United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park, NC 27711
EPA-453/R-96-002
Final Report
November 1995
Air
&EPA. PHASE II NOY CONTROLS
FOR THE MARAMA AND
NESCAUM REGIONS
Northeast States
for Coordinated
Air Use Management
(NESCAUM)
MID-
ATLANTIC
REGIONAL
AIR
MANAGEMENT
ASSOCIATION
-------
EPA-453/R-96-002
PHASE H NOX CONTROLS FOR THE
MARAMA AND NESCAUM REGIONS
Sponsored by
Emission Standards Division
Office of Air Quality Planning and Standards
U. S. Environmental Protection Agency
Research Triangle Park, NC 27711
and
Mid-Atlantic Regional Air Management Association
115 Pine Street
Harrisburg, PA 17101
and
Northeast States for Coordinated Air Use Management
129 Portland Street
Boston, MA 02114
November 1995
-------
DISCLAIMER
This report is issued by the Emission Standards Division,
Office of Air Quality Planning and Standards, U. S. Environmental
Protection Agency, to provide information to State and local air
pollution control agencies. Mention of trade names and commercial
products is not intended to constitute endorsement or
; recommendation for use. Copies of this report are available - as
. ""(
C
'•' supplies last- from the Library Services Office (MD-35), U. S.
Environmental Protection Agency, Research Triangle Park, North
j
v\ Carolina 27711 ([919] 541-5514) or, for a nominal fee, from the
National Technical Information Service, 5285 Port Royal Road,
Springfield, VA 22161 ([800] 553-NTIS).
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ACKNOWLEDGMENTS
This project was funded by the U.S. Environmental Protection Agency's Office of Air
Quality Planning and Standards(OAQPS), the Mid-Atlantic Regional Air Management
Association (MARAMA), and the Northeast States for Coordinated Air Use Management
(NESCAUM).
The project was managed by Bill Neuffer and Ken Durkee of the U. S. EPA's Emission
Standards Division of OAQPS, Jim Hambright of MARAMA and Praveen Amar of NESCAUM.
In addition, Acurex Environmental was assisted in the development of this document by the
NESCAUM Stationary Source Review Committee. A draft of this document was distributed for
review to associations representing the utility companies, air pollution control vendors and the
natural gas industry.
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TABLE OF CONTENTS
GLOSSARY ix
CHAPTER 1 SUMMARY 1-1
1.1 UTILITY BOILER NOX INVENTORY AND
INDUSTRY TRENDS 1-2
1.2 POST-RACT NOX CONTROLS 1-7
1.3 COST OF CONTROLS 1-16
CHAPTER 2 BOILER AND EMISSIONS PROFILES IN MARAMA AND
NESCAUM STATES 2-1
2.1 FUEL TYPES AND FIRING CAPACITIES 2-2
2.2 AGE OF BOILERS AND CAPACITY FACTORS 2-6
2.3 NOX EMISSIONS 2-12
2.4 RACT CONTROLS 2-21
2.5 TRENDS IN UTILITY POWER GENERATION 2-26
REFERENCES FOR CHAPTER 2 2-30
CHAPTER 3 PHASE II NOY CONTROL OPTIONS 3-1
A
3.1 NATURAL-GAS-BASED CONTROLS 3-9
3.1.1 Cofiring 3-11
3.1.2 Reburning 3-17
3.1.3 Gas Conversion 3-26
3.1.4 Potential for Retrofit of Gas-based Controls 3-32
3.2 COAL REBURNING 3-36
3.3 NONCATALYTIC FLUE GAS TREATMENT
CONTROLS 3-40
3.4 CATALYTIC FLUE GAS TREATMENT CONTROLS 3-53
3.4.1 In-duct SCR Systems 3-59
3.4.2 AH-SCR Systems 3-63
3.4.3 Full-Scale SCR Systems 3-65
3.5 COMBINED TECHNOLOGIES 3-69
3.5.1 Advanced Gas Reburning 3-69
3.5.2 SNCR and SCR 3-71
3.5.3 Combined NOX/SOX 3-75
3.6 SEASONAL CONTROLS 3-76
3.6.1 Seasonal Gas Use 3-76
3.6.2 Seasonal Flue Gas Treatment 3-78
iii
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TABLE OF CONTENTS (CONCLUDED)
3.7 SUMMARY 3-79
REFERENCES FOR CHAPTER 3 3-83
CHAPTER 4 COST OF POST-RACT CONTROLS 4-1
4.1 COST OF GAS-BASED CONTROLS 4-8
4.1.1 Cost of Natural Gas Reburning 4-9
4.1.2 Cost of Gas Conversions 4-12
4.2 COST OF SNCR 4-14
4.3 COST OF SCR 4-16
4.3.1 Cost of In-duct SCR 4-18
4.3.2 Cost of CAT-AH 4-20
4.3.3 Cost of Full-scale SCR 4-23
4.4 COST OF HYBRID CONTROLS 4-29
4.5 COST OF SEASONAL CONTROLS 4-31
4.6 SUMMARY 4-36
REFERENCES FOR CHAPTER 4 4-40
APPENDIX A — OTC MEMORANDUM OF UNDERSTANDING A-l
APPENDIX B — POST-RACT NESCAUM UTILITY BOILER
AND NOX INVENTORY
APPENDIX C —POST-RACT MARAMA UTILITY BOILER AND NOX
INVENTORY C-l
APPENDIX D — COST DETAIL D-l
AND NOX INVENTORY B-l
IV
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LIST OF ILLUSTRATIONS
Figure 1-1 Post-RACT 1995 utility boiler NOX emissions by state —
NESCAUM region 1-3
Figure 1-2 Post-RACT 1995 utility boiler NOX emissions by state —
MARAMA region 1-3
Figure 1-3 Post-RACT 1995 utility boiler control technologies — coal-fired
NOX emissions 1-5
Figure 1-4 Post-RACT 1995 utility boiler control technologies — projected
oil/gas-fired NOX emissions 1-5
Figure 1-5 Cost effectiveness of controls used all year around 1-21
Figure 1-6 Cost effectiveness of controls used on a seasonal basis 1-21
Figure 2-1 1995 utility boiler capacity by region and primary fuel 2-5
Figure 2-2 1995 utility boiler capacity by state — NESCAUM region 2-5
Figure 2-3 1995 utility boiler capacity by state and firing type — NESCAUM
region 2-6
Figure 2-4 1995 utility boiler capacity by state — MARAMA region 2-7
Figure 2-5 1995 utility boiler capacity by state and firing type — MARAMA
region 2-7
Figure 2-6 1995 utility boiler capacity versus age — NESCAUM region 2-9
Figure 2-7 1995 utility boiler capacity versus age — MARAMA region 2-9
Figure 2-8 1995 utility boiler total capacity versus age — NESCAUM region 2-10
Figure 2-9 1995 utility boiler total capacity versus age — MARAMA region 2-10
Figure 2-10 1995 utility boiler total capacity factor — NESCAUM region 2-11
Figure 2-11 1995 utility boiler total capacity versus capacity factor —
MARAMA region 2-11
Figure 2-12 1995 NOX emission factors and loading — coal-fired boilers in
NESCAUM 2-14
Figure 2-13 1995 NOX emission factors and loading — oil-/gas-fired boilers in
NESCAUM 2-14
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LIST OF ILLUSTRATIONS (CONTINUED)
Figure 2-14 1995 NOX emission factors and loading — coal-fired boilers in
MARAMA 2-16
Figure 2-15 1995 NOX emission factors and loading — oil-/gas-fired boilers in
MARAMA 2-16
Figure 2-16 Post-RACT 1995 utility boiler NOX emissions by region 2-17
Figure 2-17 NOX emissions reductions from utility boilers 2-17
Figure 2-18 Post-RACT 1995 utility boiler NOX emissions by state —
NESCAUM region 2-19
Figure 2-19 Post-RACT 1995 utility boiler NOX emissions by state —
MARAMA region 2-19
Figure 2-20a Post-RACT 1995 coal-fired utility boiler NOX emissions 2-20
Figure 2-20b Post-RACT oil/gas-fired utility boiler NOX emissions 2-20
Figure 2-21 Post-RACT 1995 utility boiler control technologies — total plant
capacity 2-22
Figure 2-22 Post-RACT 1995 utility boiler control technologies — coal-fired
NOX emissions 2-24
Figure 2-23 Post-RACT 1995 utility boiler control technologies — oil/gas-fired
NOX emissions 2-24
Figure 2-24 Post-RACT 1995 utility boiler control technologies — total NOX
emissions 2-25
Figure 3-1 Gas reburning for NOX control 3-18
Figure 3-2 Various gas-firing approaches in T-fired coal boilers 3-22
Figure 3-3 NOX versus burner area heat release rate (BAHR) correlation for
coal designed boilers firing 100 percent natural gas 3-29
Figure 3-4 Estimates of natural gas required for widespread reburn or
conversions of coal-fired boilers 3-33
Figure 3-5 Micronized coal reburn characteristics and benefits 3-39
Figure 3-6 Flue gas convective path and temperature profile — 350 MWe
bituminous coal-fired 3-41
Figure 3-7NOx removal versus residual NH3: SNCR on coal 3-47
vi
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LIST OF ILLUSTRATIONS (CONCLUDED)
Figure 3-8 In-duct SCR system — SCE Alamitos Power Station Unit 6 3-63
Figure 3-9 Possible SCR arrangements 3-65
Figure 3-10 Reactor for SCR on a coal-fired utility boiler 3-67
Figure 3-11 Advanced reburning (AR) with synergism 3-70
Figure 3-12 NOX reductions on a seasonal versus a yearly basis for coal-fired
tangential boilers 3-77
Figure 4-1 Reburn system cost versus unit size 4-10
Figure 4-2 Estimated cost of gas reburn for coal-fired boilers 4-10
Figure 4-3 Estimated annual cost of coal to gas conversion 4-13
Figure 4-4 Estimated cost effectiveness for coal to gas conversions 4-13
Figure 4-5 Cost effectiveness of urea-based SNCR 4-16
Figure 4-6 Estimated cost effectiveness of in-duct SCR systems on gas-fired
utility boilers 4-19
Figure 4-7 Capital and annualized costs for catalytic air heater on gas/oil-
fired boilers 4-22
Figure 4-8 Cost effectiveness of CAT-AH on gas-fired utility boilers 4-22
Figure 4-9 Decrease in catalyst space velocity with increasing demand on
NOX reduction efficiency 4-24
Figure 4-10 Cost effectiveness of full-scale SCR reactors retrofitted on
200 MWe coal-fired boiler 4-29
Figure 4-11 Cost effectiveness of AGR (Advanced Gas Reburn) retrofitted in
200 MWe coal-fired boiler 4-30
Figure 4-12 Estimate of SNCR + SCR cost effectiveness for retrofit on a
200 MWe coal-fired boiler 4-32
Figure 4-13 Cost effectiveness of controls used all year-around 4-35
Figure 4-14 Cost effectiveness of controls used on a seasonal basis 4-35
vu
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LIST OF TABLES
Table 1-1 Post RACT NOX emission factors for utility boilers in NESCAUM
and MARAMA, Ib/MMBtu 1-6
Table 1-2 List of candidate retrofit controls for Phase n NOX reductions 1-8
Table 1-3 Utility boilers in the United States with experience with gas-based
and flue gas treatment NOX control technologies 1-11
Table 1-4 Summary of NOX percent reductions for coal-fired boilers 1-12
Table 1-5 Summary of NOX percent reductions for oil/gas-fired boilers 1-12
Table 1-6 Documented NOX reductions from coal-fired boilers with gas-
based control technologies8 1-13
Table 1-7 Summary of costs for retrofit of a 200-MWe boiler 1-17
Table 2-1 Boiler inventory for the NESCAUM region 2-3
Table 2-2 Boiler inventory for the MARAMA region 2-3
Table 3-1 List of candidate retrofit controls for Phase II NOX reductions 3-3
Table 3-2 Domestic utility boilers experience with gas-based and flue gas
treatment NOX control technologies 3-5
Table 3-3 Utility boilers in the United States with experience with gas-based
and flue gas treatment NOX control technologies 3-8
Table 3-4 Gas cofiring experience on coal-fired utility boilers 3-13
Table 3-5 Gas cofiring experience on oil-fired utility boilers 3-16
Table 3-6 Gas reburning experience on U.S. coal-fired utility boilers 3-24
Table 3-7 Gas reburning experience on oil/gas-fired utility boilers 3-25
Table 3-8 Experience with 100 percent gas firing in coal-fired utility boilers 3-27
Table 3-9 Experience with 100 percent gas firing in oil-fired utility boilers 3-31
Table 3-10 Reburn NOX emissions as a percent reduction from baseline
versus load 3-37
Table 3-11 Coal reburning effects on general boiler operation 3-38
Table 3-12 SNCR experience on coal-fired utility boilers 3-45
vui
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LIST OF TABLES (CONCLUDED)
Table 3-13 SNCR experience on oil/gas-fired utility boilers 3-49
Table 3-14 Overseas SCR installations on coal-fired powerplants 3-53
Table 3-15 Major design factors affecting costs 3-58
Table 3-16 SCR experience on domestic coal-fired utility boilers 3-60
Table 3-17 SCR experience on domestic gas-fired utility boilers 3-61
Table 3-18 SNCR plus SCR experience on domestic utility boilers 3-74
Table 3-19 Summary of NOX reduction efficiencies for coal-fired boilers 3-81
Table 3-20 Summary of NOX reduction efficiencies for oil/gas-fired boilers 3-81
Table 3-21 Documented NOX reductions for gas-based controls on PC-fired
boilers* 3-82
Table 4-1 Factors that influence capital and operating costs of post-RACT
retrofit controls 4-2
Table 4-2 List of cost cases 4-6
Table 4-3 Required capital and operating cost components 4-7
Table 4-4 Levelized CAT-AH operating costs 4-21
Table 4-5 Utility boiler SCR costs — application of full-scale reactors on new
boilers 4-25
Table 4-6 Utility boiler SCR costs — retrofit of full-scale or expanded in-duct
reactors on existing boilers 4-26
Table 4-7 Estimates for SCR total capital requirement for 200 MWe coal
boiler 4-28
Table 4-8 Comparison of year-around and seasonal costs for post-RACT
NOX control technologies — 200 MWe coal-fired boiler 4-34
Table 4-9 Summary of costs for retrofit of a 200-MWe boiler 4-37
IX
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GLOSSARY
ABB-CE — Asea Brown Boveri — Combustion Engineering
ACT — Alternative Control Techniques
AGR — Advanced Gas Reburning
AH-CR — Air Heater Selective Catalytic Reduction
AUS — Applied Utility Systems
B&W — Babcock & Wilcox Company
BACT — Best Available Control technology
BAHR — Burner Area Heat Release Rate
BOOS — Burners out of Service
CAT-AH - Catalytic Air Heater
CCT — Clean Coal Technology Program
CTR — Combustion Controls
DOE — Department of Energy
EERC — Energy and Environmental Research, Company
EPA — Environmental Protection Agency
EPRI — Electric Power Research Institute
ESP — Electrostatic Precipitator
EVA, Inc — Energy Ventures Analysis, Inc.
EWG — Exempt wholesale generators
FEGT — Furnace Exit Gas Temperature
FGR — Flue Gas Recirculation
FGT — Flue Gas Treatment
FSW — Boilers that are considered for fuel switching to comply with RACT regulations
GR — Gas Reburn
GRI — Gas Research Institute
ICAC — Institute of Clean Air Companies
IFRF — International Flame Research Foundation
IPPs — Independent Power Producers
KP&L — Kansas Power & Light Company
LADWP — Los Angeles Department of Water and Power
LILCO — Long Island Lighting Company
LNB — Low NOX Burners
LNCB - Low NOX Cell Burner
LNCFS — Low NOX Concentric Firing Systems
MARAMA — Mid Atlantic Regional Air Management Association
MMBtu — Million Btu
MOU — Memorandum of Understanding
MWe — Megawatt of electrical generation (generator gross output)
NEPCO — New England Power Company
NESCAUM — Northeast State for Coordinated Air Use Management
NFT - Nalco Fuel Tech.
NGC — Natural gas Conversion
XI
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NGR — Natural Gas Reburn
NRP — Not reported
NSPS — New Source Performance Standards
NRP — Boilers with unreported control strategies
NSR — Normalized Stoichiometric Ratio
NSR — New Source Review
NUG — Non Utility Generator
O&M — Operation and Maintenance
OEM — Original Equipment Manufacturer
OFA — Overfire Air
OTC — Ozone Transport Commission
OTR — Ozone Transport Region
PG&E — Pacific Gas and Electric Company
PRB — Powder River Basin
PSE&G — Public Service Electric and Gas Company
PSNH — Public Service of New Hampshire
PURPA — Public Utility Regulatory Act
RACT — Reasonable Available Control Technology
RET — Boilers that are retired or planned for retirement/decommission
RPW — Power Plants that have Repowered with Gas turbine Generators
SCE — Southern California Edison Company
SCR — Selective Catalytic Reduction
SIECO — Southern Indiana Electric Company
SNCR — Selective Noncatalytic Reduction
SNR — Staged NOX Reduction
SOFA — Separate Overfire Air
TAG — Technology Assessment Guide
TVA — Tennessee Valley Authority
UEC — United Engineers and Constructors
UNC — Utility boilers currently uncontrolled for NOX
WP&L — Wisconsin Power & Light Company
Xll
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CHAPTER 1
SUMMARY
Utility fossil-fuel-fired boilers in the 14 states of the Northeast and Mid-Atlantic Regions
of the United States exceed 400 units and have an electric generating capacity of about
86,000 MWe. Many of these boilers are located within the Ozone Transport Region (OTR) that
stretches from Northern Virginia to Maine and from Rhode Island to Pennsylvania. Ambient zone
attainment plans for the OTR include a first-phase of retrofit NOX controls on these boilers and
other major NOX emission sources. By enacted regulations, these controls were to be in place by
May 31, 1995. Although the NOX reductions on utility boilers from these first retrofits are large,
additional controls may be necessary to attain the ambient ozone standard. The September 27,
1994, memorandum of understanding (MOU), signed by 10 Northeastern states and the District of
Columbia, requires a second and third round of controls starting in 1999 and 2003, respectively.
The full text of the MOU can be found in Appendix A. Beginning in 1999, major sources in the
more polluted inner corridor can reduce NOX to either 0.20 Ib/MMBtu or achieve 65 percent
reduction from 1990 baseline levels. Sources in the less polluted outer region will require a
55 percent reduction. Further tightening to either 0.15 Ib/MMBtu or 75 percent reduction will be
required in 2003 throughout the region.
Seasonal and year-around controls and emission averaging are planned for the year 1999
and beyond to meet the MOU requirements. Because seasonal controls target NOX reductions
during the peak ozone season, they are often less costly and less burdensome on the utility industry.
Recent years have seen the widespread implementation of several NOX controls on utility boilers
both in the U.S. and abroad. Performance improvements have been documented for many
1-1
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combustion and gas treatment controls. In addition, the cost of key control technologies have
reflected downward trends in part due to recent technological advances and increased market
competition.
This report presents an overview of utility boiler NOX emissions in the fourteen states1
that comprise the NESCAUM and MARAMA air quality regions and discusses the application,
performance, and cost of retrofit controls that are commercially available control options to further
reduce NOX beyond levels achieved with the implementation of RACT. Because this report
attempts to cover a multitude of boiler types, fuels, and control technologies, it is not possible to
address all feasible retrofit scenarios. Although NOX reduction performance and costs for some
actual retrofits may deviate from estimates provided in this study, the vast majority of retrofits will
be able to reduce NOX emissions in the range reported and at a cost estimated in this study. These
estimates are supported, by and large, by a growing experience base in commercial and technology
demonstration retrofits.
1.1 UTILITY BOILER NOX INVENTORY AND INDUSTRY TRENDS
Figures 1-1 and 1-2 illustrate the distribution of utility boiler NOX emissions among the
NESCAUM and MARAMA states, respectively. The majority of 86,000 MWe capacity is
concentrated in the eight states of Pennsylvania, New York, North Carolina, Massachusetts,
Maryland, New Jersey, Virginia and Connecticut. Electric power generation in MARAMA is
heavily dependent on coal, whereas in NESCAUM oil and gas are the principal fuels for utility
boilers. North Carolina's boiler power generation is entirely coal-based. In Pennsylvania,
75 percent of the utility boiler capacity is coal-based. The vast majority of boilers, regardless of
1 The 14 states are New York, Massachusetts, New Jersey, Connecticut, New Hampshire, Maine,
Rhode Island, and Vermont that comprise the Northeast States for Coordinated Air Use
Management (NESCAUM) and Pennsylvania, North Carolina, Maryland, Virginia, Delaware, and
District of Columbia that comprise the Mid Atlantic Regional Air Management Association
(MARAMA). North Carolina and Southern Virginia are not part of the OTR and therefore are
not required to install RACT controls this May 1995. Utility boiler inventory in these non-OTR
states is included here nonetheless to treat the MARAMA Region as a whole.
1-2
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120,000
Figure 1-1. Post-RACT 1995 utility boiler NOX emissions by
state — NESCAUM region
PA
Figure 1-2. Post-RACT 1995 utility boiler NOX emissions by
state — MARAMA region
1-3
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fuel used, have been in service for 20 to 50 years. The average age for all boilers is approximately
35 years. Total NOX emissions from utility boilers in NESCAUM, following the implementation
of RACT, is estimated to be about 235,000 tons/year. In MARAMA, the total NOX emissions are
estimated to be nearly 710,000 tons/year, dominated by coal-fired power plants.
Figures 1-3 and 1-4 illustrate the total NOX emissions for all utility boilers segregated
according to the type of RACT control technology that was in place by May 31, 1995. The
information was generated from a survey of RACT plans in each state, supplemented by selected
data from utilities. The control technologies include:
• LNB = Low-NOx burners with or without separate overfire air, and Low-NOx Cell
Burners (LNCBs)
• UNC = Boilers that will remain uncontrolled because they are either not required to
install RACT (e.g., all boilers in the non-OTR state of North Carolina) or
because they are included in averaging or are scheduled for early retirement
• CTR = Combustion controls such as flue gas recirculation (FGR), burners out of
service, burner tuning, biased firing, low excess air firing, or gas reburning
• FGT = Flue gas treatment controls that include either selective catalytic (SCR) or
noncatalytic (SNCR) reduction or a combination of these
• RPW = Repowering with either gas turbine or other technology
• FSW = Fuel switching to cleaner burning natural gas
• RET = Retired or decommissioned boilers
Because the survey was not complete, an additional category, labeled NRP, is also included for
boilers whose RACT compliance was not yet defined by the utilities or for those who elected not
to participate in the survey.
Figure 4-1 illustrates the dominance of combustion controls for RACT compliance for
oil/gas-fired boilers in the NESCAUM Region and LNB controls for coal units. The
disproportionate application of coal-fired LNB controls in the MARAMA Region compared to the
1-4
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500,000
400,000 -
L.
X
300,000 -
o
200,000 -
X
O
100,000 -
LNB
UNC
CTR
NHP
FGT
FSW
RET
Planned Control Technology
Figure 1-3. Post-RACT 1995 utility boiler control technologies — coal-fired
NOX emissions
70,000
CTR NRP UNC LNB FGT RPW FSW
Planned Control Technology
RET
Figure 1-4. Post-RACT 1995 utility boiler control technologies — projected
oil/gas-fired NOX emissions
1-5
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NESCAUM Region is principally due to many coal-plants in Pennsylvania that have undergone
retrofit of a variety of LNB controls for wall and tangential boilers, including LNCFSII and LNCFS
HI technology, and LNCB. The total NOX emissions from LNB-controlled units is estimated to be
about 400,000 tons per year by 1995. An estimate 290,000 tons/yr are emitted from uncontrolled
coal-fired units, principally in North Carolina and Virginia. Boilers controlled with FGT
technologies include the recent retrofits at the Public Service of New Hampshire (PSNH)
Merrimack coal-fired cyclones Units 1 and 2 and several Public Service Electric and Gas (PSE&G)
units in New Jersey. The total post-RACT utility boiler NOX inventory for NESCAUM and
MARAMA is estimated at about 940,000 tons/yr.
Table 1-1 lists the NOX emission levels for individual units following RACT implementation,
where applicable, after May 1995. The data were compiled in response to a utility survey of
emission levels following the implementation of RACT controls. The data represent a mix of actual
emissions or permitted levels. No specific averaging time is intended. The average reported values,
instead, are calculated arithmetic averages for the population of boiler firing types and weighed
according to boiler capacity within each population group.
Table 1-1. Post RACT NOX emission factors for utility boilers in NESCAUM and
MARAMA, Ib/MMBtu
RACT Control Technology
Uncontrolled
Low-NOx burners (LNBs)
Combustion controlled
Flue gas treatment (FGT)
Coal-fired Boilers
Range
0.50 to 1.2 (W)
0.45 to 0.70 (T)
0.38 to 0.70 (W)
0.35 to 0.75 (T)
0,45 to 0.55 (W)
0.42 to 0.45 (T)
0.37 to 0.55 (W)
0.90 to 1.4 (C)
Average*
0.90 (W)
0.55 (T)
0.50 (W)
0.45 (T)
0.45 (W)
0.42 (T)
0.48 (W)
1.2 (C)
Gas/Oil-fired Boilers
Range
0.30 to 0.70 (W)
0.30 to 0.50 (T)
0.28 to 0.45 (W)
0.28 to 0.50 (T)
0.25 to 0.40 (W)
0.25 to 0.45 (T)
0.22 to 0.25 (W)
0.22 to 0.25 (T)
Average8
0.50 (W)
0.40 (T)
0.43 (W)
0.40 (T)
0.25 (W)
0.28 (T)
0.25 (W)
0.25 (T)
W = wall-fired boiler; T = tangential-fired boiler; C
aCapacity weighted average.
cyclone-fired boiler.
1-6
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The length of averaging time can play an important role in quantifying the performance
limits of a given technology. For example, on a short-term basis, controlled NOX levels can be
influenced by many boiler operating factors including load, fuel quality, and equipment maintenance.
These factors tend to raise the NOX levels on a short-term basis. Over a period of a year, however,
the influence of many of these factors is greatly diminished and much lower average NOX levels are
possible. Because the data presented in this report are not sufficient to distinguish between
averaging times, it is prudent to view all reported NOX reduction efficiencies and controlled levels
as annual average levels until more detailed performance data are made available.
On average, LNB-controlled coal-fired boilers are lower than the Acid Rain presumptive
limits of 0.45 and 0.50 Ib/MMBtu for tangential and wall units respectively. Calculated averages
for these LNB-retrofitted boilers are 0.43 Ib/MMBtu for wall-fired and 0.40 Ib/MMBtu for
tangential boilers. However, the range in NOX levels shows LNB-controlled emissions as high as
0.75 Ib/MMBtu for some tangential-fired units. Uncontrolled coal units, principally in North
Carolina and parts of Virginia, where RACT does not apply, continue to show emission levels as
high as 1.2 Ib/MMBtu.
Recent SNCR and SCR controls for coal-fired units have lowered NOX emissions to levels
in the range of about 0.37 to 0.55 Ib/MMBtu for four wall-fired units and to levels in the range of
0.90 to 1.4 Ib/MMBtu for four high NOX emitting cyclone boilers. For gas/oil-fired boilers, a
combination of combustion controls and low-NOx burners will maintain NOX levels in the 0.25 to
0.45 Ib/MMBtu for the most part. Actual NOX levels will depend on fuel type, grade of oil, and
RACT control level.
12 POST-RACT NOX CONTROLS
Table 1-2 lists retrofit NOX controls considered candidates for post-RACT NOX reductions
from utility boilers. Control candidates exclude "first-round" combustion controls such as LNB for
coal units and a variety of combustion modifications such as FOR, OFA, BOOS, etc. for gas/oil-
fired boilers. Separate overfire air (SOFA), often included in tangential LNB retrofits, is not
1-7
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considered a viable post-RACT retrofit control for coal-fired wall boilers, unless applied with
natural gas reburning control, because of the marginal NOX reduction performance and the potential
for severe operational impacts on some units.
For uncontrolled coal-fired cyclones, candidate controls include coal and gas reburning and
a variety of flue gas treatment (FGT) options. Coal and gas reburning are most effective for base-
loaded units. Because most utility boilers experience some load reduction during off-peak demand,
use of reburning fuel can be curtailed during these times. FGT controls all rely on the properties
of ammonia-based compounds to reduce NOX with or without the presence of catalysts. These FGT
options include few commercial NOX/SOX combined gas treatment systems with recent
demonstrations in the U.S. and commercial applications in Europe. For other coal-fired boiler
types, equipped with either low-NOx concentric firing systems (LNCFS™) for tangential firing or
low-NOx circular burners for wall firing, controls are similar but exclude coal reburning and include
gas cofiring and gas conversion. Many LNBs just recently retrofitted on pulverized coal-fired
boilers, do not have gas cofiring capability. Experience with cofiring or gas conversion for LNB-
controlled coal units is presently lacking.
For gas/oil-fired boilers, post-RACT controls also include gas cofiring for oil-based units,
reburning for either oil- or gas-fired boilers, and gas conversions from oil to gas. SNCR technology
has been installed already on three separate oil/gas-fired boilers with a total generating capacity
of 530 MWe. SCR technology is also applicable on oil/gas-fired units. However, no SCR controls
are yet part of the NOX control arsenal in NESCAUM or MARAMA. Although SCR technology
is certainly feasible for these boilers, technical and economic factors of catalyst use with high-sulfur
oil burning are important considerations and possible limitations on their ultimate use. In place of
combined NOX/SOX controls, catalytic air heaters (AH-SCR) used principally in combination with
either SNCR and SCR systems offer additional control options for principally gas-fired boilers, and
potentially coal-fired boilers as well. SO2 reductions for oil/gas-fired boilers are typically not
1-9
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obtained by scrubbers because lower sulfur fuels or cofiring can be used to control SO2 emissions
more cost effectively.
Table 1-3 lists known retrofits and new boilers in the U.S. equipped with post-RACT
controls considered in this study. The list includes more than 20,000 MWe of gas-based
technologies, principally cofiring and full-scale gas conversions to permit 100 percent gas-firing
capacity. Reburning experience with natural gas include about 1,200 MWe of demonstration
capacity, focused primarily on the demonstration of the technology on smaller size utility boilers
(<200 MWe), although larger retrofit applications are planned. The list of domestic flue gas
treatment installations includes 15,000 MWe of retrofit and new boiler capacity. The total
commercial SNCR-controlled utility boiler capacity, in place and planned for the near future,
amounts to nearly 2,000 MWe. Commercial SCR-controlled capacity amounts to about 9,000 MWe.
Most of the capacity is retrofit on dedicated gas-fired boilers located in California. Only 440 MWe
is coal-fired retrofits, all on two slagging furnaces. An additional 1,200 MWe coal-fired SCR
capacity is in place or planned for new installations. No combined SOX/NOX control technologies
are either installed or planned in the U.S., with few DOE-sponsored demonstrations showing
promising results and some commercial installations in Europe.
Tables 1-4 and 1-5 summarize the range in NOX percent reductions for these post-RACT
control technologies. The data are based on a combustion of recent retrofit short- and long-term
test results from commercial and technology demonstration programs. The data suggest that
cofiring with up to 20 percent natural gas in coal-fired boilers has a NOX reduction potential of
10 to about 40 percent, depending on the boiler firing configuration and the location and method
of gas use. Gas reburn, with 15 to 20 percent gas can reach NOX reduction efficiencies as high as
65 percent, whereas full-scale gas conversions can reduce NOX to a maximum of 75 percent. The
actual NOX reduction achieved with gas conversions, however, depends not only on the intensity of
the heat release rate in the furnace (burner zone waterwall area) but also on the degree of
combustion controls, such as FOR, associated with the new gas burners. Operational concern with
1-10
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Table 1-3. Utility boilers in the United States with experience with gas-based and flue gas
treatment NOZ control technologies
Control
Category
Gas-based
Controls
Rue Gas
Treatment
Controls
Technology
Natural Gas
Reburning
Gas Cofiring
Natural Gas
Conversions
SNCR-based Controls
SCR-based Controls
Station Identification and State
(Commercial and Demonstration Sites)
2 Units in Illinois
2 Units in Ohio
2 Units in Colorado
1 Unit in Kansas
1 Unit in New York
6 Units in Pennsylvania
3 Units in Massachusetts
3 Units in Indiana
2 Units in Texas
1 Unit in Alabama
1 Unit in Kansas
1 Unit in Ohio
7 Units in Illinois
1 Unit in Florida
1 Unit in Michigan
4 Units in Maryland
2 Units in New Jersey
2 Units in Mississippi
2 Units in Wyoming
6 Units in Illinois
4 Units in Ohio
2 Units in Michigan
2 Units in Arizona
2 Units in Massachusetts
2 Units in New Jersey
2 Units in New York
2 Units in Connecticut
1 Unit in Colorado
1 Unit In Florida
1 Unit in Indiana
10 Units in California
4 Units in Massachusetts
3 Units in New York
5 Units in New Jersey
1 Unit in Wisconsin
1 Unit in Colorado
2 Units in New Hampshire
1 Unit in Delaware
21 Units in California
4 Units in New Jersey
1 Unit in Massachusetts
1 Unit in Florida
1 Unit in New Hampshire
Boiler Capacity and Firing Type
521 MWe coal-fired tangential
143 MWe coal-fired cyclone
385 MWe coal-fired wall/other
185 MWe oil/gas-fired tangential
5,712 MWe coal-fired tangential
3,328 MWe coal-fired wall
2,043 MWe oil/gas-fired
974 MWe coal-fired tangential
620 MWe coal-fired wall
1,124 MWe coal-fired other
4,992 MWe oil-fired
1,392 MWe coal-fired wall
3,492 MWe gas/oil-fired
421 MWe coal-fired cyclone
741 MWe coal-fired other firing
6,965 MWe gas-fired
1,582 MWe dry-bottom coal-fired
659 MWe wet bottom and cyclone
1-11
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Table 1-4. Summary of NOX percent reductions for coal-fired boilers
Control Type
Cofire
Reburn
Conversion
SNCR"
SCR
Hybrids:
SNCR + SCRb
AGRC
Ncysox
Wall-Bred Boilers
Uncontrolled
(0.90 Ib/MMBtu)
25 to 40
40 to 65
40 to 70
30 to 65
60 to 90
80 to 95
80 to 85 (est)
80 to 85
LNB-ControUed
(0.50 Ib/MMBtu)
NA
30 to 50
35
30 to 40
60 to 90
80 to 95
80 to 85 (est)
80 to 85
Tangentially-fired Boilers
Uncontrolled
(0.6 Ib/MMBtu)
10 to 35
65
70 to 75
30 to 50
(est.)
60 to 90
80 to 95
80 to 85 (est)
80 to 85
LNB-Controlled
(0.45 Ib/MMBtu)
25 to 40
20 to 25
NA
30 to 35
(est.)
60 to 90
80 to 95
80 to 85 (est)
80 to 85
Cyclone and
Slagging
Furnaces
Uncontrolled
(1.2 Ib/MMBtu)
NA
45 to 60
45 to 50
30 to 40
60 to 90
80 to 95
80 to 85 (est)
80 to 85
NA = Not applicable.
"SNCR NOX reduction efficiencies based on maximum of 10 ppm NH3 slip.
'"Estimates based on recent demonstration successes at Mercer Station.
'Advanced gas reburn (GR+SNCR). Not yet demonstrated.
Table 1-5. Summary of NOX percent reductions for oil/gas-fired boilers
Control Type
Cofire
Reburn
Conversion (oil
togas)
SNCRa
SCRb
Hybrid
(SNCR+SCR)b
Wall-fired Boilers
Uncontrolled
(0.50
Ib/MMBtu)
20 to 30
(est)
50 to 60
30 to 40
25 to 40
80 to 95
70 to 90
LNB-Controlled
(035
Ib/MMBtu)
20 to 30
(est)
50 to 60
40 to 50
(est)
10 to 40
80 to 95
70 to 90
Tangentially-fired Boilers
Uncontrolled
(030
Ib/MMBtu)
20 to 30
(est)
50 to 60
30 to 40
25 to 40
80 to 95
70 to 90
LNB-Controlled
(0.25
Ib/MMBtu)
20 to 30
(est)
30 to 40
40 to 50
(est)
10 to 40
80 to 95
70 to 90
Cyclone and
Slagging Furnaces
Uncontrolled
(0.52 Ib/MMBtu)
ND
ND
10 to 20
(est)
ND
ND
ND
*SNCR results based on maximum NH3 slip of 10 ppm.
bData for SCR and hybrids are for gas-fired boilers only.
1-12
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gas-based technologies generally increase with increasing heat input from natural gas because of
shifts in the heat absorption profile in the furnace leading to increased furnace exit gas temperature
and increased loss in efficiency. Although some recent tests confirm NOX reductions in the 30 to
50 percent range with reburn on one LNB-controlled coal unit, long-term operational experience
is generally limited. Gas cofiring and reburning can be particularly effective in reducing NOX from
tangential coal-fired boilers using the top burner elevation for the reburn zone.
Among the various applications of natural gas as a utility boiler fuel, reburning remains the
most efficient way of using gas for NOX reduction. With this technology, the NOX reduction
potential is the highest for a given percent of gas use. Table 1-6 lists ranges in NOX reductions
normalized by the amount of gas used. Cofire, conversion, and seasonal gas use offer either lower
NOX reduction potential or require much higher gas use. Because of the fuel cost differential
between gas and coal, the amount of gas needed to reduce NOX from coal-fired boilers is one of
the main utility concerns with the application of gas-based technologies. Additional utility concerns
that may limit increased natural gas use solely for NOX control include:
• Long-term natural gas availability
• Access to gas supply (proximity to pipeline)
• Marginal NOX reduction beyond LNB
Table 1-6. Documented NOX reductions from coal-fired boilers with gas-based
control technologies*
Control Type
Cofire
Reburn
Conversion
Wall-fired Boilers
Uncontrolled
(0.90 Ib/MMBtu)
0.90 to 2.8
2.5 to 3.4
0.41 to 0.68
LNB-Controlled
(0.50 Ib/MMBtu)
NA
1.0 to 1.6
035
Tangentially-flred Boilers
Uncontrolled
(0.6 Ib/MMBtu)
0.75 to 12
2.2
0.42 to 0.45
LNB-Controlled
(0.45 Ib/MMBtu)
056 to 0.90
0.56 to 0.90
NA
Cyclone and
Slagging Furnaces
Uncontrolled
(12 Ib/MMBtu)
NA
3.4 to 4.0
0.54 to 0.64
*AU units are in Ib of NO2 reduced per MMBtu of gas used in the control technology. Cofiring gas use less
than 8 to 35 percent; reburning 16 to 20 percent; conversion 100 percent gas firing.
1-13
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• Competitive gas pricing and availability of long-term contracts
• Reburning performance on large-scale coal boilers
• Combustion safety of gas injector designs
Recent estimates on natural gas availability for NOX control on utility boilers in the OTR
project 3,490 MMcfd available in 1997, reducing to 2,830 by the year 2000. A hypothetical scenario
where all dry furnaces in both NESCAUM and MARAMA would be retrofitted with 20 percent gas
cofiring or reburning capability would necessitate approximately 1,400 MMcfd, considering year
around operation with these controls. Therefore, these estimates would suggest that gas will be
available to implement the reburning and cofiring techniques, should these be considered by the
utilities for their NOX reduction compliance strategies. A recent study sponsored by the Coalition
for Gas Based Environmental Solutions, Inc. also revealed that only about 9 percent (14 out of
155 units) of the total coal-fired generating capacity in the OTR is currently equipped to burn any
amount of natural gas. Most of these plants with dual-fuel firing capability only have access to
sufficient natural gas for ignition, warm up, and for flame stabilization which require relatively small
amounts of gas. Therefore, to adapt these units to either reburning or cofiring with a maximum
of 20 percent gas use, it would require installation of new pipelines and burner equipment. The
study went on to reveal that, although few power stations have any gas firing capability, nearly half
are located less than 5 miles from an existing natural gas pipeline. For oil-fired utility boilers,
39 percent of the existing capacity has gas service, and 20 percent are fully dual fuel boilers capable
of supplying full capacity on either oil or gas. Many of the oil-fired boilers are also located within
5 miles of a gas pipeline. The same study also revealed that the current and projected differential
cost between coal and natural gas is not attractive to increased gas use in utility plants.
NOX reduction by natural gas reburning on uncontrolled coal-fired boilers have been
reported in the range of 45 to 65 percent depending on amount of gas used, boiler load, and other
factors. However, when applied to LNB-equipped boilers the NOX reduction of gas reburning can
fall as low as 20 percent for some tangential boilers to as high as 50 percent for wall-fired units.
1-14
-------
The NOX reduction performance can further deteriorate from these levels when the boilers operate
at reduced load. The lower NOX reduction performance of reburn for LNB-equipped boilers can
be an important consideration for load-cycling units. The reduced NOX reduction of reburning
could also affect its competitiveness when compared on a cost-effective basis, especially when fuel
differential costs are high.
Although most gas reburning demonstrations to date have been on smaller scale utility
boilers, several research efforts are underway to demonstrate the technology on larger utility boilers
and improve the gas reburning process for utility applications. This research includes improved gas
injection mechanisms to maximize the mixing and possibly reduce the amount of gas required;
removing the need for FOR, thus reducing operational complexity and cost; improving OFA port
designs to achieve more complete and rapid burnout; combining reburning techniques with selective
noncatalytic reduction (SNCR) in advanced reburning concepts; and more efficiently integrating gas
reburning into the operation of pulverized coal-fired low-NOx burners for enhanced NOX reduction.
The applicability of ammonia-based flue gas treatment controls, whether catalytic or
noncatalytic, hinges on several factors such as fuel choice, boiler load dispatch, ease of retrofit
access, age of unit, initial NOX level, gas temperature, and others. Yet these controls installed by
themselves or in combination may provide the only feasible approach to deep reductions in NOX
from post-RACT levels. Although experience is growing at a rapid pace, widespread reliance on
both non-catalytic and catalytic controls will be more likely once long-term performance has been
ascertained and operational impacts and costs fully realized. In the interim, further technical
improvements and demonstrations of commercial and novel technologies will likely improve the
retrofit potential of many of the flue gas treatment controls.
Retrofit experience to date indicates that SNCR, by itself, for either coal- or oil/gas-fired
plants already controlled with RACT, is likely to be able to reduce NOX in the range of 10 to
40 percent depending on initial NOX levels and its load dispatch characteristics. Although SNCR
commercial experience has been on furnaces with a capacity less than 160 MWe with NOX reduction
1-15
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levels up to 65 percent, application is deemed also feasible to larger size boilers with optimum
performance and ease of operation for base-loaded high NOX emission boilers. SCR and hybrid
technologies offer the potential to exceed 60 percent NOX reduction in all installations, whether
RACT-controlled or not. The range in NOX reduction in Table 1-4 of 60 to 90 percent reflects the
flexibility of SCR to deliver moderate to high percent reduction efficiencies depending on the
volume of catalyst and ammonia reagent used, as required to meet regulations. In reality, SCR can
achieve 80 percent control or more for most applications, including boilers with low inlet NOX levels,
as demonstrated in California. Therefore, their applications are particularly suitable for retrofit on
RACT-controlled boilers. Although the technical and experience gains of recent years on the use
of SCR and SNCR+SCR hybrids are obvious, greater experience is necessary to fully document the
long-term performance of these novel control approaches. The feasibility of retrofitting SCR by
itself or as a hybrid in SNCR+SCR applications must be evaluated on a case by case basis because
of the equipment, fuel, and layout constraints that are particular to each installation and because
cost and performance of SCR can be affected by these factors.
13 COST OF CONTROLS
The influence of site-specific factors on the cost of retrofitting NOX controls to existing
boilers is well accepted. Among process capital and O&M costs are many cost components that are
influenced by the location of the plant, its age and operating condition, the configuration of
equipment, fuel, and load dispatch. Within some degree of uncertainty, however, it is possible to
formulate estimates of actual cost of NOX controls for utility boilers using costs reported for similar
installations and estimating a range that will likely account for many of the site specific effects.
Table 1-7 lists the estimated ranges in the capital and busbar costs, and cost effectiveness
for post-RACT controls on coal-, oil-, and gas-fired boilers. The range in NOX reduction, in
Ib/MMBtu, reflects the estimated reductions from LNB-controlled wall and tangential boilers.
These reduction levels are then used to estimate the cost effectiveness of the controls on a post-
RACT basis.
1-16
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1-17
-------
The cost for gas-based controls is dominated, by and large, by the fuel price differential
between the primary fuel and natural gas and on the value of clean-fuel credits that result from
lower SO2 and fly ash emissions and from reduced plant maintenance. For gas treatment controls,
SNCR continues to be the lowest capital cost technology. However, because SNCR has lower NOX
reduction capability compared with SCR, for example, on a cost-effectiveness basis SNCR may not
always offer an economic advantage. For example, on uncontrolled high emitting cyclone furnaces,
SCR may prove to be slightly more cost effective based on economic assumptions used in the
analysis. The capital cost of SCR has shown a large downward trend in recent years, the result of
improved technology, more efficient catalyst management extending the life of the catalyst, and
increased market competition. Although the SCR experience in the United States is primarily on
in-duct catalysts for gas-fired boilers and for full-scale SCR reactors on new coal plants, retrofit of
SCR on existing coal-fired units have recently taken place. Although all post-RACT controls
considered offer the potential for tailored NOX reduction, SCR technology has perhaps the greater
range in performance. That is, the amount of catalyst can be tailored to the percent NOX reduction
needed. In fact, many of the recent SCR installations on coal plants have an initial NOX reduction
target of 65 percent with provisions for additional catalyst to increase performance to 85 percent
or higher.
Among the three gas-based control technologies, natural gas reburn (NGR) offers the lowest
cost per ton of NOX reduced because the amount of gas used is lowest and NOX reductions are
typically larger than other gas-based controls. The capital cost of NGR is considered to fall in the
range of $20 to $30/kW, except when access to a sufficiently large pipeline is not readily available.
Under these conditions, the capital cost can increase by $5 to $10/kW to account for the price of
installing a 5 to 10 mile pipeline. Busbar costs for NGR on coal-fired boilers are on the order of
0.93 to 2.0 mills/kWh based on a coal-gas price differential of $0.50 to 1.0/MMBtu. This level is
lower for oil-fired boilers because a range between $0 and $0.50/MMBtu fuel differential cost was
1-18
-------
considered. Natural gas conversions have a large busbar cost because the impact of fuel differential
cost is much larger.
Pipeline gas supply is one of the most important factors that determine natural gas
availability to the utilities. The estimates of fuel differential costs used in these calculations are
subject to considerable uncertainty because of the month-to-month volatility in the demand and
price of natural gas. In fact, the use of natural gas is very seasonal. In the summer months when
the residential and commercial demand is lowest, the price of natural gas becomes more attractive
because of the increased pipeline capacity. It is during these particular periods that natural gas can
be most cost effective in reducing NOX from utilities.
SNCR technology has successfully been installed on cyclone as well as other boiler firing
types. Estimates of the retrofit cost are $11 to $14/kW and a busbar cost in the range
0.77 mills/kWh for low NOX emitting dry bottom boilers equipped with LNB to as high
3.1 mills/kWh for high NOX emitting uncontrolled cyclone or wet bottom boilers. Cost effectiveness
of SNCR is typically less than $l,000/ton for most retrofits, especially where larger NOX reductions
are possible. The capital cost of SCR will vary according to the amount of catalyst installed.
Smaller catalyst volumes for in-duct and air heater applications will have much lower capital costs
than full-scale systems. However, many of these systems are most likely to be retrofitted on gas-
and light-oil fired units when used alone, that is, not in an hybrid SNCR-t- SCR configuration. Cost
effectiveness of these systems remains well above the $l,000/ton because smaller NOX reductions
are possible when the technologies are applied to cleaner burning fuels. Finally, full-scale SCR of
average retrofit sufficiently is estimated to have a capital cost in the range of $78 to $87/kW for
80 percent NOX reduction systems on a 200 MWe coal-fired utility boiler. These cost are likely to
be lower for cleaner burning fuels or for applications on low dust environments. The cost
effectiveness of full-scale (80-percent NOX reduction) SCR for a coal plant will be lower than
$l,000/ton when NOX reductions are large, for example in the case of retrofit of some uncontrolled
cyclone and wet bottom units such as Merrimack Unit 2 and Mercer Unit 1. For conventional
1-19
-------
LNB-retrofit wall and tangential boilers, the cost effectiveness is estimated to be in the range of
$l,200/ton to $2,000/ton. Hybrid SNCR + SCR systems are considered more cost effective than
full scale SCR. This analysis indicates cost effectiveness range in $1,100 to $l,800/ton for similar
NOX reduction levels. Because experience is limited or nonexistent in the case of AGR, estimates
of capital cost and cost effectiveness should be interpreted with caution.
Figures 1-5 and 1-6 illustrate the cost effectiveness of post-RACT controls on a 200 MWe
dry bottom coal-fired boiler equipped with LNB when controls are used all year and only during
the ozone season, typically 5 months of the year. The data are plotted versus gas-coal price
differential to reflect the sensitivity of gas-based controls to the price of natural gas versus coal.
The controls include NGR, SNCR, SCR and Hybrid (SNCR+SCR). The two sloped lines represent
the upper and lower range in cost effectiveness for NGR, which among the four selected control
types, is the only control that would show a sensitivity to price of natural gas.
In Figure 1-5, the cost effectiveness of SCR and hybrid controls (SNCR + SCR) overlap and
are shown to be in the range of about $900 to $2,000/ton. The cost effectiveness band for SNCR
is lower, in the range of $850 to $l,300/ton. As indicated, in Figure 1-5, NGR can be most
competitive when both the NOX reduction achieved is highest, estimated in this report to be about
0.40 Ib/MMBtu, and the fuel price differential is below $0.5/MMBtu. This level of NOX reduction
is more representative of NGR control performance on uncontrolled coal-fired boilers rather than
LNB-controlled units. When NOX reductions for NGR are minimal, perhaps as low as
0.1 Ib/MMBtu from well controlled tangential-fired units, NGR promises to be less cost competitive
on a year-around application basis.
The conclusions differ somewhat when controls cost effectiveness are viewed on seasonal
use basis. Here, gas-based NGR controls can be less costly or equally competitive with most gas
treatment ammonia-based controls up to a fuel price differential of $0.50/MMBtu and the amount
of NOX reduction achieved is 0.25 Ib/MMBtu. If the NOX resolution is large, e.g., approaching
0.4 Ib/MMBtu, NGR on a seasonal basis is the most cost-effective approach as long as fuel-price
differentials are lower than about $1.0/MMBtu. For seasonal use of controls, cost effectiveness
1-20
-------
c
i
V)
S3
5
0.4 Ib/MMBtu reduction
—e-—
0.1 Ib/MMBtu reduction
....A—-
025 Ib/MMBtu reduction
- SCR (0.25 to 0.60 Ib/MMBtu reductions)
- SNCR + SCR Hybrids (0.30 to 0.60 Ib/MMBtu reductions)
..*-'
- SNCR (0.10 to 0.30 Ib/MMBtu reductions) ,--'''
..-"
_,.--
A-"""
Amount of NOx reductions
-achieved with NGR
0
1.2
0.4 0.6 0.8 1
Gas-Coal Fuel Price Differential ($/MMBtu)
Yearly application ot control (12 months/yr)
60 percent capacity factor
Figure 1-5. Cost effectiveness of controls used all year around
1.4
0.4 Ib/MMBtu reduction
B
0.1 Ib/MMBtu reduction
....A—-
0.25 Ib/MMBtu Reduction
Y//\ • SCR (0.25 to 0.60 Ib/MMBtu reductions)
|\^) - SNCR + SCR Hybrids (0.30 to 0.60 Ib/MMBtu reductions)
| | - SNCR (0.10 to 0.30 Ib/MMBtu reductions)
0.2
1.2
0.4 0.6 0.8 1
Gas-Coal Fuel Price Differential ($/MMBtu)
Seasonal application of control (5 months/yr)
60 percent capacity factor
Figure 1-6. Cost effectiveness of controls used on a seasonal basis
1-21
1.4
-------
generally rises because the capital cost is amortized over fewer kW-hr. For example, the cost
effectiveness of SNCR worsens from about $850 to $l,300/ton on a yearly basis to about $1,000 to
$l,900/ton on a seasonal basis depending on the level of NOX achieved. SCR, with the most
intensive capital investment has the largest increase in dollars spent per ton of NOX reduced when
going from a yearly use to a seasonal use. These results assume that the catalyst life does not
improve with seasonal use of SCR control, a probability of the catalyst cannot be bypassed or
removed from the gas stream.
1-22
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CHAPTER 2
BOILER AND EMISSIONS PROFILES IN MARAMA AND NESCAUM STATES
The objective of this chapter of the report is to provide a profile of the boiler population
and NOX emissions from utility boilers in NESCAUM and MARAMA following the full
implementation of RACT controls in May 1995. Because considerable progress in reducing regional
NOX was recently made with the implementation of first round of RACT controls, it is important
to update the baseline from where additional NOX reductions can be evaluated. Fuels types and
emission levels have an important impact on the selection of controls, the anticipated NOX reduction
level, and its cost effectiveness. Furthermore, the retrofit feasibility of post-RACT controls and
their cost effectiveness are often influenced by decisions made on these first round of controls. For
example, boilers undergoing seasonal fuel switch or fuel conversions to natural gas may be better
amenable to a whole host of controls. Conventional combustion controls, including gas reburning,
can further suppress NOX from boiler burning natural gas. Post-combustion controls using lower
costs in-duct catalysts or hybrid controls that combine noncatalytic and catalytic reduction are also
possible. But, because NOX levels from gas-fired boilers are generally lower, the costs to reduce
1 ton of NOX can be higher. Coal-based boilers equipped with low NOX burners (LNB), instead,
would have exhausted most combustion control options for further reduction, with the exception,
perhaps, of natural gas reburning.1
1 Throughout the remainder of this report we will refer to reburning as a gas treatment control,
although the technology clearly requires modifications to the combustion process to reduce first
stage NOX and suppress second stage NOX formation via fuel substitution and/or air staging
techniques. However, the association of reburning technology with gas treatment is made to
distinguish the reburning process from more conventional first-round RACT controls that have
relied, principally, on LNB and on several other types of combustion control techniques. In so
2-1
-------
The inventory data for this chapter was collected from a combination of sources. For the
NESCAUM region, the utility boiler inventory presented in the first study (Castaldini, 1992) was
updated using input from individual states in receipt of utilities RACT compliance plans. Where
these plans were not available, the information was sought directly from selected utilities using a
brief questionnaire. The inventory for the MARAMA states was obtained using input from recent
inventories (Tech Environmental, 1994) and data gathered from the individual member states and
selected utilities. Although the data are considered the most up-to-date inventory on boiler capacity
and NOX emissions from utilities in the Northeast Ozone Transport Region (OTR), selected parts
of the inventory are considered incomplete because retrofit control information for certain utilities
could not be obtained. Many RACT plans have only recently been finalized and confirmation of
control selection is not yet available for all boilers. Further updates, therefore, will be necessary
as the data develops to reflect actual conditions prevalent after May 31, 1995.
The following sections summarize various aspects of the capacity inventory and NOX
emissions. Details of the inventories for NESCAUM and MARAMA can be found in
Appendices A and B, respectively. NESCAUM states include Connecticut, Maine, Massachusetts,
New Hampshire, New Jersey, New York, Rhode Island, and Vermont. MARAMA states include
Delaware, District of Columbia, Maryland, New Jersey, North Carolina, Pennsylvania, and Virginia.
To prevent double accounting, New Jersey boiler and emission inventories were retained in the
NESCAUM region. This is consistent with the inventory presented in an earlier NESCAUM study
(Castaldini, 1992).
2.1 FUEL TYPES AND FIRING CAPACITIES
Tables 2-1 and 2-2 list the inventory of boiler types and fuels for the NESCAUM and
MARAMA regions, respectively. Fuel type was identified based on the boiler's reported primary
fuel. Because many gas- and oil-fired units have dual fuel capability and often fire both fuels
doing, reburning can then be viewed as an additive control option similar to other gas treatment
controls, that can be retrofit to existing combustion (i.e., LNB) controlled boilers without requiring
further major changes to the primary combustion zones, thus providing additive NOX reduction
beyond RACT-achieved levels.
2-2
-------
Table 2-1. Boiler inventory for the NESCAUM region
Firing Type
Tangential
Wall
Cyclone
Vertical
Stoker
Totals
Number of Units and Capacity (MWe)a
Coal
21
3,140
19
3,920
4
757
4
340
6
230
54
8,390
Oil/Gas
65
12,900
74
11,900
7
1,070
6
297
152
26,200
Total
86
16,000
93
15,800
11
1,830
10
637
6
230
206
34,600
"All MWe values are rounded to three significant figures.
Table 2-2. Boiler inventory for the MARAMA region
Firing Type
Tangential
Wall
Cyclone
Vertical
Stoker
Totals
Number of Units and Capacity (MWe)a
Coal
80
20,900
66
18,900
2
376
9
743
—
157
40,900
Oil/Gas
18
6,760
28
3,290
1
156
—
—
47
10,200
Total
98
27,600
95
22,200
3
532
9
743
—
204
51,100
aAll MWe values are rounded to three significant figures.
2-3
-------
throughout the year on the basis on availability and pricing, no distinction was made between these
fuels in grouping boiler types. This represents a broad generalization because NOX emissions from
burning natural gas or oil can be markedly different considering that fuel oil, especially residual oil,
will add fuel NOX to the total NOX emissions, whereas natural gas produces only thermal NOX.
The total NESCAUM utility boiler population in place next year is estimated to be 206 units
for a total generating capacity of about 35,000 MWe. The total number of units is five more than
the estimate prepared for a 1987 inventory (Castaldini, 1992). The difference is the result of more
detailed accounting of multiple units located in the state of New York supplying steam to one
generator turbine. These additional boilers are reflected principally in the number of wall oil/gas-
fired boilers. The number of utility boilers in MARAMA is nearly identical to the NESCAUM
units, however, the generating capacity is about 50 percent higher, topping 51,000 MWe. Also
apparent in the inventory data is the much greater proportion of coal-fired units in MARAMA
compared to NESCAUM. In fact, the coal to oil/gas capacity ratio is more than reversed, where
the ratio is about 4 to 1 in MARAMA compared to 0.3 to 1 in NESCAUM. Total coal-fired
capacity in MARAMA is about 41,000 MWe, more than the entire boiler generating capacity in
NESCAUM. Figure 2-1 illustrates the inventory capacity data clearly indicating the dominance of
coal units in MARAMA accounting for nearly one half of the total 86,000 MWe capacity for both
regions.
Figures 2-2 and 2-3 illustrate the distribution of capacity, fuel, and firing designs among each
state in NESCAUM. The charts illustrate that New York accounts for nearly the same generating
capacity in the other NESCAUM states combined with about 18,000 MWe. Massachusetts and New
Jersey are the other major electrical power producing states in NESCAUM. Also noticeable is the
dominance of oil/gas-fired boilers accounting for most of the generating capacity in nearly all the
states. Tangential coal-fired boilers are located primarily in New York, Massachusetts and
Connecticut. Tangential oil/gas-fired boilers are the dominant design in New York and
Connecticut. Generating capacity from wall-fired boilers is largest in New York and Massachusetts.
2-4
-------
NESCAUM oil/gas 30.6%
MARAMAcoal 47.7%
NESCAUM coal 9.8%
MARAMA oil/gas 11.9%
Total capacity
86,000 MWe
Figure 2-1. 1995 utility boiler capacity by region and primary fuel
MWe
20,000
15,000
10,000
5,000
NY MA .NJ
CT NH
State
Rl VT
Figure 2-2. 1995 utility boiler capacity by state — NESCAUM region
2-5
-------
MWe
20,000
15,000
10,000
5,000
Q Oil/Gas Other
0 Oil/Gas Wall
0 Oil/Gas Tangential
Q Coal Stoker & Other
^ Coal Cyclone & Wet
^ Coal Dry Wall
E8 Coal Dry Tangential
XXX
NY
MA
NJ
CT NH
State
ME
Rl
VT
Figure 2-3. 1995 utility boiler capacity by state and firing type — NESCAUM region
In MARAMA, as illustrated in Figure 2-4, Pennsylvania has the highest generating capacity
with about 23,000 MWe followed by North Carolina, Maryland and Virginia. The dominance of
coal-based power generation in these states is evident. In fact, the entire boiler generating capacity
of North Carolina is coal-based. More detail on boiler firing types is given in Figure 2-5. This
figure shows that the coal and oil/gas generating capacity in nearly all the states is about equally
split between tangential and wall-fired boilers. Coal- and oil/gas-fired cyclones and slagging
furnaces are few in this region.
22 AGE OF BOILERS AND CAPACITY FACTORS
The age and capacity factor of a utility boiler can have important effects on the selection
of most cost-effective NOX control option. The age and capacity factors for all the boilers in
NESCAUM and MARAMA were determined from available data base (Castaldini, 1992, and Tech
Environmental, 1994) and from direct input from selected utilities. The age of the boiler is
determined based on 1995, the year for RACT compliance in all Northeast and some Mid-Atlantic
2-6
-------
MWe
25,000
20,000
PA
NC
MD VA
State
DE
Figure 2-4. 1995 utility boiler capacity by state — MARAMA region
MWe
25,000
20,000
15,000
10,000
5,000
MARAMA
Oil/Gas Wall
Oil/Gas Tangential
Coal Stoker & Other
Coal Cyclone & Wet
Coal Dry Wall
Coal Dry Tangential
'/S/A///A K/VVVM
PA
NC
MD VA
State
DE
DC
Figure 2-5. 1995 utility boiler capacity by state and firing type — MARAMA region
2-7
-------
states. Many units are in an age group where NOX compliance for their remaining life can add
significantly to the operating cost of the control because the initial investment for retrofit can only
be amortized over a short period of time. The capacity factor is intended to reflect the overall
yearly generation output divided by the capacity of the unit. Therefore, the capacity factor used in
this study makes no distinction between seasonal dispatch patterns, load, or outage time. These,
of course, are important distinctions because seasonal changes in boiler dispatch can affect NOX
emissions and control performance. For example, low load on a boiler can have a dramatic effect
on the percent NOX reduction efficiency of both selective noncatalytic and catalytic reduction
(SNCR and SCR). Also the cost effectiveness of the control can vary significantly.
Figures 2-6 and 2-7 illustrate the relationship between the age of the boilers and their
capacity in MWe. In spite of the scatter, the data illustrates that there is a general trend with newer
boilers having larger capacity and, most likely, better heat rates. In MARAMA, most of the boilers
less than 200 MWe capacity are older than 35 years. These boilers have projected remaining life
that approaches 15 years with all life extension modifications available today. In NESCAUM, the
population of boilers is slightly older with many more units in the 40 to 50 years of age.
Figure 2-8 illustrates that the average age of the 36,000 MWe boiler capacity in NESCAUM
is about 30 years. Figure 2-9 illustrates that in MARAMA, the boiler population is generally
younger with the average age on the order of 25 years. Given everything equal, the retrofit of
controls on younger boilers should result in less cost per ton of NOX removed because of longer
equipment amortization of initial capital.
Figures 2-10 and 2-11 illustrate the pattern in capacity factors for the two air management
regions. In NESCAUM, the mean capacity factor for all the boiler power generating capacity,
whether coal- or oil/gas-fired, is about 40 percent. This is lower than the capacity factor reported
for a 1987 inventory, probably reflecting a reduction in conventional power generation in the
Northeast. A similar curve for MARAMA illustrates that the coal-based power in that region
operates at much higher capacity factor. In fact, 50 percent of the total capacity in the region shows
2-8
-------
BOILER CAPACITY (MWe)
1,200
400
200
10
20 30 40 50
BOILER AGE (years, 1995)
60
Figure 2-6. 1995 utility boiler capacity versus age — NESCAUM region
BOILER CAPACITY (MWe)
20 30 40
BOILER AGE (years, 1995)
Figure 2-7. 1995 utility boiler capacity versus age — MARAMA region
2-9
-------
TOTAL MWe WITH AGE LESS THAN STATED
40,000
30,000 —
20,000 —
10,000 -
10
20 30 40 50
BOILER AGE (years, 1995)
70
Figure 2-8. 1995 utility boiler total capacity versus age — NESCAUM region
TOTAL MWe WITH AGE LESS THAN STATED
60,000
50,000
40,000 -
10
20 30 40
BOILER AGE (years, 1995)
50
60
Figure 2-9. 1995 utility boiler total capacity versus age — MARAMA region
2-10
-------
TOTAL MWe WITH CF% LESS THAN STATED
40,000
30,000
20,000
10,000 --<&&?—
0.2
0.4 0.6 0.8
CAPACITY FACTOR (%)
Figure 2-10. 1995 utility boiler total capacity factor — NESCAUM region
TOTAL MWe WITH CF% LESS THAN STATED
60,000
50,000
0.2
0.4 0.6
CAPACITY FACTOR (%)
0.8
Figure 2-11. 1995 utility boiler total capacity versus capacity factor — MARAMA region
2-11
-------
a capacity factor well over 60 percent, compared with about 40 percent for NESCAUM. One
reason for this is that in MARAMA the boiler generating capacity is principally coal-based and coal
is typically much lower in price and therefore, more economical.
23 NOX EMISSIONS
NOX emissions inventory data for the population of utility boilers in each region were
calculated using an average annual emission factor (Ib/MMBtu) multiplied by the size of the boiler
(MWe), its average heat rate (Btu/kW-hr), and its capacity factor in percent. The reported
emission factor represents the anticipated emission level that each boiler will have following the
implementation of RACT controls, if applicable, or its current baseline (uncontrolled) level, if
RACT is not applicable and no controls were implemented starting in June 1995. As will be shown
later, RACT controls apply primarily in NESCAUM and Pennsylvania where state RACT plans are
applicable and utilities have already installed selected controls. Because the retrofit of RACT for
some utilities is very recent and data are yet not available, it is likely that the estimates presented
here will change somewhat. Also, the selection of one emission level must reflect the average for
the year for the purpose of a yearly NOX inventory.
In many cases, the reported emission level reflects instead a control limit imposed over a
much shorter averaging period and may either be lower or higher than its yearly average. This
emission level is often influenced by seasonal fuel mix, load dispatch and degree of control applied.
Finally, for selected utilities, baseline emission levels are yet to be developed through the planned
installation of continuous emission monitors. For such facilities, default emission factors
corresponding to RACT mandated emission limits were suggested by the utility as interim levels
until more accurate data are available.
The heat rate of the boiler is defined as the heat input to the unit in Btu/hr, from the high
heating value of the fuel, divided by the gross power generated in kW-hr. As in the case of NOX
emissions, the value of the heat rate varies with capacity factor, fuel mix, and other plant factors.
For this study, no attempt was made to obtain a seasonal heat rate coupled with capacity factor.
2-12
-------
Instead, a yearly average heat rate was sought. For many boilers this value was obtained from
selected utilities that responded to the questionnaire asking for an estimate of the heat rate for 1995
and beyond. When not available, the average value that was used in the 1987 inventory (Castaldini,
1992) was used or an average of 10,000 Btu/kW-hr when no data was available. With this in mind,
the following data represents the estimate of NOX emission levels expected by June 1995.
Figures 2-12 and 2-13 illustrate the range in NOX emission factors for the various categories
of utility boilers in the NESCAUM and MARAMA regions. The data were developed from a
survey of current post-RACT emissions or anticipated emissions following the implementation of
planned RACT controls. RACT implementation plans of utilities, and current state emission
inventories, were reviewed to obtain this information. Where emissions data were not available,
RACT guideline levels of 0.45 Ib/MMBtu and 0.5 Ib/MMBtu were used for coal-fired tangential
and wall-fired boilers, and 0.25 and 0.30 Ib/MMBtu for gas- and oil-fired units.
For coal-fired boilers in the NESCAUM region, as illustrated in Figure 2-12, the categories
include: low-NOx burner controlled tangential and wall-fired units; flue gas treatment (FGT)-
controlled tangential, wall and cyclone boilers; and boilers controlled with a variety of combustion
modifications. Because of the widespread application of RACT in this region, no data are reported
for uncontrolled boilers. With the exception of two cyclone boilers equipped with commercial FGT
controls, all other boilers exhibit post-RACT NOX in the range of 0.34 to 0.45 Ib/MMBtu, with wall-
fired units having a reported controlled level slightly higher than tangential units. In spike of the
FGT controls, coal-fired cyclones in NESCAUM, as a group, continue to show the highest NOX
loading.
Figure 2-13 shows similar data for the MARAMA region. Because no commercial FGT
controls are in place on coal units in this region, no emission data are shown for this control
category. Several coal-fired boilers remain uncontrolled in MARAMA. Tangential units show a
range in uncontrolled NOX between 0.45 and 0.70 Ib/MMBtu. Uncontrolled wall-fired boilers show
a range of 0.5 to 1.21b/MMbtu. LNB-controlled boilers have an average of NOX level of
2-13
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1.6
1.4
I1'2
i
So.e
X
§0.6
0.4
0.2
NESCAUMONLY
LNB - AM tow NOxburners with and without SOFA
FGT - All catalytic and noncatalytic controls
Cm - Combustion controls including OFA
High
Average
Low
30,000
20,000 C
10,000 X
O
UncTang LNB Tang FGT Tang FGTCycl CTRWall
UncWall LNB Wall FGT Wall CTRTang
Figure 2-12. 1995 NOX emission factors and loading — coal-fired boilers in NESCAUM
1.4
1.2 -
m
0.8
X
O
0.4
MARAMAONLY
LNB - All low NOx burners with and without SOFA
FGT - All catalytic and noncatalytic controls
CTR - Combustion controls including OFA
1 \ 1 1
ig FGTCycl CTRWall
FGT Wall CTRTang
• •• :
ig LNB Tang FGT Tang
UncWall LNB Wall F
High
Average
Low
Figure 2-13. 1995 NO emission factors and loading — coal-fired boilers in MARAMA
2-14
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approximately 0.50 Ib/MMBtu. Figure 2-14 and 2-15 illustrate the data for oil/gas-fired boilers.
In NESCAUM, reported uncontrolled units are few. The vast majority of boilers have conventional
combustion controls already in place, while some have reported to fuel switching. In general,
average NOX levels for these units are maintained within the regulated limits of 0.20 to
0.30 Ib/MMBtu. As will be discussed later, because of their number and total generating capacity,
combustion controlled oil/gas-fired boilers in NESCAUM continue to be responsible for the bulk
of the emissions, approximating 55,000 tons/year.
In MARAMA, oil- and gas-fired boilers are few in comparison and consequently the total
NOX loading is lower. NOX emission levels from either combustion-controlled or uncontrolled
boilers are higher, possibly because of greater reliance on residual oils. NOX levels for uncontrolled
boilers average 0.3 Ib/MMBtu for tangential units and 0.5 Ib/MMBtu for wall-fired units. Reported
LNB performance on few boilers averages at 0.45 Ib/MMBtu. As stated earlier, these emission
levels are greatly influenced by the fuel type and other boiler design factors.
Figure 2-16 illustrates that the total NOX loading for both regions is estimated to be slightly
less than 950,000 tons/yr. Of this, nearly 3/4 is attributable to coal-fired utility boilers in the
MARAMA region, principally Pennsylvania and North Carolina as will be shown later. Oil/gas-
fired units in MARAMA are not a major source category in contrast with the other major boiler
groups.
A recent NOX inventory estimated that the NESCAUM region emitted 382,000 tons/yr from
utility boilers in 1987 (Castaldini, 1992). As shown in Figure 2-17, the 1990 NOX inventory for all
power generation equipment (boilers and gas turbines) in NESCAUM was estimated at 435,000 tons
(Tech Environmental, 1994). The post-RACT NOX inventory for utility boilers in NESCAUM only
is estimated to be about 240,000 tons/yr, the result of recent RACT controls already in place as of
May 31, 1995. In NESCAUM, this reduction in NOX is estimated to come more from coal-fired
power plants as the proportion of NOX between coal- and oil/gas-generated NOX in the post-RACT
phase is shifted from more coal-based NOX in 1987 to a more evenly contribution between the two
2-15
-------
0.6
0.5
•«->
CD
0.4
X
O
0.3
0.2
0.1
NESCAUM ONLY
LNB - All low NOx burners with and without SOFA
FGT - Al catalytic and noncatalytic controls
CTR - Combustion controls including OFA and rebum
FSW- Fuel switching
High
Average
Low
UncTang FSW Wall FGT Tang FSW Tang CTR Wall
UncWall LNB Wall FGT Wall CTR Tang
40,000
30,000
20,000
10,000
0
Figure 2-14. 1995 NOX emission factors and loading — oil/gas-fired boilers in NESCAUM
0.6
0.5 -
•»—'
CD
0.4 -
X
O
0.3
0.2
0.1
MARAMAONLY
LNB - AH low NOx burners with and without SOFA
FQT - All catalytic and noncatalytic controls
CTR - Combustion controls including OFA and reburn
FSW - Fuel switching
High
Average
Low
UncTang LNB Tang FGT Tang FSW Wall CTR Wall
UncWall LNB Wall FGT Wall CTR Tang
10,000 ^
8,000 .>>
6.000 §
4.000 ^*
2,000 O
o z
Figure 2-15. 1995 NOX emission factors and loading — oil-/gas-fired boilers in MARAMA
2-16
-------
MARAMA Coal 72.4%
NESCAUM Oil/Gas 11.0%
NESCAUM Coal 13.9%
MARAMA Oil/Gas 2.7%
Total NOx Emissions
943,000 tons/yr
Figure 2-16. Post-RACT 1995 utility boiler NOX emissions by region
tons/yr NOx
1,200,000
1,000,000 -
I NESCAUM
MARAMA 1995 data includes 1990 N. Carolina data.
New Jersey is incl in NESCAUM and not in MARAMA.
OTR excludes NC and includes only portion of VA
MARAMA
OTR
Figure 2-17. NOX emissions reductions from utility boilers
2-17
-------
major fuel groups in 1995. For the MARAMA region, the 1990 NOX inventory was estimated to
be about 795,000 tons/yr, more than half contributed by boilers in Pennsylvania. For 1995, the
MARAMA inventory is projected to be reduced to 708,000 tons/yr, with the reduction attributed
almost entirely to RACT controls applied on Pennsylvania coal-fired boilers. For the OTR, which
combines the NESCAUM and MARAMA regions but excludes North Carolina and parts of
Virginia, the total utility boiler NOX inventory is estimated to be about 1 million tons/yr in 1990
and estimated to decrease below the level of the MARAMA inventory at about 680,000 tons/yr in
1995.
Figures 2-18 and 2-19 illustrate the NOX attributed to each state, again in the post-RACT
phase. For NESCAUM, New York continues to dominate followed by Massachusetts and New
Jersey. As Figure 2-16 had suggested, the coal- and oil/gas-based NOX is nearly equal for this
region. Of particular note, is the total NOX level from utility boilers in New Hampshire. Large
NOX reductions from pre-RACT levels were achieved in this state because of the retrofit of the two
largest NOX emitters units in the state and in the entire NESCAUM region. The cyclone units at
the Merrimack station were recently retrofitted with gas treatment controls, reducing NOX from a
combined pre-RACT level of more than 33,000 tons/yr to about 18,000 tons/yr. In MARAMA,
Pennsylvania will continue to lead in total utility boiler NOX emissions with about 280,000 tons/yr,
even with RACT controls. North Carolina utility boiler, will remain uncontrolled because RACT
is not required in the state, emitting an estimated 227,000 tons/yr. Maryland will continue to emit
more than twice the level of NOX from utility boilers in Virginia, even though boilers in Virginia
are, for the most part, not required to install RACT controls. District of Columbia has a small level
of utility boiler generated NOX because of its few units and oil/gas-based generation.
Figures 2-20a and 2-20b illustrate the distribution of NOX by boiler firing design and fuel
in each state. Total NOX emissions from tangential coal-fired boilers are estimated to be about
338,000 ton/yr, about 20 percent less than coal-fired boilers with circular burners. Emissions are
typically commensurate with the boiler capacity. For example, in Pennsylvania tangential coal-fired
2-18
-------
NOx (tons/Yr)
120,000
100,000
80,000
60,000
40,000
20,000
NY MA NJ NH CT ME VT
Figure 2-18. Post-KACT 1995 utility boiler NOX emissions by state — NESCAUM region
NOx (tons/Yr)
350,000
300,000
250,000
200,000
150,000
100,000
50,000
NC
MD VA
State
DE
DC
Figure 2-19. Post-RACT 1995 utility boiler NOX emissions by state — MARAMA region
2-19
-------
PA 39.9%
NC 21.5%
MD 14.0%
CT 1.9%
MA 2.5%
NY 7.6%
DE 1.3%
VA 11.2%
a. Coal, T-fired
337,666 tons/yr
PA 31.4%
NC 36.6%
MO 11.5%
b. Coal, W-fired
403,705 tons/yr
NY 20.7%
NJ 24.2%
NH 30.2%
c. Coal, all slagging
59,831 tons/yr
NY 85.7%
VT 14.3%
d. Coal and wood stokers
2,122 tons/yr
Figure 2-20a. Post-RACT 1995 coal-fired utility boiler NOX emissions
DC DE VA
MD
CT
a. T-fired
69,100 tons/yr
NY 31.3%
MA 38.2%
NJ 17.8%
b. W-fired
52,687 tons/yr
NJ 61.1%
NY 5.6%
CT 33.3%
c. Other firing types
7,691 tons/yr
Figure 2-20b. Post-RACT oil/gas-fired utility boiler NOX emissions
2-20
-------
boilers have a greater total generating capacity than wall-fired units, whereas the opposite is true
for North Carolina. Also, wall-fired boilers tend to be higher emitters, when uncontrolled, than
tangential units. This explains the higher NOX levels associated with wall-fired boilers and the
contribution of North Carolina units to the total NOX loading from these boiler types. Stokers are
principally in two states and emit a total of 2,100 tons/yr of mostly uncontrolled NOX. Coal-fired
cyclone boilers and all other slagging furnaces (wet bottom units) are located principally in four
states and combined they emit nearly 60,000 tons/yr, and nearly one half of the NOX is emitted
from boilers already equipped with gas treatment technologies. Oil/gas-fired tangential and wall
units are present in most states. New York, Massachusetts, and New Jersey account for the bulk
of these emissions. Although fewer in number, tangential oil/gas-fired units tend to have larger
capacities than wall-fired units, especially in MARAMA. Therefore, as a whole they account for
a larger portion of the total NOX. Other oil/gas-fired boiler design types emit relatively low levels
of NOX.
2.4 RACT CONTROLS
In recent years, many NOX emission controls have been implemented in the Northeast and
Mid Atlantic regions on existing utility boilers. The requirement for these controls has come from
a variety of local and, more recently, state regulations that aim to reduce ground level ozone levels.
Depending on the state, several boilers have been retrofitted with low-NOx burners (LNB), a variety
of combustion controls that target a specific NOX level, or even flue gas treatment with or without
combustion controls for low levels of NOX emissions either as a demonstration project or as a
commercial application of the technology to meet RACT limits. Still other units have seen gas
cofiring and conversion to permit dual fuel firing capability for either seasonal or continuous NOX
control. Because of ozone nonattainment status and because of their position with respect to the
OTR, some states, such as North Carolina and Virginia, did not require RACT controls by May 31,
1995. Consequently, many utility boilers in these states remain uncontrolled.
2-21
-------
In order to project the NOX reduction potential from RACT-controlIed sources it is
important to assess the level of control and record control technologies that are already in place to
permit already reduced levels of NOX emissions. Therefore, this section provides a brief survey of
the control technologies that have been implemented in response to state regulations.
Figure 2-21 illustrates the types of controls in place for the entire utility boiler capacity in
both the MARAMA and NESCAUM region. The categories include boilers controlled with:
• Low-NOx burners (LNB) with or without overfire air, including low NOX cell burners
(LNCB)
• Flue gas treatment controls such as all different applications of selective noncatalytic
reduction (SNCR) and selective catalytic reduction (SCR), and hybrid systems
• Boiler decommissioning because of planned or preliminary retirement
• A variety of combustion controls such as flue gas recirculation (FGR), burners out of
service (BOOS), low excess air, burner tuning, overfire air
MWe
35,000
LNB : LNB, LNB+OFA, LNCB
FGT: SNCR, SCR, HYBRIDS
RET: RETIRED, STANBY, MOTHBALL
CTR : COMBUST. CONTROLS (LEA, FGR, BOOS, etc)
UNO : UNCONTROLLED
FSW: FUEL SWITCHING
NRP : NOT REPORTED
LNB
UNC CTR NRP FGT FSW RET
Planned Control Technology
RPW
Figure 2-21. Post-RACT 1995 utility boiler control technologies — total plant capacity
2-22
-------
• Repowering technologies that aim to boost plant capacity with high efficiency gas
turbines with heat recovery steam generators and using existing plant equipment. This
approach completely transforms the power generation cycle to include combined cycle
(Brayton-Rankine) and cogeneration facilities
• Fuel switching including the installed ability to fire an additional fuel, typically natural
gas, on a continuous or seasonal basis, providing either a fraction of the total fuel
(cofire) or all the fuel (conversion) requirement. This category also includes some gas
reburning approaches installed on oil/gas-fired tangential boilers, such as LILCO's
Barrett Station.
Two additional categories were included to account for boilers that have remained uncontrolled past
May 31, 1995 because RACT is not required by the governing state, and boilers for which
information regarding control plans was considered too sketchy (or completely unavailable) to be
reported. These latter units were given the label "not-reported". Uncontrolled boilers also include
units that are averaged in with other controlled boilers in a RACT compliance scenario that relies
on system-wide averaging rather than unit-by-unit control.
The data in Figure 2-21 illustrate a large capacity of boilers (more than 25,000 MWe) in
MARAMA controlled with LNB technologies followed by about 20,000 MWe of uncontrolled boiler
capacity, nearly all in MARAMA and nearly an equal amount of combustion-controlled capacity
principally in NESCAUM. The large LNB-controlled capacity is attributed primarily to coal-fired
boilers in Pennsylvania. Combustion controlled capacity is principally due to oil/gas-fired boilers
located in NESCAUM. Uncontrolled boilers are primarily coal-fired units in North Carolina and
Virginia where RACT controls are not required by federal statues. Because of the developing data
base, a large fraction of the boiler capacity, about 7,500 MWe, has sketchy data on control strategies
and RACT compliance plans as of this writing.
Details of Figure 2-21 showing similar data by fuel type are shown in Figures 2-22 and 2-23.
The uncontrolled and LNB-controlled coal-fired capacity in MARAMA is evident in Figure 2-22,
2-23
-------
500,000
LNB
COAL-FIRED
LNB : LNB, LNB+OFA, LNCB
FGT : SNCR, SCR, HYBRIDS
RET : RETIRED, STANBY, MOTHBALL
CTR : COMBUST. CONTROLS (LEA, FOR, BOOS, etc)
UNC: UNCONTROLLED
FSW: FUEL SWITCHING
NRP: NOT REPORTED
F43-T'J" 1
UNC CTR NRP FGT FSW RET
Planned Control Technology
RPW
Figure 2-22. Post-RACT 1995 utility boiler control technologies — coal-fired NOX emissions
70,000
CTR
OIL/GAS-FIRED
LNB : LNB, LNB+OFA, LNCB
FGT : SNCR, SCR, HYBRIDS
RET : RETIRED, STANBY, MOTHBALL
CTR : COMBUST. CONTROLS (LEA, FGR, BOOS, etc)
UNC : UNCONTROLLED
FSW: FUEL SWITCHING
NRP: NOT REPORTED
- t
NRP UNC LNB FGT RPW FSW
Planned Control Technology
RET
Figure 2-23. Post-RACT 1995 utility boiler control technologies — oil/gas-fired NOX emissions
2-24
-------
and the nearly 15,000 MWe oil/gas-fired capacity that is combustion controlled in NESCAUM is
also evident in Figure 2-23. FGT controls are entirely in the NESCAUM region, estimating to
reduce NOX from nearly 4,000 MWe of coal- and oil/gas-fired capacity. Controls include SNCR
and SCR on the Merrimack Station boilers, several SNCR controls on oil-fired boilers in
Massachusetts and Pennsylvania and other recent SCR installations on boilers in Massachusetts and
New Jersey.
Figure 2-24 illustrates the same data on a NOX emissions basis, comparing the total tonnage
of NOX emitted from utility boilers controlled by various technologies. The LNB-controlled NOX
is nearly 400,000 tons/yr, followed by 300,000 of uncontrolled NOX, nearly all in MARAMA and
more than 100,000 tons of NOX from combustion-controlled boilers in NESCAUM. Total NOX still
being emitted from FGT-controlled boilers exceeds 50,000 tons/yr.
500,000
400,000
.>• 300,000
(fl
X
O 200,000
100,000
ALL FUELS
LNB : LNB, LNB+OFA, LNCB
FGT : SNCR, SCR, HYBRIDS
RET : RETIRED, STANBY, MOTHBALL
CTR : COMBUST. CONTROLS (LEA, FOR, BOOS, etc)
UNC : UNCONTROLLED
FSW : FUEL SWITCHING
NRP : NOT REPORTED
LNB
UNC CTR NRP FGT FSW RET
Planned Control Technology
RPW
Figure 2-24. Post-RACT 1995 utility boiler control technologies — total NOX emissions
(all fuels)
2-25
-------
2.5 TRENDS IN UTILITY POWER GENERATION
The future of the electric power generation in the NESCAUM and MARAMA regions, and
throughout the country, is being shaped by important economic forces, energy and environmental
policies, and technology advances. These factors will likely change the profile of the just-described
power generation mix in these regions in ways that are difficult to project. These changes, however,
will have important effects on the NOX emission profile, the cost of controls, and NOX reduction
compliance options available to the electricity generating industry. Among the most evident factors
shaping the future of the industry are:
• Deregulation under the 1978 Public Utilities Regulatory Act (PURPA) and the more
recent 1992 PUHCA reform legislation, creating open competition among exempt
wholesale generators (EWG): utilities, nonutility generators (NUG), and independent
power producers (IPPs) for the generation and retail wheeling of new electrical power
on a low-cost basis
• Changing fuels economics affected by current pricing and availability of natural gas
compared to residual oil, and environmental benefits of coal switching to meet Acid
Rain regulations
• Technological advances in power generation equipment, principally gas-turbine based
cogeneration and combined cycle plants, and projected advances in coal-based
integrated gasification and combined cycle plants and fluidized bed combustors
• Equipment life extension programs to minimize expenditures by utilities caught in a
more competitive environment
• Interplay between NOX regulations stemming from Title I and Title IV of the Clean Air
Act Amendments and potential impact of air toxic controls on utilities from Title III
For the remainder of this century, and into the foreseeable future, the power generation
industry will face transition and uncertainty. Open and more intense competition for low-cost
electricity are leading to increased deregulation of the electric power industry. The industry was
2-26
-------
first deregulated with the passage of PURPA and more recently by the amendment of PUHCA that
created the Exempt Wholesale Generator (EWG) to enable IPP and utilities to compete for new
power generation. This open competition coupled with concerns for the environment and energy
saving measures are causing some fundamental changes in the make up of the future mix of power
generation equipment. Eventually, these equipment changes will have an effect on the generation
of emissions and the application of NOX control technologies. Most evident is the slower growth
in new power generation forecasted for the next decade. Led by voluntary energy savings programs,
energy economics, and utilities own demand side management programs, the electricity generation
annual growth is forecasted to average only 2 percent, a drop from nearly 3 percent from the past
decade (Ford and Griggs, 1993). Much of the forecasted slower growth is in peak capacity and
cogeneration/combined cycle base loaded capacity that is being filled by gas turbine based simple
and combined cycle plants.
Deregulation in the electric industry has also resulted in intense competition among the
once-regulated utilities to retain existing large clients and for new base load growth. Lowest power
cost is often being supplied by IPPs and other NUGs in the form of combustion turbine
cogeneration and combined cycle plants and even steam generating plants such as conventional coal-
fired boilers and fluidized bed combustors. These new plants are allowed to compete for wholesale
power sales using existing transmission access. This retail wheeling competition provides a
competitive edge to more efficient IPP plants eroding base power generation from utilities
conventional power plants. In fact, the demand for electricity from utility plants in the Northeast
and elsewhere is at an all time low. Many utility boilers currently operate at historically low
capacity factors as power purchase from IPPs increases. Further deterioration in load dispatch from
conventional steam cycle plants is anticipated as new IPP-based generation compete more efficiently
for electricity demand even with a growth in overall power consumption. Trends shown in
Section 2.2 illustrate how in NESCAUM capacity factors are lower on average than just a few years
ago.
2-27
-------
In an attempt to maintain or increase ratebase, utilities are planning repowering projects,
adding peaking capacity, and installing new cogeneration plants using existing infrastructure to serve
large industrial clients. Many of these projects will add additional gas turbine based power beyond
that already in place and projected from IPPs. New technological advances in large industrial and
power generation gas turbines are resulting in very low NOX emissions and improved heat rate.
Also, gas turbine plants have a much lower initial capital requirement providing additional economic
incentive for their projected growth. Other forecasted utility trends include life extension program
for existing equipment, relegating older and less efficient plants to meeting peaking demand. Life
extension of existing older plants will also delay costly decommissioning of older equipment and
disposal of asbestos insulated materials.
Fuels pricing and availability also have large effects on the mix of power generation
equipment, capacity, load dispatch strategies, and emissions. The favorable prices for natural gas
and the availability of long-term gas contracts, coupled with developing environmental regulations
for NOX and SO2 reduction favoring clean fuels, are responsible in part for the growth of gas
turbine-based power generation. Gas availability and competitive pricing is also affecting power
dispatch and fuel selection. Several plants with oil/gas firing capability rely more heavily on natural
gas rather than oil, for example, altering the baseline NOX and projected feasibility and effectiveness
of controls. Natural gas prices have for the past 10 years been lower than residual oil for the
utilities. Some utilities are evaluating alternate low-cost fuels, such as Orimulsion, to increase their
economic competitiveness among the new power generation group.
All these trends will affect the current profile of boilers and power generation fuels in the
Northeast and mid Atlantic areas of the country in ways that are still evolving. For example, older
less efficient boilers can be placed on mothball or cold start-up for peaking capacity. Installation
of expensive low-NOx controls for these units may prove unnecessary as most of the NOX reduction
will be realized from changes in load dispatch. It is important, therefore, to consider that, in
addition to environmental controls being mandated on utility boilers, several other economic forces
2-28
-------
are at play changing the way electrical power is generated and distributed. These forces will likely
determine how quickly old plants are retired, which fuels will be burned and the optimum power
dispatch that considers lowest power production cost as well as compliance with environmental
. regulations.
2-29
-------
REFERENCES FOR CHAPTER 2
Castaldini, C, "Evaluation and Costing of NOX Controls for Existing Utility Boilers in the
NESCAUM Region," EPA 453/R-92-010, December 1992.
Ford, G.C. and S. L. Griggs, The North American Power Generation Business Competing in the
1990s," in Proceedings of the Power-Gen Americas '93: November 17-19, 1993, Dallas, Texas, p. 4.
Tech Environmental, Inc., "Feasibility of a Regional Market-Based NOX Cap System for the Ozone
Transport Region," prepared for NESCAUM and MARAMA, September 1994.
2-30
-------
CHAPTERS
PHASE H NOX CONTROL OPTIONS
The previous chapter described a population of utility boilers with a wide range of yearly
emission levels that vary with emission factors, boiler capacity, and utilization. Emission factors,
in turn, vary because of fuel, firing configuration, furnace heat release rates, and degree of NOX
control already in place because of the May 31, 1995, RACT deadline. For example, a large
fraction of the installed coal-fired capacity in two MARAMA states, North Carolina and Virginia,
will have few or no NOX controls. This is because RACT does not apply to all states within the
MARAMA region. Therefore, units in North Carolina and in several counties of Virginia tend to
have the higher NOX emission factors. The majority of the boilers in NESCAUM and MARAMA,
however, already have some degree of NOX control. These controls range from LNB-based
technologies and combustion modifications to novel flue gas treatment devices. Further reductions
from these controlled levels will be possible only with application of technologies that are
compatible with existing ones. Retrofit potential for specific controls will hinge on technical
feasibility, commercialization status, cost, and many site-specific considerations.
Control candidates considered for post-RACT application on utility boilers exclude
conventional "first-round" combustion controls such as LNB, flue gas recirculation (FOR), burners
our of service (BOOS), overfire air (OFA), or combination of these. Although not always the case,
RACT compliance for coal and oil/gas-fired boilers in the Northeast has relied on these types of
controls. Utility boilers that have undergone retrofit of new LNB or combustion modifications such
as FOR, BOOS, or OFA have often exhausted the ability for further NOX reductions with additional
combustion controls. Although minor additional NOX trim is sometimes possible with optimization
3-1
-------
of existing combustion equipment, NOX reductions greater than 25 percent from post-RACT levels
are often not possible without gas treatment. The only exceptions, perhaps, are gas reburning and
cofiring technologies, and full-scale gas conversions. Although viewed as combustion modifications,
gas reburning aims to suppress the NOX already formed in the main burner zone and, in this way,
it can achieve the additional reductions being considered for the post-RACT period.
Table 3-1 lists the candidate retrofit controls for NOX reductions on coal- and oil/gas-fired
utility boilers. For uncontrolled coal-fired cyclones, candidate controls include coal and gas
reburning and a variety of FGT options. FGT controls all rely on the properties of ammonia-based
compounds to reduce NOX with or without the presence of catalysts. These FGT options include
few commercial NOX/SOX combined gas treatment systems with recent demonstrations in the U.S.
and commercial applications in Europe. For other coal-fired boiler types, equipped with either low-
NOX concentric firing systems (LNCFS™) for tangential firing or low-NOx circular burners for wall
firing, controls are similar but exclude coal reburning and include gas cofiring and gas conversion.
However, as discussed later, experience with either gas cofiring and conversion options with low-
NOX burner-equipped boilers is minimal. Further, many LNBs just recently retrofitted on
pulverized coal-fired boilers, do not have gas cofiring capability. Although gas cofiring capability
can be readily added to coal- and oil-fired units, and several boilers already have, the retrofit of this
capability represents an additional cost consideration.
For gas/oil-fired boilers, post-RACT controls also include gas cofiring for oil-based units,
reburning for either oil- or gas-fired boilers, and gas conversions from oil to gas. In place of
combined NOX/SOX controls, catalytic air heaters (AH-SCR or CAT-AH) used alone or in
combination with either SNCR or SCR systems offer additional control options for principally gas-
fired boilers, and potentially coal-fired boilers as well. SO2 scrubbing needs for oil/gas-fired boilers
are typically not cost-effective because lower sulfur fuels or cofiring can be used to regulate SO2
emissions.
3-2
-------
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3-3
-------
It is evident from recent retrofit experiences in the U.S. and Europe, for example, that
several post-LNB control options have made progress toward greater reliability and improved
performance. These recent experiences and successes clearly point to improved feasibility of retrofit
to a broader family of boilers, even some difficult retrofits. For example, flue gas treatment and
gas-based controls have been applied to uncontrolled and combustion-controlled boilers with
significant success and little or no reported operational impacts. In fact, several new and existing
boilers in the U.S. have either been retrofitted with these controls or are scheduled to in the next
several months. Operational experience is growing rapidly and preliminary results often indicate
better than guaranteed performance.
Tables 3-2 and 3-3 list known retrofit and new boilers in the U.S. equipped with post-RACT
controls considered in this study. Retrofits include both commercial and demonstration units. The
list includes more than 15 GW of gas-based technologies, principally cofiring and full-scale gas
conversions to permit 100 percent gas-firing capacity. Reburning technologies have focused
primarily on the demonstration of the technology on smaller size utility boilers (<200 MW),
although larger retrofit applications are planned. The list of domestic flue gas treatment
installations is also large. In fact, the total SNCR- and SCR-controlled utility boiler capacity, in
place and planned for the near future, amounts to nearly 15,000 MWe as well. Most of the capacity
is dedicated gas-fired and is located in California. However, about 1,200 MWe of coal-based
capacity is planned for SCR, about one half new installations and the remaining retrofits of existing
plants. No combined SOX/NOX control technologies are either installed or planned in the U.S.,
although DOE-sponsored demonstrations have shown promising results and some installations have
taken place in Europe.
The following sections briefly describe the technology, summarize the reported performance
and operational experience, and draw some general conclusions about the applicability on RACT-
controlled boilers in the Northeast and Mid-Atlantic regions. The description of the various
technologies will be limited to brief overview of the fundamental mechanisms that promote NOX
3-4
-------
Table 3-2. Domestic utility boilers experience with gas-based and flue gas treatment NOX
control technologies
Control
Technologies
Utility Company
Station Identification and
State
Boiler Size and Firing Type
Gas cofiring
(in place)
Detroit Edison
Duquesne Light Co.
Alabama Power Co.
S. Indiana Gas & Electric/Alcoa
Public Service Co. of Oakland
TU Electric
Pennsylvania Electric Co.
Illinois Power
Kansas Power & Light
Texas Municipal
Centerior Energy
Electric Energy
New England Power Service
New England Power Service
Philadelphia Electric
Illinois Power
Potomac Electric Power Co.
Potomac Electric Power Co.
Potomac Electric Power Co.
Potomac Electric Power Co.
Public Service Electric & Gas
Mississippi Power Co.
Mississippi Power Co.
Electric Energy Inc.
Electric Energy, Inc.
Electric Energy, Inc.
Electric Energy, Inc.
Electric Energy, Inc.
Public Service Electric & Gas
Pacific Corp.
Pacific Corp.
Jacksonville Electric Authority
Greenwood Unit 1, MI
Cheswick Unit 1, PA
Gadsden Unit 1, AL
Warrick Unit 1, IN
Northeastern Unit 4, OK
Big Brown Unit 1, TX
Conemaugh Units 1 & 2, PA
Hennepin Unit 1, IL
Lawrence Unit 5, KS
Gibbons Creek, TX
Eastlake Unit Unit 2, OH
Joppa, Unit 4, IN
Brayton Point Unit 4, MA
Brayton Point Unit 1, MA
Cromby Unit 2, PA
Wood River Unit 4, IL
Chalk Point Unit 1, MD
Chalk Point Unit 2, MD
Chalk Point Unit 3, MD
Chalk Point Unit 4, MD
Hudson Unit 2, NJ
Jack Watson Unit 4, MS
j'ack Watson, Unit 5, MS
Joppa Unit 1, IL
Joppa Unit 2, IL
Joppa Unit 3, IL
Joppa Unit 4, IL
Joppa Unit 5, IL
Mercer Unit 1, NJ
Naughton Unit 1, WY
Naughton Unit 2, WY
Northside Unit 1, FL
Oil-fired 815 MWe wall
Coal-fired 570 MWe tangential
Coal-fired 60 MWe tangential
Coal-fired 150 MWe wall
Coal-fired 450 MWe tangential
Coal-fired 575 MWe tangential
Coal-fired 936 MWe tangential
Coal-fired 71 MWe tangential
Coal-fired 500 MWe tangential
Coal-fired 440 MWe tangential
Coal-fired 100 MWe tangential
Coal-fired 181 MWe tangential
Oil-fired 450 MWe wall
Coal-fired 250 MWe tangential
Oil-fired 220 MWe tangential
Coal-fired 113 MWe tangential
Coal-fired 364 MWe, wall
Coal-fired 364 MWe, wall
Oil-fired 659 MWe, tangential
Oil-fired 659 MWe, tangential
Coal-fired 660 MWe, wall
Coal-fired 250 MWe, wall
Coal-fired 500 MWe, wall
Coal-fired 167 MWe tangential
Coal-fired 167 MWe, tangential
Coal-fired 167 MWe, tangential
Coal-fired 167 MWe, tangential
Coal-fired 167 MWe, tangential
oal-fired 326 MWe, wall
Coal-fired 163 MWe, tangential
Coal-fired 218 MWe, tangential
Oil-fired 275 MWe, wall
Gas cofiring
(planned)
S. Indiana Gas & Electric/Alcoa
Philadelphia Electric
Philadelphia Electric
New England Power Service
S. Indiana Gas & Electric/Alcoa
w England Power Service
Columbus Southern Power
Ohio Edison
Electric Energy Inc.
Warrick Unit 4, IN
Eddystone Unit 3, PA
Eddystone Unit 4, PA
Brayton Point Unit 3, MA
Warrick Unit 3, IN
Brayton Point Unit 2,
Conesvffle Unit 3, OH
Edgewater Unit 4, OH
Joppa Unit 6, IL
Coal-fired 300 MWe wall
Oil-fired 395 MWe tangential
Oil-fired 395 MWe tangential
:oal-fired 620 MWe wall
Coal-fired 144 MWE wall
Coal-fired 250 MWe tangential
Coal-fired 165 MWe wall
Coal-fired 105 MWe, wall
Coal-fired 167 MWe, tangential
Gas
reburning
'in place)
Illinois Power
City Water, Light & Power
Public Service of Colorado
Ohio Edison*
Central Illinois Co*
3ublic Service of Colorado"
Cansas Power & Light
-ong Island Lighting Co.
Hennepin Unit 1, IL
Lakeside Unit 7, OH
Cherokee Unit 3, CO
Niles Unit 1, OH
Edwards Unit 1, IL
Arapahoe Unit, CO
^awrence Unit 5, KS
Barrett Unit 2, NY
Coal-fired 71 MWe tangential
Coal-fired 33 MWe cyclone
Coal-fired 185 MWe wall
Coal-fired 110 MWe cyclone
Coal-fired 100 MWe wall
Coal-fired 100 MWe top-fired
Coal-fired 450 MWe tangential
Oil/gas-fired 185 MWe tangential
"Demonstration sites technology since removed.
3-5
-------
Table 3-2. Domestic utility boilers experience with gas-based and fuel gas treatment NOX
control technologies (continued)
Control
Technologies
Utility Company
Station Identification and
State
Boiler Size and Firing Type
Gas
conversion
(in place)
Jacksonville
Consumers Power
Arizona Electric
Potomac Electric
American Electric Power
American Electric Power
New England Power
Public Service of Colorado
Long Island Lighting Co.
Illinois Power
Illinois Power
Northern Indiana Public Serv.
Northern Indiana Public Serv.
Commonwealth Edison
Nortnside Unit 3, FL
Karn Unit 4, MI
Apache Units 2 & 3, AZ
Chalk Point Units 1 & 2, VA
Pickway Unit 3, OH
Conesville Unit 3, OH
Brayton Point Unit 4, MA
Arapahoe Unit 4, CO
Barrett Unit 2, NY
Hennepin Unit 1, IL
Hennepin Unit 2, IL
Michigan City Unit 12, MI
Mitchell Unit 4, IN
Fisk Unit 19, IL
Oil-fired 550 MWe Wall
Oil-fired 640 MWe Wall
Coal-fired 200 MWe turbo
Coal-fired 355 MWe wall
Coal-fired 100 MWe wall
Coal-fired 165 MWe wall
Oil-fired 432 MWe wall
Coal-fired 100 MWe top-fired
Oil-fired 185 MWe tangential
Coal-fired 71 MWe tangential
Coal-fired 231 MWe tangential
Coal-fired 540 MWe cyclone
Coal-fired 138 MWe tangential
Coal-fired 374 MWe tangential
Gas
conversion
(planned)
Connecticut Light & Power
Connecticut Light & Power
Niagara Mohawk
Pennsylvania Power & Light
Pennsylvania Power & Light
Canal Electric
American Electric Power
American Electric Power
Illinois Power
Illinois Power
Devon Unit 7, CT
Devon Unit 8, CT
Oswego Unit 5, NY
Martins Creek Unit 3, PA
Martins Creek Unit 4, PA
Canal Unit 2, MA
Conesville Unit 1, OH
Conesville Unit 2, OH
Vermillion Unit 1, IL
Vermillion Unit 1, IL
Oil-fired 66 MWe wall
Oil-fired 48 MWe wall
Oil-fired 850 MWe wall
Oil-fired 820 MWe tangential
Oil-fired 820 MWe tangential
Oil-fired 581 MWe wall
Coal-fired 148 MWe cyclone
Coal-fired 136 MWe cyclone
Coal-fired 70 MWe tangential
Coal-fired 90 MWe tangential
SNCR (in
place)
New England Power Co.
New England Power Co.
New England Power Co.
Public Service of Colorado
Long Island Lighting Co.
Atlantic Electric Co.
Public Service Electric & Gas
Public Service Electric & Gas
Wisconsin Electric Co.
Niagara Mohawk Co.
Pacific Gas & Electric Co.
San Diego Gas & Electric
Southern California Edison
Southern California Edison
Southern California Edison
Southern California Edison
Southern California Edison
Southern California Edison
Southern California Edison
Los Angeles Dept. of W&P
New York State Electric & Gas
Connecticut Light & Power
Connecticut Light & Power
Pennsylvania Electric Co.
Public S. of New Hampshire
Montaup
Salem Harbor Unit 1, MA
Salem Harbor Unit 2, MA
Salem Harbor Unit 3, MA
Arapahoe Unit 4, CO
Port Jefferson Unit 3, NY
B.L. England Unit 1, NJ
Mercer Unit 2, NJ
Mercer Unit 1, NJ
Valley Plant Unit 4, WI
Oswego Unit 1, NY
Morro Bay Unit 1, CA
Encina Unit 2, CA
Etiwanda Unit 3, CA
Etiwanda Unit 4, CA
Alamitos Unit 4, CA
El Segundo Unit 3, CA
El Segundo Unit 4, CA
El Segundo Unit 2, CA
Alamitos Unit 3, CA
Scattergood Unit 1, CA
Milliken Unit 1, NY
Norwalk Harbor Unit 1, CT
Norwalk Harbor Unit 2, CT
Seaward Unit 5, PA
Merrimack Unit 1, NH
Sommerset 5, MA
Coal-fired 84 MWe wall
Coal-fired 84 MWe wall
Coal-fired 156 MWe wall
Coal-fired 100 MWe top-fired
Oil/gas-fired 185 MWe tangential
Coal-fired 138 MWe cyclone
Coal-fired 321 MWe wet-wall
Coal-fired 320 MWe wall
Coal-fired 70 MWe wall
Coal-fired 850 MWe wall
Gas-fired 345 MWe Wall
Gas-fired 110 MWe wall
Gas-fired 333 MWe tangential
Gas-fired 333 MWe tangential
Gas-fired 333 MWe tangential
Gas-fired 342 MWe tangential
Gas-fired 342 MWe tangential
Gas-fired 156 MWe wall
Gas-fired 333 MWe tangential
Gas-fired 150 tangential
Coal-fired 150 MWe tangential
Oil-fired 172 MW tangential
Oil-fired 182 MW tangential
Coal-fired 148 MW wall
Coal-fired 120 MWe cyclone
Coal-fired 100 MWe tangential
3-6
-------
Table 3-2. Domestic utility boilers experience with gas-based and fuel gas treatment NOX
control technologies (concluded)
Control
Technologies
Utility Company
Station Identification and
State
Boiler Size and Firing Type
SCR (in
place)
Public S. of New Hampshire
Chambers Works
Chambers Works
Public S. Electric & Gas
Southern California Edison
Southern California Edison
Southern California Edison
Southern California Edison
Southern California Edison
Southern California Edison
Southern California Edison
San Diego Gas & Electric
Los Angeles Dpt. Wtr & Pwr
Los Angeles Dpt. Wtr & Pwr
Los Angeles Dpt. Wtr & Pwr
Los Angeles Dpt. Wtr & Pwr
Merrimack Unit 2, NH
Chambers Unit 1, NJ
Chambers Unit 2, NJ
Mercer Unit 2, NJ
Huntingdon Beach Unit 2, CA
Ormond Beach Unit 1, CA
Ormond Beach Unit 2, CA
Alamitos Unit 6, CA
Redondo Beach Unit 7, CA
Redondo Beach Unit 8, CA
Mandalay Unit 2, CA
Encina Unit 2, CA
Haynes Unit 1, CA
Haynes Unit 2, CA
Haynes Unit 5, CA
Haynes Unit 6, CA
Coal-fired 338 MWe cyclone
Coal-fired 143 MWe wall
Coal-fired 143 MWe wall
Coal-fired 80 MWe wet waUb
Gas-fired 150 MWe wall
Gas-fired 750 MWe wall
Gas-fired 750 MWe wall
Gas-fired 480 MWe wall
Gas-fired 480 MWe wall
Gas-fired 480 MWe wall
Gas-fired 215 MWe wall
Gas-fired 110 MWe wall
Gas-fired 230 MWe wall
Gas-fired 230 MWe wall
Gas-fired 330 MWe wall
Gas-fired 330 MWe wall
SCR
(planned)
Orlando Utilities
Keystone Energy
Southern California Edison
Southern California Edison
Southern California Edison
Southern California Edison
Southern California Edison
Southern California Edison
Southern California Edison
SEI
New Stanton Unit 1, FL
Keystone Unit 1, NJ
Alamitos Unit 3, CA
Alamitos Unit 4, CA
Alamitos Unit 5, CA
El Segundo Unit 3, CA
El Segundo Unit 4, CA
Etiwanda Unit 3, CA
Etiwanda Unit 4, CA
Birchwood Station, VA
Coal-fired 460 MWe wall
Coal-fired 230 MWe wall
Gas-fired 320 MWe tangential
Gas-fired 320 MWe tangential
Gas-fired 480 MWe wall
Gas-fired 335 MWe tangential
Gas-fired 335 MWe tangential
Gas-fired 320 MWe tangential
Gas-fired 320 MWe tangential
Coal-fired 245 MWe tangential
bAt present, only one fourth (80 MWe) of boiler capacity (321 MWe) is treated with SCR.
3-7
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Table 3-3. Utility boilers in the United States with experience with gas-based and flue gas
treatment NOX control technologies
Control
Category
Gas-based
Controls
Rue Gas
Treatment
Controls
Technology
Natural Gas
Reburning
Gas Cofiring
Natural Gas
Conversions
SNCR-based Controls
SCR-based Controls
Station Identification and State
(Commercial and Demonstration Sites)
2 Units in Illinois
2 Units in Ohio
2 Units in Colorado
1 Unit in Kansas
1 Unit in New York
6 Units in Pennsylvania
3 Units in Massachusetts
3 Units in Indiana
2 Units in Texas
1 Unit in Alabama
1 Unit in Kansas
1 Unit in Ohio
7 Units in Illinois
1 Unit in Florida
1 Unit in Michigan
4 Units in Maryland
2 Units in New Jersey
2 Units in Mississippi
2 Units in Wyoming
6 Units in Illinois
4 Units in Ohio
2 Units in Michigan
2 Units in Arizona
2 Units in Massachusetts
2 Units in New Jersey
2 Units in New York
2 Units in Connecticut
1 Unit in Colorado
1 Unit In Florida
1 Unit in Indiana
10 Units in California
4 Units in Massachusetts
3 Units in New York
5 Units in New Jersey
1 Unit in Wisconsin
1 Unit in Colorado
2 Units in New Hampshire
1 Unit in Delaware
21 Units in California
4 Units in New Jersey
1 Unit in Massachusetts
1 Unit in Florida
1 Unit in New Hampshire
Boiler Capacity and Firing Type
521 MWe coal-fired tangential
143 MWe coal-fired cyclone
385 MWe coal-fired wall/other
185 MWe oil/gas-fired tangential
5,712 MWe coal-fired tangential
3,328 MWe coal-fired wall
2,043 MWe oil/gas-fired
974 MWe coal-fired tangential
620 MWe coal-fired wall
1,124 MWe coal-fired other
4,992 MWe oil-fired
1,392 MWe coal-fired wall
3,492 MWe gas/oil-fired
421 MWe coal-fired cyclone
741 MWe coal-fired other firing
6,965 MWe gas-fired
1,582 MWe dry-bottom coal-fired
659 MWe wet bottom and cyclone
3-8
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reduction, focusing instead on commercialization status, equipment and requirements, and site
modifications that influence the applicability and performance on existing facilities. It is not the
intent of this chapter to speculate on the optimum selection of any one control option for a specific
powerplant or NOX control target. This is because, the retrofit of controls on existing powerplants
can best be evaluated on a case by case basis and often more than one approach is possible to
achieve a certain NOX reduction efficiency or NOX emission target. Indeed, the selection of a
specific control option involves several technical, economic, and strategic decisions that are well
beyond the objectives of this report.
3.1 NATURAL-GAS-BASED CONTROLS
The environmental benefits of using natural gas instead of coal or residual oil are for the
most part obvious ones. Because natural gas is essentially free of sulfur and nitrogen and without
inorganic matter typically present in coal and residual oils, SO2 emissions can be essentially
eliminated; NOX emissions can be dramatically reduced; and organic and inorganic paniculate and
air toxic compounds essentially removed from all discharge streams leaving the boiler. With these
environmental advantages, it is obvious that natural gas would be viewed as a sound alternative
to coal or oil burning in existing powerplants to meet strict emission standards in all categories:
SO2, NOX, participate, and air toxics. Natural gas can become even more attractive when small
quantities can be used in a particular burner arrangement to maximize the NOX reduction benefits
of this clean burning fuel and improve operation of the plant.
Because of its ease of transport, ease of burning, and relatively low emissions, natural gas
is a premium utility boiler fuel. Its use is often relegated to severe nonattainment areas such as
Southern California, and to fuel new advanced, high efficiency, gas turbine-based power generation
equipment used in combined cycle or cogeneration applications. Also, natural gas is the fuel of
choice in many residential and commercial heating applications. Coupled with its normally higher
cost (on a Btu basis) compared to coal, utility concerns over long-term availability, especially during
severe winter months in the Northeast and other parts of the country, limit its attractiveness solely
3-9
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for environmental benefits. Recently, particular attention has been paid to the other, not-so-
obvious, benefits of natural gas use in boilers. These benefits focus on operation improvement,
capacity recovery, life extension, etc., that might help mitigate its primary disadvantages due to cost
and uncertain long-term availability.
The following subsections discuss the experience gained to date on the various retrofit uses
of natural gas in utility boilers. The principal uses of natural gas as a utility boiler fuel are:
• Cofiring with a primary fuel such as coal or oil
• Reburning by special application to maximize its NOX reduction properties
• Boiler fuel conversion when gas is used to replace coal or oil as the principal fuel
Each of these applications has its own advantages and disadvantages when considering NOX
reduction, overall environmental benefit, cost, operation, retrofit feasibility and other issues.
Natural gas use in each of these three applications can also be done on a year-around basis or
selectively, i.e., during the peak ozone season when NOX reductions are most needed and when
natural gas is more attractively priced. Seasonal use of controls, particularly natural gas-based
controls, can be economically attractive because of lower operating costs and, in the case of gas use,
more competitive fuel pricing. Seasonal use of controls, including natural gas controls, is discussed
in Section 3.5.
Cofiring and boiler fuel conversions have a long history in the power generation industry.
Fuel selection for power generation is based on economic consideration and availability. Various
federal regulations and initiatives have also affected utility decisions to burn one fuel over another.
In fact, many plants have undergone boiler fuel conversions over the years for a number of reasons
other than emission compliance. Reburning, however, is a more recent technological development
commercialized principally in response to the NOX reduction needs under the Clean Air Act
Amendments of 1990, especially its Title I ozone attainment provisions. Gas reburning aims
specifically to maximize the NOX reduction potential with a minimum amount of natural gas. Its
development has included demonstrations on LNB-controlled boilers to maximize overall NOX
3-10
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reduction, whereas similar evaluations have not occurred with either cofiring or full-scale gas
conversions. Finally, seasonal gas use has attracted some interest because periods of highest gas
availability to the utilities coincide with peak ozone season. NOX reductions during the peak ozone
season are deemed most beneficial to the goal of ground level ozone attainment in the NESCAUM
and MARAMA regions.
3.1.1 Cofiring
Gas cofiring involves the utilization of natural gas with another primary fuel, e.g. coal or oil,
for the purpose of emission reduction, overcoming load limitations, and for operational
improvements such as startups and improved ignition. The gas can be injected into the furnace
through existing startup guns, limited-capacity ignitors, or through gas spuds, nozzles or rings in
existing burner ports. Although there are no theoretical limits to the amount of gas cofiring, the
technology generally implies natural gas utilization less than 20 percent of the total heat input
(Harding, 1994).
A recent study sponsored by the Coalition of Gas-Based Solutions puts the number of gas-
cofire boilers in the Ozone Transport Region (OTR) at about 30 percent (Energy Venture Analysis,
1994). In the absence of any gas supply and firing capability, the plant would need access to gas
supply and install the needed equipment to permit 10-20 percent cofire. This equipment includes
gas mains to the plant from the nearest gas transmission pipeline, valves for flow control and
shutoff, burner nozzles in existing burner openings, new or modified flame scanners, and associated
combustion controls. For boilers with adequate supply of gas, little or no additional equipment
changes would be necessary.
The location of new gas nozzles in existing burner openings is important to the optimization
of NOX reduction potential, burner safety, turndown capability, NOX control level, and control of
the furnace exit gas temperature (FEGT) and steam temperatures. Research on tangential boilers,
for example, points to the top burner level as the optimum location for gas injection in what is
termed "close coupled" reburning (La Flesh, 1993). For circular low-NOx burners, locating the
3-11
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optimum injection method for NOX reduction has not been sufficiently researched. Opportunities
may be available to use small quantities of natural gas to improve the low-NOx performance of
today's LNBs.
Some of the benefits of cofire are (Harding, 1994):
• Clean startup
• Improved ESP operation
• SO2 trim for environmental compliance
• 25 to 50 percent NOX reduction depending on percent cofire
• Reduced flame impingement
• Load recovery with mills out of service
• Improved O2 control, carbon burnout, furnace slagging
Additional benefits may result from (Folsom, et al., 1993):
• Improved capacity factor
• Recovery of lost capacity due to switching to a lower sulfur, higher ash coal
• Lower CO2 emissions to alleviate greenhouse gases in the atmosphere
• Reduced air toxics from reduced use of toxic metal-bearing coals
• Improved ash quality, reduced ash disposal needs and associated costs
• Reduced auxiliary power for coal transport and pulverizing
• Lower stack opacity and particulate loading
• Low load combustion stability
• Overall improved powerplant operation and reduced maintenance
NOX reductions with gas cofiring are possible by various air and fuel staging techniques. To date,
gas cofiring methods have not been fully explored. Opportunities may exist to optimize gas injection
location to maximize NOX reduction and operational benefits.
Table 3-4 lists the NOX reduction data available on selected coal-fired utility boilers cofired
with natural gas. Although gas cofiring is being practiced in many more boilers (see Table 3-2), no
3-12
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3-14
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performance data has been reported for these other units. The data listed in Table 3-4 points to
a NOX reduction efficiency in the range of about 25 to 40 percent with natural gas accounting for
8 to 35 percent of the total heat input. All three boilers, for which there is NOX reduction data, are
tangential units equipped with OFA ports. Only the Lawrence Unit 5 has an LNB in place
equipped with a separate OFA system (SOFA). For this boiler, the controlled NOX emissions are
particularly low because of the operation of the LNB and because the subbituminous coal burned
is particularly conducive to very low NOX levels with combustion staging. Because the gas was
introduced at the top burner level, some reburning effect was also responsible for very low levels
of 0.11 Ib/MMBtu. In fact, these results are also presented in Section 3.1.2 under the subject of
reburning. These controlled levels would not be likely in most NESCAUM and MARAMA boilers
because coals are less volatile and furnaces are more compact. Smaller furnaces are generally used
for combustion of eastern bituminous coals. These boilers have higher heat release rate per unit
of waterwall area. The effect of higher heat release rate on NOX emissions and NOX reduction
efficiencies with gas use in coal-designed boilers will be revisited during the discussion on gas
conversions in Section 3.1.3. Other NOX cofiring demonstration tests are scheduled for the Warrick
Station of SIECO and Joppa Station of Electric Energy (Pratapas, 1994).
Table 3-5 lists boiler sites where gas cofiring is either being practiced or is under planning
stages for boilers burning predominantly oil. The results available for this study are limited to the
Brayton Point Unit 4 of New England Power Co (NEPCO). This wall-fired boiler is equipped with
FGR and was cofired with up to 70 percent gas to document the NOX reduction benefits. As shown,
with 30 percent cofire NOX was reduced only marginally from 0.29 Ib/MMBtu to 0.254 Ib/MMBtu
without FGR. Once FGR was reinstated, the NOX was reduced to 0.23 Ib/MMBtu with only 10
percent cofire. NEPCO has reported so far that the operation with gas cofire has been satisfactory
(Harding, 1994). Heat transfer tube materials in the superheater and reheater were upgraded to
sustain the increased FEGT and higher steam attemperation capacity was also installed to permit
operation with 100 percent gas.
3-15
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3.12 Reburning
In reburning, a fuel is injected above the primary combustion zone to create a "reburning
zone" where stoichiometric ratio is maintained fuel rich at 0.9 or lower for optimum NOX
reductions. At these low stoichiometries, various reducing species created from the natural gas fuel
react to reduce burner-generated NOX to molecular nitrogen. In commercial NGR systems, the
stoichiometry in the reburn zone can be varied depending on the amount of NOX control desired.
Because sufficient fuel is added to bring the overall stoichiometry fuel rich, it is then necessary to
add overfire air above the reburning zone to complete the combustion of the reburning fuel. This
final reaction zone is typically referred to as the "burnout zone". Reburning technology has also
been referred to as "fuel staging" and "in-furnace NOX reduction". Figure 3-1 illustrates the overall
fuel and air distribution inside a boiler furnace needed to accomplish the reburning process.
The spacing allotted between the three distinct zones is carefully customized to each boiler
taking into consideration many furnace design and operating parameters. Efficient mixing of the
reburning fuel with the combustion products is also critical to guarantee the maximum NOX
reduction possible with the minimum amount of reburning fuel and with minimal adverse impacts
in key furnace operating conditions. One fundamental application criterion is that the furnace must
have sufficient room above the main combustion zone for reburning and burnout to take place.
Most boilers have sufficient volume above the primary zone to achieve NOX reduction levels
reported in these NGR demonstrations. However, larger primary combustion zones needed for
effective LNB operation can reduce the effectiveness of the NGR process precluding economic
application. The amount of fuel needed is dictated by the excess air in the main burner zone and
by the NOX reduction required. Reburning fuel is typically in the 15 to 20 percent of the total heat
input.
The reburning fuel can be natural gas, propane, oil, and micronized coal. Natural gas is
often selected because gas it is easier and quicker to burn, requiring smaller furnace volumes above
the burnout zone, thus offering greater retrofit potential. In fact, all boiler types, with the possible
3-17
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Bnrnout Zone
• Normal excess air
Reburning Zone
• Slightly fuel rich
• NOx reduced to N2
Primary
Combustion Zone
• Reduced firing rate
• Low excess air
• Lower NOx
Combustion
Air
Figure 3-1. Gas reburning for NOX control (Pratapas, 1994)
exception of very small furnaces with high heat release rates, are candidate retrofits irrespective of
primary fuel type and firing configuration, and whether they are equipped with LNB or conventional
high turbulence burners. With either coal or oil, instead, the potential for incomplete combustion
of reburning fuel is much greater. To date, only one coal-reburning demonstration has taken place
on a cyclone boiler. Although this demonstration at the Wisconsin Power & Light Company Nelson
Dewey Station showed long term NOX emission reductions of 53 to 62 percent over the load range
(Yiegela, 1993), application of this technology to other cyclones and firing types remains difficult
3-18
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or not feasible because of insufficiency furnace volumes available above the main burner zone. The
installation cost of coal-reburning is also much higher than gas reburning (in most cases) because
of the requirements for pulverizers and burner penetration. Coal reburning is discussed in
Section 3.2.
The technology of reburning using natural gas is commercial and can be applied to all boiler
firing types with approximately equal NOX reduction performance. Boilers that have been
retrofitted with LNBs can also use gas reburning because the process targets the destruction of NOX
generated by the main combustion zone adding to the overall NOX reduction. Utility boiler OEMs
such as ABB-CE and B&W are offering the technology on a commercial basis. Energy and
Environmental Research Corporation, the firm that undertook many of the demonstrations on
utility boilers, is also offering commercial retrofits for gas reburning. These vendors offer slightly
different reburning approaches, but the NOX reduction concept remains the same.
ABB-CE has demonstrated reburning on coal and oil/gas-fired utility boilers and is pursuing
commercial applications on slagging furnaces in the Ukraine (LaFlesh and Borio, 1993; LaFlesh,
et al., 1993). The ABB-CE approach relies on either a conventional reburning zone separate from
the main burner zone or on a "close-coupled" reburning zone. The latter avails itself of the top
burner level of the corner-fired system to inject natural gas and is thus considered less capital
intensive. The separate OFA system of the LNCFS design can then provide the needed safety of
complete burnout air. This approach was tested at the Kansas Power and Light Lawrence 5 boiler
retrofitted with a low-NOx tangential burner system equipped with separate OFA. Because the
performance of the close coupled gas reburn was found to be nearly as effective as conventional gas
reburn, ABB-CE Services is actively promoting this approach for all gas reburn applications on
tangential boilers (La Flesh and Borio, 1993).
Natural gas reburn is presently the most efficient of the gas-based NOX control technologies.
With gas reburn, short-term NOX reductions up to 70 percent are possible on uncontrolled boilers
with as little as 15 to 20 percent gas use (Folsom, 1993). Cofiring instead with this amount of gas
3-19
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use would at best produce about 1/2 of the reburning NOX reduction performance. Only full-scale
conversions to 100 percent gas firing coupled with combustion modifications will be able to reach
NOX reduction performance levels that are attainable with gas reburning.
The exact mechanisms that control the gas reburning process are very complex. What is
known is that the NO produced in the burner primary zone is reduced by hydrocarbon (CH)
radicals that were generated from the decomposition of the reburn fuel via the following chemical
reaction:
NO + CH -* HCN + O (3'1)
The cyanide in turn will decompose to molecular nitrogen or re-form NO in the reburn zone.
Additionally, NO can decompose by reaction with hydrogen via the following reaction:
NO + H -* HN + O (3'2)
Most fuels can provide an adequate pool of CH and H reducing radicals in the reburning zone.
Several fuels have been investigated but none have shown greater NOX reduction efficiencies than
natural gas. The principal design parameters for effective reburning are:
• primary burner zone NOX level
• primary zone stoichiometry
• reburning zone stoichiometry
• rebuming zone temperature
• reburning fuel transport medium
• reburning fuel mixing
Higher initial NOX levels from the primary burner zone tend to produce higher reburning NOX
reduction efficiencies. This finding, reported by several investigators (Wendt, et al., 1991;
Takahashi, et al., 1981; and Chen, et al., 1989), suggests that the effectiveness of reburning
3-20
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decreases when applied to LNB-controlled boilers compared to uncontrolled units. In fact, the full-
scale data suggests that this is indeed the case, as will be shown later.
The stoichiometry of the primary zone plays an important role insofar as the amount of
reburning fuel needed to achieve desired reburning stoichiometry is affected. The higher the excess
air in the primary reburn zone, the greater the quantity of reburn fuel is needed to achieve desired
reburn stoichiometries. From a NOX reduction efficiency viewpoint, its effect is secondary to the
reburn stoichiometry.
Pilot- and full-scale tests clearly point to the reburn stoichiometry as the principal process
parameter affecting NOX reduction efficiency. The desired reburn stoichiometry is approximately
0.9, indicating that the amount of combustion air in the furnace is 10 percent below the theoretical
amount needed for complete combustion of the primary and reburn fuels. At this level, the NOX
emitted from the reburning process is minimized. Further reductions in reburn stoichiometry tend
to be either counterproductive or have little additional effect. Tests have also shown that high
reburn zone temperatures are more conducive to higher NOX reduction performance. For this
reason, the reburn fuel is often injected as close as possible to the primary burner zone without
actually suppressing combustion of the primary fuel. The other benefit of introducing the reburn
fuel as close as possible to the primary burners is to maximize the residence time of the gases within
the reburning zone before final air is added to complete combustion. Longer residence time
increases the effectiveness of reburning at a fixed reburn stoichiometry.
Methods for introducing natural gas into the reburn zone vary among the major gas reburn
vendors. For example, B&W uses conventional low NOX burners to inject gas, combustion air, and
flue gas and monitor combustion with flame scanners. This approach provides an additional
measure of combustion safety. One such retrofit is being planned for a cyclone boiler at the
Eastman Kodak plant in Rochester, NY. This retrofit will demonstrate the use of gas reburn as
RACT for smaller utility and large industrial cyclones. ABB-CE uses existing tangential burner
ports to introduce the reburn gas in a close coupled approach illustrated in Figure 3-2c. ABB-CE
3-21
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Gas Co-firing
Standard Gas
Reburning
Close-Coupled
Gas Reburning
Burnout
Zone
Rebum Zone j
Main
Combustion
Zone
• Air
• Gas
• Coal
• Coal
• Coal
• Coal
B
Figure 3-2. Various gas-firing approaches in T-fired coal boilers (Lewis, et al., 1994)
refers to the close coupled reburning concept, illustrated in Figure 3-2c and tested at Kansas Power
and Light Lawrence Unit 5, as selective gas cofiring. Gas residence time between coal and gas is
minimal, 0.05 to 0.10 seconds, with this configuration (Lewis, 1994). EER, instead, promotes the
use of multiple gas injectors. Since EER's gas injectors do not require burner components or an
air supply system, they are considerably simpler and require much smaller wall penetrations than
the B&W reburning burners. In all cases, natural gas must be injected with sufficient velocity to
promote good mixing. For this purpose, a transport medium is usually used. The transport medium
for the reburn fuel can be either air or flue gas. The oxidizing capability of the transport medium
is a factor in the overall process NOX reduction efficiency. Because flue gas has much lower oxygen
content than air, it tends to produce lower NOX emissions from the reburning process. Recirculated
flue gas is also used to improve the mixing of the reburn fuel. The mixing efficiency of the
reburning fuel with the combustion gas can have some impact on the process, especially for
reburning fuels other than natural gas.
3-22
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Table 3-6 lists the results of gas reburn demonstrations performed on coal-fired utility
boilers. Reburning has been tested on a total of 670 MWe of coal-fired utility boiler capacity at five
demonstration sites. NOX reduction efficiencies measured over the long-term ranged from 45 to
67 percent. Peak NOX reductions exceeded 70 percent. It is important to note that when gas
reburn is applied on uncontrolled boilers, its NOX reduction efficiency tends to be higher.
Therefore, NOX reductions recorded at the uncontrolled Lakeside Unit 7, Niles Unit 1, and
Hennepin Unit 1 were as high as 67 percent. Gas reburn demonstrations at Cherokee Unit 3 and
Lawrence Unit 5, instead, reported NOX reduction, attributable to reburning only, in the range of
about 20 to 50 percent when operating in conjunction with LNB technologies. This is important to
keep in mind in the context of post-RACT NOX reduction capabilities of selected retrofit controls.
Overall, operation of these boilers with gas reburn did not report any operational difficulties.
The only reportable impacts are minor changes in FEGT, use of attemperation flow and burner tilt
for steam temperature control, and a loss in boiler efficiency attributable to the increase in moisture
in the flue gas. The latter is an inevitable consequence of burning a higher hydrogen content fuel.
Table 3-7 lists gas reburning data on the only gas-fired domestic boilers. The Hennepin unit
is actually a coal-designed boiler with dual fuel (gas and coal) capability. Because the coal-designed
boilers have much larger furnaces than oil- or gas-fired units, the heat release rates per wall area
are much different and consequently peak furnace temperatures also vary. For this reason, the very
low NOX levels obtained at Hennepin with gas reburning on gas fuel should not be construed as
applicable to other gas-designed units. A similar type of unit is the Barrett Unit 2 boiler of the
Long Island Lighting Company which, originally designed as a coal-fired tangential boiler, has
always burned either oil or gas and has recently been retrofit with ABB-CE reburning technology.
Although no data are available from this retrofit, results similar to Hennepin Unit 1 burning gas
are expected. The data show that NOX level as low as 0.06 Ib/MMBtu was achieved on a long term
basis using gas reburning when firing gas. This level of NOX is not much lower than the reported
range in NOX achieved with only OFA control (0.09 to 0.10 Ib/MMBtu).
3-23
-------
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3.1.3 Gas Conversion
Gas conversion and cofire are similar only that conversion implies the ability to reach the
design steaming capacity of the boiler with 100 percent gas firing. As with cofiring, the equipment
retrofit to implement a complete fuel conversion or create a dual-fuel capability is dependent on
the existing burner equipment and control system. For conventional or low-NOx circular burners
on one or opposed walls of the furnace, the retrofit of 100 percent gas firing can be accomplished
with the addition of gas spuds, canes, or ring on each existing burner. Tangential burners in the
corners of the furnace, can also be readily modified to accommodate gas firing without removing
the coal or oil-firing capability. Because of the tilting capability of tangential burners, furnace exit
gas temperatures (FEGT) and superheat/reheat steam temperatures can more readily be controlled.
Steam attemperation is also a common powerplant practice for superheater and reheater
temperature control. Some boiler conversion engineering and architect firms believe that it is easier
to convert a coal-fired boiler than an oil-fired boiler to gas firing (Harding, 1994). This is because
the lower waterwall radiation from gas flames is offsej by the cleaner waterwalls in the absence of
slagging.
In general, however, as discussed above, the firing of 100 percent natural gas in larger coal-
fired furnaces tends to result in lower than expected FEGT effects. Although the gas flame is much
less radiative than coal or oil and therefore hotter, the combined effect of a large volume, cleaner
waterwalls and lower combustion air volumes tends to compensate for the hotter flame. The
equipment that must be evaluated before the conversion includes fans, burners, spray attemperators,
boiler tube metals, and economizer steaming capacity (Harding, et al., 1994).
Table 3-8 summarizes the reported NOX emissions with 100 percent gas burning in coal-
designed utility boilers. The boilers include units that were merely tested with 100 percent gas firing
on a short term basis because of readily available gas and existing equipment. The table also
includes boiler that have recently added 100 percent gas firing capability to either replace coal or
oil firing entirely or to be able to supplement either fuel as necessary. The reported NOX reduction
3-26
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3-28
-------
experience is based on a total of about 2,300 MWe of originally coal-fired boiler capacity,
2,000 MWe principally wall-fired and the rest corner-fired.
The NOX level measured with 100 percent gas firing is reported to vary from as low as
0.11 Ib/MMBtu, measured with combustion staging at the Arapahoe Power Station boiler, to as high
as 0.83 Ib/MMBtu, measured at the Mercer Power Station boiler without any combustion controls.
This very large range in emissions is the result of two principal effects: the burner zone heat release
rate and the degree of combustion air staging implemented. The impact of burner zone area heat
release rate is dramatic. The higher the heat released in a small burner zone, the higher is the peak
flame temperature and the more the Thermal NOX production. Because Thermal NOX is the
principal form of NOX from natural gas combustion, the effect of BAHR is very important, as
illustrated in Figure 3-3. Therefore, because Mercer Unit 2 is a high temperature slagging boiler
NO (3% 02, dry)
300
250 —
200 —
150 —
100 —
50 —
LEGEND
Unit # Description
1 Hennepln, 70 MW, T-flr»d
Unit C, 300-400 MW, T-Flred
Barrett, 185 MW, T-tlred
Unit A, 100-200 MW, Wall fired
Unit B, 100-200 MW, Opposed
Stoned Combustion
Gas mixing, flue gas
entrapment, and will
conditions become more
Important for BAHR < 180
kBtu/hr/112
Filled symbols represent Staged Combustion NOx Data
I I I I I I I I I I I I . I I I I , . I I I I T I | . I ,
0.0 0.5 1,0 1.5 2.0 2.5 3.0 3.5 4.0
BAHR (100000 * Btu/hr/ft2)
Figure 3-3. NOX versus burner area heat release rate (BAHR) correlation for coal
designed boilers firing 100 percent natural gas (Hura, 1994)
3-29
-------
with a high BAHR compared to Hennepin, the resulting NOX is much higher. However, these NOX
levels can be reduced with conventional combustion modifications often applied to gas-fired boilers.
These controls would include air staging by taking burners out of service or the addition of flue gas
recirculation. The latter is probably less desirable because of cost and because it has the greatest
likelihood of aggravating an expected increase in FEGT.
Table 3-9 lists experience reported for oil-designed boilers tested with 100 percent gas firing.
The only data available for this study is limited to the Brayton Point Unit 4. The result show a 31
percent reduction without FGR use and a 38 percent reduction with FGR. It is important to note
that the additional NOX reduction compared with 10 percent cofire and FGR is only
0.05 Ib/MMBtu, from 0.23 Ib/MMBtu (see Table 3-5) to 0.18 Ib/MMBtu, only about 20 percent
NOX reduction. Considering the potential cost differential between gas and oil, and the reduction
in boiler efficiency between 1.5 to 2 percent when operating on 100 percent gas, full conversion from
oil to gas firing may not be justified strictly from the point of view of NOX reduction.
From an operations point of view, the burning of 100 percent gas instead of coal or oil
brings about one inevitable impact: lower thermal efficiencies. Although some efficiency reduction
is likely with cofiring and reburning, the reduction in boiler efficiency is much more evident with
full conversion to gas. This reduction is principally the result of increased moisture content in the
flue gas, the inevitable effect of higher hydrogen content in the fuel. The ability to burn gas at
lower excess air levels will recover a fraction of this thermal efficiency loss. The reported data
shows that boiler efficiencies were reduced in a range from about 3 to 4.5 percentage points, using
the ASME heat loss method. Other considerations for gas conversions include (Harding, et al.,
1994):
• Boiler operating duty cycle
• Physical condition of the site
• Remaining economic life of unit
3-30
-------
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3-31
-------
Boilers that operate with variable load can benefit from gas conversions because of the operational
flexibility that gas provides especially at reduced loads. The physical condition of the plant and the
remaining economic life of the plant will play important roles in the economic justification for the
capital investment of converting the boiler to gas fuel and increased operating cost of gas burning.
3.1.4 Potential for Retrofit of Gas-based Controls
Gas is a clean fuel with wide operational flexibility, documented operational benefits, and
proven NOX reduction potential. Among the various applications of natural gas as a utility boiler
fuel, reburning remains the most efficient way of using gas for NOX reduction. With this technology,
the NOX reduction potential is the highest for a given percent of gas use. Cofire, conversion, and
seasonal gas use offer either lower NOX reduction potential or require much higher gas use.
Because of the fuel cost differential between gas and coal, the amount of gas needed to reduce NOX
from coal-fired boilers is one of the main utility concerns with the application of gas-based
technologies.
The realized retrofit potential of gas-based controls for utility boilers hinge on the following
utility concerns:
• Natural gas availability
• Access to gas supply
• Marginal NOX reduction beyond LNB
• Competitive gas pricing and availability of long-term contracts
• Reburning performance on large-scale coal boilers
• Combustion safety of gas injector designs
Before gas reaches the burner, adequate supplies are needed to ensure the long-term
availability of this fuel. Figure 3-4 illustrates the amount of gas needed for two hypothetical utility
boiler retrofit scenarios: reburn or cofire for all coal dry furnace PC-fired boilers with a maximum
of 20 percent heat input from gas, and full conversion of these units to 100 percent gas firing
capability. These estimates reflect the quantities of natural gas needed over and above what is
3-32
-------
NESCUAM-tangential MARAMA-tangential TOTAL
NESCAUM-wall MARAMA-wall
Dry furnace coal-fired capacity only. Reburn
at 20 percent of capacity; gas conversions at
100 percent gas capacity
Figure 3-4. Estimates of natural gas required for widespread reburn or
conversions of coal-fired boilers
currently used by the utilities if these controls were widespread. The more realistic scenario
indicates that approximately 0.5 TCP of gas will be needed for the reburn or cofire technologies for
all the coal dry furnace boilers in both NESCAUM and MARAMA. This total amount of natural
gas translates to approximately 1,400 MMcfd, considering year around operation with these controls.
A recent study on natural gas availability estimates that the gas capacity available for NOX control
purposes in the OTR in the year 1997 is 3,490 MMcfd for the period from April to October
following a cold winter (EEA Inc., 1994). This capacity would be reduced to 2,830 by the year
2,000. Therefore, this study would suggest that gas will be available to implement the reburning and
cofiring techniques, should these be considered by the utilities for their NOX reduction compliance
strategies. Although gas supplies are projected to be capable of satisfying even the full gas
conversion of all dry furnace PC-fired boilers, this scenario is very unlikely considering the economic
impact.
3-33
-------
The second consideration is one of gas access. A recent study sponsored by the Coalition
for Gas Based Environmental Solutions, Inc. revealed that only about 9 percent (14 out of 155
units) of the total coal-fired generating capacity in the OTR is currently equipped to burn any
amount of natural gas (EVA Inc., 1994). Most of these plants with dual-fuel firing capability only
have access to sufficient natural gas for ignition, warm up, and for flame stabilization which require
relatively small amounts of gas. Therefore, to adapt these units to either reburning or cofiring with
a maximum of 20 percent gas use, it would require installation of new pipelines and burner
equipment. The study went on to reveal that, although few power stations have any gas firing
capability, nearly half are located less than 5 miles from an existing natural gas pipeline. For oil-
fired utility boilers, 39 percent of the existing capacity has gas service, and 20 percent are fully dual
fuel boilers capable of supplying full capacity on either oil or gas. Many of the oil-fired boilers are
also located within 5 miles of a gas pipeline.
Because NOX reduction efficiencies may be marginal beyond the 50 to 60 percent obtained
by LNB + OFA, gas reburning may not be able to achieve deep NOX reductions as a retrofit option
on boilers already retrofit with LNB. In fact, test results summarized above, point to lower NOX
reduction efficiencies with lower primary zone NOX. For example, NOX reduction on uncontrolled
boilers have been reported as high as 72 percent on a short-term basis. When applied to LNB-
equipped boilers, the NOX reduction of gas reburning can fall as low as 30 percent for wall fired
units and percent for tangential-fired boilers. Utilities have also expressed little incentive for reburn
retrofit on older boilers when LNBs have nearly similar NOX reduction performance.
The EVA Inc. study also evaluated the price for natural gas to project the competitiveness
of gas against coal for base loaded utility boilers. The study revealed that the break even fuel
differential cost between gas and coal was at $1.65/MMBtu. Higher differential cost will not make
natural gas attractive as a utility boiler fuel in existing coal-based powerplants. Between increased
projected demand for gas and higher wellhead prices, increased fuel differential costs will make
3-34
-------
coal-based power generation technologies more attractive in the future limiting gas role in existing
powerplants, according to EVA Inc.
All the demonstrations of reburning to date have focused on smaller-scale utility boiler
furnaces. With the exception of the KP&L Lawrence Unit 5, the sizes of boilers retrofit with gas
reburn range between 33 and 185 MWe. Because of various technical issues centering on mixing
and residence time primarily, larger utility boiler demonstrations are needed to confirm that
performance is not hindered. Larger-scale demos are being sought to address commercialization
concerns and demonstration thus far limited to smaller units. Some utilities and boiler vendors have
also concerns with the safety of gas reburning. These concerns stem from some designs that use
wall injectors rather than burners with flame scanners and other safety controls. These concerns
do not seem to be borne by any negative experience with gas reburning, however. Finally, because
of reduced NOX reduction performance with lower loads, gas reburning is seen principally as a
technology best suited for base loaded units.
Many additional developments are underway aimed at improving on the gas reburning
process for utility applications. Among the newest research being sponsored by the Gas Research
Institute (GRI) are (Freedman, et al., 1994):
• Improved gas injection mechanisms to maximize the mixing and possibly reduce the
amount of gas required.
• Improved OFA port designs to achieve more complete and rapid burnout
• Advanced reburning techniques that combine conventional gas reburn with selective
noncatalytic reduction (SNCR)
• Integration of gas reburning into the operation of pulverized coal-fired burners for
enhanced NOX reduction.
Many of the recent demonstrations have utilized flue gas recirculation (FOR) to increase the
momentum of the gas entering the furnace and, thus improve the mixing with coal combustion
products leaving the main burner zone. The objective of improved gas injection ports is to eliminate
3-35
-------
the need for FGR, thus reducing cost and simplifying its operation. OFA ports are also being
optimized for improved burnout. The combination of reburning with SNCR has some intrinsic
advantages that enhance the performance of either control when used separately, thus achieving
high overall NOX emissions reductions. Advanced gas reburning technologies will be discussed in
Section 3.4.1. The potential for improved LNB operation with the addition of some natural gas into
the burner itself has initially been demonstrated by pilot-scale tests at the International Flame
Research Foundation (IFRF) (Freedman, et al., 1994).
Coal reburning is being actively investigated by boiler OEMs as a potential technology that
might be incorporated into future low-NOx burner systems for new boilers. However, because coal
contains its own fuel-bound nitrogen, its use as a reburning fuel may lead in additional NOX being
formed. Therefore, retrofit on LNB controlled boilers in NESCAUM and MARAMA is
questionable at this time because these units have managed already to reduce NOX in the primary
combustion zone and the addition of coal as a reburning fuel would likely be less effective that
natural gas.
3.2 COAL REBURNING
The only demonstration of coal reburning to date has taken place at the Nelson Dewey
Station of WP&L. The 110 MWe Unit 2 cyclone boiler was retrofit with coal reburning under a
DOE Clean Coal II Demonstration program. For safety, the B&W retrofit uses coal burners with
their own primary and secondary air. Two coals were tested during this demonstration: a medium
sulfur Illinois Basin (Lamar) bituminous coal and a low sulfur western Power River Basin (PRB)
subbituminous coal. Table 3-10 lists the NOX reduction results obtained, and Table 3-8 lists the
measured impacts.
The short-term tests showed that NOX reductions ranged from 36 to 52 percent over the
load range for the bituminous coal to NOX levels between 0.39 to 0.44 Ib/MMBtu. Using more
volatile western coal, the NOX reductions were maximized to a range between 53 and 62 percent,
corresponding to controlled NOX levels of 0.28 to 0.30 Ib/MMBtu. The NOX reduction performance
3-36
-------
Table 3-10. Reburn NOX emissions as a percent reduction from baseline versus load
(Coal Reburning at Nelson Dewey Station)
Load
(MWc)
110
82
60
Percent Reduction and
Controlled Level with Lamar
Coal as Reburning Fuel
52 Percent (039 Ib/MMBtu)
47 Percent (039 Ib/MMBtu)
36 Percent (0.44 Ib/MMBtu)
Percent Reduction and
Controlled Level
with Reburn PRB Coal*
58 percent (032 Ib/MMBtu)
51 Percent (032 Ib/MMBtu)
50 Percent (0332 Ib/MMBtu)
Percent Reduction and
Controlled Level with
Optimized Reburn PRB Coal
62 percent (0.28 Ib/MMBtu)
55 Percent (0.29 Ib/MMBtu)
53 Percent (030 Ib/MMBtu)
•PRB = Power River Basin.
Source: Farzan, et al., 1993.
decreases with load because more burner air is introduced at the reburner zone to maintain flame
stability. This addition air increases reburner stoichiometry, increasing NOX. As indicated in
Table 3-11, coal reburning generally caused only minor changes in boiler performance. In general,
the use of more reactive western coal has the least effect on unburned carbon in the flyash, FEGT,
and steam temperatures. Also, the Nelson Dewey boiler did not suffer any derate as a result of
switching to the PRB coal. This is because B&W was able to increase coal feedrate to 30 percent
above normal to compensate for the lower heating value of the western coal. Therefore, for boilers
required to switch to a lower sulfur western coal switching to meet SO2 emission levels under
Title IV, coal reburning may be an attractive option provided the boiler furnace is large enough to
accommodate reburn (Farzan, et al., 1993).
The selection of the coal type for reburning is very important to its performance and retrofit
feasibility. Ideally, the reburning coal should be most reactive, meaning that it must contain high
percent of volatile matter. Reactive coals will burn faster and hotter thus minimizing the
requirements for large burnout zone and potential increase in unburned carbon in the flyash. Also,
reactive coals will release more of the fuel nitrogen with the volatile matter reducing the potential
for high NOX generation in the burnout zone from oxidation of char nitrogen. For this reason,
western subbituminous coals are most likely candidates as reburning coals. Eastern utility plants
that currently burn bituminous coals would have to maintain separate western coal inventories for
3-37
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Table 3-11. Coal returning effects on general boiler operation (Nelson Dewey)
Parameter
Slagging/fouling
Header/tube temperature
SSH and RH spray Hows
Opacity
Furnace corrosion
UBCL (full to low load)
FEGT at full load
Anticipated Results
No change
25 to 50 °F higher
30 percent higher
5 to 10 percent higher
No change
Would increase
Would increase
Actual results with
Lamar Coal
No change
No increase from base
75 percent lower
No increase from base
No change
0.1 to 1.5 percent
Decrease 100 to 150eF
Actual Results with
PRB Coal'
No change
No increase from base
25 percent lower
No increase from base
No change
0 to 03 percent
Decrease 25 to 50°F
•PRB = Power River Basin.
Source: Farzan, et al, 1993.
their reburning fuels. Use of less reactive bituminous coal for reburning will likely require that it
be finely ground, as in micronized coal, to minimize increases in unburned carbon or lower NOX
reduction efficiencies.
A demonstration of coal reburning using micronized coal is planned at the Tennessee Valley
Authority's (TVA) Shawnee Station 175 MWe Unit 6 (Bradshaw, et al., 1991). This project is being
sponsored under DOE's Clean Coal Technology IV. Micronized coal characteristics and benefits
are summarized in Figure 3-5. Under this project, up to 30 percent of the coal will be micronized
(80 percent less than 325 mesh, corresponding to approximately 43 micron or smaller). Today, most
coals are pulverized only to about 80 percent through 200 mesh. The micronized coal will be
injected into the upper furnace, above the four levels of existing circular burners, to create a reburn
zone with 0.80 to 0.90 percent stoichiometry. High velocity overfire air will be injected to bring the
overall stoichiometry bach to about 1.15 prior to the gases exiting the furnace. The NOX reduction
goal for the demonstration is set at 50 to 60 percent from uncontrolled levels. The retrofit of this
technology, although theoretically applicable to most existing pulverized coal-fired boilers and
cyclones, will require the installation of a MicroMill System and burners. Feasibility and benefits
3-38
-------
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3-39
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of this technology must be weighed when the demonstration results are made available at the
completion of the project.
3.3 NONCATALYTIC FLUE GAS TREATMENT CONTROLS
Selective noncatalytic reduction (SNCR) is a process that uses ammonia-based reagents to
selectively reduce NOX to nitrogen and water without the presence of a catalyst. The principal
attractive feature of this technology is that it does not rely on any catalyst surface and, therefore,
can be implemented at much lower costs compared to catalyst based technologies. The ability to
do away with the need for a catalyst, however, requires that the reagent be injected where the flue
gas temperature is optimal to promote the reaction with the minimal amount of unreacted
ammonia. This optimum temperature window is in the range of 870° to 1,150°C (1,600° to
2,100°F). Higher injection temperatures are possible by proper design and operational settings of
SNCR systems. Selected vendors of SNCR-based technologies offer proprietary additives aimed
at broadening this temperature window and, thus making the efficiency of the process and ammonia
slip requirements somewhat less sensitive to flue gas temperature swings (Rini, et al., 1993 and Lin,
et al., 1994).
In a utility boiler operating at full steam load, this temperature window occurs in a zone
starting approximately at the furnace exit plane and extending just passed the first convective
superheater and reheater tube banks. Figure 3-6 illustrates the approximate temperature profile
in the upper furnace of a typical pulverized coal-fired boiler. The SNCR temperature window shifts
toward the burner zone when boiler load is reduced. The inserted table illustrates how the average
flue gas temperature at each plane varies with load. Equally important to the process, is the fact
that the flue gas temperature across the furnace plane in this location is also not uniform and
subject to rapid cooling as heat continues to be absorbed. Furthermore, gas velocities and NOX
concentrations are also not uniform. This nonuniformity of temperature, velocity, and NOX
concentration coupled with relatively short residence times are major challenges for this technology
3-40
-------
NOT TO SCALE
Load, % MCR
Net heat input, 106 Btu/hr
Gas weight, 103 Ib/hr
Air preheat, °F (secondary)
Flue gas temperature °F (average)
Plane A
Plane B
Plane C
Plane D
Plane E
Plane F
Plane G
Plane H
Plane I
Plane J
Plane K
Plane L
Plane M
NOX - lb/N02/MMBtu
Oxygen content, % by dry Vol.
100
3,405
3,213,000
550
2,400
1,910
1,900
1,720
1,700
1,465
1,440
1,340
1,310
1,195
1,180
935
640
0.60
3.5
75
2,550
2,425,000
510
2,400
1,810
1,800
1,610
1,590
1,365
1,340
1,250
1,230
1,115
1,100
885
580
0.50
3.5
60
2,035
2,088,000
480
2,285
1,710
1,700
1,520
1,500
1,295
1,260
1,190
1,170
1,075
1,055
855
550
0.45
4.9
Figure 3-6. Flue gas convective path and temperature profile — 350 MWe bituminous coal-fired
(Source: ABB-CE)
3-41
-------
and often limit the NOX reduction performance of SNCR to maintain ammonia slip below
acceptable levels.
Ammonia slip is caused by excessive use of reagent, insufficient mixing of reagent with flue
gas, and low flue gas temperatures. When using ammonia-based reagents in a boiler burning sulfur
bearing fuels, such as coal or residual oil, the amount of ammonia slip must be particularly
controlled to minimize plugging of air heater and cold end corrosion caused by ammonia sulfates
and bisulfates compounds formed by the reaction between NH3 and SO2/SO3 in the flue gas.
Furthermore, excessive ammonia is also trapped in the flyash often precluding the continued sale
of this commodity for cement manufacturing. At least one vendor, however, offers additives to an
aqueous urea reagent mix that has proven to minimize NH3 slip under well controlled and
supervised SNCR operation (Shore, et al., 1993).
The two principal reagents used in the SNCR process are aqueous ammonia (NH4OH) and
urea (NH2CONH2). Anhydrous ammonia can also be used but it is generally not considered for
SNCR applications because of safety and better process operation with aqueous reagents. Urea is
procured and delivered to the plant in a water solution containing appropriate grade urea with or
without proprietary additives, depending on the vendor of the SNCR process. These additives are
used as corrosion inhibitors to facilitate onsite storage, transport, and injection in the furnace, and
for performance enhancement. Large onsite storage tanks with recirculation capability, and heating
if necessary, are needed to maintain a supply of reagent usually containing 30 to 50 percent water.
Additional water is then mixed prior to injection into the furnace from wall injectors. Because flue
gas temperatures are not uniform and because SNCR must often perform over some boiler load
range, several injection locations are necessary, each capable of distributing the reagent-containing
droplets over the effective area to ensure maximum reagent utilization. Controls to monitor and
change the amount of reagent injected, the droplet size, and the velocity of injection are also part
of the SNCR process needed to maximize its performance.
3-42
-------
A permanent SNCR installation will require several process modules. The following is a list
of these process modules prepared for the 321 MWe coal/gas-fired Mercer Unit 2 with four level
of reagent wall injectors, as defined by Nalco Fuel Tech (Gibbons, et al., 1994):
A. One storage tank of 250,000 gallon capacity and stainless steel construction with heat
tracing, insulation, level transmitter and accessories.
B. One Circulation Module for the continuous circulation and heating of the NOXOUT*
reagent. This module is equipped with redundant pumps, strainer, electrical heater,
flow sensor, and a local control panel
C. One Transfer Module for boosting reagent and water pressures to 150 PSI. This
module includes redundant pumps, flow meters, pressure control valves, and a local
control panel
D. The Metering Modules, one for each furnace (dual-furnace boilers) and one common
spare. These modules provide flow and pressure control for both the NOXOUT reagent
and dilution water. These modules also distribute water chemical mixture selectively
to all levels of injectors. Each module is equipped with flow meters, flow control valves,
pressure controls, static mixers, and a local control panel.
E. Eight Distribution Modules for control of flow of water/chemical mixture and atomizing
air for each level of injectors at each furnace. Each free-standing four-circuit (for four
levels of injectors) module includes flow and pressure indication, valves and manifolding
F. 32 Injector assemblies with cooling shield, tip, and flex hoses with disconnects.
G. 32 Injector Retract Mechanisms for the proper positioning of the injector into the
furnace during operation and retraction into the cooler zone when not in operation.
H. Two Injector Retract Control Panels for local or automatic operation/selection of
Injectors, with indication
I. One Master Control Module for complete automation control of the NOXOUT system
modules and collection of operating data. This module includes a PLC system, PC,
color monitor, printer, cabinetry, input terminal for plant operating signals, and
software.
The amount of urea or ammonia injected in the furnace varies with the NOX reduction target. As
a minimum, the full conversion of NOX to nitrogen and water will require a stoichiometric amount
of NH2. For ammonia, it is one mole of ammonia for each mole of NO. For urea, it is 0.5 moles
of urea for each mole of NO because of the two nitrogens in one mole of urea. However, all full-
scale test have shown that more than the stoichiometric quantity is often needed to maximize the
performance of the process. This is because of the mass transport limitations imposed by imperfect
3-43
-------
mixing of reagent with flue gas at optimum reaction temperature. Therefore, most of the excess
reagent either reacts to form NO or degrades to nitrogen and carbon dioxide. The quantity of
reagent used in the SNCR process is often reported using the Normalized Stoichiometric Ratio
(NSR), defined as:
Actual Moles of Reagent
NSR __ . _ (3.3)
Stoichiometric Molar Ratio of Reagent
Moles of Inlet NOX
where the denominator is 1.0 for ammonia and 2.0 for urea reagents. The amount of reagent
utilized is given by the ratio of measured NOX reduction (in percent) and the calculated NSR.
Table 3-12 lists the NOX reduction performance data reported on seven permanent and
demonstration coal-fired utility boiler SNCR installations. The list include nearly 1,000 MWe of
demonstration and commercial SNCR capacity with a range in NOX emission rate before reagent
injection between 0.90 to 1.54 Ib/MMBtu at full load. The boiler types include cyclones and wet-
bottom wall-fired units as well as one roof-fired boiler. All these boilers were retrofit with the
NOXOUT Process commercially available from Nalco Fuel Tech of Naperville, IL. In addition to
these units, other NOXOUT SNCR installations are planned and they include the 150 MWe Milliken
Unit 2 of New York State Electric and Gas Company and one of the two cyclones at Merrimack
Station of Public Service of New Hampshire. The SNCR demonstration at the Mercer Station was
recently converted to a commercial installation servicing the entire generating capacity of the plant.
The average NOX reduction for these facilities ranges between 30 and 66 percent at full load
with 75 percent NOX reduction peaks measured on a short-term basis. For any one boiler and
injection configuration, the NOX reduction efficiency of SNCR is linked principally to the level of
NH3 slip that can be tolerated. For example, NOX reductions at the Mercer Station were limited
to a range of 32 to 38 percent over the load range when the NH3 slip was maintained below 5 ppm.
When the NH3 slip limits were relaxed to 15 ppm, the NOX reduction efficiency was slightly
3-44
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increased to a range of 32 to 46 percent over the load range. Similar results showing the
dependence of NOX reduction performance on NH3 slip are apparent in many parametric
demonstration tests on full scale boilers (Cunningham, 1994; Himes, 1995; Staubt, 1995). Figure 3-7
illustrates other test results showing the increase in NH3 slip beyond 10 ppm for NOX reduction in
excess of 45 percent. Excessive NH3 slip is particularly a concern when burning high sulfur fuels
because of sulfate deposits that cause corrosion and plugging of air heaters. Typically, NH3 levels
are maintained below 10 ppm for all flue gas treatment technologies that use ammonia-based
reagents.
Although the retrofits of SNCR on coal units to date have included furnaces with maximum
generating capacity of 160 MWe (Mercer Unit 2 is a twin furnace 321 MWe boiler), the technology
is considered equally applicable to larger furnaces. For larger furnaces, however, it may be
NOx
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Figure 3-7. NOX removal versus residual NH3: SNCR on coal (Reference UARG, 1995)
3-47
-------
necessary to add more injectors to maintain NOX reduction performance and minimize NH3 slip.
These considerations could result in higher cost and increased operational complexity. In general,
experience with retrofit on larger furnaces is necessary to document hardware requirements and
performance.
It is also important to keep in mind that all these tests were performed on generally
uncontrolled coal-fired boilers with relatively high NOX levels. Application of SNCR on combustion
controlled units with lower initial NOX levels could result in somewhat lower average NOX
reductions efficiencies than those reported here. The dependence of SNCR performance on
changes in initial NOX levels is perhaps best illustrated by comparing these coal-fired results with
results obtained with gas fired boilers.
Table 3-13 lists SNCR performance results obtained on demonstration and commercial
oil/gas-fired utility boilers. Average NOX reduction performance of this technology ranges between
7 to 50 percent reduction, lower than coal-fired results. The lowest NOX reduction efficiencies are
reported for gas-fired combustion controlled boilers in Southern California with an initial baseline
level of 0.05 to 0.10 Ib/MMBtu. One of the gas-fired installations is the hybrid SNCR+SCR
demonstration at the Encina Station in California. The NOX reduction efficiencies attributed to
SNCR alone cannot be interpreted to be performance levels if SNCR were the only control in place.
This is because the NSRs used with hybrid control are much higher than 1.0 and are only possible
when SCR reactors are in place to further react the excess NH3. However, the results at Encina
show that with higher baseline levels of 0.19 Ib/MMBtu, the SNCR NOX reduction performance was
approximately 60 percent. When burners out of service (BOOS), biased firing, and FGR
combustion controls were in operation, the performance of the SNCR diminished to a range of 20
to 40 percent depending on load. Although temperature profiles are affected with implementation
of combustion controls, these results tend to support the conclusion that lower NOX reduction
efficiencies are likely with lower initial NOX levels.
3-48
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In general, SNCR is a low-cost gas treatment option for post-RACT NOX reduction. The
retrofit experience gathered to date on utility boilers would indicate that NOX reduction levels are
limited to a range of 25 to 65 percent for coal-fired boilers and from less than 10 to 50 percent for
oil/gas-fired boilers, depending on boiler load and NOX level. Uncertainties with SNCR
performance on larger size boilers, excessive NH3 slip, load following capability, and potential for
reduced NOX reduction performance when SNCR is implemented on combustion-controlled boilers
may limit the attractiveness of SNCR only controls for post-RACT compliance. Lower performance
levels of SNCR might be further aggravated when the controls are applied to large gas-fired utility
boilers with variable dispatch loads. Because of the strong dependence on gas temperature and
mixing, it is likely that optimum NOX reduction performance for SNCR will come from retrofit on
smaller, base loaded, coal-fired utility boilers with high inlet NOX levels. Currently these candidate
boilers include wet bottom and cyclone units and several lower capacity dry bottom units.
Reported operational impacts have been minimum for the most part. This is due principally
to the ability of most installations to maintain NH3 slip at low levels, between < 5 to 20 ppm in most
cases. Although many of these tests were performed on a short-term basis, long-term operational
impacts have also been minimal. Ammonia slip levels below 5 ppm would likely have little effect
on the salability of the flyash or air heater pluggage and cold-end corrosion. Long-term tests are
planned at some facilities to explore these issues (Cunningham, et al, 1994). Other byproducts of
the SNCR reaction, especially with urea-based reagents, are N2O and CO emissions. N2O is a
greenhouse gas not currently regulated. Typically ^O emissions are a function of the reaction
temperature and tend to range between 10 to 15 percent of the total NOX reduced (Hofmann, et
al., 1993). Because of the quantities of water injected into the furnace to provide adequate
dispersion of the reagent, a decline in boiler efficiency of 0.5 to 1 percent has been reported
(Gibbons, et al., 1994).
3-52
-------
3.4 CATALYTIC FLUE GAS TREATMENT CONTROLS
Interest in SCR for NOX reductions on a variety of combustion sources has grown
substantially in recent years. The technology has been commercially available on gas turbines,
industrial boilers, reciprocating engines, process heaters, and utility boilers in the U.S. and abroad
for several years. Because it can reach NOX reductions in excess of 90 percent, in some cases, the
SCR technology is often seen as the ultimate solution is reducing NOX in combustion sources. Little
or no additional NOX reduction seems warranted once SCR is in place. In light of recent
commercial installations in the United States, the applicability of SCR to gas, oil and coal-fired
boilers is all about certain.
SCR installations on utility boilers are many, principally in Germany and Japan as illustrated
in Table 3-14. This recent inventory, prepared by the Institute of Clean Air Companies, puts the
total SCR installations on overseas utility coal-fired boilers at 213 for a total of 56 GW. Many of
these installations are retrofits and have been in place since early to mid-1980s. Of the total
capacity, a minimum of 36 GW is coal-fired capacity (Baldwin, 1991). Considering all combustion
equipment categories, SCR is installed on about 200 combustion processes in this country and 500
Table 3-14. Overseas SCR installations on coal-fired powerplants (ICAC, 1994)
Country
Germany
Japan
Italy
Austria
Netherlands
Sweden
Finland
Total
Number
137
40
29
3
3
2
1
213
Retrofits
127
29
19
2
1
2
1
181
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10
11
10
1
—
—
—
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(GW)
30
12
12
0.9
0.13
0.08
0.56
56
Percent NOX
Reduction
70 to 90
25 to 90
80
80
80
84
70
25 to 90
3-53
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abroad (ICAC, 1994). In the U.S., SCR is installed on 12 gas-fired utility boilers in California
ranging in size from 230 to 750 MWe with nearly as many units planned for retrofit, and also
operating or planned on a combined 1,390-MWe utility coal-fired boilers in New Jersey, Florida,
and New Hampshire. Recent NOX reduction rules for utility power plants promulgated in Southern
California are being met with SCR retrofits. The SCR installation capacity, in place and planned,
on utility boilers in the U.S. now totals about 5,000 MWe with approximately 2,400 MWe more
scheduled to be in place in the next few years. The successful application of SCR control systems
on utility boilers in Southern California was possible because of design improvements that utilize
smaller catalyst volumes while retaining high NOX reduction performance.
The SCR process is based on the selective reduction of NOX by NH3 over a catalyst at a
temperature in the range of approximately 260° to 480°C (500° to 900°F). Contrary to the SNCR
process, both NO and NO2, the two principal forms of NOX from powerplants, are both reduced.
In the SNCR process only NO is affected. Also, N2O is not a byproduct of the SCR reaction,
whereas N2O can be as much as 25 percent of the NO reduced in the SNCR process. The overall
SCR reactions that occur in the flue gas of utility boilers are (Bosh and Janssen, 1987):
4M/3 + 4NO + O2 - 4N2 = 6H2O (3-4)
= 6N02 -» 7N2 + 12H20 (3-5)
Ammonia is injected in either in its anhydrous form or in an aqueous solution. The amount of NH3
injected is nearly the stoichiometric amount required, or 17 pounds of ammonia for each 46 pounds
of NOX as NO2. The optimum reaction temperature is based on the catalyst formulation. Many
of the formulation use vanadium pentoxide (V2O5) supported on titanium dioxide (TiO2) with an
operating temperature window of 300° to 400 °C (570° to 750 °F). Zeolites and other rare earth
materials are also effective catalysts, but their operating temperatures tend to be higher making
them more suitable for applications on cogeneration or simple cycle gas-turbine plants. Catalysts
and substrates are shaped in either parallel or honeycomb modules that are stacked together into
3-54
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a reactor that must then be placed in the appropriate location where gas temperature matches the
catalyst peak performance temperature. In a utility boiler, this temperature normally corresponds
to the inlet air heater when the boiler is at or near full load. At lower boiler loads, the temperature
at the air heater inlet drops sufficiently that some amount of economizer bypass may be required
to maintain the catalyst at the optimum temperature. This bypass inflicts a thermal efficiency loss
that is attributed to the operation of the SCR process.
Besides temperature, other factors that affect the performance of SCR catalysts are
(Rosenberg and Oxley, 1993):
• SO2 content of the flue gas
• Flyash content in the flue gas
• Molar feed ratio of NH3 to NO
• Catalyst space velocity
• NH3 distribution
• Trace metals in the flyash
Application of SCR in high sulfur and dust flue gas represents a particular challenge for SCR
catalysts. This is because the catalysts performance can: (1) deteriorate from the erosion effect of
the flyash, especially when gas velocities are high; (2) become plugged or fouled because of sticky
deposits; (3) become poisoned from certain trace metals and alkaline components in the flyash such
as arsenic, CaO, and MgO; and (4) cause oxidation of SO2 to SO3 that can result in higher flue gas
dew point with potential for cold end corrosion due to ammonium sulfate deposits. If neglected,
these conditions can reduce the catalyst life, and make the SCR very expensive to operate. By
considering the effects of sulfur content and dust loading on catalyst performance in the design of
each unit, system and catalyst suppliers have been able to install SCR on numerous boilers here and
abroad.
The space velocity is the volumetric flow rate of the flue gas under standard conditions
divided by the volume of the catalyst, in units of 1/hr. The smaller the space velocity, the larger
3-55
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is the catalyst volume. Large catalyst volumes offer greater NOX reduction capability and lower
emissions of unreacted NH3. With some catalyst formulations, SO2 oxidation increases with larger
catalyst volumes (lower space velocities). To put this term into perspective, a space velocity of 100
to 220 1/hr would mean an SCR catalyst the size of the boiler furnace. Fortunately, catalyst
volumes are on the order of 2,400 to 4,000 1/hr (about 20 times smaller than a boiler furnace) for
high performance SCR units on coal-fired powerplants. However, reactor housing the catalyst in
full-scale SCR systems can be as much as 5 times larger that the catalyst it contains to permit
maintenance, sootblowing, and gas flow control. The catalyst space velocities for some of the
in-duct SCR applications in Southern California gas-fired utility boilers are on the order of 33,000
1/hr.
The volume of the catalyst at the Merrimack Unit 2 will initially consist of two layers of
catalyst module for a total space velocity estimated at about 7,500 1/hr for 65 percent NOX
reduction. Anticipated deterioration of the catalyst performance over the first 5 years of operation
and planned increase in NOX removal efficiency of the system from 65 to 91 percent will require
two additional layers of catalyst bringing the final space velocity to about 3,750 1/hr (700 m3 of
catalyst), similar to catalyst space velocities used on the new coal plant in New Jersey (Philbrick,
1995).
As in the case of SNCR, the injection of NH3 must also be accomplished with the outmost
mixing efficiency with the flue gas. This requires the careful mapping of the flue gas velocities, NOX
distribution and temperatures at the plane of NH3 injection. Also, the mixing requires the
installation of an injection grid that takes into consideration the results of the flue gas mapping.
The optimization of the injection and mixing is particularly important when the volume of the
catalyst is minimized to permit retrofit in existing ducting and air preheater baskets. Often, flow
straighteners must be installed in the inlet flue gas to maximize the uniformity of the gas flow across
the catalyst inlet plane. Economizer bypass provisions are also necessary in the retrofit to ensure
that SCR inlet temperatures are maintained with decreasing boiler loads.
3-56
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Improvements in process design and catalyst formulations have alleviated many of the
potential problems discussed above. For example, downflow reactors with plate and honeycomb
catalysts and dummy catalyst layers acting as flow straighteners and operating at the higher end of
the temperature window are often used in coal-fired boilers to combat the effects of high dust
loadings. Catalyst formulations more resistant to SO2 to SO3 conversions have been developed for
applications in flue gas with high SO2 loadings. Concerns regarding sulfur limits with SCR have
diminished somewhat as new and planned SCR installation in the U.S. and Europe have guaranteed
NOX reduction performance with sulfur level as high as 2.5 percent (Philbrick, 1995). With high
sulfur levels and NOX reduction performance (large catalyst volumes), NH3 slip must be maintained
to a minimum. Flow straighteners with accurate NH3 distribution are used to minimize NH3 slip
and maximize performance. Many of these retrofit considerations and improvements have
important effects on the feasibility of retrofit, performance, operational impact, and cost. This
dependence is illustrated in Table 3-15.
For the most part, installations already in place in the U.S. are relatively new and experience
is limited. However, many of the initial reports indicate that SCR installations are operating
satisfactorily and meeting or exceeding performance guarantees. Because catalyst cost can be a
large fraction of the total operating cost, one especially important guarantee is the life (performance
period) of the catalyst material. Over time, the catalyst activation will decrease due to erosion,
blinding, or poisoning of the catalytic surface. Along with this deactivation, SO2 to SO3 conversion
can increase and lead to corrosion problems in load cycling plants. Long-term pilot tests at TVA
Shawnee Station with coal firing and Niagara Mohawk Oswego Station with oil firing conclude that
deposition of flyash and fuel oil additives (MgO) can result in significant deactivation and pluggage
of the catalyst. For the hot-side, high-dust SCR test at Shawnee, activity loss was the result of
masking of the catalyst surface by sulfate flyash and not by arsenic deposition. Catalyst activity loss
ranged from 25 to 50 percent, depending on catalyst formulation, after 8,000 of operation
(Mechtenberg, 1995).
3-57
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Table 3-15. Major design factors affecting costs
Design Factors
Capital Cost Considerations
Operating Costs
Considerations
Fuel Type
(Flue gas composition: fly
ash, SO2 content)
Initial NOX Concentration
Environmental Performance
(NOX removal/residual
NH3) control
Catalyst Management
Strategy
• Catalyst volume, geometry,
pitch, orientation
• Reactor volume
• Catalyst composition
• Reactor design (conventional
vs. in-duct)
• Cleaning provisions
• Catalyst replacement
• Ammonia consumption
• Catalyst volume
• Reactor volume
• Catalyst volume
• Reactor volume
• Catalyst volume
• Initial catalyst inventory
• Catalyst replacement
• Ammonia consumption
• Catalyst replacement
• Ammonia consumption
• Catalyst replacement
• Ammonia consumption
• Catalyst replacement
Source: Chicanowicz, E., et al., 1993.
Once performance cannot be maintained it becomes imperative to add or replace several
catalyst modules to retain performance and minimize the potential for NH3 breakthrough. Recent
reports have shown that catalyst life has exceeded vendor guarantees. SCR systems are operating
without catalyst additions or replacements for 4 to 5 years for coal applications and more than
10 years for gas applications (ICAC, 1994). Utility SCR experience in the United States although
limited, is represented well by experience in Japan and Germany when catalyst for coal-fired boilers
can be expected to operate without addition or replacement for over 4 years.
The SCR catalyst can be installed in various configurations. The most popular arrangements
are the following:
• Air preheater catalysts
• In-duct catalysts
3-58
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• Combination of air preheater and in-duct catalysts used in tandem
• Full-scale reactor catalysts
In coal fired applications, full-scale SCR reactors have been most common. The following
subsections highlight the performance results of these types of SCR configurations at specific sites.
Tables 3-16 and 3-17 list the available data on the performance of these SCR utility boiler
installations.
3.4.1 In-duct SCR Systems
Figure 3-8 illustrates the in-duct arrangement of SCR catalyst modules retrofitted on
Southern California Edison's Alamitos 5 and 6 480 MWe utility boilers firing natural gas. The
approach is to squeeze as much catalyst as possible within the existing duct space between the
economizer and the air heater without having to move any of this equipment. The amount of
catalyst is limited, however, not only by access but also by excessive pressure drop. Because the
volume of catalyst is small compared to full reactor systems, the resulting space velocities have are
as high as about 33,000 1/hr. Nonetheless, in-duct SCR retrofits on gas-fired Southern California
utility boilers are recording NOX reduction efficiencies as high as 93 percent from combustion-
controlled NOX levels. Other installations in Southern California have required moving of the air
heater to permit the installation of the catalyst volume necessary for the target NOX reduction
levels. For example, the two largest SCR retrofits in the country on the Ormond Beach 750 MWe
each Units 1 and 2, required some equipment rearrangement for the installation of the "in-duct"
catalyst. Porous plates were also necessary to "straighten" the gas flow. Detailed cold flow modeling
of the flow was used to optimize the installation and maintain the total pressure drop within the
design point. The target NOX levels with these SCR systems in place are 0.10 Ib/MW-hr for gas-
firing at all loads and 0.33 Ib/MW-hr for oil-firing at all load, corresponding to about 0.01 and 0.03
Ib/MMBtu respectively (Johnson, 1993). New Source Review (NSR) permits issued with installation
of SCR in Southern California often limit NH3 slip to 10 ppm or less to mitigate potential health
hazards. The installation of this amount of catalyst requires detailed engineering evaluations and,
3-59
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3-60
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3-61
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3-62
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FLUE GAS
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INJECTION
GRID
RUE CAS
TO
AIR
PREHEXTER
Figure 3-8. In-duct SCR system — SCE Alamitos Power Station Unit 6
as mentioned above, straightening of the flue gas flow to maintain gas velocity uniformity across the
catalyst inlet plane.
3.4.2 AH-SCR Systems
The air heater SCR technology was first introduced by Rothemuhle and Siemens of
Germany. Rothemuhle is an international manufacturer of regenerative air heaters for powerplants.
Siemens is a major European supplier of catalysts for NOX reductions from all major combustion
sources. The retrofit of this technology will require replacing the existing enamel-coated air heater
elements of a rotating Ljungstrom air heater with catalyst-coated ones on the hot end of the
3-63
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rotating elements and installations of NH3 injection and control system. The applications of air
heater SCR catalyst also result in low pressure drop that translate in fan power savings. Because
the air heater is at the ideal temperature for NOX reduction, the doubling of this device as an SCR
reactor in addition to its heat transfer duties, provides an opportunity for SCR-type NOX reductions
without major modifications to the existing ductwork. Additionally, AH-SCR acts as scrubber for
NH3 slip with hybrid systems, such as the one demonstrated at PSE&G Mercer station. The added
benefit of an NH3 scrubber downstream of an SNCR or in-duct SCR provides greater operational
flexibility and enhanced NOX performance. Traditionally, the technology has been developed
primarily for difficult retrofit cases where installation of a full-scale SCR catalytic reactor is made
difficult by poor access or insufficient space.
In Europe, AH-SCR has been installed on two 200 MWe pulverized coal-fired plants in the
Netherlands with reported NOX reductions in the range of 30 to 50 percent and less than 5 ppm
ammonia slip (Takeshita, 1994). In the U.S., catalyst air heater (CAT-AH) technology is distributed
by ABB Air Preheater, Inc. (API). Because of its limitations on NOX reduction performance and
NH3 slip when used alone, this technology is perhaps best applied in tandem with in-duct catalyst
SCR and SNCR hybrids with overall NOX reduction performance equalling that of a full-scale SCR
reactor applications of this technology are now under evaluation at the Mercer Power Station.
The first utility boiler retrofit evaluation of this technology in the U.S was performed at the
Mandalay Generating Station's 215 MWe Unit 2 (Reese, 1993). This demonstration showed a NOX
reduction capability of 50 to 64 percent from BOOS-controlled emission levels of 0.18 Ib/MMBtu.
Also, it was observed that the NOX reduction performance of this technology increases with lower
inlet emission levels, making it particularly useful for application on combustion controlled boilers.
A study performed by Pacific Gas and Electric (PG&E) Company of San Francisco on the
feasibility of CAT-AH for oil- and gas-fired boilers in their system concluded that a maximum 40
percent NOX reduction was possible with this technology (Holliday, et al., 1993). The level of NOX
reduction, although not sufficient to attain the most stringent NOX control regulations, would
3-64
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nevertheless decrease the requirements for an integrated NOX control system capable of achieving
up to 90 percent NOX reduction levels. The feasibility of retrofit and long-term performance of this
technology on oil- and coal-fired boilers remains to be demonstrated. In particular, the ability of
the catalyst material to withstand thermal cycling along with plugging and masking in high dust and
sulfur environments needs to be evaluated.
3.43 Full-Scale SCR Systems
For utility boilers burning sulfur and ash bearing fuels such as residual oil and coal, SCR
installation almost exclusively requires full-scale SCR reactors containing layers of catalyst.
Figure 3-9 illustrates the three possible arrangements to place an SCR reactor within the existing
BOILER
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Figure 3-9. Possible SCR arrangements (Rao, et al., 1994)
3-65
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equipment layout of a steam generator. The most popular arrangement, both in the U.S. and
abroad, is the hot side, high dust setup where the reactor is placed ahead of the air heater and cold-
side ESP. Although the SCR catalyst is exposed to the full dust loading leaving the boiler, this
arrangement often represents the most economical operation, provided that the catalyst can survive
in the high dust environment for sufficient time before requiring replacement. The other hot-side
arrangement requires the installation of a hot-ESP which is not popular in U.S. powerplants.
Therefore, this arrangement would require replacing the current ESP in addition to making room
for the SCR reactor.
These full-scale reactors are generally arranged for downward flow to minimize ash
deposition and they are sufficiently large to reduce flue gas velocities as low as 20 ft/sec to
minimize erosion from ash and to provide sufficient space to add active catalyst layers. Figure 3-10
illustrates a typical SCR reactor for a coal-fired installation. The space velocities of these reactors
are as low as 2,500 1/hr with as much as 10 times the catalyst volume found in some in-duct SCR
applications. The overall pressure drop is on the order of 3 to 4 inches of water, often higher than
the in-duct SCR and CAT-AH systems used in gas-fired applications. The catalyst modules are
arranged in a minimum of three layers with occasionally a layer of dummy catalyst to take the brunt
of the erosion from moving flyash. Additional space is also engineered in the reactor to add a fresh
new layer of catalyst when the NOX removal efficiency decreases below required levels and/or
ammonia slip exceeds design values. Eventually, all the layers of catalyst must be replaced to
compensate for the aging effect.
Obviously, the retrofit of a full-scale SCR reactor into an existing powerplant will require
much more equipment modifications than some of the in-duct systems so successfully retrofitted on
gas-fired boilers in California. The catalyst volume of one of these full-scale systems can be as large
as I/10th the size of the boiler furnace and the reactor required to house it can require a volume
much larger than the active catalyst. Inevitably, significant engineering must be done to evaluate
not only the rearrangement of existing equipment but also to calculate the necessary upgrades in
3-66
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3-67
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fan power and air heater washing to compensate for greater pressure drop and possible increased
plugging rates of the air heater. As is the case with SNCR and all other SCR arrangements, the
level of NH3 slip is of considerable importance from an operational point of view, if not from an
environmental one. However, the level of NH3 slip is often lower with full-scale SCR systems
because of larger catalyst volumes which permit higher NOX reduction efficiencies and, therefore,
higher reagent utilization.
Table 3-16 lists the domestic experience of SCR systems on coal-fired utility boilers. The
only performance data available to date is limited to the Cogeneration Chambers Plant in New
Jersey where the SCR reactor volume was designed to reduce inlet NOX by 70 percent to a level
of 0.1 Ib/MMBtu with less than 5 ppm NH3 slip (Cho and Dubow, 1993). The plant has been
operating satisfactorily for the past 9 months with a 2 percent sulfur coal and a planned complete
catalyst replacement period of 10 years. The Keystone facility will shortly be on line. The SCR
arrangement there is also the hot-side high-dust for a 1.1 percent sulfur coal, and is designed for
70 percent reduction in inlet NOX, also to 0.1 Ib/MMBtu (Cho and Snapp, 1994). Both the
Chambers and Keystone plants were designed by Foster Wheeler with IHI catalyst for Chambers
and Siemens catalyst for Keystone.
The first full-scale SCR reactor retrofit at the Merrimack cyclone Unit 2 in New Hampshire,
was completed in mid 1995, in time to meet the NOX RACT deadline. The cyclone is one of the
highest boiler NOX emitter because of the arrangement and size of the cyclone furnaces. Its
uncontrolled baseline level at full load is 2.66 Ib/MMBtu. The design of the SCR reactor permits
65 percent reduction in NOX to 35 tons/day (RACT limit) while burning 2.5 percent sulfur coal.
The slagging furnace design exposes the catalyst to lower flyash loadings than in a comparable dry
bottom unit. Catalyst life is projected up to 12 years, that is the entire initial catalyst charge
(installed over a period of 5 years) will be replaced in a 12-year span. Catalyst resistance to poison
such as arsenic in the coal flyash, remains to be validated. Catalyst resistance to masking and
deactivation due to deposition of sulfated flyash and poisons such as arsenic, vanadium, and other
3-68
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inorganic compounds remains to be validated. Ongoing tests suggest, however, that optimization
of physical catalyst properties, such as pitch, and countermeasures, such as sootblowing, have the
potential to increase catalyst resistance to high dust and high sulfur environments. Undoubtedly,
the success of this retrofit, once demonstrated, will propel SCR technology to the forefront of the
commercial controls available for large NOX reductions from coal plants.
3.5 COMBINED TECHNOLOGIES
Combining two or more control technologies can be a cost effective approach to large NOX
reductions without major equipment modifications. Recently, several combinations of controls have
been proposed, researched, and patented in an effort to attain NOX reduction efficiencies of 80
percent and more without the need for large-scale SCR reactors. In addition to these combined
technologies that target NOX reduction only, other gas treatment controls for simultaneous SO2 and
NOX reductions are being demonstrated under DOE's Clean Coal Program. These technologies will
likely play a significant role in controlling emissions from new coal-fueled powerplant installations
and may, in the future, offer feasible alternatives to traditionally separate NOX and SO2 controls
strategies when both SO2 and NOX emissions reductions are required.
The following subsections review these technologies and their current commercialization
status. Generally, hybrid controls have a much smaller experience base for coal- and oil-fired plants
than for gas-fired boilers. However, the recent reported success of the SNCR+SCR+AH-SCR at
Mercer certainly points to the commercial feasibility of this control approach for coal-fired boilers
as well.
3.5.1 Advanced Gas Returning
The integration of gas reburning with SNCR is referred to as advanced gas reburning
(AGR). This process is considered by EER Corporation, the patent holder, to be an improvement
over either the gas reburning and SNCR technologies used separately because of synergism between
the two technologies (Sanyal, et al., 1993). AGR uses reburning with natural gas to enhance the
SNCR process, broadening and deepening the SNCR temperature window for greater overall NOX
3-69
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reduction (Folsom, et al., 1995) The preferred arrangement for natural gas and SNCR agent
injection is illustrated in Figure 3-11. The reburn zone stoichiometry is adjusted to near
stoichiometric conditions, instead of the reburn optimum setting of 0.90. Normally, this would
require only 10 percent gas use instead of the 18 percent used in conventional reburning, thus
lowering the cost of the technology. Urea or ammonia agents are injected along with the overfire
air, reducing the complexity of another separate injection location. Pilot-scale test results showed
a peak overall NOX reduction of 90 percent from uncontrolled levels of 890 ppm (about
1.2 Ib/MMBtu). The increased CO and OH" radicals from the reburn zone produced higher SNCR
efficiencies over a broader temperature window than would otherwise be possible with conventional
SNCR (Chen, 1991). Full-scale utility boiler demonstration of this technology is being planned
(Freedman, 1994). Because the process uses a combination of gas reburning and SNCR, reliable
operation in large (>200 MWe) boilers and load-following capability as well as gas supply and
differential fuel costs remain principal concerns for full-scale retrofits.
SNCR
Agent
Reburning
Fuel (-10%)
S^ Baseline
[N^^ Reburning
| ^ SNCR agent
NOx
Reduction (%)
Incremental
--
45
73
a
&
—
45
85
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55
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Figure 3-11. Advanced reburning (AR) with synergism (Folsom, et al., 1995)
3-70
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A variation of the Advanced Gas Reburning (AGR) Process is the CombiNOx Process
(Sanyal, et al., 1993). This process combines AGR with downstream methanol injection and NO2
scrubbing. The methanol is injected downstream of the SNCR process at a molar ration of about
1.5 to oxidize the NO to NO2. Pilot-scale tests have shown overall NOX reductions of 85 percent
(Pont, et al., 1993 and Sanyal et al., 1993). Additional combinations of controls explored by EER
Corporation have included switching the location of urea injection upstream of the OFA. In this
approach, the reburn stoichiometry is maintained near 1.0 with a minimum of natural gas, typically
10 percent. The objective of the process is to increase the concentration of NOX reducing radicals
available in the reburning zone. In pilot-scale tests, high concentrations of CO in the reburning
zone with urea injection at a stoichiometry of 1.02 produced NOX reductions as high as 80 percent
at a urea injection temperature of approximately 1,850°F (Pont, et al., 1993).
Application of these technologies on full-scale utility boilers is only speculative at this time.
There are several practical considerations that will require field evaluation of this technology with
initial exploratory tests on full-scale boilers.
3.5.2 SNCR and SCR
The principal objective of combining SNCR and SCR in tandem is to reduce the volume of
catalyst needed, thus permitting the installation of SCR with the minimum of modifications to the
existing ductwork and heat transfer equipment downstream of the economizer. The synergism
between SNCR and SCR also permits more flexibility in the operation of the SNCR. For example,
the presence of SCR catalyst downstream of the SNCR allows for greater NSR levels because the
catalyst will use the unreacted NH3 leaving the SNCR temperature window to further reduce NOX.
In addition, hybrid SNCR is designed for a different temperature window than commercial stand-
alone SNCR. Stand-along SNCR is commercially designed for operation at higher temperature than
ideal for NOX reduction in order to keep NH3 slip at the user guarantee level. With hybrid, instead,
SNCR is allowed to be engineered for the maximum SNCR NOX reduction because the concern for
ammonia slip is greatly diminished. In other words, NOX reduction is greater at the same NSR
3-71
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because of latitude allowed in the NH3 slip level. The greater reagent utilization has a beneficial
effect on lifecycle O&M costs relative to stand-alone SNCR. Additionally, NSR can be increased
to provide a higher yet slip level to feed the SCR in accordance with catalyst size. Therefore, a
double positive effect relative to NOX reduction accounts for the attractiveness of this concept.
In summary, the combination of higher NSR in the SNCR zone with downstream SCR can
permit high NOX reduction efficiencies, in theory approaching the 90 percent level only possible with
full-scale SCR, with greater assurances of low NH3 slip and at lower balance of plant cost.
There are several combinations of SNCR and SCR controls. These are:
• SNCR with full-scale SCR reactor
• SNCR with catalyst air heater (CAT-AH)
• SNCR with in-duct SCR
— Existing duct
— Expanded duct
• SNCR with in-duct SCR and CAT-AH in series
The first of these combinations is the least likely and the most costly of retrofits because it does not
take advantage of the combination of controls to minimize retrofit capital requirement. To date,
retrofit demonstrations have focused on the last three arrangement options using in-duct and AH-
SCR catalysts. At least two vendors are actively pursuing installations of these combined systems.
Wahlco Environmental Systems, Inc. in California has demonstrated the efficiency of the Staged
NOX Reduction (SNR) process at the San Diego Gas and Electric Encina Power Plant and is active
in evaluating this approach for coal applications at the Public Service Electric and Gas Mercer
Unit 2. Nalco Fuel Tech, the major vendor of SNCR systems using urea, has tested the hybrid
technology in a pilot-scale program where 85 percent NOX reduction with 6 ppm or lower NH3 slip
was recorded on a short-term basis (Graff, 1995). The patented process is under the trade mark
NOxOUT CASCADE®.
3-72
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As indicated, the in-duct SCR systems can be distinguished between two major applications.
Those whose catalyst is made to fit within the existing ductwork, and those whose catalyst volume
requires an enlargement of the ductwork. The former truly in-duct systems have appeared only in
gas-fired boiler applications in California. For various reasons, including the small NOX reductions,
catalyst volumes for dedicated gas-fired boilers have been sufficiently small to fit in existing
ductwork with the aide of gas flow control devices. However, these true in-duct systems are
considered least likely for coal- or oil-fired boilers because NOX reductions goals are typically larger,
excessive gas inlet velocities cannot be tolerated, and maintenance requirements increase.
Table 3-18 lists performance data obtained on three demonstration sites: the gas-fired
Encina plant and the Mandalay plant in California and the coal-fired boiler at the Mercer Station
in New Jersey. The Encina retrofit relied on an in-duct catalyst with a space velocity of 33,800 hr'1
and a hot-end catalyst in the air heater with a space velocity of 22,800 hr"1. The demonstration of
this technology was started in 1992 and showed an average NOX reduction of greater than
50 percent. Plans to add more catalyst in the existing duct are projected to boost the overall
efficiency of the SNR to a range of 88 to 97 percent (Krimont, et al., 1993).
A similar combination of controls was recently demonstrated at the Mercer Unit 2. The
80 MWe demonstration at Mercer was not only the first SNCR+in-duct SCR+CAT-AH
demonstration on a coal unit, but it was also the first application of a horizontal catalyst
arrangement for a coal unit anywhere in the world. This type of retrofit installation was possible
because of low ash and sulfur loading. The coal is a high quality low sulfur and ash coal and the
boiler uses slagging twin furnaces reducing the amount of ash reaching the catalyst. Preliminary
concerns with potential plugging of the in-duct catalyst modules were dispelled and the system
operator with a maximum pressure drop of 5 in. H2O. The major findings of this demonstration
point to the technical feasibility of hybrid controls for low sulfur coal units with NOX reductions
exceeding 90 percent and acceptable NH3 slip levels. The long-term operating performance of the
hybrid control must be evaluated. Also, the feasibility for high-sulfur and high ash plants remains
3-73
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to be demonstrated. However, in light of these promising results, commercial retrofit of this
technology on both PSE&G units at Mercer is being planned to permit attainment of the company's
NOX reduction goals.
3.53 Combined NOX/SOX
When regulations call for significant reductions in both SO2 and NOX from coal-fired
powerplants, the retrofit of processes that can combine the reduction of both pollutants with
efficiencies reaching 90 percent may prove to be the most cost-effective approach. In Europe,
combined SO2/NOX removal systems are currently installed on 2.9 GWe of coal-based generation
capacity in Denmark, Germany, Italy and the USA (IEA Coal Research, 1994). These European
installations tend to prefer catalytic and activated carbon combined SO2/NOX removal systems. All
the installations in the US are part of the U.S. DOE Clean Coal Demonstration program and tend
to be based on sorbent injection systems. Perhaps, the most advanced of these processes are the
B&W's SOx-NOx-ROx-Box (SNRB) and The Netherland's Haldor Topsoe SNOX process. The
B&W's SNRB process uses a hot catalytic baghouse injected with dry calcium or sodium. NOX is
removed by NH3 injection all in the same reactor. The process is being demonstrated on a 5-MWe
slip stream at the Ohio Edison's R.E. Burger Station. With an NH3/NO molar ratio of 0.9, the
NOX reduction efficiency of the SNBR process has been shown to exceed 90 percent routinely
(DOE, 1994). The SNOX process uses a Haldor Topsoe NOX reducing catalyst followed by catalytic
oxidation of SO2 to SO3, which is in turn hydrated to make concentrated and salable sulfuric acid.
This process has been demonstrated at the Ohio Edison's Niles Station Unit 2 with 2 consecutive
months of 94 percent NOX reduction performance (DOE, 1994). This process is particularly
attractive because it minimizes solid waste discharge. At least one 300 MWe powerplant in Europe
is currently equipped with the SNOX process.
Many of the retrofit issues that accompany full-scale SCR reactor retrofits at existing
powerplants would apply even more so in the case of these combined NOX/SOX processes. These
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technologies are for the most part still in the demonstration stage, and their most cost-effective
applications may be for new powerplants where site layout can include provisions for these systems.
3.6 SEASONAL CONTROLS
This section highlights the feasibility and benefits of NOX controls used on a seasonal basis
to achieve reductions in emissions when ambient ozone levels are highest. From a practical
viewpoint, all control options discussed above can operate either on a year-around basis or during
the ozone season which typically spans between April and October. Because NOX control is costly,
the use of controls for a reduced amount of time brings about obvious economic benefits. However,
coupled with lower operating costs, seasonal controls also have overall lower yearly NOX reductions.
The amount of NOX reduced during the ozone season compared to a year-around basis will likely
be in proportion to the percent time that the control is in operation. If the dispatch load and
capacity factor are higher during the ozone season (i.e., scheduled boiler outage is in late fall), the
NOX reduction would benefit from a seasonal NOX reduction strategy.
3.6.1 Seasonal Gas Use
The price of natural gas can vary dramatically from one location to the next. It is not
unusual, for example, for natural gas to be very economically priced with coal and oil in one location
but much less competitive in another. This spot pricing and availability of natural gas make it
difficult to make broad generalization about the application of this fuel for utility boilers as an
emission control option. However, it is reasonable to assume that because the availability of natural
gas as a boiler fuel typically peaks in the summer season, when residential and commercial heating
demand is lowest, natural gas for utilities is most competitively priced during the summer months.
Coincidently, the summer season is also the period when ground level ozone peaks and exceedances
of federal standards are recorded. The seasonality of the ozone problem and the concurrent
availability of natural gas points to some obvious benefits of seasonal gas use as a way to reduce
the NOX emission inventory. The selected use of natural gas over a short ozone season, rather than
3-76
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throughout the year, can be used to mitigate the economic disadvantage of higher fuel cost while
providing, perhaps, the greatest benefit to the ozone attainment effort.
Seasonal gas use can be implemented via cofiring, reburning, and full gas conversions.
Considering that the NOX reduction is typically higher with reburning methods, it stands to reason
that peak reductions in NOX per unit of gas heat input will be achieved with gas reburning.
Regardless of the method of seasonal gas use chosen, however, access to a gas pipeline and boiler
modifications discussed above will be necessary even for a reduced number of months of gas firing.
Figure 3-12 illustrates the potential scenarios for seasonal gas using cofire, reburn, and 100 percent
gas firing versus similar gas uses on a year around basis. On a MWe output basis, seasonal gas use
in a reburning scenario for a tangentially coal-fired boiler would produce on the order of 3 to
17 tons a year of NOX reduction. The low end of this estimate is based on reburning with LNB
Seasonal cofire Seasonal conversion Yearly reburn
Seasonal reburn Yearly cofire Yearly conversion
Percent reductions based on results published in
Tables 3-3, 3-5, 3-9.10,000 Btu/kW-hr
Ozone season from April 1 to October 31
Figure 3-12. NOX reductions on a seasonal versus a yearly basis for coal-fired
tangential boilers
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technology in place, as the case would be for post-RACT retrofit. The high estimate is based on
reburning being in place on an uncontrolled tangentially fired boiler. The experience available with
gas reburn on an LNB-controlled tangential coal-fired boiler is limited to the Lawrence station of
KP&L. Close coupled reburning and cofiring for tangential boilers produced similar NOX reduction
levels. With an uncontrolled boiler, however, this estimate of NOX reduction is more than if the
same boiler were to operate with cofire on a year around basis. Also noticeable, is the small
difference between NOX levels from reburning and full conversions for uncontrolled boilers.
However, when combustion controls are applied to a gas-converted boiler, NOX reductions are much
higher than a coal unit using reburning and LNB. The benefits of seasonal gas use may be greater
if dispatch loads are lower in the ozone season because of the improved operational performance
of gas firing at lower boiler loads.
3.62 Seasonal Flue Gas Treatment
All flue gas treatment controls can be used to reduce NOX all year around (i.e., whenever
the boiler is operating within its normal dispatch range) or for a fraction of that time. Among the
three major control options (NSCR, SCR, or hybrid combinations), SNCR is perhaps the most
adapt to a seasonal use. This is because SNCR does not employ any catalyst and can be readily
turned off or on without consideration to continuous deterioration of equipment. In addition,
because SNCR would be used only during the warmer months, it may be possible to reduce or
eliminate insulation and heat tracing of reagent lines, reducing the initial capital investment.
The seasonal use of SCR controls may require the ability to by pass the catalyst section to
avoid continued exposure of catalyst material to flue gas without the benefits of continuous NOX
reduction. This may be particularly desirable for SCR installation on coal-fired boilers where
catalyst erosion and pressure drop due to high dust loading are of particular concern. In most
cases, the bypass of the catalyst section or reactor may not be possible or even warranted
considering the space and investment necessary to provide the additional duct-work. Removal of
3-78
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the catalyst from the gas stream to extend its life may also not prove feasible because reinstallation
would require a second boiler outage.
Compared to SCR-only controls, hybrid systems such as SNCR with in-duct SCR catalyst,
may provide greater flexibility to modulate NOX reduction with seasonal needs. In the hybrid
controls, the use of reagent in the upstream SNCR can be reduced or eliminated and the
downstream catalyst can be operated at lower reduction efficiency with its own supply of reagent.
Also, because the downstream catalyst is likely to be an in-duct design, smaller quantities of catalyst
may be exposed to the gas stream than, perhaps, in full-scale SCR applications.
3.7 SUMMARY
Several NOX control technologies are commercially available to reduce NOX from the
population of RACT-controlled utility boilers in NESCAUM and MARAMA. The reasonableness
of each application hinges on many factors. Only a few factors have been considered in this study.
Others are, for the most part, site specific and cannot be fully weighed in the context of this study.
For example, the application of gas-based controls, whether seasonally or year around, hinges on
the availability of gas supplies, primary fuel choice, RACT-controlled NOX levels, and above all, fuel
prices. Many of these gas-based controls may contribute only marginally to attainment of very low
NOX emission targets. Among the various gas-based options available, reburning is likely to provide
the largest NOX reduction on a gas heat input basis. The NOX reduction potential of cofiring has
not been fully explored, especially when used in combination with LNB technologies. Its application
on post-RACT units remains doubtful except as a technique to trim NOX emissions from selected
boilers.
The applicability of ammonia-based controls, whether catalytic or noncatalytic, hinges on
several factors such as fuel choice, boiler load dispatch, retrofit access, age of unit, and others. Yet,
these controls installed by themselves or in combination may provide the only feasible approach to
deep reduction in NOX from post-RACT levels. Although experience is growing at a rapid pace,
widespread reliance on both non-catalytic and catalytic controls will be more likely once long term
3-79
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performance has been ascertained and operational impacts and costs fully realized. SCR, especially,
must be evaluated on high sulfur units, coal and oil, to be considered commercially feasible for
plants that burn high sulfur fuels. The recent retrofit at Merrimack will provide one such
demonstration. In the interim, further technical improvements and demonstrations of commercial
and novel technologies will likely improve the retrofit potential of many of the controls evaluated
in this study.
Tables 3-19 and 3-20 list estimates of NOX reduction efficiencies for utility boilers in
NESCAUM and MARAMA. These results are based for the most part on performance of controls
reported to date and estimates based on factors impacting performance. These estimates are made
irrespective of the retrofit feasibility of these controls on specific boilers. For example, it is
recognized that retrofit of SCR may not be considered feasible because of space limitation coupled
with high sulfur fuel. Also shown are the NOX emissions for uncontrolled and RACT-controlled
boilers. Reduction efficiencies estimates are the result of performance data documented in this
chapter.
For RACT-controlled coal-fired boilers, the application of gas-based technologies, with a
maximum heat input of 20 percent, will likely add NOX reductions in the range of 30 to 50 percent.
For uncontrolled units, reburning can result in a maximum of 65 percent reduction. Most of the
uncontrolled coal-fired boilers are presently located in the MARAMA states of Maryland and North
Carolina, where access to natural gas supplies for powerplants must be evaluated. Full conversions
of LNB-controlled coal-fired boilers to gas firing are not likely considering the impact on operating
costs and the marginal benefit of this approach in reducing NOX compared to reburning. To
illustrate this point, Table 3-21 compares the NOX reduction in Ib/MMBtu of gas used. Clearly, in
all cases, reburning offers the greater NOX reduction potential on unit of gas than either cofiring
or conversions.
SNCR, by itself, for either coal- or oil/gas-fired plants already controlled with RACT, is
likely to be able to reduce NOX in the range of 10 to 40 percent depending on initial NOX levels,
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Table 3-19. Summary of NOX reduction efficiencies for coal-fired boilers
Control Type
Cofire
Reburn
Conversion
SNCRa
SCR
Hybrids:
SNCR+SCRb
AGR
NOX/SOX
Wall-fired Boilers
Uncontrolled
0.90 Ib/MMBtu
25 to 40
40 to 65
40 to 70
30 to 65
60 to 90
80 to 95
80 to 85 (est)
80 to 85
LNB-Controlled
0.50 Ib/MMBtu
ND
30 to 50
35
30 to 40
60 to 90
80 to 95
80 to 85 (est)
80 to 85
Tangentially-fired Boilers
Uncontrolled
0.6 Ib/MMBtu
10 to 35
65
70 to 75
30 to 50
(est.)
60 to 90
80 to 95
80 to 85 (est)
80 to 85
LNB-Controlled
0.4S Ib/MMBtu
25 to 40
15 to 40
ND
30 to 35
(est.)
60 to 90
80 to 95
80 to 85 (est)
80 to 85
Cyclone and
Slagging
Furnaces
Uncontrolled
1.2 Ib/MMBtu
NA
45 to 60
45 to 50
30 to 40
60 to 90
80 to 95
80 to 85 (est)
80 to 85
NA = Not applicable.
"SNCR NOX reduction efficiencies based on maximum of 10 ppm NH3 slip.
bEstimated based on recent demonstration successes at Mercer Station
cAdvanced gas reburn (GR + SNCR). Not yet demonstrated on full-scale boilers.
Table 3-20. Summary of NOX reduction efficiencies for oil/gas-fired boilers
Control Type
Cofire
Reburn
Conversion (oil
togas)
SNCRa
SCRb
Hybrids:
(SNCR + SCR)b
Wall-fired Boilers
Uncontrolled
0.50 Ib/MMBtu
20 to 30
(est.)
50 to 60
30 to 40
25 to 40
80 to 95
70 to 90
RACT-Controlled
035 Ib/MMBtu
20 to 30
(est.)
50 to 60
40 to 50
(est.)
10 to 40
80 to 95
70 to 90
Tangentially-fired Boilers
Uncontrolled
0.30 Ib/MMBtu
20 to 30
(est.)
50 to 60
30 to 40
25 to 40
80 to 95
70 to 90
RACT-Controlled
0 .25 Ib/MMBtu
20 to 30
(est.)
30 to 40
40 to 50
(est.)
10 to 40
80 to 95
70 to 90
Cyclone and
Slagging
Furnaces
Uncontrolled
0.52 Ib/MMBtu
ND
ND
10 to 20
(est.)
ND
ND
ND
ND = Not commercially demonstrated, although theoretically feasible.
"SNCR results based on maximum NH3 slip of 10 ppm.
bData for SCR and hybrids are for gas-fired boilers only.
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Table 3-21. Documented NOX reductions for gas-based controls on PC-fired boilers8
Control Type
Cofire
Reburn
Conversion
Wall-fired Boilers
Uncontrolled
0.90 Ib/MMBtu
0.90 to 2.8
2.5 to 3.4
0.41 to 0.68
LNB-ControlIed
0.50 Ib/MMBtu
NA
1.0 to 1.6
035
Tangentially-fired Boilers
Uncontrolled
0.6 Ib/MMBtu
0.75 to 1.2
2.2
0.42 to 0.45
LNB-Controlled
0.45 Ib/MMBtu
0.56 to 0.90
0.56 to 0.90
NA
Cyclone and
Slagging Furnaces
Uncontrolled
1 2 Ib/MMBtu
NA
3.4 to 4.0
0.54 to 0.64
NA = Not applicable. Technology not tested or not considered likely for that application.
"All units are in Ib of NO2 reduced per MMBtu of gas used in the control technology. Cofiring gas use less than 8
to 35 percent; reburning 16 to 20 percent; conversion 100 percent gas firing.
the size of the boiler, and its load dispatch characteristics. Higher NOX reduction levels up to
65 percent with SNCR are possible for small MWe, base-loaded uncontrolled boilers. SCR and
hybrid technologies offer the potential to exceed 80 percent NOX reduction in all installations,
whether RACT-controlled or not. The overall range in NOX reduction of 70 to 95 percent reflects
the flexibility of hybrids to deliver moderate to high percent reduction efficiencies depending on the
volume of catalyst used, as required to meet regulations. SCR by itself can achieve 60 to 95 percent
control or more for most applications, including boilers with low inlet NOX levels, as demonstrated
in California. Therefore, their applications are particularly suitable for retrofit on RACT-controlled
boilers. NOX reduction of 90 percent or more may not be feasible with some high sulfur fuel
applications, however, due to the potential for excessive SO2 to SO3 conversion and subsequent
maintenance requirements of sulfate deposits. Although the technical and experience gains of
recent years on the use of SCR and SNCR+SCR hybrids are obvious, greater experience is
necessary to fully document the long-term performance of these novel control approaches, especially
on high sulfur-fueled boilers. Furthermore, the feasibility of retrofitting SCR or SNCR+SCR must
be evaluated on a case-by-case basis because of the equipment, fuel, and layout constraints that are
particular to each installation.
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Demonstrations and Future Applications," Joint Power Conference, Kansas City, October 1993
La Flesh, R. C. et al., "Three-Stage Combustion (Reburning) Test Results from a 300 MWe Boiler
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1993.
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Philbrick, J., with Public Service/New Hampshire telephone communication with C. Castaldini with
Acurex Corporation, February 1995.
Pont, J. N., et al., "Evaluation of the CombiNOx Process at Pilot Scale," Environmental Progress.
Vol. 12, No. 2, May 1993.
Pratapas, J. M. and J. Bluestein, "Natural Gas Reburn: Cost Effective NOX Control," Power
Magazine. May 1994.
Pratapas, J. M., "Major New Gas Technology Initiatives Underway at the Gas Research Institute,"
Presented at the IGT/EPRI Conference, June 29, 1994.
Radian Corp., "Summary of Short-Term Characterization Test Results of Gas Cofire Techniques
at Warrick Unit 1," draft report prepared for Gas Research Institute, November 18, 1994.
3-85
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Reese, J., "SCR Air \-Preheater Application of Southern California Edison," Presented at the 1992
EPRI NOX Control for Utility Boilers Workshop, Cambridge, MA. July 7-9, 1992.
Rini, M. J., et al., "Evaluating the SNCR Process for Tangentially-Fired Boilers," 1993 Joint
Symposium on Stationary Combustion NOX Control, Miami, FL, May 1993.
Rosenberg, H. S. and J. H. Oxley, "Selective Catalytic Reduction for NOX Control at Coal-Fired
Power Plants," ICAC Forum '93, Controlling Air Toxic and NOX Emissions, Baltimore, MD,
February 24-26, 1993.
Sanyal A., et al., "Advanced NOX Control Technologies," Presented at the Power-Gen Americas '93,
Dallas, Texas, November 17-19, 1993.
Shore, D. E., et al., "Urea SNCR Demonstration at Long Island Lighting Company's Port Jefferson
Station Unit 3," 1993 Joint Symposium on Stationary Combustion NOX Control, Miami, FL, May
1993.
Springer, B. "Southern California Edison's Experience with SNCR for NOX Control," Presented at
the 1992 EPRI NOX Control for Utility Boilers Workshop, Cambridge, MA. July 7-9, 1992.
Staudt, J. E., et al., "Commercial Application of Urea SNCR for NOX BACT Compliance on a
112 MWe Pulverized Coal Boiler," presented at the EPRI/EPA Joint Symposium on Stationary
Combustion NOX Control, Kansas City, MO, May 16-19, 1995.
Takahashi, Y., et al., "Development of Mitsubishi "MACT" In-Furnace NOX Removal Process,"
Presented at the U.S. - Japan NOX Information Exchange, Tokyo, Japan, May 25-30, 1981.
Takeshita, M., "Air Pollution Control Costs for Coal-fired Plants," Draft Report; IEA Coal
Research, London, England, September 1994.
Teixeira, D. P., et al., "Selective Noncatalytic Reduction (SNCR) Demonstration in a Natural Gas-
Fired Boiler," 1993 Joint Symposium on Stationary Combustion NOX Control, Miami, FL, May 1993.
Wendt, J. O. L., Mereb, J. B., Air Staging and Reburning Mechanisms for NOX Abatement in a
Laboratory Coal Combustor," Presented at the AFRC/JFRC International Conference on
Environmental Control of Combustion Processes, Honolulu, HI, October 7-10, 1991.
Zamorano, D., et al., "Case Study in the Retrofit of Selective Catalytic Reduction (SCR)
Technologies in the U.S.," Presented at the ICAC Forum '94 - Living with Air Toxic and NOX
Emissions Controls, Arlington, Virginia, November 1-3, 1994.
3-86
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CHAPTER 4
COST OF POST-RACT CONTROLS
The cost to modify existing boiler equipment at power plants for the purpose of installing
NOX controls vary from plant to plant. Although the vendor's equipment may be the same,
additional costs incurred because of site-specific factors and balance of plant modifications often
determine the final cost of any one technology. For example, the overall capital cost can be much
higher than the average when the installation requires more extensive modifications for needed
equipment upgrades in aging plants, incompatible fuel type and quality, or poor retrofit access.
Also, the operating cost can change because of site specific labor costs and operational impacts such
as heat rates and ash disposal costs.
Control costs are also influenced by market competition and technology advances. For
example, the rapid development of the NOX retrofit market has intensified competitiveness among
various suppliers creating a downward trend in the cost of some NOX controls. Ongoing
technological advances, principally in SCR and SNCR+SCR hybrids, have contributed to recent
retrofit successes in certain applications at much lower costs than projected just a few years ago.
Whether this trend in declining costs is likely to continue will depend on the growth of the retrofit
market and the level of competition.
Table 4-1 lists major factors that will influence the cost of four post-RACT control options
available to utilities. The factors that influence the capital cost of gas reburn, for example, include
the gas pipeline supply (proximity to the plant and capacity), the size and firing configuration of the
boiler and its current burner configuration. Retrofit requirements will vary whether the boiler is
firing with low NOX tangential or wall burners. For example, because tangential LNCFS systems
4-1
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are likely to have SOFA ports already in place and can use the top burner level for injection of
natural gas, firebox penetration is often unnecessary for retrofit of gas reburn. Installation of OFA
ports and gas injectors is necessary, however, for wall-fired boilers retrofitted with gas reburn.
Additional capital costs can arise from other plant modifications needed because of poor operating
condition of existing boiler equipment, superheater spray improvements, reheat and superheat tube
metal upgrades, etc. These modifications may especially be necessary when 100 percent gas firing
capability is desired as in gas conversions. The major recurring costs for gas reburn is the fuel price
differential. Additional site specific costs can result in either loss or improvement in heat rate1
and any changes in furnace slagging or fouling patterns. Some sites will benefit from reduced SO2
emissions when coal or high sulfur oil is displaced, and when lost boiler load capacity is recovered,
translating to SO2 allowance and capacity recovery credits. Lost boiler load capacity can result
when the coal is switched from a low ash, high heating value eastern bituminous coal to a low sulfur,
lower heating value subbituminous coal.
SNCR capital costs are principally influenced by the boiler's size, primary fuel, and load
dispatch schedule. Aside from the effects of economies of scale, larger boiler furnaces often dictate
improved reagent coverage with more injectors to compensate for broad temperatures and gas
velocity unevenness. Changing loads will also dictate more than one injection location, increased
operational complexity and control systems. Primary fuel influences the initial NOX level and sets
limits on allowable NH3 slip to minimize problems with air heater fouling and contamination of fly
ash. For example, high sulfur coal-fired boilers may permit only 5 ppm NH3 slip because of
operational concerns, whereas gas-fired units can allow 10 ppm NH3 slip to limit potential health
hazards associated with these hazardous emissions. Boiler size and initial NOX level also define the
requirements for reagent storage. From an operational point of view, reagent cost is the highest
1 Boiler efficiency loss is the direct result of higher moisture in the flue gas from increased
hydrogen in the fuel. An efficiency improvement can result from other combustion air balance
modifications that can reduce the overall combustion excess air.
4-3
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of the recurring costs for SNCR. Other operational costs can result from increased maintenance
of downstream equipment, such as air preheaters and from some thermal efficiency loss due to the
use of water with the reagent.
Many more factors can influence the capital cost for SCR. This is because various
configurations are possible depending on the fuel, boiler size, inlet NOX level and target NOX
reduction, plant layout, etc. Fuel type is a dominant cost consideration because it often implies the
level of SO2, fly ash, and trace contaminants reaching the catalyst. Coupled with other design
considerations, fuel type often dictates the catalyst composition, configuration, and volume required
for a specific installation. Inlet and target NOX levels and NH3 slip that can be tolerated also play
key roles in the volume of catalyst required. In-duct and air heater applications are likely to have
a lower capital cost because as little as 1/10 of the catalyst needed for coal units, for example, may
be sufficient to meet the NOX target in a gas-fired boiler.
The installation of SCR is also subject to the greatest uncertainties with respect to balance
of plant costs. This is because the installation of the catalyst requires access to economizer outlet.
Modifications to the ductwork and downstream equipment are often in proportion to the volume
of catalyst installed, which in turn also affects the pressure drop. If the pressure drop exceeds the
capacity of the fans, costly fan upgrades may also be necessary. The existing equipment layout,
availability of space and ease of access, and configuration of the air heater will influence the final
retrofit design and layout. Because several configurations are possible, costs are often misleading
and do not consider these effects. Various types of flow distribution and temperature control
mechanisms are also site-specific costs incurred because of the need to optimize inlet flow
conditions to the catalyst. The O&M costs of SCR are dominated by the catalyst replacement
schedule and amount of reagent. Additional site specific factors that influence recurring variable
O&M costs are associated with heat rate losses and increased fan power to overcome the added
pressure drop of the catalyst. The costs of hybrid controls are influenced by a combination of
factors that affect SNCR and SCR costs.
4-4
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Finally, how the capital cost is amortized also influences the overall costs and cost
effectiveness. Factors that influence how capital is amortized include the remaining life of the
boiler, the average capacity factor over that period of time, the interest on capital, and the rate of
inflation on recurring costs. Low capital cost controls, such as SNCR and possibly gas reburning
on T-fired boilers, are least affected by the remaining life of the boiler or by the capacity factor.
This section provides a brief overview of the costs reported to date and arrives at some
general guidelines on expected costs of NOX control for retrofit on most utility boilers. Although
actual costs are expected to vary from plant to plant, estimates developed in this study are
representative of costs anticipated for most retrofit scenarios. These estimates are supported by
recent retrofit experiences, vendor estimates, and vendor guarantees.
Table 4-2 lists the cost cases evaluated in this chapter. The technologies selected for cost
evaluations are those that have either commercial or full-scale demonstrated experience. Each of
the entries in Table 4-2 represents the level of NOX reduction in Ib/MMBtu from post-RACT
emission levels listed in the column headings. These emission levels reflect data presented in
Chapter 2. For coal-fired plants equipped with LNB, the post-RACT technologies include gas
reburning, SNCR, and SCR. Full gas conversions are considered only for dry-bottom coal units and
oil-fired boilers with gas already available onsite. For gas reburning, a distinction is made for plants
that already have access to adequate supply of gas and those that must install a pipeline to a
maximum distance of 10 miles to ensure adequate gas supply. Performance data for hybrid
combinations of SNCR and SCR are based on recent tests on at least one slagging furnace.
For example, gas reburning on LNB-retrofitted coal-fired boilers with controlled levels in
the range of 0.38 to 0.75 Ib/MMBtu (see Chapter 2) is likely to reduce NOX by 0.10 to
0.40 Ib/MMBtu according to estimates developed in this study from full-scale experience. These
estimates predict NOX reduction performance in the range of 30 to 50 percent for boilers in this
NOX emission range. The NOX reductions for uncontrolled slagging furnaces are much higher based
on higher NOX levels and NOX reduction performance for reburn as high as 65 percent. Similarly,
4-5
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Table 4-2. List of cost cases
Control Technology
Gas reburning (NGR)
Gas Conversion (NGC)
SNCR
SCR (in-duct)
SCR (air heater)
SCR (full-scale)
Hybrid (SNCR+SCR)
NOX Reduction (Ib/MMBtu)
LNB-controlled
Coal-fired Boiler
(038 to 0.75
Ib/MMBtu)
0.10 to 0.40
0.25 to 0.50
0.10 to 0.30
NA
c
0.25 to 0.60
0.30 to 0.60
Combustion-controlled
Gas/Oil-fired Boiler
(030 to 0.45
Ib/MMBtu)
0.15 to 0.20
0.15 to 0.25
0.10 to 0.20
0.20 to 0.35b
0.05 to 0.20b
0.25 to 0.40
0.25 to 0.40
Uncontrolled
Cyclone Boiler
(0.9 to 2.4
Ib/MMBtu)
0.55 to 1.20
0.35 to 1.0a
0.30 to 0.90
NA
c
0.60 to 1.7
NA
aNot considered applicable or likely retrofit option.
bMost likely application is on gas- and low sulfur oil-fired units.
°Not a likely stand-alone NOX control for coal or oil-fired boilers.
NA = Data not available. But, if proven feasible, NOX reductions similar to SCR (80 to
95 percent) levels are anticipated with smaller catalyst volumes.
air heater SCR (CAT-AH) will likely be applied to boilers principally in combination with other gas
treatment controls because, by itself, NOX reductions are on the order of 10 to 40 percent. This
reduction efficiency translates to a net NOX reduction of 0.05 to 0.20 Ib/MMBtu from post-RACT
levels in the range of 0.30 to 0.45 Ib/MMBtu. In-duct and full-scale SCR systems will generate
reductions of 0.20 to 0.35 Ib/MMBtu for gas/oil-fired boilers and 0.25 to 0.60 Ib/MMBtu for dry
bottom coal units and up to 1.7 Ib/MMBtu for uncontrolled slagging furnaces. The high estimate
of 1.7 Ib/MMBtu is unusual because it refers to the Merrimack Unit 2 with a very high uncontrolled
level of 2.66 Ib/MMBtu.
Table 4-3 lists the various elements of the capital and operating costs that make up the total
cost at any retrofit installation. Detailed estimates of these costs are not always available on recent
retrofit experiences. Therefore, the cost evaluation in this chapter often deals with the total
reported cost. Major cost elements for gas reburning include the pipeline hookup, furnace
4-6
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waterwall modifications for OFA ports, ducting and FGR fan. Because the installation and
operation of an FGR system is expensive, attempts to operate gas reburning without FGR have also
been investigated. ABB has pioneered the use of gas reburning without FGR. When this is
possible, cost savings of about 30 percent can be realized (La Flesh and Borio, 1993). One NGR
vendor has reported a second generation reburning technology that uses high velocity gas jets thus
eliminating the need to use FGR. The result of eliminating FGR is to reduce the capital cost of
retrofit to $15/kW for a 300 MWe boiler (Folsom, et al., 1995). Gas-coal price differential and any
changes in heat rate that result from changes in boiler efficiency and reduced power for auxiliary
equipment constitute the major operating costs for any type of gas reburn retrofit. Compared to
other post-RACT control approaches, the capital cost of SNCR is often much lower. The principal
elements of the SNCR capital cost are associated with the reagent storage, transport, and injection
and their associated control system. The reagent cost dominates the O&M cost for SNCR. The
initial investment for SCR retrofit is perhaps the most variable. It depends on whether the
installation is for an in-duct, air heater, or full-scale reactor system. In-duct systems also have
variable costs, whether they require expanded ductwork or the catalyst volume is sufficient small
to fit in existing duct dimensions. Independent of this, capital costs include catalyst, reagent storage
and injection grid systems, ducting and flue gas mixing aides, process control. Reagent and
frequency of catalyst additions and replacement are the major elements of O&M cost.
4.1 COST OF GAS-BASED CONTROLS
The cost of natural gas-based controls is generally dominated by the cost differential
between the price of natural gas and the displaced fuel. For example, bituminous coal in the
MARAMA and NESCAUM regions ranges between $1.30/MMBtu and $1.90/MMBtu, equivalent
to about $34 to $48/ton. The price of natural gas is highly variable based on location and
availability. For example, in few instances, the price of delivered natural gas to the utilities has
been as low as that of coal, especially during high-availability summer months. However, it is very
unlikely that on a year around basis, natural gas can be as competitive as coal. In general, in the
4-8
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Northeast, natural gas cost delivered to the utilities ranges between $2.50 and $2.70/MMBtu. The
approximate average cost differential of $l/MMBtu between the two fuels translates to about 10
mills/kWh for a full conversion to natural gas and an incremental fuel cost of 2 mills/kWh for about
20 percent gas reburning. The range of 2 to 10 mills/kWh is equivalent to a capital cost of about
$60/kW to $300/kW, levelized over 20 years for a boiler operating at 60 percent capacity. This
range is much higher than any capital cost reported for gas-based controls. Clearly, the fuel
differential cost is the dominant factor in evaluating the cost effectiveness of gas-based controls for
utilities.
The following sections present 1995 costs estimated for gas reburning and full gas
conversions for coal boilers.
4.1.1 Cost of Natural Gas Reburning
Figure 4-1 illustrates the total capital cost for installation of gas reburning on four utility
boilers where gas reburning was retrofitted and tested. These boilers range in size from about
40 MWe to 130 MWe. The reported capital cost ranges from about $30 to $60/kW. The cost for
the three smaller units include long-term testing and engineering evaluations because they were part
of DOE's Clean Coal Demonstration projects. For most retrofit boilers, the cost of gas reburning
installations, including the cost of pipeline hookup, is estimated to fall in the range of $30 to
$35/kW for conventional NGR retrofits that use FOR to enhance mixing (GRI, 1993; Harding,
1994; DOE, 1993). As indicated earlier, NGR is now offered without FGR at a much reduced cost
(Folsom, et al, 1995). The cost of pipeline hookup for most of the coal units in the OTR was
estimated by the Coalition for Gas-Based Solutions to be less than $10/kW, or approximately
$l/kW-mile (Vaszily, 1994).
Figure 4-2 illustrates the estimated range in cost effectiveness of gas reburning for a
200 MWe coal-fired utility boiler as a function of the NOX reduction achieved. The band in the cost
is the result of a range in gas-coal differential price from $0/MMBtu to $1.5/MMBtu. The
estimates were developed using a capital cost of $20/kW, recently claimed by one vendor and
4-9
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I I I i no Is Power Hennepi n
C-E Tangential
20
Source Hording, et a I ,
120
140
Figure 4-1. Return system cost versus unit size
5,000
DIFFERENTIAL FUEL COST
200 MWe PC-fired boiler
Sulfur in coal = 2.0%
Percent reburn = 15% Heat basis
Load factor = 65%
Capital recovery factor = 16.4%
S02 reduction credit = $250/ton
Capital cost = $20/kW
Gas-coal differential $0 to 1.5/MMBtu
$0.25/MMBtu
$0.50/MMBtu
$0.75/MMBtu
$1.0/MMBtu
$1.25/MMBtu
$1.5/MMBtu
0.3 0.4 0.5
NOx Reduction (Ib/MMBtu)
Figure 4-2. Estimated cost of gas reburn for coal-fired boilers
4-10
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escalated to 200 MWe boiler, and with assumption of SO2 credit of $250/ton. The range in cost
effectiveness illustrates the dominant effects of fuel price differential and NOX reduction. In the
few cases when the price of natural gas is equivalent to that of coal, the operational benefits of gas
use are such that many of the costs of retrofits are offset and the cost effectiveness is reduced below
about $250/ton for most NOX reduction ranges. When the fuel price differential is as large as
$1.5/MMBtu, the cost effectiveness of NGR increases above $l,000/ton for all cases, except when
NOX reduction are large (e.g., from uncontrolled cyclones and slagging furnaces).
As indicated, Figure 4-2 is based on a capital retrofit cost of $20/kW. This is lower than
actual experience but is based on recent estimates of lower cost by avoiding the use of FGR. An
increase in capital requirement to $35/kW for a conventional NGR retrofit with FGR would
translate to increase of about $200 to $400/ton of NOX reduced, depending on the fuel price
differential and the initial NOX emission level.
When gas reburning is used on uncontrolled dry bottom boilers, reductions in NOX on the
order of 0.5 to 0.6 Ib/MMBtu are possible, resulting in a cost effectiveness in the range of $ ISO/ton
for a zero differential fuel price to about $l,000/ton for $1.5/MMBtu price differential. When gas
reburning is retrofitted on LNB-controlled units, the cost per ton of NOX removed will be logically
higher because NOX reductions will be smaller from lower baseline levels. For example, a NOX
reduction in the range of 0.10 to 0.40 Ib/MMBtu from LNB-controlled levels of 0.38 to
0.75 Ib/MMBtu for wall fired boiler could cost as much as $3,000/ton to as little as $800/ton with
a fuel price differential of $1.0/MMBtu to $2,300/ton. When reburning is applied to wet bottom
furnaces, the cost effectiveness improves because of the larger NOX reductions that can be achieved.
The effect of additional capital cost of $10/kWe for installation of a 10 mile pipeline, in the worst
case retrofit, will only add about $100 to $200 per ton to the cost effectiveness range illustrated in
Figure 4-2.
4-11
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4.12 Cost of Gas Conversions
The initial capital required to convert a coal-fired boiler to gas firing is estimated by GRI
to range between $10/kW to $20/kW (GRI, 1993). This is approximately half of the cost reported
for conventional gas reburning, but almost equivalent to second-generation reburning, on the
assumption that major modifications are not required such as retrofit of new burners, installation
of OFA ports, or upgrade of steam tube material to compensate for increased peak and furnace exit
gas temperatures. The upper range in capital cost for gas conversions can be much higher than the
$20/kW reported by GRI because some sites will include these upgrades. For example, the
conversion of the New England Power 430 MWe Brayton Point Unit 4 included many of these
modifications and equipment upgrades and the added cost to access a pipeline with sufficient
capacity. For this site, the cost for the retrofit exceeded $90/kW but was reported to include costs
other than those associated with gas conversion (Harding, 1994).
For the cost effectiveness analysis, the lower cost of gas conversion was set at $15/kW for
sites with onsite gas availability and no upgrades and $25/kW for retrofits requiring pipeline access.
Still higher costs are likely when burners are replaced, for example on oil-fired boilers to permit
low-NOx operation without some of the existing combustion controls such as FGR and BOOS.
Figure 4-3 illustrates the annualized capital and O&M cost of gas conversion for differential fuel
prices of $1.0 and $1.5/MMBtu. Both debits and credits are shown. Clearly, the fuel differential
cost of $l-1.5/MMBtu makes up the largest fraction of the total annualized cost. The SO2
reduction credit translates to about $0.42/MMBtu for a displaced 2.5 percent sulfur fuel. The loss
in boiler efficiency is estimated to be about $0.17/MMBtu. The net annualized cost, taking into
account the potential credits, is about $0.70/MMBtu when the fuel differential cost is $l/MMBtu
and $1.7/MMBtu when the fuel differential cost is $1.5/MMBtu.
Figure 4-4 illustrates how this total annualized cost translates into cost effectiveness for
various levels of NOX reduction. For NOX reductions on the order of 0.6 Ib/MMBtu from
uncontrolled coal-fired boilers, the cost effectiveness of gas conversions is on the order of $2,200
4-12
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C"0
10 15
Gas-Coal fuel differential cost C$/MMBtiO
ra Fuel cost jlsp Efficiency loss |||3 Annualized capital
g 502 allowance [Jim Capacity recovery^S Others combined
Figure 4-3. Estimated annual cost of coal to gas conversion
12.000
10,000
3,000
« 6,000
4,000
2,000 -
Capital requirement = S15/kW
502 Credit = $250/ton
Coal sulfur =25%
•Efflc-lency loss •=-$-)-1*
Capital recovery factor = 0 164
Differential fuel cost = $1 5/NMBtu
0 2
Q 3
04 05 OB
NOx Reduction C Ib/K/tvlBtu3
0 1
0 8
Figure 4-4. Estimated cost effectiveness for coal to gas conversions
4-13
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to $4,200/ton. The conversion of LNB-controlled coal units becomes even less attractive as the
gains in NOX reductions diminish. For example, for a NOX reduction of 0.4 Ib/MMBtu, the cost
effectiveness is well in the range of $4,000 to $6,000/ton.
For similar fuel price differentials, conversion of oil-fired boilers, already controlled to a
RACT level of 0.3 Ib/MMBtu, will result in even higher dollars per ton because net NOX reductions
from these controlled levels are on the order of 0.15 to 0.25 Ib/MMBtu depending on the firing
configuration (i.e., tangential versus wall-fired), the burner area heat release rate, and the use of
combustion controls such as FOR or BOOS. However, generally natural gas is much more
competitive with fuel oil than with coal. In fact, recent price differentials vary between $0 and
$0.50/MMBtu. Natural gas may even show a price advantage over oil during the summer ozone
season. The 1994 average price of oil delivered to utilities in the New England and with Atlantic
regions ranged between $2.1/MMBtu for high sulfur oil (up to 1 percent) to about $2.9/MMBtu
for low sulfur oil, exclusive of Pennsylvania where the price reached $3.77/MMBtu (EIA, 1994).
42 COST OF SNCR
Nalco Fuel Tech (NFT), the major vendor of urea-based SNCR controls for utilities and
industrial boilers, estimates that the cost to retrofit Mercer 320 Unit 2 as a commercial installation
would be approximately $3,400,000, or $10.6/kW (Gibbons, et al., 1994). This estimate is about at
the half point in the range of $5 to $15/kW quoted by several sources (ICAC, 1994; Kaplan, 1993).
A more recently reported cost estimate is at $14/kW for this dual furnace unit (Wallace and
Gibbons, 1995). On an annualized basis, the capital cost translates to a range of about 0.15 to 0.47
mills/kW-hr.
The reagent cost, which represents by far the largest fraction of the O&M cost for SNCR,
was estimated to be about $3,000,000 for the Mercer installation when burning coal and $1,400,000
when burning natural gas (Gibbons, et al., 1994). These O&M costs translate to about 1.8 to 0.83
mills/kW-hr, for coal and gas respectively. Kaplan (1993) estimated that the levelized costs of
SNCR range between 1.7 and 2.4 mills/kW-hr. The bulk of this O&M cost is in the use of the urea
4-14
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reagent, efficiency loss of about 0.5 to 1 percent because of the water injection, and power
consumption for reagent feed. No additional costs will be incurred, if NH3 slip from the SNCR
process can be maintained to a minimum, generally less than 10 ppm, depending on sulfur content
of the fuel. No additional costs have been reported from recent commercial applications of SNCR
on utility boilers. However, some installations have experienced air heater fouling during initial
evaluations (Himes, 1995; Shore, 1993).
Because SNCR has a relatively low capital investment compared to other technologies and
because its operating cost rests primarily with the use of the reagent, its retrofit application becomes
particularly attractive when the boilers have already reduced NOX to the extent possible with
combustion modifications. This is because lower operating costs will be incurred with lower inlet
NOX levels. Also SNCR can be used to trim NOX levels at relatively low cost or to reduce NOX on
a seasonal basis. Low cost per ton of NOX reduced is more likely when NH3 slip can be maintained
at very low levels as in the case when NOX reductions are moderate or when SNCR is used in
tandem with SCR catalyst as in the hybrid retrofit at the Mercer Plant.
Figure 4-5 illustrates the range in cost effectiveness for urea-based SNCR process on a
200-MWe coal-fired utility boiler. Three retrofit scenarios are presented for different types of
boilers, each with a different post-RACT NOX level. All costs within anticipated ranges in NOX
reduction are based on the average capital cost of $ll/kW to $14/kW and a range in O&M cost
of 1.1 to 2.4 mills/kWh for coal units and 0.45 to 0.75 mills/kWh for oil/gas-fired units. These
O&M costs do not include adverse operational impacts from loss of ash sale, forced outages, and
increased maintenance because of excessive NH3 slip. This scenario is most likely because SNCR
performance on any retrofit will be limited by the necessity to avoid operational impacts from NH3
slip. Lower NOX reductions at some site will always be preferred over excessive NH3 slip that occur
when the process is pushed to its technological limits. However, at least one reported experience
with SNCR at a 240 MWe coal-fired cogeneration facility in Virginia has shown an increase of
40 percent in the cost of SNCR operation due to excessive blinding of downstream baghouse. The
4-15
-------
3,000
2,500
o 2,000
-------
SCR catalyst volumes can sometimes be minimized without having to compromise on the NOX
reduction performance. This is often the case for boilers dedicated to natural gas burning, as
experienced in the Southern California experience. However, when the fuel is coal or another high
sulfur and ash content fuel such as residual oil, such cost saving measures are often not possible
resulting in large escalations in both capital and operating costs. Furthermore, the SCR
configuration can be readily adapted to a broad range of NOX reductions in tandem with other
control types.
The various types of SCR configurations make it difficult to report a "representative" retrofit
cost for this technology. In fact, much of the wide range in reported costs for SCR can be
attributed to dissimilar installations, boiler fuels, inlet NOX levels, NOX reduction performance, and
other retrofit factors (Cichanowicz, et al., 1993). Certainly, the retrofit of smaller quantities of
catalyst in existing ductwork of gas-fired boiler is a much different application than one with larger
quantities of catalyst needed in full-scale reactors for coal-fired boilers. Therefore, when developing
cost estimates it is important to treat these types of SCR configurations separately as much as
possible to reflect the broad differences in both installation and operating costs that can occur from
one retrofit site to another. This suggests that the retrofit SCR experience in capital cost reported
in Southern California is not applicable to the NESCAUM and MARAMA, with the exception of
boilers that exclusively fire natural gas.
The following subsections present estimates of the cost and cost-effectiveness for the three
major SCR configuration in use today: (1) in-duct SCR considered practicable at this stage mainly
on in boilers with fuels such as natural gas; (2) air heater SCR (CAT-AH) also considered
principally a technology with most promise for gas/oil-fired boilers; and (3) full-scale SCR where
the fuel and NOX reduction levels are such that larger catalyst volumes, installed in separate
structure reactors, are needed to meet design specifications on space and face velocities, SO2
conversion efficiency, NOX reduction efficiency, and NH3 slip.
4-17
-------
4J.I Cost of In-duct SCR
The bulk of the experience in the use of in-duct SCR system is in Southern California.
Retrofits of small volumes of catalyst, up to 1/6 of the volume often needed for coal plants, in the
existing ductwork of gas-fired utility boilers has proven effective in achieving NOX reductions in
excess of 90 percent from combustion-controlled levels. Because of smaller catalyst quantities and
other factors, these reductions have been achieved at significantly lower costs than projected just
a few years ago by Southern California Edison (SCE) and Los Angeles Department of Water and
Power (LADWP). In fact, recent costs of these installations were quoted by SCE to be in the range
of $25 to $35/kW (ICAC, 1994), far below estimates that often exceeded the $100/kW mark as late
as 1991 (Johnson, 1991). These large reductions in retrofit cost for the Southern California
installations have come about principally because the technology has improved so that a much lower
quantity of catalyst is needed to attain the high NOX reductions targets. Consequently, the
feasibility of inserting the catalyst in the existing ductwork became an option, voiding the much
costlier modifications, such as moving and replacing fans and stacks, that were originally anticipated.
Projections of catalyst life have also been upgraded. Current estimates put the catalyst replacement
schedule for gas firing at a minimum of 6 years for upgrade and a total of 12 years of complete
replacement. Although experience is still too limited to validate these claims, catalysts have
performed satisfactorily.
Figure 4-6 illustrates the estimated range in cost effectiveness for in-duct SCR systems on
gas- and light oil-fired boilers as a function of NOX reduction. These estimates are based on a
capital cost of $25 to $30/kW, average range for the California installations and an average first
year O&M cost of 0.87 to 1.1 mills/kWh, comprised of about 10 percent catalyst replacement,
20 percent NH4OH reagent use, and 70 percent other fixed and variable costs. The total busbar
cost of 1.4 to 1.8 mills/kWh translates to a cost effectiveness range of about $1,200 to $1,700 /ton
for a NOX reduction in the range of 0.20 to 0.35 Ib/MMBtu. The range in NOX reduction has an
upper limit of 0.35 Ib/MMBtu because in-duct SCR is likely to find applications only on dedicated
4-18
-------
5,000
4,000
-•3,000 -
-------
in-duct SCR for coal plants may prove to be a viable option for boilers with low ash and sulfur
loadings in the flue gas. As is the case for the Mercer Station, these retrofits of enlarged in-duct
SCR on low ash and sulfur units can be an option especially for retrofits with difficult access and
lack of space to install a self-supported reactor. Retrofit cost estimates for the full retrofit of
in-duct SCR followed by one layer of CAT-SCR baskets on two 321 MWe at the Mercer Station
were in the $90 to $95/kWe. For a conservative 1-year catalyst life and NOX reductions in the 85
to 90 percent range, PSE&G estimates the overall cost effectiveness in the range of $1,400 to
1,700/ton (Wallace and Gibbons, 1995). For 3-year catalyst life, the cost effectiveness would
improve to a range between $1,200 and $l,400/ton (Huhmann, 1995).
432 Cost of CAT-AH
There are presently no installations of CAT-AH as a stand-alone flue gas treatment control.
Therefore, any cost representation is considered speculative and, to some extent, academic because
the technology is not likely to be considered in applications other than hybrid systems. However,
Pacific Gas & Electric (PG&E) Company conducted an evaluation in the potential use and cost of
the CAT-AH technology on several utility boilers burning primarily natural gas. The evaluation was
undertaken to determine the potential savings associated with the use of in-duct SCR. Table 4-4
lists the various cost elements determined by PG&E for hypothetical installations on five utility
boilers in size range from 210 to 750 MWe. The budgetary costs include 10 and 25 percent process
and total project contingencies with catalyst replacement every six years. The data illustrate that
the catalyst replacement accounts for about two thirds of the total annualized cost. Capital
annualization contributes another 30 percent. O&M, including NH3 reagent use, is minimal
compared to these costs.
Figure 4-7 illustrates these data as a function of the boiler size. The data suggests that for
a 200 MWe gas-fired boiler in NESCAUM or MARAMA, the capital cost would be on the order
of $25/kW with a total annual cost of about 3 mills/kWh. Figure 4-8 illustrates the calculated cost
effectiveness of this technology. The cost effectiveness is shown over a range in NOX reductions
4-20
-------
Table 4-4. Levelized CAT-AH operating costs
Plant Output, MW
Estimated Capacity Factor
Total Capital Requirement
NOX with gas fuel before CAT-AH, ppm
NOX with oil fuel before CAT-AH, ppm
Percent reduction with gas firing
Percent reduction with oil firing
20-Year Levelized Revenue Requirement:
Capital Carrying Costs, $/kW-yr
Replacement Catalyst Elements, $/kW-yr
Fixed O&M Costs, $/kW-yr
Power Costs, $/kW-yr
NH3 Costs, $/kW-yr
Total, $/k\V-yr
Total, mills/kWh
Pittsburgh
Unit 6
329
45%
18.7
140
255
41
18
2.71
6.04
0.24
0.08
0.15
9.22
2.34
Morro Bay
Unit 3
345
45%
16.3
115
253
32
16
2.36
4.84
0.23
0.09
0.11
7.63
1.94
Potrero
Unit3
210
50%
25
132
229
47
25
3.63
7.54
0.36
0.13
0.17
11.83
2.7
Moss Landing
Unit6
750
65%
11.7
154
179
20
7
1.70
3.75
0.14
0.11
0.11
5.81
1.02
Notes:
1. 20-year levelized capital carrying charge (0.145) based on 10.5% discount rate, 5% inflation.
30-year book Me and 15 yr tax recovery preference. See EPRI TAG.
2. Levelized factor (1.484) based on 10.5% discount and 5% inflation.
3. NH3 cost at $100/ton of solution.
4. Power costs at $0.0516/kWh.
5. Fixed O&M cost include cost of new air preheater elements.
Source, Holliday, et al., 1993.
4-21
-------
200
Source Holllday. el al. 1993
300 400 500
Bo Her size
Figure 4-7. Capital and annualized costs for catalytic air heater on gas/oil-fired boilers
7,000
6,000
f 5,000
in
4,000
1
LLJ
u>
O 3,000
2,000
1,000
D\
D
Boiler size = 200 MW
Capital cost = $25/kW
Total busbar = 1.6 - 2.0 mills/kWh
- Catalyst replacement = 65%
- Annualized capital = 30%
Source: Holliday, et al, 1993
D
I
0.05 0.1 0.15 0.2 0.25
NOx reduction (Ib/MMBtu)
0.3
Figure 4-8. Cost effectiveness of CAT-AH on gas-fired utility boilers
4-22
0.35
-------
from 0.10 to 0.30 Ib/MMBtu, which is representative of gas-fired boilers and 40 percent average
NOX reduction capability for oil firing. The data shows that CAT-AH cost effectiveness will likely
be in the range of $2,000 to $6,000/ton for NOX reductions in the range of 0.05 to 0.2 Ib/MMBtu.
The catalytic air heater used in the hybrid control system at Mercer does not imply that this
technology can be implemented or stand-alone control for coal plants. Although the catalytic
surface in the air heater enhances the performance of the in-duct SCR by permitting higher
NH3/NO molar ratios, by itself the technology would not be able to reach SCR performance.
Therefore, no cost analysis is warranted at this stage for either coal- or high-sulfur oil-fired plants.
433 Cost of Full-scale SCR
The installation of full-scale SCR reactors is most likely when large (greater than 60 percent)
NOX reductions are targeted with less than 5 ppm NH3 slip on boilers burning either coal or high
sulfur oil. This is because catalyst volumes larger than those possible for in-duct of air heater
configurations are necessary to compensate for the higher inlet NOX levels and counter the
deleterious effects of high ash loadings and SO2 concentrations entering the catalyst. Full-scale
reactors are also selected to permit the gradual addition of catalyst volume for improved catalyst
life and to increase the NOX reduction performance as regulations require it.
The costs presented here reflect two types of retrofit installations, one that is targeted for
60 to 70 percent reduction and one that targets more than 80 percent reduction. This is an
important distinction because the volume of the catalyst needed is sufficiently different to have
important effects on the degree of plant modifications needed and the required equipment
upgrades. Figure 4-9 illustrates the relationship of catalyst space velocity with percent NOX
reduction. The curve was developed using the algorithm presented for a Foster Wheeler
Corporations SCR installation on a new coal-boiler at the Keystone Cogeneration Facility (Cho and
Snapp, 1993). The calculations assume a near stoichiometric NH3/NO molar ratio to account for
the need to maintain NH3 slip in check even with larger catalyst volumes. The curve illustrates, for
example, that an increase in catalyst volume of about 50 percent would be required when the target
4-23
-------
5,000
SV = -K/ln(1-n/m) [ Cho and Snapp, 1993)
NH3/NO molar ratio (m) Control efficiency (%)
3,000
60 70 80
NOx Reduction (percent)
90
100
Figure 4-9. Decrease in catalyst space velocity with increasing demand on
NOX reduction efficiency
NOX reduction is 80 percent rather than 50 percent. Considering that the cost of the catalyst and
the reactor are nearly 60 percent of the total purchased equipment cost and 40 percent of the total
process capital cost according to ICAC cost estimates (ICAC, 1994), the NOX reduction
performance is an important design criteria affecting the final cost of the retrofit. One must also
consider that with increasing catalyst volumes there is also an increase in pressure drop that can
have costly consequences on fan power requirements and maintenance as well as increased
likelihood of major equipment modification to "fit-in" the reactor and all auxiliaries.
Tables 4-5 and 4-6 summarized actual costs and cost estimates for SCR installations on new
and retrofit coal-fired boilers in the United States. Although not directly applicable to the study
of retrofit cost estimates, the data for new plants are included for reference to illustrate the possible
difference between a retrofit and a greenfield application of the technology.
4-24
-------
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-------
The new coal-fired installations are the three U.S. Generating Plants at Chambers, Keystone,
and Indiantown and the Stanton Plant in Florida, estimated to be operational sometime in 1996.
As indicated, the cost of SCR for these new plants is difficult to differentiate from the total cost
of the plant. This is because there are many equipment upgrades, such as fan horsepower, control,
ductwork, that are attributable to the placement of SCR, but are normally not separated out for the
purpose of defining the actual cost of the NOX control system. Estimates for these new plants put
the installed cost of SCR in the range of $50 to $60/kW. Other costing estimates, prepared by the
Electric Power Research Institute, DOE, and U.S. EPA, for hypothetical plants range between $60
and $97/kW. The estimates for these hypothetical plants are somewhat higher than the costs for
the actual units, in part because of greater inlet NOX concentrations, greater NOX reduction
efficiencies, and larger catalysts.
The experience with SCR retrofits on coal plants is also small. In fact, only two data points
are available, and of these, only one involves a full-scale reactor. The Merrimack plant is also not
entirely representative of the SCR retrofit costs for dry bottom plants because of the it represents
a low dust application and reduced NOX reduction performance. The reduced NOX reduction of
65 percent is translated into a smaller catalyst as suggested by the space velocity of 6,000 1/hr.
therefore, the capital cost of $65/kW for Merrimack is considered at the low end of the "average
cost of retrofitting a dry bottom boiler with requirements for 80 percent reduction. Engineering
estimates prepared by EPRI, ICAC, and DOE put the retrofit cost of SCR between $65 to $125/kW
for catalyst space velocities in the range of 2,500 to 4,000 1/hr and NOX reduction efficiencies in the
range of 75 to 80 percent.
Table 4-7 lists estimates developed in this study for retrofit of SCR on a 200 MWe coal
plant. These estimates are developed based on U.S. DOE updated IAPCS4 code2 with costs
escalated to reflect estimates for a 200 MWe boiler rather than a 500 MWe unit, using the
2 U.S. DOE document titled "Evaluation of NOX Removal Technologies - Volume 1 - Selective
Catalytic Reduction — Revision 2," September 1994.
4-27
-------
Table 4-7. Estimates for SCR total capital requirement for 200 MWe coal boiler
Capital Cost Item
Ducting
Fan Upgrade/Replace
Structural
Ammonia Storage & Distribution
Reactor/Catalyst
Controls
Air Heater
Purchased Equipment Cost
Direct Installation
Total Process Capital
Indirect Costs & Contingencies
Total Plant Cost
AFUDC
Total Capital Requirement
Total Capital Requirement
($/k\V)
11
1.6
2.7
2.4
17.3
incl.
2.4
37
19
56
22
78
0
78
11
1.6
2.7
2.4
21
incl.
2.4
41
20
62
25
87
0
87
expression: $ for 200 MWe = $ for 500 MWe * (200/500)0-6. The table shows estimates for two
SCR installation types differing only in NOX reduction efficiency target.
For a 65 percent SCR reduction system with a catalyst space velocity of 4,000 hr"1, the total
capital requirement is approximately $78/kW. This estimate includes 40 percent for indirect costs
and contingencies but does not include any funds for downtime during construction. An 80 percent
reduction system would have larger catalyst volume and therefore higher initial cost, here estimated
to reach $87/kW. Aside from the catalyst cost, the cost of other retrofit equipment will likely not
vary because installations with smaller catalyst volumes will have design provisions that allow
catalyst addition for more cost effective catalyst management and future demand for higher NOX
reduction efficiencies.
Figure 4-10 illustrates the calculated cost effectiveness of SCR retrofitted on a 200 MWe
coal-fired boiler according to percent NOX reduction. For SCR installations on dry bottom coal-
fired boilers, the anticipated NOX reduction is on the order of 0.25 to 0.6 Ib/MMBtu from RACT-
4-28
-------
3,000
2,500
o 2,000
1,500
o 1,000
500
Dry Bottom
LNB-Cqntrolled
Boilers
Capital Cost = $87/kW
Catalyst life = 8 yrs
Capital Cost = $78/kW
Catalyst Life = 8 yrs
Uncontrolled Wet-Bottom and Cyclone Boilers
J_
0 0.2
Interest on capital = 7 percent
60 percent boiler capacity factor
No allowable funds during contruction
0.4 0.6 0.8 1
NOx Reduction (Ib/MMBtu)
1.2
1.4
1.6
Figure 4-10. Cost effectiveness of full-scale SCR reactors retrofitted
on 200 MWe coal-fired boiler
controlled levels and the corresponding SCR cost effectiveness is anticipated to range between
$1,200 and $2,300/ton. When SCR is applied to uncontrolled cyclone and slagging furnaces, the cost
effectiveness is anticipated to range between $600 and $l,200/ton with NOX reductions reaching
0.90 Ib/MMBtu as in the case of the planned SCR retrofit at the Merrimack Station.
4.4 COST OF HYBRID CONTROLS
Hybrid controls can be cost effective alternatives to full-scale SCR control systems. For
example, the combination of gas reburning and SNCR can achieve NOX reduction levels that would
only be possible with full-scale SCR systems. Also, the combination of SNCR and in-duct and/or
air heater catalysts can be designed to achieve NOX reductions higher than those possible with
SNCR alone at lower cost especially for retrofit cases where SCR access is difficult. Estimates of
the cost of advanced gas reburn (AGR) were developed by EERC (Evans, et al., 1993). The cost
for AGR retrofit on a 500 MWe coal-fired boiler was estimated to be $35/kW, including 36 percent
contingency. The corresponding cost effectiveness was calculated to be about $250/ton with SO2
4-29
-------
credit of $300/ton. Estimates developed in this study, put the total capital requirement for gas
reburning at $25 for an average retrofit and for SNCR at $11 for a 200 MWe boiler. Additionally,
$10/kW was added to account for access to a natural gas pipeline to represent the upper range of
the overall retrofit cost. Consequently, the combined cost of these technologies will likely result in
a retrofit cost in the range of $36 to $46/kW. These costs are somewhat speculative because, as
of this writing, there is no commercial or demonstrated experience of AGR on a full-scale utility
boiler.
Figure 4-11 illustrates the range in established cost effectiveness of AGR as a function of
NOX reduction. The O&M cost is based on 10 percent natural gas heat input coupled with
ammonia reagent rate with an NSR of 1.4. Because the NOX reduction associated with AGR is in
the range of 0.30 to 0.60 Ib/MMBtu, the cost effectiveness of this technology is estimated to fall in
2,400
2,200
2,000
ji 1,800
§ 1,600
c
B 1,400
£
I 1,200
o
1,000
800
600
Capital cost = $36/kW
Capital Cost = $46/kW
A
_L
_L
_L
0.1
0.2
Advanced reburn
10 percent gas use
Interest on capital = 7 percent
0.3 0.4 0.5 0.6
NOx Reduction (Ib/MMBtu)
0.7
0.8 0.9
Figure 4-11. Cost effectiveness of AGR (Advanced Gas Reburn) retrofitted in
200 MWe coal-fired boiler
4-30
-------
the range of $900/ton to $l,600/ton. This cost effectiveness is based on a $1.50/MMBtu differential
fuel price between gas and coal. If the price disadvantage for gas is reduced to $0.70/MMBtu, for
example, the cost effectiveness of AGR improver to the $800 to $l,300/ton range for a favorable
capital cost of $36/kW.
Estimates provided by NFT for their proprietary SNCR+SCR combined process (known as
NOxOUT CASCADE™) are for a capital investment of $22/kW with a busbar cost of
1.8 mills/kWh and a corresponding cost effectiveness of $l,900/ton (NFT, undated). These
SNCR+SCR hybrid controls are currently commercially available only for gas-fired installations,
although some tests are underway to evaluate its feasibility on coal units. Reported retrofit costs
for in-duct SCR alone were reported in the range of $25 to $35/kW (Johnson, 1991). When
coupled with the cost of SNCR which is in the range of $11 to $14/kW, the anticipated capital
requirement is in the range of $36 to $50/kWe for gas-fired boilers. For coal-fired boilers, the
capital cost is likely to be higher because true in-duct SCR systems may not be possible because of
excessive face velocities and flyash loading. For coal-fired retrofits, the capital cost was estimated
to fall in the range of $54 to $62/kW. Higher retrofit costs are possible as indicated by the PSE&G
retrofit of $100/kW for the Mercer 80 MWe equivalent system.
Figure 4-12 illustrates the estimates of the cost effectiveness for SNCR+in-duct SCR hybrid
for a 200 MWe coal-fired boiler. The total busbar cost for each of these hybrid controls is
estimated to be in the range of about 2.5 to 3.5 mills/kWh. For oil/gas-fired boilers, the
combination of SNCR and in-duct SCR will likely result in NOX reductions in the range of 0.25 to
0.40 Ib/MMBtu at a cost of about $1,200 to $l,600/ton.
4.5 COST OF SEASONAL CONTROLS
The application of NOX controls on a seasonal basis will result in cost savings and reduced
annual NOX reductions. Gas-based control technologies such as reburn and gas conversion (i.e.,
switching fuels to 100 percent gas from either coal or oil), in particular, may attain the greatest
economic benefit. Substantial savings in the annual cost of gas-based technologies is likely in some
4-31
-------
3,000
2,500
c
o
2,000
£ 1,500
8
o
1,000
500
Capital cost = $54/kW
Capital Cost = $62/kW
A
0.1
0.2
0.3
Catalyst SV = 6000 eft; Catalyst life = 6 years
Catalyst cost = $370/cft
Interest on capital = 7 percent
0.4 0.5 0.6
NOx Reduction (Ib/MMBtu)
0.7
0.8
0.9
Figure 4-12. Estimate of SNCR + SCR cost effectiveness for retrofit
on a 200 MWe coal-fired boiler
cases because the price of natural gas tends to be lower during the summer, ozone season.
Considering that the fuel differential cost is by far the main cost of natural gas-based technologies,
it stands to reason that any cost savings in fuel during the ozone months will reflect in reduced
annual cost for these technologies and make their application more competitive for post-RACT
NOX reductions.
This section explores the changes in annual cost and cost effectiveness for the various post-
RACT control technologies when controls are applied on a seasonal basis rather than year-around.
The analysis is based on the premise that:
• Ozone season spans 5 months out of the year
• Boiler capacity factor remains unchanged at 60 percent during the ozone season
• The useful life of SCR catalysts remains unchanged as for year-around applications
4-32
-------
• Seasonal cost savings are principally the result of reduced fuel, reagent and energy
associated with the operation of the control
• Maintenance and labor costs remain unchanged, especially for capital intensive controls
such as SCR and hybrids
Except for gas based controls, the cost effectiveness of seasonal controls is expected to be higher
than similar applications operating on a year-around basis. This is because the only savings
associated with seasonal control are for the most part operating costs, whereas the total annualized
cost includes the annualization of capital. Capital intensive controls, such as SCR for coal plants,
for example, may have a dramatic increase in dollars per ton removed when operation is limited
to only a few months of the year.
Table 4-8 lists the annual cost and cost effectiveness calculated for post-RACT controls on
a 200 MWe coal-fired boiler equipped with RACT controls such as LNB. Because slagging
furnaces, including cyclones, are largely uncontrolled, a comparison of annual and seasonal SCR use
on these units was also included. The table shows the average NOX reductions that each control
was credited with in the analysis. For gas reburn, four differential prices between natural gas and
coal were considered ranging from $0.25 to $1.0/MMBtu. Lower price differentials are more likely
during the summer months. Conversely, higher gas prices are more likely for year-around
applications (un-interruptable supply), especially in the case of fuel switching. Two SCR retrofit
scenarios were considered in the analysis. For both cases, SCR capital cost are in the range $78
to $87/kWe. The first scenario is for a dry bottom coal-fired unit. The second scenario is for a
similar retrofit but on an uncontrolled cyclone or slagging unit resulting in a much higher NOX
reduction of 1.1 Ib/MMBtu compared to an average of 0.45 Ib/MMBtu for a dry bottom boiler.
The results indicate that, form an annual cost point of view, the least expensive controls are
NGR and SNCR. Average difficulty retrofits of SCR and hybrid controls have annualized costs in
the range of 3.0 to 4.8 mills/kWh. When viewed on a seasonal basis, the relative ranking of controls
remains much the same. Largest savings are for gas conversion because of gas use is reduced the
4-33
-------
Table 4-8. Comparison of year-around and seasonal costs for post-RACT NOX control
technologies — 200 MWe coal-fired boiler
Control
NGR
SNCR
SCR-Avg
(dry bottom)
SCR-Avg
(wet bottom)
Hybrid
(SNCR + SCR)
Average
Amount of
NOX Reducted
(Ib/MMBtu)
0.25
0.20
0.45
1.10
0.45
Fuel
Differential
Cost
($/MMBtu)
0.25
0.50
0.75
1.00
—
—
—
—
Capital
Cost
($/kWe)
20-35
11-14
78-87
78-87
54-62
Year Around
mills/kWh
0.55-0.85
0.93-1.2
13-1.6
1.7-2.0
0.77-1.3
3.0-3.3
4.5-4.8
2.9-3.2
$/ton
440-850
740-1,200
1,000-1,300
1,300-1,600
850-1,280
1,300-1,500
820-850
1,300-1,400
Seasonal
mills/kWh
0.40-0.77
0.60-0.92
0.70-1.1
0.81-13
0.47-0.66
3.1-3.7
3.7-4.4
2.0-2.3
$/ton
320-620
480-740
1,000-1,300
1,400-1,600
1,100-1,900
3,400-4,400
1,700-1,900
2,200-2,500
Notes: 60 percent capacity factor.
Seasonal = 5 months/yr.
No increase in life of catalyst due to seasonal use.
No reduction in capital cost of SCR due to seasonal use.
Average NOX reduction for the range shown in Chapter 3 rounded to the nearest 0.05 Ib/MMBtu
most with this strategy. In fact, favorable gas prices that result in low fuel differential cost between
coal and gas, would make NGC relatively attractive compared to other controls. As indicated
earlier, the dollars per ton of NOX for seasonal use of these controls is higher than if the controls
were used year around. The least increase in cost effectiveness is recorded for SNCR and gas
reburn.
Figures 4-13 and 4-14 illustrate cost effectiveness of yearly and seasonal controls plotted
against the gas-coal fuel price differential. The two sloped lines represent the best and worst cost
effectiveness for NGR based on the amount of NOX reduced. Gas conversions, not included in the
analysis, would be less competitive than NGR on a year around or seasonal basis. The lowest dollar
per ton of NOX removed, when controls are compared on a year-around basis, is for SNCR except
for NGR when fuel price differential is at a minimum and NOX reductions are high. The cost
effectiveness of SCR and hybrid controls (SNCR + SCR) overlap and are shown to be in the range
4-34
-------
I
I
'o
&
0
0.4 Ib/MMBtu reduction
0.1 Ib/MMBtu reduction
A
PX/4 • SCR (0.25 to 0.60 Ib/MMBtu reductions)
(\^
-------
of about $900 to $2,000/ton. The cost effectiveness band for SNCR is lower, in the range of $850
to $l,300/ton. As indicated, in Figure 1-5, NGR can be most competitive when both the NOX
reduction achieved is highest, estimated in this report to be about 0.40 Ib/MMBtu, and the fuel
price differential is below $0.5/MMBtu. This level of NOX reduction is more representative of
NGR control performance on uncontrolled coal-fired boilers rather than LNG-controlled units.
When NOX reductions for NGR are minimal, perhaps as low as 0.1 Ib/MMBtu from well controlled
tangential-fired units, NGR promises to be less cost competitive on a year-around application basis.
The conclusions differ somewhat when controls cost effectiveness are viewed on seasonal
use basis. Here, gas-based NGR controls can be less costly or equally competitive with most gas
treatment ammonia-based controls up to a fuel price differential of $0.50/MMBtu and the amount
of NOX reduction achieved is 0.25 Ib/MMBtu. If the NOX resolution is large, e.g., approaching
0.4 Ib/MMBtu, NGR on a seasonal basis is the most cost-effective approach as long as fuel-price
differentials are lower than about $1.0/MMBtu. For seasonal use of controls, cost effectiveness
generally rises because the capital cost is amortized over fewer kW-hr. For example, the cost
effectiveness of SNCR worsens from about $850 to $l,300/ton on a yearly basis to about $1,000 to
$l,900/ton on a seasonal basis depending on the level of NOX achieved. SCR, with the most
intensive capital investment has the largest increase in dollars spent per ton of NOX reduced when
going from a yearly use to a seasonal use. These results assume that the catalyst life does not
improve with seasonal use of SCR control, a probability of the catalyst cannot be bypassed or
removed from the gas stream.
4.6 SUMMARY
Table 4-9 summarizes the capital and operating costs and cost effectiveness for control
options available to utilities to further reduce NOX from post-RACT NOX emission levels. These
estimates were developed for a nominal 200 MWe capacity boiler, corresponding to the average unit
size in the entire NESCAUM and MARAMA Regions. The control list includes NGR and full-
scale conversions to gas firing, as well as a variety of ammonia- or urea-based flue gas treatment
4-36
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options using controls alone or in reasonable combinations. The cost effectiveness results are
calculated based on the busbar cost (total annualized cost) and listed NOX reductions from existing
LNB-controlled or combustion controlled levels. Cost algorithms and additional detail can be found
in Appendix C. For SNCR and SCR controls, estimates were also developed for control of cyclone
and wet-bottom boilers, which remain largely uncontrolled. Many site-specific factors will influence
the actual retrofit cost. Therefore, it is possible that some sites will show retrofit costs, either
capital, operating or cost effectiveness that may fall outside these calculated ranges. Further,
because the commercial experience in this country for many of these controls is relatively new, or
nonexistent in some cases, there continues to be considerable doubt as to the actual and long-term
costs for many applications.
The capital cost of gas-based controls is estimated to range between $10 and $35/kW with
NOX reduction levels for post-RACT controlled boilers in the range of 0.10 to 0.50 Ib/MMBtu. The
low end of the NOX reduction can be associated with NGR control effectiveness for LNB-controlled
coal-fired tangential boilers, whose current NOX levels are as low as 0.38 Ib/MMBtu. The high end
of the NOX reduction range can be attributed to currently uncontrolled coal-fired boilers or LNB-
controlled units with a level of 0.75 Ib/MMBtu, reported in the data base. The busbar cost of gas-
based controls is dominated by the fuel price differential. The cost effectiveness of gas controls is
dominated by the fuel price differential and by the amount of NOX reduced. The calculations used
for Table 4-9 are based on $0.50 to $1.0/MMBtu fuel price differential between coal and gas, lower
for oil-fired units. In some locations, natural gas can be more competitive than assumed here,
especially on a seasonal basis. In some areas, the price of gas can be lower than imported oil prices,
especially when sulfur emission limits are required. The range in cost effectiveness for NGR is
calculated to be $460 to $4,200/ton for retrofit on coal-fired units, lower for oil- and gas-fired
boilers. The difference between the low and the high cost effectiveness values is primarily the result
of fuel price differential and amount of NOX reduced.
4-38
-------
SNCR has an estimated capital cost of $11 to $14/kW for a 200 MWe boiler, the lowest of
any of the applicable control options. The range in calculated cost effectiveness for LNB-controlled
coal-fired boilers is $820 to $l,100/ton. The cost per ton of NOX removed improves when applied
on uncontrolled cyclones or wet bottom boilers. However, SNCR is limited in NOX reduction
performance to a range of 0.20 to 0.35 Ib/MMBtu for LNB-controlled coal-fired boilers, based on
the current levels in the NESCAUM and MARAMA inventory. The cost-effectiveness of SNCR
is dominated, for the most part, by the cost of the reagent. The amount of NOX reduced from dry
bottom boilers is estimated to improve to levels as high as 0.6 Ib/MMBtu for SCR, SNCR+SCR
or AGR. SCR and the hybrid combination of SNCR+SCR are the only two control options with
commercial experience. AGR, on the contrary, has yet to be demonstrated on full-scale boilers, so
the estimates remain speculative. The cost per ton of NOX removed from dry bottom coal-fired
boilers already equipped with LNB, ranges between about $1,000 and nearly $3,000/ton, depending
on the level of NOX removed and the capital cost of the installation. When SCR can be applied to
cyclone or wet bottom boilers, which are largely uncontrolled, the cost effectiveness can readily
improve to below the $l,000/ton mark, the result of large NOX reductions from very high
uncontrolled levels. The first commercial examples of this cost effective way of reducing NOX from
these types of boilers are given by the Merrimack and Mercer retrofit experiences of full-scale SCR
and hybrid systems, respectively.
4-39
-------
REFERENCES FOR CHAPTER 4
Braczyk, E. J., et al., "Cost-Effectiveness of NOX Control Retrofit at Salem Harbor Station,"
presented at the Institute of Clean Air Companies (ICAC) Forum '94, Living with Air Toxics &
NOX Emission Controls, Arlington, VA; November 1-2, 1994
Cochran, J., et al., "Selective Catalytic Reduction for a 460 MW Coal Fueled Unit: Overview of a
NOX Reduction System Section," Presented at the Joint Symposium on Stationary Combustion NOX
Control, Miami, FL, May 24-27, 1993
Energy Information Administration (EIA)/Cost and Quality of Fuels for Electric Utility Plants,
1994.
Evans, A., et al., "Development of Advanced NOX Control Concepts for Coal-fired Utility Boilers,"
prepared by Energy and Environmental Research Corporation, for the U.S. DOE, Pittsburgh Energy
Technology Center, September 1993
Gibbons, F. X., et al., "A Demonstration of Urea-Based SNCR NOX Control on A Utility
Pulverized-Coal Wet-Bottom Boiler," presented at the EPRI Workshop NOX Controls for Utility
Boilers, Scottsdale, AZ, May 11-13, 1994
Harding, N.S., et al., "Proceedings: Integrating Natural gas Technologies into Coal and Oil
Designed Boilers," EPRI TR-103469, May 1994
Holliday J. H., et al.," An Assessment of Catalyst Air Heater For NOX Emissions Control on Pacific
Gas and Electric's Gas- and Oil-Fired Steam Generating Units," presented at the Power-Gen
Americas '93, Dallas, TX, November 16-19, 1993
Huhmann, A. L., Presentation to the Stationary Source Review Committee of NESCAUM,
February 10, 1995
ICAC, "Selective Non-Catalytic Reduction (SNCR) for Controlling NOX Emissions," prepared by
SNCR Committee of the Institute of Clean Air Companies, Inc., July 1994
ICAC, "Selective Catalytic Reduction (SCR Controls to Abate NOX Emissions," prepared by the
SCR Committee of the Institute of Clean Air Companies, Inc.," October 1994
Johnson, L., "Nitrogen Oxides Emission Reduction Project," 1991 Joint Symposium on Stationary
Combustion NOX Control, EPA/EPRI, March 25-28, 1991
Kaplan, "NOX Control Costs in the IAPCS Model," Presented at the Joint Symposium on Stationary
Combustion NOX Control, Miami, FL, May 24-27, 1993
4-40
-------
LaFlesh, R. and R. Borio, "ABB C-E Services' Experience with Reburn Technology - Utility
Demonstrations and Future Application," presented at the Joint Power Conference, Kansas City,
MO. October 1993
NFT, "NALCO FUEL TECH Comments to the Ozone Transport Commission," undated
Sanyal, A., et al, "Advanced NOX Control Technologies," presented at the Power-Gen Americas '93,
Dallas, TX, November 17-19, 1993
SFA and EPT, "Gas Cofiring for Coal-Fired Utility Boilers," prepared by SFA Pacific, Inc. and the
Electric Power Technologies, Inc., for the Gas Research Institute and the Electric Power Research
Institute, EPRI TR-101512, November 1992
EPA, "Alternative Control Techniques Document — NOX Emissions from Utility Boilers," EPA-
453/R-94-023, March 1994
U.S. DOE, "Evaluation of NOX Removal Technologies. Volume 1. Selective Catalytic Reduction.
Revision 2," prepared by the U.S. Department of Energy, September 1994
U.S. DOE, "Clean Coal Technology — Reduction of NOX and SO2 Using Gas Reburning, Sorbent
Injection and Integrated Technologies," The U.S Department of Energy, September 1993
Vaszily, J. A., "Electric Utility Access to Natural Gas in the Northeast Ozone Transport Region,"
prepared by Coalition for Gas-Based Solutions, 1994
Wallace, A. J., and F. X. Gibbons, "Demonstration of Post Combustion NOX Control Technology
on a Pulverized Coal, Wet Bottom Utility Boiler at Mercer Generating Station No. 2 Unit, Furnace
#22," presented at the Acid Rain & Electric Utilities: Permits, Allowances, Monitoring &
Meteorology Conference, Tempe, Arizona, January 23-25, 1995.
4-41
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APPENDIX A
OTC MEMORANDUM OF UNDERSTANDING
A-l
-------
MEMORANDUM OF UNDERSTANDING
AMONG THE STATES OF THE OZONE TRANSPORT COMMISSION
ON DEVELOPMENT OF A REGIONAL STRATEGY CONCERNING THE CONTROL OF
STATIONARY SOURCE NITROGEN OXIDE EMISSIONS
WHEREAS, the Stateti of the Oxone Transport Commission (OTC) face a pervasive
problem in their efforts to attain the National Ambient Air Quality Standard (NAAQS) for
oione; and
WHEREAS, a 1991 National Academy of Sciences study on ground-level oione
indicates that a combination of reductions in emissions of volatile organic compounds
(VOCs) and nitrogen oxides (NOx) will be necessary to bring the entire Ozone Transport
Region (OTR) into attainment by the statutory attainment dates; and
WHEREAS, modeling and other studies confirm that NOx emission reductions are
effective in reducing ozone formation and help to reduce oxone transport; and
WHEREAS, the States of the OTC are requiring major stationary sources of NOx to
implement reasonably available control technology (RACT); and
WHEREAS, by Novemlier 15, 1994. the States must submit attainment demonstrations
to EPA as State Implementation Plan (SIP) revisions; and
WHEREAS, the implementation of RACT for the control of NOx emissions will not be
sufficient to enable all States in the OTR to reach attainment; and
WHEREAS, the undersigned States seek to develop an effective regional program to
reduce NOx emissions, which would be implemented in conjunction with other measures
to control ozone precursors (including state-specific measures, regional measures and
Federal measures required under the Clean Air Act); and
WHEREAS, these measures together may enable EPA to approve the States' SIPs and
refrain from imposing sanctions that could restrict economic growth throughout the OTR;
and
WHEREAS, information that the States have collected in their emissions inventories
shows that large boilers find other large indirect heat exchangers are the source of a
substantial portion of the NOx emissions in the States, and will continue to be so after
they implement RACT;
WHEREAS, the States intend to complete a reevaluation of stationary source control*
for 2003 and beyond in 1997, based on results of EPA-approved models and other relevant
technical data;
THEREFORE, the undersigned member States hereby agree to propose regulations
and/or legislation for the control of NOx emission from boilers and other indirect heat
exchangers with a maximum gross heat input rate of at least 250 million BTU per hour;
and
-------
FURTHERMORE, that the States agree to propose regulation* that reflect the difference
in conditiona in (i) the OTR's "Northern Zone1 consisting of the northern portion of the OTR;
(ii) the OTR's Inner Zone* consisting of the central eastern portion of the OTR; and (iii) the
OTR's 'Outer Zone1 consisting of the remainder of the OTR; and
FURTHERMORE, that to establish a credible emissions budget, the States agree to
propose regulations that require enforceable specific reductions in NOx emissions from the
actual 1000 emissions set forth in each State's 1000 inventory submitted to EPA in
compliance with | 182(a) (1) of the Clean Air Act or in a similar emissions inventory
prepared tax each attainment area (provided that for exceptional circumstances that a
more representative base year may be applied to individual sources in a manner
acceptable to EPA) subject to public notice; and
FURTHERMORE, that the States agree to develop a budget in a manner acceptable to
EPA based on the principles above no later than March 1,1005; and
FURTHERMORE, if such a budget is not developed by March 1. 1905, that the 1000
interim inventory used by ZPA in its Regional Oxidant Model simulations for the 1004 OTC
Fall Meeting will be used ibr the budget; and
FURTHERMORE, that the States agree to propose regulations that require subject
sources in the Inner Zone to reduce their rate of NOx emissions by 65 percent from base
year levels by May 1,1999, or to emit NOx at a rate no greater than 0.2 pounds per million
BTU; and
FURTHERMORE, that the States agree to propose regulations that require subject
sources in the Outer Zone to reduce their rate of NOx emissions by 55 percent from base
year levels by May 1,1099, or to emit NOx at a rate no greater than 0.2 pounds per minion
BTU;and
FURTHERMORE, that the States agree to propose regulations that require source* in
the Inner Zone and the Outer Zone to reduce their rate of NOx emissions by 75 percent
from base year levels by May 1, 2003. or to emit NOx at a rate no greater than 0.1S pounds
per million BTU; and
FURTHERMORE, that lixe States agree to propose regulations that require subject
sources in the Northern Zone to reduce their rate of NOx emissions by 55 percent from
base year levels by May 1, 2003. or to emit NOx at a rate no .greater than 0.2 pounds per
million BTU; and
FURTHERMORE, that the States agree to develop a regionwide trading mechanism in
consultation with EPA; and
FURTHERMORE, that in lieu of proposing the regulations described above, a State may
propose regulations that achieve an equivalent reduction in stationary source NOx
emissions in an equitable manner; and
-------
FURTHERMORE, that the regulations for May 1,2003 described above may be modified
if (i) additional modeling and othar scientific analysis shows that the regulations as
modified, together with regulations governing VOC emissions, win achieve attainment of
the ozone NAAQS across the OTR. fn<^ (ii) thfa Memorandum of Understanding is modified
to reflect those modeling results and other analysis no later than December 31,1998; and
FURTHERMORE, that the States agree to propose regulations that are otherwise
consistent with the attached recommendations of the OTC's Stationary/Area Source
Committee; and
FURTHERMORE, that the undersigned States, agree to request that the EPA
Administrator determine whether the SZPs of States outside the OTR contain adequate
provisions to prohibit tha emission of air pollutants in amounts that will contribute
significantly to nonattainment of a National Ambient Air Quality Standard (NAAQS) within
the OTR, as required under 42 U.S.C. Section 110(a)(2)(D).
-------
Figure 1
Northeast Ozone Transport Region
Ozone Nonattainment Areas
Pennsylvania
Virginia
Counties
New York
Maine
New
Hampshire
Connecticut
Massachusetts
Rhode
Island
New Jersey
Delaware
Maryland
s,
Washington, OC
Memttalfuntnt Cla**ific«tlon
-------
Figure 2
Northeast Ozone Transport Region
Zones for Proposed
Regional NOx Stationary Source Strategy
Outer Zone
The Inner Zone includes Marinade County, New Hrapifaire.
Northern Zone
Inner Zone
K*rtlWrtZ<»«-M«infiV«w^«idN«^HiJapihi«(exc^5t
fir itf moderate tod tbove DOoatuinmeBtvcai), and tbe
nortfaetttera attabaeot portion of New Yodc
to
-------
Signed this 27th day of September, 1994 by the following:
DISTRICT OF COLUMBIA:
MAINE:
MARYLAND:
MASSACHUSETTS:
NEW HAMPSHIRE:
NEWJERSEY:^
NEW YORK:
PENNSYLVANIA:
RHODE ISLAND:
VERMONT:
vraa
-------
APPENDIX B
POST-RACT NESCAUM UTILITY BOILER AND NOX INVENTORY
B-l
-------
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^
**
1—
o
UJ
OS
o
UJ
t—
_J
CO
X
l~
o
u
LU
_J
O
LU
Z
8
3
•M
CO
O
LU
OS
O
-------
Source:
Control :
200 MWe Coal -fired utility boiler
RETROFIT OF Full-Scale SNCR - LOW Range of Cap Cost (;
YEARLY USE
Cost Item
CAPITAL:
- Ducting
- Fan Upgrade/Replace
- Structural
- Ammonia Storage & Distribution
- Reactor/Catalyst
- Injectors and Controls
- Air Heater
- In-pi ant piping
- Access to Gas Pipeline
- Burners Modification
- OFA Ducting and Fan
- FGR Ducting and Fan
Total Purchased Equipment
Direct Installation
TOTAL PROCESS CAPITAL
INDIRECT COST AND CONTINGENCIES
TOTAL PLANT COST
ALLOWABLE FUNDS DURING CONSTRUCT
TOTAL CAPITAL REQUIREMENT
FIRST YEAR O&M:
- Labor
- Maintenance
- Ammonia/Urea (reagent)
- Fuel differential cost
- Catalyst replacement
- Catalyst installation/disposal
- Electricity
- Loss in boiler efficiency
TOTAL FIRST YEAR O&M DEBITS:
- S02 Allowance
- Capacity Recovery
- Other
TOTAL FIRST YEAR O&M CREDITS:
NET FIRST YEAR O&M:
CAPITAL ANNUALIZATION
O&M ANNUALIZATION
0.90
TOTAL ANNUALIZED COST
(CAPITAL + NET O&M)
COST EFFECTIVENESS
- 0.05 LB/MMBtu
- 0.10 LB/MMBtu
- 0.20 LB/MMBtu
- 0.30 LB/MMBtu
- 0.40 LB/MMBtu
- 0.50 LB/MMBtu
- 0.60 LB/MMBtu
- 0.70 LB/MMBtu
- 0.80 LB/MMBtu
- 0.90 LB/MMBtu
- 1.20 LB/MMBtu
- 1.50 LB/MMBtu
1995 dollars
$0
$0
$0
$680,856
$0
$179,236
$0
$0
$0
$0
$0
$0
$860,091
$903,434
$1,763,525
$529,058
$2,292,583
$0
$2,292,583
$/YR
$17,447
$10,820
$164,536
$0
$0
$0
$22,338
$78,840
$293,981
$0
$0
$0
$293,981
0.094
1.00
$/YR
$510,384
$510,384
$674,920
$1,102,713
$1,333,063
$1,662,134
$1,991,205
$2,320,277
$2,649,348
$2,978.419
$3,307,490
$4,294,704
$5,281,918
$/kWe
$0.0
$0.0
$0.0
$3.4
$0.0
$0.9
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$4.3
$4.5
$8.8
$2.6
$11.5
$0.0
$11.5
mills/kWh
0.02
0.01
0.16
0.00
0.00
0.00
0.02
0.08
0.28
0.00
0.00
0.00
0.00
0.28
mi 1 1 s/kWh
0.49
$/TON
$1.942
$1,284
$1,049
$845
$791
$758
$736
$720
$708
$699
$681
$670
Comments & Reference
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
Y ESTIMATED FROM DETAILS OF COSTING FOR ADVANCED REBURNING
N FROM EVANS, ET. AL., SEPTEMBER 993
Y
N COSTS INCLUDE FREIGHT TAXES AND ENGINEERING
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
TOTAL EQUIPMENT SUM
FROM MERCER ESTIMATE OF $1.2M FOR 321 MWe BOILER
SUM OF PURCHASED EQUIPMENT AND DIRECT INSTALLATION
ESTIMATED TO BE 30% OF TOTAL PROCESS CAPITAL
SUM OF TOTAL PROCESS CAPITAL AND INDIRECT COST/CONTINGENCIES
NOT APPLICABLE
TOTAL: COMPARES FAVORABLY W/ MERCER ADJUSTED FOR SIZE $2.559,728
Y FIXED O&M COSTS ESTIMATED FROM EPA, 1994 ACT DOCUMENT
Y USING ALGORITHM 86.000*MW"-0.21 EQUIVALENT TO TOTAL OF
Y $28,267 NO SEVERE MAINTENANCE IMPACT
N NOT APPLICABLE
N 20 PERCENT ADDED AFTER 3 YEARS AND ALL REPLACED IN 8 YEARS
N ESTIMATED $160/SCFT ACCORDING TO EPA ACT DOCUMENT
Y
Y 0.5 PERCENT LOSS IN ECONOMIZER BYPASS
N 15 PERCENT GAS USE REPLACING 2 % SULFUR COAL
N
N LOSS OF FLYASH SALES+DISPOSAL COST (40% OF BASE O&M)
DIMENTIONLESS
UNIT PRICING AND OTHER DATA:
NATURAL GAS USE (%TOTAL) : 15
CATALYST LYFE (YRS): 8
FLUE GAS FLOW (SCFH): 25000000
- COAL SULFUR (%): 2
REAGENT / NO (MOLAL RATIO): 1.5 NSR
Y SCR CATALYST ($/CFT): $370
Y AMMONIA (REAGENT) ($/TON): $300 29% AQUEOUS SOLUTION
Y NATURAL GAS ($/MMBtu): $2.50
Y COAL ($/MMBtu): $1.50
Y OIL ($/MMBtu): $2.00
Y PLANT HEAT RATE (Btu/kWH): 10000
Y PLANT REMAINING LIFE (YRS): 20
Y PLANT CAPACITY FACTOR (%) : 60
Y INTEREST RATE (%) : 7
Y CATALYST SPACE VEL. (1/HR): 3250 FOR 85% NOx REDUCTION
Y UREA (REAGENT) ($/TON): 200 FOR 50% UREA BY VOLUME
Y
-------
Source: 200 MWe Coal -fired utility boiler
Control: RETROFIT OF Full -Scale SNCR - HIGH Range of Cap Cost
YEARLY USE
Cost Item 1995 dollars $/kWe Comments & Reference
CAPITAL:
- Ducting
- Fan Upgrade/Replace
- Structural
- Ammonia Storage & Distribution
- Reactor/Catalyst
- Injectors and Controls
- Air Heater
- In-plant piping
- Access to Gas Pipeline
- Burners Modification
- OFA Ducting and Fan
- FGR Ducting and Fan
Total Purchased Equipment
Direct Installation
TOTAL PROCESS CAPITAL
INDIRECT COST AND CONTINGENCIES
TOTAL PLANT COST
ALLOWABLE FUNDS DURING CONSTRUCT
TOTAL CAPITAL REQUIREMENT
FIRST YEAR O&M:
- Labor
- Maintenance
- Ammonia/Urea (reagent)
- Fuel differential cost
- Catalyst replacement
- Catalyst installation/disposal
- Electricity
- Loss in boiler efficiency
TOTAL FIRST YEAR O&M DEBITS:
- S02 Allowance
- Capacity Recovery
- Other
TOTAL FIRST YEAR O&M CREDITS:
NET FIRST YEAR O&M:
CAPITAL ANNUALIZATION
O&M ANNUALIZATION
0.94
TOTAL ANNUALIZED COST
(CAPITAL + NET O&M)
COST EFFECTIVENESS
- 0.05 LB/MMBtu
- 0.10 LB/MMBtu
- 0.20 LB/MMBtu
- 0.30 LB/MMBtu
- 0.40 LB/MMBtu
- 0.50 LB/MMBtu
- O.BO LB/MMBtu
- 0.70 LB/MMBtu
- 0.80 LB/MMBtu
- 0.90 LB/MMBtu
- 1.20 LB/MMBtu
- 1.50 LB/MMBtu
$0
$0
$0
$680,856
$0
$588,044
$0
$0
$0
$0
$0
$0
$1,268,900
$903,434
$2,172,334
$651,700
$2,824,034
$0
$2,824,034
$/YR
$14,939
$13,328
$164,536
$0
$0
$0
$22,338
$78,840
$293,981
$0
$0
$0
$293,981
0.094
1.00
$/YR
$560,550
$560.550
$725,085
$1,152.878
$1,383,228
$1,712,299
$2.041.370
$2,370.442
$2.699,513
$3,028,584
$3,357,656
$4,344,870
$5,332,084
$0.0
$0.0
$0.0
$3.4
$0.0
$2.9
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$6.3
$4.5
$10.9
$3.3
$14.1
$0.0
$14.1
mi 1 1 s/kWh
0.01
0.01
0.16
0.00
0.00
0.00
0.02
0.08
0.28
0.00
0.00
0.00
0.00
0.28
mills/kWh
0.53
$/TON
$2.133
$1.380
$1.097
$877
$814
$777
$752
$734
$720
$710
$689
$676
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
Y ESTIMATED FROM DETAILS OF COSTING FOR ADVANCED REBURNING
N FROM EVANS, ET. AL., SEPTEMBER 993
Y
N COSTS INCLUDE FREIGHT TAXES AND ENGINEERING
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
TOTAL EQUIPMENT SUM
FROM MERCER ESTIMATE OF $1.2M FOR 321 MWe BOILER
SUM OF PURCHASED EQUIPMENT AND DIRECT INSTALLATION
ESTIMATED TO BE 30% OF TOTAL PROCESS CAPITAL
SUM OF TOTAL PROCESS CAPITAL AND INDIRECT COST/CONTINGENCIES
NOT APPLICABLE
TOTAL: COMPARES FAVORABLY W/ MERCER ADJUSTED FOR SIZE $2,559,728
Y FIXED O&M COSTS ESTIMATED FROM EPA, 1994 ACT DOCUMENT
Y USING ALGORITHM 86,000*MW"-0.21 EQUIVALENT TO TOTAL OF
Y $28.267 NO SEVERE MAINTENANCE IMPACT
N NOT APPLICABLE
N 20 PERCENT ADDED AFTER 3 YEARS AND ALL REPLACED IN 8 YEARS
N ESTIMATED $160/SCFT ACCORDING TO EPA ACT DOCUMENT
Y
Y 0.5 PERCENT LOSS IN ECONOMIZER BYPASS
N 15 PERCENT GAS USE REPLACING 2 % SULFUR COAL
N
N LOSS OF FLYASH SALES+DISPOSAL COST (40% OF BASE O&M)
DIMENTIONLESS
UNIT PRICING AND OTHER DATA:
NATURAL GAS USE (%TOTAL): 15
CATALYST LYFE (YRS): 8
FLUE GAS FLOW (SCFH): 25000000
-- COAL SULFUR (%) : 2
REAGENT / NO (MOLAL RATIO): 1.5 NSR
Y SCR CATALYST ($/CFT): $370
Y AMMONIA (REAGENT) ($/TON): $300 29% AQUEOUS SOLUTION
Y NATURAL GAS ($/MMBtu): $2.50
Y COAL ($/MMBtu): $1.50
Y OIL ($/MMBtu): $2.00
Y PLANT HEAT RATE (Btu/kWH): 10000
Y PLANT REMAINING LIFE (YRS): 20
Y PLANT CAPACITY FACTOR (%): 60
Y INTEREST RATE (%) : 7
Y CATALYST SPACE VEL. (1/HR): 3250 FOR 85% NOx REDUCTION
Y UREA (REAGENT) ($/TON): 200 FOR 50% UREA BY VOLUME
Y
-------
Source:
Control :
200 MWe Coal -fired utility boiler
RETROFIT OF Full -Scale SNCR - Low Range of Cap Cost (Seasonal)
SEASONAL USE (5 MONTHS/YR)
Cost Item
CAPITAL:
- Ducting
- Fan Upgrade/Replace
- Structural
- Ammonia Storage & Distribution
- Reactor/Catalyst
- Injectors and Controls
- Air Heater
- In-plant piping
- Access to Gas Pipeline
- Burners Modification
- OFA Ducting and Fan
- FGR Ducting and Fan
Total Purchased Equipment
Direct Installation
TOTAL PROCESS CAPITAL
INDIRECT COST AND CONTINGENCIES
TOTAL PLANT COST
ALLOWABLE FUNDS DURING CONSTRUCT
TOTAL CAPITAL REQUIREMENT
FIRST YEAR O&M:
- Labor
- Maintenance
- Ammonia/Urea (reagent)
- Fuel differential cost
- Catalyst replacement
- Catalyst installation/disposal
- Electricity
- Loss in boiler efficiency
TOTAL FIRST YEAR O&M DEBITS:
- S02 Allowance
- Capacity Recovery
- Other
TOTAL FIRST YEAR O&M CREDITS:
NET FIRST YEAR O&M:
CAPITAL ANNUALIZATION
O&M ANNUALIZATION
0.49
TOTAL ANNUALIZED COST
(CAPITAL + NET O&M)
COST EFFECTIVENESS
- 0.05 LB/MMBtu
- 0.10 LB/MMBtu
- 0.20 LB/MMBtu
- 0.30 LB/MMBtu
- 0.40 LB/MMBtu
- 0.50 LB/MMBtu
- 0.60 LB/MMBtu
- 0.70 LB/MMBtu
- 0.80 LB/MMBtu
- 0.90 LB/MMBtu
- 1.20 LB/MMBtu
- 1.50 LB/MMBtu
1995 dollars
$0
$0
$0
$680,856
$0
$179,236
$0
$0
$0
$0
$0
$0
$860,091
$903,434
$1,763,525
$529,058
$2,292,583
$0
$2,292,583
$/YR
$17,447
$10,820
$68,557
$0
$0
$0
$9.308
$32,850
$138,981
$0
$0
$0
$138,981
0.094
1.00
$/YR
$355,385
$355,385
$423,941
$602,188
$698,167
$835.280
$972,393
$1,109,506
$1,246.620
$1,383,733
$1,520,846
$1,932,185
$2,343,524
$/kWe
$0.0
$0.0
$0.0
$3.4
$0.0
$0.9
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$4.3
$4.5
$8.8
$2.6
$11.5
$0.0
$11.5
mills/kWh
0.02
0.01
0.07
0.00
0.00
0.00
0.01
0.03
0.13
0.00
0.00
0.00
0.00
0.13
mills/kWh
0.34
$/TON
$3.246
$1.936
$1.375
$1,063
$954
$888
$844
$813
$790
$772
$735
$713
Comments & Reference
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
Y ESTIMATED FROM DETAILS OF COSTING FOR ADVANCED REBURNING
N FROM EVANS, ET. AL.. SEPTEMBER 993
Y
N COSTS INCLUDE FREIGHT TAXES AND ENGINEERING
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
TOTAL EQUIPMENT SUM
FROM MERCER ESTIMATE OF $1.2M FOR 321 MWe BOILER
SUM OF PURCHASED EQUIPMENT AND DIRECT INSTALLATION
ESTIMATED TO BE 30% OF TOTAL PROCESS CAPITAL
SUM OF TOTAL PROCESS CAPITAL AND INDIRECT COST/CONTINGENCIES
NOT APPLICABLE
TOTAL: COMPARES FAVORABLY W/ MERCER ADJUSTED FOR SIZE $2,559,728
Y FIXED O&M COSTS ESTIMATED FROM EPA, 1994 ACT DOCUMENT
Y USING ALGORITHM 86,000*MW~-0.21 EQUIVALENT TO TOTAL OF
Y $28,267 NO SEVERE MAINTENANCE IMPACT
N NOT APPLICABLE
N 20 PERCENT ADDED AFTER 3 YEARS AND ALL REPLACED IN 8 YEARS
N ESTIMATED $160/SCFT ACCORDING TO EPA ACT DOCUMENT
Y
Y 0.5 PERCENT LOSS IN ECONOMIZER BYPASS
N 15 PERCENT GAS USE REPLACING 2 % SULFUR COAL
N
N LOSS OF FLYASH SALES+DISPOSAL COST (40% OF BASE O&M)
DIMENTIONLESS
UNIT PRICING AND OTHER DATA:
NATURAL GAS USE (%TOTAL) : 15
CATALYST LYFE (YRS) : 8
FLUE GAS FLOW (SCFH): 25000000
PfiAl CHI CUD fV\ • *)
— UUAL oULrUK {%) . £.
REAGENT / NO (MOLAL RATIO): 1.5 NSR
s SCR CATALYST ($/CFT): $370
s AMMONIA (REAGENT) ($/TON) : $300 29% AQUEOUS SOLUTION
s NATURAL GAS ($/MMBtu): $2.50
s COAL ($/MMBtu): $1.50
s OIL ($/MMBtu): $2.00
s PLANT HEAT RATE (Btu/kWH): 10000
s PLANT REMAINING LIFE (YRS): 20
s PLANT CAPACITY FACTOR (%) : 60
s INTEREST RATE (%) : 7
s CATALYST SPACE VEL. (1/HR): 3250 FOR 85% NOx REDUCTION
s UREA (REAGENT) ($/TON): 200 FOR 50% UREA BY VOLUME
s
-------
Cost Item
Source: 200 MWe Coal-fired utility boiler
Control: RETROFIT OF Full-Scale SNCR - High Range of Cap Cost
1995 dollars $/kUe Comments & Reference
CAPITAL:
- Ducting
- Fan Upgrade/Replace
- Structural
- Ammonia Storage & Distribution
- Reactor/Catalyst
- Injectors and Controls
- Air Heater
- In-plant piping
- Access to Gas Pipeline
- Burners Modification
- OFA Ducting and Fan
- FGR Ducting and Fan
Total Purchased Equipment
Direct Installation
TOTAL PROCESS CAPITAL
INDIRECT COST AND CONTINGENCIES
TOTAL PLANT COST
ALLOWABLE FUNDS DURING CONSTRUCT
TOTAL CAPITAL REQUIREMENT
FIRST YEAR O&M:
- Labor
- Maintenance
- Ammonia/Urea (reagent)
- Fuel differential cost
- Catalyst replacement
- Catalyst installation/disposal
- Electricity
- Loss in boiler efficiency
TOTAL FIRST YEAR O&M DEBITS:
- S02 Allowance
- Capacity Recovery
- Other
TOTAL FIRST YEAR O&M CREDITS:
NET FIRST YEAR O&M:
CAPITAL ANNUALIZATIQN
O&M ANNUALIZATION
0.53
TOTAL ANNUAL1ZED COST
(CAPITAL + NET O&M)
COST EFFECTIVENESS
- 0.05 LB/MMBtu
- 0.10 LB/MMBtu
- 0.20 LB/MMBtu
- 0.30 LB/MMBtu
- 0.40 LB/MMBtu
- 0.50 LB/MMBtu
- 0.60 LB/MMBtu
- 0.70 LB/MMBtu
- 0.80 LB/MMBtu
- 0.90 LB/MMBtu
- 1.20 LB/MMBtu
- 1.50 LB/MMBtu
$0
$0
$0
$680.856
$0
$589.858
$0
JO
$0
$0
$0
$0
$1.270.713
$903,434
$2.174,147
$652,244
$2,826,391
$0
$2,826,391
$/YR
$14,928
$13,340
$68,557
$0
$0
$0
$9,308
$32,850
$138,981
$0
$0
$0
$138,981
0.094
1.00
$/YR
$405,772
$405,772
$474.329
$652,576
$748.555
$885.668
$1,022,781
$1,159.894
$1,297,007
$1,434.120
$1,571.233
$1,982,572
$2,393,912
$0.0
$0.0
$0.0
$3.4
$0.0
$2.9
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$6.4
$4.5
$10.9
$3.3
$14.1
$0.0
$14.1
mills/kWh
0.01
0.01
0.07
0.00
0.00
0.00
0.01
0.03
0.13
0.00
0.00
0.00
0.00
0.13
mills/kWh
0.39
$/TON
$3,706
$2,166
$1,490
$1,139
$1,011
$934
$883
$846
$819
$797
$754
$729
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
Y ESTIMATED FROM DETAILS OF COSTING FOR ADVANCED REBURNING
N FROM EVANS. ET. AL.. SEPTEMBER 993
Y
N COSTS INCLUDE FREIGHT TAXES AND ENGINEERING
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
N NOT APPLICABLE
TOTAL EQUIPMENT SUM
FROM MERCER ESTIMATE OF $1.2M FOR 321 MWe BOILER
SUM OF PURCHASED EQUIPMENT AND DIRECT INSTALLATION
ESTIMATED TO BE 30% OF TOTAL PROCESS CAPITAL
SUM OF TOTAL PROCESS CAPITAL AND INDIRECT COST/CONTINGENCIES
NOT APPLICABLE
TOTAL: COMPARES FAVORABLY W/ MERCER ADJUSTED FOR SIZE $2,559,728
Y FIXED O&M COSTS ESTIMATED FROM EPA, 1994 ACT DOCUMENT
Y USING ALGORITHM 86,000*MW"-0.21 EQUIVALENT TO TOTAL OF
Y $28.267 NO SEVERE MAINTENANCE IMPACT
N NOT APPLICABLE
N 20 PERCENT ADDED AFTER 3 YEARS AND ALL REPLACED IN 8 YEARS
N ESTIMATED $160/SCFT ACCORDING TO EPA ACT DOCUMENT
Y
Y 0.5 PERCENT LOSS IN ECONOMIZER BYPASS
N 15 PERCENT GAS USE REPLACING 2 % SULFUR COAL
N
N LOSS OF FLYASH SALES+DISPOSAL COST (40% OF BASE O&M)
DIMENTIONLESS
UNIT PRICING AND OTHER DATA:
NATURAL SAS USE (%TOTAL): 15
CATALYST LYFE (YRS): 8
FLUE GAS FLOW (SCFH): 25000000
-- COAL SULFUR (%): 2
REAGENT / NO (MOLAL RATIO): 1.5 NSR
s SCR CATALYST ($/CFT): $370
s AMMONIA ( REAGENT) ($/TON): $300 29% AQUEOUS SOLUTION
s NATURAL GAS ($/MMBtu): $2.50
s COAL ($/MMBtu): $1.50
s OIL ($/MMBtu): $2.00
s PLANT HEAT RATE (Btu/kWH): 10000
s PLANT REMAINING LIFE (YRS): 20
s PLANT CAPACITY FACTOR (%) : 60
s INTEREST RATE (%): 7
s CATALYST SPACE VEL. (1/HR): 3250 FOR 85% NOx REDUCTION
s UREA (REAGENT) ($/TON): 200 FOR 50% UREA BY VOLUME
s
-------
Source: 200 HWe Coal-fired utility boiler
Control: RETROFIT OF Full-Scale SNCR — Oil and Gas Units
Cost Item
CAPITAL:
- Ducting
- Fan Upgrade/Replace
- Structural
- Ammonia Storage & Distribution
- Reactor/Catalyst
- Injectors and Controls
- Air Heater
- In-plant piping
- Access to Gas Pipeline
- Burners Modification
- OFA Ducting and Fan
- FGR Ducting and Fan
Total Purchased Equipment
Direct Installation
TOTAL PROCESS CAPITAL
INDIRECT COST AND CONTINGENCIES
TOTAL PLANT COST
ALLOWABLE FUNDS DURING CONSTRUCT
TOTAL CAPITAL REQUIREMENT
FIRST YEAR O&M:
- Labor
- Maintenance
- Ammonia/Urea (reagent)
- Fuel differential cost
- Catalyst replacement
- Catalyst installation/disposal
- Electricity
- Loss in boiler efficiency
TOTAL FIRST YEAR O&M DEBITS:
- S02 Allowance
- Capacity Recovery
- Other
TOTAL FIRST YEAR O&M CREDITS:
NET FIRST YEAR O&M:
CAPITAL ANNUALIZATION
O&M ANNUALIZATION
TOTAL ANNUALIZED COST
(CAPITAL + NET O&M)
COST EFFECTIVENESS
- 0.05 LB/MMBtu
- 0.10 LB/MMBtu
- 0.20 LB/MMBtu
- 0.30 LB/MMBtu
- 0.40 LB/MMBtu
- 0.50 LB/MMBtu
- 0.60 LB/MMBtu
- 0.70 LB/MMBtu
- 0.80 LB/MMBtu
- 0.90 LB/MMBtu
- 1.20 LB/MMBtu
- 1.50 LB/MMBtu
1995 dollars
$0
$0
$0
$680,856
$0
$179,236
$0
$0
$0
$0
$0
$0
$860.091
$903.434
$1.763,525
$529,058
$2,292,583
$0
$2,292,583
$/YR
$17.447
$10,820
$164,536
$0
$0
$0
$22,338
$78,840
$293,981
$0
$0
$0
$293,981
0.094
1.00
$/YR
$510,384
$510,384
$674,920
$1,003.991
$1,333,063
$1.662.134
$1.991,205
$2,320,277
$2,649,348
$2.978,419
$3.307,490
$4,294,704
$5,281,918
$/kWe
$0.0
$0.0
$0.0
$3.4
$0.0
$0.9
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$4.3
$4.5
$8.8
$2.6
$11.5
$0.0
$11.5
mills/kWh
0.02
0.01
0.16
0.00
0.00
0.00
0.02
0.08
0.28
0.00
0.00
0.00
0.00
0.28
mi 1 1 s/kWh
0.49
$/TON
$1.942
$1.284
$955
$845
$791
$758
$736
$720
$708
$699
$681
$670
N
N
N
Y
N
Y
N
N
N
N
N
N
Y
Y
Y
N
N
N
Y
Y
N
N
N
Comments & Reference
NOT APPLICABLE
NOT APPLICABLE
NOT APPLICABLE
ESTIMATED FROM DETAILS OF COSTING FOR ADVANCED REBURNING
FROM EVANS, ET. AL.. SEPTEMBER 993
COSTS INCLUDE FREIGHT TAXES AND ENGINEERING
NOT APPLICABLE
NOT APPLICABLE
NOT APPLICABLE
NOT APPLICABLE
NOT APPLICABLE
TOTAL EQUIPMENT SUM
FROM MERCER ESTIMATE OF $1.2M FOR 321 MWe BOILER
SUM OF PURCHASED EQUIPMENT AND DIRECT INSTALLATION
ESTIMATED TO BE 30% OF TOTAL PROCESS CAPITAL
SUM OF TOTAL PROCESS CAPITAL AND INDIRECT COST/CONTINGENCIES
NOT APPLICABLE
TOTAL: COMPARES FAVORABLY W/ MERCER ADJUSTED FOR SIZE $2,559,728
FIXED O&M COSTS ESTIMATED FROM EPA, 1994 ACT DOCUMENT
USING ALGORITHM 86,000*MW-0.21 EQUIVALENT TO TOTAL OF
$28.267 NO SEVERE MAINTENANCE IMPACT
NOT APPLICABLE
20 PERCENT ADDED AFTER 3 YEARS AND ALL REPLACED IN 8 YEARS
ESTIMATED $160/SCFT ACCORDING TO EPA ACT DOCUMENT
0.5 PERCENT LOSS IN ECONOMIZER BYPASS
15 PERCENT GAS USE REPLACING 2 % SULFUR COAL
LOSS OF FLYASH SALES+DISPOSAL COST (40% OF BASE O&M)
DIMENTIONLESS
UNIT PRICING AND OTHER DATA:
NATURAL GAS USE (%TOTAL) : 15
CATALYST LYFE (YRS): 8
FLUE GAS FLOW (SCFH): 25000000
Pflfll Clll DID f y\ . 9
UUAL oULrUK {%) . £.
REAGENT / NO (MOLAL RATIO): 1.5 NSR
SCR CATALYST ($/CFT): $370
AMMONIA (REAGENT) ($/TON): $300 29% AQUEOUS SOLUTION
NATURAL GAS ($/MMBtu): $2.50
COAL ($/MMBtu): $1.50
OIL ($/MMBtu): $2.00
PLANT HEAT RATE (Btu/kWH): 10000
PLANT REMAINING LIFE (YRS): 20
PLANT CAPACITY FACTOR (%): 60
INTEREST RATE (%): 7
CATALYST SPACE VEL. (1/HR): 3250 FOR 85% NOx REDUCTION
UREA (REAGENT) ($/TON): 200 FOR 50% UREA BY VOLUME
-------
Source: 200 MWe GAS-fired utility boiler
Control: RETROFIT OF IN-DUCT SCR - LOW CAP. COST
Cost Item
CAPITAL:
- Ducting
- Fan Upgrade/Replace
- Structural
- Ammonia Storage & Distribution
- Reactor/Catalyst
- Injectors and Controls
- Air Heater/Sootbl owing
- In-plant piping
- Access to Gas Pipeline
- Burners Modification
- OFA Ducting and Fan
- FGR Ducting and Fan
Total Purchased Equipment
Direct Installation
TOTAL PROCESS CAPITAL
INDIRECT COST AND CONTINGENCIES
TOTAL PLANT COST
ALLOWABLE FUNDS DURING CONSTRUCT
TOTAL CAPITAL REQUIREMENT
FIRST YEAR O&M:
- Labor
- Maintenance
- Ammonia (reagent)
- Fuel differential cost
- Catalyst replacement
- Catalyst installation/disposal
- Electricity
- Loss in boiler efficiency
TOTAL FIRST YEAR O&M DEBITS:
- S02 Allowance
- Capacity Recovery
- Other
TOTAL FIRST YEAR O&M CREDITS:
NET FIRST YEAR O&M:
CAPITAL ANNUALIZATION
O&M ANNUALIZATION
TOTAL ANNUALIZED COST
(CAPITAL + NET O&M)
COST EFFECTIVENESS
- 0.05 LB/MMBtu
- 0.10 LB/MMBtu
- 0.20 LB/MMBtu
- 0.30 LB/MMBtu
- 0.40 LB/MMBtu
- 0.50 LB/MMBtu
- 0.60 LB/MMBtu
- 0.70 LB/MMBtu
- 0.80 LB/MMBtu
- 0.90 LB/MMBtu
- 1.20 LB/MMBtu
- 1.50 LB/MMBtu
1995 dollars
$600,000
$320,000
$0
$480.000
$937,500
$179,000
$0
$0
$0
$0
$0
$0
$2,516,500
$1,258,250
$3,774,750
$1,509,900
$5,284,650
$0
$5,284,650
$/YR
$175,000
$24,942
$104,490
$0
$55,147
$2,363
$111,690
$78,840
$552.472
$0
$0
$552,472
0.094
1.00
$/YR
$1,051,305
$1,051,305
$1,155.795
$1.364,774
$1.573,753
$1,782.733
$1,991,712
$2.200,691
$2,409,670
$2,618,649
$2,827,628
$3,454,566
$4,081,504
$/kWe
$3.0
$1.6
$0.0
$2.4
$4.7
$0.9
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$12.6
$6.3
$18.9
$7.5
$26.4
$0.0
$26.4
mills/kWh
0.17
0.02
0.10
0.00
0.05
0.00
0.11
0.08
0.53
0.00
$0
0.53
mi 1 1 s/kWh
1.00
$/TON
$4,000
$2,199
$1,298
$998
$848
$758
$698
$655
$623
$598
$548
$518
Y
Y
N
Y
Y
Y
n
N
N
N
N
N
n
Y
Y
Y
N
Y
Y
Y
Y
N
N
N
Comments & Reference
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASEO ON OOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
ESTIMATED MAXIMUM 5 MILES FROM SUITABLE PIPELINE
ESTIMATED MAXIMUM 5 MILES FROM SUITABLE PIPELINE
NOT APPLICABLE
NOT APPLICABLE
NOT APPLICABLE
TOTAL SUM
ESTIMATED TO BE 50% OF EQUIPMENT COST BASED ON ICAC 94 ESTIMATE
SUM OF PURCHASED EQUIPMENT AND DIRECT INSTALLATION
ESTIMATED TO BE 40% OF TOTAL PROCESS CAPITAL
SUM OF TOTAL PROCESS CAPITAL AND INDIRECT COST/CONTINGENCIES
ESTIMATE BASED ON ICAC 94 DATA
TOTAL INITIAL INVESTMENT
TWO MAN YEARS
NOT APPLICABLE
20 PERCENT ADDED AFTER 3 YEARS AND ALL REPLACED IN 8 YEARS
ESTIMATED $15/SCFT ACCORDING TO EPA ACT DOCUMENT
0.5 PERCENT LOSS IN ECONOMIZER BYPASS
15 PERCENT GAS USE REPLACING 2 % SULFUR COAL
DIMENTIONLESS
UNIT PRICING AND OTHER DATA:
NATURAL GAS USE (%TOTAL): 15
CATALYST LYFE (YRS): ' 12
FLUE GAS FLOW (SCFH): 25000000
rnAi cm PID ( y \ * ?
LUAL jULrUK \to) . C
REAGENT 7 NO {MOLAL RATIO): 1.04
SCR CATALYST ($/CFT) : $350
AMMONIA ( REAGENT )($/TON): $300 29% AQUEOUS SOLUTION
NATURAL GAS ($/MMBtu): $2.50
COAL ($/MMBtu): $1.50
OIL ($/MMBtu): $2.00
PLANT HEAT RATE (Btu/kWH) : 10000
PLANT REMAINING LIFE (YRS): 20
PLANT CAPACITY FACTOR (%) : 60
INTEREST RATE (%) : 7
CATALYST SPACE VEL. (1/HR): 14000 FOR 85% NOx REDUCTION
CATALYST VOLUME(CFT): 1786
-------
Source: 200 MWe GAS-fired utility boiler
Control: RETROFIT OF IN-DUCT SCR - HIGH CAP. COST
Cost Item
CAPITAL:
- Ducting
- Fan Upgrade/Replace
- Structural
- Ammonia Storage & Distribution
- Reactor/Catalyst
- Injectors and Controls
- Air Heater/Sootbl owing
- In-plant piping
- Access to Gas Pipeline
- Burners Modification
- OFA Ducting and Fan
- FGR Ducting and Fan
Total Purchased Equipment
Direct Installation
TOTAL PROCESS CAPITAL
INDIRECT COST AND CONTINGENCIES
TOTAL PLANT COST
ALLOWABLE FUNDS DURING CONSTRUCT
TOTAL CAPITAL REQUIREMENT
FIRST YEAR O&M:
- Labor
- Maintenance
- Ammonia (reagent)
- Fuel differential cost
- Catalyst replacement
- Catalyst installation/disposal
- Electricity
- Loss in boiler efficiency
TOTAL FIRST YEAR O&M DEBITS:
- S02 Allowance
- Capacity Recovery
- Other
TOTAL FIRST YEAR O&M CREDITS:
NET FIRST YEAR O&M:
CAPITAL ANNUALIZATION
O&M ANNUALIZATION
TOTAL ANNUALIZED COST
(CAPITAL + NET O&M)
COST EFFECTIVENESS
- 0.05 LB/MMBtu
- 0.10 LB/MMBtu
- 0.20 LB/MMBtu
- 0.30 LB/MMBtu
- 0.40 LB/MMBtu
- 0.50 LB/MMBtu
- 0.60 LB/MMBtu
- 0.70 LB/MMBtu
- 0.80 LB/MMBtu
- 0.90 LB/MMBtu
- 1.20 LB/MMBtu
- 1.50 LB/MMBtu
1995 dollars
$600,000
$320,000
$0
$480,000
$937,500
$179,000
$480.000
$0
$0
$0
$0
$0
$2,996,500
$1,498,250
$4,494,750
$1,797,900
$6,292,650
$0
$6,292,650
$/YR
$175,000
$29,699
$104,490
$0
$55,147
$2,363
$111,690
$78,840
$557,229
$0
$0
$557,229
0.094
1.00
$/YR
$1,151,211
$1,151,211
$1,255,700
$1,464.680
$1.673,659
$1,882,638
$2,091,617
$2,300,596
$2,509,576
$2,718,555
$2,927,534
$3,554,472
$4.181,409
$/kWe
$3.0
$1.6
$0.0
$2.4
$4.7
$0.9
$2.4
$0.0
$0.0
$0.0
$0.0
$0.0
$15.0
$7.5
$22.5
$9.0
$31.5
$0.0
$31.5
mills/kWh
0.17
0.03
0.10
0.00
0.05
0.00
0.11
0.08
0.53
0.00
$0
0.53
mills/kWh
1.10
$/TON
$4,381
$2,389
$1,393
$1,061
$895
$796
$730
$682
$647
$619
$564
$530
Y
Y
N
Y
Y
Y
Y
N
N
N
N
N
n
Y
Y
Y
N
Y
Y
Y
Y
N
N
N
Comments & Reference
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
ESTIMATED MAXIMUM 5 MILES FROM SUITABLE PIPELINE
ESTIMATED MAXIMUM 5 MILES FROM SUITABLE PIPELINE
NOT APPLICABLE
NOT APPLICABLE
NOT APPLICABLE
TOTAL SUM
ESTIMATED TO BE 50% OF EQUIPMENT COST BASED ON ICAC 94 ESTIMATE
SUM OF PURCHASED EQUIPMENT AND DIRECT INSTALLATION
ESTIMATED TO BE 40% OF TOTAL PROCESS CAPITAL
SUM OF TOTAL PROCESS CAPITAL AND INDIRECT COST/CONTINGENCIES
ESTIMATE BASED ON ICAC 94 DATA
TOTAL INITIAL INVESTMENT
TWO MAN YEARS
NOT APPLICABLE
20 PERCENT ADDED AFTER 3 YEARS AND ALL REPLACED IN 8 YEARS
ESTIMATED $15/SCFT ACCORDING TO EPA ACT DOCUMENT
0.5 PERCENT LOSS IN ECONOMIZER BYPASS
15 PERCENT GAS USE REPLACING 2 % SULFUR COAL
DIMENTIONLESS
UNIT PRICING AND OTHER DATA:
NATURAL GAS USE (%TOTAL) : 15
CATALYST LYFE (YRS): 12
FLUE GAS FLOW (SCFH): 25000000
m&i cm n ID /v^ • 9
LUAL oULrUK (/of . £.
REAGENT / NO (MOLAL RATIO): 1.04
SCR CATALYST ($/CFT) : $350
AMMONIA (REAGENT) ($/TON) : $300 29% AQUEOUS SOLUTION
NATURAL GAS ($/MMBtu): $2.50
COAL ($/MMBtu): $1.50
OIL ($/MMBtu): $2.00
PLANT HEAT RATE (Btu/kWH): 10000
PLANT REMAINING LIFE (YRS): 20
PLANT CAPACITY FACTOR (%) : 60
INTEREST RATE (%): 7
CATALYST SPACE VEL. (1/HR): 14000 FOR 85% NOx REDUCTION
CATALYST VOLUME(CFT): 1786
-------
Source: 200 MWe Coal-fired utility boiler
Control: RETROFIT OF Full-Scale SCR - Low Range Cap. Cost
Cost Item
CAPITAL:
- Ducting
- Fan Upgrade/Replace
- Structural
- Ammonia Storage & Distribution
- Reactor/Catalyst
- Injectors and Controls
- Air Heater/Sootbl owing
- In-plant piping
- Access to Gas Pipeline
- Burners Modification
- OFA Ducting and Fan
- FGR Ducting and Fan
Total Purchased Equipment
Direct Installation
TOTAL PROCESS CAPITAL
INDIRECT COST AND CONTINGENCIES
TOTAL PLANT COST
ALLOWABLE FUNDS DURING CONSTRUCT
TOTAL CAPITAL REQUIREMENT
FIRST YEAR O&M:
- Labor
- Maintenance
- Ammonia (reagent)
- Fuel differential cost
- Catalyst replacement
- Catalyst installation/disposal
- Electricity
- Loss in boiler efficiency
TOTAL FIRST YEAR O&M DEBITS:
- S02 Allowance
- Capacity Recovery
- Other
TOTAL FIRST YEAR O&M CREDITS:
NET FIRST YEAR O&M:
CAPITAL ANNUALIZATION
O&M ANNUALIZATION
TOTAL ANNUALIZED COST
(CAPITAL + NET O&M)
COST EFFECTIVENESS
- 0.05 LB/MMBtu
- 0.10 LB/MMBtu
- 0.20 LB/MMBtu
- 0.30 LB/MMBtu
- 0.40 LB/MMBtu
- 0.50 LB/MMBtu
- 0.60 LB/MMBtu
- 0.70 LB/MMBtu
- 0.80 LB/MMBtu
- 0.90 LB/MMBtu
- 1.20 LB/MMBtu
- 1.50 LB/MMBtu
1995 dollars
$2,160,000
$320,000
$540,000
$480.000
$3.458,077
INCL.
$480,000
$0
$0
$0
$0
$0
$7,438,077
$3,719,038
$11,157,115
$4,462,846
$15.619,962
$0
$15,619,962
$/YR
$175.000
$73,721
$110,518
$0
$305,124
$12,370
$111,690
$78,840
$867,263
$0
$0
$867,263
0.094
1.00
$/YR
$2,341,677
$2,341,677
$2,452,195
$2,673,230
$2.894,266
$3,115.302
$3,336,337
$3,557,373
$3,778,409
$3,999,444
$4.220,480
$4.883.587
$5,546,694
$/kWe
$10.8
$1.6
$2.7
$2.4
$17.3
$0.0
$2.4
$0.0
$0.0
$0.0
$0.0
$0.0
$37.2
$18.6
$55.8
$22.3
$78.1
$0.0
$78.1
mills/kWh
0.17
0.07
0.11
0.00
0.29
0.01
0.11
0.08
0.83
0.00
$0
0.83
mi 1 1 s/kWh
2.23
$/TON
$8.910
$4,666
$2,543
$1,836
$1,482
$1,270
$1,128
$1,027
$951
$892
$774
$704
Y
Y
Y
Y
Y
Y
Y
N
N
N
N
N
n
Y
Y
Y
N
Y
Y
Y
Y
N
N
N
Comments & Reference
OATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DAT ABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
ESTIMATED MAXIMUM 5 MILES FROM SUITABLE PIPELINE
ESTIMATED MAXIMUM 5 MILES FROM SUITABLE PIPELINE
NOT APPLICABLE
NOT APPLICABLE
NOT APPLICABLE
TOTAL SUM
ESTIMATED TO BE 50% OF EQUIPMENT COST BASED ON ICAC 94 ESTIMATE
SUM OF PURCHASED EQUIPMENT AND DIRECT INSTALLATION
ESTIMATED TO BE 40% OF TOTAL PROCESS CAPITAL
SUM OF TOTAL PROCESS CAPITAL AND INDIRECT COST/CONTINGENCIES
ESTIMATE BASED ON ICAC 94 DATA
TOTAL INITIAL INVESTMENT
NOT APPLICABLE
20% ADDED AFTER 3 YRS AND ALL REPLACED IN YRS shown below
ESTIMATED $15/SCFT ACCORDING TO EPA ACT DOCUMENT
0.5 PERCENT LOSS IN ECONOMIZER BYPASS
15 PERCENT GAS USE REPLACING 2 % SULFUR COAL
DIMENTIONLESS
UNIT PRICING AND OTHER DATA:
NATURAL GAS USE (%TOTAL) : 15
CATALYST LYFE (YRS): 8
FLUE GAS FLOW (SCFH): 25000000
mil cm FIID tt\ • 7
IjUML jUUrUK \nj . C
REAGENT / NO (MOLAL RATIO): 1.1
SCR CATALYST ($/CFT): $370
AMMONIA (REAGENT) ($/TON): $300 29% AQUEOUS SOLUTION
NATURAL GAS ($/MMBtu): $2.50
COAL ($/MMBtu): $1.50
OIL ($/MMBtu): $2.00
PLANT HEAT RATE (Btu/kWH) : 10000
PLANT REMAINING LIFE (YRS): 20
PLANT CAPACITY FACTOR (%) : 60
INTEREST RATE (%) : 7
CATALYST SPACE VEL. (1/HR): 3250 FOR 85% NOx REDUCTION
CATALYST VOLUME(CFT): 7692
-------
Source: 200 MWe Coal-fired utility boiler
Control: RETROFIT OF Full-Scale SCR - High Range Cap. Cost
Cost Item
CAPITAL:
- Ducting
- Fan Upgrade/Replace
- Structural
- Ammonia Storage & Distribution
- Reactor/Catalyst
- Injectors and Controls
- Air Heater/Sootbl owing
- In-plant piping
- Access to Gas Pipeline
- Burners Modification
- OFA Ducting and Fan
- FGR Ducting and Fan
Total Purchased Equipment
Direct Installation
TOTAL PROCESS CAPITAL
INDIRECT COST AND CONTINGENCIES
TOTAL PLANT COST
ALLOWABLE FUNDS DURING CONSTRUCT
TOTAL CAPITAL REQUIREMENT
FIRST YEAR O&M:
- Labor
- Maintenance
- Ammonia (reagent)
- Fuel differential cost
- Catalyst replacement
- Catalyst installation/disposal
- Electricity
- Loss in boiler efficiency
TOTAL FIRST YEAR O&M DEBITS:
- S02 Allowance
- Capacity Recovery
- Other
TOTAL FIRST YEAR O&M CREDITS:
NET FIRST YEAR O&M:
CAPITAL ANNUALIZATION
Q&M ANNUALIZATION
TOTAL ANNUALIZED COST
(CAPITAL + NET O&M)
COST EFFECTIVENESS
- 0.05 LB/MMBtu
- 0.10 LB/MMBtu
- 0.20 LB/MMBtu
- 0.30 LB/MMBtu
- 0.40 LB/MMBtu
- 0.50 LB/MMBtu
- 0.60 LB/MMBtu
- 0.70 LB/MMBtu
- 0.80 LB/MMBtu
- 0.90 LB/MMBtu
- 1.20 LB/MMBtu
- 1.50 LB/MMBtu
1995 dollars
$2,160,000
$320,000
$540,000
$480,000
$4,269.231
INCL.
$480,000
$0
$0
$0
$0
$0
$8.249.231
$4,124,615
$12,373.846
$4,949,538
$17.323,385
$0
$17,323,385
$/YR
$175,000
$81,760
$110,518
$0
$376,697
$15,271
$111,690
$78,840
$949,776
$0
$0
$949,776
0.094
1.00
$/YR
$2,584,981
$2.584,981
$2,695,499
$2,916,535
$3.137,571
$3.358.606
$3.579,642
$3,800,678
$4.021.713
$4,242.749
$4,463,785
$5.126,892
$5,789,999
$/kWe
$10.8
$1.6
$2.7
$2.4
$21.3
$0.0
$2.4
$0.0
$0.0
$0.0
$0.0
$0.0
$41.2
$20.6
$61.9
$24.7
$86.6
$0.0
$86.6
mills/kWh
0.17
0.08
0.11
0.00
0.36
0.01
0.11
0.08
0.90
0.00
$0
0.90
mills/kWh
2.46
$/TON
$9.836
$5.128
$2,774
$1,990
$1.598
$1.362
$1,205
$1.093
$1,009
$944
$813
$734
Y
Y
Y
Y
Y
Y
Y
N
N
N
N
N
n
Y
Y
Y
N
Y
Y
Y
Y
N
N
N
Comments & Reference
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
ESTIMATED MAXIMUM 5 MILES FROM SUITABLE PIPELINE
ESTIMATED MAXIMUM 5 MILES FROM SUITABLE PIPELINE
NOT APPLICABLE
NOT APPLICABLE
NOT APPLICABLE
TOTAL SUM
ESTIMATED TO BE 50% OF EQUIPMENT COST BASED ON ICAC 94 ESTIMATE
SUM OF PURCHASED EQUIPMENT AND DIRECT INSTALLATION
ESTIMATED TO BE 40% OF TOTAL PROCESS CAPITAL
SUM OF TOTAL PROCESS CAPITAL AND INDIRECT COST/CONTINGENCIES
ESTIMATE BASED ON ICAC 94 DATA
TOTAL INITIAL INVESTMENT
NOT APPLICABLE
20% ADDED AFTER 3 YRS AND ALL REPLACED IN YRS shown below
ESTIMATED $15/SCFT ACCORDING TO EPA ACT DOCUMENT
0.5 PERCENT LOSS IN ECONOMIZER BYPASS
15 PERCENT GAS USE REPLACING 2 % SULFUR COAL
DIMENTIONLESS
UNIT PRICING AND OTHER DATA:
NATURAL GAS USE (%TOTAL) : 15
CATALYST LYFE (YRS): 8
FLUE GAS FLOW (SCFH): 25000000
rn&i QJII FIID /y) • ?
L-UML OULrUtx \nf . C
REAGENT / NO (MOLAL RATIO): 1.1
SCR CATALYST ($/CFT): $370
AMMONIA (REAGENT) ($/TON): $300 29% AQUEOUS SOLUTION
NATURAL GAS ($/MMBtu): $2.50
COAL ($/MMBtu): $1.50
OIL ($/MMBtu): $2.00
PLANT HEAT RATE (Btu/kWH): 10000
PLANT REMAINING LIFE (YRS): 20
PLANT CAPACITY FACTOR (%) : 60
INTEREST RATE (%): 7
CATALYST SPACE VEL. (1/HR): 3250 FOR 85% NOx REDUCTION -
CATALYST VOLUME(CFT): 7692
-------
Source: 200 MWe Coal-fired utility boiler
Control: RETROFIT OF SNCR AND IN-DUCT SCR (HYBRID) - Low range cost
Cost Item
CAPITAL:
- Ducting
- Fan Upgrade/Replace
~ Structural
- Ammonia Storage & Distribution
- Reactor/Catalyst
- Injectors and Controls
- Air Heater
- In-plant piping
- Access to Gas Pipeline
- Burners Modification
- OFA Ducting and Fan
- FGR Ducting and Fan
Total Purchased Equipment
Direct Installation
TOTAL PROCESS CAPITAL
INDIRECT COST AND CONTINGENCIES
TOTAL PLANT COST
ALLOWABLE FUNDS DURING CONSTRUCT
TOTAL CAPITAL REQUIREMENT
FIRST YEAR O&M:
- Labor
- Maintenance
- Ammonia (reagent)
- Fuel differential cost
- Catalyst replacement
- Catalyst installation/disposal
- Electricity
- Loss in boiler efficiency
TOTAL FIRST YEAR O&M DEBITS:
- S02 Allowance
- Capacity Recovery
- Other
TOTAL FIRST YEAR O&M CREDITS:
NET FIRST YEAR O&M:
CAPITAL ANNUALIZATION
O&M ANNUALIZATION
TOTAL ANNUALIZED COST
(CAPITAL + NET O&M)
COST EFFECTIVENESS
- 0.05 LB/MMBtu
- 0.10 LB/MMBtu
- 0.20 LB/MMBtu
- 0.30 LB/MMBtu
- 0.40 LB/MMBtu
- 0.50 LB/MMBtu
- 0.60 LB/MMBtu
- 0.70 LB/MMBtu
- 0.80 LB/MMBtu
- 0.90 LB/MMBtu
- 1.20 LB/MMBtu
- 1.50 LB/MMBtu
1995 dollars
$600,000
$320,000
$540,000
$696,000
$2,312,500
$179,000
$480,000
$0
$0
$0
$0
$0
$5,127,500
$2,563,750
$7,691,250
$3.076,500
$10,767,750
$0
$10,767.750
$/YR
$175,000
$50,820
$140.659
$0
$272,059
$11,029
$111.690
$126.144
$887,401
$0
$0
$887,401
0.094
1.00
$/YR
$1,903,801
$1,903,801
$2,044,460
$2.325.778
$2.607,096
$2.888,414
$3,169,732
$3,451,050
$3,732,369
$4,013.687
$4,295.005
$5,138,959
$5,982,914
$/kWe
$3.0
$1.6
$2.7
$3.5
$11.6
$0.9
$2.4
$0.0
$0.0
$0.0
$0.0
$0.0
$25.6
$12.8
$38.5
$15.4
$53.8
$0.0
$53.8
mills/kWh
0.17
0.05
0.13
0.00
0.26
0.01
0.11
0.12
0.84
0.00
$0
0.84
mi 1 1 s/kWh
1.81
$/TON
$7,244
$3,890
$2,212
$1,653
$1,374
$1,206
$1,094
$1,014
$955
$908
$815
$759
Y
Y
y
Y
Y
Y
Y
N
N
N
N
N
n
Y
Y
Y
N
Y
Y
Y
Y
N
N
N
Comments & Reference
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
ESTIMATED MAXIMUM 5 MILES FROM SUITABLE PIPELINE
ESTIMATED MAXIMUM 5 MILES FROM SUITABLE PIPELINE
NOT APPLICABLE
NOT APPLICABLE
NOT APPLICABLE
TOTAL SUM
ESTIMATED TO BE 50% OF EQUIPMENT COST BASED ON ICAC 94 ESTIMATE
SUM OF PURCHASED EQUIPMENT AND DIRECT INSTALLATION
ESTIMATED TO BE 40% OF TOTAL PROCESS CAPITAL
SUM OF TOTAL PROCESS CAPITAL AND INDIRECT COST/CONTINGENCIES
ESTIMATE BASED ON ICAC 94 DATA
TOTAL INITIAL INVESTMENT
TWO MAN YEARS
NOT APPLICABLE
20 % ADDED AFTER 3 YRS AND ALL REPLACED IN YRS shown below
ESTIMATED $15/SCFT according to ICAC
0.5 PERCENT LOSS IN ECONOMIZER BYPASS
15 PERCENT GAS USE REPLACING 2 % SULFUR COAL
DIMENTIONLESS
UNIT PRICING AND OTHER DATA:
NATURAL GAS USE (%TOTAL) : 15
CATALYST LYFE (YRS): 6
FLUE GAS FLOW (SCFH): 25000000
rnAi cm n ID (°/\ • 9
L\JrtL OuLrUK \n) • C
REAGENT / NO (MOLAL RATIO): 1.4
SCR CATALYST ($/CFT): $370
AMMONIA (REAGENT) ($/TON): $300 29% AQUEOUS SOLUTION
NATURAL GAS ($/MMBtu): $2.50
COAL ($/MMBtu): $1.50
OIL ($/MMBtu): $2.00
PLANT HEAT RATE (Btu/kWH): 10000
PLANT REMAINING LIFE (YRS): 20
PLANT CAPACITY FACTOR (%): 60
INTEREST RATE (%) : 7
CATALYST SPACE VEL. (1/HR): 6000 FOR 85% NOx REDUCTION
CATALYST VOLUME(CFT): 4167
-------
Source: 200 MWe Coal-fired utility boiler
Control: RETROFIT OF SNCR AND IN-DUCT SCR (HYBRID) - High range cost
Cost Item
CAPITAL:
- Ducting
- Fan Upgrade/Replace
- Structural
- Ammonia Storage & Distribution
- Reactor/Catalyst
- Injectors and Controls
- Air Heater
- In-plant piping
- Access to Gas Pipeline
- Burners Modification
- OFA Ducting and Fan
- F6R Ducting and Fan
Total Purchased Equipment
Direct Installation
TOTAL PROCESS CAPITAL
INDIRECT COST AND CONTINGENCIES
TOTAL PLANT COST
ALLOWABLE FUNDS DURING CONSTRUCT
TOTAL CAPITAL REQUIREMENT
FIRST YEAR O&M:
- Labor
- Maintenance
- Ammonia (reagent)
- Fuel differential cost
- Catalyst replacement
- Catalyst installation/disposal
- Electricity
- Loss in boiler efficiency
TOTAL FIRST YEAR O&M DEBITS:
- S02 Allowance
- Capacity Recovery
- Other
TOTAL FIRST YEAR O&M CREDITS:
NET FIRST YEAR O&M:
CAPITAL ANNUALIZATION
O&M ANNUALIZATION
TOTAL ANNUALIZED COST
(CAPITAL + NET O&M)
COST EFFECTIVENESS
- 0.05 LB/MMBtu
- 0.10 LB/MMBtu
- 0.20 LB/MMBtu
- 0.30 LB/MMBtu
- 0.40 LB/MMBtu
- 0.50 LB/MMBtu
- 0.60 LB/MMBtu
- 0.70 LB/MMBtu
- 0.80 LB/MMBtu
- 0.90 LB/MMBtu
- 1.20 LB/MMBtu
- 1.50 LB/MMBtu
1995 dollars
$600,000
$320,000
$540,000
$696,000
$3,083,333
$179,000
$480,000
$0
$0
$0
$0
$0
$5,898,333
$2,949,167
$8,847,500
$3,539,000
$12,386,500
$0
$12,386,500
$/YR
$175,000
$58,460
$140.659
$0
$362,745
$14,706
$111,690
$126,144
$989,404
$0
$0
$989,404
0.094
1.00
$/YR
$2,158.602
$2.158,602
$2,299.261
$2,580,579
$2,861,897
$3,143,215
$3,424.534
$3,705.852
$3,987.170
$4,268,488
$4,549,806
$5.393,761
$6,237,715
$/kWe
$3.0
$1.6
$2.7
$3.5
$15.4
$0.9
$2.4
$0.0
$0.0
$0.0
$0.0
$0.0
$29.5
$14.7
$44.2
$17.7
$61.9
$0.0
$61.9
mills/kWh
0.17
0.06
0.13
0.00
0.35
0.01
0.11
0.12
0.94
0.00
$0
0.94
mi 1 1 s/kWh
2.05
$/TON
$8,214
$4,375
$2,455
$1,815
$1,495
$1,303
$1,175
$1,084
$1.015
$962
$855
$791
Y
Y
y
Y
Y
Y
Y
N
N
N
N
N
n
Y
Y
Y
N
Y
Y
Y
Y
N
N
N
Comments & Reference
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
DATABASED ON DOE ESTIMATE UPGRATED TO 200 MWE BOILER
ESTIMATED MAXIMUM 5 MILES FROM SUITABLE PIPELINE
ESTIMATED MAXIMUM 5 MILES FROM SUITABLE PIPELINE
NOT APPLICABLE
NOT APPLICABLE
NOT APPLICABLE
TOTAL SUM
ESTIMATED TO BE 50% OF EQUIPMENT COST BASED ON ICAC 94 ESTIMATE
SUM OF PURCHASED EQUIPMENT AND DIRECT INSTALLATION
ESTIMATED TO BE 40% OF TOTAL PROCESS CAPITAL
SUM OF TOTAL PROCESS CAPITAL AND INDIRECT COST/CONTINGENCIES
ESTIMATE BASED ON ICAC 94 DATA
TOTAL INITIAL INVESTMENT
TWO MAN YEARS
NOT APPLICABLE
20 % ADDED AFTER 3 YRS AND ALL REPLACED IN YRS shown below
ESTIMATED $15/SCFT according to ICAC
0.5 PERCENT LOSS IN ECONOMIZER BYPASS
15 PERCENT GAS USE REPLACING 2 % SULFUR COAL
DIMENTIONLESS
UNIT PRICING AND OTHER DATA:
NATURAL GAS USE (%TOTAL) : 15
CATALYST LYFE (YRS): 6
FLUE GAS FLOW (SCFH): 25000000
rnAi cm nio i y\ • ?
UUML jULrUK {%) . £.
REAGENT / NO (MOLAL RATIO): 1.4
SCR CATALYST ($/CFT): $370
AMMONIA ( REAGENT )($/TON): $300 29% AQUEOUS SOLUTION
NATURAL GAS ($/MM6tu): $2.50
COAL ($/MMBtu): $1.50
OIL ($/MMBtu): $2.00
PLANT HEAT RATE (Btu/kWH): 10000
PLANT REMAINING LIFE (YRS): 20
PLANT CAPACITY FACTOR (%) : 60
INTEREST RATE (%): 7
CATALYST SPACE VEL. (1/HR): 6000 FOR 85% NOx REDUCTION
CATALYST VOLUME(CFT): 4167
-------
Source: 200 MWe Coal-fired utility boiler
Control: RETROFIT OF ADVANCED GAS REBURN (NGR+SNCR) - Low Cost range
Cost Item
CAPITAL:
- Ducting & insulation
- Fan Upgrade/Replace
- Structural
- Reagent Storage & Distribution
- Reactor/Catalyst
- Injectors and Controls
- Air Heater
- In-plant piping
- Access to Gas Pipeline
- Burners Modification & nozzles
- OFA Ducting and Fan
- FGR Ducting and Fan
Total Purchased Equipment
Direct Installation
TOTAL PROCESS CAPITAL
INDIRECT COST AND CONTINGENCIES
TOTAL PLANT COST
ALLOWABLE FUNDS DURING CONSTRUCT
TOTAL CAPITAL REQUIREMENT
FIRST YEAR O&M:
- Labor
- Maintenance
- Ammonia (reagent)
- Fuel differential cost
- Catalyst replacement
- Catalyst installation/disposal
- Electricity
- Loss in boiler efficiency
TOTAL FIRST YEAR O&M DEBITS:
- S02 Allowance
- Capacity Recovery
- Other
TOTAL FIRST YEAR O&M CREDITS:
NET FIRST YEAR O&M:
CAPITAL ANNUALIZATION
O&M ANNUALIZATION
TOTAL ANNUALIZED COST
(CAPITAL + NET O&M)
COST EFFECTIVENESS
- 0.05 LB/MMBtu
- 0.10 LB/MMBtu
- 0.20 LB/MMBtu
- 0.30 LB/MMBtu
- 0.40 LB/MMBtu
- 0.50 LB/MMBtu
- 0.60 LB/MMBtu
- 0.70 LB/MMBtu
- 0.80 LB/MMBtu
- 0.90 LB/MMBtu
- 1.20 LB/MMBtu
- 1.50 LB/MMBtu
1995 dollars
$577,080
$0
$0
$480.000
JO
$421.202
$0
$106,760
$0
$321,156
$599,815
$345,871
$2.851,883
$2,029,848
$4,881,731
$2,323,437
$7,205.167
$0
$7,205.167
$/YR
$175,000
$34,006
$102,378
$1,051,200
$0
$0
$111,690
$236,520
$1,710,794
($606,462)
$0
($606,462)
$1,104,332
0.094
1.00
$/YR
$1,784,449
$1,784,449
$1.886.827
$2,091,582
$2,296,338
$2,501,093
$2,705,849
$2,910.604
$3,115,359
$3,320,115
$3,524,870
$4,139,137
$4,753,403
$/kWe
$2.9
$0.0
$0.0
$2.4
$0.0
$2.1
$0.0
$0.5
$0.0
$1.6
$3.0
$1.7
$14.3
$10.1
$24.4
$11.6
$36.0
$0.0
$36.0
mills/kWh
0.17
0.03
0.10
1.00
0.00
0.00
0.11
0.23
1.63
-0.58
0.00
($0.6)
1.05
mi 1 1 s/kWh
1.70
$/TON
$6.790
$3.590
$1,990
$1.456
$1,190
$1,030
$923
$847
$790
$745
$656
$603
Y
N
N
Y
N
Y
N
Y
N
Y
Y
Y
N
Y
Y
Y
Y
N
N
Y
Y
Y
N
N
Comments & Reference
ESTIMATES BASED ON EVANS. September 1993
ADJUSTED ACCORDING TO BOILER SIZE
ACCORDING TO (200/500) "0.6
ESTIMATES ACORDING TO EVANS. 9/1993
ESTIMATED MAXIMUM 5 MILES FROM SUITABLE PIPELINE
NOT APPLICABLE
NOT APPLICABLE
NOT APPLICABLE
TOTAL SUM
ESTIMATED TO BE 50% OF EQUIPMENT COST BASED ON ICAC 94 ESTIMATE
SUM OF PURCHASED EQUIPMENT AND DIRECT INSTALLATION
20% OF PROCESS CAP.;
SUM OF TOTAL PROCESS CAPITAL AND INDIRECT COST/CONTINGENCIES
ESTIMATE BASED ON ICAC 94 DATA
TOTAL INITIAL INVESTMENT
ESTIMATED FOR 0.05 LB/MMBTU NOx DROP. ADJUSTED BELOW FOR OTHER
SEE BELOW FOR FUEL UNITS PRICING AND GAS USE
20 PERCENT ADDED AFTER 3 YEARS AND ALL REPLACED IN 8 YEARS
ESTIMATED $160/SCFT ACCORDING TO EPA ACT DOCUMENT
1.5 PERCENT LOSS IN ECONOMIZER BYPASS
15 PERCENT GAS USE REPLACING 2 % SULFUR COAL
WHEN INCLUDED, BASED ON 40 PERCENT INCREASE IN SNCR O&M COST
DIMENTIONLESS
UNIT PRICING AND OTHER DATA:
NATURAL GAS USE (%TOTAL) : 10
CATALYST LYFE (YRS): 6
FLUE GAS FLOW (SCFH): 25000000
rnAi ^ii! FIIP ( y \ • 9
L/UHL OULiUrx \/o) • C
REAGENT / NO (MOLAL RATIO): 1.4
SCR CATALYST ($/CFT): $370
AMMONIA (REAGENT) ($/TON): $300 29% AQUEOUS SOLUTION
NATURAL GAS ($/MMBtu): $2.50
COAL ($/MMBtu): $1.50
OIL ($/MMBtu): $2.00
PLANT HEAT RATE (Btu/kWH): 10000
PLANT REMAINING LIFE (YRS): 20
PLANT CAPACITY FACTOR (%) : 60
INTEREST RATE (%) : 7
CATALYST SPACE VEL. (1/HR): 3250 FOR 85% NOx REDUCTION
UREA COST ($/TON): 200 50% UREA SOLUTION
CATALYST VOLUME(CFT): 7692
-------
Source: 200 MWe Coal-fired utility boiler
Control: RETROFIT OF ADVANCED GAS REBURN (NGR+SNCR) - High Cost range
Cost Item
CAPITAL:
- Ducting & insulation
- Fan Upgrade/Replace
- Structural
- Reagent Storage & Distribution
- Reactor/Catalyst
- Injectors and Controls
- Air Heater
- In-plant piping
- Access to Gas Pipeline
- Burners Modification & nozzles
- OFA Ducting and Fan
- FGR Ducting and Fan
Total Purchased Equipment
Direct Installation
TOTAL PROCESS CAPITAL
INDIRECT COST AND CONTINGENCIES
TOTAL PLANT COST
ALLOWABLE FUNDS DURING CONSTRUCT
TOTAL CAPITAL REQUIREMENT
FIRST YEAR O&M:
- Labor
- Maintenance
- Ammonia (reagent)
- Fuel differential cost
- Catalyst replacement
- Catalyst installation/disposal
- Electricity
- Loss in boiler efficiency
TOTAL FIRST YEAR O&M DEBITS:
- S02 Allowance
- Capacity Recovery
- Other
TOTAL FIRST YEAR O&M CREDITS:
NET FIRST YEAR O&M:
CAPITAL ANNUALIZATION
O&M ANNUALIZATION
TOTAL ANNUALIZED COST
(CAPITAL + NET O&M)
COST EFFECTIVENESS
- 0.05 LB/MMBtu
- 0.10 LB/MMBtu
- 0.20 LB/MMBtu
- 0.30 LB/MMBtu
- 0.40 LB/MMBtu
- 0.50 LB/MMBtu
- 0.60 LB/MMBtu
- 0.70 LB/MMBtu
- 0.80 LB/MMBtu
- 0.90 LB/MMBtu
- 1.20 LB/MMBtu
- 1.50 LB/MMBtu
1995 dollars
$577,080
$0
$0
$680,000
$0
$536,618
$0
$106,760
$1,000,000
$321.156
$599,815
$345,871
$4,167,299
$2,029,848
$6,197,146
$3,020,607
$9,217.754
$0
$9,217,754
$/YR
$175,000
$43,505
$102.378
$1,051,200
$0
$0
$111,690
$236,520
$1,720,292
($606,462)
$0
($606,462)
$1,113,831
0.094
1.00
$/YR
$1,983,922
$1,983,922
$2,086,299
$2,291,055
$2,495,810
$2,700,566
$2,905,321
$3,110,077
$3,314,832
$3,519,588
$3,724,343
$4,338,610
$4,952,876
$/kWe
$2.9
$0.0
$0.0
$3.4
$0.0
$2.7
$0.0
$0.5
$5.0
$1.6
$3.0
$1.7
$20.8
$10.1
$31.0
$15.1
$46.1
$0.0
$46.1
mills/kWh
0.17
0.04
0.10
1.00
0.00
0.00
0.11
0.23
1.64
-0.58
0.00
($0.6)
1.06
mills/kWh
1.89
$/TON
$7.549
$3,969
$2,179
$1,583
$1,285
$1,106
$986
$901
$837
$787
$688
$628
Y
N
N
Y
N
Y
N
Y
N
Y
Y
Y
N
Y
Y
Y
Y
N
N
Y
Y
Y
N
N
Comments & Reference
ESTIMATES BASED ON EVANS. September 1993
ADJUSTED ACCORDING TO BOILER SIZE
ACCORDING TO (200/500)"0.6
ESTIMATES ACORDING TO EVANS, 9/1993
ESTIMATED MAXIMUM 5 MILES FROM SUITABLE PIPELINE
NOT APPLICABLE
NOT APPLICABLE
NOT APPLICABLE
TOTAL SUM
ESTIMATED TO BE 50% OF EQUIPMENT COST BASED ON ICAC 94 ESTIMATE
SUM OF PURCHASED EQUIPMENT AND DIRECT INSTALLATION
20% OF PROCESS CAP.;
SUM OF TOTAL PROCESS CAPITAL AND INDIRECT COST/CONTINGENCIES
ESTIMATE BASED ON ICAC 94 DATA
TOTAL INITIAL INVESTMENT
ESTIMATED FOR 0.05 LB/MMBTU NOx DROP. ADJUSTED BELOW FOR OTHER
SEE BELOW FOR FUEL UNITS PRICING AND GAS USE
20 PERCENT ADDED AFTER 3 YEARS AND ALL REPLACED IN 8 YEARS
ESTIMATED $160/SCFT ACCORDING TO EPA ACT DOCUMENT
1.5 PERCENT LOSS IN ECONOMIZER BYPASS
15 PERCENT GAS USE REPLACING 2 % SULFUR COAL
WHEN INCLUDED, BASED ON 40 PERCENT INCREASE IN SNCR O&M COST
DIMENTIONLESS
UNIT PRICING AND OTHER DATA:
NATURAL GAS USE (%TOTAL): 10
CATALYST LYFE (YRS): 6
FLUE GAS FLOW (SCFH): 25000000
Pf\AI Qlll CI ID /°/^ • 0
UUAL oULrUK \fy) . c.
REAGENT / NO (MOLAL RATIO): 1.4
SCR CATALYST ($/CFT): $370
AMMONIA (REAGENT) ($/TON): $300 29% AQUEOUS SOLUTION
NATURAL GAS ($/MMBtu): $2.50
COAL ($/MMBtu): $1.50
OIL ($/MMBtu): $2.00
PLANT HEAT RATE (Btu/kWH): 10000
PLANT REMAINING LIFE (YRS): 20
PLANT CAPACITY FACTOR (%) : 60
INTEREST RATE (%): 7
CATALYST SPACE VEL. (1/HR): 3250 FOR 85% NOx REDUCTION
UREA COST ($/TON): 200 50% UREA SOLUTION
CATALYST VOLUME(CFT): 7692
-------
TECHNICAL REPORT DATA
(Please read Instructions on reverse before completing)
1. REPORT NO. 2.
EPA-453/R-96-002
4. TITLE AND SUBTITLE
Phase H NOX Controls for the MARAMA and NESCAUM
Regions
7. AUTHOR(S)
Carlo Castaldini
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Acurex Environmental Corporation
Post Office Box 7044
Mountain View, California 94039
12. SPONSORING AGENCY NAME AND ADDRESS
Director
Office of Air Quality Planning and Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, NC 2771 1
15. SUPPLEMENTARY NOTES- EPA Contact -
Hambright (717)232-1961; NESCAUM Contact -
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
November 1995
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-D2-0189
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/200/04
Bill Neuffer (919)541-5435; MARAMA Contact - Jim
Praveen Amar (617)367-8540
16. ABSTRACT
This technical report discusses Phase n NOx controls for utility boilers in the Mid- Atlantic Regional
Air Management Association(MARAMA) and the Northeast States for Coordinated Air Use
Management(NESCAUM) regions. The subject areas include:
- Utility boiler population profile in the MARAMA and NESCAUM regions
- Discussion of RACT controls
- Available NOx controls and their levels of performance
- Costs and cost effectiveness of NOx controls
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
Utility boilers
NOX control techniques
Low NOX burners
Selective noncatalytic reduction
Selective catalytic reduction
DISTRI BUTION STATEMENT
b. IDENTIFIERS/OPEN ENDED TERMS
Air Pollution control
COStS 19. SECURITY CLASS (Report)
Unclassified
20. SECURITY CLASS (Page)
Unclassified
c. COSATI Field/Group
21. NO. OF PAGES
230
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION IS OBSOLETE
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U.S. Environmental Protection Agency
Region 5, Library (PL-12J)
77 West Jackson Boulevard, 12th Floor
Chicago, It 60604-3590
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