FULL SCALE CALCIUM BROMIDE INJECTION WITH SUBSEQUENT MERCURY
OXIDATION AND REMOVAL WITHIN WET FLUE GAS DESULPHURIZATION
SYSTEM: EXPERIENCE AT A 700 MW COAL-FIRED POWER FACILITY
by
MARK SIMPSON BERRY
BHARAT K. SONI, COMMITTEE CHAIR
RAMSAY CHANG
MELINDA M. LALOR
LARRY S. MONROE
PETER M. WALSH
A DISSERTATION
Submitted to the graduate faculty of The University of Alabama at Birmingham,
in partial fulfillment of the requirements for the degree of
Doctor of Philosophy
BIRMINGHAM, ALABAMA
2012
Copyright by
Mark Simpson Berry
2012
ii
FULL SCALE CALCIUM BROMIDE INJECTION WITH SUBSEQUENT MERCURY
OXIDATION AND REMOVAL WITHIN WET FLUE GAS DESULPHURIZATION
SYSTEM: EXPERIENCE AT A 700 MW COAL-FIRED POWER FACILITY
MARK SIMPSON BERRY
INTERDISCIPLINARY ENGINEERING
ABSTRACT
The Environmental Protection Agency promulgated the Mercury and Air Toxics
Standards rule, which requires that existing power plants reduce mercury emissions to
meet an emission rate of 1.2 lb/TBtu on a 30-day rolling average and that new plants
meet a 0.0002 lb/GWHr emission rate. This translates to mercury removals greater than
90% for existing units and greater than 99% for new units. Current state-of-the-art
technology for the control of mercury emissions uses activated carbon injected upstream
of a fabric filter, a costly proposition. For example, a fabric filter, if not already available,
would require a $200M capital investment for a 700 MW size unit. A lower-cost option
involves the injection of activated carbon into an existing cold-side electrostatic
precipitator. Both options would incur the cost of activated carbon, upwards of $3M per
year. The combination of selective catalytic reduction (SCR) reactors and wet flue gas
desulphurization (wet FGD) systems have demonstrated the ability to substantially reduce
mercury emissions, especially at units that burn coals containing sufficient halogens.
Halogens are necessary for transforming elemental mercury to oxidized mercury, which
is water-soluble. Plants burning halogen-deficient coals such as Power River Basin
(PRB) coals currently have no alternative but to install activated carbon-based
approaches to control mercury emissions.
This research consisted of investigating calcium bromide addition onto PRB coal
as a method of increasing flue gas halogen concentration. The treated coal was
combusted in a 700 MW boiler and the subsequent treated flue gas was introduced into a
wet FGD. Short-term parametric and an 83-day longer-term tests were completed to
determine the ability of calcium bromine to oxidize mercury and to study the removal of
iii
the mercury in a wet FGD. The research goal was to show that calcium bromine addition
to PRB coal was a viable approach for meeting the Mercury and Air Toxics Standards
rule for existing boilers.
The use of calcium bromide injection as an alternative to activated carbon
approaches could save millions of dollars. The technology application described herein
has the potential to reduce compliance cost by $200M for a 700 MW facility burning
PRB coal.
Keywords: mercury emissions, mercury oxidation, calcium bromide injection, mercury
removal, mercury reemission, Powder River Basin coal
iv
DEDICATION
I dedicate this body of work to my loving family. Particularly, I recognize my
wife, Crystal Y. Berry, who sacrificed greatly to make this work possible. This
dissertation would not have been possible without the inspiration of my father, Dr.
Simpson Berry, Jr., and my brother, Edward J. Berry, Esquire. My father and brother
have both inspired me by setting and achieving extremely high goals. Also, I thank my
mother, Gwendolyn Nell Berry, whose never-ending support made me feel that anything
was possible. I hope that the accomplishment of completing this dissertation might
inspire my children, Brandiece N. Berry, Simpson Berry III, Mark Christian Berry, and
James Stephen Berry, to reach and even exceed their own potential.
v
ACKNOWLEDGMENTS
I thank Dr. Peter Walsh for his never-ending patience with me during this very
long process and for his guidance. I also thank the members of my dissertation
committee: Dr. Ramsay Chang, with the Electric Power Research Institute; Dr. Larry
Monroe; Dr. Melinda Lalor; and Dr. Bharat Soni.
I thank Dr. Bernhard Vosteen for his mentorship and guidance in the
demonstration of bromine injection technology. Our professional relationship has
developed into a friendship for which I am very grateful. I thank the team at URS
Corporation that worked over a four-year time period collecting the information reflected
in this dissertation. More specifically, I thank Katherine Dombrowski, PE, who served as
the project manager from URS. I also thank Gary Blythe, Tom Machalek, Jenny Paradis,
and Mandi Richardson of the URS Team. I thank Dr. Larry Monroe and Nick Irvin, PE
of Southern Company Services for their contribution to this research.
Last, I thank many people at Southern Company Services who encouraged me to
finish my degree, Mr. Steve Wilson, PE, Dr. Charles Goodman (retired), Mr. Chris
Hobson, and Mr. Paul Bowers.
I recognize Alabama Power Company, Southern Company Services, and the
Electric Power Research Institute (EPRI) for providing the financial support for this
work. Also, I thank the Electric Power Research Institute for allowing me to share these
results with the broader scientific community.
vi
TABLE OF CONTENTS
Page
ABSTRACT ....................................................................................................................... iii
DEDICATION .................................................................................................................... v
ACKNOWLEDGMENTS ................................................................................................. vi
LIST OF TABLES ............................................................................................................. xi
LIST OF FIGURES ......................................................................................................... xiv
LIST OF ABBREVIATIONS ........................................................................................ xviii
CHAPTER
1. INTRODUCTION AND RATIONALE ................................................................. 1
1.1
1.2
1.3
1.4
1.5
1.6
1.7
Regulatory Background ................................................................................. 1
Problem Statement ......................................................................................... 6
Purpose of the Study ...................................................................................... 7
Significance of the Study ............................................................................... 8
Overview of Methodology ............................................................................. 9
Research Hypotheses ..................................................................................... 9
Research Limitations ................................................................................... 10
2. LITERATURE REVIEW AND BACKGROUND INFORMATION ................. 12
2.1
2.2
2.3
2.4
Introduction .................................................................................................. 12
Hg Oxidation ................................................................................................ 13
2.2.1 Homogeneous Oxidation ................................................................. 14
2.2.2 Heterogeneous Oxidation................................................................. 22
Hg Capture in wet FGD ............................................................................... 42
2.3.1 Wet FGD Hg Removal Performance Data....................................... 43
2.3.2 Solubility .......................................................................................... 44
2.3.3 Role of Hg Reemission .................................................................... 46
2.3.4 Partitioning of Hg Within the wet FGD ........................................... 49
Literature Review Synopsis ......................................................................... 51
vii
TABLE OF CONTENTS (continued)
Page
2. LITERATURE REVIEW AND BACKGROUND INFORMATION
2.5
Critical Analysis........................................................................................... 54
2.5.1 Strengths of the Literature ............................................................... 54
2.5.2 Weaknesses of the Literature ........................................................... 55
2.5.3 Importance of the Current Work ...................................................... 56
2.5.4 Issues Not Addressed by the Current Work ..................................... 57
3. METHODS .......................................................................................................... 58
3.1
3.2
3.3
3.4
Introduction .................................................................................................. 58
Research Design........................................................................................... 62
3.2.1 James H. Miller Steam Plant ............................................................ 62
3.2.2 CaBr2 Feed Rates and Coal Br Concentration ................................. 70
3.2.3 Description of the Test Phases ......................................................... 71
Measurement Techniques ............................................................................ 78
3.3.1 Flue Gas Measurement Techniques ................................................. 78
3.3.2 Liquid and Solid Measurement Techniques .................................... 86
Statistical Methods ....................................................................................... 90
3.4.1 Description of the Data .................................................................... 90
3.4.2 Descriptive Statistics ........................................................................ 93
3.4.3 Statistical Tests Used to Evaluate Population Means ...................... 93
4. RESULTS .......................................................................................................... 97
4.1
4.2
4.3
4.4
Introduction .................................................................................................. 97
Hypothesis 1................................................................................................. 98
4.2.1 Baseline Hg Oxidation Analysis ...................................................... 98
4.2.2 Equipment Configuration Impacts
on Baseline Hg Oxidation .............................................................. 105
4.2.3 Effect of SO2 Concentration .......................................................... 108
4.2.4 Effect of Flue Gas HBr and HCl Concentration ............................ 109
4.2.5 Operational Impacts on Hg Oxidation ........................................... 111
4.2.6 Summary ........................................................................................ 117
Hypothesis 2............................................................................................... 120
4.3.1 CaBr2 Addition Rate Strategy ........................................................ 120
4.3.2 Heterogeneous versus Homogeneous Oxidation ........................... 125
4.3.3 Summary ........................................................................................ 131
Hypothesis 3............................................................................................... 132
4.4.1 Wet FGD Hg Removal Efficiency ................................................. 132
4.4.2 Evaluation of Hg Reemission ........................................................ 135
4.4.3 Insights Into the Occurrence of Reemission .................................. 139
viii
TABLE OF CONTENTS (continued)
Page
4. RESULTS
4.5
4.6
4.7
4.4.4 An Evaluation of Br/Hg Ratio ....................................................... 146
4.4.5 Summary ........................................................................................ 147
Hypothesis 4 .............................................................................................. 148
4.5.1 Analysis of Phase III Hg Emissions............................................... 148
4.5.2 Impact of Coal Characteristics ....................................................... 154
4.5.3 Impact of Load ............................................................................... 158
4.5.4 Impact of Calcium Bromide Addition ........................................... 166
4.5.5 Comparison of Hg Emissions from
Unit 3 and Unit 4............................................................................ 167
4.5.6 Br/Hg Ratio Impact on Hg Removal Performance ........................ 167
4.5.7 Summary ........................................................................................ 168
Hypothesis 5............................................................................................... 169
4.6.1 Overview ........................................................................................ 169
4.6.2 Unit 4 Hourly Average Hg Emission Rate Analysis ..................... 170
4.6.3 Unit 3 and Unit 4 30-Day Hg Emission Rate Analysis ................. 172
4.6.4 Seven-day CaBr2 Addition System Outage Simulation ................. 174
4.6.5 Summary ........................................................................................ 176
Hypothesis 6............................................................................................... 176
4.7.1 Economic Analysis of CaBr2 Addition .......................................... 176
4.7.2 Economic Analysis of Activated Carbon
Injection (ACI) into a Cold-side ESP ............................................ 177
4.7.3 Comparison Cost of 90% Hg Control ............................................ 178
4.7.4 Summary ........................................................................................ 180
5. INTERPRETATIONS AND RECOMMENDATIONS ..................................... 182
6. IMPLICATIONS FOR FURTHER RESEARCH .............................................. 185
LIST OF REFRENCES .................................................................................................. 188
APPENDIX ..................................................................................................................... 199
A.
PHASES I, IIA, IIB, AND III BASELINE MERCURY
OXIDATION INFORMATION ................................................................ 199
ix
TABLE OF CONTENTS (continued)
Page
APPENDIX
B.
PHASES I, IIA, IIB, AND III COAL MERCURY
CONCENTRATION.................................................................................. 202
C.
NORMALITY ANALYSIS ....................................................................... 204
D.
STATISTICAL TEST RESULTS ............................................................. 229
x
LIST OF TABLES
Table
Page
1.1
Summary of the Mercury and Air Toxic Standards (MATS)
Rule for Coal-Fired Power Stations ........................................................................ 3
1.2
Relative Cost of Mercury Control Technologies .................................................... 5
2.1
SCR Key Design Parameters ................................................................................ 26
2.2
Solubility of Various Hg Compounds in Water .................................................... 45
3.1
Coal Analysis Plan ................................................................................................ 65
3.2
Information Used to Calculate Coal Bromine Concentration ............................... 71
3.3
Phase I Test Conditions ........................................................................................ 73
3.4
Phase IIA Test Conditions .................................................................................... 75
3.5
Phase IIB Test Conditions .................................................................................... 76
3.6
Phase III Test Conditions ...................................................................................... 78
3.7
Wet FGD Slurry Analytical Methods ................................................................... 87
3.8
Coal Analytical Methods ...................................................................................... 88
3.9
Gypsum Analytical Methods ................................................................................ 89
3.10
Fly Ash Analytical Methods ................................................................................. 90
3.11
Independent and Dependent Variables Used to Test for
Statistical Significance of the Effect of CaBr2 Injection
on Hg Emissions from Wet FGD .......................................................................... 92
xi
LIST OF TABLES (continued)
Table
Page
3.12
Time Periods During Which Independent and Dependent
Data Were Collected for Statistical Significance Analysis................................... 93
3.13
Statistical Tests Performed in Evaluating Hypothesis 4
and Hypothesis 5 ................................................................................................... 96
4.1
Coal Characteristics Summary ............................................................................ 101
4.2
Important Equipment Design and Operating Data Values
that Affect Hg Oxidation .................................................................................... 107
4.3
Flue Gas HCl, HBr, Cl2 and Br2 Concentrations during
Baseline Conditions ............................................................................................ 110
4.4
Qualitative Summary of Miller Unit 4 Ability to Support
Hg Oxidation ....................................................................................................... 119
4.5
Summary of Hg Oxidation Ratios as a Function of Br/Hg Ratio ....................... 122
4.6
Guidance on Br/Hg Ratio to Achieve Oxidation Ratios Greater
Than 0.9 While Firing PRB Coal as a Function of SCR Status .......................... 124
4.7
Hg Oxidation and Removal Information Collected During
Phases IIA and IIB. ............................................................................................. 134
4.8
Reemission Parameter Qualitative Ranking System........................................... 143
4.9
Summary Operational Information Describing the Potential
for Hg Reemission Events to Occur Within the 2 MW Pilot
Wet FGD During Phases IIA and IIB Testing. ................................................... 145
4.10
Wet FGD Hg Removal Ratio and Reemission Parameter
as a Function of Br/Hg Ratio and SCR Condition .............................................. 146
4.11
Unit 3 Hourly Average Hg Emissions Descriptive Statistics
During CaBr2 Addition Period on Unit 4 and Not During
CaBr2 Addition Period on Unit 4 ........................................................................ 155
xii
LIST OF TABLES (continued)
Table
Page
4.12
Unit 4 Hourly Average Emissions Descriptive Statistics
During September 2010 and January 2011 ......................................................... 157
4.13
Unit 3 Hourly Average Hg Emissions Descriptive Statistics
of Various Load Conditions From September 1, 2010,
Through January 31, 2011. ................................................................................. 159
4.14
Unit 4 Hourly Average Hg Emissions Descriptive Statistics
of Various Load Conditions From September 1-30, 2010,
and From January 1-30, 2011 ............................................................................. 161
4.15
Unit 4 Average Hourly Hg Emissions Descriptive Statistics
of Various Load Conditions From October 1 through
December 19, 2010 ............................................................................................. 164
4.16
Unit 4 Average Hourly Hg Emissions Descriptive Statistics
During Periods With and Without CaBr2 Addition ............................................ 166
4.17
Phase III Br/Hg Ratio Summary Based on Hg Content
Measured in the Coal and Minimum Observed Daily Br
Concentrations (wt ppm on the Dry Coal) .......................................................... 168
4.18
Financial and Miller Unit 4 Operation Assumptions Used to
Calculate Yearly CaBr2 Chemical Costs............................................................. 177
4.19
Financial Assumptions Used to Calculate Activated Carbon
Costs for One Year of Operation at Miller Unit 4 With a
90% Hg Capture Goal When the Unit Operated With
a 90% Capacity Factor ........................................................................................ 178
4.20
Comparison of CaBr2 and Activated Carbon Injection Reagent
Costs Associated With 90% Hg Removal From a Boiler
Burning PRB Coal With an SCR/Cold-side ESP/Wet FGD or
Cold-side ESP/Wet FGD .................................................................................... 180
xiii
LIST OF FIGURES
Figure
Page
2.1
Schematic diagram of the changes in flue gas
composition in an SCR ......................................................................................... 39
2.2
Schematic diagram of Hg reemission reaction pathways ..................................... 48
3.1
Electric utility technology development curve ..................................................... 59
3.2
Diagram of 2 MW slipstream pilot-scale wet FGD installed
for testing at Plant Miller Unit 4 ........................................................................... 70
4.1
Hg oxidation at baseline conditions (i.e., no CaBr2 addition
to the coal) as a function of the location of Hg concentration
measurement and of SCR operating condition ..................................................... 99
4.2
Phase I summary Box and Whisker Plot of load (MW), SCR
inlet and outlet temperatures (°C), SCR inlet and outlet NOx
concentrations (ppmv), and stack SO2 concentration (ppmv) used
to illustrate consistency or variability of operating conditions
when SCR is in service and with NH3 injection ................................................. 112
4.3
Phase IIA summary Box and Whisker Plot of load (MW), SCR
inlet and outlet temperatures (°C), SCR outlet NOx concentration
(ppmv), and stack SO2 concentration (ppmv) used to illustrate
consistency or variability of operating conditions during periods
when SCR is bypassed and when SCR is in service
without NH3 injection ......................................................................................... 113
4.4
Phase IIB summary Box and Whisker Plot of load (MW), SCR
inlet and outlet temperatures (°C), and SCR inlet and
outlet NOx concentrations (ppmv) used to illustrate consistency or
variability of operating conditions during a period when SCR
was in service with NH3 injection ....................................................................... 115
xiv
LIST OF FIGURES (continued)
Figure
Page
4.5
Phase III summary Box and Whisker Plot of load (MW), SCR
inlet and outlet temperatures (°C), SCR inlet and outlet NOx
concentrations (ppmv), wet FGD inlet SO2, and outlet SO2
concentrations (ppmv) used to illustrate consistency or
variability of operating conditions during a period when SCR
was in service with NH3 injection ....................................................................... 116
4.6
Hg oxidation ratio versus Br/Hg ratio (lb/lb) with and without
the SCR in service. Figure was developed with the use of data
from Phases I, IIA, and IIB ................................................................................. 124
4.7
Hg oxidation ratio versus Br concentration (wt ppm on the dry coal)
with SCR in service with NH3 injection to control NOx ..................................... 126
4.8
Hg oxidation ratio versus Br concentration (wt ppm in the dry coal)
at the wet FGD inlet as a function of SCR operational status ............................ 128
4.9
Illustration of NH3 consumption and its effect on Hg
oxidation behavior in an SCR ............................................................................. 130
4.10
Total Hg removal across a 2 MW pilot-scale wet FGD
as a function of Br concentration (wt ppm on the dry coal)
and SCR operational condition ........................................................................... 133
4.11
Wet FGD Hg removal versus Hg oxidation ratio for differing SCR
reactor operational conditions during Phase IIA and Phase IIB.
A marker below the 45-degree line represents lower-than-expected
Hg removal, and a marker above the 45-degree line represents betterthan-expected Hg removal. A marker to the right of the vertical line
represents 90% oxidation. A marker above the horizontal line
represents 90% removal in the wet FGD. A marker
within the green box represents at least 90% Hg oxidation
and 90% Hg removal .......................................................................................... 138
4.12
Wet FGD Hg Reemission Probability Diagram. Diagram demonstrates
visually that the probability of reemitting Hg from a wet FGD
sump is a function of slurry bromine and chlorine concentration,
sulfite concentration, oxidation reduction potential,
Hg concentration in solution, and Hg concentration in the
total suspended solids ......................................................................................... 141
xv
LIST OF FIGURES (continued)
Figure
Page
4.13
Hourly average Hg emissions concentration (µg/m3) from Miller
Unit 3 and Unit 4 from September 1, 2010, through January 30, 2011,
which includes the bromine addition test period from October 1
through December 19. Hg emissions data were not available
from December 20 through December 31. A = calcium bromide
addition begins. B = Unit 4 outage. No bromide was
injected during start-up. C = Missing data from dataset ................................... 149
4.14
Hourly average Hg emissions concentration (µg/m3); Br
concentration (wt ppm on the dry coal); and load (MW) from
Miller Unit 4 from September 1, 2010 through January 30, 2011,
which includes the CaBr2 addition test period from October 1
through December 19. Hg emissions data were not available
from December 20 through December 31 .......................................................... 151
4.15
Hourly average Hg emissions concentration (µg/m3) and Br
concentration (wt ppm on the dry coal) from Miller Unit 4 from
October 1 through December 19, 2010. Includes a Unit 4
outage from December 6 through 9, 2010. CaBr2 was not
added during start-up after the outage. CaBr2 was returned
to service at a lower addition rate after the unit reached full load. ..................... 152
4.16
Hourly average Hg emissions concentration (µg/m3) and Br
concentration (wt ppm on the dry coal) on Miller Unit 4 from
December 4 through December 19, 2010, which includes
short boiler outage............................................................................................... 153
4.17
Hourly average Unit 3 Hg emissions as a function of unit load
(1, Load > 600 MW; 2, 500 MW < Load < 600 MW; 3, Load < 500 MW);
the figure includes data from September 1, 2010,
through January 30, 2011 .................................................................................... 160
4.18
Unit 4 hourly average Hg emissions as a function of unit load
(1, Load > 600 MW; 2, 500 MW < Load < 600 MW; 3,
Load < 500 MW); the figure includes Unit 3 Hg wet FGD stack
emissions data from September 1-30, 2010,
and from January 1-30, 2011 .............................................................................. 162
xvi
LIST OF FIGURES (continued)
Figure
Page
4.19
Unit 4 hourly average Hg emissions as a function
of unit load (1, Load > 600 MW; 2, 500 MW < Load < 600 MW;
3, Load < 500 MW); the figure includes Unit 4 wet FGD
outlet Hg emissions data from October 1 through
December 19, 2010 ............................................................................................. 165
4.20
Chronological plot of Phase III Unit 4 hourly average Hg
emissions rate (lb/TBtu) and Br concentration (wt ppm on dry coal)
during the 83-day CaBr2 injection test. ............................................................... 171
4.21
Chronological plot of Phase III Unit 4 and Unit 3 daily and
30-day rolling Hg emissions rate (lb/TBtu). ....................................................... 173
4.22
Seven-day simulation of CaBr2 injection system outage combining
Phase III Unit 4 30-day rolling Hg emissions rate data with Unit 4
daily Hg emissions rate data during September 1-7, 2010.
The resulting plot represents the impact of higher emissions
on MATS rule compliance. ................................................................................. 174
xvii
LIST OF ABREVIATIONS
acfm
actual cubic feet per minute
ACI
activated carbon injection
ads
adsorbed
Br
bromine
Br2
bromine (gas)
Coxidized
concentration of oxidized mercury at the wet flue gas
desulphurization inlet
Ctotal
concentration of total mercury at the wet flue gas desulphurization
inlet
CaBr2
calcium bromide
Cl2
chlorine (gas)
CAIR
Clean Air Interstate Rule
CAMR
Clean Air Mercury Rule
CMM
continuous mercury monitoring system
DOE NETL
Department of Energy, National Energy Technology Laboratory
EPA
Environmental Protection Agency
ESP
electrostatic precipitator
FAMS
flue gas adsorbent mercury speciation
FF
fabric filter
FGD
flue gas desulphurization
g
gas
HBr
hydrogen bromide
xviii
LIST OF ABREVIATIONS (continued)
HCl
hydrogen chloride
Hg
mercury
Hg0
elemental mercury
Hgel
elemental mercury
ICR
information collection request
JB
Jarque-Bera statistic
l
liquid
LSFO
limestone forced oxidation scrubber
Macf
million actual cubic feet
MATS
Mercury and Air Toxics Standards Rule
MBtu
one million British thermal units
NH3
ammonia
ORP
oxidation reduction potential
PM
particulate matter
ppmv
part per million by volume
ppm
part per million
RP
reemission parameter
s
solid
SCEM
semi-continuous emissions monitor
SCR
selective catalytic reduction
SO2
sulfur dioxide
SO3
sulfur trioxide
TBtu
one trillion British thermal units
UBC
unburned carbon
xix
LIST OF ABREVIATIONS (continued)
wet FGD
wet flue gas desulphurization
wt %
percent by weight
wt ppb
part per billion by weight
wt ppm
part per million by weight
xx
CHAPTER 1
INTRODUCTION AND RATIONALE
1.1
Regulatory Background
In December 2000, Carol Browner, the Administrator of the Environmental
Protection Agency (EPA), declared under authority granted by Section 112 of the Clean
Air Act, that it was prudent and necessary to regulate mercury (Hg) emissions from coalfired power plants. On March 15, 2005, the EPA issued the Clean Air Mercury Rule
(CAMR), designed to reduce and permanently cap Hg emissions from coal-fired power
plants. The EPA designed the CAMR to work in conjunction with the Clean Air
Interstate Rule (CAIR); this rule required that certain power plants install selective
catalytic reduction (SCR) systems to reduce NOx emissions and wet flue gas
desulphurization (wet FGD) systems to reduce SO2 emissions. EPA was aware that the
combination of SCR systems and wet FGD systems had demonstrated the ability to
substantially reduce Hg emissions. Both CAMR and CAIR were based on a cap-andtrade mechanism designed to give utilities flexibility in meeting the required emission
reductions. EPA asserted that the utility sector constituted the largest emitter of Hg. The
goal of the combined rule structure was to reduce Hg emissions from 48 tons, the
estimated coal-fired power plant emissions of Hg in 2005, in two phases, at the lowest
cost. The first-phase cap was 38 tons, a reduction of 21%. In the second phase, due in
1
2018, utilities reduce emissions to 15 tons, a reduction of 69%. On February 8, 2008, the
Circuit Court of Appeals for the District of Columbia vacated the CAMR rule and
ordered the EPA to develop a new rule to reduce hazardous air pollutants, including Hg
emissions.
On Feb 16, 2012, EPA in response to the Court’s directive, published the Mercury
and Air Toxics Standards (MATS) Rule, (Hazardous Air Pollutants, 2012) which will
require the reduction of Hg emissions from existing and new coal-fired power plants.
The MATS rule became effective immediately and requires utilities to meet emissions
limits for various pollutants in three years, included provisions that allow utilities to
request a one-year compliance extension from their state environmental agencies, as well
as a process by which utilities can request an additional one-year extension from the
EPA. The MATS rule set limits on emissions of inorganic acids, Hg, and other metals.
The rule used hydrochloric acid as a surrogate for inorganic-acid emissions, employed
filterable particulate matter as a surrogate for heavy-metals emissions, and set direct
limits on the emissions of Hg. The EPA set differing limits for plants burning low-rank
coals (lignite) and those burning higher rank coals (i.e., subbituminous and bituminous).
The MATS rule also established limits for Integrated Gasification Combined Cycle units
utilizing all types of coals. The limits required for non-low-rank coal-fired units are
listed in Table 1.1, which excludes values for low-rank coals and Integrated Gasification
Combined Cycle units because this dissertation focuses only on subbituminous coals.
2
Table 1.1 Summary of the Mercury and Air Toxic Standards (MATS) Rule for CoalFired Power Stations
Subcategory
Existing Unit: nonlow-rank coal
New Unit: non-low
rank-coal
Filterable
Particulate Matter
Hydrogen Chloride
Mercury
0.030 lb/MBtu
0.0020 lb/MBtu
1.2 lb/TBtu
(0.30 lb/MWh)
(0.020 lb/MWh)
(0.020 lb/GWh)
0.0070 lb/MWh
0.40 lb/GWh
0.00020 lb/GWh
Note: all limits here are based on a 30-day rolling average.
lb/MBtu = pounds pollutant per million British thermal units.
lb/TBtu = pounds of pollutant per trillion British thermal units.
lb/MWh = pounds of pollutant per megawatt-hour electric output (gross).
lb/GWh = pounds of pollutant per gigawatt-hour electric output (gross).
Table adapted from “Hazardous Air Pollutants from Coal and Oil Fired Electric Utility
Steam Generating Units”, Table 3 page 9367, 77 Federal Register (2012).
In light of the EPA’s dissemination of the MATS rule, utilities must begin to
make compliance decisions that could mean billions of dollars of investment to bring
existing power stations into compliance by 2015. Alternatively utilities could choose to
close facilities because additional investment in them would not be in the best interest of
the company. For example, On March 22, 2012, American Electric Power announced
that, in response to the MATS rule, it would retire 4,600 MW of coal-fired generation and
likely install environmental controls on 13,000 MW of coal-fired generation (Hemlepp
and Rozsa, 2012). Every utility in the United States is expected to engage in similar
decision-making processes to determine which power stations to retire and which power
stations to modify by installing controls. The decision-making process is complex. At a
minimum, the analysis must include the type of control to install, the difficulty involved
3
in the installation, the cost of installation, the long-term variable operating and
maintenance costs of the control technology, and the longevity of the facility after it is
controlled. The longevity of a facility is often uncertain because the regulatory
environment constantly changes. In a report describing the impacts of the MATS rule on
society, EPA (2011) concluded that utilities had available a number of technologies with
which to meet the Hg provisions of the rule, and those technologies included sorbent
injection into a fabric filter (FF), the use of SCR and wet FGD, and halogen injection
with sorbent injection or SCR and wet FGD. Estimates of the potential cost of
compliance technology will vary EPA (2012). Table 1.2, adapted from Jozewicz (2010)
is a summary of the relative costs of technologies that might be used for compliance with
the Hg portion of MATS.
It must be acknowledged that utilities cannot make compliance decisions for
MATS without considering the potential impacts of those decisions on existing and
impending regulations such as Regional Haze, 8-hour Ozone Standard, CAIR, Steam
Effluent Guideline Revisions, and the Coal Combustion Residuals Rule. For example,
using halogen injection for MATS compliance will raise the risk of increasing the Hg
concentration in wet FGD system blowdown. The revision of steam effluent guidelines,
scheduled to be disseminated by the EPA in November 2012 (EPA 2012), likely will
impose stringent limits on Hg emissions from the liquid discharges of wet FGD systems.
As a result, using halogen injection to meet the MATS rule could require the installation
of additional technology to reduce the possibility of increasing Hg emissions from wet
FGD blowdown.
4
Table 1.2 Relative Cost of Mercury Control Technologies
Capital
Cost
Incremental
Operations
and
Maintenance
Cost
Notes
Coal Treatment:
Pre Combustion
High
Moderate
Not many options commercially
available
Coal Additives
Low
Low
Halogen injection
Co-benefit maximization
wet FGD
Low
Low
Hg reemission management
Co-benefit maximization
SCR
Moderate
Moderate
Hg oxidation
Co-benefit maximization
SCR + wet FGD
Moderate
Moderate
Optimize Hg oxidation and
minimize Hg reemission
Activated carbon injection
Upstream of existing
cold-side ESP
Low
Moderate to
High
Varies based on site conditions
Fabric filter plus activated
carbon injection
High
Moderate
Sets benchmark for Hg removal
performance
Approach
Note: From “Process Optimization Guidance for Reducing Mercury Emissions from
Coal Combustion in Power Plants” by Division of Technology, Industry and Economics
(DTIE) Chemicals Branch Geneva, Switzerland, p. 77. November 2010. Adapted with
permission.
Because of the potential high cost of compliance and because of the repercussions
if compliance is not achieved (both financial and political), utilities are conservative
when making technology investment decisions. Although the vendors supplying the
various technologies to utilities are likely to provide performance guarantees, vendors’
financial responsibilities are typically limited (e.g., a percentage of the equipment price)
5
and cover only a very short timeframe (e.g., the period of testing during initial equipment
commissioning, but may extend for 12 months of operating time). This limited guarantee
customarily only translates into a vendor putting forth a best effort, but falling short of
guaranteeing compliance. The utility must accept a measurable amount of operational
and compliance risk with any environmental control technology decision. To minimize
this risk, utilities typically desire that the technology chosen for compliance has been
tested rigorously or generously used under varying conditions.
1.2
Problem Statement
At some point, utilities must make technology decisions for complying with the
MATS rule. In the absence of compliance certainty, utilities must draw upon all
available information to support technology decisions that yield, the highest degree of
compliance certainty at the lowest possible cost. This type of technology choice (i.e., low
risk at low cost) is in the best interest of utility customers because they ultimately bear
the cost of lowering emissions. Often, regulated utilities seek permission from their
regulatory bodies to increase rates to pay for compliance costs associated with
environmental regulations. Because of the pressures exerted upon public utility
commissions by the electorate, it is in the best interest of all parties (utilities, public
service commissions, and utility customers) to keep the cost of compliance at a
minimum. For unregulated utilities, the ultimate financial risk to purchase and install
compliance technology is borne entirely by the utility, which likely translates into tighter
operating margins to maintain profitability. For regulated and unregulated utilities, the
dollars invested in compliance technology must be kept to a minimum.
6
Due to their conservative nature, it is often difficult for a utility to justify
accepting a higher risk of compliance failure in order to lower costs. As described in
Table 1.2, halogen injection potentially provides a means of achieving MATS
compliance at a cost lower than those of other approaches. This study involved providing
the utility industry with sufficient information to support a decision to use calcium
bromide (CaBr2) injection to meet the Hg provision of the MATS rule at units burning
Powder River Basin (PRB) coal equipped with a SCR for NOx reduction and a wet FGD
for SO2 control. The information gleaned during the study, in conjunction with other
publicly available information, such as that found in scientific journals, will provide
enough technical certainty to support a decision by a utility to employ CaBr2 injection as
a compliance technology. Additionally, the study was designed to provide scientists and
engineers with data concerning the performance of the approach.
1.3
Purpose of the Study
This research was undertaken to provide sufficient information to support
achieving compliance with the MATS rule by using CaBr2 on the coal (i.e., halogen
injection technology), for a coal unit burning a low-sulfur, low halogen coal (i.e. PRB) at
a site equipped with an SCR for NOx control, a cold-side ESP for particulate matter (PM)
control, and a wet FGD for SO2 control. The program specifically evaluated the use of
CaBr2 as a coal additive to aid in the oxidation of Hg so that it can be captured within a
wet FGD. As shown in Table 1.2, if successful, a coal-additive approach, like CaBr2
addition, could provide a lower cost solution to compliance with the Hg portion of the
MATS rule. The investigator developed a four-year, three-phase program to demonstrate
7
that CaBr2, when added to the coal, could successfully support Hg removals in excess of
90% , thereby lowering Hg emissions below 1.2 lb/TBtu.
During the study, CaBr2 was added to the coal to promote Hg oxidation; once
oxidized, the Hg was then removed in a wet FGD at high efficiencies (>90%). The
program was designed to ensure that both Hg oxidation and Hg removal at the desired
efficiencies were attainable in an actual situation. A 720 MW power station that burned
PRB, which is low in sulfur and halogens, was selected for the study. Phase I included
only flue gas measurements to evaluate the ability of CaBr2 to affect Hg speciation. Phase
II, completed in two parts IIA and IIB, included the installation of a slipstream 2 MW
pilot wet FGD. The Phase II tests were used to determine the ability of a wet FGD to
remove the oxidized Hg. During Phase III, an 83-day injection of CaBr2 was conducted
to evaluate longer term Hg removal in a full-scale wet FGD. The study was also
designed to provide full-scale data to be used by more fundamental researchers to better
understand the mechanisms controlling performance of the approach. The availability of
such information is often key to scientific breakthroughs and a better understanding of a
process.
1.4
Significance of the Study
This study adds to the information available to utilities seeking to determine
whether CaBr2 addition constitutes a viable technology for compliance with the Hg
portion of the MATS rule. The study also provides performance results in an actual
application setting and can be used by researchers and modelers to test theories for Hg
8
oxidation via CaBr2 injection. Findings from this research will fill in some of the gaps in
current understanding of the performance of the technology.
1.5
Overview of Methodology
This work was completed over a four-year time span in three separate phases.
The phased approach was used to reduce cost and simplify the evaluation of the
technology. Because the program involved using a 720 MW boiler, a professional testing
company was contracted to make all of the required measurements, including all flue gas,
liquids, and solids measurements. URS Corporation, the major contractor, provided a
majority of the measurement equipment and technical expertise to operate that
equipment. Along with Southern Research Institute, URS was also contracted to conduct
offsite liquid and solids measurements. URS also operated the CaBr2 injection
equipment. Particulate Control Technologies operated the 2 MW pilot wet FGD during
Phase II. Data used in the present study were compiled from a number of sources,
including data provided by URS in project reports. The data historian of Alabama Power
Company provided additional operational information. Southern Company Services
provided information about the boiler and environmental control equipment.
1.6
Research Hypotheses
The goal of the research program consisted of testing the following research
hypotheses:
9
1. Burning PRB coal results in baseline Hg oxidation levels below 50% under all
operating conditions.
2. Sufficient CaBr2 addition at a unit burning PRB coal results in Hg oxidation
levels in excess of 90%.
3. CaBr2 addition can result in Hg capture efficiencies exceeding 90% when a
wet FGD system is present.
4. The difference in average Hg emissions rates using CaBr2 addition, when
compared to not employing CaBr2 addition, is statistically significant.
5. Hg emission rates achieved during the use of CaBr2 addition are sufficiently
low to meet the MATS rule Hg limit of 1.2 lb/TBtu on a 30-day rolling
average.
6. The presence of an SCR reactor can greatly reduce the application cost of
CaBr2 injection technology and dramatically improve the cost benefit of
utilizing the approach, when compared to activated carbon injection into an
existing cold-side ESP.
By examining these hypotheses, the investigator evaluated CaBr2 injection
technology performance, provided information useful in the design of the full-scale
system, and increased knowledge about the technology application costs at a unit burning
PRB coal.
1.7
Research Limitations
Unlike traditional research efforts conducted under simulated flue gas conditions
at laboratory scale, full-scale implementation makes it impossible to control many of
10
independent variables that affect technology performance. The lack of control of the
independent variables dictates a need for fundamental understanding of the process to
better describe the behavior of the dependent variables (i.e., Hg emissions). An
exhaustive literature search was done to better understand and quantify technology
performance. The combination of fundamental understanding and technology
performance in a real situation will enable utilities to decide whether this approach meets
the performance and risk thresholds required for adoption. The availability of full-scale
results in the absence of fundamental understanding likely translates into slower
technology adoption rates. Likewise, only having a fundamental understanding without
full-scale testing information also results in slow adoption rates. It is hoped that the
results from this effort will be combined with existing and future fundamentally-based
research programs to provide a better understanding of the approach and to accelerate
adoption of the technology.
11
CHAPTER 2
LITERATURE REVIEW AND BACKGROUND INFORMATION
2.1
Introduction
During the literature search conducted to establish the parameters for analysis of
the data during this study, the emphasis was on establishing a basic understanding of Hg
oxidation and the subsequent removal of oxidized Hg in a wet FGD. The goal was to
determine what was already know about the applicability of CaBr2 addition for enhanced
Hg oxidation in a full-scale boiler for potential compliance with the MATS rule. The
MATS rule will require that existing coal-fired utility boilers control Hg emission to an
emission rate below 1.2 lb/TBtu on a 30-day rolling average.
The literature review is divided into two main sections: Hg oxidation and capture
of Hg in wet FGDs. In terms of compliance, these two processes are of equal importance
because both must be optimized to ensure compliance with the MATS rule. The
literature appeared in many different types of publications, including technical journals,
Electric Power Research Institute reports, Department of Energy National Energy
Technology Laboratory reports, and conference proceedings. The different types of
publications were given equal weight in the review. The literature dated from the early
1990s to the present, with the majority of the material published in the last ten years. A
recent increase in publishing activity on the subject of Hg oxidation and capture from flue
gas indicates an increased level of interest in this area.
12
2.2
Hg Oxidation
Elemental Hg (Hgel) oxidation in coal-fired boiler furnace flue gases has received
a tremendous amount of study over the past twenty years. In earlier years, the studies
focused primarily on the ability of chlorine to oxidize Hg and on the subsequent removal
of the oxidized Hg in a wet FGD. This phenomenon is often referred to in the industry as
Hg co-benefit removal. In a report Congress, EPA (1997) highlighted the potential for
utilizing the combination of SCR reactors and wet FGD systems to remove Hg from flue
gas. The report summarized a number of studies documenting the removal of oxidized
Hg in wet FGDs.
In 1999, the EPA initiated an Information Collection Request (ICR)
designed to compile an inventory of Hg emissions from coal-fired boilers. The ICR
required owners/operators of coal-fired electric utility units to report the quantity of coal
consumed and the Hg content of that coal. In addition, 84 power plants, randomly
selected on the basis of 36 categories of coal type, SO2 controls and particulate controls,
were instructed to measure the concentration and species of its Hg emissions. In an
analysis of the ICR data conducted by EPRI, it was determined that the Hg speciation and
removal were functions of coal chlorine (Cl) content and the presence of a wet FGD
(Chu and Levin, 2001). Senior (2001), who also studied the ICR data, concluded that Hg
removal by a wet FGD was a function of coal Cl content. This correlation led to a number
of technical papers about the role of halogens floride (F), chloride (Cl), bromine (Br),
iodide (I), and oxygen (O2), in the oxidation of Hg in coal combustion flue gases.
The oxidation of Hg can occur by two distinct mechanisms: homogeneous
oxidation and heterogeneous oxidation. The heterogeneous oxidation can occur in two
distinct regimes: native heterogeneous oxidation, which occurs on the surfaces of
13
particles, such as flyash, unburned carbon, and activated carbon suspended in the flue
gases (Niksa et al., 2010), and on engineered surfaces such as SCR catalyst, which can be
designed to optimize Hg oxidation activity.
2.2.1
Homogeneous Oxidation
Homogeneous Hg oxidation is the combination of vapor phase Hg with another
species (mainly halogens) in a gas-phase reaction. The fraction of Hg that is
homogeneously oxidized is a function of oxidant concentration, oxidant species, flue gas
temperature, flue gas quench rate, the concentration of other flue gas constituents (SO2,
CO, NO), and residence time. Wilcox (2004) reported that elemental Hg is
thermodynamically favored in the high-temperature zone of a coal-fired boiler, which is
normally approximately 1400 ◦C. As the gas cools, the state of Hg can be changed from
its elemental form to an oxidized form, by reaction with the halogens (F, Cl, Br, and I) or
oxygen.
2.2.1.1 Chlorine-Based Homogeneous Hg Oxidation
Thermodynamic calculations predict that, in the reaction with chlorine, Hg
oxidation occurs as the flue gas begins to cool, but only if sufficient chlorine, or other
halogen, is present. Wilcox (2004) postulated that Hg oxidation occurs at temperatures
below 700 ◦C and that all the Hg present should be completely oxidized at or below 450
◦
C. However, stack measurements in real-world situations have shown that Hg is not
completely oxidized at the lower temperatures. Wilcox (2004) concluded that the
difference between the thermodynamic equilibrium predictions and the actual measured
14
results suggested that the homogeneous Hg oxidation reaction is kinetically limited. The
mechanism for homogeneous oxidation of Hg developed by Xu et al. (2003) describes Hg
oxidation as following a first-order chemical reaction, with a reaction rate expressed by
the Arrhenius form of
k = ATβexp –Ea/RT
(R1)
where T is the absolute temperature, A is the frequency factor, β is a correction factor for
temperature, and Ea is the activation energy. The values of the parameters are obtained
from laboratory experiments. Many flue gas constituents and characteristics have been
found to affect the values of the parameters A, Ea and β. Studies of the effects of oxygen
have shown that O2 only weakly promotes homogeneous Hg oxidation (Xu, 2003). Other
studies have shown that the halogens (i.e., Br and Cl) are more effective homogeneous
Hg oxidizers. When compared with O2, Cl was reported by Hall et al. (1991) to be more
effective in homogeneously oxidizing Hg.
Hall et al. (1991) proposed a set of reactions describing homogeneous Hg
oxidation based on chlorine chemistry:
4HCl + O2 ↔ 2H2O + 2Cl2
(R2)
SO2 + Cl2 + H2O ↔ SO3 + 2HCl
(R3)
SO2 + ½O2 ↔ SO3
(R4)
Hg + Cl2 ↔ HgCl2
(R5)
Wilcox (2004) concluded that when combusted coal chlorine is thermodynamically
favored to exist as HCl. Procaccini et al. (2000) conducted experiments to determine the
chlorine species present during coal combustion. Results revealed that 80% of the
chlorine in flue gas existed as HCl, with up to 18% existing as Cl2. Procaccini et al.
15
(2000) also conducted thermodynamic modeling which revealed that up to 5% of the
chlorine could exist as Cl radicals. Those values are likely an upper bound, because SO2
was not present in those experiments. The interplay of SO2 and Cl2 is a major factor in
achieving high levels of homogeneous Hg oxidation. Bench-scale experiments
conducted by Sterling et al. (2004) showed that SO2 had a large, inhibitory effect on Hg
oxidation by Cl2. Silcox et al. (2008) also conducted thermodynamic modeling and
concluded that HCl was the dominant Cl species at all flue gas temperatures. As
Equation R2 indicates, a small portion of the HCl reacts with oxygen to form Cl2. This
well-documented reaction, often referred to as the chlorine Deacon reaction, has been the
basis of Cl2 production from HCl in the presence of a catalyst (Balcar, 1938) for more
than eighty years.
Cl2 shown in Equation R5 reacts with elemental Hg to form oxidized Hg.
Vosteen et al. (2006) referred to Equation R5 as direct Hg chlorination. A limiting factor
in the production of Cl2 is seen in Equation R3, in which sulfur dioxide (SO2) reacts with
Cl2 to form sulfur trioxide (SO3) and HCl. This reaction is often called the chlorine
Griffin reaction. In the case of coals that have relatively large amounts of sulfur
(>1 wt %), less available Cl2 and thus lower extents of Hg oxidation via chlorine-based
homogeneous reactions should be expected. Not shown in equations within this
document, other researchers have proposed that chlorine ions (Cl-) constitute an
important factor in the homogeneous oxidation of Hg. Edwards et al. (2001) postulated
additional Hg oxidation reactions that included elementary reactions between chlorine
radicals and Hg:
Hg + Cl ↔ HgCl
(R6)
16
HgCl + Cl ↔ HgCl2
(R7)
Hg + Cl2 ↔ HgCl2
(R8)
2Cl ↔ Cl2
(R9)
These equations reveal that not only is Cl2 important but that chlorine radicals
(Cl) can serve as reactants for Hg oxidation. A simulation conducted by Edwards et al.
(2001) showed that the extent of Hg oxidation is dictated by the interplay between
Equations R6 and R9. It may be concluded that both chlorine radicals (Cl) and chlorine
gas (Cl2) are necessary for the homogeneous Hg oxidation reaction to occur. Ghorishi
(1998) found that the homogeneous oxidation of elemental Hg in the presence of HCl
was slow and only proceeded at higher temperatures (>700 °C) and relatively with high
HCl concentrations (>200 ppmv). Ghorishi (1998) also found that homogeneous
oxidation of elemental Hg in the presence of Cl2 is very fast and suggested that the ratio
of HCl/Cl2 might be a good key indicator of the effectiveness of homogeneous oxidation
of elemental Hg by Cl. Vosteen et al. (2011) suggested that the ratio of Cl2 to total
available chlorine in flue gas is very low in flue gases containing SO2. These points
would suggest that homogeneous Hg oxidation by chlorine becomes less effective as the
flue gas SO2 concentration increases.
The presence of chlorine radicals is not only concentration dependent but
temperature dependent. At high temperature, HCl is the most chemically stable chlorine
species (Procaccini et al., 2000; and Silcox et al., 2008). Therefore, it is less likely that
homogeneous Hg oxidation will occur in the boiler itself. As the flue gas begins to cool
downstream from the boiler exit, Cl and Cl2 are formed. At lower temperatures, the
formation of Cl2 in accordance with Equation R2 is favored. Vosteen et al. (2006)
17
proposed that, at 680 ◦C, the formation of Cl2 is complete. Vosteen et al. (2011) reported
that consumption of Cl2 occurs subsequently via Equation R3, if SO2 is present. Cl2 is
not thermodynamically favored at high temperatures. However, below 370 °C, a
significant driving force exists toward the formation of Cl2 and below 260 °C, the
formation of Cl2 begins to be favored over HCl formation. Gale (2004) suggested that Cl
speciation is governed by equilibrium in furnace sections of coal-fired boilers, but is
limited by kinetics and residence time downstream. Vosteen et al. (2006) postulated that
the Hg oxidation reaction by chlorination (i.e., Cl2) ceases below 680 ◦C, which is the
proposed lower-end of the range for Hg oxidation by Cl2. This would mean that while
the formation of Cl2 is favored at the lower temperatures (i.e. 260 ◦C) the effect of higher
concentrations of Cl2 on Hg oxidation would be very limited.
The concentration of Cl present in the coal directly affects the fraction of Hg that
is oxidized. Measurements during bench-scale laboratory testing revealed Hg oxidization
percentages of 10% to 20% when HCl concentrations were below 200 ppmv and
percentages up 40% when HCl concentrations were as high as 300 ppmv (Sterling, et al.,
2004). Because these results were obtained without SO2 in the flue gas, they may
represent upper bounds for homogeneous oxidation by HCl. Additional testing done in
the absence of SO2 in the simulated flue gas revealed negligible homogeneous oxidation
rates when HCl was not present, 20% of Hg oxidized in the presence of 200 ppmv HCl
and 30% of Hg oxidized in the presence of 555 ppmv of HCl.
The homogeneous oxidation of Hg in the presence of both HCl and SO2 was
lower. The literature is not consistent on the effect of SO2 on Hg oxidation. For instance,
in studies conducted by Smith et al. (2011), the presence of SO2 had a positive impact on
18
elemental Hg oxidation when SO2 concentrations were below 400 ppmv. An SO2
concentration of 300 ppmv is typical of flue gas from burning lower sulfur fuel such as
PRB and may indicate that for lower sulfur coals SO2 may not pose a problem. Lighty et
al. (2006) found that Hg oxidation by HCl was severely inhibited in the presence of SO2.
Hg oxidation decreased from 70% to 0% when SO2 concentrations were increased from 0
ppmv to 300 ppmv. These results conflict with those obtained by Smith et al. (2011).
Ghorishi (1998), who found that the inhibition effect of SO2 on Hg oxidation with HCl
required the presence of sufficient water vapor, proposed that the inhibition effect of SO2
in the presence of water vapor may be related to a chlorine free radical scavenging effect
by SO2 and water vapor. Fry (2008) conducted experiments with 600 to 1000 ppmv of
Cl2 as a homogeneous elemental Hg oxidant and found that 90% of Hg was oxidized at
Cl2 concentrations above 200 ppmv, that 80% of Hg was oxidized at 200 ppmv of Cl2,
and that 20% of Hg was oxidized Hg at 100 ppmv Cl2, all in the absence of SO2.
Fry et al. (2007) found that, as the flue gas quench rate changed, so did the effect
of HCl on Hg oxidation. An increase in quench rate from -210 K/s to -440 K/s resulted in
an increase in the extent of Hg oxidation from 34% to 86% at an HCl concentration of
300 ppmv. Fry et al. (2007) concluded that the chlorine radical concentration is sensitive
to temperature, and therefore that oxidation kinetics are also dependent on quench rate.
Building upon the work of Niksa et al. (2001), Fry (2008) modeled the effect of quench
rate on Hg oxidation with chlorine species as oxidants. The model predicted that a high
quench rate produced a greater extent of oxidation because of the longer residence time at
temperatures below 650 ◦C and the presence of super-equilibrium concentrations of Cl
radicals.
19
2.2.1.2 Bromine-Based Homogeneous Hg Oxidation
Otten et al. (2011) concluded that, on an equivalent molar basis, Br proves more
effective than other halogens (chlorine, fluoride, and iodide) in promoting homogeneous
oxidation of Hg in coal combustion flue gases. The experiments conducted by Otten et.
al. (2011) showed that the concentrations of HBr and Br are comparable at flame
temperatures and that as the flue gas cools, the concentration of Br radicals equals that of
HBr. In a study conducted by Jin et al. (2011) of halogen species during the combustion
of municipal waste, some of which contained substantial concentrations of bromine
(7 wt%), the researchers determined that the concentrations of HBr and Br2 were almost
equal. The data seemed to suggest that higher temperatures and O2 levels tended to shift
the bromine towards Br2 at the expense of HBr. Jin et al. (2011) also found, during the
combustion of high bromine content municipal waste, that the presence of SO2 decreased
the amount of Br2 in combustion products.
Vosteen et al. (2006) reported that the following reactions are important for Hg
oxidation by bromine:
4HBr + O2 ↔ 2H2O + 2Br2
(R10)
SO2 + Br2 + H2O ↔ SO3 + 2HBr
(R11)
SO2 + Br2 + 2H2O ↔ H2SO4 + 2HBr
(R12)
Hg + Br2 ↔ HgBr2
(R13)
Niksa et al. (2010) suggested that knowledge of intermediate reactions increases
understanding of the ability of bromine radicals to homogeneously oxidize Hg and
suggested these additional elementary reactions:
Hg + Br ↔ HgBr
(R14)
20
HgBr + Br2 ↔ HgBr2 + Br
(R15)
These reactions suggest that, similar to chlorine, bromine radical chemistry plays a vital
role in homogeneous Hg oxidation by bromine.
Vosteen et al. (2006) concluded that unlike chlorine radicals, bromine radicals are
suppressed to a lesser extent by the presence of SO2, and that therefore, Equations R11
and R12 become less important. Although SO2 consumes Br2, it does so to a lesser extent
when compared the effect of SO2 to Cl2. Niksa et al. (2010), Vosteen et al. (2006), Silcox
et al. (2008), and Otten et al. (2011) all concluded that Br2 and Br radicals exist in the
flue gas in rather large quantities and that, with the lack of sensitivity of bromine species
to SO2, sufficient Br2 and Br radicals should exist to promote homogeneous Hg
oxidation. In contrast, Buitrago et al. (2010) concluded from bench-scale tests that the
presence of SO2 resulted in considerable reduction in homogeneous Hg oxidation by
bromine when SO2 was present at concentrations as low as 50 ppmv.
Niksa et al. (2010) reported that, in comparison with Cl, Br more effectively
oxidizes Hg because HBr disassociates into more reactive species (i.e. Br2 and Br
radicals) to a greater extent than HCl under typical post-flame conditions. Buitrago et al.
(2010) reported that bromine was shown to be significantly more effective for post-flame,
homogeneous oxidation of Hg than chlorine. Thermodynamic modeling performed by
Vosteen et al. (2006) showed that, at 1000 ◦C, Br2 becomes the dominant bromine
species. Results of similar studies by Silcox et al. (2008) revealed that Br2 became the
dominant bromine species at flue gas temperatures below 400 ◦C.
Silcox et al. (2008) conducted homogeneous oxidation experiments at 350 ◦C, to
ascertain the relationship between Hg oxidation and bromine concentration. Silcox et al.
21
(2008) determined that 3.5 ppmv of bromine (as HBr) resulted in 10% Hg oxidation.
Increasing the flue gas concentration of HBr to 10 ppmv increased Hg oxidation to 25%,
and increasing the HBr concentration to 20 ppmv resulted in 60% Hg oxidation. At the
highest HBr concentration of 45 ppmv, Hg oxidation was 80%. Otten et al. (2011)
performed similar experiments, but excluded SO2 from the flue gas and observed similar
extents of Hg oxidation. At a flue gas HBr concentration of 25 ppmv, Hg oxidation was
found to be 40%. Similarly, when the HBr concentration was increased to 50 ppmv, Hg
oxidation increased to 80% (Otten et al., 2011).
Vosteen (2003) reported that in order to achieve 100% Hg oxidation by
introducing a bromine compound, the bromine must be added in a mass ratio of bromine
to Hg mass ratio (Br/Hg) in the coal of 100 to 10,000. A typical concentration of Hg in
bituminous and subbituminous coals from the United States is 50 to 200 wt ppb. The
guideline provided by Vosteen (2003) suggests that Br addition rates of 5 to 200 wt ppm
in the dry coal would be required for bromine based homogenous Hg oxidation.
Silcox et al. (2008) also investigated the effect of flue gas quench rate on Hg
oxidation and their results indicated that a lower quench rate (-220 K/s) resulted in a
higher extent of Hg oxidation at equivalent HBr concentrations. For example, at 20
ppmv of HBr ,the lower quench rate (-220 K/s) resulted in Hg oxidation level of 75%;
however, at a higher quench rate (-440 K/s), only 50% oxidation was observed.
2.2.2
Heterogeneous Oxidation
The oxidation of Hg does occur on the surface of particles. The surface acts as a
catalyst to assist the chemical reaction. The Swedish chemist Jöns Jacob Berzelius, in
22
1836, first coined the term catalyst and defined it as any substance that directly alters the
rate of a chemical reaction without entering into the net chemical reaction itself
(Dartmouth, 2012). Flue gas contains a number of surfaces that have been demonstrated
to catalyze the oxidation of Hg. Niksa and Fujiwara (2005) postulated that unburned
carbon and fly ash can act as a catalyst to oxidize Hg. Engineered materials such as SCR
catalyst, activated carbon particles, iron (Fe) particles, and noble metals such as gold and
palladium can be introduced into the flue gas for that purpose. In essence, engineered
materials can be used to oxidize Hg. Feely et al. (2003) reported that the combination of
SCR and wet FGD showed promise for reducing Hg emissions and showed that the Hg
emissions from coal-fired units with SCR and wet FGD were lower than those from units
that did not have that combination of equipment. In short, the SCR promotes the
oxidation of Hg, and the wet FGD scrubs the oxidized Hg from the flue gas.
2.2.2.1 SCR Reactors
New regulations promulgated by the EPA over the past two decades have required
that utilities operating coal-fired power plants install new technology to reduce nitrogen
oxides (NOx) emissions. Many utilities have installed SCR reactors that can reduce NOx
emissions up to 95%. In the process of reducing NOx, NH3 is added to the flue gas in the
presence of an engineered catalyst. The NOx is transformed by reaction with NH3 into
nitrogen and water vapor. The chemical reactions of the process are described by the
following equations, (Sloss et al., 1992):
4NO + 4NH3 + O2 ↔ 4N2 + 6H2O
(R16)
NO + NO2 + 2NH3 ↔ N2 + 3H2O
(R17)
23
2NO2 + 4NH3 + O2 ↔ 3N2 + 6H20
(R18)
6NO2 + 8NH3 ↔ 7N2 + 12H2O
(R19)
NH3, shown in Equations R16 – R19, is adsorbed onto the catalyst surface. The NOx
diffuses from the gas stream to the surface of the catalyst, where it reacts to form the
products H2O and N2. The products desorb, and the surface returns to its prior state for
the process to repeat itself. The optimum temperature range for the reactions is 300 to
400 ◦C. Catalysts are designed to optimize the NOx and NH3 reaction while minimizing
other reactions such as the oxidation of SO2 to SO3. This selectivity typically translates to
a less active catalyst. SCR NOx reduction efficiency is a function of: inlet NOx
concentration, flue gas temperature, the ratio of NH3 to NOx; oxygen concentration;
various catalyst properties and reactor design characteristics, (e.g., space velocity; bulk
catalyst composition; surface catalyst composition; and catalyst structural design). Each
SCR is designed specifically for an individual situation in which a delicate balance
ensures a high NOx removal efficiency within the desired constraints such as SO2 to SO3
oxidation. Table 2.1 provides a summary of the key design parameters for a SCR
installation.
The operation of an SCR system is typically evaluated on two major components:
its ability to reduce NOx emissions and its ability to properly consume the injected NH3.
Any NH3 that leaves the system is referred to as NH3 slip. In a typical SCR design,
acceptable NH3 concentrations leaving the reactor are equal to or less than 2 ppm. Any
unreacted NH3 can cause difficulties in plant operations. For example, unreacted NH3
could react with SO3 to form ammonium bisulfate (NH4HSO4), a sticky substance that
could foul or corrode the air heater. The design of SCR ensures that the NH3 not reacted
24
in the systems is relatively low. Pritchard et al. (1995) reported that NH3 slip levels
should not exceed 2 to 5 ppm at the end of the useful life of the catalyst. Although well
designed catalyst is important in this regard, Pritchard et al. (1995) also discussed other
ways to ensure the proper management of NH3 levels in the SCR, including both
matching the NOx profile with the NH3 injection profile through lance injection design
and maintaining control of the NH3 injection grid on a daily basis. The interplay between
NH3 and Hg oxidation is important and will be discussed in further detail later in this
section.
SCR catalyst, a major component of the SCR system, is made from special
materials for their specific properties. Sloss et al. (1992) reported that the SCR catalyst
market is dominated by a titanium-oxide (TiO2) based catalyst in which vanadium
pentoxide (V2O5) and tungsten oxide (WO3) are added to increase activity. Although
many catalysts share common building blocks (TiO2, V2O5, WO3, and MoO3), the final
formulation of a specific catalyst is dictated by individual plant flue gas composition and
operating conditions. Catalyst activity degrades with time, and deactivation can occur via
mechanical means (erosion and plugging) or chemical means (deposition).
Catalyst activity decreases because of damage or blockage of active sites (i.e., the
locations at which the chemical reaction occurs). Erosion and plugging cause the active
sites to disappear or become inaccessible, meaning that they are covered and are no
longer available to serve as an active site. During chemical degradation, active sites are
blocked or deactivated by compounds such as arsenic (As), potassium (K), and calcium
(Ca), and can no longer serve as active catalyst materials.
25
Table 2.1 SCR Key Design Parameters
Description
Symbol
Units
Formula
Notes
Reduction
efficiency
η
n/a
molNOx,in ! molNOx,out
molNOx,in
Flue gas flow
Qg
m3/h
n/a
Gas volume flow at
treatment temperature
Catalyst
volume
Vc
m3
n/a
SCR system design
parameter
Catalyst area
Ac
m2
n/a
SCR system design
parameter
Catalyst
specific
surface area
Asp
m2/m3
n/a
SCR catalyst design
parameter
Crucial SCR design
parameter (typically 1,000–
3,000 h-1)
Molar reduction efficiency
Space velocity
SV
1/h
!!
!!
Area velocity
AV
m/h
Qg
Vc Asp
Flow rate through a catalyst
area divided by the surface
area of the passages
Laboratory measurement of
catalyst ability to remove
NOx from simulated flue
gas
Activity
K
n/a
!Av ln(1! ! )
Original
Activity
K0
n/a
n/a
Activity
Degradation
n/a
n/a
K
K0
Rector
potential
RP
n/a
!
!"
Laboratory measured
activity before catalyst is
exposed to flue gas
Used to benchmark SCR
performance over time
Measure of the overall
ability of the SCR to reduce
NOx
Note: Table was created with information from Sloss et al. (1992) and Muzio et al.
(2008)
Jensen-Holm (2007) for instance, reported that alkali metal aerosols containing sodium
(Na) and potassium (K) are of prime concern because the aerosols adhere to the catalyst
surface and the elements are transported to the active sites by surface diffusion.
26
The impact of catalyst poisoning relates directly to the coal being burned at the
site and the location at which the SCR is installed. SCRs are installed in three
configurations: (1) a high-dust SCR installed just downstream of the boiler, (2) a lowdust SCR, installed downstream of a hot-side electrostatic precipitator, and (3) a tail-end
SCR which is installed downstream of the wet FGD. In the tail-end configuration, the
flue gas is reheated between 300 to 400 °C. The high-dust SCR has the largest potential
for catalyst deactivation because of both physical plugging and chemical degradation can
occur. The low-dust SCR is less susceptible to physical plugging and the tail-end SCR
carries the lowest potential for catalyst degradation because the upstream environmental
control equipment (i.e. cold-side ESP and wet FGD) removes contaminants. For Hg
oxidation, the tail-end SCR is not important because any oxidized Hg created would be
discharged to the atmosphere.
A basic knowledge of SCR operations for NOx removal may provide some
understanding of the SCR’s ability to oxidize Hg. Current SCRs are optimized to remove
NOx and consideration is not given to Hg oxidation. At this time, the SCRs ability to
oxidize Hg is an ancillary benefit. The next sections contain discussions of key technical
terms to enhance understanding of the symbiotic relationship between NOx removal and
Hg oxidation.
2.2.2.1.1 Hg Oxidation Reaction Mechanisms
Currently no clear fundamental understanding exists of the mechanism causing
Hg oxidation within an SCR catalyst. Authors of the various scientific studies presented
27
here discussed three main possible reaction mechanisms: Eley-Rideal, LangmuirHinshelwood, and Mars-Maessen.
The Eley-Rideal mechanism describes the interaction between an adsorbed
species and a gas-phase species according to the following reactions (Tong 2009).
A(g) ↔ A(ads)
(R20)
A(ads) + B(g) ↔ AB(g)
(R21)
Senior (2006) performed extensive computer modeling using the Eley-Rideal
mechanism in combination with publicly and privately held, full-scale SCR operational
data and concluded that the model provided Hg oxidation predictive results that
compared favorably with actual data from eight different catalysts, including both
monolith and plate catalysts. Hong et al. (2010) experimentally determined that HCl is
adsorbed on the SCR surface and reacts with gas phase Hg to form HgCl2. Hong et al.
(2010) reported that HCl competes with NH3 for the active sites and that NH3 was
preferentially adsorbed on the catalyst. In earlier work Granite and Presto (2006) found
that NH3 adsorbs strongly to the V2O5 active sites. The Eiley-Rideal mechanism dictates
that the NH3 concentration must decrease before sufficient Hg oxidation can occur, which
assumes that NH3 and HCl are competing for the same active sites. A sufficient gas
phase concentration of halogens (i.e., HCl, Cl2, Br2, HBr) is needed for the Hg oxidation
reaction to occur. The production of Cl2 from adsorbed HCl proceeds under the Deacon
reaction as described in Equation R2. The adsorption of HCl onto the catalyst surface is
an important step in the oxidation of Hg. Dranga et al. (2012) provided the following
equations to describe the Eley-Rideal mechanism for Cl and Hg:
2HCl(g) + 2V-O-V(s) ↔ 2V-OH-V-Cl(s)
28
(R22)
2V-OH-V-Cl(s) + Hg(g) ↔ 2V-OH-V(s) + HgCl2(g)
2V-OH-V(s) + ½ O2(g) ↔ 2V-O-V(s) + H2O(g)
(R23)
(R24)
Dranga et al. (2012) found the Eley-Rideal mechanism highly unlikely to be the
governing mechanism, on the basis of their analysis of the available experimental results.
Their conclusion was grounded in the fact that Hg was found to adsorb onto the catalyst
surface.
According to the second possible reaction mechanism, the LangmuirHinshelwood mechanism, reaction occurs between two adsorbed species on the surface of
a catalyst. Piling and Seakins (1995) described this mechanism by the following
equations:
A(g) ↔ A(ads)
(R25)
B(g) ↔ B(ads)
(R26)
A(ads) + B(ads) ↔ AB(ads)
(R27)
AB(ads) ↔ AB(g)
(R28)
He (2009) conducted surface analyses using X-ray photoelectron spectroscopy (XPS) and
fourier transform infrared spectroscopy (FTIR) of SCR catalyst and confirmed the
presence of HCl on the surface. Experiments showed that the catalyst adsorbed Hg when
HCl was absent in the flue gas. When HCl was added to the flue gas, Hg was observed to
desorb, indicating weak adsorption of Hg to the vanadia active sites. Both observations
support the Langmuir-Hinshelwood mechanism as a plausible reaction process for Hg
oxidation. According to the mechanisms shown in Equations R29 to R32, HCl and Hg
first adsorb onto vanadia sites, HCl and Hg reacts to form intermediate species which
react with Cl to form HgCl2 and V-OH species. The HgCl2 then desorbs to the flue gas
29
and the re-oxidation of the V-OH species by oxygen follows to form V=O and H2O (He,
2009). He (2009) proposed the following reactions to describe Hg oxidation via the
Langmuir-Hinshelwood mechanism.
Hg(ads) + Cl(ads) ↔ HgCl(ads)
(R29)
HgCl(ads) + Cl(ads) ↔ HgCl2(g)
(R30)
HgCl(ads) + HCl(ads) ↔ HgCl2(g) + H
(R31)
HgCl(ads) + Cl2(ads) ↔ HgCl2(g) + Cl
(R32)
In other experiments, Qiao (2009) suggested that an intermediate reaction takes
place once HCl and Hg are adsorbed onto the vanadia active site. Qiao (2009) also found
that the activation energy for the reaction with Cl2 was lower than the activation energy
required for the HCl reaction. Thus, Hg oxidation behavior, while achievable with HCl,
might proceed to a greater extent in the presence of Cl2. The chlorine Deacon reaction
takes place at about 350 to 450 °C in the presence of copper, chromium, vanadium, and
ruthenium(IV) oxide catalyst (Dranga et al., 2012). An increase in Cl or Cl2, transformed
from HCl, could occur if a catalyst containing copper (Cu) or cadmium (Cd) were
present. Hranisavljevic and Fontijn (1997) showed by experiment that Cl radical
production can occur in flue gas when HCl or Cl2 is present along with Cd. Additional
experiments by Hisham (1995) demonstrated the ability of Cu to promote the production
of Cl2 from HCl in accordance with Equation R2.
After analyzing results for Hg oxidation in the presence of noble metal catalysts,
Granite and Presto (2008) suggested that a Langmuir-Hinshelwood mechanism might
explain the reaction kinetics in the presence of a platinum-based catalyst. Eom et al.
(2008) used transmission electron microscopy with energy dispersive X-ray (TEM-EDX)
30
analyses and X-ray photoelectron spectroscopy (XPS) to verify reaction pathways on the
surface of SCR catalyst used for Hg oxidation. The study revealed that elemental Hg and
HCl were both present on the surface of the catalyst. Eom et al. (2008) observed the
presence of multiple layers of HgCl2 on the surface. This finding clearly indicates that
the Langmuir-Hinshelwood reaction pathway is plausible. Ghorishi et al. (2005) found
experimentally that higher levels of CaO in the coal led to slightly lower rates of
heterogeneous Hg oxidation. These lower rates could result from the consumption of HCl
through chemical reaction with CaO to form CaCl2. The consumption of available HCl
by CaO could be important at plants that burn PRB coals with fly-ashes high in calcium
(up to 20 wt% Ca).
Dranga et al. (2012) postulated, from a comprehensive review of the literature,
that the Mars-Maessen mechanism is the most likely pathway for Hg oxidation in the
presence of a metal, oxide-based catalyst. In this mechanism, elemental Hg is first
adsorbed onto the catalyst surface, and then reacts with lattice oxygen from the catalyst to
form an adsorbed mercuric oxide. The catalyst surface is re-oxidized with gaseous
oxygen. The HgO(ads) reacts with HCl or HBr to form the volatile Hg halides, which are
released from the catalyst surface. Liu (2011) postulated the following Mars-Maessen
reactions for a CoO/TiO2 metal oxide catalyst:
Hg(g) ↔ Hg(ads)
(R33)
Hg(ads) + CoxOy(s) ↔ HgO-CoxOy-1(s)
(R34)
HgO-CoxOy-1(s) + ½O2 ↔ HgO(ads) + CoxOy(s)
(R35)
HgO(ads) + 2HCl(g) ↔ HgCl2(g) + H2O
(R36)
HgO(ads) + 2HBr(g) ↔ HgBr2(g) + H2O
(R37)
31
Straube et al. (2008) suggested a similar set of reactions for oxidation on active vanadium
sites.
Hg(ads) + catalyst – O ↔ HgO(ads)
(R38)
HgO(ads) + 2HCl(g) ↔ HgCl2(g) + H2O
(R39)
Straube et al. (2008) postulated that Hg is deposited on the surface of the catalyst at an
active vanadium site, where it reacts with O2 to form an intermediate species. The
intermediate species reacts with HCl to form the volatile HgCl2. In a study of nanoFe2O3-based oxidation catalysts, Kong et al. (2011) proposed that the first step of the
catalytic reaction consists of losing one oxygen atom from Fe2O3 to adsorbed elemental
Hg to form HgO. The proposed mechanism by Kong (2011) is consistent with the Mars
Maessen reaction pathway. Lee and Bae (2009) conducted X-ray photoelectron
spectroscopy analysis of nano-sized catalyst after the removal of elemental Hg during
experiments. The analysis revealed that the elemental Hg had been transformed to HgO
by vanadates, a finding which is consistent with the Mars-Maessen mechanism. During
the experiments, oxidized Hg was not liberated as HgO, but rather remained captured on
the surface (Lee and Bae, 2009). Gutberlet et al. (2008) hypothesized that the NOx
reaction causes the reduction of V5+ to V4+ and that the active site typically is re-oxidized
by oxygen, but might possibly be oxidized by oxidized Hg. The Gutberlet (2008)
hypotheses supports Mars-Maessen as a plausible mechanism.
It is plausible that all three mechanisms occur within the SCR for Hg oxidation to
occur.
32
2.2.2.1.2 SCR Governing Factors
The oxidation of Hg within an SCR reactor depends on a number of factors. The
design of the SCR catalyst itself plays a major part in its ability to produce high levels of
oxidized Hg. SCR catalysts are generally designed for the coal application by using
titanium dioxide (TiO2), supported vanadium pentoxide (V2O5) catalyst with tungsten
(WO3) or molybdenum trioxide (MoO3) as a promoter. Laudal et al. (2002) reported that
laboratory-scale testing indicated that metal oxides, including V2O5 and TiO2, promote
the conversion of elemental Hg to oxidized Hg in simple flue gas mixtures. Straube et al.
(2008) reported that because vanadia is active not only in the reduction of NOx but also in
the undesired oxidation of SO2 to SO3, its content in SCR catalyst is generally kept low
(i.e., 0.3 to 1.5 wt%). Casagrande (1999) suggested that, as an alternative to vanadia,
WO3 could be employed in larger amounts (near 10 wt%) for enhanced Hg oxidation
because WO3, a chemical promoter, also improves the mechanical and structural
properties of the catalyst. Hong et al. (2010) performed bench-scale experiments with
simulated flue gas and commercially available catalyst and found that a catalyst
containing 1.68 wt% V2O5 and 7.6 wt%. WO3 achieved 100% Hg oxidation in the
presence of 50 ppmv HCl and an NH3/NOx molar ratio of 0.8. Dranga et al. (2012)
reported that 90% mercury oxidation was achieved when the V2O5 content was 1.1 to 1.2
wt% but that Hg oxidation was only 40% when the V2O5 content was 0.5 wt%. Gutberlet
et al. (2008) provided information from bench-scale experiments that revealed 10% to
30% Hg oxidation with SCR catalyst that contained less than 0.75% V2O5 content. This
rate was achieved with 60 ppmv HCl in the flue gas at 390 °C and without NH3, NO, or
SO2 in the flue gas. This environment would have provided optimum conditions for Hg
33
oxidation. Under the same flue gas conditions, the V2O5 content was increased. With
V2O5 content of 1 wt%, the Hg oxidation was above 50% and with V2O5 content of 2.5
wt%, the Hg oxidation was 90% (Gutberlet et al., 2008). Straube (2008) concluded,
through experimental results, that Hg oxidation depends on the V2O5 content of SCR
catalyst.
In addition to the chemical makeup of the catalyst, its structural characteristics are
also important to its ability to promote Hg oxidation. Gutberlet et al. (2008) found that
SCR catalyst pitch significantly influenced Hg oxidation. The SCR pitch is defined as
the catalyst wall thickness plus the width of the channel (Drabal et al., 1996). Gutberlet
et al. (2008) found that smaller pitch was beneficial for Hg oxidation. Because mass
transfer of the gaseous species to the catalyst surface is diffusion limited, a smaller pitch
would increase the diffusion rate. However, Drabal et al. (1996) observed that smaller
pitch results in higher pressure drop across the SCR reactor. An optimum balance likely
exists among catalyst pitch, Hg oxidation, and process pressure drop. Gutberlet et al.
(2008) also found that cell wall thickness exerted no effect on Hg oxidation. Svachula et
al. (1993) reported that increasing wall thickness increased the oxidation of SO2 to SO3.
Combination of the conclusions from Gutberlet et al. (2008) and Svachula (1993) likely
means that SO2 to SO3 conversion could be managed by changing catalyst wall thickness
without any significant effect on Hg Oxidation. Senior (2006) predicted, in modeling
studies, that with NH3 present, plate and monolith catalysts would have similar levels of
Hg oxidation in low-chlorine flue gas, but that the plate catalyst would have levels of Hg
oxidation higher than those of the monolith catalyst when higher levels of HCl are
present in the flue gas.
34
Laudal et al. (2002), suggested that catalyst space velocity was important in Hg
oxidation and examined Hg oxidation behavior at four full-scale sites equipped with
SCRs. All four plants burned coal having chlorine contents greater than 60 wt ppm, with
a maximum of 1,910 wt ppm. Laudal et al. (2002) observed that Hg oxidation on a unit
with an SCR space velocity of 3,930 h-1 was lower than that of another unit that had
lower concentrations of chlorine in the coal and a space velocity of 1,800 h-1. This
finding shows that catalyst volume is important to Hg oxidation because a higher space
velocity translates to a lower volume of catalyst per unit flue gas volume. In another
analysis of full-scale data and selected bench-scale tests, Senior and Linjewile (2004)
showed that units having space velocities below 2,000 h-1 had Hg oxidation values >70%,
much higher than those of SCRs with space velocities above 4,000 h-1, which achieved
less than 40% Hg oxidation. Results of equilibrium modeling studies conducted by
Senior (2006) revealed that Hg oxidation was a function of space velocity, with the lower
values resulting in higher Hg oxidation levels for the same flue gas conditions.
Decreasing space velocity requires an increase in installed catalyst volume. Once a SCR
has been built, the ability to increase catalyst volume is limited at best. For optimum Hg
oxidation, it is best that an SCR be designed initially with a low space velocity.
The characteristics of the flue gas to which the SCR catalyst is exposed are other
important factors in achieving high levels of Hg oxidation. One of the most important
properties of the flue gas is the concentration of the halogen(s). These halogens act as Hg
oxidants and must be present in sufficient concentration for Hg oxidation to reach the
desired level. Dranga et al. (2012) observed that the activity of almost all Hg oxidation
catalysts depends on a certain concentration of HCl or HBr in the flue gas to be treated.
35
Senior (2004) provided data showing that a high level of Hg oxidation was achievable
when the Cl content of the coal exceeded 500 wt ppm. As the Cl content increased, Hg
oxidation continued to increase asymptotically toward 100%. Catalysts do not effectively
oxidize Hg when the coal contains low levels of halogens. Gutberlet et al. (2008) stated
that, in comparison to HCl, HBr ten times more effectively oxidized Hg. In laboratory
tests, the amount of HBr needed to achieve similar oxidation rates was one-tenth the
amount of HCl required.
Vosteen et al. (2006) reported that HBr proved to be more effective at oxidizing
Hg because bromine radicals are more prevalent than chlorine radicals under similar
conditions. Vosteen et al. (2006) also concluded that this behavior would be true for all
types of coals, including those containing high levels of sulfur, because, unlike chlorine
radicals, bromine radicals are not consumed when exposed to SO2. Vosteen (2003)
concluded that Hg oxidation in the presence of bromine would be complete with a Br/Hg
ratio (lb/lb) of 100:1 to 10,000:1. Cao et al. (2008), Eswaran and Stenger (2005),
Ghorishi (2003), He (2009), Hong et al. (2010), Laudal et al. (2002), Senior (2006) and
Straube (2007), have shown during bench-scale and full-scale tests, that Hg oxidation
increased as the HCl concentration increased. Cao (2008), Niksa (2010), and Vosteen et
al. (2006) found during both bench-scale tests and Hg oxidation chemistry modeling, that
Hg oxidation increased as the concentration of HBr and HI in the flue gas increased. Cao
(2008) concluded that Hg oxidation was enhanced by the addition of hydrogen halides in
the following order: HBr, HI, then HCl and HF; which means that is HBr is more
effective than HF, HI, and HCl in oxidizing Hg.
36
In addition to the halogen content, other flue gas constituents directly affect the
ability of the SCR catalyst to promote Hg oxidation. For instance, Tong (2009) observed
in bench-scale studies, that carbon monoxide (CO) inhibits Hg oxidation when the HCl
content of the flue gas is below 10 ppmv. Zhuang et al. (2007) concluded that SO2 and
SO3 influenced Hg oxidation because they compete with HCl for SCR catalyst active
sites. Lei et al. (2008) proposed that, in comparison with SO2, Hg bonded only weakly to
the active sites and that SO2 would be preferentially adsorbed.
The temperature of the flue gas is another important operating parameter. SCRs
operate in the optimum temperature range for the deNOx reaction, which is between 300
and 400 °C (Sloss et al. 1992). Granite and Presto (2006) reported that the chlorine
Deacon reaction occurs at flue gas temperatures of 300 to 400 °C, the same temperature
window of the SCR NOx–NH3 reaction. Hong et al. (2010), who discovered during
bench-scale testing that Hg oxidation was sensitive to flue gas temperature, conducted
testing at three temperatures (250, 300, and 350 °C), with HCl concentration of 50 ppmv
and without NH3 and NOx in the flue gas. Hong et al. (2010) found that the highest Hg
oxidation (70%) occurred at the temperature of 350 °C, and that the lowest oxidation
(10%) was observed at the temperature of 250 °C. During a study of Hg oxidation
behavior in full-scale SCRs, Senior and Linjewile (2004) found that when the effects of
HCl concentration and coal sulfur content were taken into account, a clear correlation
existed between higher flue gas temperatures and lower Hg oxidation within the SCR.
Senior and Linjewile (2004) observed the highest level of Hg oxidation at a flue gas
temperature of 330 °C. In a later heterogeneous oxidation modeling study, Senior (2006)
found that, in comparison with performance at 370 °C, higher extents of Hg oxidation
37
occurred at flue gas temperatures of 320 °C. Lee and Bae (2009) suggested that at higher
SCR temperatures, Hg might adsorb less readily on the SCR catalyst.
To a large extent, NH3 concentrations in the SCR inhibit the ability of the SCR to
catalyze the Hg oxidation reaction. In a study of Hg oxidation data from a bench-scale
SCR, Senior and Linjewile (2004) concluded that oxidation decreased in the presence of
NH3. Hong et al. (2010) conducted bench-scale tests experiments with constant HCl,
NOx, and Hg concentrations and varied the NH3 injection rate by varying the α ratio. The
testing revealed that, for lower values of α (<0.4), Hg oxidation was 100%. The Hg
oxidation efficiency decreased as the α ratio increased, with a final Hg oxidation
efficiency of 65% at a ratio of α =1.0. In a bench-scale study, Gutberlet et al. (2008) also
observed that increasing the α ratio negatively impacted Hg oxidation. However,
consideration must be given to the fact that the NH3 concentration does not remain
constant in an SCR reactor. As the flue gas travels through the reactor, NH3 is consumed
in its reaction with NOx. In fact, although inlet levels of NH3 can exceed 500 ppmv, the
outlet NH3 concentration is typically below 2 ppmv (Jensen-Holm, 2007). The α ratio
may not be the ideal parameter to monitor. Rather, the evaluation of local NH3
concentration may be the more appropriate condition to consider.
Dragna (2012) developed the diagram shown in Figure 2.1 to illustrate the
interplay among the NOx reaction, NH3 concentration, and Hg oxidation. As NH3 is
consumed in the SCR by the deNOx reactions, more active vanadia sites become
available on the catalyst for adsorption of HCl and Hg. Once adsorbed, the Hg can be
oxidized via the Languimuir-Hilsherwood mechanism (by reaction with HCl or HBr) or
via the Mars-Maessen mechanism (by reaction with lattice oxygen). In either case, the
38
consumption of NH3, or absence of NH3, promotes Hg oxidation. Hong et al. (2010)
concluded that injection of NH3seems to cause Hg to desorb from the catalyst surface and
that NH3 preferentially adsorbs onto the SCR catalyst surface when both NH3 and Hg
components are present. Niksa and Fujiwara (2005) concluded that HCl competes for
active sites with NH3, but this effect decreases as NH3 is consumed in the reactor.
Figure 2.1 Schematic diagram of the changes in flue gas composition in an SCR
Note: From “Oxidation Catalysts for Elemental Mercury in Flue Gases—A Review” by
B. A. Dranga, L. Lazar and H. Koeser, 2012, Catalyst, 2, p. 158. Copyright 2012 by
MPDI. Reprinted with permission.
The age of the catalyst (i.e., how long it has been exposed to flue gas) also
requires consideration. Different types of degradation of an SCR catalyst reduce its
useful lifetime (Sloss et al., 1992). The degradation is quantified through laboratory
measurement of a catalyst’s ability to reduce NOx emissions. The initial ability is
defined as the original catalyst activity (Ko). The measurement is repeated and new
values are computed (K). The relative ratio is computed (K/Ko). The catalyst reaction
39
activity (K) degrades over time (i.e. K/K0 <1), for a number of reasons: poisoning,
deposition of solids, sintering, and erosion (Crowe and Ichiki, 2002). Eswaran and
Stenger (2008), in bench-scale Hg oxidation tests with SCR catalyst and different flue gas
exposure times (1,030 h, 1,450 h and 3,300 h), concluded that increasing catalyst age
reduces Hg oxidation activity. In laboratory tests of exposed SCR catalyst, Gutberlet et
al. (2008) observed behavior similar to that reported by Eswaran and Stenger (2008).
The halogen concentration is another important factor to consider, Cao et al.
(2008) reported that 3 ppmv HBr produced 80% oxidized Hg in a bench-scale SCR with
PRB simulated flue gas. The tests were conducted at 360 °C, space velocity of 3,600 h-1,
and catalyst containing of V2O5, WO3, and TiO2. Lee et al. (2008) reported that 20 ppmv
HCl produced 88% oxidized Hg in a bench-scale reactor under simulated PRB flue gas
conditions. The tests were conducted at 350 °C, space velocity of 2000 h-1, and the flue
gas did not contain fly ash. Lee et al. (2008) also reported that the inclusion of fly ash
reduced Hg oxidation by approximately 20%, and that the absence of NH3 resulted in
higher levels of oxidized Hg.
2.2.2.2 Native Heterogeneous Oxidation
The heterogeneous oxidation of Hg is dominated by in-situ fly ash and unburned
carbon particles when a SCR is not present. During modeling studies to predict the
oxidation of Hg, Niksa et al. (2002) modeled the extent of Hg oxidation in the exhausts
from a bench-scale combustor fired with five different coals, concluded that unburned
carbon played an essential role in heterogeneous Hg oxidation. Niska et al. (2002) found,
in one test case, that sufficient concentrations of both chlorine and unburned carbon
40
produced a high rate of Hg oxidation (i.e., 90% oxidation). Although acknowledging the
roles of the amount and characteristics of unburned carbon particles (size, total surface
area) in heterogeneous oxidation, Niksa et al. (2002) also indicated that the
concentrations of CO, hydrocarbons, H2O, O2, NOx, and SOx were important.
Zhao et al. (2010), in a fixed-bed study of fly ash as an Hg oxidation catalyst,
found Hg oxidation levels from 10.3% to 27.5% and reported that the Hg oxidation
process was a byproduct of adsorption of Hg and an oxidant (i.e., HCl). Zhao et al.
(2010) reported that, similar to the heterogeneous oxidation occurring in an SCR,
heterogeneous oxidation by native fly ash and unburned carbon particles followed either
an Eley-Rideal mechanism or a Mars-Maessen mechanism. In a fixed-bed study of fly
ash as an Hg oxidation catalyst, Lee et al. (1997) found that CuO and Fe2O3 caused
significant catalytic activity for oxidation of elemental Hg when the simulated flue gas
contained 50 ppmv of HCl and when the gas temperature ranged from 150 to 200 °C.
Lee et al. (1997) reported that Hg oxidation levels reached 95% when fly ash contained
either 14 wt% Fe2O3 or 1.0 wt% CuO, levels of both oxides that are much higher than
those typically found in fly ashes. The results also showed that SO2 and H2O decreased
the Hg oxidation effectiveness of both oxides but did so to a lesser degree with the fly ash
containing 1 wt% CuO. Bhardwaj et al. (2009) found, during fixed-bed fly ash oxidation
testing, that increasing levels of unburned carbon and fly ash surface area resulted in
improved Hg oxidation and that, at unburned carbon levels of 40 wt%, 150 °C, and 50
ppmv HCl, Hg oxidation levels of 42% were achievable. During fixed-bed oxidation
tests with fly ash from PRB and bituminous coals, Norton (2002) observed that oxidation
levels up to 32% were achievable in flue gas at 180 °C, 1600 ppmv SO2, and 50 ppmv
41
HCl. Norton (1999) observed that the ash itself did not play a critical role in oxidation,
but might constitute a contributing factor but that the flue gas matrix itself was more
critical to Hg oxidation.
The literature suggests that native heterogeneous Hg oxidation can occur but that
the level of oxidation depends on many factors. Although high levels of oxidation are
observed under ideal conditions, native heterogeneous oxidation is likely to be too
dependent on fly ash characteristics such as Fe2O3 content, CuO content, and unburned
carbon content to be considered a reliable means of Hg oxidation.
2.3
Hg Capture in Wet FGD
The ability of a wet FGD to remove Hg from flue gas is directly related to the
speciation of Hg compounds entering the wet FGD and to the dynamic state of the Hg
until it is removed from the wet FGD. For example, if the flue gas at the wet FGD inlet
contains HgCl2 (a water soluble form), the exiting flue gas will be free of HgCl2, which is
captured in the wet FGD sump. As long as the compound does not change chemically,
HgCl2 should be discharged along with the wet FGD blowdown or with the gypsum.
Additional important reactions likely take place within the wet FGD sump that govern the
final state of the Hg. There are three likely outcomes or combinations of outcomes: (1)
captured Hg stays in solution and is discharged along with the wet FGD blowdown, (2)
captured Hg is reduced to its elemental form, is re-introduced into the flue gas stream,
and is emitted from the stack, and (3) captured Hg is adsorbed or precipitated with the
gypsum or other solids and exits the wet FGD along with the gypsum. In a wet FGD, all
three scenarios may occur simultaneously to varying degrees.
42
2.3.1
Wet FGD Hg Removal Performance Data
Mejj (1991), in a study of Hg emissions from boilers equipped with wet FGDs in
the Netherlands, reported that 50% to 70% of the Hg was removed from the flue gas
across the wet FGD. The boilers studied by Mejj (1991) were not equipped with SCRs to
control NOx, a fact that likely limited the oxidized Hg present and resulted in lower
removals of Hg. In a study of EPA’s Information Collection Request (EPA ICR) data,
Senior (2001) found a removal rate of 90% of the measured oxidized Hg across wet
FGDs. The EPA ICR data included results from 19 units equipped with wet FGD and
thus provided a good, diverse dataset from which Senior (2001) drew those conclusions.
Senior (2007) later reported that elemental Hg emission sometimes increased across a wet
FGD. In a study of Hg removal at ten power plants, eight of which were equipped with
wet FGDs, Withum (2006) found that the SCR-wet FGD combination removed a
substantial fraction of Hg from the flue gas. The coal-to-stack removals ranged from
65% to 97% for units equipped with an SCR and from 57% to 87% for units without an
SCR. Withum (2006) reported that oxidized Hg removal across the wet FGD was not a
function of wet FGD type. Jingjing et al. (2009) also reported that oxidized Hg removal
was independent of wet FGD type. In the Withum (2006) study, the results revealed that,
in some instances, the elemental Hg concentration in flue gas actually increased across
the wet FGD. Such an increase is referred to as Hg reemission because captured Hg is
actually reemitted from the FGD sump. During a reemission event, a chemical reaction
within the wet FGD results in the transformation of absorbed oxidized Hg to elemental
Hg. Because of its low solubility, elemental Hg is desorbed from the liquid to the gas and
emitted from the stack (Omine et al., 2012). Blythe et al. (2005), in a pilot study of low-
43
temperature oxidation catalyst, discovered that 100% of oxidized Hg was removed in the
wet FGD and that overall Hg removal was hindered by Hg reemission. In their report,
Blythe et al. (2005) stated that 84% overall Hg removal should have been achieved but
that Hg reemission resulted in an overall Hg removal rate of only 79%.
2.3.2
Solubility
The solubility of Hg in water varies with its chemical composition. Hg in flue
gases exits in various forms, such as Hg0, HgCl2, HgBr2, HgI2, and HgO, and each of
these compounds has unique water solubility. The solubility of the compounds varies as
a function of temperature, ionic strength, and the concentrations of other species. The
oxidized Hg and, to a much lesser extent, elemental Hg, are scrubbed from the flue gas
and enter the wet FGD liquor. The extent to which the Hg compounds are scrubbed is
largely a function of their solubility. Table 2.2 summarizes solubility data for various Hg
compounds.
Thomas (1939) discovered during experiments that the solubility of HgCl2 in
water increased as the concentration of dissolved CaCl2 increased. Thomas (1939) found
that, in comparison with HgCl2 solubility without CaCl2 present, the solubility increased
by 41% when the concentration of CaCl2 in the solvent (i.e., water) was raised to 0.1068
mol/kg (roughly 11,000 wt ppm) and by 219% when the CaCl2 concentration was raised
to 0.6043 mol/kg (roughly 66,000 wt ppm). Blythe et al. (2008), found, in bench-scale
studies, that high concentrations of chlorides beneficially reduced the propensity of Hg to
be reemitted once captured, and that a higher chloride concentration dramatically slowed
Hg reemission. Caro (2009) reported that the amount of air in a solution affected the
44
solubility of elemental Hg. In fact, a large concentration of dissolved air could increase
the solubility of elemental Hg by 700 times, which would make it as soluble as HgO, as
can be observed in Table 2.2.
Table 2.2 Solubility of Various Hg Compounds in Water
Molality
Molecular
at
Compound
Compound
Weight
298.15
K
Name
Formula
(g/mol)
(mol/kg)
Elemental
Hg0
200.59
3.03 x 10-7
Mercurya
Molality
at
323.15 K
(mol/kg)
Comparative
Solubility
at
298.15 K
5.91 x 10-7
1
Mercury(II)
chlorideb
HgCl2
271.50
0.259
0.467
854,785
Mercury(II)
Bromideb
HgBr2
360.40
1.7 x 10-2
3.55 x 10-2
56,106
Mercury(II)
Oxideb
HgO
216.59
2.447 x 10-4
not found
808
Mercury(II)
Iodideb
HgI2
454.40
1.21 x 10-4
4.38 x 10-4
400
Mercury
Sulfidec
HgS
232.60
1.2 x 10-25
not found
4 x 10-19
Note: Information for developing table was compiled from three separate sources: a.
Seidell (1917), b. Cleaver et al. (1985), and c. Audeh (1993)
Note: From Tables 4, 8, 13, 17 “Solubility of Mercury and Mercury Salts in Water and
Aqueous Solutions” by H.L. Clever, S.A. Johnson and M.E. Derrick, 1985, J. Phys. Chem
Ref. Data,14, No 3, 1985. Copyright 1985 by ACS. Reprinted with permission.
The low solubility of HgS has been used to remove Hg from wet FGD liquors.
Ghorishi (2006) tested the effect of forming HgS by injecting sodium hydrosulfide
(NaHS) into the FGD sump. The compound would dissolve and react with the Hg to
45
form HgS, which would precipitate from solution. The precipitation of HgS would
provide dual benefits: (1) reduce the risk of reemissions and (2) limit the Hg
concentration of the wet FGD wastewater blowdown. In addition to NaHS, there are a
number of chemical compounds that can be used to precipitate Hg.
2.3.3
Role of Hg Reemission
Reemission of Hg from wet FGDs plays an important role in the use of SCR and
wet FGD as a compliance strategy for meeting Hg emission regulations. Several
researchers studying actual, full-scale, wet FGD Hg removal data have reported Hg
reemission (Blythe et al. 2005; Chang and Ghorishi 2003; and Senior 2001). If not
controlled, Hg reemission events could cause plant emissions to exceed regulatory levels.
A study of atmospheric chemistry by Munthe (1991), revealed that oxidized Hg was
reduced to its elemental form in clouds. Munthe (1991) postulated that HSO3- (bisulfite)
and pH played an important role in the reduction of oxidized Hg. Loon (2000) confirmed
the finding by Munthe (1991) and determined reaction rate constants for the reduction of
oxidized Hg under atmospheric conditions. Blythe et al. (2008), in their laboratory study,
investigated the proposed oxidized Hg reaction pathways and conducted experiments to
determine reaction rate constants. The results indicated that the reduction of oxidized Hg
was a complicated process, likely involving a number of potential reduction pathways,
and that chloride, sulfite, and pH have major effects on the reaction rates and
mechanisms. Through experimentation at the bench scale, Blythe et al. (2008)
determined that higher concentrations of chlorides lowered the potential for Hg
reemission and postulated that the relationship of Hg reemission to pH and sulfite was
46
complex. For example, where sulfite and chloride were taken into account, Hg
reemission was found to increase with increasing pH.
In a study to determine whether adding aluminum salts to a wet FGD could limit
Hg reemission, Gonzalez et al. (2012) found that lower wet FGD pH resulted in a higher
overall Hg removal efficiency. This finding could support the earlier finding by Blythe et
al. (2008). The ability to remove oxidized Hg remained constant in both cases; however,
lower pH reduced the propensity of the captured Hg to be reemitted, thereby resulting in
an Hg removal greater than that found in the higher pH case. Schuetze et al. (2012) found
that Hg reemissions were dampened by the presence of chloride and bromide ions, when
the pH of the solution was below 7, and postulated that both chloride and bromides form
stable ionic tetrahalogenide complexes that reduce the potential for Hg reemission to
occur. Wet FGDs operating at higher concentrations of chlorides or bromides would
have lower Hg reemission and thus, would have higher overall Hg collection efficiency.
Blythe et al. (2008) presented Figure 2.2 to describe the potential Hg reemission reaction
pathways.
Omine et al. (2012) confirmed, during a bench-scale study, that oxidized Hg
reduction in wet FGDs was a function of pH, Hg concentration, total sulfite, and liquor
chloride and bromine concentrations. Omine et al. (2012) found that Hg reemission
occurred when sulfite concentrations were below 2 millimol/L (mM) and that, when
sulfite concentrations exceeded 9 mM, Hg reemission approached zero. In a review of
the literature, Senior (2007) surmised that the reduction of Hg by sulfite began when the
pH of the liquor exceeded 5. The operating pH range in most utility-style wet FGDs is 5
to 6. Schuetze et al. (2012) determined that pH levels greater than 5 increased the
47
occurrence of reemissions and concluded that, as pH increased, Hg reacted with OH- ions
to form HgX(OH) or Hg(OH)2 . Schuetze et al. (2012) determined that the reemission
caused by pH could be mitigated by increased concentrations of chlorides.
Figure 2.2 Schematic diagram of Hg reemission reaction pathways
Note: From Figure 51 “Bench-scale Kinetics Study of Mercury Reactions in FGD
Liquors” by G.M.Blythe, J. Currie and D.W. DeBerry, 2008, Final Report DE-FC2604NT42314. p. 65. Copyright 2008 by URS Corporation. Reprinted with permission
Omine et al. (2011) reported that increased ionic strength of the wet FGD slurry
solution by the presence of excess chlorine and bromine, reduced the likelihood that
reemission events would occur. Schuetze et al. (2012) conducted bench-scale tests
showing that increased concentration of chlorine in the wet FGD slurry solution reduces
Hg remission, supporting the conclusions by Omine et al. (2011). Chlorine and bromine
48
concentrations exceeding 2000 mg/L were shown to be sufficient to reduce the
occurrence of Hg reemissions (Omine et al., (2011).
Transition metal ions are also present in wet FGD slurries, from the influx of fly
ash and from the limestone used to capture the sulfur dioxide (SO2). Such metals might
also play a role in reducing Hg. In their bench-scale study, Chengli et al. (2010) found
the following reduction capabilities of ions in the solution: Pb2+ > Cu+ > Fe2+ > AsO2- >
Ni2+. The reductive effect of transition metals could prove beneficial by causing the
formation of insoluble Hg compounds that precipitate instead of being reemitted. For
example, Somoano et al. (2005) concluded that the addition of solid oxides (e.g., CaO,
MgO, Al2O3, Fe2O3 and V2O5) enhanced Hg capture in wet FGD by precipitating Hg onto
gypsum (CaSO4) particles to a larger extent.
2.3.4
Partitioning of Hg within the Wet FGD
Once collected in the wet FGD system the final fate of the absorbed oxidized Hg
has three possible outcomes, reemitted as elemental Hg, remain in the slurry as oxidized
Hg or colloidal particles, precipitate as a solid, or adsorb onto a solid (fly ash or gypsum).
Blythe and Richardson (2010) conducted a month-long characterization study of a fullscale wet FGDs to determine the partitioning of Hg among various effluent streams. All
of the solid and liquid streams were analyzed. The boiler studied by Blythe and
Richardson (2010) was burning an eastern bituminous coal, and was not equipped with an
SCR, but was equipped with a limestone forced oxidation (LSFO) scrubber (i.e., wet
FGD). Blythe and Richardson (2010) found that the wet FGD had very low
concentrations of Hg in the liquid (0.38–1.36 µg/L) and similar concentrations in the
49
solids (0.81–0.890 µg/g) but 99.5% of the total Hg was found in the solids. The low
concentration of Hg in solution precluded Blythe and Richardson (2010) from confirming
the presence of colloidal Hg in the slurry. In an examination of the solids, Blythe and
Richardson (2010) determined that 75% of the Hg was found in the fine solids. Blythe et
al. (2004) determined that, although Hg likely reports to the solids, the evidence suggests
that Hg could remain in solution under some wet FGD conditions, though the conditions
that cause Hg to remain in solution remain poorly understood.
In a report of results from their study of a full-scale pulverized coal-fired plant
equipped with a wet FGD, Cordoba et al. (2012) stated that 99% of the Hg captured by
the wet FGD was found in the wet FGD solids (i.e., gypsum) and that the remaining 1%
was found in the liquid. Laudal et al. (2000), in a study of two, full-scale pulverized
coal-fired plants, equipped with wet FGDs, determined that the majority of the Hg in the
wet FGD was associated with the solids. Senior et al., (2009) reported that Hg appeared
to be concentrated in the fine particles of the wet FGD solids that were predominately
iron oxyhydroxides and were not strongly associated with the solid calcium sulfate,
CaSO4.
Although mounting evidence indicates that most of the Hg will partition to the
solids, Ochoa et al. (2009), who studied Hg behavior in full-scale wet FGDs, reported
that 78% to 81% of the Hg entering the wet FGD was found in the liquid phase and that
only 15% of the Hg left the scrubber in the gypsum solids. Sanderson et al. (2008) found
a correlation between Hg concentration in the wet FGD liquor and each of the following
elements: chloride concentrations in the wet FGD liquor, acid insoluble inerts in the wet
FGD slurry solids, and the Hg content of the raw gypsum. Consequently, Sanderson et al.
50
(2008) postulated that wet FGDs with high blowdown rates had an absence of fine
particles and therefore Hg remained in solution.
2.4
Literature Review Synopsis
A literature search yielded current theories concerning the oxidation of Hg and its
subsequent removal in wet FGDs. Although vast and deep, the literature spans more than
20 years, a significant number of reports were published during the past 5 years.
Information related to the behavior of Hg in the presence of bromine was not as extensive
as the literature concerning the relationship between Hg oxidation and chlorine. The
review of the literature led to the following general conclusions:
•
Under proper conditions, Hg oxidation can occur via homogeneous and
heterogeneous means.
•
Halogen type and concentration are the most important factors in oxidizing
Hg in all situations.
•
Halogen addition effectively raises the potential for Hg oxidation to occur
under all oxidation schemes.
•
Homogeneous Hg oxidation typically does provide sufficient Hg oxidation to
support MATS rule compliance.
•
All halogens support Hg oxidation but do so to differing degrees. The
hierarchy of oxidation effectiveness is HBr > HCl > HI > HF.
•
Bromine-based homogeneous oxidation can produce oxidized Hg in amounts
greater than those resulting from other forms of halogen-based homogeneous
51
Hg oxidation. It may be possible with low-sulfur coals to use homogeneous
oxidation to achieve nearly 100% Hg oxidation with bromine addition alone.
•
SO2 concentration in the flue gas affects both homogeneous and
heterogeneous oxidation but affects the latter to a lesser extent.
•
Higher concentrations of SO2 in flue gas can severely limit chlorine-based
homogeneous Hg oxidation but affects bromine-based homogeneous
oxidation to a lesser extent. At some concentration of SO2, bromine-based
homogeneous oxidation may become limited. The actual SO2 concentration,
at which this limiting effect occurs, with both chlorine and bromine, remains
poorly understood.
•
Flue gas temperature has an effect on both homogeneous and heterogeneous
Hg oxidation.
•
The literature supports the use of the Eley-Rideal, Languimuir-Hinshelwood
or Mars-Maessen mechanisms to describe reaction pathways in an SCR
reactor.
•
Native heterogeneous oxidation occurs as a function of the unburned carbon,
Fe2O3, and Cu concentrations in fly ash. Native heterogeneous oxidation is not
a major factor in achieving high levels of oxidation. Oxidation catalyzed by
particles in the flue gas likely constitutes only a small percentage of the total
Hg oxidation that occurs.
•
The design and operation of an SCR can be optimized to achieve high levels
of Hg oxidation, if sufficient levels of halogens are present.
52
•
SCR design parameters such as space velocity, catalyst vanadium content,
catalyst activity, and catalyst pitch are important in determining the ability of
the SCR to support high levels of Hg oxidation.
•
SCR operating parameters affect the optimization of Hg oxidation. NOx
reduction is the dominant reaction, and NH3 must be consumed in the deNOx
reaction before the Hg oxidation reaction can proceed. As a result, Hg
oxidation occurs in the later sections of the SCR after consumption of the NH3
has occurred.
•
SCR-based (i.e., heterogeneous) oxidation of Hg is less sensitive than gas
phase (i.e. homogeneous) oxidation of Hg to flue gas constituents such as
SO2, CO, NOx, and H2O.
•
Hg removals of up to 95% have been observed at full-scale, coal-fired units
equipped with SCR and wet FGD, demonstrating that configuration as a
viable compliance option.
•
Oxidized Hg (HgCl2, HgBr2, HgI2, and HgO) is soluble in water. In
comparison with HgCl2, elemental Hg is over 850,000 times less soluble
under certain conditions.
•
Once captured in a wet FGD, oxidized Hg can be reduced and reemitted as
elemental Hg, because of chemical changes in the wet FGD.
•
The magnitude of Hg reemission is a function of wet FGD chemistry,
including, but not limited to, slurry pH, sulfite concentration, ionic strength,
wet FGD slurry Hg concentration, and the concentrations of transition metals.
53
•
After oxidized Hg is collected in the wet FGD system, it can be reemitted as
elemental Hg, remain in the slurry liquor as oxidized Hg or as colloidal
particles; precipitate as a solid, or adsorb to solids (fly ash or gypsum) present
in the slurry.
2.5
Critical Analysis
Although extensive, the available literature does not provide a complete view of
Hg oxidation and subsequent removal in a wet FGD. This section highlights the
strengths and weaknesses in the literature and provides a viewpoint of the current work
and how it is intended to fill information gaps, and what gaps still remain in the
understanding of low-sulfur, low-halogen, co-benefit Hg removal.
2.5.1
Strengths of the Literature
The literature on the behavior of Hg in coal-derived flue gas is extensive and
contains information from many excellent academic and applied researchers. The
behavior of Hg from the boiler to the stack is dependent on a number of factors that vary
with coal type, boiler design and the configuration of pollution control equipment. The
present dissertation is focused on a single coal type and equipment configuration, which
means that much of the literature may not apply directly..
•
The literature provides the basis for understanding the different potential
outcomes from an application of CaBr2 injection as a compliance technology.
Examples:
54
o CaBr2 injection may have applicability at power stations that burn lowsulfur, low-halogen coals, such as PRB, are equipped with SCR for deNOx
purposes and include a wet FGD for SO2 removal.
o CaBr2 injection is not likely to be needed to achieve high rates of Hg
oxidation when high-chlorine coal is burned in a boiler equipped with an
SCR and wet FGD.
2.5.2
Weaknesses of the Literature
While extensive, the literature documenting experience at full-scale power plants
does not provide enough variation in operating conditions to confirm results to those in
the literature presenting the results from research at the bench-scale. Observation of the
behavior of Hg in full-scale, coal-fired boilers are still rather novel. Additional test
programs are needed to advance this area.
•
The bench-scale literature is unbalanced and focused on isolating dependent
variables one at a time. Most of the published work was conducted at
laboratory scale using simulated flue gases. In addition, a number of
equilibrium chemistry studies are available. Although they provide valuable
insights, neither approach explains sufficiently well the actual behavior that
would occur under full-scale plant conditions.
•
The literature lacks sufficient detailed analysis of full-scale results that
describe the observed behavior in terms of the fundamental chemistry and
physics.
55
•
The literature contains separate oxidation and removal studies. Although such
programs are ideal for isolating singular behavior (i.e., the effects of
temperature on Hg oxidation in a SCR) they do not put performance in the
proper context. Compliance with EPA regulations will require that utilities
not only oxidize Hg, but also remove it with high efficiency.
•
The literature contains little work describing the mechanisms that control Hg
partitioning between solid and liquid phases in a wet FGD after the oxidized
Hg has been captured.
2.5.3
Importance of the Current Work
The current work is focused on demonstrating the performance of CaBr2 addition
at full-scale in the actual environment of interest. The work connects both Hg oxidation
and Hg removal in a wet FGD. Extensive analytical measurements were made and are
discussed herein.
•
The present study provides data from a full-scale program and involves
evaluation of the observed CaBr2 performance using the current level of
fundamental technical understanding.
•
This study, completed over a four-year period, provides a true indication of
the oxidized Hg removal that CaBr2 injection would provide under true
operating conditions.
•
The information produced in this study can be used by fundamental
researchers to test and validate hypotheses postulated for mechanisms of Hg
oxidation and will also provide potential adopters of the technology a clear
56
indication of achievable Hg removal using CaBr2 addition in a unit burning
low-sulfur, low-halogen coals, equipped with an SCR and a wet FGD.
2.5.4
Issues Not Addressed by the Current Work
A problem with conducting research at full-sale operating power plants is the
inability to control plant operations, to better understand dependent variable (e.g., Hg
oxidation) behavior as a function of independent variables (e.g., SCR NH3 flow) due to
the nature of the utility business. Power plants are operated for business purposes and
controlling independent variables to gain fundamental understanding through research is
not a high priority. Therefore, a combined approach of full-scale testing combined with
bench-scale testing is the best way to fully understand the capabilities of this new
technology. The work described within presents only a limited viewpoint of CaBr2
injection technology.
•
This study was designed to examine only one possible full-scale scenario. It
would be ideal to replicate the same study at different full-scale sites using
different coals, to benchmark laboratory-scale studies with measurements at
full-scale. This important step can lead to a more widespread application of
co-benefit Hg removal (i.e., SCR combined with wet FGD).
•
This study involved conducting test programs under normal plant operating
conditions only.
57
CHAPTER 3
METHODS
3.1
Introduction
The present work was designed to evaluate the potential commercial use of
calcium bromide (CaBr2) as an additive to coal, to enhance the oxidation and removal of
Hg in existing environmental control equipment, namely, an SCR and a wet FGD.
Electric utility companies, conservative by nature, require independent technology
evaluations to enable them to make compliance and technology investment decisions.
The determination by the EPA that it was prudent and necessary to control Hg emissions
from electric generating units necessitates that utilities invest in new technologies to
reduce future emissions. CaBr2 injection technology has been identified as a potentially
cost-effective approach to controlling Hg emissions from coal-fired power plants. The
technology involves the addition of a relatively small quantity of concentrated CaBr2
solution onto the coal, before to the coal enters the combustion zone, where the CaBr2
solution is volatized and decomposes into vapor phase forms of bromine (HBr, Br2, Br,
and Br-) that are then available to transform elemental Hg into oxidized Hg (HgBr2),
which is water-soluble. Henceforth, the terms CaBr2 addition and CaBr2 injection will be
used interchangeably. The HgBr2 is then removed to low levels in conjunction with SO2
removal in the existing wet FGD. The technology is well suited for units burning PRB
coals because those coals contain only low levels of native halogens (fluorine, chlorine,
58
bromine, and iodine). Utilities, as an industry, test new technologies thoroughly in a
well-defined approach that aims to reduce the risk of adoption by testing at different
scales with a wide range of varying flue gas conditions. The stages of the technology
development process are shown in Figure 3.1.
Figure 3.1 Electric utility technology development curve.
Technologies are typically first tested at the bench-scale (i.e., in a laboratory
setting with well controlled conditions using simulated flue gas), a step usually
undertaken to test process chemistry and determine whether a process can reach a level of
success in a controlled environment. This screening step can be accomplished at a
relatively low cost, but success at bench scale may not mean success at the next level.
The bench-scale test, using simulated flue gas, provides a technology with representative
59
test conditions and full control of independent variables that affect technology
performance. Technologies not successful at this scale usually do not advance to the next
level of evaluation, which consists of testing the process using actual flue gas from the
combustion of coal.
Testing at pilot scale involves exposing the technology to coal-derived flue gas,
which can be quite challenging, because it exposes the technology to trace constituents
found in coal that are not typically replicated in simulated flue gas laboratory studies.
Those trace constituents can, at times, provide unique challenges to new processes.
Testing at pilot scale also involves evaluating technology performance over a longer
period and incorporating a wide-array of operating conditions to develop a well
understood operating window. This phase dramatically increases the understanding of
technology performance without risking power production of the full-scale power plant
and keeps costs to a minimum.
Demonstration at the pre-commercial scale follows to ensure that the process can
be successfully scaled up. Process chemistry and process fundamentals are confirmed and
verified. This stage reveals process changes needed before design of commercial systems
is complete.
The last phase, testing the approach at full scale, is done to evaluate long-term
performance under actual conditions, including both normal and upset plant operating
conditions. Evaluators sometimes repeat this step at multiple sites before a technology is
considered to be commercial. This perspective may differ from that of original
equipment manufacturers (OEM), who may declare a technology commercial after, or
even before, the first full-scale test of the technology. However, exposing the technology
60
to different coals, different plant configurations, and different operating philosophies
dramatically reduces the overall risk of adopting new technology. The present research
program was designed around the utility technology development curve shown in Figure
3.1.
One complication in evaluating CaBr2 injection technology was the need, for an
integrated and cost-effective approach, to demonstrate both Hg oxidation and its
subsequent removal in a wet FGD. A pilot-scale study could be completed at a test
combustor (typically <1 MW) and would require that the combustor have a pilot wet
FGD. The cost of conducting a pilot-scale test under these constraints would have been
prohibitive.
A decision was made to use a hybrid program containing both full-scale and pilotscale components. The program was accomplished in three distinct phases over a fouryear period. All three phases were conducted by using a full-scale boiler to produce the
flue gas necessary to properly evaluate the approach. Phase I included only flue gas
measurements to evaluate the ability of CaBr2 to affect Hg speciation. In Phase I, CaBr2
was introduced into the boiler in varying concentrations, and speciated Hg measurements
were made at four locations in the flue gas stream to determine the dose–response of the
system. Phases IIA and IIB included the installation of a pilot-scale wet FGD and
replication of the conditions investigated during Phase I. During Phases IIA and IIB, the
boiler with CaBr2 injection produced the flue gas containing bromine and oxidized
mercury (HgBr2), and the installation of the pilot-scale wet FGD enabled a detailed
parametric study of HgBr2 removal. Experiments on wet FGD chemistry were conducted
to determine the impact, if any, on the removal of HgBr2 in the wet FGD. Phase III
61
included the addition of CaBr2 to the coal for an 83-day operating period and focused on
the total Hg removal performance of the technology (i.e., both Hg oxidation and
subsequent Hg removal in a wet FGD). During Phase III, the boiler was operated just as
it would have been if a technical evaluation had not been under way, allowing the
evaluation of technology performance under normal operating conditions. Between
Phase I and Phase III, a full-scale wet FGD was installed.
This test design proved ideal, because using the boiler to vaporize the CaBr2
posed virtually no risk to normal operation of the unit and provided a treated flue gas to
support the technology evaluation. If the technology proved ineffective during Phase I,
the evaluation would have been halted, a scenario also true for Phase II. A failure during
Phase III would limit consideration of CaBr2 injection technology as a MATS rule
compliance option for the site being tested. Each phase was designed to answer specific
questions and provide critical evaluation information: Phase I determined the
effectiveness of Hg oxidation chemistry, Phase II evaluated wet FGD removal
performance, and Phase III established longer term technology performance. The data
produced during the three phases were used to answer research hypotheses posed in
Chapter 1.
3.2
Research Design
3.2.1
James H. Miller Steam Plant
All three phases of the study were conducted at Alabama Power Company’s
Miller Steam Plant, located in Quinton, Alabama. The site contains four coal-fired units
that each burn PRB coal exclusively to generate electric power. The plant can produce
62
approximately 2,880 MW of electricity (gross). Each of the four units is rated at roughly
720 MW of electric power generation. At the start of the test program, all four units were
equipped with SCRs and cold side-ESPs as environmental control equipment. During the
course of the research program, each unit was outfitted with a high-efficiency, limestone
forced oxidation (LSFO) wet FGD designed by Advatech (a joint venture between
Mitsubishi Heavy Industries Americas and URS Corporation).
3.2.1.1 Plant Miller Unit 4 and Unit 3 Overview
All of the testing associated with the present work was performed on Unit 4, a
relatively new unit placed in service in 1991. The unit has a Babcock and Wilcox
(B&W) opposed-wall-fired, dry-bottom boiler. Coal is fed from seven pulverizers, each
with a dedicated silo and gravimetric feeder. The pulverizers are B&W roll-and-race
style MPS 89 mills, designed to feed up to 61,700 kg/hr (136,000 lb/hr) of coal. Coal is
loaded into the bunkers, one per pulverizer, twice per day and fed from the bunker using
a gravimetric feeder. Primary combustion air (roughly 10% of the total combustion air)
enters the pulverizer from the air heater. The primary air heats the coal from ambient
temperature to roughly 70 ◦C and transports the pulverized coal to the boiler. After being
ground to a size of 95 wt% passing 325 mesh (44 µm), the coal from each pulverizer is
split into eight individual transport pipes and transported to the burners. The Unit 4
boiler has fifty-six burners. The front wall of the furnace contains four rows of eight
burners, and the rear wall contains three rows of eight burners. One pulverizer feeds each
row of burners. At full load, all seven pulverizers and all fifty-six burners are in service.
The burner elevations are identified sequentially from Row A to Row G. The front face
63
of the boiler includes three burner elevations fed from Pulverizers B, G, and A from
bottom to top. Burners fed from pulverizers F, D, E, and C, also listed from bottom to
top, are located on the rear face of the boiler.
At the time of the study, the heat rate of the unit was approximately 10,000
Btu/kWhr. The boiler was designed to provide 2,137,000 kg/hr (4,711,000 lb/hr) steam
flow at 16.5 MPa (2,400 psig) and a boiler operating temperature of 1,400 ◦C. Once the
flue gas leaves the boiler and the superheater section, it enters the economizer, which
preheats boiler feedwater. The economizer reduces the flue gas temperature to roughly
538 ◦C. Upon leaving the economizer, the flue gas is divided into two equal streams for
treatment in the downstream environmental control equipment.
During Phase III, Unit 3 was used for Hg removal performance comparison. Unit
3 is a sister unit to Unit 4 and has the same boiler and emissions control equipment. Both
units burn PRB coal from the same source.
3.2.1.2 Coal Type and Mass Flow Rate
Unit 4 burned PRB coal exclusively during all three test phases. The PRB burned
was from three different mines: Arch Coal’s Black Thunder, Peabody Coal’s North
Antelope Rochelle, or Kennecott/Cloud Peak’s Antelope, which are all located in the
Powder River Basin of Wyoming. The higher heating value of the coals delivered to the
site range from 8,500 to 8,800 Btu/lb. The plant receives its coal via rail. Once on site,
the coal is loaded directly from the train into the bunkers or is stored locally in a pile for
later use. All four units at the site are fed from the same coal source via common coal
64
handling equipment. Table 3.1 lists the properties of the coal measured during the three
test phases.
A typical coal feed rate at 720 MW is approximately 363,000 kg/hr (800,000
lb/hr). Because of constraints on the SCR operating temperature, the minimum operating
load on the unit is roughly 300 MW. Coal flow rate at 300 MW approximate 155,000
kg/hr (342,000 lb/hr).
Table 3:1 Coal Analysis Plan
Fuel property
(dry basis, except as noted)
Unit
Phase I
Phase II
Phase III
Btu/lb
X
X
X
Carbon
wt%
X
X
X
Nitrogen
wt%
X
X
X
Oxygen
wt%
X
X
X
Ash
wt%
X
X
X
Sulfur
wt%
X
X
X
Moisture (as received)
wt%
X
X
X
Mercury
wt ppb
X
X
X
Chlorine
wt ppb
X
X
X
Bromine
wt ppb
X
X
X
Heating Value
3.2.1.3 Environmental Control Equipment
The SCR reactor, designed to reduce NOx emissions by 90%, is housed in two
separate casings. Ammonia (NH3) is added to the flue gas upstream from the SCR. The
rate NH3 addition depends on the desired NOx emission rate. In practice, setting a desired
65
SCR outlet NOx emission concentration controls the NH3 flow, which changes in realtime on the basis of SCR inlet NOx concentration. The desired stack NOx emission rate
at Unit 4 is 0.015 lb/MBtu. The Unit 4 SCR, designed to achieve 90% NOx removal with
an NH3 slip of 2 ppmv and holding up to four layers of catalyst, was placed into
commercial operation in May 2003. At that time, the SCR was filled with three layers of
9.2 mm honeycomb catalyst manufactured by Cormetech. The SCR operated at a
minimum operating temperature of 310 ◦C and a normal operating temperature of 380 ◦C.
The original catalyst loaded in 2003 had not been replaced at the time of the current tests.
During Fall 2009, a fourth layer of catalyst was added.
Historically, the SCR was placed in service during the ozone season (May 1 to
September 31) from 2003 through 2009. Operation during an ozone season corresponds
to 3,696 potential hours of flue gas exposure. Starting in January 2010, as a result of the
Clean Air Interstate Rule, continuous SCR operation was required.
From the outlet of each SCR housing, the flue gas travels to a Ljungstrom-style
air heater, where heat rejected from the flue gas is transferred to the incoming
combustion air to improve process efficiency. The flue gas temperature exiting the air
heater typically ranges from 155 ◦C (311 ◦F) to 165 ◦C (330 ◦F).
The flue gas passes from the air preheater to a cold-side ESP, which removes fly
ash from the flue gas. Two cold-side ESP casings accept flue gas from the corresponding
SCR housing. The cold-side ESP is an ABB-Flakt European-style design that contains
high-voltage electrodes having rigid frames with spiral discharge electrodes and
traditional transformer rectifier sets. The rapping system uses tumbling hammer rappers
on the high-voltage discharge electrodes and collecting plates. Generously designed, the
66
cold-side ESP has a specific collecting area of 1000 (ft2 min)/(1000 ft3) (SCA equals ft2
of collecting area/1000 actual ft3/min of flue gas). The Unit 4 SCA has almost three
times the average specific collecting area typically found in cold-side ESPs in the United
States. Each cold-side ESP casing has six rows of hoppers and four individual hoppers
per row, for a total of forty-eight hoppers. Each cold-side ESP casing has six electric
fields in the direction of gas flow with two transformer rectifiers per electrical field, for a
total of twenty-four transformer rectifiers. Historical filterable particulate matter
emissions from the ESP are low. The Title V filterable particulate matter emissions limit
is 0.03 lb/MBtu. During Phases I, IIA, and IIB, the flue gas from the ESP was exhausted
to the atmosphere via a 210 m tall stack. During Phase III, the cold-side ESP was
followed by a wet FGD.
During Phase II, a single tower 2 MW pilot-scale Advatech scrubber was installed
downstream of the A casing of the cold-side ESP. The wet FGD was installed
downstream from the cold-side ESP but was plumbed across the full-scale induced draft
(ID) fan. The outlet of the pilot-scale wet FGD connected to ductwork upstream of the
ID fan inlet and the inlet of the pilot-scale wet FGD connected to ductwork downstream
of the ID fan outlet. Because the flue gas processed by the pilot-scale wet FGD was
equivalent to only 2 MW of the 88 MW of flue gas passing through that ID fan, any
effects; such as Hg concentration, flue gas moisture content, halogen content, and flue
gas temperature, of the pilot-scale wet FGD had on the flue gas were deemed negligible.
This arrangement allowed the wet FGD to be operated without a dedicated wet induced
draft fan or a dry booster fan and reduced the complexity of the installation and overall
cost of the test program.
67
The pilot scale wet FGD was operated as a limestone forced oxidation wet FGD.
Plant compressed air was supplied to the wet FGD sump via an MHI proprietary jet air
sparger system that uses the discharge from the wet FGD slurry recycle pump and an
educator to introduce air into the sump. The amount of air introduced into the sump
exceeded the stoichiometric molar flow rate of O2 required by the reaction of sulfur
dioxide (SO2) with calcium carbonate (CaCO3) to form calcium sulfate (CaSO4). The
recycle pump provided limestone slurry to the slurry nozzles. Makeup water to the wet
FGD was also added on a periodic basis to keep the mist eliminators clean and was added
to the sump to replace evaporated water lost to the flue gas. Wet FGD slurry was
constantly introduced to a hydrocyclone, which split the slurry into two streams, the
underflow (50 wt % coarse solids) and the overflow (1 to 3 wt % finer solids). Both
streams were recombined and returned to the system until solids needed removing from
the system, at which time, the hydrocyclone underflow was directed to an external
storage tote. The gypsum crystals settled within the external storage tote via natural
gravity. The supernatant liquid above the solids was then pumped back to the sump, and
the settled gypsum crystals were disposed of, in the as-found condition, onsite in a dry
solid landfill. Limestone slurry consisted of pre-ground limestone combined with
makeup water. The feed rate of the limestone slurry was controlled via a real-time pH
measurement.
Instruments were installed to continuously monitor the 2 MW wet FGD
oxidization-reduction potential (ORP) and pH. The system was operated at a pH of 5.5
and a solids concentration of approximately 20 wt %. The concentration of solids was
determined by manual gravimetric sampling. The system was designed to achieve 90%
68
SO2 removal. SO2 removal efficiency was monitored in real-time using inlet and outlet
SO2 measurements. The flue gas exiting the 2 MW wet FGD was reheated, with the use
of an electric heater made by Chromolox, from roughly 57 to 107 ◦C before being
reintroduced into the flue gas stream of the full-scale unit.
All inlet flue gas concentration measurements (i.e., Hg semi-continuous emission
monitor, SO2, and EPA Method 26) for Hg, SO2, and halogen concentration were made in
front of the wet FGD inlet. Outlet flue gas measurements (i.e., Hg semi continuous
emission monitor, SO2, and EPA Method 26) for Hg, SO2, and halogen concentration
were made downstream from the wet FGD plenum, but in front of the flue gas heater. A
damper used at the exit of the heater assembly controlled the pressure drop across the wet
FGD and therefore allowed positive control of flue gas flow rate. A venturi type
flowmeter at the inlet to the wet FGD enabled the investigators to determine the flow rate
of gas being treated by the system. The output from the flow meter served as a control
variable for the adjustment of the control damper. A diagram of the 2 MW wet FGD is
shown in Figure 3.2.
During Phase III, the flue gas leaving the cold side ESP was treated in a full-scale
wet FGD before exiting a 150 m tall wet stack. The wet FGD is a state-of-the-art
limestone forced oxidation scrubber (LSFO) designed for 98% average SO2 removal and
sited to treat 80,700 m3/min (2,850,000 ft3/min) of flue gas. The 2 MW pilot-scale wet
FGD used during Phases IIA and IIB and the full-scale wet FGD are both single tower
double contact flow type wet FGDs made by Advatech.
69
Figure 3.2 Diagram of 2 MW slipstream pilot-scale wet FGD installed for testing at Plant
Miller Unit 4.
3.2.2
CaBr2 Feed Rates and Coal Br Concentrations
A concentrated solution of CaBr2 was used to introduce bromine to the system.
During all three phases, the CaBr2 solution was evenly split and added to the coal in the F
and G feeders. The CaBr2 solution provided the bromine (Br) that was needed to
augment the low halogen content of the coal. The Br concentration was determined as
the ratio of the mass flow of Br, provided by the CaBr2 solution, to the mass flow rate of
dry coal. Equation 1 was used to calculate the Br concentration (wt ppm on the dry coal)
with the use of information from Table 3.2. An emphasis was placed on the coal Br
concentration, and the mass flow of CaBr2 solution was not highlighted because the
70
solution flow rate required to reach a certain Br concentration on the coal can vary,
depending on the CaBr2 concentration in the solution.
!" = !!!"#! !!"# !!!"#!
!
! !"#$%
!"!!"#!
!"# !!"#!
!"!"
!
!!"#$ !!!!"#$%&'(
10! (E1)
By using coal Br concentration (wt ppm on the dry coal), changes in the CaBr2
solution concentration are compensated by adjusting the solution flow rate.
Table 3.2 Information Used to Calculate Coal Bromine Concentration
Parameter
Value
Units
Symbol
CaBr2 Solution Density
14.092
lb solution/gal
ρsol
CaBr2 Concentration
various
lb CaBr2/lb solution
CCaBr2
CaBr2 Molecular Weight
200
lb/lbmol
MWCaBr2
Br Atomic Weight
80
lb/lbmol
MWBr
Full Load Coal Flow
13,333
lb coal/min
mcoal
Typical Coal Moisture Content
0.28
lb H2O/lb coal
Cmoisture
CaBr2 Volumetric flow
various
gal solution/min
VCaBr2
3.2.3
Description of the Test Phases
The research program spanned a four-year period from fall 2006 to fall 2010.
Phase I ended in fall 2006, Phase II was conducted in two parts (IIA and IIB) in the
spring and fall of 2007, and Phase III ended in fall 2010. The phased approach to testing
reduced risk, enhanced ability to evaluate the impact of specific technical aspects on Hg
71
oxidation and removal (i.e., bromine dose-response, Hg reemissions, impact of wet FGD
ORP), and reduced the cost of the technology evaluation.
3.2.3.1 Phase I: Hg Oxidation Measurements Only
During October of 2006, seventeen days of testing were conducted at Plant Miller
Unit 4 to evaluate the potential of CaBr2 injection to oxidize mercury. Preparation of the
CaBr2 solution involved mixing 52 wt% CaBr2 stock solution with filtered water to reach
desired concentration. The diluted mixtures were stored in large plastic totes having a
total capacity of 2,500 gallons. When desired, the CaBr2 solution was pumped to the F
and G coal feeders. An injection lance introduced the CaBr2 solution into the feeder, and
the CaBr2 mixed with the coal as the coal fell from the gravemetric feeder belt into the
top of the pulverizer. The total coal flow rate, the desired Br concentration (wt ppm on
the dry coal), and the concentration of the CaBr2 solution, which were all known,
determined the desired solution feed rate. A pumping skid having a capacity of 350 to
8,300 cm3/minute conveyed the CaBr2 solution to the feeders.
To evaluate the performance of the technology, specially designed semicontinuous emissions monitors (SCEM) were used to measure speciated Hg in the flue
gas. Hg SCEMs were located at the SCR inlet, SCR outlet, cold-side ESP inlet, and the
ESP outlet. These measurement locations provided the ability to determine the effect of
flue gas temperature, equipment (i.e., SCR and cold-side ESP), and Br concentration on
Hg oxidation performance. Samples of coal, bottom ash, and fly ash were taken for future
analysis. Gas-phase measurements of halogen concentrations were made, using EPA
Method 26A, to verify the concentration of halogen added to the flue gas stream. The Br
72
concentrations investigated included 0, 3, 7, 18, 23, 33, 71, 84, 85, 165, and 328 wt ppm
on the dry coal. The duration of the tests ranged from 2 to 6 h. The SCR was in
operation with NH3 injection. NH3 injection rates were adjusted in real time and were
managed to maintain an average NOx emission rate of 0.015 lb/MBtu. Table 3.3
summarizes the Phase I test conditions.
Table 3.3 Phase I Test Conditions
Br
Concentration
(wt ppm on
the dry coal)
SCR
in service
NH3
Injection
on/off
SCR
Inlet
Hg
SCEM
in service
SCR
Wet FGD Wet FGD
Outlet
Inlet
Outlet
Hg
Hg
Hg
SCEM
SCEM
SCEM
in service in service in service
328
bypass
off
yes
yes
yes
yes
165
bypass
off
yes
yes
yes
yes
85
bypass
off
yes
yes
yes
yes
84
yes
on
yes
yes
yes
yes
71
yes
on
yes
yes
yes
yes
33
yes
on
yes
yes
yes
yes
23
yes
on
no
no
yes
yes
18
yes
on
yes
yes
yes
yes
7
yes
on
yes
yes
yes
yes
3
yes
on
yes
yes
yes
yes
0
yes
on
yes
yes
yes
yes
Note: Adapted from Table 6 “The Evaluation of Calcium Bromide for Mercury Control
at Southern Company’s Plant Miller” by Dombrowski, K. et al., 2007 p. 2-9. Copyright
2007 by EPRI. Reprinted with permission.
73
3.2.3.2 Phase IIA Spring 2007
During spring 2007, a 24-day test program was completed at Plant Miller Unit 4
to determine the ability of CaBr2 to oxidize Hg and to evaluate the subsequent oxidized
Hg removal in a 2 MW pilot-scale wet FGD. During Phase IIA, a 52 wt % solution of
CaBr2 was added to the coal to achieve the desired Br concentration (wt ppm on the dry
coal). Although the location of the injection was the same as in Phase I, in Phase IIA the
concentrated 52% CaBr2 solution was utilized rather than the diluted solution used in
Phase I. The CaBr2 solution was brought onsite in 208-liter (55 gallon) drums, and a
peristaltic pump delivered equal volumes of solution to the F and G coal feeders. A
manual metering system was used to measure the volumetric flow rate of solution. Daily
manual calibrations verified the solution flow rates. During testing, the pump calibration
curves changed over time, because of fatigue of the tubing in the peristaltic pump.
Periodic adjustment of the flow rate of CaBr2 solution compensated for this effect. A
pumping system greatly simplified from that used in Phase I allowed rapid changes in
coal Br concentration. An injection lance on each coal feeder introduced the CaBr2
solution and the coal and solution were mixed as the coal fell from the weigh feeder belt
into the top of the pulverizer. The 2 MW pilot-scale wet FGD was manned during 24
hours per day operations.
Phase IIA was divided into two parts. In the first part, Hg oxidation
measurements were made using Hg SCEMs at the SCR inlet, SCR outlet, ESP inlet and
ESP outlet to verify the oxidation behavior that was observed during Phase I. Testing
was conducted both with the SCR bypassed and with the SCR not bypassed, but without
NH3 injection.
74
In the second part of Phase IIA, extended testing ensued after determination of the
optimum Br concentration, operationally defined as the lowest Br concentration (wt ppm
on the dry coal) that resulted in the highest Hg oxidation percentage during parametric
testing. The extended test period spanned two weeks of continuous testing. During that
time, a constant Br concentration of 25 wt ppm was added to the coal for 7 days and 50
wt ppm was added for another 7 days. Testing was conducted with the SCR in service but
without NH3 injection. Table 3.4 specifies the conditions evaluated during the Phase IIA
test program.
Table 3.4 Phase IIA Test Conditions
NH3
Injection
on / off
SCR
Inlet
Hg
SCEM
in service
SCR
Outlet
Hg
SCEM
in service
Wet FGD
Inlet
Hg
SCEM
in service
Wet FGD
Outlet
Hg
SCEM
in service
bypass
off
yes
yes
yes
yes
100
bypass
off
yes
yes
yes
yes
30
bypass
off
yes
yes
yes
yes
50
yes
off
yes
yes
yes
yes
50
a
yes
off
no
no
yes
yes
30
yes
off
yes
yes
yes
yes
25a
yes
off
no
no
yes
yes
15
yes
off
yes
yes
yes
yes
5
yes
off
yes
yes
yes
yes
2
yes
off
yes
yes
yes
yes
Br
Concentration
(wt ppm on
the dry coal)
SCR
in service
250
a. denotes longer-term test condition
Note: Adapted from Table 7 “The Evaluation of Calcium Bromide for Mercury Control
at Southern Company’s Plant Miller” by Dombrowski, K. et al., 2009 p. 2-8. Copyright
2009 by EPRI. Reprinted with permission.
75
3.2.3.3 Phase IIB Fall 2007
During fall 2007, a 10-day test program was completed at Unit 4 to determine the
ability of CaBr2 to oxidize Hg and evaluate the subsequent Hg removal in a 2 MW pilotscale wet FGD. Unlike the Phase IIA test completed in spring 2007, SCR operation in
fall 2007 included NH3 injection. The absence of NH3 in the flue gas in the SCR can
provide the better Hg oxidation performance. Table 3.5 shows the conditions that were
evaluated during Phase IIB of the test program.
Table 3.5 Phase IIB Test Conditions
Br
Concentration
(wt ppm on
the dry coal)
NH3
Operation Injection
in service
on/off
SCR
ACI
Injection
duct or
sump
ACI
Rate
lb/106
acf
Wet FGD
Inlet
Hg SCEM
in service
Wet FGD
Outlet
Hg SCEM
in service
17
yes
on
no
0
yes
yes
25
yes
on
no
0
yes
yes
0
yes
on
duct
3
yes
yes
0
yes
on
duct
5.2
yes
yes
0
yes
on
duct
10.1
yes
yes
a
yes
yes
0
yes
on
sump
1.6
6
a. The lb/10 acf injection rate for the sump condition reported in the table is calculated
as if the lb/hr rate were injected into the duct (lb/Macf versus lb/gal, or wt ppm).
Note: Adapted from Table 6 “The Evaluation of Calcium Bromide for Mercury Control
at Southern Company’s Plant Miller” by Dombrowski, K. et al., 2009 p. 2-7. Copyright
2009 by EPRI. Reprinted with permission.
Senior (2004) concluded from an analysis of full-scale data that NH3 reduced the
overall effectiveness of the SCR in supporting Hg oxidation. Phase IIB was undertaken
76
to determine whether the addition of NH3 would impact the ability of CaBr2 addition to
oxidize Hg. The Phase IIA CaBr2 injection system was used during Phase IIB. In
addition to determining CaBr2 injection effectiveness, an activated carbon injection into
the wet FGD sump screening test was conducted. The activated carbon tests were done
to determine activated carbon’s ability to remove captured Hg from wet FGD slurry. The
results of the activated carbon tests are not included as part of the dissertation analysis
and discussion but are mentioned here for the sake of completeness in describing testing
details.
3.2.3.4 Phase III: 83-Day Full-Scale Demonstration
In fall 2010, an 83-day injection test program was conducted. During this test
program, Unit 4 operated in a fashion that reflected normal plant operations, that is load
was allowed to vary to meet electricity demand. As was done in Phases IIA and IIB,
CaBr2 solution was added to the F and G coal feeders but with one minor change. In
Phases IIA and IIB, the CaBr2 solution was contained in 208-liter (55-gallon) drums;
however, in Phase III, the drums were replaced with 1,040-liter (275-gallon) totes.
Monitoring of the injection system was not done on a continuous basis. The CaBr2 flow
rate was maintained to achieve a Br concentration of 20 wt ppm on the dry coal at fullload conditions. During periods of lower load, the CaBr2 addition rate remained the
same, raising the Br concentration on the coal. Higher Br concentrations were not
expected to negatively impact the results. All other environmental control equipment
(SCR with NH3 injection, cold side ESP, and wet FGD) operated under customary
operating procedures and conditions. A permanently installed Hg monitoring system
77
determined wet FGD stack gas Hg concentrations. Table 3.6 specifies the test conditions
used during Phase III.
Table 3.6 Phase III Test Conditions
Br
Concentration
(wt ppm on
the dry coal)
SCR
in service
NH3
Injection
on/off
SCR
Inlet
Hg
Monitor
in service
SCR
Outlet
Hg
Monitor
in service
Wet FGD
Inlet
Hg
Monitor
in service
Wet FGD
Outlet
Hg
Monitor
in service
0
yes
on
no
no
no
yes
20
yes
on
no
no
no
yes
10
yes
on
no
no
no
yes
8
yes
on
no
no
no
yes
2
yes
on
no
no
no
yes
Note: Adapted from Table 2-4 “Three-Month Evaluation of Furnace Addition of Calcium
Bromide for Mercury Emissions Control at Southern Company’s Plant Miller” by
Dombrowski, K. et al., 2011 p. 2-5. Copyright 2011 by Southern Company Services.
Reprinted with permission.
3.3
Measurement Techniques
3.3.1
Flue Gas Measurement Techniques
During the three phases of the research program, the use of various measurement
techniques provided data on the efficacy of CaBr2 injection technology in reaching the
goals of the program. Measurements were made of the solids (i.e., coal, fly ash,
limestone, and gypsum), flue gas, and liquids (i.e., wet FGD slurry). This section
provides details of the techniques used.
78
3.3.1.1 Hg Semi-Continuous Emission Monitoring System
During Phases I, IIA, and IIB, Hg SCEMs measured the concentration and species
of Hg present in the flue gas. CaBr2 injection is designed to alter the species distribution
of Hg by converting elemental Hg to oxidized Hg. The Hg SCEMs used during the
evaluations were designed and built at URS Corporation, and run by qualified operators
from URS. The basis of the URS Hg SCEMs is cold vapor atomic adsorption
spectrometry, coupled with a gold pre-concentration amalgamation system. A sample of
flue gas is introduced into the system using a pump, via a Quick Silver Inertial Separation
(QSISTM) Probe, which separates fly ash particles from the gas sample before it enters the
measurement system (Sjostrom et al., 2004).
Because the Hg SCEM can only measure elemental Hg, two measurement
techniques were used: (1) oxidized Hg was scrubbed from the flue gas and the elemental
Hg in the flue gas was determined, (2) the oxidized Hg was reduced to the elemental
form and the total Hg present in the flue gas was determined. The difference between the
two measurements is the concentration of oxidized Hg.
In both measurement approaches, elemental mercury passes through a cell where
the Hg is captured on a piece of gold. This process continues until Hg is collected on the
gold trap. A heated stream of air then passes over the gold trap, raising its temperature to
over 400 ◦C, and releasing the captured Hg from the gold for measurement.
A qualified person operated each Hg SCEM during the experiments. To ensure
positive quality control of the Hg speciation data, Hg spike-and-recovery checks were
conducted several times daily. During a spike and recovery check, the operator injected a
known quantity of elemental Hg into the sample line. The Hg cold-vapor atomic
79
adsorption analyzer then interrogated the modified sample. A value of +/-10% of the
expected value enabled the system to pass the quality control step (Dombrowski et al.,
2007).
3.3.1.2 Continuous Hg Monitoring System (CMMS)
During the installation of the full-scale wet FGDs, Plant Miller was outfitted with
permanent Hg measurement systems on the wet stacks of all four units. The Mercury
Freedom Systems from Thermo Scientific, designed to measure Hg on a continuous
basis, are composed of four major components: (1) 80i Hg analyzer, (2) 81i Hg
calibrator, (3) 82i probe controller, and (4) 83i probe/converter. The sample is drawn
from the stack through the model 83i inertial probe, which dilutes the sample at dilution
ratios from 25:1 to 100:1, then accelerates the flue gas through a curved loop to separate
any entrained particles from the gas. Before the flue gas is returned to the duct or stack, a
portion is bled off and becomes the sample to be analyzed for Hg concentration. The
sample is drawn through a proprietary dry conversion chamber where oxidized Hg is
converted to the elemental form. Converting the Hg at the stack avoids potential loss or
changes in oxidized Hg in the sample line. The flue gas sample travels from the probe
via a heated umbilical line to the 80i Hg analyzer. The 80i Hg analyzer contains a coldvapor atomic fluorescence (CVAF) analyzer that makes a direct measurement of Hg
concentration in the sample, a procedure that allows the analyzer to perform a continuous
measurement of Hg concentration. The analyzer, which makes an Hg concentration
measurement every 10 s (Whorton 2011), can measure total gaseous Hg (oxidized and
elemental) concentration or just elemental Hg concentration. To measure only the
80
elemental concentration, the analyzer does not convert the oxidized portion in the dry
conversion chamber. As a result, the device can determine the percentage of oxidized Hg
in the flue gas by subtracting the elemental Hg measurement from the total Hg
measurement. The Model 80i Hg analyzer has a lower detection limit of 1 ng/m3 and an
upper detection limit of 50 µg/m3.
The Model 81i Hg calibrator utilizes a vapor generator that allows standard
calibration and dynamic spiking into the sample extraction probe. A wide calibration
range, from 3 µg/m3 to 50 µg/m3, allows calibration of the analyzer at post dilution
concentrations (Thermo Scientific, 2009a). The calibration is ideally suited for daily zero
and span checks, routine converter efficiency checks, and linearity testing. The Model
82i probe controller uses a microprocessor and is connected by an umbilical line to the
stack probe and Hg converter. The controller automates probe calibration and dynamic
spiking and confirms auto dilution. In addition, it monitors the probe temperature,
measures flow rates and pressure in the sample loop, and enables automated filter
blowback (Thermo Scientific, 2009b).
The Thermo Scientific Mercury Freedom System is designed to meet or exceed
performance specifications outlined in U.S. EPA PS-12A and/or Part 75 provisions for
CMMs (Thermo Scientific, 2012). Site personnel maintain the systems daily, and the data
are collected and stored in a site-wide data collection system.
3.3.1.3 EPA Method 30B Measurement
EPA Method 30B measures total vapor-phase Hg emissions from coal-fired
combustion sources using sorbent trap sampling and an ex-situ analytical technique
81
(EPA, 2008). A known volume of flue gas is drawn through a known mass of activated
carbon, in a non-reactive glass tube, referred to as a sorbent trap. The measurement of
Hg in the sorbent trap can be done by using either digestive or thermal desorption
techniques (Laudal and Schultz, 2007). The method quantifies the mass concentration of
total vapor-phase Hg in flue gas, including elemental and oxidized forms. The analytical
range for oxidized and elemental Hg is typically from 0.1 to 50 micrograms per dry
standard cubic meter (µg/dsm3) (EPA, 2008). Although not providing a real-time Hg
concentration measurement, Method 30B does yield additional post-test for comparison
with Hg SCEM and CMMs measurements.
In the method, a specified volume of flue gas is extracted from a stack or duct
through paired, in-stack sorbent media traps at an appropriate flow rate. The traps are
arranged in two stages. The first stage, filled with iodated carbon, serves as the primary
measurement section and is spiked with a known mass of Hg to provide a reference
amount of Hg for quality control. The second stage, also filled with iodated carbon, is
used for quality assurance purposes and permits determination of breakthrough from the
first stage. If no Hg breakthrough occurs, the second stage does contain any Hg. Each
sorbent trap is mounted at the entrance to, or within, the probe, so the gas sample directly
enters the trap. Mounting the trap at the outermost tip of the probe ensures that the
sorbent trap is heated to flue gas temperatures and the sampling error is minimal, since
the Hg does not have an opportunity to react or deposit within the sampling system. The
probe and sorbent trap assembly are also heated, using auxiliary heat, to a temperature
sufficient to prevent liquid condensation in the sampling train.
82
From the heater, the sample passes through a knockout chamber and desiccant to
remove water from the sample. The gas volume is measured using a flow meter. The gas
flow is used to calculate the concentration of Hg in the flue gas once the mass of Hg in
the sorbent trap has been determined.
The Hg measurement technique used for the sorbent trap analysis was the Wet
Acid Digest/US EPA Method 1631. This method calls for the sorbent materials to be
digested by using a mixture of HNO3 / H2SO4 and the use of BrCl to completely oxidize
Hg. The oxidized Hg is reduced to elemental Hg using SnCl2. After purging the
samples, the Hg is passed over a gold trap. Thermal desorption is then used to liberate
the Hg from the gold and the Hg concentration is determined by cold-vapor atomic
fluorescence.
3.3.1.4 Ontario Hydro Hg Measurement
This Hg measurement technique was conducted according to ASTM Method
D6784-02, which applies to the determination of elemental, oxidized, particulate-bound,
and total Hg emissions from coal-fired stationary sources. The method can be used for
flue gas concentration of Hg from 0.5 µg/m3 to 100 µg/m3 under normal conditions
(ASTM, 2008).
In the Ontario Hydro method, a sample is drawn isokinetically through a probe
and filter system maintained at 120 °C, then through a set of impingers in an ice bath.
Particulate-bound Hg is captured in the front part of the system on a glass or quartz filter.
Oxidized Hg is collected in impingers containing chilled aqueous potassium chloride
(KCl) solution. Elemental Hg is collected in subsequent impingers, one of which
83
contains a chilled aqueous solution of hydrogen peroxide (H2O2) and three of which
contain chilled aqueous solutions of potassium permanganate (KMnO4). After recovery,
the impinger solutions are sent to a laboratory where they are digested and analyzed for
Hg with the use of either cold vapor atomic absorption or cold vapor atomic fluorescence.
3.3.1.5 Flue Gas Adsorbent Mercury Speciation Method
The Flue Gas Adsorbent Mercury Speciation (FAMS) method utilizes a specially
designed multiple-stage dry sorbent trap to collect Hg species from flue gas streams. The
technique selectively and sequentially captures particulate Hg, vapor phase oxidized Hg,
and vapor phase elemental Hg in separate sections of a trap and produces three
concentrations of different Hg species from a single trap.
A FAMS trap is mounted at the entrance to or within the probe, so that the gas
being sampled directly enters the trap. The temperature of the FAMS trap is held at
95 °C ± 5 °C to prevent water condensation. Elemental Hg is chemically and physically
adsorbed onto iodine impregnated carbon (Brunette et al., 2004). Particulate-bound Hg is
captured in a particulate trap, and the oxidized Hg is physically adsorbed onto potassium
chloride (KCl) treated carbon. The sample volume that can be drawn through the trap
before saturation of Hg occurs ranges from 15 to 5,000 L and is a function of the flue gas
Hg concentration. After sampling is complete, the FAMS traps are sent to a laboratory
for digestion and for analysis using EPA Method 1631 Revision E.
As with the other sorbent trap Hg measurement techniques, this method provides
no real-time flue gas Hg measurement, but provides an additional measurement for
comparison with Hg concentrations derived from Hg SCEM and CMMS.
84
3.3.1.6 EPA Method 26A
EPA Method 26A determines emissions of hydrogen halides (HCl, HBr, and HF)
and halogens (Cl2 and Br2) from stationary sources. Gas and suspended particles are
withdrawn isokinetically from the source and drawn through a sampling train containing
an optional cyclone, a filter, and impingers that contain absorbing solutions. The cyclone
collects liquid droplets; the filter collects particulate matter, including halide salts, and
the acidic and alkaline absorbing solutions collect the gaseous hydrogen halides and
halogens, respectively. The hydrogen halides, solubilized in the acidic solution, form
chloride (Cl-), bromide (Br-), and fluoride (F-) ions. The halogens have a low solubility
in the acidic solution and pass through to the alkaline solution, where they are hydrolyzed
to form a proton (H+), the halide ions, and hypohalous acid (HClO or HBrO). Sodium
thiosulfate, added to the alkaline solution, ensures reaction with the hypohalous acids to
form a second halide ion so two halide ions are formed for each molecule of halogen gas.
The halide ions in the separate solutions are then measured by ion chromatography. A
typical analytical detection limit for HCl is 0.2 µg/mL, and detection limits for the other
species should approach this limit.
Method 26A has a possible negative bias below 20 ppm HCl, perhaps resulting
from reaction with small amounts of moisture in the probe and filter. Similar bias for the
other hydrogen halides is possible (EPA, 2008). Sun et al. (2000) reported that Cl2
precisely using Method 26A was difficult at concentrations less than 5 ppmv. Method
26A remains invalidated for use in flue gas streams having halide contents less than 20
ppmv (Dombrowski et al., 2008). Because flue gas concentrations of halogens during the
85
present test are expected to be below the validated threshold of 20 ppmv, the data from
Method 26A were only used to make general observations.
3.3.1.7 EPA Method 17
During Phases I and IIA, mass concentrations of particulate matter emissions
were measured at the inlet of the the cold-side ESP A casing using EPA Method 17. In
conjunction with the data from the fly ash analytical methods, the particulate matter mass
emission data enabled the determination of the Hg mass flow rate entering the ESP.
Method 17 applies to the determination of PM emissions and within the procedure,
particulate matter, suspended within the flue gas, is withdrawn isokinetically from the
source and collected on a glass or quartz fiber filter maintained at stack temperature. The
particulate matter mass that has been collected on the filter is determined gravimetrically
after the removal of uncombined water through heating of the sample (EPA, 2000b).
3.3.2
Liquid and Solid Measurement Techniques
3.3.2.1 Wet FGD Slurry Analytical Techniques
During Phase II of the program, wet FGD slurry samples were taken daily.
Analyses for pH, ORP, and sulfite concentration were performed at the site. Additional
liquid samples were sent to a laboratory for further analyses for Hg, sulfur and nitrogen
compounds, cations, and anions. Table 3.7 provides a summary of techniques used in
analyzing the wet FGD slurry.
86
Table 3.7 Wet FGD Slurry Analytical Methods
Method
Method Title
Species/Property
Portable meter
n/a
pH
Portable meter
n/a
Oxidation Reduction Potential
(ORP)
Ion chromatography a
n/a
Sulfite
ASTM D6414a
Standard Test Methods for Total
Mercury in Coal and Coal
Combustion Residues by Acid
Extraction or Wet
Oxidation/Cold Vapor Atomic
Absorption
Mercury
Ion chromatography a
n/a
Sulfur-nitrogen compounds
a
n/a
Cations and anions
Ion chromatography
a. Measurements conducted by URS Austin Mercury Analytical Laboratory
3.3.2.2 Coal Analytical Techniques
During Phases I, IIA, and IIB, coal samples were taken at the exit of the
pulverizer using a coal fineness extraction tool. This technique involves inserting a probe
into a tap on one of the eight coal conveying pipes leaving the pulverizer. Because coal
was assumed to be uniform across all of the pulverizers, no preference was given to
which pulverizers were sampled. After removal from three of the seven pulverizers, the
samples were mixed and made into a composite sample. Because the samples were
extracted at the exit of the pulverizer, a reduction in Hg from the coal as received at the
plant was expected. During the coal pulverization process, pyrites are rejected, and
pyrites are well known to contain Hg. During Phase III, the coal samples were taken
87
from the bulk coal loaded into the bunkers (i.e., before the pulverizer). In that case, the
reported Hg values include the pyritic portion of the Hg.
During all three phases of the research program, coal samples were analyzed for
Hg concentration, halogen concentration and sulfur in addition to their ultimate and
proximate analysis. Table 3.8 provides a summary of the ASTM testing used.
Table 3.8 Coal Analytical Methodsa
Method
Method Title
Properties
ASTM D2013
Standard Practice for Preparing Coal
Samples for Analysis
Sample preparation
ASTM D5142
Standard Test Methods for Proximate
Analysis of the Analysis Sample of Coal
and Coke by Instrumental Procedures
Moisture
Volatile Matter
Ash
Fixed Carbon
ASTM D5373
Standard Test Methods for Instrumental Carbon
Determination of Carbon, Hydrogen, and Hydrogen
Nitrogen in Laboratory Samples of Coal Nitrogen
ASTM D4239
Standard Test Method for Sulfur in the
Analysis Sample of Coal and Coke
Using High-Temperature Tube Furnace
Combustion
Sulfur
ASTM D5865
Standard Test Method for Gross
Calorific Value of Coal and Coke
Heating value (Btu/lb)
ASTM D6721
Standard Test Method for Determination
of Chlorine in Coal by Oxidative
Hydrolysis Microcoulometry
Chlorine
Bromine
ASTM D6722
Standard Test Method for Total Mercury
in Coal and Coal Combustion Residues
by Direct Combustion Analysis
Mercury
a. All analyses were performed by Consol Laboratories in Phases I, IIA, IIB, and III.
88
3.2.2.3 Gypsum Analytical Techniques
During Phase II of the program, gypsum solids were extracted from the slurry of
the 2 MW pilot wet FGD and sent to a laboratory for analysis of the mass fractions of
gypsum [CaSO4Ÿ2H2O], calcium carbonate [CaCO3], and inerts, and of Hg, and halogens.
During Phase III, the solids were collected from the discharge of the Unit 3 and Unit 4
gypsum vacuum belt. Due to design constraints at the site, it was not possible to only
obtain gypsum samples from Unit 4. During Phase III, gypsum samples were taken twice
per week.
Table 3.9 provides a summary of the analytical techniques that were used in
analyzing the gypsum.
Table 3.9 Gypsum Analytical Methods
Method
Method Title
Species/Property
Atomic
Gypsum Purity Testing
Adsorption, Ion
Chromatography,
and Coulimetrics
Various
ASTM D7348a
Standard Test Methods for Loss on
Ignition (LOI) of Solid Combustion
Residues
Loss on Ignition
ASTM D6414a
Standard Test Methods for Total
Mercury in Coal and Coal Combustion
Residues by Acid Extraction or Wet
Oxidation/Cold Vapor Atomic
Absorption
Mercury
Neutron
Activationb
n/a
Bromine
a. Analysis performed by URS Austin Mercury Analytical Laboratory in Phases I, II and
III.
b. Performed by McMaster University, Ontario, Canada.
89
3.2.2.4 Fly Ash Measurement Methods
The Unit 4 cold-side ESP consists of two separate housings A and B. In Phases I,
IIA, and IIB, the fly ash samples were taken from the middle two hoppers of the first and
second rows of Housing A. A composite sample was sent to a laboratory for analysis of
Hg content and loss on ignition (LOI). Table 3.10 summarizes the test methods used.
Table 3.10 Fly Ash Analytical Methods
Method
Method Title
Species/Property
ASTM D7348a
Standard Test Methods for Loss on
Ignition (LOI) of Solid Combustion
Residues
Loss on Ignition
ASTM D6414a
Standard Test Methods for Total
Mercury in Coal and Coal Combustion
Residues by Acid Extraction or Wet
Oxidation/Cold Vapor Atomic
Absorption
Mercury
Neutron
Activationb
N/A
Bromine
a. Analysis conducted by URS Austin Mercury Analytical Laboratory in Phases I, II
and III.
b. Performed by McMaster University of Ontario, Canada.
3.4
Statistical Methods
3.4.1
Description of the Data
The statistical significance of the effect of CaBr2 injection, during Phase III, on
Hg emissions was determined by using various test methods. Table 3.11 provides a
90
listing of the independent and dependent variables used to determine the statistical
significance of the effect of CaBr2 injection on Hg emissions from wet FGDs.
Load magnitude, in Table 3.11, describes the mass flow of Hg into the system
(i.e., coal flow is linearly proportional to load); unit load directly impacts the temperature
of the flue gas. Phase III load data were transformed from scale data to nominal data by
grouping load (MW) into three different ranges: (1) 600 MW < X < 720 MW, (2) 500 <
X < 600 MW, and (3) X < 500 MW. Hg oxidation is partially dependent on flue gas
temperature, which is directly related to unit load.
CaBr2 injection status during Phase III was used as the second independent
variable. For the entire Phase III test period, CaBr2 was added to the coal at a constant
rate. For this reason, the data were transformed from a scalar value to a nominal value
representing on or off.
The Phase III Hg emissions in terms of concentration and emission rate were the
dependent variables. The Hg emissions from Unit 4 were compared with those of Unit 3,
which was never treated with CaBr2 during the research program. Unit 3 served as the
control, allowing a comparison with Hg emission from an untreated unit burning the
same coal and having a similar process train (e.g., boiler, SCR, cold-side ESP, and wet
FGD).
91
Table 3.11 Independent and Dependent Variables Used to Tests for Statistical
Significance of the Effect of CaBr2 Injection on Hg Emissions from Wet
FGD
Variable Type
Variable Description
Independent
Load
Independent
CaBr2 Addition
Dependent
Unit 4 Hg Emissions
Concentration
Hourly Hg emissions expressed in
µg/m3 measured at the wet FGD
stack.
Dependent
Unit 3 Hg Emissions
Concentration
Hourly Hg emissions expressed in
µg/m3 measured at the wet FGD
stack
Unit 4 Hg Emission Rate
30-day Rolling Average
Calculated 30-day rolling average
Hg emission rate measured at the
wet FGD stack during CaBr2
addition on Unit 4.
Unit 3 Hg Emission Rate
30-day Rolling Average
Calculated 30-day rolling average
Hg emission rate measured at the
wet FGD stack during CaBr2
addition on Unit 4.
Dependent
Dependent
Data Transformation Codes
1 – 600MW – 720 MW
2 – 501 MW – 599 MW
3 – 300 MW – 500 MW
1 – Off
2 - On
The installation of permanent CMMS on Unit 3 and Unit 4 provides a unique
opportunity to view Hg emissions for both units before, during, and after the CaBr2
injection testing. Table 3.12 provides a summary of the various periods for which data
were collected on the independent and dependent variables listed in Table 3.11.
92
Table 3.12 Time Periods During Which Independent and Dependent Data Were
Collected for Statistical Significance Analysis
Time Period
Activity
September 1-September 30, 2010
Pre-CaBr2 Injection Period
October 5-December 12, 2010
Continuous CaBr2 Injection
January 1-January 30, 2011
Post CaBr2 Injection Period
3.4.2
Descriptive Statistics
Statistical measurements, including the sample mean, standard deviation, kurtosis,
and skewness coefficients, were used to describe the Hg measurements. Histograms and
probability–probability plots (P-P plot) were used as visual aids in determining the
normality of Hg emission rate and concentration data from Units 3 and 4. The JarqueBera statistic a numerical measure of normality was used (Allen, 2011).
3.4.3
Statistical Tests Used to Evaluate Population Means
In the evaluation of statistical significance three main test procedures were used:
(1) unpaired (i.e., independent) t-test (2) paired t-test, and (3) Wilcox Ranked Sign test.
A t-test can be used to test for statistical significance if the data meet the
following criteria: (1) the dependent variable is continuous (2) each observation of the
dependent variable is independent of the other observations of the dependent variable,
and (3) the dependent variable is normally distributed. The t-test has been shown to
remain valid even if the dataset has minor deviations from normality (Lumley et al.,
2002).
93
The Wilcox Ranked Sign test is a non-parametric statistical hypothesis test used
when comparing two related samples, matched samples, or repeated measurements on a
single sample to assess whether their population means differ. The conditions for this
test are: (1) samples does not have to follow a random distribution, (2) independence
exists between the two random samples, and (3) populations do not have to be normally
distributed.
Statistical significance determines the likelihood that an observed finding could
have occurred by chance. The test of significance does not say anything about the
magnitude of the effect. The magnitude of effect describes how much of the dependent
variable can be controlled, predicted, or explained by the independent variable (Snyder
and Lawson, 1993). Cohen’s d statistic was used to describe the magnitude of effect for
the independent variable of interest. Cohen’s d is an appropriate effect size measure for
the comparison between two means and can be coupled with the results of a t-test to show
the degree of differences between the two means by the independent variable. Cohen's d
is computed by dividing the mean difference between groups by the pooled standard
deviation. A Cohen’s d value of 0.2 means that the difference in the means is small (i.e.,
a small degree of difference), whereas a Cohen’s d greater than 0.8 indicates a large
degree of difference. (Weinberg and Abromowitz, 2008).
The partial eta squared was computed as another measure of degree of effect and
provides a quantifiable measure of the correlation between an independent and a
dependent variable (Barnette, 2006). A large value of eta squared indicates that the
differences between two means is largely explained and is correlated to the independent
variable.
94
3.4.3.1 Statistical Tests for Hypotheses 4 and 5
Table 3.13 provides a summary of the statistical tests used to evaluate the
statistical significance of the effect of the independent variables (load and CaBr2 injection
on/off) on wet FGD stack Hg concentrations and emission rates. The table includes the
independent and dependent variables used in the analysis, the statistical methods used,
the null hypotheses tested, the significance levels serving as the criteria for significance.
95
Table 3.13 Statistical Tests Performed in Evaluating Hypothesis 4 and Hypothesis 5
Hypothesis
Tested
Independent
Variable
Dependent
Variable(s)
Null
Hypothesis
Test Type
Significance
Level
4
CaBr2
addition
on/off
Unit 3
wet Stack
Hg Concentration
µBr = µno Bra
Independent
t-Test
99%
4
Time
period
Unit 4
wet Stack
Hg Concentration
µSep = µJanb
Independent
t-Test
99%
4
CaBr2
addition
on/off
Unit 4
wet Stack
Hg Concentration
µBr = µno Brc
Independent
t-Test
99%
4
CaBr2
addition
on/off
Unit 3 and Unit 4
wet Stack
Hg Concentration
µU3Br = µU4Brd
Paired
t-Test
99%
5
CaBr2
addition
on/off
Unit 3/Unit 4
30-day rolling
average Hg
Emission Rate
Wilcox
Ranked
Sign
Test
99%
µU3Br = µU4Br
d
Notes: µBr - mean during CaBr2 addition; µno Br - mean without CaBr2 addition; µSep – mean
during month of September; µJan- mean during month of January; µU3Br- Unit 3 mean
during CaBr2 addition; and µU4Br – Unit 4 mean during CaBr2 addition.
a. Comparison of means of Unit 3 dependent variable when CaBr2 was being added on
Unit 4 and was not being added on Unit 4.
b. Comparison of means of Unit 4 dependent variable during months of September and
January, when CaBr2 was not being added to Unit 4.
c. Comparison of means of Unit 4 dependent variable when CaBr2 was being added on
Unit 4 and was not being added on Unit 4.
d. Comparison of means of Unit 3 and Unit 4 dependent variables when CaBr2 was being
added on Unit 4.
96
CHAPTER 4
RESULTS
4.1
Introduction
Although each phase was conducted independently, this section handles as one
large data set the data produced during the study. Hypotheses-based analysis was used to
determine whether CaBr2 injection technology enhances the ability of coal-fired units
burning PRB coal, which is low in halogens, to meet the MATS rule. The analysis was
undertaken to answer four global questions:
•
Can coal-fired boilers that burn PRB coal and are equipped with SCR, coldside ESP and wet FGD meet federal regulations for Hg emissions without the
need for additional control technology?
•
Can CaBr2 injection be utilized on a pulverized-coal boiler burning PRB coal
to increase the fraction of oxidized Hg?
•
Can the oxidized Hg created via CaBr2 injection be effectively removed from
the flue gas in sufficient quantities to meet a 30-day Hg emissions rolling
average of 1.2 lb/TBtu?
•
Can the presence of an SCR improve the cost effectiveness of CaBr2 injection
technology?
To conclusively answer these questions, six hypotheses are investigated in detail within
this chapter.
97
4.2
Hypothesis 1: Burning PRB Coal Results In Baseline Hg Oxidation Levels
Below 50% Under All Operating Conditions.
4.2.1
Baseline Hg Oxidation Analysis
Figure 4.1 provides a graphical representation of Unit 4 Hg oxidation behavior
during baseline conditions in all phases. The Hg oxidation ratio plotted on the vertical
axis and defined as the ratio of oxidized Hg to total Hg (Coxidized / Ctotal), effectively
normalizes the oxidized Hg present by the total Hg concentration in the flue gas. This
ratio provides insight into data trends while the overall concentration of Hg changes. An
Hg oxidation ratio of 1 indicates that all of the Hg present is in the oxidized form, and a
value of zero indicates that all of the Hg present is in the elemental form. The horizontal
axis in Figure 4.1 represents the location at which the various speciated Hg measurements
were made. The data are grouped by the operating conditions of the SCR as follows: (1)
the SCR was in service with NH3 injected to reduce NOx emissions, (2) the SCR was in
service without NH3 injection, and (3) the SCR was bypassed (i.e., not in service).
Figure 4.1 illustrates that Hg oxidation increases as the flue gas travels through
the system. The fraction of oxidized Hg is greater at the wet FGD inlet than at the SCR
inlet for all given test conditions. The lowest oxidation ratio (0.05) is found at the SCR
inlet, and the highest ratio (0.85) occurs at the wet FGD inlet. This represents a wide
range of oxidation ratios.
98
Figure 4.1
Hg oxidation at baseline conditions (i.e., no CaBr2 addition to the coal) as a
function of the location of Hg concentration measurement and of SCR
operating condition.
The SCR inlet Hg oxidation ratio values range from a minimum of 0.05 to a
maximum of 0.42. A closer inspection of the data used to create Figure 4.1, which can be
found in Appendix A, and reveals that the highest two Hg oxidation ratios (>0.30) at the
SCR inlet were measured during Phase I, when the native bromine concentration in the
coals was the highest. Hg oxidation at the SCR inlet would result from homogeneous and
native particle heterogeneous oxidation. Native particle heterogeneous oxidation
contribution may be small because unburned carbon levels at this plant are below 0.5 wt
99
% as a result of efficient combustion. Bhardwaj et al. (2009) reported that 40 wt % UBC
was needed to achieve 42% Hg oxidation at 150 °C and 50 ppmv HCl.
The oxidation of Hg requires chlorine, bromine, or another halogen, either from
native concentrations in the coal or added via external means. Table 4.1 provides a
summary of the coal chlorine and bromine content as well as other coal summary
information during the three phases.
As Table 4.1 shows, measurable concentrations of bromine were found in the coal
samples during Phase I but not during the other phases. Besides Phase I, the bromine
concentrations reported in the table are the detection limit of the measurement technique
used. The detection limits were used to calculate the Br/Hg ratio (lb/lb), Br/Hg ratio
average and standard deviation. Hence, those values of Br/Hg ratio should be viewed as
generous because the actual bromine level in the coal is probably lower. Gutberlet et al.
(2008) postulated that the Hg oxidation potentials of chlorine and bromine are different
and that on a molar basis, bromine proved 10 times more effective than chlorine at
oxidizing Hg. A calculated molar Cl/Br ratio of 10 would mean a flue gas where
bromine and chlorine have the same oxidative abilities. However, the concentration of
bromine and chlorine found in the coal during this study indicates that baseline Hg
oxidation via chlorine was more likely during Phases IIA, IIB and III since on a molar
basis in the coal, higher concentrations of chlorine are found. During Phase I, baseline
Hg oxidation was more likely to occur from bromine since the Cl/Br molar ratio was less
than 10. The molar ratio of Cl/Br ranged from a low of 6 in Phase I to approximately 30
in Phase IIB and III and a high of 60 in Phase IIA.
100
Table 4.1 Coal Characteristics Summary
Units
Phase
I
Phase
IIA
Phase
IIB
Phase
III
No. of samples
Dimensionless
8
8
6
11
Sulfur average
wt%
0.33
0.35
0.31
0.40
Hg average
wt ppm
0.073
0.051
0.068
0.047
Hg standard deviation
wt ppm
0.021
0.007
0.019
0.013
Cl average
wt ppm
14.50
25.75
13.17
19.55
Cl standard deviation
wt ppm
14.77
8.19
1.72
3.56
a
a
Description
Br average
wt ppm
5.82
<1.0
<1.0
<1.3a
Br standard deviation
wt ppm
1.23
n/a
n/a
n/a
Br/Hg ratio
lb/lb
87.82
20.14b
15.34b
29.42b
Br/Hg standard
deviation
lb/lb
36.29
2.81b
3.13b
8.08
a. detection limit of measurement technique
b. calculated based on detection limit as highest concentration of bromine present
Column 3 Adapted from Table B-8 “The Evaluation of Calcium Bromide for Mercury
Control at Southern Company’s Plant Miller” by Dombrowski, K. et al., 2007 p. B-7.
Copyright 2007 by EPRI. Reprinted with permission.
Column 4 Adapted from Table 33 “The Evaluation of Calcium Bromide for Mercury
Control at Southern Company’s Plant Miller” by Dombrowski, K. et al., 2009 p. 3-51.
Copyright 2009 by EPRI. Reprinted with permission.
Column 5 Adapted from Table B-13 “The Evaluation of Calcium Bromide for Mercury
Control at Southern Company’s Plant Miller” by Dombrowski, K. et al., 2009 p. B-14.
Copyright 2009 by EPRI. Reprinted with permission.
Column 6 Adapted from Table B-14 “Three-Month Evaluation of Furnace Addition of
Calcium Bromide for Mercury Emissions Control at Southern Company’s Plant Miller”
by Dombrowski, K. et al., 2011 p. B-16. Copyright 2011 by Southern Company
Serivces. Reprinted with permission.
101
The fraction of oxidized Hg during baseline conditions indicate that the native halogen
content in the coal was sufficient to support relatively high oxidation of Hg at the wet
FGD inlet (ranged from 0.42 to 0.85). It is unclear if chlorine or bromine or a
combination of both was responsible for the oxidation. It is interesting to note that at the
wet FGD inlet the Hg oxidation ratios were highest when NH3 was not present in the
SCR.
Vosteen et al. (2003) stated that a Br/Hg ratio (lb/lb) of 100:1 was needed to
achieve 100%Hg oxidation with bromine. Table 4.1 includes a calculated value for the
mass ratio of Br to Hg, hereafter referred to as the Br/Hg ratio (lb/lb).
During Phase I, the Br/Hg ratio averaged 87.82, with a standard deviation of
36.29. Therefore, at some point during Phase I, the Br/Hg ratio exceeded 100:1. Vosteen
et al. (2006) did not indicate the precise Br/Hg ratio at which high levels of Hg oxidation
would be observed for specific coals, but the wide range of values provided (100:1 to
10,000:1) might lead to the conclusion that observed Hg oxidation behavior might be
dependent on other factors, as well. During Phases IIA, IIB, and III, the Br/Hg ratios
were well below the 100:1 guidance for achieving high levels of Hg oxidation via
bromine.
The SCR outlet Hg oxidation ratios ranged from a minimum value of 0.17 to a
maximum value of 0.58. The presence of the SCR should increase the fraction of
oxidized Hg present and thereby increase the Hg oxidation ratio. While in service, the
ability of an SCR to affect Hg oxidation will be a function of a number of factors such as
coal chlorine and bromine content, catalyst pitch, space velocity, flue gas temperature,
102
NH3 flow; and catalyst activity. As Figure 4.1 shows, the Hg oxidation ratios do increase
across the SCR, as expected.
As Figure 4.shows, the largest fraction of oxidized Hg was observed at the wet
FGD inlet, when the SCR was in service but without NH3 addition. The range of Hg
oxidation ratios diverge for the SCR with NH3 and for the SCR without NH3. The SCR
without NH3 configuration should provide the best oxidation behavior because the NH3,
oxidant (bromine or chlorine), and Hg all compete for the same active sites on the surface
of the catalyst. He et al. (2009) suggested that, in an SCR, the Hg oxidation occurred via
the Langmuir-Hinshelwood mechanism, as shown in R29–R32. During these reactions,
the Hg and oxidant (bromine or chlorine) adsorb onto an active site on the catalyst
surface. After adsorption is complete, R31 occurs, and the newly formed oxidized Hg is
liberated from the catalyst site to the flue gas. Hong et al. (2010) concluded that NH3
dominantly adsorbs onto the SCR catalyst surface and precludes the optimum absorption
or retention of absorbed Hg on the catalyst surface. Senior and Linjewile (2004)
concluded from an analysis of bench-scale data that Hg oxidation across the SCR
decreased in the presence of NH3. From the literature, one concludes that Hg oxidation
performance should improve when NH3 is not present. Figure 4.1 supports this
conclusion. In fact the Hg oxidation ratio was highest (0.85) at the wet FGD inlet during
baseline conditions when the SCR was in service without NH3 present. Ignoring the
results from the SCR without NH3 test conditions at the wet FGD inlet, during Phase I the
highest fractions of oxidized Hg were achieved at the wet FGD inlet, from 0.56 to 0.67.
This result may indicate an ability of the SCR to aid in the oxidization of Hg at very low
halogen concentrations with the absence of NH3. This result indicates that the SCR may
103
produce chlorine or bromine species (e.g., Cl2, Cl, Br2, and/or Br) that remain active in
Hg oxidation reactions downstream of the SCR.
Figure 4.1 also reveals that Hg oxidation continues downstream of the SCR, and
that, for a given test day, the fraction of oxidized Hg is greater at the ESP inlet than at the
SCR outlet. Hg oxidation continues to occur before the wet FGD inlet, and in some
cases, at substantial levels, that is, 50% of the Hg oxidation happens downstream of the
SCR. Explanations in the literature may provide some insight into this behavior. Fry et
al. (2007) found that, as the flue gas quench rate changed, so did the effectiveness of HCl
as an Hg oxidant. The quench rate describes the flue gas-cooling rate downstream of the
boiler to the cold-side ESP. The quench rate at Miller Unit 4 typifies that of a full-scale
boiler. Fry et al. (2007) concluded that boilers with a typical boiler quench rate (-440
K/s) continued to oxidize Hg until reaching the cold-side ESP temperature. Fry et al.
(2007) concluded from their analysis that the quench rate was important for
homogeneous Hg oxidation by chlorine radicals. Because Hg oxidation continued to
occur downstream of the SCR during all three phases of the research program, completed
under different conditions and at different times, the oxidation behavior can be
considered repeatable and consistent. The two trendlines in Figure 4.1 represent the
impact of the SCR in Hg oxidation with and without an SCR. The steeper line represents
Hg oxidation when NH3 is not present (i.e., more complete oxidation). In both cases,
during baseline conditions, Hg oxidation continues to occur as the flue gas travels
through the system. In the case of an SCR without NH3, the level of Hg oxidation
proceeds to a higher extent.
104
4.2.2
Equipment Configuration Impacts on Baseline Hg Oxidation
The equipment installed and the specific design of that equipment can affect the
ability of a system to promote or inhibit Hg oxidation. For example, the efficiency of the
combustion process can inhibit or enhance the Hg oxidation process. Inefficient
combustion leads to higher concentrations of UBC in the fly ash, which can act as an Hg
oxidation catalytic surface (Niksa et al., 2001).
Additionally, the SCR directly affects the ability of the system to oxidize Hg, as
depicted in Figure 4.1. This effect depends on factors such as coal chlorine and bromine
content, catalyst pitch, space velocity, flue gas temperature, catalyst age, NH3 flow, and
catalyst activity. Table 4.2 provides a summary of the important Unit 4 SCR equipment
design and operational parameters that impact Hg oxidation behavior.
Senior and Linjewile (2004) concluded that SCR space velocity below 2,000 h-1
yielded Hg oxidation values much higher than those values found for SCR space velocity
above 4,000 h-1. As shown in Table 4.2, the SCR at Miller Unit 4 had a space velocity of
1,974 h-1 during Phases I, IIA, and IIB and a space velocity of 1,480 h-1 during Phase III.
This result suggests that the ability of the SCR to aid oxidation was ideal because the
space velocity during all phases remained below the 2,000 h-1 threshold limit suggested
by Senior and Linjewile (2004). From a space velocity perspective, the Unit 4 SCR is
generously designed and will promote Hg oxidation. The literature does not suggest an
ideal space velocity but indicated that lower SCR space velocity (< 2,000 h-1) promotes
Hg oxidation.
Eswaran and Stenger (2008) concluded that catalyst age reduces Hg oxidation
catalyst activity. The exposure hours for the catalyst in service at Unit 4 exceeded the
105
exposure hour experience available in the literature. The most exposed SCR catalyst
tested at bench scale by Eswaran and Stenger (2008) involved only 3,300 h of exposure.
The Unit 4 catalyst had been exposed to flue gas for 13,250 h during the Phase I testing.
During Phase III, three of the four catalyst layers were exposed to flue gas for 27,500 h,
and the fourth layer had 6,000 h of flue gas exposure. The literature provided little
information on the relationship between catalyst age and Hg oxidation but did include
general conclusions that the ability of a catalyst to aid in the oxidation of Hg decreased as
time of catalyst exposure to flue gas increased.
In comparison with catalyst age, relative NOx catalyst activity (K/Ko) may more
accurately measure the ability of a catalyst to oxidize Hg because some flue gases contain
more or fewer contaminants (such as potassium and arsenic) that affect catalyst
performance. The relative NOx catalyst activity shown in Table 4.2 exceeds 0.70 over
the life of the program but did decrease with time, from 0.79 during Phase I to 0.75
during Phases IIA and IIB. By Phase III, the relative catalyst activity of the first two
layers decreased to 0.50, but the addition of the new layer of catalyst with a relative
catalyst activity of 1.0 brought the average relative catalyst activity of the entire SCR to
0.72. The new layer of catalyst brought the total number of layers in the SCR to four.
The change in relative NOx catalyst activity during the research program did not affect
the ability of the system to support Hg oxidation. This conclusion is based solely on the
results of this study because the literature provided no guidance in this matter.
106
Table 4.2 Important Equipment Design and Operating Data Values that
Affect Hg Oxidation
Item
Symbol
Units
Value
Catalyst type
n/a
n/a
Honeycomb
Catalyst pitch
n/a
mm
9.2
SCR normal operating
temperature
T
°C
380
SCR flue gas flow under
standard conditions
V
m3/h
2,700,000
Phase I & II catalyst volume
V
m3
1,368
Phase III catalyst volume
V
m3
1,824
Phase I & II catalyst layers
n/a
n/a
3
Phase III catalyst layers
n/a
n/a
4
Phase I & II SCR space
velocity
SV
h-1
1,974
Phase III SCR space velocity
SV
h-1
1,480
Phase I catalyst age
n/a
h
13,250a
Phase I catalyst activity
!
!!
Dimensionless
0.79c
Phase IIB catalyst age
n/a
h
15,000a
Phase IIB catalyst activity
!
!!
Dimensionless
0.75c
Phase III catalyst age
n/a
h
Phase III catalyst activity
!
!!
27,500a
6,000b
Dimensionless
0.72c
NOx set point
n/a
lb/MBtu
0.1
α
mol/mol
0.9
UBC
wt%
0.40d
Design NOx/NH3 molar ratio
Unburned carbon
a.
b.
c.
d.
Operating hours since catalyst was loaded in 2003.
Operating hours of new 4th layer added in January 2010.
K/K0 is the arithmetic mean of the K/K0 for each layer.
Average of unburned carbon values for all three phases.
107
Designed to operate at 380 °C during full-load conditions (720 MW), the Unit 4
SCR has a minimum continuous operating temperature set point of 310 °C. During
Phases I, IIA, and IIB, the SCR operated mostly at 380 °C (i.e., at full-load conditions).
During Phase III testing, when the boiler was operated normally (i.e., load was allowed to
vary to meet electricity demand), the SCR operated between 380 °C and 310 °C. Hong et
al. (2010) postulated that Hg oxidation was sensitive to SCR operating temperature.
Senior (2006) concluded from data analysis of full-scale operating SCRs, that Hg
oxidation rates across an SCR were higher at 320 °C than at 370 °C. When Hg oxidation
levels resulting from the actual SCR operating temperature used in this study were
compared with those reported in the literature, it was discovered that the Unit 4 SCR
operating temperature does not overly constrain baseline Hg oxidation. Figure 4.1 shows
that the Hg oxidation ratio at the SCR outlet ranged from 0.18 to 0.60. Unfortunately,
speciated Hg measurements were not made at the SCR inlet during Phase III when lower
SCR temperatures were observed. Using the guidance of Senior (2006), one might have
expected higher fractions of oxidized Hg at lower SCR temperatures, however this
possibility was not investigated during the research program.
4.2.3
Effect of SO2 Concentration
The concentration of fuel sulfur is another parameter to consider when evaluating
a system for Hg oxidation performance. Sulfur is converted to SO2 during the
combustion process. During bench-scale testing, SO2 has been shown to negatively
impact the ability of chlorine and bromine compounds to oxidize Hg. Sterling et al.
(2004) showed that SO2 greatly inhibited Hg oxidation by Cl2. In their report, Lighty et
108
al. (2006) stated that increased SO2 concentration, via the Griffin reaction, affected Cl2
based homogeneous Hg oxidation. Buitrago et al. (2010) found in their bench-scale
studies that SO2 could also negatively impact bromine based homogeneous oxidation.
Vosteen et al. (2006) reported that SO2 negligibly affects Hg oxidation when bromine is
the Hg oxidant. The literature does not provide clear guidance for describing
conclusively the effect of SO2 on the heterogeneous oxidation regime.
In terms of sulfur content found in US coals, PRB coals contain some of the
lowest fractions of sulfur (Energy Information Agency, 1993). A review of Table 4.1
shows that the percentage of sulfur in the coal during the research program ranged from
0.27 wt% to 0.56 wt%, with an average value of 0.35 wt%. This average sulfur input into
the combustion process at Unit 4 represents a SO2 flue gas concentration of
approximately 350 ppmv. When the low levels of sulfur in the coal used during this study
and the guidance from Vosteen et al. (2006) are considered, it may be safe to conclude
that the SO2 levels expected at Unit 4 would not adversely impact Hg oxidation when
sufficient levels of bromine are present.
4.2.4
Effect of Flue Gas HBr and HCl Concentration on Baseline Hg Oxidation
In accordance with the baseline coal concentrations of bromine shown in Table
4.1, the expected flue gas concentration of HBr ranged 0.04 to 0.25 ppmv during Phases I
and IIA. Table 4.3 summarizes the baseline concentrations of halogens measured by
Method 26A.
109
Table 4.3 Flue Gas HCl, HBr, Cl2, and Br2 Concentrations During Baseline
Conditions
Compound
Units
Phase I
Phase IIA
Phase IIB
Phase III
HBr
ppmv
<0.08
0.047
not tested
not tested
Br2
ppmv
<0.03
0.003
not tested
not tested
HCl
ppmv
1.08
0.950
not tested
not tested
Cl2
ppmv
2.01
0.012
not tested
not tested
Notes: Concentrations on a dry basis at 3% O2
Column 3 Adapted from Table B-7 “The Evaluation of Calcium Bromide for Mercury
Control at Southern Company’s Plant Miller” by Dombrowski, K. et al., 2007 p. B-6.
Copyright 2007 by EPRI. Reprinted with permission.
Column 4 Adapted from Table B-9 “The Evaluation of Calcium Bromide for Mercury
Control at Southern Company’s Plant Miller” by Dombrowski, K. et al., 2009 p. B-7.
Copyright 2009 by EPRI. Reprinted with permission.
Baseline halogen flue gas concentrations were low and likely insufficient to
support sustained high Hg oxidation rates. Results of the Method 26A performed yielded
low concentrations of HBr, Br2, HCl, and Cl2; however the accuracy of these speciated
measurements remains unknown. Sun et al. (2000) reported that Cl2 measurement and
accuracy in quantifying HX or X2 by using Method 26A are difficult to achieve at Cl2
concentrations <5 ppm. In a broader sense, the total concentration of bromine (HBr and
Br2) and chlorine (HCl and Cl2) is likely the proper context in which to interpret the
information. Even in this broader view, the bromine and chlorine concentrations are low.
The bromine and chlorine compound concentrations reported in Table 4.3 are
lower than those reported in the literature to support high levels of Hg oxidation. For
instance, Silcox et al. (2008) concluded that 50 ppmv of HCl was needed to achieve a
high rate of (>80%) homogeneous based Hg oxidation and that at least 20 ppmv of HBr
would be needed to achieve at least 60% homogeneous oxidation. Additionally, Cao et
110
al. (2008) reported that 3 ppmv HBr produced 80% oxidized Hg in a bench-scale SCR
with PRB simulated flue gas, and Lee et al. (2008) reported that 20 ppmv HCl produced
88% oxidized Hg in a bench-scale reactor under simulated PRB flue gas conditions. The
measured chlorine and bromine flue gas concentrations were at least two orders of
magnitude below those demonstrated in the literature to support high fractions of
oxidized Hg. If the 100:1 Br/Hg ratio (lb/lb) guidance by Vosteen et al. (2003) and the
Phase I coal Hg content are used, approximately 0.35 ppmv of HBr (7.5 wt ppm of Br on
the dry coal) would be needed for full Hg oxidation to occur. The measured HBr
concentration was one order of magnitude below what was required. On the basis of the
literature and the guidance by Vosteen et al. (2003), one should expect Hg oxidation rates
below 90% under all baseline conditions.
4.2.5
Operational Impacts on Hg Oxidation
The operating conditions of a power plant affect its ability to promote or hinder
Hg oxidation. For Phases I, IIA, and IIB, Unit 4 was operated under full-load conditions.
During Phase III, the unit was operated under normal conditions (i.e., the unit responded
to the demand for electricity). Chapter 3 contains a detailed description of all test
conditions.
Figure 4.2 depicts a Box and Whisker Plot of key operational parameters during
Phase I. The plot shows the 25%, 50%, and 75% quartile values (box) for each parameter
of interest, as well as bars (whisker) that indicate the maximum and minimum values of
the dataset. Plots may include data points outside the whiskers that have been labeled as
111
extreme values in the data set as defined by SPSS, the statistical software package used to
generate the plots.
Figure 4.2 Phase I summary Box and Whisker Plot of load (MW), SCR inlet and outlet
temperatures (°C), SCR inlet and outlet NOx concentrations (ppmv), and stack
SO2 concentration (ppmv) used to illustrate consistency or variability of
operating conditions when SCR is in service and with NH3 injection.
Figure 4.2 shows that, for the duration of the Phase I program, operation
conditions were held constant. The operating range, listed in parentheses, was close for
each of the following operational parameters: unit load (702-715 MW), SCR inlet
temperature (364-378 °C), SCR outlet temperature (357-375 °C), SCR inlet NOx (170200 ppmv), and SCR outlet NOx (31-33 ppmv). Stack SO2 did have a wider operating
112
range, but half of the SO2 emissions (75% quartile to 25% quartile) fell between 381
ppmv and 317 ppmv. The consistent operations during this phase limited the impact of
operating conditions on Hg oxidation behavior.
Figure 4.3 is a summary plot of Phase IIA operational data during two separate
testing conditions: when the SCR was bypassed and when the SCR was in service but
without NH3 injection.
Figure 4.3 Phase IIA summary Box and Whisker Plot of load (MW), SCR inlet and outlet
temperatures (°C), SCR outlet NOx concentration (ppmv), and stack SO2
concentration (ppmv) used to illustrate consistency or variability of operating
conditions during periods when SCR is bypassed and when SCR is in service
without NH3 injection.
113
The load during both SCR conditions was above 715 MW 75% of the time, with a few
lower-load conditions occurring outside test periods. SCR inlet NOx information was
unavailable during the test, however because NH3 was not injected during Phase IIA,
inlet NOx concentration would have been identical to the observed range of outlet NOx
concentration, which were 109 to 155 ppmv. SCR inlet and outlet temperatures were
fairly constant during the test program, reaching a maximum value of 380 °C and 375 °C,
respectively. The average SCR temperature during Phase IIA was 362 °C.
The SO2 concentrations generally exceeded those observed during Phase I. With
the SCR bypassed, the 75% quartile concentration was 477 ppmv, and the 25% quartile
concentration was 340 ppmv; the maximum concentration was 631 ppmv. With the SCR
in service, the 75% quartile concentration was 427 ppmv, the 25% quartile concentration
was 328 ppmv; the maximum concentration was 634 ppmv. These SO2 concentrations
may be sufficiently high to impact Hg oxidation via the Griffin reaction. Vosteen et al.
(2006) reported that bromine is affected by SO2 to a lesser extent than chlorine, but
bromine is affected nevertheless. The exact SO2 concentration in which bromine is
adversely affected is not well understood. As the flue gas SO2 concentration increases so
does the risk that the bromine Griffin reaction (R11) will occur. Although outside the
scope of this research, the impact of SO2 concentration on Hg oxidation behavior is of
keen interest and should be investigated further.
Figure 4.4 depicts a summary plot of Phase IIB operating conditions when the
SCR was in service with NH3 injection to control NOx emissions. The figure shows that
for the duration of the Phase IIB program, operation conditions were held fairly constant.
114
The operating range, with minimum and maximum listed in parentheses, was
relatively close for each of the following operational parameters: unit load (699-725
MW), SCR inlet temperature (367-382 °C), SCR outlet temperature (363-377 °C), SCR
inlet NOx (164-208 ppmv), and SCR outlet NOx (24-48 ppmv). The SO2 concentrations
were not available in the plant historian for this period and are not shown.
Figure 4.4 Phase IIB summary Box and Whisker Plot of load (MW), SCR inlet and outlet
temperatures (°C), and SCR inlet and outlet NOx concentrations (ppmv) used
to illustrate consistency or variability of operating conditions during a period
when SCR was in service with NH3 injection.
Figure 4.5 is a Box and Whisker summary plot of operating conditions during
Phase III, when Unit 4 was operated normally (i.e., operated to meet electricity demand).
115
Because the load was not held constant, Figure 4.5 reveals a much wider load-operating
window and the data also include a shutdown and start-up event.
Figure 4.5 Phase III summary Box and Whisker Plot of load (MW), SCR inlet and outlet
temperatures (°C), SCR inlet and outlet NOx concentrations (ppmv), wet FGD
inlet SO2, and outlet SO2 concentrations (ppmv) used to illustrate consistency
or variability of operating conditions during a period when SCR was in
service with NH3 injection.
The SCR inlet and outlet full-load operating temperature ranges (i.e., 75% and 25%
quartiles) were of the magnitude seen in the earlier phases (i.e., SCR inlet 355 to 365 °C
and SCR outlet 351 to 361 °C). The SCR did experience lower temperatures during
periods of lower load and reached a temperature of 310 ºC during those periods.
116
According to Senior (2006), the lower operating temperature should support higher Hg
oxidation. The inlet wet FGD SO2 concentrations during Phase III were the lowest
observed during the research program, with a 75% quartile concentration of 213 ppmv, a
25% quartile concentration of 171 ppmv, and a maximum observed concentration of 357
ppmv. The lower SO2 concentration should lessen the impact, via the Griffin reaction, on
Hg oxidation behavior if in case impact to Hg oxidation occurred at the higher
concentrations of SO2. In terms of SO2 concentration, Phase III conditions are ideal to
support Hg oxidation. An examination of the SCR data revealed that average outlet NOx
emission levels were slightly higher than those found for Phase I. The NOx relative
catalyst activity (K/Ko) was highest (0.79) during Phase I and lowest (0.72) during Phase
III. During Phase I, the average outlet NOx emissions were 32 ppmv, with an average
inlet concentration of 182 ppmv (82% removal efficiency). During Phase III, the average
outlet NOx emissions reached 40 ppmv, while the average inlet NOx emissions were 167
ppmv (76% removal efficiency). These values suggest that NOx removal efficiency
decreased between the two phases, which may also imply a slightly less effective SCR
for supporting Hg oxidation.
4.2.6
Summary
An analysis of baseline data did not support the hypothesis that Hg oxidation
levels would be observed below 50% under all conditions. It is possible to attain baseline
Hg oxidation rates above 50% while burning PRB coal at Plant Miller Unit 4. In fact, at
the wet FGD inlet, a majority (i.e., >50%) of the Hg found during the various test periods
was oxidized (see Figure 4.1). A thorough analysis determined that several elements of
117
the Miller Unit 4 system promote Hg oxidation. In addition to showing that the
hypothesis was incorrect, the analysis led to the following generalizations:
•
The halogen content of the coal was highlighted as inadequate to support
complete Hg oxidation. The addition of halogens to the coal before
combustion could correct this deficiency.
•
During all three phases, Hg oxidation continued to occur downstream of the
SCR.
•
The hours of Unit 4 SCR catalyst exposure to flue gas and the effect of these
hours of exposure on Hg oxidation were outside what was investigated and
documented in the literature. By Phase III, the first three layers of catalyst had
been exposed to flue gas for more than 27,000 h, but an addition of a new
catalyst layer before Phase III may have mitigated any impact on Hg
oxidation.
•
Based on current technical understanding, Unit 4 SCR space velocity of
<2000 h-1 is ideal for promoting Hg oxidation.
•
The NOx relative catalyst activity (K/Ko) decreased slightly during the
program, from 0.79 at the start of Phase I to 0.72 at the start of Phase III and
this decrease may slightly impact the ability of the SCR to promote Hg
oxidation.
•
The SCR design operating temperature (380 °C) did not adversely impact Hg
oxidation across the SCR. It is anticipated that lower SCR temperatures
would improve baseline Hg oxidation behavior.
118
Examining baseline Hg oxidation behavior, enabled the development of an understanding
of ability of the system to promote Hg oxidation. Table 4.4 provides a qualitative
overview of the ability of Plant Miller Unit 4 to promote Hg oxidation.
Table 4.4 Qualitative Summary of Miller Unit 4 Ability to Support Hg Oxidation
Topic of Interest
Favorable for
Hg Oxidation
Description
Fuel sulfur
Yes
Griffin reaction impact is low
because of low flue gas SO2
concentrations.
Coal halogen
No
Low concentration of bromine and
chlorine.
SCR operating
temperature
SCR catalyst design
Relative NOx
catalyst activity
Neutral
Yes
Neutral
Maximum operating SCR
temperatures are below 380 ºC.
Pitch of 9.2 mm supports Hg
oxidation.
Maintained K/K0 above 0.7, which is
sufficient to support Hg oxidation.
SCR space velocity
Yes
Space velocity < 2,000 h-1 has been
shown to promote Hg oxidation.
Catalyst age
No
SCR reactor contains catalyst with
extended exposure to flue gas.
Yes
Data supports the continued
occurrence of Hg oxidation
downstream of SCR and before wet
FGD.
Quench rate
Unburned carbon
Neutral
Efficient combustion keeps unburned
carbon levels below 0.5 wt%
(UBC/fly ash).
119
4.3
Hypothesis 2: Sufficient CaBr2 Addition at a Unit Burning PRB Coal Results in
Hg Oxidation Levels in Excess of 90%
Under the best scenario during baseline conditions, the Hg oxidation ratio did not
reach 0.90 (i.e., 90% Hg oxidation). As Table 4.4 indicates, Miller Unit 4 has a number
of characteristics that promote Hg oxidation. One major deficiency found related to the
low concentrations of bromine and chlorine in the coal. The addition of either would
likely address that particular deficiency. During the research program, CaBr2 was added
to the coal at various rates, and speciated Hg measurements were made at various
locations in the flue gas stream to determine whether the elemental Hg could be
converted to oxidize Hg by addition of bromine.
4.3.1
CaBr2 Addition Rate Strategy
CaBr2 addition rates were chosen at random to determine the dose-response of Hg
oxidation. Phase I involved varying CaBr2 addition rates to achieve Br concentrations
from 2 to 328 wt ppm on the dry coal (calculation procedures to determine Br
concentration can be found in Chapter 3). The goal consisted of determining the Hg
oxidation behavior as a function of Br concentration. Placing the SCR in and out of
service enabled determination of the effect of the SCR on Hg oxidation behavior after the
addition of CaBr2. During Phase IIA, research protocol included a short replication of
Phase I and operation of the unit for a longer period at 25 and 50 wt ppm Br
concentrations (on the dry coal) with the SCR in service without NH3 injection. During
Phase IIB, Br concentrations of 17 and 25 wt ppm (on the dry coal) were investigated
with the SCR in service with NH3 injection.
120
This section contains analyses of data from Phases I, IIA and IIB. These analyses
were undertaken to determine the behavior of elemental Hg in the presence of different
Br concentrations (wt ppm on the dry coal).
4.3.1.1 Impact of Br/Hg Injection Ratio on Hg Oxidation
Table 4.5 was constructed from the combination of Br coal concentrations, results
from Hg coal analyses, and wet FGD inlet Hg speciation measurements. Table 4.5
provides insight into the proper Br/Hg ratio needed to achieve Hg oxidation rates above
90% with the use of PRB coal.
As the information in Table 4.5 indicates, the Br/Hg ratio needed to obtain high
fractions of oxidized Hg depends on the availability of an SCR. At Br/Hg ratios below
1,200, the Hg oxidation ratio was less than 0.60 at the SCR inlet. Upstream of the SCR
inlet, homogeneous oxidation is the dominant oxidation mechanism. In the case of
homogeneous oxidation, achieving Hg oxidation rates above 90% requires more available
bromine. As the Br/Hg ratio continues to increase, the Hg oxidation ratio at the SCR inlet
increases. In the case of SCR bypassed, the Hg oxidation ratio at the economizer exit
nears unity once the Br/Hg ratio reaches 3,000.
Hg oxidation continues to occur downstream of the SCR. This continued
oxidation should be considered during the determination of the optimal Br/Hg ratio for
use in the absence of an SCR. Table 4.5 lists four Hg oxidation ratios at the wet FGD
inlet when the SCR was bypassed. At the lowest Br/Hg ratio of 652, the Hg oxidation
ratio did not reach 0.90. The table lists three wet FGD inlet Hg oxidation ratios >0.9
when the SCR was bypassed.
121
Table 4.5 Summary of Hg Oxidation Ratios as a Function of Br/Hg Ratio
Hg in
Coal
(wt ppm)
Br
Concentration
(wt ppm)
Br/Hg
Ratio
(lb/lb)
SCR Inlet
Hg Oxidation
Ratio
Coxidized/CTotal
Wet FGD
Inlet
Hg Oxidation
Ratio
Coxidized/CTotal
SCR
in
Service
0.059
3
51
0.27
0.86
Yes
0.091
7
77
0.18
0.92
Yes
0.058
6
103
0.07
Not measured
Yes
0.105
25
238
Not measured
0.98
Yes
0.057
18
316
0.41
0.89
Yes
0.070
25
357
Not measured
0.97
Yes
0.085
33
388
0.47
0.94
Yes
0.054
25
463
Not measured
0.97
Yes
0.045
25
556
Not measured
0.83
Yes
0.046
30
652
Not measured
0.70
No
0.057
50
877
Not measured
0.99
Yes
0.080
84
1,050
0.57
0.96
Yes
0.045
50
1,111
Not measured
0.96
Yes
0.060
71
1,183
0.55
0.91
No
0.056
165
2,946
0.98
0.93
No
0.107
328
3,065
0.96
0.95
No
Adapted from Tables 6 and B-8 “The Evaluation of Calcium Bromide for Mercury
Control at Southern Company’s Plant Miller” by Dombrowski, K. et al., 2007 p. 2-9 and
B-7. Copyright 2007 by EPRI. Reprinted with permission.
Adapted from Tables 7 and 33 “The Evaluation of Calcium Bromide for Mercury Control
at Southern Company’s Plant Miller” by Dombrowski, K. et al., 2009 p. 2-8 and 3-51.
Copyright 2009 by EPRI. Reprinted with permission.
Adapted from Tables 6 and B-13 “The Evaluation of Calcium Bromide for Mercury
Control at Southern Company’s Plant Miller” by Dombrowski, K. et al., 2009 p. 2-7 and
B-14. Copyright 2009 by EPRI. Reprinted with permission.
122
The data suggest that, with a Br/Hg ratio of 1,183, oxidized Hg fractions above 0.9 at the
wet FGD inlet are plausible. The figure also shows that without an SCR at a Br/Hg ratio
(lb/lb) of 1,100 that at the wet FGD inlet the Hg oxidation ratio is above 0.9. Hg
continues to oxidize downstream of the SCR and reaches the desired 0.9 oxidized Hg
fraction goal. One could recommend a Br/Hg ratio (lb/lb) of only 1,100 or greater to
attain full oxidation but would be doing so with some risk. Without a more fundamental
technical understanding of this behavior it is likely too risky to make such a
recommendation. Future scientific work to better understand this phenomenon could
result in the reduction of bromine injected to achieve the same level of oxidized Hg. In
an effort to reduce risk, taking a more conservative viewpoint would involve requiring an
oxidized Hg fraction above 0.90 at the SCR inlet. Using this constraint and the available
data resulted in a suggested minimum Br/Hg ratio of 2,946.
When an SCR is present, Hg oxidation behavior changes. In this case,
heterogeneous oxidation is the dominant mechanism of Hg oxidation. The lowest Br/Hg
ratio in Table 4.5, with a value of 51, resulted in an Hg oxidation ratio of 0.86 at the wet
FGD inlet, which is slightly lower than the 0.9 goal. Once the Br/Hg ratio exceeded 100,
the corresponding Hg oxidation ratios at the wet FGD inlet were above 0.9. The data
support the assertion by Vosteen et al. (2003) that high rates of Hg oxidation necessitate a
Br/Hg ratio of 100:1. Based on the data in Table 4.5, a conservative Br/Hg ratio > 250 is
recommended for a unit firing PRB coal with a well designed and maintained SCR.
For a unit burning PRB coal, guidance is provided in Table 4.6 for achieving a Hg
oxidation ratio > 0.9 at the inlet of a wet FGD.
123
Table 4.6 Guidance on Br/Hg Ratio to Achieve Oxidation Ratios Greater
Than 0.9 While Firing PRB Coal as a Function of SCR Status
Equipment Configuration
Recommended Br/Hg Ratio
With SCR
>250
No SCR available / SCR bypassed
>3,000
Figure 4.6 graphically represents the Hg oxidation ratio and its relationship to
Br/Hg ratio. The figure groups the data by SCR operating condition, with a transparent
yellow box surrounding the Br/Hg ratios when the SCR was bypassed (i.e., not in
service).
Figure 4.6 Hg oxidation ratio versus Br/Hg ratio (lb/lb) with and without the SCR in
service. Figure was developed with the use of data from Phases I, IIA, and
IIB.
124
When the Br/Hg ratio reaches 3,000 the Hg oxidation ratios converge at the SCR
inlet and the wet FGD inlet; that is, the SCR bypassed Hg oxidation ratio equals the SCR
Hg oxidation ratio at the wet FGD inlet.
4.3.2
Heterogeneous versus Homogeneous Oxidation
The SCR plays a vital role in the oxidation of Hg with the use of CaBr2 as a coal
chemical amendment to raise the halogen content of the flue gas. The earlier analysis of
baseline Hg oxidation behavior demonstrated that the Miller Unit 4 SCR is well designed
for promoting the oxidation of Hg. Figure 4.7 illustrates the oxidation behavior with
various Br concentrations (wt ppm on the dry coal) when the SCR was in service and
with NH3 injection for the control of NOx. The figure shows that the Hg oxidation ratio
increases at the SCR inlet as the Br concentration in the coal increases. Situated just
downstream of the economizer exit, the SCR inlet represents the location at which
homogeneous oxidation is the main oxidation pathway. In laboratory studies, Otten et al.
(2011) achieved Hg oxidation ratios greater than 0.8 solely with homogeneous oxidation
with HBr. Theoretically, a Br concentration of 328 wt ppm in the dry coal yields 12
ppmv (dry at 3% O2) of HBr on Miller Unit 4. Silcox et al. (2008) and Otten et al. (2011)
reported oxidation ratios below 0.80 with 12 ppmv HBr concentration. Figure 4.6 shows
that a Br concentration of 328 wt ppm on the dry coal, the Hg oxidation ratio at the wet
FGD inlet was near one. Since Silcox et al. (2008) and Otten et al. (2011) both excluded
particles from their experiments; the difference from the laboratory and Unit 4 results
may be attributed to their exclusion of native heterogeneous oxidation. Cao et al. (2008)
125
in experiments that included heterogeneous oxidation via SCR catalyst, reported that 3
ppmv HBr produced 0.8 fraction of oxidized Hg with PRB simulated flue gas.
Figure 4.7 Hg oxidation ratio versus Br concentration (wt ppm on the dry coal) with SCR
in service with NH3 injection to control NOx.
At low Br concentrations in the dry coal (2 to17 wt ppm), the Hg oxidation ratio
at the SCR outlet exceeds 0.90. This demonstrates that heterogeneous Hg oxidation
efficiency, fraction of Hg oxidized by available halogen, surpasses homogeneous
oxidation efficiency. Similar fractions of oxidized Hg can be achieved via both reaction
pathways, but high Hg oxidation fractions are achievable via CaBr2 addition through
heterogeneous oxidation with low concentrations of bromine.
126
At Br concentrations greater than 150 wt ppm in the dry coal, the Hg oxidation
ratio appears to decrease across the SCR. This relationship may imply a Br concentration
exists to support the reduction of Hg within the SCR. Figure 4.7 shows that, at a Br
concentration of 328 wt ppm in the dry coal, the Hg oxidation ratio decreases from 0.96
at the SCR inlet to 0.79 at the SCR outlet. In this case, the Hg oxidation ratio increases to
0.95 due to further Hg oxidation downstream of the SCR. This potential phenomenon
has not been discussed in the literature and may warrant further investigation. Similar
behavior was observed at a Br concentration of 165 wt ppm on the dry coal but to a lower
extent.
4.3.2.1 Role of NH3 in SCR Oxidation Behavior
Dranga et al. (2012) studied the impact of NH3 on Hg oxidation in an SCR.
Dranga et al. (2012) concluded that NH3 preferentially adsorbs to the active vanadia sites
and precludes the adsorption of bromine and Hg on those same sites for R13, R14, and
R15 to occur. Figure 4.8 shows a plot of wet FGD inlet Hg oxidation ratio versus Br
concentration in the dry coal when the SCR was in service with and without NH3. The
solid black trendline represents a power series data fit to the Hg oxidation ratio values in
the absence of NH3. The dotted black trendline represents a power series data fit to the
Hg oxidation ratio values in the presence of NH3.
There is a small difference in the magnitude of Hg oxidation ratios at a given Br
concentration in the dry coal; although the similar slopes suggest an identical response in
Hg oxidation for a corresponding increase in Br concentration. Additionally, the
127
trendlines show that for the SCR with NH3 case, to achieve the same fraction of oxidation
for a given Hg oxidation ratio, a higher Br concentration is required.
Figure 4.8 Hg oxidation ratio versus Br concentration (wt ppm in the dry coal) at the
wet FGD inlet as a function of SCR operational status.
For example, Figure 4.8 includes a solid blue line representing an Hg oxidation
ratio of 0.94. The figure shows that for both cases, SCR with and without NH3, both
achieve this fraction of Hg oxidation, but they do so at different Br concentration (wt
ppm on the dry coal). Figure 4.8 illustrates the adverse effect of NH3 on Hg oxidation
can be countered by increasing the bromine concentration. Using the power fit equations
in Figure 4.8, the Br concentration to achieve a Hg oxidation ratio of 0.94 (i.e.,
128
intersecting the blue line) was 50 wt ppm on the dry coal for the SCR with NH3 case and
16 wt ppm on the dry coal for the SCR without NH3.
The results may also suggest that, to promote Hg oxidation, a higher relative
catalytic (K/Ko) NOx activity is required. The higher relative catalytic (K/Ko) NOx
activity will allow a faster consumption of NH3. Once enough NH3 has been consumed
in reactions R16, R17, R18 and R19, the remaining active vanadia sites in the SCR are
available for Hg oxidation reactions. Figure 4.9 provides a set of Hg oxidation scenarios
in the case of various relative NOx catalytic activity (K/K0) values (1.0, 0.7, and 0.5).
Figure 4.9, although not based on data, provides a possible explanation of the role
NH3 plays in Hg oxidation with an SCR. Using the figure to describe possible behavior
results in the following scenario: when K/Ko equals 1.0, NH3 is consumed fairly quickly
within the SCR; as a result, over half (0.5) of the catalyst is available to support Hg
oxidation reactions, represented by Point A in the left diagram of Figure 4.9. Point A
represents the largest extent of Hg oxidation. The Hg oxidation does not begin to occur
in earnest until the NH3 concentration drops below some level. The SCR depth
remaining to support Hg oxidation is represented by a depth scale at the extreme right of
the figure.
When K/Ko is reduced to 0.7, the outlet NH3 concentration remains the same,
represented by Point a in the center diagram of Figure 4.9; however, only 30% of the
reactor remains to support Hg oxidation reactions. Hg is oxidized but to a lower extent,
represented by Point B in the middle diagram of Figure 4.9. In the middle diagram of
Figure 4.9, Point B is close to Point A; therefore, little change in Hg oxidation is
observed. When K/Ko is reduced to 0.5, outlet NH3 concentration remains the same,
129
represented again by Point a in the right diagram of Figure 4.9; however now only 10%
of the reactor remains to support Hg oxidation. Outlet NH3 concentrations remain the
same, represented by Point a; however, Hg is oxidized but to a much lower extent,
represented by Point C in the right diagram of Figure 4.9.
Figure 4.9
Illustration of NH3 consumption and its effect on Hg oxidation behavior in
an SCR.
Because relative NOx catalyst activity in the Miller Unit 4 SCR remains relatively
high (K/K0=0.7), a slight difference in Hg oxidation ratio with and without NH3 present
seems plausible. More research is needed regarding the relationship among NOx relative
catalyst activities (K/Ko) and Hg oxidation. The results of such research would aid in
developing catalyst management plans that account for optimizing both NOx removal and
Hg oxidation.
130
4.3.3
Summary
Hypothesis 2 was proven to be correct. CaBr2 addition promoted Hg oxidation
levels in excess of 90%. In addition to proving the hypothesis, the analysis of the data
supports the following generalizations:
•
The presence of an SCR increased the efficiency of CaBr2. With a well
designed and operating SCR in service, a ten fold-reduction in CaBr2 additive
was observed to achieve bypassed SCR Hg oxidation levels.
•
A Br/Hg ratio above 3,000:1 (lb/lb) is needed when an SCR is bypassed/not
available, but that Br/Hg ratio can be reduced to 250:1 (lb/lb) when a welldesigned and maintained SCR is available.
•
The relative NOx catalytic activity (K/K0) plays an active role in the level of
optimization that can be achieved with an SCR present. As the relative NOx
catalytic activity ratio, K/Ko, decreases, more CaBr2 will be needed to
compensate for less active catalyst.
•
CaBr2 addition systems should be designed to compensate for catalyst
degradation and should accommodate the ability to inject based on a Br/Hg
ratio of 250:1 (lb/lb) under optimum conditions and on a Br/Hg ratio of
3,000:1 (lb/lb) when the SCR is bypassed or when the SCR catalyst is
seriously degraded.
131
4.4
Hypothesis 3: CaBr2 Addition Can Result in Hg Capture Efficiencies Exceeding
90% When a Wet FGD System Is Present
4.4.1
Wet FGD Hg Removal Efficiency
Testing this hypothesis involved analyzing data from Phases IIA and IIB. Data
from Phase I were excluded because a wet FGD was not installed during that test
program, and Phase III data were excluded because that phase did not include measuring
the Hg concentration entering the wet FGD.
Figure 4.10 graphically represents observed Hg removal across the 2 MW pilot
wet FGD versus the Br concentration (wt ppm in the dry coal) and was created with the
use of data provided in Table 4.7. The data are plotted in three separate series on the
basis of the SCR operating condition: SCR in service with NH3 injection, SCR in service
without NH3 injection, and SCR bypassed. Figure 4.10 includes a solid line that
represents 90% removal across the wet FGD. Data obtained during baseline and CaBr2
addition are shown for relative comparison. For the basis of testing the hypothesis, any
native removal of Hg upstream of the wet FGD is ignored.
Without CaBr2 addition to the coal (i.e., baseline conditions), in all cases the Hg
removal efficiencies were less than 90%. The baseline removals of Hg are sensitive to
SCR condition (in service or bypassed). Based on the analysis of the baseline Hg
oxidation behavior as discussed earlier, these lower rates of Hg removal were expected.
During baseline conditions, the highest Hg removal efficiency of (85% removal, occurred
with SCR in service but without NH3. The absence of NH3 provides the largest volume
of available catalyst surface to aid Hg oxidation reactions. During the other two
conditions, SCR in service with NH3 and SCR bypassed, the baseline Hg removals were
132
below 60%. The baseline tests demonstrated the inability of the system to reach Hg
emission removal rates above 90%.
Figure 4.10 Total Hg removal across a 2 MW pilot-scale wet FGD as a function of Br
concentration (wt ppm on the dry coal) and SCR operational condition.
The Hg removal observed with the SCR bypassed related strongly to the Br
concentration (wt ppm in the dry coal). The SCR bypassed condition presents a difficult
scenario for Hg oxidation because all of the bromine enhancement occurs in the gas (i.e.,
homogeneous oxidation). With the SCR bypassed, Hg removal progresses from 40% at a
Br concentration of 30 wt ppm on the dry coal to 86% at 90 wt ppm Br concentration on
the dry coal to a maximum value of 98% at 234 wt ppm Br concentration on the dry coal.
133
Table 4.7 Hg Oxidation and Removal Information Collected During Phases IIA
and IIB.
Phase
IIB
IIB
IIB
IIB
IIB
IIB
IIB
IIB
IIB
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
IIA
SCR
Equipment
Setup
Br
Concentration
(wt ppm)
A
A
A
A
A
A
A
A
A
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
C
C
C
C
C
C
C
C
0
0
0
17
17
17
25
25
25
0
0
0
2
25
25
25
25
25
25
25
28
50
50
50
50
54
0
0
0
0
0
30
90
234
Hg
Oxidation
Ratio at
wet FGD
Inlet
(Coxidized
/Ctotal)
0.30
0.42
0.46
0.92
0.97
0.95
0.98
0.97
0.98
0.81
0.66
0.85
0.95
0.87
0.83
0.92
0.92
0.97
0.97
0.97
0.99
0.98
0.99
0.99
0.96
0.96
0.46
0.34
0.55
0.51
0.38
0.70
0.88
0.97
Wet FGD
Hg Removal
(CinletCoutlet)/Cinlet)
Reemission
Parameter
Hg SCEM
Averaging
Time
(h)
0.30
0.47
0.41
0.77
0.91
0.91
0.92
0.86
0.94
0.79
0.70
0.85
0.88
0.90
0.93
0.94
0.93
0.92
0.92
0.93
0.97
0.93
0.94
0.95
No value
0.94
0.54
0.27
0.50
0.23
0.19
0.40
0.86
0.98
1.00
1.11
0.88
0.84
0.94
0.95
0.94
0.89
0.97
0.97
1.06
0.99
0.92
1.04
1.12
1.03
1.01
0.95
0.94
0.97
0.98
0.95
0.95
0.96
No value
0.98
1.16
0.81
0.92
0.45
0.50
0.57
0.98
1.01
9.00
9.00
9.00
11.75
24.00
12.00
24.00
24.00
24.00
6.00
5.00
6.00
1.50
12.00
24.00
24.00
24.00
24.00
24.00
12.00
3.00
9.00
24.00
24.00
12.00
3.00
8.50
10.00
10.00
7.25
7.00
3.00
4.30
5.00
A = SCR with NH3; B = SCR with no NH3; C = No SCR. SCEM – Hg Semicontinous
Emission Monitor
Reemission parameter is a measure of the likelihood that an Hg reemission event occurred
during a particular test; a value below 1 indicates that a reemission event may have occurred.
134
These results demonstrate that, without the presence of an SCR, Hg removal
efficiencies can exceed 90%. With the SCR in service and without NH3 injection, the Hg
removal efficiency surpassed 90% once the Br concentration reached 25 wt ppm on the
dry coal. Additionally, a Br concentration of 50 wt ppm on the dry coal provided
removal efficiencies greater than 90%.
The Hg removal results described here, in the absence of NH3 in the SCR, support
the assertions of Dragna et al. (2012) that NH3 impacts Hg oxidation. However, because
of regulatory constraints, Unit 4 will operate a vast majority of the time with the SCR in
service and with NH3 injection for the control of NOx emissions. This fact makes
analysis of the SCR with NH3 injection configuration the most applicable from the
standpoint of Hg removal performance. A review of Table 4.7 and Figure 4.10 reveals
only six discrete data points related to the configuration of SCR with NH3 injection. The
data do show that, for this equipment configuration, the observed Hg removed exceeded
90% once the Br concentration reached 17 wt ppm on the dry coal. Of the six data points
available for this configuration, four exceeded 90% removal, and one was near 90%.
The data provided during Phases IIA and IIB testing support the conclusion that
CaBr2 addition to the coal can support Hg removal efficiencies greater than 90%.
4.4.2
Evaluation of Hg Reemission
Hg reemission occurs when elemental Hg emissions leaving the wet FGD exceed
wet FGD inlet elemental Hg emissions. This condition can only occur if Hg present (i.e.,
dissolved in solution) or adsorbed to a solid particle is reduced from the soluble form
(oxidized Hg) to the insoluble form (elemental Hg).
135
To quickly evaluate whether a reemission had occurred during the Phases IIA and
IIB research programs, a numerical value, called the reemission parameter (RP) was
calculated. Equation 2 is used to calculate the RP.
RP = wet FGD Hg Removal/Hg Oxidation Ratio
(E2)
RP < 1 indicates possible Hg reemission from the wet FGD; that is, the amount of
Hg removal observed is less than the amount of oxidized Hg available for removal.
RP = 1 signifies that Hg reemission has not been observed; in other words, the Hg
removal observed equals the amount of available oxidized Hg. Last, RP > 1 indicates
that observed Hg removal exceeds the amount of available oxidized Hg, indicating some
removal of elemental Hg across the wet FGD.
Table 4.7 contains summary information on the Br concentration (wt ppm on the
dry coal), Hg oxidation ratio at the wet FGD inlet, observed Hg removal across the wet
FGD, and calculated value of the RP. In addition to this performance information, Table
4.7 contains information about the test period duration, which defines the averaging
period for the Hg measurement, and about the SCR operating condition.
A majority of the RP values are close to 1, indicating that reemission events did
not happen frequently during the test program. A few data points have RP values much
less than 1. RP values less than 0.9 may indicate a strong likelihood that a reemission
event occurred. A closer examination of Table 4.6 reveals that the lowest RP values
occurred when the SCR was out of service. Additionally, the RP values were lowest
when the halogen concentration was lowest (e.g., without the addition of CaBr2 to the
136
coal or with a Br concentration of 30 wt ppm on the dry coal). This result may indicate
that higher NOx emissions adversely affect the wet FGD chemistry or that a lack of
halogen in the wet FGD results in a higher percentage of Hg reemissions. This behavior
will be discussed in more detail later in this section.
Figure 4.11 graphically represents the data provided in Table 4.7. The figure
shows wet FGD Hg removal ratio plotted against the Hg oxidation ratio for a given data
point. Ideally, all of the oxidized Hg is captured in the wet FGD; that is, fraction of Hg
captured equals the fraction of oxidized Hg. If all oxidized Hg is removed, the respective
data point in Figure 4.11 will intersect the 45-degree line. If a data point falls below the
line, the Hg removal is below ideal and Hg was reemitted from the wet FGD slurry. If a
data point is above the line, removal exceeds the amount of oxidized Hg present. Taking
a reasonable measurement error (i.e., +/- 10%) into account, some of the data points
might be located a small distance from the ideal condition (i.e., slightly above or below
the line). Data points an extended distance away from the 45-degree line warrant close
examination to better understand if Hg reemissions are indeed responsible for non-ideal
removal behavior.
Figure 4.11 also includes a vertical and horizontal dotted lines located at 0.9 that
represent 90% Hg oxidation and removal, respectively. A data point located above the
horizontal line represents the achievement of 90% Hg removal, and a data point to the
right of the vertical line indicates the achievement of 90% or greater Hg oxidation. Data
points in the top right corner of Figure 4.11, within the light-green box, show the
occurrence of both greater than 90% oxidation and 90% removal.
137
Figure 4.11 Wet FGD Hg removal versus Hg oxidation ratio for differing SCR reactor
operational conditions during Phase IIA and Phase IIB. A marker below the
45-degree line represents lower-than-expected Hg removal, and a marker
above the 45-degree line represents better-than-expected Hg removal. A
marker to the right of the vertical line represents 90% oxidation. A marker
above the horizontal line represents 90% removal in the wet FGD. A marker
within the green box represents at least 90% Hg oxidation and 90% Hg
removal.
The three points farthest away from the ideal condition (RP = 0.45, 0.5, and 0.57)
occurred during Phase IIA when the SCR was not in service and when the Br
concentration was low (i.e., under baseline conditions without CaBr2 addition and when
the Br concentration was 30 wt ppm on the dry coal). All three data points represent low
levels of Hg oxidation but also represent instances with the lowest Br concentration in the
wet FGD sump. The other two lowest RP values (RP = 0.84 and 0.88) occurred during
Phase IIB when the SCR was in service with NH3 injection but with low Br
concentrations (wt ppm on the dry coal). Because all five potential reemission events
138
occurred during low levels of Br concentration in the system (i.e., in the flue gas and,
more important, in the wet FGD sump), bromine in the wet FGD sump may assist the
system in lowering the impact of Hg reemission.
During Phases IIA and IIB, CaBr2 was spiked into the 2 MW wet FGD sump to
replicate higher bromine concentrations in the wet FGD slurry. During Phase IIA, wet
FGD slurry bromine concentrations of less then 200 ppm, greater than 1,300 ppm, and
greater than 2,500 ppm were investigated; Phase IIB involved investigating wet FGD
slurry bromine concentrations of less than 50 ppm and greater than 1,800 ppm. Each of
the highlighted potential Hg reemission events occurred when the wet FGD slurry
bromine concentrations were lowest (i.e., below 200 ppm during Phase IIA and below 50
ppm during Phase IIB).
4.4.3
Insights Into the Occurrence of Reemission
An examination of the operational information collected during Phases IIA and
IIB provided insights into Hg reemission events or nonevents occurring during the
research program. Figure 4.12, which shows operational parameters associated with wet
FGD Hg reemission events, was developed from observations in the literature and from
the test data gathered during Phases IIA and IIB. The figure illustrates that Hg
reemission is a function of wet FGD slurry characteristics such as suspended solids Hg
concentration, liquor Hg concentration, sulfite concentration, combined chlorine and
bromine concentration, and oxidation reduction potential (ORP). The combination of Hg
concentration in the suspended solids and the slurry liquor represents the Hg available for
reemission. The concentrations of chlorine, bromine and sulfites in the slurry are the
139
compounds known to form stable Hg complexes, which have a lower potential for Hg
reemissions. The ORP measures the oxidation health of the wet FGD and expresses the
likelihood for the scrubber to reduce (i.e., emit or precipitate Hg) or maintain oxidation
(i.e., keep Hg in solution). Figure 4.12 is hereafter referred to as the Hg reemission
probability diagram.
Figure 4.12 is a pentagon with an axis for each parameter that affects the
probability that an Hg reemission event will occur. The green circle at the center of the
diagram represents operational conditions with a low likelihood of Hg reemission. Each
parameter has its own axis and is represented equally (i.e., axis lengths are the same)
because it is not currently known which parameter might dominate the occurrence or
nonoccurrence of a reemission event. For example, sulfite concentration, measured in
millimolar per liter (mM), increases the probability of occurrence of a reemission event
as concentration decreases. Omine et al. (2012) reported that, in bench-scale test, no
reemission was observed at 9 mM of sulfite, and that reemission events became more
prevalent when sulfite concentrations were below 2 mM.
Blythe et al. (2008) and Omine et al. (2012) observed that the presence of
halogens in the liquid reduced the probability of a reemissions event. Omine et al. (2012)
found that 2,000 mg/L (ppm) of chlorine or bromine was effective at reducing Hg
reemission events. Omnie et al. (2012) also concluded that, at similar concentrations,
bromine was more effective than chlorine at reducing Hg reemission events.
140
Figure 4.12 Wet FGD Hg Reemission Probability Diagram. Diagram demonstrates
visually that the probability of reemitting Hg from a wet FGD sump is a
function of slurry bromine and chlorine concentration, sulfite concentration,
oxidation reduction potential, Hg concentration in solution, and Hg
concentration in the total suspended solids.
The likelihood of an Hg reemission event significantly decreases if Hg is not
dissolved in the wet FGD slurry solution. In that sense, a 0 µg/L concentration of Hg in
the slurry solution is the best scenario, that is, as the concentration of Hg in solution
increases, so does the potential for an impactful reemission event to occur. Additionally,
the concentration of Hg in the suspended solids represents a potential reemission source,
141
although a much less probable one than Hg dissolved in the wet FGD slurry solution
constitutes.
ORP represents the oxidation health of the scrubber and high values indicate that
a wet FGD can keep Hg soluble (i.e., dissolved in solution). High ORP indicates that the
wet FGD contains a higher concentration of transition metals (e.g, Mn, Fe, and Cu).
Chengli et al. (2010) concluded from bench-scale tests that the presence of transition
metals could be a key component in managing reemissions from wet FGDs. Lower ORP
is actually more beneficial from a reemission perspective because the Hg is more likely to
precipitate. Hg reemission is less likely to occur via a reduction reaction once Hg has
precipitated.
A reemission parameter qualitative ranking system, shown in Table 4.8, was
developed incorporating information from the literature. In the ranking system, good
denotes a low likelihood for a reemission to occur, neutral indicates that the parameter
had no relative impact on whether a reemission would occur, and a rating of poor
indicates that the parameter increased the likelihood for a reemission event to occur.
A sulfite concentration of 2 mM or greater was evaluated as good, a value below
2 mM but greater than 1 mM was considered neutral and a sulfite concentration below 1
mM was evaluated as poor. The bench-scale results from Omine et al. (2012) were used
to develop this guidance.
The guidance of Omine et al. (2012) was used to assign ratings for chlorine and
bromine concentration impact on Hg reemission. A combined chlorine and bromine
concentration that exceeded 4,000 ppm was evaluated as good, a combined concentration
142
greater than 2,000 but less than 4,000 ppm was evaluated as neutral, and a combined
concentration below 2000 ppm was evaluated as poor.
Table 4.8 Reemission Parameter Qualitative Ranking System
Unit
Poor
Neutral
Good
Sulfite concentration
mM
<1
1<X<2
>2
Combined bromine
and chlorine
concentration
ppm
<2000
2000 < X < 4000
>4000
ORP
mV
>400
400 < X < 200
0 < X < 200
%
>2
0.5 < X < 2
<0.5
Wet FGD slurry
concentration
Chengli et al. (2010b) reported that ORP values less than 0 mV led to Hg
reemissions and that Hg reemission did not occur when ORP was greater than 0 mV but
less than 135 mV, which was the highest ORP value studied. On the basis of results from
full-scale studies, Dombrowski and Richardson (2012) reported that Hg reemissions did
not occur at ORP below 250 mV but were prevalent at ORP values greater than 400 mV.
For Hg concentration, a relative ranking was used that was based not on any
guidance from the literature but on the experience of the researcher. The literature
review did not reveal research based on the impact of wet FGD slurry Hg concentration
on Hg reemissions. If the Hg concentration in the slurry was less than 0.5% of the total
Hg (i.e., Hg concentration in the wet FGD slurry and gypsum), then a ranking of good
143
was given; if the Hg concentration in the slurry was 0.5% to 2% a neutral ranking was
given; if the Hg percentage in the slurry exceeded 2% a poor ranking was given. The
converse would be true for Hg concentration in the solids: poor would equal <98% of
total Hg in the solids, neutral would be given when the Hg concentration was greater than
98% but less than 99.5%, and a good score would be given when the Hg concentration
was greater than 99.5%.
To better understand the context of Hg reemission observed during Phases IIA
and IIB, the researcher developed Table 4.9 to summarize data in terms of Figure 4.13
and to apply the qualitative ranking system in Table 4.8. Table 4.9 provides a summary
of appropriate wet FGD conditions that existed on specific testing days during Phases IIA
and IIB. Unfortunately, wet FGD chemistry data were not available for some days. As
described earlier, the lowest values of RP (RP = 0.45, 0.5, and 0.57) were found on the
days when the SCR was bypassed. Unfortunately, during those instances, wet FGD
analytical samples were not taken.
Table 4.9 provides wet FGD chemistry data for five days collected during Phases
IIA and IIB. For example, although sulfite concentrations on October 12, 2008, received
a poor rating, all other parameters were evaluated as good. The halogen concentration
was high (>4,000 mg/L), the ORP was low (149 mV), and Hg concentration in the wet
FGD slurry was low (<0.5%). These other parameters likely compensated for the low
sulfite concentration. For the days that data were available, Hg reemission potential was
low.
Additional test programs are needed to assess the viability of the Hg reemission
probability diagram (Figure 4.12) and the qualitative ranking system (Table 4.8).
144
Table 4.9 Summary Operational Information Describing the Potential for Hg Reemission Events to Occur Within
the 2 MW Pilot Wet FGD During Phases IIA and IIB Testing
Date
Calculated
Reemission
Potential
Sulfite
(mM)
Total Halogen
(ppm)
Oxidation Reduction
Potential
(mV)
Slurry Hg
Concentration
(wt%)
2/22/2008
0.81
1.45
Neutral
3,049
Neutral
109
Good
0.1
Good
2/23/2008
0.92
1.6
Neutral
2,404
Neutral
117
Good
3/12/2008
0.97
1.54
Neutral
5,627
Good
159
Good
0.1
Good
0.1
Good
10/9/2008
1.11
1.71
Neutral
851
Poor
149
Good
0.2
Good
10/12/2008
0.94
0.975
Poor
4,499
Good
146
Good
0.1
Good
Criteria for parameter ranking can be found in Table 4.8.
145
Although the diagram is based on the fundamentals derived from the literature
and on researcher experience, the data collected during Phases IIA and IIB provides
insufficient outliers to test the applicability of the concept. The conclusion drawn from
the analysis of the data is reemission did not occur excessively during the research period
and the results from the qualitative ranking system agree with observed behavior.
4.4.4
An Evaluation of Br/Hg Ratio
In the previous section, ideal Br/Hg ratios were suggested for attaining high Hg
oxidation ratios. Table 4.10 catalogs the effect of Br/Hg ratio on wet FGD Hg removal.
For only a limited number of data points was all of the required information (Br/Hg ratio
and wet FGD removal) available.
Table 4.10 Wet FGD Hg Removal Ratio and Reemission Parameter as a Function of
Br/Hg Ratio and SCR Condition
Phase
SCR
in
Service
NH3
in
Service
Br
Concentration
(wt ppm)
Br/Hg
Ratio
Wet FGD
Hg Removal
Reemission
Parameter
IIA
No
No
30
652
0.40
0.87
IIA
Yes
No
6
103
Not available
Not available
IIB
Yes
Yes
25
238
0.86
0.89
IIB
Yes
Yes
25
357
0.94
0.97
IIA
Yes
No
25
463
0.92
0.95
IIA
Yes
No
25
556
0.93
1.12
IIA
Yes
Yes
No
No
50
50
877
1,111
0.94
Not available
0.95
Not available
IIA
146
Once the Br/Hg ratio was above 250, wet FGD Hg removal exceeded 90% with
the SCR in service. With the SCR bypassed and with the Br/Hg ratio below 3,000, wet
FGD Hg removal was less than 90%; however limited data were available to fully
evaluate this configuration. These findings validate for a unit burning PRB coal, a Br/Hg
recommendation for achieving 90% Hg oxidation for SCR applications: Br/Hg > 250 and
suggest that for non-SCR applications: Br/Hg > 3,000 is an appropriate recommendation.
Due to unavailability of data, results at higher Br/Hg ratios on Hg reemission were
unavailable and therefore not included in Table 4.10.
4.4.5
Summary
The hypothesis that CaBr2 injection can result in Hg capture efficiencies
exceeding 90% with a wet FGD present held. CaBr2 addition successfully oxidized Hg,
most likely in the form of HgBr2, which is readily soluble in water (Cleaver et al., 1985).
The oxidized Hg was removed from the treated flue gas with high efficiency. In addition
to proving the validity of the hypothesis, the analyses led to these general conclusions:
•
Combined with a well functioning SCR, a Br/Hg ratio > 250 will result in wet
FGD Hg removal efficiencies exceeding 90% if Hg is not reemitted from the
wet FGD sump. For a non-SCR application, a Br/Hg ratio > 3,000 is
recommended for similar Hg removal efficiencies.
•
Hg reemissions are a function of many wet FGD slurry parameters such as
sulfite concentration, chlorine and bromine concentration, liquid and solid Hg
concentration, and ORP.
147
•
Observed Hg reemission events when the wet FGD slurry bromine
concentrations were lowest, that is less than 200 ppm during Phase IIA and
less than 50 ppm during Phase IIB.
4.5
Hypothesis 4: The Difference in Average Hg Emissions Using CaBr2 Addition,
When Compared to Not Employing CaBr2 Addition is Statistically Significant
4.5.1
Analysis of Phase III Hg Emissions
Data from Phase III, which involved 83 days of continuous addition of CaBr2 to
evaluate long-term performance, were used to test the hypothesis. Figure 4.13 depicts a
chronological plot of Unit 3 and Unit 4 hourly average Hg emissions (µg/m3) from
September 1, 2010, to January 30, 2011. This period includes the CaBr2 addition testing
conducted on Unit 4 from October 1, to December 19, 2010.
As Figure 4.13 shows, the Hg emissions from Unit 3 differ markedly from those
of Unit 4 during the CaBr2 addition period, whereas the Hg emissions from the two units
are similar before CaBr2 addition began and after CaBr2 addition ceased. A break in Hg
emission values from December 20 to December 31 resulted from data unavailability.
The figure also reveals that the Hg emissions from Unit 3 trended slightly downward
during the CaBr2 addition period, possibly because of unit operations (e.g., load and SCR
operational parameters) or changes in PRB coal characteristics. If the downward trend in
Hg emissions from Unit 3 resulted from a change in coal characteristics, this merits
investigating because Unit 4 also burned the same coal during this period.
Figure 4.13 indicates that Hg emissions varied widely on both units but that the
magnitude of the variability was more pronounced on Unit 3. Br/Hg ratios were not held
148
constant during the test. The Br/Hg variability results both from changes in coal Hg
content and for variations in Br concentration (wt ppm on the dry coal) which varied by a
maximum factor of 2 and 25, respectively. (See Appendix B for coal data.) The extent of
coal Hg concentration variability Hg remains unknown because of the lack of
information. During Phase III, only 11 discrete coal Hg content measurements were
made.
Figure 4.13 Hourly average Hg emissions concentration (µg/m3) from Miller Unit 3 and
Unit 4 from September 1, 2010, through January 30, 2011, which includes
the bromine addition test period from October 1 through December 19. Hg
emissions data were not available from December 20 through December 31.
A = calcium bromide addition begins. B = Unit 4 outage. No bromide was
injected during start-up. C = Missing data from dataset.
149
The known minimum Br/Hg ratio (lb/lb) of 250 occurred on December 16, 2010 when
the Br concentration was 8 wt ppm on the dry coal and when the coal Hg content was
0.032 ppm. The maximum known Br/Hg ratio of 1,666 occurred on October 7, 2010
when the Br concentration was 50 wt ppm on the dry coal and when the coal Hg content
was 0.03 ppm. During the test, the CaBr2 liquid flow rate was maintained at a constant
rate, even during periods of low load; that is the CaBr2 addition rate was held constant
while the coal flow changed. The constant addition rate of CaBr2 while load was allowed
to fluctuate caused Br concentration variability. The results of testing in Phases IIA and
IIB showed that Br/Hg ratios in excess of 250 do not result in higher fractions of Hg
oxidation and that Br/Hg ratios below 3,000 do not adversely affect Hg oxidation at the
wet FGD inlet. During Phase III, the varying Br/Hg ratios observed were between 250
and 3,000; therefore, Hg oxidation was optimized.
Figure 4.14 focuses on the Unit 4 average hourly Hg emissions, and includes data
regarding load (MW) and Br concentration (wt ppm on the dry coal), which are plotted
chronologically. During the Phase III program, Unit 4 was operated in normal dispatch
mode; in other words, the load was allowed to vary as needed to meet electricity demand.
During the addition of CaBr2, Hg emissions were low, with an average Hg emission
concentration of 0.26 µg/m3 and with a standard deviation of 0.15 µg/m3. As expected,
the Hg emissions were not adversely affected by Br concentration variability.
Additionally, changes in unit operating load did not appear to affect Hg emissions.
As Figure 4.14 shows, when CaBr2 addition began, a corresponding reduction in
Hg emissions occurred immediately. The hourly average Hg emission concentrations
before and after the CaBr2 addition were much higher. Once the CaBr2 addition ceased,
150
the Hg emissions returned to approximately the same magnitude as those levels seen
before CaBr2 addition commenced. A more detailed discussion regarding load variability
and its effect on hourly average Hg emissions behavior is contained in 4.5.3.
Figure 4.14 Hourly average Hg emissions concentration (µg/m3); Br concentration (wt
ppm on the dry coal); and load (MW) from Miller Unit 4 from September 1,
2010 through January 30, 2011, which includes the CaBr2 addition test
period from October 1 through December 19. Hg emissions data were not
available from December 20 through December 31.
Figure 4.15 provides a closer viewpoint of Unit 4 average hourly Hg emissions
and the effect of Br concentration. The majority of hourly average Hg emissions fall
below 0.5 µg/m3, and a small number of hourly averages exceed 1 µg/m3. The variability
151
in Hg emissions does not appear tied to Br concentration since the variability in the Hg
emissions continued during a November period when the Br concentration was more
consistent.
4.0
Hg Emissions
Br Concentration
60
3.5
Hg Emissions (ug/m3)
3.0
40
2.5
2.0
30
1.5
20
1.0
Br Concentration (wt ppm on the dry coal)
50
10
0.5
0.0
0
9/28
10/12
10/26
11/9
11/23
12/7
Date
Figure 4.15 Hourly average Hg emissions concentration (µg/m3) and Br concentration
(wt ppm on the dry coal) from Miller Unit 4 from October 1 through
December 19, 2010. Includes a Unit 4 outage from December 6 through 9,
2010. CaBr2 was not added during start-up after the outage. CaBr2 was
returned to service at a lower addition rate after the unit reached full load.
The variability in Hg emissions could indicate a measurement artifact, operational issues,
or normal variability in emissions. Although not a major concern because of the smaller
number of instances, the hourly average Hg emissions above 1 µg/m3 are noteworthy
152
because, despite the fact that compliance is based on a 30-day rolling average, the MATS
rule requires that Hg emissions are below 1.2 lb/TBtu (approximately 1.15 µg/m3 at Plant
Miller Unit 4). On Saturday, December 5, 2010, Unit 4 was taken offline for an
unplanned outage of approximately 40 h. CaBr2 was not added during the start-up of the
unit to observe uncontrolled Hg emissions. After start-up operations ceased, the Br
concentration was reduced by half each day until the end of the test program. Figure 4.16
contains a plot of the hourly average Hg emissions shortly before and after the Unit 4
outage in December.
Figure 4.16 Hourly average Hg emissions concentration (µg/m3) and Br concentration
(wt ppm on the dry coal) on Miller Unit 4 from December 4 through
December 19, 2010, which includes short boiler outage.
153
The figure reveals that hourly average Hg emissions during the start-up of Unit 4
exceeded those found before the outage (1.75 µg/m3 and 0.25 µg/m3, respectively). At a
Br concentration of 10 wt ppm on the dry coal, the hourly average Hg emissions
remained at a level comparable to those seen before the outage. The Br concentration was
reduced further, and a corresponding increase in hourly average Hg emissions variability
was observed.
4.5.2
Impact of Coal Characteristics
The quality of coal delivered to a site varies with time, even in situations such as
that found at Plant Miller, which exclusively fires PRB coal from the same region. The
coal can vary in a number of constituents that could have affected the results of this
research program. Such coal constituents include Hg content, halogen content, and,
sulfur content. An analysis of baseline Hg emissions revealed that the amount of
oxidized Hg present, could in fact, be a function of these factors. Statistical and graphical
methods were used to determine the effect of coal characteristics on Hg emissions.
The analysis of coal variability of Hg emissions included a comparison of Unit 3
hourly average Hg emissions during the CaBr2 addition period, with Unit 3 hourly
average Hg emissions observed the month before and the month after the CaBr2 addition
period. This examination of the Unit 3 hourly average emissions provided insights into
the ways in which coal characteristics might have changed during the CaBr2 addition
period. Also, an analysis of Unit 4 hourly average Hg emissions when CaBr2 was not
added highlighted the impact of specific coal changes on Unit 4. Differences found in Hg
emissions from Unit 3 and Unit 4 would highlight the impacts of coal variability.
154
4.5.2.1 Unit 3 Coal Impact Analysis
The impact of coal characteristics on Hg emissions was evaluated by a t-test of
Unit 3 Hg emissions data, which were comprised of CaBr2 addition condition (i.e.,
on/off) as an independent variable and Unit 3 hourly average Hg emissions as the
dependent variable. As noted earlier, CaBr2 was not added to Unit 3. The use of CaBr2
addition condition (i.e., on/off) as the independent variable effectively segregates the Unit
3 hourly average Hg emissions data into the two periods of interest. The Unit 3 data were
not normally distributed (see Appendix C for normality analysis). The lack of normality
was not sufficiently severe to affect t-test applicability. Table 4.11 provides summary
information regarding the Unit 3 hourly average Hg emissions dataset.
Table 4.11 Unit 3 Hourly Average Hg Emissions Descriptive Statistics During
CaBr2 Addition Period on Unit 4 and Not During CaBr2 Addition
Period on Unit 4
Unit 4: CaBr2 Off
September 1-30 /
January 1-30
Unit 4: CaBr2 On
October 1-December 19
1,493
1,735
Mean (µg/m )
3.14
2.91
Standard deviation (µg/m3)
1.14
1.00
Statistic
No. of Samples
3
An independent t-test was done to determine the significance of mean differences
during the two periods. Cohen d was computed to determine the magnitude of effect.
Additionally, the partial eta squared was computed as an additional means measuring the
magnitude of effect.
155
The equality of the means of the hourly average Hg emissions (µbromine,test =
µbromine,no) was assumed to test the null hypothesis. The null hypothesis was rejected,
t(3226) = 6.116, p < .001, with Unit 3 hourly average Hg emissions greater during
periods when CaBr2 was not being added to Unit 4 than during the period when CaBr2
was being added to Unit 4. In other words, the Unit 3 Hg emissions during September
and January were greater than the Unit 3 Hg emission from October through December.
The Cohen’s d calculated value was 0.215, which translates to a low degree of effect
(Weinberg and Abromowitz, 2008). The partial eta squared was 0.011, which translates
to a low degree of effect (Barnette, 2006). The results of the t-test can be found in the
Appendix D.
The results show that Hg emissions on Unit 3 differ during the two periods (CaBr2
on and CaBr2 off on Unit 4). The magnitude of the effect was small. There was an
unexplained change during these two periods that resulted in a difference in hourly
average emissions.
4.5.2.2 Unit 4 Coal Impact Analysis
To evaluate the impact of coal characteristics on Unit 4 hourly average Hg
emissions, an independent t-test was completed by using data from Unit 4 during
September 2010 and January 2011, when CaBr2 was not being injected. The Unit 4
average hourly Hg emissions were the dependent variable with the time period of the
measurement as the independent variable. The Unit 4 data were not normal. (See
Appendix C for normality analysis.) The lack of normality was not sufficiently severe to
156
affect t-test applicability. Table 4.12 provides a summary of the descriptive statistics for
the data.
The equality of the two average hourly Hg emission means (µ4, September = µ4,
January)
was tested as the null hypothesis. The null hypothesis was rejected, t(1395) =
7.835, p < .001. The difference in Unit 4 hourly average Hg emission means during
September 2010 and January 2011 was statistically significant. Cohen’s d calculated
value was 0.41, which translates to a low degree of effect (Weinberg and Abramowitz,
2008). The partial eta squared was determined as 0.042, also a low degree of effect
(Barnette, 2006). The results of the t-test can be found in the Appendix D.
Table 4.12 Unit 4 Hourly Average Emissions Descriptive Statistics During
September 2010 and January 2011
Unit 4: CaBr2 Off
September 1-30
Unit 4: CaBr2 Off
January 1-30
Sample size
690
707
Mean
2.54
2.18
Standard deviation
1.04
0.67
Statistic
4.5.2.3 Coal Impact Analysis Summary
The analyses from both Unit 3 and Unit 4 showed that coal characteristics did
change during Phase III testing. During January 2011, the lowest mean hourly average
Hg emission mean was 2.18 µg/m3 that occurred on Unit 4 in January 2011. Even at this
low concentration, Unit 4 was out of compliance with the MATS rule Hg limit. Because
157
the lowest Hg emission average exceeded the MATS rule Hg limit, the effect of coal
characteristics was determined to be minor.
4.5.3
Impact of Load
Unit load represents a real-time measure of a number of factors that affect Hg
oxidation such as, mass flow of coal, fly ash, unburned carbon, halogens, and Hg;
operating temperatures of the SCR, air heater and cold-side ESP; and residence times in
the SCR, air preheater, cold-side ESP and wet FGD. For example, as load decreases,
SCR temperature decreases, and flue gas residence times in environmental control
equipment increase both of which are positive influences of Hg oxidation. In another
example, as coal mass flow decreases the wet FGD concentration of transition metals and
halogens decreases and those factors can adversely impact oxidized Hg retention.
Understanding these individual factors are important, for this analysis, any significant
differences in hourly average Hg emissions are attributed to changes in unit load. An
ability to exclude or properly qualify the influence of other factors on Hg emissions
ensures that differences in Hg emissions can be positively attributed to CaBr2 addition. A
focused evaluation of CaBr2 addition performance on Hg emissions supports the decision
to combine the impact of other factors on Hg emissions into a single independent variable
(i.e., load).
For the analysis, unit load data were grouped into three separate categories:
Category 1, Load > 600 MW; Category 2, 500 MW < Load < 600 MW; and Category 3,
Load < 500 MW. Once data grouping was complete, graphical and descriptive statistical
158
methods were used to determine whether differences in hourly average Hg emissions
were observed. Three test cases were analyzed:
•
Case 1: CaBr2 Off − Unit 3, September 1, 2010, through January 30, 2011.
•
Case 2: CaBr2 Off − Unit 4, September 1-30, 2010, and January 1-30, 2011.
•
Case 3: CaBr2 On − Unit 4, October 1-December 15, 2010.
4.5.3.1 Case 1: Unit 3 Load Analysis
The Unit 3 hourly average Hg emissions from September 1 to January 30 were
coded with a load category. Table 4.13 summarizes the Unit 3 Hg emissions data sorted
by load category and lists number of samples, mean Hg emission concentration, and Hg
emission standard deviation.
Table 4.13 Unit 3 Hourly Average on Hg Emissions Descriptive Statistics From During
Various Load Conditions From September 1st 2010, Through January 30, 2011
Category 1
Load < 600 MW
Category 2
500 MW < Load < 600 MW
Category 3
Load < 500 MW
No. of samples
2,948
194
82
Mean
(µg/m3)
3.15
1.86
0.64
Standard deviation
(µg/m3)
0.99
0.63
0.45
Statistic
This table shows that Unit 3 operated at or above 600 MW 90% of the time and
hourly average Hg emissions decreased with load. A number of factors could explain this
phenomenon, such as flue gas temperature and system residence time; however data are
159
not provided here to support clear and substantiated arguments. Although hourly average
emissions decreased with load, the magnitude of the standard deviation relative to the
mean increased. For categories 1 and 2, the ratio of the mean to the standard deviation
was roughly 3 but for category 3 the ratio was 1.4. This suggests that, when adjusted for
the mean, the Hg emissions in Category 3 were more than twice as variable.
Figure 4.17, a graphical representation of the Unit 3 Hg emissions versus load
category, conveys how the hourly average Hg emissions decreased as a function of load.
Figure 4.17 Hourly average Unit 3 Hg emissions as a function of unit load (1, Load > 600
MW; 2, 500 MW < Load < 600 MW; 3, Load < 500 MW); the figure
includes data from September 1, 2010, through January 30, 2011.
160
With each successive category moving from the left of the figure to the right, the
hourly average Hg emissions are lower. The box for each category represents the 75% 25% quartiles with a line in the box representing the median. For each successive
category the 75% - 25% quartiles is below the same quartile range in the immediately
higher category. Clearly, both Table 4.13 and Figure 4.17 illustrate that Unit 3 hourly
average Hg emissions vary as a function of load.
4.5.3.2 Case 2: Unit 4 Load Analysis
Table 4.14 provides a summary of Unit 4 hourly average Hg emissions during the
period when CaBr2 was not added. In this table, the data are sorted by load category, and
lists the number of samples, mean Hg emissions and Hg emissions standard deviation.
Table 4.14 Unit 4 Average Hourly Hg Emissions Descriptive Statistics of Various Load
Conditions From September 1-30, 2010, and From January 1-30, 2011
Statistic
Category 1
Category 2
Load > 600 MW 500 MW < Load < 600MW
Category 3
Load < 500 MW
Sample size
1,355
31
11
Mean
(µg/m3)
2.40
1.05
1.37
Standard deviation
(µg/m3)
0.86
0.90
0.99
The information in Table 4.14 indicates that hourly average Hg emissions
decreased from Category 1 to Category 2 and increased from Category 2 to Category 3.
Since the magnitude of the standard deviation was close to the magnitude of the mean for
161
Category 2 and 3, the variability of the Hg emissions was larger. Unit 4 operated in the
high load category 97% of the time. This provides a large dataset to draw conclusions.
The other two categories collectively represent only 3% of the samples and may be
insufficient in size from which to draw conclusions. The magnitude of Hg emissions in
the lowest load category reached 58% of Category 1 and 130% of the Category 2
emission values.
Figure 4.18 provides a graphical representation of Unit 4 average hourly Hg
emissions without CaBr2 addition by load category.
Figure 4.18 Unit 4 hourly average Hg emissions as a function of unit load (1, Load > 600
MW; 2, 500 MW < Load < 600 MW; 3, Load < 500 MW); the figure
includes Unit 3 Hg wet FGD stack emissions data from September 1-30,
2010, and from January 1-30, 2011.
162
As previously described, Hg emissions did decrease from the high-load condition to the
low-load condition. The variation of Hg emissions are much wider on Unit 4 without
CaBr2 addition when compared with Unit 3, but the magnitude of Unit 3 Hg emissions
were higher. The figure does show a wide range of hourly average of Hg emission for
the lower load condition. For the same period, this behavior is much different from what
was observed on Unit 3.
Table 4.14 and Figure 4.18 illustrate that, similar to Unit 3, Hg emissions
decreased from the high-load condition to the mid-load condition. For Unit 4, the
emissions did increase from the mid-load condition to the low-load condition. The
sample sizes for mid and low-load conditions are small (31 and 11 respectively) and may
lack sufficient samples to support substantiate conclusions.
4.5.3.3 Case 3: Analysis of Unit 4 Load During CaBr2 Addition Period
The impact of load on hourly average Hg emissions during the CaBr2 addition
period were particular noteworthy. Table 4.15 summarizes the Unit 4 Hg emissions data
sorted by load category and includes number of samples, mean Hg emission
concentration, and Hg emission standard deviation.
163
Table 4.15 Unit 4 Hourly Average Hg Emissions Descriptive Statistics of Various Load
Conditions From October 1 Through December 19, 2010
Statistic
Sample size
Mean
(µg/m3)
Standard deviation
(µg/m3)
Category 1
Load > 600 MW
Category 2
500 MW < Load < 600 MW
Category 3
Load < 500 MW
1154
78
66
0.245
0.139
0.152
0.133
0.078
0.10
Unit 4 operated above 600 MW 89% of the time. The table reveals that Hg
emissions were low across all load categories during CaBr2 addition and that variability
within each category was low.
Figure 4.19 contains a plot of Unit 4 hourly average Hg emissions during periods
of CaBr2 addition by load category. Table 4.15 and Figure 4.19 show that, with CaBr2
addition, hourly average Hg emission values are much lower and do not vary as a
function of load. The standard deviation was roughly equal to the mean, however,
because of the low magnitude of the Hg emissions themselves, this variation is not
significant.
164
Figure 4.19 Unit 4 hourly average Hg emissions as a function of unit load (1, Load > 600
MW; 2, 500 MW < Load < 600 MW; 3, Load < 500 MW); the figure
includes Unit 4 wet FGD outlet Hg emissions data from October 1 through
December 19, 2010.
4.5.3.4 Summary
During CaBr2 addition, Unit 4 hourly average Hg emissions did not vary with
load category. Without the addition of CaBr2, hourly average Hg emissions from Unit 3
proved sensitive to unit load, whereas Unit 4 Hg emissions were also sensitive to unit
load but to a lower extent. For the evaluation of CaBr2 addition on Hg emission, the
impact of load on Unit 4 Hg emissions are insignificant.
165
4.5.4
Impact of Calcium Bromide Addition
Evaluating the ability of CaBr2 addition to reduce hourly average Hg emissions on
Unit 4 involved using statistical methods to compare hourly average Hg emissions with
and without CaBr2 addition. Table 4.16 provides descriptive statistics of Hg emissions
from Unit 4, with data divided into the two periods of interest.
Table 4.16 Unit 4 Hourly Average Hg Emissions Descriptive Statistics During Periods
With and Without CaBr2 Addition
CaBr2 Off
September 1-30 / January
1-30
CaBr2 On
October 1-December 19
1,434
1,688
Mean (µg/m )
2.32
0.26
Standard deviation (µg/m3)
0.92
0.15
Statistic
Sample size
3
An independent t-test was completed using Unit 4 hourly average Hg emissions as
the dependent variable and CaBr2 addition (on/off) as the independent variable. The
magnitude of effect was computed via the Cohen d test statistic. Partial eta squared was
determined as an additional measure of magnitude of effect.
The equality of the means (µbromine,test = µbromine,no) was tested as the null
hypothesis, which was rejected. A significant difference existed for Unit 4 hourly
average Hg emissions, t(3120) = 90.947, p < .01, with Hg emissions greater during
periods when CaBr2 was not being added to the coal. Cohen’s d was 3.12, which
166
translates to a large magnitude of effect (Weinberg and Abromowitz, 2008). Partial eta
squared was 0.726, which also translates to a high magnitude of effect (Barnette, 2006).
The result statistically establishes that the hourly average Hg emissions during
CaBr2 addition are lower from hourly average Hg emissions without CaBr2 addition. A
large magnitude of the effect was found, that is the independent variable was responsible
for the difference in Hg emissions.
4.5.5
Comparison of Hg Emissions From Unit 3 and Unit 4
The analytical protocol included conducting a paired t-test to determine if Unit 3
hourly average Hg emissions and Unit 4 hourly average Hg emissions were equal (µ3,no
bromine
= µ4,with bromine) during the period in which CaBr2 was added to Unit 4 but was not
added to Unit 3. The null hypothesis was rejected, t(1259) = 112.980, p < .01. The Unit
3 hourly average Hg emissions were greater than Unit 4 Hg emissions during CaBr2
injection on Unit 4.
4.5.6
Br/Hg Ratio Impact on Hg Removal Performance
Table 4.17 is a summary of Br/Hg ratios during Phase III. The available
information is limited; coal Hg concentration data was available for only 11 test days.
The minimum daily Br concentration (wt ppm on the dry coal) for the days coal data
were available were used to calculate a conservative value of the Br/Hg ratio (lb/lb).
During Phase III, the lowest known Br/Hg ratio (lb/lb) of 258 was observed on
December 16, 2010. Figure 4.16 shows low Hg emissions (0.5 µg/m3) for that day.
167
Table 4.17 Phase III Br/Hg Ratio Summary Based on Hg Content Measured in the Coal
and Minimum Observed Daily Br Concentrations (wt ppm on the dry coal)
Minimum
Daily Br
Concentration
(wt ppm on the
dry coal)
Br/Hg
Ratio
(lb/lb)
Date Coal
Sample Taken
Sample
Hg Content
(wt ppm)
9/29/10
1
0.072
1.3a
18
a
9/30/10
2
0.061
1.3
21
10/7/10
3
0.032
22.2
694
10/14/10
4
0.045
17.1
380
10/21/10
5
0.050
20.4
408
10/28/10
6
0.054
17.9
331
11/11/10
7
0.049
18.9
386
11/17/10
8
0.048
16.9
352
11/22/10
9
0.036
17.2
479
11/29/10
10
0.044
17.8
405
12/16/10
11
0.031
8.0
258
a. Coal Br concentration used during period without CaBr2 addition.
The calculated Br/Hg ratio of 258 exceeds the Br/Hg >250 recommendation for full Hg
oxidation. The Br/Hg ratios for the other testing days having known coal Hg content were
above 250. The Unit 4 average Hg emissions during Phase III were 0.26 µg/m3. The
combination of these two facts supports the minimum Br/Hg ratio of 250 (lb/lb) when a
well-designed and maintained SCR is present.
4.5.7
Summary
The null hypothesis that Hg emissions with and without CaBr2 addition are the
same has been rejected at the 99% confidence level. In addition, statistical methods were
168
used to demonstrate that CaBr2 addition was responsible for the reduction of Unit 4 Hg
emissions. In addition the following general conclusions were drawn:
•
During Phase III, changes in coal characteristics impacted hourly average Hg
emissions on Unit 3 and Unit 4 but its impact was found to be minimal and
did not affect the evaluation of CaBr2 injection technology.
•
Load changes on Unit 3 and Unit 4 affected Hg emissions during periods
without CaBr2 addition. During low load (i.e., <500 MW), Hg emissions on
Unit 3 were below 0.7 µg/m3. The impact of low load operations on Unit 4
Hg emissions was less pronounced.
•
Unit 4 Hg emissions decreased significantly during periods of CaBr2 addition.
•
Unit 4 Hg emissions had a mean of 0.26 µg/m3 and a standard deviation of
0.156 µg/m3 during the 83-day period when CaBr2 was added to the dry coal.
Unit 4 Hg emissions had a mean of 2.32 µg/m3 and a standard deviation of
0.92 µg/m3 when CaBr2 was not added to the coal.
4.6
Hypothesis 5: Hg Emission Rates Achieved During the Use of CaBr2 Addition
Are Sufficiently Low to Meet the MATS Rule Hg Limit of 1.2 lb/TBtu on a 30Day Rolling Average
4.6.1
Overview
Phase III hourly average Hg emissions data were used to determine the
effectiveness of CaBr2 addition in reducing Hg emissions as a compliance tool for
achieving the MATS Hg limit of 1.2 lb/TBtu using a 30-day rolling average. The
protocol included using two approaches to test the hypothesis. In the first approach, Unit
169
4 hourly average emissions were converted from a concentration basis to an input basis
emission rate, using EPA Method 19, and plotted alongside the 1.2 lb/TBtu compliance
limit. If all of the hourly emission rate averages were below the 1.2 lb/TBtu limit, then
the hypothesis would be deemed proven. In the second approach, 30-day rolling Hg
emission averages from Unit 3 and Unit 4 were computed and chronologically plotted
alongside the 1.2 lb/TBtu compliance limit. For Unit 4, if all the 30-day rolling Hg
emission average were below the 1.2 lb/TBtu, the hypothesis was deemed proven.
Additionally, the Wilcox Rank Sign test was used to compare Unit 3 and Unit 4 30-day
rolling Hg emissions averages and determine whether Hg emission rates from the two
units were statistically different.
In addition to the testing of the hypothesis, a simulation of a 7-day CaBr2 addition
system outage was completed by appending Unit 4 Hg emissions data from September 1,
to September 8, 2010, to the existing 30-day rolling Hg emission averages and additional
30-day rolling Hg emission averages were computed. Plotting the data enabled
quantification of the impact the 7-day outage on 30-day rolling Hg emission averages.
4.6.2 Unit 4 Hourly Average Hg Emission Rate Analysis
Figure 4.20 shows chronological plot of Unit 4 hourly average Hg emission rate
(lb/TBtu). The figure includes Br concentration (wt ppm on dry coal) and the MATS rule
Hg limit of 1.2 lb/TBtu. At the extreme left, the figure illustrates a period without CaBr2
addition to the coal. Once CaBr2 was added, the Hg emissions decrease was immediate.
170
Variable Load
Reduced
bromine
Stable Load
Figure 4.20 Chronological plot of Phase III Unit 4 hourly average Hg emissions rate
(lb/TBtu) and Br concentration (wt ppm on dry coal) during the 83-day
CaBr2 injection test.
In the absence of CaBr2 addition, the Hg emission rate exceeds the proposed
MATS rule limit. Once CaBr2 was added on October 1, the Hg emission rate falls well
below the 1.2 lb/TBtu limit. The Br concentration (wt ppm on the dry coal) was variable
during the entire test period. The addition rate of CaBr2 solution was held constant while
unit load was allowed to vary to meet electricity demand. This caused the Br
concentration on the coal to vary. The Br concentration variability is clearly observed in
Figure 4.20. While the Br concentration did vary with load, the Hg emission rate did not
vary correspondingly. The figure illustrates two periods, one in which the Br
concentration varied widely and one period during which the Br concentration was fairly
constant. These are labeled in the figure as periods of variable and stable load. During
171
the two periods the variability of Hg emissions remained unchanged indicating that the
Hg emissions and Br concentration were not strongly linked. This suggests that sufficient
bromine was present to ensure sufficient Hg oxidation and that any extra bromine did not
result in a decrease in Hg emissions. For the entire CaBr2 injection period low Hg
emissions are observed. In a few instances in late October, the emission rate does exceed
the 1.2 lb/TBtu limit. After an unplanned outage on December 6, 2010, the Br
concentration was reduced from 20 wt ppm to 10 wt ppm, then to 8 wt ppm, and then to 2
wt ppm. With the Br concentration reduced, the Hg emission rate began to exceed 1.2
lb/TBtu more frequently. This finding suggests that, although CaBr2 addition effectively
reduced Hg emissions, the Br concentration must be maintained at a minimum level to
achieve the desired results. Because a few hourly Hg emission rate averages occurred
that exceeded the MATS limit of 1.2 lb/TBtu, additional analysis is needed to verify the
hypothesis.
4.6.3
Unit 3 and Unit 4 30-Day Hg Emission Rate Analysis
Figure 4.21 is a chronological plot of 30-day rolling Hg emission rate averages
from Unit 3 and Unit 4 and includes a vertical line representing the 1.2 lb/TBtu MATS
rule Hg limit. As the figure shows, at no point during the 83-day test did the Unit 4 30day rolling Hg emission averages exceed the MATS rule Hg limit of 1.2 lb/TBtu. In fact,
the rolling average remained well below the limit each day. Unit 4 had a maximum 30day rolling Hg emissions average of 0.41 lb/TBtu and a minimum 30-day rolling Hg
emissions average of 0.21 lb/TBtu. The Unit 4 30-day rolling averages included
172
instances of uncontrolled emissions during a start-up condition when the CaBr2 addition
system was not in service.
The observed behavior for Unit 3 differed. At no point during Phase III did the
magnitude of the Unit 3 30-day rolling average fall below the MATS rule Hg limit.
Figure 4.21 does show a downward trend in Hg emissions, but this trend did not bring
Unit 3 below the MATS rule compliance limit.
Figure 4.21 Chronological plot of Phase III Unit 4 and Unit 3 daily and 30-day rolling Hg
emissions rate (lb/TBtu).
173
A statistical comparison of Unit 4 and Unit 3 30-day rolling averages was
completed using the Wilcox Ranked Sign Test. The observed difference between both
measurements is statistically significant and the null hypothesis that the means were
equal was rejected. Details of the Wilcox Ranked Sign test can be found in Appendix D.
4.6.4
Seven-day CaBr2 Addition System Outage Simulation
Figure 4.22 was created by adding 7 days of daily average Hg emission rate data
from September 1-7, 2010, to the end of the Unit 4 Phase III CaBr2 addition Hg
emissions rate data and new 30-day rolling Hg emission averages were computed.
Figure 4.22 Seven-day simulation of CaBr2 injection system outage combining Phase III
Unit 4 30-day rolling Hg emissions rate data with Unit 4 daily Hg emissions
rate data during September 1-7, 2010. The resulting plot represents the
impact of higher emissions on MATS rule compliance.
174
The choice of the 7 days added to the data received no special consideration, and
it is assumed that the 7 days selected typify, from an Hg emissions standpoint, all other 7day periods. The simulation was done to mimic a response in 30-day rolling Hg emission
averages if the CaBr2 addition system was unavailable for 7 days. Equipment outages are
an infrequent but normal part of operating a power plant. A CaBr2 outage could result
from the lack of availability of CaBr2 or equipment failure. The 7-day period represents
an extreme case because CaBr2 systems are mechanically simple and a temporary system
to treat a full-scale system could be assembled from off-the-shelf components within a
few days. Shortages of CaBr2 can be effectively managed with a conservative
procurement program (i.e., storing large volumes of chemical onsite). The chemical is
readily available, and only 208 L (55 gallons) of 52% CaBr2 solution are needed to treat a
720 MW unit operating at full load for an entire day at Br concentration of 20 wt ppm on
the dry coal.
Figure 4.22 illustrates the effect of higher daily Hg emissions on 30-day rolling
Hg emission averages by the loss of the CaBr2 addition system. As expected, the system
outage adversely affected the 30-day rolling Hg emission averages, which increased to a
final value of 1.20 lb/TBtu, exactly equal to the MATS rule Hg limit. Utilities typically
desire to operate with emissions well below regulatory limit at all times, which is
typically referred to as compliance margin. If a utility wanted to maintain a 20%
compliance margin, then the effective MATS rule compliance limit would become 0.96
lb/TBtu. If a 20% compliance margin is added as a constraint here, a 5-day CaBr2 system
outage could be supported.
175
4.6.5
Summary
The hypothesis is true; CaBr2 addition lowered Hg emission sufficiently to meet
the MATS Hg limit of 1.2 lb/TBtu on a 30-day rolling average. Unit 4 had a range of 30day rolling Hg emission averages from a maximum value of 0.41 lb/TBtu and a minimum
value of 0.21 lb/TBtu, which included an instance of uncontrolled emissions during a
start-up event when the CaBr2 addition system was not in service. Additionally, short
periods without CaBr2 addition could be allowed without exceeding the MATS rule Hg
limit; in fact, Miller Unit 4 could support a 5-day continuous CaBr2 addition system
outage and still maintain a 20% compliance margin.
4.7
Hypothesis 6: The Presence of an SCR Can Greatly Reduce the Application Cost
of CaBr2 Injection Technology and Dramatically Improve the Cost Benefit of
Utilizing the Approach When Compared to Activated Carbon Injection into an
Existing Cold-side ESP
4.7.1
Economic Analysis of CaBr2 Addition
The results of this research were used to compare the MATS rule compliance cost
of employing CaBr2 addition with the compliance cost of activated carbon injection into
an existing cold-side ESP. Table 4.18 is a summary of CaBr2 addition information used
to determine usage cost.
In addition to using the assumptions in Table 4.18, the economic analysis
included information from Table 4.6 that yielded results for two cases. For Case 1, with
an SCR in service, a yearly volume of 16,461 gallons of 52 wt% CaBr2 solution with an
associated chemical cost of $208,774 was determined. For Case 2, without an SCR, a
176
yearly volume of 197,534 gallons of 52 wt% CaBr2 solution with an associated chemical
cost of $2,505,293 was found.
Table 4.18 Financial and Miller Unit 4 Operation Assumptions Used to Calculate Yearly
CaBr2 Chemical Costs
Item
Value
Units
10
lb/TBtu
800,000
lb/h
8,500
Btu/lb
Unit capacity factor
0.9
Dimensionless
Br/Hg ratio case 1
250
lb/lb
Br/Hg ratio case 2
3,000
lb/lb
CaBr2 solution cost
0.90
$/lb solution
PRB coal Hg content
Full load coal flow rate
Coal higher heating value
4.7.2
Economic Analysis of Activated Carbon Injection (ACI) into a Cold-side ESP
After a number of research and development programs sponsored by the
Department of Energy National Energy Technology Laboratory (DOE NETL) were
completed, Jones, et al. (2007) published consolidated findings regarding the technical
and commercial viability of Hg control technologies. This report included cost
information related to the use of ACI to remove Hg from the flue gases of various coal
types, including PRB. ACI into a cold-side ESP has been demonstrated as a viable
option for achieving 90% Hg reduction from PRB coal (Jones et al., 2007). This fact
177
enables determination of the relative efficacy of using CaBr2 addition as a cost-effective
option for MATS rule compliance by comparing the cost of these two options.
Table 4.19 lists the assumptions used to determine the cost of ACI into an existing
cold-side ESP to achieve compliance with the Hg portions of the MATS rule. Using the
assumptions in Table 4.18 reveals a yearly mass flow of 3,756,883 lb of activated carbon
at a cost of $3,569,039.
Table 4.19 Financial Assumptions Used to Calculate Activated Carbon Costs for
One Year of Operation at Miller Unit 4 With a 90% Hg Capture Goal
When the Unit Operated With a 90% Capacity Factor
Item
Value
Units
2,850,000
acfm
Average activated carbon concentrationb
2.79
lb/Macf
Unit capacity factor
0.90
Dimensionless
0.95
$/lb
Cold-side ESP inlet flue gas volumea
Activated carbon cost
b
3
6
3
Notes: acfm = actual ft /min; Macf = 10 ft .
a. Average gas volume measured during Phase I Method 17 testing.
b. Value from Jones, et al. (2007) to achieve 90% Hg removal on PRB coal.
4.7.3
Comparison Cost of 90% Hg Control
Jones et al. (2007) calculated the total direct cost for the ACI system, including
equipment cost, cost of materials and labor associated with site integration, applicable
taxes, and installation cost. Each approach (e.g. activated carbon injection and CaBr2
injection) requires an injection/addition system to introduce its active component to the
flue gas stream. Jones et al. (2007) calculated a total direct cost range of $3.82/kW to
178
$16.02/kW (2006 dollars) for ACI-related equipment. NRDC (2011) estimated a $2/kW
capital cost for CaBr2 addition equipment. The total direct cost were ignored in this
financial analysis, which likely favored the ACI approach and provided a conservative
estimate for any cost savings associated with CaBr2 addition.
This analysis also involved ignoring the balance of plant impact costs because
little is known about these costs associated with CaBr2 addition. Jones et al. (2007)
described substantial balance of plant costs associated with ACI. These costs stemmed
mainly from the loss of fly ash sales for concrete admixture usage. Jones et al. (2007)
estimated a roughly 2.5-fold increase in the $/lb Hg removed when the loss of fly ash
sales was considered. With an assumed fly ash total avoided cost value of $35/ton (fly
ash sales income and landfill avoidance cost) a $7M value was computed for fly ash sales
if the PRB coal arriving at Plant Miller was 8% ash and, 80% reported to the cold-side
ESP. Larrimore et al. (2008) reported that CaBr2 addition would not preclude the use of
fly ash within concrete admixtures. The decision to ignore the balance of plant effects
again likely favors the ACI approach and provided a conservative estimate for any cost
savings associated with CaBr2 addition.
Table 4.20 contains a summary of the cost of CaBr2 addition to achieve 90% Hg
control with and without an SCR present and includes the cost of ACI into an existing
cold-side ESP. The table includes only the reagent costs (chemical or carbon) and
excludes total direct costs and balance of plant impacts. It was assumed that these
exclusions favored ACI systems and provided a conservative comparison of the
approaches.
179
A significant differential exists between the costs of using CaBr2 addition with an
SCR in service and those incurred without an SCR. In comparison with the reagent cost
of ACI, the lower expense of either CaBr2 addition approach yields significant financial
savings.
Table 4.20 Comparison of CaBr2 and Activated Carbon Injection Reagent Costs
Associated With 90% Hg Removal From a Boiler Burning PRB Coal With
an SCR/Cold-side ESP/Wet FGD or Cold-side ESP/Wet FGD
Configuration
Br/Hg
Ratio
(lb/lb)
CaBr2
Yearly Cost
($M)
Activated
Carbon
Injection Rate
(lb/Macf)a
Activated
Carbon
Yearly Cost
($M)
Cold side ESP
and Wet FGD
3,000
2.505
2.79
3.57
SCR/Cold-side
ESP and Wet FGD
250
0.208
2.79
3.57
Note: Macf =106 ft3.
a. activated carbon rate based on the use of chemically treated carbon.
4.7.4
Summary
The presence of an SCR reactor greatly reduces the application cost of CaBr2
addition. With an SCR, the chemical reagent costs were an order of magnitude less. In
both cases of CaBr2 injection with and without an SCR, the compliance cost proved less
when compared to activated carbon injection into an existing cold-side ESP. The
financial analysis excluded total direct and balance of plant impact costs, but these costs
are likely much greater for activated carbon injection therefore the difference in costs is
likely much wider than shown here.
180
The analysis supported the hypothesis; the cost of compliance with the MATS
rule using CaBr2 injection is lower than compliance costs associated with using activated
carbon injection into an existing cold-side ESP.
181
CHAPTER 5
INTERPRETATIONS AND RECOMMENDATIONS
The study consisted of a three-phase program conducted at Alabama Power
Company’s Plant Miller Unit 4, a 700 MW PRB coal-fired power plant equipped with an
SCR, cold-side ESP and wet FGD, to evaluate the effectiveness of CaBr2 injection at
oxidizing and removing elemental Hg from flue gas. The goal was to determine whether
CaBr2 injection reduced emissions sufficiently to comply with the Hg portion of the
MATS rule limit of 1.2 lb/TBtu on a 30-day rolling average. The work yielded the
following conclusions:
•
The Plant Miller Unit 4 SCR possesses positive attributes that promote Hg
oxidation, including a space velocity less than 2,000 h-1, relative NOx activity
(K/Ko) greater than 0.7, and an operating temperature of 310 to 380 °C.
However, baseline Hg oxidation levels were insufficient to support MATS
rule compliance without additional technology, primarily because PRB coal
halogen content does not support high levels of Hg oxidation.
•
CaBr2 injection promotes Hg oxidation levels in excess of 90%, and the
presence of the SCR decreases ten-fold the amount of CaBr2 required to
achieve these levels of oxidation.
182
•
The presence of ammonia in the SCR has a minor affect on Hg oxidation. A
slightly higher concentration of bromine in the flue gas mitigates this effect.
•
The relative NOx activity (K/Ko) plays an active role in the oxidation of
mercury across the SCR. As the relative NOx activity ratio (K/Ko) decreases,
a higher concentration of bromine in the flue gas is needed to compensate for
less active catalyst.
•
Combined with a well functioning SCR, a Br/Hg ratio > 250 (lb/lb) results in
Hg oxidation and removal efficiencies exceeding 90%, if the captured Hg is
not reemitted from the wet FGD sump. For a non-SCR application, a Br/Hg
ratio > 3,000 (lb/lb) is recommended for similar Hg oxidation and removal
efficiencies.
•
Reemission of captured Hg represents a source of compliance risk for Hg
oxidation and capture techniques such as CaBr2 injection. Mercury
reemissions are a function of many wet FGD slurry parameters such as sulfite
concentration, chlorine and bromine concentrations, solid and liquid Hg
concentrations, and ORP. Significant Hg reemission events were not
observed during this investigation.
•
During the 83-day calcium bromide injection evaluation period, Unit 4 hourly
average mercury emissions had a mean of 0.26 µg/m3, with a standard
deviation of 0.16 µg/m3. During the 30 days before and after the evaluation
period, Unit 4 hourly average mercury emissions had a mean of 2.32 µg/m3
and a standard deviation of 0.92 µg/m3.
183
•
A statistically significant difference, t(3120) = 90.95, p < 0.01, existed
between hourly average Hg emissions with and without CaBr2 injection. A
Cohen’s d statistic value of 3.12 demonstrated that the CaBr2 was largely
responsible for the reduction of Hg emissions.
•
Changes in coal characteristics and operational factors such as unit load and
SCR ammonia flow rate affect Hg emissions but were shown to have minor
effects, when compared to the impact of CaBr2 injection.
•
CaBr2 injection lowers Hg emissions sufficiently to meet the MATS rule limit
of 1.2 lb/TBtu on a 30-day rolling average. During the 83-day long-term
evaluation, Unit 4 had a maximum 30-day rolling average Hg emission of
0.41 lb/TBtu and a minimum 30-day rolling Hg average emission of 0.21
lb/TBtu. The 30-day rolling averages included a start-up and shutdown event
during which emissions were uncontrolled. During the same 83-day period
Hg emissions on Unit 3, which is similar to Unit 4, were twice the MATS rule
limit.
•
Unit 4 could support a 5-day continuous CaBr2 injection system outage and
still maintain a MATS rule compliance margin of 20%.
•
The cost of using CaBr2 injection to achieve compliance with the MATS rule
is lower than the cost associated with using activated carbon injection into an
existing cold-side ESP. Yearly CaBr2 chemical costs are $208,774 with an
SCR and $2,505,293 without an SCR. In comparison, sorbent costs for
activated carbon injection into an existing cold-side ESP would be
$3,569,039.
184
CHAPTER 6
IMPLICATIONS FOR FURTHER RESEARCH
During the study, an opportunity did not exist to vary independent variables to
determine their effects on Hg oxidation behavior; neither did the study parameters enable
detailed research into the nature of Hg reemission from the wet FGD sump. Both areas
have implications in managing compliance risk for utilities. The following work is
proposed to address these concerns:
•
Additional fundamental work is needed to understand the impact of SO2
concentration on Hg oxidation via the chlorine and bromine Griffin reactions.
Vosteen et al. (2006) clearly articulated that Hg oxidation via bromine is
impacted less by SO2 than Hg oxidation via chlorine, but it is at some point
impacted nevertheless. Other experience, reported by Ghorishi et al. (2005),
Silcox et al. (2008), Buitrago et al. (2010), Niksa et al (2010), Smith et al.
(2011), and Otten et al. (2011) yielded conflicting findings concerning the
impact of SO2 on Hg oxidation with bromine, with some authors reporting
that SO2 does impact bromine-assisted Hg oxidation and others concluding
that SO2 does not affect bromine-assisted Hg oxidation. To resolve this
variation in results, it is suggested that researchers conducting bench-scale
experiments include in their studies variable SO2 concentration, homogeneous
185
and heterogeneous (native and SCR-based) oxidation pathways, and
replication of the power plant flue gas temperature profile from the
economizer outlet to the wet FGD inlet, that is vary simulated flue gas
temperatures from 700 to 55 °C. The upper temperature would represent
economizer inlet conditions and the lower temperature would represent wet
FGD inlet conditions. Simulated flue gas SO2 concentrations should be
representative of 0.3 to 2.5 wt % sulfur coals at a minimum.
•
More fundamental work is needed to increase understanding of the role of the
NOx relative catalyst activity ratio (K/Ko) in Hg oxidation. Even though
Dranga et al. (2012) described the importance of ammonia and catalyst
activity on Hg oxidation, technology users need additional guidance.
Quantification of the relationship between relative catalyst activity (K/Ko) and
Hg oxidation would allow users to properly manage their SCR catalyst
purchases to minimize NOx emissions and maximize Hg oxidation.
•
More fundamental work is needed regarding the parameters that affect Hg
reemission from wet FGD sumps. The relationships among factors that
govern Hg reemission remain incompletely understood, and this lack of
technical understanding hampers the ability of users to control Hg emissions
by leveraging the solubility of oxidized Hg. Although Blythe et al. (2008) and
Omine et al. (2010) provided a framework with which to better understand Hg
reemission, the industry has not yet obtained sufficient wet FGD chemistry
data to confirm the observations of researchers. The lack of full-scale, realtime wet FGD inlet and outlet flue gas Hg measurements leaves utilities
186
without sufficient information to correlate Hg reemission events and wet FGD
chemistry data. A coordinated effort between fundamental and applied
researchers will result in substantial progress in this area.
•
More fundamental work is needed to describe the mechanisms that control Hg
partitioning between solid and liquid phases in a wet FGD after the oxidized
Hg has been captured. An increase in understanding would provide utilities
with the knowledge necessary to better manage Hg remission risk.
•
Future full-scale CaBr2 injection tests should include taking coal samples
daily, to determine coal Hg content. The Br/Hg ratio (lb/lb), a key parameter
controlling Hg oxidation has not been a focus of previous research at fullscale. Because this ratio provides a proper basis on which to compare results
from different testing programs, parametric and continuous injection tests
should be designed around this parameter, rather than just the mass flow rate
of CaBr2 or Br concentration on the coal. Use of the Br/Hg ratio (lb/lb) would
enable technology adopters to determine the rate of bromide injection needed
for coals having varying Hg concentrations and facilitate the design of
injection equipment.
•
Little information exists regarding the anticipated balance-of-plant impacts
from full-time CaBr2 injection. For example, the potential impact of bromine
on plant materials, such as the corrosion behavior of boiler tube surfaces, air
heater surfaces, and wet FGD materials would greatly interest potential
technology users.
187
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Balcar, F., 1938. Method of Producing Chlorine. US Patent 2,204,172, filed July 22,
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Barnette, J.J. 2006. “Effect Size and Measures of Association.” Paper presented at
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Bhardwaj, R., Chen, X., Vidic, R.D. 2009. Impact of fly ash composition on mercury
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APPENDIX A
PHASES I, IIA, IIB, AND III BASELINE MERCURY OXIDATION INFORMATION
199
APPENDIX A
PHASES I, IIA, IIB, AND III BASELINE MERCURY OXIDATION INFORMATION
Phase
Equipment
Configuration
Measurement
Location
Total
Hg
Concentration
(µg/Nm3)
!!"#$#%&$
!!"!#$
Measurement
Average
Period
(Hr:Min)
Measurement
Technique
I
A
SCR Inlet
10.80
0.42
12
SCEM
I
A
SCR Outlet
13.80
0.44
12
SCEM
I
A
Wet FGD Inlet
8.20
0.59
12
SCEM
I
A
SCR Inlet
12.60
0.17
10
SCEM
I
A
SCR Outlet
11.20
0.17
10
SCEM
I
A
Wet FGD Inlet
9.30
0.62
10
SCEM
I
A
SCR Inlet
8.20
0.13
13
SCEM
I
A
SCR Outlet
7.50
0.58
13
SCEM
I
A
Wet FGD Inlet
6.00
0.58
13
SCEM
I
A
SCR Inlet
10.80
0.33
10
SCEM
I
A
SCR Outlet
8.70
0.32
10
SCEM
I
A
ESP Inlet
7.10
0.41
10
SCEM
I
A
Wet FGD Inlet
7.20
0.57
10
SCEM
I
A
SCR Inlet
12.30
0.15
10
SCEM
I
A
SCR Outlet
10.10
0.17
10
SCEM
I
A
ESP Inlet
8.70
0.40
10
SCEM
I
A
Wet FGD Inlet
8.60
0.66
2
SCEM
I
A
Wet FGD Inlet
9.50
0.56
2
OH
I
A
Wet FGD Inlet
11.80
0.64
2
OH
I
A
Wet FGD Inlet
11.90
0.67
2
OH
IIA
C
Wet FGD Inlet
5.20
0.64
2
OH
IIA
C
Wet FGD Inlet
5.22
0.62
2
OH
IIA
C
Wet FGD Inlet
6.88
0.61
2
OH
IIA
B
SCR Inlet
13.60
0.15
10
SCEM
IIA
B
SCR Outlet
4.60
0.41
6
SCEM
IIA
B
SCR Inlet
12.00
0.05
6
SCEM
IIA
B
SCR Outlet
5.10
0.50
6
SCEM
IIA
B
SCR Inlet
13.20
0.06
5:45
SCEM
IIA
B
SCR Outlet
8.00
0.57
5:45
SCEM
IIA
B
SCR Inlet
16.70
0.05
5
SCEM
200
Phase
Equipment
Configuration
Measurement
Location
Total
Hg
Concentration
(µg/Nm3)
!!"#$#%&$
!!"!#$
Measurement
Average
Period
Measurement
Technique
IIA
B
SCR Outlet
11.90
0.23
5
SCEM
IIA
B
SCR Outlet
8.00
0.37
6
SCEM
IIA
C
Wet FGD Inlet
5.40
0.46
9:30
SCEM
IIA
C
Wet FGD Inlet
7.70
0.35
10
SCEM
IIA
C
Wet FGD Inlet
4.40
0.54
10
SCEM
IIA
C
Wet FGD Inlet
8.00
0.57
4:15
SCEM
IIA
C
Wet FGD Inlet
9.40
0.46
4:15
SCEM
IIA
C
Wet FGD Inlet
7.30
0.51
6
SCEM
IIA
C
Wet FGD Inlet
4.30
0.52
9
SCEM
IIA
C
Wet FGD Inlet
5.20
0.46
9
SCEM
IIA
B
Wet FGD Inlet
8.40
0.81
6
SCEM
IIA
B
Wet FGD Inlet
10.50
0.65
5
SCEM
IIA
B
Wet FGD Inlet
16.50
0.85
6
SCEM
IIB
A
Wet FGD Inlet
4.67
0.53
2
OH
IIB
A
Wet FGD Inlet
5.11
0.54
2
OH
IIB
A
Wet FGD Inlet
4.80
0.49
2
OH
IIB
A
Wet FGD Inlet
5.57
0.54
2
OH
IIB
A
Wet FGD Inlet
4.40
0.29
8
SCEM
IIB
A
Wet FGD Inlet
4.30
0.42
8
SCEM
IIB
A
Wet FGD Inlet
5.60
0.46
8
SCEM
III
A
Wet FGD Inlet
6.40
0.55
2
OH
III
A
Wet FGD Inlet
4.97
0.52
2
OH
III
A
Wet FGD Inlet
4.76
0.56
2
OH
201
APPENDIX B
PHASES I, IIA, IIB, AND III COAL MERCURY CONCENTRATION
202
APPENDIX B
PHASES I, IIA, IIB AND III COAL MERCURY CONCENTRATION
Phase I
Phase IIA
Phase IIB
Phase III
Sample Hg Concentration Hg Concentration Hg Concentration Hg Concentration
(wt ppm)
(wt ppm)
(wt ppm)
(wt ppm)
1
0.048
0.058
0.062
0.074
2
0.107
0.041
0.070
0.061
3
0.056
0.046
0.105
0.030
4
0.085
0.058
0.060
0.043
5
0.057
0.045
0.055
0.047
6
0.091
0.054
0.058
0.052
7
0.059
0.057
n/a
0.047
8
0.080
0.045
n/a
0.051
9
n/a
n/a
n/a
0.034
10
n/a
n/a
n/a
0.049
11
n/a
n/a
n/a
0.032
Adapted from Table B-8 “The Evaluation of Calcium Bromide for Mercury Control at
Southern Company’s Plant Miller” by Dombrowski, K. et al., 2007 p. B-7. Copyright
2007 by EPRI. Reprinted with permission.
Adapted from Table 33 “The Evaluation of Calcium Bromide for Mercury Control at
Southern Company’s Plant Miller” by Dombrowski, K. et al., 2009 p. 3-51. Copyright
2009 by EPRI. Reprinted with permission.
Adapted from B-13 “The Evaluation of Calcium Bromide for Mercury Control at
Southern Company’s Plant Miller” by Dombrowski, K. et al., 2009 p. B-14. Copyright
2009 by EPRI. Reprinted with permission.
Adapted from Table B-14 “Three-Month Evaluation of Furnace Addition of Calcium
Bromide for Mercury Emissions Control at Southern Company’s Plant Miller” by
Dombrowski, K. et al., 2011 p. B-16. Copyright 2011 by Southern Company Serivces.
Reprinted with permission.
203
APPENDIX C
NORMALITY ANALYSIS
204
APPENDIX C.1
NORMALITY OF UNIT 3 HOURLY MERCURY EMISSIONS DURING JANUARY
2011
Appendix C.1 includes the analysis for determining the normality of Unit 3 hourly
average Hg emissions data from January 1, 2011, through January 30, 2011, while CaBr2
was not being added to Unit 4. Figure C.1 is a histogram of Unit 3 hourly averaged Hg
emissions during the period of interest. The histogram plots frequency of Hg emissions
in particular concentration ranges. The graph includes a line representing the frequency
of a normal distribution.
Figure C.1 Histogram of Unit 3 hourly average Hg emissions (µg/m3) from January 1-30,
2011, while CaBr2 was not added to the coal on Unit 4.
205
The histogram shows that the data are nearly normal. The most frequently
observed hourly average Hg emissions appear near the center of the distribution, and the
data do not appear skewed. Additionally, the frequency magnitudes appear near the
normal distribution.
Figure C.2 charts expected cumulative probability versus observed cumulative
probability (P-P plot). A normal dataset would have a P-P plot that is a straight-line, in
other words, observed values for the data equal the expected values of normally
distributed data.
Figure C.2 Normal expected cumulative probability versus observed cumulative
probability (P-P Plot) of Unit 3 hourly average Hg emissions (µg/m3) from
January 1, 2011, to January 30, 2011, while CaBr2 was not added to the coal
on Unit 4.
206
Figure C.2 shows that observed cumulative probability is close to expected
cumulative probability with small variations. At some points, within the P-P plot, the
observed behavior exceeds predicted behavior, at some points the converse is true.
Nevertheless, the data are nearly normal using the graphical methods in Figures C.1 and
C.2.
Table C.1 provides summary information regarding the Unit 3 hourly averaged
Hg emissions during January 1-30, 2011. The table includes the mean, standard
deviation, skewness, kurtosis, and the Jarque-Bera (JB) statistic. Skewness measures the
asymmetry of the data around the mean. The skewness of a normal distribution is zero.
Kurtosis measures the fraction of outliers in a distribution (i.e., whether the data
are peaked or flat relative to a normal distribution). A large value means that the dataset
is peaked about the mean, and a low value indicates relatively flat values about the mean.
A normal distribution has a kurtosis value of 3. The SPSS value of kurtosis is adjusted
for normality (i.e., K-3), therefore a value of zero indicates a normal distribution.
The JB statistic is a measure of normality, follows a Chi-squared distribution with
a degree of freedom of 2, and can be used to quantitatively test for normality.
The summary statistics tabulated in Table C.1 does not support the conclusion
drawn from Figures C.1 and C.2 that the data are nearly normally distributed. The values
of skewness and kurtosis are close to zero but are slightly negative, indicating more of the
data points are above the mean and that the frequencies are below the normal distribution.
This distribution is slightly flatter than a normal distribution.
Table C.1 Summary Statistics of the Unit 3 Hourly Average Hg Emissions (µg/m3) from
January 1, 2011, to January 30, 2011, while CaBr2 was Not Added to the Coal
on Unit 4.
207
Statistic
Value
Unit
Sample size
719
n/a
Mean
2.6434
µg/m3
Standard deviation
1.0136
µg/m3
Kurtosisa
-0.012
n/a
-0.635
n/a
12.09
n/a
Skewness
Jarque-Bera (JB)
b
Note:
a. Kurtosis calculated by SPSS has been adjusted. A value of zero represents a
normal distribution.
b. Jarque-Bera statistic formula has been adjusted for excess kurtosis.
The JB statistic is large (12.09). After applying the Chi-squared distribution (df =
2) the hypothesis that Unit 3 hourly average Hg emissions from January 1-30, 2011, were
normal was rejected (p < .01).
208
APPENDIX C.2
NORMALITY OF UNIT 3 HOURLY MERCURY EMISSIONS DURING
SEPTEMBER 2010
Appendix C.2 includes the analysis for determining the normality of the Unit 3
hourly average Hg emissions data from September 1-30, 2010, while CaBr2 was not
being added to Unit 4. Figure C.3 is a histogram of the Unit 3 hourly averaged Hg
emissions during the period of interest. The histogram plots the frequency of Hg
emissions in particular concentration ranges. The graph includes a line representing the
frequency of a normal distribution.
Figure C.3 Histogram of Unit 3 hourly average Hg emissions (µg/m3) from September 130, 2010 while CaBr2 was not added to the coal on Unit 4.
209
The histogram shows that the data are nearly normal but do not exhibit normal
behavior. The most frequently observed hourly average Hg emissions are near the center
of the distribution, and the distribution appears to have a long tail with more of the data
values above the mean, this would indicate positive skewness.
Figure C.4 charts an expected cumulative probability versus observed cumulative
probability (P-P plot). A normal dataset would have a P-P plot that is a straight line; that
is observed values equal the expected values of a normally distributed dataset.
Figure C.4 Normal expected cumulative probability versus observed cumulative
probability (P-P Plot) of Unit 3 hourly average Hg emissions (µg/m3) from
September 1-30, 2010 while CaBr2 was not added to the coal on Unit 4.
210
Figure C.4 shows that observed cumulative probability is close to expected
cumulative probability with some variations. At some points, within the P-P plot, the
observed behavior exceeds predicted behavior and at some points the converse is true,
nevertheless the data are nearly normal using the graphical methods in Figures C.3 and
C.4.
Table C.2 provides summary information regarding the Unit 3 hourly averaged
Hg emissions during September 1-30, 2010. The table includes the mean, standard
deviation, skewness, kurtosis, and the JB statistic. Skewness measures the asymmetry of
the data around the mean, and the skewness of a normal distribution is zero.
Kurtosis measures the fraction of outliers in a distribution (i.e., whether the data
are peaked or flat relative to a normal distribution). A large value means the dataset is
peaked about the mean, and a low value indicates relatively flat values about the mean.
A normal distribution has a kurtosis value of 3. The SPSS value of kurtosis is adjusted
for normality (i.e., K-3), therefore a value of zero indicates a normal distribution.
The JB statistic is a measure of normality, follows a Chi-squared distribution with
a degree of freedom of 2, and can be used to quantitatively test for normality.
The summary statistics tabulated in Table C.2 support the conclusions drawn from
Figures C.3 and C.4 that the data are not normally distributed. A large positive value of
skewness (2.334) indicates that a majority of the data points are above the mean, and a
negative value of kurtosis indicates that the distribution is flatter than a normal
distribution.
211
Table C.2 Summary Normality Statistics of Unit 3 Hourly Average Hg Emissions
(µg/m3) from September 1-30, 2010, While CaBr2 Was Not Added to the Coal
on Unit 4.
Statistic
Value
Unit
Sample size
695
n/a
Mean
3.8239
µg/m3
Standard deviation
0.8283
µg/m3
Kurtosisa
-0.862
n/a
2.334
n/a
244
n/a
Skewness
Jarque-Bera (JB)
b
Note:
a. Kurtosis calculated by SPSS has been adjusted. A value of zero represents a
normal distribution.
b. Jarque-Bera statistic formula has been adjusted for excess kurtosis.
The JB statistic is large (244). When the Chi-squared Distribution (df = 2) was
used, the hypothesis that the Unit 3 hourly average Hg emissions from September 1-30,
2010, were normal was rejected.
212
APPENDIX C.3
NORMALITY OF UNIT 3 PHASE III HOURLY MERCURY EMISSIONS
Appendix C.3 includes the analysis for determining the normality of the Unit 3
Hg hourly average emissions data from October 1, 2010, through December 19, 2010,
during the addition of CaBr2 to the coal on Unit 4. Figure C.5 is a histogram of the Unit
3 hourly averaged Hg emissions during the period of interest. The histogram plots the
frequency of Hg emissions in particular concentration ranges. The graph includes a line
representing the frequency of a normal distribution.
Figure C.5 Histogram of hourly average Unit 3 Hg emissions (µg/m3) from October 1,
2010, to December 19, 2010 during CaBr2 addition to the coal on Unit 4.
213
Figure C.5 shows that the data are near normal. The most frequently observed
hourly average Hg emissions are near the center of the distribution and the tails are even
on both sides of the mean. There does appear to be a slightly higher number of observed
data points to the left of the mean so the data may be slightly negatively skewed.
Figure C.6 plots expected cumulative probability versus observed cumulative
probability (P-P plot). A normal dataset has a P-P plot that is a straight-line meaning;
that is observed values equal the expected values of a dataset that is normally distributed.
Figure C.6 Normal expected cumulative probability versus observed cumulative
probability (P-P plot) of Unit 3 hourly average Hg emissions (µg/m3) from
October 1, 2010, through December 19, 2010 during CaBr2 addition to the
coal on Unit 4.
214
Figure C.6 shows that the Unit 3 hourly averaged Hg emissions from October 1,
2010 through December 19, 2010, exhibited near normal behavior.
Table C.3 provides summary information regarding the Unit 3 hourly averaged
Hg emissions from October 1, 2010 through December 19, 2010. The table includes the
mean, standard deviation, skewness, kurtosis, and the JB statistic. Skewness measures
the asymmetry of the data around the mean, and the skewness of a normal distribution is
zero.
Kurtosis measures the fraction of outliers in a distribution (i.e., whether the data
are peaked or flat relative to a normal distribution). A large value means the dataset is
peaked about the mean, and a low value indicates relatively flat values about the mean.
A normal distribution has a kurtosis value of 3. The SPSS value of kurtosis is adjusted
for normality (i.e., K-3), therefore a value of zero indicates a normal distribution.
The JB statistic is a measure of normality, follows a Chi-squared distribution with
a degree of freedom of 2, and can be used to quantitatively test for normality.
The summary information in Table C.3 supports the conclusions drawn from
Figures C.5 and C.6; the data are nearly normally distributed, with the exception of the
JB statistic. The values of both skewness and kurtosis are near zero. The slightly
negative value of skewness means that more of the data points in the dataset fall below
the mean of 2.904 µg/m3 than fall above the mean. The skewness is very difficult to
observe visually from Figure C.5.
215
Table C.3 Summary Normality Statistics of Unit 3 Hourly Average Hg Emissions
(µg/m3) from October 1, 2010 through December 19, 2010 During CaBr2
Addition to the Coal on Unit 4.
Statistic
Value
Unit
Sample size
1,738
n/a
Mean
2.904
µg/m3
Standard deviation
1.005
µg/m3
Kurtosisa
-0.023
n/a
-0.192
n/a
10.7
n/a
Skewness
Jarque-Bera (JB)
b
Note:
a. Kurtosis calculated by SPSS has been adjusted. A value of zero represents a
normal distribution.
b. Jarque-Bera statistic formula has been adjusted for excess kurtosis.
The JB statistic is low, with a value of 10.7. Using the Chi-squared distribution
(df = 2) led to the rejection of the hypothesis that the Unit 3 hourly average Hg emissions
from October 1, 2010 through December 19, 2010, were normal (p < .05). Although
Figures C.5 and C.6 appear to indicate nearly normal dataset, the use of statistical
methods caused the hypothesis that the dataset is normal to be rejected.
216
APPENDIX C.4
NORMALITY OF UNIT 4 HOURLY MERCURY EMISSIONS
DURING JANUARY 2011
Appendix C.4 includes the analysis for determining the normality of the Unit 4
hourly average Hg emissions data from January 1-30, 2011, while CaBr2 was not being
added to Unit 4. Figure C.7 is a plotted histogram of the Unit 4 hourly average Hg
emissions during the period of interest. The histogram plots frequency of Hg emissions
in particular concentration ranges. The graph includes a line representing the frequency
of a normal distribution.
Figure C.7 Histogram of Unit 4 hourly average Hg emissions (µg/m3) from January 1-30,
2011, while CaBr2 was not added to the coal on Unit 4.
217
Figure C.7 shows that the data are not normal and that a cluster of values
surrounds the mean, which will likely mean that the kurtosis will be positive. The most
frequently observed hourly average Hg emissions appear slightly to the right of the center
of the distribution that is the data appear to be positively skewed.
Figure C.8 plots an expected cumulative probability versus observed cumulative
probability chart (P-P plot). A normal dataset has a P-P plot that is a straight line; that is
observed values equal the expected values of a normally distributed dataset.
Figure C.8 Normal expected probability versus observed probability (P-P Plot) of hourly
average Unit 4 Hg emissions (µg/m3) from January 1-30, 2011, while CaBr2
was not added to the coal on Unit 4.
218
Figure C.8 shows that, for the most part, the observed values equal the expected
values for a normal distribution. The exception occurs towards the left portion of the
distribution, where the observed values occur more often than expected. This behavior
can be observed also in Figure C.8 when the frequency bins are above the normal curve
in the histogram. In Figure C.7 and C.8, the dataset appears nearly normal.
Table C.4 provides summary information regarding Unit 4 hourly average Hg
emissions during January 1-30, 2011. The table includes the mean, standard deviation,
skewness, kurtosis, and the JB statistic. Skewness measures the asymmetry of the data
around the mean, and the skewness of a normal distribution is zero.
Kurtosis measures the fraction of outliers in a distribution (i.e., whether the data
are peaked or flat relative to a normal distribution). A large value means the dataset is
peaked about the mean, and a low value indicates relatively flat values about the mean.
A normal distribution has a kurtosis value of 3. The SPSS value of kurtosis is adjusted
for normality (i.e., K-3), therefore a value of zero indicates a normal distribution.
The JB statistic is a measure of normality, follows a Chi-squared distribution with
a degree of freedom of 2, and can be used to quantitatively test for normality.
The summary statistics tabulated in Table C.4 support the conclusions drawn from
Figures C.7 and C.8 that the data are not normally distributed. The kurtosis was positive
a result that supports the earlier assertions derived from Figure C.7; also the data was
peaked around the center. Additionally, the conclusions drawn from the figures support
the likelihood that the distribution was positively skewed.
219
Table C.4 Summary Statistics of the Hourly Average Unit 4 Hg Emissions (µg/m3) from
January 1-30, 2011, While CaBr2 Was Not Added to the Coal.
Statistic
Value
Unit
Sample size
707
n/a
Mean
2.1820
µg/m3
Standard deviation
0.6712
µg/m3
Kurtosisa
0.775
n/a
Skewness
0.081
n/a
Jarque-Bera (JB)b
18.46
n/a
Note:
a. Kurtosis calculated by SPSS has been adjusted. A value of zero represents a
normal distribution.
b. Jarque-Bera Statistic formula has been adjusted for excess kurtosis.
The JB statistic was large (18.46). Using the Chi-squared distribution (df = 2)
resulted in the rejection of the hypothesis that the Unit 4 hourly average Hg emissions
from September 1-30, 2010, were normal. The nearly normal appearance from Figures
C.7 and C.8 is not supported statistically.
220
APPENDIX C.5
NORMALITY OF UNIT 4 HOURLY MERCURY EMISSIONS
DURING SEPTEMBER 2010
Appendix C.5 includes the analysis for determining the normality of the Unit 4
hourly average Hg emissions data from September 1-30, 2010, while CaBr2 was not
being added to Unit 4. Figure C.9 is a histogram of the Unit 4 hourly averaged Hg
emissions during the period of interest. The histogram plots frequency of Hg emissions
in particular concentration ranges. The graph includes a line representing the frequency
of a normal distribution.
Figure C.9 Histogram of Unit 4 hourly average Hg Emissions (µg/m3) from September 130, 2010, while CaBr2 was not added to the coal on Unit 4.
221
Figure C.9 shows that the data are not normal. The most frequently observed
hourly average Hg emissions appear to the right of the center of the distribution and the
frequency magnitudes appear to be below the normal distribution curve so a low value for
kurtosis is expected.
Figure C.10 charts expected cumulative probability versus observed cumulative
probability (P-P plot). A normal dataset has a P-P plot that is a straight line; that is
observed values equal the expected values of a normally distributed dataset.
Figure C.10 Normal expected cumulative probability versus observed cumulative
probability (P-P Plot) of Unit 4 hourly average Hg emissions (µg/m3) from
September 1- 30, 2010, while CaBr2 was not added to the coal on Unit 4.
222
Figure C.10 shows a departure from normal behavior at the center of the
distribution. This departure can be observed in Figure C.9 when the magnitude of the
frequency bins is above the normal distribution curve. After this point, the P-P plot
returns to ideal normal behavior. It should be expected that the skewness of the dataset
will be large and positive and that the kurtosis will be near zero, indicating a flatter than
normal distribution curve.
Table C.5 provides summary information regarding the Unit 4 hourly averaged
Hg emissions during September 1-30, 2010. The table includes the mean, standard
deviation, skewness, kurtosis, and the JB statistic. Skewness measures the asymmetry of
the data around the mean, and the skewness of a normal distribution is zero.
Kurtosis measures the fraction of outliers in a distribution (i.e., whether the data
are peaked or flat relative to a normal distribution). A large value means the dataset is
peaked about the mean, and a low value indicates relatively flat values about the mean.
A normal distribution has a kurtosis value of 3. The SPSS value of kurtosis is adjusted
for normality (i.e., K-3), therefore a value of zero indicates a normal distribution.
The JB statistic is a measure of normality, follows a Chi-squared distribution with
a degree of freedom of 2, and can be used to quantitatively test for normality.
The summary statistics tabulated in Table C.5 support the conclusions drawn from
Figures C.9 and C.10 that the data are not normally distributed. The kurtosis was slightly
negative which supports the earlier assertions from Figures C.9 and C.10.
223
Table C.5 Summary Statistics of the Unit 4 Hourly Average Hg Emissions (µg/m3) from
September 1-30, 2010, while CaBr2 was not added to the coal on Unit 4.
Statistic
Value
Unit
Sample size
690
n/a
Mean
2.5493
µg/m3
Standard deviation
1.0447
µg/m3
Kurtosisa
-0.390
n/a
Skewness
-0.662
n/a
Jarque-Bera (JB)b
30.09
n/a
Note:
a. Kurtosis calculated by SPSS has been adjusted. A value of zero represents a
normal distribution.
b. Jarque-Bera statistic formula has been adjusted for excess kurtosis.
The JB statistic is large (30.09). Using the Chi-squared distribution (df =2 )
resulted in the rejection of the hypothesis that the Unit 4 hourly average Hg emissions
from September 1, 2010, through September 30, 2010, were normal.
224
APPENDIX C.6
NORMALITY OF UNIT 4 PHASE III HOURLY MERCURY EMISSIONS
Appendix C.6 includes the analysis for determining the normality of the Unit 4
Hg emissions data from October 1, 2010, through December 19, 2010, during CaBr2
addition. Figure C.11 is a plotted histogram of the Unit 4 hourly averaged Hg emissions
during the period of interest. The histogram plots frequency of Hg emissions in
particular concentration ranges. The graph includes a line representing the frequency of a
normal distribution.
Figure C.11 Histogram of Unit 4 hourly average Hg emissions (µg/m3) from
October 1, 2010, through December 19, 2010, during CaBr2 addition to
the coal on Unit 4.
225
Figure C.11 shows that the data were not normal. The most frequently observed
hourly average Hg emissions are near the center of the distribution, but slightly to the left
of the mean but has a long tail to the right. The dataset is pinned on the left end of the
axis because values below zero cannot occur.
Figure C.12 charts expected cumulative probability versus observed cumulative
probability (P-P plot). A normal dataset has a P-P plot that is a straight line; that is
observed values equal the expected values of a normally distributed dataset.
Figure C.12 Normal expected cumulative probability versus observed cumulative
probability (P-P plot) of Unit 4 Hg hourly average emissions (µg/m3) from
October 1, 2010, through December 19, 2010, during CaBr2 addition to the
coal on Unit 4.
226
Figure C.12 shows that, at times, the observed behavior occurs more often than
expected and that at other times, observed behavior is less than expected. This figure
demonstrates that the dataset does not exhibit normal behavior.
Table C.6 provides summary information regarding the hourly averaged Hg
emissions from Unit 4 during October 1, 2010, through December 19, 2010. The table
includes the mean, standard deviation, skewness, kurtosis, and the JB statistic. Skewness
measures the asymmetry of the data around the mean, and the skewness of a normal
distribution is zero.
Kurtosis measures the fraction of outliers in a distribution (i.e., whether the data
are peaked or flat relative to a normal distribution). A large value means the dataset is
peaked about the mean, and a low value indicates relatively flat values about the mean.
A normal distribution has a kurtosis value of 3. The SPSS value of kurtosis is adjusted
for normality (i.e., K-3), therefore a value of zero indicates a normal distribution.
The JB statistic is a measure of normality, follows a Chi-squared distribution with
a degree of freedom of 2, and can be used to quantitatively test for normality.
The summary information in Table C.6 supports the conclusions drawn from
Figures C.11 and C.12 that the data are not normally distributed. The large value for
kurtosis (18.304) demonstrates numerically that the data set is peaked about the mean and
drops sharply at the edges. This behavior is easily observed in Figure C.11. The positive
value of skewness indicates that more values in the dataset fall to the left of the mean and
that the distribution has a long tail to the right of the mean.
227
Table C.6 Summary Normality Statistics of the Unit 4 Hourly Average Hg Emissions
(µg/m3) from October 1, 2010, to December 19, 2010, During CaBr2 Addition
to the Coal on Unit 4
Statistic
Value
Unit
Sample size
1,689
n/a
Mean
0.2605
µg/m3
Standard deviation
0.1568
µg/m3
Kurtosisa
18.304
n/a
2.871
n/a
25,898
n/a
Skewness
Jarque-Bera (JB)
b
Note:
a. Kurtosis calculated by SPSS has been adjusted. A value of zero represents a
normal distribution.
b. Jarque-Bera statistic formula has been adjusted for excess kurtosis.
The JB statistic is large (25,898). Using the Chi-squared distribution (df =2 )
resulted in the rejection of the hypothesis that the Unit 4 hourly average Hg emissions,
during October 1, 2010, through December 19, 2010, were normal.
228
APPENDIX D
STATISTICAL TEST RESULTS
229
APPENDIX D.1
INDEPENDENT T-TEST RESULTS FROM COMPARING UNIT 3 MERCURY
EMISSIONS WITH AND WITHOUT CALCIUM BROMINE ADDITION
ON UNIT 4
Hypothesis Tested
µBr = µNo,Br
Table D.1 Output From SPSS Testing The Hypothesis If Unit 3 Hg Emissions During
CaBr2 Addition On Unit 4 Are Equal To Unit 3 Hg Emissions Without CaBr2
Addition On Unit 4. Data Consists Of Hourly Hg Emission Averages Taken
From September 1, 2010, Through January 30, 2011.
Table D.2 Output from SPSS Providing Sample Size, Mean, and Standard Deviation of
Unit 3 Hg Emissions During Phase III, Pre-testing and Post-test Periods
Grouped by CaBr2 Condition. Data Consists Of Hourly Hg Emission Averages
Taken From September 1, 2010, Through January 30, 2011.
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APPENDIX D.2
INDEPENDENT T-TEST RESULTS FROM COMPARING UNIT 4 MERCURY
EMISSIONS WITHOUT CALCIUM BROMINE ADDITION
ON UNIT 4
Hypothesis Tested
µSeptember = µJanuary
Table D.3 Output From SPSS Testing The Hypothesis If Unit 4 Hourly Average Hg
Emissions During Period Without CaBr2 Addition (September 1-30, 2010) Are
Equal To Unit 4 Hourly Average Hg Emissions Period Without CaBr2
Addition (January 1-30, 2011).
Table D.4 Output From SPSS Providing Sample Size, Mean, And Standard Deviation of
Phase III Unit 4 Hourly Average Hg Emissions One Month Before (September
1-30, 2010) And After (January 1-30, 2011). 9 Denotes September And
January Is Denoted By 1.
231
APPENDIX D.3
INDEPENDENT T-TEST RESULTS FROM COMPARING UNIT 4 MERCURY
EMISSIONS WITH AND WITHOUT CALCIUM BROMINE ADDITION
ON UNIT 4
Hypothesis Tested
µBr = µNo,Br
Table D.5 Output From SPSS Testing The Hypothesis If Unit 4 Hourly Average Hg
Emissions During Period Without CaBr2 Addition On Unit 4 (September 1-30,
2010, and January 1-30, 2011) Are Equal To Unit 4 Hourly Average Hg
Emissions During Period With CaBr2 Addition On Unit 4 (October 1, 2010,
Through December 19, 2010).
Table D.6 Output From SPSS Providing Sample Size, Mean, And Standard Deviation of
Unit 4 Hourly Average Hg Emissions During Period Without CaBr2 Addition
On Unit 4 (September 1-30, 2010, and January 1-30, 2011) And Unit 4 Hourly
Average Hg Emissions During Period With CaBr2 Addition On Unit 4
(October 1, 2010 Through December 19, 2010)
232
APPENDIX D.4
PAIRED T-TEST RESULTS FROM COMPARING UNIT 3 AND UNIT 4 MERCURY
EMISSIONS DURING CALCIUM BROMINE ADDITION ON UNIT 4
Hypothesis Tested
µ3 U4,Br = µ4 U4,Br
Table D.7 Output From SPSS Testing The Hypothesis If Unit 3 Hourly Average Hg
Emissions During Period With CaBr2 Addition On Unit 4 (October 1, 2010,
Through November 30, 2010) Are Equal To Unit 4 Hg Emissions During
Period With CaBr2 Addition On Unit 4 (October 1, 2010, Through November
30, 2010).
Table D.8 Output From SPSS Providing Sample Size, Mean, And Standard Deviation Of
Unit 3 Hourly Average Hg Emissions During Period With CaBr2 Addition On
Unit 4 (October 1, 2010, Through November 30, 2010) And Unit 4 Hourly
Average Hg Emissions During Period With CaBr2 Addition On Unit 4
(October 1, 2010, Through November 30, 2010)
233
APPENDIX D.5
WILCOX RANKED SIGN TEST RESULTS FROM COMPARING UNIT 3 AND UNIT
4 30-DAY ROLLING AVERAGE MERCURY EMISSION RATE DURING CALCIUM
BROMINE ADDITION ON UNIT 4
Hypothesis Tested
µ3 U4,Br = µ4 U4,Br
Figure D.9 Output from SPSS testing the hypothesis if Unit 3 Hg emission rate 30-day
rolling averages during period with CaBr2 addition on Unit 4 (October 1,
2010, through November 30, 2010) were equal to Unit 4 Hg emission rate 30day rolling averages during period with CaBr2 addition on Unit 4 (October 1,
2010, through November 30, 2010) using the Wilcox Signed Rank Test.
234