WPC1 2iBVY`Z#|2olbook&)o=3Uo P['C&P"m^%,==\^%%7C%C==========CCC1RMOOVOIV\-CRIhZVIVRIKZMfMKI%C%C7?=1C1%;C%#=%bC7?=11'C9V773%C%C%%%n%%%%%%%%%%=%M?M?M?M?M?`OO1O1O1O1O1-%-%-%-%ZCV7V7V7V7ZCZCZCZCK7M?V7V7K7V7I?M?M?M?O1O1O1O1VCO1O1O1O1V;V;V;V;V;V;\C-%-%-%-%CR=I%I%I%I%ZCZCZCZCV7V7lVR1R1R1I1I1I1I1K'K'ZCZCZCZCZCZCfVK7I3I3I3VCI%ZCR1I1K'K7K7VCV7ZCNCH7%1//===.)\\=%RR=\%++7n%%77iCCn+n%CC<'#|M2P2CP#NOTES:#|M2P3CP#8EHPA-Changes type to Helv. Bold 10 pt. *?@*#J2PQQP# #J2PRQP# 7EHPA-Changes font to Helv. Bold 12!*AB*#:s2PSCXP# #:s2PTCXP# 2&""##$S$%%6EHPA-Suppresses headers/footers & changes font":CD'#:x2UCX#   #:x2VCX#Table Title EHPA-Suppresses headers/footers & changes font#:EF'#:x2WCX#   #:x2XCX#FootnoteFootnote for reports (schoolbook)$GH (08@HPX!"#e P[YCP#Helv. Bold 1EHPA-Changes font to Helv. Bold 12%*IJ*#:s2PZCXP# #:s2P[CXP# 2X)&r&'.'(')(BulletEHPA-Bullet (Schoolbook)&KL"Table TextEHPA-Formats text in Pechan tables''M'N#`2P\CP##o P[]C&P#SourceEHPA-Sources for tables(9OP'#|M2P^CP#SOURCE:#|M2P_CP#4th tier (i)EHPA-Heading for 4th-tier section)BQ R'#:x2`CX# #:x2aCX#20*)+sl+,]+-<-ChapterheadEHPA-Chapter title*ST1yxdddy #2bC # yxdddy #2cC #Bullet ListEHPA-Indented Bullet List+UV ResumeEHPA-Pechan staff resume format 09/03/91,WX#a\  PdC P#P 0 pP0LetterEHPA-Pechan letterhead letter-pYZ#PeX#  #o P[fC&P#  @Page @  X`hp x  p#o P[gC&P#     3 1, 4 2X4.60/2021u3Appendix CovEHPA-Formats text for appendix cover sheet.[\1yxdddy #2hC # yxdddy#2iC #NoteEHPA-For single note below table/7]^'#|M2PjCP#NOTE:#|M2PkCP#SourcesEHPA-Formats references at bottom of table0=_`*#|M2PlCP# SOURCES:   #|M2PmCP# ReferencesEHPA-Pechan references1Sab1#o P[nC&P#  #o P[oC&P#2;2n434455`6BibliogrphyBibliography2cd 5th tierHeading for 5th level30ef'#vz  pC&# " #vz  qC&#Run-InRun-In Heading40gh'#PDurQ#. 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P( 71st tier (A)#:x2C!X#A.`COST ESTIMATES FOR RETROFIT CONTROL TECHNOLOGIES##81st tier (A)#(#  J #o P['CU&P#Retrofit control options by source category (scc_id) are listed in Table 2. This table  J lists the source category (scc_id and description), the applicable SO2 control technology, and the expected control efficiency. These are the control techniques for which control cost information is to be included in the IAS. !Flue gas desulfurization (FGD!) is a control option for most of the source categories  J ! that were evaluated. The use of FGD scrubbers for controlling SO2 emissions has been applied to utility and industrial boilers for 25 years, and is now considered a mature  J" technology that can be designed for controlling SO2 emissions from most industrial sources. FGD scrubbers can be either wet or dry systems. In wet systems, a liquid sorbent is sprayed into the flue gas in an absorber vessel. Limestone and limebased reagents are most frequently used in scrubbers in the United States. DryFGD systems include spray dryers, circulating dry scrubbers, and dry injection (ICAC, 1995). Costs for FGD scrubbers were developed using the 1990 Grand Canyon emission inventory and a computer spreadsheet model provided by the !U.S. Environmental Protection Agency (EPA!). The model is based on a wet FGD system and was developedz) ,**  P #o P[CU&P#  #o P[CU&P# 3'3'Standard'3'3StandardHPLAIIPO.PRSo߰X : P #o P[CU&P##o P[CU&P# (08@ (08@#o P[CU&P# (08@ (08@ (08@ (08@ (08@ (08@#:x2C!X#({Table 1 (continued) :r#o P[CU&P##o P[CU&P# (08@ (08@#o P[CU&P# (08@ (08@ (08@ (08@ (08@ (08@ U 1  1 ! xXX)cx#o P[CU&P# (08@ (08@ (08@ (08@ (08@ (08@ (08@ (08@<Mr9Table Titlej#:x2C!X# Table 1 r@Other Point Source Category Groupings"7:Table Title"   ;#o P['CU&P# #|M2P#CdP# c ddx !dd< ;+y c  N M IAS wScc_id0 Source ,PClassification 1Z Code Source Category/Process f@ 1990 SO2 Emissions b(tpy)!Number of M!Emission o!Sources) )  f@+ <'Controls Applicable N f@  Sulfuric Acid Plants t23,913"10Increase Acid Conversion Rate or FGD$$?ptsap1uc/30102301Contact Absorber (99.9% Conversion) ԃ:#ԃ?ptsap2uc/30102306Contact Absorber (99% Conversion) ԃ:#ԃ?ptsap3ucy /30102308y Contact Absorber (98% Conversion)y  ԃy :#ԃy ?ptsap4uc[ /30102310[ Contact Absorber (97% Conversion)[  ԃ[ :#ԃ[ y ?ptsap5ucM /30102318M Contact Absorber (93% Conversion)M  ԃM :#ԃM [  f@  Sulfur Recovery Plants / / 4,336/ "8/ Increase Acid Conversion Rate or FGDM Bptesc1uc /30103201 Elemental Sulfur Production (Claus: 2 Stage w/o Control (92-95% Removal))    #ԃ / Bptesc2uc/30103202Elemental Sulfur Production (Claus: 3 Stage w/o Control (95-96% Removal))? ? #ԃ? Bptesc3uc!/30103203!Elemental Sulfur Production (Claus: 3 Stage w/o Control (96-97% Removal))  #ԃ?;ptsrmpuc/30103204Sulfur Removal Process (99.9% Removal) ԃ:#ԃBptesncuc/30103299Elemental Sulfur Production (Not Classified) ԃ:#ԃ f@  Inorganic Chemical Manufacture } ԃ}:#ԃ}Bptincmuc_/30199999_Elemental Phosphorous (Stack Emissions)_7,543_"1_FGD}Q/30100509QCarbon Black Production (Furnace Process: Fugitive Emissions)Q1,606Q"1QCapture Hood + FGD_ f@  Coke Oven Plants 339,0433"23Vacuum CarbonateQBptcokenc/30300315By-product Coke Manufacturing (Gas By-product Plant) ԃ:#ԃ3/30300401Coke Manufacture: Beehive Process ԃ:#ԃ f@C  Process Heaters 6,909"15FGD]ptprhtuc/31000402Residual Oil ԃ:#ԃ/31000403Crude Oil ԃ:#ԃ/31000404Natural Gas ԃ:#ԃq/31000405qProcess Gasq ԃq:#ԃqS/31000412SResidual Oil: Steam GeneratorsS ԃS:#ԃSqE/31000413ECrude Oil: Steam GeneratorsE ԃE:#ԃE  00PPS f@<  Industrial, Commercial, & Institutional Boilers 7,482"25FGDkpticibuc/10200217Atmospheric Fluidized Bed Combustion: Bubbling Bed (Bituminous Coal)j j #ԃjL/10200224LSpreader Stoker (Subbituminous Coal)L ԃL:#ԃLj./10200225.Traveling Grate (Overfeed) Stoker (Subbituminous Coal). .:#ԃ.L/10200229Cogeneration (Subbituminous Coal) ԃ:#ԃ./10200303Cyclone Furnace (Lignite Coal) ԃ:#ԃ/1020040210-100 Million !British thermal units (Btu!)/hour (Residual Oil)  ԃ:#ԃ/10200403< 10 Million Btu/hour (Residual Oil)  ԃ:#ԃ/10200404Grade 5 Residual Oil ԃ:#ԃz /10200502z 10-100 Million Btu/hour (Distillate Oil)z  ԃz :#ԃz \ /10201402\ !Carbon Monoxide (CO!) Boiler (Process Gas)\  ԃ\ :#ԃ\ z > /10300206> Pulverized Coal: Dry Bottom (Bituminous Coal)>  ԃ> :#ԃ> \  /10300207 Bituminous Coal/Overfeed Stoker  ԃ :#ԃ >  /10300209 Spreader Stoker (Bituminous Coal)  ԃ :#ԃ   /10300401 Grade 6 Oil (Residual Oil)   ԃ :#ԃ  /1030060210-100 Million Btu/hour (Natural Gas) ԃ:#ԃ  f@  Primary Metal Production 4,114"7FGD;ptpmtpuc/30300901Steel Manufacturing (Open Hearth Furnace (Stack)) ԃ:#ԃ|/30300908|Steel Manufacturing (Electric Arc Furnace: Carbon Steel (Stack))| | #ԃ|^/30301101^Molybdenum (Mining: General)^ ԃ^:#ԃ^|@/30301199@Molybdenum (Other Not Classified)@ ԃ@:#ԃ@^"/30301201"Titanium (Chlorination)" ԃ":#ԃ"@/30399999 Aluminum Ore (Electro-reduction): Prebaked Reduction Cell3,333"1Capture Hood with gas stream sent to FGD" f@P  Secondary Metal Production -600"1FGD?ptsmtpuc/30499999Other Not Classified ԃ:#ԃ2   f@<  Nonmetallic Minerals Processing t16,302"32FGDptnmmpuc/30500606Cement Manufacturing: Kilns (Dry Process) ԃ:#ԃ/30500612Cement Manufacturing: Raw Material Transfer (Dry Process) :#ԃ/30500622Cement Manufacturing: Preheater Kilns (Dry Process) ԃ:#ԃj/30500706jCement Manufacturing: Kilns (Wet Process)j ԃj:#ԃjL/30500801LCeramic Clay/Tile Manufacture (Drying)L ԃL:#ԃLj./30501037.Coal Mining, Cleaning, and Material Handling (Truck Loading: Overburden)  #ԃL/30501401Glass Manufacture (Furnace/General) ԃ:#ԃ/30501402Glass Manufacture (Container Glass: Melting Furnace) ԃ:#ԃz /30501403z Glass Manufacture (Flat Glass: Melting Furnace)z  ԃz :#ԃz \ /30501410\ Glass Manufacture (Raw Material Handling (All Types of Glass))\ \ #ԃ\ z > /30501602> Lime Manufacture (Secondary Crushing/Screening)>  ԃ> :#ԃ> \  /30501604 Lime Manufacture (Calcining: Rotary Kiln)  ԃ :#ԃ >  /30501905 Phosphate Rock (Calcining)  ԃ :#ԃ   /30502201 Potash Production (Mine: Grinding/Drying)  ԃ :#ԃ  /30502509Construction Sand and Gravel (Cooler) ԃ:#ԃ /30599999Cement Plant (Other Not Defined) ԃ:#ԃ f@  Sulfate (Kraft) Pulping 4,602"8FGDsptkrftuc|/30700104|Recovery Furnace/Direct Contact Evaporator| ԃ|:#ԃ|n/30700106nLime Kilnn ԃn:#ԃn| f@  Refinery Sources PP2,651P"7PFGDnlptrfnruc2/306001012Process Heaters (Oil-Fired)2 ԃ2:#ԃ2P/30600105Process Heaters (Natural Gas-Fired) ԃ:#ԃ2/30600301Thermal Catalytic Cracking Units ԃ:#ԃ/30600402Blowdown Systems (Without Controls) ԃ:#ԃ/30600903Flares (Natural Gas) ԃ:#ԃ/30601401Petroleum Coke Calciner ԃ:#ԃ/30609904Incinerators (Process Gas) ԃ:#ԃ f@  Totals for All Source Categories t93,969\"119ON     P  '3'3StandardHPLAIIPO.PRSo3'3'StandardHPLAIIPO.PRSo(߰X #o P['CU&P#  9Table Titlec#:x2C!X# Table 2 ZhRetrofit Control Options":Table Title"  f -#o P['CU&P# #|M2PkCdP# h !dd< ;+y  AyddT D@" TDh f"$ $ !Lscc_idR R MDescriptionControl WTechnology ^Description f@ Expected SO2 RControl  f@C Efficiency (%) f" ptsap1uc Sulfuric Acid Plants Contact Absorber (99.9% Conversion)?FGDD90" ptsap2uc Sulfuric Acid Plants Contact Absorber (99% Conversion)Dual adsorption Dual adsorption + FGDD90 99" ptsap3uc Sulfuric Acid Plants Contact Absorber (98% Conversion) Dual adsorption Dual adsorption + FGD3 D95 99.5" ptsap4uc- Sulfuric Acid Plants Contact Absorber (97% Conversion)- Dual adsorption Dual adsorption + FGD D96.7 99.673 " ptsap5uc Sulfuric Acid Plants Contact Absorber (93% Conversion) Dual adsorption Dual adsorption + FGDs D98.6 99.86 " ptesc1ucm Sulfur Recovery Plants Elemental Sulfur (Claus: 2 Stage)mAmine scrubbing Amine scrubbing + FGDD98.4 99.84s " ptesc2uc  Sulfur Recovery Plants Elemental Sulfur (Claus: 3 Stage) Amine scrubbing Amine scrubbing + FGDD97.8 99.78" ptesc3uc Sulfur Recovery Plants Elemental Sulfur (Claus: 3 Stage)Amine scrubbing Amine scrubbing + FGDSD97.1 99.71" ptsrmpucM Sulfur Recovery Plants Sulfur Removal ProcessM?FGDMD90S" ptesncucG Sulfur Recovery Plants Elemental Sulfur Production n.c.G?FGD GD90M" ptincmucA Inorganic Chemical ManufactureA?FGDAD90G" ptcokeuc; Coke Oven Plants;Vacuum carbonate;D82A" +ptprhtuc5 Process Heaters (Oil and Gas Production Industry)5?FGD5D90;" 9pticibuc/ !Industrial, Commercial, and Institutional (ICI!) Boilers/?FGD/D905" ptpmtpuc) Primary Metal Production)?FGD)D90/" ptsmtpuc# Secondary Metal Production#?FGD#D90)" ptnmmpuc Nonmetallic Minerals Processing?FGDD90#" Aptkrftuc Sulfate (Kraft) Pulping?FGDD90 " :ptrfnruc! Refinery Sources!?FGD!D90 #o P[&CU&P#! ,**  J   from data presented in a report that analyzed the impacts of SO2 controls on the electric power generation sector (EPA, 1996). To develop a method for estimating costs for emission sources in the 1990 emission inventory, the spreadsheet model was used to develop capital and operating cost components using the stack gas flow rate and stack gas temperature for emission points in the 1990 emission inventory as the independent variable. The following describes the spreadsheet model and then describes the equations used to estimate costs for emission sources. In this report, all costs are expressed in 1990 dollars unless otherwise indicated. Capital costs were updated from these base years by means of the Chemical Engineering Cost Index. Operating costs were updated using the Producer Price Index.  P ;2nd tier (1)#:x2'C!X#1.&FGD Scrubber Spreadsheet Cost Model#X<2nd tier (1)#(#  J #o P['CU&P#Table 3 presents an illustration of the spreadsheet model. The key input parameters used as variables in the model include stack gas flow rate and temperature entering the  J scrubber, and annual operating time. SO2 emission reductions are estimated as 95percent of the uncontrolled emissions reported for each emission source (EPA, 1996). The inputs for capital, fixed !operation and maintenance (O&M!), and variable O&M costs are used as constants in the model. These constants are based on data for FGD scrubber cost assumptions for utility boilers with a 3percent coal sulfur content (EPA, 1996). The assumptions apply to capacities at or above 500 !megawatts (MW!) [approximately 1,000,000 !actual cubic feet per minute (acfm!)]. For smaller sizes, the costs are scaled down using the standard 0.6power law. Thus, at lower capacities, capital costs [in !dollars per kilowatt ($/kW!) or $/acfm] are proportionately higher. In the spreadsheet model, costs are scaled down using the 0.6 power law if the gas flow rate is less than 1,028,000 acfm. A gas flow rate factor of 0.486 is used to convert costs from $/kW to $/acfm. This factor was derived from data in the Integrated Air Pollution Control System (IAPCS) model (version 5). For existing emission sources, a retrofit factor of 1.1 is applied to the capital costs. The FGD scrubber cost assumptions are in 1995 dollars. Capital and annual costs are deescalated to 1990 dollars using the ratio of Chemical Engineering Annual Plant Cost Indexes for 1990 and 1995.  P ;2nd tier (1)#:x2'C!X#2.&Sulfuric Acid Plants#ܤ<2nd tier (1)#(#  J #o P['CU&P#Technology for SO2 emissions control from sulfuric acid plants is well established. The dual absorption process is operating successfully at many U.S. facilities. In addition, several desulfurization processes apply to tail gases from a sulfuric acid plant. Using a  J,! dual absorption process, a plant can convert 99.7 to 99.8 percent of the SO2 produced to  J" !sulfur trioxide (SO3!). The dual absorption process has proved to be the SO2 control system of choice for the sulfuric acid industry since the promulgation of the New Source Performance Standards (NSPS). $,**  P 9Table Titlec#:x2C!X# Table 3 M Illustration of FGD Scrubber Cost Spreadsheet Model":Table Title"  f -#o P['CU&P# #V2P1C P# Y AyddT D@" TD a0"PY   sD  Model Inputs  qF ԩ Gas flow rate at FGD scrubber inlet [!standard cubic feet per minute (scfm!)] 1;500,000Variable qF ԩ Gas temperature at FGD scrubber inlet ($F) 1h^400hVariable qF ԩ SO2 concentration at FGD scrubber inlet (vol. %)O1.0OVariableh qF ԩ Capital cost (1995 $/kW) 26^1926ConstantO qFf ԩ Fixed O&M cost (1995 $/kWyear) 2 6.9 Constant6 qFM ԩ Variable O&M cost (1995 $/kWh) 2 0.0015 Constant  qF4 ԩ Flow Rate factor (kW/acfm) 3 0.486 Constant  qF ԩ FGD scrubber operating time (hour/year) 1 8,736 Variable  qF ԩ FGD scrubber control efficiency (%) 2 90 Constant ܩ FGD scrubber useful life (year) 15 Constant ܩ Interest (discount) rate (fraction)40.07Constant  qF ԩ Retrofit factor 2n41.10nConstant qF ԩ Deescalation factor 4e0.9383eConstantnLWL#eS sD 3 Model OutputsS# Lܩ Gas flow rate at FGD inlet (acfm):;811,321:#S qFj ԩ SO2 inlet rate (tons/year)!;124,063!#: qFQ ԩ Capital cost (1995 $/acfm) 5107.6#!ܩ Fixed O&M cost (1995 $/acfmyear)43.35#ܩ Variable O&M cost (1995 $/acfmhour)0.000729# qF ԩ Capital costretrofit (1995 $) 6k96,028,000# qF ԩ Capital costretrofit (1990 $) 6k90,103,000# qF ԩ Fixed O&M cost (1995 $/year) 62,718,000# qF ԩ Variable O&M cost (1995 $/year) 6r2,957,000r#ܩ Capital recovery factorY0.1098Y#r qF ԩ Capital recovery cost (1995 $/year) 6@k10,544,000@#Y qFp ԩ Total annual cost (1995 $/year) 6'k16,219,000'#@ qFW ԩ Total annual cost (1990 $/year) 6k15,218,000#'ܩ Cost effectiveness (1995 $/ton)^140#ܩ Cost effectiveness (1990 $/ton) ^130#  dB! =Notes# |M2P2CdP#NOTES:'1Emission pointspecific input value obtained from the !National Particulates Inventory (NPI!). Note that the gas flow rate in the NPI is reported in units of acfm. The NPI values were converted to scfm for the model.#  dB" `))'2These costs are for the high sulfur (3percent) case in the report. They apply to capacities at or above 500 MW (approximately 1,000,000 acfm). For smaller sizes, report suggests scaling down costs via the standard 0.6 power law. Thus, at lower capacities the capital cost (in $/kW or $/acfm) will be higher (EPA, 1996).#  dB$ `))'3Factor derived from data in IAPCS model (version 5).#  dBn% `))'4Ratio of Chemical Engineering Plant Indexes (annual) for 1990 and 1995, respectively (357.6/381.1). Ratio used for both capital and annual costs.#  dB& `))'5If flow rate < 1,028,000 acfm, cost is scaled down via 0.6 power law.#  dB`' `))'6Values are rounded to $1,000.>Notes#V2PkC P### o P[6CU&P#(,** Cost equations for dual absorption (EPA, 1985):  P  1dddddddd (1) 1dddddddd (1) !#xddddd ddUx?Capital~cost~=~$990,000~+~$9.836~*~Flow~rate~( \in~ft^3/minute)o P['C&Po P['C&Po P['C&P@Capital@cost @FlowR @rate@in@ft@minute@@ @@$@9901@,_@000@$@99 @.g @836@(zzV3@/@)ߙ$(#(#(#(#!!'#$ 1dddddddd (1) !1dddddddd (1) A#xdddddzddUx@Operating~cost~=~$75,800~+~$12.82~*~Flow~rate~(\in~ ft^3/minute)o P['C&Po P['C&Po P['C&P@ OperatingW@cost @Flow @rateu@inT@ft5@minute@2@: @@$@75@,@800@$L @12 @.2 @828@(zz3@/(@)ߛ$(#(#`(#(#!A'#$;2nd tier (1)#:x2'C!X#3.&Coke Ovens#.<2nd tier (1)#(#  J #o P['CU&P#The cokeoven gases produced by the controlled pyrolysis of coal contain reduced sulfur compounds, in addition to numerous hydrocarbons. About 25 to 30 percent of the sulfur in the coal is emitted in gaseous form as a constituent of the coke oven gas. Almost  JB all of this sulfur is present as !hydrogen sulfide (H2S!), with minor amounts of mercaptans. Using the coke oven gas to heat or underfire the coke ovens, or as fuel for other  J combustion operations, results in SO2 emissions unless the H2S is removed.  J Several processes are suitable for removing H2S from coke oven gases. In the vacuum  Jz carbonate process, H2S is absorbed into a 3.0 to 3.5 percent solution of sodium carbonate.  JR The H2S is then stripped by steam from the absorbent in a reactivating tower. The reactivation is performed under vacuum to reduce the quantity of steam required. Conventional systems achieve about 90 percent removal. Cost equations for vacuum carbonate (EPA, 1986):  P  1dddddddd (1) A1dddddddd (1) a#x:dddddddUx1BCapital~cost~=~$3,449,803~+~$135.86~*~Flow~Rate~(ft^3~per~ minute)o P['C&Po P['C&Po P['C&P@Capital@costo @Flow8@Rate@ft@perW@minute@M@ @@$@3y@,@449@,@803 @$g @135{ @. @86@(zz3J@)1߮$(#(#(#(#!a'#$ 1dddddddd (1) a1dddddddd (1) #xdddddddUx@Operating~cost~=~$797,667~+~$58.54~*~Flow~Rate~(ft^3~per~minute)o P['C&Po P['C&Po P['C&P@ OperatingW@costT @Flow@Rate@ft@per<@minute@@ @@$@797@,*@667L @$ @58` @. @54@(zzk3/@)ߍ$(#(#(#(#!'#$;2nd tier (1)#:x2'C!X#4.&Sulfur Recovery Plants#*<2nd tier (1)#(#  Jl #o P['CU&P#Refinery sour gas streams are generally fed to a regenerative type of H2S removal process. The concentrated acid gas is then sent to the sulfur recovery unit. The Claus  J process is the most widely used method of producing sulfur from refinery H2S. The modified Claus process is based on producing elemental sulfur by first converting one J third of the H2S feed by precise combustion with air. The combustion products are then  J allowed to react thermally with the remaining twothirds of the H2S feed in the presence of a suitable catalyst to form sulfur vapor. 8Cost equations for amine scrubbing:  P"  1dddddddd (1) 1dddddddd (1) #x&dddddddUx0ACapital~cost~=~$2,882,540~+~$244.74~*~Flow~Rate~(ft^3~per~minute)o P['C&Po P['C&Po P['C&P@Capital@costo @Flow8@Rate@ft@perW@minute@M@ @@$@2y@,@882@,@540 @$g @244{ @. @74@(zz3J@)0߭$(#(#"(#(#!'#$8 1dddddddd (1) 1dddddddd (1) #x<)dddddddUxAOperating~cost~=~$749,170~+~$148.40~*~Flow~Rate~(ft^3~per~minute)o P['C&Po P['C&Po P['C&P@ OperatingW@cost @Flowy@RateV@ftT@per@minute@@ @@$@749@,*@170L @$ @148 @. @40@(zz3@)ߏ$(#(#$(#(#!'#$;2nd tier (1)#:x2'C!X#5.&Fuel Switching#<2nd tier (1)#(#  J( #o P['CU&P#One of the potential control strategies investigated was fuel switching to either a lower sulfur content fuel of the same type, or to natural gas. The most important of these),**a'#!'#A A:'#ka'#&'#(<)'#m+ options is the switch to natural gas, because natural gas essentially has no associated sulfur emissions. While fuel price projections are available that can be used to estimate the operating cost difference associated with a fuel change, the capital costs of constructing a natural gas pipeline to a site where one currently does not exist, depend on the distance to the nearest existing pipeline. The present IAS data bases do not include fuel switching as a potential control technique for utilities and other industrial sources because of the difficulty in quantifying pipeline costs.  J For this analysis of other point source SO2 emitters, it was hypothesized that plant sites in urban areas would be able to access natural gas pipelines with modest capital investment. There are a limited number of IAS Regions that only include urban counties. A review of the correspondence between IAS Regions that are predominantly urban, and  J other point source SO2 emitters found that most facilities were not in urban areas. Therefore, fuel switching was not included in the analysis as a viable control option. A current example of the potential significance of gas pipeline costs is the situation in Coos Bay, Oregon. Nucor Steel is proposing to build a steel plant at an industrial site in the area, but the firm has said that it will not locate in Coos Bay unless the area pays for a gas pipeline to be constructed to the site.  P 71st tier (A)#:x2C!X#B.`NEW SOURCE CONTROL TECHNOLOGIES#81st tier (A)#(#  J #o P['CU&P#Table 4 lists the proposed new technology control techniques and control effectiveness estimates for the source categories (scc_ids) in this study. This table was developed by examining NSPS as well as !Best Available Control Technology (BACT!) determinations. In all cases, the listed control technologies and expected control efficiencies are at least as  J stringent as current NSPS. Expected SO2 control efficiencies are reductions from uncontrolled emission levels. Technologies listed in this table are those that would be expected to be required by NSPS or BACT analysis in the absence of any new requirements, or regional agreements.  PJ ;2nd tier (1)#:x2'C!X#1.&Sulfuric Acid Plants#k<2nd tier (1)#(#  J #o P['CU&P#EPA NSPS for new and modified plants is 2 kg/mg (4 pounds per ton) of 100 percent acid produced, maximum 2 hour average. Achieving this standard requires a conversion  J efficiency of 99.7 percent in an uncontrolled plant, or the equivalent SO2 collection mechanism in a controlled facility (EPA, 1995). Dual absorption has generally been accepted as the BACT for meeting NSPS emission limits. There are no byproducts or waste scrubbing materials created, only additional sulfuric acid. Conversion efficiencies of  J,! 99.7 percent and higher are achievable, whereas most single absorption plants have SO2 conversion efficiencies ranging only from 95 to 98 percent.  P# ;2nd tier (1)#:x2'C!X#2.&Sulfur Recovery#C<2nd tier (1)#(#  J% #o P['CU&P#Existing NSPSs limit sulfur emissions from Claus sulfur recovery plants of greater than 22.40 tons per day capacity to 0.025 percent by volume (250 parts per million volume). This limit is effective at zero percent oxygen on a dry basis if emissions are controlled by an oxidation control system, or a reduction control system, followed by incineration. This is comparable to the 99.8 to 99.9 percent control level for reduced sulfur.),**  P  3'3'StandardHPLAIIPO.PRSo'3'3Standardding for 2nd-tier section߰X  X #o P[?CU&P##o P[@CU&P# (08@ (08@#o P[ACU&P# (08@ (08@ (08@ (08@ U 1  1 1! xXX~x#o P[BCU&P# (08@ (08@ (08@ (08@ (08@ (08@<M1 XX   9Table Titlej#:x2C!X# Table 4 vNew Technology Specification":Table Title"   ;#o P['CU&P##|M2PECdP# ^ a0"P dd Dq@" TT"^   "& & Wscc_idH& H& C DescriptionyPControl wTechnology wDescription f@ aExpected SO2 )Control Efficiency"' '  f@# &Notes X"ptsap1uc Sulfuric Acid Plants Contact Absorber (99.9% Conversion)zNoneT0New plants with acid adsorption of less than 99.7% will not meet the existing NSPS.XX"ptsap2uc Sulfuric Acid Plants Contact Absorber (99% Conversion)ufDual adsorptionT70New plants with acid adsorption of less than 99.7% will not meet the existing NSPS.XX1"ptsap3uc; Sulfuric Acid Plants Contact Absorber (98% Conversion);ufDual adsorption;T85;New plants with acid adsorption of less than 99.7% will not meet the existing NSPS.XX"ptsap4uc Sulfuric Acid Plants Contact Absorber (97% Conversion) ufDual adsorption T90 New plants with acid adsorption of less than 99.7% will not meet the existing NSPS.XX"ptsap5uc Sulfuric Acid Plants Contact Absorber (93% Conversion) ufDual adsorption T98.5 New plants with acid adsorption of less than 99.7% will not meet the existing NSPS.XX9 "ptesc1ucC Sulfur Recovery Plants Elemental Sulfur (Claus: 2 Stage)C uHAmine scrubbingC T98.4C  dB New plants must have SO2 removal efficiencies of 99% to meet standards.XX "ptesc2uc Sulfur Recovery Plants Elemental Sulfur (Claus: 3 Stage) uHAmine scrubbing T97.8  dB New plants must have SO2 removal efficiencies of 99% to meet standards.XX "ptesc3uc Sulfur Recovery Plants Elemental Sulfur (Claus: 3 Stage)uHAmine scrubbingT97.1 dBM New plants must have SO2 removal efficiencies of 99% to meet standards.XXA"ptsrmpucK Sulfur Recovery Plants Sulfur Removal ProcessKzNoneKT0K dB New plants must have SO2 removal efficiencies of 99% to meet standards.X"ptesncuc Sulfur Recovery Plants Elemental Sulfur Production n.c.zNone T0ܩ"ptincmucU Inorganic Chemical ManufactureU{FGDUT90UAlthough it seems unlikely that new plants like these will be built again, any BACT review will probably require FGD or equivalent removal."ptcokeucS Coke Oven PlantsSsGas desulfurizationST82SCoke oven gas desulfurization is a likely candidate for BACT."6ptprhtuc Process Heaters (Oil and Gas Production Industry){FGDT90FGD applicability is based on the probability that a BACT review under !prevention of significant deterioration (PSD!) will consider control of process heaters to be similar to that for boilers and  dBQ require technology which will reduce SO2 emissions by about 90%.S"Dpticibuc ICI Boilers{FGDT90Control of boilers will be FGD for both NSPS as well as BACT.X"ptpmtpuc[ Primary Metal Production[{FGD[T90[Both control of sulfur before or after combustion is feasible and will be required assuming that new operations like these are built.X"ptsmtpuc Secondary Metal ProductionzNone T0ܩ"ptnmmpuce Nonmetallic Minerals ProcessingezNone eT0eܩ"Lptkrftuc Sulfate (Kraft) Pulping{FGDT90ܩZe"Eptrfnruc Refinery Sources{FGDT90Process heaters in the refineries will be judged in the same manner as boilers and other process heaters and control by FGD will be BACT. Other refinery sources like blowdown systems, petroleum coke, incinerators, and flares will probably not be required to be controlled.Z  #o P[FCU&P#X '3'3Standardding for 2nd-tier section3'3'Standardmats table titles in Pechan repo(߰X  XX q!\ \ $$ Emissions from the Claus process may be reduced by: (1) extending the Claus reaction into a lower temperature liquid phase; (2) adding a scrubbing process to the  J Claus exhaust stream; or (3) incinerating the H2S gases to form SO2.  P` ;2nd tier (1)#:x2'C!X#3.&Boilers and Process Heaters#<2nd tier (1)#(#  J2 #o P['CU&P#Table 4 lists FGD as the expected new source technology requirement for SO2 control for ICI boilers, refinery process heaters, and other general process heaters. For boilers, this assumption is consistent with what is being applied to the new coalfired industrial boilers that are already included in an IAS source category (scc_id). Because the scc_ids that were developed for other point sources for boilers and heaters include all fuel types,  Jj assuming FGD at a 90 percent SO2 reduction as the new source technology may over  JB estimate the SO2 reduction associated with new source technology for these source  J categories. California addresses boiler and process heater control by limiting the fuel sulfur to a value that essentially restricts sources to using natural gas, or removing the sulfur from the fuel before combustion. For instance, the South Coast Air Quality Management Division Rule 431.1 limits the sulfur in refinery gas to 40 parts per million by volume. Liquid fuel is limited to a sulfur content of 0.05 percent, and solid fossil fuels are  JR limited to no more than 0.56 pounds of SO2 per million Btu. There are two options for examining the sensitivity of the IAS baseline forecast to these new source technology assumptions:  J 1.&Change the new source technology control for ICI boilers, and the two categories of process heaters to no control and run an IAS baseline simulation to 2040.(#  J: 2.&Break each of the applicable assigned scc_ids into two scc_ids, with the fuel types, such as coal and oil, where FGD is most likely to be required in one scc_id, and the gaseous fuels in another. Then, FGD would be an appropriate new source control technology for the coal and oilfired units (and perhaps process gasfired units), while the gaseous fuels would have their new source technology be the same as the existing source technology.(#  P" 71st tier (A)#:x2C!X#C.`GROWTH AND RETIREMENT RATES#"81st tier (A)#(#  P #o P['CU&P#;2nd tier (1)#:x2'C!X#1.&Retirement Rates##<2nd tier (1)#(#  J #o P['CU&P#Because technologies continue to evolve, it is important to reflect the potential for reductions in future emissions from the adoption of loweremitting processes/equipment. There are two available sources of information that can be used in estimating the rate of the adoption of new technologies. These sources have estimated and applied annual equipment turnover rates in projecting fuel consumption (!U.S. Department of Energy  J" [DOE!]) and in estimating historical capital stocks data (!Bureau of Economic Analysis! [BEA]). DOE has estimated annual retirement rates in estimating the amount of future  J$ industry output that will be produced using new equipment (Industrial Sector Demand   J% Module of the National Energy Modeling System, January 1998). BEA has estimated service lives of plant and equipment in developing its capital stock series ("Improved  J6' Estimates of Fixed Reproducible Tangible Wealth, 192995," Survey of Current Business, May 1997). (,**ԌThe emission projections developed for the GCVTC employed an earlier set of DOE annual retirement rates in estimating reduced emissions in future years ("Development of Emission Control and New Technology Options for the Grand Canyon Visibility Transport Region, Volume I, Technology Costs, Performance, and Applicability," Argonne National Laboratory, October 1995). In addition, the GCVTC analysis employed an average turnover rate for fuel combustion sources based on estimates developed for industrial boilers for the !National Acid Precipitation Assessment Program (NAPAP!). While the new !National Energy Modeling System (NEMS!) retirement rate estimates are available, it was decided to use the retirement rates developed for the original IAS model in order to employ a consistent approach for simulating source retirement. Table 5 displays the annual retirement rate allocation to source categories.  P ;2nd tier (1)#:x2'C!X#2.&Growth Rates#-<2nd tier (1)#(#  J #o P['CU&P#Appropriate growth rates for each new source category (scc_id) being added to IAS were determined by matching the new scc_ids with a !Regional Economics Model, Inc. (REMI!) growth sector (or set of growth sectors). This allocation is shown in Table5.  PR 71st tier (A)#:x2C!X#D.`DATA BASE ISSUES#//81st tier (A)#(#  J$ #o P['CU&P#There were a number of situations where the information in the 1990 emission inventory to be used in the cost analysis had to be further evaluated where information was incomplete, or included questionable information. These investigations are summarized below for each facility where additional information was gathered.  J\ 1. Plant Name: Monsanto((MU00]d88lt@@| Facility Identifier: 160290001 Source Classification Code: 30199999  J  SO2 emissions: 7,543 tons per year This facility is now owned by P4 Production, which is a joint venture of Monsanto and Solutia, Inc. The Idaho Department of Health and Welfare, Division of Environmental Quality was contacted by PechanAvanti to obtain more information about  J the SO2 emitting processes at this facility (because the SCC listed in the 1990 emission inventory was too general to identify the process). This facility produces elemental phosphorus (one of two facilities in the U.S. that does). The air permit for P4 Production was requested from the Idaho Division of Environmental Quality (and received January 22, 1999) (Casile, 1999). This revealed that the sulfur emitting process is a calcining type process (not fuel sulfur), and that FGD is an appropriate control technique. 2. Plant Name: Unknown Oregon source Facility Identifier: 41511851 Source Classification Code: 30399999  J$  SO2 emissions: 3,333 tons per year Brian Fields of the Oregon DEQ indicated that this facility is Reynolds Metals. He suggested that the most appropriate SCC for this facility/process is 30300101. The process was indicated to be a primary collection system for an aluminum reduction process. There is residual sulfur in the reduction cells from the baking process. ),**  P 9Table Titlec#:x2C!X# Table 5 IOther Point Source Retirement and Growth Factor Assignments"7:Table Title"  f -#o P['CU&P# #V2PMC P# c dd Dq@" TT" ddx!E" T"c Z"!t scc_idT} ODescriptionKRetirement Rate (%)"HREMI Sector  sD Growth Indicator /"Eptsap1uc Sulfuric Acid Plants Contact Absorber (99.9% Conversion)T:1.9"18//"Eptsap2uc Sulfuric Acid Plants Contact Absorber (99% Conversion)T:1.9"18//"Eptsap3uc& Sulfuric Acid Plants Contact Absorber (98% Conversion)& T:1.9& "18//"Eptsap4ucU Sulfuric Acid Plants Contact Absorber (97% Conversion)U T:1.9U "18//& "Eptsap5uc Sulfuric Acid Plants Contact Absorber (93% Conversion) T:1.9 "18//U "Iptesc1uc Sulfur Recovery Plants Elemental Sulfur (Claus: 2 Stage) T:1.9 "18// "Iptesc2uc Sulfur Recovery Plants Elemental Sulfur (Claus: 3 Stage) T:1.9 "18// "Iptesc3uc Sulfur Recovery Plants Elemental Sulfur (Claus: 3 Stage)T:1.9"18// "@ptsrmpuc@ Sulfur Recovery Plants Sulfur Removal Process@T:1.9@"18//"Iptesncuco Sulfur Recovery Plants Elemental Sulfur Production n.c.oT:1.9o"18//@"Iptincmuc Inorganic Chemical ManufactureT:1.9"18//o"Iptcokeuc Coke Oven PlantsT:1.9"4//"fptprhtuc Process Heaters (Oil and Gas Production Industry)T:2.3"22//"wpticibuc+ ICI Boilers+T:0.62+"54//"@ptpmtpucZ Primary Metal ProductionZT:1.2Z"4//+"Dptsmtpuc Secondary Metal ProductionT:1.2"4//Z"ptnmmpuc Nonmetallic Minerals ProcessingT:1.2"3//"~ptkrftuc Sulfate (Kraft) P