# Supplementary Information for

Four

- Factor Analyses for Selected Individual Facilities in Wyoming

May 6 , 2009

Revised Draft Report

Prepared by:
William Battye Janet Hou Brad Nelson
EC/R Incorporated 501 Eastowne Drive, Suite 250 C hapel Hill, North Carolina 27514

Prepared for:
Lee Gribovicz, Project Manager
Western Regional Air Par tnership (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 d ocuments 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 Wes tern 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. Boiler s

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

- 1 3 .1 Factor 1

– Costs

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

- 2 3 .2 Factor 2

– Time Necessary for Compliance

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

- 2 3 .3 Factor 3

– Energy and Other Impacts

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

- 3 3 .4 Factor 4

– Remaining Equipment Life

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

- 3 3 .5 References for Section 3

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

- 5
4. Cement Manufacturing

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

- 1 4 .1 Factor 1

– Costs

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

- 4 4 .2 Factor 2

– Time Necessary for Compliance

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

- 4 4 .3 Factor 3

– Energy and Other Impacts

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

- 4 4 .4 Factor 4

– Remaining Equipment Life

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

- 5 4 .5 References for Section 4

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

- 8iv Abbreviations

BART Best Available Retrofit Technology EC Elemental Carbon EDMS Emissions Data Management System EPA Environmental Protection Agency ESP Electrostatic Precipitator ICAC Institute of Clean Air Companies LNB Low

- NOx Burn ers MRP O Midw est Regional Planning Organization MW Megawatt NACAA National Association of Clean Air Agencies NEI National Emissions Inventory NO x Nitrogen O xides OC Organic Carbon OFA Overfire Air PM Particulate Matter PM 10 Particulate Matter Particles of 10 Mi crometers or Less PM 2.5 Particulate Matter Particles of 2.5 Micrometers or Less SCR Selective Catalytic Reduction SNCR Selective Noncatalytic Reduction SO 2 Sulfur Dioxide WRAP Western Regional Air Partnership1

- 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 2 008 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 f actors 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 ident ified control measures for emissions of nitrogen oxides (NO X ) , which can react in the atmosphere to produce visibility

- obscuring particulate matter (PM) on a regional scale, and also for direct emissions of particulate matter

. By request from the Wyoming state representative, SO 2 has not been analyzed as SO 2 emissions have been addressed through the back stop trading program. For direct particulate matter emissions, we have evaluated the impacts of control measures on various part iculate 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 e ngines and t urbines 2. Oil and natural gas exploration 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 h eaters

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.”1

- 2

The current report presents the results of a f our

- factor analysis of potential control measures f

or selected emission sources and includes two electric generating units and one cement kiln in Wyoming

. The emission sources addre ssed in this current report were selected by the Wyoming Department of Env ironmental Quality

. Section 2 discusses the methodology employed in these analyses. Section 3 presents the results of the four

- factor analysis for emission sources from boilers and Section 4 presents the results of the four

- factor analysis for emission sources from the kiln at the cement manufacturing plant

.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 followed the pro tocols 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 calculati on 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 overl y 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 th e 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 c ontrol 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 incl udes 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 and wastewater discharged

. 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 Fac tor 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 comply ing 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 quali ty impacts of identified control technologies were aggregated to estimate the energy impacts for the specified industry sectors. However, indirect energy impacts2

- 3

were not considered, such as the different energy requirements to produce a given amount of c oal 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 Impacts Not Included Impacts of control measures on boiler efficiency Energy required to produce lower sulfate fuels Secondary environmental impacts to produce additional energy 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 parti cular 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 equip ment 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

- effec tiveness.2

- 4

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 Utility En vironmental 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 Re gional 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), Control ling 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 Setting Re asonable 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

. Boilers

A four

- factor analysis was performed on two coal

- fired boilers (Units BW41 & BW42) at the Pacificorp Dave Johnston electric generating station. These boilers are used to produce steam from the combustion of su b

- bituminous coal to generate electricity in a steam turbine

. Each of the boilers is rated to be able to generate 114 megawatts (MW). Pollutant emissions from the boilers include: nitrogen oxides (NO X ) and particulate matter (PM). The emissions of SO 2 emissions have not been addressed in this analysis, because the emissions have already been addressed through a back stop trading program.

Table 3

- 1 s ummarizes the NO X emi ssions from each of the boilers, as well as the co ntrol measures used to reduce these emissions. 1 The pollutant emission rates shown in Table 3

- 1 were obtained from the WRAP 2002 emission inventory. 2 Emissions of elemental carbon ( EC ) and organic carbon ( OC ) were estimated using speciation fac tor s from EPA’s SPECIATE database. 3 The EC and OC components are estimated to comprise 0.0 21 % and 0.01 2 % of PM 10 emissions from coal

- fired boilers , respectively.

Currently, each of the boilers is equipped with a cold

- side electrostatic precipitator (ESP) used to reduce particulate emissions from the boiler exhaust gas. This control technology is comparable to other PM control op tions; therefore PM control options for these boilers will not be explored. A list of p otential NO X control strategies are presented in Table 3

- 2

. The table provides a range of pollutant reductions and presents the potential emission reductions f rom the baseline emissions by applying the listed control options. 3 , 4 These control options have been applied to many electrical generating unit boilers in the U.S. to reduce emissions of NO X .3

- 2

3 .1 Factor 1

– Costs

Table 3

- 3 provides cost estimates for the emission control options which have been identified for each of the electrical generating unit boilers

. For each option, the table gives an estimate of the capital cost to install the necessary equipment, and th e total annual cost of control, including the amortized cost associated with the capital equipment cost. The capital cost values are expressed in terms of the cost per MW size of the boiler using EPA cost information

. 5 The capital cost data was extrap olated to determine the capital cost for the larger sized boilers. The annual cost was calculated by amortizing the capital cost over 3 0 years at an interest rate of 7% and multiplying that value by an O&M factor. Table 3

- 3 also estimates the cost effectiveness for each control measure, in terms of the cost per ton of emission reduction. Recent literature 6 has indicated that the cost of SCR for electric generating can vary from $ 1 5 0 to $ 30 0 per kilowatt, therefore due to this variability, the capital and annual costs for SCR are presented as a range.

3 .2 Factor 2

– Time Necessary for Compliance

Once a S tate decides to adopt a particular control strat eg 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 1 8 months is required to design, fabricate, and install SCR or SNCR technology for NO X control

. 7 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. For a complete system, the typical deployment of LNB or LNB + OFA takes between 24

- 32 weeks (6

– 8 m onths) on a typical industrial boiler covering the bid evaluation through the startup of the technology. Based on these figures, the total time required to achieve emission reductions for boilers is estimated at a total of 51⁄2 years for NO X strategies

.3

- 3

3

. 3 Factor 3

– Energy and Other Impacts

Table 3

- 4 shows the estimated energy and non

- air pollution impacts of control measures for industrial boilers

. The values were obtained from an EPA report listing the pe rformance impacts of each of the control technology options

. 8 In general, the combustion modification technologies ( LNB, OFA ) do not require steam or generate solid waste, or wastewater. They also do not requir e 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. Installation of SCR on an industrial boiler is not expected to increase fuel consumption

. However additional energy is required to operate the SCR . In addition, spent catalyst would have to be changed periodically, producing an increase in solid waste disposal. However, many catalyst companies accept the return of spent cataly st material.

3

. 4 Factor 4

– Remaining Equipment Life

Electric g enerating u nits 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 t echnologies 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.3

- 43

- 5

3

. 5 References for Section 3

1

. NEEDS 2006.

2

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

. http://www.wrapedms.org/app_main_dashboard.asp

3

. 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/

4

. NESCAUM (2009), Applicability and Feasibility of NO X , SO 2 , and PM Emission Control Technologies for Industrial, Commercial, and Institutional (ICI) Boilers.

5

. Khan, Sikander (2003), Methodology, Assumptions, and References: Preliminary NO X Controls Cost Estimates for Industrial Boilers.

6

. Power Magazine (2006), Estimating SCR Installation Costs. http://www.powermag.com/instrumentation_and_controls/Estimating

- SCR

installationcosts_506_p3.html

7

. Institute of Clean Air Companies (2006), Typical Installation Timelines for NO X E missions Control Technologi es on Industrial Sources.

8

. Reference 5

.4

- 1 

## 4

. Cement Manufacturing

Four

- factor analyses have been conducted for selected emission sources at one Wyoming cement manufacturing plant

. The following facilit y and emission source has been evaluated:

 Mountain Cement Company , Laramie Plant

– Cement Kiln #2

Table 4

- 1 outlines the baseline levels of emissions and potential control measures that could be adopted to re duce these emissions

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

Baseline emissions of NO X for the kiln were obtained from the WRAP 2002 emissions inventory. 1 Em issions of PM 2.5 and PM 10 were obtained from the 2002 U.S

. EPA NEI

. Emissions of EC and OC were estimated using speciation factors from EPA’s SPECIATE database. 2 EC and OC are estimated to comprise 0.07% and 0.014% of PM 10 emissions from cement kilns , respectively

. The primary source of emissions from cement manufacturing plants is the cement kiln

. There are four types

– long wet kilns, long dry kilns, preheater kilns, and preheater/precalciner kilns . Fuels used in cem ent kilns include coal, natur al gas, and waste

- derived fuels ( primarily scrap tires, but also motor oils, surplus printing inks, and sludge from the petroleum industry )

. 3

W et, long dry, and most preheater kilns have one fuel combustion zone; newer prehea ter/precalciner kilns have two fuel combustion zones and some may even have three

. NO X emissions are generated due to oxidation of molecular nitrogen present in the combustion air (i.e., thermal NO X formation) or oxidation of nitrogen compounds within the combustion fuel (i.e., fuel NO X formation)

. The temperature within the combustion zone(s) dictate, in part, the amount of NO X formed during the production of clinker

. The energy efficiency also dictates the formation of emissions, as the efficiency infl uences the amount o f heat input required to produce cement. 4 PM emissions are also generated by cement kilns.

The Mountain Cement Company Laramie Plant cement kiln is a long dry kiln with a capacity of 1,500 tons of clinker per day ; assuming the plant runs 365 days of the year the result is 547,500 tons per year ( tpy )

. 5 NO X emissions from the Laramie preheater kiln are 524 tpy

. 1Company Source Pollutant Baseline emissions (tons/yr) Control Technology Estimated control efficiency (%) Potential emission

reduction (1000 tons/year) References LNB (indirect) 30-40 157 - 210 4, 5,7,8,13 LNB (direct) 40 210 4, 5,7,8,13 Biosolid Injection 50 262 4, 5,7,8,13 NOXOUT 35 183 4, 5,7,8,13 CemSTAR 20-60 105 - 314 4, 5,7,8,13 LoTOx TM 80-90 5, 6 SCR 80 419 4, 5,7,8,13 SNCR (urea) 35 183 13 SNCR (ammonia) 35 183 13 PM 10 37.42 37 7, 9
PM 2.5 15.11 15 7, 9 EC 2.6 2.59 7, 9 OC 0.21 0.52 7, 9 PM 10 37.42 36 - 37 7, 9
PM 2.5 15.11 14 - 15 7, 9 EC 2.6 2.52 - 2.59 7, 9 OC 0.21 0.20 - .021 7, 9 Table 4-1. Potential Control Options for Selected Cement Manufacturing Operations in Wyoming

Mountain Cement Company Long Dry Kiln #2 NO X 523.95

Fabric Filter

Dry ESP 99

95-984

- 3

C ombustion control options for NO X include:

 D irect and indirect

- fired low NO X burners , and the  CemStar TM process.

Kilns can be considered either direct

- or indirect

- fired kilns. Direct

- fired kilns use more than 10% of primary air (i.e., air that is used f or conveying the pulverized c oa l from the coal mill to the kiln). Indirect

- fired kilns use less than 10% of primary air. Low NO X burners can be used on either direct

- or indirect

- fired kilns. L ow NO X burners reduce flame turbu lence, delay fuel/air mixing, and establish fuel

- rich zones for initial combustion, thus reducing thermal NO X formation. 4 The CemStar process adds a small amount of steel slag to the raw kiln feed and lower th e temperature required to operate the kiln.

 NO X removal controls include :  B iosolid injection ,  LoTOx TM

,  SCR ,  SNCR , and  NO X OUT
Biosolid injection uses biosolids from wastewater treatment plants to lower the kiln heating temperature required to produce clinker (biosolid tipping fees are such that often the annualized cost is negative, i.e., the plant receives a credit for using the technology)

. In the LoTOx TM system, ozone is injected int o the kiln which oxidizes NO X . The resulting higher oxides of nitrogen can then be removed by a wet scrubber. 6 LoTOx is licensed by the BOC G roup and is currently being used on the Midlothian cement wet kilns in Texas. 6 , 7
SCR uses an ammonia catalyst (such as a t i t a nium dioxide or vanadium pentoxide mixture) to selectively reduce NO X emissions from exhaust gases by converting NO X to nitrate

. SNCR also reduces NO X formation by ammonia or urea but does not u se a catalyst

. Instead the ammonia or urea is injected into the kiln

. Similar to SCR, there is an ideal temperature range at which these reactions optimally occur

. Long wet and dry kilns have the ideal temperature for SNCR reactions in the middle of the kiln, whereas preheater/precal c iner kilns have the ideal temperature at the lower end of the preheater tower or at the cooler end of the kiln, i.e., not in the middle

. Thus preheater/precalciner kilns are much more conducive to the SNCR technology although SNCR has been used in both long wet and dry kilns

.
NO X OUT is similar to the SNCR process and uses urea to complete the chemical conversion of NO to nitrate and oxygen

. The temperature window is somewhat wider than typical SNCR systems due to an additive developed by the proprietors of the NO X OUT technology. 4 PM emissions are often controlled by fabric filters or ESP s

. 8 , 94

- 4

4 .1 Factor 1

– Costs

Table 4

- 2 provides cost estimates for the emission control options which have been identified for the Wyoming cement manufacturing plant

. For each option, the table gives an estimate of the capital co st 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

.
4 .2 Factor 2

– Time Necessary for Compliance
Once the regional haze control strategy is formulated for Wyoming , 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 ICAC has estimated that approximately 13 months is required to design, fabri cate, and install SCR or SNCR technology for NO X control. 10 However, state regulators’ experience indicates that closer to 18 months is required to install this technology. 11 Installation of a single NO X syste m on cement kilns typically takes less than 18 months. However, LoTOx requires a scrubber, which will take approximately 26 months to procure the necessary capital, plan, and construct the system. It is assumed that the time for compliance for installing PM controls also falls within the range of 13

- 18 months.
Based on these figures, the total time required to achieve emission reductions for the cement kilns would be u p to 7 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.

4

. 3 Factor 3

– Energy and Other Impacts

Table 4

- 3 shows the estimated energy and non

- air pollution impacts of control measures for sou rces at the Wyoming cement manufacturing plant

. The table shows the additional fuel, electricity, and steam requirements needed to operate the control equipment; and the additional solid waste that would be produced

.
A LoTOx TM 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 may require additional heat input as the temperature at which the catalytic reactions occur can be higher than the typical cement kiln flue gas temperatures

. However, it is possible to use heat recovery systems to reheat the exhaust and avoid generating4

- 5

additional heat input

. There is also the additional burden of getting rid of fouled or deactivated catalyst from the system

– often the PM control device in the form of a fabric filter or electrostatic precipitator can achieve this goal

. 4 SCR sys tems would produce additional solid waste because of spent catalyst disposal

. Dust captured by an ESP or fabric filter would also require disposal as a solid waste

. The presence of catalyst fines in the dust may require treatment as a hazardous waste. 12

4

. 4 Factor 4

– Remaining Equipment Life
Information was not available on the age of the cement kilns. However, industrial processes often refurbish cement kilns 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.
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: A 1 = the annual cost of control for the shorter equipment lifetime ($) A 0 = the original annual cost estimate ($) C = the capital cost of instal ling 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 equipmentCompany Source Control option Pollutant Estimated control efficiency (%) Potential

emission reduction (tons/year) Estimated capital

cost ($1000) Estimated

annual cost ($1000/year) Cost effectiveness

($/ton) References

LNB (indirect) NO X 30-40 157 - 210 826 205 6,568 - 4,910 4, 5,7,8,13 LNB (direct) NO X 40 210 2,460 449 13,853 4, 5,7,8,13 Biosolid Injection NO X 50 262 474 -127 c 1,324 4, 5,7,8,13 NOXOUT NO X 35 183 960 507 8,023 4, 5,7,8,13
CemStar NO X 20-60 105 - 314 Unknown a Unknown a Unknown a 4, 5,7,8,13
LoTOx TM NO X 80-90 419 - 472 Unknown d 5, 6 SCR NO X 80 419 27,042 7,553 82,535 4, 5,7,8,13 SNCR (urea) NO X 50 183 Unknown b Unknown b 1,223 8, 13 SNCR (ammonia) NO X 50 183 Unknown b Unknown b 1,223 8, 13

PM 10 , EC, OC 99 37 5,261 4,451 262,489 7, 9
PM 2.5 99 15 5,261 4,451 647,472 7, 9
PM 10 , EC, OC 95-98 36 - 37 10,926 6,475 483,356 - 470,292 7, 9
PM 2.5 95-98 14 - 15 10,926 6,475 1,242,915 - 1,160,054 7, 9

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). b Capital and annual costs for SNCR has only been costed for preheater and precalcnier kilns. Only cost effectiveness figures were available for dry kilns. c A negative annual cost is given because cement kilns receive a credit for the biosolids tipping fee paid by facilities providing the biosolids to the cement plant. For the purposes of this analysis the tipping fee is $5.00/ton.

Table 4-2. Estimated Costs of Control for Selected Cement Manufacturing Operations in Wyoming

Mountain Cement Company Long Dry

Kiln #2

Fabric Filter

Dry ESP

a The CemStar process has been costed for long wet kilns only although the process is currently being used in long dry kilns at two facilities, one in Texas and one in California. Unknown dSource Type Control Technology Pollutant controlled Electricity requirement (kW-hr) Steam

requirement (tons steam) Solid waste

produced (tons waste) Wastewater

produced (1000 gallons) LNB (indirect) NO X 157 - 210 a 182 LNB (direct) NO X 210 a 182 Biosolid Injection NO X 262 a NOXOUT NO X 183 CemSTAR NO X 105 - 314 a LoTOx TM NO X 419 - 472 c b b
SCR NO X 419 SNCR (urea) NO X 183 b SNCR (ammonia) NO X 183 b
PM 10 , EC, OC 37 b 1
PM 2.5 15 b 1
PM 10 , EC, OC 36 - 37 b 1
PM 2.5 14 - 15 b 1 NOTES: a - The measure is expected to improve fuel efficiency. Potential emission reduction (1000 tons/year)

blank indicates no impact is expected. b - Some impact is expected but insufficient information is available to evaluate the impact. c - According to the ERG Report (reference 6) "electricity and oxygen costs are reported to be high" although there is no quantification given. Energy and non-air pollution impacts (per ton of emission reduced) Table 4-3. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Selected Cement Manufacturing Operations in Wyoming

Mountain Cement Company Long Dry Kiln #2

Fabric Filter

Dry ESP Additional fuel requirement (%)4

- 8

4

. 5 References for Section 4

1

. WRAP (2008), Emissions Data Management System, Western Regional Air Partnership , Denver, CO, http://www.wrape dms.org/app_main_dashboard.asp

2

. U.S. Environmental Protection Agency (2006), SPECIATE version 4 , U.S

. EPA, RTP, NC ., http://www.epa.gov/ttn/chief/software/speciate/index.html

3 Lake Michigan Air Directors Consortium, Interim White Paper

– Midwest RPO Candidate Control Measures , http://www.ladco.org/reports/control/white_papers/

.
4 EC/R Incorporated (2000), NO X Control Technologies for the Cement Industry , Prepared for OAQPS/OPSP/AQSSD, EPA Contract No , 68

- D98

- 026 , http://www.epa.gov/ttn/naaqs/ozone/rto/fip/data/cement.pdf

.
5 Wyoming De partment of Environmental Quality (2007), WAQSR Chapter 6, Section 3 Operating Permit, Mountain Cement Company, Permit No

. 3

- 1

- 098

- 1 , http://deq.state.wy.us/aqd/TitleVPermitsIssued.asp

.
6 ERG, Inc. (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

. 7 NACAA (formerly STAPPA and ALAPCO) (2006), Controlling Fine Particulate Matter Under the Cle an Air Act: a Menu of Options , Prepared by the State and Territorial Air Pollution Program Administrators and Association of Local Air Pollution Control Officials , www.4cleanair.org/ PM25Menu

- Fin al.pdf

. 8 E.H

. Pechan & Associates (2005), AirControlNET, Version 4.1

- Documentation Report , U.S

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

.
9 Lake Michigan Air Directo rs Consortium (LADCO) (2005), Midwest Regional Planning Organization (RPO) Cement Best Available Retrofit Technology (BART) Engineering Analysis , Prepared by MACTEC Federal Programs/MACTEC Engineering and Consulting, Inc. , http://www.ladco.org/reports/control/bart/cement_plants.pdf

10

. 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

. .4

- 9

11

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

- on
co ntrol measures for NO X , , Wisconsin Department of Natural Resources, April 27.

12 US Environmental Protection Agency/Office of Air Quality Planning and Standards (1994), Alternative Control Techniques Document

- NOX Emissions from Cement Manufacturing , EPA

- 453/R

- 94

- 004, Chapter 7 , http://www.epa.gov/ttn/catc/dir1/cement.pdf

.