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             ATTACHMENT G:

EMISSIONS CONTROL REDUCTION FACTORS AND
          METEOROLOGICAL DATA
                 D-110
-------
                        ATTACHMENT G
         GENERAL  FUGITIVE DUST EMISSIONS ASSUMPTIONS
                  AND METEOROLOGICAL DATA
     Reduction factors to account for emissions control
practices and assumptions regarding meteorological data
apply to all fugitive dust emissions estimates.

G.I  Reduction Factors
     Controlled fugitive dust emission rates were determined
by applying a reduction factor to the uncontrolled fugitive
dust emission rates, depending on the fugitive dust control
practices employed by each facility.  When several types of
housekeeping control practices were used, the following
order was assumed:  power washing, followed by area
vacuuming, followed by wet suppression.
     Table G-l presents the reduction factors assumed for
various combinations of fugitive dust emissions control
practices at secondary lead smelters.
     A reduction of 99.0 percent was applied for fugitives
dust control by total enclosure and ventilation to a
baghouse and/or scrubber.  The value was based on a range of
PM control efficiencies of 98.4 percent  (fabric filter on
blast furnace) to 99.8 percent (settling chamber plus dry
cyclone plus fabric filter on reverberatory furnace).*  This
reduction factor was applied to furnace and refining/casting
areas that are totally enclosed even if they are not
ventilated to a baghouse or scrubber.
     For power washing, a reduction of 69 percent was
assumed.  This is the reported .-maximum control efficiency
due to power washing, assuming water is applied at
0.48 gallons per square yard.2  No reduction was assumed for
power washing in the materials storage area.
     Wet suppression of any kind was assumed to reduce
emissions by 50 percent.  A control efficiency 9f 54 percent
was measured at a secondary lead smelter for a paved roadway

                            D-lll
-------
sprinkler system that operates 3 out of every 15 minutes.3
Other estimates of control efficiency found in the
literature are 50 percent for unpaved road watering4 and
50 percent for watering of storage piles.5
     For paved roads, area vacuuming was assumed to reduce
emissions by 34 percent, based on average measured
efficiency.6  No reduction was assumed for area vacuuming in
the materials storage area because of the heavy dust loading
in this area.
     For combinations of power washing, wet suppression, and
vacuuming, an order of application was assumed.  For
example, the value for power washing (69 percent efficiency)
followed by area vacuuming (34 percent efficiency)"was
calculated as follows:

          0.69 + [(1-0.69)*0.34] = 0.795 (or 79.5%)

The value for power washing followed by area vacuuming
(79.5 percent combined efficiency) and then followed by wet
suppression  (50 percent efficiency) was calculated as
follows:

          0.795 + [(1-0.795)*0.50] = 0.898  (or 89.8%)

G.2  Meteorological Data
     All fugitive dust emissions estimates used the
following meteorological parameters:
          Precipitation days per year  (p), rounded to the
          nearest 10,
          Mean wind speed  (U) in miles per hour, rounded to
          the nearest whole number, and
          Percent of time  the wind speed  exceeds 12 miles
          per hour  (f), rounded to the nearest  5.
     The meteorological values were  taken  from Climates  of
the States  (Third Edition) and were  rounded  from the  values
presented in an earlier memorandum to  discourage   r

                            D-112
-------
identification of actual facilities from the model plants
developed to represent the secondary lead industry.
                            D-113
-------
-------
G.3  References
1.   U. S. Environmental Protection Agency.  Compilation of
     Air Pollutant Emission Factors.  Washington, DC.
     Publication No. AP-42.  September 1985. p. 7.11-8.

2.   Marinshaw, R. and D. Wallace, Midwest Research
     Institute.  Estimating and Controlling Fugitive Lead
     Emissions from Industrial Sources, Final Report.
     Prepared for the U. S. Environmental Protection Agency,
     Research Triangle Park, NC.  EPA Contract No. 68-02-
     4395, Work Assignment 41.  September 28, 1990.  p. 74.

3.   Memorandum from Marinshaw, R. and C. Cowherd, Midwest
     Research Institute, to Scott, D., OAQPS/AQMD.
     September 28, 1990.  Sealing Feasibility Study:  Source
     Identification for a New Lead Standard.  p. 12.

4.   Bohn, R., T. Cuscino, Jr., and C. Cowherd, Jr.,
     (Midwest Research Institute).  Fugitive Emissions from
     Integrated Iron and Steel Plants.  Prepared for the U.
     S. Environmental Protection Agency, Research Triangle
     Park, NC.  Publication No. EPA-600/2-78-050.  March
     1978.  p. 6-15.

5.   Bohn, R., T. Cuscino, Jr., and C. Cowherd, Jr.,
     (Midwest Research Institute).  Fugitive Emissions from
     Integrated Iron and Steel Plants.  Prepared for the U.
     S. Environmental Protection Agency, Research Triangle
     Park, NC.  Publication No. EPA-600/2-78-050.  March
     1978.  p. 6-20.

6.   Marinshaw, R. and D. Wallace, Midwest Research
     Institute.  Estimating and Controlling Fugitive Lead
     Emissions from Industrial Sources, Final Report.
     Prepared for the U. S. Environmental Protection Agency,
     Research Triangle Park, NC.  EPA Contract No. 68-02-
     4395, Work Assignment 41.  September 28, 1990.  p. 73.
                            D-114
-------
 TABLE G-l.   REDUCTION FACTORS FOR FUGITIVE DUST EMISSIONS
             CONTROL PRACTICES AT SECONDARY LEAD SMELTERS


   Reduction
   Factor (%)	Technique	

       99.0       Total enclosure ventilated to a baghouse
                  or scrubber

       89.8       Power washing,  followed by area
                  vacuuming,  followed by wet suppression

       84.5       Power washing,  followed by wet
                  suppression

       79.5       Power washing,  followed by area
                  vacuuming

       69.0       Power washing

       67.0       Area vacuuming,  followed by wet ~
                  suppression

       50.0       Wet suppression

	34.0	Area vacuuming	
                           D-115
-------
                         APPENDIX E

             CONTROL COST ESTIMATION PROCEDURES
1.0  INTRODUCTION
     The purpose of this appendix is to present the
procedures used to estimate the cost of control technologies
being considered as the candidate maximum achievable control
technology (MACT) for secondary lead smelters.  The cost
procedures outlined in this appendix are consistent with
those in the OAOPS Control Cost Manual1 where possible;
however, other sources were used to develop procedures for
control equipment not covered in the cost manual.  The
industry characterization data in the secondary lead smelter
database, presented in appendix C,2 are used with the
costing procedures to estimate (1) baseline control cost,
(2) potential control cost impacts of MACT, and (3)
potential control cost impacts of MACT in the fifth year
after proposal.
     This appendix is organized into seven sections.  The
costing procedures for afterburners are presented in
section 2.0,  for scrubbers in section 3.0, for hoods in
section 4.0,  for duct work in section 5.0, for wet
suppression in section 6.0, and for vacuum sweeping in
section 7.0.  Section 8.0 presents the references cited in
this appendix.

2.0  AFTERBURNERS
2.1  OVERVIEW
     An afterburner is essentially a thermal incinerator
that follows a furnace and is operated to combust organic
                             E-l
-------
compounds in the furnace exhaust.   Therefore, the cost
procedures described in the OAQPS Control Cost Manual1 for
thermal incinerators are used to estimate capital and annual
costs for afterburners that may need to be installed at
existing facilities.3  However, in estimating costs for new
afterburners at existing facilities, a retrofit factor is
applied to account for access and congestion problems that
may be encountered during installation.  Table 1 presents
these retrofit factors and guidelines for selecting the
appropriate factor.
     For new afterburners at existing facilities, a retrofit
factor of 0.42 is applied because of the afterburners'
proximity to the process equipment  (e.g., furnace).  The
retrofit cost is then determined by multiplying the retrofit
factor by the total direct cost of the new afterburner,
excluding duct work.  The cost of replacing an inadequate
afterburner is estimated in the same manner as for existing
afterburners, with the additional cost of removing the old
afterburner.  The cost of removing the inadequate
afterburner is assumed equivalent to the sum of the direct
and indirect installation costs of the new afterburner.4
2.2  DESIGN PARAMETERS
     This section discusses the calculation of the design
parameters needed to estimate the cost of an afterburner.
Data needed to calculate the design parameters used in cost
procedures include:
     •    Volumetric flow rate of the waste stream;
     •    Temperature of the waste stream;
     •    Chemical composition of the combustibles; and
     •    Combustion chamber outlet temperature.
The EAB Control Cost Manual-' states that a flue gas (furnace
exhaust) oxygen content of ci least  3 percent by volume is
required to ensure that sufficient oxygen is available for
combustion.  An afterburner test at a secondary lead
facility showed that between 8.2 and 10.2 percent oxygen

                             E-2
-------
TABLE 1.   SITE ACCESS  AND CONGESTION FACTORS  FOR
             RETROFITTING AIR POLLUTION CONTROL
                EQUIPMENT AT EXISTING PLANTSa
  Retrofit
   Factor
Congestion
  Level
Guidelines for Selecting Factor
    0.02       Base Case    Interferences similar to those at a
                            new plant with adequate crew work
                            space.  Free access for cranes.

    0.08          Low       Some  above-ground interferences and
                            work  space limitations.  Access for
                            cranes  limited to two sides.
                            Equipment cannot be laid out in
                            standard design.  Some equipment must
                            be elevated or located remotely.

    0.25        Medium      Limited space.  Interference with
                            existing structures or equipment that
                            cannot  be relocated.  Special design
                            is necessary.  Crane access limited to
                            one side.  Majority of equipment
                            elevated or remotely located.

    0.42         High       Severely limited space and access.
                            Crowded working conditions.  Access
                            for cranes blocked from all sides.
 aReference  4.
                               E-3
-------
remained in the gas stream after the afterburner.6
Therefore, it is assumed that no auxiliary air will be
added.  It is also assumed that waste gas will not be
preheated before entering the afterburner and that the
concentration of the combustibles in the waste stream is
below 25 percent of the lower explosive limit.
     Other design specifications will be obtained from the
facilities database discussed in a separate memorandum.2
The model plant data provided by the database are in metric
units; however, the variables in the cost equations must be
in English units.  Therefore, the temperature and gas flow
rate input parameters needed for costing are converted to
English units.  These conversions are shown in attachment 1.
     In the following sections, the afterburner design
parameters needed for the cost procedures are calculated for
an example waste stream.  Specifications of the example
waste stream are shown in table 2.  Additional detail is
provided in the spreadsheets in attachment l.
2.2.1     Step 1 - Standardization.
     The cost algorithms require that the waste gas flow
rate be standardized to 77°F and 1 atmosphere (atm) of
pressure.  It is assumed that the waste gas stream is near
1 atm.  The waste gas flow rate in units of actual cubic
feet per minute (acfm) are standardized to units of standard
cubic feet per minute (scfm) as follows:

           Qs = Qwo =  (Qa) [ (460 + 77) / (460 + Twi) ]       (2.1)

where:
     QS   =    waste gas flow rate (scfm)
     Qwo  =    outlet waste gas flow (scfm)
     Qa   =    waste gas flow rate (acfm)
     Twi  =    furnace exhaust temperature (°F)
                             E-4
-------
TABLE 2.  SPECIFICATIONS OF EXAMPLE WASTE STREAM FOR
          AFTERBURNER DESIGN AND COSTING PROCEDURES
Afterburner/Process Unit Specific Inputs
Afterburner operating temperature (°C)
Waste gas flow rate (actual m3/rain)
Percent moisture in exhaust from furnace (%)
Furnace exhaust temperature (°C)
Hours of operation per year (hrs/yr)
Inlet CO concentration (ppmv @1 atm, 25°C, dry)
Inlet total hydrocarbon concentration (mg C/m3 @
1 atm, 25°C, dry)
Variable
Name
Tfim
Qam
Pmoist
Twim
Ho
COin
THin
Value
870
1,133
1.0
260
8,760
10,000
2,000
                         E-5
-------
The example stream waste gas flow rate is:
       Qs = QWO = (40,000 acfm)  [(460 + 77) / (460 + 500)]

          - 22,400 SCfm


2.2.2     Step 2 - Heat of combustion of the waste stream
          calculation.
     The heat of combustion of the waste stream is
calculated as follows:3
                           IL
                   Hcwg =  [J£]  HiXi/(Dwi)              (2.2)
                          i='l

where:
     Hcwg =    heat of combustion of the waste stream
               [British thermal units per pound (Btu/lb)]
     n    =    number of combustibles
     Hi   =    volumetric heat of combustion of component i
               at 25°C  (Btu/scf)
     Xi   =    volume fraction of component i
     Dwi  =    inlet density of the waste gas  (Ib/scf)
     The primary combustible components in a secondary lead
furnace exhaust stream are total hydrocarbon  (THC) and
carbon monoxide (CO).  Numerous hydrocarbon compounds may be
emitted from a secondary lead furnace.  Results of EPA
testing show that benzene (a hydrocarbon) is typically
emitted in high concentrations.^  Therefore, the heat of
combustion of benzene is used as the heat of combustion  for
THC emitted from a furnace.  The heats of combustion for THC
and CO at 25°C are:

     Hth  =    3,587 Btu/scf for THC  (as benzene)8
     Hco  «    311 Btu/scf for CO9

The inlet concentration of THC  (as carbon) is  converted  to a
volume fraction of THC  (as benzene) as follows:
                             E-6
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                     (1 g C)     (l mol C)  (I mol hexane)
                   i^Qoo mg c  12-011 g c     6 mol c
                                                       (2.3)
                   (002447 m3)
                       mol
where :
     Xth  =    volume fraction of THC (as benzene) in waste
               gas (m3 THC/m3 waste gas)
     THin =    inlet concentration of THC (as carbon) (mg
               C/m3)
For the example waste stream, the conversion is as follows:

 Xth - (2f OOOmgC)   (IgC)    (ImolC)   (1 mol hexane)  (0.02447
           in3     l,OOOmgC 12.011gC)     6molC        mol

     = 6.8 x 10 ~4 m3 THC/m3  total

The composition of CO in the example waste stream is
converted from parts per million by volume (ppmv) to volume
fraction as follows:

        Xco - 10,000 ppmv x 10 ~6 - 0.01 m3 CO/m3 total
Assuming that the waste gas is principally air, with a
molecular weight of 28.97 and a density of 0.0739 Ib/scf,
the heat of combustion per pound of waste gas is:3

  Hcwa -  (6-8xlO~4)  (3,587 BtU/scf) + (0.01)  (3 . 11 Btu/scf )
     9                     0.0739 Ib/SCf
       =75 Btu/lb
2.2.3     Step 3; - Minimum auxiliary fuel requirement
          calculation.
     Waste gas streams with high heats of combustion may
require only enough auxiliary fuel in the afterburner to
stabilize the burner flame (less than 5 percent of the total
energy input).  The auxiliary fuel is assumed to be natural
gas with*a heat of combustion of 21,502 Btu/lb and a density
                             E-7
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of 0.041 Ib/scf.  The minimum auxiliary fuel required is

calculated as follows:3

                [Dwi x Qwo x Cpmfi (Tfi - Tref ) ] x 0.05       .
                             Daf x Hcaf                 (2>4)
where :
     Maux      =    minimum auxiliary fuel requirements
                    (scfm)

     Dwi       =    inlet density of the waste gas
                    (0.0739 Ib/scf)3

     Qwo       =    outlet waste gas flow (scfm)

     Cpmfi     =    mean heat capacity of waste gas
                    (0.255 Btu/lb-°F)3

     Tfi       =    afterburner operating temperature goal
     Tref      =    reference temperature, taken as the
                    inlet temperature of the auxiliary fuel,
                    (77°F)3

     Daf       =    density of auxiliary fuel  (Ib/scf) ;
                    natural gas (0.041 Ib/scf )3

     Hcaf      =    heat of combustion of auxiliary fuel
                    (Btu/lb) ; natural gas (21,502 Btu/lb)3
The minimum auxiliary fuel requirement for the example waste
stream is:
         0.0739^^ 22,400-^  0.255 °u"  (160QOF - 77°F)  (0
 Maux = A	3cf A	min/\      lb-°F/v  	;|

                                    /on  502 BtU\
                                    |21,502  lb|
        37
           mm
2.2.4     Step 4 - Auxiliary fuel requirement calculation.

     In general, more fuel is required to maintain the

afterburner temperature than just the minimum amount to
stabilize the burner flame.  With the following assumptions,
the auxiliary fuel requirement  (Qaf) can be estimated.3
                             E-8
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     •    The reference temperature (Tref) is taken as the
          inlet temperature of the auxiliary fuel  (77°F).

     •    An insignificant amount of auxiliary air is
          required.

     •    Energy losses (Hi) are assumed to be 10 percent of
          the total energy input to the incinerator above
          ambient conditions.  Thus, if the reference
          temperature is near ambient conditions,

          HI - 0.1 x Dfi x Qwo x Cpmfi x  (Tfi - Tref)   (2.5)

     •    The heat capacity of the waste gas at the entrance
          and exit of the combustion chamber are
          approximately the same.  This is true for waste
          streams, which are dilute mixtures of organic^ in
          air.

With these assumptions, the auxiliary fuel requirement is
estimated with the following equation:3

 Oaf - Dwo x Qwo  [ (Cpmfi (1.1 x. Tf i-Twi-0.1 x Tref)) -HcwoJ fi.
              [Hcaf -1.1 x Cpmfi x  (Tfi - Tref)] Daf     ^  '

For the example waste stream, each of the terms in

equation 2.6 is as follows:

     Dwo  =    0.0739 Ib/scf

     Qwo  =    22,400 scfm; from Step 1

     Cpmfi=    0.255 Btu/lb-°F

     Tfi  =    1,600 °F

     Twi  =    500 °F

     Tref =    77 °F

     Hcwg =    75 Btu/lb; from Step 2

     Hcaf =    21,502 Btu/lb

     Daf  =    0.041 Ib/scf

The auxiliary fuel requirement for the example waste stream
is:


For the example waste stream, the auxiliary fuel requirement

(Qaf)  is greater than the minimum auxiliary fuel requirement
                             E-9
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                  (0.0739 JllL)  (22,400  SCf )
 _ _                      scf           min
 Qaf =
              15 til
       [21,502 -  - 1.1 X 0.255 - ___ X (1600°F - 77°F) ]
               lb               lb-°F
                  Btu                                         Rtu
         [(0.255 — - ) (1.1 Xl600°F - 500°F - 0.1 X 77°F) - 75    ]
                 lb-°F                                         lb
       x --
                                (0.041
                                       SCf
     = 470 scfm

(Maux); therefore, the value for Qaf (470 scfm) is used to
estimate the auxiliary fuel cost.
2.2.5     Step 5 - Calculation of the total standard
          volumetric flow rate of gas through the
          incinerator.
     The total standard volumetric flow rate of gas leaving
the afterburner (Qtot) is the basis of the cost
correlations.  The total flow rate measured at standard
conditions of 77°F and l atm is the sum of the inlet streams
to the afterburner.3
                       Qtot » Qs  + Qaf                  (2.7)

The total flow rate for the example waste stream is:
                Qtot = 22,400 scfm + 470 scfm

                     - 22,870 scfm

2.3  COSTING PROCEDURES
     This section discusses the costing procedures for
estimating capital and annual costs for afterburners.  The
costing methodology was derived from the OAQPS Control Cost
Manual.3  All costs are converted to December 1991 dollars
using the appropriate indices* presented in table 3.
Detailed example cost calculation spreadsheets are presented
in attachment 1.
                            E-10
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                 TABLE  3.   COST  INDICES
Time Frame
Chemical Enaineerina
April 1988
December 1991
June 1991
Third Quarter 1986
July 1988
February 1989
February 1988
March 1980
August 1988
December 1988
Industrial Commoditi
Index
Plant Cost
340.1
359.3
362.1
317.9
343.0
352.4
336.1
253.5
344.0
Variable
Name
Indices
11
12
13
14
15
16
17
110
111
349.2 112
es Less Fuels and Related
Reference
10
11
12
13, 14
15
16
17
18
15
19
Products
Index
February 1992          126.7        18            20
December 1991          126.2        19            21
                         E-ll
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2.3.1     Total Capital Investment
     Total capital investment (TCI) for afterburners
includes equipment cost (EC) for the afterburner itself, the
cost of auxiliary equipment (e.g., duct work, fans), direct
installation costs, indirect installation costs, building
costs, site preparation, off-site facilities, land, and
working capital.  Building costs, site preparation, off-site
facilities, land, and working capital are considered
negligible for afterburners at secondary lead facilities and
are not included in the costing procedures.  Duct work costs
are discussed in section 5.0.   Fan costs are considered
negligible for afterburners,, both because the facility will
already have a fan and because the pressure drop across the
afterburner will be relatively small.
     2.3.1.1   Equipment Cost.  The EC for afterburners is
estimated with the cost equation for a recuperative thermal
incinerator with no heat recovery from the OAQPS Control
Cost Manual.^  The cost is given as free on board  (F.O.B) in
April 1988 dollars but is converted to December 1991 dollars
using the Chemical Engineering plant cost indices presented
in table 3.  The EC is estimated as a function of total
volumetric throughput (Qtot) in scfm as follows:3

              EC = 10,294  Qtot 0.2355 x (12/11)          (2.8)

where:
     EC   =    afterburner cost  (December 1991 dollars)
     12   =    December 1991 plant cost index (359.3)10
     II   =    April 1988 plant cost index (340.l)11

     2.3.1.2   Installation Costs.  The purchased equipment
cost (PEC) is the sum of the EC and the cost of auxiliary
equipment  (e.g., duct work, fans), taxes, freight, and
instrumentation.  The cost of duct work is addressed in
section 5.0.  Taxes, freight,  and instrumentation are
fractions of the EC and are presented in table 4.  Average
values of direct and indirect installation factors to be

                            E-12
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     TABLE 4.   CAPITAL COST FACTORS  FOR AFTERBURNERSa
                     Cost  Item
  Factor
 Direct Costs
   Purchased equipment costs
     Incinerator (EC)  + auxiliary equipment13
     Instrumentation
     Sales taxes
     Freight
       Purchased equipment cost  (PEC)

   Direct Installation Costs
     Foundations & supports
     Handling & erection
     Electrical
     Piping
     Insulation for duct work
     Painting
       Direct installation cost
             Total Direct Cost  (DC)
As estimated, A
         0.10 A
         0.03 A
         0.05 A
     B = 1.18 A
         0.08 B
         0.14 B
         0.04 B
         0.02 B
         0.01 B
         0.01 B
         0.30 B
         1.30 B
 Indirect Costs (Installation1
   Engineering
   Construction and field expenses
   Contractor fees
   Start-up
   Performance test
   Contingencies
             Total Indirect  cost  (1C)
             Total Capital Investment  (TCI)
             DC +  1C
         0.10 B
         0.05 B
         0.10 B
         0.02 B
         0.01 B
         0.03 B
         0.31 B
         1.61 B
aReference 3.
"Auxiliary equipment cost  considered separately.
                               E-13
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applied to the PEC are also presented in table 4.  The sum
of the EC, the direct installation costs, and the indirect
installation costs yields the TCI.  Table 5 shows the
itemized PEC and installation costs for the example waste
stream.
2.3.2     Total Annual Cost
     The total annual cost (TAG)  is the sum of the direct
and indirect annual costs.  The TAG for the example stream
is shown in table 6, along with suggested factors for each
item.  The following sections discuss the various elements
that make up the annual costs for operating an afterburner
system.
     2.3.2.1   Direct Annual Costs.  Direct annual costs for
afterburners include labor (operating and supervisory),
maintenance (labor and materials), and fuel.  A
December 1991 operating labor rate (Copla) of $13.49 per
hour was obtained from the Survey of Current Business.22
Operating labor for an afterburner is estimated at 0.5 hours
per 8-hour shift.  The cost of supervisory labor is
estimated at 15 percent of the cost of the operating labor.
The maintenance labor rate (Cmla) is estimated to be
10 percent higher than the operating labor rate at $14.84
per hour, and the amount of maintenance labor required is
0.5 hours per shift.  The cost of maintenance materials is
estimated as equal to the cost of maintenance labor.3  The
fuel for afterburners is assumed to be natural gas at a cost
of $3.03 per thousand cubic feet.23
     The cost of auxiliary fuel  (i.e., natural gas) is
calculated as follows:3

               „  .        (Qaf x 60 x Ho)                ,
               Nat_gas = —	 x Cng          (2.9)
                              1000

where:
     Nat_gas   =    auxiliary fuel cost  (December 1991 $/yr)
     Qaf       =    auxiliary fuel requirement (scfm)
                            E-14
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 TABLE  5.  EXAMPLE AFTERBURNER WASTE STREAM  CAPITAL COSTS

	Cost  Item	Cost	
 Direct  Costa
   Purchased equipment costs
     Afterburner (EC - 10,294 Qtot 0.2355)                        S109.423
     Convert to  December  1991 dollars                              115,600
       (A = EC (12/11))
     Instrumentation (0.10A)                                        11,560
     Sales tax (0.03A)                                               3,468
     Freight (0.05)                                             	5.780
            Purchased equipment cost  (B)                         $136,408

   Direct Installation Costs
     Foundations & supports  (0.08B)                                 10,913
     Handling  &  erection  (0.14B)                                    19,097
     Electricity (0.04B)                                             5,456
     Piping (0.02B)                                                  2,728
     Insulation  for duct  work  (0.01B)                           	1,364
     Painting  (0.01B)                                                1,364
            Direct installation cost  (0.03B)                      $40,922

            Total Direct Cost  (DC) »  1.30B                       $177,330

 Indirect Costs  (Installation!
   Engineering (0.10B)                                              13,641
   Construction  and field expenses (0.05B)                           6,820
   Contractor  fees (0.10B)                                          13,641
   Start-up (0.02B)                                                  2,728
   Performance test (0.01B)                                          1,364
   Contingencies (0.03B)                                        	4,092
            Total Indirect Cost (1C)  = 0.31B                      $42,286
	Total Capital Investment  (TCI) = DC+IC               $219,617
                               E-15
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 TABLE  6.  EXAMPLE AFTERBURNER WASTE STREAM ANNUAL  COSTS

	Cost Item	Cost	
 Direct  Annual Costs
   Operating labor
     Operator (0.5 hrs/shift)                                      $7,386
     Supervisor  (15% of op. labor)                                  1,108

   Maintenance
     Labor (0.5  hrs/shift)                                          8,124
     Materials (100% of main, labor)                                8,124

   Utilities
     Natural gas                                                 748.354
            Total Direct Annual Cost (TDAC)                      $773,096

 Indirect  Annual Costs
   Overhead (60% of operating, tmpv., & maint.
     labor, and  maintenance materials                              14,845
   Administrative charges  (0.02 TCI)                                4,392
   Property tax  (0.01 TCI)                                          2,196
   Insurance (0.01 TCI)                                             2,196
   Capital Recovery (CRF x TCI)                                   S31.269
            Total Indirect Annual Cost (TIAC)                     $54,899

	Total Annual Cost (TAG) = TDAC + TIAC	$827,995
                               E-16
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     Ho        =    hours of operation per year
     Cng       =    cost of natural gas ($3.03/thousand ft3)
     2.3.2.2   Indirect Annual Costs.  Indirect annual costs
include overhead, administrative changes,  property tax,
insurance, and capital recovery.  Overhead is calculated as
60 percent of the sum of operating labor,  supervisory labor,
maintenance labor, and maintenance materials costs.
Administrative changes, property tax, and insurance can be
estimated at 1 percent, 1 percent, and 2 percent of the TCI,
respectively.  The system capital recovery will be based on
a 10-year equipment life and a 7 percent annual interest
rate.  The annual capital recovery is calculated by
multiplying the TCI by a capital recovery factor (CRF),
which is determined as follows:3

                            i  (i + i\Ls
                      CRF =    *     ;                  (2.10)
                            (1 + i)Ls-l

where:
     CRF  =    capital recovery factor
     i    =    annual interest rate, (decimal)
     Ls   =    system life (years)
Using equation 2.10, the CRF for afterburner is 0.142.

3.0  SCRUBBERS
3.1  OVERVIEW
     The costing procedures described in The Cost Digest;
Cost Summaries of Selected Environmental Control
Technologies24 are used to estimate the capital and annual
costs for scrubbers.
     The cost of new scrubbers that may need to be installed
at existing facilities as a result of the standard are
estimated using the same procedures as for existing
scrubbers.  A retrofit factor is not applied because
scrubbers are generally located in an open area outside and
away from the main facility.  The primary purpose of
existing scrubbers at secondary lead facilities is for
                            E-17
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sulfur dioxide (SO2) removal; however,  hydrochloric acid
(HC1) emissions reductions may also be achieved through the
use of a scrubber.  Hydrochloric acid is preferentially
removed by an S02 scrubber.  The cost of replacing existing
scrubbers is not addressed because it is unlikely that any
scrubbers will need to be replaced to increase HC1 emissions
reductions.
3.2  DESIGN PARAMETERS
     The design parameter calculations for scrubbers are a
great deal simpler than those for afterburners.  The only
design parameter calculations are the temperature and
volumetric flow rate conversions from metric to English
units for the cost algorithms.  Example calculations are
shown in attachment 2.
3.3  COSTING PROCEDURES
     This section discusses the costing procedures for
estimating capital and annual costs for spray, tray,
packed-bed, and venturi scrubbers.  The cost equations
provide costs in March 1980 dollars; however, they are
converted to December 1991 dollars using the Chemical
Engineering plant cost indices presented in table 3 above.
The Cost Digest25 provides capital and annual operating cost
curves in relation to waste gas flow rate.  In order to
obtain cost equations, several points were selected from the
curves and linear regression was performed.  The detailed
calculations for deriving the cost equations for scrubbers
is shown in attachment 3.
     The specifications of an example waste stream are shown
in table 7 in order to present example costs.  Capital costs
for the example stream are presented in table 8 and annual
costs are presented in table 9.  Detailed scrubber example
costing spreadsheets are presented in attachment 2.
3.3.1     Total Capital Investment
     3.3.1.1   Spray Scrubbers.  The cost algorithms for
spray scrubbers use the cost curves for the lime/limestone
flue gas desulfurization  (FGD) system presented in The Cost
Digest.25  The algorithms include costs for the scrubber,
                            E-18
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  TABLE 7.   SPECIFICATIONS OF EXAMPLE WASTE STREAM FOR
         SCRUBBER DESIGN AND COSTING PROCEDURES

                                           Variable
  Scrubber/Process Unit Specific Inputs	Name	Value
Scrubber type                              SC_type     Spray
Waste gas flow rate (actual m3/min)        Qam         1,130
Pressure drop (mmHg)                       PDm            20
Outlet temperature  (°C)                    Tout           80
Hours of operation per year  (hrs/yr)       Ho          8,760
Inlet SO2 concentration  (ppmv @ 1 atm,     SO2in       1,000
25°C, dry)	
                         E-19
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  TABLE 8.   EXAMPLE SCRUBBER WASTE  STREAM CAPITAL COSTS


	Cost Item	Cost

 Scrubber system cost                           $2,449,572

 Venturi scrubber stainless steel add-on                 0

               Total Capital Investment         $2,449,572
	(TCI)	
                          £-20
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   TABLE 9.   EXAMPLE SCRUBBER WASTE STREAM ANNUAL COST

	Cost Item	Cost
 Operating cost                                   $831,207
 Venturi scrubber stainless steel add-on                 0
 Capital recovery (TCI x CRF)                 	268,950
	Total Annual Cost (TAG)	$1,100,157
                          E-21
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holding tank, solid/liquid separation system, sorbent  (lime)
preparation systems, solids disposal, and auxiliaries  (e.g.,
fans, pumps, duct work).  The system is assumed to have a
15-year life and a 90-percent SC>2 removal efficiency.  The
Cost Digest provides cost curves for TCI in terms of gas
flow rate in acfm.  The following points were selected from
the curves:25
       Gas Flow Rate facfml   TCI  (March 1980 dollars)
              41,000                  1,800,000
              82,000                  2,250,000
             124,000                  2,600,000
             165,000                  2,850,000
Using linear regression, the following capital cost equation
was derived (R2 = 0.98):

      TCIun_sp = Gas Flow Rate (acfm) x 8.454 + 1,504,247(3.1)

This equation corresponds to a waste gas with an SC>2
concentration of 1,474 ppmv.  The capital cost of a spray
scrubber varies with SC>2 concentration; therefore, an
equation was derived to calculate a multiplier factor for
capital costs as a function of SO2 concentration.  At
1,474 ppmv SC>2, the multiplier factor would be 1.0; at
253 ppmv S02, it would be 0.847.  Using linear regression,
the following capital cost multiplier factor equation was
derived (R2 = 0.98):

        TCImf_sp = 0.0001253 X SC>2 cone, (ppmv) + 0.815   (3.2)

Therefore, the TCI'for spray scrubbers is calculated as
follows:

                TCI_sp = TCIun_sp x TCImf_sp           (3.3)

     3.3.1.2  Trav and Packed-Bed Scrubbers.  The cost
algorithms for tray scrubbers and packed-bed scrubbers use
the cost curves for the sodium alkali FGD system presented
in The Cost Digest.25 The algorithms include costs for the
same items as for spray scrubbers except that a waste  liquid

                            E-22
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disposal  cost  is  included and the scrubbing medium  is  soda
ash.  As  with  spray scrubbers, The Cost Digest provides  cost
curves  for TCI (in terms of gas flow rate.  The  following
points  were  selected  from the curves:25
       Gas Flow Rate  facfml  TCI  (March  1990  dollars!
               41,000                  1,260,000
               82,000                  1,575,000
              124,000                  1,820,000
              165,000                  1,995,000
Using linear regression, the following capital cost equation
was derived  (R2 = 0.98):

      TCIun_tp = Gas Flow Rate (acfm) x 5.918 + 1,052,973(3.4)

As with spray  scrubbers, this equation corresponds  to  an SO2
concentration  of  1,474 ppmv.  A capital cost  multiplier
factor  equation was derived for tray and packed-bed scrubber
systems as well.  At  1,474 ppmv SO2, the multiplier factor
would be  1.0;  at  253  ppmv SO2, it would be 0.839.   Using
linear  regression, the following capital cost multiplier
factor  equation was derived (R2 = 0.98):

        TCImf_tp = 0.0001319 x SO2 cone, (ppmv) + 0.806  (3.5)

Therefore, the TCI for tray and packed-bed scrubbers is
calculated as  follows:

                 TCI_tp = TCIun_tp x TCImf_tp            (3.6)
     3.3.1.3  Venturi Scrubbers.  The cost algorithms  for
venturi scrubbers are based on carbon steel construction
with a clarifier  for wastewater treatment and solids
removal.  For stainless steel construction, the capital
costs are increased by 134 percent.  The Cost Digest
provides cost curves for total capital investment in terms
of gas flow rate.  The following points were  selected  from
the curves:26
                            E-23
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       Gas Flow Rate facfm)   TCI  (March 1980 dollars)
              10,000                    110,000
              20,000                    190,000
              30,000                    250,000
              40,000                    300,000
              50,000                    350,000
              60,000                    400,000
              70,000                    450,000
              80,000                    500,000
              90,000                    550,000
             100,000                    600,000
Using linear regression, the following capital cost equation
was derived:

        TCI_ven = Gas Flow Rate  (acfm) x 5.261 +  80,667   (3.7)

Secondary lead smelters do not use venturi scrubbers to
control SO2 emissions; therefore, SO2 concentration is not
considered in the estimated capital cost of a venturi
scrubber.
3.3.2  Annual Costs
     The annual operating cost algorithms for scrubbers were
developed in a similar manner to those for capital costs.
Annual capital recovery is determined using a 15-year life
and a 7 percent annual interest rate.25  Using equation
2.10, the CRF for scrubbers is 0.110.
     3.3.2.1  Spray Scrubbers.   The annual operating cost
algorithms for spray scrubbers were developed from cost
curves in The Cost Digest.  The following points were
selected from the curves:25
                               Annual Operating Cost
       Gas Flow Rate (acfm)      (March 1980 dollars)
              41,000                    660,000
              82,000                  1,040,000
             124,000                  1,440,000
             165,000                  1,800,000
Using linear regression, the following capital cost equation
was derived (R2 = 0.98):
     As with the capital cost algorithms, this equation
corresponds to an SO2 concentration of 1,474 ppmv.
                            E-24
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       Op_un_sp = Gas Flow Rate (acfm) x 9.228 + 284,564  (3.8)
Therefore, an annual operating cost multiplier factor
equation was derived to account for different concentrations
of SO2-  At 1,474 ppmv SC>2, the annual cost multiplier
factor would be 1.0; at 253 ppmv SO2/ it would be 0.67.
Using linear regression, the following annual operating cost
multiplier factor equation was derived (R2 = 0.98):

        Op_mf_sp = 0.0002703 x S02 cone, (ppmv) + 0.602  (3.9)

Therefore, the total annual operating cost for a spray
scrubber is estimated as follows:
                T_op_sp = Op_un_sp x Op_mf_sp          (3.10)

     3.3.2.2  Tray and Packed-Bed Scrubbers.  The annual
operating cost algorithms for tray and packed-bed scrubbers
were developed from cost curves in The Cost Digest.  The
following points were selected from the curves:25
                               Annual Operating Cost
       Gas Flow Rate facfnO     (March 1980 dollars)
              41,000                    594,000
              82,000                    936,000
             124,000                  1,296,000
             165,000                  1,620,000
Using linear regression, the following capital cost  equation
was derived (R2 = 0.98):
       Op_un_tp = Gas Flow Rate (acfm) x 8.305 + 256,107(3.11)

     As mentioned in section 3.3.2.1, this equation
corresponds to an SO2 concentration of 1,474 ppmv.
Therefore, an annual operating cost multiplier factor
equation was derived to account for different concentrations
of S(>2.  At 1,474 ppmv SO2 / the annual cost multiplier
factor would be 1.0; at 253 ppmv SO2, it would be 0.588.
Using linear regression, the following annual operating cost
multiplier factor equation was derived (R2 = 0.98):
                            E-25
-------
        Op_mf_tp = 0.0003374 x SO2 cone, (ppmv) + 0.503  (3.12)


Therefore, the total annual operating cost for tray and
packed-bed scrubbers is estimated as follows:

                T_op_tp = Op_un_tp x Op_mf_tp          (3.13)

     3.3.2.3  Venturi Scrubbers.  The annual operating cost
algorithms for venturi scrubbers were developed from cost
curves in The Cost Digest.   Annual operating cost curves for
low-energy [10 inches of water (in. H2O)], medium-energy (20
in. H2O), and high-energy (40 in. H20) systems in terms of
gas flow rate is provided.26
     The following points were selected from the low-energy
cost curves:
                               Annual Operating Cost
       Gas Flow Rate facfm)      (March 1980 dollars)
              10,000                     40,000
              20,000                     63,000
              30,000                     79,000
              40,000                     92,000
              50,000                    110,000
              60,000                    120,000
              70,000                    130,000
              80,000                    140,000
              90,000                    150,000
             100,000                    160,000

Using linear regression, the following capital cost equation
was derived (R2 = 0.98):

       Op_ven_l = Gas Flow Rate (acfm) x 1.284 + 37,800 (3.14)
                            E-26
-------
     The following points were selected  from the medium-
energy cost curves:
                               Annual Operating Cost
       Gas Flow Rate facfm)     (March 1980 dollars)
               10,000                     50,000
               20,000                     78,000
               30,000                     92,000
               40,000                    120,000
               50,000                    140,000
               60,000                    155,000
               70,000                    180,000
               80,000                    190,000
               90,000                    200,000
              100,000                    210,000

Using linear regression, the following equation was derived
(R2 = 0.98) :

       Op_ven_m = Gas Flow Rate (acfm) x 1.805 + 42,200 (3.15)

     The following points were selected  from the high-energy
cost curves:
                               Annual Operating Cost
       Gas Flow Rate facfm)     (March 1980 dollars)
               10,000                     60,000
               20,000                     90,000
               30,000                    120,000
               40,000                    160,000
               50,000                    190,000
               60,000                    200,000
               70,000                    240,000
               80,000                    260,000
               90,000                    290,000
             100,000                    300,000

Using linear regression, the following equation was derived
(R2 = 0.98):

            Annual     Gas
           Operating = Flow  (acfm) x 2.733 + 40,667     (3.16)
              Cost      Rate

     The annual operating cost of a venturi scrubber
operating at a pressure drop less than 15  in. H2O is

                            E-27
-------
estimated with the low-energry cost equation (equation 3.14).
The annual operating cost of venturi scrubbers with pressure
drops between 15 and 30 in. H2<5 is estimated using the
medium-energy cost equation (equation 3.15), and the annual
operating cost of venturi scxubbers with greater than 30 in.
H2O pressure drop is estimated using the high-energy cost
equation (equation 3.16).  Secondary lead smelters do not
use venturi scrubbers to control SO2 emissions; therefore,
SO2 concentration is not considered in the estimated annual
cost of a venturi scrubber.  The annual operating costs for
venturi scrubbers are shown in figure 1.

4.0  HOODS
     Process fugitive emissions sources at secondary lead
smelters that will likely require hoods include:
     •    Smelting furnace charging hoppers, chutes, and
          skip hoists;
     •    Smelting furnace lead taps and molds;
     •    Smelting furnace slag taps and molds;
     •    Refining kettles;
     •    Drying kiln transition pieces; and
     •    Agglomerating furnace process vents and product
          taps.

     Normally, the cost of a hood is included as part of the
auxiliary equipment cost for a control device (e.g.,
afterburner or scrubber).  However, because of the large
number of potential sources that may require hooding and the
various control devices to which hoods may be vented, the
capital and the annualized costs associated with hooding are
estimated separately from the control devices.  The hood
cost estimation methodology is based on the methodology
presented in Estimating Costs of Air Pollution Control.27
The estimated costs are given in August 1988 dollars but are
                            El-2 8
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converted to December 1991 dollars using the Chemical
Engineering plant cost indices presented in table 3  (above)
4.1  HOOD COSTING METHODOLOGY
     The methodologies for estimating costs for circular
hoods and for rectangular hoods are presented separately.
Rectangular hoods are costed for all process fugitive
sources described above except refining kettles (for which
circular hoods are costed).  The cost of rectangular hoods
is estimated as:28
           Price
 [December
  1991
 dollars
+ 39.0
         1.80,  /TO/TI-M      (4-1)
where:
     L    =    hood length (ft)
     111  =    August 1988 plant cost index (344)15
     A hood length-to-width (L/W) ratio of 1.0 is associated
with equation 4.1.  It is likely that many of the
rectangular hoods at secondary lead smelters will have
higher L/W ratios than 1.0; however, this will not
significantly affect the cost estimates for hoods overall
and should be within a 30-percent margin of error.
     The cost of circular hoods will be estimated as:28
           Price
December
  1991
dollars
+ 47.1
         1.62, ,To/T11x     (4.2)
where:
     dh   =    hood diameter (ft)
     The hood cost equations are for 3/16-inch carbon steel
hoods.28  A multiplier of 4.4 is used to increase hood costs
in order to account for stainless steel construction for
corrosive gas streams (e.g., hopper hood exhaust).29
     The cost of a hood is dependent on the length or
diameter of the hood.  Because of the lack of information on
                            E-30
-------
recommended hood sizes for the various process fugitive
sources at secondary lead smelters, default lengths and
diameters were established.  Table 10 presents the default
hood lengths, widths, and diameters for the various process
fugitive sources.
4.2  FLOW RATE CALCULATIONS
     In order to estimate the fan and duct work costs for
controlling hooded sources, the volumetric flow rate of
exhaust from each source must be estimated.  The flow rate
from a hood must be high enough to ensure adequate capture
of emissions.  The recommended hood face velocity for
sources at secondary lead smelters is 300 ft/min.30
     Because of the lack of information about actual face
velocities at existing facilities, it is assumed for costing
purposes that existing facilities are using face velocities
of 300 ft/min to control hooded process fugitive emission
sources.  The volumetric flow rate is determined by
multiplying the face velocity (300 ft/min) by the hooded
area.  Recommended hood areas and volumetric flow rates for
controlling process fugitive sources are shown in table 10
(above).

5.0  DUCT WORK COSTING PROCEDURES
     The design and costing procedures for duct work were
derived from Estimating Costs of Air Pollution Control.31
The cost of 300 feet of primary duct work is estimated for
each control system.  The cost of 20 feet of secondary duct
work is estimated for each hooded process fugitive emission
source.  The cost of 40 feet of secondary duct work is
estimated for each enclosed and controlled fugitive dust
emissions source.
                            E-31
-------
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5.1  DESIGN PARAMETERS
     The cost of duct work is related to the total weight of
the duct work.  For costing purposes, the duct work at
secondary lead smelters is assumed to be round.  In order to
calculate the weight of duct work, the diameter and the
length must be established.  The diameter of duct work is
calculated by the following relationship:31
               D_duct = 13.54  (flow/V_duct)
0.5         (5.1)
where:
     D_duct    =    diameter of duct work  (in.)
     flow      =    flow rate of waste gas (acfm)
     V_duct    =    velocity of waste gas  in duct  (ft/min)

     The waste gas flow rate from furnaces is obtained from
the model plants database.  The waste gas  flow rate from
hooded process fugitive sources is obtained from table 10.
The waste gas flow rate from enclosures is determined
assuming 15 air changes per hour.  A velocity of
5,000 ft/min of waste gas in the duct work (V_duct) is used
for the ductwork design procedures.31
     The weight of duct work is calculated as:31

          W_duct = 32 x (D_duct/12) x L_duct x 1.225     (5.2)

where:
     W_duct    =    weight of duct work (Ib)
     L_duct    =    length of duct work (ft)
The 1.225 multiplier factor is a stiffener factor for
streams at a pressure drop between 10 and  20 in. H2O.31
5.2  COSTING PROCEDURES
5.2.1  Capital Cost
     The cost per pound of duct is different for various
duct diameters.  The cost of duct work with a diameter
between 2 and 4 feet is calculated as:31

               Duct_C = W_dUGt X 1.03 X  (12/16)          (5.3)
                            E-33
-------
The cost of duct work greater than 4 feet in diameter is
calculated as:31
               Duct_C = W_duct X 0.97 X  (12/16)          (5.4)

where:
     Duct_C    =    duct cost (December 1991 dollars)
     16        =    February 1989 plant cost index (352.4)16

These cost equations are for straight,  1/4-inch carbon steel
duct work.  For corrosive exhaust streams, a stainless steel
multiplier of 4.4 is applied.  Because of the high
particulate loading of exhaust streams at secondary lead
smelters, elbows and sharp turns in duct work are
undesirable.  Therefore, the number of elbows and sharp
turns are minimized and no additional duct work costs for
elbows are included in the estimated costs for duct work.
5.2.2  Annual Cost
     The annual cost for duct work is the annual capital
recovery.  The CRF for duct work is based on a 10-year
equipment life and a 7 percent annual interest rate.  Using
equation 2.10, the CRF for cluct work is 0.142.

6.0  WET SUPPRESSION
     Control of emissions by wet suppression will likely be
required for some fugitive dust emission sources at
secondary lead smelters.  Wet suppression costs are based on
wetting fugitive dust sources with water only, without
chemical surfactants.
6.1  DESIGN PARAMETERS
     The cost elements for wet suppression are based on the
total area that needs to be wetted and water usage.  For
areas that store piles of materials (e.g., the battery
breaking area, the materials storage area), the surface area
to be wetted is considered equivalent to the area
represented in the model plants database  (in square meters).
The rate of water application is estimated to be
7,500 liters per hectare  (ha) of treated surface area per
                            E-34
-------
day (800 gallons per acre per day) , with wetting performed
365 days per year.  This rate is based on wetting the area
to a depth of 0.75 millimeters per day (0.03 in. /day).
However, because all secondary lead smelters are required to
collect and treat storm water runoff, it is assumed that
captured storm water will supply 75 percent of the water
applied.  Therefore, the water usage rate for costing
purposes is assumed to be only 1,875 liters per hectare per
day (200 gallons per acre per day) .
     The surface area to be wetted is calculated as:

                 SA = SAm x (1 ha/10,000 m2)             (6.1)

where :
     SA   =    surface area to be wetted (ha)
     SAm  =    area to be wetted  (m2)
6.2  COSTING PROCEDURES
     Capital costs were considered negligible for the
installation of an automated sprinkler system.  The cost of
wet suppression is based solely on water usage.  The cost of
water is estimated at $1.057 per thousand liters ($4.00 per
thousand gallons) in Fall 1991 dollars.32
     The cost of wet suppression is therefore:

          Annual             Water
        Operating = SA (ha) x Usage (liter/ha/day)
           Cost              Rate
                                                       (6.2)
                    x 365      x WatSr ($/l,000 liter)
                          yj.    COSt
7.0  VACUUM SWEEPERS
     Control of emissions by vacuum sweeping will likely be
required of some fugitive dust emissions sources at
secondary lead smelters.
                            E-35
-------
7.1  COSTING PROCEDURES
7.1.1  Capital Cost
     The capital cost of a regenerative vacuum sweeper based
on August 1993 dollars is $47,000, delivered.33
7.1.2  Annual Cost
     The annual cost for vacuum sweeping includes the annual
capital recovery and the annual labor cost associated with
operating the sweeper.  The CRF for a sweeper is based on a
10-year equipment life and a 7 percent annual interest rate.
Using equation 2.10, the CRF for a sweeper is 0.142.
     Operating labor for a sweeper is estimated at 1 hour
per day per affected area, using an operating labor rate of
$13.90 per hour.
                            E-36
-------
8.0  REFERENCES
1.   U. S. Environmental Protection Agency.  Office of Air
     Quality Planning and Standards.  OAQPS Control Cost
     Manual.  EPA 450/3-90-006.  January 1990.

2.   Memorandum from Pelt, R., Radian Corporation to George
     Streit, EPA/ISB.  June 15, 1992.  Development of
     Databases for Existing and New Secondary Lead Smelters
     (Final).

3.   Reference 1.  pp. 3-1 to 3-66.

4.   U. S. Environmental Protection Agency.  Office of Air
     Quality Planning and Standards.  Municipal Waste
     Combustors - Background Information for Proposed
     Standards:  Cost Procedures.  EPA 450/3-89-27.  August
     1989.  pp. 3.7-2 to 3.7-3.

5.   U. S. Environmental Protection Agency.  Office of Air
     and Radiation.  EAB Control Cost Manual.  EPA 450/5-87-
     001A.  February 1987.  p. 3-2.

6.   Resources Consultants, Inc.  Determination of
     Destruction Efficiency of Total Gaseous Non-Methane
     Organic Emissions Conducted on Blast Furnace No. 4
     Flash Tank Afterburner.  Sanders Lead Company.  Troy,
     Alabama.  July 27, 1990.

7.   Roy F. Weston, Inc.  Secondary Lead Smelters VOC
     Screening Sample Test Results.  Work Order No. 06709-
     001-023.  September 1, 1992.

8.   Handbook of Chemistry and Physics.  CRC Press, Inc.
     1988.  p. D-119.

9.   Felder, R. M. and R. W. Rousseau, Elementary Principles
     of Chemical Principles, Second Edition.  1986.  p. 612.

10.  Chemical Engineering Plant Cost Index.  Chemical
     Engineering.  Volume 99, No. 3.  March 1992.

11.  Chemical Engineering Plant Cost Index.  Chemical
     Engineering.  Volume 95, No. 10.  July 18, 1988.

12.  Chemical Engineering Plant Cost Index.  Chemical
     Engineering.  Volume 98, No. 9.  September 1991.

13.  Chemical Engineering Plant Cost Index.  Chemical
     Engineering.  Volume 93, No. 22.  November 24, 1986.

14.  Chemical Engineering Plant Cost Index.  Chemical
     Engineering.  Volume 93, No. 23.  December 8, 1986.
                            E-37
-------
15.  Chemical Engineering Plant Cost Index.  Chemical
     Engineering.  Volume 95, No. 15.  October 24, 1988.

16.  Chemical Engineering Plant Cost Index.  Chemical
     Engineering.  Volume 96, No. 5.  May 1989.

17.  Chemical Engineering Plant Cost Index.  Chemical
     Engineering.  Volume 95, No. 6.  May 23, 1988.

18.  Chemical Engineering Plant Cost Index.  Chemical
     Engineering.  Volume 87, No. 14.  July 14, 1980.

19.  Chemical Engineering Plant Cost Index.  Chemical
     Engineering.  Volume 96, No. 3.  March 1989.

20.  Producer Price Indexes Data for February 1992.
     U. S. Department of Labor.  March 1992.  p. 192.

21.  Reference 20.  p. 189.

22.  Survey of Current Business.  Volume 72, No. 5.  May
     1992.  p. S-12.

23.  Monthly Energy Review.  March 1992.  p. 105.

24.  U. S. Environmental Protection Agency.  Office of
     Environmental Engineering and Technology.  The Cost
     Digest:  Cost Summaries of Selected Environmental
     Control Technologies.  EPA-600/8-84-010.  October 1984.
     92 p.

25.  Reference 24.  pp. 64-81.

26.  Reference 24.  pp. 58-63.

27.  Vatavuk, W. M.  Estimating Costs of Air Pollution
     Control.  Lewis Publishers.  1990.

28.  Reference 27.  pp. 88-93.

29.  Reference 27.  p. 77.

30.  U. S. Environmental Protection Agency.  Inspection and
     Operating and Maintenance Guidelines for Secondary Lead
     Smelter Air Pollution Control.  Contract No.
     68-03-2924.  December 1983.  p. 52.

31.  Reference 27.  pp. 73-73.

32.  Reference 1.  Supplemental Chapter 9  (1992), p. 9-51.

33.  Telecon.  Cavender, K., Radian Corporation, with K.
     Young, Tymco Incorporated.  August 10, 1993.
                            E-38
-------
        ATTACHMENT  1

 EXAMPLE DESIGN AND COSTING
SPREADSHEETS FOR AFTERBURNERS
            E-39
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       ATTACHMENT 2

EXAMPLE DESIGN AND COSTING
SPREADSHEETS FOR SCRUBBERS
           E-44
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Scrubber ID
Scrubber Type
Waste Gas Flo
Pressure Drop
Percent Moistu
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                                       E-45
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     ATTACHMENT 3

 DETAILED DERIVATIONS
OF SCRUBBER ALGORITHMS
         E-49
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                      Scrubber Costing
Source:   The cost Digest:  Cost summaries of selected
          Environmental Control Technologies.
          EPA-600/8-84-00.  October 1984
Spray Scrubbers

     The reference has cost curves for flue gas
desulfurization (FGD) systems for total capital investment
(TCI) and annual operating cost in terms of total gas flow-
rate.  The limestone process used with industrial coal-fired
boilers appears to be the most applicable for estimating the
cost of spray scrubber systems and secondary lead smelters.

     The reference states the following design factors for
the lime/limestone process:

     •    Cost estimates are for new units;
     •    Size range of 30 x 106 - 400 x 106 Btu/hr boiler;
     •    Coal contains 3.5% sulfur and has heating value of
          11,800 Btu/lb;
     •    System designed for 90% SC>2 removal;
     •    No process redundancy except for spare pumps;
     •    No stack gas reheat;
     •    Operating capacity factor is 0.60;
     •    PM removal costs not included;
     •    Cost of fan is included;
     •    Costs include duct work for FGD unit;
     •    No gas bypass provisions;
     •    15-Year life;
     •    Midwest location;
     •    Scrubber is turbulent contact absorber (TCA)
                            E-50
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          Solids disposal is off-site landfill; $15/ton at
          50% solids; capital costs include clarifiers and
          filters but not landfill site preparation.
Spray Scrubbers - TCI


     From the cost curves:


               TCI                          Gas  Flow Rate
	(March 1980 Dollars)	          	(acfm)

            1,800,000                            41,000
            2,250,000                            82,000
            2,600,000                          124,000
            2,850,000                          165,000


Using linear regression:


TCI (March 1980 $) = Gas Flow Rate (acfm) x 8.454 +

1,504,247


Spray Scrubbers - Annual Operating cost
   Annual Operating Cost                    Gas Flow Rate
    (March 1980 Dollars)  	             	(acfm)

         6,600,000                              41,000
         1,040,000                              82,000
         1,440,000                             124,000
         1,800,000                             165,000
Using linear regression:


Annual Operating Cost (March 1980 $) = Gas Flow Rate  (acfm)
                                       X 9.228 + 284,564


Spray Scrubbers - 803 Correlations


     The SOg concentration in the exhaust affects the

capital and annual operating cost of a scrubber system.  The

reference provides capital and annual operating costs at

different coal sulfur contents.  From this information, an       \


                            E-51
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SO2 concentration in the exhaust and cost impacts  can be
determined  at  different SC>2 limits to vary the costs  in
terms of SO2 concentrations.

8O2 Concentration in Exhaust (base case)

     5.5% sulfur in coal fired to the boiler is the base
case.  The  803 concentration in the exhaust is calculated as
follows:

Select firing  rate and exhaust flow:

     •    200  x 106 Btu/hr firing rate; and
     •    82,000 acfm exhaust flow.

Total Amount of SC>2 produced per year:


  200 x 10* Btu v    Ib coal  v  3.5 Ib S   „  Ib-mol S „ 1 lb-mol SO2  8760 hr
  —i — • . i i . i. — -i  i A   ii .. i.i •. iii •. ii—• i X  - — - _- __— -•   X ...-- _ _ -- ...- 	  X	_—	- .. _- - _ 	 X -	— _-
      hr        11,800 Btu   100 Ib coal  32.06 Ib S    1 lb-mol S     yr
= 162,090  lb-mol  S02/yr

Total Exhaust Flow:
     •    Assumed  exhaust temperature = 25 °C at scrubber
          inlet; and
     •    Molar volume  at 25 °C = 359.05 ft3/lb-mol.

 molar volume @ 25° C = 359.05 X  273 + 25 = 391.93 ft3/lb-mol
                                    <& / J
          82,000 ft3  x   lb-mol   x 60 min x 8760 hr
                       391.93 ft3     hr        yr
= 109,966,576 lb-mol  total  exhaust/yr

                             E-52
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SQ2_J3oncentration in Exhaust (base easel

        162,090 Ib-mol SO,/yr       i x io6
     109,966, 576 Ib-mol total/yr X ^^ ' 1474 Ppmv SO=



Spray Scrubbers - Multiplier Factors
          1474 ppmv S(>2 corresponds to a coal sulfur content
          of 3.5%.

          The reference indicates that a coal sulfur content
          of 0.6 percent would decrease the TCI by 15.3% and
          would decrease the annual operating cost by 33.0%.
Correlations between sulfur content and multiplier factors:
                   SO2                      Multiplier
 Coal Sulfur  Concentration   Multiplier    Factor for
   Content      in Exhaust    Factor for      Annual
                  (ppmv)          TCI         Operating

0.6
3.5

253
1474

0.847
1.0
Cost
0.67
1.0
Using linear regression:
TCI Multiplier factor = 0.0001253 x SO2 concentration  (ppmv)
                        + 0.815

Annual operation multiplier factor = 0.0002703 x SO2
                                     concentration  (ppmv)
                                     + 0.602
Tray Scrubbers


     Sodium alkali scrubber systems used to control SO2 from

individual boilers appear to be applicable for estimating

the cost of tray scrubbers at secondary lead smelters.
                            E-53
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     The design factors are the same as for spray  scrubbers
except:


     •    The scrubber is a tray tower type;
     •    Waste liquor disposal is included; and
     •    Sodium alkali is soda ash.


Tray Scrubbers - TCI


For the cost curves:
               TCI                         Gas Flow Rate
       (March  1980  dollars)                     facfm)

            1,260,000                          41,000
            1,575,000                          82,000
            1,820,000                         124,000
            1,995,000                         165,000

Using linear regression:
TCI  (March 1980 dollars) = Gas Flow Rate  (acfm)
                           X 5.918 + 1,052,973
Tray Scrubbers - Annual Operating Cost
      Annual Operating Cost                Gas Flow Rate
       fMarch  1980 dollars)                     facfm)

              594,000                           41,000
              936,000                           82,000
            1,296,000                         124,000
            1,620,000                         165,000
Using linear regression:
Annual Operating Cost (March 1980 dollars) = Gas Flow Rate
                                              (acfm) x 8.305
                                             + 256,107
                            E-54
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Trav Scrubbers - Multiplier Factor
          1474 ppmv SO2 corresponds to a coal sulfur content
          of 3.5%

          The reference indicates that a coal sulfur content
          of 0.6 percent would decrease the TCI by 16.1% and
          would decrease the annual operating cost by 41.2%.
Correlations between sulfur content and multiplier factors:
                   SC>2                        Multiplier
              Concentration    Multiplier     Factor for
 Coal Sulfur    in Exhaust    Factor for        Annual
 Content (%1      fppmv)           TCI	   Operating Cost

     0.6            253          0.839          0.588
     3.5           1474          1.0            1.0


Using linear regression:


TCI multiplier factor = 0.0001319 x SO2 concentration (ppmv)
                        + 0.806

Annual Operating multiplier factor = 0.0003374 x SO2
                                     concentration (ppmv)
                                     + 0.503
Venturi Scrubbers
          Costs based on carbon steel scrubber with
          clarifier for wastewater treatment and solids
          removal.

          For stainless steel construction, increase capital
          costs by 134 percent and increase annual operating
          costs by 24 percent.
TCI
     The reference provides graphs with cost correlations
for TCI in terms of gas flow rate.
                            E-55
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               TCI                        Gas  Flow Rate
       (March  1980 dollars!                     facfnn

             110,000                           10,000
             190,000                           20,000
             250,000                           30,000
             300,000                           40,000
             350,000                           50,000
             400,000                           60,000
             450,000                           70,000
             500,000                           80,000
             550,000                           90,000
             600,000                         100,000


Using linear regression:
TCI (March 1980 dollars) = Gas Flow Rate  (acfm) x 5.261
                           + 80,667
Venturi Scrubbers - Annual Operating Costs


     The reference provides annual operating cost curves for
low energy (10 inches H2O pressure drop), medium energy  (20
inches H2O pressure drop), and high energy  (40 inches H2O
pressure drop) systems.


From the cost curves:


Low energy systems (10 inches H2O pressure drop; 95 percent
efficiency)
     Annual Operating Costs                Gas  Flow Rate
       (March  1980 dollars!                     facfnn

              40,000                          10,000
              63,000                          20,000
              79,000                          30,000
              92,000                          40,000
             110,000                          50,000
             120,000                          60,000
             130,000                          70,000
             140,000                          80,000
             150,000                          90,000
             160,000                         100,000
                            E-56
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Using linear regression:
Annual Operating Cost (March 1980 dollars)
   Gas Flow Rate
   (acfm)  x 1.284
   + 37,800
From the cost curves:
Medium Energy Systems (20 inches H2<3 pressure drop;
99 percent efficiency)
     Annual Operating Costs
       (March 1980 dollars)

              50,000
              78,000
              92,000
             120,000
             140,000
             155,000
             180,000
             190,000
             200,000
             210,000

Using linear regression:
Gas Flow Rate
    (acfm)

    10,000
    20,000
    30,000
    40,000
    50,000
    60,000
    70,000
    80,000
    90,000
   100,000
Annual Operating Cost/March 1980 dollars)
  Gas Flow Rate
  (acfm)  x 1.805
  + 42,200
                            E-57
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From the Cost curves:


High Energy Systems  (40 inches H^O pressure drop;
99.9 percent efficiency
     Annual Operating Costs
       (March  1980 dollars)

              60,000
              90,000
             120,000
             160,000
             190,000
             200,000
             240,000
             260,000
             290,000
             300,000

Using linear regression:
Gas Flow Rate
    (acfm)

    10,000
    20,000
    30,000
    40,000
    50,000
    60,000
    70,000
    80,000
    90,000
   100,000
Annual Operating Cost (March 1980 dollars) = Gas Flow Rate
                                             (acfm) x 2.733
                                             + 40,667
                            E-58
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-452/R-94-024b
2.
4. TITLE AND SUBTITLE
Secondary Lead Smelting - Background Inforr
Document for Proposed Standards - Volume 2
Appendices
7. AUTHOR(S)
3. RECIPIENT'S ACCESSION NO
5. REPORT DATE
nation -June 1994

_ 6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME ANO ADDRESS
Emission Standards Division (MD-13)
Office of Air Quality Planning and Standarc
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27"
12. SPONSORING AGENCY NAME AND ADDRESS
Director
1C. PROGRAM ELEMENT NO
Is 11. CONTRACT/GRANT NO
Ju 68-D1-0117
13. TYPE OF REPORT AND PERIOD COVERED
Final
Office of Air Quality Planning and Standards 14. SPONSORING AGENCY CODE
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina
15. SUPPLEMENTARY NOTES
16. ABSTRACT
Under the authority of the 1990 Clean Air Act Amendments, a national
emission standard for hazardous air pollutants (NESHAP) is proposed to control
emissions from secondary lead smelters. This document contains the appendices
for the background information on hazardous air pollutant emissions (HAP) from
secondary lead smelters contained in EPA-450/R-94-024a.
17.
KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
Air Pollution
Secondary Lead Smelters
Hazardous Air Pollutants
NESHAP
18. DISTRIBUTION STATEMENT
Release Unlimited
b. IDENTIFIERS/OPEN ENDED TERMS
Hazardous Air Pollutants
Secondary Lead Smelters
19. SECURITY CLASS /This Report/
Unclassified
20. SECURITY CLASS / This page)
Unclassified
c. COSATI Field/Group

21 NO. OF PAGES
322
22 PRICE
EPA Form 2220-1 (R«v. 4-77)    PREVIOUS EDITION is OBSOLETE
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