Stationary Source NOx and PM Emissions

in the WRAP Region:

An Initial Assessment of Emissions, Controls,

and Air Quality Impacts

Final Report of the WRAP Market Trading Forum

October 1, 2003

Western Governors’ Association

1515 Cleveland Place, Suite 200

Denver, CO 80202

NOTE: Section VI of this report is bound separately and available

on the WRAP Web site at http://www.wrapair.org/forums/mtf/nox-pm.html
PREFACE

Regulatory Framework for Tribal Visibility Implementation Plans

The regional haze rule explicitly recognizes the authority of tribes to implement the provisions of

the rule, in accordance with principles of federal Indian law, and as provided by the Clean Air

Act §301(d) and the tribal authority rule (TAR) (40 CFR §§49.1– .11). Those provisions create

the following framework:

1. Absent special circumstances, reservation lands are not subject to state jurisdiction.

2. Federally recognized tribes may apply for and receive delegation1 of federal authority to

implement CAA programs, including visibility regulation, or "reasonably severable"

elements of such programs (40 CFR §§49.3, 49.7). The mechanism for this delegation is a

tribal implementation plan (TIP). A reasonably severable element is one that is not integrally

related to program elements that are not included in the plan submittal, and is consistent with

applicable statutory and regulatory requirements.

3. The regional haze rule expressly provides that tribal visibility programs are “not dependent

on the strategies selected by the state or states in which the tribe is located” (64. Fed. Reg.

35756), and that the authority to implement §309 TIPs extends to all tribes within the

GCVTC region (40 CFR §51.309(d)(12)).

4. The EPA has indicated that under the TAR tribes are not required to submit §309 TIPs by the

end of 2003. Rather, they may choose to opt-in to §309 programs at a later date (67 Fed.

Reg. 30439).

5. Where a tribe does not seek delegation through a TIP, EPA, as necessary and appropriate,

will promulgate a federal implementation plan (FIP) within reasonable timeframes to protect

air quality in Indian country (40 CFR §49.11). EPA is committed to consulting with tribes

on a government-to-government basis in developing tribe-specific or generally applicable

TIPs where necessary (See, e.g., 63 Fed. Reg. 7263-64).

The amount of modification, if any, needed for this report to fulfill tribal needs may vary

considerably from tribe to tribe. The authors have striven to ensure that all references to tribes in

the document are consistent with principles of tribal sovereignty and autonomy as reflected in the

above framework. Any inconsistency with this framework is strictly inadvertent and not an

attempt to impose requirements on tribes which are not present under existing law.

Tribal Participation in the WRAP

Tribes, along with states and federal agencies, are full partners in the WRAP, having equal

representation on the WRAP Board as states. Whether Board members or not, it must be

remembered that all tribes are governments, as distinguished from the “stakeholders” (private

interest) which participate on Forums and Committees but are not eligible for the Board.

 

1 Tribes also possess a more fundamental source of authority to regulate their environments, based on their inherent

authority as sovereign nations, which predates the formation of the United States. However, in the context of air

pollution regulation and visibility planning in particular, tribal authority will more likely be based on delegation of

federal authority.
Despite this equality of representation on the Board, tribes are very differently situated than

states. There are over four hundred federally-recognized tribes in the WRAP region, including

Alaska. The sheer number of tribes makes full participation impossible. Moreover, many tribes

are faced with pressing environmental, economic, and social issues, and do not have the

resources to participate in an effort such as the WRAP, however important its goals may be.

These factors necessarily limit the level of tribal input into and endorsement of WRAP products.

The tribal participants in the WRAP, including Board members Forum and Committee members

and co-chairs, make their best effort to ensure that WRAP products are in the best interest of the

tribes, the environment, and the public. One interest is to ensure that WRAP policies, as

implemented by states and tribes, will not constrain the future options of tribes who are not

involved in the WRAP. With these considerations and limitations in mind, the tribal participants

have joined the state, federal, and private stakeholder interests in approving this report as a

consensus document.
TABLE OF CONTENTS

Section I: Executive Summary

Prepared by WRAP Staff

Section II: NOx and PM Emissions from Stationary Sources

Prepared by WRAP Staff

Section III: Nitrate and PM Ambient Concentrations

Prepared by WRAP Staff

Section IV: A Conceptual Model of Regional Haze in the West

and the Role of Stationary Source NOx and PM Emissions

Prepared by Armistead Russell, Georgia Institute of Technology

Section V: Summary of Air Quality Modeling Results

Prepared by WRAP Staff, the University of California at Riverside, and

ENVIRON Corporation

Section VI: Summary of Emission Controls Available for Large Stationary Sources of

NOx and PM

Prepared by Reaction Engineering Incorporated and Energy &

Environmental Strategies

Section VI Bound separately and available at

http://www.wrapair.org/forums/mtf/nox-pm.html
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SECTION I:

EXECUTIVE SUMMARY

Background and Purpose

The primary purpose of this report is to provide the information necessary for western states and

tribes to fulfill the requirements of Section 309(d)(4)(v) of the U.S. Environmental Protection

Agency’s (EPA) regional haze rule (40 CFR 51.309). Specifically, the rule states:

Provisions for stationary source NOx and PM. The plan submission must include a

report which assesses emissions control strategies for stationary source NOx and PM,

and the degree of visibility improvement that would result from such strategies. In the

report, the State must evaluate and discuss the need to establish emission milestones for

NOx and PM to avoid any net increase in these pollutants from stationary sources within

the transport region, and to support potential future development and implementation of

a multipollutant and possibly multisource market-based program. The plan submission

must provide for an implementation plan revision, containing any necessary long-term

strategies and BART requirements for stationary source PM and NOx (including

enforceable limitations, compliance schedules, and other measures) by no later than

December 31, 2008.

The regional haze rule provides the nine western states within the Grand Canyon Visibility

Transport Region (GCVTR) an opportunity to submit state implementation plans (SIPs)

containing policies and programs recommended in the final report of the Grand Canyon

Visibility Transport Commission (June 1996). Such plans must be submitted by December 31,

2003. GCVTR states electing not to submit SIPs under Section 309 must submit SIPs under

Section 308 of the regional haze rule in the 2005-07 time frame. Indian tribes have the option to

submit tribal implementation plans (TIPs) under either section at any time. Moreover, the TIPs

may include reasonably severable elements of the rule. A map of the WRAP region, mandatory

federal Class I areas addressed by the regional haze rule, and WRAP state and tribal members is

provided in Figure I-1.

A major provision of Section 309 is the control of stationary source sulfur dioxide (SO2)

emissions. The provision quoted above – for a report on stationary sources of NOx and PM – is

to ensure that states begin the process of evaluating other pollutants from stationary sources.

Hence, this report is meant as a starting point for a potentially multi-year process of evaluating

stationary sources and designing further control strategies where appropriate. At a minimum,

this process must include the determination of best available retrofit technology (BART) for

certain sources1

 and the resulting visibility improvements and may include an alternative (e.g.,

emissions trading) program achieving greater reasonable progress towards the national visibility

goal of no man-made impairment.

 

1

 BART-eligible sources are those which belong to one of 26 industrial categories, have the potential to emit at least

250 tons per year of a visibility-impairing pollutant, and were put into place between 1962 and 1977.
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Organization of Report

This report is required for the GCVTR states choosing to submit SIPs under Section 309 of the

region haze rule, but since all states must ultimately address stationary source NOx and PM

emissions from BART-eligible and potentially other stationary sources, the scope of this report

goes somewhat beyond the nine states in the GCVTR and the limited number of BART-eligible

sources in the WRAP region. For example, the air quality modeling evaluates the impact of

emission changes within the GCVTR, but at all Class I areas within the contiguous WRAP

region. Also, emission control technologies evaluated in Section VI were chosen on the basis of

source types throughout the WRAP region, which do not differ substantially from those types

within the GCVTR. They were also chosen on the basis of all existing source types, not just

BART-eligible source types, partly because sources eligible for BART as a result of pollutants

other than SO2 have not yet been identified2

 and partly because an alternative program to BART

could apply to a much broader universe of sources. By extending the scope of this report beyond

the nine GCVTR states and beyond the BART-eligible stationary sources, it not only becomes

applicable to a wider range of WRAP members and potential control strategies but serves to

coordinate regional development of such strategies. It is also a more cost-effective approach

than dealing with the nine GCVTR states separately.

As noted above, this report contains analyses and information to initiate a process for evaluating

stationary sources of NOx and PM – a process required of all states and open to Indian tribes as

well. The Executive Summary contains highlights of the report, but it is also where specific

issues raised in Section 309(d)(4)(v), such as interpollutant trading, are directly and succinctly

discussed. This is intended to help Section 309 states and tribes address the literal requirements

of the rule.

Table I-1 shows how analyses within this report were designed to address the specific

requirements of the rule. Emissions data can be used to assess emission control strategies and to

evaluate the need for milestones by illustrating the relative significance of different source

categories to total NOx and PM emissions, both now and in the future. Ambient monitoring data

can be used to assess emission control strategies by illustrating where and how much nitrate and

primary PM may contribute to actual visibility impairment. The conceptual model is intended to

support this entire assessment and to provide a common, scientifically-founded understanding of

western haze and the role of stationary sources in anticipation of a multi-year assessment of their

importance and control options. The conceptual model is intended to provide a more complete

framework than what can be provided alone by the air quality modeling and other assessments.

Air quality modeling is used in a “sensitivity capacity” to assess emission control strategies, their

degree of visibility improvement, and the need for milestones to prevent any future increase in

emissions. A summary of current NOx and PM control technologies and their costs, trends, and

secondary and multi-pollutant impacts can be used to assess emission control technologies and

the need for milestones to support multisource and multipollutant programs. This summary is

also a useful starting point for addressing the BART requirements in Section 308 SIPs and

Section 309 SIP revisions. All these analyses are expected to be updated and improved by the

WRAP before such SIPs are adopted.

 

2

 The full universe of BART-eligible sources does not need to be identified until SIPs and SIP revisions are due in

2005-08, although this identification process is expected to begin in 2003.
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Table I-1. Analyses Contained in this Report and Their Relation to the Requirements in

Section 309(d)(4)(v) of the Regional Haze Rule.

Requirements of 309(d)(4)(v)

EmissionsDataAmbientDataConceptualModelAir QualityModelControlTechnologies

Assess emission control strategies X X X X X

Assess degree of visibility improvement

that would result from such strategies XXX

Evaluate and discuss the need to establish

milestones to avoid any net increase X XX

Evaluate and discuss the need for

milestones to support potential future

development of multipollutant and

multisource market-based programs

X X

Implementation plan revision by

December 31, 2008

Finally, emissions in Alaska are not presented because resources did not permit examination of a

second emissions inventory database, nor are air quality modeling results presented for Alaska

because the visibility modeling system for Alaska is currently under development. However,

ambient monitoring data for Alaska are presented, and the conceptual model and control

technology information are applicable as well.

Summary of Findings

Analysis of current and future emissions, ambient monitoring data, and very limited modeling

results indicates that stationary source emissions of PM probably cause less than 2 percent of the

region’s visibility impairment, whereas stationary source NOx emissions result in nitrates3

 that

probably cause about 2 to 5 percent of the impairment on the Colorado Plateau4

 and about

10 percent of the impairment in some areas of the Northern Plains, Pacific Northwest, and

southern California. These findings may change as emission projections are updated and as

ambient monitoring data from new sites is collected and analyzed, and especially as modeling

capabilities are improved and as more data become available for the best and worst visibility

days.

 

3

 NOx emissions may also increase other PM species.

4

 Some of the 20 percent haziest days, however, are dominated by nitrate.
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Regardless of this or future regional technical analyses, the remedy embodied in reasonably

attributable visibility impairment requirements under the regional haze rule is still available

where BART-eligible sources of NOx and PM are found to have direct impact on specific

mandatory federal Class I areas. Furthermore, when considering NOx and PM milestones,

attention should be given to the reasonable progress goals in the regional haze rule, which

generally entail steady and continuing emission reductions and no degradation on the best

visibility days. Where stationary source NOx emission reductions are appropriate, substantial

reduction may be feasible with commercially-available technologies for about $300 to $1,200

per ton.

Assessment of Emission Control Strategies for Stationary Sources of NOx and PM

Since this report is primarily a starting point for addressing stationary source NOx and PM

emissions, the control of which would not be determined until the 2005-08 timeframe, specific

emission control strategies including such elements as level of control, applicability, and

emissions trading are not addressed. Rather, this report identifies significant issues in assessing

and designing such control strategies and provides some preliminary emissions, monitoring, and

modeling results.

Stationary source NOx emissions comprise about 25 percent of the WRAP NOx emission

inventory. One byproduct of NOx emissions is nitrate aerosols. As described in Section III,

during the 20 percent worst days on the Colorado Plateau, nitrate aerosols are responsible for

about 6 to 18 percent of the man-made visibility impairment, although on some of these days

they are responsible for as much as 40 to 60 percent. At some sites in the Northern Plains,

Pacific Northwest, and southern California, nitrate aerosols are responsible for about 40 percent

of the man-made visibility impairment during the 20 percent worst days. Assuming the

contribution of stationary sources to nitrate is roughly equal to their proportion of the NOx

emission inventory, then stationary source NOx emissions might be expected to contribute to

about 2-5 percent of the Plateau’s light extinction and to about 10 percent of the extinction in the

Northern Plains, Pacific Northwest, and southern California.

Potentially increasing these contributions is the fact that stationary sources have unique emission

characteristics which may disproportionately impact visibility (e.g., stack heights, transport

distances, and proximity to Class I areas). Also, NOx is known to influence the formation of

non-nitrate secondary fine particles, to alter the characteristics of primary coarse particles, and its

future significance may depend on future changes in sulfur and ammonia emissions. On the

other hand, total NOx emission in the WRAP region are expected to decrease by over

25 percent,5

 primarily as a result of federal controls on mobile sources, and NOx reductions may,

in isolated instances, lead to local increases in nitrate concentrations.

To determine the effectiveness of stationary source NOx controls, it is therefore important to

have an air quality model that can account for the processes above. The WRAP’s current

modeling system, while sufficient for analyzing the regional impact of some emission changes, is

not predicting nitrate concentrations well enough to support a decision on whether or not

 

5

 Future NOx emissions will, of course, depend on uncertain activity levels (e.g., oil and gas development) and

regulatory developments (e.g., new source review reforms).
I-5

stationary source NOx controls are an effective way at achieving reasonable progress – the

results are simply too uncertain. Several improvements to the modeling system are underway,

but until the model produces better nitrate results, other means of assessment will be necessary to

determine the appropriate level of NOx control in future SIPs.

Given the model’s current performance, its use in this report is limited to the summer months

(July through September), when it is performing best for nitrate, but also when nitrate

concentrations are lowest. Furthermore, its use is limited to two “sensitivity analyses” – a

50 percent stationary source NOx reduction and a 50 percent stationary source PM10 reduction.

The purpose of the sensitivity analyses is to gauge how nitrate and other atmospheric

constituents might respond to significant changes in emissions, albeit such responses may be

conservative given the model’s limited application to the July – September time period. Results

are summarized in the next part of this Executive Summary and discussed in more detail in

Section V of the report.

As advancements are made towards understanding the air quality impacts of stationary source

NOx emissions, it is appropriate to investigate the potential level of control that can be achieved,

and at what cost. Section VI of this report identifies 34 NOx control technologies. Most of these

are commercially available, while others are near-available. Those for coal-fired boilers (by far

the largest category of stationary source NOx emissions) typically achieve 30 to 50 percent NOx

control at a cost of about $300 to $1,200 per ton.6

 Actual costs and emission reductions are

highly dependent on boiler type, vintage, and configuration, fuel burned, and existing controls.

For these reasons, it is important to have recent, extensive, and reliable data on the emission

source population, some of which are lacking in the WRAP inventory, such as current control

information, utility boiler heat rates, information on the process producing the emissions (e.g.,

from natural gas compressor stations), and utilization rates (e.g., from industrial internal

combustion engines). Future WRAP emission inventories should include such information.

Visibility impairment may occur when a high portion of the NOx emissions are in the form of (or

converted to) nitrogen dioxide gas (NO2). This may be important in urban hazes and in some

coherent plumes, but is typically negligible for regional haze.7

 For this reason, NO2 is not

included in the light extinction budget in the EPA’s guidance for tracking reasonable progress.

Stationary source PM10 emissions8

 are currently 6 percent of the WRAP PM10 inventory and may

grow slightly to 7 percent by 2018. However, the WRAP inventory does not yet include windblown fugitive dust emissions (currently under development), which will tend to decrease the

apparent contribution of stationary source PM10 emissions. PM10 accounts for nearly all the

man-made light extinction, but the amount attributable to primary stationary source emissions is

difficult to determine. Since most of the coarse fraction (between 2.5 and 10 microns) is

believed to be primary and only some of the fine fraction is believed to be primary, the percent

of visibility impairment attributable to coarse particles should approximate the contribution of

 

6

 One exception is selective catalytic reduction (SCR), which is capable of achieving 70 to 90+ percent control at

costs of approximately $1,200 to $2,000 per ton.

7

 See, for example, Watson J., Visibility: Science and Regulation, J. of Air and Waste Manage. Assoc. 52:628.

8

 As explained in Section II of this report, the term “PM” used in Section 309(d)(4)(v) of the regional haze rule is

construed as primary PM10 emissions.
I-6

primary PM10 emissions from all sources. As shown in Section III, this is approximately 10 to

20 percent (on average) across most of the WRAP region, with generally lower percentages in

the Pacific Northwest and higher percentages in the southeast part of the region. Assuming the

contribution of stationary sources to ambient primary PM10 is roughly equal to their proportion

of the PM10 emission inventory, then stationary source PM10 emissions might be expected to

contribute to less than 2 percent of the region’s light extinction. Coupled with the fact that

stationary source PM10 emissions are relatively well controlled in the West, there does not appear

to be much potential in a stationary source PM control strategy for purposes of regional haze.

PM10 emissions, however, appear to have a greater visibility impact per ton than NOx emissions,

as shown in Section V. Also, some PM10 emission co-benefits may result from multi-pollutant

technologies described in Section VI, so reductions in stationary source PM10 emissions could

conceivably be part of a broader air quality management strategy and/or part of a broader

strategy to achieve reasonable progress under the visibility regulations – e.g., to prevent

degradation on the cleanest days.

Finally, the appropriate level of stationary source NOx and PM control, if any, should be

informed by a comprehensive assessment, which may include some non-visibility impacts (to the

extent they can be estimated within WRAP resources and with the WRAP’s visibility-based

tools) and the full costs and benefits of controls, not just those associated with facility

compliance and visibility improvements. To this end, the WRAP is completing work on an

economic analysis framework to conduct such analyses in a consistent and technically sound

manner.

Degree of Visibility Improvement Resulting from Emission Control Strategies for

Stationary Sources of NOx and PM

Due to the complex role of NOx emissions in the atmosphere, a regional-scale modeling effort is

underway to more carefully assess the visibility improvement from potential control strategies.

Given the model’s current performance, its application in this report is limited to the JuneSeptember timeframe – when nitrate performance is best, but also when nitrate concentrations

are lowest – and it is only used in a “sensitivity analysis mode”, meaning two scenarios were

modeled to gauge how nitrate and other atmospheric constituents might respond to significant

changes in emissions: one in which emissions of NOx are reduced by 50 percent (412,000 tpy)

from stationary sources in the GCVTR with emissions of NOx greater than 100 tpy, and an

identical scenario for PM10 (98,000 tpy).

Current modeling results indicate that the stationary source NOx and PM10 emission reductions

described above would reduce regional haze (in Mm-1) by 0.5 percent and 0.4 percent,

respectively, when averaged across all sites in the GCVTR over the June-September time period,

although some areas would see an improvement of 2 to 5 percent on some days.9

 On a purely

ton-per-ton basis, reductions in stationary source PM10 emissions appear to yield greater regional

haze benefits than reductions in NOx emissions, since they produced almost the same visibility

benefit at one-fourth the emission change.

 

9

 These results are similar to the more general assessment made in Section IV (see page IV-21).
I-7

The NOx emission reductions had the greatest impact in southern CA, where ammonium nitrate

concentrations in Class I areas are predicted to decrease by 0.15 to 0.25 ug/m3

. A second area of

reductions is predicted in the central-east Rocky Mountains, especially in north-central CO.

Although the reductions are not as large as in southern CA (0.04 to 0.11 ug/m3), they are larger

than average across the domain and exhibit the largest percentage reduction (10 to 20 percent).

It is interesting to compare these results with those simulating the effects of the SO2 backstop

emissions trading program, or Annex. In the case of the Annex, an SO2 emission reduction of

15 percent (132,000 tons) in the GCVTR produced a sulfate reduction of 4 percent averaged

across all Class I areas in the GCVTR on the 20% worst modeled days. In the case of the NOx

sensitivity run, a NOx emission reduction of 15 percent (412,000 tons) in the GCVTR produced

a nitrate reduction of 5 percent averaged across all Class I areas in the GCVTR on the JulySeptember modeled days. The nitrate reduction does not produce as much visibility benefit at

most Class I areas because its concentrations are much smaller than the sulfate concentrations,

but the response of nitrate to NOx reductions is similar in proportion to the response of sulfate to

SO2 reductions.

NOx changes appear to have very little effect on aerosol concentrations beyond changes in

nitrate. Other species that could be indirectly affected – e.g., ozone concentrations and

subsequent oxidation of SO2 and organic gases into the particulate phase – do not appear

influenced by the levels of NOx reductions (16 percent of the total inventory) assumed in this

analysis.

The PM10 emission reductions had a maximum impact of about 0.1 to 0.5 ug/m3, or about 4 to

8 percent. Compared to the NOx reduction scenario, reductions in ambient PM10 are more

dispersed, with a greater number of local maximums. This may reflect the fact that there are a

fewer number of large PM10 sources than large NOx sources and that much of the PM10

emissions are coarse particles, with shorter transport distances.

All modeling results in this report are subject to change after the modeling improvements

described in Section V are implemented. Results may also change when compiled for the best

and worst visibility and nitrate days throughout the year, as opposed to a three-month summer

average. For reasons described in Section V, the three-month summer average probably tends to

reduce the apparent impact of emission changes.

The Need to Establish Milestones to Avoid Any Net Increase in NOx and PM Emissions

from Stationary Sources

Sensitivity modeling was also done to evaluate the impacts of a 25 percent simultaneous increase

in stationary source NOx and PM10 emissions. The increase in nitrate formation was

approximately half the magnitude of the decrease resulting from the NOx reduction scenario.

However, the increase in PM10 (nitrates and primary particulates) and visibility impairment were

about the same in the 25 percent increase scenario as in the two 50 percent decrease scenarios

because both pollutants were increased simultaneously.
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The need to establish milestones to avoid any net increase in NOx and PM emissions from

stationary sources should be determined when more complete and accurate modeling results (and

ambient data analyses) are available, prior to submittal of the Section 309 SIP revisions in

2007-08. In addition to the modeling results per se, consideration should be given to meeting the

reasonable progress goals of the regional haze rule, which generally imply a steady and

continuous reduction in emissions and a prevention of degradation on the best visibility days.

The Need for Milestones to Support Potential Future Development of Multipollutant and

Multisource Market-Based Program

Milestones are not absolutely necessary to support potential multipollutant and multisource

market-based programs. For example, a group of sources could theoretically comply with an

SO2 milestone by reducing emissions of other pollutants, and/or in other sectors, for which no

milestones exist. Regardless, the key issues raised by such programs do not involve the

milestones as much as the uncertainties associated with such emissions trading.

As discussed in Section IV, there are a number issues that must be addressed. Most of these

relate to the visibility-improvement value of eliminating a ton of emissions. Different pollutants

have different impacts on visibility on a per ton basis. Establishing an “equivalency ratio” to

allow X tons of one pollutant to be reduced in lieu of Y tons of another would require significant

analysis, and the certainty of such values may be suspect (especially for NOx) or insufficient to

ensure a specific level of visibility improvement. Moreover, the equivalency ratio between two

pollutants may vary across the region, between seasons, and possibly over time as the

composition of the atmosphere changes. These same uncertainties (involving trades among

pollutants) also pertain to trades among a single pollutant, most notably NOx, as nitrate

concentrations are highly variable by season and location.

Trading across emission source categories poses a couple of additional issues. First, all

categories would have to have sufficient emissions monitoring to validate emission credits, and

monitoring of non-stationary sources is generally less accurate and verifiable than monitoring of

stationary sources. Second, concentrated emissions from stacks may have different impacts than

diffuse emissions at ground-level.

The uncertainties identified above could be reduced through further research, and the remaining

uncertainties could be further addressed by limiting the emission trading markets to certain

subregions, pollutants, or seasons where the equivalency ratios are fairly certain and stable.

However, such market restrictions could limit the economic benefits the market is intended to

provide. In short, some level of multipollutant and/or multisource market based program could

be a feasible way of meeting the long-term national visibility goal, and several of the

technologies described in Section VI of this report are capable of multipollutant reductions, but

substantially more research should be performed before committing to such programs, especially

in the 2007-08 timeframe.
I-9

Figure I-1. Map of the WRAP Region, Members, and Mandatory Federal Class I Areas.
II-1

SECTION II:

NOx AND PM EMISSIONS FROM STATIONARY SOURCES

Data Sources

The data presented in this section are based on “Version 1” of the WRAP stationary source

emission inventory, downloaded from the WRAP website in June 2002 (filename wga_pt96.dbf).

A second version of the inventory was released in October 2002, which contained a couple dozen

corrections to point source coordinates, stack parameters, and source classification codes among

the 214,000 records in the database. There were also some corrections to the NOx and PM

emissions, which reduced the regional point source totals by two percent and six percent,

respectively. A third version of the inventory was released in March 2003. This version

contained minor NOx and PM emission changes in Pima and Navajo Counties (less than one

percent of state-wide point sources) and NOx emission reductions in Nevada amounting to a

4,400 ton (or nine percent) decrease in the state-wide point source inventory. Discrepancies

noted in Maricopa, Pima, and Pinal Counties by stakeholders in Arizona have not yet been

incorporated into the WRAP database.

For the purposes of this regional-scale characterization of NOx and PM sources, the changes

made to Version 1 of the stationary source inventory are essentially insignificant. The analysis,

therefore, was not repeated. However, the analysis presented in Section VI is based on the most

recent inventory since the analysis was begun after the Version 3 was available. This may cause

slight discrepancies between the data presented here and in Section VI, but the conclusions are

unaffected.

The term “PM” used in Section 309(d)(4)(v) of the regional haze rule has been construed in this

report as primary PM10 emissions. Precursor emissions are not considered “PM” because they

are explicitly referenced where appropriate throughout the rule, as is done with NOx in

309(d)(4)(v). PM10 was chosen over PM2.5 because PM10 includes PM2.5 and because all

particles less than 10 microns have visibility impairing attributes. Moreover, many of the PM2.5

emission estimates are derived from PM10 emission factors as opposed to direct PM2.5

measurements – i.e., a certain fraction of the PM10 is assumed to be PM2.5.

Emissions Summary

Table II-1 provides a summary of air pollutant emissions in the 13-state contiguous WRAP

region (including Nevada but not Alaska). NOx emissions from stationary sources are expected

to increase slightly, but due to decreases from other sources, their percentage of the total

inventory is expected to grow from 22 percent to 33 percent to become the single largest source

category. Stationary source PM10 emissions appear less important than NOx emissions, but they

may contribute more to haze on a per ton basis, partly because not all NOx emissions are

converted to particles and partly because stationary source PM emissions contain some elemental

carbon, which is a highly-efficient light absorber. Compared to other source categories,

stationary sources do not emit a large amount of PM10, but their emissions may contribute more

to haze on a per ton basis than other source categories because they emit particles primarily in
II-2

the fine mode (less than 2.5 microns) and often through stacks, making them more likely to be

transported to Class I areas. Future work should examine available information on the dispersion

characteristics, size distribution, and chemical and optical properties of primary PM emissions

from stationary sources relative to other types of sources.

Table II-1. Air Pollutant Emissions in the 13-State WRAP Region.

Figure II-1 shows the location and relative magnitude of stationary source NOx emissions in the

WRAP region with emissions of NOx greater than 100 tons per year (tpy) on a plant-wide basis.

The WRAP 1996 inventory contains over 6,700 point sources of NOx. Approximately

11 percent of these plants (763) emitted 100 tpy or more of NOx and were responsible for

94 percent of total stationary source NOx emissions. Approximately 150 of the plants are

electric power plants.

Figure II-2 shows the location and relative magnitude of stationary source PM10 emissions in the

WRAP region with emissions of PM10 greater than 100 tpy on a plant-wide basis. The WRAP

1996 inventory contains over 6,500 point sources of PM10. Approximately 5 percent of these

(338 plants) emitted 100 tpy or more of PM10 and were responsible for 82 percent of total

stationary source PM10 emissions.

Figures II-3 and II-4 identify and compare emissions from the major stationary source

categories of NOx and PM10, respectively. External combustion boilers (utility and industrial)

are the largest source categories for both NOx and PM10. Industrial internal combustion engines

(mostly natural gas fired) is another substantial source of NOx emissions. This category may

warrant more attention since it is not inventoried with the same rigor as electric utility sources.

The major source categories of PM10 are more diverse in character than those for NOx, including

such broad categories as mineral products, chemical manufacturing, and primary metal

production. This part of the inventory may also warrant further investigation since many of the

emissions might be fugitive. Categorization of fugitive emission, in addition to source

classifications, may vary across states. Further information on stationary source emissions,

especially on the largest sources (boilers and internal combustion engines), is provided in

Section VI.

Emissions Category tons % tons % tons % tons %

Point 1,059,985 22% 196,005 6% 1,118,460 33% 247,071 7%

Area 352,623 7% 1,921,389 54% 449,559 13% 1,981,060 54%

On-Road Mobile 1,755,573 37% 59,098 2% 485,270 14% 46,139 1%

Off-Road Mobile 1,368,663 29% 103,069 3% 950,414 28% 91,412 2%

Wildfire 166,703 4% 755,537 21% 59,641 2% 270,307 7%

Prescribed Fire 16,688 0% 50,057 1% 338,627 10% 525,393 14%

Agricultural Fire * * * * 3,504 0% 8,894 0%

Paved Road Dust 0 0% 91,322 3% 0 0% 165,106 5%

Unpaved Road Dust 0 0% 370,762 10% 0 0% 326,042 9%

Total 4,720,236 100% 3,547,239 100% 3,405,475 100% 3,661,423 100%

* Not available

1996 2018

NOx PM10 NOx PM10
II-3

Figure II-1. Stationary Source NOx Emissions > 100 tpy in the WRAP Region (1996).
II-4

Figure II-2. Stationary PM10 Emissions > 100 tpy in the WRAP Region (1996).
II-5

Figure II-3. Categorization of Stationary Source NOx Emissions > 100 tpy in the WRAP

Region (1996).

0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000 450,000

Emissions (tpy)

Process Heaters (petro)

Natural Gas Production

Cement Manufacturing

Natural Gas

Wood/Bark Waste

Distillate Oil

Sub/Bituminous Coal

Natural Gas

Natural Gas

Distillate Oil (diesel)

Natural Gas

Lignite

Sub/Bituminous Coal

Utility Boilers

Utility ICEs

Industrial ICEs

Industrial Processes

Industrial Boilers These sources

comprise 91% of the

emissions > 100 tpy
II-6

Figure II-4. Categorization of Stationary Source PM10 Emissions > 100 tpy in the WRAP

Region (1996).

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000

Emissions (tpy)

Misc. Manufacturing

Sulfate (Kraft) Pulping

Not Classified

Copper Smelting

Gold

Iron Production

Metal Mining (General)

Not Classified

Magnesium Carbonate

Nonmetallic Minerals Mining

Coal Mining and Handling

Sub/Bituminous Coal

Wood/Bark Waste

Lignite

Sub/Bituminous Coal

Utility Boilers

Industrial Boilers

Mineral Products

Chemical Manufacturing

Primary Metal Production

Industrial Processes

These sources

comprise 78% of the

emissions > 100 tpy
III-1

SECTION III:

NITRATE AND PM AMBIENT CONCENTRATIONS

Figures III-1 through III-11 show spatial patterns of ammonium nitrate (NH4NO3) and PM

and historical trends in PM at IMPROVE monitoring sites in 1996 and 2001. The maps and data

were downloaded from the VIEWS website (http://vista.cira.colostate.edu/views) on May 20,

2003. At that time, maps were only available for annual and seasonal averages, but some are

now available for the best and worst visibility days. Hence, all the maps in this section except

one indicate annual averages. Also, because the legends are auto-scaled, they are not the same in

each map. For example, the value indicated by a yellow contour in Figure III-1 (1996) is not the

same as the value indicated by a yellow contour in Figure III-2 (2201).

IMPROVE sites are located in rural settings, typically within Class I areas. They are not

representative of more heavily polluted urban areas and tend to represent air quality at regional

scales. Due to the size of the IMPROVE monitoring network, the maps for 1996 include data

from less than a third of the western Class I areas. The maps for 2001 include data from about

two-thirds of the western Class I areas, and additional monitors have been established since then.

Figures III-1 and III-2 show the annual average NH4NO3 concentrations in 1996 and 2001,

respectively. Concentrations are typically less than 0.6 ug/m3

, with some areas in southern CA

and the Columbia River Gorge exceeding 1.5 ug/m3.

Figures III-3 and III-4 show the percent of aerosol-caused10 annual average light extinction due

to NH4NO3 in 1996 and 2001, respectively. This percent is typically less than 14, with some

higher areas in the Pacific Northwest and Northern Plains, and especially in southern CA

(exceeding 20 percent). Since some aerosols – principally organic carbon and “soil” and

“coarse” aerosols – have substantially strong natural sources, the percent contribution of

NH4NO3 to man-made haze is somewhat greater than indicated in Figures III-3 and III-4. A

rough estimate of the contribution to man-made impairment can be obtained by assuming half

the organic carbon, soil, and coarse aerosols are naturally caused. Removing these natural

contributions from the light extinction budgets would raise the percent contribution of NH4NO3

by approximately 20 percent in each of the regions noted above (Colorado Plateau, Pacific

Northwest, Northern Plains, and southern California).11 For example, where NH4NO3 may

contribute to 15 percent of the aerosol-caused light extinction in these areas, it would contribute

to about 18 percent of the man-made light extinction.

Data recently provided on the VIEWS website indicates that the percent contribution of

NH4NO3 to light extinction on the 20 percent worst days, as shown in Figure III-5, is slightly

greater than the percent contribution on average, as shown in Figure III-4. Moreover, a cursory

examination of daily data collected on the Colorado Plateau in 2001 indicates that some of the

20 percent worst days are dominated by NH4NO3. Some examples are provided in Table III-1.

Such episodes should be quantified and studied more thoroughly in future WRAP work.

 

10 Aerosol-caused light extinction excludes natural (Rayleigh) scattering by air molecules.

11 See Table 3.3 in Malm, William C. et al., Spatial and Seasonal Patterns and Temporal Variability of Haze and Its

Constituents in the United States, Colorado State University, May 2000.
III-2

Table III-1. A Sample of Hazy Days in 2001 Dominated by NH4NO3 on the Colorado

Plateau.

Class I Area Date Light Extinctiona

(Mm-1)

NH4NO3

Contribution

2001 Average

Light Extinctiona

(Mm-1)

2001 Average

NH4NO3

Contribution

Bryce Canyon 01/16/01 35 55 % 16 11 %

01/28/01 28 49 %

Canyonlands 01/04/01 23 55 % 14 15 %

01/19/01 31 48 %

01/22/01 33 55 %

San Pedro 01/07/01 16 50 % 11.5 10 %

02/09/01 14 31 %

12/21/01 13 36 % a

 Over and above natural (Rayleigh) scattering by air molecules (10 Mm-1).

Finally, NH4NO3 exhibits a strong seasonal pattern. When averaged across the 32 IMPROVE

sites operating in 1996-1999, the light extinction due to NH4NO3 is about 10 percent on an

annual basis and about 17 percent in the winter.

Figures III-6 and III-7 show the annual average PM10 concentrations in 1996 and 2001,

respectively. Specifically, the values are reconstructed total mass – that is, speciated fine mass

plus gravimetrically-determined coarse mass (PM10 - PM2.5). (Gravimetric PM10 was not

available from the VIEWS website.) PM10 concentrations are typically below 8 ug/m3

, with

some areas in the Columbia River Gorge, Northern Plains, and southern CA exceeding 10 ug/m3

.

Figures III-8 and III-9 show the percent of aerosol-caused annual average light extinction due

to coarse particulate matter (between 2.5 and 10 microns) in 1996 and 2001, respectively. Since

most of the coarse fraction is believed to be primary and only some of the fine fraction is

believed to be primary, the percent of visibility impairment attributable to coarse particles should

approximate the contribution of primary PM10 emissions from all sources to visibility

impairment. As shown in the figures, this is approximately 10 to 20 percent across most of the

WRAP region, with generally lower percentages in the Pacific Northwest and higher percentages

in the southeast part of the region.

Figure III-10 shows trends in (gravimetric) PM10 concentrations during average visibility days

at 27 western IMPROVE sites. Data for the best and worst visibility days are available, but only

data for average visibility days are shown for comparability with the maps in Figures III-1

through III-7. The values shown are 5-year rolling averages, meaning that the value shown for

1993 represents data collected from 1989-1993. The full names of the sites shown in Figure III10 are provided in Table III-2.
III-3

At most sites, there appears to be a gradual decline in PM10 concentrations on days with average

visibility, with exceptions at Chiricahua, Grand Canyon, and Guadalupe Mountain. On the worst

visibility days, however, there is less of a decline, if any, at most sites. Compare, for example,

the trend at the sites shown in Figure III-11 with the first trend chart shown in Figure III-10.

Note that the trends, even when averaged over 5-year periods, can sometimes be affected by one

or two extremely high events, typically associated with wildfires or dust storms. Trends in

NH4NO3 concentrations and the percent of light extinction due to NH4NO3 are not available

because of a measurement bias in data collected prior to June 1996. These data, however, are

sufficient for showing the spatial patterns in Figures III-1 through III-7.
III-4

Figure III-1. Annual Average NH4NO3 Concentrations at IMPROVE Sites (1996).

Figure III-2. Annual Average NH4NO3 Concentrations at IMPROVE Sites (2001).
III-5

Figure III-3. Percent of Annual Average Aerosol Light Extinction Due to NH4NO3 at

IMPROVE Sites (1996).

Figure III-4. Percent of Annual Average Aerosol Light Extinction Due to NH4NO3 at

IMPROVE Sites (2001).
III-6

Figure III-5. Percent of Aerosol Light Extinction Due to NH4NO3 at IMPROVE Sites on

the 20 Percent Worst Days (2001).
III-7

Figure III-6. Annual Average PM10 Concentrations at IMPROVE Sites (1996).

Figure III-7. Annual Average PM10 Concentrations at IMPROVE Sites (2001).
III-8

Figure III-8. Percent of Annual Average Light Extinction Due to Coarse Particulate

Matter at IMPROVE Sites (1996).

Figure III-9. Percent of Annual Average Light Extinction Due to Coarse Particulate

Matter at IMPROVE Sites (2001).
III-9

Table III-2. Name of IMPROVE Sites Shown in Figure III-9.

Code Site Name Code Site Name

BADL Badlands LAVO Lassen Volcanic

BAND Bandalier MEVE Mesa Verde

BRCA Bryce Canyon MORA Mount Ranier

BRID Bridger PEFO Petrified Forest

CANY Canyon Lands PINN Pinnacles

CHIR Chiricahua PORE Point Reyes

CRLA Crater Lake REDW Redwood

DENA Denali ROMO Rocky Mountain

GLAC Glacier SAGO San Gorgonio

GRBA Great Basin TONT Tonto

GRCA Grand Canyon WEMI Weminuche

GRSA Great Sand Dunes YELL Yellowstone

GUMO Guadalupe Mountain YOSE Yosemite

JARB Jarbidge

Figure III-10. Trends in PM10 Concentrations at Western IMPROVE Sites on Days with

Average Visibility.

0

2

4

6

8

10

12

14

1993 1994 1995 1996 1997 1998 1999

PM10 on Days with Average Visibility (ug/m3

)

BADL

BAND

BRCA

BRID

CANY
III-10

0

2

4

6

8

10

12

14

1993 1994 1995 1996 1997 1998 1999

PM10 on Days with Average Visibility (ug/m3

)

GRCA

GRSA

GUMO

JARB

LAVO

0

2

4

6

8

10

12

14

1993 1994 1995 1996 1997 1998 1999

PM10 on Days with Average Visibility (ug/m3

)

CHIR

CRLA

DENA

GLAC

GRBA
III-11

0

5

10

15

20

25

30

1993 1994 1995 1996 1997 1998 1999

PM10 on Days with Poor Visibility (ug/m3

)

BADL

BAND

BRCA

BRID

CANY

0

5

10

15

20

25

1993 1994 1995 1996 1997 1998 1999

PM10 on Days with Average Visibility (ug/m3

)

MEVE

MORA

PEFO

PINN

PORE
III-12

Figure III-11. Trends in PM10 Concentrations at Western IMPROVE Sites on Days with

Poor Visibility (Worst 20 Percent).

0

5

10

15

20

25

1993 1994 1995 1996 1997 1998 1999

PM10 on Days with Average Visibility (ug/m3

)

REDW

ROMO

SAGO

TONT

WEMI

YELL

YOSE
IV-1

SECTION IV:

A CONCEPTUAL MODEL OF REGIONAL HAZE IN THE WEST

AND THE ROLE OF STAITIONARY SOURCE NOx AND PM

EMISSIONS

Introduction

The objective of this report is to provide a foundation for better understanding the dynamics of

PM in the West, with particular attention to the nitrate and primary component that may be due

to point source emissions. Further, the report explores how stationary source NOx and primary

PM controls might impact FPM levels. As part of that, the utilization of a trading system is

discussed. The report sets up a detailed framework to understand the issues by developing a

conceptual model of PM formation, atmospheric dynamics, and impacts in the West. Next, the

report discusses the likely effectiveness of PM and NOx controls on PM levels in the West and

the relationship with visibility. This section also deals with issues involving emission trading.

The final two sections discuss potentially useful computer simulations and a summary.

Overview of PM in the West

The area covered by the Western Regional Air Partnership (WRAP) includes a large fraction of

the continental United States. In an air quality management context, this area has very different

air quality characteristics. In part, this is due to the diversity in the source characteristics of the

region, ranging from large coastal California cities to very sparsely populated and isolated

regions. In the former, the emissions are dominated by mobile sources, disperse human

activities, and a variety of industries. In the latter, natural sources (e.g., fire, dust, and biogenic

emissions) and large point sources (e.g., electricity generating units) can dominate. Similarly

important are the meteorological and topographical differences: e.g., rainy and cool coastal areas

in the Northwest, dry mountainous regions further inland, and deserts in the Southwest.

Pollutant levels and characteristics vary accordingly. Not only do the relative levels of pollutants

vary, but the composition and source contributions change as well. This is especially seen in the

particulate matter composition. In Los Angeles, nitrate (and the associated ammonia) is a major

contributor. Outside of California, nitrate is usually a relatively minor contributor, though the

Columbia Gorge and Seattle areas find somewhat elevated levels (Malm et al., 2003).

Unlike gases, particulate matter is characterized not only by its composition, but by the particle

size as well. From a regulatory standpoint, particulate matter is divided in to three fractions:

fine, coarse and very coarse. To a degree, these capture how the particulate mater size

distribution is considered from a scientific perspective, which is broken in to four modes of

ascending size: nucleation, Aitken, accumulation and coarse modes. The nucleation mode is the

very fine fraction where new particles are formed from nucleation of vapors. Recently, as part of

the Supersite experiments, regional nucleation events have been seen. These particles then grow

into the Aitken mode, which also contains primary emissions from combustion sources, and

finally the accumulation mode. The accumulation mode is aptly named as the smaller particles

grow in to this mode, but the growth out of accumulation mode particles into the coarse mode is

very slow. Recent interest has grown over another possible division of PM: ultrafines (having
IV-2

particle diameters less than about 0.1 um). There is relatively less information about ultrafine

PM.

Fine particulate matter (FPM) is often measured as PM2.5, or particulate matter with an

aerodynamic diameter less than 2.5 micrometers (um). Some measurements of FPM have used

other cut points, but there is a natural cut point at 2.5 um between the accumulation and coarse

modes. On a mass basis, FPM is dominated by PM in the accumulation mode. Thus, coarse

particulate matter is the fraction with particle diameters greater than 2.5 um. Given the historical

measurements of PM10, coarse PM is often taken as the fraction between 2.5 and 10 um. The

fraction above 10 um can be considered as very coarse, and is included (along with the other

fractions) in total suspended particulate matter (TSP) measurements. The reasons for using these

ranges have to do with the somewhat distinct dependence of the various size fractions on source,

their atmospheric dynamics and impacts. Also, if one looks at a size distribution of PM, these

modes become apparent. Characteristics of the coarse fraction are that the particles are

mechanically generated (e.g. from road dust, construction, mining, etc.) and have relatively

shorter atmospheric lifetimes due to settling and deposition, particularly for the very coarse

particles. FPM can be mechanically generated (FPM can be present as the tail end portion of

emissions that are mostly coarse) or from chemical conversion (SO2 oxidation to sulfate,

combustion generation of soot, etc.), the latter often dominating. FPM also has a longer lifetime

in the atmosphere as it deposits relatively slowly, though rain can rapidly remove much of the

FPM. Ultrafines are due to emissions from combustion sources and chemical reactions in the

atmosphere. Like FPM, ultrafines deposit slowly, but have a limited atmospheric lifetime as

ultrafines because they grow due to condensation and coagulation.

While size differences are important, so are species differences. Sulfate is almost solely a

secondary species, formed from the oxidation of SO2 (e.g., from coal-fired EGUs and other

combustion processes). This may take place in the gas phase or from heterogeneous reactions.

Sulfate is found in the fine fraction. Sulfate tends to be one of the largest components of FPM in

the rural West, and still a major fraction in urban areas. Average levels are about 1 ug/m3

 in

rural western areas. Nitrate is also a secondary component, resulting from the oxidation of NOx

to form nitric acid gas, which then undergoes gas-to-particle conversion. NOx emissions are

dominated by combustion sources, though there is a small fraction from biogenic emissions.

Nitrate is also primarily in the FPM range, though tends to have a somewhat larger average

particle diameter than the sulfate. A fraction of the nitrate is found in the coarse mode,

indicative of gaseous nitric acid reacting with preexisting CPM (Malm et al., 2003). In the

West, typical levels of measured nitrate outside of and not downwind of urban areas and central

California tend to be low, averaging well less than 1 ug/m3

. In the Los Angeles basin, nitrate

levels can exceed 25 ug/m3

, and significantly impact areas downwind. Care should be taken in

interpreting measured nitrate levels as the techniques used are subject to artifacts (both positive

and negative).

Organic carbon (OC) is the most complex part of the PM in many ways. First, it is comprised of

many different species. Further, it can be primary or secondary, and biogenic and anthropogenic

in origin. Again, OC is primarily FPM. Levels are highest in the cities or in areas with biomass

burning (e.g., due to wild or planned fires), and there is growing evidence of the importance of

secondary OC (Brown et al., 2000).
IV-3

Elemental carbon (EC), or black carbon, is due to incomplete combustion, and appears to be

primarily from wood burning and diesel vehicle emissions, though other sources contribute, and

the actual fraction due to diesel vehicles is under study. Given the sources, EC is highest in

urban areas, and a relatively small component of FPM in rural locations. While small on a mass

basis, EC does absorb light, so can contribute more significantly to visibility degradation.

Metals, metal oxides and other crustal materials are due to a wide variety of sources, largely

wind blown dust, as well as combustion, cement manufacture, etc. These are largely in the

coarse mode, though a fraction is found as FPM, generally as the tail end of the size distribution

of the coarse PM, or from combustion sources. In the non-coastal states of the West, the soil

fraction is between about 20-30% of the FPM (Malm et al., 2003).

FPM has come to attention as an important fraction of the total particulate matter because of its

potential impacts. FPM has been suspect of impacting human health, and recent and continuing

studies tend to provide further support. (Less information is available for ultrafines). FPM also

exists in a size range (e.g., similar to the wavelength of visible light) that effectively scatters and

absorbs light, decreasing visibility, which is of particular concern in the West with its many

national parks, forests and wilderness areas. Coarse particulate matter is of less concern

(though still some) due to its shorter lifetimes, apparently reduced health effects and it is less

effective, on a mass basis, of scattering light.

FPM levels in the West go from very low, with some of the lowest annual averages found in the

US, to very high, with the Los Angeles area experiencing some of the highest. Other areas in the

West experience isolated events of high PM (e.g., due to dust storms and fires) but annual

average levels tend to be low. In much of the West and other parts of the country, the FPM is

dominated by organic carbon and sulfate, while nitrate is typically a more minor constituent.

While levels of these components, as well as FPM in general, are usually lower than in the east,

the sources appear to be similar: sulfate comes from fuel combustion, particularly coal fired

power plants and organic carbon comes from biomass burning and secondary formation. Of

interest, recent results from the BRAVO study using molecular markers (Brown et al, 2002)

suggest that a significant fraction of the organic FPM is secondary, as do similar studies in the

Southeast. Carbon 14 dating of the organic matter in the Southeast (Edgerton, 2002) further

suggest that the secondary organic is biogenic, which, given the emissions in the Big Bend area,

would likely be the case there. Unlike most other areas, in Los Angeles and the Central Valley

of California nitrate is a significant contributor, along with organic carbon and some sulfate.

Literature Review

Particulate matter dynamics has been an on-going research topic for decades. In-depth

treatments of atmospheric particulate matter are contained in Seinfeld and Pandis (1998) and

Friedlander (1977). The impact of PM on visibility has likewise been studied for years, with

early work by van de Hulst (1957), and on-going study from the IMPROVE (Interagency

Monitoring of Protected Visual Environments) program begun in 1985 (e.g.,

http://vista.cira.colostate.edu/improve/, and Malm, 2000, and references there in). Early studies
IV-4

of nitrate dynamics and response to emissions controls include Stelson and Seinfeld (1982) and

Russell and Cass (1984).

In the WRAP area, particulate matter studies have been conducted for years. One could group

them in to urban vs. pristine area studies, or a second split could be California studies and the

rest of the west. The urban vs. pristine area consideration is typified by studies with different

considerations, e.g., in urban areas health and attaining the National Ambient Air Quality

Standards are often the drivers, while in pristine areas, visibility is of primary importance. The

latter distinction, between California and other areas in the west, is made on a couple of bases.

First, California has been very active in conducting air quality studies, in part because of the

severe air quality problems in that state. Second, as presented in the regional conceptual model

discussion below, particulate matter in regions in California is compositionally distinct from

what is found over much of the West.

Outside of California, the primary information that is available concerning PM in the West is

derived from the IMPROVE program (e.g., Malm, 2000), and a number of studies focusing on

specific areas. IMPROVE is an ongoing study of visibility in Class I areas in the U.S. most

notably national parks. Amongst its objectives are to monitor the composition of particulate

matter in protected environments and identify sources. Other, more regionally focused studies

include the Big Bend Regional Aerosol and Visibility Observational (BRAVO) study (see Green

et al., 2000, Brown et al., 2002) those associated with the Grand Canyon and Colorado Plateau

(e.g., Grand Canyon Visibility Transport Commission, 1996 and project MOHAVE: Lowenthal

et al., 2000), Mt. Zirkel (e.g., Watson et al., 2001), the Denver Brown Cloud, which included the

Northern Front Range Air Quality Study (NFRAQS) (e.g., Watson et al., 1998). The Grand

Canyon studies were directed primarily at assessing how nearby power plants (in particular, the

Navajo Generating station) impact visibility in areas on the Colorado Plateau, which includes a

number of Class I areas, including the Grand Canyon, which had experienced days with

decreased visibility. BRAVO is assessing the sources of particulate matter and visibility

degradation in the Big Bend area of Texas, and NFRAQS studied visibility in the area around

Denver. While not focused on PM in the West, the Southern Appalachians Mountains Initiative

(SAMI) study (SAMI, 2002) is relevant here because it addressed many of the same issues,

except for the focus on Class I areas in the southeastern United States.

Within California, a number of programs are available for providing information on particulate

matter in various regions. First, a number of Class I areas in the state do have IMPROVE

monitors, which provide both a long term record of PM composition, as well as a means of

comparing, directly, levels in California with those in other states. In addition, California has

conducted a number of additional, intensive efforts, most notably in the Los Angeles area and the

Central Valley. In the Los Angeles (or South Coast) Basin, two studies are of particular note: the

Southern California Air Quality Study (SCAQS) and the Southern California Ozone Study, 1997

(SCOS97). There have been a number of additional studies as well, notably those by Cass and

coworkers (e.g., Hildemann et al., (1984); Gard et al., 1998), and the current studies associated

with the Supersite (e.g., Sioutas et al., 2003). In the Central Valley, the San Jaoquin

Valley/Atmospheric Utility Signature Prediction Experiment (SJV/AUSPEX), the California

Regional Particulate Matter Air Quality Study (CRPAQS) and the Fresno Supersite are providing
IV-5

detailed information on the air quality and sources in that region. The two Supersite studies,

however, are more focused on urban air quality, and less focused on visibility in protected areas.

A number of publications and reports discuss the results of the IMPROVE program,

documenting the composition and trends and their relationship to visibility. A recent manuscript

by Malm et al. (2003) presents the annual average fine particulate matter composition in each of

30 IMPROVE regions. In general, sulfate levels in the West are significantly below those in the

East. Ammonium nitrate is high in southern California and the Lower Central Valley, with very

low concentrations most other locations in the West (generally less than 0.5 ug/m3

 except in

isolated spots, Malm et al, 2003). It should be noted that ammonium nitrate is actually not

measured, but inferred from the nitrate measurements. As they note, nitrate can also be found in

other forms, some of which are thermally stable (e.g., from the reaction of nitric acid with soil or

sea salt, Malm et al., 1994; Gard et al., 1998 ). Organic carbon, regionally, typically runs

between 0.5 and 2 ug/m3

. Elemental carbon levels are low, typically below 0.5 ug/m3 on

average, but can be an important component in terms of visibility reduction. A recent trends

report from IMPROVE (Malm, 2000, also see Sisler et al., 2000 and Malm et al., 2002) shows

that trends in PM levels are mixed throughout the West. For example, Sisler et al., (2000) found

that of the western sites where a significant trend was found, not quite two thirds reported

improvements. In some cases, decreases of one component (e.g., sulfate) were off set by another

(e.g., organic carbon), as found at Jarbridge Wilderness area. At the Guadalupe Mountains NM,

organics are going down, but nitrate and fine soil are going up, with no real change in visibility.

In the Mt. Zirkel Visibility Study (Watson et al., 2001), the major components that impaired

visibility were found to be sulfate, organic carbon and crustal material, similar to the results form

IMPROVE monitors in the region. Nitrate was a small contributor. Greater amounts of nitrate

were found during the NFRAQS study, presumably because of the more concentrated sources of

oxidized nitrogen in an urban area, and the proximity of confined animal operations.

Given the use of regional PM modeling, it is instructive to compare the modeling conducted here

with similar studies, in particular BRAVO and SAMI, as well as other applications of PM

regional models. In the SAMI study, the Urban-to-Regional, Multiscale (URM) model was used

(Odman et al., 2002), and used the Decoupled, Direct Method (Yang et al., 1997) to assess

source impacts and response to controls. They also assessed the response of PM levels to

emissions changes corresponding to varying levels of controls. Results of their modeling was

used to calculate the expected changes in visibility, stream health and ozone damage (SAMI,

2002). Model simulations led to FPM mass having an normalized error of under 50%. Sulfate

and elemental and organic carbon simulations also found errors on the same order, but nitrate

predictions were high. Seigneur (2003) recently completed a report discussing regional

modeling applications of CMAQ and REMSAD, two of the more commonly used regional PM

models. The focus of this review was the model performance in the BRAVO, WRAP, Southeast

US and various EPA studies. In general, model performance in the studies outside of the WRAP

found PM predictions with a normalized error of 35-90%. Nitrate predictions had the largest

error.

SAMI air quality modeling dealt with many of the same issues being addressed currently by the

WRAP (Odman et al., 2002). Specific issues addressed were quantifying the relationship
IV-6

between emissions and various air quality endpoints, including PM levels, deposition and ozone.

PM results, which were by species, were used for visibility calculations. Specific results of

relevance here include:

• PM reductions were sub-linear to controls, and that the degree of sub-linearity increased

as PM concentrations decreased. For example, when sulfate concentrations were highest,

a 10% reduction in SO2 emissions resulted in an approximately 8-9% reduction in

sulfate. At lower sulfate levels, the same 10% reduction led to a smaller percentage

change. For nitrate, the sub-linear response was greater. A 10% reduction in NOx led to

about a 5% reduction in nitrate, averaged over the year.

• Reductions in sulfate led to an increase in nitrate levels.

• Increases in ammonia led to an increase in nitrate.

• Nitrate formation was generally ammonia-limited.

These findings are important both individually and collectively. Over the next few years, SO2

emissions are expected to decrease and ammonia emissions are expected to increase, both

leading to increases in nitrate. SAMI results suggest that these increases will be relatively small,

but non-zero. However, in many locations, they offset the 27-63% reductions in NOx, such that

nitrate actually increased. It is difficult to translate how similar changes will impact the WRAP

regions, particularly since the WRAP regions are more heterogeneous. However, the

preliminary results from the CMAQ modeling suggest that nitrate formation is ammonia-limited

in a large part of the West. The sub-linear response suggests that controls will not get as much

reduction as might originally be expected. However, the greatest fractional improvements will

occur on the most heavily impacted days.

A final reference that provides a good overview of the issue is the NARSTO Assessment

(NARSTO, 2003). It provides a more thorough discussion of many of the issues contained here,

as well as conceptual models of PM dynamics in a number of areas of the United States.

Conceptual Model of Primary PM and Nitrate Dynamics in Western Airsheds

Here, conceptual models are developed to help elucidate the dynamics of both primary and

nitrate PM in various western airsheds, starting with primary coarse and fine PM, which are not

as involved with gas-to-particle conversion and less complicated. Note, secondary species can

condense on primary PM, so even primary species can impact the formation and properties of

secondary material.

Coarse PM is typically emitted by mechanical processes, e.g., grinding operations, transport of

solid materials, road dust and wind blown dust. Further, CPM is typically emitted near the

ground, not from tall stacks. In part, this is due to controls on large point sources. CPM has a

relatively short lifetime, on the order of a few hours, though particles at the upper end of the

coarse mode will have very short lifetime. For wind blown dust, this is much of the mass.

Primary CPM can be attacked by nitric acid, and because of the shorter lifetime, act as a sink of
IV-7

nitrate PM. Given total primary CPM emissions of 70 tons per year (tpy) (1/2 of the total PM10

emissions), one can develop a first order estimate of the contribution to total PM in the region by

dividing by the approximate volume of the boundary layer in the WRAP area (~1015 m3

), and

multiply (~1 hr) by the lifetime. This leads to an average contribution of large point sources to

PM of 0.005 ug/m3

, a small fraction, again, on average. However, high levels of CPM are often

very episodic (dust storms) or very local: i.e., within a few km of the source. Further downwind,

the emissions have deposited and been diluted.

A portion of the CPM can be secondary, e.g., due to reaction of nitric acid on the surface of the

aerosol, or condensation. Measurements suggest that a non-insignificant fraction of the nitrate in

the regions outside of the California valleys is coarse. As discussed below, the existence of CPM

nitrate is important from a control point of view. CPM nitrate is less likely to be reduced from

reductions in ammonia as compared to FPM nitrate.

From this conceptual model of CPM, driving points are:

• CPM is predominantly primary, with a fraction due to gas-to-particle conversion, e.g., by

the reaction of nitric acid with pre-existing particles,

• CPM has a relatively short lifetime,

• CPM can act as a sink for nitrate, and

• CPM is typically episodic, often occurring during periods with large amounts of

windblown dust.

Primary FPM is emitted, often as a combustion by-product, in to the atmosphere, where it

undergoes transport, growth, deposition, rain-out and a variety of other processes. The size of

such emissions are typically in the ultrafine region, though from some processes the average

particle size can be larger, e.g., as fine and coarse PM (e.g., cement manufacture). If emitted as

an ultrafine, the small particles will likely grow in to the accumulation mode via condensation of

other compounds to it (primarily) and coagulation with other particles, staying as FPM.

Primary FPM is transported very efficiently, essentially as a gas, since its sedimentation velocity

(the rate at which it falls due to gravity) is very slow. As such, it will follow the prevailing

winds and be distributed vertically and horizontally due to atmospheric turbulence. Removal of

FPM occurs due to wash-out (e.g., rain and snow) and dry deposition. Dry deposition is slow,

slower than many gases, due to the slow transport of FPM across the fluid dynamic boundary

layer near solid surfaces (gases diffuse much more rapidly than particles) and low sedimentation

velocities. As an example, for a 1 um particle, the deposition velocity is on the order of 5x10-4

 m

s

-1. Using a boundary layer height (e.g., the well mixed portion of the atmosphere near the

earth’s surface) of 1000m, this leads to an atmospheric lifetime of about 3 weeks, and the

particles will be transported out of the region before depositing. Larger particles will deposit

somewhat faster as their sedimentation velocity is higher (the particles are heavier), and very

small particles will as well since they diffuse faster. With such long lifetimes, wash-out can be

very important, particularly in areas that have frequent rains. Depending on the intensity of the
IV-8

rain, FPM can be very effectively removed, such that the lifetime of the FPM is very directly

linked to the frequency of rain. Without rain, FPM is generally transported out of the airshed or,

as will be discussed for nitrate, be lost due to some other process. The lifetime due to transport

in the region is on the order of 10 days. Using this, along with assuming that one half of the

primary PM emissions from stationary sources (Seignuer et al., 2003) are fine, one calculates

that the average primary FPM levels would be on the order of 1 ug/m3

. This is somewhat above

what is measured as crustals in most locations, and more in line with the measured organic

carbon. However, organic carbon would be due more to wood boilers and internal combustion

engines. Using just those emissions, the average contribution to the organics would be less than

0.1 ug/m3

. This is in line with source apportionments that suggest a large fraction of the organic

carbon is due to biomass burning and other processes (e.g. Maykut et al., 2003). The stationary

source emissions estimates would suggest that primary FPM from stationary sources may have a

regionally significant impact, though this calculation is conservative and does not take in to

account rainout and other loss processes.

If the primary FPM is emitted from the stack of a large point source, it will be transported in the

plume with the gaseous pollutants and can undergo somewhat more rapid growth due to the

concentration of condensable compounds. It may also be transported above the well mixed

boundary layer, delaying the dry deposition loss mechanism, at least temporarily. When the

mixed layer grows to capture the plume, the FPM will be diffused downwards. Given the cloud

heights relative to the typical effective plume height, washout will typically remove FPM from

plumes.

During transport, primary FPM can grow. Growth will depend upon the particle size and

composition. Of particular importance is the hygroscopicity of the compounds in the particles.

Some compounds will readily absorb water, such that in a humid environment, they will grow

significantly, e.g., doubling in size. If the compound is hydrophobic, they will undergo more

slow growth due to condensation of other compounds. Water is not the only compound that will

be selective as to which particles are most readily absorbed. Semi-volatile organic gases can

have a preference for particles with similar-structured organic matter already present. SO2(g)

can be absorbed in to particles that already contain water, and then oxidized to form sulfate.

Nitric acid will prefer non-acidic particulate matter. Important here is to recognize that a

primary particle will interact with its environment, and end up as having both primary and

secondary components. From a visibility standpoint, this is important since the growth can make

the particles more efficient at degrading visibility. While the argument could be made that the

condensable species would find some other process to form particulate matter without direct

emissions (e.g., nucleation, followed by condensation), there is an abundance of water that would

not necessarily do so. Further, as compounds such as sulfate condense on primary FPM, they

can become more hygroscopic. Since primary emissions of FPM can undergo atmospheric

growth, it is not directly apparent that decreases in FPM emissions will lead to the same level of

decrease in FPM in the atmosphere. Indeed, greater reductions may be realized if the nuclei

provided by the primary FPM is a limiting factor in the formation of secondary FPM. On the

other hand, the observed effects may not be as enhanced since the condensable species will find

other particles.
IV-9

From this conceptual model of primary FPM, driving points are:

• FPM has potentially long lifetimes in the atmosphere,

• Wash-out is an important loss mechanism,

• Ultrafine primary FPM can grow in to a size range that is efficient at scattering light,

• Hygroscopic FPM can pick up water and become diffusive, and

• Even if emitted from tall stacks, primary FPM can be diffused downwards to the

surface.

Particulate nitrate dynamics is significantly more complex than for primary PM because of the

added chemistry and gas-to-particle/particle-to-gas conversion. While there is a small amount of

primary nitrate emissions, most of the particulate nitrate in the troposphere starts out as NOx

which was emitted from a combustion process. NOx, which is well known for its role in the

formation of ozone, can be oxidized to nitric acid via two important pathways. During the day,

NO2 is oxidized by the hydroxyl radical:

NO2 + OH →HNO3

This reaction is responsible for most of the nitric acid formation. A second route takes place

mostly at night. First, NO2 is oxidized by ozone to the nitrate radical, NO3:

NO2 + O3 →NO3 + O2

(The nitrate radical should not be confused with the nitrate ion, NO3

-

). Next, the nitrate radical

reacts with NO2 to form dinitrogen pentoxide, N2O5:

NO2 + NO3 →N2O5

N2O5 then reacts with water to form two nitric acid molecules:

2 5 2 3 N O + H O →2HNO

This reaction is slow in the gas phase, but can occur rapidly on the surface of a particle that

contains water. However, the rate of this reaction is very uncertain, and it is believed that the

rate used by CMAQ in the past may be too high (Dennis, 2003, personal communication),

leading to an over prediction of PM nitrate. NO3 photolyzes very rapidly, and during the

daytime it is found at very, very low levels, blocking this formation route when the sun is up.

The nitric acid gas formed from the above reactions can dry-deposit out, be washed out, or

undergo gas-to-particle conversion. Nitric acid reacts very rapidly with surfaces, and deposits

out rapidly. It’s lifetime to dry deposition is on the order of a few hours. Nitric acid is also very

soluble, and is removed effectively by rain.
IV-10

In terms of particulate matter formation, nitric acid is a strong gas and can attack pre-existing

particles, being adsorbed or displacing other compounds present. For example, nitric acid gas

can displace chlorine in a sea salt-derived particle, leading to sodium nitrate and HCl(g).

Likewise, it can react with alikilinic crustal material to form PM nitrate (e.g., Malm et al., 2003).

In both such cases, the particulate nitrate formed is in the coarse fraction because the original

particle was in the coarse mode. In many regions, the route to forming FPM nitrate is via the gas

phase reaction between nitric acid and ammonia (NH3):

HNO (g) NH (g) NH NO (aerosol) 3 + 3 → 4 3

followed by gas to particle conversion. The reaction is reversible, and the ammonium nitrate can

thermally decompose. The forward and backward reactions are fast enough such that the two

reactions are often considered to be in equilibrium:

NH NO (aerosol) K HNO (g) NH (g) 3 + 3 ←→ 4 3

where K is the equilibrium constant. Thus, the fraction of nitrate formed is very sensitive to the

abundance of ammonia available, as probed later. In areas with substantial quantities of

ammonia, large amounts of nitrate can be formed (e.g., in areas with confined animal

operations). In areas with relatively little ammonia, or where the ammonia available is bound as

ammonium sulfate (or ammonium bisulfate), very little nitrate is present. Another factor is that

the equilibrium constant is very temperature dependent, and at higher temperatures, the gas

phases of the two compounds is preferred. The equilibrium makes the formation of ammonium

nitrate very nonlinear. In some cases, e.g., in an environment rich in ammonia but with little

nitric acid, the ammonium nitrate levels are governed almost solely by the available nitrate (e.g.,

nitric acid formation), and ammonia reductions will have little impact. If ammonia is low, it is

the controlling species

Surprisingly, nitrate levels, locally, may go up when NOx emissions are decreased. This is

analogous to the disbenefit found in the response of ozone to NOx emissions. Regionally, NOx

reductions will reduce ozone because NO2 is needed to form ozone. However, locally, reducing

NOx can lead to local increases in ozone for two reasons. The most easily understood is that

NOx is primarily emitted as NO, which titrates ozone. This is important at night. During the

day, NO2 reacts with the hydroxyl radical, significantly lowering OH levels. This decreases the

rate of VOC oxidation, which reduces the rate of NO oxidation to NO2, which reduces ozone

formation. Most of the hydroxyl radical formed comes from ozone photolysis, so lower ozone

reduces OH formation. Thus, there is a positive feedback. NOx emissions increases decrease

ozone, decrease OH, and decrease the rate at which NO2 is oxidized to nitrate, locally.

Regionally, more nitric acid will be formed. In the SAMI study, this appeared to be a second

order effect.

Complicating the nitrate formation issue is the presence of other condensed phase species, in

particular sulfate. As noted above, ammonium nitrate formation is very sensitive to the

availability of ammonia. SO2 oxidation, which is faster in the summer when hydroxyl levels are

highest, leads to the formation of sulfuric acid, H2SO4. Sulfuric acid reacts with ammonia to

form ammonium bisulfate [(NH4)HSO4], and if enough ammonia is present, ammonium sulfate
IV-11

[(NH4)2SO4]. Ammonia will preferentially react with sulfate to form the above two species

before reacting with nitric acid to form ammonium nitrate. As such, the presence of sulfate will

reduce the amount of ammonia available to form ammonium nitrate. In many cases, there is so

little free ammonia that ammonium nitrate is not formed. On the other hand, nitric acid that has

reacted with sea salt or crustal material to form sodium/calcium nitrate does not require

ammonia, so there can be some aerosol nitrate even in high sulfate areas, though typically not as

much as in high ammonia/low sulfate areas.

The interaction between sulfate, nitric acid and ammonia has implications for the “lifetime” of

nitrate in the atmosphere as sulfate is reduced: decreasing sulfate will make more ammonia

available to form PM nitrate, reducing nitric acid gas levels. The PM nitrate deposits much less

rapidly than nitric acid, so the total abundance of nitrate in the atmosphere will increase. Thus,

decreasing sulfate levels may lead to somewhat more nitrate than is expected from just

considering the amount of nitric acid currently available to form PM nitrate.

Sulfur dioxide reductions will lead to the reduction of sulfate particulate matter, and hence, can

lead to more ammonium being available to form ammonium nitrate, leading to what is referred to

as the “rebound effect”. In this case, the sulfur dioxide controls will not lead to the expected (or

desired) reductions in particulate matter because as sulfate decreases, nitrate increases due to the

availability of ammonia in a condition where nitrate formation was ammonia limited. This was

found to be true in the SAMI study to a limited degree.

One issue that should be addressed is the impact of certain NOx controls on increasing ammonia

emissions, e.g., SCR and SNCR. Compared to other sources of emissions, such controls would

represent a very small fraction of the total ammonia emissions. However, in the plume, the

ammonia emissions might be high enough to lead to an increase in ammonium nitrate, and hence

impact visibility in concentrated plumes.

Washout is very important to nitrate levels. Not only will rain remove the nitrate aerosol, but

will also remove nitric acid gas and ammonia very effectively. Clouds can also increase the

oxidation of SO2 to sulfate, which captures ammonia, and is also washed out. Some of the

lowest FPM levels are found following a rain storm.

From this conceptual model of PM nitrate, driving points are:

• PM nitrate formation is due to both gas and heterogeneous reactions forming nitric

acid from nitrogen oxide emissions, followed by gas-to-particle conversion,

• FPM nitrate is largely due to reaction with ammonia, while CPM nitrate is due to

reactions of nitric acid on a preexisting particle,

• Reducing ammonia can reduce nitrate formation in areas that are “ammonia limited”,

but may have little impact in areas where there is an abundance of ammonia, and
IV-12

• NOx controls can reduce nitrate in areas where ammonium nitrate formation is nitrate

limited, as well as areas where nitrate is formed from the reaction of nitric acid on

pre-existing particles.

This conceptual model is diagrammed in the figure below. It should be noted that this figure, or

the discussion above, does not have all of the complexities leading to nitrate formation. The

atmospheric chemistry involves hundreds of compounds, and thousands of reactions. Describing

the physical processes is equally complex. The systems of equations governing the pollutant

evolution are non-linear. Pollutants evolve spatially and temporally. For such reasons, complex

computer models are generally used to study the details of the pollutant dynamics. However, a

good picture of the system dynamics, and an understanding of the importance of various

processes can be developed from a simplified, zero-dimensional model.

While very simplified, a zero-dimensional model can be used to demonstrate the important

features and resulting formation and loss of particulate nitrate. In this case, the model includes

the formation of nitric acid, peaking during the day, an increase in temperature during the day,

going from 10 to 30 C, the increase in the equilibrium constant with temperature, deposition of

nitric acid, and a constant level of ammonia/ammonium. The result is that the highest levels of

PM nitrate occur at night and the early morning, going to zero during the hottest parts of the day.

Nitric acid peaks during the day when all of the ammonium nitrate has dissociated. Most of the

nitrate deposits during the day since nitric acid is so reactive with surfaces. In the SAMI project,

the deposition of oxidized nitrogen due to nitric acid was about an order of magnitude higher

than for PM nitrate, due both to the higher nitric acid levels and deposition velocities.

One of the important features of this system is that while ammonium nitrate does not deposit

rapidly, nitric acid does. Thus, an ammonium nitrate aerosol will disappear relatively rapidly in

a continual, two-step process: the nitric acid gas deposits rapidly as a gas. The ammonium

nitrate will thermally decompose to replace the lost nitric acid. The nitric acid released will then

deposit out, etc.. At higher temperatures, i.e., when a significant amount of the nitrate is in the
IV-13

gas phase, this process can be rapid. In cold areas, almost all of the nitrate will be bound as

ammonium nitrate, and the thermal decomposition is slow, so the process is inhibited.

A multi-day observation of aerosol nitrate levels is shown in Figure 2, along with the

temperature trace. As shown, nitrate goes up in the morning due to NOx oxidation along with

low temperatures. As the temperature increases, the nitrate decreases and goes to near zero

during the day. While not shown, sulfate also increases during the day, scavenging ammonia and

further decreasing nitrate levels.

Particles and Visibility

As noted previously, particles can degrade visibility. The three primary mechanisms are Mie,

Rayleigh and Geometric scattering, and absorption. Only a few types of particles absorb visible

light effectively. Most notably is elemental carbon. Mie scattering occurs from a complex

interaction between light waves and particles of a size similar to the wavelength of light (visible

light ranges from about 0.2 to 0.8 um). Larger particles scatter and block light. Air molecules

also scatter light (Rayleigh scattering), limiting visibility on even the cleanest days.

Visibility, or visual range, xv, is often calculated using the Koschmeider formula:

ext

v b

x

3.912 =

where bext is called the extinction coefficient, and is generally given in Mm-1. The extinction

coefficient is calculated by accounting for all of the processes scattering and absorbing light.

While very complex formulas have been derived, a useful parameterization that corresponds to

he air quality data usually available from IMPROVE and other sites is:

b 3 f (RH)([Sulfate] [Nitrate]) 4 f (RH )[Organic] [Soil] 0.6[CPM ] 10[LAC] ext = T + + org + + +
IV-14

where fT(RH) is a function to account for sulfate and nitrate absorbing water (forg(RH) is a

similar function for organic material), [Sulfate], [Nitrate], [Organic] and [Soil], are the measured

masses of the corresponding fine PM constituents, and [LAC] is the measured mass of the “light

absorbing carbon” similar to EC, (depending on measurement technique). The latter term

accounts for absorption. At relative humidities (RH) above 40%, fT(RH) is greater than one,

going up to above 5. However, forg(RH) is taken as one. Given this, one sees that, on a mass

basis, sulfate and nitrate are usually more effective at scattering light than organics, soil and

CPM. LAC is very effective at absorbing light, and a small amount can lead to significant light

extinction. Another measure of visibility impairment is the deciview (Pitchford and Malm,

1993). It is proportional to the log of the extinction coefficient and relates to the perception of

haziness. Given the non-linear nature of the relationship between deciviews and extinction

coefficient, but the linear relationship between extinction and PM composition, for the purposes

of this report, it is easier to consider extinction.

Regional Conceptual Models

The above description of the formation and fate of primary FPM and nitrate was done for a

general case, without consideration of regional differences in either the processes impacting

primary FPM and nitrate. In the West, many such regions exist. To provide a better

understanding of how such differences manifest themselves, four sub-regions of the WRAP are

identified based on their meteorological and FPM characteristics. The four regions are: wet

coastal, dry mountainous, southwest desert, and California valleys. Wet coastal regions include

the coastal regions starting in northern California to the Olympic Peninsula, and include the

coastal mountains. The dry mountainous sub-region includes the Rockies, the Sierras, and other

drier mountainous areas. The southwest desert region would include non-mountainous areas in

Arizona, New Mexico, Colorado and Nevada. California valleys include the Los Angeles basin

and the surroundings (including the mountainous and desert areas downwind) and the Central

Valley and surrounding mountains. A fifth case, considered separately, but not as a separate

region, “in-and-near,”., i.e., those regions that have significant sources of PM either directly

within or nearby. For example, a Class I area near a major city or facility with very large

emissions, or if the activities within a Class I area led to significant emissions. The IMPROVE

investigators have dissected the west in to 15 regions, which is more than is needed for

developing the conceptual models as done below. However, which “IMPROVE” regions fall in

to each of the four given below are noted.

Wet, Coastal Subregion

This subregion occurs along the Pacific coast and the Puget Sound, in to the coastal mountains

and the Cascades. As such, it includes the IMPROVE Pacific Coastal and Cascade Mountains.

As the name implies, this region tends to be wet, and is known for rain, and can also experience

intense coastal storms. The temperatures tend to be cool. There are a few population centers in

this region (e.g., Portland and Seattle).

PM levels in the coastal region tend to be low, e.g., on the order of a 3-4 ug/m3

 average over the

year (Malm et al., 2003). Average levels of nitrate and primary FPM are very low: 0.2-0.8

ug/m3

, though nitrate is higher in the Puget Sound and Columbia Gorge areas (Malm et al.,
IV-15

2003). The rain removes FPM and its precursors and coastal winds ventilate the region. The

cloudiness of the area inhibits the rate of oxidation of NO2 to nitric acid. There are relatively

fewer sources of FPM and precursors in the region. Higher levels of FPM are experienced in the

population centers. In the Class I areas, FPM tends to be primarily sulfate and OC, with little

nitrate and primary material. Biomass burning (e.g., forest fires) appears to be a major

contributor in some areas, as suggested by high OC levels, particularly during some very high

events. In terms of the general conceptual model, discussed above, particulate nitrate can be

formed from the reaction of nitric acid with sea salt. Ammonium nitrate formation in the area

appears to be limited by the presence of both free nitrate and ammonium. On the other hand, the

cool temperatures promote converting what little available nitric acid and ammonia is available

in to ammonium nitrate. Without further investigation (e.g., longer term, detailed modeling) it is

difficult to tell how nitrate will respond to controls, but it is likely that the formation is limited by

NOx emissions, not ammonia. Results from the WRAP modeling suggest that part of Oregon is

ammonia sensitive (Tonneson, 2003).

The days with the most severe visibility impairment appear to be impacted most heavily by

organics (particularly during severe episodes) and sulfate.

Dry, Mountainous Subregion

This region includes the more inland mountains, and would contain the Sierra Nevada, Wasatch,

Northern Rocky, Sierra-Humboldt and Central Rocky Mountain IMPROVE regions. These

areas are much drier than the coastal mountains. While not immune to rain and storms, they are

less frequent, particularly during the summer. Temperatures tend to get hotter during the

summer. During the winter, temperatures can get quite low. The area has a relatively low

population density, and few major source regions, though is relatively agricultural. Major point

sources include utility boilers, and smelting operations. Confined animal operations can lead to

areas of very high ammonia. Forest fires, particularly in the northern mountainous areas (e.g.,

Montana and Idaho) and the Sierras can lead to very large PM concentrations during episodes.

In such cases, OC dominates mass.

FPM levels in this region are low, around 2-5 ug/m3

 in Class I areas. Again, cities have higher

levels. Nitrate and primary FPM levels are a small fraction of the total (0.1 to 0.4 ug/m3

, except

in the regions of the Sierra Nevada that are influenced by emissions in the Central Valley),

particularly during the some of the most polluted events that are dominated by sulfate. Given the

low levels of nitrate, and the likely higher ammonia emissions, nitrate formation is likely limited

by nitric acid formation from NO2. Simulations by UCR tend to suggest a mixture of

sensitivities (Tonneson, 2003).

The days with the most severe visibility impairment appear to be impacted most heavily by

organic matter or sulfate, though some events have very high levels of coarse mass as well.

Nitrate tends to be a relatively small contributor, which is to be expected when sulfate is high.

Because the measurements can not distinguish as to the source of primary PM, it is not

immediately apparent as to the source of the coarse mass, but given the episodic nature, it is

likely that the primary PM is natural in origin.
IV-16

Southwest

This region includes the far eastern part of southern California, Arizona, New Mexico, southern

Colorado and Nevada. IMPROVE regions corresponding to this region are the Great Basin of

Nevada, the Colorado Plateau and Sonoran Desert. The Southwest has features similar to the

Dry Mountainous subregion, being dry and having low FPM levels. It differs in that

temperatures tend to be higher, and there is a greater abundance of major point sources of NOx

and FPM. Biogenic sources in much of the southwest are very small, but appear to be a major

component of the OC nonetheless (Brown et al., 2000). Ammonia emissions are less dense,

though crustal material can be higher from wind blow dust as this area finds higher soil

concentrations than the others (Malm et al., 2003).. While more detailed modeling is needed, it

would appear that the higher levels of sulfate measured, and the apparently lower levels of

ammonia emissions, would make this area ammonia limited much of the time.

The days with the most severe visibility impairment appear to be impacted most heavily by

sulfate, OC and nitrate, though some of the events with the lowest visibility have very high levels

of coarse mass, likely associated with dust storms. There are periods with very high levels of

OC, indicative of major biomass burning events (forest fires).

California Valleys

This subregion is the most distinct of the four, and includes California’s Los Angeles Basin and

the Central Valley, and the areas most directly impacted by transport from these regions (e.g.,

downwind of Los Angeles and the mountains directly along the valley, including part of the

Sierra Nevada). This region is relatively dry and warm. There are periods of significant

stagnation. Most importantly, this region has greater emission densities of the pollutants

impacting nitrate PM, in particular both NOx and ammonia. These characteristics lead to

substantially higher FPM levels, especially for nitrate. Nationally, this region has the highest

nitrate levels.

Of all the regions, most is known about the dynamics of PM here due to a history of studies

being sponsored by the state of California, industries and others. In Los Angeles, the high nitrate

levels are due to the large emissions of NOx, e.g., from mobile sources, confined animal

operations leading to high ammonia emissions, low ventilation rates concentrating both sets of

emissions, and plentiful sun, oxidizing the NO2. In parts of the basin, e.g., before the air masses

pass over the confined animal operations, nitrate formation is ammonia limited. Further

downwind, the formation becomes nitrate-limited as there are plentiful ammonia emissions and

the nitric acid continues to deposit out. The highest nitrate levels are found in the fall when the

sunlight still leads to rapid oxidation of NO2, winds are light, there is little rain, and the

temperatures are lower favoring the formation of ammonium nitrate. On hot summer days, the

ammonium nitrate thermally decomposes, though large amounts of nitrate can be present during

the cooler hours.

The Central valley shares some of the characteristics of the LA basin, but has some unique

features. First, the sources of NOx differ, having a larger non-mobile component, and being less

dense. There are widespread agricultural and animal operations leading to ammonia emissions
IV-17

throughout the valley. There can be long stagnation events with fog and very little ventilation.

During these stagnation events, nitrate levels can build.

An interesting study of the NOx-nitrate relationship was recently completed for the San Joaquin

Valley using a box model (Stockwell et al., 2000). They found that for each gram of NOx

emission, approximately 0.6 grams of nitrate is formed. This is a high ammonia region, so while

those results are in general agreement with field measurements in the region, the extrapolation of

those results elsewhere is limited.

For both areas, the days with the greatest visibility impairment are high in nitrate, OC and

sulfate, with episodes of coarse material.

In and Near

A few Class I areas lie very near a major source region (e.g., a city) or specific source (e.g., a

major highway, mining operation or power plant). In this case, the PM levels can be higher than

experienced by the rest of the region, and have a different composition. Examples that are near

source regions include San Gorgonio (downwind of Los Angeles) and Casa Grande and Tonto

National Monuments near Phoenix. In this case, the PM takes on a characteristic that is a blend

between these in the urban area and the regional background. For example, this can lead to

elevated nitrate, as particularly found in San Gorgonio, and organic and elemental carbon. For

areas near major sources, the PM can be enriched in the compounds being directly emitted by the

source. Secondary pollutants, particularly sulfate, take longer to form, so there is less of a direct

impact, but some enrichment is likely (e.g. Grand Canyon Visibility Transport Commission,

1996; Pitchford et al., 1999). Pollutant dispersion reduces the apparent source impact relatively

rapidly, so after a few 10s of km, the impact from that source is reduced by an order of

magnitude or so. This is particularly true for CPM which also deposits rapidly. Also, human

activities within a protected area (e.g., driving, fires, etc.) can contribute to locally higher PM

levels. However, these sources are outside of the subject of this study, do not appear to be a

significant contributor to visibility degradation regionally, and are not dealt with further here.

Particulate Matter Modeling

Currently, the most scientifically well-founded approach to assessing how future emissions

changes will impact air quality is to use a physically and chemically comprehensive air quality

model that describes the evolution of pollutants in the atmosphere. Such models (actually,

multiple models are used) are complex, and are run on fast computers. The WRAP is now using

such an approach. In particular, the WRAP is using the Models-3 suite of models, including

SMOKE for emissions, MM5 for meteorology and CMAQ for air quality, including particulate

matter. MM5 is one of the most widely used meteorological models, and CMAQ is an

increasingly popular air quality model.

MM5 solves the equations governing the motions of the atmosphere. These equations are very

complex and non-linear, and sensitive to boundary and initial conditions. The model uses a

variety of parameterizations to simulate various processes. For some processes, MM5 has more

than one choice of parameterization since no one approach appears to be universally best. This,
IV-18

in part, shows the complexity of meteorological models, and that modeling errors can be

expected. Errors can grow with time, degrading performance in longer simulations if nothing is

done to constrain the growth. For this reason, data assimilation is used where observations are

used to adjust the results as the fields evolve. As such, the model results are sensitive to model

inputs (including initial and boundary conditions), model parameterizations and errors in the data

used in the assimilation. While MM5 often achieves very good performance, there are events

where good performance is elusive.

CMAQ is a comprehensive chemical transport model, developed primarily by the US EPA and

funding from that agency. It represents the state-of-the-science in most aspects, and has been

developed for use by the modeling community. Its use by the community is, in part, to help it

evolve and continuously improve. CMAQ contains processes describing gas phase chemistry,

aerosol dynamics, dry and wet deposition, pollutant transport and more. A common

configuration of CMAQ uses CB-IV, a rather older, simplified chemical mechanism, though

versions exist with RADM-II and SAPRC-99, two of the newer, most comprehensive and well

tested mechanisms.

All three models have been used in a variety of efforts in the past. MM5 and CMAQ, the two

predictive models, have been able to show good performance, at least for some species, though

performance can vary from site to site and study to study. Since CMAQ uses the results from

MM5, poor performance by MM5 can lead to similarly poor performance from CMAQ.

However, even with ostensibly good performance from MM5, CMAQ may not perform well due

to poor emissions inputs and/or problems with CMAQ itself, e.g., how it treats various processes.

Further, here, CMAQ is being applied using a 36 km grid resolution. Such large grids are not

appropriate for assessing the impact of a point source of CPM on nearby areas because of the

rapid deposition of the larger particles, and the artificially large dilution of the emissions over the

36x36 km grid.

Model Performance Issues

Confidence in using such a model is derived from successful evaluation of the results. What

constitutes good model performance varies by pollutants, and for FPM there is no standard

criteria. Recent modeling efforts have found errors for sulfate to be within about 50%, OC

within a similar range, and nitrate within about 100% (Seignuer, 2003).

However, current model performance found for the WRAP effort suggests poor model

performance for some species, particularly nitrate (up to a factor of 10 high in the winter, but

some days with essentially no nitrate formation simulated in regions where nitrate is monitored

to be present). It is difficult to assess the model performance for primary FPM from stationary

sources since the measurements and the model results are not able to support such an evaluation.

How does poor model performance affect the use of the results, in particular for quantifying the

likely impact of emissions changes?

First, it is important to understand the likely reasons for the poor nitrate performance. It is

unlikely that the NOx emissions estimates are very far off, so other problems likely exist.

Ammonia emissions are much more uncertain, and can be part of the problem. Also suspect is

the deposition rate used for nitric acid (too low) and the nighttime, heterogeneous oxidation of
IV-19

NOx to nitric acid (too high), both leading to higher levels of nitrate. The reasons for having too

little nitrate during the summer (e.g., no nitrate is sometimes predicted when some is observed)

may be because the nitrate present is particulate nitrate formed from nitric acid attacking preexisting particles to form a thermally stable form of particulate nitrate (e.g., soil material and

salt), slight overestimates in the amount of sulfate formed or underestimates in the ammonia

emissions. Monitoring has found that a significant amount of the nitrate in Class I areas outside

of southern California is larger FPM or coarse, suggesting that it is formed from nitric acid

attacking pre-existing aerosol forming a thermally stable form of nitrate. If this is the reason for

the discrepancy, and that ammonium nitrate is not present, then the modeled sensitivity to

emissions reductions will be very different than would occur. In particular, an area that might

appear to be ammonia limited from the modeling, may be nitrate-limited, and most sensitive to

NOx emissions.

A large error indicates that either the sensitivity to emissions changes is in error, or there is a

large error in the emissions. If the latter were true, the model results could be used to scale

observed levels to get a reasonably good approximation of how the ambient levels would

respond. The decision was made, in advance, in SAMI to use scaling, even for the species where

very good performance was found. Note, if performance is perfect, the same results are found if

one uses scaling or the model results directly. Thus, the approach is asymptotically correct.

If model performance is poor, scaling the observations with model results becomes more

questionable. Given the very large errors found for nitrate, the low correlation between observed

and simulated levels, and that NOx emissions are relatively well known (probably well within a

factor of two), the modeled sensitivity of nitrate levels to NOx emissions could be well off.

Indeed, the very low observed nitrate, versus that simulated, suggest that much of the time the

model is in a different regime than the actual atmosphere (e.g., the case where the two species,

ammonia and nitric acid, are in sufficient supply to form aerosol nitrate vs. the case where one or

both are at concentrations low enough to negate ammonium nitrate formation, and what little

nitrate found is due to reactions of nitric acid with a crustal material or sea salt). Performance is

worst during the winter, but during the summer there are days where no nitrate is predicted,

though some is observed. In this case, NOx controls will not lead to any change in predicted

nitrate, so scaling will not show any benefit. Given the performance problems, it is difficult to

suggest if the sensitivity of either the annual nitrate levels, or the nitrate levels on the days with

the most limited visibility, is adequately represented by the model.

One issue concerning the use of scaling is that it does not account for spatial inhomogeneities in

the controls. For example, control at a specific source, even though it is a very small fraction of

the total inventory, will have an enhanced local impact, though little impact further away. This

issue can be dealt with by using the model to develop source-receptor relationships, and use

those results to help guide the scaling.

For primary fine and coarse PM, the response of ambient PM is likely to be quite linear (though

not totally due to particle growth), so scaling should work relatively well, as long as the issue of

spatial inhomogeneities in the emissions controls is adequately addressed. This can be relatively

easily tested using a single model simulation.
IV-20

At present, the simulations have not been conducted to provide a complete source apportionment

of the PM. By this, one means exercising the model to show how each source (or group of

sources) impacts PM at specific receptors (e.g., the Class I areas). Such a calculation can be very

helpful in suggesting controls. Further, it is important to understand the magnitude of the

problem with which we are dealing, and how to interpret model results and observations. In

particular, this is important for primary PM. At most Class I areas, FPM is dominated by

secondary species (nitrate, ammonium, sulfate and a fraction of the OC), and primary EC and

OC. Other compounds are a relatively small contributor to both FPM mass and visibility. One

question, for which the model can be used to help understand, is if a significant fraction of the

PM is from stationary sources. If not, i.e., that stationary sources are a small fraction of the

primary PM at Class I areas, and that primary PM is a small fraction of the total PM, reductions

in primary PM emissions will have a rather small impact.

Effectiveness of PM and NOx Controls on PM levels and Visibility in the West

As discussed above, nitrate is a major contributor to PM levels and visibility extinction in a few

areas of the West, notably in California, and to a lesser amount the Columbia Gorge. In the

southern half of California, nitrate can be the major constituent. In most other areas, nitrate is

found at relatively small concentrations, around 5-20% of the total FPM. Likewise, point source

primary emissions of PM, both coarse and fine, are a small contributor, regionally, as well.

Thus, controls on point source emissions of NOx and PM will have a relatively limited effect on

both PM and visibility in much of the West, all else being equal. The latter clause is important

because, as SO2 emissions are reduced, and ammonia emissions increase (as is forecast in many

areas), aerosol nitrate may become a more significant contributor, as was found in SAMI.

In and around the California valleys, nitrate formation appears to be nitrate limited. As noted

above, Stockwell et al., (2000) found that one gets, roughly, about 0.6 grams of nitrate (as

ammonium nitrate) per gram of NOx emissions. This would suggest that, in these areas, NOx

controls will reduce nitrate levels. The exact level of benefit will have to come from either

analysis of the measurements or modeling after performance improves. The California inventory

suggests that about 478 tons per day (tpd), or about 14% of the 3441 tpd statewide, of NOx come

from stationary sources. Assuming that stationary sources have a similar impact on nitrate

formation (SAMI results suggest this is not totally true, Odman et al., (2002)), this puts an upper

bound on the likely benefits of around 15%, and the results of the SAMI study suggest that the

actual impact on nitrate mass is more around 7%. This translates in to approximately 2% of the

total FPM in areas around Los Angeles where nitrate makes up about 30% of the total FPM and

1% in areas of California, such as the Sierras east of the Central Valley where nitrate is about

15% of the total FPM. In other areas, the stationary source contribution, on average, would be

smaller, on average. Three considerations would increase the importance somewhat: on days

with the worst visibility in these areas, nitrate makes up a larger fraction of the total (in some

cases, over 50%) on days with the highest levels of nitrate, a greater fractional response to NOx

reductions is suggested and if the receptor is directly downwind of a major point source, the

impact would be increased. The first two considerations might lead to an increased impact of up

to 5%. The latter consideration would be very site and meteorology dependent.
IV-21

Elsewhere in the West, nitrate levels are relatively small: usually less than a ug/m3

, and from 5-

10% of the total PM. The days with the worst visibility tend to be dominated by one of three

cases: high CPM and crustal (indicative of dust storms), high organic and elemental carbon

(which can indicate forest fires) or high sulfate, which tends to be elevated much of the time, and

increases during stagnation. Thus, unless the increasing ammonia and decreasing sulfate lead to

significant nitrate increases, stationary point sources will lead to only about 2% (or less) of the

visibility extinction, except in areas significantly impacted by major sources. SAMI modeling

suggested that there will be small additional benefits of NOx controls in reducing sulfate due to

decreased sulfur dioxide oxidation. Thus, NOx controls will have a relatively small impact on

PM and visibility in the West.

The impacts of primary PM controls on point sources are more difficult to assess at this time

since the available data is less specific as to the fraction of PM from point sources. As noted

above, CPM has such a short lifetime that reductions will have a small impact on PM levels and

visibility, except very near the source. Primary stationary source FPM, while longer lived, still

appears to be relatively minor, contributing less than 0.1 ug/m3

, so controls on FPM would also

have a minor impact on PM levels and visibility. This is in line with the results from studies such

as those conducted at Mt. Zirkel (Watson et al., 1996). Total removal would lead to a decrease in

extinction of about 0.4 Mm-1, or less than about 0.5% of the total extinction on a day with

relatively bad visibility of about 20 miles.

The above analysis suggests that primary PM and NOx controls will have limited impact on

visibility in the West in the near term, except in areas of California and areas directly impacted

by specific stationary sources being controlled. Near-field impacts of sources needs to be

conducted on a site-by-site basis. However, as sulfate levels come down, the impact of NOx

controls will increase, both because nitrate levels will increase and due to the non-linear

relationship between visibility and extinction. Locations whose visibility is currently dominated

by sulfate may find that nitrate becomes the species of concern. Looking towards the future, it is

prudent to identify the types of controls and mechanisms to increase their cost effectiveness.

Emissions Trading

Emissions trading is viewed as an economically efficient approach to air quality management, as

has been experienced through the acid rain program. However, when trading pollutant

emissions, the economic efficiencies tend to decrease as limits are placed on trading, e.g.,

spatially, temporally, across sectors, and across pollutants. There are issues associated with

each. Allowing spatially diverse trades can shift emissions reductions and the resulting air

quality improvements.

Temporal trading can lead to decreased (or enhanced) benefits. For example, sulfate tends to be

higher in the summer due to more rapid oxidation. If the trading results in greater reductions

during the winter, average sulfate levels may decrease less than if the reductions were more

uniform. On the other hand, if the SO2 reductions are greater in the summer, the benefits could

be enhanced. This may be more critical for nitrate which, as discussed above, is very sensitive to

temperature, and is thus found predominantly in the winter. Primary emissions would not be

affected as much.
IV-22

Trading across source sectors may be impacted by (1) the spatial and temporal trading concerns

identified above, (2) that sources can emit at different elevations above the ground, and (3) that

different sectors do not have the same PM characteristics. Emissions from a tall stack are in to a

very different environment than a more dispersed ground level source. First, elevated emissions,

e.g., from utilities, tend to be very concentrated in NOx, and the plumes can stay very NOx rich

for significant distances. Ground level sources tend to be more disperse and in to environments

with higher levels of VOCs. In recent field experiments, this has been found to have an impact

on ozone formation efficiencies (e.g., Ryerson et al., 2001). Recent modeling has also found this

to be the case for ozone and acid deposition, and nitrate FPM (Odman et al., 2002), though the

differences were not as large as that measured for ozone. For primary FPM, this is likely a small

impact, though ground level FPM emitted in populated areas would likely lead to a greater

exposure than if emitted higher up. It is likely that the spatial and temporal issues are of greater

concern. A final concern is that trading primary PM emissions between sectors can lead to a

different type (e.g., predominant size) of PM being emitted. For example, utility emissions are

likely going to be more fine than, say, cement production or mining emissions (as well as being

emitted at different levels). CPM deposits faster, and impacts visibility less. Thus, removing a

ton of CPM would not have the same benefit as removing a ton of FPM, all else equal. In this

way, trading primary PM emissions between sectors is much like trading pollutant types, with

the issues discussed below.

Scientifically, the most challenging type of trade is across pollutant types, e.g., SO2 for NOx,

primary PM for NOx, etc. This is because it is difficult to quantify how much of one pollutant

can be traded for another and have equal air quality benefits. The possibility of displacement

reactions further clouds how such trades can be weighted. For example, reducing SO2 will lead

to sulfate aerosol reductions. However, this can free up ammonium to react with nitric acid,

leading to increased nitrate. While this was found to be the case in SAMI modeling, the

“rebound effect” was not large. Finally, the different species will have different impacts, e.g., in

terms of visibility reduction. For example, each fraction of the PM has a different impact on

visibility per mass. Nitrate and sulfate have a greater impact, on a per mass basis, than soil or

CPM. Further, sulfate and nitrate both have a greater impact on visibility at higher humidities,

other constituents do not, generally leading those two constituents to have a bigger impact on

visibility on a per mass basis than (say) organics. Conversely, elemental carbon is very effective

at absorbing light. If one can correctly account for the relationships between emissions and the

resulting concentrations, it is straightforward to account for the visibility impairment differences,

though the relationships can change with time. For example, as SO2 emissions are reduced in

the future, and ammonia emissions increase, the area could become more sensitive to NOx

emissions. Thus, one ton of NOx reduction may become more valuable in relationship to one ton

of primary FPM.

A final issue is that reducing NOx emissions will impact both secondary sulfate and OC

formation. This is because NOx is central to the formation of ozone and increasing the oxidizing

capacity of the atmosphere. Modeling as part of SAMI suggested that this secondary effect is

small, but non-zero, impacting mainly the formation of sulfate. Typically, reducing NOx also

reduced sulfate formation slightly, but in some locations NOx reductions led to small sulfate

increases due to increasing H2O2 formation and the heterogeneous oxidation of SO2, as well as
IV-23

increasing OH levels. In general, these secondary impacts will slightly enhance the effects of

NOx emissions reductions, but can be ignored for now due to the larger uncertainties in

quantifying the NOx-aerosol nitrate system response.

Given the complexities, the question arises is, if emissions trading is to be done, how should

trading equity be established. If the trades are somewhat restricted to the point that there are no

obvious resulting inequities (e.g., limited spatially and not across pollutants, and that there is

little likelihood that there would be little temporal or elevation differences), policy makers could

likely proceed without the use of some more extensive approach. However, this would severely

restrict the market and the associated economic benefits. Dealing with the issues identified is

ideally tackled using a comprehensive air quality modeling effort, such as is being done by the

WRAP. In this case, the model could be exercised to identify the appropriate trading ratios and

the inequities resulting from various trades.

A major problem at this time, as discussed above, is that confidence in a model’s use can only be

developed through successful evaluation and good model performance for the species of interest.

In the case of the WRAP modeling, nitrate performance was poor, and it would be difficult to

use such results to assess how to make trades equitable, e.g., to develop trading ratios across

pollutants. While less of an issue, using the model to assess trading SO2 for FPM is also

difficult because of the rebound effect. When model performance is such that the WRAP is

comfortable that the model is adequately capturing the physics and chemistry affecting pollutant

evolution of the compounds of interest, then the model, presumably, can be used to determine

how to make trades equitable. Note, this does not mean that performance for all species has to

be good. Having poor performance for crustal species would not significantly impact the use of

the model for comparing SO2 and NOx trades.

Given the successes achieved from emissions trading, it is important to identify model

performance problems such that trading guidelines can be established in a sound fashion. None

of the issues identified above are “show stoppers”. However, given the level of uncertainty in

the modeling results at present, inter-pollutant trading would have the potential to jeopardize

visibility improvements in the region.

Suggested Model Simulations

At present, a few sensitivity simulations have been conducted using CMAQ. While conducted,

in part, to understand model performance, they are providing insight into PM dynamics in the

West. In particular, the cases where NH3 emissions are being changed to find areas that are most

sensitive to NH3 emissions. Such sensitivity calculations are key to addressing trading issues

and identifying effective control strategies.

After model performance is judged to be adequate, a number of calculations are suggested. A

first set of calculations is to conduct a comprehensive source apportionment by source type (e.g.,

point, area and mobile), pollutant (SO2, NOx, NH3, CPM and FPM), and location (e.g., state or

region). The resulting matrix (a total of about 45 sensitivities) can be used to guide trading,

assessing the impact of transport, identifying important source regions to pristine areas, and

guiding control simulations. While 45 simulations may appear prohibitive, various tools exist to
IV-24

facilitate the process. For example, SAMI used DDM-3D. The results of these sensitivities

should be stratified into days with very good and poor visibility, and the annual average. The

aggregation of days will tend to suggest a more local impact of sources than looking at a typical

day.

A second set of simulations would be to explore specific control issues, e.g., the imposition of

certain sets of controls. A particular interest would be to explore future PM levels as the NOx

and SO2 emissions are decreased, but NH3 emissions increase. The interest would be to assess if

there is the possibility of increased nitrate formation due to the higher NH3 and lower sulfate in

spite of lower NOx emissions, as was found in the SAMI study. In some areas, this may lead to

nitrate replacing sulfate as the major contributor to visibility reduction, greatly increasing the

impact of NOx controls on visibility.

A third calculation would look at how SCR or SNCR controls would impact visibility in a point

source plume. The ammonia in such a plume might lead to locally increased ammonium nitrate

formation. While, regionally, ammonia emissions from such control technologies are small

compared to animal waste decomposition and fertilizer, on a very local scale there may be

increased PM formation. Such a calculation may require a finer grid being employed in

locations to capture the finer scale impacts of the plume where, presumably, both NOx and NH3

would be elevated.

Summary

The states that are part of the WRAP have a very diverse chemical/PM “climatology”,

represented by extremes ranging from the dry, high nitrate areas in Southern California to the

wet, low PM northern coastal mountains, to the dry mountains and deserts inland. Typically, the

major constituents of the visibility-impairing PM are fine PM sulfate, OC and, at times, nitrate,

though there are episodes of high coarse material.

Doing a simple, approximate, mass-lifetime balance on coarse PM emissions from primary

sources suggests that, on average, primary CPM emissions from point sources will contribute a

very small fraction of the total PM. This is borne out in the observations. Near the source

(within a few 10s of km), however, the sources may be significant. FPM is much longer lived

than CPM, and is predominantly secondary, being composed primarily of sulfate, OC and nitrate.

Primary FPM from point sources is estimated to be a small contributor to FPM mass and light

extinction on a regional basis. First, the total amount is small relative to other components of the

FPM. Second, it has a lower impact, on a per mass basis, than other constituents. Third, periods

of highest extinction do not appear to have significant amounts of point source-derived, primary

FPM as compared to the other components, particularly CPM during dust storms, organic and

elemental carbon during fires, sulfate during stagnation events, and nitrate in areas of high

ammonia.

Nitrate is formed from emissions of NOx that react to form nitric acid, which then can undergo

gas-to-particle conversion. Much, but not all, of the nitrate is fine, and higher observed

concentrations are formed from the reaction between nitric acid and ammonia to form
IV-25

ammonium nitrate. A fraction of the nitrate will be formed from nitric acid attacking preexisting PM (coarse or fine). Ammonium nitrate levels can be reduced by either reducing nitric

acid formation or ammonia emissions, with the greatest sensitivity to reducing the precursor that

is least abundant (on a mole basis). Thus, some parts of the region will be ammonia-limited,

others will be nitrate-limited (e.g., areas with high ammonia, such as near confined feeding and

intense agricultural operations). The fraction that is formed from nitrate attacking pre-existing

PM will not be very ammonia sensitive, responding more to NOx controls. Modeling currently

suggests that much of the domain is ammonia-limited (in terms of nitrate formation). However,

CMAQ does not include the capability to simulate the nitric acid attacking pre-existing PM, so

this may be an artifact. What this suggests is that it is important to get model performance to the

point where one is confident that the nitrate formation mechanisms are quantitatively reliable.

In areas where nitrate formation is nitric acid-limited, NOx controls will generally reduce PM

(with a few local exceptions). However, one ton of emissions reductions will not lead to one less

ton of PM being formed. NO, NO2 and nitric acid all deposit out (dry or wet). Indeed, nitric

acid deposits very rapidly, and simulations suggest that most of the mass will be removed this

way. The WRAP model can develop the response of nitrate PM to NOx emissions.

Trading emissions of primary FPM from one source to another would be relatively

straightforward compared to other types of trades. The relative height of emission will have little

impact on far downwind receptors. As with trading any type of emissions, trades across sources

in very different locations may lead to one area receiving greater air quality benefits than

another. Trading emissions of point source CPM would be especially sensitive to location in that

the major impact is very near the source, dropping dramatically within 10 km.

NOx emissions trading to reduce PM formation would be more complex. First, as noted above,

some (if not most) regions are likely ammonia-limited, so NOx controls will have relatively

smaller impacts on nitrate than might be expected. Second, the oxidation of NOx to nitric acid

will depend on emission height and the intensity of emissions (e.g., the concentration of NOx in

a plume). Third, reducing NOx will slightly impact the formation of sulfate and OC. Further

complicating the issue is that an equitable trade (in terms of visibility) today may not be

equitable in the future. Again, trading across large spatial areas may lead to issues in terms of

which areas benefit most.

Trading between pollutants is more involved yet, and a major concern is that the relationship

between NOx emissions and nitrate formation is not well quantified at present. As model

performance improves, there is no reason that it would not be practical to use the model to set

trading relationships between pollutants. In so doing, one must account for the differing impact

on visibility on a mass basis and the response to humidity.
IV-26

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IV-27

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V-1

SECTION V:

SUMMARY OF AIR QUALITY MODELING RESULTS

Context

The modeling performed for this report is best described as a “sensitivity analysis.” The intent is

to get a preliminary assessment of the general atmospheric response to changes in NOx and PM

emissions from stationary sources. A secondary objective is to “practice” this type of modeling

to get a better understanding of the key technical issues and to identify the most effective ways at

evaluating and displaying model results. The results presented here are the best available

predictions at this time, but forthcoming improvements to the modeling system may affect the

results in ways that alter the policy implications. For this reason, results are discussed in a fairly

broad and qualitative manner – i.e., spatial patterns and relative changes. As the modeling

system improves and specific strategies are contemplated, additional emission scenarios will be

designed and modeled.

Modeling System

The WRAP’s regional-scale air quality modeling system used to support other aspects of the

Section 309 plans was also used to provide information for this report. A description of the

modeling system – in addition to model performance statistics, input files, and detailed model

results – is available at http://pah.cert.ucr.edu/rmc.

Emission Scenarios

Three emission scenarios were simulated:

 A 50 percent decrease in NOx emissions from plants with NOx emissions > 100 tpy,

 A 50 percent decrease in PM10 emissions from plants with PM10 emission > 100 tpy, and

 A 25 percent increase in NOx and PM10 emissions from all stationary sources.

The first two scenarios are meant to address the regional haze rule’s requirement to “assesses

emissions control strategies for stationary source NOx and PM, and the degree of visibility

improvement that would result from such strategies.” As discussed in Section VI of this report,

many commercially-available technologies (and various combinations of such technologies) are

capable of achieving a 50% or greater NOx emission reduction without having to switch fuels.

Hence, the 50% reduction, although intended primarily to gauge the general atmospheric

response to NOx reductions, is not an unreasonable level of control to assume for this exercise in

terms of technical feasibility. Again with technical (and administrative) feasibility in mind,

emission reductions were limited to plants with emissions greater than 100 tpy, similar to the

approach in the Annex. The third scenario is meant to address the rule’s requirement to

“evaluate and discuss the need to establish emission milestones for NOx and PM to avoid any net

increase in these pollutants from stationary sources within the transport region.” Hence, a

25 percent increase from all stationary sources was assumed to simulate potential growth in the
V-2

economy and/or disproportionate growth in high-emitting sectors such as energy development,

fossil-fueled electricity generation, and mineral processing.

For reasons implied in the rule, the emission changes in the scenarios described above were

limited to the nine-state GCVTR12. Also, the emission changes were applied to the 2018

inventory, which includes reductions expected from full implementation of the Annex. This

provides a basis for comparing results to other strategies being modeled by the WRAP.

Model Performance and Future Improvements

Nitrate concentrations are poorly predicted by the current modeling system, especially in the

winter. For this reason, results for nitrate (and all other species) for the NOx and PM sensitivity

runs are only presented for the three month period of July – September.

Several aspects of the modeling system are being improved and evaluated, which should improve

confidence in future model predictions, both in the summer and winter. These improvements

and evaluations involve the chemical mechanisms, the ammonia inventory, a more robust

meteorological database (2002 vs 1996), enhanced grid resolution (12 km vs 36 km), plume-ingrid capabilities, the introduction of an inventory for wind-blown dust emissions, and better

temporal allocation and chemical speciation of point and area source emissions. A source

apportionment mechanism is also expected to be included with the model.

Model Results

As stated above, results are presented in a fairly broad and qualitative manner – i.e., spatial

patterns and relative changes. Relative (percent) changes are of particular interest because their

errors are believed to be smaller than those of the absolute concentrations. It is not clear how the

seasonal limitation of this analysis (July – September) may affect the relative changes, but it is

likely to reduce them to some extent. First, nitrate concentrations tend to be lower in the summer

than in the winter, especially in areas where nitrate concentrations are highest and the potential

for change the greatest. Second, results are averaged over a full three-month period. Typically,

visibility effects are measured by averaging conditions over the worst 20 percent of the days

observed per year at an ambient monitoring site, which is approximately 22 days. But in this

analysis, because it is limited to the July-September timeframe, the results are averaged over 92

consecutive days and do not represent a measure of the worst conditions, again when the

potential for change is the greatest. Thus, while there are many uncertainties surrounding the

model’s nitrate predictions, the limitation of this study to July – September will tend to limit the

apparent impacts from the NOx (and to some extent) PM10 emission changes.

On a ton-per-ton basis, reductions in stationary source PM10 emissions appear to yield greater

regional haze benefits than reductions in NOx emissions. For instance, when stationary source

PM10 emissions are reduced by 98,000 tpy (a 50 percent reduction from GCVTR facilities

> 100 tpy), the average summer-time visibility improvement across all Class I areas in the

GCVTR (in Mm-1) is about 0.4 percent. When stationary source NOx emissions are reduced by

 

12 In 1996, stationary sources in the GCVTR emitted about 75 percent and 83 percent of the NOx and PM10

emissions, respectively, in the13-state WRAP region.
V-3

412,000 tpy (a 50 percent reduction from GCVTR facilities > 100 tpy), the visibility

improvement is only somewhat greater, at 0.5 percent.13 Hence, on a purely technical basis

(without considering existing controls, costs, or other implementation issues), reductions in PM

emissions might be more effective at improving regional haze than reductions in NOx emissions.

Nevertheless, the 50 percent NOx reduction scenario tends to produce slightly greater regional

haze benefits than the 50 percent PM10 reduction scenario. This is because stationary sources

comprise 33 percent of the total NOx inventory but only 7 percent of the total PM10 inventory.

So even though much of the NOx is never converted to the particulate phase, the sheer volume of

NOx emission reductions relative to PM10 reductions and the fact that nitrate (mostly in the fine

mode) scatters light more efficiently than primary PM (mostly in the coarse mode) make the

NOx reduction scenario more meaningful in terms of regional haze benefits than the PM10

reduction scenario. The fact that stationary source NOx emissions are not as well controlled as

stationary source PM10 emissions in the West actually lends some relevance to the outcome that

NOx emissions are altered more in the sensitivity analysis than PM10 emissions.

For the three-month summer period examined in this analysis, NOx changes have very little

effect on aerosol concentrations beyond changes in nitrate. Other species that could be indirectly

affected – e.g., ozone concentrations and subsequent oxidation of SO2 and organic gases into the

particulate phase – do not appear influenced by the levels of NOx reductions (16 percent of the

total inventory) assumed in this analysis. This finding may change after implementing all the

model improvements noted above, but since nitrate currently appears as the largest responder to

NOx changes, and given the information above regarding the NOx and PM scenarios, the maps,

tables, and discussion below place somewhat more emphasis on nitrate and the results of the

50 percent NOx reduction scenario than on other species and scenarios.

Figures V-1 and V-2 show the model-predicted 2018 base case (Annex included) surface-layer

concentrations of ammonium nitrate (NH4NO3) and PM10, respectively, averaged over the three

month period of July-September. The values in these maps should not be construed as the

expected ammonium nitrate and PM10 concentrations in 2018, which are determined by scaling

the ambient monitoring data by the relative changes predicted by the model. Rather, these maps

are intended to provide a sense of the spatial variability and span of concentrations, which are

useful for interpreting the following maps of relative (percent) changes – e.g., a high percentage

change in a low-concentration area may be less meaningful than a moderate percentage change

in a high concentration area.

Figures V-3 and V-4 show the absolute and percentage change, respectively, in NH4NO3

concentrations from a 50 percent reduction in stationary source NOx emissions from facilities in

the GCVTR greater than 100 tpy. The largest absolute changes occur in southern CA, where

concentrations in Class I areas are predicted to decrease by 0.15 to 0.25 ug/m3

. A second area of

reductions is predicted in the central-east Rocky Mountains, especially in north-central CO.

Although the reductions are not as large as in southern CA (0.04 to 0.11 ug/m3

), they are larger

than average across the domain and exhibit the largest percentage reduction (10 to 20 percent).

 

13 In some Class I areas, the visibility improvement can be two to five percent on some days.
V-4

It is interesting to compare these results with those simulating the effects of the SO2 backstop

emissions trading program, or Annex. In the case of the Annex, an SO2 emission reduction of

15 percent (132,000 tons) in the GCVTR produced a sulfate reduction of 4 percent averaged

across all Class I areas in the GCVTR on the 20% worst modeled days. In the case of the NOx

sensitivity run, a NOx emission reduction of 15 percent (412,000 tons) in the GCVTR produced

a nitrate reduction of 5 percent averaged across all Class I areas in the GCVTR on the JulySeptember modeled days. The nitrate reduction does not produce as much visibility benefit at

most Class I areas because its concentrations are much smaller, but the response of nitrate to

NOx reductions is similar in proportion to the response of sulfate to SO2 reductions.

Figures V-5 and V-6 show the absolute and percentage change, respectively, in NH4NO3

concentrations from a 25 percent increase in stationary source NOx and PM10 emissions from all

stationary sources in the GCVTR. The spatial pattern of changes is very similar to that in the

50 percent NOx reduction scenario, although the magnitude of changes are about half. Again, it

is interesting to see some proportionality in the modeling results – i.e., an emission change that is

half as large produces aerosol changes that are about half as large. The percent increase in

NH4NO3 concentrations and visibility impairment (in Mm-1) in this scenario is 2 percent and

0.5 percent, respectively, when averaged over all Class I areas in the GCVTR for JulySeptember.

Figures V-7 and V-8 show the absolute and percentage change, respectively, in PM10

concentrations from a 50 percent reduction in stationary source PM10 emissions from facilities in

the GCVTR greater than 100 tpy. Maximum reductions in PM10 are about 0.1 to 0.5 ug/m3

, or

about 4 to 8 percent. Compared to the NOx reduction scenario, reductions in ambient PM10 are

more dispersed, with a greater number of local maximums. This may reflect the fact that there

are a fewer number of large PM10 sources than large NOx sources and that much of the PM10

emissions are coarse particles, with shorter transport distances.

Figures V-9 and V-10 show the absolute and percentage change, respectively, in PM10

concentrations from a 25 percent increase in stationary source NOx and PM10 emissions from all

stationary sources in the GCVTR. The spatial pattern of changes reflects where both relatively

large NH4NO3 changes (southern CA and central-east Rockies) and PM10 changes (additional

areas) are predicted. The largest PM10 increases are about 0.1 to 0.3 ug/m3

, or 2 to 3 percent.

Less than half of this is NH4NO3.

Table V-1 shows the predicted change in light extinction and NH4NO3 at each Class I area in

the GCVTR averaged over the July-September period as a result of reducing NOx emissions by

50 percent from stationary sources with emissions greater than 100 tpy in the GCVTR.14 As

shown in the maps, the greatest impacts occur in southern CA, followed by areas in CO. The

average improvements in light extinction in these areas is about 0.3 to 1.5 Mm-1 (1 to

2.5 percent). The average improvement in NH4NO3 is about 0.05 to 0.25 ug/m3

 (3 to

20 percent).

 

14 Tabular, site-specific data for other scenarios is available upon request. Tabulay presentation of results was

limitted to this scenario since others tend to produce smaller changes in visibility.
V-5

Figure V-1. Base Case Ammonium Nitrate Concentrations (μg/m3) – for purposes of

illustrating spatial patterns, not magnitudes.

Figure V-2. Base Case PM10 Concentrations (μg/m3

) – for purposes of illustrating spatial

patterns, not magnitudes.
V-6

Figure V-3. Change in Ammonium Nitrate Concentrations Resulting from

a 50% Reduction in Stationary Source NOx Emissions > 100 tpy.

Figure V-4. Relative Change in Ammonium Nitrate Concentrations Resulting from

a 50% Reduction in Stationary Source NOx Emissions > 100 tpy.
V-7

Figure V-5. Change in Ammonium Nitrate Concentrations Resulting from

a 25% Increase in Stationary Source NOx and PM10 Emissions.

Figure V-6. Relative Change in Ammonium Nitrate Concentrations Resulting from

a 25% Increase in Stationary Source NOx and PM10 Emissions.
V-8

Figure V-7. Change in PM10 Concentrations Resulting from

a 50% Reduction in Stationary Source PM10 Emissions > 100 tpy.

Figure V-8. Relative Change in PM10 Concentrations Resulting from

a 50% Reduction in Stationary Source PM10 Emissions > 100 tpy.
V-9

Figure V-9. Change in PM10 Concentrations Resulting from

a 25% Increase in Stationary Source NOx and PM10 Emissions.

Figure V-10. Relative Change in PM10 Concentrations Resulting from

a 25% Increase in Stationary Source NOx and PM10 Emissions.
V-10

Table V-1. Light Extinction and Ammonium Nitrate Changes Resulting from

a 50% Reduction in Stationary Source NOx Emissions > 100 tpy,

Sorted by Average Light Extinction.

Light Extinction NH4NO3

State GCVTR Class I Area ∆ Mm-1 ∆ % ∆ μg/m3 ∆ %

CA Cucamonga Wilderness -1.59 -1.37 -0.25 -3.25

CA San Jacinto Wilderness -1.13 -1.18 -0.19 -2.97

CA San Gabriel Wilderness -0.83 -0.82 -0.13 -3.06

CA Agua Tibia Wilderness -0.81 -1.05 -0.12 -2.77

CA San Gorgonio Wilderness -0.80 -0.93 -0.16 -2.65

CO Rawah Wilderness -0.69 -2.41 -0.11 -16.84

CO Mount Zirkel Wilderness -0.61 -2.28 -0.09 -20.86

CO Rocky Mountain NP -0.57 -1.68 -0.09 -14.14

CA Joshua Tree NP -0.47 -0.77 -0.13 -3.69

CO Eagles Nest Wilderness -0.45 -1.41 -0.07 -11.97

CO Great Sand Dunes NM -0.43 -1.57 -0.06 -13.87

NM White Mountain Wild. -0.36 -1.11 -0.05 -10.51

CO Flat Tops Wilderness -0.34 -1.28 -0.05 -13.82

CO La Garita Wilderness -0.34 -1.27 -0.05 -12.15

CO West Elk Wilderness -0.33 -1.19 -0.05 -12.09

CO Black Canyon of Gunnison -0.31 -0.97 -0.04 -14.83

CO Weminuche Wilderness -0.29 -1.14 -0.04 -13.02

CO Maroon Bells-Snowmass -0.29 -1.00 -0.04 -10.62

CA Dome Land Wilderness -0.27 -0.46 -0.04 -4.48

CA Pinnacles NM -0.26 -0.86 -0.04 -5.93

NM Wheeler Peak Wilderness -0.24 -0.91 -0.03 -8.94

AZ Mount Baldy Wilderness -0.22 -0.64 -0.03 -6.25

NM Salt Creek Wilderness -0.22 -0.71 -0.02 -7.75

AZ Petrified Forest NP -0.21 -0.73 -0.01 -6.88

WY Bridger Wilderness -0.20 -0.77 -0.03 -7.51

CA Hoover Wilderness -0.20 -0.19 -0.04 -2.60

CA Emigrant Wilderness -0.19 -0.25 -0.03 -3.08

NM Gila Wilderness -0.18 -0.34 -0.02 -3.81

CA Minarets -0.18 -0.23 -0.03 -2.71

OR Mount Jefferson Wild. -0.17 -0.28 -0.02 -2.59

NM San Pedro Parks Wild. -0.17 -0.64 -0.02 -10.43

NM Bandelier NM -0.17 -0.58 -0.02 -7.42

AZ Superstition Wilderness -0.16 -0.40 -0.02 -2.04

OR Mount Washington Wild. -0.16 -0.30 -0.02 -2.55

OR Mount Hood Wilderness -0.14 -0.22 -0.03 -1.83

CA Kaiser Wilderness -0.14 -0.19 -0.02 -2.63

CA Kings Canyon NP -0.14 -0.22 -0.02 -2.83

CA John Muir Wilderness -0.14 -0.23 -0.02 -2.69

CA San Rafael Wilderness -0.14 -0.32 -0.01 -5.40

AZ Sierra Ancha Wilderness -0.13 -0.35 -0.01 -1.76

CA Sequoia NP -0.13 -0.24 -0.02 -4.56

CA Yosemite NP -0.13 -0.17 -0.02 -2.63

UT Arches NP -0.13 -0.51 -0.01 -14.82
V-11

Light Extinction NH4NO3

State GCVTR Class I Area ∆ Mm-1 ∆ % ∆ μg/m3 ∆ %

NM Pecos Wilderness -0.12 -0.44 -0.03 -7.29

WY Fitzpatrick Wilderness -0.12 -0.46 -0.02 -4.83

NM Bosque del Apache Wild. -0.12 -0.44 -0.01 -8.65

OR Kalmiopsis Wilderness -0.11 -0.34 -0.01 -3.05

OR Eagle Cap Wilderness -0.11 -0.31 -0.02 -4.29

OR Three Sisters Wilderness -0.11 -0.24 -0.02 -2.55

AZ Grand Canyon NP -0.11 -0.40 -0.01 -7.36

UT Capitol Reef NP -0.11 -0.45 -0.01 -8.21

WY Grand Teton NP -0.11 -0.36 -0.02 -3.47

WY Teton Wilderness -0.10 -0.36 -0.02 -3.56

OR Crater Lake NP -0.10 -0.21 -0.01 -2.09

ID Hells Canyon Wilderness -0.10 -0.13 -0.02 -3.87

OR Strawberry Mountain Wild. -0.10 -0.15 -0.01 -2.89

AZ Sycamore Canyon Wild. -0.10 -0.32 -0.01 -5.25

CA Marble Mountain Wild. -0.10 -0.23 -0.01 -2.57

AZ Chiricahua NM -0.10 -0.36 0.00 -6.65

AZ Chiricahua Wilderness -0.10 -0.36 0.00 -6.65

AZ Galiuro Wilderness -0.10 -0.30 -0.01 -4.30

UT Canyonlands NP -0.09 -0.42 -0.01 -10.61

OR Diamond Peak Wild. -0.09 -0.18 -0.01 -2.20

AZ Saguaro Wilderness -0.09 -0.28 -0.01 -6.84

UT Bryce Canyon NP -0.08 -0.32 -0.01 -6.14

AZ Pine Mountain Wild. -0.08 -0.24 -0.01 -2.82

AZ Mazatzal Wilderness -0.08 -0.23 -0.01 -2.82

NM Carlsbad Caverns NP -0.08 -0.26 -0.01 -4.03

OR Mountain Lakes Wild. -0.07 -0.18 -0.01 -2.43

UT Zion NP -0.07 -0.21 -0.01 -7.22

CO Mesa Verde NP -0.07 -0.21 -0.03 -17.68

CA Lava Beds Wilderness -0.06 -0.15 -0.01 -2.09

WY Yellowstone NP -0.06 -0.20 -0.01 -2.50

CA South Warner Wilderness -0.06 -0.19 -0.01 -3.77

ID Selway-Bitterroot Wild. -0.05 -0.12 -0.01 -2.19

WY North Absaroka Wild. -0.05 -0.19 -0.01 -2.43

WY Washakie Wilderness -0.05 -0.19 -0.01 -2.43

CA Point Reyes NS -0.05 -0.15 0.00 -2.80

ID Craters of The Moon Wild. -0.04 -0.14 -0.01 -3.89

OR Gearhart Mountain Wild. -0.04 -0.13 0.00 -2.24

CA Caribou Wilderness -0.04 -0.11 0.00 -3.38

CA Thousand Lakes Wild. -0.03 -0.09 0.00 -2.30

CA Lassen Volcanic NP -0.03 -0.07 0.00 -2.28

CA Yolla Bolly Middle Eel Wild. -0.03 -0.09 0.00 -1.13

NV Jarbridge Wilderness -0.03 -0.13 0.00 -4.49

CA Ventana Wilderness -0.02 -0.12 0.00 -5.24

CA Redwood NP -0.02 -0.06 0.00 -2.92

Average -0.21 -0.51 -0.03 -5.79
SECTION VI: 

SUMMARY OF EMISSION CONTROLS AVAILABLE 

FOR LARGE STATIONARY SOURCES OF NOx AND PM

 

Final Report 

Prepared for: 

Lee Alter 

Western Governors’ Association 

1515 Cleveland Place, Suite 200 

Denver, CO 80202-5114 

Prepared by: 

Constance Senior, Brooke Shiley, Bradley Adams 

Reaction Engineering International 

77 West 200 South, Suite 210 

Salt Lake City, UT 84101 

Rui Afonso 

Energy & Environmental Strategies 

50 Old Faith Road 

Shrewsbury, MA 01545 

June 30, 2003 
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TABLE OF CONTENTS 

1 INTRODUCTION ...............................................................................................................................................1

1.1 BACKGROUND ................................................................................................................................................1

1.2 OBJECTIVES....................................................................................................................................................1

1.3 DEFINITIONS AND METHODOLOGY.................................................................................................................2

2 NOX AND PM SOURCES IN THE WESTERN UNITED STATES ..............................................................6

2.1 CHARACTERIZATION OF NOX SOURCES ..........................................................................................................6

2.2 COMPARISON WITH OTHER DATABASES FOR NOX CONTROL TECHNOLOGIES ..............................................13

2.3 TRENDS IN NOX EMISSIONS AND CONTROLS FOR COAL-FIRED UTILITY BOILERS, 1995-2000. ....................16

2.4 CHARACTERIZATION OF SOURCES OF PARTICULATE MATTER (PM).............................................................17

2.4 CHARACTERIZATION OF SOURCES OF PARTICULATE MATTER (PM).............................................................18

2.5 COMPARISON WITH OTHER DATABASES FOR PM CONTROL TECHNOLOGIES ...............................................22

3 NOX CONTROL TECHNOLOGIES...............................................................................................................24

3.1 OVERVIEW....................................................................................................................................................24

3.2 COAL-FIRED BOILERS ..................................................................................................................................39

3.3 RECIPROCATING ENGINES ............................................................................................................................42

3.4 CEMENT KILNS.............................................................................................................................................43

3.5 NATURAL GAS AND OIL FIRED BOILERS ......................................................................................................43

3.6 TURBINES .....................................................................................................................................................44

4 PM CONTROL TECHNOLOGIES ................................................................................................................46

4.1 OVERVIEW....................................................................................................................................................46

4.2 PM CONTROL FOR COAL-FIRED BOILERS AND OTHER COMBUSTION SOURCES ...........................................47

4.3 OTHER DEVELOPMENTS ...............................................................................................................................48

4.4 COSTS...........................................................................................................................................................49

5 MULTI-POLLUTANT CONTROL TECHNOLOGIES ...............................................................................51

5.1 PROPOSED MULTI-POLLUTANT EMISSION REGULATIONS FROM UTILITY BOILERS.......................................51

5.2 MULTI-POLLUTANT CONTROL TECHNOLOGIES.............................................................................................52

6 SUMMARY AND RECOMMENDATIONS...................................................................................................56

6.1 NOX AND PM SOURCES ................................................................................................................................56

6.2 CONTROLS FOR NOX AND PM.......................................................................................................................57

6.3 WHAT’S ON THE HORIZON? WHAT TRENDS WILL INFLUENCE EMISSIONS AND CONTROL TECHNOLOGIES?...58

6.4 RECOMMENDATIONS FOR FUTURE WORK ....................................................................................................59

7 REFERENCES ..................................................................................................................................................60

APPENDIX A: BREAKDOWN OF NOX EMISSIONS BY STATE 

APPENDIX B: BREAKDOWN OF PM EMISSIONS BY STATE 

APPENDIX C: NOX CONTROL TECHNOLOGY SUMMARIES 

APPENDIX D: PM CONTROL TECHNOLOGY SUMMARIES 
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LIST OF ACRONYMS, ABBREVIATIONS AND SYMBOLS 

ACFM Actual cubic feet per minute

AFBC Atmospheric fluidized bed combustor

BART Best available retrofit technology 

DLN Dry Low NOx 

EIA Energy Information Administration

EPA United States Environmental Protection Agency 

GCVTC Grand Canyon Visibility Transport Commission 

GCVTR Grand Canyon Visibility Transport Region 

FGR Flue Gas Recirculation

Hg Mercury 

ICE Internal Combustion Engine 

LEC Low Emission Combustion 

LNB Low-NOx burner 

MBtu Millions of British Thermal Units

MTF Market Trading Forum 

NG Natural Gas 

NOx Nitrogen oxides 

NSCR Non-selective catalytic reduction 

NSPS New Source Performance Standard

O&M Operating and Maintenance 

OFA Overfire air 

PM Particulate matter 

PM10 Particulate matter less than 10 microns 

PM2.5 Particulate matter less than 2.5 microns 

SCC Source Classification Code 

SCR Selective catalytic reduction 

SIP State Implementation Plan 

SNCR Selective non-catalytic reduction

SO2 Sulfur dioxide 

TPY Tons per year 

WGA Western Governors’ Association 

WRAP Western Regional Air Partnership 
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ACKNOWLEDGEMENTS 

We are grateful to Dr. Praveen Amar for providing help in locating the most recent sources of 

information on control technologies, as well as for external review of the report from the 

perspective of making it relevant to readership in the state governments/regional entities. 
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1 INTRODUCTION 

1.1 Background 

The Western Regional Air Partnership (WRAP) has undertaken a program to assess emissions 

control technologies and strategies for large stationary sources of NOx and PM emissions in the 

western states region. The WRAP is a collaborative effort of tribal governments, state 

governments, and various federal agencies to implement the recommendations of the Grand 

Canyon Visibility Transport Commission (GCVTC) and to develop the technical and policy tools 

needed by western states and tribes to comply with the U.S. Environmental Protection Agency’s 

(EPA) Regional Haze Rule. 

The WRAP established the Market Trading Forum (MTF), in large part, to develop and 

recommend emission control strategies for stationary sources of air pollution. A major focus of 

the MTF has been the establishment of regional emission milestones for sulfur dioxide (SO2) and 

a regional backstop cap-and-trade program for SO2 to be triggered if the milestones are not met 

voluntarily. 

The MTF is also responsible for generating a report required in 40 CFR 51.309(d)(4)(v) of the 

Regional Haze Rule. The report must assess emission control technologies and strategies for 

stationary source NOx and PM emissions and the degree of visibility impairment that would 

result from such strategies. It must also evaluate the need for NOx and PM milestones to avoid 

any net emissions increase and to support possible multi-pollutant and multi-source control 

programs. Finally, this year several states must submit state implementation plans (SIPs) to EPA 

and must commit to a 2008 revision containing any necessary long-term strategies and Best 

Available Retrofit Technology (BART) requirements for stationary source NOx and PM. 

This project is essentially a starting point for addressing stationary source NOx and PM emission 

sources over the next four years, at which point local and/or regional emission control 

program(s) may be implemented. Future work by the WRAP will investigate these issues further 

and will attempt more detailed cost estimates and emission reductions achievable in the WRAP 

region given the nature of its sources and existing controls. 

1.2 Objectives 

The main objectives of this project are to identify and briefly describe for large stationary 

sources in the western United States: 

• The universe of modern commercially-available or near-available stationary source 

NOx and PM controls (either technologies or best management practices); 

• Trends in such controls; 

• Their approximate capital and operating costs, control efficiencies, and cost 

effectiveness; 

• Secondary environmental impacts, such as control of other air pollutants and 

generation of solid or hazardous waste; 

• Real-world experience at facilities implementing or testing such controls; 
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• Future opportunities for improvements and demonstrations; and 

• Recommendations for future work. 

1.3 Definitions and Methodology 

The work plan for the project consisted of the following tasks: 

Task 1. Inventory of Stationary Sources in the WRAP Region. This task involved a review of 

the 1996 WRAP stationary source emissions inventory (version 3, in MS Access format), as well 

as other recent and relevant databases to determine the number/type of stationary sources with 

emissions greater than 100 tons per year (TPY) and the type and performance of air pollution 

control devices installed on those sources. Two subsets were created for NOx and PM emissions, 

respectively, based on the following criteria: 

• Sources (defined as emission units, or records, in the database) having annual emissions 

of the pollutant of interest greater than 100 TPY; and 

• Sources located in the thirteen-state region: AZ, CA, CO, ID, MT, ND, NM, NV, OR, 

SD, UT, WA, WY (See Figure 1). 

Table 1 lists the fields extracted from the WRAP database. 

Figure 1. Thirteen-state region considered in the technology assessment. 
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The source classification codes (SCCs) used to categorize sources served as general guidelines 

for choosing the categories in Task 1. The similarities (or differences) in the control 

technologies applicable to specific SCCs were also factors in grouping sources. For example, a 

category called “Coal-fired boilers” was created containing emissions data from utility and 

industrial boilers (of different boiler types) burning coal because the same NOx and PM control 

technologies can be applied to most of these sources. With this in mind, Table 2 gives the 

categories created for characterization of the WRAP emissions and a description of the WRAP 

categories (i.e., SCC codes) used to define the categories in this report. 

For electric utility point sources, additional databases were used to determine boiler capacity 

(MBtu/yr), enhance and update information on control technologies in place, and verify other 

source information. These databases were: EPA CEMs database for 1996 and 2001 [1], EPA EGRID database for 1996 and 2000 [2] and the EIA-767 database for 1996 [3]. 

The results of Task 1 are discussed in Section 2 of this report. 

Table 1. WRAP database fields used in the technology assessment. 

Field Description 

FIPST FIP State Code 

POINTID NAPAP Point ID Code 

STACKID Stack Number 

BLRID Boiler ID Code Code (utility only) 

SEGMENT Segment Number 

ORISID ORIS Plant ID (utility only) 

PLANT Plant Name 

SCC Source Classification Code 

SCC1_DESC General category (e.g., External Combustion Boiler) 

SCC3_DESC Major industrial group within general category 

SCC6_DESC Specific industry or emission source 

SCC8_DESC Particular emitting process or fuel type 

NOX_ANN Annual NOx Emissions, tons per year 

PM10_ANN Annual PM Emissions, tons per year 

CO_ANN Annual CO Emissions, tons per year 

SO2_ANN Annual SO2 Emissions, tons per year 

NOX_CPRI Primary Control Equipment Code - NOx

PM_CPRI Primary Control Equipment Code - PM 

CONTROL_DEVICE_DESC Control Device Description (either NOx or PM) 

Note: Codes taken from the 1996 National Emission Trends (NET) PC Inventory File Format 
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Table 2. List of Categories Used to Characterize Point Sources 

Category WRAP Sources (based on SCC Codes contained with the category) 

Coal-Fired Boilers All coal-fired external combustion boilers 

Reciprocating Engines All reciprocating ICE’s 

 NG Natural gas-fired ICE’s, including 2- and 4-cycle 

 Diesel Diesel-fired ICE’s, including large-bore engines 

 Process Gas Unspecified process gas-fired ICE’s 

Cement Kilns All cement kilns (wet and dry process) 

Oil/NG Boilers External combustion boilers firing oil or natural gas 

Turbines All fired turbines 

 NG Natural gas-fired turbines 

 Diesel Diesel-fired turbines 

Mineral Processing 

Cement crushing, grinding and drying, asphalt, other drying 

applications 

Petrochemical 

Flares, cat.crackers, nitric acid plants, unspecified process gas 

operations, does not include process heaters

NG Compressor Technology (reciprocating engine or turbine) not specified 

Pulp and Paper Recovery boilers, lime kilns, drying and smelting 

Wood Boilers Wood waste and/or bark boilers, technology unspecified 

Refinery Process Heaters Process heaters 

Glass Manufacture Glass melting furnaces 

Primary Metal Production 

 Electric arc furnaces, reheat furnaces, material handling and 

unspecified 

Waste Combustion Liquid waste (Dakota gasifier) and solid waste (WTE) 

Refinery Unspecified refinery emissions 

In-process Fuel Use Unspecified combustion systems at glass and cement plants 

Jet Engine Testing Jet engine testing 

Oil and Gas Production Flares and unspecified processes 

Smelting Operations Copper and aluminum smelting 

Sugar Beet Processing Sugar beet processing 

Secondary Metal Production Steel foundries 

Turbines, Steam Geothermal power production 
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Task 2. Survey and Documentation of Emission Control Technologies. In this task, we focused 

on the identification and compilation of control technologies for NOx and PM (main focus) and 

for SO2 and Hg (secondary focus). Sources identified in Task 1 that represented minor 

contributions to the emissions profile of the region, either due to their small number, uniqueness, 

or size, were considered in a more cursory fashion if their control technology options fell outside 

of the range of the more common/available technologies. This effort consisted mainly of 

literature reviews, on-line searches and personal (telephone) contacts and interviews. 

The following information was collected on each technology or process: 

• Type and fundamentals of technology or process; 

• Projected performance; 

• Costs (capital and O&M or cost effectiveness in $/ton of pollutant removed) or cost 

projections; 

• Status of development and opportunities for or barriers to further development; and 

• Applicability to category (or categories) of WRAP sources identified in Task 1. 

The results of this task are presented in Sections 3 and 4. 

Task 3. Control Technology Analysis and Discussion. This task was the main focus of the 

project, in which a thorough evaluation and discussion of the many identified technologies was 

conducted. A summary containing the following information was created for each technology: 

• Process name 

• For each source category to which the technology was applicable, the following 

information was tabulated: 

o Total annual NOx or PM emissions from sources greater than 100 TPY 

o Percentage NOx and PM reduction 

o Cost ($/ton or $/ACFM) 

o Development status 

• Detailed descriptions were prepared for the following: 

o Process description 

o Achievable NOx or PM reduction 

o Cost information 

o Development status 

o Practical considerations 

o Compatibility with other air pollution control technologies 

o Secondary environmental impacts 

• References 

The results of this task are presented in Appendices C and D. 

Task 4. Final Report. The draft version of the final report was submitted to WRAP on 25 April 

2003. The final report was submitted on 30 June 2003. 
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2 NOx AND PM SOURCES IN THE WESTERN UNITED STATES 

2.1 Characterization of NOx Sources 

Table 3 gives the annual NOx emissions in the GCVTR as well as in thirteen-state region for 

sources (defined as emission units, or records, in the WRAP database) exceeding 100 TPY. The 

cut-off of 100 TPY captures 84% of the stationary source NOx emissions in the WRAP database 

for the thirteen-state region. Figure 2 shows the distribution of annual NOx emissions (greater 

than 100 TPY) as a function of state. 

The largest source category by far in the thirteen-state region is coal-fired boilers (69%); the top 

five categories (coal-fired boilers, internal combustion engines, cement kilns, turbines and oil 

and natural gas boilers) account for almost 90% of the NOx emissions. Therefore, this report 

concentrates on control technologies applicable to these major process categories. 

The states with the largest NOx emissions are AZ, CA, ND, NM, UT, and WY. Since all these 

states except ND are in the GCVTR, it is not surprising that emissions from the nine states in the 

GCVTR (AZ, CA, CO, ID, NM, NV, OR, UT, WY) account for 75% of the thirteen-state 

emissions greater than 100 TPY. Appendix A contains NOx emissions by process category and 

by state. 

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

AZ CA CO ID MT ND NM NV OR SD UT WA WY

Annual NOx Emissions, TPY

Figure 2. Annual NOx emissions from sources with emissions greater than 100 TPY for the 

thirteen-state region. 
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Table 3. A comparison of annual emissions of NOx from sources with emissions greater 

than 100 TPY between the thirteen-state region and the GCVTR. 

 13-States GCVTR 

Category # Units 

Total NOx TPY 

(>100 TPY) # Units 

Total NOx TPY 

(>100 TPY) 

% NOx in 

GCVTR 

Coal-Fired Boilers 151 607,748 117 436,882 72% 

Reciprocating Engines 423 86,210 394 78,092 91% 

Cement Kilns 39 41,009 31 32,503 79% 

Oil/NG Boilers 112 32,910 80 26,116 79% 

Turbines 86 25,278 78 23,955 95% 

Mineral Processing, Other 34 16,250 25 13,342 82% 

Petrochemical 48 13,719 31 8,326 61% 

NG Compressor 16 10,959 16 10,959 100% 

Pulp and Paper 39 10,010 20 4,619 46% 

Wood Boilers 48 9,776 36 6,864 70% 

Refinery Process Heaters 38 9,311 29 7,302 78% 

Glass Manufacture 14 5,033 12 4,379 87% 

Primary Metal Production 17 3,476 16 3,360 97% 

Waste Combustion 6 3,309 2 339 10% 

Fugitive 8 3,256 8 3,256 100% 

In-process Fuel Use 9 2,605 8 2,016 77% 

Fixed Wing Aircraft 4 2,297 4 2,297 100% 

Oil and Gas Production 7 1,140 5 792 70% 

Smelting Operations 3 961 2 852 89% 

Food and Agriculture 3 730 1 111 15% 

Secondary Metal Production 4 507 0 0 0% 

Turbines, Steam 1 165 1 165 100% 

Total (> 100 TPY) 1,110 886,659 916 666,527 75% 
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With few exceptions, the distribution of NOx sources is similar in the thirteen-state region as 

compared to the GCVTR. ICE’s (reciprocating engines and turbine) are predominantly in the 

GCVTR, while pulp and paper emissions are mostly outside the GCVTR. As a result of this 

similarity, the scope of this project was expanded to include additional WRAP states at minimal 

cost. 

The achievable NOx emission rate depends on the fuel type. For coal-fired boilers, lower NOx

emission rates are obtained when firing subbituminous coal as compared to bituminous coal. 

Thus, it is useful to look at the distribution of coals in use in the thirteen-state region. Figure 3 

shows the distribution of coals burned in utility boilers as a function of boiler type and coal rank. 

Most coal burned in the West is burned close to the mine; this distribution of coal rank reflects 

the native coals in the West. 









































 0

50,000

100,000

150,000

200,000

250,000

300,000

Dry Bottom

(Wall-fired)

Dry Bottom

(Tangential)

Wet Bottom Stoker Cyclone AFBC

NOx, tons per year

 Lignite

 Subituminous

Bituminous

Figure 3. NOx emissions from coal-fired utility boilers as a function of boiler type 

and coal rank for thirteen-state region from WRAP 1996 database. 
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For ICE’s, the application of NOx control technology can depend on the type of fuel. More so 

than with utility boilers, the design and operation of the engine is often determined by the 

primary fuel. Most of the stationary ICE’s with annual emissions greater than 100 TPY burn 

natural gas, as shown in Figure 4. 

As long as a source category consists of primarily large sources, the cut-off of 100 TPY will 

include most of the NOx emission sources. The 100-TPY cut-off captures 84% of the NOx

emissions in the WRAP database as a whole. However, certain source categories contain a very 

large number of small sources. For ICE’s (reciprocating engines and turbines) the 100-TPY cutoff only captures about 56% of the emissions as shown in Figures 5 and 6, although this is by far 

the second largest source category of stationary source NOx emissions. Thus, NOx control 

programs for sources in this category will require careful consideration of population attributes 

(e.g., controlling a large number of small sources). 

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

Reciprocating Engines Turbines

NOx Emissions, tons per year

 Process Gas

 Diesel

 NG

Figure 4. NOx emissions from Internal Combustion Engines as a function of engine 

type and fuel for thirteen-state region from WRAP 1996 database. 
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40, 78.0%

100, 55.6%

30, 82.4%

50, 73.9%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 500 1000 1500 2000 2500 3000 3500 4000

TPY/sources

Cumulative NOx Emissions

Figure 5. Cumulative NOx emissions from ICE’s in the thirteen-state 

region as a function of annual emission per source. 

100TPY, 55.6%

50 TPY, 73.9%

40 TPY, 78.0%

30 TPY, 82.4%

53.00 19.20 9.54 4.19 1.84 0.52 0.10 0.00

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 1000 2000 3000 4000 5000 6000 7000 8000

Number of Sources (in order of decreasing TPY/source)

Cumulative NOx Emissions

TPY/source

Figure 6. Cumulative NOx emissions from ICE’s in the thirteen-state 

region as a function of number of sources (in order of decreasing 

annual emission per source.) 
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The 1996 WRAP database contains information on control technologies for the pollutants of 

interest. According to the 1996 data for sources greater than 100 TPY, few sources had NOx

controls, as shown in Table 4. Overall, just above 4% of the NOx sources greater than 100 TPY 

in the WRAP 1996 database had installed controls. Coal-fired boilers were the most frequently 

controlled (15% of the units), followed by petrochemical processes (about 13% of the units). 

Note that control technologies listed in the right-hand column are as reported in the WRAP 

database. In a few cases, the description of the control technology does not seem correct (e.g., 

fabric filter or electrostatic precipitator) for NOx control; this is a limitation of the data available 

and it is outside the scope of this program to determine the accuracy of the data in the WRAP 

database. 
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NOx Control Technology (numb

parentheses)

Ammonia Injection(2), Fluid Bed Dry SAir Firing(3) , Modified Furnace Or BuCatalytic Reduction(1), Process Change

Electrostatic Precipitator – High Effici

Low Excess Air Firing(3), SNCR(1)

Steam Or Water Injection(5)

Fabric Filter - High Temperature, i.e. T

Catalytic Afterburner(1), Catalytic AfteExchanger(1), Catalytic Reduction(1), STray-Type Gas Absorption Column(1) None None Ammonia Injection(1)

None None Process Enclosed(1)

None None None None None None None None None 

Avg NOx 

TPY/Unit 

4,025 

204 

1,052 

294 294 478 286 685 257 204 245 360 204 552 407 289 574 163 320 243 127 165 799 

Total NOx

TPY 

607,748 

86,210 41,009 32,910 25,278 16,250 13,719 10,959 10,010 

9,776 9,311 5,033 3,476 3,309 3,256 2,605 2,297 1,140 

961 730 507 165 

886,660 

 Units 

Controlled 

23 

3 2 4 5 1 6 0 0 1 0 0 1 0 0 0 0 0 0 0 0 0 

46 

# Units 

151 423 

39 

112 

86 34 48 16 39 48 38 14 17 

6 8 9 4 7 3 3 4 1 

1,110 

Category Coal-Fired Boilers Reciprocating Engines 

Cement Kilns Oil/NG Boilers Turbines Mineral Processing

Petrochemical NG Compressor Pulp and Paper Wood Boilers Refinery Process Heaters 

Glass Manufacture Primary Metal Production 

Waste Combustion Refinery

In-process Fuel Use 

Jet Engine Testing

Oil and Gas Production Smelting Operations 

Sugar Beet Processing

Secondary Metal 

Turbines, Steam 

Total 

Table 4. NOx Control Technologies in use in 1996 on Sources Greater than 100 TPY from 1996 WRAP da
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2.2 Comparison with Other Databases for NOx Control Technologies 

The level of control for coal-fired boilers in the WRAP database seemed low, even for 1996. 

Therefore, the 1996 WRAP database was compared with the data available for utility boilers in 

the 1996 CEMS and E-GRID databases. The EIA-767 database was also searched for NOx

control technologies. The E-GRID database should contain the information in the other two 

databases since it contains data from 24 different federal data sources, including EIA data and 

other EPA data. Only coal-fired utility boilers were included in this comparison, not all coalfired boilers. However, only 3% of the WRAP NOx emissions from coal-fired boilers in the 

thirteen-state region were from non-utility boilers. 

It is worthwhile to take a closer look at utility boilers for two reasons. First, they are by far the 

largest source of NOx emissions, accounting for 68% of the emissions from sources greater than 

100 TPY. Second, the effectiveness of NOx control technologies on boilers depends on the type 

of the boiler as well as on the fuel burned. 

For this exercise, the EPA databases (CEMs and E-GRID) were queried to obtain information on 

capacity (MBtu per year) and control technologies. Data from 1996 was used in order to 

compare with the WRAP 1996 database. EPA and WRAP records were matched using ORIS 

Plant ID numbers and plant names. For matching records, control technologies not listed in the 

WRAP database were added, capacity (MBtu) entries were added, and NOx emissions were 

replaced from the EPA databases. 

A comparison of Tables 5 and 6, which contain, respectively, the WRAP data and the WRAP 

data augmented by the other databases, shows that the combination of the WRAP data and the 

EPA and EIA data suggests that 44% of the utility boilers had NOx control (in 1996), as 

compared to only 12% when considering only the WRAP data by itself. The EPA databases 

probably undergo a more thorough QA/QC procedure than was used to create the WRAP 

database. Thus, the E-GRID and other federal databases might be expected to have more 

complete information. 
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NOx Control Technol

Modified Furnace/Burner Design (13), Low Low Excess Air Firing(1)

None Low Excess Air Firing(3)None None None None 

Average 

Emissions 

(Tons/Source) 

4,945 

14,694 

9,844 

392 296 977 299 

3,694 

NOx 

Emissions 

(TPY) 

489,580 

73,468 

19,688 18,813 

1,779 1,954 

598 

605,881 

Controlled 

Units 

14 

1 0 3 0 1 0 

19 

Number of 

Units 

99 

5 2 

48 

6 2 2 

164 

Dry Bottom Cyclone 

Wet Bottom NG Boiler Stoker Coal-fired AFBC Wood Boiler Oil Boilers Total 

Table 5. NOx Emissions and Control Technologies for Utility Boilers in the Thirteen-State Region from W

Table 6. NOx Emissions and NOx Control Technologies for Utility Boilers in the Thirteen-State Region 

Database Combined with EPA and EIA Databases. 

NOx Control Technol

Modified Furnace/Burner Design(13) , Low Low NOx Burner(21), OFA(3), Misc.(7) Low Excess Air Firing(1) Low NOx Burner(3) Low Excess Air Firing(3), SCR(2), SNCR(None Low Excess Air Firing(1), Misc.(1) None None 

Average 

Emissions 

(Tons/Source) 

5,380 

14,706 

7,803 

424 665 977 319 110 

3,963 

NOx 

Emissions 

(TPY) 

538,003 

73,528 23,409 19,917 

3,987 1,954 

957 110 

661,866 

Controlled 

Units 

45 

1 3 

22 

0 2 0 0 

73 

Number of 

Units 

100 

5 3 

47 

6 2 3 1 

167 

Dry Bottom Cyclone Wet Bottom NG Boiler Stoker Coal-fired AFBC Wood Boiler Oil Boilers Total 
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The achievable NOx emission rate depends on the boiler-fuel combination. The largest general 

class of utility boilers (in terms of number and capacity) is the dry bottom boiler. Dry bottom 

boilers can further be subdivided into wall-fired and tangential. Natural gas boilers emit less 

NOx than coal-fired boilers per unit of fuel consumed. Of coal-fired boilers, tangential-fired 

units have the lowest emission rate and cyclones have the highest. The controls in the WRAP 

database are almost entirely low-NOx burners or other combustion modifications. Figure 7 

compares the range of NOx emission rates for all boilers and fuels. 

Application of low-NOx burners and other combustion modifications can reduce NOx emissions 

significantly; this can be seen in the large range of NOx emission that is due, in part, to the use of 

NOx controls on some of the boilers in each subset. Substantial NOx reductions can also be 

achieved on coal-fired boilers just with combustion modifications. 

Since 1996, low-NOx burners have continued to improve; currently there are vendors who will 

guarantee NOx emissions as low as 0.15 lb/MBtu from low-NOx burners or low-NOx firing 

systems. Furthermore, options have been developed for other combustion modifications, and 

SCR has begun to be applied to coal-fired boilers. Thus, the potential for NOx control on coalfired boilers is significantly better today than in 1996. 

0

0.1

0.2

0.3

0.4

0.5

0.6

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

NOx, lb/MBtu

fraction of occurrences

Natural Gas

Tangential

Wall-fired

Cyclone

Figure 7. Distribution of NOx emission rates for utility boilers in the thirteen-state 

region, combination of WRAP and EPA/EIA databases for 1996. 
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2.3 Trends in NOx Emissions and Controls for Coal-Fired Utility Boilers, 1995-2000. 

The most recent data available from the EPA databases for electric utility boilers are from 2000. 

In this section, we compare the 1996 data on NOx emissions and controls discussed in the 

previous section with data from 2000. 

Table 7 presents the data for 2000 derived from the EPA E-GRID and CEMS databases; this 

should be compared with Table 6 for 1996. The capacity of electric utility boilers increased by 

37%, from 3,019,873,933 MBtu/yr in 1996 to 4,130,818,353 MBtu/yr in 2000, but the total NOx

emissions decreased by 7%. Figure 9 shows that the average annual emissions from dry bottom 

coal boilers (the largest category) decreased. Overall there was a decrease in emissions and an 

increase in the number of units that were controlled. 

The number of sources increased, particularly the number of natural gas boilers, which increased 

from 47 to 82. The percent of natural gas boilers having NOx controls decreased from 47% to 

30%. During the time from 1996 to 2000, low-NOx burners were added to natural gas units; 

there was also a small increase in SCR and SNCR on these types of boilers. 

NOx control on dry-bottom boilers increased from 47% to 71% from 1996 to 2000, resulting in a 

9% decrease in total NOx emissions from these boilers. The number of units with low-NOx

burners doubled. Overfire air (OFA) installations, though small in number, tripled. There were 

no SCR or SNCR installations on coal-fired boilers in 2000. 

Thus, there was a modest reduction in NOx emissions from electric utility boilers from 1996 to 

2000, accompanied by a substantial increase in generating capacity. NOx control increased, 

particularly on coal-fired boilers. The added NOx control technologies were primarily low-NOx

burners and OFA. 
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NOx Control Technolog

Modified Furnace/Burner Design(13), Low ELow NOx Burner(41), OFA(9), Misc.(4) Low Excess Air Firing(1), OFA(1) Low Excess Air Firing(4), Low NOx Burner(SNCR(4) Low NOx Burner(2) Low Excess Air Firing(1), Misc.(1) None None None 

Average 

Emissions 

(Tons/Source) 

5,101 

13,203 

480 

15,519 

1,059 

299 335 216 

3,207 

NOx 

Emissions 

(TPY) 

489,680 

66,013 39,381 14,159 

2,118 

598 335 216 

612,500 

Controlled 

Units 

68 

2 

25 

2 2 0 0 0 

99 

Number of 

Units 

96 

5 

82 

2 2 2 1 1 

191 

Dry Bottom Cyclone NG Boiler Wet Bottom Coal-fired AFBC Wood Boiler Stoker Oil Boilers Total 

Table 7. NOx Emissions and NOx Control Technologies for Utility Boilers in the Thirteen-State Region co

and EIA Databases for 2000. 
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2.4 Characterization of Sources of Particulate Matter (PM) 

Table 8 gives the annual PM emissions for all PM sources in the thirteen-state region with 

emissions greater than 100 TPY. The cut-off of 100 TPY captures 60% of the PM emissions in 

the 1996 WRAP database for the thirteen-state region. With few exceptions, the distribution of 

PM sources is similar in the thirteen-state region as compared to the GCVTR. (Primary metal 

production emissions are mostly outside the GCVTR.) As a result of this similarity, the scope of 

this project was expanded to include additional WRAP states at minimal cost. 

The largest source category (for those sources with emissions greater than 100 TPY) in the 

thirteen-state region is coal-fired boilers (40%); the top eight categories account for 92% of the 

PM emissions. Therefore, this report will focus on control technologies applicable to these 

process categories. 

The state with the largest PM emissions is WY, followed by AZ, ID, and NM (Figure 9). Since 

all these states are in the GCVTR, it is not surprising that emissions from the nine states of the 

GCVTR (AZ, CA, CO, ID, NM, NV, OR, UT, WY) account for 83% of the total stationary 

source emissions greater than 100 TPY, as shown in Figure 10. Appendix B contains PM 

emissions by process category and by state. 

 Table 8. Annual Emissions of PM from Sources with Greater than 100 TPY. 

. 

Category 13-States GCVTR 

 # Units 

Total PM 

TPY (>100 

TPY) # Units 

Total PM 

TPY (>100 

TPY) 

% PM in 

GCVTR 

Coal-Fired Boilers 88 46,010 67 35,137 76% 

Mineral Processing 85 24,499 75 21,824 89% 

Petrochemical 42 10,836 37 9,716 90% 

Wood Boilers 24 5,718 20 5,210 91% 

Refinery Emissions 11 5,631 7 5,011 89% 

Primary Metal Production 20 4,697 11 2,244 48% 

Pulp and Paper 15 4,476 13 4,119 92% 

Smelting Operations 8 3,555 7 3,397 96% 

Miscellaneous 1 2,456 1 2,456 100% 

Oil/NG Boilers 5 1,379 5 1,379 100% 

Sugar Beet Processing 5 1,150 3 750 65% 

Cooling Tower 4 932 4 932 100% 

Cement Kilns 4 641 3 524 82% 

Turbines 2 838 2 838 100% 

Secondary Metal Production 1 537 1 537 100% 

Jet Engine Testing 2 535 2 535 100% 

Reciprocating Engines 3 525 3 525 100% 

Refinery Process Heaters 1 176 1 176 100% 

Total 321 114,589 262 95,308 83% 
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    0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

Dry

Bottom

Cyclone NG

Boiler

Wet

Bottom

Coalfired

AFBC

Wood

Boiler

Stoker Oil

Boilers

Average Emission per Source, TPY

1996

 2000

Figure 8. Average Annual NOx Emissions (greater than 100 TPY) from Electricity 

Generating Boilers: Comparison of 1996 and 2000 data from EPA Databases. 
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Table 9 lists the control technologies in use in the 1996 WRAP database for particulate matter. 

72% of coal-fired boilers, the largest category of emissions, had some form of PM control. 

Overall, though, only 38% of sources with emissions greater than 100 TPY had controls. 

0

5,000

10,000

15,000

20,000

25,000

30,000

AZ CA CO ID MT ND NM NV OR SD UT WA WY

Annual PM Emissions, TPY

Figure 9. Annual PM Emissions from Sources with Emissions Greater than 100 

TPY for the Thirteen-State Region. 
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PM Control Techn

Centrifugal Collector (Cyclone)(2), ElectFabric Filter(12), Multiple Cyclone(4), MCyclone/Electrostatic Precipitator(2), MuScrubber(1), Wet Scrubber(8) Centrifugal Collector (Cyclone)(2), Dust Stabilizers or Wetting(5), Dust SuppressiFabric Filter(1), Water Curtain(1), Wet SCentrifugal Collector (Cyclone)(3), SulfuProcess(2), Wet Scrubber(2) Centrifugal Collector (Cyclone)(1), Wet Dust Suppression by Water Sprays(2), FaAlkalized Alumina(2), Dust Suppression Scrubber(3), Misc.(1) Centrifugal Collector (Cyclone)(1), Wet None None Electrostatic Precipitator(4) Centrifugal Collector (Cyclone)(1) None None Electrostatic Precipitator(1) None None None None 

Avg PM 

(TPY/Source) 

523 288 258 238 512 235 298 444 

2,456 

276 230 233 419 160 537 267 175 176 357 

Total PM 

(TPY) 

46,010 24,499 10,836 

5,718 5,631 4,697 4,476 3,555 2,456 1,379 1,150 

932 838 641 537 535 525 176 

114,590 

Controlled 

Units 

64 29 

7 3 3 7 3 0 0 4 1 0 0 1 0 0 0 0 

122 

Number 

of Units 

88 85 42 24 11 20 15 

8 1 5 5 4 2 4 1 2 3 1 

321 

Coal-Fired Boilers Mineral Processing Petrochemical Wood Boilers Refinery Emissions Primary Metal Production Pulp and Paper Smelting Operations Miscellaneous Oil/NG Boilers Sugar Beet Processing Cooling Tower Turbines Cement Kilns Secondary Metal Production Jet Engine Testing Reciprocating Engines Refinery Process Heaters Total 

Table 9. PM control technologies in use on sources greater than 100 TPY from 1996 WRAP database. 
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2.5 Comparison with Other Databases for PM Control Technologies 

The 1996 WRAP database was compared with the data available for utility boilers in the 1996 

CEMS and E-GRID databases. The EIA-767 database was also searched for PM control 

technologies. The E-GRID database should contain the information in the other two databases 

since it contains data from 24 different federal data sources, including EIA data and other EPA 

data. 

EPA and WRAP records for 1996 were matched using ORIS Plant ID numbers and plant names. 

For matching records, control technologies not listed in the WRAP database were added, 

capacity (MBtu) entries were added, and PM emissions were replaced from the EPA databases. 

The EIA-767 database reported PM emissions as lb PM/MBtu, from which we calculated PM 

emissions in tons per year. 

PM emissions data in the EPA databases do not agree with data in the WRAP database, 

suggesting that the data were obtained from different measurement and/or estimation methods. 

The differences, illustrated by a few sample records in Table 10, follow no general trend from 

plant to plant. 

A comparison of Tables 11 and 12, which contain, respectively, the WRAP data and the WRAP 

data augmented by the other databases, shows that the combination of the WRAP data and the 

EPA and EIA data suggests that about 94% of the utility boilers had PM control (in 1996), as 

compared to only 53% when considering only the WRAP data by itself. The EPA databases 

probably undergo a more thorough QA/QC procedure than was used to create the WRAP 

database. Thus, the E-GRID and other federal databases might be expected to have more 

complete information.

Table 10. Sample PM Records from WRAP 1996 and EPA 1996 databases. 

Boiler 

Capacity 

(MBtu/yr) 

PM Emissions 

Rate, EPA 

(PM/MBtu) 

PM Emissions 

Rate, WRAP 

(PM/MBtu) 

PM 

Emissions, 

EPA (TPY) 

PM 

Emissions, 

WRAP 

(TPY) 

Four Corners 1 (NM) 16,530,550 0.03 0.13 248 1,048 

Four Corners 2 (NM) 9,369,730 0.03 0.13 141 618 

Four Corners 3 (NM) 18,823,220 0.03 0.13 282 1,243 

Four Corners 4 (NM) 58,100,720 0.01 0.03 291 883 

Four Corners 5 (NM) 52,759,010 0.01 0.03 264 789 

Reid Gardner 1 (NV) 9,599,371 0.05 0.05 240 222 

Reid Gardner 2 (NV) 23,152,788 0.05 0.01 579 128 

Reid Gardner 3 (NV) 30,579,084 0.05 0.02 764 278 

Reid Gardner 4 (NV) 42,514,192 0.05 0.01 1,063 245 
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PM Control Technology 

Multiple Cyclone(3), Fabric Filter(8), Wet Scrubber(7), Electrostatic Precipitator(12) Electrostatic Precipitator(4) Electrostatic Precipitator(3) None Multiple Cyclone(1) None 

Average 

Emissions 

(TPY/Source) 

615 309 234 190 381 102 554 

PM 

Emissions 

(TPY) 

36,889 

1,235 

702 571 381 102 

39,880 

Controlled 

Units 

30 

4 3 0 1 0 

38 

Number of 

Units 

60 

4 3 3 1 1 

72 

Dry Bottom NG Boiler Cyclone Stoker Coal-fired AFBC Wet Bottom Total 

PM Control Technology 

Multiple Cyclone(3), Fabric Filter(15), Wet Scrubber(8), Electrostatic Precipitator(44), Multiple Cyclone/Electrostatic Precipitator(3), Multiple Cyclone/Wet Scrubber(2), Electrostatic Precipitator(4), Fabric Filter(1) Electrostatic Precipitator(4) Fabric Filter(2) None Multiple Cyclone/Electrostatic Precipitator(1), Fabric Filter(1) 

Average 

Emissions 

(TPY/Source) 

1,093 

327 309 232 190 137 942 

PM 

Emissions 

(TPY) 

84,140 

1,633 1,235 

697 571 274 

88,549 

Controlled 

Units 

75 

5 4 2 0 2 

88 

Number of 

Units 

77 

5 4 3 3 2 

94 

Dry Bottom Cyclone NG Boiler Wet Bottom Stoker Coal-fired AFBC Total 

Table 11. PM Emissions and Control Technologies for Utility Boilers in the Thirteen-State Region from WRAP 1996 Database. 

Table 12. PM Emissions and Control Technologies for Utility Boilers in the Thirteen-State Region from WRAP 1996 Database Combined with EPA and EIA Databases. 
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3 NOx CONTROL TECHNOLOGIES 

3.1 Overview 

As discussed in Section 2, the NOx emissions greater than 100 TPY in the thirteen-state region 

come predominantly from coal-fired boilers. We have concentrated on obtaining detailed 

information on NOx control technologies for the top five categories, which account for 90% of 

the emission, although in some cases, where information was readily available, we have 

collected information for other source categories (refinery process heaters, glass melters, and 

wood-fired boilers). Table 13 shows that these source categories together account for 92% of the 

NOx emissions greater than 100 TPY. 

In this section, the information is organized in two formats. First, Table 14 lists all the 

technologies considered. For the most part, these are commercial technologies, in that vendors 

are offering these technologies. Not all technologies listed in Table 14 have demonstrated longterm operation, however. Table 14 gives the following information about each technology: 

• Name of the technology 

• Source categories to which the technology can be applied 

• Was a summary prepared? (Yes/No). If yes, technology summaries are contained in 

Appendix C. 

Second, Tables 15 through 22 summarize the NOx control options for major source categories for 

ease of comparison. More detailed information, particularly on the range of cost and NOx

control, is given in Appendix C. These tables contain the following information: 

• Name of Technology 

• Process Description 

• Applicability to units in the source category 

• Range of performance (NOx removal efficiency) 

• Range of costs ($/ton of NOx removed, levelized annual cost) 

• Commercial status 

Table 13. Annual NOx emissions greater than 100 TPY from major source categories. 

Category # Units 

Total NOx

TPY 

% of NOx

Emissions 

Coal-Fired Boilers 151 607,748 68% 

Reciprocating Engines 423 86,210 10% 

Cement Kilns 39 41,009 5% 

Oil/NG Boilers 112 32,910 4% 

Turbines 86 25,278 3% 

Wood Boilers 48 9,776 1% 

Refinery Process Heaters 38 9,311 1% 

Glass Manufacture 14 5,033 1% 

Others 199 69,385 8% 

Total 1,110 886,660 
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Table 14. NOx Control Technologies. 

 Technology Applicability 

Summary in 

Appendix C 

(Y/N) 

1 Air or fuel staging Coal-fired boilers, Cement kilns Y 

2 Batch/Cullet Preheating Glass Melters Y 

3 Biosolids injection Cement kilns N 

(not common) 

4 Burner Modifications Coal-fired boilers N 

(see LNB) 

5 Catalytic combustion Gas Turbines Y 

6 DLN (fuel-lean combustion) Gas Turbines Y 

7 Electric Boost Glass Melters N 

(too expensive) 

8 Flue Gas Recirculation (FGR) Oil/Nat'l Gas Boilers Y 

9 Fuel Reburn Coal-fired boilers, Wood/biomass boilers, Glass 

Melters Y 

10 High Energy Ignition Reciprocating Engines Y 

11 High-Pressure Fuel Injection Reciprocating Engines Y 

12 Hybrid Reburn + SNCR Coal-fired boilers 

N 

(see Reburn, 

SNCR) 

13 Hybrid SNCR + SCR Coal-fired boilers 

N 

(see SNCR, 

SCR) 

14 Hydrocarbon-enhanced SNCR Coal-fired boilers N 

(see SNCR) 

15 Intelligent controls Coal-fired boilers, Oil/NG boilers, Wood/biomass 

boilers Y 

16 Iron addition (CemStar) Cement kilns Y 
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 Technology Applicability 

Summary in 

Appendix C 

(Y/N) 

17 Kiln dust insufflation Cement kilns 

N 

(see O2-

enhanced 

combustion) 

18 Kiln temperature control Cement kilns Y 

19 LNB + FGR Coal-fired boilers, Oil/NG boilers, Process 

heaters, Pyrolysis furnaces 

N 

(see LNB, FGR) 

20 Low-Emission Combustion (LEC) Reciprocating Engines Y 

21 Low NOx Burners Coal-fired boilers, Oil/NG boilers, Glass Melters, 

Pyrolysis furnaces, Process heaters, Cement kilns Y 

22 Low-NOx Calciner Cement kilns Y 

23 Mid-kiln or tower tire injection Cement kilns Y 

24 Non-Selective Catalytic Reduction 

(NSCR) Reciprocating Engines Y 

25 NOxTech Reciprocating Engines Y 

26 Overfire Air Coal-fired boilers, Wood/Biomass boilers. 

Oil/Nat'l Gas Boilers Y 

27 Oxy-Fuel Firing Glass Melters Y 

28 Oxygen-enhanced Combustion 

Modifications Coal-fired boilers, Cement kilns, Glass Melters Y 

29 Pre-stratified Charge Reciprocating Engines Y 

30 Rich Reagent Injection (RRI) Coal-fired boilers N 

(see SNCR) 

31 SCONOX Oil/Nat'l Gas Boilers, Reciprocating Engines, Gas 

Turbines Y 

32 SCR 

Coal-fired boilers, Oil/NG boilers, Glass Melters, 

Pyrolysis furnaces, Process heaters, Reciprocating 

Engines, Gas Turbines 

Y 
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 Technology Applicability 

Summary in 

Appendix C 

(Y/N) 

33 SNCR 

Coal-fired boilers, Wood/Biomass boilers Oil/NG 

boilers, Glass Melters, Pyrolysis furnaces, Cement 

kilns, Reciprocating Engines, Gas Turbines 

Y 

34 Tempering (Steam, water or air 

injection) Gas turbines, Process heaters, Pyrolysis furnaces Y 
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Cos100500(Hidepon crebu300800500<10200250

Performance 10 to 30% NOx reduction 

20 to 30% NOx reduction for Fuel-Lean Gas Reburning (no OFA), and 30 to 60% reduction for conventional reburning. 50-70% 50 to 90% NOx reduction, de-pending on how much catalyst is installed. 40 to 60% NOx reduction 0 to 30% NOx reduction. 

30-50% NOx reduction. 

20 to 40% NOx reduction. 

Applicability Most units. Most units. Furnace height (residence time) may restrict some applications Same as individual technologies. Same as individual technologies. Most units. Can use more NH3 with less 

slip. Available for all units Most boilers already have LNB. Most units. Furnace height may restrict some applications 

Description Burner air and/or fuel modifications to improve air/fuel interaction Inject portion of the fuel into the furnace downstream of burner zone. Usually requires OFA to complete combustion Co-inject reburning fuel and SNCR reagent. Overfeed reagent into the furnace, and allow ammonia carryover to further reduce NOx over a catalyst 

downstream. Inject small amount of natural gas to create radicals that enhance SNCR effectiveness at 1700 to 2000 °F. Emerging technology. Sensors and software optimize air-fuel ratio to burners. Burners designed to produce lower NOx emissions – “staged” combustion 

Form of “staged” combustion. Divert portion of the air from the windbox to OFA ports installed above the burners. 

Technology Burner Modifications Fuel Reburn Hybrid Reburn + SNCR Hybrid SNCR + SCR Hydrocarbonenhanced SNCR “Intelligent” Controls Low-NOx burners 

(LNB) Overfire air (OFA) 

Table 15. Coal-Fired Boilers. 
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Cos100800150800

Performance 30-50% beyond OFA 20 to 30% additional NOx

reduction beyond OFA. 70 to 90+% NOx reduction 

25 to 50% NOx reduction, 

depending on the furnace temperature and time for reaction. 

Applicability Best applied with new OFA system designed to achieve stoichiometric airfuel ratio < 0.8. Most units. Modeling required to determine injection locations. Most units. Space availability may constrain some options. High sulfur fuels more challenging Most. Residence time and temperature characteristics are important. 

Description Improve effectiveness of OFA operation by injecting O2 into fuelrich flames. Operate more fuel-rich 

without the problems. Emerging technology. SNCR applied to fuel-rich region of OFA system. Ammonia added upstream of catalytic reactor installed upstream of air preheater (conventional), downstream of a hot ESP (low dust), or downstream of the cold ESP (tail end). Inject ammonia-based reagent into upper furnace (1700-2000 degrees F) to destroy NOx. 

Technology Oxygen-enhanced combustion modification Rich Reagent Injection (RRI) Selective Catalytic Reduction (SCR) Selective Non-catalytic Reduction (SNCR) 

Table 15. Coal-Fired Boilers (Continued). 
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Cost115-Not but lLEC190-depeengin$650BHP<500 ~ 10< 50

Performance 80% NOx reduction. Use 

of plasma ignition is new, so there is limited operating experience. ~80% 80-90% NOx reduction 

40-98% NOx reduction, depending on engine speed. Average of 95% reduction is achievable. 90-95% NOx reduction, 60-80% particulate removal, 50-70% CO removal, 90% hydrocarbon removal. 80-95% NOx reduction. 

Applicability For lean-burn engines (to support ignition under very lean conditions) Same as LEC Not available for all engines, some fuel efficiency decrease. Requires turbo-charging or inter-cooling upgrades. Requires rich-burn engine to produce hydrocarbons used for NOx reduction. 

Applicable to all engines, but exhaust must be heated for most engines. For carbureted, rich-burn engines. 

Description Provide continuous electrical discharge at the spark plug gap for 10 to 90 o of 

crankshaft rotation. This extended energy delivery ensures combustion in the leanest of conditions. Enhance mixing of fuel and air under lean conditions Retrofit kits available to implement lean burn for new engines as well as retrofit. Install oxidation-reduction catalyst that uses hydrocarbons in exhaust to destroy NOx. 

Inject chemical reagent into exhaust at temperatures of 1400 to 1500 °F. Inject air into intake manifold so that the piston initially draws in air, followed by a fuel-rich air-fuel mixture. 

Technology High Energy Ignition High-Pressure Fuel Injection Low-Emission Combustion (LEC) Non-Selective Catalytic Reduction (NSCR) NOxTech Pre-stratified Charge 

Table 16. Reciprocating Engines. 
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CostNot < 10

Performance 95% reduction of NOx, CO, and hydrocarbons. 75-90% NOx reduction 

Applicability Theoretically works for all engines. Catalyst regeneration is difficult. Little operating data available. All engine types (especially diesel), but difficult to control if load range is wide. 

Description Add chemical reactor for NOx

sorption, followed by regeneration. Inject ammonia upstream of a catalyst that operates at 300-900 °F. 

Technology SCONOX SCR 

Table 16. Reciprocating Engines (Continued). 
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Cost1000100-50-100 100-3200-5500-

Performance 0 to 50% NOx reduction, 

depending on existing equipment. 20 to 30% NOx reduction, 

but can reduce kiln capacity due to high moisture content. 20 to 30% NOx reduction, 

depending on cement specifications 0 to 20% NOx reduction in 

conjunction with a 0-5% kiln capacity increase. 0 to 20% NOx reduction, and requires less operator attention. 0 to 20% NOx reduction; production may increase. 

Applicability More easily implemented in tower kilns. Tried in long kilns and preheater/precalciner kilns, but effectiveness is limited by poor combustion and increased hydrocarbon or SO2 emissions. 

Applicable to all kiln types, but may affect cement quality. Applicable to long kilns. Applicable to all kiln types, but risks unacceptable cement quality. Applicable to all kiln types. Can reduce cement quality on some kilns. 

Description Inject portion of the fuel downstream of the main flame to create locally reducing conditions where NOx can be destroyed. 

Sometimes includes installing a “NOx fan” to increase burnout. 

Add sewerage sludge to mid-kiln or tower for combined SNCR and fuel-staging affect. Change cement formulation by adding waste iron to lower clinkering temperature and suppress NOx. 

Re-inject cement kiln dust (CKD) into flame zone to lower peak temperatures and increase clinker production. Add temperature-monitoring device to kiln controls to minimize high-temperature excursions where more NOx is 

emitted. Replace open pipe burner with multi-annular design. Usually accompanied by installation of an indirect coal feed system to reduce coal transport airflow. 

Technology Air or fuel staging Biosolids injection Iron addition (CemStar) Kiln dust insufflation Kiln temperature control Low-NOx Burner 

(LNB) 

Table 17. Cement Kilns. 
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Cost, $/1000-500-1000 200-100200-100

Performance 30-50% NOx. Little 

experience 15 to 30% NOx reduction; 

generate revenues. 0 to 20% NOx reduction 

and potential for additional capacity. 30 to 70% NOx reductions, 

depending on access to temperatures in 1600-1800 °F range. 

Applicability Applicable only to preheater/precalciner kilns. Injected mid-kiln in long kilns, and into lower tower for preheater/precalciner kilns. Cement quality could be more difficult to control. Applicable to preheater/precalciner kilns. 

Description Replace calciner with new lowNOx design. 

Inject whole tires or shredded tires downstream of the flame to reduce NOx formed in the burner. 

O2 lance to decrease fuel 

requirement for clinker formation. Inject ammonia-based reagent into upper furnace (1700-2000oF) 

to destroy NOx. 

Technology Low-NOx calciners 

Mid-kiln or tower tire injection Oxygen enrichment SNCR 

Table 17. Cement Kilns (Continued). 
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Cost, $/T 500-3000 200-1000 1000-200Not avail2000-1001300-300

Performance 40-80% NOx reduction 

30-60% NOx reduction 40-80% NOx reduction 70-99% NOx reduction claimed. 70-90+% NOx reduction 

30-60% NOx reduction 

Applicability Most units, but could affect heat balance. Induced FGR requires pressure part changes. Most boilers. Most units. Furnace height may restrict some applications Steam-hydrogen regeneration gas not practical for some boilers. Limited testing to date. Most units. Space availability may constrain some options. High sulfur fuels more challenging Most. Residence time and temperature characteristics are important. 

Description Recycle 15-25% of the flue gas to the windbox to reduce flame temperature. Can use eductors for induced FGR Burners designed to produce lower NOx emissions – 

“staged” combustion Form of “staged” combustion. Divert portion of the air from the windbox to OFA ports installed above Add chemical reactor for NOx sorption, followed by 

regeneration. Ammonia added upstream of catalytic reactor. Inject ammonia-based reagent into upper furnace (1700-2000oF) to destroy 

NOx. 

Technology Flue Gas Recirculation (FGR) Low-NOx Burners 

Overfire Air (OFA) SCONOX SCR SNCR 

Table 18. Oil/Natural Gas-Fired Boilers. 
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Table 19. Turbines. 

Cost,$/T > 500 1000-2000 > 7000 500-10000+ 2000-7000 

Performance 0.05 lb/MBtu (80% reduction) has been measured. 0.1 lb/MBtu (70% reduction) can be guaranteed on new units. 0.02 lb/MBtu (> 90% reduction) claimed. 90 % reduction down to 0.03 lb/MBtu. 0.15 lb./MBtu (50% reduction) can be achieved. 

Applicability Limited experience. Most turbines. Flame instability a problem for some gas fuels. Reliability of system not yet proven. Applied to most turbines Can be applied to most turbines, but some will experience slight efficiency loss. 

Description Catalytic combustor reduces combustion temperature below thermal NOx limit. 

Low NOx combustor is GT 

“equivalent” of LNB. Add chemical reactor for NOx

sorption, followed by regeneration. Add catalyst section to HRSG to destroy NOx at temperatures 

of 600 to 900 °F. Spray water or steam into combustor to suppress flame temperature. 

Technology Catalytic combustion DLN (fuel-lean combustion) SCONOX SCR Tempering (Water/ Steam Injection) 
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Table 20. Wood or Biomass-Fired Boilers. 

Cost, $/T 300-3000 200-500 200-2000 900-2200 

Performance 40-60% NOx reduction 

0-20 % NOx reduction 

20-60% NOx reduction 

40-80 % NOx reduction 

reported 

Applicability Stoker, water tube Watertube boilers Stoker, watertube Stoker, FBC, watertube 

Description Inject portion of the fuel into the furnace downstream of burner zone. Usually requires OFA to complete combustion Sensors and software optimize air-fuel ratio to burners. Form of “staged” combustion. Divert portion of the air from the windbox to OFA ports installed above the burners. Inject ammonia-based reagent into upper furnace (1700-2000o

F) to destroy NOx. 

Technology Fuel Reburn "Intelligent" Controls Overfire air (OFA) Selective NonCatalytic Reduction (SNCR) 
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Table 21. Process Heaters. 

Cost, $/Ton Gas: 1,720-2,480 Oil: 2,390-2,910 Gas: 1,210-1,820 Oil: 1,200-2,340 Gas: 810-1,280 Oil: 400-1,440 Gas: 5,130-10,600 Oil: 3,710-6,490 Gas: 1,470-2,640 Oil: 1,230-2,350 

Performance 50-60% 30-50% Ultra-LNB: 50-80% 75-90% 50-70% 

Applicability Oil/gas fired, MD only Oil/gas fired Oil/gas fired Oil/gas fired 

Description Staged firing with flue gas mixed with precombustion air Staged firing; Combines staged firing with induced flue gas recirculation Ammonia added upstream of catalytic reactor. Inject ammonia-based reagent into upper furnace (1700-2000o F) 

to destroy NOx. 

Technology LNB + FGR Low-NOx Burners, 

Ultra Low-NOx Burners 

SCR SNCR 
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Table 22. Glass Melting Furnaces. 

Cost, $/Ton 890-1,040 2,600-9,900 790-1,680 moderate 2,150-4,400 

Performance 5-25% 10-30% 40% 50-65% 80-85% 

Applicability Any glass melting furnace w/ >50% cullet in batch Oil/gas fired furnaces 

Description Residual heat of waste gas used to preheat batch materials/cullet (recycled glass) Burners designed to produce lower NOx emissions – “staged” 

b ti

Inject portion of the fuel into the furnace downstream of burner zone. Oxygen used instead of air; requires different furnace design 

Technology Batch/Cullet Preheating Electric Boost Low-NOx Burners 

Natural Gas Reburn Oxy-Fuel Firing 
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The formation of NOx is a byproduct of the combustion of fossil fuels. Nitrogen contained in 

fuels such as coal and oil, as well as the harmless nitrogen in the air, will react with oxygen 

during combustion to form nitrogen oxides (NOx). The degree to which this formation evolves is 

dependent on many factors, including both the combustion process itself and the properties of the 

particular fuel being burned. This explains why similar boilers firing different fuels or similar 

fuels burned in different boilers will yield different NOx emissions. 

As a result of these complex interactions in the formation of NOx, an equally large number of 

approaches to minimize or reduce its emissions into the atmosphere have been and continue to be 

developed. A relatively simple way of understanding the many technologies available for NOx

emission control is to divide them into two major categories: (1) those that minimize the 

formation of NOx during the combustion process (e.g., smaller quantities of NOx are formed); 

and (2) those that reduce NOx after the combustion process. It is common to refer to the first 

approach as “combustion modifications” whereas technologies in the second category are termed 

"post-combustion controls." 

Within each of these categories, several technologies and variations of the same technology 

exist. Finally, combinations of some of these technologies are not only possible but often 

desirable as they may produce more effective NOx control than the application of a stand-alone 

technology. 

The following summaries describe the major technologies in each category. 

3.2 Coal-Fired Boilers 

Combustion modifications can vary from simple "tuning" or optimization efforts (similar to a 

"tune-up" of a car) to the deployment of dedicated technologies such as low-NOx burners (LNB), 

Overfire air (OFA), or Reburn. All combustion modification approaches face a common 

challenge: that of striking a balance between NOx reduction and fuel efficiency. The concern is 

exemplified by the typically higher carbon levels in the fly ash, which reflect lower efficiency 

(more fuel needed for the same electrical output) and which may contaminate the fly ash itself, 

possibly making it unsuitable for reutilization (e.g., cement and concrete production). 

Combustion Optimization

Combustion optimization efforts can lead to reductions in NOx emissions of 5%-15% or even 

higher in cases where a unit may be poorly "tuned." It is important to remember that 

optimization results are truly a function of the "pre-optimization" condition of the power plant or 

unit, and as such have limited opportunity for drastic emission reductions. Recent development 

of "intelligent controls" - software-based systems that "learn" to operate a unit and then maintain 

its performance during normal operation may go a long way towards keeping plants well-tuned 

as they age. 

LNB’s and OFA

LNB’s and OFA represent practical approaches to minimizing the formation of NOx during 

combustion. Simply, this is accomplished by controlling the quantities and the way in which 
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fuel and air are introduced and mixed in the boiler (usually referred to as "fuel or air staging"). 

These technologies are the most prevalent in the power industry at present. For example, plants 

that have had to comply with Phase I of Title IV of the CAAA of 1990 have largely used these 

technologies for compliance. (Phase II of the Title IV has required the use of post-combustion 

technologies to meet more stringent requirements for both Group 1 and Group 2 boilers.) 

Competing manufacturers have proprietary designs, geared towards application in different 

boiler types, as well as reflecting their own design philosophies. LNB’s and OFA, which can be 

used separately or as a system, are capable of NOx reductions of 40% - 60% from uncontrolled 

levels. Again, the type of boiler (e.g., dry vs. wet-bottom, wall- vs. tangential-fired, NSPS vs. 

pre-NSPS) and the type of fuel (e.g., bituminous vs. sub-bituminous) will influence the actual 

performance achieved. NOx emission rates on the order of 0.15 lb/MBtu can be achieved with 

low NOx burners under circumstances, particularly in dry-bottom boilers burning low-rank coals. 

LNB’s/OFA have little or no impact on operating costs, other than those noted above. As such, 

the economics of these technologies are driven by capital/retrofit costs which typically range 

from $10-$40/kW, with the lower range reflecting easier "plug-in" application, whereas the 

higher costs are typically associated with more difficult and involved retrofits (e.g., where new 

controls or other systems may be replaced as part of the LNB retrofit). 

From the standpoint of scheduling retrofits for existing units, LNB/OFA retrofit projects have 

"lead" times of 10-14 weeks and can require outages of 6-10 weeks, depending on factors such as 

scope of work, integration with other plant outage requirements, etc. 

Reburn

Reburn, while generically included in the "Combustion Modification" category, is different from 

the other technologies in this group (LNBs/OFA) in that it "destroys" NOx through chemically 

reducing conditions shortly after it is formed rather than minimizing its formation as discussed 

previously. From a practical standpoint, this is accomplished by introducing the reburn fuel 

(theoretically any fossil fuel can be used, but natural gas is the most common) into the boiler 

above the main burner region. Subsequently, this "fuel-rich" environment reacts with and 

"destroys" the NOx formed in the main burners. This technology has been implemented in the 

U.S. and overseas, and while not as common as LNB/OFA, it is commercial at this time. Owing 

to stricter compatibility criteria, reburn is not as universal as LNB/OFA in its applicability to the 

overall boiler population. Specific criteria such as boiler size, availability of natural gas, type 

and quality of the main fuel are all important in determining the suitability of a unit for this 

technology. One important feature of reburn is its compatibility with cyclone boilers, for which 

the previously mentioned technologies are not particularly well suited. Cyclones boilers 

represent over 25,000 MW of capacity in the U.S. 

Reburn performance has been shown to range from 35%-60% depending on such factors as 

reburn fuel type and quantity, initial NOx level, boiler design, etc. Reburn can be thought of as a 

"dial-in" NOx technology in that NOx reductions are a function of the amount of reburn fuel. 

This feature may provide strategic value in compliance scenarios. 
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With respect to cost, systems using natural gas as the reburn fuel range from $15/kW to $30/kW 

whereas those using coal for reburn range from $30/kW to $60/kW. Operating costs are 

primarily driven by the fuel cost differential in the case of gas reburn, while for coal or oil reburn 

fuel preparation costs (pulverization and atomization, respectively) represent the dominating 

O&M costs. Countering these costs, particularly in the gas reburn case, are SO2, particulates, 

and CO2 co-benefits proportional to the fraction of gas used. 

Project retrofit schedules for this technology are on the order of 15 to 20 weeks with 6 to 10 

weeks of outage time likely. 

Recently, reburn technology has evolved into several variations of the original approach. One of 

these is “Fuel Lean Gas Reburn" (FLGR) developed for specific applications where NOx

reductions of around 30%-40% may be required. FLGR uses less gas than conventional reburn 

(3%-7% vs 15%-20%), and its capital cost is less than $10/kW, making it a potentially effective 

option in specific applications. 

SCR and SNCR

Readily available post-combustion NOx controls are limited to selective non-catalytic reduction 

(SNCR) and selective catalytic reduction (SCR). They are fundamentally similar in that both use 

an ammonia-containing reagent to react with the NOx produced in the boiler and convert it to 

nitrogen and water. SNCR accomplishes this at higher temperatures (1700oF-2000oF) in the 

upper furnace region of the boiler, while SCR operates at lower temperatures (about 600oF) and 

hence needs a catalyst to produce the desired reaction between ammonia and NOx. 

While this difference between the two technologies may seem minor, it results in significant 

difference in performance and costs. This is because in the case of SNCR, the reaction occurs in 

a somewhat uncontrolled fashion (e.g., the existing upper furnace becomes the "makeshift" 

reactor, which is not what it was originally designed to be), while in the SCR case, a dedicated 

reactor and the reaction-promoting catalyst ensure a highly controlled, efficient reaction. In 

practice, this means that SNCR has lower capital costs (no need for a reactor/catalyst); higher 

operating costs (lower efficiency means that more reagent is needed to accomplish a given 

reduction in NOx); and finally, has limited NOx reduction capability (typically 30%-40%, with 

some cases achieving reductions in the 50% range). SCR, on the other hand, has higher capital 

costs but offers lower operating costs and the opportunity for very high NOx reductions (up to 

90%). 

Capital costs range from $10 to $15/kW and $60 to $100/kW for SNCR and SCR, respectively. 

Operating costs are driven primarily by the consumption of the chemical reagent – usually urea 

for SNCR and ammonia for SCR, which in turn is dependent upon the efficiency of the process 

(usually referred to in terms of reagent utilization) as well as the initial NOx level and the desired 

percent reduction. Two additional parameters important in the overall operating costs are (1) the 

potential contamination of fly ash by ammonia, making it unusable and (2) the life cycle of the 

catalyst due to fly ash. 
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Combined Approaches

In theory, most of these technologies can be used together. However, NOx reductions are not 

necessarily additive, and more importantly, the “economics” of the combined technologies may 

or may not be cost-effective. Such analyses are highly site- and strategy-specific. 

However, several such combinations of technology are considered attractive and have or are 

gaining acceptance. For example, the combination of LNB/OFA with either SCR or SNCR is 

more prevalent than the application of the post-combustion technologies alone. The economics 

of this approach are justified by the reduced chemical (SNCR) and capital costs (SCR – smaller 

reactor/catalyst) due to lower NOx levels entering the SCR/SNCR system. Another example is 

the combination of Reburn with SNCR, driven by the synergisms between the two (similar 

location, temperatures in the boiler). This application may yield NOx reductions of 60%-70% 

with capital costs in the $20-$30/kW range, but has a relatively high operating cost due to 

reagent and reburning fuel consumption. 

3.3 Reciprocating Engines 

Several control technologies are available for ICE’s, having a wide range of complexity, cost and 

performance. 

Some in-cylinder methods offer low to moderate NOx reductions at costs well below $1,000/ton. 

These include injection timing retard, and air/fuel ratio adjustment (with or without high-energy 

ignition). These methods are widely available, and NOx performance will vary from one engine 

design to another. However, fuel efficiency can suffer as a result of these methods and emissions 

of products of incomplete combustion can increase. 

Spark-ignited engines that can be retrofitted with Low-Emission Combustion (LEC) technology 

can potentially achieve significant NOx reductions (80 to 90%). LEC technology can be 

expensive to retrofit on some engines, and it may not be available from all engine manufacturers. 

For large, low-speed engines, LEC technology is estimated to provide annual NOx reductions of 

about 80% at under $1,000/ton under most conditions. LEC technology is estimated to be more 

cost effective on smaller, medium-speed engines (under $500/ton for annual control under most 

conditions). It is estimated to be somewhat more expensive for dual-fuel engines (annual control 

at a capacity factor of 65% is estimated to cost under $1,000/ton). 

SCR is the only commercially available choice for post-combustion control of diesel and leanburn spark-ignition engines. Experience in the U.S. with SCR on these engines is growing, 

especially for diesel engines. SCR has been applied to approximately 30 diesel engines and to an 

equivalent number of constant-load lean burn ICE’s. Experience with SCR on variable-load 

engines is limited. In analysis using data from case studies, it was estimated that SCR provides 

annual NOx reductions of as high as 90% at a cost below $1,000/ton in all cases, except for very 

low capacity factors (~10%), and it provides seasonal reductions at a cost of under $1,000/ton for 

engines operating at high capacity factors (typically, 65% or greater). 

Recent developments from the application of urea-SCR on mobile sources (diesel trucks) offer 

the possibility of reducing the size and capital cost of SCR systems for stationary ICE’s. This 
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new technology, developed from efforts to apply SCR to mobile diesel engines, appears to make 

it possible to achieve much more cost-effective NOx reduction on stationary ICE’s that operate 

for only a few hundreds of hours a year. NOx reduction of about 75% is estimated to be possible 

for under $2,000/ton even for seasonal controls of some stationary ICE’s that operate only a few 

hundred hours each ozone season. Seasonal control at a cost of under $1,000/ton is estimated to 

be achievable for most applications with capacity factor greater than 45%.

3.4 Cement Kilns 

As with other combustion systems, modifying the combustion process is one strategy for 

reducing NOx in cement kilns. However, the quality of the clinker produced by the kiln can be 

affected by combustion modifications so these must be undertaken carefully. 

Monitoring temperature and excess air in the combustion zone increases the efficiency of the 

cement-making process and can result in reduced NOx emissions. Combustion modifications 

include staged combustion of air or fuel. Specifically designed low-NOx burners are sometimes 

used. Even without low-NOx burners, staging can be achieved by adding some of the fuel midkiln, as in mid-kiln injection of tires. Mid-kiln injection of fuel (most often tires) was in practice 

in twenty kilns in the U.S. in 2000. 

Iron addition (CemStar process) has been used at about a dozen facilities in the U.S. This 

reduces the temperature needed in the kiln for formation of clinker and allows the combustion 

zone to operate cooler (and thus reducing NOx). 

Post-combustion (post-kiln) NOx controls include SCR and SNCR. SCR has not been used on 

cement kilns in the U.S.; pilot studies have been conducted in Europe. SNCR technology 

requires a specific temperature window and residence time; these are not attainable in all cement 

kilns. SNCR can be applied to preheater/precalciner kilns. SNCR is widely practiced in Europe 

on cement kilns, but to date there have been only a handful of demonstrations in the U.S. 

3.5 Natural Gas and Oil Fired Boilers 

The menu of NOx control options for gas and oil-fired boilers is essentially the same as for coalfired boilers. One noted exception is the use of Flue Gas Recirculation (FGR), which is not 

effective in coal applications and hence, is not mentioned there. 

While the control technologies are common to the coal-fired options, application issues require 

different considerations and analyses. Examples range from differences in the inherent NOx

formation amongst the fuels (thermal NOx vs. “fuel”-NOx), which dictate that combustion-based 

technologies are designed accordingly for each fuel, to the fact that gas produces no PM or 

SO2/SO3 and hence can afford some design changes from coal and oil applications. Equally 

important are the economics of the different fuels, which may favor different technology 

approaches. 

In summary it can be said that the available menu of technologies is the same as for coal 

applications, but that (at least for gas), deployment of these technologies tends to be less 

constraining than for coal. 
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3.6 Turbines 

There have been some important developments in gas turbine NOx control technology, but wellestablished technologies continue to play an important role in reduction of NOx. Dry Low NOx

(DLN), catalytic combustion, and some new post-combustion methods are making their way into 

the control technology market, while water or steam injection and SCR continue to be important 

technologies for reducing NOx from gas turbines. 

Many turbine manufacturers can convert or replace conventional combustors on existing turbines 

with DLN combustors. DLN combustion retrofits have been made possible by recent 

developments in gas turbine combustor technology. DLN technology offers the potential for 

substantial reduction of NOx from turbines firing natural gas or other low-nitrogen fuels, as well 

as improved engine performance when compared to wet controls (water or steam injection). For 

turbines under about 15 MW in size, NOx emissions of 25 ppm can be guaranteed for new 

turbines and emissions below 42 ppm can be guaranteed for retrofitted turbines. For large 

turbines (75 MW and higher in size), controlled NOx emission levels of as low as 9 ppm have 

been guaranteed, even for retrofits. 

DLN capital costs vary with the size of the turbine and the specifics of the particular turbine 

being retrofitted. The baseline NOx level significantly affects the estimate of cost per ton of NOx

reduced. Using expected baseline NOx emissions levels provided by the turbine manufacturers 

and retrofit costs expected to be typical of most applications, retrofit of DLN on industrial 

turbines (about 3 to 10 MW) originally equipped with conventional combustion control is 

estimated to provide NOx reductions under $2,000/ton for annual controls with high capacity 

factors and at a higher cost for seasonal controls. For larger turbines (~75 MW), cost was 

estimated to be well below $1,000/ton for nearly all conditions. 

Water injection and steam injection are two well-established technologies that can offer 

controlled NOx emission levels below 42 ppm in many cases. Because water or steam injection 

technologies frequently have lower capital cost than DLN but higher variable costs, these 

technologies can be more attractive for peaking turbines or other turbines that operate 

infrequently. It was estimated that water injection installed on peaking units that operate 200 

hours to 400 hours in the summer would reduce NOx at a cost of about $2,500/ton to about 

$7,000/ton, depending upon the number of operating hours and the fuel used (gas or distillate 

oil). 

SCR continues to be the most widely used post-combustion technology for gas turbines. 

Catalyst technology developments have made SCR viable over a wider temperature range. This 

makes SCR a viable control option in situations that were difficult in the past, such as simplecycle turbines that may now benefit from high-temperature SCR and combined-cycle turbines 

with duct burners that may now benefit from low-temperature SCR. 

The cost of NOx reduction with SCR varies considerably according to application, turbine size, 

and the type of SCR technology that is appropriate for the application. As in the case of the 

DLN cost estimates, expected baseline NOx emissions levels provided by the turbine 

manufacturers were used as a basis for cost calculations. Conventional SCR on a large 

(~75MW) combined-cycle turbine with high capacity factors was estimated to cost about 
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$440/ton for annual controls and $870/ton for seasonal controls, for turbines equipped with 

conventional combustion technology (baseline NOx emissions of 154 ppm). For turbines with 

lower baseline NOx emissions (such as those equipped with DLN combustors having baseline 

NOx emissions of 15 ppm), the cost per ton of additional NOx removed was estimated to be 

greater, ranging from about $3,700/ton (annual control, high capacity factor) to over $13,000/ton 

(seasonal controls, low capacity factor). On smaller turbines (~5 MW), the cost of conventional 

SCR is estimated to be as low as $1,300/ton (with annual control and conventional combustion 

technology having baseline NOx emissions of 142 ppm). Seasonal controls for smaller turbines 

are estimated at over $15,000/ton of NOx removed at a low capacity factor (45%) with baseline 

NOx emissions of 42 ppm. 

For installations that may be better suited for high- or low-temperature SCR variants, such as 

simple-cycle turbines (high-temperature SCR) or combined-cycle turbines with limited space 

(low-temperature SCR), the cost of SCR is somewhat higher than for conventional SCR on a 

combined-cycle plant. A 75 MW turbine at a high capacity factor equipped with conventional 

combustion technology (baseline NOx emissions of 154 ppm) can be controlled annually with 

high- or low-temperature SCR for about $550/ton and for about $1,200/ton seasonally. As with 

conventional SCR, turbines with lower baseline NOx emissions (such as those equipped with 

DLN combustors) showed a higher cost per ton of NOx reduction. The estimated cost of NOx

reduction for a 75 MW turbine with baseline NOx emissions of 15 ppm ranges from $5,170/ton 

(annual controls, high capacity factor of 85%) to as high as $20,000/ton (seasonal controls, low 

capacity factor of 45%). On smaller turbines (~5MW), the cost for high- or low-temperature 

SCR is estimated to be as low as $2,000/ton with annual control and conventional combustion 

technology (baseline NOx emissions of 142 ppm). Cost is estimated to range from $6,750/ton 

(annual controls, high capacity factor of 85%) to about $27,000/ton (seasonal controls, low 

capacity factor of 45%) with baseline NOx emissions of 42 ppm. 

Emerging combustion technologies (such as catalytic combustion) and post-combustion 

technologies (such as SCONOx) offer the potential for very low NOx emission levels. Because 

there is much less experience with these technologies, available cost information is limited. 
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4 PM CONTROL TECHNOLOGIES 

4.1 Overview 

As discussed in Section 2, 8 source categories make up about 92% of the PM emissions and are 

summarized in Table 23. Detailed information on PM control technologies has been obtained for 

industrial processes that generate particulate matter. We have not provided cost information on 

fugitive emissions, however, since costs of fugitive dust control are highly variable and it is 

difficult to find an adequate metric for costs and then quantify them. 

Table 24 lists all the technologies considered. These are commercial technologies, in that 

vendors are offering these technologies with demonstrated operating experience in a wide range 

of applications. Table 24 gives the following information about each technology: 

• Name 

• Source categories to which the technology can be applied 

• Summary prepared? (Y/N) 

Technology summaries are contained in Appendix D. 

Table 23. PM emissions from top eight source categories. 

 # Units 

Total PM 

TPY 

% PM 

Emissions 

Coal-Fired Boilers 88 46,010 40% 

Mineral Processing 85 24,499 21% 

Petrochemical 42 10,836 9% 

Wood Boilers 24 5,718 5% 

Refinery Emissions 11 5,631 5% 

Primary Metal Production 20 4,697 4% 

Pulp and Paper 15 4,476 4% 

Smelting Operations 8 3,555 3% 

Others 28 9,168 8% 

Total (>100 TPY) 321 114,589 
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Table 24. PM Control Technologies 

4.2 PM Control for Coal-Fired Boilers and Other Combustion Sources 

Particulate matter is generated by a variety of physical and chemical processes. It is emitted to 

the atmosphere through combustion, industrial processes, fugitive emissions and natural sources. 

In combustion processes, the mineral matter (inorganic impurities) is converted to ash. The 

particles suspended in the flue gas are known as fly ash. Fly ash constitutes the primary 

particulate matter, which enters the particulate control device. Particulate matter is in general 

referred to as "PM", "PM10", "PM2.5" (particulate matter (PM) with an aerodynamic equivalent 

diameter of 10 microns or less and 2.5 microns or less, respectively). 

Quantity and characteristics of the fly ash and particle size distribution depend on the mineral 

matter content of the fuel, combustion system, and operating conditions. Combustion technique 

mainly determines the particle size distribution in the fly ash and hence the final particulate 

emissions. Common combustion systems in pulverized coal firing include dry bottom, wall 

(front, opposed) and corner (tangential) burners and wet bottom furnaces. In dry bottom boilers, 

10-20% of the ash is discharged as dry, bottom ash. In wet bottom boilers, 50-60% of the ash is 

discharged at the bottom of the boiler as slag. Stokers or grate-fired boilers are used to burn 

coal, wood and waste. The majority of the ash falls through the grate and is discharged as 

bottom ash. Mineral composition of the coal and the amount of carbon in the fly ash determine 

the quantity, resistivity and cohesivity of the fly ash. 

PM emissions from other point source processes involve similar phenomena where particulate 

matter is carried with the flue gas, in suspension to the stack. Hence, the general technologies 

applicable to one source are typically suitable for the others as well. Factors such as type and 

 Technology Applicability Summary 

(Y/N) 

1 Cyclones Coal-fired boilers, Oil/NG boilers, 

Wood/Biomass boilers, Cement kilns, Smelting Y 

2 Electrostatic precipitator 

(ESP) 

Coal-fired boilers, Oil/NG boilers, 

Wood/Biomass boilers, Cement kilns Y 

3 Fabric Filter Coal-fired boilers, Oil/NG boilers, 

Wood/Biomass boilers, Cement kilns Y 

4 PM Scrubber Coal-fired boilers, Oil/NG boilers, 

Wood/Biomass boilers, Cement kilns, smelting Y 

5 

Surface modification 

• Water 

• Surfactants 

• Shape 

Fugitive Emissions, Mineral Products N 

6 Traffic operations Fugitive Emissions, Mineral Products N 
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quantity of PM, characteristics of the process gas (temperature, moisture, other contaminants) 

will have a major influence on the selection and design of the PM control technology. 

Without getting into the details of the various technologies, the following four major types of 

particulate controls technologies are common for a variety of applications: 

• Wet scrubbers – scrubbers work on the principle of rapid mixing and impingement of 

the particulate with the liquid droplets and subsequent removal with the liquid waste. 

For particulate controls the “venturi scrubber” is an effective technology whose 

performance is directly related to the pressure loss across the venturi section of the 

scrubber. Venturi scrubbers are effective devices for particulate control. However, for 

higher collecting efficiencies and a wider range of particulate sizes, higher pressures are 

required. High-energy scrubbers refer to designs operating at pressure losses of 50-70 

inches of water. Of course, higher pressure translates to higher energy consumption. 

Performance of scrubbers varies significantly across particle size range with as little as 

50% capture for small (<2 microns) sizes to 99% for larger (>5 microns) sizes. 

 

• Electrostatic Precipitators (ESP) –ESP’s operate on the principle of electrophoresis, by 

imparting a charge to the particulates and collecting them on opposed charged plates. 

Dry vs. wet refers to whether the gas is water cooled and saturated prior to entering the 

charged plate area, or is collected dry on the plates. In gases with high moisture content, 

dry ESP’s are not suitable because the wet gas would severely limit the ability to collect 

the “sticky” particulates from the plates. The wet ESP technology is capable of very 

high removal efficiencies and is well-suited for the wet gas environments. Both types 

of ESP’s are capable of 99+% removals for particle sizes above 1 micron. 

• Fabric Filters – These are essentially “giant” vacuum cleaners. As in the case of the dry 

ESP, Fabric Filters are not well suited for wet gas applications. However FFs are 

extremely efficient in collecting PM including fine (submicron) size fractions. 

• Cyclones – Cyclones are devices that separate particulates from the gas stream through 

aerodynamic/centrifugal forces. However, the technology is only effective in removing 

larger size particulates (greater than about five microns). 

4.3 Other Developments 

While the technologies above represent the major available options for particulate control from 

point sources, it is relevant to note that advancements and innovative application of these 

technologies have and will continue to occur. Examples of these can vary from simple retrofits 

(e.g. new filter bag materials for Fabric Filters or newer spark control electronics on ESPs) to 

innovations including electrostatically- enhanced fabric filtration and hybrid concepts that 

combine attributes of various technologies. 

The Electric Power Research Institute’s (EPRI) COHPAC process and the University of North 

Dakota Energy and Environmental Research Center’s Advanced Hybrid Particulate Collector 
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(AHPC) are examples of hybrid particulate collectors. In COHPAC, an ESP is followed by a 

pulse-jet Fabric Filter either immediately following it or actually integrated into the original 

casing of the ESP (in the case of larger older ESP’s), where the FF acts as a “polishing” device 

significantly increasing the overall and fine particulate collection efficiency of the ESP alone. 

The AHPC technology can be described as an ESP with alternating rows of electrode plates and 

highly efficient membrane filter bags. In this case, the technology benefits from good synergism 

between the ESP and FF during bag cleaning resulting in very high performance levels, small 

sizes and operational flexibility. 

4.4 Costs 

As with most control technologies, the costs of PM controls involve both capital and operating 

costs. A cost-effectiveness indicator such as $/ton as is typically used for other technologies 

(e.g. NOx and SO2) is very difficult to address for generic PM control costs, as the range of PM 

reductions for different fuels and processes is wide that cost ranges become useless. An attempt 

to summarize costs in terms of capital and O&M components is presented below. 

Capital

While it is customary to indicate capital costs on a $/kW basis for power generation applications, 

this is not relevant for non-power applications since no electricity is generated. However, one of 

the main parameters dictating the “sizing” and hence, the costs of a PM control device, is the 

quantity of flue gas it must handle. As a result, it is more appropriate to generalize capital costs 

on a “$/ACFM” basis. The following values represent typical costs for several of these 

technologies (these numbers reflect unit sizes ranging from utility-size units up to about 

2,000,000 ACFM to smaller process down to about 10,000 ACFM)) 

• Dry ESPs - $15 - $40/ACFM 

• Wet ESPs - $15 - $40/ACFM 

• Reverse Air Fabric Filter - $17 - $40/ACFM 

• Pulse Jet Fabric Filter - $12 - $40/ACFM 

• Venturi Scrubber - $5 - $20/ACFM 

• Cyclone - $1 - $5/ACFM 

O&M

O&M costs are difficult to generalize for such a variety of technologies and applications, as they 

are affected by many parameters that include type of fuel, type of process, local ash disposal 

options, local cost of power, etc. O&M costs include fixed costs (FOM) and variable costs 

(VOM). The costs provided below are presented in $/year-ACFM and reflect costs for coal based 

fuels but should reasonably apply to other sources as well. 

Fixed O&M 

• Dry ESPs - $0.25 - $0.65/yr-ACFM 

• Wet ESPs - $0.15- $0.50/yr-ACFM 

• Reverse Air Fabric Filter - $0.35 - $0.75/yr-ACFM 
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• Pulse Jet Fabric Filter - $0.50 - $0.90/yr-ACFM 

• Venturi Scrubber - $0.25 - $0.65/yr-ACFM 

• Cyclone – Not applicable 

Variable O&M 

• Dry ESPs - $0.45 - $0.60/yr-ACFM 

• Wet ESPs - $0.25 - $0.50/yr-ACFM 

• Reverse Air Fabric Filter - $0.70 - $0.80/yr-ACFM 

• Pulse Jet Fabric Filter - $.90 - $1.1/yr-ACFM 

• Venturi Scrubber - $1.2 - $1.8/yr-ACFM 

• Cyclone – Not applicable 

 
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5 MULTI-POLLUTANT CONTROL TECHNOLOGIES 

Emerging environmental issues and proposed federal legislation (President’s Clear Skies 

Initiative, Carper Bill, Jeffords’ Bill) as well as state legislation (examples include MA, NY, NC, 

NH, CT) have driven interest in multi-pollutant (as opposed to single pollutant) control 

technologies capable of addressing air pollutant emissions more comprehensively with greater 

flexibility and ultimately lower cost. Multi-pollutant control technologies integrate in-situ and/or 

post-combustion controls of at least two of the following pollutants: SO2, NOx, and Hg (and 

other hazardous air pollutants including cadmium, arsenic, and nickel), and CO2. Multi-pollutant 

controls are intended primarily for large utility coal-fired boilers since the complexity of some of 

these processes as well as regulatory drivers often limit them to larger, utility boilers. Since 

coal-fired boilers represent the single largest source category for both NOx (as well as SO2 and 

Hg) and PM in the thirteen-state region, it is worth considering some of these technologies. 

5.1 Proposed Multi-pollutant Emission Regulations from Utility Boilers 

In 2002 and 2003 three “multi-pollutant” bills were introduced in the US Congress that call for 

coordinated reductions in NOx, SO2, and Hg from coal-fired power plants [26]. Some of the bills 

also include emission limits for CO2. The three bills are briefly summarized here. 

• The Clean Power Act (CPA, Jeffords) would amend the CAA to require electric power 

generation sources greater than 15 MW. It is the most stringent of the three proposals. It will 

cap SO2 emissions at 2.26 mm TPY in 2008 (0.28 mm TPY in the western region that 

includes WRAP states and MT, WY and CA; and 1.98 mm TPY in the eastern region). For 

NOx, the cap of 1.51 mm TPY is to be met by 2008. The cap on Hg is at 5 TPY, also to be 

met by 2008. In addition, this bill sets a cap of 2.08 billion TPY for CO2 to be met by 2008 

(roughly 1990 levels). Except for Hg, national trading will be allowed to meet the caps. 

• The Clear Skies Act (CSA) has been proposed by the Bush administration. It is the least 

stringent of the three proposals. It would cap SO2 emissions at 4.5 mm TPY in 2010 and at 3 mm 

TPY in 2018. The corresponding limits for NOx are 3 mm TPY (in 2008) and 1.7 mm TPY in 

2018. For Hg, the proposed national caps are at 26 TPY in 2010 and 15 TPY in 2018. There are 

no limits for CO2. A national trading program similar to the existing trading program for SO2

emissions under Title IV of the Clean Air Act will be the implementation mechanism to achieve 

these caps. All electric generation sources greater than 25 MW would fall under this program. 

• The Clean Air Planning Act (CAPA, Carper,Breaux, Baucus, and Chafe)) was intended as 

middle ground between the CPA and CSA. For SO2, the caps are 4.5 mm TPY by 2008, 3.5 

mm TPY by 2012, and 2.25 mm TPY by 2015. The caps for NOx are 1.87 mm TPY by 2008 

and 1.7 mm TPY by 2012. The Hg cap limits are 24 TPY by 2008, and a potential cap of 5-

16 TPY by 2012 (this cap to be set by EPA and implies a control in the range of 79 to 93% 

from current Hg emission level). Cap and trade program will be the implementation 

mechanism for all four pollutants, except trading for Hg will be limited. In a “hybrid” 

approach, limited trading for Hg would be allowed (each plant will be required to reduce its 

Hg emissions at site by at least 50% in 2008 and by 75% in 2012). For CO2, CAPA proposes 

to stabilize CO2 emissions at 2005 levels (approximately 2.6 billion TPY) by 2008, and then 

stabilize to 2001 levels (approximately 2.4 billion TPY) by 2012. 
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All three bills recognize and incorporate the WRAP SO2 trading program by setting separate 

caps on SO2 emissions in the West. The CPA and CAPA allow nationwide trading of NOx, 

while the CSA divides the country into two zones for NOx trading. The western zone includes 

the ND, SD, NE, OK, KS, western TX, the eleven states west of the Rockies, AK, HI and the 

U.S. territories. The largest differences among the three bills are in the Hg emissions reduction 

requirements. The first-phase Hg emissions caps under CSA and CAPA are about the same, but 

compliance would come two years earlier under CAPA. CPA has the most stringent Hg 

reduction requirement: a cap of 5 TPY or about 90% control. The CSA would allow nationwide 

Hg trading, while the CAPA would allow partial trading. There is no trading under CPA. 

Both CSA and the first phase of CAPA have modest Hg emission reduction targets; these would 

make it possible in some cases to achieve reduction of Hg as a “co-benefit” of other control 

technologies, for example, from the combination of an SCR and wet scrubber. If one of these 

bills were enacted, there might be some additional incentive to install an SCR and/or FGD on 

plants for which there might not be justification on the basis of a single pollutant. 

In terms of Hg co-benefits, the West is at a disadvantage as compared to the East. In the latter 

region, more utilities burn bituminous coals that are high in chlorine (which tends to increase the 

amount of oxidized Hg in flue gas) and in sulfur. Wet scrubbers are effective for the removal of 

oxidized Hg, but ineffective for removal of the elemental Hg that is the predominant form of Hg 

in many western power plants. If all coal-fired power plants must reduce Hg emissions by 

upwards of 70%, the West will have a more difficult job than the East, owing to differences in 

coal composition. The bills that allow Hg trading (CSA and CAPA) would allow western power 

plants to deploy Hg control technology at plants were the highest emissions reductions are likely 

to be achieved. 

If the CPA is enacted or if none of the three bills are enacted this year, it is likely that EPA will 

continue with the MACT process for Hg control, which does not allow trading and which will 

probably impose a Hg emission reduction target in the range of 70% to 90% (or an emission 

limit in the range of 0.2 to 0.6 pound of Hg per trillion Btu input). In this case, coal-fired power 

plants will have to look at application of activated carbon injection, the most mature technology 

for Hg control currently, or one of the multi-pollutant processes under development. Activated 

carbon injection may require adding additional particulate control equipment (such as a polishing 

baghouse with high cloth to air ratio), which will lower PM as well as the emissions of other 

hazardous pollutants including arsenic, chromium, lead, manganese, and nickel) as a 

consequence. 

5.2 Multi-pollutant Control Technologies 

A multi-pollutant control technology may be one integrated process or a combination of 

synergistic processes. In addition to in-situ and post-combustion control processes, options such 

as advanced power generation technologies, power plant rehabilitation-upgrading-repowering, 

fuel switching or blending and power plant optimization are sometimes included in the multipollutant control category. Emerging and commercial processes for multi-pollutant control for 

coal-fired boilers are summarized in Table 25, which is largely taken from Reference 4, with 

more recent information from the DOE-EPRI-U.S. EPA -A&WMA Combined Power Plant Air 

Pollutant Control Symposium in Washington, D.C., May 19-22, 2003. 
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Approximately half of the options listed in Table 25 are in commercial and early commercial 

stages. However, nearly all the options in commercial stage are proven SO2 control 

technologies, which also remove Hg, advanced power generation options and power plant 

upgrading-fuel switching options. Nearly all in-situ and post-combustion controls (SO2-NOx or 

SO2-NOx-Hg) are either in demonstration or pilot-scale. Some technologies (e.g., SNOX, SNRB, 

Advacate and CZD) have been tested either in pilot or demonstration scale in the early phase of 

the U.S. Department of Energy’s Clean Coal Technology (CCT) program, but have not been 

adopted by the industry. Some of these technologies may become more cost-effective if 

additional controls are required. Most of the environmental control processes increase the 

auxiliary power requirements of the plant (some up to 5%, but mostly in the range of 1 to 2%), 

increasing proportionally the CO2 emissions. 

Emerging post-combustion, multi-pollutant control technologies are being developed by a 

number of companies. The Electro-Catalytic Oxidation (ECO) system is a four-stage pollution 

control process that integrates established technologies to remove SO2, NOx, Hg and PM2.5. 

The system also produces a valuable fertilizer byproduct. The AIRborne process removes SO2

and NOx from plant emissions while turning the leftover material into a high-quality granular 

fertilizer. EnviroScrub is a dry scrubbing system that results in control of SO2, NOx, and 

possibly mercury and results in a byproduct that can be sold into the fertilizer, chemical, and/or 

explosives industry. None of these technologies controls emissions of CO2. 

Capital costs of options controlling two pollutants (either SO2-NOx or SO2-Hg) are projected to 

be in the 50-315 $/kW range, but there is significant uncertainty associated with these estimates 

because of their early stage of development. Also, lack of information, especially associated 

with O&M costs, makes it difficult to compare their cost-effectiveness. Further monitoring and 

updating of cost-related information is needed. For reference, the costs of the combined 

commercial technologies, FGD and SCR are above 200-250 $/kW. 

Advanced power generation technologies such as circulating fluidized bed (CFB), pressurized 

fluidized bed (PFBC) and integrated gasification combined cycle (IGCC) are potentially attractive 

options because they are revenue-generating options, while reducing significantly SO2 and NOx, 

and to a lesser extent CO2. These options are available mainly for new power plants. Also, 

supercritical pulverized coal boiler provides an attractive alternative to subcritical pulverized coal 

boiler for nearly the same investment and results in an additional 4-12% reduction of all emissions. 

While this may not seem to be a significant percentage, their cost-effectiveness is attractive; also, 

the amount of CO2 reduction (in tons or tons per year) is significant. 

Of particular interest are options such as power plant optimization, fuel blending or switching 

and power plant upgrading. These options may play an important role in a flexible compliance 

regulatory framework and may result in significant savings for the utility industry compared to 

the implementation of control technology options. Optimization involves only operating 

changes, and while it results in only minor emission reductions, its costs are very low and 

therefore it is an attractive option and should be pursued in all power plants. Fuel blending or 

switching, and power plant upgrading provide significant opportunities for emission control, but 

their site-specific nature makes it difficult to generalize regarding their emission reduction 

potential and cost-effectiveness. A more site-specific assessment is recommended to assess the 

potential for these options in a typical utility system. 
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Table 25. Commercial and Emerging Multi-Pollutant Control Technologies for External Combustion B

Status: P = pilot stage; C = commercial; D = demonstration 

Issues Hg removal can coal type, operaPotential impactDemonstration oneeded Not used commimpacts on ESP Full scale demoinsufficient infoFew application potentially expeHg removal may coal type, operato Spray DryersHigh costs and arequirements Cost-effectiveneRequires demonDemonstration icomparable to FIn demonstratio

Applicability Low to medium sulfur coals Units with ESP or FF for particulate control Existing plants, especially older units less than 300 MW Units with ESP or FF for particulate control Wet Scrubber Plants Integration with wet scrubbers, retrofit dry ESPs, new units NOX-Hg control for low to medium sulfur coals(same as Spray Dryers) New and retrofit New and retrofit New and retrofit New and retrofit New and retrofit 

Emissions Reductions SO2: >95%; NOx: NA; Hg: 5- 

85% SO2: 40-85%; NOx: NA; Hg: 0-

90% SO2: 65-70%; NOx: NA; Hg: 

65-90% SO2: 40-85%; NOx: NA; Hg: 50-90% SO2: 95%; NOx: NA; Hg: 

80+% SO2: 99%; NOx: NA; Hg: 80+% SO2: 90-98%; NOx: NA; Hg: 

<90% SO2: 95+%; NOx: 50-90%; Hg: 

NA SO2: 90+%; NOx: 50-90%; Hg: 0% SO2: 80-90%; NOx: 50-90%; 

Hg: 0% SO2: 90->99%; NOx: 50-60%; 

Hg: 30-75% 

30 %

SO2: 90-95%; NOx: 80-90%; Hg: 

NA 

Status C P/C C/D P/C P C/P P/C C/D C P D D 

Technology SO2/Mercury Control

Dry Scrubbers (conventional) SO2 sorbents, low temperature 

SO2 sorbents, furnace injection Activated carbon with SO2

sorbent processes Wet FGD with mercury oxidation processes Wet FGD with wet ESP Advanced Dry FGD SO2/NOx Control

E-BEAM SNOX SNRB AIRborne Thermal NOX 
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Issues High costs, due to high Not widely ash salabilitimpact of mDemonstratDemonstratestimated to FGD-SCRDepends on 

Applicability New and retrofit Retrofit and new units with ESP an/or FF New and Retrofit New and retrofit. Plants with SCR and Wet scrubber technologies 

Emissions Reductions SO2: 90-98%; NOx: 60-80%; 

Hg: 90-99% Hg: 50-90% SO2: 95-98%; NOx: 90%; Hg: 

70+% SO2: 99+%; NOx: 99%; 

Hg: 60-70% SO2: 95%; NOx: 90-95%; Hg: 

0-80% 

Status C P/C D D C 

Technology SO2/NOx/Mercury Control

Activated Coke Activated carbon with particulate controls Electro Catalytic Oxidation EnviroScrub Wet FGD and SCR 

Table 25. Commercial and Emerging Multi-Pollutant Control Technologies for External Combustion B

Status: P = pilot stage; C = commercial; D = demonstration 

Table 25. Commercial and Emerging Multi-Pollutant Control Technologies for External Combustion Boi
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6 SUMMARY AND RECOMMENDATIONS 

6.1 NOx and PM Sources 

The main objectives of this project were to identify and briefly describe the available (or 

emerging) technologies for control of NOx and PM emissions that could be applied to sources in 

the western United States. The starting point for this work was an analysis of large (greater than 

100 TPY) sources from the WRAP 1996 Emission Inventory (Version 3). Sources were limited 

to those from the thirteen-state region: AZ, CA, CO, ID, MT, ND, NM, NV, OR, SD, UT, WA, 

and WY. 

The source profile from the thirteen-state region was compared with that from the nine-state 

GCVTR: AZ, CA, CO, ID, NM, NV, OR, UT, and WY. The GCVTR accounted for 75% of the 

NOx emissions and 83% of the PM emissions within the thirteen-state region. Generally, the 

distribution of sources was the same in the GCVTR as compared to the thirteen-state region. 

Thus, conclusions based on the thirteen-state region should therefore be valid for the GCVTR 

while achieving broader applicability to WRAP members. 

The cut-off of 100 TPY captures 84% of the NOx emissions in the 1996 WRAP database for the 

thirteen-state region. For ICE’s (reciprocating engines and turbines) the 100 TPY cut-off only 

captures about 56% of the emissions, though this category is the second largest category and 

responsible for 10% of stationary source emissions. Thus, NOx control programs for sources in 

this category will require careful consideration of population attributes (e.g., a large number of 

small sources). 

The largest source category for NOx by far in the thirteen-state region is coal-fired boilers (68%); 

the top five categories (coal-fired boilers, internal combustion engines, cement kilns, turbines 

and oil and natural gas boilers) account for 90% of the NOx emissions. The states with the 

largest stationary source NOx emissions according to the 1996 WRAP database were AZ, CA, 

ND, NM, UT, and WY. 

According to the WRAP 1996 (Version 3) stationary source emissions database, about 4% of the 

NOx sources greater than 100 TPY had at least one type of control. Coal-fired boilers had the 

highest level of control (15%), followed by petrochemical processes (13%). The level of control 

for coal-fired boilers seemed low, even for 1996. Therefore, the 1996 WRAP database was 

compared with the data available for utility boilers in the 1996 CEMS and E-GRID databases. 

The EIA-767 database was also searched for NOx control technologies. This comparison only 

looked at coal-fired utility boilers and not all coal-fired boilers. However, only 3% of the WRAP 

NOx emissions from coal-fired boilers in the thirteen-state region were from non-utility boilers. 

WRAP data augmented by these other databases suggested that 44% of the utility boilers had at 

least one type of NOx control in 1996, mostly low-NOx burners. 

The NOx emission rate from external combustion boilers that is achievable with combustion 

modification depends on the fuel type. For coal-fired boilers, lower NOx emission rates are 

obtained when firing subbituminous coal as compared to bituminous coal. Considering the 
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amount of subbituminous coal in the West, there is a fairly even split between bituminous and 

subbituminous coals as fuels for utility boilers. This may have shifted since 1996, however. 

The cut-off of 100 TPY captures 60% of the PM emissions in the 1996 WRAP database for the 

thirteen-state region. The largest source category in the thirteen-state region is coal-fired boilers 

(40%); the top eight categories account for 92% of the PM emissions (greater than 100 TPY): 

coal-fired boilers, mineral processing, petrochemical, wood boilers, fugitive, primary metal 

production, pulp and paper, and smelting operations. The state with the largest PM emissions is 

WY, followed by AZ, ID, and NM. 

In the 1996 WRAP database, 72% of coal-fired boilers, the largest category of emissions, had 

PM controls. Overall, though, only 38% of units had PM controls. 

6.2 Controls for NOx and PM 

Many commercially available technologies exist for control of NOx and PM emissions from 

stationary sources. Twenty-five NOx control technologies and four PM control technologies 

were summarized. Cost and performance information was obtained for most technologies. 

There are a lot more technologies available for NOx control because of the different ways in 

which NOx can be prevented or destroyed. In contrast, PM control on industrial processes is 

often done only at the back end of the process. This is not to say that process modification 

cannot be used to reduce PM emissions. Fugitive emissions, for example, can sometimes be 

controlled by process modification. Further work should be done to look into the details of 

important industrial processes to determine where process modification will yield significant 

reductions in PM. 

Most of the NOx emissions from stationary sources are generated by combustion or by high 

temperature thermal processing. NOx control technologies fall broadly into two categories: 

combustion modifications and post-combustion removal or destruction. Combustion systems 

differ, from internal combustion engines to external combustion boilers. Thus, there are many 

different strategies for modifying the combustion process. Deciding on an appropriate NOx 

control technology is highly dependent on the process conditions and on the type of fuel. The 

existing NOx control technology on a particular source will also influence what additional NOx

controls can be added successfully. Post-combustion NOx controls are not truly “back-end” 

technologies, like ESPs and baghouses for PM control; some degree of process integration is 

required. Thus, not all post-combustion control processes can be applied to a given source. 

There is no “one size fits all” solution for NOx control. Deciding which technology to apply to a 

certain source depends on: 

• The fuel type; 

• The specific combustion process; 

• Post-combustion characteristics: temperature, residence times, etc.; 

• The type of NOx control technology already in use; and 

• The target NOx emission rate. 
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Emerging environmental issues and regulatory changes have driven interest in multi-pollutant (as 

opposed to single pollutant) control technologies capable of addressing air pollutant emissions 

more comprehensively with greater flexibility and ultimately lower cost. Multi-pollutant control 

technologies integrate in-situ and/or post-combustion controls of at least two of the following: 

SO2, NOx, and mercury pollutants, and CO2 emissions. Multi-pollutant controls are intended 

primarily for external combustion boilers, particularly coal-fired boilers. The complexity of 

some of these processes as well as regulatory drivers often limit them to larger, power-generation 

boilers. 

Emerging post-combustion, multi-pollutant control technologies are being developed for SO2, 

NOx, and mercury that could be applied to stationary combustion sources in the western U.S. in 

the next five or ten years. These processes generally produce a saleable byproduct and have SO2

removal rates of greater than 50%, and NOx removal rates of greater than 70%. Several of these 

processes are currently in pilot or full-scale demonstration. Costs of options controlling two 

pollutants (either SO2-NOx or SO2-Hg) are projected to be in the 50-315 $/kW range, but there is 

significant uncertainty associated with these estimates because of their early stage of 

development. Also, lack of information, especially associated with O&M costs, makes it 

difficult to compare their cost-effectiveness. Further monitoring and updating of cost-related 

information is needed. For reference, the costs of the combined commercial technologies, FGD 

and SCR are above 200-250 $/kW. 

6.3 What’s on the horizon? What trends will influence emissions and control 

technologies? 

- The rate of advancement and use of multi-pollutant technologies (NOx/Hg, SO2/Hg, 

PM/Hg, etc.) will depend on the levels of future mercury emissions reduction. 

- Significant enhancements have been made in the ability of combustion modifications to 

reduce NOx formation, but they may be reaching their maximum potential given the 

theoretical limits within the combustion process and given the nitrogen content of some 

fuels (e.g., coal). Determining how much NOx emissions can be reduced in the West 

through this type of technology will require closer examination of the types and vintages 

of combustion modifications already in place. 

- There is (and always will be) uncertainty in the future mix of fuels for some combustion 

processes (e.g. electricity production). This influences the retirement of existing sources 

and the investment in new sources, which, in turn requires that a range of projections be 

made for future source distribution scenarios.

- Historically new technologies have had one major evaluation criteria in common: their 

performance improvement over the existing technology (e.g. SCR capable of 90% 

reductions over SNCR). As technologies push the potential control levels to 90% or 

more, we need to view them from a new perspective, one which includes greater 

emphasis on overall impacts, costs, inter-pollutant compatibility, etc.
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6.4 Recommendations for Future Work 

Further work must be done in order to generate both accurate costs and reasonable control 

scenarios to be used in both regional-scale atmospheric models and in evaluating regional control 

strategies, particularly in light of the multi-pollutant control legislation currently under 

consideration in Congress. This includes the following: 

• Accurate cost information (generally available now); 

• Details of the emission-generating processes; 

• NOx and PM control technologies already in place; and 

• Accurate estimates of the current emissions. 

Better use could be made of existing EPA databases; in addition, the WRAP database should be 

updated to give a more accurate description of sources and existing control technology. 

In this work, we found that the EPA databases (CEMs and E-GRID) were easy to use and 

provided what appeared to be a fairly complete picture of current emissions and control 

technologies for NOx and PM. Since much has changed in the West since the 1996 WRAP 

stationary source inventory, these databases are useful for getting more current information on 

utility boilers, which generate a significant amount of the emissions in the western U.S. It would 

be worthwhile now to look at trends in emissions and NOx control technologies in the West by 

analyzing the most recent CEMs and E-GRID databases. 

Sufficient detail about the configuration and process of the sources is generally not available in 

the EPA databases and these databases are only for utility boilers. The next WRAP inventory 

should be used to collect the information needed to make estimates of costs for control. Better 

identification of sources is important; there are instances in the 1996 WRAP database in which 

there is insufficient information on the type of source and/or the fuel in use. Obviously, better 

identification of existing air pollution control technology is critical. For combustion sources, 

particularly utility boilers, the capacity, in terms of MBtu/yr should also be included in the 

WRAP database. 

Consideration should also be given to selecting a subset of sources for detailed characterization 

and calculate ranges of costs and expected emissions reductions. The subset should be a 

representative distribution of those sources within the most important source categories. 
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 7 REFERENCES 

1. EPA Emissions Tracking System (Acid Rain Program), 

http://www.epa.gov/airmarkets/emissions/index.html. 

2. EPA Emissions & Generation Resource Integrated Database (E-GRID), 

http://www.epa.gov/airmarkets/egrid/. 

3. DOE Energy Information Agency, EIA-767 Steam Electric Plant Report, 

http://www.eia.doe.gov/fuelelectric.html. 

4. “Multi-pollutant Emission Control Technology Options for Coal-Fired Power Plants,” 

EPA-600/R-02/075, October 2002. 

5. Battye, R., Walsh, S., Lee-Greco, J. “NOx Control Technologies for the Cement Industry 

(Final Report).” EPA Contract No. 68-D98-026, EC/R Incorporated, Chapel Hill, NC, 

September 2000. 

6. Dusome D. (1993). “Staged Combustion for NOX Control at the Calaveras Tehachapi 

Plant”, presented to the Portland Cement Association. 

7. Nielsen, P.B. et al. (1990). “An Overview of the Formation of SOX and NOX in Various 

Pyroprocessing Systems”, IEEE Cement Industry Technical Conference. 

8. SA Johnson and S Haythornthwaite, Summary of Available NOx Control Techniques for 

the Cement Industry, submitted to the Portland Cement Association, Skokie, IL 1998. 

9. Amar, K.P., Staudt, J. “Status Report on NOx Controls for Gas Turbines, Cement Kilns, 

Industrial Boilers, Internal Combustion Engines; Technologies and Cost Effictiveness.” 

Norhteast States for Coordinated Air Use Management, Boston, MA, January, 2001.

10. U.S. Environmental Protection Agency. “Alternative Control Techniques DocumentNOx Emissions from Stationary Gas Turbines.” EPA-453/R-93-007, Research Park 

Triangle, NC, January, 1993. 

11. Edgerton, S. W., Lee-Greco, J., and Walsh, S. “Stationary Reciprocating Internal 

Combustion Engines Updated Information on NOx Emissions and Control Techniques 

(Final Report).” EPA contract No. 68-D98-026, EC/R Incorporated, Chapel Hill, NC, 

August 29, 2000. 

12. State of New Jersey Department of Environmental Protection. “State of the Art (SOTA) 

Manual for Reciprocating Internal Combustion Engines.” Trenton, NJ, July, 1997. 

13. SA Johnson and S Haythornthwaite, Summary of Available NOx Control Techniques for 

the Cement Industry, submitted to the Portland Cement Association, Skokie, IL 1998. 

14. State of California Air Resources Board. “CAPCOA/ARB Proposed Determination of 

Reasonably Available Control Technology and Best Available Retrofit Control 

Technology for Stationary Internal Combustion Engines (DRAFT).” Sacramento, CA, 

December, 1997. 

15. State of New Jersey Department of Environmental Protection. “State of the Art (SOTA) 

Manual for Reciprocating Internal Combustion Engines.” Trenton, NJ, July, 1997. 

16. European IPPC Bureau. “Reference Document on Best Available Techniques in the 

Glass Manufacturing Industry.” Seville, Spain, October, 2000. 

17. W. Neuffer, U. S. EPA. Summary of Information Provided by Engine Manufacturers on 

Low Emission Combustion. 

18. Telecon. R. Faulkner, Diesel Supply Company, with S. Edgerton, EC/R. April 6, 2000. 
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19. Cooper-Bessemer. Facsimile from J. W. Hibbard to W. Neuffer, U. S. EPA. Information 

on Low Emission Combustion. Cooper-Bessemer, Cooper Energy Services, Mount 

Vernon, OH. March 3, 1999. 4pp. 

20. Dresser-Rand. Facsimile from C. F. Willke to W. Neuffer, U. S. EPA. Information on 

Low Emission Combustion. Dresser-Rand Services, Painted Post, NY. May 7, 1999. 

2pp. 

21. National Center for Environmental Research, U. S. EPA Office of Research and 

Development. “1994 Phase II Abstracts: Plasma Ignition Retard for NO(x) Reductions.” 

http://es.epa.gov/ncerqa_abstracts/sbir/94/topics43.html. 

22. Manufacturers of Emission Controls Association. Emission Control Technology for 

Stationary Internal Combustion Engines. Status Report, July 1997. Pg. 7. 

23. NOxTech Inc. Letter and attachments from E. Cazzola to Mary Jo Krolewsky, U. S. EPA 

Acid Rain Division. April 12, 1999. 

24. NOxTech Inc. “NOxTech® Technology.” website. 

www.noxtechinc.com/products.htm. 

25. Goal Line Environmental Technology News. “Cummins Engine Co. Tests SCONOx®

for Diesel IC Engines.” Oct 1999. Vol 1, Issue 3. 
APPENDIX A : Breakdown of NOx Emissions by State 
A-1 

Table A-1. WRAP NOx Emissions for sources > 100 TPY by State 

Category 13-States AZ* CA*  # Units 

Total NOx

TPY (>100 

TPY) # Units 

Total NOx

TPY (>100 

TPY) # Units 

Total NOx

TPY (>100 

TPY) # Units 

Coal-Fired Boilers 151 607,748 15 75,018 3 1,544 31 Reciprocating Engines 423 86,210 16 6,441 58 10,274 56  NG 404 81,786 14 5,731 54 9,436 5 Diesel 16 4,021 2 709 3 708  Process Gas 3 403 1 130 Cement Kilns 39 41,009 2 4,662 16 15,886 4 Oil/NG Boilers 112 32,910 4 1,092 40 12,290 9 Turbines 86 25,278 8 1,918 37 8,990 9  NG 83 24,821 7 1,795 37 8,990  Diesel 3 457 1 123 Mineral Processing 34 16,250 4 2,861 4 3,263 Petrochemical 48 13,719 1 101 13 3,978 4 NG Compressor 16 10,959 14 10,686 Pulp and Paper 39 10,010 3 602 Wood Boilers 48 9,776 14 2,430 Refinery Process Heaters 38 9,311 28 7,096 Glass Manufacture 14 5,033 11 4,128 1 Primary Metal Production 17 3,476 2 1,009 2 Waste Combustion 6 3,309 Refinery Emissions 8 3,256 8 3,256 In-process Fuel Use 9 2,605 7 1,906 Jet Engine Testing 4 2,297 4 2,297 Oil and Gas Production 7 1,140 Smelting Operations 3 961 2 852 Sugar Beet Production 3 730 1 111 Secondary Metal Production 4 507 Turbines, Steam 1 165 1 165 Total (> 100 TPY) 1,110 886,659 68 104,639 248 78,217 116 

* GCTVR State 
A-2 

Table A-1. WRAP NOx Emissions for sources > 100 TPY by State [continued] 

Category ID* MT ND  # Units 

Total NOx

TPY (>100 

TPY) # Units 

Total NOx

TPY (>100 

TPY) # Units 

Total NOx

TPY (>100 

TPY) # Units 

Coal-Fired Boilers 6 2,218 6 25,452 17 108,007 10 Reciprocating Engines 14 4,357 8 2,569 201  NG 4 2,056 8 2,569 20 Diesel 10 2,301  Process Gas Cement Kilns 1 1,662 1 Oil/NG Boilers 1 128 3 909 10 Turbines 1 139 0 0 3 564 12  NG 1 139 3 564 1 Diesel Mineral Processing 1 117 3 428 1 Petrochemical 3 1,449 5 842 1 915 1 NG Compressor Pulp and Paper 3 377 4 920 Wood Boilers 4 708 4 1,057 1 Refinery Process Heaters 1 Glass Manufacture Primary Metal Production Waste Combustion 4 2,971 Refinery Emissions In-process Fuel Use 1 589 Jet Engine Testing Oil and Gas Production 2 348 1 Smelting Operations Sugar Beet Production 2 619 Secondary Metal Production Turbines, Steam Total (> 100 TPY) 18 5,008 39 35,436 40 116,901 23

* GCTVR State 
A-3 

Table A-1. WRAP NOx Emissions for sources > 100 TPY by State [continued] 

Category NV* OR* SD  # Units 

Total NOx

TPY (>100 

TPY) # Units 

Total NOx

TPY (>100 

TPY) # Units 

Total NOx

TPY (>100 

TPY) # Units 

Coal-Fired Boilers 8 39,040 1 4,195 3 17,268 15 Reciprocating Engines 15  NG  Diesel  Process Gas Cement Kilns 2 3,789 2 687 3 2,718 2 Oil/NG Boilers 6 3,727 6 2,155 1 Turbines 1 191 3 5,372 2 435 3  NG 2 5,229 2 435  Diesel 1 191 1 143 Mineral Processing 2 218 2 577 5 Petrochemical 2 NG Compressor 2 Pulp and Paper 14 3,641 Wood Boilers 17 3,366 Refinery Process Heaters Glass Manufacture Primary Metal Production 1 125 3 514 7 Waste Combustion 2 Refinery Emissions In-process Fuel Use 1 109 Jet Engine Testing Oil and Gas Production Smelting Operations Sugar Beet Production Secondary Metal Production Turbines, Steam Total (> 100 TPY) 21 47,199 46 19,929 10 20,998 

* GCTVR State 
A-4 

Table A-1. WRAP NOx Emissions for sources > 100 TPY by State [continued] 

Category WA WY*  # Units 

Total NOx 

TPY (>100 

TPY) # Units 

Total NOx 

TPY (>100 

TPY) 

Coal-Fired Boilers 8 20,138 28 95,148 Reciprocating Engines 7 1,191 48 10,219  NG 5 918 48 10,219  Diesel  Process Gas 2 273 Cement Kilns 4 4,126 2 1,444 Oil/NG Boilers 28 5,758 4 553 Turbines 3 324 4 1,971  NG 3 324 4 1,971  Diesel Mineral Processing 4 1,904 8 2,197 Petrochemical 11 3,635 7 1,619 NG Compressor Pulp and Paper 15 4,471 Wood Boilers 8 1,856 Refinery Process Heaters 9 2,009 Glass Manufacture 2 654 Primary Metal Production 1 116 1 205 Waste Combustion Refinery Emissions In-process Fuel Use Jet Engine Testing Oil and Gas Production 4 652 Smelting Operations 1 109 Sugar Beet Production Secondary Metal Production 4 507 Turbines, Steam Total (> 100 TPY) 105 46,798 106 114,009 

*GCVTR State 
: 

APPENDIX B : Breakdown of PM Emissions by State 
Table B-1. WRAP PM Emissions for sources > 100 TPY by State 

Category 13-States AZ* CA* C # Units 

Total PM 

TPY # Units 

Total PM 

TPY # Units 

Total PM 

TPY # Units 

Coal-Fired Boilers 88 46,010 9 2,657 1 699 3 Mineral Processing 85 24,499 14 4,932 5 710 18 Petrochemical 42 10,836 5 834 4 Wood Boilers 24 5,718 3 471 Refinery Emissions 11 5,631 2 3,949 1 104 3 Primary Metal Production 20 4,697 3 529 1 139 1 Pulp and Paper 15 4,476 2 272 Smelting Operations 8 3,555 1 137 Miscellaneous 1 2,456 1 2,456 Oil/NG Boilers 5 1,379 Sugar Beet Processing 5 1,150 1 210 1 110 1 Cooling Tower 4 932 Cement Kilns 4 641 1 132 Turbines 2 838 1 590 1  Diesel 1 590 1 590  NG 1 248 Secondary Metal Production 1 537 Jet Engine Testing 2 535 2 535 Reciprocating Engines 3 525 1 104 1  Diesel 2 273 1 104  NG 1 252 Refinery Process Heaters 1 176 1 176 Total 321 114,589 32 13,107 24 6,638 32 

* GCTVR State 
Table B-1. WRAP PM Emissions for sources > 100 TPY by State [continued] 

Category ID* MT ND N # Units 

Total PM 

TPY # Units 

Total PM 

TPY # Units 

Total PM 

TPY # Units 

Coal-Fired Boilers 8 5,180 4 3,990 11 3,679 9 Mineral Processing 5 1,864 9 2,565 1 110 2 Petrochemical 4 688 2 274 1 590 1 Wood Boilers 6 1,683 2 242 Refinery Emissions Primary Metal Production 1 477 Pulp and Paper 6 2,949 Smelting Operations 1 158 4 Miscellaneous Oil/NG Boilers Sugar Beet Processing 1 297 Cooling Tower Cement Kilns 1 216 1 117 1 Turbines  Diesel  NG Secondary Metal Production Jet Engine Testing Reciprocating Engines  Diesel  NG Refinery Process Heaters Total 30 12,579 20 7,825 14 4,676 17 

* GCTVR State 
Table B-1. WRAP PM Emissions for sources > 100 TPY by State [continued] 

Category NV* OR* SD U # Units 

Total PM 

TPY # Units 

Total PM 

TPY # Units 

Total PM 

TPY # Units 

Coal-Fired Boilers 8 5,688 1 108 2 236 8 Mineral Processing 2 244 11 Petrochemical Wood Boilers 11 3,056 Refinery Emissions 1 233 Primary Metal Production 1 211 1 276 4 Pulp and Paper 5 898 Smelting Operations 2 Miscellaneous Oil/NG Boilers 4 1,235 1 144 Sugar Beet Processing Cooling Tower Cement Kilns Turbines  Diesel  NG Secondary Metal Production 1 537 Jet Engine Testing Reciprocating Engines  Diesel  NG Refinery Process Heaters Total 15 7,379 20 5,019 3 469 25 

* GCTVR State 
Table B-1. WRAP NOx Emissions for sources > 100 TPY by State [continued] 

Category WA WY*  # Units 

Total PM 

TPY # Units 

Total PM 

TPY 

Coal-Fired Boilers 4 2,968 20 10,400 Mineral Processing 18 6,594 Petrochemical 2 255 23 7,130 Wood Boilers 2 266 Refinery Emissions 3 386 1 115 Primary Metal Production 8 1,976 Pulp and Paper 2 357 Smelting Operations Miscellaneous Oil/NG Boilers Sugar Beet Processing 1 103 Cooling Tower 4 932 Cement Kilns Turbines  Diesel  NG Secondary Metal Production Jet Engine Testing Reciprocating Engines 1 252  Diesel  NG 1 252 Refinery Process Heaters Total 22 6,311 67 25,423 

*GCVTR State 
APPENDIC C: NOx Control Technology Summaries 
C-1 

Process: Air or Fuel Staging

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

 Cement Kilns 41,009 0 to 50% 1000-2000 Commercial 

Process Description: 

Inject portion of the fuel downstream of the main flame to create locally reducing conditions where NOx

can be destroyed. Sometimes includes installing a “NOx fan” to increase burnout. Most commonly 

applied to preheater/precalciner kilns in which part of the coal is already being fired in the calciner. In 

this case, airflow is rerouted downstream of the calciner fuel injector. 

Air and Fuel Staging as commonly applied to large industrial/utility boilers is discussed under the more 

commonly referred names technologies Overfire Air and Fuel Reburn 

NOx Reduction: 

NOx reduction is achieved by creating two separate combustion zones. The burner zone is fired fuel-lean 

to create the high temperatures needed for clinker formation. Limestone calcination, which takes place at 

temperatures in the range of 1600 to 1800 °F, is accomplished in the second combustion zone in the 

tower. NOx reductions as high as 50% can be achieved by controlling the size of the fuel-rich region in 

the second combustion zone. Conversely, if combustion is fuel-lean or well-mixed in the second zone, 

NOx would not be reduced. The ideal stoichiometric ratio in the calciner is 0.7 to 0.8. Some systems do 

not perform well because the second combustion zone is too fuel-rich (SR < 0.6), causing significant NOx

production when the staging air is added. 

Cost Information: 

Capital cost for the technology includes additional ductwork and controls. This should run between 

$200,000 and 500,000 depending on the length of new ductwork required. Operating cost should not 

change unless lower temperatures or locally reducing conditions adversely affect cement quality. 

Development Status: 

Commercially available. 

Practical Considerations: 

The technology is easier to implement on preheater/precalciner kilns since special injectors are required to 

introduce fuel or air into the middle of a rotating kiln. In either case, there must be sufficient residence 

time at high temperature to complete burnout. 

Compatibility with other air pollution control technologies: 

Reducing conditions may increase sulfur emissions or require additional SO2 emission controls. 
C-2 

Process: Air or Fuel Staging

Secondary Environmental Impacts: 

None expected. 

References: 

Dusome D. (1993). “Staged Combustion for NOx Control at the Calaveras Tehachapi Plant”, presented to 

the Portland Cement Association. 

Nielsen, P.B. et al. (1990). “An Overview of the Formation of SOX and NOX in Various Pyroprocessing 

Systems”, IEEE Cement Industry Technical Conference. 

Johnson, S.A. and Haythornthwaite, S., “Summary of Available NOx Control Techniques for the Cement 

Industry”, submitted to the Portland Cement Association, Skokie, IL, 1998. 
C-3 

Process: Batch/Cullet Preheating

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

Glass Manufacturing 5,033 5-25% 890-1,040 Commercial 

Process Description: 

Batch and cullet (recycled glass) preheating can be applied by direct preheating, indirect preheating and 

Edmeston EGB Filter. Direct preheating requires direct contact between the flue gas and the raw material 

in a cross-counter flow and incorporates a bypass that allows furnace operation to continue when 

preheater use is either inappropriate of impossible. The indirect preheater is in principle a cross-counter 

flow, plate heat exchanger. The Edmeston electrified granulate bed (EGB) filter system is a hybrid 

between an electrostatic precipitator for dust removal and a direct cullet preheater. 

NOx Reduction: 

Cullet preheating is primarily an energy saving technique (savings between 10-20%), but its practice 

reduces NOx emissions due to lower fuel requirements and lower furnace temperatures. 

Cost Information: 

Capital costs generally range from $42K-110K. Economics are strongly dependent on the capacity of the 

furnace and the preheater. 

Development Status: 

Commercially available 

Practical Considerations: 

Cullet preheating systems can be installed at any existing glass melting furnace with greater than 50% 

cullet in the batch. For economic reasons, the temperature of the waste gas available should be at least 

400-450°C, and a cooling of the flue gases by at least 200-250°C is needed. To prevent material 

agglomeration, the maximum entry temperature of the flue gases should not exceed 600°C. 

The design and implementation of the preheating unit should be evaluated with the over-all system 

configuration. Many technical issues, such as monitoring of the preheating temperature, should be 

carefully reviewed prior to the implementation. 

Compatibility with other air pollution control technologies: 

Cullet preheating is compatible with combustion modification techniques and post-combustion 

technologies. 

Secondary Environmental Impacts: 

• The use of a direct preheater causes increased emissions of particulate matter (up to 2000 

mg/Nm3

) and secondary particulate abatement is necessary. 

• Direct preheating reduces acidic compounds, SO2, HF, and HCl by up to 60%, 50%, and 90% 

respectively (difference before and after cullet bed). 

References 

European IPPC Bureau. “Reference Document on Best Available Techniques in the Glass Manufacturing 

Industry.” Seville, Spain, October, 2000. 
C-4 

Process: Catalytic Combustion

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

 Combustion or Gas Turbines 25,278 > 80% > 500 Commercial 

Process Description: 

Catalytic combustion reduces NOx formed from the combustion process by reducing the combustion 

temperature to reduce thermal NOx. The fuel and air are premixed into a fuel-lean mixture (fuel/air ratio 

of approximately 0.02) and then pass into a catalyst bed. In the bed, the mixture oxidizes without forming 

a high-temperature flame font. Peak combustion temperatures can be limited to below 2800 °F, which is 

below the temperature at which significant amounts of thermal NOx begin to form. Catalytic combustors 

can also be designed to operate in a rich/lean configuration. In this case, the air and fuel are premixed to 

form a fuel-rich mixture, which passes through a first stage catalyst where combustion begins. Secondary 

air is then added to produce a lean mixture, and combustion is completed in a second stage catalyst bed. 

NOx Reduction: 

According to one developer of the technology, catalytic combustion has been demonstrated to achieve 3 

ppm NOx on a 1.5 MW gas turbine. A NOx level of 3.3 ppm was achieved on a General Electric Frame 9 

test stand. 

Cost Information: 

Costs referenced above are preliminary and based on DOE reference below.

Development Status: 

Commercially available. 

Practical Considerations: 

Catalytic combustion techniques apply to all combustor types and are effective on both diesel- and gasfired turbines. The technology has a limited operating range, and thus cannot be applied to gas turbines 

subject to rapid load changes. 

Compatibility with other air pollution control technologies: 

Compatible with post-combustion technology. 

Secondary Environmental Impacts: 

None expected. 

References: 

NESCAUM, “ Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers and 

Internal Combustion Engines: Technologies and Cost Effectiveness,” December 2000

U.S. Environmental Protection Agency. “Alternative Control Techniques Document-NOx Emissions 

from Stationary Gas Turbines.” EPA-453/R-93-007, Research Park Triangle, NC, January 1993. 

DOE, “Cost Analyses of NOx Control Alternatives for Stationary Gar Turbines”, November 1999.
C-5 
C-6 

Process: DLN (Fuel-lean combustion)

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Turbines 25,278 70% 1,000-2,000 Commercial 

Process Description: 

Dry Low NOx (DLN) is a combustion technology for gas turbines that enables gas-turbine combustors to 

produce low NOx emission levels without diluents (such as water or steam) or catalysts. DLN technology 

utilizes a lean, premixed flame as opposed to a turbulent diffusion flame, a gas turbine equivalent of the 

LNB. 

NOx Reduction: 

Engines from 3-10 MW retrofit with DLN achieved 42 ppm NOx emissions, corresponding to reductions 

in the range of 60-83%. New and retrofit turbines in the larger, power plant sizes (over 50 MW) have 

been retrofitted to below 9 ppm of NOx. 

Cost Information: 

The cost of NOx reduction by DLN is very sensitive to the capacity factor of the turbine. There is also 

substantial variation in capital cost measured in terms of dollars/horsepower ($/hp) due to different 

turbine types and variations in turbine design. Reported costs in case studies show capital costs ranging 

from $750K-1,950K (4,700 hp at $160/hp and 13,000 hp at $150/hp). These are total project costs that 

owners attributed to the project, which may include project management or other charges associated with 

the project beyond the equipment and installation. 

Development Status: 

Commercially available 

As of August 2000, about 50 turbines had been retrofitted and over 500 new turbines were operating with 

DLN technology. 

Practical Considerations: 

Because DLN combustor technology operates under conditions that are much closer to the flammability 

limit than the conventional combustor technology, there is a significant risk of flame instability. 

Manufacturers have developed improved electronic turbine controls to address this problem. Some early 

experience has also found combustor liners failing after only about 5,000 hours compared to over 20,000 

hour lifetime for conventional technology. Similarly, manufacturers have developed improved liners to 

address this problem. 

Other considerations are: 

• DLN is achievable with fuels that can be premixed and are low in fuel nitrogen content, such as 

natural gas. Turbines that must maintain low NOx levels while operating on fuel oil may not be 

compatible with DLN. 

• Achieving low NOx across the full load range requires a sophisticated combustor design, often 

with variable operating modes in order to maintain flame stability. 
C-7 

Process: DLN (Fuel-lean combustion)

• The DLN combustor is typically larger than a conventional combustor and can have more limited 

operating ranges. 

Compatibility with other air pollution control technologies: 

Compatible with post-combustion technology (SCR, SNCR). 

Secondary Environmental Impacts: 

None expected. 

References: 

NESCAUM, “ Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers and 

Internal Combustion Engines: Technologies and Cost Effectiveness” December 2000. 
C-8 

Process: Flue Gas Recirculation (FGR)

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Oil/Natural gas boilers 32,910 40-80% 500-3,000 Commercial 

Refinery Process Heaters 9,311 

(combined 

with LNB) 5,900 Commercial 

Process Description: 

Flue Gas Recirculation (FGR) simply refers to a NOx reduction approach that involves reintroducing 

some flue gas (5% to 15%) into the combustion air (or directly into the burner) to suppress flame 

temperatures and minimize NOx formation. 

This technology usually involves a dedicated FGR fan to recirculate the flue gas back to the burner front 

and it is most applicable to gas fired applications. This is because its main benefit is in the minimization 

of thermal NOx (NOx formed from nitrogen in the combustion air), as opposed to fuel-NOx (NOx formed 

from fuel-bound nitrogen). Since in oil and coal sources a significant fraction of NOx comes from “fuelNOx”, FGR is less effective in such applications 

NOx Reduction: 

NOx reductions from FGR on gas-fired sources can be in the range of 40% to 80%. 

FGR is often used in combination with LNBs and discriminating between the relative NOx reduction 

contributions is difficult in some cases. 

Cost Information: 

The main costs associated with FGR involve the retrofit of the FGR fan(s) and required ductwork to route 

the flue gas to the burner front. Costs in the range of $10 - $20/kW are expected for power generation 

sources 

Development Status: 

FGR is a well-proven technology in commercial operations for many years. Variations of the general 

concept include Induced FGR where the gas recirculated to the burner zone through an eductor, as well as 

recirculated to individual burners as opposed to the combustion air windbox for mixing with the 

combustion air prior to entering the burners. 

Practical Considerations: 

As mentioned above, FGR is mostly appropriate for gas-fired applications. Its effectiveness on oil and 

coal reduce its “appeal” to such sources 

Care is necessary to ensure that the amount of FGR does not compromise boiler safety by diluting oxygen 

concentration in the combustion air to unsafe levels 
C-9 

Process: Flue Gas Recirculation (FGR)

Compatibility with other air pollution control technologies: 

FGR is used in combination with LNB’s and OFA. 

FGR is also compatible with post combustion NOx technologies although the overall cost effectiveness 

needs to be addressed case-by-case. 

Secondary Environmental Impacts: 

None expected. 

References: 

EPRI, “Retrofit NOx Control Guidelines for Gas- and Oil-Fired Boilers”, Final Report, December 1993. 

Poole, L., “Houston Galveston Area NOx Abatement Industries Perspective,” present at the Council of 

Industrial Boiler Owners, NOx Control XV Conference, Houston, TX, August 2002. 
C-10 

Process: Fuel Reburn

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Coal-fired boilers 607,748 30-60% 500-2,000 Commercial 

Wood/Biomass boilers 9,776 40-60% 300-3,000 Commercial 

Glass Melters 5,033 50-65% “moderate” Commercial 

Process Description: 

Reburning, while generically included in the “Combustion Modification” category of NOx control 

technologies, differs from the others (BCM, LNB and OFA) by “destroying” NO rather than by 

minimizing its formation. Fuel is introduced above the main burner zone in the furnace, creating a fuelrich (reducing) atmosphere in which NOx formed in the main burner zone is destroyed by reacting with 

hydrocarbon and nitrogen compounds. The hardware needed for reburning includes reburn fuel burners or 

nozzles and overfire or burnout air ports (see discussion on fuel-lean reburn for deviations from this). 

The level of complexity of a particular system depends mostly on the choice of the reburn fuel itself (gas, 

coal, oil, orimulsion), as well as on the status and capability of the existing boiler (e.g., the burner/boiler 

control system). 

NOx Reduction: 

Full load NOx reductions with reburning can be expected to range from 35% to 60% depending on factors 

such as: 

• reburn fuel type and quantity; typically the reburn fuel needs to provide 15-20% of the total 

heat input if it is gas or 25-30% if coal to obtain 50-60% ∆NOx

• initial NOx level 

• “tolerance” of negative impacts (e.g., efficiency loss, ash quality) 

At low loads, NOx reduction may fall to the 20-40% range, depending on the burner zone stoichiometry 

and low load operating characteristics of the boiler (e.g., operating at high excess air to control reheat 

temperature). Reburning, like SNCR and SCR, may be thought of as a “dial-in” technology in that NOx

reductions will be a function of the amount of reburn fuel (or the amount of nitrogen compound reagent in 

the case of SNCR and SCR). This feature may make it particularly attractive for compliance scenarios 

based on seasonal use, averaging and/or trading. 

Cost Information: 

In general, the capital costs range from $15/kW to $30/kW for gas reburn and $30/kW to $60/kW when 

using coal as the reburn fuel. Operating costs are mainly driven by fuel cost differential (certainly gas vs 

coal). For other fuels (e.g. coal/orimulsion reburning), fuel preparation costs become more important 

(micronization, atomization) as there is little or no fuel cost differential. 

Retrofit schedules are directly related to the scope of the retrofit requirements. In most cases, 3-6 weeks 

are adequate for a reburn retrofit. 
C-11 

Process: Fuel Reburn

Development Status: Commercial 

While reburning does not account for a significant fraction of installed NOx reduction technologies 

compared to LNBs, SNCR and SCR worldwide, it is gaining acceptance, and a number of recent activities 

suggest it has become a viable strategic option for NOx control. This increase in interest is due to two key 

factors, among others: (1) increased experience and encouraging results, which increase the level of 

comfort with the technology; and (2) the “proliferation” of advanced reburn technologies, each with its 

own features, advantages and disadvantages. These “advanced” reburning options involve enhancements 

of the conventional approach, with features ranging from combinations with SNCR to the outright 

avoidance of overfire air, as in fuel-lean gas reburn (FLGR). 

Practical Considerations: 

Boilers with the following design and operating characteristics are expected to be more suitable 

candidates for reburning: 

• firing low-sulfur coals (e.g., less propensity for waterwall corrosion) 

• low baseline unburned carbon (e.g., to minimize ash salability impacts). 

• favorable cross-section/height profiles (e.g., tall boilers which provide for adequate 

mixing/residence time to maximize effectiveness). 

• gas availability, very efficient/effective coal pulverizers (e.g., approaching micronization) or 

access to orimulsion for the reburn fuel 

Of major importance is the choice of reburn fuel. The increasing experience with coal and orimulsion 

dictates that these must be considered in light of cost, availability, deliverability and overall project 

objectives. However, the use of natural gas provides benefits from lower maintenance costs (e.g., less 

demand on pulverizers) and lower emissions of other pollutants (particulate, SOx, CO2). 

Compatibility with other air pollution control technologies: 

Reburn Technology can be implemented with both Low NOx combustion approaches (e.g. LNBs) and 

post combustion technologies (SNCR/SCR). However, the overall NOx reductions are not strictly additive 

and careful evaluation is required to ensure cost effective strategies. 

Secondary Environmental Impacts: 

Reburn technology has the potential to effect both positive and negative secondary environmental impacts 

depending on factors such as the reburn fuel, main combustion and reburn zone stoichiometries, boiler 

physical characteristics, etc. 

The following are potential impacts that must be analyzed on an individual unit basis 

• CO may increase due to stoichiometry in the reburn zone 

• LOI may increase due to stoichiometries and OFA design 
C-12 

Process: Fuel Reburn

• SO2/CO2 benefits when reburn fuel is gas (proportional to gas input) 

References: 

NESCAUM, “Status Report on NOx Control Technologies and Cost Effectiveness for Utility Boilers”, 

June 1998. 

EPRI, “Retrofit NOx Controls for Coal-Fired Utility Boilers – 2000 Update”, EPRI Final Report, 

December 2000. 

Folsom, B. “Field Experience with Reburn NOx Control”, ICAC Forum 2000, Arlington, VA. March 

2000. 
C-13 

Process: High Energy Ignition System (HEIS)

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

 Reciprocating Engines 86,210 50% - 80% 115 - 200+ Commercial 

Process Description: 

HEIS technology, also known as plasma ignition, provides a continuous electrical discharge at the gap of 

a conventional spark plug for 10 to 90 degrees of crankshaft rotation as opposed to traditional spark 

ignition where the life of the spark is only a fraction of a degree of crankshaft rotation. The extended 

energy ensures that ignition will occur even in the leanest of conditions. A rich mixture is ignited in a 

small ignition cell located in the cylinder head. The ignition cell flame passes to the cylinder where it 

provides a uniform ignition source. 

NOx Reduction: 

Laboratory tests and case studies have shown NOx emissions in the range of 2.5 to 3.0 g/bhp-hr while 

maintaining acceptable engine operation. Emissions of 2.5 b/bhp-hr were achieved on a 2,750-bhp 

engine, amounting to an 84% reduction from the uncontrolled level. 

Cost Information: 

Cost information was not widely reported. Cost range indicated above was taken from the NESCAUM 

reference below. 

Development Status: 

Commercially available 

HEIS has been installed on numerous engines to meet NOx RACT requirements in the range of 2.5 to 3.0 

g/bhp-hr in the Eastern United States. Several users have reported over 80% reduction in NOx emissions. 

Practical Considerations: 

HEIS technology can be used only in lean-burn, natural gas-fired spark ignition engines. This technique 

can be retrofit to turbocharged 2- and 4-cycle engines. 

Compatibility with other air pollution control technologies: 

Compatible with post-combustion NOx technologies (SCR, NSCR). However, the overall NOx reductions 

are not strictly additive and careful evaluation is required to ensure cost effective strategies. 

Secondary Environmental Impacts: 

In most cases, NOx reductions have been accompanied by increased power output and increased fuel 

economy. 

References: 

Edgerton, S. W., Lee-Greco, J., and Walsh, S. “Stationary Reciprocating Internal Combustion Engines 

Updated Information on NOx Emissions and Control Techniques (Final Report).” EPA contract No. 68-

D98-026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000. 

NESCAUM, “ Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers and 
C-14 

Process: High Energy Ignition System (HEIS)

Internal Combustion Engines: Technologies and Cost Effectiveness,” December 2000. 

State of New Jersey Department of Environmental Protection. “State of the Art (SOTA) Manual for 

Reciprocating Internal Combustion Engines.” Trenton, NJ, July, 1997. 

Alternative Control Techniques Document: NOx Emissions from Stationary Reciprocating Internal 

Combustion Engines. EPA Document No. EPA-453/R-93-032, July 1993. 
C-15 

Process: High-Pressure Fuel Injection 

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Reciprocating Engines 86,210 ~80% N/A (less than LEC) Commercial 

Process Description: 

High-Pressure Fuel Injection represents a “second generation” Low Emission Combustion (LEC), 

according to one vendor of NOx control equipment and retrofit services. The technology uses high 

pressure to enhance the mixing of air and fuel in the combustion cylinder under fuel lean conditions. This 

technique reduces the quantity of excess air in comparison to LEC, diminishing the turbocharging and 

intercooling retrofit requirements. 

NOx Reduction: 

Tests from a large (~5,000 bhp) turbocharged Clark engine showed 80% NOx reduction. May be 

comparable to LEC reductions. 

Cost Information: 

Less than LEC because the technology does not require pre-combustion chambers or as much excess air, 

thus reducing the degree of turbocharging and intercooling required. 

Development Status: 

Commercially available 

Considered emerging in 2000. 

Practical Considerations: 

An LEC retrofit vendor stated that NOx emissions cannot be reduced to 2 g/bhp-hr through the use of a 

high-pressure fuel system alone. Less stringent regulatory requirements cans be met with a combination 

of ignition timing adjustment, high-pressure fuel injectors, and improve A/F ratio and ignition system 

controls. 

Compatibility with other air pollution control technologies: 

Compatible with post-combustion NOx technologies (SCR, NSCR). However, the overall NOx reductions 

are not strictly additive and careful evaluation is required to ensure cost effective strategies. 

Secondary Environmental Impacts: 

None expected. 

 

References: 

Edgerton, S. W., Lee-Greco, J., and Walsh, S. “Stationary Reciprocating Internal Combustion Engines 

Updated Information on NOx Emissions and Control Techniques (Final Report).” EPA contract No. 68-

D98-026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000. 

National Center for Environmental Research, U. S. EPA Office of Research and Development. “1994 

Phase II Abstracts: Plasma Ignition Retard for NO(x) Reductions.” 

http://es.epa.gov/ncerqa_abstracts/sbir/94/topics43.html. 
C-16 
C-17 

Process: “Intelligent” Combustion Controls

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

 Coal-Fired Boilers 607,748 0-30% 100-300 Commercial 

 Oil/Gas Boilers 32,910 0-30% 100-500 Commercial 

 Wood/Biomass Boilers 9,776 0-20% 200-500 Commercial 

Process Description: 

Sensors and computer software programs are used to control air-fuel ratio to individual burners. 

Conventional combustion systems provide measured airflow to the windbox (that feeds all burners) and to 

each pulverizer (that feeds from two to eight burners). However, coal flow to individual burners may 

deviate by as much as 50%, while airflow to each burner may deviate by over 20%. Measuring and 

controlling (using existing or new control valves) these quantities at each burner allows the boiler to 

operate with lower excess air or slightly staged. Sensors are also available to monitor post-combustion 

processes. Online measurements of unburned carbon and CO provide feedback for burner adjustments. 

Other sensors evaluate flame quality, furnace temperature, or boiler heat transfer. Software can be rulebased or neural net. Usually the new software resides on the operator’s digital control system (DCS). 

NOx Reduction: 

Full -load NOx reductions with combustion monitoring and tuning can be expected to range from 0% to 

30% depending on factors such as: 

o Current state of “out of tune” combustion system. 

o Initial NOx level. 

o Operational flexibility of the burner/furnace design. 

The highest NOx reductions are usually found on boilers that are able to bias their fuel input to lower 

burners and bias the airflow to upper burners. At low loads where there may be more operating 

flexibility, NOx reduction may improve to the 20-40% range, depending on the burner zone stoichiometry 

and low load operating characteristics of the boiler (e.g., operating at high excess air to control reheat 

steam temperature). 

Cost Information: 

In general, the capital costs for combustion monitoring and tuning are less than $1M per boiler. 

Operating costs are mainly driven by additional labor to maintain the new equipment. Often the 

installation of this technology is driven by the potential to reduce boiler operational expenses. For 

example, if total airflow is minimized, boiler efficiency can be increased. Reducing unburned carbon in 

the ash residue will not only increase boiler efficiency but also could improve salability of this byproduct 

to the cement industry. 

An outage is generally not required when implementing this technology, but coal-flow sensors and 

adjustable orifices are best installed when a mill is out of service. 
C-18 

Process: “Intelligent” Combustion Controls

Development Status: 

Commercially available. Many of the sensors, however, are relatively new and do not have a track record 

for reliability and dependability. Since each application of the technology is custom-engineered, there 

may be a steep learning curve for every user. For now, each installation also requires onsite presence (for 

a few weeks) from the supplier or other combustion expert to achieve best results. 

Practical Considerations: 

Boilers with the following design and operating characteristics are expected to be more suitable 

candidates for combustion monitoring and tuning: 

• Combustion equipment must be in good operating condition. The technology will not be 

able to overcome such factors as poor coal fineness or failure of burner parts. 

• Favorable cross-section/height profiles (e.g., tall boilers which provide for adequate 

mixing/residence time to maximize effectiveness). 

• Excess coal pulverizer capacity so that fuel biasing can be maximized. 

Of major importance is acceptance from boiler operators. If operators want to stick with old procedures 

and operating conditions, the effectiveness of the technology may not be realized. 

Compatibility with other air pollution control technologies: 

Combustion monitoring and tuning can be implemented with both Low NOx combustion approaches (e.g. 

LNBs) and post combustion technologies (SNCR/SCR). However, the overall NOx reductions are not 

strictly additive and careful evaluation is required to ensure cost effective strategies. 

Secondary Environmental Impacts: 

Combustion monitoring and tuning has the potential to affect both positive and negative secondary 

environmental impacts depending on factors such as the fuel, burner stoichiometries, boiler physical 

characteristics, etc. 

The following are potential impacts that must be analyzed on an individual unit basis 

• CO may increase due to stoichiometry in the burner zone 

• LOI may increase due to increased staging 

• ESP performance may degrade with increased LOI 

References: 

Power Plant Optimization Guidelines, EPRI Report, December 1998 

Alternative Control Techniques Document: NOx Emissions from Industrial/Commercial/Institutional 

(ICI) Boilers. EPA Document No. EPA-453/R-94-022, July 1994. 

Alternative Control Techniques Document: NOx Emissions from Utility Boilers. EPA Document No. 
C-19 

Process: “Intelligent” Combustion Controls

EPA-453/R-94-023, July 1994. 

Fuller, T., “Field Experience with the Flame DoctorTM System”, EPRI/DOE/EPA Mega Symposium, 

Washington, May 2003 

Kohn, D. “Combustion Optimization Case Studies & Emerging Applications”, EPRI/DOE/EPA Mega 

Symposium, Washington, May 2003 
C-20 

Process: Iron Slag Addition (CemStar)

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

 Cement Kilns 41,009 12-30% 0-100 Commercial 

Process Description: 

Change cement formulation by adding waste iron to lower clinkering temperature and suppress NOx. The 

iron waste is usually supplied from local steel production facilities, which limits the technology to certain 

geographical areas. 

NOx Reduction: 

NOx reduction is achieved by reducing clinkering temperature as well as the required heat input to 

produce a ton of clinker. The technology reduces total NOx emissions by about 20 to 30%, and also may 

increase clinker production. 

Cost Information: 

Iron addition provides an overall economic benefit while reducing total NOx emissions. The technology 

is currently being used at several cement plants for its original purpose of increasing production capacity. 

There are no capital costs for installing the technology. Operating and maintenance costs depend on the 

cost of the iron (shipping can be a large portion of this cost). 

Development Status: 

Commercially available. 

Practical Considerations: 

There is a limit to how much iron that can be incorporated into the clinker. Cement product specifications 

may limit or prevent use of this technology for some products. 

Compatibility with other air pollution control technologies: 

Should not affect other control systems. 

Secondary Environmental Impacts: 

None expected. 

References: 

NESCAUM, “Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, Internal 

Combustion Engines; Technologies and Cost Effectiveness.” December 2000. 
C-21 

Process: Kiln temperature control

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

 Cement Kilns 41,009 0 to 20% 200-500 Commercial 

Process Description: 

Add temperature-monitoring device to kiln controls to minimize high-temperature excursions where more 

NOx is emitted. 

NOx Reduction: 

NOx reduction is achieved by measuring a characteristic flame-zone temperature and then controlling heat 

input to maintain that temperature. Without direct temperature measurement, temperatures fluctuate 

within a wide range since clinker formation is an exothermic reaction. When clinker formation slows 

down or stops, temperatures fall. Operators respond with a large burst of fuel that sends temperature up 

by as much as 500 °F. Then they back off the fuel input. Temperature measurement helps operators avoid 

losing clinker formation and thus maintain relatively steady kiln temperatures. 

Cost Information: 

Capital cost for the technology includes installation of a continuous temperature monitor along with 

control system upgrades to tie the temperature signal into the coal feed rate. Operating cost should not 

change unless lower temperatures adversely affect cement quality. 

Development Status: 

Commercially available. 

Practical Considerations: 

The dynamics of a cement kiln are very difficult to control, even with direct temperature measurement 

and control. Each kiln will react differently. It will require considerable operator experience to minimize 

the temperature on each kiln. 

Compatibility with other air pollution control technologies: 

Should not affect other control systems. 

Secondary Environmental Impacts: 

None expected. 
C-22 

Process: Kiln temperature control

References: 

U.S. Environmental Protection Agency. “Alternative Control Techniques Document: NOx Emissions from 

Cement Manufacturing.” EPA Document No. EPA-453/R-94-004, January 1994. 

Johnson, S.A. and Haythornthwaite, S., “Summary of Available NOx Control Techniques for the Cement 

Industry”, submitted to the Portland Cement Association, Skokie, IL, 1998. 
C-23 

Process: Low-Emission Combustion (LEC)

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Reciprocating Engines 86,210 80-90% 190-700 Commercial 

Process Description: 

NOx formation from a spark-ignited engine is highest when the mixture is slightly fuel-lean. LEC 

enhances the effectiveness of the air/fuel ratio method by enabling much deeper leaning without the 

adverse effects associated with lean mixtures. Additional combustion air acts as a heat sink, lowering the 

temperature in the cylinder and reducing NOx formation. Deeper leaning can be achieved by relocating 

the spark plug to a precombustion chamber (may use High-Energy Ignition, see associated description) 

where the mixture is somewhat richer than in the cylinder. Early sparking avoids problems associated 

with ignition and misfiring that can result form leaning the mixture. Some smaller engines use an “open 

chamber” LEC design instead of a precombustion chamber. These designs typically incorporate 

improved air-fuel mixing systems to achieve stable combustion under very lean conditions. 

NOx Reduction: 

Large, stationary spark-ignition engines usually achieve 80% NOx reduction through a LEC Retrofit. A 

NOx emission level of 125 ppm (at 15% oxygen) is an achievable exhaust NOx value. Up to 90% 

reduction can be achieved in natural gas engines, and about 60-70% for landfill gas engines (probably due 

to lower initial NOx from the lower heating-value landfill gas). 

Engines with open-chamber LEC technology typically are designed for excess air levels only slightly 

above 50%, while engines with precombustion chambers typically are designed for excess air levels of 

75-100%. Consequently, prechambered engines have generally lower NOx emissions than do openchamber models. 

Cost Information: 

The capital cost of retrofitting these engines depends on the engine BHP. For engines firing a single fuel, 

retrofits have been implemented costing $340/hp for 3400hp engines. A lower capital cost is expected for 

smaller, medium-speed engines, about $200/hp. Dual-fuel engines have much greater capital costs. For 

these engines (larger than 1,000 hp), the capital cost can be estimated by 

Capital Cost = $405,000 + ($450 x hp). 

Retrofitting a 2,500 hp engine is projected to cost $615/hp. 

Development Status: 

Commercially available 

The California Air Resources Board considers LEC Retrofit a Reasonably Available Control Technology 

(RACT) for large spark-ignition engines. LEC based on precombustion chamber technology has been in 

use for over 20 years. All major manufacturers of lean-burn spark ignition engines offer LEC-equipped 

models. Retrofit kits are also available. 
C-24 

Process: Low-Emission Combustion (LEC)

Practical Considerations: 

Available for spark-ignition engines fired with gaseous fuels including dual-fuel engines operating in 

dual-fuel mode (as opposed to firing only diesel fuel). LEC can cause some fuel efficiency decrease. A 

reasonable fuel efficiency penalty is estimated to be on the order of 0.5%. 

Turbocharging and intercooling are required to avoid derate. In retrofit situations, this typically involves 

upgrading or replacing the turbocharger and intercooler, or adding this equipment. 

Other equipment associated with increased air flows may also need to be modified for LEC, such as the 

air intake and filtration system, the intercooler radiator, and the exhaust system and muffler. To maintain 

the optimum A/F ratio, an automated A/F ratio controller typically is used. 

The challenge with very lean combustion is to achieve proper ignition and stable combustion. Vendors of 

LEC technology (i.e., engine manufacturers and third-party retrofitters) have met these requirements with 

some combination of improved combustion chamber design, enhanced air-fuel mixing, and improved 

ignition systems. 

Compatibility with other air pollution control technologies: 

Compatible with post-combustion NOx technologies (SCR, NSCR). However, the overall NOx

reductions are not strictly additive and careful evaluation is required to ensure cost effective strategies. 

Secondary Environmental Impacts: 

Emissions of products of incomplete combustion can increase. 

References: 

Edgerton, S. W., Lee-Greco, J., and Walsh, S. “Stationary Reciprocating Internal Combustion Engines 

Updated Information on NOx Emissions and Control Techniques (Final Report).” EPA contract No. 68-

D98-026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000. 

NESCAUM. “Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, 

Internal Combustion Engines; Technologies and Cost Effectiveness.” December, 2000. 

State of California Air Resources Board. “CAPCOA/ARB Proposed Determination of Reasonably 

Available Control Technology and Best Available Retrofit Control Technology for Stationary Internal 

Combustion Engines (DRAFT).” Sacramento, CA, December, 1997. 

State of New Jersey Department of Environmental Protection. “State of the Art (SOTA) Manual for 

Reciprocating Internal Combustion Engines.” Trenton, NJ, July, 1997. 

U.S. Environmental Protection Agency. “Alternative Control Techniques Document – NOx Emissions 

from Stationary Reciprocating Internal Combustion Engines.” EPA-453/R-93-032, July, 1993. 

Cooper-Bessemer. Facsimile from J. W. Hibbard to W. Neuffer, U. S. EPA. Information on Low 

Emission Combustion. Cooper-Bessemer, Cooper Energy Services, Mount Vernon, OH. March 3, 1999. 

4pp. 

Dresser-Rand. Facsimile from C. F. Willke to W. Neuffer, U. S. EPA. Information on Low 

Emission Combustion. Dresser-Rand Services, Painted Post, NY. May 7, 1999. 2pp.
C-25 

Process: Low-NOx Burners

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

Coal-Fired Boilers 607,748 30 to 60% 200-1000 Commercial 

Cement Kilns 41,009 0 to 20% 500-1000 Commercial 

Oil/NG Boilers 32,910 30 to 60% 200-1000 Commercial 

Glass Manufacturing 5,033 ~ 40% 790-1,680 Commercial 

Refinery Process Heaters 9,311 30 to 60% 5,900 (with FGR) Commercial 

Process Description: 

LNB’s operate on the principal of carefully controlling the rate of mixing of air and fuel within the flame 

so that peak flame temperatures are low and fuel-bound nitrogen is released in a region where the 

concentration of oxygen is very low. This inhibits the formation of both fuel and thermal NOx by 

reducing the concentration of oxygen in the flame zone. Most LNB’s work by limiting the amount of air 

in the primary flame creating a central fuel-rich flame core. Additional air is introduced to surround the 

primary flame where the temperature is lower, limiting thermal NOx formation. A few low-NOx burners 

split the coal flow into two or more streams to create multiple fuel-rich regions. One Japanese burner 

concentrates the coal-primary air mixture, and introduces the dilute coal stream downstream of the burner 

while air is introduced only to the primary flame. The fuel introduced into the primary flame zone results 

in a high temperature fuel rich central flame. The balance of coal is added outside the primary flame 

where it burns at a lower temperature. 

NOx Reduction: 

Full load NOx reductions with Low-NOx Burners can be expected to range from 30% to 60% depending 

on factors such as: 

• Fuel type. 

• Initial NOx level. 

• Excess air 

• Operational flexibility of the boiler or furnace. 

For coal-fired boilers, NOx emissions rates as low as 0.15 lb/MBtu are achievable, particularly when 

burning low rank coals. However, the fuel nitrogen content of coal is such that significantly lower 

emission rates are probably not possible with coal. Lower emission rates can be achieved with natural 

gas. Installing Low-NOx burners is usually the first step taken to reduce NOx emissions. 

Cost Information: 

In general, the capital costs for burners range from $10,000 to 50,000 per burner plus installation. The 

lower end of this range applies when existing burners are modified instead of replaced to achieve lower 

NOx. Operating costs are negligible unless increased unburned carbon results in lost revenues from ash 

sales. An outage is generally required when implementing this technology, but coal-flow sensors and 

adjustable orifices are best installed when a mill is out of service. 
C-26 

Process: Low-NOx Burners

Development Status: 

Commercially available. 

Practical Considerations: 

Since low-NOx Burners usually produce longer flames, the size and shape of the furnace could cause 

problems for some installations. Flame impingement on sidewalls or rear wall can result in ash deposits, 

corrosion, or unacceptable unburned carbon in the flue gas. Most burners have optional configurations to 

shape the flame at the expense of less NOx reduction. 

Compatibility with other air pollution control technologies: 

Low-NOx burners can be implemented with other NOx-control technologies such as OFA, SNCR, or SCR. 

In general, the NOx reduction achieved with LNB make post-combustion NOx control technologies more 

cost-effective. 

Secondary Environmental Impacts: 

Low-NOx burners can cause both positive and negative secondary environmental impacts depending on 

factors such as the fuel, burner stoichiometries, boiler physical characteristics, etc. 

The following are potential impacts that must be analyzed on an individual unit basis 

• CO may increase due to stoichiometry in the burner zone 

• LOI may increase due to increased staging 

• ESP performance may degrade with increased LOI or finer particulate. 

 

References: 

EPRI, “Retrofit NOx Controls for Coal-Fired Utility Boilers – 2000 Update”, EPRI Final Report, 

December 2000 

EPRI, “Retrofit NOx Controls for Coal-Fired Utility Boilers – 1996 Update Addendum”, May 1997 
C-27 

Process: Low-NOx Calciners

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

 Cement Kilns 41,009 30 to 50% 1000-5000 Commercial 

Process Description: 

Replace the riser duct in existing preheater/precalciner kilns with new equipment designed for staged 

combustion. The new duct has separated air and fuel injection points, and extended residence time 

downstream of the final air addition point to assure acceptable burnout and minimize CO or hydrocarbon 

emissions. 

NOx Reduction: 

NOx reduction is achieved by creating two separate combustion zones. The burner zone is fired fuel-lean 

to create the high temperatures needed for clinker formation. Limestone calcination, which takes place at 

temperatures in the range of 1600 to 1800 °F, is accomplished in the second combustion zone in the 

tower. NOx reductions as high as 50% can be achieved by controlling the size of the fuel-rich region in 

the second combustion zone. Conversely, if combustion is fuel lean or well mixed in the second zone, 

NOx will not be reduced. The ideal stoichiometric ratio in the calciner is 0.7 to 0.8. Some systems do not 

perform well because the second combustion zone is too fuel-rich (SR < 0.6), causing significant NOx

production when the staging air is added. 

Cost Information: 

Capital cost for the technology includes additional injectors, ductwork and controls. In some cases, the 

cyclones used to improve gas-solids contact are also replaced. Capital cost range from $500,000 and 

5,000,000 depending on how much of the existing tower is replaced. Operating costs should not change 

unless cement quality degrades due to lower temperatures or locally reducing conditions. An outage is 

required to install the new equipment. 

Development Status: 

Commercially available. 

Practical Considerations: 

Space to fit the newer larger equipment may not be available in all kilns. 

Compatibility with other air pollution control technologies: 

Reducing conditions may increase sulfur emissions or require additional SO2 emission controls. 

Secondary Environmental Impacts: 

None expected. 
C-28 

Process: Low-NOx Calciners

References: 

Rother, R. and Kupper, D., “Staged Fuel Supply – An Effective Way of Reducing NOx Emissions”, 

Zement-Kalk-Gips, No. 9. 1989. 
C-29 

Process: Mid-Kiln or Tower Tire Injection

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

 Cement Kilns 41,009 15-30% 0-1000 Commercial 

Process Description: 

Cement kilns are normally fired with a single open-pipe burner fueled by coal or natural gas. However, a 

portion of the main fuel may be replaced by a waste fuel injected in the mid-kiln region of long, wet or 

dry kilns, or in the calcining region of tower kilns. Special injectors have been designed to time the 

introduction of two to four tires into the mid-kiln region as the kiln rotates. Due to rotation, tires can only 

fall into the kiln once per revolution when the door is on top. Alternately, tires can be dropped into the 

tower where temperatures are high enough to support combustion. 

Mid-kiln tire injection is attractive because it not only reduces NOx but also generates revenue in the form 

of tipping fees and reduced fuel requirements. Cadence Environmental Energy, a subsidiary of Ash 

Grove Cement, offers an automated whole-tire injection system, including a fork that picks up the tires 

and drops them into the kiln through a gate assembly. A second option is to set up a tire shredding 

operation on site and inject tire flake into the kiln. 

NOx Reduction: 

NOx is lowered by burning some of the fuel at a lower temperature, and by creating pockets of fuel-rich 

gas as the tires decompose. Hydrocarbons from tire destruction can reduce NOx formed in the burner 

flame. Results to date have varied from 15 to 30% NOx reduction, depending on: 

• Kiln type. 

• Number of tires injected. 

• Injection temperature. 

In some installations, a booster fan has been mounted on the kiln downstream of the tire injection point to 

provide additional burnout air. This “NOx fan” gets rid of the high CO or smoke emissions caused by the 

tires, and may allow operation at higher tire injection rates. 

Cost Information: 

The capital costs for installing a mid-kiln tire injection system are about $2 to 4M. Operating and 

maintenance costs should not be affected. Often the installation of this technology is driven by the 

tipping fee revenue generation. If this is possible, injector costs can be recovered within a few years. 

An outage is required when implementing this technology, but downtime can be minimized at sites where 

space is sufficient for installing the injection system ahead of time (without getting in the way of kiln 

operation). 

Development Status: 

Commercially available. 
C-30 

Process: Mid-Kiln or Tower Tire Injection

Practical Considerations: 

The main purpose of a cement kiln is to produce as much high-quality clinker as possible at the lowest 

energy cost. Over-feeding tires creates locally reducing conditions that cause smoke, soot, and spoil the 

naturally occurring sulfur capture in the clinker resulting in higher SO2 emissions. The practical limit on 

tire injection is replacement of about 10 to 30% of the fuel, depending on the kiln design. Also, since 

tires are injected every two minutes, the NOx emissions rise and fall erratically, making control very 

difficult. 

Compatibility with other air pollution control technologies: 

High airflows from the NOx fans can cause increased carryover of cement kiln dust (CKD) into the 

exhaust. Reducing conditions in the flame zone increase SO2 emissions. 

Secondary Environmental Impacts: 

Combustion monitoring and tuning has the potential to effect both positive and negative secondary 

environmental impacts depending on factors such as the fuel, burner air-fuel ratio, kiln design, etc. 

The following are potential impacts that must be analyzed on an individual unit basis 

• CO, hydrocarbons and soot emissions may increase due to tire byproducts escaping the secondary 

combustion zone. 

• SO2 may increase due to increased staging. 

• ESP performance may degrade with increased CKD. 

References: 

U.S. Environmental Protection Agency, “Alternative Control Techniques Document: NOx Emissions from 

Cement Manufacturing.” EPA Document No. EPA-453/R-94-004, January 1994. 

“Stick a Fork in It”. Product Brochure from Cadence Inc., 1997. 
C-31 

Process: Non-Selective Catalytic Reduction (NSCR) 

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

IC Engines, rich-burn only 111,488 40-98% < 500 Commercial 

Process Description: 

In NSCR, the engine exhaust is routed to a catalyst bed across which NOx is reduced to nitrogen gas. At 

the same time, VOC and carbon monoxide are oxidized to water and carbon dioxide. Because the catalyst 

reduces emissions all three of these pollutants, NSCR is often referred to as a “three-way catalyst” 

system. These systems are similar to the catalytic converters used on automobiles. 

For an NSCR system to operate optimally (i.e., to minimize NOx emissions), the inlet exhaust stream 

must have very low oxygen content, as well as proper concentrations of NOx, hydrocarbons, and carbon 

monoxide. This requires initial engine adjustments, followed by careful monitoring of oxygen content in 

the exhaust. For this reason, an automatic air-fuel (A/F) ratio controller typically is used to regulate the 

exhaust oxygen content entering the catalyst bed. The controller adjusts the A/F ratio based on input from 

an oxygen sensor upstream from the catalyst bed. 

Because of the requirement for low oxygen content, NSCR systems are limited to rich-burn SI engines. 

NOx Reduction: 

This source indicates that these catalyst systems reduce NOX emissions by over 98 percent, while 

reducing VOC by 80 percent and carbon monoxide by over 97 percent. NOx levels in the range of 0.1 to 

1.0 g/bhp-hr have been achieved. 

Cost Information: 

Capital cost for NSCR includes the catalyst as well as the addition of oxygen sensors and controls. 

Catalyst replacement generally occurs after about 20,000 hours of operation. 

Development Status: 

Commercial. Information from vendors of NSCR systems indicates that NSCR three-way catalysts have 

been installed on over 1,000 IC engines in the United States and have been in use for over 10 years. . 

Practical Considerations: 

The engine adjustments required to optimize NSCR systems typically reduce the efficiency of the engine, 

harming fuel economy. The biggest operational problem associated with NSCR has been damage to the 

catalyst caused by excessive temperature. This is caused when the exhaust stream is too fuel rich. In this 

situation, the uncombusted natural gas is rapidly oxidized in the catalyst bed, burning it out. At about 

1,300 o

F, the catalyst sustains damage. 

Compatibility with other air pollution control technologies: 

Enhanced removal of CO and VOC can be achieved. 
C-32 

Process: Non-Selective Catalytic Reduction (NSCR) 

Secondary Environmental Impacts: 

None expected. 

References: 

Manufacturers of Emission Controls Association. “Emission Control Technology for Stationary Internal 

Combustion Engines.” Status Report, July 1997. 

Edgerton, S. W., Lee-Greco, J., and Walsh, S. “Stationary Reciprocating Internal Combustion Engines 

Updated Information on NOx Emissions and Control Techniques (Final Report).” EPA contract No. 68-

D98-026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000.
C-33 

Process: NOxTech

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Reciprocating Engines 86,210 90-95% ~ 1000 Commercial 

Process Description: 

According to product literature, the NOxTech® emission control system, developed by NOxTech Inc., 

NOxTech is an automated system in which exhaust gases are chemically treated with a nonhazardous 

liquid chemical. The technology involves replacing the engine exhaust silencer with a reaction chamber 

where NOx and reagent react to form nitrogen, water vapor, and carbon dioxide. The non-catalytic 

chemical reagent is injected into the exhaust at temperatures between 1,400 and 1,500 °F. 

NOx Reduction: 

The vendor states that NOxTech has been proven to remove 90-95% of NOx, as seen in the 4,000-bhp 

diesel-powered generator on Catalina Island. 

Cost Information: 

Based on vendor literature, self-sustained, gas-phase autocatalysis reduces emissions of NOx are reduced 

at costs as low as $1,000/ ton. 

Development Status: 

Commercially available 

As of August 2000, the system has been installed and is operating on several diesel generators in 

California. Based on commercial performance in these engines, NOxTech has been demonstrated as 

BACT for some diesel engines. 

Practical Considerations: 

The exhaust gas must be heated to achieve the temperatures necessary for the NOxTech system reactions. 

A heat exchanger should be placed downstream from the reactor to reclaim and reuse this heat energy. 

Compatibility with other air pollution control technologies: 

Compatible with low-NOx combustion approaches (LNB, combustion modification). Can be used to 

augment LEC. 

Secondary Environmental Impacts: 

Technology also potentially removes 60-80% of particulate matter, 90% of VOC, and 50-70% of carbon 

monoxide from the exhaust, as seen in the 4,000-bhp diesel-powered generator on Catalina Island. 

The process produces trace ammonia emissions of less than 2 to 5 ppmv. 
C-34 

Process: NOxTech

References: 

Edgerton, S. W., Lee-Greco, J., and Walsh, S. “Stationary Reciprocating Internal Combustion Engines 

Updated Information on NOx Emissions and Control Techniques (Final Report).” EPA contract No. 68-

D98-026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000. 

NOxTech Inc. “NOxTech® Technology.” website. www.noxtechinc.com/products.htm. 

NOxTech Inc. Letter and attachments from E. Cazzola to Mary Jo Krolewsky, U. S. EPA Acid Rain 

Division. April 12, 1999. 
C-35 

Process: Overfire Air (OFA)

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Coal-fired boilers 607,748 20-40% 250-600 Commercial 

Oil/NG boilers 32,910 40-80% 1,000-2,000 Commercial 

Wood/Biomass boilers 9,776 20-60% 200-2,000 

Process Description: 

OFA, like LNB’s, represents practical approaches to minimizing the formation of NOx during 

combustion. Simply, this is accomplished by "controlling" the quantities and the way in which fuel and 

air are introduced and mixed in the boiler (referred to as staging). 

In the case of OFA, the approach consists of diverting some of the combustion air (typically up to about 

30%) to dedicated injection nozzles (called OFA ports) located some distance above the burner or main 

combustion zone. Variations include the design and location of the OFA ports, the supply of air to the 

OFA (either directly from the windbox, or from a dedicated booster fan). 

NOx Reduction: 

OFA, which can be used separately or as a system with LNBs, is capable of NOx reductions of 20% - 40% 

from uncontrolled levels, when used alone. The type of boiler (e.g., dry vs. wet-bottom, wall- vs. 

tangential-fired, NSPS vs. pre-NSPS, etc.) and the type of fuel will influence the actual performance 

achieved. 

Cost Information: 

OFA technologies have little or no impact on operating costs (other than the potential for an increase in 

unburned carbon - efficiency loss -, and the resulting impact on ash disposal options). Retrofit costs are 

site-specific. As such, the economics of these technologies are driven by capital/retrofit costs which 

typically range from $5-$10/kW, with the lower range reflecting easier application whereas the higher 

costs are typically associated with more difficult and involved retrofits. 

 

From a schedule standpoint, OFA retrofit projects can require outages of 3 – 6 weeks, depending on 

factors such as scope of work, integration with other plant outage requirements, etc. 

Development Status: Commercial 

OFA and LNB’s are the most prevalent in the power industry at present. Plants that have had to comply 

with Title IV of the CAAA of 1992 have largely used these technologies for compliance. Competing 

manufacturers have proprietary designs, geared towards application in different boiler types, as well as 

reflecting their own design philosophies. 

Practical Considerations: 

Boilers with the following design and operating characteristics are expected to be more suitable 

candidates for OFA applications: 

• firing lower-sulfur fuels (e.g., less propensity for waterwall corrosion) 

• low baseline unburned carbon (e.g., to minimize ash salability impacts). 
C-36 

Process: Overfire Air (OFA)

• favorable cross-section/height profiles (e.g., tall boilers which provide for adequate 

mixing/residence time to maximize effectiveness). 

• units with existing burners in good operating condition, 

• Potential O&M impacts due to combustion NOx controls include: 

• Change in optimum excess air level: 0.5-1.5 percentage points increase in excess O2 is 

possible 

• 3-5 percentage points increase in LOI is possible; in general, as higher NOx reduction is 

being sought, the higher the probability for increased LOI (NOx vs. LOI trade-off) 

• Changes in reheat and superheat steam temperatures (typically lower by 20-50 degrees F) 

are possible in some applications. 

Compatibility with other air pollution control technologies: 

OFA technologies are often used in conjunction with LNB’s. As a main combustion based NOx control 

approach, OFA is fully compatible with other NOx controls including LNB’s, reburning (OFA is an 

integral component of reburning), as well as the post combustion technologies such as SNCR and SCR 

Secondary Environmental Impacts: 

OFA, like all combustion modification approaches face a common challenge: that of "striking a balance" 

between NOx reduction and fuel efficiency. The concern is exemplified by the typically higher carbon 

levels in the fly ash, which reflect lower combustion efficiency but also the contamination of the fly ash 

itself possibly making it unsuitable for reutilization (e.g., cement industry). 

References: 

EPRI, “Retrofit NOx Control Guidelines for Gas- and Oil-Fired Boilers”, Final Report, December 1993. 

EPRI, “Retrofit NOx Controls for Coal-Fired Utility Boilers – 1996 Update Addendum”, May 1997. 

EPRI, “Retrofit NOx Controls for Coal-Fired Utility Boilers – 2000 Update”, EPRI Final Report, 

December 2000 
C-37 

Process: Oxy-Fuel Firing

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

Glass Manufacturing 5,033 80-85% 2,150-4,400 Commercial 

Process Description: 

Oxy-fuel melting involves the replacement of the combustion air with oxygen (>90% purity). The 

technique can be used with either natural gas or oil as the fuel, although the use of gas is more common. 

The elimination of the majority of the nitrogen form the combustion atmosphere reduces the volume of 

the waste gases (composed mainly of CO2 and water vapor) by 70-85 % depending on oxygen purity. In 

general, oxy-fuel furnaces have the same basic design as recuperative melters, with multiple lateral 

burners and a single waste gas exhaust port. In the most modern furnaces the geometry is optimized for 

oxy-fuel firing and minimization. Furnaces designed for oxygen combustion do not currently utilize heat 

recovery systems to pre-heat the oxygen supply to the burners, due to safety concerns; however, the 

technique potentially involves substantial energy savings because it is not necessary to heat the 

atmospheric nitrogen to the temperature of the flames. The formation of thermal NOx is greatly reduced 

because the main source of nitrogen in the furnace is much lower. 

NOx Reduction: 

Compared to air-fuel fired furnaces, NOx emissions are generally reduced by 70-90%. This reduction 

equates to: 

• <1 kg/ton glass for fiber and container glass furnaces 

• 1-2 kg/ton glass for special glass (without nitrate addition) 

The latest versions of oxy-fuel burners combined with optimized furnace design and operation can in 

some cases reduce emissions to 0.3-0.8 kg NOx/ton of glass melted. No information is available for 

emissions from flat glass production, but emissions of 0.5 to 1.5 kg/ton of glass melted are considered 

likely. 

Cost Information: 

In general, capital costs for oxy-fuel firing are $1,930K-$9,810K. An important factor in the capital cost 

is that oxy-fuel furnaces do not have a conventional combustion gas preheat system and so the capital cost 

is generally lower than for a regenerative or recuperative furnace of comparable pull-rate. In most 

applications, the determining factor regarding cost effectiveness of oxy-fuel firing will be the difference 

between the energy savings and the costs of the oxygen compared with the costs of alternative NO

abatement techniques. 

Development Status: 

Commercially available 

It is estimated that 5-10% of the world’s glass production is made with oxy-fuel melting, but this figure 

varies between the sectors. There are several examples of oxy-fuel furnaces operating successfully in the 

following sectors: container glass, glass wool, special glass (particularly TV glass), continuous filament 

glass fiber, and frits. Trials have been carried out in the domestic glass sector resulting in good NOx

reduction, but problems occurred with severe foaming. The problems encountered in domestic glass 

production are similar to those initially encountered in other applications e.g. container glass. Similar 
C-38 

Process: Oxy-Fuel Firing

solutions are likely to be possible but the higher quality requirements make them more difficult to apply. 

There are several examples of the technique operating successfully for domestic glass production 

worldwide. Considerable development work is being undertaken and the number of plants and the level 

of operating experience are increasing. 

Practical Considerations: 

The merits of oxy-fuel firing vary greatly from case to case depending on furnace size and availability of 

pure oxygen. The technique is most effectively installed during furnace rebuild. Hot installation may 

lead to energy savings and to an increased pull rate; however, it is unlikely to result in lower NOx

emissions, and there is a danger of accelerated refractory wear. 

Furnace waste-gas temperature can be very high, 1200-1300 °C and will usually require cooling. Due to 

high water content and concentration of corrosive species, cooling is usually by dilution with air. The 

higher temperatures associated with the technique can result in higher refractory wear. 

Oxygen required for combustion can be supplied either by delivery to the site or by on-site production. 

Except for very small applications, the amounts of oxygen required usually make it more economical to 

produce the oxygen on-site. 

Compatibility with other air pollution control technologies: 

Addition of a cullet preheating system, which can also reduce NOx and other emissions by reducing the 

amount of fuel required, can add to the energy savings of oxy-fuel firing by recovering heat from the 

waste gases. See cullet preheating description. 

Secondary Environmental Impacts: 

Oxy-fuel firing can also help to reduce overall emissions of volatile materials form the furnace 

(particulates, fluorides, chlorides etc.), due to reduces gas flow over the melt and in some cases reduced 

turbulence. 

• Particulate emissions in soda-lime glass can be reduced to 0.2-0.3 kg/ton. 

• Particulate emissions most effectively reduced for boron containing glasses (up to 50%). 

• Reduction in fuel usage leads to lower SO2 emissions for oil-fired furnaces. 

Concentrations of all pollutants may actually be higher due to reduced gas volume, although the absolute 

emission is reduced. Dilution with cooling air usually brings the concentrations closer to more normal 

levels. 

References: 

European IPPC Bureau. “Reference Document on Best Available Techniques in the Glass 

Manufacturing Industry.” Seville, Spain, October, 2000. 
C-39 

Process: Oxygen-Enhanced Combustion Modifications

Category 

NOx, TPY 

(WRAP 

1996) 

%NOx

reduction Cost, $/ton Status 

Coal-fired Boilers 607,748 30 to 80% 1,000-2,000 Near Commercial 

Cement kilns 41,009 0-20% 100-1000 Commercial 

Process Description: 

In coal-fired boilers, O2 injection is used to improve effectiveness of OFA operation. Small amounts of 

oxygen are introduced into the burner zone through specially designed lances. The added O2 creates a 

local hot spot that increases the rate of coal volatile release, encourages more NOx reduction, and enables 

more fuel-rich operation where less NOx is formed. The technology has been demonstrated on a 44-MW 

coal-fired boiler. 

In cement kilns, oxygen lances are used to create a hot spot in the flame zone and achieve higher kiln 

throughput (increase clinker production). In doing so, NOx is not reduced but NOx emission rates (lb. 

NOx/ton of clinker) goes down in proportion to the increase in production. O2 injection achieves even 

higher production when cement kiln dust (CKD) is co-injected. The CKD also quenches peak flame 

temperature to achieve some reduction in thermal NOx formation. 

NOx Reduction: 

In the coal-fired boiler demonstration, conventional OFA reduced NOx to around 0.35 to 0.40 lb./MBtu. 

O2 injection lowered the NOx further to around 0.22 to 0.25 lb./MBtu, while also decreasing LOI and 

opacity, and allowing better steam temperature control when firing bituminous coal. NOx reductions 

down to 0.16-0.19 lb./MBtu were achieved when the unit switched to a blend of 90% sub-bituminous and 

10% bituminous coal. 

In the cement industry, oxygen injection has achieved 0 to 20% NOx reduction in conjunction with a 0-

5% kiln capacity increase. Increased capacity (when it occurs) is the primary cause of the NOx reduction. 

Cost Information: 

The primary cost of all these applications of oxygen-enhanced combustion is the cost of the oxygen. 

Oxygen required for combustion can be supplied either by delivery to the site or by on-site production. 

Except for very small applications, the amounts of oxygen required usually make it more economical to 

produce the oxygen on-site. Capital cost for oxygen storage and delivery systems range from $100,000 

when pipeline gas is used, to $1,500,000 when on-site storage is required. In general, capital costs are 

$1,930K-9,810K when on-site generation is chosen. 

An important factor for the capital cost of oxy-fuel firing is that oxy-fuel furnaces do not have a 

conventional combustion gas preheat system and so the capital cost is generally lower than for a 

regenerative or recuperative furnace of comparable pull-rate. In most applications, the determining factor 

regarding cost effectiveness of oxy-fuel firing will be the difference between the energy savings and the 

costs of the oxygen compared with the costs of alternative NOx abatement techniques. 
C-40 

Process: Oxygen-Enhanced Combustion Modifications

Development Status: 

The coal-fired boiler technology needs to be demonstrated over several months to show effectiveness, 

reliability, and safety. Such a demonstration is expected to begin during the summer of 2003. The 

technologies are commercially available for application to cement and glass manufacturing. 

Practical Considerations: 

Using oxygen enrichment results in less flue gas flow since it eliminates the nitrogen in the air it replaces. 

The merits of oxy-fuel firing vary greatly from case to case depending on furnace size and availability of 

pure oxygen. The technique is most effectively installed during furnace rebuild. Hot installation may 

lead to energy savings and to an increased pull rate; however, it is unlikely to result in lower NOx

emissions, and there is a danger of accelerated refractory wear. 

Furnace waste-gas temperature can be very high, 1200-1300 °C and will usually require cooling. Due to 

high water content and concentration of corrosive species, cooling is usually by dilution with air. The 

higher temperatures associated with the technique can result in higher refractory wear. 

Many potential users do not want to own and operate an air-separation plant. Oxygen suppliers offer to 

build, own, and operate the air separation system in return for a long term contract for oxygen sales. 

Compatibility with other air pollution control technologies: 

Oxygen-enhanced combustion on coal-fired boilers can only be effective when implemented with OFA. 

If O2 is added to an unstaged flame, NOx emissions will increase. The technology can also be combined 

with SNCR or SCR for greater NOx reductions. O2 can also be used with post-combustion NOx control 

technologies in cement kilns and glass melters. 

Secondary Environmental Impacts: 

Oxygen-enhanced combustion may lessen the impacts of staged combustion. The following are potential 

impacts that must be analyzed on an individual unit basis: 

• CO may increase due to stoichiometry in the burner zone 

• LOI may increase due to increased staging 

• ESP performance may degrade with increased LOI or finer particulate. 

Oxy-fuel firing can also help to reduce overall emissions of volatile materials from the kiln or furnace 

(particulates, fluorides, chlorides etc.), due to reduced gas flow and in some cases reduced turbulence. 

• Particulate emissions in soda-lime glass can be reduced to 0.2-0.3 kg/ton. 

• Particulate emissions most effectively reduced for boron containing glasses (up to 50%). 

• Reduction in fuel usage leads to lower SO2 emissions for oil-fired furnaces. 

Concentrations of all pollutants may actually be higher due to reduced gas volume, although the absolute 

emission is reduced. Dilution with cooling air usually brings the concentrations closer to more normal 

levels. 

References: 

U.S. Environmental Protection Agency, “Alternative Control Techniques Document: NOx Emissions from 
C-41 

Process: Oxygen-Enhanced Combustion Modifications

Utility Boilers”. EPA Document No. EPA-453/R-94-023, July 1994. 

 

Bool, L., “NOx Reduction from a 44MW Wall-Fired Boiler Utilizing Oxygen-enhanced Combustion”, 

EPRI/DOE/EPA Mega Symposium, Washington, May 2003 
C-42 

Process: Pre-Stratified Charge

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Reciprocating Engines 86,210 80-95% <500 Commercial 

Process Description: 

Air is injected into the intake manifold so that during the intake stroke, the piston initially draws in air, 

followed by a fuel-rich air-fuel mixture. Thus, the mixture near the spark plug is fuel rich, promoting 

good combustion, while the mixture away form the spark plug is very lean, acting a s a heat sink and 

suppressing NOx formation. 

NOx Reduction: 

From tests for ten engine models ranging from 100 to 800 bhp, NOx emissions ranged from about 0.1 

g/bhp-hr to 9.5 g/bhp-hr, with a mean of 0.6 g/bhp-hr. Engines ranging from 300 to 800 bhp averaged 

95% reduction, while tests on engines less than 50 bhp showed NOx reductions averaging 77%. 

Vendors guarantee the achievable NOx emission level of 2.0 g/bhp-hr. 

Cost Information: 

See EPA Report below. 

Development Status: 

Commercially available. In commercial use since 1980s. 

Practical Considerations: 

Applicable only to carbureted (i.e. non-fuel-injected) rich-burn engines. May cause some power derating; 

20% has been observed. While the PSC system itself requires very little maintenance, the engines require 

more frequent overall maintenance. 

Compatibility with other air pollution control technologies: 

Compatible with exhaust gas recirculation (EGR), with air injected by PSC system coming form the 

engine’s exhaust. May also be used in conjunction with post-combustion technologies. However, the 

overall NOx reductions are not strictly additive and careful evaluation is required to ensure cost effective 

strategies. 

Secondary Environmental Impacts: 

Possible increase in CO and VOC emissions. 

References: 

Edgerton, S. W., Lee-Greco, J., and Walsh, S. “Stationary Reciprocating Internal Combustion Engines 

Updated Information on NOx Emissions and Control Techniques (Final Report).” EPA contract No. 68-

D98-026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000.
C-43 

Process: SCONOx Technology

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Reciprocating Engines 86,210 95% Not available Commercial 

Oil/NG boilers 32,910 70-99% Not available Commercial 

Turbines 25,278 >90% >7,000 Commercial 

Process Description: 

The SCONOx system adds a chemical reactor for NOx sorption using a catalyst/sorbent to remove NOx, 

carbon monoxide, and VOC. NOx is oxidized in the presence of a platinum-based catalyst and the 

resulting NO2 is adsorbed onto a potassium carbonate sorbent, forming potassium nitrites. The sorbent 

must be regenerated periodically by passing a controlled mixture of regeneration gases across its surface 

in the absence of oxygen. Regeneration gases react with the nitrites to form water and elemental nitrogen. 

The system is installed as a bed of sorbent/catalyst. A system of louvers and piping allows portions of the 

bed to oxidize and adsorb pollutants and other portions of the bed to undergo regeneration. 

NOx Reduction: 

The first commercial installation in gas turbines achieved NOx emissions below 2 ppm, a reduction of 

over 90%. 

Vendor testing shows SCONOx reduced NOx emissions in natural gas-fired reciprocating engines up to 

95%. Preliminary testing in diesel engines found the technology reduced NOx by 98.9% to 0.4 g/bhp-hr. 

Cost Information: 

Cost for Gas Turbine application is preliminary and from DOE reference below. 

Development Status: 

Commercially available 

First commercial installations in gas turbines commenced in 1999. Commercial applications for natural 

gas-fired reciprocating engines went online in 2000. Diesel applications were sold in 2000, but further 

information is unavailable. 

Practical Considerations: 

The technology was initially applied only to gas turbines, but variations have been developed for naturalgas and diesel-fired reciprocating engines. 

Regeneration gas flow is about 1 percent of exhaust gas flow. Typically, natural gas is converted to 

hydrogen in a reformer at 600-900 °F to produce the regeneration gas. The regeneration step is 

complicated and the reformer requires additional labor and maintenance. 

Exhaust temperatures should be controlled at 600-700 °F for best NOx reduction. Performance also 

improves as exhaust gas oxygen levels approach zero. Temperature and O2 control may be difficult at 

some sites. The catalyst is de-activated by soot or sulfur species, so catalyst must be cleaned every 

20,000 hours. 
C-44 

Process: SCONOx Technology

SCOSOx is required to remove SO2, which would otherwise poison the SCONOx catalyst. SCOSOx 

requires regeneration similar to SCONOx. 

Compatibility with other air pollution control technologies: 

Due to the emerging nature of the technology, little is discussed about compatibility with other 

technologies. Based on tests with LEC engines, issues regarding increases in CO/VOC may be of concern 

Secondary Environmental Impacts: 

Carbon monoxide and VOC are also reduced up to 95%. 

References: 

Edgerton, S. W., Lee-Greco, J., and Walsh, S. “Stationary Reciprocating Internal Combustion Engines 

Updated Information on NOx Emissions and Control Techniques (Final Report).” EPA contract No. 68-

D98-026, EC/R Incorporated, Chapel Hill, NC, August 29, 2000. 

Amar, K.P., Staudt, J. “Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial 

Boilers, Internal Combustion Engines; Technologies and Cost Effectiveness.” Northeast States for 

Coordinated Air Use Management, Boston, MA, January, 2001. 

Goal Line Environmental Technology News. “Cummins Engine Co. Tests SCONOx® for Diesel IC 

Engines.” Oct 1999. Vol 1, Issue 3. 
C-45 

Process: Selective Catalytic Reduction (SCR)

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Coal-fired boilers 607,748 70-90% 1,500-2,000 Commercial 

Reciprocating Engines 86,210 75-90% <1,000 Commercial 

Oil/NG boilers 32,910 70-90% 2,000-10,000 Commercial 

Turbines 25,278 ~90% 500-10,000 Commercial 

Refinery Process Heaters 9,311 75-90% 3,700-11,000 Commercial 

Glass Melters 5,033 75-90% --- Commercial 

Process Description: 

Post-combustion NOx controls include Selective Non-Catalytic Reduction (SNCR) and Selective 

Catalytic Reduction (SCR). They are fundamentally similar, in that both use an ammonia-containing 

reagent to react with the NOx produced in the boiler, and convert it to harmless nitrogen and water, SNCR 

accomplishes this at higher temperatures (1700oF-2000oF) in the upper furnace region of the boiler, while 

SCR operates at lower temperatures (about 600oF to 750°F) and hence needs a catalyst to produce the 

desired reaction between ammonia and NOx. High temperature catalysts, sometimes used in gas turbine 

applications can operate at temperatures up to ~1100°F 

Conventional SCR incorporates a reactor located typically between the economizer and the air preheater. 

The reactor housing is sized to provide optimum flue gas velocity and catalyst volume. 

In about one-quarter to one-third of the German SCR installations, the SCR reactor is located downstream 

of the flue gas desulfurization (FGD) system. This is called a “tail-end” configuration. Because the 

catalyst operates at temperatures of at least 600+°F, the flue gas temperature needs to be increased 

between the FGD and tail-end SCR. This reheating the flue gas before it enters the SCR. This extra 

equipment makes the capital and energy costs higher than in a conventional SCR. On the other hand, the 

tail-end SCR uses less catalyst, experiences a longer catalyst life, and can be built without impacting plant 

operations, with tie-in typically occurring during a normal two-week outage. 

An ammonia injection system is located upstream of the catalyst typically in a grid configuration to inject 

and disperse the ammonia uniformly into the flue gas. 

NOx Reduction: 

NOx reductions of 90+% are capable with SCR. NOx reduction levels are typically limited by the need to 

control residual ammonia to low levels (2-5ppm), and by cost effectiveness considerations (higher costto-NOx reduction ratio for deeper reductions. SCR applications typically represent a balance between the 

percentage NOx reduction requirement, residual ammonia limit, SO2 to SO3 oxidation rate, and ability to 

continuously maintain a uniform, stable NH3/NOx distribution across the entry plane into the catalyst. 

Cost Information: 

Capital costs for retrofit SCR systems to power generation sources are mostly within the range of $60/kW 

to about $140/kW. The lower end of this range applies to retrofits with nominal difficulty. The high end 

of the range would typically be associated with retrofits having significantly impeded construction access, 

extensive relocations, and difficult ductwork transitions. 
C-46 

Process: Selective Catalytic Reduction (SCR)

Operating costs are mainly driven by cost of reagent, energy penalty (pressure loss, ammonia 

vaporization), catalyst replacement and dedicated O&M costs

Development Status: 

Commercially available

SCR is widely used oversees (Germany and Japan represent over 50,000 MW of installed capacity. In the 

US, significant activity has recently occurred with SCR installations on coal fired units. Projections for 

over 100 new installations in the US in the next 5 years have been made. 

Practical Considerations: 

From a technical perspective, SCR can be used many different applications and sources. However, the 

cost can vary considerably depending on retrofit difficulty and plant layout, fuel, or unit operating 

characteristics. 

The performance of an SCR system is dependent on the size and arrangement of the catalysts, the fuel 

burned, gas flow conditions at the catalyst entrance, and the type and amounts of reagent used. A number 

of factors should be considered when installing an SCR system. They include: 

• Operating temperature window temperature which is a function of the catalyst formulation but 

typically ranges between 600°-750°F for sulfur bearing fuels, 

• Ammonia injection system design to ensure good distribution in proportion to the mass flux of 

NOx for optimized performance (maximum NOx reduction and minimum NH3 slip) 

• Flue gas pressure drop which is dependent upon flue gas velocity, catalyst configuration, and 

quantity of catalyst required to achieve specified NOx reduction 

• Flue gas flow/temperature distribution, as catalyst guarantees are typically predicated upon 

predetermined conditions 

• Fouling potential of catalyst and/or APH surfaces. Reaction of excess ammonia with SO3

generated in the furnace when firing sulfur bearing fuels will form ammonium bisulfate/sulfate 

that deposits on the cold end sections of the air heater to cause corrosion and increased pressure 

drop 

• Flue gas contaminants - alkaline compounds, halogens, and heavy metals can cause catalyst 

poisoning. 

• Decreased heat rate at low load if economizer bypass is needed to maintain the required flue gas 

temperature in the SCR reactor. 

Compatibility with other air pollution control technologies: 

SCR applications are fully compatible with combustion NOx controls (LNBs, OFA, reburn, etc.) and can 

be used with other amine-based controls (e.g. SNCR) in hybrid configurations. In theory, most of these 

technologies can be used together. However, NOx reductions are not necessarily additive, and more 

importantly, the “economics” of the combined technologies may or may not be cost-effective. Such 

analyses are highly site- and strategy-specific. 

However, several such combinations of technology are considered attractive and have or are gaining 

acceptance. For example, the combination of LNB/OFA with either SCR or SNCR is more prevalent than 

the application of the post-combustion technologies alone. The economics of this approach are justified 

by the reduced chemical and capital costs due to lower NOx levels entering the SCR system. 

 
C-47 

Process: Selective Catalytic Reduction (SCR)

When combining SCR with NOx control technologies whose performance depends on mixing 

characteristics in the upper furnace (i.e., OFA, reburn, or SNCR), potential stratification of inlet NOx

levels to the SCR becomes a key design issue that can impact SCR performance. 

Secondary Environmental Impacts: 

Potential impacts arising from the application of SCR include: 

• Increased corrosion downstream of the SCR from SO3 formed on the catalysts 

• Air heater fouling due to ammonia bisulfate formation in the cold end 

• Ammonia contamination of fly ash affecting its salability or disposal 

• Increased system pressure drop 

• FGD waste management, if located downstream of SCR 

These impacts are mostly relevant to applications with sulfur and other contaminants-bearing fuels (e.g. 

coal/oil). Applications with natural gas are more benign both with respect to catalyst choice and life, as 

well as other plant impacts. 

References: 

EPRI, “Retrofit NOx Controls for Coal-Fired Utility Boilers – 2000 Update”, EPRI Final Report, 

December 2000 

NESCAUM, “Status Report on NOx Control Technologies and Cost Effectiveness for Utility Boilers”, 

June 1998. 

Cichanowicz, J., “100 GW of SCR: Installation Status and Implications of Operating Performance on 

Compliance Strategies”, EPRI/DOE/EPA Mega Symposium, Washington, May 2003 

McIlvaine, R., “SCR Operating Experience of German Power Plant Owners as Applied to Challenging 

US High Sulfur Service”, EPRI/DOE/EPA Mega Symposium, Washington, May 2003
C-48 

Process: Selective Non-Catalytic Reduction (SNCR)

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Coal-fired boilers 607,748 25-50% 800-1,500 Commercial 

Cement Kilns 41,009 30-70% 200-1,000 Commercial 

Oil/NG boilers 32,910 30-60% 1,300-3,000 Commercial 

Wood/Biomass boilers 9,776 40-80% 900-2,200 Commercial 

Refinery Process Heaters 9,311 50-70% 1,200-2,700 Commercial 

Glass Melters 5,033 ~40% --- Commercial 

Process Description: 

Post-combustion NOx controls include Selective Non-Catalytic Reduction (SNCR) and Selective 

Catalytic Reduction (SCR). They are fundamentally similar, in that both use an ammonia-containing 

reagent to react with the NOx produced in the boiler, and convert it to harmless nitrogen and water, SNCR 

accomplishes this at higher temperatures (1700oF-2100oF) in the upper furnace region of the boiler, while 

SCR operates at lower temperatures (about 600oF to 750°F) and hence needs a catalyst to produce the 

desired reaction between ammonia and NOx. 

While this difference between the two technologies may seem minor, it yields significant difference in 

performance and costs. This is because in the case of SNCR, the reaction occurs in a somewhat 

uncontrolled fashion (e.g., the existing upper furnace becomes the “reactor”). In practice, this means that 

SNCR has lower capital costs (no need for a reactor/catalyst); higher operating costs (lower efficiency 

means that more reagent is needed to accomplish a given reduction in NOx); and limited NOx reduction 

capability (typically 30%-40%, with some cases achieving reductions in the 50% range). 

With SNCR, the reagent is introduced directly into the upper furnace, within the temperature window 

above. Typical applications may include multiple injection nozzles at various elevations (temperature 

points). in the furnace to optimize the distribution of reagent as well as to allow for operation at various 

load points. 

NOx Reduction: 

SNCR technology is typically capable of NOx reductions in the range of 25% to 80% depending on many 

design and operating characteristics of the specific application. 

Cost Information: 

Capital cots range from $10 to $20/kW for power generation boilers. 

Operating costs are driven primarily by the consumption of the chemical reagent – usually urea for SNCR 

- which in turn is dependent upon the efficiency of the as well as the initial NOx level and the desired 

percent reduction. These are typically in the range of $500-$700/ton of NOx. 

An additional consideration important in the overall operating costs is the potential contamination of fly 

ash by ammonia making it potentially unsalable. 

Development Status: Commercial

SNCR is a fully commercial technology widely employed in various industries and applications. Ureabased applications are the predominant approach, as urea seems to have several advantages over ammonia 

in large-scale applications. 
C-49 

Process: Selective Non-Catalytic Reduction (SNCR)

Practical Considerations: 

SNCR applications must be considered on a site –specific basis as several design and operating 

characteristics will affect the suitability of the technology. Some key issues include 

• Available temperature window 

• Size (cross-section/height) of the furnace for appropriate distribution and mixing of the reagent 

• Sulfur content of the fuel (SO3 and NH3 form ammonium salts which can have negative impacts 

on the downstream equipment) 

• Operational profile of the unit (rapid swings in flows/temperatures often result in poor 

performance in terms of NOx reduction and ammonia slip) 

 

Compatibility with other air pollution control technologies: 

SNCR applications are compatible with combustion NOx controls (LNBs, OFA, reburn, etc.) and can be 

used with other amine-based controls (e.g. SCR) in hybrid configurations. In theory, most of these 

technologies can be used together. However, NOx reductions are not necessarily additive, and more 

importantly, the “economics” of the combined technologies may or may not be cost-effective. Such 

analyses are highly site- and strategy-specific. 

The application of SNCR with reburn has yielded several developments by different companies. Various 

approaches are available commercially. Essentially they all revolve around the ability to combine the 

injection the reburn fuel and the amine reagent in the upper furnace region. NOx reductions are not 

additive but better than the individual technology. While these combined approaches have not gained 

extensive commercial deployment reductions of 60%-70% have been reported. Economic effectiveness 

needs to be properly addressed on an individual basis as both the cost of reagent and reburn fuel 

contribute to the overall cost analyses 

Other variations of SNCR-based technology include the use of hydrocarbon injection to promote NH3

reduction reactions, as well as reagent injection into a fuel rich zone of the OFA system. These variations 

while offered commercially are still under demonstration 

Secondary Environmental Impacts: 

SNCR has some of the same issues associated with SCR. The two most likely to warrant consideration are 

• NH3 slip (emissions and impacts on ash) 

• Formation of nitrous oxide (N2O – a green house gas). This is mostly associated with urea, as 

opposed to ammonia, and may become a larger concern from the perspective of global climate 

issues 

 

References: 

NESCAUM, “Status Report on NOx Control Technologies and Cost Effectiveness for Utility Boilers”, 

June 1998. 

EPRI, “Retrofit NOx Controls for Coal-Fired Utility Boilers – 2000 Update, Final Report”, December 

2000. 

Himes, R., “A Fresh Look at SNCR”, EPRI/DOE/EPA Mega Symposium, Washington, May 2003 

EPRI, “Sate of the Art Assessment of SNCR Technology”, September 1993. 

EPRI, “SNCR Feasibility and Economic Evaluation Guidelines for Fossil-Fired Utility Boilers”, May 

1994
C-50 
C-51 

Process: Tempering (Water, air, steam injection)

Category 

NOx, TPY 

(WRAP 

1996>100 

TPY) 

%NOx

reduction Cost, $/ton Status 

Turbines 25,278 ~50% 2,000-7,000 Commercial 

Refinery Process Heaters 9,311 --- --- Commercial 

Process Description: 

Tempering is a combustion control using water, air, or steam to lower the combustion temperatures, 

which reduces thermal NOx formation. Water or steam, treated to quality levels comparable to boiler 

feedwater, is injected into the combustor and acts as a heat sink to lower flame temperatures. 

NOx Reduction: 

Controlled NOx emission levels range form 25 to 42 ppmv for natural gas fuel and from 42 to 75 ppmv 

for distillate oil fuel. 

Cost Information: 

Capital costs for wet injection include a mixed bed demineralizer and reverse-osmosis water treatment 

system and an injection system. All costs are based on availability of the injection medium on site. 

Capital costs range from $388K for a 4,430 hp turbine ($89/hp) to $4,830K for a 216,000 hp turbine 

($22/hp). For steam injection, capital costs are slightly higher than for water injection. 

Development Status: 

Commercially available 

Practical Considerations: 

This technique is available for all new turbine models and can be retrofitted to most existing installations. 

The decision of which injection medium to use for NOx reduction depends on many factors including the 

availability of steam injection nozzles and controls from the turbine manufacturer, the availability and 

cost of steam at the site, and turbine performance and maintenance impacts. This decision is usually 

driven by site-specific environmental and economic factors. 

Compatibility with other air pollution control technologies: 

None. 

Secondary Environmental Impacts: 

 

None expected. 

References: 

Alternative Control Techniques Document: NOx Emissions from Stationary Gas Turbines. EPA 

Document No. EPA-453/R-93-007, January 1993. 

U.S. Environmental Protection Agency. “Alternative Control Techniques Document – NOx Emissions 

form Stationary Reciprocating Internal Combustion Engines.” EPA-453/R-93-032, July, 1993. 
C-52 

Process: Tempering (Water, air, steam injection)

Poole, L., “Houston Galveston Area NOx Abatement Industries Perspective,” present at the Council of 

Industrial Boiler Owners, NOx Control XV Conference, Houston, TX, August 2002.
APPENDIX D: PM Control Technology Summaries 
D-1 

Process: Cyclones

Category 

PM, TPY 

(WRAP 1996 

>100 TPY) 

%PM 

reduction Cost Status 

Mineral Processing 24,499 50 – 90% See below Commercial 

Petrochemical 10,836 50 – 90% See below Commercial 

Wood/Biomass boilers 5,718 50 – 90% See below Commercial 

Primary metal production 4,697 50 – 90% See below Commercial 

Pulp & Paper 4,476 50 – 90% See below Commercial 

Process Description: 

Cyclones use centrifugal force to separate particulate from gas streams, and belong to the broader family 

of mechanical collectors, which use a variety of mechanical forces to collect particulate. A multiple 

cyclone is an array of a large number of small (several inch diameter) cyclones in parallel. 

PM Reduction: 

Multiple cyclones have overall mass removal efficiencies of 70-90%. However, cyclone collection 

efficiencies fall off rapidly with particle size, so that control of fine particulate (PM-2.5) is limited. While 

collection efficiency is a function of the cyclone design and particle properties, cyclone removal 

efficiencies will be 90% or greater for 10 micron particles, dropping to perhaps 70% for 2.5 micron 

particles, and 50% for 1 micron particles. Addition of a second multiple cyclone in series with the first 

will allow for increased removal efficiency. 

The efficiency of a cyclone increases with the gas flow rate through the cyclone. Cyclones are therefore 

most effective at high boilers loads, where flue gas flow rates are highest, with collection efficiency 

decreasing at lower loads. 

Cost Information: 

The following values represent typical costs for several of these technologies (these numbers reflect unit 

sizes ranging from utility-size units up to about 2,000,000 ACFM to smaller process down to about 

10,000 ACFM). 

• Capital - $1 - $5/ACFM 

• O&M - NA 

Development Status: 

Commercial.

Cyclones have been used extensively in various particulate collection applications over the years. In the 

past, industrial plants used mainly cyclones. Cyclones are robust technologies that can deal with the 

cyclic operation and load changes. However, their efficiency is moderate when compared with ESP or 

fabric filtration 

Practical Considerations: 

Cyclones are best suited for applications of relatively large particle sizes as their effectiveness on smaller 

particles is limited 

Cyclones are less expensive than other PM controls and have no costs beyond the initial capital cost. 
D-2 

Process: Cyclones

Multiple cyclones have no moving parts, but do require regular 

cleaning to avoid plugging, and preventive maintenance to avoid 

leaks, which can disrupt flow patterns and thus lower collection 

efficiency. 

Compatibility with other air pollution control technologies: 

Cyclones are compatible with other PM controls and may be desirable in selected applications to 

minimize PM loadings into downstream controls such as an ESP, FF or PM scrubber 

Secondary Environmental Impacts: 

None expected. 

References: 

http://www.icac.org

http://www.IEA-coal.org.UK/

http://www.croll.com
D-3 

Process: Electrostatic Precipitator (ESP)

Category 

PM, TPY 

(WRAP 1996 

>100 TPY) 

%PM 

reduction Cost Status 

Coal-fired boilers 46,010 90%-99+% See below Commercial 

Wood/Biomass boilers 5,718 90%-99+% See below Commercial 

Oil/NG boilers 1,379 90%-99+% See below Commercial 

Cement kilns 641 90%-99+% See below Commercial 

Process Description: 

ESP’s operate on the principle of electrophoresis, by imparting a charge to the particulates and collecting 

them on opposed charges plates. Dry vs. wet refers to whether the gas is water cooled and saturated prior 

to entering the charged plate area, or is collected dry on the plates. 

Electrostatic precipitators (ESPs), have been in use for particulate control since the early 1920’s, use 

electrical fields to remove particulate from boiler flue gas. 

In an electrostatic precipitator, an electric field is maintained between high-voltage discharge electrodes, 

typically wires or rigid frames, and grounded collecting electrodes, typically plates. A corona discharge 

from the discharge electrodes ionizes the gas passing through the precipitator, and gas ions subsequently 

ionize particulates. The electric fields impart electrostatic forces to the negatively charged particles, 

“driving” them to the collecting electrodes. Particulates are collected from the electrode plates either by 

mechanical rapping (Dry ESP) or by using a water spray to remove this particulate. (Wet ESP). 

In a typical electrostatic precipitator, collecting plates are arranged parallel to the gas flow, normally 9-18 

inches apart, with discharge electrodes between them. Most precipitators have 3-5 independent electrical 

sections, i.e., sets of discharge and collecting electrodes with independent power supplies called 

Transformer/Rectifier (TR) sets, in series. Each independent section removes a fraction of the particulate 

in the gas stream. This arrangement allows the use of lower power (higher voltages, but lower current) in 

the first sections of the precipitator, where there is more particulate to be removed. Higher power is 

needed in the later sections, to collect the smaller particles. 

A typical wet ESP configuration uses cylindrical collecting electrodes, with discharge electrodes located 

in the centers of the cylinders. Wet ESPs are useful in obtaining low opacities through the removal of acid 

gases and mists in addition to fine particulate. In addition, these devices have no rapping re-entrainment 

losses, and no back corona. 

PM Reduction: 

Many factors determine electrostatic precipitator removal efficiency. ESP size is an important one. Size 

determines residence time (longer particle residence times help collection efficiency) 

Precipitator size is related to and usually referred to as the specific collection area (SCA), the ratio of the 

surface area of the collection electrodes to the gas flow. Higher collection areas lead to better removal 

efficiencies. Collection areas normally are in the range of 200-800 ft2/1000 acfm. In order to achieve 

collection efficiencies of 99.5%, specific collection areas of 350-400 ft2/1000 acfm are typically used. 

Electrostatic precipitator collection efficiencies can exceed 99.9%, and efficiencies in excess of 99.5% are 

common. Precipitators with high overall collection efficiencies will have high collection efficiencies for 

particles of all sizes. Good control of PM-10 and PM-2.5 can be achieved with well-designed and 

operated electrostatic precipitators. 
D-4 

Process: Electrostatic Precipitator (ESP)

Precipitator collection efficiencies decreases for very small particles (less than 1 micron). The reason for 

lower efficiency for submicron particles is that both particle charge and the resistance of the gas to 

particle motion increase with particle size. As particles get smaller, the particle charge is lower, while the 

resistance to particle motion is higher resulting in poor collection. In practice this effect means that an 

ESP precipitator with a 99.9% overall mass collection efficiency may only collect over 90% of submicron 

particles, and over 97-98% of the 0 to 5 micron particles. 

Some older precipitators on utility boilers are small, with SCAs below 200 ft2/1000 acfm and 

correspondingly short treatment times. 

Cost Information: 

The following values represent typical costs for several of these technologies (these numbers reflect unit 

sizes ranging from utility-size units up to about 2,000,000 ACFM to smaller process down to about 

10,000 ACFM)) 

• Capital: $15 - $40/ACFM 

• Fixed O&M: Dry ESP’s - $0.25 - $0.65/yr-ACFM 

 Wet ESP’s - $0.15- $0.50/yr-ACFM 

• Variable O&M: Dry ESP’s - $0.45 - $0.60/yr-ACFM 

 Wet ESP’s - $0.25 - $0.50/yr-ACFM 

Development Status: 

Commercial 

ESP’s have been in use for over 75 years and are a widely recognized technology option for PM control 

Practical Considerations: 

Maximizing electric field strength will maximize precipitator collection efficiency. 

 

Other actors limiting precipitator performance include flow non-uniformity and particle re-entrainment. 

Uniform flow distribution helps ensure that there are no high gas velocity, short treatment time paths 

through the precipitator. 

Re-entrainment of collected particles may occur during rapping. Proper rapper design and timing will 

minimize rapper re-entrainment. Maintenance of appropriate hopper ash levels and of flow uniformity 

will minimize re-entrainment of ash from the hoppers. 

A major consideration of ESP collection efficiency is the electrical resistivity of the particles to be 

collected. Particles with resistivities in the range of 107

-1010 ohm-cm are more easily collected with ESPs: 

these particles are easy to charge, and loose their charge slowly once deposited on a collecting electrode. 

Particles with low resistivities (less than 107

 ohm-cm), on the other hand, loose their charge to a collecting 

electrode rapidly and tend not to adhere to the electrode, causing high re-entrainment losses. (Carbon 

black is an example of a low resistivity material). 

Particles with high resistivity (greater than 1010 ohm-cm) can be difficult to remove with a precipitator: 

such particles are not easily charged, and thus are not easily collected. High-resistivity particles also form 

ash layers with very high voltage gradients on the collecting electrodes. Electrical breakdowns in these 

ash layers lead to injection of positively charged ions into the space between the discharge and collecting 
D-5 

Process: Electrostatic Precipitator (ESP)

electrodes ("back corona"), thus reducing the charge on particles in this space and lowering collection 

efficiency. Fly ash from the combustion of low-sulfur coal typically has a high resistivity, and thus is 

difficult to collect. Flue gas treatment options exist to address both high and low resistivity problems and 

include the injection of ammonia, SO3 and other proprietary additives.

Compatibility with other air pollution control technologies: 

ESP’s are compatible with other PM controls and may be desirable in selected applications to minimize 

PM loadings into downstream controls such as a FF or PM scrubber 

Secondary Environmental Impacts: 

None expected. 

References: 

EPRI, “Economic Evaluation of Particulate Control Technologies”, Final Report, September 1992. 

Staehle, R., “The Past, Present and Future of Wet ESPs in Power plant Applications”, EPRI/DOE/EPA 

Mega Symposium, Washington, May 2003. 

IEA Coal Research, “Particulate control Handbook”, Final report, July 1997. 

IEA Coal Research, “Prevention of Particulate Emissions”, Final report, December 2000. 

ICAC, “ESPs vs. Fabric Filters: A Symposium and Debate”, March 1994. 

http://www.icac.org

http://www.IEA-coal.org.UK/

http://www.croll.com
D-6 

Process: Fabric Filter

Category 

PM, TPY 

(WRAP 1996 

>100 TPY) 

%PM 

reduction Cost, Status 

Coal-fired boilers 46,010 99+% See below Commercial 

Mineral Processing 24,499 99+% See below Commercial 

Wood/Biomass boilers 5,718 99+% See below Commercial 

Fugitive 5,631 99+% See below Commercial 

Oil/NG boilers 1,379 99+% See below Commercial 

Cement kilns 641 99+% See below Commercial 

Process Description: 

Fabric filter (FF) collectors (also referred to as baghouses) are the industrial equivalent of very large 

vacuum cleaners: by passing flue gas through a tightly woven fabric, particulate in the flue gas will be 

collected on the fabric by sieving and other mechanisms. The dust cake which forms on the filter from the 

collected particulate can contribute significantly to the overall collection efficiency. 

FF types are usually defined by the type of bag cleaning utilized. Major types include: (1) the “reverseair” baghouse, where the flue gas flows upward through the insides of vertical bags, which open 

downward. The fly ash thus collects on the insides of the bags, and the gas flow keeps the bags inflated. 

To clean the bags, a compartment of the FF is taken off-line, and the gas flow is reversed. This causes the 

bags to collapse, and collected dust to fall from the bags into hoppers. (Shaking or other method may be 

necessary to dislodge the dust from the bags.); and (2) the pulse-jet fabric filter, where the dirty gas flows 

from the outside of the bags inward, and the bags are mounted on cages to keep them from collapsing. 

Dust that collects on the outsides of the bags is removed by a reverse pulse of high-pressure air. This 

cleaning does not require isolation of the bags from the flue gas flow, and thus may be done on-line. 

PM Reduction: 

FF’s are capable of 99.9% removal efficiencies. In addition removal efficiency is relatively level across 

the particle size range, making FF’s good alternatives for very small particle sizes 

. 

Key performance factors include the fabric of the bag, the cleaning frequency and methods, and the 

particulate characteristics. Fabrics can be chosen for different applications, and some fabrics are 

specialty-coated for enhanced removal of submicron particulate. 

Cleaning intensity and frequency are also important variables in determining removal efficiency. Because 

the dust cake can provide a significant fraction of the fine particulate removal capability of a fabric, 

cleaning which is too frequent or too intense will lower the removal efficiency. On the other hand, if 

removal is too infrequent or too ineffective, then pressure drop will increase rapidly and impact overall 

operation. 

 
D-7 

Process: Fabric Filter

Cost Information: 

FF’s have been used extensively for many years in different industries. The power generation sector while 

predominantly dominated by ESP’s has started to utilize FF’s in the last 20 years. 

• Capital: Reverse Air Fabric Filter - $17 - $40/ACFM 

 Pulse Jet Fabric Filter - $12 - $40/ACFM 

• Fixed O&M: Reverse Air Fabric Filter - $0.35 - $0.75/yr-ACFM 

 Pulse Jet Fabric Filter - $0.50 - $0.90/yr-ACFM 

• Variable O&M: Reverse Air Fabric Filter - $0.70 - $0.80/yr-ACFM 

 Pulse Jet Fabric Filter - $.90 - $1.1/yr-ACFM 

Development Status: 

Commercial. 

FF’s have been used extensively for many years in different industries. The power generation sector while 

predominantly dominated by ESP’s has started to utilize FF’s in the last 20 years.

Practical Considerations: 

FF size is determined by the choice of air-to-cloth ratio (A/C), or the ratio of air flow to cloth area, 

typically expressed in feet per minute (cubic feet per minute of flow divided by square feet of fabric 

area). The selection of air-to-cloth ratio depends on the particulate loading and characteristics, and the 

cleaning method used. A high particulate loadings will require the use of a larger FF (lower A/C) in order 

to avoid forming too heavy a dust cake, resulting in an excessive pressure drop 

Pulse-jet FF’s are smaller (higher A/C) than reverse-air FFs due to the higher cleaning intensity and 

resulting bags being cleaner

Compatibility with other air pollution control technologies: 

FF’s are compatible with other PM controls. FF’s are also choices for applications downstream of dry 

SO2 controls (e.g. spray dryers) as well as in combination with sorbent injection techniques for SO2 

and/or Hg control 

Adding a FF downstream from an existing electrostatic precipitator is a strategy gaining some acceptance 

in the power industry. Because the ESP removes the bulk of the particulate, the baghouse can be 

relatively small, and thus less expensive. One commercial approach to this is the installation of a small 

pulse-jet fabric filter downstream of an ESP, known as a Compact Hybrid Particulate Collector 

(COHPAC). Physically, it may be separate from the precipitator, or even fully integrated into the last 

field of the existing ESP, further reducing the over cost and space requirements. 

Secondary Environmental Impacts: 

As mentioned above FF’s can represent a complementary option to sorbent injection technologies where 

they enhance the contact (reaction) times between the sorbent and the flue gas contaminant of interest. 

This results in enhanced collection efficiency for the pollutant (e.g. mercury), as well as reduced 

quantities of sorbent needed 

 
D-8 

Process: Fabric Filter

References: 

EPRI, “Economic Evaluation of Particulate Control Technologies”, Final Report, September 1992. 

Staehle, R., “Particulate Control Options for Dry FGD Systems”, EPRI/DOE/EPA Mega Symposium, 

Washington, May 2003. 

IEA Coal Research, “Particulate control Handbook”, Final report, July 1997. 

IEA Coal Research, “Prevention of Particulate Emissions”, Final report, December 2000. 

ICAC, “ESPs vs. Fabric Filters: A Symposium and Debate”, March 1994. 

http://www.icac.org

http://www.IEA-coal.org.UK/

http://www.croll.com
D-9 

Process: PM Scrubber

Category 

PM, TPY 

(WRAP 1996 

>100 TPY) 

%PM 

reduction Cost, Status 

Mineral Processing 24,499 50%-99+% See below Commercial 

Petrochemical 10,836 50%-99+% See below Commercial 

Wood/Biomass boilers 5,718 50%-99+% See below Commercial 

Primary Metal production 4,476 50%-99+% See below Commercial 

Pulp & Paper 4,476 50%-99+% See below Commercial 

Process Description: 

Scrubbers work on the principle of rapid mixing and impingement of the particulate with the 

liquid droplets and subsequent removal with the liquid waste. For particulate controls the 

“venturi scrubber” is an effective technology whose performance is directly related to the 

pressure loss across the venturi section of the scrubber. 

Venturi scrubbers are one type of the more commonly used “scrubbers” for particulate collection. As the 

name implies, the scrubbing liquid and flue gases accelerate through a converging section into a narrow 

throat. In the throat, very high gas velocity shears the scrubbing liquid into many very fine droplets, 

which collect particles through numerous “collisions”. 

PM Reduction: 

Scrubbers have varying PM reduction capabilities based on deign operating conditions and particle 

characteristics. Performance can range 50% for the small size fraction (< 2microns) to over 99% for the 

larger sizes. 

Higher collecting efficiencies and a wider range of particulate sizes, require higher operating pressures. . 

High-energy scrubbers refer to designs operating at pressure drop of 50-70 inches of water. Of course, 

higher pressure translates to higher energy consumption. 

Cost Information: 

The following values represent typical costs for several of these technologies (these numbers reflect unit 

sizes ranging from utility-size units up to about 2,000,000 ACFM to smaller process down to about 

10,000 ACFM) 

• Capital: Venturi Scrubber - $5 - $20/ACFM 

• Fixed O&M: Venturi Scrubber - $0.25 - $0.65/yr-ACFM 

• Variable O&M: Venturi Scrubber - $1.2 - $1.8/yr-ACFM 

Development Status: 

Commercial 

Wet scrubbers are widely used in various industries. One advantage of scrubbers is their ability to treat 

wet gases which are not conducive to other technologies such as dry ESPs and FFs. 

Practical Considerations: 

For applications where variation in flow require throat velocity compensation to maintain 

specified scrubbing efficiencies, automatic and manually variable throat designs are available. 
D-10 

Process: PM Scrubber

The automatic throat is used where flow conditions vary widely and frequent adjustments are 

required. When occasional variations occur, a manually controlled throat is generally sufficient. 

Compatibility with other air pollution control technologies: 

Scrubbers are compatible with other PM controls. However, dry ESP’s and FF’s would not be deployed 

downstream of a scrubber without prior reheating of the flue gas which would make such application 

economically questionable in general 

Secondary Environmental Impacts: 

Liquid waste disposal requires consideration on a case-by-case basis. 

Since scrubbers have the capability to reduce acid gases, applications where this is important must be 

considered. 

References: 

IEA Coal Research, “Particulate control Handbook”, Final report, July 1997. 

http://www.icac.org

http://www.IEA-coal.org.UK/

http://www.croll.com