# 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 analysi s 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 re asonable 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 strate gies.



## 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

– Remain ing 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 Im pacts

................................ ................................ ................................ ............ 4

- 10
4 .4 Factor 4

– Remaining Equipment Life

................................ ................................ ................................ ........... 4

- 1 3
4 .5 References for Section 4

................................ ................................ ................................ ................................ 4

- 1 3 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 Othe r 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 Impac ts

................................ ................................ ................................ .............. 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 Oth er 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 Othe r 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
CO 2 

### Carbon Dioxide
EC Elemental Carbon

E DMS Emissions Data Management System
EGU Electric Generating Units

EPA Environmental Protection Agency
ESP Electrostatic Precipitator
FCC Fluid Catalytic Cracking
FGR Flue Gas R ecirculation

FF Fabric Filters

H 2 

### S H ydrogen S ulf ide
ICAC Institute of Clean Air Companies
ICI Industrial/Commercial/Institutional
LEC Low

- Emission Combustion

LNB Low

- NOx Burn ers MRP O Midwest Regional Planning Organization

N 2 

### O 5 

### Dinitrogen P entoxide NAAQS National Ambient Air Quality Standards
NACAA Na tional Association of Clean Air Agencies

NEI National Emissions Inventory
NESCAUM Northeast States for Coordinated Air Use Management
NO Nitric Oxide
NO 2 

### Nitrogen Dioxide
NO
x 

### Nitrogen O xides
NSCR Nonselective Catalytic Reduction
NSPS New Source Perf ormance Standards
OC Organic Carbon
OFA Overfire Air

PM Particulate Matter

PM 10 

### Particulate Matter Particles of 10 Micrometers or Less

PM 2.5 

### 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
SO 2 

### Sulfur Dioxide

### vi

STAPPA State and Territorial Air Pollution Progr am 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 Ho ur MW Megaw att

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 meet ing 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 state s, 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 purp ose of this report is to analyze these factors for possible control strategies intended to improve visibility in the WRAP region. T he following priority source categories of
emissions are addressed :

1. Reciprocating internal combustion engines and t urbines
2. Oil and natural gas exploration and production field operations
3. Natural gas processing plants
4. I ndustrial 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 refiner ies

### 1

- 2

We have identified c ontrol measures for emi ssions of nitrogen oxides (NO X 

### ) and sulfur dioxide (SO 2 

### ), 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

pa rticulate matter emissions, we have evaluated the impacts of control measures on various particulate matter components, including PM 2.5 

### , PM 10 

### , e lemental carbon (EC) particulate matter,
and particulate organic carbon (OC)

. Data on emissions of volatile org anic compounds (VOC) were also collected. In addition, although VOC emission control measures were not explicitly evaluated in this study, the impacts of NO X 

### , SO 2 

### , and particulate matter controls on VOC were
calculated where co

- control benefits would occu r.

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.

T his report is organized in 1 0 sections, including this introduction. Section 2 describes the methodology for the four factor analysis. The next 8 sections present the resul ts 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 wa s to identify the major sources of emissions from the category. Emissions assessments were initi ally
ba sed 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 p rovided updated data when applicable. In some cases, detailed data on PM 10 

### and PM 2.5 

### emissions were
not available from the WRAP inventory. Therefore, PM 10 

### and PM 2.5 

### data from the U.S. Environmental Protection Agency’s (EPA) 2002 National Emissions Inven tory (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 AirControlNET 2 

### and CUECost

, 3 

### Best Available Retrofit Te chnology (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 ). 5 

### The opt ions 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 select ed 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 eq uipment 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 a re 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, a re 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 fu el 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 a nalyses 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 cos t 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 an alysis 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 F actor 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 an alysis 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).

I n 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 un der 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 s pecified 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 ( CO 2 

### ) produced
Reduced acid deposition
Reduced nitrogen deposition

Benefits from reductions in PM 2.5 

### 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
CO 2 

### ) produced

2. 4 Factor 4

– Remaining Equipment Life

Facto r 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) t hat 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 e xpected 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), AirControl NET, Version 4.1

- Documentation Report

, U.S. EPA , R TP , 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 Consort ium, 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 Opti ons , National Association of Cle an 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 Q uality Planning and Standards, RTP, NC, Section 5

- SO 2 

### 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 T

urbines

Reciprocating engines and turbines at industrial, commercial, and institutional facilities in the WRAP region are estimated to emit about 274,000 tons of NO X 

### per y ear, based on the 2002 emissions inventory for the region. 1 

### These sources a re 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 tha t are listed in the point source inventory ; however, the area sources inventory also includes about 27,000 tons of NO X 

### emissions from internal combustion engines. The area source emissions estimates are derived from industrial, commercial, and institution al fuel consumption in the WRAP states. NO X 

### emissions from internal combustion engines represent about 23% of total point source emissions of NO X 

### in the
WRAP region, and about 19% of all stationary source (point and area source ) NO X 

### emissions in the regio n.

Table 3

- 1 shows estimated emissions of NO X 

### , SO 2 

### , PM 10 

### , PM 2.5 

### and V OC in the WRAP region, broken down by state, engine type, and fuel. The emissions estimates for NO X 

### , SO 2 

### , and VOC were taken from the WRAP emissions data management system. 1 

### Estimates for PM 10 

### and
PM 2.5 

### were taken from the National Emissions Inventory (NEI). As the table shows, SO 2 

### , VOC and particulate matter emissions from reciprocating engines and turbines sources are much lower
than NO X 

### 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 PM 10 

### emissions using data from EPA’s SPECIATE database. 2 

### EC and OC are estimated to comprise 78.8% and 18. 5% of
diesel PM 10 

### emissions; and 38.4% and 24.7 % of natural gas combustion PM 10 

### 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 o perations, and at natural gas processing facilities. These emissions are included again in Chapters 3 and 4, which discuss control measures for these operations.

R eciprocating engines account for about 64% of the NO X 

### emissions from point sources in

t he 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 turb ines 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 recipr ocating engines range up to 850 tons of NO X 

### per year, and natural gas fired reciprocating engine emissions range up to 1,370 tons of NO X 

### per year. Individual diesel

- fired turbines range up to 1,400 tons of NO X 

### per year, and natural gas turbines range up t o 877 tons NO X 

### per year. 1AK AZ CA CO ID MT ND NM NV OR SD UT WA WY Tribes TotalPointsourcesTurbines‐gaseousfuel 44,293 3,593 11,832 4,233 697 321 524 9,433 4,088 2,028 372 1,302 1,267 2,113 1,890 87,987Turbines‐liquid 4,446 15 411 90 3 0 0 109 9 0 3 48 0 0 6 5,142Reciprocating‐gas 50 2,979 10,114 18,628 1,715 2,511 3,861 41,962 84 348 0 3,097 875 1,258 2,348 89,830Reciprocating‐liquid 12,779 1,370 12,735 5,336 312 3,968 305 6,714 209 0 7 2,156 114 13,060 5,051 64,116Areasource(unspecified)Naturalgas 0 0 14,778 0 0 0 0 0 70 0 0 0 0 0 0 14,848Kerosene 0 0 11,327 0 0 0 0 922 75 0 0 0 0 0 0 12,323Total61,569 7,957 61,197 28,287 2,726 6,800 4,691 59,141 4,535 2,376 383 6,602 2,256 16,431 9,294 274,246PointsourcesTurbines‐gaseousfuel 705 31 352 143 7 9 20 20 20 31 11 22 85 4 18 1,479Turbines‐liquid 2,539 1 75 3 0 0 0 0 0 3 0 4 0 0 0 2,628Reciprocating‐gas 0 2 180 65 0 0 12 244 0 0 0 8 53 11 200 774Reciprocating‐liquid 670 37 689 71 23 234 8 53 14 0 0 185 553 1 19 2,557Areasource(unspecified)Naturalgas 0 0 12 0 0 0 0 0 0 0 0 0 0 0 0 12Kerosene 0 0 708 00 0 0 84 0 0 0 0 0 0 0 793Total 3,915 71 2,016 281 31 243 40 402 34 35 11 219 691 17 238 8,243Turbines‐gas 167 765 459 335 976 115 0 105 27 542 4 6 13 0 2,481 5,995Turbines‐liquid 140 1 88 10 0 0 0 4 5 0 0 2 2 0 0 254Reciprocating‐gas 0 25 232 294 25 0 25 158 0 1 0 27 10 32 14 843Reciprocating‐liquid 179 14 436 42 201 56 2 64 135 1 0 26 1 0 279 1,435Total486 806 1,215 681 1,202 171 27 330 167 544 4 61 26 33 2,774 8,527Turbines‐gas 66 665 450 242 966 36 0 53 25 129 3 5 11 0 1,743 4,394Turbines‐liquid 127 1 80 10 0 0 0 3 5 0 0 2 2 0 0 231Reciprocating‐gas 0 24 231 294 25 0 25 160 0 1 0 23 10 32 13 837Reciprocating‐liquid 168 13 418 34 69 38 2 63 131 1 0 22 1 0 127 1,089Total361 703 1,179 580 1,060 74 27 280 161 131 4 52 23 33 1,884 6,551Turbines‐gas 665 93 1,088 652 27 66 40 548 20 217 35 81 65 49 69 3,715Turbines‐liquid 2 0 33 6 0 0 0 2 70 0 0 5 0 0 1 119Reciprocating‐gas 1 133 1,884 3,440 53 88 106 2,326 1 26 0 90 83 441 232 8,904Reciprocating‐liquid 466 29 824 1,340 11 216 23 3,044 9 0 0 198 7 1,236 128 7,531Total1,133 256 3,829 5,439 90 370 169 5,920 100 242 36 375 156 1,726 429 20,270Table 3-1. Emissions from Reciprocating Internal Combustion Engines and Turbines in the WRAP RegionNOXemissions in 2002 (tons/year)SO2emissions in 2002 (tons/year)PM10emissions in 2002 (tons/year)PM2.5emissions 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 the NEI.3

- 3



### Table 3

- 2 lists potential control measures for NO X 

### emissions from reciprocating engines
and turbines. A number of options were identified for stationary reciprocating eng ines 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 elect ronic 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
i nvolves modifying the combustion system to achieve very lean combustion conditions (high air

to

- 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 NO X 

### emissions from reciprocating engines or turbines by 90%. 6 

### In addition, Non

- Sele ctive 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 NO X 

### , particulate matter, and VOC.

A nother ACT guidance document analyzed control options for turbines using gaseous
and liquid fuels. 9 

### Turbines can be retrofit with w ater or steam inject ion to reduce emissions by up to 80%. In addition, SCR can be used in conjunction with water or steam injection or low

NO X 

### burner technology to reduce emissions by 93 to 96%. The ACT di d not analyze retrofit
installations or low

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

- NO X 

### burner technology).

3 .1 Factor 1

– Costs

Table 3

- 3 provides cost estimates fo r 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 amor tized cost associated with the capital equipment cost. Retrofit costs were not available
for low

- NO X 

### 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 end s 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 re duction.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 NO X 95 68 ‐ 80 65 ‐ 76 9

Low

‐ NO X burners NO X 95 68 ‐ 84 65 ‐ 80 9

SCR NO X 95 90 80 6,7,9

Water or steam injection with

SCR NO X 95 93 ‐ 96 88 ‐ 91 9

Air

‐ fuel ratio adjustment NO X 105 10 ‐ 40 10 ‐ 42 3

Ignition retarding technologies NO X 105 15 ‐ 30 16 ‐ 31 3

Low

‐ emission combustion (LEC) retrofit NO X 105 80 ‐ 90 84 ‐ 94 5

SCR NO X 105 90 94 3,4,6

NO X a 90 ‐ 99 a 4

VOC a 40 ‐ 85 a 4

NO X 105 100 105 8

SO 2 0.79 100 0.79

PM 10 0.84 100 0.84

PM 2.5 0.84 100 0.84

EC 0.32 100 0.32

OC 0.21 100 0.21

VOC 8.9 100 8.9

Overall b 115 116
Ignition timing retard NO X 76 15 ‐ 30 11 ‐ 23 3,8

EGR NO X 76 40 31 3,8

SCR NO X 76 80 ‐ 95 61 ‐ 73 3,4,6,8

NO X 76 87 67 8

PM 10 1.4 85 1.2

PM 2.5 1.1 85 0.9

EC 0.6 85 0.5

OC 0.5 85 0.4

VOC 7.5 87 6.6

Overall b 85 75

PM 10 1.4 25 0.4 7,8

PM 2.5 1.1 25 0.3

EC 0.6 25 0.2

OC 0.5 25 0.1

VOC 7.5 90 6.8

Overall b 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. NSCRSourceType ControlTechnologyPollutantcontrolledEstimatedcontrolefficiency(%)Estimatedcapitalcost($/unit)Estimatedannualcost($/year/unit) UnitsCosteffectiveness($/ton)Refer‐encesWaterorsteaminjection NOX68‐80 4.4‐16 2‐5 1000Btu 560‐3,100 9Low‐NOXburnersaNOX68‐84 8‐22 2.7‐8.5 1000Btu 5,200‐16,200 9SCR NOX90 8‐22 2.7‐8.5 1000Btu 2000‐10,000 6,7,9WaterorsteaminjectionwithSCRNOX93‐96 13‐34 5.1‐13 1000Btu 1,000‐6,700 9Air‐fuelratioadjustment NOX10‐40 4.4‐43 13‐86 hp 320‐8,300 3Ignitionretardingtechnologies NOX15‐30 na 10‐32 hp 310‐2,000 3LECretrofit NOX80‐90 120‐820 30‐210 hp 320‐2,500 5SCR NOX90 20‐180 40‐461 hp 430‐4,900 3,4,6NOX90‐99 17‐35 3‐6 hp 16‐36 4VOC 40‐85 1,500‐6,200 4Overallc16‐36NOX100 120‐140 38‐44 hp 100‐4,700 8SO2>13,000PM10>13,000PM2.5>13,000EC >33,000OC >50,000VOC 1,000‐60,000Overallc90‐4,300Ignitiontimingretard NOX15‐30 16‐120 14‐66 hp 1,000‐2,200 3,8EGR NOX40 100 26‐67 hp 780‐2,000 3,8SCR NOX80‐95 100‐2,000 40‐1,200 hp 3,000‐7,700 3,4,6,8NOX87 125 20 hp 900‐2,400 8PM1085 25,000‐68,000PM2.585 25,000‐68,000EC 85 >50,000OC 85 >50,000VOC 87 22,000‐59,000Overallc840‐2,200PM1025 10 1.7 hp 1,400 7,8PM2.525 1,400EC 25 3,300OC 25 4,200VOC 90 350Overallc280NSCRbbNSCRappliesonlytorich‐burnengines.Thedistributionofemissionsbetweenrich‐burnandlean‐burnenginesisnotknown.cForcontrolmeasuresreducingmultiplepollutants,theoverallcost‐effectivenessisthecostpertotalreductionofallpollutants.However,EC,OC,andPM2.5arecomponentsofPM10,andthereforearenotaddedseparatelytotheemissionreductiontotal.ReplacementofTier2engineswithTier4DieseloxidationcatalystTable 3-3. Estimated Costs of Control Options for Reciprocating Engines and TurbinesTurbinesReciprocatingengines,gaseousfuelsReplacementwithelectricmotorsReciprocatingengines,dieselandotherliquidfuelsaCostsestimatesforlow‐NOXburnersreflecttheincrementalcostsofnewlow‐NOXburnersversusstandardburners.Retrofitcostsforexistingburnerswerenotavailable.3

- 6



### 3 .2 Factor 2

– Time Necessary for Compliance

Once a state decides to adopt a particular control strateg y , up to 2 years will be needed to develop the necessary rules to implement the strategy. We h ave 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 S CR or SNCR technology for NO X 

### 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



### Add it ional 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 turb ines is estimated at a total of 5 1⁄2

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 CO 2 

### 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

co nsumption 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
CO 2 

### 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 CO 2 

### emissions to generate the electricity. In addition, spent

ca talyst would have to be changed periodically, producing an increase in solid waste disposal. 14SourceType ControlTechnologyPollutantcontrolledElectricityrequirement(kW‐hr)Steamrequirement(tonssteam)Solidwasteproduced(tonswaste)Wastewaterproduced(1000gallons)AdditionalCO2emitted(tons)Waterorsteaminjection NOX65‐76 a 31 8.1Low‐NOXburners NOX65‐80 aSCR NOX80 aWaterorsteaminjectionwithSCRNOX88‐91 0.45 0.026 1.7Air‐fuelratiocontrollers NOX10‐42 aIgnitionretardingtechnologies NOX16‐31 aLECretrofit NOX84‐94 aSCR NOX94 0.5 0.008 0.43NSCR NOX,VOC d 0.5 0.008 0.24NOX105 (100) 66,000 bSO20.79PM100.84PM2.50.84EC 0.32OC 0.21VOC 8.9Overalle116Ignitiontimingretard NOX11‐23 aEGR NOX31 2.7 2.0SCR NOX61‐73 0.5 0.008 0.38NOX67 c cPM101.2PM2.50.9EC 0.5OC 0.4VOC 6.6Overalle75PM100.4 0.5 b 316PM2.50.3EC 0.2OC 0.1VOC 6.82.5Overalle7.22.6dNOTES:Table 3-4. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Reciprocating Engines andTurbinesPotentialemissionreduction(1000tons/year)Additionalfuelrequirement(%)Energyandnon‐airpollutionimpacts(pertonofemissionreduced)aThemeasureisexpectedtoimprovefuelefficiency.bCO2fromthegenerationofelectricitywouldbeoffsetbyavoidedemissionsduetoreplacingthedieselengineTurbinesReciprocatingengines,gaseousfuelsReplacementwithelectricmotorsReciprocatingengines,dieselandotherliquidfuelseForcontrolmeasuresreducingmultiplepollutants,overallemissionsandreflectthesumofallpollutants.However,EC,OC,andPM2.5arecomponentsofPM10,andthereforearenotaddedseparatelytothetotals.Impactsareexpressedastheimpactpertonoftotalpolluantsreduced.ReplacementofTier2engineswithTier4DieseloxidationcatalystdNSCRappliesonlytorich‐burnengines.Thedistributionofemissionsbetweenrich‐burnandlean‐burnenginesisnotknown.cEPAhasestimatedthatthecontrolmeasuresusedtomeetTier4standardswillbeintegratedintotheenginedesignsothatsacrificesinfueleconomywillbenegligible.blankindicatesnoimpactisexpected.3

- 8



### 3

. 4 Factor 4

– Remaining Equipment Life

Information was not available on the a ge 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 tha n 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.

I f the remaining life of a reciprocating engine or turbine is les s 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:
A 1 

### = the annual cost of control for the shorter equipment lifeti me ($)
A 0 

### = 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 cont rol 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 C ontrol Techniques Document

— NO X 

### 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 N umber EPA

- HQ

- OAR

- 2005

- 0030

- 0054.

5

. Edgerton, Stephen, Judy Lee

- Greco, and Stephanie Walsh (2002)

, Stationary Reciprocating Internal Combustion Engines

– Updated Information on NO X 

### Emissions and Control Techniques

, U.S. E PA, RTP , NC.

6

. NACAA ( formerly S TAPPA and ALAPCO ) ( 2006 )

, Controlling Fine Particulate Mat ter 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), A lternative Control Techniques Document

— NO X 

### 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 NO X 

### Emissions Control Technologies on Indu strial Sources

.

11

. Ghoreishi, Farrokh (2007), Time required to install add

- on control measures for NO X

, 

### 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 u nderway to identify additional reserves

. Both the production and exploration industries involve a number of operations which emit NO X 

### , SO 2 

### , particulate matter and VOC. Turbines are used to drive compressors and other equ ipment, 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 a s 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 NO X 

### , SO 2 

### , and VOC from these operations
were extracted from the 2002 W RAP emissions inventory , which catalogs emission sources by their Standard Industrial Classification (SIC). 1 

### SIC 131 covers c r ude petroleum and natural gas production, and SIC 138 covers oil and gas field exploration services. Estimates for PM 10 

### and
PM 2. 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 s ector are also included in the emission totals reported in Table 3

- 1 (for all reciprocating engines and turbines). However, the point source inventor ies do not include small engines such as oil well motors and gas well engines. Emissions for these source s have been estimated by the WRAP in a separate oil and gas industry study, 2 

### and these estimates are also included in Table 4

- 1.

Based on the inventory emissions estimates

, NO X 

### emissions are the predominant regional haze precursor emissions in oil and ga s exploration and production operations . Overall NO X 

### emissions from these operations are estimated at about 294,000 tons/year , which represent about 20% of stationary source (point and area source) NO X 

### emissions in the region

. These result from
combustio n 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 operation s are fired by natural gas. Emission s from individual natural gas turbines at production operations range up to about
877 tons of NO X 

### per year, whic h is comparable to natural gas turbines at industrial facilities. Emissions from individual natural gas turbines at exploration operations range up to 131 tons of
NO X 

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

o perations are somewhat smaller than natural gas reciprocating engines at industrial facilities.
NO X 

### emissions from individual gas reciprocating engines range up to 700 tons per year for oilAK 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

ProductionAK 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

e ngines at oil and gas operations are also smaller than those at industrial facilities. NO X 

### emissions from individ ual 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



### SO 2 

### emissions fro m oil and gas exploration and production are estimated to be an order of magnitude lower than NO X 

### emissions. SO 2 

### emissions from incinerators and flares result from the presence of sulfur compounds in waste gases that are burned at the production site. Th ese 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, SO 2 

### emissions from these sources are reported t o be about 4,000 tons/year. These emissions may result from the combustion of unsweetened natural gas at the well head. SO 2 

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

PM 10 

### , PM 2.5 

### , and VOC emissi ons from oil and gas exploration and production are also estimated to be an order of magnitude lower than NO X 

### 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 PM 10 

### emissions using data from EPA’s SPECIATE database. 3 

### EC and OC are estimated to comprise 78.8% and 18.5% of diesel PM 10 

### emissions; and 38.4% and 24.7 % of natural gas combustion PM 10 

### emissions, respectively.

Table 4

- 2 lists potential control measures f or 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 c ontrol 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 mixtu re 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 recipr ocating 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 te chnologies to reduce NO X 

### 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



### SO 2 

### emissions from inci nerators 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 int o non

producing rock formations. 10 

### Flue gas scrubbing has also been used to control SO 2 

### emissions
from incinerators. 11

, 12 

### SO 2 

### emissions from existing sulfur recovery units can be reduced by adding additional recovery stages, or by adding a tail gas treatmen t unit. 12 

### In some cases, it may be possible to avoid SO 2 

### emissions from process heaters by substituting a lower

- sulfur sweetened natural gas for the gas currently being burned. A number of options are availab le toSource Type Control Technology Pollutant

controlled Baseline

emissions (1000 tons/yr) Estimated

control efficiency (%) Potential

emission

reduction (1000 tons/year) References Air-fuel ratio adjustment NO X 166 10 - 40 17 - 66 2,5

Ignition timing retard NO X 166 15 - 30 25 - 50 2

Low-emission combustion (LEC) retrofit NO X 166 80 - 90 130 - 150 2,5

SCR NO X 166 90 150 2,8,12

NO X a 90 - 99 a 8

VOC a 40 - 85 a 8

NO X 166 100 166 2

SO 2 0.30 100 0.30

PM 10 0.21 100 0.21

PM 2.5 0.21 100 0.21

EC 0.08 100 0.08

OC 0.05 100 0.05

VOC 5.9 100 5.9

Overall b 172 172

Ignition timing retard NO X 60 15 - 30 9 - 18 2

Exhaust gas recirculation NO X 60 40 24 2

SCR NO X 60 80 - 95 48 - 57 2,8,12

NO X 60 87 52 2

PM 10 0.2 85 0.2 2

PM 2.5 0.2 85 0.2

EC 0.1 85 0.1

OC 0.1 85 0.1

VOC 8.0 87 6.9 2

Overall b 68 59

PM 10 0.23 25 0.06 2

PM 2.5 0.18 25 0.05

EC 0.10 25 0.03

OC 0.08 25 0.02

VOC 8.0 90 7.2 2

Overall b 8.2 7.3

Water or steam injection NO X 47 68 - 80 32 - 38 11

Low-NO X burner (LNB) NO X 47 68 - 84 32 - 39 11

SCR NO X 47 90 42 6,7,12

Water or steam injection with

SCR NO X 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 NSCRSource 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 SO 2 8.5 90 - 95 c 9

Acid gas injection SO 2 8.5 100 c 10

Spray dryer absorber SO 2 9.0 80 - 95 7.2 - 8.6 12

Wet FGD SO 2 9.0 90 - 99 8.1 - 9 11,12

Acid gas injection SO 2 9.0 100 c 10

Additional recovery stages SO 2 2.4 94 - 96 2.2 - 2.3 11,14
Tail gas treatment unit (TGTU) SO 2 2.4 90 - 99.5 2.1 - 2.4 11,14

Substitution of lower sulfur

fuel SO 2 4.0 up to 90 0 - 3.6 9,12

LNB NO X 3.1 40 1.2 13,14

ULNB NO X 3.1 75 - 85 2.3 - 2.6 12,13,14

LNB and FGR NO X 3.1 48 1.5 13,14

SNCR NO X 3.1 60 1.9 12,13,14

SCR d NO X 3.1 70 - 90 2.2 - 2.8 12,13,14

LNB and SCR NO X 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 NO X 

### emissions from process heaters. Combustion modifications including low

- NO X 

### burners (LNB), ultralow

- NO X 

### burners (ULNB), and flue gas recirculation (FGR) reduce the
formation of NO X 

### . In addition, flue gases from the process heaters can be treated with selective catalytic reduction (SCR) or selective non

- catalytic reduction (SNCR) to reduce NO X 

### emissions. These post

- combustion controls can be used either alone or in conjunction with combustion
controls. 13

, 14



### 4 .1 Factor 1

– C osts

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 t he 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 th roughput. E ngine size is expressed in horsepower for reciprocating engines and
MMB tu/h ou r 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 s ulfur
recovered.

Sulfur recovery units are believed to be more cost

- effective than post

- combustion controls for reducing SO 2 

### emissions from flares and incinerators at oil and gas production operations . Recent analyses of controls for Regional Haze prec ursors have focused on add

- on controls for SO 2 

### , 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 fa ctors. 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 strateg y , 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, fabr icate, and install SCR or SNCR technology for NO X 

### 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 th is technology. 16 

### In the CAIR analysis, EPA estimated that approximately 30 months is required to design, build,
and install SO 2 

### scrubbing technology for a single emission source

. 17 

### The analysis also estimated that up to an additional 12 months may be requi red 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 6 1⁄2 years.SourceType ControlTechnologyPollutantcontrolledEstimatedcontrolefficiency(%)Estimatedcapitalcost($/unit)Estimatedannualcost($/year/unit) UnitsCosteffectiveness($/ton)Refer‐encesAir‐fuelratioadjustment NOX10‐40 5.3‐42 0.9‐6.8 hp 68‐2,500 2,5Ignitiontimingretard NOX15‐30 na 1‐3 hp 42‐1,200 2LECretrofit NOX80‐90 120‐820 30‐210 hp 320‐2,500 5SCR NOX90 100‐450 40‐270 hp 870‐31,000 2,8,12NOX90‐99 17‐35 3‐6 hp 16‐36 8VOC 40‐85 1,500‐6,200 8Overallb16‐36NOX100 120‐140 38‐44 hp 100‐4,700 2SO2>55,000PM10>79,000PM2.5>79,000EC>205,000OC>319,000VOC 3,000‐130,000Overallb100‐4,500Ignitiontimingretard NOX15‐30 16‐120 14‐66 hp 1,000‐2,200 2EGR NOX40 100 26‐67 hp 780‐2,000 2SCR NOX80‐95 100‐2,000 40‐1,200 hp 3,000‐7,700 2,8,12NOX87 125 20 hp 900‐2,400 2PM1085 125 20 hp 25,000‐68,000 2PM2.5ECOCVOC 87 125 20 hp 22,000‐59,000 2Overallb840‐2,200PM1025 10 1.7 hp 1400 2PM2.51400EC3,300OC4,200VOC 90 10 1.7 hp 350 2Overallb280Table 4-3. Estimated Costs of Control for Oil and Gas Production and ExplorationDrillingrigenginesandotherenginesDieseloxidationcatalystReplacementofTier2engineswithTier4CompressorenginesReplacementwithelectricmotorsNSCRaSourceType ControlTechnologyPollutantcontrolledEstimatedcontrolefficiency(%)Estimatedcapitalcost($/unit)Estimatedannualcost($/year/unit) UnitsCosteffectiveness($/ton)Refer‐encesTable 4-3. Estimated Costs of Control for Oil and Gas Production and ExplorationWaterorsteaminjection NOX68‐80 4.4‐16 2‐5 1000BTU 560‐3,100 7Low‐NOXburnerscNOX68‐84 8‐22 2.7‐8.5 1000BTU 2,000‐10,000 7SCR NOX90 13‐34 5.1‐13 1000BTU 1,000‐6,700 6,7,12WaterorsteaminjectionwithSCRNOX93‐96 13‐34 5.1‐13 1000BTU 1,000‐6,700 7AddorexpandsulfurrecoveryunitSO290‐95 0.1‐1.1 28‐190 ton‐Sulfur/year 14‐95 9Acidgasinjection SO210010Spraydryerabsorber SO280‐95 1,500‐1,900 12WetFGD SO290‐99 1,500‐1,800 11,12Acidgasinjection SO210010Additionalrecoverystages SO294‐9611,14Tailgastreatmentunit(TGTU)SO290‐99.5 1,100‐1,200 11,14SubstitutionoflowersulfurfuelSO2upto909,12LNB NOX40 3.8‐7.6 0.41‐0.81 1000BTU 2,100‐2,800 13,14ULNB NOX75‐85 4.0‐13 0.43‐1.3 1000BTU 1,500‐2,000 12,13,14LNBandFGR NOX48 16 1.7 1000BTU 2,600 13,14SNCR NOX60 10‐22 1.1‐2.4 1000BTU 4,700‐5,200 12,13,14SCRdNOX70‐90 33‐48 3.7‐5.6 1000BTU 2,900‐6,700 12,13,14LNBandSCR NOX70‐90 37‐55 4‐6.3 1000BTU 2,900‐6,300 12,13,14GlycoldehydratorsOptimizeglycolcirculationrateVOC 33‐67 31‐170 5‐28 gal/hr 2dSCRcostestimatesforprocessheatersapplytomechanicaldraftheaters.NaturaldraftheaterswouldhavetobeconvertedtomechanicaldraftforinstallationofSCR.Thiswouldincreaseboththecapitalandannualizedcostsofcontrolbyabout10%.aNSCRappliesonlytorich‐burnengines.Thedistributionofemissionsbetweenrich‐burnandlean‐burnenginesisnotknown.bForcontrolmeasuresreducingmultiplepollutants,theoverallcost‐effectivenessisthecostpertotalreductionofallpollutants.However,EC,OC,andPM2.5arecomponentsofPM10,andthereforearenotaddedseparatelytotheemissionreductiontotal.cCostsestimatesforlow‐NOXburnersforturbinesreflecttheincrementalcostsofnewlow‐NOXburnersversusstandardburners.Retrofitcostsforexistingburnerswerenotavailable.FlaresSulfurrecoveryunitsProcessheatersIncineratorsTurbines4

- 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 reciprocatin g 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 CO 2 

### 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 co nsumption 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 reciprocatin g 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 requir e 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
CO 2 

### 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 catal yst bed. 18 

### This would produce an increase in CO 2 

### 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 ov ercome 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, thi s option would also result in the sequestration of CO2 present in the injected gas

stream. 10



### Low

- NO X 

### burners for process heaters are expected to improve overall fuel efficiency. FGR would require additional e lectricity 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 CO 2 

### to generate the electricity. In addition, spent catalyst would have to be changed periodically, producing an increase in solid waste disposal. 20Electricity
requirement (kW-hr) Steam

requirement (tons steam) Solid waste

produced (tons waste) Wastewater

produced (1000 gallons) Additional CO 2

emitted (tons) Air-fuel ratio adjustment NO X 17 - 66 a

Ignition retarding technologies NO X 25 - 50 a

LEC retrofit NO X 130 - 150 a

SCR NO X 150 0.5 0.008 0.43

NSCR NO X , VOC e 0.5 0.008 0.24

Replacement with electric

motors NO X 166 (100) 66,000 b

Ignition timing retard NO X 9 - 18 a

EGR NO X 24 2.7 2.0

SCR NO X 48 - 57 0.5 0.008 0.38

NO X 52 c c

PM 2.5 , PM 10 , EC, OC 0.2 c c

VOC 6.9 c c

Total e 59

PM 2.5 , PM 10 , EC, OC 0.1 0.5 b 316

VOC 7.2 2.5

Total f 7.3 2.6 e

Water or steam injection NO X 32 - 38 a 31 8.1

Low-NO X burner (LNB) NO X 32 - 39 a

SCR 42 a Water or steam injection

with SCR NO X 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

TurbinesElectricity
requirement (kW-hr) Steam

requirement (tons steam) Solid waste

produced (tons waste) Wastewater

produced (1000 gallons) Additional CO 2

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 SO 2 0 - 3.6 b b

LNB NO X 1.2 a g

ULNB NO X 2.3 - 2.6 a g

LNB and FGR NO X 1.5 3,300 3.3

SNCR NO X 1.9 0.16 460 3.2

SCR NO X 2.2 - 2.8 8,400 0.073 8.4

LNB and SCR NO X 2.2 - 2.8 8,400 0.073 8.4
Add or expand sulfur
recovery unit NO X up to 8.5 270 3.2 <0.01 1.1

Acid gas injection SO 2 up to 8.5 d h

Spray dryer absorber SO 2 7.2 - 8.6 400 3.7 1.1

Wet FGD SO 2 8.1 - 9 1,100 3.1 2.8 3.7 2.6

Acid gas injection SO 2 up to 9.0 d h

Additional recovery stages SO 2 2.2 - 2.3 270 3.2 <0.01 1.1

Tail gas treatment unit (TGTU) SO 2 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 CO 2 present in the acid gas stream. b CO 2 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 PM 2.5 are components of PM 10 , 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. T he remaining lifetime of most equipment is expected to be longer than the projected lifetime of pollution control technologies which have bee n analyzed for this category. In the case of add

- on technologies

, the projected lifetime is 15 years.

I f 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 de vice 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:
A 1 

### = the annual cost of control for the shorter equipment lifetime ($)
A 0 

### = 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 (2 008), 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 Abiga il Hoats (2007)

, WRAP Area Source Emissions Inventory Protection and Control Strategy Evaluation

- Phase II

, Western Governor's Association, Denver, C O

, 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

— NO X 

### 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 NO X 

### Emissions and Control Techniques

, U.S. E PA, 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

— NO X 

### 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.p df/$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

- Documen tation Report

, U.S. EPA, RTP, NC

, http://www.epa.gov/ttnecas1/AirControlNET.htm

.

12

. NACAA ( formerly STAPPA and ALAPCO ) ( 2006 )

, Controlling Fine Particulate Mat ter Under the Clean Air Act: A Men u of Options, National Association of Clean Air Agencies

, www.4cleanair.org/ PM25Menu

- Final.pdf

.

13

. EPA (1993), Alternative Control Techniques Document

— NO X 

### Emissions from Process Heaters (Revi sed) , 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 NO X 

### Emissions Control Tech nologies on Industrial Sources

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

. .

16

. Ghoreishi, Farrokh (2007), Time require d to install add

- on control measures for NO X

, 

### 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 R ule . 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, E ngines & 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 Pro cessing Operations

Natural ga s 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 fractionat ed 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. Tu rbines 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 SO 2 

### emanate from sul fur 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 NO X 

### , SO 2 

### , and VOC from these ope rations were extracted from the 2002 WRAP emissions inventory , which catalogs emission sources by their Standard Industrial Classification (SIC). 1 

### SIC 13 2 covers natural gas

pro cessing

. Estimates for PM 10 

### and PM 2.5 

### 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 reciproca ting 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 NO X 

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

, and SO 2 

### emi ssions are estimated at about 12,000 tons/year. These emissions represent about 2 % of stationary source (point and area source) NO X 

### emissions , and 1% of stationary source SO 2 

### emissions in the region

.

PM 10 

### and PM 2.5 

### emissions from natural gas processing facilities are estimated to be an order of magnitude lower than NO X 

### 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
PM 10 

### emissions using data from EPA’s SP ECIATE database. 2 

### EC and OC are estimated to comprise 38.4% and 24.7 % of natural gas combustion PM 10 

### 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 NO X 

### per year, comp ared with 845 tons per year for the largest natural gas turbines at
in dustrial 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 incinerat ors, 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, andEmissionsource AK CA CO MT ND NM NV UT WY Tribes TotalReciprocatingengines(naturalgas)86 626 1,027 33 2,428 15,976 0 612 1,935 1,140 23,863Turbines 1,533 11 107 0 0 4,317 0 0 27 486 6,482Processheaters 19 7 30 0 55 263 0 1 122 1 498Boilers 1 29 60 0 0 193 0 20 6 26 335Flares 0 14 1 0 0 56 0 1 25 0 97Othera0 14 5 0 10 122 0 1 82 0 234Total1,639 686 1,228 33 2,493 20,871 0 634 2,172 1,654 31,411Sulfurrecoveryunits00001,604 4,739 0 0 196 0 6,539Flares0 1 0 0 673,628 0 0 506 0 4,203Incinerators0 0 0 0 358 417 0 0 0 0 775Processheaters0 0 0 0 0 274 0 0 0 7 281Othera0 1 1 0 0 14 0 0 6 113 136Total02102,030 9,072 0 0 708 119 11,934Reciprocatingengines‐naturalgas0 3 0 0 25 70 0 4 0 0 102Othera2 3 4 0 0 20 0 1 1 0 31Total2 6 4 0 25 90 0 5 1 0 134Reciprocating engines -natural gas0 3 0 0 25 70 0 3 0 0 102Othera2 3 4 0 0 19 0 1 1 0 30Total2 6 4 0 25 90 0 4 1 0 131Storage 0 10 52,006 0 5 395 0 12 146 35 52,610Reciprocatingengines 0 687 102 20 44 1,135 0 13 278 29 2,308Fugitiveemissions 0 308 91 0 0 317 0 5 242 132 1,095Glycoldehydrator 0 2 118 0 0 113 0 31 55 5 324Turbines 100 0 0 0 187 0 0 0 21 219Othera1 89 210 0 2 54 0 90 35 35 515Total11 1,095 52,527 20 51 2,202 0 151 757 257 57,070aIncludesglycoldehydratorreboilers,incinerators,aminetreatmentunits,andsourcesnotspecificallyclassifiedintheemissionsinventory.ForSO2,incineratorsarebrokenoutseparately.NOXemissions(tons/year)SO2emissions(tons/year)VOCemissions(tons/year)Table 5-1. Emissions from Natural Gas Processing in the WRAP RegionPM10emissions(tons/year)PM2.5emissions(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 NO X 24 10 ‐ 40 2 ‐ 10 3,7

Ignition timing retard NO X 24 15 ‐ 30 4 ‐ 7 3,7

Low

‐ emission combustion (LEC) retrofit NO X 24 80 ‐ 90 19 ‐ 21 4,7

SCR NO X 24 90 21 7,8,12

NO X a 90 ‐ 99 a 8

VOC a 40 ‐ 85 a 8

NO X 24 100 24 7

PM 10 0.10 100 0.10

PM 2.5 0.10 100 0.10

EC 0.04 100 0.04

OC 0.03 100 0.03

VOC 2 100 2

Overall b 26 26

Water or steam injection NO X 6.5 68 ‐ 80 4.4 ‐ 5.2 6

Low

‐ NO X burner (LNB) NO X 6.5 68 ‐ 84 4.4 ‐ 5.4 6

SCR NO X 6.5 90 5.8 5,6

Water or steam injection with

SCR NO X 6 93 ‐ 96 6 6

Substitution of lower sulfur

fuel SO 2 0.28 up to 90 0 ‐ 0.25 9,12

LNB NO X 0.50 40 0.20 13,14

ULNB NO X 0.50 75 ‐ 85 0.37 ‐ 0.42 12,13,14

LNB and FGR NO X 0.50 48 0.24 13,14

SNCR NO X 0.50 60 0.30 12,13,14

SCR c NO X 0.50 70 ‐ 90 0.35 ‐ 0.45 12,13,14

LNB and SCR NO X 0.50 70 ‐ 90 0.35 ‐ 0.45 12,13,14

LNB with OFA NO X 0.33 30 ‐ 50 0.1 ‐ 0.17 11,12

LNB, OFA, and FGR NO X 0.33 30 ‐ 50 0.1 ‐ 0.17 11,12

SNCR NO X 0.33 30 ‐ 75 0.1 ‐ 0.25 11,12

SCR NO X 0.33 40 ‐ 90 0.13 ‐ 0.3 11,12

Add or expand sulfur recovery
unit SO 2 4.2 90 ‐ 95 d 9

Acid gas injection SO 2 4.2 100 d 10

Additional recovery stages SO 2 6.5 94 ‐ 96 6.1 ‐ 6.3 11,14

Tail gas treatment unit (TGTU) SO 2 6.5 90 ‐ 99.5 5.9 ‐ 6.5 11,14

Spray dryer absorber SO 2 0.78 80 ‐ 95 0.62 ‐ 0.74 12

Wet FGD SO 2 0.78 90 ‐ 99 0.7 ‐ 0.77 11,12

Acid gas injection SO 2 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 engin es 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 NO X 

### 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



### SO 2 

### 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 com pressing sulfur

- containing acid gases and injecting these gases into non

producing rock formations. 10 

### Flue gas scrubbing has also been used to control SO 2 

### emissions
from incinerators. 11

, 12 

### SO 2 

### 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 SO 2 

### emissions from process heaters by substituting a lower

- sulfur sweetened natural gas f

or the gas currently being burned. A number of options are available to
reduce NO X 

### emissions from process heaters. Combustion modifications includ ing LNB, ULNB, and FGR reduce the formation of NO X 

### . In addition, flue gases from the process heaters can be
treated with SCR or SNCR to reduce NO X 

### 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 c ontrol 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 asso ciated 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. E ngine size is expressed in horsepower for reciprocating engines and MMB tu/h ou r 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

- comb ustion controls for reducing SO 2 

### 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 SO 2 

### , rather than such process modifications. Howeve r, 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 co st 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 size s, and t he higher ends of the cost ranges typically reflect smaller engine or process sizes. The t able also shows the5

- 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 proc ure 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 NO X 

### control. 15 

### However, the time

neces sary 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 SO 2 

### 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 con sumption by up to 5%, with a typical value of about 2.5%. 18

, 19 

### This increased fuel consumption would result in increased CO 2 

### 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 incr ease 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
CO 2 

### 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 CO 2 

### emissions to generate the electricity. In addition, spent catalyst would have to be changed periodically, producing an increase in solid waste disposal. 13Source 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 NO X 10 ‐ 40 5.3 ‐ 42 0.9 ‐ 6.8 hp 68 ‐ 2,500 3,7

Ignition timing retard NO X 15 ‐ 30 na 1 ‐ 3 hp 42 ‐ 1,200 3,7

LEC retrofit NO X 80 ‐ 90 120 ‐ 820 30 ‐ 210 hp 320 ‐ 2,500 4,7

SCR NO X 90 100 ‐ 450 40 ‐ 270 hp 870 ‐ 31,000 7,8,12

NO X 90 ‐ 99 17 ‐ 35 3 ‐ 6 hp 16 ‐ 36 4

VOC 40 ‐ 85 1,500 ‐ 6,200 4

Overall b 16 ‐ 36
Replacement with electric

motors all b 100 120 ‐ 140 38 ‐ 44 hp 100 ‐ 4,700 7

Water or steam injection NO X 68 ‐ 80 4.4 ‐ 16 2 ‐ 5 1000 Btu/hr 560 ‐ 3,100 6

Low

‐ NO X burners c NO X 68 ‐ 84 8 ‐ 22 2.7 ‐ 8.5 1000 Btu/hr 5,200 ‐ 16,200 6

SCR NO X 90 13 ‐ 34 5.1 ‐ 13 1000 Btu/hr 1,000 ‐ 6,700 5,6

Water or steam injection

with SCR NO X 93 ‐ 96 13 ‐ 34 5.1 ‐ 13 1000 Btu/hr 1,000 ‐ 6,700 6

Substitution of lower

sulfur fuel SO 2 up to 90 9,12

LNB NO X 40 3.8 ‐ 7.6 0.41 ‐ 0.81 1000 BTU 2,100 ‐ 2,800 13,14

ULNB NO X 75 ‐ 85 4.0 ‐ 13 0.43 ‐ 1.3 1000 BTU 1,500 ‐ 2,000 12,13,14

LNB and FGR NO X 48 16 1.7 1000 BTU 2,600 13,14

SNCR NO X 60 10 ‐ 22 1.1 ‐ 2.4 1000 BTU 4,700 ‐ 5,200 12,13,14

SCR d NO X 70 ‐ 90 33 ‐ 48 3.7 ‐ 5.6 1000 BTU 2,900 ‐ 6,700 12,13,14

LNB and SCR NO X 70 ‐ 90 37 ‐ 55 4 ‐ 6.3 1000 BTU 2,900 ‐ 6,300 12,13,14

LNB with OFA NO X 30 ‐ 50 500 ‐ 5,300 11,12

LNB, OFA, and FGR NO X 30 ‐ 50 500 ‐ 11,000 11,12

SNCR NO X 30 ‐ 75 400 ‐ 2,500 11,12

SCR NO X 40 ‐ 90 2,400 ‐ 7,200 11,12

Add or expand sulfur

recovery unit NO X 90 ‐ 95 0.1 ‐ 1.1 28 ‐ 190 ton

‐ Sulfur/year 14 ‐ 95 9

Acid gas injection SO 2 95 10

Additional recovery stages SO 2 94 ‐ 96 0.1 ‐ 1 28 ‐ 150 ton

‐ Sulfur/year 14 ‐ 75 9

Tail gas treatment unit (TGTU) SO 2 90 ‐ 99.5 0.3 ‐ 1.1 67 ‐ 190 ton

‐ Sulfur/year 33 ‐ 95 9

Spray dryer absorber SO 2 80 ‐ 95 1,500

‐ 1,900 12

Wet FGD SO 2 90 ‐ 99 1,500 ‐ 1,800 11,12

Acid gas injection SO 2 100 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

‐ NO X burners for turbines reflect the incremental costs of new low

‐ NO X 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%. NSCR a

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 CO 2

emitted (tons)

Air-fuel ratio controllers NO X 2 - 10 a

Ignition timing retard NO X 4 - 7 a

LEC retrofit NO X 19 - 21 a

SCR NO X 21 0.5 0.008 0.43

NSCR NO X , VOC e 0.5 0.008 0.24

Replacement with

electric motors NO X 24 (100) 66,000 b

Water or steam injection NO X 4.4 - 5.2 a 31 8.1

Low-NO X burner (LNB) NO X 4.4 - 5.4 a

SCR NO X 5.8 0.45 0.026 1.7

Water or steam injection

with SCR NO X 6 0.45 0.026 1.7

Substitution of lower

sulfur fuel SO 2 0 - 0.25

LNB NO X 0.2 a f

ULNB NO X 0.37 - 0.42 a f

LNB and FGR NO X 0.24 3,300 3.3

SNCR NO X 0.3 0.16 460 3.2

SCR NO X 0.35 - 0.45 8,400 0.073 8.4

LNB and SCR NO X 0.35 - 0.45 8,400 0.073 8.4

LNB with OFA NO X 0.1 - 0.17 a
LNB, OFA, and FGR NO X 0.1 - 0.17 3,300 3.3

SNCR NO X 0.1 - 0.25 0.16 460 3.2

SCR NO X 0.13 - 0.3 8,400 0.073 8.4

Add or expand sulfur
recovery unit SO 2 up to 4.2 270 3.2 <0.01 1.1

Acid gas injection SO 2 up to 4.2 d g
Additional recovery

stages SO 2 6.1 - 6.3 270 3.2 <0.01 1.1

Tail gas treatment unit (TGTU) SO 2 5.9 - 6.5 190 3.5 3.7 1.1

Spray dryer absorber SO 2 0.62 - 0.74 400 1.1

Wet FGD SO 2 0.7 - 0.77 1,100 3.1 3.7 2.6

Acid gas injection SO 2 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 CO 2 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 CO 2 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 CO 2 

### present in the injected gas

stream. 10



### Low

- NO X 

### 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 t hrough the catalyst bed. The fans would require electricity, with resultant increases in CO 2 

### 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. T he remaining lifetime of most equipment is expected to be lo nger 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.

I f the remaining life of an emission source is less than the projecte d 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 c apital 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:
A 1 

### = the annual cost of control for the shorter equipment lifetime ($)
A 0 

### = the o riginal 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

— NO X 

### 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

– U pdated Information on NO X 

### Emissions and Control Techniques

, U.S. E PA, 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

— NO X 

### E missions 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, C O

, 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 , R TP , 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 Mat ter Under the Clean Air Act: A Menu of Options, National Association of Clean Air Agencie s.

13

. EPA (1993), Alternative Control Techniques Document

— NO X 

### 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 NO X 

### Emissions Control Technologies on Industrial Sources

.5

- 10



### 16

. Ghoreishi, Farrokh (2007), Time required to install add

- on control measures for NO X

, 

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

.

17

. EPA (2005), Boilermaker Labor Analysis and Installation Timin g

– 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 boiler s 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 fo r 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 NS PS 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 repor t 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 tables 2 

### lists a total of 2,171 facilities with industrial boilers in the 102XXX Source Classification Code (SCC). The majority of the boilers are located at facil ities in the food, paper, chemicals, refining and primary metals industries. The most common fuel used for combustion is natural gas with n early 73% of the facilities in the WRAP region operat ing natural gas

- fired
industrial boilers.

Industrial boilers in the WRAP region are estimated to emit about 43,060 tons of NO X 

### and 28,155 tons of SO 2 

### , based on the 2002 emissions inventory for the region. 3 

### These boilers utilize the combustion of fuel which includes; coal, oil, natural gas , wa ste, and wood, to produce
steam. Coal

- fired industrial boilers comprise of 15,920 tons of NO X 

### , or 37 % of the total NO X 

### emissions

, and 14,376 tons , or 5 1 % of the total SO 2 

### emissions from industrial boilers in the WRAP region. I ndustrial boilers represent about 4.1 % of the total point source emissions of
NO X 

### , and about 3.4 % of the total SO 2 

### point source emissions in the WRAP region.

Table 6

- 1 shows estimated emissions of NO X 

### , SO 2 

### , PM 10 

### , PM 2.5 

### , and VOC from the WRAP emissions inventory, broken down by st ate and fuel. The table shows that PM 10 

### , PM 2.5 

### , and VOC emissions from industrial boilers ar e significantly lo wer than the NO X 

### and SO 2 

### emissions. Emissions of PM from these sources were not included in the inventory , but are expected to be much lower tha n the NO X 

### and SO 2 

### emissions. As the table shows, coal

- fired boilers were the most significant source of NO X 

### , SO 2 

### , and VOC emissions in the WRAP region.
For NO X 

### , coal fired boilers accounted for about 56 % of the emissions from point sources

, and
41% of th e total stationary source emissions in the WRAP region.

Table 6

- 2 a lists potential control measures for NO X 

### , SO 2 

### , PM 10 

### , PM 2.5 

### , 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 identifi ed using information from6

- 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 NO X 

### , SO 2 

### , PM 10 

### , PM 2.5 

### , EC, and OC coal

fired 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 vi sibility 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 Avail able 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 emiss ion 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

- 36

- 46

- 56

- 66

- 76

- 8

6 

### .1 Factor 1

– Costs

Table 6

- 3 provides cost estimates for the em ission 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 a ssociated 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 ref lect 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
h igher 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 strateg y , up to 2 years will be needed to develop the necessar y 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 1 8 months is requ ired to design, fabricate, and install SCR or SNCR technology for NO X 

### control , and approximately 30 months to design, build, and install SO 2 

### scrubbing technology

. 9 

### Addit ional time of up to 12 months may be required for staging the installation process if multiple boilers a re 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 NO X 

### strategies, and 61⁄2 years for SO 2 

### 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 CO 2 

### . 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 require s energy for compressor power and steam for mixing. This would produce a small increase in CO 2 

### emissions to generate electricity; however the technology itself do es not produce additional CO 2 

### 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
CO 2 

### emissions to generate the electricity. In addition, spent catalyst would have to be changed periodically, producing an increase in solid waste disposal.6

- 96

- 106

- 11



### For SO 2 

### control technologies, energy is required material preparation (e.g., grinding), materials handling (e.g., pumps/b lowers), 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 pr oduce an increase in CO 2 

### 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

. E nergy and E nvironmental A nalysis (2005)

, Characteriza tion 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 Joi nt Forum, Western R egional 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 Admi nistrators and Association of Local Air Pollution Control Officials.

7

. Khan, Sikander (2003), Methodology, Assumptions, and References: Preliminary NO X 

### Controls Cost Estimates for Industrial Boilers.

8

. Khan, Sikander (2003), Methodology, Assumptions, a nd References: Preliminary SO 2 

### Controls Cost Estimates for Industrial Boilers.

9

. NESCAUM (200 9 )

, Applicability and Feasibility of NO X 

### , SO 2 

### , and PM Emission Control Technologies for Industrial, Commercial, and Institutional (ICI) Boilers

.

1 0

. Institute o f Clean Air Companies (2006), Typical Installation Timelines for NO X 

### Emissions Control Technologies on Industrial Sources

.7

- 1 

# 7

. Cement Kilns

The main emission unit s 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 SO 2 

### 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 SO 2 

### control

.

Cement kilns at cement manufacturing facilities in the WRAP region are estimated to
emit about 40

, 610 tons of NO X 

### ; 6,2 30 tons of SO 2 

### ; 1,57 3 tons of PM 2 .5 

### ; 4,2 4 5 tons of PM 10 

### and 4,46 7 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 emission s is generated primarily from the t ransfer of clinker and the grinding and drying
of the raw material

. NO X 

### emissions from cement kilns represent approximately 4 % of total point
source emissions of NO X 

### in the WRAP region, and approximately 3 % of all stationary source (point and area source ) NO X 

### emissions in the region

. SO 2 

### emissions from cement kilns represent approximately 0.75% of total point source emissions of SO 2 

### in the WRAP region, and approximately 0.68% of all stationary source (point and area source) S O 2 

### emissions in the region.

Table 7

- 1 shows estimated emissions of NO X 

### , SO 2 

### , PM 10 

### , PM 2 .5 

### and VOC from the
WRAP emissions i nventory and updated data provided by the states , brok en down by state and
emission source

. As the table shows, SO 2 

### , PM 10 

### , PM 2.5 

### and VOC emissions from cement ki ln
sources are much lower than NO X 

### emissions

. Emissions of particul ate matter from these sources
were not included in the WRAP EDMS inventor y

– the emissions presented were gathered from
the NEI

. Long dry kilns produce over half of the NO X 

### emissions (54. 8%) and most of the PM 2.5 

### and PM 10 

### emissions (79.4 and 71.3%, respectively) generated by cement manufacturing in the WRAP region

. Long wet kilns produce almost half of the SO 2 

### 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 NO X 

### 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

- t his combustion generates primarily NO X 

### emissions but also produces SO 2 

### and PM
emission s

. 6 

### Controls can be broken into three categories: process modifications, combustion
modifications and NO X 

### removal controls

. Process modifications include fuel switching and the inclusion of steel slag into the raw kiln f eed (also known as the CemStar (T M ) 

### 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 R MC Pacific Materials, Inc. and to the Rio Grande Portland Cement Company. 3 

### Combustion modifications include low NO X 

### burners and mid

- kiln firing

. NO X 

### removal controls include SCR, SNCR, LoTOX TM



### , and biosolids or sorbent injection. Low NO X7

- 2



### burners reduce f

lame turbulence, delay fuel/air mixing and create fuel

- rich zones for initial combustion, reducing the flame temperature and thus NO X 

### formation. 4 

### SCR introduces
ammonia

, presented as a catalyst

, into the clinker making process to selectively reduce NO X



### em is sions from exhaust gases. SNCR, available to preheater or precalciner cement kilns 1

, 5

, 6



### , does not use a catalyst to reduce NO X 

### emissions. Instead, the process uses either ammonia or urea that is generated wh en 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 LoTOx TM 

### system, ozone is injected into the kiln which oxidizes NO X 

### . 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 t o 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, o r 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 ty pically reflect smalle r 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 NO X 

### control. 16 

### However, state regulators’ experience indi cates 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 tot al 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

NO X emissions (tons/year)

SO 2 emissions (tons/year)

PM 2.5 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) PM 10 emissions (tons/year)Source Type Control Technology Pollutant

controlled Baseline

emissions Estimated control

efficiency (%) Potential emission

reduction (tons/year) References

Low NOX burners NO X 8,628 20-30 1725 - 2588 1, 6

Mid-kiln firing NO X 8,628 20-50 1725 - 4313 1, 6

SCR with ammonia NO X 8,628 80-90 6902 - 7764 5, 6

SNCR with ammonia or urea NO X 8,628 30-70 2588 - 6039 6

Biosolid injection NO X 8,628 50 4313 7

CemStar TM process NO X 8,628 20-60 1725 - 5176 1, 3, 7

LoTOx TM NO X 8,628 80-90 6902 - 7765 1, 5

Dry ESP PM 10 691 95-98 656 - 677 9

Dry ESP PM 2.5 121 95-98 114 - 118 9

Dry ESP EC 4 95-98 3 9
Dry ESP OC 15 95-98 14 9

Fabric Filter PM 10 691 80-99 656 - 677 9

Fabric Filter PM 2.5 121 80-99 114 - 118 9

Fabric Filter EC 4 80-99 3 9

Fabric Filter OC 15 80-99 14 9

Absorbant Addition SO 2 1,917 60-80 1150 - 1533

Wet FGD SO 2 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

LoTOx TM NO X 19541 80 - 90 15,633 - 17,587 1, 5

CemStar TM 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 KilnSource 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

LoTOx TM NO X 3204 80 - 90 2,563 - 2,884 1, 5

CemStar TM process NOX 19541 Unknown a Unknown a 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

LoTOx TM NO X 3204 80 - 90 2,563 - 2,884 1, 5

CemStar TM process NOX 19541 Unknown a Unknown a 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 Kiln7

- 7



### 7

. 3 Factor 3

– Energy and Other Impacts

Table 7

- 4 shows the estimated energy and non

- air pollution impacts of control measu res for cement kilns

. In general in

- combustion NO X 

### 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 requi red 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 reg ion. 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

LoTOx TM NOX 80 - 90 3,155 - 3,891 c 5

CemStar TM process NOX 20-60 1,176 220000 ton clinker 550 7

Dry ESP PM 10 , PM 2.5 , OC,

EC 95-98 40 - 250 9

Fabric Filter PM 10 , PM 2.5 , 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

LoTOx TM NOX 80 - 90 5

CemStar TM 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 PM 10 , PM 2.5 , OC,

EC 95-98 40 - 250 9

Fabric Filter PM 10 , PM 2.5 , 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

CemStar TM 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

LoTOx TM NOX 80 - 90 5
Biosolids Injection NOX 50 1,200 (322,000) ton clinker (310) 7
Dry ESP PM 10 , PM 2.5 , OC,

EC 95-98 0.013 Not available a cfm 40 - 250 9

Fabric Filter PM 10 , PM 2.5 , OC,

EC 99 0.029 Not available a cfm 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 available d

Not available d Table 7-3. Estimated Costs of Control for Cement Kilns

Not available a

Not available a Long Wet Kiln

Long Dry Kilns

Preheater Kilns

Not available b Not available a

Not available a Not available a

Not available a Not available a

Not available bSource 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

CemStar TM process NOX 20-60

LoTOx TM NOX 80 - 90 2,419 - 2,734 e 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 PM 10 , PM 2.5 , OC,

EC 99 0.013 Not available a cfm 40 - 250 9

Fabric Filter PM 10 , PM 2.5 , OC,

EC 99 0.029 Not available a cfm 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 available a Not available b

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 available a

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 KilnsSource 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 CO 2

emitted (tons/ton reduced)

Low NOX burners NO X 1725 - 2588 a 182
Mid-kiln firing NO X 1725 - 4313 a 182

SCR with ammonia NO X 6902 - 7764 9.8 57 Unknown b

SNCR with ammonia

or urea NO X 2588 - 6039 Unknown b

Biosolid injection NO X 4313 a

LoTOx TM NO X 6902 - 7765 Unknown c

CemStar TM process NO X 1725 - 5176 a

Fabric Filter PM 10 , PM 2.5 , EC,

OC 1,898 - 1,958 Unknown b 1

Dry ESP PM 10 , PM 2.5 , EC,

OC 1,898 - 1,958 Unknown b 1

Wet FGD SO 2 1725 - 1897 1,100 3.1 2.8 3.7 2.6

Low NOX burners NO X 7816 a 158
Mid-kiln firing NO X 2149 - 10747 a 158

SCR with ammonia NO X 1563 - 1758 9.8 48 Unknown b

Biosolid injection NO X 9770

LoTOx TM NO X 15,633 - 17,587 Unknown c

CemStar TM process NO X 3908 - 1172

Dry ESP PM 10 , PM 2.5 , EC,

OC 1,898 - 1,958 Unknown b 1

Fabric Filter PM 10 , PM 2.5 , EC,

OC 1,898 - 1,958 Unknown b 1

Wet FGD SO 2 2310 - 2541 1,100 3.1 2.8 3.7 2.6

Dry FGD SO 2 2310 - 2438 Unknown b

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 impactsSource 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 CO 2

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 NO X 1281 a 194

SCR with ammonia NO X 2723 9.8 59 Unknown b

SNCR with urea NO X 1121 Unknown b

SNCR with ammonia NO X 1121 Unknown b

LoTOx TM NO X 2,563 - 2,884 Unknown c
Biosolid injection NO X 736 - 1602 a Sorbent injection SO 2 261 - 348 a
Dry ESP PM 10 , PM 2.5 , EC,

OC 1,898 - 1,958 Unknown b 1

Fabric Filter PM 10 , PM 2.5 , EC,

OC 1,898 - 1,958 Unknown b 1

Wet FGD SO 2 392 - 431 1,100 3.1 2.8 3.7 2.6

Dry FGD SO 2 392 - 414 Unknown b

Low NOX burners NO X 961 - 1281 a 285

SCR with ammonia NO X 2723 9.8 89 Unknown b

SNCR with urea NO X 1121 Unknown b

SNCR with ammonia NO X 1121 Unknown b

LoTOx TM NO X 2,563 - 2,884 Unknown c
Biosolid injection NO X 1602 a Sorbent injection SO 2 60-80 a
Dry ESP PM 10 , PM 2.5 , EC,

OC 1,898 - 1,958 Unknown b 1

Fabric Filter PM 10 , PM 2.5 , EC,

OC 1,898 - 1,958 Unknown b 1

Wet FGD SO 2 392 - 431 1,100 3.1 2.8 3.7 2.6

Dry FGD SO 2 392 - 414 Unknown b

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

Kilns7

- 12



### 7

. 5 References for Section 7

1

. NACAA ( formerly STAPPA and ALAPCO ) ( 2006 )

, Controlling Fine Particulate Mat ter Under the Clean Air Act: A Menu of Options, National As sociation of Clean Air Agencies, www.4cleanair.org/ PM25Me nu

- 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), CemStar sm 

### 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 NO X 

### 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 (199 4 ), Alternative Control Techniques Document

— NO X 

### Em issions 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), NO X 

### Control Technologies for the Cem ent 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

- Midw est RPO Candidate Control Measures for Cement Kilns

, http://www.ladco.org/reports/control/white_papers/portland_cement_plants.pdf

.

9

. E.H. Pechan & Associates (2 005), 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/Cal ciner Through the Use of the NOXOUT Process , Presented at the International Specialty Conference on
Waste Combus t ion 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 SO 2 

### Con trol

, http://www.iea

- coal.org.uk/site/ieacoal/databases/ccts/sorbent

- injection

- systems

- for

- so2

- control

.

14

. Battye, R. and S. Edgerton, EC/R I ncorporated (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 NO X 

### Control , Received during December 199 plant trip.

16

. Institute of Clean Air Companies (2006), Typical Installation Timelines for NO X 

### 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 instal l add

- on control measures for NO X 

### , 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 SO 2 

### emissions in the WRAP region. These emissions are from a limited number of facilities, with facility

- leve l
SO 2 

### 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 amou nts of SO 2 

### emissions from facilities at different efficiency levels for the acid recovery process. As the table shows, reported emissions of NO X 

### , PM 10 

### , PM 2.5 

### , and VOC emissions are much lower than SO 2 

### emissions from sulfuric acid plants in the region.

Emissions of SO 2 

### 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. SO 2 

### e missions can also be controlled using tail gas treatment units. 3

, 4 

### Table 8

- 2 shows the estimate d 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 opt ions 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
thro ughput 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 t able also shows the estimated cost effectiv eness 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 NO X 

### emissions (tons/year)

SO 2 

### 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 SO 2 

### 710 75 530 2,3

Tailgas treatment unit SO 2 

### 710 90 640 3,4

Increase absorption efficiency to NSPS level SO 2 

### 105 87.5 92 2,3

Tailgas treatment unit SO 2 

### 105 95 100 3,4

Increase absorption efficiency to NSPS level SO 2 

### 3,273 96.4 3,200 2,3

Tailgas treatment unit SO 2 

### 3,273 98.6 3,200 3,4

Chamber process Tailgas treatment unit SO 2 

### 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 SO 2 

### 75 55 - 96 23 - 29 acfm 6,800 - 7,000 2,3

Tailgas treatment unit SO 2 

### 90 23 - 32 36 acfm 5,300 - 6,500 3,4

Increase absorption efficiency to NSPS level SO 2 

### 87.5 6,200 2,3

Tailgas treatment unit SO 2 

### 95 48 38 acfm 3,375 3,4

Increase absorption efficiency to NSPS level SO 2 

### 96.4 1,600 2,3

Tailgas treatment unit SO 2 

### 98.6 48 38 acfm 928 3,4

Chamber process Tailgas treatment unit SO 2 

### 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 efficiency8

- 5



### 8 .2 Factor 2

– Time Necessary for Compliance

Once a state decides to adopt a particular control strateg y , up to 2 y ears 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 approximat ely 30 months is required to design, build, and install
SO 2 

### 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 6 1⁄2 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, 2 

### as would a tailgas treatment unit. 4 

### This would result in
increased CO 2 

### emissions to generate the electricity and steam.

8

. 4 Factor 4

– Remaining Equipment Life

Information was not avai lable on the age of sulfuric acid plants in the WRAP region. However, industrial processes often refurbished to extend their lifetimes. Therefore, t he 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.

I f 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, a nd a corresponding increase in the total annual cost of control . This increased cost can be quantified
as follows:

where:
A 1 

### = the annual cost of control for the shorter equipment lifetime ($)
A 0 

### = the original annual cost estimate ($)
C = the capi tal cost of installing the control equipment ($)

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 CO 2



### emitted (tons)
Contact process Increase absorption

efficiency to NSPS level SO 2 

### 530 2,450 29 <0.01 10

Tailgas treatment unit SO 2 

### 640 1,470 27 8

Increase absorption efficiency to NSPS level SO 2 

### 92 1,050 13 <0.01 4

Tailgas treatment unit SO 2 

### 100 700 12 4

Increase absorption efficiency to NSPS level SO 2 

### 3,200 270 3.2 <0.01 1

Tailgas treatment unit SO 2 

### 3,200 190 3.5 1

Chamber process Tailgas treatment unit SO 2 

### 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 (tons/year) Control Technology Source Type Pollutant

controlled8

- 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

- Documen tation Report

, U.S. EPA, RTP, N C, 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

, S ection 5

- SO 2 

### 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
indust ry, accounting for more than 75% of the sector’ s PM 2.5 

### , SO 2 

### , and NO X 

### emissions

. 1 

### The role of lime kilns in the kraft pulp ing 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 NO X 

### , 104 tons of SO 2 

### , 603 tons of PM 2.5 

### , 667 tons of P M 10 

### , 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

. NO X 

### emissions from lime ki lns represent approximately 0.08 % of total point source emissions of NO X 

### in the WRAP region, and approximately 0.06 % of all stationary source (point and area source) NO X 

### emissions in the region

. SO 2 

### emissions from lime kilns represent approximately 0.01% of total point source emissions of SO 2 

### in the WRAP region, and approximately 0.01% of all stationary source (point and area source) SO 2 

### emissions in the region.

Table 9

- 1 shows estimated emissions of NO X 

### , SO 2 

### , PM 10 

### , PM 2 .5 

### and VOC from the
WRAP emi ssions inventory and updated data provided by the states , brok en down by state and
emission source

. As the table shows, SO 2 

### , PM 10 

### , PM 2.5 

### and VOC emissions from lime kiln
sources are much lower than NO X 

### emissions

. PM e missions from these sources were not
included in the WRAP EDMS inventory

– the emissions presented were gathered from the
2002 NEI

.

Table 9

- 2 lists potential control measures for NO X 

### , SO 2 

### , PM 10 

### and PM 2.5 

### emissions from
lime kilns

. A number of options were iden tified 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 co ntrol technologies but have been found to be technically infeasible. Additionally

, according to the NACAA

, there are no technically feasible methods for controlling
NO X 

### emissions from lime kilns. 1 

### Therefore 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

NO X 

### emissions (tons/year)

SO 2 

### emissions (tons/year)

PM 2.5 

### emissions (tons/year)

PM 10 

### 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 NO X 

### 828 30 248 4

Mid-kiln firing NO X 

### 828 30 248 4

LoTOX NO X 

### 828

SCR with ammonia NO X 

### 828 60 - 80 496 - 662 4

SNCR with ammonia or

urea NO X 

### 828 50 414 4

Wet FGD SO 2 

### 104 50 51 4

Dry ESP PM 10 

### 1271 95-98 1207 - 1245 4

Dry ESP PM 2.5 

### 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

Kiln9

- 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 kiln s

. Table 9

- 3 also show s 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 strateg y , up to 2 year s 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 estima ted that approximately 13 months is required to design, fabricate, and install SCR or SNCR technology for NO X 

### control

. 5 

### However, state regulators’ experience indicates that closer to 18 months is required to install this technology. 6 

### Addit ional time of u p 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 NO X 

### burners negatively affect efficiency and energy usage

, 7 

### and stage d combustion, while lowering NO X 

### emissions, can lead to increased SO 2 

### emissions

. SCR and SNCR require, on average, 890 kilowatt

- hour ( kW h ) of electricity per ton of pollutant reduced, and 0.25 tons of steam for every ton of pollutant reduced

. Approximate ly one ton of
CO 2 

### is produced per mW h 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. 9 

### Installation of SCR would also require an increase in fuel consumption, which would also produce an increase in CO 2 

### 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
W RAP 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 t o 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 NO X 

### burners NO X 

### 30 560 4
Mid-kiln firing NO X 

### 30 460 4

SCR with ammonia NO X 

### 60 - 80 3370 4

SNCR with ammonia or

urea NO X 

### 50 770 - 850 4

Wet FGD SO 2 

### 50 4

Dry ESP PM 2.5 

### 95 15 - 50 4 - 40 scfm 4

Dry ESP PM 10 

### 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 PM 2.5 

### 95 4

Wet ESP PM 10 

### 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

CO 2 

### emitted (tons/ton reduced)

Low NOX burners NO X 

### 30 Unknown Unknown

Mid-kiln firing NO X 

### 30 a

SCR with ammonia NO X 

### 60 - 80 Unknown 890 0.25 1

SNCR with

ammonia or urea NO X 

### 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 Mat ter 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 NO X 

### 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 NO X 

### , Wisconsin Departm ent 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 f or US EPA/Office of Research and Developme nt, 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

- 00 1, 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 NO X 

### and 58,000 tons of SO 2 

### , based on the WRAP emissions inventory. These emissions represent about 2% of stationary s ource (point and area source) NO X 

### emissions, and 6% of stationary
source SO 2 

### emissions in the region. PM 10 

### and PM 2.5 

### emissions from natural gas processing facilities are estimated to be an order of magnitude lower than NO X 

### and SO 2 

### 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 NO X 

### and SO 2 

### emissions at

r efineries 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 PM 10 

### emissions using data from EPA’s
SPECIATE database. 2 

### EC and OC are estimat ed to comprise 0.07% and 0.014% of PM 10 

### emissions from catalytic cracking units, respectively ; 38.4% and 24.7 % of natural gas
combustion PM 10 

### emissions; and 1% each in oil combustion PM 10



### .

Table 10

- 2 lists potential control measures for emissions of SO 2 

### , NO X 

### , 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 SO 2 

### emissions from process heaters result from the burning of refinery fuel gases containing hydrogen sulfide (H 2 

### S). These emissions can be reduced by treating the refinery fuel gas to remove H 2 

### S before the gas is burned. A number of options are available to
reduce NO X 

### emissions from process heaters. Co mbustion modifications including LNB, ULNB,
and FGR reduce the formation of NO X 

### . In addition, flue gases from the process heaters can be
treated with SCR or SNCR to reduce NO X 

### emissions. These post

- combustion controls can be used either alone or in conju nction 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 build

up. Since the catalyst coke contains relatively high levels of sulfur, the combustion products from this coke are an important source of SO 2 

### emissions. Uncontrolled SO 2 

### concentrations in
the f luid catalytic cracking ( 

### FCC ) regenerator exhaust stream range from 150 to 3000 parts per million by volume ( ppmv ) . The FCC regenerator burner also emits NO X 

### and PM, including material abraded from the catalyst (catalyst fines). Uncontrolled NO X 

### emissio ns from the regenerator vent can range from 50 to 400 ppmv. 5AK CA CO MT ND NM NV OR UT WA WY Tribes AllProcessHeaters 573 7,778 349 1,072 864 783 48 615 3,088 192 1 15,362CatalyticCrackingUnits 1,179 239 463 193 245 2,319Flares 102 942 12 191 7 261 57 9 1,582FluidCokingUnits 122 25147Other 122 563 106 103 31 7 105 996 1,156 1,984 5,174Total 797 10,583 707 1,854 864 1,014 48 7 1,226 4,141 1,358 1,985 24,584ProcessHeaters 62 2,093 338 628 4,592 1,268 93 715 2,330 363 10 12,491CatalyticCrackingUnits 5,567 1,197 4,649 2,044 671 2,645 379 17,152Flares 8 4,940 2 380 31 313 936 139 6,750FluidCokingUnits 5,937 2826,219CokeCalcining 3,642186 3,828Incinerators 41 29 183 457 1 2,105 44 629 3,489Other 41 5,802 126 183 688 10 2,105 698 5,238 113 15,003Total 111 24,340 1,663 6,122 4,592 4,030 93 10 3,804 6,609 6,120 122 57,615ProcessHeaters 30 1,049 31 38 72 61 200 28 1,509CatalyticCrackingUnits 305 264 333 171 30 74 1,177Flares 6 41 0 2 5 0 55FluidCokingUnits 154 6160Other 7 51 193 2 3 280 70 536 1,142Total 43 1,600 488 379 0 244 0 3 373 349 564 0 4,042ProcessHeaters 2 1,026 64 60 30 1,184CatalyticCrackingUnits 278 103 4 384Flares 41 2 1 44FluidCokingUnits 140140Other 0 54 3 2 60Total 2 1,539 0 0 0 167 0 0 70 33 0 0 1,812Fugitiveemissions 0 3,094 127 1,326 0 1,396 20 37 447 955 469 1 7,872Wastewatertreatment 1,018 960 13 531 0 221 5 2 139 344 94 0 3,327Processheaters 9 418 67 27 161 30 1 1 22 101 2,613 10 3,461Flares 130 2,311 17 330 5 0 0 63 117 27 02,703Other 11 1,304 43 100 0 151 8 1 67 161 7 0 1,852Total 1,167 8,086 268 2,017 161 1,802 34 41 738 1,678 3,210 12 19,215NOXemissions(tons/year)SO2emissions(tons/year)PM2.5emissions(tons/year)PM10emissions(tons/year)Table 10-1. Emissions from Petroleum Refineries in the WRAP RegionVOCemissions(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 SO 2 12 up to 90 0 ‐ 11 5,13

LNB NO X 15 40 6.1 3,6

ULNB NO X 15 75 ‐ 85 12 ‐ 13 5,6,3

LNB and FGR NO X 15 48 7.4 3,6

SNCR NO X 15 60 9.2 3,5,3

SCR NO X 15 70 ‐ 90 11 ‐ 14 3,5,3

LNB and SCR NO X 15 70 ‐ 90 11 ‐ 14 3,5,3
Catalyst additives for

NO X reduction NO X 2.3 46 1.1 5,7

LoTOX TM NO X 2.3 85 2.0 5,8

SNCR NO X 2.3 40 ‐ 80 0.93 ‐ 1.9 5,7

SCR NO X 2.3 80 ‐ 90 1.9 ‐ 2.1 8,7
Catalyst additives for SO 2 absorbtion SO 2 17 20 ‐ 60 3.4 ‐ 10 5,7

Desulfurization of catalytic cracker feed SO 2 17 up to 90 0 ‐ 15 7,13

Wet scrubbing SO 2 17 70 ‐ 99 12 ‐ 17 5,6,9

PM 10 1.2 95+ 1.1 ‐ 1.2 5,6,10

PM 2.5 0.4 95+ 0.4

EC 0.0008 95+ 0.0008

OC 0.0002 95+ 0.0002

Spray dryer absorber SO 2 10 80 ‐ 95 8 ‐ 10 5

Wet FGD SO 2 10 90 ‐ 99 9 ‐ 10 5,11,12
Improved process control and operator training SO 2 varies 5

Expand sulfur recovery
unit SO 2 varies 5

Flare gas recovery system SO 2 varies 5 Process heaters Table 10-2. Control Options for Petroleum Refineries

Coking or coke calcining boilers Fluid catalytic cracking units

ESP

Flares10

- 4



### Many refineries use catalyst additives to reduce SO 2 

### and NO X 

### emissions from fluid catalytic cracking units. SO 2 

### emissions can also be reduced by treating the fluid catal ytic cracker feed stream to remove sulfur compounds. Some refineries in the U.S. have also used SCR to
control NO X 

### emissions from catalytic cracking units, and one refinery in Japan has also used
SNCR. 6

, 7 

### In addition, the LoTOx TM 

### process has been develop ed to control NO X 

### 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 (NO 2 

### ) which comprise NO X 

### into more highly oxidized forms of nitrogen such a s dinitrogen pentoxide (N 2 

### O 5 

### ). 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
LoTOx TM 

### system is more cost effective if used in conjunction with a wet scrubber to control SO 2 

### emissions

. W et scrubbers are often used for simultaneous control of PM, SO 2 

### , and NO X 

### emissions from the catalyst regenerator. 9 

### In additio n, c yclones and ESP are commonly used to control PM emissions in the catalyst regenerator offgas. 5

, 10



### SO 2 

### 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
SO 2 

### emissions from the coking unit, with reported efficiencies of 95% to over 99%. 11 

### T he 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 NO X 

### emissions from these streams can be controlled using SCR or SNCR. 12

, 13



### Petroleum refineries use flares to burn combustible ga ses 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 operation s are predictable, and others are not. S O 2 

### emissions from flaring result from the flaring of sour gases or other gases which have high concentrations of sulfur compounds. These e missions 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 unti l they can be treated to remove sulfur compounds. 5 

### NO X 

### 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, incl uding 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.SourceType ControlTechnologyPollutantcontrolledEstimatedcontroleffieiency(%)Estimatedcapitalcost($1000/unit)Estimatedannualcost($/year/unit) UnitsCosteffectiveness($/ton)Refer‐encesFueltreatmenttoremovesulfurSO2upto90 3.4‐10 28,000‐36,000 Refinerycapacity,1000barrels/day1,300‐1,700 5,13LNB NOX40 2.7‐7.6 290‐810 MM‐Btu/hr 650‐2,800 3,6ULNB NOX75‐85 2.8‐13 300‐1,300 MM‐Btu/hr 400‐2,000 3,5,6LNBandFGR NOX48 5.8‐16 640‐1,700 MM‐Btu/hr 1,000‐2,600 3,6SNCR NOX60 5.2‐22 570‐2,400 MM‐Btu/hr 890‐5,200 3,5,6SCRbNOX70‐90 33‐48 3,700‐5,600 MM‐Btu/hr 2,900‐6,700 3,5,6LNBandSCR NOX70‐90 37‐55 4,000‐6,300 MM‐Btu/hr 2,900‐6,300 3,5,6CatalystadditivesforNOXreductionNOX465,7LoTOXTMNOX85 1,700‐2,000 5,8SNCR NOX40‐80 2500 5,7SCR NOX80‐90 2500 7,8CatalystadditivesforSO2absorbtionSO220‐605,7DesulfurizationofcatalyticcrackerfeedSO2upto90 23‐54 190,000‐250,000Refinerycapacity,1000barrels/day6,200‐8,000 7,13Wetscrubbing SO270‐99 1,500‐1,800 5,6,9ESP PM2.5,PM10,EC,OC95+ >10,000 5,6,10Spraydryerabsorber SO280‐95 1,500‐1,900 5WetFGD SO290‐99 1,500‐1,800 5,11,12ImprovedprocesscontrolandoperatortrainingSO2Varies5ExpandsulfurrecoveryunitSO2Varies5FlaregasrecoverysystemSO2Varies5aCostsofprocessmodificationswilldependonthespecificrefineryconfiguration.bSCRcostestimatesforSCRapplytomechanicaldraftheaters.NaturaldraftheaterswouldhavetobeconvertedtomechanicaldraftforinstallationofSCR.Thiswouldincreaseboththecapitalandannualizedcostsofcontrolbyabout10%.FlaresnotavailableanotavailableanotavailableaCokingorcokecalciningboileroffgasTable 10-3. Estimated Costs of Control Petroleum RefineriesProcessheatersFluidcatalyticcrackingunitsnotavailableanotavailablea10

- 6



### Sulfur recovery units are believed to be more cost

- effective than post

- c ombustion controls for reducing SO 2 

### 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 SO 2 

### , rather than such process modifications. How ever, costs of sulfur recovery units were estimated in an earlier study of model refineries in different size ran g es. 14 

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

Table 10

- 3 shows a range of valu es 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 size s, and the higher ends of the cost ranges typically
reflect smaller process sizes. The t able 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 adop t a particular control strateg y , 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 NO X 

### control

. 15 

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

### In the CAI R analysis, EPA estimated that approximately 30 months is required to design, build, and install SO 2 

### 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 install ation 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 6 1⁄2 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 hydrotreatm ent 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 NO X 

### 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 CO 2 

### 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 NO X 

### and SO 2 

### 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 in creases in fuel consumption. However, information is not available to quantify these impacts. A LoTOxSourceType ControlTechnologyPollutantcontrolledElectricityrequirement(kW‐hr)Steamrequirement(tonssteam)Solidwasteproduced(tonswaste)Wastewaterproduced(1000gallons)AdditionalCO2emitted(tons)FueltreatmenttoremovesulfurSO20‐11 bbLNB NOX6aeULNB NOX12‐13 a eLNBandFGR NOX7.4 3,300 3.3SNCR NOX9.2 0.16 460 3.2SCR NOX11‐14 8,400 0.073 8.4LNBandSCR NOX11‐14 8,400 0.073 8.4CatalystadditivesforNOXreductionNOX1.1 d dLoTOXTMNOX2.0 d d dSNCR NOX0.93‐1.9 460 3.2SCR NOX1.9‐2.1 8,400 0.073 8.4CatalystadditivesforSO2absorbtionSO23.4‐10 d dDesulfurizationofcatalyticcrackerfeedSO20‐15 d d d dWetscrubbing SO212‐17 1,100 3.1 3.7 2.6ESP PM2.5,PM10,EC,OC1.1‐1.2 97 1 0.1Spraydryerabsorber SO28‐10 400 1.1WetFGD SO29‐10 1,100 3.1 3.7 2.6ImprovedprocesscontrolandoperatortrainingSO2VariesExpandsulfurrecoveryunitSO2Varies d d d dFlaregasrecoverysystemSO2Varies d d d dNOTES:eSomedesignesoflow‐NOXburnersandultralow‐NOXburnersrequiretheuseofpressurizedairsupplies.ThiswouldrequireadditionalelectricitytopressurizethecombustionaThemeasureisexpectedtoimprovefuelefficiency.bCO2fromthegenerationofelectricitywouldbeoffsetbyavoidedemissionsduetoreplacingthedieselenginecEPAhasestimatedthatthecontrolmeasuresusedtomeetTier4standardswillbeintegratedintotheenginedesignsothatsacrificesinfueleconomywillbenegligible.dSomeimpactisexpectedbutinsufficientinformationisavailabletoevaluatetheimpact.blankindicatesnoimpactisexpected.CokingorcokecalciningboileroffgasFlaresTable 10-4. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Petroleum RefineriesProcessheatersFluidcatalyticcrackingunitsPotentialemissionreduction(1000tons/year)Additionalfuelrequirement(%)Energyandnon‐airpollutionimpacts(pertonofemissionreduced)10

- 8



### scrubbing system or wet scrubbing system applied to the fluidized catalytic cracking unit would require electricity to operate fans and othe r 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 p roduce 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 recove ry 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, t he remaining lifetime of most equipment is expected to be longer than the projected lifetime of pollution control technologies which have been analyzed for th is category. In the
case of add

- on technologies

, the projected lifetime is 15 years.

I f 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 t o 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:
A 1 

### = the annual cost of control for the shorter equipment lifetime ($)
A 0 

### = 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 equipment10

- 9



### 10

. 5 References for Section 10

1

. WRAP (2008), Emission s 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

— NO X 

### Emissions from Process Heaters (Revised) , EPA

- 453/R

- 93

- 034, U.S. EPA, RTP, NC, p p 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 Mat ter 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 Availab le 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
Po tential 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, In dia.

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.ht ml#cccinfo

.

11

. EPA (2006), Final 2002 National Emissions Inventory

, U.S. E PA, 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 NO X 

### Emissions Control Technologies on Industrial Sources

, http://www.icac.com/f

iles/public/ICAC_NOx_Control_Installation_Timing_120406.pdf

.

16

. Ghoreishi, Farrokh (2007), Time required to install add

- on control measures for NO X

, 

### Personal communication, Wisconsin Department of Natural Resources

.

17

. EPA (2005), Boilermaker Labor An alysis 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

.