# Technologies for Control and Measurement of Mercury Emissions from Coal-Fired Power Plants in the United States: A 2010 Status Report

Northeast States for Coordinated Air Use Management

(NESCAUM)

July 2010Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report ii



### Members of Northeast States for Coordinated Air Use Management

Anne Gobin, Bureau Chief Connecticut Department of Environmental Protection, Bureau of Air Management

James P. Brooks, Bureau Director Maine Department of Environmental Protection, Burea u of Air Quality

Barbara Kwetz, Director Massachusetts Department of Environmental Protectio n, Bureau of Waste Prevention

Robert Scott, Director New Hampshire Department of Environmental Services, Air Resources Division

William O’Sullivan, Director New Jersey Department of Environmental Protection, Office of Air Quality Management

David Shaw, Director New York Department of Environmental Conservation, Division of Air Resources

Douglas L. McVay, Chief Rhode Island Department of Environmental Management , Office of Air Resources

Richard A. Valentinetti, Director Vermont Department of Environmental Conservation, A ir Pollution Control Division

Arthur Marin, Executive Director Northeast States for Coordinated Air Use ManagementTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report iii 

# Technologies for Control and Measurement of Mercury Emissions from Coal-Fired Power Plants in the United States: A 2010 Status Report

Northeast States for Coordinated Air Use Management

(NESCAUM)

July 2010Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report iv


# TECHNOLOGIES FOR CONTROL AND MEASUREMENT OF MERCURY EMISSIONS FROM COAL-FIRED POWER PLANTS IN THE UNITED STATES: A 2010 STATUS REPORT

Project Director Praveen Amar, Ph.D., P.E., Director, Science and Po licy, NESCAUM

Principal Contributors Constance L. Senior, Ph.D., Manager, Engineering Re search and Development, Reaction Engineering International

Rui Afonso, President, Energy and Environmental Str ategies

James Staudt, Ph.D., President, Andover Technologie s PartnersTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report v



## ACKNOWLEDGMENTS

NESCAUM gratefully acknowledges the joint funding s upport provided by the United States Environmental Protection Agency (Office of A ir and Radiation (OAR), Clean Air Markets Division (CAMD), and Office of Air Quality Planning and Standards (OAQPS)). We are greatly indebted to Ms. Ellen Kurlansky of OAR for her dedi cated interest in this project and for her extraordinary ability and good will. We thank Mr. Scott Hedges of CAMD for his helpful guidance as the Project Manager and for coordinatin g an extensive review of the draft version of this report.
This project and report were managed and directed b y NESCAUM (Dr. Praveen Amar). NESCAUM was very ably supported by its contractors, Reaction Engineering International (Dr. Constance L. Senior, Ms. Brydger Van Otten), Energy and Environmental Strategies (Mr. Rui Afonso) and Andover Technology Partners (Dr. James Staudt). Mr. Jesse Colman of NESCAUM and Ms. Mary Sullivan Douglas of National A ssociation of Clean Air Agencies (NACAA) made substantial contributions in designing the state survey of installed mercury monitoring systems as of fall 2009. Dr. Paul Mille r, Deputy Director, NESCAUM, provided excellent editing support. Ms. Wendy Roy, Administ rative Assistant, NESCAUM, was extremely helpful in the final formatting of the re port.

NESCAUM thanks the members of the NESCAUM Stationar y Sources and Permitting Committee, who guided the design of this report in early stages and provided technical data on mercury controls and measurement. The following in dividuals provided strong technical support and comments on the final draft version of the repo rt:
Sunila Agrawal, New Jersey Department of Environmen tal Protection
Andrew Bodnarik, New Hampshire Department of Enviro nmental Services
Patricio Silva, Massachusetts Department of Environ mental Protection
NESCAUM is an association of the eight northeast st ate air pollution control programs that provides technical guidance and policy advice to its member states.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report vi



## TABLE OF CONTENTS

Acknowledgments....................................

................................................... .....................................v List of Acronyms ...................................

................................................... ..................................... xi
ES-1. Objectives ...................................

................................................... .................................... xiii ES-1.1. Mercury Control Technologies...............

................................................... ..................... xiii ES-1.1.1. Continuous Mercury Monitoring Technologie s.................................................. ......... xvi
1. Mercury Control Technologies: Strategies and Co sts ................................................ .......... 1-1 1.1. Introduction..................................

................................................... ............................. 1-1 1.1.1. Objectives ..................................

................................................... ....................... 1-1 1.1.2. Current and Emerging Regulatory Conditions .. .................................................. 1 -1 1.1.3. Boiler and Air Pollution Control Device (APC D) Populations........................... 1-1 1.2. Mercury Control Technologies..................

................................................... ............... 1-6 1.2.1. Introduction................................

................................................... ....................... 1-6 1.2.2. Impacts of Fuel on Mercury Speciation.......

................................................... ..... 1-7 1.2.3. Impact of Air Pollution Control Devices.....

................................................... ... 1-10 1.3. Oxidation Enhancement in Flue Gas .............

................................................... ......... 1-14 1.3.1. Chemical Additives..........................

................................................... ............... 1-14 1.3.2. Fixed-bed Oxidation Catalysts...............

................................................... ......... 1-19 1.4. Sorbent Injection.............................

................................................... ........................ 1-26 1.4.1. Sorbents for Mercury Control................

................................................... ......... 1-26 1.4.2. Sorbents Injection and Cold-Side ESPs.......

................................................... ... 1-28 1.4.3. Sorbent Injection and Hot-Side ESPs .........

................................................... .... 1-33 1.4.4. Sorbent Injection and Fabric Filters........

................................................... ........ 1-34 1.4.5. Sorbent Injection and Spray Dryers..........

................................................... ...... 1-36 1.5. Other Hg Control Technologies.................

................................................... ............. 1-37 1.5.1. Pre-Combustion Removal......................

................................................... ......... 1-37 1.5.2. Fixed Adsorption ............................

................................................... ................ 1-38 1.5.3. Multi-Pollutant Processes ...................

................................................... ............ 1-38 1.6. Coal Combustion Residues (CCRs)...............

................................................... ......... 1-39 1.6.1. Impact of Hg Control Technologies on CCRs... ................................................ 1-3 9 1.6.2. Environmental Stability of Hg in CCRs .......

................................................... .. 1-41 1.7. Costs of Mercury Reduction ....................

................................................... ............... 1-42 1.7.1. Basis for Cost Calculations.................

................................................... ............ 1-42 1.7.2. National Energy Technology Laboratory (NETL) Costs Summary for ACI .... 1-44 1.7.3. National Energy Technology Laboratory (NETL) Cost Summary for Oxidation Technologies .........................

................................................... ... 1-47 1.7.4. U.S. Government Accountability Office (GAO) Mercury Control Study......... 1-48 1.8. Commercial Experience with Sorbent Injection T echnologies ................................. 1-49
2. Continuous Mercury Monitoring Technologies......

................................................... ............ 2-1 2.1. Hg CEMS Technology Overview...................

................................................... .......... 2-1 2.2. Hg CEMS Suppliers.............................

................................................... ..................... 2-2 2.2.1. ThermoFisher Scientific Hg CEMS.............

................................................... ..... 2-2 2.2.2. Tekran Instruments Hg CEMS..................

................................................... ........ 2-4Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report vii

2.2.3. Other suppliers of Hg CEMS..................

................................................... .......... 2-7 2.3. Approximate Costs of Hg CEMS ..................

................................................... ........... 2-7 2.4. Operating Issues of Hg CEMS...................

................................................... ............... 2-8 2.5. Sorbent Trap Method ...........................

................................................... ................... 2-17 2.5.1. Sorbent Trap Method Description .............

................................................... ..... 2-17 2.5.2. Sorbent Trap Accuracy/Precision .............

................................................... ...... 2-18 2.6. Approximate Costs of Sorbent Trap Systems.....

................................................... .... 2-21 2.7. Advantages/Disadvantages of Sorbent Traps When Compared to Hg CEMS.........................................

................................................... ................... 2-21 2.8. Availability of Sorbent Traps used as CMMS....

................................................... .... 2-24 2.9. Approximate Number of Units Installed/In Opera tion .............................................. 2 -25 2.10. Summary......................................

................................................... ........................... 2-26

3. Conclusions.....................................

................................................... .................................... 3-1 3.1. Outlook for Control Technologies..............

................................................... .............. 3-1 3.2. Outlook for Measurement Systems...............

................................................... ............ 3-3

4. References......................................

................................................... ..................................... 4-1Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report viii



## LIST OF FIGURES Figure 1-1. Number of coal-fired boilers > 25 MW pe r state............................................ ....... 1-2 Figure 1-2. Map of coal fields in the U.S. (www.nat ionalatlas.gov).................................... .... 1-3 Figure 1-3. Percent of coal-fired boilers in each s tate burning predominantly

bituminous coal....................................

................................................... ............... 1-4 Figure 1-4. Percent of coal-fired boilers in each s tate burning predominantly

subbituminous coal .................................

................................................... ............ 1-5 Figure 1-5. Percent of coal-fired boilers in each s tate burning predominantly lignite coal ..... 1-5 Figure 1-6. Distribution of mercury in coal burned at U.S. power plants

from 1999 ICR Part 2...............................

................................................... .......... .1-9 Figure 1-7. Distribution of sulfur in coal burned a t U.S. power plants

from 1999 ICR Part 2...............................

................................................... ........... 1-9 Figure 1-8. Distribution of chlorine in coal burned at U.S. power plants

from 1999 ICR Part 2...............................

................................................... ......... 1-10 Figure 1-9. Hg removal across particulate control d evices (PCDs) vs. chlorine

in coal based on 1999 ICR Part 3 data..............

................................................... 1-12 Figure 1-10. Hg removal across wet FGD and particu late control devices (PCDs)

vs. chlorine in coal based on 1999 ICR Part 3 data . ............................................ 1-12 Figure 1-11. Hg removal across spray dryer (SD) an d particulate control devices (PCDs) vs.

chlorine in coal based on 1999 ICR Part 3 data..... .............................................. 1-13 Figure 1-12. Hg removal and oxidation results with various additives

at Milton R Young (top) and Monticello (bottom) pow er plants......................... 1-16 Figure 1-13. Hg oxidation at air preheater outlet (Holcomb) and removal across APCDs

at two PRB-fired plants with SD-FF (Holcomb) and ES P (Meramec)................ 1-17 Figure 1-14. Mercury removal at Pleasant Prairie w ith KNX TM injection ............................... 1-17 Figure 1-15. Test results for wet FGD Hg 0 re-emission additive at Mill Creek Unit 4......... ... 1-19 Figure 1-16. Hg removal across the FGD and mitigat ion of Hg 0 re-emission

with Absorption Plus(Hg) TM at Elmer Smith station ............................ ............... 1-19 Figure 1-17. Relationship between SO 2 conversion and Hg 0 oxidation across SCR catalyst .. 1-20 Figure 1-18. Typical Hg 0 oxidation catalyst application in ESP-wet FGD plan t ..................... 1-21 Figure 1-19. Summary of NETL Hg 0 oxidation catalyst test results from slipstream te sting

at Monticello and Yates power plants...............

................................................... 1-22 Figure 1-20. Impact of Hg 0 oxidation catalysts on total mercury removal by we t FGD,

pilot-scale testing at Monticello..................

................................................... ...... 1-23 Figure 1-21. Slipstream TRAC TM catalyst performance Hg oxidation vs. time........ ............... 1-25 Figure 1-22. Hg oxidation and removal with full sa le TRAC TM catalyst 640 MW,

wall-fired boiler, firing PRB coal at an undisclose d location.............................. 1-25 Figure 1-23. Application of activated carbon injec tion ............................................... ............. 1-26 Figure 1-24. Mercury removal across ESP at Merrima ck Unit 2, combinations

of Darco Hg-LH and trona sorbents..................

................................................... 1-30 Figure 1-25. Removal across ESP at Labadie with in jection of activated carbon as function of SO 3 injection and injection location .................. ........................... 1-31 Figure 1-26. Hg removal at MRC as a function of co ncentration of SO 3 injected

into flue gas......................................

................................................... ................. 1-32 Figure 1-27. Removal of Hg across Presque Isle TOX ECON TM baghouse via injection of

Darco ® Hg sorbent ........................................

................................................... .... 1-35Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report ix

Figure 1-28. Cost of 90% mercury control with and without impact of lost sale

of fly ash as a by-product.........................

................................................... ......... 1-45 Figure 1-29. Incremental cost of electricity (COE) for 90% mercury control with and

without impact of lost sales of fly ash as a by-pro duct........................................ 1-46 Figure 1-30. Cost of 90% mercury reduction vs. a) capital cost b) plant size; and c) sorbent

consumption........................................

................................................... .............. 1-46 Figure 1-31. Cost of mercury reduction using oxida tion technologies combined with FGD... 1-47 Figure 1-32. Cost of mercury reduction for oxidati on technologies vs. catalyst

and chemical costs .................................

................................................... ........... 1-48 Figure 1-33. Mercury control systems orders booked by state.......................................... ....... 1-49 Figure 1-34. Mercury control systems orders booked by coal rank burned at plant ................ 1-50 Figure 1-35. Summary of Hg emissions from coal-fir ed power plants

in Massachusetts, 2008-2009........................

................................................... .... 1-52 Figure 2-1. ThermoFisher Scientific Mercury Freedom System............................................ .. 2-3 Figure 2-2. Schematic of Tekran Hg CEMS ............

................................................... ............. 2-5 Figure 2-3. Simplified diagram of the Tekran Model 3315 Ionic Mercury Calibrator ............ 2-6 Figure 2-4. General approach for elemental mercury calibration gas

generator certification ............................

................................................... ........... 2-11 Figure 2-5. RATA results at low mercury concentrati ons................................................ ...... 2-14 Figure 2-6. Low level Hg CEMS accuracy check agains t sorbent traps on a stack

that follows a wet scrubber or wet stack...........

................................................... 2-14 Figure 2-7. Nebraska Public Power Sheldon 2 RATA re sults.............................................. .. 2-15 Figure 2-8. Method 30B sorbent trap equipment......

................................................... ........... 2-18 Figure 2-9. RATA results reported by Wright and Sch mid with (a) concentrations under

1 μg/m 3 ; (b) concentrations near 1 μg/m 3 ; and (c) concentrations over 1 μg/m 3 2-19 Figure 2-10. RATA results reported by Wright with (a) concentrations under 1 μg/m 3 ;

(b) concentrations near 1 μg/m 3 ; and (c) concentrations over 1 μg/m 3 ............... 2-20 Figure 2-11. Hg CEMS performance compared with Sor bent Traps ....................................... 2- 23 Figure 2-12. Sorbent Trap availability reported by Wright and Schmid ................................. . 2-24Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report x


## LIST OF TABLES Table 1-1. Coal-fired units greater than 25 MW in t he U.S. by coal rank ............................... . 1-3 Table 1-2. Air pollution control devices on U.S. co al-fired boilers in 2010,

number of boilers > 25 MW..........................

................................................... ........ 1-6 Table 1-3. Summary of APCD and coal type informatio n for 1999 ICR Part 3 data sets ...... 1-11 Table 1-4. Recently published testing with boiler a dditives to enhance Hg 0 oxidation.......... 1-15 Table 1-5. Recent published testing with Hg 0 oxidation catalysts................................ .......... 1-21 Table 1-6. Hg oxidation and removal - summary of re sults at Fayette Unit 3........................ 1-24 Table 1-7. Description of mercury sorbents.........

................................................... ................ 1-27 Table 1-8. List of sorbent injection demonstration sites with cold-side ESPs........................ 1- 29 Table 1-9. List of sorbent injection demonstration sites with hot-side ESPs.......................... 1 -33 Table 1-10. List of sorbent injection demonstration sites with fabric filters ......................... ... 1-34 Table 1-11. List of sorbent injection demonstration sites with spray dryers ........................... . 1-36 Table 1-12. Configurations of units in NETL cost st udy and capital cost of ACI

for 90% Hg removal.................................

................................................... ........... 1-44 Table 1-13. List of key parameters in NETL cost stu dy of oxidation technologies

combined with FGD..................................

................................................... .......... 1-47 Table 1-14 Summary of results from U.S. GAO Hg cont rol survey........................................ 1 -49 Table 1-15. Summary of New Jersey stack test mercur y emissions for 2008 and 2009........... 1-51 Table 1-16. Dominion Energy Salem Harbor Station 20 09 reported Hg emissions ................. 1-53 Table 1-17. Dominion Energy Brayton Point Station 2 009 reported Hg emissions ................. 1-54 Table 2-1. Availability of Hg CEMS at Dominion Bray ton Point power plant in 2008......... 2-16 Table 2-2. Availability information for Dominion Sa lem Harbor Units 1, 2, 3 CMMS......... 2-24 Table 2-3. NESCAUM 2009 survey of Hg CMMS in nine s tates and one city...................... 2-26Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report xi



## List of Acronyms
AAS Atomic absorption spectroscopy ACI Activated carbon injection AEA Air-entraining agent
AEP American Electric Power APCD Air pollution control device APH Air preheater
CAAA Clean Air Act Amendments CAMR Clean Air Mercury Rule
CCR Coal combustion residue CEA Cold-end temperature CEMS Continuous emission monitoring system CMMS Continuous mercury monitoring system COE Cost of electricity CVAF Cold-vapor atomic fluorescence DEP Department of Environmental Protection DOE Department of Energy EDX Energy-dispersive X-ray EIA Energy Information Administration EERC Energy & Environmental Research Center EPA Environmental Protection Agency
EPRI Electric Power Research Institute ESP Electrostatic precipitator
FBC Fluidized bed combustor
FF Fabric filter FGC Flue gas conditioning FGD Flue gas desulfurization GAO Government Accountability Office HAP Hazardous air pollutant ICP-MS Inductively coupled plasma mass spectrometry ICR Information Collection Request
ICSET Institute for Combustion Science and Environm ental Technology MRC Mercury Research Center MW Megawatt
ND North Dakota NETL National Energy Technology Laboratory
NOx Oxides of Nitrogen NIST National Institute of Standards & TechnologyTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report xii 

## List of Acronyms [Cont’d]

OA Oxidation additive
PAC Powdered activated carbon
PCD Particulate control device
PM Particulate matter
PRB Powder River Basin PSNH Public Service of New Hampshire QA Quality assurance QC Quality control RATA Relative accuracy test audit RCRA Resource Conservation and Recovery Act
RM Reference method SCA Specific collection area SCR Selective catalytic reduction SD Spray dryer
SEA Sorbent enhancement additive SEM Scanning electron microscope SNCR Selective non-catalytic reduction
SO 2 Sulfur dioxide ST Sorbent trap

TX Texas
WRI Western Research InstituteTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report xiii



## Executive Summary

ES-1. Objectives
The current status of mercury control technologies and mercury measurement systems for coal-fired power plants is reviewed in this report, including recent information on performance and costs (capital costs, fixed and variable costs , and operating and maintenance costs). The objective is to summarize the outlook for the next two to three years of various mercury control and measurement options so as to present a realisti c picture of mercury emissions reductions that may be achievable in the United States.
Recent experience (2006-2009) with mercury control technologies, including activated carbon injection (ACI) technology, is evaluated, ba sed on projects funded by the U.S. Department of Energy’s National Energy Technology L aboratory (NETL), Electric Power Research Institute (EPRI), and others. Key sub-pop ulations of coal-fired boilers (for example, boilers burning different coal types or using different typ es of control equipment for nitrogen oxides (NOx), sulfur oxide (SO 2 ), and particulate matter (PM) emissions) have been identified as needing additional technology development to meet s tringent mercury emission requirements.
The status of continuous mercury monitoring systems (CMMS), which include mercury continuous emission monitoring systems (CEMS) and s orbent trap (ST) systems, is assessed. Data have been collected and evaluated on measureme nt technologies including recent experience in the field. For both mercury CEMS and STs, the report provides:

• a brief overview of the technology;

• approximate costs;

• approximate number of units installed and in operat ion, and where possible, data sorted by state and by CEMS vendor; and

• a brief description of operating issues as well as data on reliability and sensitivity.
The advantages and disadvantages of sorbent trap te chnology compared to mercury CEMS are also discussed.



### ES-1.1. Mercury Control Technologies
Mercury chemistry in flue gas is complex, because m ercury interacts with acid gases (e.g., HCl, SOx) and unburned carbon in ash. The c ompositions of coals that are burned in power plant boilers vary, which results in a range of compositions of flue gas. Thus, there is not a “one size fits all” technology for control of mer cury emissions. Instead, solutions must be tailored to a given boiler.
Two general approaches for mercury control have, to date, proven capable of effectively reducing mercury emissions at levels of control of 90% or greater on combinations of coal type and air pollution control devices (APCDs) that repr esent the majority of coal-fired boilers. These approaches involve use of either existing APC Ds or dedicated mercury control technology, primarily powdered activated carbon inj ection.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report xiv

There are cases where the existing APCDs alone may be capable of greater than 90% reduction in mercury, but this is not always possib le even for similar plant/fuel configurations. In recognition of these considerations, the develop ment of dedicated mercury control technologies over the last 15 years has concentrate d on two major areas:

• Development of techniques and technologies to promo te oxidation of elemental mercury (Hg 0 ) to oxidized mercury (Hg 2+ ) in the flue gas for subsequent removal in a wet or dry scrubber; and

• Development of sorbents and associated systems to p romote the adsorption of mercury on sorbents.
Increased oxidation of mercury in flue gas can be p romoted by two different methods:

• Chemical additives designed to maximize the oxidati on of Hg 0 in the flue gas; and

• Fixed bed oxidation catalysts.
The majority of work involving enhanced oxidation t echniques has been focused on plant configurations with wet flue gas desulfurization (F GD) systems, in which the oxidized mercury is captured. The “re-emission” of Hg 0 after Hg 2+ has been captured and chemically reduced in the scrubber has been observed and can be addressed by the use of additives to the scrubber.
Powdered activated carbon (PAC) is the most widely used mercury sorbent, and in many of these coal-fired power plants, injection of PAC can achieve mercury removal of 90% or greater. Activated carbons are made from coal or b iomass and have been chemically treated to enhance mercury removal, using halogens (chlorine, bromine, iodine) or sulfur. While injection of untreated carbon-based sorbents works well for p lants burning bituminous coal, this control strategy is not as effective for plants burning sub bituminous or lignite coals. Chemically treated sorbents are able to achieve high mercury reduction s across all coal types. Other non-carbon based sorbents are also being developed.
Most coal-fired boilers will have options for high levels of mercury control to meet existing state or anticipated federal regulations o n mercury emissions. The combination of a wet scrubber and an SCR has demonstrated mercury remova l in the range of 70% to 90% on plants burning high-sulfur bituminous coal. Activated car bon has been shown to be cost-effective for high levels of mercury removal (80% to 90%) at boil ers with a cold-side ESP or baghouse that burn low-sulfur bituminous coal, subbituminous, or lignite coal, as long as the plant does not use flue gas conditioning with the ESP.
A report by the U.S. Government Accountability Offi ce (GAO) in 2009 identified several power plant configurations for which mercury contro l by sorbent injection might not achieve 90% removal, including units with high SO 3 concentrations in the flue gas, units equipped wit h hot-side electrostatic precipitators (ESPs), and th ose burning lignite coal. These units might require alternate technologies for mercury control or improvements in existing technologies.

• Lignite is burned at 3% of coal-fired boilers in th e U.S. While the overall amount of lignite burned is small, regionally the fuel is important. Lignite from the northern Great Plains is burned in North Dakota and lignite from the Gulf Coast is burned in Texas and Louisiana. Great Plains (GP) l ignite is relatively low in sulfur, similar to subbituminous coal, and reasonab ly good success has been demonstrated in controlling mercury using a combina tion of boiler additives andTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report xv

activated carbon. Gulf Coast (GC) lignite can be s ignificantly higher in sulfur, relative to Great Plains lignite. When compared wi th Powder River Basin subbituminous coals, lower levels of mercury reduct ion have been observed when firing Gulf Coast lignite.

• Hot-side ESPs are the only particulate control devi ce on about 9% of boilers; these boilers burn both bituminous and subbituminou s coals. Activated carbons, even those designed specifically for the high tempe ratures of a hot-side ESP, have not been able to show 90% removal in hot-side ESPs. Unless sorbents can be found that are effective at temperatures greater th an about 700oF, the best control option for hot-side ESPs would be to install a fabr ic filter (FF) downstream of the ESP for use with sorbent injection.

• High levels of SO 3 are produced in boilers that burn high-sulfur bitu minous coal (defined as greater than 1.7 wt% sulfur) or that ha ve a selective catalytic reduction (SCR) unit and burn bituminous coal. The higher th e sulfur content in the coal, the higher the resulting concentration of SO 2 in flue gas; SCRs produce additional SO 3 in the flue gas by catalytic oxidation of SO 2 . In both these situations, SO 3 concentrations in the flue gas are high enough to r educe the effectiveness of activated carbon for Hg removal. The combination o f an SCR and a wet FGD might achieve 90% Hg removal on these plants. The high-sulfur bituminous plants that have a cold-side ESP without both SCR a nd FGD make up only 11% of the U.S. boiler population. This percentage is expected to shrink in the next several years as more bituminous-fired plants insta ll advanced NOx and SO 2 controls (e.g., SCRs and FGDs). Injection of alkal ine sorbents, like trona, can be used to reduce SO 3 in the flue gas and improve the performance of act ivated carbon. Furthermore, new carbon-based mercury sorb ents are being developed that are tolerant of higher levels of SO 3 . The other category of plants that have relatively high levels of SO 3 are plants burning low-sulfur bituminous, subbituminous or lignite coal with cold-side ESPs t hat require flue gas conditioning to meet limits on stack opacity. Appr oximately 15% of boilers with cold-side ESPs use flue gas conditioning. SO 3 -tolerant sorbents are being developed to address the difficulty in achieving 90 % mercury removal in these systems. Trona injection has been proposed as an a lternative to SO 3 as a flue gas conditioning agent and there are other alternative flue gas conditioning agents under development. Another, but more expensive alt ernative, is to install a TOXECON TM fabric filter (an EPRI-patented technology) after the ESP and to inject the sorbent into the fabric filter.
The report contains a summary of the most recently published data available with respect to costs of dedicated or mercury-specific control t echnologies. Specifically, this includes algorithm-based cost information as well as actual costs on installed systems for mercury control. These recent studies, conducted in 2007-2009, repre sent a reasonable basis for the current status of estimates of mercury control costs.
The installed capital costs of ACI technology are l ow (from about $3.5/kW to about $9.2/kW). Levelized operating costs of ACI technol ogy are primarily driven by the cost of the sorbent. Hence, quantity and quality of the sorben t are the key factors in the total sorbent cost. In some situations, if ACI would result in a loss o f sales of fly ash as a by-product, the operatingTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report xvi
costs are higher. Costs for ACI range from about $ 6,000/lb Hg removed to $30,000/lb Hg removed when by-product contamination/sales are not a factor, and between about $18,000/lb Hg removed and $50,000/lb Hg removed if revenue fro m fly ash sales is lost. These estimates correspond to 20-year levelized costs of electricit y ranging from about 0.35 mills/kWh to 2 mills/kWh (0.035 to 0.2 cents/kWh) without by-pro duct penalty and about 1 mill/kWh to 3.5 mills/kWh (0.1 to 0.35 cents/kWh) if by-product impacts are present.
If ACI technology is combined with a new fabric fil ter (TOXECON TM ), then capital and operating costs will be substantially higher. For example, the TOXECON TM system installed at the Presque Isle power plant reported a capital cos t of $128/kW and an overall mercury removal cost of $67,000/lbHg.
The two types of Hg oxidation technologies (catalys ts and additives) have different cost components: catalysts are primarily driven by the i nitial capital and re-generation costs, while additive technology is not capital-intensive, but a s with the ACI technologies, is driven by costs of chemicals. Unlike the estimates above for ACI t echnologies, the oxidation technology costs were estimated based on pilot-scale results and app lied to a nominal 500 MW plant. The capital and operating costs are comparable to those for sor bent injection technologies. Specifically, the incremental cost of electricity was in the range of 1.0 to 1.8 mills/kWh, which is about the same as that for the ACI technologies when by-product im pacts are not included.
Cost-effective use of ACI is not necessarily possib le on all plants, particularly on plants that sell their fly ash for concrete manufacture. Plants that fire low-rank coal and sell their fly ash represent about 23% of boilers in the U.S., whi le 21% of plants that fire bituminous coal sell their fly ash. According to the 2008 Production an d Use Survey by the American Coal Ash Association (www.acaa-usa.org), of the 30 million t ons of fly ash sold for commercial applications, 42% was used to make concrete. Addin g enough activated carbon to achieve 90% removal can reduce the economic value of the fly as h, if the fly ash is intended for concrete manufacture. Process variations have been identifi ed that require low activated carbon injection rates to achieve high levels of removal, which migh t allow for the sale of fly ash. Several sorbent vendors offer activated carbon that is spec ially treated to allow the fly ash-sorbent mixtures to be made into acceptable concrete. An a lternative is to segregate the fly ash collection from the sorbent collection by using add -on technology.



### ES-1.1.1. Continuous Mercury Monitoring Technologies
This report examines the technologies for continuou s monitoring of mercury emissions from power plant stacks, including continuous analy zers, or mercury CEMS and sorbent trap (ST) methods. Hg CEMS and STs are currently applie d on more than 700 coal-fired power plant stacks, with over 600 Hg CEMS and about 100 STs.
The findings of this report for Hg CEMS are summari zed below:

• Hg CEMS, at roughly $500,000 of capital cost per si te (with some variation due to site-specific variables), are the more costly of the two approaches to install, but they offer advantages that are discussed below. Al though there has been a significant learning curve with Hg CEMS, the techno logy has advanced rapidly and many of the technical challenges that existed w ith the technology only a few years ago have been addressed.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report xvii

• Many issues affecting reliability of Hg CEMS have b een addressed, and it is expected that design changes implemented over the p ast few years as Hg CEMS have been installed will improve future reliability . Although only a small percentage of Hg CEMS have reported annual emission s data to state agencies, they have reported availability of 90% or greater. In other states power plant owners are operating Hg CEMS in anticipation of fut ure state and federal regulatory requirements to report such data; howeve r, official performance statistics are not publicly available from these st ates. As more state mercury emission rules take effect, more mercury data shoul d become available.

• Measurement accuracy at low mercury levels has impr oved. Data indicate that Hg CEMS may offer reliable measurements to well bel ow 1.0 μg/m 3 , which is important for situations where Hg emission controls are in place.

• Mercury calibration gas standards (generators) that are traceable to National Institute of Standards and Technology (NIST) measur ements are available. Interim calibration protocols have been established

. The findings of this report for sorbent trap method s are summarized below:

• Sorbent traps, at about $150,000 of capital cost pe r site (with some variation on this cost due to site specifics), are a lower capit al cost alternative to Hg CEMS. However, STs require regular replacement and testin g (roughly, every four to seven days) of the sorbent traps, which entails add itional labor and cost relative to CEMS.

• Although only three of the more than 100 installed STs have reported annual emissions data to state agencies (Massachusetts), t hey have a reported availability of about 90% or greater. As more state mercury emi ssion rules take effect, more availability data should become public.

• STs appear to offer reliable measurements to well b elow 1.0 μg/m 3 , which is important for situations where Hg controls are in p lace.

• In addition to lower capital cost, STs offer the ad vantage of requiring less sophisticated technical support compared to that ne eded for Hg CEMS.
Hg CEMS have some advantages relative to STs. They are:

• Hg CEMS offer results in minutes, while it can take days for ST results to become available.

• Sorbent traps are inherently more labor-intensive t han Hg CEMS, and this implies that long-term operating costs for STs may not have as much room for improvement as operating costs for Hg CEMS.

• Hg CEMS offer mercury speciation data, which may be useful for Hg control or for understanding the environmental impact of Hg em issions. STs offering mercury speciation data are available but have not been extensively tested.
Sorbent traps have some advantages relative to CEMs . They are:Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report xviii

• CEMS require significantly higher capital cost: ab out $500,000 for CEMS versus about $150,000 for STs.

• Hg CEMS are more complex than sorbent traps systems and will require more sophisticated technical staff to support.

• Hg CEMS are not able to measure low concentration l evels as well as STs. However, Hg CEMS are improving their ability to mea sure to low levels such that any advantage STs have in this respect may be small

.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-1



## 1. Mercury Control Technologies: Strategies and Costs

1.1. Introduction

1.1.1. Objectives The objective of this Chapter is to provide a detai led review of the current status (2006- 2009 timeframe) of mercury control technologies for coal-fired power plants in the U.S. The review covers results from actual field application s of control technologies as well as technologies that are under development and getting ready for commercial deployment. The Chapter also provides data on cost performance of t he reviewed technologies with focus on the application of most common technology, activated ca rbon injection (ACI). The report focuses on the near-term outlook for the next two to three years of various mercury control options so as to present a realistic picture of mercury emission reductions that should be achievable in the U.S.



### 1.1.2. Current and Emerging Regulatory Conditions With the U.S. Court of Appeals D.C. Circuit vacatur of the federal Clean Air Mercury Rule (CAMR) in early 2008, about 20 states across t he country have moved forward implementing their state-specific approaches and me thods to control mercury emissions in the range of 85 to 95%. Some states have percentage re duction requirements (from mercury in coal), others have emission limits (input or output -based standards), and some states have a combination standard, providing the flexibility of meeting the less stringent of the two. A common theme of these state rules is that, unlike C AMR, none of the state rules allow trading of mercury emissions to meet the regulatory requiremen ts. The time frame for compliance with various state requirements is typically from 2007 t o 2014, with a few states allowing until 2018.
The real-world experience drawn from these ongoing individual state efforts, along with continued industry applications and data collection under real-world conditions, is expected to help steer the design of future federal mercury reg ulations. Under the current timetable, the U.S. Environmental Protection Agency (EPA) is expected t o propose utility MACT regulations no later than March 16, 2011, with finalization of the se rules eight months later, by November 16, 2011. The federal utility MACT rules will cover no t only mercury, but also other trace metals, acid gases, and other compounds listed under sectio n 112 of the 1990 Clean Air Act Amendments (CAAA).



### 1.1.3. Boiler and Air Pollution Control Device (APCD) Popu lations Mercury emission rates and capture of mercury from coal-fired power plants depend on the chemical composition of the coal burned and on the design and operation of APCDs on the plant. These relationships will be discussed in de tail in Section 1.2. This section introduces the range of coal types and APCDs on coal-fired boilers in the U.S.
A survey of the types of APCDs on coal-fired power plant boilers in the U.S. was carried out using the National Energy Technology Laboratory (NETL) 2007 Coal Power Plant Database, 1 which includes data from the U.S. Energy Informati on Administration (EIA) 767 database, and a U.S. EPA New Source Review database , which was updated in August 2009. 2 The information on APCDs was updated by using other public information on devices installedTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-2

since 2005. There are approximately 1,130 coal-fir ed boilers greater than 25 MW at more than 500 facilities in the U.S. The locations of these boilers are shown in Figure 1-1. Coal-fired power plants are concentrated in the eastern half o f the U.S., with the highest concentrations generally found along the Ohio River (Pennsylvania, Ohio, Kentucky, Indiana, Illinois).

0
1-20
21-40
41-60
61-80
>80

Figure 1-1. Number of coal-fired boilers > 25 MW p er state
Coal burned in the U.S. may be categorized by rank as either bituminous, subbituminous, or lignite. Often subbituminous and lignite coals are lumped together and called low-rank coals. A small number of plants burn waste coal refuse, wh ich typically consists of high-ash rejects that come from historic mining or coal washing operation s. Some plants in the U.S. co-fire petroleum coke (also called petcoke) with coal. Th e properties of different coal ranks relative to mercury emissions control are discussed in more det ail in Section 1.2.
A map of the coal fields in the U.S. is shown in Fi gure 1-2. Eastern bituminous coals are mined primarily in Illinois, Indiana, Ohio, Kentuck y, Pennsylvania, West Virginia, Virginia, and Alabama. Western bituminous coals are mined in Uta h and Colorado. Subbituminous coals are mined primarily in Wyoming and Montana, although th ere are locally used subbituminous sources in Colorado, New Mexico, and Arizona. Gulf Coast (GC) lignite is mined primarily in Texas, while Great Plains (GP) lignite is mined pri marily in North Dakota.
A breakdown of coal-fired units by coal rank is sho wn in Table 1-1 for plants greater than 25 MW, based on data collated from References 1 and 2. Plants that burn blends have been grouped with the rank of the largest share of coal. The majority of the coal-fired units burn bituminous (54% on a MW basis) or subbituminous (42 % on a MW basis) coal.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-3

Table 1-1. Coal-fired units greater than 25 MW in the U.S. by coal rank

Coal rank No. units % of total units MW % of total MW Bituminous 668 58.8% 181,438 53.6% Subbituminous 406 35.7% 141,566 41.8% Lignite 30 2.6% 13,564 4.0% Other fuels 32 2.8% 2,201 0.6% Total 1,136 338,769

Figure 1-2. Map of coal fields in the U.S. (www.na tionalatlas.gov)
The geographical locations of boilers burning the m ajor coal ranks are illustrated in Figure 1-3 through Figure 1-5. Eastern bituminous coal is burned in the eastern half of the U.S. It should be noted that boilers that import bitumin ous coal from South America have been included in Figure 1-3. In the Rockies and Intermo untain West, western bituminous coal isTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-4

burned. Bituminous coal is more likely to be burne d in the regions where it is mined, while subbituminous coal (primarily from Wyoming and Mont ana) is used in almost all regions of the U.S. except New England and the Atlantic States, as shown in Figure 1-4. Lignite is an important fuel in the regions where it is mined (Fi gure 1-5), but not elsewhere.

0%
1-20%
21-40%
41-60%
61-80%
81-99%
100%

Figure 1-3. Percent of coal-fired boilers in each state burning predominantly bituminous coalTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-5

0%
1-20%
21-40%
41-60%
61-80%
81-99%
100% 0%
1-20%
21-40%
41-60%
61-80%
81-99%
100%

Figure 1-4. Percent of coal-fired boilers in each state burning predominantly subbituminous coal

Figure 1-5. Percent of coal-fired boilers in each state burning predominantly lignite coalTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-6

The input mercury from these coals can vary widely; however, mercury content is not always an indication of mercury emissions. Native mercury removal (i.e., removal with existing APCDs without any mercury-specific technology) is i nfluenced by coal composition and various APCDs installed for the reduction of NOx, SO 2 , or PM as discussed in Section 1.2. The coalfired units in the U.S. were categorized based on t ype of PM control, SO 2 control, and type of post-combustion NOx control. An overall breakdown of the APCDs used in U.S. coal-fired boilers greater than 25 MW is shown in Table 1-2. Cold-side ESPs for particulate control are the most widely installed APCDs, followed by wet FGD un its, SCR units, and FFs. While all units are equipped with particulate control, about a thir d of units have SO 2 control and about 25 percent have SCR post-combustion NOx control. In t he next five years, this distribution is expected to shift, as more power plants install SCR units and wet or dry scrubbers to meet future federal regulations to lower SO 2 and NOx emissions.

Table 1-2. Air pollution control devices on U.S. c oal-fired boilers in 2010, number of boilers > 25 MW

Bituminous Subbitum. Lignite Other # Total

Particulate Control

Cold-side ESP* 454 257 17 1 729

Fabric Filter** 120 112 12 31 275

Hot-side ESP 78 23 0 0 101

Other 16 14 1 0 31

Post-Combustion NOx

SNCR 146 22 2 15 185

SCR 208 84 2 1 295

SO 2 Control

Fluidized Bed*** 20 4 7 29 60 Dry Sorbent Inject. 29 7 1 0 37 Spray Dryer 54 31 3 0 88

Wet FGD 255 89 16 1 361

# Includes waste coal and petcoke *Includes combinations of cold-side and hot-side **Includes combinations of ESP and FF ***Includes in-bed capture in fluidized bed



### 1.2. Mercury Control Technologies

1.2.1. Introduction Technologies to measure and control mercury emissio ns from coal-fired power plants are relatively new when compared to technologies to mea sure and control SO 2 and NOx emissions that have been commercially available for at least two decades. Section 112 of the 1990 CAAA triggered the requirement for the U.S. EPA to addre ss hazardous air pollutants (HAPs) from coal-fired power plants including mercury. Much ha s been accomplished in the intervening years, certainly in terms of the technical learning curve. In this section, the impacts andTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-7

contributions of fuel and control equipment on merc ury emissions and controls are briefly reviewed. It is relevant to this discussion to not e that initially, the control of mercury emissions in the flue gas from coal-fired boilers presented some technical challenges due to the following considerations.

• Very small quantities of Hg present - Typical concentrations of mercury in the flue ga s of a coal-fired power plant boiler are about 4 to 5 or ders of magnitude (0.01 ppmv vs. more than 100 ppmv) lower than those of NOx or SO 2

.

• Chemical speciation and physical forms of Hg presen t - Unlike NOx or SO 2 (which are mostly present as gaseous NO or SO 2 in flue gases), mercury is present in both vapor form (as insoluble elemental mercury and as soluble ionic mercury (mercury chloride, mercuric sulfate, and mercuric oxide)) and in parti culate form adsorbed on fly ash.

• Measurement

- The very small quantities of various chemical fo rms of mercury present in the flue gas make it difficult to develop sufficien tly accurate measurement devices.
These characteristics of mercury emissions and conc entrations are well understood today, as reflected by the types and number of technology options available for controlling mercury emissions.



### 1.2.2. Impacts of Fuel on Mercury Speciation Mercury transformations in a coal-fired plant are c omplex and site-specific. As mercury leaves the boiler, it is present mostly in an eleme ntal form (Hg 0 ). As it proceeds through various components and APCDs of the plant, some of it is ox idized (Hg 2+ ) and the rest remains in an elemental form. Both Hg 0 and Hg 2+ may be adsorbed on particulate matter (Hg P ), although Hg 2+ is generally easier to adsorb. The amount of Hg 0 converted to Hg P and Hg 2+ depends on plant configuration and operating conditions as well as o n flue gas composition. Hg 2+ is highly water soluble and is easily captured in scrubbers, wherea s Hg 0 is not water soluble and is emitted from the stack. Hg P is frequently captured in an ESP or FF. This is i mportant not only to the understanding and development of control technologi es, but also to the broader environmental impact of the emissions. In this regard, it is not ed that elemental mercury has a relatively long residence time in the atmosphere (1-2 years), while oxidized forms of mercury have lifetimes of only a few days as a result of the higher solubilit y of Hg +2 in atmospheric moisture. Elemental mercury can thus be transported globally over long distances, whereas oxidized and particulate forms of mercury deposit locally or regionally with in tens to a few hundreds of miles of the point of emission. 3

Much has been learned since the late 1990s and earl y 2000s regarding the major contributors to mercury speciation in the flue gas. Chlorine in the coal which causes HgCl 2 formation in the flue gas, is the dominant contribu tor along with resultant oxidized species in the

gas. 4 The key kinetic pathway to formation of HgCl 2 in flue gas is through the reaction of atomic chlorine (Cl) with elemental mercury. 4,5 Although the oxidation of elemental mercury in the convective section of a boiler is assumed to pr oceed primarily via gas-phase reaction, some fly ash can also catalyze oxidation of elemental me rcury. Iron oxide and other constituents in the fly ash (carbon, calcium compounds) may also contri bute to mercury oxidation. The presence of acid gases (HCl, SO 2 , NO, NO 2 ) in the flue gas can also promote oxidation in the presence of fly ash. 6,7 Additionally, SCR technology for NOx control on b ituminous coal-fired units has been observed to oxidize elemental mercury. 8 These reactions are further influenced by operati ngTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-8

conditions in the plant, specifically, gas temperat ures (absolute and gradients), unburned carbon levels in the fly ash, and residence times.
In Section 1.1.3, the population distribution of co al-fired boilers in the U.S. was summarized. It is broadly distinguished by coal ra nk. Figure 1-6, Figure 1-7, and Figure 1-8 provide an overview of some of the key coal quality parameters and their distribution in U.S. coals, based on the data collected in Part 2 of the U.S. EPA’s 1999 Information Collection Request (ICR). As stated above, chlorine plays a k ey role in the oxidation of Hg 0 in the flue gas.
Mercury in coal translates directly to mercury in t he flue gas, and therefore coal choice affects mercury emission levels, but the impact goe s beyond the coal mercury content. Figure 1-8 shows the distribution of Cl in U.S. coals. It is relevant to note the range of Cl present primarily in bituminous coals, indicating that a si gnificant portion of U.S. coals (on the order of 50%) have Cl concentrations between about 200 μg/g (or ppmw) and 2000 μg/g. This significant range of Cl content in coal results in varying Hg speciation in the flue gas. This, in turn, influences the choice of strategies and/or te chnologies for effective Hg emissions control. The distribution of sulfur in U.S. coals (Figure 1- 7) varies even more than Cl. The sulfur content of the coal affects the choice of SO 2 control technology, which in turn affects the pote ntial for removal of mercury in the scrubber system. Further more, the amount of sulfur in the flue gas (as SO 2 and SO 3 ) can interfere with adsorption of mercury on carbo n, as discussed below.
In summary, coal composition (primarily in terms of chlorine content and ash composition), the operation of the combustion syste m (primarily in terms of carbon left unburned in the ash), and the temperature and residence time of the exhaust gas in the particulate control device affect mercury speciation in the flue gas. These parameters and conditions affect the ultimate speciation of mercury in the flue gas, the reby influencing the choice of the most effective technology for removing mercury from the flue gas.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-9

Figure 1-6. Distribution of mercury in coal burned at U.S. power plants from 1999 ICR Part 2

Figure 1-7. Distribution of sulfur in coal burned at U.S. power plants from 1999 ICR Part 2 0% 20% 40% 60% 80% 100%

0 10 20 30 40 50**Cumulative Percent Less Than**

**Hg, lb/TBtu** E.Bitum.

W.Bitum.

Subbituminous
GC Lignite
GP Lignite

0% 20% 40% 60% 80% 100%

0 2 4 6 8 10**Cumulative Percent Less Than**

**Sulfur, lb SO 2**  **/MMBtu** E.Bitum.

W.Bitum.

Subbituminous
GC Lignite
GP LigniteTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-10

Figure 1-8. Distribution of chlorine in coal burne d at U.S. power plants from 1999 ICR Part 2



### 1.2.3. Impact of Air Pollution Control Devices The various types of APCDs installed on coal-fired power plants include FFs and ESPs for particulate control, scrubbers for SO 2 control, and low-NOx burners, SCR or selective non

catalytic reduction (SNCR) for NOx control. Most o f these APCDs have an unintended impact (positive or negative) on the behavior of mercury ( speciation, capture).
The U.S. EPA’s Mercury ICR in 1999 was designed to provide useful information for making a regulatory determination about mercury emi ssions from coal-fired power plants. Table 1-3 shows the distribution of the various types of APCDs in the coal-fired power plants tested in Part 3 of the 1999 ICR. Part 3 included data from over 80 boilers, which were selected for mercury emission testing based on a representative sample of plant configurations, air pollution control equipment configurations, and coal types. In this table, low-rank coal denotes subbituminous and lignite coals. 0% 20% 40% 60% 80% 100%

0 500 1000 1500 2000 2500**Cumulative Percent Less Than**

**Chlorine, ug/g dry** E.Bitum.

W.Bitum.

Subbituminous
GC Lignite
GP LigniteTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-11

Table 1-3. Summary of APCD and coal type informati on for 1999 ICR Part 3 data sets 9
APCD Equipment Coal Type %Units Tested in ICR Part 3 %Units in

Population
Cold-side ESP Bituminous 7.2 48.3
Cold-side ESP Low-Rank 7.1 11.7
Hot-side ESP Bituminous 7.2 6.6
Hot-side ESP Low-Rank 3.6 2.4
Cold-side ESP+FGD Bituminous 6.0 8.8 Cold-side ESP+FGD Low-Rank 9.2 2.5
Hot-side ESP+FGD Bituminous 4.8 0.7
Hot-side ESP+FGD Low-Rank 3.6 1.0 FF Bituminous 3.6 2.9
FF Low-Rank 7.2 2.7
FF+FGD Bituminous 7.2 1.6
FF+FGD Low-Rank 3.6 1.6 SD-FF Bituminous 3.6 2.9
SD-FF Low-Rank 7.2 1.3
SD+ESP Bituminous 2.4 0.2
SD+ESP Low-Rank 3.6 0.3
FF+FBC Bituminous 3.6 2.9 Other Other 9.3 1.6

FBC=Fluidized bed combustor SD=Spray dryer

At each site, measurements were made to characteriz e the mercury reduction due to the particular site configuration and conditions. Anal yses were conducted and the data obtained were reported. 9 These results, combined with more recent testing done at additional plants, have formed a basis for estimating the typical or averag e expected mercury capture associated with existing equipment (i.e., “co-benefit” control). F igure 1-9, Figure 1-10, and Figure 1-11 summarize the mercury removal observed by type of A PCD and fuel rank. (In Figure 1-10, WS stands for wet particulate scrubber.) Mercury remov al varied significantly among plants with similar equipment and chlorine content of the fuel. While Cl can be seen to have a positive effect in mercury removal in all three graphs, the otherwise significant scatter in the results amongst the various APCD types did not allow for st rong, universal correlations to be drawn at that time.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-12

-40% -20% 0% 20% 40% 60% 80% 100%Hg Removal Across PCD

10 100 1,000 10,000

Coal Chlorine, ppm dry ESP

FF

HESP

Figure 1-9. Hg removal across particulate control devices (PCDs) vs. chlorine in coal based on 1999 ICR Part 3 data 9

-20% 0% 20% 40% 60% 80% 100% 120%Hg Removal across FGD/PCD

10 100 1,000 10,000

Coal Chlorine, ppm dry ESP

FF

HESP

WS

Figure 1-10. Hg removal across wet FGD and particu late control devices (PCDs) vs.

chlorine in coal based on 1999 ICR Part 3 data 9Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-13

-20% 0% 20% 40% 60% 80% 100%H g R e m o v a l a c r o s s S D A / P C D

10 100 1,000 10,000 Coal Chlorine Content, ppm dry ESP

FF

Coal Chlorine, ppm dry

Figure 1-11. Hg removal across spray dryer (SD) an d particulate control devices (PCDs)

vs. chlorine in coal based on 1999 ICR Part 3 data 9

As the data show, although there are cases where th e co-benefit control alone may be capable of greater than 90% reduction in mercury, t his is not always true even for similar plant (boiler/APCD) and fuel configurations. Mercury reduction co-benefits can be exploited on a site-specific basis, but may not completely satisfy regulatory requirements, particularly stringent mercury emission limits. Therefore, this report fo cuses on dedicated or mercury-specific technologies, while co-benefits are discussed as ap propriate.
Mercury transformations during the combustion proce ss and subsequent flue gas path are driven by many complex factors, which ultimately yi eld mercury in elemental, oxidized and particulate forms. Particulate-bound mercury (Hg P ) may be collected in particulate control devices such as ESPs and FFs. As has been stated p reviously, Hg 2+ is the “easier” form (as opposed to Hg 0 ) to remove from the flue gas, both through adsorpt ion on particulate matter and through absorption in the wet FGD due to its water solubility.
In recognition of these considerations, technology developments over the last 15 plus years have concentrated on two major areas: 1) deve lopment of sorbents and associated systems (e.g. , promoting the transformation of Hg 0 and Hg 2+ to Hg P ); and 2) development of techniques and technologies to promote oxidation of Hg 0 to Hg 2+ in the flue gas.
The following sections present several technical ap proaches to enhanced and dedicated mercury controls. These include technologies that improve the mercury capture capabilities of existing equipment, primarily through methods that help oxidize increasingly larger fractions of the mercury in the flue gas (Section 1.3), as well as the use of dedicated sorbents in various system configurations (Section 1.4).Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-14



### 1.3. Oxidation Enhancement in Flue Gas
Oxidation of Hg 0 in the flue is affected by many factors as describ ed previously. These include plant-specific equipment and operating cond itions, as well as fuel quality characteristics. Increased oxidation can be promoted by several diff erent methods. Most of the development has concentrated in two general areas: 1) chemical addi tives designed to maximize the oxidation of Hg 0 in the flue gas; and 2) fixed bed oxidation cataly sts.
The majority of the work involving enhanced oxidati on techniques has been focused on plants with wet FGD systems, where the oxidized mer cury is subsequently captured. The “reemission” of Hg 0 after Hg 2+ has been captured and chemically reduced in the sc rubber has been observed and can be addressed by the use of additiv es to the scrubber.



### 1.3.1. Chemical Additives

Boiler Additives One approach for enhancing mercury oxidation in the flue gas is the use of boiler additives that may be applied to the coal and the f lue gas to promote Hg 0 oxidation. Much laboratory, pilot-scale and full-scale work has bee n done and reported on boiler additives. 10-15 NETL sponsored projects were awarded in three Phase s, with the Phase I starting in 2000, Phase II in 2003 and Phase III in 2006. 10 Table 1-4 summarizes some of the more recent work in Phases II and III, as well as other relevant work.
Boiler additives for Hg 0 oxidation are often referred to as sorbent enhance ment additives (SEAs) or oxidation additives (OAs). Most of the t esting of these additives undertaken under NETL sponsorship was conducted by the Energy & Envi ronmental Research Center (EERC) and URS Corporation. These additives are typically spr ayed onto the coal in an aqueous salt solution. Spraying the chemical on the coal prior to combustion maximizes the residence time for the reactions with Hg 0 in the flue gas. When the boiler additives contai ning halogens (like chlorine or bromine) are applied to the coal, the r esults are often reported in terms of the weight of halogen per unit weight of coal, i.e., equivalen t concentration in coal.
The tests at Milton R Young Unit 2 and Monticello U nit 3 were conducted at full scale and included several additives. Milton R Young Uni t 2 used lignite coal in a cyclone boiler and was equipped with a cold-side ESP and wet FGD. Ini tially three boiler additives were tested: SEA1 (calcium chloride - CaCl 2 ); 2) SEA2 (proprietary chemical); and 3) magnesium chloride (MgCl 2 ). Total Hg capture in the ESP/wet FGD was 44% wit h the additive SEA2 at an injection level of 75 ppmw (equivalent concentration in coal) . Injecting SEA2 at 50 ppmw and adding PAC at a rate of 1 pound per million actual cubic f eet (lb/MMacf) resulted in total Hg removal of 60%. The SEA1 and MgCl 2 additives at 500 ppmw (equivalent Cl in coal) only produced 20% mercury removal. In long-term tests (30 days), Hg capture across the ESP/wet FGD configuration ranged from 50 to 65% with SEA2 injec tion at 60-100 ppmw and activated carbon at 0.15 lb/MMacf

.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-15

Table 1-4. Recently published testing with boiler additives to enhance Hg 0 oxidation 10-15

Project Company Unit (MW ) (Date) Coal APCD Configuration Milton R Young Unit 2 (475MW) (2005-07) ND Lignite Cold-side ESP - wet FGD Mercury Oxidation Upstream of ESP and wet FGD EERC

Monticello Unit 3 (593MW) (2005-07) TX Lignite/PRB Blends Cold-side ESP - wet FGD

Monticello Unit 3 (590MW) (2005-07) TX Lignite/PRB Blends Cold-side ESP - wet FGD

Plant Yates Unit 1 (120MW) Low-sulfur Bituminous Cold-side ESP - wet FGD Field testing of FGD additives URS

Petersburg Unit 2 (470MW) (2005-07) High-sulfur Bituminous Cold-side ESP - wet FGD

Hawthorne Unit 5 (565MW) PRB SCR-SD-FF Long-term demonstration of SEA technology for mercury control EERC

Mill Creek Unit 4 (545MW) (2006-07) High-sulfur Bituminous SCR-Cold-side ESP-wet FGD

Full scale results from Alstom’s KNX TM technology Alstom Pleasant Prairie (600MW) (2007-08) PRB SCR-Cold-side ESP-wet FGD

Mercury control using B&W Absorption Plus(Hg) TM B&W Elmer Smith Station (440MW) (2008) Bituminous SCR-Cold-side ESP-wet FGD Impact of HBr injection on Hg speciation and capture ICSET ICSET (slip stream) (2008) SCR/ESP

Mercury oxidation upstream of ESP and wet FGD EERC Milton R Young Unit 2 (475MW) (2005-07) ND Lignite Cold-side ESP - wet FGD

EERC = Energy & Environmental Research Center SEA = Sorbent enhancement additive ICSET = Institute for Combustion Science and Enviro nmental Technology at Western Kentucky University Monticello Unit 3 burned blends of lignite and Powd er River Basin (PRB) subbituminous coals and employed a similar ESP/wet FGD configurat ion to Milton R Young. Two additives were evaluated: OA1 (CaCl 2 ); and OA2 (CaBr 2 ). CaBr 2 proved very effective in parametric testing, yielding 72% Hg 2+ at the ESP outlet at an injection level of 100 ppm w (equivalent Br concentration in coal). Follow-up longer-term (two weeks) testing confirmed the expected performance of CaBr 2 . At a relative concentration of 55 ppmw coal equi valent Br, CaBr 2 resulted in 67% oxidation of Hg 0 upstream of the wet FGD and 65% total capture in t he scrubber. Injection rates of 113 ppmw and 330 ppmw increased total capture in the scrubber to 86% and 92%, respectively. Figure 1-12 summarizes the key results from these programs. (Note: no data were reported for Monticello for Hg 0 oxidation at the 330 ppm CaBr 2 additive rate.)Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-16

Figure 1-12. Hg removal and oxidation results with various additives at Milton R Young

(left) and Monticello (right) power plants 10

EERC conducted a test program at San Miguel station to evaluate several Hg sorbents and oxidation additives. 11 San Miguel station had a 450 MW boiler with an ES P-wet FGD configuration and fired Texas lignite coal. The fu ll-scale portion of the test program followed a pilot-scale program where several chemicals (sorben ts and boiler additives) were evaluated. For the full-scale tests, the focus was on additive SEA 2 and PAC. The results showed Hg removal of up to 78% with SEA2 at 50 ppmw and PAC at 4 lb/MMac f injection rates.
At this plant, as at others, there was a significan t increase in the concentration of Hg 0 at the wet FGD outlet as compared to the inlet with 3 μg/Nm 3 measured at the inlet and 7 μg/Nm 3 at the outlet. Wet FGDs are effective at absorbing oxidized Hg species from the flue gas. Some of the absorbed Hg 2+ can be reduced in the scrubbing solution to elemen tal Hg. Because Hg 0 is not very soluble in aqueous solutions, this Hg 0 goes into the gas phase in the outlet gas. This phenomenon has been called “Hg re-emission,” and it is evident in the San Miguel data.

Alstom’s KNX TM technology 12,13 is bromine-based (CaBr 2 ) which has been shown to be quite effective. The additive was added to the coa l prior to combustion in the boiler, typically sprayed on the coal either on the conveyor or at th e coal feeders (upstream of the mills). As with any application of this type, it is important to en sure that the method of application yields a uniform distribution of the chemical on the coal.

Tests at two PRB-fired boilers, Holcomb and Meramec , indicated KNX TM performance consistent with the results shown in Figure 1-13. 14 In these two cases, however the plant APCD configurations did not include a wet FGD. Holcomb employed a spray dryer-fabric filter (SDFF) combination and had very low unburned carbon an d low native Hg oxidation (about 20% at the APH outlet) and overall collection. PAC inject ion at the rate of about 1 lb/MMacf yielded Hg capture across the SD-FF of about 50%. KNX TM was successful in increasing Hg oxidation at the air preheater outlet to 80% and total Hg col lection to 86%.

Meramec, on the other hand, had about 2% to 4% unbu rned carbon, which is high relative to typical PRB firing, and the boiler employed only an ESP for particulate control. The native Hg capture was about 40%. With KNX TM injection, the overall capture increased to over 8 0%. Figure 1-13 shows these results.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-17

Figure 1-13. Hg oxidation at air preheater outlet (Holcomb) and removal across APCDs at

two PRB-fired plants with SD-FF (Holcomb) and ESP ( Meramec) 12

More detailed tests were conducted by Alstom at Ple asant Prairie in Wisconsin, a plant with two 600 MW PRB coal-fired boilers equipped wit h SCR-ESP-wet FGD.13 In these tests, varying concentrations of KNX TM were tested with the results shown in Figure 1-14. Mercury reductions of more than 90% were achieved with addi tive concentrations of less than 20 ppmw (coal equivalent Br).

Figure 1-14. Mercury removal at Pleasant Prairie w ith KNX TM injection 12,13

CaBr 2 is an attractive boiler additive for oxidizing Hg in low-rank (subbituminous and lignite) coal applications. However, secondary eff ects of adding bromine to the coal need to be considered. For example, high-temperature corrosio n of convective pass equipment (e.g., superheaters) due to high halogen-content fuels is well known. At coal chlorine levels below 2000 ppmw, this potential problem seems to be negli gible. Most U.S. coals have Cl contents below 2000 ppmw (see Figure 1-8). Therefore, at th ese low levels of Br addition, it is expectedTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-18

that no increased corrosion potential would result. However, long-term data on corrosion behavior when bromine compounds are injected to the boiler has not yet been collected.
Hydrogen bromide (HBr) has been investigated as a s uitable boiler additive to affect the speciation of mercury in power plant flue gas. 15 Slip stream tests were conducted at the Institute for Combustion Science and Environmental Technology (ICSET) at the University of Western Kentucky to evaluate the potential of HBr to oxidiz e Hg 0 in the flue gas and increase its capture in fly ash. Fly ash was injected into the slipstre am reactor. The tests were conducted at two temperature regimes (350 ° C and 150 ° C) and used low-Cl coals (average concentrations be tween about 120 ppmw and 165 ppmw) as well as several fly ashes, to determine the effect on the capture of Hg. Hg measurements were conducted usin g the Ontario Hydro method as well as using a CEMS. Both Hg 0 oxidation and in-flight Hg capture in fly ash were observed. The HBr rate of injection was up to 6 ppmw for the high tem perature test (350 ° C) and up to 4 ppmw at the lower temperatures (150 ° C). HBr was injected in gaseous and solution forms . Lastly, corrosion test coupons (metal strips placed in the process st ream to measure the state of corrosion) were used to address potential Br induced corrosion issu es.

The results indicate that HBr was effective in oxid izing Hg 0 and enhancing Hg capture in fly ash. Specifically, Hg 0 oxidation rates of up to 60% and 90% were achieved at low and high temperature, respectively, with HBr injection rate of 4 ppmw. Further, Hg capture in fly ash yielded varying results for different fly ash types and fly ash concentrations ranging from about 40% to about 80%. Corrosion test coupons were anal yzed by scanning electron microscopyenergy dispersive X-ray (SEM-EDX) analysis and prel iminary results suggested no negative impacts at the tested HBr concentration levels.

Wet FGD Additives

Several additives have been tested to demonstrate t heir effectiveness in mitigating the reemission of Hg 0 in wet scrubbers. The additives help precipitate the absorbed Hg as a stable salt, minimizing the re-emission of Hg 0 and lowering the concentration of Hg in the FGD li quor. As shown in Table 1-4, tests have been conducted at Mo nticello Unit 3 (pilot-scale), Plant Yates Unit 1 (pilot- and full-scale), Petersburg Unit 2 ( full-scale), and Mill Creek Unit 4 (full-scale). Of the various additives tested, Babcock and Wilcox ’s (B&W’s) Absorption Plus(Hg)TM yielded the most successful results during long-term testin g, with Hg capture in the scrubber increasing from about 80% (without the additive) to 92%. Note that Mill Creek fired a bituminous coal with moderate chlorine, which resulted in a higher fraction of Hg 2+ in the flue gas which explains the high baseline Hg removal (80%) in the scrubber. Figure 1-15 shows the results of the B&W Absorption Plus(Hg) TM technology at Mill Creek Unit 4 from the NETL test program.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-19

Figure 1-15. Test results for wet FGD Hg 0 re-emission addtive at Mill Creek Unit 4 16

Another recent application of an Hg 0 re-emission additive was undertaken at Elmer Smith station. 16 The Elmer Smith station is a 445 MW station compr ised of two boilers (one cyclone and one tangential-fired) firing eastern bituminous coal. The shared APCD configuration consists of SCR/SNCR, cold-side ESP, and wet FGD. The Absorption Plus(Hg) TM additive demonstrated its effectiveness in minimizing Hg 0 re-emissions from the wet FGD. The total Hg (HgT) capture in the scrubber increased from a base line value of 31% to 83% with the additive, because there was less re-emission of Hg 0 when the additive was used. The capture of the Hg 2+ in the flue gas by the FGD was similar with and wit hout the Hg 0 re-emission additive (91% baseline and 99% with the additive). The major cha nge with the re-emission additive was that Hg 0 did not increase across the FGD. Operationally, t he Hg 0 re-emission additive did not affect SO 2 removal or gypsum quality. Figure 1-16 summarizes these results.

Figure 1-16. Hg removal across the FGD and mitigat ion of Hg 0 re-emission with

Absorption Plus(Hg) TM at Elmer Smith station 16



### 1.3.2. Fixed-bed Oxidation Catalysts Fixed-bed Hg oxidation catalysts employ different c atalyst materials including vanadium (V)/titanium (Ti), gold (Au), and palladium (Pd). Conventional SCR NOx catalysts have been shown to promote some oxidation of Hg 0 . However, typical formulations for SCR catalysts are developed to balance, among other things, NOx reduc tion while keeping the undesirableTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-20

oxidation of SO 2 to SO 3 to minimum levels. Unfortunately, Hg 0 oxidation and SO 2 conversion across the SCR catalyst are strongly correlated, as shown in Figure 1-17. 17 This has led to the development of dedicated of Hg 0 oxidation catalysts.

Figure 1-17. Relationship between SO 2 conversion and Hg 0 oxidation across SCR catalyst 17

The application of Hg oxidation catalysts is simila r to that of commonly used SCR catalysts. Depending on catalyst formulation and o ther plant considerations, applications of dedicated Hg oxidation catalysts upstream (similar to SCR temperatures of 600 ° F to 700 ° F) and downstream of the air preheater (APH) at temperatur es on the order of 300 ° F are possible. Figure 1-18 shows a sketch of a typical configurati on downstream of the air preheater. 19 In general, other design and operating concerns associ ated with SCR are common to Hg 0 oxidation catalysts. These include gas flow conditions, such as uniformity and velocity, and control of ash deposition (i.e., sootblowers). Plant operators ha ve significant experience with these concerns based on over 140 GW of operating SCR installations

.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-21

**Air**
**Preheater**

Figure 1-18. Typical Hg 0 oxidation catalyst application in ESP-wet FGD plan t 19

The current level of Hg 0 oxidation catalyst technology demonstrations is st ill relatively small compared to the more wide spread deployment o f sorbent injection technologies (discussed in Section 1.4). However, much laboratory and pilo t-scale work has been done and limited fullscale testing has been reported. 10,17,18,19 Table 1-5 summarizes the more recent work on Hg 0 oxidation catalysts.

Table 1-5. Recent published testing with Hg 0 oxidation catalysts 10,17,18,19

Project Company Unit (MW ) (Date) Coal APCD Configuration
Monticello Unit 3 (590MW) (2004-07) Lignite/PRB Cold-side ESP - wet FGD

Plant Yates Unit 1 (120MW) (2004-07) Low-sulfur Bituminous Cold-side ESP -

wet FGD Pilot/Full-scale testing of Hg Oxidation Catalyst URS Group

Fayette Unit 3 (460MW) (2008) PRB Blends Cold-side ESP - wet FGD

Pilot/Full-scale testing of Hg Oxidation Catalyst Hitachi Power

Systems America Northern U.S. Power

Plant (640MW) (2006-08) PRB Cold-side ESP - wet FGD

Pilot-scale testing of Hg removal in CT-121 FGD (w/SCR) Chiyoda

Corporation/SCS Plant Crist/MRC

(~2MW) (2007-08) (simulated flue gas) SCR - Cold-side

ESP - wet FGD

PRB = Powder River Basin The results of the earlier pilot tests at both Mont icello and Plant Yates, as well as the initial pilot tests at Fayette have been well docum ented and recently summarized. 10 These testTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-22

programs were sponsored by NETL under Phases II/III Field Testing and Mercury Control Technology projects. Highlights from these tests a re summarized below.
Several Hg 0 oxidation catalysts were tested at Luminant’s Mont icello Station Unit 3, which fires a blend of Texas (TX) lignite and PRB c oals. In 2005, Hg 0 oxidation catalysts were installed downstream of the cold-side ESP and inclu ded the following catalysts: (1) Au; (2) V-Ti SCR; (3) regenerated Pd; and (4) fresh Pd.
Results were encouraging with the Pd catalyst yield ing about 72% Hg 0 oxidation, while the Au catalyst achieved 66% oxidation after about 17 months of operation. With respect to Hg capture in the wet FGD, the pilot-scale results ran ged from 76% to 87%, a significant improvement compared to the baseline performance (e .g., no catalysts) of only about 36%.
At Plant Yates, firing low-sulfur bituminous coal, the menu of catalysts tested included Pd, fresh and regenerated Au, as well as SCR cataly sts, located downstream of a cold-side ESP pilot unit. The results after about 11 months of o peration showed Hg 0 oxidation ranging from 26% for the regenerated Au catalyst to58% for fresh Au catalyst. The SCR and Pd catalysts yielded oxidation values of 32% and 38%, respective ly.
Figure 1-19 and Figure 1-20 show these results grap hically for Hg 0 oxidation across the catalysts and the resulting improvement in total Hg removal in the wet FGD.

Figure 1-19. Summary of NETL Hg 0 oxidation catalyst test results from slipstream te sting at Monticello and Yates power plants 10Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-23

Figure 1-20. Impact of Hg 0 oxidation catalysts on total mercury removal by we t FGD, pilot-scale testing at Monticello 10

These results clearly indicate the importance of ma ximizing the Hg 2+ at the wet FGD inlet to enhance the overall Hg removal effectivene ss of wet FGD. However, these are pilotscale test results, intended to provide a basis for full-scale designs and applications. At present there is not a significant database of full-scale e xperience with Hg 0 catalysts. Two full-scale test programs have been reported recently that include s ome field test data. One is NETL’s project at Fayette Unit 3. The other describes work performed by Hitachi Power Systems America at an undisclosed U.S. power plant. Brief summaries of t he available results follow.
In May 2008, URS Corporation carried out a program at the Lower Colorado River Authority’s (LCRA’s) Fayette station Unit 3, 19 which was designed to evaluate catalyst performance in PRB coal flue gas, as well as to bet ter understand full scale operation and maintenance (O&M) issues such as catalyst de-activa tion and ash deposition mitigation. The project involved the deployment and testing of an H g 0 oxidation catalyst installed downstream of a cold-side ESP and upstream of one of three wet FG D modules at the station. This was nominally a 200 MW equivalent demonstration. The c atalyst was a gold-plated, solid honeycomb type and was installed at the inlet to on e of the scrubber modules (the diagram in Figure 1-18 depicts the overall configuration). Th e test plan required monitoring of the pressure drop across the catalyst over time and mercury meas urements to determine Hg 0 oxidation, as well as total Hg removal in the wet FGD. The confi guration permitted a direct comparison between the mercury removal across the two modules without the Hg 0 oxidation catalyst (A/B) and the test module (C). Tests were conducted usin g Ontario Hydro Method measurements. The key results between May 2008 and June 2009 are summ arized in Table 1-6.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-24

Table 1-6. Hg oxidation and removal - summary of r esults at Fayette Unit 3

PARAMETER May 2008 Nov 2008 June 2009
Catalyst Inlet Oxidation (%) 35 ± 9 52 ± 7 44 ± 7 Predicted Hg oxidation (%) 81 81 81
Measured Hg oxidation (%) 80 ± 9 77 ± 4 52 ± 5 Hg oxidized at catalyst outlet (%) 86 ± 6 90 ± 1 74 ± 1 Hg removal - module C (w/ catalyst) (%) 80 ± 5 49 ± 4 71 ± 5 Hg 0 re-emission - module C – (% of Hg 2+ ) 5 ± 11 41 ± 3 3 ± 9 Hg removal - modules A/B (w/o catalyst) (%) 34 ± 18 37 ± 9 44 ± 8 Hg 0 re-emission - modules A/B – (% of Hg 2+ ) 23 ± 45 28 ± 9 2 ± 7 Hg removal – module C vs. A/B (% increase) 60 ± 13 18 ± 6 48 ± 11

While these results are not fully understood, some general comments can be made.

• Catalyst activity (i.e., measured Hg oxidation) dropped from about 80% to 52% over time. This was thought to be possibly driven by catalyst blockage due to fly ash deposition on the catalyst.

• Mercury removal across module C showed a significan t increase from November 2008 to June 2009 (49% to 71%) which is consistent with the decrease Hg 0 reemissions during the same period (41% to 3%). Hg 0 re-emissions result from reactions between the Hg 2+ absorbed in the liquor and sulfite/bisulfate in th e liquor. It has been suggested that the higher leve ls of Hg 2+ in the FGD liquor in November 2008 as compared to May 2008 and June 2009 may explain the reemission levels and associated overall mercury remo val. Other variables can also account for re-emissions from wet FGD, including pH , chloride concentration, and the amount of slurry solids.

• Despite these uncertainties, the increased effectiv eness in mercury removal from module C (w/catalyst) over modules A/B (w/o catalys t) was significant and supported the importance of minimizing the presence of Hg 0 for best mercury removal in wet FGD systems.
Operationally, it was reported that increased press ure loss across the catalyst due to fly ash build up required better sootblowing schemes an d was likely to account for the loss in catalyst activity over the test period.
Hitachi also has developed a new SCR catalyst to en hance Hg 0 oxidation, while keeping SO 2 /SO 3 conversion low. 17 Its technology, TRAC TM (TRiple Action Catalyst) was tested at a power plant in the U.S., first in a slip-stream rea ctor and subsequently at full scale. The unit was a 640 MW, wall-fired boiler, firing PRB coal at an undisclosed location. The APCD equipment was configured in a conventional SCR-ESP-wet FGD ar rangement.
The slip stream reactor included a four layer catal yst configuration and ran for about 8,000 hours. The results were very encouraging wit h Hg 0 oxidation rates ranging from about 95% initially to about 80% after 8,000 hours (see F igure 1-21).Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-25

Figure 1-21. Slipstream TRAC TM catalyst performance Hg oxidation vs. time 17

The full-scale application of TRAC TM involved replacing one of the three original catalyst layers with one layer of TRAC TM catalyst. The test program included measurements of Hg speciation at the inlet (through the plant’s Hg CEMS) and at the outlet of the wet FGD, and comparing results with similar testing prior to the TRAC TM installation. The results confirmed the slip stream tests and suggested the suitability of this approach to enhancing Hg 0 oxidation (and subsequent removal with wet FGD). Figure 1-22 summarizes the results. Hg 0 oxidation increased significantly. The percentage of oxidize d mercury (Hg 2+ /Hg total) went from 40% before TRAC TM to about 70% with the TRAC TM catalyst, while overall mercury capture in the wet FGD increased from 30% to about 70%. It should be noted that the reported results represent short-term testing and do not address any potential long-term issues.

Figure 1-22. Hg oxidation and removal with full sa le TRAC TM catalyst 640 MW, wall-fired

boiler, firing PRB coal at an undisclosed location 17Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-26



### 1.4. Sorbent Injection

1.4.1. Sorbents for Mercury Control Injection of powdered sorbents upstream of particul ate matter control devices is the most promising mercury capture technology for plants wit hout FGD scrubbers. Powdered activated carbon (PAC) is the most widely studied sorbent, bu t other non-carbon based sorbents are also being developed. Activated carbon injection is rel atively simple to install. The equipment consists of a silo, a feeder, a blower (for carrier air), hoses and injection lances. Activated carbon is typically injected either upstream or dow nstream of the air preheater, as shown in Figure 1-23, so that the sorbent can be collected i n the particulate collector.

Boiler

Burners Air

Heater

Particulate Collector SO 2 Scrubber Stack

SCR Boiler

Burners Air

Heater

Fuel

Particulate Collector SO 2 Scrubber Stack

SCR Activated Carbon Injection

Figure 1-23. Application of activated carbon injec tion
Various mercury sorbents are described in Table 1-7 . Mercury is readily adsorbed on carbon surfaces. PAC is a good adsorbent for mercu ry due to its large surface area (due to open pore structure and fine particle size). Activated carbons are made from coal or biomass and may be chemically treated to enhance mercury removal. Halogens (chlorine, bromine, iodine) and sulfur have been used as additives in activated car bons. Studies have shown that several factors influence the mercury adsorption capacity of PAC. These factors include temperature, mercury concentration and oxidation state, sorbent particle size, and flue gas composition (moisture, NOx, and most notably SO 3 ).Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-27

Table 1-7. Description of mercury sorbents
Sorbent Vendor Description
Power Pac Premium ADA-ES Brominated activated carbo n Mer-Clean TM Alstom Power Proprietary carbon-based, chemically t reated sorbent
Amended Silicates TM Amended Silicates Mineral-based sorbent BS IAC (CB 200xF TM ) Barnebey Sutcliffe Iodated activated carbon manuf actured from coconut shells BS SAC (208CP TM ) Barnebey Sutcliffe Iodated super activated carbon manufactured from coconut shells BASF (MS-200) BASF Mineral-based sorbent Calgon HGR-LH TM Calgon Carbon Iodated carbon
FLUEPAC ® MC Calgon Carbon Activated carbon made from bitumi nous coal
FLUEPAC ® -MC PLUS Calgon Carbon Brominated activated carbon
FLUEPAC ® CF Calgon Carbon “Ash-Friendly” activated carbon
FLUEPAC ® -CF PLUS Calgon Carbon “Ash-Friendly” activated car bon made with a proprietary ingredient
FLUEPAC ® ST Calgon Carbon Activated carbon specially formul ated for use in flue gas with elevated SO 3 DARCO ® Hg Norit Americas Activated carbon made from Texas lignite Insul Norit Americas Fine particle size, chemically washed activated carbon HydroDARCO-C Norit Americas Coarser version of DARC O Hg
DARCO ® Hg XTR Norit Americas Low-activity lignite-based a ctivated carbon
DARCO ® Hg-LH Norit Americas Brominated activated carbon m ade from Texas lignite
DARCO ® Hg E-XX Norit Americas Experimental sorbent
PAC2B Norit Americas Subbituminous/bituminous blend activated carbon NH Carbon Ningxia Huahui Activated Carbon Co., Ltd Iodated activated carbon from China

Super HOK RWE Rhinebraun Activated carbon made from German lignite
B-PAC TM Albemarle Brominated activated carbon
C-PAC TM Albemarle Brominated activated carbon designed to have low impact on ash
H-PAC TM Albemarle Brominated activated carbon optimized fo r hotside ESP temperature regime Q-PAC TM Albemarle High performance brominated activated ca rbon
FF-PAC TM Albemarle Brominated activated carbon designed for systems with FF

The U.S. Government Accountability Office (GAO) rep ort in 2009 identified 14 coalfired power plants that operate sorbent injection s ystems on 25 boilers. 20 Although injection of untreated carbon-based sorbents works well for plan ts burning bituminous coal, this control strategy is not as effective for plants burning sub bituminous or lignite coals. Chemically treated sorbents are able to achieve high mercury reduction s across all coal types (ranks). The U.S. GAO report also identified several power plant conf igurations for which mercury control by sorbent injection might be difficult, including uni ts with high SO 3 concentrations in the flue gas (which prevents mercury from binding to carbon sorb ents), hot-side ESPs (high temperatures reduce the ability of mercury to bind to sorbents), and those burning lignite coal (which releasesTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-28

high levels of elemental mercury). These units mig ht require alternate technologies for mercury control or improvements in existing technologies to achieve higher levels of mercury control.
A variety of companies design and install PAC injec tion systems for mercury control. Companies that produce PAC also design PAC injectio ns systems, both permanent and temporary. ADA-ES claims to have sold over 140 PAC injection systems for mercury control in power plant boilers. 21 Albemarle Sorbent Technologies, another supplier of PAC, has started up over 50 PAC injection systems. 22 A number of equipment vendors that do not sell PA C do design and install injection systems. For example, Sargent & Lundy claims to have installed 57 PAC injection systems. 23



### 1.4.2. Sorbents Injection and Cold-Side ESPs The majority of boilers in the U.S. are equipped wi th cold-side ESPs. This configuration can offer several challenges for mercury control by sorbent injection. Demonstrations have been performed at several power plants with cold-side ES Ps burning a variety of coals, as shown in Table 1-8. The biggest challenge arises with high levels of SO 3 in the flue gas, due either to burning high-sulfur eastern bituminous coal, oxidat ion of SO 2 in an SCR, or direct injection of SO 3 for improved ESP performance. Temperature and flu e gas SO 3 concentrations directly influence the mercury removal efficiency of sorbent injection. The majority of f ull-scale tests have been done at plants where SO 3 concentrations limit sorbent injection mercury rem oval efficiencies. Based on the survey of the U.S. boil er population (Section 1.1.3), 15% of boilers in the U.S. use flue gas conditioning (FGC) on cold-si de ESPs.
Several tests have been performed at various power plants to investigate alternatives to enhance mercury removal from flue gas with high SO 3 concentrations. 24 ADA-ES worked with DOE/NETL, EPRI, and several electric generating pla nt partners at the American Electric Power’s (AEP) Conesville Unit 6 (high-sulfur coal), Public Service of New Hampshire (PSNH) Merrimack Unit 2 (medium-sulfur coal and SCR), and Ameren Labadie Unit 2 (SO 3 injection for flue gas conditioning). These three plants exempli fy the possible causes of elevated SO 3 in the flue gas.
Conesville Unit 6 fired a high-sulfur coal (3-4%) a nd native mercury capture across the ESP was low (1% to 20%). There was typically 60% t o 70% oxidized mercury at the ESP outlet, most of which was captured in the wet FGD. Native SO 3 concentration was typically above 20 ppmv. More than 20 sorbents or combination of sorb ents were tested at injection rates of 9-18 lb/MMacf. Injection of 9.5 lb/MMacf DARCO ® Hg resulted in 8% removal. The highest removal was 31% using DARCO ® E12 (experimental lignite-based activated carbon c hemically treated with basic materials to provide buffering a gainst SO 3 condensation) at 12 lb/MMacf. No sorbent was able to achieve the goal of 50% removal at injection rates <10 lb/MMacf.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-29

Table 1-8. List of sorbent injection demonstration sites with cold-side ESPs

Plant name Blr

ID State Unit

MW Primary boiler

fuel Particle Ctrl ESP SCA, ft 2 /kacfm FGC SO 2

Ctrl NOx

Ctrl:PostCombu stion Baldwin 3 IL 635 PRB FF/CSE 247 Yes Brayton Point 1 MA 241 MSEB FF/CSE 559 Yes SDA SCR Coal Creek 1 ND 605 ND Lignite CSE 599 No wFGD

Conesville 6 OH 444 HSEB CSE 301 No wFGD SCR

Crawford 7 IL 239 PRB CSE 112 No

Victor J Daniel Jr 1 MS 500 PRB/LSEB CSE -- No SNC R

Dave Johnston 3 WY 230 PRB FF/CSE 629 No wFGD

Hoot Lake 3 MN 75 PRB CSE -- No Independence 2 AR 850 PRB CSE 540 No

Labadie 2 MO 574 PRB CSE 279 Yes

Lee 1 NC 75 MSEB CSE 300 Yes

Lee 3 NC 253 LSEB CSE 300 Yes Leland Olds 1 ND 570 ND Lignite CSE 320 No Limestone 1 TX 813 TX Lignite/PRB CSE -- No wFGD

Meramec 2 MO 138 PRB CSE 376 No

Merrimack 2 NH 346 MSEB CSE 350 No SCR

Miami Fort 6 OH 163 HSEB CSE 353 No SNCR Milton R Young 2 ND 477 ND Lignite CSE 375 No wFGD

Monroe 4 MI 817 PRB/MSEB CSE 285 Yes SCR

Pleasant Prairie 2 WI 617 PRB CSE 468 Yes wFGD SCR

Portland 1 PA 172 HSEB CSE 284 No Salem Harbor 1 MA 82 LSB (S.American) CSE 474 No S NCR

Shawville 3 PA 188 HSEB CSE -- No SNCR

St Clair 1 MI 169 PRB/HSEB CSE 467 No

Stanton 1 ND 172 PRB CSE 470 No Stanton 1 ND 172 ND Lignite, PRB CSE 470 No

Yates 2 GA 123 MSEB CSE 149 Yes

Yates 1 GA 123 MSEB CSE 173 Yes wFGD

HSEB = High-sulfur eastern bituminous

MSEB = Medium-sulfur eastern bituminous

LSEB = Low-sulfur eastern bituminous

PRB = Powder River Basin subbituminous

The SCR-generated SO 3 level at Merrimack Unit 2 was typically between 20 and 25 ppmv, which resulted in low native mercury removal usually less than 10%. The mercury capture was affected by the SO 3 concentration and the APH cold-end average (CEA) temperature. When the APH outlet temperature was l owered from approximately 330 o F to 315 o F, mercury removal increased, but reduction of SO 3 concentrations in the flue gas had a larger effect on Hg removal. Mercury removal by PA C was significantly increased with coinjection of SO 3 sorbent as shown in Figure 1-24. Trona injection reduced SO 3 concentration to 7-8 ppmv. Mercury capture can be improved with opt imization of the trona injection system, but long-term balance of plant impacts must be consider ed. Balance of plant impacts seen atTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-30

Merrimack when injecting PAC and/or SO 3 sorbent included deterioration of ESP performance, increased pressure drop across the APH, increased s odium content in the fly ash when injecting trona (more limitation on fly ash utilization), and smoldering fly ash/PAC in the ESP hoppers

.

0 10 20 30 40 50 60 70 80 90 100

0 5 10 15 20% Vapor-phase Removal

Sorbent (lb/MMacf) Merrimack 2, Darco Hg-LH
Merrimack 2, Darco Hg-LH, Trona, normal CEA
Merrimack 2, Darco Hg-LH, Trona, low CEA
Merrimack 2, Darco Hg-LH, Mill Trona, low CEA
Merrimack 2, Darco Hg-LH, APH In, normal CEA

Effect of SO 3 Effect of temperature Effect of milling

Figure 1-24. Mercury removal across ESP at Merrima ck Unit 2, combinations of Darco Hg-LH and trona sorbents
Recent data on carbon injection presented by Sjostr om et al. 25 showed that injection of activated carbon upstream of the air preheater does not always improve mercury removal in boilers using SO 3 injection for flue gas conditioning. Testing was carried out at a 200 MW PRBfired boiler with a cold-side ESP. Parametric test ing of brominated PAC injections showed mercury removals from 21% at 0.85 lb/MMacf to 58% a t 8.2 lb/MMacf when injected at the APH inlet, with the FGC system in service. Mercury removals were similar when PAC was injected at the APH outlet. The air preheater outl et temperature was 350 ° F to 375 ° at full load at this plant. This high outlet temperature could hav e contributed to the lack of improvement of mercury removal when PAC was injected upstream of t he air preheater: the temperature in the air preheater might have been too high for signific ant mercury removal. When the FGC system was not in service (i.e., no SO 3 injection), mercury removals from PAC injection in creased. For example, at PAC injection rates of 3.3 and 4.1 lb/M Macf, mercury removals were 40% and 44%, respectively, with the FGC system in service; with the FGC system out of service, the mercury removals were 66% and 77%, respectively.
Sorbent injection testing at Labadie Power Plant il lustrates the effect of injecting activated carbon in plants that use SO 3 injection for flue gas conditioning. 25 Native mercury removal across the ESP at Labadie was low and most of the mercury was in the elemental form. Figure 1-25 illustrates the results of SO 3 injected downstream of the air preheater and Norit HgLH sorbent injection upstream or downstream of the air preheater. Concentrations of SO 3 are given as percent of full scale on the sorbent injec tion system. Injection of activated carbon upstream of the air preheater has demonstrated high er Hg removal than injection downstream of the air preheater at plants that inject SO 3 downstream of the air preheater for flue gasTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-31

conditioning. This method of injection has not alw ays worked at bituminous plants with high levels of SO 3 at the air preheater inlet. At Merrimack, for exa mple, there was no improvement in Hg removal with DARCO Hg-LH injected upstream of th e air preheater as compared to injection downstream.

0

10 20 30 40 50 60 70 80 90 100

0 5 10 15 20% Vapor-phase Hg Removal

Sorbent (lb/MMacf) Labadie 2, Hg-LH, 0 SO3: APH Outlet Labadie 2, Hg-LH, 30% SO3: APH Outlet Labadie 2, Hg-LH, 60% SO3: APH Outlet Labadie 2, Hg-LH, 0 SO3: APH Inlet Labadie 2, Hg-LH, 30% SO3: APH Inlet Labadie 2, Hg-LH, 45% SO3: APH Inlet Labadie 2, Hg-LH, 60% SO3: APH Inlet Effects of SO 3

Injection upstream of APH

Injection

downstream of APH

Figure 1-25. Removal across ESP at Labadie with in jection of activated carbon as function of SO 3 injection and injection location 25

Figure 1-24 illustrates the improvement in ACI perf ormance at Merrimack when the carbon was milled on-line. Further tests were perf ormed at Independence Unit 2 and Labadie Unit 2 to investigate on-site milling of activated carbon. 26 At Independence, on-site milling also increased mercury removal from 40% to 75% with 0.5 lb/MMacf of DARCO ® Hg-LH injected upstream of the APH and from 60% to 90% with 1 lb/M Macf DARCO ® Hg-LH injected upstream of the APH.

Alstom’s Mer-Cure TM process was developed to improve mercury capture w hen activated carbon is injected upstream of the air preheater. 27,28 Mer-Cure TM uses a processor to mill the sorbent just before the point of injection, which l eads to increase the mass transfer to the sorbent by reducing the size and by de-agglomerating sorben t at the injection point. Alstom reports that it is has carried out more than 12 field test demon strations of the Mer-Cure TM process. Some of these were carried out at plants burning low- to me dium-sulfur bituminous coals. In recent results on bituminous-fired plants in Pennsylvania, Alstom reported approximately 90% removals of mercury at several plants with sorbent injection rates in the range of 4 to 6 lb/MMacf.

The effect of SO 3 sorbents on mercury removal by activated carbon wa s also studied at the Mercury Research Center (MRC) located at Gulf P ower Company’s Plant Crist in Pensacola, Florida. This is a test facility that takes a slip stream of flue gas, equivalent to about 5 MWe, through a series of modules, including SCR, air pre heater, ESP, FF, and wet scrubber. The facility can be configured to bypass some of the mo dules, in order to generate different APCDTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-32

configurations. The plant typically burns a low-su lfur bituminous coal (less than 1 wt% sulfur). The flue gas composition in the slipstream reactor can be changed to some extent by adding SO 3 or HCl.

Recent work at the MRC 29 tested several Calgon sorbents using PAC injection upstream of the ESP with SO 3 injection. Calgon FLUEPAC ® ST, a new sulfur-tolerant sorbent, was tested against a standard brominated activated carbon (Nor it DARCO ® Hg-LH). The baseline SO 3 concentration in the flue gas was not given, but up to 34 ppmv of additional SO 3 was injected during the testing. The FLUEPAC ® ST sorbent performed better than the standard bromi nated sorbents, although both sorbents were affected by S O 3 concentrations (as shown in Figure 1-26). The FLUEPAC ® ST sorbent had an overall higher level of mercury r emoval and, therefore, maintained a higher level of Hg removal as SO 3 increased.

0% 20% 40% 60% 80% 100%

0 10 20 30 40**Hg Removal across ESP**

**ppm SO 3**  **added**

FLUEPAC ST 10 lb/MMacf

Hg-LH 10 lb/MMacf

Figure 1-26. Hg removal at MRC as a function of co ncentration of SO 3 injected into flue gas 29

Several potential solutions to the problem of SO 3 interference with ACI on cold-side ESPs have been proposed. SO 3 -friendly sorbents are being developed, such as Cal gon’s FLUEPAC ® ST. 29 New SCR systems often have improved catalytic con trol or novel catalysts 30

that can minimize the oxidation of SO 2 to SO 3 . In the case of SO 3 for FGC, other options for enhancing ESP performance are being explored, such as ammonia conditioning, water humidification, or rapid onset pulse energization, but these options also have disadvantages. As discussed above, sorbent injection upstream of FGC is a viable option if there is sufficient residence time for in-flight capture and mercury ad sorbed onto the sorbent surface is not displaced by SO 3 . For cases where coal sulfur is the cause of SO 3 rather than FGC, co-injection of alkali minerals (trona, lime, magnesium oxide) t o adsorb SO 3 may improve mercury capture on carbon as at Merrimack. 24 Bituminous plants that burn coal greater than 1.7 wt% S have scrubbers for SO 2 control and are more likely to use these scrubbers rather than sorbent injection to control mercury.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-33



### 1.4.3. Sorbent Injection and Hot-Side ESPs Other configurations that might have problems contr olling mercury emissions by sorbent injection include units with hot-side ESPs. Hot-si de ESPs operate at high flue gas temperatures (600-750°F), which limit mercury capture on sorbent surfaces. High-temperature sorbents are being developed, such as Albemarle Sorbent Technolo gies’ H-PAC. Sorbent injection may be effective downstream of the hot-side ESP, although a dedicated particulate control device must also be installed. The TOXECON TM system (an EPRI-patented technology) involves inje ction of sorbent upstream of a dedicated FF.

A limited number of demonstrations have been conduc ted at units with hot-side ESPs (Table 1-9). All of these tests were conducted by Albemarle Sorbent Technologies. B-PAC TM

was tested at Cliffside Unit 2 31 and H-PAC TM was tested at Buck Unit 6. 32 H-PAC TM , an experimental low-cost version of H-PAC TM , and DARCO ® Hg-LH were tested at Progress Energy H.F. Lee Unit 2. 33 C-PAC TM was tested at Midwest Generation’s Will County Uni t 3. 33

Table 1-9. List of sorbent injection demonstration sites with hot-side ESPs

Plant name Blr

ID State Unit

MW Primary

boiler fuel Particle

Ctrl ESP

SCA, ft2/kacfm SO 2

Ctrl NOx Ctrl:

PostCombustion

Buck 6 NC 125 LSEB HSE 240 -- SNCR

Cliffside 2 NC 40 MSEB HSE -- -- SNCR

Lee 2 NC 75 LSEB HSE -- -- --
Will County 3 IL 299 PRB HSE 200 -- --

MSEB = Medium-sulfur eastern bituminous

LSEB = Low-sulfur eastern bituminous

PRB = Powder River Basin subbituminous

At Cliffside Unit 2, B-PAC TM was injected at various loads ranging from 12-40 M W. 31 Lower load corresponded to lower hot-side ESP inlet temperatures and lower flue gas flow rate. At high load (40 MW, 686°F injection temperature), mercury removal ranged from 16-39% with B-PAC TM injection rates of 1.8-5.7 lb/MMacf. At low load (12 MW, 530°F injection temperature), mercury removal was 78% with 6.2 lb/M Macf B-PAC TM

. Mercury removal at Buck Unit 6 during parametric te sting with 7 lb/MMacf H-PAC TM was 54-64% for loads between 60 MW (540°F injection temperature) and 140 MW (640°F injection temperature). 32 Removal at 140 MW using 7 lb/MMacf DARCO ® Hg was only 3%. During longer testing, 50% removal was seen with 5 lb/MMacf H-PAC TM at 60 MW (540°F) and 140 MW (640°F). Mercury removal increased to 71% w hen the H-PAC TM injection rate was increased to 10 lb/MMacf (60 MW, 540°F). Mercury r emoval with fluctuating injection temperature seemed to be more stable using H-PAC TM instead of B-PAC TM

. Further testing was conducted at Lee Unit 2 and Wil l County Unit 3. 33 The hot-side ESP inlet temperature at Lee averaged 798°F at full loa d (83 MW) and 564 ° F at reduced load (44 MW). At full load, injection of H-PAC TM at rates of 5 and 10 lb/MMacf resulted in mercury removals of 41% and 60% respectively. At reduced l oad, injection of 5-15 lb/MMacf H-PAC TM resulted in removals of 56-84%. The experimental l ow-cost version of H-PAC TM performed similarly at reduced load but showed significantly decreased mercury removal at full load (25%Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-34

at 5 lb/MMacf and 34% at 10 lb/MMacf), although it should be noted that the injection temperature was slightly higher during these tests (809-827°F). DARCO ® Hg-LH did not perform as well as H-PAC TM . Injection of 10 lb/MMacf DARCO ® Hg-LH at full load gave removals in the range of 38-42%. Will County Unit 3 has two boilers: a “reheat” boiler and a “superheat” boiler. Testing was performed on the “ superheat” boiler which has a hot-side ESP inlet temperature between 500°F and 700°F depending on load. Injection of C-PAC TM at rates of 3 and 5 lb/MMacf resulted in mercury reductions of 38% and 55%, respectively.
The dramatic effect of load illustrates the importa nce of temperature and residence time on mercury removal with sorbents. These data sugge st that under normal operating conditions of a hot-side ESP, mercury removal by the current gene ration of activated carbon sorbents is limited and cannot achieve 90% removal without impr ovement in existing technology or development of new technologies.



### 1.4.4. Sorbent Injection and Fabric Filters Sorbent injection upstream of a fabric filter gener ally shows high mercury removal efficiency. The sorbent generally has a long conta ct time with the flue gas as sorbent builds up in the filter cake on the bags. Several demonstrat ions have been performed at units with FFs (Table 1-10), either as a primary particulate contr ol device or in a COHPAC TM configuration (an EPRI-patented technology) in which the FF is instal led downstream of another particulate control device. A COHPAC TM baghouse becomes a TOXECON TM configuration when sorbent is injected upstream of the baghouse.

Table 1-10. List of sorbent injection demonstratio n sites with fabric filters

Plant name Blr

ID State Unit

MW Primary boiler fuel Particle Ctrl SO 2 Ctrl NOx Ctrl:
PostCombustion

E C Gaston 3 AL 272 MSEB FF/HSE -- SNCR Presque Isle 7,6,9 MI 270 PRB FF/HSE -- -- Big Brown 2 TX 593 TX Lignite/PRB FF/CSE -- SNCR Harrington 3 TX 360 PRB, TX Lignite/PRB FF -- --

Tolk 1 TX 568 PRB FF -- SCR

MSEB = Medium-sulfur eastern bituminous

PRB = Powder River Basin subbituminous

Harrington Unit 3 and Tolk Unit 1 both fired PRB co al and had FFs for particulate control. Seven sorbents were tested at Harrington and four were tested at Tolk. 34 At Harrington and Tolk, all brominated carbons tested (B-PAC TM , DARCO ® Hg-LH, FLUEPAC ® -MC PLUS, and C-PAC TM ) performed well and were able to achieve greater t han 80% removal at injection rates of less than 1 lb/MMacf. The non-carbon base d sorbents (Amended Silicates and BASF MS200) did not perform as well at Harrington as the carbon based sorbents.

Alabama Power E.C. Gaston Unit 3 burned bituminous coal and controlled particulate matter with a hot-side ESP followed by a COHPAC TM baghouse. Three non-brominated carbons from Norit Americas were injected between the hot-s ide ESP and the baghouse: DARCO ® Hg, PAC2B (subbituminous/bituminous blend activated car bon), and DARCO ® Insul. 35 There was no discernable difference between the various carbo ns. Mercury removal increased linearly with activated carbon injection rate up to 2 lb/MMacf an d then leveled off at about 90% removal.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-35

Long-term injection of DARCO ® Hg at 1.5 lb/MMacf resulted in an average removal of 78% (mercury removal over the 5-day tests ranged from 3 6% to 90%). The large range in removal was probably due to varying coal and operating cond itions.

The TOXECON TM configuration was further tested at Luminant’s Big Brown Unit 2. 36 Big Brown burns a blend of PRB and Texas lignite co als. Activated carbon (DARCO ® Hg or a proprietary EERC enhanced activated carbon) was inj ected at rates of 0.5-6.5 lb/MMacf. While injecting DARCO ® Hg, mercury removal increased rapidly with activat ed carbon injection rates of up to 3 lb/MMacf (70% removal) and tapered to a maximum removal of 90% with 6.5 lb/MMacf. The enhanced activated carbon performed better and reached 90% removal with 2 lb/MMacf. Month-long injection of 1.5 lb/MMacf enh anced activated carbon resulted in an average removal of 75%.
WE Energies’ Presque Isle Power Plant burns PRB coa l and has a TOXECON TM baghouse installed after the hot-side ESPs on units 7-9. DARCO ® Hg and DARCO ® Hg-LH were injected upstream of the baghouse. 37 DARCO ® Hg-LH (60-95% removal with 0.5-3 lb/MMacf) slightly outperformed DARCO ® Hg (45-90% removal with 0.5-3 lb/MMacf). DARCO ® Hg was also more affected by elevated temperatures . DARCO ® Hg showed a linear relationship between increasing temperature and dec reasing Hg removal (at a given ACI rate, see Figure 1-27). Removal also decreased with an incre ase in time between bag cleaning (at a given ACI rate and temperature).

0 10 20 30 40 50 60 70 80 90 100

300 310 320 330 340 350 360 370%Vapor Phase Hg Removal

Temperature, o F Presque Isle 7-9 6.5 Pressure Drop Set Point

Presque Isle 7-9 6.0 Pressure Drop Set Point

Presque Isle 7-9 5.5 Pressure Drop Set Point

Figure 1-27. Removal of Hg across Presque Isle TOX ECON TM baghouse via injection of Darco ® Hg sorbent 37Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-36

This technology has been set-up to operate on a lon g-term basis. The average mercury removal for 2007 was 90%, achieved using DARCO ® Hg or DARCO ® Hg-LH. Balance of plant impacts include smoldering fly ash/PAC in hoppers a nd fugitive dust emissions during transfer of fly ash/PAC to the ash silo.
Activated carbon injected upstream of a FF can achi eve on the order of 90% mercury removal at plants burning bituminous and subbitumin ous coals, with less than 2 lb/MMacf of activated carbon. Removal across FFs can be sensit ive to temperature. This level of performance has not been demonstrated to date on li gnite plants. In general, less sorbent is required for the same level of mercury removal on a FF as compared to a cold-side ESP, all other things being equal.



### 1.4.5. Sorbent Injection and Spray Dryers Spray dryers (SDs) are installed in combination wit h either a FF or ESP. Full-scale demonstrations have shown that plants with spray dr yers and firing bituminous coal have high native mercury capture while units burning subbitum inous or lignite coals do not. Thus several sorbent injection demonstrations have been performe d at plants burning PRB or lignite coals with spray dryers in an effort to improve mercury c apture (Table 1-11).

Table 1-11. List of sorbent injection demonstratio n sites with spray dryers

Plant name Blr

ID State Unit

MW Primary boiler fuel Particle Ctrl SO 2

Ctrl NOx Ctrl:

PostCombustion

Laramie River 3 WY 570 PRB CSE SD -- Stanton 10 ND 60 ND Lignite FF SD -- Antelope Valley 1 ND 435 ND Lignite FF SD -- Stanton 10 ND 60 ND Lignite, PRB FF SD --

Holcomb 1 KS 349 PRB FF SD --

Hardin 1 MT 116 PRB FF SD SCR

Hawthorn 5A MO 550 PRB FF SD SCR

CSE = Cold-side ESP

PRB = Powder River Basin subbituminous
Stanton Unit 10 burned North Dakota lignite and was equipped with a spray dryer-fabric filter (SD-FF). Four carbon-based sorbents were te sted at Stanton Unit 10: DARCO ® Hg, Desorex HOK300S (German lignite-based carbon), Barn ebey & Sutcliffe IAC (iodated carbon made from coconut shells), and LAC0101 (low-cost ex perimental carbon made from North Dakota lignite). 38 No native mercury removal was measured across the SD-FF. The three untreated carbons (DARCO ® Hg, HOK, LAC) performed similarly but removal acro ss the SDFF was limited to 70% with 6.1 lb/MMacf. During lo ng-term testing, the average removal with 6.1 lb/MMacf DARCO ® Hg was 81%. The treated carbon (IAC) performed mu ch better with removal greater than 90% at 0.7 lb/MMacf.

Sunflower Electric’s Holcomb Unit 1 and Missouri Ba sin Power Project’s Laramie River Unit 3 both fired PRB coal and had spray dryers for SO 2 control. Laramie River had an ESP for particulate control while Holcomb had a fabric filt er. DARCO ® Hg and DARCO ® Hg-LH were injected at Laramie River while DARCO ® Hg, Calgon’s 208CP, and DARCO ® Hg-LH were tested at Holcomb. 39 Mercury removal was limited to 55% with 6 lb/MMac f DARCO Hg at Laramie River. The brominated DARCO ® Hg-LH performed much better and reached greaterTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-37

than 90% removal with 5 lb/MMacf. At Holcomb, the two non-treated activated carbons performed similarly. At injection rates of 1.0 lb/ MMacf upstream of the SD, mercury removal was 50% to 54%. Mercury removal reached 90% with 5 .7 lb/MMacf DARCO ® Hg. Once again, DARCO ® Hg-LH performed better and reached greater than 90 % removal with 1 lb/MMacf.
Brominated carbon injection was tested at Rocky Mou ntain Power’s Hardin Unit 1, which fired PRB coal and was equipped with an SCR f or NOx control, an SD for SO 2 control, and a FF for particulate control. 40 At full load during baseline operation, little na tive mercury removal was seen across the SD-FF and there was no oxidized mercury at the SD inlet or the stack. With reduced load, as much as 50% removal w as seen across the SD-FF corresponding to 50% SD inlet oxidized mercury. Significantly more mercury was oxidized across the SCR at reduced load caused by higher oxygen levels, lower temperatures, and longer residence time within the SCR. Two brominated carbons (DARCO ® Hg-LH and FLUEPAC ® -MC PLUS) were tested at Hardin. For both carbons, 90% mercury ca pture was obtained with injection of 1 lb/MMacf. During long-term testing, between 1.5 lb /MMacf and 2 lb/MMacf (up to 4 lb/MMacf at times) brominated carbon was required to maintai n 90% removal.
Activated carbon in conjunction with a spray dryer- fabric filter is a promising technology for application on plants that combust subbituminou s coal. This combination can achieve more than 90% mercury removal at injection rates that ar e comparable to those rates used with brominated carbons and FFs alone, that is, 1-2 lb/M Macf.



### 1.5. Other Hg Control Technologies
As noted before, activated carbon injection is the most commercially mature control technology of those designed specifically to contro l mercury emissions from coal-fired boilers. Alternate sorbents and technologies are currently u nder development. Most of these are not ready for commercial deployment, but could become s o by the time power plant owners are ready to deploy mercury control technologies. Ther efore, alternate technologies are discussed briefly.



### 1.5.1. Pre-Combustion Removal Western Research Institute (WRI) patented a pre-com bustion mercury removal technology (Patent No. 5,403,365) in which mercury is removed from coal in a two-stage thermal pre-treatment process. 58 The process also removes some of the coal moistur e, which increases the heating value of the coal product, re lative to the feed coal. This increase in heating value can be significant if the feedstock is a high -moisture subbituminous or lignite coal. This removal technology is best suited for plants that c ombust low-rank coals, because mercury in these coals is more likely to be found associated w ith the organic matrix and thus easily volatilized. By contract, the mercury in bituminou s coals is associated with minerals like pyrite. In WRI’s process, the coal is first heated to remov e moisture and then, in a second stage, heated to a temperature of approximately 550 ° F. At this temperature, 60% to 80% of the mercury in subbituminous and lignite coals is volatilized and removed by an inert sweep gas. The sweep gas stream containing the evolved mercury is cooled , passed to mercury capture equipment and the cleaned sweep gas is returned to the process. Bench-scale testing of seven low-rank coals demonstrated mercury removals in the range of 35% t o 89%. A pilot-scale unit, which can handle up to 100 lb/hr of raw fuel, has been run us ing the same coals. It was reported thatTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-38

similar levels of mercury removal were achieved in this pilot-scale unit. Costs have not yet been published for this process.



### 1.5.2. Fixed Adsorption Injecting activated carbon (or other sorbents) crea tes a waste stream, a mixture of sorbent and fly ash, that is enriched in mercury. As discu ssed below, the presence of activated carbon in fly ash can reduce the economic value of fly ash as a by-product. For these reasons, fixed substrates have been developed and tested for the r emoval of mercury from flue gas. Fixed substrates are located downstream of the particulat e control device and thus preserve the economic value of the fly ash. Furthermore, fixed substrates could be regenerated and the mercury could be captured and segregated from the l arger fly ash stream.
Considerable development effort was made in the Mer Cap TM process in which goldcoated structures were used to adsorb mercury. Sli pstream evaluation of the MerCap TM process was carried out at Great River Energy’s Stanton Sta tion and Southern Company’s Georgia Power Plant Yates. 42 The demonstrations used an electroplated layer of gold on a stainless steel screen (substrate). High levels of mercury removals were demonstrated in some cases. Mercury adsorption was affected by temperature and by the p resence of acid gases. The captured mercury could be removed by a thermal treatment and collect ed using a carbon canister or cryogenic trap. Chemical desorption of the mercury from the gold-co ated substrates could also be used as a regeneration technology.
Honeycomb substrates containing carbon-based sorben ts were tested in laboratory and power plant slipstream reactors. 43 Two power plant slipstream tests demonstrated the ability to consistently remove 90% of the mercury from bitumin ous and subbituminous flue gas. Laboratory-scale experiments with simulated flue ga s showed that mercury adsorption was not affected by up to 40 ppm SO 3 in the gas.
More recently, slipstream testing has been carried out on the MercScreen TM process, in which a thin bed of granular sorbent is located in the flue gas downstream of the ESP. Testing was carried out at Southern Company’s Plant Yates a nd Plant Miller. 44 High levels of mercury removal were demonstrated. Estimates of the costs of the MercScreen TM process were competitive with the use of activated carbon and th e TOXECON TM baghouse. Future testing is underway.



### 1.5.3. Multi-Pollutant Processes Powerspan developed the Electro-Catalytic Oxidation (ECO®) technology, which removes NOx, SO 2 , mercury and fine particulate matter, as well as h eavy metals and other hazardous air pollutants. 45 The process is installed downstream of a coal-fir ed power plant’s existing particulate control device. The three-ste p process includes 1) the ECO® Reactor, which oxidizes pollutants; 2) the absorber vessel, which cools the flue gas, removes SO 2 , NO 2 , and oxidized mercury and concentrates the fertilizer co -product; and 3) the wet electrostatic precipitator, which removes acid aerosols, air toxi cs, and fine particulate matter. The ECO® process produces a marketable fertilizer by-product . Powerspan has been operating a 50 MW commercial unit of the ECO® technology at FirstEner gy’s R.E. Burger Plant in southeastern Ohio since February 2004.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-39

J-Power EnTech developed the Regenerative Activated Coke Technology (ReACT). 46 This is a multi-pollutant control technology for co ntrol of SOx, NOx, mercury and particulate matter. There have been a number of industrial and power plant installations in Japan, including J-Power’s (Electric Power Development Co.) Isogo an d Takehara Power Stations. The process involves three steps: 1) adsorption, 2) regenerati on, and 3) by-product recovery. The flue gas contacts a bed of activated coke pellets in an adso rption vessel where the pollutants are removed. The pellets are regenerated in a separate vessel. Removal efficiencies have been reported as up to 99.9% SO2, 20% to 80% NOx, and greater than 90% mercury. Although there are no installations of ReACT in the U.S., Hamon Research- Cottrell has recently entered into a license agreement with J-Power EnTech to market the ReACT t echnology in North America.



### 1.6. Coal Combustion Residues (CCRs)

1.6.1. Impact of Hg Control Technologies on CCRs A possible problem with sorbent injection is its ef fect on fly ash. According to the American Coal Ash Association, 41 approximately 42% of fly ash produced by coal-fire d power plants in 2008 (30 million out of 72 million tons) was used in commercial or engineering applications to avoid land disposal and to generate additional revenue for the power plant. Based on the power plant data in Section 1.1.3, plants th at fire low-rank coal and sell their fly ash represent about 23% of boilers in the U.S., while 2 1% of plants that fire bituminous coal sell their fly ash.
The single most important usage category for fly as h is as a replacement for Portland cement in concrete manufacturing (42% of fly ash or 12.6 million out of 30 million tons per year). Other commercial applications include struc tural fill and other construction applications, raw material for cement (clinker) production, and m ining applications. Many power plants sell their fly ash for use in concrete or cement manufac turing and construction (road fill, soil stabilization, etc.).
The U.S. EPA recently proposed regulating CCRs unde r the Resource Conservation and Recovery Act (RCRA) to address the risks from the d isposal of CCRs. 48 The U.S. EPA proposed two a two-pronged approach on June 21, 201 0. First, the U.S. EPA would list CCRs as special wastes subject to regulation under subtitle C of RCRA, when they are destined for disposal in landfills or surface impoundments. Sec ond, the U.S. EPA would not change the May 2000 Regulatory Determination for beneficially used CCRs, which are currently exempt from the hazardous waste regulations under sec. 3001(b)(3)(A ) of RCRA.
Sorbent injection can often make fly ash unsuitable for use in beneficial applications, specifically if the carbon content is too high from injection of carbon-based sorbents. The Foam Index test is often used to quantify the effect of activated carbon on fly ash destined for concrete production. In this test, a fly ash sample is mixe d with water and a measured amount of a surfactant, or air-entraining agent (AEA). The sol ution is shaken to see if bubbles form as a result of the surfactant. More AEA is added and th e solution is shaken again. This is repeated until bubbles are observed to form. The test mimic s the use of AEAs in concrete production to create small air bubbles in the concrete. The high surface area of activated carbon, if present in the fly ash, requires the use of more AEA, and this can make mixtures of fly ash and PAC unsuitable for concrete production.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-40

Segregation of fly ash and carbon is one method to preserve the value of fly ash. Other possible solutions to mitigate the effect of sorben t injection of fly ash include reducing the amount of sorbent needed or using “ash-friendly” so rbents such as C-PAC TM or FLUEPAC ® -CF PLUS.

The use of a TOXECON TM baghouse downstream of a particulate collection de vice allows segregation of fly ash and activated carbon, as discussed previously. However, the capital cost of a baghouse is high. A less expensive solut ion for units with cold-side ESPs is injection of sorbent mid-field in the ESP, a technology called T OXECON II TM (an EPRI patented technology). The first few fields in the ESP remov e most of the fly ash. There is no sorbent present in this fly ash, making it suitable to sell . The last fields collect remaining fly ash and th e sorbent. This technique is only suitable for boile rs that have ESPs with a relatively large specific collection area (SCA), larger than 400 ft 2 per 1000 acfm.

TOXECON II TM was demonstrated at Entergy’s Independence Steam E lectric Station Unit 2, which fired PRB coal and had a cold-side ES P for particulate control. 29 Several lance designs were used at Independence in an effort to m aximize sorbent distribution. The coverage area inside an ESP is at least 10 times larger than the cross-sectional area of the inlet ductwork, and this creates difficulties in the injection and distribution of the carbon in the flue gas. Mercury removal of 78% was achieved using 5 lb/MMac f DARCO ® Hg-LH.
Reducing the amount of sorbent needed to achieve a given level of mercury emissions is another method of preserving the economic value of fly ash. NRG’s Limestone Station burned a mixture of Texas lignite and PRB subbituminous coal s. The fly ash at this plant was sold for concrete manufacture. Testing carried out in 2009 at Limestone 31 showed that ash generated during injection of 2 lb/MMacf DARCO ® Hg-LH carbon was not suitable for sale to the conc rete industry, but ash generated during injection of 0.5 lb/MMacf of the same sorbent was acceptable for sale.
Injecting a finer grind of sorbent has been tested as a means to increase mass transfer and reduce the amount of sorbent required. 31 On-site milling of the activated carbon injected in the TOXECON II TM configuration at Independence achieved 78% removal with only 2 lb/MMacf. Tests were performed at Independence Unit 2 and Lab adie Unit 2 to investigate the effect of onsite milling of activated carbon. 26 At Independence, on-site milling also increased m ercury removal from 40% to 75% with 0.5 lb/MMacf of DARCO ® Hg-LH injected upstream of the APH and from 60% to 90% with 1 lb/MMacf DARCO ® Hg-LH injected upstream of the APH. At Labadie, more than 10 lb/MMacf FLUEPAC ® -MC PLUS was required to achieve 85% mercury removal. When the carbon was milled, only 4.1 lb/MMacf was required to achieve similar mercury removal, which was a 60% reduction in carbon usage.
Injection of PAC upstream of the air preheater is a nother method to reduce the amount of sorbent required (see Figure 1-25). Alstom has dem onstrated 90% removal with the Mer-Cure TM process on PRB-fired units (without FGC) using inje ction rates of less than 1 lb/MMacf. 28

Another possible solution to mitigate the effect of sorbent injection of fly ash is to use “ash-friendly” sorbents such as C-PAC TM or FLUEPAC ® -CF PLUS.
Recent testing at the Boardman Plant 51 focused on DARCO ® Hg-LH sorbent as compared to several experimental sorbents designed to be mor e compatible with concrete applications. The plant burned PRB coal and had a cold-side ESP. Pow dered activated carbon was injectedTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-41

upstream of the ESP. Foam Index Tests of sorbent-f ly ash mixtures showed that the experimental sorbents required about one-quarter of the amount as compared to DARCO ® HgLH. A “pass” on the Foam Index Test means that the amount of AEA required is below a certain level, generally set by the buyer of the fly ash fo r concrete applications. At moderate levels of ACI, approximately 2 lb/MMacf, some of the experime ntal sorbents mixed with fly ash showed a Foam Index test result that was similar to the fly ash alone or to Portland cement. However, concrete air stability testing, in which the PAC-fl y ash mixtures were substituted for 20% of the cement in concrete mixtures, showed that the air co ntent of the concrete decreased with time. This could cause difficulties for providers of conc rete because the time from initial mixing of concrete to use is variable. If properties of conc rete change with time because of the presence of PAC, then this will make it less likely that PAC-co ntaining fly ash will be used for concrete manufacture.
Injection of FLUEPAC ® -CF PLUS upstream of the APH at Labadie Unit 2 26 produced removals similar to injection of DARCO ® Hg-LH at the same location indicating no decrease in performance due to the ash-compatible carbon. Ash samples, collected while injecting FLUEPAC ® -CF PLUS at rates from 1.5 to 2.0 lb/MMacf, were an alyzed using the Foam Index Test. The samples passed the test and were deemed suitable for concrete, although it was noted that the ash had a dark color that would probably n ot be acceptable for some concrete applications.

C-PAC TM , a product of Albemarle Sorbent Technologies, has been tested at a number of plants. A recent review of C-PAC TM testing 49 highlighted results from Crawford Station Unit 7, a PRB-fired boiler with a cold-side ESP. At an ave rage injection rate of 4.6 lb/MMacf, over 80% mercury removal was achieved for a month-long p eriod. The resulting fly ash, containing C-PAC TM , was extensively tested for use in concrete. Base d on the Foam Index Test, the fly ash was shown to be usable for concrete production. Te sting at another PRB-fired unit, Corrette Station, showed that a C-PAC TM injection rate of 3 lb/MMacf resulted in 85% mercu ry removal and that the resulting fly ash could be used in con crete manufacture, again based on the Foam Index Test.
There are several strategies that are currently bei ng tested to allow sorbent injection for mercury removal while preserving the economic value of the fly ash. Several companies are developing non-carbon, mineral-based sorbents. 52,53 These can remove mercury while not increasing the carbon content of the fly ash collec ted in the particulate control device. Other strategies involve using activated carbon for mercu ry removal while making changes to the sorbent or the process. Segregation of the fly ash from the activated carbon using separate collection devices or different fields in the ESP h as been demonstrated. In configurations in which fly ash is commingled with activated carbon, specialized sorbents have been developed to minimize the impact of activated carbon on concrete properties. Another approach is to reduce the amount of carbon required, either by on-line mi lling or by injection upstream of the air preheater.



### 1.6.2. Environmental Stability of Hg in CCRs A wide range of mercury concentrations have been fo und in fly ash. One reference 53 summarized several studies, which reported an avera ge Hg concentration of 527 ng/g, and a range of 16 to 1530 ng/g. Some uses of fly ash may involve high-temperature processing that may increase the potential for release of mercury a nd other metals. In cement manufacturing, forTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-42

example, fly ash can be raw feed for producing clin ker in cement kilns. Virtually all mercury will be volatilized when fly ash is used as feedsto ck to cement kilns as a result of high operating temperatures (1450 ° C). 56 Curing of concrete can also involve temperatures on the order of 80 ° C. In a laboratory simulation experiment, mercury emis sions during steam-curing of concrete were measured at 0.4 to 5.8 ng of mercury/kg of concrete . The study reported that the Hg flux from exposed concrete surfaces did not exceed mercury fl uxes from soils (4.2 ng m -2 h -1 ). The study concluded that less than 0.022% of the total quanti ty of Hg present in concrete was released during the curing process. Therefore greater than 99% of the Hg was retained in the concrete under the conditions tested. 57

There has also been concern raised for other proces ses, such as the production of asphalt. Using 13 different CCRs, including fly ash containi ng activated carbon, a laboratory simulation was conducted on asphalt production at 170 ° C. 56 The results suggest that volatilization of mercury is less than 10% except for one CCR where r esults suggested volatilization of 92% to 100%.
When there is no beneficial use for fly ash, it is placed in landfills or ponds, where mercury (and other trace metals) might be leached o ut. Laboratory studies and field measurements of solid-gas exchange between fly ash and fly ash mixed with FGD solid mixtures have been conducted. 58 These studies have shown that fly ashes from bitu minous and subbituminous coals act as a sink for atmospheric m ercury, while lignitic fly ash may emit mercury to the atmosphere. In the field, mercury f luxes (solid to gas) from both uncovered landfills and vegetated, topsoil-covered landfills containing bituminous or mixed subbituminousbituminous fly ash were determined to be lower than the mercury fluxes from the surrounding soils. Mercury fluxes from a landfill containing F GD solids mixed with lignitic fly ash were estimated to be about four times higher than the su rrounding soil. 58



### 1.7. Costs of Mercury Reduction

1.7.1. Basis for Cost Calculations Assessing costs of new emission control technologie s has traditionally been a challenging task. Many factors contribute to this, including b usiness confidentiality concerns, early stage technology questions (e.g., short vs. long-term per formance, expected market penetration, regulatory uncertainty), vendor vs. user perspectiv es, etc. Confidence in cost estimates typically grows with statistically significant, actual cost d ata. Also, developing “universal” cost estimates for broad technical and policy decisions represent s a different effort and approach than, for example, developing a site-specific cost estimate f or a given technology.
Universal technology cost estimates are typically a ccomplished through algorithm-based analyses, using a combination of assumptions and em pirical data and using procedures and tools such as NETL’s cost analyses framework 59,60 and the U.S. EPA’s CUECost. 61 On the other hand, site-specific costs can be estimated with more or l ess precision ranging from full-fledged engineering designs to more general “order-of-magni tude” estimates depending on the particular objectives.
In this section of the report no attempt is made to conduct either of the above types of analyses. The objective is to provide a summary of the most recent data available with respect to costs of mercury control technologies. To that ext ent, the information in this section is veryTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-43

consistent with the earlier technical sections in t his report, in that it is based on researching and summarizing recently published data. Specifically, this includes algorithm-based cost information developed by NETL, 59,60 as well as plant survey-based actual costs gathere d by the GAO. 20 These recent studies, conducted in 2007-2009, repr esent a reasonable basis for the current status of estimates of mercury control cost s, specifically because they included several key components necessary for such analyses: actual cost and performance data from well monitored and documented test programs, generally a ccepted cost factors for power plant economics (e.g., taxes, interest rates, contingenci es, retrofit assumptions, labor and material costs, etc.), a consistent “study-level” methodolog y throughout (all these common to the NETL cost analyses), as well as actual reported costs fr om commercially operating plants under the U.S.GAO study/survey. In addition, other specific costs available in the literature are included as well.
As stated previously, this report addresses dedicat ed mercury control technologies, even though mercury capture can and does occur in other plant APCDs (co-benefits). Hence, in this section, the focus remains on dedicated mercury con trol costs and not those associated with cobenefits. For example, the costs of an SCR or WFGD , both of which can affect the overall mercury capture in a plant, are not part of this re port. The costs reported in the NETL and the U.S. GAO studies focus on the mercury control techn ologies described in this report (sorbents, oxidation catalysts and additives). It is importan t to recognize that the effect of mercury reduction co-benefits can have a major impact of th e actual cost of mercury reductions ($/lb Hg removed). This is similar to the impact of varying mercury levels in the coal, in that the actual reductions in pounds, for a given level of control (i.e., percent reduction) are proportionally higher or lower with the respective higher or lower initial mercury level concentrations. This real, but potentially misleading, reporting of cont rol costs is avoided when costs are presented in terms of their impact on the plants’ resulting cost of electricity (COE). As such, the NETL analyses presents costs in both formats – cost of m ercury removed ($/lb) and 20-year levelized COE (mills/kWh).
A potentially very large factor affecting mercury c ontrol costs is the impact of sorbents (activated carbon) on the resulting fly ash from th e plant. This comes from the fact that many plants sell their fly ash for beneficial reuse (e.g ., concrete industry) and the addition of the sorbent may render the fly ash undesirable for that market. In such cases, the revenue represented by the sale of fly ash is replaced by t he cost of its disposal. Given the potentially large cost of these scenarios, the NETL studies inc lude analyses with and without fly ash (or “by-product”) impacts.
It should be noted that although both NETL cost stu dies 59,60 were based on results from its Phase II field test programs, representing most ly short-term results, subsequent longer-term testing (as described in the technical sections abo ve) have for the most part corroborated the earlier tests, providing additional confidence that these costs remain relevant. Comparisons with the U.S. GAO commercial plant surveys lend further credibility to the cost analyses. In addition, it should be noted that the NETL studies present se veral cost scenarios for various coals, configurations and levels of mercury control. For the sorbent technology (ACI), the analyses include 50%, 70% and 90% control scenarios for bitu minous, subbituminous and lignite coals; for the oxidation technologies (catalysts and addit ives), the analyses include subbituminous and lignite coals and mercury reduction levels of 73% ( for the catalysts and additive - CaBr 2 ) and 85% for CaBr 2

.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-44

The U.S. GAO survey provides a much different level of cost detail. Only average cost and ranges are provided. Further they are not dire ctly linked to the plants identified in the survey; hence there is no direct opportunity to ana lyze those results in a more detailed manner. However, using the U.S. power plant information des cribed in Section 1.1.3, it was possible to develop nominal costs for comparison with the NETL estimates.



### 1.7.2. National Energy Technology Laboratory (NETL) Costs Summary for ACI ACI technology costs are primarily driven by the co st of the sorbent. Hence, quantity (injection rate, plant size) and quality (type of s orbent –treated or untreated) of the sorbent are the key factors in the total sorbent cost. Sorbent costs varied between about $0.40/lb and $1.35/lb.
Total installed capital costs ranged from about $3. 6/kW to about $9.2/kW reflecting primarily the wide range of unit sizes in the study (from 140 MW to 360 MW). Table 1-12 summarizes the configurations of APCDs and coal ran k for the units in the cost study at the 90% Hg control level.

Table 1-12. Configurations of units in NETL cost s tudy and capital cost of ACI for 90% Hg removal 59

Coal Type Bit Bit/PRB PRB PRB PRB PRB LIG Size (MW) 172 145 360 240 140 150 220
APCD ESP ESP SD-FF ESP ESP ESP ESP Hg in coal, (lb/TBtu) 8.23 5.66 10.36 7.17 7.83 5.5 8.66 ACI, (lb/MMacf) 5.34 2.31 1.03 0.55 2.4 3.65 1.64 Capital ($/kW) 8 8.79 3.63 8 9.16 8.5 8

Figure 1-28 and Figure 1-29 summarize mercury contr ol costs ($/lb Hg) and 20-year levelized COE (mills/kWh), with and without an impa ct on ash (i.e., lost sales of fly ash as a byproduct), for the various units and coal types. As can be seen in the figures, when the combined cost of not selling the fly ash and paying for its disposal is factored in to the cost of mercury control, the cost of control (in $/lb Hg) and cost of electricity (mills/kWh) are higher.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-45

Figure 1-28. Cost of 90% mercury control with and without impact of lost sales of fly ash as a by-product 59

These results indicate costs ranging from about $60 00/lb to $30,000/lb when by-product
contamination/sales are not a factor and between ab out $18,000/lb and $50,000/lb if ash revenue is lost. These numbers correspond to 20-yr leveliz ed COE ranging from about 0.35 mills/kWh to 2 mills/kWh (0.035 to 0.2 cents/kWh) without by-pro duct penalty and about 1 mill/kWh to 3.5 mills/kWh (0.1 to 0.35 cents/kWh) if by-product imp acts are present.
As already discussed, the cost of sorbent injection technology is largely driven by the cost of sorbent, and the costs are thereby influenc ed by the price of the sorbent and especially its consumption requirements. Figure 1-30 shows the re lative impact of capital cost (a), plant size (b) and sorbent consumption on COE. There is a dir ect relationship between sorbent consumption and control cost, while plant size and capital cost have minor impact on the ultimate COE.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-46

Figure 1-29. Incremental cost of electricity (COE) for 90% mercury control with and

without impact of lost sales of fly ash as a by-pro duct 59

a) b)

c) Figure 1-30. Cost of 90% mercury reduction vs. a) capital cost b) plant size; and c) sorbent consumption 59Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-47



### 1.7.3. National Energy Technology Laboratory (NETL) Cost S ummary for Oxidation Technologies The two types of Hg oxidation technologies (catalys ts and additives) have different cost components: catalysts are primarily driven by the i nitial capital and re-generation costs, while additive technology is not capital-intensive, but a s with the ACI technologies, is driven by chemical costs. Unlike the analyses above for ACI technologies, the oxidation technology costs were estimated based on pilot-scale results and app lied to a nominal 500 MW plant. Table 1-13 summarizes the major parameters for the units in th e cost study. Figure 1-31 summarizes the costs of mercury reduction for Hg oxidation technol ogies in $/lb of mercury removed and 20- year COE.

Table 1-13. List of key parameters in NETL cost st udy of oxidation technologies combined with FGD 60

Technology Pd Catalyst Au

Catalyst Au

Catalyst CaBr 2 CaBr 2 CaBr 2 CaBr 2

Coal type ND Lig TX Lig/PRB PRB TX Lig/PRB PRB PRB PRB

Hg control (%) 73 73 73 73 73 73 85 APCD ESP, wFGD ESP,

wFGD ESP,

wFGD ESP,

wFGD ESP,

wFGD SCR,

wFGD SCR,

wFGD Hg in coal (lb/TBtu) 10.5 16.98 6 16.98 6 6 6
CaBr 2 rate (lb/hr) NA NA NA 294 322 5.9 25 Catalyst volume (ft 3 ) 4,640 5,890 6,060 NA NA NA NA Capital ($/kW) 2.69 3.42 3.53 1.56 1.56 1.56 1.56

Figure 1-31. Cost of mercury reduction using oxida tion technologies combined with FGD 60

It can be seen from the graph in Figure 1-31 that t he costs are comparable to those for sorbent injection technologies. Specifically, the incremental COE in the range of 1.0 toTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-48

1.8 mills/kWh is about the same as that for the ACI technologies shown in Figure 1-29 when byproduct impacts are not included. It should be poi nted out that Hg oxidation technologies do not impact fly ash (or scrubber waste) and are not ther efore subject to by-product impact costs as with ACI technologies. It is also important to not e that the costs for oxidation technologies were based on lower level of Hg reductions (73% and 85%) than for ACI (90%). Another important observation is the impact of SCR on the overall COE with CaBr 2 . The last two bars in Figure 1-31 show the low COE (~1 mill/kWh) due to the lower injection rate required for CaBr 2 because of the Hg oxidation impact of the SCR co-be nefit. As shown in Table 1-13, capital costs are low for these technologies. Figure 1-32 below shows the key cost components affecting both catalyst and additive oxidation technologies. For the ranges of oxidation catalyst volume and CaBr 2 injection rates cited in the NETL study, COE is co nsiderably higher when an oxidation catalyst is used to oxidize mercury upstream of a w et FGD. From a cost perspective, bromine injection appears to be advantageous relative to ox idation catalysts, assuming that the desired level of Hg oxidation can be obtained.

Figure 1-32. Cost of mercury reduction for oxidati on technologies vs. catalyst and chemical costs 60



### 1.7.4. U.S. Government Accountability Office (GAO) Mercury Control Study The U.S. GAO study focused on a plant survey/interv iew process designed to obtain current performance and cost data from plants opera ting mercury control technologies. The plants/units included in the survey employed sorben t injection technologies (ACI), but exhibited different APCD configurations. The majority of the applications were on units equipped with ESPs, although several had FFs. Further, there wer e several units with SD-FF configurations, presumably for compliance with other regulatory req uirements (e.g., SO 2 ). As already stated, the data presented in the U.S. GAO report were used her e in conjunction with the databases described in Section 1.1.3. Table 1-14 summarizes the information obtained from this analysis. It should be noted that these estimates represent n ominal values, because no direct comparison between the U.S. GAO data and individual units can be made. However, the results are veryTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-49

consistent with the overall cost estimates in the N ETL cost studies (capital and COE) and are further corroborated in that the capital cost for b oth ACI and FF technologies agree well with the NETL estimates for ACI, as well as with other avail able cost data for FFs. 61

Table 1-14. Summary of results from U.S. GAO Hg co ntrol survey 20

Technology MW range MW avg. ACI Capital ($/kW) FF Capital

($/kW) COE

(mills/kWh)

ACI/ESP 80-375 240 11-15 NA 1.2 ACI/FF 75-350 260 10-14 140-200 NA
ACI/SD-FF 250-790 430 NA 190-210 NA
Additionally, the reported O&M costs (sorbent costs ) range from about $1/kW-yr to $5/kW-yr. This also compares well with the NETL co sts for ACI, which ranged from about $1.2/kW-yr to $9/kW-yr. These results represent re al, commercial operating data and appear to corroborate with the NETL costs quite well.
One last commercial data point, included in the U.S . GAO survey, but not identified individually, is the operation of ACI with FF (TOXE CON TM ) at Presque Isle power plant. The 270 MW project reported a capital cost of $128/kW a nd an overall mercury removal cost of $67,000/lb Hg. 63 These correlate well with the NETL and the U.S. G AO estimates.



### 1.8. Commercial Experience with Sorbent Injection Techn ologies
The penetration of mercury control technologies int o the U.S. electric power marketplace has grown rapidly in the recent past, mostly as a r esult of various state regulations and initiatives. The Institute of Clean Air Companies (ICAC) has col lected information relative to the current and projected deployment of mercury controls. 64 At present about 25 units representing about 7,500 MW are using commercial ACI technologies for mercury control. In addition, about 55,000 MW of new bookings are reported by ICAC. Fi gure 1-33 and Figure 1-34 summarize these data by state and by coal type, respectively.

Figure 1-33. Mercury control systems orders booked by state 64Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-50

Figure 1-34. Mercury control systems orders booked by coal rank burned at plant 64

NESCAUM has received, courtesy of the New Jersey De partment of Environmental Protection, 65 Hg emission data from several sites, based on stac k testing data. Selected data from this information are summarized in Table 1-15. Dat a were selected for sites reporting percent mercury reduction for the years 2008 to 2009. The sites in the table include dedicated mercury control technologies (ACI) as well as those whose m ercury reductions are solely attributable to co-benefits through other installed APCD equipment.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-51

Table 1-15. Summary of New Jersey stack test mercury emissions for 2008 and 2009 65

Unit/APCD Test Date Load ACI Hg Reduction
(MW) (lb/hr) (%)

Mercer 1/SCR-FF-ACI Jun-08 325 603 92 Sep-08 325 607 56
Dec-08 215 98 99
Mercer 2/ FF-ACI Jun-08 260 478 95 Sep-08 324 643 59
Dec-08 317 643 98 Carney’s Point 1/SCR-SD-FF Feb-08 139 NA 98.4
Jun-08 139 NA 96.9 Sep-08 139 NA 97.2 Carney’s Point 2/SCR-SD-FF Feb-08 138 NA 98.5
Jun-08 138 NA 97.1 Sep-08 138 NA 97.4 Logan 1/SCR-SD-FF Mar-08 224 NA 99.9
Jun-08 223 NA 96.2 Sep-08 222 NA 96.5
Nov-08 219 NA 97.8 B L England 2/SNCR-SD-ESP-ACI Mar-08 160 414 96.7
Jun-08 163 337 97.8 Sep-08 167 373 91.2
Nov-08 167 365 99.1
Mar-09 165 209 83.8
Jul-09 169 362 99.5Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 1-52

Information from the Massachusetts Department of En vironmental Protection was also obtained, including a summary of the 2008-2009 Hg e missions data from the coal-fired plants in Massachusetts (Figure 1-35), as well as the formal compliance reports submitted by two of the plants in the state: Salem Harbor 66 and Brayton Point. 67

Figure 1-35. Summary of Hg emissions from coal-fir ed power plants in Massachusetts, 2008-2009 66,67

The required Hg reductions in Massachusetts are bas ed on baseline Hg emissions from a historical 12-month period; hence it is not possibl e to infer the performance of the Hg controls from the available data. It is, however, important to note that Salem Harbor does not have dedicated Hg controls (e.g., reductions are through co-benefits only), while Brayton Point employs SD-FF with ACI for multi-pollutant control in Units 1 and 2, and has an SCR and ESP in Unit 3. Table 1-16 and Table 1-17 present the d ata provided for Salem Harbor and Brayton Point, respectively.Technologies for Control & Measurement of Mercury Emissions from Coal-Fired Power Plantsin the United States: A 2010 Status Report1-53Table 1-16. Dominion Energy Salem Harbor Station 2009 reported Hg emissions661/092/093/094/095/096/097/098/099/0910/0911/0912/09Total/AverageNet GenerationMWh 51,845 37,354 42,001 34,430 27,839 22,265 16,298 30,035 351 27,258 30,539 39,231 395,446Emissionspounds 0.172 0.108 0.095 0.064 0.138 0.084 0.112 0.074 0.011 0.179 0.171 0.251 1.458

Unit 1Monthly Ratelb/GWh 0.0033 0.0029 0.0023 0.0019 0.0049 0.0038 0.0068 0.0025 0.0321 0.0066 0.0056 0.0064 0.0041Net GenerationMWh 43,732 41,515 42,820 34,381 20,096 11,887 5,81716,299 0 12,166 1,588 37,712 268,013Emissionspounds 0.250 0.254 0.240 0.200 0.157 0.138 0.081 0.163 0.000 0.132 0.034 0.227 1.877

Unit 2Monthly Ratelb/GWh 0.0057 0.0061 0.0056 0.0058 0.0078 0.0116 0.0140 0.0100 0.0000 0.0109 0.0215 0.0060 0.0070Net GenerationMWh 101,316 81,851 22,717 54,591 59,828 55,467 58,199 62,525 11,816 36,876 33,543 81,843 660,572Emissionspounds 1.109 0.559 0.035 0.388 0.456 0.427 0.549 0.656 0.169 0.308 0.236 0.342 5.235

Unit 3Monthly Ratelb/GWh 0.0109 0.0068 0.0015 0.0071 0.0076 0.0077 0.0094 0.0105 0.0143 0.0084 0.0070 0.0042 0.0079Net GenerationMWh 196,893 160,720 107,538 123,402 107,763 89,61980,314 108,859 12,167 76,300 65,670 158,786 1,288,031Emissionspounds 1.532 0.921 0.369 0.652 0.751 0.650 0.742 0.893 0.180 0.619 0.441 0.820 8.570Monthly Ratelb/GWh 0.0078 0.0057 0.0034 0.0053 0.0070 0.0072 0.0092 0.0082 0.0148 0.0081 0.0067 0.0052 0.00677.29 Allowablelb/GWh 0.0075 0.0075 0.0075 0.0075 0.0075 0.0075 0.0075 0.0075 0.0075 0.0075 0.0075 0.007512-month Rolling Ratelb/GWh 0.0073 0.0071 0.0068 0.0068 0.0069 0.0070 0.0071 0.0067 0.0066 0.0067 0.0066 0.00657.29AllowableRemoval Rate% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%

Total - Units 1,2,312-month removalfrom baseline% 92% 92% 91% 91% 91% 91% 91% 92% 92% 93% 93% 93%Technologies for Control & Measurement of Mercury Emissions from Coal-Fired Power Plantsin the United States: A 2010 Status Report1-54Table 1-17. Dominion Energy Brayton Point Station2009 reported Hg emissions671/092/093/094/095/096/097/098/099/0910/0911/0912/09Total/AverageNet GenerationMWh 143,058 152,989 39,412 168,096 147,966 164,825155,255 141,769 136,307 156,235 170,732 155,778 1,732,422Emissionspounds 0.6 0.9 0.2 0.8 0.8 0.6 0.3 0.9 0.5 0.5 0.50.5 7.1

Unit 1Monthly Ratelb/GWh 0.0042 0.0060 0.0043 0.0048 0.0055 0.0037 0.0018 0.0061 0.0040 0.0031 0.0029 0.0033 0.0041Net GenerationMWh 176,803 157,947 173,406 169,232 177,239 137,536171,803 129,959 107,122 152,936 172,305 173,993 1,900,281Emissionspounds 0.7 0.6 0.7 0.8 1.2 0.8 1.7 2.3 0.9 1.4 1.21.1 13.4

Unit 2Monthly Ratelb/GWh 0.0042 0.0036 0.0041 0.0048 0.0066 0.0055 0.0102 0.0173 0.0082 0.0090 0.0070 0.0066 0.0070Net GenerationMWh 435,058 398,332 421,296 349,860 113,339 322,896339,495 296,013 401,206 424,009 442,176 330,854 4,274,534Emissionspounds 3.3 3.5 3.4 3.1 1.5 2.9 2.7 2.5 3.1 3.7 4.51.3 35.6

Unit 3Monthly Ratelb/GWh 0.0076 0.0089 0.0081 0.0090 0.0132 0.0089 0.0081 0.0084 0.0076 0.0087 0.0102 0.0040 0.0083Net GenerationMWh 762,654 718,106 634,114 687,188 438,544 635,689666,553 567,741 644,635 733,180 785,262 670,250 7,943,916Emissionspounds 4.7 5.0 4.3 4.8 3.5 4.2 4.8 5.6 4.5 5.5 6.23.0 56.1Monthly Ratelb/GWh 0.0061 0.0070 0.0068 0.0069 0.0080 0.0066 0.0072 0.0099 0.0070 0.0076 0.0079 0.0045 0.00717.29 Allowablelb/GWh0.007512-month RollingRatelb/GWh0.00717.29AllowableRemoval Rate%85%

Total - Units 1,2,312-month removalfrom baseline%85% 85%Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-1



## 2. Continuous Mercury Monitoring Technologies
There are two forms of continuous mercury monitorin g systems (CMMS), devices that continuously sample mercury emissions and provide a measurement of mercury emissions over time. They are

• Analyzer-based CEMS; and

• Sorbent traps (STs). Hg CEMS are analyzers that continuously sample the stack gases and provide an indication of mercury concentration in the stack fl u gas within minutes of the gas being sampled. In this respect, the Hg CEMS provide information to the operator about mercury emissions on a near real-time basis, or at least in a timely fashi on that provides emissions data for a particular hour or day. The total mass emissions rate of merc ury is determined by multiplying the measured concentration of mercury in the flue gas t imes the measured flue gas flow rate.
Sorbent traps provide an indication of cumulative m ercury mass emissions over a period of time that could be hours, days, or even weeks. Gas is pulled through a set of traps filled with sorbent that captures mercury. The gas flow rate d rawn through the sorbent is varied at a rate that is in proportion to the flue gas flow rate, an d must be isokinetic if there is significant amount of particulates in the flue gas. After a period of time, the sorbent traps are removed and replaced. The used sorbent traps are analyzed for total mercu ry. The mass of mercury trapped can be used to determine the average mercury emission rate over that period of time.
This Chapter focuses on methods that are intended f or permanent installation and continuous monitoring of mercury emissions. For co ntinuous monitoring and reporting for the purpose of regulatory compliance there are requirem ents imposed that assure the reliability and accuracy of the measurement. The same technologies as discussed in this Chapter have been used for short term test programs spanning hours, d ays, or even weeks. Many of the method requirements that are discussed in this Chapter tha t are necessary for a method designed for regulatory compliance purposes would not be necessa ry if the same methods were used for a short-term test.



### 2.1. Hg CEMS Technology Overview
Currently in the U.S, the two principal suppliers o f Hg CEMS technology are ThermoFisher Scientific and Tekran Instruments. Th ese two suppliers have supplied nearly every Hg CEMS ordered for power plants. This Chapt er, therefore, focuses on the technologies offered by these two companies.
Each company has been working to address the specif ic challenges associated with measuring mercury in flue gas. Some of these chall enges include:

• Mercury is present in much smaller concentrations t han typical criteria pollutants, (i.e., concentration measured in parts per trillion versus parts per million). Although ambient monitors are capable of measuring mercury concentrations to much lower levels than what is experienced in power plant flue gases, some of the particular characteristics of mercury and power pla nt flue gas – such as interferences and reactivity – make the concentrati on of mercury in power plant flue gas especially difficult to measure at such lo w levels.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-2

• Ionic mercury is a reactive material that tends to react with or adhere to other materials, and thereby may be lost in sample handli ng unless special precautions are taken.

• Elemental mercury tends to form an amalgam with met als. So, to avoid loss of sample, metal surfaces in the sampling system must be coated and temperature
maintained at180 ° C. The challenge faced by the Hg CEMS suppliers has be en to design a monitoring system that is reliable while also addressing the above di fficulties unique to mercury measurement in flue gas.



### 2.2. Hg CEMS Suppliers

2.2.1. ThermoFisher Scientific Hg CEMS ThermoFisher Scientific has shipped more than 450 H g CEMS. 68 Figure 2-1 shows how the ThermoFisher Hg CEMS is configured. The key co mponents are the Sample Extraction & Conversion System, the Probe Controller, the Cold-V apor Atomic Fluorescence (CVAF) Analyzer, and the Calibration System.
Sample Extraction and Converter Flue gas is sampled from the stack by the probe and is typically diluted at a 40:1 ratio with air (or in some cases with nitrogen). Within the probe is a converter that converts oxidized mercury, which is mostly in the form of HgCl 2 , to elemental mercury. Therefore, all of the mercury sent into the lines to the analyzer is in t he form of elemental mercury. This makes the sample somewhat easier to transport and also puts t he mercury in a form that the analyzer is capable of measuring. The sample line from the pro be to the analyzer must be heated to 120 ° C (248 ° F) in order to ensure that sample integrity is pres erved. The probe also provides the means to convert elemental Hg gas from the calibrator to oxidized mercury for the purpose of system integrity checks.

Probe Controller The Probe Controller sends signals to the probe tha t control the oxidized Hg to elemental Hg converter and the elemental Hg to oxidized Hg co nverter, nitrogen supply and other functions performed within the probe. It also controls probe and sample line temperature.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-3

Figure 2-1. ThermoFisher Scientific Mercury Freedo m System 68

CVAF Analyzer Within the analyzer the sample is continuously meas ured using CVAF. In the CVAF method, free mercury atoms (elemental mercury) in a carrier gas are excited by an ultraviolet light source. The excited mercury atoms re-radiate their absorbed energy (fluoresce). The fluorescence intensity is related to the amount of mercury present. The technique is sensitive, selective, and linear over a wide range of concentr ations; however, molecular gases (such as oxygen and nitrogen) present in the carrier gas que nch the fluorescence signal, which reduces instrument sensitivity.
The analyzer provides a measure of total mercury an d cannot speciate mercury on its own. In order to measure mercury speciation, it is necessary to take two measurements – one with the converter in the probe operating (for tota l mercury) and another with the converter bypassed and with HgCl 2 removed from the gas (to arrive at elemental Hg). The difference between the amount of total mercury and the amount of elemental mercury equals the amount of oxidized mercury. When used for regulatory purpose s, CEMS are not typically operated in speciating mode, but rather used to measure total m ercury only.
The gas in the analyzer is maintained at a vacuum t o suppress quenching and improve sensitivity. Sensitivity of the analyzer’s CVAF me asurement can be improved roughly five-fold by using nitrogen as the dilution gas in the probe rather than air because oxygen has a greater tendency to quench the atomic fluorescence than nit rogen. 68 Therefore, for low concentration measurements (less than 2 μg/m 3 ), nitrogen dilution gas is recommended by the manu facturer.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-4

The analyzer has digital outputs for various data p rotocols. The advantage of digital output is that, with the high degree of linearity e xpected from the CVAF analysis method combined with digital output, good linearity over a broad dynamic range is expected.

Calibration Gases and Standards It is periodically necessary to verify the accuracy of the Hg CEMS using calibration gases that have known concentrations of both elemental an d oxidized mercury. As an alternative to commercial, bottled calibration gases, the Hg CEMS manufacturers have been working with the U.S. EPA and NIST on traceable methods for the inst ruments to produce elemental mercury calibration gases utilizing known relationships for mercury vapor pressure. 69 The elemental mercury calibration gas generators for both supplie rs operate by carefully controlling a sample of Hg and dilution gas to a specific temperature and p ressure that is determined by the desired vapor pressure. In this manner, the mercury concen tration of the gas exiting the calibration gas generator is determined by the mercury vapor pressu re relationship. The calibrator output is NIST-traceable.
It is important that the Hg CEMS measure all forms of mercury accurately. A system integrity check is performed to verify the accurate measurement of oxidized mercury. For system integrity checks it is necessary to have oxi dized mercury calibration gas provided to the probe tip where it is drawn through the probe and t hrough the converter and to the analyzer. To do this, the ThermoFisher Hg CEMS adds chlorine to the elemental Hg calibration gas at the probe in order to convert the elemental mercury fro m the elemental mercury gas generator to oxidized mercury. It is necessary to have a bottle of chlorine gas at the probe for this system integrity check. The probe has a converter that co nverts the oxidized mercury back to elemental mercury, which is then transported to the analyzer for measurement. So, for system integrity checks on ThermoFisher’s Hg CEMS, elemental mercury calibration gas is oxidized with chlorine, sent through the probe tip, and then the oxidized mercury is converted back to elemental mercury before leaving the probe.



### 2.2.2. Tekran Instruments Hg CEMS Tekran Instruments has sold roughly 175 Hg CEMS to power plants plus additional systems sold for the purpose of mercury monitoring for control technology test programs, for research or for other purposes. The Tekran Instrum ents Hg CEMS, shown schematically in Figure 2-2 has some similarities and some significa nt differences with the ThermoFisher Hg CEMS; these will be discussed below.
Sample Extraction The Tekran probe extracts sample from the stack and dilutes it with air at roughly a 30:1 ratio. The probe is heated. The portion of the probe that is in the gas stream is made of Hasteloy (a corrosion-resistant metal) coated with a thin quart z layer. The probe body is made of coated stainless steel. The filter is titanium. Unlike t he Thermo Fisher analyzer, which conditions the sample at the probe, the Tekran sample is sent in i ts sampled form to the sample conditioner, which is near the analyzer. The sample line from t he probe to the sample conditioner is
maintained at about 180 ° C (356 ° F) to avoid loss of ionic or elemental mercury or p lating out of selenium. If selenium were allowed to build up in the sample line, the elemental mercury would be lost in the line because elemental mercury react s with condensed selenium. If this takes place after the converter, it will result in a low bias f or the total Hg measurement. An unheated line isTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-5

also used in some cases to carry air for the probe. The unheated line does not carry sample or calibration gas.

Figure 2-2. Schematic of Tekran Hg CEMS 70

Sample Conditioner The sample conditioner converts the oxidized mercur y to elemental mercury using a pyritic converter. Also, acid gases (and selenium) , which could induce mercury recombination reactions and could adversely affect analyzer relia bility, are scrubbed out using deionized (DI) water. The conditioner therefore provides an acid gas-free stream with elemental mercury and other gases to the analyzer. The sample conditione r facilitates speciation by providing one of two gas streams to the analyzer: 1) 100% of the flu e gas mercury after having converted any ionic mercury to elemental mercury; and 2) a sample with the ionic mercury removed so that only the elemental mercury from the flue gas remain s. Similar to the ThermoFisher analyzer, ionic mercury is determined in the Tekran analyzer by subtracting the elemental mercury concentration from the total mercury concentration.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-6

CVAF Analyzer

Both the ThermoFisher instrument and the Tekran ins trument use CVAF for analysis. However, Tekran’s analyzer uses a gold amalgam to c ollect and concentrate the mercury prior to analysis. This also permits the mercury to be re-r eleased into an inert gas (argon) atmosphere. The argon gas ensures that fluorescence is not quen ched by molecular gases that are present in the boiler flue gas. The gold amalgam concentratio n method and the use of inert gas help the analyzer to provide high sensitivity. The analyzer consumes argon gas; one tank of argon is expected to last roughly six weeks. Like the Therm oFisher analyzer, the Tekran analyzer produces an output concentration of total mercury. Speciation is performed in concert with the sample conditioner.

Calibrators The Tekran Hg CEMS has two calibrators – one for el emental mercury and another for ionic mercury. The elementary mercury calibrator p roduces a gas stream with a known concentration of elemental mercury in a similar man ner as the ThermoFisher analyzer – by carefully controlling the temperature and pressure of a sample of mercury and dilution gases to provide a gas with a well-controlled elemental merc ury vapor pressure. Tekran also has an oxidized mercury calibrator, whi ch generates a defined mixture of air and water vapor and mercuric chloride by evaporatin g a controlled amount of aqueous mercury chloride solution of known concentration into a car efully controlled gas volume, as shown in Figure 2-3. Because this approach starts with oxid ized mercury in a NIST-traceable aqueous solution, there is assurance that only oxidized mer cury is produced. Also, because the solution and the hardware are NIST-traceable, the amount of oxidized mercury is NIST-traceable. This method of generating oxidized mercury does require transporting the oxidized Hg from the generator, up a heated umbilical to the probe tip, through the probe, and back through a heated umbilical to the sample conditioner for the system integrity check.



### Mixing Chamber DI Water 1.0 μ g/ml HgCl 2



### Dry Air Misting Device

Precision
MicroPumps

Mass Flow
Meter 

### Hg 2+


### Calibration Gas

Figure 2-3. Simplified diagram of the Tekran Model 3315 Ionic Mercury CalibratorTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-7



### 2.2.3. Other suppliers of Hg CEMS Three other suppliers of Hg CEMS have been identifi ed: PS Analytical, Cemtrex and Ohio Lumex. PS Analytical’s Sir Galahad mercury CE MS uses an amalgamation method combined with CVAF, the same general method as the Tekran CEMS. The Cemtrex and Ohio Lumex CEMS analyze the gas using the method of atom ic absorption spectroscopy (AAS). In AAS, a light source is scanned at a wavelength wher e elemental mercury vapor absorbs light. The amount of light that is absorbed is related to the amount of mercury in the light path. This Chapter focuses on the results achieved so far with the more widely used ThermoFisher and Tekran analyzers.



### 2.3. Approximate Costs of Hg CEMS

ThermoFisher and Tekran confirmed that the initial cost of an Hg CEMS is typically on the order of $500,000. 68,71 These costs include:

• Approximately $200,000 for system including startup and training;

• Another $200,000-$300,000 for site preparation. Costs will vary somewhat from this $500,000 figure. The heated umbilical alone is a significant cost item that might cost anywhere from about $10,000 for a short stack to over $100,000 for a very tall stack. Other factors that affect cost include the number of Hg CEMS located at the site, site conditions, and local cli mate.
Typical annual operating costs are more difficult t o estimate, because there has been limited experience with the learning curve associat ed with the use of Hg CEMS and the actual quality assurance (QA) and reporting requirements a re not certain. Midwest Generation estimates that it takes three times as many labor h ours to support the Hg CEMS as traditional NOx and SO 2 CEMS. 72 Using the U.S. EPA’s CEMS cost estimating tool, t here is roughly $20,000 in annual plant labor charges for a typical power plant CEMS with NOx, SO 2 , opacity, and flow, and total annual costs including Relative Accuracy Test Audits (RATAs), reporting, parts and consumables, and other costs of about $65 ,000. The U.S. EPA CEMS cost model 73 would suggest that Midwest Generation’s annual labo r charges have been in the range of about $60,000 for the Hg CEMS. Due to the learning curve with these instruments, experience to date should not represent long-term estimates.
According to ThermoFisher, the long-term operating requirements are expected to approach those of the dilution CEMS that most power plants currently have installed for NOx and SO 2

. 74 This is consistent with information from Tekran t hat labor costs should ultimately approach those of the existing NOx and SO 2 CEMS; but that total annual costs will be somewhat higher when including RATAs, reporting, parts and c onsumables, NIST traceability and other costs for a total of about $100,000 or more. 75 These estimates are based upon the Part 75 mercury monitoring requirements of the vacated Clea n Air Mercury Rule (CAMR). ∗ The actual costs of monitoring will depend upon the requiremen ts of any future monitoring rule.

∗ On March 15, 2005, EPA issued CAMR to permanently c ap and reduce mercury emissions from coal-fired power plants for the first time ever. Included in the rule were mercury monitoring and reporting requ irements under Part 75. Appendix K of Part 75 set forth the mercury monitoring and reporting requirements for Sorbent Trap Monitoring Systems. On February 8, 2008, the D.C. Circuit vacated EPA’s rule removing power plan ts from the Clean Air Act list of sources of hazardous air pollutants. At the same time, the Court vacate d CAMR. Because the mercury monitoring and reporting requir ements were part of CAMR, they too were vacated. E PA isTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-8



### 2.4. Operating Issues of Hg CEMS
Although ambient mercury analyzers have been availa ble and operating well for many years, Hg CEMS for power plant or other combustion exhaust gases are new. There are numerous challenges in accurately and reliably meas uring mercury emissions from power plants that do not exist for ambient analyzers. These inc lude:

• Transporting the sample from the stack to the analy zer while preserving sample integrity;

• Measuring small amounts of mercury in the presence of large amounts of combustion gases that may interfere with the measur ement;

• Measuring mercury that may exist in multiple chemic al forms;

• Having the means to verify the accuracy of the meas urement for the purpose of assuring that the instrument is providing reliable measure of emissions compliance; and

• Doing all of this while having a system that is not unduly expensive or difficult to use under the harsh industrial conditions at a powe r plant.
The suppliers of mercury analyzers have made great progress in addressing these issues. The following sections examine the key issues relat ing to operation of Hg CEMS, including:

• Reliability;

• Calibration and NIST traceability;

• Measurement bias and bias adjustment factor;

• Accuracy and precision at low concentrations; and

• Availability and data substitution.



### Reliability
Because Hg CEMS are fairly new devices, there is re asonable concern regarding the reliability of the devices for power plant applicat ions. In some cases product development has been occurring concurrently with implementation of Hg CEMS at power plants. As challenges associated with these applications have been encoun tered, design changes have been implemented to address them. Recognizing that thes e systems have been under development and that some of the problems encountered a few years a go have been addressed, the focus here is on issues that may continue to have an impact on relia bility.

Umbilical Failure The umbilical is the heated sample line(s) from the probe to the analyzer or sample conditioner. It is often several hundred feet long . Failure of the umbilicals has been a problem. Dominion Generation stated that 5 of 13 umbilicals on its Tekran systems installed in Illinois and

now developing air toxics emissions standards for p ower plants under the Clean Air Act (section 112), consistent with the D.C. Circuit’s opinion regarding CAMR. EP A intends to propose air toxics standards for coal- and oilfired electric generating units by March 10, 2011 a nd finalize a rule by November 16, 2011.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-9

Massachusetts had failed. 76 These failures are mostly due to overheating. Mi dwest Generation noted similar experiences with the umbilicals of it s ThermoFisher analyzers installed on boilers in Illinois and Pennsylvania, with 6 of 13 umbilica ls failing. Midwest Generation also noted that there were approximately 50 umbilical failures indu stry-wide. 72 This is roughly consistent with information on umbilical reliability from other sou rces. Tekran stated that about 10% of umbilicals have failed, which has led to new design s for umbilicals with better temperature control. 71 This is consistent with information from Dekoron/ Unitherm, the primary manufacturer of these umbilicals for both Hg CEMS suppliers, who reported a failure rate of 8.4%. 77

The causes of umbilical failures have varied. Acco rding to Dekoron/Unitherm, about half of the failures were field repaired; the balan ce required replacement. In some cases there was an installation error, as installers were not a ccustomed to installations of several hundred to a thousand feet of this type of heated and insulate d sample line. Failure modes varied from leads being pulled apart during installation, to short ci rcuits of heaters, and in a small number of cases, fires. (Again, according to Dekoron/Unitherm, ever y one of the cases in which there were fires was the result of faulty installation, i.e., no gro und fault protection despite recommendation by the manufacturer and requirements of the National E lectric Code.) The other causes of the failures included improper installation, incomplete information at the time of design, defective heater elements (that were ultimately replaced by t he manufacturer), and lack of individual and high limit temperature control (a heater controller design issue). To address these causes, there have been design changes to eliminate the failure m odes, education of installers to reduce risk of damage during installation or failure upon start up , and education of all parties involved to improve specification, design and installation to r educe risk of failure. 77 In addition, many facilities have installed redundant umbilicals to p rovide a backup in the event of an umbilical failure.
As a result of the improvements made by the various companies involved in the manufacture, supply and installation of the umbilic als, it is anticipated that umbilical failures should be less troublesome in the future.
System Integrity Tests System integrity tests exercise the entire sampling , conditioning, analysis, and calibration gas generating system. A shortcoming in any one of the associated components will result in a failed system integrity test. According to Dominio n, 76 this was the most frequently failed quality assurance (QA) test. Also, unlike the calibration tests, the system integrity test requires use of oxidized mercury calibration gases, which are more difficult to assure because oxidized mercury is so reactive that it can be lost easily in sample streams after leaving the calibration gas generator (such as in the Tekran instrument), or th e conversion rate of elemental to oxidized Hg in the probe (in the case of ThermoFisher) may be d ifficult to verify. Dominion recorded 80-150 hours of down time per Hg CEMS in 2008 as a result of failed system integrity tests. 76 Dominion has found that it is beneficial to perform the system integrity test manually to ensure that a technician can observe the physical process and identify problems during the test, which has proven to be helpful in avoiding false failures of the test. 78 This is consistent with the experience of Midwest Generating, who reported that its Hg CEMS do not have a good record at passing system integrity tests. 72 At this point, it appears that the equipment asso ciated with the system integrity tests may not yet be at the point where the test can be performed in an automated fashion with high reliability. This affe cts how the tests can be scheduled because a technician needs to be available to monitor them. 78Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-10

The difficulty of system integrity tests is closely related to the development of NIST traceable oxidized Hg standards, which are explored more fully in the following section.



### Calibration and NIST Traceability
For regulatory compliance purposes, it is important that emissions monitors provide measurements with accuracy that can be traced back to verifiable NIST standards. This is done through regular calibration checks of the Hg CEMS a gainst gases of a known mercury concentration.
Elemental Mercury Calibration Standards Traceability of the elemental mercury measurement o f each Hg CEMS is to be performed using a calibration gas generator that is certified by NIST. The U.S. EPA has established interim traceability protocols for elemental gas generators , which provide procedures to: “(1) establish the quantitative output of elemental Hg generators; and (2) determine the expanded, combined uncertainty values of the gas standards produced by the elemental Hg generators.” 80 The protocol also specifies the maximum allowable uncer tainty for the elemental Hg gas standards. Elemental mercury is also available as a bottled ga s, but the U.S. EPA has not yet established traceability protocols for gas cylinders.
The NIST certification is achieved through an unbro ken chain of comparison of one elemental mercury calibration gas generator to anot her and eventually to a NIST-verified standard. An interim traceability protocol has bee n developed to provide for this and was promulgated by the U.S. EPA on July 1, 2009. 79 In this protocol, NIST uses isotope dilution inductively coupled plasma mass spectrometry (ICP-M S) as the fundamental measurement to certify the NIST Prime elemental mercury calibratio n gas generator. This NIST Prime calibration gas generator is used to certify Vendor Prime calibration gas generators. The Vendor Prime calibration gas generators are used to certif y user calibration gas generators that are sent to the vendors for certification. In cases where a us er cannot send in their calibration gas generator to the vendor for certification, a Field Reference calibration gas generator, which is certified against the Vendor Prime calibration gas generator, can be used at the user’s site to certify the user calibration gas generator. Figure 2-4 shows h ow this approach produces an unbroken chain of measurement comparisons for certification back t o a NIST-verified standard.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-11

NIST ID -ICP Mass Spec

NIST Prime gas generator

Vendor 1 Prime gas generator Vendor 2 Prime gas generator

User F gas generator User C gas generator User A gas generator User D gas generator Vendor 1
Field Reference gas generator Vendor 2
Field Reference gas generator NIST

User B gas generator User E gas generator

Figure 2-4. General approach for elemental mercury calibration gas generator certification Certification of gas generators is valid for a peri od of time, and each calibration gas generator needs to be periodically recertified. Th e NIST Prime gas generator needs to be periodically recertified against ICP-MS (or another method determined by NIST). Vendor Prime gas generators are periodically sent to NIST for re certification against the NIST Prime gas generator, and User and Field Reference gas generat ors need to be periodically recertified against the Vendor Prime gas generators. As a result, this will become a regular requirement for all companies involved in mercury monitoring.
Oxidized Hg Calibration Gas Standards The interim oxidized Hg NIST traceability protocol was promulgated on July 1, 2009. 80 The interim oxidized Hg gas traceability protocol p rovides procedures for: “(1) establishing the NIST traceability and quantitative performance of k ey components of HgCl 2 generators; (2) determining the uncertainty contributed by each of these components; and (3) calculating certified output concentrations and expanded, combi ned uncertainty values for the gas standards produced by the generators.” 69 Oxidized mercury must be used for system integrit y checks. There are no gas cylinders for oxidized mercury, so the two CEMS manufacturers have developed different generators for oxidized Hg cali bration gas.
The ThermoFisher Hg CEMS starts with elemental merc ury, transports it to the probe, oxidizes it to HgCl 2 in the probe using chlorine that is added at that location, and sends the oxidized Hg sample to the probe tip. Certification of the ThermoFisher oxidized mercury generator is related to the elemental gas generator

. 81 The combined uncertainty of the HgCl 2 calibration standards is calculated based on the un certainty of the elemental Hg generator, the water vapor dilution (if applicable), and the chlor ine dilution. In the interim oxidized Hg protocol, the oxidation efficiency of ThermoFisher systems is not included in the overallTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-12

combined uncertainty calculation. However, the app arent percent conversion of elemental Hg to HgCl 2 is calculated as part of the periodic QA (data qual ity) assessments. 82

For the Tekran’s oxidized mercury calibrator that u ses an evaporative gas generator, NIST traceability may be achieved in a different ma nner because NIST-traceable solutions are available and it is possible to verify the precisio n of the metering pumps, etc., used in the device. For a reason that is not clear, comparisons of this type of oxidized Hg gas generator (Tekran 3315 or any other evaporative type) against element al gas generators have shown a fairly consistent difference of about 8% to 9%, with the i onic calibrator always producing a lower level. Because of the consistency of this differen ce, this type of oxidized Hg calibration gas generator can be certified by NIST. 83 This approach does not involve an actual measurem ent to verify the output concentration, but relies on the calibrated, theoretical value.



### Measurement Bias and Bias Adjustment Factor

When a measurement device indicates a different val ue than a reference method (RM) and that difference is consistent, the difference i s regarded as bias. To correct for this difference and make the reported values consistent with the RM , bias adjustments (up or down) may be made. Part 75 requires bias adjustments for SO 2 , NOx, and volumetric flow rate monitoring systems, based on data collected during relative ac curacy test audits (RATAs), but Part 60 does not require such adjustments.
When compliance is achieved under a trading mechani sm, the measurements provide the “currency” used in the allowance market and an exce ss in emissions can be made up through purchase of allowances in the market. Bias adjustm ents may, at the discretion of the regulatory agency, be required if the RM shows a consistently higher value than the monitor during the RATA (i.e., the CEMS is biased low) and the differe nce is statistically significant. The regulatory agency may require the subsequent data f rom the CEMS to be adjusted upward to agree with the RM; consequently, the reported emiss ions will be higher than would otherwise be indicated by the monitor. Similarly, downward bias adjustment may be required if the CEMS consistently reads higher than the RM. Under the A cid Rain Program, the U.S. EPA has, since 1993, required bias adjustment of SO 2 , NOx, and volumetric flow rate data only in one di rection (i.e., upward), to correct for low bias. However, under a compliance mechanism where trading is not an option, there may be an argument to require bias adjustments in both directions, rather than adjusting only for low bias. This is because there is no ability to sell excess allowances or to purchase allowances that are needed. The potent ial problem if there is no requirement to adjust for low bias is that it could open an opport unity for sources to deliberately adjust their Hg CEMS to read below the reference method, while stay ing marginally within the percent relative accuracy requirements when performing a RATA. This could result in under-reporting of emissions. 77

The issue of bias adjustment was raised in testimon y before the Illinois Pollution Control Board by representatives of electric generators. 76 The Illinois EPA subsequently agreed to remove bias adjustments from its rule. 85 However, for the most part the Illinois power pla nts are complying with a percent reduction requirement or a lternatively with a technology-based standard and therefore have been given the option o f quarterly stack tests rather than Hg CEMS. This is a different situation than would exist with an annual mass emission limit where the argument in favor of bias adjustments is stronger. As a result, the argument in favor of bias adjustments is not as great under Illinois’ rule.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-13


### Accuracy/Precision at Low Concentrations
Accurate and precise mercury measurements are becom ing increasingly important at low mercury concentrations because some APCDs (or combi nations of APCDs) are capable of producing removal efficiencies of mercury that can result in emissions concentrations well below 1.0 μg/m 3 . Furthermore, some states have required 90% and g reater removal of mercury from flue gases. Accuracy relates to how close the meas urement is to the actual number. Precision relates to how repeatable a measurement is at a giv en level. Both qualities are desirable.
The CVAF method is capable of measuring mercury con centrations at levels far lower than what is seen in flue gas, as demonstrated in i ts use in ambient monitoring. However, there is some concern regarding its accuracy and precisio n at low concentrations when it is used to analyze flue gas samples that are transported throu gh a probe, sample line, sample conditioning, etc. Also, there is concern about the ability to v erify low Hg concentrations against a RM, such as Ontario Hydro or Method 30B (STs), which may hav e poorer accuracy and precision at lower concentrations.
As shown in Figure 2-5, Hg CEMS have demonstrated t he ability to measure mercury concentrations well below 1.0 μg/m 3 and to agree with the Ontario Hydro Method (the RM ) measurements within about 0.09 μg/m 3 . The trend shown indicates good precision when compared against the RM, and an accuracy that has a relatively steady offset that is generally under 0.10 μg/m 3 . Figure 2-6, which shows data taken from a stack with a wet scrubber, shows that good agreement between Hg CEMS and Method 30B has also been achieved at levels well under 1.0 μg/m 3

. Because the absolute difference between the RM and the Hg CEMS at low concentrations may be a significant percentage of the average RM v alue, this can be an issue of concern when calculating the percent relative accuracy of the CE MS and when making bias adjustments (if such adjustments are required). If, during a RATA, the measurements are expected to be well under 1.0 μg/m 3 , as shown in Figure 2-5 and Figure 2-6, it may be difficult to achieve a particular relative accuracy (RA) percentage (e.g. , 20% RA). Therefore, an alternative RA standard, in terms of the absolute difference betwe en the RM and CEMs mean values is sometimes needed. At these low concentration level s, the error band allowed by the alternative RA specification should be sufficiently large to en sure that well-running instruments will pass the RATAs, yet not so great as to make it impossibl e to fail the test. In the original requirements under CAMR, the alternative RA specification was 1 μg/m 3 absolute difference. That specification was based on an initial assumption th at a low emitting source would have Hg concentrations of about 5 μg/m 3 . At the time CAMR was published, the U.S. EPA cou ld not have anticipated the extremely low Hg concentration levels that have since been observed at many units equipped with wet scrubbers. For concen trations of 1 μg/m 3 or less, the alternative RA specification in the vacated CAMR is obviously t oo wide; a specification on the order of 0.3 to 0.5 μg/m 3 would appear to be more appropriate.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-14

Figure 2-5. RATA results at low mercury concentrat ions 71

Figure 2-6. Low level Hg CEMS accuracy check again st sorbent traps on a stack that follows a wet scrubber or wet stack 71



### Availability and Data Substitution
Availability is a measure of the number of hours in an operating period that the monitoring system is providing reliable data, and i s generally expressed as a percentage of the operating hours. Data substitution is sometimes re quired for periods in which a monitored facility is operating, but the emissions monitoring system is not providing reliable data (not available). For example, the Acid Rain Program req uires substitute data to be reported in the periods of time when the monitoring system is not a vailable. The monitoring requirements under the vacated CAMR required the use of missing data s ubstitution for Hg concentration. The substitute data values became increasingly more con servative (i.e., conservatively high) as the percent monitor data availability (PMA) dropped and the length of the missing data period increased. If the PMA ever dropped below 70%, the maximum potential Hg concentration would have been reported.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-15

Even absent trading, due to the variability in merc ury emissions, there is an argument for maintaining high data availability. Mercury emissi ons are sensitive to many factors that can vary routinely for a power plant, such as furnace oxygen (through its impact on fly ash carbon), soot blowing, coal mercury levels and other factors.

Figure 2-7 shows results of a RATA at Nebraska Publ ic Power’s Sheldon Unit 2. Measured mercury concentrations varied by more than a factor of two over the period of the RATA, comparing an Hg CEMS (shown in figure as HgT) versus sorbent traps as the reference method (shown as 30B). As a result, data substitut ion can be inaccurate and periods of lost data should be minimized.

Figure 2-7. Nebraska Public Power Sheldon 2 RATA r esults 86

There are several factors that affect Hg CEMS avail ability, including the following:

• Stringency of Regulation – If QA testing requiremen ts are stringent, then there is likely to be more down time because failure of a QA test will require troubleshooting.

• Technician Skill Level – This will vary from plant to plant. The higher the skill level of the technicians, the faster they will be a ble to restore an instrument to service in the event of a failure.

• Priority of Preventive Maintenance (PM) Program – I s the PM program at the plant a management priority that has adequate resou rces? If not, then maintenance in general for all equipment will be po or and uptime will suffer. HgT = Total Mercury from Hg CEMS CEM Ave = average Hg CEMS reading during sorbent trap samp le period 30B = Sorbent Trap measurement run diff = the difference between CEM Ave and Sorbent Trap
allowed = allowed difference for RATA 9 run mean difference = average difference for nine RATA runsTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-16

• Spare Parts Stocking – If spares are on hand, the i nstrument can be restored to service faster than if parts must be ordered.
According to ThermoFisher, customers that are consc ientiously operating and maintaining the equipment, even with no current rep orting requirements, have been able to keep the instruments operational about 90-98% of the tim e. 33

Availability is a concern for new technology. Alth ough few states require reporting of availability, Massachusetts did request that the co al plants in Massachusetts report availability of their Hg CEMS. As shown in Table 2-1, the Hg CEMS at the Brayton Point station reported availability ranging from 88% to 94%. 87 The Mount Tom generating station reported 98% availability. 88

Strictly speaking, the reported availability statis tics in Table 2-1 for Hg CEMS in Massachusetts are not subject to the Part 75 requir ements of CAMR because those requirements were vacated when the CAMR was vacated. Also, ther e are some aspects of the original Part 75 CAMR that have since evolved out of technical neces sity, particularly with regard to the move to on-site calibration gas generators that will be NIS T-traceable rather than use of NIST-traceable compressed gas cylinders. The reported data are no t QA-tested by the Massachusetts Department of Environmental Protection (DEP) in exa ctly the same manner as the U.S. EPA would have done under a Part 75 requirement because the U.S. EPA – who has the capability to perform Part 75 data QA - lost the authority to per form data QA when CAMR was vacated. According to the Massachusetts DEP, 89 the Massachusetts requirements under 310 CMR 7.00 et al. are otherwise identical to those of the now-vac ated Part 75 CAMR requirements. The units in Massachusetts must undergo the same daily calibrati on checks, weekly system integrity checks, quarterly linearity checks, RATAs, and other requir ements of the now vacated Part 75, and these availability statistics and the good quality emissi ons data being generated are a strong indication of the industry’s efforts and ability to operate Hg CEMS.

Table 2-1. Availability of Hg CEMS at Dominion Bra yton Point power plant in 2008 86

Quarter 1 Quarter 2 Quarter 3 Quarter 4 Overall Operating Hours 1,536 2,076 2,102 2,159 7,873
Out of Service Hours 96 223 87 52 458 Unit 1 Availability, % 93.7 89.3 95.9 97.6 94.2 Year-to-date Availability, % 93.7 91.17 92.89 94.2 Operating Hours 2,184 2,116 1,994 2,208 8,501 Out of Service Hours 140 123 415 346 1,024 Unit 2 Availability, % 93.6 94.2 79.2 84.3 88.0 Year-to-date Availability, % 93.6 93.88 89.23 88.0 Operating Hours 2,170 1,422 1,929 2,072 7,593
Out of Service Hours 359 253 55 104 771 Unit 3 Availability, % 83.5 82.2 97.1 95.0 89.8 Year-to-date Availability, % 83.5 82.96 87.92 89.8

Missing data are normally substituted under a Part 75 system because trading programs rely on knowing the total mass emissions. Under a rule where a percent reduction or implementation of a specific control technology is required, it could be argued that data substitution may not be necessary. On the other ha nd, in the case where there is a mass emissions limit, it could be argued that data subst itution should be performed to ensure that massTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-17

emissions are not under-reported. Also, data subst itution for missing data provides motivation for maintaining a high availability of the instrume nt.



### 2.5. Sorbent Trap Method

2.5.1. Sorbent Trap Method Description The ST method is an approach to measuring total mer cury emissions over a period of time. The continuous measurement method was addres sed by Appendix K of the Part 75 requirements of the now vacated CAMR. The U.S. EPA Method 30B has replaced Appendix K and is a reference method that can be used for RATA s as well as for monitoring. The ST method is pictured in Figure 2-8. Gas is drawn through tw o separate traps concurrently. Two traps are necessary for the purpose of quality assurance, and agreement must be within prescribed levels or the sample fails QA. The two traps can be insta lled within the same probe or in separate probes. The mercury traps must also be installed i n the probe such that gas is pulled directly into the traps. The method assumes that there is not a significant concentration of particulate matter in the flue gas. A common trap sorbent material is activated carbon impregnated with iodine or another halogen, such as bromine. For continuous m onitoring each trap must have the sorbent configured into three sections that can be tested i ndependently. The first section is for primary mercury collection. The second section is to provi de an indication of mercury breakthrough. If there is too much breakthrough, the sample fails QA . The third section is for spike recovery testing using a spiked mercury sample gas. Analysi s of the third section must show good recovery of the spiked sample for acceptable result s. After a period of sampling, the traps are removed and analyzed to measure the total amount of mercury in the traps. The mercury found in the traps divided by the total gas flow over the period of the sampling indicates mercury concentration in the gas.
The balance of the sampling system includes a moist ure removal system, dry gas flow pump, and dry gas flow meter (or other equivalent m ass flow equipment), and related instrumentation. The flow meter and associated ins trumentation (barometer and temperature indication) must be regularly calibrated to ensure that they are reporting the correct volume of gas. The flow meter must also have a variable flow control to maintain sample flow rate in proportion with load.
Because of the QA requirements that could cause a s ample to be rejected, most users replace traps every four to seven days. This assur es that if a sample is rejected for QA reasons, only four to seven days of data are lost. 90Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-18

Figure 2-8. Method 30B sorbent trap equipment 91

The two most widely used approaches to analyzing th e traps for mercury are: 1) a wet digestion method using atomic absorption or fluores cence analysis; and 2) thermal release with atomic absorption analysis. The latter approach ca n be done on site with the proper equipment. However, it has the disadvantage that the sample is destroyed, so that if there is a problem with the analysis it cannot be checked again.
Sorbent traps can be used as a reference method aga inst a CMMS or as a CMMS. Sorbent trap requirements as CMMS were defined unde r CAMR as Appendix K. As a reference method, STs are the U.S. EPA Method 30B. Because i t is used as a reference method, Method 30B has different QA requirements than Appendix K i n terms of spike recovery, etc., and is somewhat different in procedure.



### 2.5.2. Sorbent Trap Accuracy/Precision The ST method for measuring mercury generally has g ood measurement accuracy down to relatively low mercury concentrations well under 1 μg/m 3 . This can be influenced by sample time, trap size and other parameters that the user can control depending upon their needs. Figure 2-9 92 and Figure 2-10 93 show results from six different RATA’s from six di fferent power plants, in each case (a), (b) and (c) showing results for l ow concentrations (under 1 μg/m 3 ), moderate concentrations (about 1 μg/m 3 ), and higher concentrations (over 1 μg/m 3 ), respectively. Relative accuracy can be more difficult at the lower concent rations because there appears to be more variation in concentration on a percent of value ba sis at these low levels of mercury. The sorbent trap CMMS in the figure being compared to a sorbent trap reference method (Method 30B) follow the Appendix K protocol. In these cases bot h sorbent trap methods (either Appendix K or Method 30B) were being drawn at the same time. The refore, in each case there was a comparison of total mercury collected in the traps over the same period.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-19



### (a)

(b)

(c)

Figure 2-9. RATA results reported by Wright and Sc hmid 92 with (a) concentrations under 1 μg/m 3 ; (b) concentrations near 1 μg/m 3 ; and (c) concentrations over 1 μg/m 3Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-20



### (a)

(b)

(c)

Figure 2-10. RATA results reported by Wright 93 with (a) concentrations under 1 μg/m 3 ;

(b) concentrations near 1 μg/m 3 ; and (c) concentrations over 1 μg/m 3Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-21



### 2.6. Approximate Costs of Sorbent Trap Systems
The initial installed cost of a sorbent trap system is on the order of $150,000. Operating costs entail roughly $500 to $700 per week for trap s and analysis ($26,000 to $36,000 per year). 66,75 The cost of labor for operating the traps corresp onds to about two people for half a day per stack every four to seven days. 93 At $50/hr for labor, that is roughly another $21,0 00 to $36,000 per year.



### 2.7. Advantages/Disadvantages of Sorbent Traps When Comp ared to Hg CEMS
The advantages of STs versus Hg CEMS are:

• Significantly lower capital cost - The principal ad vantage of STs over Hg CEMS is much lower capital cost – about $150,000 versus about $500,000.

• Simpler system to operate and maintain – Sorbent tr ap systems are less complex than Hg CEMS and do not require as sophisticated a technical staff to support. However, the personnel involved in STs do need trai ning on how to properly handle the traps to avoid contamination and other p roblems that could introduce

errors.

• Lower concentrations - In principal, STs may be abl e to measure to lower concentrations than Hg CEMS, but this is very metho dology dependent. Furthermore, Hg CEMS are improving their ability to measure to low levels such that any advantage in this respect may be small.
Disadvantages of STs versus Hg CEMS are:

• No real-time, or near real-time data – This is the principal technical advantage of Hg CEMS over STs. The information is available in minutes, which enables the performance of Hg emission control processes to be monitored in near real time and can thereby offer advantages in Hg control. Fi gure 2-11 shows how Hg CEMS data and ST data compare at one facility equip ped with a wet scrubber over a period of 5 days and 30 days, respectively. As shown, there was a wide variation in Hg emissions that was not evident in t he ST results, since the latter were inherently averaged over the trap sample time.

• Higher Labor Costs - This may not have been realize d yet since Hg CEMS have been coming down a fairly steep learning curve, whi ch means that owners have had to dedicate more hours to service and support t han they ultimately will in the future. Sorbent traps, on the other hand, will alw ays require regular trap replacement and testing (typically every four to se ven days) and the labor associated with replacing and testing the traps is not likely to drop very much.

• Loss of Data – If there is a problem with a ST samp le, it may not be discovered until after the sample is completed, and when ST sa mples fail the quality control tests, the data are lost for the full sampling peri od. For this reason, ST systems have quality control procedures in place to minimiz e this risk, and in practice samples are limited to about four to seven days. F or Hg CEMS the existence of a problem that would cause lost data is generally app arent right away, so thatTechnologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-22

corrective action can be immediately taken to resto re the instrument to a fully functioning state.

• Personnel Safety – STs require that personnel regul arly go up to the sampling point to remove and replace sorbent traps. This cr eates an added concern for personnel safety.

• Speciation – Although only total Hg emissions would have been reported under the vacated Part 75 CAMR requirements, oxidized Hg and elemental Hg do behave differently in terms of capture and in terms of how they behave once released to the environment. Therefore, there is a benefit with respect to emissions control and with respect to understanding environmental impact in having speciated Hg emissions information. Althoug h speciated Hg measurement approaches are available using STs, they are diffic ult to conduct due to the reactivity of oxidized mercury. Additionally, ther e is limited experience with taking speciated ST measurements.

• Process Steps - There can be many people and steps necessary to assure a good measurement; a mistake at any point in the process could introduce error.

• Hazardous Wastes - Hazardous wastes can be generate d from the analysis methods that need to be disposed of in accordance w ith procedures for handling and disposing of hazardous materials.

• Trap Analysis - The analysis of the trap (thermal d esorption or wet chemical analysis) destroys the sample, so that it can not b e checked in the event of an analysis error.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-23



### (a)

(b)

Figure 2-11. Hg CEMS performance compared with Sor bent Traps 94Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-24



### 2.8. Availability of Sorbent Traps used as CMMS

Because reporting of Hg monitoring data has not bee n required in many states, there are limited data on reported availability of the method . However, information on short-term experience (under six months) using Part 75 availab ility requirements has shown availability generally over 90%. Figure 2-12 shows availability data over several months for eight different STs. Also, as shown in Table 2-2, year-long data from Dominion reported to Massachusetts on its Salem Harbor Units 1 through 3 CMMS show availability of 89% to 96%. 94

Figure 2-12. Sorbent Trap availability reported by Wright and Schmid 96

Table 2-2. Availability information for Dominion S alem Harbor Units 1, 2, 3 CMMS 94

Unit 1 Unit 2 Unit 3 Online operating hours 5,922 6,209 3,620 Monitored hours 5,263 5,587 3,480 Total operating hours of downtime 659 622 140 Availability 89% 90% 96% Missing data caused by: Monitor not operated* 269 82 0
Monitor malfunction/maintenance 12 74 129** Trap QA/QC*** 360 429 0 Trap change out 5 17 3 Monitor calibration 13 12 8 * Early in the monitoring program the monitor operating parameters (e.g., vacuum, trap flow) wer e not well enough understood to use as predictive information to change out traps in a timely manner to avoid the monitor shutting down on its own. Automated alerts were not sufficient. The issue has since been res olved. ** One recurring maintenance issue caused the b ulk of this downtime. The issue has since been res olved.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-25

*** Initially the sorbent traps were not able to sample for longer than three days due to a loss of spike recover. In June 2008, the design of the traps was improved, wh ich allowed the duration of the run to increase. Subsequently, data loss due to trap quality assuran ce/quality control (QA/QC) has been greatly reduced

.

Strictly speaking, the reported availability statis tics in Table 2-2 for the STs in Massachusetts are not subj ect to the Part 75 requirements of the CAMR because those requirements were vacated when t he CAMR was vacated. And as discussed previously, some changes from the origina l Part 75 CAMR protocol have been made out of technical necessity. In other words, these changes would have occurred even if CAMR were still in place. According to the Massachusett s DEP, 89 the Massachusetts requirements under 310 CMR 7.00 et al. are otherwise identical t o those of the now vacated Part 75 CAMR requirements, and these availability statistics and the good quality emissions data being generated are a strong indication of the industry’s efforts and ability to use STs for the continuous monitoring of mercury emissions.



### 2.9. Approximate Number of Units Installed/In Operation
According to ThermoFisher, over 450 of its Hg CEMS systems have been shipped to date. Of the 450, more than 160 systems were insta lled directly by ThermoFisher, and the balance of the Hg CEMS were installed by CEMS syste m integration companies – other companies that purchase the analyzer from ThermoFis her and install it at the customer’s site. Because the manufacturers, ThermoFisher and Tekran, sell spare parts, provide service, and in many cases monitor instruments remotely, they can e stimate the number of Hg CEMS in operation. Of the total 450 Hg CEMS, ThermoFisher estimates that about 375 are actively in operation in the U.S. 33 About 75 of the ThermoFisher systems are not acti ve at least in part because some owners do not currently have a need to monitor mercury emissions and are choosing to avoid the cost of operating the systems . According to Tekran, of the 175 systems sold, approximately 140 are in operation and 100 ha ve completed RATA testing. The balance of the systems represents later orders that are still in the process of installation and startup. 75

In 2009, NESCAUM surveyed nine states and one city as to the purchase and usage of Hg CMMS. These data are summarized in Table 2-3. In these states, 116 CEMS and 44 ST systems had been purchased. Most of the CEMS (73%) were installed and operating, but only a third of the ST systems were installed and operatin g. Half of the states required the collection of Hg emissions data and information on the availabili ty of the CMMS.
A CMMS being active does not mean that the company is reporting data. The reason many companies operate Hg CMMS (even without a curr ent requirement to operate them or to report data) is because of the anticipated need to do so in the future and the benefit gained from the experience of operating them prior to facing a regulatory requirement.
With few exceptions, RATA tests and other tests suc h as system integrity tests have been performed for the purpose of verifying that the sys tems met their contractual performance requirement rather than an emissions reporting requ irement imposed by a regulation. Therefore, the results of these tests are not publicly availab le unless they were published in a paper or other forum.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-26

Table 2-3. NESCAUM 2009 survey of Hg CMMS in nine states and one city

Data Summary
Number of states surveyed 9
Number of cities surveyed 1
States/city collecting Hg data 5

States collecting monitoring reliability/availability data 4

Hg CEM Prevalence CEMS purchased 116
CEMS installed 99 CEMS operating 85

ST Prevalence STs purchased 44
STs installed 20 STs operating 14 Number of Units Sold per Vendor: Thermo Fisher Hg CEMS 34+ Tekran Hg CEMS 9+ Apex STs 5

Frontier Geosciences STs 1 Monitors’ First Year of Use

2006 3

2007 1
2008 41+

2009 28+



### 2.10. Summary
This Chapter examined the technologies for continuo us monitoring of mercury emissions from power plant stacks, including continuous analy zers, or mercury CEMS and sorbent trap methods. Both Hg CEMS and STs are currently being applied to over 700 coal-fired power plant stacks, with over 600 Hg CEMS and about 100 STs.
The findings of this Chapter with regard to Hg CEMS are summarized below:

• Hg CEMS, at roughly $500,000 of capital cost per si te (with some variation due to site specifics), are the more costly of the two approaches to install, but offer advantages that are listed below. There has been a significant learning curve with Hg CEMS, with the technology advancing rapidly and many of the technical challenges that existed with the technology only a few years ago having been addressed.

• Many issues affecting reliability of Hg CEMS have b een addressed, and it is expected that design changes implemented over the p ast few years as Hg CEMS have been installed will improve reliability going forward. Although only a small percentage of Hg CEMS have reported annual emission s data to state agencies,Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 2-27

the reported availability is 90% or greater. In ot her states, power plant owners may be operating Hg CEMS in anticipation of require ments to report such data; however, official availability statistics have not been made available from these states. As more state mercury emission rules take effect, more data should become available.

• Accuracy at low mercury levels has improved. Data indicate that Hg CEMS may offer reliable measurements to well below 1.0 μg/m 3 , which is important for situations where Hg emission controls are in place.

• Mercury calibration gas standards (generators) that are traceable to NIST measurements have been developed. Interim calibrat ion protocols have been established.
The findings of this Chapter with regard to ST meth ods are summarized below:

• Sorbent traps, at about $150,000 of capital cost pe r site (with some variation on this cost due to site specifics), are a lower capit al cost alternative to Hg CEMS. However, STs require regular replacement and testin g (roughly every four to seven days) of the sorbent traps, which entails add itional labor and cost that will continue at that level.

• Although only 3 of the more than 100 installed STs have reported annual emissions data to state agencies (Massachusetts), t he reported availability has been 90% or greater. As more state mercury emissio n rules take effect, more availability data should become available.

• STs appear to offer reliable measurements to well b elow 1.0 μg/m 3 , which is important for situations where Hg controls are in p lace.

• In addition to lower capital cost, STs offer the ad vantage of requiring less sophisticated technical support than that needed fo r Hg CEMS.

• Hg CEMS offer results in minutes, while STs offer i nformation in days.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 3-1



## 3. Conclusions

3.1. Outlook for Control Technologies
Two general approaches for mercury control have, to date, proven capable of effectively reducing mercury emissions at levels of control of 90% or greater on combinations of coal type and APCDs that represent the majority of coal-fired boilers. These approaches involve use of either existing APCDs or dedicated mercury control technology, primarily powdered activated carbon injection.
There are cases where the co-benefit of existing AP CDs alone may be capable of greater than 90% reduction in mercury, but this is not univ ersally true even for similar plant/fuel configurations. The use of oxidation additives or dedicated mercury catalysts has been demonstrated to increase the removal of mercury by wet FGD systems, which is the leading method of obtaining removal of high levels of mercu ry with existing APCDs.
Powdered activated carbon (PAC) is the most widely used mercury sorbent, and in the majority of coal-fired power plants, injection of P AC can achieve mercury removal of 90% or greater. In order for activated carbon to achieve such high levels of removal, special sorbents have been developed for low-halogen environments, f or environments with high concentrations of SO 3 , for plants in which fly ash is sold for concrete manufacture, etc. Different methods of introducing activated carbon into flue gas have als o been developed, including the Mer-Cure TM process and the TOXECON TM and TOXECON II TM processes.

The combination of a wet scrubber and an FGD has de monstrated mercury removal in the range of 70% to 90% on plants burning high-sulfur b ituminous coal. Activated carbon has been shown to be cost-effective for high levels of mercu ry removal at boilers with a cold-side ESP or baghouse that burn low-sulfur bituminous coal, subb ituminous, or lignite coal, as long as the plant does not use flue gas conditioning with the E SP. The U.S. GAO, in its report to Congress, 20 concluded:

While sorbent injection technology has been shown t o be effective with all coal types and on boiler configurations that currently exist at mo re than three-fourths of U.S. coal-fired power plants, DOE tests show that some plants may n ot be able to achieve mercury reductions of 90% or more with sorbent injection sy stems alone.

The situations that the U.S. GAO identified as fall ing short of 90% mercury reduction with sorbent injection alone were: plants burning lignite, plants with hot-side ESPs, and plants with high levels of SO 3 in the flue gas.
Lignite burning coal plants are not a very large ca tegory, comprising approximately 3% of the boilers greater than 25 MW in size in the U. S. Sorbents are currently under development specifically for lignite-fired boilers.
Hot-side ESPs are the only particulate control devi ce on about 9% of boilers; these boilers burn both bituminous and subbituminous coal s. There have been a limited number of full-scale demonstrations of activated carbon speci fically designed for hot-side ESPs. Unless sorbents can be found that are effective at tempera tures greater than about 700 ° F, the best current control option for hot-side ESPs would be to instal l a fabric filter for use with sorbent injection.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 3-2

High levels of SO 3 are produced at plants that burn high-sulfur bitum inous coal (defined as greater than 1.7 wt% sulfur) or that have an SCR and burn bituminous coal. At present, only 17% of boilers burn high-sulfur bituminous coals. Some of the plants that burn high-sulfur bituminous coal have both an SCR and an FGD, and th is combination of APCDs might achieve 90% Hg removal. The high-sulfur bituminous plants that have a cold-side ESP or FF without both SCR and FGD make up only 11% of the US boiler population. This percentage is expected to shrink in the next several years as more bitumin ous-fired plants install advanced NOx and SO 2 controls. Injection of alkaline sorbents, like tro na, can be used to reduce SO 3 in the flue gas and improve the performance of activated carbon. Furth ermore, new carbon-based mercury sorbents are being developed that are tolerant of higher lev els of SO 3

. The other category of plants that have relatively h igh levels of SO 3 are plants burning low-sulfur bituminous, subbituminous or lignite coa l with cold-side ESPs that require flue gas conditioning to meet limits on stack opacity. Appr oximately 24% of boilers with cold-side ESPs use flue gas conditioning, which represents 15% of the overall boiler population. As noted above, SO 3 -tolerant sorbents are being developed to address t he difficulty in achieving 90% mercury removal in these systems. Trona injection has been proposed as an alternative to SO 3 as a flue gas conditioning agent and there are other a lternative flue gas conditioning agents under development. Another, but more expensive alternati ve, is to install a fabric filter after the ESP and to inject the sorbent into the fabric filter.
Another consideration in the implementation of acti vated carbon injection for mercury control is the potential loss of revenue for plants that sell their fly ash for concrete manufacture. Plants that fire low-rank coal and sell their fly a sh represent about 23% of boilers in the U.S., while 21% of plants that fire bituminous coal sell their fly ash. Forty-two percent of the fly ash sold in the U.S. goes toward the production of conc rete. Adding enough activated carbon to achieve 90% removal can ruin the economic value of the fly ash, if the fly ash is sold for concrete manufacture. The Mer-Cure TM process, which requires low activated carbon injec tion rates to achieve high levels of removal, might allo w for the sale of fly ash. Several sorbent vendors offer activated carbon that is specially tr eated to allow the fly ash-sorbent mixtures to be made into acceptable concrete. An alternative is t o segregate the fly ash collection from the sorbent collection by using the TOXECON TM or TOXECON II TM configurations.
Regarding the cost of mercury controls, the detaile d, test data-based NETL cost analyses compared well with the recent U.S. GAO survey-based costs for sorbent technologies (ACI). Sorbent-based Hg reduction costs should range betwe en about $6000/lb to $30,000/lb when byproduct contamination/sales are not a factor and be tween about $18,000/lb and $50,000/lb if ash revenue is lost (note that ash revenues/losses can vary greatly across geographical areas and its impact can deviate from these values depending on s ite-specific market conditions). These estimates correspond to 20-year levelized COE of 0. 35 to 2 mills/kWh and 1 to 3.5 mills/kWh respectively. Capital costs for sorbent injection technologies were found to be in the $5/kW to $15/kW range, while special applications, such as f abric filter-based TOXECON TM , are likely to cost $120/kW to $150/kW.
Mercury oxidation technologies, catalysts and addit ives primarily used in wet FGD plants have lower capital costs, about $1-$2/kW for additi ves and $2-$4/kW for catalysts. Twenty-year
levelized COE is under 1 mill/kWh for additives and between 1 and 2 mills/kW-hr for catalyst technologies.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 3-3



### 3.2. Outlook for Measurement Systems
CMMS are currently deployed on a subset of coal-fir ed power plants in the U.S. There are two types of CMMS: 1) CEMS, which measure mercu ry in the gas phase using CVAF or AAS, and 2) STs, which collect mercury on substrate and then analyze the mercury in the substrate after collection. Hg CEMS, at roughly $500,000 of capital cost per si te, are the more costly of the two approaches to install. Many issues affecting relia bility of Hg CEMS have been addressed, and it is expected that design changes implemented over th e past few years as Hg CEMS have been installed will improve reliability going forward.
Although only 5 of the more than 600 Hg CEMS have r eported annual emissions data to state agencies, they have reported availability of about 90% or greater. In other states power plant owners may be operating Hg CEMS in anticipati on of requirements to report such data; however, official availability statistics have not been made available from these states. As more state mercury emission rules take effect, more data should become available.
There has been a significant learning curve with Hg CEMS with the technology advancing rapidly. Many of the technical challenge s that existed with the technology only a few years ago have now been addressed. Accuracy at low mercury levels has improved. Data indicate that Hg CEMS may offer reliable measuremen ts to well below 1.0 μg/m 3 , which is important for situations where Hg emission controls are in place. Calibration gas standards and calibration gas generators that are traceable to NI ST measurements have been developed. Interim calibration protocols have been established

. Sorbent traps, at about $150,000 of capital cost pe r site, are a lower capital cost alternative to Hg CEMS. However, STs require regul ar replacement and testing (roughly, every four to seven days) of the sorbent traps, which ent ails additional labor and cost that will continue at that level. Thus, the operating costs of STs mi ght be higher than those of Hg CEMS.
Although only 3 of the more than 100 installed STs have reported annual emissions data to state agencies (Massachusetts), the reported ava ilability is 90% or greater. As more state mercury emission rules take effect, more availabili ty data should be reported. STs appear to offer reliable measurements to well below 1.0 μg/m 3 , which is important for situations where Hg controls are in place. In addition to lower capita l cost, STs offer the advantage of requiring less sophisticated technical support than that needed fo r Hg CEMS.
The choice between Hg CEMS or STs for continuous me rcury monitoring will be influenced by a number of factors that are specific to a particulate plant. Hg CEMS offer results in minutes, while STs offer information in days. I f information on Hg emissions is desired on a daily basis in real-time, then a CEMS are a better choice. At present, Hg CEMS require more technical training and sophistication for the opera tor than STs, although this distinction might fade as manufacturers of CEMS improve the product o fferings. The level of technical training of plant personnel is therefore an issue in selecting a CMMS. Sorbent traps are able to measure mercury with good accuracy to well below 1.0 μg/m 3 . If the mercury concentration in the stack is well below 1.0 μg/m 3 , then an ST system is at present a better choice. As Hg CEMS vendors continue to improve the detection limits of the ins truments, this distinction might disappear in the future. Finally, the capital and operating cos ts of the two approaches might also influence the decision for a power plant.Technologies for Control & Measurement of Mercury E missions from Coal-Fired Power Plants in the United States: A 2010 Status Report 4-1



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