Tài liệu Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options pdf

STAPPA

State and Territorial Air Pollution

Program Administrators

ALAPCO

Association of Local Air

Pollution Control Officials

March 2006

Controlling

Fine Particulate Matter

Under the Clean Air Act:

A Menu of Options

STAPPA

State and Territorial Air Pollution

Program Administrators

ALAPCO

Association of Local Air

Pollution Control Offi cials

March 2006

Controlling

Fine Particulate Matter

Under the Clean Air Act:

A Menu of Options

Acknowledgements i

Acknowledgements

On behalf of the State and Territorial Air Pollution

Program Administrators (STAPPA) and the Association

of Local Air Pollution Control Offi cials (ALAPCO),

we are pleased to provide Controlling Fine Particulate

Matter Under the Clean Air Act: A Menu of Options. Our

associations developed this document to assist states and

localities in determining the most effective ways to control

emissions of fi ne particles (PM2.5) and PM2.5 precursors

from sources in their areas. We hope that states and

localities fi nd this document useful as they prepare

their State Implementation Plans (SIPs) for attaining or

maintaining the PM2.5 standard.

STAPPA and ALAPCO express gratitude to M.J Bradley

& Associates, Inc. for its assistance in drafting this

document, in particular, Ann Berwick, Michael Bradley,

Tom Curry, Will Durbin, Dana Lowell and Chris Van

Atten. We thank Brock Nicholson (North Carolina) and

Lynne Liddington (Knox County, Tennessee), co-chairs

of the associations’ Criteria Pollutants Committee, under

whose guidance this document was prepared. We also

appreciate the efforts of the STAPPA and ALAPCO PM2.5

Menu of Options Review Workgroup, who helped shape

the options presented in this document. We thank Bill

Becker, Executive Director of STAPPA and ALAPCO, and

Amy Royden-Bloom, Senior Staff Associate of STAPPA

and ALAPCO, who oversaw the project. Finally, we

express our gratitude to EPA for providing the funding for

this project.

Once again, we believe that Controlling Fine Particulate

Matter Under the Clean Air Act: A Menu of Options

will serve as a useful and important resource for states

and localities as they develop approaches to regulate

emissions of PM2.5 and PM2.5 precursors and thank all who

contributed to its development.

Eddie Terrill John Paul

STAPPA President ALAPCO President

Contents iii

Contents

Introduction ........................................................................................................................................... 1

Chapter 1. The Highlights .................................................................................................................... 5

Chapter 2. Effects of Particulate Matter on Human Health and the Environment ....................... 16

Chapter 3. Fine Particulate Matter and Precursor Emissions ....................................................... 22

Chapter 4. The Clean Air Act ............................................................................................................. 32

Chapter 5. Boiler Technologies ........................................................................................................ 42

Chapter 6. Industrial and Commercial Boilers................................................................................. 60

Chapter 7. Electric Generating Units ................................................................................................ 86

Chapter 8. Pulp and Paper ............................................................................................................... 108

Chapter 9. Cement Manufacturing ................................................................................................. 120

Chapter 10. Iron and Steel ............................................................................................................... 136

Chapter 11. Petroleum Refi neries ................................................................................................... 158

iv Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Chapter 12. Diesel Engine Technologies ....................................................................................... 172

Chapter 13. Diesel Trucks and Buses............................................................................................. 188

Chapter 14. Nonroad Equipment ..................................................................................................... 202

Chapter 15. Light-Duty Cars and Trucks ........................................................................................ 216

Chapter 16. Airports ......................................................................................................................... 228

Chapter 17. Marine Ports ................................................................................................................. 238

Chapter 18. Residential Fuel Combustion and Electricity Use .................................................... 252

Chapter 19. Commercial Cooking ................................................................................................... 266

Chapter 20. Fugitive Dust ................................................................................................................ 274

About STAPPA and ALAPCO v

The State and Territorial Air Pollution Program

Administrators (STAPPA) and the Association of Local

Air Pollution Control Offi cials (ALAPCO) are the two

national associations of air quality offi cials in the states,

territories and major metropolitan areas throughout the

country. The members of STAPPA and ALAPCO have

primary responsibility for implementing our nation’s air

pollution control laws and regulations. The associations

serve to encourage the exchange of information and

experience among air pollution control offi cials; enhance

communication and cooperation among federal, state

About STAPPA and ALAPCO

and local regulatory agencies; and facilitate air pollution

control activities that will result in clean, healthful air

across the country. STAPPA and ALAPCO share joint

headquarters in Washington, DC.

For further information, contact STAPPA and ALAPCO at

444 North Capitol Street, NW, Suite 307, Washington, DC

20001 (telephone: 202-624-7864; fax: 202-624-7863; email

[email protected]) or visit our associations’ web site

at www.4cleanair.org.

Introduction 1

The State and Territorial Air Pollution Program

Administrators (STAPPA) and the Association of Local

Air Pollution Control Offi cials (ALAPCO) have prepared

Controlling Fine Particulate Matter Under the Clean Air

Act: A Menu of Options (PM2.5 Menu of Options) to assist

state and local air pollution control offi cials in evaluating

the options for reducing fi ne particulate matter (PM2.5) and

PM2.5-precursor emissions.

Areas throughout the eastern U.S. and California (and one

area in Montana) currently exceed EPA’s National Ambient

Air Quality Standards (NAAQS) for PM2.5, and states must

submit State Implementation Plans (SIPs) by April 2008

detailing their plans for achieving the national standards.

Meanwhile, the PM2.5 NAAQS are once again undergoing

the periodic review that §109(d)(1) of the Clean Air Act

requires take place at fi ve-year intervals. Under the terms

of a consent decree, EPA is to issue fi nal standards by

September 27, 2006. The Agency proposed new standards

on January 17, 2006.

EPA estimates that meeting the current PM2.5 standards

would avoid tens of thousands of premature deaths

annually and save hundreds of thousands of people from

signifi cant respiratory and cardiovascular disease. The

Agency further estimates that the monetized health

benefi ts of improvements in PM2.5 air quality exceed the

costs by a substantial margin.

PM2.5 is a complex pollutant with many sources

Introduction

contributing to the ambient air quality problem. As a

result, this PM2.5 Menu of Options addresses a broad

array of emission source categories, ranging from

household furnaces to petroleum refi neries. The challenge

confronting air quality offi cials is tremendous, as

evidenced by the sheer number of options that we identify

for improving air quality. But therein lie the opportunities,

as well.

Like STAPPA’s and ALAPCO’s previous document—

Controlling Particulate Matter Under the Clean Air

Act: A Menu of Options—this document compiles and

analyzes secondary information. It is intended to serve

as a general reference for a national audience, and it will

in no way substitute for a thorough analysis by state and

local agencies of local emissions sources and conditions,

using appropriate guidance from EPA and other available

information.

What To Regulate

The national focus of this report should not obscure an

absolutely central point: local choices about the sources

and pollutants to control will need to be informed by

highly local considerations. A particular source category

may account for a small share of national PM2.5 emissions,

but it may nonetheless dominate the local inventory.

The chemistry and physics of PM2.5 formation in the

atmosphere is incompletely understood. Some PM2.5 is

2 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

released directly to the atmosphere, and some forms from

emissions of sulfur dioxide (SO2) and nitrogen oxides

(NOx) (which are currently viewed as the most signifi cant

precursors and are the only ones addressed in this report).

Ammonia and volatile organic compounds (VOCs),

which are not included in this report, can also contribute

to ambient PM2.5. Direct PM2.5 emissions may be largely

responsible for one area’s nonattainment, while SO2

emissions may cause the problem elsewhere. The choice of

whether to focus on reducing direct PM2.5, SO2 or NOx—or

all of them, or ammonia or VOCs—will depend on local

source contributions and atmospheric chemistry.

There are further challenges for SIP writers. In a perfect

world, control-effi ciency and cost-effectiveness data would

be at hand; however, it is not consistently available. Of

course, even when information of this sort can be found, it

may not be applicable to all sources.

And another source of uncertainty complicates the job.

As we discuss in Chapter 3, Fine Particulate Matter and

Precursor Emissions, there are important distinctions

between fi lterable and condensable PM2.5. Further, some

methods used to measure PM emissions refl ect only the

fi lterable components and, to exacerbate the problem, the

fi lterable components vary depending on the test method

used. Although we discuss this issue in Chapter 3 in the

context of the national PM2.5 inventory, the distinction

between fi lterables and condensables also raises regulatory

and permitting issues.

The Authority to Regulate

Having decided what sources and pollutants need to

be controlled in order to address PM2.5 nonattainment,

regulators must then ascertain their authority to do so.

The Clean Air Act divides responsibility for various

types of air pollution sources and air pollutants between

the states and localities on the one hand and the federal

government on the other. Generally, state and local

regulators share responsibility with EPA for regulating

so-called “criteria” pollutants from stationary and area

sources (see Chapter 4, The Clean Air Act), with states and

localities assigned the lead role in addressing emissions

from these source categories.

States and localities are free under federal law to adopt

more stringent standards for stationary and area sources

than the Clean Air Act requires. However, some states

may be limited by state law or policy in whether they can

enact requirements that are more stringent than federal

standards. Here, we outline the possible approaches to

tightening federal standards that states and localities may

consider, and to developing standards where no federal

programs exist.

For states that have no latitude or little latitude beyond

what the Clean Air Act prescribes, the priority will be to

ensure strict compliance with the limits that the Act and

federal regulations impose on particulates and precursor

pollutants. In these states, the precise language of the

statutory limitation will inform the degree of regulatory

latitude. For example, regulators in at least some of these

states may not be able to set more stringent standards

for those sources that federal law or regulations actually

address, but in some of these states regulators may see

their way clear to setting standards for smaller sources

than those covered by federal requirements.

Moreover, there are no actual federal Reasonably Available

Control Technology (RACT) standards—EPA issues

only guidelines (and although the RACT standards are

intended to refl ect real-time advancements in technology,

many of the guidelines are seriously outdated). Since the

guidelines do not set actual limits, even state prohibitions

against enacting more stringent state standards may be

inapplicable.

States and localities that are not limited to the requirements

promulgated under federal law will want to look to the most

stringent standards that regulators in other jurisdictions

have imposed; we have identifi ed these throughout this

Menu of Options. State and local authority to impose

such limits derives from the federal requirement to attain

the NAAQS. The options for imposing more stringent

requirements than current federal regulations include the

following:

Under the state or local version of federal regulatory

air pollution programs, or through permit

determinations, adopt the most stringent standards

that appear to be feasible, even if they are more

stringent than federal rules impose; or apply the

federal or stricter standards to sources that are smaller

than those covered by the federal requirements.

Craft state or local regulatory programs or permits

that impose on sources the most stringent standards

that appear to be feasible. For example, this might

include the imposition of Best Available Control

Technology (BACT)-level standards on existing

sources, even in the absence of a modifi cation that

would trigger New Source Review (NSR).

Through regulations or permits, set limits on sulfur

levels in coal and oil for sources that burn these fuels.

For sources that are permitted to burn more than one

type of fuel, impose permit conditions that strictly

limit the extent to which they may burn the more

polluting fuel.

Consider the imposition of regulatory standards that

can be met by most, but not necessarily all, sources to

which the standard is applicable, with an opportunity

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Introduction 3

for sources to demonstrate that the standards

are technically infeasible in light of particular

circumstances.

Adopt a state-level cap-and-trade program or

participate in a regional trading program for a

particular source category or group of source

categories.

The discussion above applies to stationary and area

sources, but not to mobile sources, as to which all states

other than California have less leeway to impose their own

standards. For new vehicles, states are limited to federal

standards or to the more stringent standards that California

has adopted. For existing onroad vehicles, all states can

impose their own standards; although for existing nonroad

vehicles, they once again have only the choice of federal or

California standards.

However, by no stretch of the imagination does this mean

that states should overlook the possibilities for mobile

source strategies as a way of tackling PM2.5 nonattainment.

As we discuss in the chapters that follow, states have a

range of opportunities for addressing these sources.

Energy Effi ciency

The rising cost of fossil fuels has focused the nation’s

attention on the opportunities for reducing fuel

consumption, including energy effi ciency measures,

some of which are addressed in this report. For example,

Chapter 18, Residential Fuel Combustion and Electricity

Use, discusses several demand-side effi ciency measures.

However, other source categories surely present

opportunities for increased effi ciency that regulators

should not overlook.

On the supply side, energy effi ciency measures involve

increasing the effi ciency of the fuel combustion process or

of the way the fuel is utilized. At a conventional power

plant, two-thirds of the potential energy in the fuel burned

to produce electricity is inevitably lost to waste heat.

Meanwhile, facilities burn additional fuel to satisfy their

thermal needs (for hot water, space heating and the like).

Combined heat and power (CHP or cogeneration) facilities

located at or near a facility address this problem by

recovering the waste heat and putting it to productive use.

CHP systems can achieve overall effi ciencies of greater

than 80 percent (Elliott, 1999; EPA, 2000). In the late

1990s, 9 percent of this country’s electricity came from

cogeneration plants, although a number of other countries

garnered a much higher percentage: Denmark (40 percent),

Finland and the Netherlands (30 percent each), the Czech

Republic (18 percent), and Germany (15 percent) (Elliott,

1999).

A number of the industry sectors we profi le in this

•

report are candidates for cogeneration. The petroleum

refi ning and pulp and paper industries already employ

cogeneration to some degree, but the practice has room to

grow further in those industries and others, such as cement

manufacturing and iron and steel production (Elliott,

1999).

There are unquestionably disincentives to the development

of CHP in this country (e.g., high prices for excess power

that CHP projects sell to the grid, long tax depreciation

periods for CHP equipment), although increasing fuel

prices make cogeneration more attractive. Environmental

regulators can reverse some of the disincentives; for

example, by writing air pollution permits on an electricity

(and, where appropriate, thermal) output rather than on a

heat input basis, to encourage effi ciency in the use of fuel.

This Report

As indicated, this report addresses a broad range of source

categories. These sources do not represent the entire

inventory of PM2.5, SO2 and NOx emissions, although they

do cover a large share of the national inventory. Each

source category chapter provides an overview of the

category, background on the technical as opposed to the

policy options for reducing emissions, and an overview of

existing regulatory authority (with the regulatory authority

issues discussed up-front in the mobile source chapters

because of the preeminence of preemption considerations).

Each chapter concludes with a discussion of state and local

policy measures.

Additionally, the report has two separate technology

chapters—one on boiler and another on diesel engine

technologies. The boiler technology chapter informs the

industrial and commercial boiler and electric generating

unit chapters, as well as the chapters on other source

categories that burn process fuels (e.g., pulp and paper).

The chapter on diesel engine technologies is useful for

understanding the three mobile source chapters, as well

as substantial portions of the airport and marine port

chapters.

The report begins with the The Highlights of the source

category chapters. Although these do not substitute for

the detail provided in each chapter, they cull the most

signifi cant emissions reductions opportunities. Prior

to the sector-specifi c chapters, Chapter 2 discusses the

health effects of PM2.5, Chapter 3 discusses the national

emissions inventory, and Chapter 4 provides an overview

of the Clean Air Act.

References

Elliott, R. Neal, and M. Spurr, American Council for an

Energy-Effi cient Economy. Combined Heat and Power:

4 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

Capturing Wasted Energy, May 1999. http://www.aceee.

org/pubs/IE983.htm.

U.S. Environmental Protection Agency (EPA). Combined

Heat and Power, January 2000. http://yosemite.epa.gov/

oar/globalwarming.nsf/UniqueKeyLookup/SHSU5BPLD4/

$File/combinedheatandpower.pdf.

State and Territorial Air Pollution Program Administrators

and the Association of Local Air Pollution Control Offi cials

(STAPPA/ALAPCO). Restrictions on the Stringency

of State and Local Air Quality Programs: Results of a

Survey by the State and Territorial Air Pollution Program

Administrators (STAPPA) and the Association of Local

Air Pollution Control Offi cials (ALAPCO), December 17,

2002. http://www.4cleanair.org/stringency-report.pdf.

Chapter 1 - The Highlights 5

Introduction

The highlights that follow identify the most signifi cant

emissions reduction opportunities for fi ne particulate

matter (PM2.5) and PM2.5-precursors from each of the

industries addressed in the sector-specifi c chapters of this

report. We emphasize, however, that local considerations

need to inform local choices about the sources and

pollutants to control in order to address PM2.5 pollution

most effectively.

Additionally, almost all of the items we identify in The

Highlights fall within the purview of environmental

regulators. However, in certain instances we have included

strategies that would require action by other agencies or

branches of government, such as measures to reduce total

vehicle miles traveled. We have done so only when these

strategies are particularly effective.

Industrial and Commercial Boilers

Industrial and commercial boilers represent about 40

percent of all energy use in the industrial and commercial

sectors. Although most commercial boilers are small (less

than 10 million British thermal units per hour (MMBtu/

hr)), very large industrial boilers (greater than 250

MMBtu/hr) account for almost half of industrial boiler

capacity. However, in many fuel and size categories,

standards for PM, sulfur dioxide (SO2) and nitrogen

dioxides (NOx) emissions from industrial and commercial

boilers are less stringent than standards for the same

Chapter 1

The Highlights

pollutant emissions from electric generating unit (EGU)

boilers. Although there may be reasons in individual cases

why the most stringent EGU boiler limits are not feasible

for industrial and commercial boilers, those limits suggest

an appropriate starting point for consideration of limits for

industrial and commercial boilers larger than 250 MMBtu/

hr, and even for those larger than 100 MMBtu/hr.

Apart from the differences in EGU and industrial/

commercial boiler standards, there are enormous

disparities in terms of the stringency of various emissions

standards for PM, SO2 and NOx for industrial and

commercial boilers. These disparities suggest that there is

signifi cant room for improvement in the emissions profi le

of this source category. For example:

In certain industrial and commercial boiler categories

(e.g., new residual oil-fi red boilers between 10–100

MMBtu/hr, new and existing natural gas-fi red

boilers larger than 5 MMBtu/hr), state Best Available

Control Technology (BACT) determinations set

much tighter PM emissions limits than do the federal

Maximum Achievable Control Technology (MACT)

standards. For example, compare the BACT limit of

0.02 pounds per MMBtu (lb/MMBtu) to the MACT

standard of 0.03 lb/MMBtu for new residual oil￾fi red boilers between 10–100 MMBtu/hr; and the

BACT limit of 0.007 lb/MMBtu to the absence of any

MACT limit for new natural gas-fi red boilers larger

•

6 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

than 5 MMBtu/hr.

The same kind of disparity appears between the new

federal New Source Performance Standards (NSPS)

for SO2 emissions from industrial and commercial

boilers built after February 2005 and the NSPS

for SO2 from existing industrial and commercial

boilers. For example, the SO2 standard for new coal￾fi red boilers between 100–250 MMBtu/hr is 0.20

lb/MMBtu, compared to 1.2 lb/MMBtu for existing

units of that size. The SO2 standard for new residual

oil-fi red boilers greater than 100 MMBtu/hr is 0.32

lb/MMBtu, compared to 0.8 lb/MMBtu for existing

boilers. State and local regulators will want to

consider the feasibility of requiring existing sources

to meet these more stringent standards.

Although wood-fi red boilers constitute 4 percent of

industrial boiler capacity, they account for fully 20

percent of industrial boiler PM2.5 emissions. Average

uncontrolled PM2.5 emissions rates for wood-fi red

industrial boilers are higher than those of any fossil

fuel-fi red boilers. A recent BACT limit for PM for

an existing wood-fi red EGU boiler sets the same limit

as the MACT standard for PM emissions for new

wood-fi red industrial and commercial boilers (0.025

lb/MMBtu). This limit is approximately three times

more stringent than the MACT standard for PM from

existing wood-fi red boilers industrial and commercial

boilers (0.07 lb/MMBtu).

For industrial and commercial boilers burning

natural gas and residual oil, the San Joaquin Valley

Unifi ed Air Pollution Control District (UAPCD) has

set some of the most stringent NOx emissions limits

in the country. For example, it imposes a limit of

0.007 lb/MMBtu on natural gas-fi red boilers greater

than 5 MMBtu/hr, as compared to an NSPS of 0.3 lb/

MMBtu for natural gas-fi red boilers greater than 100

MMBtu/hr. Also, the San Joaquin Valley UAPCD

has NOx standards that apply to units as small as

0.075 MMBtu/hr, while the federal NSPS apply only

to units larger than 100 MMBtu/hr.

State and local agencies have other options for limiting

emissions from industrial and commercial boilers in

addition to setting emissions limits. For example,

Connecticut has set limits of 0.3 percent by weight on the

sulfur content of fuel oil used by power plants (with the

alternative of a 0.33 lb/MMBtu SO2 emissions rate), and

these limits could be applied to boilers in other industry

sectors. New York has set limits on the sulfur content of

both oil and coal used by power plants and other sources.

The limits vary by area within the state, with the lowest

limits in New York City: (1) 0.30 percent sulfur by weight

for residual oil, (2) 0.20 percent sulfur by weight for

distillate oil, and (3) 0.2 lb of sulfur per MMBtu gross heat

content for solid fuels.

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States should also consider supporting regional multi￾pollutant initiatives (aimed at SO2, NOx and mercury

emissions from EGUs and large industrial boilers), such

as the Clean Air Interstate Rule (CAIR)-Plus initiative of

the Ozone Transport Commission (OTC) and the regional

air quality initiative of the Lake Michigan Air Directors

Consortium (LADCO), discussed in the EGU Highlights

below.

Electric Generating Units

The electric power sector is one of the dominant sources

of PM2.5, SO2 and NOx emissions in the U.S. Within the

EGU sector, coal-fi red power plants account for the vast

majority of emissions. Nationwide, EGUs account for

almost 10 percent of the PM2.5 emissions, nearly 70 percent

of the SO2 emissions, and more than 20 percent of the NOx

emissions from all source categories. In 2002, coal-fi red

power plants were responsible for 92, 95 and 87 percent of

EGU emissions of PM2.5, SO2 and NOx, respectively.

The average emissions rates for SO2 and NOx across all

coal-fi red EGUs in the U.S. in 2002 were 0.94 lb/MMBtu

and 0.40 lb/MMBtu, respectively. To put these average

emissions rates in perspective, a typical baseload coal

plant would generate about 33,000 tons of SO2 and 14,000

tons of NOx annually at these rates.

There are many opportunities for states and localities to

regulate PM2.5 emissions and their precursors from EGUs

far more stringently than EPA’s CAIR. In fact, several

states have already passed laws or regulations aimed at

reducing EGU emissions beyond federal requirements.

Other states and localities may wish to adopt similar

programs. For example, New Hampshire law requires

EGUs to reduce their SO2 emissions 75 percent (based

on a rate of 3.0 pounds per megawatt-hour (lb/MWh)) by

December 2006, and their NOx emissions 70 percent (based

on a rate of 1.5 lb/MWh) by the same date. Massachusetts

regulations also limit coal plant SO2 emissions to roughly

0.3 lb/MMBtu and NOx emissions to roughly 0.15 lb/

MMBtu within the next few years, well in advance of the

second-phase CAIR caps. North Carolina law imposes

similar limits, although with a later effective date.

STAPPA and ALAPCO have conducted an analysis

identifying the emissions reductions that can be achieved

from EGUs by applying BACT. The Associations

concluded that EGUs could achieve emissions limits of

0.10 lb/MMBtu for SO2 and 0.07–0.08 lb/MMBtu for NOx.

States should also consider national and regional

approaches to achieving more stringent and expeditious

reductions than CAIR. STAPPA and ALAPCO’s strategy

calls for a national SO2 cap of 1.26–1.89 million tons per

year (as compared to a baseline of 10.6 million tons in

2001) by 2013, and a NOx cap of 0.88–1.26 million tons

Chapter 1 - The Highlights 7

per year by the same date (as compared to a baseline of 4.7

million tons in 2001).

Additionally, regional groups like the OTC and LADCO

are considering options that extend beyond CAIR and

could include large industrial boilers. The OTC is

evaluating a phased cap-and-trade program for SO2 and

NOx. In Phase 1, which would be implemented on January

1, 2009, the program would be based on an SO2 emissions

rate of 0.24 lb/MMBtu, and a NOx emissions rate of 0.12

lb/MMBtu. In Phase 2, which would be implemented

beginning January 1, 2012, the caps would be ratcheted

down based on an SO2 emissions rate of 0.14 lb/MMBtu

and a NOx emissions rate of 0.08 lb/MMBtu. The Midwest

Regional Planning Organization has been evaluating

similar reduction targets, including a Phase 2 SO2 cap

between 0.15 lb/MMBtu and 0.10 lb/MMBtu in 2013 and

a Phase 2 NOx cap between 0.10 lb/MMBtu and 0.07 lb/

MMBtu in 2013.

State and local agencies have other options for limiting

emissions from power plants in addition to setting

emissions limits. For example, as detailed in The

Highlights for industrial and commercial boilers,

Connecticut and New York have both set limits on the

sulfur content of fuel.

States should also consider options for promoting

renewable energy sources and energy-effi cient power

generation to meet future energy demands. The District

of Columbia and 21 states have adopted Renewable

Portfolio Standard (RPS) programs, requiring varying

amounts of renewables in their electricity supply. For

example, California requires 20 percent renewable

generation by 2017, New York requires 25 percent by

2013, and Pennsylvania requires 18 percent by 2020.

(These percentages are not exactly comparable, because

the states vary in the resources they defi ne as renewable.)

States have also established funding initiatives to promote

renewable energy projects. These programs can be an

important complement to the approaches recommended

above.

Pulp and Paper

The pulp and paper industry is divided into three

segments: pulp making, paper making and converting

operations. The pulp making process is the largest source

of emissions, accounting for over 75 percent of the sector’s

PM2.5, SO2 and NOx emissions. Over 80 percent of the

pulp mills in the U.S. use the kraft pulping process. There

are four primary sources of emissions from kraft pulping

operations: power boilers, recovery furnaces, lime kilns

and smelt dissolving tanks (SDTs).

Power boilers dominate the emissions from pulp mills.

The approaches discussed in Chapter 6, Industrial and

Commercial Boilers, and in The Highlights for those

sources, are equally applicable to power boilers used in the

kraft pulping process.

There are MACT standards for PM emissions from

recovery furnaces, lime kilns and SDTs. These standards

are 40 to 85 percent more stringent for new sources than

they are for existing sources. The MACT standards for

new sources limit PM emissions to 0.034 grams per dry

standard cubic meter (g/dscm) for recovery furnaces,

0.023 g/dscm for lime kilns and 0.06 kilograms per

megagram for SDTs. State and local regulators should

consider evaluating the feasibility of requiring existing

sources to meet these more stringent standards. For

example, upgrades to electrostatic precipitators (ESPs) and

replacement of wet scrubbers with ESPs can signifi cantly

reduce PM emissions. Older model ESPs on recovery

furnaces have collection effi ciencies close to 90 percent,

while newer model ESPs have collection effi ciencies

greater than 99 percent.

While there are federal standards for SO2 and NOx

emissions from power boilers at pulp and paper facilities,

there are no federal NSPS and MACT standards for SO2

or NOx emissions from other pulping emissions sources.

Although the options for reducing NOx emissions from

these sources are more limited, signifi cant reductions

in SO2 emissions from recovery furnaces and lime kilns

at kraft pulp mills are feasible. Some facilities have

successfully lowered SO2 emissions from recovery

furnaces by reducing the sulfur content of the process￾based fuels and by regulating temperatures in the furnace

to minimize SO2 formation. Where these techniques are

not practical or successful, facilities should consider using

a wet scrubber for SO2 control.

Much like a number of the other industry sectors we have

discussed, pulp and paper manufacturers are candidates

for facility-wide emissions caps for PM, SO2 and NOx,

on account of the number of their emissions sources

and potential reduction strategies. In fact, the MACT

standards for PM emissions from recovery furnaces, SDTs

and lime kilns already include the option of a facility-wide

emissions limit as an alternative to compliance with unit￾specifi c standards. If regulators pursue the cap approach

for all three pollutants, they should consider including

power boilers, in light of their contribution to the overall

emissions profi le of these facilities.

Cement Manufacturing

The largest source of emissions in cement manufacturing—

and the centerpiece of the process—is the kiln. Cement

kilns generate over 40 percent of the PM emissions and

more than 80 percent of both the SO2 and NOx emissions

associated with cement manufacturing.

8 Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options

More than 80 percent of the burners used to heat cement

kilns use coal, and the remainder use other fossil fuels or

waste materials combined with fossil fuels. A signifi cant

portion of the NOx emissions and the SO2 emissions

come from this fuel combustion, although raw material

composition also infl uences SO2 emissions signifi cantly.

PM emissions come from fuel combustion and from the

handling, grinding and storing of raw materials, clinker

and the fi nal product.

States and localities have signifi cant opportunities to

reduce SO2 and NOx emissions from cement operations,

especially in light of the fact that there are currently no

federal NSPS for this industry. Recent advancements in

selective non-catalytic reduction (SNCR) technology make

it suitable for use on cement kilns. Although there is only

one SNCR device currently installed at a cement plant in

the U.S., there are over 32 SNCR systems installed on kilns

in Germany and many more in the rest of Europe.

Recently approved permits in Florida have required the

installation of SNCR controls with low-NOx burners

(LNBs) and multi-staged combustion as BACT for NOx.

BACT determinations that include all three technologies

include NOx limits as low as 1.95 pounds per ton (lb/ton)

of clinker (30-day average). Recent BACT determinations

that do not include SNCR, but do include LNBs and multi￾staged combustion have NOx limits of 2.8–5.52 lb/ton of

clinker.

Sulfur levels in the fuel and raw materials heavily

infl uence SO2 emissions rates from cement kilns. Cement

kiln systems have highly alkaline internal environments

that can absorb up to 95 percent of potential SO2 emissions.

For this reason, even if they burn fuels that are relatively

high in sulfur, preheater/precalciner kilns can virtually

eliminate SO2 emissions. However, without the use of raw

materials that are low in sulfur, uncontrolled emissions

from preheater/precalciner kilns can be as high as 7.6 lb/

ton of clinker. By contrast, recent BACT determinations

have set SO2 limits ranging from 0.20 to 2.16 lb/ton of

clinker. In the absence of add-on controls, the use of low￾sulfur raw materials is essential for the control of SO2.

Where the process itself does not achieve satisfactory

SO2 emissions levels, wet fl ue gas desulfurization (FGD)

technology can provide an SO2 control effi ciency of

90–99 percent. Use of wet FGD systems in the cement

manufacturing process can be complicated by particle

build-up and clogging, but LADCO has concluded that

these problems are manageable if the FGD device is

installed downstream of an effi cient fabric fi lter. Of more

than 100 cement plants in the country, only fi ve currently

use wet scrubbers to control SO2, suggesting substantial

opportunities for the industry to improve its emissions

profi le. Dry FGD technology (not recommended for

wet kilns) and lime spray injection are other SO2 control

options, although they are less effective.

Federal NSPS and MACT standards limit particulate

emissions from cement manufacturing. Recently

promulgated MACT standards set PM limits for cement

kilns using hazardous waste as fuel. These standards are

substantially more stringent than the NSPS and MACT

standards for PM for fossil fuel-fi red cement kilns. State

and local regulators should require kilns that burn fuels

other than hazardous waste to meet the more stringent

standards, absent a showing that a particular plant cannot

achieve these levels.

Additionally, recent BACT determinations for PM and

particulate matter less than 10 micrometers (PM10) for

combined kiln and clinker cooler emissions are about a

quarter of the federal NSPS and MACT PM limits for

combined kiln and clinker cooler emissions for cement

facilities burning non-hazardous materials.

Almost all stages of the manufacturing process include

particle capture devices, most frequently fabric fi lters

or ESPs, each with control effi ciencies of 95–99 percent.

Control device collection effi ciencies can be improved by

rebuilding ESPs with a larger number of collection areas

and increased treatment times, and using fabric fi lters in

combination with ESPs.

Regulators should consider as a model the rules recently

promulgated by the South Coast Air Quality Management

District (AQMD) to control fugitive PM emissions

from cement manufacturing. Among other things, the

rules require the enclosure of many parts of the cement

manufacturing operation, and mandate the ventilation of

enclosed areas to a control system.

Iron and Steel

Coke making

Coke making involves the heating of coal in coke ovens at

high temperatures until all volatile components evaporate.

The best way to reduce emissions from coke making is

to reduce the amount of coke produced. Pulverized coal

or other fossil fuels may substitute for some portion of

the coke used in the blast furnace. Further, a number of

relatively new coke production processes reduce coking

emissions (e.g., using a non-recovery coke battery), and

technologies exist to produce iron and steel without using

coke at all.

In the production of coke, it is important to avoid large

temperature fl uctuations (thereby reducing damage to the

coke oven battery) and incomplete coking (which results

in “green pushes”), in order to minimize PM emissions.

Emissions should also be controlled by staged charging,

which involves introducing coal into the oven at a

Chapter 1 - The Highlights 9

controlled rate.

All quench towers should have baffl es that are cleaned

periodically, and clean water should be used for quenching.

Dry quenching is expensive, but is even more effective in

reducing emissions.

SO2 emissions can also be reduced by desulfurizing coke

oven gas before it is burned. Only 11 of the 16 byproduct

recovery coke plants do so, and state and local regulators

should consider requiring this. The U.S. Steel plant in

Allegheny County, Pennsylvania has managed to produce

coke oven gas with hydrogen sulfi de levels between 15-20

grains per 100 dry standard cubic feet.

Allegheny County stands at the forefront in a number

of other respects, and regulators elsewhere may wish to

consider its rules. Allegheny County sets instantaneous

limits for visible emissions from doors, charging, lids and

offtake systems, as well as for PM emissions from pushing

and combustion stacks. Because coking emissions

can be controlled to some degree by a careful program

of maintenance—e.g., door cleaning and rebuilding,

application of sealing material on coke oven doors—

workers are required to undergo extensive training.

Indiana has also set opacity limits for bypass heat

exchanger stacks and for pushing controls.

Iron making

The blast furnace converts iron ore into a more pure and

uniform iron. Casting, the main source of blast furnace

emissions, is the process of periodically removing molten

iron and slag from the furnace. About half of U.S. blast

furnaces control casthouse emissions with covered runners

and by evacuating emissions through capture hoods ducted

to a baghouse. The half of U.S. blast furnaces that do

not have these controls have opportunities for signifi cant

reductions.

Steel making

Most integrated mills use basic oxygen furnaces, or

BOFs, for the fi nal step of making iron into steel. The

oxygen blow portion of the furnace cycle, which involves

introducing oxygen into the furnace to refi ne the iron,

accounts for the largest share of emissions, followed

by tapping (pouring the molten steel into a ladle) and

charging (the addition of molten iron and metal scrap to

the furnace).

Primary emissions during oxygen blow periods are

typically controlled with an open hood directed to an

ESP or wet scrubber, or by a closed hood ducted to a wet

scrubber. According to EPA, fabric fi lters would provide

signifi cantly better PM control, but are not used at any

facility in the U.S. Upgrading old scrubbers to scrubbers

with a higher pressure drop and upgrading ESPs will also

reduce primary emissions.

About half of BOF shops rely on the primary collection

system to capture some of the fugitive emissions from

BOF operations. Regulators should consider requiring

the addition of secondary collection systems, which

would signifi cantly enhance the pollution control of these

furnaces.

Sinter plants

There are only fi ve sinter plants in the U.S. These plants

convert fi ne-sized raw material into an agglomerated

product (sinter) to be charged into a blast furnace.

Although all the plants operate sinter coolers to cool the

product prior to storage, only one has a control device. The

other four vent directly to the atmosphere. Requiring these

four to install control devices for their coolers represents

the most signifi cant emissions reduction opportunity for

sinter plants.

State and local agencies should also consider Indiana’s

regulations on the oil and grease content of sinter plant

feedstock.

Minimills

Minimills bypass the coke and iron making processes by

producing steel from metal scrap using electric arc furnace

(EAF) technology. All plants should be required to use a

baghouse to control primary emissions from scrap melting,

as well as hoods and baghouses to control emissions from

the ladle metallurgy process and from the argon oxygen

decarburization vessel.

All minimills control fugitive emissions from charging,

tapping and melting with baghouses, but ten plants are

subject to opacity limits for fugitive emissions that are

not as stringent as the NSPS. Regulators should consider

adopting opacity limits for these plants that are at least as

stringent as the NSPS requirements.

Petroleum Refi neries

Petroleum refi neries are complex facilities with numerous

sources of air pollution, including boilers, process heaters,

catalytic cracking units, internal combustion engines

and fl ares. Although no single control technology or

combination of controls will be applicable to all cases,

facilities have a wide range of opportunities for reducing

emissions.

Because of the large number of refi nery emissions sources

and potential reduction strategies, state and local agencies

should consider adopting facility-wide emissions standards

for refi nery combustion units, allowing sources to average