during the construction period. 

The allowance for funds used during construction (AFUDC) of 2.35% was derived using the pretax weighted cost of capital presented in Table 42 and a construction period of 1.67 years, 

consistent with the amount of time required for engineering, procurement, construction, and 

start-up at AES Greenidge Unit 4. The total capital requirement was calculated as the sum of 
 191

the TPI, pre-production cost, and inventory capital. Pre-production (start-up) costs were 

computed as 2% of the TPI plus one month of fixed and variable O&M costs. Inventory capital 

was computed as 0.5% of the TPC. 

The TPC for the multi-pollutant control system at AES Greenidge Unit 4 was $349/kWnet. This is 

about 40% less than it would have cost to retrofit AES Greenidge Unit 4 with conventional SCR 

and wet FGD systems, based on quotes and cost estimates that were obtained prior to the start 

of the project. 

Published cost data also confirm the higher cost of conventional SCR and wet FGD systems 

relative to the Greenidge multi-pollutant control system. For example, Hoskins (2003) reported 

an average installed cost of ~$125/kW ($2002) for SCR retrofits on units with capacities 

between 150 and 200 MW, based on data from four actual installations. Assuming that the 

average unit capacity was at the midpoint of the cited range, this equates to an installed cost of 

~$21,900,000 for a 175 MW unit, in year 2002 dollars. According to the Power Capital Costs 

Index (PCCI) that is published by Cambridge Energy Research Associates (CERA), the capital 

cost of power plant construction projects (excluding nuclear) was about 21.6% higher in 2005 

than it was in 2002 (CERA, 2008). If the SCR retrofit cost reported by Hoskins is escalated by 

this factor and scaled to a 107-MW unit size using the six-tenths rule (i.e., via multiplication by a 

factor of [107/175]0.6), it becomes $19,800,000, or about $185/kW. The total plant cost for the 

hybrid SNCR/SCR system at AES Greenidge Unit 4 was about 38% less than this amount. 

Similarly, Sargent and Lundy (2003) reported an estimated EPC capital cost of $85,539,000, in 

year 2002 dollars, for a wet limestone forced oxidation scrubber retrofit on a 500 MW unit firing 

Appalachian high-sulfur coal. (The reported total plant cost of $77,763,000 was multiplied by a 

factor of 1.1 to convert it to an EPC basis, as recommended by the authors). If this cost is 

escalated to year 2005 dollars and scaled to a 107 MW plant size using the same methodology 

set forth above, it becomes $41,250,000, or about $386/kW. The EPC capital cost for the 

Turbosorp® system at AES Greenidge Unit 4 was about 41% less than this amount. 

11.2 Fixed Operating and Maintenance Costs

Fixed operating and maintenance costs include operating labor costs, maintenance labor and 

materials costs, and administrative and support labor costs. 

As discussed in Section 10.3, plant personnel estimated that, in the absence of any other 

changes at the plant, installation of the multi-pollutant control system would have increased 

operating labor requirements by the equivalent of two full-time operators, or about 11.4 manhours per day. Hence, the estimate presented here assumes 12 hours per day of additional 

operating labor (at $45/hour) to run the multi-pollutant control system. 

Maintenance labor and materials costs from the Operation and Testing Phase of the Greenidge 

Project are not expected to reflect the actual long-term operation of the multi-pollutant control 

system. Certain maintenance costs incurred during the first year-and-a-half of operation at AES 

Greenidge, such as the costs related to the LPA problem, arose as part of the learning process 

associated with this first-of-a-kind installation. These costs, which generally led to design 

improvements, are not expected to be incurred in subsequent years at AES Greenidge or in 

subsequent installations of the multi-pollutant control system. Moreover, excluding these “onetime” costs, first-year maintenance costs are expected to underrepresent the actual 
 192

maintenance costs over the life of the system, because the multi-pollutant control equipment will 

likely require more attention as it ages. Hence, given the uncertainty associated with 

interpreting first-year maintenance cost data, maintenance labor and materials costs were 

estimated as 1.5% of the total plant cost for purposes of this analysis. This is less than the 

general guidance provided by the NETL Quality Guidelines for Energy System Studies (2.2% of 

TPC), consistent with the mechanical simplicity afforded by the multi-pollutant control system 

relative to conventional technologies. The fixed maintenance costs estimated in this way do not 

include the costs associated with change-out of the SCR catalyst and change-out of the 

baghouse bags and cages, which are categorized as variable O&M costs. Forty percent of the 

fixed maintenance costs were assigned to labor, and sixty percent were assigned to materials, 

in accordance with common cost estimating practices. The maintenance labor cost estimated 

by this method was about 20% greater than the cost associated with adding two new 

maintenance personnel (@ $45/hour) per the discussion in Section 10.3. The maintenance 

materials cost was about twice as great as the plant’s estimate of $145,000 for routine 

maintenance materials and services, based on first-year operating experience. Additional 

experience is required before the maintenance costs associated with the multi-pollutant control 

system can be accurately quantified. 

Administrative and support labor costs were estimated as 30% of total operating and 

maintenance labor costs, per the guidance provided by the NETL Quality Guidelines for Energy 

System Studies. 

Table 38 summarizes the fixed O&M costs that were estimated in this way. (Costs were 

converted to a $/MWh basis using the 107 MW net capacity and 80% capacity factor shown in 

Table 36). Overall fixed O&M costs are estimated to be approximately $880,000 per year, or 

about $1.18/MWh. 

Table 38. Estimated fixed operating and maintenance costs for the multi-pollutant control system at AES 

Greenidge Unit 4.

$MM/year $/MWh 

Operating Labor 0.20 0.26 

Maintenance Labor 0.22 0.30 

Maintenance Materials 0.34 0.45 

Administrative & Support Labor 0.13 0.17 

TOTAL 0.88 1.18 

11.3 Variable Operating and Maintenance Costs 

The variable operating and maintenance costs associated with the multi-pollutant control system 

include costs for pebble lime, urea, activated carbon, waste disposal, electricity, water, 

compressed air, replacement catalyst, and replacement baghouse bags and cages. 

Table 39 summarizes the unit prices that were used in the variable O&M cost calculations. 

Costs for reagents (e.g., urea, lime, and powdered activated carbon) reflect approximate market 

prices during start-up of the multi-pollutant control system in early 2007. 
 193

Table 39. Unit prices used in variable O&M cost calculations (as of early 2007). 

Item Unit Price per Unit 

Aqueous urea – 50% w/w gal (delivered) $1.35 

Pebble lime ton (delivered) $115 

Powdered activated carbon lb (delivered) $0.35 

Electricity MWh $40 

Plant service water 1000 gal $0.20 

Compressed air 1000 scf $0.25 

Replacement catalyst layer $380,000 

Baghouse bags bag $80 

Baghouse cages cage $60 

Waste disposal ton $17 

As discussed above, the actual performance of the multi-pollutant control system observed 

during the Operation and Testing Phase of the Greenidge Project was not always consistent 

with its expected performance. To illustrate the effect of these deviations in performance on the 

economics of the multi-pollutant control system, variable O&M costs and levelized costs 

(discussed in the next section) were computed on the basis of both the projected performance 

at the time of design (“design case”) and the actual performance observed during the first yearand-a-half of commercial operation of the system (“actual performance case”). Table 40 

summarizes the differences in the assumptions used for these two cases. 

Table 40. Performance assumptions used to compute the variable O&M costs and levelized costs 

associated with the multi-pollutant control system at AES Greenidge Unit 4. 

Design 

Case 

Actual 

Performance 

Case 

Hybrid NOx Control System

 NOx rate following combustion modifications (lb/mmBtu) 0.25 0.26 

 NOx rate at SCR outlet (lb/mmBtu) 0.10 0.14 

 SNCR normalized stoichiometric ratio 1.35 1.56 

 Catalyst life (years) 3 2 

Circulating Fluidized Bed Dry Scrubber

 SO2 removal efficiency (%) 95 95 

 Ca/S molar ratio 1.65 1.66 

 Pebble lime available CaO (% w/w) 95 89 

 CaO hydration efficiency (%) 99 99 

 Number of baghouse bags and cages 3,168 3,168 

 Baghouse bag and cage life (years) 5 5 

 Solid byproduct production (lb/h, excluding fly ash) 12,972 13,459 

Activated Carbon Injection System

 Mercury removal efficiency (%) 90 98 

 Activated carbon feed rate (lb/mmacf) 3.5 0 

Utilities

 Power consumption (% of net MWe) 1.8 1.8 

 Water consumption (gpm) 139 139 

 Compressed air consumption (scfm) 600 600 
 194

The assumptions for the design case were generally derived from the information presented in 

Section 6 and in drawing No. 100276-SK081706-05 in Appendix B. (The normalized 

stoichiometric ratio of 1.35 and Ca/S molar ratio of 1.65 are consistent with original performance 

expectations but slightly lower than the values represented in drawing No. 100276-SK081706-

05. Hence, the water and byproduct flow rates indicated in the drawing were adjusted in the 

cost estimate so that they correspond to these lower values). 

The assumptions for the actual performance case were derived from the results presented in 

Sections 9 and 10. (In the absence of any compelling evidence suggesting a change in 

performance from the design case, the same value was assumed for both cases). The NOx rate 

following the combustion modifications, NOx rate at the SCR outlet, and SNCR normalized 

stoichiometric ratio represent the average values observed during testing of the hybrid NOx

control system on March 10, March 13, and May 21, 2008. These results, which are 

representative of the long-term performance of the hybrid NOx control system, were 

summarized in Table 15 and discussed in Section 9.3.2. The assumed 2-year catalyst life is 

consistent with the catalyst management plan being developed as of the end of the project, per 

the discussion in Section 10.1. The Ca/S molar ratio of 1.66 is the average value observed 

during the Turbosorp® system tests on October 9-10, 2007, and June 17, 2008, as discussed in 

Section 9.3.7. During those tests, the average coal sulfur content was 4.0 lb SO2/mmBtu, and 

the average SO2 removal efficiency was 95%, consistent with design conditions. The average 

available CaO content of pebble lime samples collected at AES Greenidge between March 2007 

and June 2008 was substantially less than the 95% value assumed in the design case; this 

difference is also reflected in Table 40. (The byproduct flow rates for the design case and the 

actual performance case were estimated using the same equation, which was derived from the 

projected product ash composition in the design case. The larger flow rate for the actual 

performance case reflects the slightly higher Ca/S molar ratio and lower pebble lime available 

CaO content for that case). Finally, the actual performance case assumes 98% Hg removal 

efficiency with no activated carbon injection, per the results presented in Section 9.3.8. 

Table 41 summarizes the estimated variable O&M costs for the multi-pollutant control system at 

AES Greenidge Unit 4. (Annual costs were computed using an 80% capacity factor, per the 

assumptions set forth above). The total estimated variable O&M cost is $6.55 per MWh ($4.91 

million per year) for the design case and $6.77 per MWh ($5.08 million per year) for the actual 

performance case. The $0.22/MWh increase in cost from the design case to the actual 

performance case represents the net effect of increased pebble lime consumption, increased 

waste disposal, increased urea consumption, decreased activated carbon consumption, and 

more frequent catalyst purchases. Pebble lime and waste disposal costs, which both depend 

on the amount of hydrated lime required in the Turbosorp® system, collectively account for 

about 70% of the variable O&M cost associated with the multi-pollutant control system. (Waste 

disposal costs only include the incremental costs associated with the solid byproduct added by 

the multi-pollutant control system, and do not include the costs associated with fly ash disposal). 

Hence, the economics of the multi-pollutant control process are particularly sensitive to changes 

in coal sulfur content, SO2 removal efficiency, and lime quality, which affect hydrated lime 

consumption. The effect of lime quality on process economics is evident in the difference 

between the design case, which assumed 95% available CaO in the pebble lime, and the actual 

performance case, which assumed 89% available CaO. The effects of coal sulfur content and 

SO2 removal efficiency are explored in Section 11.4. 

As stated earlier, the variable O&M costs associated with the multi-pollutant control system are 

somewhat greater than those for conventional stand-alone SCR and wet FGD systems. The 

greater costs arise largely because of less efficient reagent utilization in the multi-pollutant 
 195

control system relative to these conventional technologies. Wet FGD systems typically operate 

with a Ca/S molar ratio close to 1.0 to achieve >95% SO2 removal efficiency (Sarget and Lundy, 

2003) and, therefore, require considerably fewer moles of calcium reagent than the Turbosorp®

system, which uses a Ca/S molar ratio of ~1.7 to achieve 95% removal. Moreover, many wet 

FGD systems use limestone reagent, which is significantly (e.g., more than 50%) less expensive 

per mole of calcium than pebble lime. The gypsum byproduct produced by some wet FGD 

systems also can be sold for a credit, further reducing variable O&M costs. (Wet FGDs have 

greater auxiliary power and water costs than the Turbosorp® system, but these are not sufficient 

to compensate for the difference in reagent costs). Similarly, the hybrid SNCR/SCR system 

consumes more moles of nitrogen (from either urea or ammonia reagent), and achieves less 

NOx reduction, than a conventional SCR system. Whereas the hybrid SNCR/SCR system at 

AES Greenidge has a reagent utilization of 30% (actual performance case) to 45% (design 

case), reagent utilization in conventional SCR systems approaches 100% (Albanese et al., 

1995). For a given reagent (e.g., urea), this equates to greater reagent costs for the hybrid 

SNCR/SCR relative to a conventional SCR. (Many SCR systems use aqueous or anhydrous 

ammonia reagents rather than urea, and reagent costs are therefore application-specific). 

Table 41. Estimated variable operating and maintenance costs for the multipollutant control system at AES Greenidge Unit 4. 

Design 

Case 

Actual Performance 

Case 

$MM/year $/MWh $MM/year $/MWh

Pebble lime 2.62 3.50 2.81 3.75 

Waste disposal 0.77 1.03 0.80 1.07 

Electricity 0.54 0.72 0.54 0.72 

Urea 0.47 0.62 0.57 0.76 

Powdered activated carbon 0.22 0.29 0.00 0.00 

Catalyst 0.13 0.17 0.19 0.25 

Baghouse bags and cages 0.09 0.12 0.09 0.12 

Compressed air 0.06 0.08 0.06 0.08 

Process water 0.01 0.02 0.01 0.02 

TOTAL 4.91 6.55 5.08 6.77 

11.4 Levelized Costs 

The capital costs (TCR) presented in Section 11.1 were annualized using a fixed charge factor 

of 13.05%, which was derived according to the economic assumptions shown in Table 42. The 

financial structure is consistent with the guidance for high-risk projects set forth in the NETL 

Quality Guidelines for Energy System Studies. 

The total levelized cost associated with the multi-pollutant control system was computed by 

combining the levelized capital cost with the annual fixed and variable O&M costs presented in 

Sections 11.2 and 11.3, and dividing the result by the unit’s annual net electric output (again, an 

80% capacity factor was assumed). Table 43 summarizes the derivation of this cost for both the 

design case and the actual performance case. Overall, based on the capital cost to install the 

system at AES Greenidge and the actual performance observed during the Operation and 

Testing Phase of the project, it is estimated that the multi-pollutant control system increased the 
 196

unit’s levelized cost of electricity by about $14.85/MWh. Capital charges and variable O&M 

costs each account for about 46% of this cost, and fixed O&M costs account for the remaining 

8%. 

Table 42. Financial assumptions used for levelized capital cost calculations. 

Constant / current dollars 2005 constant 

Plant life 20 years 

Discount rate (before tax) 7.09% 

 Percent debt 45% 

 Percent preferred stock 10% 

 Percent common stock 45% 

 Nominal cost of debt 9% 

 Nominal cost of preferred stock 8.5% 

 Nominal cost of common stock 12% 

 Inflation rate 3% 

Federal tax rate 35% 

State tax rate 4% 

Property tax rate 2% 

Investment tax credit 0% 

Fixed charge factor 13.05% 

Table 43. Estimated levelized costs for the multi-pollutant control system at AES Greenidge Unit 4. Costs 

are expressed in constant 2005 dollars. 

Design Case Actual Performance Case 

$MM/year $/MWh $MM/year $/MWh 

Annualized capital cost 5.17 6.89 5.17 6.90 

Annual fixed O&M cost 0.88 1.18 0.88 1.18 

Annual variable O&M cost 4.91 6.55 5.08 6.77 

Total levelized cost 10.97 14.62 11.13 14.85 

Levelized costs were also computed separately for the hybrid NOx control system, circulating 

fluidized bed dry scrubbing system, and activated carbon injection system, so that they could be 

expressed in terms of the cost per mass of pollutant removed. Tables 44-46 summarize the 

levelized costs for each of these major subsystems associated with the multi-pollutant control 

process. 

 

Table 44. Estimated levelized costs for the hybrid NOx control system (including the combustion 

modifications) at AES Greenidge Unit 4. Costs are expressed in constant 2005 dollars.

Design Case Actual Performance Case 

$/MWh 

$/ton NOx

removed $/MWh 

$/ton NOx

removed 

Annualized capital cost 2.24 2,251 2.24 2,771 

Annual fixed O&M cost 0.37 372 0.37 457 

Annual variable O&M cost 

 Urea 

 Replacement catalyst 

 Electricity 

 Water 

0.85 

0.62 

0.17 

0.05 

0.00 

853 

626 

170 

55 

3 

1.07 

0.76 

0.25 

0.05 

0.00 

1,322 

937 

313 

67 

4 

Total levelized cost 3.46 3,476 3.68 4,550 

 
 197

Table 45. Estimated levelized costs for the circulating fluidized bed dry scrubbing system at AES 

Greenidge Unit 4. Costs are expressed in constant 2005 dollars.

Design Case Actual Performance Case 

$/MWh 

$/ton SO2

removed $/MWh 

$/ton SO2

removed 

Annualized capital cost 4.54 241 4.54 241 

Annual fixed O&M cost 0.79 42 0.79 42 

Annual variable O&M cost 

 Lime 

 Waste disposal 

 Electricity 

 Baghouse bags and cages 

 Compressed air 

 Water 

5.41 

3.50 

1.03 

0.67 

0.12 

0.08 

0.01 

287 

186 

55 

35 

6 

4 

1 

5.70 

3.75 

1.07 

0.67 

0.12 

0.08 

0.01 

303 

199 

57 

35 

6 

4 

1 

Total levelized cost 10.74 570 11.03 586 

Table 46. Estimated levelized costs for the activated carbon injection system at AES Greenidge Unit 4. 

Costs are expressed in constant 2005 dollars. 

Design Case Actual Performance Casea

$/MWh 

$/lb Hg 

removed $/MWh 

$/lb Hg 

removed 

Annualized capital cost 0.11 1,566 0.11 1,398 

Annual fixed O&M cost 0.02 268 0.02 246 

Annual variable O&M cost 0.29 4,038 0.00 0 

Total levelized cost 0.42 5,872 0.13 1,644 

a

Although activated carbon injection is not needed at AES Greenidge Unit 4, AES must still incur the 

capital and fixed charges for the ACI system that was installed as part of the project. However, based on 

the results from AES Greenidge, future applications of the multi-pollutant control system may not require 

the installation of an activated carbon injection system to achieve >90% Hg removal. Those applications 

would have a total levelized Hg control cost of zero. 

Hence, SO2 control accounts for about three-fourths of the total levelized cost associated with 

the multi-pollutant control system, and NOx control accounts for about one-fourth of the total 

levelized cost. The overall levelized costs (including annualized capital, fixed O&M, and 

variable O&M costs) for NOx and SO2 control are about $3.68/MWh (~$4,550 / ton of NOx

removed) and about $11.03/MWh (~$586 / ton of SO2 removed), respectively, based on the 

actual performance case. The cost for SO2 control also covers SO3, HCl, and improved primary 

particulate matter control, which are co-benefits of the Turbosorp® system and which add no 

incremental cost. As discussed in Section 5, AES Greenidge is a merchant plant that 

dispatches when its variable cost of producing electricity is less than the market price of 

electricity. The NOx and SO2 control costs that figure into the economic dispatch calculations for 

Unit 4 are the costs for urea, lime, and waste disposal. Hence, the hybrid NOx control system 

adds about $0.76/MWh to the unit’s dispatch cost, and the circulating fluidized bed dry 

scrubbing system adds about $4.82/MWh to the dispatch cost. 

As shown in Table 44, the hybrid NOx control system at AES Greenidge is now estimated to 

cost about $0.22/MWh more to operate than expected at the time of design. About 64% of this 

cost increase is attributable to the higher-than-anticipated urea consumption (NSR) observed 

during long-term operation, and the remaining 36% is attributable to the more frequent catalyst 

replacements that will likely be required because of plugging and erosion. Whereas the 

increase in NOx control costs is relatively modest (6%) when expressed on a megawatt-hour 
 198

basis, it is much more dramatic when expressed per ton of NOx removed. As discussed in 

Section 9.3.1 and shown in Table 40, in addition to requiring more urea than expected, the 

hybrid NOx control system fell short of its targeted NOx removal efficiency. As a result, the 

capital costs and fixed and variable O&M costs are spread out over fewer tons of NOx, inflating 

the NOx removal cost. As shown in Table 44, the cost per ton of NOx removed is about 31% 

greater for the actual performance case than for the design case. 

The cost per ton of NOx removed becomes even larger when the NOx removal contributed by 

the combustion modifications is excluded from the calculation. For purposes of computing the 

NOx control costs in Table 44, the NOx removal was taken as the total removal contributed by 

both the combustion modifications and the hybrid SNCR/SCR system (i.e., such that the total 

NOx reduction was 0.20 lb/mmBtu for the design case and 0.16 lb/mmBtu for the actual 

performance case). This was necessary in order to derive the total levelized cost (including 

capital and fixed costs) associated with the overall NOx control system. However, the variable 

O&M costs shown in Table 44 are associated solely with the hybrid SNCR/SCR system and not 

with the combustion modifications. Hence, these costs might be more appropriately expressed 

on the basis of the NOx reduction contributed by only that system (i.e., 0.15 lb/mmBtu for the 

design case and 0.12 lb/mmBtu for the actual performance case). When the NOx reduction 

arising from the combustion modifications is excluded, the total variable O&M cost associated 

with the hybrid SNCR/SCR system is $1,136 / ton of NOx removed for the design case and 

$1,702 / ton of NOx removed for the actual performance case. The cost for urea, which figures 

into the unit’s dispatch calculations, is $834 / ton of NOx removed for the design case and 

$1,207 / ton of NOx removed for the actual performance case. 

Unlike the hybrid NOx control system, the circulating fluidized bed dry scrubbing system met the 

performance expectations for both SO2 removal efficiency and reagent utilization. Nevertheless, 

the estimated cost to operate the scrubber increased by about 3% as a result of experience 

gained during the Operation and Testing Phase of the project. This increase arose because the 

average available CaO content of the pebble lime delivered to AES Greenidge (89%) was less 

than the available CaO content assumed in the design case (95%). As a result of the poorer 

lime quality, AES Greenidge had to purchase about 7% more pebble lime than expected in 

order to obtain a given amount of available CaO. 

As discussed in Section 11.3, in addition to being dependent on lime quality, the variable O&M 

costs for the Turbosorp® system are particularly sensitive to changes in the coal sulfur content 

or required SO2 removal efficiency. Both of these factors affect the amount of hydrated lime 

required in the circulating fluidized bed dry scrubber and the amount of byproduct generated by 

the scrubber. 

The multi-pollutant control system at AES Greenidge Unit 4 was designed for coals containing 

2-4% sulfur (~ 3-6 lb SO2/mmBtu); hence, variations in coal sulfur content are anticipated during 

operation of the system. Figure 96 illustrates the effect of these changes on SO2 control costs, 

assuming that SO2 removal efficiency is held constant at 95%. (When calculating these SO2

control costs, the pebble lime available CaO content was assumed to be 89%). The total 

levelized cost (including capital and operating costs) and the cost for lime and waste disposal 

are each plotted in order to show the effects on overall control costs and dispatch costs, 

respectively. As the coal sulfur content increases, more SO2 must be removed per unit of 

electric output, and SO2 control costs increase accordingly on a $/MWh basis. (It is important to 

recognize that, with respect to the unit’s overall variable operating cost, this increase in SO2

control costs may be offset by a decrease in fuel costs, because higher-sulfur coals tend to be 

less expensive than lower-sulfur coals). This effect is eliminated if costs are levelized based on 
 199

the mass of SO2 removed rather than the net electric output from the unit. When expressed on 

this basis, the total SO2 control cost decreases with increasing coal sulfur content, because the 

capital costs and fixed O&M costs are spread over a greater number of tons of SO2. 

$0

$100

$200

$300

$400

$500

$600

$700

$800

$900

$1,000

1.50 2.50 3.50 4.50 5.50 6.50

Coal SO2 (lb/mmBtu)

$/ton SO2 removed

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

$/MWh

Total Levelized Cost ($/ton)

Lime + Waste Disposal ($/ton)

Total Levelized Cost ($/MWh)

Lime + Waste Disposal ($/MWh)

Figure 96. Projected effect of coal sulfur content on SO2 control costs for 95% SO2 removal efficiency. 

As discussed in Section 9.3.7 and shown in Figure 72, parametric tests were conducted in June 

2008 to determine the effect of variations in SO2 removal efficiency on the required Ca/S molar 

ratio in the Turbosorp® process. The data collected during these tests were used to derive the 

sensitivity of SO2 control costs to changes in SO2 removal efficiency. Results are plotted in 

Figure 97, using the same four cost metrics shown in Figure 96. All of the costs in Figure 97 are 

for a 3.6 lb SO2/mmBtu coal, consistent with the coal used during the June tests. As shown in 

the figure, all four measures of cost increased with increasing SO2 removal efficiency. When 

expressed on a $/MWh basis, the cost for lime and waste disposal increased by 43% as SO2

removal increased from 92% to 98%, and the total levelized cost for SO2 control increased by 

16% over the same increment of SO2 removal efficiencies. Costs rose more slowly when 

expressed per ton of SO2 removed, owing to the increase in the divisor with increasing SO2

removal efficiency. The June 2008 tests also examined the effect of the scrubber operating 

temperature on the required Ca/S ratio. Based on the test results, for 95% SO2 removal 

efficiency with a 3.6 lb SO2/mmBtu coal, raising the operating temperature by 5 °F (e.g., to 

reduce the risk of condensation) causes the lime and waste disposal costs to increase by 

$0.47/MWh ($28/ton of SO2 removed), or about 11%. 

All of the costs presented thus far for the Turbosorp® system and the overall multi-pollutant 

control system have assumed that AES Greenidge must pay $17/ton to landfill the solid 

byproduct generated in the circulating fluidized bed dry scrubber. However, as discussed in 
 200

Sections 6.3.6 and 10.4, process economics would improve if an opportunity for beneficial reuse 

of this byproduct could be identified. Using the actual performance case as an example (Tables 

41, 43, and 44), if waste disposal costs were eliminated (e.g., by providing the scrubber 

byproduct for beneficial reuse at zero net cost), then the costs associated with the multipollutant control system, including its contribution to the unit’s dispatch cost, would decrease by 

$57 / ton of SO2 removed ($1.07/MWh). 

$0

$100

$200

$300

$400

$500

$600

$700

90% 91% 92% 93% 94% 95% 96% 97% 98% 99% 100%

SO2 Removal Efficiency

$/ton SO2 removed

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$/MWh

Total Levelized Cost ($/ton)

Lime + Waste Disposal ($/ton)

Total Levelized Cost ($/MWh)

Lime + Waste Disposal ($/MWh)

Figure 97. Effect of SO2 removal efficiency on SO2 control costs for a 3.6 lb SO2/mmBtu coal. Costs 

were derived from the results of parametric testing of the Turbosorp®

 system on June 16-18, 2008. 

Finally, as shown in Table 46, it was originally anticipated that the Hg control costs associated 

with the multi-pollutant control system could be as great as $0.42/MWh, or $5,872 / lb of Hg 

removed, owing to the potential need for up to 3.5 lb/mmacf of activated carbon injection in 

order to achieve 90% Hg removal efficiency. However, the tests conducted at AES Greenidge 

in March 2007 through June 2008 proved that >90% Hg removal efficiency can be achieved 

consistently without any activated carbon injection. Hence, there are no variable O&M costs 

associated with Hg control at AES Greenidge (i.e., Hg control is accomplished as a co-benefit of 

the other components of the multi-pollutant control system), resulting in a savings of 

$0.29/MWh. Although it is not used, AES Greenidge must continue to incur the capital and fixed 

costs associated with the activated carbon injection system that was installed as part of the 

project, which amount to $0.13/MWh, or $1,644/lb of Hg removed. However, these costs can 

also be avoided in future installations that do not require activated carbon injection. 
 201

In short, installation of the multi-pollutant control system has enabled AES Greenidge Unit 4 to 

satisfy its air emissions requirements while remaining profitable, thereby extending the life of the 

unit. This is indicative of the economic viability of the system. 

12. Commercialization 

The Greenidge Multi-Pollutant Control Project, as a major demonstration project under the 

Power Plant Improvement Initiative, was conducted to resolve any remaining technical and 

economic uncertainties regarding the multi-pollutant control technology so as to enable and 

promote its commercial deployment. Babcock Power Environmental Inc. is responsible for 

marketing the technology. 

The Greenidge Project has already succeeded in spurring commercialization of the Turbosorp®

technology. As of the end of the project in October 2008, three additional projects were 

underway to retrofit Turbosorp® circulating fluidized bed dry scrubbers to coal-fired EGUs in the 

United States. Key features of these additional projects are summarized in Table 47. (Key 

features of the AES Greenidge application are also included for comparison). The performance 

specifications for all three projects resemble those at AES Greenidge. All are designed to 

achieve SO2 removal efficiencies of 95% or more, with fuel sulfur contents ranging from 2.3 to 

4.6 lb SO2/mmBtu. 

Table 47. Turbosorp® projects at coal-fired electric generating units in the United States, as of October 

2008. 

AES 

Greenidge 4 

AES 

Westover 8 

GRU 

Deerhaven 2 

FirstLight 

Mt. Tom 1 

Unit Capacity 

MWe

107 (net) 84 (net) 248 (gross) 155 (gross) 

Turbosorp®

Start-Up Spring 2007 Fall 2008 Spring 2009 Fall 2009 

Fuel Bituminous 

Pulverized Coal 

Bituminous 

Pulverized Coal 

Bituminous 

Pulverized Coal 

Bituminous 

Pulverized Coal 

Inlet SO2 

lb/mmBtu 4.0 3.4 2.3-3.9 2.7-4.6 

Outlet SO2

lb/mmBtu ≤0.2 ≤0.17 ≤0.10 0.14-0.23 

SO2 Removal 

% ≥95 ≥95 ≥95.6-97.4 ≥95 

Hydrator 1 x 100% No 2 x 100% No 

Existing ESP Cold Side 

Abandon 

Cold Side 

Abandon 

Hot Side 

Retain 

Cold Side 

Retain 

New Baghouse Yes Yes Yes Yes 

Activated Carbon Injection 

System Yes No Provisions Yes 

SCR Compact/Hybrid Yes Yes Existing 
 202

The projects at AES Westover Unit 8, GRU Deerhaven Unit 2, and FirstLight Mt. Tom Unit 1 

include several noteworthy variations in the application of the Turbosorp® technology, illustrating 

some of the design options available to candidate units. 

As discussed earlier, the particulate control device is an integral part of the Turbosorp® process. 

Although it is possible to install a Turbosorp® system with an ESP to remove the reaction 

products and spent sorbent from the flue gas, baghouses are generally preferred because they 

provide for deeper emission reductions. All of the projects in Table 47 include a new baghouse 

as part of the Turbosorp® system. The existing particulate control device can be either retired 

(as it was at AES Greenidge) or retained (because of economic and/or operating 

considerations). At AES Westover Unit 8, as at AES Greenidge Unit 4, the existing cold-side 

ESP was abandoned, with fly ash being collected along with the spent sorbent and reaction 

products in the new baghouse. At these sites, both the booster fan and the existing ID fans are 

located downstream of the Turbosorp® reactor and baghouse. The hot-side ESP at GRU 

Deerhaven Unit 2 will be retained, allowing the new SCR reactor and the existing air heater to 

operate with low dust loading. The cold-side ESP at Mt. Tom will also be retained. Retaining 

the ESP allows the fly ash to be disposed or sold separately from the scrubber product, if 

desired. However, the ESP can be operated at reduced power, because the baghouse 

provides supplemental particulate emission control. At Deerhaven, the Turbosorp® system will 

be located downstream of the unit’s two existing ID fans, but upstream of two new booster fans 

that are being installed as part of the project. At Mt. Tom, the Turbosorp® system will be 

installed upstream of the two existing ID fans, and a single new booster fan will be installed 

ahead of the Turbosorp® absorber vessel. To enable low-load operation of the Turbosorp®

system, both of these installations will include a flue gas recirculation stream taken downstream 

of the final fan; the recycled flue gas will be introduced downstream of the ID fans (but upstream 

of the Turbosorp® absorber vessel) at Deerhaven, and upstream of the booster fan at Mt. Tom. 

The hydrated lime required by the Turbosorp® system can be produced from pebble lime in an 

onsite hydrator, as it is at AES Greenidge, or it can be purchased and delivered to site for direct 

use in the process. The Turbosorp® installations at AES Westover and FirstLight Mt. Tom do 

not include hydrators; both of these applications are designed to use hydrated lime that is 

delivered by truck. At GRU Deerhaven, two complete hydration trains will provide fully 

redundant, on-site hydration capacity, while allowing for delivery of both pebble lime and 

hydrated lime. The lime hydration system specified for the Deerhaven project includes an 

improved hydrator design that eliminates the need for post-hydrator milling and classification. 

This design is expected to avoid many of the problems discussed in Section 10.2.2.1, likely 

resulting in a significant reduction in maintenance requirements relative to those at AES 

Greenidge. Each hydration train will also require appreciably less equipment than the lime 

hydration system that was installed as part of the Greenidge Project. 

The Turbosorp® system at Mt. Tom Unit 1 will include an activated carbon injection system; the 

system at Deerhaven Unit 2 includes provisions for an ACI system, and the system at Westover 

Unit 8 does not include an ACI system. The decision to include or exclude activated carbon 

injection capabilities for a given installation depends upon the required amount of Hg reduction 

and the amount of Hg removal that can be reasonably expected as a co-benefit of the 

Turbosorp® system and any other pollution controls that are installed. As discussed in Section 

9.3.8, the Turbosorp® system at AES Greenidge Unit 4 was able to achieve 98% Hg removal 

without any activated carbon injection. However, it is uncertain whether this high level of 

removal will be observed for units that produce fly ash with low unburned carbon content, fire 

low-chlorine coal, or capture fly ash upstream of the Turbosorp® process. 
 203

None of the three additional announced deployments of the Turbosorp® system are being 

installed in combination with the hybrid SNCR/SCR system that was included at AES 

Greenidge. However, all of these deployments will include a conventional SCR upstream of the 

Turbosorp® system. Two of the projects include SCR as part of the retrofit; BPEI recently 

installed an SCR system at Mt. Tom Unit 1, and this SCR will continue in service. 

The Turbosorp® projects at Westover, Deerhaven, and Mt. Tom are consistent with the 

population of smaller, existing coal-fired EGUs targeted by the Greenidge Project. As shown in 

Section 2.2, there are a number of additional, similar units that remain candidates for the 

demonstration technology. Babcock Power Environmental continues to market the technology 

to these units. In addition to conventional applications involving mid- or high-sulfur coal, such 

as those presented in Table 47, BPEI is pursuing application of the Turbosorp® process to lowsulfur coals, to opportunity fuels such as petroleum coke and biomass, and as a polishing 

scrubber to achieve very low emissions from fluidized bed boilers. The successful 

commercialization of the demonstration technology is the greatest indicator of the success of 

the Greenidge Project. 

13. Conclusions and Recommendations

As part of the Greenidge Project, an integrated multi-pollutant control system including a 

NOxOUT CASCADE® hybrid SNCR/SCR system and a Turbosorp® circulating fluidized bed dry 

scrubbing system was successfully installed, tested, and operated commercially for more than a 

year-and-a-half at AES Greenidge Unit 4. The project represented the first application in which 

these technologies were combined to form an integrated multi-pollutant control system, as well 

as the first application of either of these technologies to a unit firing >2%-sulfur eastern U.S. 

bituminous coal. It also included more ambitious performance targets for both technologies 

than any prior application. The testing results and experience gained from the Greenidge 

Project resolved uncertainties related to the technical and economic performance of the multipollutant control system, helping to establish its commercial viability. Major conclusions of the 

project are as follows: 

• The multi-pollutant control system achieved the performance target of ≥95% SO2

removal efficiency during both short-term and long-term testing while AES Greenidge 

Unit 4 fired eastern U.S. bituminous coals containing >2% sulfur. The average SO2

removal efficiency observed during 14 months of commercial operation (August 2007 – 

September 2008) was 96.3%. The inlet SO2 rate averaged 3.62 lb/mmBtu during this 

period, and SO2 removal efficiencies greater than 95% were achieved for coals 

containing up to 3.3% sulfur (4.8 lb SO2/mmBtu). Performance tests showed that the 

system required a calcium-to-sulfur molar ratio of 1.6-1.7 to achieve 95% SO2 removal 

efficiency under design conditions; however, the required Ca/S ratio is sensitive to the 

SO2 removal efficiency and proximity to the adiabatic saturation temperature in the 

absorber vessel. 

• The multi-pollutant control system achieved the performance target of ≥90% Hg removal 

efficiency (coal-to-stack) during both short-term and long-term testing. No activated 

carbon injection was required to achieve this removal efficiency. The average coal-tostack Hg removal efficiency measured during 29 tests without activated carbon injection 

between March 2007 and June 2008 was 98%. This represents a 97% reduction from 

the baseline removal efficiency that had been achieved by the unit’s ESP prior to the 
 204

project. Hg removal efficiencies of >90% were observed irrespective of plant operating 

conditions. The high mercury removal efficiency may be attributable in part to the high 

unburned carbon content of the fly ash at AES Greenidge Unit 4; it is unclear whether 

activated carbon would be required for units that produce fly ash containing less 

unburned carbon. Tests conducted around the single-layer SCR suggested that it 

increases the proportion of mercury that is present in oxidized form; this may contribute 

to better capture efficiency in the downstream scrubber. 

• The multi-pollutant control system achieved the performance target of ≥95% SO3 and 

HCl removal efficiency during both short-term and long-term testing. The average SO3

removal efficiency observed during 42 tests between May 2007 and June 2008 was 

95.3%, and the average HCl removal efficiency observed during 30 tests between March 

2007 and June 2008 was 96.7%. Routine variations in process conditions (e.g., fuel, 

load, scrubber operating conditions) did not have a discernible effect on the SO3 and HCl 

removal performance of the system. Attainment of the performance target of ≥95% HF 

removal efficiency could not be determined, because HF concentrations measured at the 

Turbosorp® scrubber inlet and stack were too low to demonstrate 95% removal. 

• Primary (non-condensable) particulate matter emissions from AES Greenidge Unit 4 

were significantly reduced by replacing the unit’s existing ESP with the Turbosorp®

system, which includes a new baghouse. The average PM emission rate measured 

during 58 tests between March 2007 and June 2008, following the installation of the 

multi-pollutant control system, was <0.001 lb/mmBtu. This represents a more-than 98% 

reduction over the baseline full-load PM emission rate of 0.063 lb/mmBtu measured in 

November 2004, prior to the installation of the system. The improvement in PM 

emissions occurred in spite of the substantial increase in flue gas particulate loading 

brought about by the hydrated lime, reaction products, and high solids recycle rate in the 

Turbosorp® system. 

• The multi-pollutant control system achieved the performance target for high-load NOx

emissions of ≤0.10 lb/mmBtu during short-term (guarantee) testing, but it did not meet 

this goal during long-term operation. The average high-load NOx emission rate 

observed during 14 months of commercial operation (August 2007 – September 2008) 

was 0.14 lb/mmBtu. Urea consumption was also greater during routine, long-term 

operation than it was during guarantee testing. The increase in NOx emissions between 

the guarantee tests and the long-term performance evaluation period occurred because 

AES Greenidge had to reduce the aggressiveness of low-NOx firing in order to attain 

suitable combustion characteristics for routine operation. This caused the NOx

emissions from the combustion zone to exceed the target of 0.25 lb/mmBtu, and it 

caused boiler conditions to deviate from the design basis for the SNCR system, likely 

resulting in less-than-optimal performance of that system. Nevertheless, installation of 

the combustion modifications and hybrid SNCR/SCR system reduced NOx emissions 

from AES Greenidge Unit 4 by ~25-50% at low generator loads and by ~50-60% at mid 

and high generator loads. Overall, NOx emissions were reduced by about 52% relative 

to the pre-project baseline. The success of the hybrid NOx control system in achieving 

NOx emissions of ≤0.10 lb/mmBtu during guarantee testing suggests that future 

installations may be able to achieve this level of performance if they incorporate 

appropriate design improvements. 
 205

• Biomass (waste wood) co-firing did not have any discernible effect on the performance 

of the multi-pollutant control system. However, the extent (<5% of total heat input) and 

duration of co-firing were too limited to permit a thorough evaluation of its impact on the 

system. 

• Operation of the multi-pollutant control system was hindered by the accumulation of 

large particle ash in the in-duct SCR catalyst, but the severity of the problem was 

reduced by the installation of a large particle ash removal system. Numerous outages 

and derates were required during the first year of operation of the multi-pollutant control 

system to clean LPA from the SCR reactor. An LPA removal system, including a sloped 

screen, soot blowers, and vacuum ports, was installed in May 2007 and modified in 

September 2007 and May 2008 to mitigate the problem. The development of an 

effective LPA removal system for the in-duct SCR at AES Greenidge Unit 4 was very 

challenging because of space constraints, the vertically downward flow through the SCR 

reactor, and the lack of any ductwork bends or hoppers upstream of the reactor. The 

LPA removal system has significantly reduced the frequency of outages and derates, 

although additional operating experience is needed to confirm its effectiveness. The 

September 2007 outage also included the installation of a rake soot blower above the 

SCR catalyst; this has helped to reduce the rate of catalyst plugging. 

• Ammonia slip from the hybrid SNCR/SCR system was generally greater than expected 

during the first year-and-a-half of operation. The system was designed to limit the 

ammonia concentration at the SCR outlet to ≤2 ppmvd @ 3% O2. Ammonia slip was 

demonstrated at 2 ppmvd during guarantee testing in June 2007, while the hybrid NOx

control system achieved a NOx emission rate of 0.10 lb/mmBtu. This level of 

performance was not sustained during long-term operation, however. Ammonia 

concentrations ranged from 1.6 to 7.3 ppmvd (mean = 4.6 ppmvd) over the course of 26 

ammonia slip measurements that were performed at intermediate or high loads between 

October 2007 and June 2008. The greater-than-expected ammonia slip likely resulted 

from several factors, including stratification of the flue gas flow and/or composition at the 

inlet to the SCR reactor and decreased SCR performance arising from LPA 

accumulation in the catalyst. The ammonia slip has not significantly affected plant 

operations, however. Air heater basket modifications implemented outside of the scope 

of the DOE project appear to have been effective in reducing the impact of ammonium 

bisulfate fouling on air heater performance. Also, SO2-to-SO3 conversion across the 

SCR catalyst was less than 1% (based on 9 tests performed between October 2007 and 

June 2008), helping to limit the driving force for ammonium bisulfate formation. 

• The retrofit difficulty associated with the installation of the multi-pollutant control system 

at AES Greenidge Unit 4 was low. The multi-pollutant control system required a footprint 

of only ~0.4 acre and was able to be integrated with the unit during a seven-week tie-in 

outage. No major problems were encountered during construction of the system. 

• The multi-pollutant control system affords lower capital costs in exchange for somewhat 

greater variable O&M costs relative to conventional technologies that are capable of 

achieving deep reductions in NOx and SO2. The EPC capital cost ($2005) for the multipollutant control system at AES Greenidge Unit 4 (including the combustion 

modifications and LPA screen, which were installed outside of the DOE scope) was 

~$349/kWnet, which is about 40% less than the estimated cost to retrofit the unit with 

conventional SCR and wet FGD systems. Fixed and variable O&M costs for the multi-
 206

pollutant control system total ~$7.95/MWh, and the costs for urea, lime, and waste 

disposal, which figure into the unit’s dispatch calculations, are ~$5.58/MWh. The tradeoff between capital costs and variable O&M costs is consistent with the needs of many 

operators of older, smaller units. Mercury control, acid gas control, and improved 

primary particulate matter control are co-benefits of the NOx and SO2 control systems 

and add no incremental cost. 

• Operation and maintenance of the multi-pollutant control system were handled by 

existing AES Greenidge plant personnel. During periods of routine operation, AES is 

able to run Unit 4, including the multi-pollutant control system, with 3-4 operators per 

shift, as was the case prior to the project. Apart from the LPA problem, most of the 

maintenance requirements during the first year-and-a-half of operation involved the lime 

hydration system and the ash disposal and recirculation system. These were usually 

resolved without impacting operation of the Turbosorp® system, and actions have been 

taken to minimize their recurrence. The multi-pollutant control system has, however, 

caused the loss of 8 MW of turndown capability for Unit 4, owing to problems with 

automatic control of the flue gas recirculation system in the Turbosorp® process. Firstyear maintenance requirements are expected to be less than maintenance requirements 

in subsequent years; hence, the maintenance requirements associated with the system 

cannot be fully quantified on the basis of data collected during this project. 

• No major problems were encountered with byproduct disposal. The only significant 

byproduct from the multi-pollutant control system is the product ash from the Turbosorp®

process; approximately 3.4 tons of scrubber byproduct (excluding fly ash) are produced 

for each ton of SO2 removed. AES Greenidge generally disposes of the product ash at a 

landfill adjacent to the plant site. Process economics can be improved if a beneficial 

reuse for the product ash can be identified. During the project period, 3,500 tons of 

product ash were sent for use as fill material in a local construction project; however, 

transportation costs severely limit opportunities for beneficial reuse of the ash. The 

mercury captured by the multi-pollutant control system resides in the product ash; tests 

confirmed that very little (0.1%) of this Hg is leachable. Ammonia slip from the hybrid 

SNCR/SCR system has not affected byproduct handling. Liquid discharges from the 

multi-pollutant control system consist solely of 19 gpm (maximum) of once-through 

cooling water. 

• The commercial viability of the multi-pollutant control system was demonstrated at AES 

Greenidge Unit 4. The system, which will remain in service after the conclusion of the 

project, has enabled the unit to satisfy its permit requirements while continuing to 

operate profitably. Performance has been established over more than a year-and-a-half 

of routine operation. As a result of the success at AES Greenidge Unit 4, three 

additional deployments of the Turbosorp® technology had been announced by the end of 

the project. 

Lessons learned during the Greenidge Multi-Pollutant Control Project can be used to improve 

upon the design of the multi-pollutant control system and provide for greater ease of operation 

in future installations. The project team offers the following recommendations based upon the 

experience acquired at AES Greenidge: 

1. The hybrid NOx control system should be designed on the basis of less optimistic 

assumptions about the combustion system (i.e., without assuming overly aggressive 
 207

low-NOx firing), so that the SNCR system can be designed to operate optimally under 

these realistic conditions. 

2. Large particle ash should be considered as part of the SCR reactor design, even if it is 

only produced in very small amounts. A large particle ash removal system should be 

installed upstream of the SCR reactor unless it is known with certainty that the unit will 

not generate LPA. The design of the LPA removal system will vary by unit. However, if 

it is integrated upfront as part of the overall design of the hybrid NOx control system, 

then it may be able to incorporate desirable features (e.g., one-piece screen design, 

hoppers, ductwork bends, etc.) that would be difficult or impossible to implement after 

the SCR reactor has been installed. LPA should also be considered when selecting the 

catalyst for the SCR reactor. Important considerations include the geometry of the 

catalyst (i.e., pitch, honeycomb vs. plate vs. corrugated design), which might affect its 

susceptibility to plugging, and the durability (resistance to erosion) of the catalyst. 

3. A rake soot blower should be installed in addition to, or in place of, the sonic horns in 

order to prevent fly ash accumulation in the SCR catalyst. The placement of the sonic 

horns, which are located above the static mixers at AES Greenidge Unit 4, should be 

reconsidered in order to improve their effectiveness. 

4. Plant personnel should consider implementing a catalyst management plan in 

conjunction with the installation of the multi-pollutant control system in order to maximize 

the useful operating life of the catalyst and minimize costs associated with catalyst 

replacement or rejuvenation. To reduce the risk of prolonged downtime, it is 

recommended that a spare catalyst layer always be kept on site in the event that the 

catalyst must be replaced because of plugging or damage (e.g., from LPA accumulation 

or an economizer tube leak). 

5. The design should provide a system for removing ash from the hopper at the inlet to the 

Turbosorp® absorber vessel, thereby eliminating the need to hire a vacuum truck for this 

purpose. 

6. For plants located in cold climates, consideration might be given to enclosing the 

Turbosorp® and lime hydration structures in order to reduce the risk of weather-induced 

plugging or freezing of equipment, and to facilitate wintertime maintenance. If exposure 

to cold temperatures is anticipated, the ash disposal chutes should be heated to prevent 

condensation and plugging. 

7. Minor improvements should be made to the Turbosorp® structure to facilitate 

maintenance. Specific recommendations include the addition of cable ports to the roof 

of the absorber vessel for maintenance access and the addition of a hoist rail to aid in 

change-out of the water injection lance. 

8. If possible, the design should provide for change-out of the Turbosorp® water injection 

lance without interrupting the supply of water to the absorber vessel. This would 

eliminate the transient spikes in SO2 emissions that occur when the lance is changed, 

and it might be particularly important for units with permit limits that are based on short 

averaging periods. 

9. The Turbosorp® system should include some means for continuously estimating the 

approach to adiabatic saturation in the absorber vessel, so that the operating 
 208

temperature can be adjusted to maximize lime utilization while avoiding the risk of 

condensation. 

10. The design of the lime hydration system should be modified to eliminate or improve the 

milling and classification system. (As discussed in Section 12, an improved hydrator 

design that avoids post-hydrator milling and classification will be implemented at GRU 

Deerhaven Unit 2). Further tests should be conducted to establish the effect of the 

hydrated lime particle size on the performance of the Turbosorp® system. 

11. The design should provide sufficient onsite hydrated lime storage capacity (~1-2 days) to 

allow for offline maintenance of the lime hydration system without upsetting the 

Turbosorp® process. 

12. The relatively large compressed air demand arising from the baghouse should be 

considered as part of the initial design, and the plant’s compressed air capacity should 

be increased as necessary to accommodate this demand. 

13. The baghouse compartment isolation valves should be exercised routinely (when the 

unit is operating at reduced load) in order to maintain their operability and retain the 

ability to perform online maintenance on the baghouse. 

14. If possible, the flue gas recirculation duct should be tied into the ID fan discharge rather 

than the booster fan discharge to provide for improved control of the flue gas 

recirculation system and to avoid the potential for reverse flow through the system (i.e., 

bypassing the Turbosorp® scrubber and baghouse). This will help to ensure that the 

unit’s full original turndown capability is retained. In some cases, it might make sense to 

replace the existing ID fans with larger fans, rather than installing a separate booster fan, 

in order to simplify the system. 

15. Additional testing should be conducted to elucidate the fate of HF in the system. 

16. Additional testing should be conducted to determine the Hg removal performance of the 

multi-pollutant control system (and the amount of activated carbon injection required, if 

any) for units that produce fly ash with low unburned carbon content, fire low-chlorine 

coal, or capture fly ash upstream of the Turbosorp® process. 

 

 
 209

REFERENCES 

Albanese, V.; Boyle, J.; Huhmann, A.; Wallace, A. Evaluation of Hybrid SNCR/SCR for NOx

Abatement on a Utility Boiler; Presented at Power-Gen ’95, Anaheim, CA, December 1995. 

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PROJECT BIBLIOGRAPHY 

1. Connell, D.P.; Roll, D.J.; Rady, W.B.; Abrams, R.F. Design of an Integrated Multi-Pollutant 

Control System for Reducing Emissions of SO2, NOx, Hg, Acid Gases, and Particulate 

Matter from Smaller Coal-Fired Power Plants; In Proceedings of the 2006 American 

Filtration and Separations Society Conference on Separations Processes for the Power 

Generation Industry, Pittsburgh, PA, October 16-18, 2006. 

2. Connell, D.P.; Roll, D.J.; Rady, W.B.; Abrams, R.F.; Huber, W.P. Initial Cost and 

Performance Results from the Greenidge Multi-Pollutant Control Project; In Proceedings of 

the 2007 Electric Power Conference & Exhibition, Rosemont, IL, May 1-3, 2007. 

3. Connell, D.P.; Roll, D.J.; Rady, W.B.; Abrams, R.F.; Huber, W.P. The Greenidge MultiPollutant Control Project: Key Technical and Economic Features of a New Approach for 

Reducing Emissions from Smaller Coal-Fired Units; In Proceedings of the Air & Waste 

Management Association’s 100th Annual Conference & Exhibition, Pittsburgh, PA, June 26-

29, 2007. 

4. Connell, D.P.; Locke, J.E.; Roll, D.J.; Rady, W.B.; Huber, W.P. Preliminary Performance 

Testing Results from the Greenidge Multi-Pollutant Control Project; In Proceedings of 

COAL-GEN, Milwaukee, WI, August 1-3, 2007. 

5. Roll, D.J.; Abrams, R.F.; Connell, D.P. Follow-on Turbosorp Testing Results from the 

Greenidge Multi-Pollutant Control Project; In Proceedings of POWER-GEN International, 

New Orleans, LA, December 11-13, 2007. 

6. Connell, D.P.; Locke, J.E.; Roll, D.J. Mercury Capture in a Circulating Fluidized Bed Dry 

Scrubber at AES Greenidge Unit 4; In Proceedings of the DOE-NETL Mercury Control 

Technology Conference, Pittsburgh, PA, December 11-13, 2007. 

7. Connell, D.P.; Locke, J.E.; Roll, D.J.; Huber, W.P.; Abrams, R.F. Mercury Removal 

Performance of the Greenidge Multi-Pollutant Control System; In Proceedings of the EUEC 

Energy & Environment Conference, Tucson, AZ, January 28-30, 2008. 

8. Connell, D.P.; Roll, D.J.; Huber, W.P. Multi-Pollutant Control and the Smaller Unit: 

Greenidge One Year On; Modern Power Systems 2008, 28(5), 18-23. 

9. Roll, D.J.; Connell, D.P.; Huber W.P. Results from the First Year of Operation of a 

Circulating Fluidized Bed Dry Scrubber with High-Sulfur Coal at AES Greenidge Unit 4; In 

Proceedings of the 2008 Electric Power Conference & Exhibition, Baltimore, MD, May 6-8, 

2008. 

10. Connell, D.P.; Roll, D.J.; Huber, W.P. First-Year Operating Experience from the Greenidge 

Multi-Pollutant Control Project; In Proceedings of the 33rd International Technical 

Conference on Coal Utilization and Fuel Systems, Clearwater, FL, June 1-5, 2008. 
 213

11. Connell, D.P.; Locke, J.E.; Roll, D.J.; Abrams, R.F.; Beittel, R.; Huber, W.P. The Greenidge 

Multi-Pollutant Control Project: Performance and Cost Results from the First Year of 

Operation; In Proceedings of the Power Plant Air Pollutant Control “Mega” Symposium, 

Baltimore, MD, August 25-28, 2008. 

12. Connell, D.P.; Roll, D.J.; Abrams, R.F.; Beittel, R.; Huber, W.P. The Greenidge MultiPollutant Control Project: Demonstration Results and Deployment of Innovative Technology 

for Reducing Emissions from Smaller Coal-Fired Power Plants; In Proceedings of the 25th

Annual International Pittsburgh Coal Conference, Pittsburgh, PA, September 29-October 2, 

2008. 

13. Connell, D.P.; Roll, D.J.; Huber, W.P. The Greenidge Multi-Pollutant Control Project: 

Demonstration of Innovative Technology for Reducing Air Emissions from Smaller CoalFired Units; Presented at the 2008 Joint Meeting of the Pittsburgh Coal Mining Institute of 

America / Society for Mining, Metallurgy, and Exploration, Inc., Canonsburg, PA, October 

30-31, 2008. 
 214

ACRONYMS AND ABBREVIATIONS 

°C - degrees Celsius 

°F - degrees Fahrenheit 

A - ampere 

AC - actual cost 

ACAA - American Coal Ash Association 

acfm - actual cubic feet per minute 

ACI - activated carbon injection 

AFUDC - allowance for funds used during construction 

ASTM - ASTM International (formerly American Society for 

Testing and Materials) 

BET - Brunauer-Emmett-Teller 

bhp - brake horsepower 

BPEI - Babcock Power Environmental Inc. 

Btu - British thermal unit 

CAE - Clean Air Engineering 

Ca/S - calcium-to-sulfur molar ratio 

CCTDP - Clean Coal Technology Demonstration Program 

CCV - continuing calibration verification 

CEM - continuous emission monitor 

CERA - Cambridge Energy Research Associates 

CFD - computational fluid dynamics 

CKM - chemical kinetic modeling 

CONSOL - CONSOL Energy Inc. 

CPI - cost performance index 

CTM - Conditional Test Method 

CVAAS - cold vapor atomic absorption spectroscopy 

CVAFS - cold vapor atomic fluorescence spectroscopy 

DAHS - data acquisition and handling system 

DCS - distributed control system 

DEC - Department of Environmental Conservation 
 215

DOE - U.S. Department of Energy 

dP - pressure drop 

dscf - dry standard cubic foot 

dscm - dry standard cubic meter 

EDT - Eastern Daylight Time (United States) 

EGU - electric generating unit 

EIA - U.S. Energy Information Administration 

EPA - U.S. Environmental Protection Agency 

EPC - engineering, procurement, and construction 

ESP - electrostatic precipitator 

EST - Eastern Standard Time (United States) 

EV - earned value 

Fd - oxygen-based fuel factor 

FD - forced draft 

FGD - flue gas desulfurization 

FONSI - Finding of No Significant Impact 

ft - foot 

g - gram 

gal - gallon 

gph - gallons per hour 

gpm - gallons per minute 

gr - grain 

GW - gigawatt 

h - hour 

HFD - high flow delivery and circulation 

HHV - higher heating value 

hp - horsepower 

Hg0

 - elemental mercury 

Hg2+ - oxidized mercury 

Hgpart - particle-bound mercury 

HgTOT - total gas-phase mercury 

IC - ion chromatography 
 216

icfm - inlet cubic feet per minute 

ICV - independent calibration verification 

ICP-AES - inductively coupled plasma-atomic emission 

spectroscopy 

ICP-MS - inductively coupled plasma-mass spectrometry 

ID - induced draft 

IPA - isopropyl alcohol 

ISE - ion selective electrode 

iwc - inches of water column 

IZM - injector zone metering 

kg - kilogram 

kW - kilowatt 

L - liter 

lbmol - pound-mole 

LPA - large particle ash 

lb - pound 

M - molar 

m - meter 

MASS - Multipoint Automated Sampling System 

MCC - motor control center 

MCR - maximum continuous rating 

mg - milligram 

min - minute 

mL - milliliter 

MM - million 

mm - millimeter 

mmacf - million actual cubic feet 

mmBtu - million British thermal units 

MNL - multiple nozzle lance 

MW - megawatt 

MWe - megawatt of electricity 

MWn - net megawatt 
 217

MWg - gross megawatt 

MWh - megawatt hour 

N - normal 

NEPA - National Environmental Policy Act 

NETL - National Energy Technology Laboratory 

ng - nanogram 

NH3-N - ammonia as nitrogen 

NIST - National Institute of Standards and Technology 

NOx - nitrogen oxides 

NSR - normalized stoichiometric ratio 

NYSEG - New York State Electric & Gas Corporation 

O&M - operating and maintenance 

PAC - powdered activated carbon 

PCCI - Power Capital Costs Index 

pH - measurement of the acidity or alkalinity of an 

aqueous solution 

P&ID - piping and instrument diagram 

PID - proportional-integral-derivative 

PLC - programmable logic controller 

PM - particulate matter 

PM2.5 - fine particulate matter (<2.5 μm aerodynamic 

diameter) 

PPII - Power Plant Improvement Initiative 

ppm - parts per million 

ppmvd - parts per million by volume, dry basis 

ppmw - parts per million by weight 

PRB - Powder River Basin 

psig - pounds per square inch gauge 

PV - planned value 

QA/QC - quality assurance and quality control 

R2

 - coefficient of determination 

RD - relative deviation 

RPD - relative percent difference 
 218

RSD - relative standard deviation 

scf - standard cubic feet 

scfm - standard cubic feet per minute 

SCR - selective catalytic reduction 

SM - Standard Method 

SNCR - selective non-catalytic reduction 

SOFA - separated overfire air 

SPDES - State Pollutant Discharge Elimination System 

SPI - schedule performance index 

SPLP - Synthetic Precipitation Leaching Procedure 

SRM - Standard Reference Material 

STPH - short tons per hour 

TBtu - trillion British Thermal Units 

TCR - total capital requirement 

TPC - total plant cost 

TPI - total plant investment 

TRI - Toxics Release Inventory 

U.S. - United States 

V - volt 

VAC - volts alternating current 

w/w - by weight 

XRD - X-ray diffraction 

μg - microgram 

μm - micrometer 
 219

CHEMICAL SYMBOLS 

Al2O3 - aluminum oxide 

BaCl2 - barium chloride 

C - carbon 

Ca - calcium 

CaCl2 - calcium chloride 

CaCO3 - calcium carbonate 

CaF2 - calcium fluoride 

CaO - calcium oxide (or quicklime) 

Ca(OH)2 - calcium hydroxide 

CaSO3·1⁄2H2O - calcium sulfite hemihydrate 

CaSO4 - calcium sulfate 

CaSO4·1⁄2H2O - calcium sulfate hemihydrate 

Cl - chlorine 

Cl-

 - chloride 

Cl2 - molecular chlorine 

CO - carbon monoxide 

CO2 - carbon dioxide 

CO(NH2)2 - urea 

F - fluorine 

F-

 - fluoride 

F2 - molecular fluorine 

Fe2O3 - iron (III) oxide (or ferric oxide) 

H - hydrogen 

HCl - hydrogen chloride (or hydrochloric acid) 

Hg - mercury 

Hg0

 - elemental mercury 

Hg2+ - oxidized mercury 

Hgpart - particle-bound mercury 

HgTOT - total gas-phase mercury 

HgCl2 - mercury (II) chloride (or mercuric chloride) 
 220

HF - hydrogen fluoride (or hydrofluoric acid) 

HNCO - isocyanic acid 

HNO3 - nitric acid 

H2O - water 

H2O2 - hydrogen peroxide 

H2SO4 - sulfuric acid 

KCl - potassium chloride 

KMnO4 - potassium permanganate 

K2O - potassium oxide 

MgO - magnesium oxide 

N - nitrogen 

N2 - molecular nitrogen 

Na2O - sodium oxide 

NCO - isocyanate radical 

NH2 - amido radical 

NH3 - ammonia 

NH3-N - ammonia as nitrogen 

NH4HSO4 - ammonium bisulfate 

(NH4)2SO4 - ammonium sulfate 

NO - nitric oxide 

NO2 - nitrogen dioxide 

NOx - oxides of nitrogen 

O2 - oxygen 

P2O5 - phosphorus pentoxide 

S - sulfur 

Se - selenium 

SiO2 - silicon dioxide 

SO2 - sulfur dioxide 

SO3 - sulfur trioxide 

SO4

2- - sulfate 

TiO2 - titanium dioxide