Supplementary Information for

Four-Factor Analyses for Selected Individual 

Facilities in New Mexico

May 5, 2009

Revised Draft Report

Prepared by:

William Battye

Janet Hou

Brad Nelson

EC/R Incorporated

501 Eastowne Drive, Suite 250

Chapel Hill, North Carolina 27514

Prepared for:

Lee Gribovicz, Project Manager

Western Regional Air Partnership (WRAP) and

Western Governors’ Association (WGA)

1600 Broadway, Suite 1700

Denver, Colorado 80202
Scope of Document

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

considered in establishing a reasonable progress goal toward achieving natural 

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

several candidate control measures for priority pollutants and emission sources. 

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

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

Partnership (WRAP) region. 

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

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

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

share of emission reductions, and coordinated emission control strategies. 

Disclaimer

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

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

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

sponsoring and participating organizations, and no official endorsement should be 

inferred.
iii

Contents

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

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

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

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

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

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

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

3. Petroleum Refineries .............................................................................................................................................3-1

3.1 Factor 1 – Costs............................................................................................................................................3-4

3.2 Factor 2 – Time Necessary for Compliance .................................................................................................3-4

3.3 Factor 3 – Energy and Other Impacts...........................................................................................................3-4

3.4 Factor 4 – Remaining Equipment Life .........................................................................................................3-9

3.5 References for Section 2.............................................................................................................................3-10
iv

Abbreviations

ALAPCO Association of Local Air Pollution Control Officials

BACT Best Available Control Technology

BART Best Available Retrofit Technology

CAIR Clean Air Interstate Rule

CEMS Continuous Emissions Monitoring System

CO Carbon Monoxide

CO2 Carbon Dioxide 

DSI Duct Sorbent Injection

EC Elemental Carbon

EDMS Emissions Data Management System

EGU Electric Generating Units 

EPA Environmental Protection Agency 

ESP Electrostatic Precipitator

FCCU Fluid Catalytic Cracking Unit

FGD Flue Gas Desulfurization

FGR Flue Gas Recirculation

ICAC Institute of Clean Air Companies

LNB Low-NOx Burners

MRPO Midwest Regional Planning Organization

N2 Nitrogen

N2O5 Dinitrogen Pentoxide

NACAA National Association of Clean Air Agencies

NEI National Emissions Inventory

NH3 Ammonia

NO Nitric Oxide

NO2 Nitrogen Dioxide

NOx Nitrogen Oxides

OC Organic Carbon

OFA Overfire Air

PM Particulate Matter

PM10 Particulate Matter Particles of 10 Micrometers or Less

PM2.5 Particulate Matter Particles of 2.5 Micrometers or Less

PSD Prevention of Significant Deterioration

RACT Reasonably Achievable Control Technology

RBLC RACT/BACT/LAER Clearinghouse

SCR Selective Catalytic Reduction

SDA Spray Dryer Absorber

SNCR Selective Noncatalytic Reduction

SO2 Sulfur Dioxide

STAPPA State and Territorial Air Pollution Program Administrators

ULNB Ultralow-NOX Burners

VOC Volatile Organic Compounds

WRAP Western Regional Air Partnership
v

Units

acfm Actual Cubic Feet per Minute

cfm Cubic Feet per Minute

kWh Kilowatt Hour

MM-BTU/hr Million British Thermal Units per Hour

MW Megawatt

ppm Parts Per Million

ppmv Parts per Million by Volume

scfm Standard Cubic Feet per Minute
2-1

1. Introduction

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

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

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

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

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

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

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

1. Cost of compliance

2. Time necessary for compliance

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

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

This report has been prepared as part of a project to evaluate the above factors for 

possible control strategies intended to improve visibility in the WRAP region. We have 

identified control measures for emissions of nitrogen oxides (NOX) and sulfur dioxide (SO2), 

which can react in the atmosphere to produce visibility-obscuring particulate matter on a regional 

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

(PM), we have evaluated the impacts of control measures on various particulate matter 

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

carbon (OC) particulate matter. A number of emission source categories have been addressed, 

including:

1. Reciprocating internal combustion engines and turbines

2. Oil and natural gas exploration and production field operations

3. Natural gas processing plants

4. Industrial boilers

5. Cement manufacturing plants

6. Sulfuric acid manufacturing plants

7. Pulp and paper plant lime kilns

8. Petroleum refinery process heaters

The four-factor analyses for these emission categories are documented in a separate report, 

entitled “Assessing Reasonable Progress for Regional Haze in the WRAP Region – Source 

Category Analysis.” 

The current report presents a the results of a four-factor analysis of potential control

measures for selected emission sources at three petroleum refineries in New Mexico. The 

emission sources addressed in this current report were selected by the New Mexico Environment 
2-2

Department. Section 2 presents the methodology employed to conduct the analyses and Section 

3 presents the results of the four-factor analysis for emission sources at the three refineries. 
2-1

2. Methodology

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

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

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

(EDMS),

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

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

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

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

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

to supplement the WRAP inventory where necessary.

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

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

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

models such as AirControlNET2and CUECost,

3 Best Available Retrofit Technology (BART) 

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

4

and 

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

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

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

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

technologies.

2.1 Factor 1 – Costs

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Haze Program6indicates that the four-factor analyses should conform to the methodologies 

given in the EPA Air Pollution Control Cost Manual.

7

This study draws on cost analyses which 

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

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

Marshall & Swift Equipment Cost Index or the Chemical Engineering Plant Cost Index, both of 

which are published in the journal, Chemical Engineering.

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

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

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

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

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

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

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

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

is beyond the scope of this project.

2.2 Factor 2 – Time Necessary for Compliance

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

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

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

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

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

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

2.3 Factor 3 – Energy and Other Impacts

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

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

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

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

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

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

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

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

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

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

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

Energy needs and non-air quality impacts of identified control technologies were aggregated to 
2-3

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

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

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

Table 2-1 Summary of Energy and Environmental Impacts 

Evaluated Under Factor 3 

Energy Impacts

Electricity requirement for control equipment and associated fans

Steam required

Fuel required

Environmental Impacts

Waste generated

Wastewater generated

Additional carbon dioxide (CO2) produced

Reduced acid deposition

Reduced nitrogen deposition

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

Impacts Not Included

Impacts of control measures on boiler efficiency

Energy required to produce lower sulfate fuels

Secondary environmental impacts to produce additional energy (except 

CO2) produced

2.4 Factor 4 – Remaining Equipment Life

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

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

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

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

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

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

amortization schedule will increase the annual cost of the scrubber.

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 
2-4

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

annualized cost-effectiveness.

2.5 References for Section 2

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

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

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

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

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

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

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

Midwest Regional Planning Organization and Lake Michigan Air Directors Consortium, 

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

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

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

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

6 EPA (2007), Guidance for Setting Reasonable Progress Goals under the Regional Haze

Program, 

http://www.epa.gov/ttncaaa1/t1/memoranda/reasonable_progress_guid071307.pdf.

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

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

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

3. Petroleum Refineries

Four-factor analyses have been conducted for selected emission sources at three New 

Mexico petroleum refineries. The following facilities and emission sources have been evaluated:

 Navajo Refining Co., Artesia Refinery – Fluid Catalytic Cracking Unit (FCCU) #1, 

catalyst regeneration and process heater

 Western Refining Southwest, Bloomfield Refinery – FCCU #1, catalyst regeneration and 

process heater

 Western Refining Southwest, Gallup Refinery – CO Boiler Unit #1

Table 3-1 summarizes the emission control measures that have already been applied to the 

selected emission sources, the baseline levels of emissions with these current controls, and 

potential additional control measures that could be adopted to further reduce emissions. The 

table also gives the estimated control efficiency and annual emission reduction for each potential 

future control measure.

Baseline SO2 emissions from the Navajo Artesia refinery FCCU regenerator were derived 

from the permit concentration limit listed in the EPA RACT/BACT/LAER Clearinghouse

(RBLC).

1

 The Navajo Artesia refinery permit listed in the RBLC database was issued on 

March 5, 2002. Other baseline emissions of NOX and SO2 for the refineries are based on the 

WRAP 2002 emissions inventory, and data received from the New Mexico Environment 

Department.

2,3

 Emissions of PM2.5 and PM10 were obtained from the 2002 U.S. EPA NEI. 

Emissions of EC and OC were estimated using mass fraction factors from EPA’s SPECIATE 

database.4 EC and OC are estimated to comprise 0.07% and 0.014% of PM10 emissions from 

catalytic cracking units, respectively. PM10 emissions from the carbon monoxide (CO) boiler 

were assumed to have a composition similar to natural gas combustion emissions, about 38.4% 

EC and 24.7% OC. It should be noted that the emission estimates were not verified by the New 

Mexico Environment Department and therefore may not reflect the actual emissions from the 

facility.

In catalytic cracking, the heavier fractions of crude petroleum are treated with a catalyst 

which breaks the petroleum molecules into lighter compounds. The catalyst is continuously 

cycled between the cracking and a separate regeneration reactor in order to burn off coke buildup. Since the catalyst coke contains relatively high levels of sulfur, the combustion products 

from this coke are an important source of SO2 emissions. The catalyst regenerator also emits 

NOX and PM, including material abraded from the catalyst (catalyst fines). 
ppm tons/yr

Optimization of NOX 

reduction catalyst

47 - 59 72 - 90 8,9

SCR 67 - 84 103 - 129 9,11

SO2 Wet scrubber 25 43 None identified

PM10, PM2.5, 

EC, OC

Wet scrubber not availableNone identified

4.0 LNB 40 1.6 17,18

ULNB 75 - 85 3 - 3.4 8,17,18

LNB and FGR 48 1.9 17,18

SNCR 60 2.4 8,17,18

SCR 70 - 90 2.8 - 3.6 8,17,18

LNB and SCR 70 - 90 2.8 - 3.6 8,17,18

SO2 Sulfur recovery 0.15

PM10, PM2.5, 

EC, OC

None identified not available

Catalyst additives for 

NOX reduction

75 - 81 43 - 46 8,9

LoTOxTM 85 49 8,11

SNCR 40 - 80 23 - 46 8,9

SCR 85 - 92 49 - 53 9,11

Catalyst additives for SO2 

absorbtion

98 364 8,9

Desulfurization of 

catalytic cracker feed

98 364 9,15

Wet scrubbing 98 364 8,12,17

PM10, PM2.5, 

EC, OC

ESP 0.90 None identified

6.1 LNB 40 2.4 17,18

ULNB 75 - 85 4.6 - 5.2 8,17,18

LNB and FGR 48 2.9 17,18

SNCR 60 3.7 8,17,18

SCR 70 - 90 4.3 - 5.5 8,17,18

LNB and SCR 70 - 90 4.3 - 5.5 8,17,18

SO2 Sulfur recovery 0.84 None identified

PM10, PM2.5, 

EC, OC

None identified 0.15 None identified

LNB with OFA 30 - 50 20 - 33 19,20,21,22

LNB, OFA, and FGR 30 - 50 20 - 33 19,20,21,22

SNCR 30 - 75 20 - 49 19,20,21,22

SCR 40 - 90 26 - 59 19,20,21,22

DSI 50 - 90 352 - 633 20,23

SDA 80 - 90 563 - 633 20,23

FGD 80 - 90 563 - 633 20,23

PM10 21.4

PM2.5 21.4

EC 7.3

OC 5.1

FCCU 

regenerator 

(Unit 22)

Navajo 

Refining 

Company, 

Artesia 

Refinery

NOX NOX reduction catalyst 

and low-NOX 

combustion promoters

123

Western 

Refining 

Southwest, 

Bloomfield 

Refinery

Western 

Refining 

Southwest, 

Gallup 

Refinery

CO Boiler, 

Unit 10

SO2

Baseline emissions

Estimated 

control 

efficiency (%)

Potential 

emission 

reduction 

(tons/year) References

Potential additional 

control measures

Existing control 

measures

NOX None identified

FCCU 

heater

NOX None identified

FCCU 

heater (H202)

Table 3-1. Control Options for Selected Petroleum Refinery Operations in New Mexico

NOX

SO2

57

371

153

Company Pollutant

1,223

Source

None identified 703.5

None identified

65.1

FCCU 

regenerator (A201)

None identified

None identified

262

NOX
3-3

The Navajo Artesia refinery FCCU has a capacity of 27,000 barrels per day (bbl/day), 

and the Western Refining Southwest Bloomfield refinery FCCU has a capacity of 7,200 

bbl/day.3,5 The Western Refining Gallup refinery FCCU has a capacity of 8,500 bbl/day. (It is 

not being analyzed under this effort.)

The SO2 concentration in the Artesia FCCU regenerator exhaust is limited by permit 

conditions to 25 parts per million (ppm), which is achieved by a wet scrubber.

1

 The SO2 permit 

limit was imposed after the 2002 baseline year, but for the purposes of this analysis, the wet 

scrubber system will be included as the baseline control. The NOX emissions from the FCCU 

regenerator are also limited to 34.9 lb/hr, or about 153 tons/year.3 This emission rate is 

estimated to correspond to an exhaust NOX concentration of about 123 ppm, and is achieved by 

the use of NOX absorption catalyst and low-NOX combustion promoters.

3

 Based on reported 

stack gas flow rates and emissions data, the concentrations of NOX and SO2 in the Bloomfield 

FCCU regenerator exhaust are about 262 ppm and 1,223 ppm respectively.2 

The EPA RBLC includes a number of Best Available Control Technology (BACT) and 

Prevention of Significant Deterioration (PSD) determinations and case-specific determinations 

for the FCCU regenerator exhaust stream, which are based on the application of synthetic 

catalytic reduction (SCR).1 The RBLC does not list any Reasonably Achievable Control 

Technology (RACT) determinations for this category. Permit limits for the SCR installations 

range from 20 to 40 ppm on an annual average basis. Some refineries have used catalyst 

additives to reduce NOX emissions in the FCCU regenerator exhaust to 50 to 65 ppm.6,7 One 

refinery in Japan has also used selective noncatalytic reduction (SNCR).

8,9

In addition, the 

LoTOxTM process has been developed to control NOX emissions in the catalytic cracking 

regenerator offgas. In this system, ozone is injected into the offgas to convert the nitrogen oxide 

(NO) and nitrogen dioxide (NO2) which comprise NOX into more highly oxidized forms of 

nitrogen such as dinitrogen pentoxide (N2O5). These more highly oxygenated compounds are 

more soluble in water, and are removed from the offgas stream in a wet scrubber. The ozone 

also reacts with particulate compounds in the exhaust stream, therefore there is no ozone slip 

from the system.10 This system has been reported to reduce NOX emissions to under 10 parts per 

million by volume (ppmv).

8,11,12,

 

A menu of control options developed by NACAA identifies a regenerator offgas 

concentration of 25 ppm, on an annual average basis, as well-controlled for SO2.

8

 In addition, 

the EPA RBLC shows an offgas SO2 concentration of 25 ppm for a number of recent 

BACT/PSD determinations.1 Refineries have achieved the 25 ppm level by wet scrubbing, 

which can reduce SO2 emissions by 95% to over 99%.1,8,13 Some refineries have achieved the 25 

ppm level by using an SO2 adsorption catalyst, which is added to the catalytic cracking catalyst.

6

The catalyst additive adsorbs sulfur oxide compounds produced in the catalyst regenerator. 

These compounds are then converted to H2S in the catalytic cracking reactor, and exit this 

reactor with the cracked hydrocarbon stream. The H2S is eventually removed from the 

hydrocarbon stream in an amine treatment process, and then recovered in the sulfur recovery 

process.

14

 SO2 emissions from the FCCU regenerator can also be controlled by desulfurization 
3-4

of the oil feed stream to the FCCU.7,15 Particulate matter emissions from the FCCU regenerators 

can be controlled by wet scrubbing or by electrostatic precipitation (ESP).8,16

Based on the RBLC determinations and the NACAA report, the Artesia FCCU exhaust 

would be considered to be well controlled for SO2, with an emission concentration of 25 ppm. 

The wet scrubber used to control SO2 for the Artesia regenerator also provides control of 

particulate emissions. Artesia also uses NOX absorption catalyst and low-NOX combustion 

promoters to reduce NOX emissions to less than 123 ppm, as stated in the RBLC determination 

for this facility. It is possible that this emission rate could be further reduced by testing different 

NOX catalyst addition rates. As noted above, some refineries in another state have used catalyst 

additives to reduce NOX emissions in the FCCU regenerator exhaust to 50 to 65 ppm.6,7 These 

concentrations represent an emission reduction of 47 to 59% from the concentration currently 

achieved in the Artesia regenerator. These lower emission levels were achieved by testing 

different types and usage rates of NOX reduction catalysts, in order to identify the formula for the 

best NOX control.6,7 The EPA RBLC shows a number of BACT determinations for NOX from 

FCCU regenerators based on SCR.1 These SCR installations have achieved exhaust 

concentrations of 20 to 40 ppm, which would represent a reduction of 67 to 84% from the 

emission level currently achieved for the Artesia FCCU regenerator.

The Western Refining Bloomfield refinery FCCU regenerator is well controlled for 

particulate matter, with an ESP. No baseline controls have been identified for NOX or SO2 from 

the regenerator vent. As discussed above, a number of options are available for reducing NOX

and SO2. 

Various options are available to reduce NOX emissions from process heaters. 

Combustion modifications including low-NOX burners (LNB), ultralow-NOX burners (ULNB), 

and flue gas recirculation (FGR) reduce the formation of NOX.

17

 In addition, flue gases from the 

process heaters can be treated with SCR or SNCR to reduce NOX emissions. These postcombustion controls can be used either alone or in conjunction with combustion controls.18

 The 

RBLC lists a number of BACT/PSD determinations for refinery process heaters. These are 

based on the use of ULNB or LNB, with emission limitations ranging from 0.3 lb/MMBTU to 

0.1 lb/MMBtu.

The Gallup Refinery uses a CO boiler to combust CO and volatile organic compound 

(VOC) off-gases produced by the refinery. The steam generated by the boiler is used as process 

steam at the refinery. The CO boiler is uncontrolled and has NOX and SO2 emissions of 65.1 

tons/yr and 703.5 ton/yr, as reported in the NEI database. NOX emissions from a CO boilers can 

be controlled using a variety of combustion modifications including overfire air (OFA), LNB, 

FGR, and combinations of these technologies.

19,20,21,22,23

 Add-on control systems such as SCR

and SNCR can also be used to reduce NOX emissions from boilers.8 In SCR, the flue gas is 

treated with a small quantity of ammonia (NH3) in a catalyst bed. The ammonia reacts with NOX

to produce nitrogen gas (N2). Alternatively, urea [(NH3)2CO] can be added instead of ammonia. 

In this case, the urea decomposes to produce ammonia, which reacts with NOX. SNCR also 

involves the addition of ammonia or urea to reduce NOX, but without a catalyst. SNCR is less 
3-5

efficient at reducing NOX than SCR, but is also generally less expensive. SNCR can also be 

used in situations where flue gas contaminants would poison the SCR catalyst. 

It must be noted that SCR and SNCR for controlling NOX require injection of ammonia 

(NH3), urea [(NH3)2CO], or other nitrogen compounds into the exhaust stream. These chemicals 

react with NOX to chemically convert the pollutant to elemental nitrogen (N2). However, the use 

of these chemicals generally results in ammonia emissions, termed ammonia slip.

Emissions of SO2 can be reduced by using duct sorbent injection (DSI), spray dryer 

absorber (SDA), or flue gas desulfurization (FGD). DSI uses dry limestone to react with the 

SO2 in the flue gas. The reacted limestone is then collected in a particulate control device, The 

SDA process is similar to the DSI process, except that a limestone slurry is injected into the flue 

gas where it reacts with the SO2 and is removed in a particulate control device. FGD involves 

the flue being passed through a vessel where it is contacted with an alkaline solution which 

reacts with the flue gas SO2 to form a sulfate particulate. The sulfate particulate is removed in 

the system and the used alkaline solution is recycled through the process. 

3.1 Factor 1 – Costs

Table 3-2 provides cost estimates for the emission control options which have been 

identified for the New Mexico refineries. For each option, the table gives an estimate of the 

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

amortized cost associated with the capital equipment cost. The table also shows the estimated 

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

3.2 Factor 2 – Time Necessary for Compliance

Once the regional haze control strategy is formulated for New Mexico, up to 2 years will 

be needed for the state to develop the necessary rules to implement the strategy. We have 

estimated that sources may then require up to a year to procure the necessary capital to purchase 

control equipment. The Institute of Clean Air Companies (ICAC) has estimated that 

approximately 13 months is required to design, fabricate, and install SCR or SNCR technology 

for NOX control.24 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.25 In the CAIR analysis, EPA estimated that approximately 30 

months is required to design, build, and install SO2 scrubbing technology for a single emission 

source.

26

 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. 
Company Source Control Technology

Pollutant 

controlled

Estimated 

control 

efficiency (%)

Potential 

emission 

reduction 

(tons/year)

Estimated 

capital cost 

($1000)

Estimated annual 

cost (1000 

$/year)

Cost effectiveness 

($/ton)

References

Optimization of NOX 

reduction catalyst

NOX 47 - 59 72 - 90 8,9

SCR NOX 67 - 84 103 - 129 not avail. 260 - 320 2,500 9,11

LNB NOX 40 1.6 76 8.1 5,100 17,18

ULNB NOX 75 - 85 3 - 3.4 131 13 3,800 - 4,400 8,17,18

LNB and FGR NOX 48 1.9 161 17 9,000 17,18

SNCR NOX 60 2.4 221 24 10,100 8,17,18

SCRa NOX 70 - 90 2.8 - 3.6 483 56 15,600 - 20,100 8,17,18

LNB and SCR NOX 70 - 90 2.8 - 3.6 553 63 17,600 - 22,600 8,17,18

Catalyst additives for 

NOX reduction

NOX 75 - 81 43 - 46 8,9

LoTOxTM NOX 85 49 not avail. 80 - 100 1,700 - 2,000 8,11

SNCR NOX 40 - 80 23 - 46 not avail. 60 - 120 2,500 8,9

SCR NOX 85 - 92 49 - 53 not avail. 120 - 130 2,500 9,11

Catalyst additives for SO2 

absorbtion

SO2 98 364 8,9

Desulfurization of 

catalytic cracker feed

SO2 98 364 9,15

Wet scrubbing SO2 98 364 not avail. 180 - 660 1,500 - 1,800 8,17,12

LNB NOX 40 2.4 117 12 5,200 17,18

ULNB NOX 75 - 85 4.6 - 5.2 199 20 3,800 - 4,300 8,17,18

LNB and FGR NOX 48 2.9 245 26 9,000 17,18

SNCR NOX 60 3.7 337 37 9,900 8,17,18

SCRa NOX 70 - 90 4.3 - 5.5 736 86 15,600 - 20,000 8,17,18

LNB and SCR NOX 70 - 90 4.3 - 5.5 843 97 17,600 - 22,500 8,17,18

LNB with OFA NOX 30 - 50 20 - 33 0.5 - 0.7 80 - 110 2,500 - 5,600 19

LNB, OFA, and FGR NOX 30 - 50 20 - 33 0.8 - 1.0 125 - 170 3,800 - 8,700 19

SNCR NOX 30 - 75 20 - 49 0.5 - 0.7 320 - 440 6,600 - 22,500 19

SCR NOX 40 - 90 26 - 59 1.5 - 2.0 400 - 600 6,800 - 10,200 19

DSI SO2 50 - 90 352 - 633 1.5 - 2.0 720 - 970 1,100 - 3,400 20

SDA SO2 80 - 90 563 - 633 1.5 - 2.0 1380 - 1860 2,200 - 3,300 20

FGD SO2 80 - 90 563 - 633 1.5 - 2.0 1150 - 1560 1,800 - 2,800 20

Table 3-2. Estimated Costs of Control for Selected Petroleum Refinery Operations in New Mexico

not available

not available

Western 

Refining 

Southwest, 

Gallup 

Refinery

not available

FCCU 

heater

FCCU 

regenerator 

(Unit 22)

Navajo not available

Refining 

Company, 

Artesia 

Refinery

FCCU 

heater

Western 

Refining 

Southwest, 

Bloomfield 

Refinery

b

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%. 

FCCU 

regenerator (A201)

CO Boiler, 

Unit 10
3-7

Based on these figures, the total time required achieve emission reductions for the 

FCCUs would be up to 61⁄2 years. This includes 2 years for regulatory development, 1 year for 

capital acquisition, and 21⁄2 years for designing, building and installing a scrubber, if this option 

is selected. If catalyst additives are used, time will be required to select and test the appropriate 

additives, and to determine the optimum feed rate for the additive.

The time to achieve emission reductions for the CO boiler would be up to 51⁄2 years. 

This includes 2 years for regulatory development, 1 year for capital acquisition, and 11⁄2 years for

designing, building and installing NOX controls. 

3.3 Factor 3 – Energy and Other Impacts

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

for sources at the New Mexico refineries. The table shows the additional fuel, electricity, and 

steam requirements resulting required to operate the control equipment; and the additional solid 

waste would be produced. CO2 emissions associated with the generation of the additional 

electricity and steam are also estimated in the table. 

The use of catalyst additives for the FCCU or desulfurization of the FCCU feed stream 

involve process modifications which are tailored to each specific refinery. Therefore, it was not 

possible to quantify the energy and non-air pollution impacts of these modifications within the 

time limitations of this project. However, process modifications to desulfurize the FCCU feed 

stream would generally require increases in catalytic hydrotreatment processing. These 

modifications may increase the generation of spent catalyst, which would need to be treated as a 

solid waste or a hazardous waste. Catalyst additives for reducing NOX and SO2 emissions from 

fluid catalytic cracking units are likely to result in increased generation of spent catalyst, which 

would have to be disposed as hazardous waste. These catalyst additives may also result in 

increases in fuel consumption. 

A LoTOxTM scrubbing system or wet scrubbing system applied to the fluidized catalytic 

cracking unit would require electricity to operate fans and other auxiliary equipment, and would 

produce a wastewater stream which would require treatment. In addition, sludge from the 

scrubber would require disposal as solid waste. SCR and SNCR systems would also require 

electricity for fans, and SCR systems would produce additional solid waste because of spent 

catalyst disposal. 

3.4 Factor 4 – Remaining Equipment Life

Information was not available on the age of the FCCU processes or the CO boiler. 

However, industrial processes often refurbished to extend their lifetimes. Therefore, the 

remaining lifetime of most equipment is expected to be longer than the projected lifetime of 

pollution control technologies which have been analyzed for these sources. 
Company Source Control Technology

Pollutant 

controlled

Electricity 

requirement 

(kW-hr)

Steam 

requirement 

(tons steam)

Solid waste 

produced (tons 

waste)

Wastewater 

produced (1000 

gallons)

Additional CO2 

emitted (tons)

Optimization of NOX 

reduction catalyst

NOX 72 - 90 ~0.03

SCR NOX 103 - 129 8,400 0.073 8.4

LNB NOX 1.6 a

ULNB NOX 3 - 3.4 a

LNB and FGR NOX 1.9 3,300 3.3

SNCR NOX 2.4 0.16 460 3.2

SCR NOX 2.8 - 3.6 8,400 0.073 8.4

LNB and SCR NOX 2.8 - 3.6 8,400 0.073 8.4

Catalyst additives for 

NOX reduction

NOX 43 - 46 ~0.03

LoTOxTM NOX 49.0 1,100 1.9 3.7 1.6

SNCR NOX 23 - 46 460 3.2

SCR NOX 49 - 53 8,400 0.073 8.4

Catalyst additives for 

SO2 absorbtion

SO2 364 0.03

Desulfurization of 

catalytic cracker feed

SO2 364 3 <0.03 0.5

Wet scrubbing SO2 364 1,100 3.1 3.7 2.6

LNB NOX 2.4 a

ULNB NOX 4.6 - 5.2 a

LNB and FGR NOX 2.9 3,300 3.3

SNCR NOX 3.7 0.16 460 3.2

SCR NOX 4.3 - 5.5 8,400 0.073 8.4

LNB and SCR NOX 4.3 - 5.5 8,400 0.073 8.4

LNB with OFA NOX 20 - 33 a

LNB, OFA, and FGR NOX 20 - 33 3,300 3.3

SNCR NOX 20 - 49 0.16 460 3.2

SCR NOX 26 - 59 8,400 0.073 8.4

DSI SO2 352 - 633 1,207 6.7 84 1.2

SDA SO2 563 - 633 836 8.0 67 0.8

FGD SO2 563 - 633 2,387 7.0 148 2.4

NOTES:

Table 3-3. Energy and Non-Air Pollution Impacts of Control for Selected Petroleum Refinery Operations in New Mexico

Potential 

emission 

reduction 

(tons/year)

Additional fuel 

requirement 

(%)

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

Navajo 

Refining 

Company, 

Artesia 

Refinery

FCCU 

regenerator 

(Unit 21)

FCCU 

heater

Western 

Refining 

Southwest, 

Gallup 

Refinery

CO Boiler, 

Unit 1

FCCU 

regenerator (A201)

A blank indicates no impact is expected.

a - The measure is expected to improve fuel efficiency.

FCCU 

heater

Western 

Refining 

Southwest, 

Bloomfield 

Refinery
3-9

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

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

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

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

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

as follows:

where:

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

A0 = the original annual cost estimate ($)

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

r = the interest rate (0.07)

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

n = the projected lifetime of the pollution control equipment
3-10

3.5 References for Section 3

1. EPA (2009), RACT/BACT/LAER Clearinghouse (RBLC), U.S. EPA, Technology Transfer 

Network, Clean Air Technology Center, RTP, NC, 

http://cfpub.epa.gov/rblc/htm/bl02.cfm

 

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

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

3. Bates, Rita (2009). Comments on draft analysis and baseline emissions information. 

Email from Rita Bates, New Mexico Department of Environment to Janet Hou, EC/R 

Incorporated, April 16, 2009.

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

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

5. DOE/EIA (2008), Petroleum Supply Annual, U.S. DOE Energy Information 

Administration, Washington, DC.

6. Montana Department of Environmental Quality, October 16, 2007, Air Quality Permit 

Issued to ConocoPhillips Corporation, Billings Refinery, Permit # 2619-23, 

http://www.deq.state.mt.us/AirQuality/ARM_Permits/ AWM_final_permit.asp

7. Montana Department of Environmental Quality, October 6, 2007, Air Quality Permit 

Issued to CHS Incorporated, Laurel Refinery, Permit # OP1821-01, 

http://www.deq.state.mt.us/AirQuality/ARM_Permits/AWM_final_permit.asp

8. NACAA (formerly STAPPA/ALAPCO) (2006), Controlling Fine Particulate Matter 

Under the Clean Air Act: a Menu of Options, Prepared by the State and Territorial Air 

Pollution Program Administrators (STAPPA) and Association of Local Air Pollution 

Control Officials (ALAPCO), www.4cleanair.org/ PM25Menu-Final.pdf.

9. European Commission (2003), Integrated Pollution Prevention and Control (IPPC): 

Reference Document on Best Available Techniques for Mineral Oil and Gas Refineries, 

http://eippcb.jrc.ec.europa.eu/reference/

10 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.

11. Ahmed, Shafi (2007), Technical Bulletin: Work Group Recommendations and Other 

Potential Control Measures, Stationary Combustion Sources Workgroup, SCS004c, Fluid 

Catalytic Cracking Unit in a Petroleum Refinery, 

http://www.nj.gov/dep/airworkgroups/docs/wps/SCS004C_fin2.pdf
3-11

12. Eagleson, Scott, et. al (2005), A Logical and Cost Effective Approach for Reducing 

Refinery Fluid Catalytic Cracking Unit Emissions, Presented at PETROTECH-2005, the 

6th International Petroleum Conference & Exhibition, New Delhi, India.

13. Lake Michigan Air Directors Consortium (LADCO) (2005), Midwest Regional Planning 

Organization (RPO) Petroleum Refinery Best Available Retrofit Technology (BART) 

Engineering Analysis, http://www.ladco.org/Regional_Air_Quality.html

14. Green, et. al. (1986), Catalyst for reduction of SOX Emissions from Fluid Catalytic 

Cracking Units, U.S. Patent 4,589,978.

15. 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

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

EPA, Office of Air Quality Planning and Standards RTP, NC, Section 6 - Particulate 

Matter Controls, page 3-58, http://www.epa.gov/ttncatc1/products.html#cccinfo

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

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

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

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

http://www.epa.gov/ttncatc1/products.html.

19 . Khan, Sikander (2003), Methodology, Assumptions, and References: Preliminary NOX

Controls Cost Estimates for Industrial Boilers, U.S. EPA.

20. Khan, Sikander (2003), Methodology, Assumptions, and References: Preliminary SO2

Controls Cost Estimates for Industrial Boilers, U.S. EPA.

21. EPA (1999), Technical Bulletin: Nitrogen Oxides, Why and How they Are Controlled,

U.S. EPA, RTP, NC.

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

U.S. EPA, RTP, NC, pp III-1223 through III-1276, 

http://www.epa.gov/ttnecas1/AirControlNET.htm.
3-12

23. 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/

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

Emissions Control Technologies on Industrial Sources, 

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

25 . Ghoreishi, Farrokh (2007), Personal communication, Time required to install add-on 

control measures for NOX, Wisconsin Department of Natural Resources, April 27.

26. 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