# 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 C hape l 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 in itial 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 priori ty 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 i ssues, 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 c ontrol 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 sp onsoring 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 Im pacts

................................ ................................ ................................ ........... 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 Facto r 4

– Remaining Equipment Life

................................ ................................ ................................ ......... 3

- 9 3.5 References for Section 2

................................ ................................ ................................ ............................. 3

- 10iv 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 CO 2 Carbon Dioxide DSI Duct Sorbent Injection EC Elemental Carbon EDMS E missions Data Management System EGU Electric Generating Units EPA Environmenta l 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 Burn ers 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 NO 2 Nitrogen Dioxide NO x Nitrogen Oxides 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 RACT Reasonably Achievable Contr ol Technology RBLC RACT/BACT/LAER Clearinghouse SCR Selective Catalytic Reduction SDA S pray D ryer A bsorber SNCR Selective Noncatalytic Reduction SO 2 Sulfur Dioxide STAPPA State and Territorial Air Pollution Program Administrators ULNB U ltralow

- NO X B urners VOC Volatile Organic Compounds WRAP Western Regional Air Partnershipv 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 p p m Par ts Per Million ppmv Parts per Million b y Volume scfm Standard Cubic Feet per Minute2

- 1 

## 1

. Introduction

The Regional Haze Rule requires States to set reasonable progress goals toward meeting a national goal of natural visibility conditions in Cla ss 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 (NO X ) and sulfur dioxide (SO 2 ), which can react in the atmosphere to produce visibility

- o bscuring 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 PM 2.5 , PM 10 , 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 t urbines 2. Oil and natural gas ex ploration and production field operations 3. Natural gas processing plants 4. I ndustrial 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 Analysi s.”
The current report presents a the results of a four

- factor analysis of potential control measures f

or selected emission sources at three petroleum refineries in New Mexico

. The emission sources addressed in this current report were selected by the New Mexico Environment2

- 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 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 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 ins tallation 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, whi ch 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 amo rtized 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 Se tting Reasonable Progress Goals under the Regional Haze Program 6 indicates 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 fo llowed 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

- effective ness 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 co st 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 economi c 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 t he 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 contr ol 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 depositi on, 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 otherwi se 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 to2

- 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 am ount 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 ad ditional energy (except CO 2 ) 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 o f 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 the2

- 4

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

- 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 , R TP , NC
, http://www.epa.gov/ttnecas1/AirControlNET.htm

.
3

. Coal U

tility 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
, M idwest 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 Cle an Air Agencies, www.4cleanair.org/ PM25Menu

- Final.pdf

.
6 EPA (2007), Guidance for Se tting Reasonable Progress Goals under the Regional Haze Program , http://www.epa.gov/ttncaaa1/t1/memoranda/reasonable_progress_guid071307.pdf

. 7

. EPA ( 2002 ), EPA Air Pollut ion Control Cost Manual
, 6th ed., EPA/452/B

- 02

- 001, U.S. EPA, Office of Air Quality Planning and Standards, RTP, NC, Section 5

- SO 2 and Acid Gas Controls, pp 1

- 30 through 1

- 42
, http://www.ep a.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 sourc es 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 R efining 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 addition al 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 SO 2 emissions from the Navajo Artesia refi n ery 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 b aseline emissions of NO X and SO 2 for the refineries are based on the WRAP 2002 emissions inventory , and data received from the New Mexico Environment Department

. 2
, 3 Emissions of PM 2.5 and PM 10 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 PM 10 emissions from catalytic cracking units, respectively. PM 10 emissions from the carbon monoxide ( CO ) boiler were assumed to have a composit ion 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 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. The catalyst regenerator also emits NO X and PM, including material abraded from the catalyst (catalyst fines).ppm tons/yr Optimization of NO X reduction catalyst 47 - 59 72 - 90 8,9

SCR 67 - 84 103 - 129 9,11

SO 2 Wet scrubber 25 43 None identified
PM 10 , PM 2.5 , EC, OC Wet scrubber not available None 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 SO 2 Sulfur recovery 0.15
PM 10 , PM 2.5 , EC, OC None identified not available Catalyst additives for NO X reduction 75 - 81 43 - 46 8,9

LoTOx TM 85 49 8,11 SNCR 40 - 80 23 - 46 8,9 SCR 85 - 92 49 - 53 9,11 Catalyst additives for SO 2 absorbtion 98 364 8,9

Desulfurization of catalytic cracker feed 98 364 9,15

Wet scrubbing 98 364 8,12,17 PM 10 , PM 2.5 , 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
SO 2 Sulfur recovery 0.84 None identified
PM 10 , PM 2.5 , 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
PM 10 21.4
PM 2.5 21.4
EC 7.3 OC 5.1 FCCUregenerator (Unit 22) Navajo Refining Company, Artesia Refinery NO X NO X reduction catalyst and low-NO X combustion promoters 123

Western Refining Southwest, Bloomfield Refinery

Western Refining Southwest, Gallup Refinery CO Boiler,

Unit 10

SO 2 Baseline emissions Estimated control efficiency (%) Potential

emission reduction (tons/year) References Potential additional control measures Existing control

measures

NO X None identified FCCU heater NO X None identified

FCCUheater (H202) Table 3-1. Control Options for Selected Petroleum Refinery Operations in New Mexico

NO X

SO 2 57

371 153 Pollutant Company

1,223

Source

None identified 703.5 None identified

65.1 FCCUregenerator (A201) None identified

None identified 262

NO X3

- 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 T he Western Refining Gallup refinery FCCU has a capacity of 8,500 bbl/day. (It is not being analyzed under this effort.)

The SO 2 concentration in the Artesia FCCU regenerator exhaust is limited by permit conditions to 25 parts per million ( ppm )
, which is ac hieved by a wet scrubber

. 1 The SO 2 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 NO X emis sions 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 NO X concentration of about 123 ppm, and is achieved by the u se of NO X a bsorption catalyst and low

- NO X combustion promoters

. 3 Based on reported stack gas flow rates and emissions data, the concentrations of NO X and SO 2 in the Bloomfield FCCU regenerator exhaust are abou t 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 determinat ions 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) determinatio ns 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 NO X emissions in the FCCU regenerator exhaust to 50 to 65 ppm. 6 , 7 O ne refinery in Ja pan has also used s elective noncatalytic reduction ( SNCR )

. 8
, 9 In addition, the LoTOx TM process has been developed to control NO X emissions in the catalytic cracking regenerator offgas. In this system, ozone is injected into the offgas to conver t the nitrogen oxide (NO) and nitrogen dioxide (NO 2 ) which comprise NO X into more highly oxidized forms of nitrogen such as dinitrogen pentoxide (N 2 O 5 ). These more highly oxygenated compounds are more soluble in water, and are removed from the offgas stre am 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 NO X 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 b asis, as well

- controlled for SO 2 . 8 In addition, the EPA RBLC shows an offgas SO 2 concentration of 25 ppm for a number of recent BACT/ PSD determinations. 1 Refineri es have achieved the 25 p pm level by wet scrubbing, which can reduce SO 2 emissions by 95% to over 99%. 1
, 8
, 13 Some refineries have achieved the 25 ppm level by using an SO 2 adsorpt ion 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 H 2 S in the ca talytic cracking reactor, and exit this reactor with the cracked hydrocarbon stream. The H 2 S is eventually removed from the hydrocarbon stream in an amine treatment process, and then recovered in the sulfur recovery process. 14 SO 2 emissions from the FCCU regenerator can also be controlled by desulfurization3

- 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 preci pitation (ESP). 8
, 16

Based on the RBLC determinations and the NACAA report, the Artesia FCCU exhaust would be considered to be well controlled for SO 2 , with an emission concentration of 25 ppm. T he wet scrubbe r used to control SO 2 for the Artesia regenerator also provides control of particulate emissions. Artesia also uses NO X absorption catalyst and low

- NO X combustion promoters to reduce NO X 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 NO X catalyst addition rates. As noted above, s ome r efineries in another state have used catalyst additives to reduce NO X emissions in the FCCU regener ator 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 leve ls were achieved by testing different types and usage rates of NO X reduction catalysts, in order to identify the formula for the best NO X control. 6 , 7 The EPA RBLC shows a number of BACT determina tions for NO X 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 currentl y 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 NO X or SO 2 from the regenerator vent. As discus sed above, a number of options are available for reducing NO X and SO 2 .
Various options are available to reduce NO X emissions from process heaters. Combustion modifications including low

- NO X burners ( LNB )
, ultralow

- NO X burners ( ULNB )
, and flue gas recir culation ( FGR ) reduce the formation of NO X . 17 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. 18 T he 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 volatil e organic compound ( VOC ) off

- gases produced by the re finery. The steam generated by the boiler is used as process steam at the refinery. The CO boiler is uncontrolled and has NO X and SO 2 emissions of 65.1 tons/yr and 703.5 ton/yr, as reported in the NEI database. NO X 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 NO X emissions from boilers. 8 In SCR, the flue gas is treated with a small quantity of ammonia (NH 3 ) in a catalys t bed. The ammonia reacts with NO X to produce nitrogen gas (N 2 ). Alternatively, urea [(NH 3 ) 2 CO] can be added instead of ammonia. In this case, the urea decomposes to produce ammonia, which reacts with NO X . SNCR also involves the addition of ammonia or urea to reduce NO X , but without a catalyst. SNCR is less3

- 5

efficient at reducing NO X 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 NO X require injection of ammonia (NH 3 ), urea [(NH 3 ) 2 CO], or other nitrogen compounds into the exhaust stream. These chemicals react with NO X to chemically convert the pollutant to elemental nitrogen (N 2 ). However, the use of the se chemicals generally results in ammonia emissions, termed ammonia slip.

Emissions of SO 2 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 SO 2 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 SO 2 and is removed in a particu late control device. FGD involves the flue being passed through a vessel where it is contacted with a n alkaline solution which reacts with the flue gas SO 2 to form a sulfate particulate. The sulfate particulate is removed in the system and the used alkal ine 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 ne cessary 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 i s required to design, fabricate, and install SCR or SNCR technology for NO X 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 SO 2 scrubbing technology for a single emission

source

. 26 The analysis also estimated that up to an additio nal 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 NO X reduction catalyst NO X 47 - 59 72 - 90 8,9

SCR NO X 67 - 84 103 - 129 not avail. 260 - 320 2,500 9,11

LNB NO X 40 1.6 76 8.1 5,100 17,18
ULNB NO X 75 - 85 3 - 3.4 131 13 3,800 - 4,400 8,17,18 LNB and FGR NO X 48 1.9 161 17 9,000 17,18
SNCR NO X 60 2.4 221 24 10,100 8,17,18
SCR a NO X 70 - 90 2.8 - 3.6 483 56 15,600 - 20,100 8,17,18 LNB and SCR NO X 70 - 90 2.8 - 3.6 553 63 17,600 - 22,600 8,17,18 Catalyst additives for NO X reduction NO X 75 - 81 43 - 46 8,9

LoTOx TM NO X 85 49 not avail. 80 - 100 1,700 - 2,000 8,11
SNCR NO X 40 - 80 23 - 46 not avail. 60 - 120 2,500 8,9
SCR NO X 85 - 92 49 - 53 not avail. 120 - 130 2,500 9,11 Catalyst additives for SO 2 absorbtion SO 2 98 364 8,9

Desulfurization of catalytic cracker feed SO 2 98 364 9,15

Wet scrubbing SO 2 98 364 not avail. 180 - 660 1,500 - 1,800 8,17,12
LNB NO X 40 2.4 117 12 5,200 17,18
ULNB NO X 75 - 85 4.6 - 5.2 199 20 3,800 - 4,300 8,17,18 LNB and FGR NO X 48 2.9 245 26 9,000 17,18
SNCR NO X 60 3.7 337 37 9,900 8,17,18
SCR a NO X 70 - 90 4.3 - 5.5 736 86 15,600 - 20,000 8,17,18 LNB and SCR NO X 70 - 90 4.3 - 5.5 843 97 17,600 - 22,500 8,17,18 LNB with OFA NO X 30 - 50 20 - 33 0.5 - 0.7 80 - 110 2,500 - 5,600 19 LNB, OFA, and FGR NO X 30 - 50 20 - 33 0.8 - 1.0 125 - 170 3,800 - 8,700 19
SNCR NO X 30 - 75 20 - 49 0.5 - 0.7 320 - 440 6,600 - 22,500 19
SCR NO X 40 - 90 26 - 59 1.5 - 2.0 400 - 600 6,800 - 10,200 19
DSI SO 2 50 - 90 352 - 633 1.5 - 2.0 720 - 970 1,100 - 3,400 20
SDA SO 2 80 - 90 563 - 633 1.5 - 2.0 1380 - 1860 2,200 - 3,300 20
FGD SO 2 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 FCCUregenerator (Unit 22) not available Navajo 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%.

FCCUregenerator (A201)

CO Boiler, Unit 103

- 7

Based on these figures, the total time required achieve emission reductions for the FCCU s 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 appropri ate 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 5 1⁄2 years. This includes 2 years for regulatory development, 1 year for capital acquisition, and 11⁄2 years for designing, building and installing NO X 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 tabl e shows the additional fuel, electricity, and steam requirements resulting required to operate the control equipment; and the additional solid waste would be produced. CO 2 emissions associated with the generation of the additional electricity and steam ar e 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 n on

- 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 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 increases in fuel consumption.

A LoTOx TM scrubbing system or wet scrubbing system applied to the fluidized catalytic cracking unit would req uire 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 elec tricity 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 p rocesses 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 CO 2

emitted (tons) Optimization of NOX reduction catalyst NO X 72 - 90 ~0.03

SCR NO X 103 - 129 8,400 0.073 8.4

LNB NO X 1.6 a ULNB NO X 3 - 3.4 a LNB and FGR NO X 1.9 3,300 3.3
SNCR NO X 2.4 0.16 460 3.2
SCR NO X 2.8 - 3.6 8,400 0.073 8.4 LNB and SCR NO X 2.8 - 3.6 8,400 0.073 8.4 Catalyst additives for NO X reduction NO X 43 - 46 ~0.03

LoTOx TM NO X 49.0 1,100 1.9 3.7 1.6
SNCR NO X 23 - 46 460 3.2
SCR NO X 49 - 53 8,400 0.073 8.4 Catalyst additives for SO 2 absorbtion SO 2 364 0.03

Desulfurization of catalytic cracker feed SO 2 364 3 <0.03 0.5

Wet scrubbing SO 2 364 1,100 3.1 3.7 2.6
LNB NO X 2.4 a ULNB NO X 4.6 - 5.2 a LNB and FGR NO X 2.9 3,300 3.3
SNCR NO X 3.7 0.16 460 3.2
SCR NO X 4.3 - 5.5 8,400 0.073 8.4 LNB and SCR NO X 4.3 - 5.5 8,400 0.073 8.4 LNB with OFA NO X 20 - 33 a LNB, OFA, and FGR NO X 20 - 33 3,300 3.3
SNCR NO X 20 - 49 0.16 460 3.2
SCR NO X 26 - 59 8,400 0.073 8.4

DSI SO 2 352 - 633 1,207 6.7 84 1.2
SDA SO 2 563 - 633 836 8.0 67 0.8
FGD SO 2 563 - 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 FCCUregenerator (A201)

A blank indicates no impact is expected. a - The measure is expected to improve fuel efficiency.

FCCU heater Western Refining Southwest, Bloomfield Refinery3

- 9

If the remain ing 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: A 1 = the annual cost of co ntrol 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 pr ojected lifetime of the pollution control equipment3

- 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 In formation 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 A ir 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.o rg/ PM25Menu

- Final.pdf

.
9

. European Commission ( 2003 )
, Inte grated 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, I nc. (2005), Assessment of NO X 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 Mea sures, Stationary Combustion Sources Workgroup, SCS004c, Fluid Catalytic Cracki ng Unit in a Petroleum Refinery, http://www.nj.gov/dep/airworkgroups/docs/wps/SCS004C_fin2.pdf3

- 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 & E x hibition, New Delhi, India.

13

. Lake Michigan A ir Directors Consortium (LADCO) ( 2005 )
, Midwest Regional Planning Organization (RPO) Petroleum Refinery Best Available Retrofit Technology (BART) Engineering Analysis, http://www.ladco.org/Re gional_Air_Quality.html

14

. Green, et. al

. (1986), Catalyst for reduction of SO X Emissions from Fluid Catalytic Cracking Un its, U.S. Patent 4,589,978.

15

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

x 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/vwA N/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

— NO X 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 NO X Controls Cost Estimates for Industrial Boilers , U.S. EPA.

20

. Khan, Sikander (2003), Met hodology, Assumptions, and References: Preliminary S O 2 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 Compa nies (2006), Typical Installation Timelines for NOX Emissions Control Technologies on Industrial Sources
, http://www.icac.com/files/public/ICAC_NOx_Control_Inst allation_Timing_120406.pdf

.
25

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

- on control measures for NO X , 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