Final Technical Support Document (TSD)
for the Cross-State Air Pollution Rule for the 2008 Ozone NAAQS
Docket ID No. EPA-HQ-OAR-2015-0500
Assessment of Non-EGU NOx Emission Controls, Cost of
Controls, and Time for Compliance Final TSD
U.S. Environmental Protection Agency
Office of Air and Radiation
August 2016
1
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1 Introduction/Purpose
The purpose of this Technical Support Document (TSD) is to discuss the currently available
information on emissions and control measures for sources of NOx other than electric
generating units (EGUs). This information provides more detail about why EGUs are the
focus of the final rulemaking, namely the uncertainty that exists regarding whether
significant aggregate NOx mitigation is achievable from non-EGU point sources by the 2017
ozone season, and the fact that the limited available information points to an apparent
scarcity of non-EGU reductions that could be accomplished in this timeframe.
Notwithstanding these conclusions as regards the 2017 ozone season, the EPA continues to
assess the role of NOx emissions from non-EGU sources to downwind nonattainment
problems.
This TSD begins by briefly discussing the non-EGU emissions inventories used in the
proposed and final Cross-State Air Pollution Rule (CSAPR) Update analyses, both for the
2011 base year and 2017 future baseline assessed for this rule. The TSD then presents an
evaluation of whether non-EGU emissions can be reduced in a cost-effective manner for
particular categories. Then, it assesses the available NOx emission reductions from such
categories and presents the category-by-category emissions reduction potential. This
assessment considers and presents the annualized costs per ton of these reductions, with a
focus on technologies that achieve cost-effective reductions within a range of costs similar
to that evaluated for EGUs. The TSD then presents estimates of the time required to install
and implement the control measures, both for comparison to the 2017 compliance
timeframe, and for discussion of installation time should such measures be required in the
future. It should be noted that no changes to these data or estimates have been made for
this final TSD compared to the draft version of this TSD provided in the docket for the
proposed rule. Finally, the TSD presents a summary of comments received on the proposed
rule TSD, along with responses as appropriate.
For the reasons stated in the preamble, the data and discussion in this TSD are intended to
focus on the eastern states that are included in the CSAPR Update rule. Information
inclusive of western states1 is presented where available and appropriate.
1 For the purpose of this action, the western United States (or the West] consists of the 11 western contiguous states of
Arizona, California, Colorado, Idaho, Montana, New Mexico, Nevada, Oregon, Utah, Washington, and Wyoming, and the
eastern U.S. (or East] consists of the remaining states in the contiguous U.S.
2
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2 Background
In this section we present annual and ozone-season NOx emission inventory totals and the
relative percentages for non-EGU source categories statewide and/or nationally. This
information is summary in nature and is not meant to replace other, more detailed
information available from the EPA, such as the EPA's 2011v6.2 Emissions Modeling
Platform TSD2 as well as the Notice of Data Availability3 (NODA) and Regulatory Impact
Analysis4 (RIA) for the proposed and final rule.
Table 1 lists 2011 and 2017 projected NOx emissions by sector, in summary form, for the
48 contiguous states of the United States (CONUS).
Table 1: 2011 Base Year and 2017 Projected NOx Emissions by
Sector (tons), for the 48 CONUS
Sector
2011 NOx,
annual
2017 NOx,
annual
2011 NOx, ozone
season
2017 NOx, ozone
season
EGU-point
2,000,000
1,500,000
942,000
689,000
NonEGU-point
1,200,000
1,200,000
515,000
502,000
Point oil and gas
500,000
410,000
213,000
172,000
Wild and prescribed fires
330,000
330,000
165,000
165,000
Nonpoint oil and gas
650,000
690,000
275,000
293,000
Residential wood
combustion
34,000
35,000
3,000
3,000
Other nonpoint
760,000
730,000
204,000
211,000
Nonroad
1,600,000
1,100,000
825,000
582,000
Onroad
5,700,000
3,200,000
2,417,000
1,329,000
C3 commercial marine
vessel (CMV)
130,000
130,000
58,000
58,000
Locomotive and C1/C2
CMV
1,100,000
910,000
451,000
384,000
Biogenics
1,000,000
1,000,000
630,000
630,000
TOTAL
15,000,000
11,200,000
6,698,000
5,018,000
It is clear from Table 1 that NOx emissions are projected to remain constant or decrease for
most sectors in the 48 states between 2011 and 2017, and this is true whether examining
annual or ozone season (OS) tons. Emissions from the non-EGU point source sector and the
other nonpoint source sector are not projected to change significantly, while emissions
2 Technical Support Document (TSD], Preparation of Emissions Inventories for the Version 6.2,2011 Emissions Modeling
Platform, August 2015, available at: https://www.epa.gov/air-emissions-modeling/2011-version-62-technical-support-
document
3 Notice of Availability of the Environmental Protection Agency's Updated Ozone Transport Modeling Data for the 2008
Ozone National Ambient Air Quality Standard (NAAQS]. The official version is available in the docket for this rulemaking.
4 Regulatory Impact Analysis for the Proposed Cross-State Air Pollution Rule (CSAPR] for the 2008 Ozone National
Ambient Air Quality Standards (NAAQS] and Regulatory Impact Analysis for the Cross-State Air Pollution Rule (CSAPR]
Update for the 2008 Ozone National Ambient Air Quality Standards (NAAQS]. The official versions are available in the
docket for this rulemaking.
3
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from the nonpoint oil and gas source sector are projected to grow (approximately
6%)during this time period. Based on the values in Table 1, Figures 1 and 2 show the
relative contributions of the various sectors to overall NOx emissions (left panel) in the
CONUS and for the non-EGU sectors (right panel) for 2011 and 2017, respectively.
Figure 1:2011 NOx emissions by sector, with further non-EGU
breakout (48 states)
2011 v6.2 Emissions - NOx by 2011 v6.2 Emissions -
Sector (Total 6.7 million OS tons) NOx in Non-EGU
Sector (further detail)
60%
EGU
Non-EGU total
Fires
Residential wood
Mobile
Biogenics
-
25%
IE
42%
Non-EGU
point
Point oil &
gas
Nonpoint oil
& gas
Other
nonpoint
Figure 2: Projected 2017 NOx emissions by sector, with further
non-EGU breakout (48 states)
2017 Projections - NOx By Sector
(TOTAL 5.0 million OS TONS)
2017 Projections -
NOx in Non-EGU
Sector (further detail)
¦ EGU
¦ Non-EGU total
¦ Fires
¦ Residential wood
Mobile
Biogenics
Non-EGU
point
¦ Point oil &
gas
¦ Nonpoint oil
& gas
¦ Other
nonpoint
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Figure 1 depicts the CONUS total ozone season NOx emissions of 6,698,000 tons in 2011
and Figure 2 depicts the CONUS total ozone season NOx emissions of 5,018,000 tons in
2017. In both 2011 and 2017, the mobile source sector has the largest NOx emissions.5
Substantial reductions in mobile source NOx emissions are projected to occur by 2017.
Mobile source emissions are projected to decrease because of sector-specific standards
related to fuels, fuel economy, pollution controls, and repair and replacement of the
existing fleet. Because these reductions are already expected to occur, mobile source
emission reductions are not included in this analysis of non-EGU emission reductions
achievable by the 2017 ozone season.
For the purposes of preliminary analysis in this TSD, "non-EGU total" refers to four
separate categories of sources: non-EGU point, point oil and gas, nonpoint oil and gas, and
other nonpoint (and does not include mobile sources). The oil and gas point and nonpoint
sources are separated from the remaining non-EGU point and nonpoint sources due to the
magnitude of their contribution to the inventory and other aspects related to the inventory
development, emissions modeling, and future year projections for that industry. The point
oil and gas sources are also separated out from the other non-EGU point sources according
to the North American Industry Classification System (NAICS) code specified for the
various sources. Note that point oil and gas sources include a variety of types of processes,
and there is overlap with the processes included in the rest of the non-EGU point inventory.
More information on the emissions sectors is available in the 2011v6.2 Emissions Modeling
Platform TSD.
Comparing the proportions of the total inventory for non-EGUs (Figures 1 and 2), it
becomes clear that, although they are decreasing in the absolute sense, non-EGU NOx
emissions are becoming a larger share of overall ozone-season NOx emissions (16% in
2011 compared with 21% in 2017).
Table 2 compares statewide projected total anthropogenic NOx emissions (inclusive of all
sectors listed in Table 1 with the exception of fires and biogenics) for the 2017 ozone
season to non-EGU NOx emissions for the 2017 ozone season for each of the 48 contiguous
United States . Totals are given for the 48 contiguous United States (the 37 eastern states
plus the District of Columbia that are addressed in the rule are highlighted below in blue).
Non-EGU sources in this table are broken down into two groups (non-EGU point sources,
including point oil & gas sources, and other nonpoint and nonpoint oil & gas sources).
5 The mobile source sector comprises multiple different types of sources (onroad cars & trucks, boats, ships, trains,
construction equipment, mining equipment, tractors, etc.].
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Table 2: Projected Total Anthropogenic Ozone-Season NOx
Emissions vs. Projected Non-EGU Source Group NOx Emissions,
2017 Projections, Tons6
State
Total
Anthropogenic
Non-EGU
Point + Oil &
Gas Point
%
Anthro
Oil & Gas
Nonpoint+ Other
Nonpoint
%
Anthro
Oil & Gas
Point + Oil
& Gas
Nonpoint
%
Anthro
Alabama
88,805
22,187
25
7,952
9
7,442
8
Arizona
71,906
5,015
7
2,310
3
612
1
Arkansas
69,737
13,400
19
5,308
8
9,164
13
California
236,322
29,342
12
20,220
9
3,105
1
Colorado
90,756
19,594
22
16,899
19
27,284
30
Connecticut
17,672
1,105
6
2,626
15
98
1
Delaware
7,786
628
8
615
8
0
0
District of
Columbia
2,252
212
9
312
14
0
0
Florida
177,514
16,293
9
7,543
4
1,112
1
Georgia
103,536
18,8.16
18
4,559
4
1,495
1
Idaho
27,893
3,752
13
1,989
7
503
2
Illinois
148,178
24,668
17
15,409
10
9,424
6
Indiana
139,133
27,222
20
6,864
5
5,931
4
Iowa
70,467
7,888
11
3,861
5
153
0
Kansas
79,939
6,968
9
12,619
16
10,697
13
Kentucky
106,830
11,456
11
11,905
11
12,251
11
Louisiana
173,330
45,506
26
30,160
17
31,503
18
Maine
17,576
4,639
26
809
5
26
0
Maryland
46,029
6,213
13
3,508
8
522
1
Massachusetts
35,369
4,144
12
4,807
14
105
0
Michigan
131,486
21,867
17
12,245
9
9,398
7
Minnesota
89,328
15,541
17
6,414
7
46
0
Mississippi
54,832
11,684
21
2,122
4
6,557
12
Missouri
101,035
9,238
9
3,594
4
122
0
Montana
38,504
2,948
8
3,630
9
3,390
9
Nebraska
70,005
3,884
6
1,163
2
467
1
Nevada
28,192
4,018
14
1,003
4
115
0
New Hampshire
8,932
680
8
1,028
12
0
0
New Jersey
52,743
4,544
9
5,506
10
173
0
New Mexico
65,263
10,559
16
19,940
31
27,759
43
New York
109,910
13,738
12
14,624
13
904
1
North Carolina
98,064
15,711
16
3,657
4
1,203
1
North Dakota
74,118
4,047
5
18,125
24
19,185
26
Ohio
160,110
21,280
13
11,617
7
2,906
2
Oklahoma
131,763
32,203
24
33,178
25
51,257
39
Oregon
40,507
6,130
15
4,348
11
365
1
6 EGUs are not provided a separate breakout in Table 2 since state-level emissions are presented in the Preparation of
Emissions Inventories for the Version 6.3,2011 Emissions Modeling Platform TSD and other TSDs for the proposed and
final rules.
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Oil & Gas
Non-EGU
Oil & Gas
Point + Oil
Total
Point + Oil &
%
Nonpoint+ Other
%
& Gas
%
State
Anthropogenic
Gas Point
Anthro
Nonpoint
Anthro
Nonpoint
Anthro
Pennsylvania
174,664
23,735
14
33,508
19
26,713
15
Rhode; Island
5,845
544
9
1,370
23
12
0
South Carolina
55,897
10,144
18
3,980
7
348
1
South Dakota
22,192
1,24.1
6
432
2
75
0
Tennessee
85,759
13,494
16
5,846
7
1,922
7
Texas
467,245
95,671
20
115,180
25
145,285
31
Tribal Data
26,717
3,799
14
0
0
3,700
14
Utah
66,486
8,004
12
9,781
15
9,349
14
Vermont
5,473
163
3
937
17
0
0
Virginia
87,754
14,039
16
7,318
8
4,775
5
Washington
75,833
8,666
11
1,150
2
164
0
West Virginia
64,839
9,678
15
12,642
19
16,723
26
Wisconsin
75,047
11,181
15
5,351
7
178
0
Wyoming
68,864
26,488
38
4,018
6
10,905
16
Eastern States
3,411,193
545,649
16
418,692
12
378,171
11
US Total
4,248,436
673,964
16
503,980
12
465,421
11
Table 2 indicates that, in the projected 2017 inventory, non-EGU sources comprising non-
EGU point and point oil and gas sources are estimated to make up 16% of anthropogenic
NOx emissions in the 48 contiguous United States. In individual states, the percentage of
anthropogenic emissions contributed by these two non-EGUs categories range from 3% to
26% (eastern states) and from 7% to 38% (western states).
We also note that in the projected 2017 inventory, non-EGU sources comprising nonpoint
oil & gas and other nonpoint sources are estimated to make up 12% of anthropogenic NOx
emissions in the entire continental U.S. In individual states, the percentage of
anthropogenic emissions contributed by these non-EGUs ranges from 2% to 25% (eastern
states) and from 4% to 31% (western states).
The EPA's preliminary analysis indicates that NOx emissions from oil and gas sources
(inclusive of emissions from the point oil and gas and nonpoint oil and gas sectors)
comprise an average of 11% of the total ozone season NOx emissions inventory. For some
states, this percentage increases up to 43%, with oil and gas emissions exceeding non-EGU
point totals in a number of states. The key sources of NOx emissions in the oil and gas
sector are from the combustion of fossil fuel (primarily drilling rigs, internal combustion
(IC) engines and pipeline compressors) and flares. Please refer to the EPA's 2011v6.2
Emissions Modeling Platform TSD for more information on emissions from these sectors.
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3 Preliminary Analysis
For the purposes of the proposed rule, the EPA performed a preliminary analysis to
characterize whether there are non-EGU source groups with a substantial amount of
available cost-effective NOx reductions achievable by the 2017 ozone season. The EPA
received no comments that would substantively change this analysis, therefore there was
no need to repeat this preliminary analysis for the final CSAPR Update rule.
3.1 Methodology
The EPA's preliminary analysis of potential non-EGU NOx emission reductions was
performed using the Control Strategy Tool (CoST). CoST is the software tool the EPA uses
to estimate the emission reductions and costs associated with future-year control
strategies, and then to generate emission inventories that result from the control strategies
applied. CoST tracks information about control measures, their costs, and the types of
emissions sources to which they apply. The purpose of CoST is to support national- and
regional-scale multi-pollutant analyses, primarily for Regulatory Impact Analyses (RIAs) of
the National Ambient Air Quality Standards (NAAQS). CoST is also a component of the
Emissions Modeling Framework (EMF) that was used to generate the 2017 non-EGU
emissions presented above and in the Emissions Modeling Platform TSD for the proposed
CSAPR Update rule. Further discussion and documentation of CoST is available on the
EPA's website at http://www.epa.gov/ttnecasl/cost.htm.
Appendices to this TSD discuss recommendations for updates to CoST, including
corrections for inapplicable controls, sources already controlled by state rules, sources
with permit emissions limits or that have clearly identified controls in place, and sources
subject to future NOx emission limits. Appendix A discusses contractor RTI International's
work to review estimates for lean burn internal combustion (IC) engines, glass
manufacturing, ammonia reformers, and gas turbines.7 Appendix B discusses contractor
SRA International's work on a variety of other categories including many of the others
evaluated in this TSD.8
EPA has prepared a set of data called the Control Measure Data Base (CMDB) that is used as
an important input to CoST. This data includes all control measures utilized by the tool for
control strategy analysis. It should be noted that most of the NOx measures included in this
report are currently in the Control Measure Data Base used by CoST, and generally do not
reflect the updates suggested in these contractor reports. Obstacles to full incorporation of
the recommended changes include availability of accurate costs for these measures, and to
have cost equations rather than average cost/ton to estimate costs. Control efficiencies are
readily available for measures, but costs, particularly those that can be estimated using
equations that consider source size or capacity, often are not. In addition, the Pennsylvania
7 "Update of NOx Control Measure Data in the CoST Control Measure Database for Four Industrial Source Categories:
Ammonia Reformers, NonEGU Combustion Turbines, Glass Manufacturing, and Lean Burn Reciprocating Internal
Combustion Engines," Revised Draft Report, RTI International, 2014.
8 "Review of CoST Model Emission Reduction Estimates," SRA International, 2014; "Summary of State NOx Regulations for
Selected Stationary Sources," SRA International, 2014.
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Department of Environmental Protection's Additional RACT Requirements for Major
Sources of NOx and VOCs rule,9 which was recently finalized, is not included in these
contractor reports. The EPA will consider whether or not to incorporate these
recommendations for changes or additions to the NOx controls for non-EGUs to support
NOx control efforts for future rules and other efforts. The EPA will also consider updates to
reflect state emission control requirements (i.e., Pennsylvania's RACT rule). Nonetheless,
the information from these reports helped inform our assessment in terms of uncertainty
surrounding non-EGU emission reduction potential. Further details on the CMDB can be
found on the CoST web site shown above.
For the purpose of identifying a list of non-EGU NOx source groups with controls available,
the EPA ran CoST for non-EGU point sources for the 37 eastern U.S. with NOx emissions of
greater than 25 tons/year in 2017. The analysis using CoST was a basis for the review of
NOx control measures for non-EGUs undertaken by two different contractors for EPA.
Through a contractual agreement with EPA, SRA International and RTI International
provided reports within which CoST examined a number of source categories of non-EGUs
with annualized control costs up to $10,000 per ton (in 2011 dollars). These reports are
included in the Appendices of this TSD. CoST selected particular control technologies based
on application of a least-cost criterion for control measures applied as part of the control
strategy. Other NOx control measures are available for some of these categories, but on
average, annualized costs for these measures were at higher cost.
3.2 Uncertainties and Limitations
The EPA acknowledges several important limitations of the non-EGU cost analysis included
in this TSD, which include the following:
Boundary of the cost analysis: In this cost analysis we include only the impacts to the
regulated industry, such as the costs for purchase, installation, operation, and maintenance
of control equipment over the lifetime of the equipment. Recordkeeping, reporting, testing
and monitoring costs are not included. Additional profit or income may be generated by
industries supplying the regulated industry, especially for control equipment
manufacturers, distributors, or service providers. These types of secondary impacts are not
included in this cost analysis.
Cost and effectiveness of control measures: Our application of control measures reflect
nationwide average retrofit factors and equipment life. We do not account for regional or
local variation in capital and annual cost items such as energy, labor, materials, and others.
Our estimates of control measure costs may over- or under-estimate the costs depending
on how the difficulty of actual retrofitting and equipment life compares with our control
assumptions. In addition, our estimates of control efficiencies for control measures
included in our analysis assume that the control devices are properly installed and
maintained. There is also variability in scale of application that is difficult to reflect for
small area sources of emissions.
9 Available at: http://www.pabulletin.com/secure/data/vol46/46-17/694.html
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Discount (interest) rate: Because we obtain control cost data from many sources, we are
not always able to obtain consistent data across original data sources. If disaggregated
control cost data are not available (i.e., where capital, equipment life value, and operation
and maintenance [O&M] costs are not shown separately), the EPA assumes that the
estimated control costs are annualized using a 7 percent discount rate, which is the
discount (interest) rate used in accordance with OMB guidance in Circular A-4. In general,
we have some disaggregated data available for non-EGU point source controls. In addition,
while these interest rates are consistent with OMB guidance, the actual interest rates may
vary regionally or locally.
Accuracy of control costs: We estimate that there is an accuracy range of +/- 30 percent for
non-EGU point source control costs. This level of accuracy is described in the EPA Air
Pollution Control Cost Manual, which is a basis for the estimation of non-EGU control cost
estimates included in this TSD. This level of accuracy is consistent with either the budget or
bid/tender level of cost estimation as defined by the American Association for Cost
Engineering (AACE) International. In addition, the accuracy of costs is also influenced by
the availability of data underlying the cost estimates for individual control measures. For
some control measures, we recognize that there is limited data available to generate robust
cost estimates. This is reflected in the derivation of costs for some of the non-EGU NOx
control measures discussed in Appendix A for this TSD.
3.3 CoSTResults
The results of the CoST analysis are displayed in Table 3. In Table 3, we display the source
groups selected by CoST, the Source Classification Codes (SCCs) included in those groups10,
the least-cost control technology for a given source group (selected by CoST), the current
estimate (in dollars per ton, using 2011 dollars) of the annualized cost per ton NOx reduced
of the control technology, the current estimate of the time necessary to install the selected
control technology (not including permitting time), the estimated ozone season emissions
in the East from the non-EGU source group in 2017 in the absence of the installation of the
selected controls, and the estimated potential ozone season reductions in the East from the
non-EGU source group in 2017 assuming the CoST selected controls could be fully installed
and operational prior to the 2017 ozone season (which as discussed in more detail later, is
not the case for many of the categories examined). Note that CoST does not account for
installation time or time required for the permitting process. Instead it provides
information on the control measures applicable to sources in the inventory, along with the
cost of installation and operation and maintenance of the selected measures.
10 The CoST results do not indicate applicability of the recommended control technology to all sources in the source group
but only to the specific SCCs for which control technologies are applicable. For example, for the cement kilns source
group, Biosolid Injection Technology (BSI] is applicable only for the types of cement kilns covered by the listed SCCs.
10
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Table 3: CoST Results: Non-EGU Source Groups with NOx Reductions
Non-EGU
SCCs
Control
Current
Time to install11
201714
2017
Source Group
Technology
estimate
12 (excluding
NOx
Potential
Recommen
of NOx
permitting,
Emissio
Reductions
ded by
$/ton,
reporting
ns (37
15 (37 States
CoST
CoST
preparation,
States +
+ DC), OS
(2011 $)
programmatic
DC), OS
tons, CoST
and
tons,
administrative
CoST
considerations13
1
Cement Kilns
30500622 (preheater kiln], 30500623
Biosolid
$410
Uncertain
24,760
4,207
(preheater/precalciner]; 39000201
Injection
(kiln/dryer]; 39000288 (kiln in process
Technology
coal]
(BSI]
11 Time to install is not an output of CoST, but are rather estimates determined by the EPA based on research from a variety of sources. See, "Typical Installation
Timelines for NOx Emissions Control Technologies on Industrial Sources," Institute of Clean Air Companies, December 2006 (all sources except Cement Kilns and RICE
(Reciprocating Internal Combustion Engines]], "Cement Kilns Technical Support Document for the NOx FIP," EPA, January 2001 (cement kilns], and "Availability and
Limitations of NOx Emission Control Resources for Natural Gas-Fired Reciprocating Engine Prime Movers Used in the Interstate Natural Gas Transmission Industry,"
Innovative Environmental Solutions Inc., July 2014 (prepared for the INGAA Foundation].
12 In general, for control retrofits to non-EGU sectors, it appears that the full sector-wide compliance time is uncertain, but is longer than the installation time shown
above for a typical unit. We have insufficient information on capacity and experience within the OEM suppliers and major engineering firms supply chain to offer
conclusions on their availability to execute the project work for non-EGU sectors.
13 Non-EGUs of any type - boiler or turbine - that are not currently required to monitor and report in accordance with 40 CFR Part 75 and/or not currently participating
in the CSAPR program will require additional time relative to EGUs that are currently equipped with Part 75 monitoring and reporting and/or participating in the
current CSAPR program. Installation of NOx monitors for the reporting of NOx mass requires the construction of platforms, CEM shelters, procurement of equipment,
certification testing, and electronic data reporting programming of a data handling system. These added timing considerations for infrastructure on the non-EGU
sources combined with the additional programmatic adoption measures necessary make installation of controls by the 2017 timeframe established in this rule less likely
and more uncertain for industrial sources.
14 Emissions and potential reductions for Gas Turbines ($163/ton grouping]. Cement Kiln/Dryer (Bituminous Coal] ($942/ton grouping]. Coal Cleaning - Thermal Dryer
(2], Spreader Strokers, Petroleum Refinery Process Heaters, Incinerators, Boilers & Process Heaters, Gas-Fired Process Heaters, Coal Boilers, By-Product Coke
Manufacturing, ICI Boilers - Residual Oil, Ammonia Production, Glass Manufacturing, ICI Boilers, Iron & Steel - In-Process Combustion - Bituminous Coal, Industrial
Processes Miscellaneous, Catalytic Cracking, Process Heaters, & Coke Ovens, Petroleum Refinery Gas-Fired Process Heaters, Glass Manufacturing - Pressed, Glass
Manufacturing - Container, Petroleum Refinery Gas-Fired Process Heaters, and RICE source groups were calculated for 2018, however they are likely to be virtually
identical to projections for 2017. Non-EGU source groups with projected aggregate 2017 NOx emissions below 100 OS tons are excluded from this table.
15 Potential reductions assume fully implemented controls by the start of the 2017 ozone season.
11
-------
Cement Mfg
(dry)
30500606 Industrial Processes, Mineral
Products, Cement Manufacturing (Dry
Process), Kilns
Selective Non-
Catalytic
Reduction
(SNCR]
$1,255
42-51 weeks
13,006
6,501
Cement Mfg
(wet)
30500706 Industrial processes, mineral
products. Cement Manufacturing (Wet
Process], Kilns
Mid-Kiln Firing
$73
5-7 months
7,971
2,287
Coal Cleaning -
Thermal Dryer
(1)
30502508 Construction Sand & Gravel,
Dryer; 30501001 Industrial Processes,
Mineral Products, Coal Mining, Cleaning,
and Material Handling, Fluidized Bed
Reactor
Low NOx Burner
(LNB)
$1,125
6-8 months
503
165
Coal Cleaning -
Thermal Dryer
(2)
30501001 Industrial Processes, Mineral
Products, Coal Mining, Cleaning, and
Material Handling, Fluidized Bed Reactor
Low NOx Burner
(LNB)
$1,640
6-8 months
154
63
Cement
Kiln/Dryer
(Bituminous
Coal)
39000201 Industrial Processes, In-process
Fuel Use, Bituminous Coal, Cement
Kiln/Dryer (Bituminous Coal)
SNCR
$942
42-51 weeks
520
260
Iron and Steel
Mills -
Reheating
30300934 (303015] Primary Metal
Production: Steel; 30300933
Low NOx Burner
(LNB] & Flue Gas
Recirculation
(FGR]
$620
6-8 months
1,064
664
Steel
Production
30490033 Industrial Processes,
Secondary Metal Production, Fuel Fired
Equipment, Natural Gas: Furnaces;
30400704 Industrial Processes,
Secondary Metal Production, Steel
Foundries, Heat Treating Furnace
Low NOx Burner
(LNB)
$928
6-8 months
281
141
Nitric Acid Mfg
30101301 Chemical Manufacturing,
Nitric Acid, Absorber Tail Gas (Pre-1970
Facilities]; 30101302 Chemical
Manufacturing, Nitric Acid, Absorber Tail
Gas (Post-1970 Facilities]
NSCR
$900
6-14 weeks
1,290
724
Petroleum
Refinery
Process Heaters
30600106 Industrial Processes, Petroleum
Industry, Process Heaters, Process Gas-fired
SCR-95%
$940-$l101
28-58 weeks
179
177
12
-------
Gas Turbines
20200201 Natural Gas, Turbine; 20200203
Natural Gas, Turbine: Cogeneration;
20300202 Natural Gas, Turbine
Low NOx Burner
(LNB)
$163
12 months
945
793
Gas Turbines
20200201 Natural Gas, Turbine;
20200203 Natural Gas, Turbine:
Cogeneration; 20300202 Natural Gas,
Turbine; 20300203 Natural Gas, Turbine:
Cogeneration
Low NOx Burner
(LNB]
$800
6-8 months
16,036
4,713
Natural Gas
RICE Pipeline
Compressors
20200202 Internal Combustion Engines,
Industrial, Natural Gas, Reciprocating
Adjust Air to
Fuel Ratio and
Ignition Retard
$249
Uncertain
10,099
2,958
Natural Gas
RICE
Miscellaneous
20100202 Internal Combustion Engines,
Electric Generation, Natural Gas,
Reciprocating; 20200202 Internal
Combustion Engines, Industrial, Natural
Gas, Reciprocating; 20200204, Internal
Combustion Engines, Industrial, Natural
Gas, Reciprocating: Cogeneration;
20300201, Internal Combustion Engines,
Commercial/Institutional, Natural Gas,
Reciprocating
Adjust Air to
Fuel Ratio and
Ignition Retard
$447
Uncertain
27,600
8,085
Natural Gas
RICE Pipeline
Compressors,
Rich Burn
20200253 Internal Combustion Engines,
Industrial, Natural Gas, 4-cycle Rich Burn
NSCR
$517
Uncertain
11,758
10,571
Natural Gas
RICE Pipeline
Compressors,
Lean Burn /
Clean Burn
20200252 Internal Combustion Engines,
Industrial, Natural Gas, 2-cycle Lean
Burn; 20200254 Internal Combustion
Engines, Industrial, Natural Gas, 4-cycle
Lean Burn; 20200255 Internal
Combustion Engines, Industrial, Natural
Gas, 2-cycle Clean Burn; 20200256
Internal Combustion Engines, Industrial,
Natural Gas, 4-cycle Clean Burn
Low Emission
Combustion
(LEC)
$649
Uncertain
47,321
41,169
Diesel / Dual
Fuel RICE
20200401 Internal Combustion Engines,
Industrial, Large Bore Engine, Diesel;
20200402 Internal Combustion Engines,
Industrial, Large Bore Engine, Dual Fuel
(Oil/Gas]
Ignition Retard
$1,255
Uncertain
865
216
13
-------
Catalytic
Cracking (1)
30600201 Industrial Processes, Petroleum
Industry, Catalytic Cracking Units, Fluid
Catalytic Cracking Unit
Low NOx Burner
(LNB) & Flue
Gas Recirculation
(FGR)
$1,375
6-8 months
255
140
Spreader
Strokers
10100204 External Combustion Boilers,
Electric Generation,
Bituminous/Subbituminous Coal,
Spreader Stroker [Bituminous Coal]
SNCR
$1,390
42-51 weeks
394
158
Petroleum
Refinery
Process Heaters
30600106 Industrial Processes, Petroleum
Industry, Process Heaters, Process Gas-fired
SCR-95%
$1,406-$ 1,501
28-58 weeks
161
157
Incinerators
50200102, 50200103, 50200104,
50200504, 30190013, 30190014,
50300101, 50300106, 50300112,
50300113, 50300501, 50300503,
50300504, 50300599, 50100101,
50100102,
50100103, 50100506, 50100515, 50100516,
39990024 Incineration
SNCR
$1,842
42-51 weeks
6,556
2,950
Boilers &
Process Heaters
10200203,10200217, 10300216,10200204,
10200205,10300207,10300209,10200799
External Combustion Boilers; 30190002,
30600103 Industrial Process Heaters
SCR
$2,235
28-58 weeks
13,146
10,358
Natural Gas
RICE Electric
Generation
20100206 Internal Combustion Engines,
Electric Generation, Natural Gas,
Reciprocating: Evaporative Losses (Fuel
Delivery System)
Adjust Air to Fuel
Ratio and Ignition
Retard
$2,347
Uncertain
107
32
Catalytic
Cracking (2)
30600201 Industrial Processes, Petroleum
Industry, Catalytic Cracking Units, Fluid
Catalytic Cracking Unit; 30600202
Industrial Processes, Petroleum Industry,
Catalytic Cracking Units, Catalyst Handling
System
Low NOx Burner
(LNB) & Flue
Gas Recirculation
(FGR)
$2,369
6-8 months
274
97
Gas-Fired
Process Heaters
(1)
30600104 Industrial Processes, Petroleum
Industry, Process Heaters, Gas-fired
SCR-95%
$2,376
28-58 weeks
211
204
Coal Boilers
10200206,10200224,10200225,
10300102,10300208,10300224,
10300225
SNCR
$2,413
42-51 weeks
1099
495
14
-------
Gas-Fired
Process Heaters
30600104 Industrial Processes, Petroleum
Industry, Process Heaters, Gas Fired
Ultra-Low NOx
Burners
$2,419-$2,638
6-8 months
137
64
(2)
By-Product
Coke
Manufacturing
30300306 Industrial Processes, Primary
Metal Production, By-Product Coke
Manufacturing, Oven Underfiring
SNCR
$2,673
42-51 weeks
2,366
1,420
ICI Boilers -
Residual Oil
10200401,10200402, 10200404,10300401,
10300402 External Combustion Boilers,
Residual Oil
LNB & SNCR
$2,850
6-8 months
991
689
Ammonia
Production
30100306 Industrial Processes, Chemical
Manufacturing, Ammonia Production,
Primary Reformer: Natural Gas Fired
SCR
$2,896
28-58 weeks
2,508
2,257
Glass
Manufacturing
-Flat
30501403 Industrial Processes, Mineral
Products, Glass Manufacture, Flat Glass:
Melting Furnace
OXY-Firing
$3,097
Uncertain
9,721
7,880
ICI Boilers
10200201,10200202, 10200212,10300205,
10200501,10200504, 10200601,10200602,
10200603,10200604,10201401,10300601,
10300602,10200701, 10200704,10200707,
10201402 External Combustion Boilers
Low NOx Burner
& SCR
$3,456
6-8 months (LNB)
28-58 weeks (SCR)
31,005
28,204
Iron & Steel -
In-Process
Combustion -
30300819,30300824, 30300913,30300914,
30301522 Industrial Processes, Primary
Metal Production
SCR
$3,705
28-58 weeks
829
746
Bituminous
Coal
Diesel RICE
Miscellaneous
20100102 Internal Combustion Engines,
Electric Generation, Distillate Oil (Diesel],
Reciprocating; 20100107 Internal
Combustion Engines, Electric Generation,
Distillate Oil (Diesel], Reciprocating:
Exhaust; 20200102 Internal Combustion
Engines, Industrial, Distillate Oil (Diesel],
Reciprocating;
20200106 Internal Combustion Engines,
Industrial, Distillate Oil (Diesel],
Reciprocating: Evaporative Losses (Fuel
Storage and Delivery System];
SCR
$3,814
28-58 weeks
1,091
869
15
-------
20200107 Internal Combustion Engines,
Industrial, Distillate Oil (Diesel],
Reciprocating: Exhaust;
20300101 Internal Combustion Engines,
Commercial/Institutional, Distillate Oil
(Diesel], Reciprocating;
20400403 Internal Combustion Engines,
Engine Testing, Reciprocating Engine,
Distillate Oil
Catalytic
Cracking,
Process
Heaters, &
Coke Ovens
30600201, 30390004, 39000701,
39000702,39000797
LNB & FGR
$5,199
6-8 months
1,989
1,094
Petroleum
Refinery Gas-
Fired Process
Heaters (3)
30600104 Industrial Processes, Petroleum
Industry, Process Heaters, Gas-fired,
30600106 Industrial Processes, Petroleum
Industry, Process Heaters, Process Gas-fired
SCR-95%
$8,885-$9,140
28-58 weeks
370
316
Glass
Manufacturing
- Pressed
30501404 Industrial Processes, Mineral
Products, Glass Manufacture, Pressed and
Blown Glass: Melting Furnace
OXY-Firing
$6,356
Uncertain
1,001
851
Petroleum
Refinery Gas-
Fired Process
Heaters (2)
30600104 Industrial Processes,
Petroleum Industry, Process Heaters,
Gas-fired, 30600106 Industrial
Processes, Petroleum Industry, Process
Heaters, Process Gas-fired
SCR-95%
$7,533-$8,120
28-58 weeks
362
304
Industrial
Processes
Miscellaneous
30600201 Industrial Processes,
Petroleum Industry, Catalytic Cracking
Units, Fluid Catalytic Cracking Unit;
39000701 Industrial Processes, In-
process Fuel Use, Process Gas, Coke Oven
or Blast Furnace
LNB & FGR
$4,026
6-8 months
871
479
Glass
Manufacturing
- Container
30501402 Industrial Processes, Mineral
Products, Glass Manufacture, Container
Glass: Melting Furnace
OXY-Firing
$7,481
Uncertain
3,107
2,628
Petroleum
Refinery Gas-
30600104 Industrial Processes,
Petroleum Industry, Process Heaters,
Gas-fired; 30600106 Industrial
SCR-95%
$5,609-$5,884
28-58 weeks
372
338
16
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Fired Process
Heaters (1)
Processes, Petroleum Industry, Process
Heaters, Process Gas-fired
Taconite Ore
Processing
30302351, 30302352, 30302359
Industrial Processes, Primary Metal
Production, Taconite Ore Processing,
Induration
SCR
$6,449
28-58 weeks
1,188
991
Diesel RICE
Electric
Generation
20200102 Internal Combustion Engines,
Electric Generation, Distillate Oil (Diesel],
Reciprocating
SCR
$1,499
28-58 weeks
778
622
17
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3.4 Discussion ofNon-EGlJ Source Groups
The below discussion utilizes the information in Table 3 in order to assess whether
significant aggregate NOx mitigation is achievable from non-EGU sources by the 2017
ozone season.
It is clear that a number of source categories have been identified by CoST using the least-
cost procedure that have the potential for non-EGU stationary source emissions reductions.
There are some notable source categories that have the potential for substantial non-EGU
stationary source emissions reductions below $10,000 per ton.16 However, for the
purposes of this analysis, the EPA did not further examine control options above $3,400
per ton. This is consistent with the range we analyzed for EGUs in the proposed and final
rules, and is also consistent with what the EPA has identified in previous transport rules as
highly cost-effective, including the NOx SIP call.17 Again, this was done because the
objective of this analysis is to characterize whether significant aggregate NOx mitigation is
achievable from non-EGU sources by the 2017 ozone season, so we focused the search on
categories with highly cost-effective technologies. This focus excludes several source
groups with high emissions reduction potential because reductions from those source
groups are not available for $3,400 per ton or less, including: ICI boilers using SCR & LNB;
Catalytic Cracking, Process Heaters, & Coke Ovens using LNB & FGR; and Pressed and
Container Glass Manufacturing using OXY-Firing.
At a cost level of $3,400 per ton or less, there are a number of source groups with
substantial reduction potential. However the table also identifies several source groups
whose reduction potential is not significant, and which the EPA did not weigh heavily in
assessing the aggregate non-EGU NOx emission reduction potential. This is because the
aggregate potential reductions from these "insignificant" source groups is small. These
"insignificant" source groups comprise those source groups with many small sources, as
well those containing a limited number of larger sources; for either of these types of
groups, potential aggregate emission reductions are small relative to reductions available
from other source categories. The EPA does not believe that small sources have significant
emission reduction potential in the aggregate because most small sources emit less than
100 tons of NOx per year. (It is worth noting that small sources account for a significant
percentage of the total number of non-EGU point sources. See Appendix A/B for more
information on the number of sources within certain states.) The EPA therefore excludes
from the focus of this analysis these insignificant source groups, namely, those with
aggregate potential reductions of 1,000 tons per year or less (which represents less than
0.1 percent of the anthropogenic ozone season inventory).
The EPA will now focus on the several source groups with significant cost-effective
reductions identified in Table 3. These source groups include cement kilns, two types of
cement manufacturing (dry and wet), gas turbines, four separate groups of natural gas
reciprocating IC engines (RICE), incinerators, boilers & process heaters, by-product coke
16 $10,000 per ton represents the cost/ton for Best Available Control Technology (BACT) determinations, which usually
do not exceed $10,000/ton in the Eastern U.S.
17 $3,400 per ton represents the $2,000 per ton value (in 1990 dollars] used in the NOx SIP call, adjusted to the 2011
dollars used throughout this proposal Adjustment of costs was made using the Chemical Engineering Plant Cost Index
(CEPCI] annual values for 1990 and 2011.
18
-------
manufacturing, ammonia production, and flat glass manufacturing. These source groups
are listed below with their control technologies, estimated annualized control costs, and
estimated installation time. These groups have been organized into 7 categories for clarity,
based on either common control technologies (categories 1 through 6) or similarity of
source groups (category 7).
Category 1
-Cement Mfg (dry)
-Incinerators
-By-Product Coke Manufacturing
Category 2
-Cement Kilns
Category 3
-Gas Turbines
Control Tech.
SNCR
SNCR
SNCR
Est. Cost
$1,255
$1,842
$2,673
Biosolid Injection $410
Technology (BSI)
Low NOx Burner $800
(LNB)
Est. Inst. Time
42-51 weeks
42-51 weeks
42-51 weeks
Uncertain
6-8 months
Category 4
-Cement Mfg (wet)
Category 5
-Boilers & Process Heaters
-Ammonia Production
Mid-Kiln Firing $73
SCR
SCR
$2,235
$2,896
5-7 months
28-58 weeks
28-58 weeks
Category 6
-Glass Manufacturing - Flat
Category 7
-Gas RICE Pipeline Compressors
-Gas RICE Miscellaneous
-Gas RICE Pipeline Compressors,
Rich Burn
-Gas RICE Pipeline Compressors,
Lean/Clean Burn
OXY-Firing
$3,097
Adjust AFR and $249
Ignition Retard
Adjust AFR and $447
Ignition Retard
NSCR $517
Low Emission $649
Combustion (LEC)
Uncertain
Uncertain
Uncertain
Uncertain
Uncertain
The EPA makes the following observations about the potential reductions from these
significant cost-effective categories.
The source groups listed in Category 1 would utilize SNCR as the recommended control
technology. The time necessary to install SNCR equipment is generally well known. A
typical installation timeline of 42-51 weeks is generally needed to complete a SNCR project
19
-------
going from the bid evaluation through startup, which installation timeline is specific to
non-EGUs. Based on this fact alone (which does not consider additional time likely
necessary for permitting or installation of monitoring equipment), the ability for SNCR
technology to be installed and operational in time for the 2017 ozone season seems very
unlikely.
The source group listed in Category 2 contains a specific source of uncertainty in regards to
biosolid injection technology (BSI). Due in large part to the lack of widespread use of this
control technology, research performed by the EPA has been unable to uncover any reliable
information on the time required to install the necessary BSI equipment on cement kilns.
Compliance timing with regard to biosolid injection technology should therefore be
considered extremely uncertain. Based on this fact alone (and aside from additional time
likely necessary for permitting or installation of monitoring equipment), the ability for this
technology to be installed and operational at all facilities in this category in time for the
2017 ozone season is unknown.
The source group listed in Category 3 would utilize LNB as the recommended control
technology, with a necessary installation time of approximately 6-8 months. Some of the
LNB combustion control technology identified for non-EGU sources reflects a different
technology that may have different timing considerations than that considered for EGU
boilers. For instance, LNB at non-EGU combustion turbines in this assessment refers to
"dry low-NOx burners" (DLNB) which, in addition to the usual diffusion burner, typically
also include provisions to "premix" natural gas and combustion air prior to combustion. In
spite of the similarity in naming, this is a different technology than the LNB technology
examined and assumed for reductions at EGU boilers. Therefore, the same timing
assumptions assumed and demonstrated on the EGU side are not necessarily applicable to
combustion control technology for non-EGU sources. Moreover, non-EGUs of any type -
boiler or turbine - that are not currently required to monitor and report in accordance
with 40 CFR Part 75 will require additional time relative to EGUs that are currently
equipped with Part 75 monitoring and reporting (such as those EGUs covered under
federal transport rulemakings and this one). Installation of NOx monitors for the reporting
of NOx mass requires the construction of platforms, Continuous Emissions Monitoring
(CEM) shelters, procurement of equipment, certification testing, and electronic data
reporting programming of a data handling system. These timing considerations on the
non-EGU sources make installation of controls by the 2017 timeframe established in this
rule less likely and more uncertain for industrial sources.
The source group listed in Category 4 would utilize mid-kiln firing as the recommended
control technology. A fairly well-known aspect is the time necessary to install this
equipment; typically, 5-7 months is needed to complete a mid-kiln firing project going from
the bid evaluation through startup. However, the above-discussed issues regarding
monitoring and reporting of NOx mass on non-EGU sources that currently lack such
monitoring equipment make installation of controls by the 2017 timeframe of this rule less
likely and more uncertain for industrial sources such as those in the cement manufacturing
(wet) source group.
20
-------
The source groups listed in Category 5 would utilize SCR as the recommended control
technology, with an installation time of 28-58 weeks for SCR (dependent on exhaust gas
flow rates; larger systems require longer installation times). Based on the installation time
frame alone (which does not consider additional time likely necessary for permitting or
installation of monitoring equipment), the ability for SCR technology to be installed and
operational in time for the 2017 ozone season seems unlikely In addition to this
uncertainty, the above-discussed issues regarding monitoring and reporting of NOx mass
on non-EGU sources that currently lack such monitoring equipment make installation of
controls by the 2017 timeframe established in this rule less likely and more uncertain for
industrial sources such as those in Category 5 source groups.
The source group listed in Category 6 would utilize OXY-Firing as the recommended
control technology, with an uncertain necessary installation. A specific source of
uncertainty with regard to the estimated installation time of this control technology is that
OXY-Firing is generally installed only at the time of a furnace rebuild, which rebuilds may
occur at infrequent intervals of a decade or more.18 In addition to this uncertainty, the
above-discussed issues regarding monitoring and reporting of NOx mass on non-EGU
sources that currently lack such monitoring equipment make installation of controls by the
2017 timeframe established in this rule less likely and more uncertain for industrial
sources such as those in Category 6 source group.
Finally, the source groups listed in Category 7 are all RICE. While some of the
recommended control technologies may involve installation timelines that are relatively
short on a per-engine basis, there is substantial uncertainty in large-scale installation over
numerous sources. References indicate that implementation of NOx controls of any type on
a large number of RICE will require significant lead time to train and develop resources to
implement emission reduction projects; market demand could significantly exceed the
available resource base of skilled professionals.19 Additionally, in order not to disrupt
pipeline capacity, engine outages must be staggered and scheduled during periods of low
system demands for those engines involved in natural gas pipelines (as is the case with 3 of
the 4 RICE source groups with significant cost-effective reductions). In addition to this
uncertainty, the above-discussed issues regarding monitoring and reporting of NOx mass
on non-EGU sources that currently lack such monitoring equipment make installation of
controls by the 2017 timeframe established in this rule less likely and more uncertain for
industrial sources such as RICE.
4 Summary of Comments Receive ' ted Rule TSD
The EPA received relatively few comments on the draft Assessment of Non-EGU NOx
Emission Controls, Cost of Controls, and Time for Compliance TSD provided in the docket
for this rule. None of these comments changed our conclusions reached in the draft TSD, as
commenters generally agreed with the EPA's assessment with respect to the regulation of
18 See Appendix B.
19 "Availability and Limitations of NOx Emission Control Resources for Natural Gas-Fired Reciprocating Engine Prime
Movers Used in the Interstate Natural Gas Transmission Industry," Innovative Environmental Solutions Inc., July 2014.
21
-------
non-EGUs in this rule. Detailed responses to these comments can be found in the response
to comments document available in the docket for this final rule. A brief discussion of one
comment containing data on control information is presented below.
Commenter Fuel Tech, Inc. (FTI) provided information on the installation time required for
SNCR equipment, stating that "FTI has provided SNCR systems in 8-12 months (from
contract award to performance guarantee certification) ..."20 This timeframe is largely
consistent with the 42-51 week (9.7-11.7 month) timeframe estimate presented by the EPA
in the draft TSD.
In addition, FTI provided information on a range of SNCR cost per ton based on
installations from 2010 to 2015 on non-EGU sources, stating that "these recent examples
show NOx reduction cost effectiveness in the range of $2,200 to $2,900 per ton of NOx
removed on an annual basis."21 FTI's "Figure l"22 also provided a chart of cost effectiveness
($/ton) versus unit size (mmBTU/hr) for both annual and ozone season NOx. A log fit of the
ozone season curve shows cost effectiveness in the range of approximately $2,000 to
approximately $6,500 per ton of ozone season NOx removed, with installations tending to
be more expensive for smaller unit sizes. Although FTI's estimates are based on different
interest rates and capital investments than our estimates, they are worthwhile to note in
comparison to our stated estimate of $1,300 to $2,700 per ton of NOx removed on an ozone
season basis.
5 Conclusion
The above preliminary analysis performed by the EPA indicates that uncertainty exists
regarding whether significant aggregate NOx mitigation is achievable from non-EGU point
sources by the 2017 ozone season. Reducing this uncertainty requires further
understanding of potentially available control measures that could have annualized costs of
$3,400 per ton or less. In addition, further implementation of the recommendations in the
Appendices to this TSD, the extent of which as determined by the EPA to be needed, may
also reduce our uncertainty regarding the credibility of data for control measures included
in future non-EGU NOx control strategy efforts. Please note that while the information in
these Appendices supports our conclusion regarding whether significant aggregate NOx
mitigation is achievable from non-EGU point sources by the 2017 ozone season, this final
TSD is making no conclusions about the recommendations for further improvements.
While a number of source groups with control options were identified, the EPA did not
further examine control options above $3,400 per ton, consistent with the range analyzed
for EGUs in the proposed and final rules and with what the EPA has identified in previous
transport rules as highly cost-effective. A number of source groups were identified at a cost
level of $3,400 per ton or less, however the EPA believes several of these source groups
may not be significant. Of the remaining source groups, a variety of factors indicated the
ability for control technology to be installed and operational in time for the 2017 ozone
20 EPA-HQ-OAR-2015-0500-0356, page 3.
21 EPA-HQ-OAR-2015-0500-0356, page 7.
22 EPA-HQ-OAR-2015-0500-0356, page 6.
22
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season seemed unlikely, with an overarching consideration being that non-EGUs of any
type that are not currently required to monitor and report in accordance with 40 CFR Part
75 will require additional time for implementation relative to EGUs that are currently
equipped with Part 75 monitoring and reporting. These added timing considerations on the
non-EGU sources make installation of controls by the 2017 timeframe established in this
rule less likely and more uncertain for industrial sources.
With all of these factors being considered, the limited available information points to an
apparent scarcity of non-EGU reductions that could be accomplished by the beginning of
the 2017 ozone season. As noted in the proposed and final rule, this conclusion has led the
EPA to focus the final FIPs on EGU reductions. Both the proposal and the final rule
acknowledge that this may not be the full remedy that is ultimately needed to eliminate an
upwind state's significant contribution to nonattainment or interference with maintenance
of the 2008 ozone NAAQS (or, for that matter, the 2015 ozone NAAQS) in other states.
Emissions reductions from the non-EGU categories discussed above may be necessary,
though on a longer timeframe than the 2017 compliance deadline being finalized in this
rulemaking. The EPA intends to explore this question further in future ozone transport
rulemakings.
23
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May 2014
Update of NOx Control Measure Data in the
CoST Control Measure Database for Four
Industrial Source Categories:
Ammonia Reformers, NonEGU Combustion
Turbines, Glass Manufacturing, and Lean Burn
Reciprocating Internal Combustion Engines
Final Report
Prepared for
Larry Sorrels
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Air Economics Group
Research Triangle Park, NC 27711
Prepared by
RTI International
3040 E. Cornwallis Road
Research Triangle Park, NC 27709
RTI Project Number 0212979.002.002
HRTI
INTERNATIONAL
-------
RTI Project Number
0212979.002.002
Update of NOx Control Measure Data in the
CoST Control Measure Database for Four
Industrial Source Categories:
Ammonia Reformers, NonEGU Combustion
Turbines, Glass Manufacturing, and Lean Burn
Reciprocating Internal Combustion Engines
Revised Draft Report
October 2014
Prepared for
Larry Sorrels
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Air Economics Group
Research Triangle Park, NC 27711
Prepared by
RTI International
3040 E. Cornwallis Road
Research Triangle Park, NC 27709
RTI International is a trade name of Research Triangle Institute.
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CONTENTS
Section Page
1 Introduction 1-1
2 Ammonia Reformers Sector 2-1
2.1 Recommended Deletions 2-2
2.2 Recommended Additions 2-2
2.3 Recommended Changes 2-3
2.4 Other Comments 2-5
3 Combustion Turbines 3-1
3.1 Recommended Del eti on s 3-2
3.2 Recommended Additions 3-2
3.2.1 Catalytic Combustion; Gas Turbines—Natural Gas
(NCATCGTNG) 3-3
3.2.2 EMx and Water Injection; Gas Turbines—Natural Gas
(NEMXWGTNG) 3-4
3.2.3 EMx and Dry Low NOx Combustion; Gas Turbines—Natural Gas
(NEMXDGTNG) 3-8
3.3 Recommended Changes 3-9
3 3 I Water Injection; Gas Turbines—Natural Gas (NWTINGTNG) 3-10
3.3.2 Steam Injection; Gas Turbines—Natural Gas (NSTINGTNG) 3-11
3.3.3 Dry Low NOx Combustion; Gas Turbines—Natural Gas
(NDLNCGTNG) 3-12
3.3.4 SCR and Water Injection; Gas Turbines—Natural Gas
(NSCRWGTNG) 3-13
3.3.5 SCR and Steam Injection; Gas Turbines—Natural Gas
(NSCTSGTNG) 3-16
3.3.6 SCR and Dry Low NOx Combustion; Gas Turbines—Natural Gas
(NSCRDGTNG) 3-17
3.3.7 Water Injection; Gas Turbines—Oil (NWTINGTOL) 3-19
in
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3.3.8 SCR and Water Injection; Gas Turbines—Oil (NSCRWGTNG) 3-20
3.3.9 Water Injection; Gas Turbines—Jet Fuel (NWTINGTJF) 3-22
3.3.10 SCR and Water Injection; Gas Turbines—Jet Fuel (NSCTWGTJF).... 3-22
3.3.11 Applicable Control Measures for Gas Turbine SCCs 3-22
3.4 Example Emission Limits for NonEGU Combustion Turbines 3-26
3.5 References 3-26
4 Glass Manufacturing Sector 4-1
4.1 Introduction 4-1
4.2 Example NOx Regulatory Limits 4-1
4.2.1 Wisconsin 4-1
4.2.2 New Jersey 4-1
4.2.3 New York 4-1
4.3 Recommended Additions 4-1
4.4 Recommended Changes 4-3
4.5 Recommended Deletions 4-5
4.6 Updates to Source Classification Codes 4-5
4.7 References 4-7
5 Lean Burn Engines.. 5-1
5.1 Literature Search 5-1
5.2 Document Review 5-2
5.3 Low Emission Combustion (LEC) (NLECICENG) 5-3
5.4 Layered Combustion (LC), 2 Stroke (NLCICE2SNG) 5-5
5.5 Layered Combustion (LC), Large Bore, 2 Stroke, Low Speed
(NLCICE2SLBNG) 5-7
5.6 Air to Fuel Ratio Controller (AFRC) (NAFRCICENG) 5-9
5.7 SCR (for 4 Stroke Natural Gas Engines) (NSCRICE4SNG) 5-10
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5.8 SCR (for Diesel Engines) (NSCRICEDS) 5-12
5.9 Applicable SCCs for Lean Burn Engine Control Measures 5-14
Appendixes
A Ammonia Reformers A-l
B Combustion Turbines B-l
C Glass Manufacturing .C-l
D Lean Burn Engines D-l
E Notes Provided Here to EPA Questions on Lean Burn RICE E-l
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LIST OF TABLES
Number Page
2-1 Applicable SCCs for the Ammonia Production Industry 2-4
2-2 RACT NOX Limits for ICI Natural Gas Boilers 2-5
3-1 Summary of Cost Effectiveness and Supporting Data for Catalytic Combustion 3-4
3-2 Summary of Cost Effectiveness and Supporting Data for EMx Plus Water
Injection 3-7
3-3 Summary of Cost Effectiveness and Supporting Data for EMx Plus Dry Low
NOx Combustion 3-8
3-4 Summary of Cost Effectiveness and Supporting Data for DLN Combustion 3-13
3-5 Summary of Cost Effectiveness and Supporting Data for SCR Plus Water
Injection 3-15
3-6 Summary of Cost Effectiveness and Supporting Data for SCR Plus Steam
Injection (SI) 3-17
3-7 Summary of Cost Effectiveness and Supporting Data for SCR Plus DLN
Combustion 3-18
3-8 Summary of Cost Effectiveness and Supporting Data for SCR Plus Water
Injection (WI) for Oil-Fired Turbines 3-21
3-9 Recommended Control Measures for Gas Turbine SCCs 3-23
3-10 NOx Emissions Limits for NonEGU Combustion Turbines in New York 3-26
4-1 Summary of Cost Effectiveness and Supporting Data for Recommended
Additions 4-2
4-2 Summary of Cost Effectiveness and Supporting Data for Recommended
Additions 4-5
4-3 Applicable SCCs for the Glass Manufacturing Industry 4-6
5-1 LEC for Natural Gas Lean Burn Engines 5-4
5-2 LC for Natural Gas Lean Burn Engines, 2-stroke 5-6
5-3 LC for Natural Gas Lean Burn Engines, Large Bore 2-stroke 5-8
5-4 AFRC for Natural Gas Lean Burn Engines 5-9
5-5 SCR for Natural Gas Lean Burn Engines, 4-stroke 5-11
5-6 SCR for Diesel Lean Burn Engines—Assumptions 5-13
5-7 Potential Reciprocating Engine SCCs to Add to the CMDB and Applicable
Control Measures 5-15
5-8 Recommended New Control Measures to Associate With Lean Burn
Reciprocating Engine SCCs in the CMDB 5-17
5-9 Recommended Control Measure Deletions From SCCs in the CMDB 5-18
5-10 NOx Control Requirements for RICE in Pennsylvania 5-21
5-11 Characteristics of NOx Emissions and Controls for RICE 5-21
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SECTION 1
INTRODUCTION
The U.S. Environmental Protection Agency (EPA) Health and Environmental Impacts
Division (HEID) has developed the Control Strategy Tool (CoST) to support national- and
regional-scale multipollutant air quality modeling analyses. CoST allows users to estimate the
emissions reductions and costs associated with future-year emission control strategies, and then
to generate emission inventories that reflect the effects of applying the control strategies. The
tool uses EPA HEID's Control Measures Database (CMDB) to develop control strategies and
provides a user interface to that database. The CMDB is a relational database that contains
information on an extensive set of control measures for point sources, nonpoint sources, and
mobile sources. Information contained in the database includes descriptions of the measures,
control efficiencies for the pollutants affected, costs of control, and the types of sources or
processes to which the control measures can be applied. The database includes robust cost
equations to determine engineering costs for some control measures that take into account how
control costs vary with respect to variables for the source such as unit size or flow rate. The
database also includes simple cost factors for all source types in terms of dollars per ton of
pollutant reduced that can be used to calculate the cost of the control measure if the applicable
source variable data are unavailable or no equation has been developed.
This report presents the results of an effort to review and enhance the CMDB with new and/or
updated NOx control measure data for the following four industrial source categories: ammonia
reformers, combustion turbines (nonEGU), glass manufacturing, and lean burn reciprocating
internal combustion engines. Section 2 of this report describes the procedures used to locate
more recent data than that currently in the CMDB for control measures applicable to ammonia
reformers. Section 2 also identifies the source of the new data, describes any modifications to the
assumptions or procedures in the referenced analyses needed to make the results consistent with
results for other control measures in the database (such as operating hours for determination of
total annual costs), and describes the specific recommended changes or additions to the database.
Sections 3 through 5 of this report provide similar details for combustion turbines, glass
manufacturing, and lean burn reciprocating internal combustion engines, respectively. Appendix
A presents all of the records for ammonia reformer control measures in each of the CMDB tables
showing their content after making the recommended revisions described in the report.
Appendixes B through D provide comparable tables for the combustion turbine, glass
manufacturing, and lean burn reciprocating internal combustion engine (RICE) source
categories, respectively. Appendix E provides answers to questions on lean-burn RICE NOx
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emissions and available control measures. It should be noted that these revisions and updates
will improve the accuracy and quality of NOx non-EGU control strategy and cost analyses for
EPA rulemakings.
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SECTION 2
AMMONIA REFORMERS SECTOR
The control measures database includes the following NOx emissions control measures
for ammonia reformers:
¦ Oxygen trim and water injection,
¦ Low NOx burners and flue gas recirculation,
¦ Selective non-catalytic reduction (SNCR),
¦ Selective catalytic reduction (SCR), and
¦ Low NOx burners.
In order to update the existing control measures database. a lilcialuic search was
conducted using the following terms:
¦ reformer
¦ cost
¦ "NOx" or "nitrogen oxide"
¦ "Low NOx burner" or "LNB"
¦ "Flue gas recirculation" or "FGR"
¦ oxygen trim
¦ water injection
¦ "Selecth e catalytic reduction" or "SCR"
¦ "Selective non catalytic reduction" or "SNCR"
¦ emission reduction
¦ control efficiency
Due to the use of SCR and SNCR to control NOx emissions and the fact that ammonia is
used in the operation of SCR and SNCR, the literature search resulted in NOx reductions on
processes other than ammonia production.
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In order to focus on ammonia production, a focused internet search for operating permits,
BACT analyses, and NOx controls was conducted using the 22 ammonia production facilities in
the United States.
As a result of the following facts, most of the internet search results included NOx
reductions from the production of nitric acid production instead of ammonia production:
¦ The NOx emissions from nitric acid production are covered by a New Source
Performance Standard (NSPS) codified as Subpart G and Subpart Ga of Pan 60
¦ Nitric acid facilities covered by the NSPS are required to install NOx continuous
emission monitoring systems (CEMS).
¦ Many nitric acid facilities use SCR to control NOx emissions.
¦ Many ammonia production facilities are co-located with nitric acid production
facilities.
The internet search resulted in one new NOx reduction project, which was the result of a
voluntary agreement between Terra Nitrogen and the Indian Nations Council of Governments to
install "ultra-low NOx burner technology to an existing ammonia reformer [and] reduce the
unit's NOx emissions by approximately 60% at a projected capital cost of two million dollars."
The existing ammonia reformer is located at Terra Nitrogen, L.P., Verdigris Plant in Claremore,
Oklahoma.
Based on information known to EPA and collected for this report, Low NOx burner
technologies are known and demonstrated control techniques for ammonia reformers.
The following sections outline the deletions, additions, changes, and other comments
recommended for the CMDB in relation to NOx emissions from ammonia reformers.
2.1 Recommended Deletions
No deletions are recommended.
2.2 Recommended Additions
The only addition to the CMDB is to add the following reference: Tulsa Metropolitan
Area 8-Hour Ozone Flex Plan: 2008 8-O3 Flex Program. Prepared by Indian Nations Council of
Governments (INCOG), 201 W. 5th Street, Suite 600, Tulsa, OK 74103. March 6, 2008.
http://www.epa.gov/ozoneadvance/pdfs/Flex-Tulsa.pdf.
This addition is shown in Appendix A as Table A-l.
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2.3 Recommended Changes
Updates to costs and Efficiencies.
Changes to one record (LNB applied to large source types) are recommended to reflect
the new reference dated March 6, 2008.
Using the new reference and a reference already contained in the CMDIi. I he following
assumptions were made:
¦ NOx reductions of 425 tons per year1
¦ Capital cost of $2 million1
¦ Maintenance costs are 2.75% of capital costs
¦ Equipment life of 10 years
¦ Interest rate of 7%
¦ Capital recovery factor of 0.1424
The resulting annual costs are $339,800 and the cost effectiveness is $800 per ton of NOx
reduction (both in 2008 dollars). The capital to annual cost ratio is 5.9.
The previous entry showed a cost effectiveness of $650 per ton of NOx reduction (in
1990 dollars) and a capital to annual cost ratio is 5.5. The changes are included in Appendix A as
Table A-2 and Table A-3. Changes are indicated by red, italic text.
Updates to Source Classification Codes.
The U.S. Environmental Protection Agency (USEPA) developed the Source
Classification Code (SCC) system, which assigns an eight digit code to each emission unit based
on the general criteria pollutant emission point type, the major industry group, specific industry
group, and specific process unit/fuel combination. The system allows similar emission points to
be grouped together for analyses.
For ammonia reformers, there are seven applicable SCCs, as shown in Table 2-1.
1 Indian Nations Council of Governments (INCOG), 2008: Indian Nations Council of Governments (INCOG),
"Tulsa Metropolitan Area 8-Hour Ozone Flex Plan: 2008 8-03 Flex Program," March 6, 2008. Downloaded from
http://www.epa.gov/ozoneadvance/pdfs/Flex-Tulsa.pdf.
2 U.S. Environmental Protection Agency. Alternative Control Techniques Document— NOx Emissions from
Process Heaters (Revised), document EPA-453/R-93-034, dated September 1993.
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Table 2-1. Applicable SCCs for the Ammonia Production Industry
SCC
SCC1
SCC3
SCC6
SCC8
30100305
Industrial Processes
Chemical
Manufacturing
Ammonia Production
Feedstock
Desulfurization
30100306
Industrial Processes
Chemical
Manufacturing
Ammonia Production
Primary Reformer:
Natural Gas Fired
30100307
Industrial Processes
Chemical
Manufacturing
Ammonia Production
Primary Reformer: Oil
Fired
30100308
Industrial Processes
Chemical
Manufacturing
Ammonia Production
Carbon Dio\nle
Regenerator
30100309
Industrial Processes
Chemical
Manufacturing
Ammonia Production
Condensate Stripper
30100310
Industrial Processes
Chemical
Manufacturing
Ammonia Production
Storage and Loading
Tanks
30100399
Industrial Processes
Chemical
Manufacturing
Ammonia Production
Other Not Classified
In an analysis of NOx emissions for the Ozone Transport Region in 2011, four of the
SCCs in Table 2-1 were identified. These SCCs are 30100306, 30100307, 30100310, and
30100399. Only SCCs 30100306 and 30100307 are associated with ammonia reformer NOx
controls in the current CMDB.
The known control techniques for ammonia reformers are typically used for point
emission sources, such as stacks. Emissions from SCC 30100310 are not typically vented, so
capture and control of these emissions is likely not feasible. Therefore, no changes related to
SCC 301003 10 are recommended lor the CMDB.
For 1 Ik- purposes of this analysis, SCC 30100399 is assumed to include combustion
emissions from gaseous fuels other than natural gas. Therefore, all control techniques that are
applicable to natural gas fired ammonia reformers are assumed to also apply to SCC 30100399.
Also, the cost to control NOx emissions from gaseous fuels is assumed to be comparable to the
cost to control NOx emissions from natural gas. Therefore, the costs related to those control
techniques are assumed to apply to SCC 30100399.
The applicable SCC from Table 2-1 was added to the Description field for each control
technique in Table A-2 of Appendix A. SCC 30100306 was already included in the table; SCCs
30100305, 30100307, and 30100399 were added, where appropriate. Changes are indicated by
red text.
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2.4 Other Comments
Control measures used by ICI boilers. Review of NOx control measures used for
boilers was not included in this analysis. However, many of the SCR costs in the CMDB for
natural gas fired ammonia reformers are based on SCR costs for
Industrial/Commercial/Institutional (ICI) Boilers using Process Gas. No SCR costs specific to
ammonia reformers were noted in the CMDB.
At a later time, it may be pertinent to review recent final ICI Boilers ivuulalions or other
sources for potential updates to the cost of SCR on ammonia reformers. The final major source
NESHAP for ICI Boilers was promulgated on January 31, 2013 and the final area source
NESHAP for ICI Boilers was promulgated on February 1, 2013.
Potential NOx limits for ammonia reformers based on boiler NOx limits. According
to NOx Reasonably Acceptable Control Technology (R.ACT), the states of New Jersey and New
York have established emission limits for ICI Natural Gas Boilers (greater than 100 million BTU
per hour) that could be applicable to natural gas ammonia reformers. These R.ACT limits are
shown in Table 2-2.
Table 2-2. RACT NOx Limits for ICI Natural Gas Boilers
State
Boiler Size
Limit (lb NOx/MMBTU)
Effective Date
New Jersey3
>100 MMBTl
0.10
Already in effect
New York
>100 MMBTl and :5o \1\1l 5TIJ
0.06
7/1/14
New York
>250 MM 1 i l l
0.08
7/1/14
a The limil also applies in oilier iih.Iiiv.vi heal exchangers.
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SECTION 3
COMBUSTION TURBINES
The CMDB includes the following NOx emissions control measures for Combustion
Turbines:
¦ Water injection for natural gas-fired turbines (achieves 76 percent reduction)
¦ Steam injection for natural gas-fired turbines (achieves 80 percent reduction)
¦ Low NOx Burners for natural gas-fired turbines (achieves 84 percent reduction)
¦ SCR on natural gas-fired turbines that also have water injection (achieves 95 percent
reduction)
¦ SCR on natural gas-fired turbines that also have steam injection (achieves 95 percent
control)
¦ SCR on natural gas-fired turbines that also have low NOx burners (achieves 94
percent reduction)
¦ Water injection for oil-fired turbines (achieves 68 percent reduction)
¦ SCR on oil-fired turbines that also ha\ e ualer i njection (achieves 90 percent
reduction)
¦ Water injection for jet fuel-fired turbines (achieves 68 percent reduction)
¦ SCR on jet fuel-fired turbines that also have water injection (achieves 90 percent
reduction)
¦ Water injection lor aeroderivative turbines (achieves 40 percent reduction)
All of the cost data are in 1990 dollars, except the costs of water injection for
aeroderiv ali\ e turbines, which are in 2005 dollars. In addition, all of the costs are based on
estimated operation for 8,000 hr/yr, except the costs of water injection for aeroderivative
turbines, which are for intermittently operated units. The costs in 1990 dollars are based
primarily on analyses in EPA's 1993 ACT document for NOx Emissions from Stationary Gas
Turbines (EPA, 1993). Capital and annual cost equations are provided for all of the controls
except those for jet fuel-fired turbines and water injection for aeroderivative turbines.
Literature search. In order to update the existing CMDB, a literature search was
conducted for articles and papers published since 2008. In addition, an internet search was
conducted for BACT analysis reports and control technology reports prepared for federal and
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state agencies and RPOs. The literature search did not identify any documents with cost data, but
the internet search identified the documents listed in Section 3.5 of this report.
Changes to CMDB. The following sections outline the deletions, additions, and other
changes recommended for the CMDB in relation to NOx emissions from Combustion Turbines.
All cost data and calculations are in an Excel Worksheet (RTI, 2014). Copies of the CMDB
tables with recommended revisions to the records for combustion turbine controls are provided
in Appendix B.
The coefficient of determination (R2) is 1.0 for many of the regression equations
presented in sections 3.2 and 3.3. The R2 value is exactly 1.0 in cases where the analysis was
based on only two data points; these cases are noted in the discussions for the particular control
measure. In other cases, actual R2 values greater than 0.995 have been rounded to 1.0. These
high values likely are due to the fact that available data for most control measures are from a
single source, and those sources may have already developed a correlation and then picked
specific data points from that correlation for presentation in their documentation.
3.1 Recommended Deletions
RTI recommends deleting the record lor w tiler injection for aeroderivative turbines
because the estimated costs are for combustion turbines that operate on a limited and intermittent
basis (i.e., peaking EGUs). In principle, data for small EGU combustion turbines would be
acceptable for estimating costs of control measures for nonEGUs. However, the limited
operation of peaking units is inconsistent with the assumed operating time of about 8,000 hr/yr
for all of the other nonEGU combustion turbine control measures in the database. For several
SCCs that are currently associated with this control measure in the CMDB we are recommending
applying other existing control measures, as discussed in Section 3.3.11 of this report.
The CMDB also currently applies several gas turbine control measures to reciprocating
internal combustion engine SCCs and to gas turbine SCCs for evaporative losses from fuel
storage and delivery systems. We recommend deleting these applications of the gas turbine
control measures, as discussed in Section 3.3.11 and Section 5.9 of this report.
3.2 Recommended Additions
There are 3 control technique additions for emerging technologies to be added to the
CMDB; these additions include:
¦ Catalytic Combustion; Gas Turbines—Natural Gas;
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¦ EMx and Water Injection; Gas Turbines—Natural Gas;
¦ EMx and Dry Low NOx Combustion; Gas Turbines—Natural Gas.
3.2.1 Catalytic Combustion; Gas Turbines—Natural Gas (NCATCGTNG)
Catalytic combustion is a flameless process that allows fuel oxidation to occur at
temperatures approximately 1800°F lower than those of conventional combustors (OSEC, 1999).
Lower temperatures are desirable because NOx emissions levels are strongly correlated with
temperature. One design that has been commercialized is the Xonon™ combustor (now called K-
Lean™). In the Xonon combustor, a small amount of fuel is burned in a low temperature pre-
combustor. Additional fuel is then mixed with the air and combustion gases from the pre-
combustor and passed through a catalyst module. The catalyst promotes a flameless reaction
between some of the fuel and oxygen. The gases then enter a burnout zone in which the
remaining fuel burns. The maximum temperature in the system is between 2300°F and 2700°F.
In addition to low NOx emissions, the catalytic combustor generates very little CO emissions.
(Peltier, 2003; CARB, 2004; Leposky, 2004; Kawasaki, 2010; Quackenbush, 2012)
Since 1999 at least six Xonon combustors ha\ e been installed; all are 1.4 MW units
(CARB, 2004; Kawasaki, 2010; Quackenbush, 2012). Testing of four of the operating Xonon
combustors has shown NOx emissions less than 3 parts per million by volume on a dry basis
(ppmvd) at 15% oxygen, and permit limits range from 3 ppmvd to 20 ppmvd at 15% oxygen
(CARB, 2004; Quackenbush, 2012). Several companies have conducted research into developing
larger catalytic combustors and other types of designs, but no information was found indicating
that such units have been commercialized (CARB, 2004; Leposky, 2004; Cybulski, 2006).
Although one type of catalytic combustor has been commercialized, we recommend
considering catalytic combustion as an emerging technology in the CMDB because so few units
are in operation, and they are all only one size. In addition, as of 1999, issues with catalytic
combustors include the need for the air-fuel mixture to have completely uniform temperature,
composition, and velocity profile to assure effective use of all the catalyst and to prevent damage
to the substrate from high temperatures. Also the catalyst durability is uncertain (OSEC, 1999).
The recommended costs are based on costs presented in a report by Onsite Sycom Energy
Corporation (OSEC, 1999). The only change we made to the OSEC costs was to calculate capital
recovery using an interest rate of 7 percent instead of 10 percent; this change makes the capital
recovery costs consistent with guidance in Circular A-4 from the Office of Management and
Budget. Table 3-1 summarizes the recommended cost effectiveness and capital to annual cost
ratios for implementing the catalytic combustion NOx control technology. With an outlet
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concentration of 3 ppmvd, catalytic combustion achieves an average reduction of 98 percent
relative to uncontrolled conventional diffusion combustion.
Table 3-1. Summary of Cost Effectiveness and Supporting Data for Catalytic Combustion
Turbine
Output, MW
Cost
Year
Uncontrolled NOx
Emissions
Avg. ppmvd tpy
Outlet
- Concentration,
ppmvd
Cost
Effectiveness,
$/ton NOx
Capital to
Annual Cost
Ratio
Small (5.2)
1999
150
<365
3
920
1.7
Small (26.3)
1999
130
>365
3
670
1.2
Large (170)
1999
210
>365
3
370
0.7
Based on regression of the data in the analysis, the best fit trend lines are represented by
the following equations for the uncontrolled scenario:
Total capital investment (1999 dollars) = 20668 x (MMBtu/hr) A ° '7 (R2=1.0)
Total annual cost (1999 dollars) = 4254.2 x (MMBtu/hr) A 0 82 (R2=1.0)
For all but the smallest turbines, the incremental cost of catalytic combustors relative to
conventional combustors is less than the incremental cost of DLN combustion versus
conventional combustors. Thus, there are no incremental capital costs for catalytic combustion
relative to conventional combustion. However, there are incremental annual costs because the
cost of catalyst replacement is high A best fit equation for incremental catalytic combustion total
annual costs relative to a RACT baseline of DLN combustion is:
Total annual cost (1999 dollars) = 743.22 x (MMBtu/hr) + 54105 (R2=1.0)
3.2.2 EMx and Water Injection; Gas Turbines—Natural Gas (NEMXWGTNG)
Like SCR, EMx™ (formerly called SCONOX™) is a post-combustion catalytic NOx
reduction technology. EMx uses a precious metal catalyst and a NOx absorption/regeneration
process to convert CO and NOx to C02, H20, and N2. NOx reacts with the potassium carbonate
absorbent coating the surface of the oxidation catalyst in the EMx reactor, forming potassium
nitrites and nitrates that are deposited onto the catalyst surface. Each segment, or "can," within
the reactor becomes saturated with potassium nitrites and nitrates over time and must be
desorbed. Regeneration is accomplished by isolating the can via stainless steel lovers and
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injecting hydrogen diluted with steam. Hydrogen is generated onsite with a small reformer that
uses natural gas and steam as input streams. The hydrogen concentration of the reformed gas is
typically 5 percent. Hydrogen and carbon dioxide react with the potassium nitrites and nitrates to
form N2 and H20 and to regenerate the potassium carbonate for another absorption cycle.
(OSEC, 1999; CARB, 2004)
At least 8 EMx systems at 6 facilities have been installed on combustion turbines with
capacities up to 45 MW. Permit limits at most of these facilities have been set al 2 5 ppm vd for
gas-fired operation. EPA has certified it as "demonstrated in practice" LAER-le\ el technology
that reduces NOx to less than 5 ppmvd. The operating range of the catalyst is 300 to 700°F,
which means the technology is not applicable for simple cycle turbines. The vendor for the
technology has indicated that these systems also reduce carbon monoxide emissions to
undetectable levels (essentially 100 percent reduction), reduce volatile organic compound
emissions by greater than 90 percent, and reduce fine particulate matter emissions by 30 percent
(EmeraChem, 2004). Test data documenting these reductions are not available. For the purposes
of the CMDB database, we recommend that this control measure be listed as an emerging
technology (rather than known) because its use has been limited to only a few small turbines.
The recommended costs for EMx in the combined EMx/water injection control measure
are based on costs presented in a 2008 cost estimate prepared by EmeraChem Power for the Bay
Area Air Quality Management District (ECP, 2008). For the purposes of developing 2008 cost
inputs for the CMDB, we made the following changes to the data and assumptions used in the
ECP analysis:
¦ Increased the indirect cost for engineering from $200,000 to $255,000 for the 50 MW
turbine. ECP's documentation indicated that this cost (as well as most of the other
direct installation and indirect costs) would be the same as for an SCR system on the
same turbine. The reported cost of $200,000 was inconsistent with this statement.
¦ Increased the contingencies cost for the 50 MW turbine from $76,486 to $244,101.
This change makes the cost consistent with ECP's statement that the cost for
contingencies is estimated to be equal to 5 percent of the total purchased equipment
cost, excluding the cost of the precious metals in the catalyst, sales taxes, and freight.
¦ Added a cost for the performance loss due to back pressure from the EMx system for
both turbines. ECP estimated the loss to be 0.5 percent, which is consistent with the
estimate in the 1993 ACT for SCR and the estimate OSEC used in a cost analysis for
SCONOx (EPA, 1993; OSEC, 1999). However, the ECP analysis did not include a
corresponding dollar amount for this element.
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¦ Changed the operating hours from 7,884 hr/yr to 8,000 hr/yr. This change also had a
small effect on the annual costs for utilities.
¦ Added costs for natural gas to generate steam for the 50 MW turbine using the same
procedures presented in the ECP analysis for the 180 MW turbine. ECP did not report
the basis for the amount of steam needed for the 180 MW turbine. Therefore, we
plotted the reported steam consumption versus turbine size for this unit and for two
turbines identified in a CARB analysis (CARB, 2004). We calculated the quantity of
steam needed for EMx on the 50 MW turbine using the regression equation from this
plot. Note that the unit cost for natural gas is $9.75/1000 scf. This was a reasonable
annual average cost in 2008, but it would be much too high for an analysis in 2014.
¦ Deleted the credit for recovery of precious metals in the spent catalyst because the
cost for replacement catalyst considers only the difference between the total purchase
price minus the value of the recovered material.
¦ Estimated the annualized cost of replacement catalyst (both the non-precious metal
substrate and the precious metal coating) using the future worth factor, whereas the
cost in the ECP analysis was the purchased cost divided by the 10-year replacement
interval.
¦ Estimated the cost of annual catalyst cleaning based on the average if data reported by
CARB (CARB, 2004) plus the amounts reported by ECP. Although ECP reported a
slightly higher cleaning cost for the 180 M W turbine than for the 50 MW turbine, an
analysis of all the cleaning data showed no correlation with turbine size. Thus, we
used the average of all reported costs for both turbines.
¦ Revised the indirect annual cost for administrative charges. ECP estimated that these
costs are the same as for an SCR system on the same turbines. We factored the cost as
2 percent of the TCI for the applicable EMx systems, which is consistent with the
approach for all control devices in the EPA Control Cost Manual. This resulted in
slightly higher costs.
¦ Increased the indirect costs for insurance, property tax, and capital recovery for both
turbines because the ECP analysis excluded the precious metal costs from the TCI
used in these calculations.
¦ Calculated capital recovery using an interest rate of 7 percent instead of 10 percent.
The capital costs for water injection in the combined EMx/water injection control
measure were estimated in 1999 dollars using the regression equation for the water injection
control measure (see Section 3.3.1) and then scaled to 2008 dollars using the Chemical
Engineering Plant Cost Index (CEPCI). Total annual costs for water injection were first
estimated in 1999 dollars using the regression equation for the water injection control option. On
average, 25 percent of these costs were estimated to be for indirect costs that are factored from
3-6
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the system capital cost, and the remaining 75 percent is for direct annual costs and overhead. To
estimate the total annual costs for water injection in 2008, the indirect costs were scaled from the
1999 estimate using the CEPCI, and the direct annual costs and overhead were assumed to be the
same as in 1999.
Table 3-2 summarizes the recommended cost effectiveness and capital to annual cost
ratios for implementing the EMx plus water injection NOx control measure. With an outlet
concentration of 2 ppmvd, this control measure achieves an average reduction ofpercent
relative to uncontrolled conventional diffusion combustion.
Table 3-2. Summary of Cost Effectiveness and Supporting Data for EMx Plus Water
Injection
Uncontrolled NOx
Emissions Incremental Cost
EMx Outlet Cost Capital to Relative to
Turbine Output, Cost Avg Concentration, Effectiveness, Annual RACT Baseline
MW Year ppmvd tpy ppmvd S/ton NOx Cost Ratio of WI, $/ton NOx
Large (50-180) 2008 160a >365 2.0 2.760 3.1 6,810
"Uncontrolled concentrations were not reported in the referenced analysis. Thus, the value used in this analysis is an
assumed average that results in the estimated 84 percent reduction for DLN combustion, as described in Section
3.3.3 of this report.
Based on regression of the data in the analysis, the best fit trend lines are represented by
the following power equations for the uncontrolled scenario (the R2 =1.0 for both equations
because there were only two data points in the analysis):
Total capital investment (2008 dollars) = 196928 x (MMBtu/hr) A 0 68
Total annual cost (2008 dollars) = 18747 x (MMBtu/hr) A 0 86
Best fit equations for incremental EMx costs relative to a RACT baseline of water
injection are:
Total capital investment (2008 dollars) = 156349 x (MMBtu/hr) A 0 68
Total annual cost (2008 dollars) = 17252 x (MMBtu/hr) A °-80
3-7
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3.2.3 EMx and Dry Low NOx Combustion; Gas Turbines—Natural Gas (NEMXDGTNG)
Table 3-3 summarizes the recommended cost effectiveness and capital to annual cost
ratios for implementing the EMx plus dry low NOx combustion control measure. With an outlet
concentration of 2 ppmvd, this control measure achieves an average reduction of 99 percent
relative to uncontrolled conventional diffusion combustion. For the same reasons noted in
Section 3.2.2, we recommend that this control measure be listed as an emerging technology in
the CMDB.
Table 3-3. Summary of Cost Effectiveness and Supporting Data for E]\lx Plus Dry Low
NOx Combustion
Uncontrolled Incremental
NOx Emissions Capital to Cost Relative to
Turbine Output,
MW
Cost
Year
Avg
ppmvd
tpy
EMx Outlet
Concentration,
ppmvd
Cost
Effectiveness,
S/ton NOx
Annual
Cost
Ratio
RACT Baseline
of DLN, $/ton
NOx
Small (4.2)
1999
134
<365
2.0
2.860
3.9
14,940
Small (23)
1999
174
>365
2.0
1.720
4.1
10,270
Large (170)
1999
210
>365
: (i
840
3.9
6,600
Large (50-180)
2008
o
>365
: (i
2,050
4.1
12,390
"Uncontrolled concentrations were not reported in the referenced analysis. Thus, the value used in this analysis is an
assumed average that results in the estimated 84 percent reduction for DLN combustion, as described in Section
3.3.3 of this report.
The recommended costs for EMx in 2008 dollars for the combined EMx/dry low NOx
combustion control measure are the same as in the estimate for the EMx/water injection control
measure described in Section 3.2.2. The recommended costs for EMx in 1999 dollars are based
on an analysis prepared by Onsite Sycom Energy Corporation (OSEC, 1999). For this analysis
the only changes we made to OSEC's analysis were to reduce the operating hours from
8,400 hr/yr to 8,000 hr/yr, which slightly reduced the energy penalty and utilities costs, and we
calculated the capital recovery factor using an interest rate of 7 percent instead of 10 percent.
Note that the total annual costs for natural gas (or purchased steam) are considerably lower in
this analysis than in the 2008 analysis because the unit cost of natural gas was considerably
lower in 1999.
The recommended total capital investment and total annual cost for dry low NOx
combustion in 1999 dollars for the combined EMx/dry low NOx combustion control measure are
the same as in the estimate for the dry low NOx combustion control measure alone as described
in Section 3.3.3. The recommended total capital investment for dry low NOx combustion in 2008
3-8
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dollars was estimated in 1999 dollars using the regression equation for the water injection control
measure (see Section 3.3.1) and then scaled to 2008 dollars using the CEPCI. The recommended
total annual costs for dry low NOx combustion consist of capital recovery plus the cost for parts
and repair; capital recovery costs in 2008 dollars were estimated by escalating the 1999 costs
using the CEPCI, and annual parts and repairs costs were assumed to be the same in 2008 as in
1999.
Based on regression of the data in both the 1999 and 2008 cost analyses, the Ix-sl fit trend
lines are represented by the following power equations for the uncontrolled scenario (the R2 =1.0
for the equations in 2008 dollars because there were only two data points in the analysis; R2 for
the equations in 1999 dollars round to 1.0 when only two significant figures are presented):
Total capital investment (1999 dollars) = 58237 x (MMBtu/hr) A 0 78
Total annual cost (1999 dollars) = 15004 x (MMBtu/hr) A 0 78
Total capital investment (2008 dollars) 120S92 x (MMBtu/hr) A 074
Total annual cost (2008 dollars) = 20041 x (MMBtu/hr) A °-80
Best fit equations for incremental EMx costs relative to a RACT baseline of DLN
combustion are:
Total capital investment (1999 dollars) = 65163 x (MMBtu/hr) A 0 72
Total annual cost (1999 dollars) = 13702 x (MMBtu/hr) A 0 76
Total capital investment (2008 dollars) = 156349 x (MMBtu/hr) A 0 68
Total annual cost (2008 dollars) = 17252 x (MMBtu/hr) A °-80
3.3 Recommended Changes
This section presents updated cost estimates for combustion turbine control measures that
are currently in the CMDB, and it describes the basis for such changes. These changes include
both more recent costs for some control measures as well as minor revisions to existing estimates
for other control measures. The changes affect both cost per ton values and equations.
3-9
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This section also identifies applicable SCCs for the new control measures described in
Section 3.2, and it identifies additional SCCs for which the control measures in this section are
applicable.
3.3.1 Water Injection; Gas Turbines—Natural Gas (NWTINGTNG)
Recommended updates to the costs for water injection are based on analyses in a report
prepared by OnSite Sycom Energy Corporation for the U.S. Department of Energy (OSEC,
1999). OSEC estimated costs for some of the same small turbine model sizes as in EPA's 1993
ACT document (4 MW and 23 MW). OSEC obtained water injection equipment costs in 1999
dollars. They then estimated total capital investment and total annual costs using the same
procedures as in the 1993 ACT document, and they concluded that 1999 costs for water injection
were essentially the same as the 1990 costs presented in the ACT document. Because the ACT
analysis included a greater number of models over a wider range of sizes, RTI recommends
continuing to use the cost data from the ACT analysis in the CMDB, except the cost year should
be updated from 1990 to 1999. RTI also recommends the four additional changes noted below.
Our second recommendation is to split the record for small sources into two records—
one for sources with uncontrolled emissions less than 365 tpy, and the other for emissions greater
than 365 tpy. The 2006 AirControlNET Documentation Report indicates that small sources are
turbines with design outputs up to 34.4 MW. Four model turbines in the ACT analysis have
outputs below this threshold. The two turbines with uncontrolled emissions <365 tpy have an
average cost effectiveness of $ 1,790/ton of NOx. The two turbines with uncontrolled emissions
>365 tpy have an average cost efllvli veness of $ 1,000/ton of NOx.
Our third recommendation is to revise the control efficiency for water injection from 76
percent to 72 percent. The 76 percent control level is the average reduction for all 6 model
turbines in the 1993 ACT analysis. Five of those models were guaranteed to reduce NOx
emissions to less than 42 ppmvd, while the sixth was guaranteed to meet 25 ppmvd. Although
water injection may be more effective on some combustion turbines than others, 42 ppmvd is the
generally accepted threshold. Thus, we think this threshold should be incorporated in the CMDB.
The average reduction of the 5 models in the 1993 ACT analysis with an outlet concentration of
42 ppmvd was 72 percent.
Our fourth recommendation is to use a capital to annual cost ratio of 2.4 in the new
record for small sources with uncontrolled emissions >365 tpy; this is the average value for the
two turbines in the ACT analysis in this size range. (The capital to annual cost ratio for the small
sources with uncontrolled emissions <365 tpy would remain at 3.1 because this is the average
3-10
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value for the two turbines in this size range; it is not clear why this value was applied for all
small sources in the current version of the CMDB.) The total annual costs in this calculation are
based on using a 7 percent interest rate in the calculation of capital recovery, instead of the 10
percent value in the 1993 ACT. Even if capital recovery was estimated using the 10 percent
interest rate, it is not clear how the 3.1 value was developed.
Our fifth recommendation is to revise the constants in the CMDB table of equations for
estimating capital and annual costs. Based on regression of the data in the 1993 ACT, the best fit
trend lines are represented by the following revised power equations for both uncontrolled and
RACT baseline scenarios:
Total capital investment (1999 dollars) = 27665 x (MMBtu/hr) A °-()9 (R2 =0.97)
Total annual cost (1999 dollars) = 3700.2 x (MMBtu/hr) A °-9- (R2=0.95)
3.3.2 Steam Injection; Gas Turbines—Natural Gas (NSTINGTNG)
The only available information on the cost of steam injection was in the 1999 report from
Onsite Sycom Energy Corporation (OSEC, 1999). OSEC discussed steam injection only in the
context of large GE Frame 7F turbines (170 M W). They noted that only the first such model,
operational in 1990 when the ACT analysis was being conducted, was equipped with steam
injection. All subsequent units (at least through 1999) were equipped with DLN combustion
technology.
Because the limited available information suggests that steam injection costs, like water
injection costs, were essentially the same in 1999 as in 1990, we recommend continuing to base
the steam injection costs on the results in the 1993 ACT, but update the cost year from 1990 to
1999. In addition, as for water injection, we recommend splitting the one record for small
sources into two records—one for sources with uncontrolled NOx emissions <365 tpy, and the
other for uncontrolled NOx emissions >365 tpy. This split results in average cost effectiveness
values of $ 1,690/ton of NOx for the small sources with uncontrolled NOx emissions
<365 tons/yr and $820/ton of NOx for the small sources with uncontrolled NOx emissions
>365 tons/yr. The capital cost to annual cost ratios also are slightly less than the current values in
the CMDB.
Based on regression of the data in the 1993 ACT, the best fit trend lines are represented
by the following revised power equations for both uncontrolled and RACT baseline scenarios:
3-11
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Total capital investment (1999 dollars) = 43092 x (MMBtu/hr) A 0 82 (R2=0.95)
Total annual cost (1999 dollars) = 7282 x (MMBtu/hr) A 0 76 (R2=0.96)
3.3.3 Dry Low NOx Combustion; Gas Turbines—Natural Gas (NDLNCGTNG)
Dry low NOx (DLN) combustion technology premixes air and a lean fuel mixture that
significantly reduces peak flame temperature and thermal NOx formation. In some cases, this
can be accomplished by using low NOx burners, but in other cases, the combustor design itself
differs as well as the burner design. For example, the DLN combustor volume is typically twice
that of a conventional combustor (OSEC, 1999). Therefore, we recommend revising the current
control technology name in the CMDB from "Low NOx Burners" to "Dry Low NOx
Combustion." In addition, the CM abbreviation should be changed from NLNBUGTNGto
NDLNCGTNG.
Recommended updates to the costs for DLN Combustion are based on analyses in a
report prepared by Onsite Sycom Energy Corporation for the U.S. Department of Energy (OSEC,
1999). OSEC estimated costs for some of the six turbines with design outputs ranging from
4 MW to 169 MW.
OSEC obtained installed equipment costs and annual repair costs in 1999 dollars from
three turbine manufacturers, but there are some uncertainties in the data. Although the reported
tabular summary indicates the equipment costs are incremental relative to the cost of a
conventional combustor, the text of the report states that the costs for 169 MW turbines are the
total cost to replace a conventional combustor (which may explain why the regression equation
for the capital costs is linear rather than a power function). Annual costs for parts and repair for
some of the turbines were proprietary for two of the small turbines and thus could not be
reported. As a result, the annual costs for those turbines are biased low. In addition, because parts
and repair costs were unavailable for the 169 MW turbine, OSEC assumed these costs could be
represented by the costs for the 23 MW turbine.
The only change we made to the assumptions and data reported by OSEC was to
calculate capital recovery using an interest rate of 7 percent instead of 10 percent.
Table 3-4 summarizes the recommended new cost effectiveness and capital to annual cost
ratios for implementing the DLN combustion NOx control technology. In addition to changing
these costs in the CMDB, we also recommend changing the control efficiency for DLN
combustion applied to small sources from 68 percent to 84 percent. The 84 percent level is
3-12
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currently used for large sources, and it is consistent with the efficiency for DLN combustion (or
low NOx burners) in the 1993 ACT. It appears the 68 percent entry was a data transcription error
because that is the control efficiency for water injection applied to oil-fired turbines.
Table 3-4. Summary of Cost Effectiveness and Supporting Data for DLN Combustion
Uncontrolled NOx
Emissions
Outlet
Cost
Capital to
Turbine
Cost
- Concentration,
Effectiveness,
Annual Cost
Output, MW
Year
Avg. ppmvd
tpy
ppmvd
$/ton NOx
Ratio
Small (4-23)
1999
152
<365
25
300
5.0
Large (170)
1999
210
>365
25
130
7.4
Based on regression of the data in both analyses, the best fit trend lines are represented by
the following revised equations for both uncontrolled and RACT baseline scenarios:
Total capital investment (1999 dollars) = 2860.6 x (MMBtu/hr) + 25427 (R2=1.0)
Total annual cost (1999 dollars) = 584.5 x (MMBtu/hr) A 0 96 (R2=0.95)
3.3.4 SCR and Water Injection; Gas Turbines—Natural Gas (NSCRWGTNG)
Recommended updates to the costs for SCR combined with water injection are based on
two sets of cost analyses. One set of costs is in 1999 dollars for three turbines ranging in size
from 4.2 MW to 161 MW (OSEC, 1999). The second is in 2008 dollars for two larger turbines
with design outputs of 50 MW and 180 MW (ECP, 2008). For SCR, the referenced analyses
estimated direct installation costs and indirect costs based on scaling from the purchased
equipment costs using standard factors as in the Control Cost Manual. Annual costs were
estimated for the same cost elements that were used in the SCR analysis in the 1993 ACT. Water
injection costs for the two smallest turbines in the 1999 analysis were estimated as described
above for the water injection control option. Water injection costs for the large turbines were not
estimated in the referenced analyses.
For the purposes of developing 1999 cost inputs for the CMDB, we made the following
changes to the data and assumptions used in the OSEC analysis:
¦ Increased the engineering cost for SCR for the 161 MW turbine from $100,000 to
$228,865. The revised value is equal to 10 percent of the purchased equipment cost,
which is consistent with the approach used for the smaller turbines. The report did not
explain why $100,000 was used instead of the factor.
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¦ Estimated performance penalty costs and electricity costs for the blower and pumps in
the ammonia injection system using operating hours of 8,000 hr/yr instead of
8,400 hr/yr.
¦ Calculated capital recovery for the SCR system using an interest rate of 7 percent
instead of 10 percent.
¦ Calculated annual catalyst replacement and disposal costs using a future worth factor
instead of a capital recovery factor.
¦ Estimated total capital investment and total annual costs for the lc-> I \I\V lurhine
using the regression equations for the water injection control option. (Maybe it would
be better to drop the large model from this analysis and just present 1999 costs for
small turbines and 2008 costs for large turbines.)
For the purposes of developing 2008 cost inputs for the CMDB, we started with the ECP
analysis for SCR costs and then made the following changes to the data and assumptions:
¦ Calculated the performance penalty for SCR using an electricity cost of $0.06/kwh
instead of $0.1/kwh and 8,000 hr/yr instead of 8,400 hr/yr. In addition, although it
appears that the referenced analysis assumed a performance loss equal to 0.5 percent
of the turbine's design output, the cited cost was significantly greater than it should
be for that percentage loss, even if the cited electricity cost and operating hours were
used in the calculation. We changed the cost to be consistent with the calculated
amount.
¦ Calculated capital recovery for the SCR system using an interest rate of 7 percent
instead of 10 percent.
¦ Estimated capital costs for water injection in 1999 dollars using the regression
equation for the water injection control option, and then scaled the costs to 2008
dollars using the CEPCI.
¦ Estimated total annual costs for water injection following the same procedure
described in Section 3.2.2 for the water injection portion of a combined water
injection and EMx control measure. Thus, the total annual costs for water injection
are the same in both control measures.
Table 3-5 summarizes the recommended new cost effectiveness and capital to annual cost
ratios values for implementing SCR plus water injection on natural gas-fired combustion
turbines. Table 3-5 also presents revised incremental costs of SCR relative to a RACT baseline
of water injection for the different categories of turbines. Note that the SCR outlet NOx level
was assumed to be 2.5 ppmvd in the ECP analysis, which results in an overall control efficiency
of 98 percent versus the 94 percent for the OSEC and ACT analyses.
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Table 3-5. Summary of Cost Effectiveness and Supporting Data for SCR Plus Water
Injection
Turbine
Output, MW
Cost
Year
Uncontrolled NOx
Emissions
SCR Outlet
Concentration,
ppmvd
Cost
Effectiveness,
$/ton NOx
Capital to
Annual
Cost Ratio
Incremental Cost
Relative to RACT
Baseline of WI,
$/ton NOx
Avg. ppmvd
tpy
Small (4.2)
1999
134
<365
9
2,790
3.0
5,840
Small (22.7)
1999
174
>365
9
1,370
2.9
3,130
Large (161)
1999
210
>365
9
1,070
1.5
l.ii'Ni
Large (50-180)
2008
o
>365
2.5
1,830
2.7
3.170
"Uncontrolled concentrations were not reported in the referenced analysis. Thus, the value used in this analysis is an
assumed average that results in the estimated 84 percent reduction for DLN combustion, as described in Section
3.3.3 of this report.
Based on regression of the data in both analyses, the revised best fit trend lines are
represented by the following power equations for both uncontrolled scenarios (R2=l for the 2008
costs because the analysis was based on only two data points):
Total capital investment (1999 dollars) = 62962 x (MMBtu/hr) A 0 ()6 (R2=1.0)
Total annual cost (1999 dollars) = 8590 x (MMBtu/hr) A 0 87 (R2=0.99)
Total capital investment (2008 dollars) = 34533 x (MMBtu/hr) A 0 85 (R2=1.0)
Total annual cost (2008 dollars) = 6794 x (MMBtu/hr) A 0 94 (R2=1.0)
Revised best fit equations for incremental SCR costs relative to a RACT baseline of
water injection are (R2=l for the 2008 costs because the analysis was based on only two data
points).
Total capital investment (1999 dollars) = 37193 x (MMBtu/hr) A 0 63 (R2=1.0)
Total annual cost (1999 dollars) = 12065 x (MMBtu/hr) A 0 64 (R2=1.0)
Total capital investment (2008 dollars) = 10323 x (MMBtu/hr) A 0 96 (R2=1.0)
Total annual cost (2008 dollars) = 3106.1 x (MMBtu/hr) A 0 94 (R2=1.0)
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3.3.5 SCR and Steam Injection; Gas Turbines—Natural Gas (NSCTSGTNG)
Combined costs for SCR and steam injection were not presented in any available
references. Thus, costs for combined control systems were estimated in 1999 dollars for four
model turbines ranging from 4 MW to 161 MW using the procedures described above for steam
injection alone and for SCR as part of combined SCR and water injection control systems.
Specifically, steam injection costs for each model turbine were assumed to be the same as in the
1993 ACT, consistent with the description above for steam injection control costs. Since OSEC
did not estimate SCR costs for the specific turbines in this analysis, we estimated the SCR costs
using the trendlines that we developed for incremental SCR costs relative to a RACT baseline of
water injection. We then summed the separate SCR and steam injection costs to obtain the
combined system costs.
We also estimated costs for a combined steam injection and SCR control measure in 2008
dollars. The SCR portion of the costs are the same as for SCR in the combined water injection
plus SCR control measure, as described in Section 3.3.4. Total capital investment for the steam
injection portion were estimated in 1999 dollars using the regression equation developed for
steam injection alone, as described in Section 3.3.2. These costs were escalated to 2008 costs
using the CEPCI. Total annual costs for steam injection were first estimated in 1999 dollars
using the regression equation for the steam injection control option (see Section 3.3.2). On
average, 40 percent of these costs were estimated to be for indirect costs that are factored from
the system capital cost, and the remaining 60 percent is for direct annual costs and overhead. To
estimate the total annual costs for steam injection in 2008, the indirect costs were scaled from the
1999 estimate using the CF.PCI, and the direct annual costs and overhead were assumed to be the
same as in 1999.
Table 3-6 summarizes the recommended new cost effectiveness and capital to annual cost
ratios values for implementing SCR plus steam injection on natural gas-fired combustion
turbines. Table 3-6 also presents revised incremental costs of SCR relative to a RACT baseline
of steam injection for the different categories of turbines. Note that the incremental costs are
slightly different from the costs in Table 3-5. The costs should be the same for a given turbine
category. They differ because the two analyses examined a different number of turbines, and the
sizes were not exactly the same. At a later date, the analysis could be improved by combining the
SCR costs from both analyses and developing a single set of incremental SCR costs.
3-16
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Table 3-6. Summary of Cost Effectiveness and Supporting Data for SCR Plus Steam
Injection (SI)
Turbine Output,
MW
Cost
Year
Uncontrolled NOx
Emissions
SCR Outlet
Concentration,
ppmvd
Cost
Effectiveness,
$/ton NOx
Capital to
Annual
Cost Ratio
Incremental Cost
Relative to RACT
Baseline of SI,
$/ton NOx
Avg. ppmvd
tpy
Small (4.2)
1999
155
<365
9
2,570
3.3
5,550
Small (26.8)
1999
142
>365
9
1,380
3.1
2,870
Large (83-161)
1999
300
>365
9
570
2.7
1 .S III
Large (50-180)
2008
o
>365
2.5
1,420
3.9
3.170
"Uncontrolled concentrations were not reported in the referenced analysis. Thus, the value used in this analysis is an
assumed average that results in the estimated 84 percent reduction for DLN combustion, as described in Section
3.3.3 of this report.
Based on regression of the data in the analysis, the revised best fit trend lines are
represented by the following power equations for the uncontrolled scenario (R2= 1 for the 2008
costs because the analysis was based on only two data points):
Total capital investment (1999 dollars) = 72169 x (MMBtu/hr) A 0 ()() (R2=0.99)
Total annual cost (1999 dollars) = 1755 1 x (MMBtu/hr) A 0 72 (R2=0.98)
Total capital investment (2008 dollars) = 46492 x (MMBtu/hr) A 0 82 (R2=1.0)
Total annual cost (2008 dollars) = 8704 x (MMBtu/hr) A 0 86 (R2=1.0)
Revised best fit equations for incremental SCR costs relative to a RACT baseline of
steam injection are assumed to be the same as noted above in the discussion of costs for SCR and
water injection.
3.3.6 SCR and Dry Low NOx Combustion; Gas Turbines—Natural Gas (NSCRDGTNG)
Updated costs for combined SCR and DLN combustion control systems were estimated
in 1999 dollars for all turbine sizes, 2007 dollars for small turbines, and 2008 dollars for large
turbines. The 1999 costs were estimated by combining the separate costs for DLN combustion
and SCR provided by Onsite Sycom Energy Systems (OSEC, 1999). The 2007 costs were
estimated by combining SCR costs developed by Energy and Environmental Analysis in a report
prepared for EPA with the OSEC costs for DLN combustion in 1999 dollars, escalated to 2007
dollars (EEA, 2008). Similarly, costs in 2008 dollars were estimated by combining SCR costs
3-17
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developed by EmeraChem Power in an analysis for the Bay Area Air Quality Management
District with escalated DLN combustion costs (ECP, 2008). The EEA analysis provided only
capital costs; therefore, we estimated annual costs using the same factors provided in ECP's
analysis of costs in 2008 dollars. For both the 2007 and 2008 cost estimates, DLN capital costs
and capital recovery were escalated from 1999 dollars using the CEPCI, and annual parts and
repairs costs were assumed to be the same in all three years.
Table 3-7 summarizes the recommended new cost effectiveness and capital to annual cost
ratios values for implementing SCR plus dry low NOx combustion on natural gas-fired
combustion turbines. Table 3-7 also presents revised incremental costs of SCR relative to a
RACT baseline of steam injection for the different categories of turbines. Note that the SCR
outlet NOx level was assumed to be 2.5 ppmvd in the ECP analysis, which results in an overall
control efficiency of 98 percent versus the 94 percent for the OSEC analyses. We also used an
outlet concentration of 2.5 ppmvd to estimate emissions to use with EEA's 2007 costs. The ECP
and EEA analyses did not specify inlet NOx emissions concentrations to the SCR; therefore, we
assumed 25 ppmvd, as in other DLN analyses. We also assumed an average uncontrolled
emissions level of 160 ppmvd for all models so that the overall control efficiency of the DLN
combustion plus the SCR was 98 percent. Note that the incremental costs in 1999 dollars are
significantly higher than those for SCR following water injection and steam injection; this is due
to the inlet concentration being 25 ppmvd for this analysis and 42 ppmvd for water injection and
steam injection.
Table 3-7. Summary of Cost Effectiveness and Supporting Data for SCR Plus DLN
Combustion
Turbine Output.
MW
Cost
Year
Uneontrolled NOx
Emissions
SCR Outlet
Concentration,
ppmvd
Cost
Effectiveness,
$/ton NOx
Capital to
Annual
Cost Ratio
Incremental Cost
Relative to RACT
Baseline of DLN,
$/ton NOx
Av& ppmvd
tpy
Small (4.2)
1999
134
<365
9
1,800
2.9
11,900
Small (26.8)
1999
174
>365
9
990
3.6
6,320
Large (161)
1999
210
>365
9
390
4.2
3,340
Small (1-10.2)
2007
o
<365
2.5
2,910
4.3
18,900
Small (25)
2007
o
>365
2.5
1,460
3.8
7,510
Large (50-180)
2008
o
>365
2.5
1,040
4.5
5,560
"Uncontrolled concentrations were not reported in the referenced analysis. Thus, the value used in this analysis is an
assumed average that results in the estimated 84 percent reduction for DLN combustion, as described in Section
3.3.3 of this report.
3-18
-------
Based on regression of the data in each analysis, the best fit trend lines are represented by
the following power equations for uncontrolled scenarios (R2=l for the 2008 costs because the
analysis was based on only two data points, and note that the R2 for the 2007 equations is not
meaningful because the DLN portion of the costs are based on a regression equation instead of
independent, model-specific data):
Total capital investment (1999 dollars) = 24854 x (MMBtu/hr) A 0 79 (R2=l .0)
Total annual cost (1999 dollars) = 12725 x (MMBtu/hr) A 0 69 (R2=l .0)
Total capital investment (2007 dollars) = 187647 x (MMBtu/hr) A 0 54 (R2=l .0)
Total annual cost (2007 dollars) = 2782 x (MMBtu/hr) + 167494 (R2=1.0)
Total capital investment (2008 dollars) = 14790 x (MMBtu/hr) A 0 97 (R2=1.0)
Total annual cost (2008 dollars) = 5263.5 x (MMBtu/hr) A °-90 (R2=1.0)
The equations to estimate incremental costs for SCR relative to a RACT baseline of dry
low NOx combustion in 1999 dollars and 2008 dollars are assumed to be the same as noted in
Section 3.3.4 for incremental costs relative to a RACT baseline of water injection. Incremental
costs for SCR relative to a RACT baseline of water injection in 2007 dollars are estimated using
the following equations'
Total capital imesiment (2007 dollars) = 210883 x (MMBtu/hr) A 046 (R2=1.0)
Total annual cost (2007 dollars) = 1894 x (MMBtu/hr) + 185570 (R2=0.99)
3.3.7 Water Injection; Gas Turbines—Oil (NWTINGTOL)
No new data are available on costs of water injection for oil-fired combustion turbines.
However, because the water injection costs for natural gas-fired turbines were determined to be
essentially the same in 1999 as in 1990, we assume the same would be true for water injection on
oil-fired turbines; the costs for both types of turbines also were the same in the 1993 ACT
analysis. Therefore, we recommend continuing to base costs on the results of the 1993 ACT
analysis, but to update the cost year from 1990 to 1999. In addition, we changed the size of the
large model in the ACT analysis from 83.3 MW to 84.7 MW because it appears the incorrect
3-19
-------
model was used in the ACT analysis. As for the natural gas-fired turbines, we also recommend
splitting the single record for small sources into two records—one for source with uncontrolled
NOx emissions <365 tpy, and the other for sources with uncontrolled NOx emissions >365 tpy.
The resulting cost effectiveness values for the turbines with uncontrolled NOx emissions
<365 tpy and >365 tpy are $l,630/ton of NOx and $960/ton of NOx, respectively. The capital to
annual cost ratios also change slightly.
As for other control technologies, the constants in the equations to estimate total capital
costs and total annual costs differ from those in the regression analyses performed in Excel. In
this case, the differences are small, but we recommend revising the constants so that all
equations are developed based on the same approach. The revised equations for both the
uncontrolled and RACT baseline scenarios are:
Total capital investment (1999 dollars) = 43255 x (MMBtu/hr) A 0 ()0 (R2=1.0)
Total annual cost (1999 dollars) = 6796.8 x (MMBtu/hr) A °-80(R2=1.0)
3.3.8 SCR and Water Injection; Gas Turbines—Oil (NSCRWGTNG)
SCR costs were developed in a BACT analysis for a 48 MW oil-fired combustion turbine
(FMPA, 2004). Because water injection costs in 2004 dollars are not available, we calculated
costs in 1999 dollars as described above for the water injection option, and then estimated costs
in 2004 dollars by scaling up the 1999 capital costs (and capital recovery) using the CEPCI;
other annual operating and maintenance costs were assumed to be unchanged. We used the SCR
capital cost as presented in the FMPA analysis, but we made several changes to the annual costs.
Although the original values may have been appropriate for the specific application evaluated by
FMPA, the following changes were made to be consistent with the calculations for other controls
in this analysis:
¦ Estimated O&M costs assuming operation for 8,000 hr/yr instead of 4,422 hr/yr.
¦ Excluded cost for one week of lost power generation while catalyst is being replaced,
assuming that catalyst replacement can be performed during scheduled annual
downtime.
¦ Reduced sales tax and freight cost for catalyst from 12.25 percent of the purchased
cost to 8 percent of the purchased cost.
¦ Deleted capital recovery cost for catalyst because the catalyst is replaced annually.
3-20
-------
¦ The reported annual cost for ammonia was based on a stoichiometric ratio of 1.4
(possibly because they assumed a significant generation of N02 relative to NO).
They also applied a factor of 1.05, apparently to account for ammonia slip, as in the
Control Cost Manual procedures for SCR on boilers. However, both factors should
not be needed. For this analysis, we used just the 1.05 factor (also used the reported
unit cost of $750/ton of ammonia, which may have been high for 2004).
¦ Reduced the property tax factor from 2.75 percent of the TCI to 1 percent of the TCI.
Table 3-8 summarizes the recommended cost effectiveness and capital lo minimi cost
ratios values for implementing SCR plus water injection on oil-fired combustion turbines.
Table 3-8 also presents incremental costs of SCR relative to a RACT baseline of water injection.
The 1990 costs are essentially the same as the costs currently in the CMDB, except that we
recommend splitting the one record for small sources into two records.
Table 3-8. Summary of Cost Effectiveness and Supporting Data for SCR Plus Water
Injection (WI) for Oil-Fired Turbines
Uncontrolled NOx
Incremental Cost
Emissions
SCR Outlet Cost
Capital to
Relative to RACT
Turbine
Cost
" Concentration. Effectiveness,
Annual
Baseline of WI,
Output, MW
Year
Avg. ppmvd
tpy
ppnml S/tonNOx
Cost Ratio
$/ton NOx
Small (3.3)
1990
179
<365
IS 3,200
2.9
7,620
Small (26.3)
1990
211
>365
IS 1,320
2.3
2,450
Large (84)
1990
228
>365
18 1,000
2.4
2,210
Large (48)
2004
200"
>365
5 1,560
2.3
4,790
aThe referenced analysis did nol report an uncontrolled emissions level. The value used in this analysis is the
average of the uncontrolled emissions concentrations for oil-fired model turbines in the 1993 ACT.
Based on regression of the data in the 1993 ACT, the best fit trend lines are represented
by the following revised power equations for the uncontrolled scenario:
Total capital investment (1990 dollars) = 95837 x (MMBtu/hr) A 0 62 (R2=0.99)
Total annual cost (1990 dollars) = 25990 x (MMBtu/hr) A °-70 (R2=1.0)
Revised best fit equations for incremental SCR costs relative to a RACT baseline of
water injection are:
Total capital investment (1990 dollars) = 4744 x (MMBtu/hr) + 368162 (R2=1.0)
3-21
-------
Total annual cost (1990 dollars) = 1522.5 x (MMBtu/hr) + 142643 (R2=1.0)
We could not develop equations for this control system in 2004 dollars because 2004 data
are available for only one turbine, and thus are insufficient for this purpose.
3.3.9 Water Injection; Gas Turbines—Jet Fuel (NWTINGTJF)
The current CMDB assumes costs for jet fuel-fired turbines are the same as for oil-fired
turbines. Thus, we recommend the same changes for jet fuel fired turbines as noted al">o\ e lor oil-
fired turbines.
3.3.10 SCR and Water Injection; Gas Turbines—Jet Fuel (NSCTWGTJF)
The current CMDB assumes costs for jet fuel-fired turbines are the same as for oil-fired
turbines. Thus, we recommend the same changes for jet fuel fired turbines as noted above for oil-
fired turbines.
3.3.11 Applicable Control Measures for Gas Turbine SCCs
The first column in Table 3-9 lists all of the gas turbine SCCs that are associated with one
or more gas turbine control measures in the CMDIi luMe called "Table 03_SCCs." In addition,
the last seven SCCs in Table 3-9 are additional gas turbine SCCs that are not currently assigned
any NOx control measures in the CMDB. These seven SCCs, as well as many of the others at the
top of Table 3-9, were identified with NOx emissions in an EPA query of the NEI for facilities in
the Ozone Transport Group Assessment Region (i.e., 37 states that are partially or completely to
the east of 100°W longitude). The first 1 1 control measures in column headings in Table 3-9 are
the gas turbine control measures that are currently in the CMDB; the last three column headings
are the new control measures identified in this review and described in Section 3.2 of this report.
Each control measure that was determined to be applicable for a specific SCC is
identified by either an "E" or an "N" in the cell at the intersection of the applicable SCC row and
the control measure column. An "E" means the control measure is already listed in the CMDB
for the particular SCC, and we concur with that designation. An "N" means the control measure
is not currently linked to a particular SCC, but we recommend adding this link in the database. In
some cases, we recommend applying new links between existing control measures and existing
SCCs. For example, some of the SCCs are for turbines that are fired with relatively uncommon
fuels such as landfill gas or gasoline. We have not located any analyses that determined the
applicable controls and related costs for gas turbines fired with such fuels. In order to conduct
CoST modeling analyses for these turbines, the most representative available control measures
3-22
-------
Table 3-9. Recommended Control Measures for Gas Turbine SCCs
Applicable Gas Turbine Control Measures for the SCCd
see
see
hJ
O
H
O
z
-J
O
H
O
£
li
H
O
Z
li
O
£
O
z
H
O
z
STTNGTNG
O
Z
H
O
U
O
Z
H
O
O
Z
H
O
C/2
O
Z
H
O
h
C
<
h
O
z
H
O
U
O
Z
H
O
O
Z
H
O
Q
scca
Level
lb
Level
T
SCC Level 3
SCC Level 4
HH
H
£
C£
U
cn
HH
H
£
C£
U
cn
HH
H
£
Z
-J
Q
C£
U
cn
C£
U
cn
U
cn
e
H
U
|
U
Z
Z
z
Z
z
Z
Z
Z
Z
Z
z
z
Z
20200101
ICE
Ind
Distillate Oil (Diesel)
Turbine
E
E
20200103
ICE
Ind
Distillate Oil (Diesel)
Turbine: Cogeneration
E
E
20200108
ICE
Ind
Distillate Oil (Diesel)
Turbine: Evap Losses
D
D
20200109
ICE
Ind
Distillate Oil (Diesel)
Turbine: Exhaust
E
E
20200201
ICE
Ind
Natural Gas
Turbine
E
E
E
E
E
E
D
N
N
N
20200203
ICE
Ind
Natural Gas
Turbine: Cogeneration
E
E
E
E
E
E
D
N
N
N
20200208
ICE
Ind
Natural Gas
Turbine: Evap Losses
D
D
D
D
D
D
D
20200209
ICE
Ind
Natural Gas
Turbine: Exhaust
E
E
E
E
E
E
D
N
N
N
20200701
ICE
Ind
Process Gas
Turbine
Ne
Ne
Ne
Ne
Ne
Ne
D
Ne
Ne
Ne
20200705
ICE
Ind
Process Gas
Refinery Gas: Turbine
Ne
Ne
Ne
Ne
Ne
Ne
D
Ne
Ne
Ne
20200713
ICE
Ind
Process Gas
Turbine: Evap Losses
D
20200714
ICE
Ind
Process Gas
Turbine: Exhaust
Ne
Ne
Ne
Ne
Ne
Ne
D
Ne
Ne
Ne
20200901
ICE
Ind
Kerosene/Naphtha (Jet
Fuel)
Turbine
E
E
20200908
ICE
Ind
Kerosene/Naphtha (Jet
Fuel)
Turbine: Evap Losses
D
D
20200909
ICE
Ind
Kerosene/Naphtha (Jet
Fuel)
Turbine: Exhaust
E
E
20201008 ICE
Ind Liquified Petroleum Gas
(LPG)
Turbine: Evap Losses
D
(continued)
-------
Table 3-9. Recommended Control Measures for Gas Turbine SCCs (continued)
Applicable Gas Turbine Control Measures for the SCCd
SCC SCC
Level Level
SCCa lb 2C
SCC Level 3
SCC Level 4
-J
O
H
O
z
—
H
£
-j
o
H
o
%
U
cn
H
O
Z
HH
H
£
I
I
U
O
z
H
O
z
HH
H
£
O
z
H
o
z
HH
H
m
O
Z
H
O
U
Z
-J
Q
O
z
H
0
1
U
in
O
Z
H
O
in
Pi
u
CA)
O
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H
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U
CA)
h
c
<
h
c
o
z
H
o
U
H
U
O
z
H
O
o
z
H
o
Q
20201009
ICE
Ind
Liquified Petroleum Gas
(LPG)
Turbine: Exhaust
Ne
Ne
D
20201011
ICE
Ind
Liquified Petroleum Gas
(LPG)
Turbine
Ne
Ne
D
20201013
ICE
Ind
Liquified Petroleum Gas
(LPG)
Turbine: Cogeneration
Ne
\
D
20300102
ICE
C/l
Distillate Oil (Diesel)
Turbine
E
E
20300108
ICE
C/l
Distillate Oil (Diesel)
Turbine: Evap Losses
D
D
20300109
ICE
C/l
Distillate Oil (Diesel)
Turbine: Exhaust
E
E
20300202
ICE
C/l
Natural Gas
Turbine
E
E
E
E
E
E
D
N
N
N
20300203
ICE
C/l
Natural Gas
Turbine: Cogeneration
E
E
E
E
E
E
D
N
N
N
20300208
ICE
C/l
Natural Gas
Turbine: Evap Losses
D
D
D
D
D
D
D
20300209
ICE
C/l
Natural Gas
Turbine: Exhaust
E
E
E
E
E
E
D
N
N
N
20300701
ICE
C/l
Digester Gas
Turbine
Ne
Ne
Ne
Ne
Ne
Ne
D
Ne
Ne
Ne
20300708
ICE
C/l
Digester Gas
Turbine: Evap Losses
D
20300709
ICE
C/l
Digester Gas
Turbine: Exhaust
Ne
Ne
Ne
Ne
Ne
Ne
D
Ne
Ne
Ne
20300801
ICE
C/l
Landfill Gas
Turbine
Ne
Ne
Ne
Ne
Ne
Ne
D
Ne
Ne
Ne
20300808
ICE
C/l
Landfill Gas
Turbine: Evap Losses
D
20300809
ICE
C/l
Landfill Gas
Turbine: Exhaust
Ne
Ne
Ne
Ne
Ne
Ne
D
Ne
Ne
Ne
20400301
ICE
ET
Turbine
Natural Gas
N
N
N
N
N
N
D
N
N
N
20400304
ICE
ET
Turbine
Landfill Gas
Ne
Ne
Ne
Ne
Ne
Ne
D
Ne
Ne
Ne
(continued)
-------
Table 3-9. Recommended Control Measures for Gas Turbine SCCs (continued)
Applicable Gas Turbine Control Measures for the SCCd
scca
see
Level
lb
see
Level
2C
SCC Level 3
SCC Level 4
-J
o
H
o
z
HH
H
-J
o
H
o
%
U
/
y
to
H
o
z
—
H
to
I
u
/.
O
z
H
O
z
HH
H
O
z
H
o
z
HH
H
o
Z
H
O
U
Z
-J
Q
O
z
H
0
1
U
o
z
H
O
in
Pi
u
CA)
O
z
H
O
U
in
h
C
<
h
e
o
z
H
O
U
H
U
O
z
H
O
o
z
H
o
Q
50100420
WD
SWD-G
Landfill Dump
Waste Gas Recovery:
GT
\
Ne Ne Ne Ne Ne D Ne Ne Ne
20201609
ICE
Ind
Methanol
Turbine: Exhaust
20201701
ICE
Ind
Gasoline
Turbine
20300901
ICE
C/I
Kerosene/Naphtha (Jet
Fuel)
Turbine: JP-4
N
N
20400302
ICE
ET
Turbine
Diesel/Kerosene
N
N
20400303
ICE
ET
Turbine
Distillate Oil
N
N
20400305
ICE
ET
Turbine
Kerosene/Naphtha
N
N
20400399
ICE
ET
Turbine
Other Not Classifiedf
Ne
Ne
aSCCs in regular font are associated with one or more gas turbine control measures in the current CMDB. The SCCs in bold font represent gas turbine activities
that were identified with NOx emissions in the Ozone Transport Assessment Group Region analysis but are not associated with gas turbine control measures in
the current CMDB.
bICE means "Internal Combustion Engines" and WD means "Waste Disposal."
Tnd means "Industrial," C/I means "Commercial/Institutional." ET means "Engine Testing," and SWD-G means "Solid Waste Disposal-Government."
dAn "E" means the control measure is currently associated with the SCC in the CMDB, and no changes are recommended. A "D" means the control measure is
currently associated with the SCC. but this control measure should be deleted because it is not appropriate for the SCC. An "N" means the control measure is
not currently associated with the SCC in the CMDB. but adding it is recommended.
eThe control measure is assumed to be representative for the SCC: control cost data are unavailable for the specific fuel type for the SCC.
The fuel type is unknown. For the purposes of this analysis it is assumed to be a liquid because most of the emissions identified for the engine testing SCCs in
the analysis done in the Ozone T ransport Assessment Group Region were from liquid fuel-fired turbines.
-------
should be assigned. For turbines that burn miscellaneous gaseous fuels, the most representative
control measures are those for natural gas-fired turbines. Similarly, for turbines that burn
miscellaneous liquid fuels, the most representative available control measures are those for oil-
fired turbines. The description field in the CMDB table called "Table 02_Efficiencies" could be
revised to indicate that the control measures for natural gas units are assumed to be applicable for
all gaseous fuel fired units, and the control measures for oil-fired units are assumed to be
applicable for all liquid fuel-fired units (note that the separate control measures already in the
CMDB for jet fuel-fired turbines are also based on the data for oil-fired units).
Finally, gas turbine SCCs for evaporative losses from turbine fuel storage and delivery
systems are associated with NOx control measures in the current CMDB. We recommend
deleting these NOx control measure/SCC records from the CMDB table called "Table 03_SCCs"
because there should be no NOx emissions from the sources represented by these SCCs. These
control measure/SCC combinations are identified with a "D" in the applicable cells in Table 3-9.
3.4 Example Emission Limits for NonEGU Combustion Turbines
NonEGU combustion turbines are subject to sc\ era I emission regulations, including
NSPS in 40 CFR part 60 and various state regulations. Example emission limits in state
regulations are presented in Table 3-10.
Table 3-10. NOx Emissions Limits for NonEGU Combustion Turbines in New York
State
Type of Service
Type of Combustion Turbine
Operating Cycle
Emission Limit
Effective
Date
New Yorka
Any—gaseous fuel
Combined cycle
42 ppmdv (at 15% 02)
Current
Simple cycle or regenerative
cycle
50 ppmdv (at 15% 02)
Current
\n\ iiil-fiivxl
Combined cycle
65 ppmdv (at 15% 02)
Current
Simple cycle or regenerative
cycle
100 ppmdv (at 15% 02)
Current
aThe requirements apply to combustion turbines with a maximum heat input rate greater than or equal to 10 million
Btu per hour at major sources of NOx emissions. The specified limits apply until July I, 2014; beginning on July
I, 2014, owners/operators must submit a proposal for RACT (NYCRR, 2014).
3.5 References
BAAQMD, 2010. Bay Area Air Quality Management District. Preliminary Determination of
Compliance. Marsh Landing Generating Station. Application 18404. March 2010.
Available at: http://www.energy.ca.gov/sitingcases/marshlanding/documents/other/2010-
03-24 Bay Area AOMD PDOC.pdf
3-26
-------
CARB, 2004. California Environmental Protection Agency. Air Resources Board. Report to the
Legislature. Gas-Fired Power Plant NOx Emission Controls and Related Environmental
Impacts. Stationary Source Division. May 2004. Available at:
http://www.arb.ca.gov/research/apr/reports/12069.pdf
CH2MHill, 2002. Walnut Energy Center Application for Certification. Prepared for the
California Energy Commission. November 2002. Available at:
www.energy.ca.gov/sitingcases/turlock/documents/applicant files/volume 2/App 08.01
E Eval Control.pdf
Cybulski, 2006. Cybulski, A. and J. Moulin, editors. Structured Catalysts and Reactors CRC
Press. 2006. p. 236.
DeCicco, 2004. DeCicco, S., B. Reyes, and T. Girdlestone. EmeraChem, LLC. SCONOX White
Paper. Multi-Pollutant Emission Reduction Technology For Stationary Gas Turbines and
IC Engines. January 5, 2004. Available at:
\v\v\v.emera.serveyourmarket.com/papers/S('ONOx"f tper%20-
%20rl.pdf
ECP, 2008. EmeraChem Power. Attachment in email from J. Yalmus, EmeraChem Power, to W.
Lee, BAAQMD. Request for EMx Cost Information. September 8, 2008. Available at:
http://www.baaqmd.gOv/~/media/Files/Engineering/Public%20Notices/2010/18404/Foot
notes/EMx%20BACT%20economic%20analvsis%20final09072008.ashx
EEA, 2008. Energy and Environmental Analysis (An 1CF International Company). Technology
Characterization: Gas Turbines. Prepared for Environmental Protection Agency Climate
Protection Partnership Division. December 2008. Available at:
http://www.epa.gov/chp/documents/catalog chptech gas turbines.pdf
EPA, 1993. U.S. Environmental Protection Agency. Alternative Control Techniques
Document—NOx Emissions from Stationary Gas Turbines. EPA-453/R-93-007. January
1993.
FMPA, 2004. Florida Municipal Power Agency. Chapters 3 and 4 of PSD BACT Analysis for
Stock Island Facility in Key West, Florida. Available at: Available at:
http://www.dep.state.fl.us/air/emission/construction/stockisland/BasisofBACT.pdf and
http://www.dep.state.fl.us/air/emission/construction/stockisland/NOxBACT.pdf
Kawasaki, 2010. Kawasaki Gas Turbines—Americas. Press Release. Kawasaki Gas Turbines
Cogeneration System Helps Bridgewater Correctional Facility. January 25, 2010.
Available at:
http://www.kawasakigasturbines.com/index.php/press releases/read/kawasaki gas turbi
nes cogeneration system helps bridgewater correctional fa
Leposky, 2004. Leposky, G. Oil producer installs cogeneration system with ultra-low NOx
emissions. Distributed Energy. July/August 2004. Available at:
http://www.distributedenergv.com/DE/Articles/Oil Producer Installs Cogeneration Svst
em With Ult 2857.aspx?pageid=62d52359-blc7-4115-9d0d-7837abe081cb
3-27
-------
NYCRR, 2014. New York Codes, Rules and Regulations. Title 6. Chapter III. Subchapter A.
Part 227. Subpart 227-2. Reasonably Available Control Technology (RACT) For Major
Facilities of Oxides of Nitrogen (NOx). Available at:
http:// government, westl aw. com/linkedslice/default, asp? SP=nycrr-1000
OSEC, 1999. Onsite Sycom Energy Corporation. Cost Analysis of NOx Control Alternatives for
Stationary Gas Turbines. Prepared for U.S. Department of Energy. Environmental
Programs Chicago Operations Office. November 5, 1999. Available at:
https://wwwl.eere.energy.gov/manufacturing/distributedenergy/pdfs/gas turbines nox c
ost analvsis.pdf
Peltier, 2003. Peltier, R. Gas turbine combustors drive emissions toward nil. Power Magazine.
March 15, 2003.
Quackenbush, 2012. Quackenbush, G. Cogeneration plant saves Pacific Union College $1
million a year in energy costs. North Bay Business Journal. March 19, 2012. Available at:
http://www.northbavbusinessiournal.com/50863/cogeneration-plant-saves-pacific-union-
college-1 -million-a-vear-in-energy-costs/
RDC, 2001. Resource Dynamics Corporation. Assessment of Distributed Generation Technology
Applications. Prepared for Maine Public Utilities Commission. February 2001. Available
at: http://www.distributed-generation.com/Library/Maine.pdf
RTI, 2014. Spreadsheet "Turbines control costs xlsx." Prepared for U.S. Environmental
Protection Agency Office of Air Ouulily Planning and Standards. Air Economics Group.
February 7, 2014
3-28
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SECTION 4
GLASS MANUFACTURING SECTOR
4.1 Introduction
The control cost database separates the glass manufacturing sector into four different
types; flat glass, container glass, pressed glass, and general glass manufacturing. The CMDB
listed six different control technologies for NOx emissions which were all reviewed in 2006 and
included cullet preheat, oxy-firing, electric boost, low NOx burners, selective catalytic reduction
(SCR) and selective non-catalytic reduction (SNCR). A literature and internet search was
conducted to find any new control technologies for NOx or any updates to existing controls
regarding cost and efficiencies. Operating permits for some glass manufacturing plants were
reviewed and control system vendors were also contacted for information. A brief summary of
data from each reference reviewed in included in the spreadsheet "CoSTGlass Mfg.xlsx."
4.2 Example NOx Regulatory Limits
4.2.1 Wisconsin
Glass manufacturing furnace with a maximum heat input capacity equal to or greater than
50 mmBtu per hour, 2.0 pounds per ton of produced glass.1
4.2.2 New Jersey
Commercial container glass, specialty container glass, borosilicate recipe glass, pressed
glass, blown glass, and fiberglass manufacturing furnaces: 4.0 lbs/ton glass removed. Flat glass
manufacturing furnaces: 9.2 lbs/ton glass removed.
4.2.3 New York
NOx emissions are covered under NY's case-by case RACT regulations.
4.3 Recommended Additions
The following NOx controls are recommended additions for the glass manufacturing
industry that are not currently in the control cost database, and a tabular summary of the costs is
presented in Table 4-1.
¦ Electric Boost—Three entries for electric boost controls were in the CMDB for
container, flat, and pressed glass manufacturing. A cost estimate for electric boost was
found for "general" glass manufacturing (DOE, 2002), since the CMDB did not have a
"general" entry for electric boost controls, an entry for "Electric Boost; Glass
Manufacturing—General" was added with a new abbreviation of NELBOGMGN. The
1 http://dnr.wi.gov/About/NRB/2007/Januarv/01-Q7-3A4.pdf
4-1
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reference provided an annualized cost of $7,100 per ton of NOx removed based on a
250 ton of glass per day glass melting furnace operating with an emission rate of 8-lb
NOx per ton glass produced and a NOx removal efficiency of 30 percent. Since the
reference did not provide capital costs, the capital to annual cost ratio could not be
determined, and the capital recovery factor was assumed to be the same as the electric
boost entries for container, flat, and pressed glass (i.e., 0.1424, assuming equipment
life of 10 years).
¦ Oxy-firing—Three entries for oxy-firing were in the CMDB for container, flat, and
pressed glass manufacturing. Similar to electric boost controls, an updated cost
estimate for oxy-firing was found for "general" glass manufacturing (DOE, 2002);
since the CMDB did not have a "general" entry for oxy-firing, an entry for "OXY-
Firing; Glass Manufacturing—General" was added to the CMDB with a new
abbreviation of NOXYFGMGN. The reference provided an annualized cost of $2,352
per ton of NOx removed based on a 250 ton of glass per day glass melting furnace
emitting 8-lb NOx per ton glass produced and a NOx removal efficiency of 85
percent.1 Since the capital costs were not provided the capital to annual cost ratio and
the capital recovery factor were assumed to be the same as the oxy-firing entries for
container, flat, and pressed glass, which all had the same values.
¦ Catalytic Ceramic Filter—This new control technology for NOx reduction was not
previously in the database and was added for flat glass manufacturing with a new
abbreviation of CATCFGMFT. A vendor was contacted for information (2013
Vendor Quote). The minimum and maximum cost per ton estimates were based on
regenerative gas-fired furnace with pull rates of 600 tons per day and 490 tons per
day, respectively. The estimate provided by the vendor included capital cost,
annualized capital costs, and annual operational cost in 2013 dollars; it also included
NOx reductions based on a 95 percent NOx efficiency.
Table 4-1. Summary of Cost Effectiveness and Supporting Data for Recommended
Additions
Technology
Furnace Production
Rate (ton/dav)
Cost
Year
NOx Removal
Efficiency (%)
Cost Effectiveness,
$/ton NOx
Capital to Annual
Cost Ratio
Electric Boost
250
2002
30
7,100
N/Aa
(general)
Oxy-firing
250
2002
85
2,352
2.7
General
Catalytic
490
2013
95
1,045
4.6
Ceramic Filter
600
2013
95
997
4.6
aThe ratio cannot be calculated because capital costs are not available.
4-2
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4.4 Recommended Changes
Changes to the CMDB are recommended for the following three types of control
measures, which are also summarized in Table 4-2.
¦ Low NOx Burner General—Three entries for Low NOX burners were in the cost
database for container, flat, and pressed glass manufacturing. An updated cost
estimate for low NOx burners for flat glass and container glass manufacturing (EC,
2013) was found and entries NLNBUGMCN and NLNBUGMFT were updated. The
reference provided capital costs and an annualized cost in euros per kilogram of NOx
removed which was converted to dollars per ton of NOx. For flat glass the minimum
cost per ton estimate was based on a 900 ton per day gas fired furnace, and the
maximum cost per ton estimate was based on a 500 ton per day gas fired furnace. For
container glass the minimum cost per ton estimate was based on 450 ton per day gas
fired furnace, and the maximum cost per ton estimate was based on a 200 ton per day
gas fired furnace. The capital recovery factor and the capital to annual cost ratio were
also updated. We also recommend changing the equipment life for low NOx burners
on flat glass furnaces from 3 years to 10 years (EC, 2013).
Additionally, equations for low NOx burners were added for entries NLNBUGMCN
and NLNBUGMFT to "Table 04_Equations" of the CMDB based on the best fit trend
lines of the total capital investment and total annual cost for the facilities with the
production levels described above, the best fit trend line results were as follows:
NLNBUGMCN (The correlation coefficients are high because the data are from a
single source, and they may reflect data points from a correlation performed by that
source)
Total capital investment (2007 dollars) = 30,930 x (tons/day)0 45 (R2 = 0.99)
Total annual cost (2007 dollars) = 9,377 x (tons/day) °'40 (R2 = 0.99)
M.NBUGMFT (The correlation coefficients are a perfect 1.0 because only two data
points are available)
Total capital investment (2007 dollars) = 527 x (tons/day) + 664,557 (R2 = 1.0)
Total annual cost (2007 dollars) = 132x (tons/day) + 150,105 (R2 = 1.0)
¦ Cullet Preheating—Two entries for cullet preheating controls were in the cost
database for container and pressed glass manufacturing. An updated annualized cost
per ton value and NOx efficiency for pressed and container glass entries (IT, 2002)
were found and updated for entries NCLPTGMCN and NCUPHGMPD. The
reference provided an annualized cost of $5,000 per ton of NOx removed based on a
250 ton of glass per day glass melting furnace emitting 8-lb NOx per ton glass
produced and a NOx removal efficiency of 5 percent.1 Since the reference did not
1 Annualized cost includes capital and O&M costs and is based on 2002 dollars.
4-3
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provide capital costs separately, the capital to annual cost ratio and the capital
recovery factor were not updated. Additionally, based on information from EPA's
OECA staff, class entries for cullet preheating should be changed from "known" to
"emerging" in Table OlSummary of the CMDB because this control measure is
technically feasible but has rarely been implemented.1
¦ Selective Catalytic Reduction—Three entries for selective catalytic reduction were in
the CMDB for container, flat, and pressed glass manufacturing. An updated cost
estimate for SCR for flat glass and container glass manufacturing (EC, 2013) was
found, and entries NSCRGMCN and NSCRGMFT were updated. The reference
provided capital costs and an annualized cost in euros per kilogram of NOx removed
which was converted to dollars per ton of NOx.2 For flat glass the minimum and
maximum cost per ton estimates were based on a 900 and 500 ton per day gas fired
furnace, respectively. For container glass the minimum and maximum estimates were
based on a 450 and 200 ton per day gas fired furnaces, respectively. The capital to
annual cost ratio were also updated.
Equations for SCR were added for entries NSCRGMCN and NSCRGMFT to Table 4
of the CMDB based on the best fit trend lines of the total capital investment and total
annual cost for the facilities with the production levels described above, the best fit
trend line results were as follows:
NSCRGMCN (The correlation coefficients are high because the data are from a
single source, and they may reflect data points from a correlation performed by that
source)
Total capital investment (2007 dollars) = 79,415 x (tons/day) 0 51 (R2 = 0.99)
Total annual cost (2007 dollars) = 643 x (tons/day) + 135,302 (R2 = 1.0)
NSCRGMFT (The correlation coefficients are a perfect 1.0 because only two data
points are available)
Total capital investment (2007 dollars) = 3681 x (tons/day) + 1.0E+06 (R2 = 1.0)
Total annual cost (2007 dollars) = 842 x (tons/day) + 424,930 (R2 = 1.0)
1 Personal communication. Katie McClintock, US EPA/OCEA, with Larry Sorrels, US EPA/OAR/OAQPS, Feb.
13,2014.
2 Conversion based on 2008 average exchange rate of 0.711. Source: http://www.irs.gov/Individuals/International-
Taxpavers/Yearlv-Average-Currencv-Exchange-Rates
4-4
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Table 4-2. Summary of Cost Effectiveness and Supporting Data for Recommended
Additions
Technology
Furnace Production
Rate (ton/day)
Cost
Year
NOx Removed
(tons/year)
Cost Effectiveness,
$/ton NOx
Capital to Annual
Cost Ratio
NLNBUGMCN
200
2007
66
1,365
4.2
450
2007
100
1,072
4.3
NLNBUGMFT
500
2007
371
574
4 :
900
2007
611
447
4.3
NCLPTGMCN
250
2002
5%
5,000
4.5
NCUPHGMPD
250
2002
5%
5,000
4.5
NSCRGMCN
200
2007
i:i
h.'J
4.5
450
2007
25 1
l.(.S4
4.2
NSCRGMFT
500
2007
SS(.
3.4
900
2007
1. W
S55
3.7
4.5 Recommended Deletions
¦ Selective Non-Catalytic Reduction Three entries for selective non-catalytic
reduction were in the cost database lor container, flat, and pressed glass
manufacturing. Based on conversations between EPA and OECA staff, SNCR entries
for glass manufacturing should be removed based on recent NSR settlements that
indicate SNCR is not a technically feasible control technology for the removal of
NOx.1
4.6 Updates to Source Classification Codes
¦ There are twenty applicable SCCs for glass manufacturing as shown in Table 4-3.
¦ In an analysis of NOx emissions for the Ozone Transport Assessment Group Region
in 2011, fourteen of the SCCs in Table 4-3 were identified. The six SCCs not
included in the Ozone Transport Region are shown at the bottom of Table 4-3. Four
of the SCCs, 30501401, 30501402, 30501403, and 30501404 are associated with
glass manufacturing NOx controls in the current CMDB.
¦ Furnaces are the primary source of NOx emissions in the glass manufacturing
industry, therefore NOx emission control techniques are typically for point emission
sources associated with furnace emissions. The four SCCs identified in the CMDB
pertain to four types of melting furnaces; general, flat, container, and pressed. The
1 Personal communication. Katie McClintock, US EPA/OCEA, with Larry Sorrels, US EPA/OAR/OAQPS, Feb. 13,
2014.
4-5
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remaining sixteen SCCs in Table 4-3 are not associated with furnaces. Therefore, no
changes related to SCCs are recommended for the CMDB.
¦ For new control techniques added to the CMDB for glass manufacturing, the
applicable SCC from Table 4-3 was added to the Description field for each control
technique in Table OlSummary in the CMDB (Table C-lof Appendix C of this
report). These related control measures and SCCs should also be added to "Table
03 SCCs" in the CMDB.
Table 4-3. Applicable SCCs for the Glass Manufacturing Industry
SCC Code
SCC Level One
SCC Level Two
SCC Level Three
SCC Level Four
305014013
Industrial Processes
Mineral Products
Glass Manufacture
Furnace/Genera 1 * *
305014023
Industrial Processes
Mineral Products
Glass Manufacture
Container Glass: Melting Furnace
305014033
Industrial Processes
Mineral Products
Glass Manufacture
Flat Glass: Melting Furnace
305014043
Industrial Processes
Mineral Products
Glass Manufacture
Pressed and Blown Glass:
Melting Furnace
30501406
Industrial Processes
Mineral Products
Glass Manufacture
Container Glass:
Forming/Finishing
30501407
Industrial Processes
Mineral Products
Glass Manufacture
Flat Glass: Forming/Finishing
30501408
Industrial Processes
Mineral Products
Glass Manufacture
Pressed and Blown Glass:
Forming/Finishing
30501410
Industrial Processes
Mineral Products
Glass Manufacture
Raw Material Handling (All
Types of Glass)
30501411
Industrial Processes
Mineral Products
Glass Manufacture
General **
30501413
Industrial Processes
Mineral Products
Glass Manufacture
Cullet: Crushing/Grinding
30501414
Industrial Processes
Mineral Products
Glass Manufacture
Ground Cullet Beading Furnace
30501416
Industrial Processes
Mineral Products
Glass Manufacture
Glass Manufacturing
30501420
Industrial Processes
Mineral Products
Glass Manufacture
Mirror Plating: General
30501499
Industrial Processes
Mineral Products
Glass Manufacture
See Comment **
SCCs Not Included in the Ozone Transport Assessment Group Region:
30501405
Industrial Processes
Mineral Products
Glass Manufacture
Presintering
30501412
Industrial Processes
Mineral Products
Glass Manufacture
Hold Tanks **
30501415
Industrial Processes
Mineral Products
Glass Manufacture
Glass Etching with Hydrofluoric
Acid Solution
30501417
Industrial Processes
Mineral Products
Glass Manufacture
Briquetting
30501418
Industrial Processes
Mineral Products
Glass Manufacture
Pelletizing
30501421
Industrial Processes
Mineral Products
Glass Manufacture
Demineralizer: General
aDenotes SCCs included in the CMDB.
4-6
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4.7 References
DOE, 2002. Oxygen Enriched Air Staging a Cost-effective Method For Reducing NOx
Emissions. U.S. Department of Energy. Office of Industrial Technologies. April 2002.
http://wwwl .eere.energy, gov/manufacturing/resources/
glass/pdfs/airstaging.pdf
EC, 2013. Best Available Techniques (BAT) Reference Document for the Manufacture of Glass.
European Commission 2013. http://eippcb.irc.ec.europa.eu/reference/BREF/
GLS Adopted 03 2012.pdf
Vendor Quote 2013 - Confidential Business Information
4-7
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SECTION 5
LEAN BURN ENGINES
The CMDB includes the following NOx emissions control measures for Lean Burn
Engines:
¦ Air to fuel ratio (AFR) (achieves 20 percent reduction)
¦ Air to fuel ratio (AFR) and Ignition retard (IR) (achieves 30 percent reduction)
¦ Ignition retard (IR) (achieves 20 percent reduction)
¦ Low emission combustion (achieves 87 percent reduction)
¦ Low emissions combustion, low speed (achieves 87 percent reduction)
¦ Low emissions combustion, medium speed (achieves 87 percent reduction)
¦ Nonselective catalytic reduction (NSCR) (achieves 90 percent reduction)
¦ Selective catalytic reduction (SCR) (achic\ cs on percent reduction)
¦ Selective noncatalytic reduction (SNCR) (achieves 90 percent reduction)
Based on the literature review and the new cost data identified for Lean Burn control
technologies, several changes to the CMDB are recommended. No changes to existing records in
CMDB are recommended. The following sections outline the additions and other comments
recommended for the CMDB in relation to NOx emissions from Lean Burn Engines.
5.1 Literature Search
In order to update the existing control measures database, a literature search was
conducted for articles and papers published since 2008 (to include 2008 through August 2013)
using the following terms:
¦ engine
¦ lean burn
¦ cost
¦ NOx or "nitrogen oxides"
¦ scr or "selective catalytic reduction"
¦ turbocharge
5-1
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¦ air/fuel ratio
¦ layered combustion
¦ high energy ignition
¦ high pressure fuel injection
¦ "low emission control" or LEC
¦ electronic engine control
¦ combustion modification
¦ timing
¦ exhaust gas recirculation
¦ lean NOx catalyst
¦ lean NOx trap
¦ control efficiency
¦ emission reduction
The literature search identified a total of 19 references, and the abstracts for these
references were reviewed. Three references of potential interest were identified and two of these
were obtained for review in the lean burn engine control device study.
5.2 Document Review
A brief summary of data from each reference reviewed in included in the spreadsheet
"CoSTleanburn.xlsx," in worksheet "Overall Sum—New Ref Review." The information and
data available from each reference is provided in table format, along with indication of whether
the data were used or not.
There are 6 control technique additions to be added to the CMDB from 5 references.
The recommended additions include:
¦ Low Emission Combustion, LEC (for natural gas engines);
¦ Layered Combustion, LC (for 2 stroke natural gas engines);
¦ Layered Combustion, LC (for 2 stroke Large Bore natural gas engines);
5-2
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¦ Air to Fuel Ratio Controller, AFRC;
¦ Selective Catalytic Reduction, SCR (for 4 stroke natural gas engines); and
¦ SCR (for diesel engines).
Recent cost data for these control techniques were available from reports dated 2001
through 2012.
The references for the added control techniques are included on the "Table 06
References" worksheet and are as follows:
OTC 2012. Technical Information Oil and Gas Sector, Significant Stationary Sources of NOx
Emissions. Final. October 17, 2012.
SJVAPCD 2003. RULE 4702—Internal Combustion Engines—Phase 2. Appendix B, Cost
Effectiveness Analysis for Rule 4702 (Internal Combustion Engines—Phase 2). San
Joaquin Valley Air Pollution Control District. July 17, 2003.
www, arb. ca. gov/pm/pmmeasures/ceffect/rul es/si vaped 4702. pdf
CARB 2001. Determination of Reasonably Available Control Technology and Best Available
Retrofit Control Technology for Stationary Spark-Ignited Internal Combustion Engines.
California Environmental Protection Agency, Air Resources Board, Stationary Source
Division, Emissions Assessment Branch, Process Evaluation Section. November 2001.
EPA 2010. Alternative Control Techniques Document: Stationary Diesel Engines. March 5,
2010.
PA DEP 2013. Technical Support Document General Permit GP-5. Pennsylvania Department of
Environmental Protection. Bureau of Air Quality. January 31, 2013.
5.3 Low Emission Combustion (LEC) (NLECICENG)
The costs and cost effectiveness for applying LEC to natural gas Lean Burn engines are
obtained from the document Appendix B, Cost Effectiveness Analysis for Rule 4702 (Internal
Combustion Engines Phase 2) (SJVAPCD 2003). Information was provided on Capital costs,
Annual costs, uncontrolled emissions, and reduction efficiency. The assumptions for the original
reference analysis are provided in Table 5-1 for LEC along with changes in assumptions for the
current analysis.
LEC are described as retrofit kits that allow engines to operate on extremely lean fuel
mixtures to minimize NOx emissions. The LEC retrofit may include: (1) redesign of cylinder
head and pistons to improve mixing (on smaller engines), (2) Precombustion chamber (on larger
engines), lower cost, simple versions, (3) Turbocharger, (4) High energy ignition system,
5-3
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Table 5-1. LEC for Natural Gas Lean Burn Engines
Assumptions in Original Reference
Changes to Assumptions Made in Current Analysis
Capital costs
Control efficiency: 80%
Capital costs: provided for multiple models
Annual Costs
Equipment life: 10 yr
Interest rate: 10%
Operating hours: 2000 hr/yr
Emission rate, uncontrolled: 740 ppmv
Emission rate, controlled: 80% reduction
Annualized equipment cost: provided for multiple
model sizes
None.
None.
None.
Interest rate: 7%
None.
Emission rate, uncontrolled: Assumed in id 10 upper end
hp rating for each model.
Xone
( Kl u 1424
Annual O&M cost: assumed $0.
None
(5) Aftercooler, and (6) Air to fuel ratio controller. (A discussion of individual technologies is
provided in Appendix B of the original reference, pp. B-l to B-28). No detail was provided on
the exact combination of combustion modifications included in the example cost analysis; some
references indicate that LEC on larger engines often includes aPCC (p.B-10) (CARB 2001).
LEC are known or demonstrated control techniques for lean burn engines. An 80 percent NOx
emission reduction can be achieved by LEC with little or no fuel penalty (in fact, LEC
technologies are expected to decrease fuel consumption because they result in leaner burning
engine, though the costs do not account for fuel consumption decrease). The original reference
assumed an 80 percent reduction in the cost example.
Capital and annual costs were provided for multiple size ranges of engines. The capital
costs ranged from $14,000 to $256,000. Costs for the 1000 to 3000 hp model were given as
$40,000 to $256,000, and a mid-range cost of $148,000 was assumed in the current analysis. The
total annual costs ranged from $2,000 to $21,000 (these costs are very similar to the costs
calculated in the original reference analysis). The original reference assumed there are no annual
operation and maintenance costs incurred from the combustion modification technologies, and
the only annual cost provided is for annualized capital costs. No emission reductions are
provided in the document (however the final cost effectiveness values are provided and the
reduction assumed in the original analysis can be back-calculated). In the current analysis, a hp
5-4
-------
rating based on the middle or upper end of each size range was assumed for estimating the
uncontrolled NOx emissions. An estimate of emissions was made in the current analysis.
Uncontrolled NOx emissions were estimated based on an uncontrolled NOx concentration of 740
ppmv (this equates to approximately 9 g/bhp-hr), the operating hours were provided as 2000
hr/yr in the original reference, and controlled emissions were estimated based on 80 percent
reduction as stated in the reference. Uncontrolled NOx emissions ranged from 1.1 to 34 tpy for
the models, and the NOx reductions ranged from 0.90 to 27 tpy for the models
The current analysis shows a cost effectiveness of $2,200/ton of NOx reduction lo
$780/ton for 2000 hr/yr operation, and the average cost effectiveness across all the models is
$l,000/ton of NOx reduction.
The cost year is not provided in the reference; assumed the cost year is the date of the
cited reference, 2001$.
Based on the cost calculations for engines of varying hp, the following equations were
developed for the capital cost and annual costs for l.F.C on natural gas Lean Burn engines:
Capital cost = 16019 e 0 00,6x(hP)
Annual cost = 2280.8 e 0 0016x(hP)
The R2 value for these equations is 0.96. These equations should be included in the CoST
database file under a new equation type.
See the cost calculations in worksheet "LEC (CARB)-2001" of the Excel file.
5.4 Layered Combustion (LC), 2 Stroke (NLCICE2SNG)
The costs and cost effectiveness for applying LC to natural gas Lean Burn engines (2
stroke) are obtained from the document Technical Information Oil and Gas Sector, Significant
Stationary Sources of NOx Emissions (OTC 2012). Information was provided on Capital costs;
assumptions were made to determine Annual costs, uncontrolled emissions, and reduction
efficiency. The assumptions for the original reference analysis are provided in Table 5-2 for LC
for 2 stroke engines, along with changes in assumptions for the current analysis.
LC consists of multiple combustion modification technologies. The combustion
modifications included in this example are related to (1) Air supply; (2) Fuel supply, (3) Ignition,
(4) Electronic controls, and (5) Engine monitoring (a discussion of individual technologies is
provided on pp. 17 to 19 for 2 stroke Lean Burn engines). No significant detail was provided on
which specific combustion modification technologies were applied. In the example study, 3 of
5-5
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the most representative manufacturer and models of 2 stroke Lean Burn engines used for integral
compressors were selected for evaluation; these 3 engines were Cooper GMVH-10 2250 hp,
Table 5-2. LC for Natural Gas Lean Burn Engines, 2-stroke
Assumptions in Original Reference
Capital costs
Control efficiency: Not provided.
Capital costs: based on cited ERLE 2009 project
(First unit upgrade costs)
Annual Costs
Equipment life: Not provided.
Interest rate: Not provided.
Operating hours: Not provided.
Emission rate, uncontrolled: Not provided
Emission rate, controlled: 0.5 g/bhp-hr
Annualized equipment cost: Not provided.
Annual O&M cost: Not provided.
Changes to Assumptions Made in Current Analysis
Control efficiency: derived value is 97% (this is high)
Capital costs: used average based on the provided range
for each make/model engine.
Equipment life: 10 yr
Interest rale: 7%
Operating hours: 2000 lvr/yr
Emission rale, uncontrolled: 16.8 g/bhp-hr
None.
CRF: 0.1424
Annual O&M cost: $0.
Clark TLA-6 2000 hp, and Cooper GMW-10 2500 hp (cited ERLE 2009 report "ERLE Cost
Study of the Retrofit Legacy Pipeline Engines to Satisfy 0.5 g/bhp-hr NOx"). LC are known or
demonstrated control techniques for lean burn, 2 stroke engines. A NOx emissions rate of 0.5
g/bhp-hr was achieved. The OTC 2012 document provided an estimate of the capital cost range
for retrofitting technologies to achie\ c the outlet NOx limit for each engine. An average cost
based on the range was estimated lor each engine and used in the current analysis. Details on the
buildup of these costs are not provided in the OTC 2012 document. No annual costs are provided
in the document. No emission reductions are provided in the document.
Based on the review of other references in this analysis, it was assumed that there are no
additional annual operating costs incurred from the combustion modification technologies,
except for annualized capital costs (CARB 2001). Because no emission reduction data were
provided, an estimate of emissions was made in the current analysis. Uncontrolled NOx
emissions were assumed to be 16.8 g/bhp-hr (EPA 2003), controlled emissions were 0.5 g/bhp-hr
as stated in the reference, and the operating hours were assumed to be 2000 hr/yr (this
assumption is consistent with the LEC operating hours in the CARB 2001 document).
5-6
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Uncontrolled NOx emissions for the 3 similar sized engines ranged from 74 to 93 tpy, and the
NOx reductions ranged from 72 to 90 tpy.
Based on the 3 make and model engines, the average cost was estimated to be $2,800,000
for approximately 2250 hp engines (average hp of the 3 units), and the average total annual cost
was estimated to be $390,000. The average cost effectiveness is $4,900/ton of NOx reduction for
2000 hr/yr operation.
The cost year is not provided in the reference; we assumed the cost year is ihe dak- of the
cited Cameron 2010 retrofit project, 2010$.
See the cost calculations in worksheet "Overall Sum—New Ref Review" of the Excel
file, rows 21 through 25.
5.5 Layered Combustion (LC), Large Bore, 2 Stroke, Low Speed (NLCICE2SLBNG)
The costs and cost effectiveness for applying LC to natural gas Lean Burn engines (2
stroke Large Bore) are obtained from the document Technical Information Oil and Gas Sector,
Significant Stationary Sources of NOx Emissions (OK' 2<) 12). Large Bore RICE are those with
large piston diameters. The larger the bore (or piston diameter), the larger the volume available
for engine combustion, and hence the greater the power delivered by the engine. Information was
provided on Capital costs; assumptions were made to determine Annual costs, uncontrolled
emissions, and reduction efficiency. The assumptions for the original reference analysis are
provided in Table 5-3 for 1 ,C for large bore 2 Stroke engines, along with changes in assumptions
for the current analysis
LC consists of multiple combustion modification technologies. The combustion
modifications included (1) High pressure fuel injection; (2) Turbocharging, (3) Precombustion
chamber, and (4) Cylinder head modifications (a discussion of individual technologies is
provided on pp. 18 to 19 for 2 stroke Lean Burn engines). LC are known or demonstrated control
techniques for lean burn, large bore, 2 stroke engines. These modifications achieved a NOx
emissions rate of 0.5 g/bhp-hr. The OTC 2012 document provided ranges of capital costs for
retrofitting combustion modifications for large bore 2 stroke Lean Burn engines from 200 to
11,000 hp (cited Cameron 2011 presentation "Available Emission Reduction Technology for
Existing Large Bore Slow Speed Two Stroke Engines." A copy of this presentation was not
found.). Details on the buildup of these costs are not provided in the OTC 2012 document. No
annual costs are provided in the document. No emission reductions are provided in the
document.
5-7
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Based on the review of other references in this analysis, it was assumed that there are no
additional annual operating costs incurred from the combustion modification technologies,
except for annualized capital costs (CARB 2001). Because no emission reduction data were
provided, an estimate of emissions was made in the current analysis. Uncontrolled NOx
Table 5-3. LC for Natural Gas Lean Burn Engines, Large Bore 2-stroke
Assumptions in Original Reference
Changes to Assumptions Made in Current Analysis
Capital costs
Control efficiency: Not provided.
Capital costs: based on cited Cameron 2010
project
Annual Costs
Equipment life: Not provided.
Interest rate: Not provided.
Operating hours: Not provided.
Emission rate, uncontrolled: Not provided
Emission rate, controlled: 0.5 g/bhp-hr
Annualized equipment cost: Not provided.
Annual O&M cost: Not provided.
Control efficiency: derived value is 97% (this is high)
None.
Equipment life: 10 yr
Interest rale: 7%
Operating hours: 2.000 hr/yr
Emission rale, uncontrolled: 16.8 g/bhp-hr
None
( Kl u 1424
Annual O&M cost: $0.
emissions were assumed to be 16.8 g/bhp-hr (EPA 2003), controlled emissions were 0.5 g/bhp-hr
as stated in the reference, and the operating hours were assumed to be 2000 hr/yr (this
assumption is consistent with the LEC operating hours in the CARB 2001 document).
Uncontrolled NOx emissions were estimated to be 410 tpy for the larger 11,000 hp engines and
were estimated to be 7.4 tpy for the smaller 200 hp engines.
For the larger 11,000 hp engines, the current analysis shows a cost effectiveness of
$l,500/ton of NOx reduction, and for the smaller 200 hp engines, the cost effectiveness is
$38,000/ton of NOx reduction.
The cost year is not provided in the reference; assumed the cost year is the date of the
cited Cameron 2010 retrofit project, 2010$.
See the cost calculations in worksheet "Overall Sum—New Ref Review" of the Excel
file, rows 12 and 13.
5-8
-------
5.6 Air to Fuel Ratio Controller (AFRC) (NAFRCICENG)
The costs and cost effectiveness for applying AFRC to natural gas Lean Burn engines are
obtained from the document Determination of Reasonably Available Control Technology and
Best Available Retrofit Control Technology for Stationary Spark-Ignited Internal Combustion
Engines (CARB 2001). Information was provided on Capital costs; assumptions were made to
determine Annual costs, uncontrolled emissions, and reduction efficiency. The assumptions for
the original reference analysis are provided in Table 5-4 for AFRC, along with changes in
assumptions for the current analysis.
Table 5-4. AFRC for Natural Gas Lean Burn Engines
Assumptions in Original Reference
Capital costs
Control efficiency: not provided
Capital costs: provided for multiple models
Annual Costs
Equipment life: 10 yr
Interest rate: 10%
Operating hours: 2000 hr/yr
Emission rate, uncontrolled: 740 ppmv
Emission rate, controlled: 80% reduction
Annualized equipment cost pan ided for multiple
model sizes
Annual O&M cost: assumed V).
Changes to Assumptions Made in Current Analysis
Control efficiency: assumed 20%
None.
None.
Interest rate: 7%
None.
Emission rate, uncontrolled: Assumed mid to upper end
hp rating for each model.
None.
CRF: 0.1424
None.
AFRC are electronic engine controls that typically monitor engine parameters and
atmospheric conditions to determine the correct air/fuel mixture for the operating condition, such
as varying engine load or speed conditions, varying ambient conditions, or startup/shutdown
conditions. (OTC 2012) (A discussion of individual technologies is provided in Appendix B of
the original reference, CARB 2001, pp. B-l to B-28). AFRC are known or demonstrated control
techniques for lean burn engines. An 80 percent NOx emission reduction can be achieved by
AFRC in combination with other combustion modifications, however a fuel consumption penalty
of up to 3 percent can occur due to AFRC.
Capital were provided for multiple size ranges of engines. The capital costs ranged from
$4,200 to $6,500 per engine.
5-9
-------
No annual costs were provided in the document. No emissions reductions were provided
in the document. Based on the cost analysis for other combustion technology controls in this
document, it was assumed that there are no additional annual operating costs incurred from the
combustion modification technologies, except for annualized capital costs (this assumption
ignores the fuel penalty issue). The total annual costs ranged from $600 to $930. Because no
emission reductions were provided in the document, an estimate of emissions was made in the
current analysis. In the current analysis, a hp rating based on the middle or upper end of each size
range was assumed for estimating the uncontrolled NOx emissions. Uncontrolled NOx emissions
were estimated based on an uncontrolled NOx concentration of 740 ppmv (this equates to
approximately 9 g/bhp-hr), the operating hours were assumed to be 2000 hr/yr (similar to the
operating hours for other control technology analyses provided in the document), and controlled
emissions were estimated based on an assumption of 20 percent reduction. Uncontrolled NOx
emissions ranged from 1.1 to 34 tpy for the models, and the NOx reductions ranged from 0.22 to
6.7 tpy for the models.
The current analysis shows a cost effectiveness of $2,700/ton of NOx reduction to
$140/ton for 2000 hr/yr operation, and the average cost effectiveness across all the models is
$810/ton of NOx reduction.
The cost year is not provided in the reference; assumed the cost year is the date of the
cited reference, 2001$.
Based on the cost calculations for engines of varying hp, the following equations were
developed for the capital cost and annual costs for AFRC on natural gas Lean Burn engines:
Capital cost= 1.3007 x (hp) + 4354.5
Annual cost = 0.1852 x (hp) + 619.99
The R2 value for these equations is 0.87. These equations should be included in the CoST
database file under a new equation type.
See the cost calculations in worksheet "AFRC (CARB)-2001" of the Excel file.
5.7 SCR (for 4 Stroke Natural Gas Engines) (NSCRICE4SNG)
The costs and cost effectiveness for applying SCR to natural gas engines are obtained
from the document Appendix B, Cost Effectiveness Analysis for Rule 4702 (Internal Combustion
5-10
-------
Engines—Phase 2) (SJVAPCD 2003). Information was provided on Capital costs, Annual costs,
uncontrolled emissions, and reduction efficiency. The assumptions for the original reference
analysis are provided in Table 5-5 for SCR for natural gas engines along with changes in
assumptions for the current analysis. SCR is a known or demonstrated control technique for lean
burn engines, although multiple references indicate that the feasibility of SCR application for
lean burn engines is highly site-specific.
Table 5-5. SCR for Natural Gas Lean Burn Engines, 4-stroke.
Assumptions in Original Reference
Capital costs
Control efficiency: 90%
Capital costs: based on RACT/BARCT
Determination.
Annual Costs
Equipment life: 10 years
Interest rate: 10%
Operating hours rate 1: 2190 hr/yr (equivalent to
capacity factor of 0.25)
Operating hours rate 2: 6570 hr/vr (cquivalciii lo
capacity factor of 0.75)
Emission rate, unconlrollcd: 740 ppmv NOx
Emission rate, controlled: 65 ppmv NOx
Annualized equipment cost: based on
RACT/BARCT Determination.
Annual O&M cost: based on RACT/BARCT
Determination.
Changes to Assumptions Made in Current Analysis
None.
None
None
lnkTcsl rale
None
\i»ne
None.
None.
None.
None.
The installed equipment capital cost ranged from $45,000 to $185,000 for 50 hp engines
and 1500 hp engines, respectively. The total annual costs ranged from $27,000 for a 50 hp
engine to $ 140,000 for a 1500 hp engine (these costs are very similar to the costs calculated in
the original reference analysis; the only difference in annual costs is related to the CRF, i.e.,
changing the interest rate from 10 percent in the original reference analysis to 7 percent in the
current analysis). NOx emissions are provided for two cases: a capacity factor of 0.25 (2190
hr/yr) and a capacity factor of 0.75 (6570 hr/yr). The uncontrolled NOx emissions ranged from
1.2 to 37 tpy for the lower capacity case, and the NOx reductions ranged from 1.1 to 33 tpy. For
the higher capacity case, uncontrolled NOx emissions ranged from 3.7 to 110 tpy, and the NOx
reductions achieved ranged from 3.3 to 100 tpy. The current analysis shows an average cost
5-11
-------
effectiveness of $8,700/ton of NOx reduction for 2190 hr/yr of operation, and $2,900/ton of NOx
reduction for 6570 hr/yr operation (these cost effectiveness values are very similar to the costs
shown in the original reference analysis).
Based on the cost calculations for engines of varying hp and annual capacity operating,
the following linear equations were developed for the capital cost and annual costs for SCR on
natural gas 4-stroke lean burn engines:
Capital cost = 107.1 x (hp) + 27186
Annual cost = 83.64 x (hp) + 14718
The R2 values for these equations are 0.95 for capital cost and 0.98 for annual cost. These
equations should be included in the CoST database file under a new equation type for linear
equations.
The cost year is not provided in the reference: assumed the cost year is the date of the
cost-basis document, 2001$.
See the cost calculations in worksheet "SCR NG (SJVAPCD)-2003" of the Excel file.
[Other cost effectiveness values for SCR are available from the PA DEP that are higher than the
cost effectiveness values shown for the SJ VAPCD SCR analysis, and other analyses. See the
summary of SCR costs in worksheet "Other SCR Cost Info" of the Excel file.]
5.8 SCR (for Diesel Engines) (NSCRICEDS)
The costs and cost effectiveness for applying SCR to diesel lean burn engines is provided
in Alternative Control Techniques Document: Stationary Diesel Engines (EPA 2010). The
assumptions for the original reference analysis are provided in Table 5-6 for SCR for diesel
engines, along with changes in assumptions for the current analysis. SCR is a known or
demonstrated control technique for lean burn, diesel engines.
Approximately 76 percent of the population of stationary diesel engines is less than 300
hp and the remaining 24 percent is greater than 300 hp. Applications for stationary engines under
300 hp include standby power generation, agriculture, and industrial applications, and less than 5
percent are used for continuous power generation. Applications for stationary engines greater
than 300 hp are primarily power generation and are almost evenly divided between continuous
duty and standby applications.
5-12
-------
The cost analysis provided in the original reference includes an assumption that
stationary diesel lean burn engines operate approximately 1000 hr/yr. This assumption is likely
appropriate for the majority of those units that are less than 300 hp and for half of the diesel
engines greater than 300 hp, i.e., approximately 87 percent of diesel lean burn engines (this
ignores the "fewer than 5 percent" used for continuous power generation). For the remaining 13
percent of engines that are greater than 300 hp and used in continuous power generation
applications, an assumption for longer operating hours, such as 8000 hr/yr, may be needed to
estimate the cost effectiveness.
Table 5-6. SCR for Diesel Lean Burn Engines—Assumptions
Assumptions in Original Reference Changes to Assumptions Made in Current Analysis
Capital costs
Control efficiency: 90 % None.
Equipment life: 15 year None.
Interest rate: 7% None
Capital costs: $98/hp None
Annual Costs
Operating hours: 1000 hr/yr None.
Annual costs: $40/hp (based on 1000 hr/vr None.
operation; already includes Capital Recovery)
The original reference analysis provided a capital cost of $98/hp, and based on the mid-
range hp rating for four model engines, the capital costs ranged from $7,300 to $98,000 for SCR.
The original reference analysis provided an annual cost of $40/hp, and the annual costs ranged
from $3,000 to $40,000 per year. Uncontrolled NOx emissions factors in the original reference
were based on Tier 0 to Tier 3 values1 and an assumption of 1000 hr/yr operation. Uncontrolled
NOx emissions range from 0.25 to 9.2 tpy across the four models, and the NOx reductions
ranged from 0.22 to 8.3 tpy.
The current analysis shows an average cost effectiveness of $9,300/ton of NOx reduction
for 1000 hr/yr of operation (no weighting to the average based on engine age was applied). The
cost effectiveness over the engine size range varied from $4,800/ton to $16,000/ton for diesel
engines (and are very similar to the costs shown in the original reference analysis). It is
1 Federal Standards, from the Exhaust and Crankcase Emission Factors for Nonroad Engine Modeling—
Compression Ignition. EPA Publication No. EPA420-P-04 009. April 2004.
5-13
-------
important to note that the cost effectiveness is correlated to the manufacturing year of the diesel
engine, i.e., the Tier limit for NOx emissions. Older engines manufactured prior to 1998 have the
most lenient emissions limit while later model years have more stringent NOx emission limits
(lower baseline emissions). The overall magnitude of emission reduction achieved by the SCR is
lower for later model years as compared to earlier years, and therefore, the cost effectiveness
values are higher for later model years.
[Note: This analysis shows emission reductions and cost effectiveness lor existing and
new diesel engines through approximately 2011, the last year for phase in of the Tiered emission
values. The original reference provided information (circa 2005) on the age of the stationary
engine population, with approximately 57 percent of engines at that time being manufactured
prior to 1994 and approximately 42 percent manufactured after 1994 (note that the grouping of
the age data does not align well with the Tier years, in that the age data shows breaks in 1994
and 2003 while the Tier ranges show breaks in 1996, 1998, 2002, 2003, etc.). As the diesel
engine population continues to age and older engines are retired (i.e., those diesel engines subject
to the Pre-1998 and the Tier 1 (1998 to 2003) or Tier 1 (1996 to 2001), etc. and are replaced with
newer engines achieving lower NOx baseline emissions, the cost effectiveness for new engines
would tend to be in the higher end shown for each model and would contribute to a somewhat
higher average cost-effectiveness value. The average cost effectiveness will likely move toward
the $13,000/ton to $16,000/ton of NOx reduction range.]
See the cost calculations in worksheet "SCR Diesel (EPA Dies ACT)-2010" of the Excel
file.
5.9 Applicable SCCs for Lean Burn Engine Control Measures
Table 5-7 lists all of the ICE SCCs that are associated with one or more gas lean burn
ICR control measures in the CMDB table called "Table 03_SCCs." These SCCs were identified
with NOx emissions in an EPA query of the NEI for facilities in the Ozone Transport Group
Assessment Region (i.e., 37 states that are partially or completely to the east of lOOoW
longitude). The control measures shown in the column headings in Table 5-7 are the ICE control
measures that are currently in the CMDB. Each control measure that was determined to be
applicable for a specific SCC is identified with an "N" in the cell, meaning the control measure is
"new," i.e., not currently linked to this particular SCC, but we recommend adding this link in the
database. In some cases, we recommend applying new links between existing control measures
and existing SCCs. For example, some of the SCCs are for ICE that are fired with relatively
uncommon fuels such as process gas, methanol, digester gas, or landfill gas. While we have not
5-14
-------
Table 5-7. Potential Reciprocating Engine SCCs to Add to the CMDB and Applicable Control Measures
Applicable Conl ml Measures lur the Reciprocating Engine SCCd
SCCa
SCC
Level SCC
lb Level 2C
in
O
U
in
o
u
SCC Level 3
SCC Level 4
§
U
HH
£5
/¦
o
u
o
o
d
o
u
SS s s
§
u
HH
M
u
{*)
l/l
o
u
HH
M
u
{*)
hJ
o
u
HH
u
d
o
u
u
o
u
HH
u
z
20200702
ICE
Ind
Process Gas
Reciprocating Engine
N
N
N
20200712
ICE
Ind
Process Gas
Reciprocating: Exhaust
\
\
N
N
N
20201602
ICE
Ind
Methanol
Reciprocating Engine
N
20201607
ICE
Ind
Methanol
Reciprocating: Exhaust
\
N
20201702
ICE
Ind
Gasoline
Reciprocating Engine
N
N
20201707
ICE
Ind
Gasoline
Reciprocating: Exhaust
N
N
20280001
ICE
Ind
Equipment Leaks
Equipment Leaks
20282001
ICE
Ind
Wastewater, Aggregate
Process Area Drains
20300702
ICE
C/I
Digester Gas
Reciprocating: POTW Digester Gas
N
N
N
N
N
20300707
ICE
C/I
Digester Gas
Reciprocating: Exhaust
N
N
N
N
N
20300802
ICE
C/I
Landfill Gas
Reciprocating
N
N
N
N
N
20400401
ICE
ET
Reciprocating Engine
Gasoline
N
N
20400402
ICE
ET
Reciprocating Engine
Diesel/Kerosene
N
N
N N
N
N
20400404
ICE
ET
Reciprocating Engine
Process Gas
N
N
N
N
20400406
ICE
ET
Reciprocating Engine
Kerosene/Naphtha (Jet Fuel)
N
N
20400409
ICE
ET
Reciprocating ] ingine
Liquified Petroleum Gas (LPG)
N
N
aSCCs represent reciprocating engine activities thai were identified with NOx emissions in the Ozone Transport Assessment Group Region analysis but are not
associated with reciprocating engine control measures in the current CMDB.
bICE means "Internal Combustion Engines."
°Ind means "Industrial," C/I means "Commercial/Institutional," and ET means "Engine Testing."
dThe control measure is assumed to be representative for the SCC; control cost data are unavailable for the specific fuel type for the SCC.
-------
located any analyses that determined the applicable controls and related costs for ICE fired with
such fuels, similar control measures can be assigned to these SCCs. In order to conduct CoST
modeling analyses for these ICE, the most representative available control measures could be
assigned. For ICE that burn miscellaneous gaseous fuels, the most representative control
measures are those for natural gas-fired ICE. Similarly, for ICE that burn miscellaneous liquid
fuels such as methanol, gasoline, kerosene/diesel, and LPG, the most representative available
control measures are those for gas- or diesel-fired ICE. Also, for ICE that burn liquid fuels such
as diesel/kerosene, the most representative available control measures are those for gas-, diesel-,
or oil-fired ICE.
Six new control measures have been added to the CMDB for lean burn engines under this
review and these control measures are described in Sections 5.3 through 5.8 of this report.
Table 5-8 lists those SCCs that should be associated with the newly added lean burn engine
control measures. Each control measure that was determined to be applicable for a specific SCC
is identified by a "Y," which means yes.
In Table 5-9, a number of recommendations were made to delete NOx control
measure/SCC combinations from the CMDB. ICE SCCs for evaporative losses from fuel storage
and delivery systems are incorrectly associated with NOx control measures in the current
CMDB, and we recommend deleting these all NOx control measure/SCC records from the
CMDB table called "Table 03_SCCs" because there should be no NOx emissions from the
sources represented by these SCCs. In addition, multiple ICE control measures are misassigned
to turbine SCCs and we recommend deleting these NOx control measure/SCC records. The
reverse issue also exists where multiple turbine control measures are misassigned to ICE SCCs,
and we recommend deleting these NOx control measure/SCC records, as well. These control
measure/SCC combinations are identified in Table 5-9.
5.10 Pennsylvania General Permit 5 (GP-5) for Natural Gas Compression and/or
Processing Facilities
Pennsylvania DEP recently released a general permit for Natural Gas Compression
and/or Processing Facilities that includes limits on NOx emissions from ICE. NOx emission
limits from this general permit, along with other NOx limits for Pennsylvania, are shown in
Table 5-10. Typical emission rates and the cost-effectiveness values for applying certain control
measures are shown for lean burn and rich burn engines in Table 5-11.
5-16
-------
Table 5-8. Recommended New Control Measures to Associate With Lean Burn Reciprocating Engine SCCs in the CMDB
Applicable Control Measures for the Lean Burn
Reciprocating Engine SCC
O
z
w
y
O
z
in
r\
W
O
z
CO
hJ
l/l
r\
W
O
z
w
U
HH
u
O
z
l/l
w
y
VI
O
w
y
scca
SCC Level 1
SCC Level 2
SCC Level 3
SCC Le\ el 4
u
w
-j
z
u
HH
u
hJ
z
u
HH
u
hJ
z
g
zi
5
u
i/i
z
5
u
VI
Z
20200102
Internal Combustion Engines
Industrial
Distillate Oil (Diesel)
Reciprocating
Y
20200107
Internal Combustion Engines
Industrial
Distillate Oil (Diesel)
Reciprocating: Exhaust
Y
20200252
Internal Combustion Engines
Industrial
Natural Gas
2-cycle Lean Burn
Y
Y
Y
Y
Y
20200254
Internal Combustion Engines
Industrial
Natural Gas
4-cycle Lean Burn
Y
Y
Y
Y
Y
20200255
Internal Combustion Engines
Industrial
Natural Gas
2-cycle Clean Burn
Y
Y
Y
Y
Y
20200256
Internal Combustion Engines
Industrial
Natural Gas
4-cycle Clean Burn
Y
Y
Y
Y
Y
2020040lb
Internal Combustion Engines
Industrial
Large Bore Engine
Diesel
Y
20200402b
Internal Combustion Engines
Industrial
Large Bore Engine
Dual Fuel (Oil/Gas)
Y
20200403 b
Internal Combustion Engines
Industrial
Large Bore Engine
Cogeneration: Dual Fuel
Y
aSCCs represent reciprocating engine activities thai were identified with NO.\ emissions in the recent Ozone Transport Region analysis but are not associated
with reciprocating engine control measures in the current CMDB.
bThe control measure is assumed to be representative for the SCC: control cost data arc unavailable for the specific fuel type for the SCC.
-------
Table 5-9. Recommended Control Measure Deletions From SCCs in the CMDB
see
SCC Level 1
SCC Level 2
SCC Level 3
SCC Level 4
Control Measures
Recommended for Deletion
20200106
Internal Combustion Engines
Industrial
Distillate Oil (Diesel)
Reciprocating:
Losses
Evap
All NOx control measures
20200206
Internal Combustion Engines
Industrial
Natural Gas
Reciprocating:
Losses
Evap
All NOx control measures
20200306
Internal Combustion Engines
Industrial
Gasoline
Reciprocating:
Losses
Evap
All NOx control measures
20200406
Internal Combustion Engines
Industrial
Large Bore Engine
Reciprocating:
Losses
Evap
All NOx control measures
20200506
Internal Combustion Engines
Industrial
Residual/Crude Oil
Reciprocating:
Losses
Evap
All NOx control measures
20200906
Internal Combustion Engines
Industrial
Kerosene/Naphtha (.lei Fuel)
Reciprocating:
Losses
Evap
All NOx control measures
20201006
Internal Combustion Engines
Industrial
Liquified Petroleum Gas (LPG)
Reciprocating:
Losses
Evap
All NOx control measures
20300106
Internal Combustion Engines
Commercial/Institutional
Distillate Oil (Diesel)
Reciprocating:
Losses
Evap
All NOx control measures
20300206
Internal Combustion Engines
Commercial/Institutional
Natural Gas
Reciprocating:
Losses
Evap
All NOx control measures
20300306
Internal Combustion Engines
Commercial/Institutional
Gasoline
Reciprocating:
Losses
Evap
All NOx control measures
20301006
Internal Combustion Engines
Commercial/Institutional
Liquified Petroleum Gas (LPG)
Reciprocating:
Losses
Evap
All NOx control measures
20200108
Internal Combustion Engines
Industrial
Distillate Oil (Diesel)
Turbine: Evap Losses
All NOx control measures
20200109
Internal Combustion Engines
Industrial
Distillate Oil (Diesel)
Turbine: Exhaust
NNSCRRBIC
20200208
Internal Combustion Engines
Industrial
Natural Gas
Turbine: Evap Losses
All NOx control measures
20200209
Internal Combustion Engines
Industrial
Natural Gas
Turbine: Exhaust
NNSCRRBIC2
20200908
Internal Combustion Engines
Industrial
Kerosene/Naphtha (Jet Fuel)
Turbine: Evap Losses
All NOx control measures
20200909
Internal Combustion Engines
Industrial
Kerosene/Naphtha (Jet Fuel)
Turbine: Exhaust
NNSCRRBGD
(continued)
-------
Table 5-9. Recommended Control Measure Deletions From SCCs in the CMDB (continued)
see
SCC Level 1
SCC Level 2
SCC Level 3
SCC Level 4
Control Measures
Recommended for Deletion
20201008
Internal Combustion Engines
Industrial
Liquified Petroleum Gas (LPG)
Turbine: Evap Losses
All NOx control measures
20201009
Internal Combustion Engines
Industrial
Liquified Petroleum Gas (LPG)
Turbine: Exhaust
NNSCRRBGD
20201011
Internal Combustion Engines
Industrial
Liquified Petroleum Gas (LPG)
Turbine
NNSCRRBGD
20201013
Internal Combustion Engines
Industrial
Liquified Petroleum Gas (LPG)
Turbine: Cogeneration
NNSCRRBGD
20300108
Internal Combustion Engines
Commercial/Institutional
Distillate Oil (Diesel)
Turbine: Evap Losses
All NOx control measures
20300109
Internal Combustion Engines
Commercial/Institutional
Distillate Oil (Diesel)
Turbine: Exhaust
NNSCRRBIC
20300208
Internal Combustion Engines
Commercial/Institutional
Natural Gas
Turbine: Evap Losses
All NOx control measures
20300209
Internal Combustion Engines
Commercial/Institutional
Natural Gas
Turbine: Exhaust
NNSCRRBIC2
20200105
Internal Combustion Engines
Industrial
Distillate Oil (Diesel)
Reciprocating: Crankcase
Blowby
NNSCRWGTOL, NWTINGTOL
20200107
Internal Combustion Engines
Industrial
Distillate Oil (Diesel)
Reciprocating: Exhaust
NSCRWGTOL, NWTINGTOL
20200205
Internal Combustion Engines
Industrial
Natural Gas
Reciprocating: Crankcase
Blowby
NLNBUGTNG, NSCRLGTNG,
NSCRSGTNG, NSCRWGTNG,
NSTINGTNG, NWTINGTNG
20200207
Internal Combustion Engines
Industrial
Natural Gas
Reciprocating: Exhaust
NLNBUGTNG, NSCRLGTNG,
NSCRSGTNG, NSCRWGTNG,
NSTINGTNG, NWTINGTNG
20200252
Internal Combustion Engines
Industrial
Natural Gas
2-cycle Lean Burn
NLNBUGTNG, NSCRLGTNG,
NSCRSGTNG, NSCRWGTNG,
NSTINGTNG, NWTINGTNG
20200253
Internal Combustion Engines
Industrial
Natural Gas
4-cycle Rich Burn
NLNBUGTNG, NSCRLGTNG,
NSCRSGTNG, NSCRWGTNG,
NSTINGTNG, NWTINGTNG
20200254
Internal Combustion Engines
Industrial
Natural Gas
4-cycle Lean Burn
NLNBUGTNG, NSCRLGTNG,
NSCRSGTNG, NSCRWGTNG,
NSTINGTNG, NWTINGTNG
20200255
Internal Combustion Engines
Industrial
Natural Gas
2-cycle Clean Burn
NLNBUGTNG, NSCRLGTNG,
NSCRSGTNG, NSCRWGTNG,
NSTINGTNG, NWTINGTNG
(continued)
-------
Table 5-9. Recommended Control Measure Deletions From SCCs in the CMDB (continued)
see
SCC Level 1
SCC Level 2
SCC Level 3
SCC Level 4
Control Measures
Recommended for Deletion
20200256
Internal Combustion Engines
Industrial
Natural Gas
4-cycle Clean Burn
NLNBUGTNG, NSCRLGTNG,
NSCRSGTNG, NSCRWGTNG,
NSTINGTNG, NWUNGTNG
20200905
Internal Combustion Engines
Industrial
Kerosene/Naphtha (Jet Fuel)
Reciprocating: Crankcase
Blowby
NSCRWGTJF, NWTINGTJF
20200907
Internal Combustion Engines
Industrial
Kerosene/Naphtha (Jet Fuel)
Reciprocating: Exhaust
NSCRWGTJF, NWTINGTJF
20300105
Internal Combustion Engines
Commercial/Institutional
Distillate Oil (Diesel)
Reciprocating: Crankcase
Blowby
NNSCRWGTOL, NWUNGTOL
20300107
Internal Combustion Engines
Commercial/Institutional
Distillate Oil (Diesel)
Reciprocating: Exhaust
NSCRWGTOL, NWUNGTOL
20300205
Internal Combustion Engines
Commercial/Institutional
Natural Gas
Reciprocating: Crankcase
Blowby
NLNBUGTNG, NSCRLGTNG,
NSCRSGTNG, NSCRWGTNG,
NSTINGTNG, NWUNGTNG
20300207
Internal Combustion Engines
Commercial/Institutional
Natural Gas
Reciprocating: Exhaust
NLNBUGTNG, NSCRLGTNG,
NSCRSGTNG, NSCRWGTNG,
NSTINGTNG, NWUNGTNG
-------
Table 5-10. NOx Control Requirements for RICE in Pennsylvania
State
Source Category
Covered
NOx Control Level
Reference
Pennsylvania
153 tonNOx/season
>2400 hp: 3 g/bhp-hr (220 ppm)
IEPA 2007
Pennsylvania
(proposed
values)
[Assume
proposal was
201 lMar26]
General Permit—Natural
Gas Production and
Processing Facility, SI, ICE
Existing LB or RB, 100 to 1500 hp: 2 g/bhp-hr
New, Reconfigured, LB <100 hp: 2 g/bhp-hr
New, Reconfigured, LB 100 to 637 hp: 1 g/bhp-hr
New, Reconfigured, LB >637 hp: 0.5 g/bhp-hr
OTC 2012
Pennsylvania
(amended
2013Feb02)
Natural Gas Compression
and Processing, NG, SI,
ICE, includes facilities
with actual or potential
emissions <100 tpy NOx,
and <25 tpy NOx in 5
counties.
New, Reconfigured LB or RB, <100 hp: 2 g/bhp-hr
New, Reconfigured LB, 100 to 500 hp: 1 g/bhp-hr
New, Reconfigured LB, >500 hp: 0.5 g/bhp-hr
New, Reconfigured RB, 100 to 500 hp: 0.25 g/bhp-hr
New, Reconfigured RB, >500 hp: 0.2 g/bhp-hr
PA OKI'2013
Pennsylvania
Interstate Pollution
Transport Reduction,
Emission of NOx from
Stationary ICE
LB, >2400 hp: 3.0 g/bhp-hr
RICE, RB, >2400 hp: 1.5 g/bhp-hr
DE 2012
Table 5-11.
Characteristics of NOx
Kinissions and Controls for RICE
Engine Type and Uncontrolled
Size Emissions
Cost Effectiveness for
Emissions NOx Reductions
Reference
Lean burn
LB >500 hp
NA
SCR, stack test, 0.22 SCR: $71,000 to $60,000/ton
to 0.50 g/bhp-hr (for 500 to 4000 hp)
PADEP 2013,
p. 22
LB 100 to 500 hp 1 to 16.4 g/bhp-hr
NA SCR: >$42,000/ton
PADEP 2013,
p. 20
LB <100 hp
2 g/bhp-hr
2 g/bhp-hr SCR: >$48,000/ton
PADEP 2013,
p. 17
Rich burn
RB >500 hp
13 to 16 g/bhp-hr
NSCR: stack test, 0.02 NA
to 0.14 g/bhp-hr
PADEP 2013,
p. 28, 29
RB 100 to 500 hp 13 to 16.4 g/bhp-hr.
NA NSCR: $177/ton
PADEP 2013,
p. 25, 26
RB <100 hp
11.41 to 21.08 g/bhp-
hr
NSCR: <2 g/bhp-hr, at NSCR: <$650/ton for 100 hp
least 90% reduction NSCR. <$ j 200/ton for 50 hp
PADEP 2013,
p. 17
5-21
-------
APPENDIX A
AMMONIA REFORMERS
Copies of database tables showing all records for ammonia reformer controls,
highlighting revisions.
A-l
-------
Table A-l. CMDB Table 06 References (New)
Data Source
Description
AR-1
Indian Nations Council of Governments (INCOG), 2008: Indian Nations Council of Governments (INCOG), "Tulsa
Metropolitan Area 8-Hour Ozone Flex Plan: 2008 8-03 Flex Program," March 6. 2008. Downloaded from
htto://www.era.eov/ozoneadvance/i3dfs/Flex-Tulsa.i3df
t>
K>
-------
Table A-2. CMDB Table 01 Summary
cmname
Cm
Abbreviation
Pechan
Meas
Code
Major
Poll
Control
Technoloqv
Source Group
Sector
Class
Equip
Life
Nei Device
Code
Date
Reviewed
Data
Source
Months
Description
Low NOx
Burner;
Ammonia—NG-
Fired Reformers
NLNBUFRNG
N0561
NOx
Low NOx
Burner
Ammonia—NG-Fired
Reform ers
ptnonipm
Known
10
204|205
2013
AR-1 1186
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions. LNBs
reduce the amount of NOx created from reaction between fuel nitrogen and oxygen by lowering the
temperature of one combustion zone and reducing the amount of oxygen available in another.
This control is applicable to small (<1 ton NOx per OSD) ammonia production operations with natural gas-
fired reformers (SCC 30100306) and uncontrolled NOx emissions greater than 10 tons per year.
Discussion: LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-
rich combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-air
LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion zone.
Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of excess air,
which acts as a heat sink to lower combustion temperatures (EPA, 2002).
Low NOx
Burner and Flue
Gas
Recirculation;
Ammonia—NG-
Fired Reformers
NLNBFFRNG
N0562
NOx
Low NOx
Burner and
Flue Gas
Recirculation
Ammonia—NG-Fired
Reform ers
ptnonipm
Known
10
2006
72|172|175|
179|186
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation (FGR) to
reduce NOx emissions. LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount of oxygen available
in another.
This control is applicable to small (<1 ton NOx per OSD) ammonia production operations with natural gas-
fired reformers (SCC 30100306) and uncontrolled NOx emissions greater than 10 tons per year.
Discussion: LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-
rich combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-air
LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion zone.
Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of excess air,
which acts as a heat sink to lower combustion temperatures (EPA, 2002).
Low NOx
Burner and Flue
Gas
Recirculation;
Ammonia—Oil-
Fired Reformers
NLNBFFROL
N0572
NOx
Low NOx
Burner and
Flue Gas
Recirculation
Ammonia—Oil-Fired
Reform ers
ptnonipm
Known
10
2006
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation (FGR) to
reduce NOx emissions. LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount of oxygen available
in another.
This control is applicable to ammonia production operations with oil-fired reformers (SCC 30100307).
Discussion: LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-
rich combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-air
LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion zone.
Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of excess air,
which acts as a heat sink to lower combustion temperatures (EPA, 2002).
Low NOx
Burner and Flue
Gas
Recirculation;
Ammonia Prod;
Feedstock
Desulfurization
NLNBFAPFD
N0622
NOx
Low NOx
Burner and
Flue Gas
Recirculation
Ammonia Prod;
Feedstock
Desulfurization
ptnonipm
Known
10
2006
72|172|175|
179| 185
Application: This control is the use of low NOx burner (LNB) technology and flue gas recirculation (FGR) to
reduce NOx emissions. LNBs reduce the amount of NOx created from reaction between fuel nitrogen and
oxygen by lowering the temperature of one combustion zone and reducing the amount of oxygen available
in another.
This control is applicable to small (<1 ton per OSD) feedstock desulfurization processes in ammonia
products operations (SCC 3Q1QQ3Q5) with uncontrolled NOx emissions greater than 10 tons per year.
Discussion: It is assumed that the superheated steam needed to regenerate the activated carbon bed
used in the desulfurization process is the NOx source.
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich
combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply excess
air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-air LNBs
create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion zone. Staged-
fuel LNBs create a lean combustion zone that is relatively cool due to the presence of excess air, which
acts as a heat sink to lower combustion temperatures (EPA, 2002).
Oxygen Trim
and Water
Injection;
Ammonia—NG-
Fired Reformers
NOTWIFRNG
N0563
NOx
Known
10
2006
72|172|175|
179| 184| 18
5
Application: This control is the use of OT + Wl to reduce NOx emissions
This control is applicable to small (<1 ton NOx per OSD) ammonia production operations
with natural gas-fired reformers (SCC 30100306) and uncontrolled NOx emissions greater
than 10 tons per year. This control is also applicable to miscellaneous combustion
emissions from ammonia production operations (SCC 30100399).
Discussion: Water is injected into the gas turbine, reducing the temperatures in the NOx-forming regions.
The water can be injected into the fuel, the combustion air or directly into the combustion chamber (ERG,
2000).
(continued)
-------
Table A-2. CMDB Table 01 Summary (continued)
cmname
Cm
Abbreviation
Pechan
Meas
Code
Major
Poll
Control
Technoloqv
Source Group
Sector
Class
Equip
Life
Nei Device
Code
Date
Reviewed
Data
Source
Months
Description
Selective
Catalytic
Reduction;
Ammonia—NG-
Fired Reformers
NSCRFRNG
N0564
NOx
Selective
Catalytic
Reduction
Ammonia—NG-Fired
Reform ers
ptnonipm
Known
20
139
2006
72|167|175|
179|224|22
5|226
Application: This control is the seieuive uaiaiyiic reduction of NOx through add-on controls. SCR controls
are post-combustion control technologies based on the chemical reduction of nitrogen oxides (NOx) into
molecular nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx removal
efficiency, which allows the process to occur at lower temperatures.
Applies to natural-gas fired reformers involved in the production of ammonia (SCC 30100306) with
uncontrolled NOx emissions greater than 10 tons per year.
Discussion: Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-
fired, combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction (EPA,
2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue gas. The
reagent reacts selectively with the flue gas NOx within a specific temperature range and in the presence of
the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx reduction
efficiency and the lower and broader temperature ranges. However, the decrease in reaction temperature
and increase in efficiency is accompanied by a significant increase in capital and operating costs (EPA,
2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous ammonia is
a gas at atmospheric pressure and normal temperatures. There are safety issues with the use of
anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous
ammonia is qenerallv transported and stored at a concentration of 29.4% ammonia in water.
Selective
Catalytic
Reduction;
Ammonia—Oil-
Fired Reformers
NSCRFROL
N0573
NOx
Selective
Catalytic
Reduction
Ammonia—Oil-Fired
Reform ers
ptnonipm
Known
20
139
2006
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR controls
are post-combustion control technologies based on the chemical reduction of nitrogen oxides (NOx) into
molecular nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx removal
efficiency, which allows the process to occur at lower temperatures.
Applies to natural-gas fired reformers involved in the production of ammonia (SCC 30100306) with
uncontrolled NOx emissions greater than 10 tons per year.
Discussion: Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-
fired, combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction (EPA,
2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue gas. The
reagent reacts selectively with the flue gas NOx within a specific temperature range and in the presence of
the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx reduction
efficiency and the lower and broader temperature ranges. However, the decrease in reaction temperature
and increase in efficiency is accompanied by a significant increase in capital and operating costs (EPA,
2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous ammonia is
a gas at atmospheric pressure and normal temperatures. There are safety issues with the use of
anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous
ammonia is generally transported and stored at a concentration of 29.4% ammonia in water.
Today, catalyst formulations include single component, multi-component, or active phase with a support
structure. Most catalyst formulations contain additional compounds or sup-ports, providing thermal and
structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important design and
operational factors that affect the rate of reduction include: reaction temperature range; residence time
available in the optimum temperature range; degree of mixing between the injected reagent and the
combustion gases; uncontrolled NOx concentration level; molar ratio of injected reagent to uncontrolled
NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop across the catalyst; catalyst pitch;
catalyst deactivation; and catalyst management (EPA, 2001).
(continued)
-------
Table A-2. CMDB Table 01 Summary (continued)
cmname
Cm
Abbreviation
Pechan
Meas
Code
Major
Poll
Control
Technoloqv
Source Group
Sector
Class
Equip
Life
Nei Device
Code
Date
Reviewed
Data
Source
Months
Description
Selective Non-
Catalytic
Reduction—
Ammonia; NG-
Fired Reformers
NSNCRFRNG
N0565
NOx
Selective
Non-Catalytic
Reduction
Ammonia—NG-Fired
Reform ers
ptnonipm
Known
20
107
2006
72|172|175|
179| 185
Application: This control is the reduction of NOx emission through selective non-catalytic reduction add-on
controls. SNCR controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20).
This control applies to small (<1 ton NOx per OSD) ammonia production natural gas fired reformers (SCC
30100306) with uncontrolled NOx emissions greater than 10 tons per year.
Discussion: SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of flue
gas components. However, the NOx reduction reaction is favored for a specific temperature range and in
the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the choice of
reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic, less
volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets can
penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002). Because of
these advantages, urea is more commonly used than ammonia in large boiler applications.
Low NOx
Burner;
Ammonia—Oil-
Fired Reformers
NLNBUFROL
N0571
NOx
Low NOx
Burner
Ammonia—Oil-Fired
Reform ers
ptnonipm
Known
10
204|205
2006
72
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions. LNBs
reduce the amount of NOx created from reaction between fuel nitrogen and oxygen by lowering the
temperature of one combustion zone and reducing the amount of oxygen available in another.
This control is applicable to ammonia production operations with oil-fired reformers (SCC 30100307).
Discussion: LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-
rich combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-air
LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion zone.
Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of excess air,
which acts as a heat sink to lower combustion temperatures (EPA, 2002).
Selective Non-
Catalytic
Reduction—
Ammonia; Oil-
Fired Reformers
NSNCRFROL
N0574
NOx
Selective
Non-Catalytic
Reduction
Ammonia—Oil-Fired
Reform ers
ptnonipm
Known
20
107
2006
72
Application: This control is the reduction of NOx emission through selective non-catalytic reduction add-on
controls. SNCR controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20).
This control applies to ammonia production natural gas fired reformers (SCC 30100306) with uncontrolled
NOx emissions greater than 10 tons per year.
Discussion: SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of flue
gas components. However, the NOx reduction reaction is favored for a specific temperature range and in
the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the choice of
reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic, less
volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets can
penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002). Because of
these advantages, urea is more commonly used than ammonia in larqe boiler applications.
(continued)
-------
Table A-2. CMDB Table 01 Summary (continued)
cmname
Cm
Abbreviation
Pechan
Meas
Code
Major
Poll
Control
Technoloqv
Source Group
Sector
Class
Equip
Life
Nei Device
Code
Date
Reviewed
Data
Source
Months
Description
Low NOx
Burner;
Ammonia
Production;
Other Not
Classified
NLNBUAONC
NOx
Low NOx
Burner
Ammonia
Production—Other
Not Classified
ptnonipm
Known
10
204|205
2013
AR-11186
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions. LNBs
reduce the amount of NOx created from reaction between fuel nitrogen and oxygen by lowering the
temperature of one combustion zone and reducing the amount of oxygen available in another.
This control is applicable to miscellaneous combustion emissions from ammonia production operations
(SCC 30100399).
Discussion: LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-
rich combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-air
LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion zone.
Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of excess air,
which acts as a heat sink to lower combustion temperatures (EPA, 2002)
Low NOx
Burner and Flue
Gas
Recirculation;
Ammonia
Production;
Other Not
Classified
NLNBFAONC
NOx
Low NOx
Burner and
Flue Gas
Recirculation
Ammonia
Production—Other
Not Classified
ptnonipm
Known
10
2013
72|172|175|
179|186
Application: This control is the use of low NOx burner (LNB) technology and flue gas
recirculation (FGR) to reduce NOx emissions. LNBs reduce the amount of NOx created
from reaction between fuel nitrogen and oxygen by lowering the temperature of one
combustion zone and reducing the amount of oxygen available in another.
This control is applicable to miscellaneous combustion emissions from ammonia production operations
(SCC 30100399).
Discussion: LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-
rich combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply
excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-air
LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion zone.
Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of excess air,
which acts as a heat sink to lower combustion temperatures (EPA, 2002).
Selective Non-
Catalytic
Reduction—
Ammonia;
Ammonia
Production;
Other Not
Classified
NSNCRAONC
NOx
Selective
Non-Catalytic
Reduction
Ammonia
Production—Other
Not Classified
ptnonipm
Known
20
107
2013
Application: This control is the reduction of NOx emission through selective non-catalytic reduction add-on
controls. SNCR controls are post-combustion control technologies based on the chemical reduction of
nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20).
This control is applicable to miscellaneous combustion emissions from ammonia production operations
(SCC 30100399).
Discussion: SNCR is the reduction of NOx in flue gas to N2 and water vapor. This reduction is done with a
nitrogen based reducing reagent, such as ammonia or urea. The reagent can react with a number of flue
gas components. However, the NOx reduction reaction is favored for a specific temperature range and in
the presence of oxygen (EPA, 2002).
Both ammonia and urea are used as reagents. The cost of the reagent represents a large part of the
annual costs of an SNCR system. Ammonia is generally less expensive than urea. However, the choice of
reagent is also based on physical properties and operational considerations (EPA, 2002).
Ammonia can be utilized in either aqueous or anhydrous form. Anhydrous ammonia is a gas at
atmospheric pressure and normal temperatures. There are safety issues with the use of anhydrous
ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is
generally transported and stored at a concentration of 29.4% ammonia in water.
Urea based systems have several advantages, including several safety aspects. Urea is a nontoxic, less
volatile liquid that can be stored and handled more safely than ammonia. Urea solution droplets can
penetrate farther into the flue gas when injected into the boiler, enhancing mixing (EPA, 2002). Because of
these advantages, urea is more commonly used than ammonia in large boiler applications.
Oxygen Trim
and Water
Injection;
Ammonia
Production;
Other Not
Classified
NOTWIAONC
NOx
Oxygen Trim
and Water
Injection
Ammonia
Production—Other
Nnt ClaccifipiH
ptnonipm
Known
10
2013
72|172|175|
179| 184| 18
5
Application: This control is the use of OT + Wl to reduce NOx emissions
This control is applicable to miscellaneous combustion emissions from ammonia
production operations (SCC 30100399).
Discussion: Water is injected into the gas turbine, reducing the temperatures in the NOx-forming regions.
The water can be injected into the fuel, the combustion air or directly into the combustion chamber (ERG,
2000).
(continued)
-------
Table A-2. CMDB Table 01 Summary (continued)
cmname
Cm
Abbreviation
Pechan
Meas
Code
Major
Poll
Control
Technoloqv
Source Group
Sector
Class
Equip
Life
Nei Device
Code
Date
Reviewed
Data
Source
Months
Description
Selective
Catalytic
Reduction;
Ammonia
Production;
Other Not
Classified
NSCRAONC
NOx
Selective
Catalytic
Reduction
Ammonia
Production—Other
Not Classified
ptnonipm
Known
20
139
2013
72|167|175|
179|224|22
5|226
Application: This control is the seieuuve uaiaiyiic reduction of NOx through add-on controls. SCR controls
are post-combustion control technologies based on the chemical reduction of nitrogen oxides (NOx) into
molecular nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx removal
efficiency, which allows the process to occur at lower temperatures.
This control is applicable to miscellaneous combustion emissions from ammonia production operations
(SCC 30100399).
Discussion: Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-
fired, combustion units for emission control since the early 1970s. SCR is typically implemented on units
requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA,
2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference
between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction (EPA,
2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue gas. The
reagent reacts selectively with the flue gas NOx within a specific temperature range and in the presence of
the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx reduction
efficiency and the lower and broader temperature ranges. However, the decrease in reaction temperature
and increase in efficiency is accompanied by a significant increase in capital and operating costs (EPA,
2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent.
Anhydrous ammonia is a gas at atmospheric pressure and normal temperatures. There
are safety issues with the use of anhydrous ammonia, as it must be transported and
stored under pressure (EPA, 2002). Aqueous ammonia is generally transported and
stored at a concentration of 29.4% ammonia in water.
t>
-------
Table A-3. CMDB Table 02 Efficiencies
cmabbreviation
Pollutant
Locale
Effective
Date
existingmeasureabbr
neiexistingdevcode
minemissions
maxemissions
controlefficiency
costyear
costperton
ruleeff
rulepen
equationtype
caprecfactor
discountrate
capannratio
incrementalcpt
Details
NLNBFAPFD
NOx
0
0
365
60
1990
2560
100
100
cpton
0.1424
5.9
2470
Applied to small source types
NLNBFAPFD
NOx
0
365
60
1990
590
100
100
cpton
0.1424
7.5
280
Applied to large source types
NLNBFFRNG
NOx
0
0
365
60
1990
2560
100
100
cpton
0.1424
5.9
2470
Applied to small source types
NLNBFFRNG
NOx
0
365
60
1990
590
100
100
cpton
0.1424
7.5
280
Applied to large source types
NLNBFFROL
NOx
0
0
365
60
1990
1120
100
100
cpton
0.1424
5.9
1080
Applied to small source types
NLNBFFROL
NOx
0
365
60
1990
390
100
100
cpton
0.1424
7.5
190
Applied to large source types
NLNBUFROL
NOx
0
0
365
50
1990
400
100
100
cpton
0.1424
5.5
Applied to small source types
NLNBUFROL
NOx
0
365
50
1990
430
100
100
cpton
0.1424
5.5
Applied to large source types
NOTWIFRNG
NOx
0
0
365
65
1990
680
100
100
cpton
0.1424
2.9
Applied to small source types
NOTWIFRNG
NOx
0
365
65
1990
320
100
100
cpton
0.1424
2.9
Applied to large source types
NSCRFRNG
NOx
0
0
365
90
1999
2366
100
100
cpton
0.0944
10
Applied to small source types
NSCRFRNG
NOx
0
365
90
1999
2366
100
100
cpton
0.0944
9.6
Applied to large source types
NSCRFROL
NOx
0
0
365
80
1990
1480
100
100
cpton
0.0944
10
1910
Applied to small source types
NSCRFROL
NOx
0
365
80
1990
810
100
100
cpton
0.0944
9.6
940
Applied to large source types
NSNCRFRNG
NOx
0
0
365
50
1990
3870
100
100
cpton
0.0944
9.4
2900
Applied to small source types
NSNCRFRNG
NOx
0
365
50
1990
1570
100
100
cpton
0.0944
8.2
840
Applied to large source types
NSNCRFROL
NOx
0
0
365
50
1990
2580
100
100
cpton
0.0944
9.4
1940
Applied to small source types
NSNCRFROL
NOx
0
365
50
1990
1050
100
100
cpton
0.0944
8.2
560
Applied to large source types
NLNBUFRNG
NOx
0
0
365
50
1990
820
100
100
cpton
0.1424
5.5
Applied to small source types; no new
information was available for small sources
during 2013 update
NLNBUFRNG
NOx
0
365
50
2008
800
100
100
cpton
0.1424
5.9
Applied to large source types; equipment
life of 10 years and 7% interest
-------
APPENDIX B
COMBUSTION TURBINES
Copies of the database tables for showing all records for Combustion Turbines NOx
controls are provided. Changes are highlighted in red font.
- Table B-l. CMDB Table OlSummary
- Table B-2. CMDB Table 02_Efficiencies
- Table B-3. CMDB Table 04_Equations
- Table B-4. Additional CMDB Table 06 References
B-l
-------
Table B-l. CMDB Table OlSummary
cmname
cmabbreviation
pechanmea
scode
majorpoll
controltechnologv
sourcegroup
sector
class
equiplife
ll'iTHlli'
dntcrcviewed
datasource
months
Dry Low NOx
Combustion; Gas
Turbines—Natural Gas
NDLNCGTNG
N0243
NOx
Dry Low NOx
Combustion
Gas Turbines—
Natural Gas
ptnonipm
Known
15
72 172 175 179 22
3 CT-2 CT-6
SCR + Dry Low NOx
Combustion; Gas
Turbines—Natural Gas
NSCRDGTNG
N0244
NOx
SCR + DLN
Combustion
Gas Turbines—
Natural Gas
ptnonipm
Known
15
2013
72 172 175 179 22
3 224 CT-2 CT-
3 CT-4 CT-6 CT-8
Selective Catalytic
Reduction and Steam
Injecti; Gas Turbines—
Natural Gas
NSCRSGTNG
N0245
NOx
Selective Catalytic
Reduction and
Steam Injection
Gas Turbines—
Natural Gas
ptnonipm
Known
15
2013
72 172 175 179 22
3 224 CT-2 CT-3
Selective Catalytic
Reduction and Water
Injecti; Gas Turbines—
Jet Fuel
NSCRWGTJF
N0502
NOx
Selective Catalytic
Reduction and
Water Injection
Gas Turbines—
Jet Fuel
ptnonipm
Known
2013
72 172 175 179 22
3 CT-2 CT-7
Selective Catalytic
Reduction and Water
Injecti; Gas Turbines—
Natural Gas
NSCRWGTNG
N0246
NOx
Selective Catalytic
Reduction and
Water Injection
Gas Turbines—
Natural Gas
ptnonipm
Known
15
2013
72 172 175 179 22
3 224 CT-2 CT-
3 CT-8
Selective Catalytic
Reduction and Water
Injecti; Gas Turbines—
Oil
NSCRWGTOL
N0232
NOx
Selective Catalytic
Reduction and
Water Injection
Gas Turbines—
Oil
ptnc nil 'iii
TInown
15
2013
72 172 175 179 22
3 224 CT-2 CT-7
Steam Injection; Gas
Turbines—Natural Gas
NSTINGTNG
N0242
NOx
Steam Injection
Gas Turbines—
Natural Gas
ptnonipm
Known
15
2013
72 172 175 184 22
3 CT-2
Water Injection; Gas
Turbines—Jet Fuel
NWTINGTJF
N0501
NOx
Water Injection
Gas Turbines—
Jet Fuel
ptnonipm
Known
15
2013
72 172 175 184 22
3 CT-2
Water Injection; Gas
Turbines—Natural Gas
NWTINGTNG
N0241
NOx
Water Injection
Gas Turbines—
Natural Gas
ptnonipm
Known
15
2013
72 172 175 184 22
3 CT-2
Water Injection; Gas
Turbines—Oil
NWTINGTOL
N0231
NOx
Water Injection
Gas Turbines—
Oil
ptnonipm
Known
15
2013
72 172 175 184 22
3 CT-2
Catalytic Combustion;
Gas Turbine—Natural
Gas
NCATCGTNG
N/A
NOx
Catalytic
Combustion
Gas Turbines—
Natural Gas
ptnonipm
Emerging
15
2013
CT-1 CT-2
EMx and Dry Low NOx
Combustion; Gas
Turbines—Natural Gas
NEMXDGTNG
N/A
NOx
EMx and Dry Low
NOx Combustion
Gas Turbines—
Natural Gas
ptnonipm
Emerging
15
2013
CT-1 CT-2 CT-
3 CT-4 CT-5
EMx and Water
Injection; Gas
Turbines—Natural Gas
NEMXWGTNG
N/A
N( )x
EMx and Water
ink1' tion
Gas Turbines—
Natural Gas
ptnonipm
Emerging
15
2013
CT-1 CT-3
*For ease in reading this table, 1 lie Descnpiimi field is included on separate pages.
-------
Table B-l. CMDB Table OlSummary (continued)
cmabbreviation
Description
NDLNCGTNG
Application: This control is the use of dry low NOx combustion (DLN) technology to reduce NOx emissions. DLN combustion reduces the amount of NOx created from reaction
between fuel nitrogen and oxygen by lowering the temperature of one combustion zone and reducing the amount of oxygen available in another.
This control applies to large (83.3 MW to 161 MW) natural gas fired turbines with uncontrolled NOx emissions greater than 10 tons per year.
Discussion: LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich combustion and one at a lower temperature. Staging techniques are
usually used by LNB to supply excess air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-air LNBs create a fuel-rich reducing primary
combustion zone and a fuel-lean secondary combustion zone. Staged-fiiel LNBs create a lean combustion zone that is relatively cool due to the presence of excess air, which acts as
a heat sink to lower combustion temperatures (EPA, 2002).
NSCRDGTNG
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR controls are post-combustion control technologies based on the chemical
reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx removal efficiency, which allows the
process to occur at lower temperatures.
This control applies to natural gas fired turbines with NOx emissions greater than 10 Ions per year.
Discussion: Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil foel-fired, combustion units for emission control since the early 1970s. SCR is
typically implemented on units requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA, 2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference between SNCR and SCR is that SCR uses a metal-based catalyst to increase the
rate of reaction (EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue gas. The reagent reacts selectively with the flue gas NOx within a
specific temperature range and in the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx reduction efficiency and the lower and broader temperature ranges. However, the
decrease in reaction temperature and increase in efficiency is accompanied by a significant increase in capital and operating costs (EPA, 2002). The cost increase is due to the large
amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous ammonia is a gas at atmospheric pressure and normal temperatures. There are safety
issues with the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is generally transported and stored at a concentration
of 29.4% ammonia in water.
Today, catalyst formulations include single component, multi-component, or active phase with a support structure. Most catalyst formulations contain additional compounds or sup-
ports, providing thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important design and operational factors that affect the rate of reduction include: reaction
temperature range; residence time available in the optimum temperature range; degree of mixing between the injected reagent and the combustion gases; uncontrolled NOx
concentration level; molar ratio of injected reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop across the catalyst; catalyst pitch; catalyst
deactivation; and catalyst management (EPA, 2001).
NSCRSGTNG
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR controls are post-combustion control technologies based on the chemical
reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx removal efficiency, which allows the
process to occur at lower temperatures.
This control applies to natural gas fired turbines with NOx emissions greater than 10 tons per year.
(continued)
-------
Table B-l. CMDB Table OlSummary (continued)
cmabbreviation
Description
NSCRSGTNG
(cont.)
Discussion: Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired, combustion units for emission control since the early 1970s. SCR is
typically implemented on units requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA, 2002),
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference between SNCR and SCR is that SCR uses a metal-based catalyst to increase the
rate of reaction (EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue gas. The reagent reacts selectively with the flue gas NOx within a
specific temperature range and in the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx reduction efficiency and the lower and broader temperature ranges. However, the
decrease in reaction temperature and increase in efficiency is accompanied by a significant increase in capital and operating costs (EPA, 2002). The cost increase is due to the large
amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous ammonia is a gas at atmospheric pressure and normal temperatures. There are safety
issues with the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is generally transported and stored at a concentration
of 29.4% ammonia in water.
Today, catalyst formulations include single component, multi-component, or active phase with a support structure. Most catalyst formulations contain additional compounds or sup-
ports, providing thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important design and operational factors that affect the rate of reduction include: reaction
temperature range; residence time available in the optimum temperature range; degree of mixing between the injected reagent and the combustion gases; uncontrolled NOx
concentration level; molar ratio of injected reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop across the catalyst; catalyst pitch; catalyst
deactivation; and catalyst management (EPA, 2001).
NSCRWGTJF
Application: This control is the selective catalytic reduction of NOx through add-on controls in combination with water injection. SCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx
removal efficiency, which allows the process to occur at lower temperatures.
This control applies to jet fuel-fired turbines with uncontrolled NOx emissions greater than 10 tons per year.
Discussion: Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired, combustion units for emission control since the early 1970s. SCR is
typically implemented on units requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA, 2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference between SNCR and SCR is that SCR uses a metal-based catalyst to increase the
rate of reaction (EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue gas. The reagent reacts selectively with the flue gas NOx within a
specific temperature range and in the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in luo advantages of the SCR process over SNCR, the higher NOx reduction efficiency and the lower and broader temperature ranges. However, the
decrease in reaction temperature and increase in efficiency is accompanied by a significant increase in capital and operating costs (EPA, 2002). The cost increase is due to the large
amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous ammonia is a gas at atmospheric pressure and normal temperatures. There are safety
issues with the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is generally transported and stored at a concentration
of 29.4% ammonia in water.
(continued)
-------
Table B-l. CMDB Table OlSummary (continued)
cmabbreviation
Description
NSCRWGTJF
(cont.)
Today, catalyst formulations include single component, multi-component, or active phase with a support structure. Most calalysl formulations contain additional compounds or sup-
ports, providing thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important design and operational factors that affect the rate of reduction include: reaction
temperature range; residence time available in the optimum temperature range; degree of mixing between the injected reagent and the combustion gases; uncontrolled NOx
concentration level; molar ratio of injected reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop across the catalyst; catalyst pitch; catalyst
deactivation; and catalyst management (EPA, 2001).
NSCRWGTNG
Application: This control is the selective catalytic reduction of NOx through add-on controls in combination with water injection. SCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx
removal efficiency, which allows the process to occur at lower temperatures.
This control applies to natural gas-fired gas turbines with uncontrolled NOx emissions greater than 10 tons per year.
Discussion: Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired, combustion units for emission control since the early 1970s. SCR is
typically implemented on units requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA, 2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference between SNCR and SCR is that SCR uses a metal-based catalyst to increase the
rate of reaction (EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue gas. The reagent reacts selectively with the flue gas NOx within a
specific temperature range and in the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx reduction efficiency and the lower and broader temperature ranges. However, the
decrease in reaction temperature and increase in efficiency is accompanied by a significant increase in capital and operating costs (EPA, 2002). The cost increase is due to the large
amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous ammonia is a gas at atmospheric pressure and normal temperatures. There are safety
issues with the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is generally transported and stored at a concentration
of 29.4% ammonia in water.
Today, catalyst formulations include single component, multi-component, or active phase with a support structure. Most catalyst formulations contain additional compounds or sup-
ports, providing thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important design and operational factors that affect the rate of reduction include: reaction
temperature range; residence time available in the optimum temperature range; degree of mixing between the injected reagent and the combustion gases; uncontrolled NOx
concentration level; molar ratio of injected reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop across the catalyst; catalyst pitch; catalyst
deactivation; and catalyst management (EPA, 2001).
NSCRWGTOL
Application: This control is the selective catalytic reduction of NOx through add-on controls in combination with water injection. SCR controls are post-combustion control
technologies based on the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx
removal efficiency, which allows the process to occur at lower temperatures.
This control applies to oil-fired turbines with uncontrolled NOx emissions greater than 10 tons per year.
Discussion: Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired, combustion units for emission control since the early 1970s. SCR is
typically implemented on units requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA, 2002).
(continued)
-------
Table B-l. CMDB Table OlSummary (continued)
cmabbreviation
Description
NSCRWGTOL
(cont.)
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference between SNCR and SCR is lhal SCR uses a metal-based catalyst to increase the
rate of reaction (EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue gas. The reagent reacts selectively with the flue gas NOx within a
specific temperature range and in the presence of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx reduction efficiency and the lower and broader temperature ranges. However, the
decrease in reaction temperature and increase in efficiency is accompanied by a significant increase in capital and operating costs (EPA, 2002). The cost increase is due to the large
amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous ammonia is a gas at atmospheric pressure and normal temperatures. There are safety
issues with the use of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is generally transported and stored at a concentration
of 29.4% ammonia in water.
Today, catalyst formulations include single component, multi-component, or active phase with a support structure. Most catalyst formulations contain additional compounds or sup-
ports, providing thermal and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important design and operational factors that affect the rate of reduction include: reaction
temperature range; residence time available in the optimum temperature range; degree of mixing between the injected reagent and the combustion gases; uncontrolled NOx
concentration level; molar ratio of injected reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop across the catalyst; catalyst pitch; catalyst
deactivation; and catalyst management (EPA, 2001).
NSTINGTNG
Application: This control is the use of steam injection to reduce NOx emissions.
This control applies to small (3.3 MW to 34.4MW) natural gas-fired gas turbines with uncontrolled NOx emissions greater than 10 tons per year.
Discussion: Steam is injected into the gas turbine, reducing the temperatures in the NOx-forming regions. The steam can be injected into the fuel, the combustion air or directly into
the combustion chamber (ERG, 2000).
NWTINGTJF
Application: This control is the use of water injection to reduce NOx emissions.
This control applies to small (3.3 MW to 34.4MW) jet fuel-fired turbines with uncontrolled NOx emissions greater than 10 tons per year.
Discussion: Water is injected into the gas turbine, reducing the temperatures in the NOx-forming regions. The water can be injected into the fuel, the combustion air or directly into
the combustion chamber (ERG, 2000).
NWTINGTNG
Application: This control is the use of water injection to reduce NOx emissions.
This control applies to small (3.3 MW to 34.4MW) natural gas-fired gas turbines with uncontrolled NOx emissions greater than 10 tons per year.
Discussion: Water is injected into the gas turbine, reducing the temperatures in the NOx-forming regions. The water can be injected into the fuel, the combustion air or directly into
the combustion chamber (ERG, 2000).
NWTINGTOL
Application: This control is the use of water injection to reduce NOx emissions.
This control applies to small (3.3 MW to 34.4MW) oil-fired turbines with uncontrolled NOx emissions greater than 10 tons per year.
Discussion: Water is injected into the gas turbine, reducing the temperatures in the NOx-forming regions. The water can be injected into the fuel, the combustion air or directly into
the combustion chamber (ERG, 2000).
(continued)
-------
Table B-l. CMDB Table OlSummary (continued)
cmabbrevlation
Description
NCATCGTNG
Application: This control is the use of catalytic combustion to reduce NOx emissions. Catalytic combustors reduce the amount of NOx created by oxidizing fuel at lower
temperatures (and without a flame) than in conventional combustors. Catalytic combustion uses a catalytic bed to oxidize a lean air fuel mixture within a combustor instead of
burning with a flame. The fuel and air mixture oxidizes at lower temperatures than in a conventional combustor, producing less NOx.
Currently installed only on a few 1.4 MW combustion turbines, and commercially available for turbines rated up to 10 MW (CT-1).
NEMXDGTNG
Application: This control is the use of EMx in combination with dry low NOx combustion. EMx is a post-combustion catalytic oxidation and absorption technology that uses a two-
stage catalyst/absorber system for the control of NOx as well as CO, VOC, and optionally SOx. A coated catalyst oxidizes NO to N02, CO to C02, and VOC to C02 and water.
The N02 is then absorbed onto the catalyst surface where it is chemically converted to and stored as potassium nitrates and nitrites. A proprietary regeneration gas is periodically
passed through the catalyst to desorb the N02 from the catalyst and reduce it to elemental nitrogen (N2). EMx has been successfully demonstrated on several small combustion
turbine projects up to 45 MW. The manufacturer has claimed that EMx can be effectively scaled up to larger turbines (CT-1).
Cost estimates for DLN combustion in 2008 dollars are not available. Thus, the total system cost in this analysis in 2008 dollars was developed from 1999 cost estimates for DLN
combustion that were escalated to 2008 dollars and added to the available 2008 estimate for the EMx system.
NEMXWGTNG
Application: This control is the use of EMx in combination with water injection.
Cost estimates for water injection in 2008 dollars are not available. Thus, the total system cos1 in this analysis in 2008 dollars was developed from 1999 cost estimates for water
injection that were escalated to 2008 dollars and added to the available 2008 estimate for Ihe I'.M\ system.
td
-------
Table B-2. CMDB Table 02 Efficiencies
cmabbreviation
pollutant
tj
©
Effective Date ||
existingmeasureabbr ||
neiexistingdevcode ||
minemissions
maxemissions
controlefficiency
costyear
costperton
ruleeff
rulepen
equationtype
caprecfactor
iliscountrate ||
capannratio
£
E
(J
e
details
NWTINGTNG
NOx
0
0
365
72
1999
1790
100
100
cpton
0.109::
3.1
Applied to small source types (<34.4 MW),
uncontrolled emissions <365 tpy
NWTINGTNG
NOx
0
365
72
1999
1000
100
100
cpton
0.109b
2.4
Applied to small source types (<34.4 MW),
uncontrolled emissions >365 tpy
NWTINGTNG
NOx
0
365
72
1999
730
100
100
cpton
0.1098
1.6
Applied to large source types
NSCRWGTNG
NOx
0
0
365
94
1999
2790
100
100
cpton
0.1098
3
5840
Applied to small source types (3 to 26 MW),
uncontrolled emissions <365 tpy.
NSCRWGTNG
NOx
0
365
94
1999
1370
100
100
cpton
0.1098
2.9
3130
Applied to small source types (3 to 26 MW),
uncontrolled emissions >365 tpy.
NSCRWGTNG
NOx
0
365
94
1999
1070
100
100
cpton
0.1098
1.5
1690
Applied to large source types (~80 to 160 MW)
NSCRWGTNG
NOx
0
365
98
2008
1960
100
100
cpton
0.1098
2.5
3170
Applied to large source types (~50 to 180 MW), 1999
costs for WI assumed to be the same as 1990 costs in
the 1993 ACT based on data in ref CT-2 that showed
the costs were essentially the same for NG-fired units.
1999 WI capital and indirect annual costs were
escalated to 2008 dollars using ratio of 2008 to 1999
CEP cost indexes, direct annual costs for WI were
assumed to be the same in 2008 as in 1999, and
resulting 2008 costs were added to the 2008 SCR costs
from ref CT-3.
NEMXWGTNG
NOx
0
365
99
2960
100
100
cpton
0.1098
2.9
7120
Applied to large source types (50 to 180 MW); WI costs
estimated using the same procedure as for
NSCRWGTNG applied to large sources.
NSTINGTNG
NOx
0
0
80
1690
100
100
cpton
0.1098
3.5
Applied to small source types (3 to 26.3 MW),
uncontrolled emissions <365 tpy, 1999 costs for SI
assumed to be the same as 1990 costs in the 1993 ACT
based on data in ref CT-2 that showed WI costs were
essentially the same for NG-fired units (assumed same
pattern holds for steam injection).
NSTINGTNG
NOx
80
820
100
100
cpton
0.1098
3.5
Applied to small source types (3 to 26.3 MW),
uncontrolled emissions >365 tpy, 1999 costs for SI
assumed to be the same as 1990 costs in the 1993 ACT
based on data in ref CT-2 that showed WI costs were
essentially the same for NG-fired units (assumed same
pattern holds for steam injection).
NSTINGTNG
NOx
o
80
1999
500
100
100
cpton
0.1098
3.0
Applied to large source types (~80 to 160 MW), 1999
costs for SI assumed to be the same as 1990 costs in the
1993 ACT based on data in ref CT-2 that showed WI
costs were essentially the same for NG-fired units
(assumed same pattern holds for steam injection).
NSCRSGTNG
NOx
0
0
365
95
1999
2570
100
100
cpton
0.1098
3.3
5550
Applied to small source types (3 to 26 MW),
uncontrolled emissions <365 tpy.
-------
(continued)
Table B-2. CMDB Table 02_Efficiencies (continued)
cmabbreviation
pollutant
tj
©
Effective Date ||
existingmeasureabbr ||
neiexistingdevcode ||
minemissions
maxemissions
>¦.
tj
c
*5
E
"©
•—
c
©
u
costyear
costperton
ruleeff
rulepen
equationtype
caprecfactor
«
•—
c
3
capannratio
<3
c
E
u
e
details
NSCRSGTNG
NOx
0
365
95
1999
1380
100
100
cpton
0.109::
3.1
2870
Applied to small source types (3 to 26.3 MW),
uncontrolled emissions >365 tpy.
NSCRSGTNG
NOx
0
365
95
1999
570
100
100
cpton
0.1098
2.7
1810
Applied to large source types (~80 to 160 MW)
NSCRGYNG
NOx
0
365
95
2008
1420
100
100
cpton
0.1098
3.9
3170
Applied to large source types (50 to 180 MW)
NDLNCGTNG
NOx
0
0
365
84
1999
300
100
100
rrt^n
0.1098
5
S4&
Applied to small source types
NDLNCGTNG
NOx
0
365
84
1999
130
100
100
0.1098
7.4
Applied to large source types
NSCRDGTNG
NOx
0
0
365
94
1999
1800
100
100
0.1098
2.9
11900
Applied to small source types (3 to 26.3 MW),
uncontrolled emissions <365 tpy.
NSCRDGTNG
NOx
0
365
94
1999
990
100
100
cpton
0.1098
3.6
6320
Applied to small source types (3 to 26.3 MW),
uncontrolled emissions >365 tpy.
NSCRDGTNG
NOx
0
365
94
1999
390
100
100
cpton
0.1098
4.2
3340
Applied to large source types (~160 MW)
NSCRDGTNG
NOx
0
365
2007
18900
Applied to small source types (up to 40 MW,
uncontrolled emissions <365 tpy)
NSCRDGTNG
NOx
0
365
2007
7510
Applied to small source types (up to 40 MW,
uncontrolled emissions >365 tpy)
NSCRDGTNG
NOx
0
365
94
2008
1040
100
100
cpton
0.1098
4.6
5560
Applied to large source types (~50 to 180 MW), 1999
costs for DLN were estimated based on data in ref CT-
2. Escalated these costs to 2008 dollars using ratio of
2008 to 1999 CEP cost indexes and added to the 2008
SCR costs from ref CT-3.
NEMXDGTNG
NOx
365
1999
2860
14940
Applied to small source types (<26 MW), uncontrolled
emissions <365 tpy
NEMXDGTNG
NOx
365
1999
1720
10270
Applied to small source types (<26 MW), uncontrolled
emissions >365 tpy
NEMXDGTNG
NOx
365
1999
840
6600
Applied to large source types (170 MW), uncontrolled
emissions >365 tpy
NEMXDGTNG
NOx
0
365
Applied to small source types
NEMXDGTNG
NOx
2008
2040
100
100
cpton
0.1098
4.1
12370
Applied to large source types (50 to 180 MW); DLN
costs estimated in 1999 dollars were escalated to 2008
dollars using the CEPCI, except parts and repair costs
were assumed to be the same in 2008 as in 1999.
NCATCGTNG
NOx
1999
920
100
100
cpton
0.1098
1.7
4760
Applied to small source types (3 to 26 MW),
uncontrolled emissions <365 tpy.
NCATCGTNG
NOx
o
365
98
1999
670
100
100
cpton
0.1098
1.2
2580
Applied to small source types (3 to 26 MW),
uncontrolled emissions >365 tpy.
NCATCGTNG
NOx
o
365
98
1999
370
100
100
cpton
0.1098
0.7
2200
Applied to large source types (~170 MW)
NWTINGTOL
NOx
o
0
365
68
1999
1630
100
100
cpton
0.1098
3.0
Applied to small source types (3 to 26.3 MW),
uncontrolled emissions <365 tpy, 1999 costs assumed to
be the same as 1990 costs in the 1993 ACT based on
data in ref CT-2 that showed the costs were essentially
the same for NG-fired units.
-------
(continued)
Table B-2. CMDB Table 02_Efficiencies (continued)
cmabbreviation
pollutant
tj
©
Effective Date ||
existingmeasureabbr ||
neiexistingdevcode ||
minemissions
maxemissions
>¦.
tj
c
*5
E
"©
•—
c
©
u
costyear
costperton
ruleeff
rulepen
equationtype
caprecfactor
«
•—
c
3
capannratio
<3
c
E
u
e
details
NWTINGTOL
NOx
0
365
68
1999
960
100
100
cpton
0.109-
1.8
Applied to small source types (3 to 26.3 MW),
uncontrolled emissions >365 tpy, 1999 costs assumed to
be the same as 1990 costs in the 1993 ACT based on
data in ref CT-2 that showed the costs were essentially
the same for NG-fired units.
NWTINGTOL
NOx
0
365
68
1999
650
100
100
cpton
0.1098
1.6
Applied to large source types (—83 MW), uncontrolled
emissions >365 tpy, 1999 costs assumed to be the same
as 1990 costs in the 1993 ACT based on data in ref CT-
2 that showed the costs were essentially the same for
NG-fired units.
NSCRWGTOL
NOx
0
0
365
90
1990
3190
100
100
cpton
0.1098
2.9
7620
Applied to small source types (3 to 26.3 MW),
uncontrolled emissions <365 tpy.
NSCRWGTOL
NOx
0
365
90
1990
1320
100
100
cpton
0.1098
2.3
2450
Applied to small source types (3 to 26.3 MW),
uncontrolled emissions >365 tpy.
NSCRWGTOL
NOx
0
365
97
2004
1560
100
100
cpton
0.1098
2.3
4790
Applied to large source types (—83 MW), uncontrolled
emissions >365 tpy, 1999 costs for WI assumed to be
the same as 1990 costs in the 1993 ACT based on data
in ref CT-2 that showed the costs were essentially the
same for NG-fired units. Escalated these costs to 2004
dollars using ratio of 2004 to 1999 CEP cost indexes
and added to the 2004 SCR costs from ref CT-7.
Control efficiency based on data from analysis for one
unit (ref CT-7).
NWTINGTJF
NOx
0
0
365
68
1999
1630
100
100
cpton
0.1098
3.0
Applied to small source types (3 to 26.3 MW),
uncontrolled emissions <365 tpy, costs assumed to be
the same as for oil-fired turbines.
NWTINGTJF
NOx
0
365
68
1999
960
100
100
cpton
0.1098
1.8
Applied to small source types (3 to 26.3 MW),
uncontrolled emissions >365 tpy, costs assumed to be
the same as for oil-fired turbines.
NWTINGTJF
NOx
o
68
1999
650
100
100
cpton
0.1098
1.6
Applied to large source types (—83 MW), uncontrolled
emissions >365 tpy, costs and control efficiency
assumed to be the same as for oil-fired turbines.
NSCRWGTJF
NOx
o
o
90
1990
3190
100
100
cpton
0.1098
2.9
7620
Applied to small source types (3 to 26.3 MW),
uncontrolled emissions <365 tpy, costs assumed to be
same as for oil-fired turbines.
NSCRWGTJF
NOx
o
90
1990
1320
100
100
cpton
0.1098
2.3
2450
Applied to small source types (3 to 26.3 MW),
uncontrolled emissions >365 tpy, costs assumed to be
same as for oil-fired turbines.
NSCRWGTJF
NOx
0
365
97
2004
1560
100
100
cpton
0.1098
2.3
4790
Applied to large source types (—83 MW), uncontrolled
emissions >365 tpy, costs and control efficiency
assumed to be same as for oil-fired turbines).
-------
td
-------
Table B-3. CMDB Table 04_Equationsa
cmabbreviation
cmeqntype
pollutant
costyear
varl
var2
var3
var4
var5
\arfi
var7
var8
var9
varlO
NWTINGTNG
Type 2
NOx
1999
27665
0.69
3700.2
0.95
27665
u.oy
3700.2
0.95
NSCRWGTNG
Type 2
NOx
1999
62962
0.66
8590
0.87
37193
0.63
12065
0.64
NSCRWGTNG
Type 2
NOx
2007
210883
0.46
NSCRWGTNG
Type"L"
NOx
2007
1893.8
185570
NSCRWGTNG
Type 2
NOx
2008
34533
0.85
7236
0.94
10323
0.96
3106
0.94
NEMXWGTNG
Type 2
NOx
2008
200894
0.68
19215
0.86
160409
0.67
20174
0.78
NSHNGTNG
Type 2
NOx
1999
43092
0.66
7282.3
0.76
43092
0.66
7282.3
0.76
NSCRSGTNG
Type 2
NOx
1999
72169
0.66
17551
0.72
37193
0.63
12065
0.64
NSCRSGTNG
Type 2
NOx
2008
46492
0.82
9434.1
0.86
10323
0.96
3106
0.94
NDLNCGTNG
Type 2
NOx
1999
676.37
0.96
676.37
0.96
NDLNCGTNG
Type"L"
NOx
1999
2860.6
25427
2860.6
25427
NSCRDGTNG
Type 2
NOx
1999
24854
0.79
12725
0.69
37193
0.63
12065
0.64
NSCRDGTNG
Type 2
NOx
2007
187647
0.54
210883
0.46
NSCRDGTNG
Type"L"
NOx
2007
2782
167494
1893.8
185570
NSCRDGTNG
Type 2
NOx
2008
14785
0.97
5250.8
0.9
10323
0.96
3106.1
0.94
NEMXDGTNG
Type 2
NOx
1999
58237
0.78
15004
0.78
65163
0.72
13702
0.76
NEMXDGTNG
Type 2
NOx
2008
129611
0.74
23051
0.78
160409
0.67
20174
0.78
NCATCGTNG
Type 2
NOx
1999
20668
0.57
4254.2
0.82
NCATCGTNG
Type"L"
NOx
1999
N/A
N/A
743.2
54105
NWTINGTOL
Type 2
NOx
1999
42533
0.6
6776.7
0.8
42533
0.6
6776.7
0.8
NSCRWGTOL
Type 2
NOx
1990
94337
0.63
25914
0.7
NSCRWGTOL
Type"L"
NOx
1999
4868.5
349694
1546.1
139203
aType "L" is a linear equation; variables arc the slope and intercept. No incremental TCI for NCATCGTNG relative to DLN because the capital costs for
catalytic combustion are lower than the capital costs for DLN for all but the smallest turbines. The underlying data for 2008 costs for SCR and EMx are for
large turbines (50 MW to 180 MW). The underlying data for 2007 costs are for 1 MW to 40 MW turbines.
-------
Table B-4. Additional CMDB Table 06 References
Data Source
Description
CT-1
Bay Area Air Quality Management District, 2010. Preliminary Determination of Compliance. Marsh Landing Generating Station. March 2010.
Available at: http://www.energy.ca.gov/sitingcases/marshlanding/documents/other/2010-03-24_Bay_Arca_AQMD_PDOC.pdf
CT-2
Onsite Sycom Energy Corporation, 1999. "Cost Analysis of NOx Control Alternatives for Stationary Gas Turbines." Prepared for U.S.
Department of Energy. Environmental Programs Chicago Operations Office. November 5, 1999. Available at:
https://wwwl.eere.energy.gov/manufacturing/distributedenergy/pdfs/gas_turbines_nox_cost_analysis.pdf
CT-3
EmeraChem Power, 2008. Attachment in email from Jeff Valmus. EmcraChcm Power, to WcymanLee, BAAQMD. Request for EMx Cost
Information. September 8, 2008. Available at:
http://www.baaqmd.gOv/~/media/Files/Engineering/Public%20Noticcs/2010/18404/Foolnolcs/EMx%20BACT%20economic%20analysis%20f
inal09072008.ashx
CT-4
CH2MHill, 2002. Walnut Energy Center Application for Certification." Prepared for California Energy Commission. November 2002.
Available at: www.energy.ca.gov/sitingcases/turlock/documcnls/applicanl_filcs/volumc_2/App_08.01E_Eval_Control.pdf.
CT-5
CARB, 2004. California Environmental Protection Agency. Air Resources Board. Report to the Legislature. Gas-Fired Power Plant NOx
Emission Controls and Related Environmental Impacts. Stationary Source Division. May 2004. Available at:
http://www.arb.ca.gov/research/apr/reports/12069.pdf
CT-6
Resource Dynamics Corporation, 2001. "Assessment of Distributed Generation Technology Applications." Prepared for Maine Public Utilities
Commission. February 2001. Available at: http://www.dislribulcd-gcncralion.com/Library/Maine.pdf
CT-7
Florida Municipal Power Agency. 2004. Chapters 3 and 4 of PSD BACT analysis for Stock Island facility in Key West, Florida. Available at
http://www.dep.state.fl.us/air/cmission/conslruclion/slockisland/BasisofBACT.pdf and
http://www.dep.state.fl.us/air/cmission/construclion/slockisland/NOxBACT.pdf
CT-8
Energy and Environmental Analysis ( An ICF International Company), 2008. Technology Characterization: Gas Turbines. Prepared for
Environmental Protection Agency Climate Protection Partnership Division. December 2008. Available at:
http://www.epa.gov/chp/documcnls/calalog_chplcch_gas_lurbines.pdf
-------
APPENDIX C
GLASS MANUFACTURING
Copies of database tables showing all records for glass manufacturing controls,
highlighting revisions.
C-l
-------
Table C-l. CMDB Table 01 Summary
cmname
cmabbreviation
pechanm
eascode
major
poll
controltechnologv
sourcegroup
Sector
Class
equiplile
neidevic
ecode
daterevi
ewed
datasource
Month
s
Description
Cullet Preheat; Glass
Manufacturing—Container
NCLPTGMCN
N0302
NOx
Cullet Preheat
Glass Manufacturing—
Container
ptnonipm
Emerging
10
2013
72 175 182
GM-1
Cullet Preheat; Glass
Manufacturing—Pressed
NCUPHGMPD
N0322
NOx
Cullet Preheat
Glass Manufacturing—
Pressed
ptnonipm
Emerging
10
2013
72 175 182
GM-1
OXY-Firmg; Glass
Manufacturing—General
NDOXYFGMG
N/A
NOx
OXY-Firing
Glass Manufacturing—
General
ptnonipm
Emerging
10
167
Electric Boost; Glass
Manufacturing—General
NELBOGMGN
N0301
NOx
Electric Boost
Glass Manufacturing—
Container
ptnonipm
Known
10
2013
GM-1
Electric Boost; Glass
Manufacturing—Container
NELBOGMCN
N0301
NOx
Electric Boost
Glass Manufacturing—
Container
ptnonipm
Known
10
2006
72 175 182
Electric Boost; Glass
Manufacturing—Flat
NELBOGMFT
N0311
NOx
Electric Boost
Glass Manufacturing—
Flat
ptnonipm
Known
10
2006
72 175 182
Electric Boost; Glass
Manufacturing—Pressed
NELBOGMPD
N0321
NOx
Electric Boost
Glass Manufacturing—
Pressed
ptnonipm
Known
10
2006
72 175 182
Low NOx Burner; Glass
Manufacturing—Container
NLNBUGMCN
N0303
NOx
Low NOx Burner
Glass Manufacturing—
Container
ptnonipm
Known
10
204 205
2013
72 175 179
182 GM-2
Low NOx Burner; Glass
Manufacturing—Flat
NLNBUGMFT
N0312
NOx
Low NOx Burner
Glass Manufacturing—
Flat
ptnonipm
Known
10
204 205
2013
72 175 179
182 GM-2
Low NOx Burner; Glass
Manufacturing—Pressed
NLNBUGMPD
N0323
NOx
Low NOx Burner
Glass Manufacturing—
Pressed
ptnonipm
Known
10
204 205
2006
175 179 18
2
OXY-Firmg; Glass
Manufacturing—General
NOXYFGMGN
N0306
NOx
OXY-Firing
Glass Manufacturing—
Container
ptnonipm
Known
10
2013
GM-1
OXY-Firmg; Glass
Manufacturing—Container
NOXYFGMCN
N0306
NOx
OXY-Firing
Glass Manufacturing—
Container
ptnonipm
Known
10
2006
72
OXY-Firmg; Glass
Manufacturing—Flat
NOXYFGMFT
N0315
NOx
OXY-Firing
Glass Manufacturing—
Flat
ptnonipm
Known
10
2006
72
OXY-Firmg; Glass
Manufacturing—Pressed
NOXYFGMPD
N0326
NOx
OXY-Firing
Glass Manufacturing—
Pressed
ptnonipm
Known
10
2006
72
Selective Catalytic Reduction;
Glass Manufacturing—Container
NSCRGMCN
N03403
NOx
Selective Catalytic
Reduction
Glass Manufacturing—
Container
ptnonipm
Known
10
139
2013
72 172 175
179 182 22
4 GM-2
Selective Catalytic Reduction;
Glass Manufacturing—Flat
NSCRGMFT
N0314
NOx
Selective Catalytic
Reduction
Glass Manufacturing—
Flat
ptnonipm
Known
10
139
2013
72 172 175
179 182 18
6 224 GM-2
Selective Catalytic Reduction;
Glass Manufacturing—Pressed
NSCRGMPD
N0325
NOx
Selective Catalytic
Reduction
Glass Manufacturing—
Pressed
ptnonipm
Known
10
139
2006
72 172 175
179 182 18
6 224
Catalytic Ceramic Filter; Glass
Manufacturing—Flat
CAT
NOx
Catalytic Ceramic
Filter
Glass Manufacturing—
Flat
ptnonipm
Known
20
2013
GM-3
-------
Table C-l. CMDB Table 01 Summary—Description Field
cmabbreviation
description
NCLPTGMCN
Application: This control is the use of cullet preheat technologies to reduce NOx emissions from glass manufacturing operations.
This control is applicable to container glass manufacturing operations classified under 305010402.
NCUPHGMPD
Application: This control is the use of cullet preheat technologies to reduce NOx emissions from glass manufacturing operations.
This control is applicable to pressed glass manufacturing operations classified under 305010404.
NDOXYFGMG
Application: This control is the use of OXY-firing in glass manufacturing furnaces to reduce NOx emissions. Oxygen enrichment refers to the substitution of oxygen for nitrogen in the combustion air used
to burn the fuel in a glass furnace. Oxygen enrichment above 90 percent is sometimes called "oxy-firing."
Discussion: The basic rationale for oxy-firing is improved efficiency, i.e., more of the theoretical heat of combustion is transferred to the glass melt and is not lost in the flue gas. Many other combustion
modification techniques (e.g., flue gas recirculation, staged combustion, and low excess air combustion) reduce NOx formation but also reduce the combustion efficiency. Oxy-firing was originally
developed to improve the combustion efficiency primarily by eliminating the sensible heat lost in heating the nitrogen present in air, which is then lost in the flue gas.
NELBOGMGN
Application: This control is the use of electric boost technologies to reduce NOx emissions from glass manufacturing operations.
This control applies to general glass manufacturing operations classified under SCC 30501401.
NELBOGMCN
Application: This control is the use of electric boost technologies to reduce NOx emissions from glass manufacturing operations.
This control applies to container glass manufacturing operations classified under SCC 30501402.
Discussion: The 250 tons per day plant is assumed to be representative of container glass plants (Pechan, 1998).
NELBOGMFT
Application: This control is the use of electric boost technologies to reduce NOx emissions from glass manufacturing operations.
This control applies to flat glass manufacturing operations classified under SCC 30501403.
Discussion: The 500 tons per day plant is assumed to be representative of flat glass plants (Pechan, 1998).
NELBOGMPD
Application: This control is the use of electric boost technologies to reduce NOx emissions from glass manufacturing operations.
This control applies to pressed glass manufacturing operations classified under SCC 30501403.
Discussion: The 50 tons per day plant is assumed to be representative of pressed glass plants (Pechan, 1998).
NLNBUGMCN
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions. LNBs reduce the amount of NOx created from reaction between fuel nitrogen and oxygen by lowering
the temperature of one combustion zone and reducing the amount of oxygen available in another.
This control is applicable to container glass manufacturing operations classified under 305010402 with uncontrolled NOx emissions greater than 10 tons per year.
Discussion: The 250 tons per day plant is assumed to be representative of container glass plants (Pechan, 1998).
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply excess
air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion zone.
Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
NLNBUGMFT
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions. LNBs reduce the amount of NOx created from reaction between fuel nitrogen and oxygen by lowering
the temperature of one combustion zone and reducing the amount of oxygen available in another.
This control is applicable to flat glass manufacturing operations classified under 305010404 with uncontrolled NOx emissions greater than 10 tons per year.
Discussion: The 500 tons per day plant is assumed to be representative of flat glass plants (Pechan, 1998).
LNBs are designed to "stage" combustion so that two combustion zones are created, one fuel-rich combustion and one at a lower temperature. Staging techniques are usually used by LNB to supply excess
air to cool the combustion process or to reduce available oxygen in the flame zone. Staged-air LNBs create a fuel-rich reducing primary combustion zone and a fuel-lean secondary combustion zone.
Staged-fuel LNBs create a lean combustion zone that is relatively cool due to the presence of excess air, which acts as a heat sink to lower combustion temperatures (EPA, 2002).
(continued)
-------
Table C-l. CMDB Table 01 Summary—Description Field (continued)
cmabbreviation
description
NLNBUGMPD
Application: This control is the use of low NOx burner (LNB) technology to reduce NOx emissions. LNBs reduce the amount of NOx created from reaction between fuel nitrogen and oxygen by lowering
the temperature of one combustion zone and reducing the amo
NOXYFGMGN
Application: This control is the use of OXY-firing in flat glass manufacturing furnaces to reduce NOx emissions. Oxygen enrichment refers to the substituti' 11 ¦ - ygen for nitrogen in the combustion air
used to burn the fuel in a glass furnace. Oxygen enrichment above 90 percent is sometimes called "oxy-firing."
This control applies to general manufacturing operations. This control applies to general glass manufacturing operations classified under SCC 3u5(Jl4(Jl.
Discussion: The basic rationale for oxy-firing is improved efficiency, i.e., more of the theoretical heat of combustion is transferred to the glass melt and is not lost in the flue gas. Many other combustion
modification techniques (e.g., flue gas recirculation, staged combustion, and low excess air combustion) reduce NOx formation but also reduce the combustion efficiency. Oxy-firing was originally
developed to improve the combustion efficiency primarily by eliminating the sensible heat lost in heating the nitrogen present in air, which is then lost m the flue gas.
NOXYFGMCN
Application: This control is the use of OXY-firing in container glass manufacturing furnaces to reduce NOx emissions. Oxygen enrichment refers to the substitution of oxygen for nitrogen in the
combustion air used to burn the fuel in a glass furnace. Oxygen enrichment above 90 percent is sometimes called "oxy-firing."
Discussion: The basic rationale for oxy-firing is improved efficiency, i.e., more of the theoretical heat of combustion is transferred to the glass melt and is not lost in the flue gas. Many other combustion
modification techniques (e.g., flue gas recirculation, staged combustion, and low excess air combustion) reduce NOx formation but also reduce the combustion efficiency. Oxy-firing was originally
developed to improve the combustion efficiency primarily by eliminating the sensible heat lost in heating the nitrogen present in air, which is then lost in the flue gas.
NOXYFGMFT
Application: This control is the use of OXY-firing in flat glass manufacturing furnaces to reduce NOx emissions. Oxygen enrichment refers to the substitution of oxygen for nitrogen in the combustion air
used to burn the fuel in a glass furnace. Oxygen enrichment above 90 percent is sometimes called "oxy-firing."
This control applies to flat-glass manufacturing operations with uncontrolled NOx emissions greater than 10 tons per year.
Discussion: The basic rationale for oxy-firing is improved efficiency, i.e., more of the theoretical heat of combustion is transferred to the glass melt and is not lost in the flue gas. Many other combustion
modification techniques (e.g., flue gas recirculation, staged combustion, and low excess air combustion) reduce NOx formation but also reduce the combustion efficiency. Oxy-firing was originally
developed to improve the combustion efficiency primarily by eliminating the sensible heat lost in heating the nitrogen present in air, which is then lost in the flue gas.
NOXYFGMPD
Application: This control is the use of OXY-firing in pressed glass manufacturing furnaces to reduce NOx emissions. Oxygen enrichment refers to the substitution of oxygen for nitrogen in the combustion
air used to burn the fuel in a glass furnace. Oxygen enrichment above 90 percent is sometimes called "oxy-firing."
Discussion: The basic rationale for oxy-firing is improved efficiency, i.e., more of the theoretical heat of combustion is transferred to the glass melt and is not lost in the flue gas. Many other combustion
modification techniques (e.g., flue gas recirculation, staged combustion, and low excess air combustion) reduce NOx formation but also reduce the combustion efficiency. Oxy-firing was originally
developed to improve the combustion efficiency primarily by eliminating the sensible heat lost in heating the nitrogen present in air, which is then lost in the flue gas.
(continued)
-------
Table C-l. CMDB Table 01 Summary—Description Field (continued)
cmabbreviation
description
NSCRGMCN
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR controls are post-combustion control > i n i> ¦¦1 !>.¦¦¦ i1 ised on the chemical reduction of nitrogen oxides
(NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx removal efficiency, which aiiows ine process to occur at lower temperatures.
Applies to glass-container manufacturing processes, classified under SCC 30501402 and uncontrolled NOx emissions greater than 10 tons per year.
Discussion: Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired, combustion units for emission control since the early 1970s. SCR is typically implemented
on units requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA, 2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction (EPA,
2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in the presence
of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx reduction efficiency and the lower and broader temperature ranges. However, the decrease in reaction
temperature and increase in efficiency is accompanied by a significant increase in capital and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with the use of
anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in water.
Today, catalyst formulations include single component, multi-component, or active phase with a support mi 11< mi ¦ Most catalyst formulations contain additional compounds or sup-ports, providing thermal
and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important design and operational factors that affect the rate of reduction include: reaction temperature range; residence
time available in the optimum temperature range; degree of mixing between the injected reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected reagent to
uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
NSCRGMFT
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR controls are post-combustion control technologies based on the chemical reduction of nitrogen oxides
(NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx removal efficiency, which allows the process to occur at lower temperatures.
Applies to large(>l ton NOx per OSD) flat-glass manufacturing operations (SCC 30501403) with uncontrolled NOx emissions greater than 10 tons per year.
Discussion: Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired, combustion units for emission control since the early 1970s. SCR is typically implemented
on units requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA, 2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction (EPA,
2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in the presence
of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR. the higher NOx reduction efficiency and the lower and broader temperature ranges. However, the decrease in reaction
temperature and increase in efficiency is accompanied by a significant increase m capital and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with the use of
anhydrous ammonia, as it must be transported and stored under pressure ("EPA, 2002). Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in water.
Today, catalyst formulations include single component, multi-component, or active phase with a support structure. Most catalyst formulations contain additional compounds or sup-ports, providing thermal
and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important design and operational factors that affect the rate of reduction include: reaction temperature range; residence
time available in the optimum temperature range; degree of mixing between the injected reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected reagent to
uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
(continued)
-------
Table C-l. CMDB Table 01 Summary—Description Field (continued)
cmabbreviation
description
NSCRGMPD
Application: This control is the selective catalytic reduction of NOx through add-on controls. SCR controls are post-combustion control > i n i> ¦¦1 !>.¦¦¦ i1 ised on the chemical reduction of nitrogen oxides
(NOx) into molecular nitrogen (N2) and water vapor (H20). The SCR utilizes a catalyst to increase the NOx removal efficiency, which aiiows ine process to occur at lower temperatures.
Applies to pressed-glass manufacturing operations, classified under SCC 30101404 and uncontrolled NOx emissions greater than 10 tons per year.
Discussion: Selective Catalytic Reduction (SCR) has been widely applied to stationary source, fossil fuel-fired, combustion units for emission control since the early 1970s. SCR is typically implemented
on units requiring a higher level of NOx control than achievable by SNCR or other combustion controls (EPA, 2002).
Like SNCR, SCR is based on the chemical reduction of the NOx molecule. The primary difference between SNCR and SCR is that SCR uses a metal-based catalyst to increase the rate of reaction (EPA,
2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue gas. The reagent reacts selectively with the flue gas NOx within a specific temperature range and in the presence
of the catalyst and oxygen to reduce the NOx.
The use of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx reduction efficiency and the lower and broader temperature ranges. However, the decrease in reaction
temperature and increase in efficiency is accompanied by a significant increase in capital and operating costs (EPA, 2002). The cost increase is due to the large amount of catalyst required.
The SCR system can utilize either aqueous or anhydrous ammonia as the reagent. Anhydrous ammonia is a gas at atmospheric pressure and normal temperatures. There are safety issues with the use of
anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in water.
Today, catalyst formulations include single component, multi-component, or active phase with a support mi 11< uk Most catalyst formulations contain additional compounds or sup-ports, providing thermal
and structural stability or to increase surface area (EPA, 2002).
The rate of reaction determines the amount of NOx removed from the flue gas. The important design and operational factors that affect the rate of reduction include: reaction temperature range; residence
time available in the optimum temperature range; degree of mixing between the injected reagent and the combustion gases; uncontrolled NOx concentration level; molar ratio of injected reagent to
uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop across the catalyst; catalyst pitch; catalyst deactivation; and catalyst management (EPA, 2001).
CATCFGMFT
Application: Filter tubes have nanobits of proprietary catalyst are embedded throughout the filter walls. The system can achieve excellent NOx removal using liquid ammonia that is injected upstream of the
filters, reacting with NOx at the catalyst to form nitrogen gas and water vapor.
This control applies to general glass manufacturing operations classii 10 i> r SCC 30501403
-------
Table C-2. CMDB Table 02 Efficiencies
cmabbreviatio
n
polluta
nt
loca
le
Effec
tive
Date
existing
measure
abbr
neiexistingd
evcode
minemissi
ons
maxemissi
ons
controleffi
ciency
costyea
r
costperton
ruleeff
rulepen
equation
type
capii rl'.iri
or
(llM-Hll
ntrate
r.ipannr
atio
incremen
talcpt
details
NCLPTGMCN
NOx
0
365
0
5
2002
5000
100
100
cpton
0.1424
4.5
Applied to large source types
NCLPTGMCN
NOx
0
0
365
5
2002
5000
100
100
cpton
0.1424
4.5
Applied to small source types
NCUPHGMPD
NOx
0
365
5
2002
5000
100
100
cpton
0.1424
4.5
Applied to large source types
NCUPHGMPD
NOx
0
0
365
5
2002
5000
100
100
cpton
0.1424
4.5
Applied to small source types
NELBOGMCN
NOx
0
365
10
1990
7150
100
100
cpton
0.1424
0
Applied to large source types
NELBOGMCN
NOx
0
0
365
10
1990
7150
100
100
cpton
0.1424
0
Applied to small source types
NELBOGMFT
NOx
0
365
10
1990
2320
100
100
cpton
0.1424
0
Applied to large source types
NELBOGMFT
NOx
0
0
365
10
1990
2320
100
100
cpton
0.1424
0
Applied to small source types
NELBOGMPD
NOx
0
365
10
1990
8760
100
100
cpton
0.1424
0
Applied to large source types
NELBOGMPD
NOx
0
0
365
10
1990
2320
100
100
cpton
0.1424
0
8760
Applied to small source types
NELBOGMGN
0
365
0
30
2002
7100
100
100
cpton
0.1424
0
Applied to large source types
NELBOGMGN
0
0
365
30
2002
7100
100
100
cpton
0.1424
0
Applied to small source types
NLNBUGMCN
NOx
0
365
40
2007
1072
100
100
cpton
0.14
4.3
1690
Applied to large source types
NLNBUGMCN
NOx
0
0
365
40
2007
1365
100
100
cpton
0.14
4.2
1690
Applied to small source types
NLNBUGMFT
NOx
0
0
365
40
2007
574
100
100
cpton
0.14
4.2
Applied to small source types
NLNBUGMFT
NOx
0
365
40
2007
447
100
100
cpton
0.14
4.3
Applied to large source types
NLNBUGMPD
NOx
0
365
40
1990
1500
100
100
cpton
0.1424
2.2
Applied to large source types
NLNBUGMPD
NOx
0
0
365
40
1990
1500
100
100
cpton
0.1424
2.2
Applied to small source types
NOxYFGMCN
NOx
0
0
365
85
1990
4590
100
100
cpton
0.1424
2.7
Applied to small source types
NOxYFGMCN
NOx
0
365
85
1990
4590
100
100
cpton
0.1424
2.7
Applied to large source types
NOxYFGMFT
NOx
0
365
85
1990
1900
100
100
cpton
0.1424
2.7
Applied to large source types
NOxYFGMFT
NOx
0
0
365
85
1990
1900
100
100
cpton
0.1424
2.7
Applied to small source types
NDOXYFGMG
NOx
0
85
1999
4277
100
100
cpton
NOxYFGMPD
NOx
0
0
365
85
1990
3900
100
100
cpton
0.1424
2.7
Applied to small source types
NOxYFGMPD
NOx
365
85
1990
3900
100
100
cpton
0.1424
2.7
Applied to large source types
NOxYFGMGN
365
0
85
2002
2353
100
100
cpton
0.1424
2.7
Applied to large source types
NOxYFGMGN
0
365
85
2002
2353
100
100
cpton
0.1424
2.7
Applied to small source types
NSCRGMCN
NOx
0
365
0
75
2007
1684
100
100
cpton
0.1424
4.2
Applied to large source types
NSCRGMCN
NOx
0
0
365
75
2007
2169
100
100
cpton
0.1424
4.5
Applied to small source types
NSCRGMFT
NOx
0
365
0
75
2007
855
100
100
cpton
0.1424
3.7
710
Applied to large source types
NSCRGMFT
NOx
0
0
365
75
2007
957
100
100
cpton
0.1424
3.4
Applied to small source types
(continued)
-------
Table C-2. CMDB Table 02 Efficiencies (continued)
cmabbreviatio
n
polluta
nt
loca
le
Effec
tive
Date
existing
measure
abbr
neiexistingd
evcode
minemissi
ons
maxemissi
ons
controleffi
ciency
costyea
r
costperton
ruleeff
rulepen
equation
type
capii rl'.iri
or
(llM-Hll
ntrate
r.ipannr
atio
incremen
talcpt
details
NSCRGMPD
NOx
0
365
75
1990
2530
100
100
cpton
0.1424
1.3
Applied to large source types
NSCRGMPD
NOx
0
0
365
75
1990
2530
100
100
cpton
0.1424
1.3
Applied to small source types
CATCFGMFT
NOx
0
365
0
95
2013
997
100
100
cpton
0.05
4.6
Applied to large source types
CATCFGMFT
NOx
0
0
365
95
2013
1045
100
100
cpton
0.05
4.6
Applied to small source types
O
-------
Table C-3. CMDB Table 06 References (New)
Data Source
Description
GM-1
Oxygen Enriched Air Staging a Cost-effective Method For Reducing NOx Emissions. Industrial Tcchnologics. April 2002. Available at:
htto://wwwl.eere.enerev.eov/manufacturine/resources/elass/odfs/airstaeine.i3df
GM-2
Best Available Techniques (BAT) Reference Document for the Manufacture of Glass. European Commission 2013. Available at:
htto://eiirocb.irc.ec.eurora.eu/reference/BREF/GLS Adootcd 03 2012.odf
GM-3
Confidential Vendor Quote
Table C-4. CMDB Table 04_Equationsa
cmabbreviation
cmeqntype
pollutant
costyear
varl
var2
var3
var4
var5
var6
var7
var8
var9
varlO
NLNBUGMCN
Type 2
NOx
2008
30,930
0.45
9,377
0.40
NLNBUGMFT
Type "L"
NOx
2008
527
664,557
132
150,105
NSCRGMCN
Type 2
NOx
2008
79,415
0.51
NSCRGMCN
Type "L"
NOx
2008
643
135,302
NSCRGMFT
Type "L"
NOx
2008
3,681
1,000,000
842
424,930
aType "L" is a linear equation; variables are the slope and intercept.
-------
APPENDIX D
LEAN BURN ENGINES
Copies of the database tables for showing all records for Lean Burn Engine NOx controls
are provided:
- Table D-01_Summary
- Table D-02_Efficiencies
- Table D-03_SCCs
- Table D-04_Equations
- Table D-06 References
D-l
-------
Table D-01_Summary
cmname
cmabbreviation
pechanme
ascode
majorp
oil
controltechn
ology
sourcegr
oup
sector
class
equiplife
neid
evic
eco
de
datereviewe
d
datasour
ce
months
description
Low
Emission
Combustion;
Lean Burn
ICE—NG
NLECICENG
NOx
Low
Emission
Combustion
Lean
Burn
ICE—
NG
PTNONIPM
Known
10
9/15/2013
ABCD3
Low Emission Combustion includes Precombustion
chamber head and related equipment on a Lean Burn
engine.
Layered
Combustion;
Lean Burn
ICE 2
stroke—NG
NLCICE2SNG
NOx
Layered
Combustion
Lean
Burn
ICE—
NG
PTNONIPM
Known
10
9/15/2013
ABCD1
Layered combustion—2 stroke, Lean Burn, NG (Air
Supply; Fuel Supply; Ignition; Electronic Controls;
Engine Monitoring). Evaluation for 3 most representative
made/models of 2 stroke LB compressor engines. All
retrofit combustion-related controls may not be available
for all manufacturers and models of 2-stroke lean burn
engines. Actual NOx emission rates would be engine
design specific. Efficiency achieved may range from 60
to 90%, depending on the make/model of engine
(approximate range of NOx emissions of 3.0 to 0.5
g/bhp-hr).
Layered
Combustion;
Lean Burn
ICE 2 stroke
Large
Bore—NG
NLCICE2SLBNG
NOx
Layered
Combustion
Lean
Burn
ICE—
NG
PTNONIPM
Known
10
9/15/2013
ABCD1
Layered combustion—for Large Bore, 2 stroke, Lean
Burn, Slow Speed (High Pressure Fuel Injection achieves
90% reduction; Turbocharging achieves 75% reduction;
Precombustion chambers achieves 90% reduction;
Cylinder Head Modifications). All retrofit combustion-
related controls may not be available for all
manufacturers and models of 2-stroke lean burn engines.
Actual NOx emission rates would be engine design
specific. Efficiency achieved may range from 60 to 90%,
depending on the make/model of engine (approximate
range of NOx emissions of 3.0 to 0.5 g/bhp-hr).
Air to Fuel
Ratio
Controller;
Lean Burn
ICE—NG
NAFRCICENG
NOx
Air to Fuel
Ratio
Controller
jn Li-
1 NIPM
Known
10
12/5/2012
ABCD3
Selective
Catalytic
Reduction;
Lean Burn
ICE 4
Stroke—NG
NSCRICE4SNG
NOx
Selective
Catalytic
Reduction
Lean
Burn
ICE—
NG
PTNONIPM
Known
10
9/15/2013
ABCD1
ABCD2
ABCD3
SCR can be used on Lean Burn, NG engines. Assumed
SCR can meet NOx emissions of 0.89 g/bh-hr. This is a
Known technology, however there is indication that
applicability is engine/unit specific.
Selective
Catalytic
Reduction;
ICE—Diesel
NSCRICEDS
. ".'i<;ctive
Catalytic
Reduction
ICE—
Diesel
PTNONIPM
Known
7
9/15/2013
ABCD4
SCR can be used on Diesel engines.
-------
Table D-02 Efficiencies
cmabbreviation
polluta
nt
local
e
Effec
tlve
Date
existing
measur
eabbr
neiexi
stingd
evcod
e
mine
missio
IIS
maxemis
sions
controle
fflciency
costyear
costperton
raleeff
rulepe
n
equation
type
caprect'ac
tor
discount
rate
capann
ratio
increme
ntalcpt
details
NLECICENG
NOx
NA
NA
NA
NA
0
365
80
2001
1,000
100
100
cpton
0.1424
7
7.025
NA
NLCICE2SNG
NOx
NA
NA
NA
NA
0
365
97
2009
4,900
100
100
cpton
0.1424
7
7.024
NA
NLCICE2SLBNG
NOx
NA
NA
NA
NA
365
0
97
2010
1,500
100
100
cpton
0.1424
7
7.024
NA
Apply to large
source types.
Assumed Interest
Rate of 7 percent
(not provided in
documentation)
to calculate
annual costs.
NLCICE2SLBNG
NOx
NA
NA
NA
NA
0
365
97
2010
38,000
100
100
cpton
0.1424
7
7.024
NA
Apply to small
source types.
NAFRCICENG
NOx
NA
NA
NA
NA
0
365
80
2001
200
100
100
cpton
0.1424
7
7.023
NA
NSCRICE4SNG
NOx
NA
NA
NA
NA
0
365
96
2001
2,900
100
100
cpton
0.1424
7
1.401
NA
NSCRICEDS
NOx
NA
NA
NA
NA
0
365
90
2005
9,300
100
100
cpton
0.1098
7
2.45
NA
-------
Table D-03 SCCs
cmabbreviation
Source Oassiflcation Code
Status
NLECICENG
20200252
NLECICENG
20200254
NLECICENG
20200255
NLECICENG
20200256
NLCICE2SNG
20200252
NLCICE2SNG
20200254
NLCICE2SNG
20200255
NLCICE2SNG
20200256
NLCICE2SLBNG
20200252
NLCICE2SLBNG
20200254
NLCICE2SLBNG
20200255
NLCICE2SLBNG
20200256
NLCICE2SLBNG
20200401
NLCICE2SLBNG
20200402
NLCICE2SLBNG
20200403
NAFRCICENG
20200252
NAFRCICENG
20200254
NAFRCICENG
20200255
NAFRCICENG
20200256
NSCRICE4SNG
20200252
NSCRICE4SNG
20200254
NSCRICE4SNG
20200255
NSCRICE4SNG
20200256
NSCRICEDS
20200102
NSCRICEDS
20200107
-------
Table D-04_Equations
cmabbreviation
cmeqntype
pollutant
co sty ear
varl
var2
var3
var4
var5
var6
var7
var8
var9
varlO
NSCRICE4SNG
linear capital and annual
NOx
2001
107.1
27186
83.64
14718
NLECICENG
capital and annual
NOx
2001
16019
0.0016
2280.8
0.0016
NAFRCICENG
linear capital and annual
NOx
2001
1.0337
4354.5
0.1852
619.99
Table D-06 References
Data Source
Description
ABCD1
OTC 2012. Technical Information Oil and Gas Sector. Significant Stationary Sources of NOx Emissions. Final. October 17, 2012.
ABCD2
SJVAPCD 2003. RULE 4702—Internal Combustion Engines—Phase 2. Appendix B, Cost Effectiveness Analysis for Rule 4702
(Internal Combustion Engines—Phase 2). San Joaquin Valley Air Pollution Control District. July 17, 2003.
www.arb.ca.sov/om/i3mmeasures/ceffect/rulcs/sivaDcd 4702.Ddf
ABCD3
CARB 2001. Determination of Reasonably Available Control Technology and Best Available Retrofit Control Technology for
Stationary Spark-Ignited Internal Combustion Engines. California Environmental Protection Agency, Air Resources Board, Stationary
Source Division, Emissions Assessment Branch. Process Evaluation Section. November 2001.
ABCD4
EPA 2010. Alternative Control Techniques Document: Stationary Diesel Engines. March 5, 2010.
-------
APPENDIX E
NOTES PROVIDED HERE TO EPA QUESTIONS ON LEAN BURN RICE
E-l
-------
EPA Question 1: What is the applicability of SCR to RICE, especially Lean Burn?
Notes for Question 1
In addition to the two documents cited in Section 5 of the report with costs for selective
catalytic reduction (SCR) for Lean Burn (LB) engines, there are several other references that
indicate SCR is feasible for LB engines and several that provide input on technical issues related
to SCR use for LB engines. In summary, from the references reviewed, SCR seems to be
technically feasible in most instances for LB engines, however, SCR application may not be
feasible in all cases due to technical issues at individual sites and individual engines. In addition,
SCR costs are higher relative to other NOx control techniques for LB engines. See more detailed
discussion below.
SCR can be applied to LB engines, achieving greater than 90 percent NOx reductions
(Table 4 on p. 6 provides a slightly different value, greater than 95 percent). The costs [assumed
this referred to capital costs] ranged from $50/hp to $ 125/hp. No annual operating costs were
provided. In discussions on p. 8 regarding "catalysts on 1C engines" in general (including NSCR,
SCR, oxidation, and Lean-NOx), it is noted that "Thousands of stationary 1C engine catalyst
applications have been effectively used for stationary 1C engine gaseous emission control for
five years or more. Some installations, however, do experience performance loss over time,"
however the text goes on to explain remedies for catalyst poisoning issues. Costs [capital] for
SCR, LB ranged from $50 to $ 125/hp (no cost year provided). (MECA 1997)
The literature suggests that SCR is technically feasible for LB engines but there are
problems that make SCR installation questionable. Two stroke (2S) LB engines are sensitive to
changes in exhaust pressure, which could be problematic for retrofit of SCR on existing engines,
but can be alleviated with proper design and sizing of airflow and exhaust components. This
reference cited a presentation that indicated the following issues with SCR: applying SCR to
pipeline engines is not feasible because the exhaust temperatures (T) are below the operating
window for SCR or where SCR effectiveness is reduced; SCR installations are at unmanned
facilities; and SCR has not been demonstrated for variable loads. However, the OTC 2012
reference responded to each of these issues, stating that there are several manufacturers and
suppliers that offer SCR systems that indicate their catalysts are capable of effectively operating
over a wide range of exhaust gas T; modern software based controls and SCADA
communication technologies allow operation from a remote location; and SCR can function
properly over a broad range of loads given catalysts that are effective over wide T ranges,
modern controls regulate fuel and air flows to ensure combustion O2 and T are at expected levels
E-2
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and to regulate reagent flow. A study conducted for retrofitting existing pipeline engines
indicates that SCR is a high cost alternative to combustion improvements, primarily due to the
high cost of ongoing reagent consumption, (p. 25-26) (There is a similar discussion for SCR for
four stroke (4S) LB on p. 39-40; cited presentation at Gas Machinery Conference in October
2011.) (OTC 2012)
Shell indicated they have installed SCR on diesel engines (LB) that they utilize in drilling
rig operations. Shell indicated that have been able to achieve greater than 90 percent reduction in
NOx emissions while encountering minimal operational issues (see p. 10). (OTC 2012)
The OTC 2012 document indicated that MECA has noted there have been limited
examples to date of SCR retrofit on 2S LB engines as demonstration test programs, but the
results of these programs have not been published (see p. 27). It appears that SCR for NOx does
not appear to be technically infeasible genetically but that individual 2S LB engine
characteristics and installations may be greatly problematic or not cost effective, although this
site-specific issue is not altogether different than other emission reduction technologies (see p.27,
40). (OTC 2012)
The OTC 2012 document indicated that MECA has stated the commercial use of SCR
systems for LB stationary engines have been in place since the mid-1980's in Europe and since
the early 1990s in the US. One MECA member company has installed over 400 SCR systems
worldwide for stationary engines with varying fuel combinations, including dozens of NG
compressor engines in the US. These 4S LB engines with urea-SCR achieve >90% NOx
reduction (see p.40). (OTC 2012)
EF&EE announced in November 2010 that is received an order from Clean Air Power
Inc. for 6 SCR systems, to be installed on large LB NG compressor engines at gas storage sites in
TX and MS (see p.40). (OTC 2012)
Clean Air Power cited: 4 SCRs supplied at Pine Prairie Energy Center, Louisiana; 1 SCR
supplied at EXTERRAN/TRESPALACIOS, Texas; and 4 SCRs supplied to EXTERRAN/LEAF
River, Mississippi (see p.41). (OTC 2012)
A PowerPoint slide presentation from a MARAMA workshop discusses the use of SCR
for RICE and LB. Johnson Mathey (JM) included SCR as a feasible control for LB engines in a
presentation at a May 2011 MARAMA Workshop. (The SCR systems included Urea and
Ethanol as reagents.) SCR operating temperatures range from 700 to 900°F for internal
combustion (IC) engines and achieved 90 percent NOx reductions. The budgetary costs
E-3
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[assumed this referred to capital costs] ranged from $150/ hp for a 500 hp unit (approximately
$75,000) to $42/hp for a 3000 hp unit (approximately $126,000) (cost year not provided). No
annual operating costs were provided. JM cited 4 LB engine installations of SCR on gas
compressors at 2 locations, including Loudon Compressor Station in Clarksburg, WV and Lodi
Compressor/Storage in Kirby Hills, CA. (Chu 2011) These engines are listed in the following
table:
SCR for Lean Burn Engines—Johnson Mathey presentation at 2007 MAUA.M A Workshop
Engine Model
Engine hp
NOx, g/bhp-hr
NOx Reduction, %
CAT G3516
1,340
1.5
90%
CAT G3608
2,370
0.7
90%
CAT G3612
3,550
0 "
90%
CAT G3616
4,735
0 "
90%
References
(MECA 1997). Emission Control Technology for Stationary Internal Combustion Engines:
Status Report. Manufacturers of Emission Controls Association (MECA). July 1997.
(Chu 2011). NOx Control for Stationary Gas Engines. W. Chu, Johnson Mathey. Presented at
Advances in Air Pollution Control Technology, MARAMA Workshop. May 19, 2011.
(OTC 2012). Technical Information Oil and (}as Sector, Significant Stationary Sources of NOx
Emissions. Final. October 17, 2012.
E-4
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EPA Question 2: What are credible estimates of the percentage of RICE NOx Emissions
that are lean burn versus rich burn when RICE emissions are unspecified?
Notes for Question 2
There does not seem to be much information on NOx emission totals for LB and rich
burn (RB) engines. A few references attempted to provide information on the numbers or
populations of LB and RB engines. Several of the references highlighted surveys of engine
populations and summary information from various engine databases. These data in general tend
to point to a large LB engine population, however most of the references noted that RB engines
are typically not captured or covered in surveys, databases, or by permits because the RB engines
tend to be smaller in size. In general, larger engines tend to be LB and smaller engines tend to be
RB. The ERLE 2009 study noted that approximately 73% of the 5,600 engines/horsepower
capacity covered in their study of NG pipeline systems are LB, and approximately 6% are RB
(the balance is not known). In the KSU 2011 database, approximately 66% of the 4,729 engines
used in E&P at major sources are LB and 34% are RB. In addition, the EDF 2008 document
cited a 2007 survey conducted for DFW NAA and AA that attempted to identify those engines
that did not meet reporting requirement thresholds and were therefore not included in the TCEQ
inventory. This reference, which included small engines, indicated that for smaller engines <500
hp, approximately 96% are RB and 4% are LB. The reference also indicated that for larger
engines >500 hp, there is approximately a 50-50 split of LB and RB engines and of horsepower
capacity. The ETCG 2013 reference also highlights engines in the Barnett Shale region. Data
from the TCEQ Barnett Shale Special Inventory (Phase I) survey indicated that the majority of
engines in the Barnett Shale are RB (84%). For those engines <240 hp, 95% are RB and 5% are
LB, however, in looking at those engines >240 hp, 59% are LB and 41% are RB. More details
for each of these references are provided in the discussion that follows.
Note also that the emissions rate in g/bhp-hr for LB engines tend to be higher, and the
emissions rate for RB engines tends to be lower. (See the tables under Question 4 of this
appendix for relative emission rate values for LB and RB engines in various states and local
districts.)
A summary of the information available from various references is provided below.
The CARB 2001 reference indicated that LB engines tend to be larger in size, and smaller
engines tend to be RB (p.B-4). (CARB 2001)
EPA received comments from the Interstate Natural Gas Association of America
(INGAA) on the 2002 proposed rule, where EPA indicated that 156 of 168 large engines listed in
E-5
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the NOx SIP Call Inventory that have SIC codes associated with the NG transmission industry
are LB engines (with the exception that the other 12 engines are no longer in service, are owned
by a company not included in the industry database, or are duplicates). INGAA recommended
that EPA assume all large NG stationary engines in the inventory are LB. (EPA 2003).
One prominent use of large Reciprocating Internal Combustion Engines (RICE) is to
drive NG pipeline compressor stations; almost all engines affected by the NOx SIP Call Phase 2
rule in IL (except for 3 engines) are used to compress NG at NG pipeline stations (11 ¦ l\\ 2< n >7)
A 2009 ERLE study cited in this reference indicated there are 5,600 engines on the NG
pipeline systems with a collective rating of 9,150,000 hp. That study further indicated that
approximately 80 percent of the rated output was low speed 2S, low speed 4S integral engines
and diesel medium speed engines converted to spark ignition (SI). Of these 80 percent of
engines, 78 percent were 2S LB, 14 percent were 4S LB, and 8 percent were 4S RB. (On a rated
horsepower basis, 80 percent was 2S LB, 15 percent was 4S LB, and 5 percent 4S RB) (p. 16).
[On an overall basis, compared to the full 9,150,000 hp collective rating, 2S LB would be
roughly 62%, 4S LB would be roughly 1 1%, and 4S RB would be roughly 6% of the overall
rating/engines. So 73% would be LB, 6% would be RB, and the balance is not known.] (OTC
2012)
Engine Type
No. Engines, %
Horsepower, %
2S LB
78
80
4S LB
14
15
4S RB
8
5
The DE 2012 document cited a 2003 Pipeline Research Council International (PRCI)
document that identified 5,686 engines: 71% are LB and 29% are RB (based on dropping the
turbine numbers in the table below) (p. 19). (DE 2012) [These data may be repeated in OTC
2012, as it looks fairly similar to the 2009 ERLE study data cited above from OTC 2012.]
2003 Pipeline Research Council International Data (PRCI)
Unit Type
U.S. Total Units (%)
Avg hp
2SLB
2,955 (44%)
2,113
4SLB
1,059 (16%)
1,844
RB
1,672 (25%)
589
Turbine
1,016 (15%)
6,121
E-6
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Energy Information Agency (EIA) data cited in the OTC 2012 reference indicated there
were 1201 NG mainline compressor stations in the U.S. in 2006, with combined rating of
16,800,000 hp. Between 2007 and 2010, the Federal Energy Regulation Commission (FERC)
approved new compressor stations or upgrades to existing compressor facilities that were
expected to add 2,600,000 hp (p. 16). (OTC 2012)
The Kansas State University (KSU) 2011 document included a database on 4.721) engines
used in Exploration and Production (E&P) at major sources. LB engines accounted for bb
percent of engines (17 percent are 2S and 49 percent are 4S), and RB engines accounted for 34
percent. LB outnumbers RB among engines included in the database; because many engines
rating less than 100 hp are not included, and because the majority of the smaller units are 4S RB,
RB are actually underrepresented in the database. A listing of the engines (manufacturer and
model), air to fuel (A/F) ratio type, cycle, and horsepower are included in Appendix I of the KSU
2011 document. The database was not meant to collect every single engine in use but rather to
provide a frequency distribution of engines. The data was pulled from multiple sources,
including the State of Wyoming Engine Inventory Database, EPA 1CCR Database, GTI/PRCI
Engine and Turbine Database, and Database of Colorado and New Mexico Engines (from
Universal Compression). The engine database likely includes only permitted engines, and lower-
hp engines are underrepresented in the database, (pp. 5-7) (KSU 2011)
The EDF 2008 reference indicated most engines in Barnett Shale area of Texas are 100 to
500 hp but some large engines of 1000+ hp are also used. (EDF 2008)
The EDF 2008 reference indicated that the TCEQ Point Source Emissions Inventory
(PSEI) does not include a substantial fraction of compressor engine emissions. Most of the
missing engines in the DFW NAA were units with emissions below the reporting thresholds, but
the combined emissions from large numbers of these engines can be substantial (pp. 13-14). The
2007 DFW Engine survey indicated there were approximately 680,000 hp of installed engine
capacity in DFW NAA not previously reported to the TCEQ PSEI (p. 14). The report also
estimated that there is approximately 132,000 hp of engines in Attainment Area (AA) counties
within the Barnett Shale that don't report to PSEI (non-PSEI) (p. 14). The LB and RB engine
data from the 2007 DFW Engine Survey for the DFW NAA is provided in the table below. In
this survey, there seem to be fairly even numbers of LB (51%) and RB (49%) engines in the
>500 hp category, and there seems to be fairly even horsepower capacity for the LB and RB
engines. For smaller engines that are <500 hp, there are significantly more RB engines (736
E-7
-------
engines, or 96%) than LB engines (27 engines, or 4%). In addition, for the smaller engines <500
hp, the horsepower capacity for RB represents 15% and for LB is <1%. (EDF 2008)
Installed Engine Capacity in 2007 DFW Engine Survey by Engine Type and Size, in DFW
NAA (EDF 2008)
Engine
Type
Engine
Size, hp
Number of
Engines
Percent of
Engines,
%
Typical Size,
hp
Installed
Capacity, hp
Percent of
Installed
Capacity,
%
RB
<50
12
1.03%
50
585
0.086%
RB
50-500
724
62%
140
101,000
15%
RB
>500
200
17%
1,400
280,000
41%
LB
<500
27
2.3%
185
4.940
0.72%
LB
>500
206
18%
1.425
294.000
44%
The EDF 2008 reference looked at all of the compressor engines in the Barnett Shale
region, including both the engines located within the DFW NAA and the engines in the DFW
AA (including those larger engines that report to the PSE1 and those non-PSEI engines). New
TCEQ rules became effective in 2009 to reduce NOx from the subset of engines located in the
DFW NAA that typically are not reported to the PSE1 (due to their small size) for major sources
(p. 25). Engines that are located outside the DFW NAA are not subject to the 2009 rule. As
shown in the table below, a 50% reduction of emissions from 2007 to 2009 was estimated in
DFW NAA, taking into account the growth, regulation affect, and NSCR installations. For AA
engines, emissions will increase from 2007 to 2009 due to growth and the fact that no regulation
applies (these engines not subject to 2009 engine regulation) (p. 19). (EDF 2008)
NOx Emissions from Compressor Engines in Barnett Shale of Texas (EDF 2008)
Area
2007 NOx Emissions, tpd
2009 NOx Emissions, tpd
DFW NAA engines
32
16
AA engines
20
31
Barnett Shale engines, total
52
47
The reference then looked at emission reductions for extending the 2009 rule to all
engines in the Barnett Shale (including those in the AA). By extending the 2009 engine rule,
E-8
-------
NOx emissions from AA engines would drop by approximately 6.5 tpd (p.25) (this approach
reduces emissions from a large number of engines, in particular RB engines between 50 to 500
hp). (EDF 2008)
The ETCG 2013 reference indicated that analysis of test reports at the TCEQ Tyler office
showed 68 compressor engines: 9 engines (13%) <240 hp and 59 engines (87%) >240 hp (and
69% of all engines >500 hp) (p. 11). (A graph showing the distribution of the hp for all 68
engines is shown on p. 12 of the reference document.) (ETCG 2013)
The ETCG 2013 reference discussed TCEQ Barnett Shale Special Inventory (Phase 1)
survey data. The table below is a summary of the engine horsepower distribution. (A graph
showing the distribution of NG engines in the Barnett Shale region is shown in Figure 5-1 on
p. 21 of the reference document.) The majority of engines in the Barnett Shale are RB and are
<240 hp, see the two tables below. This data set shows that smaller hp engines are predominantly
RB, with 2,089 engines <240 hp are RB (95%) and 104 engines (5%) are LB. For engines >240
hp, 327 engines (59%) are LB and 230 engines (41%) are RB.
2009 Equipment Inventory of Stationary NG Engines by Horsepower for Barnett Shale
Region. (ETCG 2013)
Percent of
Engine Size
Total I'.ngines
Total
Engines
Engine Type,
RB or LB
Number of
Engines
Percent of Each
Size Category
0 to 50 hp
31"
i:".,
RB
302
95%
LB
15
4.7%
50 to 240 hp
I.S"(.
«.x%
RB
1,787
95%
LB
89
4.7%
>240 hp
55"
20%
RB
230
41%
LB
327
59%
E-9
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Barnett Shale Special Inventory Phase I Equipment Survey Data on Stationary Gas-Fired
Engines for 2009. (ETCG 2013)
Engine counts
<240 hp >240 hp Total
RB and LB
2,193 557 2,750
RB only
2,089 230 2,319
LB only
104 327 431
The CO DPHE reference indicates that large NG RICE represent 16% of the statewide
point source NOx emissions (16,199 tpy of 101,818 tpy) and 73% of the ICENOx emissions
(16,199 tpy of 22,210 tpy) (p. 1). (CO DPHE)
Example Emissions Estimates: It is difficult to draw conclusions for the emissions from
LB versus RB from the data provided. However, some assumptions could be made to help draw
conclusions for the defined scenario. If assume that the total capacity between LB and RB in the
ERLE study is more representative of the total reporting population than the 50-50 split in the
EDF study; assume that operating hours are similarly distributed for both LB and RB; and if the
EFs tend to be higher for LB than for RB engines, then it is likely that 90% plus of the total
emissions are from I ,li
References
(CARB 2001). / V/iT///ii ml ioii of Reasonably Available Control Technology and Best Available
Retrofit (. 'onirol technology for Stationary Spark-Ignited Internal Combustion Engines.
California Environmental Protection Agency, Air Resources Board, Stationary Source
Division, Emissions Assessment Branch, Process Evaluation Section. November 2001.
(IEPA 2007). Technical Support Document for Controlling NOx Emissions from Stationary
Reciprocating Internal Combustion Engines and Turbines. AQPSTR 07-01. Illinois
Environmental Protection Agency, Air Quality Planning Section, Division of Air
Pollution Control, Bureau of Air. March 19, 2007.
(EPA 2003). Stationary Reciprocating Internal Combustion Engines: Technical Support
Document for NOx SIP Call. U.S. Environmental Protection Agency. D. Grano and B.
Neuffer. October 2003.
E-10
-------
(EDF 2008). Emissions from Natural Gas Production in the Barnett Shale Area and
Opportunities for Cost Effective Improvements. Conducted by Department of
Environmental and Civil Engineering, Southern Methodist University, for Environmental
Defense Fund. Peer-Review Draft. September 30, 2008.
(KSU 2011). Final Report: Cost-Effective Reciprocating Engine Emissions Controls and
Monitoring for E&P Field and Gathering Engines. K. Hohn and S. Nuss-Warren, Kansas
State University. November 2011.
(OTC 2012). Technical Information Oil and Gas Sector, Significant Stationary Sources ofNOx
Emissions. Final. October 17, 2012. [This document focuses on Offshore Gulf of
Mexico, Rocky Mountains, Southwest, and Mid-Continent areas.]
(ETCG 2013). Gas Compressor Engine Study for Northeast Texas, for East Texas (\>uncil of
Governments. Prepared by ENVIRON International Corporation, for East Texas Council
of Governments. June 2013.
(CO DPHE). Reciprocating Internal Combustion Engine (RICE) Source Category, Reasonable
Progress Evaluation for RICE Source Category. Colorado Department of Public Health
and Environment—Air Pollution Control Division.
E-ll
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EPA Question 3: What is the effect of NOx SIP call controls on RICE in NOx SIP call
states? That is, what percent reduction and types of controls have gone into place in states
affected by the NOx SIP call?
Notes for Question 3
The applicability, reduction achieved, and cost for RICE NOx controls are often engine
specific and highly variable. (DE 2012) (OTC 2012)
Common NOx control techniques are provided in the table below, along with \()k
emission reductions achievable. (References from other areas outside of the NOx SIP call states
also provided details on controls and emissions reductions achieved by these controls and are
included in the table.)
Effectiveness of Combustion Control Technologies and Add-On Controls
Control Technique
(OTC 2012)
(KSU 2011)
(CARB 2001) (CO DPHE)
2 Stroke, LB
Improved combustion air
flow, Turbocharger
Retard ignition timing
Improved air fuel mixing.
High Pressure Fuel Injection
Screw-in PCC
Autobalance cylinders
(p. 18, 31): up to
75%
(p. 54): diescl. 10%
(reduces engine
efficiency: increases
PM)
(p. 18. 31): up to
90%
Up to 90%:
0.5 to 2 g/bhp-hr
(increases fuel
economy: may
increase CO) (p. 9)
Up to 10% (increase
fuel economy: may
increase CO) (p. 9)
Advanced In-cvlindcr mixing —
Precombuslion chamber
(PCC) ignition system
Micro Precombuslion
chamber (MPCC). hybrid of
Highenergv Ignition system
and PCC
(p. 19, 31-32): up to
90%
(p. 23): not
provided
(p. B-7.8): 15 to 20% (pp. 5-7);
30% (increases $310 to
fuel consumption; $2,000/ton
increases VOC, (p. 8)
HAP)
30 to 70% (p. 11) —
1 g/bhp-hr (p. 10) —
2 to 4 g/bhp-hr (p. 10) —
1 g/bhp-hr (p. 10) —
(continued)
E-12
-------
Effectiveness of Combustion Control Technologies and Add-On Controls (continued)
Control Technique
(OTC 2012)
(KSU 2011)
(CARB 2001) (CO DPHE)
2 Stroke, LB (cont.)
Air to Fuel Ratio Controller
(AFRC)
(p. 19, 32): not
provided
Combustion modifications,
Layered Combustion controls
(p. 25): 60 to 90%;
range of 0.5 to 3
g/bhp-hr
Not provided; use in
combo with Increased
air flow, or
postcombustion
Catalyst; a few
thousand $ for small
engine to $30K for
larger engines (p. 12).
(p. B-8): not
provided (fuel
consumption
penalty of 3%;
may increase CO.
VOC)
5 to 30%
(pp. 5-7); $320
to $8,300/ton
(P- 7)
4 stroke, LB
EGR and NSCR
Combustion modifications,
Layered Combustion controls
(p. 32): (emissions
lower than SCR)a
(p. 38): 90%; range
of 0.5 to 2 g/bhp-hr
Engines (general) or LB
High energy ignition system
(HEIS)
Low emission combustion
(LEC)/precombustion
chamber retrofit (PCC) [also
applicable to RB]
Turbochaiuinu'
superchaiuiiiu. and
Aftercoolniu
(p. 18, 31,44) lu",
2 5 In ' u hhp-hr
ipp 'J-1 ID
ip IS) I p in "5".. —
EGR
ip 55) diesel.
-40% (lobb of fuel
efficiency; loss of
engine output)
Still under
development for NG
engines; not cost
effective at this time
(p. 11).
Ignition system improvement —
(p. B-12): 200
ppm NOx
(p. B-10): 80%
(may increase
VOC, CO)
(p. B-13): 3 to
35% for
Aftercooling
(may reduce
VOC, CO;
increases engine
efficiency, power
rating)
(p. B-14): 30%
(reduces engine
peak power;
reduces fuel
efficiency by 2 to
12%)
(p. B-ll-2): not
provided (may
increase VOC,
CO)
(continued)
E-13
-------
Effectiveness of Combustion Control Technologies and Add-On Controls (continued)
Control Technique
(OTC 2012)
(KSU 2011)
(CARB 2001) (CO DPHE)
Engines (general) or LB
(cont.)
Homogeneous charge
compression ignition
(HCCI), combines best
features of SI and CI engines
Fuel switching,
Hydrogen/NG blended fuel
Selective Catalytic Reduction
(SCR)
Lean-NOx catalysts
(p. 19, 32, 55): 50 to
95% (reduces THC,
CO)
(p. 55): diesel,
50%
10 In
NOxTech
LeanNCK imps
NOx Adsmlvi
(SCOMK)
^"..i(P- 14)
(p. B-23): >80% 80 to 90%
(pp. 5-7); $430
to $4,900/ton
(P- 9)
(p. B-24): diesel, —
25 to 50%
(increases fuel
consumption;
may increase
VOC, PM)
(p. B-25): 80 to —
90%; (decreases
CO, VOC, PM by
80%; fuel penalty
5 to 10%)
(p. B-27): >90% —
on diesel engine
<100 hp; [2 ppmv
on NG turbine]
50 to 95%
(pp. 5-7)
(continued)
E-14
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Effectiveness of Combustion Control Technologies and Add-On Controls (continued)
Control Technique
(OTC 2012)
(KSU 2011)
(CARB 2001) (CO DPHE)
Engines (general) or LB
(cont.)
Fuel switching, methanol —
Hybrid system, modification
of dual bed NSCR system
Use of electric motors in
place of combustion engines
(p. B-16): 30%
for conversion
from NG to
methanol (c;m
generate
formaldehyde
emissions)
(p. B-22): 3 in 4
ppm NOx
(p. B-27): >60%
60 to 100%
(pp. 5-7); $100
to $4,700/ton
[not include
Ml costs]
(P- 9)
RB
Nonselective catalytic
reduction (NSCR) plus
AFRC
Convert RB to LB
EGR
Pre-stratified charge
(converts RB to LB)
(p. 45, 49-51): 90 to
99% (reduces CO.
VOC)
>90%. < 1 g/bhp-hr
(reduces CO. HC)
(p. 13)
(p. B-19-20):
>90% (reduces
CO >80%:
reduces
CO>5()%:
increases fuel
consumption)
80 to 90%
(pp. 5-7);
Capital cost is
$35,000; O&M
is $6,000;
Annualized
capital is
$4,851; TAC is
$10,851;
$571/ton (p. 8)
80%
(improved fuel
efficiency)
E-15
-------
aSome industry literature suggests that some particular 4S RB SI reciprocating engines can be converted to LB
configurations with the accompanying LB engine NOx reduction capabilities. One vendor indicates that
conversion to a LB configuration and the use of exhaust gas recirculation (EGR) delivers the advantages of a LB
engine's efficiency and the RB engine's capability of utilizing NSCR for NOx control. The ability to convert a RB
engine to a LB configuration is highly unit specific and does appear to have had widespread application in
industry (p. 45). (OTC 2012)
Illinois: IEPA projected 2007 NOx emissions from 28 engines subject to the NOx SIP
call to be 6,618 ton/season. NOx emission reductions from these sources were estimated to be
5,422 ton/season, and controlled NOx emissions levels were estimated to be 1,196 ton/season.
(So baseline emissions were estimated to be 6,618 ton/season and controlled emissions were
estimated to be 1,196 ton/season.) (IEPA 2007)
IEPA 2002 base year emissions inventory was 23,347 tpy NOx emitted from RICE and
turbines, or approximately 8.4 percent of total point source NOx emissions (277,899 tpy NOx
emissions from all point sources in Illinois) (p. 12). (IEPA 2007)
In addition to the NOx SIP Call requirements, IEPA also included additional units in its
NOx regulation. NOx SIP Call units were to comply by May 2007, and additional units in NAA
and AA were to comply in 2009, 2011, and 2012 (p. 5 1). The 1L regulation will potentially affect
202 RICE engines and 36 turbines and reduce NOx emissions by 5,422 ton/season in 2007 ozone
control season (p. 10). (IEPA 2007) [Full implementation of the IL regulation in 2012, to include
additional units in NAA and AA counties down to the 500 hp size [28 NOx SIP Call units plus
an additional 246 engines], was projected to reduce NOx emissions statewide by 17,082 tpy and
7,206 ton/season, which is 65 percent reduction on an annual basis and 55 percent reduction in
O3 season emissions (pp. 1 1 and 56). Uncontrolled NOx emissions in 2012 were projected to be
21,532 tpy and 9,134 ton/season, for those units included under the full implementation of the
rule (p. 56). (TEPA 2007)]
Other A vuilable Information
Additional RB control technologies and data are available in the OTC 2012.
Additional Diesel control technologies and data are available in OTC 2012.
References
(CARB 2001). Determination of Reasonably Available Control Technology and Best Available
Retrofit Control Technology for Stationary Spark-Ignited Internal Combustion Engines.
California Environmental Protection Agency, Air Resources Board, Stationary Source
Division, Emissions Assessment Branch, Process Evaluation Section. November 2001.
E-16
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(IEPA 2007). Technical Support Document for Controlling NOx Emissions from Stationary
Reciprocating Internal Combustion Engines and Turbines. AQPSTR 07-01. Illinois
Environmental Protection Agency, Air Quality Planning Section, Division of Air
Pollution Control, Bureau of Air. March 19, 2007.
(KSU 2011). Final Report: Cost-Effective Reciprocating Engine Emissions Controls and
Monitoring for E&P Field and Gathering Engines. K. Hohn and S. Nuss-Warren, Kansas
State University. November 2011.
(DE 2012) Background Information, Oil and Gas Sector, Significant Sources ofAY h Emissions.
Delaware Department of Natural Resources and Environmental Quality.
(OTC 2012). Technical Information Oil and Gas Sector, Significant Stationary Sources of NOx
Emissions. Final. October 17, 2012.
(CO DPHE). Reciprocating Internal Combustion Engine (RICE) Source Category, Reasonable
Progress Evaluation for RICE Source Category. Colorado Department of Public Health
and Environment - Air Pollution Control Division.
E-17
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EPA Question 4: What are typical or realistic baseline and controlled NOx emissions
factors (grams/hp-hr) for RICE in the OTC states?
Notes for Question 4
NOx control requirements for several of the Ozone Transport Commission (OTC) states
were provided for Connecticut, New Jersey, New York, and Rhode Island, based on a 1994
STAPPA/ALAPCO document (p. 45). (IEPA 2007) These could potentially be used as
maximum EF for RICE units. NOx control requirements are listed in the following table
NOx Control Requirements for RICE in Some OTC States and Other States
State
Covered
NOx Control Level
Reference
Connecticut
>3 MMBtu/hr (1175 hp)
Liquid-fired. CI: 8 g/bhp-hr(584 ppm)
IEPA 2007
New York
RACT for Major
Facilities of NOx, Severe
O3 NAA >200 hp and
Rest of state >400 hp
¦ Thru March 31. 2005. NG. RICE. LB: 3
g/bhp-hr (220 ppm)
¦ Aflcr April 1. 2005. LB: 1.5 g/bhp-hr (110
ppm)
¦ Thru March 31. 2005. Liquid-fired. CI: 9
g/bhp-hr (657 ppm)
¦ Aflcr April 1. 2005: 2.3 g/bhp-hr (168 ppm)
OTC 2012, DE
2012, IEPA 2007
New York
(RACT)
Major facilities >25 tpy,
NYC and Lower Orange
Co: >200 kW
Rest of stele, major
facilities >100 Ipv: >400
kW
¦ NG: 1.5 g/bhp-hr
¦ Landfill or digester gas: 2.0 g/bhp-hr
New Jersey
¦ NG. LB. >500 hp: 2.5 g/bhp-hr (182 ppm)
¦ Liquid-fired. CI, >500 hp: 8 g/bhp-hr (584
ppm)
IEPA 2007
New Jersey
(RACT)
>148 k\\
Group of 2 or more
engines, each al >37 to
<148 kW. but lolal
combined power >148
kW
¦ Gas. LB: 1.5 g/bhp-hr, or 80% reduction
¦ Gas. RB: 1.5 g/bhp-hr
New Jersey
(RACT)
>37 kW
¦ Commenced on or after March 7, 2007:
0.9 g/bhp-hr
¦ Modified on or after March 7, 2007: 0.9
g/bhp-hr, or 90% reduction
Maryland
NG pipeline engines with
>15% capacity factor
NA
IEPA 2007
Other States and Areas
Illinois
NA
¦ 3 g/bhp-hr (210 ppm)
NA
(continued)
E-18
-------
NOx Control Requirements for RICE in Some OTC States and Other States (continued)
State
Covered
NOx Control Level
Reference
Other States and Areas (cont.)
SJVAPCD Rule 4702
(amended ICE SI and CI
2011 Aug 18) nameplate rating >25 hp
Texas
Texas
Texas
Oil & Gas Handling and
Production Facilities
Oil & Gas Handling and
Production Facilities
Texas
(NAA major
sources)
Texas
(NAA minor
sources)
Texas
Oil & Gas Handling and
Production Facilities
RACT. Major ICI. 03
NAA. Beaumont-Port
Arthur O? NAA Major
sources
Combustion Control at
Minor Sources in O3
NAA, Houston-
Galveston-Brazoria
03 NAA, Dallas Ft.
Worth
2S, LB, NG, <100 hp: 75 ppmvd
LB limited use or Gas compression: 65
ppmvd
LB, all others: 11 ppmvd
2S, SI, LB, >500 hp:
- Mfg before 9/23/1982: 8 g/bhp-hr
- Mfg before 6/18/1992, <825 hp: 8 g/bhp-
hr
- Mfg btwn 9/23/1982 and 6/18/1992,
>825hp: 5 g/bhp-hr
- Mfg btwn 6/18/1992 and 6/1/2010: 2
g/bhp-hr (except 5 g/bhp-hr at reduced
speed and torque 80-100%)
- Mfg after 6/1/2010: 1 g/bhp-hr
4S, SI. LB:
- Mfg before 9/23/1982. >500hp: 5 g/bhp-hr
(except 8 g/bhp-hr at reduced speed and
torque 80-100%)
- Mfg before 6/18/1992. <825 hp: 5 g/bhp-
hr (except 8 g/bhp-hr at reduced speed and
torque 80-100%)
- Mfg btwn 9/23/1982 and 6/18/1992.
X25hp: 5 g/bhp-lir
\ 1 fg btwn 6/18/1992 and 6/1/2010,
500hp: 2 g/bhp-lir (except 5 g/bhp-hr at
reduced speed and torque 80-100%)
- Mfg after 6/1/2010, >500hp: 1 g/bhp-hr
After 1/1/2030, no 4S LB SI engine NOx
emissions shall exceed 2 g/bhp-hr regardless
of manufacture date.
4S SI. LB. <500hp:
Mfg before 7/1/2008: 2 g/bhp-hr
After 1/1/2030: no 4S LB SI engine NOx
emissions shall exceed 2 g/bhp-hr regardless
of manufacture date.
NG, SI, RICE, LB >300 hp: 3 g/bhp-hr
NG, SI, RICE, RB, >300 hp: 2 g/bhp-hr
NG, RICE, >50 hp: 0.5 g/bhp-hr
RB, >50 hp: 0.5 g/hp-hr
LB, >50 hp:
- Installed or moved before June 2007: 0.7
g/hp-hr
- Installed or moved after June 2007: 0.5
g/hp-hr
OTC 2012
O TC 2012
OTC 2012
OTC 2012
OTC 2012, DE
2012
DE 2012, ETCG
2013
EDF 2008;
ETCG 2013
(continued)
E-19
-------
NOx Control Requirements for RICE in Some OTC States and Other States (continued)
State
Covered
NOx Control Level
Reference
Other States and Areas (cont.)
Texas East Texas Combustion
Rule (existing engines
comply by March 1,
2010; new engines
comply at startup.)
Colorado
USEPAPart
60, subpart
JJJJ (NSPS)
(final
2008Janl8)
USEPAPart
60, subpart
JJJJ (NSPS)
(final
2008Janl8)
USEPAPart
60, subpart
JJJJ (NSPS)
(final
2008Janl8)
USEPA Pari
60, subpart
JJJJ (NSPS)
(final
2008Janl8)
Regulation 7, RICE, LB,
NG, New, modified,
relocated
NG, SI, ICE
SI, NG and SI, LB, LPG,
100 to 500 hp
NGandLK.. SI. I.li.
500 to 135u hp
SI. Mi and SI. I.li. I.l>(,
(cxccpi I.li 5iio to 1350
hpi
RB, NG, RICE, 240 to 500 hp: 1 g/hp-hr ETCG 2013
RB, NG, RICE, >500 hp: 0.5 g/hp-hr
RB, Landfill gas, RICE, >500 hp: 0.6 g/hp-hr
After July 1, 2007, >500 hp: 2 g/bhp-hr ()|(' 2u 12: CO
After July 1, 2010, >500 hp: 1 g/bhp-hr I>1*1 If
After January 1, 2008, 100 to 500 hp: 2 g/bhp-
hr
After January 1, 2011, 100 to 500 hp: 1 g/bhp-
hr
Mfg after 7/1/2008. <25 hp. Class I: 11.0 ETGC2013
g/hp-hr of NMHC + NOx combined
Mfg after 7/1/2008. <25 hp. Class I-B: 27.6
g/hp-hr of NMHC + NOx combined
Mfg after 7/1/2008. <25 hp. Class II: 8.4 g/hp-
hr of NMHC + NOx combined
Mfg after 7/1/2008. 25 to 100 hp: 2.8 g/hp-lir
of HC + NOx combined
Mfg after 7/1/2008: 2 g/bhp-hr ETCG 2013
Mfg after 1/1/2011: 1 g/bhp-hr
\ 1 lu after 7/1/2008: 2 g/bhp-hr OTC 2012
MI'u after 7/1/2010: 1 g/bhp-hr
\llu after 7/1/2007: 2 g/bhp-hr ETCG 2013
E-20
-------
NOx Control Requirements for RICE in Local Areas.
State or
Area
Criteria
NOx control level Reference
SCAQMD
Rule 1110.2 Emissions
¦ >500 hp: 0.5 g/bhp-hr (36 ppmvd) OTC 2012
(July 2010)
from Gaseous and Liquid
¦ <500 hp: 0.6 g/bhp-hr (45 ppmvd)
Fueled Engines
¦ After July 1, 2010, >500 hp: 0.15 g/bhp-hr
(11 ppmvd)
¦ After July 1, 2010, <500 hp: 0.6 g/bhp-hr
(45 ppmvd)
¦ After July 1, 2011, All: 0.15 g/bhp-hr (1 1
ppmvd)
For engines with unknown pre-rule emissions, NOx emissions were assumed to be
16.4 g/bhp-hr for 2S and 18.9 g/bhp-hr for 4S. (DE 2012)
A list of Stack test results for engines in PA that are >500 hp are given in Appendix A,
Table 3 of the PA DEP 2013 reference (p. 53). (PA DEP 2013) [Capital] costs for NSCR, RB
ranged from $10 to $12/bhp. (p. 9) NSCR, RB ranged from $ 10 to $ 15/bhp (slightly different
value given here), (p. 16) (MECA 1997)
IC Engine Typical Emissions Levels (MECA 1997)
Engine Type
Lambda (Actual A/F ratio to
Stoichiometric A/F ratio)
Mode
NOx, g/bhp-hr
NG
0.98
Rich
8.3
0.99
Rich
11.0
1.06
Lean
18.0
1.74
Lean
0.7
Diesel
1.6-3.2
Lean
11.6
Dual I'ucl
1.6-1.9
Lean
4.1
For RB, CARB 2001 document has Costs for NSCR w/o AFRC achieving 96%
reduction. Capital costs ranged from $11,000 to $44,000; Annual costs ranged from $8,200 to
$18,000; and cost effectiveness ranged from $2,100/ton to $300/ton NOx reduction (p. V-2 to
V-3). (CARB 2001)
For RB, CARB 2001 document has Costs for Pre-stratified Charge, achieving 80%
reduction. Capital costs ranged from $10,000 to $47,000; Annual costs ranged from $2,700 to
E-21
-------
$11,000; and cost effectiveness ranged from $800/ton to $200/ton NOx reduction (pp. V-2 to V-
3). (CARB 2001)
CARB 2001 document has costs for Ignition Timing Retard (ITR), although the
description of the combustion technology indicates it is less popular on Stationary engines than
mobile source engines (pp. V-2, B-7 to B-8). (CARB 2001)
The EDF 2008 reference provided NOx EF for engines in the Bartlett Shale region. The
document notes that extending the 2009 engine rules in Barnett Shale to counties outside the
DFW NAA would likely result in many engine operators installing NSCR on RB engines. NSCR
costs were cited as follows: $330/ton (IEPA 2007); $92 to $105/ton (EPA 2006); and $ 112 to
$183/ton (northeast Texas 2005 report). Another control technique reviewed in this report
included replacement of compressor engines with electric motors. There are multiple
compressors driven by electric motors throughout Texas (p. 26). Use of electric motors instead of
gas-fired engines eliminates combustion emissions (p. 27). The costs are time and site specific,
based on the cost of electricity, cost of NG, hours of operation per year, number of compressors,
size of compressor, etc. (EDF 2008)
NOx Emission Factors for Engines Identified in DFW 2007 Engine Survey (EDF 2008)
2007 EF
2009 EF
Engine
Type
Engine
Size, hp
NOx, g/hp-hr
Engine Type
Engine Size, hp
NOx, g/hp-hr
RB
<50
13.6
RB
<50
13.6
RB
5o son
13.6
RB
50-500
0.5
RB
5()()
0.9
RB
>500
0.5
LB
5()()
6.2
LB, installed or
moved before June
2007
<500
0.62
LB
5()()
0.9
LB, installed or
moved after June
2007,
<500
0.5
LB, installed or
moved before June
2007
>500
0.7
LB, installed or
moved after June 2007
>500
0.5
E-22
-------
References
(MECA 1997). Emission Control Technology for Stationary Internal Combustion Engines:
Status Report. Manufacturers of Emission Controls Association (MECA). July 1997.
(CARB 2001). Determination of Reasonably Available Control Technology and Best Available
Retrofit Control Technology for Stationary Spark-Ignited Internal Combustion Engines.
California Environmental Protection Agency, Air Resources Board, Stationary Source
Division, Emissions Assessment Branch, Process Evaluation Section. November 2001.
(IEPA 2007). Technical Support Document for Controlling NOx Emissions from Stationary
Reciprocating Internal Combustion Engines and Turbines. AQPSTR 07-01. Illinois
Environmental Protection Agency, Air Quality Planning Section, Division of Air
Pollution Control, Bureau of Air. March 19, 2007.
(EDF 2008). Emissions from Natural Gas Production in the Bar net! Shale Area and
Opportunities for Cost Effective Improvements. Conducted by Department of
Environmental and Civil Engineering, Southern Methodist University, for Environmental
Defense Fund. Peer-Review Draft. September 30, 2008.
(DE 2012) Background Information, Oil and Gas Sector, Significant Sources of NOx Emissions.
Delaware Department of Natural Resources and Environmental Quality.
(OTC 2012). Technical Information Oil and (!as Sector, Significant Stationary Sources of NOx
Emissions. Final. October 17, 2012.
PA DEP 2013. Technical Support Document General Permit GP-5. Pennsylvania Department of
Environmental Protection, Bureau of Air Quality. January 31, 2013.
(ETCG 2013). Gas Compressor Engine Study for Northeast Texas, for East Texas Council of
Governments. Prepared by ENVIRON International Corporation, for East Texas Council
of Governments. June 2013.
(CO DPHE). Reciprocating Interna! (\>m bust ion Engine (RICE) Source Category, Reasonable
Progress Evaluation for RI( E Source (\itegory. Colorado Department of Public Health
and Environment—Air Pollution Control Division.
E-23
-------
EPA Question 5: Using FERC data or other data sources, what is the relationship between
RICE model and age, and emissions (both for baseline and with controls)? In particular,
what is the relationship for RICE built before the imposition of the SI (spark ignition,
natural gas-fired) RICE NSPS in 2007?
Notes for Question 5
The DE 2012 reference stated that many of the installed mainline NG compressors are of
the age (in excess of 40 years old) to have pre-dated modern original equipment manufacturer
(OEM) installed NOx emission controls and otherwise applicable new source performance
standards (NSPS). There is little information on the number of units that may have undergone
NOx modifications as a result of federal or State rules and regulations. The reference cited a
2003 Pipeline Research Council International (PRCI) document that identified 5,686 engines:
71% are LB and 29% are RB (based on dropping the turbine numbers in the table below). The
average age for each unit type is shown in the following table. [These data are repeated in OTC
2012.] [Based on these data, it is estimated that the LB and RB engines are 37 years old on
average (based on dropping the turbine numbers in the table below).] (p. 19) (DE 2012)
2003 Pipeline Research Council International Data (PRC!)
Unit Type U.S Total Units (%) Average Ajjc (as of 2003) Avg hp
2SLB 2.955 (44%) 42 2,113
4SLB 1.059 (16%) 33 1,844
RB 1.672 (25%) 32 589
Turbine 1.016(15%) 24 6,121
The OTC 2<) 12 reference indicated that many of the reciprocating engines driving
mainline NG compressors are in excess of 40 years old, pre-dating any applicable modern OEM
installed NOx emission control and any otherwise applicable NSPS NOx controls (p. 16). (OTC
2012)
The DE 2012 reference discussed a 2005 study conducted for NG field gathering engines
in Eastern Texas; the study was able to determine the age only for a very small portion of the
engines, and the engine age ranged from 2 to 25 years. The output ratings of engines in the study
ranged from 26 to 1478 hp, with the majority rated between 50 and 200 hp (p. 12). (DE 2012)
The DE 2012 reference indicated they reviewed MARAMA's 2007 Point Source
Inventory and 2007 FERC data. The 2007 FERC data are provided as Attachment III to the
E-24
-------
reference. The two sets of data did not match: 2007 MARAMA data indicated 107 compressor
facilities, and 2007 FERC data indicated 150 compressor facilities. The reviewed databases did
not provide any information regarding NOx emission rates (g/bhp-hr, ppmvd). NOx emission
rates were obtained for a small number of prime movers, through operating permits: 2SLB range
from 1 to 13.3 g/bhp-hr; 4SLB range from 0.5 to 6 g/bhp-hr; and 4SRB were 3 g/bhp-hr. The
data are not sufficient to estimate actual NOx emission rates and NOx reductions. Note that the
FERC data addresses large entities, and smaller companies may not be required to report data to
FERC. The 2007 OTC compressors from FERC are provided in the following table. (DE 2012)
State
No. Compressors
Total Rated hp
CT
10
35,300
MA
15
25,702
MD
17
52.250
ME
4
33.244
NJ
36
129.130
NY
120
359.487
PA
4(.~
1.131,164
RI
o
29,170
VA (OTR area only)
22
49,390
The KSU 2011 reference discussed control technologies testing performed in the
laboratory on a 1966 Ajax DP-1 15 (Lean Burn) that has none of the low emissions controls that
are currently OEM standard. The published emission factor (EF) for this engine is 4.4 g/bhp-hr,
and the emissions from actual testing were 4.69±0.18 g/bhp-hr (the Lab testing results are
discussed on pp. 19-27). There is additional discussion of Field testing conducted on multiple LB
engines with NOx emission control techniques, including (1) Increased air flow, and
precombustion chamber (PCC) screw-in type, (2) PCC screw-in type and Upgraded
turbocharger, (3) Integral PCC and high-output turbocharger (pp. 27-29). Discussion of Field
testing conducted on two RB engines with NOx emission control techniques (p. 29). Integrated
nonselective catalytic reduction (NSCR) with modeling and enhanced controller is also
discussed. (KSU 2011).
References
(KSU 2011). Final Report: Cost-Effective Reciprocating Engine Emissions Controls and
Monitoring for E&P Field and Gathering Engines. K. Hohn and S. Nuss-Warren, Kansas
State University. November 2011.
E-25
-------
(DE 2012) Background Information, Oil and Gas Sector, Significant Sources ofNOx Emissions.
Delaware Department of Natural Resources and Environmental Quality.
(OTC 2012). Technical Information Oil and Gas Sector, Significant Stationary Sources ofNOx
Emissions. Final. October 17, 2012.
E-26
-------
EPA Question 6: What is the variability in NOx emissions from RICE within each State,
both for baseline and with controls?
Notes for Question 6
No data were found, r Likely a review of RICE SCCs in the NEI across states would be a
useful exercise to see the relative levels of baseline and/or controlled NOx emissions, however
this exercise was not part of this task.1
E-27
-------
From:
Subject:
Date:
To:
US EPA OAQPS
SRA International, Inc.
Review of CoST Model Emission Reduction Estimates
September 30, 2014
EPA uses the Control Strategy Tool (CoST) to estimate the emission reductions and engineering costs
associated with control strategies applied to point, area, and mobile sources of air pollutant emissions to
support the analyses of air pollution policies and regulations. CoST accomplishes ill is by matching
control measures to emission sources using algorithms such as "maximum emissions reduction", "least
cost", and "apply measures in series". There was a concern that the baseline m\ eniorv used by CoST did
not completely account for emission control requirements already in place, and lhal llic emission
reductions were perhaps overestimated.
SRA reviewed the CoST results and made recommeiidalions lor chaiiL:iny llie ( oST control measure
assignment and the estimated reductions for o\ides ol'nilrogen (\(K) The recommendations were based
on a review of source permits, state regulations, enforcement actions. and oilier available information.
The analysis was conducted for a 24-state area in the eastern two-lhirds of the U.S. The focus was on
stationary point sources other than electric generating units (non-EGUs). The purpose of this memo is to
document the data used and assumptions made in recommending changes to the CoST results, and to
summarize the differences Ivlxxeen llie CoST results and the recommended changes.
The findings in this memo are Ixised on rex ie\x of CoST results for a 2018 emissions inventory projected
from the 2011 National Lmission Inxenlorx (\LI). This work was in support of EPA's current Transport
Rule efforls lor implementing llie 75 pph ozone standard. If EPA considers establishing a tighter ozone
standard in llie lulu re. il is likelx dial a more dislant future year will be used and that some of the
conclusions reached in lliis memo could change.
CoST DATA PROVIDED BY EPA
EPA provided SRA xvith the outputs from a CoST scenario that identified sources for which NOx controls
were available at a cost-effectiveness level of less than $10,000 per ton. The CoST outputs included
source identifiers, control technology, baseline emissions and estimates of NOx emission reductions. The
CoST results were divided into two groups. The first group included sources where CoST estimated NOx
emission reductions of more than 100 tons per year. There were 547 sources in this group where CoST
controls were initially applied. The second group included sources where CoST estimated emission
reductions for sources whose 2018 projected emissions were greater than 25 tons/year, excluding those
1
-------
with reductions greater than 100 tons/year. There were 1,280 sources in this group where CoST controls
were initially applied.
Another contractor reviewed the CoST results for additional source categories, and their
recommendations were merged with SRA's recommendations in the summary tables and maps that
follow. The data used, assumptions made and results for IC engines are documented elsewhere1.
REVIEW OF CoST RESULTS FOR THE GREATER THAN 100 TI>Y GKOl l»
Table 1 summarizes the source categories included in our analysis, the CoST recommendation for NOx
control, and the recommendation for changing the CoST control measure assignment and associated
emission reduction estimates. Following Table 1. there is a discussion for each source group to provide
more detail on the rationale for the recommended changes for each source group. Attachments 1 to 4 are
tabular comparisons of the initial CoST emission reduction estimates and the recommended changes. All
Attachments present the results in terms of tons per ozone season, simply estimated by assuming that
ozone season emissions were equal to 5/12 of the annual emissions. Maps 1A and 1B graphically show
the location of sources and the magnitude of the recommended emission reductions.
Table 1 - CoST Controls and Recommended Changes for
Greater than 100 TPY Sources
Source Group
CoST Control
Recommendation
Summary of Recommended Changes to
CoST Controls and Reductions
Ammonia - NG-fired
Reformers
Selective Catalytic
Reduction
Agreed with CoST recommendation of SCR
except for those sources where a permit or
state regulation already required the source
to be controlled.
By-Product Coke Mfg;
Oven Underfiring
Selective Non-Catalytic
Reduction
Review of a source-specific NOx RACT
permit indicated that NOx controls were
technically or economically infeasible.
Cement Kilns
Biosolid Injection
Technology
Disagreed with CoST recommendation
based on concerns about biosolids
availability and information from EPA's ISIS
(Industrial Sector Integrated Solutions)
Model; recommended SNCR for all sources,
except those that already have SNCR due to
NOx SIP Call, NSR requirement, Consent
Decree, or other state regulation.
1 Update of NOx Control Measure Data in the CoST Control Measures Database for Four Industrial
Source Categories: Ammonia Reformers, NonEGU Combustion Turbines,Glass Manufacturing, and Lean
Burn Reciprocating Internal Combustion Engines," prepared by Research Triangle Institute, July 2014.
2
-------
Source Group
CoST Control
Recommendation
Summary of Recommended Changes to
CoST Controls and Reductions
Cement Manufacturing
- Dry
Selective Non-Catalytic
Reduction
Agreed with CoST recommendation except
when already controlled due to NOx SIP Call,
NSR requirement, Consent Decree, or other
state regulation.
Cement Manufacturing
-Wet
Mid-kiln Firing
Disagreed with CoST recommendation
based on information from EPA's ISIS Model;
recommended SNCR for all sources, except
those that already controlled
Coal Cleaning -
Thermal Dryer
Low NOx Burner
Agreed with CoST recommendation
Comm/lnst Incinerators
Selective Non-Catalytic
Reduction
Both sources are already controlled with
SNCR
External Combustion
Boilers, ElecGen, Solid
Waste
Selective Non-Catalytic
Reduction
All 6 sources are already controlled with
SNCR
Fluid Catalytic Cracking
Units
Low NOx Burner and Flue
Gas Recirculation
Nearly all FCCUs are already controlled due
to the OECA global refinery consent decrees.
There is one small refinery in West Texas
that does not appear to be covered by a
consent decree, so the CoST
recommendation was accepted.
Glass Manufacturing -
Container. Flat.
Pressed
OXY-Firing
Disagreed with CoST recommendation.
OXY-firing is not generally required under
recent OECA consent decrees. More
common control is oxygen-enriched air
staging (OEAS). OXY-firing can only be
implemented at the time of furnace rebuild,
which is generally done every 10-15 years.
Changed recommended control to OEAS
with a 50% NOx reduction instead of OXY-
firing at 85% NOx reduction, except for
sources that already had NOx controls in
place due to a consent decree, NSR
requirement, or state regulation. Assumed
that a furnace with a NOx emission limit of
less than 4 lbs/ton of glass pulled was
already reasonably controlled.
ICI Boilers -
Coal/Cyclone
Selective Catalytic
Reduction
Agreed with CoST recommendation of SCR
except for those sources where a permit or
state regulation already required the source
to be controlled. LADCO/OTC also
recommends SCR
ICI Boilers -
Coal/Stoker
Selective Catalytic
Reduction
Disagreed with CoST recommendation of
SCR. CoST has $2200/ton, which appears
3
-------
Source Group
CoST Control
Recommendation
Summary of Recommended Changes to
CoST Controls and Reductions
very low for ICI boilers. Used LADCO/OTC
recommendation of SNCR for Coal-Stokers
with a 50% reduction, except for those
sources where a permit or state regulation
already required the source to be controlled.
ICI Boilers - Coal/Wall
Low NOx Burner and
Selective Catalytic
Reduction
Agreed with CoST recommendation of SCR
except for those sources where a permit or
state regulation already required the source
to be controlled. LADCO/OTC also
recommends LNB/SCR
ICI Boilers - Gas,
Natural Gas, Process
Gas
Selective Catalytic
Reduction
Disagreed with CoST recommendation of
SCR. CoST has $3456/ton, which appears
very low for ICI boilers. Used LADCO/OTC
recommendation of Low NOx Burners plus
Flue Gas Recirculation for Gas-fire ICI
boilers with a 60% reduction, except for
those sources where a permit or state
regulation already required the source to be
controlled
Industrial Incinerators
Selective Non-Catalytic
Reduction
Agreed with CoST recommendation of SNCR
except for those sources where a permit or
state regulation already required the source
to be controlled.
Iron & Steel Mills -
Reheating
Low NOx Burner and Flue
Gas Recirculation
Agreed with CoST recommendation except
for those sources where a permit or state
regulation already required the source to be
controlled.
Municipal Waste
Combustors
Selective Non-Catalytic
Reduction
Agreed with CoST recommendation of SNCR
except for those sources where a permit or
state regulation already required the source
to be controlled.
Nitric Acid
Manufacturing
Nonselective Catalytic
Reduction
Agreed with CoST recommendation of NSCR
except for those sources where a permit or
state regulation already required the source
to be controlled.
Petroleum Refinery
Process Heaters
SCR-95%
Nearly all refineries are already controlled
due to the OECA global refinery consent
decrees, which generally require 40-60%
reductions across all boilers/heaters that
each company operates. Not possible at
present to identify the individual
boilers/heaters that actually have been
controlled or are scheduled to be controlled
due to confidentiality agreements between
EPA and companies.
4
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Source Group
CoST Control
Recommendation
Summary of Recommended Changes to
CoST Controls and Reductions
Taconite Ore
Processing - Induration
- Coal or Gas
Selective Catalytic
Reduction
Disagree with CoST recommendation of
SCR. EPA Region V considers SCR/SNCR
to be infeasible. Used Low NOx Burners at
70% reduction instead as reasonable control,
except for those sources where a permit or
state regulation already required the source
to be controlled. .
Utility Boilers* -
Coal/Wall
Selective Catalytic
Reduction
Agreed with CoST recommendation of SCR
except for those sources where a permit or
state regulation already required the source
to be controlled.
Utility Boilers* - Oil/Gas
Selective Catalytic
Reduction
Agreed with CoST recommendation of SCR
except for those sources where a permit or
state regulation already required the source
to be controlled.
The utility boilers included in the context of this report are non-IPM utility boilers. In the NEI, these units
have an SCC of 1-01—xxx-xx (the SCC series generally used for electric generating units. However, the
sources included in this analysis do not sell electricity to the grid.
Ammonia - NG-fired Reformers
There are 15 sources in this category The CoST conlrol kvhnologv was selective catalytic reduction
(SCR) with a 90% reduction in NOx emissions. We determined that four of these sources were already
controlled by either SCR or ultra-NO\ burners and recommended no further control/reductions. For all
other sources, we agreed with the CoST control and emission reduction estimate.
By-Product Coke Mfg; Oven Underfiring
There are 14 sources in llus calegor\ The CoST control technology was selective non-catalytic reduction
(SNCR) \\ iill a Mi",, ivduclion in \(K emissions. We reviewed a detailed RACT analysis for a facility in
Pennsyh uniu iluil delernuned llml no controls were feasible. For all sources in this category, we
recommended that no controls were feasible and thus no reductions were appropriate.
Cement Preheater/Precalciner Kilns
There are 36 sources in this category. The CoST control technology was biosolid injection technology
with a 23% reduction in NOx emissions. We reviewed permits and consent decrees to identify those kilns
that are already controlled. Several kilns are already controlled based on NOx SIP Call requirements that
typically required low NOx burners, mid-kiln firing, or an approved alternative that resulted in a 30%
reduction. Other kilns already had SNCR installed due to a consent decree, new source review
requirement, or other state-level requirement.
5
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EPA expressed a concern whether there was sufficient biosolids availability for use by the uncontrolled
kilns. Also, EPA has done considerable research on cement kiln NOx controls as part of its Industrial
Sector Integrated Solutions (ISIS) project. EPA uses the ISIS-cement model help analyze policy options
for various rulemakings. Based on the ISIS work, we recommended that low-NOx burners and SNCR as
the appropriate control for all types of kilns.
For uncontrolled kilns, we applied a 65% reduction in NOx emissions. For kilns already controlled with
low-NOx burners or mid-kiln firing, we applied a 35% incremental reduction to account for the additional
reductions from SNCR. For kilns already controlled with SNCR, we applied no addilional emission
reductions.
Cement Manufacturing - Dry Process
There are 20 sources in this category. The CoST control technology was SNCR w illi a 5<)"„ reduction in
NOx emissions. We reviewed permits and consent decrees to identity those kilns that are already
controlled. Several kilns are already controlled based on NOx SIP Call requirements that typically
required low NOx burners, mid-kiln firing, or an approved alternative that resulted in a 30% reduction.
Other kilns already had SNCR installed due to a consent decree, new source review requirement, or other
state-level requirement.
As discussed earlier, we recommended that lo\\-M)\ burners and SNCR as the appropriate control for all
types of kilns based on the ISIS work. For unconliolled kilns, we applied a 65% reduction in NOx
emissions. For kilns already controlled with low-\()\ burners or mid-kiln firing, we applied a 35%
incremental reduction to account for the additional reductions from SNCR. For kilns already controlled
with SNCR, we applied no additional emission reductions.
Cement Manufacturing - Wet Process
There arc seven sources in this caleijoiy The CoST control technology was mid-kiln firing with a 30%
reduction in MK emissions \\ e deleinuned lhat two of these kilns were installing a pilot SCR system as
partofaconsenl decree One kiln recently went through NSR review and has state-of-the-art control.
Another kiln is required in install SNCR as part of a consent decree. No additional reductions were
applied for these kilns. For the remaining kilns, we applied low-NOx burners and SNCR as described in
the previous sections
Coal Cleaning - Thermal Dryer
There was one source in this category. The CoST control technology was a low-NOx burner with a 50%
reduction in NOx emissions. We could not find any information on this source and accepted the CoST
controls.
6
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Comm/Inst Incinerators
There are two sources in this category. The CoST control technology was SNCR with a 45% reduction in
NOx emissions. Both of these sources are already controlled by SNCR and we applied no additional
emission reductions.
External Combustion Boilers, Elec Gen, Solid Waste
There are six sources in this category. The CoST control technology was SNCR with a 50% reduction in
NOx emissions. All six of these sources are already controlled by SNCR and we applied no additional
emission reductions.
Fluid Catalytic Cracking Units
There are six sources in this category. The CoST control technology was lou-MK burners and flue gas
recirculation with a 55% reduction in NOx emissions. Nearly all sources arc a I read \ con i rolled or
required to install controls as a result of the ERA's global relineiy consent decrees There is one small
refinery in West Texas that does not appear to be covered b\ a consent decree, so llie CoST
recommendation was accepted.
Glass Manufacturing - Container, Flat, Pressed
There are 65 sources in this category. The CoST control technology was o\\ -11 ring with an 85%
reduction in NOx emissions. There were several concerns about using oxv-firing for this analysis. First,
there is a concern about the timing of installing oxv-firing technology. Oxv-firing is typically installed at
the time of a furnace rebuild, which is typically done every 10 to 15 years. Second, oxy-firing is not
generally required under recent EPA consent decrees. More common control is oxygen-enriched air
staging (OEAS). We recommended that OEAS with a 50% NOx reduction instead of OXY-firing at 85%
NOx reduction, except for sources that already had NOx controls in place due to a consent decree, NSR
requirement, or state regulation. We assumed that a furnace w ith a NOx emission limit of less than 4
lbs/ton ol'glass pulled was already reasonably controlled.
ICI Boilers - Coal/C Vclone
There are cighl sources in ill is category. The CoST control technology was SCR with an 80% reduction in
NOx emissions. We reviewed the Evaluation of Control Options for Industrial, Commercial and
Institutional (ICI) lloilers Technical Support Document (TSD), March, 2011 prepared by the Lake
Michigan Air Directors Consortium (LADCO) and the Ozone Transport Commission (OTC).
LADCO/OTC also recommended SCR for coal-cyclone boilers. Since the LADCO/OTC recommendation
was consistent with the CoST control, we agreed with the CoST control technology for five sources
which we determined were uncontrolled. Two sources were determined to be already controlled. One
source appears to have shut down their coal-fired boilers. No reductions were applied for these three
sources since they are already controlled.
7
-------
ICI Boilers - Coal/Stoker
There are 45 sources in this category. The CoST control technology was SCR with an 80% reduction in
NOx emissions. The LADCO/OTC recommendation was for combustion tuning and SNCR. We agreed
with the LADCO/OTC recommendation and assumed a 50% control efficiency. We determined that most
of these sources are currently uncontrolled. Two coal-fired boilers are scheduled to be replaced with gas-
fired boilers. Two other boilers recently installed SNCR.
ICI Boilers - Coal/Wall
There are 54 sources in this category. The CoST control technology was low -\( )\ burners and SCR with
a 91% reduction in NOx emissions. The LADCO/OTC recommendation was also lor low -\()\ burners
and SCR. Since the LADCO/OTC recommendation was consistent with llie ( oST control, we agreed
with the CoST control technology and emission reductions.
ICI Boilers - Gas, Natural Gas, Process Gas
There are 130 sources in this category. The CoST control technology was SCR with an 80% reduction in
NOx emissions. The LADCO/OTC recommendation was for low-NOx burners, flue gas recirculation, or
low-NOx burners combined with flue gas recirculation. We agreed with the LADCO/OTC
recommendation of low-NOx burners combined with flue gas recirculation and assumed a 60% control
efficiency.
Several of these sources arc located in the O'l'R or ozone nonulLiinment areas, and as a result already have
aRACT control requirement or emission limitation that is consistent with the LADCO/OTC
recommendations. A few of ihese sources are located at petroleum refineries and were assumed to be
already controlled due to EPA's ielinei\ enforcement initiative.
Municipal Waste Combustors
There arc 55 sources in this calegoiy The ( oST control technology was SNCR with a 45% reduction in
NOx emissions. We determined that 35 of these sources are already controlled with SNCR and no
additional reductions were applied. For the remaining uncontrolled sources, we agreed with the CoST
controls and emission reductions.
Nitric Acid Manufacturing
There are seven sources in this category. The CoST control technology was non-selective catalytic
reduction (NSCR) with a 98% reduction in NOx emissions. All but one of these sources is already
controlled by NSCR or SCR.
Petroleum Refinery Process Heaters
There are 28 sources in this category. The CoST control technology was SCR with a 95% reduction in
NOx emissions. All of the sources in this category are covered sources under EPA's global refinery
enforcement initiative. The settlements generally require 40-60% reductions across all boilers/heaters that
8
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each company operates. Companies have submitted NOx compliance plans to OECA that identify the
specific sources that have been controlled or are planned to be controlled, along with the technology used.
But it is not possible at present to identify the individual boilers/heaters that actually have been controlled
or are scheduled to be controlled due to confidentiality agreements between EPA and companies. No
additional reductions were included for this category.
Taconite Ore Processing - Induration - Coal or Gas
There are 10 sources in this category. The CoST control technology was SCR with a 90% reduction in
NOx emissions. All of the sources in this category are already subject to I icsl Available Retrofit
Technology (BART) requirements under the Regional Haze program. EPA Region Y determined that
BART is low-NOx burners and agreed that SCR controls are infeasible for indurating furnaces. No
additional reductions were included for this category.
Utility Boilers - Coal/Wall, Oil, Gas
There are 11 sources in this category. The CoST control technology was SCR w ilh a 80 to 90% reduction
in NOx emissions depending on fuel type. All of the sources in llus category appear to be uncontrolled
and we agreed with the CoST control and emission reduction estimate
REVIEW OF CoST RESULTS FOR THE 25 TO 100 TPY GROl P
Due to the large number of sources in llns group, we were not able to review individual permits to
determine whether the individual source was already controlled. Instead, our recommendations were
based on of state regulations, enforcement actions, engineering judgment, and other available information.
We generally assumed that sources located in areas w ith stringent NOx rules are already well controlled
and we assumed that no additional reductions were likely from these sources. This assumption was
generally applied in New Jersey. New York and sources located in the Houston nonattainment area.
Given more 11me. w e would 11ke to have also applied this assumption in other areas with stringent existing
regulations, such as Chicago. Milwaukee, and Baton Rouge. In any future analysis, it would be useful to
examine the stringency of rules that apply strictly to nonattainment areas.
Table 2 summarizes the source categories included in our analysis, the CoST recommendation for NOx
control, and the recommendation for changing the CoST control measure assignment and associated
emission reduction estimates. Following Table 2, there is a discussion for each source group to provide
more detail on the rationale for the recommended changes for each source group. Attachments 5 to 8 are
tabular comparisons of the initial CoST emission reduction estimates and the recommended changes. All
Attachments present the results in terms of tons per ozone season, simply estimated by assuming that
9
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ozone season emissions were equal to 5/12 of the annual emissions. Maps 3A and 3B graphically show
the location of sources and the magnitude of the recommended emission reductions.
Table 2 - CoST Controls and Recommended Changes for
25 to 100 TPY Sources
Source Group
CoST Control
Recommendation
Summary of Recommended Changes to
CoST Controls and Reductions
Ammonia - NG-fired
Reformers
Selective Catalytic
Reduction
Agreed with CoST recommendation of SCR
except for those sources where a permit or
state regulation already required the source to
be controlled.
Cement Kilns
Biosolid Injection
Technology
Because of low emissions, assume that the
kiln is already controlled or have very low
usage which would result in a unreasonably
high cost-effectiveness
Cement Manufacturing
-Wet
Mid-kiln Firing
Because of low emissions, assume that the
kiln is already controlled or have very low
usage which would result in a unreasonably
high cost-effectiveness
Ceramic Clay Mfg;
Drying
Low NOx Burner
Questions about technical feasibility for these
category, assume zero reductions
Coal Cleaning -
Thermal Dryer
Low NOx Burner
Agree with CoST recommendation
Comm/lnst Incinerators
Selective Non-Catalytic
Reduction
Agree with CoST recommendation
External Combustion
Boilers, Elec Gen,
Sub/Bit Coal
Selective Non-Catalytic
Reduction
Agree with CoST recommendation, although
questions as to whether the source is already
controlled or very low usage which would
result in a unreasonably high cost-
effectiveness
Fluid Catalytic Cracking
Units
Low NOx Burner and Flue
Gas Recirculation
Nearly all FCCUs are already controlled due
to the OECA global refinery consent decrees.
Gas Turbines
Low NOx Burners
Agreed with CoST recommendation except for
those sources where a state regulation
already required the source to be controlled.
Glass Manufacturing -
Container, Flat, Pressed
OXY-Firing
Because of low emissions, assume that the
furnace is already controlled or have very low
usage which would result in a unreasonably
high cost-effectiveness
ICI Boilers -
Coal/Stoker
Selective Catalytic
Reduction
Disagreed with CoST recommendation of
SCR. CoST has $2200/ton, which appears
very low for ICI boilers. Used LADCO/OTC
recommendation of SNCR for Coal-Stokers
with a 50% reduction, except for those
sources where a state regulation already
required the source to be controlled.
ICI Boilers - Coal/Wall
Low NOx Burner and
Selective Catalytic
Reduction
Agreed with CoST recommendation of SCR
except for those sources where a state
regulation already required the source to be
10
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Source Group
CoST Control
Recommendation
Summary of Recommended Changes to
CoST Controls and Reductions
controlled. LADCO/OTC also recommends
LNB/SCR
ICI Boilers - Distillate
Oil or Process Gas
Selective Catalytic
Reduction
Because of low emissions, assume that the
boiler is already controlled or have very low
usage which would result in a unreasonably
high cost-effectiveness
ICI Boilers - Natural
Gas
Low NOx Burner and
Selective Catalytic
Reduction
Disagreed with CoST recommendation of
SCR. Used LADCO/OTC recommendation of
Low NOx Burners plus Flue Gas Recirculation
for Gas-fire ICI boilers with a 60% reduction,
except for those sources where a permit or
state regulation already required the source to
be controlled
ICI Boilers - Residual
Oil
Low NOx Burner and
Selective Non-Catalytic
Reduction
Agreed with CoST recommendation of SCR
except for those sources where a state
regulation already required the source to be
controlled.
Industrial Incinerators
Selective Non-Catalytic
Reduction
Agreed with CoST recommendation of SNCR
except for those sources where a state
regulation already required the source to be
controlled.
Iron & Steel Mills -
Reheating
Low NOx Burner and Flue
Gas Recirculation
Agreed with CoST recommendation except for
those sources where a state regulation
already required the source to be controlled.
Municipal Waste
Combustors
Selective Non-Catalytic
Reduction
Agreed with CoST recommendation of SNCR
except for those sources where a state
regulation already required the source to be
controlled.
Nitric Acid
Manufacturing
Nonselective Catalytic
Reduction
Agreed with CoST recommendation of NSCR
except for those sources where a state
regulation already required the source to be
controlled.
Petroleum Refinery
Process Heaters
SCR or Ultra-Low NOx
Burner
Nearly all refineries are already controlled due
to the OECA global refinery consent decrees,
which generally require 40-60% reductions
across all boilers/heaters that each company
operates. Not possible at present to identify
the individual boilers/heaters that actually
have been controlled or are scheduled to be
control due to confidentiality agreements
between EPA and companies.
Utility Boilers -
Coal/Wall
Selective Catalytic
Reduction
Agreed with CoST recommendation of SCR
except for those sources where a state
regulation already required the source to be
controlled
Utility Boilers - Oil/Gas
Selective Catalytic
Reduction
Because of low emissions, assume
unreasonably high cost-effectiveness for
SCR; use LNB/FGR as reasonable control.
11
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Ammonia - NG-fired Reformers
There are seven sources in this category. The CoST control technology was SCR with a 90% reduction in
NOx emissions. For all other sources, we agreed with the CoST control and emission reduction estimate.
Cement Kilns
There are six sources in this category. The CoST control technology was either biosolid injection
technology with a 23% reduction in NOx emissions or mid-kiln firing with a 30% reduction. Because of
the low baseline emissions for these kilns, we assumed that the kilns were already controlled or have low
usage which would result in a very high cost-effectiveness. We determined that no reductions be applied
for these sources.
Coal Cleaning - Thermal Dryer
There are 10 sources in this category. The CoST control technology was a lou-\(K burner \\ilha50%
reduction in NOx emissions. We agreed with the CoST control and emission reduction eslimate.
Commercial/Institutional Incinerators
There are four sources in this category. The CoST control technology was S\CR with a 45% reduction in
NOx emissions. We agreed with the CoST control and emission reduction esl imate.
External Combustion Boilers, Electric Generation, Coal
There are 14 sources in this category. The CoST control technology was SJNCR with a 40% reduction in
NOx emissions. It appears that the sources in this category are low usage spreader stokers. Although there
may be a concern about the cost-cffcctivcncss for these sources, we agreed with the CoST control and
emission reduction estimate.
Fluid Catalytic Cracking Units
There are 21 sources in this category. The CoST control technology was low-NOx burners and flue gas
recirculation with a 55% reduction in NOx emissions. All sources in this category are assumed subject to
existing control i'ci|uii'cmenls resulting from the OECA global refinery enforcement initiative.
Additional l\. eight of the sources are located in the Houston nonattainment area and are likely subject to
stringent controls I-'or these reasons, we assumed no further control or emission reductions for the
FCCUs.
Gas Turbines
There are 438 sources in this category. The CoST control technology was for low-NOx burners with a
68% reduction in NOx emissions. We agreed with the CoST control and emission reduction estimate,
except for those sources located in the OTR and Houston ozone nonattainment area, where we assumed
that these sources already had RACT controls.
Glass Manufacturing - Container, Flat, Pressed
12
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There are eight sources in this category. The CoST control technology was SCR with a 90% reduction in
NOx emissions. Because of the low baseline emissions for these furnaces, we assumed that the furnaces
were already controlled and determined that no reductions be applied for these sources.
ICI Boilers - Coal/Stoker
There are 133 sources in this category. The CoST control technology was SCR with a 90% reduction in
NOx emissions. The LADCO/OTC recommendation was for combustion tuning and SNCR. We agreed
with the LADCO/OTC recommendation and assumed a 50% control efficiency.
ICI Boilers - Coal/Wall
There are 11 sources in this category. The CoST control technology was SCR w illi a 90% reduction in
NOx emissions. The CoST control technology was low-NOx burners and S('R w ilh a 91 % reduction in
NOx emissions. The LADCO/OTC recommendation was also for low-NOx burners and SCR. Since the
LADCO/OTC recommendation was consistent w illi I lie ( oST control. we agreed wi ill I lie ( oST control
technology and emission reductions.
ICI Boilers - Natural Gas
There are 376 sources in this category. The CoST coin ml technology was low-NOx burners and SCR
with a 91% reduction in NOx emissions. The l..\l)( () OK recommendation was for low-NOx burners,
flue gas recirculation, or low-NOx burners combined w ilh Hue gas recirculation. We agreed with the
LADCO/OTC recommendation of low-NOx burners combined w ith flue gas recirculation and assumed a
50% control efficiency, except for those sources located in the OTR and Houston ozone nonattainment
area, where we assumed thai lliese sources already had RACT controls.
ICI Boilers - Process Gas
There are 57 sources in this category. The CoST control technology was SCR with a 90% reduction in
NOx emissions Most of these sources are located at petroleum refineries and are assumed subject to
existing control requirements resulting from the OECA global refinery enforcement initiative, or are
located in llie I louslon nonallainment area and arc likely subject to stringent controls. For these reasons,
we assumed no I'urther control or emission reductions.
ICI Boilers - Residual Oil
There are 28 sources in this category. The CoST control technology was low-NOx burner and SNCR with
a 69.5% reduction in NOx emissions. We agreed with the CoST control and emission reduction estimate,
except for those sources located in the OTR and Houston ozone nonattainment area, where we assumed
that these sources already had RACT controls.
Industrial Incinerators
There are 21 sources in this category. The CoST control technology was SNCR with a 45% reduction in
NOx emissions. We agreed with the CoST control and emission reduction estimate, except for those
13
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sources located in the OTR and Houston ozone nonattainment area, where we assumed that these sources
already had RACT controls.
Iron & Steel Mills - Reheating
There are 32 sources in this category. The CoST control technology was low-NOx burners and flue gas
recirculation with a 77% reduction in NOx emissions. We agreed with the CoST control and emission
reduction estimate.
Municipal Waste Combustors
There are 25 sources in this category. The CoST control technology was SCR w ilh a 90% reduction in
NOx emissions. RTI identified the sources are already controlled and no additional reductions were
applied for these sources. For the remaining sources, we agreed with the CoST controls and emission
reductions.
Nitric Acid Manufacturing
There are 14 sources in this category. The CoST control technology was \S( R with a 98% reduction in
NOx emissions. We agreed with the CoST control and emission reduction estimate.
Petroleum Refinery Process Heaters
There are 30 sources in this category. The CoST control technology was SCR with a 90-98% reduction or
ultra-low NOx burners with a 30-50% reductions in NOx emissions Most of these sources are located at
petroleum refineries and arc assumed subject to existing control requirements resulting from the OECA
global refinery enforcement initiative, or are located in the Houston nonattainment area and are likely
subject to stringent controls. I-'or these reasons, we assumed no further control or emission reductions.
Utility Boilers - Coal/Wall
There arc three sources in this category. The CoST control technology was SCR with a 90% reduction in
NOx emissions. We agreed with the CoST control and emission reduction estimate.
Utility Boilers - ()il/(ias
There arc 27 sources in this category. The CoST control technology was SCR with a 80% reduction in
NOx emissions The l..\l)( () OTC recommendation was for low-NOx burners or flue gas recirculation.
We agreed with the LADCO/OTC recommendation of low-NOx burners combined with flue gas
recirculation and assumed a 60% control efficiency.
14
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Attachment 1 - NOx Emission Reductions by State for Sources in the >100 Ton per Year Reduction Group
Recommended
NOx emissions
NOx emissions
Size of correction
reduced from
reduced from
in NOx emission
controls in CoST
controls in CoST
reductions
Number of
(tons/03 season)
(tons/03 season)
(tons/03 season)
State
Sources
(A)
(B)
(A-B)
Alabama
24
2.855
2.287
568
Arkansas
6
455
293
162
Delaware
2
206
0
206
Florida
20
2.158
1.370
788
Illinois
21
2.659
1.472
1,187
Indiana
41
5.405
4.510
896
Iowa
10
1.226
999
227
Kansas
7
735
452
283
Kentucky
11
915
838
77
Louisiana
57
7.623
3.622
4,000
Maryland
10
1.933
355
1,578
Michigan
27
2.758
1,768
990
Mississippi
7
1.054
516
538
Missouri
15
1.698
1,562
136
New Jersey
15
417
0
417
New York
30
3.091
281
2,810
Ohio
37
4.098
2,039
2,058
Oklahoma
20
2.949
1,864
1,086
Pennsylvania
52
5.637
2,215
3,422
Tennessee
13
4,741
1,987
2,755
Texas
65
8,860
6,383
2,477
Virginia
28
3,337
3,033
303
West Virginia
9
1,180
793
387
Wisconsin
20
4,092
3,416
676
547
70,082
42,054
28,028
15
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Attachment 2 - NOx Emission Reductions by Source Group for Sources in the >100 Ton per Year Reduction Group
Source Group
Ammonia - NG-Fired Reformers
By-Product Coke Mfg; Oven Underfiring
Cement Kilns
Cement Manufacturing - Dry
Cement Manufacturing - Wet
Coal Cleaning-Thrml Dryer; Fluidized Bed
Comm./lnst. Incinerators
External Combustion Boilers, Solid Waste
Fluid Cat Cracking Units; Cracking Unit
Fuel Fired Equip; Process Htrs; Pro Gas
Glass Manufacturing - Container
Glass Manufacturing - Flat
Glass Manufacturing - Pressed
ICI Boilers - Coal/Cyclone
ICI Boilers - Coal/FBC
ICI Boilers - Coal/Stoker
ICI Boilers - Coal/Wall
ICI Boilers - Gas
ICI Boilers - Natural Gas
ICI Boilers - Process Gas
ICI Boilers - Residual Oil
Indust. Incinerators
In-Proc;Process Gas;Coke Oven/Blast Furn
Recommended
Number of
Sources
15
NOx emissions
reduced from
controls in CoST
(tons/03 season)
(A)
2.427
NOx emissions
reduced from
controls in CoST
(tons/03 season)
(B)
1,551
Size of correction
in NOx emission
reductions
(tons/03 season)
(A-B)
875
14
1.199
0
1,199
36
3.932
6,586
-2,654
20
3.672
2,234
1,438
7
1.294
1,120
174
1
50
50
0
2
137
0
137
6
472
0
472
6
607
52
556
2
143
143
0
34
2,759
678
2,081
23
10,241
6,024
4,217
8
684
402
282
8
2,987
1,840
1,147
3
233
180
53
45
4,688
2,938
1,750
54
12,041
7,996
4,045
10
1,266
910
356
84
7,578
3,452
4,126
36
3,868
1,229
2,639
2
199
82
117
9
586
124
461
3
299
0
299
16
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Number of
Source Group Sources
In-Process; Bituminous Coal; Cement Kiln 2
Iron & Steel - In-Process Coal Combustion 4
Iron & Steel Mills - Reheating 2
Municipal Waste Combustors 55
Nitric Acid Manufacturing 7
Petroleum Refinery Gas-Fired Process Heaters 28
Taconite Iron Ore - Induration - Coal or Gas 10
Utility Boiler - Coal/Wall 5
Utility Boiler - Oil-Gas/Tangential 2
Utility Boiler - Oil-Gas/Wall 4
547
NOx emissions
reduced from
controls in CoST
(tons/03 season)
(A)
290
Recommended
NOx emissions
reduced from
controls in CoST
(tons/03 season)
(B)
295
Size of correction
in NOx emission
reductions
(tons/03 season)
(A-B)
-5
419
0
419
156
156
0
1.591
876
715
687
82
605
2.025
0
2,025
829
451
379
555
555
0
526
526
0
1.645
1,524
121
70,082
42,054
28,028
-------
Attachment 3 - NOx Emission Reductions by 3-Digit NAICS Code for Sources in the >100 Ton per Year Reduction Group
Recommended
NOx emissions
NOx emissions
Size of correction
reduced from
reduced from
in NOx emission
controls in CoST
controls in CoST
reductions
Number of
(tons/03 season)
(tons/03 season)
(tons/03 season)
3-Diait NAICS Code
Sources
(A)
(B)
(A-B)
211 Oil and Gas Extraction
1
46
30
16
212 Mining (except Oil and Gas)
11
879
500
379
221 Utilities
10
1.186
853
333
311 Food Mfg
12
1.181
815
366
312 Beverage and Tobacco Product Mfg
7
761
761
0
322 Paper Mfg
70
11.616
7,968
3,648
324 Petroleum and Coal Products Mfg
49
3.942
239
3,703
325 Chemical Mfg
132
19.689
10,753
8,937
3272 Glass and Glass Product Mfg
64
13,588
7,047
6,540
3273 Cement and Concrete Product Mfg
64
9,113
10,183
-1,070
3274 Lime & Gypsum Product Mfg
1
75
52
22
331 Primary Metal Mfg
50
4,908
1,837
3,070
333 Machinery Mfg
1
57
35
21
336 Transportation Equipment Mfg
2
148
103
46
424 Merchant Wholesalers, Nondurable Goods
2
160
0
160
531 Real Estate
1
72
0
72
562 Waste Mgmt and Remediation Services
65
2,366
843
1,523
611 Educational Services
5
295
34
261
547
70,082
42,054
28,028
18
-------
Attachment 4 - NOx Emission Reductions by 3-Digit NAICS Code for Sources in the > 100 Ton per Year Reduction Group
Recommended
NOx emissions
NOx emissions
Size of correction
reduced from
reduced from
in NOx emission
controls in CoST
controls in CoST
reductions
Number of
(tons/03 season)
(tons/03 season)
(tons/03 season)
Recommended Change to CoST Control
Sources
(A)
(B)
(A-B)
Already Controlled
138
12.973
0
12,973
Already Controlled by Glass CD
12
1.034
0
1,034
Already Controlled By Refinery CD
52
4.300
0
4,300
Control Technically or Economically Infeasible
18
1.618
0
1,618
Fuel Switch Already Occurred
4
2.370
0
2,370
Low NOx Burner
7
629
500
129
Low NOx Burner and Flue Gas Recirculation
88
8.792
6,022
2,769
Low NOx Burner and SCR
44
7.996
7,996
0
Low NOx Burner and SNCR
41
5,895
10,236
-4,341
Non-Selective Catalytic Reduction
1
82
82
0
Oxygen Enriched Air Staging
47
12,077
7,104
4,973
Selective Catalytic Reduction (SCR)
27
6,088
6,088
0
Selective Non-Catalytic Reduction (SNCR)
62
5,109
4,026
1,083
Source Already Shutdown
6
1,120
0
1,120
547
70,082
42,054
28,028
19
-------
Attachment 5 - NOx Emission Reductions by State for Sources in the 25 to 100 Ton per Year Reduction Group
Recommended
NOx emissions
NOx emissions
Size of correction
reduced from
reduced from
in NOx emission
controls in CoST
controls in CoST
reductions
Number of
(tons/03 season)
(tons/03 season)
(tons/03 season)
State
Sources
(A)
(B)
(A-B)
Alabama
38
641
517
123
Arkansas
14
277
203
74
Delaware
5
73
58
15
Florida
27
532
399
133
Illinois
91
1.519
845
675
Indiana
44
894
580
314
Iowa
19
422
309
113
Kansas
31
562
421
140
Kentucky
33
619
407
212
Louisiana
101
2.046
1.467
579
Maryland
18
353
209
144
Michigan
67
1.149
844
304
Mississippi
22
366
343
23
Missouri
13
224
179
45
New Jersey
7
72
11
61
New York
41
685
59
625
Ohio
86
1.476
1,075
402
Oklahoma
40
749
669
81
Pennsylvania
79
1.359
423
936
Tennessee
42
742
514
228
Texas
374
6,444
3,311
3,133
Virginia
30
450
350
100
West Virginia
21
421
334
87
Wisconsin
37
697
471
226
1280
22,774
14,000
8,774
20
-------
Attachment 6 - NOx Emission Reductions by Source Group for Sources in the 25 to 100 Ton per Year Reduction Group
Recommended
NOx emissions
NOx emissions
Size of correction
reduced from
reduced from
in NOx emission
controls in CoST
controls in CoST
reductions
Number of
(tons/03 season)
(tons/03 season)
(tons/03 season)
Source Group
Sources
(A)
(B)
(A-B)
Ammonia - NG-Fired Reformers2
7
200
155
45
Cement Kilns
4
93
0
93
Cement Manufacturing - Wet
2
60
0
60
Ceramic Clay Mfg; Drying
4
29
0
29
Coal Cleaning-Thrml Dryer; Fluidized Bed
10
188
188
0
Comm./lnst. Incinerators
4
47
47
0
Ext Comb Boilers, Elec Gen, Nat Gas (2)
1
28
28
0
Ext Comb Boilers, Elec Gen, Sub/Bit Coal (3)
14
158
158
0
Fbrglass Mfg; Txtle-Type Fbr; Recup Furn
2
9
9
0
Fluid Cat Cracking Units; Cracking Unit
21
393
0
393
Fuel Fired Equip; Furnaces; Natural Gas
3
18
18
0
Fuel Fired Equip; Process Htrs; Pro Gas
7
86
86
0
Gas Turbines - Natural Gas
438
7,193
5,749
1,444
Glass Manufacturing - Flat
8
190
0
190
ICI Boilers - Coal/FBC
1
35
22
13
ICI Boilers - Coal/Stoker
133
2,502
1,629
873
ICI Boilers - Coal/Wall
11
246
246
0
ICI Boilers - Distillate Oil
4
75
0
75
ICI Boilers - Gas
26
601
0
601
ICI Boilers - Natural Gas
350
6,814
3,705
3,109
ICI Boilers - Oil
2
41
0
41
ICI Boilers - Process Gas
31
609
0
609
ICI Boilers - Residual Oil
28
484
437
47
21
-------
Number of
Source Group Sources
Indust. Incinerators 21
In-Proc;Process Gas;Coke Oven/Blast Furn 4
Iron & Steel - In-Process Comb - Coal 1
Iron & Steel Mills - Reheating 32
Municipal Waste Combustors 25
Nitric Acid Manufacturing 14
Petroleum Refinery Gas-Fired Process Heaters 30
Solid Waste Disp;Gov;Other lncin;Sludge 1
Space Heaters - Natural Gas 2
Steel Foundries; Heat Treating Furn 7
Surf Coat Oper;Coating Oven Htr;Nat Gas 2
Utility Boiler - Coal/Wall 2
Utility Boiler - Coal/Wall2 1
Utility Boiler - Oil-Gas/Tangential 8
Utility Boiler - Oil-Gas/Wall 19
1280
NOx emissions
reduced from
controls in CoST
(tons/03 season)
(A)
230
Recommended
NOx emissions
reduced from
controls in CoST
(tons/03 season)
(B)
118
Size of correction
in NOx emission
reductions
(tons/03 season)
(A-B)
113
33
8
25
19
0
19
481
481
0
472
228
243
363
289
74
456
0
456
6
6
0
17
13
4
122
122
0
11
0
11
48
48
0
13
13
0
99
62
37
307
137
170
22,774
14,000
8,774
-------
Attachment 7 - NOx Emission Reductions by 3-Digit NAICS Code for Sources in the 25 to 100 Ton per Year Reduction Group
3-Diqit NAICS Code
211 Oil and Gas Extraction
212 Mining (except Oil and Gas)
213 Support Activities for Mining
221 Utilities
311 Food Manufacturing
312 Beverage and Tobacco Products
313 Textile Mills
314 Textile Product Mills
316 Leather and Allied Product Manufacturing
321 Wood Product Manufacturing
322 Paper Manufacturing
324 Petroleum and Coal Products
325 Chemical Manufacturing
326 Plastics and Rubber Products
327 Nonmetallic Mineral Product Manufacturing
331 Primary Metal Manufacturing
332 Fabricated Metal Product Manufacturing
333 Machinery Manufacturing
334 Computer and Electronic Products
336 Transportation Equipment Manufacturing
337 Furniture and Related Products
447 Gasoline Stations
454 Nonstore Retailers
Recommended
NOx emissions NOx emissions Size of correction
reduced from reduced from in NOx emission
controls in CoST controls in CoST reductions
Number of (tons/03 season) (tons/03 season) (tons/03 season)
Sources {A> (B) {A-Bl
146
2.674
2,573
100
12
247
227
20
1
20
20
0
96
1.575
1,035
540
46
715
450
266
9
151
91
60
1
24
15
9
1
12
7
4
1
10
7
3
6
100
56
44
79
1,662
1,028
634
115
2,083
527
1,556
332
6,480
3,218
3,262
13
206
142
65
24
417
32
385
87
1,380
1,094
285
4
80
46
33
2
20
14
6
1
9
9
0
13
261
192
69
2
18
18
0
1
7
0
7
1
9
0
9
23
-------
Number of
3-Diqit NAICS Code Sources
482 Rail Transportation 3
486 Pipeline Transportation 156
488 Support Activities for Transportation 1
531 Real Estate 8
541 Professional Services 6
561 Administrative and Support Services 1
562 Waste Mgmt and Remediation Services 21
611 Educational Services 62
622 Hospitals 7
713 Amusement, Gambling, and Recreation 2
721 Accommodation 2
922 Justice, Public Order, and Safety Activities 4
923 Administration of Human Resources 1
928 National Security and International Affairs 13
1280
NOx emissions
reduced from
controls in CoST
(tons/03 season)
(A)
37
Recommended
NOx emissions
reduced from
controls in CoST
(tons/03 season)
(B)
23
Size of correction
in NOx emission
reductions
(tons/03 season)
(A-B)
14
2.551
2,034
517
18
12
6
147
0
147
81
77
4
8
0
8
376
184
192
963
617
346
116
36
80
49
45
4
25
10
15
29
17
12
12
8
4
201
135
66
22,774
14,000
8,774
-------
Attachment 8 - NOx Emission Reductions by 3-Digit NAICS Code for Sources in the 25 to 100 Ton per Year Reduction Group
Recommended Change to CoST Control
Already Controlled
Already Controlled by Refinery CD
Low NOx Burner
Low NOx Burner and Flue Gas Recirculation
Low NOx Burner and SCR
Low NOx Burner and SNCR
Natural Gas Reburn
Non-Selective Catalytic Reduction
Questions About Feasibility
Questions About Feasibility - Cement
Questions About Feasibility - Ceramic Clay Mfg
Questions about Feasibility - Coating Ovens
Questions about Feasibility - Distillate Oil
Questions About Feasibility - Glass
Questions about Feasibility - Process Gas
Selective Catalytic Reduction
Selective Non-Catalytic Reduction
Recommended
Number of
Sources
207
NOx emissions
reduced from
controls in CoST
(tons/03 season)
(A)
3.380
NOx emissions
reduced from
controls in CoST
(tons/03 season)
(B)
0
Size of correction
in NOx emission
reductions
(tons/03 season)
(A-B)
3,380
40
704
0
704
362
6.087
6,087
0
361
6.726
4,491
2,235
11
246
246
0
24
437
437
0
1
28
28
0
12
289
289
0
1
22
0
22
6
154
0
154
4
29
0
29
2
11
0
11
6
116
0
116
7
167
0
167
50
1,070
0
1,070
8
216
216
0
178
3,094
2,207
886
1280
22,774
14,000
8,774
25
-------
From:
Subject:
Date:
To:
US EPA OAQPS
SRA International, Inc.
Summary of State NOx Regulations for Selected Stationary Sources
September 30, 2014
SRA compiled a summary of state/local NOx emission control regulations pertaining six categories of
nonEGUs:
• Cement kilns
• Industrial/Commercial/Institutional (ICI) Boilers - Coal-fired
• ICI Boilers - Gas-fired
• ICI Boilers - Oil-fired
• Gas Turbines
• Internal Combustion (IC) Engines
The analysis included 27 states in the eastern luo-ihuds of ihe I S I'or each of iliese states and source
categories, we identified state-specific sub-calegones (c g fuel l\ pe or si/.e ihreshold), the NOx emission
limit or control requirement, averaging time lor ihe emission liniil. geographic applicability within the
state, testing/monitoring requirements, and rule cilalion This mformalion is contained in the attached
spreadsheet (Draft State NOx RACT I.mills 2d 14 i>4 <)| \ls\).
Attachment 1 is an overall summaiy of ihe relali\e sliingcncv of the NOx requirements by geographic
area and source cak-ijoiy We also prepared a 2-page summary for each of the six categories to concisely
compare state NO\ emission limns or conliol requirements. These are shown in Attachments 2 to 7, along
withnoles highlighting the major differences Ivlweenthe state regulations.
Please lei us know should \ou ha\e questions or comments about any of the data presented in this
memorandum
1
-------
Attachment 1 - Relative Stringency of NOx Requirements
Source Category
States/Areas with
Most Stringent Regulations
States/Areas with
Less Stringent Regulations
States with
No Regulations or Sources
Cement Kilns1
States: IL, MD, NY, PA, TX
Areas: Ellis County, TX
States: AL (NOx SIP area), IN, KY,
MO, Ml, OH, SC, TN, VA, WV
States: AR, FL, GA, MS, OK
States with no cement kilns:
CT, DE, LA, MA, NC, NJ, Wl
Coal-fired ICI Boilers2
States: NY
Areas: Chicago, St. Louis (IL portion),
Baton Rouge, Houston-Galveston (coke-
fired), Milwaukee,
States: FL, GA, IN, MA, MD, Ml, PA,
TN, VA
Areas: Chicago, St. Louis (MO
portion), Baton Rouge, Charlotte,
Cleveland
States: AL, AR, KY, MS, OK, SC, TX
(except Houston-Galveston) WV
NE States with no coal-fired ICI
boilers: CT, DE, NJ
Gas-fired ICI Boilers
States: NJ, NY, PA
Areas: Chicago, St. Louis (IL portion),
Baton Rouge, Beaumont-Port Arthur,
Cleveland, Dallas, Houston, Milwaukee
States: CT, DE, FL,GA, MA, MD, Ml,
MO, TN, VA
Areas: Clark/Floyd Counties, St.
Louis (MO portion), Charlotte
States: AL, AR, KY, MS, OK, SC, WV
Oil-fired ICI Boilers
States: NJ, NY, PA
Areas: Chicago, St. Louis (IL portion),
Baton Rouge, Cleveland, Dallas, Houston,
Milwaukee
States: CT, DE, FL, GA, MA, MD,
Ml, TN, VA
Areas: Clark/Floyd Counties, St.
Louis (MO portion), Charlotte
States: AL, AR, KY, MS, OK, SC, WV
Gas Turbines
States: NJ
Areas: GA 45-county area, Dallas,
Houston, Milwaukee
States: CT, DE, FL, LA, MA, MD,
NY, PA, TN, VA
Areas: Chicago, St. Louis (IL
portion), St. Louis (MO portion),
Charlotte, Cleveland,
States: AL, AR, IN, KY, Ml, MS, OK,
SC, WV
IC Engines > about 500 hp
States: MD, NJ, NY
Areas: Chicago, St. Louis (IL portion),
Dallas, Houston
States: CT, DE, MA, Ml, PA, TN, VA
Areas: Baton Rouge, St. Louis (MO
portion), Charlotte, Cleveland,
Milwaukee
States: AL, AR, IN, KY, MS, OK, SC,
WV
1) Cement kiln emission limits imposed by recent EPA enforcement settlements tend to be more stringent than the emission control
requirements in state rules.
2) CT, DE and NJ have no active coal-fired boilers, so the stringency of their regulations for coal-fired ICI boilers is difficult to evaluate
2
-------
Attachment 2 - Cement Kilns
NOx Limit (lbs/ton clinker)
State
Long Dry
Long Wet
Pre-heater
Pre-calciner
AL
Ozone season: low-NOx burners, mid-kiln system firing, or approved ACT
AR
No Limits
No Limits
No Limits
No Limits
CT
No Cement Kilns in State
DE
No Cement Kilns in State
FL
No Limits
No Limits
No Limits
No Limits
GA
No Limits
No Limits
No Limits
No Limits
IL
5.1
5.1
3.8
2.8
IN
6.0
5.1
3.8
2.8
IN
(Clark/Floyd)
10.8 (op day)/
6 (30 day)
No Limits
5.9 (op day)/
4.4 (30 day)
No Limits
KY
6.6
6.6
6.6
6.6
LA
No Cement Kilns in State
MA
No Cement Kilns in State
MD
5.1
6.0
2.8
2.8
Ml
6.0
5.1
3.8
2.8
MO
6.0
6.8
4.1
2.7
MS
No Limits
No Limits
No Limits
No Limits
NC
No Cement Kilns in State
NJ
No Cement Kilns in State
NY
Case-by-case RACT Determination
OH
Ozone season: low-NOx burners, mid-kiln system firing, or approved ACT
OK
No Limits
No Limits
No Limits
No Limits
PA
3.44*
3.88*
2.36*
2.36*
SC
Ozone season:
ow-NOx burners, mid-kiln system firing, or approved ACT
TN
Ozone season: low-NOx burners, mid-kiln system firing, or approved ACT
TX
5.1
4
3.8
2.8
TX
(Ellis County)
No Limits
3.4
No Limits
1.7
VA
Case-by-case RACT Determination
Wl
No Cement Kilns in State
WV
Ozone season: low-NOx burners, mid-kiln system firing, or approved ACT
ACT = Alternative Control Technology
* Pennsylvania has proposed "RACT 2" presumptive RACT limits
3
-------
Observations Regarding State NOx Rules for Cement Kilns:
~ Geographic Applicability
• All NOx SIP Call states with cement kilns have NOx rules in place
• Since only portions of Alabama, Michigan, and Missouri were affected by NOx SIP Call, the
NOx rules only apply in the affected counties.
• States not included in the NOx SIP Call do not have NOx RACT for cement kilns, except for
Texas. The Texas NOx requirements only apply in in Bexar, Comal. Ellis. Hays, and McLennan
Counties.
~ Form of NOx Limitation or Control Requirement
• A few states express the requirement as "at least one of the follow mil: low -\()\ burners, mid-kiln
system firing, alternative control techniques or reasonably available control technology approved
by the Director and the EPA as achieving at leasl I lie same emissions decreases as with low-NOX
burners or mid-kiln system firing."
• A few states specify presumptive emission li in i is in lemis of pounds ol' \()\ per ton of clinker.
• Three states do not set presumptive emission limits but rather require facilities to submit a case-
by-case RACT determination. Pennsylvania has a proposed regulation that will specify
presumptive RACT limits: current rules require sources to hold 1 trading allowance per ton of
NOx calculated by multiplying ions clinker by the presumptive NOx limit.
~ Stringency of NOx Limitation or ( onliol Requirement
• For states requiring "low-NOX burners, mid-kiln system firing, or ACT", it is generally assumed
that this will result in a 30% ivduclion from uncontrolled levels.
• For states with numerical emission limits, the limits generally represent a 20 - 40 % reduction
from uncontrolled levels, depending on the type of kiln.
• le\as has \eiy stringent limils for kilns in Ellis County.
• Penns\ l\ ama lias proposed presumptive RACT emission limitations in April 2014 that are more
slnngenl lhan existing presumptive RACT limits in other states.
4
-------
Attachment 3 - Coal-fired Boilers
NOx Limit (Ibs/mmBtu)
State
Geographic Area
Boilers
50-100
mmBtu/hr
Boilers
100 - 250
mmBtu/hr
Boilers
>250
mmBtu/hr
AL
Statewide
No limits
No limits
No limits
AR
Statewide
No limits
No limits
No limits
CT
Statewide
0.29 to 0.43
0.29 to 0.43
0.29 to 0.43
DE
Statewide
LEA, Low NOx,
FGR
0.38 to 0.43
0.38 to 0.43
FL
Broward, Dade, Palm Beach
Counties
0.9
0.9
0.9
GA
45 county area
No limits
30 ppmvd @ 3%
02
0.7
IL
Chicago & St Louis areas
Tune-up
0.12 CFB
0.25 Other
0.12 CFB
0.18 Other
IN
Clark and Floyd Counties
No limits
0.4 to 0.5
0.4 to 0.5
KY
Statewide
No limits
No limits
No limits
LA
Baton Rouge 5 counties &
Region of Influence
0.2
0.1
0.1
MA
Statewide
0.43
0.33 to 0.45
0.33 to 0.45
MD
Select counties
No limits
0.38 to 1.0
0.38 to 1.0
Ml
Fine grid zone
No limits
No limits
0.4
MO
St Louis area
No limits
0.45 to 0.86
0.45 to 0.86
MS
Statewide
No limits
No limits
No limits
NC
Charlotte 6 county area
No limits
0.4 to 0.5
1.8
NJ
Statewide
0.43 to 1.0
0.38 to 1.0
0.38 to 1.0
NY
Statewide
No limits
0.08 to 0.20
0.08 to 0.20
OH
Cleveland 8 county area
0.3
0.3
0.3
OK
Statewide
No limits
No limits
No limits
PA
Statewide
0.45
0.45
0.20 to 0.35
SC
Statewide
No limits
No limits
NOx SIP Call
TN
5 Counties
Source specific
RACT
Source specific
RACT
Source specific
RACT
TX
Houston area
0.057
coke-fired
0.057
coke-fired
0.057
coke-fired
VA
Northern VA
No limits
0.38 to 1.0
0.38 to 1.0
Wl
Milwaukee 7 county area
0.10 to 0.25
0.10 to 0.25
0.10 to 0.20
WV
Statewide
No limits
No limits
No limits
5
-------
Observations Regarding State NOx Rules for Coal-fired Boilers:
~ Geographic Applicability
• States in the OTR (CT, DE, MA, MD, NJ, NY, and PA) have NOx emission requirements that
apply statewide, not just in ozone nonattainment areas.
• Six states (AL, AR, KY, MS, OK, and WV) do not have regulations limiting NOx emissions.
• For the remaining states (FL, GA, IL, IN, KY, LA, MI, MO, NC, OH, TN, VA, WI), the NOx
emission control requirements only apply in ozone nonattainmenl areas
• Texas only has emission limitations for coke-fired boilers in the I louslon-( ial\ cslon
nonattainment area.
~ Size Applicability
• Most of the states do not have NOx emission requirements for boilers less than I no mmBtu/hour.
• 10 states do regulation boilers in the 50-100 mmBtu size range
~ Form of NOx Limitation or Control Requirement
• Nearly all states express the NOx emission limits in terms of lbs/mmBtu.
• A few states require either a case-bv-case RACT determination or specify specific types of
control equipment (e.g., low-NOx burners, flue gas recirculation).
~ Stringency of NOx Limitation or Control Requirement
• Most states specify different emission limits for different types of boilers and firing types (e.g.,
dry bottom tangential-fired) vs. dry bottom wall-fired)
• A few states in the Northeast have very few or no coal-fired ICI boilers, so the stringency of the
regulations in those states is difficult to evaluate. These states are CT, DE, NJ and MA.
• For boilers greater than 100 mmBtu/hour. the LADCO/OTC1 Phase I recommended limits are in
the 0.2-0.3 lbs/mmBtu range (depending on boiler/firing configuration). The LADCO/OTC Phase
11 recommended limits arc in the 0.1 -0.2 lbs/mmBtu range. Four areas have limits that generally
meet ihe I.ADCO/OTC recommendations (Chicago, Baton Rouge, New York State, and
Milwaukee.
• Texas has a \ ery stringent limit (0.057 lbs/mmBtu) for coke-fired boilers in the Houston-
Galveston area.
1 Evaluation of Control Options for Industrial, Commercial and Institutional (ICI) Boilers Technical Support
Document (TSD), March, 2011 prepared by the Lake Michigan Air Directors Consortium (LADCO) and the Ozone
Transport Commission (OTC).
6
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Attachment 4 - Gas-fired Boilers
NOx Limit (Ibs/mmBtu)
State
Geographic Area
Boilers
50-100
mmBtu/hr
Boilers
100 - 250
mmBtu/hr
Boilers
>250
mmBtu/hr
AL
Statewide
No Limits
No Limits
No Limits
AR
Statewide
No Limits
No Limits
No Limits
CT
Statewide
0.2 to 0.43
0.2 to 0.43
0.2 to 0.43
DE
Statewide
LEA, low NOx, FGR
0.2
0.2
FL
Broward, Dade, Palm Beach
Counties
0.2 to 0.5
0.2 to 0.5
0.2 to 0.5
GA
45 county area
30 ppmvd
@ 3% 02
30 ppmvd
@ 3% 02
0.2
IL
Chicago & St. Louis Areas
Tune-up
0.08
0.08
IN
Clark and Floyd Counties
No Limits
0.2
0.2
KY
Statewide
No Limits
No Limits
No Limits
LA
Baton Rouge 5 counties &
Region of Influence
0.1 to 0.2
0.1
0.1
MA
Statewide
0.1
0.2
0.2 to 0.28
MD
Select counties
Tune-up
0.2
0.2
Ml
Fine grid zone
No limits
Source specific
RACT
0.2
MO
St Louis area
No limits
0.2 to 0.5
0.2 to 0.5
MS
Statewide
No limits
No limits
No Limits
NC
Charlotte 6 county area
0.3
0.3
0.3
NJ
Statewide
0.1 to 0.5
0.1
0.1
NY
Statewide
0.05
0.06
0.08
OH
Cleveland 8 county area
0.1
0.1
0.1
OK
Statewide
No limits
No limits
No limits
PA
Statewide
0.08
0.08
0.08
SC
Statewide
No limits
No limits
No Limits
TN
5 Counties
Source specific
RACT
Source specific
RACT
Source specific
RACT
TX
Dallas and Houston areas
0.03 or
90% reduction
0.03 or
90% reduction
0.03 or
90% reduction
TX
Beaumont area
0.10
0.10
0.10
VA
Northern VA
0.2
0.2
0.2
Wl
Milwaukee 7 county area
No limits
0.08
0.08
WV
Statewide
No limits
No limits
No Limits
7
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Observations Regarding State NOx Rules for Gas-fired Boilers:
~ Geographic Applicability
• States in the OTR (CT, DE, MA, MD, NJ, NY, and PA) have NOx emission requirements that
apply statewide, not just in ozone nonattainment areas.
• Six states (AL, AR, KY, MS, OK, and WV) do not have regulations limiting NOx emissions.
• For the remaining states (FL, GA, IL, IN, KY, LA, MI, MO, NC, OH, TN, TX,VA, WI), the NOx
emission control requirements only apply in ozone nonattainmenl areas
~ Size Applicability
• About half of the states have NOx emission requirements for boilers less than I'll) mini itu/hour.
ranging from combustion tuning to emission limits as low as 0.05 Ilis mmlJlu
~ Form of NOx Limitation or Control Requirement
• Nearly all states express the NOx emission limits in terms of lbs/mmBtu.
• A few states require either a case-by-case RACT determination or specify specific types of
control equipment (e.g., low-NOx burners, flue gas recirculation).
~ Stringency of NOx Limitation or Control Requirement
• The LADCO/OTC Phase I recommendations arc combustion tuning for boilers less than 100
mmBtu/hour. and either 0.1 lbs/mmBtu or 50% reduction for boilers greater than 100 mmBtu/hr.
• The LADCO/OTC Phase II recommendations arc cither 0.05-0.1 lbs/mmBtu or 60% reduction.
• New Jersey and New York have state-w ide limits that are consistent with the OTC/LADCO
Phase II recommendations. Pennsylvania has proposed state-wide limits that are consistent with
the OTC/LADCO Phase II recommendations.
• Five areas (Chicago. Baton Rouge. Beaumont-Port Arthur, Cleveland, and Milwaukee) have
11hiiIs that arc consistent w ith the OTC/LADCO Phase II recommendations.
• Dal las and I louslon ha\ c I he most stringent emission limitations - 0.02 lbs/mmBtu for greater
thai I'm ninililu hr umls
8
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Attachment 5 - Oil-fired Boilers
NOx Limit (Ibs/mmBtu
State
Geographic Area
Boilers
50-100
mmBtu/hr
Boilers
100 - 250
mmBtu/hr
Boilers
>250
mmBtu/hr
AL
Statewide
No limits
No limits
No limits
AR
Statewide
No limits
No limits
No limits
CT
Statewide
0.2 Distillate
0.25-0.43 Resid.
0.2 Distillate
0.25-0.43 Resid.
0.2 Distillate
0.25-0.43 Resid.
DE
Statewide
LEA, Low NOx, FGR
0.38 to 0.43
0.38 to 0.43
GA
45 county area
30 ppmvd
30 ppmvd
0.3
IL
Chicago & St Louis areas
Tune-up
0.1 Distillate
0.15 Resid.
0.1 Distillate
0.15 Resid.
IN
Clark and Floyd Counties
No limits
0.2 Distillate
0.3 Resid.
0.2 Distillate
0.3 Resid.
KY
Statewide
No limits
No limits
NOx SIP Call
LA
Baton Rouge
0.2
0.1
0.1
MA
Statewide
Tune-up
0.3 Distillate
0.4 Resid.
0.25 to 0.28
MD
Select counties
No limits
0.25
0.25
Ml
Fine grid zone
No limits
No limits
0.3 Distillate
0.4 Residual
MO
St Louis area
No limits
0.3
0.3
MS
Statewide
No limits
No limits
No limits
NC
Charlotte 6 county area
0.2
0.2
0.2
NJ
Statewide
Tune-up
0.1 Distillate
0.2 Resid.
0.1 Distillate
0.2 Resid.
NY
Statewide
0.08 to 0.2
0.15
0.15 to 0.2
OH
Cleveland 8 county area
0.12 Distillate
0.23 Resid.
0.12 Distillate
0.23 Resid.
0.12 Distillate
0.23 Resid.
OK
Statewide
New only
New only
New only
PA
Statewide
0.12 Distillate
0.20 Resid.
0.12 Distillate
0.20 Resid.
0.12 Distillate
0.20 Resid.
SC
Statewide
No limits
No limits
No limits
TN
5 Counties
Case-by-Case
RACT
Case-by-Case
RACT
Case-by-Case
RACT
TX
Dallas and Houston areas
No limits
~0.01
~0.01
VA
Northern VA
0.25 to 0.43
0.25 to 0.43
0.25 to 0.43
Wl
Milwaukee 7 county area
No limits
0.10 Distillate
0.15 Resid.
0.10 Distillate
0.15 Resid.
WV
Statewide
No limits
No limits
No limits
9
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Observations Regarding State NOx Rules for Oil-fired Boilers:
~ Geographic Applicability
• States in the OTR (CT, DE, MA, MD, NJ, NY, and PA) have NOx emission requirements that
apply statewide, not just in ozone nonattainment areas.
• Six states (AL, AR, MS, OK, SC, and WV) do not have regulations limiting NOx emissions.
• For the remaining states (FL, GA, IL, IN, KY, LA, MI, MO, NC, OH, TN, TX, VA, WI), the
NOx emission control requirements only apply in ozone nonattai nine ill areas
~ Size Applicability
• About half of the states have NOx emission requirements for boilers less iluin I < >() nunBtu/hour,
ranging from combustion tuning to emission limits as low as 0.08 lbs/inmBlu.
~ Form of NOx Limitation or Control Requirement
• Nearly all states express the NOx emission limits in terms of lbs/mmBtu.
• A few states require either a case-by-case RACT determination or specify specific types of
control equipment (e.g., low-NOx burners, flue gas recirculation).
~ Stringency of NOx Limitation or Control Requirement
• The LADCO/OTC Phase I recommendations for distillate oil are combustion tuning for boilers
less than 100 nunBtu/hour. and either 0.1 lbs/mmBtu or 50% reduction for boilers greater than
100 mmBtu/hr. The LADCO/OTC Phase II recommendations for distillate oil are either 0.08-0.1
lbs/mmBtu or 60% reduction.
• Only New Jersey has state-w ide limits that are consistent with the OTC/LADCO Phase II
recommendations for distillate oil.
• Three areas (Chicago. Baton Rouge, and Milwaukee) have limits that are consistent with the
OTC I.ADCO Phase II recommendations for distillate oil.
• The I A l)( () OTC Pluise I recommendations for residual oil are combustion tuning for boilers
less Hum Inn inmBtu hour, and either 0.2 lbs/mmBtu or 60% reduction for boilers greater than
100 mmBlu. hr. The LADCO/OTC Phase II recommendations for residual oil are either 0.2
lbs/mmBlu or 50-70% reduction.
• New Jersey and New York have state-wide limits that are consistent with the OTC/LADCO
Phase II recommendations for residual oil. Pennsylvania has proposed state-wide limits that are
consistent with the OTC/LADCO Phase II recommendations for residual oil.
• Four areas (Chicago, Baton Rouge, Charlotte, and Milwaukee) have limits that are consistent with
the OTC/LADCO Phase II recommendations for residual oil
• Dallas and Houston have the most stringent emission limitations - 0.01 lbs/mmBtu for greater
that 100 mmBtu/hr units.
10
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Attachment 6 - Gas Turbines
NOx Limit (ppmvd @15% 02)
State
Geographic Area
Simple Cycle
>25 MW
Gas-fired
Simple Cycle
>25 MW
Oil-fired
Combined Cycle
> 25 MW
Gas-fired
Combined Cycle
>25 MW
Oil-fired
AL
Fine grid zone
No limits
No limits
No limits
No limits
AR
Statewide
No limits
No limits
No limits
No limits
CT
Statewide
55
258
(0.9 Ib/mmBtu)
55
258
(0.9 Ib/mmBtu)
DE
Statewide
42
88
42
88
GA
45 county area
6
6
6
6
IL
Chicago & St Louis
areas
42
96
42
96
IN
Statewide
No limits
No limits
No limits
No limits
KY
Statewide
No limits
No limits
No limits
No limits
LA
Baton Rouge 5
counties & Region
of Influence
54
(0.2 Ib/mmBtu)
86
(0.3 Ib/mmBtu)
54
(0.2 Ib/mmBtu)
86
(0.3 Ib/mmBtu)
MA
Statewide
65
100
42
65
MD
Select counties
42
65
42
65
Ml
Fine grid zone
No limits
No limits
No limits
No limits
MO
St Louis area
75
100
75
100
MS
Statewide
No limits
No limits
No limits
No limits
NC
Charlotte 6 county
area
75
95
75
95
NJ
Statewide
33
(2.2 Ib/MWh)
53
(3.0 Ib/MWh)
33
(2.2 Ib/MWh)
53
(3.0 Ib/MWh)
NY
Statewide
50
100
42
65
OH
Cleveland 8 county
area
42
96
42
96
OK
Statewide
No limits
No limits
No limits
No limits
PA
Statewide
42
75
42
75
SC
Statewide
No limits
No limits
No limits
No limits
TN
5 Counties
source specific
RACT
source specific
RACT
source specific
RACT
source specific
RACT
TX
Dallas and Houston
areas
9
(0.032 Ib/mmBtu)
9
(0.032 Ib/mmBtu)
9
(0.032 Ib/mmBtu)
9
(0.032 Ib/mmBtu)
VA
Northern VA
42
65/77
42
65/77
Wl
Milwaukee 7
county area
25 to 42
65 to 96
9
9
WV
Statewide
No limits
No limits
No limits
No limits
11
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12
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Observations Regarding State NOx Rules for Gas Turbines:
~ Geographic Applicability
• States in the OTR (CT, DE, MA, MD, NJ, NY, and PA) have NOx emission requirements that
apply statewide, not just in ozone nonattainment areas.
• Nine states (AL, AR, IN, KY, MI, MS, OK, SC, and WV) do not have regulations limiting NOx
emissions.
• For the remaining states (GA, IL, LA, MO, NC, OH, TN, TX, VA. \\ I). llie NOx emission
control requirements only apply in ozone nonattainment areas.
~ Other Applicability Criteria
• States use a variety size thresholds. For example. Ohio's rules diffeivniiale between units <3.5
MW and > 3.5 MW. Wisconsin has requiremenls lor lluve si/.e ranges: 10-25 MW. 25-50 MW,
and >50 MW.
• State limits generally differ by type of fuel - yus or oil Wisconsin also includes limits for
biologically derived fuel.
• Some states have different limits for simple-c\ cle and comlnned-c\ cle units. Other states have a
single limit that applies to both types of units.
~ Form of NOx Limitation or Control Rcquiremcnl
• States do not specify specific types of control techniques, but rather set a numerical emission
limit.
• Most states express limits in terms of "ppmv at 15% oxygen". Some states use lbs/mmBtu, and
the equivalent limits shown in the table above were calculated using based on Part 75 Eq-F5 and
F-factors. New Jersey's limits arc in terms of lbs/MHr.
~ Sli'ingenc\ of NOx Limitation or Control Requirement
• Three areas ha\e \ei\ low limits compared to other states/areas: the 45 county area in Georgia,
Dallas and I louslon-(ial\eslon
13
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Attachment 7 - IC Engines Greater than ~500 hp
NOx Limit (g/hp-hr)
State
Geographic Area
Gas-fired,
Lean Burn
Gas-fired,
Rich Burn
Diesel
Dual Fuel
AL
Fine grid zone
No limits
No limits
No limits
No limits
AR
Statewide
No limits
No limits
No limits
No limits
CT
Statewide
2.5
2.5
8.0
8.0
DE
Statewide
Technology Stds.
Technology Stds.
Technology Stds.
Technology Stds.
GA
45 county area
?
?
?
?
IL
Chicago & St Louis
areas
210 ppmvd @
15% 02
(2.9 g/hp-hr)
150 ppmvd @
15% 02
(2.2 g/hp-hr)
660 ppmvd @
15% 02
(9.1 g/hp-hr)
660 ppmvd @
15% 02
(9.1 g/hp-hr)
IN
Statewide
No limits
No limits
No limits
No limits
KY
Statewide
No limits
No limits
No limits
No limits
LA
Baton Rouge 5
counties & ROI
4.0
2.0
?
?
MA
Statewide
3.0
1.5
9.0
9.0
MD
Select counties
150 ppmvd @
15% 02
(1.7 g/hp-hr)
110 ppmvd @
15% 02
(1.6 g/hp-hr)
175 ppmvd @
15% 02
(2.0 g/hp-hr)
125 ppmvd @
15% 02
(1.4 g/hp-hr)
Ml
Fine grid zone
3.0
1.5
2.3
1.5
MO
St Louis area
3.0 10.0
2.5 to 9.5
2.5-8.5
2.5-6.0
MS
Statewide
No limits
No limits
No limits
No limits
NC
Charlotte Area
2.5
2.5
8.0
8.0
NJ
Statewide
2.5
1.5
8.0
8.0
NY
Statewide
1.5
1.5
2.3
2.3
OH
Cleveland
3.0
3.0
3.0
3.0
OK
Statewide
No limits
No limits
No limits
No limits
PA
Statewide
3.0
2.0
8.0
8.0
SC
Statewide
No limits
No limits
No limits
No limits
TN
5 Counties
Source specific
RACT
Source specific
RACT
Source specific
RACT
Source specific
RACT
TX
Dallas and Houston
area
0.5
0.5
2.8 to 6.9
0.5
VA
Northern VA
Source specific
RACT
Source specific
RACT
Source specific
RACT
Source specific
RACT
Wl
Milwaukee 7
county area
3.0
3.0
3.0
3.0
WV
Statewide
No limits
No limits
No limits
No limits
14
-------
Observations Regarding State NOx Rules for IC Engines:
~ Geographic Applicability
• States in the OTR (CT, DE, MA, MD, NJ, NY, and PA) have NOx emission requirements that
apply statewide, not just in ozone nonattainment areas.
• Eight states (AL, AR, IN, KY, MS, OK, SC, and WV) do not have regulations limiting NOx
emissions.
• For the remaining states (GA, IL, LA, MI, MO, NC, OH, TN, TX. Y.\. \YI). the NOx emission
control requirements only apply in ozone nonattainment areas.
~ Other Applicability Criteria
• States use a variety size thresholds. For example, Louisiana's rules lui\ e separale linuis for IC
engines that are 150-300 hp, >300 hp, and > 15<>u hp New York uses -> 200 hp and 400 hp.
Delaware uses > 450 hp, while North Carolina uses foil hp
• State limits generally differ by type of fuel - gas. oil. dual-fuel or landfill/digester gas.
• A few states have different limits lean-burn and nch-lnun engines Other states have a single limit
that applies to both types of units.
~ Form of NOx Limitation or Control Requirement
• Most states express limits in terms of "gram per brake horsepower hour".
• Some states use "ppmvd @ 15% 02", and llie equivalent limits shown in the table above were
calculated using conversion factors from ppmv iin 15% 02 to g/hp-hr from EPA ACT, July 1993
EPA453-R-93-032.
• Delaware specifies control technology standards rather than numerical emission limits.
~ Stringency of NOx Limitation or Control Requirement
• \lar\ land. New Jerse\. New York and the Dallas/Houston areas of Texas have limits that are
more slnngenl lhan oilier slales/arcas.
15
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