# Supplementary Information for Four

- Factor Analyses for Selected Individual Facilities in

South Dakota

May 19
, 2009

Revised Draft Report

Prepared by:
William Battye Janet Hou Brad Nelson
EC/R Incorporated 501 Eastowne Drive, Suite 250 C hapel Hi ll, 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 Regio nal 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 th e 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 Fact or 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. Boilers

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

- 1 3.1 Factor 1

– Costs

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

- 2 3.2 Factor 2

– Time Necessary for Complian ce

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

- 2 3.3 Factor 3

– Energy and Other Impacts

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

- 3 3.4 Factor 4

– Remaining Equipment Life

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

- 4 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

- 6 4.4 Factor 4

– Remaining Equipment Life

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

- 7 4.5 References for Section 4

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

- 9iv Abbreviations BART Best Available Retr ofit Technology CAIR Clean Air Interstate Rule CO 2 Carbon Dioxide EC Elemental Carbon EDMS E missions Data Management System EPA Environmental Protection Agency ESP Electrostatic Precipitator FGD Flue Gas Desulfurization ICAC Institute of Clean Air Companies LNB Low

- NOx Burn ers MW Megawatt NACAA National Association of Clean Air Agencies NEI National Emissions Inventory NO x Nitrogen Oxides OC Organic Carbon OFA Overfire Air PM Partic ulate Matter PM 10 Particulate Matter Particles of 10 Micrometers 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 VOC Volatile Organic Compounds 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 visibilit y 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 agenc ies, 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 fo llows:

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 proje ct 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 p roduce visibility

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

. For direct particulate matter (PM) emissions, we have evaluated the impacts of control measures on various particulate matter componen ts, 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 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 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.”1 2

The current report presents the results of a four

- factor analysis of potential control measures f

or selected emission sources including one electric generating unit and two cement kilns at one cement manufacturing plants in South Dakota

. The emission sources addressed in this current repo rt were selected by th e South Dakota Department of Environment and Natural Resources

. Section 2 presents the methodology employed for the analyses, Section 3 presents the results of the four

- factor analysis for boilers and Section 4 presents the results for cement kilns

.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

.2

- 1 

## 3

. Boilers

A four

- factor analysis was performed on a single coal

- fired boiler at Black Hill Power and Light Company

– Ben French Station . Th i s boiler is used to produce steam from the combustion of sub

- bituminous coal to generate electricity in a steam turbine

. The unit at BEN French Station is rate d at 25 megawatts (MW). Pollutant emissions from the boilers include: nitrogen oxides (NO X ), sulfur dioxide (SO 2 ), and particulate matter (PM).

Table 2

- 1 s ummarizes the N O X and SO 2 emi ssions from the boiler, as well as the control measures used to reduce these pollutant emissions. 1 The pollutant emission rates shown in Table 2

- 1 were obtained from the WRAP 2002 emission inventory. 2 Emissions of EC and OC can be estimated using speciation factor 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, the boiler at the Ben French Station is uncontrolled. T he facility does utilize a low sulfur coal (0.33 wt %) to minimize the formation of SO2 during the combustion process. A list of p otential NO X and SO 2 control strategies are presented in Table 2

- 2

. The table provides a range of pollutant reductions and p resents the potential emission reductions from the baseline emissions by applying the listed control options. 4,5 These control options have been applied to many electrical generating unit boilers in the U.S. to reduce emissions of NO X and SO 2 .2

- 2

3 .1 Factor 1

– Costs

Table 2

- 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 t o install the necessary equipment, and the total annual cost of control, including the amortized cost associated with the capital equipment cost. The capital cost values are expressed in terms of the cost per MW size of the boiler using EPA cost informati on

. 6,7 The capital cost data was extrapolated 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 2

- 3 also estimates the cost effectiveness for each control measure, in terms of the cost per ton of emission reduction. Recent literature 8 has indicated that the cost of SCR for electric generating can vary from $120 to $170 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 strateg y , up to 2 years will be needed to dev elop 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 , and approximately 30 months to design, build, and install SO 2 scrubbing technology

. 9 Addit ional time of up to 12 months may be required for staging the install ation process if multiple boilers a re to be controlled at a single facility. Based on these figures, the total time required to achieve emission reductions for industrial boilers is estimated at a total of 51⁄2 years for NO X strategies, and 61⁄2 years for SO 2 strategies

.2

- 3

3

. 3 Factor 3

– Energy and Other Impacts

Table 2

- 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 performance impacts of each of the control technology options

. 10 ,11 In general, the combustion modification technologies (LNB, OFA) do not require steam or generate solid waste, or wastewater. They also do not require additional fuel to operate, and in some cases may decrease fuel usage because of the optimized combustion of the fuel.
Retrofitting of a SNCR require s energy for compressor power and steam for mixing. This would produce a small increase in CO 2 emissions to generate electricity; however the technology itself does not produce additional CO 2 emissions.

Installation of SCR on an industrial boiler is not expected to increase fuel consumption

. However additional energy is required to operate the SCR, which will produce an increase in CO 2 emissions to generate the elect ricity. 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 catalyst material.
Retrofitting of the SO 2 control options increase the usage of electricity, and produce both a solid waste and wastewater stream. In addition, increases of CO 2 emission s will occur due to the increased energy usage for material preparation (e.g., grinding), materials handling (e.g., pumps/blowers), flue gas pressure loss, and steam requirements. Power consumption is also affected by the reagent utilization of the control technology, which also affects the control efficiency of the control technology.2

- 4

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 technologies will not be applied to units that are expected to be retired prior to the amortization period for the specific control equipment. Therefore, the remaining life of an industrial boiler is not expected to affect the cost of control technologies for industrial boilers.2

- 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

. EPA (2006), SPECIATE version 4 , U.S. EPA, RTP, NC. http://www.epa.gov/ttn/chief/software/speciate/index.html

4. MRPO (2006), Interim White Paper

- Midwest RPO Candidate Contro l Measures Source Category: Industrial, Commercial, and Institutional (ICI) Boilers

. http://www.ladco.org/reports/control/white_papers/

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

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

.
7

. Khan, Sikan der (2003), Methodology, Assumptions, and References: Preliminary SO2 Controls Cost Estimates for Industrial Boilers

.
8. Power Magazine (2006), Estimating SCR Installation Costs

. http://www.powermag.com/instrumentation_and_controls/Estimating

- SCR

- installation

costs_506_p3.html

9

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

.
10. Reference 6.

11. Reference 7.4

- 1 

## 4

. Cement Manufacturing

Four

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

. The following facility and emission sources have been evaluated:

 GCC Dacotah, Rapid City Plant

– Cement Kiln s # 4 and # 5

Table 3

- 1 outlines the baseline levels of emissions and potential additional control measures that could be adopted to further reduce emissions

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

Baseline emissions of NO X and SO 2 for the refineries were obtained from the WRAP 2002 emissions inventory. 1 Emissions of PM 2.5 and PM 10 were obtained from the 2002 U.S

. EPA NEI and from the st ate of South Dakota

. 2 Emissions of EC and OC were estimated using speciation factors from EPA’s SPECIATE database. 3 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 cement kilns include coal, natural gas, and waste

- derived fuels (primarily scrap tires , but also motor oils, surplus printing inks, and sludge from the petroleum industry). 4
Wet, long dry, and most preheater kilns have one fuel combustion zone; newer preheater/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 influences the amount of heat input required to produce cement. 5 SO 2 emissions are cr eated from sulfur compounds in the raw materials used (i.e., limestone, clay, sand and iron ore) and to a smaller extent in the fuel. 4 PM emissions are also generated by cement kilns.Company Source Pollutant Baseline emissions (tons/yr) Existing Control

Technology Potential Control

Technology Estimated

control efficiency (%) Potential

emission reduction (tons/year) References LNB (indirect) 30-40 212 - 283 5,11,15,19 LNB (direct) 40 283 5,11,15,19 Biosolid Injection 23 163 5,11,15,19 CemSTAR 20-60 14 - 424 5,11,15,19 Mid-Kiln 20-50 14 - 353 5,11,15,19 SCR 80 565 10,11,14,15 SO 2 26 None Wet FGD 90-99 24 - 26 10,11,14,15
PM 10 136 Dry ESP Fabric Filter 99 134 10,11,14,15
PM 2.5 67 Dry ESP Fabric Filter 99 67 10,11,14,15
EC 10 Dry ESP Fabric Filter 99 9.38 10,11,14,15 OC 2 Dry ESP Fabric Filter 99 1.876 10,11,14,15 LNB (indirect) 30-40 116 - 155 5,11,15,19 LNB (direct) 40 155 5,11,15,19 Biosolid Injection 23 89 5,11,15,19 CemSTAR 20-60 78 - 233 5,11,15,19 Mid-Kiln 20-50 78 - 194 5,11,15,19 SCR 80 310 10,11,14,15 SO 2 431 None Wet FGD 90-99 388 - 427 10,11,14,15
PM 10 , PM 2.5 , EC, OC 45 Dry ESP Fabric Filter 82 37 2, 10,11,14,15 NO X None

None Table 4-1. Existing Control Measures and Potential Additional Control Options for Selected Cement Manufacturing Operations

Long Wet Kiln # 4

Long Wet Kiln # 5 NO X 707

388 GCC Dacotah, Rapid City Plant4

- 3

The GCC Dacotah Rapid City Plant cement kilns analyzed in this report are all long wet kilns

. K ilns #4 and #5 have capacities of 550 tons of clinker per day each; assuming the kilns run 365 days of the year the result is 200,750 tons of clinker per year (tpy) per kiln

. NO X and SO 2 emissions from the Kiln #4 are 707 tpy and 27 tpy , respectively

. NO X and SO 2 emissions from the Kiln #5 are 388 tpy and 431 tpy , respectively

. 1
Combustion control options for NO X include:  Direct and indirect

- fired low NO X burners,  The CemStar process, and  Mid

- kiln firing

.
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 for conveying the pulverized c oa l from the coal mill to the kiln). Indirect

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

- or indirect

- fired kilns. Low NO X burners reduce flame turbulence, delay fuel/air mixing, and establish fuel

- rich zones for initial combustion, thus reducing thermal NO X formation. 5 The CemStar process adds a small amount of steel slag to the raw kiln feed and lower the temperature required to operate the kiln

. M id

- kiln firing uses an additional feed injection mechanism and injects solid fuel into the calc ining zone of a rotating kiln, thus lowering the temperature to produce clinker

.
NO X removal control options include:  Biosolid injection,  LoTOx TM  SCR
,  SNCR , and  NO X OUT
Biosolid injectio n 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 into 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 group and is currently being used on the Midlothian cement wet kilns in Texas. 6 , 15 Both CemStar and biosolid injection are most feasible when there are nearby sources of steel slag or biowaste, respectively, that the cement plant can easily procure without incurring large transportation costs.
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

. The catalytic react ions can take place only in certain temperature ranges which are often higher than typical cement kiln flue gas temperatures. Process reconfigurations , such as an automatically activated bypass duct place d around the SCR reactor to control temperature fluc tuations or installing equipment to maintain the desired temperature, can successfully deal4

- 4

with temperature issues. 6 Due to potential fouling problems of the catalyst the SCR system must be installed after th e particulate collection device.

SNCR also reduces NO X formation by ammonia or urea but does not use 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 optimall y 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 and as such SNCR is not applicable to long wet and dry kills.

NO X OUT is similar to the SNCR process and uses urea to complete the chemical conversion of NO to nit rate 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. 5

The clinker production process controls SO 2 to a significant degree. 7 , 8 The interior of the kiln is highly alkaline absorbs up to 95 percent of the SO 2 emissions generated, although this can vary depending on the kiln feed. 9 The option to control SO 2 is limited to flue gas desulfurization (FGD). 10 Flu e gas is the primary source of SO 2 and volatile organic carbons ( VOCs )

– the fuel and raw materials dictate the amount of SO 2 emissions generated

. Wet scrubbers have 80

- 99 percent control efficiency, although the generation of sludge and particulate build

- up necessitates the FGD be installed downstream of a fabric filter. 11
, 12 13 PM emissions are often controlled by fabric filters or wet or dry Electrostatic Precipitators (ESP s ). 14
, 15 Kilns #4 and #5 at the GCC facility already have dry ESPs installed and thus only fabric filters are analyz ed for further PM control.

4 .1 Factor 1

– Costs

Table 4

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

. For each option, the table gives an estimate of the capital cost to install the necessary equipment (including any req uired instrumentation and equipment and all piping and ductwork) , 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 South Dakota , up to 2 years will be needed for the state to develop t he necessary rules to implement the strategy

. We have estimated that sources may then require up to a year to procure the necessary capital to purchaseCompany Source Control option Pollutant Estimated control efficiency (%) Potential

emission reduction (tons/year) Estimated capital

cost ($1000) Estimated annual

cost ($1000/year) Cost

effectiveness ($/ton) Refer-ences LNB (indirect) NO X 30-40 212 - 283 526 129 3,092 - 1,859 5,14,15 LNB (direct) NO X 40 283 1,873 331 7,788 5,14,15 Biosolid Injection NO X 23 163

- - 421.41 5,14,15
CemSTAR NO X 20-60 14 - 424 1,599 299 4,476 - 13,459 5,14,15
Mid-Kiln NO X 20-50 14 - 353 2,758 -315 6,922 - 17,328 5,14,15
LoTOx TM NO X 80-90 565 - 636 3155 - 3891 6,15

SCR NO X 80 565 14,813 4,137 34 5,14,15
Wet FGD SO 2 90-99 24 - 26 9,133 1,370 403,942 - 437,604 10,11,15

Fabric Filter PM 10 , EC, OC 99 134 1,357 1,148 18,699 10,11,15

Fabric Filter PM 2.5 99 67 1,235 1,045 37,399 10,11,15 LNB (indirect) NO X 30-40 116 - 155 526 129 4,229 - 5,651 5,14,15 LNB (direct) NO X 40 155 1,873 331 14220 5,14,15 Biosolid Injection NO X 23 89

- - 0 5,14,15
CemSTAR NO X 20-60 78 - 233 1,599 299 8,144 - 24,330 5,14,15
LoTOx TM NO X 80-90 310 - 349 3155 - 3891 6,15
Mid-Kiln NO X 20-50 78 - 194 2,758 -315 12,594 - 31,324 5,14,15
SCR NO X 80 310 14,813 4,137 61 5,14,15
Wet FGD SO 2 90-99 388 - 427 9,133 1,370 27,068 10,11,15

Fabric Filter PM 10 , PM 2.5 ,

EC, OC 82 37 1,235 1,045 110,421 2,10,11,15

a 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).

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

Long Wet Kiln # 4

Long Wet Kiln # 5 GCC Dacotah, Rapid City Plant

Unknown a

Unknown a4

- 6

control equipment

. The ICAC has estimated that approximately 13 mon ths is required to design, fabricate, and install SCR or SNCR technology for NO X control. 16 However, state regulators’ experience indicates that closer to 18 months is required to install this technology. 17 In the Clean Air Interstate Rule ( CAIR ) analysis, EPA estimated that approxim ately 30 months is required to design, build, and install SO 2 scrubbing technology for a single emission source

. 18 The analysis also estimated that up to an additional 12 months may be required for staging the installation process if multiple sources are t o be controlled at a single facility

. Based on these figures, the total time required to achieve emission reductions for the cement kilns 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.

4 .3 Factor 3

– Energy and Other Impacts

Table 4

- 3 shows the estimated energy and non

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

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

. CO 2 emissions associated with the generation of the additional electricity and steam are also estimated in the table

.
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 fro m 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 k iln flue gas temperatures
, although it may be possible to use heat recovery systems to reheat and achieve the required temperature

. 5 However, it is possible to use heat recovery systems to reheat the exhaust a nd avoid generating 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 goa l

. 5 SCR systems would produce additional solid waste because of spent catalyst disposal

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

. The presence of catalyst fines in the dust may require treatment as a hazardous waste. 194

- 7

4

. 4 Factor 4

– Remaining Equipment Life

Information was not available on the age of the cement kilns

. However, indust rial processes often refurbish cement kilns to extend their lifetimes

. Ther efore, 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 lif etime 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 capita l 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 ($) A 0 = the origin al annual cost estimate ($) 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 equipmentSource Type Control Technology Pollutant controlled Electricityrequirement (kWhr) Steam requirement

(tons steam) Solid waste

produced (tons waste) Wastewater

produced (1000 gallons) Additional CO 2

emitted (tons) LNB (indirect) NO X 212 - 283 a 182 LNB (direct) NO X 283 a 182 Biosolid Injection NO X 163 a
NOXOUT NO X 247 b

CemSTAR NO X 14 - 424 a
Mid-Kiln NO X 14 - 353 a
LoTOx TM NO X 565 - 636 c b b c SCR NO X 565 9.8 57 b
Wet FGD SO 2 24 - 26 1,100 3 3 3.7 2.6 Fabric Filter PM 10 , EC, OC 134 b 1
Fabric Filter PM 2.5 67 b 1 Dry ESP PM 10 , EC, OC 44 b 1 Dry ESP PM 2.5 21 b 1 LNB (indirect) NO X 116 - 155 a LNB (direct) NO X 155 a Biosolid Injection NO X 89 a
NOXOUT NO X 136 b

CemSTAR NO X 78 - 233 a
Mid-Kiln NO X 78 - 194 a
LoTOx TM NO X 310 - 349 c b b c
SCR NO X 310 9.8 57 b
Wet FGD SO 2 388 - 427 1,100 3 3 3.7 2.6 Fabric Filter PM 10 , EC, OC 45 b 1 b
Fabric Filter PM 2.5 22 b 1 Dry ESP PM 10 , EC, OC 45.17 a b 1 Dry ESP PM 2.5 22.34214973 0.5 b 1 0.0
NOTES: GCC Dacotah, Rapid City Plant

Table 4-3. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Selected Cement Manufacturing Operations in South Dakota

Additional fuel requirement (%)

a - The measure is expected to improve fuel efficiency. Potential emission reduction ( tons/year)

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

blank indicates no impact is expected. Energy and non-air pollution impacts (per ton of emission reduced)

Long Wet Kiln # 4

Long Wet Kiln # 5

c - According to the ERG Report (reference 5) "electricity and oxygen costs are reported to be high" although there is no quantification given.4

- 9

4 .5 References for Section 4

1

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

2 Boddicker, Ric k (2009)
, Personal Communication
, Potential Reduction of Part i culate Matter by Dry ESP , South Dakota Department of Environment & Natural Resources, May 5.

3

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

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

4 Lake Michigan Air Directors Consortium, Interim White Paper

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

.
5 EC/R Incorporated (2000), NO X C ontrol 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

.
6 ERG, Inc. (2 005), Assessment of NOX Emissions Reduction Strategies for Cement Kilns

- Ellis County , Chapter 4 , TCEQ Contract No. 582

- 04

- 65589, Work Order No. 05

- 06, http://www.tceq.state.tx.us/assets/public/implementation/air/sip/agreements/BSA/CEME NT_FINAL_REPORT_70514_final.pdf

. 7 Davis, W

. (2000) Air Pollution Engineering Manual: Second Edition , Air & Waste Management Association.

8 Sumter Cement Company (2005), Application to Construct New Portland Cement Plant, NSR/PSD Construction Permit for Center Hill Plant , submitted to Florida Department of Environmental Protection, www.dep.state.fl.us/Air/permitting/construction/sumter/APPLICATION.zip

9 U.S

. Environmental Protection Agency (1995), Chapter 11: Mineral Products Industry: Portland Cement Manufacturing” in AP 42, Fifth Edition, Volum e I, http://www.epa.gov/ttn/chief/ap42/ch11/final/cs11s06.pdf

.
10 U.S

. Department of Energy, National Energy Technology Laboratory (2001), Cement Kiln Flue Gas Recovery Scrubber Pro ject: A DOE Assessment , DOE/NETL

- 2002/1163
, http://www.epa.gov/ttn/chief/ap42/ch11/final/cs11s06.pdf

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

.4

- 10

12 Miller, F.M., G.L. Young, M. von Seebach (200 1), Formation and Techniques for Control of Sulfur Dioxide4 and Other Sulfur Compounds in Portland Cement Kiln Syste ms , Portland Cement Association, PCA R&D Serial No. 2460, pp. 37

- 48.

13 NESCAUM (2005), Assessment of C o ntrol Technology Options for BART

- Eligible Sources : Steam Electric Boilers, Industrial Boilers, Cement Plants and Paper and Pulp Facilities
, U.S. EPA Grant XA

- 983799

- 01

- 2 , pp. 59

- 78, http://www.nescaum.org/documents/bart

- control

- assessment.pdf/

14 E.H

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

- Documentation Report , U.S

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

15 NACCA (formerly STAPPA and 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 and Association of Local Air Pollution Co ntrol Officials
, www.4cleanair.org/ PM25Menu

- Final.pdf

.
16

. Institute of Clean Air Companies (2006), Typical Installation Timelines for NOX Emissions Control Technologies on Industrial Sources

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

.
17

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

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

18

. EPA (2005), Boilermaker Labor Analysis and Installation Timing

– Technical Support Document for the Final Clean Air Interstate Rule

. OAR

- 2003

- 0053, U.S

. EPA, W ashington, DC

. www.epa.gov/cair/technical.html#final

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

- NO X Emi ssions from Cement Manufacturing , EPA

- 453/R

- 94

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

.