United States      Office of Air Quality         EPA-450/3-89-27a
           Environmental Protection  Planning and Standards        August 1989
           Agency        Research Triangle Park, NC 27711
           __
vvEPA     Municipal Waste
           Combustors-
           Background
           Information for
           Proposed Standards:
           Cost Procedures
                                 This document is printed on recycled paper.

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        MUNICIPAL WASTE COMBUSTORS --
         BACKGROUND  INFORMATION FOR
    PROPOSED STANDARDS:   COST PROCEDURES
                FINAL  REPORT
                Prepared for:

             Michael G. Johnston
    U.S. Environmental  Protection  Agency
      Industrial  Studies Branch (MD-13)
Research Triangle Park,  North  Carolina 27711
                Prepared  by:

             Radian Corporation
     3200  E.  Chapel  Hill  Rd./Nelson Hwy.
            Post Office Box 13000
               AUGUST 14,  1989
                       U.S. Environment '. "•"<      "• -'•'•••
                       Region 5, Library
                       77 West Jack:';:•! :  •
                       Chicago, IL  606^-,-o

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                            DISCLAIMER
This report has been reviewed by the Emission Standards Division
of the Office of Air Quality Planning and Standards, EPA, and
approved for publication.  Mention of trade names or commercial
products is not intended to constitute endorsement or
recommendation for use.   Copies of this report are available
through the Library Services Office (MD-35), U.S. Environmental
Protection Agency, Research Triangle Park NC 27711, or from
National Technical Information Services, 5285 Port Royal Road,
Springfield VA 22161.
                                11

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                             TABLE OF CONTENTS


Section                                                               Page

1.0  INTRODUCTION	    1-1

2 .0  PROCEDURES FOR NEW PLANTS	    2.1-1

2.1  COMBUSTORS AND BALANCE OF PLANT	    2.1-1

     2.1.1  Modular Units	    2.1-2

          2.1.1.1  Overview of Technology	    2.1-2
          2.1.1.2  Capital  Cost Procedures	    2.1-2
          2.1.1.3  Operating Cost Procedures	    2.1-4

     2.1.2  Mass Burn Units	    2.1-5

          2.1.2.1  Overview of Technology	    2.1-5
          2.1.2.2  Capital  Cost Procedures	    2.1-6
          2.1.2.3  Operating Cost Procedures	    2.1-6

     2.1.3  RDF Units	    2.1-9

          2.1.3.1  Overview of Technology	    2.1-9
          2.1.3.2  Capital  Cost Procedures	    2.1-11
          2.1.3.3  Operating Cost Procedures	    2.1-11

     2.1.4  FBC Units	    2.1-12

          2.1.4.1  Overview of Technology	    2.1-13
          2,1.4.2  Capital  Cost Procedures	    2.1-13
          2.1.4.3  Operating Cost Procedures	    2.1-13

References	    2.1-20

? 2  cLECTROSTATIC PRECIPITATORS	    2.2-1

     2.2.1  Overview of Technology	    2.2-1
     2.2.2  Capital Cost Procedures	    2.2-1

          2.2.2.1  Direct Costs	    2.2-1
          2.2.2.2  Indirect Costs and Other Costs	    2.2-8

     2.2.3  Operating Cost  Procedures	    2.2-12

References	    2.2-14
                                   iii

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                             TABLE OF CONTENTS

Section                                                               Page

2.3  DRY SORBENT INJECTION	     2.3-1

     2.3.1  Overview-of Technology.	     2.3-1
     2.3.2  Capital Cost Procedures	     2.3-2
     2.3.3  Operating Cost Procedures	     2.3-6

References	     2.3-9

2.4  SPRAY DRYING WITH EFFICIENT PARTICULATE CONTROL	     2.4-1

     2.4.1  Overview of Technology	     2.4-1
     2.4.2  Capital Cost Procedures	     2.4-1

          2.4.2.1  Direct Costs	     2.4-2
          2.4.2.2  Indirect and Other Costs	     2.4-5

     2.4.3  Operating Cost Procedures	     2.4-5

References	     2.4-10

?.5  COMPLIANCE MONITORING	     2.5-1

     2.5.1  Overview of Technology	     2.5-1

          2.5.1,1  Continuous Opacity Monitoring	     2.5-1
          2.5.1.2  Continuous S02 Monitoring	     2.5-1
          2.5.1.3  Continuous HCT Monitoring	     2.5-2
          2.5.1.4  Diluent (02/C02 Monitoring)	     2.5-3

     2.5.2  Compliance Monitoring Costs	   2.5-3

References	   2.5-5

3.0  PROCEDURES FOR EXISTING PLANTS	   3.1-1

3.1  OPERATION OF THE EXISTING COMBUSTORS	   3.1-1

3.2  COMBUSTCR MODIFICATIONS	   3.2-1

     3.2.1  Introduction	   3.2-1
     3.2.2  Capital Cost Procedures	   3.2-1
          3,2,2.1  Stoker Rehabilitation	   3.2-3
          3.2.2.2  Refractory-Wall Furnace Reconfiguration	   3.2-4
          j 2.2.3  Fuel Feeding Modifications	   3.2-4
          3.2,2.4  Underfire Air Modifications	   3.2-5
          3.2.2.5  Overfire Air Modifications	   3.2-7
          3.2.2.6  Combustion Controls and Monitors	   3.2-9
          3.2.2.7  Auxiliary Fuel Burner Installation	   3.2-10
                                     IV

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                             TABLE OF CONTENTS

Section                                                               Page

          3.2.2.8  Carbon Monoxide Profiling	   3.2-11
          3.2.2.9  Economizer for Flue Gas Temperature Control	   3.2-11

     3.2.3  Operating Cost Procedures	 3.2-12

References	   3.2-15

3.3  HUMIDIFICATION	   3.3-1

     3.3.1  Overview of Technology	   3.3-1
     3.3.2  Capital Cost Procedures	   3.3-2
     3.3.3  Operating Cost Procedures	   3.3-3

References	   3.3-6

3.4  PARTICULATE MATTER CONTROL RETROFIT	   3.4-1

     3.4.1  Installation of a New ESP	   3.4-1

          3.4.1.1  Capital Cost Procedures	   3.4-1
          3.4.1.2  Operating Cost Procedures	   3.4-1

     3.4.2  Increase in ESP Plate Area	   3.4-2

          3.4.2.1  Capital Cost Procedures	   3.4-2
          3.4.2.2  Operating Cost Procedures	   3.4-2

     3.4.3  ESP Rebuild	  3.4-3

          3.4.3.1  Capital Cost Procedures	  3.4-3
          3.4.3.2  Operating Cost Procedures	  3.4-3

References	  3.4-4

3.5  JRY SORBENT INJECTION RETROFIT	  3.5-1

     3.5.1  Overview of Technology	  3.5-1
     3.5.2  Capital Cost Procedures	  3.5-1
     3.5.3  Operating Cost Procedures	  3.5-2

References	  3.5-3

3.6  SPRAY DRYER RETROFIT	  3.6-1

     3.6.1  Overview of Technology	  3.6-1
     3.6.2  Capital Cost Procedures	  3.6-1
     3.6.3  Operating Cost Procedures	  3.6-5
                                  V

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                             TABLE OF CONTENTS

Section                                                               Page

References	  3.6-8

3.7  DETERMINATION OF RETROFIT FACTORS AND SCOPE ADDER COSTS	  3.7-1

     3.7.1  Retrofit Factors	  3.7-1
     3.7.2  Scope Adders	  3.7-1

          3.7.2.1  Ducting	  3.7-1
          3.7.2.2  Stacks	  3.7-1
          3.7.2.3  Demolition and Replacement	  3.7-3

References	  3.7-4

3.8  DOWNTIME COSTS FOR RETROFIT MODIFICATIONS	  3.8-1

     3.8.1  Procedures to Estimate Loss of Steam and
             Electricity Sales	  3.8-1

          3.8.1.1  Loss of Steam Sales	  3.8-1
          3.8.1.2  Loss of Electricity Sales	  3.8-1

     3.8.2  Procedures to Estimate Costs from Loss of Tipping
             Fees	  3.8-3

References	  3.8-4

Appendix A  COST COMPARISON BETWEEN SPRAY DRYER/FABRIC FILTER AND
              SPRAY DRYER/ELECTROSTATIC PRECIPITATOR SYSTEMS	  A-l

Appendix B  DETAILED COST EQUATIONS	  B-l
                                   VI

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LIST OF TABLES
Table
2.1-1
2.1-2

2.1-3


6.1-4

2.1-5
2.1-6

2.2-1

2,2-2

2.2-3

2.2-4

2.? 5

2.3-1

2.3-2

2.3-3

?.* 1

2.4-2

CAPITAL COSTS FOR MODULAR MWC's 	 '..
CAPITAL COSTS FOR A 860 TON/DAY MASS BURN MWC WITH
(WITHOUT) ELECTRICITY GENERATION 	
CAPITAL COSTS FOR A COARSE RDF FACILITY WITH ELECTRICITY
GENERATION (CAPACITY = 850 TONS/DAY MSW, 800 TONS/DAY
RDF) 	
PROCEDURE FOR ESTIMATING CAPITAL COSTS FOR NEW FBC'S
(DECEMBER 1987 DOLLARS) 	
ANNUAL OPERATING COST PROCEDURES FOR NEW FBC'S 	
PROCEDURE FOR ESTIMATING ANNUAL OPERATING COSTS FOR
FBC'S (DECEMBER 1987 DOLLARS) 	
VENDOR QUOTES FOR ESP EQUIPMENT COSTS (IN 1000$
AUGUST 1986) 	
SPECIFIC COLLECTION AREA (SCA) REPORTED BY THE ESP
MANUFACTURERS 	
AVERAGE SPECIFIC COLLECTION AREA (SCA) CALCULATED FROM
THE MANUFACTURERS' DATA 	
COST PROCEDURES FOR ESTIMATING CAPITAL COSTS FOR ESP'S
ON NEW PLANTS 	
COST PROCEDURES USED TO ESTIMATE ANNUAL OPERATING COSTS
FOR ESP'S ON NEW UNITS 	
PROCEDURES FOR ESTIMATING CAPITAL COSTS FOR DRY SORBENT
INJECTION 	 	 , 	 	 	
ANNUAL OPERATING COST PROCEDURES FOR DRY SORBENT
INJECTION FOR NEW MWC's 	
ANNUAL OPERATING COST PROCEDURES FOR FABRIC FILTERS
FOR NEKf MWC ' s 	 	
VENDOR QUOTES FOR SPRAY DRYER/FABRIC FILTER TOTAL
CAPITAL COSTS (IN 1,000$ AUGUST 1986) 	
CAPITAL COST PROCEDURES FOR SD/FF FOR NEW MWC's 	
Page
2.1-3

2.1-7


2.1-10

2.1-14
2.1-15

2.1-17

2.2-2

2.2-5

2.2-6

2.2-11

2.2-13

2.3-4

2.3-7

2.3-8

2.4-3
2.4-6
     vii

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LIST OF TABLES
Table
2.4-3

2.5-1
3.2-1
3.3-1
3.3-2
3.6-1

3.6-2
3.6-3

3.7-1

3.8-1

ANNUAL OPERATING COSTS PROCEDURES FOR SPRAY DRYER/FABRIC
FILTER FOR NEW MWC's 	
CONTINUOUS MONITORING COST SUMMARY (DECEMBER 1987 DOLLARS)
O&M COST INPUTS (DECEMBER 1987 DOLLARS) 	
CAPITAL COST PROCEDURES FOR HUMIDIFICATION 	
OPERATING AND MAINTENANCE COSTS FOR HUMIDIFICATION,, ,
VENDOR QUOTES FOR SPRAY DRYER DIRECT CAPTIAL COSTS
(in 1000$ August 1988) 	
CAPITAL COST PROCEDURES FOR SPRAY DRYERS 	
ANNUAL OPERATING COSTS PROCEDURES FOR STAND-ALONE SPRAY
DRYERS FOR NEW MEW' s 	 	 	
SITE ACCESS AND CONGESTION FACTORS FOR RETROFITTING
APCD EQUIPMENT AT EXISTING PLANTS 	
DOWNTIME REQUIREMENTS IN MONTHS 	
Page

2.4-7
2.5-4
3.2-13
3.3-4
3.3-5

3.6-2
3.6-3

3.6-6

3.7-2
3.8-2
    viii

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                              LIST OF FIGURES

Figure                                                                Page

2.2-1     Correlation of ESP equipment costs (in August 1986
           dollars) from ESP manufacturers and total plate area...    2.2-3

2.2-2     Relationship between ESP manufacturers' specific
           collection area and particulate matter removal	    2.2-7

2.2-3     Correlation of ESP purchase equipment costs with total
           plate area for modular ESP's	    2.2-9

2.2-4     Relationship between specific collection area and
           particulate matter removal for modular ESP's	    2.2-10

2.4-1     Capital  cost estimates of an SD/FF for a Model  MB
           facility, and RDF facility	    2.4-4

3.6-1     Correlation of SD direct capital costs (in August 1988
           dollars) from the SD manufacturers and flue gas
           flowrate	    3.6-4
                                  IX

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                              1.0  INTRODUCTION

     This report documents the development of cost procedures for costing new
and existing municipal waste combustor (MWC) facilities, associated heat
recovery equipment, humidification equipment, air pollution control devices
(APCD's) for the reduction of particulate matter (PM) and acid gas emissions,
and continuous emission monitoring equipment.  Costs presented in this report
are divided into three major cost categories:

          o    Capital Costs;
          o    Operating and Maintenance (O&M) Costs; and
          o    Annualized Costs (total O&M cost plus capital -
               related annual charges).

Each of these cost categories is further subdivided into individual cost
elements.
     Capital cost elements include direct costs (purchase equipment and
installation costs), indirect costs,  and contingencies.  Direct costs consist
of the basic and auxiliary equipment, the labor and material required to
install the equipment, plus site preparation and buildings costs.  Indirect
costs are those costs which are not attributable to specific equipment items
such as engineering, construction and field expenses, contractor fees, and
start-up and performance tests.  Contingencies cover any unpredicted events
and other unforeseen expenses that may arise.
     The O&M cost elements include direct and indirect costs.  Direct O&M
costs consist of operating and maintenance labor, fuel, utilities, materials
and spare parts, supplies, waste disposal, and chemicals.  These costs are
Dependent on the combustor capacity utilization.  Indirect O&M costs, on the
oUier hand, ara totally independent of capacity utilization.  These costs
include plant and payroll overhead, real  estate and local taxes, insurance,
administrative charges, and replacement parts.
                                     1-1

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     Total annualized costs are the sum of the direct and indirect O&M costs
and capital recovery costs.  Capital recovery costs are determined by
multiplying the total capital costs by the capital recovery factor, which is
based on the assumed interest rate and economic equipment life.  A 10 percent
real interest rate and a 15-year equipment life are assumed for the
combustors and control equipment in this report.  This translates into a
capital recovery factor of 13.15 percent.
     All costs are presented in December 1987 constant dollars.  Chapter 2.0
of this report presents the costing procedures for new MWC plants.  Included
are procedures to estimate capital, operating and maintenance, and annualized
costs for combustors, combustor-related equipment, flue gas temperature
control, PM control using dry electrostatic precipitators (ESP's), acid gas
control using either dry sorbent injection or spray dryers followed by a
fabric, filter for PM control, and continuous emission monitors (CEM's).
Chapter 3.0 presents the costing procedures for existing MWC plants which
include procedures used to estimate costs for operating existing combustors
and for retrofitting emission controls.  Emission controls evaluated include
combustor modification, temperature control, PM control (rebuilding an
existing ESP, adding plate area, or installing a new ESP), and acid gas
controls using either dry sorbent injection or spray dryers with an existing
ESP or a fabric filter for PM control.
     Appendix A compares the costs between spray dryer/fabric filter and
spray dryer/electrostatic precipitator systems applied to new plants.  The
purpose of this comparison was to determine whether (1) the costs of these
systems differ sufficiently to warrant separate costing procedures for each
system and (2) a single procedure can be used.  Appendix B presents the
tables summarizing the cost procedures presented  in this report.
                                     1-2

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                       2.0  PROCEDURES FOR NEW PLANTS
     This section presents procedures for estimating costs of new MWC plants.
The capital and annualized costs of a new plant include the combustors and
associated equipment, air pollution control devices (APCD's), and continuous
emission monitoring equipment.  Section 2.1 presents the procedures for
costing the MWC combustors and associated equipment (denoted as the balance
of plant).  Procedures for costing electrostatic precipitators (ESP's), dry
sorbent injection (DSI), and spray drying (SD) are presented in Sections 2.2,
2.3, and 2.4, respectively.  Section 2.5 presents compliance monitoring
equipment costs for opacity, HC1,  S0?, 02» and CO^.
2.1  COMBUSTORS AND BALANCE OF PLANT
     This section presents procedures for estimating the combustor and
associated equipment costs, excluding the air pollution control devices
(APCD's), for four types of combustors:  modular, mass burn, refuse-derived
fuel (RDF), and fluidized bed combustion (FBC).  The capital cost procedures
for each combustor type with the exception of fluidized bed combustors were
developed from data presented in Frost and Sullivan.   The operating cost
procedures were developed from responses to an information request which EPA
sent to MWC operators under authority of Section 114 of the Clean Air Act.
Capital and operating cost procedures for FBC's were developed from vendor
data.
     Sections 2.1.1, 2.1.2, 2.1.3, and 2.1.4 present the cost procedures for
modular, mass burn,  RDF, and FBC facilities, respectively.  Detailed cost
data suitable for direct estimation of capital costs for MWC's of various
types and sizes were not available.  Therefore, the procedures presented in
these sections-are based on scaling the capital cost of typical size
facilities of each combustor type.  The capital costs estimated for these
facilities were all  based on Frost and Sullivan (with the exception of FBC's)
to minimize inconsistencies in cost assumptions among combustor types.  To
facilitate use of these costs with those presented in subsequent sections of
this report,  the original combustor capital  cost estimates were revised'to
exclude the cost of the APCD.   Indirect cost estimations for general
facilities and engineering fees are also based on Frost and Sullivan.
                                    2.1-1

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Capital costs were updated from 1985 dollars in Frost and Sullivan to
December 1987 dollars using the Chemical  Engineering Plant Cost Index.
2.1.1  Modular Units
     2.1.1.1  Overview of Technology.  Modular combustors are prefabricated
units which are generally used to combust unprocessed MSW.  Individual
combustor units typically range in size from 5 to 150 tons per day (tpd).
     Modular combustors are of two general  designs,  starved-air and
excess-air.  In typical starved-air combustors, MSW  is ram-fed into a
primary combustion chamber with a moving  grate.  Primary air is fed up
through the grate at substoichiometric conditions.   Volatile gases released
from the heated MSW enter a secondary chamber where  sufficient air and
supplemental fuel, typically natural gas  or oil, are supplied to complete
combustion.  Excess-air combustors provide air in excess of stoichiometric
requirements in the primary combustion chamber.  Additional air and supple-
mental fuel may be added in a secondary chamber to assure complete
combustion.
     Modular combustors which recover energy typically do so in waste heat
boilers following the combustion chambers.   The steam produced can be sold
directly to users or used to generate electricity.
     2.1.1.2  Capital Cost Procedures.  The original modular combustors were
relatively simple in design and had low capital costs.  As a result of
subsequent design changes, the capital costs of modular units have increased
but are still relatively low compared to other MWC technologies on a "ton per
day of MSW capacity" basis.  However, thermal efficiencies are also lower,
decreasing the cost advantage for facilities when designed primarily for heat
recovery.  Because of their modular design, little or no economy of scale
                                      2
exists as a function of facility size.
     As shown in Table 2.1-1, capital costs were obtained for a 50 tpd
modular facility without heat recovery and for a 100 tpd facility consisting
ot two modular starved-air combustors, one waste heat boiler (17,000 Ib/hr
steam), and an optional 1.475 MW steam turbine.  Costs for excess air modular
units are expected to be similar.  Based on the costs presented in this
                                    2.1-2

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               TABLE 2.1-1.  CAPITAL COSTS FOR MODULAR MWC'sa
             Equipment                                 Costs, $l,000's
A.  Without Heat Recovery

    Combustors (1 @ 50 tpd)                                 1,125


    Total0                                                  1,125
    Engineering Fees                                           88
    Total Capital  Costs                                     1,210
    Unit Capital  Costs                                    $24,300 per
                                                           tpd of MSW
                                                            processed
    = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = =; = = = = = = = = = ;= = = :=::

B.  With Electricity Generation (Without Electricity Generation)

    Combustors (2 @ 50 tpd)                                 2,250
    Waste Heat Boiler (1 @ 17,000 Ib/hr)                      770
    Turbine/Generator (1 0 1,475 kW)                        2,050  (0)
    Total0                                                  5,070  (3,020)
    Engineering Fees                                          390  (232)


    Total Capital  Costs                                     5,460  (3,250)
    Unit Capital  Costs                                    $54,600  ($32,500)
                                                            per tpd of
                                                           MSW processed


Reference 1, p.  128.

 December 1987 dollars.

°Pepresents total  direct costs (sum of the equipment and installation costs)

 Costs in parenthesis represent modular MWC's producing steam without
 generating electricity.
                                   2.1-3

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table, the following procedure can be used to estimate capital costs for
modular facilities:
     0  Modular facilities without heat recovery  = $24,300 per tpd capacity
     •  Modular facilities producing steam        = $32,500 per tpd capacity
     •  Modular facilities generating electricity = $54,600 per tpd capacity
The heat recovery boiler and turbine/generator set effectively double the
cost of the facility.
     Because modular combustors are packaged units which require little site
preparation or extra equipment, no separate costs were included for general
facilities (foundations and building) or MSW or ash handling systems.
     2.1.1.3  Operating Cost Procedures.  Annual operating cost procedures
were developed from analysis of cost data provided by five plants with
modular combustors in their responses to the Section 114 questionnaire.  All
operating costs except for capital recovery and waste disposal costs were
examined.  The approach used in developing the operating cost procedures was
to correlate the ratio of the operating to capital costs with facility
capacity (tpd) and annual operating hours.  The following best fit equation
was derived for these facilities, all of which were rated below 150 tpd and
were operating less than 6,000 hours per year:
                    Ratio = 10 - 0.23 tpd + 0.006 hrs                 (1)
where, Ratio = percentage of operating to capital plant costs
         tpd = facility waste feed rate, tons/day
         hrs = annual operating hours.
     For modular facilities outside these size or operating hour limits, the
following equation can be used to estimate annual operating cost based on
mass burn refractory wall facilities as discussed in Section 2.1.2.3:
                    Ratio = 15.7  - 0.00115 tpd                        (2)
It is assumed that the ratio of operating to capital costs for modular and
mass burn refractory wall facilities are similar, since the design and
equipment arrangements of both MWC types are similar (i.e., use of waste heat
boilers for heat recovery).
                                    2.1-4

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     Capital recovery costs are calculated as 13.15 percent of the total
capital costs, based on a 10 percent interest rate and 15 year economic life.
Waste disposal costs are estimated by the following equation based on a
$25/ton landfill  tipping fee:
                             100 - RED             (HRS)
               WDC = $25 *     (100)      * TPD *   (24)              (3)
where, WDC = waste disposal costs, $/yr
       RED = weight reduction of MSW within the combustor, percent
       TPD = facility waste feed rate, tons/day
       HRS = annual operating hours.
Therefore, the total annualized costs are obtained by summing the annual
operating costs calculated from Equations 1 or 2, the capital recovery costs,
and the waste disposal  costs estimated from Equation 3.  All costs are
presented in December 1987 dollars.
7.1.2  Mass Burn  Units
     2.1.2.1  Overview of Technology.  Mass burn combustors are field-erected
units used to combust unprocessed municipal solid waste.  Mass burn
combustors range  in unit size from 50 to 1,000 tons/day for a combustor unit
and from 50 to several  thousand tons/day for a facility.
     In a mass burn combustor,  municipal waste is gravity- or ram-fed to a
single combustion chamber.  Several different grate designs can be used to
move the waste through  the combustion chamber.  Air is supplied in excess of
stoichiometric requirements through the grates (underfire air) and into the
combustion chamber above the grates (overfire air).
     Either waterwall or waste  heat boilers are used for recovering heat.  In
units with waterwalls,  boiler tubes are built into the walls of the com-
bustion chamber.   Additional heat recovery sections can include superheaters,
economizers, and  air preheaters.   In units with waste heat boilers, the
combustion chamber is refractory lined and steam is generated downstream of
the combustion chamber.
                                    2.1-5

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     Electricity is generally produced on-site from steam.  Some facilities
sell both electricity and steam.  Because of the large quantity of steam
produced by large mass burn units, production and sale of only steam is
unlikely unless a very large industrial facility with a consistent steam
demand is nearby.
     Waterwall units are typically larger (100 to 1,000 tons/day per unit)
than units with waste heat boilers (50 to 375 tons/day per unit).  Most new
units are of waterwall design.   No units are projected to be built without
heat recovery.
     2.1.2.2  Capital Cost Procedures.  As shown in Table 2.1-2, the
estimated capital cost for a mass burn facility is $60,700 per tpd capacity.
This cost is based on an 860 tpd facility consisting of two 430 tpd
combustors with 174,000 Ib/hr of steam capacity and a 20 MW turbine.  For the
same facility without a steam turbine, the estimated capital costs are
$50,420 per tpd capacity.  The capital costs for waterwall units and
refractory units with waste heat boilers are assumed to be roughly equal.
     To account for the economy of scale of mass burn facilities, capital
costs reported by Frost and Sullivan were correlated with facility size to
yield the following scaling equation:

          C = 60,700 (430/size)0'39,  with electrical generation      (4)
                               n "3Q
          C = 50,420 (430/size)    ,  without electrical generation   (5)

where,    C = new facility capital costs in December 1987 dollars per
              tpd
       size = size per combustor in tpd.

Capital cost for a combustor is estimated using equations 4 or 5 to calculate
cost on a dollar per tpd basis and then multiplying this cost by plant
capacity in tons per day.
     2.1.2.3  Operating Cost Procedures.  Annual operating cost procedures
were developed from analysis of cost data provided by six plants (4 of which
were mass burn waterwall and 2 were RDF facilities) in their responses to the
Section 114 questionnaire.  The RDF facility operating cost data were

                                    2.1-6

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            TABLE  2.1-2.   CAPITAL  COSTS  FOR A 860 TON/DAY MASS BURN.  h
                            MWC WITH (WITHOUT) ELECTRICITY GENERATION  '
Equipment
Water-wall Combustors
(2 a 430 ton/day)
Refuse Cranes (2)
Weight Scales (2)
Fans and Ducts (2)
Ash Handling System
Dump Condenser (1)
Stacks (2)
Water Supply and Treatment
Piping System
Electrical
Instruments and Controls
Insulation and Paint
Cooling Tower (1)
Turbine/Generator (1 a 20 MW)
Total Capital Costs
General Facilities
Foundations
Building and Structural
Total General Facilities
Engineering Fees
Total Capital Costs
Unit Capital Costs

Costs, $1,000C


Purchase Cost Installation Cost Total Installed Cost
6,742
1,245
614
1,245
2,933
778
880
1,611
3,127
1,562
2,073
519
3,105
6,318 (0)
32,752 (26,434)
2,544 (2,053)
1.487 (1,200)
4,031 (3,253)
--
36,783 (29,687)

3,519
498
302
368
440
547
365
189
975
293
195
293
440
1,100 (0)
9,524 (8,424)
1,664 (1,472)
172 (152)
1,836 (1,624)
4,097 (3,624)
15,457 (13,672)

10,261
1,743
916
1,613
3,373
1,325
1,245
1,800
4,102
1,855
2,268
812
3,545
7,418
42,276
4,208
1.659
5,867
4,097
52,240
$60,700













(0)
d (34,858)d
(3,525)
(1,352)
(4,877)
(3,624)
(43,359)
(50,420)
per tpd of
HSW processed
"Reference 1,  p.  113.

 Costs in parentheses represent mass burn MWC's producing steam without generating
 electrici ty.

CDecember 1987 dollars.

 Represents total direct costs (sum of  equipment and installation costs).
                                         2.1-7

-------
analyzed along with the mass burn cost data because of limited data for mass
burn plants and because both combustor types are constructed similarly
(i.e., field erected) and will likely be operated for a similar number of
hours per year.  All operating costs except for capital recovery and
waste disposal costs were examined.  The approach used in developing the
operating cost procedures was to correlate the ratio of the operating to
capital  costs with facility capacity (tpd) and operating hours.  The
following best-fit equation was derived for mass-burn waterwall facilities:
                    Ratio = 12.5 - 0.00115 tpd                        (6)
where, Ratio = percentage of operating to capital plant costs
         tpd = facility waste feed rate, tons/day.
     For mass burn refractory wall facilities, no equation could be derived
due to the limited amount of cost data.  However, by comparing the
Section 114 data for waterwall and refractory wall facilities, the operating
to capital cost percentages for refractory facilities were roughly 3 percent
higher than those for mass-burn waterwall facilities.  Therefore, to estimate
the annual operating cost for mass-burn refractory wall facilities, the
equation for mass-burn waterwall (Equation 4) was modified to give the
following:
                    Ratio = 15.7 - 0.00115 tpd.                       (7)
Equations 6 and 7 are multiplied by equation 5 to estimate annual operating
costs for mass burn waterwall and mass burn refractory wall facilities,
respectively.
     Capital recovery costs for both types of mass burn facilities are
calculated as 13.15 percent of the total capital costs, based on a 10 percent
interest rate and 15 year economic life.  Waste disposal costs are estimated
by equation 3 presented for modular facilities (Section 2.1.1.3).  Therefore,
the total annualized costs are obtained by summing the annual operating costs
calculated from equations 6 or 7, capital recovery costs, and waste disposal
costs calculated from equation 3.
                                    2.1-8

-------
2.1.3  RDF Units
     2.1.3.1  Overview of Technology.  Refuse-derived fuel MWC's are
field-erected units used to combust processed MSW.  Individual RDF combustors
typically combust 180 to 1,200 tons/day of RDF.  Plant sizes range from
180 to several thousand tons/day of RDF.
     Refuse-derived fuel processing includes removal of noncombustible
materials and shredding of the remaining material.  The two types of RDF
considered in this analysis include coarse RDF (cRDF) suitable for combusting
in a specially designed RDF combustor and fluff RDF (fRDF) suitable for
suspension firing in a utility or industrial boiler.
     Coarse RDF production generally includes primary shredding and ferrous
metals recovery.  The RDF material is reduced in size to 4 to 6 inches.  A
weight reduction due to metals recovery of approximately 6 percent is
assumed; energy recovery is nearly 100 percent.  Fluff RDF production usually
includes crushing, initial trommel screening, and magnetic separation
followed by primary shredding, air classification, and secondary shredding.
This processing removes oversized combustibles and glass as well as
nonferrous metals and reduces the size to below 2 inches.  The associated
weight reduction is approximately 20 percent of the unprocessed MSW; energy
recovery is roughly 97 percent.  Production of both types of RDF includes a
dust control system to prevent fugitive emissions of fine dust generated by
RDF processing equipment.
     Existing RDF combustion is based almost entirely on use of cRDF in
spreader strokers.  In general with this technology, cRDF is thrown to the
rear of the furnace by a dry-swept stoker.  Fine particles are burned in
suspension, and heavier materials fall  to the grate and are combusted.  A
traveling grate moves the materials to the front of the furnace during which
time combustion is completed.  The heat from combustion is recovered using
radiant waterwall and convective heat transfer.  Electricity is generally
generated on-site, especially with the larger units.  Both electricity and
steam may be sold.
                                    2.1-9

-------
   TABLE 2.1-3.   CAPITAL COSTS  FOR A COARSE  RDF  FACILITY  WITH  ELECTRICITY
                 GENERATION (CAPACITY =  850  TONS/DAY  MSW,  800  TONS/DAY RDF)'




Equipment
Waterwall Combustors (2 @ 400 ton/day)
Front End Loaders (9)
Primary Shredders (2)
Weigh Scales (2)
Magnetic Separation System (2)
Fans and Ducts (2)
Ash Handling System (2)
Dump Condenser (1)
Dust Control System
Stacks (2)
Water Supply and Treatment
Piping System
Electrical
Instruments and Controls
Insulation and Paint
Cooling Tower
Turbine/Generator (1 @ 24 MW)
Total Capital Costs
General Facilities
Foundation
Building and Structural
Total General Facilities
Engineering Fees
Total Capital Costs
Unit Capital Costs



Purchase
Cost
5,085
713
1,016
639
205
993
2,441
916
508
689
1,985
3,663
1,657
2,339
539
3,586
7,627
34,601

3,945
3,283
7,228
--
41,829


Costs, $1,000

'sb
Total
Installation Installed
Cost
2,544
--
508
307
68
273
368
670
205
303
225
1,221
375
253
307
506
1,345
9,478

2,704
388
3,092
4,512
17,082

per
Cost
7,629
713
1,524
946
273
1,266
2,809
1,586
713
992
2,210
4,884
2,032
2,592
846
4,092
8,972
44,079°

6,649
3,671
10,320
4,512
58,911
$73,600
tpd of RDF
 Reference 1,  p.  117.
 December 1987 dollars.
cRepresents total  direct costs (sum of equipment and installation costs).
                                   2.1-10

-------
     Fluff RDF has been co-fired with coal in several existing utility and
                   4
industrial boilers.   Of the total heat input, fRDF generally represents less
than 10 percent.
     2.1.3.2  Capital Cost Procedures.  The cost procedures developed for
RDF-fired MWC's are based on cRDF.  As shown in Table 2.1-3, the estimated
capital cost for a cRDF facility is $73,600 per tpd of cRDF capacity.  This
cost was based on a cRDF facility designed to process 850 tpd of MSW into
800 tpd of cRDF.  The cRDF is combusted in two identical waterwall boilers to
generate 203,000 Ib/hr of steam for a 24 MW turbine.  The major equipment
items and associated materials and labor costs for the cRDF production/
combustion facility are presented in Table 2.1-3.
     Because no data are available from Frost and Sullivan for other cRDF
facility sizes, it is assumed that the economy of scale of RDF facilities is
the same as mass-burn facilities, since both mass-burn and RDF combustors are
field-constructed.  Similar indirect installation costs would be incurred for
both MWC types.  Therefore, the following equation can be used to estimate
capital cost for cRDF facilities:

                         C = 73,600 (400/size)0'39                    (8)

where,  C = new cRDF facility capital  costs in December 1987 dollars
           per ton of RDF
    size = size per combustor in tons RDF/day.
     2.1.3.3  Operating Cost Procedures.   Annual  operating cost procedures
were developed from analysis of cost  data as discussed in Section 2.1.2.3.
To estimate the annual  operating costs except for capital recovery and waste
disposal costs, equation 6 presented  in Section 2.1.2.3 can be used.
     Capital  recovery costs are calculated as 13.15 percent of the total
capital costs,  based on a 10 percent  interest rate and 15 year economic life.
Waste disposal  costs are estimated using  Equation 3 presented in
Section 2.1.1.3.   It should be noted  that the annual cost procedures  do not
include estimates on sale of recoverable  material  such as metal  and glass.
                                   2.1-11

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2.1.4  FBC Units
     2.1.4.1  Overview of Technology.   Fluidized-bed combustors are
field-erected units used to combust RDF.   Only three RDF-fired FBC plants are
currently operating in the U.  S.   Existing and currently planned FBC's are
designed to combust 195 to 500 tpd of RDF.  Plant sizes range from 195 to
1,200 tpd of RDF.   For costing purposes,  it is assumed that a cRDF fuel
processing facility is included in the design of the FBC facility.  Two basic
FBC designs exist:  bubbling bed  and circulating fluidized-bed.
     In a bubbling-bed combustor,  the RDF  burns in a turbulent bed of heated
noncombustible material, such  as  limestone or sand.   Typical bed temperatures
are from 1,450 to 1,700°F.  As with conventional combustors, primary combus-
tion air is introduced underneath  the bed, but at a  flowrate high enough to
suspend or "fluidize" the solid particles  in the bed.  Secondary combustion
air is introduced through ports in the upper part of the combustor to complete
the combustion process.  If good  mixing between air  and combustible waste is
achieved, the amount of excess air required for complete combustion is
similar to conventional RDF combustors.  In addition, by adding limestone to
the bed, SCL and HC1 can be removed from the flue gas to reduce acid gas
emissions.  Bed material entrained in the  flue gas is typically removed by a
cyclone in series with a fabric filter (FF) or an electrostatic precipitator
(ESP).
     Circulating fluidized-bed combustors  are similar to bubbling-bed
combustors except that the superficial velocities within the bed are 3 to
5 times higher than in bubbling-bed combustors.  As  a result, a physically
well-defined bed is not formed; instead,  solid particles are entrained with
the transport air/combustion gases.  Most  of the solids are captured by a
cyclone, and are continuously recirculated into the  combustor.  The solids
still in the flue gas are captured by a downstream FF or an ESP.
     Available information on the capital  and operating costs of FBC's are
insufficient to distinguish bubbling versus circulating bed designs. '
Therefore, a single set of cost procedures has been  developed.
                                   2.1-12

-------
     2.1.4.2  Capital Cost Procedures.  Table 2.1-4 presents the capital cost
procedure for FBC's.  All costs are estimated in December 1987 dollars.  The
procedures do not include the costs for FF's or ESP's.  The costs for ESP's
and FF's can be estimated using procedures discussed in Sections 2.2 and 2.3
of this report, respectively.
     The direct and indirect cost equation shown in Table 2.1-4 is based on a
vendor cost estimate for two combustors each rated at 450 tpd (i.e., total
                           Q
plant capacity of 900 tpd).   The vendor cost estimate included:  combustor
vessel, natural gas preheat system, forced draft and induced draft fans,
tramp removal system, boiler, fuel and limestone storage and metering,
multiclone, instrumentation and control including a boiler management system,
ductwork, freight, and engineering and start-up supervision.  However, the
cost estimate provided by the vendor did not include cRDF processing and
other equipment associated with the combustors such as front-end loaders,
primary shredders, weight scales, magnetic separators, stacks, cooling tower,
water treatment and supply, and steam turbine.  Because the other equipment
would be the same for both cRDF and FBC facilities, costs for the balance of
plant in Table 2.1-3 (adjusted by size to 900 tpd using the 0.6 power cost
rule) were added to the vendor cost estimates to estimate the total direct
     g
cost.   Indirect costs for general facilities and engineering fees were based
on percentages of the direct cost estimated by Table 2.1-3.
     To estimate the direct and indirect capital cost for other plant sizes,
it is assumed that the economy of scale of FBC facilities is the same as for
mass-burn and RDF facilities (0.39).  Similar indirect installation costs
would be incurred for these boiler types.  A 20-percent process contingency
is added to account for the relatively limited application of FBC to MWC's.
     2.1.4.3  Operating Cost Procedures.  Table 2.1-5 presents the operating
cost bases for FBC's.  Table 2.1-6 presents operating cost equations derived
from Table 2.1-5.  The FBC operating procedures are divided into two process
areas:  combustor and the balance of plant, and cRDF processing.  The direct
operating cost bases for the combustor and balance of plant were based on
information provided by one vendor for labor, electrical  consumption, and
water requirements.   The maintenance materials costs were determined from
cost data for coal-fired industrial FBC's.    Lime costs are based on the

                                   2.1-13

-------
     TABLE 2.1-4.  PROCEDURE FOR ESTIMATING CAPITAL COSTS FOR NEW FBC'S
                                 (December 1987 dollars)
Total Direct and Indirect Costs:9
              •5                            n on
     Costs, 1(T$ = 64,900 * TPD * (900/TPDr"5*
Process Contingency:  20% of total direct and indirect costs
Total  Capital FBC Costs:  Total direct and indirect costs + process
                          contingency
aTPD = plant municipal waste feed rate, tons/day.
                                    2.1-14

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        TABLE 2.1-5.  ANNUAL OPERATING COST PROCEDURES FOR NEW FBC'S
                                                                 References
Combustors and Balance of Plant
(except coarse RDF processing area)
     Operating Labor:


     Supervision:



     Maintenance Labor:



     Maintenance Materials:

     Electricity:



     Limestone:

     Water:



     Waste Disposal:



     Overhead:
     Taxes,  Insurance,  and
     Administrative:
     Capital  Recovery of
     FBC Facility:
10 man-years/year,  40 hours/week,
  and $12/hr for a  900 tpd plant

 3 man-years/year,  40 hours/week,
  and 30% premium over operating
  wage for a 900 tpd plant

 3 man-years/year,  40 hours/week,
  and 10% premium over operating
  wage for a 900 tpd plant

 3% of the total capital  costs

 3 MW power consumption for a
  900-tpd plant and electricity
  costs of $0.046/kwh

 $40/ton

 3% blowdown rate calculated
  from steam production and
  $0.50/1,000 gal for water

 $25/ton tipping fee and  99%
  combustible material  in RDF
  and spent sorbent collected

 60% of the sum of  all  labor
  costs (operating,  supervisory,
  and maintenance)  plus 60% of
  the maintenance materials costs
 4% of the  sum  of  the  total  capital
  costs
 15  year  life  and  10% interest
  rate
6, 12



6, 13



6, 14

11



6

15



6, 16



6, 17




18



18



19
                                Continued
                                   2.1-15

-------
  TABLE 2.1-5 (CONCLUDED).  ANNUAL OPERATING COST PROCEDURES FOR NEW FBC'S
                                                                 References
Coarse RDF Processing Area

     Total Operating and
     Maintenance:
     Taxes, Insurance, and
     Administrative:
     Capital Recovery of
     FBC Facility:
4.4% of the total direct and
 indirect capital costs * ratio
 of operating to capital costs
 from Equation 6 in Section 2.1.2        1

4% of the sum of the total capital
 costs                                  18
15 year life and 10% interest
 rate                                   19
                                   2.1-16

-------
  TABLE 2.1-6.   PROCEDURE FOR ESTIMATING ANNUAL OPERATING COSTS FOR FBC'S
                                 (December 1987 dollars)
Combustor and Balance of Plant (excludes coarse RDF processing area):

     Operating labor (based on 10 man-years,  40 hours/week,  $12/hr):
     OL = 10 * 40 * 52 * 12 * (TPD/900)  = 277.3 * TPD
     Supervision (based on 3 man-years/vear,  40 hours/week,  30% wage  rate
     premium over the operating labor wage):
     SPRV = 3 * 40 * 52 * 12 * 1.3 * (TPD/900)  = 108.2  * TPD
     Maintenance labor (based on 3 man-years/vear,  40 hours/week,  10% wage
     rate premium over the operating labor wage):
     ML = 3 * 40 * 52 * 12 * 1.1 * (TPD/900)  =  91.5 * TPD
     Maintenance materials: 3% of the total  capital  costs
     Electricity (based on 3 MW power consumption,  and  electricity rate of
     $0.046/kwh):
     ELEC = 0.153 * TPD * MRS
     Limestone (based on $40/ton for limestone):
     LIMESTONE = 0.02 * LFEED * MRS * N
     Water (based on 3% blowdown rate and $0.05/1,000 gal):
     WC = 1.86 x 10"6 * STM * HRS
     Waste disposal  (based on tipping fee of  $25/hr):
     AD = 1.25 x 10"2 * N * HRS * WDR
     Overhead:   60% of the sum of all  labor costs  (operating,  supervisory,
     and maintenance) plus 60% of maintenance materials  costs
     Taxes,  Insurance,  and Administrative Charges:
     4% of the total  capital  cost
     Capital  Recovery (based on 15 year  life  and  10% interest  rate):
     13.15% of the total  capital  cost
                                 Continued
                                   2.1-17

-------
  TABLE 2.1-6 (CONCLUDED).  PROCEDURE FOR ESTIMATING ANNUAL OPERATING COSTS
                                   FOR FBC'S (December 1987 dollars)
Coarse RDF Processing Area:

     Total Operating and Maintenance Costs (TOT O&M):

     TOT O&M = 4.4 x 10"4 * (12.5 - 0.00115 * TPD)  * TDI

     Taxes, Insurance, and Administrative Charges:

     4% of the total capital  cost

     Capital Recovery (based  on 15 year life and 10% interest rate):

     13.15% of the total capital  cost
 OL = operating labor costs, $/yr
 SPRV = supervision costs, $/yr
 ML = maintenance labor costs, $/yr
 ELEC = electricity costs, $/yr
 HRS = hours of operation per year
 LIMESTONE = limestone costs, $/yr
 LFEED = limestone feed rate per unit,  Ib/hr
 N = number of combustors
 WC = water costs, $/yr
 STM = plant steam production, Ib/hr
 AD = waste disposal costs, $/yr
 WDR = waste disposal rate per unit (bottom and fly ash collected), Ib/hr
 TPD = plant municipal waste feed rate, tons/day
 TDI = total direct and indirect capital costs for FBC plant, $
                                   2.1-18

-------
amount of limestone injected at a cost of $40/ton.  This cost is based on a
limestone freight-on-board cost of $20/ton and a transportation cost of
$20/ton, assuming a handling rate of $0.04/ton-mile hauling distance and a
500-mile hauling distance.  The cost for waste disposal is determined from
the amount of solids removed by the FBC plus additional fly ash collected by
the downstream particulate control device.
     All cost rates are based on December 1987 dollars.  The operating labor
wage is the average from those wages in the Department of Commerce Survey of
Current Business for private nonagricultural payrolls and EPRI's Technical
                 20 21
Assessment Guide.  '    Electricity rates are from the Energy Information
                                      22
Administration, Monthly Energy Review.
     The annual operating cost procedures for RDF processing facilities in
Section 2.1.3.3 were used to estimate the annual operating costs for the
cRDF processing area.   Operating costs for the cRDF processing area are
estimated to be 4.4 percent of the product of total FBC capital cost and the
ratio of operating-to-capital costs for RDF facilities from Equation 6 in
Section 2.1.2.3.
                                   2.1-19

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REFERENCES

 1.   Frost and Sullivan, Incorporated.   As cited in Waste-Energy Boom Seen
     Through Century.  Coal  and Synfuel  Technology.  March 17, 1986.  259 p.

 2.   U. S. Environmental Protection Agency.  Small  Modular Incinerator
     Systems with Heat Recovery:  A Technical Environmental,  and Economic
     Evaluation-Executive Summary.  Cincinnati,  OH.  Publication
     No. EPA/SW-797.  1979.   p. 5.

 3.   Reference 1.  p. 105.

 4.   Energy and Environmental  Research  Corporation.  Refuse Derived Fuel
     Co-firing Technology Assessment.   Prepared  for the U. S. Environmental
     Protection Agency.   Research Triangle Park, NC.  September 1988.

 5.   Energy and Environmental  Research  Corporation.  Fluidized-Bed Combustor
     Technology Assessment.   Prepared  for the U. S. Environmental  Protection
     Agency.  Research Triangle Park,  NC.  September 1988.  pp. 2-13 to 2-24.

 6.   Letter from Hansen, J.  L., Energy  Products  of Idaho, to Martinez, J. A.,
     Radian Corporation.  December 1,  1988.  Costs for bubbling fluidized-bed
     combustors applied to MWC's.

 7.   Letter from Ferm, B.,  Gotaverken  Energy Systems, to Johnston, M. G.,
     EPA.  March 17, 1989.   Costs for  circulating fluidized-bed combustors
     applied to MWC's.  9 p.

 8.   Reference 6.

 9.   Garrett, D. E., Chemical  Engineering Economics.  New York, Van Nostrand
     Reinhold.  1989.  p. 37.

10.   Electric Power Research Institute.   TAG™ -  Technical Assessment Guide
     (Volume 1:  Electricity Supply -  1986).  Palo Alto, CA.   EPRI Report
     No. P-4463-SR.  December 1986.  p.  3-3.

11.   Young, C. W., et al. (GCA).  Technical Assessment Report for Industrial
     Boiler Applications:  Fluidized-bed Combustion.  Prepared for the
     U. S. Environmental Protection Agency.  Publication No.  EPA-600/7-79-178e.
     November 1979.  pp. 517-553.

12.   Reference 10, p. B-4.

13.   Neveril, R. B.  (CARD,  Inc.).  Capital and Operating Costs of Selected
     Air Pollutant Control  Systems.  Prepared for the U. S. Environmental
     Protection Agency.  Research Triangle Park, NC.  Publication
     No. EPA-450/5-80-002.   December 1978.  p. 3-12.
                                   2.1-20

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14.  Devitt, T., P. Spaite, and L. Gibbs (PEDCo Environmental).  Population
     and Characteristics of Industrial/Commercial  Boilers in the U.S.
     Prepared for the U. S. Environmental Protection Agency.  Research
     Triangle Park, NC.  Publication No. EPA-600/7-79-178a.  August 1979.
     462 p.

15.  Jordan, R. J.  The Feasibility of Wet Scrubbing for Treating
     Waste-to-Energy Flue Gas.  Journal of Air Pollution Control Association
     (New York).  37:422-430.   April 1987.

16.  Letter from Solt,  J. C.,  Solar Turbines Incorporated, to Noble, E., EPA.
     October 19, 1984.   Development cost for wet control for stationary gas
     turbines.

17.  U. S. Environmental Agency.  EAB Control Cost Manual.  Research Triangle
     Park, NC.   Publication No. EPA-450/5-87-001a.  February 1987.  p. 2-29.

18.  Reference  17, p. 2-31.

19.  Bowen, M.  L.  and M. S. Jennings (Radian Corporation).  Cost of Sulfur
     Dioxide, Particulate Matter,  and Nitrogen Oxide Controls in Fossil Fuel
     Fired Boilers.  Prepared  for the U. S.  Environmental Protection Agency.
     Research Triangle  Park, NC.  Publication No.  EPA-450/3-82-021.
     August 1982.   pp.  2-17 and 2-18.

20.  United States Department  of Commerce.  Survey of Current Business.
     Washington, DC.  Volume 68.  Number 6.   June  1988.   p. S-12.

21.  Electric Power Research Institute.  TAG™ Technical  Assessment Guide
     (Volume 1:  Electricity Supply - 1986).  Palo Alto, CA.  Publication
     No. EPRI P-4463-5R.  December 1986.  p. B-4.

22.  Energy Information Administration.  Monthly Energy  Review:
     December 1987.  Washington, D.C. Publication  No.  DOE/EIA-0035 (87/12).
     March 1988.  p. 109.
                                   2.1-21

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2.2  ELECTROSTATIC PRECIPITATORS
2.2.1   Overview of Technology
     Electrostatic precipitators are used to control  PM emissions from MWC's.
In this process, flue gas flows between a series of high voltage discharge
electrodes and grounded metal plates.   Negatively charged ions formed by this
high voltage field attach to particulate in the flue gas, causing the charged
particles to migrate toward the grounded plates.  Charged particles that
collect on the grounded plates are periodically removed by rapping or
washing.  Key ESP design and operating characteristics influencing ESP
performance are particulate size and resistivity, specific collection area
(SCA, equal to the total surface area of the collection plates divided by the
flue gas flow rate), and the number of ESP fields.  When the plates are
cleaned, some of the collected particulate is reentrained in the flue gas.
To ensure good particulate collection efficiency during plate cleaning and
electrical upsets, ESP's have several  fields located in series along the
direction of flue gas flow that can be energized and cleaned independently.
Particles reentrained when the dust layer is removed from one field can be
recollected in a downstream field.
2.2.2   Capital Cost Procedures
     2.2.2.1   Direct costs.  Information on direct equipment costs is
available for ESP's at three PM control levels  (0.01, 0.02, and 0.03 gr/dscf
at 12 percent CO,) for mass-burn, modular, and  RDF facilities ranging in size
                ^                          i
from 100 to 3,000 tpd total plant capacity.   These cost estimates, based on
data provided by eight manufacturers,  are presented in Table 2.2-1.
     The equipment cost data were correlated with total plate area.
Figure 2.2-1 illustrates the "best fit" equation for the data from all of the
ESP vendors except for one.  The data from manufacturer "D" in Table 2.2-1 at
a flue gas flowrate of 245,230 acfm were not included in the analysis because
the cost data varied significantly from the rest of the data (refer to the
three solid data points in Figure 2.2-1).  Data from manufacturers F and G in
Table 2.2-1 were excluded  in Figure 2.2-1, because flue gas flowrates for the
large mass-burn units were not reported.  The resultant "best fit" equation
using this approach is:
                                    2.2-1

-------
        TABLE 2.2-1.  VENDOR QUOTES FOR ESP EQUIPMENT COSTS
                             (IN 1000$ AUGUST 1986)3

Vendor
A
A
B
C
D
E
C
D
F
G
B
H
H
A
H
A
Furnace
type3
MOD
MOD
MOD
MB
MB
MB
MB
MB
MB
MB
MB
MB
RDF
RDF
RDF
RDF
Flue gas
flowrates,
acfm
54,105
86,568
86,568
24,523
24,523
76,000
NA
NA
245,230
240,000
190,031
126,687
130,843
130,843
196,264
196,264
Outlet
0.03
240
280
325
253
410
NAb
503
1,470
1,313
NA
475
567
580
780
768
910
PM emissions.
0.02
250
290
325
423
450
640
828
1,640
NA
1,813
475
576
645
880
832
970
qr/dscf
0.01
310
390
325
440
570
NA
980
2,310
1,750
2,188
545
617
781
890
977
980
MOD = modular; MB= mass-burn, and RDF = refuse-derived fuel.

NA = not available.
                                  2.2-2

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          Purchase equipment cost, 103 $ = 305.2 + 0.00738 * TPA, in     (1)
                                           December 1987 dollars
                                                   2
          where:  TPA is the total plate area in ft  calculated as the
                  product of the SCA in ft /1000 acfm and the flue gas
                  flowrate in 1000 acfm.

     The flue gas flowrate is assumed to be 125 percent of the design
flowrate to accommodate variations in feed waste composition and operating
           o
conditions.   Equation 1 was derived using the Chemical Engineering Plant
Index to update the cost equation shown in Figure 2.2-1 to December 1987
dollars and including the cost for taxes and freight.  Taxes and freight were
estimated at 8 percent of the equipment cost.
     To estimate the required SCA for new units, the following approach was
taken.  Data on SCA's were provided by eight manufacturers, as shown in
            4
Table 2.2-2.   From this table,  the average SCA was calculated for each PM
removal efficiency, as shown in  Table 2.2-3.  The average SCA's from
Table 2.2-3 were correlated with PM collection efficiency using the
Deutsch-Anderson equation.  The  Deutsch-Anderson equation is frequently used
to predict ESP performance.   Using the form of the Deutsch-Anderson
equation, the following equation is derived:
     PM collection efficiency, % = 100 - 101.89 * exp(-0.0112 * SCA) or

     SCA = -(89.29) * In [(100 - PM collection efficiency, %)/101.89] (2)

                                             2
     where SCA = specific collection area, ft /1000 acfm

Figure 2.2-2 presents the "best  fit" equation for the average SCA data.
     Both equations (Equations 1 and 2) reasonably fit the data.  The
                                2
coefficients of determination (R ) were 0.86 for Equation 1 and 0.97 for
Equation 2.  Part of the scatter not explained by Equation 1 may be due to
differences in equipment included in different vendor estimates.
     Equations 1 and 2 apply to  field-erected ESP's with total plate areas
              2
above 6,500 ft  and flue gas flowrates above 30,000 acfm.  ESP's applied to
                                    2.2-4

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-------
            TABLE 2.2-3.  AVERAGE SPECIFIC COLLECTION AREA (SCA)  CALCULATED
                          FROM THE MANUFACTURERS'  DATA

Inlet PM
Loading,
gr/dscf at 12% C02
0.11
0.11
0.11
1.72
1.72
1.72
4.63
4.63
4.63
Outlet PM
Loading,
gr/dscf at 12% C02
0.03
0.02
0.01
0.03
0.02
0.01
0.03
0.02
0.01
PM Removal
Efficiency,
Precent
72.7
81.8
90.9
98.3
98.8
99.4
99.4
99.6
99.8
SCA
ft2/100o'acfm
138 (3)a
172 (3)
208 (3)
332 (9)
397 (8)
500 (8)
406 (2)
504 (2)
553 (2)
aNumber in parantheses indicates the number of data points used for the average.
                                     2.2-6

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smaller modular combustor facilities generally are shop-assembled and are
installed at the facility at a minimal cost.  To estimate the costs of this
type of ESP, cost data from one manufacturer were analyzed using the same
approach as for field-erected ESP's.   The "best fit" equation relating
purchase equipment costs to total plate area (TPA) is:
                                           96.3 + 0.01!
                                           in December 1987 dollars      (3)
Purchase equipment costs,  10 $ = 96.3 + 0.015 * TPA,
                                      R2 = 0.86
Figure 2.2-3 presents the "best fit" equation for the data from this
manufacturer.  Costs received from another ESP manufacturer after Equation 3
was developed are similar to those used to develop Equation 3.
     To estimate the required SCA, the SCA calculated from the manufacturer
cost data was correlated with PM collection efficiency using the
Deutsch-Anderson equation:
          PM collection efficiency, % = 100 - 79.6 * exp (-0.0035 * SCA) or

          SCA = -(285.7) * ln[(100-PM collection efficiency, %)/79.6]     (4)

          R2  =0.90

Figure 2.2-4 presents the "best fit" equation for the SCA data.
     Table 2.2-4 summarizes the procedure for estimating total capital cost
for ESP's using the above four equations.  The SCA required to achieve a
given PM collection efficiency is estimated using either equation 2 or 4.
Purchased equipment costs for the ESP can then be obtained using either
Equation 1 or 3.  For the costs of additional ESP units, the costs of a
single ESP are multiplied by the number of required units.  Procedures for
estimating the costs of ductwork and fan, and installation direct costs are
                              Q
also presented in Table 2.4-4.
     2.2.2.2  Indirect and Other Costs.  The cost factors for estimating
indirect costs for field-erected ESP's are based on those presented in
                                9 10
established EPA cost procedures. '    Because installation and engineering
                                    2.2-8
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-------
         TABLE 2.2-4.  COST PROCEDURES FOR ESTIMATING CAPITAL COSTS
                          FOR ESP'S ON NEW PLANTS3
Purchased Equipment Costs (December 1987 dollars):

Single Field-erected ESP unitb:  Costs, 103$ = 305.2 + 0.00738 * TPA
                                         TPA = SCA * Q/1000
                             PM efficiency % = 100-101.89 exp (-0.0112 * SCA)

Single Shop-assembled ESP unitb'c:  Costs, 103 = 96.3 + 0.015 * TPA
                               PM efficiency % = 100-79.6 exp (-0.0035 * SCA)

Multiple Units:   Costs = N * Costs for single ESP unit

Ductwork:         Costs = 0.7964 * L * Q°'5

Fan:              Costs = 1.077 * Q°'96
Installation Direct Costs = 67% of equipment costs ,


Indirect Costs = 54% of Purchase Equipment Costs for field-erected ESP's
               = $14,000 for shop-assembled ESP's

Contingency = 3% of the Purchase Equipment Costs


Total Capital Investment = Purchased Equipment Costs + Installation Direct
                           Costs + Indirect Costs + Contingency



aTPA = total plate area, ft2       2
 SCA = specific collection area, ft /1000 acfm
   Q = 125 percent of the calculated flue gas flowrate, acfm
   L = Duct length, ft
   N = Number of ESP units

 Includes taxes and freight of 8 percent of the ESP equipment costs.

cApplies only to modular combustors whose flue gas flowrate Q is less than
 30,000 acfm.
                                    2.2-11
-------
costs are less for a shop-assembled ESP than for a field-erected ESP,
indirect costs for shop-assembled ESP's are based on the manufacturer's
estimate of $14,000.    Costs reported in August 1986 dollars were updated to
December 1987 dollars using the Chemical  Engineering Plant Cost Index for all
equipment.
2.2.3   Operating Cost Procedures
     Table  2.2-5 presents the procedure for estimating annual operating costs
for ESP's.   The procedures and factors shown for estimating the various
components  of annual operating costs and the references for each are listed
in Table 2.2-5.  Operating costs are presented in December 1987 dollars.
     To the extent that data are available, cost rates are based on actual
rates in December 1987 dollars.  Operating labor wage rate is the average
from those  obtained from the U. S.  Department of Commerce, in its Survey of
Current Business for private non-agricultural payrolls and the EPRI's
                           12 13
Technical Assessment Guide.  '    Electricity rates were obtained from the
                                                                14
Energy Information Administration,  in its Monthly Energy Review.    An ash
disposal cost rate of $25/ton was used, since typical ash disposal rates
(tipping fees) are between $20 and $30/ton.
                                   2.2-12
-------
      TABLE 2.2-5.  COST PROCEDURES USED TO ESTIMATE ANNUAL OPERATING
                        COSTS FOR ESP'S ON NEW UNITS
Operating Labor:
Supervision:
Maintenance:
       Labor

   Materials
Electricity:

Ash Disposal:
Overhead:
Taxes, Insurance,
and Administrative
Charges:
Capital Recovery:
                                    References
1 man-hour/shifta                      16
15% of operator labor costs            17
0.5 man-hour/shift,                   17,  18
10% wage rate premium
over operating labor wage
1% of the total  capital  costs          17
            2
1.5 watts/ft  collection area          19
0.5 inch pressure drop W.C.             20
$25/ton                                21
60% of the sum of all labor costs      22
(operating,  supervisory, and
 maintenance) and 60% of the
 maintenance material.
4% of total capital  costs              22
15 year life and 10% interest          15
rate
aLabor requirement in the range reported by Reference 16 (from 1/2 to 2 man-
 hour/shift) .
                                   2.2-13
-------
REFERENCES

 1.   U.S.  Environmental  Protection Agency.   Municipal  Waste Combustion Study:
     Costs of Flue Gas Cleaning Technologies.   Research Triangle Park, NC.
     Publication No.  EPA/530-SW-87-021e.  June 1987.  121 p.

 2.   Letter from Sedman, C.B., EPA, to Chang,  J.   Acurex Corporation.
     July 14, 1986.  EPA guidelines for costing flue gas cleaning
     technologies for municipal waste combustion.

 3.   Turner, J.H., et al.   Sizing and Costing  of Electrostatic Precipitators,
     Part II:  Costing Considerations.  Air Pollution  Control Association
     (New York).  38:715 - 726. May 1988.

 4.   Reference 1.

 5.   Radian Corporation.  Background Information  Document for Nonfossil Fuel
     Fired Boilers.  Prepared for the U.S.  Environmental Protection Agency.
     Research Triangle Park,  NC.  Publication  No.  EPA  450/3-82-007.
     March 1982.  p.  4-31.

 6.   Letter and attachments from Martinez,  J.A.,  Radian Corporation, to
     Graham, G., PPC  Industries.  June 20,  1988.   Costs for electrostatic
     precipitators applied to small modular combustors.

 7.   Letter and attachments from Childress, J., United McGill Corporation, to
     Martinez, J.A.,  Radian Corporation.  July 28, 1988.  Costs for
     electrostatic precipitators applied to small  modular combustors.

 8.   Reference 3.

 9.   Reference 3.

10.   U.S.  Environmental  Protection Agency.   EAB Control Cost Manual.
     Research Triangle Park,  NC.  Publication  No.  EPA  450/5-87-001A.
     February 1987.  p.  2-6.

11.   Reference 6.

12.   Electric Power Research  Institute.  TAG™  - Technical Assessment Guide
     (Volume 1:  Electricity  Supply - 1986).   Palo Alto, CA.  Publication
     No. EPRI P-4463-SR.  December 1986.  p.  B-4.

13.   United States Department of Commerce.   Survey of  Current Business.
     Washington, D.C.  Volume 68.  Number 6.   June 1988.  p. S-12.

14.   Energy Information  Administration.  Monthly Energy Review:
     December 1987.  Washington, D.C.  Publication No. DOE/EIA-0035 (87/12).
     March 1988.  p.  109.
                                   2.2-14
-------
15.   Reference 17, p. 3-16.

16.   Vatavuk,  W.  M., and R.  B.  Neveril,  "Estimating Costs of Air Pollution
     Control  Systems, Part II:   Factors  for Estimating Capital and Operating
     Costs,"  Chemical Engineering,  November 3,  1980.   pp. 157-162.

17.   Neveril,  R.  B., (CARD,  Inc).   Capital  and  Operating Costs of Selected
     Air Pollution Control Systems.   Prepared for U.S. Environmental
     Protection Agency.   Research  Triangle Park,  NC.   Publication No. EPA
     450/5-80-002.  December 1978.   p.  3-12.

18.   Reference 17, p. 3-14.

19.   Reference 17, p. 3-18.

20.   Reference 17, p. 5-2.

21.   Reference 10, p. 2-29.

22.   Reference 10, p. 2-31.
                                   2.2-15
-------
2.3  DRY SORBENT INJECTION
2.3.1   Overview of Technology
     Dry sorbent injection is being examined as a control option for achieving
moderate acid gas control and indirectly increasing dioxin control for MWC's.
Two basic variations of this technology exist:
     •    furnace sorbent injection in which alkali sorbent is injected
          through the overfire air ports into the furnace, and
     •    duct sorbent injection in which the sorbent is injected into either
          a duct or a reactor vessel upstream of the particulate control
          system.
Particulate control following sorbent injection can be accomplished by either
an ESP or fabric filter.
     Sorbent injection technologies have been used commercially on MWC's in
Europe and Japan since 1979.   Japanese duct injection technology generally
uses a high-temperature (approximately 500°F) ESP tor particulate matter
collection.  European duct injection technology incorporates a fabric filter
(FF) for particulate control with typical FF inlet temperatures of 350°F.
Furnace and duct sorbent injection systems have recently been installed and
tested at several MWC's in the U. S.  In addition, significant testing of
furnace and duct injection applied to coal-fired systems for SCL control has
occurred.  However, data on the comparative performance and the cost of
different sorbent injection approaches for MWC's are limited.
     The basic chemistry for acid gas control is the reaction of calcium or
sodium sorbent with HC1 and SO^ to form chloride,  sulfite, and sulfate salts.
The degree of acid gas control is a function of sorbent feed rate, the
extent of flue gas and sorbent mixing, the flue gas temperature, and the PM
control device.  For moderate levels of acid gas control, sorbent can be
injected directly into the furnace or the flue gas duct.  For higher levels of
control, a separate reactor vessel can be used that is designed to enhance
flue gas and sorbent mixing and provide additional reaction time.  Flue gas
humidification with water sprays or additional heat recovery in an economizer
or air preheater can be used to reduce flue gas temperature.  Procedures for
estimating the costs of flue gas temperature reduction using humidification
are presented in Section 3.5.
                                     2.3-1
-------
     Based on similarities in equipment requirements,  the capital  costs for
furnace and duct injection are expected to be generally similar.   As a result,
a "generic" cost procedure was developed to estimate the capital  and operating
costs for both types of sorbent injection.  Major equipment associated with
both technologies consists of a storage silo, a pneumatic feeding system for
transferring sorbent from the storage silo to feed bins, feed bins with
                                                              2
gravimetric metering systems, and pneumatic sorbent injectors.    For duct
sorbent injection,  a venturi  or a reaction vessel with mixing baffles is
provided to ensure  adequate gas-to-sorbent mixing.  For furnace sorbent
injection, sorbent  will be injected through the overfire air ports or separate
injection ports in  the combustor.  For new systems, a  FF is assumed for PM
control because of its enhanced acid gas and dioxin removal capabilities
compared to an ESP.
     Primary operating costs include labor, maintenance materials,
electricity, and sorbent.  Labor, maintenance material, and electricity cost
are expected to be  generally similar for both duct and furnace sorbent
injection.  Because of the greater amount of data on calcium-based sorbents,
the cost procedures assume use of hydrated lime (Ca^HJp).  For furnace
injection, limestone (CaCO.,)  or lime (CaO) can be used which may be less
expensive.
2.3.2   Capital Cost Procedures
     The direct capital cost of sorbent injection equipment depends on the
flue gas and sorbent flowrates.  These two parameters, in turn, depend on MSW
feed rate and composition, excess air levels, flue gas temperature, sorbent
quality and utilization rate, and emission control requirements.   Based on a
simple material balance that assumes all of the sulfur and chlorine in the MSW
are converted to SCL and HC1  , sorbent throughput requirements can be
calculated using the following equation:
                    = 74>1 * (2'°00/24) * TPD * [%s/32 + %C1/71] * CAG/PURITY
where:
     TPD    = tons per day of MSW, based on 125 percent of the design capacity
              to accommodate variations in feed waste composition and
              operating conditions ,
                                     2.3-2
-------
     %S     = percent sulfur in the MSW,
     %C1    = percent chlorine in the MSW,
     CAG    = calcium-to-acid gas molar ratio (i.e., stolchiometric
              ratio), and
     PURITY = weight percent of calcium in  the lime.
Based on available data for duct sorbent injection,  a value of 2 for CAG is
expected to achieve removal efficiencies of 80 percent for HC1 and 40 percent
        A
for SO,.   For furnace sorbent injection, a CAG value of 2 is expected to
      <-                                                         5
achieve 70 percent removal of HC1 and 70 percent removal of S(L.   PURITY is
assumed to be 90 percent.
     Procedures for calculating direct capital costs for the individual major
equipment items shown in Table 2.3-1 were derived from data in standard cost
                                              fi 7 ft
estimating manuals and manufacturer estimates. ' '    Cost for a reactor vessel
is based on a vaned, stainless steel tank with one second of flue gas
               g
residence time.   Installation costs are assumed to  be 30 percent of the
equipment costs.    Indirect costs, also shown in Table 2.3-1, are calculated
as a percentage of total direct costs.  These indirect cost rates are the same
as those used for estimating the indirect capital costs of a spray
dryer/FF (presented in Section 2.4-1).  The equations in Table 2.3-1 estimate
costs in December 1987 dollars.  The costs  were escalated to December 1987
dollars using the Chemical Engineering Plant Cost Index for all equipment.
     Capital  costs for pulse jet FF's with  a net air-to-cloth ratio
of 4:1 are estimated using equations for single units.    Direct and indirect
capital costs as a function of flue gas flowrate can be estimated from these
equations.  Installation and indirect costs for FF's are 72 and 42 percent of
                                 12
the equipment cost, respectively.    The flue gas flowrate is based on
125 percent of the design flowrate to accommodate variations in feed waste
composition and operating conditions.  The  costs for FF and auxiliary
equipment are in December 1987 dollars.  Contingency is included to account
for unforeseen costs (50 percent of the direct and indirect cost) during
installation  and start-up due to the relative lack of operating experience of
        >nt
         14
dry sorbent injection systems applied to MWC's.     Projected equipment life is
15 years.
                                     2.3-3
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-------
2.3.3   Operating Cost Procedures
     Table 2.3-2 presents procedures for estimating operating costs for dry
sorbent injection alone.  Operating costs for humidification are presented in
Section 3.5.  The operating and maintenance labor requirements and maintenance
materials for sorbent injection are based on typical  values for coal-fired
boilers.  Electricity costs are based on electrical requirements to operate
the pneumatic feed systems.  Lime costs are based on  the amount of lime
injected.  Equations for electricity and lime were taken from Reference 10.
     Table 2.3-3 presents procedures for estimating operating costs for FF's.
The operating and maintenance labor requirements are  based on those from
established EPA procedures, with the exception of maintenance materials.
Because maintenance material requirements for FF's can vary directly with the
size of the unit, maintenance material  costs are assumed to be calculated at
five percent of the direct capital  costs.  This percentage is the same one
used for dry sorbent injection to estimate maintenance material costs.  The
cost of bag replacement assumes a 2-year bag life, which is typical for FF's.
A gross air-to-cloth ratio of 3:1 is used.
     Electricity to operate the I.D. fan is calculated using a total pressure
drop of 12.5 inches of water, 7 inches  of water across the FF and 5.5 inches
for the additional ductwork and dry sorbent injection.  The cost of compressed
air for the pulse jet FF's is estimated from established EPA procedures.  The
costs for solids disposal are determined from the amount of solids collected
by the FF and a tipping fee of $25/ton.
     All cost rates are based on December 1987 dollars.  The operating labor
wage is the average from those obtained from the Department of Commerce Survey
of Current Business for private nonagricultural payrolls and EPRI's Technical
Assessment Guide.  '    Electricity rates will be obtained from the Energy
Information Administration, Monthly Energy Review.    Operating hours per year
can be varied to meet model plant specifications.
     Indirect operating costs such as taxes, insurance, and administrative
charges are based on percentages of the capital costs. Payroll and plant
overhead are based on a percentage of the labor and material costs.
                                     2.3-6
-------
              TABLE 2.3-2.  ANNUAL OPERATING COST PROCEDURES FOR
                     DRY SORBENT INJECTION FOR NEW MWC's11
Operating Labor:

Supervision:

Maintenance Labor:


Materials:

Electricity:



Lime:


Overhead:
Taxes, Insurance,
and Administrative
Charges:
2 manhour/shift

15% of operator labor costs

0.5 manhour/shift, 10% premium
over operating labor wage

5% of total direct costs

(52.56 * (lime feed ratea) + 251,850) *
(electricity costs) * (hours of
operation/8,760)

4.38 * (lime feed rate3) * (lime cost) *
(hours of operation/8,760)

60% of the sum of all labor costs
(operating, supervisory, and
maintenance) plus maintenance material
4% of total capital  costs
References

    14

    18

  18,  19


  20,  21

    22



    22


    23
    23
aLime feed rate in Ib/hr is based on 100 percent capacity of waste processed.
                                    2.3-7
-------
                TABLE 2.3-3.  ANNUAL OPERATING COST PROCEDURES
                       FOR FABRIC FILTERS FOR NEW MWC's
Operating Labor:
Supervision:
Maintenance Labor:

Materials:
Bag Replacement:

Electricity:

Compressed Air:
Sol id Waste:

Overhead:
Taxes, Insurance,
and Administrative
Charges:
Capital Recovery:
2 manhour/shift
15% of operator labor costs
1 manhour/shift,  10% wage rate premium
over operating labor wage
5% of direct capital costs
        2
$1.35/ft  for teflon coated fiberglass;
2-year 1ife
Calculated based on fan requirements
for inches of water pressure drop
across FF
2 scfm/1,000 acfm flue gas
Apply appropriate tipping fee in $/ton
(Assume $25/ton)
60% of the sum of all labor costs
(operating, supervisory, and
maintenance) plus materials
4% of total capital costs
15-year life and 10% interest rate
References
    24
    24
  18, 24

    20
    25

    26

    27
    28

    23
    23
    29
                                     2.3-8
-------
                                  REFERENCES

 1.  Radian Corporation.  Municipal  Waste Combustors - Background Information
     for Proposed Standards:  Post-Combustion Technology Performance.
     EPA-450/3-89-27C.  August 1989.

 2.  Reference 1.

 3.  Letter from Sedman, C.B., EPA,  to Chang, J., Acurex Corporation.
     July 14, 1986.   EPA guidelines  for costing flue gas cleaning technology
     for municipal  waste combustion.

 4.  Reference 1.

 5.  Reference 1.

 6.  Callaspy, D.T.   Dry Sorbent Emission Control Prototype Conceptual Design
     and Cost Study.  Presented at the First Joint Symposium on Dry S02 and
     Simultaneous SCL/NO  Control  Technologies. November 1984.
                    £   /\

 7.  Process Plant  Construction Estimating Standards.  The Richardson Rapid
     System.  Volume 4.  1982.  p. 100-45.

 8.  Stearns Catalytic Corporation.   Economic Evaluation of Dry-Injection Flue
     Gas Desulfurization Technology.  Prepared for Electric Power Research
     Institute.   Palo Alto, CA.  EPRI No. CS-4343.  January 1986.  Appendix A.

 9.  Garrett, D.E.   Chemical Engineering Economics.   Van Nostrand Reinhold,
     New York.  1989.  p. 298.

10.  Radian Corporation.  Industrial Boiler Furnace  Sorbent Injection
     Algorithm Developed.  Prepared  for U. S. Environmental Protection Agency.
     Research Triangle Park, NC.  Contract No. 68-02-3994.  May 1986.  p. 10.

11.  U.  S.  Environmental Protection  Agency.  Municipal  Waste Combustion Study:
     Costs  of Flue  Gas Cleaning Technologies.  Research Triangle Park, NC.
     Publication No. EPA/530-SW-87-021e.  June 1987.  p. 3-6.

12.  Reference 10,  pp. 9 and 10.

13.  Electric Power Research Institute.  TAG^-Technical Assessment Guide
     (Volume 1:   Electricity SUDD!v-1986).  Palo Alto,  CA.  Publication No.
     EPRI P-4463-SR.  December 1986.  p. 3-3.

14.  U.  S.  Environmental Protection  Agency.  EAB Control Cost Manual.
     Research Triangle Park, NC.  Publication No. EPA-450/5-87-001A.  February
     1987.   p. 5-42.

15.  Reference 13,  p. B-4.
                                    2.3-9
-------
16.   United States Department of Commerce.  Survey of Current Business.
     Washington, D.C.  Volume 68.   Number 6.  June 1988.  p. S-12.

17.   Energy Information Administration.   Monthly Energy Review:
     December 1987.   Washington, D.C.   Publication No. DOE/EIA-0035 (87/12).
     March 1988.  p. 109.

18.   Reference 10, p. 12.

19.   Neveril, R.B.,  (GARD Inc.).  Capital and Operating Costs of Selected Air
     Pollution Control  Systems.   Prepared for U. S. Environmental Protection
     Agency.   Research  Triangle  Park,  NC.  Publication No. EPA 450/5-80-002.
     December 1978.   p. 3-12.

20.   Reference 10, p. 11.

21.   Reference 8, p. 1-9.

22.   Kaplan,  N.  et al.   Control  Cost Modeling for Sensitivity and Economic
     Comparison.  Proceedings from the 1986 Joint Symposium on Dry S02 and
     Simultaneous S0,/N0  Control  Technologies, EPRI CS-4966, Volume 2.
                    £   A

23.   Reference 14, p. 2-31.

24.   Reference 10, p. 2-31.

25.   Reference 14, p. 5-39 and 5-43.

26.   Reference 20.

27.   Reference 14, p. 5-45.

28.   Reference 14, p. 2-29.

29.   Reference 19, p. 3-16.
                                   2.3-10
-------
2.4   SPRAY DRYING WITH EFFICIENT PARTICULATE CONTROL
2.4.1  Overview of Technology
     Spray drying is designed to control S02 and HC1 emissions.  When used in
combination with an efficient participate control system, spray drying can
also control CDD/CDF, PM, and metals emissions.  In the spray drying process,
lime slurry is injected into a spray dryer (SD) vessel.  The water in the
slurry evaporates to cool the flue gas, and the lime reacts with acid gases to
form salts that can be removed by a PM control device.  The simultaneous
evaporation and reaction increases the moisture and particulate content in the
flue gas.  The particulate exiting the SD vessel contains fly ash plus calcium
salts, water,  and unreacted lime.
     Spray drying is commonly used in combination with either a fabric
filter (FF) or an electrostatic precipitator (ESP) for PM control.  Both
combinations have been used for MWC's in the United States, although SD/FF
systems are more common and may be more effective for CDD/CDF, PM, and metals
control.   Two basic designs of FF's are available:" reverse air and
pulse jet.  In a reverse air FF,  flue gas flows through unsupported filter
bags, leaving the particulate on  the inside of the bags.   The particulate
builds up to form a particulate filter cake.   Once an excessive pressure drop
across the filter cake is reached, air is blown through the filter in the
opposite  direction,  the filter bag collapses,  and the filter cake falls off
and is collected.  In a pulse jet FF, flue gas flows through supported filter
bags leaving particulate on the outside of the bags.  To  remove the built-up
particulate filter cake, compressed air is introduced through the inside of
the filter bag,  the filter bag expands and the filter cake falls off and is
collected.  The cost procedures are based on  pulse jet FF systems.
2.4.2  Capital  Cost Procedures
     Vendor capital  cost estimates for SD systems combined with either an ESP
or a FF applied to three types of MWC's (mass-burn, modular, and RDF) were
obtained  for systems designed to  achieve 90 percent HC1 and 70 percent S0«
removal  and PM emissions of 0.01, 0.02,  and 0.03 gr/dscf  at 12 percent COp.1
     A cost comparison of SD/FF and SD/ESP systems designed to achieve a PM
emission  rate  of 0.01 gr/dscf at  12 percent C02 is presented in Appendix A for
                                     2.4-1
-------
two mass-burn facility capacity sizes (250 and 3,000 tons/day of MSW).  This
comparison indicates that, at this PM control level, costs for SD/FF and
SD/ESP systems are very similar, with the annualized costs for SD/FF's being
slightly lower than for SD/ESP's.  Although cost procedures presented in this
section focus on SD/FF systems, they are representative of costs for SD/ESP
systems.
     Cost procedures for stand-alone SD systems (i.e., without a FF) are
presented in Section 3.6.  These procedures were developed based on the SD/FF
data plus supplemental cost quotes from three SO manufacturers.  These cost
procedures are intended to assist in evaluating methods to retrofit SD systems
at existing plants already equipped with efficient PM control devices.
     2.4.2.1   Direct Costs.  Direct costs for an SD/FF system include
purchased equipment cost for an SD, FF,  induced draft (I.D.) fan, and ducting.
The SD components include a reaction vessel, atomizer, lime feed preparation
equipment, and solids handling equipment.  The SD is sized based on a
stoichiometric ratio (moles of calcium per mole of both 862 and HC1 in the
flue gas entering the spray dryer) of 1.5:1.  The FF cost is based on a
pulse-jet type unit operated at a net air-to-cloth ratio of 4:1 and a gross
air-to-cloth ratio of 3:1.
     Costs for single SD/FF units were based on cost data provided by two
manufacturers as shown in Table 2.4-1.  The data from these two manufacturers
were used to estimate installed capital  costs of SD/FF systems for all furnace
                                                                         2
types and are plotted as a function of flue gas flowrate in Figure 2.4-1.
The costs are approximately the same for any combustor type at the same
flowrate.  There are two reasons for this.  First, the cost of the FF is
assumed to be sensitive only to flue gas flowrate and is unaffected by PM
grain loading.  Second, the inlet SCk and HC1 concentrations in the flue gas
were assumed to be essentially the same for all facility types.  Inlet SO- and
HC1 concentrations primarily depend on the MSW composition (particularly
sulfur and chlorine contents) and MSW heating value.  The values for these
three factors assumed for the three facility types result in approximately the
same S0« and HC1 concentrations.
                                     2.4-2
-------
         TABLE 2.4-1.  VENDOR QUOTES FOR SPRAY DRYER/FABRIC FILTER TOTAL
                            CAPITAL COSTS (IN $1,000 AUGUST 1986)a
                        Flue gas
                   ;e   flowrates,  Outlet PM emissions, qr/dscf at 12% CO,,
Vendor
C
C
G
type
MB
MB
MB
acfm
24,523
245,230
245,230
0.03
1,712
5,262
6,000
0.02
1,712
5,262
6,000
0.01
1,762
5,624
6,000
   Installed capital costs reported are the purchase costs for one unit
   multiplied by a 1.6 adjustment factor.  Auxiliary equipment costs are not
   included.

   MB = mass-burn.

  C0utlet grain loading from fabric filters.
tmg.017
section.2-4
2.4-3
-------
   too
   90
e
J
   to
                                                                          OulM Loading.
                                                                           0.01
                                                                           0.02grM«cf
                                                                           	Q	
                                                       0.03grM«cf
    Figure 2.4-1.
Capital cost  estimates of an SD/FF for  a model  MB facility,  and

RDF facility.2
                                        2.4-4
-------
     Table 2.4-2 summarizes the capital cost procedures for single SD/FF
units.  These procedures are based on achieving a PM control level of
0.01 gr/dscf at 12 percent CCu.   The equation was developed from
Figure 2.4-1.
     From Table 2.4-2, the total direct costs can be estimated for single
units by knowing the  inlet flue gas flowrate and the length of ductwork
needed.  The flue gas flowrate is based on 125 percent of the design flowrate
to accommodate variations in feed waste composition and operating conditions.
To estimate the costs of multiple units, the direct costs of a single SD/FF
unit including auxiliary equipment are multiplied by the number of units.
     2.4.2.2  Indirect and Other Costs.  To be consistent with established EPA
methodology, the equations were adjusted to distinguish direct costs (i.e.,
purchased equipment and installation costs) from indirect capital costs (i.e.,
engineering costs, construction and field expenses, contractor fees, start-up
and performance test costs).  To separate these costs, indirect costs are
assumed to be 33 percent of the direct capital costs.   Contingency is assumed
to be similar to that applied to fossil-fuel  fired boilers.   Interest during
construction and working capital is not included for air pollution control
devices.   Costs are reported in December 1987 dollars.  The Chemical
Engineering Plant Cost Index for all equipment was used to escalate costs from
August 1986 dollars.
     2.4.3  Operating Cost Procedures
     Table 2.4-3 presents the procedure for estimating operating costs.  In
general, the references in this table have been used in previous EPA cost
analyses.
     The operating and maintenance labor requirements for SD/FF are based on
those used in fossil fuel industrial boiler cost analyses and assume that
operating and maintenance labor costs bases would be essentially the same for
coal-fired industrial  boilers and MWC facilities.  However, the maintenance
material cost for SD/FF systems applied to MWC facilities is usually lower
than  the cost for systems at coal-fired boiler facilities, since uncontrolled
SCL emissions are much higher from coal-fired boilers.  Because SCu
concentrations are lower at MWC facilities, less concentrated slurries can be
                                    2.4-5
-------
        TABLE 2.4-2.  CAPITAL COST PROCEDURES FOR SD/FF FOR NEW MWC'S3
Total Direct Costs (December 1987 dollars)
Single SD/FF Unitb:  Costs, 103 $ = 8.053 (Q)0'517
Ductworkb:  Costs, 103 $ = [1.3868 * L * Q°'5]/l,000
Fanb:  Costs, 103 $ = [1.8754 * Q0t96]/l,000
Multiple Units:  Multiply the above costs by the number of units
Indirect Costs = 33% of total direct costs
Contingency = 20% of sum of direct and indirect costs
Total Capital Costs = Total Direct Costs + Indirect Costs + Contingency Costs
aQ = 125 percent of the actual flue gas flowrate, acfm
 L = Duct length, feet
 Assumes that the total installed costs are 133 percent of the direct capital
 costs.
                                     2.4-6
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              TABLE 2.4-3.  ANNUAL OPERATING COSTS PROCEDURES FOR
                    SPRAY DRYER/FABRIC FILTER FOR NEW MWC's3
                                                                     Reference

Operating Labor:  4 manhours/shift; $12/manhour                         8, 9

Supervision:  15% of operating labor costs                               10

Maintenance:

     Labor:   2 manhours/shift; 10% wage rate premium                     9
              over operating labor wage

     Materials:  2% of direct capital costs                              11

Bag Replacement:
                    2
     Bags:  $1.35/ft  for teflon-coated fiberglass;                      12
            2-year life for SD/FF;
            Bag replacement cost not included for SD only

Electricity:  Cost Rate = $0.046/kwh

     Fan:  12.5 inches of water pressure drop                          13, 14

     Atomizer:  6kW/l,000 Ibs/hr of slurry feed + 15kW                   15

     Pump:  20 feet of pumping height                                    16
            10 psi discharge pressure
            10 ft/sec velocity in pipe

Compressed Air:  2 scfm air/1,000 acfm flue gas;                         17
                 $0.11/1,000 scfm of air

Water:   Calculate water flowrate required for cooling the flue           18
        gas to 300°F; water cost = $0.50/1000 gal

Lime:   Based on lime feed rate calculated for a given                    19
       stoichiometric ratio; lime cost = $70/ton

Solid Waste:  Calculate solid waste collected by the spray               20
              dryer and fabric filter using PES program and
              apply appropriate ash disposal  fee in $/ton;
              Assume $25/ton


                                                                  (continued)
                                    2.4-7
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                           TABLE 2.4-3.  (Continued)
                                                                     Reference

Overhead:  60% of the sum of all labor costs (operating,                 21
           supervisory, and maintenance) plus materials

Taxes, Insurance, and
 Administrative Charges:  4% of total capital costs                      21


Capital Recovery:  15-year life and 10% interest rate                    22
aAll costs are in December 1987 dollars.
                                     2.4-8
-------
used to achieve the same removal efficiency, which in turn result in less
erosion of equipment and potential for plugging.  Therefore, the maintenance
                                                                    23
material cost was estimated at 2 percent of the direct capital cost.
Estimating the material cost at 2 percent of the direct capital cost
corresponds to 1.25 percent of the total capital costs.
     The costs of bag replacement assumes a 2-year bag life, which is a
                          24
typical bag-life for FF's.    A gross air-to-cloth ratio of 3:1 is used.
Electricity costs include electricity consumed by the I.D. fan, atomizer, and
slurry pumps.  Electricity consumed by the I.D. fan is calculated using a
pressure drop of 12.5 inches of water across the SD/FF.  Atomizer electrical
                                                    25
requirements are based on the amount of slurry feed.    Slurry pumping
requirements are estimated from assumed pumping height, discharge pressure,
                                                          26
and fluid velocity in pipe used in previous cost analysis.    The costs for
compressed air for pulse-jet FF's are estimated from the air usage rate of 2
                            27
scfm/1,000 acfm of flue gas.    The stoichiometric ratio (moles of calcium per
mole of SOp and HC1 in the inlet flue gas) assumed is 2.5 to achieve 90
percent SOp and 97 percent HC1 removals.
     All cost rates are based on December 1987 dollars.  The operating labor
wage rate used is the average from those in the Department of Commerce, Survey
of Current Business for private nonagricultural payrolls and EPRI's Technical
                 ?8 29
Assessment Guide.  '    Electricity rates are from the Energy Information
Administration, Monthly Energy Review.    The freight-on-board (FOB) costs for
quick lime (calcium oxide, CaO), $45/ton bulk, are from the Chemical Marketing
Reporter;   an additional cost of $25/ton is assumed for transportation, based
on a hauling rate of $0.05/ton-mile and a 500-mile hauling distance.  For
estimating ash disposal costs, a tipping fee of $25/ton is used.  For new
plants, the operating costs will be based on the assumption of 8,000 hours of
operation per year; however, operating costs can be calculated for any number
of operating hours.
                                    2.4-9
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                                  REFERENCES

 1.   U.  S.  Environmental  Protection Agency.   Municipal  Waste Combustion
     Study:   Costs of Flue Gas Cleaning Technologies,  Research Triangle
     Park,  NC.   Publication No. EPA/530-SW-87-021e.   June 1987.  121 pp.

 2.   Reference  1,  p.  4-10.

 3.   Reference  1.

 4.   Letter from Sedman,  C.B., EPA, to Chang, J.,  Acurex Corporation.
     July 14,  1986.   EPA  guidelines for costing flue gas cleaning technology
     for municipal waste  combustion.

 5.   Bowen,  M.L. and  M.S.  Jennings.  (Radian Corporation.)   Cost of Sulfur
     Dioxide,  Particulate Matter,  and Nitrogen Oxide Controls in Fossil Fuel
     Fired  Industrial Boilers.  Prepared for the U.  S.  Environmental
     Protection Agency.   Research  Triangle Park, NC.  Publication No.
     EPA-450/3-82-021. August 1982.   p. 2-11.

 6.   Reference  4.

 7.   U.  S.  Environmental  Protection Agency.   EAB Control Cost Manual.
     Research Triangle Park, NC.   Publication No.  EPA-450/5-87-001A.
     February 1987.   p.  2-6.

 8.   Memorandum from  Aul,  E.F., et al., Radian Corporation,  to Sedman, C.B.,
     EPA.  May  16, 1983.   36 pp.   Revised Cost Algorithms for Lime Spray
     Drying and Dual  Alkali FGD Systems.

 9.   Neveril,  R.B. (CARD,  Inc).  Capital and Operating Costs of Selected Air
     Pollution  Control Systems.  Prepared for the U. S. Environmental
     Protection Agency.   Research  Triangle Park, NC.  Publication
     No. EPA-450/5-80-002.  p. 3-12.

10.   Reference  7,  p.  5-43.

11.   Electric Power Research Institute.  TAG^-Technical Assessment Guide
     (Volume 1:  Electricity Supply-1986).  Palo Alto,  CA.   Publication
     No. EPRI P-4463-SR.   December 1986.  p. 3-10.

12.   Reference  7,  p.  5-39 and 5-43.

13.   Reference  7,  p.  5-45.

14.   Letter and attachment from Fiesinger, T., New York State, Energy Research
     and Development  Authority, to Johnston, M., EPA.   January 27, 1987.
     Draft  report on  the  economics of various pollution control alternatives
     for refuse-to-energy plants,   p. 6-9.

15.   Reference 1,  p.  4-23.
                                   2.4-10
-------
16.  Dickerman, J.C. and K.L. Johnson.  (Radian Corporation.)  Technology
     Assessment Report for Industrial Boiler Applications:  Flue Gas
     Desulfurization.  Prepared for the U.S. Environmental Protection
     Agency.  Washington, DC.  Publication No. EPA-600/7-79-178i.
     November 1979.  pp. 5-5 and 5-17.
17.  Reference 7, pp. 5-46 and 5-52.
18.  Letter from Solt, J.C., Solar Turbines Incorporated, to Noble, E., EPA.
     October 19, 1984.  Development cost for wet control for stationary gas
     turbines.
19.  Chemical Marketing Reporter.  Volume 233.  Number 1.  January 4,  1988.
20.  Reference 7, p. 2-29.
21.  Reference 7, p. 2-31.
22.  Reference 5, pp. 2-17 and 2-18.
23.  Reference 17.
24.  Reference 12.
25.  Reference 1.
26.  Reference 18.
27.  Reference 19.
28.  Reference 11,  p. B-4.
29.  United States  Department of Commerce.  Survey of Current Business.
     Washington, D.C.  Volume 68.  Number 6.  June 1988.  p. S-12.
30.  Energy Information Administration.  Monthly Energy Review:
     December 1987.  Washington, D.C.  Publication No. DOE/EIA-0035 (87/12).
     March 1988.  p. 109.
31.  Reference 21.
                                   2.4-11
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2.5  COMPLIANCE MONITORING
     Continuous emission monitoring (CEM) systems are used to determine
compliance with emission limits for MWC facilities.   The following sections
describe monitoring systems for opacity, S02, HC1,  02, and CO^.  Section 3.1
discusses the types of combustion control monitors  required for good
combustion practices.
2.5.1  Overview of Technology
     2.5.1.1  Continuous Opacity Monitoring .  Stack opacity can be
continuously measured using emission measurement systems based on the
principle of transmissometry.  Transmissometry measures the attenuation of
visible light by particulate matter in stack effluent.  Light from a lamp
source is projected across the stack to a light sensor.  The degree of
attenuation (opacity)  reflects the amount of light  adsorbed and scattered by
the particulate matter in the effluent.
     The EPA regulations (Appendix B of 40 CFR Part  60) require the opacity
monitoring system to operate for a minimum of 168 hours within certain
performance specifications without unscheduled maintenance, repair, or
adjustment.  The regulations set forth minimum performance criteria for the
following system parameters:  calibration error (<3  percent), 24 hour zero
drift (<2 percent), 24 hour calibration drift (<2 percent), and response time
(10 seconds maximum).   During or before installation, it is necessary to
calibrate, zero, and span using calibration filters  and to perform all
alignments.
     To validate accuracy, as required in 60.13(d),  instruments automatically
perform simulated zero and span calibration checks  at selectable intervals
(usually daily).  It is also usually necessary to have an air purge system to
prevent accumulation of particulate from condensing  on the optical surfaces.
Maintenance is typically required on an as-needed basis (usually weekly).
This involves cleaning all filters, checking the optical alignment and the air
purge system, and recalibrating the instrument.
                                       2
     2.5.1.2  Continuous SO,, Monitoring  .  Continuous monitoring of SO,
                           z                                          i.
emissions is typically accomplished by irradiating  a given volume of sample
air by ultraviolet (UV) or infrared (IR) light and  measuring either the
                                     2.5-1
-------
energy absorbed or the resulting fluorescence of the S02 molecules.
Commercially available units differ in design and method, but in general it is
necessary to:  (1) collimate the light from the original source to provide a
narrow band; (2) prepare the sample for analysis; and (3) increase the
signal-to-noise ratio of the final signal via phase-sensitive detection,
second derivative spectroscopic measurement, or other techniques.
     All SO- monitoring systems required under NSPS must have complete zero
and span calibration checks performed daily.  If not, a weekly manual check is
recommended.  About every month, it is necessary to clean, service, and
readjust the instrument.  The actual maintenance schedule needed depends on
the instrument and the site of application.  Instruments utilizing filters,
chillers, sample dryers, or support gases typically require more maintenance.
     Continuous monitoring systems must be installed at sampling locations
where representative measurements can be made of the total emissions from the
affected facility, or can be corrected so as to be representative.  The SCL
monitoring system must be capable of operating for a 168-hour minimum within
certain performance specifications without unscheduled maintenance, repairs or
adjustments.  The regulations (Appendix B of 40 CFR Part 60) set forth minimum
performance criteria for the following system parameters:  accuracy
(<20 percent) and 24-hour calibration drift (2.5 percent of span).  The
calibration drift is determined using calibration gases (i.e., gases of known
concentrations), gas cells, or optical filters.  The relative accuracy is
determined by measuring pollution concentrations with EPA reference methods
while concurrently operating the continuous monitoring system.
     2.5.1.3  Continuous HC1 Monitorjng.  The EPA has not published
performance specifications for HC1 monitors, but is currently evaluating the
reliability, accuracy, and reproducibility of various monitoring systems.  The
outcome of this evaluation will  determine which monitoring systems will serve
as the basis for any ensuing EPA performance specifications for continuous HC1
monitors.
     In brief,  four types of extractive monitors are being evaluated and are
available commercially.  The first type is a wet chemical batch process.   A
sample of the flue gas passes through an automatic bubbler system, and the
HC1-laden liquor is sprayed against a specific ion electrode.  The second type
                                     2.5-2
-------
is a nondispersive infrared (NDIR) analyzer.   This instrument determines the
HC1 concentration of the sample flue gas by ratioing the peak heights of the
flue gas and reference gas.  Both types of monitors are certified for CEM
applications in West Germany.
     The third type uses a tape sampler.   A sample of gas is exposed to a
chemically impregnated tape.  The HC1 in the flue gas reacts with the
chemical on the tape leaving the tape stained.   The instrument determines the
HC1 concentration by measuring the reduction in transmissivity of the tape.
The last type of monitoring system is based on  continuous spectrophotometry.
A sample of flue gas is contacted with a thiocyanate reagent stream in a
column.  The reagent leaving the column, which  contains adsorbed HC1, is fed
to the spectrophotometer to obtain an HC1 signal.  These two types are not
certified for CEM applications in West Germany.
     2.5.1.4  Diluent (Op/CO,,  Monitoring).   Diluent monitors are an integral
part of an S02 or HC1 continuous monitoring system.  Diluent concentrations
(02 or COp on a percent basis) are required to  convert actual concentrations
of SOp or HC1 to concentrations at either 7 percent 02 or 12 percent CCL.
     Continuous monitoring of 02 is based on the paramagnetic properties of
02 molecules and their response to nonhomogeneous magnetic fields or by oxide
cell differential voltages.  Monitoring C02 is  accomplished through infrared
absorption methods.
2.5.2   Compliance Monitoring  Costs
     Table 2.5-1 summarizes the continuous monitoring costs associated with PM
only, acid gas only, and PM and acid gas controls combined.  Except for HC1
and operating costs for S02 and 02 monitors, the monitoring costs are the same
as those used by EPA in developing NSPS for both small and industrial steam
                 o
generation units.   Costs for HC1 monitors and  operating costs for a combined
                                               8 9
S02/02 monitor are based on recent information.  '
     The capital costs were updated to December  1987 dollars using the
Chemical Engineering Plant Cost Index for all equipment, while the operating
costs were updated to the same time bases using  the Bureau of Labor
Statistics' Producer Price Index for all industrial commodities.  An automatic
data reduction system is included in all options shown in Table 2.5-1.
                                     2.5-3
-------

TABLE 2.5-1. CONTINUOUS MONITORING
(December 1987 Dollars)
{JST SUMMARY




Pollutant
PM
Acid Gas



PM + Acid Gas




Capital
Costs
Method ($1,000)
Opacity3 61
SO, (inlet and outlet) 67
HCt (inlet and outlet) 140
02/C02 19
Data Reduction System 31
Total 256
Opacity3 61
S09 (inlet and outlet) 67
HCT (inlet and outlet) 140
00/C00 19
£' — 	 c. 	 	
Total 286
Operating
Costs .
($l,000/yr)D
8
10
74
15
4
103
8
10
74
15

107
Annual i zed
Costs
($l,000/yr)c
16
19
92
18
8
137
16
19
92
18

145

 Includes costs for automatic data reduction system.

 Based on 2 certifications/year and maintenance requirements of 0.5 man-hour/
 day for opacity and Op/COp monitors and 1 man-hour/day for SOp and HC1
 monitors.

°Annualized costs include annual operating costs and capital charges on
 equipment and installation costs.  Capital charges are based on a 15-year
 equipment life at 10 percent interest rate.
                                     2.5-4
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                                  REFERENCES

 1.   Radian Corporation.   Industrial  Boiler NSPS Issue Papers'  Issue Paper
     No.  7 Compliance Monitoring Costs.   Prepared for the U.S.  Environmental
     Protection Agency.   Research Triangle Park, N.C.  September 1980.
     pp.  A3 and A-4.

 2.   Reference 1.   pp. A-l and A-2.

 3.   Letter and attachments from Rigo,  H.G., Rigo and Rigo Associates,
     Incorporated,  to Russo,  G.P.,  Connecticut Resources Recovery Authority.
     November 18,  1986.   p. 1.  Draft position papers on technical  questions
     concerning Connecticut waste-to-energy projects.

 4.   Reference 3.

 5.   Reference 3.   p. 2.

 6.   Reference 5.

 7.   Reference 1.   pp. A-3 and A-4.

 8.   Kiser, J.V.,  "More on Continuous Emissions Monitoring",  Waste Age,
     June 1988.  p. 124.

 9.   Memorandum from Peeler,  J., Entropy Environmentalists, Inc., to Riley,
     G.,  EPA.  June 1, 1988.   Review of Draft MWC Compliance  Monitoring
     Document.

10.   Radian Corporation.   Industrial  Boiler SOp Cost Report.   Prepared for the
     U.S. Environmental  Protection Agency.  Research Triangle Park, N.C.
     Publication No.  EPA-450/3-85-011.   November 1984.  p. 2-23.

11.   Reference 1.   p. 3.
                                     2.5-5
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                      3.0  PROCEDURES FOR EXISTING PLANTS

     This section presents procedures for estimating costs for existing
municipal waste combustion (MWC) plants. Most procedures presented in this
section rely on those procedures discussed for new plants.  However,
additional procedures are developed which are unique to existing plants such
as costs for combustion modifications to the combustors, flue gas cooling
using humidification, and downtime associated with either the installation of
the air pollution control device (APCD) or modifications to the combustor.
This section also provides a methodology to assess the higher costs of
installing APCD's at existing plants, compared to new plants, using retrofit
factors.
     Section 3.1 presents procedures for estimating costs for operating the
existing combustor.  Procedures for estimating costs of combustion
modifications are presented in Section 3.2.  Section 3.3 provides the
procedure for estimating costs for flue gas temperature control using
humidification.  Sections 3.4, 3.5, and 3.6 discuss estimation of costs for
particulate matter control, dry sorbent injection, and spray drying,
respectively.  Section 3.7 present the methodology to determine retrofit
factors and additional site-specific costs.  Downtime costs associated with
the installation of an APCD or modifications to the combustor at an existing
plant are discussed in Section 3.8.
3.1  OPERATION OF THE EXISTING COMBUSTORS
     No capital costs are estimated for the combustors and other equipment
associated with the balance of plant, because these costs are sunk and are
independent of the costs for retrofitting additional APCD's.  Therefore, only
the operating costs of the combustors and the balance of the plant are
considered.  Operating costs procedures for new combustors and the balance of
plant are presented in Section 2.1 and are assumed to be the same for existing
plants.  For existing plants, capital recovery costs are not included in the
total operating costs.
                                     3.1-1
-------
3.2  COMBUSTOR MODIFICATIONS
3.2.1  Introduction
     This section describes the methodology and assumptions used to estimate
capital  and annual costs associated with combustor modifications needed to
                                 1 2
ensure good combustion for MWC's.  '   The organization of this chapter is as
follows:

     •    Section 3.2.2 discusses  the approach used to estimate capital costs
          for each of the combustion modifications, including all assumptions.
          An example calculation is provided for each retrofit.
     •    Section 3.2.3 provides a methodology for estimating annual costs for
          MWC plants.

The Chemical Engineering Plant Cost Indices are used to convert costs to
December 1987 dollars.
3.2.2  Capital Cost Procedures
     Capital cost estimates were calculated for each retrofit component and
expressed as a direct, installed cost,  unless otherwise noted.  When
uninstalled equipment costs are provided, an installation factor is applied:

     Direct Capital Cost (DCC) = 1.45(Equipment Cost)

The installation factor applies to delivered equipment in a solids processing
plant.
     Capital costs that may vary based  on unit size must be scaled using
factors.   For example, the cost of a modification, C, at a unit of a given
size is  scaled for a unit of different  size by the following equation:

                         Cj = C2 (TPDj/TPDg)"

     where:
               C,  = scaled capital  cost of equipment at unit #1;
               C« = capital cost of equipment at unit #2;
                                     3.2-1
-------
               TPDj = capacity (tons per day) of unit #1; and
               TPD2 = capacity (tons per day) of unit #2.
The exponent n varies according to the retrofit application.  It is assumed
that the volumetric heat release (Btu/ft -hr) is constant for similar
combustor types (i.e., mass-burn waterwall,  RDF-fired, etc.).  Therefore, for a
given design, unit firing capacity (tons per day) scales directly with furnace
volume.  Consequently, a change in a given design feature will vary as the
cube root of each resulting change in dimension modifications, and the
exponent is 0.667.  In the case of retrofitting a row of overfire air nozzles,
where a one-dimensional change is required (along the width of the combustor),
the exponent is 0.333.  Perry's Chemical Engineers' Handbook also applies
                                                  A
typical exponents for various pieces of equipment.    The exponent values
range from 0.30 to 1.00 depending on the specific equipment.  As noted in
Perry's Chemical Engineer's Handbook, use of exponents to estimate costs
results in a slightly higher probable error (10 to 50 percent) than study
estimates (up to 30 percent).
     Indirect capital costs (ICC) and contingencies must be applied to the
direct capital costs  (DCC) estimates.   Indirect capital costs, which include
general facilities and engineering and home office costs, etc., are calculated
as 30 percent of DCC:

                              ICC = 0.30(DCC).

A single contingency  is applied to the DCC:

                         Contingency = 0.20(DCC).

The 20 percent contingency factor is applied in all cases except when a
retrofit is judged to be especially difficult, such as with stoker (grate)
                                     3.2-2
-------
replacement; a contingency factor of 30 percent is used in this case.  The
total plant capital cost (TPC) is calculated as follows:

                         TPC = DCC + ICC + Contingency.

     The following subsections describe the costing methodology for specific
retrofit elements, including:

     •    Stoker rehabilitation,
     •    Refractory-wall furnace reconfiguration,
     •    Fuel feeding modifications,
     •    Underfire air modifications,
     •    Overfire air modifications,
     t    Monitoring/control modifications,
     •    Auxiliary fuel burner installation,  and
     •    Economizer installations for flue gas temperature reduction.

3.2.2.1  Stoker Rehabilitation
     This modification includes demolition and replacement of existing stoker,
drives, siftings hopper, siftings conveyor, and structural steel.  It is also
assumed that a new stoker is equipped with a ram feeder.

     •    Chesner reports direct  capital costs for stoker rehabilitation for
          four 250-tpd units to be $4,160,000  (in December 1984 dollars) based
          on quotes from two stoker equipment  suppliers.
     •    Assume single unit cost for 250-tpd  unit is $1,040,000.
     •    Apply CEP index:
               12/84 - 324.3
               12/87 - 332.5
               Unit Cost = 1,040,000 (332.5/324.3) = $1,066,000.
     •    Apply scaling factor and account for number of units:
               DCC = 1,066,000 (TPD/250)'677(number of units).
                                     3.2-3
-------
     •    Example:  Estimate the direct capital cost of replacing traveling
          grates with new reciprocating grates in two 375-tpd units:
               DCC = 1,066,000 (375/250)'677 (2) = $2,797,000.
3.2.2.2  Refractory-Wall Furnace Reconfiguration
     This modification includes material and labor for reconstructing the
combustion chambers and refractory-lined flues, including structural steel and
refractory brickwork.  It is assumed that new overfire air nozzles and
sampling ports are included in the new furnace design.

     •    Chesner reports direct capital costs for furnace reconfiguration for
          four 250-tpd units to be $6,072,000 (12/84 dollars).
     t    Assume single unit cost for a 250-tpd unit is $1,518,000.
     •    Apply CEP index:
               12/84 - 324.3
               12/87 - 332.5
               Unit Cost = $1,518,000(332.5/324.3) = $1,556,000.
     t    Apply scaling factor:
          DCC = l,556,000(TPD/250)'667(number of units).
     •    Example:  Estimate the direct capital cost of reconstructing two
          120-tpd refractory wall combustors:
          DCC = 1,556,000(120/250)>667(2) = $1,903,000.
3.2.2.3  Fuel Feeding Modifications
     Ram Feeder - This modification includes material and labor, including the
hydraulic system, for a new ram feeder, plus any necessary modifications to
the feed chute.

     •    Nashville Thermal reports 1979 direct capital (installed) costs of
          ram feedecs (one dual ram for each of two 360-tpd units) to be
          $360,000.'
     •    Assume that the unit cost is $180,000 for dual rams and $90,000 for
          single ram.  (Single rams can be used for grates with widths up to
          8 feet.)
                                     3.2-4
-------
     t    Apply CEP Index:

          1979 (yearly average) - 247.6
          12/87 - 332.5
          DCC = 90,000(332.5/247.6} = $121,000 per ram feeder.

     •    Example:  Estimate the direct capital  cost of retrofitting one ram
          on each of two 120-tpd units with 8-foot wide grates:

          DCC = $121,000(2) = $242,000.

     RDF Metered Feeder - This modification includes installing metered

feeding modules, consisting of two hoppers, one  ram feeder,  and one

variable-speed drive conveyor per module.

                                               Q
     •    Equipment cost = $150,000 per module.

     •    Apply installation factor to obtain direct capital  cost:

          DCC = $150,000(1.45) = $217,500  per module.

     •    Example:  Estimate the direct cost of  retrofitting  metered feeding
          modules on two 300-tpd RDF-fired facilities.   Assume two
          distributors per unit and one module per distributor:

          DCC = $217,500(2 modules/unit)(2 units)  = $870,000.


3.2.2.4  Underfire Air Modifications

     Segmented Underfire Air Supplies - This modification includes  installing

segmented, separately controllable underfire air plenums.


     •    Laval in estimated the direct capital cost of five new underfire air
          plenums to be $153,000 Canadian  (2/85) for the Quebec City
          Incinerator.

          Assume cost for one plenum = $153,000/5  = $30,600.

     •    Convert to U.S. dollars:10  $Canadian  =  1.35 ($U.S.)

               $U.S. = 30,600/1.35 = $22,700 (2/85 dollars).

     •    Apply CEP Index:

               2/85 - 325.4
               12/87 - 332.5
                                     3.2-5
-------
               (22,700)(332.5/325.4)  = 23,200.
     •    Apply scaling factor:
               (Quebec City'is a 250-tpd unit.)
               DCC = 23,200(TPD/250)'667(h)(number of units),
               where h =  number of plenums.
     •    Example:  Estimate the direct capital  cost  of installing  a  single
          underfire air plenum to the drying  grate section of  two  120-tpd
          units:
               DCC = 23,200(120/25)-667(l)(2)  =  $28,400.
     Underfire Air Preheat - This modification  includes a natural gas burner
sized to provide  sufficient heat input to raise  combustion air temperatures
from 68°F to 300°F.
     t    Example:  Determine the size and direct capital cost of an  auxiliary
          fuel burner required to preheat underfire air supplied to the drying
          grate.   Assume  that the unit size is  250 tpd.
               250 tpd(2000 Ib/ton)(day/24 hr)(hr/60  min) = 347 Ib/min MSW.
          Assume  that the combustor operates  at  150 percent excess  air and
          that stoichiometric air requirements  are 3.25 Ib air/lb waste.
          Total air requirements are:
          (347 lb/min)(3.25 Ib air/lb waste)(2.5) » 2820  Ib air/min.
          Assume  that 70  percent of total air is supplied as undergrate air,
          and 20  percent  of undergrate air is supplied to the  drying  grate.
          (2,820  lb/min)(.70)(.20) = 395 Ib/min  at 68°F.
          Q - mcp T
          where:     Q  =  heat input,
                    m  =  395 Ib/min (mass flowrate),
                    c  =  0.24 Btu/lb F (specific heat of  air at standard
                     P                 conditions), and
                    T  =  300 - 68 = 232°F.
          Q = (395 Ib/m1n)(0.24 Btu/lb°F)(232°F)(60 min/hr) =  1.32  106 Btu/hr
               Use a 1.4  x 106 Btu/hr burner.

                                     3.2-6
-------
     •    MITRE reports capitalficosts of burners ranging from capacity of
          9.2 x 10° to 1.5 x 10° Btu/hr to be $1200 per burner.
     •    Apply CEP Index:
               1981 (yearly average) - 297.0
               12/87 - 332.5
               1,200 (332.5/297.0) = 1340.
     •    Apply installation factor to obtain direct capital cost:
               DCC = 1,340(1.45) = $1,950 per burner.
3.2.2.5  Overfire Air Modifications

     Flow modeling/thermal analysis studies are required in most cases prior
to modifying overfire air systems.  Overfire air modifications made at
refractory-wall MWC's and tube and tile waterwall MWC's will usually require
only new ducting,  dampers, and nozzles.  New overf-'-e air rows in
membrane-wall MWC's are assumed to require installation of new waterwall tube
panels.

                                           12
     Flow Modeling/Thermal Analysis Studies   - These analyses include flow
visualization studies, mixing and dispersion measurements,  and flow
distribution studies on a built-to-scale physical model.  In addition,
mathematical modeling is included as part of the thermal analysis.

                    Cold flow modeling - $75,000
                    Thermal  analysis   - $50.000
                    Total               $125,000
     Ducting and Dampers -
     •    Ducting Capital Costs:13  C = l.l(L)(Q)0<5,
               where L = Length (ft) and
                     Q = 125 percent of the actual  flue gas flowrate (acfm).
     s    Example:  Estimate direct capital costs of ductwork and dampers
          required to supply overfire air to two rows of nozzles.  Assume a
          gas flowrate of 21,400 acfm.   Assume  that the overfire air system
                                     3.2-7
-------
          is designed to provide 40 percent of total  air flow (8,560 acfm).
          At standard conditions, Q = 1.25(8,560)  = 10,700 acfm.
          Assume ducting length requirements are 100  feet.
               C = 1.1(100)(10,700)'5 = $ll,400(equipment cost).
     •    Damper Capital Costs:  Chemical  Engineering.  December 29,  1980
          presents cost curves for rectangular dampers.
     •    Estimate costs of a damper to install  in ducting.   Assume  that the
          damper is manually controlled and has  a  1.5 ft  cross-sectional
          area.   The damper equipment cost is $400 (in  December 1977 dollars).
               Apply CEP Index:
                    12/77 - 210.3
                    12/87 - 332.5
               400(332.5/210.3) = $600 per damper  (equipment cost).
          Total  equipment cost = Ducting costs + damper costs
               $11,400 + 600 = $12,000.
          Apply installation factor:
               Total DCC = 1.45(12,000) = $17,400.

     Insulation for Ducting - Capital costs for ducting insulation vary from
3.5 to 22 percent of direct capital costs for ducting.   Selection of the
appropriate factor is based on flue gas temperature.
     •    Example:  Assume that ducting carries  preheated air at a temperature
          of 300UF and that capital costs for the  ducting are $20,000.
          Estimate direct capital costs of insulation.
          Perry's Chemical Engineers Handbook (Table  25-51)  specifies a range
          of 3.5 to 6 percent of ducting costs over $17,000.  Select 6 percent
          as conservative number.
               C = 20,000(0.06) = $1,200.
          Apply installation factor:
               DCC = 1.45(1,200) = $1,740.
                                     3.2-8
-------
     Membrane Wall  Overfire Air Nozzle -
          •    Laval in reports direct capital  costs for one row of nozzles
               installed at Quebec City Incinerator to be $40,000 (Canadian
               2/85 dollars).10
          t    Convert to U.S. dollars:
               $U.S. = $Canadian/1.35
               $U.S. - 40,000/1.35 = 29,600 (2/85 dollars).
          •    Apply CEP Index:
               2/85 - 325.4
               12/87 - 332.5
               DCC  = 29,600(332.5/325.4) = $30,200 per row.
          •    Apply scaling factor:
               (Quebec City is a 250-tpd unit.)
               DCC  = 30,200(TPD/250)'333(number  of rows)(number of units).
     •    Example:   Estimate direct capital  costs for two new overfire air
          rows per  unit for two 1000-tpd combustors:
               DCC  = 30,200(1000/250)>333(2 rows/unit)(2  units) = $192,000.
3.2.2.6  Combustion Controls and Monitors
     Fully Automatic Combustion Controller - This modification includes all
hardware and software required for converting  a  manual  combustion control
system to a fully automatic control (programmable logic controller).
                                                         17 18
     •    Direct capital costs for one unit are  $200,000.   '
     •    Additional units can be installed in control  scheme using  the same
          hardware.  Incremental capital costs are restricted to those costs
          required  for installation.  Assume that the direct  capital  cost  of
          an automatic controller for more than  one combustor is:
               DCC  = 200,000[1 + 0.45(N - 1)],
               where N = number of combustors, and
               installation factor = 45 percent  of equipment  costs.
               DCC  = 200,000 + 90,000(3 - 1) = $380,000.
                                     3.2-9
-------
     Monitors - Display readouts and data loggers are included for each

monitor.  Air flow monitors are venturi flow meters with pressure transducers.
                                                                 1 Q
     •    Direct capital cost of in situ CO/CL monitors - $45,000  .
                                                             1 Q
     •    Direct capital cost of in situ CO monitor - $22,000  .

     •    Direct capital cost of air flow pressure monitors for underfire air
          plenums and overfire air headers - $1,500 per plenum or row of
          overfire air nozzles.

     Oxygen Trim Control - This modification includes installation of a

control loop which adjusts underfire air flowrate and/or plenum distribution

based on feedback signals from an 0- analyzer.


     •    Hampton, VA plant manager reports direct capital  costs  to be $25,000
          for two 100-tpd units.
     •    Assume that these costs are fixed, per unit costs:

               DCC = $12,500/combustor.

3.2.2.7  Auxiliary Fuel Burner Installation

     •    Gas pipeline costs:

               DCC - $50,000 per 1/2 mile22.

     •    Auxiliary gas burners - Capital costs of dual-fuel burner packages,
          including blowers, igniters, safety panels, and controls, are
          available for the following burner sizes.    An installation factor
          of 45 percent is applied to obtain direct capital costs.

          Burner size (Btu/hr)	Equipment Cost	Direct Capital Cost

               10.5                     $16,000                $23,200
               30.0                     $25,500                $37,000
               45.0                     $35,000                $50,800
               60.0                     $42,000                $60,900
          Burner equipment costs for sizes other than those provided above
          should be extrapolated based on size, and the 45 percent
          installation factor should then be applied.

          Example:  Estimate the capital cost of providing auxiliary fuel to a
          facility with three 300-tpd combustors.  Assume the nearest source
          of gas is one mile away, and each combustor requires two burners,
          each rated at 35 x 10  Btu/hr.
                                    3.2-10
-------
               DCC of pipeline = $100,000 and
               Cost of one 35 x 10  Btu/hr burner = $31,400.
               Apply installation factor:
                    DCC = 1.45(31,400) = $45,500.
               Total direct capital  costs for burners = $45,500 and
               (2 burners/unit) (3 units) = $273,000.
               Total direct capital  costs = 100,000 + 273,000 = $373,000.
3.2.2.8  Carbon Monoxide Profiling
     This activity includes two days labor for three men in the field plus
travel and reporting.  Sampling is assumed to include (L,  carbon monoxide
(CO), and temperature measurements in a 16-point array under six variable  air
distribution settings.  Carbon monoxide profiling is required on only one
combustor when multiple units of identical design are in place:
     DCC = $10,000 (Reference 24).

3.2.2.9  Economizer for Flue Gas Temperature Control
     This modification includes a separate economizer module designed to
    :e flue gas temperatures
ducting and a bypass damper.
reduce flue gas temperatures from 600°F to 450°F,  along  with the addition of
          Equipment cost = $45,000 (1986 dollars)  for an economize^sized to
          handle flue gases from four 75-tpd units (300-tpd total).
          Apply CEP Index:
               1986 - 318.4
               12/87 - 332.5
               45,000(332.5/318.4) = $47,000.
          Apply installation factor:
               DCC = $47,100(1.45) = $68,100.
          Apply scaling factor:
               DCC = 68,100(TPD/300)'59.
                                    3.2-11
-------
     t    Example:  Estimate the direct capital  cost of installing one
          economizer for three 50-tpd units:
                    DCC = 68,100(150/300)'59  = $45,200.

3.2.3  Operating Cost Procedures
     Total annual  costs include annual  operating and maintenance (O&M) costs
and annualized capital costs.  Table 3.2-1  presents a summary of inputs used
to estimate annual costs.  The costs provided for each plant are incremental
O&M costs.  For example, if a plant is  equipped  with auxiliary fuel burners at
baseline, it is assumed that the fuel is used for start-up and shutdown, and
no incremental O&M cost is applied to the plant  for auxiliary fuel
consumption.  Plants without auxiliary  burners in place will incur additional
costs for fuel consumption.  The following  examples illustrate the calculation
of annualized costs associated with combustion controls.

     •    Example:  A mass-burn refractory-wall  MWC'consisting of three
          250-tpd combustors must add auxiliary  fuel burners and operate the
          burners during start-up and shutdown.   The facility maintains a five
          per week operating schedule.   Determine the size of burners required
          to provide 60 percent of rated thermal load and  estimate natural gas
          consumption costs.
          Combustor               (250  ton/day)(2000 1b/tonH4500 Btu/lb)
                              zs   T  —     r    J ^   —  —r -"" J—x    —   ' - T
          thermal  load                            (24 hr/day)

                              =  94 x 106 Btu/hr

          Assume for a refractory-wall  facility that gas is fired for six
          hours during start-up and two hours during shutdown.  Assume that
          the plant operates 50 weeks/year, and  start-up/shutdown occurs
          weekly.

          Total gas use =  (50 wk/yr)(6 + 2 hours)(56 x 106 Btu/hr)(3 units)
                        = 67.2 x 109 Btu/yr
                                    3.2-12
-------
          TABLE 3.2-1.  O&M COST INPUTS (DECEMBER 1987 DOLLARS)
Item
Value
Direct Operating Costs
Operating Labor
Supervision
Maintenance Labor
Maintenance Materials
Natural Gi.s
Water
SteaiT;
Solid Was e Disposal
Indirect ( Derating Costs
Overhand
Taxes, Insurance, and
Administrative Charges
Capital Racovery
$12.00/hour
15 percent of operating labor
110 percent of operating labor
(assume 1 hr/shift for
maintenance of controls and
monitors)
100 percent of maintenance labor
$4.50 per 106 Btu
$0.50 per 1000 gallons
$5.30 per 1000 Ib
$25 per ton
60 percent of all labor costs
(operating, supervisory, and
maintenance) plus 60 percent
maintenance materials
4 percent of total plant capital
costs
15 year life and 10 percent
interest rate
                                       CRF = —
                                                id + i)n
       (1
                                                       -  1
                                       where i  = interest rate and
                                       n = number of years
                                       CRF =
      .1 + fl.n"
      (l.l)15 - 1
= .1315
                                    3.2-13
-------
Using c gas cost of $4.50/106 Btu:
C = (67.2 x -Cr Bti!/yr}(4.50/106 Btu) = $302,000/yr
ExiHULLi:  Determine the annual costs for a combustion retrofit at the
plant in the above example.  Total plant capital costs are assumed to be
$500,OOC. including installation of CO and ()„ monitors.
Direct Costs:
     Assume ]  hr/shift (3 hr/day) maintenance of monitors and
     controls.
     Maintenance Materials = (3 hr/day)(5 day/wk)(50 wk/yr)($13.20/hr) =
                              $10,000/yr,
     Maintenance Materials = $10,000/yr (100% of maintenance labor)
     Ges costs = $302,GQO/yr, and
     Kc additional operating labor is required.
     lota' Direct Annual  Costs = 10,000 + 10,000 + 302,000 - "322,000.
Indirect Costs:
     Overhead = G.6(maintenance labor + maintenance materials;,
          Overhead = 0.6(20,000) = $12,000.
     Taxes, insurance and Administrative Charges = .04(total plant
     capital costs) = .04(500,000) = $20,000.
     Annualized capital =  .1315(500,000) = $66,000 assuming 15 year
     facility life and 10 percent weighted cost of capital.
     Total Indirect Annual Cost = Overhead + Taxes, Insurance, and
     Administrative + Annualized Capital
               = $12,000 + $20,000 + $66,000 = $98,000.
     Total annual cost = Direct Cost + Indirect Cost
               = $322,000 + $98,000 = $420,000/yr.
                               3.2-14
-------
REFERENCES

1.    Radian Corporation and Energy and Environmental Research Corporation.
     Municipal Waste Combustors - Background Information for Proposed
     Guidelines for Existing Facilities.   Prepared for U. S. Environmental
     Protection Agency.  Publication No.  EPA-450/3-89-27e.  August 1989.

2.    EER.  Municipal Waste Combustion Study:  Combustion Control of MSW
     Combustors to Minimize Emission of Trace Organics.  Prepared for U. S.
     Environmental Protection Agency.  June 1987.  Publication
     No. EPA/530-SW-021C.

3.    Perry, Robert H. and Don Green.  Perry's Chemical Engineers' Handbook
     (Sixth Edition).  New York:  McGraw-Hill,  1984, p. 25-70.

4.    Reference 3,  p. 25-69.

5.    U. S. Environmental Protection Agency. EAB Control Cost Manual (Third
     Edition).  Research Triangle Park, NC.  Publication
     No. EPA-450/5-87-001A.  February 1987.

6.    Chesner Engineering and Black and Veatch Engineers.  Energy Recovery from
     Existing Municipal Incinerators.  New York State Energy Research and
     Development Authority (NYSERDA) Report No. 85-14.  November 1984.
     p. 43-85.

7.    Telecon.  Conversation between J. Jackson, Nashville Thermal, and
     P. Schindler, EER, on April 6, 1988.

8.    Telecon.  Conversation between Tom Giaier, Detroit Stoker, and
     P. Schindler, EER, on May 13, 1988.

9.    Lavalin.  National Incinerator Testing and Evaluation Program (NITEP):
     Quebec Urban Community MSW Incinerator Program Planning.  Part 2 Final
     Report.  Prepared for Environment Canada.   April 1985.

10.  Wall Street Journal.  Foreign Exchange.  February 7-27, 1985.

11.  MITRE Corporation.  The Estimation of Hazardous Waste Incineration Costs.
     MTR-82W233.  January 1983.  p. 55.

12.  EER in-house estimate provided by D. Moyeda.

13.  U. S. Environmental Protection Agency.  Municipal Waste Combustion Study:
     Costs of Flue Gas Cleaning Technologies.  Research Triangle Park, NC.
     Publication No. EPA/530-SW-87-021e.   June 1987.

14.  Vatavuk, W. and R. Neveril.  "Part IV - Estimating the Size and Cost of
     Ductwork."  Chemical Engineering, December 29, 1980, p. 73.

15.  Reference 1,  Table 25-51, p. 25-70.


                                    3.2-15
-------
16.   Reference 5, p. 7-3.

17.   Reference 5, p. 7-3.

18.   Telecon.  Conversation between Rob Busby, Bailey Controls, and
     P.  Schindler, EER, on May 17, 1988.

19.   Compilation of vendor quotes obtained by S. Agrawal,  EER, for EPA/OSWER.
     Documented in letter to Robert Holloway, EPA/OSWER.  April 8, 1987.

20.   Waukee Flo-meter Price List.  Waukee Engineering Company Bulletin No.
     1-1274-R8.  Milwaukee, WI.  April 1, 1987.

21.   Information provided to EPA and EER during  visit to NASA/Langley Waste to
     Steam Plant, Hampton, VA.  July 6, 1988.

22.   Telefax from Dan Hughes,  Florida Gas Transmission Company, to
     W.S. Lanier, EER.   April  12, 1988.

23.   Vendor cost quotes provided to EER by Ed Flammang, North American
     Manufacturing Company, Cleveland, OH.  August 11, 1988.

24.   EER in-house estimate provided by Z. Frompovich.

25.   Telecon.  Conversation between Col.  Frank Rutherford, Tuscaloosa Solid
     Waste Authority and P. Schindler, EER.  May 26, 1988.
                                    3.2-16
-------
3.3  HUMIDIFICATION
3.3.1  Overview of Technology
     Humidification is used to cool the flue gas entering the particulate
matter (PM) control device.  Humidification can be used separately or in
combination with dry sorbent injection.  The primary objective of cooling
is to reduce the temperature of the flue gas entering the PM control device
to below that at which post-combustion formation of dioxin is suspected to
occur (approximately 450°F).
     The quantity of water required is a function of the temperature,
flowrate, and moisture content of the flue gas at the inlet to the
humidification chamber and the temperature reduction required.

               Qw = (T.-T0) * Qs * (1-WTR/100)/940                      (1)

where:    Q  = water required for flue gas coolirj, lb/hr;
          T, = inlet flue gas temperature,  F;
          T  = outlet flue gas temperature, °F;
          Q  = flue gas flowrate, scfm; and
         WTR = moisture content of the inlet flue gas, volume percent.

     Flue gas temperatures at the combustor exit for refractory-wall
combustors generally ranged from 1,400 to 1,600°F; for waterwall
combustors, temperatures ranged from 400 to 600°F.
     For units already using quench towers for flue gas cooling (primarily
refractory-wall  systems without heat recovery), the water feed rate is
increased to achieve the additional cooling.  For units without an existing
flue gas cooling system, a humidification chamber is installed.  The
humidification chamber diameter is sized for a flue gas velocity of
                                                                      2
10 feet/second and a chamber length-to-diameter (L/D) ratio of 3 to 1.   To
minimize PM fallout and impingement of wetted solids on chamber walls, no
baffles or other internals are used.  Pressure nozzles are used for water
atomization.
     A secondary effect of cooling the flue gas entering the PM control
device is a reduction in flue gas volume (i.e., acfm) and a corresponding
                                   3.3-1
-------
increase in the specific collection area (SCA) thereby enhancing the PM
collection efficiency of the ESP.  However, because MWC ESP's operate at
temperatures above the temperature of maximum particle resistivity (300 to
400°F for most fly ashes), decreasing flue gas temperature may in some
instances increase fly ash resistivity enough to create ESP back corona
problems and impair PM collection efficiency.  Because of the current lack
of information on resistivity-temperature relationships for MWC fly ash,
this analysis assumes that humidification does not alter particulate
resistivity enough to cause ESP operating problems.  As a result, the
impact of humidification on ESP performance is estimated based solely on
the change in SCA due to flue gas volume reduction.
3.3.2  Capital Cost Procedures
     Capital costs are estimated for existing facilities without an
existing flue gas cooling system.  Direct capital  costs include the
humidification (evaporative cooling) chamber including the vessel and
supports, water spray system and controls,  and duct modifications.  Direct
equipment cost for the humidification chamber are based on the flue gas
                                      3
flowrate using the following equation:

               Equipment Costs ($) = 0.372 * Q + 67,980               (2)

where:    Q is 125 percent of the actual inlet flue gas flowrate (acfm)
          to accommodate variations in waste composition and operating
                     4
          conditions.

The costs estimated by equation 2 are in December 1987 dollars.
Originally, the costs were in December 1977 dollars and were adjusted to
December 1987 dollars using the Chemical Engineering Plant Cost Index for
all equipment.  The equipment costs are then adjusted for retrofit
difficulty based on the procedures described in Section 3.7.1.
     Costs for instrumentation, taxes, freight, and installation are
estimated using indirect cost factors for venturi  scrubbers.   The
                                   3.3-2
-------
resultant procedure for estimating capital cost is summarized in
Table 3.3-1.
3.3.3  Operating Cost Procedures
     Table 3.3-2 presents procedures for estimating operating and
maintenance (O&M) costs for the humidification chamber.  Because of the
simple design and operating requirements of the system, O&M labor and
maintenance materials are assumed to be at the low end of those presented
in Reference 6 (i.e., using the wet scrubber labor and materials
requirements).  Other O&M costs include water and the electricity used by
the pumps.  All  costs are based on December 1987 dollars.  An operating
labor wage of the $12/hr was used.  This wage was the average of the labor
wages reported by both the Department of Commerce Survey of Current
Business for private nonagricultural payrolls and EPRI's
                                                    7 8
Technical Assessment Guide for utility power plants.      The labor wage
reported by EPRI in January 1985 dollars was updated to December 1987
dollars using the Bureau of Labor Statistics' Producer Price Cost Index for
all industrial commodities, prior to averaging.  An electricity cost of
$0.046/kWh was obtained from the Energy Information Administration
                      Q
Monthly Energy Review.   Equipment life is assumed to be 15 years.
                                   3.3-3
-------
       TABLE 3.3-1  CAPITAL COST PROCEDURES FOR HUMIDIFICATION10'11
Equipment Costs (December 1987 dollars)
     1.  Humidification Chamber and Pumps:3
               Cost, $ = 0.372 * Q + 67,980
     2.  Ductwork
          Cost, $ = 0.981 * L * Q°'5
Retrofit Purchase Equipment Costs = 1.18 * Equipment Costs * Retrofit
                                    Factor (from Section 3.7)
Installation Direct Costs     = 0.56 * Purchased Cost
Indirect Costs  = 0.35 * Purchased Cost
Total Capital
Costs           = Purchased Equipment Costs + Installation Direct Costs +
                    Indirect Costs
               = 1.91 * Purchased Costs
aQ = 125 percent of the actual flue gas flowrate, acfm
 L = Duct length, feet.
 Includes a contingency of 3 percent of the purchased costs.
                                   3.3-4
-------
      TABLE 3.3-2  OPERATING AND MAINTENANCE COSTS FOR HUMIDIFICATION
Operating Labor:

Supervision:

Maintenance Labor:
Maintenance
 Materials:

Water:3
           .a,b
Electricity:
Overhead:
Taxes, Insurance,
and Administrative
Charges:

Capital Recovery:
0.5 man-hours/shift; wages of $12/hr

15% of operating labor costs

0.5 man-hours/shift
10% wage premium over operating labor wages


1% of total capital investment

0.00012 * Q  * (hours of operation) *
(water costs, $/1000 gal)

cost of $0.50/1000 gal
1.587 x 10"4 * Q  * (hours of operation) *
(electricity costs, $/kWh)

cost of $0.046/kWh

60% of the sum of all  labor costs (operating,
supervisory, and maintenance) and maintenance
materials
4% of the total  capital  costs

15-year life and 10% interest rate
References

     6, 8

     12

     12



     13

     14
     15
                                                                      15
     15
 Q  = water injection rate,  Ib/hr,  (from Equation 1 in Section 3.3.1).
  w

•'Assume 20 feet of pumping height,  100 psi  discharge pressure, and
 10 ft/sec velocity in pipe.
                                   3.3-5
-------
REFERENCES

 1.   PEI Associates, Inc.  User's Manual for the Integrated Air Pollution
     Control System Cost and Performance Program (Version 2).  Prepared for
     the U. S. Environmental Protection Agency.  Research Triangle Park,
     NC.  Contract No.  68-02-3995.  April 1985.  p. 4-16.

 2.   Neveril, R.S.  (GARD Inc.) Capital and Operating Costs of Selected Air
     Pollution Control  Systems.  Prepared for U. S. Environmental
     Protection Agency.  EPA-450/5-80-002.   December 1978.  p. 4-40.

 3.   Reference 2.  p. 4-41.

 4.   Letter from Sedman, C.B.,  EPA,  to Chang, J. Acurex Corporation.  July
     14, 1986.  EPA guidelines  for costing  flue gas cleaning technologies
     for municipal waste combustor.

 5.   Reference 2.  p. 3-11.

 6.   Reference 2.  p. 3-14.

 7.   United States Department of Commerce.   Survey of Current Business.
     Washington, D.C.  Volume 68.  Number 6.  Oui\2 1988.  p. S-12.

 8.   Electric Power Research Institute.  TAG - Technical Assessment Guide
     (Volume 1:  Electricity Supply - 1986).  Palo Alto, CA.  Publication
     No. EPRI P-4463-SR.  December 1986.  p. B-4.

 9.   Energy Information Administration.  Monthly Energy Review:
     December 1987.  Washington, D.C.  Publication No. DOE/EIA-0035 (87/12).
     March 1988.  p. 109.

10.   Reference 2.  p. 4-41.

11.   U. S. Environmental Protection Agency.  Municipal Waste Combustion
     Study:  Costs of Flue Gas  Cleaning Technologies.  Research Triangle
     Park, NC.  Publication No. EPA/530-SW87-021e.  June 1987.

12.   Reference 2.  p. 3-12.

13.   Reference 5.  p. 4-23.

14.   Letter from Solt,  J.C., Solar Turbines Incorporated, to Noble, E.,
     EPA.  October 19,  1984.  Development cost for wet control for
     stationary gas turbines.

15.   U. S. Environmental Protection Agency.  EAB Control Cost Manual.
     Research Triangle Park, NC.  Publication No. EPA-450/5-87-001A.
     February 1987.  p. 2-31.
                                   3.3-6
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3.4  PARTICULATE MATTER CONTROL RETROFIT
     This section discusses three electrostatic precipitator (ESP) control
alternatives for reducing PM emissions from existing MWC facilities.  These
alternatives are:  installation of a new ESP (discussed in Section 3.4.1),
increasing the plate area of an existing ESP (Section 3.4.2), and rebuilding
an existing ESP to improve performance (Section 3.4.3).
3.4.1  Installation of a New ESP
     The procedures for estimating ESP capital  costs for new plants (described
in Section 2.2.2) are applicable to the procedures used for existing plants.
The existing plant cost procedures include site-specific retrofit factor and
scope adders used to estimate the cost of demolition, replacement, relocation
of existing equipment, new ducting, and stacks, if needed.
     3.4.1.1  Capital Cost Procedures.  The procedures developed for
estimating the capital costs of ESP's for new plants (described in
Section 2.2.4.1) are used to estimate the direct costs of major equipment,
including the fans and ash handling.  Estimated duct lengths are required to
calculate duct costs for connecting the ESP to an existing plant.  The
estimated direct costs of new equipment and ducts are then multiplied by
site-specific retrofit factors determined by the procedures described in
Section 3.7.1.
     Total direct capital costs for retrofit are calculated as the sum of the
adjusted equipment costs plus any scope adders.  Scope adders are additional
significant costs for items, such as chimneys or demolition, that are required
for an accurate estimate of the ESP retrofit.  Determination of scope adder
costs is described in Section 3.7.2.
     After the total  direct capital costs have been estimated,  the remainder
of the capital cost procedure (for indirect and contingencies costs) is the
same as for ESP's installed in new plants as described in Section 2.2.4.1.
     3.4.1.2   Operating Cost Procedures.  Operating costs for retrofit ESP's
are estimated using the same procedures as those for new plants discussed in
Section 2.2.4.2.  The costs of taxes,  insurance, and administrative charges
are estimated as a fraction of the total  retrofit capital  costs.  The proposed

                                      3.4-1
-------
procedures also allow operating hours to be varied to reflect model plant
specifications.
3.4.2  Increase in ESP Plate Area
     Additional ESP plate area is installed when the existing ESP is too small
to achieve the desired PM control.   Addition of plate area is accomplished by
installing a new ESP in series with the existing ESP.  This approach results
in minimum facility downtime and will simplify cost estimation relative to the
addition of plate area to the existing ESP.
     3.4.2.1  Capital Cost Procedures.  The procedures developed for
estimating the capital costs of ESP's for new plants (described in
Section 2.2.4.1) are used to estimate the direct costs of installing
additional ESP plate area.  First,  the required particulate removal efficiency
is calculated based on the PM emission limit desired and the inlet PM
concentration.  This removal efficiency is then used to calculate the required
specific collection area (SCA) using either equation 2 or 4 presented in
Section 2.2.4.1.  Next, the SCA of the existing ESP is subtracted from the
calculated SCA to determine the additional SCA required.  The additional SCA
required is used to calculate the additional plant area requirement and the
direct costs of the second ESP using equations 1 or 3 in Section 2.2.4.1.  The
required duct length is estimated for each model plant based on the equipment
configuration for that plant.  The estimated direct costs of the new ESP and
ducts are then multiplied by a site-specific retrofit factor determined
according to the guidelines discussed in Section 3.7.1.  Appropriate scope
adders are costed based on procedures described in Section 3.7.2.
     After the total direct capital costs have been estimated, the remainder
of the capital cost procedure (for indirect and contingency costs) are the
same as for ESP's installed in new plants presented in Section 2.2.4.1.
     3.4.2.2  Operating Cost Procedures.  Operating costs for the second ESP
are estimated using procedures for new plants discussed in Section 2.2.4.2.
Only those costs associated with the second ESP are included.  Because
operating, supervision, and maintenance labor are available for the existing
ESP, it is assumed that no additional labor requirements are necessary to
operate and maintain the second ESP.
                                      3.4-2
-------
3.4.3  ESP Rebuild
     An ESP rebuild can be used with existing ESP's with PM removal
efficiencies lower than those predicted in either Figures 2.2-2 or 2.2-4 for a
new ESP with equivalent SCA.  Rebuild of an ESP includes replacing worn or
damaged internal components (plates, frame, and electrodes), upgrading
controls and electrical systems for more effective energization, and flow
modeling to evaluate gas distribution.   The ESP rebuild does not include
making design changes to the existing ESP, such as changes to the
plate-electrode geometry or addition of collection area.
     3.4.3.1  Capital Cost Procedures.   The procedures developed for
estimating the capital costs of ESP's for new plants (described in
Section 2.3.4.1) are used to estimate the direct costs of ESP rebuild.  Based
on contacts with ESP vendors,  a typical cost for rebuilding an existing ESP is
roughly 30 percent of the total capital cost of a new ESP of equivalent size,
                                                     i o
but can be as high as 50 percent of the new ESP cost. '
     The recommended procedure for estimating the total capital costs for ESP
rebuild is to use 30 percent of the cost for a new ESP.  This factor assumes
equipment costs of 42 percent of the cost of a new ESP plus installation and
indirect equipment cost multipliers of 0.33 and 0.27, respectively.   These
indirect cost multipliers are lower than those used for new ESP's because:
(1) new foundations, supports, piping,  insulation, and painting are not
required and (2) engineering and erection expenses are reduced relative to the
costs for a new ESP.  Site-specific retrofit factors are not used since the
rebuild is performed within the existing ESP.
     3.4.3.2  Operating Cost Procedures.  The operating and maintenance costs
after ESP rebuild are the same as before the rebuild with the exception of
additional waste removal.  The additional waste removal requirements are based
on the incremental reduction of PM achieved after the ESP is rebuilt.
                                      3.4-3
-------
                                  REFERENCES

1.   Telecon.  Lamb, Linda, Radian Corporation, with Gawrelick, Gary,
     Research-Cottrell.  February 13, 1988.  Rebuild Costs for ESP's.

2.   Telecon.  Martinez, John, Radian Corporation, with Gawrelick, Gary,
     Research-Cnttrell.  April 11, 1988.  Additional cost information on ESP
     rebuilds.

3.   Turner J.H. et al.  Electrostatic Precipitators (draft section).   In:
     EAB Control Cost Manual, U. S. Environmental Protection Agency.  Research
     Triangle Park, NC.  Publication No. EPA-450/5-87-001A.  February 1987.
     p. 6-56.
                                      3.4-4
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3.5  DRY SORBENT INJECTION RETROFIT
3.5.1   Overview of Technology
     Cost procedures are presented in Section 2.3 for the injection of dry
sorbent into the furnace or duct of a new plant.  The major distinctions
between the design of sorbent injection systems for most existing facilities
versus new facilities are (1) the reuse of an existing ESP rather than a new
fabric filter for PM control, and (2) the higher capital costs to reflect the
difficulty of a site-specific retrofit.  For existing facilities not equipped
with an ESP, new fabric filters can be used.
     Another retrofit option for duct sorbent injection at existing facilities
is to  , ,-.jcct dry sorbent following an existing spray humidification chamber.
In this j^ion, the flue gas leaving the combustor is cooled by humidification
to 350C  :,..fore it enters the ESP, or to 300°F in the case of a fabric filter.
Dry sor •:•.-., -'i, is injected after the gas is humiinfied to minimize cake buildup
in the cruet.
3,5.2  '.aoltal Cost Procedures
     Tba procedures developed for estimating the capital costs of dry sorbent
injection for new plants are used to estimate the direct capital cost of major
equipment and ductwork for retrofit installations.  Because the major
equipment components of dry sorbent injection (reagent storage and handling
system) can be located in remote areas,  difficulties associated with spacial
constraints (i.e., access/congestion) and underground obstructions is
generally minimal.  Based on the application of dry sorbent injection to
coal-fired utility boilers, the direct capital cost for new plants is
increased by 10 percent to account for the estimated costs of modifying an
existing duct in the case of duct sorbent injection, modifying an existing
overfire air system in the case of furnace sorbent injection, or modifying an
existing humidification chamber.
     The total direct capital costs for retrofit also include the cost of any
scope adders such as additional ducting or existing equipment demolition that
is required to accurately estimate dry sorbent injection retrofit costs at a
specific site.  Additional ductwork can be estimated using cost equations in
Section 2.3.  Scope adders are defined in Section 3.7.2.  Determination of
scope adder costs is also described in Section 3.7.2.

                                     3.5-1
-------
     After the total direct capital costs have been estimated, the remainder
of the capital cost procedure for estimating indirect capital costs and
contingencies is the same as for dry sorbent injection at a new plant
presented in Section 2.3.4.1.
3.5.3   Operating Cost Procedures
     Operating costs for retrofit dry sorbent injection installations are
estimated using the same procedures discussed in Section 2.3.4.2 for new
plants.  Operating costs for existing plants are higher than for new plants of
equivalent sizes because the maintenance expenses are affected by access and
congestion difficulties.  This increased cost is handled by calculating
maintenance materials as a percentage of the total capital investment.  The
costs of taxes, insurance, and administrative charges are based on the total
retrofit capital costs.
                                     3.5-2
-------
                              REFERENCE

Radian Corporation.  Retrofit Costs for SO, and NO  Control Options at 50
Coal-Fired Plants (Draft Report).  Preparea for the U. S. Environmental
Protection Agency.  Research Triangle Park, NC.  Contract No. 68-02-4286.
February 1988.
                                3.5-3
-------
3.6  SPRAY DRYER RETROFIT

3.6.1  Overview of Technology
     Spray dryers (SD) combined with fabric filters (FF)  can be retrofitted at
existing plants where very high levels of CDD/CDF and acid gas control are
required.  Key technology considerations include reconfiguration of the
ducting between the combustor outlet and stack,  and the availability of space
for installing sorbent handling equipment,  SD vessel, FF,  and ash disposal
facilities.
     Stand-alone SD costs were developed for this study to evaluate the costs
of retrofitting a new SD in front of an existing particulate control device.
Cost procedures presented in Sections 3.6.2 and  3.6.3 can  be applied to
estimate SD retrofit costs at existing plants.  In most cases, the existing
particulate control device is an ESP.  For cases where it  is determined that
additional plate area is required to handle the  increase in fly ash loading to
the ESP caused by the SD, costing procedures presented in  Sections 2.2 and
3.4.2 for modifying ESP's to add plate area should be used.
3.6.2  Capital Cost Procedures
     The procedures developed for estimating the capital  costs of SD/FF
systems for new plants (described in Section 2.4.4) can be used to estimate
the direct capital cost of major equipment and ducts for retrofit
installations.  Required duct lengths are used to estimate the duct costs for
connecting the SD system to an existing plant.  The estimated direct costs of
new equipment and ducts are then multiplied by site-specific retrofit factors
determined by the procedures in Section 3.7.1.
     Capital costs for stand-alone SD systems are based on quotes obtained
from three manufacturers. "   These quotes, shown in Table 3.6-1, exclude the
costs of any particulate control device.  As discussed in  Section 2.4, direct
capital costs were correlated with flue gas flowrates.  The direct capital
cost equation in Table 3.6-2 for a single SD unit was developed from these
                                       2
quotes.  The correlation coefficient (R ) for this equation is 0.81.
Figure 3.6-1 shows the relationship of both the predicted  SD direct capital
costs and the vendor costs with flue gas flowrate.  The accuracy of the
                                      3.6-1
-------
TABLE 3.6-1.  VENDOR QUOTES FOR SPRAY DRYER DIRECT CAPITAL COSTS
                     (in 1000$ August 1988)


Vendor
A
A
A
A
A
B
B
B
B
B
C
C
C
C
C
aMB/WW
MB/RC
RDF
btpd =

Combustor
Type
MB/WW
MB/RC
RDF
MB/WW
RDF
MB/WW
MB/RC
RDF
MB/WW
RDF
MB/WW
MB/RC
RDF
MB/WW
RDF
= mass burn/waterwall

Combustor.
Size, tpd°
100
250
300
750
1,000
100
250
300
750
500
100
250
300
750
500

Flue gas
Flowrate,
acfm
24,000
49,000
82,800
210,000
393,000
24,000
49,000
82,800
210,000
196,500
24,000
49,000
41,400
210,000
196,500


Direct
Capital Costs
890
1,225
1,575
2,725
3,930
850
1,400
900
2,500
2,150
1,300
2,170
1,650
3,430
2,560

= mass burn/rotary combustor
= refuse-derived fuel
tons burned per day






                                3.6-2
-------
            TABLE 3.6-2.  CAPITAL COST PROCEDURES FOR SPRAY DRYERS'
Total Direct Costs (December 1987 dollars)
Single SD Unit only:  Costs, 103 $ - 8.428 (Q)0'460 * N * RF
Ductwork5:  Costs, 103 $ = [1.3868 * L * Q°'5]/l,000 * N * RF
Fan5:  Costs, 103 $ = [1.8754 * Q°'96]/l,000 * N * RF
Multiple Units:  Multiply the above costs by the number of units
Indirect Costs = 33% of total direct costs
Contingency = 20% of sum of direct and indirect costs
Total Capital Costs = Total Direct Costs + Indirect Costs + Contingency Costs
 Q  = 125 percent of the actual flue gas flowrate, acfm
 L  = Duct length, feet
 N  = Number of units
 RF = Retrofit factor, dimensionless
 Assumes that the total installed costs are 133 percent of the direct capital
 costs.
                                       3.6-3
-------
                             
                             .M
                             
                                                          M 3*  a- h
                                                00 V
                                                0> -M
                                                                  i/l O
                                                                    (V
                                                              5  si
                                          •O

                                        O §
                                                                  V)
                                                                  0 -0
                                                                  o e
                                                              UJ
                                                        i-i
                                                                  l« 3

                                                                  °tl
                                                                  £ B

                                                                  o a
                                                S§
                                                •»• o
                                                *J V.
                                                <« <*-

                                                'v

                                                s.
                                                o
                                                                  CO

                                                                  
-------
±30 percent.  It should be noted that the costs shown in this figure are
reported in August 1988 dollars and that the flue gas flowrate is the actual
flue gas flowrate.  The SD direct capital cost equation in Table 3.6-2 was
derived by de-escalating the predicted cost curve shown in Figure 3.6-1 to
December 1987 dollars using the Chemical Engineering Plant Index and by
correcting for 125 percent of the actual flue gas flowrate.  Comparing the
direct capital coits for SD with those for SD/FF estimated using procedures in
Section 2.4, the SD costs are generally between 50 and 60 percent of the costs
for a SD/FF for flue gas flowrates ranging from 25,000 to 400,000 acfm.  These
flue gas flowrates covor the range of flowrates from small modular units to
large RDF units.  For ESP reuse, the costs of additional plate area, if any,
estimated from procedures presented in Section 3.4.2 should be included.
     The required duct length is estimated for each model plant based on the
proposed air pollution control device (APCD) equipment configuration for that
plant.  The estimated direct costs of new equipment and ductwork are then
multiplied by site-specific retrofit factors described in Section 3.7.1.
     The total direct capital cost for retrofit is calculated as the sum of
the adjusted new equipment costs plus any scope adders.  Scope adders
incorporate additional capital costs for items such as chimneys or demolition
that are required for SD retrofit.  Determination of scope adder costs is
described in Section 3.7.2.
     After the total direct capital cost has been estimated, the remainder of
the capital costing procedure for indirect capital costs and contingencies
is the same as for SD/FF installation at a new plant (see Section 2.4.2).
3.6.3  Operating Cost Procedures.
     Operating costs for retrofit SD/FF installations are estimated using the
same procedures as for new plants in Section 2.4.3.  Table 3.6-3 presents the
annual operating cost procedures for stand-alone SD's.  Annual operating costs
for the SD system alone exclude costs associated with the PM control device,
such as bag replacement, compressed air, and solid waste costs.  Operating
labor, supervision, and maintenance labor costs for the SD alone are half
those for a similar SD/FF system.  Electricity costs for the I.D. fan are
based on 5.5 inches of water pressure drop for an SD compared with
                                      3.6-5
-------
        TABLE 3.6-3.  ANNUAL OPERATING COSTS PROCEDURES FOR STAND-ALONE
                               SPRAY DRYERS FOR NEW MWC's3
Operating Labor:

Supervision:

Maintenance:

     Labor:


     Materials:

Electricity:

     Fan:
2 man-hours/shift; $12/man-hour

15% of operating labor costs



1 man-hour/shift; 10% wage rate
premium over operating labor wage

2% of direct capital costs

Cost Rate = $0.046/kwh

5.5 inches of water pressure drop
Reference

   4, 5

     6
     5

     7



   4, 5
     Atomizer:

     Pump:
Water:
L i me :
Overhead:
6kW/l,000 Ibs/hr of slurry feed + 15kW

20 feet of pumping height
10 psi discharge pressure
10 ft/sec velocity in pipe

Calculate water flowrate reguired for
cooling the flue gas to 300 F; water
cost - $0.50/1000 gal

Based on lime feed rate calculated by
assuming a stoichiometric ratio of
1.5:1; lime cost = $70/ton

60% of the sum of all labor costs
(operating, supervisory, and maintenance)
plus materials
Taxes, Insurance, and
 Administrative Charges: 4% of total capital  costs
Capital Recovery:
15-year life and 10% interest rate
     8

     9



    10



    11



    12




    12


    13
 All costs are in December 1987 dollars.
                                     3.6-6
-------
12.5 inches of water pressure drop for a SD/FF.  Operating costs for ESP reuse
are estimated from procedures presented in Section 3.4.2 for additional ESP
plate area.
     Operating costs for existing plants are higher than for new plants of
equivalent size, since maintenance expenses will  be affected by access and
congestion difficulties.  This increased cost is  handled by calculating
maintenance materials as a percentage of the total capital investment.  The
costs of taxes, insurance, and administrative charges are based on total
retrofit capital costs.  These procedures also allow operating hours to be
varied to meet model plant specifications.
                                      3.6-7
-------
                                  RFFERENCES

 1.  Letter and attachment from Weaver, E.H.,  Belco Pollution Control
     Corporation,  to Johnston, M.G., EPA.  September 28, 1988.  Retrofitting
     of spray dryers to existing MWC's.

 2.  Letter and attachment from Buschmann, J.C., Flakt Incorporated, to
     Johnston, M.G., EPA.  October 27,  1988.  Costs for spray dryers applied
     to MWC's.

 3.  Letter and attachment from Murphy, J.L.,  Wheelabrator Air Pollution
     Control, to Johnston, M.G., EPA.   November 18, 1988.  Costs for spray
     dryers applied to MWC's.

 4.  Memorandum from Aul, E.F., et al., Radian Corporation, to Sedman, C.B.,
     EPA.  May 16, 1983.  36 p.  Revised Cost  Algorithms for Lime Spray Drying
     and Dual Alkali FGD Systems.

 5.  Neveril, R.B. (CARD, Inc.).  Capital and  Operating Costs of Selected Air
     Pollution Control Systems.  Prepared for  the U. S. Environmental
     Protection Agency.  Research Triangle Park, NC.  Publication No.
     EPA-450/5-80-002.  December 1978.   p. 3-12.

 6.  U. S. Environmental Protection Agency.  EAB Control Cost Manual.
     Research Triangle Park, NC.  Publication  No.  EPA-450/5-87-001A.
     February 1987.  p. 2-6.

 7.  Electric Power Research Institute.  TAG^-Technical Assessment Guide
     (Volume 1:  Electricity Supply-1986).  Palo Alto, CA.  Publication No.
     EPRI P-4463-SR.  December 1986.  P. 3-10.

 8.  Reference 1,  p. 4-23.

 9.  Dickerman, J.C. and K.L. Johnson.   (Radian Corporation.)  Technology
     Assessment Report for Industrial  Boiler Applications:  Flue Gas
     Desulfurization.  Prepared for the U. S.  Environmental Protection Agency.
     Washington, DC.  Publication No.  EPA-600/7-79-178i.  November 1979.
     pp. 5-5 and 5-17.

10.  Letter from Solt, J.C., Solar Turbines Incorporated, to Noble, E., EPA.
     October 19, 1984.  Development cost for wet control for stationary gas
     turbines.

11.  Chemical Marketing Reporter.  Volume 233.  Number 1.  January 4, 1988.

12.  Reference 7,  p. 2-29.
                                      3.6-8
-------
13.   Bowen,  M.L. and M.S.  Jennings.   (Radian Corporation).   Cost of Sulfur
     Dioxide,  Particulate  Matter,  and Nitrogen Oxide Controls in Fossil Fuel
     Fired Industrial Boilers.   Prepared for the U.  S.  Environmental
     Protection Agency.  Research  Triangle Park, NC.  Publication No.
     EPA-450/3-82-021.  August  1982.  pp.  2-17 and 2-18.
                                      3.6-9
-------
3.7  DETERMINATION OF RETROFIT F*^TORS AND SCOPE ADDER COSTS
     The costs of air pollution control device (APCD) installation at an
existing plant are greater than at a new facility due to higher construction
costs imposed by site access and congestion, longer duct runs caused by space
limitations, and the need to demolish and relocate some existing facilities.
Procedures for estimating these costs at MWC's were adapted from procedures
developed for the Electric Power Research Institute (EPRI) for retrofitting
APCD's at existing electric generating plants.   These additional costs are
divided into two types of adjustments:  retrofit multipliers (discussed in
Section 3,7.1) and scope adders (discussed in Section 3.7.2).
3.7.1  Retrofit Factors
     Site-specific retrofit factors can be estimated based on access and
congestion problems associated with retrofitting APCD's at existing plants.
Depending on the level of accessibility and congestion, one of four factors
(ranging from 1.02 to 1.42) is recommended based on the guidelines shown in
Table 3.7-1.  The total direct costs of new APCD equipment excluding ductwork
                                                                  2
are multiplied by this retrofit factor to estimate retrofit costs.
3.7.2   Scope Adders
     Scope adders are site-specific costs for additional ducting, chimneys,
demolition, or any other major items that can be included in retrofit cost
estimates in addition to the main control system equipment.  Estimating
procedures for some common scope adders are described here.
     3.7.2.1  Ducting.  Direct capital costs for ducts are estimated using the
equation described in Section 2.2 for new plants.  The duct costs are then
multiplied by the retrofit factor from Section 3.7.1 to estimate the direct
capital cost of ducts for existing plants.  Depending on chimney and APCD
tie-in difficulties at the model plant, the ductwork retrofit factor may be
different than that chosen for the APCD.
     3.7.2.2  Stacks.  The installed capital cost of stacks is estimated from
equations developed for industrial boilers.   Total direct and indirect
capital cost data from one manufacturer were correlated into separate
equations for lined and unlined stacks, and for stacks larger and smaller than
                                     3.7-1
-------
             TABLE 3.7-1.  SITE ACCESS AND CONGESTION FACTORS FOR
                RETROFITTING APCD EQUIPMENT AT EXISTING PLANTS3
Retrofit
factor
Congestion
  level
     Guidelines for selecting retrofit factor
1.02
Base Case
1.08
Low
1.25
Medium
1.42
High
Interferences similar to a new plant with adequate
crew work space.  Free access for cranes.  Area
around combustor and stack adequate for standard
layout of equipment.

Some aboveground 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.

Limited space.  Interference with existing
structures or equipment which cannot be relocated.
Special designs are necessary.  Crane access
limited to one side.  Majority of equipment
elevated or remotely located.

Severely limited space and access.  Crowded
working conditions.  Access for cranes blocked
from all sides.
 Reference 4.
                                     3.7-2
-------
5 feet in diameter (stacks larger tnan 5 feet in diameter and 100 feet tall
are normally tapered).  For a lined acid-resistant stack, the equations for
direct and indirect capital cost, updated to December 1987 dollars, are:
     Cost, 103 $ = [26.2 + 0.089 x (H) x (1 + 4.14 D)] for D > 5 ft and
     Cost, 103 $ = [26.2 + 0.080 x (H) x (1 + 4.33 D)] for D < 5 ft
For an unlined stack, the equations are:
     Cost, 103 $ - [26.2 + 0.0625 x (H) x (1 + 2.59 D)] for D > 5 ft and
     Cost, 103 $ = [26.2 + 0.087 x (H) x (1 + 2.20 D)] for D < 5 ft,
where
     H = stack height, ft and
     D = stack diameter, ft.
To estimate the total capital costs, the direct and indirect costs are
increased by 20 percent to account for contingency.
     3.7.2.3  Demolition and Replacement.  Costs for demolition of existing
buildings required for installation of new APCD equipment are estimated
according to EPRI guidelines.   In general, demolition cost is estimated by
multiplying the amount of material to be demolished or moved (i.e., square
feet of building space) by an appropriate cost factor in Reference 5.  These
estimates are made on a plant-specific basis as needed.  Costs for demolition
or replacement of existing equipment such as ductwork, fans, and ESP's are
assumed to be the same as the costs for installing the same equipment.
                                     3.7-3
-------
                                 REFERENCES

1.  Stearns Catalytic Corporation.   Retrofit FGD Cost-Estimating Guidelines.
    Prepared for Electric Power Research Institute.  Palo Alto, CA.
    Publication No. CS-3696.  October 1984.

2.  Reference 1.  pp. 4-1 to 4-3.

3.  Bowen, M.L. and M.S. Jennings  (Radian Corporation).  Costs of Sulfur
    Dioxide, Particulate Matter, and Nitrogen Oxides Controls on Fossil
    Fuel-Fired Industrial Boilers.   Prepared For the U. S. Environmental
    Protection Agency.  Research Triangle Park, NC.  Publication
    No. EPA-450/3-82-021.  August  1982.   p. 2-11.

4.  Reference 1.  p. 5-4.

5.  Reference 1.  pp. 4-9 to 4-14.
                                    3.7-4
-------
3.8  DOWNTIME COSTS FOR RETROFIT MODIFICATIONS
     In many situations,  the retrofit equipment cannot be installed during a
normally scheduled maintenance shutdown and thus will  result in additional
downtime and loss of MWC revenues during retrofit.   The loss of revenue is
mainly from:  (1) a loss of steam and/or electrical  sales and (2) a loss of
tipping fees from receiving MSW.  It is assumed that the work force at the
facility would be productive during the downtime period and that the cost of
idle workers can be ignored.
     To estimate the downtime costs due to loss of revenue, the length of
downtime required to install the APCD must be estimated.  Table 3.8-1 presents
ranges of unit downtimes required to apply combustion  control and install
various APCD's on existing MWC facilities.  Once the downtime period is
estimated,  Sections 3.8.1 and 3.8.2 present the procedures used to estimate
costs for the loss of steam and electrical sales and the loss of tipping fees,
respectively.  Costs attributed to the loss of revenue are treated as a
one-time cost that is annualized over the useful life  of the APCD.
3.8.1  Procedures to Estimate Loss of Steam and Electricity Sales
     3.8.1.1  Loss of Steam Sales.  To estimate the  costs of loss of steam
during downtime, the amount of steam that would have been generated during the
downtime period is multiplied by a sales price for steam (typically in dollars
per 1,000 Ib of steam).  A typical steam price in December 1987 dollars is
$5.50/1,000 Ib of steam.    For example, the lost revenues from steam sales for
a facility normally producing 10,000 Ib/hr of steam  are $1,320 per day (i.e.,
$5.50/1,000 Ibs steam times 10,000 Ibs steam/hr times  24 hours).
     3.8.1.2  Loss of Electricity Sales.  The cost of lost electricity sales
is estimated by multiplying the amount of lost electricity generation by the
electricity price.  The electricity price is assumed to be the same as the
electrical  cost rate used in this report to estimate APCD electricity costs
($0.046/kWh in December 1987 dollars).  Applying this  procedure, the cost of
lost electricity sales for a facility with a 1,000 kW  capacity turbine is
$1,100 per day (i.e., $0.046/kWh times 1,000 kW times  24 hours).
                                      3.8-1
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             TABLE 3.8-1.   DOWNTIME REQUIREMENTS IN MONTHS4
                                             Combustor
                                             downtime
                                             (months)
Combustion Modifications                       0.25-4
ESP-Rebuild                                       1-2
ESP-Add plate area                              0.5-lb
Retrofit Spray Dryer                                1
Retrofit Sorbent Injection                      0.5-lb
Humidification                                 0.25-1
Reference 2.
 If there are significant space limitations,  up to an additional
 6 months could be required.
                                 3.8-2
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3.8.2  Procedures to Estimate Cost; from Loss of Tipping Fees
     Downtime costs associated with loss of tipping fees are estimated by
multiplying an appropriate tipping fee (typically $25/ton) by the increase in
tonnage of solid waste disposal.  The increase in solid waste is the
amount of feed that would have been reduced in the combustor plus the fly ash
t!r,t would have been collected by the existing PM control device, if the
combustor were operating during the downtime period.  For example, if the
weight of MSW fed to a 100 tpd combustor is reduced by 75 weight percent
during combustion (including bottom ash and fly ash), the tonnage of solid
waste to be disposed would increase from 25 tpd during combustor operation up
to 100 tpd when the unit is shut down.  The increase in solid waste disposal
costs is approximately $1,880, based on a $25/ton tipping fee (i.e., $25/ton
times 75 tons per day).
                                      3.8-3
-------
                                  PtFERENCES

1.    Electric Power Research Institute.   TAG™-Technical  Assessment Guide
     (Volume 1:   Electricity Supply-1986).   Palo Alto,  CA.   EPRI
     No.  P-4463-SR.  December 1986.   p.  B-4.

2.    Memorandum from White,  D.M.  and J.T, Waddell,  Radian Corporation, to
     R.E. Myers,  EPA/ISB.   June 3,  1988.   Time Requirements for Retrofit of
     Particulate  Matter (PM), Acid  Gas,  and Temperature Control Technologies
     on Existing  Municipal  Waste Combustors (MWC's).
                                      3.8-4
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                    APPENDIX A

COST COMPARISON BETWEEN SPRAY DRYER/FABRIC FILTER
AND SPRAY DRYER/ELECTROSTATIC PRECIPITATOR SYSTEMS
-------
         COST COMPARISON BETWEEN SPRAY DRYER/FABRIC FILTERS (SD/FF)
        AND SPRAY DRYER/ELECTROSTATIC PRECIPITATOR (SD/ESP) SYSTEMS

A.I  INTRODUCTION
     This appendix compares SD/FF and SD/ESP costs for two model mass-burn
waterwall plants (a 250-tpd plant and a 3,000-tpd plant) at a PM outlet
concentration of 0.01 gr/dscf.  Costs presented in the appendix for SD/FF
systems are based on cost procedures discussed in Section 2.4.  Cost
procedures presented in this appendix were used for SD/ESP.  Lime
requirements are based on a stoichiometric ratio of 1.5:1 for both systems.
The objective of this comparison was to determine whether (1) the costs of
these systems differ sufficiently to warrant separate costing procedures for
each system and (2) a single procedure can be used.

A.2  COST COMPARISON BETWEEN SD/ESP'S AND SD/FF
     Costs for SD/ESP's and SD/FF systems are estimated for two model
mass-burn plants.    Model plant 1 is a 250-tpd plant with two combustors,
whereas model plant 3 is a 3,000-tpd plant with four combustors.  These
plants were selected to cover the size range of most MWC facilities.  For
both plants, the SD systems are assumed to achieve 90 percent HC1 and 70
percent S0? removal and an outlet PM emissions of 0.01 gr/dscf at 12 percent
C02-  The following two sections discuss the approach taken in estimating
costs for SD/ESP applied to these model plants and the results of the cost
comparison.  The costs for SD/FF systems are based on procedures presented in
Section 2.4 at a stoichiometric ratio of 1.5:1.
A.2.1  Approach Used to Estimate SD/ESP Costs
     Table A-l presents purchased equipment cost data for SD/ESP's provided
by five manufacturers.  The vendor quotations were based on design
specifications for model mass-burn and refuse-derived fuel (RDF) plants.
Because the costs in Table A-l contain significant scatter, the costs for
vendors A and C were used to develop the capital cost procedure for SD/ESP's
applied to mass-burn combustors.  Both manufacturers are experienced in SD
technology.  Furthermore, the costs reported by both were consistent and
generally were conservative compared to the other vendor's costs.  Limited
                                     A-l
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  TABLE A-2.  CAPITAL AND ANNUALIZED COSTS PROCEDURES FOR MASS BURN MWC'sa'b

Capital Costs (dollars per ton/day of MSW processed)
1.   Mass burn MWC without electrical generation:
     Unit Capital Costs = 50,420 (430/Size)0'39
2.   Mass burn MWC with electrical generation:
                                           n ^Q
     Unit Capital Costs = 60,700 (430/Size)""33
3.   Total Capital Costs = Unit Capital  Cost * TPD

Annualized Costs
1.   Operating and Maintenance Costs excluding waste disposal:
     For mass burn refractory wall MWC,
          Costs = (15.7 - 0.00115 TPD) * Total Capital Costs/100
     For mass burn waterwall MWC,
          Costs = (12.5 - 0.00115 TPD) * Total Capital Costs/100
2.   Capital Recovery0
     Costs = CRF * Total Capital Costs
3.   Waste Disposal of Bottom Ash:
     Costs = 1_ *  IOP__WR  * TPD * HRS * WDC

aCosts are estimated in December 1987 dollars.
 Size = combustor MSW feed rate, tons/day
 TPD  = plant MSW feed rate, tons/day
 HRS  = hours of operation
 CRF  = Capital recovery factor, 0.1315 based on 10 percent interest rate and
          15-year economic life
 WR   = weight reduction MSW in the combustor percent
 WDC  = waste disposal cost rate, dollars per ton (typically $25/ton)
cApplies  only to new plants.  Capital recovery costs are not estimated for
 retrofit applications, since the capital costs are sunk.
                                      A-2
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cost daU were available from vendor E at other outlet PM emission levels to
substantiate the relative high equipment cost at 0.01 gr/dscf at 12 percent
co2.
     Table A-2 presents the capital cost procedures for SD/ESP applied to
mass-burn facilities only.  A cost equation was developed relating purchased
equipment costs in Table A-l at an outlet PM emission level of 0.01 gr/dscf
at 12 percent CO,, with flue gas flowrate on a logarithmic basis.  The
resultant equipment cost equation updated to December 1987 dollars using the
Chemical Engineering Plant Index is given below:

          Equipment Costs, 103 $ = 5.896 Q°'535
where:
          Q = 125 percent of the actual flue gas flowrate, acfm.
Both installation and indirect costs are 60 percent of the equipment costs.
                                                                    2
Assuming that the indirect costs are 33 percent of the direct costs,  the
direct cost equation for SD/ESP system shown in Table A-2 can be derived.
Total direct cost equations for ductwork and the I.D. fan for SD/FF systems
in Section 2.4 are used directly for SD/ESP systems.  To be consistent with
the SD/FF procedures in Section 2.4, costs for installation, indirect capital
costs, and contingencies for SD/ESP are based on the same percentages used in
the SD/FF procedures.
     Operating costs for SD/ESP were estimated using Table A-3.  These
operating costs are based on lower operating labor requirements (3 man-hours/
shift versus 4 man-hours/shift) and lower fan gas-side pressure drop
requirements (5.5 inches versus 12.5 inches) than those for SD/FF.  The
gas-side pressure drop of 5.5 inches is based on a pressure drop of 5 inches
across the SD and 0.5 inches across the ESP.  Electricity costs are included
for ESP energization.  Additional costs are included for the SD/FF systems
for bag replacement and compressed air.  The same cost rates used to estimate
SD/FF operating costs in Section 2.4 are used for estimating operating costs
for SD/ESP systems in December 1987 dollars.
A.2.2  Cost Comparison Results
     Tables A-4 and A-5 present costs for both SD/ESP and SD/FF systems
applied to 250- and 3,000-tpd mass-burn plants, respectively.  The capital
                                     A-3
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   TABLE A-2.   CAPITAL COST PROCEDURES FOR SD/ESP ON  NEW  MASS-BURN PLANTS
     Total  Direct Costs (December 1987 dollars)3
     Single SD/ESP Unit:  Costs,  103$  = 7.087 (Q)0'535
     Ductwork:  Costs,  103$ = 1.387 *  L * Q°'5/1000
     Fan:       Costs,  103$ = 1.875 *  Q°'96/1000
     Multiple Units:   Multiply the above costs by the number of units.
     Indirect Costs =  33% of total direct costs.
     Contingency = 20% of sum of direct and indirect costs.
     Total  Capital
      Investment = Total  Direct Costs + Indirect Costs + Contingency Costs.
aQ = 125 percent of the actual  flue gas flowrate,  acfm
 L = Duct length, feet
Cost procedures assume thatjthe total  installed costs are 133 percent of the
total direct capital costs.
                                     A-4
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             TABLE A-3.  ANNUAL OPERATING COSTS PROCEDURES FOR
                            SD/ESP ON NEW MASS-BURN PLANTS
                                                            Reference
Operating Labor:  3 man-hours/shift; $12/man-hour             3, 4
Supervision:  15% of operation labor costs                      4
Maintenance:
     Labor -- 2 man-hour/shift                                3, 4
              10% wage rate premium
              over operating labor wage
     Materials -- 2% of direct capital costs                    3
Electricity:  Electricity costs = $0.046/kwh
                                     2
     ESP Energization -- 1.5 watts/ft  plate area               5
     Fan -- 5.5 inches of water pressure drop                 6, 7
     Atomizer Auxiliary Equipment --                            8
      Kw = 6kw per 1,000 Ibs/hr of slurry feed + 15kw
     Pump --20 feet of pumping height                          9
             10 psi discharge pressure
             10 ft/sec velocity in pipe
Water:   Based on water flowrate required for                   10
        cooling flue gas to 300 F and water cost
        rate of $0.50/1000 gal
Lime:  Based on lime feed rate to the spray                    11
       dryer calculated by assuming a stoichiometric
       ratio of 1.5:1.  Apply appropriate lime
       costs in $/ton ($70/ton)
Solid Waste:  Calculate solid waste disposal rate              12
              collected by the ESP and the spray
              dryer and apply appropriate tipping
              fee in $/ton. (Assume $25/ton)
                                     A-5
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        TABLE A-3.  ANNUAL OPERATING COSTS PROCEDURES FOR
                      SD/ESP ON NEW MASS-BURN PLANTS
                              (Continued)
                                                       Reference
Overhead:  60% of the sum of all labor                    13
           costs (operating, supervisory,
           and maintenance) plus materials


Taxes, Insurance, and
Administrative Charges:   4% of total                     13
                          capital costs

Capital Recovery:  15-year life and 10%                   14
                   interest rate
                                A-6
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          TABLE A-4.   COSTS FOR SD/ESP'S AND SD/FF'S FOR A 250-TPD
                              MASS-BURN PLANT3
Model Plant No. 1

               250 tpd Mass-Burn Facility with 2 Combustors
                    Outlet PM Emissions = 0.01 gr/dscf

                                             SD/FF           SD/ESP

Capital Cost (1.000 $)

     Total Direct                            3,270           3,730
     Total Indirect                          1,080           1,230
     Contingency                               870             993
     Total Capital Costs                     5,220           5,960


Operating Costs (1,000$)

     Direct Costs:

     Operating Labor                            96              72
     Supervision                                14              11
     Maintenance Labor                          53              40
     Materials                                  65              75
     Electricity                                62              51
     Water                                       1               1
     Lime                                       50              50
     Waste Disposal                             81              81
     Bag Replacements                           15               0
     Compressed Air                              80

     Indirect Costs:

     Overhead                                  137             119
     Taxes, Insurance. & Administration        209             238
     Total Operating Costs                     791             738

Annualized Costs

     Capital Recovery                          687             783
     Total Annualized Costs                  1,480           1,520
aCosts are in December 1987 dollars.
                                     A-7
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        TABLE A-5.   COSTS FOR SD/ESP'S AND SD/FF'S FOR A 3,000-TPD
                              MASS-BURN PLANT3
Model Plant No. 3

               3,000 tpd Mass-Burn Facility with 4 Combustors
                     Outlet PM emissions = 0.01 gr/dscf

                                             SD/FF           SD/ESP

Capital Cost (1.000 $)

     Total Direct                            17,340          20,260
     Total Indirect                           5,720           6,690
     Contingency                              4,610           5,390
     Total Capital Costs                     27,600          32,300


Operating Costs (1.000 $)

     Direct Costs:

     Operating Labor                            192             144
     Supervision                                 29              22
     Maintenance Labor                          106             106
     Materials                                  347             405
     Electricity                                629             504
     Water                                       12              12
     Lime                                       594             594
     Waste Disposal                             975             975
     Bag Replacements                           184               0
     Compressed Air                              98               0

     Indirect Costs:

     Overhead                                   404             406
     Taxes, Insurance. & Administration       1.110           1,290
     Total Operating Costs                    4,680           4,460

Annualized Costs

     Capital Recovery                         3,640           4.250
     Total Annualized Costs                   8,320           8,710
aCosts are in December 1987 dollars.
                                     A-8
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costs for SD/ESP systems are higher than those for SD/FF systems for both
plants.  This is because ESP capital costs are more sensitive to PM removal
requirements than those for FF's.  At the removal efficiencies required to
achieve an outlet loading of 0.01 gr/dscf, the capital costs for a SD/ESP are
roughly 15 percent higher than for a SD/FF.
     Tables A-4 and A-5 show that operating costs for SD/ESP and SD/FF
systems are essentially the same.  For both plants, capital-related operating
costs are greater for an SD/ESP than for an SD/FF.  The noncapital-related
costs for an SD/ESP are lower.  The magnitude of these cost differences are
roughly equal, resulting in about the same operating costs for both SD
systems.
     Because of lower capital  costs, annualized costs for SD/FF systems are
roughly 4 percent less than SD/ESP systems for both model plants.  The
results from this cost comparison, which showed the annualized costs for both
systems are similar, agreed with those presented in another cost study
prepared for the State of New York.
                                     A-9
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REFERENCES


 1.   U.  S. Environmental Protection Agency.  Municipal  Waste Combustion Study:
     Costs of Flue Gas Cleaning Technologies, Research  Triangle Park, NC.
     Publication No. EPA/530-SW-87-021e.   June 1987.   pp. 2-1 to 2-3.

 2.   Bowen,  M.L. and M.S.  Jennings (Radian Corporation).   Cost of Sulfur
     Dioxide, Particulate  Matter,  and Nitrogen Oxide  Controls in Fossil Fuel
     Fired Industrial Boilers.   Prepared  for the U.  S.  Environmental
     Protection Agency.   Research  Triangle Park, NC.   Publication No.
     EPA-450/3-82-021.  August  1982.  p.  2-11.

 3.   Memorandum from Aul,  E.F.  et  al., Radian Corporation, to Sedman, C.B.,
     EPA.   May 16, 1983.  30 p.  Revised  Cost Algorithms  for Lime Spray
     Drying and Dual Alkali  FGD Systems.

 4.   Vatavuk, W.M., and R.B. Neveril, Estimating Costs  of Air Pollution
     Control  Systems, Part II:   Factors for Estimating  Capital and Operating
     Costs,  Chemical Engineering,  November 3, 1980.   pp.  157 to 162.

 5.   Neveril, R. B. (CARD, Inc.)  Capital and Operating Costs of Selected Air
     Pollution Control Systems.  Prepared for the U.  S. Environmental
     Protection Agency.   Research  Triangle Park, NC.   Publication No.
     EPA-750/5-80-002.  p. 3-18.

 6.   U.  S. Environmental Protection Agency.  EAB Control  Cost Manual.
     Research Triangle Park, NC.  Publication No. EPA-450/5-87-001A.
     February 1987.  p.  6-39.

 7.   Letter and attachment from Fiesinger, T., New York State Energy Research
     and Development Authority, to Johnston, M., EPA.  January 27, 1987.
     Draft report on the economics of various pollution control alternatives
     for refuse-to-energy plants,   p. 6-9.

 8.   Reference 7, p. 6-10.

 9.   Dickerman, J.C. and K.  L.  Johnson.  (Radian Corporation)  Technology
     Assessment Report for Industrial Boiler Applications:  Flue Gas
     Desulfurization.  Prepared for the U. S. Environmental Protection
     Agency.   Washington,  DC.  Publication No. EPA-600/7-79-178i.
     November 1979.  pp. 5-5 and 5-17.

10.   Letter from Solt, J.C., Solar Turbines Incorporated, to Noble, E., EPA.
     October 19, 1984.  Development cost for wet control  for stationary gas
     turbines.

11.   Chemical Marketing Reporter.   Volume 233.  Number 1.  January 4,  1988.

12.   Reference 6, p. 2-29.
                                    A-10
-------
13.  Reference 6, p. 2-31.



14.  Reference 2, pp. 2-17 and 2-18.



15.  Reference 7, pp. 6-1 to 6-17.
                                    A-ll
-------
      APPENDIX B



DETAILED COST EQUATIONS
-------
    TABLE B-l.  CAPITAL AND ANNUALIZED COST PROCEDURES FOR MODULAR MWC'sa'b
Capital Costs
1.   Modular MWC without heat recovery:
     Unit Capital Cost = $24,300 per ton/day of MSW processed
2.   Modular MWC producing steam (without generating electricity):
     Unit Capital Cost = $32,500 per ton/day of MSW processed
3.   Modular MWC generating electricity:
     Unit Capital Cost = $54,600 per ton/day of MSW processed
4.  Total Capital Costs = Unit Capital Costs * TPD
Annualized Costs
1.   Operating and Maintenance Costs excluding waste disposal:
     For TPD < 150 and MRS < 6,000,
          Costs = (10 - 0,23 TPD + 0.006 MRS) * Total Capital Costs/100
     Otherwise,
          Costs = (15.7 - 0.00115 TPD) * Total Capital Costs/100
2.   Capital Recovery0:
     Costs = CRF * Total Capital Costs
3.   Waste Disposal  of Bottom Ash:
     Costs
24 *(10°100  | * TPD * HRS * WDC
aCosts are estimated in December 1987 dollars.
bTPD = plant MSW feed rate, tons/day
 HRS = hours of operation
 CRF = capital recovery factor, 0.1315 based on 10 percent interest rate and
       15-year economic life
 WR  = weight reduction of MSW in the combustor,  percent
 WDC = waste disposal cost rate, dollars per ton (typically $25/ton)
 Applies only to new plants.  Capital recovery costs are not estimated for
 retrofit applications since the capital costs are sunk.
                                      B-l
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  TABLE B-2.  CAPITAL AND ANNUALIZED COSTS PROCEDURES FOR MASS-BURN MWC's

Capital Costs (dollars per ton/day of MSW processed)
1.   Mass-burn MWC without electrical generation:
     Unit Capital Costs = 50,420 (430/Size)0'39
2.   Mass-burn MWC with electrical generation:
     Unit Capital Costs = 60,700 (430/Size)0'39
3.   Total Capital Costs = Unit Capital Cost * TPD
Annual ized Costs
1.   Operating and Maintenance Costs excluding waste disposal:
     For mass-burn refractory wall MWC,
          Costs = (15.7 - 0.00115 TPD) * Total Capital Costs/100
     For mass-burn waterwall MWC,
          Costs = (12.5 - 0.00115 TPD) * Total Capital Costs/100
2.   Capital Recovery0
     Costs = CRF * Total Capital Costs
3.   Waste Disposal of Bottom Ash:
     Costs = 1_
                                                                       'a'b
                             * TPD * HRS * WDC
aCosts are estimated in December 1987 dollars.
 Size = combustor MSW feed rate, tons/day
 TPD  = plant MSW feed rate, tons/day
 HRS  = hours of operation
 CRF  = Capital recovery factor, 0.1315 based on 10 percent interest rate and
         15-year economic life
 WR   = weight reduction MSW in the combustor percent
 WDC  = waste disposal cost rate, dollars per ton (typically $25/ton)
cApplies only to new plants.  Capital recovery costs are not estimated for
 retrofit applications, since the capital costs are sunk.
                                      B-2
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   TABLE B-3.  CAPITAL AND ANNUALIZED COST PROCEDURES FOR RDF FACILITIES3'13
Capital Costs (dollars per ton/day of RDF processed)


1.   Coarse RD facility:

     Unit Capital Costs = 73,600 (400/Size)0'39


2.   Fluff RDF facility:

     Unit Capital Costs = 161,880 (315/Size)0*39


3.   Total Capital Costs = Unit Capital Costs * TPD
Annualized Costs0
1.   Operating and Maintenance Costs excluding waste disposal

     Costs = (12.5 - 0.00115 TPD) * Total Capital Costs/100


2.   Capital Recovery0:

     Costs = CRF * Total Capital Costs


3.   Waste Disposal of Bottom Ash:

     Costs = 1
L. * /JOO - WR\
24   y  100  f
                             * TPD * HRS * WDC
aCosts are estimated in December 1987 dollars.

 Size = combustor RDF feed rate, tons/day
 TPD  = plant MSW feed rate, tons/day
 CRF  = capital recovery factor, 0.1315 based on 10 percent interest rate and
        15-year economic life
 WR   = weight reduction of MSW in the combustor, percent
 HRS  = hours of operation
 WDC  = waste disposal  cost rate,  dollars per ton (typically $25/ton)

°Applies only to new plants.  Capital recovery costs are not estimated for
 retrofit applications since the capital costs are sunk.
                                      B-3
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      TABLE B-4.  PROCEDURE FOR ESTIMATING CAPITAL COSTS FOR NEW FBC'S
                                 (December 1987 dollars)
Total Direct and Indirect Costs:a

     Costs, 103$ = 64,900 * TPD * (900/TPD)0'39
Process Contingency:  20% of total direct and indirect costs
Total Capital FBC Costs:  Total direct and indirect costs + process
                          contingency
aTPD = plant municipal waste feed rate, tons/day.
                                      B-4
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   TABLE B-5.  PROCEDURE FOR ESTIMATING ANNUAL OPERATING COSTS FOR FBC'S
                                 (December 1987 dollars)
Combustor and Balance of Plant (excludes coarse RDF processing area):

     Operating labor (based on 10 man-years,  40 hours/week.  $12/hr):
     OL = 10 * 40 * 52 * 12 * (TPD/900)  = 277.3 * TPD
     Supervision (based on 3 man-vears/vear.  40 hours/week.  30% wage  rate
     premium over the operating labor wage):
     SPRV = 3 * 40 * 52 * 12 * 1.3 * (TPD/900)  = 108.2 * TPD
     Maintenance labor (based on 3 man-vears/vear,  40 hours/week.  10% wage
     rate premium over the operating labor wage):
     ML = 3 * 40 * 52 * 12 * 1.1 * (TPD/900)  =  91.5 * TPD
     Maintenance materials: 3% of the total  capital costs
     Electricity (based on 3 MW power consumption,  and electricity rate of
     $0.046/kwh):
     ELEC = 0.153 * TPD * HRS
     Limestone (based on $40/ton for limestone):
     LIMESTONE = 0.02 * LFEED * HRS * N
     Water (based on 3% blowdown rate and $0.05/1.000 gal):
     WC = 1.86 x 10"6 * STM * HRS
     Waste disposal (based on tipping fee of  $25/hr):
     AD = 1.25 x 10"2 * N * HRS * WDR
     Overhead:  60% of the sum of all  labor costs (operating,  supervisory,
     and maintenance) plus 60% of maintenance materials costs
                                 Continued
                                    B-5
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  TABLE B-5. (CONCLUDED).  PROCEDURE FOR ESTIMATING ANNUAL OPERATING COSTS
                                   FOR FBC'S (December 1987 dollars)
Coarse RDF Processing Area:

     Total Operating and Maintenance Costs (TOT O&M):

     TOT O&M = 4.4 x 10"4 * (12.5 - 0.00115 * TPD)  * TDI

Taxes, Insurance, and Administrative Charges:

4% of the total capital cost

Capital Recovery (based on 15 year life and 10% interest  rate):

13.15% of the total capital  cost
 OL = operating labor costs, $/yr
 SPRV = supervision costs, $/yr
 ML = maintenance labor costs, $/yr
 ELEC = electricity costs, $/yr
 MRS = hours of operation per year
 LIMESTONE = limestone costs, $/yr
 LFEED = limestone feed rate per unit, Ib/hr
 N = number of combustors
 WC = water costs, $/yr
 STM = plant steam production, Ib/hr
 AD = waste disposal costs, $/yr
 WDR = waste disposal rate per unit (bottom and fly ash collected), Ib/hr
 TPD = plant municipal waste feed rate, tons/day
 TDI = total direct and indirect capital costs for FBC plant, $
                                      B-6
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              TABLE B-6.  PROCEDURES FOR ESTIMATING CAPITALISTS
                  FOR ELECTROSTATIC PRECIPITATORS (ESP'S)a'D
Design Equation for Mass-burn and RDF Facilities:

     SCA = -189.29 In   (100 - PMEFF)
                            101.89
Design Equation for Modular Units:

     o    Use above design equation for large modular units whose flue gas
          flowrate (Q) is greater than or equal  to 30,000 acfm

     o    For small modular units whose Q < 30,000

          SCA = -285.7 In   (100 - PMEFF)
                                79.6
Purchased Equipment Costs

ESP for Massburn and RDF plants and large modular plants0:
     Costs,  10J $ = (305.2 + 0.00738 * TPA) * RF * N

ESP for small  modular plants (Q < 30,000)c:
     Costs,  10J $ = 1.08 * (96.3 + 0.015 * TPA) RF * N

ESP Rebuilds:  3
     Costs,  10  $ = 0.42 * purchased equipment costs for a new ESP (RF = 1)

Ductwork:     ~                        n c
     Costs,  10J $ = 0.7964 * N * RF * Qu<0

Fan:          ,                       n Qfi
     Costs,  10J $ = 1.077 * N * RF * Qu'30


Installation Direct Costs

     = 67% of purchased equipment costs for new ESP and ESP upgrades
       (i.e.,  addition of new plate area in existing ESP)
     = 33% of purchased equipment costs for ESP rebuilds only

                                                                   (continued)
                                      B-7
-------
                            TABLE B-6.   (Continued)
Indirect Costs
       54% of purchased equipment costs for mass-burn,  RDF,  and large modular
       units with new ESP and ESP upgrades
       $14,000 for small modular units with new ESP and ESP upgrades
       24% of the purchased equipment costs for ESP rebuilds
Contingency

     = 3% of purchased equipment costs


Total Capital Costs

     = Purchased equipment costs + installation direct costs +
       indirect costs + contingency costs
aCosts are estimated in December 1987 dollars.
 PMEFF = particulate matter removal efficiency, percent
   SCA = specific collection area, ft /I,000 acfm
     Q = 125 percent of the actual flue gas flowrate per ESP unit, acfm
   TPA = total plate area, ft*
    RF = retrofit factor obtained from Table B-16
     N = number of ESP units
     L = duct length, feet
clncludes taxes and freight of eight percent of the ESP equipment costs.  For
 retrofit applications requiring additional plate area of the existing ESP,
 TPA is the increase in the plate area.
                                       B-8
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      TABLE B-ll.  PROCEDURES FOR ESTIMATING CAPITAL COSTS OF STANDALONE
                       SPRAY DRYER AND SPRAY DRYER/FABRIC FILTERS3'D
Direct Costs
SD/FF Unit0:  Costs, 103 t = 8.053 * N * RF * (Q)0'517
Stand-Alone SD Unit:  Costs, 103 $ = 8.428 * N * RF * (Q)°'46°
Ductwork0:  Costs, 103 $ = (1.3868 * N * RF * L * Q°'5)/l,000
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Indirect Costs = 33% of direct costs
Contingency = 20% of sum of direct and indirect costs
Total Capital Investment = Direct Costs + Indirect Costs + Contingency Costs
aAll costs are estimated in December 1987 dollars.
 Q  = 125% of the actual flue gas flowrate, acfm
 N  = number of units
 RF = retrofit factor obtained from Table B-16
 L  = Duct length per unit, feet
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 costs.
                                      B-14
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-------
  TABLE B-13.  PROCEDURES FOR ESTIMATING CAPITAL COSTS FOR HUMIDIFICATION
Purchased Equipment Costs, 10  $
     1.   Humidification Chamber and Pumps:

          Costs  = (0.438 * Q + 80,220) N * RF/1,000


     2.   Ductwork:

          Costs = (1.16 * L * Q°-5) * N * RF/1,000


Installation Direct Costs = 56% of Purchase Equipment Costs


Indirect Costs            = 32% of Purchase Equipment Costs


Contingency               = 3% of the Purchase Equipment Costs
Total Capital Costs       = Purchased Equipment Costs +
                            Installation Direct Costs + Indirect Costs

                          = 191% of Purchase Equipment Costs
aAll costs are estimated in December 1987 dollars.

 Q  = 125% of the actual flue gas flowrate,  acfm
 L  = duct length per unit, feet
 N  = number of units
 RF = retrofit factor obtained from Table B-16
                                                                         a,b
                                     B-17
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-------
               TABLE B-15.  CONTINUOUS MONITORING COST SUMMARY'

Pollutant
compliance
options
PM only
Acid gas only



PM + acid gas




Method
Opacity5
S0? (inlet and outlet)
HCt (inlet and outlet)
o2/co2
Data Reduction System
Total
Opacity
S0? (inlet and outlet)
HCT (inlet and outlet)
00/C00
-------
       TABLE B-16.   SITE ACCESS AND CONGESTION FACTORS FOR RETROFITTING
                       APCD EQUIPMENT AT EXISTING PLANTS


Retrofit     Congestion
factor         level             Guidelines for selecting retrofit factor


1.02         Base case      Interferences similar to a new plant with adequate
                            crew work space.   Free access for cranes.  Area
                            around combustor and stack adequate for standard
                            layout of equipment.

1.08         Low            Some aboveground 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.

1.25         Medium         Limited space.  Interference with existing
                            structures or equipment which cannot be relocated.
                            Special designs are necessary.  Crane access
                            limited to one side.  Majority of equipment
                            elevated or remotely located.

1.42         High           Severely limited space and access.  Crowded
                            working conditions.  Access for cranes blocked
                            from all sides.
                                     B-20
-------
      TABLE B-17.  PROCEDURE FOR ESTIMATING SCOPE ADDER CAPITAL COSTSa'b
Direct and Indirect Costs
1.   New Ducting:
     Costs, 103 $ = 1.844 * L * N * RF * Q°'5
2.   New I.D. Fan:
     Costs, 103 $ = 2.493 * N * RF * Q°'96

3.   New Stacks (costs per stack):
     o    For a lined acid resistant stack,
          Costs, 103 $ = [26.2 + 0.089 * H * (1 + 4.14 * D)] for D > 5
          Costs, 103 $ = [26.2 + 0.080 * H * (1 + 4.33 * D)] for D < 5
     o    For a unlined stack,
          Costs, 103 $ = [26.2 + 0.0625 * H * (1 + 2.59 * D)] for D > 5
          Costs, 103 $ = [26.2 + 0.087 * H * (1 + 2.2 * D)] for D < 5

Contingency = 20% of the direct and indirect costs

Total Capital Costs = Direct Costs + Indirect Costs + Contingency Costs
aAll costs are estimated in December 1987 dollars.
 L  = duct length per unit, feet
 N  = number of units
 RF = retrofit factor obtained from Table B-16
 Q  = 125% of the actual flue gas flowrate, acfm
 H  = stack height, feet
 D  = stack diameter, feet
                                     B-21
-------
                     TABLE B-18.   DOWNTIME COST PROCEDURE3
Capital Costsb
Loss of Tipping Fees:
     Costs, $ =/ME_l*fI£D\ * WDC * HRS * (D-|y12)



Loss of Energy (Steam or Electricity):


     Costs, $ = IE2 * ER * HRS * DC * (DT/12)
                24
Annualized Costs (Capital Recovery)0
     Costs, $ = CRF * Downtime Capital  Costs
aCosts are estimated in December 1987 dollars.  Apply only to retrofit
 applications.

 WR  = weight reduction of waste in the combustor, percent
 WDC = waste disposal cost rate, dollars per ton (typically $25/ton)
 TPD = plant waste feed rate, tons/day
 HRS = hours of operation
 DT  = downtime, months
 ER  = energy cost rate, dollars per ton ($24.84/ton for mass burn waterwall
       units, $36.16/ton for RDF units, and $19.52/ton for modular and mass
       burn refractory units with heat recovery)
CCRF = capital recovery factor, 0.1315 based on 10 percent interest rate and
       15-year economic life
                                     B-22
-------
                                   TECHNICAL REPORT DATA
                            (Please read Instructions on the reverse before completing]
1. REPORT NO.
  EPA-450/3-89-27a
               3. RECIPIENT'S ACCESSION NO
4. TITLE AND SUBTITLE
  Municipal Waste Combustors  - Background Information for
  Proposed Standards:  Cost Procedures
               5. REPORT DATE
                 August 1989
               6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
                                                            8. PERFORMING ORGANIZATION REPORT NO. ;
9. PERFORMING ORGANIZATION NAME AND ADDRESS
   Office  of Air Quality Planning and Standards
                                                            10. PROGRAM ELEMENT NO.
   U. S.  Environmental Protection Agency
   Research Triangle Park, North Carolina
27711
11. CONTRACT/GRANT NO.

     68-02-4378
12, SPONSORING AGENCY NAME AND ADDRESS
  DAA  for  Air Quality Planning  and Standards
  Office of Air and Radiation
  U.S.  Environmental Protection Agency
  Research Triangle Park, North Carolina  27711
               13. TYPE OF REPORT AND PERIOD COVERED
                  Final
               14. SPONSORING AGENCY CODE
                  200/04
15. SUPPLEMENTARY NOTES
16. ABSTRACT

         Cost Procedures for  the  costing of new and  existing municipal  waste combustor
   facilities and associated  equipment are presented.   Cost procedures  are developed
   for  combustors, heat recovery  equipment, humidification equipment, air pollution
   control devices for the  reduction of particulate  matter and acid gas emissions, and
   continuous emission monitoring equipment.

         Costs in this report  are divided into capital costs, operating and maintenance
   costs,  and annualized costs.   Costs associated with retrofitting existing facilities
   are  also presented.
17.
                                KEY WORDS AND DOCUMENT ANALYSIS
                  DESCRIPTORS
                                               b.IDENTIFIERS/OPEN ENDED TERMS  C. COSATI Field/Group
  Air Pollution
  Municipal  Waste Combustors
  Incineration
  Pollution  Control
  Costs
  Air Pollution Control
                    13B
18. DISTRIBUTION STATEMENT
 19 SECURITY CLASS (This Report)
      Unclassified
              21 NO OF PAGES
                  166
                                               20 SECURITY CLASS (Tins page)
                                                   Unclassified
                                                                          22 PRICE
EPA Form 2220-1 (Rev. 4-77)    PREVIOUS EDITION is OBSOLETE
-------
-------





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