### 1 

## Technical Suppor t Document (TSD) for the Cross-State Air Pollution Rule for the 2008 Ozone NAAQS Docket ID No. EPA-H Q -OAR-201 5 -0 500



# Assessment of Non-EGU NOx Emission Controls, Cost of

Controls, and Time for Compliance

U.S. Environmental Protection Agency Office of Air and Radiation
November 2015

### 2



# 1 Introduction/Purpose

Th e purpose of this Technical Support Document (TSD) is to discuss the currently available information on emissions and control measures for sources of NO x other than electric generating units (EGUs). This information provides more detail about why EGUs are the focus of the proposed rulemaking , namely the uncertainty that exists regarding whether significant aggregate NOx mitigation is achievable from non

- EGU point sour ces 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

, t he EPA continues to assess the role of NOx emissions from non

- EGU sources to downwind nonattainment problems , and welcomes comments on the information in this TSD both as it relates to the current rule and for future use.

This TSD begins by briefly discussing t he non

- EGU emissions inventories used in this proposed rule, both for the 2011 base year and 2017 future baseline assessed for this proposed rule. The TSD then presents an evaluat ion of whether non

- EGU emissions can be reduced in a cost

- effective manner fo r 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 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 EGU s

. Finally, the TSD presents estimates of the time required to install and implement the control measures, both for comparison to the 201 7 compliance timeframe, and for discussion of installation time should such measures be required in the future.

For the reasons stated in the preamble, the data and discussion in this TSD are intended to focus on the e astern states that are the focus of the Cross

- State Air Pollution Rule (CSAPR). Information inclusive of w estern states 1 

### is presented w here available and appropriate.

1 For the purpose of this action, the western U.S. (or the West) consists of the 11 western contiguous states o f 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.

### 3



# 2 Background

In this section we present annual and ozone

- season NOx emission inventory totals and the relative per centage s 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 TSD 2 

### as well as t he Notice of Data Availability 3 

### (NODA) and Regulatory Impact Analysis 4 

### (RIA) for this proposed rulemaking.

Table 1 lists 2011 and 2017 projected NOx emissions by sector, in summary form, for the 48 contiguous states of the U.S. (CONUS).



# Table 1: 2011 B ase Year and 2017 Projected NOx Emissions by

Sector (tons), for the 48 CONUS

Sector 2011 NO x , annual 2017 NO x ,

annual 2011 NO x , ozone

season 2017 NO x , ozone

season EGU

- point 2,000,000 1,500,000 942, 000 6 89,000

NonEGU

- point 1,200,000 1,200,000 515

, 000 5 0 2,000 Point oil and gas 500,000 410,000 213,000 172,000

Wild and p rescribed f

ires 330,000 330,000 165,000 1 65,000 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 2 11,000

Nonroad 1,600,000 1,100,000 825,000 582,000

Onroad 5,700,000 3,200,000 2,41 7

, 000 1,3 29,000

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 3 84,000

Biogenics 1,000,000 1,000,000 630,000 6 30,000

TOTAL 15,000,000 11,200,000 6,6 98,000 5,01 8
, 00 0



### 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

. E missions from the n on

- EGU point

source sector and the other nonpoint source sector are not projected to change significantly

, while emissions 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, Fi gures

2 Technical Support Document (TSD), Preparation of Emissions Inventories for the Version 6.2, 2011 Emissions Modeling Platform, August 2015, available at: http://www3.epa.gov/ttn/chief/emch/2011v6/2011v6_2_2017_2025_E misMod_TSD_aug2015.pdf

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 prop osed rulemaking.

4 Regulatory Impact Analysis for the Proposed Cross

- State Air Pollution Rule (CSAPR) for the 2008 Ozone National Ambient Air Quality Standards (NAAQS). The official version is available in the docket for this proposed rulemaking.

### 4



### 1 and 2 show the relative contributions of the various sectors to overall NOx emissions (left panel) 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 (4 8 states)

Figure 2: Projected 2017 NOx emissions by sector, with further

non
- EGU breakout (48 states) 13%

16%

2%

0% 60% 9% 

# 2011 v2 NEI

- NOx by Sector (TOTAL 6.7M os TONS)

EGU

Non-EGU total

Fires

Residential wood

Mobile

Biogenics 42%

15% 25% 18% 

# 2011 V2 NEI

- NOx IN
NON

- EGU SECTOR

Non-EGU point

Point oil &

gas

Nonpoint oil & gas

Other nonpoint

12%

21%

3%

0% 53% 11% 

# 2017 PROJECTIONS

- NOx BY

SECTOR (TOTAL 5.0M os TONS)

EGU

Non-EGU total

Fires

Residential wood

Mobile

Biogenics 42%

18% 23% 17% 

# 2017 PROJECTION

- NOx IN NON

- EGU


# SECTOR

Non-EGU

point

Point oil &

gas

Nonpoint oil & gas

Other nonpoint

### 5



### Figure 1 depicts total ozone season NOx emissions of 6, 698

, 000 tons in 2011 and Figure 2 depicts total ozone season NOx emissions of 5,01 8

, 00 0 tons in 2017. In both 2011 and 2017, t he mobile source sector has the largest NOx emissions

. Substantial reductions in mobile source NOx are projected to occur by 2017. Mobile sources are projected to decrease because of sector

- specific standards related t o 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 achievab le by the 2017 ozone season

.

For the purposes of preliminary analysis in this TSD

, “non

- EGU total” refer s 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 sour ces)

. 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 NAICS code specified for the various sources. Note that point oil and gas sources include a variety of t ypes 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 states of the U.S. Totals are given for the 48 contiguous United States ( the 37 e astern states plus D.C. that are addressed in the proposed rulemaking are highlighted below in blue )

. N on

- EGU sources in this table are broken down into two groups (non

- EGU p oint sources , including point oil & gas sources , and other nonpoint and nonpoint oil & gas sources )

.

### 6



# Table 2: Projected Total Anthropogenic Ozone

- Season NOx
Emissions vs. Projected Non

- EGU Source Group NOx Emissions
,

2017 Projections, Tons 5

State T otal

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 18,816 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 1 0,697 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 11 5 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 Pennsylvania 174,664 23,735 14 33,508 19 26,713 15

5 EGUs ar e not provided a separate breakout in Table 2 since state

- level emissions are presented in the emissions modeling platform TSD and other TSDs for this proposal.

### 7

State T otal

Anthropogenic Non

- EGU

Point + Oil &
Gas Point %

Anthro Oil & Gas

Nonpoint + Other Nonpoint %

Anthro Oil & Gas

Point + Oil
& Gas Nonpoint %

Anthro
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 1,241 6 432 2 75 0

Tennessee 85,759 13,494 16 5,846 7 1,922 2

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 Stat es 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

- EGU s categories range from 3% to
2 6 % ( e astern states) and from 7 % to 3 8 % ( w estern states).

W e 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 continen tal U.S . In individual states, the percentage of

an thropogenic emissions contributed by these non

- EGUs ranges from 2 % to 25 % ( e astern states) and from 4 % to 3 1 % ( w estern states).

The EPA ’s preliminary analysis indicates that NOx emissions from oil and gas sources ( inclusive of emissions from the point oi l 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 2011 v6.2 Emissions Modeling Platfo rm TSD for more information on emissions from these sectors.



# 3 Preliminary Analysis For the purposes of this proposed rule, the EPA performed a preliminary analysis to characterize whether there are non

- EGU source groups with a substantial amount of

ava ilable cost

- effective NOx reductions achievable by the 2017 ozone season

.

### 8



## 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 u ses 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 th e 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 Analys e s (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 this proposal. Further discussion and documentation of CoST is available on the EPA’s website at http://www.epa.gov/ttnecas1/cost.htm

.

Appendices to this TSD discuss recommendations for updates to CoST, including

c orrections for inapplicable controls, sources already controlled by state rules, sources with permit limits or that clearly identified controls in place, and sources subject to future
NOx emission l imits

. Appendix A summaries RTI ’s work to review estimates for lean burn IC engines, glass manufacturing, ammonia reformers, and ga s turbines

. 6 

### Appendix B discusses SRA ’s work on a variety of other categories including many of the others evaluated in this TSD. 7



### It should be noted that all of the NOx measures included in this report are currently in the
C ontrol Measure Data Base (CMDB ) used by CoST , and 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. The EPA plans 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. Nonetheless, the information from these reports helped inform ou r assessment in terms of uncertainty surrounding non

- EGU emission redu ction potential. Further details on the CMDB can be found on the CoST web site.

For the purpose of identifying a list of non

- EGU NOx source groups with controls available, the EPA ran CoST including non

- EGU sources for the 37 e astern U.S. with NOx emissio ns of greater than 25 tons/year in 2017

. These reports are included in the Appendices of this
TSD. Through a contractual agreement with EPA, SRA International and RTI International provided reports which CoST examined a number of source categories of non

- EGUs with control costs up to $10,000 per ton (in 2011 dollars) . CoST selected particular control

6 “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.

7 “Review of CoST Model Emission Reduction Estimates,” SRA Inter national, 2014; “Summary of State NOx Regulations for Selected Stationary Sources,” SRA International, 2014.

### 9



### technologies based on application of a least

- cost criterion for control measures applied as part of control strategy. Other NOx control measures are availabl e 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 includ e the following:

Boundary of the cost analysis: In this engineering 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 th e equipment. Recordkeeping, reporting, testing and moni toring 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 prov iders. 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 lives. We do not account for regiona l 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 compa res 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.

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 d ata 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 (i nterest) rate used in accordance with OMB guidance in Circular A

- 94. 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 rate s 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 AACE International. In addition, the accuracy of costs is also influenced by the a vailab ility 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 derivatio n

### 10



### of costs for some of the non

- EGU NOx control measures discussed in Appendix A for this

TSD.



## 3. 3 CoST Results
The results of the CoST analysis are displayed in Table 3

. In this table, we display the source groups selected by CoST , the Source Classif ication Codes (SCCs) included in those

groups 8 

### , the least

- cost control technology for a given source group (also selected by CoST), the current estimate (in dollars per ton, using 2011 dollars) of the annualized cost per ton NOx reduced of the control tech nology , 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 selected controls could be fully installed and operational prior to the 2017 ozone season (which as discussed in more deta il 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 inventor y, along with the cost of installation and operation of the selected measures.

8 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, BSI is applicable only for the types of cement kilns covered by the listed SCCs

.

### 11



# Table 3: CoST Results: Non

- EGU S ource Groups with NOx Reductions

9 Time to install is not an output of CoST, but are rather estimates determ ined by 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 excep t cement kilns and RICE), “Cement Kilns Technical Support Document for the NOx FIP,” EPA, January 2001 (cement kilns), and “Availability and Limitations of NOx Emiss ion 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)

. 10 In general, f

or control retrofits to non

- EGU sectors, it appears that the full sector

- wide compliance time is uncertain , but is longer than the installati on time shown above for a typical unit . We have insufficient information on capacity and experience within the OEM suppliers and major engineering firms supply cha in to offer conclusions on their availability to execute the project work for non

- EGU sectors

. 11 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 existing CSAPR program will require additional time relative to EGUs that are c urrently 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, certifica tion testing, and electronic data reporting programming of a data handling system. These added timing considerations for inf rastructure on the non

EGU sources combined with the additional programmatic adoption measures necessary make installation of contr ols by the 2017 timeframe established in this rule less likely and more uncertain for industrial sources.

12 Emissions and potential reductions for Gas Turbines ($163/ton grouping), Cement Kiln/Dryer (Bituminous Coal) ($942/ton groupi ng), Coal Cleaning

– Th ermal 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, IC I 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

– C ontainer

, 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.

13 Potential reductions assume fully implemented controls by the start of the 2017 ozone season. Non

- EGU Source Group SCCs Control Technology Recommended by CoST Current

estimate of NOx $/ton, CoST (2011 $) Time to install 9

10 ( excluding permitting, reporting preparation, programmatic and administrative considerations 11 ) 2017 12
NOx
Emissions (37 States + DC), OS tons, CoST 2017 Potential

Reductions 13 (37 States + DC), OS tons, CoST

Cement Kilns 30500622 (prehe ater kiln), 30500623

(preheater/precalciner); 39000201 (kiln/dryer); 39000288 (kiln in process coal) Biosolid Injection Technology (BSI) $410 Uncertain 24,760 4,207

Cement Mfg (dry) 30500606 Industrial Processes, Mineral

Products, Cement Manufacturing (Dr y 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

### 12

Coal Cleani ng

– 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

- Reheat i ng 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 m onths 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

- $1101 28

- 58 weeks 179 177

Gas Turbines 20200201 Natural Gas, Turbine; 20200203

Natural Gas, Turbine: Cogeneration; 20300202 Natural Gas, Tur bine 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 16,03 6 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

### 13

Natural Gas RICE Miscellaneous 20100202 Internal Combust ion 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 Comb ustion 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

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,
B ituminous/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

### 14

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

Gas

- Fired Process Heaters (2) 30600104 Industrial Processes, Petroleum

Industry, Process Heaters, Gas Fired Ultra

- Low NOx
Burners $2,419

- $2,638 6

- 8 months 137 64

By

- Product Coke Manufacturing 30300306 Industrial Processes, Pri mary

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 9 91 689

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

### 15

ICI Boilers 10200201, 10200202, 10200212,

10300205, 10200501, 10200504, 10200601, 10200602, 10200603, 10200604, 10201401, 10300601, 10300602, 10200701, 10200704, 10200707, 1 0201402 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

- Bituminous Coal 30300819, 30300824, 30300913,

30300914, 30301522 Industrial Processes, Primary Metal P roduction SCR $3,705 28

- 58 weeks 829 746

Diesel RICE Miscellaneous 20100102 Internal Combustion Engines,

Electric Generation, Dist i llate Oil (Diesel), Reciprocating; 20100107 Internal Combustion Engines, Electric Generation, Dist i llate Oil (Diesel), Recip rocating: Exhaust; 20200102 Internal Combustion Engines, Industrial,
Dist i llate Oil (Diesel), Reciprocating; 20200106 Internal Combustion Engines, Industrial, Dist i llate Oil (Diesel), Reciprocating: Evaporative Losses (Fuel Storage and Delivery System);
20 200107 Internal Combustion Engines, Industrial, Dist i llate Oil (Diesel), Reciprocating: Exhaust; 20300101 Internal Combustion Engines, Commercial/Institutional, Dist i llate Oil (Diesel), Reciprocating; 20400403 Internal Combustion Engines, Engine Testing, R eciprocating Engine, Distillate Oil SCR $3,814 28

- 58 weeks 1,091 869

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 Indust rial Processes, Mineral

Products, Glass Manufacture, Pressed and Blown Glass: Melting Furnace OXY

- Firing $6,356 Uncertain 1,001 851

### 16

Petroleum Refinery Gas

Fired Process Heaters (2) 30600104 Industrial Processes,

Petroleum Industry, Process Heaters,
Gas

- fi red, 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 Cat alytic 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, Cont ainer Glass: Melting Furnace OXY

- Firing $7,481 Uncertain 3,107 2,628

Petroleum Refinery Gas

Fired Process Heaters (1) 30600104 Industrial Processes,

Petroleum Industry, Process Heaters,
Gas

- fired; 30600106 Industrial Processes, Petroleum Industry, Process Heaters, Process Gas

- fired SCR

- 95% $5,609

- $5,884 28

- 58 weeks 372 338

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
El ectric
Generation 20200102 Internal Combustion Engines,

Electric Generation, Dist i llate Oil (Diesel), Reciprocating SCR $1,499 28

- 58 weeks 778 622

### 17



## 3. 4 Discussion of Non

- EGU Source Groups
The below discussion utilizes the information in Table 3 in o rder 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 that have the potential for non

- EGU stationary source emis sions reductions . There are some notable source categories below $10,000 per ton that have the potential for substantial non

- EGU stationary source emissions reductions

. However, for the purposes of this analysis , the EPA did not further examine control op tions above $3,300 per ton. This is consistent wit h the range we analyzed for EGUs in this proposal, and is also consistent with what the EPA has identified in previous transport rules as highly cost

- effective , including the NOx SIP call. 14 

### 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 fo cus excludes several source groups with hig h reduction potential, including as SCR & LNB from ICI boilers, LNB & FGR on Catalytic Cracking, Process Heaters, & Coke Ovens

, and O XY

- Firing on Pressed and Container Glass Manufacturing

, because reductions from those source groups are not available for $3,300 per ton or less.

At a cost level of $3,300 per ton or less, there are a number of remaining source groups with substantial reduction potential. H owever the table also identifies several source

groups whose r eduction potential is not significant , and which EPA did not weigh heavily in assessing the aggregate non

- EGU NOx reduction potential . This is because the aggregate potential reductions from these “insignificant” source groups is small

. These “insignifican t” source groups comprise those with many small sources, as well those containing a limited number of larger sources; for either of these types of groups, potential aggregate emission reduction s are small relative to reductions available from other source categories

. T he EPA does not believe that small sources have significant potential in the aggregate because m ost small sourc es emit less than 100 tons of N O x per year . (It is worth noting that s mall sources account for a significant percentage of the total num ber of non

- EGU point sources. Please 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 poten tial 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 RICE, incinerators, boilers & process heaters, by

- product coke manufacturing, ammonia production, and flat glass manufac turing

. These remaining source groups are listed below with their control technologies, estimated control costs, and estimated installation time.

14 $3,300 per ton represents the $2,000 per ton value ( in 1990 dollars ) used in the NOx SIP call , adjusted to the 2011 doll ars used throughout this proposal

.

### 18



### These groups have been organized into 7 categories for clarity , based on either common control technologies (c ategories 1 through 6) or similarity of source groups (category 7)

.

Category 1 Cement Mfg (dry) SNCR $1,255 42

- 51 weeks
Incinerators SNCR $1,842 42

- 51 weeks By

- Product Coke Manufacturing SNCR $2,673 42

- 51 weeks

Category 2 Cement Kilns Biosolid Injection Technology (BSI) $410 Uncertain

Category 3 Gas Turbines Low NOx Burner (LNB) $800 6

- 8 months

Category 4 Cement Mfg (wet) Mid

- Kiln Firing $73 5

- 7 months

Category 5 Boilers & Process Heaters SCR $2,235 28

- 58 weeks
Amm onia Production SCR $2,896 28

- 58 weeks

Category 6 Glass Manufacturing

- Flat OXY

- Firing $3,097 Uncertain

Category 7 Gas RICE Pipeline Compressors Adjust AFR and Ignition Retard $249 Uncertain Gas RICE Miscellaneous Adjust AFR and Ignition Reta rd $447 Uncertain Gas RICE Pipeline Compressors, Rich Burn NSCR $517 Uncertain Gas RICE Pipeline Compressors, Lean / Clean Burn

Low Emission Combustion (LEC) $649 Uncertain

The EPA make s the following observations about the potential reductions f rom these significant cost

- effective categories.

The source groups listed in Category 1 would utilize SNCR as the recommended control technology

. T he time necessary to install SNCR equipment is generally well known . A typical installation timeline of 42

- 51 weeks is generally needed to complete an SNCR project going from the bid evaluation through startup. 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

### 19



### 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 bioso lid 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 asses sment 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 tech nology 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. Moreove r, 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 t hose EGUs covered under federal transport rulemakings and this one). 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 repo rting programming of a data handling system. 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.

The source group list ed 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 evalu ation 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 proposed in this rule less likely and more uncertain for industrial sources such as those in the cement manufacturing (wet) source group

.
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 (depen dent 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 monitor ing equipment make installation of

### 20



### 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 th e 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 r ebuild, which rebuilds may occur at infrequent intervals of a decade or more. 15 

### 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

recomme nded 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. 16 

### Additionally, in ord er 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 Concl usion 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 $3,300 per ton or less. In addition, further implementation of the recommendatio ns in the Appendic es to this TSD w ould also reduce our uncertainty regarding the control measures included in future non

- EGU NOx control strategy efforts

.
While a number of source groups with control options were identified, the EP A did not further examine control options above $3,300 per ton, consistent with the range analyzed for EGUs in this proposal and with what the EPA has identified in previous transport rules as highly cost

- effective. At a cost level of $3,300 per ton or les s, a number of source groups

15 See Appendix B.

16 “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 Environme ntal Solutions Inc., July 2014.

### 21



### remained, however the EPA believes several of these source groups are not significant. Of the remaining source groups, a variety of considerations indicated the ability for control technology to be installed and operational in time for the 2017 ozone season seem ed 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 relative to EGUs that are currently equipped with P art 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 al l of these factors being considered, t he 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 rule, this conclusion has led EPA t o focus the current proposed FIPs on EGU reductions. The proposal acknowledges that this may not be the full remedy that is ultimately be needed to eliminate an upwind state’s significant contribution to nonattainment or interference with maintenance of t he 2008 ozone NAAQS (or, for that matter, the 2015 ozone NAAQS). Emissions reductions from the

non

- EGU categories discussed above may be necessary , though on a longer timeframe than the 2017 compliance deadline being proposed in this rulemaking

. EPA inte nds to explore this question further in the near future and welcomes comment on any of the information in this TSD to assist with that effort

.

## 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_________________________________ RTI International is a trad e name of Research Triangle Institute

. 

### RTI Project Number 0212979.002.002



# Update of NOx Control Measure Data in the
CoST Control Measure Database for Four

Industr ial 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

### iii 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 Deletions

................................ ................................ ..................... 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

3.3.1 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

### iv 3.3.8 SCR and Water Injection; Gas Turbines

— Oil (NSCRWGTNG)

.......... 3

- 20

3.3.9 Water Injection; Gas Turbin es

— 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 Manufactu ring 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

### v

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

- 1

B Combustion Turbines

................................ ................................ ........................... B

- 1

C Glas s Manufacturing

................................ ................................ ............................ C

- 1

D Lean Burn Engines

................................ ................................ .............................. D

- 1

E Notes Provided Her e to EPA Questions on L ean B urn RICE

............................. E

- 1

### vi 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 Suppor ting 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 S ummary 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 Injectio n (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 Reco mmended 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 En gines

................................ ................................ ..... 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

### 1

- 1 SECTION 1

INTRODUCTION

The U.S. Environmental Protection Agency (EPA) Health and Environmental Impacts Division (HEID) has developed the Control Strategy Tool (C oST) 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 t hat 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 sourc e 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 categor ies: 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 assumpti ons 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 r eformer 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 recipr ocating internal combustion engine (RICE) source categories, respectively. Appendix E provides answers to questions on lean

- burn RICE NOx

### 1

- 2

emissions and available control measures. It should be noted that these revisions and updates will improve the accura cy and quality of NOx non

- EGU control strategy and cost analyses for EPA rulemakings.

### 2

- 1 SECTION 2

AMMONIA REFORMERS SE CTOR

The control measures database includes the following NO X 

### emissions control measures

for ammonia reformers:

■ 

### Oxygen trim and water injection,

■ 

### Low NO X 

### burners and flue gas recirculation,

■ 

### Selective non

- catalytic reduction (SNCR),

■ 

### Selective catalytic reduction (SCR), and

■ 

### Low NO X 

### burners.

In order to update the existing control measures database, a literature search was conducted using the following terms:

■ 

### reformer

■ 

### cost

■ 

### “ NO X 

### ” or “ nitrogen oxide ”

■ 

### “ Low NO X 

### burner ” or “ LNB ”

■ 

### “ Flue gas recirculation ” or “ FGR ”

■ 

### oxygen trim

■ 

### water injection

■ 

### “ Selective catalytic reduction ” or “ SCR ”

■ 

### “ Selective non catalytic reduction ” or “ SNCR ”

■ 

### emission reduction

■ 

### control effici ency

Due to the use of SCR and SNCR to control NO X 

### emissions and the fact that ammonia is used in the operation of SCR and SNCR, the literature search resulted in NO X 

### reductions on processes other than ammonia production.

### 2

- 2

In order to focus on ammonia production, a focused internet search for operating permits, BACT analyses, and NO X 

### 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 NO X 

### reductions from the production of nitric acid production instead of ammonia production:

■ 

### The NO X 

### emissions from nitric acid production are covered by a New Source Performance Standard (NSPS) codified as Subpart G and Subpart Ga of Part 60.

■ 

### Nitric acid faci lities covered by the NSPS are required to install NO X 

### continuous emission monitoring systems (CEMS).

■ 

### Many nitric acid facilities use SCR to control NO X 

### emissions.

■ 

### Many ammonia production facilities are co

- located with nitric acid production facilities.

Th e internet search resulted in one new NO X 

### reduction project, which was the result of a voluntary agreement between Terra Nitrogen and the Indian Nations Council of Governments to

install “ ultra

- low NO X 

### burner technology to an existing ammonia reformer [and ] reduce the

unit ’ s NO X 

### 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 coll ected for this report, Low NO X 

### 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 NO X 

### 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

- O 3 

### Flex Program . Prepared b y Indian Nations Council of
Governments (INCOG), 201 W. 5 th 

### Street, Suite 600, Tulsa, OK 74103. March 6, 2008. http://www.epa.gov/ozoneadvance/pdfs/Flex

- Tulsa.pdf

.

This addition is shown i n Appendix A as Table A

- 1.

### 2

- 3

2.3 Recommended C hanges

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 CMDB, the following assumptions were made:

■ 

### NO X 

### reductions of 425 tons per year 1

■ 

### Capital cost of $2 million 1

■ 

### Maintenance costs are 2.75% of capital costs 2

■ 

### 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 NO X 

### 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 NO X 

### reduction (in

1990 dolla rs) 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 Code s
. The U.S. Environmental Protection Agency (USEPA) developed the Source Classification Code (SCC) system, which assigns an eight digit code to e ach 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 SCC s, 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

- O3 Flex Program,” March 6, 2008. Downloaded from http://www.epa.gov/ozoneadvance/pdfs/Flex

- Tulsa.pdf

. 2 U.S. E nvironmental Protection Agency

. Alternative Control Techniques Document

— NO X Emissions from Process Heaters (Revised), document EPA

- 453/R

- 93

- 034, dated September 1993

.

### 2

- 4

Table 2

- 1. Applicable SCCs for the Ammonia Production Industry

SCC SCC 1 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 Dioxide 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 NO X 

### emissions for the Ozone Transport R egion 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 NO X


### controls in the current CMDB.

The known control techniques for ammo nia 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 30100310 are recommend ed for the CMDB.

For the purposes of this analysis, SCC 30100399 is assumed to include combustion emissions from gaseous fuels other than natural gas. The refore, 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 NO X 

### emissions from gaseous fuels is assumed to be comparable to the

cost to control NO X 

### emissions from natural gas. Therefore, the costs related to those control techniques are assumed to apply to SC C 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. Cha nges are indicated by

red text.

### 2

- 5

2.4 Other Comments

Control measures used by ICI boilers. Review of NO X 

### 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 b ased 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 regulations or other

sourc es 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 NO X 

### limits for ammonia reformers based on boiler NO X 

### limits. According

to NO X 

### Reasonably Acceptable Control Technology (RACT), 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 appli cable to natural gas ammonia reformers. These RACT limits are

shown in Table 2

- 2

.

Table 2

- 2

. RACT NO X 

### Limits for ICI Natural Gas Boilers

State Boiler Size Limit (lb NO X /MMBTU) Effective Date

New Jersey a >100 MMBTU 0.10 Already in effect

New York >100 MMBTU and  250 MMBTU 0.06 7/1/14

New York > 250 MMBTU 0.08 7/1/14

a The limit also applies to other indirect heat exchangers.

### 3

- 1 SECTION 3

COMBUSTION TURBINES

The CMDB includes the following NO X 

### 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 turbine s (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 turbi nes 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 have water injection (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 for aeroderivative turbines (achieves 40 percent reduction)

All of the cost data are in 1990 dollar s, except the costs of water injection for
aeroderivative 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 in termittently 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

### 3

- 2

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 NO X 

### 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 (R 2 

### ) is 1.0 for many of the regression equations presented in sections 3.2 and 3.3. The R2 v alue 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 for water 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 fo r 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 combu stion turbine control measures in the database

. For several

SCC s 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

sto r age and delivery systems. We recommend deleting these applications of the gas turbine

contr ol meas ures, 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;

### 3

- 3 ■ 

### 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 correl ated with

temperature. One design that has been commercialized is the Xonon TM 

### combustor (now called K

Lean TM 

### ). 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 combu stion 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 s ystem is between 2300 ° F and 27 00 ° 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 have be en 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
( ppm v d ) at 15% oxygen, and permit limits range from 3 ppm v d to 20 ppm v d 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 i ndicating

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, a s 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 u se 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). Th e 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

Bud get . 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

### 3

- 4

concentration of 3 ppm v d , 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 Outlet

Concentration,

ppmv d Cost

Effectiven ess, $/ton NOx Capital to

Annual Cost Ratio Avg. ppmv d tpy

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) ^ 0.57 

### (R 2 

### =1.0)

Total annual cost (1999 dollars) = 4254.2 x (MMBtu/hr) ^ 0.82 

### (R 2 

### =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 D LN combustion versus conventional combustors. Thus, there are no incremental capital costs for catalyt ic 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 (R 2 

### =1.0)

3.2.2 EMx and Water Injection; Gas Turbines

— Natural Gas (NEMXWGTNG)

Like SCR, EMx TM 

### (formerly called SCONOX TM 

### ) 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 CO2, H2O, and N2. NOx reacts with the potassium carbonate absorbent coating the surface of the oxidation catalyst in the EMx reactor , forming potassium

nitrit es 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

### 3

- 5

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. H ydrogen and carbon dioxide react with the potassium nitrites and nitrates to

form N2 and H2O and to regenerat e 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 at 2.5 ppm v d for

gas

- fired operation. EPA has certified it as “ demonstrated in practice ” LAER

- level technology that reduces NOx to less than 5 ppm vd

. 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 reductio n), 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 rec ommend 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 pre sented in a 2008 cost estimate prepared by Emera C hem 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 syste m 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 conting encies 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 d ollar amount for this element.

### 3

- 6 ■ 

### Changed the operating hours from 7

, 884 hr/yr to 8

, 000 hr/yr. This change also had a small effect on the annual cost s for utilities.

■ 

### Added costs for natural gas to generate steam for the 50 MW turbine using the same

p rocedures 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 identifie d 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 MW 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

co sts are the same as for an SCR system on the same tur bines. 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 interes t 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) an d the n 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

- 7

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 wat er injection NOx control measure . With an outlet concentration of 2 ppm vd , this control measure ach ieves an average reduction of 99 percent

relative to uncontrolled conventional diffusion combustion.

Table 3

- 2. Summary of Cost Effectiveness and Supporting Data for EMx Plus Water

Injection

Turbine Output,
MW Cost

Year Uncontrolled NOx

Emissions EMx Outlet

Concentration,

ppmv d Cost

Effectiveness, $/ton NOx Capital to

Annual Cost Ratio Incremental Cost

Relative to RACT Baseline of WI, $/ton NOx Avg

ppmv d tpy

Large (50

- 180) 2008 160 a >365 2.0 2,760 3.1 6,81 0

a 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 R 2 

### =1.0 for both equations because there were only two data points in the analysis):

Total capital i nv estment (2008 dollars) = 196928 x (MMBtu/hr) ^ 0.68



### Total annual c ost (2008 dollars) = 18747 x (MMBtu/hr) ^ 0.86



### Best fit equations for incremental EMx costs relative to a RACT baseline of water injection are:

Total capital investment (2008 dollars) = 15 6349 x (MMBtu/hr) ^ 0.68



### Total annual cost (2008 dollars) = 17252 x (MMBtu/hr) ^ 0.80

### 3

- 8

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 ppm vd , this control measure achieves an average reduction of 99 percent

relative to uncontrolled conventional diffusion combustion. For the same reasons not ed 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 EMx Plus Dry Low

NOx Combustion

Turbine Output,
MW Cost

Year Uncontrolled NOx Emis sions EMx Outlet

Concentration,

ppmv d Cost

Effectiveness, $/ton NOx Capital to

Annual Cost Ratio Incremental

Cost Relative to RACT Baseline of DLN , $/ton
NOx Avg

ppmv d tpy

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 2.0 840 3.9 6,600

Large (50

- 180) 2008 160 a >365 2.0 2,05 0 4. 1 1 2,39 0

a 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 r ecommended 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 b ased 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 ut ilities 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 d ry 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 combust ion in 2008

### 3

- 9

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 consi st of capital recovery plus the cost for parts and repair; capital recovery costs in 2008 dollars were estimated by escalating the 1 999 costs using the CEPCI, and annual parts and repairs costs were assumed to be the same in 2008 as in

1999.

Based on regre ssion of the data in both the 1999 and 2008 cost analys e s, the best fit trend lines are represented by the following power equations for the uncontrolled scenario (the R 2 

### =1.0

for the equations in 2008 dollars because there were only two data points in the analysis ; R 2 

### 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) ^ 0.78



### Total annual cost (1999 dollars) = 15004 x (MMBtu/hr) ^ 0.78



### Total capital investment (2008 dollars) = 126892 x (MMBtu/hr) ^ 0.74



### Total annual cost (2008 dollars) = 20041 x (MMBtu/hr) ^ 0. 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) ^ 0.72



### Total annual cost (1999 dollars) = 13702 x (MMBtu/hr) ^ 0.76



### Total capital investment (2008 dollars) = 156349 x (MMBtu/hr) ^ 0.68



### Total annual cost (2008 dollars) = 17252 x (MMBtu/hr) ^ 0.80



### 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 revisi ons to existing estimates for other control measures. The changes affect both cost per ton values and equations.

### 3

- 10

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. Depa rtment 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 a nd 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 numbe r 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 rec ommendation 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 effectiveness 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 f or all 6 model turbines in the 1993 ACT analysis. Five of those models were guaranteed to reduce NOx emissions to less than 42 ppm v d, while the sixth was guaranteed to meet 25 ppm v d. Although water injection may be more effective on some combustion turbine s than others, 42 ppmv d 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 ppmv d was 72 percent.

Our fourt h 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 ra tio for the small sources with uncontrolled emissions <365 tpy would remain at 3.1 because this is the average

### 3

- 11

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 CMD B.) 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 w as 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 repre sented by the following revised power equations for both uncontrolled and

RACT baseline scenarios:

Total capital investment (1999 dollars) = 27665 x (MMBtu/hr) ^ 0.69 

### (R 2 

### =0.97)

Total annual cost (1999 dollars) = 3700.2 x (MMBtu/hr) ^ 0.95 

### (R 2 

### =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 Fra me 7F turbines (170 MW). 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 t he 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. T his 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 annua l 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

- 12

Total capital investment (1999 dollars) = 43092 x (MMBtu/hr) ^ 0.82 

### (R 2 

### =0.95)

Total annual cost (1999 dollars) = 7282 x (MMBtu/hr) ^ 0. 7 6 

### (R 2 

### =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 de sign 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 NLNBUGTNG to

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. De partment 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 th us 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

ratio s 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

- 13

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 injectio n applied to oil

- fired turbines.

Table 3

- 4

. Summary of Cost Effectiveness and Supporting Data for DLN Combustion

Turbine Output, MW Cost

Year Uncontrolled NOx

Emissions Outlet

Concentration,

ppmv d Cost

Effectiveness, $/ton NOx Capital to

Annual Cost Ratio Avg. ppmv d tpy

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 (R 2 

### =1.0)

Total annual cost (1999 dollars) = 584.5 x (MMBtu/hr) ^ 0.96 

### (R 2 

### =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 instea d of the factor.

### 3

- 14 ■ 

### 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 interes t 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 161 MW turbine using th e 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 inste ad 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 th e 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 effecti veness 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 ca tegories of turbines. Note that the SCR outlet NOx level was assumed to be 2.5 ppm vd in the ECP analysis, which results in an overall control efficiency of 98 percent versus the 94 percent for the OSEC and ACT analyses.

### 3

- 15

Table 3

- 5

. Summary of Cost Effective ness and Supporting Data for SCR Plus Water

Injection

Turbine Output, MW Cost

Year Uncontrolled NOx

Emissions SCR Outlet

Concentration,

ppmv d Cost

Effectiveness, $/ton NOx Capital to

Annual Cost Ratio Incremental Cost

Relative to RACT Baseline of WI, $/ton NOx Avg. ppmv d 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 1,690

Large (50

- 180) 2008 160 a >365 2.5 1,830 2.7 3,170

a 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 (R 2 

### =1 for the 2008 costs because the analysis was based on only two data points) :

Total capital investment (1999 dollars) = 62962 x (MMBtu/hr) ^ 0.66 

### (R 2 

### =1.0)

Total annual cost (1999 dollars) = 8590 x (MMBtu/hr) ^ 0.87 

### (R 2 

### =0.99)

Total capital investment (2008 dollars) = 34533 x (MMBtu/hr) ^ 0.85 

### (R 2 

### =1.0)

Total annual cost (2008 dollars) = 6794 x ( MMBtu/hr) ^ 0.94 

### (R 2 

### =1.0)

Revised best fit equations for incremental SCR costs relative to a RACT baseline of water injection are (R 2 

### =1 for the 2008 costs because the analysis was based on only two data points) :

Total capital investment (1999 dollars) = 37193 x (MMBtu/hr) ^ 0.63 

### (R 2 

### =1.0)

Total annual cost (1999 dollars) = 12065 x (MMBtu/hr) ^ 0.64 

### (R 2 

### =1.0)

Total capital investment (2008 dollars) = 10323 x (MMBtu/hr) ^ 0.96 

### (R 2 

### =1.0)

Total annual cost (2008 dollars) = 3106.1 x (MMBtu/hr) ^ 0.94 

### (R 2 

### =1.0)

### 3

- 16

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 injectio n 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 c osts 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 stea m 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 dolla rs 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 d irect 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 CEPCI, 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 ba seline 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, t he analysis could be improved by combining the SCR costs from both analyses and develop ing a single set of incremental SCR costs.

### 3

- 17

Table 3

- 6

. Summary of Cost Effecti veness and Supporting Data for SCR Plus Steam

Injection (SI)

Turbine Output,
MW Cost

Year Uncontrolled NOx

Emissions SCR Outlet

Concentration,

ppmv d Cost

Effectiveness, $/ton NOx Capital to

Annual Cost Ratio Incremental Cost

Relative to RACT Baseline of SI , $/ton NOx Avg. ppmv d 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 1,810

Large (50

– 180) 2008 160 a >365 2.5 1, 42 0 3.9 3,170

a 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 (R 2 

### =1 for the 2008 costs because the analysis was based on only two data points) :

Total capital investment (1999 dollars) = 72169 x (MMBtu/hr) ^ 0.66 

### (R 2 

### =0.99)

Total annual cost (1999 dollars) = 17551 x (MMBtu/hr) ^ 0.72 

### (R 2 

### =0.98)

Total capital investment (2008 dollars) = 46492 x (MMBtu/hr) ^ 0.82 

### (R 2 

### =1.0)

Total annual cost (2008 dollars) = 8704 x (MMBtu/hr) ^ 0.86 

### (R 2 

### =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 la rge 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

- 18

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 20 07 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 effectiven ess 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 differen t categories of turbines. Note that the SCR outlet NOx level was assumed to be 2.5 ppm vd 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 ppm vd 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 ppm vd , as in other DLN analyses. We also assumed an average uncontrolled

emission s level of 160 ppm vd 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 in jection; this is due to the inlet concentration being 25 ppm vd for this analysis and 42 ppm vd 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 Unc ontrolled NOx

Emissions SCR Outlet

Concentration,

ppmv d Cost

Effectiveness, $/ton NOx Capital to

Annual Cost Ratio Incremental Cost

Relative to RACT Baseline of DLN, $/ton NOx Avg. ppmv d 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 160 a <365 2.5 2,910 4.3 18,900

Small (25) 2007 160 a >365 2.5 1,460 3.8 7,510

Large (50

– 180) 2008 160 a >365 2.5 1,040 4.5 5,560

a 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

- 19

Based on regression of the data in each analysis, the best fit trend lines are represented by the following power equations for uncontrolled scenarios (R 2 

### =1 for the 2008 costs because the analysis was based on only two data points , and note that the R 2 

### 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) ^ 0.79 

### (R 2 

### =1.0)

Total annual cost (1999 do llars) = 12725 x (MMBtu/hr) ^ 0.69 

### (R 2 

### =1.0)

Total capital investment (2007 dollars) = 187647 x (MMBtu/hr) ^ 0.54 

### (R 2 

### =1.0)

Total annual cost (2007 dollars) = 2782 x (MMBtu/hr) + 167494 (R 2 

### =1.0)

Total capital investment (2008 dollars) = 14790 x (MMBtu/hr) ^ 0.97 

### (R 2 

### =1.0)

Total annual cost (2008 dollars) = 5263.5 x (MMBtu/hr) ^ 0.90 

### (R 2 

### =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 investment (2007 dollars) = 210883 x (MMBtu/hr) ^ 0.46 

### (R 2 

### =1.0)

Total annual cost (2007 dollars) = 1894 x (MMBtu/hr) + 185570 (R 2 

### =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 f or 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 mo del in the ACT analysis from 83.3 MW to 84.7 MW because it appears the incorrect

### 3

- 20

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 $1,630/ton of NOx and $960/ton of N Ox, 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 Exc el. 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 (199 9 dollars) = 4 3255 x (MMBtu/hr) ^ 0.60 

### (R 2 

### =1.0)

Total annual cost (199 9 dollars) = 67 96.8 x (MMBtu/hr) ^ 0.80 

### (R 2 

### =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 purchase d cost to 8 percent of the purchased cost.

■ 

### Deleted capital recovery cost for catalyst because the catalyst is replaced annually.

### 3

- 21 ■ 

### The reported annual cost for ammonia was based on a stoichiometric ratio of 1.4 (possibly because they assumed a significant ge neration of NO2 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 f actor (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 to annual cost ratios values for implementing SCR plus water injection on oil

- f ired combustion turbines.

Table 3

- 8 also presents incremental costs of SCR relative to a RACT baseline of water inject ion. 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

I njection (WI) for Oil

- Fired Turbines

Turbine Output, MW Cost

Year Uncontrolled NOx

Emissions SCR Outlet

Concentration,

ppmv d Cost

Effectiveness, $/ton NOx Capital to

Annual Cost Ratio Incremental Cost

Relative to RACT Baseline of WI, $/ton NOx Avg. ppmv d tpy

Small (3.3) 1990 179 <365 18 3,200 2.9 7,620

Small (26.3) 1990 211 >365 18 1,320 2.3 2,450

Large (84) 1990 228 >365 18 1,000 2.4 2,210

Large (48) 2004 200 a >365 5 1,560 2.3 4,790

aThe referenced analysis did not 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 revi sed power equations for the uncontrolled scenario:

Total capital investment (1990 dollars) = 9 5837 x (MMBtu/hr) ^ 0.6 2 

### (R 2 

### =0.99)

Total annual cost (1990 dollars) = 259 90 x (MMBtu/hr) ^ 0.70 

### (R 2 

### =1.0)

Revised best fit equations for incremental SCR costs relative to a RACT baseline of water injection are:

Total capital investment (1990 dollars) = 4 744 x (MMBtu/hr) + 3 68162 (R 2 

### =1.0)

### 3

- 22 Total annual cost (1990 dollars) = 15 22.5 x (MMBtu/hr) + 1 42643 (R 2 

### =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

- f ired turbines. Thus, we recommend the same changes for jet fuel fired turbines as noted above for 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

T he first column in T able 3

- 9 lists all of the gas turbine SCCs that are associated with one or more gas turbine control measures in the CMDB table 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 o 

### W longitud e). The first 11 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 h eadings

are the new control measures identified in this review and described in Section 3.2 of thi s 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 al ready 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 contro ls and related costs for gas turbines fired with such fuels. In order to con duct CoST modeling analyses for these turbines, the most representative available control measures3

- 23 

### Table 3

- 9

. Recommended Control Measures for Gas Turbine SCCs

SCC a SCC

Level 1 b SCC
Level 2 c SCC Level 3 SCC Level 4 Applicable Gas Turbine Control Measures for the SCC d NWTINGTOL NSCRWGTOL NWTINGTJF NSCRWGTJF NWTINGTNG NSTINGTNG NDLNCGTNG NSCRWGTNG NSCRSGTNG NSCRDGTNG NWIGTAGT NCATCGTNG NEMXWGTNG NEMXDGTNG

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 N e N e N e N e N e N e D N e N e N e

20200705 ICE Ind Process Gas Refinery Gas: Turbine N e N e N e N e N e N e D N e N e N e

20200713 ICE Ind Process Gas Turbine: Evap Losses D

20200714 ICE Ind Process Gas Turbine: Exhaust N e N e N e N e N e N e D N e N e N e

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)3

- 24 

### Table 3

- 9. Recommended Control Measures for Gas Turbine SCCs (continued)

SCC a SCC

Level 1 b SCC
Level 2 c SCC Level 3 SCC Level 4 Applicable Gas Turbine Control Measures for the SCC d NWTINGTOL NSCRWGTOL NWTINGTJF NSCRWGTJF NWTINGTNG NSTINGTNG NDLNCGTNG NSCRWGTNG NSCRSGTNG NSCRDGTNG NWIGTAGT NCATCGTNG NEMXWGTNG NEMXDGTNG

20201009 ICE Ind Liquified Petroleum Gas (LPG) Turbine: Exhaust N e N e D

20201011 ICE Ind Liquified Petroleum Gas (LPG) Turbine N e N e D

20201013 ICE Ind Liquified Petroleum Gas (LPG) Turbine: Cogeneration N e N e D

20300102 ICE C/I Distillate Oil (Diesel) Turbine E E

20300108 ICE C/I Distillate Oil (Diesel) Turbine: Evap Losses D D

20300109 ICE C/I Distillate Oil (Diesel) Turbine: Exhaust E E

20300202 ICE C/I Natural Gas Turbine E E E E E E D N N N

20300203 ICE C/I Natural Gas Turbine: Cogeneration E E E E E E D N N N

20300208 ICE C/I Natural Gas Turbine: Evap Losses D D D D D D D

20300209 ICE C/I Natural Gas Turbine: Exhaust E E E E E E D N N N

20300701 ICE C/I Digester Gas Turbine N e N e N e N e N e N e D N e N e N e

20300708 ICE C/I Digester Gas Turbine: Evap Losses D

20300709 ICE C/I Digester Gas Turbine: Exhaust N e N e N e N e N e N e D N e N e N e

20300801 ICE C/I Landfill Gas Turbine N e N e N e N e N e N e D N e N e N e

20300808 ICE C/I Landfill Gas Turbine: Evap Losses D

20300809 ICE C/I Landfill Gas Turbine: Exhaust N e N e N e N e N e N e D N e N e N e

20400301 ICE ET Turbine Natural Gas N N N N N N D N N N

20400304 ICE ET Turbine Landfill Gas N e N e N e N e N e N e D N e N e N e (continued)3

- 25 

### Table 3

- 9. Recommended Control Measures for Gas Turbine SCCs (continued)

SCC a SCC

Level 1 b SCC
Level 2 c SCC Level 3 SCC Level 4 Applicable Gas Turbine Control Measures for the SCC d NWTINGTOL NSCRWGTOL NWTINGTJF NSCRWGTJF NWTINGTNG NSTINGTNG NDLNCGTNG NSCRWGTNG NSCRSGTNG NSCRDGTNG NWIGTAGT NCATCGTNG NEMXWGTNG NEMXDGTNG

50100420 WD SWD

- G Landfill Dump Waste Gas Recovery: GT N e N e N e N e N e N e D N e N e N e

20201609 ICE Ind Methanol Turbine: Exhaust N e N e

20201701 ICE Ind Gasoline Turbine N e N e

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 Classified f N e N e

a SCCs 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 R egion analysis but are not associated with gas turbine control measures in the current CMDB.

b ICE means “ Internal Combustion Engines ” and WD means “ Waste Disposal. ”

c Ind means “ Industrial, ” C/I means “ Commercial/Institutional

, ” ET means “ Engine Testing, ” and SW D

- G means “ Solid Waste Disposal

- Government. ”

d An “ E ” means the c ontrol measure is currently associated with the SCC in the CMDB, an d 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.

e The control measure is assumed to be representative for the SCC; control cost data are unavailable for the specific fuel type for the SCC

.
f 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 testin g SCCs in the analysis done in the Ozone Transport Assessment Group Region were from liquid fuel

- fired turbines.

### 3

- 26

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 several 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 York a Any

— gaseous fuel Combined cycle 42 ppmdv (at 15% O2) Current

Simple cycle or regenerative cycle 50 ppmdv (at 15% O2) Current

Any

— oil

- fired Combined cycle 65 ppmdv (at 15% O2) Current

Simple cycle or regenerative cycle 100 ppmdv (at 15% O2) Current

a The requirements apply to combust ion 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 1, 2014; b eginning on July 1, 2014, o wners/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_AQMD_PDOC.pdf

### 3

- 27

CARB, 2004. California Environmental Protection Agency. Air Re sources 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/l2069.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: www.emera.serveyourmarket.com/ pa pers / SCONOx %20 White %20 Paper %20

- %20r1.pdf

ECP, 2008. EmeraChem Power. Attachment in email from J. Valmus, 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%20eco nomic%20analysis%20final09072008.ashx

EEA, 2008. Energy and Environmental Analysis (An ICF International Company). Technology Characterization: Gas Turbines. Prepared for Environmental Protection Agency Climate Protection Partnership Division. December 200 8. Available at: http://www.epa.gov/chp/documents/catalog_chptech_gas_turbines.pdf

EPA, 1993. U.S. Environmental Protection Agency. Alternative Control Techniques
Document

— NO x 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_syste m_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.distributedenergy.com/DE/Articles/Oil_Producer_Installs_Cogeneration_Syst em_With_Ult_2857.aspx?pageid=62d52359

- b1c7

- 4115

- 9d0d

- 7837abe081cb

### 3

- 28

NYCRR, 20 14. 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.westlaw.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://www1.eere.energy.gov/manufacturing/distributedenergy/pdfs/gas_turbines_nox_c ost_analysis.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.northbaybusinessjournal.com/50863/cogeneration

- plant

- saves

- pacific

- union

college

- 1

- million

- a

- year

- in

- energy

- costs/

RDC, 2001. Reso urce Dynamics Corporation. Assessment of Distributed Generation Technology Applications. Prepared for Maine Public Utilities Commission. February 2001. Available

at: http://www.distrib uted

- generation.com/Library/Maine.pdf

RTI, 2014. Spreadsheet “ Turbines control costs.xlsx .” Prepared for U.S. Environmental Protection Agency. Office of Air Quality Planning and Standards. Air Economics Group. February 7, 2014.

### 4

- 1 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 diff

erent 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 intern et 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 “CoST_ Glass 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 cur rently 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.g ov/About/NRB/2007/January/01

- 07

- 3A4.pdf

### 4

- 2 referen ce 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 produce d 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 );

s ince 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 assum ed 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 manufa cturing 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 a nd Supporting Data for Recommended

Additions

Technology Furnace Production

Rate (ton/day) Cost

Year NOx Removal Efficiency (%) Cost Effectiveness,

$/ton NOx Capital to Annual

Cost Ratio

Electric Boost (general) 250 2002 30 7,100 N/A a

Oxy

- firing General 250 2002 85 2,35 2 2.7

Catalytic Ceramic Filter 490 2013 95 1,045 4.6

600 2013 95 997 4.6

a 

### T he ratio cannot be calculated because capital costs are not available

.

### 4

- 3

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 a nd 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 9 00 ton per day gas fired furnace

, and the

max imum cost per ton estimate was based on a 5 00 ton per day gas fired furnace. For container glass the minimum cost per ton estimate was based on 45 0 ton pe r day gas fired furnace

, and the max imum cost per ton estimate was based on a 20 0 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 b urners 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 0 4 _Equations” of the CMDB based on the best fit trend lines of the total capital investm ent 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 (200 7 dollars) = 30,930 x (tons/day) 0.45 

### (R2 = 0.99)

Total annual cost (200 7 dollars) = 9,377 x (tons/day) 0.40 

### (R2 = 0.99)

NLNBUGMFT (The correlation coefficients are a perfect 1.0 because only two data points are available)

Total capital investment (200 7 dollars) = 527 x (tons/day) + 664,557 (R2 = 1.0)

Total annual cost (200 7 dollars) = 132x (tons/day) + 150,105 (R2 = 1.0)

■ 

### Cullet Pr eheating

— 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 updat ed 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

- 4 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 01_Summary 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 co ntainer, 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 c ost 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 9 00 and 5 00 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 furnace s , 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 si ngle source, and they may reflect data points from a correlation performed by that source)

Total capital investment (200 7 dollars) = 79,415 x (tons/day) 0.51 

### (R2 = 0.99)

Total annual cost (200 7 dollars) = 643 x (tons/day) + 135,302 (R2 = 1.0)

NSCRGMFT (T he correlation coefficients are a perfect 1.0 because only two data points are available)

Total capital investment (200 7 dollars) = 3681 x (tons/day) + 1.0E+06 (R2 = 1.0)

Total annual cost (200 7 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 20 08 average exchange rate of 0.711. Source: http://www.irs.gov/Individuals/International

Taxpayers/Yearly

- Average

- Currency

- Exchange

- Rates

### 4

- 5

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 200 200 7 66 1,365 4.2

450 2007 100 1,072 4.3

NLNBUGMFT 500 2007 371 574 4.2

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 121 2,169 4.5

450 2007 251 1,684 4.2

NSCRGMFT 500 2007 886 957 3.4

900 2007 1,383 855 3.7



### 4.5 Recommended Deletions

■ 

### Selective Non

- Catalytic Reduction

— Three entries for selective non

- catalytic reduction were in the cost database for 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 manufactur ing as shown in Table 4

- 3

.

■ 

### In an analysis of NO X 

### 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 NO X 

### 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

- 6 remaining sixteen SCCs in Table 4

- 3 are not a ssociated 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 techniq ue in Table 01_Summary in the CMDB (Table C

- 1 of 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

30501401 a Industrial Processes Mineral Products Glass Manufacture Furnace/General**

30501402 a Industrial Processes Mineral Products Glass Manufacture Container Glass: Melting Furnace

30501403 a Industrial Processes Mineral Products Glass Manufacture Flat Glass: Melting Furnace

30501404 a 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 Asses s ment 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

a Denotes SCCs included in the CMDB.

### 4

- 7

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://www1.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.jrc.ec.europa.eu/reference/BREF/ GLS_Adopted_03_2012.pdf

Vendor Quote 2013

– Confidential Business Information

### 5

- 1 SECTION 5

LEAN BURN ENGINES

The CMDB includes the following NO X 

### emissions control measures for Lean Burn Engines:

■ 

### Air to fuel ratio (AFR) (achieves 20 percent reduction)

■ 

### Air to fuel ratio (AFR) and I gnition 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) (achieves 90 percent re duction)

■ 

### 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 NO X 

### emissions from Lean Burn Engines.

5.1 Literature Search

In order to update the existing control measures database, a literatur e 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

- 2 ■ 

### air/fuel ratio

■ 

### layered co mbustion

■ 

### 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 Revie w

A brief summary of data from each reference reviewed in included in the spreadsheet

“ CoST_leanburn.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 natura l gas engines);

■ 

### Layered Combustion, LC (for 2 stroke Large Bore natural gas engines);

### 5

- 3 ■ 

### 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 contro l 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/rules/sjvapcd_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 2 010. 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). Infor mation 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 (o n larger engines), lower cost, simple versions, (3) Turbocharger, (4) High energy ignition system,

### 5

- 4

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% None.

Capital costs: provided for multiple models None.

Annual Costs

Equipment life: 10 yr None.

Interest rate: 10% Interest rate: 7%

Operating hours: 2000 hr/yr None.

Emission rate, uncontrolled: 740 ppmv Emission rate, uncontrolled: Assumed mid to upper end hp rating for each model.

Emission rate, controlled: 80% reduction None.

Annualized equipment cost: provided for multiple model sizes CRF: 0.1424

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

- 1 to B

- 28). No detail was provided on the exact combination of combustion modifications included in the example cost analysis ; som e references indicate that LEC on larger engines often includes a PCC (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.

Ca pital 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 c ombustion 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

- 5

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 NO x 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 per cent 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 to $780/ton for 2000 hr/yr operation, and the average cost effectiveness across all the models is
$1,000/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 co st calculations for engines of varying hp, the following equations were developed for the capital cost and annual costs for LEC on natural gas Lean Burn engines:

Capital cost = 16019 e 0.0016 x (hp)



### Annual cost = 2280.8 e 0.0016 x (hp)



### The R 2 

### 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 cos ts; 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 curr ent 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

- 6

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 Changes to Assump tions M ade in Current Analysis

Capital costs

Control efficiency: Not provided. Control efficiency: derived value is 97% (this is high)

Capital costs: based on cited ERLE 2009 project (First unit upgrade costs) Capital costs: used average based on the provided range for each make/model engine.

Annual Costs

Equipment life: Not provided. Equipment life: 10 yr

Interest rate: Not provided. Interest rate: 7%

Operating hours: Not provided. Operating hours: 2000 hr/yr

Emission rate, uncontrolled: Not provided Emission rate, uncontrolled: 16.8 g/bhp

- hr

Emission rate, controlled: 0.5 g/bhp

- hr None.

Annualized equipment cost: Not provided. CRF: 0.1424

Annual O&M cost: Not provided. 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 achieve the outlet NOx limit for each engine. An average cost based on the range was estimated for each engine and used in the current analysis. Details on the

buildu p 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

additi onal 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 N Ox 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

- 7

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 h p 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 co st 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 21 through 25.

5.5 Layered Combustion (LC), Large Bore, 2 Stroke , Low Speed (NLCICE2SLBNG)

The co sts 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 (OTC 2012). 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 dete rmine Annual costs, uncontrolled emissions, and reduction efficiency. The assumptions for the original reference analysis are provided in Table 5

- 3 for LC for large bore 2 Stroke engines, along with changes in assumptions for the current analysis.

LC consi sts of multiple combustion modification technologies. The combus tion
modifications included (1) Hi gh 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 c opy 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

- 8

Based on the review of other refer ences 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 estimat e of emissions was made in the current analysis. Uncontrolled NOx

Table 5

- 3

. LC for Natural Gas Lean Bu rn Engines, Large Bore 2

- stroke

Assumptions in Original Reference Changes to Assumptions Made in Current Analysis

Capital costs

Control efficiency: Not provided. Control efficiency: derived value is 97% (this is high)

Capital costs: based on cited Cameron 2010 project None.

Annual Costs

Equipment life: Not provided. Equipment life: 10 yr

Interest rate: Not provided. Interest rate: 7%

Operating hours: Not provided. Operating hours: 2

, 000 hr/yr

Emission rate, uncontrolled: Not provided Emission rate, uncontrolled: 16.8 g/bhp

- hr

Emission rate, controlled: 0.5 g/bhp

- hr None.

Annualized equipment cost: Not provided. CRF: 0.1424

Annual O&M cost: Not provided. 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 sh ows a cost effectiveness of $1,500/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

- 9

5.6 Air to Fuel Ratio Controller (AFRC) (NAFRCICENG)

The costs and cost effectiveness for applying AFRC to natural gas Lean Burn en gines 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; as sumptions 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 Changes to Assumptions Made in Current Analysis

Capital costs

Control efficiency: not provided Control efficiency: assumed 20%

Capital costs: provided for multiple models None.

Annual Costs

Equipment life: 10 yr None.

Interest rate: 10% Interest rate: 7%

Operating hours: 2000 hr/yr None.

Emission rate, uncontrolled: 740 ppmv Emission rate, uncontrolled: Assumed mid to upper end hp rating for each model.

Emission rate, controlled: 80% reduction None.

Annualized equipment cost: provided for multiple model sizes CRF: 0.1424

Annual O&M cost: assumed $0. None.



### AFRC are electronic engine controls that typically monitor engine parameters and atmospheric conditions to dete rmine 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

th e original reference, CARB 2001, pp. B

- 1 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 cons umption 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

- 10

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 analys is, 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. Uncontrol led 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
$ 1 4 0 /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 fo llowing 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 R 2 

### 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

- 11

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 mul tiple 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 Changes to Assumptions Made in Current Analysis

Capital costs

Control efficiency: 90% None.

Capital costs: based on RACT/BARCT Determination. None.

Annual Costs

Equipment life: 10 years None.

Interest rate: 10% Interest rate: 7%

Operating hours rate 1: 2190 hr/yr (equivalent to capacity factor of 0.25) None.

Operating hours rate 2: 6570 hr/yr (equivalent to capacity factor of 0.75) None.

Emission rate, uncontrolled: 740 ppmv NOx None.

Emission rate, controlled: 65 ppmv NOx None.

Annualized equipment cost: based on RACT/BARCT Determination. None.

Annual O&M cost: based on RACT/BARCT Determination. 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 co sts 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 provi ded 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 cap acity 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

- 12

effectiveness of $8,700/ton of NOx reduction for 2190 hr/yr of operation, and $2,900/t on 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 lin ear 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 R 2 

### value s for these equations are 0.95 for capital cost and 0 .9 8 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 c ost 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 SJVAPCD SCR analysis, and other analyses. See t he 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 analysi s 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 sta ndby applications.

### 5

- 13

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 th an 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 gr eater 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 O riginal 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/yr operation; already includes Capital Recovery) None.



### 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 values 1 

### 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 reductio n 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

- 14

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 w hile 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

va lues are higher for later model years.

[Note: This analysis shows emission reductions and cost effectiveness for existing and new diesel engines through approximately 2011, the last year for phase in of the Tiered emission values. The original reference pr ovided 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 d ata 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 (EP A 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 100oW 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 t his 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 fue ls such as process gas, methanol, digester gas, or landfill gas. While we have not5

- 15 

### Table 5

- 7. Potential Reciprocating Engine SCCs to Add to the CMDB and Applicable Control Measures

SCC a SCC

Level 1 b SCC
Level 2 c SCC Level 3 SCC Level 4 Applicable Control Measures for the Reciprocating Engine SCC d NAFRICGS NAFRIICGS NIRICGD NIRICGS NIRICOL NIRRICOIL NSCRICGD NSCRICGS NSCRICOL NSCRRICOIL NSNCRICGS

20200702 ICE Ind Process Gas Reciprocating Engine N N N N N

20200712 ICE Ind Process Gas Reciprocating: Exhaust N N N N N

20201602 ICE Ind Methanol Reciprocating Engine N N

20201607 ICE Ind Methanol Reciprocating: Exhaust N 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 Engine Liquified Petroleum Gas (LPG) N N

a SCCs represent reciprocating engine activities that 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.

b ICE mean s “ Internal Combustion Engines. ”

c Ind means “ Industrial, ” C/I means “ Commercial/Institutional, ” and ET means “ Engine Testing. ”

d The control measure is assumed to be representative for the SCC; control cost data are unavailable for the specific fuel type for the SCC.

### 5

- 16

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 ana lyses 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 miscellaneo us 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 cont r ol 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

CMD B, 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 misassigne d to turbine SCCs and we recommend deleting these NOx control measure/SCC records. The reverse issue also exists where multiple t urbine control measures are mis assigned 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 Pr ocessing 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 c ertain control

measures are shown for lean burn and rich burn engines in Table 5

- 11.5

- 17 

### Table 5

- 8. Recommended New Control Measures to Associate With Lean Burn Reciprocating Engine SCCs in the CMDB

SCC a SCC Level 1 SCC Level 2 SCC Level 3 SCC Level 4 Applicable Control Measures for the Lean Burn Reciprocating Engine SCC NLECICENG NLCICE2SNG NLCICE2SLBNG NAFRCICENG NSCRICE4SNG NSCRICEDS

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

20200401 b Internal Combustion Engines Industrial Large Bore Engine Diesel Y

20200402 b 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

a SCCs represent reciprocating engine activities that were identified with NOx emissions in the recent Ozone Transport Region a nalysis but are not associated with reciprocating engine control measures in the current CMDB.

b The control measure is assumed to be representative for the SCC; control cost data are unavailable for the specific fuel type for the SCC.5

- 18 

### Table 5

- 9. Recommended Control Measure Deletions From SCCs in the CMDB

SCC 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: Evap
L osses All NOx control measures

20200206 Internal Combustion Engines Industrial Natural Gas Reciprocating: Evap
Losses All NOx control measures

20200306 Internal Combustion Engines Industrial Gasoline Reciprocating: Evap
Losses All NOx control measures

20200406 Internal Combustion Engines Industrial Large Bore Engine Reciprocating: Evap
Losses All NOx control measures

20200506 Internal Combustion Engines Industrial Residual/Crude Oil Reciprocating: Evap
Losses All NOx control measures

20200906 Internal Combustion Engines Industrial Kerosene/Naphtha (Jet Fuel) Reciprocating: Evap
Losses All NOx control measures

20201006 Interna l Combustion Engines Industrial Liquified Petroleum Gas (LPG) Reciprocating: Evap
Losses All NOx control measures

20300106 Internal Combustion Engines Commercial/Institutional Distillate Oil (Diesel) Reciprocating: Evap
Losses All NOx control measures

20300206 Internal Combustion Engines Commercial/Institutional Natural Gas Reciprocating: Evap
Losses All NOx control measures

20300306 Internal Combustion Engines Commercial/Institutional Gasoline Reciprocating: Evap
Losses All NOx control measures

20301006 Internal Combustion Engines Commercial/Institutional Liquified Petroleum Gas (LPG) Reciprocating: Evap
Losses 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)5

- 19 

### Table 5

- 9. Recommended Control Measure Deletions From SCCs in the CMDB (continued)

SCC 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 G as 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)5

- 20 

### Table 5

- 9. Recommended Control Measure Deletions From SCCs in the CMDB (continued)

SCC 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, NWTINGTNG

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, NWTINGTOL

20300107 Internal Combustion Engines Commercial/Institutional Distillate Oil (Diesel) Reciprocating: Exhaust NSCRWGTOL, NWTINGTOL

20300205 Internal Combustion Engines Commercial/Institutional Natural Gas Reciprocating: Crankcase Blowby NLNBUGTNG, NSCRLGTNG, NSCRSGTNG, NSCRWGTNG, NSTINGTNG, NWTINGTNG

20300207 Internal Combustion Engines Commercial/Institutional Natural Gas Reciprocating: Exhaust NLNBUGTNG, NSCRLGTNG, NSCRSGTNG, NSCRWGTNG, NSTINGTNG, NWTINGTNG

### 5

- 21

Table 5

- 10

. NOx Control Requirements for RICE in Pennsylvania

State Source Category

Cover ed NOx Control Leve l R e ference

Pennsylvania 153 ton NOx/season ≥2400 hp: 3 g/bhp

- hr (220 ppm) IEPA 2007

Pennsylvania ( proposed values ) [Assume proposal was 2011Mar26] 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) N atural G as 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 DEP 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 Emissions and Controls for RICE

Engine Type and Size Uncontrolled

Emissions Emissions Cost Effectiveness for NOx Reductions Reference

Lean burn

LB >500 hp NA SCR, stack test, 0.22 to 0.50 g/bhp

- hr SCR: $71,000 to $60,000/ton

(for 500 to 4000 hp) PA DEP 2013,

p. 22

LB 100 to 500 hp 1 to 16.4 g/bhp

- hr NA SCR: >$42,000/ton PA DEP 2013,

p. 20

LB <100 hp 2 g/bhp

- hr 2 g/bhp

- hr SCR: > $48,000/ton PA DEP 2013,

p. 17

Rich burn

RB >500 hp 13 to 16 g/bhp

- hr NSCR: stack test, 0.02 to 0.14 g/bhp

- hr NA PA DEP 2013,

p. 28, 29

RB 100 to 500 hp 13 to 16.4 g/bhp

- hr. NA NSCR: $177/ton PA DEP 2013,

p. 25, 26

RB <100 hp 11.41 to 21.08 g/bhp

hr NSCR: <2 g/bhp

- hr, at least 90% reduction NSCR: <$650/ton for 100 hp

NSCR: <$1200/ton for 50 hp PA DEP 2013,

p. 17

### A

- 1 APPENDIX A

AMMONIA REFORMERS

Copies of database tables showing all records for ammonia reformer controls, highlighting revisions

.A

- 2 

### Table A

- 1. 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

- O3 Flex Program,” March 6, 2008. Downloaded from http://www.epa.gov/ozoneadvance/pdfs/Flex

- Tulsa.pdfA

- 3 

### Table A

- 2. CMDB Table 01 Summary

cmname Cm

Abbreviation Pechan

Meas Code Major

Poll Control Technology 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

Reformers ptnonipm Known 10 204|205 2013 AR

- 1 |186 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 redu ce 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

Reformers 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 tem perature 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 g reater 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 th e 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

Reformers ptnonipm Known 10 2006 72 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 oper a tions with oil

- fired reformers (SCC 30100307).

Discussion: LNBs are designed to “ stage ” combu stion 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 comb ustion 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 30100305) 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 fue l

- 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 Oxygen Trim and Water Injection Ammonia

— NG

- Fired

Reformers ptnonipm Known 10 2006 72|172|175| 179|184|18
5 Application: This control is the use of OT + WI 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 (ER G, 2000). (continued)A

- 4 

### Table A

- 2. CMDB Table 01 Summary (continued)

cmname Cm

Abbreviation Pechan

Meas Code Major

Poll Control Technology 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

Reformers ptnonipm Known 20 139 2006 72|167|175| 179|224|22 5|226 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 ( H2O). The SCR utilizes a catalyst to increase the NOx removal efficiency, which allows th e 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, 20 02).

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 ammoni a 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, 200 2). 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.
Selective Catalytic Reduction; Ammonia

— Oil

Fired Reformers NSCRFROL N0573 NOx Selective Catalytic Reduction Ammonia

— Oil

- Fired

Reformers ptnonipm Known 20 139 2006 72 Application: This control is the selective catalytic reduction of NOx through add

- on controls. SCR controls are post

- combustion control technologie s based on the chemical reduction of nitrogen oxides (NOx) into molecular nitrogen (N2) and water vapor (H2O). 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, combus tion 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 s electively 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 cat alyst 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 operati onal 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; mol ar 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)A

- 5 

### Table A

- 2. CMDB Table 01 Summary (continued)

cmname Cm

Abbreviation Pechan

Meas Code Major

Poll Control Technology 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

Reformers 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 (H2O).

This control applies to small (<1 ton NOx per OSD) ammonia production natural gas fired reformer s (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 la rge 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 anh ydrous 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 an d 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 c an 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

Reformers 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 nitro gen 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 t o “ 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 flam e 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 lo wer combustion temperatures (EPA, 2002).
Selective Non

Catalytic Reduction

— Ammonia; Oil

Fired Reformers NSNCRFROL N0574 NOx Selective Non

- Catalytic Reduction Ammonia

— Oil

- Fired

Reformers 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 (H2O).

This c ontrol 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 nitrog en 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 considerati ons (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 sto red 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 appli cations. (continued)A

- 6 

### Table A

- 2. CMDB Table 01 Summary (continued)

cmname Cm

Abbreviation Pechan

Meas Code Major

Poll Control Technology 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

- 1|186 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 emission s 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 suppl y 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 NLNBFAON C NOx Low NOx Burner and Flue Gas Re circulation 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 c ombustion 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 NSNCR AONC NOx Selective Non

- Catalytic Reduction Ammonia

Production

— Other Not Classified ptnonipm Known 20 107 2013 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 (H2O).

This control is applicable to miscellaneous combustion emissions from ammonia production operations (SCC 30100399).

Discussion: SNCR is the reduction of NOx i n 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
reage nt 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 u se 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 safet y 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 advant ages, urea is more commonly used than ammonia in large boiler applications. Oxygen Trim and Water Injection; Ammonia Production; Other Not Classified NOTWI AONC NOx Oxygen Trim and Water Injection Ammonia

Production

— Other Not Classified ptnonipm Known 10 2013 72|172|175| 179|184|18
5 Application: This control is the use of OT + WI 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)A

- 7 

### Table A

- 2. CMDB Table 01 Summary (continued)

cmname Cm

Abbreviation Pechan

Meas Code Major

Poll Control Technology 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 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 (H2O). The SCR utilizes a catalyst to increase the NOx removal efficiency, which allows the process to occur at lower temperatures.

This con trol 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 cont rol 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 d ifference 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 temperat ure 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, 20 02). Aqueous ammonia is generally transported and stored at a concentration of 29.4% ammonia in water.A

- 8 

### 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

### B

- 1 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

- 1. CMDB Table 01_Summary

– Table B

- 2. CMDB Table 02_Efficiencies

– Table B

- 3. CMDB Table 04_Equations

– Table B

- 4. Additional C MDB Table 06_ReferencesB

- 2 

### Table B

- 1. CMDB Table 01_Summary

cmname cmabbreviation pechanmea scode majorpoll controltechnology sourcegroup sector class equiplife neidevicecode datereviewed datasource months Dry Low NOx Combustion; Gas Turbines

— Natural Gas NDLNCGTNG N0243 NOx Dry Low NOx Combustion Gas Turbines

—

Natural Gas ptnonipm Known 15 204|205 2013 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 15 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 ptnonipm Known 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 NOx EMx and Water Injection Gas Turbines

—

Natural Gas ptnonipm Emerging 15 2013 CT

- 1|CT

- 3

*For ease in reading this table, the Description field is included on separate pages

.B

- 3 

### Table B

- 1. CMDB Table 01_Summary (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 tw o 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 (EP A, 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 (H2O). 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.

Discu ssion: 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 achi evable 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 wit h the flue gas NOx within a specific temperature range and in the presence of the catalyst and oxygen to reduce the NOx.

The u se of a catalyst results in two advantages of the SCR process over SNCR, the higher NOx reduction efficiency and the lower an d broader temperature ranges. However, the decrease in reaction temperature and increase in efficiency is accompanied by a signific ant 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 a nd 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, ca talyst 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 tha t 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 selectivi ty; pressure drop across the catalyst; ca talyst 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 (H2O). The SCR utilizes a catalyst to increas e the NOx removal efficiency, which allows the process to occur at lower temperatures.

This control applies to natural gas fired t urbines with NOx emissions greater than 10 tons per year. (continued)B

- 4 

### Table B

- 1. CMDB Table 01_Summary (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 r eduction 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 pres sure 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 concentra tion of 29.4% ammonia in water.

Today, catalyst formulations include single component, multi

- component, or active phase with a sup port 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 imp ortant 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 a nd the combustion gases; uncontrolled NOx concentration level; molar ratio of injected reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivi ty; 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 (H2O). 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

ra te of reaction (EPA, 2002). A nitrogen based reducing reagent, such as ammonia or urea, is injected into the flue gas. The reagent reacts selectively wit h the flue gas NOx within a specific temperature range and in the presence of the catalyst and oxygen t o 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 low er 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% amm onia in water. (continued)B

- 5 

### Table B

- 1. CMDB Table 01_Summary (continued)

cmabbreviation Description

NSCRWGTJF (cont.) 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 tha t affect the rate of reduction include: reaction temperature range; residence time available in the optimum temperatu re 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 selectivi ty; pressure drop across the cat alyst; 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 (H2O). 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, combusti on 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 N Ox 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 sel ectively 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 re quired.

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 sto red 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 cataly st 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 operation al 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 a nd the combustion gases; uncontrolled NOx concentration level; molar ratio of injected reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop across th e 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 vapo r (H2O). 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: Se lective 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)B

- 6 

### Table B

- 1. CMDB Table 01_Summary (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 that SC R uses a metal

- based catalyst to increase the

rate of reaction (EPA, 2002). A nitrogen based reducing reagent, such as ammonia or u rea, 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 proc ess 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). T he 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 pres sure and normal temperatures. There are safety issues with the u se of anhydrous ammonia, as it must be transported and stored under pressure (EPA, 2002). Aqueous ammonia is generally transp orted and stored at a concentration of 29.4% ammonia in water.

Today, catalyst formulations include single component, multi

- compon ent, 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 rem oved 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 a nd the com bustion gases; uncontrolled NOx concentration level; molar ratio of injected reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivi ty; pressure drop across the catalyst; catalyst pitch; catalyst deactivation; and catalyst manageme nt (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.

Dis cussion: 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 t emperatures 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 contr ol 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 turbine s 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 com bustion chamber (ERG, 2000). (continued)B

- 7 

### Table B

- 1. CMDB Table 01_Summary (continued)

cmabbreviation Description

NCATCGTNG Application: This control is the use of cat a lytic 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 mixtur e 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 catalys t oxidizes NO to NO2, CO to CO2, and VOC to CO2 and water. The NO2 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 t he catalyst to desorb the NO2 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 combust i on 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 ad ded 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 cost 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 the EMx system.B

- 8 

### Table B

- 2. CMDB Table 02_Efficiencies

cmabbreviation pollutant locale Ef fective Date existingmeasureabbr neiexistingdevcode minemissions maxemissions controlefficiency costyear costperton ruleeff rulepen equationtype caprecfactor discountrate capannratio incrementalcpt details

NWTINGTNG NOx 0 0 365 72 1999 1790 100 100 cpton 0.1098 3.1 Applied to small source types (<34.4 MW), uncontrolled emissions <365 tpy
NWTINGTNG NOx 0 365 72 1999 1000 100 100 cpton 0.1098 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 1 96 0 100 100 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

r esulting 2008 costs were added to the 2008 SCR costs from ref CT

- 3.
NEMXWGTNG NOx 0 365 99 2008 29 60 100 100 cpton 0.1098 2.9 712 0 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 0 365 80 1999 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 0 365 80 1999 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 0 365 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).

N SCRSGTNG 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.B

- 9 (continued) 

### Table B

- 2. CMDB Table 02_Efficiencies (continued) cmabbreviation pollutant locale Effective Date existingmeasureabbr neiexistingdevcode minemissions maxemissions controlefficiency costyear costperton ruleeff rulepen equationtype caprecfactor discountrate capannratio incrementalcpt details

NSCRSGTNG NOx 0 365 95 1999 1380 100 100 cpton 0.1098 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 cpton 0.1098 5 540 Applied to small source types
NDLNCGTNG NOx 0 365 84 1999 130 100 100 cpton 0.1098 7.4 140 Applied to large source types
NSCRDGTNG NOx 0 0 365 94 1999 1800 100 100 cpton 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 0 365 99 2008 204 0 100 100 cpton 0.1098 4. 1 1 237 0 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 0 365 98 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 0 365 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 0 365 98 1999 370 100 100 cpton 0.1098 0.7 2200 Applied to large source types (~170 MW)
NWTINGTOL 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, 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.B

- 10 (continued) 

### Table B

- 2. CMDB Table 02_Efficiencies (continued) cmabbreviation pollutant locale Effective Date existingmeasureabbr neiexistingdevcode minemissions maxemissions controlefficiency costyear costperton ruleeff rulepen equationtype caprecfactor discountrate capannratio incrementalcpt details

NWTINGTOL 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, 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 ana lysis 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 0 365 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 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, costs assumed to be same as for oil

- fired turbines.
NSCRWGTJF 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, 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).B

- 11B

- 12 

### Table B

- 3. CMDB Table 04_Equations a

cmabbreviation cmeqntype pollutant costyear var1 var2 var3 var4 var5 var6 var7 var8 var9 var10

NWTINGTNG Type 2 NOx 1999 27665 0.69 3700.2 0.95 27665 0.69 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 1 60409 0.6 7 20174 0. 7 8

NSTINGTNG 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 2 305 1 0. 7 8 1 60409 0.6 7 20174 0. 7 8

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

a Type “ L ” is a linear equation; variables are 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.B

- 13 

### 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/sit ingcases/marshlanding/documents/other/2010

- 03

- 24_Bay_Area_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://www1.eere.energy.gov/manufacturing/distributedenergy/pdfs/gas_turbines_nox_cost_analysis.pdf

CT

- 3 EmeraChem Power, 2008. Attachment in email from Jeff Valmus, EmeraChem Power, to Weyman Le e, BAAQMD. Request for EMx Cost

Information. September 8, 2008. Available at: http://www.baaqmd.gov/~/media/Files/Engineering/Public%20Notices/2010/18404/Footnotes/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/documents/applicant_files/volume_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/l2069.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.distributed

- generation.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/emission/construction/stockisland/BasisofBACT.pdf and http://www.dep.state.fl.us/air/emission/co nstruction/stockisland/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/documents/catalog_chptech_gas_turbines.pdf

### C

- 1 APPENDIX C

GLASS MANUFACTURING

Copies of database tables showing all records for glass manufacturing controls, highlighting revisions

.C

- 2 

### Table C

- 1. CMDB Table 01 Summary

cmname cmabbreviation pechanm eascode major

poll controltechnology sourcegroup Sector Class equiplife 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

- Firing; 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

- Firing; Glass Manufacturing

— General NOXYFGMGN N0306 NOx OXY

- Firing Glass Manufacturing

— Container ptnonipm Known 10 2013 GM

- 1

OXY

- Firing; Glass Manufacturing

— Container NOXYFGMCN N0306 NOx OXY

- Firing Glass Manufacturing

— Container ptnonipm Known 10 2006 72

OXY

- Firing; Glass Manufacturing

— Flat NOXYFGMFT N0315 NOx OXY

- Firing Glass Manufacturing

— Flat ptnonipm Known 10 2006 72

OXY

- Firing; 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 CATCFGMFT NOx Catalytic Ceramic Filter Glass Manufacturing

—

Flat ptnonipm Known 20 2013 GM

- 3C

- 3 

### Table C

- 1. 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 combustio n 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 or iginally developed to improve the combustion efficiency primarily by eliminating the sensible heat lost in heating the nitrogen presen t in air, which is then lost in the flue gas.
NELBOGMGN Application: This control is the use of electric boost technologi es to reduce NOx emissions from glass manufacturing operations.

This control applies to general glass manufacturing operati ons classified under SCC 305014 0 1

. 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 manufac turing 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 emiss ions 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 emiss ions 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 o f 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 3050 10404 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 crea ted, 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 primar y 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)C

- 4 

### Tabl e C

- 1. 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 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 g eneral manufacturing operati ons. This control applies to general glass manufacturing operations classified under SCC 305014 0 1.

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.

NOXYFGMCN Application: This control is the use of OXY

- firing in container glass manufacturin g 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 b asic 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 l ost in the flue gas. Many other combustion modification techniques (e.g., flue gas recirculation, staged com bustion, 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 presen t 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 a ir

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 l ost in the flue gas. Many other combustion modification techniques (e.g., flue gas recirculation, staged co mbustion, 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 presen t 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 combusti on

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 o riginally developed to improve the combustion efficiency primarily by eliminating the sensible heat lost in heating the nitrogen presen t in air, which is then lost in the flue gas. (continued)C

- 5 

### Table C

- 1. 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 technologies based on the chemical reduction of nitrogen oxides

(NOx) i nto molecular nitrogen (N2) and water vapor (H2O). The SCR utilizes a catalyst to increase the NOx removal efficiency, which allows the process to occur at lower temperatures.

Applies to glass

- container manufacturing processes, classified under SCC 305014 02 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 wit h the flue gas NOx within a specific temperature range an d 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 low er and broader temperature ranges. However, the decrease in react ion temperature and increase in efficiency is accompanied by a significant increase in capital and operating costs (EPA, 2002). T he cost increase is due to the large amount of catalyst required.

The SCR system can utilize either aqueous or anhydrous ammon ia 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, pr oviding 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 tha t affect the rate of reduction include: reactio n temperature range; residence time available in the optimum temperature range; degree of mixing between the injected reagent and the combustion gases; unco ntrolled 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 cataly st 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 (H2O). The SCR utilizes a catalyst to increase the NOx removal efficiency, which allows th e process to occur at lower temperatures.

Applies to large(>1 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 wide ly 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 pr ocess 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

- comp onent, 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 r emoved 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 c ombustion 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; c atalyst deactivation; and catalyst manage ment (EPA, 2001). (continued)C

- 6 

### Table C

- 1. 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 technologies based on the chemical reduction of nitrogen oxides

(NOx) into molecular nitrogen (N2) and water vapor (H2O). The SCR utilizes a catalyst to increase the NOx removal efficiency, which allows the 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, fo ssil 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 ch emical 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 ga s. 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 red uction 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). T he cost increase is due to the la rge 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 mu st 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 suppo rt 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 impor tant 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; unco ntrolled NOx c oncentration level; molar ratio of injected reagent to uncontrolled NOx; ammonia slip; catalyst activity; catalyst selectivity; pressure drop across the catalyst; catalyst pitch; c atalyst deactivation; and catalyst management (EPA, 2001).
CATCFGMFT Application: Filter tubes have nanobits of proprietary catalyst are embedded throughout the filter walls. The system can achi eve 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 classified under SCC 305014 03C

- 7 

### Table C

- 2. CMDB Table 02 Efficiencies

cmabbreviatio

n polluta

nt loca le Effec tive
Date existing

measure abbr neiexistingd

evcode minemi ssi

ons maxemissi

ons controleffi

ciency costyea

r costperton ruleeff rulepen equation type caprecfact

or discou
ntrate capannr

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 40 200 7 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

NOx YFGMCN NOx 0 0 365 85 1990 4590 100 100 cpton 0.1424 2.7 Applied to small source types

NOx YFGMCN NOx 0 365 85 1990 4590 100 100 cpton 0.1424 2.7 Applied to large source types

NOx YFGMFT NOx 0 365 85 1990 1900 100 100 cpton 0.1424 2.7 Applied to large source types

NOx YFGMFT 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

NOx YFGMPD NOx 0 0 365 85 1990 3900 100 100 cpton 0.1424 2.7 Applied to small source types

NOx YFGMPD NOx 0 365 85 1990 3900 100 100 cpton 0.1424 2.7 Applied to large source types

NOx YFGMGN 365 0 85 2002 235 3 100 100 cpton 0.1424 2.7 Applied to large source types

NOx YFGMGN 0 365 85 2002 235 3 100 100 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)C

- 8 

### 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 caprecfact

or discou
ntrate capannr

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 typesC

- 9 

### 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 Technologies. April 2002. Available at:

http://www1.eere.energy.gov/manufacturing/resources/glass/pdfs/airstaging.pdf

GM

- 2 Best Available Techniques (BAT) Reference Document for the Manufacture of Glass. European Commission 2013. Available at:

http://eippcb.jrc.ec.europa.eu/reference/BREF/GLS_Adopted_03_20 12.pdf

GM

- 3 Confidential Vendor Quote



### Table C

- 4. CMDB Table 04_Equations a

cmabbreviation cmeqntype pollutant costyear var1 var2 var3 var4 var5 var6 var7 var8 var9 var10

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

a Type “ L ” is a linear equation; variables are the slope and intercept.

### D

- 1 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_ReferencesD

- 2 

### Table D

- 01_Summary

cmname cmabbreviation pechanme ascode majorp

oll 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 an d 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% redu ction; 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 Lean

Burn ICE

— NG PTNONIPM 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 NOx Selective Catalytic Reduction ICE

— Diesel PTNONIPM Known 7 9/15/2013 ABCD4 SCR can be used on Diesel engines.D

- 3 

### Table D

- 02_Efficiencies

cmabbreviation polluta

nt local

e Effec tive
Date existing

measur eabbr neiexi stingd evcod

e mine missio

ns maxemis sions controle fficiency costyear costperton ruleeff rulepe

n equation type caprecfac

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 NAD

- 4 

### Table D

- 03_SCCs

cmabbreviation Source Classification 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 20200107D

- 5 

### Table D

- 04_Equations

cmabbreviation cmeqntype pollutant costyear var1 var2 var3 var4 var5 var6 var7 var8 var9 var10

NSCRICE4SNG linear capital and annual N O x 2001 107.1 27186 83.64 14718

NLECICENG capital and annual N O x 2001 16019 0.0016 2280.8 0.0016

NAFRCICENG linear capital and annual N O x 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.gov/pm/pmmeasures/ceffect/rules/sjvapcd_4702.pdf

ABCD3 CARB 2001. Determination of Reasonably Available Control Technology and Best Available Retrofit Control Technology for

Stationary Spark

- Ignited Internal Combustion Engines. C alifornia 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.

### E

- 1 APPENDIX E

NOTES PROVIDED HERE TO EPA QUESTIONS ON LEAN BURN RICE

### E

- 2

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 perc ent 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 IC engines” in general (including NSCR,
SCR, oxidation, and Lean

- NOx), it is noted that “Thousands of stationary IC engine catalyst
appl ications have been effectively used for stationary IC 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 exhau st 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 technol ogies 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 O 2 

### and T are at expected levels

### E

- 3

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 simil ar 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 indica ted 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 generically but that individual 2S LB engine

character istics 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 sta ted 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 syste ms, 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 cite d : 4 SCRs supplied at Pine Prairie Energy Center, Louisiana; 1 SCR supplied at EXTERRAN/TRESPALACIOS, Texas; and 4 SCRs suppl ied 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

- 4

[assumed this referred to ca pital 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

compressor s at 2 locations, including Loudon Compressor Station in Clarksburg, WV and Lodi Compressor/Storage in Kirby Hills, CA. (Chu 2011) These e ngines are listed in the following

table:

SCR for Lean Burn Engines

— Johnson Mathey presentation at 2007 MARAMA Worksh op

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 0.7 90%

CAT G3616 4

, 735 0.7 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 Gas Sector, Significant Stationary Sources of NOx Emissions. Final. October 17, 2012.

### E

- 5

EPA Question 2: What are credible estimates of the percentage of RICE NOx Emissions that are lean burn versus rich burn when RICE emissi ons 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 note d 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 engin es /horsepower capacity covered in their study of NG pipeline systems are LB , and approximately 6% are RB
(the balance is no t known). In t he KSU 2011 database

, approximately 66% of the 4,729 engines used in E&P at major sources are LB and 34% are RB

. In add ition, 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% a re 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

e missions rate for RB engines tends to be lower. (See the table s 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 th e 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 A merica (INGAA) on the 2002 proposed rule, where EPA indicated that 156 of 168 large engines listed in

### E

- 6

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 a re 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 Inter nal 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. (IEPA 2007)

A 2009 ERLE study cited in th is reference indicated there are 5,600 engines on the NG pipeline systems with a collective rating of 9,150,000 hp. That study further indicate d that approximately 80 percent of the rated output was low speed 2S, low speed 4S integral engines

and diesel me dium 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 11%, 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: 7 1% 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 Typ e U.S

. Total Units (%) Avg hp

2S LB 2

, 955 (44%) 2

, 113

4S LB 1

, 059 (16%) 1

, 844

RB 1

, 672 (25%) 589

Turbine 1

, 016 (15%) 6

, 121

### E

- 7

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 4,729 engines used in Exploration and Production (E&P) at major sources. LB engines accounted for 66

pe rcent 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 sma ller 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 t o 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 ICCR Database, GTI/PRCI Engine and Turbine Database, an d 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 en gines 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 ther e 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 cat egory, 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

- 8

engines , or 96% ) than LB engines (27 engines , or 4% ). In addition, for the smaller en gines <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 PSEI and those non

- PSEI engin es). 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 PSEI (due to their small size) for major sources
(p. 25). Engines that are located outside the DFW NAA are n ot 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 Emissio ns, 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

- 9

NOx emissions from AA engines would drop by approximately 6.5 tpd (p.25) (this approach

reduces em issions 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 I) 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 table s 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 en g ines (4 1%) are RB.

2009 Equipment Inventory of S tationary NG E ngines by H orsepower for Barnett Shale

R egion. (ETCG 2013)

Engine Size Total Engines Percent of
Total Engines Engine Type,

RB or LB Number of

Engines Percent of Each

Size Category

0 to 50 hp 317 12% RB 302 95%

LB 15 4.7%

50 to 240 hp 1,876 68% RB 1,787 95%

LB 89 4.7%

>240 hp 557 20% RB 230 41%

LB 327 59%

### E

- 10

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 ICE NOx 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 R B; 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 LB.

References

(CARB 2001). Determination of Reasonably Available Control Technology and Best Available Retrofit Control Technol ogy 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 Suppor t 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 1 9, 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

- 11

(EDF 2008). Emissions from Natural Gas Production in the Ba rnett 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 Station ary Sources of NOx 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 Council of
Governme nts . 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 o f Public Health and Environment

— Air Pollution Control Division.

### E

- 12

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 th e 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 NOx

em ission 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 Technolo gies and Add

- On Controls

Control Technique (OTC 2012) (KSU 2011) (CARB 2001) (CO DPHE)

2 Stroke, LB

Improved combustion air flow, Turbocharger ( p. 18, 31): up to 75% Up to 90% ;

0.5 to 2 g/bhp

- hr (increases fuel

economy; may increase CO) ( p. 9) — —

Retard ignition timing ( p. 54): diesel, 10% (reduces engine efficiency; increases PM) Up to 10% (increase

fuel economy; may increase CO) ( p. 9) (p. B

- 7 ,8 ): 15 to

30% (increases fuel consumption; increases VOC, HAP) 20% (pp. 5

- 7);

$310 to $2,000/ton ( p. 8)

Improved air fuel mixing, High Pressure Fuel Injection ( p. 18, 31): up to 90% — — —

Advanced In

- cylinder mixing

— 30 to 70% ( p. 11)

— —

Precombustion chamber (PCC) ignition system ( p. 19, 31

- 32): up to 90% 1 g/bhp

- hr ( p. 10)

— —

Micro Precombustion chamber (MPCC), hybrid of High energy Ignition system and PCC — 2 to 4 g/bhp

- hr ( p. 10)

— —

Screw

- in PCC

— 1 g/bhp

- hr ( p. 10)

— — Autobalance cylinders ( p. 23): not provided — — —

(continued)

### E

- 13

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 Not provided; u se 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)

Combustion modifications, Layered Combustion controls ( p. 25): 60 to 90%; range of 0.5 to 3 g/bhp

- hr — — —

4 stroke, LB

EGR and NSCR ( p. 32): (emissions lower than SCR) a — — —

Combustion modifications, Layered Combustion controls ( p. 38): 90%; range of 0.5 to 2 g/bhp

- hr — — —

Engines (general) or LB

High energy ignition system (HEIS) ( p. 18, 31, 44): 10% 2.5 to 3 g/bhp

- hr (p p. 9

- 10) (p. B

- 12): 200

ppm NOx —

Low emission combustion (LEC)/precombustion chamber retrofit (PCC) [also applicable to RB] — — ( p. B

- 10): 80% (may increase VOC, CO) —

Turbocharging/ supercharging, and Aftercooling ( p. 18): Up to 75%

— ( p. B

- 13): 3 to 35% for Aftercooling (may reduce VOC, CO; increases engine efficiency, power rating) —

EGR ( p. 55): diesel, >40% (loss of fuel efficiency; loss of engine output) Still under

development for NG engines; not cost effective at this time ( p. 11)

. (p. B

- 14): 30%

(reduces engine peak power; reduces fuel efficiency by 2 to 12%) —

Ignition system improvement

— — ( p. B

- 11

- 2): not provided (may increase VOC, CO) —

(continued)

### E

- 14

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 — Still in R&D phase, no reduction or cost info available (reduces PM; high efficiency) ( p. 11

- 12). — —

Fuel switching, Hydrogen/NG blended fuel — 40 to 50% ( p. 12)

Still under development, no cost info available; use of
H 2 blend removes need for PCC; H 2 fuel would need to be available in the field. — —

Selective Catalytic Reduction (SCR) ( p. 19, 32, 55): 50 to 95% (reduces THC, CO) 80 to 90% (can

release NH3) ( p. 13) ( p. B

- 23): >80% 80 to 90% (p p. 5

- 7); $430 to $4,900/ton ( p. 9)

Lean

- NOx catalysts ( p. 55): diesel, 10 to 50% Up to 80% (reduces

CO, HC by 60%; reduces fuel economy by 3%) ( p. 14) (p. B

- 24): diesel,

25 to 50% (increases fuel consumption; may increase VOC, PM) —

NOxTech

— — (p. B

- 25): 80 to 90%; (decreases CO, VOC, PM by 80%; fuel penalty 5 to 10%) —

Lean NOx traps ( p. 55): diesel, up to 90% — — —

NOx Adsorber Technology (SCONOx) — — (p. B

- 27): >90% on diesel engine <100 hp; [2 ppmv on NG turbine] —

Selective noncatalytic reduction (SNCR) [also applicable to RB] — — — 50 to 95% (p p. 5

- 7)

(continued)

### E

- 15

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

— — (p. B

- 16): 30% for conversion from NG to methanol (can generate formaldehyde emissions) —

Hybrid system, modification of dual bed NSCR system — — (p. B

- 22): 3 to 4 ppm NOx —

Use of electric motors in place of combustion engines — — (p. B

- 27): >60% 60 to 100% (p p. 5

- 7); $100 to $4,700/ton [not include full costs] ( p. 9)

RB

Nonselective catalytic reduction (NSCR) plus
AFRC ( 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>50%; increases fuel consumption) 80 to 90%

(p p. 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)

Convert RB to LB ( p. 45): not provided — — —

EGR ( p. 49): up to 80% (increase power output by 10%; decrease fuel consumption by 7%) — — —

Pre

- stratified charge (converts RB to LB) — For 4S, RB, 2 g/bhp

hr (may de

- rate engine power by 20%; costs significant) ( p. 11) (p. B

- 15): >80%

(improved fuel efficiency) —

### E

- 16 a Some 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 recirculati on (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 applicati on 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 emission s 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 fro m 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 i ts 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. 51). The IL regulation will potentially affect 202 RICE engines and 36 turbines and reduce NOx emissions by 5,42 2 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 project ed 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

O 3 

### season emissions (pp. 11 and 56). Uncontrolled NOx emissions in 2012 were projected to be
21,532 tpy an d 9,134 ton/season, for those units included under the full implementation of the rule (p. 56). (IEPA 2007)]

Other Available 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

- 17

(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
Moni toring 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 of NOx Emissions

. Delaware Department of Natural Resources and Environ mental 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 R ICE Source Category. Colorado Department of Public Health and Environment

– Air Pollution Control Division.

### E

- 18

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 Qu estion 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
O 3 NAA ≥200 hp and Rest of state ≥400 hp  Thru March 31, 2005, NG, RICE, LB: 3 g/bhp

- hr (220 ppm)

 After April 1, 2005, LB: 1.5 g/bhp

- hr (110 ppm)

 Thru March 31, 2005, Liquid

- fired, CI: 9 g/bhp

- hr (657 ppm)

 After 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 state, major facilities >100 tpy: ≥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 kW

Group of 2 or more engines, each at ≥37 to <148 kW, but total 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

- 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.)

SJVAPCD (amended 2011Aug18) Rule 4702

ICE, SI and CI, nameplate rating ≥25 hp  2S, LB, NG, <100 hp: 75 ppmvd

 LB limited use or Gas compression: 65 ppmvd

 LB, all others: 11 ppmvd OTC 2012

Texas Oil & Gas Handling and

Production Facilities  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 OTC 2012

Texas Oil & Gas Handling and

Production Facilities  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, >825hp: 5 g/bhp

- hr

– Mfg btwn 6/18/1992 and 6/1/2010, ≥500hp: 2 g/bhp

- hr (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. OTC 2012

Texas Oil & Gas Handling and

Production Facilities  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. OTC 2012

Texas (NAA major sources) RACT, Major ICI, O3

NAA, Beaumont

- Port Arthur O 3 NAA Major

sources  NG, SI, RICE, LB ≥300 hp: 3 g/bhp

- hr

 NG, SI, RICE, RB, ≥300 hp: 2 g/bhp

- hr OTC 2012, DE
2012

Texas (NAA minor sources) Combustion Control at

Minor Sources in O 3 NAA, Houston

Galveston

- Brazoria  NG, RICE, >50 hp: 0.5 g/bhp

- hr DE 2012, ETCG
2013

Texas O3 NAA, Dallas Ft.

Worth  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 EDF 2008; ETCG 2013

(continued)

### E

- 20

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.)  RB, NG, RICE, 240 to 500 hp: 1 g/hp

- hr

 RB, NG, RICE, ≥500 hp: 0.5 g/hp

- hr

 RB, Landfill gas, RICE, ≥500 hp: 0.6 g/hp

- hr ETCG 2013

Colorado Regulation 7, RICE, LB,

NG, New, modified, relocated  After July 1, 2007, ≥500 hp: 2 g/bhp

- hr

 After July 1, 2010, ≥500 hp: 1 g/bhp

- hr

 After January 1, 2008, 100 to 500 hp: 2 g/bhp

hr

 After January 1, 2011, 100 to 500 hp: 1 g/bhp

hr OTC 2012; CO
DPHE

USEPA Part 60, subpart JJJJ (NSPS)
(final 2008Jan18) NG, SI, ICE  Mfg after 7/1/2008, ≤25 hp, Class I: 11.0 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 co mbined

 Mfg after 7/1/2008, 25 to 100 hp: 2.8 g/hp

- hr of HC + NOx combined ETGC 2013

USEPA Part 60, subpart JJJJ (NSPS)
(final 2008Jan18) SI, NG and SI, LB, LPG,

100 to 500 hp  Mfg after 7/1/2008: 2 g/bhp

- hr

 Mfg after 1/1/2011: 1 g/bhp

- hr ETCG 2013

USEPA Part 60, subpart JJJJ (NSPS)
(final 2008Jan18) NG and LPG, SI, LB,

500 to 1350 hp  Mfg after 7/1/2008: 2 g/bhp

- hr

 Mfg after 7/1/2010: 1 g/bhp

- hr OTC 2012

USEPA Part 60, subpart JJJJ (NSPS)
(final 2008Jan18) SI, NG and SI, LB, LPG

(except LB 500 to 1350 hp )  Mfg after 7/1/2007: 2 g/bhp

- hr ETCG 2013

### E

- 21

NOx Control Requirements for RICE in Local Areas.

State or Area Criteria NOx control level Reference

SCAQMD (July 2010) Rule 1110.2 Emissions

from Gaseous and Liquid Fueled Engines  ≥500 hp: 0.5 g/bhp

- hr (36 ppmvd)

 <500 hp: 0.6 g/bhp

- hr (45 ppmvd)

 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 (11 ppmvd) OTC 2012



### 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 refe rence (p. 53). (PA DEP 2013) [Capital] c osts 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 (A ctual 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 Fuel 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

- stratifi ed Charge, achieving 80% reduction. Capital costs ranged from $10,000 to $47,000; Annual costs ranged from $2,700 to

### E

- 22

$11,000; and cost effectiveness ranged from $800/ton to $200/ton NOx reduction (p p. V

- 2 to V

3). (CARB 2001)

CARB 2001 document has costs f or Ignition Timing Retard (ITR), although the description of the combustion technology indicates it is less popular on Stationary engines than mobile source engines (p p. V

- 2, B

- 7 to B

- 8). (CARB 2001)

The EDF 2008 reference provided NOx EF for engines in th e 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 2 007); $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 motor s 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 50

– 500 13.6 RB 50

– 500 0.5

RB >500 0.9 RB >500 0.5

LB <500 6.2 LB, installed or moved before June
2007 <500 0.62

LB >500 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

- 23

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 Assessme nt 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 Barnett Shale Area and Opportunities for Cost Effective Improvements. Conducted by Department of Environmen tal 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 Gas Sector, Significant Stationary Sources of NOx
Emissions . Final. October 17, 2012.

PA DEP 2013. Technical Support Document General Permit GP

- 5. Pennsylvania Department of
Env ironmental 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 Internal Combustion Engine (RICE) Source Category, Reasonable Progress Evaluation for RICE Source Category . Colorado Department o f Public Health and Environment

— Air Pollution Control Division.

### E

- 24

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) RIC E 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 cite d a
2003 Pipeline Resear ch 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 (PRCI)

Unit Type U.S Total Units (%) Average Age (as of 2003) Avg hp

2S LB 2

, 955 (44%) 42 2

, 113

4S LB 1

, 059 (16%) 33 1

, 844

RB 1

, 672 (25%) 32 589

Turbine 1

, 016 (15%) 24 6

, 121



### The OTC 2012 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 condu cted 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

- 25

reference. The two sets of dat a 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 ob tained 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. Not e 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 467 1

, 331

, 164

RI 6 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

- 115 (Lean Burn) that has no ne of the low emissions controls that are currently OEM standard. The p ublished 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 (t he 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) Int egral 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

- 26

(DE 2012) Backgroun d Information, Oil and Gas Sector, Significant Sources of NOx Emissions

. Delaware Department of Natural Resources and Environmental Quality.

(OTC 2012). Technical Information Oil and Gas Sector, Significant Stationary Sources of NOx Emissions. Final. Octo ber 17, 2012.

### E

- 27

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 w ere found. [Likely a review of RICE SCCs in the NEI across states would be a

useful exer cise to see the relative levels of baseline and/or controlled NOx emissions, however this exercise was not part of this task.]

### 1

To: US EPA OAQPS

From: SRA International, Inc.

Subject: Review of CoST Model Emission Reduction Estimates

Date: 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 this 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 inventory used by CoST did

not completely account for emission control requirements already in place, and that the emission

reductions were perhaps overestimated.

SRA reviewed the CoST results and made recommendations for changing the CoST control measure

assignment and the estimated reductions for oxides of nitrogen (NOx). The recommendations were based

on a review of source permits, state regulations, enforcement actions, and other available information.

The analysis was conducted for a 24

- state area in the eastern two

- thirds 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 recommend ing changes to the CoST results, and to

summarize the differences between the CoST resu lts and the recommended changes.

T he findings in this memo are based on review of CoST results for a 2018 emissions inventory projected

from the 2011 N ational Emission Inventory (N EI ). This work was in support of EPA’s current Transport

Rule efforts for implementing the 75 ppb ozone standard. If EPA considers establishing a tighter ozone

standard in the future, it is likely that a more distant future year will be used and that some of the

conclusions reached in this memo could change.

CoST D ATA PROVIDED BY EPA

EPA provided SRA with 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 estimate s 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 ton s /y ear, exclud ing those

### 2

with reductions greater than 100 tons/year. There were 1,280 sources in this group where CoST controls

were initially applied.

Another contractor review ed the CoST results for additional source categories, and their

recommendations were merged w ith SRA’s recommendations in the summary tables and maps that

follow. The data use d

, assumptions made and results for IC engines are documented elsewhere 1



### .

REVIEW OF CoST RESULTS FOR THE GREATER THAN 100 TPY GROUP
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 d iscussion 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 estimate s and the recommended change s . All

Attachme nts 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 emi ssion 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 Disa greed with CoST recommendation
based on concerns about biosolids availability and information from EPA’s ISIS (Industr ial 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.

### 3

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 Disa greed with CoST recommendation
based on information from EPA’s I SIS Model ; recommended SNCR for all sources, except those that already controlled Coal Cleaning

– Thermal Dryer Low NOx Burner Agreed with CoST recommendation

Comm/Inst Incinerators Selective Non

- Catalytic
Reduction Both sources are already controlled with
SNCR

External Combustion Boilers, Elec Gen, 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 controlle d 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 Disagr eed 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 ever y 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 r egulation 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

### 4

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 Agre ed 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 Disagr eed 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 pe rmit 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 Agree d 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 ref inery 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 led due to confidentiality agreements between EPA and companies.

### 5

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

e xcept 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 regul ation 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. H owever, 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 control technology 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

- NOx burners and recommended no further control/reductions. For all

other sources, we agreed with the CoST control and emission re duction estimate.

By

- Product Coke Mfg; Oven Underfiring

There are 14 sources in this category. The CoST control technology was selective non

- catalytic reduction

(SNCR) with a 6 0% reduction in NOx emissions. We reviewed a detailed RACT analysis for a facili ty in

Pennsylvania that determined that 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 Kiln s

There are 36 sources in this cat egory. 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 C all 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 requ irement.

### 6

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) projec t. EPA uses the ISIS

- cement model help analyze policy options

for various rulemaking s. 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% reductio n 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 additional emission

r eductions.

Cement Manufacturing

- Dry Process

There are 20 sources in this category. The CoST control technology was SNCR with a 50 % 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.

As discussed earlier, we recommended that low

- NOx burners and SNCR as the appropriate control for all

types of kilns based on the ISIS work

. 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 additional emission re ductions.

Cement Manufacturing

– Wet Process

There are seven sources in this category. The CoST control technology was mid

- kiln firing with a 3 0%

reduction in NOx emissions. We determined that two of these kilns were installing a pilot SCR system as

part of a consent decree. One kiln recently went through NSR review and has state

- of

- the

- art control.

Another kiln is required to install SNCR as part of a consent decree. No additional reductions were

applied for these kilns. For the remaining kilns, we appli ed 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 5 0%

reduction in NOx emissions. We could not find any information on this source and accepted the CoST

controls.

### 7

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 alread y 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 low

- NOx burners and flue gas

recirculation with a 55 % reduction in NOx emissions. Nearly all sources are already controlled or required to install controls as a result of the EPA’s 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

There are 6 5 sources in this category. The CoST control technology was oxy

- firing with an 85 %

reduction in NOx emissions. There were several concerns about using oxy

- firing for this analysis. First,

there is a concern about the timing of installing oxy

- firing technology. Oxy

- firing is typically installed at

the time of a furnace rebuild, which is typically done every 10 to 15 year s. 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 t hat already had NOx controls in place due to a consent decree, NSR

requirement, or state regulation. We a ssumed 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

T here are eight sources in this 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) Boilers 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, w e 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

source s since they are already controlled.

### 8

ICI Boilers

– Coal/Stoker

There are 4 5 sources in this category. The CoST control technology was SCR with an 80% reduction in

NOx emissions. The LADCO/OTC recommendation was for c omb ustion tuning and SNCR . We agreed

w ith 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 SNC R.

ICI Boilers

– Coal/Wall

There are 54 sources in this category. The CoST control technology was low

- NOx burners and SCR with

a 91% reduction in NOx emissions. The LADCO/OTC recommendation was also for low

- NOx burners

and SC R . Since the LADCO/OTC recomm endation was consistent with the CoST control, we agreed

with the CoST control technology and emission reductions

. ICI Boilers

– Gas, Natural Gas, Process Gas

There are 1 30 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 recir culation and assumed a 60% control

efficiency.

Several of these sources are located in the OTR or ozone nonattainment areas, and as a result already have

a RACT control requirement or emission limitation that is consistent with the LADCO/OTC

recommendatio ns. A few of these sources are located at petroleum refineries and were assumed to be
already controlled due to EPA’s refinery enforcement initiative.

Municipal Waste Combustors

There are 5 5 sources in this category. The CoST 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.

Nitr ic Acid Manufacturing

There are seven sources in this category. The CoST control technology was non

- selective catalytic

reduction (NSCR) with a 9 8 % reduction in NOx emissions. All but one of these sources is already

controlled by NSCR or SCR.

Petroleum R efinery Process Heaters

There are 28 sources in this category. The CoST control technology was SCR with a 9 5 % 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

### 9

each company operates. Companies have submitted NOx compliance p lans 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 n ot possible at present to identify the individual boilers/heaters that actually have been controlled

or ar e scheduled to be control led 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 1 0 sources in this category. The CoST control technology was SCR with a 90% reduction in

NOx emissions. All o f the sources in this category are already subject to Best Available Retrofit

Technology (BART) requirements under the Regional Haze program. EPA Region V determined that

BART is low

- NOx burner s 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 s ources in this category. The CoST control technology was SCR with a 80 to 90% reduction

in NOx emissions depending on fuel type. All of the sources in this 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 GROUP
Due to the large number of sources in this 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, enginee ring judgment, and other available information.

We generally assumed that sources located in areas with stringent NOx rules are already well controlled

and we assumed that no additional reductions were likely from these sources. This assumption was

general ly applied in New Jersey, New York and sources located in the Houston nonattainment area.

Given more time, we would like to have also applied this assumption in other areas with stringent existing

regulations, such as Chicago, Milwaukee, and Baton Rouge. I n 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 fo r 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. Attachment s 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

### 10

ozone season emissions were equal to 5/1 2 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 Mi d

- 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/Inst 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 Burne r 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

### 11

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 so urces 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 N SCR 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 a greements 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.

### 12

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 dete rmined 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 low

- NOx burner with a 5 0%

reduction in NOx emissions. We agreed with the CoST control and emiss ion reduction estimate.

Comm ercial /Inst itutional Incinerators

There are four sources in this category. The CoST control technology was S N CR with a 45 % reduction in

NOx emissions. We agreed with the CoST control and emission reduction estimate.

External Combustion Boilers, Elec tric Gen eration , Coal

There are 14 sources in this category. The CoST control technology was S N CR with a 4 0% 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

- effectiveness 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 requirements resulting from the OECA global refinery enforcement initiative.

Additionally, eight of the s ources are located in the Houston nonattainment area and are likely subject to

stringent controls. For 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 source s already had RACT controls.

Glass Manufacturing

– Container, Flat, Pressed

### 13

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 a ssumed that the furnaces

were already controlled and determined that no reductions be applied for these sources.

ICI Boilers

– Coal/Stoker

There are 1 33 sources in this category. The CoST control technology was SCR with a 90% reduction in

NOx emissions. The LADCO/OTC recommendation was for c omb ustion tuning and SNCR . We agreed

with the LADCO/OTC recommendation and assumed a 50% control efficiency.

ICI Boilers

– Coal/Wall

There are 1 1 sources in this category. The CoST control technology was SCR with a 90% reduction in

NOx emissions. The CoST control technology was low

- NOx burners and SCR with 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 with the CoST c ontrol, we agreed with the CoST control

technology and emission reductions.

ICI Boilers

– Natural Gas

There are 376 sources in this category. The CoST control technology was low

- NOx burners and SCR

with a 9 1 % 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

50% co ntrol efficiency, except for those sources located in the OTR and Houston ozone nonattainment

area, where we assumed that these 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 the Houston nonattainment area and are likely subject to stringent controls. For these reasons,

we assumed no further control or emission reductions

. ICI Boilers

– Residual Oil

There are 28 sources in this category. The CoST control technology was low

- NOx burner and S N CR 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 S N CR with a 45 % reduction in

NOx emissions. We agreed with the CoST control and emission reduction estimate, except for those

### 14

sources located in the OTR and Hou ston 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 w ith 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 with a 90% reduction in

NOx emissions. RTI identified the sou rces 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 1 4 sources in this category. The CoST control technology was N SCR with a 9 8 % reduction in

NOx emissions. We agreed with the CoST control and emission reduction estimate.

Petroleum Refinery Process Heaters

There are 3 0 sources in this category. The CoST cont rol technology was SCR with a 90

- 98 % reduction or

ultra

- low NOx burners with a 30

- 50% reductions i n NOx emissions. Most of these sources are located at

petroleum refineries and are assumed subject to existing control requirements resulting from the OECA

gl obal refinery enforcement initiative, or are located in the Houston nonattainment area and are likely

subject to stringent controls. For these reasons, we assumed no further control or emission reductions.

Utility Boilers

– Coal/Wall

There are three source s 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

– Oil/Gas

There are 27 sources in this category. The CoST control technology was SCR with a 8 0% reduction in

NOx emissions. The LADCO/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 effici ency.

### 15 Attachment 1

– NOx Emission Reductions by State for Sources in the > 100 Ton per Year Reduction Group

State Number of

Sources NOx emissions

reduced from controls in CoST (tons/ O3 season )

( A ) Recommended

NOx emissions reduced from controls in CoST (tons/ O3 s eason )

( B ) Size of correction in NOx emission reductions (tons/ O3 season )

( 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

### 16

Attachment 2

– NOx Emission Reductions by Source Group for Sources in the > 100 Ton per Year Reduction Group

S ource Group Number of Sources NOx emissions reduced from controls in CoST (tons/ O3 season )

( A ) Recommended

NOx emissions reduced from controls in CoST (tons/ O3 season )

( B ) Size of correction

in NOx emission reductions (tons/ O3 season )

( A

- B )
Ammonia

- NG

- Fired Reformers 15 2,427 1,551 875 By

- Product Coke Mfg; Oven Underfiring 14 1,199 0 1,199

Cement Kilns 36 3,932 6,586

- 2,654 Cement Manufacturing

- Dry 20 3,672 2,234 1,438 Cement Manufacturing

- Wet 7 1,294 1,120 174 Coal Cleaning

- Thrml Dryer; Fluidized Bed 1 50 50 0

Comm./Inst. Incinerators 2 137 0 137 External Combustion Boilers, Solid Waste 6 472 0 472 Fluid Cat Cracking Units; Cracking Unit 6 607 52 556 Fuel Fired Equip; Process Htrs; Pro Gas 2 143 143 0 Glass Manufacturing

- Container 34 2,759 678 2,081 Glass Manufacturing

– Flat 23 10,241 6,024 4,217 Glass Manufacturing

- Pressed 8 684 402 282

ICI Boilers

- Coal/Cyclone 8 2,987 1,840 1,147

ICI Boilers

- Coal/FBC 3 233 180 53

ICI Boilers

- Coal/Stoker 45 4,688 2,938 1,750

ICI Boilers

- Coal/Wall 54 12,041 7,996 4,045

ICI Boilers

– Gas 10 1,266 910 356

ICI Boilers

- Natural Gas 84 7,578 3,452 4,126

ICI Boilers

- Process Gas 36 3,868 1,229 2,639

ICI Boilers

- Residual Oil 2 199 82 117

Indust. Incinerators 9 586 124 461

In

- Proc;Process Gas;Coke Oven/Blast Furn 3 299 0 299

### 17

S ource Group Number of Sources NOx emissions reduced from controls in CoST (tons/ O3 season )

( A ) Recommended

NOx emissions reduced from controls in CoST (tons/ O3 season )

( B ) Size of correction

in NOx emission reductions (tons/ O3 season )

( A

- B )

In

- Process; Bituminous Coal; Cement Kiln 2 290 295

- 5

Iron & Steel

- In

- Process Coal Combustion 4 419 0 419

Iron & Steel Mills

– Reheating 2 156 156 0 Municipal Waste Combustors 55 1,591 876 715 Nitric Acid Manufacturing 7 687 82 605 Petroleum Refinery Gas

- Fired Process Heaters 28 2,025 0 2,025

Taconite Iron Ore

- Induration

- Coal or Gas 10 829 451 379 Utility Boiler

- Coal/Wall 5 555 555 0 Utility Boiler

- Oil

- Gas/Tangential 2 526 526 0 Utility Boiler

- Oil

- Gas/Wall 4 1,645 1,524 121

547 70,082 42,054 28,028

### 18

Attachment 3

– NOx Emission Reductions by 3

- Digit NAICS Code for Sources in the > 100 Ton per Year Reduction Group

3

- Digit NAICS Code Number of Sources NOx emissions reduced from controls in CoST (tons/ O3 season )

( A ) Recommended

NOx emissions reduced from controls in CoST (tons/ O3 season )

( B ) Size of correction

in NOx emission reductions (tons/ O3 season )

( 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

### 19

Attachment 4

– NOx Emission Reductions by 3

- Digit NAICS Code for Sources in the > 100 Ton per Year Reduction Group

Recommended Change to CoST Control Number of Sources NOx emissions reduced from controls in CoST (tons/ O3 season )

( A ) Recommended

NOx emissions reduced from controls in CoST (tons/ O3 season )

( B ) Size of correction

in NOx emission reductions (tons/ O3 season )

( 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 S CR 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

### 20 Attachment 5

– NOx Emission Reductions by State for Sources in the 25 to 100 Ton per Year Reduction Group

State Number of

Sources NOx emissions

reduced from controls in CoST (tons/ O3 season )

( A ) Recommended

NOx emissions reduced from controls in CoST (tons/ O3 season )

( B ) Size of correction in NOx emission reductions (tons/ O3 season )

( 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

### 21

Attachment 6

– NOx Emission Reductions by Source Group for Sources in the 25 to 100 Ton per Year Reduction Group

S ource Group Number of Sources NOx emissions reduced from controls in CoST (tons/ O3 season )

( A ) Recommended

NOx emissions reduced from controls in CoST (tons/ O3 season )

( B ) Size of correction

in NOx emission reductions (tons/ O3 season )

( 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./Inst. 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

### 22

S ource Group Number of Sources NOx emissions reduced from controls in CoST (tons/ O3 season )

( A ) Recommended

NOx emissions reduced from controls in CoST (tons/ O3 season )

( B ) Size of correction

in NOx emission reductions (tons/ O3 season )

( A

- B )
Indust. Incinerators 21 230 118 113

In

- Proc;Process Gas;Coke Oven/Blast Furn 4 33 8 25

Iron & Steel

- In

- Process Comb

- Coal 1 19 0 19

Iron & Steel Mills

- Reheating 32 481 481 0 Municipal Waste Combustors 25 472 228 243 Nitric Acid Manufacturing 14 363 289 74 Petroleum Refinery Gas

- Fired Process Heaters 30 456 0 456 Solid Waste Disp;Gov;Other Incin;Sludge 1 6 6 0 Space Heaters

- Natural Gas 2 17 13 4 Steel Foundries; Heat Treating Furn 7 122 122 0 Surf Coat Oper;Coating Oven Htr;Nat Gas 2 11 0 11 Utility Boiler

- Coal/Wall 2 48 48 0 Utility Boiler

- Coal/Wall2 1 13 13 0 Utility Boiler

- Oil

- Gas/Tangential 8 99 62 37 Utility Boiler

- Oil

- Gas/Wall 19 307 137 170

1280 22,774 14,000 8,774

### 23

Attachment 7

– NOx Emission Reductions by 3

- Digit NAICS Code for Sources in the 25 to 100 Ton per Year Reduction Group

3

- Digit NAICS Code Number of Sources NOx emissions reduced from controls in CoST (tons/ O3 season )

( A ) Recommended

NOx emissions reduced from controls in CoST (tons/ O3 season )

( B ) Size of correction

in NOx emission reductions (tons/ O3 season )

( A

- B )
211 Oil and Gas Extraction 146 2,674 2,573 100 212 Mining (except Oil and Gas) 12 247 227 20 213 Support Activities for Mining 1 20 20 0

221 Utilities 96 1,575 1,035 540 311 Food Manufacturing 46 715 450 266 312 Beverage and Tobacco Product s 9 151 91 60

313 Textile Mills 1 24 15 9

314 Textile Product Mills 1 12 7 4 316 Leather and Allied Product Manufacturing 1 10 7 3 321 Wood Product Manufacturing 6 100 56 44 322 Paper Manufacturing 79 1,662 1,028 634

324 Petroleum and Coal Products 115 2,083 527 1,556 325 Chemical Manufacturing 332 6,480 3,218 3,262

326 Plastics and Rubber Products 13 206 142 65 327 Nonmetallic Mineral Product Manufacturing 24 417 32 385 331 Primary Metal Manufacturing 87 1,380 1,094 285 332 Fabricated Metal Product Manufacturing 4 80 46 33 333 Machinery Manufacturing 2 20 14 6 334 Computer and Electronic Product s 1 9 9 0 336 Transportation Equipment Manufacturing 13 261 192 69

337 Furniture and Related Product s 2 18 18 0

447 Gasoline Stations 1 7 0 7

454 Nonstore Retailers 1 9 0 9

### 24

3

- Digit NAICS Code Number of Sources NOx emissions reduced from controls in CoST (tons/ O3 season )

( A ) Recommended

NOx emissions reduced from controls in CoST (tons/ O3 season )

( B ) Size of correction

in NOx emission reductions (tons/ O3 season )

( A

- B ) 482 Rail Transportation 3 37 23 14

486 Pipeline Transportation 156 2,551 2,034 517 488 Support Activities for Transportation 1 18 12 6

531 Real Estate 8 147 0 147

541 Professional Services 6 81 77 4 561 Administrative and Support Services 1 8 0 8

562 Waste M gmt and Remediation Services 21 376 184 192

611 Educational Services 62 963 617 346 622 Hospitals 7 116 36 80 713 Amusement, Gambling, and Recreation 2 49 45 4

721 Accommodation 2 25 10 15 922 Justice, Public Order, and Safety Activities 4 29 17 12

923 Administration of Human Resource s 1 12 8 4 928 National Security and International Affairs 13 201 135 66

1280 22,774 14,000 8,774

### 25

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 Number of Sources NOx emissions reduced from controls in CoST (tons/ O3 season )

( A ) Recommended

NOx emissions reduced from controls in CoST (tons/ O3 season )

( B ) Size of correction

in NOx emission reductions (tons/ O3 season )

( A

- B ) Already Controlled 207 3,380 0 3,380 Already Controlled by Refinery CD 40 704 0 704

Low NOx Burner 362 6,087 6,087 0

Low NOx Burner and Flue Gas Recirculation 361 6,726 4,491 2,235

Low NOx Burner and SCR 11 246 246 0

Low NOx Burner and SNCR 24 437 437 0

Natural Gas Reburn 1 28 28 0

Non

- Selective Catalytic Reduction 12 289 289 0 Questions About Feasibility 1 22 0 22 Questions About Feasibility

- Cement 6 154 0 154 Questions About Feasibility

- Ceramic Clay Mfg 4 29 0 29 Questions about Feasibility

- Coating Ovens 2 11 0 11 Questions about Feasibility

- Distillate Oil 6 116 0 116 Questions About Feasibility

- Glass 7 167 0 167 Questions about Feasibility

- Process Gas 50 1,070 0 1,070 Selective Catalytic Reduction 8 216 216 0

Selective Non

- Catalytic Reduction 178 3,094 2,207 886

1280 22,774 14,000 8,774

### 1

To: US EPA OAQPS

From: SRA International, Inc.

Subject: Summary of State NOx Regulations for Selected Stationary Sources

Date: 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 two

- thirds of the U.S. For each of these states and source

categories, we identified state

- specific sub

- categories (e.g. f uel type or size threshold), the NOx e mission

l imit or control requirement, a veraging t ime for the emission limit, ge ographic a pplicability w ithin the

s tate , testing/monitoring requirements, and rule citation. This information is contained in the attached

spreadsheet ( Draft State NOx RACT Limits 2014_04_01 .xlsx)

.

Attachment 1 is a n overall summary of the relative stringency of the NOx requirements by geographic

area and source category. We also prepared a 2

- page summary for each of the six categories to concisely

compare state NOx emission limits or control requirements. These are shown in Attachments 2 to 7 , along

with notes highlighting the major differences between the state regulations.

Please let us know should you have questions or comments about any of the data presented in this

memorandum.

### 2 Attachment 1

– Relative Stringency of NOx Requirements

Source Category States/Areas with

Mo st Stringent Regulations States/Areas with Less Stringent Regulations States with No Regulations or Sources
Cement Kilns 1 

### States : IL, MD, NY, PA, TX
Areas : Ellis County, TX States : AL (NOx SIP area), IN, KY, MO, MI, OH, SC, TN, VA , WV States : AR, FL, GA, MS, OK
States with no cement k ilns : CT, DE, LA, MA, NC, NJ, WI
Coal

- fired ICI Boilers 2 

### States : NY
Areas : Chicago, St. Louis (IL portion), Baton Rouge, Houston

- Galveston (coke

fired) , Milwaukee, States : FL, GA, IN, MA, MD, MI, PA, TN, VA
Areas : Chicago, St. Louis (MO portion), Baton Rouge, Charlotte,
Cleveland States : AL, AR, KY, MS

, OK, SC, TX (except Houst on

- 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, MI, 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, MI, TN, VA
Areas : Clark/Floyd Counties, St. Louis (MO portion), Charlotte States : AL, AR, KY, MS, OK, SC, WV

Gas Turbines States : NJ

Ar eas : 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, MI, 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, MI, 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

### 3 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

MI 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: low

- 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

WI No Cement Kilns in State

WV Ozone season: low

- NOx burners, mid

- kiln system firing, or approved ACT

ACT = Alternative Control Technology

* P ennsylvania has proposed “RACT 2” presumptive RACT limits

### 4

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 requirem ents 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 following: low

- NO x burners, mid

- kiln

system firing, alternative control tech niques or reasonably available control technology approved

by the Director and the EPA as achieving at least the same emissions decreases as with low

- NOX

burners or mid

- kiln system firing

. ”

 A few states specify presumptive emission limits in terms of poun ds of NOx 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 req uire sources to h old 1 trading allowance per ton of

NOx c alculate d by m

ultiplying tons clinker by the presumptive NOx limit

.  Stringency of NOx Limitation or Control Requirement

 For states requiring “ low

- NOX burners, mid

- kiln system firing, or ACT”, it is generally assumed

that this will result in a 30% reduction 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

.

 Texas has very stringent limits for kilns in Ellis County.

 Pennsylvania has proposed presumptive RACT emission limitation s in April 2014 that are more

stringent than existing presumptive RACT limits in other states.

### 5 Attachment 3

– Coal

- fired Boilers

NOx Limit (lbs/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%

O2 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

MI 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

WI 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

### 6

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 nonattainment areas

.

 Texas onl y has emission limitations for coke

- fired boilers in the Houston

- Galveston

nonattainment area.

 Size Applicability

 Most of the states do not have NOx emission requirements for boilers less than 100 mmBtu/hour.

 10 states do regulation boilers in the 50

- 100 m mBtu 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

- 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

 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 sta tes 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/OTC 1 

### Phase I recommended limits are in

the 0.2

- 0.3 lbs/mmBtu range (depending on boiler/firing configuration). The LADCO/OTC Phase

II recommended limits are in the 0.1

- 0.2 lbs/mmBtu range. F our areas have limits that generally

meet the LADCO/OTC recommendations (Chicago, Baton Rouge, New York State, and

Milwaukee.

 Texas has a very 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 (TS

D) , March, 2011 prepared by the Lake Michigan Air Directors Consortium (LADCO) and the Ozone Transport Commission (OTC).

### 7 Attachment 4

– Gas

- fired Boilers

NOx Limit (lbs/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% O2 30 ppmvd

@ 3% O2 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

MI 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 area s 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

WI Milwaukee 7 county area No limits 0.08 0.08

WV Statewide No limits No limits No Limits

### 8

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 nonattainment areas.

 Size Applicability

 About half of the states have NOx emission requirements for boilers less t han 100 mmBtu/hour

, ranging from combustion tuning to emission limits as low as 0.05 lbs/mmBtu

.  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

- cas e 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 recommend ations are combustion tuning for boilers less than 100

m mBtu/hour, and either 0.1 lbs/mmBtu or 50% reduction for boilers greater than 100 mmBtu/hr.

 The LADCO/OTC Phase II recommendations are either 0.05

- 0.1 lbs/mmBtu or 60% reduction.

 New Jersey and New York have state

- wide limits that are consistent with the OTC/LADCO

Phase II recommendation s . Pennsylvania has proposed state

- wide limits that are consistent with

the OTC/LADCO Phase II recommendations.

 F ive areas (Chicago, Baton Rouge, Beaumont

- Port Arthur, Cleveland, and Milwaukee) have

limits that are consistent with the OTC/LADCO Phase II recommendations.

 Dallas and Houston have the most stringent emission limitations

– 0.02 lbs/mmBtu for greater

that 100 mmBtu/hr units.

### 9 Attachment 5

– Oil

- fired Boile rs

NOx Limit (lbs/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

MI 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

WI 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

### 10

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 re maining states (FL, GA, IL, IN, KY, LA, MI, MO, NC, OH, TN, TX, VA, WI), the

NOx emission control requirements only apply in ozone nonattainment areas.

 Size Applicability

 About half of the states have NOx emission requirements for boilers less than 100 mmBtu/hour,

ranging from combustion tuning to emission limits as low as 0.08 lbs/mmBtu.

 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 d etermination 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 mmBtu/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 0.0 8

- 0.1

lbs/mmBtu or 60% reduction.

 Only New Jersey has state

- wide limits that ar e 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/LADCO Phase II recommendations for distillate oil

.

 The LADCO/OTC Phase I recommend ations for residual oil are combustion tuning for boilers

less than 100 mmBtu/hour, and either 0.2 lbs/mmBtu or 60% reduction for boilers greater than

100 mmBtu/hr. The LADCO/OTC Phase II recommendations for residual oil are either 0.2

lbs/mmBtu 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 resi dual 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

– 0.0 1 lbs/mmBtu for greate r

that 100 mmBtu/hr units.

### 11 Attachment 6

– Gas Turbines

NOx Limit (ppmvd @15% O2)

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 lb/mmBtu) 55 258 (0.9 lb/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 lb/mmBtu) 86

(0.3 lb/mmBtu) 54

(0.2 lb/mmBtu) 86

(0.3 lb/mmBtu)

MA Statewide 65 100 42 65

MD Select counties 42 65 42 65

MI 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 lb/MWh) 53

(3.0 lb/MWh) 33

(2.2 lb/MWh) 53

(3.0 lb/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 lb/mmBtu) 9

(0.032 lb/mmBtu) 9

(0.032 lb/mmBtu) 9

(0.032 lb/mmBtu)

VA Northern VA 42 65/77 42 65/77

WI Milwaukee 7
county area 25 to 42 65 to 96 9 9

WV Statewide No limits No limits No limits No limits

### 12

### 13

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 , WI), the NOx emission

control requirements only apply in ozone nonattainment areas.

 Other A pplicability Criteria

 States use a variety size thresholds. For example, Ohio’s rules differentiate between units < 3.5

MW and > 3.5 MW

. Wisconsin has requirement s for three size ranges: 10

- 25 MW, 25

- 50 MW,

and >50 MW.

 State limits generally differ by type of fuel

– gas or oil. Wisconsin also includes limits for

biologically derived fuel.

 Some states have different limits for simple

- cycle and combined

- cycle unit s. Other states have a single limit that applies to both types of units.

 Form of NOx Limitation or Control Requirement

 States do not specify specific types of control techniques, but rather set a numerical emission

limit.

 Most states express limits in ter ms 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 are in terms of lbs/MHr.

 Stringency of NOx Limitation or Control Requ irement

 Three areas have very low limits compared to other states/areas: the 45 county area in Georgia,

Dallas and Houston

- Galveston

### 14 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% O2 (2.9 g/hp

- hr) 150 ppmvd @

15% O2 (2.2 g/hp

- hr) 660 ppmvd @

15% O2 (9.1 g/hp

- hr) 660 ppmvd @

15% O2 (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% O2 (1.7 g/hp

- hr) 110 ppmvd @

15% O2 (1.6 g/hp

- hr) 175 ppmvd @

15% O2 (2.0 g/hp

- hr) 125 ppmvd @

15% O2 (1.4 g/hp

- hr)

MI 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

WI Milwaukee 7
county area 3.0 3.0 3.0 3.0

WV Statewide No limits No limits No limits No limits

### 15

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, VA, WI), the NOx emission

control requirements only apply in ozone nonatta inment areas.

 Other Applicability Criteria

 States use a variety size thresholds. For example, Louisiana’s rules have separate limits for IC

engines that are 150

- 300 hp , > 300 hp, and >1500 hp. New York uses > 200 hp and > 400 hp.

Delaware uses > 450 hp, w hile North Carolina uses > 650 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 rich

- burn engines . Other states have a single limit

that applies to both type s 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% O2 ”

, and the equivalent limits shown in the table above were

calculated using c onversion factor s from ppmv @ 15% O2 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

 Maryland, New Jersey, New York and the Dallas/Houston areas of Texas have limits that are

more stringent than other states /areas

.