Supplementary Information for Four Factor 

Analyses by WRAP States

May 4, 2009 (Corrected 4/20/10)

Revised Draft Report 

Prepared by: 

William Battye 

Brad Nelson 

Janet Hou 

EC/R Incorporated 

501 Eastowne Drive, Suite 250 

Chapel Hill, North Carolina 27514 

Prepared for: 

Lee Gribovicz, Project Manager 

Western Regional Air Partnership (WRAP) and 

Western Governors’ Association (WGA) 

1600 Broadway, Suite 1700 

Denver, Colorado 80202
Scope of Document

This document provides an initial analysis of the four factors which must be 

considered in establishing a reasonable progress goal toward achieving natural 

visibility conditions in mandatory Class I areas. These factors were examined for 

several candidate control measures for priority pollutants and emission sources. 

The results of this report are intended to inform policymakers in setting 

reasonable progress goals for the Class I areas in the Western Regional Air 

Partnership (WRAP) region. 

This document does not address policy issues, set reasonable progress goals, or 

recommend a long-term strategy for regional haze. Separate documents will be 

prepared by the States which address the reasonable progress goals, each state's 

share of emission reductions, and coordinated emission control strategies. 

Disclaimer

The analysis described in this document has been funded by the Western 

Governors’ Association. It has been subject to review by the WGA and the 

WRAP. However, the report does not necessarily reflect the views of the 

sponsoring and participating organizations, and no official endorsement should be 

inferred.
iii

Contents

1. Introduction .......................................................................................................................................................... 1-1

2. Methodology......................................................................................................................................................... 2-1

2.1 Factor 1 – Costs.............................................................................................................................................. 2-1

2.2 Factor 2 – Time Necessary for Compliance.................................................................................................... 2-2

2.3 Factor 3 – Energy and Other Impacts............................................................................................................. 2-2

2.4 Factor 4 – Remaining Equipment Life............................................................................................................ 2-3

2.5 References for Section 2 ................................................................................................................................. 2-4

3. Reciprocating Internal Combustion Engines and Turbines ...................................................................................3-1

 3.1 Factor 1 – Costs...............................................................................................................................................3-3

 3.2 Factor 2 – Time Necessary for Compliance ....................................................................................................3-6

 3.3 Factor 3 – Energy and Other Impacts..............................................................................................................3-6

 3.4 Factor 4 – Remaining Equipment Life.............................................................................................................3-8

 3.5 References for Section 3..................................................................................................................................3-8

4. Oil and Natural Gas Exploration and Production Field Operations.......................................................................4-1

 4.1 Factor 1 – Costs...............................................................................................................................................4-7

 4.2 Factor 2 – Time Necessary for Compliance ....................................................................................................4-7

 4.3 Factor 3 – Energy and Other Impacts............................................................................................................4-10

 4.4 Factor 4 – Remaining Equipment Life...........................................................................................................4-13

 4.5 References for Section 4................................................................................................................................4-13

5. Natural Gas Processing Plants...............................................................................................................................5-1

 5.1 Factor 1 – Costs...............................................................................................................................................5-4

 5.2 Factor 2 – Time Necessary for Compliance ....................................................................................................5-5

 5.3 Factor 3 – Energy and Other Impacts..............................................................................................................5-5

 5.4 Factor 4 – Remaining Equipment Life.............................................................................................................5-8

 5.5 References for Section 5..................................................................................................................................5-8

6. Industrial Boilers ...................................................................................................................................................6-1

 6.1 Factor 1 – Costs...............................................................................................................................................6-8

 6.2 Factor 2 – Time Necessary for Compliance ....................................................................................................6-8

 6.3 Factor 3 – Energy and Other Impacts..............................................................................................................6-8

 6.4 Factor 4 – Remaining Equipment Life...........................................................................................................6-11

 6.5 References for Section 6................................................................................................................................6-12

7. Cement Manufacturing Plants ...............................................................................................................................7-1

 7.1 Factor 1 – Costs...............................................................................................................................................7-2

 7.2 Factor 2 – Time Necessary for Compliance ....................................................................................................7-2

 7.3 Factor 3 – Energy and Other Impacts..............................................................................................................7-7

 7.4 Factor 4 – Remaining Equipment Life.............................................................................................................7-7

 7.5 References for Section 7................................................................................................................................7-12

8. Sulfuric Acid Manuracturing Plants ......................................................................................................................8-1

 8.1 Factor 1 – Costs...............................................................................................................................................8-1

 8.2 Factor 2 – Time Necessary for Compliance ....................................................................................................8-5

 8.3 Factor 3 – Energy and Other Impacts..............................................................................................................8-5

 8.4 Factor 4 – Remaining Equipment Life.............................................................................................................8-5

 8.5 References for Section 8..................................................................................................................................8-7

9. Pulp and Paper Plant Lime Kilns...........................................................................................................................9-1

 9.1 Factor 1 – Costs...............................................................................................................................................9-1

 9.2 Factor 2 – Time Necessary for Compliance ....................................................................................................9-4

 9.3 Factor 3 – Energy and Other Impacts..............................................................................................................9-4

 9.4 Factor 4 – Remaining Equipment Life.............................................................................................................9-4

 9.5 References for Section 9..................................................................................................................................9-7
iv

10. Oil Refineries.....................................................................................................................................................10-1

 10.1 Factor 1 – Costs...........................................................................................................................................10-4

 10.2 Factor 2 – Time Necessary for Compliance.................................................................................................10-6

 10.3 Factor 3 – Energy and Other Impacts..........................................................................................................10-6

 10.4 Factor 4 – Remaining Equipment Life.........................................................................................................10-8

 10.5 References for Section 10............................................................................................................................10-9
v

Abbreviations

ACT Alternative Control Techniques

ALAPCO Association of Local Air Pollution Control Officials

BART Best Available Retrofit Technology

CAIR Clean Air Interstate Rule

CAA Clean Air Act

CO2 Carbon Dioxide 

EC Elemental Carbon

EDMS Emissions Data Management System

EGU Electric Generating Units 

EPA Environmental Protection Agency 

ESP Electrostatic Precipitator

FCC Fluid Catalytic Cracking 

FGR Flue Gas Recirculation

FF Fabric Filters 

H2S Hydrogen Sulfide

ICAC Institute of Clean Air Companies

ICI Industrial/Commercial/Institutional

LEC Low-Emission Combustion

LNB Low-NOx Burners

MRPO Midwest Regional Planning Organization

N2O5 Dinitrogen Pentoxide

NAAQS National Ambient Air Quality Standards

NACAA National Association of Clean Air Agencies

NEI National Emissions Inventory

NESCAUM Northeast States for Coordinated Air Use Management

NO Nitric Oxide

NO2 Nitrogen Dioxide

NOx Nitrogen Oxides

NSCR Nonselective Catalytic Reduction

NSPS New Source Performance Standards

OC Organic Carbon

OFA Overfire Air

PM Particulate Matter

PM10 Particulate Matter Particles of 10 Micrometers or Less

PM2.5 Particulate Matter Particles of 2.5 Micrometers or Less

PSD Prevention of Significant Deterioration

RPO Regional Planning Organizations

SCC Source Classification Codes

SCR Selective Catalytic Reduction

SIC Standard Industrial Classification

SNCR Selective Noncatalytic Reduction

SO2 Sulfur Dioxide
vi

STAPPA State and Territorial Air Pollution Program Administrators

ULNB Ultra-Low NOx Burners

VOC Volatile Organic Compounds

WRAP Western Regional Air Partnership

Units

acfm Actual Cubic Feet per Minute

cfm Cubic Feet per Minute

kWh Kilowatt Hour

MM-BTU/hr Million British Thermal Units per Hour

MW Megawatt

ppmv Parts per Million by Volume

scfm Standard Cubic Feet per Minute
1-1

1. Introduction

The Regional Haze Rule requires States to set reasonable progress goals toward meeting 

a national goal of natural visibility conditions in Class I areas by the year 2064. The first 

reasonable progress goals will be established for the planning period 2008 to 2018. The Western 

Regional Air Partnership (WRAP), along with its member states, tribal governments, and federal 

agencies, are working to address visibility impairment due to regional haze in Class I areas. The 

Regional Haze Rule identifies four factors which should be considered in evaluating potential 

emission control measures to meet visibility goals. These are as follows:

1. Cost of compliance

2. Time necessary for compliance

3. Energy and non-air quality environmental impacts of compliance

4. Remaining useful life of any existing source subject to such requirements

The purpose of this report is to analyze these factors for possible control strategies 

intended to improve visibility in the WRAP region. The following priority source categories of 

emissions are addressed:

1. Reciprocating internal combustion engines and turbines

2. Oil and natural gas exploration and production field operations

3. Natural gas processing plants

4. Industrial boilers

a. Coal- and oil- fired

i. By size category

Up to and including 200 million British Thermal Units (BTU) per hour 

Greater than 200 million BTU/hour

ii. By age category

Constructed prior to regulations for Prevention of Significant Deterioration 

(PSD) (before August 7, 1977)

After PSD regulations but before the Clean Air Act Amendments of 1990 

(August 7, 1977 through December 31, 1990)

After the Clean Air Act Amendments of 1990

b. Wood fired industrial boilers

c. Natural gas fired industrial boilers

5. Cement manufacturing plants

6. Sulfuric acid manufacturing plants

7. Pulp and paper plant lime kilns

8. Petroleum refineries
1-2

We have identified control measures for emissions of nitrogen oxides (NOX) and sulfur 

dioxide (SO2), which can react in the atmosphere to produce visibility-obscuring particulate 

matter on a regional scale, and also for direct emissions of particulate matter. For direct 

particulate matter emissions, we have evaluated the impacts of control measures on various 

particulate matter components, including PM2.5, PM10, elemental carbon (EC) particulate matter, 

and particulate organic carbon (OC). Data on emissions of volatile organic compounds (VOC) 

were also collected. In addition, although VOC emission control measures were not explicitly 

evaluated in this study, the impacts of NOX, SO2, and particulate matter controls on VOC were 

calculated where co-control benefits would occur.

It must be noted that the source category analyses in this report are general in nature. In 

developing their Regional Haze State Implementation Plans (SIPs), states will also draw on other 

category-specific analyses and source-specific analyses. 

This report is organized in 10 sections, including this introduction. Section 2 describes 

the methodology for the four factor analysis. The next 8 sections present the results of factor 

analyses for the priority emission source categories listed above. 
2-1

2. Methodology

The first step in the technical evaluation of control measures for a source category was to 

identify the major sources of emissions from the category. Emissions assessments were initially 

based on 2002 emissions inventory in the WRAP Emissions Data Management System

(EDMS),

1 which consists of data submitted by the WRAP states in 2004. The states then 

reviewed the emissions data and parameters from the EDMS used for this analysis and provided 

updated data when applicable. In some cases, detailed data on PM10 and PM2.5 emissions were 

not available from the WRAP inventory. Therefore, PM10 and PM2.5 data from the U.S. 

Environmental Protection Agency’s (EPA) 2002 National Emissions Inventory (NEI) were used 

to supplement the WRAP inventory where necessary.

Once the important emission sources were identified within a given emission source 

category, a list of potential additional control technologies was compiled from a variety of 

sources, including control techniques guidelines published by the EPA, emission control cost 

models such as AirControlNET2and CUECost,

3 Best Available Retrofit Technology (BART) 

analyses, White Papers prepared by the Midwest Regional Planning Organization (MRPO),

4

and 

a menu of control options developed by the National Association of Clean Air Agencies 

(NACAA).5The options for each source category were then narrowed to a set of technologies 

that would achieve the emission reduction target under consideration. The following sections 

discuss the methodology used to analyze each of the regional haze factors for the selected 

technologies.

2.1 Factor 1 – Costs

Control costs include both the capital costs associated with the purchase and installation 

of retrofit and new control systems, and the net annual costs (which are the annual reoccurring 

costs) associated with system operation. The basic components of total capital costs are direct 

capital costs, which includes purchased equipment and installation costs, and indirect capital 

expenses. Direct capital costs consist of such items as purchased equipment cost, 

instrumentation and process controls, ductwork and piping, electrical components, and structural 

and foundation costs. Labor costs associated with construction and installation are also included 

in this category. Indirect capital expenses are comprised of engineering and design costs, 

contractor fees, supervisory expenses, and startup and performance testing. Contingency costs, 

which represent such costs as construction delays, increased labor and equipment costs, and 

design modification, are an additional component of indirect capital expenses. Capital costs also 

include the cost of process modifications. Annual costs include amortized costs of capital 

investment, as well as costs of operating labor, utilities, and waste disposal. For fuel switching 

options, annual costs include the cost differential between the current fuel and the alternate fuel.
2-2

The U.S. EPA’s Guidance for Setting Reasonable Progress Goals under the Regional 

Haze Program (June 1, 2007) indicates that the four-factor analyses should conform to the 

methodologies given in the EPA Air Pollution Control Cost Manual.

6

This study draws on cost 

analyses which have followed the protocols set forth in the Cost Manual. Where possible, we 

have used the primary references for cost data. Cost estimates have been updated to 2007 dollars 

using the Marshall & Swift Equipment Cost Index or the Chemical Engineering Plant Cost 

Index, both of which are published in the journal, Chemical Engineering.

For Factor 1, results of the cost analysis are expressed in terms of total cost-effectiveness, 

in dollars per ton of emissions reduced. A relevant consideration in a cost-effectiveness 

calculation is the economic condition of the industry (or individual facility if the analysis is 

performed on that basis). Even though a given cost-effectiveness value may, in general, be 

considered “acceptable,” certain industries may find such a cost to be overly burdensome. This 

is particularly true for well-established industries with low profit margins. Industries with a poor 

economic condition may not be able to install controls to the same extent as more robust 

industries. A thorough economic review of the source categories selected for the factor analysis 

is beyond the scope of this project.

2.2 Factor 2 – Time Necessary for Compliance

For Factor 2, we evaluated the amount of time needed for full implementation of the 

different control strategies. The time for compliance was defined to include the time needed to 

develop and implement the regulations, as well as the time needed to install the necessary control 

equipment. The time required to install a retrofit control device includes time for capital 

procurement, device design, fabrication, and installation. The Factor 2 analysis also included the 

time required for staging the installation of multiple control devices at a given facility.

2.3 Factor 3 – Energy and Other Impacts

Table 2-1 summarizes the energy and environmental impacts analyzed under Factor 3. 

We evaluated the direct energy consumption of the emission control device, solid waste 

generated, wastewater discharged, acid deposition, nitrogen deposition, and climate impacts 

(e.g., generation and mitigation of greenhouse gas emissions).

In general, the data needed to estimate these energy and other non-air pollution impacts 

were obtained from the cost studies which were evaluated under Factor 1. These analyses 

generally quantify electricity requirements, steam requirements, increased fuel requirements, and 

other impacts as part of the analysis of annual operation and maintenance costs.

Costs of disposal of solid waste or otherwise complying with regulations associated with 

waste streams were included under the cost estimates developed under Factor 1, and were 

evaluated as to whether they could be cost-prohibitive or otherwise negatively affect the facility. 
2-3

Energy needs and non-air quality impacts of identified control technologies were aggregated to 

estimate the energy impacts for the specified industry sectors. However, indirect energy impacts 

were not considered, such as the different energy requirements to produce a given amount of coal 

versus the energy required to produce an equivalent amount of natural gas. 

Table 2-1 Summary of Energy and Environmental Impacts 

Evaluated Under Factor 3 

Energy Impacts

Electricity requirement for control equipment and associated fans

Steam required

Fuel required

Environmental Impacts

Waste generated

Wastewater generated

Additional carbon dioxide (CO2) produced

Reduced acid deposition

Reduced nitrogen deposition

Benefits from reductions in PM2.5 and ozone, where available

Impacts Not Included

Impacts of control measures on boiler efficiency

Energy required to produce lower sulfate fuels

Secondary environmental impacts to produce additional energy (except 

CO2) produced

2.4 Factor 4 – Remaining Equipment Life

Factor 4 accounts for the impact of the remaining equipment life on the cost of control. 

Such an impact will occur when the remaining expected life of a particular emission source is 

less than the lifetime of the pollution control device (such as a scrubber) that is being considered. 

In this case, the capital cost of the pollution control device can only be amortized for the 

remaining lifetime of the emission source. Thus, if a scrubber with a service life of 15 years is 

being evaluated for a boiler with an expected remaining life of 10 years, the shortened 

amortization schedule will increase the annual cost of the scrubber.
2-4

The ages of major pieces of equipment were determined where possible, and compared 

with the service life of pollution control equipment. The impact of a limited useful life on the 

amortization period for control equipment was then evaluated, along with the impact on 

annualized cost-effectiveness.

2.5 References for Section 2

1. WRAP (2008), Emissions Data Management System, Western Regional Air Partnership, 

Denver, CO, http://www.wrapedms.org/app_main_dashboard.asp.

2. E.H. Pechan & Associates (2005), AirControlNET, Version 4.1 - Documentation Report, 

U.S. EPA, RTP, NC, http://www.epa.gov/ttnecas1/AirControlNET.htm.

3. Coal Utility Environmental Cost (CUECost) Model Version 1.0, U.S. EPA, RTP, NC, 

http://www.epa.gov/ttn/catc/products.html.

4. MRPO (2006), Interim White Papers-- Midwest RPO Candidate Control Measures, 

Midwest Regional Planning Organization and Lake Michigan Air Directors Consortium, 

Des Plaines, IL, www.ladco.org/reports/control/white_papers/.

5. NACAA (formerly STAPPA and ALAPCO) (2006), Controlling Fine Particulate Matter

Under the Clean Air Act: A Menu of Options, National Association of Clean Air 

Agencies, www.4cleanair.org/ PM25Menu-Final.pdf.

6. EPA (2002), EPA Air Pollution Control Cost Manual, 6th ed., EPA/452/B-02-001, U.S. 

EPA, Office of Air Quality Planning and Standards, RTP, NC, Section 5 - SO2 and Acid 

Gas Controls, pp 1-30 through 1-42, http://www.epa.gov/ttncatc1/products.html#cccinfo.
3-1

3. Reciprocating Internal Combustion 

Engines and Turbines

Reciprocating engines and turbines at industrial, commercial, and institutional facilities in 

the WRAP region are estimated to emit about 274,000 tons of NOX per year, based on the 2002 

emissions inventory for the region.1 These sources are commonly grouped together under the 

general category of internal combustion engines. Most of the emissions from this category, 

about 247,000 tons per year, are from sources that are listed in the point source inventory; 

however, the area sources inventory also includes about 27,000 tons of NOX emissions from 

internal combustion engines. The area source emissions estimates are derived from industrial, 

commercial, and institutional fuel consumption in the WRAP states. NOX emissions from 

internal combustion engines represent about 23% of total point source emissions of NOX in the 

WRAP region, and about 19% of all stationary source (point and area source) NOX emissions in 

the region.

Table 3-1 shows estimated emissions of NOX, SO2, PM10, PM2.5 and VOC in the WRAP 

region, broken down by state, engine type, and fuel. The emissions estimates for NOX, SO2, and 

VOC were taken from the WRAP emissions data management system.1 Estimates for PM10 and 

PM2.5 were taken from the National Emissions Inventory (NEI). As the table shows, SO2, VOC 

and particulate matter emissions from reciprocating engines and turbines sources are much lower 

than NOX emissions. Emissions of OC and EC are not specifically quantified in either the 

WRAP inventory or the NEI, but can be estimated as a percentage of PM10 emissions using data 

from EPA’s SPECIATE database.2 EC and OC are estimated to comprise 78.8% and 18.5% of 

diesel PM10 emissions; and 38.4% and 24.7% of natural gas combustion PM10 emissions, 

respectively.

The point source emissions estimates in Table 3-1 include reciprocating engines and 

turbines used in oil and natural gas production and exploration operations, and at natural gas 

processing facilities. These emissions are included again in Chapters 3 and 4, which discuss 

control measures for these operations. 

Reciprocating engines account for about 64% of the NOX emissions from point sources in 

the internal combustion category, and turbines account for about 36%. The area source 

inventory does not differentiate between reciprocating engines and turbines, but reciprocating 

engines are expected to make up the bulk of area sources. Most of the turbines burn gaseous 

fuels, which include natural gas, liquefied petroleum gas, and industrial process gas. 

Reciprocating engines are divided between gaseous fuels and liquid fuels, such as kerosene and 

diesel oil. 

Emissions from individual diesel reciprocating engines range up to 850 tons of NOX per 

year, and natural gas fired reciprocating engine emissions range up to 1,370 tons of NOX per 

year. Individual diesel-fired turbines range up to 1,400 tons of NOX per year, and natural gas 

turbines range up to 877 tons NOX per year.1
AK AZ CA CO ID MT ND NM NV OR SD UT WA WY 

Point sources

Turbines ‐ gaseous fuel 44,293 3,593 11,832 4,233 697 321 524 9,433 4,088 2,028 372 1,302 1,267 2,1

Turbines ‐ liquid 4,446 15 411 90 3 0 0 109 9 0 3 48 0 

Reciprocating ‐ gas 50 2,979 10,114 18,628 1,715 2,511 3,861 41,962 84 348 0 3,097 875 1,2Reciprocating ‐ liquid 12,779 1,370 12,735 5,336 312 3,968 305 6,714 209 0 7 2,156 114 13,0

Area source (unspecified)

Natural gas 0 0 14,778 0 0 0 0 0 70 0 0 0 0 Kerosene 0 0 11,327 0 0 0 0 922 75 0 0 0 0 

Total 61,569 7,957 61,197 28,287 2,726 6,800 4,691 59,141 4,535 2,376 383 6,602 2,256 16,4

Point sources

Turbines ‐ gaseous fuel 705 31 352 143 7 9 20 20 20 31 11 22 85 

Turbines ‐ liquid 2,539 1 75 3 0 0 0 0 0 3 0 4 0 

Reciprocating ‐ gas 0 2 180 65 0 0 12 244 0 0 0 8 53 Reciprocating ‐ liquid 670 37 689 71 23 234 8 53 14 0 0 185 553 

Area source (unspecified)

Natural gas 0 0 12 0 0 0 0 0 0 0 0 0 0 Kerosene 0 0 708 0 0 0 0 84 0 0 0 0 0 

Total 3,915 71 2,016 281 31 243 40 402 34 35 11 219 691 Turbines ‐ gas 167 765 459 335 976 115 0 105 27 542 4 6 13 

Turbines ‐ liquid 140 1 88 10 0 0 0 4 5 0 0 2 2 

Reciprocating ‐ gas 0 25 232 294 25 0 25 158 0 1 0 27 10 Reciprocating ‐ liquid 179 14 436 42 201 56 2 64 135 1 0 26 1 

Total 486 806 1,215 681 1,202 171 27 330 167 544 4 61 26 

Turbines ‐ gas 66 665 450 242 966 36 0 53 25 129 3 5 11 

Turbines ‐ liquid 127 1 80 10 0 0 0 3 5 0 0 2 2 

Reciprocating ‐ gas 0 24 231 294 25 0 25 160 0 1 0 23 10 Reciprocating ‐ liquid 168 13 418 34 69 38 2 63 131 1 0 22 1 

Total 361 703 1,179 580 1,060 74 27 280 161 131 4 52 23 

Turbines ‐ gas 665 93 1,088 652 27 66 40 548 20 217 35 81 65 

Turbines ‐ liquid 2 0 33 6 0 0 0 2 70 0 0 5 0 

Reciprocating ‐ gas 1 133 1,884 3,440 53 88 106 2,326 1 26 0 90 83 4Reciprocating ‐ liquid 466 29 824 1,340 11 216 23 3,044 9 0 0 198 7 1,2

Total 1,133 256 3,829 5,439 90 370 169 5,920 100 242 36 375 156 1,7

Table 3-1. Emissions from Reciprocating Internal Combustion Engines and Turbines in the WRAP Region

NO X emissions in 2002 (tons/year)

SO 2 emissions in 2002 (tons/year)

PM 10 emissions in 2002 (tons/year)

PM 2.5 emissions in 2002 (tons/year)

VOC emissions in 2002 (tons/year)

Source: NOX, SO2, and VOC emissions were taken from the WRAP emissions data management system, and PM10 and PM2.5 emissions were taken from 
3-3

Table 3-2 lists potential control measures for NOX emissions from reciprocating engines 

and turbines. A number of options were identified for stationary reciprocating engines in an 

Alternative Control Techniques (ACT) guidance document written by the U.S. EPA in 1993, and 

in more recent analyses for New Source Performance Standards.

3,4

 Reciprocating engines can be 

designed to operate under rich fuel mixture, or lean fuel mixture conditions. Air-to-fuel-ratio 

adjustments and ignition retarding adjustments can be used to control emissions under either fuel 

mixture condition and for diesel or natural gas engines. This approach typically requires the 

installation of an electronic control system. In addition, fuel efficiency is generally reduced and 

emissions of soot may be increased. Low-Emission Combustion (LEC) retrofit technology can 

also reduce emissions from lean burn reciprocating engines by an average of 89%.5 LEC 

involves modifying the combustion system to achieve very lean combustion conditions (high airto-fuel ratios). EPA prepared an update to the ACT guidance for reciprocating engines in 2002 

which focused on LEC technology.

5

 Selective Catalytic Reduction (SCR) can also be used either 

alone or in conjunction with the above technologies to reduce NOX emissions from reciprocating 

engines or turbines by 90%.6 In addition, Non-Selective Catalytic Reduction (NSCR) can be 

used for rich-burn natural gas engines.4

A separate ACT guidance document identifies control options for particulate matter 

emissions from diesel engines.7 In addition, the WRAP sponsored a study of control options for 

engines used in the oil and gas industry.8 This study covered control measures for NOX, 

particulate matter, and VOC.

Another ACT guidance document analyzed control options for turbines using gaseous 

and liquid fuels. 9 Turbines can be retrofit with water or steam injection to reduce emissions by 

up to 80%. In addition, SCR can be used in conjunction with water or steam injection or lowNOX burner technology to reduce emissions by 93 to 96%. The ACT did not analyze retrofit 

installations or low-NOX burner technology for turbines, or impact of SCR used alone (without 

water or steam injection or low-NOX burner technology).

3.1 Factor 1 – Costs

Table 3-3 provides cost estimates for the emission control options which have been 

identified for reciprocating engines and turbines. For each option, the table gives an estimate of 

the capital cost to install the necessary equipment, and the total annual cost of control, including 

the amortized cost associated with the capital equipment cost. Retrofit costs were not available 

for low-NOX burners.

The capital and annual cost figures are expressed in terms of the cost per unit of engine 

size, where the engine size is expressed in horsepower for reciprocating engines and million 

British thermal units per hour (MM-Btu/hr) for turbines. The table shows a range of values for 

each cost figure, since the cost per unit of engine size will depend on the engine size and other 

factors. The lower ends of the cost ranges typically reflect larger engines, and the higher ends of 

the cost ranges typically reflect lower engine sizes. Table 3-3 also shows the estimated cost 

effectiveness for each control measure, in terms of the cost per ton of emission reduction. 
Source Type Control Technology

Pollutant

controlled

Baseline

emissions

(1000

tons/yr)

Estimated

control

effieiency (%)

Potential

emission

reduction

(1000

tons/year)

Refer‐

ences

Water or steam injection NOX 95 68 ‐ 80 65 ‐ 76 9

Low‐NOX burners NOX 95 68 ‐ 84 65 ‐ 80 9

SCR NOX 95 90 80 6,7,9

Water or steam injection with

SCR

NOX 95 93 ‐ 96 88 ‐ 91 9

Air‐fuel ratio adjustment NOX 105 10 ‐ 40 10 ‐ 42 3

Ignition retarding technologies NOX 105 15 ‐ 30 16 ‐ 31 3

Low‐emission combustion

(LEC) retrofit

NOX 105 80 ‐ 90 84 ‐ 94 5

SCR NOX 105 90 94 3,4,6

NOX a 90 ‐ 99 a 4

VOC a 40 ‐ 85 a 4

NOX 105 100 105 8

SO2 0.79 100 0.79

PM10 0.84 100 0.84

PM2.5 0.84 100 0.84

EC 0.32 100 0.32

OC 0.21 100 0.21

VOC 8.9 100 8.9

Overallb 115 116

Ignition timing retard NOX 76 15 ‐ 30 11 ‐ 23 3,8

EGR NOX 76 40 31 3,8

SCR NOX 76 80 ‐ 95 61 ‐ 73 3,4,6,8

NOX 76 87 67 8

PM10 1.4 85 1.2

PM2.5 1.1 85 0.9

EC 0.6 85 0.5

OC 0.5 85 0.4

VOC 7.5 87 6.6

Overallb 85 75

PM10 1.4 25 0.4 7,8

PM2.5 1.1 25 0.3

EC 0.6 25 0.2

OC 0.5 25 0.1

VOC 7.5 90 6.8

Overallb 9.0 7.2

Table 3-2. Control Options for Reciprocating Engines and Turbines

Turbines

b

For control measures reducing multiple pollutants, overall emissions and emission reductions reflect the sum of all

pollutants.  However, EC, OC, and PM2.5 are components of PM10, and therefore are not added separately to the totals.

Reciprocating

engines, gaseous

fuels

Replacement with electric

motors

Reciprocating

engines, diesel and

other liquid fuels

Diesel oxidation catalyst

Replacement of Tier 2 engines

with Tier 4

a

NSCR applies only to rich‐burn engines.  The distribution of emissions between rich‐burn and lean‐burn engines is not known.

NSCR
Source Type Control Technology

Pollutant

controlled

Estimated

control

efficiency (%)

Estimated

capital cost

($/unit)

Estimated

annual cost

($/year /unit) Units

Cost effectiveness

($/ton)

Refer‐

ences

Water or steam injection NOX 68 ‐ 80 4.4 ‐ 16 2 ‐ 5 1000 Btu 560 ‐ 3,100 9

Low‐NOX burnersa NOX 68 ‐ 84 8 ‐ 22 2.7 ‐ 8.5 1000 Btu 5,200 ‐ 16,200 9

SCR NOX 90 8 ‐ 22 2.7 ‐ 8.5 1000 Btu 2000 ‐ 10,000 6,7,9

Water or steam injection with

SCR

NOX 93 ‐ 96 13 ‐ 34 5.1 ‐ 13 1000 Btu 1,000 ‐ 6,700 9

Air‐fuel ratio adjustment NOX 10 ‐ 40 4.4 ‐ 43 13 ‐ 86 hp 320 ‐ 8,300 3

Ignition retarding technologies NOX 15 ‐ 30 na 10 ‐ 32 hp 310 ‐ 2,000 3LEC retrofit NOX 80 ‐ 90 120 ‐ 820 30 ‐ 210 hp 320 ‐ 2,500 5SCR NOX 90 20 ‐ 180 40 ‐ 461 hp 430 ‐ 4,900 3,4,6

NOX 90 ‐ 99 17 ‐ 35 3 ‐ 6 hp 16 ‐ 36 4

VOC 40 ‐ 85 1,500 ‐ 6,200 4

Overallc 16 ‐ 36

NOX 100 120 ‐ 140 38 ‐ 44 hp 100 ‐ 4,700 8

SO2 >13,000

PM10 >13,000

PM2.5 >13,000

EC >33,000

OC >50,000

VOC 1,000 ‐ 60,000

Overallc 90 ‐ 4,300

Ignition timing retard NOX 15 ‐ 30 16 ‐ 120 14 ‐ 66 hp 1,000 ‐ 2,200 3,8

EGR NOX 40 100 26 ‐ 67 hp 780 ‐ 2,000 3,8

SCR NOX 80 ‐ 95 100 ‐ 2,000 40 ‐ 1,200 hp 3,000 ‐ 7,700 3,4,6,8

NOX 87 125 20 hp 900 ‐ 2,400 8

PM10 85 25,000 ‐ 68,000

PM2.5 85 25,000 ‐ 68,000

EC 85 >50,000

OC 85 >50,000

VOC 87 22,000 ‐ 59,000

Overallc 840 ‐ 2,200

PM10 25 10 1.7 hp 1,400 7,8

PM2.5 25 1,400

EC 25 3,300

OC 25 4,200

VOC 90 350

Overallc 280

NSCRb

bNSCR applies only to rich‐burn engines. The distribution of emissions between rich‐burn and lean‐burn engines is not known.

cFor control measures reducing multiple pollutants, the overall cost‐effectiveness is the cost per total reduction of all pollutants. However, EC, OC, and PM2.5

are components of PM10, and therefore are not added separately to the emission reduction total.

Replacement of Tier 2 engines

with Tier 4Diesel oxidation catalyst

Table 3-3. Estimated Costs of Control Options for Reciprocating Engines and Turbines

TurbinesReciprocatingengines, gaseousfuels

Replacement with electric

motors

Reciprocatingengines, diesel

and other liquid

fuels

aCosts estimates for low‐NOX burners reflect the incremental costs of new low‐NOX burners versus standard burners. Retrofit costs for existing burners were

not available.
3-6

3.2 Factor 2 – Time Necessary for Compliance

Once a state decides to adopt a particular control strategy, up to 2 years will be needed to 

develop the necessary rules to implement the strategy. We have estimated that sources may then 

require up to a year to procure the necessary capital to purchase control equipment. The Institute 

of Clean Air Companies (ICAC) has estimated that approximately 13 months is required to 

design, fabricate, and install SCR or SNCR technology for NOX control.

10

 However, the time 

necessary will depend on the type and size of the unit being controlled. For instance, state 

regulators’ experience indicates that closer to 18 months is required to install this technology.11

Additional time up to 12 months may be required for staging the installation process if multiple 

sources are to be controlled at a single facility. Based on these figures, the total time required 

achieve emission reductions for reciprocating engines and turbines is estimated at a total of 51⁄2 

years.

3.3 Factor 3 – Energy and Other Impacts

Table 3-4 shows the estimated energy and non-air pollution impacts of control measures 

for reciprocating engines and turbines. In general, air-to-fuel-ratio adjustments and ignition 

retarding technologies have been found to increase fuel consumption by up to 5%, with a typical 

value of about 2.5%.12,13 This increased fuel consumption would result in increased CO2

emissions. LEC technology is not expected to increase fuel consumption; and may provide some 

fuel economy.12 

Diesel oxidation catalyst and diesel filtration technologies would produce an increase in 

fuel consumption in order to overcome the pressure drop through the catalyst bed and the filter. 

This is assumed to be roughly the same as the increase in fuel consumption for SCR installations, 

about 0.5%.12 In the case of diesel oxidation catalyst, the catalyst would have to be changed 

periodically, producing an increase in solid waste disposal.14 If diesel reciprocating engines are 

replaced with electric motors, there would be an increase in electricity demand, but this would be 

offset by the fuel consumption that would be avoided by replacing the engine. 

For turbines, water injection and steam injection would require electricity to operate 

pumps and ancillary equipment.14 Water injection would produce an increase in fuel 

consumption in order to evaporate the water, and steam injection would require energy to 

produce the steam. The increased electricity, steam, and fuel demands would produce additional 

CO2 emissions.

Installation of SCR on any type of engine would cause a small increase in fuel 

consumption, about 0.5%, in order to force the exhaust gas through the catalyst bed.12 This 

would produce an increase in CO2 emissions to generate the electricity. In addition, spent 

catalyst would have to be changed periodically, producing an increase in solid waste disposal.14
Source Type Control Technology

Pollutant

controlled

Electricity

requirement

(kW‐hr)

Steam

requirement

(tons steam)

Solid waste

produced

(tons waste)

Wastewater

produced

(1000 gallons)

Additiona

CO2 emitte

(tons)

Water or steam injection NOX 65 ‐ 76 a 31 8.1

Low‐NOX burners NOX 65 ‐ 80 aSCR NOX 80 a

Water or steam injection with

SCR

NOX 88 ‐ 91 0.45 0.026 1.7

Air‐fuel ratio controllers NOX 10 ‐ 42 a

Ignition retarding technologies NOX 16 ‐ 31 aLEC retrofit NOX 84 ‐ 94 aSCR NOX 94 0.5 0.008 0.43

NSCR NOX, VOC d 0.5 0.008 0.24

NOX 105 (100) 66,000 b

SO2 0.79

PM10 0.84

PM2.5 0.84

EC 0.32

OC 0.21

VOC 8.9

Overalle 116

Ignition timing retard NOX 11 ‐ 23 a

EGR NOX 31 2.7 2.0

SCR NOX 61 ‐ 73 0.5 0.008 0.38

NOX 67 c c

PM10 1.2

PM2.5 0.9

EC 0.5

OC 0.4

VOC 6.6

Overalle 75

PM10 0.4 0.5 b 316

PM2.5 0.3

EC 0.2

OC 0.1

VOC 6.8 2.5

Overalle 7.2 2.6d

NOTES:

Table 3-4. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Reciprocating Engines and 

Turbines

Potential

emission

reduction

(1000

tons/year)

Additional

fuel

requirement

(%)

Energy and non‐air pollution impacts (per ton of emission reduced)

aThe measure is expected to improve fuel efficiency.bCO2 from the generation of electricity would be offset by avoided emissions due to replacing the diesel engine

TurbinesReciprocatingengines, gaseousfuels

Replacement with electric

motors

Reciprocatingengines, diesel

and other liquid

fuels

eFor control measures reducing multiple pollutants, overall emissions and reflect the sum of all pollutants. However, EC, OC, and PM2.5 are components of PM10, and

therefore are not added separately to the totals. Impacts are expressed as the impact per ton of total polluants reduced.

Replacement of Tier 2 engines

with Tier 4

Diesel oxidation catalyst

dNSCR applies only to rich‐burn engines. The distribution of emissions between rich‐burn and lean‐burn engines is not known.cEPA has estimated that the control measures used to meet Tier 4 standards will be integrated into the engine design so that sacrifices in fuel economy will be negligible.

blank indicates no impact is expected.
3-8

3.4 Factor 4 – Remaining Equipment Life

Information was not available on the age of reciprocating engines and turbines in the 

WRAP region. However, engines in industrial service are often refurbished to extend their 

lifetimes. Therefore, the remaining lifetime of most reciprocating engines and turbines is 

expected to be longer than the projected lifetime of pollution control technologies which have 

been analyzed for this category. In the case of add-on technologies such as SCR, the projected 

lifetime is 15 years. 

If the remaining life of a reciprocating engine or turbine is less than the projected lifetime

of a pollution control device, then the capital cost of the control device would have to be 

amortized over a shorter period of time, corresponding to the remaining lifetime of the emission 

source. This would cause an increase in the amortized capital cost of the pollution control 

option, and a corresponding increase in the total annual cost of control. This increased cost can 

be quantified as follows:

where:

A1 = the annual cost of control for the shorter equipment lifetime ($)

A0 = the original annual cost estimate ($)

C = the capital cost of installing the control equipment ($)

r = the interest rate (0.07)

m = the expected remaining life of the emission source (years)

n = the projected lifetime of the pollution control equipment

3.5 References for Section 3

1. WRAP (2008), Emissions Data Management System, Western Regional Air Partnership, 

Denver, CO, http://www.wrapedms.org/app_main_dashboard.asp.

2. EPA (2006), SPECIATE version 4, U.S. EPA, RTP, NC,

http://www.epa.gov/ttn/chief/software/speciate/index.html.

3. EPA (1993), Alternative Control Techniques Document — NOX Emissions from 

Stationary Reciprocating Internal Combustion Engines, EPA-453/R-93-032, U.S. EPA, 

RTP, NC, Chapter 6.

4. Alpha-Gamma Technologies, Inc. (2006), Control Technologies for Internal Combustion 

Engines, Docket Number EPA-HQ-OAR-2005-0030-0054.

5 . Edgerton, Stephen, Judy Lee-Greco, and Stephanie Walsh (2002), Stationary 

Reciprocating Internal Combustion Engines – Updated Information on NOX Emissions 

and Control Techniques, U.S. EPA, RTP, NC.

6. NACAA (formerly STAPPA and ALAPCO) (2006), Controlling Fine Particulate Matter 

Under the Clean Air Act: A Menu of Options, National Association of Clean Air 

Agencies.
3-9

7. Nelson, Bradley (2009), Alternative Control Techniques Document: Stationary Diesel 

Engines, U.S. EPA, RTP, NC.

8. Bar-Ilan, Amnon, Ron Friesen, Alison Pollack, and Abigail Hoats (2007), WRAP Area 

Source Emissions Inventory Protection and Control Strategy Evaluation - Phase II, 

Western Governor's Association, Denver, Colorado, Chapter 4.

9. EPA (1993), Alternative Control Techniques Document — NOX Emissions from 

Stationary Gas Turbines, EPA-453/R-93-007, U.S. EPA, RTP, NC, Chapter 6.

10 . Institute of Clean Air Companies (2006), Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial Sources.

11 . Ghoreishi, Farrokh (2007), Time required to install add-on control measures for NOX,

Personal communication, Wisconsin Department of Natural Resources, April 2007.

12. Reference 3, Page 7-12.

13. Center for Alternative Fuels, Engines & Emissions (2005), Alice Austen Ferry Emissions 

Tests, M.J. Bradley & Associates, Manchester, NH, Page 13.

14. EPA (2002), EPA Air Pollution Control Cost Manual, 6th ed., EPA/452/B-02-001, U.S. 

EPA, Office of Air Quality Planning and Standards, RTP, NC.
4-1

4. Oil and Gas Exploration and 

Production Field Operations 

The WRAP region is an important domestic source of crude oil and natural gas. Many of 

the WRAP states have active production fields for oil and natural gas; and exploration operations 

are also underway to identify additional reserves. Both the production and exploration industries 

involve a number of operations which emit NOX, SO2, particulate matter and VOC. Turbines are 

used to drive compressors and other equipment, and diesel engines are used in a variety of 

applications. Flares and incinerators are used to dispose of waste gases, and process heaters are 

used in various operations. In addition, emissions emanate from various gas treatment 

operations, such as glycol dehydrators and amine treatment units. 

Table 4-1 summarizes emissions from the industry, broken down by state and by the 

various emission sources. Point source emissions of NOX, SO2, and VOC from these operations 

were extracted from the 2002 WRAP emissions inventory, which catalogs emission sources by 

their Standard Industrial Classification (SIC).1 SIC 131 covers crude petroleum and natural gas 

production, and SIC 138 covers oil and gas field exploration services. Estimates for PM10 and 

PM2.5 were extracted from the 2002 National Emissions Inventory (NEI), which also classifies 

emissions by SIC. It must be noted that the point source emissions in Table 4-1 for reciprocating 

engines and turbines in the oil and gas production and exploration sector are also included in the 

emission totals reported in Table 3-1 (for all reciprocating engines and turbines). However, the 

point source inventories do not include small engines such as oil well motors and gas well 

engines. Emissions for these sources have been estimated by the WRAP in a separate oil and gas 

industry study,2and these estimates are also included in Table 4-1.

Based on the inventory emissions estimates, NOX emissions are the predominant regional 

haze precursor emissions in oil and gas exploration and production operations. Overall NOX

emissions from these operations are estimated at about 294,000 tons/year, which represent about 

20% of stationary source (point and area source) NOX emissions in the region. These result from 

combustion processes in engines, turbines, heaters, incinerators, and flares. It should be noted 

that emissions from point source engines and turbines, about 166,000 tons/year, also fall into the 

reciprocating engines and turbines category discussed in Chapter 3. However, according to an 

analysis of oil and gas emission sources sponsored by the WRAP, emissions estimates from 

small engines at oil and gas operations are not believed to be included in the area source 

inventory internal combustion estimates.

2

 

Most turbines at oil and gas production and exploration operations are fired by natural 

gas. Emissions from individual natural gas turbines at production operations range up to about 

877 tons of NOX per year, which is comparable to natural gas turbines at industrial facilities. 

Emissions from individual natural gas turbines at exploration operations range up to 131 tons of 

NOX per year. Natural gas reciprocating engines at oil and gas production and exploration 

operations are somewhat smaller than natural gas reciprocating engines at industrial facilities. 

NOX emissions from individual gas reciprocating engines range up to 700 tons per year for oil
AK AZ CA CO ID MT ND NM NV OR SD UT WY Tribes Total

Recip. Engines (mostly gas) 4,208 642 8,050 24,525 2,590 3,996 4,838 52,219 83 1,182 323 2,983 12,272 1,127 119,519

Turbines, gas 40,987 2,490 571 0 0 345 0 66 956 630 46,044

Process heaters 935 1,518 100 4 84 339 0 12 92 1 3,085

Flares 361 72 17 0 164 48 0 12 95 2 772

Oil well motors 0 0 9 42 75 329 1 3 31 111 601

Compressor engines 8 3,271 1,791 2,920 35,140 33 73 284 843 1,791 46,154

Other gas well engines 9 9 8,070 15,946 4,678 101 14,602 4 12 44 2,127 6,398 52,000

Coal methane pumps 1,489 92 1,428 3,009

Recip. Engines (mostly gas) 235 268 123 0 0 3,447 0 0 195 0 4,269

Turbines, gas 0 0 0 0 0 890 0 0 0 0 890

Other 64 128 93 0 0 187 0 18 182 2 673

Non-point 

engines

Drill rig motors 877 2,803 1,046 1,536 5,476 24 29 334 4,997 17,122

Total 47,677 659 20,597 48,947 2,590 11,557 9,718 113,113 145 1,267 683 6,426 28,517 1,762 293,658

Incinerators 0 17 0 0 199 0 0 1,420 7,404 0 9,041

Flares 38 158 3 2 77 3,822 0 33 4,318 48 8,499

Sulfur recovery units 0 0 0 0 283 820 0 0 1,284 0 2,387

Process heaters (gas) 92 730 1 0 0 69 0 0 0 3 896

Turbines, gas 704 57 1 0 0 0 0 1 0 10 773

Recip. Engines (mostly gas) 17 43 35 0 11 0 0 0 0 196 302

Other 8 95 55 0 0 36 0 0 2 1 197

Exploration Non-point 

engines

Drill rig motors 66 118 225 358 244 1 6 17 150 1,185

Total 926 1,099 212 227 929 4,992 1 6 1,472 13,159 258 23,280

Process heaters, gas 50 0 268 7 0 0 0 12 0 0 0 0 2 0 339

Recip. Engines (mostly gas) 0 11 189 0 0 3 0 3 5 0 211

Turbines, gas 144 36 13 0 0 1 0 0 0 0 194

Other 107 0 70 14 0 0 0 14 0 0 0 3 1 0 209

Table 4-1. Emissions from Oil and Gas Production and Exploration in the WRAP Region

PM 10 emissions (tons/year)

Point 

sources

Other 

engines

Point 

sources

Point 

sources

NO X emissions (tons/year)

Point 

sources

Emission source

 Production

SO 2 emissions (tons/year)

 Production

Exploration

Production
AK AZ CA CO ID MT ND NM NV OR SD UT WY Tribes Total

Table 4-1. Emissions from Oil and Gas Production and Exploration in the WRAP Region

Emission source

Exploration Point 

sources

General 0 0 10 2 0 0 0 7 0 0 0 0 0 0 19

Total 301 0 395 224 0 0 0 37 0 0 0 6 8 0 972

Process heaters, gas 44 268 7 0 0 12 0 0 2 0 333

Recip. Engines (mostly gas) 0 11 189 0 0 3 0 1 5 0 209

Turbines - natural gas 60 34 12 0 0 1 0 0 0 0 108

Other 65 0 69 13 0 0 0 12 0 0 0 2 1 0 162

Exploration Point 

sources

General 0 0 10 1 0 0 0 7 0 0 0 0 0 0 18

Total 169 0 392 222 0 0 0 35 0 0 0 4 8 0 830

Recip. Engines (mostly gas) 209 647 3,697 28 55 670 0 96 294 213 5,908

Fugitive emissions 0 1,302 1,079 6 0 125 3 75 747 50 3,388

Glycol dehydrator 25 3 2,669 2 0 126 0 48 229 95 3,195

Other 2 602 1,313 0 0 1 17 61 297 48 2,340

Storage 0 405 611 2 0 125 3 41 43 20 1,251

Process heaters 49 167 751 0 6 159 0 1 11 20 1,163

Turbines 641 210 103 0 0 11 0 14 42 46 1,066

Flares 527 67 10 0 6 33 0 25 33 3 704

Recip. Engines (mostly gas) 5 6 34 0 0 1,900 0 0 107 0 2,052

Storage 0 1 0 0 0 979 0 0 1 0 981

Glycol dehydrator 0 0 34 0 0 605 0 0 6 0 645

Fugitive emissions 0 0 2 0 0 180 0 0 30 0 213

Other 11 15 113 0 0 233 0 1 252 1 626

Total 1,469 3,424 10,417 38 67 5,148 22 361 2,090 497 23,533

PM 2.5 emissions (tons/year)

Point 

sources

Production Point 

sources

Exploration

 Production Point 

sources

VOC emissions (tons/year)
4-4

and gas production operations, and up to 210 tons per year for exploration operations, compared 

with a maximum of 1,370 tons per year for reciprocating engines at industrial facilities. Diesel 

engines at oil and gas operations are also smaller than those at industrial facilities. NOX

emissions from individual diesels range up to 46 tons per year for production operations, and 

10 tons per year for exploration operations, compared with 850 tons per year for the largest 

industrial diesel engine.1

SO2 emissions from oil and gas exploration and production are estimated to be an order 

of magnitude lower than NOX emissions. SO2 emissions from incinerators and flares result from 

the presence of sulfur compounds in waste gases that are burned at the production site. These are 

generally the waste gases from natural gas sweetening operations such as amine treatment units. 

Although the process heaters at oil and gas production facilities are listed as using natural gas 

fuel, SO2 emissions from these sources are reported to be about 4,000 tons/year. These 

emissions may result from the combustion of unsweetened natural gas at the well head. SO2

emissions from drill rig motors also result from the presence of sulfur compounds in the motor 

fuels.

PM10, PM2.5, and VOC emissions from oil and gas exploration and production are also 

estimated to be an order of magnitude lower than NOX emissions. Emissions of OC and EC are 

specifically quantified in either the WRAP inventory or the NEI, but can be estimated as a 

percentage of PM10 emissions using data from EPA’s SPECIATE database.3 EC and OC are 

estimated to comprise 78.8% and 18.5% of diesel PM10 emissions; and 38.4% and 24.7% of 

natural gas combustion PM10 emissions, respectively.

Table 4-2 lists potential control measures for oil and gas production and exploration 

emissions. The table includes options for reciprocating engines and turbines, process heaters, 

flares and incinerators, and sulfur recovery units. As discussed in Chapter 3, a number of 

options are available to control emissions from gas-fired reciprocating engines, diesel-fueled 

reciprocating engines, and turbines.2,4,5,6,7,8 Reciprocating engines can be designed to operate 

under rich fuel mixture, or lean fuel mixture conditions. Air-to-fuel-ratio adjustments and 

ignition retarding technologies can be used to control emissions under either fuel mixture 

condition. Low-Emission Combustion (LEC) retrofit technology which can also reduce 

emissions from lean burn reciprocating engines by an average of 89%. LEC involves modifying 

the combustion system to achieve very lean combustion conditions (high air-to-fuel ratios). 

Selective Catalytic Reduction (SCR) can also be used either alone or in conjunction with the 

above technologies to reduce NOX emissions from reciprocating engines or turbines by 90%. In 

addition, Non-Selective Catalytic Reduction (NSCR) can be used for rich-burn natural gas 

engines.8

SO2 emissions from incinerators and flares could be avoided by installing sulfur recovery 

units to remove sulfur from the waste gases prior to incineration or flaring.

9

 These emissions can 

also be reduced by compressing sulfur-containing acid gases and injecting these gases into nonproducing rock formations.10

 Flue gas scrubbing has also been used to control SO2 emissions 

from incinerators.11,12 SO2 emissions from existing sulfur recovery units can be reduced by 

adding additional recovery stages, or by adding a tail gas treatment unit.12 In some cases, it may 

be possible to avoid SO2 emissions from process heaters by substituting a lower-sulfur 

sweetened natural gas for the gas currently being burned. A number of options are available to 
Source Type Control Technology

Pollutant 

controlled

Baseline 

emissions 

(1000 tons/yr)

Estimated 

control 

efficiency (%)

Potential 

emission 

reduction 

(1000 

tons/year)

References

Air-fuel ratio adjustment NOX 166 10 - 40 17 - 66 2,5

Ignition timing retard NOX 166 15 - 30 25 - 50 2

Low-emission combustion 

(LEC) retrofit

NOX 166 80 - 90 130 - 150 2,5

SCR NOX 166 90 150 2,8,12

NOX a 90 - 99 a 8

VOC a 40 - 85 a 8

NOX 166 100 166 2

SO2 0.30 100 0.30

PM10 0.21 100 0.21

PM2.5 0.21 100 0.21

EC 0.08 100 0.08

OC 0.05 100 0.05

VOC 5.9 100 5.9

Overallb 172 172

Ignition timing retard NOX 60 15 - 30 9 - 18 2

Exhaust gas recirculation NOX 60 40 24 2

SCR NOX 60 80 - 95 48 - 57 2,8,12

NOX 60 87 52 2

PM10 0.2 85 0.2 2

PM2.5 0.2 85 0.2

EC 0.1 85 0.1

OC 0.1 85 0.1

VOC 8.0 87 6.9 2

Overallb 68 59

PM10 0.23 25 0.06 2

PM2.5 0.18 25 0.05

EC 0.10 25 0.03

OC 0.08 25 0.02

VOC 8.0 90 7.2 2

Overallb 8.2 7.3

Water or steam injection NOX 47 68 - 80 32 - 38 11

Low-NOX burner (LNB) NOX 47 68 - 84 32 - 39 11

SCR NOX 47 90 42 6,7,12

Water or steam injection with 

SCR

NOX 47 93 - 96 44 - 45 11

Turbines

Table 4-2. Control Options for Oil and Gas Production and Exploration

Compressor 

engines and gas 

fueled 

reciprocating 

engines

Replacement with electric 

motors

Diesel oxidation catalyst

Drilling rig 

engines and 

other diesel 

engines

Replacement of Tier 2 engines 

with Tier 4

NSCR
Source Type Control Technology

Pollutant 

controlled

Baseline 

emissions 

(1000 tons/yr)

Estimated 

control 

efficiency (%)

Potential 

emission 

reduction 

(1000 

tons/year)

References

Table 4-2. Control Options for Oil and Gas Production and Exploration

Add or expand sulfur recovery 

unit

SO2 8.5 90 - 95 c 9

Acid gas injection SO2 8.5 100 c 10

Spray dryer absorber SO2 9.0 80 - 95 7.2 - 8.6 12

Wet FGD SO2 9.0 90 - 99 8.1 - 9 11,12

Acid gas injection SO2 9.0 100 c 10

Additional recovery stages SO2 2.4 94 - 96 2.2 - 2.3 11,14

Tail gas treatment unit (TGTU) SO2 2.4 90 - 99.5 2.1 - 2.4 11,14

Substitution of lower sulfur 

fuel

SO2 4.0 up to 90 0 - 3.6 9,12

LNB NOX 3.1 40 1.2 13,14

ULNB NOX 3.1 75 - 85 2.3 - 2.6 12,13,14

LNB and FGR NOX 3.1 48 1.5 13,14

SNCR NOX 3.1 60 1.9 12,13,14

SCRd NOX 3.1 70 - 90 2.2 - 2.8 12,13,14

LNB and SCR NOX 3.1 70 - 90 2.2 - 2.8 12,13,14

Glycol 

dehydrators

Optimize glycol circulation rate VOC 3.8 33 - 67 1.3 - 2.6 2

d

SCR can be used for mechanical draft process heaters. Natural draft heaters would have to be converted to mechanical 

draft for installation of SCR.

Flares

a

NSCR applies only to rich-burn engines. The distribution of emissions between rich-burn and lean-burn engines is not 

known.

c

Insufficient information is available in the emissions inventory to determine the percentage of flare or incinerator 

emissions in this category that is amenable to these control strategies.

Incinerators

Sulfur recovery 

units

Process heaters

b

For control measures reducing multiple pollutants, overall emissions and emission reductions reflect the sum of all 

pollutants. However, EC, OC, and PM2.5 are components of PM10, and therefore are not added separately to the totals.
4-7

reduce NOX emissions from process heaters. Combustion modifications including low-NOX

burners (LNB), ultralow-NOX burners (ULNB), and flue gas recirculation (FGR) reduce the 

formation of NOX. In addition, flue gases from the process heaters can be treated with selective 

catalytic reduction (SCR) or selective non-catalytic reduction (SNCR) to reduce NOX emissions. 

These post-combustion controls can be used either alone or in conjunction with combustion 

controls.13,14 

4.1 Factor 1 – Costs

Table 4-3 provides cost estimates for the emission control options which have been 

identified for oil and gas production and exploration operations. For each option, the table gives 

an estimate of the capital cost to install the necessary equipment, and the total annual cost of 

control, including the amortized cost associated with the capital equipment cost. The capital and 

annual cost figures are expressed in terms of the cost per unit of engine size or per unit of 

process throughput. Engine size is expressed in horsepower for reciprocating engines and 

MMBtu/hour for turbines. Throughput for process heaters is also expressed in MMBtu/hour. 

Process throughput for sulfur recovery units is expressed in terms of the amount of sulfur 

recovered. 

Sulfur recovery units are believed to be more cost-effective than post-combustion 

controls for reducing SO2 emissions from flares and incinerators at oil and gas production 

operations. Recent analyses of controls for Regional Haze precursors have focused on add-on 

controls for SO2, rather than such process modifications. However, costs of sulfur recovery units 

were estimated in an earlier study of model refineries in different size ranges.9 These estimates 

have been updated to current dollars using the Chemical Engineering plant cost index.

Table 4-3 shows a range of values for each cost figure, since the cost per unit of process 

throughput size will depend on the process size and other factors. The lower ends of the cost 

ranges typically reflect larger engines or processes, and the higher ends of the cost ranges 

typically reflect smaller engines or processes. The table also shows the estimated cost 

effectiveness for each control measure, in terms of the cost per ton of emission reduction.

4.2 Factor 2 – Time Necessary for Compliance

Once a state decides to adopt a particular control strategy, up to 2 years will be needed to 

develop the necessary rules to implement the strategy. We have estimated that sources may then 

require up to a year to procure the necessary capital to purchase control equipment. The Institute 

of Clean Air Companies (ICAC) has estimated that approximately 13 months is required to 

design, fabricate, and install SCR or SNCR technology for NOX control.

15

 However, the time 

necessary will depend on the type and size of the unit being controlled. For instance, state 

regulators’ experience indicates that closer to 18 months is required to install this technology.16

In the CAIR analysis, EPA estimated that approximately 30 months is required to design, build, 

and install SO2 scrubbing technology for a single emission source.

17

 The analysis also estimated 

that up to an additional 12 months may be required for staging the installation process if multiple 

sources are to be controlled at a single facility. Based on these figures, the total time required to 

achieve emission reductions for oil and gas production and exploration operations is estimated at 

a total of 61⁄2 years.
Source Type Control Technology

Pollutant

controlled

Estimated

control

efficiency (%)

Estimated

capital cost

($/unit)

Estimated annual

cost ($/year

/unit) Units

Cost effectiv

($/ton

Air‐fuel ratio adjustment NOX 10 ‐ 40 5.3 ‐ 42 0.9 ‐ 6.8 hp 68 ‐ 2,5

Ignition timing retard NOX 15 ‐ 30 na 1 ‐ 3 hp 42 ‐ 1,2

LEC retrofit NOX 80 ‐ 90 120 ‐ 820 30 ‐ 210 hp 320 ‐ 2,5

SCR NOX 90 100 ‐ 450 40 ‐ 270 hp 870 ‐ 31,

NOX 90 ‐ 99 17 ‐ 35 3 ‐ 6 hp 16 ‐ 36 

VOC 40 ‐ 85 1,500 ‐ 6,

Overallb 16 ‐ 36

NOX 100 120 ‐ 140 38 ‐ 44 hp 100 ‐ 4,7

SO2 >55,00

PM10 >79,00

PM2.5 >79,00

EC >205,00

OC >319,00

VOC 3,000 ‐ 130

Overallb 100 ‐ 4,5

Ignition timing retard NOX 15 ‐ 30 16 ‐ 120 14 ‐ 66 hp 1,000 ‐ 2,

EGR NOX 40 100 26 ‐ 67 hp 780 ‐ 2,0

SCR NOX 80 ‐ 95 100 ‐ 2,000 40 ‐ 1,200 hp 3,000 ‐ 7,

NOX 87 125 20 hp 900 ‐ 2,4

PM10 85 125 20 hp 25,000 ‐ 68

PM2.5

EC

OC

VOC 87 125 20 hp 22,000 ‐ 59

Overallb 840 ‐ 2,2

PM10 25 10 1.7 hp 1400 

PM2.5 1400

EC 3,300

OC 4,200

VOC 90 10 1.7 hp 350 

Overallb 280

Table 4-3. Estimated Costs of Control for Oil and Gas Production and Exploration

Drilling rigengines and

other engines

Diesel oxidation catalyst

Replacement of Tier 2engines with Tier 4

Compressorengines

Replacement with electricmotorsNSCRa
Source Type Control Technology

Pollutant

controlled

Estimated

control

efficiency (%)

Estimated

capital cost

($/unit)

Estimated annual

cost ($/year

/unit) Units

Cost effectiv

($/ton

Table 4-3. Estimated Costs of Control for Oil and Gas Production and Exploration

Water or steam injection NOX 68 ‐ 80 4.4 ‐ 16 2 ‐ 5 1000 BTU 560 ‐ 3,1

Low‐NOX burnersc NOX 68 ‐ 84 8 ‐ 22 2.7 ‐ 8.5 1000 BTU 2,000 ‐ 10

SCR NOX 90 13 ‐ 34 5.1 ‐ 13 1000 BTU 1,000 ‐ 6,

Water or steam injection

with SCR

NOX 93 ‐ 96 13 ‐ 34 5.1 ‐ 13 1000 BTU 1,000 ‐ 6,

Add or expand sulfur

recovery unit

SO2 90 ‐ 95 0.1 ‐ 1.1 28 ‐ 190 ton‐Sulfur/year 14 ‐ 95 

Acid gas injection SO2 100 

Spray dryer absorber SO2 80 ‐ 95 1,500‐1,9

Wet FGD SO2 90 ‐ 99 1,500 ‐ 1,

Acid gas injection SO2 100 

Additional recovery stages SO2 94 ‐ 96 

Tail gas treatment unit

(TGTU)

SO2 90 ‐ 99.5 1,100 ‐ 1,

Substitution of lower

sulfur fuel

SO2 up to 90 

LNB NOX 40 3.8 ‐ 7.6 0.41 ‐ 0.81 1000 BTU 2,100 ‐ 2,

ULNB NOX 75 ‐ 85 4.0 ‐ 13 0.43 ‐ 1.3 1000 BTU 1,500 ‐ 2,

LNB and FGR NOX 48 16 1.7 1000 BTU 2,600 

SNCR NOX 60 10 ‐ 22 1.1 ‐ 2.4 1000 BTU 4,700 ‐ 5,

SCRd NOX 70 ‐ 90 33 ‐ 48 3.7 ‐ 5.6 1000 BTU 2,900 ‐ 6,

LNB and SCR NOX 70 ‐ 90 37 ‐ 55 4 ‐ 6.3 1000 BTU 2,900 ‐ 6,

Glycoldehydrators

Optimize glycol circulationrate

VOC 33 ‐ 67 31 ‐ 170 5 ‐ 28 gal/hr 

dSCR cost estimates for process heaters apply to mechanical draft heaters. Natural draft heaters would have to be converted to mechanical d

of SCR. This would increase both the capital and annualized costs of control by about 10%.

aNSCR applies only to rich‐burn engines. The distribution of emissions between rich‐burn and lean‐burn engines is not known.bFor control measures reducing multiple pollutants, the overall cost‐effectiveness is the cost per total reduction of all pollutants. However, E

are components of PM10, and therefore are not added separately to the emission reduction total.

cCosts estimates for low‐NOX burners for turbines reflect the incremental costs of new low‐NOX burners versus standard burners. Retrofit cos

burners were not available.FlaresSulfur recovery

unitsProcessheatersIncineratorsTurbines
4-10

4.3 Factor 3 – Energy and Other Impacts

Table 4-4 shows the estimated energy and non-air pollution impacts of control measures 

for sources at oil and gas production and exploration operations. For gas-fired reciprocating 

engines and diesel engines, air-to-fuel-ratio adjustments and ignition retarding technologies have 

been found to increase fuel consumption by up to 5%, with a typical value of about 2.5%.18,19 

This increased fuel consumption would result in increased CO2 emissions. LEC technology is 

not expected to increase fuel consumption; and may provide some fuel economy.18 

Diesel oxidation catalyst and diesel filtration technologies would produce an increase in 

fuel consumption in order to overcome the pressure drop through the catalyst bed and the filter. 

In the case of diesel oxidation catalyst, the catalyst would have to be changed periodically, 

producing an increase in solid waste disposal.20 If diesel reciprocating engines are replaced with 

electric motors, there would be an increase in electricity demand, but this would be offset by the 

fuel consumption that would be avoided by replacing the engine. 

For turbines, water injection and steam injection would require electricity to operate 

pumps and ancillary equipment.20 Water injection would produce an increase in fuel 

consumption in order to evaporate the water, and steam injection would require energy to 

produce the steam. The increased electricity, steam, and fuel demands would produce additional 

CO2 emissions.

Installation of SCR on any type of engine would cause a small increase in fuel 

consumption, about 0.5%, in order to force the exhaust gas through the catalyst bed.18 This 

would produce an increase in CO2 emissions to generate the electricity. In addition, spent 

catalyst would have to be changed periodically, producing an increase in solid waste disposal.20

Sulfur recovery units require electricity and steam. Wet or dry scrubbers applied to 

incinerators and tail gas treatment units applied to sulfur recovery units would use electricity for 

the fan power needed to overcome the scrubber pressure drop. These systems would also 

produce solid waste, and wet scrubbers would produce wastewater which would require 

treatment. Injection of acid gases would require the consumption of fuel to compress the gases. 

However, this option would also result in the sequestration of CO2 present in the injected gas 

stream.10

Low-NOX burners for process heaters are expected to improve overall fuel efficiency. 

FGR would require additional electricity to recirculate the fuel gas into the heater. In SCR 

systems for process heaters, fans would be required to overcome the pressure drop through the 

catalyst bed. The fans would require electricity, with resultant increases in CO2 to generate the

electricity. In addition, spent catalyst would have to be changed periodically, producing an 

increase in solid waste disposal.20
Electricity 

requirement 

(kW-hr)

Steam 

requirement 

(tons steam)

Solid waste 

produced (tons 

waste)

Wastewater 

produced (1000 

gallons)

Additional CO2 

emitted (tons)

Air-fuel ratio adjustment NOX 17 - 66 a

Ignition retarding 

technologies

NOX 25 - 50 a

LEC retrofit NOX 130 - 150 a

SCR NOX 150 0.5 0.008 0.43

NSCR NOX, VOC e 0.5 0.008 0.24

Replacement with electric 

motors

NOX 166 (100) 66,000 b

Ignition timing retard NOX 9 - 18 a

EGR NOX 24 2.7 2.0

SCR NOX 48 - 57 0.5 0.008 0.38

NOX 52 c c

PM2.5, PM10, 

EC, OC

0.2 c c

VOC 6.9 c c

Totale 59

PM2.5, PM10, 

EC, OC

0.1 0.5 b 316

VOC 7.2 2.5

Totalf 7.3 2.6e

Water or steam injection NOX 32 - 38 a 31 8.1

Low-NOX burner (LNB) NOX 32 - 39 a

SCR 42 a

Water or steam injection 

with SCR

NOX 44 - 45 0.45 0.026 1.7

Drilling rig engines 

and other engines

Diesel oxidation catalyst

Additional fuel 

requirement 

Source Type (%)

Replacement of Tier 2 

engines with Tier 4

Control Technology

Table 4-4. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Oil and Gas Production and Exploration

Compressor 

engines

Potential 

emission 

reduction (1000 

tons/year)

Energy and non-air pollution impacts (per ton of emission reduced)

Pollutant 

controlled

Turbines
Electricity 

requirement 

(kW-hr)

Steam 

requirement 

(tons steam)

Solid waste 

produced (tons 

waste)

Wastewater 

produced (1000 

gallons)

Additional CO2 

emitted (tons)

Additional fuel 

requirement 

Source Type Control Technology (%)

Table 4-4. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Oil and Gas Production and Exploration

Potential 

emission 

reduction (1000 

tons/year)

Energy and non-air pollution impacts (per ton of emission reduced)

Pollutant 

controlled

Substitution of lower 

sulfur fuel

SO2 0 - 3.6 b b

LNB NOX 1.2 a g

ULNB NOX 2.3 - 2.6 a g

LNB and FGR NOX 1.5 3,300 3.3

SNCR NOX 1.9 0.16 460 3.2

SCR NOX 2.2 - 2.8 8,400 0.073 8.4

LNB and SCR NOX 2.2 - 2.8 8,400 0.073 8.4

Add or expand sulfur 

recovery unit

NOX up to 8.5 270 3.2 <0.01 1.1

Acid gas injection SO2 up to 8.5 d h

Spray dryer absorber SO2 7.2 - 8.6 400 3.7 1.1

Wet FGD SO2 8.1 - 9 1,100 3.1 2.8 3.7 2.6

Acid gas injection SO2 up to 9.0 d h

Additional recovery stages SO2 2.2 - 2.3 270 3.2 <0.01 1.1

Tail gas treatment unit 

(TGTU) 

SO2 2.1 - 2.4 190 3.5 3.7 1.1

Glycol dehydrators Optimize glycol circulation 

rate

VOC 1.3 - 2.6 a

NOTES:

c

EPA has estimated that the control measures used to meet Tier 4 standards will be integrated into the engine design so that sacrifices in fuel economy will be negligible.

Flares

Process heaters

blank indicates no impact is expected.

Incinerators

h

Acid gas injection is also expected to result in sequestration of the CO2 present in the acid gas stream.

b

CO2 from the generation of electricity would be offset by avoided emissions due to replacing the diesel engine

Sulfur recovery 

units

f

For control measures reducing multiple pollutants, energy and other impacts are expressed as the impact per per total reduction of all pollutants. (However, EC, OC, and PM2.5 are 

components of PM10, and therefore are not added separately to the emission reduction total.)

g

Some designs of low-NOX burners and ultralow-NOX burners require the use of pressurized air supplies. This would require additional electricity to pressurize the combustion air.

a

The measure is expected to improve fuel efficiency.

e

NSCR applies only to rich-burn engines. The distribution of emissions between rich-burn and lean-burn engines is not known.

d

Some impact is expected but insufficient information is available to evaluate the impact.
4-13

4.4 Factor 4 – Remaining Equipment Life

Information was not available on the age of oil and gas production and exploration 

equipment in the WRAP region. The remaining lifetime of most equipment is expected to be 

longer than the projected lifetime of pollution control technologies which have been analyzed for 

this category. In the case of add-on technologies, the projected lifetime is 15 years. 

If the remaining life of an emission source is less than the projected lifetime of a 

pollution control device, then the capital cost of the control device would have to be amortized 

over a shorter period of time, corresponding to the remaining lifetime of the emission source. 

This would cause an increase in the amortized capital cost of the pollution control option, and a 

corresponding increase in the total annual cost of control. This increased cost can be quantified 

as follows:

where:

A1 = the annual cost of control for the shorter equipment lifetime ($)

A0 = the original annual cost estimate ($)

C = the capital cost of installing the control equipment ($)

r = the interest rate (0.07)

m = the expected remaining life of the emission source (years)

n = the projected lifetime of the pollution control equipment

4.5 References for Section 4

1. WRAP (2008), Emissions Data Management System, Western Regional Air Partnership, 

Denver, CO, http://www.wrapedms.org/app_main_dashboard.asp.

2. Bar-Ilan, Amnon, Ron Friesen, Alison Pollack, and Abigail Hoats (2007), WRAP Area 

Source Emissions Inventory Protection and Control Strategy Evaluation - Phase II, 

Western Governor's Association, Denver, CO, Chapter 4.

3. EPA (2006), SPECIATE version 4, U.S. EPA, RTP, NC. 

http://www.epa.gov/ttn/chief/software/speciate/index.html.

4. EPA (1993), Alternative Control Techniques Document — NOX Emissions from 

Stationary Reciprocating Internal Combustion Engines, EPA-453/R-93-032, U.S. EPA, 

RTP, NC, Chapter 6, 

5 . Edgerton, Stephen, Judy Lee-Greco, and Stephanie Walsh (2002), Stationary 

Reciprocating Internal Combustion Engines – Updated Information on NOX Emissions 

and Control Techniques, U.S. EPA, RTP, NC, 

http://www.epa.gov/ttn/naaqs/ozone/ozonetech/ic_engine_nox_update_09012000.pdf.

6. Nelson, Bradley (2009), Alternative Control Techniques Document: Stationary Diesel 

Engines, U.S. EPA, RTP, NC.
4-14

7. EPA (1993), Alternative Control Techniques Document — NOX Emissions from 

Stationary Gas Turbines, EPA-453/R-93-007, U.S. EPA, RTP, NC, Chapter 6, 

http://www.epa.gov/ttn/catc/dir1/gasturb.pdf.

8. Alpha-Gamma Technologies, Inc. (2006), Control Technologies for Internal Combustion

Engines, Docket Number EPA-HQ-OAR-2005-0030-0054.

9. Research Triangle Institute (1972), Control Technology for Sulfur Oxide Pollutants, 2nd 

ed, Appendix B: Sulfur Emission Factors and Control Costs for Petroleum 

Refineries,Prepared for the U.S. EPA, RTP, 

NC,http://yosemite.epa.gov/ee/epa/eermfile.nsf/vwAN/EE-0233-05.pdf/$File/EE-0233-

05.pdf.

10. EPA (2008), Press release: EPA reaches agreement with Merit Energy and Shell on 

clean-air violations, contact: William Omohundro, U.S. EPA, Chicago, IL.

11. E.H. Pechan & Associates (2005), AirControlNET, Version 4.1 - Documentation Report, 

U.S. EPA, RTP, NC, http://www.epa.gov/ttnecas1/AirControlNET.htm.

12. NACAA (formerly STAPPA and ALAPCO) (2006), Controlling Fine Particulate Matter 

Under the Clean Air Act: A Menu of Options, National Association of Clean Air 

Agencies, www.4cleanair.org/ PM25Menu-Final.pdf.

13. EPA (1993), Alternative Control Techniques Document— NOX Emissions from Process 

Heaters (Revised), EPA-453/R-93-034, U.S. EPA, RTP, NC, pp 6-14 thru 6-36, 

http://www.epa.gov/ttn/catc/dir1/procheat.pdf.

14. MRPO (2006), Interim White Paper - Midwest RPO Candidate Control Measures Source 

Category: Petroleum Refining, http://www.ladco.org/reports/control/white_papers/.

15 . Institute of Clean Air Companies (2006), Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial Sources, 

http://www.icac.com/files/public/ICAC_NOx_Control_Installation_Timing_120406.pdf..

16 . Ghoreishi, Farrokh (2007), Time required to install add-on control measures for NOX,

Personal communication, Wisconsin Department of Natural Resources, April 27. 

17. EPA (2005), Boilermaker Labor Analysis and Installation Timing – Technical Support 

Document for the Final Clean Air Interstate Rule. OAR-2003-0053, U.S. EPA, 

Washington, DC. www.epa.gov/cair/technical.html#final.

18. Reference 4, Page 7-12.

19. Center for Alternative Fuels, Engines & Emissions (2005), Alice Austen Ferry Emissions 

Tests, M.J. Bradley & Associates, Manchester, NH, Page 13.
4-15

20. EPA (2002), EPA Air Pollution Control Cost Manual, 6th ed., EPA/452/B-02-001, U.S. 

EPA, Office of Air Quality Planning and Standards, RTP, NC, 

http://www.epa.gov/ttncatc1/products.html#cccinfo..
5-1

5. Natural Gas Processing Operations 

Natural gas processing facilities carry out a number of operations to remove impurities 

from natural gas before it is piped to consumers. In addition, the gas is typically fractionated to 

remove propane and heavier hydrocarbons, which are then processed as separate products. 

Emission sources at natural gas processing facilities include many of the same sources found at 

gas production operations, discussed in the previous chapter. Turbines and natural gas 

reciprocating engines are used to drive compressors and other equipment. Flares and 

incinerators are used to dispose of waste gases, and process heaters are used in various 

operations. In addition, emissions of SO2 emanate from sulfur recovery operations at sour 

natural gas processing plants. 

Table 5-1 summarizes emissions from the natural gas processing industry, broken down 

by state and by the various emission sources. Point source emissions of NOX, SO2, and VOC 

from these operations were extracted from the 2002 WRAP emissions inventory, which catalogs 

emission sources by their Standard Industrial Classification (SIC).1 SIC 132 covers natural gas 

processing. Estimates for PM10 and PM2.5 were extracted from the 2002 NEI, which also 

classifies emissions by SIC. It must be noted that the point source emissions in Table 5-1 for 

reciprocating engines and turbines in the natural gas processing industry are also included in the 

emission totals reported in Table 3-1 for all reciprocating engines and turbines. However, these 

emissions are separate from those reported in Table 4-1 for the oil and gas production and 

exploration sector.

Total NOX emissions from natural gas processing are estimated at about 31,000 tons/year, 

and SO2 emissions are estimated at about 12,000 tons/year. These emissions represent about 2% 

of stationary source (point and area source) NOX emissions, and 1% of stationary source SO2

emissions in the region. 

PM10 and PM2.5 emissions from natural gas processing facilities are estimated to be an 

order of magnitude lower than NOX emissions. Emissions of OC and EC are not specifically 

quantified in either the WRAP inventory or the NEI, but can be estimated as a percentage of 

PM10 emissions using data from EPA’s SPECIATE database.2 EC and OC are estimated to 

comprise 38.4% and 24.7% of natural gas combustion PM10 emissions, respectively.

Emissions from individual reciprocating engines at natural gas processing plants range up 

to about 1,000 tons per year, compared with 1,373 tons per year for the largest natural gas fired 

reciprocating engines at industrial facilities. Emissions from individual turbines range up to 

338 tons of NOX per year, compared with 845 tons per year for the largest natural gas turbines at 

industrial facilities.1

Table 5-2 lists potential control measures for natural gas processing emissions. The table 

includes options for reciprocating engines and turbines, process heaters, flares and incinerators, 

and sulfur recovery units. As discussed in Chapter 3, a number of options are available to 

control emissions from gas-fired reciprocating engines, diesel-fueled reciprocating engines, and 
Emission source AK CA CO MT ND NM NV UT WY Tribes 

Reciprocating engines(natural gas)

86 626 1,027 33 2,428 15,976 0 612 1,935 1,140 

Turbines 1,533 11 107 0 0 4,317 0 0 27 486 Process heaters 19 7 30 0 55 263 0 1 122 1 Boilers 1 29 60 0 0 193 0 20 6 26 Flares 0 14 1 0 0 56 0 1 25 0 Othera 0 14 5 0 10 122 0 1 82 0 

Total 1,639 686 1,228 33 2,493 20,871 0 634 2,172 1,654 

Sulfur recovery units 0000 1,604 4,739 0 0 196 0 

Flares 0 1 0 0 67 3,628 0 0 506 0 

Incinerators 0 0 0 0 358 417 0 0 0 0 Process heaters 0 0 0 0 0 274 0 0 0 7 Othera 0 1 1 0 0 14 0 0 6 113 

Total 0210 2,030 9,072 0 0 708 119 

Reciprocating engines ‐ natural gas

0 3 0 0 25 70 0 4 0 0 

Othera 2 3 4 0 0 20 0 1 1 0 

Total 2 6 4 0 25 90 0 5 1 0 

Reciprocating engines - natural gas

0 3 0 0 25 70 0 3 0 0 

Othera 2 3 4 0 0 19 0 1 1 0 

Total 2 6 4 0 25 90 0 4 1 0 

Storage 0 10 52,006 0 5 395 0 12 146 35 Reciprocating engines 0 687 102 20 44 1,135 0 13 278 29 Fugitive emissions 0 308 91 0 0 317 0 5 242 132 Glycol dehydrator 0 2 118 0 0 113 0 31 55 5 Turbines 10 0 0 0 0 187 0 0 0 21 Othera 1 89 210 0 2 54 0 90 35 35 

Total 11 1,095 52,527 20 51 2,202 0 151 757 257 

aIncludes glycol dehydrator reboilers, incinerators, amine treatment units, and sources not specifically classified in the emissions inventory. For 

incinerators are broken out separately.

NO X emissions (tons/year)

SO 2 emissions (tons/year)

VOC emissions (tons/year)

Table 5-1. Emissions from Natural Gas Processing in the WRAP Region

PM 10 emissions (tons/year)

PM 2.5 emissions (tons/year)
Source Type Control Technology

Pollutant

controlled

Baseline

emissions

(1000

tons/yr)

Estimated

control

efficiency (%)

Potential

emission

reduction (1000

tons/year)

Refer‐

ences

Air‐fuel ratio adjustment NOX 24 10 ‐ 40 2 ‐ 10 3,7

Ignition timing retard NOX 24 15 ‐ 30 4 ‐ 7 3,7

Low‐emission combustion

(LEC) retrofit

NOX 24 80 ‐ 90 19 ‐ 21 4,7

SCR NOX 24 90 21 7,8,12

NOX a 90 ‐ 99 a 8

VOC a 40 ‐ 85 a 8

NOX 24 100 24 7

PM10 0.10 100 0.10

PM2.5 0.10 100 0.10

EC 0.04 100 0.04

OC 0.03 100 0.03

VOC 2 100 2

Overallb 26 26

Water or steam injection NOX 6.5 68 ‐ 80 4.4 ‐ 5.2 6

Low‐NOX burner (LNB) NOX 6.5 68 ‐ 84 4.4 ‐ 5.4 6

SCR NOX 6.5 90 5.8 5,6

Water or steam injection with

SCR

NOX 6 93 ‐ 96 6 6

Substitution of lower sulfur

fuel

SO2 0.28 up to 90 0 ‐ 0.25 9,12

LNB NOX 0.50 40 0.20 13,14

ULNB NOX 0.50 75 ‐ 85 0.37 ‐ 0.42 12,13,14

LNB and FGR NOX 0.50 48 0.24 13,14

SNCR NOX 0.50 60 0.30 12,13,14

SCRc NOX 0.50 70 ‐ 90 0.35 ‐ 0.45 12,13,14

LNB and SCR NOX 0.50 70 ‐ 90 0.35 ‐ 0.45 12,13,14

LNB with OFA NOX 0.33 30 ‐ 50 0.1 ‐ 0.17 11,12

LNB, OFA, and FGR NOX 0.33 30 ‐ 50 0.1 ‐ 0.17 11,12

SNCR NOX 0.33 30 ‐ 75 0.1 ‐ 0.25 11,12

SCR NOX 0.33 40 ‐ 90 0.13 ‐ 0.3 11,12

Add or expand sulfur recovery

unit

SO2 4.2 90 ‐ 95 d 9

Acid gas injection SO2 4.2 100 d 10

Additional recovery stages SO2 6.5 94 ‐ 96 6.1 ‐ 6.3 11,14

Tail gas treatment unit (TGTU) SO2 6.5 90 ‐ 99.5 5.9 ‐ 6.5 11,14

Spray dryer absorber SO2 0.78 80 ‐ 95 0.62 ‐ 0.74 12

Wet FGD SO2 0.78 90 ‐ 99 0.7 ‐ 0.77 11,12

Acid gas injection SO2 0.78 100 d 10

Glycol

dehydrators

Optimize glycol circulation

rate

VOC 0.32 33 ‐ 67 0.11 ‐ 0.22 7

d

Insufficient information is available in the emissions inventory to determine the percentage of flare or incinerator emissions

in this category that is amenable to these control strategies.

Table 5-2. Control Options for Natural Gas Processing

Replacement with electric

motors

Reciprocating

engines, gas

Flares

Sulfur recovery

units for amine

treatment units

Process heaters

Boilers

NSCR

a

NSCR applies only to rich‐burn engines.  The distribution of emissions between rich‐burn and lean‐burn engines is not

k

c

SCR can be used for mechanical draft process heaters.  Natural draft heaters would have to be converted to mechanical draft

for installation of SCR.

Turbines

Incinerators

b

For control measures reducing multiple pollutants, overall emissions and emission reductions reflect the sum of all

pollutants.  However, EC, OC, and PM2.5 are components of PM10, and therefore are not added separately to the totals.
5-4

turbines.3,4,5,6,7,8 Reciprocating engines can be designed to operate under rich fuel mixture, or 

lean fuel mixture conditions. Air-to-fuel-ratio adjustments and ignition retarding technologies 

can be used to control emissions under either fuel mixture condition. Low-Emission Combustion 

(LEC) retrofit technology can also reduce emissions from lean burn reciprocating engines by an 

average of 89%. LEC involves modifying the combustion system to achieve very lean 

combustion conditions (high air-to-fuel ratios). Selective Catalytic Reduction (SCR) can also be 

used either alone or in conjunction with the above technologies to reduce NOX emissions from 

reciprocating engines or turbines by 90%. In addition, Non-Selective Catalytic Reduction 

(NSCR) can be used for rich-burn natural gas engines.8

SO2 emissions from incinerators and flares could be reduced by installing sulfur recovery 

units to remove sulfur from the waste gases prior to incineration or flaring.

9

 These emissions can 

also be reduced by compressing sulfur-containing acid gases and injecting these gases into nonproducing rock formations.10 Flue gas scrubbing has also been used to control SO2 emissions 

from incinerators.11,12 SO2 emissions from existing sulfur recovery units can be reduced by 

adding additional recovery stages, or by adding a tail gas treatment unit.12 In some cases, it may 

be possible to avoid SO2 emissions from process heaters by substituting a lower-sulfur 

sweetened natural gas for the gas currently being burned. A number of options are available to 

reduce NOX emissions from process heaters. Combustion modifications including LNB, ULNB, 

and FGR reduce the formation of NOX. In addition, flue gases from the process heaters can be

treated with SCR or SNCR to reduce NOX emissions. These post-combustion controls can be 

used either alone or in conjunction with combustion controls.13,14 

5.1 Factor 1 – Costs

Table 5-3 provides cost estimates for the emission control options which have been 

identified for the natural gas processing industry. For each option, the table gives an estimate of 

the capital cost to install the necessary equipment, and the total annual cost of control, including 

the amortized cost associated with the capital equipment cost. The capital and annual cost 

figures are expressed in terms of the cost per unit of engine size or per unit of process 

throughput. Engine size is expressed in horsepower for reciprocating engines and MMBtu/hour 

for turbines. Throughput for process heaters is also expressed in MMBtu/hour. Process 

throughput for sulfur recovery units is expressed in terms of the amount of sulfur recovered. 

Sulfur recovery units are believed to be more cost-effective than post-combustion 

controls for reducing SO2 emissions from flares and incinerators at natural gas processing 

facilities. Recent analyses of controls for Regional Haze precursors have focused on add-on 

controls for SO2, rather than such process modifications. However, costs of sulfur recovery units 

were estimated in an earlier study of model refineries in different size ranges.9 These estimates 

have been updated to current dollars using the Chemical Engineering plant cost index.

Table 5-3 shows a range of values for each cost figure, since the cost per unit of 

throughput will depend on the engine or process size and other factors. The lower ends of 

the cost ranges typically reflect larger engine or process sizes, and the higher ends of the 

cost ranges typically reflect smaller engine or process sizes. The table also shows the 
5-5

estimated cost effectiveness for each control measure, in terms of the cost per ton of 

emission reduction.

5.2 Factor 2 – Time Necessary for Compliance

Once a state decides to adopt a particular control strategy, up to 2 years will be needed to 

develop the necessary rules to implement the strategy. We have estimated that sources may then 

require up to a year to procure the necessary capital to purchase control equipment. The Institute 

of Clean Air Companies (ICAC) has estimated that approximately 13 months is required to 

design, fabricate, and install SCR or SNCR technology for NOX control.15 However, the time 

necessary will depend on the type and size of the unit being controlled. For instance, state 

regulators’ experience indicates that closer to 18 months is required to install this technology.16 

In the CAIR analysis, EPA estimated that approximately 30 months is required to design, build, 

and install SO2 scrubbing technology for a single emission source.

17

 The analysis also estimated 

that up to an additional 12 months may be required for staging the installation process if multiple 

sources are to be controlled at a single facility. Based on these figures, the total time required 

achieve emission reductions for natural gas processing facilities is estimated at a total of 61⁄2 

years.

5.3 Factor 3 – Energy and Other Impacts

Table 5-4 shows the estimated energy and non-air pollution impacts of control measures 

for sources at natural gas processing facilities. For gas-fired reciprocating engines and diesel 

engines, air-to-fuel-ratio adjustments and ignition retarding technologies have been found to 

increase fuel consumption by up to 5%, with a typical value of about 2.5%.18,19 This increased 

fuel consumption would result in increased CO2 emissions. LEC technology is not expected to 

increase fuel consumption; and may provide some fuel economy.18 

For turbines, water injection and steam injection would require electricity to operate 

pumps and ancillary equipment.13 Water injection would produce an increase in fuel 

consumption in order to evaporate the water, and steam injection would require energy to 

produce the steam. The increased electricity, steam, and fuel demands would produce additional 

CO2 emissions. 

Installation of SCR on any type of engine would cause a small increase in fuel 

consumption, about 0.5%, in order to force the exhaust gas through the catalyst bed. 18 This 

would produce an increase in CO2 emissions to generate the electricity. In addition, spent 

catalyst would have to be changed periodically, producing an increase in solid waste disposal. 13
Source Type Control Technology

Pollutant

controlled

Estimated

control

efficiency (%)

Estimated

capital cost

($/unit)

Estimated annual

cost ($/year

/unit) Units

Cost effectiveness

($/ton)

Refer‐

ences

Air‐fuel ratio adjustment NOX 10 ‐ 40 5.3 ‐ 42 0.9 ‐ 6.8 hp 68 ‐ 2,500 3,7

Ignition timing retard NOX 15 ‐ 30 na 1 ‐ 3 hp 42 ‐ 1,200 3,7

LEC retrofit NOX 80 ‐ 90 120 ‐ 820 30 ‐ 210 hp 320 ‐ 2,500 4,7

SCR NOX 90 100 ‐ 450 40 ‐ 270 hp 870 ‐ 31,000 7,8,12

NOX 90 ‐ 99 17 ‐ 35 3 ‐ 6 hp 16 ‐ 36 4

VOC 40 ‐ 85 1,500 ‐ 6,200 4

Overallb 16 ‐ 36

Replacement with electric

motors

allb 100 120 ‐ 140 38 ‐ 44 hp 100 ‐ 4,700 7

Water or steam injection NOX 68 ‐ 80 4.4 ‐ 16 2 ‐ 5 1000 Btu/hr 560 ‐ 3,100 6

Low‐NOX burnersc NOX 68 ‐ 84 8 ‐ 22 2.7 ‐ 8.5 1000 Btu/hr 5,200 ‐ 16,200 6

SCR NOX 90 13 ‐ 34 5.1 ‐ 13 1000 Btu/hr 1,000 ‐ 6,700 5,6

Water or steam injection

with SCR

NOX 93 ‐ 96 13 ‐ 34 5.1 ‐ 13 1000 Btu/hr 1,000 ‐ 6,700 6

Substitution of lower

sulfur fuel

SO2 up to 90 9,12

LNB NOX 40 3.8 ‐ 7.6 0.41 ‐ 0.81 1000 BTU 2,100 ‐ 2,800 13,14

ULNB NOX 75 ‐ 85 4.0 ‐ 13 0.43 ‐ 1.3 1000 BTU 1,500 ‐ 2,000 12,13,14

LNB and FGR NOX 48 16 1.7 1000 BTU 2,600 13,14

SNCR NOX 60 10 ‐ 22 1.1 ‐ 2.4 1000 BTU 4,700 ‐ 5,200 12,13,14

SCRd NOX 70 ‐ 90 33 ‐ 48 3.7 ‐ 5.6 1000 BTU 2,900 ‐ 6,700 12,13,14

LNB and SCR NOX 70 ‐ 90 37 ‐ 55 4 ‐ 6.3 1000 BTU 2,900 ‐ 6,300 12,13,14

LNB with OFA NOX 30 ‐ 50 500 ‐ 5,300 11,12

LNB, OFA, and FGR NOX 30 ‐ 50 500 ‐ 11,000 11,12

SNCR NOX 30 ‐ 75 400 ‐ 2,500 11,12

SCR NOX 40 ‐ 90 2,400 ‐ 7,200 11,12

Add or expand sulfur

recovery unit

NOX 90 ‐ 95 0.1 ‐ 1.1 28 ‐ 190 ton‐Sulfur/year 14 ‐ 95 9

Acid gas injection SO2 95 10

Additional recovery

stages

SO2 94 ‐ 96 0.1 ‐ 1 28 ‐ 150 ton‐Sulfur/year 14 ‐ 75 9

Tail gas treatment unit

(TGTU)

SO2 90 ‐ 99.5 0.3 ‐ 1.1 67 ‐ 190 ton‐Sulfur/year 33 ‐ 95 9

Spray dryer absorber SO2 80 ‐ 95 1,500‐1,900 12

Wet FGD SO2 90 ‐ 99 1,500 ‐ 1,800 11,12

Acid gas injection SO2 100 10

Glycol

dehydrators

Optimize glycol

circulation rate

VOC 33 ‐ 67 31 ‐ 170 5 ‐ 28 gal/hr 7

Table 5-3. Estimated Costs of Control for Natural Gas Processing

Flares

Sulfur recovery

units for amine

treatment units

Incinerators

Process heaters

Boilers

Turbines

b

For control measures reducing multiple pollutants, the overall cost‐effectiveness is the cost per total reduction of all pollutants.  However, EC, OC, and PM2.5

are components of PM10, and therefore are not added separately to the emission reduction total.

c

Costs estimates for low‐NOX burners for turbines reflect the incremental costs of new low‐NOX burners versus standard burners.  Retrofit costs for existing

burners were not available.

Reciprocating

engines, gas

d

SCR cost estimates for process heaters apply to mechanical draft heaters.  Natural draft heaters would have to be converted to mechanical draft for installation

of SCR.  This would increase both the capital and annualized costs of control by about 10%.

NSCRa

a

NSCR applies only to rich‐burn engines.  The distribution of emissions between rich‐burn and lean‐burn engines is not known.
Source Type Control Technology

Pollutant 

controlled

Electricity 

requirement 

(kW-hr)

Steam 

requirement 

(tons steam)

Solid waste 

produced (tons 

waste)

Wastewater 

produced (1000 

gallons)

Additional CO2 

emitted (tons)

Air-fuel ratio controllers NOX 2 - 10 a

Ignition timing retard NOX 4 - 7 a

LEC retrofit NOX 19 - 21 a

SCR NOX 21 0.5 0.008 0.43

NSCR NOX, VOC e 0.5 0.008 0.24

Replacement with 

electric motors

NOX 24 (100) 66,000 b

Water or steam injection NOX 4.4 - 5.2 a 31 8.1

Low-NOX burner (LNB) NOX 4.4 - 5.4 a

SCR NOX 5.8 0.45 0.026 1.7

Water or steam injection 

with SCR

NOX 6 0.45 0.026 1.7

Substitution of lower 

sulfur fuel

SO2 0 - 0.25

LNB NOX 0.2 a f

ULNB NOX 0.37 - 0.42 a f

LNB and FGR NOX 0.24 3,300 3.3

SNCR NOX 0.3 0.16 460 3.2

SCR NOX 0.35 - 0.45 8,400 0.073 8.4

LNB and SCR NOX 0.35 - 0.45 8,400 0.073 8.4

LNB with OFA NOX 0.1 - 0.17 a

LNB, OFA, and FGR NOX 0.1 - 0.17 3,300 3.3

SNCR NOX 0.1 - 0.25 0.16 460 3.2

SCR NOX 0.13 - 0.3 8,400 0.073 8.4

Add or expand sulfur 

recovery unit

SO2 up to 4.2 270 3.2 <0.01 1.1

Acid gas injection SO2 up to 4.2 d g

Additional recovery 

stages

SO2 6.1 - 6.3 270 3.2 <0.01 1.1

Tail gas treatment unit 

(TGTU) 

SO2 5.9 - 6.5 190 3.5 3.7 1.1

Spray dryer absorber SO2 0.62 - 0.74 400 1.1

Wet FGD SO2 0.7 - 0.77 1,100 3.1 3.7 2.6

Acid gas injection SO2 up to 0.78 d g

Glycol 

dehydrators

Optimize glycol 

circulation rate

VOC 0.11 - 0.22 a

NOTES:

Energy and non-air pollution impacts (per ton of emission reduced)

Boilers

a

The measure is expected to improve fuel efficiency.

b

CO2 from the generation of electricity would be offset by avoided emissions due to replacing the diesel engine

c

EPA has estimated that the control measures used to meet Tier 4 standards will be integrated into the engine design so that sacrifices in fuel economy will be negligible.

d

Some impact is expected but insufficient information is available to evaluate the impact.

blank indicates no impact is expected.

Flares

Incinerators

Turbines

f

Some designs of low-NOX burners and ultralow-NOX burners require the use of pressurized air supplies. This would require additional electricity to pressurize the combustion air.

g

Acid gas injection is also expected to result in sequestration of the CO2 present in the acid gas stream.

e

NSCR applies only to rich-burn engines. The distribution of emissions between rich-burn and lean-burn engines is not known.

Table 5-4. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Natural Gas Processing

Additional fuel 

requirement 

(%)

Reciprocating 

engines

Sulfur recovery 

units for gas 

sweetening units

Process heaters

Potential 

emission 

reduction (1000 

tons/year)
5-8

Sulfur recovery units require electricity and steam. Wet or dry scrubbers applied to 

incinerators and tail gas treatment units applied to sulfur recovery units would use electricity for 

the fan power needed to overcome the scrubber pressure drop. These systems would also 

produce solid waste, and wet scrubbers would produce wastewater which would require 

treatment. Injection of acid gases would require the consumption of fuel to compress the gases. 

However, this option would also result in the sequestration of CO2 present in the injected gas 

stream.10

Low-NOX burners for process heaters are expected to improve overall fuel efficiency. 

FGR would require additional electricity to recirculate the fuel gas into the heater. In SCR 

systems for process heaters, fans would be required to overcome the pressure drop through the 

catalyst bed. The fans would require electricity, with resultant increases in CO2 to generate the 

electricity. In addition, spent catalyst would have to be changed periodically, producing an 

increase in solid waste disposal. 13

5.4 Factor 4 – Remaining Equipment Life

Information was not available on the age of natural gas processing equipment in the 

WRAP region. The remaining lifetime of most equipment is expected to be longer than the 

projected lifetime of pollution control technologies which have been analyzed for this category. 

In the case of add-on technologies, the projected lifetime is 15 years. 

If the remaining life of an emission source is less than the projected lifetime of a 

pollution control device, then the capital cost of the control device would have to be amortized 

over a shorter period of time, corresponding to the remaining lifetime of the emission source. 

This would cause an increase in the amortized capital cost of the pollution control option, and a 

corresponding increase in the total annual cost of control. This increased cost can be quantified 

as follows:

where:

A1 = the annual cost of control for the shorter equipment lifetime ($)

A0 = the original annual cost estimate ($)

C = the capital cost of installing the control equipment ($)

r = the interest rate (0.07)

m = the expected remaining life of the emission source (years)

n = the projected lifetime of the pollution control equipment

5.5 References for Section 5

1. WRAP (2008), Emissions Data Management System, Western Regional Air Partnership, 

Denver, CO, http://www.wrapedms.org/app_main_dashboard.asp.
5-9

2. EPA (2006), SPECIATE version 4. U.S. EPA, RTP, NC,

http://www.epa.gov/ttn/chief/software/speciate/index.html.

3. EPA (1993), Alternative Control Techniques Document — NOX Emissions from 

Stationary Reciprocating Internal Combustion Engines, EPA-453/R-93-032, U.S. EPA, 

RTP, NC, Chapter 6.

4 . Edgerton, Stephen, Judy Lee-Greco, and Stephanie Walsh (2002), Stationary 

Reciprocating Internal Combustion Engines – Updated Information on NOX Emissions 

and Control Techniques, U.S. EPA, RTP, NC.

5. Nelson, Bradley (2009), Alternative Control Techniques Document: Stationary Diesel 

Engines, U.S. EPA, RTP, NC.

6. EPA (1993), Alternative Control Techniques Document — NOX Emissions from 

Stationary Gas Turbines, EPA-453/R-93-007, U.S. EPA, RTP, NC, Chapter 6.

7. Bar-Ilan, Amnon, Ron Friesen, Alison Pollack, and Abigail Hoats (2007), WRAP Area 

Source Emissions Inventory Protection and Control Strategy Evaluation - Phase II, 

Western Governor's Association, Denver, CO, Chapter 4.

8. Alpha-Gamma Technologies, Inc. (2006), Control Technologies for Internal Combustion

Engines, Docket Number EPA-HQ-OAR-2005-0030-0054.

9. Research Triangle Institute (1972), Control Technology for Sulfur Oxide Pollutants, 2nd 

ed, Appendix B: Sulfur Emission Factors and Control Costs for Petroleum Refineries,

Prepared for the U.S. EPA, RTP, NC,

http://yosemite.epa.gov/ee/epa/eermfile.nsf/vwAN/EE-0233-05.pdf/$File/EE-0233-

05.pdf.

10. EPA (2008), Press release: EPA reaches agreement with Merit Energy and Shell on 

clean-air violations, contact: William Omohundro, U.S. EPA, Chicago, IL.

11. E.H. Pechan & Associates (2005), AirControlNET, Version 4.1 - Documentation Report, 

U.S. EPA, RTP, NC

12. NACAA (formerly STAPPA and ALAPCO) (2006), Controlling Fine Particulate Matter 

Under the Clean Air Act: A Menu of Options, National Association of Clean Air 

Agencies.

13. EPA (1993), Alternative Control Techniques Document— NOX Emissions from Process 

Heaters (Revised), EPA-453/R-93-034, U.S. EPA, RTP, NC, pp 6-14 thru 6-36.

14. MRPO (2006), Interim White Paper - Midwest RPO Candidate Control Measures Source 

Category: Petroleum Refining, http://www.ladco.org/reports/control/white_papers/.

15 . Institute of Clean Air Companies (2006), Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial Sources.
5-10

16 . Ghoreishi, Farrokh (2007), Time required to install add-on control measures for NOX,

Personal communication, Wisconsin Department of Natural Resources, April 27. 

17. EPA (2005), Boilermaker Labor Analysis and Installation Timing – Technical Support 

Document for the Final Clean Air Interstate Rule, OAR-2003-0053, U.S. EPA,

Washington, DC, www.epa.gov/cair/technical.html#final.

18. Reference 3, Page 7-12.

19. Center for Alternative Fuels, Engines & Emissions (2005), Alice Austen Ferry Emissions 

Tests, M.J. Bradley & Associates, Manchester, NH, Page 13.
6-1

6. Industrial Boilers

Industrial boilers encompass the category of boilers used in manufacturing, processing, 

mining, and refining or any other industry to provide steam, hot water, and/or electricity. There 

are no specific size definitions for an industrial boiler, however for the purposes of this 

document, the definition described in Subpart Db of 40 CFR Part 60, New Source Performance 

Standards (NSPS) for Industrial, Commercial, and Institutional Steam Generating Units will be 

used. This NSPS regulates steam generating units with a heat input capacity between 100 to 250 

MMBtu/hr (29 - 73 MW). Steam generating units greater than 250 MMBtu/hr (73 MW) are 

subject to the requirements of Subpart D of 40 CFR Part 60. 

An industrial boiler report

1

estimated that there are approximately 43,000 industrial 

boilers operating in the U.S. with an aggregate capacity of 1.5 million MMBtu/hr input. The 

report noted that approximately half of these industrial boilers are less than 10 MMBtu/hr in size, 

but account for only 7% of the total capacity. The 2002 WRAP stationary point source 

emissions tables2lists a total of 2,171 facilities with industrial boilers in the 102XXX Source 

Classification Code (SCC). The majority of the boilers are located at facilities in the food, paper, 

chemicals, refining and primary metals industries. The most common fuel used for combustion 

is natural gas with nearly 73% of the facilities in the WRAP region operating natural gas-fired

industrial boilers.

Industrial boilers in the WRAP region are estimated to emit about 43,060 tons of NOX

and 28,155 tons of SO2, based on the 2002 emissions inventory for the region.3 These boilers 

utilize the combustion of fuel which includes; coal, oil, natural gas, waste, and wood, to produce 

steam. Coal-fired industrial boilers comprise of 15,920 tons of NOX, or 37% of the total NOX

emissions, and 14,376 tons, or 51% of the total SO2 emissions from industrial boilers in the 

WRAP region. Industrial boilers represent about 4.1% of the total point source emissions of 

NOX, and about 3.4% of the total SO2 point source emissions in the WRAP region. 

Table 6-1 shows estimated emissions of NOX, SO2, PM10, PM2.5, and VOC from the 

WRAP emissions inventory, broken down by state and fuel. The table shows that PM10, PM2.5,

and VOC emissions from industrial boilers are significantly lower than the NOX and SO2

emissions. Emissions of PM from these sources were not included in the inventory, but are 

expected to be much lower than the NOX and SO2 emissions. As the table shows, coal-fired 

boilers were the most significant source of NOX, SO2, and VOC emissions in the WRAP region. 

For NOX, coal fired boilers accounted for about 56% of the emissions from point sources, and 

41% of the total stationary source emissions in the WRAP region. 

Table 6-2a lists potential control measures for NOX, SO2, PM10, PM2.5, EC, and OC

emissions from coal-fired and oil-fired industrial boilers. Table 6-2b presents control options for 

natural gas boilers, and Table 6-2c provides control options for wood-fired industrial boilers for 

each of these pollutants. Uncontrolled emission rates were obtained from the respective AP-42 

section for each of the fuels.4 Control technology options were identified using information from 
6-2

industrial boiler control option studies.5 The control options were divided into appropriate 

control technologies for each of the four fuels; coal, oil, natural gas, and wood. 

Table 6-2d lists potential control options for NOX, SO2, PM10, PM2.5, EC, and OC coalfired and oil-fired industrial boilers by age. These pollutants are regulated under the Clean Air 

Act (CAA) to attain and maintain National Ambient Air Quality Standards (NAAQS), reduce 

acidic deposition, and improve visibility under regional haze regulations. To attain and maintain 

the NAAQS, the EPA enacted the Prevention of Significant Deterioration (PSD) regulations to 

establish maximum pollution concentration levels to protect public health and welfare from 

harmful levels of pollutants. The PSD regulations require new major sources or major 

modifications at existing sources to install "Best Available Control Technology (BACT)” and 

conduct ambient air quality analyses to show that the new source or modification will not cause 

or contribute to a violation of any applicable NAAQS or PSD increment. Because PSD 

requirements are on a case-by-case basis, the age groups were segregated into using the New 

Source Performance Standards (NSPS) to show control options and emission levels for coal-fired 

and oil-fired industrial boilers. The age groups are designated as pre-NSPS, post-NSPS, and post 

CAA amendments of 1990.
6-3

Emission source A K A Z CA CO I D M T ND NM N V OR S D U T WA WY Tribes Total

Coal-fired Boilers 1,823 0 1,366 336 3,268 366 1,264 0 0 0 0 2,412 49 5,036 0 15,920

Natural gas-fired Boilers 260 786 5,555 2,706 1,184 726 140 764 114 370 224 764 2,435 685 26 16,740

Oil-fired Boilers 67 7 86 44 4 2 118 0 0 26 4 1 0 7 8 478 5 10 1,004

Waste-fired Boilers 0 0 49 0 480 214 9 4 0 0 1 0 0 72 0 0 910

Wood-fired Boilers 0 0 2,089 7 349 1,999 0 0 0 7 0 89 0 2,988 1 0 525 8,126

Total 2,150 793 9,145 3,093 5,323 3,424 1,498 765 140 481 313 3,255 6,022 5,736 561 42,700

Coal-fired Boilers 1,421 0 139 24 2,976 128 1,284 0 0 0 0 2,831 62 5,511 0 14,376

Natural gas-fired Boilers 7 5,668 969 138 6 1 3 9 11 2 497 435 1,113 544 0 9,403

Oil-fired Boilers 55 6 127 25 113 1,241 0 3 77 234 0 5 2 1,444 1 14 3,391

Waste-fired Boilers 0 0 2 0 8 46 1 4 0 0 1 6 0 0 5 0 0 91

Wood-fired Boilers 0 0 161 0 7 54 0 0 0 3 6 0 622 2 33 887

Total 1,483 5,674 1,396 187 3,109 1,470 1,301 12 89 255 503 3,319 3,245 6,058 47 28,147

Coal-fired Boilers 0 19 37 7 468 36 1 2 0 0 100 0 100 0 581 0 1,361

Natural gas-fired Boilers 11 5 82 22 1 4 2 2 8 5 1 3 3 1 3 19 7 0 207

Oil-fired Boilers 2 2 16 3 4 54 0 0 77 2 6 0 1 223 7 9 0 488

Waste-fired Boilers 0 0 0 0 4 4 136 0 0 0 3 3 0 0 25 0 0 238

Wood-fired Boilers 0 0 671 6 4 1 267 0 0 0 2,025 75 0 1,035 0 0 4,119

Total 13 26 806 38 571 495 1 4 8 82 2,196 79 115 1,302 667 0 6,413

Coal-fired Boilers 0 3 28 1 255 27 2 0 0 6 3 0 4 3 0 123 0 543

Natural gas-fired Boilers 10 4 78 22 1 2 2 2 7 4 1 2 3 1 0 17 6 0 190

Oil-fired Boilers 2 1 14 3 3 45 0 0 49 2 0 1 149 4 9 0 318

Waste-fired Boilers 0 0 0 0 2 83 0 0 0 2 7 0 0 25 0 0 136

Wood-fired Boilers 0 0 625 4 4 1 229 0 0 0 1,776 12 0 646 0 0 3,333

Total 12 8 745 29 312 386 3 7 53 1,880 15 5 5 837 178 0 4,520

Coal-fired Boilers 6 0 3 4 3 1 0 9 0 0 0 0 1 2 0 1 0 0 76

Natural gas-fired Boilers 11 205 316 193 4 4 14 5 33 15 1 1 15 3 9 80 1 9 1 1,001

Oil-fired Boilers 3 0 2 1 1 0 0 0 9 1 0 1 9 1 0 28

Waste-fired Boilers 0 0 5 0 116 59 3 1 0 0 0 0 0 62 0 0 273

Wood-fired Boilers 0 0 373 0 1 5 511 0 0 0 2 3 47 0 284 0 110 1,363

Total 21 205 697 198 208 583 4 6 33 24 3 5 62 5 3 435 3 0 111 2,741

NOX emissions (tons/year)

S O 2 emissions (tons/year)

VOC emissions (tons/year)

Table 6-1. Emissions from Industrial Boilers in the WRAP Region

P M 10 emissions (tons/year)

P M 2.5 emissions (tons/year)
6-4

Source Type

Pollutant 

controlled Control Technology

Uncontrolled 

emissions1,2 

(lb/MMBtu)

Estimated 

control 

efficiency 

(%)

Potential 

controlled 

emissions 

(lb/MMBtu) References

LNB 1.3 50 0.63 4, 5, 7, 9

LNB w/OFA 1.3 50 - 65 0.63 - 0.46 4, 5, 7, 9

SNCR 1.3 30 - 75 0.91 - 0.33 4, 5, 7, 9

SCR 1.3 40 - 90 0.78 - 0.13 4, 5, 7, 9

Physical coal cleaning 1.3 10 - 40 1.2 - 0.78 4, 5, 8, 9

Chemical coal cleaning 1.3 50 - 85 0.63 - 0.20 4, 5, 8, 9

Use lower sulfur fuel 1.3 20 - 90 1.0 - 0.13 4, 5, 8, 9

Dry sorbent injection 1.3 50 - 90 0.63 - 0.13 4, 5, 8, 9

Spray dryer absorber 1.3 90 0.13 4, 5, 8, 9

Wet FGD 1.3 90 0.13 4, 5, 8, 9

Fabric filter 1.5 99.3 0.011 4, 5, 9

ESP 1.5 99.3 0.011 4, 5, 9

LNB 0.34 40 0.20 4, 5, 7, 9

LNB w/ OFA 0.34 30 - 50 0.24 - 0.17 4, 5, 7, 9

LNB w/ OFA and FGR 0.34 30 - 50 0.24 - 0.17 4, 5, 7, 9

SNCR 0.34 30 - 75 0.24 - 0.085 4, 5, 7, 9

SCR 0.34 40 - 90 0.20 - 0.034 4, 5, 7, 9

Use lower sulfur fuel 0.67 20 - 90 0.54 - 0.067 4, 5, 8, 9

Spray dryer absorber 0.67 90 0.067 4, 5, 8, 9

Wet FGD 0.67 90 0.067 4, 5, 8, 9

Fabric filter 0.044 95.8 0.0018 4, 5, 9

ESP 0.044 95.8 0.0018 4, 5, 9

1

 Uncontrolled coal-fired emission rates calculated using AP-42 emission factors for PC, dry bottom, wall-fired, 

bituminous Pre-NSPS. The emission factor was converted to lb/MMBtu assuming MT coal with a heat rate of 

17.5 MMBtu/ton, a sulfur content of 0.62 weight percent sulfur, and an ash content of 11.5 percent.

2

 Uncontrolled oil-fired emission rates calculated using AP-42 emission factors for No. 6 oil fired, normal firing.

The emission factor was converted to lb/MMBtu assuming a distillate oil heat content of 140,000 Btu/gal, and 

a sulfur content of 0.60 weight percent sulfur.

PM2.5, PM10, 

EC, OC 

Coal-fired

Table 6-2a. Control Options for Coal-Fired and Oil-Fired Industrial Boilers

Oil-fired

N OX

SO2

PM2.5, PM10, 

EC, OC 

N OX

SO2
6-5

Source Type

Pollutant 

controlled Control Technology

Uncontrolled 

emissions1 

(lb/MMBtu)

Estimated 

control 

efficiency (%)

Potential 

controlled 

emissions 

(lb/MMBtu) References

LNB 0.27 40 0.16 4, 5, 7, 9

LNB w/ OFA 0.27 40 - 60 0.11 - 0.16 4, 5, 7, 9

LNB w/ OFA and FGR 0.27 40 - 80 0.05 - 0.16 4, 5, 7, 9

SNCR 0.27 30 - 75 0.19 - 0.07 4, 5, 7, 9

SCR 0.27 70 - 90 0.08 - 0.03 4, 5, 7, 9

1

 Uncontrolled natural gas-fired emission rates calculated using AP-42 emission factors for Large Wall-Fired Boilers,

>100 MMBtu/hr, Uncontrolled (Pre-NSPS).

Natural gasfired

N OX

Table 6-2b. Control Options for Industrial Natural Gas-Fired Boilers

Source Type

Pollutant 

controlled Control Technology

Uncontrolled 

emissions1 

(lb/MMBtu)

Estimated 

control 

efficiency (%)

Potential 

controlled 

emissions 

(lb/MMBtu) References

SNCR 0.49 30 - 75 0.12 - 0.34 4, 5, 7, 9

SCR 0.49 40 - 90 0.05 - 0.29 4, 5, 7, 9

Fabric filter 0.36 95.8 0.015 4, 5, 9

ESP 0.36 95.8 0.015 4, 5, 9

1

 Uncontrolled wood-fired emission rates calculated using AP-42 emission factors for uncontrolled dry wood combustion.

Wood-fired

Table 6-2c. Control Options for Industrial Wood-Fired Boilers

PM2.5, PM10 

N OX
6-6

Source Type

Pollutant 

controlled Control Technology

Uncontrolled 

emissions1,2 

(lb/MMBtu)

Estimated 

control 

efficiency (%)

Potential 

controlled 

emissions 

(lb/MMBtu) References

LNB 1.3 50 0.63 4, 5, 7, 9

LNB w/OFA 1.3 50 - 65 0.63 - 0.46 4, 5, 7, 9

SNCR 1.3 30 - 75 0.91 - 0.33 4, 5, 7, 9

SCR 1.3 40 - 90 0.78 - 0.13 4, 5, 7, 9

Physical coal cleaning 1.3 10 - 40 1.2 - 0.78 4, 5, 8, 9

Chemical coal cleaning 1.3 50 - 85 0.63 - 0.20 4, 5, 8, 9

Use lower sulfur fuel 1.3 20 - 90 1.0 - 0.13 4, 5, 8, 9

Dry sorbent injection 1.3 50 - 90 0.63 - 0.13 4, 5, 8, 9

Spray dryer absorber 1.3 90 0.13 4, 5, 8, 9

Wet FGD 1.3 90 0.13 4, 5, 8, 9

Fabric filter 1.5 99.3 0.011 4, 5, 9

ESP 1.5 99.3 0.011 4, 5, 9

LNB 0.34 40 0.20 4, 5, 7, 9

LNB w/ OFA 0.34 30 - 50 0.24 - 0.17 4, 5, 7, 9

LNB w/ OFA and FGR 0.34 30 - 50 0.24 - 0.17 4, 5, 7, 9

SNCR 0.34 30 - 75 0.24 - 0.085 4, 5, 7, 9

SCR 0.34 40 - 90 0.20 - 0.034 4, 5, 7, 9

Use lower sulfur fuel 0.67 20 - 90 0.54 - 0.067 4, 5, 8, 9

Spray dryer absorber 0.67 90 0.067 4, 5, 8, 9

Wet FGD 0.67 90 0.067 4, 5, 8, 9

Fabric filter 0.044 95.8 0.0018 4, 5, 9

ESP 0.044 95.8 0.0018 4, 5, 9

LNB 0.69 50 0.34 4, 5, 7, 9

LNB w/OFA 0.69 50 - 65 0.34 - 0.24 4, 5, 7, 9

SNCR 0.69 30 - 75 0.48 - 0.17 4, 5, 7, 9

SCR 0.69 40 - 90 0.41 - 0.069 4, 5, 7, 9

Physical coal cleaning 1.3 10 - 40 1.2 - 0.78 4, 5, 8, 9

Chemical coal cleaning 1.3 50 - 85 0.63 - 0.20 4, 5, 8, 9

Use lower sulfur fuel 1.3 20 - 90 1.0 - 0.13 4, 5, 8, 9

Dry sorbent injection 1.3 50 - 90 0.63 - 0.13 4, 5, 8, 9

Spray dryer absorber 1.3 90 0.13 4, 5, 8, 9

Wet FGD 1.3 90 0.13 4, 5, 8, 9

Fabric filter 1.5 99.3 0.011 4, 5, 9

ESP 1.5 99.3 0.011 4, 5, 8

LNB 0.34 40 0.20 4, 5, 7, 9

LNB w/ OFA 0.34 30 - 50 0.24 - 0.17 4, 5, 7, 9

LNB w/ OFA and FGR 0.34 30 - 50 0.24 - 0.17 4, 5, 7, 9

SNCR 0.34 30 - 75 0.24 - 0.085 4, 5, 7, 9

SCR 0.34 40 - 90 0.20 - 0.034 4, 5, 7, 9

Use lower sulfur fuel 0.67 20 - 90 0.54 - 0.067 4, 5, 8, 9

Spray dryer absorber 0.67 90 0.067 4, 5, 8, 9

Wet FGD 0.67 90 0.067 4, 5, 8, 9

Fabric filter 0.044 95.8 0.0018 4, 5, 9

ESP 0.044 95.8 0.0018 4, 5, 9

Table 6-2d. Control Options for Industrial Coal-Fired and Oil-Fired Boilers

Coal-fired (Pre 

PSD Regulations)1

N OX

SO2

PM2.5, PM10, 

EC, OC 

Oil-fired (Pre PSD 

Regulations)2

N OX

SO2

PM2.5, PM10, 

EC, OC 

Coal-fired (Post 

PSD Regulations)3

N OX

SO2

PM2.5, PM10, 

EC, OC 

Oil-fired (Post 

PSD Regulations)4

N OX

SO2

PM2.5, PM10, 

EC, OC 
6-7

Source Type

Pollutant 

controlled Control Technology

Uncontrolled 

emissions1,2 

(lb/MMBtu)

Estimated 

control 

efficiency (%)

Potential 

controlled 

emissions 

(lb/MMBtu) References

LNB 0.50 50 0.25 4, 5, 7, 9

LNB w/OFA 0.50 50 - 65 0.25 - 0.18 4, 5, 7, 9

SNCR 0.50 30 - 75 0.35 - 0.13 4, 5, 7, 9

SCR 0.50 40 - 90 0.30 - 0.050 4, 5, 7, 9

Physical coal cleaning 0.20 10 - 40 0.18 - 0.12 4, 5, 8, 9

Chemical coal cleaning 0.20 50 - 85 0.10 - 0.030 4, 5, 8, 9

Use lower sulfur fuel 0.20 20 - 90 0.16 - 0.020 4, 5, 8, 9

Dry sorbent injection 0.20 50 - 90 0.10 - 0.020 4, 5, 8, 9

Spray dryer absorber 0.20 90 0.02 4, 5, 8, 9

Wet FGD 0.20 90 0.02 4, 5, 8, 9

Fabric filter 0.05 99.3 0.00035 4, 5, 9

ESP 0.05 99.3 0.00035 4, 5, 9

LNB 0.20 40 0.12 4, 5, 7, 9

LNB w/ OFA 0.20 30 - 50 0.14 - 0.10 4, 5, 7, 9

LNB w/ OFA and FGR 0.20 30 - 50 0.14 - 0.10 4, 5, 7, 9

SNCR 0.20 30 - 75 0.14 - 0.050 4, 5, 7, 9

SCR 0.20 40 - 90 0.12 - 0.020 4, 5, 7, 9

Use lower sulfur fuel 0.50 20 - 90 0.40 - 0.005 4, 5, 8, 9

Spray dryer absorber 0.50 90 0.050 4, 5, 8, 9

Wet FGD 0.50 90 0.050 4, 5, 8, 9

Fabric filter 0.044 95.8 0.0018 4, 5, 9

ESP 0.044 95.8 0.0018 4, 5, 9

1

 Uncontrolled coal-fired emission rates calculated using AP-42 emission factors for PC, dry bottom, wall-fired, bituminous

Pre-NSPS. The emission factor was converted to lb/MMBtu assuming MT coal with a heat rate of 17.5 MMBtu/ton, a sulfur

content of 0.62 weight percent sulfur, and an ash content of 11.5 percent.

2

 Uncontrolled oil-fired emission rates calculated using AP-42 emission factors for No. 6 oil fired, normal firing.

The emission factor was converted to lb/MMBtu assuming a distillate oil heat content of 140,000 Btu/gal, and a sulfur

content of 0.60 weight percent sulfur.

3

 Uncontrolled coal-fired emission rates calculated using AP-42 emission factors for PC, dry bottom, wall-fired, bituminous

Post-NSPS. The emission factor was converted to lb/MMBtu assuming MT coal with a heat rate of 17.5 MMBtu/ton, a sulfur

content of 0.62 weight percent sulfur, and an ash content of 11.5 percent.

4

 Uncontrolled oil-fired emission rates calculated using AP-42 emission factors for No. 6 oil fired, normal firing.

The emission factor was converted to lb/MMBtu assuming a distillate oil heat content of 140,000 Btu/gal, and a sulfur

content of 0.60 weight percent sulfur.

5

 Uncontrolled Coal fired and oil-fired emission rates are base the the 40 CFR 60, Subpart Db limits for each of the fuels.

Table 6-2d. Control Options for Industrial Coal-Fired and Oil-Fired Boilers (cont.)

Coal-fired (Post 

Clean Air Act 

Amendments of 

1990)5

N OX

SO2

PM2.5, PM10, 

EC, OC 

Oil-fired (Post 

Clean Air Act 

Amendments of 

1990)5

N OX

SO2

PM2.5, PM10, 

EC, OC 
6-8

6.1 Factor 1 – Costs

Table 6-3 provides cost estimates for the emission control options which have been 

identified for each of the industrial boilers. For each option, the table gives an estimate of the 

capital cost to install the necessary equipment, and the total annual cost of control, including the 

amortized cost associated with the capital equipment cost. The capital cost values are expressed 

in terms of the cost per heat input (MMBtu/hr) to the boiler. The annual cost is presented in 

millions of dollars per year. The table shows a range of values for each cost figure, since the 

capital cost will depend on the rated heat input to the boiler and other factors. The lower ends of 

the capital and annual cost ranges typically reflect smaller sized boilers, and the higher ends of 

the capital and annual cost ranges reflect larger sized boilers. Table 3-3 also shows the estimated 

cost effectiveness for each control measure, in terms of the cost per ton of emission reduction. 

Lower cost effectiveness values generally reflect the larger heat input boiler sizes, whereas 

higher cost effectiveness values reflect lower heat input boilers sizes.

6.2 Factor 2 – Time Necessary for Compliance

Once a state decides to adopt a particular control strategy, up to 2 years will be needed to 

develop the necessary rules to implement the strategy. We have estimated that sources may then 

require up to a year to procure the necessary capital to purchase control equipment. The Institute 

of Clean Air Companies (ICAC) has estimated that approximately 18 months is required to 

design, fabricate, and install SCR or SNCR technology for NOX control, and approximately 30 

months to design, build, and install SO2 scrubbing technology.

9

 Additional time of up to 12 

months may be required for staging the installation process if multiple boilers are to be 

controlled at a single facility. Based on these figures, the total time required to achieve emission 

reductions for industrial boilers is estimated at a total of 51⁄2 years for NOX strategies, and 61⁄2 

years for SO2 strategies.

6.3 Factor 3 – Energy and Other Impacts

Table 6-4 shows the estimated energy and non-air pollution impacts of control measures 

for industrial boilers. The values were obtained from a report summarizing the applicability and 

feasibility of control options for industrial boilers.8 In general, the combustion modification 

technologies (LNB, OFA, FGR) do not require steam or generate solid waste, wastewater, or 

additional CO2. They also do not require additional fuel to operate, and in some cases may 

decrease fuel usage because of the optimized combustion of the fuel.

Retrofitting of a SNCR requires energy for compressor power and steam for mixing. 

This would produce a small increase in CO2 emissions to generate electricity; however the 

technology itself does not produce additional CO2 emissions. 

Installation of SCR on an industrial boiler is not expected to increase fuel consumption. 

However additional energy is required to operate the SCR, which will produce an increase in 

CO2 emissions to generate the electricity. In addition, spent catalyst would have to be changed 

periodically, producing an increase in solid waste disposal.
6-9

Source Type Control Technology

Pollutant 

controlled

Estimated 

control 

efficiency 

(%)

Estimated 

capital cost 

($/MMBtu/hr)

Estimated 

annual cost 

($M)

Cost 

effectiveness 

($/ton) References

LNB 50 3,435 - 6,856 0.175 - 0.317 344 - 4,080 5, 7, 9

LNB w/OFA 50 - 65 4,908 - 9,794 N A 412 - 4,611 5, 7, 9

SNCR 30 - 75 3,550 - 7,083 0.333 - 0.419 1,728 - 6,685 5, 7, 9

SCR 40 - 90 9,817 - 19,587 0.738 - 1.32 1,178 - 7,968 5, 7, 9

Physical coal cleaning 10 - 40 N A N A 70 - 563 5, 8, 9

Chemical coal cleaning 50 - 85 N A N A 1,699 - 2,561 5, 8, 9

Use lower sulfur fuel 20 - 90 N A N A 5, 8, 9

Dry sorbent injection 50 - 90 11,633 - 36,096 N A 851 - 5,761 5, 8, 9

Spray dryer absorber 90 27,272 - 73,549 7.93 - 9.26 3,885 - 8,317 5, 8, 9

Wet FGD 90 40,203 - 86,410 10.10 - 11.71 4,687 - 10,040 5, 8, 9

Fabric filter 99.3 20,065 - 30,287 0.82 - 1.39 406 - 592 5, 6, 9

ESP 99.3 17,037 - 24,293 0.66 - 1.17 342 - 485 5, 6, 9

LNB 40 1,205 - 2,405 0.190 - 0.346 412 - 7,075 5, 7, 9

LNB w/ OFA 30 - 50 1,722 - 3,435 N A 412 - 7,075 5, 7, 9

LNB w/ OFA and FGR 30 - 50 2,690 - 5,368 N A 439 - 6,689 5, 7, 9

SNCR 30 - 75 2,840 - 5,666 0.206 - 0.355 1,997 - 9,952 5, 7, 9

SCR 40 - 90 5,399 - 10,773 0.484 - 0.831 1,022 - 24,944 5, 7, 9

Use lower sulfur fuel 20 - 90 N A N A 5611 5, 8, 9

Spray dryer absorber 90 119,731 - 270,514 7.72 - 8.80 4,947 - 10,887 5, 8, 9

Wet FGD 90 36,930 - 73,660 9.85 - 11.29 6,008 - 13,156 5, 8, 9

Fabric filter 95.8 17,205 - 26,291 0.72 - 1.20 7,298 - 10,889 5, 6, 9

ESP 95.8 14,302 - 21,243 0.58 - 0.98 5,983 - 8,844 5, 6, 9

LNB 40 1,205 - 2,405 0.190 - 0.346 412 - 7,075 5, 7, 9

LNB w/ OFA 40 - 60 1,722 - 3,435 N A 412 - 7,075 5, 7, 9

LNB w/ OFA and FGR 40 - 80 2,690 - 5,368 N A 439 - 6,689 5, 7, 9

SNCR 30 - 75 2,840 - 5,666 0.206 - 0.355 1,997 - 9,952 5, 7, 9

SCR 70 - 90 5,399 - 10,773 0.484 - 0.831 1,022 - 24,944 5, 7, 9

SNCR 30 - 75 2,840 - 5,666 0.206 - 0.355 1,997 - 9,952 5, 7, 9

SCR 40 - 90 5,399 - 10,773 0.484 - 0.831 1,022 - 24,944 5, 7, 9

Fabric filter 95.8 17,205 - 26,291 0.72 - 1.20 7,298 - 10,889 5, 6, 9

ESP 95.8 14,302 - 21,243 0.58 - 0.98 5,983 - 8,844 5, 6, 9

NA - Control cost not available.

Annual cost assumes 7.5% interest rate and 15-year project life.

Capital and annual costs are presented in 2007 dollars.

Table 6-3. Estimated Costs of Control for Industrial Boilers

N OX

SO2

PM2.5, PM10 

N OX

SO2

Natural gasfired

N OX

Wood-fired N OX

PM2.5, PM10 

Coal-fired

Oil-fired

PM2.5, PM10 
6-10

Source Type Control Technology

Pollutant 

controlled

Electricity 

requirement

Steam 

requirement

Solid waste 

produced

Wastewater 

produced

Additional CO2 

emitted

LNB NOX

LNB w/OFA NOX

SNCR NOX 1 - 2 kW/1000 

acfm

0.25

SCR NOX 0.89 0.25 0.021

Physical coal cleaning SO2

Chemical coal cleaning SO2

Switch to lower sulfur 

fuel

SO2

Dry sorbent injection SO2 2 - 4 kW/1000 

acfm

0.25 0.021

Spray dryer absorber SO2 0.4 3.7 0.69

Wet FGD SO2 4 - 8 kW/1000 

acfm

Fabric filter PM2.5, PM10 1 - 2 kW/1000 

acfm

ESP PM2.5, PM10 0.5 - 1.5 

kW/1000 acfm

LNB NOX

LNB w/ OFA NOX

LNB w/ OFA and FGR NOX 6.4

SNCR NOX 1 - 2 kW/1000 

acfm

0.25

SCR NOX 0.89 0.25 0.021

Switch to lower sulfur 

fuel

SO2

Spray dryer absorber SO2 0.4 3.7 0.69

Wet FGD SO2 4 - 8 kW/1000 

acfm

Fabric filter PM2.5, PM10 1 - 2 kW/1000 

acfm

ESP PM2.5, PM10 0.5 - 1.5 

kW/1000 acfm

LNB NOX

LNB w/ OFA NOX

LNB w/ OFA and FGR NOX 6.4

SNCR NOX 1 - 2 kW/1000 

acfm

0.25

SCR NOX 0.89 0.25 0.021

Water injection NOX

LNB w/ OFA NOX

LNB w/ OFA and FGR NOX 6.4

ULNB NOX

SNCR NOX 1 - 2 kW/1000 

acfm

0.25

SCR NOX 0.89 0.25 0.021

Fabric filter PM2.5, PM10 1 - 2 kW/1000 

acfm

ESP PM2.5, PM10 0.5 - 1.5 

kW/1000 acfm

NOTES:

A blank cell indicates no impact is expected.

Natural gas-fired

Wood-fired

Table 6-4. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Industrial 

Boilers

Energy and non-air pollution impacts (per ton of emission reduced)

Coal-fired

Oil-fired
6-11

For SO2 control technologies, energy is required material preparation (e.g., grinding), materials 

handling (e.g., pumps/blowers), flue gas pressure loss, and steam requirements. Power 

consumption is also affected by the reagent utilization of the control technology, which also 

affects the control efficiency of the control technology.

PM control technologies require energy to operate compressors, heaters, and ash 

handling. In addition, an additional fan may be required to reduce the flue gas pressure loss by 

the ESP or FF. The ESP also requires energy to operate the transformer-rectifier. These energy 

requirements will produce an increase in CO2 emissions to generate the required electricity.

6.4 Factor 4 – Remaining Equipment Life

Similar to Electric Generating Units (EGUs), industrial boilers do not have a set 

equipment life. Since many of the strategies are market-based reductions applied to geographic 

regions, it is assumed that control technologies will not be applied to units that are expected to be 

retired prior to the amortization period for the specific control equipment. Therefore, the 

remaining life of an industrial boiler is not expected to affect the cost of control technologies for 

industrial boilers.
6-12

6.5 References for Section 6

1. Energy and Environmental Analysis (2005), Characterization of the U.S. 

Industrial/Commercial Boiler Population. 

http://www.icfi.com/markets/energy/doc_files/eea-boiler-population.pdf

2. WRAP (2008), Stationary Sources Joint Forum, Western Regional Air Partnership, 

Denver, CO. http://www.wrapair.org/forums/ssjf/pivot.html

3. WRAP (2008), Emissions Data Management System, Western Regional Air Partnership, 

Denver, CO. http://www.wrapedms.org/app_main_dashboard.asp

4. AP 42, Fifth Edition, Volume I, Chapter 1: External Combustion Sources. 

http://www.epa.gov/ttn/chief/ap42/ch01/index.html

5. MRPO (2006), Interim White Paper - Midwest RPO Candidate Control Measures Source 

Category: Industrial, Commercial, and Institutional (ICI) Boilers.

http://www.ladco.org/reports/control/white_papers/

6. STAPPA and ALAPCO (2006), Controlling Fine Particulate Matter Under the Clean Air 

Act: a Menu of Options. (March 2006) Prepared by the State and Territorial Air Pollution 

Program Administrators and Association of Local Air Pollution Control Officials.

7. Khan, Sikander (2003), Methodology, Assumptions, and References: Preliminary NOX

Controls Cost Estimates for Industrial Boilers.

8. Khan, Sikander (2003), Methodology, Assumptions, and References: Preliminary SO2

Controls Cost Estimates for Industrial Boilers.

9. NESCAUM (2009), Applicability and Feasibility of NOX, SO2, and PM Emission Control 

Technologies for Industrial, Commercial, and Institutional (ICI) Boilers.

10. Institute of Clean Air Companies (2006), Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial Sources.
7-1

7. Cement Kilns

The main emission units of interest at cement plants are the cement kilns. There are two 

major types, wet and dry kilns; dry kilns are further categorized as long dry, preheater, or 

precalciner kilns. On the whole, wet kilns tend to produce more tons of cement (or “clinker”) 

but also require more energy than dry process kilns. There was limited information on SO2

controls for cement kilns, particularly for long wet kilns.

1

 Process modification and replacement 

of a wet kiln with a dry process kiln are the most feasible options for SO2 control. 

Cement kilns at cement manufacturing facilities in the WRAP region are estimated to 

emit about 40,610 tons of NOX; 6,230 tons of SO2; 1,573 tons of PM2.5; 4,245 tons of PM10 and 

4,467 tons of VOC per year, based on the 2002 emissions inventory for the region and WRAP 

updates.

2

 Most of the emissions from this category are from the kilns themselves; the remainder 

of the emissions is generated primarily from the transfer of clinker and the grinding and drying 

of the raw material. NOX emissions from cement kilns represent approximately 4% of total point 

source emissions of NOX in the WRAP region, and approximately 3% of all stationary source 

(point and area source) NOX emissions in the region. SO2 emissions from cement kilns represent 

approximately 0.75% of total point source emissions of SO2 in the WRAP region, and 

approximately 0.68% of all stationary source (point and area source) SO2 emissions in the 

region.

Table 7-1 shows estimated emissions of NOX, SO2, PM10, PM2.5 and VOC from the 

WRAP emissions inventory and updated data provided by the states, broken down by state and 

emission source. As the table shows, SO2, PM10, PM2.5 and VOC emissions from cement kiln 

sources are much lower than NOX emissions. Emissions of particulate matter from these sources 

were not included in the WRAP EDMS inventory – the emissions presented were gathered from 

the NEI. Long dry kilns produce over half of the NOX emissions (54.8%) and most of the PM2.5

and PM10 emissions (79.4 and 71.3%, respectively) generated by cement manufacturing in the 

WRAP region. Long wet kilns produce almost half of the SO2 emissions generated by the 

cement manufacturing (48.4%), and precalciner kilns produce almost half of the VOC emissions 

generated by cement manufacturing (45.6%).

Table 7-2 lists potential control measures for NOX emissions from cement kilns. A 

number of options were identified for cement kilns in an ACT guidance document written by the 

U.S. EPA in 1994.

6

 Cement kilns use coal, waste products, tires, or natural gas for combustion 

fuel - this combustion generates primarily NOX emissions but also produces SO2 and PM 

emissions.

6

 Controls can be broken into three categories: process modifications, combustion 

modifications and NOX removal controls. Process modifications include fuel switching and the 

inclusion of steel slag into the raw kiln feed (also known as the CemStar(TM)process) which 

improves thermal efficiency. CemStar is currently used in TXI’s Hunter and Midlothian, TX 

plants, TXI’s Oro Grande, CA plant and Holcim’s North Texas Cementer plant. TXI has also 

licensed CemStar out to RMC Pacific Materials, Inc. and to the Rio Grande Portland Cement 

Company.3 Combustion modifications include low NOX burners and mid-kiln firing. NOX

removal controls include SCR, SNCR, LoTOXTM, and biosolids or sorbent injection. Low NOX
7-2

burners reduce flame turbulence, delay fuel/air mixing and create fuel-rich zones for initial 

combustion, reducing the flame temperature and thus NOX formation.4 SCR introduces

ammonia, presented as a catalyst, into the clinker making process to selectively reduce NOX

emissions from exhaust gases. SNCR, available to preheater or precalciner cement kilns1,5,6,

does not use a catalyst to reduce NOX emissions. Instead, the process uses either ammonia or 

urea that is generated when reagents are injected into the kiln at specific temperatures. However, 

SNCR has been tested primarily in European facilities; there have been two demonstrations in 

the United States but no kilns have yet adopted the technology.7,8,9,10,11

In the LoTOxTM system, ozone is injected into the kiln which oxidizes NOX. The 

resulting higher oxides of nitrogen can then be removed by a wet scrubber.12 LoTOx is licensed 

by the BOC group and is currently being used on the Midlothian cement wet kilns in Texas.1,12 

Biosolid or absorbent injection is similar to SNCR, although instead of a catalyst either biosolids 

from wastewater treatment plants or limestone/hydrated lime are injected into the kiln.7,13 

Biosolid injection is being used in one kiln in Southern California where dewatered sewage 

sludge is injected into the mixing chamber where the flue gas streams from the kiln and the

precalciner mix together. 14,15

7.1 Factor 1 – Costs

Table 7-3 provides cost estimates for the emission control options which have been 

identified for cement kilns. For each option the table gives an estimate of the capital cost to 

install the necessary equipment and the total annual cost of control, including the amortized cost 

associated with the capital equipment cost. The capital and annual cost figures are expressed in 

terms of the cost per unit of clinker tonnage produced, or cubic feet per minute (cfm) for PM 

emission sources. The table shows a range of values for each cost figure since the cost per unit 

of clinker tonnage will depend on the amount of clinker produced and other factors. The lower 

ends of the cost ranges typically reflect smaller kilns and the higher ends of the cost ranges 

typically reflect larger kiln sizes. Table 7-3 also shows the estimated cost effectiveness for each 

control measure, in terms of the cost per ton of emission reduction.

7.2 Factor 2 – Time Necessary for Compliance

Once a state decides to adopt a particular control strategy, up to 2 years will be needed to 

develop the necessary rules to implement the strategy. We have estimated that sources may then 

require up to a year to procure the necessary capital to purchase control equipment. The ICAC 

has estimated that approximately 13 months is required to design, fabricate, and install SCR or 

SNCR technology for NOX control.16 However, state regulators’ experience indicates that closer 

to 18 months is required to install this technology.17 Additional time of up to 12 months may be 

required for staging the installation process if multiple sources are to be controlled at a single 

facility. Based on these figures, the total time required to achieve emission reductions for 

cement kilns is estimated at a total of 51⁄2 years.
Emission Source AK AZ CA CO ID MT ND NM NV OR SD UT WA WY Tribes All

Wet Process Kiln 0 0 0 1136 461 1814 0 0 0 0 2966 0 2251 0 0 8,628

Dry Process Kiln 0 2476 11544 2162 0 0 0 804 0 1741 0 0.012 1213 2080 0 22,020

Clinker Transfer 0 0 601 0 0 0 0 0 0 0 0 0 0 0 0 601

Raw Material Grinding and Drying 0 0 78 12 0 0 0 0 0 0 0 0 0 0 0 91

Preheater/Precalciner Kiln 0 5066 1370 511 0 0 0 0 0 0 0 1322 0 0 0 8,269

Other 0 0 5 0 0 0 0 0 0 0 0 0 0 0 0 5

Total 0 7,542 13,598 3,821 461 1,814 0 804 0 1,741 2,966 1,322 3,464 2,080 0 39,613

Wet Process Kiln 0 0 0 240 17 233 0 0 0 0 656 0 771 0 0 1,917

Dry Process Kiln 0 61 2101 18 0 0 0 15 0 38 0 0.001 188 207 0 2,628

Clinker Transfer 0 0 86 0 0 0 0 0 0 0 0 0 0 0 0 86

Raw Material Grinding and Drying 0 0 11 32 0 0 0 0 0 0 0 0 0 0 0 43

Preheater/Precalciner Kiln 0 9 1 378 0 0 0 0 0 0 0 58 0 0 0 446

Other 0 0 0.44 0 0 0 0 0 0 0 0 0 0 0 0 0

Total 0 70 2,200 667 17 233 0 15 0 38 656 58 959 207 0 5,121

Wet Process Kiln 0 0 14 0 3 0 0 0 0 0 91 6 6 0 0 121

Dry Process Kiln 0 0 1184 0 0 0 0 3 0 0 0 32 28 0 0 1,247

Clinker Transfer 0 0.48 105 3 0.47 0 0 0 0 0 0 1 0 0 0 110

Raw Material Grinding and Drying 0 0.26 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Preheater/Precalciner Kiln 0 74 2 15 0 0 0 0 0 0 0 5 0 0 0 95

Other 0 0 0 0 0.24 0 0 0 0 0 0 0 0 0 0 0.24

Total 0 75 1,305 18 4 0 0 3 0 0 91 44 34 0 0 1,573

Table 7-1. Emissions from Cement Kilns in the WRAP Region

NOX emissions (tons/year)

SO2 emissions (tons/year)

PM2.5 emissions (tons/year)
Emission Source AK AZ CA CO ID MT ND NM NV OR SD UT WA WY Tribes All

Table 7-1. Emissions from Cement Kilns in the WRAP Region

Wet Process Kiln 0 0 20 75 4 376 0 0 0 0 185 17 14 0 0 691

Dry Process Kiln 0 0 2023 414 0 1 0 97 0 64 0 222 30 179 0 3,030

Clinker Transfer 0 1 163 5 2 0 0 0 0 0 0 4 0 0 0 175

Raw Material Grinding and Drying 0 0.47 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Preheater/Precalciner Kiln 0 132 5 26 0 0 0 0 0 0 0 14 0 0 0 178

Other 0 0 0 0 0.84 0 0 0 0 0 0 0 0 0 0 1

Total 0 134 2,211 521 7 377 0 97 0 64 185 257 44 179 0 4,075

Wet Process Kiln 0 0 0 0 1 0 0 0 0 0 81 0 0 0 1 84

Dry Process Kiln 0 10 114 3 0 0 0 33 0 15 0 1 0 46 0 221

Clinker Transfer 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Raw Material Grinding and Drying 0 1 0 125 0 0 0 0 0 0 0 0 0 0 0 126

Preheater/Precalciner Kiln 0 5 4 2 0 0 0 0 0 0 0 42 0 0 1,984 2,038

Other 0 6 1 0 0 0 0 2 0 0 4 0 0 0 1,986 1,999

Total 0 21 119 131 1 0 0 35 0 15 85 43 0 46 3,972 4,467

VOC emissions (tons/year)

PM10 emissions (tons/year)
Source Type Control Technology

Pollutant 

controlled

Baseline 

emissions

Estimated control 

efficiency (%)

Potential emission 

reduction 

(tons/year) References

Low NOX burners NOX 8,628 20-30 1725 - 2588 1, 6

Mid-kiln firing NOX 8,628 20-50 1725 - 4313 1, 6

SCR with ammonia NOX 8,628 80-90 6902 - 7764 5, 6

SNCR with ammonia or urea NOX 8,628 30-70 2588 - 6039 6

Biosolid injection NOX 8,628 50 4313 7

CemStarTM process NOX 8,628 20-60 1725 - 5176 1, 3, 7

LoTOxTM NOX 8,628 80-90 6902 - 7765 1, 5

Dry ESP PM10 691 95-98 656 - 677 9

Dry ESP PM2.5 121 95-98 114 - 118 9

Dry ESP EC 4 95-98 3 9

Dry ESP OC 15 95-98 14 9

Fabric Filter PM10 691 80-99 656 - 677 9

Fabric Filter PM2.5 121 80-99 114 - 118 9

Fabric Filter EC 4 80-99 3 9

Fabric Filter OC 15 80-99 14 9

Absorbant Addition SO2 1,917 60-80 1150 - 1533

Wet FGD SO2 1,917 90-99 1725 - 1897 1

Low NOX burners NOX 19541 40 7816 1, 6

Mid-kiln firing NOX 19541 11-55 2149 - 10747 1, 6

SCR with ammonia NOX 19541 80-90 1563 - 1758 6

Biosolid injection NOX 19541 50 9770 7

LoTOxTM NOX 19541 80 - 90 15,633 - 17,587 1, 5

CemStarTM process NOX 19541 20-60 3908 - 1172 1, 3, 7

Dry ESP PM10 3,030 95-98 2878 - 2969 9

Dry ESP PM2.5 1,247 95-98 1184 - 1221 9

Dry ESP EC 37 95-98 34 - 36 9

Dry ESP OC 158 95-98 150 - 155 9

Fabric Filter PM10 3,030 99 3000 9

Fabric Filter PM2.5 1,247 99 1234 9

Fabric Filter EC 37 99 36 9

Fabric Filter OC 158 99 156 9

Wet FGD SO2 2567 90-99 2310 - 2541 1

Dry FGD SO2 2567 90-95 2310 - 2438 1

Sorbent injection SO2 2567 60-80 1540 - 2053

Table 7-2. Control Options for Cement Kilns

Long Wet Kiln

Long Dry Kiln
Source Type Control Technology

Pollutant 

controlled

Baseline 

emissions

Estimated control 

efficiency (%)

Potential emission 

reduction 

(tons/year) References

Table 7-2. Control Options for Cement Kilns

Low NOX burners NOX 3204 40 1281 1, 6

Mid-kiln firing NOX 3204 11-55 352 - 1762 1, 6

SCR with ammonia NOX 3204 85 2723 5, 6

SNCR with urea NOX 3204 35 1121 5, 6

SNCR with ammonia NOX 3204 35 1121 5, 6

LoTOxTM NOX 3204 80 - 90 2,563 - 2,884 1, 5

CemStarTM process NOX 19541 UnknownaUnknowna 1, 3, 7

Biosolid injection NOX 3204 23 - 50 736 - 1602 7, 9

Dry ESP PM10 178 95-98 169 - 174 9

Dry ESP PM2.5 95 95-98 90 - 93 9

Dry ESP EC 3 95-98 2 9

Dry ESP OC 12 95-98 11 - 11 9

Fabric Filter PM10 178 99 176 9

Fabric Filter PM2.5 95 99 94 9

Fabric Filter EC 3 99 2 9

Fabric Filter OC 12 99 11 9

Wet FGD SO2 436 90-99 392 - 431 1

Dry FGD SO2 436 90-95 392 - 414 1

Sorbent injection SO2 436 60-80 261 - 348 8

Low NOX burners NOX 3204 30-40 961 - 1281 6

Mid-kiln firing NOX 3204 11-55 352 - 1762 1, 6

SCR with ammonia NOX 3204 85 2723 5, 6

SNCR with urea NOX 3204 35 1121 5, 6

SNCR with ammonia NOX 3204 35 1121 5, 6

LoTOxTM NOX 3204 80 - 90 2,563 - 2,884 1, 5

CemStarTM process NOX 19541 UnknownaUnknowna 1, 3, 7

Biosolid injection NOX 3204 50 1602 7

Dry ESP PM10 178 95-98 169 - 174 9

Dry ESP PM2.5 95 95-98 90. - 93. 9

Dry ESP EC 3 95-98 2.6 - 2.7 9

Dry ESP OC 12 95-98 11 - 11 9

Fabric Filter PM10 178 99 176 9

Fabric Filter PM2.5 95 99 94 9

Fabric Filter EC 3 99 2 9

Fabric Filter OC 12 99 11 9

Wet FGD SO2 436 90-99 392 - 431 1

Dry FGD SO2 436 90-95 392 - 414 1

Sorbent injection SO2 436 60-80 261 - 348 8

a The CemStar process has been analyzed for long wet and dry kilns only although the process is currently being used in long dry kilns 

and preheater/precalciner kilns at two facilities, one in Texas and one in California. It is unknown what the control efficiency is of the 

CemStar process in preheater or precalciner kilns.

Preheater Kiln

Precalciner Kiln
7-7

7.3 Factor 3 – Energy and Other Impacts

Table 7-4 shows the estimated energy and non-air pollution impacts of control measures 

for cement kilns. In general in-combustion NOX control technologies will increase energy 

efficiency of the cement production process since these technologies reduce excess air and 

burning.18 SCR requires additional energy input since the process required a particular gas 

temperature, requiring the gas stream to be reheated. An additional 9.8 percent of the total 

energy required in cement manufacturing will be needed to utilize the SCR control technology.18

In addition, spent catalyst would have to be changed periodically, producing an increase in solid 

waste disposal.19

7.4 Factor 4 – Remaining Equipment Life

Information was not available on the age of cement kilns in the WRAP region. Cement 

kilns have no set equipment life. The units, whether wet or dry, can be refurbished to extend 

their lives. In addition, it is assumed that controls will be not be applied to units that are 

expected to be retired prior to the amortization period for the control equipment. Therefore, 

remaining equipment life is not expected to affect the cost of control for cement kilns.
Source Type Control Technology

Pollutant 

controlled

Estimated 

control 

efficiency (%)

Estimated 

capital cost 

($1000/unit)

Estimated annual 

cost 

($/year/unit) Units

Cost 

effectiveness 

($/ton) References

Low NOX burners 

(indirect fired)

NOX 20-47 401 - 564 100,000 - 

144,000

ton clinker 270 - 620 1, 6, 7

Low NOX burners (direct 

fired)

NOX 20-47 1,910 376,000 - 

343,500

ton clinker

855 - 1,005

1, 6, 7

Mid-kiln firing NOX 20-50 613 - 3,205 183,500 - (192,300) ton clinker (460) - 730 1, 6, 7, 8

SCR with ammonia NOX 80-90 15,100 5,780 - 4,105,000 ton clinker 3,370 5, 6, 7

LoTOxTM NOX 80 - 90 3,155 - 3,891c 5

CemStarTM process NOX 20-60 1,176 220000 ton clinker 550 7

Dry ESP PM10, 

PM2.5, OC, 

EC

95-98 40 - 250 9

Fabric Filter PM10, 

PM2.5, OC, 

EC

80-99 117 - 148 9

Wet FGD SO2 90-99 2,211 - 6,917 1, 8

Low NOX burners 

(indirect fired)

NOX 30 - 40 334 - 509 83,000 - 135,500 ton clinker 300 (3) - 620 1, 6, 7

Low NOX burners (direct 

fired)

NOX 40 1,455 298,000 - 272,500 ton clinker

166 - 1,299

1, 6, 7

Mid-kiln firing NOX 11-55 455 - 3,180 89,830 - 144,000 ton clinker (460) - 730 1, 6, 7, 8

LoTOxTM NOX 80 - 90 5

CemStarTM process NOX 20-60 7

SCR with ammonia NOX 80-90 11,485 3,000,000 ton clinker 586 - 3,400 6, 7, 8

Dry ESP PM10, 

PM2.5, OC, 

EC

95-98 40 - 250 9

Fabric Filter PM10, 

PM2.5, OC, 

EC

80-99 117 - 148 9

Wet FGD SO2 90-99 5,610 - 84,000 10,000 - 30,571 ton clinker 2,000 - 4,000 1, 8

Dry FGD SO2 90-95 3,300 - 95,800 9,142 - 32,286 ton clinker 1,900 - 7,000 1

Low NOX burners 

(indirect fired)

NOX 30 - 40 379 - 608 94,500 - 150,000 ton clinker 300 - 620 1, 6, 7

Low NOX burners (direct 

fired)

NOX 40 1,765 - 1,800 351,500 - 330,000 ton clinker 175 - 1,201 1, 6, 7

CemStarTM process NOX 20-60

SCR with ammonia NOX 85 14,400 3,850,000 ton clinker 500 - 3,805 5, 6, 7, 8

SNCR with urea NOX 35 799 546500 ton clinker (310) - 2,500 5, 6, 8

SNCR with ammonia NOX 35 1,595 635500 ton clinker (310) - 2,500 5, 6, 8

LoTOxTM NOX 80 - 90 5

Biosolids Injection NOX 50 1,200 (322,000) ton clinker (310) 7

Dry ESP PM10, 

PM2.5, OC, 

EC

95-98 0.013 Not availableacfm 40 - 250 9

Fabric Filter PM10, 

PM2.5, OC, 

EC

99 0.029 Not availableacfm 117 - 148 9

Wet FGD SO2 90-99 3,710 - 54,000 2,714 - 15,857 ton clinker 2,000 - 64,600 1, 8

Dry FGD SO2 90-95 2,100 - 61,400 2,857 - 17,571 ton clinker 10,000 - 72,800 1

Sorbent Injection SO2 60 - 80 2,031 - 7,379 8

Not availabled

Not availabled

Table 7-3. Estimated Costs of Control for Cement Kilns

Not availablea

Not availablea

Long Wet Kiln

Long Dry Kilns

Preheater Kilns

Not availableb

Not availablea

Not availablea

Not availablea

Not availablea

Not availablea

Not availableb
Source Type Control Technology

Pollutant 

controlled

Estimated 

control 

efficiency (%)

Estimated 

capital cost 

($1000/unit)

Estimated annual 

cost 

($/year/unit) Units

Cost 

effectiveness 

($/ton) References

Table 7-3. Estimated Costs of Control for Cement Kilns

Low NOX burners 

(indirect fired)

NOX 30 406 - 863 101,000 - 188,500 ton clinker 245 - 620 6, 7

Low NOX burners (direct 

fired)

NOX 30 1,945 - 2,235 382,500 - 393,500 ton clinker 920 - 985 6, 7

CemStarTM process NOX 20-60

LoTOxTM NOX 80 - 90 2,419 - 2,734e 5

SCR with ammonia NOX 85 21,950 6,240,000 ton clinker 4635 5, 6, 7

SNCR with urea NOX 35 1,105 709,000 ton clinker (310) - 2,500 5, 6, 8

SNCR with ammonia NOX 35 1,880 779,500 ton clinker (310) - 2,500 5, 6, 8

Biosolids Injection NOX 23 - 50 5,581 1,498 ton clinker (310) 7, 8

Dry ESP PM10, 

PM2.5, OC, 

EC

99 0.013 Not availableacfm 40 - 250 9

Fabric Filter PM10, 

PM2.5, OC, 

EC

99 0.029 Not availableacfm 117 - 148 9

Sorbent Injection SO2 60-80 2,031 - 7,379 8

Wet FGD SO2 90-99 3,710 - 54,000 2,714 - 15,857 ton clinker 2,211 - 6,917 8

Not availablea

Not availableb

d Cost effectiveness figures for LoTOx were not determined for dry kilns or preheater kilns, but only for wet kilns (the kilns that currently use the system) and 

precalciner kilns (developed from vendor information).

c The cost effectivenes was calculated for a wet kiln that did not already have a scrubber system in place.

e The cost effectiveness was calculated for a precalciner kiln that already has a scrubber system in place.

Not availablea

b The CemStar process has been costed for long wet kilns only although the process is currently being used in long dry kilns and preheater/precalciner kilns at 

two facilities, one in Texas and one in California.

a References discussing this particular control technology did not provide any capital or annual costs but only a cost effectiveness figure.

Precalciner Kilns
Source Type Control Technology

Pollutant 

controlled

Potential 

emission 

reduction 

(tons/year)

Additional Fuel 

Requirement (%)

Additional electricity 

requirement (kW/ton 

reduced)

Steam requirement 

(tons steam/ton 

reduced)

Solid waste 

produced (tons 

waste/ton reduced)

Wastewater 

produced (million 

gallons/ton 

reduced)

Additional CO2 

emitted 

(tons/ton 

reduced)

Low NOX burners NOX 1725 - 2588 a 182

Mid-kiln firing NOX 1725 - 4313 a 182

SCR with ammonia NOX 6902 - 7764 9.8 57 Unknownb

SNCR with ammonia 

or urea

NOX 2588 - 6039 Unknownb

Biosolid injection NOX 4313 a

LoTOxTM NOX 6902 - 7765 Unknownc

CemStarTM process NOX 1725 - 5176 a

Fabric Filter PM10, PM2.5, EC, 

OC

1,898 - 1,958 Unknownb 1

Dry ESP PM10, PM2.5, EC, 

OC

1,898 - 1,958 Unknownb 1

Wet FGD SO2 1725 - 1897 1,100 3.1 2.8 3.7 2.6

Low NOX burners NOX 7816 a 158

Mid-kiln firing NOX 2149 - 10747 a 158

SCR with ammonia NOX 1563 - 1758 9.8 48 Unknownb

Biosolid injection NOX 9770

LoTOxTM NOX 15,633 - 17,587 Unknownc

CemStarTM process NOX 3908 - 1172

Dry ESP PM10, PM2.5, EC, 

OC

1,898 - 1,958 Unknownb 1

Fabric Filter PM10, PM2.5, EC, 

OC

1,898 - 1,958 Unknownb 1

Wet FGD SO2 2310 - 2541 1,100 3.1 2.8 3.7 2.6

Dry FGD SO2 2310 - 2438 Unknownb

Table 7-4. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Cement Kilns

Long Wet 

Kilns

Long Dry Kilns

Energy and non-air pollution impacts
Source Type Control Technology

Pollutant 

controlled

Potential 

emission 

reduction 

(tons/year)

Additional Fuel 

Requirement (%)

Additional electricity 

requirement (kW/ton 

reduced)

Steam requirement 

(tons steam/ton 

reduced)

Solid waste 

produced (tons 

waste/ton reduced)

Wastewater 

produced (million 

gallons/ton 

reduced)

Additional CO2 

emitted 

(tons/ton 

reduced)

Table 7-4. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Cement Kilns

Energy and non-air pollution impacts

Low NOX burners NOX 1281 a 194

SCR with ammonia NOX 2723 9.8 59 Unknownb

SNCR with urea NOX 1121 Unknownb

SNCR with ammonia NOX 1121 Unknownb

LoTOxTM NOX 2,563 - 2,884 Unknownc

Biosolid injection NOX 736 - 1602 a

Sorbent injection SO2 261 - 348 a

Dry ESP PM10, PM2.5, EC, 

OC

1,898 - 1,958 Unknownb 1

Fabric Filter PM10, PM2.5, EC, 

OC

1,898 - 1,958 Unknownb 1

Wet FGD SO2 392 - 431 1,100 3.1 2.8 3.7 2.6

Dry FGD SO2 392 - 414 Unknownb

Low NOX burners NOX 961 - 1281 a 285

SCR with ammonia NOX 2723 9.8 89 Unknownb

SNCR with urea NOX 1121 Unknownb

SNCR with ammonia NOX 1121 Unknownb

LoTOxTM NOX 2,563 - 2,884 Unknownc

Biosolid injection NOX 1602 a

Sorbent injection SO2 60-80 a

Dry ESP PM10, PM2.5, EC, 

OC

1,898 - 1,958 Unknownb 1

Fabric Filter PM10, PM2.5, EC, 

OC

1,898 - 1,958 Unknownb 1

Wet FGD SO2 392 - 431 1,100 3.1 2.8 3.7 2.6

Dry FGD SO2 392 - 414 Unknownb

c - According to the ERG Report (reference 3) "electricity and oxygen costs are reported to be high" although there is no quantification given.

b - Impacts are expected, however there is no available information to quantify these impacts.

a - The measure is expected to improve fuel efficiency.

Precalciner 

Kilns

Preheater 

Kilns
7-12

7.5 References for Section 7

1. NACAA (formerly STAPPA and ALAPCO) (2006), Controlling Fine Particulate Matter 

Under the Clean Air Act: A Menu of Options, National Association of Clean Air 

Agencies, www.4cleanair.org/ PM25Menu-Final.pdf.

2. WRAP (2008), Emissions Data Management System, Western Regional Air Partnership, 

Denver, CO, http://www.wrapedms.org/app_main_dashboard.asp.

3 Yates, J. Roger, D. Perkins, R. Sankaranarayanan (2003), CemStarsm Process and 

Technology for Lowering Greenhouse Gases and Other Emissions while Increasing 

Cement Production, 

http://www.hatch.ca/environment_community/sustainable_development/projects/copy%2

0of%20cemstar-process-final4-30-03.pdf.

4. Reference 6, Chapter 5.

5. ERG, Inc. (2005), Assessment of NOX Emissions Reduction Strategies for Cement Kilns -

Ellis County, TCEQ Contract No. 582-04-65589, Work Order No. 05-06, 

http://www.tceq.state.tx.us/assets/public/implementation/air/sip/agreements/BSA/CEME

NT_FINAL_REPORT_70514_final.pdf.

6. EPA (1994), Alternative Control Techniques Document— NOX Emissions from Cement 

Manufacturing, EPA-453/R-94-004, U.S. EPA, RTP, NC, Chapter 3, 

http://www.epa.gov/ttn/catc/dir1/cement.pdf.

7. EC/R, Incorporated (2000), NOX Control Technologies for the Cement Industry, EPA 

Contract No. 68-D98-026, http://www.epa.gov/ttn/naaqs/ozone/rto/fip/data/cement.pdf.

8. Lake Michigan Air Directors Consortium (2006), Interim White Paper - Midwest RPO 

Candidate Control Measures for Cement Kilns, 

http://www.ladco.org/reports/control/white_papers/portland_cement_plants.pdf.

9. E.H. Pechan & Associates (2005), AirControlNET, Version 4.1 - Documentation Report, 

U.S. EPA, RTP, NC, http://www.epa.gov/ttnecas1/AirControlNET.htm.

10. Sun et al. (1994), Reduction of NOX Emissions from Cement Kiln/Calciner Through the 

Use of the NOXOUT Process, Presented at the International Specialty Conference on 

Waste Combustion in Boilers and Industrial Furnaces.

11. Interoffice Correspondence from McAnany, L. to H. Knopfel, H, Lafarge Corporation 

(1998) re: Fuel Tech NOXOUT Testing.

12 ERG, Inc. (2005), Assessment of NOX Emissions Reduction Strategies for Cement Kilns -

Ellis County, Chapter 4, TCEQ Contract No. 582-04-65589, Work Order No. 05-06, 

http://www.tceq.state.tx.us/assets/public/implementation/air/sip/agreements/BSA/CEME

NT_FINAL_REPORT_70514_final.pdf.
7-13

13. IEA Clean Coal Center (2009), Sorbjent Injection Systems for SO2 Control, 

http://www.iea-coal.org.uk/site/ieacoal/databases/ccts/sorbent-injection-systems-for-so2-

control.

14. Battye, R. and S. Edgerton, EC/R Incorporated (2000), Trip Report to Mitsubishi Cement 

Corporation, Cushenbury Plant, Lucerne Valley, CA, December 2, 1999, Prepared for the 

US EPA, RTP, NC, Contract No. 68-D-98-026.

15. Biggs, H.O., Plant Manager, Mitsubishi Cement Corporation (no date), Biosolids 

Injection Technology: An Innovation in Cement Kiln NOX Control, Received during 

December 199 plant trip.

16. Institute of Clean Air Companies (2006), Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial Sources, 

http://www.icac.com/files/public/ICAC_NOx_Control_Installation_Timing_120406.pdf.

17. Ghoreishi, Farrokh (2007), Personal communication, Time required to install add-on 

control measures for NOX, Wisconsin Department of Natural Resources, April 27. 

18. Reference 3, Chapter 7.

19. EPA (2002), EPA Air Pollution Control Cost Manual, 6th ed., EPA/452/B-02-001, U.S. 

EPA, Office of Air Quality Planning and Standards, RTP, NC, 

http://www.epa.gov/ttncatc1/products.html#cccinfo.
8-1

8. Sulfuric Acid Manufacturing Plants

Sulfuric acid manufacturing plants account for about 4,700 tons/year of SO2 emissions in 

the WRAP region. These emissions are from a limited number of facilities, with facility-level 

SO2 emissions ranging from about 100 tons/year to about 2,000 tons/year. Table 8-1 summarizes 

emissions from the sulfuric acid manufacturing plants, broken down by state, based on the 

WRAP emissions inventory and the NEI.

1

 The table also shows the amounts of SO2 emissions 

from facilities at different efficiency levels for the acid recovery process. As the table shows, 

reported emissions of NOX, PM10, PM2.5, and VOC emissions are much lower than SO2

emissions from sulfuric acid plants in the region. 

Emissions of SO2 from sulfuric acid manufacturing processes can be reduced by 

increasing the absorption efficiency of the acid recovery process. The NSPS emission level for 

sulfuric acid plants corresponds to an estimated recovery efficiency of 99.75%.2 Based on the 

SCC used in the WRAP inventory, the recovery efficiency ranges from 93 to 99% for most of the 

emission sources in the WRAP region. Increasing the efficiency of sulfuric acid plants to the 

NSPS level would result in emission reductions 75 to 96.4% from the current baseline level of 

control. This increase in efficiency is achieved by adding more absorption stages to the acid 

recovery process. SO2 emissions can also be controlled using tail gas treatment units.3,4 Table 8-

2 shows the estimated control efficiencies and emission reductions which could be achieved for 

sulfuric acid plants operating at different baseline levels of control.

8.1 Factor 1 – Costs

Table 8-3 provides cost estimates for the emission control options which have been 

identified for sulfuric acid manufacturing plants. For each option, the table gives an estimate of 

the capital cost to install the necessary equipment, and the total annual cost of control, including 

the amortized cost associated with the capital equipment cost. The capital and annual cost 

figures are expressed in terms of the cost per unit of gas treated, in actual cubic feet per minute 

(acfm). 

Table 8-3 shows a range of values for each cost figure, since the cost per unit of 

throughput will depend on the process size and other factors. The lower ends of the cost ranges 

typically reflect larger processes, and the higher ends of the cost ranges typically reflect lower 

process sizes. The table also shows the estimated cost effectiveness for each control measure, in 

terms of the cost per ton of emission reduction.
CA ID WA WY Tribes All

General 32 0 10 54 7 103

Contact process

99% efficient 710 710

98% efficient 105 105

93% efficient 364 364

Unspecified 2,012 897 2,909

Chamber process 600 600

Total 1,310 364 105 2,012 897 4,688

General 2 23 2 27

NOX emissions (tons/year)

SO2 emissions (tons/year)

VOC emissions (tons/year)

Table 8-1. Emissions from Sulfuric Acid Manufacturing Plants in the WRAP 

Region
Source Type Control Technology

Pollutant 

controlled

Baseline 

emissions

Estimated 

control 

efficiency (%)

Potential 

emission 

reduction 

(tons/year)

References

Contact process

Increase absorption 

efficiency to NSPS level

SO2 710 75 530 2,3

Tailgas treatment unit SO2 710 90 640 3,4

Increase absorption 

efficiency to NSPS level

SO2 105 87.5 92 2,3

Tailgas treatment unit SO2 105 95 100 3,4

Increase absorption 

efficiency to NSPS level

SO2 3,273 96.4 3,200 2,3

Tailgas treatment unit SO2 3,273 98.6 3,200 3,4

Chamber process Tailgas treatment unit SO2 600 98.6 590 3,4

Table 8-2. Control Options for Sulfuric Acid Manufacturing Plants

99% baseline 

efficiency

98% baseline 

efficiency

93% baseline 

efficiency
Source Type Control Technology

Pollutant 

controlled

Estimated 

control 

efficiency (%)

Estimated 

capital cost 

($/unit)

Estimated annual 

cost 

($/year/unit) Units

Cost 

effectiveness 

($/ton)

References

Contact process

Increase absorption 

efficiency to NSPS level

SO2 75 55 - 96 23 - 29 acfm 6,800 - 7,000 2,3

Tailgas treatment unit SO2 90 23 - 32 36 acfm 5,300 - 6,500 3,4

Increase absorption 

efficiency to NSPS level

SO2 87.5 6,200 2,3

Tailgas treatment unit SO2 95 48 38 acfm 3,375 3,4

Increase absorption 

efficiency to NSPS level

SO2 96.4 1,600 2,3

Tailgas treatment unit SO2 98.6 48 38 acfm 928 3,4

Chamber process Tailgas treatment unit SO2 98.6 19 34 acfm 8,100 3,4

Table 8-3. Estimated Costs of Control for Sulfuric Acid Manufacturing Plants

99% baseline 

efficiency

98% baseline 

efficiency

93% baseline 

efficiency
8-5

8.2 Factor 2 – Time Necessary for Compliance

Once a state decides to adopt a particular control strategy, up to 2 years will be needed to 

develop the necessary rules to implement the strategy. We have estimated that sources may then 

require up to a year to procure the necessary capital to purchase control equipment. In the CAIR 

analysis, EPA estimated that approximately 30 months is required to design, build, and install 

SO2 scrubbing technology for a single emission source.

5

 The analysis also estimated that up to 

an additional 12 months may be required for staging the installation process if multiple sources 

are to be controlled at a single facility. Based on these figures, the total time required achieve 

emission reductions for sulfuric acid manufacturing facilities is estimated at a total of 61⁄2 years.

8.3 Factor 3 – Energy and Other Impacts

Table 8-4 shows the estimated energy and non-air pollution impacts of control measures 

for sulphuric acid plants. Additional absorption stages to increase acid plant efficiency would 

require additional electricity and steam,2as would a tailgas treatment unit.4 This would result in 

increased CO2 emissions to generate the electricity and steam. 

8.4 Factor 4 – Remaining Equipment Life

Information was not available on the age of sulfuric acid plants in the WRAP region. 

However, industrial processes often refurbished to extend their lifetimes. Therefore, the 

remaining lifetime of most equipment is expected to be longer than the projected lifetime of 

pollution control technologies which have been analyzed for this category. In the case of add-on 

technologies, the projected lifetime is 15 years. 

If the remaining life of an emission source is less than the projected lifetime of a 

pollution control device, then the capital cost of the control device would have to be amortized 

over a shorter period of time, corresponding to the remaining lifetime of the emission source. 

This would cause an increase in the amortized capital cost of the pollution control option, and a 

corresponding increase in the total annual cost of control. This increased cost can be quantified 

as follows:

where:

A1 = the annual cost of control for the shorter equipment lifetime ($)

A0 = the original annual cost estimate ($)

C = the capital cost of installing the control equipment ($)

r = the interest rate (0.07)

m = the expected remaining life of the emission source (years)

n = the projected lifetime of the pollution control equipment
Additional 

electricity 

requirement 

(kW-hr)

Steam 

requirement 

(tons steam)

Solid waste 

produced (tons 

waste)

Additional CO2 

emitted (tons)

Contact process

Increase absorption 

efficiency to NSPS level

SO2 530 2,450 29 <0.01 10

Tailgas treatment unit SO2 640 1,470 27 8

Increase absorption 

efficiency to NSPS level

SO2 92 1,050 13 <0.01 4

Tailgas treatment unit SO2 100 700 12 4

Increase absorption 

efficiency to NSPS level

SO2 3,200 270 3.2 <0.01 1

Tailgas treatment unit SO2 3,200 190 3.5 1

Chamber process Tailgas treatment unit SO2 590 2,450 29 <0.01 10

99% baseline 

efficiency

98% baseline 

efficiency

93% baseline 

efficiency

Table 8-4. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Sulfuric Acid 

Manufacturing Plants

Energy and non-air pollution impacts (per ton of pollutant reduced)

Potential 

emission 

reduction 

Source Type Control Technology (tons/year)

Pollutant 

controlled
8-7

8.5 References for Section 8

1. WRAP (2008), Emissions Data Management System, Western Regional Air Partnership, 

Denver, CO, http://www.wrapedms.org/app_main_dashboard.asp.

2. EPA (1985), Sulfuric Acid: Review of New Source Performance Standards for Sulfuric 

Acid Plants, EPA/450/3-85/012, U.S. EPA, RTP, NC, http://nepis.epa.gov/.

3. E.H. Pechan & Associates (2005), AirControlNET, Version 4.1 - Documentation Report, 

U.S. EPA, RTP, NC, pp III-1223 through III-1276, 

http://www.epa.gov/ttnecas1/AirControlNET.htm.

4. EPA (2002), EPA Air Pollution Control Cost Manual, 6th ed., EPA/452/B-02-001,

Section 5 - SO2 and Acid Gas Controls, U.S. EPA, Office of Air Quality Planning and 

Standards, RTP, NC, pp 1-30 through 1-42, 

http://www.epa.gov/ttncatc1/products.html#cccinfo.

5. EPA (2005), Boilermaker Labor Analysis and Installation Timing – Technical Support 

Document for the Final Clean Air Interstate Rule, OAR-2003-0053, U.S. EPA, 

Washington, DC, www.epa.gov/cair/technical.html#final.
9-1

9. Pulp and Paper Lime Kilns

The pulp making process produces the largest amount of emissions in the pulp and paper 

industry, accounting for more than 75% of the sector’s PM2.5, SO2, and NOX emissions.

1

The 

role of lime kilns in the kraft pulping process is to produce white liquor and calcium carbonate.

2

Lime kilns at pulp and paper manufacturing facilities in the WRAP region are estimated 

to emit about 828 tons of NOX, 104 tons of SO2, 603 tons of PM2.5, 667 tons of PM10, and 32 

tons of VOC per year, based on the 2002 emissions inventory for the region.3 The area source 

emissions estimates are derived from industrial, commercial, and institutional fuel consumption 

in the WRAP states. NOX emissions from lime kilns represent approximately 0.08% of total 

point source emissions of NOX in the WRAP region, and approximately 0.06% of all stationary 

source (point and area source) NOX emissions in the region. SO2 emissions from lime kilns 

represent approximately 0.01% of total point source emissions of SO2 in the WRAP region, and 

approximately 0.01% of all stationary source (point and area source) SO2 emissions in the 

region.

Table 9-1 shows estimated emissions of NOX, SO2, PM10, PM2.5 and VOC from the 

WRAP emissions inventory and updated data provided by the states, broken down by state and 

emission source. As the table shows, SO2, PM10, PM2.5 and VOC emissions from lime kiln 

sources are much lower than NOX emissions. PM emissions from these sources were not 

included in the WRAP EDMS inventory – the emissions presented were gathered from the 

2002NEI.

Table 9-2 lists potential control measures for NOX, SO2, PM10 and PM2.5 emissions from 

lime kilns. A number of options were identified for lime kilns in the AirControlNet 

documentation report written by Pechan in 2006.

4

 Many of the controls listed are similar to 

those to control emissions from cement kilns (please see chapter 7). SCR and SNCR have been 

investigated as possible control technologies but have been found to be technically infeasible.

Additionally, according to the NACAA, there are no technically feasible methods for controlling 

NOX emissions from lime kilns.1Therefore NACAA discusses control options for PM emissions 

only.

9.1 Factor 1 – Costs

Table 9-3 provides cost estimates for the emission control options which have been 

identified for lime kilns used in the pulp and paper industry. For each option, the table gives an 

estimate of the capital cost to install the necessary equipment, and the total annual cost of 

control, including the amortized cost associated with the capital equipment cost. The capital and 

annual cost figures are expressed in terms of the cost per standard cubic feet per minute (scfm). 

The table shows a range of values for each cost figure, since the cost per scfm will depend on the 
AK CA CO ID MT ND NM NV OR UT WA WY Tribes All

Total* 0 66 0 99 236 0 0 0 96 0 308 23 0 828

Total* 0 1 0 3.3 2 0 0 0 57 0 40 0 0 104

Total* 0 40 0 87 31 0 0 0 336 0 109 0 0 603

Total* 0 53 0 93 38 0 0 0 370 0 113 0 0 667

Total* 0 0.28 0 5 20 0 0 0 2.18 0 4 0 0 32

* The majority of emissions produced in the pulp and paper lime kiln operations are generated from the kilns themselves. Thus the total 

emissions presented in this table are emissions from kilns.

Table 9-1. Emissions from Lime Kilns in the WRAP Region

NOX emissions (tons/year)

SO2 emissions (tons/year)

PM2.5 emissions (tons/year)

PM10 emissions (tons/year)

VOC emissions (tons/year)
Source Type Control Technology

Pollutant 

controlled

Baseline 

emissions

Estimated 

control 

effieiency 

(%)

Potential 

emission 

reduction 

(tons/year) References

Low NOX burners NOX 828 30 248 4

Mid-kiln firing NOX 828 30 248 4

LoTOX NOX 828

SCR with ammonia NOX 828 60 - 80 496 - 662 4

SNCR with ammonia or 

urea

NOX 828 50 414 4

Wet FGD SO2 104 50 51 4

Dry ESP PM10 1271 95-98 1207 - 1245 4

Dry ESP PM2.5 1271 95-98 1207 - 1245 4

Dry ESP EC 37 95-98 35 - 36 4

Dry ESP OC 161 95-98 153 - 158 4

Table 9-2. Control Options for Lime Kilns

Kiln
9-4

kiln size and other factors. The lower ends of the cost ranges typically reflect smaller kilns, and 

the higher ends of the cost ranges typically reflect larger kilns. Table 9-3 also shows the 

estimated cost effectiveness for each control measure, in terms of the cost per ton of emission 

reduction.

9.2 Factor 2 – Time Necessary for Compliance

Once a state decides to adopt a particular control strategy, up to 2 years will be needed to 

develop the necessary rules to implement the strategy. We have estimated that sources may then 

require up to a year to procure the necessary capital to purchase control equipment. The ICAC

has estimated that approximately 13 months is required to design, fabricate, and install SCR or 

SNCR technology for NOX control.

5

 However, state regulators’ experience indicates that closer 

to 18 months is required to install this technology.6 Additional time of up to 12 months may be 

required for staging the installation process if multiple sources are to be controlled at a single 

facility. Based on these figures, the total time required to achieve emission reductions for pulp 

and paper lime kilns is estimated at a total of 51⁄2 years.

9.3 Factor 3 – Energy and Other Impacts

Table 9-4 shows the estimated energy and non-air pollution impacts of control measures 

for pulp and paper lime kilns. Low NOX burners negatively affect efficiency and energy usage,

7

and staged combustion, while lowering NOX emissions, can lead to increased SO2 emissions. 

SCR and SNCR require, on average, 890 kilowatt-hour (kWh) of electricity per ton of pollutant 

reduced, and 0.25 tons of steam for every ton of pollutant reduced. Approximately one ton of 

CO2 is produced per mWh of electricity generated.

8

 In addition, spent catalyst from the SCR 

technology would have to be changed periodically, producing an increase in solid waste 

disposal.9Installation of SCR would also require an increase in fuel consumption, which would 

also produce an increase in CO2 emissions to generate the electricity.

Fabric filters and ESP technologies, on average, generate approximately one ton of solid 

waste for every ton of pollutant reduced. It is also likely that there will be additional electricity 

usage for in-combustion and post-combustion technologies. 

9.4 Factor 4 – Remaining Equipment Life

Information was not available on the age of reciprocating engines and turbines in the 

WRAP region. However, lime kilns, like cement kilns, have no set equipment life. These units 

can be refurbished to extend their lives. In addition, it is assumed that controls will be not be 

applied to lime kilns that are expected to be retired prior to the amortization period for the 

control equipment. Therefore, remaining equipment life is not expected to affect the cost of 

control for lime kilns.
Source Type Control Technology

Pollutant 

controlled

Estimated 

control 

effieiency (%)

Estimated 

capital cost 

($1000/unit)

Estimated annual cost 

($/year/unit) Units

Cost 

effectiveness 

($/ton) References

Low NOX burners NOX 30 560 4

Mid-kiln firing NOX 30 460 4

SCR with ammonia NOX 60 - 80 3370 4

SNCR with ammonia or 

urea

NOX 50 770 - 850 4

Wet FGD SO2 50 4

Dry ESP PM2.5 95 15 - 50 4 - 40 scfm 4

Dry ESP PM10 98 15 - 50 4 - 40 scfm 40-250 4

Dry ESP EC 95 15 - 50 4 - 40 scfm 4

Dry ESP OC 95 15 - 50 4 - 40 scfm 4

Wet ESP PM2.5 95 4

Wet ESP PM10 99 30 - 60 6 - 45 scfm 55 - 550 4

Wet ESP EC 95 4

Wet ESP OC 95 4

Not available

Not available

Not available

Not available

Table 9-3. Estimated Costs of Control for Lime Kilns

Not available

Kilns

Not available

Not available

Not available
Source 

Type

Control 

Technology Pollutant controlled

Potential 

emission 

reduction 

(tons/year)

Additional Fuel 

Requirement (%)

Additional 

electricity 

requirement 

(kW-hr/ton 

reduced)

Steam 

requirement 

(tons steam/ton 

reduced)

Solid waste 

produced (tons 

waste/ton 

reduced)

Wastewater 

produced 

(million 

gallons/ton 

reduced)

Additional 

CO2 emitted 

(tons/ton 

reduced)

Low NOX burners NOX 30 Unknown Unknown

Mid-kiln firing NOX 30 a

SCR with ammonia NOX 60 - 80 Unknown 890 0.25 1

SNCR with 

ammonia or urea

NOX 50 Unknown 890 0.25 1

Wet FGD SO2 90 1,100 3.1 2.8 3.7 2.6

Dry ESP PM10, PM2.5, EC, OC 95-98 Unknown 1

Fabric Filter PM10, PM2.5, EC, OC 95-99 Unknown 1

Table 9-4. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Lime Kilns

Energy and non-air pollution impacts

Kilns

a - The measure is expected to improve fuel efficiency.
9-7

9.5 References for Section 9

1. NACAA (formerly STAPPA and ALAPCO) (2006), Controlling Fine Particulate Matter 

Under the Clean Air Act: A Menu of Options, National Association of Clean Air 

Agencies, Chapter 8, http://www.4cleanair.org/PM25Menu-Final.pdf.

2. Davis, W. (2000), Air Pollution Engineering Manual: Second Edition, Air & Waste 

Management Association.

3. WRAP (2008), Emissions Data Management System, Western Regional Air Partnership, 

Denver, CO, http://www.wrapedms.org/app_main_dashboard.asp.

4. E.H. Pechan & Associates (2005), AirControlNET, Version 4.1 - Documentation Report, 

U.S. EPA, RTP, NC, http://www.epa.gov/ttnecas1/AirControlNET.htm.

5 . Institute of Clean Air Companies (2006), Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial Sources, 

http://www.icac.com/files/public/ICAC_NOx_Control_Installation_Timing_120406.pdf.

6 . Ghoreishi, Farrokh (2007), Personal communication, Time required to install add-on 

control measures for NOX, Wisconsin Department of Natural Resource, April 27.

7. Northeast States for Coordinated Air Use Management (NESCAUM) (2005), Assessment 

of BART-Eligible Sources: Steam Electric Boilers, Industrial Boilers, Cement Plants and 

Paper and Pulp Facilities, 

http://bronze.nescaum.org/committees/haze/BART_Control_Assessment.pdf.

8. Keeth, R. et al. (2000), Coal Utility Environmental Cost (CUECost) Workbook User’s 

Manual Version 1.0, Prepared for US EPA/Office of Research and Development, EPA 

Contract No. 68-D7-0001, http://www.epa.gov/ttn/catc/products.html.

9. EPA (2002), EPA Air Pollution Control Cost Manual, 6th ed., EPA/452/B-02-001, U.S. 

EPA, Office of Air Quality Planning and Standards, RTP, NC, 

http://www.epa.gov/ttncatc1/products.html#cccinfo.
10-1

10. Oil Refineries

Petroleum refineries in the WRAP region are estimated to emit about 25,000 tons of NOX

and 58,000 tons of SO2, based on the WRAP emissions inventory. These emissions represent 

about 2% of stationary source (point and area source) NOX emissions, and 6% of stationary 

source SO2 emissions in the region. PM10 and PM2.5 emissions from natural gas processing 

facilities are estimated to be an order of magnitude lower than NOX and SO2 emissions. 

Table 10-1 summarizes estimated emissions from petroleum refineries in the WRAP 

region, broken down by state and by the various emission sources. These emissions estimates 

are based on the 2002 WRAP emissions inventory.

1

 Major sources of NOX and SO2 emissions at 

refineries in the WRAP region include process heaters, catalytic cracking units, coking units and 

ancillary operations, flares and incinerators. Other sources include boilers, which have been 

discussed in Chapter 6, and reciprocating engines and turbines, which have been discussed in 

Chapter 3.

Emissions of OC and EC are not specifically quantified in either the WRAP inventory or 

the NEI, but can be estimated as a percentage of PM10 emissions using data from EPA’s 

SPECIATE database.2 EC and OC are estimated to comprise 0.07% and 0.014% of PM10

emissions from catalytic cracking units, respectively; 38.4% and 24.7% of natural gas 

combustion PM10 emissions; and 1% each in oil combustion PM10. 

Table 10-2 lists potential control measures for emissions of SO2, NOX, and PM at 

petroleum refineries. The table includes options for process heaters, fluid catalytic cracking 

units, fluid coking operation boilers, coke calcining boilers, and flares. 

Most of the SO2 emissions from process heaters result from the burning of refinery fuel 

gases containing hydrogen sulfide (H2S). These emissions can be reduced by treating the 

refinery fuel gas to remove H2S before the gas is burned. A number of options are available to 

reduce NOX emissions from process heaters. Combustion modifications including LNB, ULNB, 

and FGR reduce the formation of NOX. In addition, flue gases from the process heaters can be 

treated with SCR or SNCR to reduce NOX emissions. These post-combustion controls can be 

used either alone or in conjunction with combustion controls.3,4 

In catalytic cracking, the heavier fractions of crude petroleum are treated with a catalyst 

which breaks the petroleum molecules into lighter compounds. The catalyst is continuously 

cycled between the cracking and a separate regeneration reactor in order to burn off coke buildup. Since the catalyst coke contains relatively high levels of sulfur, the combustion products 

from this coke are an important source of SO2 emissions. Uncontrolled SO2 concentrations in 

the fluid catalytic cracking (FCC) regenerator exhaust stream range from 150 to 3000 parts per 

million by volume (ppmv). The FCC regenerator burner also emits NOX and PM, including 

material abraded from the catalyst (catalyst fines). Uncontrolled NOX emissions from the 

regenerator vent can range from 50 to 400 ppmv. 5
AK CA CO MT ND NM NV OR UT WA WY 

Process Heaters 573 7,778 349 1,072 864 783 48 615 3,088 192 Catalytic Cracking Units 1,179 239 463 193 245 Flares 102 942 12 191 7 261 57 9 Fluid Coking Units 122 25 

Other 122 563 106 103 31 7 105 996 1,156 

Total 797 10,583 707 1,854 864 1,014 48 7 1,226 4,141 1,358 

Process Heaters 62 2,093 338 628 4,592 1,268 93 715 2,330 363 Catalytic Cracking Units 5,567 1,197 4,649 2,044 671 2,645 379 Flares 8 4,940 2 380 31 313 936 139 Fluid Coking Units 5,937 282 

Coke Calcining 3,642 186 Incinerators 41 29 183 457 1 2,105 44 629 Other 41 5,802 126 183 688 10 2,105 698 5,238 

Total 111 24,340 1,663 6,122 4,592 4,030 93 10 3,804 6,609 6,120 

Process Heaters 30 1,049 31 38 72 61 200 28 Catalytic Cracking Units 305 264 333 171 30 74 Flares 6 41 0 2 5 0 Fluid Coking Units 154 6 

Other 7 51 193 2 3 280 70 536 

Total 43 1,600 488 379 0 244 0 3 373 349 564 

Process Heaters 2 1,026 64 60 30 Catalytic Cracking Units 278 103 4 Flares 41 2 1 Fluid Coking Units 140 

Other 0 54 3 2 

Total 2 1,539 0 0 0 167 0 0 70 33 0 

Fugitive emissions 0 3,094 127 1,326 0 1,396 20 37 447 955 469 Wastewater treatment 1,018 960 13 531 0 221 5 2 139 344 94 Process heaters 9 418 67 27 161 30 1 1 22 101 2,613 Flares 130 2,311 17 33 0 5 0 0 63 117 27 

Other 11 1,304 43 100 0 151 8 1 67 161 7 

Total 1,167 8,086 268 2,017 161 1,802 34 41 738 1,678 3,210 

NOX emissions (tons/year)

SO2 emissions (tons/year)

PM2.5 emissions (tons/year)

PM10 emissions (tons/year)

Table 10-1. Emissions from Petroleum Refineries in the WRAP Region

VOC emissions (tons/year)
Source Type Control Technology

Pollutant

controlled

Baseline

emissions

(1000 tons)

Estimated

control

effieiency (%)

Potential

emission

reduction (1000

tons/year)

Refer‐

ences

Fuel treatment to

remove sulfur

SO2 12 up to 90 0 ‐ 11 5,13

LNB NOX 15 40 6.1 3,6

ULNB NOX 15 75 ‐ 85 12 ‐ 13 5,6,3

LNB and FGR NOX 15 48 7.4 3,6

SNCR NOX 15 60 9.2 3,5,3

SCR NOX 15 70 ‐ 90 11 ‐ 14 3,5,3

LNB and SCR NOX 15 70 ‐ 90 11 ‐ 14 3,5,3

Catalyst additives for

NOX reduction

NOX 2.3 46 1.1 5,7

LoTOXTM NOX 2.3 85 2.0 5,8

SNCR NOX 2.3 40 ‐ 80 0.93 ‐ 1.9 5,7

SCR NOX 2.3 80 ‐ 90 1.9 ‐ 2.1 8,7

Catalyst additives for SO2

absorbtion

SO2 17 20 ‐ 60 3.4 ‐ 10 5,7

Desulfurization of

catalytic cracker feed

SO2 17 up to 90 0 ‐ 15 7,13

Wet scrubbing SO2 17 70 ‐ 99 12 ‐ 17 5,6,9

PM10 1.2 95+ 1.1 ‐ 1.2 5,6,10

PM2.5 0.4 95+ 0.4

EC 0.0008 95+ 0.0008

OC 0.0002 95+ 0.0002

Spray dryer absorber SO2 10 80 ‐ 95 8 ‐ 10 5

Wet FGD SO2 10 90 ‐ 99 9 ‐ 10 5,11,12

Improved process

control and operator

training

SO2 varies 5

Expand sulfur recovery

unit

SO2 varies 5

Flare gas recovery

system

SO2 varies 5

Process heaters

Table 10-2. Control Options for Petroleum Refineries

Coking or coke

calcining boilers

Fluid catalytic

cracking units

ESP

Flares
10-4

Many refineries use catalyst additives to reduce SO2 and NOX emissions from fluid 

catalytic cracking units. SO2 emissions can also be reduced by treating the fluid catalytic cracker 

feed stream to remove sulfur compounds. Some refineries in the U.S. have also used SCR to 

control NOX emissions from catalytic cracking units, and one refinery in Japan has also used 

SNCR.6,7 In addition, the LoTOxTM process has been developed to control NOX emissions in the 

catalytic cracking regenerator offgas. In this system, ozone is injected into the offgas to convert 

the nitrogen oxide (NO) and nitrogen dioxide (NO2) which comprise NOX into more highly 

oxidized forms of nitrogen such as dinitrogen pentoxide (N2O5). These more highly oxygenated 

compounds are more soluble in water, and are removed from the offgas stream in a wet scrubber. 

An emission control efficiency of 90% has been reported for this system.5,8 However, the

LoTOxTM system is more cost effective if used in conjunction with a wet scrubber to control SO2

emissions. Wet scrubbers are often used for simultaneous control of PM, SO2, and NOX

emissions from the catalyst regenerator.9In addition, cyclones and ESP are commonly used to 

control PM emissions in the catalyst regenerator offgas.5,10

SO2 emissions from fluid coking and coke calcining operations result from the 

combustion of a portion of the coke in a coke burner. Wet scrubbers have been used to control 

SO2 emissions from the coking unit, with reported efficiencies of 95% to over 99%.11 The 

emission streams from a coke calciner incinerator and from the coke burner in a fluid coking unit 

are similar to the emission streams from a boiler.11 Therefore, it is believed that NOX emissions 

from these streams can be controlled using SCR or SNCR.12,13

Petroleum refineries use flares to burn combustible gases that must be vented from 

various processes and cannot be practically processed or recovered. These gases generally 

emanate from non-steady-state operations, such as start-up, shut-down, process maintenance, and 

process upsets. Some of these operations are predictable, and others are not. SO2 emissions 

from flaring result from the flaring of sour gases or other gases which have high concentrations 

of sulfur compounds. These emissions can often frequently be reduced through the use of 

improved process controls or improved training of process operators. Emissions can also be 

reduced by expanding the sulfur recovery unit to handle all of the acid gases produced by the 

refinery, and by optimizing the performance of the sulfur recovery unit. All of these measures 

are designed to reduce the number of times that sulfur-containing gases are flared.5

A flare gas recovery system can also be used to capture waste gases before they are flared, and 

hold the gases until they can be treated to remove sulfur compounds.5 NOX emissions during 

flaring events can be mitigated by combustion controls such as steam injection.

10.1 Factor 1 – Costs

Table 10-3 provides cost estimates for the emission control options which have been 

identified for petroleum refineries. For each option, the table gives an estimate of the capital cost 

to install the necessary equipment, and the total annual cost of control, including the amortized 

cost associated with the capital equipment cost. The capital and annual cost figures are 

expressed in terms of the cost per unit process throughput. 
Source Type Control Technology

Pollutant

controlled

Estimated

control

effieiency (%)

Estimated

capital cost

($1000/unit)

Estimated annual

cost

($/year/unit) Units

Cost

effectiven

($/ton)

Fuel treatment toremove sulfur

SO2 up to 90 3.4 ‐ 10 28,000 ‐ 36,000 Refinery capacity,

1000 barrels/day

1,300 ‐ 1,7

LNB NOX 40 2.7 ‐ 7.6 290 ‐ 810 MM‐Btu/hr 650 ‐ 2,80

ULNB NOX 75 ‐ 85 2.8 ‐ 13 300 ‐ 1,300 MM‐Btu/hr 400 ‐ 2,00

LNB and FGR NOX 48 5.8 ‐ 16 640 ‐ 1,700 MM‐Btu/hr 1,000 ‐ 2,6

SNCR NOX 60 5.2 ‐ 22 570 ‐ 2,400 MM‐Btu/hr 890 ‐ 5,20

SCRb NOX 70 ‐ 90 33 ‐ 48 3,700 ‐ 5,600 MM‐Btu/hr 2,900 ‐ 6,7

LNB and SCR NOX 70 ‐ 90 37 ‐ 55 4,000 ‐ 6,300 MM‐Btu/hr 2,900 ‐ 6,3Catalyst additives for

NOX reduction

NOX 46 

LoTOXTM NOX 85 1,700 ‐ 2,0

SNCR NOX 40 ‐ 80 2500 

SCR NOX 80 ‐ 90 2500 Catalyst additives for

SO2 absorbtion

SO2 20 ‐ 60 

Desulfurization ofcatalytic cracker feed

SO2 up to 90 23 ‐ 54 190,000 ‐ 

250,000

Refinery capacity,

1000 barrels/day

6,200 ‐ 8,0

Wet scrubbing SO2 70 ‐ 99 1,500 ‐ 1,8

ESP PM2.5, PM10,

EC,OC

95+ >10,000 

Spray dryer absorber SO2 80 ‐ 95 1,500‐1,9

Wet FGD SO2 90 ‐ 99 1,500 ‐ 1,8

Improved processcontrol and operatortraining

SO2 Varies 

Expand sulfur recoveryunit

SO2 Varies 

Flare gas recovery

system

SO2 Varies 

aCosts of process modifications will depend on the specific refinery configuration.bSCR cost estimates for SCR apply to mechanical draft heaters. Natural draft heaters would have to be converted to mechanical draft for insta

This would increase both the capital and annualized costs of control by about 10%.

Flares not availablea

not availableanot availablea

Coking or coke

calcining boileroffgas

Table 10-3. Estimated Costs of Control Petroleum Refineries

ProcessheatersFluid catalytic

cracking units

not availablea

not availablea
10-6

Sulfur recovery units are believed to be more cost-effective than post-combustion 

controls for reducing SO2 emissions from flares and incinerators at natural gas processing 

facilities. Recent analyses of controls for Regional Haze precursors have focused on add-on 

controls for SO2, rather than such process modifications. However, costs of sulfur recovery units 

were estimated in an earlier study of model refineries in different size ranges.14 These estimates 

have been updated to current dollars using the Chemical Engineering plant cost index.

Table 10-3 shows a range of values for each cost figure, since the cost per unit of 

throughput will depend on the process size and other factors. The lower ends of the cost ranges 

typically reflect larger engine or process sizes, and the higher ends of the cost ranges typically 

reflect smaller process sizes. The table also shows the estimated cost effectiveness for each 

control measure, in terms of the cost per ton of emission reduction.

10.2 Factor 2 – Time Necessary for Compliance

Once a state decides to adopt a particular control strategy, up to 2 years will be needed to 

develop the necessary rules to implement the strategy. We have estimated that sources may then 

require up to a year to procure the necessary capital to purchase control equipment. The ICAC 

has estimated that approximately 13 months is required to design, fabricate, and install SCR or 

SNCR technology for NOX control.

15

 However, state regulators’ experience indicates that closer 

to 18 months is required to install this technology.16 In the CAIR analysis, EPA estimated that 

approximately 30 months is required to design, build, and install SO2 scrubbing technology for a 

single emission source.

17

 The analysis also estimated that up to an additional 12 months may be 

required for staging the installation process if multiple sources are to be controlled at a single 

facility. Based on these figures, the total time required achieve emission reductions for oil 

refineries estimated at a total of 61⁄2 years.

10.3 Factor 3 – Energy and Other Impacts

Table 10-4 shows the estimated energy and non-air pollution impacts of control measures 

for sources at petroleum refineries. Process modifications to desulfurize process gases burned in 

process heaters would generally require increases in catalytic hydrotreatment processing. These 

modifications may increase the generation of spent catalyst, which would need to be treated as a 

solid waste or a hazardous waste. Low NOX burners for process heaters are expected to improve 

overall fuel efficiency.3 FGR would require additional electricity to recirculate the fuel gas into 

the heater. In SCR systems for process heaters or other sources, fans would be required to 

overcome the pressure drop through the catalyst bed. The fans would require electricity, with 

resultant increases in CO2 to generate the electricity. In addition, spent catalyst would have to be 

changed periodically, producing an increase in solid waste disposal.10

Catalyst additives for reducing NOX and SO2 emissions from fluid catalytic cracking 

units are likely to result in increased generation of spent catalyst, which would have to be 

disposed as hazardous waste. These catalyst additives may also result in increases in fuel 

consumption. However, information is not available to quantify these impacts. A LoTOx 
Source Type Control Technology

Pollutant

controlled

Electricity

requirement

(kW‐hr)

Steam

requirement

(tons steam)

Solid waste

produced (tons

waste)

Wastewater

produced (1000

gallons)

Fuel treatment to

remove sulfur

SO2 0 ‐ 11 b 

LNB NOX 6aeULNB NOX 12 ‐ 13 a eLNB and FGR NOX 7.4 3,300 

SNCR NOX 9.2 0.16 460 SCR NOX 11 ‐ 14 8,400 0.073 

LNB and SCR NOX 11 ‐ 14 8,400 0.073 Catalyst additives for

NOX reduction

NOX 1.1 d d

LoTOXTM NOX 2.0 d d dSNCR NOX 0.93 ‐ 1.9 460 

SCR NOX 1.9 ‐ 2.1 8,400 0.073 

Catalyst additives for

SO2 absorbtion

SO2 3.4 ‐ 10 d d

Desulfurization ofcatalytic cracker feed

SO2 0 ‐ 15 d d d 

Wet scrubbing SO2 12 ‐ 17 1,100 3.1 3.7 

ESP PM2.5, PM10,

EC,OC

1.1 ‐ 1.2 97 1 

Spray dryer absorber SO2 8 ‐ 10 400 

Wet FGD SO2 9 ‐ 10 1,100 3.1 3.7 Improved processcontrol and operatortraining

SO2 Varies

Expand sulfur recovery

unit

SO2 Varies d d d 

Flare gas recovery

system

SO2 Varies d d d 

NOTES:

eSome designes of low‐NOX burners and ultralow‐NOX burners require the use of pressurized air supplies. This would require additional electricity to pressurize aThe measure is expected to improve fuel efficiency.bCO2 from the generation of electricity would be offset by avoided emissions due to replacing the diesel enginecEPA has estimated that the control measures used to meet Tier 4 standards will be integrated into the engine design so that sacrifices in fuel economy will be ndSome impact is expected but insufficient information is available to evaluate the impact.

blank indicates no impact is expected.Coking or cokecalcining boileroffgasFlares

Table 10-4. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Petroleum Refin

ProcessheatersFluid catalytic

cracking units

Potential

emission

reduction (1000

tons/year)

Additional fuel

requirement

(%)

Energy and non‐air pollution impacts (per ton of emission 
10-8

scrubbing system or wet scrubbing system applied to the fluidized catalytic cracking unit would 

require electricity to operate fans and other auxiliary equipment, and would produce a 

wastewater stream which would require treatment. In addition, sludge from the scrubber would 

require disposal as solid waste. SCR and SNCR systems would also require electricity for fans, 

and SCR systems would produce additional solid waste because of spent catalyst disposal. Dust 

captured by an ESP or fabric filter would also require disposal as a solid waste. The presence of 

catalyst fines in the dust may require treatment as a hazardous waste.

Sulfur recovery units require electricity and steam. Wet or dry scrubbers applied to 

incinerators and tail gas treatment units applied to sulfur recovery units would use electricity for 

the fan power needed to overcome the scrubber pressure drop. These systems would also 

produce solid waste, and wet scrubbers would produce wastewater which would require 

treatment.

10.4 Factor 4 – Remaining Equipment Life

Information was not available on the age of processes at petroleum refineries in the 

WRAP region. However, industrial processes often refurbished to extend their lifetimes. 

Therefore, the remaining lifetime of most equipment is expected to be longer than the projected 

lifetime of pollution control technologies which have been analyzed for this category. In the 

case of add-on technologies, the projected lifetime is 15 years. 

If the remaining life of an emission source is less than the projected lifetime of a 

pollution control device, then the capital cost of the control device would have to be amortized 

over a shorter period of time, corresponding to the remaining lifetime of the emission source. 

This would cause an increase in the amortized capital cost of the pollution control option, and a 

corresponding increase in the total annual cost of control. This increased cost can be quantified 

as follows:

where:

A1 = the annual cost of control for the shorter equipment lifetime ($)

A0 = the original annual cost estimate ($)

C = the capital cost of installing the control equipment ($)

r = the interest rate (0.07)

m = the expected remaining life of the emission source (years)

n = the projected lifetime of the pollution control equipment
10-9

10.5 References for Section 10

1. WRAP (2008), Emissions Data Management System, Western Regional Air Partnership, 

Denver, CO, http://www.wrapedms.org/app_main_dashboard.asp.

2. EPA (2006), SPECIATE version 4, U.S. EPA, RTP, NC,

http://www.epa.gov/ttn/chief/software/speciate/index.html.

3. EPA (1993), Alternative Control Techniques Document— NOX Emissions from Process 

Heaters (Revised), EPA-453/R-93-034, U.S. EPA, RTP, NC, pp 6-14 thru 6-36, 

http://www.epa.gov/ttn/catc/dir1/procheat.pdf.

4. MRPO (2006), Interim White Paper - Midwest RPO Candidate Control Measures Source 

Category: Petroleum Refining, http://www.ladco.org/reports/control/white_papers/.

5. NACAA (formerly STAPPA and ALAPCO) (2006), Controlling Fine Particulate Matter 

Under the Clean Air Act: A Menu of Options, National Association of Clean Air 

Agencies, www.4cleanair.org/ PM25Menu-Final.pdf.

6. Lake Michigan Air Directors Consortium (LADCO) (2005), Midwest Regional Planning 

Organization (RPO) Petroleum Refinery Best Available Retrofit Technology (BART) 

Engineering Analysis, http://www.ladco.org/Regional_Air_Quality.html.

7. European Commission (2003), Integrated Pollution Prevention and Control (IPPC): 

Reference Document on Best Available Techniques for Mineral Oil and Gas Refineries, 

http://eippcb.jrc.es/reference/ref.html.

8. Ahmed, Shafi (2007), Technical Bulletin: Work Group Recommendations and Other 

Potential Control Measures, Stationary Combustion Sources Workgroup, SCS004c, 

Fluid Catalytic Cracking Unit in a Petroleum Refinery, 

http://www.nj.gov/dep/airworkgroups/ docs/wps/SCS004C_fin2.pdf.

9. Eagleson, Scott, et. al (2005), A Logical and Cost Effective Approach for Reducing 

Refinery Fluid Catalytic Cracking Unit Emissions, Presented at PETROTECH-2005, the 

6th International Petroleum Conference & Exhibition, New Delhi, India.

10. EPA (2002), EPA Air Pollution Control Cost Manual, 6th ed., EPA/452/B-02-001, U.S. 

EPA, Office of Air Quality Planning and Standards, RTP, NC, 

http://www.epa.gov/ttncatc1/products.html#cccinfo.

11. EPA (2006), Final 2002 National Emissions Inventory, U.S. EPA, Office of Air Quality 

Planning and Standards, RTP, NC.

12. E.H. Pechan & Associates (2005), AirControlNET, Version 4.1 - Documentation Report, 

U.S. EPA, RTP, NC, http://www.epa.gov/ttnecas1/AirControlNET.htm.
10-10

13. MRPO (2006), Interim White Paper - Midwest RPO Candidate Control Measures Source 

Category: Industrial, Commercial, and Institutional (ICI) Boilers,

http://www.ladco.org/reports/control/white_papers/.

14. Research Triangle Institute (1972), Control Technology for Sulfur Oxide Pollutants, 2nd 

ed., Appendix B: Sulfur Emission Factors and Control Costs for Petroleum Refineries,

Prepared for the U.S. EPA, RTP, NC,

http://yosemite.epa.gov/ee/epa/eermfile.nsf/vwAN/EE-0233-05.pdf/$File/EE-0233-

05.pdf.

15 . Institute of Clean Air Companies (2006), Typical Installation Timelines for NOX 

Emissions Control Technologies on Industrial Sources, 

http://www.icac.com/files/public/ICAC_NOx_Control_Installation_Timing_120406.pdf.

16 . Ghoreishi, Farrokh (2007), Time required to install add-on control measures for NOX,

Personal communication, Wisconsin Department of Natural Resources.

17. EPA (2005), Boilermaker Labor Analysis and Installation Timing – Technical Support 

Document for the Final Clean Air Interstate Rule, OAR-2003-0053, U.S. EPA, 

Washington, DC, www.epa.gov/cair/technical.html#final.