Evaluation And Costing Of NOx Controls For Existing Utility Boilers In The Nescaum Region


vvEPA
          United States
          Environmental Protection
          Agency
              Office of Air Quality
              Planning and Standards
              Research Triangle Park, NC 27711
EPA453/R-92-010
December 1992
          Air
EVALUATION AND COSTING OF
NOx CONTROLS FOR EXISTING
UTILITY BOILERS IN THE
NESCAUM REGION
           NORTHEAST STATES
           FOR COORDINATED
          AIR USE MANAGEMENT
             (NESCAUM)
                         CONTROL TECHNOLOGY CENTER

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                                 EPA-453/R-92-010
EVALUATION AND COSTING  OF NOX
 CONTROLS FOR EXISTING UTILITY
BOILERS IN  THE NESCAUM REGION
      CONTROL TECHNOLOGY CENTER
               Sponsored by:

            Emission Standards Division
       Office of Air Quality Planning and Standards
          U.S Environmental Protection Agency
       Research Triangle Park, North Carolina 27711

      Air and Energy Engineering Research Laboratory
          Office of Research and Development
          U.S Environmental Protection Agency
       Research Triangle Park, North Carolina 27711

                    and

   NORTHEAST STATES FOR COORDINATED
           AIR USE MANAGEMENT

                 (NESCAUM)
               129 Portland Street
            Boston, Massachusetts 02114
                December 1992

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                                                  EPA-453/R-92-010
                                                    December 1992
EVALUATION AND COSTING  OF NOX CONTROLS
          FOR EXISTING UTILITY BOILERS
              IN THE NESCAUM REGION
                          Prepared by:

                        Carlo Castaldini
                 Acurex Environmental Corporation
                        555 Clyde Avenue
                         P.O. Box 7044
                  Mountain View, California 94039
                   EPA Contract No. 68-D9-0131
                     Work Assignment No. 1-19
                        Project Managers

                        William Neuffer
                    Emission Standards Division
                U.S Environmental Protection Agency
             Research Triangle Park, North Carolina 27711

                             and

               Praveen K. Amar and Nancy L. Seidman
          Northeast States for Coordinated Air Use Management
                       129 Portland Street
                    Boston, Massachusetts 02114    g Envirottmenta^Protect»on Agen y
                                             Pr'" V'H 5i Ll"f3'y  	  i  1 O4-K Elr>nr
                                              H   . iT'^cr..-) r v;i'.A ard, IZtn rioui
                          Prepared for:         c-ii^o, ^^60604-3590 -

               CONTROL TECHNOLOGY CENTER
                U.S Environmental Protection Agency

                             and

 NORTHEAST STATES FOR COORDINATED AIR USE MANAGEMENT

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                                 EPA REVIEW NOTICE
       This report has been reviewed by the U.S. Environmental Protection Agency, and approved
for publication. Approval does not signify that the contents necessarily reflect the views and policy
of the Agency, nor does mention of trade names or commercial products constitute endorsement
or recommendation for use.

       This document is available to the public through the National Technical Information Service,
Springfield, Virginia  22161, (703) 487-4650.

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                                       PREFACE
       The  Control  Technology  Center (CTC) was  established by the  U.S.  Environmental
Protection Agency's (EPA's) Office of Research and Development (ORD) and the Office of Air
Quality Planning and Standards (OAQPS) to provide technical assistance to State and local air
pollution control agencies. Several levels of assistance can be provided when appropriate. These
include the following:

       •   CTC HOTLINE—provides  quick telephone  assistance  on matters  relating to  air
           pollution control technology (919-541-0800)

       •   Engineering Assistance Projects—provide more in-depth assistance to  State and local
           agencies when needed  to address a specific air pollution problem or source

       •   Technical Guidance Projects—address problems  or source categories of regional or
           national interest by developing technical guidance documents, computer software, or
           presentation of workshops on control technology  matters

       •   Small Business Assistance—coordinates efforts among EPA centers participating in the
           Federal Small Business Assistance Program to assist State Small Business Assistance
           Programs

       •   Global  Greenhouse Gases  Technology Transfer Center—provides information  on
           greenhouse gas  emissions  and  available  prevention,  mitigation, and  control
           technologies/strategies

       •   Data Base Assistance—provides control technology information on the RACT/BACT/
           LAER  Clearinghouse Information System (BLIS) and  CTC electronic bulletin board
           system  (BBS).  These systems are available on the  OAQPS Technology Transfer
           Network BBS  (919-541-5742)

       This Technical Guidance Project addresses retrofit control options for NOX emissions from
utility boilers. The Northeast States for Coordinated Air Use Management (NESCAUM) requested
and  cofunded this effort.   NESCAUM includes the following  states:   Connecticut,  Maine,
Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and  Vermont.  NESCAUM
requested this project to  provide  a  technical basis  for its member  States to make  Reasonably
Available Control  Technology (RACT) determinations  for  NOX  emissions from utility  boilers.
RACT for NOX emissions is required in most northeastern States to attain the National Ambient
Air Quality Standard for ozone.  This information is also relevant to other States considering NOX
controls  for  utility boilers.  This  report presents  information on  the  technical  feasibility,
performance, and cost of  NOX emission control  options.

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                            TABLE OF CONTENTS
            EPA REVIEW NOTICE	    ii
            ACKNOWLEDGEMENTS	   iii
            PREFACE 	    v
            LIST OF FIGURES	    x
            LIST OF TABLES 	   xv
            LIST OF ABBREVIATIONS  	   xix

SECTION 1   EXECUTIVE SUMMARY	   1-1

SECTION 2   BOILER EQUIPMENT PROFILE	   2-1

            2.1    FIRING CONFIGURATIONS AND FUEL TYPES	   2-2
            2.2    AGE OF BOILERS	   2-5
            2.3    CAPACITY FACTOR	  2-6
            2.4    SUMMARY OF POPULATION DATA	  2-9

SECTION 3   BASELINE EMISSION PROFILES	   3-1

SECTION 4   NOX CONTROL TECHNOLOGY EVALUATION 	   4-1

            4.1    COMBUSTION CONTROLS FOR COAL-FIRED
                  BOILERS 	   4-3

            4.1.1   Overfire Air (OFA)	  4-7
            4.1.2   Low-NOx Burners (LNB)	  4-8
            4.1.3   Low-NO x Burners with Overfire Air (LNB + OFA)  	 4-14
            4.1.4   Reburning or Fuel Staging	 4-18
            4.1.5   Retrofit Potential for the NESCAUM Boilers	 4-19

            4.2    COMBUSTION CONTROLS FOR OIL- AND
                  GAS-FIRED BOILERS	 4-22

            4.2.1   Burners Out of Service (BOOS)	 4-24
            4.2.2   Flue Gas  Recirculation (FOR)	 4-26
            4.2.3   Overfire Air (OFA)	 4-27
            4.2.4   Low-NOx Burners (LNB)	 4-28
            4.2.5   Combined FRG, OFA and LNB 	 4-28
            4.2.6   Reburning 	 4-30
            4.2.7   Retrofit Potential for the NESCAUM Boilers	 4-30
                                     VII

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                        TABLE OF CONTENTS (Continued)
            4.3     FLUE GAS TREATMENT CONTROLS	  4-32

            4.3.1   Selective Noncataiytic Reduction (SNCR) 	  4-34
            4.3.2   Selective Catalytic Reduction (SCR)  	  4-35
            4.3.3   Retrofit Potential for the NESCAUM Boilers	  4-39

            4.4     COMBINED NOX/SOX CONTROLS 	  4-41

SECTIONS  DESCRIPTION OF COST ALGORITHM AND TEST  CASES	   5-1

            5.1     COST ALGORITHM	   5-1
            5.2     COST CASES  	   5-9

SECTION 6  COST OF NOX CONTROLS 	   6-1

            6.1     COMBUSTION MODIFICATIONS  FOR PC-FIRED
                   BOILERS  	   6-2

            6.1.1   Overfire Air (OFA)	   6-2
            6.1.2   Low-NOx Burners (LNB) for Wall-Fired Units and
                   LNB + CCOFA for T-Fired Units	   6-4
            6.1.3   Low-NOx Burners and Advanced Overfire Air
                   (LNB+AOFA)	  6-10
            6.1.4   Reburn for Cyclone Boilers	  6-11
            6.1.5   Summary of Combustion Modification Retrofit Costs for
                   Coal-Burning Power Plants 	  6-16

            6.2     CONTROLS FOR OIL-/GAS-FIRED BOILERS	  6-16

            6.2.1   Burners Out Of Service (BOOS) 	  6-18
            6.2.2   Flue Gas Recirculation (FGR)	  6-18
            6.2.3   Low-NOx Burners (LNB)	  6-20
            6.2.4   Burners Out of Service and Flue Gas Recirculation
                   (BOOS + FGR)	  6-20
            6.2.5   Low-NOx Burners, Overfire air, and  Flue Gas
                   Recirculation (LNB + OFA+FGR)	  6-20
            6.2.6   Summary of Combustion Modification Retrofit Costs for
                   Oil- and Gas-Fired Power Plants	  6-25

            6.3     FLUE GAS TREATMENT CONTROLS 	  6-25

            6.3.1   Selective Noncataiytic Reduction (SNCR) Costs  	  6-30
            6.3.2   Selective Catalytic Reduction (SCR)  Costs  	  6-30

            6.4     SUMMARY OF CONTROL COSTS 	  6-36
                                       via

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                     TABLE OF CONTENTS (Concluded)
SECTION 7  EFFECTS OF NOX CONTROLS ON COMBUSTION
           EFFICIENCY AND RELATED EMISSIONS		   7-1

           7.1    CO EMISSIONS FROM UNBURNED CARBON FROM
                COAL-FIRED UTILITY BOILERS	   7-2

           7.1.1  CO Emissions 	   7-2
           7.1.2  Unburned Carbon 	   7-7

           7.2    CO EMISSIONS FROM NATURAL GAS-FIRED
                UTILITY BOILERS 	  7-11
           7.3    CO EMISSIONS FROM OIL-FIRED UTILITY
                BOILERS  	  7-17
           7.4    HYDROCARBON EMISSIONS	  7-21
           7.5    SUMMARY AND CONCLUSIONS	  7-23

           REFERENCES	   R-l

           APPENDIX A — NESCAUM BOILER INVENTORY-COAL-FIRED
                        UNITS 	  A-l
           APPENDIX B — NESCAUM BOILER INVENTORY-OIL-/GAS-FIRED
                        UNITS 	   B-l
           APPENDIX C — SCHEMATICS OF LOW-NOX CONTROL
                        EQUIPMENT AND OPERATION	  C-l
           APPENDIX D - SUMMARY OF REPORTED NOX CONTROL
                        PERFORMANCE  	  D-l
           APPENDIX E - SCR INSTALLATIONS ON COAL-FIRED PLANTS
                        IN-USE OR FIRMLY PLANNED 	   E-l
           APPENDIX F - NOX CONTROL COSTS, PC-FIRED AND
                        CYCLONE BOILERS	   F-l
           APPENDIX G — NOX CONTROL COSTS, OIL-/GAS-FIRED
                        BOILERS 	  G-l
           APPENDIX H - DATA BASE ON CO, HC, AND UBC UNDER BASELINE
                        AND LOW-NOX OPERATION  	  H-l
                                  IX

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                                     LIST OF FIGURES


Figure 1-1    Contribution of boiler/fuel types to the total utility NOX inventory  	   1-3

Figure 1-2    NOX control cost-effectiveness for PC wall-fired utility boilers	    1-17

Figure 1-3    NOX control cost-effectiveness for PC tangential-fired utility
              boilers  	    1-17

Figure 1-4    NOX control cost-effectiveness for oil/gas wall-fired utility boilers	    1-18

Figure 1-5    NOX control cost-effectiveness for oil/gas tangential-fired utility
              boilers  	    1-18

Figure 2-1    Contribution of boiler/fuel types to the total utility NOX inventory  	   2-4

Figure 2-2    Trends  in coal-fired boiler sizes with age for the NESCAUM
              region	   2-7

Figure 2-3    Trends  in oil-/gas-fired boiler size with age for the NESCAUM
              region	   2-7

Figure 2-4    Distribution of NESCAUM boilers—number of units versus age 	   2-8

Figure 2-5    Distribution of NESCAUM boilers—total MW versus age	   2-8

Figure 2-6    Distribution of NESCAUM boilers—number of units versus
              capacity factor  	  2-10
           »
Figure 2-7    Distribution of NESCAUM boilers—total MW versus capacity
              factor	  2-10

Figure 2-8    Age distribution of coal-fired  boilers 	    2-11

Figure 2-9    Age distribution of oil- and gas-fired boilers  	    2-11

Figure 2-10   NOX emissions,  coal-fired boilers	    2-13

Figure 2-11   NOX emissions,  oil-  and gas-fired boilers  	    2-13

Figure 3-1    Conversion of fuel N in practical combustors	   3-2

Figure 3-2    Fuel effect on NOX	   3-3

Figure 3-3    Full load NOX emissions for pre-NSPS coal-fired utility  boilers  	   3-4

Figure 3-4    NOX emission levels for pre-NSPS coal units  	   3-7

Figure 3-5    NOX emission levels for oil/gas units	   3-9

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                             LIST OF FIGURES (Continued)


Figure 3-6     Distribution of NESCAUM boilers—NOX versus capacity	   3-13

Figure 4-1     NOX reduction summary of FWEC CF/SF LNB  	   4-13

Figure 4-2     Fuel effects:  XCL burner plus modified impeller  	   4-14

Figure 4-3     Estimates of combustion-controlled NOX emission levels for coal-
              fired boilers in the NESCAUM region	   4-23

Figure 4-4     NOX control effectiveness of 20 percent WFGR versus initial NOX
              level for gas and oil fuels	   4-27

Figure 4-5     Estimates of NOX  reduction from oil- and gas-fired boilers in the
              NESCAUM region	   4-33

Figure 4-6     Possible SCR configurations	   4-38

Figure 4-7     Estimates of systemwide NOX reductions with contributions from
              FGT controls on limited boiler capacity	   4-42

Figure 5-1     Components of capital cost  	   5-2

Figure 5-2     Capital levelization	  5-7

Figure 6-1     Flyash combustibles losses from parametric testing with AGFA	   6-3

Figure 6-2     Total capital requirement and busbar cost of OFA retrofit for
              wall-fired PC boilers . . '.	   6-3

Figure 6-3     Cost effectiveness  of OFA retrofit for wall-fired PC-fired boilers	   6-4

Figure 6-4     Capital cost of LNB and LNB + OFA for wall-fired PC boilers	  6-7
                                                                        •
Figure 6-5     Capital cost of LNB with CCOFA and  LNB + SOFA for T-fired
              PC boilers  	  6-7

Figure 6-6     Capitol and busbar cost of LNB retrofit for wall-fired PC boilers	  6-9

Figure 6-7     Capital and busbar cost of LNB + CCOFA retrofit for T-fired PC
              boilers  . : .	  6-9

Figure 6-8     Cost effectiveness  of LNB for wall and  tangential PC-fired boilers	  6-10

Figure 6-9     Capital and busbar cost of LNB + OFA  retrofit for wall-fired PC
              boilers  	  6-12
                                           XI

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                              LIST OF FIGURES (Continued)
Figure 6-10   Capital and busbar cost of LNB + SOFA retrofit for tangential-
              fired PC boilers 	  6-12

Figure 6-11   Cost effectiveness  of LNB + OFA retrofit for wall and tangential
              PC-fired boilers 	  6-13

Figure 6-12  • Effect of boiler age on the cost effectiveness of LNB + OFA
              systems	  6-13

Figure 6-13   Effect of capacity factor on the cost effectiveness of LNB + OFA
              systems	  6-14

Figure 6-14   Capital and busbar cost of NGR for cyclone boilers	  6-15

Figure 6-15   Cost effectiveness  of NGR for cyclone boilers	  6-15

Figure 6-16   Effect of fuel differential cost on the cost effectiveness of NGR for
              cyclone boilers 	  6-16

Figure 6-17   Capital and busbar cost of BOOS for  oil/gas wall-fired boilers  	  6-19

Figure 6-18   Cost effectiveness  of BOOS for wall and tangential oil-/gas-fired
              boilers  	  6-19

Figure 6-19   Capital and busbar cost of FGR for oil-/gas-fired boilers	  6-21

Figure 6-20   Cost effectiveness  of FGR for wall and tangential oil-/gas-fired
              boilers	  6-21

Figure 6-21   Capital and busbar cost of LNB for oil-/gas-fired boilers	  6-22

Figure 6-22   Cost effectiveness  of LNB for wall and tangential oil-/gas-fired
              boilers  	:	  6-22

Figure 6-23   Capital and busbar cost of BOOS + FGR for oil-/gas-ftred boilers  	  6-23

Figure 6-24   Cost effectiveness  of BOOS + FGR for wall and tangential oil-/gas-
              fired boilers  	  6-23

Figure 6-25   Capital and busbar cost of LNB + FGR + OFA for oil-/gas-fired
              boilers  	  6-26

Figure 6-26   Cost effectiveness  of LNB + FGR + OFA for wall and tangential
              oil-/gas-fired boilers	  6-26

Figure 6-27   Capital and busbar cost of SNCR for  coal-fired utility boilers  	  6-31
                                            XII

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                               LIST OF FIGURES (Continued)
Figure 6-28   Cost effectiveness of SNCR for uncontrolled and LNB-controlled
              wall coal-fired utility boilers	  6-31

Figure 6-29   Cost effectiveness of SNCR for uncontrolled and LNB-controlled
              tangential coal-fired utility boilers 	  6-32

Figure 6-30   Capital and busbar cost of cold-side SCR for coal-fired utility
              boilers 	  6-32

Figure 6-31   Capital and busbar cost of hot-side SCR for coal-fired utility
              boilers 	  6-33

Figure 6-32   Cost effectiveness of cold-side SCR for coal-fired utility
              boilers—effect of catalyst unit cost 	  6-33

Figure 6-33   Cost effectiveness of cold-side SCR for coal-fired utility
              boilers—effect of catalyst life  	  6-34

Figure 6-34   Capital and busbar cost of SCR for oil-/gas-fired utility boilers	  6-34

Figure 6-35   Cost effectiveness of SCR for  uncontrolled and combustion-
              controlled wall oil-/gas-fired boilers	  6-35

Figure 6-36   Cost effectiveness of SCR for  uncontrolled and combustion-
              controlled tangential oil-/gas-fired boilers  	  6-35

Figure 6-37   NOX control cost-effectiveness for PC wall-fired utility boilers	  6-37

Figure 6-38   NOX control cost-effectiveness for PC tangential-fired utility
              boilers 	  6-37

Figure 6-39   NOX control cost-effectiveness for oil/gas wall-fired utility boilers	  6-38

Figure 6-40   NOX control cost-effectiveness for oil/gas tangential-fired utility
              boilers 	  6-38

Figure 7-1    NOX and  CO emissions at full load, Edgewater Unit 4	   7-5

Figure 7-2    CO versus NOX, 600 MWe wall-fired boiler with OFA, firing
              German brown coal  	  7-5

Figure 7-3    CO versus NOX, NEI-ICL, 500 MWe wall-fired boiler with/without
              LNB	  7-6

Figure 7-4    NOX versus UBC, wall-fired boiler with LNB	  7-9

Figure 7-5    CO versus NOX, natural gas-fired boilers	  7-12
                                             VIII

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                            LIST OF FIGURES (Concluded)


Figure 7-6    Pre- and post-retrofit CO emissions versus excess O2—SCE
             Ormond Beach Unit 2	  7-14

Figure 7-7    Pre- and post-retrofit CO emissions versus excess O2—SCE
             Alamitos Unit 6	  7-15

Figure 7-8    NOX versus CO emissions—oil-fired boilers  	  7-19

Figure 7-9    Historical summary of Kane 6 NOX and opacity	  7-21
                                          xiv

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                                     LIST OF TABLES
Table 1-1

Table 1-2

Table 1-3

Table 1-4


Table 1-5


Table 2-1


Table 3-1

Table 3-2


Table 3-3


Table 3-4


Table 4-1

Table 4-2


Table 4-3

Table 4-4


Table 4-5


Table 4-6


Table 4-7

Table 4-8

Table 4-9
Combustion controls for coal-fired utility boilers 	   1-5

Combustion controls for oil- and gas-fired utility boilers  	   1-8

Flue gas treatment controls  	   1-10
Summary of NOX control costs for coal-fired utility boilers (1st Qtr
$1991)  	
                                                                         1-12
Summary of NOX control costs for oil- and gas-fired utility boilers
(1st Qtr $1991)	    1-15

NESCAUM boiler inventory by firing type and fuel:  number of
units	   2-2

NOX emission factors—coal-fired boilers in the NESCAUM region  	   3-5

NOX emission factors—oil-/gas-fired boilers in the NESCAUM
region	   3-8


                                                                  	  3-10
Average NOX emission factors for utility boilers in the NESCAUM
region	
Range and average baseline NOX levels for Pre- and Post-NSPS
utility boilers in the NESCAUM region	 3-11

Combustion controls for coal-fired utility boilers  	   4-4

Estimates for average controlled levels for pre-NSPS NESCAUM
coat-fired boilers   	   4-6

Partial list and performance of wall PC-fired LNB applications	   4-11

Partial list and performance of coal-fired LNB+SOFA applications
on tangential boilers	   4-15

Partial list and performance of coal-fired LNB + OFA applications
on wall-fired boilers	   4-17

Estimates of retrofit  NOX reduction potential for pre-NSPS coal-
fired boilers in the NESCAUM region	   4-20

Combustion controls for oil- and gas-fired  utility boilers  	   4-25

Partial list of gas- and oil-fired low-NOx burner applications	 4-29

Estimates of retrofit  NOX reduction potential for oil- and gas-fired
boilers in the NESCAUM region	   4-31
                                            xv

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                              LIST OF TABLES (Continued)


Table 4-10    Flue gas treatment controls  	 4-40

Table 4-11    Processes under consideration for combined NOX/SOX control 	   4-43

Table 4-12    Combined NOX/SOX control technologies being evaluated under
              the CCT program    	 4-44

Table 5-1     Unit costs	  5-6

Table 5-2     Cost assumptions	  5-8

Table 5-3     Cost cases for coal-fired boilers	   5-10

Table 5-4     Cost cases for gas- and oil-fired boilers  	   5-11

Table 5-5     Parametric variations for coal-fired boiler cost cases  	   5-12

Table 5-6     Parametric variations for gas- and oil-fired boiler cost cases  	   5-13

Table 6-1     Recent LNB and OFA installed costs for PC-fired boilers	  6-6

Table 6-2     Retrofit material costs	  6-8

Table 6-3     Summary of Riley's economic evaluation for LNB	  6-8

Table 6-4     Summary of NOX combustion control costs for coal-fired utility
              boilers (1st Qtr $1991)	 6-17

Table 6-5     Summary of combustion modification NOX control costs for oil-
              and gas-fired utility boilers (1st Qtr $1991)  	 6-27

Table 6-6     Summary of flue gas treatment NOX control costs for coal-fired
              utility boilers (1st Qtr $1991)	 6-28

Table 6-7     Summary of flue gas treatment NOX control costs for gas- and oil-
              fired utility boilers  (1st Qtr $ 1991)	 6-29

Table 7-1     Sample of baseline/controlled CO and UBC data, wall-fired PC
              boilers  	  7-3

Table 7-2     Summary of baseline/controlled CO and UBC data, tangential-
              fired PC boilers 	  7-4

Table 7-3     Summary of baseline/controlled CO and UBC data, coal-fired
              cyclone and turbo furnace boilers	  7-4

Table 7-4     NOX reduction at various CO emission levels, selected coal-fired
              boilers  	 7-8

                                            xvi

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                              LIST OF TABLES (Concluded)
Table 7-5      NOX reduction at various UBC levels for coal-fired boilers at full
              load 	 7-10

Table 7-6      Summary of CO data for natural gas-fired boilers  	 7-13

Table 7-7      NOX reduction at various CO emission levels, selected natural gas-
              fired boilers 	 7-16

Table 7-8      Summary of CO data for oil-fired boilers	 7-18

Table 7-9      NOX reduction at various CO emission levels, selected oil-fired
              boilers 	 7-20

Table 7-10    Summary of total hydrocarbon (THC) emission data	 7-22

Table 7-11    Summary of NOX reduction levels achieved when low-NOx
              CO = baseline (uncontrolled)  CO	 7-24

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LIST OF ABBREVIATIONS
ABB Asea Brown Boveri. Major supplier of powerplant steam generators and gas turbines
and the only supplier of tangential-fired boilers and retrofit control equipment.

ACT Alternative Control Techniques. Documents are prepared by the EPA under
requirements of 1990 CAAA.

AFDC Allowance for funds during construction. Cost element of EPRI TAG and EPA's
IAPCS.

AFS Axial Fuel Staged. Gas/oil-fired low-NOx burner offered by Riley.

AOFA Advanced Overfire Air. The technique of introducing secondary air by separate air
ports above the burner windbox. Designed for high velocity and effective mixing.

APS Arizona Public Service

ASR Axial Staged Return. Gas/oil-fired low-NOx burner offered by Riley.

B&W Babcock and Wilcox, a McDermott Company. Major supplier of wall- and opposed-
fired utility boilers and low-NOx combustion equipment. Manufactured the now-
discontinued cyclone boilers.

BHK Babcock Hitachi K.K. Developer of low-NOx burner and flue gas treatment
technologies.

BOOS Burners out of service. The technique of terminating fuel flow to selected burners
while increasing fuel flow to remaining burners to create a staged combustion effect
that reduces NOX.

BWE Burmeister and Wain Energy. A European low-NOx burner developer.

BZHRR Burner zone heat release rate. A boiler design parameter and an important factor
in establishing the uncontrolled level of NOX and the potential for retrofit of
combustion modification controls. Also known as burner zone liberation rate
(BZLR).

CAA The Clean Air Act of 1977.

CAAA Clean Air Act Amendments of 1990.

CAT-AH Selective Catalytic Reduction Air Heater. Selective catalytic system developed by
KAH of Germany.

CCOFA Close-Coupled Overfire Air. OFA for tangential (corner-fired) boilers that is
introduced immediately above the top level of fuel nozzles and is part of the same
burner windbox.
xix

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CCT Clean CoaJ Technology. The national program funded by DOE, industry, and
technology vendors to demonstrate new technologies to reduce NOX and SO2
emissions from power plants.

CCTFS Concentric clustered tangential firing system. A low-NOx burner design for tangential
boilers that uses two levels of OFA and deeply staged combustion. Patented and
used by ABB-CE (not commercially offered).

CCV Controlled Combustion Venturi. A low-NOx burner developed and used by Riley
Stoker.

CE Combustion Engineering. Now part of Asea Brown Boveri (ABB), the only supplier
of tangential (corner)-fired boilers and controls for these units.

CEGB Central Electricity Generating Board of the U.K.

CEM Continuous emission monitors

CETF Combustion and Environment Test Facility. The pilot-scale research combustion
facility used by FWEC for the development of low-NOx burners.

CF/SF Controlled flow/Split flame. A low-NOx burner developed and used by FWEC.

DOE U.S. Department of Energy

DP&L Dayton Power and Light Company

DRB-XCL® Duel Register Burner—Type XCL. Sixth generation axial control, low-NOx enhanced
staged combustion burner developed and used by B&W.

EERC Energy and Environmental Research Corporation, Irvine, California

EHOF Engineering and Home Office Overhead and Fee. Cost element of EPRI TAG and
EPA's IAPCS.

EIA Energy Information Administration of the U.S. Department of Energy. Agency that
documents fuel use of the electric utilities.

ENEL Ente Nationale Energia Electrica, the Italian National Electric Utility

EPA U.S. Environmental Protection Agency

EPDC Electric Power Development Company of Japan

EPRI Electric Power Research Institute, Palo Alto, California

ESEERCO Empire State Electric Energy Research Corporation

FGD Flue Gas Desulfurization. A variety of gas treatment technologies to scrub sulfur
using wet or dry systems.
xx

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FGET Flue Gas Exit Temperature. An important indicator of heat release and absorption
in the furnace.

FOR Flue gas recirculation. The technique of recirculating a fraction of the flue gas to the
burners to reduce peak flame temperature and oxygen availability with vitiated (flue
gas diluted) air for NOX reduction. FOR can also be used for steam temperature
control when introduced through furnace hopper.

FGT Flue gas treatment. Controls that scrub or chemically destroy NOX from the flue gas
after it is already formed.

FR Fuel ratio. The ratio of fixed carbon to volatile matter content of coals. Used as an
indication of coal reactivity and rank. Also an indicator of NOX reduction potential
with combustion modifications.

FWEC Foster-Wheeler Energy Corporation. Major supplier of face-fired utility boilers and
low-NOx combustion burners.

GF General Facilities. Cost element of EPRI TAG and EPA's IAPCS.

GPC Gulf of Power Company

GR Gas reburn. A technology that uses natural gas to reduce NOX primarily in coal-fired
boilers (also referred to as natural gas reburning, NGR). Developed and marketed
by Energy and Environmental Research Corporation.

GRI Gas Research Institute, Chicago, Illinois

GR-SI Gas Reburn and Sorbent Injection. A technology that combines NOX and SO2
control techniques.

HT-NR Hitachi NOX Reduction. A low-NOx burner developed and used by BHK.

HZC Hitachi Zosen Corporation. Developer and seller of NOX reduction catalysts.

IAPCS Integrated Air Pollution Control System. EPA's cost algorithm to determine new and
retrofit costs of air pollution control at power plants.

IFNR In-furnace NOX reduction. A staged fuel combustion technique offered by B&W and
Babcock Hitachi K.K.

IFS Internal fuel staging. A modification to the FWEC CF/SF low-NOx burner for
further reduction in NOX.

IHI Ishikawajima Harima Heavy Industries. Developer and seller of NOX reduction
catalysts.

KHI Kawasaki Heavy Industry. Developer and seller of NOX reduction catalysts.

KP&L Kansas Power and Light Company
xxi

-------
LADWP Los Angeles Department of Water and Power

LEA Low excess air. Operation of boiler with minimal excess combustion air to optimize
thermal efficiency and reduce NOX formation.

LIMB Limestone Injection Multistage Burner. A low-NOx burner using staged air with
limestone addition in the furnace for SO2 reduction.

LNB Low-NOx burner. Burner and windbox assemblies designed to minimize the
formation of NOX by various techniques such as separated fuel jets, flue gas
recirculation (FOR), and controlled air mixing. LNB designs for T-firing incorporate
close-coupled OFA as part of the LNB design.

LNCB Low-NOx Cell Burner. A burner designed by B&W in cooperation with the Electric
Power Research Institute (EPRI) for retrofit applications on existing opposed wall-
fired cell boilers.

LNCFS Low-NOx concentric firing system. A burner modification applicable to tangential
boilers to divert some of the combustion air along the waterwalls for the reduction
of NOX. Three separate configurations of LNCFS are available. Two configurations
use separate overfire air. Patented and used by ABB-CE.

LNS Low NOX and SOX. A process marketed by TransAlta Resources Investment Corp.
for the combined reduction of NOX and SO2.

MACT Mitsubishi Advanced Combustion Technology. A staged fuel combustion technique
developed by MHI for in-furnace NOX reduction.

MHI Mitsubishi Heavy Industries. Developer of low-NOx burner technologies for
tangential boilers and FGT techniques.

MP Monongahele Power Company

NAAQS National Ambient Air Quality Standards

NESCAUM Northeast States for Coordinated Air Use Management, Boston, Massachusetts

NGR Natural gas reburning. A technology that uses natural gas to reduce NOX primarily
in coal-fired boilers (also referred to simply as GR or gas reburn).

NOXSO A process for combined reduction of NOX and SO2. Developed and marketed by
NOXSO Inc.

NOxOUT The trade name for the urea-based SNCR process developed by the EPRI and
marketed by Nalco-Fuel Tech.

NSPS New Source Performance Standards. Emissions standards promulgated by the U.S.
Environmental Protection Agency. Typically are not technology-forcing standards.

NSR Normalized stoichiometric ratio. Actual mole ratio of urea to NOX divided by the
theoretical stoichiometric ratio, which is 0.5 for the reaction between urea and NOX.

xxii

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NURF National Utility Reference File. A U.S. Environmental Protection Agency file that
documents several statistical factors for the electric utilities including reported NOX
emission levels.

NYPP New York Power Pool, Schenectady, New York

OAQPS Office of Air Quality Planning and Standards, EPA, Research Triangle Park, North
Carolina.

OFA Overfire air. The technique of injecting separated combustion air above the main
burner zone to produce staged combustion that reduces NOX. Sometimes also called
AGFA for wall-fired units.

OS Off Stoichiometric. The combustion techniques such as BOOS and OFA that rely on
reducing first stage stoichiometry to stage combustion and reduce NOX generation.

PC Pulverized coal. Most coal-fired utility boilers in the NESCAUM region are
pulverized coal-fired boilers.

PENELEC Pennsylvania Electric Company

PETC Pittsburgh Energy Technology Center. Combustion research laboratory for DOE.

PG&E Pacific Gas and Electric Company, San Francisco, California

PG-DRB Primary Gas-Dual Register Burner. A low-NOx burner for gas/oil boilers developed
by B&W and BHK.

PM Pollution Minimum. A low-NOx burner developed by MHI for application on
tangential boilers. Burner uses staging and FGR.
%

PSC Public Service of Colorado

PSI Public Service of Indiana

PSNM Public Services of New Mexico

RACT Reasonably available control technology. Required by §172 of the 1990 CAAA
(Ozone Nonattainment Plan Provisions) on existing major sources in nonattainment
areas. The lowest emission limit that a particular source is capable of meeting by the
application of control technology that is reasonably available considering technological
and economic feasibility.

RAP Reduced air preheat. The technique of bypassing a fraction of the combustion air
around the air preheater to reduce the peak flame temperature thus reducing NOX.

SCAQMD South Coast Air Quality Management District

SCE Southern California Edison Company
XXlll

-------
SCR Selective catalytic reduction. The injection of chemical reagents in the flue gas for
the selective reduction of NOX to nitrogen and water.

SCS Southern Company Services

SGR Separate gas recirculation. A low-NOx burner technique developed by MHI.

SNCR Selective noncatalytic reduction. The injection of a chemical reagent at high flue gas
temperatures to selectively reduce NOX to nitrogen and water. Unlike SCR, the
process does not use a catalyst.

SNRB SOxNOxROxBox. A process developed by B&W that uses a hot catalytic baghouse
for the combined reduction of NOX, SOX and flyash.

SOFA Separate Overfire Air. A combustion technique that brings up to 25 percent of the
total air entering a boiler furnace at a sufficient distance above the main burner zone
to promote decay of fuel nitrogen to N2 under reducing combustion conditions.

STS Swirl Tertiary Separation. A low-NOx burner for gas/oil-fired boilers developed by
Riley Stoker and Deutsche Babcock.

TAG Technical Assessment Guide. EPRI's guidelines for estimating the cost of power
plant equipment.

TCR Total capital required. Includes all capital necessary to complete the entire project.

TPC Taiwan Power Company

TPC Total plant cost. The cost of all purchased, fabricated, and installed equipment at
power plants.

TPI Total plant investment. Includes the escalation of construction cost and AFDC.

TSC Two-stage combustion. A generalized term to categorize several techniques such as
biased firing, BOOS, and OFA that stage combustion of fuel to reduce NOX.

TSV Tertiary Staged Venturi. Low NOX burner developed and offered by Riley for turbo
furnaces.

TVA Tennessee Valley Authority

UARG Utility Air Regulatory Group, a voluntary, nonprofit, ad hoc group representing
70 electric utility companies including utilities throughout NESCAUM, the Edison
Electric Institute, the National Rural Electric Cooperative Association, and the
American Public Power Association.

UBC Unburned carbon content. The content of unburned carbon in the flyash of utility
boilers. An indicator of loss in combustion efficiency.
xxiv

-------
WACF       Weighted average capacity factor; calculated as follows:


                                           T CFt MW,
                                  WACF
             when:

             CFj is the capacity factor for individual boilers and MW; is the size of individual
             boilers.
WFGR       Windbox flue gas recirculation.  A distinction made to separate the recirculation of
             gas to the burners versus recirculation of gas to the bottom hopper for flue  gas
             tempering.

WI          Water injection. The technique of injecting water or water/fuel emulsions to reduce
             the peak flame temperature thus reducing NOX. Not a common control strategy for
             boilers. Generally" used for gas turbines.

WSA-SNOX  A combined catalytic NOX/SOX control technology developed by Haldor Topsoe and
             marketed by ABB Flakt, Inc.
                                          xxv

-------

-------
                                       SECTION 1

                                 EXECUTIVE SUMMARY
       The  Northeast  States for Coordinated Air Use Management (NESCAUM)  requested
assistance from the EPA's Control Technology Center in the Office of Air Quality Planning and
Standards (OAQPS), in the development of a technical support document discussing the  feasibility,
performance, and costs of retrofit nitrogen oxides (NOX) controls for utility boilers operating in the
eight Northeast states that comprise the NESCAUM region. These states include Connecticut,
Maine, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont.

       Section 182 of the Clean Air Act Amendments of 1990 requires that the NESCAUM states
develop Reasonably Available Control Technology (RACT) standards for utility boilers and other
NOX sources. EPA's Office of Air Quality Planning and Standards is developing Alternative Control
Technique (ACT) documents for stationary source categories that emit or have the potential to emit
25 tons/yr or more of NOX. The ACT documents are  required under Section 183(c) of Subpart 2
to Part D of Title I of the Clean Air Act Amendments of 1990.  The findings presented in this
report are intended to assist the NESCAUM states in assessing the potential and costs of NOX
RACT reductions from the existing utility boiler inventory in the NESCAUM region, and will assist
the EPA in the preparation of the ACT document for NOX controls  from  utility boilers.

       The principal objectives of this report are to:

       •   Examine  the  population profile of the  utility boilers in the  NESCAUM  region to
           segregate existing boilers according to NOX retrofit potential

       •   Evaluate the commercially available controls and the reductions in NOX achievable by
           each technology, including technical feasibility and emission limits

       •   Estimate  the  retrofit cost  and  cost effectiveness  of  these controls,  considering
           site-specific factors and systemwide control applications to the extent possible

       •   Summarize the impact of NOX reduction on other emissions (CO, HC, and carbon in
           the flyash), and estimate changes in these  emissions resulting  from the retrofitting of
           combustion controls

       This report contains six sections that discuss:

       •   Utility  boiler  population profile  and  current  estimates of  total  NOX  emissions
           (Section 2)

       •   Uncontrolled NOX emissions as a function of boiler design, fuel, and  age (Section  3)

       •   NOX control technologies available for coal- and oil-/gas-fired  boilers (Section 4)

                                           1-1

-------
• Cost methodology for estimating the costs of 36 scenarios for NOX control (Section 5)

• Cost and cost effectiveness of controls as a function of several design and operating
characteristics of boilers (Section 6)

• Effect of NOX controls on emissions of CO, HC, and carbon in the flyash (Section 7)

This report uses current NOX levels to estimate the potential NOX reductions for individual
families of boilers throughout the NESCAUM region. Appendices A and B list the NESCAUM
boiler inventories for coal- and oil-/gas-fired boilers, respectively. Appendix C presents schematics
of NOX control technologies discussed in Section 4. Appendix D lists the NOX reduction
performances reported in the literature used to estimate the reduction potential for the NESCAUM
boiler population. Appendix E lists current and planned selective catalytic reduction (SCR)
installations worldwide. Appendices F and G provide the detailed cost analyses for the 36 retrofit
cases evaluated in this study.

Because the applicability, ease of retrofit, NOX reduction performance, and cost are very
much influenced by site-specific factors that cannot be taken fully into account without a site-by-site
retrofit analysis, results and conclusions presented in this report should be interpreted on the basis
of the NOX retrofit experience reported to date. Regardless of the commercialization status of
controls, site-specific analyses are recommended to ascertain whether the emission levels, percent
NOX reductions, and costs cited in this report can be achieved on a long-term basis by a given site.
Site-specific factors that influence NOX reductions and control targets, such as important boiler
design, operation, and fuel characteristics, are highlighted and general trends discussed.

In the Northeast, approximately 40 percent of the total annual NOX emissions are from
stationary sources and the remaining 60 percent are from mobile sources. NOX emissions adversely
affect human health and the environment. NOX emissions chemically react with other pollutants
to form ozone; nitrogen dioxide; gaseous and particulate acids, including nitric acid; and other
pollutants. In 1987, NOX emissions from all sources in the NESCAUM region totaled approximately
1.6 million tons. Utility NOX emissions in the NESCAUM region represent over 20 percent of the
inventory, totalling about 380,000 tons. Figure 1-1 illustrates the contribution of major boiler design
types to the total NOX emitted in 1987 from all utility boilers in the NESCAUM region. The data
show that the major emitters of NOX emissions are wall and opposed gas-/oil-fired boilers, which
contribute 24 percent of the total emissions, followed by wall and opposed pulverized coal
(PC)-fired (21 percent), tangential oil-/gas-fired (20 percent), wet-bottom boilers (nearly
18 percent), and tangential PC-fired boilers (14 percent). Although fewer in number, coal-fired
slagging furnaces, which include cyclone and wet-bottom wall-fired boilers, contribute nearly as much
as other major design types. The combined NOX output of other boiler designs, including stokers
and small oU-/gas-fired units, contributes only about 3 percent of the total NOX emitted by utilities
in the region.

In examining the region by capacity in MWe, PC-fired boilers account for about 20 percent
of the total capacity in the NESCAUM region. Among PC units, tangential- or corner-fired designs
account for about 43 percent of the capacity, followed by opposed-firing (27 percent), and single
wall-firing, including vertical or down-fired units, (30 percent). Many of the combustion controls
developed for wall-fired boilers are equally applicable to single or opposed wall-fired boilers.

The two major routes of NOX formation are the high-temperature oxidation of nitrogen in
the combustion air (thermal NOX), and the conversion of fuel-bound nitrogen (fuel NOX). When
fuel is burned in utility boilers, both thermal and fuel NOX are a function of fuel properties and

1-2

-------
many boiler design and operating variables. Among the most influential variables are the fuel
nitrogen content, the excess air, the heat release rate per unit of waterwall area in the burner zone,
the amount of air preheat, and the burner spacing and stoichiometry. When pulverized coal is
burned, the fuel ratio (FR, fixed carbon divided by volatile matter) and oxygen/fuel nitrogen ratio
also influence the uncontrolled emissions and NOX levels achievable with combustion controls.
Typically, the more volatile the coal (lower FR), the greater the potential for large NOX reductions
and lower controlled levels. Therefore, high-volatile bituminous coals and western subbituminous
coals will show greater reduction efficiencies and lower NOX levels with combustion modifications.
This is due in part to the ability to apply greater degrees of combustion control without incurring
unacceptable losses in combustion and thermal efficiencies. Similarly, low-nitrogen fuels such as
light oils and clean-burning natural gas, offer the potential for the lowest NOX levels because control
is limited to reducing thermal-NOx.

Combustion modification technologies are the principal methods for controlling NOX from
existing and new utility boilers. The retrofit feasibility, NOX reduction performance, and costs of
combustion controls are largely influenced by boiler design and operating characteristics such as the
firing configuration, the furnace size and heat release rate, the type of fuel used, the boiler capacity
factor, and the condition of existing equipment. Many of these factors vary with the age of the unit.
Flue gas treatment (FGT) controls, including catalytic and noncatalytic processes, can provide
additional NOX reductions from combustion-controlled levels or can be used without combustion
modifications. The retrofit feasibility and cost of FGT controls are often influenced by the fuel
type, the capacity factor, the load dispatch profile, and several site-specific factors, including site
access and space availability.

Table 1-1 summarizes NOX reduction performance, application, and anticipated equipment
modifications for retrofit NOX combustion modification controls for pre-New Source Performance
Standard (NSPS) and post-NSPS coal-fired utility boilers. The achievable percent NOX reductions
listed in the table reflect performance levels reported in the literature. These reduction efficiencies
were applied to baseline NOX ranges from the various boiler designs. Larger percent NOX
reductions generally apply to boilers with higher baseline NOX levels, plants burning coals that have
low-NOx properties with combustion staging (e.g., high volatile content), and short-term duration
tests under favorable boiler operating conditions. Table 1-1 shows that overfire air (OFA), low-NOx
burner (LNB), LNB + OFA, and reburning are candidate combustion modification controls for
retrofitting existing coal-fired boilers. The bulk of the retrofit experience to date is limited to LNB
only, however. For wall-fired boilers (both single wall- and opposed-fired units), LNBs are generally
installed without OFA because the retrofit of OFA involves added expenses and the potential for
adverse impacts on the operation and efficiency of the boiler. Current domestic experience with
LNB + OFA for wall-fired PC boilers is minimal. Although few foreign installations have reported
attractive short-term results, one ongoing demonstration in the U.S. indicates minimal added benefit
of OFA to overall NOX reduction accompanied by a significant fuel penalty. Whereas combustion
efficiency loss is likely with LNB alone, a larger efficiency loss is a certainty when OFA is used in
conjunction with LNB.

For tangential boilers, separate OFA (SOFA) is the most effective feature, in terms of NOX
reduction, of advanced tangential firing systems. However, experience with retrofit of LNB with
SOFA for tangential coal-fired boilers is currently limited to a few installations with NOX reduction
levels on the order of 40 percent to levels below 0.45 Ib/MMBtu, measured on a long-term basis
(continuously over a period of 30 days or longer). Natural gas reburning (NGR) is an effective
combustion option for all coal-firing boiler types, including cyclones, and can result in 45- to
60-percent NOX reductions. The technical and economic feasibilities of NGR are currently under
study at four full-scale demonstrations sponsored by DOE, GRI, EPRI, and host utilities.

1-4

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Reburning using pulverized coal is also under study for cyclone boilers, and shows initially promising
results. These reburn technologies offer the potential for use in commercial applications in the near
future.

Ranges in control efficiency and NOX control levels, rather than specific numbers, are given
for each of the retrofit cases evaluated in this study. The ranges indicate several important points
that require explanation. First, there is a degree of uncertainty in the actual performance that can
be obtained at each power plant site. This uncertainty can be narrowed only with detailed analyses
of several site-specific factors. Therefore, when considering a broad family of boilers, it is more
appropriate to provide a range in performance rather than a fixed value. Second, these results are
based on performances reported to date for several retrofits. Data obtained from more than one
retrofit also indicate a range in performance indicative of variations in actual NOX reduction
efficiency and control level that can be achieved from site to site. Third, lower NOX reduction
efficiencies and higher NOX emission levels reflect results that can be anticipated under more trying
control conditions. These conditions include high initial uncontrolled NOX, low coal fineness,
combustion of low-volatile eastern coal, operational difficulties, and compliance with emissions
averaged over a long-term period (e.g., 30 days) to account for routine variations in key operational
parameters that affect NOX. Conversely, the higher reduction efficiency and lowest NOX reflect the
best performance reported to date, excluding results of some retrofits that are not considered
commercial for widespread application in NESCAUM and exclusive of selected vendor claims. As
discussed later, this higher performance is generally associated with volatile coals and short-term
results obtained at selected boiler loads under well-controlled conditions, and over a period of time
not exceeding a few hours of continuous monitoring.

The NESCAUM population of PC-fired boilers includes only one post-NSPS Subpart Da
unit whose reported level of NOX is 0.55 Ib/MMBtu. The retrofit of newer vintage LNBs without
OFA ports on this unit is projected to, at best, reduce NOX to 0.40 to 0.45 Ib/MMBtu, based on
limited data collected with two retrofits on a short-term basis. Coupled with OFA, controlled NOX
levels are estimated to be slightly lower. However, no supporting documentation on similar
LNB+OFA retrofits is available.

Approximately 50 percent of the current pre-NSPS dry-bottom wall-fired capacity in
NESCAUM has an average NOX level of about 0.95 Ib/MMBtu. The retrofit of LNB to most of
these boilers will reduce the average NOX level to a range of about 0.45 to 0.60 Ib/MMBtu. This
level of control corresponds to a reduction of 35 to 55 percent (rounded to the nearest 5 percent)
from the average baseline level and is supported by results from several retrofits monitored on
short- and long-term bases. Lower emitting units will show lower reduction efficiencies because
combustion modification is limited to a minimum level of NOX that can be achieved at a given site
without incurring major operational and energy penalties. For those wall-fired boilers that can be
retrofitted and operated with OFA in addition to LNB, controlled NOX levels are estimated to
range from 0.35 to 0.55 Ib/MMBtu (40- to 65-percent reduction). Again, the higher NOX level
(0.55 Ib/MMBtu) is representative of retrofit cases and operating conditions that are considered
more prevalent in the NESCAUM region (e.g., low-volatile coals and pre-NSPS). A much smaller
number of utility boilers are considered retrofittable with OFA or advanced overfire air (AOFA)
without significantly affecting efficiency, operation, and reliability. This is because many of these
boilers have small pre-NSPS furnaces that do not provide the access or gas residence time needed
for safe and effective operation. OFA, alone or in combination with LNB, is only as effective as
the degree of air staging used. This is limited by the adverse effects of excessive staging on
waterwall slagging corrosion and loss on ignition (LOI) that are considered more likely with
compact furnace designs burning high-sulfur coals.
1-6

-------
These estimates of NOX reduction, together with estimates of retrofit potential to the
existing population, can be used to estimate the total NOX reduction potential for these technologies
on a systemwide basis. For example, widespread retrofit of LNB is estimated to result in NOX
reductions between 29,000 and 42,000 tons/yr with a target coal-fired retrofit capacity of about
5,800 MWe. Application of other technologies currently under development and demonstration on
cyclone and wet-bottom boilers, such as reburning, can achieve additional systemwide NOX
reductions. Consider, for example, the combination of 5,800 MWe of LNB retrofit on existing dry-
bottom units with 1,200 MWe of reburn retrofit on existing wet-bottom units (including cyclones).
This combination is estimated to remove about 50,000 to 70,000 tons/yr of NOX from current
NESCAUM-wide coal-fired levels of about 200,000 tons/yr. These estimates are calculated based
on broad assumptions of retrofit feasibility using estimates of current emission levels and projected
NOX reduction efficiencies. Because of the uncertainties involved, actual reductions may be higher
or lower.

Combustion modifications in full-scale, oil-, and gas-fired utility boilers can result in
significant NOX reductions. Ninety percent reductions have been achieved from very high
uncontrolled levels on some units in California. Table 1-2 summarizes the performance and
hardware modifications for applicable NOX combustion controls for oil-/gas-fired boilers in the
NESCAUM region. Combustion modification controls for oil-/gas-fired boilers have been
implemented since the early 1970s, primarily in California. Past retrofit efforts in California can
provide a wealth of technology and retrofit experience that is directly applicable to the NESCAUM
oil-/gas-fired units. Although NOX reduction successes similar to those of the California utilities
cannot be guaranteed (fuel oil properties are different, for example), significant reductions in NOX
are possible. Important fuel differences include the use of high-grade low-nitrogen fuel oil in
California, and a heavier reliance on natural gas. In NESCAUM, heavier crudes with higher
nitrogen, ash, and sulfur content are used, and there is a greater reliance on fuel oil rather than
natural gas.

Commercially available controls for oil-/gas-fired boilers include burners out of service
(BOOS), flue gas recirculation (FOR), LNB, and a combination of these. Reburning for these
boiler types has not received wide scrutiny, and is not considered either commercially available or
sufficiently demonstrated to be a near-term option. As stated, experience with these combustion
controls is substantial considering existing retrofits in California, Texas, and New York. A
combination of BOOS + FOR is anticipated to reduce NOX levels to at least 0.30 Ib/MMBtu, for
wall-fired units, and 0.20 Ib/MMBtu, for tangential units, from average baseline levels of
0.45 Ib/MMBtu and 0.30 Ib/MMBtu for all wall and tangential units, respectively. Lower NOX
levels are possible, depending on the type of fuel or fuel mix used and the success of recently
introduced LNB technology.

The 1987 NOX emission inventory from oil-/gas-fired utility boilers was 176,000 tons/yr. To
estimate NESCAUM-wide NOX reductions from these boilers using combustion controls, two
control scenarios were evaluated. The first considered an NOX limit of 0.3 Ib/MMBtu for all
dry-bottom tangential-, wall-, and opposed-fired boilers. NOX emissions would be reduced by
30,000 tons/yr under this scenario. NOX reductions would occur primarily from wall-fired boilers
whose baseline emissions currently exceed 0.3 Ib/MMBtu. A more stringent control limit of
0.2 Ib/MMBtu for all dry-bottom units, regardless of fuel mix, would result in NOX reductions of
50,000 to 60,000 tons/yr throughout NESCAUM.

Commercially available technologies for the control of NOX after it is formed in the
combustion process are currently limited to the selective noncatalytic reduction (SNCR) and SCR.
Both of these processes have seen very limited application in the United States for utility boilers.

1-7

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However, SCR is being used extensively in Japan and Germany with reported successes with all
fuels; and SNCR claims 44 boiler retrofits worldwide on all fuels, as of this writing. Most SCR
applications to PC-fired boilers must consider the sulfur content of coal to minimize SO2 to SO3
conversion over the catalyst. This is especially important for hot-side applications of SCR systems.
Recent applications of SCR catalysts in Europe and Japan have been on high-sulfur coals, with the
catalysts installed upstream of flyash and sulfur scrubbing (hot-side), indicative of advances in
catalyst formulations that minimize SO2 to SO3 conversion while resisting abrasion and plugging.
The SCR process has been investigated for coal-fired boiler retrofits in a few pilot- and full-scale
utility boiler programs sponsored by the Electric Power Research Institute (EPRI), the U.S.
Environmental Protection Agency (EPA), and selected utilities.

The SNCR process has been used with moderate to high success primarily on smaller
industrial combustion sources,'fluidized-bed combustors in California, and two PC-fired boilers also
in California. There are also ongoing demonstrations at utilities in the states of New York,
Colorado, and California. Renewed regulatory efforts to attain ozone air quality standards in
southern California's Los Angeles Basin are leading to several demonstrations of both SNCR and
SCR commercial equipment. For example, Southern California Edison (SCE) has planned a total
of 5,000 MWe retrofits with SNCR (urea-based). Many of these retrofits are already in place.
Several Japanese SCR vendors are offering this technology in the U.S. SCR retrofit projects have
begun for SCE and some U.S. gas turbine cogeneration facilities. At least four vendors are offering
urea- or ammonia-based SNCR processes for combustion sources including utility boilers.

Table 1-3 lists estimates of NOX reduction and achievable NOX levels with FGT controls on
NESCAUM boilers. These estimates are based on retrofits on currently uncontrolled boilers
(Case 1) and on boilers already controlled with combustion modifications (Case 2). Control
efficiencies for SNCR range between 25 and 50 percent. For SCR, control efficiencies are
estimated to range between 60 and 85 percent depending on application, fuel, and inlet NOX
concentration. Generally, lower performance is anticipated with lower inlet concentration, and, in
the case of SCR, when the catalyst is installed in a more severe flue gas environment.

NOX levels achievable with the application of SNCR on combustion-controlled coal-fired
boilers range from 0.35 to 0.45 Ib/MMBtu, for wall-fired units equipped with LNB, and from 0.25 to
0.35 Ib/MMBtu, for T-fired boilers also equipped with LNB + close-coupled overfire air (CCOFA).
For oil-/gas-fired boilers, corresponding NOX levels range from 0.20 to 0.25 Ib/MMBtu, for
wall-fired units, and from 0.10 to 0.15 Ib/MMBtu, for T-fired boilers. NOX levels achievable with
the application of hot-side SCR to combustion-controlled boilers are as low as 0.10 to
0.20 Ib/MMBtu, for coal units, and 0.05 to 0.10 Ib/MMBtu, for oil-/gas-fired boilers. Limited
application of SNCR technology could result in an additional 8,000 tons of NOX reductions per year
from coal units already equipped with LNB controls, and 14,000 tons/yr from oil-/gas-fired units
equipped with TSC (BOOS or OFA) controls plus FGR capable of reducing NOX to
0.25 Ib/MMBtu. Limited application of SCR technology could result in an additional 23,000 tons/yr
of NOX reduction from LNB-controlled coal units, and 25,000 tons/yr from combustion-controlled
oil-/gas-fired units. These numbers are based on limited FGT retrofit on boilers that use fuels with
a sulfur content of less than 1.5 percent and an estimate of 50-percent applicability of FGT controls
to this target capacity.

The costs of controlling NOX emissions presented in this report are based on cost data
reported in the literature for similar retrofit cases or, when available, on estimates obtained directly
from technology vendors and users. However, actual retrofit costs will depend on several site-
specific factors, and a given technology may not be relevant for all boilers. Therefore, the costs
presented should not be interpreted as applicable to any specific power plant within the NESCAUM

1-9

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utility boiler population. By evaluating several cases based on boiler size, age, capacity factor, and
NOX reduction efficiency, ranges in NOX control costs were developed that encompass some of the
uncertainties due to site-specific factors.  To develop actual cost estimates for specific power plants,
it is necessary to perform a detailed analysis of the type and condition of the existing equipment,
its layout, the fuel type, and the boiler operating characteristics.

       A simplified cost estimating procedure was developed is this study.  The procedure contains
all the principal cost elements of the EPA's Integrated Air Pollution Control System (IAPCS).  The
IAPCS was developed by the  EPA's Air and Energy Engineering Research Laboratory (AEERL)
to estimate the costs and performance of emission controls for coal-fired utility boilers.  Originally
patterned after the Tennessee Valley Authority cost model, it  now incorporates many of EPRI's
Technical Assessment Guide cost elements and procedures are needed to evaluate the capital and
levelized busbar costs  and  cost effectiveness of power plant equipment, including air pollution
control retrofit equipment. Estimates of total capital requirement (TCR) were annualized over the
remaining life of the boiler using a capital recovery factor based on a 10-percent discount rate.  The
annualized capital was then added to the estimate of annual operation and maintenance (O&M)
costs to calculate the total busbar cost  of the control.  All costs are on  the basis of constant dollars
using 1st quarter 1991 as the  base year.

       Thirty-six boiler NOX control retrofit cases were evaluated to determine the costs and cost
effectiveness of various boiler-control combinations.  For  each of these test  cases, parametric
variations in boiler  capacity,  age, capacity factor, and NOX control efficiency were evaluated to
determine the effects of these variables on the overall costs.  The range in boiler age and capacity
factor was based on the current population profile  in the NESCAUM region.  Estimates of NOx
reductions for cost-effectiveness calculations were based on average baseline emission factors and
average controlled levels shown in Table  1-1 for each boiler class and control technology.  Costs for
FGT controls (SNCR and SCR) were evaluated based on  application  on both the uncontrolled
boilers and combustion-controlled boilers.

       Table 1-4 summarizes the economic data for 18 control retrofit cases for coal-fired boilers
investigated in this study. This table uses a standard size boiler (200 MWe) for comparing the cost
of control options. The complete data from these cost scenarios  are described in more detail in the
full text of the report and in Appendices  F and G. The results for wall-fired PC units indicate that
the total capital requirements for combustion  controls range from  $20 to $42/kW.   The  cost
effectiveness ranges from a low of $160/ton, for LNB, to $l,200/ton, for NGR,  depending on the
degree of NOX  control required.  Also, higher cost effectiveness  is  estimated for  tangential units
because of lower uncontrolled levels from these boiler types.  Note  that these capital  costs are
specific to a given boiler size.  The costs would be lower for  larger size boilers and higher for
smaller  size  boilers, as discussed in Section 6 of this report.

       The cost of reducing NOX from wall-fired PC boilers  by 35 to 55 percent with current LNB
technology is estimated to range between $160/ton and $450/ton of NOX removed. The retrofit of
LNB, or LNB + CCOFA, for T-firing is estimated to  result in  the least cost per ton of NOX reduced.
The cost per ton of NOX removed of  added OFA with LNB is anticipated to be higher because
installation of OFA requires significant added capital,  results in  greater fuel penalty and, for
wall-fired units, adds little additional NO- reduction.
                                      x
       Although SNCR costs are estimated to be cost competitive with combustion modifications,
a higher degree of uncertainty exists because of limited full-scale experience on the long-term
operational impact of reagent-based FGT controls. Similarly, the cost of reburning using natural
gas is estimated to be well below $l,000/ton of NOX removed when applied to high-NOx-emitting
                                           1-11
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cyclone units.  The low cost per ton of NOX removed is due principally to the significant NOX
reduction potential for these units.  Uncertainties in costs for reburning are associated with the
limited data on long-term operational impacts and ability to secure long-term contracts for natural
gas in  the NESCAUM region.  Because natural gas supply  to industry is more plentiful during
summer months, when ambient ozone concentrations are typically at the highest levels, reburning
may be a cost effective approach for seasonal NOX control for some units.

       Table 1-5 lists cost estimates for retrofit NOX controls on oil-/gas-fired boilers.  The cost
of combustion modifications varies from as low as $230/ton to about $5,000/ton.  The level of NOX
control that can be achieved with these investments will depend on many factors that are difficult
to gauge without a detailed site-specific and fuel evaluation.  The lowest  cost per ton of NOX
reduced is associated with the implementation of BOOS, which has minimal capital requirement
and  permits significant  NOX reductions depending on the type of  fuel burned, the initial
uncontrolled NOX, and the boiler's flexibility in meeting load demand with  a reduced number of
burners in service. Several OFA+FGR+BOOS retrofits have taken place in Southern California.
Additional combustion optimization is ongoing to maximize NOX reduction with LNB retrofits and
other adjustments. The total capital requirements of these control combinations can be significant
as reported  by Southern California  Edison (SCE) because of the extent of modification required
and added operational control. "The retrofit of hot-side SCR  on oil-/gas-fired boilers can result in
emissions as low  as 0.05 to  0.08 Ib/MMBtu (40 to  60 ppm) when  used  in  combination with
LNB+OFA+FGR combination modifications.  These levels are  more realistic when clean fuels
(e.g., natural gas) are burned.  The cost effectiveness of this control option, however, can be as high
as $15,000/ton when used on combustion-controlled boilers, lower for  larger  capacity  units.
Figures 1-2  through 1-5 illustrate the change in  cost effectiveness as lower NOX levels are sought
from coal- and oil-/gas-fired boilers.  Figures 1-2 through 1-5 illustrate these cost estimates as a
function of predicted NOX levels.  Uncertainties in these estimates, and the inherent variability in
NOX control performance and costs  from site to site, result in much overlap  among control
technologies. It is clear that combustion modifications, NGR, and noncatalytic gas treatment offer
the lowest cost options for each ton of NOX reduced.

       In conclusion, this study suggests that NOX emissions from  utility boilers in the NESCAUM
region can be reduced to levels substantially below levels reported in the late 1980s using a variety
of commercially available technologies.  These technologies include  combustion modifications,
burner replacements, and post-combustion technologies such as SNCR and SCR. However, current
experience dictates that only selected controls should be considered not only commercially available
but also sufficiently demonstrated for immediate retrofit on existing boilers.  Regardless of the
commercialization status, the retrofit of NOX controls will require detailed engineering evaluations
and site-specific analyses to ensure the safe, reliable, and economical operation of the boiler,  while
providing the required margin of safety in regulatory compliance.

       For  PC-fired boilers,  domestic LNB  retrofit  experience is  currently the largest of any
technology  and  is expanding.   With  LNB  retrofits the  average  wall-fired  PC unit  with  an
uncontrolled level  of 0.95 Ib/MMBtu can be projected to meet a range in NOX from as low as 0.45
to 0.60 Ib/MMBtu. Higher-emitting units, and units burning  coal with unfavorable properties will
likely not be able to meet lowest  NOX  reductions projected in  this study on either  short- or
long-term basis.   Significant  NOX  reduction  on oil-/gas-fired units is also projected.   Several
combustion  modification controls are currently commercially  available for oil-/gas-fired units, and
there is a significant experience base for retrofit consideration  on NESCAUM boilers.  In fact,  some
of these controls for oil-/gas-fired units are already in place on some NESCAUM boilers,  while
others are actively being evaluated.  Maximum control potential  for these  oil-/gas-fired units is
difficult to estimate because of the influence of fuel characteristics and other factors.  Certainly, a

                                           1-14
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WALL-FIRED
SIZE « 200 MW
CF = 40-82%
AGE = 20-40 years
Base NOx (Ib/MMBtu):
 Uncontrolled = 0.95
 Controlled = 0.60
                            0              0.2             0.4             0.6             0.8
                                      CONTROLLED NOx EMISSIONS (Ib/MMBtu)
                        Figure 1-2.  NOX control cost-effectiveness for PC wall-fired utility boilers
COST EFFECTIVENESS ($/ton NOx)
r* J° J" P P* P -^
- TANGENTIAL-FIRED
1 | INBw/CCOFA gg LNB + SOFA ^ NOB SIZE = 200 MW
. £^3 SNCR on uncontrolled JXT3 SNCflonLNB y~ ] SCR on uncontroltad ^F = 40-82%
Lxa balm L2SJ coniroiKd boii«n L/J boii«™ AGE = 20-40 years
f-q SCRonLNB I — 1 SCR on LN&contn>ll*d Base NOx (Ib/MMBtu):
_ CO eontrotodboton I_J boMn (Hot Sid.) Uncontrolled = 0.60
Controlled = 0.45
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                                         0.1           0.2           0.3           0.4
                                      CONTROLLED NOx EMISSIONS (Ib/MMBtu)
                                                            0.5
                     Figure 1-3.  NO  control cost-effectiveness for PC tangential-fired utility boilers
                                                         1-17
-------
    100,000
                                                                  WALL-FIRING
                                                                  SIZE » 200 MW
                                                                       40-65%
                                                     ^onuncontrell*d  CF
                                                                  AGE = 15-40 years

                                                     oofltroiicdboilm    Base NOx (Ib/MMBtu):
                                                                   Uncontrolled = 0.45
                                                                   Controlled - 0.30
                                   eoos
-------
combination of BOOS (or low-NOx OFA ports) coupled with FOR can achieve NOX levels of
0.10 to 0.20 Ib/MMBtu when burning natural gas.  However, these levels are much less likely when
burning low-grade residual oils.  With these fuels, combustion modifications will be limited by the
onset of inefficient combustion, soot  emissions, and increased carbon content in the fly ash.
Controls that aim at reducing NOX, once it is already formed, in the furnace or convective passes
of the boiler, offer further potential for additional NOX reduction. Some of these controls (e.g.,
NGR and  SNCR) may  prove to be cost competitive with combustion  modifications.   The
combination of combustion controls and noncatalytic controls (NGR or SNCR) can achieve NOX
levels almost as low as the levels achieved using SCR technology.

       The  1987 NOX  emissions  from all  utility boilers  in  the  NESCAUM region totaled
approximately 380,000 tons.  Application  of LNB based controls to 80 percent of the currently
uncontrolled dry bottom PC-fired boiler  population is expected to  reduce NOX by  29,000 to
42,000 tons/yr. The control of 50 to 80 percent of the cyclone and wet-bottom boiler capacity with
NGR coupled with LNB retrofit  on dry-bottom  units will reduce  NOX  by about 48,000  to
70,000 tons/yr throughout the region.  Control of oil-/gas-fired boilers to a system-wide level of
0.3 Ib/MMBtu will add another 29,000 tons/yr reduction throughout the region. The  overall cost
of these controls is anticipated to be less than  $l,000/ton of NOX removed, in most cases.
                                          1-19
-------
                                        SECTION 2

                             BOILER EQUIPMENT PROFILE
       Combustion modifications are the principal methods to economically control NOX from
existing and new utility boilers. The retrofit feasibility, NOX reduction performance, and costs of
combustion controls are largely influenced by boiler design and operating characteristics such as
firing configuration, furnace size and heat release rate, type of fuel, and boiler capacity factor, and
condition of existing equipment.  Many of these factors vary with the age of the unit. FGT controls
can provide additive NOX reduction from combustion-controlled levels. The retrofit feasibility and
cost of FGT controls are often influenced by the fuel type, capacity factor, load dispatch profile, and
several site-specific factors including site access and space availability.

       This section examines the population of boilers in the NESCAUM region according to five
primary classifications:

           Fking configuration (tangential, single wall and opposed, cyclones)
           Primary fuel (pulverized coal or oil/gas)
           Heat release rate (dry and wet bottom furnaces)
           Age
           Capacity factor

       The purpose of grouping the boilers into these conventional classifications  is to assign
retrofit control technologies and to calculate potential NOX reductions and costs applicable to  the
existing boiler profile in NESCAUM on the basis of broad retrofit assumptions.  Retrofit controls
are selected principally on the basis of the boiler's primary fuel, firing configuration and heat release
rate.  Low-NOx circular burners, for example, are applicable to wall- or opposed-fired boilers.
Control performance of these retrofits may vary from levels obtained from retrofit of corner-fired
boilers. The age and capacity factor will often influence the ease of retrofit and  the cost of NOX
reduction.  It should not be construed that these are the only factors that influence the retrofit
potential, performance, and eventual cost of NOX controls. In fact, fuel characteristics of coal and
oil, design  of existing furnaces, and overall operational status  of equipment are  but  a few other
site-specific factors that will influence actual performance and cost of applicable controls.

       The boiler population profile, NOX emissions, and fuel consumption data presented in this
section are based on information reported in the EPA's National  Utility Reference File (NURF)
supplemented with energy consumption data  from DOE's  Energy Information Administration
(ELA), Form EIA-767 annual report (Pechan,  1989), and information obtained directly from  the
utilities.  Appendices A and B provide a  listing of the  data  on the boiler population  in  the
NESCAUM region.
                                            2-1
-------
2.1    FIRING CONFIGURATIONS AND FUEL TYPES

       The type of NOX combustion control selected for a specific boiler type must be compatible
with the existing design of the units and the fuels. For example, burners out of service (BOOS),
a popular and inexpensive operational modification that uses combustion  air staging for NOX
control, is generally not preferred for PC-fired boilers because of modifications necessary to the coal
pulverizers. Existing PC units are for the most part not adaptable to redistribution of coal feed but
must rely on other equipment modifications to take advantage of the air staging approach  in NOX
control. Because of compact furnaces, installation of OFA ports in some pre-NSPS pulverized coal-
fired boilers can be severely limited to minimize the loss in unburned carbon in  the flyash, furnace
exit temperature, and slagging and corrosion of furnace walls.  Slagging furnaces are not adaptable
to many combustion modifications. Vertical-, turbo-, cyclone- and stoker-fired  boilers offer fewer
control options than other coal-fired boiler  designs.  As discussed below, NOX emissions from
vertical-, turbo-, and stoker-fired boilers are a small portion of the total utility boiler NOX inventory
in the  NESCAUM region. Cyclone and wet-bottom units, although  few in number, can be an
important retrofit target because of generally high uncontrolled NOX emissions.

       Table 2-1 summarizes the population of utility boilers according to firing configuration and
primary fuel type.  The 200 units listed account for more than 99 percent of the existing capacity
and current utility fossil fuel consumption in the NESCAUM region. Many boilers have multifuel


       Table 2-1.  NESCAUM boiler inventory by firing type and Fuel:  number of units
                  (capacity in MWe)
Firing Type
Tangential
Opposed
Wall
Cyclone
Vertical
Stoker
Total
Primary Fuel Type3
Coal
21
(3,170)
5
(1,980)
16
(1,790)
4
(760)
5
(370)
' 8
(160)
59
(8,220)
Oil
33
(8,210)
12
(3,160)
24
(5,120)
3
(310)
3
(160)

75
( 17,000)
Gas
29
(4,640)
5
(1,390)
25
B (3,980)
4
(760)
3
(150)

66
(10,900)
Totalb
83
(16.000)
22
(6,530)
65
(10,900)
11
(1,830)
11
(680)
8
(160)
200
(36,100)
     aMany oil- and gas-fired boilers burn both fuels.
     bAU reported capacities are rounded to three significant digits.
     Source:  EPA's NURF, DOE's EIA-767 survey, and utilities data.
                                           2-2
-------
capability and burn one fuel or the other depending on fuel pricing and availability, which vary on
a seasonal basis.  Multifuel firing capability is particularly the case for oil- and gas-fired units.  In
1987, approximately 60 percent of the gas and oil capacity burned both fuels  with  each fuel
contributing at least  10 percent of the total fuel consumption (on a Btu basis).   Throughout
NESCAUM, fuel oil accounted for 65 percent of the fuel consumption in 1987 for oil-/gas-fired
boilers. The distinction that is made between oil- and gas-fired boilers in Table 2-1 was based on
the percent of the fuel consumed  during the 1987 base year.  For example, if  oil accounted for
51 percent or  more of the total fuel consumed in the unit, then the boiler was categorized as an
oil-fired boiler. However, when data were available on the emission factor for each fuel (gas and
oil), the  reported NOX emission factor for gas-/oil-fired  units was based on the proportion of
quantity  of each  fuel consumed in 1987.  For coal-fired boilers,  only 6 percent of the available
capacity burned another fuel.
           *
       Figure 2-1 illustrates the contribution of major boiler design types to the total NOX emitted
in 1987 from all utility boilers in the NESCAUM region.  The emission level in  1987 was calculated
using the emission factor in Ib/MMBtu for individual boilers and the 1987 fuel consumption data
in 109 Btu provided in the  EPA NURF and DOE EIA data base and supplemented  with data
obtained directly  from the utilities.  The data show that the major emitters of NOX emissions are
tangential coal, tangential oil-/gas-, wall and opposed coal-, and wall and opposed oil-/gas-fired
boilers, each  category contributing approximately  an amount ranging from  14 to 24 percent.
Coal-fired  slagging furnaces which  include cyclone  and wet bottom wall-fired boilers contribute
18 percent to  the total utility NOX budget. The combined NOX output of other boiler designs
including stokers and vertical fired units burning all fuels contributes only 3 percent to the total NOX
emitted by utilities in the region.

       PC-fired boilers account for about 20 percent of  the total capacity.  Among  PC units,
tangential- or corner-fired designs account for  nearly  40 percent of the capacity,  followed by
opposed firing (24 percent), and wall-firing (22 percent).  From a  hardware modification point of
view, all opposed-, front-, and wall-fired boilers can  be considered as one design configuration, as
many of the combustion NOX controls developed for wall-fired boilers are equally applicable to
single- or opposed-wall-fired units.   When taken as a whole, wall- and opposed-fired units  account
for nearly half the fuel-based capacity (46 percent for coal and 49 percent for oil and gas combined).

       Another important design distinction among PC-fired boilers  is whether the furnace is of
the slagging type or not. Slagging furnace, also known as wet-bottom furnaces or  slag tap furnaces,
operate at higher temperatures so that the ash  deposits  on the furnace waterwalls (slag)  are
sufficiently fluid to fall in the bottom hopper without sootblowing assistance. Two  tangential-fired
boilers (174 MWe total) at the Somerset Station and seven wall- and down (vertical)-fired boilers
(1,067 MWe total), primarily at the Mercer and CR Huntley Stations, are listed as wet-bottom
furnaces in the NESCAUM inventory.  In the early 1950s to about 1967, Combustion Engineering
introduced only few (estimated at less than six) wet-bottom tangential boilers. Wet-bottom furnaces
were more popular in the wall- and  opposed-fired design.  Because of the  higher  combustion
temperature and  the requirements  for a certain higher heat release per unit of waterwall area, the
uncontrolled NOX level from wet-bottom boilers is generally higher than dry-bottom furnaces and
combustion modifications are typically limited in  applicability and effectiveness.

       Stoker boilers are generally much smaller in size than  PC units and constitute an older
vintage coal-fired design for utilities. In the NESCAUM region, stokers account for less than one
half percent of the total installed capacity. Therefore, their total contribution to the NOX inventory
in the region is expected to be minor compared to PC units. Since early-1980s research sponsored
by EPA on the retrofit of combustion modification controls to reduce NOX from stoker boilers, little

                                            2-3
-------
ISNVHO
                                                                                                    i
                                                                                                    3

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                                                                                                    41
                                                                                                    41
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                                                      2-4
-------
additional operational experience has been gained (Maloney,  1983). Existing utility stokers have
generally remained uncontrolled.  Cyclone-fired boilers are a  particular design introduced in the
1960s, primarily for low-volatile eastern bituminous coal burning.  In the NESCAUM region there
are 10 such units, with nearly half of the capacity coal-based and the other oil-/gas-based. Because
of their characteristically high-NOx emission rate, cyclones although few in number and capacity,
are an important part of the overall NOX inventory and control strategy. These units, along with
wet-bottom furnaces, are therefore evaluated for NOX reduction  potential in the present study.
Vertical or down firing configurations are included in the "other" category. These units, accounting
for less than 3 percent  of  the  oil-/gas-fired capacity, are not a  major  contributor to  the NOX
inventory; therefore, they are not  evaluated in this study.

22    AGE OF BOILERS

       The design  of utility boilers  has undergone some important  changes over the past few
decades. These changes influence the applicability of combustion controls and are often a measure
of the retrofit difficulty of the hardware and the attainable control efficiency.

       The furnace and burner design practices of the past six decades can be divided into three
principal time periods. The early boiler designs represented by units installed prior to the 1960s
(greater than 30 years of age) were generally built with large furnace volumes and low volumetric
heat release rate. Many designs are also negative draft with poor combustion air management and
distribution to the  burners. The larger  furnaces were often necessary  to achieve high combustion
efficiency with high rank coals.  Also, low furnace exit temperatures were necessary for  fouling
control and because of steam temperature limitations. Burner designs were not very sophisticated,
providing inadequate  burner air management  by today's standards.   Many  of  the boilers were
generally of low firing capacity compared to large units  built today  that take advantage  of the
economy of scale.  Because of the low capacity and poor burner control system and combustion air
management, these older units present greater retrofit difficulty and hardware upgrade. These units
also have a lower utilization (capacity factor) due to higher plant heat  rates (Btu/kWh).

       The decade of the 1960s was the second distinctive period for utility boiler designs.  During
this time, increased competitiveness among  boiler manufacturers  and improved combustion
technology and material science contributed to  the design  of more  compact boiler furnaces, larger
capacity units, and  larger burners with better combustion air control. High combustion turbulence
(mixing) and higher temperatures were  emphasized in the design for better combustion efficiency.
Unfortunately, these design conditions also led to higher NOX levels. For PC-fired boilers, greater
emphasis was placed  on low-volatile coals which,  under unstaged combustion conditions, also
contribute to higher uncontrolled NOX levels. Because of the higher baseline NOX emissions, these
20- to 30-year old  units have the potential for large NOX reductions with the retrofit of current
low-NOx combustion technologies. Some designs, such as cyclones and opposed cell-burner units
however, present significant retrofit  challenges.  Only recently have  combustion controls been
investigated for these units and commercialization of the technologies awaits  key demonstrations.

       The third period spans the past 20 years,  the post-NSPS period (Subpart D boilers). Starting
in 1971, new orders for utility boilers  called for technologies capable of compliance with new NOX
regulations (Subpart D).  Later, in 1978, more stringent regulations went into  effect (Subpart Da).
Because the NSPS  applied to new orders, some units with startup dates as late as 1975 were exempt
from regulations.  Fuel conversion boilers (units that switched from gas and oil to coal) also  had
to comply with these regulations. This motivated some important changes in the way manufacturers
designed their coal-fired furnaces and burners.  Tangential units, built by Combustion Engineering
(CE), now Aesea Brown Boveri (ABB), which  were traditionally a lower NOX emitter, started to

                                            2-5
-------
introduce SOFA as a means of ensuring compliance. In reality, tangential units were usually well
below the 1971 NSPS levels.  Babcock & Wilcox (B&W), Foster-Wheeler  Energy Corporation
(FWEC), and Riley Stoker (now a member of Deutsche Babcock Group), builders of wall-fired
boilers enlarged their furnaces to reduce heat release rate and peak temperature. Larger furnaces
were also required as lower volatile coals were increasingly used. A recent survey of 200 coal-fired
boiler designs showed that furnace volumes of post-NSPS boilers were increased 40 percent (Emmel
and Maibodi, 1991). Although some boilers were equipped with OFA as a safety measure to meet
NSPS limits, manufacturers of  these units, and owners/operators, did not rely  on OFA  ports
because of the potential impact on unburned carbon and steam temperature control and because
of concern over  corrosion (Lisauskas, 1987).  This was also the time when cyclone, wet-bottom
furnaces, and cell burners (closely coupled burner outlets) were discontinued.  In the late 1970s,
some boilers were converted to coal burning while new wall-fired units were introduced with
advanced coal burners and OFA capability to meet more stringent NSPS levels (LaRue, 1990).

       With this information as background, Figures  2-2 and  2-3  illustrate the  trend in boiler
capacity versus age for the coal- and oil-/gas-fired boiler population  in the NESCAUM region.
Clearly, the newer boilers have generally higher capacity.   The trend  is most  evident in  the
tangential and opposed-fired units.  Immediately following the initial 1971 NSPS, only one new
coal-fired boiler was introduced in the NESCAUM region, the opposed-fired 675 MWe Somerset
Unit 1.  This post-NSPS coal-fired boilers must  comply with the 1978  NSPS NOX  limits.  Several
other older  boiler were  modified  during  the past  10 years to burn pulverized coal.  These fuel-
switching units include 600  MWe of opposed firing, 520 MWe of tangential firing, and nearly
560 MWe of wall firing.

       Figure 2-4 illustrates the distribution of boilers according to age. The data show that, when
excluding fuel switching units, less than 20 percent of the oil- and gas-fired units were commissioned
in the past 20 years (post-NSPS).  Past this period, the trend is similar for all boilers irrespective
of fuel, meaning that at any given  percentage, oil-  and  gas-fired units are generally as old as coal
units. Figure 2-5 illustrates the  same data on a capacity basis.  Here the data show that less than
10 percent of the coal-fired boiler capacity was introduced in  the post-NSPS time.   When fuel
switching units are counted, the  total  PC-based  capacity introduced  in  the post-NSPS period
accounts for 34 percent of the total. In the same period of time about 40 percent of the current
oil- and gas-based capacity was put online.

2.3    CAPACITY FACTOR

       The  capacity  factor is defined as the percent of the  boiler maximum capacity that was
utilized throughout the year. For example, a unit whose maximum continuous rating is 300 MWe
can generate 2.63 GWh  of electricity in one year  operating continuously at  full load.  However,
boilers do not operate in  this manner since they require routine maintenance  during scheduled
outages.  Also, the system for  dispatching power means that less efficient  units are generally
operated less frequently than more fuel-efficient  units. Finally, load demand varies over a 24-hour
period and from  season-to-season.  Less efficient  boilers are not operated at constant base load but
are made to vary according to peak  demands. Therefore, most boilers operate  only a fraction of
the time available in any one  year and  at an  average load  that  is  lower than the  maximum
continuous rating (MCR).

       The capacity factor is an important variable for estimating the overall NOX reduction benefit
and the cost effectiveness of control technologies.  A boiler with a very low capacity factor will
typically  have a higher cost ($/ton of NOX removed) than a  boiler with a much higher capacity
factor. As heat rates are generally lower for newer and base-loaded boilers, the NOX control costs

                                           2-6
-------
        800
-. 60°

5
UJ
§400
CC
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     O
     CD
        200
*       AA

     DO
                                                 l_l
                                                 go
                  10          20          30
                          BOILER AGE (years)
                                                          COAL-FIRED BOILERS
                                                           40
                                50
 Figure 2-2.  Trends in coal-fired boiler sizes with age for the NESCAUM region
LU
N
53
CC
     O
     m
       1,000
         800
         600
         400
        200
                              D
                  A
                A
                                                          OIL 4QAS FIRED

                                                       A

                  10     20     30     40      50
                              BOILER AGE (years)
                                                 60      70
                                                               80
Figure 2-3. Trends in oil-/gas-fired boiler size with age for the NESCAUM region
                                    2-7
-------
                10     20     30    40     SO     60     70
                  AGE (YEARS OLD BASED UPON 1991)
Figure 2-4. Distribution of NESCAUM boilers—number of units versus age
       100
  UJ
  O
  8  2
  |  5

  II
(A
  S  £  40 -
  1
  u.
  O
§
<2
                10     20    30    40     50     60     70
                  AGE (YEARS OLD BASED UPON 1991)
                                                       80
   Figure 2-5.  Distribution of NESCAUM boilers—total MW versus age
                             2-8
-------
associated  with these units are lower  because such units have higher capacity factors.   This
assumption is not always valid, however, because older units, although generally used less often than
newer units, can be  high  emitters of NOX, and even  a small percentage reduction can offer
significant total systemwide reductions. Examples of such units are the slagging or wet-bottom coal-
fired boilers and the cyclone-fired boilers.  As noted earlier, coal-fired cyclone and wet-bottom PC-
fired boilers account  for 17 percent of the total NOX in the  NESCAUM region.   Those cyclone
boilers in service for nearly 30 years have capacity factors typically in the range of 60 to 80 percent.

       In this report, we used the most  recent 1987 fuel consumption data  reported by Form
EIA-767 to calculate the capacity factor of each boiler in the NESCAUM region  (Pechan,  1989).
The reported fuel consumption was then translated to an  equivalent electrical output using the heat
rate reported by the  utilities for their respective power plants.   For the New York Power Pool
(NYPP), heat rates of boilers were based on data reported in a recent study for the Empire State
Electric Energy Research Corporation (Hunter, 1989). Some utilities reported capacity factor data
for the 1990 year.   In  a few  cases  when this  information was  not  available, a standard
10,000 Btu/kWh heat  rate was used.  The calculation of capacity factor, using the boiler  steam
turbine generator rated MW and a nominal heat rate for the unit, is subject to uncertainty. This
is because  the heat rate varies according to boiler load and fuel mix. A more correct calculation
would have used the rated firing capacity of the boiler.  However, this information was not readily
available for the majority of the units.  The heat rate of a boiler will vary with load, age and design.
For the NESCAUM boilers,  the  gross heat  rate is  likely  to be in the  range of 9,500 to
14,000 Btu/kWh.

       Figure 2-6 illustrates the distribution of units according to boiler capacity factors. The data
clearly shows that coal-fired boilers have a higher utilization rate, and more than 80 percent of all
units had a capacity factor greater than 50 percent.  The trends for oil- and gas-fired boilers are
similar. Only about 30 percent of all the units had a capacity factor greater than  50 percent in 1987.
Figure 2-7  illustrates the same data on a capacity basis. Here  the data show that about 80 percent
of the coal-fired boiler capacity,  approximately 8,000 MWe, was on line at least 50 percent  of the
time.  Of the approximate 28,000 MWe of combined oil- and  gas-fired boiler capacity, only about
30 percent  had a capacity factor  greater than 50 percent, significantly lower than PC-fired boilers.

2.4    SUMMARY OF POPULATION  DATA

       Figures 2-8 and 2-9 illustrate the distribution  of existing coal- and oil-/gas-fired boilers in
operation in 1987 in the NESCAUM region, respectively.  The capacity of these units is segregated
by age of boilers. The figures also give data on the weighted average capacity factor (WACF, see
glossary for definition) for each group of boiler designs in that time period.  The average capacity
factor is weighted according to the size  of the boiler.  The single post-NSPS coal-fired boiler has
a capacity factor (81 percent) higher than all other  units from any other age group or fuel type.
Also the average capacity of the newer units has increased.  Stokers and vertical units not only
account for very little capacity but also have a lower operating  factor, here calculated at an average
of 51 percent.  Stoker  boilers have heat rates in the range of 14,000 to 15,000  Btu/kW, much higher
than most other boiler design types.

       Contrary to coal-fired units, less total oil-/gas-fired capacity was added in the past 20 years
than in the  previous 20 years. Because of fuel economies, the overall capacity factors for these units
are generally lower than those for coal.  Wall-fired boilers show an unusually low capacity  factor
regardless of the age of the units.  For example, in  1987 post-NSPS oil-/gas-fired boilers showed
a capacity factor of only 33  percent, 6 percent for units of 21 to 30 years of age, and 25 percent for
units of 31  to 40 years of age.  It is likely that these boilers were used to follow load demand and

                                            2-9
-------
           100
                   10
20
30   40   50    60    70
CAPACITY FACTOR {%)
80
90   100
Figure 2-6. Distribution of NESCAUM boilers—number of units versus capacity factor
           100
                        20
     30    40    SO    60   70
     CAPACITY FACTOR (%)
                          80
     90
     100
   Figure 2-7. Distribution of NESCAUM boilers—total MW versus capacity factor
                                   2-10
-------
     5,000
 |
     4,000
 f-  3,000

 §
 Q.
 <
 O  2,000
 -1

 I
     1,000
                                  COAL FIRED UNITS
         SunHs
         57 WACF
lunlt
81 WACF
         2 unto
         S8WACF
         4 units
         80 WACF
                           5 units
                           66WACF
                            2 unit*
                            57 WACF

                            6 units
                            87 WACF
                            8 units
                            59 WACF
13 units
67WACF
                  Stokers & Vertical

                  Cyclone & Wet Bottom

                  Opposed-Fired Boilers

                  Wall-Fired Boilers

                  Tangential Boilers
                   WACF:  Weighted Average
                         Capacity Factor
                                             1 unit (Tangential)
                                             48 WACF
  2 units
  27 WACF
                                                            1 unit (Wall)
                                                            63 WACF
                                                      7 unto
                                                      51 WACF
                  Oto20            21 to 30            31 to 40
                               AGE OF BOILERS (years)
                   Figure 2-8.  Age distribution of coal-fired boilers
                                                        >40
    12,000
    10,000
    8,000
g   6,000

g
_J
<   4,000
    2,000
                           OIL- & GAS-FIRED UNITS
           3 units
           43 WACF
           9 units
           33 WACF
           10 unto
           55 WACF
           2 units
           31 WACF

           5 unto
           54 WACF
           3 units
           8 WACF
           13 unto
           44 WACF
                                                    2 unto
                                                    15 WACF
 5 unto
 33 WACF
 9 unto
 47 WACF
                            18 unto
                            25 WACF
                                              22 unto
                                              50 WACF
Vertical

Cyclone

Opposed-Fired Boilers

Wall-Fired Boilers

Tangential Boilers

 WACF:  Weighted Average
       Capacity Factor
                                                                         4 units
                                                                         7 WACF
                                                                15 unto
                                                                28 WACF
                   0 to 20            21 to 30           31 to 40             > 40
                              AGE OF BOILERS (years)

               Figure 2-9.  Age distribution of oil- and gas-fired boilers
                                           2-11
-------
for peaking power needs, whereas coal-fired boilers were more base load units.  Cyclone and
vertical fired boilers account for minor capacities even when considered in their own age groups.

       Figures 2-10 and 2-11 illustrate the NOX emission levels attributed to the various coal- and
oil-/gas-fired boiler groups, respectively. The low PC-fired post-NSPS boiler is attributed with about
12,000 tons/year of NOX.  Among coal-fired equipment, the largest NOX sources are the slagging
units (wet bottom and cyclone) followed by tangential boilers, opposed and wall-fired boilers. Most
of the NOX is emitted by pre-NSPS boilers. Among slagging furnaces, cyclone units, although few
in number, contribute significantly to the total NOX inventory in the region (16 percent of the NOX
from all coal-fired boilers; 8 percent of the total utility boiler NOX).  As shown, stoker boilers are
relatively insignificant NOX emitters when compared to other boiler types. For oil-/gas-fired boilers,
the tangential firing designs as a whole contribute the bulk of the  NOX emissions.  In contrast with
PC-fired boilers,  post-NSPS oil-  and  gas-fired units account for a large fraction of total NOX
emissions. Vertical and cyclone boilers are minor contributors to the NOX inventory.
                                           2-12
-------
   120,000
^110,000
C
O 100,000
g  90,000
Q  80,000
CO
^  70,000
UJ  60,000
X
^  50,000
CO  40,000
0)
    30,000
    20,000
    10,000
         0
              COAL FIRED UNITS
                                                   ^
                                                            Stokers & Vertical
                                                            Cyclone & Wet Bottom
                                                            Opposed-Fired Boilers
                                                            Wall-Fired Boilers
                                                            Tangential Boilers
                                                               \
                                                                Stoker
                                                             Tangential
                  0 to 20           21 to 30           31 to 40
                               AGE OF BOILERS (years)
TOTAL 1987 NOx - 206,000 tons
                 Figure 2-10. NOX emissions, coal-fired  boilers
                                                                      >40
    80,000
 (0
 C 70,000
 O
    60,000
 
                                                               Vertical
                                                                    KXXXXXXX
                 01020           21 to 30           311040
                              AGE OF BOILERS (years)
TOTAL 1967 NOx - 176,000 tons
             Figure 2-11. NOX emissions, oil- and gas-fired boilers
                                                                      >40
                                      2-13
-------
                                       SECTION 3

                            BASELINE EMISSION PROFILES
       In this study, the term baseline NOX is used to describe the current NOX emission levels
from  utility boilers in the region.  Because the vast majority of these boilers do  not use NOX
controls, such as low-NOx burners or flue gas treatment, the term can also be interpreted to mean
uncontrolled NOX emission levels.   NOX emissions from utility boilers are  a  function of fuel
properties and many boiler design and operating variables.  Among the most influential variables
are the fuel nitrogen content, the excess air rate, the heat release rate  per unit of waterwall area
in the burner zone, the amount of air preheat, and the burner stoichiometry.  When pulverized coal
is burned, the fuel ratio (fixed carbon divided by volatile matter) and oxygen/fuel nitrogen ratio also
influence the uncontrolled NOX levels as well as NOX levels  achievable  with combustion controls.

       As the nitrogen content in the fuel increases so does the overall NOX level.  Generally, only
a fraction of the total fuel-bound nitrogen is converted to NOX.  That amount is usually in the range
of 20 to 80 percent when combustion is not staged as illustrated in Figure 3-1. The higher nitrogen
fuels have lower conversion rates but higher  overall NOX emissions. For pulverized coal burning,
the FR affects NOX to  a degree equivalent to fuel N.   Typically, under  unstaged combustion
conditions lower fuel ratios (i.e., higher volatile content of the coal) correlate with higher production
of NOX.  This is the result of greater amount of volatile nitrogen released in the high temperature
zone of the flame where sufficient oxygen is available to generate high levels of NOX. When the
combustion is staged, the effect is the opposite.  Figure 3-2 illustrates this combined effect of FR
and fuel-bound N under staged combustion with two low NOX burner  technologies coupled with
SOFA.  The proprietary fuel factor developed by B&W illustrates that  higher FR and N result in
higher controlled NOX levels.  Therefore, staged combustion controls are typically more effective
on high volatile content  coals also known as  reactive coals.  Under combustion staging with OFA
or low-NOx burners, lower NOX levels are attainable when burning subbituminous coals which have
higher volatile and oxygen content than higher rank eastern bituminous coals.  The  effect of coal
quality is important because performance results of low-NOx combustion systems reported with one
coal type cannot be interpreted to apply to other coal types.  This distinction of NOX performance
with coal type is further  highlighted in Section 4.

       NOX generally increases with excess air and the burner zone heat release rate (BZHRR).
The BZHRR is a key boiler design parameter used by manufacturers to design furnace volumes and
waterwall area according to fuel type and NOX control requirements. BZHRR varies with the firing
type, the age of the unit, the primary fuel type, and the operating load.  For example, slagging or
wet bottom  furnaces have  a high BZHRR  necessary to achieve  high furnace temperatures to
maintain the slag in a fluid state. In a similar  manner, the cyclone furnaces enclose the combustion
of coal in a small  refractory furnace creating high combustion  temperatures  that lead  to  much
higher NOX levels. As discussed in Section 2, all of these furnace designs were introduced in  the
late 1950s and 1960s when NOX was not regulated.  Because of their requirements for high furnace
temperature, control of  NOX in these boiler types is extremely difficult.  For gas- and oil-fired
                                           3-1
-------
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                       2.5
                    .1
                    JS  1-5
                    o>
                    en

                              1.2   1.4  1.6   1.8   2  2.2  2.4   2.6  2.8

                                        B&W Fuel Factor
                                        a. b. c « proprietary constants
                                  D   Mitsubishi/CE • PM System
                                  -   B&W - XCL + NO, Ports
                        Figure 3-2. Fuel effect on NOX (LaRue, 1990)
boilers, air preheat contributes to higher NOX levels. Typically, all utility boilers utilize air preheat
for improved thermal efficiency.

       Figure 3-3 illustrates the variation in  uncontrolled, pre-NSPS, NOX levels for the various
designs of PC-fired boilers.  As shown, NOX generally increases with boiler capacity for all boiler
types.  Slagging furnaces are the highest contributors to NOX emissions. Existing tangentially-fired
boilers are typically the lowest NOX emitters.  Newer wall-fired designs can often match the low
emission levels of the ABB-CE boilers because of the recent breakthroughs in  low-NOx burner
technologies.

       Table 3-1 summarizes the uncontrolled emission factors  for the major  coal-fired boiler
design groups in the NESCAUM region.  Two emission factors are presented.  The first is that
reported in the NURF and current ELA data  bases (Pechan,  1989) supplemented, when available,
with information obtained directly from the utilities during the course of this study and with data
presented in the ESEERCO study (Hunter, 1989). Where available, both the range and the average
value (weighted according to capacity) for that boiler population  is  reported  (see  Appendix A
for details).   The second set of emission factors are those reported by the EPA for each boiler
design/fuel category.  The AP-42 emission factors are  reported solely for  companion purpose to
establish the reasonableness of emission levels reported in the data base.  These AP-42 emission
factors are not used anywhere else in  the report.

       A review of the boilers' emission  rate for the  post-NSPS boilers shows  that the Kintigh
Unit 1 coal-fired utility boiler, with a  reported startup data in 1984, meets the regulatory limit of
0.6 Ib/MMBtu introduced  in 1978 for bituminous-coal-fired boilers.  Other areas of general
agreement between NOX emissions factors reported by this study and those in AP-42 include all dry
                                            3-3
-------
         2.0-
 CD
CO
 CO
 z
 o
 CO
 CO

 2
 LLI

  X
 O
 Z
            -   WALL-FIRED
              WET BOTTOM
                     CYCLONE
ROOF
FIRED
                                 PRE-NSPS BURNERS
                           WALL-FIRED
                          DRY  BOTTOM
                          WET BOTTOM
                       URBO-FIRED
                         	 null"           i

                  ? TANGENTIALLY FIRED |
                       NSPS BITUMINOUS - —

                  NSPS SUBBITUMINOUS	
                  ARCH-FIRED
                100   200   300  400   500    600   700   800


                          UNIT CAPACITY, fiw
Figure 3-3. Full load NOX emissions for pre-NSPS coal-fired utility boilers (Miller, 1985)


                            3-4
-------
 Table 3-1. NOX emission factors—coal-fired boilers in the NESCAUM region
Age
(yr)
0-20a


21-30




31-40




>41



Firing Type
Tangential, dry bottom
Wall, dry bottom
Opposed, dry bottom
Tangential, dry bottom
Wall, dry bottom
Opposed, dry bottom
Cyclone
Wall, wet bottom
Tangential, wet bottom0
Tangential, dry bottom
Wall, dry bottom
Wall, wet bottom
Vertical, wet bottom
Tangential, dry bottom
Vertical, wet bottom0
Wall, dry bottom
Opposed, dry bottom
Number
of Units
0
0
1
5
4
2
4
1
2
13
8
2
2
1
2
1
2
Average
Capacity
(MWe)
NA
NA
675
267
106
630
189
326
87
124
73
200
66
53
64
55
22
NOX Emission Factors
(Ib/MMBtu)
This Study
NA
NA
0.55
0.58-0.70
(0.65)b
0.57-0.80
(0.65)
0.84-1.77
(1.33)
1.10-1.41
(1.28)
2.06
0.60-1.64
(1.04)
0.45-0.80
(0.64)
0.42-1.00
(0.89)
0.44-2.01
(1.20)
1.10
0.52
1.10
0.79
0.83
AP-42
0.6
0.6
0.6
0.61
0.86
0.86
1.51
1.39
1.39
0.61
0.86
1.39
1.39
0.61
1.39
0.86
0.86
"Several boilers were converted to coal firing in this time period.
bWeighted average; calculated by summing the product of each emission factor
 in Ib/MMBtu and boiler size (MWe) and dividing by the total capacity for that
 boiler category.
°It is not confirmed if these units have slagging furnaces.
NA:  No NESCAUM  boilers in this category.
Note:  To convert to average concentration in ppm at 3 percent O-, multiply
       Ib/MMBtu by 750.
                                   3-5
-------
bottom units with greater than 30 years of service.  Significant disagreements, however, are shown
for dry bottom boilers in the 21 to 30 years age group and for most wet bottom boilers.

       Another important observation is that NOX levels can vary significantly even within a given
source category. For example, the five tangential dry bottom boilers in service for the past 21 to
30 years show a range in NOX emissions between 0.58 to 0.70 Ib/MMBtu.  The  two dry bottom
opposed wall-fired boilers show a range of 0.84 to 1.77 Ib/MMBtu. This is indicative of the possible
variations in NOX  levels  from "similar" units and also that some units may already be controlled.
It is important to recognize that percent NOX reductions are lower from boilers whose current NOX
levels  are already low because  of  existing controls or other site-specific design and  operating
characteristics. This is because the effectiveness of combustion modifications on existing boilers is
limited by operational side effects that can become unacceptable to the safe and reliable  operation
of the plant when NOX levels are controlled beyond safety limits. These limits of performance are
often very site-specific.

       Figure 3-4 plots NOX emission factors (EF) for the pre-NSPS coal-fired boilers versus boiler
capacity. The data illustrate that, for the most part, there does not seem to be any correlation of
NOX with  boiler  capacity,  defined  by gross generator output.  This illustrates the principal
dependency of NOX on other key boiler design/operating  factors, such as heat.release rate and
firing configuration, and on fuel characteristics, such as volatile matter of coal or fuel nitrogen.
Wet-bottom boilers exhibit a full range of uncontrolled NOX levels.

       Table 3-2 summarizes the uncontrolled emission factors for gas- and oil-fired utility boilers.
For post-NSPS units, uncontrolled NOX levels are reported in this study are in the range of 0.21 to
1.05 Ib/MMBtu. Only one boiler was reported to exceed 0.5 Ib/MMBtu. The averages, weighted
according to boiler capacity, ranged from 0.34 Ib/MMBtu, for tangential units, to 0.44 Ib/MMBtu,
for wall-fired boilers and 0.27 Ib/MMBtu for opposed-fired boilers (see Appendix B for details).
Current NSPS levels are 0.3  Ib/MMBtu for oil and 0.2 Ib/MMBtu for gas. Average NOX  emissions
reported for units  in the other age groups are 0.20 to 0.25 Ib/MMBtu for tangential  units, 0.31 to
0.58 Ib/MMBtu for wall-fired units,  and 0.28 to 0.65 Ib/MMBtu for opposed-fired units.  Unless
reported directly by the utilities, baseline NOX emission levels for boilers in the state  of New York
were calculated based on the emission factors for full boiler load oil- and gas-firing presented in the
ESEERCO study (Hunter,  1989) proportioned according to the oil and gas consumption reported
in the EIA data base. Unfortunately, separate NOX emission factors for oil- and gas-firing were not
available for all  units,  therefore  some  uncertainty in these levels  exists.  Also,  it should be
recognized that because  emission levels vary with boiler load as well as fuel mix,  each boiler will
exhibit a particular NOX emission profile that varies over a day's period, from season to season, and
from year to year. Overall,  these emission levels  indicate that wall and opposed fired units  are
generally higher emitter  of NOX compared to tangential designs.

       Figure 3-5  illustrates current NOX levels from oil-/gas-fired boilers plotted against boiler
capacity in MWe.  The boilers are segregated according to  dry-bottom, pre- and post-NSPS units,
and  wet-bottom boilers.  It is likely  that many of the pre-NSPS boilers are improperly labeled
because many were not  subject to  Subpart D or Da at the time of startup.  As with  coal-fired
boilers, there is no direct relationship between current NOX levels and boiler capacity.  This is again
due in part to the influence of boiler design/operating conditions and fuel characteristics, and due
to the  fact that some units  may be already controlled for NOX.

       Table 3-3 summarizes the emission factors for all major boiler/fuel categories in NESCAUM
by age group.  These factors correspond  to the weighted average emission levels  presented in
Appendices A and B and in Tables 3-1 and 3-2. Table 3-4 groups these data further  into only two

                                            3-6
-------
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                  3-7
-------
 Table 3-2.  NOX emission factors—oil-/gas-fired boilers in the NESCAUM region
Age
(yr)
0-20


21-30


31-40




3>41


Firing Type
Tangential
Wall
Opposed
Tangential
Wall
Opposed
Cyclone
Tangential
Wall
Opposed
Cyclone
Vertical
Tangential
Wall
Vertical
Number
of Units
10
9
3
13
3
5
2
22
18
9
5
2
15
15
4
Average NESCAUM
Capacity (MW)
. 441
333
515
330
276
320
310
120
140
120
90
64
80
46
46
NOX Emission Factors
(Ib/MMBtu)
This Study
0.22-0.48
(0.34)a
0.21-1.05
(0.44)
0.21-0.30
(0.27)
0.17-0.34
(0.25)
0.29-1.40
(0.52)
0.45-0.90
(0.65)
0.50-0.68
(0.63)
0.14-1.36
(0.25)
0.28-1.08
(0.58)
0.25-0.31
(0.28)
0.44-0.50
(0.48)
0.30-0.70
(0.58)
0.14-0.40
(0.20)
0.24-0.48
(0.31)
0.22-0.53
(0.44)
AP-42
0.3
0.3
0.3
0.26-0.28
0.45-0.52
0.45-0.52
NAb
0.26-0.28
0.45-0.52
0.45-0.52
NA
0.45-0.52
0.26-0.28
0.45-0.52
0.45-0.52
aEmission factor weighted according to capacity; calculated by summing the product
 of each emission factor in Ib/MMBtu and a boiler size (MWe) and dividing by the
 total capacity for that boiler category.  See Appendix B for detail.
bNA = No AP-42 emission factor available for his equipment type.
Note: To convert to average concentration in ppm at 3 percent O-> multiply
      Ib/MMBtu of NOX as NO2 by 790.
                                     3-8
-------
3SNVHD





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PRE-NSPS
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PRE-NSPS
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                         3-9
-------
Table 3-3. Average NOX emission factors for utility boilers in the NESCAUM region
Age
(yr)
0-20


21-30




31-40






»
>41



Firing Type
Tangential
Wall
Opposed
Tangential
Wall
Opposed
Wall wet bottom
Cyclone
Tangential
Wall
Opposed
Tangential wet bottom
Wall wet bottom
Opposed wet bottom
Vertical wet
Cyclone
Tangential
Wall
Opposed
Vertical wet
NOX, Ib/MMBtu
PC-Fired
NAa
NA
0.55
0.65
0.65
1.33
2.06
1.28
0.64
0.89
NA
1.04
1.20
NA
1.10
NA
0.52
0.79
0.83
1.10
Gas/Oil-Fired
0.34
0.44
0.27
0.25
0.52
0.65
-b
0.63
0.25
0:58
0.28
—
—
—
—
0.48
0.20
0.31
NA
—
         aNA = No NESCAUM boilers in this category.
         bDashes indicate that this boiler design type is either not available
         or that reported emission factors for these units have been
         included in the average for dry bottom boilers.
                                      3-10
-------
Table 3-4. Range and average baseline NOX levels for Pre- and Post-NSPS
          utility boilers in the NESCAUM region (Ib/MMBtu)
Fuel
Coal

•

Oil/gas mix



Firing Type
Tangential
Wall and opposed
Cyclone
Wet bottom units
Tangential
Wall and opposedf
Vertical
Cyclone
Pre-NSPSa
0.45-0.80
(0.60)b
0.42-1.77
(0.95)
1.10-1.41
(1.28)
0.44-2.06
(1.85)
0.14-0.40
(0.24)
0.24-1.40
(0.52)
0.22-0.70
(0.52)
0.44-0.68
(0.60)
Post-NSPS
NAC
0.55
NA
NA
• 0.22-0.48e
(0.34)
0.21-1.051e
(0.35)
NA
NA
    aAH boilers with more than 20 years of service.
     Number in parenthesis is the weighted average for all units in
     the source category.
    °NA = No boilers with 0 to 20 years of age.
     Average for all pre- and post-NSPS units.
    eAlthough listed as post-NSPS boilers, high NOX emitters are
     not likely subject to NSPS levels because age of boilers in this
     study, is based on startup date other than the date when the
     unit was ordered, which is the effective date for NSPS
     compliance determination.
    * Average for all pre- and post-NSPS units.
                                 3-11
-------
age groups:  pre- and post-NSPS boilers. Table 3-4 also shows the full range in  reported NOX
emissions for the major figure types. These baseline emission factors are used in this study to
determine the range in  NOX controlled  levels and  cost  effectiveness of applicable control
technologies. Single wall- and opposed-fired boilers have been combined here because both firing
configurations use circular burners and  combustion controls that are applicable  to both firing
configurations. Average PC-unit NOX emissions for pre-NSPS wall/opposed and tangential designs
with more than 20 years of service (only one boiler in the NESCAUM region is post-NSPS) are
0.95 and 0.60 Ib/MMBtu.  Coal-fired cyclone and  other slagging boilers emit,  on the average,
1.28 and 1.85 Ib/MMBtu.  Average NOX emission levels for gas- and oil-fired boilers are generally
in the 0.34 to 0.35 Ib/MMBtu range, for post-NSPS tangential- and wall/opposed-fired boilers, and
in the 0.24 to 0.52 Ib/MMBtu range, for pre-NSPS  units.  Vertical (down-fired) and cyclone units
emit, on the average, 0.52 and 0.60 Ib/MMBtu. The range in emission levels shown by individual
boilers is significant. Emissions as high as 1.40 Ib are indicative of a high furnace heat release rate
and high-nitrogen-content fuel. These high emitting gas- and oil-fired units have the potential for
the largest net NOX reductions with combustion controls.

       Figure 3-6 plots the baseline  NOX emissions of individual boilers, starting with the lowest
emitting unit, versus the cumulative  percent capacity of each boiler  category of firing  types and
fuels.  For example, approximately 60 percent of  the total  dry-bottom PC wall-fired  (including
vertical firing) capacity (2,260 MWe)  has a current emission factor of less than 1.0 Ib/MMBtu.  One
unit (shown as the last data point for filled triangles), which  accounts for about 30  percent of the
existing  dry-bottom PC wall-fired capacity, has a  reported emission factor of  1.7 Ib/MMBtu.
Approximately 10 percent of the 3,770-MWe current  capacity (370 MWe) for dry-bottom  PC
wall-fired units has uncontrolled levels of 0.6 Ib/MMBtu or less. Significant NOX reductions from
these already low-emitting  units should not be  anticipated with  today's  retrofit combustion
modifications. For example, a 50-percent NOX reduction with combustion modifications  is very
unlikely  from boilers  emitting 0.6 Ib/MMBtu  (because 0.3 Ib/MMBtu controlled is not deemed
reasonable), whereas a 50-percent reduction from units currently emitting more than  1.0 Ib/MMBtu
is considered more probable but not  necessarily achievable in all cases. Nearly all the capacity of
tangential PC-fired boilers has an emission factor of about 0.6 Ib/MMBtu, nearly twice the current
level of most gas-/oil-fired units.
                                           3-12
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                                       SECTION 4

                      NOX CONTROL TECHNOLOGY EVALUATION


       NOX emissions from fossil fuel combustion  are caused by the  oxidation of fuel-bound
nitrogen and the thermal fixation of nitrogen in the combustion  air.   Although it cannot be
predicted with certainty, the amount of fuel nitrogen conversion is known to be a function of many
fuel properties and combustion parameters. In coal flames, fuel properties such as nitrogen content,
volatile matter, the ratio of fixed carbon to volatile matter, internal moisture, and coal size, among
other factors, all affect the  quantity of NOX formed and  the  degree of control achieved with
combustion modifications. As discussed above, boiler furnace designs and operating practices also
have a dominant influence on the amount of NOX generated.

       Typically, fuel NOX in coal and residual (No. 6) fuel oil flames accounts for 60 to 80 percent
of the total NOX formed (Pohl,  1976 and Pershing,  1979).  Thus,  when  burning these fuels the
control of fuel NOX is very important in achieving the desired degree of overall reduction.  Control
of fuel-air mixing by selective staging of combustion  air is the principal combustion modification
technique used to suppress fuel NOX formation in utility boilers.  When lighter grade fuel oil or
natural gas is burned in boilers, nearly all the NOX is generated from the high-temperature fixation
of free nitrogen in the air. Controlling the peak temperature of combustion and fuel-air mixing is
the fundamental approach in reducing NOX from combustion of "clean" low-nitrogen fuels in boilers.
Combustion modifications designed to reduce NOX emissions from  utility coal-, oil-, or gas-fired
boilers can result in increased CO and HC emissions and excessive unburned carbon (UBC) in the
flyash when coal is burned. Section 7 documents the reported experience to date with CO and HC
emissions when NOX controls are implemented on utility boilers.

       There are two  basic approaches to the  control of NOX from utility boilers.  The first
approach focuses on the modification of the combustion process at the  burners or in the  near
burner region of the furnace. In this approach, the fuel and combustion air flowrates and locations
are manipulated in such a way to obtain localized regions where N*> formation is favored over NOX.
For fuel NOX control from coal and high nitrogen fuel oil flames, the principal technique used is
two-staged combustion (TSC) also referred to as off-stoichiometric (O.S.) combustion.  TSC is
particularly effective in controlling fuel NOX but also reduces thermal NOX. In the first stage of this
process, the amount of combustion air is suppressed to levels below the theoretical amount required
for complete combustion. The lack of oxygen creates reducing conditions that, given sufficient time
at high temperature, causes the fuel nitrogen to  form N9 rather than NO.  Control technologies
using this approach are BOOS, OFA, and LNB. For thermal NOX control, the principal techniques
used are based on reducing the peak flame temperature and/or oxygen concentration.  Control
technologies that use  these  approaches are  flue gas recirculation  (FOR),  reduced air  preheat
(RAP), load reduction, TSC and some  LNB  designs that utilize high air/fuel ratios in premixed
flames with secondary staging. Because of the heavy fuel efficiency penalties, RAP is not viable for
retrofit NOX reduction on utility boilers.  For this  reason, RAP is not included as a control option
for the NESCAUM units.
                                           4-1
-------
       Low excess air (LEA) is an operational modification that can provide measurable reductions
in NOX.  In this report, we have not included LEA as a separate control technology for several
reasons.  First, LEA is part of good combustion air management that is desirable to minimize dry
heat loss.  Most utilities attempt to operate their units with LEA to maximize thermal efficiency
while ensuring complete combustion.  Also, some units require a certain level of excess air to
maintain superheater steam temperature.  Reduction  of excess air from these levels is often not
possible without affecting steam temperature. Second,  older negative or balanced draft units often
have poor combustion air management because furnace air inleakage is difficult to control.  Third,
LEA generally provides low NOX reduction efficiency  (0 to  15 percent) depending on the degree
of available excess air reduction without incurring steam temperature control problems or excessive
CO or hydrocarbon emissions. Finally, LEA accompanies the application of low-NOx combustion
hardware such as low-NOx burners.  More importantly, good air/fuel  distribution to the various
burners is often necessary to optimize excess air while ensuring efficient combustion and adequate
cooling of burner equipment. Many PC-fired utility boilers operate with less than optimum air/fuel
distribution which can cause high excess air and NOX emissions and can limit the effectiveness of
burner retrofit controls. Although LEA is not considered a NOX retrofit technology in this report,
improved  air/fuel distribution to burners along with good fuel preparation  can be an important
aspect of low-NOx combustion retrofit  controls.

       The second approach to NOX  control relies on the destruction of already formed NOX in the
upper section of the radiant furnace or the convective flue gas passages of the boiler.  In the
returning process, part  of the fuel bypasses the main heat release zone area  and is injected above
the main burner zone within the furnace. Substoichiometric conditions are attained in the reburning
zone. The NOX formed in  the lower  burner zone is reduced by radicals such as NH3, HCN as well
as molecular nitrogen.  These reactions take place at temperatures exceeding  1,090°C (2,000°F).
Additional OFA is then added  to combust the residual CO and UHC prior  to the combustion
products exiting the furnace.

       This in-furnace NOX reduction process is contrasted to flue gas  treatment processes which
reduce NOX in the temperature  range  of about 290 to  1,090°C (550 to 2,000°F).  These controls
are generally based on the property of  NO as an oxidizer for the NH^ + specie to produce N-j and
water. This reaction can  occur selectively at elevated temperatures (870  to 1,090°C [l,65o to
2,000°F]) without the assistance of a  catalyst or at  lower temperatures (typically 288 to 371°C [550
to 700 °F]) with the assistance of a catalyst.  The common reagents used for these techniques are
ammonia (NH3) and urea (NHTCONH-)), which are used in the SNCR process, and NH3, which
is used exclusively in the SCR process. In some technologies, these NOX controls are combined with
SOX dry and wet controls to reduce these two pollutants simultaneously. Additional FGT techniques
have  been investigated, but for the most part,  the  most common NOX  control technologies
applicable to some units in the NESCAUM boiler inventory are the SNCR and SCR processes.

       Recent regulations in Germany and Japan have necessitated the use of an FGT process,
primarily SCR,  to achieve  some of the lowest NOX standards  in the world.  In the United States,
the control of NOX from  power plant  coal-,oil-, and gas-fired boilers has focused on the  use of
combustion modification  techniques developed and  implemented over  the  past  two  decades.
Although in Europe, particularly Germany, and Japan both SNCR and SCR have been applied with
success, these countries also rely primarily on the application of combustion modifications to
achieve the bulk of necessary NOX  reductions.  Only  when the capabilities of these lower cost
approaches have been exhausted, are FGT controls generally considered.

       The following sections discuss  the commercially available  retrofit NOX controls that are
applicable to the utility  boilers in the NESCAUM  Region and the documented experience in  NOX

                                           4-2
-------
reduction performance and retrofit requirements. Although, these NOX reduction performance and
controlled levels span a wide range of values, actual NOX reductions  that are attainable at any
power plant in NESCAUM are often a function of many site-specific considerations coupled with
the degree of combustion equipment upgrades that are included with the retrofit. Therefore, the
information presented in this section on applicability and performance  of NOX retrofit controls in
offered as general guidelines for the "typical" boiler within a given fuel/design and age category and
that the information does  not necessarily apply to any specific unit in  NESCAUM.  Site-specific
analyses  are recommended  to ascertain whether the emission levels cited in this report can be
achieved by any particular site.

       Schematics of many of the controls are included in Appendix C.  Reports of NOX reduction
performance and controlled levels attained in full-scale retrofits are summarized  in Appendix D.
Controlled emission levels and control efficiencies reported in Appendix D are used as the basis
for estimating NOX reduction performance from average baseline levels in the NESCAUM region
and to estimate the range in controlled emission levels.

4.1    COMBUSTION CONTROLS FOR COAL-FIRED  BOILERS

       Table 4-1 summarizes NOX reduction performance, application,  and anticipated equipment
modifications for  retrofit  NOX combustion  modification controls for coal-fired utility boilers.
Percent NOX reductions and controlled levels listed in the table reflect performance levels reported
in the literature. Appendix D details this reported performance. These  reduction efficiencies were
applied to average  baseline  NOX  levels for the various boiler designs  (Tangential [T], wall-fired
including opposed firing [W], slagging or wet-bottom [S], and cyclone  [C]) and age groups (pre-
NSPS and post-NSPS) reported in Table 3-4  to arrive  at estimates of controlled NOX emission
estimates for NESCAUM units.

       Estimates of lowest NOX levels achievable with combustion controls are  in the range of
0.35 to 0.55 Ib/MMBtu (260 to 420 ppm at  3 percent O2), for pre-NSPS  dry-bottom wall-fired
boilers, and 0.30 to 0.45 Ib/MMBtu, for pre-NSPS dry-bottom tangential  boilers. As discussed later,
the current experience with retrofit of LNB + OFA on wall-fired boilers is minimal. Therefore, these
LNB+OFA estimates are based on a limited performance data set that can prove optimistic. Also,
the level of control that will be attained will be  influenced by the furnace size, the fuel type, and the
ability to maintain operational flexibility with  UBC, waterwall corrosion, and steam temperature
control in check.  The current data  base on LNB retrofit  alone, however, is more  extensive,
supporting NOX reductions of 35 to 55 percent  on individual pre-NSPS boilers with controlled levels
reported in  the range of 0.45 to 0.60 Ib/MMBtu.  Again, as explained  later, the more aggressive
reductions are more likely from boilers with high uncontrolled levels, burning favorable medium-
to high-volatile coals, undergoing extensive upgrade of existing equipment, operating within  a
narrow load range, and monitored under short-term test conditions.

       No  attempt was made  in this study  to differentiate or  correlate the  NOX  reduction
performance of these controls according to other key boiler design and operating variables such as
furnace or burner zone liberation rate (BZLR, Btu/hr-ft2), volumetric  heat release rate (VHRR,
Btu/hr-ft3),  excess combustion  air, or boiler  load.  NOX reduction performance of combustion
modification controls is influenced by these and other design and  operating variables.   Typically
larger percent NOX reductions apply to boilers with higher baseline  NOX levels and boilers burning
high-volatile-content coals.

      All these combustion controls utilize  staging of combustion air, fuel, or both  for NOX
reductions estimated to range from  15 to 65 percent.  The lowest reduction potential is for OFA

                                            4-3
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which  has some important limitations in the degree  of combustion  staging and first  stage
stoichiometries.  Because OFA utilizes a large portion of the entire firebox volume to obtain the
needed separation between first and second stage, unburned carbon in the flyash and CO emissions
can be significant if excessive (greater than 25 percent) OFA is utilized, especially when burning
high-rank bituminous coals. Waterwall corrosion is also a significant concern in the retrofit of OFA
for high-sulfur coal- and oil-fired boilers. The potential for increased corrosion rate can be reduced
by several approaches. One such approach for wall-fired boilers uses curtain air introduced from
the furnace hopper so that an oxidizing environment  is maintained near the waterwalls.  For
tangential boilers, some of the combustion air is diverted away from the center of the furnace
toward the waterwall to prevent exposure of furnace tubes to reducing conditions that cause H2S
formation.

       Because  of recent  advances  in  LNB  technologies  offered  by  most  major boiler
manufacturers, LNB is often the preferred low-NOx option for both new and retrofit units.  One
technology vendor has claimed that when combined with OFA, LNB can reduce NOX from coal-
fired utility boilers to levels approaching 160 ppm (0.21 Ib/MMBtu) (Vatsky, 1991).  However, full-
scale  experience  at such low  NOX levels  is limited, and has  shown significantly more modest
performance.  Reburning with natural gas or coal can achieve significant NOX reductions, reported,
as high as 65 percent  for pre-NSPS wet-bottom and cyclone units. Although  applicable to most
boiler  designs, reburning is primarily  targeted for the cyclones and wet-bottom boilers  that are
difficult to control by other combustion methods.  Commercialization of this promising technology
in the U.S. awaits the  results of long-term testing at the five ongoing demonstrations described in
Section 4.1.4.

        Table 4-2 compares controlled NOX levels  estimated for the NESCAUM major boiler
categories of pre-NSPS vintage with controlled NOX levels reported in the literature.  As the
footnote  indicates, details of  these reported controlled levels  are given in  Appendix D.   The
comparison is made with data reported on a short-term or long-term basis and with two broad
categories of coal type:  low volatile with an FR equal or greater than  1.5, and medium to high
volatile coal with an FR lower than  1.5.   As discussed earlier, these are important distinctions
because they affect the NOX levels that can be achieved and maintained by a  utility boiler over a
specified period of time under  routine  load dispatch, fuel mix, and operating practices. Long-term
refers to  data reported in the literature averaged over a 30-day period or longer.  Some important
aspects of this comparison are discussed below.

       NOX controlled levels estimated for NESCAUM T-fired boilers  following the retrofit of
LNB + SOFA  are  in  the  range  of 0.30  to 0.45 Ib/MMBtu.   The  upper level of this range,
0.45 Ib/MMBtu,  compares favorably with NOX levels reported with low volatile coals under long-
term operation.  However, the lower level in the range, 0.30 Ib/MMBtu, compares more favorably
with higher volatile coals under either short or long-term performance evaluation. As noted earlier,
lower NOX levels under staged combustion conditions are more likely with high volatile coals than
with higher rank low volatile bituminous coals. Furthermore, long-term performance is generally
more difficult to attain because it encompasses boiler operation under a variety of boiler loads and
other operating  conditions that can  significantly affect NOX emissions.  Short-term  testing is
normally taken to mean boiler operation under well controlled and supervised operation over a
period of a few hours.

       The controlled NOX levels estimated for LNB + OFA for single- or opposed wall-fired boilers
range between 0.35 to  0.55 Ib/MMBtu. This range corresponds to a drop of about 40 to 60 percent
from the average baseline level of 0.95 Ib/MMBtu.  The reported data for this type of low-NOx
application are sparse as will be discussed later in this section.  However,  it is clear that the upper

                                           4-5
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range of 0.55 Ib/MMBtu compares favorably with short-term data taken at one facility burning
eastern bituminous coal, recently reported by Southern Company Services, Inc. (Sorge, 1992).  The
lower end of the range compares with a level obtained at one facility burning high volatile coal. As
will be discussed later, much more experience exists with LNB only for wall-fired boilers than  with
LNB+OFA.

       The following sections provide a brief summary of the status of these technologies and
reported retrofit performance.

4.1.1   Overfire Air (OFA)

       OFA was one of the first control technologies evaluated by boiler  manufacturers  and
regulated utilities.  OFA, by itself, generally offers  modest NOX reductions with potential for
significant operational impacts.  In this approach, OFA ports are installed in the furnace above the
top row of burners. The existing windbox is either extended or a separate OFA ducting is installed
to provide secondary OFA to these new upper furnace ports.

       For pulverized-coal units, OFA is applicable to both corner-fired and wall-fired (front and
opposed) boilers.  For tangential boilers, ABB-CE distinguishes OFA between two configurations:
CCOFA and SOFA (Towle, 1991). A third OFA configuration combines the two OFA systems used
under advanced low-NOx burner configurations discussed in the next section. OFA is not applicable
to cyclone boilers and other slagging furnaces because combustion staging will alter the heat release
profile significantly changing the slagging rates and properties of the slag.  Many of the post-NSPS
tangential boilers come equipped with CCOFA  ports.  Newer OFA designs that increase  the
penetration of air into wall-fired furnaces for improved second-stage burnout under deeper staging
are often referred to  as AGFA, and have separate ports with a separate windbox located above the
main burner windbox.

       There are two principal design requirements for the retrofit of OFA ports in an existing
coal-fired boiler furnace.  First, there must  be sufficient  furnace  volume above the top row of
burners to provide adequate residence time of the first stage gases for NO reduction to N2 and
adequate residence time of the second stage gases prior to exiting the furnace to achieve carbon
burnout (Lisauskas, 1988; LaRue, 1990). Often, sufficient distance  between the  top burner and the
furnace exit is  not available to achieve the ideal 0.8-second residence time (Lisauskas,  1988).  The
amount of residence  time needed for maximum NOX reduction is dictated by overall kinetic rates
of reactions at the furnace  temperature, and the gas  composition.  This often necessitates a
compromise in NOX reduction performance.

       The second requirement is that the OFA must be effectively mixed with the first stage gases
to ensure complete combustion.  This effective mixing cannot be simply achieved by high rate of
OFA addition  since low O2 levels must be maintained to minimize the dry gas heat loss from the
boiler. The high OFA velocity needed for good mixing requires installation of several ports, which
can affect the structural integrity of the furnace. For example, access to the OFA injection location
may require the reconfiguration of the boiler structural support. Also, penetration into the furnace,
due to the installation of air ports, may result in structural weakness of the boiler tube panels.

       Generally, the OFA ports are designed to allow 20 to 30 percent of the total air injected in
the furnace (Lisauskas,  1987; LaRue, 1990; Wilson, 1990). There  are practical limitations to this
quantity of OFA.  First, excessive OFA can result in an increase in  unburned carbon (UBC) in the
flyash and increased emissions of CO, both are measures of loss in combustion efficiency. Data on
reported loss in combustion efficiency are presented in Section 7. Excessive UBC in flyash can  also

                                           4-7
-------
affect the ability to sell flyash for use in cement production. For several utilities that currently
follow this practice, the inability to continue to sell the flyash would result in a significant financial
penalty. Increasing coal fineness can offset the effect of OFA on UBC. But increasing fineness can
require replacing the pulverizers or making modifications to  the classifiers.   Modification  to
classifiers can reduce the capacity of the existing mill resulting in a derate of the boiler.  Second,
excessive OFA can  cause too low first stage stoichiometries which can lead to localized reducing
conditions near furnace waterwalls with increase in waterwall slagging, corrosion  and tube failure
rate. Curtain air is used in some boilers to counter the potential detrimental corrosion effect of
OFA or other air staging techniques.

       Installation  of OFA  requires retrofit of OFA ports, modification of the combustion air
ducting, addition of airflow dampers to control the  amount of air in the primary and secondary
combustion stages, and improved combustion control system. The retrofit of OFA ports necessitates
the replacement of waterwall panels. The OFA ports for tangential units are typically equipped with
directional vanes that,  along with burner tilt,  are  used for better control of combustion and
superheater steam temperature at variable boiler loads.

       Retrofit of  the  technology generally results in  a loss in combustion  efficiency  due  to
increased unburned carbon in the flyash and increase in excess oxygen level. For example, efficiency
loss with 27 percent OFA on one retrofit tangential boiler was reported at 0.4 percent (Thompson,
et al., 1989) due to an increase of 1 percent  in excess oxygen.  Additional  efficiency loss due to
unburned carbon in the flyash could further decrease the overall thermal efficiency. For example,
a 2-percent  increase in UBC for a  13,000 Btu/lb coal with  14 percent ash  translates into a 0.4-
percent loss in combustion efficiency  and an equivalent increase in fuel consumption.  Carbon
burnout is sensitive to changes in  combustion  conditions, and increases in UBC due  to staged
combustion, LEA, or LNB are likely. For some older boilers, however, these losses in efficiencies
could be partially offset by improvements in overall combustion air management and air infiltration.
OFA alone frequently does not offer sufficient NOX reductions to be a viable NOX control technique
for some eastern bituminous coals because of negative  impacts of excessive UBC and potential
accelerated furnace corrosion.

       The NOX reduction efficiency for OFA is estimated to range between  15 and 30 percent for
pre-NSPS boilers.  However, there is little full-scale retrofit experience to support these  reduction
efficiencies.  Recent tests at  the Hammond Unit 4 show NOX reduction efficiencies of 18 percent
over the long term and up to 30 percent for short-term tests at certain boiler loads (Sorge,  1992).
Post-retrofit  NOX  levels from these boilers are anticipated to  be in the range of 0.40  to
0.50  Ib/MMBtu, for T-fired units, and 0.70 to 0.80 Ib/MMBtu, for wall-/opposed-fired units. These
controlled levels are calculated based on the average baseline emissions of 0.60 Ib/MMBtu for pre-
NSPS T-fired dry-bottom boilers and 0.95 for pre-NSPS W-fired dry bottom boilers; see Table 3-4,
and  estimated reduction efficiencies  in  Tables 4-1  and 4-2.   Boilers with significantly higher
uncontrolled NOX will likely  not achieve these targets. NOX reductions of 0.40 to  0.50 Ib/MMBtu
are estimated for the only PC wall-fired post-NSPS boiler in the NESCAUM region with a current
baseline of 0.55 Ib/MMBtu.  These estimates are highly speculative because no data are available
to confirm the ability of post-NSPS boilers to achieve these  NOX levels without retrofit of newer
generation burners.

4.12  Low-NO., Burners (LNB)
       Since the first application of OFA in the 1970s, the major boiler manufacturers in the U.S.
and Japan have realized that combustion staging with OFA ports is not the ideal approach to NOX
control from pulverized coal flames. The NOX reduction potential of OFA was initially limited by

                                            4-8
-------
several factors. Under staged combustion a significant fraction of the fuel NOX is from char nitrogen
oxidation. By operating the entire lower burner zone under substoichiometric conditions, the local
temperature is also reduced. This lower temperature  tends to liberate less of the nitrogen in the
first stage, consequently carrying more to the second stage where it can be  oxidized to produce
NOX.  Furthermore,  staging creates the potential for localized corrosion  and increased  carbon
carryover that can be a significant problem to boiler operators and utilities.  Installation of OFA
ports requires changes to pressure parts. The compactness of the boilers furnaces built in the 1960s
was another disincentive to further OFA development because of the space limitations imposed for
retrofit applications.  Extending the furnace or derating for additional gas residence time with OFA
applications can present a potential remedy  to compact furnaces.  However, furnace modification
and derating  are costly options.

       All major utility boiler manufacturers, here and abroad, have  successfully developed LNBs
that can  be used in new and retrofit applications. The controlled mixing of combustion air and
pulverized coal is at  the heart of all tangential and circular LNB designs.  By  imparting greater
separation of fuel and air in the near-burner region, LNBs take advantage of combustion air  staging
and lower peak temperatures that result from larger flame volumes to suppress both fuel NOX and
thermal NOX formation.  However, by far the greatest design accomplishment of LNB technology
has been the suppression of fuel NOX via well-controlled mixing while  maintaining satisfactory
combustion efficiency,  heat release profile, and  operational  flexibility.  A detailed engineering
analysis by experienced equipment vendors and  site  personnel  is necessary in order to match
off-the-shelf LNB  technology to existing boiler  equipment,  fuel characteristics,  and operating
requirements. Although most LNB retrofits have been successful, compatibility between specific
NOX targets and satisfactory boiler operation must rely on detailed site-specific analyses.

       The following two subsections briefly discuss the LNB technologies offered for tangential
and wall-fired boilers.

4.12.1  LNB for Tangential-Fired Boilers with CCOFA

       ABB-CE improved on its inherently low-NOx corner-fired burner design  by developing the.
Low-NOx Concentric Firing System (LNCFS). ABB-CE offers three levels of LNCFS equipment
for retrofit on existing T-fired boilers.  NEI-International Ltd., of Europe, also offers low-NOx
burners for T-fired boilers.  Each of these three  configurations offers CCOFA.  LNCFS II and
LNCFS III also offer SOFA above  the main  windbox, without  CCOFA  under LNCFS II
configuration. All three design types divert some of the combustion air toward the walls of the
furnace, further reducing the amount of combustion air in the center of the furnace while providing
some protection against waterwall corrosion.  Combined with clustering of coal and air nozzles,
various degrees of combustion staging  can be  realized while protecting waterwalls and achieving
efficient combustion.  Appendix C provides details of these LNCFS configurations.

       This section is limited to a discussion of LNCF Level I configuration because it is the only
one of the three that does not come equipped with SOFA. LNCFS II and LNCFS III, together with
other LNB systems that also come equipped with SOFA, are discussed in Section 4.1.3. Although
SOFA  is an integral  part of the  tangential  firing configurations, we  have  arbitrarily selected to
discuss these combined technologies under the heading  of LNB + OFA to compare various wall- and
tangential-technologies that use OFA introduced  at a  significant distance above the main  burner
zone.

       The retrofit experience with LNCFS I is minimal. Only two domestic applications have been
documented to  date.   The first of the  LNCFS I  applications was at the Utah  Power and Light

                                           4-9
-------
Hunter 2 (Kokkinos, 1985).  This post-NSPS 420 MWe boiler burning western bituminous coal
achieved a 30-day average NOX reduction of 33 percent to 0.41 Ib/MMBtu.  More recently,
LNCFS I is being evaluated at the Georgia Power's Lansing Smith 2 (Hardman, EPRI 1992;
ICTTE, 92). As of this writing, test data are not available for Lansing Smith 2. The performance
of this pre-NSPS boiler burning bituminous coal will be more representative of the anticipated
performance for this burner system for NESCAUM T-fired units. ABB-CE projects LNCFS INOX
reduction performance in the range of 25 to 32 (Grusha, 1991).  In Europe, LNCFS  offered by
NEI-International Ltd. was retrofitted on Fiddlers Ferry Unit 1 of Powergen in England.  The boiler
has routinely achieved 35-percent NOX reduction throughout the boiler load range, with improved
furnace conditions (Jones,  1992).

4.1.2.2 LNB for Wall-Fired Boilers

       For wall-fired boilers, single wall or opposed burner configurations, FWEC, B&W, and Riley
Stoker in the U.S., Babcock Hitachi (BHK) of Japan, and Burmeister & Wain Energy (BWE) of
The Netherlands have  introduced and  installed several LNB  with  proven NOX  reduction
performance of about 35 to 55  percent. Table 4-3 lists a number of LNB retrofits for wall-fired
boilers.   The  information includes both  pre-NSPS and post-NSPS units as well as reported
performance for short and long term tests with a variety of coals and LNB designs. FWEC provides
two commercial LNB designs: the CF/SF and IFS. Retrofit of these burners have shown a range
in difficulty of retrofit and NOX  reduction performance.  Although several retrofits  have been
successfully implemented,  more  recent applications  at  GPC Hammond  Unit 4  (Sorge, 1992),
PENELEC Homer City  Unit 2 (Manaker,  1992),  and PSC Cherokee Unit 3 (Hunt,  1992) have
illustrated both the sensitivity of operation and NOX performance to the adequate control of air/fuel
distribution, combustion air velocity and cooling, primary air/fuel ratio, and pulverizer performance.

       Figure  4-1 illustrates FWEC reported performance of the CF/SF and IFS designs offered
for wall-fired boilers.  The plot is for NOX levels achieved  with FWEC LNB versus burner zone
liberation rate, a measure of the combustion intensity in the  near burner zone. The plot  shows that
generally, the higher the liberation rate, the higher the uncontrolled and controlled NOX levels. The
black arrows describe the reduction in NOX achieved from full-scale boilers with the retrofit of the
CF/SF burner without the  use of OFA. The plot also shows that performance of the CF/SF LNB
was generally projected to be about 0.40 Ib/MMBtu and that the newer IFS design might  be capable
of controlled levels of 0.25 Ib/MMBtu based on these limited results. However, recent applications
of both these burner types  have not realized these performance levels, as illustrated in  Table 4-3.
                                                     •
       The B&W LNCB burner is designed for minimum retrofit cost to existing cell burner boilers.
The current LNCB demonstration is being conducted under DOE's CCT demonstration program.
The more commercial B&W LNB design, the DRB-XCL burner, has seen relatively good success
on at least two boilers. Other LNB retrofits include several foreign designer by Babcock Energy,
BWE, and  BHK.   Because the BWE burners do not use  a common windbox design, as is the
practice with U.S. boilers, the retrofit of this type  of burner will require  greater  equipment
modifications.  ABB-CE also offer LNB for wall-fired boilers. More recently, FWEC has also been
evaluating LNB prototypes for T-fired units.

       The retrofit of LNBs to  existing units often require no changes to pressure parts, meaning
that most LNB retrofits are  possible with  minimal modifications to the waterwall, significantly
reducing retrofit cost (Vatsky, 1991; Lisauskas, 1987). Significant modifications are often needed
to the windbox, however,  for improved  air distribution with changes in  the fuel ducting, and
pulverizer  adjustments.   Some  LNB designs  have  only minor increases  in pressure drops
necessitating minor changes  to the combustion air fans to  maintain furnace draft.  Excessive

                                          4-10
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                                                             4-12
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        (1)   800 MW Four Corners #4
        (2)  626 MW Pleasants #2
         0   275 MW Front Wall Fired
        (3)   360 MW Front Wall Fired
         •   525 MW Opposed Fired
               1.2
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     Single Wall Fired Units^

  Pre-NSPS Burner
(.-.-  -*-

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                                     (6)  CETF
                                     (7)  500 MW Opposed Fired
                                                                 ppjSosed Fired Units
                                             CF/SF Low NOx Burner

                                  CF/SF * Advanced OFA
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                           BURNER ZONE LIBERATION RATE
                                (10 3 Btu/Hr-Ft 2)
                                                               Coir
                                                 450
                                                  Fotttr WnttHf Entrgy Corp
                                                  lion i Environmental Sytttmt
          Figure 4-1. NOX reduction summary of FWEC CF/SF LNB (Vatsky, 1991)

increases in pressure drop can result in costly fan upgrades and higher operating costs.  One
additional concern with LNB retrofit for wall units is the increased flame length and potential flame
impingement on furnace waterwalls causing overheat, excessive slagging and tube failure.

       Some increase in UBC content of the flyash can also occur, as discussed in Section 7. The
amount of this loss will depend on the coal type (e.g., low volatile eastern bituminous coals will
result in higher combustion  efficiency losses)  and  the  degree of burner staging.  Figure 4-2
illustrates this dependency.  The data  in this figure were obtained from pilot-scale tests conducted
at the B&W combustion research furnace, but is indicative of full-scale UBC trends.  The data show
how NOX is  reduced  by lowering the stoichiometry at the burner.  A burner stoichiometry of 1.10
indicates 10  percent excess air. The Utah subbituminous coal, which has the highest volatile content
of the three coals used, has the lowest emissions.  Figure 4-2 also  shows that when burner
stoichiometry is reduced the unburned carbon in the flyash increases.  Unburned carbon in the ash
is an indicator of combustion inefficiency.   In these tests, the unburned carbon increased nearly
4 percentage points by reducing the burner stoichiometry from 1.3 to  1.10. Coals with low volatile
matter have  higher unburned carbon losses. Increasing the fineness of the pulverized coal can often
offset this efficiency loss.  Section 7 provides additional discussion on the potential effect of LNB
retrofit on UBC levels in flyash  and other combustible emissions.

       Overall, the performance of LNB retrofits on existing wall- and opposed-fired boilers has
shown a range in NOX reduction from about 35 to 55 percent with controlled  NOX levels in the
range of 0.40 to 0.64 Ib/MMBtu including both short- and long-term test results on all coals and
excluding retrofits on post-NSPS or new units.  Long-term test results on domestic pre-NSPS units
burning low  volatile bituminous coal are limited to Hammond Unit 4 and Colbert Unit 3  showing
a range in controlled NOX from 0.47 to  0.64 Ib/MMBtu.  Several retrofit difficulties have been
experienced  at GPC's Hammond Plant,  including burner fires  due to plugging and reduced air
cooling.  NOX reduction performance  was in  part  limited by low pulverizer fineness (about
                                          4-13
-------
                      600
                       200
                                 1 10       1 20       I 30
                                      Burner Stoichtometry
140
         Figure 4-2. Fuel effects:  XCL burner plus modified impeller (LaRue, 1989)
64 percent through 200 mesh) pointing to the need for auxiliary equipment upgrade with some LNB
retrofits.

4.13   Low-NOx Burners with Overfire Air (LNB + OFA)

       This section deals with the use of separate OFA in conjunction with LNB to achieve greater
NOX reduction efficiencies. The use of OFA with LNB dates back to the early 1970s, when it was
used by B&W and CE to comply with the early NOX NSPS levels (LaRue, 1990). The OFA proved
to be effective but for the most part unnecessary  to achieve regulated limits because of adequate
LNB NOX reduction efficiencies on new Subpart D and Subpart Da boilers.  Therefore, the use of
OFA ports was discontinued primarily for wall-fired boilers. Tangential units generally continued
the use of close-coupled OFA.  More recently, as newer regulations set lower NOX Limits, the use
of separate OFA ports with LNB is being reevaluated to augment the NOX reduction efficiency in
some retrofit applications.

4.1 J.I   LNB+SOFA for Tangential Boilers

       Table 4-4 lists LNB+SOFA applications for tangential-fired boilers.  In the United States,
there are ongoing demonstrations of LNCFS II  and  LNCFS III  burners for tangential boilers.
These recent burner designs by ABB-CE incorporate SOFA above the main burner zone to permit
additional combustion staging. The design configurations of LNCFS II and LNCFS III, along with
other LNB designs, can be found in Appendix C.  Domestic applications of these burner systems
have shown NOX reductions in the range of about 30 to 50 percent, depending on boiler load, fuel
type, and degree of staging.  Corresponding NOX  levels for tangential boilers ranged from 0.28 to
0.45 Ib/MMBtu.

                                         4-14
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       Additional LNB+SOFA configurations for tangential boilers include burners that have found
application primarily in Japan and Italy.  Two LNBs developed by MHI, the SGR and the PM, also
incorporate FOR to provide a more distinct separation between the fuel rich and fuel lean zones
of the burner. This separation is intended to enhance the degree of NOX control.  However, in the
United States, FOR has not been used in connection with these controls. The only demonstration
of this Japanese  LNB+OFA technology in  the United States is the PM burner retrofit at  KP&L
Lawrence Station. This retrofit did not use  FOR because pilot-scale tests sponsored by EPRI had
revealed little additional benefit from .the use of FOR (Tokuda, 1987).

       The performance of the PM burner  is heavily dependent on the amount of OFA as is the
case for  LNCFS II and LNCFS III burner systems.  NOX reductions to  as low as 100 ppm
(0.13 Ib/MMBtu) have been reported with Japanese high volatile coals (Tokuda,  1987; Nakabayashi,
1983). These extremely low-NOx levels are not deemed attainable with U.S. high-rank eastern coals
that have typically  higher fuel  ratios  (ratio  of fixed carbon  to volatile  matter from the  coal
proximate analysis), which reduces the effectiveness of combustion staging (Tokuda, 1987).

       Generally, NOX reduction performance for this combination of controls have been reported
to reach  as high as  55 percent for some tangential units.  For tangential units, controlled levels
below 0.3 Ib/MMBtu have been reported during short-term tests for several of these  retrofits at
selected loads and operating conditions.  The only two long-term (30-day average test period) tests,
both on the Lansing Smith Unit 2 boiler with LNCFS  II and LNCFS III, have shown more modest
performance in the range of 35 percent  reduction to about 0.45 Ib/MMBtu.  The SOFA on these
units was identified  as responsible  for most of the reduction in  NOX from baseline levels.  This is
not too surprising because the distance between  the primary burner zone and the SOFA parts
provide the longest residence time available between  the substoichiometric primary zone and the
SOFA level for  total fuel  nitrogen reduction to  N->.  Various tilt and yaw mechanisms on the
individual coal and air nozzles at each evaluation allow for combustion optimization for low-NOx,
combustion efficiency, waterwall protection, and steam temperature control.

4.132  LNB + OFA for Wall-Fired Boilers

       For wall- and opposed-fired boilers, the  CF/SF burner manufactured by FWEC has been
used in United States applications  in connection with  OFA. In  these systems, 10  to 20 percent of
the total air is diverted to OFA ports.  Table 4-5 lists two retrofits on pre-NSPS units, one burning
eastern bituminous coal and another burning western subbituminous coal.  All test data available
to date are short term and show a  controlled NOX level of approximately 0.35 to 0.55 Ib/MMBtu.
The controlled levels are as low as 0.33 Ib/MMBtu for higher volatile coals, and 0.54 Ib/MMBtu
for  a lower volatile eastern bituminous coal at the GPC Hammond Unit 4 demonstration project.
Also, it is important to note that this combination of controls has proven most effective on larger
post-NSPS furnaces or boilers originally designed  with OFA ports. As discussed in Section 4.1.1,
operation of pre-NSPS boilers with OFA causes operational problems and a loss of fuel combustion
efficiency.  In fact, this combination of controls has generally resulted in a significant  increase in
LOI especially in the most recent demonstration at the Hammond Plant.

       In summary, the data on LNB + OFA technologies are sparse, and limited to the most recent
demonstrations at Lansing Smith and the Hammond  Plant. Because tests on ongoing, additional
results are  anticipated to better define  the performance range.  However, it appears that, on a
short-term basis, tangential boilers burning  high-volatile coals may be able to achieve  NOX levels
as low as 0.30 Ib/MMBtu, whereas on a long-term compliance basis with eastern bituminous coals,
levels of 0.45 Ib/MMBtu  seem more appropriate. For wall-fired boilers, NOX Reduction projections
for  the NESCAUM population  of pre NSPS units are  more tenuous. The limited data suggest

                                          4-16
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controlled NOX levels as low as 0.35 for high volatile coals and 0.55  for lower volatile coals.
Although, higher NOX levels are projected for the Hammond Plant where long-term test data are
generated, optimization of pulverizer performance and other burner settings may provide solutions
to early  operational problems and  additional  reduction from  the current NOX  levels.  Boiler
efficiency losses for the LNB + OFA combination, at times excessively high, should be anticipated
as increases in both  LOI  and excess air levels have been reported.   NOX levels  as  low as
0.25 Ib/MMBtu for some foreign installations and for the PM burner at KP&L Lawrence  Station
are considered unlikely target levels for current LNB + OFA technologies because these levels reflect
performances obtained with high volatile levels on a short-term basis and with newer large furnace
designs.

4.1.4   Returning or Fuel Staging

       Reburning or fuel staging involves the  injection of fuel above the main burner zone to
destroy the formed NO by passing the primary zone gases through a flame (reburning) or through
a low oxygen  reducing zone in which NO can be reduced to N2 (fuel staging).   OFA  is then
introduced to complete combustion of the fuel-rich products leaving the reburning zone, and in so
doing, to bring the overall excess air in the normal range of 15 to 20 percent.  This OFA must be
introduced sufficiently downstream of the reburning fuel to provide the residence time needed for
the NOX reduction reactions to take  place while still completing combustion.

       The effect of reburning on NOX has been known for sometime. In repowering cogeneration
plants, for example, NOX emitted from the prime mover (e.g., a gas turbine) passes through a fuel-
fired boiler and is partially  destroyed such that the combination of the turbine and boilers NOX
emissions is less than if the units were fired separately.  In the fuel staging approach, the staged fuel
is used to create a localized reducing zone where the  NOX is reduced prior to the  addition of air
to fully combust the added fuel.

       Much of the developmental and implementation work for fuel staging techniques has taken
place in  Japan.   Mitsubishi Heavy  Industries  (MHI) has developed the Mitsubishi  Advanced
Combustion Technology (MACT) process, which is  reported to attain 50-percent NOX reduction
(Araoka, 1987 and Murakami, 1986).  The technology has been used in Japan on at least one large
600 MWe  PC boiler  and  several  oil/gas-fired units  in  connection with  LNB  operation
(Murakami, 1986).  B&W,  under license with BHK,  is offering the In-Furnace NOX  Reduction
(IFNR) process.   In the U.S.,  with the exception of the ongoing demonstrations identified below,
the technologies of reburning and fuel staging have not been commercially introduced for either new
or retrofit units  (EER, 1991).  However, this NOX  reduction  approach offers one of the few
potential control methods for  cyclone and wet-bottom (slagging) wall-fired boilers.

       Demonstrations are  underway to evaluate the retrofit potential and control performance of
fuel staging on five utility boilers, three cyclone units, one tangential boiler, and one wall-fired
boiler:

       •   Illinois Power, Hennepin  Station 71 MWe Unit 1 tangential boiler (Borio,  1991)

       •   City  Water,  Light and   Power,  Lakeside Station  33 MWe Unit 7 cyclone  boiler
           (DOE, 1991; EER, 1991)

       •   Ohio Edison,  Niles 108 MWe Unit 1 cyclone boilers (Brown,  1992)
                                           4-18
-------
       •   Public  Service  of  Colorado, Cherokee Station 158 MWe Unit 3 wall-fired boiler
           (HER,  1991)

       •   Wisconsin Power and Light, Nelson Dewey Station 100 MWe Unit 2 cyclone boiler
           (Yagiela, 1991)

The first four demonstrations use natural gas for the  reburning fuel (NCR), and the last uses
pulverized coal.  The reburn technology used in the first two demonstrations is combined with dry
sorbent injection (SI) for simultaneous NOX/SOX control. The demonstration of NGR at Cherokee
Unit 3 is not currently underway and will eventually be installed in combination with LNB for a
NOX reduction target of 70 percent.

       Because of its clean burning properties, natural gas holds better promise for a more efficient
reburning fuel for all boiler types. NGR is also relatively straightforward to retrofit and it has the
benefit of reduced SO2 emissions because of displaced coal.  One full-scale demonstration of NGR
on a tangential boiler has shown NOX reductions from 400 ppm to a range of 120 to 150 ppm with
a reburn zone stoichiometry of 0.9 (Bartok, et al., 1991). More recent results reported by May and
Kruger indicate  a constant long-term performance of 60 percent  reduction to 0.28 Ib/MMBtu
(200 ppm) with 18 percent  natural gas and a reburn stoichiometry of 0.90.  FGR is often used in
connection with NGR to enhance penetration and mixing of the natural gas in .the furnace.  The
performance of NGR on one cyclone boiler (Niles Unit  1) has shown NOX reductions in the range
of 46 to 48 percent over the long term to  levels on the order of 0.4 Ib/MMBtu (300 ppm), with
acceptable CO levels, and an overall efficiency loss of about 0.6 percent due principally to increased
flue gas moisture (Brown, 1992). The principal disadvantages of natural gas as the reburning fuel
are that it carries a significant fuel differential penalty, and it may not be economically feasible to
ensure an adequate and constant supply of this premium fuel.

       Pulverized coal as a reburning fuel has been evaluated at the Nelson Dewey Station with
considerable success.  A schematic of this retrofit, shown in Appendix C, illustrates the hardware
requirements, including the use of a high-efficiency  pulverizer.  Preliminary  results show  NOX
reductions  of 30 to 53 percent over the load range of the  boiler, with improved boiler thermal
performance because of reduced furnace slapping (Newell, 1992).  Contrary to NGR, reburning with
pulverized coal is considered limited in its application to cyclone units because these furnace designs
provide better residence times for pulverized coal to complete its combustion then would otherwise
be possible in wall and tangential boilers.

       In summary, these initial tests have shown that reburning has the potential to be an effective
control technology. However, long-term testing remains to adequately address control performance,
operational impacts, and commercial feasibility.

4.1.5   Retrofit Potential for the NESCAUM Boilers

       Table 4-6 presents estimates of the potential NOX reduction from coal-fired utility boilers
in the NESCAUM region. For this analysis, only the most common PC-fired boilers were included.
Other coal-fired designs, such as stokers and vertical or down-fired  units,  account for a minor
fraction of the overall coal-fired capacity, as discussed in Section  2. The estimates for systemwide
NOX reduction potential, shown on the far right of the table, were calculated as follows:
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           [Estimate of Control]    [Range in Percent NOX
NOX  J x  L  Applicability   J    \_ReductionEfficiency
                                                                                     (4-1)
For  example, current baseline levels for dry-bottom tangential coal-fired  boilers are  about
50,000 tons/yr (see  Figure 2-1).   For SOFA control, the retrofit applicability is estimated at
60 percent, and  the  NOX reduction  efficiency was  given in the range of 15 to 30 percent with
controlled NOX levels in the range of 0.40 to 0.50 Ib/MMBtu. Thus, the calculated NOX reductions
are as follows:

               (50,000 tons/yr) x  (0.6) x (0.15 to 0.30) = 4,500 to 9,000 tons/yr         C4'2)
where 15 to 30 percent is the estimated NOX reduction efficiency for the technology (see Table 4-1),
calculated from current average baseline emission factors for tangential boilers (see Table 3-3) and
controlled NOX levels reported in the literature.

       The calculation of systemwide NOX reduction potential includes the estimate for applicability
of the retrofit technology to the existing boiler population.  Although all boilers can theoretically
be retrofitted with some combination  of these controls  (e.g., most  dry-bottom units can  be
retrofitted  with LNB, whereas far  fewer  wall  fired boilers  can  utilize  OFA without  adverse
operational impact), site-specific constraints can make the retrofit of some technologies impractical
or much less attractive than others.  For example, OFA may not prove a viable option for some
boilers because of space constraints due to structural interferences and furnace access; small furnace
volume, resulting in severe limitations to the amount of OFA introduced, and, thus, NOX reduction;
and poor steam temperature control, resulting in significant energy  penalties.  Tangential boilers
built after the 1971 NSPS, and especially those built after the 1978 NSPS, were generally equipped
with OFA.  Because all the PC-fired boilers in that age group were introduced in the last 10 years,
it is very likely  that these  units already have OFA.   Therefore, the retrofit of  OFA cannot  be
credited for this boiler design in this age group.

       In the case of gas reburning, access to natural gas, and long-term gas supply contracts, will
dictate the viability of this control option for  all coal-fired boilers, including cyclone units.

       The retrofit of LNB with or without OFA can be quite expensive in cases where access to
indoor boilers is impossible without  significant demolition  and reconstruction, coupled with the
replacement of a substantial portion of the coal pipes, furnace, windbox, ducting, fans, and control
system.   In addition, retrofits of older facilities can become more complicated when asbestos
removal is  necessary.

       Estimates by EPRI put the percentage of the retrofit capacity for low-NOx burners at about
50 to 80 percent, depending on firing configuration and boiler manufacturer (Miller,  1985).  It is
clear that a  significant  portion of the  most  recent  boiler population  of tangential-, wall-, and
opposed-fired units can  be retrofitted with today's low-NOx burners. LNB technology represents
the retrofit NOX control method most accepted by the utilities, especially if it can be accomplished
with minor modifications to the furnace, windbox, and auxiliary equipment.  This is often not the
case for older units because the existing windbox  and auxiliary equipment may require upgrade  or
replacement to ensure adequate operation and performance. Typically, smaller and older units may
be less  capable  of utilizing  this and other low-NOx  technologies without significant equipment
upgrade.

                                           4-21
-------
       Therefore, we selected a retrofit applicability factor of less than 100 percent for each retrofit
control technology to estimate the systemwide NOX reduction potential. The applicability factor was
estimated to vary between 50 and 80 percent for all control technologies, as in the EPRI estimate.

       This information, together with the estimated baseline and controlled emission levels for
each control application, resulted in estimates of the total NOX reduction potential, shown in the
far right column of the  table.  For example, OFA retrofitted to about 3,000 MWe of applicable
tangential-, wall-, and opposed-fired boiler capacity is estimated to achieve 10,000 to 17,000 tons/yr
of NOX reduction.  LNB retrofit for dry-bottom units is estimated to contribute the highest  NOX
reduction with a target coal-fired retrofit capacity of about 5,800 MWe and NOX reductions reaching
42,000 tons/yr. The range in NOX reduction potential calculated for each boiler design/NOx control
combination is  due to variations  in the NOX reduction efficiencies estimated for each control
technology as shown in Table 4-1 and in Appendix D.

       Figure 4-3 illustrates the NOX reduction  potential  for coal-fired boilers based on  three
combustion control retrofit scenarios.  The first scenario is based on the retrofit of 80 percent of
the current dry-bottom, PC-fired tangential-, wall-, and opposed-firing capacity with LNB.  The
second scenario assumes retrofit capability of 50 to 60 percent for LNB + OFA on these same units.
The third scenario adds the retrofit of 80 percent of cyclone capacity with 50-percent retrofit of wet-
bottom boilers with reburn technology. The baseline NOX emissions from all coal-fired boilers are
about 200,000 tons/yr in the NESCAUM region.  This level can be reduced  to  approximately
155,000 to  168,000 tons/yr using LNB-based  combustion modification controls.  For comparison,
NOX emissions  reductions achieved with LNB + OFA  are slightly lower than  those achieved with
LNB only, because of the reduced estimate of retrofit capability assigned to OFA. With the added
control of wet-bottom and cyclone units with reburn technology, systemwide NOX emissions  from
coal-fired boilers are  estimated to be controlled to a range  of 127,000 to  147,000 tons/yr  from
current baseline levels of about 200,000 tons/yr.

       The estimates of NOX reductions from these units are offered only as guidelines to illustrate
the capability of existing control technologies on a NESCAUM region-wide basis.  The results are
heavily  influenced by  the assumption  used for the applicability of  NOX controls to the  existing
population of boilers  in the NESCAUM region.  More definitive control levels  require detailed
site-by-site specific analyses of the retrofit potential,  actual baseline emissions, and current and
future fuel use practice and capacity factors.

42    COMBUSTION  CONTROLS FOR OIL- AND GAS-FIRED BOILERS

       The modification of combustion in full-scale, gas-, and oil-fired utility boilers can result in
significant  NOX reductions, at times reaching 90 percent from  uncontrolled  levels. Combustion
modification controls for these boilers have been implemented since the early 1970s, primarily in
California.  Utility boilers operated  by SCE, Los Angeles Department of Water and  Power
(LADWP), San Diego Gas and Electric (SDG&E), and Pacific Gas and Electric (PG&E) have been
retrofitted with  a variety of single and combined techniques to  produce controlled NOX levels in the
range of 42 to 255 ppm at 3 percent O2 (0.053 to  0.323 Ib/MMBtu). The low range of  emission is
normally associated with natural gas firing. The 42 ppm level  was achieved from SCE Scattergood
Unit 3 which had an initial NOX level in excess of 1,000 ppm when introduced in the mid- 1960s and
was retrofitted with a  combination of FGR, and derate (Pepper, 1987).

       Following a period of low retrofit activity, new efforts are again underway in California to
optimize existing combustion controls and  introduce new technologies.  These  efforts  are in
response to the.recent passage of the  South Coast Air Quality Management District (SCAQMD)

                                           4-22
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Rule 1135, which will ultimately require controlled NOX levels as low as 23 ppm (0.03 Ib/MMBtu,
0.25 Ib/MW-hr) in 1999.  Because of these past retrofit efforts there is a wealth of technology and
retrofit experience that is directly applicable to the NESCAUM oil- and gas-fired units.  Although
NOX reduction successes similar to those of the SCE, LADWP, and PG&E utilities cannot be
guaranteed (for example, fuel oil  properties, such as fuel  nitrogen content, may be  different)
significant reductions in NOX are possible.

       The control of NOX from oil and gas fuel combustion relies on the suppression of both fuel
and thermal NO with a combination of techniques that stage the combustion  and reduce peak
temperatures.  The applicable TSC techniques are BOOS or biased burner firing and OFA ports.
FGR to the windbox is a very effective NOX reduction technique for these fuels,  especially natural
gas.  FGR becomes less effective  when the nitrogen content of the  fuel oil is high, e.g., when
burning residual oil.

       BOOS, FGR, and OFA are by far the most popular retrofit NOX control techniques for gas-
and oil-fired utility boilers.  The recent demands for  additional NOX  reductions from California
utility boilers to levels well  below 100 ppm  are shifting attention to LNB  and postcombustion
technologies (Mansour, 1991).  New LNBs are being evaluated often not as a replacement for the
other controls but as  additional combustion modifications  needed to-stabilize  the combustion,
minimize furnace vibration, and reduce particulate emissions when higher FGR and OFA rates or
additional BOOS are implemented to attain  NOX reductions. In general, there is little experience
on the LNB capabilities as stand-alone control methods for oil- and gas-fired boilers.  Japanese
boilers manufacturers have adopted coal LNB technology to oil and gas burning.  Industrial-size-
burner manufacturers are also introducing utility oil- and gas-fired LNBs. Another technique that
has received some exploratory  research, but has  no current U.S.  application, is the  IFNR, or
reburning.

       Table 4-7 summarizes the performance and hardware modifications for applicable NOX
combustion controls.  The  table  reports percent NOX reduction efficiencies  published in the
literature, and estimates of controlled  NOX levels  associated with these reductions.   The
appropriateness of these NOX reduction efficiencies to the NESCAUM boiler population depends
heavily on fuel characteristics, degree  of control, and current uncontrolled NOX levels. Because
several of the gas- and oil-fired boilers in the NYPP are currently equipped with some combustion
controls, average  baseline emissions are  already low, and the percent NOX reduction shown in
Table 4-7 are likely to be inflated for the  NESCAUM boiler population as a whole. Consequently,
estimates of  controlled  NOX  levels  have been adjusted  upward  to reflect more reasonable
performance targets corresponding to uncontrolled boilers. Because of boiler design constraints and
fuel properties, some boiler  with currently high baseline levels exceeding 1.0 Ib/MMBtu may be
unable to achieve some of these NOX control targets without the retrofit of several controls, fuel
switching, and possibly derating. The following subsections discuss the NOX reduction performance
and utilization status of these controls. Appendix D provides details on the reported NOX reduction
performance and controlled  limits for oil-/gas-fired boilers.

42.1   Burners Out of Service (BOOS)

       A common low-cost operational modification for gas- and oil-fired boilers with  moderate
to high NOX reduction efficiency is  biased firing and BOOS.  Biased burner firing consists of firing
the lower rows  of burners more fuel  rich  than  the upper rows of burners.   This may be
accomplished by maintaining normal air distribution to the burners while adjusting fuel flow so that
a greater amount of fuel enters the furnace through  the lower rows  of burners. Additional air
required for complete combustion enters through the upper rows of burners which are air-rich. In

                                           4-24
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the BOOS mode, individual burners, or row of burners, admit air only.  This reduces the air flow
through the active burners, thereby creating fuel-rich and fuel-lean zones that lead to reduced NOX
emissions.  These techniques are  often described under the common heading off stoichiometric
(O.S.) combustion.

       These techniques are equally effective for oil- and gas-fired boilers in controlling both fuel
and thermal NOX.  BOOS and biased firing are attractive first level NOX control retrofit because
few, if any, equipment modifications are required. Both techniques were used quite extensively on
both wall and tangential boilers in the early stages of utility NOX controls in Southern California.
For example, 24 SCE units are currently controlled with a combination of BOOS, NOX ports (OFA),
and FGR. BOOS has also been used quite extensively in the Consolidated Edison system where
many gas- and oil-fired boilers produce both electricity and steam.  Con  Edison has estimated an
overall reduction potential due to  O.S. of 30 percent to controlled NOX emissions in the range of
0.20 to 0.35 Ib/MMBtu based on direct  retrofit experience with BOOS and NOX ports (Mormille,
1991).  Other NOX reduction estimates have been in the range of 35 to 45 percent (Hunter, 1989)
and 35 to 55 percent (Lim, 1980).

       The actual percent reduction that can be realized depends on the initial NOX levels, i.e., the
higher the uncontrolled NOX the higher is the potential for large reductions due to O.S. combustion.
The current  NOX levels  from pre-NSPS  tangential-  and wall-fired boilers average 0.24 and
0.52 Ib/MMBtu.  Estimates  of controlled levels in  the range of 0.25 to 0.35 would  translate to
reductions of 0 to 33 percent. In reality, individual boilers will exhibit  significantly higher or lower
NOX reductions based on current baseline conditions.

       Although large NOX reductions can be achieved with BOOS, the operational performance
of the boiler is generally somewhat degraded because of the need to increase excess air to keep CO,
hydrocarbons, and smoke emissions in check.  Some limitations in the degree of staging may also
result from difficulty in steam temperature control  and restrictions on load following capability.
Because flame stability problems can also result, care must be taken  in selecting the  appropriate
BOOS and on the degree of staging at each of the remaining burners in service.

422   Flue Gas Recirculation (FGR)

       FGR for NOX control consists of extracting a portion of the flue gas from the  economizer
or air heater outlet and  returning it to the furnace, admitting the flue  gas  through the burner
windbox. FGR lowers the bulk furnace gas temperature and reduces  the concentration of oxygen
in the combustion zone. FGR is also referred to as windbox FGR (WFGR) to distinguish it from
FGR through the hopper or  above the windbox, which is used primarily to control of superheater
steam temperature at variable boiler load.

       In California, WFGR has been used effectively on utility oil- and gas-fired boilers to achieve
significant reductions  in  NOX on the  order of 40  to 65 percent (Lim, 1980).   The amount of
reduction varies with the amount of gas  recirculated (i.e., degree of control): Figure'4-4 illustrates
the effectiveness of WFGR based on the California experience. This experience is based primarily
on "clean" fuels (natural gas  and low nitrogen  distillates), which are more conducive to high NOX
reduction performance compared  with heavier grade oils.  This is important when applying these
results to the NESCAUM boilers.  Highest NOX reductions are achieved  on natural gas fuel. The
low range of NOX reduction efficiency is associated with oil combustion. WFGR is generally much
more effective in reducing NOX when natural gas is being burned.  The range in NOX reduction
depends also on the percent WFGR (typically 20 percent of the total flue gas or less) and the initial
NOX levels.  In  New York State, the Niagara Mohawk Oswego Unit 6 and Orange and Rockland

                                           4-26
-------
                               80
120      160      200
Initial NOx, ppm
240
280
 Figure 4-4. NOX control effectiveness of 20 percent WFGR versus initial NOX level for gas and
            oil fuels (Mormile, 1991)
Utilities, Inc., Bowline Unit 2  are already equipped with  FOR.  Baseline levels of 0.21 and
0.27 Ib/MMBtu reported for these units (see Appendix B) are based on the use of WFGR.

       Sometimes,  the technique is used in connection with many low-NOx burner designs to
achieve very high NOX reductions on the order 60 to 70 percent. For example, the MHI PM burner
uses FOR to achieve a separation between the fuel jets and the  secondary air, ensuring sufficient
time for NOX reduction during staging. When  using OFA, WFGR can be used to control the
superheater steam temperature caused by the lowering of the peak combustion temperature in the
furnace.

423   Overilre Air (OFA)

       OFA is generally not a preferred retrofit control for oil- and gas-fired boilers because BOOS
can offer similar NOX reduction efficiency at a fraction of the cost.  Also, high heat release furnaces,
built from the late 1950s to the first NSPS, are  generally not suitable for retrofit of OFA ports
because the furnaces are small and there  is insufficient volume above the top  burner zone  to
complete combustion.  With some units it becomes necessary to derate and modify  the superheater
tube bank to minimize changes in the heat absorption  profile of the unit.

       The experience with OFA ports on oil-/gas-fired units can be considered limited. However,
some units in California have been retrofitted with OFA ports.   NOX reduction  efficiencies for
California utilities have been reported to average 24 percent for  oil and nearly 60  percent for gas
(Lim, 1980). Generally, OFA is used in conjunction with other controls such as WFGR and BOOS.
                                          4-27
-------
Potential NOX reductions are similar to those achieved with BOOS. Operational performance losses
similar to BOOS are also encountered (Lim, 1980).

4.2.4   Low-NOv Burners (LNB)
              'x
       There are few LNBs for gas- and oil-fired units, and there isJittle experience with those that
are considered commercially available. Because many of the O.S. combustion techniques, such as
BOOS and WFGR, have been exploited to the  maximum extent possible by utilities subject to
stringent NOX standards, there is renewed interest in the demonstration of oil- and gas-fired LNB
technologies.  The concept of LNB  is appealing because it can avoid some  of the operational
performance losses associated with BOOS and OFA. As mentioned before, LNB is currently used
primarily in conjunction with other controls. There is little documentation  on  the NOX reduction
potential for this technology by itself.

       Table 4-8 contains a partial list of oil- and gas-fired LNBs that are commercially offered and
some known applications and demonstrations. Note that several of these applications combine LNB
with other controls such as OFA and FOR.  NOX reductions obtained at Fusina in Italy should be
considered with caution because this boiler in primarily a coal-fired unit with multiple fuel firing
capability.  Consequently, NOX reductions obtained on  this unit cannot be considered as widely
applicable to oil-/gas-dedicated units, which  are, by design, more compact and have a different heat
release profile.  Recent results of a  low-NOx burner system retrofitted on New England Power
(NEP) Salem Harbor, 435 MWe  Unit 4, showed NOX reduction from 0.6 to 0.34 Ib/MMBtu during
short-term tests with oil firing (Afonso, 1992). Tests with one row of BOOS prior to LNB retrofit
also showed similar NOX reduction  performance.  Other burner manufacturers also have LNB
technology, but limited information is available on these other designs.  Overall,  LNB has been
applied sparingly on gas- and oil-fired U.S. boilers; estimates for NOX control performance for LNB
alone range from 20 to 50 percent based  on the recent NEP retrofit experience.

42JS   Combined FGR, OFA and LNB

       The largest NOX reductions can be obtained with  a combination of retrofit technologies and
operational modifications. The combination of WFGR, O.S., (with OFA ports or BOOS), and LNB
provides significant reductions from  uncontrolled levels. The current experience for these retrofit
combinations is limited to the California utilities where NOX levels were reduced to the current
limits of 42 to  225 ppm (about 0.05 to 0.3 Ib/MMBtu) from uncontrolled levels of as  high as
900 ppm (McDannel, 1991 and Bayard DeVolo, 1991). It should be recognized, however, that  the
low end of these emissions were obtained with natural gas. Similar performance with other fuels
cannot be expected.  Other tests with a combination of FGR and OFA at reduced boiler load have
shown NOX reductions in  the range of 60 to 85 percent (Lim, 1980). It should  also be recognized
that these high NOX reduction efficiencies are only likely on boilers with initially very  high baseline
emissions (greater than 1.0 Ib/MMBtu).

       NOX reduction performance and controlled limits are supported by retrofit results on several
utility boilers in Southern California.  NOX levels as low as  0.06 Ib/MMBtu based on short-term
(0.10 Ib/MMBtu  for  long-term)  were  reported  for  gas  firing  (Bayard  DeVolo,  1991)   to
0.20 Ib/MMBtu, for several retrofits in the SCE, LADWP, SDG&E systems (Bisonett, 1991; Bayard
DeVolo, 1991), and at the  Kahe Station of Hawaiian  Electric Co. (Kerho,  1991).   These NOX
control levels can often be matched by the performance of TSC (OFA or BOOS) with  FGR without
LNB retrofits.
                                          4-28
-------
            Table 4-8.  Partial list of gas- and oil-fired Iow-NOx burner applications
Burner
Type
STS'

ASRe
LNCFS
PG-DRBb
ROPM

PM°
Dynaswirl



DRB
XCL
RV
TTL-50
Manufacturer
Riley/Deutsche
Babcock

Riley/Deutsche
Babcock
ABB-CE
B&W and BHK
ABB-CE and
MHI

ABB-CE and
MHI
Todd



B&W
Rodenhuis and
Verloop
Retrofit Applications
Wall-Fired Boilers:
Arzberg Power Station 220 MWe Unit 6 in
Germany
Vartan Power Station 250 MWe in Sweden
More than 520 MWe retrofitted in Europe
Germany: Several boilers
U.S.: Industrial units
Corner-Fired Boilers:
ENEL Fusina 160 MWe Unit 2 in Italy
(primarily a coal-fired boiler)
Hawaiian Electric Co. Kahe 146 MWe.
Evaluated for retrofit on LADWP boilers
No installation in U.S.; for wall-fired
boilers

No installation in U.S.; several in Japan
for tangential boilers
SCE Osmond Beach Unit 2 and Alamitos



Italy: ENEL Brindisi Sud Unit 2
No U.S. known retrofits to date. Recently
introduced
Salem Harbor Unit and Brayton Point
Unit 4
Reported
Performance
0.06 Ib/MMBtu for gas
0.2 Ib/MMBtu for heavy oil

50% NOX reduction with
natural gas to about
0.13 Ib/MMBtu. Heavy fuel
oil to about 0.22 Ib/MMBtu.
50-60% NOX reduction with
OFA. Controlled levels
reported were 0.14 Ib/MMBtu
for oil and 0.06 Ib/MMBtu
for gas.
NOX reduced to below
0.23 Ib/MMBtu with OFA
and FGR
25-50 percent NOX reduction
projected from controlled
levels to 0.06 to 0.08
Ib/MMBtu for natural gas
and 0.12 to 0.17 Ib/MMBtu
for oil
40-50 percent NOX reduction.
Controlled NOX levels same
as ROPM
Up to 93 percent NOX
reduction when combined
with BOOS and FGR to 0.03
to 0.04 Ib/MMBtu at partial
load and 0.04 to 0.08
Ib/MMBtu at full load
NAd
More than 40% reduction to
less than 0.35 Ib/MMBtu on
oil
References
Lisauskas,
1991

Oppenberg,
1986
Tarli, 1991
Bisonett,
1991
Kerho, 1991
Pepper, 1987

Pepper, 1987
Bayard
DeVolo,
1991


LaRue, 1989
Afonso, 1992
*STS = Swirl Tertiary Separation.
bPG-DRB = Primary Gas-Dual Register Burner.
°PM = Pollution Minimum.
dNA = Not Available.
eASR = Axial-Staged Reburn.
                                              4-29
-------
42.6   Reburning

       Reburning for NOX control on oil- and gas-fired boilers has received little evaluation in this
country. Although technically feasible, the technology is not considered commercial for oil and gas
or likely to achieve that status in the near future.  The  NGR demonstration at Hennepin Station
has included tests with natural gas as the primary fuel instead of pulverized coal. This short test
demonstration also showed significant reductions. However, because the boiler is designed to burn
coal (its furnace is larger  than an equivalent oil-/gas-burning furnace)  this demonstration is not
directly relevant to the analysis of reburn technology on oil-/gas-fired boilers.  No other retrofit
experience exists in the United States (Pratapas, 1991). Bisonett and McElroy, 1991,  recently
evaluated the performance and retrofit potential for the IFNR process along with other combustion
and FGT controls for five utility boilers in the PG&E inventory (Bisonett, 1991). In that study,
NOX reduction performance was estimated in the range of 47 to 75 percent with boiler derating.
No test data were taken  to verify this performance.  The derating of the boiler capacity was
considered necessary because adequate gas  residence time must be  available in the furnace to
complete combustion of the staged fuel. Major extension of the furnace height is another way to
achieve this increase in residence time, but the modification is excessively expensive to consider
under normal conditions.

       In Italy, reburning with propane and fuel oil as reburning fuels on a 35 MWe unit has been
experimented to compare the overall effectiveness to other combustion controls available to oil-fired
boilers. NOX reductions of up to 70 percent were achieved with propane and 60  percent with oil
as the  reburning fuel (DeMichele, G.,  et al., 1992).   Reburning performance and control of CO
emissions were sensitive to reburn residence  time. A minimum of 0.45 seconds of residence time
was reported as necessary to optimize NOX reduction with adverse  increase in CO emissions.  In
Japan,  the application  of the  MACT process has  been reported to achieve significant NOX
reductions  (Araoka, 1987  and Murakami, 1986).  Usually MACT is applied with  LNB to achieve
levels of less than 0.15 Ib/MMBtu (Araoka, 1987). Performance data for reburn in gas and oil-fired
designed units remains limited. In Japan, reburn on  PC-fired boilers is the preferred application
for the MACT, however.

42.7   Retrofit Potential for the NESCAUM Boilers

       Table 4-9 provides estimates  of the NOX reduction potential  for  the  retrofit  control
technologies applicable to  oil- and gas-fired utility boilers. These estimates were developed based
on assumptions of retrofit applicability (ranging from 50 to 90 percent) and  estimates of control
levels achieved from current baseline inventories. For example, 80 percent  of the  wall-fired boiler
capacity responsible for 30,000 tons/yr of NOX emissions is deemed  retrofitable with either BOOS
or OFA controls that reduce emissions by staging the combustion (TSC).  With  this technology,
control levels are estimated in the range of 0.25 to 0.45 (25 to  35 percent reduction), depending on
initial NOX level (pre- or post-NSPS), fuel  type,  and several other site-specific  factors.   These
control levels result in a reduction of 7,500 to 11,000 tons/yr of NOX throughout NESCAUM from
this boiler  design category. Because these estimates are based on  several assumptions, they are
offered as guidelines to estimate NESCAUM-wide reduction potentials. Site-specific analyses are
required so that accurate predictions can be developed. Generally, lower retrofit potential estimates
were used  in the case of LNB, combined control (OFA + LNB + FGR), and reburning  retrofits
because of the lack of reported experience to date and increased retrofit difficulties.  High retrofit
potential is estimated for BOOS and FGR (or a combination of these controls), because  they are
relatively easy  to retrofit  on  most boilers.  The degree of TSC  accomplished will vary with the
flexibility that  a  particular unit has in managing load with  BOOS.   The retrofit potential of
                                           4-30
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-------
LNB-based controls is considered to be less compared to TSC+FGR because of more limited
experience.

       The NOX reduction estimates in Table 4-9 can be somewhat misleading because several
boilers are already controlled with combustion modifications. Also, several boilers currently have
low NOX levels,  and, because of this, significant NOX reductions are not anticipated from these
units.  Therefore, another estimate of NESCAUM-wide NOX  reduction  can be  obtained  by
calculating the contribution of each oil-/gas-fired boiler required to meet  a certain NOX level.
Figure 4-5 illustrates this estimate, which assumes widespread application of emission control levels
of 0.3 or 0.2 Ib/MMBtu to all dry-bottom boilers.  The figure  shows  that  a control level  of
0.3 Ib/MMBtu results  in little  reduction  from the current  emission  inventory attributable  to
tangential units.  This is because most tangential boilers are already reported to emit NOX at this
level.  Most of the estimated 30,000 tons/yr of NOX reduced under this scenario is contributed
principally by reductions in NOX from wall- and opposed-fired boilers.  Under the 0.2 Ib/MMBtu
control NOX scenario, 50,000 to 60,000 tons/yr  are reduced with significant contributions from  all
major boiler types. As indicated, wet-bottom  units  with high furnace heat  release rates remain
uncontrolled because these are significant uncertainties in the applicability and performance  of
applicable controls due to limited retrofit experience.  Combustion controls with reburning on these
units are likely to  add no more than 10,000 tons/yr to the overall reduction in the  NESCAUM
region.

4J    FLUE GAS TREATMENT CONTROLS

       Commercially  available  technologies for  the control of NOX after it  is formed  in the
combustion process are currently limited to SNCR and SCR.  Both of these processes have seen
very limited application in the U.S. for utility boilers.  The  SNCR process has been used with
moderate to high success  primarily on  smaller  industrial  combustion sources,  fluidized bed
combustors in California, and two PC-fired boilers and one larger gas-fired utility boiler, also  in
California.  The SCR  process has been investigated in a  few pilot- and full-scale utility boiler
programs sponsored by EPRI, EPA, and selected utilities.  Recently, renewed regulatory efforts to
attain ozone air quality standards in Southern California's Los Angeles Basin are including several
demonstrations of  SNCR and SCR commercial  equipment.  For example, SCE has planned a total
of 5,000 MWe retrofit, with high-energy, urea-based SNCR. Many of these retrofits are already in
place and being tested. There are also a total of 40 industrial plants equipped with SNCR, as well
as ongoing utility  SNCR demonstrations in the states of New York, Colorado, and California.
These controls  are being evaluated after the utility industry has exhausted  most  combustion
modification retrofit options.

       SCR is being used extensively in Japan  and Germany with  reported successes on all fuels
including coal. Several SCR vendors, primarily Japanese vendors, are offering this technology in
this country. Application of SCR systems on utilities in the U.S. has been  slow because of absence
of regulations requiring low-NOx levels and utility concerns over cost, operational impacts, ammonia
slip,  corrosion and flyash contamination,  and catalyst  poisoning with higher  sulfur and  lower
volatility  domestic coals.   However,  SCR has  been  installed  on  numerous cogeneration-,
reciprocating-engine-, and gas-turbine-based facilities in this country, primarily  in California, New
Jersey,  and other NESCAUM  states.   For  example, the  Chamber  Works and Lakewood
Cogeneration plants in New Jersey operate with SCR controls. Several other states have mandated
SCR as Best Available Control Technology (BACT) for engines and turbines.  A new 224 MWe PC
plant to be located also in New Jersey will be the first SCR coal installation  in  the United States.
                                           4-32
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       The following subsections briefly describe these technologies and their application to the
NESCAUM boiler inventory.

4.3.1   Selective Noncatalytic Reduction (SNCR)

       In the SNCR process, ammonia (NH3) or urea (NH2CONH2)  are injected into the
convective section of the boiler where the temperature of the flue gas is in the range of 930
to 1,090°C (1,700 to 2,000°F). Within this temperature window, NH2 radicals from the injected
reagent react selectively with  NO to form nitrogen and water.  The efficiency of these patented
processes depends primarily on the temperature of the gas, the mixing of the reagent with the flue
gas, and the amount of reagent injected in relation to the concentration of NOX in the gas.  The
optimum gas temperature for the reaction is  about  950°C (1,750°F).  Deviations from  this
temperature result in a decrease in NOX reduction efficiency. Therefore, NOX reductions are very
boiler-specific and sensitive to the  boiler load.  Aside from the ability of SNCR technology to
maintain NOX reduction performance with boiler load, major concerns are NH3 slip (caused by
unreacted reagent) and  the operational problems that these emissions can cause when burning
sulfur bearing fuels.   Additionally, excessive NH3 can contaminate flyash to the point  that  it
eliminates its resale  value.   More  recently, N2O has been  shown to be a byproduct of SNCR
chemistry, primarily when urea-based reagents are used.

       Early demonstrations of the SNCR technology utilized Exxon's Thermal DeNOx process on
a Southern California utility boiler.  NOX reductions were limited to 35 to 45 percent due to the
inability of the process to follow boiler load, difficulty in controlling the amount of NH3 injected
as the load changed, and inefficient  mixing of the NH3  in the gas stream (Dziegiel, 1983).
Significant uncontrolled  NH3 emissions were associated with early applications  of the Thermal
DeNOx process.  Since  that  initial demonstration  at the LADWP Haynes  Unit 4,  significant
improvements have been made to the Thermal DeNOx process such that process guarantees are
in the 40 to 60 percent NOX  reduction.  However, no utility boiler retrofit has taken place since.
NH3 injection has been used on municipal waste combustors and other sources such as industrial
boilers and fluidized-bed combustors with significant NOX reduction success.

       Urea injection in the  NOXOUT Process has recently been installed  on three Southern
California oil- and gas-fired boilers.  On two boilers, NOX reductions attributed to urea injection
were approximately 30 percent with NH3 slip of 20 ppm (Abele, 1991).  On the third boiler,  NOX
reductions were limited to about 20 to 25 percent  to minimize the amount of unreacted NH3. Here
the process  was found to be  very sensitive to the temperature fluctuations due to routine load
changes (Jones,  1991).  The Long  Island Lighting  Company (LILCO) is  evaluating  urea in an
oil-/gas-fired utility boiler.  Several parametric tests were performed at LILCO's Port Jefferson
185 MWe Unit 3 to optimize  the performance of Nalco Fuel Tech's NOXOUT-A process. With
a urea injection rate corresponding to a normalized stoichiometric ratio (NSR) of 1.5 to 2.0, NOX
was reduced 50 to 56 percent across the load range, with  a 20-  to 40-ppm NH3 slip and  N->O
generation corresponding to 10 percent  of the NOX removed (Teetz, 1992).

       In another oil-/gas-fired retrofit demonstration, a urea/ammonia injection system by Noell,
Inc. was installed at the PG&E Morro Bay oil-/gas-fired 330 MWe Unit 3. Tests showed consistent
NOX reduction  efficiencies in  the range of 30 to 40 percent. However, NH3 slip levels exceeded
100 ppm (Teixeira, 1992). In one coal-fired utility demonstration of urea injection, the NOXOUT
process was tested on a tangentially-fired boiler. NOX was reduced from 225 ppm to 165 ppm after
application of combustion modifications  (Camparato, 1991).  In a more recent application of SNCR
retrofit on a coal-fired boiler,  two-level injection  system, by Noell Inc., using high-energy urea was
reported to  achieve 10- to 30-percent reductions from  LNB-combustion-controlled levels (Hunt,

                                          4-34
-------
1992).  NH3 slip from Arapahoe 100 MWe Unit 4 was low and N2O conversion accounted for 10 to
15 percent of the NOX reduced.  New applications are evaluating processes where SNCR can be
used in connection with an SCR catalyst to minimize the unreacted NH3 emissions, reduce the
catalyst required and improve performance. These systems await demonstration.

       The retrofit of SNCR for utility boilers requires a detailed mapping of the gas flow,
temperature and NOX emissions profiles in the upper regions of the furnace and convective passes
of the  unit. These profiles should be completed for the entire boiler load range. Based on this
information and the available cavities for placement of the reagent injection nozzles, the optimum
injection location is selected. Many retrofits will require multiple injection locations to compensate
for the rapidly dropping gas temperature with boiler load. This compb'cates the process monitoring
and  reagent  feedrate  control which must be  adequately  designed to  retain  NOX  reduction
performance and low NH3 emissions  throughout the boiler load range (Jones, 1991).

       A principal concern with this technology is its ability to retain NOX reduction performance
over a wide range of boiler loads, with minimal unreacted NH3 emissions.  Such emissions can
cause severe operational problems, including air heater fouling, low-temperature corrosion, and
plume  opacity. For coal-fired power plants, the amount of unreacted SNCR ammonia collected on
the flyash can be a significant concern because of landfill restrictions, and loss of revenue from the
sale  of flyash to cement manufacturers.   The NOXOUT  technology uses  advanced furnace
aerodynamic and heat transfer computational modeling coupled with control of the mean droplet
size of liquid urea and proprietary additives to optimize NOX reduction throughout the boiler load
range with minimal NH3 slip.

       In  summary, SNCR is a commercially available control technology with potential for a 25-
to 40-percent additional NOX  reduction beyond levels achieved with combustion modifications
already in place.  Lower percent NOX reductions are expected when the initial NOX levels are low.
Therefore, oil- and gas-fired boilers with emissions of 150 ppm attained via combustion retrofits will
likely be limited to a maximum of 40-percent reduction using SNCR, commensurate with results
obtained at Morro Bay Unit 3.  With uncontrolled  NOX  emissions, the performance of the
urea-based SNCR is estimated to range between 40 and 50 percent, with  NH3 emission slip in the
range of 5 to 100 ppm depending on the process selected and  type of application. A portion of this
NOX reduction will be changed to N2O emissions depending on the reagent selected, combustion
conditions  (CO and HC emission concentrations), and NOX reduction target.

       Generally, the  technology is considered  applicable to all fuel types  and to both  controlled
and uncontrolled units, but long-term performance and operational impact experience is lacking.
Also, concerns over corrosive ammonium  sulfate and bisulfate formation with high-sulfur fuels
currently limits potential the application to low sulfur fuel-fired power plants to minimize impacts
on ash  disposal and corrosion/fouling.  Furthermore, the complexities  of load following  favors
process applications on boilers that are generally base-loaded.

432   Selective Catalytic Reduction  (SCR)

       In  the SCR process, gaseous  NH3  along with a carrier gas (typically compressed  air) is
injected upstream of a catalytic reactor operating at temperatures between 230 and 400°C (450 and
750°F). As in the SNCR process, the NH3  reduces NO to N2 and water.  NOX control efficiencies
are often in the 70- to 90-percent range depending on the size of the catalyst, the amount of NH3
injected, the initial NOX level, and the age of the catalyst.  Typically, the reduction efficiency of the
catalyst degrades over time as the catalytic surface  becomes contaminated or coated with flue gas
                                          4-35
-------
particulate and ash. Layers of the initial catalyst have to be replaced routinely to maintain overall
performance.

       SCR is conceptually applicable to all coal-, oil-, and gas-fired utility boilers.  Applications
of SCR on both new and retrofit utility boilers have been limited to Japan and Germany, however.
Other European countries are planning SCR retrofits  to meet new European Community (EC)
power plant emission regulations. Appendix E lists current and planned SCR installations on coal-
fired boilers worldwide. In the United States, SCR projects for utility boilers have been limited, for
the most part, to a few coal and oil demonstrations sponsored by EPRI, EPA, and related utilities
(Janik, 1992; Huang, 1992; Guest,  1992; Kerry, 1986; Cichanowicz, 1987). Many of these initial SCR
demonstrations have  also been  discontinued.   However, new SCR retrofit projects are being
initiated  for Southern  California  utilities, because  of  increasingly stringent  NOX control
requirements in that severe ozone nonattainment area, and by EPRI.  SCR has been installed on
many gas  turbines and reciprocating engine prime movers in cogeneration plants and industrial
applications in the United States and abroad. These units are typically based loaded and burn clean
fuels.

       Japan has about 20 years  of full-scale utility experience with SCR.  The more recent SCR
experience is reported to have significant success.  Early concerns about ammonia slip (the amount
of unreacted NH3 leaving the flue gas), the formation of ammonia sulfate and bisulfate,  and
catalyst poisoning and deactivation have been addressed. Reports of ammonia slip control to levels
below 5 ppm are routine (Beherens, 1991, Lowe,  1991).  Ammonium sulfates, a principal concern
because of the corrosive properties of these compounds, have been reduced with different catalyst
formulations that minimize the amount of SO2 to SO3 conversion in the reactor (Lowe, 1991). This
catalyst property that converts a fraction of the SO2 to SO3 is important because of the potentially
severe  corrosion  that can  occur with ammonium sulfate  compounds.  Also,  higher SO3
concentrations increases the dew  point of flue gas requiring higher stack temperature and a  loss in
thermal efficiency. Catalyst life has been reported to range between 4 and 10 years for coal-fired
power plants depending on whether the application is in a high or low dust environment.  For oil
and gas firing, the  Japanese report no  catalyst degradation for up  to 10 years (Lowe, 1991).

       Today, SCR   is  used  on more than  100  utility boilers  in  Japan,   40  burning coal
(Nakabayashi, 1987).  Some SCR systems are operated on high sulfur (2.5 percent) coal with no
performance degradation  and  low  NH3  slip  (Beherens,  1991).    Major  Japanese  catalyst
manufacturers are MHI, Kawasaki Heavy Industries (KHI), Ishikawajima Harima Heavy Industries
(IHI), Hitachi Ltd. (HTC), Nippon Shokybai, and Hitachi Zosen Corporation (HZC).  In Germany,
129 SCR systems have been installed on over 30,000 MWe of utility  service (Lowe,  1991).  Major
European SCR manufacturers are Siemens AG, Haldor Topsoe, and Kraftanlagen AG. Most utility
boiler applications have been retrofits including low sulfur coal-burning plants. In the U.S., Norton,
Engelhard, W. R. Grace, and  Joy Environmental are major suppliers of catalyst. The major U.S.
boiler manufacturers also offer Japanese SCR technology. Southern Company Services, Inc., will
shortly undertake a test program where 10 different SCR catalysts will be evaluated at the Gulf
Power  Company's Plant Crist  in Florida (Clean  Coal Today, 1991). The successful demonstration
of these technologies  could result in greater acceptance of SCR  as a retrofit  control option  for
utility boilers.

       The retrofit of SCR on existing power plants can be significant in cost and complexity.
Apart from the ammonia storage, preparation, and control monitoring requirements, significant
modifications to  the boiler convective ducts are necessary. The SCR  reactor must be placed in  the
existing flue gas path where the temperature is sufficiently high for efficient NOX control. Also, a
                                           4-36
-------
reagent feed system must be installed to ensure adequate distribution of NH3 across the gas flow.
Figure 4-6 illustrates the various SCR retrofit arrangements for PC units.

       There are two basic locations for the retrofit of the SCR reactor. The first is downstream
of the boiler economizer, upstream of the air preheater, where the flue gas temperature is typically
optimal for  the catalytic reaction to take place. This location, typically referred to as hot-side, is
common for oil- and gas-fired boilers and for low-ash coal-fired boilers. The second, for a coal-fired
unit, is downstream of any air particulate and acid scrubber, upstream of the induced draft fan and
stack.  This  location, commonly referred to as cold-side, has the advantage that most of the flyash
has been scrubbed and in some cases the sulfur has also been reduced.  However, because the gas
is much cooler, it must be reheated at a high cost to catalyst requirements necessitating additional
equipment,  such as a regenerative air preheater, for energy recovery. For coal-fired cyclones and
wet-bottom  units, the tail-end SCR system is most appropriate. Recent improvements in catalyst
materials, showing resistance to erosion, blinding  and contamination and SO2 to SO3 conversion,
will make it feasible  to consider retrofit upstream of particulate control at significant cost saving
over cold-end applications.  Some wet-bottom boilers in Germany have been retrofitted with SCR.
However, significant  catalyst degradation  due to arsenic oxide poisoning  has  been reported
(Balling, 1991).

       Regardless of the configuration and reactor location, the retrofit of SCR to existing power
plants  requires significant boiler modification  and control system upgrade.  The reactor volume
typically ranges from about 60 ft3/MWe for a tail-end retrofit to  120 ft3/MWe for a high-dust
retrofit requiring considerable space for the installation (Borio, 1991).  When a high-dust SCR is
installed, it is often necessary to also install an  economizer bypass to be able to maintain the SCR
inlet gas temperature  to system requirements when the boiler is operating at part load.   The
economizer  bypass can result in a significant energy penalty. Modifications of the building structure,
and sootblower relocations are  often necessary because of the tight spaces available. Upgrade of
the combustion air  fans is always necessary  to  accommodate the  increase  in pressure drop.
Additionally, induced draft units will require conversion  to balanced draft resulting in upgraded fan
capacity.

       A sophisticated ammonia monitoring and feedrate control system is necessary to maintain
consistently  high NOX reductions and low NH3 slip.  Excessive NH3 slip can cause changes in ash
characteristics.  For some facilities it may be necessary  to relocate the stack and replace the liner
and make considerable changes to the powerplant building. These large modifications are often due
to little space available between the boiler and stack to install the SCR reactor.  Depending on the
location of the boiler, precautions are  necessary for the ammonia storage tank to abide by local
safety codes.  Ultimately, the catalyst  has  to  be  replaced and the spent catalyst must be land-
disposed.  In the U.S., this disposal is regulated because of potential environmental hazard due to
metal formulations of many catalysts.

       In spite of the relatively easier application  on oil- and gas-fired utility boilers, SCR has not
been  retrofitted  on  U.S.  utility  boilers  except  for  few  demonstrations  (Kerry, 1986  and
Cichanowicz, 1987).  SCE is currently  demonstrating an SCR  air heater (CAT-AH) supplied by
KAH of Germany (Reese, 1991; Reese,  1992).  In this configuration,  one half of the ABB-CE
rotating air  heater serving 107 MWe of the oil-  and gas-fired boiler has been replaced with a
catalytic ceramic surface that will perform as  an  SCR reactor while retaining the heat transfer
properties of the air heater.  This arrangement can be used in connection with the SNCR process,
where any unreacted NH3 or urea leaving the SNCR temperature window will reduce NOX further
when passing through  the air heater.  This retrofit is attractive in that it minimizes the space
requirements and boiler modifications.  Preliminary results of the SCE demonstration of CAT-AH

                                           4-37
-------
                H«at»r
                     SCR
                           VVV
 ESP or   W« SO2
FabricFilttr Scrubber
V
 Spray
 Dryer
         (ib)
                                 ,A
                                 ~  Wmflm   VW«<
                           NH3
                                 Ath
         Wast*  West*
         Wat»r  Solids
                      vvv
                        I
          W»«l«
          W«l»r
                                          West*
                                          Sohdt
         (1C)
          (id)
          (le)
                           NH3
                         NH3
                       vvv
                                      vvv
            A»h. Dry
          ScruCtwr WM«
                             vvv  N^y  vvv

                              A«h       Dry Scrub!
            Dry Scrubber
             Wan*
                         A*h  W»»l»   Wist*
                            Water   Sohds
              d
Figure 4-6. Possible SCR configurations (Source: Cichanowicz and Offen, 1987)
                           4-38
-------
has shown NOX reductions of 50 to 64 percent at full load from combustion-controlled levels of
145 ppm (0.18 Ib/MMBtu) (Reese, 1992).  However, performance and reliability remain to be
demonstrated.  Furthermore application of the CAT-AH catalyst of higher sulfur content fuel oils
burned in the NESCAUM boiler population remains to be demonstrated.

       In conclusion, SCR is a commercially available technology that has been applied to new as
well as retrofit utility boilers in Europe and Japan since the early 1970s. However, caution should
be used in interpreting these foreign SCR successes because catalyst performance can be severely
affected by contaminants present in the coal. U.S. coals have typically higher concentration of some
catalyst poisoning agents such as arsenic.  NOX reductions of 70 to 80 percent are possible and are
often guaranteed by SCR vendors. Slightly lower NOX reduction efficiencies are anticipated when
the initial concentration of NOX entering  the reactor  is low because of combustion controls.
Application of these foreign SCR technologies to coal-fired U.S. utilities is likely to be more easily
accomplished when the coal burned has low sulfur and low ash. In the NESCAUM inventory, only
about one forth of the coal-fired boilers use coal with a sulfur content of 1 percent or less. The use
of SCR with higher sulfur coal will result in greater boiler maintenance as few of the units control
SO2.  SCR  can be retrofitted to gas-fired boilers  with  little anticipated operational difficulty.
Retrofit  for oil-fired boilers  will require  some limitations  on the sulfur content of the oil.
Approximately  two-thirds of the gas and oil-fired boiler inventory in the NESCAUM region
operated in  1987 with  fuel oil containing less  than  1 percent sulfur or less.  These units can be
considered candidates for SCR retrofit.

4JJ   Retrofit Potential for the NESCAUM Boilers

       Table 4-10 lists  estimates of NOX reduction potential for  FGT controls on applicable
NESCAUM boilers.  For each fuel and boiler firing types, two  retrofit cases are considered for the
following  FGT controls: retrofit on uncontrolled boilers and retrofit on  combustion controlled
boilers.  Uncontrolled levels for PC units are 0.60 and 0.95  Ib/MMBtu on the average for tangential
and wall units, respectively.  Application of SNCR-based controls from  these levels would reduce
NOX to a range of 0.50  to 0.65 Ib/MMBtu on wall-fired PC boilers (30- to 50-percent reduction),
and 0.30 to 0.40 Ib/MMBtu (30- to 50-percent  reduction) on T-fired boilers.  Application of SCR
controls at the  economizer outlet of PC-fired boilers (hot-side) is estimated to  reduce NOX to a
range  of 0.20 to 0.30 Ib/MMBtu  (70  to  80 percent), for  wall-fired  boilers,  and  0.15 to
0.20 Ib/MMBtu (also 70 to 80 percent), for tangential  boilers.   NOX reduction  estimates for
cold-side application of SCR are slightly higher because of anticipated better performance with
scrubbed flue gas.

       As footnote "a" in Table 4-10 indicates, combustion-controlled levels considered for PC-fired
units are 0.60 Ib/MMBtu, for wall-fired boilers, and 0.45 Ib/MMBtu, for tangential units, based on
the upper level of NOX control performance of LNB retrofit projected for NESCAUM units.  From
these NOX levels, SNCR controls are anticipated to  reduce NOX to 0.35 to 0.45 Ib/MMBtu  (25 to
40 percent), for wall-fired boilers, and 0.25 to 0.35  Ib/MMBtu (25 to 40 percent), for tangential
units. Hot-side SCR controls would reduce NOX to the 0.10- to 0.20-lb/MMBtu (70- to 80-percent)
range, depending on uncontrolled NOX levels.  For gas-/oil-fired boilers,  the current baseline levels
of dry-bottom units range between 0.30 and 0.45 Ib/MMBtu on the average for combined pre- and
post-NSPS tangential- and wall-fired boilers, respectively. Estimates of SNCR control performance
would reduce these levels to a range of 0.15 to 0.20 Ib/MMBtu (30 to 50 percent), for tangential
units, and 0.25 to 0.30 Ib/MMBtu, for wall-fired units. SCR-based controls on uncontrolled boilers
would be capable of lowering NOX levels to as low as 0.05 to 0.15 Ib/MMBtu. When  coupled with
combustion modifications, SCR is estimated to reduce NOX to a range of 0.05 to 0.10 Ib/MMBtu.
                                           4-39
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These levels are based on  regulatory targets in California's SCAQMD (Johnson, 1991).  These
controlled levels are used in Section 6 to calculate the cost effectiveness of these control strategies.

       The retrofit target boiler population was selected by excluding all boilers that in 1987 burned
fuel with less than 1.5 percent sulfur content.  The remaining boiler capacity was further reduced
in half to obtain a conservative estimate of the target boiler capacity with favorable dispatch profile,
site access, ease of retrofit  and fuel properties compatible to SCR systems with hot-side catalysts
for PC and oil-/gas-fired units.  Figure 4-7 illustrates system-wide NOX reduction estimated in
NESCAUM with contributions from the retrofit of SNCR or SCR controls on 15 and 40 percent
of PC- and oil-/gas-fired capacities, respectively.  These estimates were based on FGT controls
implemented only after combustion control options are exhausted for  these  units.  The figure
illustrates that, with SCR retrofit, systemwide NOX is reduced to 145,000 tons/yr, for PC units, and
108,000 tons/yr, for oil-/gas-fired  units.  Lower total utility NOX emissions can be realized by
increasing the total capacity of boilers retrofitted with FGT controls above the estimated considered
in this study.

       It should be pointed out that some PC-fired units will also be targets for SO2 control as part
of the acid precipitation abatement program.  These boilers will become candidates for combined
SO2/NOX  FGT controls such as  dry or slurry  sorbent injection with urea  injection with  the
NOXOUT process or other SNCR processes.  Some of the  more promising combined NOX/SOX
control technologies  are highlighted next.  These  technologies are not currently commercially
available.

4.4     COMBINED NOX/SOX CONTROLS

       Recent regulatory and technological developments have resulted in an increased interest in
the demonstration  of low-cost combined NOX/SOX control technologies as alternatives to SCR and
FGD gas treatment technologies. The recent CAA Amendments of 1990, and the mandates for acid
rain control and attainment of the ozone standard, require a combination of NOX and SO-, control
strategies for coal-fired powerplants. Although SCR and FGD controls are widely used in Europe
and Japan, the widespread  acceptance of SCR, particularly  in United States,  has suffered from
concerns regarding the cost and operational reliability with domestic high sulfur coals. Combined
NOX/SOX  control  technologies offer the potential for low cost alternatives with capabilities
exceeding 90 percent reduction for  both pollutants.

       Table 4-11  lists several combined  NOX/SOX  reduction processes under various stages of
research development and  demonstration.  Table 4-12 lists processes that are currently being
demonstrated under the Clean Coal Technology (CCT) program sponsored by the DOE.  Many
existing NOX controls  such  as LNG and urea  injection are also being introduced with other SOX
reduction processes and marketed as combined NOX/SOX controls. Appendix  C provides schematics
of these processes. EPRI has undertaken a study to identify the most promising processes which
will then be evaluated in detail for cost and operational reliability (DePriest, 1990). Among the
most promising are the NOXSO which uses a high surface area 7-alumina  substrate impregnated
with sodium to achieve removal efficiencies of 90 percent for SO-, and 70  to 90 percent of NOX.
The process has been successfully tested at pilot-scale facilities and is undergoing slip-stream full-
scale  testing at  the Ohio  Edison  Toronto  Station (Neal  and BoUi, 1991).  Other  promising
technologies are the  SNRB, E-Beam, and WSA-SNO2 processes (DePriest, 1990).  In  general,
combined NOX/SOX control technologies  are  not commercially available.  Many are undergoing
demonstration programs in  the U.S., Canada, and Europe.
                                          4-41
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         Table 4-11. Processes under consideration for combined NOX/SOX control
    Overall Process Group
                     Process Name
Solid Adsorption/Regeneration
UOP/PETC Fluidized-Bed Copper Oxide
Process Rockwell Moving-Bed Copper Oxide Process
NOXSO Process
Mitsui/BF Activated Coke Process
Sumitomo/EPDC Activated Char Process
Sanitech Nelsorbent SOX/NOX Control Process
NFT slurry with NOXOUT Process
Irradiation of the Flue Gas
Ebara E-Beam Process
Karksruhe Electron Streaming Treatment
ENEL Pulse-Energization Process
Wet Scrubbing
Argonne/Dravo ARGONNOX Process
Dow Electrochemical Regeneration Process
Dow Polychelant/Ultrafiltration Process
PETC Electrodialysis Process
California (Berkeley) Ferrous Cysteine Process
Gas/Solid Catalytic Operations
Haldor Topsoe WSA-SOX Process
Degussa DESONOX Process
B&W SOX/NOX/ROX/BOX (SNRB) Process
Parsons Flue Gas Cleanup Process
Lehigh University Low-Temperature SCR Process
Electrochemical Operations
IGR/Helipump Solid-State Electrochemical Cell
Alkali Injection Operations
Argonne High-Temperature Spray Drying Studies
PETC Mixed Alkali Spray Dryer Studies
Battelle ZnO Spray Dryer Process
Source:  DePriest, et al., 1990.
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-------
                                      SECTION 5

                DESCRIPTION OF COST ALGORITHM AND TEST CASES
       This  section describes the cost algorithm used and the NOX control cost retrofit cases
evaluated in this study.

5.1    COST ALGORITHM

       A simplified cost estimating procedure was developed for this study. The procedure contains
all the principal cost elements of the EPA's IAPCS (Maibodi, 1990).  The IAPCS was developed
by the EPA AEERL to estimate the costs and performance of emission controls for coal-fired utility
boilers.  Originally patterned after  the Tennessee  Valley Authority  (TVA) cost model, it now
incorporates many of the EPRI's Technical Assessment Guide (TAG) cost elements and procedures
needed to evaluate the capital and  levelized busbar costs and cost effectiveness of power plant
equipment, including air pollution control retrofit equipment. Only minor differences exist between
the EPRI TAG and EPA's IAPCS costing procedures to the extent that the two methods can be
considered essentially equivalent.

       The principal cost elements of the IAPCS costing procedure are as follows:

          Process Capital Equipment
          Total Plant Cost
          Total Plant Investment
          Total Capital Requirement  ,
          Fixed Operating Cost
          Variable Operating Cost
          Consumable Costs
          Levelized Capital Charges
          Levelized Busbar Costs
          NOX Reduction
          NOX Control Effectiveness

       These cost elements are incorporated into a spreadsheet format used to calculate the cost
and cost effectiveness of several scenarios.  Appendices F and G contain these spreadsheets. The
following briefly describes what is included in these various cost elements and the procedures and
assumptions used in this study to determine these costs.

       The components of capital cost are  illustrated in Figure 5-1. The total plant cost (TPC)
includes the  following:

       •  Process capital
       •  General facilities capital
       •  Engineering and home office overhead

                                          5-1
-------
Direct field labor
Factory equipment
Field materials  and  supplies
          I
      Indirect Field labor
(e.g.,  supervision,  payroll  burden)
      Tools and facilities
       Field engineering
Direct construction  costs
      Indirect construction costs
                                 Bare erected cost
                                (Process  Capital  and
                                General Facilities)
                                Engineering  and  Home
                              offices  overhead and  fee
                                   Contingencies
                              m(project and process)t
                               Total  Plant  Cost  (TPC)
                    Allowance for Funds  Used  During  Construction
                           (Interest  during construction)
                          .Escalation during  construction.
                            Total  Plant  Investment  (TPI)
                                (at  In-Service  Date)
                                 Prepaid Royalties
                           Preproduction (startup) Costs
                        Inventory Capital (Working Capital)
                       Initial Catalyst and Chemical Charges
                                        Land
                             Total Capital Requirement
            Figure 5-1.  Components of capital cost (EPRI TAG, 1982)
                                     5-2
-------
       •   Process contingency
       •   Project contingency

The process capital is the total constructed cost of all retrofit equipment installed at the site as the
result of the NOX control retrofit.  For example, the retrofit of LNB on a coal-fired boiler will
require the  fabrication  and  installation of  the  burners and  associated  ducting  and  piping,
modifications or replacement of the existing windbox, modifications to the structures including boiler
enclosures for access, and other potential upgrades to the pulverizers, fans and boiler monitoring
and control systems.  Therefore, the installation of a technology may require several individual
retrofit components  and modifications.  The  detailed breakdown of the individual costs would
provide a measure of the potential effects of key site-specific factors.  However, apart from a few
exceptions, this cost detail was not available in the open literature.  Technology vendors generally
decline to provide specific line item costs for a broad study such as this because of the uncertainty
associated with site-specific factors  and for competitive reasons (Smith, 1991 and Kleisley, 1991).
When necessary, capital cost data were normalized to 1991 dollars using published power plant cost
indices.

       The general facilities include road, office buildings, shops, etc., and are typically taken as
5 to 20 percent of the process capital cost (PCC) according to EPRI cost premises.  For this study
a 10 percent factor was recommended for most boiler design types (Maibodi, 1990).  Engineering
and home office overhead fee (EHOF) are costs associated with the retrofit project and typically
vary between 10 to 15 percent of the process capital.  Ten percent was generally used in this study.
The contingencies (process and project) are significant components of the total capital requirement
(TCR). The project contingency is intended to cover for the uncertainty in the cost estimate itself,
whereas  the process  contingency addresses the uncertainty in the  performance of the  retrofit
equipment.   The EPRI TAG  provides guidelines for  estimating these costs.   The  process
contingency varies between  10 and  20 percent of the process capital and the project contingency
varies between 30 and 40 percent of the process capital plus related expenses.  Technologies which
have not been demonstrated generally have a higher project centingency. In this study, the  highest
project contingency (40 percent) was used for selective catalytic reduction  (SCR) retrofit on  coal-
fired boilers. All other technologies were given a project contingency of 30  percent according to
IAPCS procedures.

       In addition to these costs, the EPRI TAG has provision for the costs associated with the
duration of the retrofit project. For retrofit projects exceeding 1 year, additional costs are included
in the estimate based on  the escalation during that period of time.  Because the time required to
install the NOX controls analyzed in this study is estimated to not exceed  1 year, no incremental cost
was considered due to escalation.  Many LNB retrofits  have required 8  to  16 weeks of  outage
including serious upgrades (Smith, 1991; Laursen, 1992; Hardman, 1992; Sorge, 1992; and Manaker,
1992).  This time does not include startup and optimization testing.

       The total  capital requirement (TCR) used includes additional costs such as royalties and
preproduction.  Unless royalty costs were reported in the literature or supplied to this study by the
technology vendors, no royalties were assumed.  Preproduction includes  the cost of training of
personnel for the operation  of the retrofitted technologies. This cost is standardized at 2 percent
of the total plant  costs (TPC).  Land, inventory capital (some has been included in process costs),
land, allowance for funds during construction  (AFDC), and sales tax were not calculated in this
study.

       The operating costs are divided between the fixed and variable portions. Both the fixed and
variable operating costs  includes  the increase in  operating labor associated with the  retrofit

                                            5-3
-------
technology, maintenance, and administrative and support costs. For example, the equation from
IAPCS used for calculating the operating labor associated with an SCR system is:

            Operating labor {— — } = -^- (1341 + 5.363 MW) UCnr { - - - )      (5-1)
             ^    *      (kW-yr)   0.628                '    OL 1,1000 MW)

where CF is the capacity factor (fraction), MW is the boiler rating in megawatts,  and U€QL is the
unit cost of operating labor in $/man-hr. In conformance with EPRI's TAG, the maintenance cost
was set at 2 to 4 percent of the TPC (4 percent for SCR technology).  Without further information,
the maintenance labor to materials ratio was assumed to be 40/60.  The administrative and support
labor costs were set at 30 percent of the operating and maintenance labor. The breakdown between
fixed O&M and variable O&M is defined by the following equations:

                           Fixed O&M (—^—} = CF (O&M)                       (5-2)
                                       (kW-yr)
             Variable O&M (-^-} . (1-CF) (O&M) 1 100° mills} f 876° hr] CF       (5-3)
                          \kW-hr)                 (     $    )(   yr   }

where O&M is the sum of operating labor, total maintenance, and administrative and support labor
costs.

       Consumables include the incremental fuel used due to thermal efficiency losses or used as
part of the process (e.g., for reburning and to reheat flue gas in the SCR cold-side retrofit), catalyst
replacement and disposal,  NOX reduction reagent (e.g., urea or ammonia), incremental use of
electrical power for fan  boosting and pumps, and any water or steam associated with  the NOX
reduction process. The equations used for calculating consumables operating costs (in mills/kW-hr)
were derived from IAPCS for ammonia, urea, electricity, catalyst replacement, and catalyst waste
disposal.

       In order to use lAPCS's equation for catalyst replacement, the volume of the replacement
catalyst is needed. The following equations were used:

                    4.762(nc+n,) * 0.9405^-3.762/1^,    lb-mol flue gas
                                   %O2 flue               Ib-fuel
                            1-4.762-
                                      100
Where                                                                             (5-4)

                      %C          %H          %S
                                                         /  .^
                      1201          100.8        3206              3200
Coal (fuel) composition:  %C = 72.8%, %S = 2.2%, %H = 4.8%, and %O2 = 6.2%
Flue gas %O2 = 3%
                                          5-4
-------
             Ib-mol flue gas
                 Ib-fuel
                  f  38S.3ft3
                  ^ Ib-mol gast

£)
ft* of flue gas       (5-5)
     hr
           ^ . t -. w »
           Catalyst Volume
                                                Flowrate
                               •Space
                                                       (1/nr)
                                                                  A3
                                                                 )*3
HR is the heat rate in Btu/kW-hr, and HV is the heating value in Btu/lb.

       Fuel efficiency losses, reported as an increase in heat rate, result in an increase in fuel
consumption.  Thermal efficiency losses of 0.5 percent were attributed to all technologies that use
burner staging with OFA alone or in combination with other technologies.  BOOS only applicable
to oil- and gas-fired boilers, was considered to have an efficiency loss of 0.25 percent.  Efficiency
loss are generally lower, if any, when burning gas because little additional excess air is needed to
control CO and HC emissions. LNB vendors generally report little or no adverse impact of LNB
when used without OFA or advanced OFA (AOFA) (Vatsky, 1991; LaRue, 1990, Lisaukas, 1987).
Efficiency loss of 0.25 percent was used for LNB applications to reflect increase in  LOI reported
by several retrofits.  Details of this effect of LNB retrofit on LOI are provided  in Section 7. The
retrofit of NGR is reported to result in an increase in heat  rate of 0.10 to 0.50 percent (Farzan,
1989; Brown, 1992;  and May 1992).  A 0.5-percent increase in heat rate was  used for this cost
analysis.

       The amount of NOX reagent needed for FGT technologies was calculated  based on the
uncontrolled NOX levels and the size of the boiler. For example, the  quantity of NH3 needed for
SCR application is based on one mole of anhydrous NH3 for each mole of NOX in the flue gas.
Therefore, the annual usage is determined as follows:
 /tort HJ
>(yr) 46lb
                      N02  NOX

                                                                                    (5-7)
Where EF is the baseline NOX emission factor in Ib/MMBtu, HR is the heat rate in Btu/kW-hr,
kW is the boiler, capacity in kilowatts, and CF is the capacity factor (fraction).  Urea usage was
based on using a normal stoichiometric ratio (NSR) of 1.5.  The molecular weight of NO2 is used
because emission levels are generally reported in Ib NO2/MMBtu. For SNCR and SCR retrofits,
no economic penalty was calculated due to potential  loss of revenue  from the  sale of flyash or
increased disposal costs.

       Some control technologies may result in the reduction of some consumables. For example,
the application of natural gas reburning NGR to a coal  burning power plant will reduce  the amount
of coal by the same amount, on a heating value basis,  as natural gas used (typically 15 percent of
the total heat input).  However, because natural gas is more expensive than coal on a Btu basis,
there is a net increase in costs.  No cost credit was considered for the reduction in SO-, emissions
with  this technology.

       Once the amount of consumables was determined from process  requirements or from data
reported in the literature, these costs were  calculated using the boiler capacity and the unit price
costs. Table 5-1 shows the unit price costs used in the  algorithm.  SCR catalyst costs are reported
in the literature to range between $350/ft3 and $650/ft3 (Robie, 1990). In this study, catalyst cost
was based on the higher unit price to develop worst-case costs. However, the relationship between
                                           5-5
-------
                                   Table 5-1. Unit costs
               Cost Item
         Coal
         Oil
         Gas
         Ammoniab
         Ureac
         Electricity
         Catalyst
         Catalyst Disposal
         Operating Labor
         Solid Waste Disposal
   Unit Cost
$45.84/ton
$22.85/bbl
$2.61/1,000 ft3
$145/ton
$220/ton
$0.05/kW-hr
$370-$600/ft3
$315/ton
$21.45/man-hr
$8.00/ton
           Reference
 Electric Power Monthly, Mar 91*
 Electric Power Monthly, Mar 91*
 Gas Facts, 1991
 Robie, 1990
 BP Chemical, 1991
 Robie, 1990
.IAPCS, 1988; Robie, 1991
 Robie, 1990
 Robie, 1990
 IAPCS, 1990
         "Average price for New England Region.
         bUsed only in the SCR and Thermal DeNOx™ processes.
         °Used in the NOXOUT™ process only.
cost effectiveness and catalyst unit price is presented to illustrate cost savings associated with lower
catalyst costs.
       The TCR and the operating costs are levelized to determine the busbar cost and ultimately
the cost effectiveness of the retrofit technology.  The levelization procedures used in this study
follow those of the EPRI's TAG and the EPA's IAPCS with the exception that the levelization in
this study was based on the  remaining (book) life of the plant rather than a fixed  30-year
levelization factor applied in the EPA and EPRI guidelines. Different levelization factors were used
to illustrate the  incremental costs associated with retrofit of technologies to units that are near
retirement age compared to  units that will see a longer period of operation.
       Utilities have increasingly turned to life extension projects to extend the service life of PC-
fired boilers to 50 years, well beyond the 30-year nominal design and economic life of these units
(EPRI,  1989).  The feasibility  of these power plant life extension projects depends on several
economic considerations, including the efficiency of the plant, the needed capital investment, and
the cost of alternative power supplies.  For this study, the book life was based  on the assumption
that coal-fired power plants  have a 50-year service life  and oil-/gas-fired boilers have a 60-year
service life.  Nearly 20 percent of the existing coal-fired  boiler capacity in the NESCAUM region
has been in service for more than 35 years.  For gas-fired boilers,  20 percent of the capacity has
seen more than 40 years of service.
       The  TCR was levelized over the book life by applying the capital recovery (levelization)
factor for a uniform series (EPRI TAG). The total operating and maintenance cost (O&M) is not
levelized with any factors. The levelized busbar cost is  therefore only the levelized capital cost
added to fixed and variable O&M, and consumables including fuel, converted to  mills/kW-hr.
                                           5-6
-------
Figure 5-2 shows the effect of discount rate on the capital levelization (in percent) versus book life
(in years) curves for annual discount (interest) rates of 5, 10, and 15 percent. This study used an
annual discount rate of 10 percent. Constant-dollar analysis was used because the effect of inflation
was not considered. The cost effectiveness, in $/ton of NOX removed, is calculated based on the
reduction in NOX from the baseline levels divided into the levelized capital cost.  NOX reduction
levels are calculated from data presented in Tables 3-4, 4-1, 4-7, and 4-10).  Note that for NOX
controls, whose initial process capital is the largest fraction of the levelized cost, much lower costs
are seen as the  book life of the unit increases.  For these controls, the NOX reduction  costs
effectiveness will be least attractive for older facilities  that are close to retirement.

       Table 5-2 lists the principal cost  assumptions  used to  develop the costs of retrofit NOX
controls.  For  cost calculations,  a nominal power plant heat rate of 10,670 Btu/kW-hr (value
obtained from  averaging all heat rates used  in  Appendices A and B [coal  and oil/gas boilers,
respectively]) was used for all boiler test cases.  Information on heat rates for all boilers in the
NESCAUM region was not  available  to  differentiate between  the major boiler design and fuel
classes and age groups.  Average  heat rates calculated with available data were 10,937 Btu/kW-hr,
for PC-fired boilers,  and 10,558 Btu/kW-hr, for oil-/gas-fired  boilers.  These heat rates  vary
according to boiler load and plant age.   The boiler scaling factor, used to calculate the  cost
variability over a range  of boiler capacities uses a conventional exponential relationship where the
capital cost varies according  to the ration of the capacities raised to the 0.6 power, as follows:
                                                                                     -40
                               Figure 5-2.  Capital levelization

                                             5-7
-------
                           Table 5-2. Cost assumptions8
             Parameter
       Assumed Value
   Reference
Gross heat rate
Catalyst life for oil/gas applications
Natural gas reburn fraction (NOR only)
Catalyst life for PC applications
Oil/gas fuel use ratio
Number of catalyst layers
Ammonia injection ratio (SCR)
Urea injection ratio, NSR (SNCR)
Boiler scaling factor

Boiler service life (coal)
Boiler service life (oil/gas)
Capital levelization (recovery) factor
   n = boiler book (remaining) life
   i = annual discount  (interest) rate
       (i - 0.10)
Escalation
Allowance for funds during construction
(AFDC)
General facilitates (GF)

Engineering home office fee (EHOF)
Process contingency (proc)
Project contingency (proj)
Royalty allowance

Preproduction costs
Inventory capital costs
Maintenance costsb  (MC)  (without
more detail, 40% of MC is  labor)
Administration and support labor
10,670 Btu/kW-hr
8 years
15%
4
0.65/0.35
4 years
1.0 mole/mole NO
1.5 moles/mole NO
         kW
50 years
60 years
0%
0%

10 % of Process capital cost
(PCC)
10% of PCC
10% of PCC (20% for NGR)
30% of PCC
10% of PCC for cold-side SCR
15% of PCC for hot-side SCR
0.5% of PCC for SCR
10% to 15% of PCC for SNCR
2% of Total plant costs (TPC)
0%
2% of TPC (4% for SCR)

30% of operating and main-
tenance labor
Johnson, 1991
GRI, 1991
Robie, 1990
Pechan, 1989
Maibodi, 1990
Robie, 1990
                              EPRI TAG
EPRI TAG
Maibodi, 1990

Maibodi, 1990

Maibodi, 1990
Maibodi, 1990
Maibodi, 1990
Robie, 1990
Robie, 1990
Maibodi, 1990
Albanese, 1991
Maibodi, 1990
Maibodi, 1990
Maibodi, 1990
EPRI TAG
EPRI TAG
*For other O&M costs such as operating labor, electrical consumption, waste disposal,
 fuel consumption, and catalyst costs, see Maibodi, 1990.
bFor maintenance costs of NGR and SGR, see Maibodi, 1990.
                                       5-8
-------
                                               r
                                                   o»2                               (5-8)
                                                                                      ^   '
This scaling procedure varies slightly from that used in the IAPCS (Maibodi, 1990).

52    COST CASES

       Thirty-six boiler NOX control retrofit cases were evaluated to determine the costs and cost
effectiveness of various boiler-control combinations.  Tables 5-3 and 5-4 list these cases and the
principal sources of data used to develop the capital costs presented in this report.  For each of
these test cases, parametric variations in the boiler capacity, the age, the capacity factor, and the
NOX control efficiency were evaluated to determine the effect of these variables on the overall costs.
The range in the values of these variables to the costs are summarized in Tables 5-5 and 5-6.  The
range in  boiler age and capacity factor were based  on the current  population profile in the
NESCAUM region. The mean, 10th or 20th, and 90th percentile values of the current coal and
gas/oil boiler populations were used for these variables.  For the boiler capacity, the three cases
considered were based on the average, highest and lower boiler sizes within each boiler firing  type
and fuel category. The lower boiler sizes chosen may not be the lowest in each category due to the
exponential growth in costs (and also  estimation errors)  characteristic of the algorithm.   The
exponential growth in costs indicates that with smaller boiler sizes,  it is economically unfeasible to
consider them candidates for NOX control retrofits.

       Although these parametric variation provide a measure of cost variability for boilers  with
different firing configurations, fuel type, capacity factors, age, baseline NOX emissions, and control
technology, they do not yet address the potential cost variations due to site-specific factors. These
factors can add significantly to  the variability in cost shown by these parametric variations.  The
major site-specific factors that can influence the cost significantly are the following (Smith, 1991 and
Kleisley, 1991):

           Condition of the existing equipment
           Type of windbox
           Presence of asbestos insulation
           Access to the boiler
           Space availability
           Operating constraints

       The condition of the existing boiler refractory, burner, waterwall, windbox, and ancillary
equipment at the power plant plays  a significant role in the retrofit modifications necessary for
many low-NOx combustion modifications. For example, the windbox air dampers may have been
frozen in a given position for many years necessitating the  replacement of the windbox even with
"plug-in" burner replacements.  Pulverizers, fans, waterwall panels  may also require replacements
even with the most straight forward retrofits depending on condition.  Often, older  units were
equipped with castable windboxes that can  not be easily modified  and  must be replaced entirely.
Physical interferences, such as buckstays, headers, and downcomers, can limit available locations for
OFA and reburning ports, altering the effectiveness of the technology and  decreasing the  cost
effectiveness (Lisauskas, 1987 and Carnevale, 1989). The relocation of such equipment can be
prohibitively expensive (Lisauskas, 1987). The degree of pressure parts changes can also affect the
overall retrofit cost significantly (Vatsky, 1989).
                                            5-9
-------
                         Table 5-3.  Cost cases for coal-fired boilers
Case No."
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Control Technology
OFA
LNB
LNB"
LNB + OFA
LNB + SOFA'
NCR
NGR
NCR
SNCR
SNCR
SNCR
SNCR
SCR (cold side)"
SCR (cold side)"
SCR (cold side)"
SCR (cold side)"
SCR (hot side)'
SCR (hot side)'
Boiler Firing Type
Wall
Wall
Tangential
Wall
Tangential
Wall
Tangential
Cyclone
Wall
LNB-Controlled
Wall
Tangential
LNB-Controlled"
Tangential
Wall
LNB-Controlled
Wall
Tangential
LNB-Controlled"
Tangential
LNB-Controlled
Wall
LNB-Controlled"
Tangential
Cost Reference
Sorge, 1992
See Figure 6-4
Manaker, 1992
Sorge, 1992
See Figure 6-5
Farzan, 1991
EERC, 1991
Farzan, 1991
EERC, 1991
Farzan, 1991
EERC, 1991
Nalco, 1992
Hunt, 1992
Nalco, 1992
Hunt, 1992
Nalco, 1992
Hunt, 1992
Nalco, 1992
Hunt, 1992
Robie, 1991
Robie, 1991
Robie, 1991
Robie, 1991
Robie, 1991
Robie, 1991
'Case No. indicates the order in which cost analyses spreadsheets can be found in Appendix F.
"LNB for tangential units is based on LNCFS I with CCOFA.
TNB+SOFA is based on LNCFS Levels II or III.
"Cold side SCR retrofit downstream of ESP and FGD with reheat penalty.
*Hot side SCR retrofit downstream of economizer with small energy penalty for bypass.
                                            5-10
-------
                     Table 5-4.  Cost cases for gas- and oil-fired boilers
Case No."
1
2
3
4 '
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Control Technology
BOOS
BOOS
FOR
FOR
LNB
LNB
BOOS + FGR"
BOOS + FGR"
LNB + FGR + OFA
LNB + FGR + OFA
SNCR
SNCR
SNCR
SNCR
SCR
SCR
SCR
SCR
Boiler Firing Type
Wall
Tangential
Wall
Tangential
Wall
Tangential
Wall
Tangential
Wall
Tangential
Wall
BOOS + FGR-Controlled
Wall
Tangential
BOOS + FGR-Controlled
Tangential
Wall
BOOS + FGR-Controlled
Wall
Tangential
BOOS + FGR-Controlled
Tangential
Cost Reference
Mormile, 1987
Mormile, 1987
Mormile, 1987
Mormile, 1987
Mormile, 1987
Mormile, 1987
Mormile, 1987
Mormile, 1987
Carnevale, 1989
Yee, 1989
Carnevale, 1989
Yee, 1989
Springer, 1992
Springer, 1992
Springer, 1992
Springer, 1992
Johnson, 1991
Johnson, 1991
Johnson, 1991
Johnson, 1991
"Case No. indicates the order in which cost analyses spreadsheets can be found in Appendix G.
"Alternatives to BOOS + FGR include OFA + FGR.
                                           5-11
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-------
       Some older boilers  were enclosed  in  power  plant  buildings.   These  enclosures  can
significantly add to the complexity of the retrofit (Smith, 1991).  When castable windboxes must be
replaced because of low-NOx burner retrofits, it is sometimes necessary to tear down the building
to allow access to and removal of the windboxes.  Such large modifications can result in the removal
of asbestos-insulated ducts and piping, resulting in a significant increase in the cost of disposal
(Smith, 1991 and Carnevale,  1989). The available space near the power plant is also critical to the
cost for some retrofit  technologies such as SCR.  Because of such space restrictions, for example,
SCE has reported SCR retrofit costs for some of the facilities as high as twice the estimates by local
regulatory agencies (Johnson, 1983). Operation of the boiler and its duty cycle also influences the
retrofit cost and cost effectiveness.  In most applications, the NOX reduction performance of
combustion modification technologies and noncatalytic flue gas treatment processes varies with
boiler operating loads. Although on a mass emission basis emissions are lower at lower loads, the
percent of NOX reduction attributed  to the retrofit technology is generally less than at higher loads,
unless  the control was specifically designed to operate at reduced heat input rates.
                                           5-14
-------
                                        SECTION 6

                                COST OF NOX CONTROLS


       The costs presented here are based on cost data reported in the open literature for similar
retrofit cases, or, when available, on estimates obtained directly from technology vendors and users.
However, it is important to point out that actual retrofit costs are quite dependent on several site-
specific factors,  as discussed in Section 5. Because of this dependence, the costs presented here
should not be interpreted as applicable to any specific power plant within the NESCAUM utility
boiler population.  By evaluating several cost cases based on boiler size, age,  and capacity factor,
we have attempted to develop ranges in NOX control costs that encompass some of the uncertainties
due  to  site-specific factors.  However, site-specific considerations could  significantly  alter the
estimates presented here." To develop actual costs for specific power plants, a detailed analysis is
necessary of the type and condition of the existing equipment, its layout, the fuel type, and the
boiler operating characteristics. Additionally, some sites may incur costs for replacement power if
retrofit of controls exceeds scheduled outages.  The current  regulatory schedule mandated under
Title I of the CAAA calls for many retrofit NOX controls to be in place by May 1995.  Because of
the anticipated volume of retrofit equipment to be engineered, procured, installed, and tested during
this short time,  an inflationary factor is anticipated to result in actual costs above the estimates
presented here.  Evaluating the effects on projected costs of these site-specific factors, and global
market forces, was beyond the scope of this study.

       Combustion modification controls for NOX reduction on existing coal-fired utility boilers
have been applied only in the past few years.   Therefore, retrofit experience and actual costs of
these controls have only been documented recently. Ongoing commercial retrofit and demonstra-
tion projects are generating new information on performance, cost, and operational impacts.  For
oil- and gas-fired boilers, the retrofit experience and documented costs is based principally on data
reported by California utilities that have been the target of NOX reduction regulations for the past
15 years.  Many of the combustion modifications considered in this study for  oil- and gas-fired
boilers in the NESCAUM region have been in  use for several years on SCE, LADWP,  SDG&E,
and PG&E boilers in California. Because of the recent passage of more stringent NOX rules by the
SCAQMD, these  utilities  are  now evaluating the least-cost options using  second- and  third-
generation retrofit controls, including several flue gas treatment options.

       This section presents the cost estimates  of retrofit control options evaluated and reported
in Section 4 of the report. Capital costs reflect those reported in the literature or obtained directly
from technology vendors. All capital costs are escalated to first quarter  1991 dollars. Where several
sources of data are available for these costs, a comparison of the costs developed in this study with
costs reported elsewhere is made.  The procedure for developing levelized  busbar costs relies on
available information on consumables, such as fuel from efficiency loss and NOX reduction reagents,
and levelization  factors for capital cost based  on EPRI premises,  as discussed in  the previous
section.   Cost-effectiveness  results include estimates  of NOX  reduction potential  based  on
information presented in Section 4.
                                            6-1
-------
6.1     COMBUSTION MODIFICATIONS FOR PC-FIRED BOILERS

       Combustion modifications for PC-fired boilers include OFA, LNB, LNB + OFA, and natural
gas reburning (NGR) or pulverized-coal reburning.  For reburning cost analysis, only NOR was
evaluated because there is a larger experience base with this reburning fuel. The following sections
detail the retrofit costs of these control options for coal-fired power plants.  Appendix F provides
details of the various cost elements and calculations based on the simplified algorithm developed
for this study.

6.1.1   Overfire Air (OFA)

       OFA is considered a first-generation control option that was included  in some new boiler
designs to comply with NSPS limits (LaRue, 1990; Lisauskas,  1989).  Many of these first-design
OFA ports, however, have remained closed because of the ability of these units to comply with
NSPS limits without their use.  More recently, AOFA systems have been investigated.   These
systems rely on improved control and better penetration for improved performance.  AOFA is
generally never considered without the use of LNB.

       In this section, OFA is defined  as the installation of overfire air ports, separate and above
the existing windbox, to provide a separation between the primary burner  zone and  the staged air
needed for complete combustion.  For tangential boilers, this type of OFA  is called  SOFA to
distinguish it from CCOFA, inherent to most T-firing systems.  This distinction  is not necessary for
wall-fired boilers because OFA is always injected separate from the existing windbox.  In both cases,
a new windbox  and associated  ducting and control  system  are  required,  with  waterwall
modifications,  to permit penetration of secondary air into the furnace.   Some  vendors of this
technology may require only the extension of the existing windbox (Lisauskas, 1989).  Although
retrofit experience is limited, it is generally accepted that the retrofitting of this technology will
require a separate windbox, and that the amount of OFA used is limited to 20 to 30 percent of the
total combustion air because of concerns with LOT, corrosion, and other operational impacts.

       Current OFA systems are capable  of NOX  reductions in the 15  to  30 percent  range,
depending on the initial uncontrolled NOX level, the degree of air staging, and firing configurations.
Typically, the higher degree of NOX reduction is achieved with higher uncontrolled levels of NOX.
The use  of OFA is often  associated with decrease in thermal efficiency due to an increase in
unburned carbon (UBC) in the flyash and a requirement for higher overall excess oxygen levels that
contribute to an increase in the dry gas heat loss.  Figure 6-1 illustrates the increase in UBC with
AOFA experienced for a tangential boiler retrofit.  These losses in efficiency contribute to the total
cost of the retrofit.  For  this cost analysis an efficiency loss  of 0.5 percent was  assumed  for all
retrofit cases involving the use of OFA or AOFA with or without  LNB.

       Figure 6-2 illustrates the calculated cost of OFA for pre-NSPS wall PC-fired boilers.  The
figure shows both the total capital  requirement (which includes process and project contingencies)
and the busbar cost. The cost effectiveness is shown in Figure 6-3 as a band in  cost for each boiler
size  to illustrate the effect  of a range in NOX reduction  from 0.95  Ib/MMBtu  to 0.8  and
0.7 Ib/MMBtu. The data are for a range in boiler capacities, each  with a book  life of 20  years and
a capacity factor of 65 percent. The estimates indicate that the reduction of 15 to 25  percent of the
NOX estimated for wall-fired boilers with OFA will cost approximately  from about $12/kW to
$25/kW depending on boiler size with a busbar of about 0.40 to 0.7 mills/kWh  and a resulting cost
effectiveness ranging from about $300  to $900/ton of NOX removed.
                                           6-2
-------

                  1
                  290      300

                   Unit Load (MWa)
                    390      400      400      900      990
  Figure 6-1. Flyash combustibles losses from parametric testing with AGFA (Wilson, 1990)
       30 r        1.0
       25
       20
    £  15 -
    or


       10 -
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                   0.6 -

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        0L       0.0
                                                         BOILER AGE = 30 years

                                                         CAPACITY FACTOR = 0.65
                             100      200     300      400     500

                                        BOILER CAPACITY (MW)
                                                         600     700
Figure 6-2. Total capital requirement and busbar cost of OFA retrofit for wall-fired PC boilers


                                          6-3
-------
        1,000
     c
     .     800
     LU

     LU
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                 BOILER AGE - 30 years
                 CAPACITY FACTOR - 0.65
                      100      200      300      400      500
                               BOILER CAPACITY (MW)
                                                           600
700
           Figure 6-3. Cost effectiveness of OFA retrofit for wall-fired PC boilers
6.12   Low-NOx Burners (LNB) for Wall-Fired Units and LNB + CCOFA for T-Fired Units

       LNB is the centerpiece of all major NOX reduction retrofit programs for PC-fired boilers.
The category of LNB encompasses a wide range of burner modifications and retrofit equipment
designed to reduce NOX according to the requirements of the utilities and within the limitations of
the technology and the boiler operational constraints.  The technology has undergone several
improvements over the years. More recent results of several utility boiler retrofits, including some
long-term measurements, have shown that LNB + OFA for wall-fired boilers can achieve reductions
of 35 to 55 percent, to levels in the range of 0.45 to 0.64 Ib/MMBtu (see Section 4 for details).

       For tangential boilers, LNB designs vary from minor equipment modifications of the LNCFS
Level I burner to more significant modifications of the LNCFS Levels II and III and PM systems
that incorporate SOFA systems. Controlled NOX levels for LNCFS with SOFA on two retrofits are
reported to range between 0.28 and 0.32 Ib/MMBtu (Hunt, 1991).  For PM burners, early tests on
the only retrofit demonstration to data in the United States show controlled NOX levels to as low
as 0.25  Ib/MMBtu (Wilson, 1990). All these LNB designs use OFA or AGFA. For this study, LNB
and LNB+OFA controlled NOX levels from tangential boilers were estimated to range between
0.30 and 0.45 Ib/MMBtu based on recent reports of control efficiency and average uncontrolled
levels for T-fired boUers in NESCAUM.
                                         6-4
-------
       The reductions in NOX are often commensurate with the degree of modification to the
existing equipment. For example, modification or replacement of existing pulverizers to increase
coal fineness can provide additional NOX reduction. Better air/fuel distribution is also necessary
to improve overall boiler efficiency and provide needed flexibility in boiler operation and fuel mix.
The discussion in this section is limited to cost estimates for LNB retrofit on wall-fired boilers.
LNB retrofit costs for tangential boilers are discussed in the following section on LNB + OFA
because most T-fired retrofits will likely be equipped with SOFA, which is responsible for most of
the NOX reduction capability of the LNCFS burner configuration.

       Table 6-1 lists the  LNB and  LNB + OFA  installation  costs of several recent retrofits.
Figures 6-4 and 6-5 plot these reported  costs versus  boiler size for wall-and tangential boilers,
respectively. The best fit power curve was taken as the basis for the total plant costs for these units.
For example,  the  TPC for LNB retrofit for wall-fired boilers was selected  at $15/kW for  a
400 MWe boiler. For T-fired units, the cost reported by TVA for Galletin  Unit 4 was selected as
the total capital requirement (TCR) for LNB+CCOFA on a 288-MWe boiler. For the combination
of LNB + OFA, the recent estimates for Hammond  Unit 4 provided cost basis for wall-fired units.
For T-fired boilers, the cost of retrofitting PSC Cherokee 350 MWe Unit 4 was selected as the basis
for LNCFS II or III burner systems.  These LNB + OFA costs are discussed  in greater detail in the
next section.  It is apparent that, beside boiler  capacity, the cost of LNB can  vary significantly from
site to site, often depending on the degree of additional modifications to existing equipment planned
or needed as part of the retrofit.

       Table 6-2 lists retrofit costs reported at an earlier date for the CF/SF LNB on several boiler
types. These reported costs vary from $4.0/kW to $9.3/kW. Table 6-3 lists retrofit costs developed
by another major boiler manufacturer (Lisauskas, 1987).  The first  two  lines in this table illustrate
the variation anticipated in the capital cost of LNB, even in these  early estimates. Estimates for
the cost to replace the existing burner with a  new LNB was predicted to range between $4.6/kW
and $8.7/kW (1983 dollars) for boilers in the  range of 140 to 400 MWe. Even after escalation to
1991 dollars, a comparison with data shown  in  Figures 6-4 and 6-5 shows that these early estimates
of LNB costs have proven lower than more recent costs.

       Figures 6-6 and 6-7 illustrates the costs calculated in this study for LNB retrofitted to wall-
T-fired  boilers, respectively.  The TCR for LNB  retrofitted on boilers from  680  to 100 MWe
capacity ranges from $14/kW to about $27/kW.  As shown in Table 6-1, several of the reported
costs fall near  estimates presented  in Figure 6-6.  For example,  TVA's Johnsonville 150 MWe
Unit 8 has a reported cost of $32/kW, comparable to  levels shown in Figure 6-6. Also  shown in
Figure 6-6, the cost  of LNB  is estimated to increase significantly for smaller units less than
150 MWe. The busbar cost includes an efficiency loss  of 0.25 percent.  For T-fired units, the cost
of LNB + CCOFA is considered comparable  to that of wall-fired  boilers.  Estimates shown in
Figure 6-7 show a range in cost from  about $20/kW  $33/kW  for a range in capacity of 375 to
100 MWe.

       Figure 6-8 illustrates the range in cost effectiveness for LNB retrofit  for wall and tangential
units. The range in boiler capacities were selected from the boiler population profile. The cost per
ton of NOX reduced is higher for T-fired boilers principally because NOX reduction, on a Ib/MMBtu
basis, are lower for this design category. The shaded part of the graphs illustrates the  uncertainty
in the overall NOX reduction, reported in Table 4-1.

       Cost effectiveness ranges from less than $200/ton to for  large wall-fired boilers  with  a
current  emission factor  of 0.95 Ib/MMBtu  to nearly $l,000/ton for T-fired boilers of 100 MWe
-------
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 Data reported in Table 6-1
                                         LNB + OFA
                                       (Hammond Unit 4L
                                 LNB only LNB + OFA
                                    a     	A	
               200           300           400
                         Boiler Capacity (MWe)
                                                            500,28
                                                              A
                                                          D
                                                          i
                                                         500
600
     Figure 6-4. Capital cost of LNB and LNB + OFA for wall-fired PC boilers
24

22
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 Data reported in Table 6-1
                          288 21
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                               /~TVA GaJlatin
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                                                   LNCFS II & III
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                             LNB
                                     LNB + OFA
                                      ...... A ......
                        300         400         500
                         Boiler Capacity (MWe)
                                                               600
                                                                       700
Figure 6-5. Capital cost of LNB with CCOFA and LNB + SOFA for T-fired PC boilers
-------
                              Table 6-2.  Retrofit material costs
MWe
525
650
600
600
800
800
No. of Burners
24
24
40
40
48
48
Burner Modification
Type
Circ.
Circ.
Cell
Cell
Circ.
Cell
Type8
1
1
1
2
1
3
$/kW
4.0
4.3
6.0
7.5
5.4
9.3
                  al =  Burner "Plug-in."
                   2 =  Burners + panels for vertical spread.
                   3 =  Burners + panels + convert to one mill/row.
                  Source: Vatsky, 1990.
                Table 6-3. Summary of Riley's economic evaluation for LNB

LNB
Coal nozzle retrofit
Total burner replacement
LNB plus conventional OFA
LNB plus advanced OFA
LNB plus reburning
Case A*
Capital
Cost

2.8
8.7
11.6
17.8
21.5
Leveiized
Cost

0.10
0.32
0.42
0.80
0.97
CaseBb
Capital
Cost

1.4
4.6
6.3
11.3
13.5
Capital Cost - S/kW
Leveiized Cost - mills/kWh (30-yr average)
Leveiized
Cost

0.05
0.17
0.23
0.51
0.57


CaseC0
Capital
Cost

2.1
5.4
7.1
13.8
53.2


Leveiized
Cost

0.08
0.19
0.26
0.62
2.40


Case Dd
Capital
Cost

1.4
4.8
6.0
14.9
L8.3


Leveiized
Cost

0.05
0.17
0.22
0.67
0.82


"Case A:  140 MWe, front-fired, four burner rows, no existing OFA ports.
bCase B:  400 MWe, front-fired, four burner rows, no existing OFA ports.
°Case C:  360 MWe, opposed-fired, two burner rows, no existing OFA ports.
dCase D:  360 MWe, opposed-fired,  three burner rows, with existing OFA ports.
Source: Lisauskas, 1987.
                                               6-8
-------



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pital and busbar cost of LNB retrofit for wall-fired PC boilers
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BOILER CAPACITY (MW)
Z
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350 400
Figure 6-7.  Capital and busbar cost of LNB + CCOFA retrofit for T-fired PC boilers




                                    6-9
-------
         1,200
      o  1'000 r
     (O    80°
     LLJ

     UJ
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     o
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     LL
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                                       WALL  TANGENTIAL
                •  BOILER AGE = 30 years
                :  CAPACITY FACTOR = 0.65
                       100       200      300      400       500
                                 BOILER CAPACITY (MW)
                                                             600
700
        Figure 6-8. Cost effectiveness or LNB for wall and tangential PC-fired boilers
capacity.  For wall-fired boilers, the cost effectiveness of LNB are lower than those calculated for
OFA alone.

6.13   Low-NOx Burners and Advanced Overfire Air (LNB + AOFA)

       LNB + OFA, or AGFA, for wall-fired boilers and LNCFS Level II and III with SOFA are
the most effective combination of combustion modification control techniques evaluated to date for
PC-fired boilers. Recent retrofit results on both tangential- and wall-fired boilers have shown NOX
reductions of 30 to 60 percent (see Table 4-4), and NOX levels as low as 0.30 Ib/MMBtu for some
tangential boilers.  Actual NOX  levels  will vary according to coal properties and design and
operational constraints of the retrofit and the method of reporting and data averaging (e.g., short-
er long-term) as discussed in Section  4. For the most part, these levels are reported with minimal
operational impacts such as accumulation of furnace slag, changes in furnace exit gas temperature
(FEGT),  waterwall corrosion, boiler  load turndown capability,  and  effects on  precipitator
performance. However, several severe design and operational problems have been experienced in
some retrofits pointing to the additional development needed for this combination of technologies
(Sorge, 1992; Wingard,  1992).  Because  OFA  is used,  some reduction in boiler efficiency is
anticipated as illustrated in Figure 6-1 and discussed in Section 7.  For  these cost  estimates, an
efficiency loss of 0.5 percent was used to determine the fuel penalty of the LNB + OFA retrofit.

       The base capital costs for this combination control technology were determined from recent
estimates for Plant Hammond Unit 4, for wall-fired boilers, and from cost trend shown in Figure 6-5
                                          6-10
-------
for tangential boilers; As of this writing,  the Hammond Unit 4 provided the only cost data for
LNB+OFA for wall-fired units as shown in Figure 6-4. Figures 6-9 and 6-10 illustrate the TCR and
busbar costs calculated  for wall- and tangentially-fired PC boilers retrofitted with LNB + AOFA
systems.   In all cases,  the retrofit included the complete replacement  (for T-fired  boilers)  or
extensive modification (for wall- or opposed-fired boilers) of the existing windbox, installation of
AOFA air ducts and windbox, dampers and  controls, and a new burner management system.

       As shown in Figures 6-9 and 6-10,  with the exception of the units smaller than  100 MWe,
the cost of this retrofit  technology on wall-fired boilers is  estimated to range from slightly over
$20/kW for the largest boilers (660 MWe  for wall-firing and 375 MWe for T-firing) to more than
$40/kW for the smaller boilers.  In contrast, retrofit estimates in 1983 dollars for  140  MWe wall-
fired boilers were as high as $!7.8/kW (Lisauskas, 1987).  For tangential boilers, the costs are
estimated to be slightly  less, depending on the number of burner corners to be modified (4  or 8).

       Figure 6-11 illustrates the corresponding cost  effectiveness estimates for the two retrofit
cases. The band of costs for T-fired boilers is wider because of the larger range in control reduction
effectiveness resulting from SOFA.  It should also be emphasized that because T-fired boilers have
an initial NOX level lower than wall-fired boilers (i.e., the average uncontrolled NOX in NESCAUM
is 0.6 Ib/MMBtu for T-firing and 0.95 Ib/MMBtu for wall- and opposed-firing), equivalent capital
and operating costs will result in higher costs per ton of NOX removed for T-fired units.  Therefore,
for 30-year-old boilers with a 0.65 capacity factor, the estimated LNB + OFA cost effectiveness for
wall-firing is between about $200/ton and  $600/ton, compared to $400/ton  to  $l,200/ton for
T-firing.

       Boiler age and capacity factor influence the cost-effectiveness of these controls. Figures 6-12
and 6-13 illustrate the effect of boiler age  and  capacity factor  on the cost effectiveness of the
LNCFS II or III  burner (for T-fired  units) and LNB + OFA for  wall-fired units  retrofitted on
200-MWe boilers. The effect of boiler age is to increase the levelization  factor for the  TCR,
Therefore, retrofits that have a high TCR  will show a significant  effect of boiler age which results
in increased cost.  The effect of lower book life is to increase cost effectiveness by about 20 percent.
Similarly,  lower capacity factors increase overall  costs, as shown  in Figure 6-13. These estimates
suggest that  to reduce  1 ton of NOX from  a boiler operating with a 40 percent capacity factor
instead of 65 percent will cost approximately 50  percent more.   However, it is apparent that the
amount of NOX reduction is the principal variable affecting cost effectiveness.

6.1.4   Reburn for Cyclone Boilers

       The cost of NGR is sensitive to three principal factors: the availability of onsite  natural gas
pipeline, the cost of natural gas compared  to the  coal, and the amount of returning used (Farzan,
1989 and Maringo, 1987). In Section 4, NGR is considered for application to all major boiler types.
However,  a cost analysis was presented only for cyclone boilers because these retrofits will provide
the most attractive cost effectiveness for this technology due to the larger NOX reductions that can
be  achieved.  Cost  analyses for NGR retrofit  on wall and tangential  units are  presented  in
Appendix F.  The cost for wet-bottom boilers will be influenced by the size of the furnace and the
available residence time  to induce an effective reburn and complete combustion within the available
furnace volume.  Research by B&W indicates that NGR can be applied  to  most cyclone boilers
without negative effects on the heat absorption profile in the furnace. An increase in efficiency loss
is anticipated, however (Farzan, 1989; EERC, 1990). A recent report by the developer, Energy and
Environmental Research Corporation (EERC) for GRI  sets the capital cost at $30/kW for large
capacity boilers (EERC,  1990). The report  also states that there are no adverse operational impacts
of gas reburning.  Several demonstrations  to evaluate these claims are ongoing.

                                           6-11
-------







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, . . . 1 , . . . 1 . . . . 1 . . , , ! . , , . 1 . , , , 1 , , , ,
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Figure 6-9. Capital and busbar cost of LNB + OFA retrofit for wall-fired PC boilers




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Figure 6-10. Capital and busbar cost of LNB + SOFA retrofit for tangential-fired PC boilers




                                       6-12
-------
    I

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                      100       200       300      400       500


                                  BOILER CAPACITY (MW)
                                                                600
                                                                         700
Figure 6-11. Cost effectiveness of LNB+OFA retrofit for wall and tangential PC-fired boilers
        1,400
        1.200


      Ct


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            15
                  20
                                                  LNB + OFA - PC WALL FIRED UNITS
                                                                     40
                             25         30          35

                              BOILER AGE (years)

Figure 6-12. Effect of boiler age on the cost effectiveness of LNB + OFA systems
                                                                           45
                                         6-13
-------
         1,750
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      CO
      CO
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                           LNB + SOFA - PC TANGENTIAL FIRED UNITS
                   BOILER CAPACITY - 200 MW
                   BOILER AGE -30 years

                   , , , ,  , i I	, ,1
                                                    LNB + OFA - PC WALL FIRED UNITS
              30
                   40
 50         60          70
CAPACITY FACTOR (%)
80
90
     Figure 6-13.  Effect of capacity factor on the cost effectiveness of LNB + OFA systems


       NGR costs were  developed using the capital equipment cost reported for  a  200-MWe
cyclone with 50-percent NOX reduction and with a natural gas use rate of 15  percent of the total
heat input (Farzan, 1989). In that study, the process capital cost was estimated at $22.4/kW for a
200-MWe cyclone boiler  and the busbar rate at 2.3  mills/kWh.  Thermal efficiency loss of
0.5 percent was assumed to account for additional latent  heat of increased moisture in the flue gas.
When installing a gas pipeline or using coal as the reburning fuel, the capital cost is reported to
double to the range of $41 to $44/kW.  Estimates for pipeline installation are about $lM/mi. This
pipeline cost was not considered in the analysis because of wide variability in cost. The levelized
busbar cost increases to $3.1 mills/kWh in the case of the pipeline requirement.  Fuel differential
cost savings reduce the busbar cost for coal reburning to less than that of NGR (Farzan, 1989).

       Figures 6-14 and 6-15 illustrate the costs calculated for the NESCAUM  study using the
Farzan process capital cost data  and EPRI economic premises.  The data indicate a TCR  in the
range of $35 to $50/kW  scaled according to  boiler size and a  cost effectiveness  in the range of
about $500 to $800/ton for a NOX  reduction of 45 to 65 percent from an uncontrolled  NOX level
of 1.28 Ib/MMBtu. Because of the large contribution of fuel cost to the total busbar cost, the cost
effectiveness was found not to vary appreciably with capacity factor or age of the boiler.  The cost
effectiveness of NGR is heavily influenced by  the  differential in cost between natural gas and coal
as shown in Figure 6-16. These cost estimates do  not include an economic credit for the reduction
of SC>2 emissions. SO', emissions are reduced  by an amount equivalent to the coal displaced. This
credit can be an important consideration if the retrofit boiler is also subjected to SO0 control. This
credit is estimated by GRI at $500  to $700/ton (EERC, 1991).
                                           6-14
-------








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i . . . . i , . , , i . . . . i . , , , i

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BOILER CAPACITY (MW)
(X
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            BOILER AGE = 30 years

            CAPACITY FACTOR = 0.73
      100
150
               200       250        300

             BOILER CAPACITY (MW)

Figure 6-15. Cost effectiveness of NCR for cyclone boilers
350
400
                                  6-15
-------
        1,600
    ~  1,400
     o
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o
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                                                         BOILER SIZE = 200 MW
                                                         BOILER AGE = 30 years
                                                         CAPACITY FACTOR - Q.73
                                                         REBURN FRACTION = 0.15
                                                                          2.5
             0            0.5            1            1.5           2
                      DIFFERENTIAL FUEL COSTS ($/MMBtu)

 Figure 6-16.  Effect of Fuel differential cost on the cost effectiveness of NCR for cyclone boilers
6.1.5   Summary of Combustion Modification Retrofit Costs for Coal-Burning Power Plants

       Table 6-4 summarizes the costs calculated for several retrofits of coal-fired boilers with
combustion modifications. These costs are for a 20- to 40-year-old 200-MWe boiler with a capacity
factor in the range of 40 to 82 percent. The data illustrate that the cost effectiveness of these
combustion modification controls ranges between $160 and $l,200/ton of NOX removed, for wall-
fired boilers, and $420 to $2,200/ton, for tangential units.  The actual cost is based on several
factors not limited to boiler capacity, baseline NOX, boiler age, and capacity factor. The cost to
reduce emission levels with LNE only for tangential boilers and for wall-fired boilers is estimated
to be lower than all other options, including OFA only, LNB + OFA, and reburn.

62    CONTROLS FOR OIL-/GAS-FIRED  BOILERS

       Combustion  modification NOX control  technologies for  oil-/gas-fired  boiler retrofits
evaluated for cost in this study include:

          Burners out of service (BOOS)
          Flue gas recirculation (FOR)
          Low-NOx burners (LNB)
          BOOS+FGR
          LNB+OFA+FGR
                                         6-16
-------
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                                           6-17
-------
Reburning was not considered for these boilers because the retrofit experience with this approach
is minimal.  Ongoing research in Italy, and, to some extent, in the United States, has shown that
NGR for oil-fired boilers can offer NOX reduction potentials on the same order as those attainable
with more conventional controls. Therefore, it holds promise for some applications.  No cost data
are available, however.

       The  following  section discuss  the costs developed in this study.   For each of  these
technologies, capital and operating cost information reported in the literature was used to establish
the base case on which  the EPRI economic premises were applied. Standard procedures were then
applied to develop costing for various boiler applications according to capacities, age, and capacity
factor.  Appendix G provides details of cost calculations for these boiler retrofit test cases.

62.1   Burners Out Of Service (BOOS)

       The basic cost information for this technology was taken from a recent study for the Empire
State Electric  Energy Research Corporation (Mormile, 1990).  BOOS is the simplest  and least
expensive combustion modification for oil-/gas-fired utility boilers.  Its implementation requires no
retrofit equipment with the exception of-some online analyzer for emissions monitoring.   The
principal capital cost is due to the combustion and emissions testing that is necessary to  select the
optimum burner pattern for minimum NOX, with the least impact on emissions of other pollutants,
efficiency loss, and operational impacts such as  load turndown capabilities.   The impact on the
boilers is difficult to ascertain because it can vary significantly with the boiler burner pattern and
the steam load requirements of the unit.  Loss in boiler  efficiency can vary between  zero and
1 percent depending on the degree of staging applied and  the resulting increase in  the minimum
excess oxygen  necessary to ensure good combustion. An efficiency loss of 0.3 percent  was used
based on estimates provided by Consolidated Edison and past NOX control efforts (Hunter, 1989).
BOOS is applicable to  both wall-fired (single wall or opposed)  and T-fired boilers.

       Figures 6-17 and 6-18 illustrates the cost and cost effectiveness of BOOS  as a function of
boiler  capacity. The TCR is estimated at less than $1.0/kW for  most size  units and the cost
effectiveness is estimated to be relatively independent of boiler capacity at less than $200/ton. The
cost effectiveness for  wall-fired boilers, which  is based  on  a reduction from an average of
0.45 Ib/MMBtu to a range of 0.30 to 0.35 Ib/MMBtu (20 to 35 percent efficiency) for most  units,
does not vary significantly  with boiler size because most of the cost is due to loss of fuel efficiency.
Higher NOX reductions and thus improved cost effectiveness, are possible for boilers with initially
high baseline levels. Therefore, higher costs are anticipated for BOOS on T-fired boilers.

622   Flue Gas Recirculation (FGR)

       The retrofit installation of WFGR can be quite costly. The fan, flues, dampers and controls,
as well as possibly requiring existing fan capacity to be  increased due to increased draft loss, can
represent a large  investment.  The amount of WFGR is generally maintained at levels lower than
25 percent because  of  draft loss, cost, and  flame instability.  Little additional NOX reduction is
gained with FGR rates greater than  15 percent.  In addition, the FGR system can require a
substantial maintenance program.

       Costs for FGR  were also developed based on capital and O&M costs published under the
ESEERCO study (Mormile, 1990, and Hunter,  1989).  FGR is applicable to both tangential and
wall-fired boilers.  The retrofit of  FGR requires  the installation of  a  fan to recirculate up to
30 percent of the  flue gas to the windbox, ducting, and associated dampers and controls.  Detailed
combustion testing is also necessary to ensure adequate distribution of the FGR flow to each burner

                                           6-18
-------









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1 .... 1 	 	 1
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0 200 400 600 800 1000
• BOILER CAPACITY (MW)
    Figure 6-17.  Capital and busbar cost of BOOS for oil/gas wall-Fired boilers
  CO
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       1,000
        800
600
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                                   WALL    TANGENTIAL
              BOILER AGE = 25 years

              CAPAOTY FACTOR = 0.40
           0           200          400          600           800          1,000


                               BOILER CAPACITY (MW)


Figure 6-18.  Cost effectiveness of BOOS for wall and tangential oil-/gas-fired boilers
                                      6-19
-------
and to determine the most effective FGR rates through the boiler load  range.  Figures 6-19
and 6-20 illustrate the calculated costs for FGR. TCR estimates range between $6/kW and $ 12/kW
for units below 200 MWe; when the capacity factor is more than 0.40, the cost effectiveness for
units 200 MWe and larger ranges from about $300 to $ 1,000 per ton of NOX removed for wall-firing,
twice as much for T-firing.  The NOX reduction effectiveness of FGR and, consequently the cost
effectiveness, very significantly with the type of boiler fuel. Better FGR performance and lower cost
should be anticipated when burning clean fuels such as natural gas and high-grade fuel oil.

6.2.3   Low-NOx Burners (LNB)

       As discussed in Section 4, LNB for oil- and gas-fired  utility boilers has only recently been
introduced  as a retrofit  option. The intent of these retrofits, especially in California, has been
primarily to improve combustion stability at extremely low NOX conditions induced by other controls
such as FGR, OFA, BOOS, or  a combination of these.

       Estimates of LNB retrofit cost for this study were based primarily on estimates provided by
Consolidated Edison  Co. (Mormile  1989).  These utility estimates show a cost of $20/kW for a
350 MWe  boiler.  In comparison, the retrofit of B&Ws PG-DRB burners  on LADWP Haynes
230 MWe Unit 3 was reported to cost about $10/kW with additional $16/kW for asbestos removal
and disposal, compartmenting the windbox,  and adding a primary  gas injection system (Carnevale,
1989).  The Southern California experience shows that the  estimate by Consolidated Edison in
reasonable, and therefore it was adopted for this study.

       Figures 6-21 and 6-22 illustrate the capital cost for retrofit  of LNB on wall-fired boilers and
cost effectiveness of this control option for wall and tangential units.  These  estimates show that
LNB will cost from about $16 to 38/kW to retrofit depending on the size of the boiler.  The cost
to removal  1 ton of NOX will be higher for a 200 MWe tangential  unit ($1,000 to $5,000/ton) than
for a wall-fired unit ($750 to $l,700/ton) because of higher NOX reductions anticipated for wall-
fired boilers.

6.2.4   Burners Out of Service and Flue Gas Recirculation (BOOS + FGR)

       The combination of BOOS + FGR is an  effective approach in the control of NOX from
oil-/gas-fired boilers.  In place  of BOOS, OFA ports can also be  used to achieve the combustion
staging necessary for deep reduction  in  NOX or  to  provide  better  combustion air mixing.
Appendix C provides  schematics of retrofits of FGR and FGR-t-OFA techniques  installed  on
Southern California boilers.

       The basis for costing the BOOS + FGR combination of controls was simply derived from the
addition of the individual costs discussed in Section 6.2.1 and 6.2.2.  Figure 6-23 illustrates  the
capital cost of BOOS + FGR on a wall-fired boiler.  The capital cost for a tangential boiler  is
anticipated to be the same.  Figure 6-24 illustrates that the cost effectiveness of this control option
can be quite low, from $440 to  $850/ton for wall-firing and $580  to $l,300/ton for T-firing.

6.2.5   Low-NOx Burners, Overfire air, and Flue Gas Recirculation (LNB + OFA + FGR)
       Combining combustion controls provides for greater NOX reduction potential. Although the
costs are nearly additive, NOX reductions are generally not.  Cost data for two boiler retrofits with
a combination of LNB + OFA+FGR have been reported (Bisonett, 1991; Yee, 1989; and Carnevale,
1989).  The LNB was the B&W PG-DRB, which is designed to use FGR in combination with OFA.
                                         . 6-20
-------
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                                     6-22
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Figure 6-24. Cost effectiveness of BOOS + FGR for wall and tangential oil-/gas-fired boilers
                                         6-23
-------
This combination technology represents one of the most effective methods for reducing NOX from
oil-/gas-fired boilers.

       Engineering evaluation of the retrofit modifications to an opposed-fired 345-MWe boiler,
owned and operated by PG&E, show that the modifications required to achieve a reduction in NOX
from the 350 to 400 ppm (0.45 to 0.51 Ib/MMBtu) to 75 to 150 ppm (0.10 to 0.20 Ib/MMBtu) range
included the following (Bisonett, 1991):

           Replace FOR fan motor
           Install new FOR and OFA ducts and dampers
           Install 24 new PG-DRB burners and associated piping and controls
           Partial replacement of superheater tube banks
           Upgrade of steam attemperation for increased capacity
           Installation of 12 OFA ports
           Upgrade of boiler control system

The reported TCR for this installation was $45.7/kW with a total levelized cost of 3.7 mills/kWh.

       The second cost estimate for a similar retrofit application, but this time on a 145-MWe front
wall-fired boiler. The equipment  modification implemented on this unit included (Yee, 1989):

       •   Installation of nine PG-DRB B&W LNBs and OFA ports
       •   Improved steam atomizers for oil firing
       •   Upgrading of the boiler control system
       •   Modification of the existing FGR system

As  indicated, the boiler was already equipped  with FGR and required only modifications and
upgrades to meet  the requirement of the PG-DRB operation. The reported TCR for this retrofit
installation cost was $26/kW.   Because the unit was already equipped with FGR, this cost was
avoided in the retrofit.  NOX emissions were reduced significantly from this boiler from  about
600 ppm (0.75 Ib/MMBtu)•without any controls burning oil to  a guaranteed level of 180 ppm
(0.23 Ib/MMBtu).

       The third retrofit cost of this most-effective combustion control combination was reported
by the Los Angeles Department  of Water  and Power (Carnevale, 1989).   For this retrofit, the
230-MWe opposed-fired Haynes Unit 3 was selected for the economic evaluation. The PG-DRB
burners with a combination of OFA and FGR required the following modification to the boiler and
ancillary equipment (Carnevale, 1989):

       •   Replacement of the existing mechanical atomized circular oil/gas burners with steam-
           atomized PG-DRB with 20 percent FGR capability

       •   Modification of the existing windbox using compartmentalization for  better air flow
           distribution, (also required asbestos removal)

       •   Installation of OFA ports and associated ducting, dampers, and controls

       •   Replacement of the existing FGR fans and associated ductwork, dampers, and controls

       •   Improved boiler management system
                                          6-24
-------
       •   Significant structural modifications to accommodate the new ducting arrangement

The total retrofit cost of this equipment was estimated at $51/kW.

       These three retrofit cases provide a range in costs for the same technology based on the use
of the B&W PG-DRB burner patterned  after the Babcock  Hitachi K.K. (BHK) HTNR design.
These costs range from $26/kW, for the  145-MWe boiler, to $51/kW, for the 230-MWe LADWP
retrofit case.  The low estimate, however, does not include the installation of a new FOR system,
necessary for a facility not already equipped with this low-NOx technology. For our cost analysis,
we  based  the calculations  of the retrofit cost  on  the TCR  estimates provided  by LADWP
(Carnevale, 1989).

       Figure 6-25 illustrates the calculated costs for this control option for oil/gas wall-fired
boilers. The TCR ranged from about $34/kW to $72/kW for  boilers in the 100 to 850 MWe range
(the NESCAUM boiler range).  The cost for smaller units escalates significantly.  For 200-MWe
boilers with a capacity factor greater than 0.40, the cost effectiveness for wall-fired boilers ranges
from about $1,400 to $2,500 for the older and smaller boilers, as shown in Figure 6-26.

62.6   Summary of Combustion Modification Retrofit Costs for Oil- and Gas-Fired Power Plants

       Table 6-5 summarizes the costs for combustion controls on oil- and gas-fired boilers with
a medium capacity of 200 MWe.  Minimum NOX levels for these units are estimated to be on the
order of 0.10 to 0.20 Ib/MMBtu deemed more likely when  burning clean fuels with little  or  no
nitrogen content. This control level corresponds to a  reduction of about 45 to 80 percent for wall-
fired  boilers and  about 40  to 60 percent for T-fired units.   The costs of these reductions are
estimated  to range between  $900/ton  and $2,000/ton, for controls on wall-fired  boilers, and
$l,600/ton to $5,200/ton, for controls on tangential boilers, based on a combination of OFA, LNB,
and FGR.  Larger capacity boilers would  exhibit lower costs.  NOX  reduction on the order of 15 to
40 percent can be achieved on some boilers at very low cost" using  BOOS.

63     FLUE GAS TREATMENT CONTROLS

       Flue gas treatment controls evaluated for the cost of retrofit  on oil-/gas- fired and coal-fired
boilers include the urea-based SNCR and the ammonia-based SCR processes.  For PC-fired power
plants, the SCR cost was based on the retrofit of the reactor downstream of any particulate or SO-,
control systems (cold-side).   Although more costly than the hot-side  SCR installations  more
commonly found in Europe and Japan, the cold-side retrofit application is considered more feasible
for United States coals (Lowe, 1991). This application requires the expensive use of fuel to reheat
the flue gas to catalytic reaction temperatures. SCR capital and cost data for oil-/gas-fired boilers
used in this cost analysis were taken from the information obtained by SCE (Johnson, 1991). For
PC-fired power plants, the capital and  operating cost  data were reported  in a detailed  study
sponsored by EPR1 (Robie,  1990).  Economic data for SNCR capital cost were supplied by vendors
of the technology and in recent full-scale retrofits (Albanese, 1991; Johnson, 1991; Hunt, 1992; and
Teixeira, 1992).

       Tables 6-6 and 6-7 summarize the range in costs for these FGT technologies when retrofitted
to coal- and oil-/gas-fired boilers, respectively. Cost effectiveness values are reported for two types
of applications: (a) boilers with uncontrolled NOX emissions, and (b) boilers whose emissions have
been lowered with available controls such as LNB for PC units and TSC (BOOS or OFA) + FGR
for  oil-/gas-fired  units.   NOX levels controlled  with a combination of commercially available
combustion modifications coupled with SCR  range between 0.05 to 0.10 Ib/MMBtu,  for oil-/gas-

                                          6-25
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                                          6-26
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                                                    6-29
-------
fired boilers, to 0.10 to 0.20 Ib/MMBtu, for PC-fired units.  When SCR is applied to uncontrolled
boilers, the limits of the SCR technology are estimated to range between 0.05 to 0.15 Ib/MMBtu,
for oil-/gas-fired boilers, and 0.10 to 0.25 Ib/MMBtu, for PC-fired boilers.

       Figures 6-27 through 6-36 illustrate the economic data developed for these FGT applications
for different boiler capacities. These costs are highly speculative considering the limited application
and experience in the United States.  The  following subsections highlight the basis for these cost
estimates and briefly discuss the results. Details on line item costs can be found in Appendix F, for
PC-fired boilers, and in Appendix G, for oil-/gas-fired boilers.

6.3.1   Selective Noncatalytic Reduction (SNCR) Costs

       Capital cost and cost-effectiveness for SNCR applications on PC-fired boilers are shown in
Figures 6-27 through 6-29.   Estimates are for boilers already controlled with the most effective
combustion modifications, and for boilers currently uncontrolled. The capital requirement of the
SNCR process is reported to vary widely, from $4/k\V (Teixeira, 1992) to $27/kW (Hunt, 1992).
For PC-fired boilers,  the capital cost for this study was based on two recent estimates, one for the
NOXOUT process retrofitted on WEPCO Valley Power Plant 89-MWe Unit 3, for which the capital
requirement was reported at about $28/kW (Nalco,  1992), and the other for a coal-fired 100-MWe
boiler at PSC Arapahoe Unit 4, for which the capital requirement was reported as high as $27/kW
(Hunt, 1992).

       For a 200-MWe boiler, these estimates translate to about $18/kW, as shown in Table 6-6.
Levelized busbar costs for SNCR processes are principally the annualized capital costs and the costs
of reagent use, which vary linearly with degree of NOX reduction. The calculated  cost effectiveness
for SNCR ranges from about $590/ton to $ 1,300/ton, for uncontrolled PC-fired boilers, to $760/ton
to $2,200/ton, for those PC  boilers  whose NOX emissions  have already been reduced with
combustion controls  to levels of 0.60 Ib/MMBtu, for wall-fired units, and 0.45 Ib/MMBtu, for
tangential-fired units.

       For oil-/gas-fired units, the capital cost of SNCR retrofit was based on recent  estimates
provided by PG&E on the basis of a recent field test demonstration on Morro Bay 350-MWe Unit 3
(Teixeira,  1992). During that study, the retrofit capital cost was estimated to range between $5 and
$10/kW. This estimate agrees with that of SCE for low-energy urea (Johnson, 1991). On this cost
premise, the overall cost effectiveness for SNCR on a 200-MWe oil-/gas-fired boiler was calculated
to range  between  $670/ton and S 1,300/ton,  for  uncontrolled units,  to  about $l,000/ton  to
$2,600/ton, for combustion-controlled units. The cost effectiveness is little influenced by the size,
age, and capacity of the boiler because reagent cost is the dominant portion of the overall busbar
cost.

632,   Selective Catalytic Reduction (SCR) Costs

       SCR is the most expensive option for reducing NOX from existing utility boilers.  Recent
SCR cost  estimates from applications of the technology show that the retrofit TCR for coal-fired
power plants has ranged from $60/kW to $189/kW in Germany and $35/kW to  $80/kW in Japan
(Lowe, 1991).  The German  experience is based on retrofit of generally hot-side SCR systems on
older, more congested power plants sites. SCE is evaluating the cost and technical feasibility of low-
cost SCR-based alternatives. One such technology,  already  under demonstration in Germany and
                                           6-30
-------
     15.0 r
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     10.0 -
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      3,000
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                                UNCONTROLLED  CONTROLLED
               BOILER AGE -25 years

               CAPACITY FACTOR - 0.40
                       200           400           600

                               BOILER CAPACITY (MW)
800
1,000
Figure 6-29.  Cost effectiveness of SNCR for uncontrolled and LNB-controlIed tangential

             coal-fired utility boilers




1
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250
225
200
175
150
125
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BOILER AGE = 30 years
t CAPACITY FACTOR = 0.65
0 100 150 200 250 300 350 4C
BOILER CAPACITY (MW)
I















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Figure 6-31.  Capital and busbar cost of hot-side SCR for coal-Fired utility boilers
     4,250
     4,000
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                      200 MW BOILER     400 MW BOILER     660 MW BOILER
                         :%^
                                                        BOILER AGE = 30 years
                                                        CAPACITY FACTOR = 0.65
                                                        CATALYST LIFE = 4 years

                                                        Combustion controlled coal/SCR
                     300         400         500          600

                               CATALYST COST ($/ft ^ 3)
700
800
  Figure 6-32. Cost effectiveness of cold-side SCR for coal-fired utility boilers-
               effect of catalyst unit cost
                                       6-33
-------
Q
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     4,250
     4,000
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                                        400 MW BOILER
660 MW BOILER
                                                         BOILER AGE = 30 years
                                                         CAPACITY FACTOR = 0.65
                                                         CATALYST COST = $660/ft ~ 3
                                                         Combustion controlled coal/SCR
                                  3           4           5

                                CATALYST LIFE (years)
  Figure 6-33. Cost effectiveness of cold-side SCR for coal-fired utility boilers-
               effect of catalyst life





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                                   UNCONTROLLED  CONTROLLED
                  BOILER AGE >2S years

                  CAPACITY FACTOR - 0.40
              0            200           400           600           800          1,000

                                   BOILER CAPACITY (MW)

    Figure 6-35. Cost effectiveness of SCR for uncontrolled and combustion-controlled wall
                oil-/gas-fired boilers
         20,000
         17,500
         15.000
      CO
      CO
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      UJ
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                  BOILER AGE >2S years

                  CAPACITY FACTOR = 0.40
                                                                                   1
200          400           600           800

        BOILER CAPACITY (MW)
                                                                                1,000
Figure 6-36.  Cost effectiveness of SCR for uncontrolled and combustion-controlled tangential
             oil'/gas-fired- boilers
-------
at SCE's Mandalay Unit 2, is the air heater SCR (CAT-AH) system which is reported to  have a
NOX reduction efficiency  in the range of 30 to 80 percent and a potential capital cost of only
$23/kW  (Reese,  1992; Johnson, 1991).  The upper range in NOX reduction performance was
reported for a combination of urea-SNCR with CAT-AH. The combination of urea-SNCR with
small downstream catalyst, such as the CAT-AH, may prove a viable economic alternative to SCR
systems in some retrofit cases.

       Tables 6-6 and 6-7, and Figures 6-30 through 6-36, present cost  estimates for SCR for
several retrofit cases, including hot- and cold-side catalyst installation, uncontrolled and controlled
boilers, and varying assumptions on  catalyst unit cost and durability.  For  PC units, the economic
data for SCR retrofit (both hot- and cold-side) were based on detailed cost estimates prepared by
EPRI (Robie, 1991).   For oil-/gas-fired units, capital costs of SCR were based on estimates
prepared by SCE (Johnson, 1991). Most of the SCR costs presented here are based on catalyst unit
pricing of  $660/ft3 and  a life of 4  to 6 years  for PC  and  oil-/gas-fired boiler applications,
respectively.

       The total capital requirement for SCR retrofit on the average size 200-MWe PC-fired unit
in NESCAUM is  estimated to be about $150/kW, for hot-side, and $190/kW, for cold-side. The
cost effectiveness  for uncontrolled units is estimated to range between $ 1,700/ton and $5,000/ton,
depending  on  the quantity of NOX reduced.  The cost effectiveness escalates to about $6,400/ton
for  NOX reductions from combustion-controlled levels.  Figures 6-32 and 6-33 illustrate some
important relationships between cost-effectiveness and catalyst unit cost and durability.  By halving
the catalyst unit price  from $660/ft3 to about $300/ft3 and extending its life from 4 to 6 years, the
overall cost effectiveness is reduced by a combined amount of about  15  percent.   This effect is
minor compared to changes in cost effectiveness due  to boiler size and NOX reduction efficiency.

       For 200-MWe oil-/gas-fired  boilers, the retrofit of SCR is estimated to average $ 135/kW
and result in cost effectiveness in the range of $2,600/ton to $7,400/ton, for uncontrolled boilers,
and $3,600/ton to $15,000/ton, for combustion-controlled units.  As  illustrated in Figures 6-35
and 6-36, the cost effectiveness of these retrofits is highly variable with boiler size because  of the
influence of the initial investment on the overall busbar cost.

6.4     SUMMARY OF CONTROL  COSTS

       Figures 6-37 and 6-38 illustrate the economic data for all of the control retrofit cases for
coal-fired boilers  investigated in this study. A standard boiler size of 200 MWe for PC-fired units
was selected for this comparison. The  information on NOX control level clearly indicates that NOX
emissions below 0.35  to 0.55 Ib/MMBtu, for wall-fired boilers, and 0.25  to 0.45 Ib/MMBtu, for
tangential boilers, are not achievable without the added control afforded by FGT technologies.  In
reality, as discussed in Section 4, combustion modification retrofits are unlikely  to attain the low
end of these NOX targets, and only higher control levels are considered possible with commercially
available technologies. The cost effectiveness of LNB and LNB + OFA control technologies  would
likely not exceed $l,000/ton for wall-fired boilers,  and be slightly higher for tangential units. For
larger size  boilers, the total capital requirement in $/kW and cost effectiveness will be lower.  All
other controls have higher costs per  ton  of NOX  removed compared to LNB  and LNB + OFA
controls. The data also illustrate  that, among these other  controls, both  NGR and SNCR on
uncontrolled boilers have estimated cost effectiveness  levels equivalent to those  of  combustion
modifications.

       Figure 6-39 illustrates the cost effectiveness of controls for a 200-MWe wall oil-/gas-fired
boiler; Figure  6-40 illustrates the same for a 200-MWe tangential oil-/gas-fired boiler.  Controlling

                                           6-36
-------
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 c  20,000
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CF = 40-82%


AGE = 20-40 years


Base NOx (Ib/MMBtu):

 Uncontrolled » 0.95

 Controlled = 0.60
                        0.2             0.4             0.6             0.8


                   CONTROLLED NOx EMISSIONS (Ib/MMBtu)
Figure
100,000
_ 50,000
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6-37. NOX control cost-effectiveness for PC wall-fired utility boilers
r TAf
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                                                                        0.5
 Figure 6-38.  NOX control cost-effectiveness for PC tangential-fired utility boilers
                                      6-37
-------
   100,000
                                                                 WALL-FIRING
                                                                 SIZE = 200 MW
                                                        °° uneontroll*d CF = 40-65%
                                                                 AGE = 15-40 years
                                                                 _   .^ ,„.„„_ .
                                                                 Base NOx (Ib/MMBtu):
                                                                   Uncontrolled - 0.45
                                                                   Controlled - 0.30
                                   SOTonuncontrelHd
                                                 I — I  SCflonBOOS+FOH
                                                 I _ I
                           0.1                0.2               0.3
                    CONTROLLED NOx EMISSIONS (Ib/MMBtu)
   Figure 6-39.  NOX control cost-effectiveness for oil/gas wall-fired utility boilers
   100,000
^ 50.000


c  20,000

<£ 10,000

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                                 FOR
[XJ  BOOSfOFA)

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n-n                TANGENTIAL-FIRED
^  ^B            SIZE = 200 MW
j~7|  SNCR on uncontrolled   CF = 40-65%
    *****           AGE = 15-40 years
D  c^roT^^"    Base NOx (Ib/MMBtu):
                                                                  Uncontrolled =• 0.30
                                                                  Controlled * 0.20
                     0.05         0.1         0.15         0.2         0.25
                     CONTROLLED NOx EMISSIONS (Ib/MMBtu)
                                                                                0.3
Figure 6-40. NOX control cost-effectiveness for oil/gas tangential-fired utility boilers
                                        6-38
-------
NOX emissions to levels as low as 0.25 Ib/MMBtu (about 200 ppm) is estimated to cost less than
$l,000/ton.  Lower costs are anticipated for larger capacity  boilers. Significant NOX reductions
from low NOX levels of tangential units are anticipated to cost more  than $ 1,000/ton, with the
possible exception of BOOS and FOR. The cost of further NOX reductions from these units will
be much higher regardless of the control option.

       Because of uncertainty in cost assumptions used in this study, and in reported costs for some
control  technologies with limited operational experience, these estimates are offered only as
guidelines.  Actual costs can be much different depending on the ease of retrofit; the extent of
equipment modifications; and the control's performance, including operational impacts.
                                          6-39
-------
-------
                                       SECTION 7

                                      CONTROLS
                        EFFICIENCY AND RELATED EMISSIONS
EFFECTS OF NOX CONTROLS ON COMBUSTION
       The reduction in peak flame temperature and the delayed mixing of fuel with combustion
air needed to suppress both thermal and fuel NOX formation can result  in a decrease in both
combustion and thermal efficiencies, therefore this must be considered during the design phase of
NOX retrofits to minimize these impacts. In oil- and gas-fired boilers, combustion efficiency losses
are indicated by concentrations of CO, THC, and soot (opacity) in the stack gas.   In PC-fired
boilers, reduction in combustion efficiency is evidenced primarily by an increase of the UBC in the
flyash. Along with its associated efficiency loss, the increased concentration of UBC in the flyash
can alter the properties of the ash, affecting the performance of the electrostatic precipitator, and
ultimately the emissions of fine particulate from  the stack. Also, increasing UBC levels can make
the ash unsalable, resulting in a significant ash disposal cost for some plants that currently sell the
ash for cement production.

       If unchecked, flue gas  CO, THC,  and soot emissions can have an adverse effect on the
environment in addition to decreasing system performance.  For example, the NESCAUM region
contains  nonattainment areas for CO and PM10, as well as for ozone. Therefore, it is important
to understand the effects of retrofit controls on these emissions and to identify the range of NOX
reduction that can be achieved without  adversely affecting the levels of these other emissions.

       The principal indicators of combustion efficiency in utility boilers are CO and stack opacity
for oil-/gas-fired boilers, and CO emissions and UBC content of the flyash for PC-fired units.
When burning natural gas and high grade fuel  oils in utility boilers, CO emissions will usually
increase  first before any measurable amount of THC or soot is emitted (Radak, 1991).  When
burning residual  oil, large increases in  CO emissions are followed by increases in soot formation
that contribute to opacity haze at the stack outlet.  THC emissions,  as measured by conventional
analyzers, are typically very low for utility boilers,  irrespective of fuel.  In  most  cases, significant
increases in CO are necessary to  record increases in gaseous THC.  Consequently, CO emissions
are often considered a precursor to THC emissions and are thus routinely monitored, whereas THC
emissions normally are not.  Since large quantities of CO and UBC mean  decreased combustion
efficiency, utility boilers are normally operated to keep CO and UBC levels at a minimum (Steam,
1978), thereby precluding any significant levels of THC emissions.

       This   section summarizes the  reported efforts of utility boiler retrofit  combustion
modification controls on emissions of CO for all fuel types (natural gas, oil, and coal), and on the
levels of  UBC in the flyash of PC-fired boilers. Appendix H provides a tabulated summary of the
data presented in this section.  It  is not  the intent of this section to develop a correlation between
CO and NOX and THC  and NOX but rather to provide  some overall guidelines on the potential
effect of  NOX controls on combustible emissions.
                                           7-1
-------
7.1     CO EMISSIONS AND UNBURNED CARBON FROM COAL-FIRED UTILITY BOILERS

7.1.1   CO Emissions

       Tables 7-1 through 7-3 summarize CO emissions and UBC data for 25 coal-fired boilers of
various firing type, the majority being wall-fired. For several boilers, the data show increased CO
emissions with decreased NOX levels. The tables also show that the relationships between NOX and
CO emissions are very boiler-specific and depend, for example, on firing configuration and capacity,
fuel type, furnace heat release rate, control type, and air/fuel distribution.

       Figure 7-1 shows NOX and CO data for  Ohio Edison's  Edgewater Unit 4,  a 100 MW
wall-fired boiler retrofitted with LNBs. Installation of LNBs reduced NOX by 25 percent initially,
with a corresponding 475 percent increase in  CO to 115 ppm, relative  to pre-retrofit baseline
emission levels.   LNB optimization adjustments produced an additional 9 percent NOX reduction
from baseline, and post-retrofit CO emissions were lowered to 60 ppm.

       This LNB retrofit program showed the importance of accurate air/fuel control to low-NOx
combustion optimization. During LNB optimization, further balancing and tuning of the combustion
system was hampered by significant variations in air/fuel distribution. These imbalances resulted
in unacceptably high CO and UBC when further NOX reduction was pursued.  It was concluded that
these "high performance low NOX burners can reach their potential only when used in combination
with systems which accurately and consistently regulate their air and  fuel supply" (LaRue, 1989).
The original pre-NSPS rapid mix burners were less sensitive to inaccuracies in air/fuel distribution,
and did not experience  significant combustion inefficiencies.

       Tests at  Germany's RWE utility boiler show increased CO when NOX was reduced below
about 125 ppm (0.17 Ib/MMBtu) during OFA operation. These data are shown in Figure 7-2. The
boiler operating variable used in these tests was the excess air level (Hein, 1989; Allen, 1991). With
OFA and with excess air levels above 20 percent, CO emissions remained constant at 20 ppm, while
the lowest NOX emission level was 150 ppm  (0.2 Ib/MMBtu)—roughly 50 percent NOX reduction
when compared to  baseline.   CO emissions  for  the  same air  levels  but without  OFA were
approximately 10 ppm.  Once excess air was reduced below 20 percent, CO emissions increased at
a rapid rate during  both baseline and low NOX operation.  For example, an additional 50 ppm
(0.07 Ib/MMBtu) NOX  reduction  resulted in  CO increase to 240 ppm. Thus, comparing low NOX
to baseline operation, there was little increase in CO until very low excess air levels were reached.
This boiler was fired on German  brown coal, thus the emission levels reported may not be
representative of boilers firing U.S. coals.  However, the data illustrate the relative change in CO
when NOX controls are implemented.

       Similar  results  were  recorded with  tests  performed by  NEI-International Combustion
Limited (NEI-ICL) on a 500 MW unit equipped with LNB. These data, shown in Figure 7-3, show
little  or no  effect  of NOX  reduction  on  CO  until controlled NOX  levels below 300 ppm
(0.4 Ib/MMBtu) were reached; corresponding to NOX reduction of about 50 percent from baseline.

       Tests on Allegheny Power's Pleasants Unit 2 illustrate that the  use of LNB in place of OFA
resulted in more efficient combustion conditions.  When OFA was used, a 30-percent reduction in
NOX occurred along with a 50 percent increase in  CO.  When LNBs  were retrofitted without the
use of OFA, 57-percent NOX reduction was demonstrated with no increase in CO. A combination
                                          7-2
-------
       Table 7-1.  Sample of baseline/controlled CO and UBC data, wall-fired PC boilers
Boiler ID
Asnaes 4, Denmark

BHK, Japan

Drax G, U.K.

Edgewater 4, OH

Eggborough 2, U.K.

Four Comers 4, NM

Hammond 4, GA



Inkoo 4, Finland

Maas 5, Netherlands

NEI-ICL, U.K.

Pleasants 2, PA



Stuart 4, OH

Gaston 2, AL

RWE, Germany

Vado Ligure 4, Italy

Capacity
(MWe)
285

360

660

100

500

800

500



265

166

500

650



600

250

600

330

Coal Type
Polish

Japanese/Canadian

U.K. Bituminous

U.S. E Bituminous

U.K.

U.S. Subbituminous

U.S. E Bituminous



U.S.

Cerrejon

U.K.

U.S. E. Bituminous



U.S. Ky Bituminous

M.W. Bituminous

German brown

U.S. Bituminous

NO, Control
Baseline
LNB
Baseline
LNB
Baseline
LNB
Baseline
LNB
Baseline
LNB
Baseline
LNB
Baseline
LNB
AGFA
LNB+AOFA
Baseline
LNB
Baseline
LNB + OFA
Baseline
LNB
Baseline
LNB
OFA
LNB + OFA
Baseline
LNB
Baseline
LNB
Baseline OFA

Baseline
OFA
NO,
(lb/MMBtu)a
0.99b
0.496
0.30-0.32
0.21-9.29
1.11
0.44-0.58
0.71
0.47-0.53
0.84-1.03
0.45-0.60
1.27
0.50
1.0-1.2b
0.55-0.76
0.9-0.95b
0.54
1.0
0.32-0.44
0.56-0.96b
0.33-0.40"
0.73-0.91
0.36-0.64
0.95
0.41
0.65
0.33
1.17"
0.53b
0.50-0.78
0.30-0.40
0.26-0.45
0.13-0.27
0.78-0.93
0.52-0.63
CO
(ppm @ 3% O,)
NAC
NA
NA
NA
NA
NA
20
60-115
NA
NA
<40
20-40
30-100b
10-20b
10-15"
NA
NA
NA
NA
NA
20-80
9-50
40
40
40-60
100
30"
41"
NA
NA
10^00
20-260
NA
8
UBC
(%)
5
<5
7.5-10
3.8-8.3
1-1.5
1-6.5
2.2
2.8-6
1.2-2.5
2.5-7.2
0.1
0.1
4.5-5.2
5.5-8
9.5-10
11.0
3
6.3-8.5
0.8-4.5
2.5-13
2.1-5.2
0.8-7.0
2.5
2.5
2.5
NA
1.1-2.5
2.9
5.5-7.0
5.6-10.0
NA
NA
5.5-6
7.7-12
Reference
Pederson, 1991

Morita, 1989

King 1991

LaRue 1989

Beard 1989

Vatsky, Lu
1991
Wilson 1991
Sorge 1992


Vemura 1991

Vanderkooij
1991
Allen 1991

Vatsky 1989



Laursen 1992

Hardman.
1992
Hem 1989

Tarli 1991

*To convert to ppm @ 3% ©2, multiply by 750.
bLong-term test data.
cNo data available.
                                               7-3
-------
  Table 7-2.  Summary of baseline/controlled CO and UBC data, tangential-fired PC boilers
Boiler ID
Cherokee 4, CO

Fusina 2, Italy

Hennepin 1, IL
Labadie 4, MO

Lansing Smith 2, FL

Lawrence 5, KS

Valmont 5, CO

Capacity
(MWe)
350

160

71
600

200

400

165

Coal Type
U.S. W. Bituminous

U.S. E. Bituminous

U.S. Bituminous
U.S. Bituminous/
Subbituminous
U.S. E. Bituminous

U.S. MW
Bituminous
U.S. W. Bituminous

NO, Control
Baseline
LNB-t-OFA
Baseline
LNB+OFA
Baseline
NO return + OFA
Baseline
LNB-t-OFA
Baseline
LNB-t-OFA
LNB+OFA
Baseline
LNB+OFA
Baseline
LNB+OFA
NO,
(Ib/MMBtu)11
0.45-0.54
0.32
0.68
0.34
0.73
0.28C
0.50-0.69
<0.45
0.6-0.65°
0.4C
0.34C
0.43-0.5
0.24-0.3
0.66
0.29-0.31
CO
(ppm @ 3%
02)
30
39
NAb
40
NA
10C
5-35
NA
10-15C
20-32C
25-65c
NA
NA
30
30
UBC
(%)
4.4-2.2
1.9-2.5
5.9
15
NA
NA
0.5-1.0
NA
4.4-5
3.8-5.4
5.5-6.5
0.4
0.3
1.6
1.6
Reference
Hunt 1991,
1992
Grusha 1991
Ghiribelli 1992
May 1992
Smith 1992

Hardman 1992

Thompson
1989
Hunt 1991

*To convert to ppm @ 3% O2, multiply by 750.
bNo data available.
cLong-term test data.
     Table 7-3. Summary of baseline/controlled CO and UBC data, coal-fired cyclone and
                turbo furnace boilers
Boiler ID
Cyclone Units:
Nelson Dewey 2, Wl
Niles I, OH
Turbo Furnace:
Wabash 5, IN
Capacity
(MWe)

100
108

105
Coal Type

U.S. Bituminous
U.S. E. Bituminous

NA
NO, Control

Baseline
Coal rcburn
Baseline
N.G. rebum

Baseline
LNB
NO,
(Ib/MMBtu)"

0.81
0.36
0.94
0.37

0.85
0.45
CO
(ppm @ 3% O2)

90
90
30
35

NA
NA
UBC
(%)

NAb
NA
1.39
1.15

10
3.5
Reference

Newell 1992
Booth 1991
Brown 1992

Penterson
1991
  To convert to ppm @ 3% O2, multiply by 750.
  bNo data available.
                                              7-4
-------
      NOx (ppm @ 3% O2)
      600
      500 -
     400
     300 —
     200 -
      100 -
                 Baseline
                          LNB as installed

                         • NOx   D CO
                                            CO (ppm @ 3% O2)
                                                              120
                 LNB optimized
CM
O
 E
 Q_
 CL


O
O
           Figure 7-1. NOX and CO emissions at full load, Edgewater Unit 4
      500
      200  -
       100
       50
20
        10
                                     D
                                  D
                   0.13
                    0.20
0 27
0 33
0.40
                                                               O
0.47 ib/MMBtu
          50       100      150      200      250      300
                              NOx (ppm  © 3%  02)
                                                         350
                                     400
Figure 7-2. CO versus NOX, 600 MWe wall-fired boiler with OFA, firing German brown coal


                                    7-5
-------
  CM
  O
      100
       80 -
       60
   E
   Q-  40
  O
  O
       20
        0
                                     With
                     l^JB     Bowline
                                 D
                                   D
                                    D
                                                           D
                                                  Q
          0 27
0.40
  i
0.53
  i
0.67
 i
0 80
                                                              0.93  Ib/MMBtu
200
                     300
             400
             500
            600
             700
800
                                  NOx  (ppm  ©  5% 02)
     Figure 7-3. CO versus NOX, NEI-ICL, 500 MWe wall-fired boiler with/without LNB
of both the LNB and OFA resulted in a total NOX reduction of 65 percent; however, CO increased
by 150 percent .(Vatsky, 1989).

       Six of the tangential-fired boilers listed in Table 7-2 were retrofitted with combined LNB
and OFA NOX controls. Of the three units for which pre- and post-retrofit CO data were available,
two experienced no change in CO as a result of adding NOX controls, while the third experienced
only a slight increase in CO. The units with unchanged CO both were fired on highly reactive
western bituminous coal while the third unit, Plant Lansing Smith Unit 2, fired eastern bituminous
coal with a lower volatile content (Hardman, 1992). CO was no higher than 65 ppm for this unit,
under low-NOx conditions.  The data support the conclusion that the use of high volatile coals
results in a lower tendency towards high  CO emissions, relative to low volatile eastern coals.

       The single tangential boiler  with gas reburn controls, Hennepin Unit  1, experienced no
adverse effect on CO emissions, even when 60-percent NOX reduction was achieved (May 1992).

       CO emissions for the two cyclone boilers in Table 7-3 did not increase much when reburn
control technology was applied. For example, CO for Niles Unit 1 increased only 5 ppm when NOX
was reduced 60 percent.  Meanwhile, at  the. 100 MW Nelson Dewey Unit 2, the furnace emitted
90 ppm CO during both pre- and post-retrofit tests. An NOX reduction of 55 percent was achieved
with coal reburn.
                                          7-6
-------
       Additional examples that support the conclusion that CO emissions remain at low levels,
following the retrofit of NOX controls are provided by these additional cases.  For example, Vado
Ligure Unit 4 had  CO emissions  less than or equal to 8 ppm and Fusina  Unit 2 reported  a
maximum CO level of 40 ppm after retrofit (Grusha, Tarli 1991). No baseline CO emission data
were reported for these units. Valmont Unit 5 and Cherokee Unit 4 both emitted less than 30 ppm
CO before and after retrofit, and Four Corners Unit 4 reported maximum CO emissions of 40 ppm.
Thus, these units were able to achieve between 35 and 60 percent NOX reduction while keeping CO
emissions at  or below  40 ppm.  Corresponding NOX levels for these units ranged from 210  to
300 ppm (0.28 to 0.4 Ib/MMBtu).  Valmont Unit 5 and Cherokee Unit 4, using LNB and OFAs,
were able to maintain low CO levels by keeping the post-retrofit overall boiler oxygen concentration
equal to baseline levels, while lowering  the stoichiometric ratio in the main  burner area (Hunt,
1991).

       Little data are available on CO emissions resulting when flue gas treatment controls are
used,  in part because attention has focused on the issue of ammonia slip instead, which is a more
important concern with urea- and ammonia-based controls. This concern was previously highlighted
in Section 4.3. The use of urea injection  did not appear to affect CO emissions to any measurable
degree for the Kerr-McGee Argus Unit 26, a PC-fired 750,000 Ib/hr tangential boiler. Average CO
emissions before  SNCR was applied were 11 ppm.  When urea injection  was used, NOX levels
decreased 33 percent to an  average level of 135 ppm (0.18 Ib/MMBtu), thereby meeting the NOX
emission standard for that unit, while CO emissions  increased to only 17 ppm.

       Table 7-4 shows levels of NOX reduction at various CO emission levels for 10 of the boilers
in Tables 7-1, 7-2, and 7-3.  Data are given for situations when post-retrofit CO levels are similar
to pre-retrofit levels.  The highest reported post-retrofit CO  levels are  also listed with their
corresponding NOX levels.   For all units, the  NOX reduction  level  at which post-retrofit CO
emissions begin to increase above baseline levels ranged between 33 and 61 percent NOX reduction.

       In conclusion, baseline and controlled  data on NOX and CO emissions from existing coal-
fired boilers appear to be very site-specific.  Factors including load, coal characteristics, furnace
design and operating conditions can  influence the level of NOX reduction  without significant
increases in CO emissions.   Limited data reviewed,  presented in Tables 7-1 through 7-4, suggest
that, for some NOX control techniques, CO levels can increase markedly as the NOX reduction goal
is increased beyond 50 percent. Additionally, the data suggest that the use of reactive western coals
results in a lower tendency  towards high  CO emissions,  relative to less reactive eastern coals.

7.1.2   Unburned Carbon

       The amount of UBC in the  flyash depends on  several factors, including the physical and
chemical coal characteristics in addition to burner/furnace operation.  Coal reactivity  and coal
fineness are two of the most important coal characteristics which affect UBC levels in pulverized
coal firing.  Coals with high levels of volatile matter, that is, lignitic,  subbituminous, or western
bituminous coals, are generally much more reactive that coals  with low percentages of volatile
matter.   High volatile  content coals correspondingly show much lower levels of UBC and are
relatively less  sensitive to variations in the combustion environment  such  as  changes in burner
stoichiometry, firing rate, and excess air levels (Lewis, 1989; Grusha, 1991; Miyamae, 1987; Tanaka,
1987).  Typically, lower NOX levels are possible  with  higher reactive coals without significant
penalties in combustion efficiency (Lewis, 1989; Narita, 1987; Offen, 1989).  Most of the UBC data
presented in  this  section are for units firing reactive or foreign coals.  Only six units  fired less
reactive eastern bituminous coals.
                                           7-7
-------
Table 7-4. NOX reduction at various CO emission levels, selected coal-fired boilers
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       Figure 7-4 depicts NOX versus UBC levels for three of the wall-fired boilers in Table 7-1;
all showing increased UBC with decreasing NOX. Using a LNB, NOX emissions from Drax Unit 6
were reduced 50 percent to approximately 400 ppm (0.53 Ib/MMBtu) before UBC levels increased
above baseline values.  Data reported for Inkoo Unit 4 showed an increase in UBC after retrofit
with combustion control.  UBC levels increased from 3 to approximately 6 percent when NOX was
reduced from 750 to 330 ppm (1.0 to 0.44 Ib/MMBtu).  For Edgewater 4 UBC increased only
slightly from 2 to 3 percent at 40 percent NOX reduction. When an additional 7 percent NOX was
reduced, however, UBC rose markedly to 6 percent. Table 7-5 summarizes UBC in flyash data for
selected boilers whose UBC levels changed after retrofit with NOX controls. In general, post-retrofit
UBC levels for the wall-fired boilers did not increase markedly until greater than 40 percent NOX
reduction was achieved.

       A number of the boilers listed in Table 7-1 through 7-3 showed no increase in UBC when
NOX controls were used,  even when boiler excess air levels were lowered.  The majority of these
units were fired on highly reactive western, subbituminous, or foreign coals.  When less reactive
coals were used with retrofit NOX controls, UBC levels tend to increase with the lowering of burner
stoichiometries to reduce NOX (Offen, 1989).  For Eggborough Unit 2, UBC was much more
sensitive to  burner stoichiometry when  LNB was used.   Prior to the  retrofit,  under baseline
conditions, lowering the excess air to reduce NOX increased UBC by 1 percentage point for every
100 ppm (0.13 Ib/MMBtu)  NOX reduction.   After LNB retrofit, lowering excess air caused an
increase of 4 percentage  points of UBC for every 100 ppm NOX reduction.  This trend was also
noted for  Vado  Ligure Unit 4, the boiler tested by NEI-ICL, and Maas Unit 5.  Thus, when
lowering excess air, UBC increases at  a faster  rate under low-NOx conditions compared to
operation with the regular burner.
         10
  O
  CD
                                                              Inkoo 4 with LNB
                                                                     •           |
                                                              Inkoo 4  baseline    j

                                                            Edgewater 4  with LNB

                                                            Edgewater  4 basehne

                                                              Drax  6  with LNB

                                                               Drax 6 baseline
                                 ..
            0 27
0
 200
          0 40
            !
          0 53
0 67
  1
0 80
0 93
300       400      500       600       700
             NOx  (ppm  @  3%  02;
                                                                         00
                 Figure 7-4. NO  versus UBC, wall-fired boilers with LNB
                                          7-9
-------


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-------
       Another important coal characteristic which can influence the amount of unburned carbon
in flyash is particle fineness. Utility boilers generally pulverize coal to about 70 percent through
200 mesh. Although this is adequate for baseline operation, the retrofit of combustion NOX controls
may necessitate an increase in coal fineness.  As discussed in Section 4, this can be accomplished
by modification of the classifiers on existing mills or replacement of the mills with larger capacity
and more efficient designs available today. The recent retrofit of Hammond Unit 4 with OFA ports
and LNB has shown that relatively low coal fineness (63 to 67 percent through 200 mesh), coupled
with NOX reductions in the order of 50 percent, can result in unacceptably high levels of UBC.  In
this  retrofit,  UBC levels reached 11 percent from a baseline of 5.2 percent at full boiler  load
(Sorge,  1992).

       Increasing the fineness of the pulverized coal often results in more complete combustion and
lower UBC levels (Makino, 1989; Trivett, 1991, GhiribeUi, 1992). A study of the effects  of particle
fineness of seven  different  coals on  combustion  efficiency showed that UBC levels  increase
considerably when the particle size is increased; the study also showed that NOX emissions increase
with increased particle size. It was determined that smaller particles allow for increased staging and
hence lower NOX (Kinoshita, 1989).  Thus, reductions in  burner efficiency due  to the addition of
low NOX controls can be somewhat counterbalanced by increasing the fineness of the  coal.  For
example, increasing the mill fineness reduced UBC to acceptable values (6 to 8  percent) for all of
the coals tested in Fusina Unit 2  (Tarlf, 1991).

12    CO EMISSIONS FROM NATURAL GAS-FIRED UTILITY BOILERS

       Figure 7-5 shows CO emissions as a function of NOX levels for two natural gas-fired boilers
operating with combustion modification NOX controls.  CO data for these and for seven other
boilers are also given in Table 7-6. NOX emission ranges are wide and dependent on the specific
boiler.  SCE's Redondo Unit 8 and Alamitos Unit 6  emitted NOX at much lower levels than any
other boiler previously described,  under lowest-NOx operating modes.  CO emissions, however, for
all but the South Bay Unit  1 were below 100 ppm (0.12 Ib/MMBtu) except at maximum  NOX
reduction conditions.

       Data from Fusina Unit 2 exhibited a very gradual increase in CO emissions until NOX fell
below 100 ppm, as CO emissions remained in the range of 50 ppm. At approximately 65 percent
NOX reduction from baseline, corresponding to 60 ppm NOX  (0.07 Ib/MMBtu), CO emissions were
twice the baseline level.  Emissions from this boiler were dependent on the firing zone stoichiome-
try.  As the stoichiometry was reduced by the utilization of staged  combustion, NOX decreased by
a maximum 70 percent; CO at this NOX level was 175 ppm, the highest level throughout all testing
(Grusha, 1991).

       Rossano Unit 4 displayed a greater CO increase compared to Fusina Unit 2.  The rate of
CO increase divided by the rate of NOX decrease was, in fact,  highest when NOX control—in this
case, BOOS—was used. With 12 of 18 burners in service, CO increased by 5.8 ppm for every 1  ppm
NOX reduction; in comparison, with all burners in service (ABIS), CO increased by only  3.4  ppm
for every 1 ppm NOX reduction as excess air was reduced to  optimize NOX reduction performance
(Benanti, 1989).

       Figure 7-6 shows the  relationship between CO and excess oxygen levels for SCE's Ormond
Beach Unit 2, an 800 MW wall-fired boiler that was retrofitted with LNB. Data is depicted for pre-
and  post-retrofit O.S. and ABIS firing modes.  O.S.  firing in this case was achieved  by taking
selected BOOS. A comparison of the pre- and post-retrofit O.S. curves shows that in order to keep
post-retrofit CO  equal to pre-retrofit levels, the excess oxygen had to be increased. For example,

                                          7-11
-------
      500
      300
CM
O
E
Q.
Q.


o
o
      100
       50
       30
                         Fusina 2 w/LNB    Fusina 2^baseline

                        Rossano 4 w/BOOS Rossano 4 baseline

                                     a
                                                             o
                O.6
                        0,12
O18
0.2
0.^0
0.6
o
 0.42
          0      50     -100     150     200     250     300

                             NOx  (ppm ©  3% 02)
                                                                350
                                       400
                Figure 7-5. CO versus NOX, natural gas-fired boilers
                                   7-12
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      O
                                                            ORMOND BEACH #2
                                                            GAS FUEL
                                                            550 MW - 750 MW
Pra Rwoffl (O.S.)

POM Rwoflt (ABtS)
              0                0.5               1               1.5                2
                                 BOILER EXCESS O2, % (dry)

 Figure 7-6. Pre- and post-retrofit CO emissions versus excess O2—SCE Ormond Beach Unit 2
            (Bayard de Volo, 1991) (O.S. = Off Stoichiometric; ABIS — All Burners in Service)


when pre-retrofit CO was 200 ppm, excess oxygen was roughly between 0.75 and 1 percent.  Under
post-retrofit O.S. firing, excess oxygen had to be increased to bottom 1.5 and  1.75 percent in order
to keep CO at 200 ppm.  This increase is excess oxygen reduced the amount of NOX reduction
achieved by the LNB (Bayard de Volo, 1991).

       In the case of Alamitos Unit 6, a 480-MW wall-fired boiler outfitted with the same LNB as
Ormond Beach 2, the minimum allowable excess oxygen level at which acceptable CO emissions
were maintained was lower after retrofit (Figure 7-7). This reduction in minimum allowable excess
air did not follow the more typical trend that was displayed by Ormond Beach Unit 2. Figure 7-7
shows the relationship between CO and excess O2.  Under post-retrofit O.S. (BOOS)  firing mode,
Alamitos Unit  6 was able  to operate on lower excess oxygen, keeping CO emissions  the same as
pre-retrofit levels.  The CO/O2 performance of Alamitos Unit 6 was attributed partly to more
uniform air and fuel flow  in the firing zone, which was achieved by modifying the boiler windbox
and  by balancing the burner fuel  and air flows  during shakedown testing.  Similar windbox
modifications had been  made to the Ormond Beach Unit, but the results were as described above,
with little improvement  in  CO/O2 performance. SCE could not explain the large variance between
the two boilers' performance (Bayard de Volo, 1991). It is probable that the differences in boiler
size and design contributed to these results. This demonstrates that there may be exceptions to the
general trends that can be seen in  boiler performance, and that emissions performance  is  very
boiler-specific and may depend on other factors besides the actual application of low-NOx controls.

       This is  indeed the  case with  Redondo Unit 8 and South Bay Unit 1.  Taking Burner 6 out
of service  from Redondo  Unit 8 resulted in  a  36 percent reduction in NOX without adversely
affecting CO. The explanation for this is that Burner 6 south had been "starved" for air, resulting
in lower O-, and higher CO levels in the south side of the boiler when Burner 6 was in service.  The
                                          7-14
-------
          700
          600
          500
        |_400
        0.
       O
          300
          200
          100
  ALAMITOS #6
  GAS FUEL
  250480 MW
                                                        Pre Retrofit (O.S.)
Post Retrofit
 (O.S.)
             0.5
                        1.5            2
                    EXCESS O2, PERCENT
2.5
    Figure 7-7. Pre- and post-retrofit CO emissions versus excess O2—SCE Alamitos Unit 6
               (Bayard de Volo, 1991) (O.S. = Off Stoichiometric)
removal of Burner 6 thus improved the overall combustion air balance between the north and south
sides, resulting in lower CO (McDannel, 1991).  This was much the  case with South Bay Unit 1,
where it was determined that four of the eight  burners were starved for air;  this poor air/fuel
distribution was due to nonuniform fuel orifice sizes in the burner rings.  BOOS operation resulted
in an exponential increase in CO emissions to levels greater than 2000 ppm. The use  of the fuel
biasing resulted in a lower CO emission level, yet  this was still more than three times as high as the
baseline level of 250 ppm (Quartucy, 1987).

       Three other boilers or burners in Table 7-6—Arzberg Unit 6, the low-NOx burner tested for
New England Power Company (NEPCO) which simulates Brayton Point and Salem Harbor Units 4,
and Sermide Unit 3—emitted no more than 32 ppm CO during low NOX operation. Corresponding
NOX emissions were also quite low, ranging between 50 and 83 ppm (0.06 to 0.1  Ib/MMBtu).  The
fourth unit, the low-NOx B&W XCL burner evaluated at the  Riley test  facility, also had  NOX
emissions of less than 80 ppm (0.1 Ib/MMBtu), but had a higher level of CO averaging 40 ppm*
These relatively low CO emission levels suggest that for these  units, the effect of adding  NO
controls on CO emissions is not great.                                                     x

       Table 7-7 summarizes  NOX  emission levels and NOX reduction at various CO emission
levels.  NOX reductions for wall-firing  ranged from 23 to 83  percent at the point where CO
emissions begin to increase above baseline levels,  while for the tangential-fired Fusina Unit 2, this
point  corresponded  to  17 percent NOX  reduction.   High CO  levels with  low  NOX  reduction
efficiencies are more likely when the initial NOX levels is low, as is the case for many Southern
California boilers. Otherwise, significant NOX reductions are possible from gas-fired boilers without

                                          7-15
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an increase in CO emissions.  CO emissions range from gas-fired boilers evaluated in this study
showed a range of 12 to 90 ppm at combustion-controlled NOX emission levels in the range of
0.06 to 0.31 Ib/MMBtu.

7.3     CO EMISSIONS FROM OIL-FIRED UTILITY BOILERS

       CO and NOX emission data for 12 oil-fired boilers or burners are given in Table 7-8.  For
those units with both pre- and post-retrofit data available, these data are also presented graphically
in Figure 7-8. It is apparent that CO emission levels for most  of these boilers tended to be no
higher  than 50 ppm prior to use of NOX controls. Only Monfalcone Unit 4 reported baseline CO
emissions which were greater.

       The data in Table 7-8 and in Figure 7-8 show little or no increases in CO when NOX controls
were used, unless  absolute  minimum NOX levels  were pursued.  As discussed below,  26 to
57 percent NOX reduction was achieved from the eight wall-fired boilers with no increase in  CO.

       In order to maintain low CO emissions, higher excess  oxygen is often necessary  when
low-NOx combustion controls are used. Thus,  operational flexibility with excess air is reduced at
low-NOx conditions. Monfalcone Unit 4 illustrates  this trend.   Prior to retrofit with  LNB,  NOX
could be reduced 30 percent using low excess oxygen while keeping CO emissions below 70 ppm.
In order to maintain the same level of CO after the LNB retrofit, the excess air level had to be
raised, limiting low excess air's NOX reduction  contribution to only 19 percent (Tarli, 1991).  The
LNB provided the remainder  of the overall 51 percent post-retrofit NOX  reduction. In Figure 7-8,
the steeper rise in CO with small reduction in  NOX is more evident in the post-retrofit case than
in the baseline case.  Overall,  Figure 7-8 shows  that for the four boilers post-retrofit CO emissions
were kept at  roughly the same levels as pre-retrofit emissions.

       Table 7-9 summarizes NOX reductions and emission levels when post-retrofit CO emissions
were roughly the same as pre-retrofit levels.  For the eight wall-fired boilers,  CO ranged from 20
to 67 ppm at this point.  Corresponding NOX reduction levels ranged between 26 and 57 percent,
meaning that this range of NOX reduction was attained on these boilers without an increase in CO
emissions from baseline  levels. This NOX range is fairly consistent with the 33 to 60 percent range
for  coal-fired boilers discussed earlier.

       In some  cases where oil-fired boilers were retrofitted with NOX controls, opacity reaches
unacceptably high levels before CO emissions do. Increased stack opacity is indicative of higher
soot emissions, which also contributes to higher particulate loadings and possibly higher air  toxic
emissions as well.  These opacity levels thus act as the "trigger" for the maximum NOX reduction
that should be pursued.  Opacity levels are generally related to NOX emissions in much the same
way as  CO emissions, that is, as excess oxygen is decreased to lower NOX, less complete combustion
occurs, resulting in higher levels of opacity. Lowering NOX is not the only cause of high opacity,
however.  Opacity is also dependent on fuel oil characteristics such as fuel grade (distillate versus
residual) and mean droplet size (atomization efficiency).

       This tradeoff between NOX and opacity  is a fundamental feature of the low-NOx system in
use at  Hawaiian Electric Company's (HECO)  Kahe Unit 6, particularly when firing heavy oil.
Figure 7-9 gives a historical summary of NOX and opacity levels for this 146 MW wall-fired boiler.
Initially, between 1981 and 1988, the unit had been operating with FOR and BOOS to satisfy  NOX
emission requirements;  NOX  and opacity levels were 219 ppm (0.28 Ib/MMBtu) and 6 percent,
respectively (left most part of Figure 7-9). After retrofit with  a LNB—known as the PG-DRB
burner— and  a front and rear wall OFA system, NOX was reduced on average by 29 percent,  with
              •
                                           7-17
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                 NOx  (ppm ©3%  02)
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Figure 7-8.  NOX versus CO emissions—oil-fired boilers
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              35

              30

              25
         Figure 7-9. Historical summary of Kahe 6 NOX and opacity (Kerho, 1991)
                    (Note:  to convert ppm to Ib/MMBtu divide by 790)
a range in controlled levels from 141 to 172 ppm (0.18 to 0.22 Ib/MMBtu, second set of bars in
Figure 7-9). At the same time, opacity levels more than doubled, increasing to between 12 and
17 percent.  These  ranges in NOX  or opacity are denoted by horizontal  lines in the bars  of
Figure 7-8.  Two years later, performance had degraded somewhat, with NOX emissions being as
high as 180 ppm (0.23 Ib/MMBtu) and opacity levels reaching 20 percent  (third set  of bars in
Figure 7-9). To reduce opacity levels, additional modifications were then made to the boiler under
a program jointly sponsored by the Electric Power Research Institute (EPRI) and HECO (fourth
set of bars  in  Figure 7-9).   New fuel  atomizers were  installed to  reduce the size  of the oil
droplets—smaller droplets burn out more completely, lowering the opacity—and the fuel and air flows
to the burners  were balanced.  As  a result of these changes, NOX  emissions were reduced  to
152 ppm (0.19 Ib/MMBtu) and opacity levels were lowered to 10 percent (Kerho/ 1991).

7.4   HYDROCARBON EMISSIONS

      THC emission test data are not commonly available for utility boilers.  Since high CO, UBC,
and opacity levels precede THC emissions (Radak,  1991), monitoring of THC emissions is not
usually a part of the retrofit program. Table 7-10 summarizes the  limited THC data collected as
part of this study for three boilers with NOX controls and seven  units without controls.  THC
                                        7-21
-------
             Table 7-10. Summary of total hydrocarbon (THC) emission data
Boiler Unit
Boilers with NOX
Controls:
Alamitos 6, CA
Ormond Beach 2, CA
Alamitos 6, CA
Ormond Beach 2, CA
Niles 1, OH
Uncontrolled Boilers:
Crist 6
Harllee Branch 3
Naughton 3
SCE Boiler
Widows Creek 6
Wood River I, IL
Wood River 4, IL
Fuel

Natural gas
Oil
Coal

Coal
Coal
Coal
Oil
Coal
Oil
Coal
THC Data (measured as
hexane)

No increase in THC
under lowest NOX
operating conditions
compared to pre-retrofit
No increase in solid
carbon or condensible
hydrocarbon under lowest
NOX conditions
Negligible THC gaseous
emissions

0.32 ppm (avg.)
0.56 ppm (avg.)
0.46 ppm (avg.)
1.75 ppm
0.39 ppm (avg.)
0.32 ppm
0.24 ppm
NOX Levels,
ppm @ 3% O2
(Ib/MMBtu)

16-90
(0.02-0.11)
90-150
(0.11-0.18)
275
(0.37)

290-681
(0.39-0.91)
148-747
(0.20-0.99)
169-569
(0.23-0.76)
NAa
290-68 1
(0.39-0.91)
63-95
(0.08-0.12)
465-490
(0.62-0.65)
Reference

Bayard de
Volo 1991
Bayard de
Volo 1991
Booth
1991

EPA 1974
EPA 1974
EPA 1974
Taback
1978
EPA 1974
EPA 1977
EPA 1977
aNA = No data available.
                                        7-22
-------
emissions from these utility boilers were very low, ranging from negligible levels to less than 2 ppm
(THC as hexane), independent of fuel or boiler type.

       For example, SCE reported an increase in THC emissions under the lowest NOX operating
conditions (off stoichiometric firing, low excess air, high FGR), compared to pre-retrofit conditions,
for both Alamitos Unit 6 and Ormond Beach  Unit 2 when firing natural gas.  There was also "no
increase in solid carbon or condensible hydrocarbons under lowest NOX conditions" when firing oil
(Bayard de  Volo,  1991).  Niles Unit 1, operating on  coal, reported "negligible gaseous THC
emissions" (Booth, 1991). These three boilers illustrate that THC emissions from utility boilers tend
to be very low under low NOX conditions, regardless of the fuel used.

       A short-term test of a SCE boiler firing No. 6 residual oil measured THC emissions of less
than 2 ppm, measured as hexane. The low level of hydrocarbon in this test was attributed to the
relatively long residence time of the combustion gases in the boiler, allowing ample time for more
complete combustion (Taback, 1978).  Data are also provided on two boilers tested in the late 1970s
at Illinois Power's Wood River Power Plant.  Short-term tests were conducted using oil and coal.
THC emissions were found  to  be less than  1 ppm for  both fuels  (EPA,  1977).  Similar THC
emissions levels were measured at the remaining boilers, in  Table 7-8, all of which were fired on
coal.

       Typically, THC emissions from oil-fired utility boilers are on the order of 0.005 Ib/MMBtu,
while for natural gas-fired boilers, THC emissions are typically 1 x 10"5 Ib/MMBtu (Taback, 1978).
Three test programs on utility boilers measured hydrocarbon  emissions less than 1 ppm in virtually
all tests, for both baseline and low NOX operation.  It was  concluded that THC emissions were
relatively unaffected by imposing NOX combustion controls on large utility boilers (EPA, 1980).

7.5    SUMMARY AND CONCLUSIONS

       CO emissions data- for 25 coal-fired, 9 natural gas-fueled, and  12  oil-fired  boilers were
examined in  this study. These  data  are summarized in Table 7-11.  Although the  listed NOX
reduction ranges are very  wide  in general, when  NOX combustion controls were used, there was
relatively little increase in CO  emissions until 40  to 50 percent NOX reduction—referenced to
baseline levels—was achieved, beyond which CO levels begin to increase rapidly. The magnitude
of this increase varies widely from boiler to boiler,  and is affected by fuel type, furnace volume, heat
release rate,  burner configuration, NOX control  technique,  uncontrolled NOX level and  control
target, and fuel/oxygen balance, as well as the condition of existing boiler equipment.

       For PC wall-fired boilers, firing bituminous coal,  CO was found to increase  once  greater
than 33 to 56 percent NOX reduction was reached. Corresponding NOX levels ranged from 280 to
390 ppm (0.37 to 0.52 Ib/MMBtu), while CO ranged from 8  to 60 ppm.  For the natural gas wall-
fired boilers, the available data show that baseline CO values were not exceeded across a wide range
of NOX reductions, from 7 to  83 percent.  The 7-percent reduction in NOX without CO increase was
due to NOX reduction efforts  from an already controlled California utility boiler with an initial NOX
level of only 60 ppm (0.007 Ib/MMBtu).  Test  results on  oil-fired  boilers indicated a marked
increase in CO when greater than 26 to 57 percent NOX reduction was reached via combustion
modification.  For some boilers, increases in  CO from  baseline were relatively minor, with CO
emissions never exceeding  40 to 50 ppm. Emissions data for one application of urea injection did
not show any noticeable effect on CO.

       Combustion  control retrofit experience to date has revealed that  fuel/air imbalances can
cause large increases in CO emissions even at small NOX reduction levels. Modifications  may be

                                           7-23
-------
                Table 7-11. Summary of NOX reduction levels achieved when
                            low-NOx CO  = baseline (uncontrolled) CO
                    Fuel Type
               Bituminous coal


               Natural gas


               Heavy (residual) oil
   Boiler
   Type
Wall-fired
Tangential
Cyclone

Wall-fired
Tangential

Wall-fired
Tangential
                                                   NOX Reduction Achieved,
                                                      CO = baseline CO
33 to 56
43 to 57
  61a

 7 to 83
  17a

26 to 67
  48a
               *Data for one unit only.
necessary to adjust burner performance to balance air and fuel as part of the NOX control retrofit.
Therefore, CO versus NOX response in these cases cannot be predicted using the results of this
section and must await site-specific evaluation.  This may be especially true for certain coal-fired
units, since coal-fired systems generally suffer more air/fuel imbalance than oil or natural gas-fired
units. However, the data suggest that on the average, 40 to 50 percent NOX reduction is possible
from existing baseline levels without markedly affecting baseline CO emissions. Often, when NOX
controls are applied, the excess oxygen level of the burner must be increased to maintain CO at
acceptable levels, limiting the  amount of NOX reduction that is feasible and resulting  in some
thermal efficiency loss.

       Retrofit NOX controls had little effect on UBC in flyash levels when burning highly reactive
coal, as shown by data for eight boilers. Of the other wall-fired boiler data examined, post-retrofit
UBC values did not increase markedly from baseline levels until greater than 29 to 57 percent NOX
reduction was achieved.  The coal  particle  fineness also  affects the UBC level to a certain
degree—increasing fineness can offset some loss in combustion efficiency.

       Although the data base  on THC is too sparse to draw any definitive conclusions, limited test
data available indicate that THC emissions from utility boilers are very low, less than 2 ppm for the
boilers discussed in this section.  This emission level was reported regardless of fuel type and
whether  operating under baseline or low NOX conditions.  The available data suggest  minimal
impact of combustion controls  on THC.
                                           7-24
-------
                                    REFERENCES
Abele, A. R., et al., "Performance of Urea NOX Reduction Systems on Utility Boilers," 1991 Joint
Symposium on Stationary Combustion NOX Control, EPA/EPRI, March 25-28, 1991.

Afonso,  R. F., et al., "An R&D Evaluation of Low-NOx Oil/Gas Burners for Salem Harbor and
Brayton  Point Units," 1991 Joint Symposium on Stationary Combustion NOX Control, EPA/EPRI,
March 25-28, 1991.

Albanese, V., Nalco Fuel Tech — Correspondence, July 1991.

Allen, J. W., "Low NOX Coal Burner Development and Application," 1991 Joint Symposium on
Stationary Combustion NOX Control, EPA/EPRI, March 25-28, 1991.

Allen, J.  W., et al., "Reduction in NOX Emissions from a 500 MW Corner Fired Boiler," 1987 Joint
Symposium on Stationary Combustion NOX Controls, EPRI Report CS-5361, August 1987.

Araoka,  M., et al., "Application of Mitsubishi Advanced MACT In-Furnace NOX Removal at TAIO
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Balling, L., et al., "Poisoning Mechanisms in Existing SCR Catalytic Converters and Development
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Bartok, W., et al., "Application of Gas Reburning-Sorbent Injection Technology for Control of NOX
and SO-, Emissions," 1991 Joint Symposium on Stationary Combustion NOX Control, EPA/EPRI,
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Bayard de Volo, N., et al., "NOX Reduction and Operational Performance of Two Full-Scale Utility
Gas/Oil-Burner Retrofit Installation," 1991 Joint Symposium on Stationary Combustion NOX
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Beard, P., et al.,  "Reduction of NOX Emissions from a  500MW Front Wall Fired  Boiler," 1989
Symposium on Stationary Combustion NOX Control, EPRI GS-6423, July 1989.

Beherens, E., "KHI Operating Experience of SCR on Coal Fired Utility Boilers and High Sulfur
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Benanti, A., et al., "ENEL's Ongoing and Planned NOX  Control Activities," 1989 Symposium on
Stationary Combustion NOX Control, EPRI GS-6423, July 1989.

Bisonett, G. L., and  McElroy, M., "Comparative Assessment of NOX  Reduction Techniques for
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Booth, R. C, et al., "Reburn Technology for NOX Control on a Cyclone-Fired Boiler,"  1991 Joint
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                                         R-l
-------
Borio, R. W., et al., "Reburn Technology for NOX Control on a Cyclone-Fired Boiler," 1991 Joint
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Brown, S. W., and R. W. Borio, "Gas Reburn System Operating Experience on Cyclone Boiler,"
EPRI Workshop NOX Controls for Utility Boilers, Cambridge, MA, July 7-9,  1992.

Camparato, J. R., et al., "NOX Reduction at the Argus Plant Using NOxOUT Process," 1991 Joint
Symposium on Stationary Combustion NOX Control, EPA/EPRI, March 25-28, 1991.

Carnevale, J. J.,  and Klueger, J. A., "Retrofit Implications of a Low-NOx Burner System on a 230
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Chen S. L, et al., "Reburning and Repowering for NOX Control on Large Utility  Boilers," 1989
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Cichanowicz, J. E., and Offen, G.  R., "Applicability of European SCR Experience to U.S. Utility
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DeMichele, G.,  et al., "Application  of Reburning Technologies  for NOX Emissions Control on
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DePriest, W., et al., "Engineering Evaluation of Combined  NOX/SOX Removal Processes: Second
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Dziegiel, H. T., et al., "The Thermal  DeNOx Demonstration  Project," EPRI CS-3182, July 1983.

EERC, "Gas Reburning Technology Review," prepared for the Gas Research Institute, Chicago, IL,
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Emmel, T. E., and Maibodi, M., "Retrofit Costs  and Performance of NOX Controls at 200 U.S.
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EPA, "Regional Air  Pollution  Study, Point Source Emission  Inventory,"  U.S. Environmental
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Gerdes, J., et al.,  "Retrofitting Low  NOX Burners for Gas and Oil Firing,"* 1989 Symposium on
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                                         R-2
-------
Ghiribelli, G., et al, "Thermal Performance Characterization of Low NOX Firing System at ENEL's
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Grusha, J., and  McCartney, M.  S., "Development  and  Evaluation of the ABB Combustion
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Guest, M., "SCR Pilot-Scale Results from Niagara Mohawk's Oswego Station," EPRI Workshop
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Hardman, R. R., "Tangentially-Fired Low NOX Combustion Systems Test Results at  Gulf Power
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Hardman, R. R., "Wall-Fired Low NOX Burner Test Results from the EPRI Tailored Collaboration
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Haslbeck, J. L., et al., "Proof-of-Concept Test of the NOxSO Fuel Gas Treatment  System," in
Proceedings:  1990 SO2 Control Symposium, EPRI GS-6363, September 1990.

Hein, K.  R. G., "The Application of Combustion Modifications for NOX Reduction to Low Rank
Coal Fired Boilers," 1989 Symposium on Stationary Combustion NOX Control, EPRI GS-6423, July
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Hofmann, J., et  al., "NOX Control in a  Brown Coal-Fired Utility Boiler," 1989 Symposium on
Stationary Combustion NOX Control, EPRI GS-6423,  July  1989.

Huang, C.  M., "SCR Pilot-Scale  Results from TVA Shawnee Station," EPRI Workshop NOX
Controls  for Utility Boilers, Cambridge, MA, July 7-9, 1992.

Hunt, T., "Low NOX Burner Application at  Public Service Company of Colorado's Cherokee
Station,"  EPRI Workshop NOX Controls for Utility Boilers, Cambridge, MA, July 7-9, 1992.

Hunt, T. G., et al., "Retrofit Experience Using LNCFS on 350 MW and 165 MW Fired Tangential
Boilers," 1991 Joint Symposium on Stationary Combustion NOX Control, EPA/EPRI, March 25-28,
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Hunter, S. C., "NOX Emissions from Fossil Fuel Power Plants in New York State," KVB Report
Prepared for The Empire State Electric Energy Research Corporation, August 1989.

Janik, J., "SCR-Pilot-Scale Results from NYSEG's Kentigh  Station' 1," EPRI Workshop NOX
Controls  for Utility Boilers, Cambridge, MA, July 7-9, 1992.

Johnson,  L., Southern California Edison Company, Correspondence, July 1991.

Johnson L., " Nitrogen Oxides Emission  Reduction Project," 1991 Joint Symposium on Stationary
Combustion NOX Control, EPA/EPRI, March 25-28,  1991.

Jones, A.  R., "Low NOX Burner Applications in UK Utility Boilers," EPRI Workshop NOX Controls
for Utility Boilers, Cambridge,  MA, July 7-9, 1992.

                                         R-3
-------
Jones, D. G., et al., "Preliminary Results High Energy Urea Injection DeNOx on a 215 MW Utility
Boiler," 1991 Joint Symposium on Stationary Combustion NOX Control, EPA/EPRI, March 25-28,
1991.

Kerho, S. E., et al., "Reduced NOX, Particulate and  Opacity on Kahe Unit 6  Low-NOx Burner
System,"  1991  Joint  Symposium  on  Stationary  Combustion  NOX  Control,  EPA/EPRI,
March 25-28, 1991.

Kerry, H. A., and Weir, A., Jr., "Operation Experience on Southern California Edison 107.5 MW
Selective Catalytic Reduction DeNOx System," EPRI CS-4360, January 1986.

King, J. L., and Macphail, J., "Full Scale Retrofit of Low NOX Axial Swirl  Burner to a 600MW
Utility  Boiler, and  the  Effect  of Coal  Quality on Low NOX  Burner Performance,"  1991 Joint
Symposium on Stationary Combustion NOX Control, EPA/EPRI, March 25-28,  1991.

Kinoshita, J., et al., "New Approach to NOX Control Optimization  of NOX and Unburnt Carbon
Losses," 1989 Symposium on Stationary  Combustion NOX Control, EPRI GS-6423, July 1989.

Kleisley, R., Babcock and Wilcox, Telephone Communication, July  1991.

Kokkinos, A., et al.," Low NOX Coal-Firing System Demonstration Results on a Tangentially Fired
Boiler," 1985 Joint Symposium on Stationary Combustion NOX Control, EPA/EPRI, April 1985.

LaRue, A. D., "NOX Reduction by Combustion in PC-Fired Boilers," presented at the ASME/IEEE
Power Generation Conference, Boston,  MA, October  1990.

LaRue, A. D., "The XCL Burner—Latest Developments and Operating Experience," EPRI GS-6423,
1989 Symposium on Stationary Combustion NOX Control, July  1989.

Laursen, T. A., and H. Duong, "Application of Low NOX Cell" Burners at Dayton Power & Light's
J. M. Stuart Station  Unit No. 4," EPRI Workshop NOX Controls for Utility Boilers, Cambridge, MA,
July 7-9, 1992.

Lewis, R. D., et al., "Retrofit and Boiler Performance Evaluation of the Low NOX PM Firing System
at Kansas Power and Light," 1989 Symposium on Stationary Combustion NOX Control, EPRI GS-
6423, July 1989.

Lim, K. J., et al., "Environmental  Assessment of Utility Boiler Combustion Modification  NOX
Controls:  Vol. 1 Technical Results," EPA-600/7-80-075a, April  1980.

Lisauskas, R. A., and Rawolon, A. H.,  "Status of NOX  Controls for Riley, A  Stoker-Fired and
Turbo-Fired Boilers," EPRI CS-3182, July 1983.

Lisauskas, R. A., et al., "Engineering and Economic Analysis of Retrofit Low-NOx Combustion
Systems," 1987 Symposium on Stationary Combustion Nitrogen Oxide Control, EPRI CS-5361,
August 1987.

Lisauskas, R. A., et al., "Status of NOX Control Technology at Riley Stoker," 1989 Symposium  on
Stationary Combustion NOX Control, EPRI GS-6423, July 1989.
                                         R-4
-------
Lisauskas, R. A., and Pendersen, C. A., "An Advanced Low-NOx System for Gas and Oil Firing,"
1991 Joint Symposium on Stationary Combustion NOX Control, EPA/EPRI, March 25-28, 1991.

Lowe, P. A., et al., "Understanding the German and Japanese Coal-Fired SCR Experience," 1991
Joint Symposium on Stationary Combustion NOX Control, EPA/EPRI, March 25-28, 1991.

Lu, T. L., et al., "Performance of a Large Cell-Burner Utility Boiler Retrofitted with Foster Wheeler
Low-NOx Burners," 1991 Joint Symposium on Stationary Combustion NOX Control, EPA/EPRI,
March 25-28, 1991.

Maibodi, M., Blackard, A. L., and Page, R. J., "Integrated Air Pollution Control System Version 4.0
— Volume 2: Technical Documentation Manual," EPA-600/7-90-002B, December 1990.

Makino, K., "Up to Date Technology of Pulverized Coal Combustion with Boilers," International
Coal Utilization Conference. Beijin,  1989.

Maloney, K. L.,  "Combustion Modifications for Coal-Fired Stoker Boilers," in Proceedings:  1982
Joint Symposium on Stationary Combustion NOX Control, EPRI CS-3182,  July 1983.

Manaker, A. M., and R E. Collins, "Status of TVA's NOX Compliance Program," EPRI Workshop
NOX Controls for Utility Boilers, Cambridge,  MA, July 7-9, 1992.

Mansour, M. M., et al., "Integrated NOX Reduction Plan to Meet Staged SCAQMD Requirements
for  Steam Electric  Power Plants," presented  at the 53rd  Annual American Power Conference,
Chicago, IL, April-May  1991.

May, T. J., "Gas Reburn Demonstration Results at Hennepin Power Plant," EPRI Workshop NOX
Controls for Utility Boilers, Cambridge, MA, July 7-9, 1992.

McDannel,  M. D., et al., "Low NOX Levels Achieved by Improved Combustion Modification on Two
480 MW Gas-Fired  Boilers," 1991 Joint Symposium on Stationary Combustion NOX Control,
EPA/EPRI, March  25-28,  1991.

Miller, M. J., "SO-, and NOX Control Technologies Handbook," EPRI Special Report CS-4277-SR,
October 1985.

Miyamae, S., et al., "NOX and Unburned Carbon Simulation Technologies on Pulverized Coal Firing
Boiler—2nd Report Evaluation of NOX Formation and NOX Control Technology for Foreign Coals,"
IHI Engineering Review, Vol. 20, No. 4, 1987.

Morita, S., et al., "Design Methods for Low-NOx Retrofits of Pulverized Coal Fired Utility Boilers,"
1989 Symposium on Stationary Combustion NOX Control, EPRI GS-6423, July  1989.

Mormile, D. J.,  et al., "NOX Inventory and Retrofit Assessment," 1987 Symposium on  Stationary
Combustion Nitrogen Oxide Control, EPA/EPRI CS-5361, August 1987.

Murakami,  M., "Application of the MACT In-Furnace NOX Process Coupled with Low-NOx SGR
Burner," in Proceedings:  1989 Symposium on Stationary Combustion NOX Control, EPRI CS-4360,
January  1986.
                                         R-5
-------
Nakabayashi, Y., and Rikiya A.," Current Status of SCR in Japan," 1987 Symposium on Stationary
Combustion Nitrogen Oxide Control, EPRI CS-5361, August 1987.

Nakabayashi, Y., et ah, "Status of Japanese Technical Development for Coal Combustion NOX
Control," in: Proceedings of the  1982 Joint Symposium on Stationary Combustion NOX Control,
EPRI CS-3182, July 1983.

Narita, T., et ah, "Operating  Experiences of Coal Fired Boilers  Using Hitachi NOX Reduction
Burners," 1987 Symposium on Stationary Combustion NOX Control, EPRI CS-5361, August 1987.

Neal, L, G., and Bolli, R. E., "Pilot-Plant Test for the NOXSO Flue Gas Treatment System," 1991
Joint Symposium on Stationary Combustion NOX Control, EPA/EPRI, March 25-28,  1991.

Newell, R., et ah, "Coal Reburning Application on a Cyclone Boiler," EPRI Workshop NOX Controls
for Utility Boilers, Cambridge, MA, July 7-9, 1992.

Offen, G., et ah, "Update on Industrial Experience with NOX Control," Pittsburgh Coal Conference,
September  1989.

Oppenberg, R., "Primary Measures Reducing  NOX Levels in  Oil- and Gas-fired Water  Tube
Boilers," Conference of the Association of German Engineers, Duisburg, Germany, September 26,
1986.

Pechan, E. H., "Reporting of Selected EPA-Sponsored Form ELA-767  Data for  1985-1987,"
EPA/600/7-89/014a, NTIS PB90-165879, November 1989.

Pedersen, J., and Berg, M., "Design and Application Results of a New European Low-NOx Burner,"
1991 Joint Symposium on Stationary Combustion NOX Control,  EPA/EPRI, March 25-28, 1991.

Penterson, C. A., "Controlling NOX Emissions to Meet the 1990 Clean Air Act," presented at the
1991 Power Generation Conference, San Diego, CA.

Pepper, W. W., et ah, "Retrofit Combustion Controls for Gas/OilrFired Utility  Boilers,"  1987
Symposium on Stationary Combustion Nitrogen Oxide Control,  EPRI CS-5361, August 1987.

Pershing, D. W., and Wendt, J.O.L., "Relative Contribution of Volatile and Char Nitrogen to NOX
Emissions from Pulverized Coal Flames," Ind. Eng. Chem. Proc., Des and Dev., 1979, (18), 60.

PETC Review. Issue 3, March 1991.

Pohl, J. H., and Sarofim, A. F., "Devolatilization  and Oxidation of Coal Nitrogen," 16th Symposium
(Int) on Combustion,  1976, 491.

Pratapas, J., Communication with C. Castaldini, August 9, 1991.

Quartucy, G. C., et ah, "Application of Fuel Biasing for NOX Emission Reductions in Gas-Fired
Utility Boilers," 1987 Symposium on Stationary Combustion NOX Control, EPRI CS-5361, August
1987.

Radak, L., Southern California Edison, Telephone Communication, October 1991.
                                          R-6
-------
Reese, J. L, et al., "Evaluation of SCR Air Heater for NOX Control on a Full-Scale Gas- and
Oil-Fired Boiler," 1991 Joint Symposium on Stationary Combustion NOX Control, EPA/EPRI,
March 25-28, 1991.

Reese, J., et al.,  "Application of Catalyst Air Heater at Southern California Edison's Mandaloy
Generating Station," EPRI Workshop NOX Controls for Utility Boilers, Cambridge, MA, July 7-9,
1992.

Robie, C. P., et al., "Technical Feasibility and Cost of SCR for U.S. Utility Applications," 1991 Joint
Symposium on Stationary Combustion NOX Control, EPA/EPRI, March 25-28,  1991.

Robie, C. P. and P. A. Ireland, "Technical Feasibility and Cost of Selective Catalytic Reduction
(SCR) NOX Control," EPRI  GS-7266, May 1991.

Seidman, N. L., and McVay, D. L., "Stationary  Source Nitrogen Oxides Control Strategies in the
Northeast States," presented at the 84th Annual Meeting and Exhibition, Vancouver, BC, Canada,
June 16-21, 1991.

Smith, C., ABB-Combustion Engineering, Telephone Communication, July 1991.

Smith, R. C., "LNCFS Level  III Low NOX Burner Retrofit-Labedie Unit 4," EPRI Workshop NOX
Controls for Utility Boilers,  Cambridge, MA, July 7-9, 1992.

Sorge, J. N., "Wall-Fired Low NOX Burner Test Results from the Innovative Clean Coal Technology
Project at Georgia Power Company's Plant Hammond Unit 4," EPRI Workshop  NOX Controls for
Utility Boilers, Cambridge, MA, July 7-9,  1992.

Sorge, J. N., et al., "Demonstration of Advanced Wall-Fired Combustion Modifications for the
Reduction  of  Nitrogen  Oxide  (NOX)  Emissions  from Coal-Fired Boilers," presented at the
International Joint Power Generation Conference and Exhibition, San Diego, CA, October 6-10,
1991.

Spliethoff, H., "Large Scale Trials and Development of Fuel Staging in a 160MW Coal Fired Boiler,"
1991 Joint Symposium on Stationary Combustion NOX Control, EPA/EPRI, March 25-28, 1991.

Springer, B. K., "Southern California Edison's NOX Reduction Program Utilizing Selective  Non-
Catalytic Reduction  (Urea-Injection)," EPRI  Workshop NOX  Controls  for Utility  Boilers,
Cambridge, MA, July 7-9, 1992.

Steam. 39th Edition, Babcock and Wilcox, 1978.

Taback, H.  J., et al., "Control of Hydrocarbon Emissions from Stationary Sources in the California
South Coast Air Basin," KVB 5804-714, June 1978.

Tanaka, T.,  "Emissions of Pollutants in Coal Combustion: Development of Prediction Methods and
Countermeasures," 8th EPRI/CRIEPI Joint Working Session, October 1987.

Tarli, R., "Retrofitting of the Italian  Electricity Board's Thermal Power  Boilers," 1991  Joint
Symposium on Stationary Combustion NOX Control, EPA/EPRI, March 25-28,  1991.
                                          R-7
-------
Teetz, R. D., et al., "Urea SNCR Demonstration at Long Island Lighting Company's Port Jefferson
Unit 3," EPRI Workshop NOX Controls for Utility Boilers, Cambridge, MA, July 7-9,  1992.

Teixeira, D. P., et al., "Full Scale  Tests of SNCR Technology on  a Gas Fired Boiler," EPRI
Workshop NOX Controls for Utility Boilers, Cambridge, MA, July 7-9, 1992.

Thompson, R.  E., et al., "NOX Emission Results for  a  Low-NOx PM Burner Retrofit," EPRI
GS-6423, July 1989.

Tokuda, K., et  al., "Evaluation of the PM Burner: A Low-NOx Pulverized-Coal-Firing System for
Tangentially Fired Utility Boilers,"  EPRI CS-5034, February 1987.

Towle, D. P., et al., "An Update on NOX Emissions Control Technologies for Utility Coal, Oil, and
Gas Fired Tangential Boilers," presented at the American Flame Research Committee Spring 1991
Meeting on Control, Development,  and  Commercial  Applications,  Hanford,  Connecticut,
March 1991.

Trivett, G. M., "NOX Reduction and Control  Using an Expert System Advisor,"  1991 Joint
Symposium on Stationary Combustion NOX Control, EPA/EPRI, March 25-28, 1991.

U.S. DOE, "CCT Demonstration Program, Program Update 1990," DOE/FE-0219P, February 1991.

U.S. Senate, Committee on Public Works, "Air Quality and Stationary Source Emission Control,"
Serial No.  94-4, March 1975.

Uemura, T., "Update 91 on Design and Application of Low NOX Combustion Technologies for Coal
Fired Utility Boilers," 1991 Joint Symposium on Stationary Combustion NOX Control, EPA/EPRI,
March 25-28, 1991.

Utility Air Regulatory Group (UARG), NOX Acid Rain Advisory Committee Meeting, Washington,
DC, July 31-August 2, 1991.

Van der Kooij, et al., "Demonstration of Low NOX Combustion Techniques at the Coal/Gas-Fired
Maas Power Station Unit 5,"  1991 Joint Symposium  on Stationary Combustion NOX Control,
EPA/EPRI, March 25-28,  1991.

Vatsky, J.,  and Sweeney, T. W., "Development of an Ultra-Low NOX Pulverizer Coal-Burner," 1991
Joint Symposium on Stationary Combustion NOX Control, EPA/EPRI, March 25-28, 1991.

Vatsky, J., "NOX  Control:  The Foster Wheeler Approach,"  1989 Symposium  on  Stationary
Combustion NOX Control, EPRI GS-6423, July 1989.

Wilson, S. M., et al., "Demonstration of Low-NOx Combustion Control Technologies on  a 500 MWe
Coal-Fired Utility Boiler,"  1991 Joint Symposium on  Stationary  Combustion  NOX Control,
EPA/EPRI, March 25-28,  1991.

Wingard, R. M.,  and J. G. Herbein, "Homer City Generating Station Unit 2 Low NOX  Burner
Experience," EPRI Workshop NOX  Controls for  Utility Boilers, Cambridge, MA, July  7-9,  1992.

Yagiela, A. S., et al., "Update on Coal Reburning Technology for Reducing NOX in Cyclone Boilers,"
1991 Joint Symposium on Stationary Combustion NOX Control, EPA/EPRI,  March 25-28, 1991.

                                         R-8
-------
Yee, J. L. B., et al, "Retrofit of an Advanced Low-NOx Combustion System at Hawaiian Electric's
Oil-Fired Kobe Generating Station," 1989 Symposium on Stationary Combustion Nitrogen Oxide
Control, EPRI GS-6423, July 1989.
                                         R-9
-------
-------
                       EXPLANATION OF APPENDICES A AND B


       Appendices A and B contain data extracted from the EPA NURF data base on utility boiler
NOX emissions in the NESCAUM region, supplemented with revised utility data on unit size, age,
furnace design, firing type, heat rate, NOX  emission factor,  capacity factor, total 1987 NOX
emissions, and 1987 fuel consumption. The revised data were obtained from the ESEERCO1 study
and the following utilities/organizations:

          Northeast States for Coordinated Air Use Management (NESCAUM)
          United Illuminating Company
          Consolidated Edison  Company of New York, Inc. (Con Edison)
          New York State Electric & Gas Corporation (NYSEG)
          Niagara Mohawk Power Corporation (NMPC)
          Public Service Electric and Gas Company (PSE&G)

Appendices A and B contain the NESCAUM boiler inventory for coal-fired units and oil-/gas-fired
units, respectively. Two spreadsheets are included in each appendix.

       In the first spreadsheet, the information is sorted according to age, furnace design, and firing
type. Weighted average NOX emission factors (WANEFs) and weighted average capacity factors
are calculated for each furnace design/firing type category within each specified age group (0 to
20 years, 21  to 30 years,  31 to 40 years, and  greater than 40 years). The WANEFs, in  units of
"Ib/MBtu," are calculated using the individual NOX emission  factors (NEF)-and boiler sizes (MW)
as follows:
                                WANEF =
The weighted average capacity factors (WACFs) are calculated with the individual factors (CF) and
boiler sizes (MW) as follows:


                                             CF MW.
                                 WACF  =
       Hunter, S. C, "NOX Emissions from Fossil Fuel Power Plants in New York State,"
       KVB Report No. EP85-6, prepared for the Empire State Electric Energy Research
       Corporation, August 1989.
-------
The data can be  used to identify the units within  a  specific age and  design group and the
representative capacity and NOX emission factors.

       In the second spreadsheet, the information is sorted alphabetically according to the state,
utility, and plant names.  The organization of the data facilitates the location of specific boilers of
interest.

       At the end of each spreadsheet is a total for the 1987 NOX emissions, in tons; the capacity,
in MW; and the number of units used for that spreadsheet.
-------
               APPENDIX A




NESCAUM BOILER INVENTORY-COAL-FIRED UNITS
                  A-1
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                  APPENDIX B




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                     APPENDIX C




SCHEMATICS OF LOW-NOX CONTROL EQUIPMENT AND OPERATION
                        C-l
-------
-------
C.1    OVERFIRE AIR SYSTEMS
                                   C-3
-------
-------
    r
Combustion Air
                Advanced overfire air concept (Wilson, 1991)
                                KCOHOAIT
                                All DUCl
                                VEHIUII
          Typical advanced overfire air port system (Vatsky, 1991)
                                    C-5
-------
-------
C2   COAL-FIRED LOW-NOX BURNERS
                               C-7
-------







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                                                 Principle of offset firing with LNCFS
                                       ADJUSTABLE TURNING VANES
                                                                    SCANNER
                                                       TILT DRIVE
                                   PLAN VIEW (A - A) OF AUX. AIR COMPART.
Low-NOx concentric firing system (LNCFS) windbox modification arrangement at Hunter No. 2
(Kokkinos, et al., 1985)
                                           C-10
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                                  U
                                             SEPARATED OFA WITH
                                               ADJUSTABLE YAW
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                                              CLOSE COUPLED OFA
                                              COAL NOZZLE CLUSTER
                                              OFFSET AIR NOZZLES
                                                     ( CFS )
PRE RETROFIT
POST RETROFIT
   Concentric clustered tangential firing system (CCTFS) concept for low-NOx retrofit
   applications (not commercially offered)
                                C-13
-------
OF*
OFA
Firing Zone
                                                                 SEPARATED
                                                                 CLOSE COUPLED
                                                                     OFA
                                                                       c	
                                                                       Firing Zone
                   SIDE ELEVATION
                    UNMODIFIED
                     W1NOBOX
                                                              CONC.
                                                              COAL

                                                              WEAK
                                                              COAL
                                                              AIR
                                                     SIDE ELEVATION
                                                    PM FIRING SYSTEM
                                                       MOOIFIEO
                                                       wiNoeox
          PM Elbow
          Separator
                                                                                  (Cone)
                                                                                  (Weak)
                                                                             Burner
                                                                             Front
                                                                        Coal
                                                                        Pipe
      Schematic of Unmodified and PM modified windowboxes at Kansas Power & Light
      Lawrence Unit No. 5 (Lewis, et al., 1989)
                                           C-14
-------
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                                                                            Inner secondary air with some
                                                                            recircutation to base of flame
Conical
Diffuser
                                                   Measuring   j- Adjustable
                                                               Spin Vanes
         Pulverized
         Coal and
         Primary Air
                             (A) High temperature - fuel rich devolatization zone

                             () Production of reducing species

                             (£) NOX decomposition zone

                             (D) Char oxidizing zone

                            Babcock & Wilcox XCL burner with impeller
                            (La Rue, 1990)
                                                                                      Outer Secondary
                                                                                        Air Mixing
                                   TERTIARY   SECONDARY

                                     AIR        AIR
          ,— IGNITER
                               FOR SUiRL CONTROL
                    I

                    I— FLAHE HOLDER
   PRIriARY AIR
       »

PULVERIZED COAL
                           "BWE type 4 AF" attached flame low-NOx burner
                           (McCartney, 1991)
                                                 C-16
-------
Modified HTNR burner for coal and gas firing (Van der Kooij, et al., 1991)
                               C-17
-------
   Controlled flow split name burner (Vatsky, 1991)
                                               (X GUN
Internal Fuel Staged Low NOX Burner™ (Vatsky, 1991)
                       C-18
-------
                                    ADJUSTABLE AIR ZONE DISK

                                                    AIR ROW MONITOR
AIR ZONE
DISK DRIVE
                                                        ADJUSTABLE
                                                        AIR ZONE DISK
                              OBSERVATION     SPIN \*N£
                              PORT          ADJUSTMENT
                                                                           ADJUSTABLE
                                                                           LOUVER DAMPERS
           Low NOX cell burner (LaRue, 1989)
-------
C3   REBURNING OR FUEL STAGING ARRANGEMENTS
                               C-21
-------
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C-23
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                                            ADVANCED MACT SYSTE"
          Principle of MACT (Araoka, 1987)
                        C-24
-------
           SORBENT
        (HIGH LOAD)
     OVERFIRE AIR + ,
SORBENT (LOW LOAD)

       GAS 20% +FGR'

          COAL 80% -
                                      COAL 80%'
                  SORBENT
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                  GAS 20% + FGR
                      TANGENTIAL
        CYCLONE
                    GR-SI configurations for two types of boilers
                    (Bartok, et al., 1991)
           SQRBENT*
      EL 553' - 0"
      SIX 3" INJECTORS
      - 240 FT/S
      - 4 ON FRONT WALL
      - 2 ON SIDE WALLS
      TRANSPORT AIR IS 3% OF
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           REBURN GAS
      EL  520' - 6"
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       4Va" * I" NOZZLES
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      - 415 FT/S
      FGR IS 3% OF TOTAL FLUE
      GAS FLOW
              REBURN AIR
          EL  530'  - 9"
          FOUR 15" x 30" PORTS
          - 110 FT/S
          - 575°F
          - ADJUSTABLE VANES
EXISTING
  COAL
BURNERS
                                        * LOW  LOAD SI THROUGH REBURN AIR INJECTORS

            Summary of injector specifications for tangentially-fired boiler
                                      C-25
-------
C-26
-------
C.4   OIL- AND GAS-FIRED BURNERS
                                 C-27
-------
                      Vane
Fuel gas  ring
                                               Tert.  air
                                                  Sec. air
     PG dual air register low-NO, burner/OFA/FGR (BHK/B&VV)
     (Pepper, et al., 1987)
                            C-29
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Structure of gas firing ROPM burner (Pepper, et al., 1987)
                         C-32
-------
Burner  assembly
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21 Atomizing air
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 6/ Ignitor
 71 Flame detector
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101 Cylindrical air damper with drive

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 Rodenhuis and Verloop TTL/MG Burner and Atomizing Bullet Assembly (Afonso, 1991)
                                C-33
-------
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FUEL GAS INLET
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                                          C-34
-------
C5   FLUE GAS RECIRCULATION AND OVERFIRE AIR (NOX PORTS) SYSTEMS
                                C-35
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                                                                     Surface
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                                         C-50
-------
                                                Coolside Sorbent and
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                                          Dampers
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                                                                        Collector
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                                                                               Acid
                                                                             Storage
                                                                               Tank
                     WSA-SNOX flue gas cleanup
                                  C-51
-------
    NOx RECYCLE
                                            TO GLAUS PLANT
    DENSE
    PHASE
TRANSPORT
                                                     AIR
     NOXSO process flow diagram.  Source:  Neal, 1991
                          C-52
-------
                                      APPENDIX D

               SUMMARY OF REPORTED NOX CONTROL PERFORMANCE
       This Appendix lists references and assumptions that were used to estimate NOX control
efficiencies for applicable control technologies evaluated in this study. Baseline NOX levels for the
NESCAUM boiler population are presented in Table 3-4 in the main body of the report.  Percent
NOX reductions shown in bold reflect estimates of NOX reduction potential for the NESCAUM
boilers. These estimates are based on reported efficiency of NOX controls or controlled NOX levels
achieved on other utility boilers of the same firing type and that use the same type of fuel (coal and
gas/oil), taking into consideration control levels achieved and what NOX reduction efficiency these
control levels correspond  to when applied  to baseline levels  in NESCAUM.  These reduction
efficiencies and controlled NOX limits are also presented in Tables 4-1, 4-2,  4-3,  and 4-6.   NOX
reduction  efficiencies  are  reported  in  ranges to reflect the variability  of reported control
performances.  Generally, higher percentages of NOX reductions apply to  higher baseline  NOX
levels.   For example, pre-NSPS wall  PC-fired boilers in the NESCAUM region are currently
emitting NOX in the range of  0.42 to  1.77 Ib/MMBtu (0.95 weighted average).   The control
efficiency of low-NOx burners without separate overfire air  is estimated in  the  range  of 35 to
55 percent, reflecting performances reported in the literature.  Therefore, the controlled limits are
estimated to vary between approximately 0.43 (0.95 x 0.45) to 0.62 (0.95 x 0.65) Ib/MMBtu.  This
range is rounded to 0.45 to 0.60 Ib/MMBtu since controlled emission  limits in  this study are
generally rounded up in increments of 0.05 Ib/MMBtu.
                                           n.i
-------
TANGENTIAL, DRY-BOTTOM, PC-FIRED BOILERS

Average Baseline NOX Emission Levels (see Table 3-4)

       0.45 to 0.80 Ib/MMBtu-pre NSPS (range)
       0.65 Ib/MMBtu—pre-NSPS (average)

Reported NOX Control Efficiencies

       OFA—15- to 30-Percent NOX Reduction

          Based on efficiency  range of  15  to 30  percent provided by EPRI (Miller, 1985;
       Thompson, 1986). Effect of OFA for the 420 MWe Utah Power & Light Hunter Unit 2 was
       to reduce NOX from  460 to  360 ppm  on short-term tests, about 20-percent  reduction
       (Kokkinos, 1985) at 80-percent load.

       LNB (LNCFS Burners With CCOFA)-25- to 35-Percent NOV Reduction
                                                            x
          Ranges in NOX reductions are based on results from  Utah Power & Light  Hunter
       Unit 2 retrofit of LNCFS with close coupled OFA resulting in NOX reduction from baseline
       levels of 460 and 360 (without and with OFA) to 240 and 260 ppm, corresponding to a
       control efficiency range of 33 to 48 percent (short term).  Long-term tests over a 50- to
       85-percent load range showed 33-percent reduction to 0.41 Ib/MMBtu (Kokkinos, 1985)
       ABB-CE projects LNCFS Level I performance in the 25-  to 32-percent range (Grusha,
       1991).

       SOFA + LNB (PM and LNCFS Level Levels II and III)-30- to 50-Percent NO., Reduction
          Thirty-day mean reported at 34- to 35-percent reduction to 0.45 Ib/MMBtu on Plant
       Lansing Smith 200-MWe Unit 2 with LNCFS Level II and Level III (Hunt 1992).  Results
       of these  tests are particularly applicable because the coal is eastern bituminous, which is
       more representative of the NESCAUM  region.  Additional tests  include the following.
       LNCFS Level III retrofit at Labadie 600-MWe Unit 2 which showed short-term performance
       in the 30- to 50-percent range, to a range of 0.5 to 0.69-lb/MMBtu (highly controlled levels
       at low loads)  burning midwestern bituminous coal  (Smith, 1992).  Short-term  tests on
       ENEL's  160-MWe Fusina burning U.S. bituminous coal showed 50-percent reduction with
       CCTFS and 30-percent SOFA from 510 to 240 ppm (ABB, 1991).  NOX reductions of 48 and
       52 percent to 200 ppm levels with  LNCFS Level II reported on short-term tests on Public
       Service of Colorado 160-MWe Valmont Unit 5 and 350-MWe Cherokee Unit 4 (Hunt, 1991;
       Hunt,  1992).  CCTFS reduction range reported ABB in the range of 41 to 50 percent
       (Grusha, 1991).

          Short-term tests on Kansas Power & Light 400-MWe Lawrence Unit 5 PM burner
       retrofit with 25-percent SOFA reporting NOX controlled levels of 125 to  150 ppm  from
       baseline  levels of 310 to 400 ppm over load range of 40  to 80 percent (Thompson, 1989;
       Grusha,  1991) corresponding to reductions of about 60 percent.  Results of these tests are
       least applicable to NESCAUM boilers because the PM technology is not likely to be used
       in the U.S. and because these results were obtained with  high volatile coals.
                                         D-3
-------
Returning—40- to 60-Percent Reduction

    Based on  NOX reduction  efficiency short-term  full-load test  results  showing NO
reduction from baseline of 400 ppm (0.53 Ib/MMBtu)  to the range of 125 to  225 ppm
(0.17 to 0.30 Ib/MMBtu), corresponding to a reduction of 44 to 69 percent for the 71-MWe
Hennepin Station Unit 1 reburn demonstration burning high sulfur bituminous coal (Bartok,
1991);  long-term tests  on  the  same boiler showed a performance of 60-percent NOX
reduction to 0.28 Ib/MMBtu (May and Kruger,  1992) and a minimum NOX reduction of
40 percent for the  technology reported by GRI (1991).  Therefore, the  minimum NOX
reduction efficiency is taken to be 40 percent, whereas the best reduction is taken to be
60 percent based on the long-term tests at Hennepin.
                                   D-4
-------
WALL AND OPPOSED, DRY-BOTTOM, PC-FIRED BOILERS

Average Baseline NOX Emission Levels (see Table 3-4)

      0.42 to 1.77 Ib/MMBtu pre-NSPS range
      0.95 Ib/MMBtu (average)

Reported NOX Control Efficiencies

      OFA—15- to 25-Percent NOX Reduction

          Long-term tests on Georgia Power Hammond Unit 4 burning eastern bituminous coal
      retrofitted with 20-percent AGFA ports showed NOX reduction from about 900 to 720 ppm
      (1.12 to 0.96 Ib/MMBtu), 18-percent average reduction; 24-percent reduction at full load
      (Sorge, 1992)  and 670 ppm to 550 ppm (0.89 to 0.73 Ib/MMBtu), 19-percent at low load
      (Wilson, 1991).

          Allegheny Power Pleasant 650-MWe Unit 2 post-NSPS unit equipped with OFA. Long-
      term tests show NOX  reduction from  0.95 to 0.65 Ib/MMBtu  at full load (33-percent
      reduction) (Vatsky, 1989).  The low range in performance (15-percent reduction efficiency)
      was also reported by EPRI (Miller,  1985).

      LNB—35- to 55-Percent NOX Reduction

          Results at Hammond 500-MWe Unit 4 show a 30-day, 48-percent NOX reduction
      average  to  0.64 Ib/MMBtu;  53 percent based on 94-day average  from 1.12 baseline  to
      0.53 Ib/MMBtu (Sorge,  1992). Short-term tests on Harrison 500-MWe Unit 4 also showed
      55-percent reduction to a level of 0.5 to 0.6 Ib/MMBtu (Vatsky, 1989). TVA Johnsonville
      results report 53-percent reduction, short-term, to 0.45 Ib/MMBtu (McAusker, 1992). B&W
      LNB retrofits  report  short-term  NOX reductions of 46 percent at Gaston 250 MWe Unit 2
      (Hardman, 1992); 43  percent at Edgewater 100 MWe Unit 4 (LaRue, 1989); and 55 percent
      at Stuart 605 MWe Unit 4 (Laursen, 1992). Controlled levels for these B&W retrofits range
      between 0.40  and 0.53 Ib/MMBtu.   Lowest  performance  reported  at  San Juan with
      34-percent NOX reduction (Vatsky, 1995) and foreign LNB retrofits (VanDerKooji, 1991).

          Additional results include NOX reduction for Pleasant Unit 2 opposed firing retrofit with
      CF/SF were 55 to 60 percent from pre-NSPS levels to 0.4 Ib/MMBtu and 43 percent from
      post NSPS of  0.7 Ib/MMBtu. These levels achieved without OFA at full load (Vatskey,
       1989). Four Corners Units 4 and 5 subbituminous opposed firing retrofit of CF/SF LNB
      without OFA reduced NOX from pre-NSPS level of 1.28 Ib/MMBtu (cell-burners) to a range
      of 0.48 to 0.52 Ib/MMBtu corresponding to about 60-percent reduction  (Vatsky, 1989).
      Retrofit of other boilers with CF/SF LNBs show controlled levels in  the range of 0.35  to
      0.50 Ib/MMBtu  (Vatksy, 1989) corresponding to  reductions of 40  to  55 percent from
      NESCAUM boilers baseline levels.

      LNB + OFA-40- to 60-Percent NOX Reduction

          Only two domestic pre-NSPS boilers have been tested with LNB + OFA. Of these, only
      one, the Hammond 500-MWe Unit 4, is burning eastern bituminous coal.  Short-term test
      results show a 60-percent NOX reduction to  levels of 0.54 Ib/MMBtu (Sorge, 1992).  The
      second retrofit, Allegheny Power Pleasant 650-MWe  Unit 2 retrofitted with CF/SF and

                                          D-5
-------
OFA,  reduced  NOX from  0.90 to  0.95 Ib/MMBtu,  uncontrolled  without OFA,  to
0.33 Ib/MMBtu (60- to 65-percent NOX reduction) on short-term tests at full-load burning
a more volatile coal (Vatksy, 1989).

   Additional tests concluded San Juan Unit 1 of Public Service of New Mexico with a
short-term performance of 65 percent (Vatsky,  1989) and two foreign installations with
reported long-term performed  in the range  of 60 to  64 percent  (Vatsky, 1991 and
VanDerKooji, 1991).

Reburning—45- to 60-Percent NOX Reduction

   No test data available yet on the only one domestic wall-fired demo at Public Service
of Colorado  158-MWe, Cherokee Unit 3.  Assumed NOX reduction efficiency based  on
tangential 71-MWe Hennepin Unit 1 (see tangential data).  However, the low end of NOX
reduction performance is increased slightly, from 40 to  45 percent, because higher NOX
reduction efficiency is anticipated with the higher baseline level of wall-fired units.
                                    D-6
-------
CYCLONE, COAL-FIRED BOILERS

Average Baseline NOX Emission Levels (see Table 3-4)

       1.28 Ib/MMBtu (21 to 30 years of service)

Reported NOX Control Efficiencies

       Returning—45- to 60-Percent NOX Reduction

          Ohio Edison Niies Station  Unit 1,  108 MWe,  burning  eastern bituminous  coal,
       retrofitted with 18-percent gas reburn with 10-percent  FOR.  Short-term tests at full load
       show reduction from 700 ppm to 300 ppm (0.93 to 0.40 Ib/MMBtu), 57-percent reduction.
       At 80 percent of full load, NOX reduced from 620 to the range of 250 to 300 ppm (52 to
       60 percent)  on short-term tests.  Long-term  performance at Niies was reported to range
       between 46 and 48 percent (Brown, 1992).  With coal as the reburning fuel, NOX reductions
       of 30 to  53 percent over the load range were reported  at Nelson Dewey 100 MWe Unit 2
       (Newell, 1992). Therefore, the lowest performance  for natural gas  reburn is taken to be
       45 percent based on Brown's results.  The best performance is taken to be 60 percent based
       on short-term test results.
                                         D-7
-------
TANGENTIAL, OIL-, AND GAS-FIRED BOILERS

Average Baseline NOX Emission Levels (see Table 3-4)

       0.34 Ib/MMBtu (average post-NSPS)
       0.24 Ib/MMBtu (average pre-NSPS)
       0.28 Ib/MMBtu (average all units)

Reported NOX Control Efficiencies

       Two-Staged Combustion (BOOS or OFA)—15- to 20-Percent NOX Reduction (Pre-NSPS)
                                             25- to 40-Percent NOX Reduction (Post-NSPS)

          NOX reduction estimated by Con Edison  to be approximately 30 percent (Mormile,
       1991), corresponding to the  average of  the  range estimated for  NESCAUM.   Other
       estimates reported by Hunter, 1989, and Lim,  1980, for Northeast and California utilities
       were reported as high as 45 and 55 percent, respectively.

          NOX reduction efficiency  was based on the results for wall-fired boilers (Kehro, 1991
       and Bayard de Volo, 1991), which indicated controlled NOX levels with BOOS and OFA in
       the range of 0.19 to 0.28 Ib/MMBtu.  0.19 Ib/MMBtu corresponds to reduction efficiency
       of less than  20  percent  from  current  NESCAUM  (pre-NSPS)  baseline level  of
       0.24 Ib/MMBtu and 20 to 40 percent from the post-NSPS level of 0.34 Ib/MMBtu.

       Windbox Flue Gas Recirculation—25- to 40-Percent NOX Reduction (Pre-NSPS)
                                     20- to 30-Percent NOX Reduction  (Post-NSPS)

          Six SCE Units in the range of 320 to 330 MWe operating on oil with 20-percent FOR
       at full  load reduced  NOX  from about 350 ppm  to a  range  of 215 to 245 ppm,  30- to
       40-percent reduction (Lim, 1980).  Con  Edison predicts 23-percent NOX  reduction with
       15-percent FOR (Mormile, 1987).

       Two-Staged Combustion and Flue Gas Recirculation—30- to 50-Percent NOX Reduction
                                                       (Pre-NSPS)
                                                       30- to 40-Percent NOX Reduction
                                                       (Post-NSPS)

          PG&E Pittsburgh Unit 7 equipped with FOR and TSC, with OFA ports,  resulted in
       long-term operation with controlled NOX levels as low as 175 ppm (about 0.20 Ib/MMBtu)
       from a baseline of about 750 ppm, corresponding to a reduction of 77 percent (Lim, 1980).
       For the NESCAUM oil/gas T-fired population, the uncontrolled NOX level of 175 ppm
       represents  a  reduction potential  of about   30 percent  from  current  baseline  levels.
       Experience reported in Southern California with SCE boilers shows  controlled  NOX levels
       achieved with this combination of controls in the range of 0.10 to 0.20 Ib/MMBtu (Bayard
       de Volo,  1991) principally with natural gas  fuel.  This  range  corresponds to an NOX
       reduction efficiency of 40 to 60 percent.  Lower percent reductions are likely with heavier
       oil and with low initial NOX levels shown by tangential units.
                                          D-8
-------
Low-NOx Burners—25- to 50-Percent NOX Reduction (Pre-NSPS)
                  20- to 40-Percent NOX Reduction (Post-NSPS)

    Tests  performed  on ENEL's  Fusina 160-MWe Unit 2 coal-/oil-/gas-fired boiler.
Baseline emissions on oil/gas are about 200 to 250 ppm.  Short-term tests with CCFTS
resulted in controlled NOX levels in the range of 125 to  150 (0.16 to 0.19 Ib/MMBtu);
corresponding to a reduction of 25 to 50 percent at full load (Grusha, 1991).  Performance
sensitive to fuel nitrogen.  Although those tests may not be considered representative of
NOX reduction performance for  boilers designed for gas  and oil firing, several units in
NESCAUM have undergone fuel switching. Recent tests on a non-tangential boiler by New
England Power (NEPCO)  Company showed  controlled  levels  in  the range  of 0.27 to
0.15 Ib/MMBtu with LNB retrofit (Afonso, 1992). These levels correspond to a reduction
of about 20 to 50 percent from average baseline levels.  Estimates as  high as  60-percent
reduction with LNB by Con Edison are not deemed applicable to initially  low levels of
baseline NOX.

OFA (BOOS) + FGR + LNB-40- to 60-Percent NOX Reduction (Post-NSPS)
                          40- to 70-Percent  NOX Reduction (Pre-NSPS)

    NOX controlled levels reported to date for this combination of controls on gas-/oil-fired
boilers show a range  of 0.10 to 0.20 Ib/MMBtu (Bisonett, 1991, Kehro,  1991;  Bayard de
Volo, 1991).  See results reported for wall-fired units. These levels are deemed attainable
with tangential units  but will depend on properties  of fuel burned.  Therefore, control
efficiencies are estimated to range between 40 and 70 percent from current control levels
of T-fired boilers.

Reburning—50- to 60-Percent NOX Reduction (Pre-NSPS)
           30- to 50-Percent NOX Reduction (Post-NSPS)

    Pilot tests at ABB Boiler Simulation Facility with plans for full-scale retrofits on ENEL
boilers in Italy show NOX reduction of 50 to 60 percent on  natural gas fuel with  15-percent
reburn (ABB, 1991).  Full-scale reductions of 60 percent achieved with fuel oil reburning
fuels on one  demonstration in Italy (DeMichele,  1992).  Maximum NOX reductions are
estimated to be on the same order of magnitude as LNB-based controls.  These estimates
are highly speculative because of lack of full-scale  data and experience.
                                   D-9
-------
WALL AND OPPOSED OIL- AND GAS-FIRED BOILERS

Average Baseline NOX Emission Levels (see Table 3-4)

          0.35 Ib/MMBtu (average post-NSPS)
          0.52 Ib/MMBtu (average pre-NSPS)
          0.45 Ib/MMBtu (average all units)

Reported NOX Control Efficiencies

      Two-Staged Combustion (BOOS or OFA)—30- to 35-Percent NOX Reduction (Pre-NSPS)
                                             25- to 35-Percent NOX Reduction (Post-NSPS)

          BOOS on  Hawaiian Electric Co. (HECO) Kahe  146-MWe  Unit 6  resulted in  a
      38-percent reduction from baseline levels of 0.8 Ib/MMBtu firing oil with approximately
      0.3-percent fuel-bound nitrogen (Yee, 1989). Tests with one row of BOOS on Salem Harbor
      Unit 4 showed NOX reductions equivalent to that achieved with oil/gas LNB, 43 percent
      (Afonso,  1992).   Long-term  operation under this BOOS pattern was not considered
      acceptable, however.

          SCE Los Alamitos 460-MWe opposed gas-fired Unit 6 with uncontrolled NOX emissions
      of 700 ppm. Long-term tests at full load show reduction by 79 percent, to 150 ppm (Bayard
      de Volo,  1991).  Controlled level of 150 ppm (0.19 Ib/MMBtu) corresponds to average
      reduction of about 50 percent from all NESCAUM boilers.  However, this performance is
      expected only when natural gas is burned in a high heat release  unit.  Con Edison estimates
      performance at 30 to 35 percent (Mormile, 1991; Mormile 1987).

      Windbox Flue Gas Recirculation—25- to 40-Percent NOX Reduction (Pre-NSPS)
                                     20- to 30-Percent NO, Reduction (Post-NSPS)
                                                       *                         .

          PG&E Contra Costa 345-MWe oil-/gas-fired pre-NSPS boiler retrofitted with OFA and
      FOR reduced NOX emissions from 330 to 420 ppm at full load to 200 to  180 ppm with
      controls (39- to 52-percent reduction), long-term tests (Bisonett, 1991).

          Ten-percent FGR on HECO's 146-MWe Kahe  Unit 6 resulted  in a  reduction of
      48 percent to an NOX level of about 320 ppm (0.40 Ib/MMBtu) with 0.3-percent nitrogen
      oil (Yee, 1989).  This controlled level corresponds to 25-percent reduction from pre-NSPS
      NESCAUM units.   Con  Edison predicts 23-percent reduction  with  15-percent FGR
      (Mormile,  1987).

      Two-Staged Combustion (BOOS or OFA) and   —40- to  50-Percent NOX Reduction
      Flue Gas Recirculation                       (Pre-NSPS)
                                                  40- to 50-Percent NOX Reduction
                                                  (Post-NSPS)

          Hawaiian  Electric Co. Kahe  146-MWe Unit 6, oil-/gas-fired.  Long-term tests with
      BOOS and 10-percent FGR showed controlled NOX levels to 220 ppm (0.28 Ib/MMBtu) at
      full load (Kehro, 1991). Controlled level of 0.28 corresponds to a reduction of 30 percent
      from average baseline emissions from all NESCAUM boilers.
                                         D-10
-------
    SCE Los Alamitos 460-MWe opposed gas-fired Unit 6 with uncontrolled NOX emissions
of 700 ppm.  Short-term tests at full load show  reduction by  91 percent to 65 ppm
(0.08 Ib/MMBtu) (Bayard de Volo, 1991).  From average NESCAUM boiler emissions this
level of control corresponds  to a reduction of 80 percent.

    SCE Ormond Beach 820-MWe Unit 2 with FOR and BOOS reduced emissions from
1,200 ppm uncontrolled to  120 to 150 ppm (0.15 to  0.19 Ib/MMBtu) over the 400-  to
700-MWe load range during 1-month duration tests (Bayard de Volo, 1991).  This level of
control translates to an average  NOX  reduction  of 55 to 65 percent from  NESCAUM
baseline levels. PG&E estimates NOX reductions of 43  percent for 345-MWe Contra Costa
Unit 6 with oil and 50 percent with gas  (Bisonett, 1991).

Low-NOx Burners (LNB)-40- to 50-Percent NOX Reduction (Pre-NSPS)
                        30- to 40-Percent NOX Reduction (Post-NSPS)

    Retrofit of PG-DRB burners  at HECO's Kahe  146-MWe Unit 6 resulted in an NOX
reduction   from  about  600 ppm  (0.8  Ib/MMBtu)   to  400  ppm  (0.53  Ib/MMBtu),
corresponding to a 33-percent reduction (Yee, 1989).

    Recent tests at Salem Harbor 435-MWe Unit 4  showed short-term NOX  reduction of
43 percent (Afonso,  1992). B&W  tests on pilot-scale facility using XCL gas/oil  LNB show
75 ppm (0.1 Ib/MMBtu for gas) without FOR from 160 ppm uncontrolled (about 50 percent
reduction).  No. 6 oil results from uncontrolled 210 to 120 ppm (0.27 to 0.15 Ib/MMBtu)
with no FGR (LaRue, 1989).  This level of control translates to  a  reduction  efficiency of
33 to 63 percent, the average NESCAUM baseline level. Con Edison estimates 60-percent
reduction for  LNB (Mormile, 1987). This level is considered optimistic.

BOOS + FGR-40- to 50-Percent NOX Reduction (Pre-NSPS)
             40- to 50-Percent NOX Reduction (Post-NSPS)

    Con Edison  reports control efficiency in  the range of 45 to  50 percent (Mormile).
Control efficiency reported in the range of 19 to 76 percent, with an average for five utility
boilers at 55 percent (Lim,  1980).  For NESCAUM, the efficiency is estimated to be no
greater than that achievable  with LNB retrofit.

OFA (BOOS) + FGR + LNB—60- to 80-Percent NOX Reduction (Pre-NSPS)
                         45- to 70-Percent NOX Reduction (Post-NSPS)

    PG&E Contra Costa 345-MWe oil-/gas-fired pre-NSPS boiler showed short-term NOX
reduction from 330 to 420 ppm to  70 to 150 ppm (65- to 78-percent reduction) at full load
(Bisonett, 1991).

    Hawaiian Electric Co. Kahe 146-MWe Unit 6 oil-/gas-fired. Retrofit of PG-DRB, OFA,
and FGR resulted in NOX controlled levels of 0.19 Ib/MMBtu at full load during short-term
tests (Kehro, 1991); corresponds to about 60-percent  reduction from average baseline level
of 0.45 Ib/MMBtu for all wall-fired boilers in NESCAUM.

    SCE Los AJamitos 460-MWe opposed gas-fired Unit 6 with uncontrolled NOX emissions
of 700 ppm.  Short-term tests at full load show reduction of 49 ppm (93-percent reduction
over the load range of 100 to  500 MWe)  (Bayard de Volo, 1991); corresponds to 80-percent
reduction using average NESCAUM baseline.
-------
    These retrofits represent a controlled NOX range of 0.10 to 0.20 Ib/MMBtu, depending
on fuel type. This control range corresponds to control efficiency of about 60 to 80 percent
from pre-NSPS baseline of 0.52 Ib/MMBtu, and 45 to 70 percent from post-NSPS baseline
of 0.35 Ib/MMBtu.

    SCE Ormond Beach 820-MWe Unit 2 burning gas/oil. Retrofitted with Todd Dynaswirl
burners and FOR+BOOS reduced NOX from 1,200 ppm uncontrolled to 90 to 150 ppm over
load range from 400 to  700 MWe and  1-month duration tests (Bayard de Volo, 1991);
corresponds to 50- to 70-percent reduction from average NESCAUM baseline levels.

    SCE Los Alamitos 460-MWe opposed gas-fired Unit 6 with uncontrolled NOX emissions
of 700 ppm.  Short-term tests at full load show reduction by 75 percent to 174 ppm (Bayard
de Volo, 1991).

Returning—50- to 60-Percent NOX Reduction  (Pre-NSPS)
           30- to 50-Percent NOX Reduction (Post-NSPS)

    Pilot-tests at ABB Boiler Simulation Facility with plans for full-scale retrofits on ENEL
boilers in Italy show NOX reduction of 50 to 60 percent on natural gas fuel with 15-percent
reburn (ABB,  1991).   PG&E estimates 30- to  73-percent  NOX  reduction  (average
58 percent) for 5 boilers ranging in size from  330 to 700 MWe  (Bisonett, 1991).  No test
data available on full-scale utility boilers. Maximum NOX reductions are estimated to be on
the same order of magnitude as LNB-based controls.  These estimates are highly speculative
because full-scale data and experience are  lacking.
                                   D-12
-------
COAL-FIRED DRY-BOTTOM BOILERS

Average Baseline NOX Emission Levels (All Boiler Designs)

       0.75 Ib/MMBtu (pre-NSPS)

Combustion Controlled NOX Levels (AH Boiler Designs)

       0.25 to 0.40 (0.33) Ib/MMBtu (all boilers)

Reported NOX Control Efficiency

       Selective Noncatalytic Reduction (SNCR)—25- to 40-Percent NOX Reduction from
                                              Controlled Levels
                                              30- to 50-Percent NOX Reduction from
                                              Uncontrolled Levels

       Reduction based on short-term results on these installations:

           Wisconsin Electric Power Co. Valley Power Plant Unit 4 (650,000 Ib/hr) showed short-
       term NOX reduction of 60 to 70 percent from uncontrolled levels of about 1.3 Ib/MMBtu
       at full load with NSR in  the range of 1.0 to 1.5 using the NOXOUT process. These high
       performance levels are not considered feasible with lower NSR, lower baseline levels, and
       larger  utility  boilers.  NOX  was reduced by 50 percent at partial load from  level of
       0.66 Ib/MMBtu (Nalco,  1992).  Public  Service of Colorado, Arapahoe 100-MWe Unit 4
       recent  retrofit showed only 25- to 40-percent reduction (Hunt, 1992).

           German RWE 150-MWe and 75-MWe brown coal boilers where initial combustion-
       controlled NOX was 150 ppm and was reduced to 100 ppm (33 percent reduction) with boiler
       load down to 60 percent  of capacity. Reported capability set in the 30- to 50-percent NOX
       reduction range (Hofmann, 1989).

           Kerr-McGee Argus  Unit No. 26 (710,000 Ib/hr) industrial size boiler.  Initial NOX
       emissions reduced to 225 ppm with further NOX reduction to  165  ppm with urea injection
       (NOXOUT) for a reduction efficiency of SNCR of 27 percent (Comparato, 1989).

       Selective Catalytic Reduction (SCR)—80-Percent NOX Reduction from Uncontrolled Levels
                                         70-Percent NOX Reduction from Controlled Levels

           NOX reduction based on  reported SCR performance  for installations worldwide that
       shows  reductions in the  range of 70 to 80 percent (IEA, 1991).  Performance  has been
       established with long-term monitoring of the more than 200  facilities operated  since the
       early 1980s.  Rarely are NOX reductions reported to be equal to or greater than 90 percent
       for utility boilers. 70- to 80-percent reductions are reported as representative performance
       levels for SCR (Robie, 1991).
                                          D-13
-------
OIL-/GAS-FIRED DRY-BOTTOM BOILERS

Average Baseline NOX Emission Levels (All Boiler Designs)

       0.37 Ib/MMBtu (post-NSPS)
       0.37 Ib/MMBtu (pre-NSPS)

Combustion Controlled NOX Levels (All Boiler Designs)

       0.10 to 0.15 (0.13) Ib/MMBtu (all boilers)

Reported NOX Control Efficiency

       Selective Noncatalytic Reduction (SNCR)—35- to 50-Percent NOX Reduction from
                                             Uncontrolled Levels
                                             25- to 40-Percent NOX Reduction from
                                             Controlled Levels

          NOX reduction potential for combustion controlled boilers based on short-term data
       reported by SCE and SDG&E on the following boilers (Teixeira, 1992; Abele, 1989; Jones,
       1991):

          Morro Bay 330-MWe Unit 3 showed NOX reductions of 30 to 40 percent with either
       aqueous ammonia or urea but with relatively high NH3 slip  (Teixeira, 1992).

          Long Island Lighting Co. (LILCO) Port Jefferson 185-MWe Unit 3 NOX was reduced
       50 to  56 percent from  uncontrolled NOX levels of 0.29 to 0.33 Ib/MMBtu with NSR
       approaching 2.0.  With lower NSR  and lower initial NOX levels (0.22 to 0.25 Ib/MMBtu),
       NOX reductions were in the range of 36 to 48 percent (Teetz, 1992).

          Experience reported by SCE on the retrofit of SNCR on  16 Southern California boilers
       showing 25- to 30-percent NOX reduction from low, combustion-controlled levels (Springer,
       1992). Some specific results include:

          Encina  110-MWe Unit 2 burning natural with minimum NOX levels in the range of 23
       to 38 ppm over the load range of 40 to 100 percent of MCR.

          Etiwanda 320-MWe Unit 3 oil-/gas-fired NOX reduction of 30 percent over entire load
       range, with controlled NOX emission in the range of 25  to 45 ppm.

          SCE Huntington 215-MWe  Unit 2 oil-/gas-fired showed NOX reductions in the range
       of 25 to 40 percent from combustion controlled levels of 120 ppm over 60 to 100 percent
       of boiler load.

       Selective Catalytic Reduction (SCR)—80-Percent NOX Reduction from Uncontrolled Levels
                                         70-Percent NOX Reduction from Controlled Levels

          NOX reduction based on reported SCR performance for installations worldwide that
       shows reductions in the  range of 70 to 80 percent (IEA, 1991).  Performance has been
       established with long-term monitoring of over 200 facilities operated since the early 1980s.
       Rarely are NOX reductions reported to be equal or greater  than 90 percent. .This control

                                         D-14
-------
alternative excludes the CAT-AH process, which has shown 50- to 64-percent NOX reduction
on SCE's  Mandalay Unit 2 (Reese, 1992).  Although still under demonstration, this SCR
process represents a low-cost alternative to more conventional SCR installations targeted
for more than 80-percent NOX reduction.
                                   D-15
-------
-------
                                 APPENDIX E

    SCR INSTALLATIONS ON COAL-FIRED PLANTS IN-USE OR FIRMLY PLANNED
(Source: IEA Coal Research, "NOX Control Installations on Coal-Fired Plants," March 1991, pp.
39-43.)
                                     E-l
-------
PUm
Austria
DQrnrohr
Oiirarohr
Mellach
Unit MWc

1 403
2 320
200
Supplier

Voest-Alpine. Babcock Hitachi KK
Vuesi-Alpine. flabctxk Hiuchi KK
SGP-VA Encrgie. Mitsubishi
SCR
toei

HO
HO
HO
Catalyst
type

TiOj based
TiOi based
TiOi based
Catalyst
form

plate
plate
honeycomb
%NO»
removal

80
80
30
Emissions,
mg/nr1

200
200
200
N/R-

R
R
N
Sun
year

1986
1986
1986
Voiisberg
Denmark
        Heavy Ind
330     Babcock Hitachi KK. Kawasaki    HO
        Heavy Ind
TiOi baaed   honeycomb
130
1990
Aniagervaerkei
Avedoerevaerket
3
1
230
230
not known
Haldor Topsee
TE
HO
not known
TiOj based
not known
plate
80
80
156
156
R
R
1998
1992
Federal Republic of Germany
Altbach Deizisau
Aschaffenburg
Ascha/fenburg
BASF
Ludwigshafen
(Mi tie)
BASF Marl
Bergkamen
Bexbach
Buer
Chariouenburg
Chariouenburg
Charlottcnburg
Cuoo(Herdecke)
Datteln
Oatiein
Oaiieln
Dane In
Datteln
Dormagen. Bayer
OU Sudtmitte
HKWII
OU Stadtmitte
HKWII
Elverlingen
Elverlingen
Ensdorf
Easdorf
Forge
FennelH
RingemI
Flingem II
Fraiikcn 11
Franken 11
Frankfurt Hochst
Frankfurt Hochst
5 HO = high dust;
3
21
31
230



A
1

I
2
3
2
1
2
3
4
3
7
A

B

E3
E4
2
3


1-2
3-t
1
2
1
2
LD-
420
130
130



230
747
730
130
33
33
73
96
48
48
48
48
97
37
70

140

238
238
110
300
350
163
46
67
200
200
44
44
Steuuniiller
Thyssen Engineering
Thyssen Engineering
Knauf Research Cottrell


not known
Energie- und Verfahreasiechnik
Energie- und Vertahrensiechnik
Steinmuller, NSK
Steinmuller
Steinmuller
Siemmutler
Deutsche Babcock
Veba K/aftwerke Ruhr. NSK
Veba Kraitwerke Ruhr. NSK
Veba Kraftwerke Ruhr. NSK
Veba Kraftwerke Ruhr. NSK
Didier
Deutsche Babcock
Thyssen Engineering

Thyssen Engineering

Sieinmiiller
Steinmuller
Knauf Research Cottreil
Knauf Research Cottreil
Uhde. Lenijes
not known
Lentjes. Steinmuller. Hugo Petersen
Lentjes. Steinmuller. Hugo Petersen
Thy^cn Enyiixxnag, KWU
Thyssen Engineering. KWU
Knauf Research Couretl
Knauf Research Cottrell
HO
HO
HO
TE


TE
HO
HO
HO
TE
TE
TE
TE
TE
TE
TE
TE
TE
HO
TE

TE

TE
TE
TE
TE
HO
HO
TE
TE
HO
HO
TE
TE
TiOj based
TiOj based
TiOj based
TiOj based


TiOi bused
TiOj based
TiOi based
TiOj based
TiOj based
TiOi based
TiOi based
TiOj based
TiOj based
TiOi based
TiOi based
TiOz based
FeO* based
TiOz based
TiOj based

TiOi based

TiOi based
TiOj based
TiOi based
TiOz based
TiOz based
TiOi based
TiOj based
TiOi based
TiOj based
TiOz based
TiCh based
TiOj based
honeycomb
plate
plate
honeycomb


honeycomb
honeycomb
honeycomb
plate
honeycomb
honeycomb
honeycomb
not known
honeycomb
honeycomb
honeycomb
honeycomb
not known
honeycomb
honeycomb

honeycomb

honeycomb
honeycomb
honeycomb
honeycomb
plate
plate
honeycomb
honeycomb
plate
plate
not known
not known
69
80
80




73
77
75
35
35
85







82

85

36









>78

200
200
200
200


200
200
200
200
200
200
200
200
200
200
200
200
200
200
200

200

200
200
200
<200
200
200
200
200
200
200
200
200
R
R
R
R



R

R
R
R
R
N
R
R
R
R

R
R

R

R
R

R
R
R
R
R
R
R
R
R
1985
1990
1990
1990


1989
1989
1989
1985
1990
1990
1990
1990
1989
1989
1989
1989
1989
1989
1989

1989

1989
1989
1989
1990
1990
1990
1990
1990
1990
1990
1991
1991
low dust: TE = tail end
• N/R » New or Retrofit
                                                      E-3
-------
riant
Frankfort West
Frankfurt West
Garath

Ha/en (Bremen)
Ha/en (Bremen)
Hafen (Hamburg)
Hannover-Stficken
Hannover-Sttfcken
Hastedt (Bremen)
Heilbronn
Heilbronn
Heilbronn
Heilbronn
Heilbronn
Hcme
Heme
Hcmc
Heyden
IbocnbOrcn
Karlsruhe West
unit
2
3


5
6
2
1
2
15
3
4
5
6
7
1
2
3
4
B
3
Kellermann(Liinen)K10
KielOst
Knepper
Kraftwerk Hals I
Knftwerk HO Is I
Kraftwerk HUls II
Lausward
Lausward
Lausward
Lausward
Mainz
Mainz
Mannheim
Marmheim
Mannheim
Mannheim
Mehi uiti
Mine
MOnster (Stuttgart)
Munster (Stuttgart)
MQnster (Stuttgart)
Nord (MOnchen)
Oberhavel
Oberhavel
Ost(Lunen)
Porta WF Velthetm
Porta WF Velthetm

C
4
5
3
A
B
C
D
2
3
3
4
IY1 T»C
90
90
20

150
300
85
130
130
130
110
110
125
125
750
15(1
150
300
800
770
64
150
350
375
125
131
84
127
127
127
127
100
100
220
220
7(KIS) 473
8(K19)480
3
1
12
15
25
2
1
2
Kll
1
2
Porta WF Veltheim 3
Reuter
Reuter
Reuter
1
2
C
f HD = high dust: LD «
700
87
40
40
67
362
100
100
350
100
100
330
50
50
130
low dust;
«ju|jyirci
Lentjes
Lentjes
Steinmuller. Hugo Petersen

B • j ,. j ._ L ;
cnergie- und Verfahrenstechnik
Energie- und Verfahrenstecnnik
Sieinmuller
Uhde. Lent jes
Uhde. Lenijes
Energie- und Verfahrensiechnik
Deutsche Babcock
Deuuche Babcock
Deuische Babcock
Deutsche Babcock
Energie- und Verfahrenstechnik
Dixie Lcmjcs
Uhde. Lenijes
Uhde. Lenijes
Uhde. Lenijes
Uhde. Lentjes
Krupp (Coppers
Lentjes
Uhde. Lentjes
OV.A
HD
HD
TE

HD
HD
TE
TE
TE
HD
TE
TE
TE
TE
HD
TE
TE
TE
HD
TE
TE
TE
HD
Uhde. Lentjes. Thyssen Engineering HD
Knauf Research Coitrell
Knauf Research Coitrell
Thyssen Engineering
Lentjes. Steinmiiller. Hugo Petersen
Lenijes. Sleinmuller. Hugo Petersen
Lentjes. Steinmuller; Hugo Petersen
Lenijes. Steinmuller. Hugo Petersen
Deutsche Babcock
Deutsche Babcock
Deutsche Babcock
Deutsche Babcock
Energie- und Verfahrenstechnik
Energie- und Verfahrenstechnik
Uhde. Lentjes. Hitachi
Knauf Research Cottrell
Energie- urv) Verfahrenstechnik
Energie- und Verfahrenstechnik
Energie- und Verfahrenstechnik
Deuische Babcock
Sieinmuller
Steinmuller
Lenijes
Deutsche Babcock
Deutsche B.tbcock
Deuische Babcock
Lentjes
Lenijes
Lenijes
TE » tail end
TE
TE
TE
TE
TE
TE
TE
TE
TE
TE
TE
HD
HD
HD
TE
HD
HD
HD
HD
HD
HD
TE
HD
HD
HD
TE
TE
TE

•m
TiCh based
TiCh based
activated
lignite coke
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TrCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiOihasctl
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiCh based
TiOj based
TiCh based
TiCh based
TiOz based
TiO7 based
TiCh based
TiOz based
TiCh based
TiOz based
TiOi based
TiCh based
TiCh based
TiCh based
TiCh based

form
not known
not known
pellets

plate
plate
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honcycnrnh
honeycomb
honeycomb
not known
honeycomb

honeycomb
honeycomb
honeycomb
plate
honeycomb
H ___„.__ i_
oneycomo
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
plate
not known
honeycomb
honeycomb
honeycomb
plate
not known
not known
honeycomb
plate
plate
plate
not known
not known
not known

removal mg/irr3
80
80


85
85
75


70
>80
>80
>80
>80
>80
>xn
>80
>80
75


>80
80
90




80
80
80




75
85
75

HO
80
72



>80
82






200
200
200

200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
<200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
100
200
200
200
200
200
200
200
200
200

N
*
R



N
R
R
N
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
R
N
R
R
R
R
R
N
R
R
R
R
R
R
R
R
R

year
1989
1989
1987

1990
1990
1987
1989
1989
1989
1990
1990
1990
1990
1986
1989
1989
1989
1988
1988
1988
1989
1989
1986
1990
1991
1990
1989
1989
1989
1989
1988
1988
1988
1988
1988
1992
1988
1988
1986
1986
1986
1992
1990
1990
1989
1989
1989
1989
1990
1990
1990

E-4
• N/R = New or Retrofit
-------
                                                          loci   type
                   form
remuviU mg/nr1
ReuierWest

ReuierWest

Rheinhafen
(Karlsruhe)
Rudow
Rudow
Rudow
Riliselsheim,
Adam Opel AC
ROkselshcim,
Adam Opel AC
Sandreuih
Sandreuih
Sandreuih
Scholven
Scholven
Scholven
Scholven
Scholven
Schwandorf
Schwandorf
Schwandorf
Shamrock
Shamrock
Shamrock
Shamrock
Siersdorl
Staudingcr
Suudinger
Siaudinger
Suudinger
Tie/stack
Ordingen. Bayer
Ordingen. Bayer
Voerde
Voerde
Volklingen
Walheim
Walheim
Walsum
WiUum
Wedel
Wedel
Weiherll
Weiher II
Weiiicrlll
Weme
Wesi Voerde
Wesi Voerdc
Wesi (VW)
Wesi(VW)
Westerholi
Wesierholt
Wesitalen
Westfalen
i HD * high dusi;
O

E

7

1
2
3
2

3

1
2
3
B
C
O
E
F
B
C
0
1
2
3
4

1
2
3
5
t
I
2
A
B

1
2
7
9
I
2
1
2

K
I
2
1
2
I
2
A
B
LD =
300

300

550

38
38
100
20

20

35
35
35
370
370
370
370
740
100
100
300
83
83
39
39
1X0
250
250
300
500
243
85
55
707
707
230
105
150
150
410
107
107
150
150
707
750
350
350
140
140
150
150
176
176
a lOW dust
Deutsche Babcock. Balcke.
Dttrr. Borsig
Deuische Babcock. Balcke.
Diirr. Borsig
Sieinmuller

Deuische Babcock
Deutsche Babcock
Deuische Babcock
Lurgi

Lurgi

HO

HO

HO

HO
TE
TE
TE

TE

Unde. Werksgruppe TVT Munchen TE
Unde. Werksgruppe TVT Munchen TE
Linde. Werksgruppe TVT Munchen TE
Veba Krafiwerke Ruhr. KWU
Veba Kraftwerke Ruhr. KWU
Veba Kraftwerke Ruhr. KWH
Veba Kraftwerke Ruhr. KWU
BASF
Uhde. Lenijes
Uhde. Lenijes
Uhde. Lenijes
Veba Krafiwerke Ruhr. NSK
Veba Kraftwerke Ruhr. NSK
Veba Krafiwerke Ruhr. NSK
Veba Krafiwerke Ruhr. NSK
Lunijcs
Uhde, Lenijes
Uhde. Lenijes
Uhde. Lenijes
Uhde Lenijes
Sieinmuller
Sieinmuller
Sieinmuller
Knauf Research Conrell
Knauf Research Conrell
Deuucne Babcock
Sieinmuller
Sieinmuller
Uhde. Lenijes
Uhde. Lenijes
Sieinmuller
Sieinmuller
not known
not known
Sleinniuller
Sieinmuiler
Uhde. Lenijes
Uhde. Lxntjci
Uhde. Lenijes
Uhde, Lunljc*
Veba Kraliwerke Ruhr. BASF
Veba Kraftwerke Ruhr, BASF
Sleiiuniiller
Sicmmiiilcr
TEatailend
HO
HO
HO
HO
HO
HO
HO
HO
TE
TE
TE
TE
TE
HO
HO
HO
HO

TE
TE
HO
HO
HO
HO
HD
LO
HO
HO
HD
TE
TE
HD
TE
TE
TE
TE
TE
TE
TE
TE
TE

TiO} based

TiOj based

TiO: based

TiO: based
TiO: based
TtOj based
TiO: based

TiO: based

zeolite
zeolite
zeolite
T5O: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: ha.sed
TiO> based
TiO: based
FeO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: based
TiO: ha\eil
TiOi based
TiO: based
TiO: h:Lsol
TiOj based

honeycomb

honeycomb

honeycomb

plate
honeycomb
not known
honeycomb

honeycomb

pellets
pellets
pellets
plate
plate
plate
plate
honeycomb
plate
plate
plate
honeycomb
honeycomb
honeycomb
honeycomb
hiNieycoiiib
not known
plate
plate
not known
not known
honeycomb
honeycomb
honeycomb
honeycomb
plate
not known
honeycomb
plate
plate
honeycomb
honeycomb
not known
not known
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb










85

85









70
70
70












80
80

79
84
>«0
70
80
80




>80
>SO







200

2(M

200

200
200
200
200

200

200
200
200
200
200
200
200
200
£200
£200
£200
200
200
200
200
2(X)
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
200
2(X)
200
200
2
-------
                                                           loe«   type
form       removal mg/nr1
Westfalen C
Wilhelmshaven

Tolling 5
Leiningerwerk
320
750

450

Sleinmtiller
Uhde. Lentjes

Uhde. Lent jes

TE
HD

HD

TiOj based
FeO7 based
(50%)
TiOi based

honeycomb
honeycomb

plate 70

200
200

200

R
R

R

1991
19*8

1988

Finland
560     Tampella
HD    TiOj hosed    plaie
                                                                                         80
                   <200
                                                                                                                1993
Italy
Brindisi Sud
Brindisi Sud
Brindisi Sud
Brindisi Sud
Fiume Santo
Fiume Santo
Fustna
Fusina
Fusina
Fusina
Gioia Tauro
Gioia Tauro
Gioia Tauro
Gioia Tauro
La Spezia
LaSpezia
LaSpezia
LaSpezia
San Ftlippo Dei
Mela
San Filippo Del
Mela
Sulcis
Sulcis
Sulcis
Tavazzano
Tavazzano
Vado Ligure
Vado Ligure
Vado Ligure
Vado Ligure
Japan
Chiba Factory
Daicel Chemical
Co. Aboshi
Factory
Hekinan
Hekinan
Himeji No 1
Idemitsu Kosan
Engineering Co
[demitsu Kosan
Petroleum. Hyogo
Refinery
1
2
3
4
3
4
1
2
3
4
1
2
3
4
1
2
3
4
5

6

I
2
3
3
4
1
2
3
4

2



2
3
I
A




660
660
660
660
320
320
160
160
320
.320
660
660
660
660
320
320
600
600
320

320

240
240
240
320
320
320
320
320
320

90
100


700
700
33
50

40


not known
not known
not known
not known
not known
not known
riot known
not known
not known
not known
not known
not known
not known
not known
not known
not known
not known
not known
not known

not known

not known
not known
not known
not known
not known
not known
not known
not known
not known

Mitsubishi Heavy Industries
Mitsubishi Heavy Industries


Mitsubishi Heavy Industries
Ishikawajima Harima Heavy Ind
Ishikawajima Hanrna Heavy (nd
Kawasaki Heavy Industries

Babcock Hitachi KK


HD
HD
HD
HD
HD
HD
HD
HD
HD
HD
HD
HD
HD
HD
HD
HD
HD
HD
HD

HD

HD
HD
HD
HD
HD
HD
HD
HD
HD






HD



HD


not known
not known
not known
not known
not known
not known
not known
not known
not known
not known
not known
not known'
not known
not known
not known
not known
not known
not known
not known

not known

not known
not known
not known
not known
not known
not known
not known
not known
not known

TiO: based
TiOz based


TiOj based
TiOi based
TiOj based
TiOj based

TiOi based


nm known
not known
not known
not known
not known
not known
not known
not known
not known
not known
not known
not known
not known
not known
not known
not known
not known
not known
not known

not known

not known
not known
not known
not known
not known
nn< known
not known
not known
not known

honeycomb
honeycomb


honeycomb
honeycomb
honeycomb
not known

plate


80
80
80
80
80
80
80
80
80
80
80
80
80
80
80
SO
80
80
80

80

80
80
80
80
80
80
80
80
80





80
80
75
>55

60


<2
-------

Matsuura (Kyushu I
Electric Power)
Maisuura (EPOQ 1
Maisuura 2
Minato 1
Mizushima 1
Miztishima 2
Nakoso 8
Nakoso 9
Saijo 1
Saijo 2
Sakata 1
Sakata 2
Sendai 2
Sendai 3
Shimonoseki 1
Shin Onoda 1
Shin Onoda 2
Shin Ube 1
Shin Ube 2
Shin Ube 3
Sumitomo 2
Chemical Co.
Chibu Factory
Sumitomo Metal 1
Industries.
Kokura Factory
Takeda Chemical
Ind. Hikari Factory
Takehara 1

Takehara 3
Tomaioazuma 1
Toray Industries 4
Inc. Tokai Factory
Toyama Kyodo 1
Shinko
Toyama Kyodo 2
Shinko
Tsuruga i
Ube Industries
Yokosuka 1
Yokosuka 2
Netherlands
Gelderiand 12
Sweden
Vasteris 1
Vasteras 2

700

1000
1000
136
123
156
600
600
156
250
350
350
175
175
175
500
500
75
75
156
70


20


30

250

700
350
30

200

200

500

265
265

125

40
40
--ft"-"
Mitsubishi Heavy Industries

Babcock Hitachi KK
not known
Mitsubishi Heavy Industries
Babcock Hitachi KK
Babcock Hitachi KK
Mitsubishi Heavy Industries
Ishikawajima Harima Heavy Ind
Mitsubishi Heavy Industries
Ishikawajima Haruna Heavy Ind
Mitsubishi Heavy Industries
Mitsubishi Heavy Industries
Babcock Hitachi KK
Babcock Hitachi KK
Mitsubishi Heavy Industries
(shikawajima Harima Heavy Ind
Ishikawajima Harima Heavy liid
Mitsubishi Heavy Industries
Mitsubishi Heavy Industries
Mitsubishi Heavy industries
Mitsubishi Heavy Industries


Mitsubishi Heavy Industries


Mitsubishi Heavy Industries

Babcock Hitachi KK.
Kawasaki Heavy Ind
Babcock Hitachi KK
Babcock Hitachi KK
Ishikawajima Harima Heavy Ind

Babcock Hitachi KK

Babcock Hitachi KK

Mitsubishi Heavy Industries
Kawasaki Heavy Industries
Mitsubishi Heavy Industries
Mitsubishi Heavy Industries

ESTS-

Fliikt
Flakt
«0^»«*
loej
HO

LO
LO
HO
HO
HO
HO
HO
HO
HO
HO
HO
HO
HO
HO
HO
HO
HO
HO
HO








LO

LD
LO


HO

HO



HO
HO

HO

HO
HO
N*~* •«/•**
type
TIOj based

TiOj based
TiCn based
TiOj based
TiOi based
TO? based
TiOz based
TiOj based
TiO? based
TiO: based
TiOi based
TiOj based
TiOi based
TiOi based
TiO: based
TiO: based
TiOi based
TiOi based
TiOi based
TiOj based
TiOj based


TiO: based


TiOi based

TiO: based

TiC" based
TiOz based
TiOj based

TiOz based

TiCn based

TiOi based
TiOi based
TiOz based
TiOj based

TiOz based

TiO? based
TiO: based
^ *\m*j**
fono
honeycomb

plate
plate
honeycomb
plate
plate
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
plate
plate
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb
honeycomb


honeycomb


honeycomb

honeycomb.
plate
plate
plate
not known

plate

plate

honeycomb
not known
honeycomb
honeycomb

honeycomb

plate
plate
removal mg/m3


80 123

33
65
65
60
60
65
65
80
35
60
60
50
80
80
65
65
65
80


84


25

80 144

30 123
90


60

60


38
70
70

80 100

34 280
34 280
N

N
N
R
ft
R
N
N
R
R
R
N
R
R
R
N
N
R
R
R








R

N
N


R

R



R
R

R

R
R
*?«*•• I
year
1989

1990
1999
1983
1984
1984
1983
1983
1983
1984
1984
1984
1983
1983
1981
1986
1987
1982
1981
1981
1985


1985


1986

1981

1983
1980
1988

1984

1984

1990
1982
1985
1985

1987

1991
1991
} HO » high dust; LO * low dust; TE » tail end
  N/R a New or Retrofit
                                                         P-7
-------
-------
                                       APPENDIX F
                                  NOX CONTROL COSTS
                           PC-FIRED AND CYCLONE BOILERS
       The enclosed spreadsheets include cost estimates for the following test cases:

       1.   Overfire air (OFA) for wall-fired boilers
       2.   Low-NOx burners (LNB) for wall-fired boilers
       3.   Low-NOx burners (LNB) for tangential-fired boilers
       4.   Low-NOx burners (LNB) and overfire air (OFA) for wall-fired boilers
       5.   Low-NOx burners (LNB) and overfire air (OFA) for tangential-fired boilers
       6.   Natural gas reburn (NGR) for wall-fired boilers
       7.   Natural gas reburn (NGR) for tangential-fired boilers
       8.   Natural gas reburn (NGR) for cyclone boilers
       9.   Selective noncatalytic reduction (SNCR) for wall-fired boilers (uncontrolled)
       10.  Selective noncatalytic reduction (SNCR) for wall-fired boilers (controlled)
       11.  Selective noncatalytic reduction (SNCR) for tangential-fired boilers (uncontrolled)
       12.  Selective noncatalytic reduction (SNCR) for tangential-fired boilers (controlled)
       13.  Selective catalytic reduction  (SCR) for wall-fired boilers (uncontrolled)—cold side
       14.  Selective catalytic reduction  (SCR) for wall-fired boilers (controlled)—cold side
       15.  Selective catalytic reduction (SCR) for tangential-fired boilers (uncontrolled)—cold side
       16.  Selective catalytic reduction  (SCR) for tangential-fired boilers (controlled)—cold side
       17.  Selective catalytic reduction  (SCR) for wall-fired boilers (controlled)—hot side
       18.  Selective catalytic reduction  (SCR) for tangential-fired boilers (controlled)—hot side

       Uncontrolled NOX is taken as average of pre-NSPS current baseline emission levels (see
Table 3-4). For wall-fired retrofit cost cases, the average emission levels for wall- and opposed-fired
boilers are used. For controlled NOX emission levels, both the high and low estimates provided in
Tables 1-1 and 5-5 for  pre-NSPS boilers are used to illustrate the sensitivity of cost effectiveness
to control efficiency. For FGT controls, the upper level of the NOX range estimated for LNB-based
controls is used as the baseline from which further NOX reductions are achieved.  For comparison,
cost cases for FGT controls on uncontrolled units are also presented.
                                            F-l
-------
-------
NOx CONTROL COSTS - COAL BOILERS clwofa.wkl
OVtRrlKt AIR - PC WALL-rlRtu UNI la
(Sorge. 1992) Case 1 | SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV {Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (% wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (8STP:68F: 14.7psia)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):

-ourners
-Ducting
-Fan Upgrade/Replace
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Air Maator
n i r neater
-Construct i on/ Instal 1 at i on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) =
-GENERAL FACILITIES (GF) 10% of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) 10% of PCC
-PROJECT CONTINGENCY (% of PCC+EHOF+Proc) 30%
TCTAL PLANT COSTS (TPC) (1991$/kU) =
-ESCALATION (0%)
-AFDC (0%)
TCTAL PLANT INVESTMENT (1991$/kW) »
-ROYALTY ALLOWANCE 0.0% of PCC
-PREPROOUCTION COSTS 2% of TPC
-INVENTORY CAPITAL (0%)
TCTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) =
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (J/kW-yr)
-MAINTENANCE COSTS (MC) (S/kW-yr) 2% of TPC
-ADMIN/SUPPORT LABOR ($/kU-yr) 30% of OL+0.4MC
FIXED 0 4 M COSTS ($/kW-yr) =
VARIABLE 0 & M COSTS (mi lls/kW-hr) =
= 3 333 ======33333= ========= ==333===== 33333333=== ==3S
EFFECT OF CAPACITY
100 200 | 300 400 660

30
20
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.5%

12080
0.0
0
0
0.0
0.117

















15.74
1.57
1.57
1.57
5.67
26
0
0
26
0.00
0.52
0
27


0.523
0.063
0.38
0.036
33=3333

30
20
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.5%

24159
0.0
0
0
0.0
0.117

















11.93
1.19
1.19
1.19
4.30
20
0
0
20
0.00
0.40
0
20


0.396
0.048
0.29
0.027
========

30
20
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.5%

36239
0.0
0
0
0.0
0.117

















10.14
1.01
1.01
1.01
3.65
17
0
0
17
0.00
0.34
0
17


0.337
0.040
0.25
0.023
========

30
20
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.5%

48318
0.0
0
0
0.0
0.117

















9.04
0.90
0.90
0.90
3.26
15
0
0
15
0.00
0.30
0
15


0.300
0.036
0.22
0.021
=3======

30
20
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.5%

79725
0.0
0
0
0.0
0.117

















7.40
0.74
0.74
0.74
2.66
12
0
0
12
0.00
0.25
0
13


0.246
0.029
0.18
0.017
====33=3
EFFECT OF C.F.
200 200

30
20
10.0%
0.40
13080
N/A
N/A
N/A

10670
0.5%

24159
0.0
0
0
0.0
0.117

















11.93
1.19
1.19
1.19
4.30
20
0
0
20
0 00
0.40
0
20


0.396
0 048
0 18
0.076
= 3 = = = = s:s

30
20
10.0%
0.82
13080
N/A
N/A
N/A

10670
0.5%

24159
0.0
0
0
0.0
0.117

















11.93
1.19
1.19
1.19
4.30
20
0
0
20
0.00
0.40
0
20


0.396
0.048
0.35
0.011
========
EFFECT OF AGE
200 | 200

20
30
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.5%

24159
0.0
0
0
0.0
0.106

















11.93
1.19
1.19
1 19
4.30
20
0
0
20
0.00
0.40
0
20


0 396
0 048
0.29
0.027

40
10
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.5%

24159
0.0
0
0
0.0
0.163

















11.93
1 19
1.19
1.19
4.30
20
0
0
20
0 00
0.40
a
20


0 336
0 . 048
0 29
0 327
=333333= ===3=3=3
F-3
-------
NOx CONTROL COSTS - COAL BOILERS clwofa.wkl
UVtKrlKt AIR - rt WALL-riKtU UNI 11 ------ — ...
(Sorge. 1992) Case 1 | SIZE (HW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft"3/yp)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mllls/kW-hr)
-UREA (m1lls/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mllls/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mi lls/kV-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kU-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) -
LEVELIZED BUSBAR COST (mills/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOUER NOx REDUCTION (tons/yp)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) =
UNIT
APPLICABLE UNIT PRICING COST
COAL (J/ton) 45.84
OIL ($/bbl) 22.85
GAS (S/1000 ff 3) 2.51
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST ($/f.f 3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY
100 | 200

0
0
0
1161

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.067
0.036
0.000
0.093
3.13
0.75

0.95
0.70
759
559
0.80
456
932

0
0
0
2322

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.051
0.027
0.000
0.093
2.37
0.59

0.95
0.70
1519
441
0.80
911
735
300 | 400 | 660

0
0
0
3484

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.043
0.023
0.000
0.093
2.02
0.51

0.95
0.70
2278
385
0.80
1367
642

0
0
0
4645

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.038
0.021
0.000
0.093
1.80
0.47

0.95
0.70
3038
351
0.80
1823
585

0
0
0
7664

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.031
0.017
0.000
0.093
1.47
0.40

0.95
0.70
5012
300
0.80
3007
500
EFFECT OF C.F.
	 -._.- 	
200 200

0
0
0
1429

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.051
0.076
0.000
0.093
2.37
0.90

0.95
0.70
935
673
0.80
561
1121

0
0
0
2930

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.051
0.011
0.000
0.093
2.37
0.49

0.95
0.70
1916
364
0.80
1150
607
EFFECT OF AGE
200 200

0
0
0
2322

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

O.Q51
0.027
0.000
0.093
2.14
0.55

0.95
0.70
1519
411
0.80
911
684

0 i
0 '
0
2322

0

o.ooo ;
o.ooo '
0.000
0.000
0.000
O.QOO

0.093

0.000

0 051
0,027
o.ooo ;
0.093
3.29 ;
0.75

0.95
0.70
1519
561
0.80
911
936


Electric Power Monthly. March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991
Robie. 1991
8P Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-4
-------
NOx CONTROL COSTS - COAL BOILERS cZwlnb.wkl
LOW NOx BURNERS - PC WALL-FIRED UNITS 	
(Figure 6-4) Case 2 | SIZE (HW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft*3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
~Burners
-Ducting
-Fan Upgrade/Rep 1 ace
-Structural
-Reagent Storage & 01 strl but 1 on
-OeNOx Reactor/Catalyst
-Control System
-Fl ue Gas Heat Exchanger
-Ai r Heater
-Construct i on/ 1 nstal 1 at 1 on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) »
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) I OX of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 30%
TOTAL PLANT COSTS (TPC) (1991JAW) »
-ESCALATION (OX)
-AFOC (OX)
TOTAL PLANT INVESTMENT (1991J/kW) -
-ROYALTY ALLOWANCE O.OX of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991J/kW) »
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) (J/kW-yr) 2% of TPC
-AOMIN/SUPPORT LABOR (J/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS ($/kW-yr) »
VARIABLE 0 & M COSTS (mi lls/kW-hr) »

EFFECT OF CAPACITY
100 | 200 | 300 400 | 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.2SX

12080
0.0
0
0
0.0
0.117












15.42
1.54
1.54
1.54
5.55
26
0
0
26
0.00
0.51
0
26


0.512
0.061
0.37
0.035


30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.25X

24159
0.0
0
0
0.0
0.117












11.69
1.17
1.17
1.17
4.21
19
0
0
19
O.dO
0.39
0
20


0.388
0.047
0.28
0.027


30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.25X

36239
0.0
0
0
0.0
0.117












9.94
0.99
0.99
0.99
3.58
16
0
0
16
0.00
0.33
0
17


0.330
0.040
0.24
0.023


30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.25X

48318
0.0
0
0
0.0
0.117












8.86
0.89
0.89
0.89
3.19
15
0
0
15
0.00
0.29
0
15


0.294
0.035
0.21
0.020


30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.25X

79725
0.0
0
0
0.0
0.117












7.25
0.73
0.73
0.73
2.61
12
0
0
12
0.00
0.24
0
12


0.241
0.029
0.18
0.017

EFFECT OF C.F.
200 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
0.25%

24159
0.0
0
0
0.0
0.117












11.69
1.17
1.17
1.17
4.21
19
0
0
19
Q.OO
0.39
0
20


0.388
0.047
0.17
0.074


30
20
10.0%
0.82
13080
N/A
N/A
N/A

10670
0.25%

24159
0.0
0
0
0.0
0.117












11.69
1.17
1.17
1.17
4.21
19
0
0
19
0 00
0.39
0
20


0.338
0.047
0.36
0.011

EFFECT OF AGE .
200 | 200

20
30
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.25%

24159
0.0
0
0
0.0
0.106












11.69
1.17
1.17
1.17
4.21
19
0
0
19
0.00
0 39
0
20


0.388
0.047
0 28
0 027

40 •
10 !
10.0%
0.55 ,
13080 i
N/A i
N/A !
N/A '

10670
0.25KJ

24159 •
O.Q
0
0
0.0
0.163 ;












11.69 '
1.17
1.17 '
1.17 ,'
4 21
19
0
Q
19
0 30
Q 39
0
20


0 338
0 047
0.23
0 027

F-5
-------
NOx CONTROL COSTS - COAL BOILERS c2wlnb.wkl


(Figure 6-4) Case 2 | SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MV-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kU-hr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (m1l1s/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) =•
LEVELIZED BUSBAR COST (mills/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (J/1000 ft" 3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY

	
100

0
0
0
581

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.065
0.035
0.000
0.047
3.07
0.69

0.95
0.45
1519
257
0.60
1063
367
200

0
0
0
1161

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.050
0.027
0.000
0.047
2.32
0.53

0.95
0.45
3038
199
0.60
2126
285
300 400 660

0
0
0
1742

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.042
0.023
0.000
0.047
1.98
0.46

0.95
0.45
4557
172
0.60
3190
246

0
0
0
2322

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.038
0.020
0.000
0.047
1.76
0.41

0.95
0.45
6075
155
0.60
4253
222

0
0
0
3832

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.031
0.017
0.000
0.047
1.44
0.35

0.95
0.45
10025
130
0.60
7017
136
EFFECT OF C.F.

	
200 200

0
0
0
715

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.050
0.074
0.000
0.047
2.32
0.83

0.95
0.45
1869
313
0.60
1309
447

0
0
0
1465

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.050
0.011
0.000
0.047
2.32
0.43

0.95
0.45
3832
162
0.60
2683
231
EFFECT OF AGE


200 | 200

0
0
0
1161

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.050
0.027
0.000
0.047
2.10
0.49

0.95
0.45
3038
184
0.60
2126
263

0
0
0
1161

0

0.000
0.000
0.000
0.000
O.OOQ
O.OQO

0.047

0.000

0.050
0.027
0.000
0.047
3.22
0.69

0.95
0 45
3038
258
0.60
2126
359


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991 .
Robie. 1991
Robie. 1991
Robie. 1991
F-6
-------
NOx CONTROL COSTS - COAL BOILERS c3t1nb.wkl

LOW NOX BURNERS - PC lANutNl lAL-rlKtU -----------
(Manaker. 1992) Case 3 | SIZE (HU)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOURATE (9STP:68F:14.7ps1a)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVEL I ZAT I ON (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
•Burners
-Ducting
-Fan Upgrade/Replace
— C * HI i/* Vi if* » 1
j t rue tura i
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Air Moator
M i r nca icr
-Const ruct i on/ 1 nsta 1 1 at 1 on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kU) -
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 30X
T3TAL PLANT COSTS (TPC) (199U/kW) »
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) -
-ROYALTY ALLOWANCE O.OX of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (199U/kW) »
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (J/kW-yr)
-MAINTENANCE COSTS (MC) (J/kV-yr) 2X of TPC
-AOMIN/SUPPORT LABOR (J/kW-yr) 30X of OL+0.4MC
FIXED 0 i M COSTS (J/kW-yr) =
VARIABLE 0 & M COSTS (mi 1 Is/kW-hr) »
EFFECT OF CAPACITY

	 	 	 	 	
	
100 150 200 300 375

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.25X

12080
0.0
0
0
0.0
0.117

















18.93
1.89
1.89
1.89
6.82
31
0
0
31
0.00
0.63
0
32


0.629
0.075
0.46
0.043

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.25X

18119
0.0
0
0
0.0
0.117

















16.10
1.61
1.61
1.61
5.79
27
0
0
27
0.00
0.53
0
27


0.534
0.064
0.39
0.037

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.25X

24159
0.0
0
0
0.0
0.117

















14.35
1.43
1.43
1.43
5.16
24
0
0
24
0.00
0.48
0
24


0.476
O.OS7
0.35
0.033

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.25X

36239
0.0
0
0
0.0
0.117

















12.20
1.22
1.22
1.22
4.39
20
0
0
20
0.00
0.41
0
21


0.405
0.049
0.29
0.028

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.25X

45298
0.0
0
0
0.0
0.117

















11.16
1.12
1.12
1.12
4.02
19
0
0
19
0.00
0.37
0
19


0.370
0.044
0.27
0 026
EFFECT OF C.F.
	

200 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
0.25X

24159
0.0
0
0
0.0
0.117

















14.35
1.43
1.43
1.43
5.16
24
0
0
24
0.00
0.48
0
24


0.476
0.057
0.21
0.091

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
0.25X

24159
0.0
0
0
0.0
0.117

















14.35
1.43
1.43
1.43
5.16
24
0
0
24
0.00
0.48
0
24


0 475
0 057
0.44
0 013
EFFECT OF AGE


200 | 200

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.25X

24159
0.0
0
0
0.0
0.106

















14.35
1.43
1.43
1.43
5.16
24
0
0
24
0.00
0.48
0
24


0.475
0.057
0.35
0.033

40
10
10.0%
0.55
13080
N/A
N/A
N/A

10670
0.25%
|
24159 '
0.0
0 t
0
O.Q :
0.153

















14.35
1 43
1.43
1.43
5.16
24
0
a :
24
0.00
0 48
0
24


0 475
0 G57
0.35
0.033
F-7
-------
NOx CONTROL COSTS - COAL BOILERS c3t1nb.wkl


(Hanaker. 1992) Case 3 | SIZE (HU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (nrills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mllls/kW-hr)
-GAS (mllls/kW-hr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 i M (mllls/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (m1lls/kW-Hr)
LEVELIZED CAPITAL CHARGES (J/kW-yr) »
LEVELIZED BUSBAR COST (mills/kU-hr) «
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) •
UNIT
APPLICABLE UNIT PRICING COST
COAL (J/ton) 45.84
OIL ($/bbl) 22.85
GAS (S/1000 ft* 3) 2.61
AMMONIA ($/ton) 145.00
UREA (J/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST ($/ft'3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

	
---------------------------- — ------
100

0
0
0
581

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.080
0.043
0.000
0.047
3.77
0.83

0.60
0.40
60S
779
0.45
456
1039
150 200

0
0
0
871

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.068
0.037
0.000
0.047
3.20
0.71

0.60
0.40
911
669
0.45
683
892

0
0
0
1161

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.061
0.033
0.000
0.047
2.85
0.64

0.60
0.40
1215
601
0.45
911
802
300 1 375

0
0
0
1742

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.052
0.028
0.000
0.047
2.43
0.55

0.60
0.40
1823
518
0.45
1367
690

0
0
0
2177

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.047
0.026
0.000
0.047
2.22
0.51

0.60
0.40
2278
477
0.45
1709
636
EFFECT OF C.F.


200

0
0
0
715

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.061
0.091
0.000
0.047
2.85
1.01

0.60
0.40
748
950
0.45
561
1266
200

0
0
0
1465

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.061
0.013
0.000
0.047
2.85
0.52

0.60
0.40
1533
486
0.45
1150
648
EFFECT OF AGE


200 200

0
0
0
1161

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

0.000

0.061
0.033
0.000
0.047
2.58
0.59

0.60
0.40
1215
556
0.45
911
741

0
0
0
1161

0

0.000
0.000
0.000
0.000
0.000
0.000

0.047

O.QOO

0.061
0.033
0.000
0.047
3.95
Q.83

0.60
0.40
1215
782
0.45
911
1043


Electric Power Monthly, March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991
Robie. 1991
8P Chemical, 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-8
-------
NOx CONTROL COSTS - COAL BOILERS c4wlnof.wkl

LNB * UFA - PC WALL-rlRcO UNI 15 ..—--—--
(Sorge. 1992) Case 4 | SIZE (MU)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (flSTP:68F:14.7psia)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft*3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Ducting
-Fan Upgrade/Replace
_C f> r*t ir* 1 1 1 v*a 1
j true Lura i
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Ai r Heater
n i i ncd icr
-Const ruct i on/ Insta I lation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) »
-GENERAL FACILITIES (GF) IOX of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) IOX of PCC
-PROCESS CONTINGENCY (Proc) IOX of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 30X
TOTAL PLANT COSTS (TPC) (1991$/kV) *
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) =
-ROYALTY ALLOWANCE O.OX of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) =
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (J/kW-yr)
-MAINTENANCE COSTS (MC) (J/kW-yr) 2% of TPC
-ADMIN/SUPPORT LABOR ($/kW-yr) 30% of OL+0.4MC
FIXED 0 & M COSTS (S/kW-yr) -
VARIABLE 0 & M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY


100 200 300 | 400 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.5X

12080
0.0
0
0
0.0
0.117















31.48
3.15
3.15
3.15
11.33
52
0
0
52
0.00
1.05
0
53


1.045
0.125
0.76
0.072

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.5X

24159
0.0
0
0
0.0
0.117















23.86
2.39
2.39
2.39
8.59
40
0
0
40
0.00
0.79
0
40


0.792
0.095
0.58
0.055

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.5X

36239
0.0
0
0
0.0
0.117















20.28
2.03
2.03
2.03
7.30
34
0
0
34
0.00
0.67
0
34


0.673
0.081
0.49
0.046

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.5%

48318
Q.Q
0
0
0.0
0.117















18.08
1.81
1.81
1.81
6.51
30
Q
0
30
0.00
0.60
0
31


0.600
0.072
0.44
0.041

30
20
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.5%

79725
0.0
0
0
0.0
0.117















14.80
1.48
1.48
1.48
5.33
25
0
0
25
0.00
0.49
0
25


- 0.491
0.059
0.36
0.034
EFFECT OF C.F.


200 200

30
20
10.0%
0.40
13080
N/A
N/A
N/A

10670
0.5%

24159
O.Q
0
0
0.0
0.117















23.86
2.39
2.39
2.39
8.59
40
0
0
40
0.00
0.79
0
40


0.792
0 095
Q.35
0.152

30
20
10.0%
0.82
13080
N/A
N/A
N/A

10670
0.5%

24159
O.Q
0
0
0.0
0.117















23.86
2.39
2.39
2.39
8.59
40 .
0
0
40
0.00
0.79
0
40


0.792
0 095
Q 73
O.Q22
EFFECT OF AGE


200 | 200

20
30
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.5%

24159
Q.Q
0
0
0.0
0.106















23.86
2.39
2.39
2.39
8.59
40
0
0
40
0.00
0.79
0
40


0.792
0.095
Q 58
0 055

40
10
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.5%

24159
0.0
0
0
0.0
0.153















23.86
2.39
2.39
2.39
8.59
40
3
Q
40
0 CO
0.79
0
40


0 7S2
0 OS5
0 58
0.355
F-9
-------
NOx CONTROL COSTS - COAL BOILERS c4wlnof.wkl

Lno * UrA - PC WALL-rlKtU UNI 19 .-...------
(Sorge. 1992} Case 4 | SIZE (HU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft*3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel

-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (ntills/kU-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mllls/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZEO 0 4 M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZEO CAPITAL CHARGES ($/kW-yr) =
LEVELIZED BUSBAR COST (mills/kW-hr) -
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL (J/bbl) 22.85
GAS (S/1000 ff 3) 2.61
AMMONIA (I/ton) 145.00
UREA (S/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

	 . 	 „ 	
	
100 200

0
0
0
1161

0


0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.134
0.072
0.000
0.093
6.26
1.40

0.95
0.35
1823
437
0.55
1215
655

0
0
0
2322

0


0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.101
0.055
0.000
0.093
4.74
1.08

0.95
0.35
3645
338
0.55
2430
507
300 400 660

0
0
0
3484

0


0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.086
0.046
0.000
0.093
4.03
0.93

0.95
0.35
5468
292
0.55
3645
438

0
0
0
4645

0


0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.077
0.041
0.000
0.093
3.60
0.84

0.95
0.35
7291
263
0.55
4860
395

0
0
0
7664

0


0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.063
0.034
0.000
0.093
2.94
0.71

0.95
0.35
12029
221
0.55
8020
331
EFFECT OF C.F.


200 | 200

0
0
0
1429

0


0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.101
0.152
0.000
0.093
4.74
1.70

0.95
0.35
2243
'531
0.55
1496
797

0
0
0
2930

0


0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.101
O.Q22
0.000
0.093
4.74
0.88

0.95
0.35
4599
274
0.55
3066
' 411
EFFECT OF AGE


200 200 •

0
0
0
2322

0


0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.101
0.055
0.000
0.093
4.28
1.00

0.95
0.35
3645
313
0.55
2430
469
1
Q ;
0
0
2322 i

0 j
1
i
o.ooo !
O.QOQ '
0.000 •
0.000 '
0.000
0.000

0.093

0.000

0.101
0.055
0.000 '
0.093
6.57 ;
1.40 ;

0.95
0.35 !
3645
439 ,
0.55
2430 '
658


Electric Power Monthly, March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-10
-------
NOx CONTROL COSTS - COAL BOILERS cStlnso.wkl
LHB * SOrA - PC lANutNTlAL-rlKtU UHlIb 	 	 	 —
(Figure 6-5) Case 5 | SIZE (MV)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft'3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kU):

-OUrners
-Ducting
-Fan Upgrade/Replace
_ C * pi i/» * i 1 1» » 1
j L rut* UUIQ i
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Ai r HaatAr
Mir neater
-Construct i on/ Instal 1 ati on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) =
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10% of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc ) 30%
TOTAL PLANT COSTS (TPC) (1991$/kW) =
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) =
-ROYALTY ALLOWANCE O.OX of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) =
OP-RATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 2X of TPC
-ADMIN/SUPPORT LABOR (|/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS ($/kW-yr) -
VARIABLE 0 & M COSTS (mills/kU-hr) =•
EFFECT OF CAPACITY
100 150 | 200 | 300 | 375

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.5X

12080
0.0
0
0
0.0
0.117


















23.11
2.31
2.31
2.31
8.32
38
0
0
38
0.00
0.77
0
39


0.767
0.092
0.56
0.053

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.5X

18119
0.0
0
0
0.0
0.117


















19.65
1.96
1.96
1.96
7.07
33
0
0
33
0.00
0.65
0
33


0.652
0.078
0.47
0.045

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.5X

24159
0.0
Q
0
0.0
0.117


















17.51
1.75
1.75
1.75
6.30
29
0
0
29
0.00
0.58
0
30


0.581
0.070
0.42
0.040

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.5X

36239
0.0
0
0
0.0
0.117


















14.89
1.49
1.49
1.49
5.36
25
0
0
25
0.00
0.49
0
25


0.494
0.059
0.36
0.034

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.5X

45298
0.0
0
0
0.0
0.117


















13.62
1.36
1.36
1.36
4.90
23
0
a
23
0.00
0.45
0
23


0.452
0.054
0.33
0.031
EFFECT OF C.F.
200 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
0.5X

24159
0.0
0
0
0.0
0.117


















17.51
1.75
1.75
1.75
6.30
29
0
0
29
0.00
0 53
0
30


0.581
0 070
0.26
0.112

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
0.5X

24159
0.0
0
0
0.0
0.117


















17.51
1.75
1.75
1.75
6.30
29
0
0
29
0.00
0.53
0
30


0.581
0.070
0.53
0.015
EFFECT OF AGE |
200 200 [

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.5X

24159
0.0
0
0
0.0
0.106


















17.51
1.75
1.75
1.75*
6.30
29
0
0
29
0.00
0.58
0
30


0 531
0.070
0.42
0 040

40 i
10 1
10. OX
0.65 i
13080
N/A i
N/A ,
N/A !
1
(
10670 !
0.5X|
,
24159 i
0.0 |
0 ;
0 :
0.0 '
0.163


















17.51
1.75 '.
1.75 ]
1.75
6.30
29 '.
o !
0
29
0 00
0 58
Q
30


0 581
0 070
0 42
0 040
F-ll
-------
NOx CONTROL COSTS - COAL BOILERS cStlnso.wkl

(Figure 6-5) Case 5 | SIZE (MV)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA {tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ff3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kV-hr)
-UREA (nrills/kW-hr)
-ELECTRICITY (mllls/kW-hr)
-CATALYST (mllls/kW-hr)
-CATALYST WASTE DISPOSAL (mllls/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kU-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kU-hr)
-GAS (mllls/kW-hr)
LEVELIZED 0 i M COSTS
-FIXED 0 4 M (mllls/kW-hr)
-VARIABLE 0 & M (mllls/kW-Hr)
-CONSUMABLES (mllls/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES (S/kW-yr) »
LEVELIZED BUSBAR COST (mills/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) «
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
1 UNIT
APPLICABLE UNIT PRICING | COST
COAL (J/ton) 45.84
OIL ($/bbl) 22.85
GAS (S/1000 ft"3) 2.61
AMMONIA (J/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST (J/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY

	
100 150 200 | 300 | 375

0
0
0
1161

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.098
0.053
0.000
0.093
4.60
1.05

0.60
0.30
911
657
0.45
456
1314

0
0
0
1742

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.083
0.045
0.000
0.093
3.91
0.91

0.60
0.30
1367
567
0.45
683
1135

0
0
0
2322

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.074
0.040
0.000
0.093
3.48
0.82

0.60
0.30
1823
512
0.45
911
1024

0
0
0
3484

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.063
0.034
0.000
0.093
2.96
0.71

0.60
0.30
2734
444
0.45
1367
888

0
0
0
4355

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.058
0.031
0.000
0.093
2.71
0.66

0.60
0.30
3417
411
0.45
1709
822
EFFECT OF C.F.

200 200

0
0
0
1429

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.074
0.112
0.000
0.093
3.48
1.27

0.60
0.30
1122
796
0.45
561
1591

0
0
0
2930

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.074
0.016
0.000
0.093
3.48
0.67

* 0.60
0.30
2299
418
0.45
1150
836
EFFECT OF AGE '
1
200 200

0
0
0
2322

0

0.000
0.000
0.000
0.000
0.000
0.000

0.093

0.000

0.074
0.040
0.000
O.Q93
3.15
0.76

0.60
0.30
1823
475
0.45
911
950
1
a ;
0
0
2322

0

0.000 ,
0.000
0.000 ,
Q.QQO
0.000
o.ooa

0.093 '

O.OQO '

0.074
0 040
0.000
0 093
4.33
1 06 -

0.60
0.30
1823
659
0.45
911
1319


Electric Power Monthly. March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie, 1991
Robie. 1991
Robie. 1991
Robie, 1991
F-12
-------
NOx CONTROL COSTS - COAL BOILERS c6wngr.wkl
NAIUKAL uAS KtbUKN - PC WALL Unils „—....—
(Farzan/EERC. 1991) Case 6 | SIZE (HW)
BOILER AND FUEL SPECIFICATIONS

BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (8STP:68F:14.7psia)(1000 ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):

"Burners
-Ducting
-Fan Upgrade/Replace
_ C ^ V>| |f*^1 |f"» 1
j true tura I
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Ai r H«*tor
n i r neater
~Const ruct 1 on/ 1 nsta 1 lation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) >
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) 20% of PCC
-PROJECT CONTING. (X of PCC+GF+EHOF+Proc) 30X
TOTAL PLANT COSTS (TPC) (1991J/kW) =
-ESCALATION (0%)
-AFDC (0%)
TCTAL PLANT INVESTMENT (1991$/ky) -
-ROYALTY ALLOWANCE 0.0% of PCC
-PREPRODUCTION COSTS 2% of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991J/kV) -
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 2X of TPC
-ADMIN/SUPPORT LABOR (J/kW-yr) 30% of OL+0.4MC
FIXED 0 & M COSTS (S/kW-yr) =
VARIABLE 0 4 M COSTS (mllls/kW-hr) =
EFFECT OF CAPACITY
100 200 | 300 400 | 660


30
20
10. OX
0.65
13080
N/A
N/A
N/A
22
10670
0.5X
0.1S
12080
0.0
0
0
0.0
0.117


















29.56
2.96
2.96
5.91
12.41
54
0
0
54
0.00
1.08
0
55

-0.089
1.075
0.102
0.71
0.067


30
20
10. OX
0.65
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117


















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.52
0.049


30
20
10. OX
0.65
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
36239
0.0
0
0
0.0
0.117


















19.05
1.90
1.90
3.81
8.00
35
0
0
35
0.00
0.69
0
35

-0.089
0.693
0.056
0.43
0.041


30
20
10. OX
0.65
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
48318
0.0
0
0
0.0
0.117


















16.98
1.70
1.70
3.40
7.13
31
0
0
31
0.00
0.62
0
32

-0.089
0.617
0.047
0.37
0.035


30
20
10. OX
0.65
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
79725
0.0
0
0
0.0
0.117


















13.89
1.39
1.39
2.78
5.84
25
0
0
25
0.00
0.51
0
26

-0.089
0.505
0.034
0.29
0.028
EFFECT OF C.F.
200 200


30
20
10. OX
0.40
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117


















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.32
0.136


30
20
10. OX
0.82
13080
N/A
N/A
N/A
22
10670
0.5%
0.15
24159
0.0
0
0
0.0
0.117


















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.039
0.815
0.071
0.55
0.020
EFFECT OF AGE
200 | 200


20
30
10.0%
0.65
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.106


















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0 52
0.049
I
I
40 1
10 !
10.0X|
0.65
13080
N/A
N/A
N/A
22
10670
0.5%
0.15
24159
0.0
0
0
0.0
0.163
'

















22.40 ,
2.24 '
2.24 '
4 48 :
9.41 !
41 ,
Q
0
*1
0 00
0.82 |
0 ,
42

-0.089
0 315
0.071
0.52
0.049 ,
F-13
-------
NOx CONTROL COSTS - COAL BOILERS cSwngr.wkl
NATIIRAI RAC OPRIIDN - PC Uil 1 IINIT^ ._.___-----
(Farzan/EERC. 1991) Case 6 | SIZE (HW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kW-hr)
-SOLID/ ASH WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) -
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mil1s/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) »
LEVELIZED BUSBAR COST (mills/kW-hr) -
EMISSIONS
* -UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL (J/bbl) 22.85
GAS ($/1000 ft*3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ft'3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
SOLID/ASH WASTE DISPOSAL ($/ton) 8.00
EFFECT OF CAPACITY
	 	
100

0
0
-756
-33675

911325

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.124
0.067
-0.174
1.466
6.44
2.62

0.95
0.40
1671
891
0.50
1367
1089
200 300

0
0
-1512
-67351

1822649

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.091
0.049
-0.174
1.466
4.88
2.29

0.95
0.40
3342
780
0.50
2734
954

0
0
-2268
-101026

2733974

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.075
0.041
-0.174
1.466
4.15
2.14

0.95
0.40
5012
728
0.50
4101
890
400 660

0
0
-3024
-134701

3645299

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.066
0.035
-0.174
1.466
3.70
2.04

0.95
0.40
6683
696
0.50
5468
851

0
0
-4989
-222257

6014743

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.051
0.028
-0.174
1.466
3.03
1.90

0.95
0.40
11027
649
0.50
9022
793
EFFECT OF C.F.

200 200

0
0
-930
-41447

1121630

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.091
0.136
-0.174
1.466
4.88
2.91

0.95
0.40
2056
993
0.50
1682
1214

0
0
-1907
-84966

2299342

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.091
0.020
-0.174
1.466
4 88
2.08

0.95
0.40
4215
710
0.50
3449
868
EFFECT OF AGE

200 | 200

0
0
-1512
-67351

1822649

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.091
0.049
-0.174
1.466
4.41
2.21

0.95
0.40
3342
752
0.50
2734
919

0
0
-1512
-67351

1822649

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.091
0.049
-0.174
1.456
5.77
2. 52

0.95
0.40
3342
893
0.50
2734
1092


Electric Power Monthly. March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
IAPCS. 1990
F-14
-------
NOx CONTROL COSTS - COAL BOILERS c7tngr.wkl
NATURAL GAS REBURN - PC TANGENTIAL UNIT 	
(Farzan/EERC. 1991) Case 7 | SIZE (MU)
BOILER AND FUEL SPECIFICATIONS

BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (8tu/kW-hr)
EFFICIENCY LOSS
RE3URN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia){1000 ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Ai r Heater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) •
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 20X of PCC
-PROJECT CONTING. (X of PCC+GF+EHOF+Proc) 30X
TOTAL PLANT COSTS (TPC) (1991$/kW) =
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) »
-ROYALTY ALLOWANCE O.OX of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991J/kU) =
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 2X of TPC
-ADMIN/SUPPORT LABOR (S/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS ($/kW-yr) *
VARIABLE 0 & M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 | 150 | 200 300 | 375


30
20
10. OX
0.65
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
12080
0.0
0
0
0.0
0.117













29.56
2.96
2.96
5.91
12.41
54
0
0
54
0.00
1.08
0
55

-0.089
1.075
Q.102
0.71
0.067


30
20
10. OX
0.65
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
18119
0.0
0
0
0.0
0.117













25.13
2.51
2.51
5.03
10.56
46
0
0
46
0.00
0.91
0
47

-0.089
0.914
0.083
0.59
0.056


30
20
10. OX
0.65
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117













22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.52
0.049


30
20
10. OX
0.65
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
36239
0.0
0
0
0.0
0.117













19.05
1.90
1.90
3.81
8.00
35
0
0
35
0.00
0.69
0
35

-0.089
0.693
0.056
0.43
0.041


30
20
10. OX
0.65
13080
N/A
N/A
N/A
22
10670
0.5%
0.15
45298
0.0
0
0
0.0
0.117













17.42
1.74
1.74
3.48
7.32
32
0
0
32
0.00
0.63
0
32

-0.089
0.634
0.049
0.39
0.036
EFFECT OF C.F.
200 200


30
20
10. OX
0.40
13080
N/A
N/A
N/A
22
10670
0.5%
0.15
24159
0.0
0
0
0.0
0.117













22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.32
0.136


30
20
10. OX
0.82
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117













22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.65
0.020
EFFECT OF AGE
200 200


20
30
10. OX
0.65
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.106













22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0 071
0.52
0 049


40
10
10.0%
0.65
13080
N/A
N/A
N/A
22
10670
0.5%
0.15
24159
0.0
Q
0
0.0 :
0.163













22.40
2.24
2.24
4.48
9 41
41
0
0 .
41
0 00
0 32
0
42

-0.089
0 315
0 071
0.52
0 049
F-15
-------
NOx CONTROL COSTS - COAL BOILERS c7tngr.wkl

(Farzan/EERC. 1991) Case 7 | SIZE (HW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel

-AMMONIA (mllls/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (m1lls/kW-hr)
-CATALYST (mills/kW-hr)
-SOLID/ASH WASTE DISPOSAL (mills/kW-hr)

TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 i M (mills/kW-hr)
-VARIABLE 0 & M (mi 11 s/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) =
LEVELIZED BUSBAR COST (mills/kW-hr) «
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) *
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) •
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL (J/bbl) 22.85
GAS {J/1000 ft'3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST (J/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
SOLID/ASH WASTE DISPOSAL ($/ton) 8.00
EFFECT OF CAPACITY

100 | 150 | 200

0
0
-756
-33675

911325


0.000
0.000
-0.066
0.000
-0.108

-0.174

-2.711

4.177.

0.124
0.067
-0.174
1.466
6.44
2.62

0.60
0.25
1063
1401
0.35
759
1961

0
0
-1134
-50513

1366987


0.000
0.000
-0.066
0.000
-0.108

-0.174

-2.711

4.177

0.104
0.056
-0.174
1.466
5.48
2.41

0.60
0.25
1595
1293
0.35
1139
1810

0
0
-1512
-67351

1822649


0.000
0.000
-0.066
0.000
-0.108

-0.174

-2.711

4.177

0.091
0.049
-0.174
1.466
4.38
2.29

0.60
0.25
2126
1226
0.35
1519
1717
300 375

0
0
-2268
-101026

2733974


0.000
0.000
-0.066
0.000
-0.108

-0.174

-2.711

4.177

0.075
0.041
-0.174
1.466
4.15
2.14

0.60
0.25
3190
1145
0.35
2278
1603

0
0
-2835
-126283

3417468


0.000
0.000
-0.066
0.000
-0.108

-0.174

-2.711

4.177

0.068
0.036
-0.174
1.466
3.80
2.06

0.60
0.25
3987
1105
0.35
2848
1547
EFFECT OF C.F.
	
200 200

0
0
-930
-41447

1121630


0.000
0.000
-0.066
0.000
-0.108

-0.174

-2.711

4.177

0.091
0.136
-0.174
1.466
4.88
2.91

0.60
0.25
1309
1560
0.35
935
2184

0
0
-1907
-84966

2299342


0.000
0.000
-0.066
0.000
-0.108

-0.174

-2.711

4.177

0.091
0.020
-0.174
1.466
4 88
2.08

0.60
0.25
2683
1116
0.35
1916
1562
EFFECT OF AGE

200 200

0
0
-1512
-67351

1822649


0.000
0.000
-0.066
0.000
-0.108

-0.174

-2.711

4.177

0.091
0.049
-0.174
1.466
4.41
2.21

0.60
0.25
2126
1182
0.35
1519
1655

0
0
-1512
-67351

1822649


0.000
0.000
-0.066
0.000
-0.108 :
I
-0.174

-2.711

4.177

0.091
0.049 :
-0.174
1.466
5 77
2.62

0.6Q
0.25
2126
1403
0.3S
1519
1965


Electric Power Monthly. March 1991
Electric Power Monthly, March 1991
Gas Facts, 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie, 1991
Robie. 1991
IAPCS. 1990
F-16
-------
NOx CONTROL COSTS - COAL BOILERS cScngr.wkl
NATURAL GAS REBURN - PC CYCLONE UNITS 	
(Farzan/EERC. 1991) Case 8 | SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kV-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (8STP:68F:14.7ps1a)(1000 ft*3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft'3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (19911/kW):
•Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
• Air* Maat Ar>
Ml r nedLQr
-Const ruct i on/ Insta 1 1 at 1 on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) •
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) 20X of PCC
-PROJECT CONTING. (X of PCC+GF+EHOF+Proc) 30X
TOTAL PLANT COSTS (TPC) (1991$/kV) =
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kV) »
-ROYALTY ALLOWANCE O.OX of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) -
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 2X of TPC
-AOMIN/SUPPORT LABOR (J/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS ($/ky-yr) «
VARIABLE 0 & M COSTS (mills/kW-hr) »
EFFECT OF CAPACITY
120 150 200 300 | 340

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
14496
0.0
0
0
0.0
0.117















27.48
2.75
2.75
5.50
• 11.54
50
0
0
50
0.00
1.00
0
51

-0.089
0.999
0.093
0.73
0.042

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
18119
0.0
0
0
0.0
0.117















25.13
2.51
2.51
5.03
10.56
46
0
0
46
0.00
0.91
0
47

-0.089
0.914
0.083
0.66
0.038

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117















22.40
2.24
2.24
4.43
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.58
0.034

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
36239
0.0
0
0
0.0
0.117















19.05
1.90
1.90
3.81
8.00
35
0
0
35
0.00
0.69
0
35

-0'.089
0.693
0.056
0.48
0.028

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
41071
0.0
0
0
0.0
0.117















18.12
1.81
1.81
3.62
7.61
33
0
0
33
0.00
0.66
0
34

-0.089
0.659
0.052
0.45
0.026
EFFECT OF C.F.
200 I 200

30
20
10. OX
0.55
13080
N/A
N/A
N/A
22
10670
0.5%
0.15
24159
0.0
0
0
0.0
0.117















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.44
0.074

30
20
10. OX
0.83
13080
N/A
N/A
N/A
22
10670
0.5%
0.15
24159
0.0
0
0
0.0
0.117















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0 089
0.315
0.071
0.66
0.019
EFFECT OF AGE
200 | 200

25
25
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5%
0.15
24159
0.0
0
0
0.0
0.110















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.32
0
42

-0.089
0.815
0.071
0.53
0.034

35
15
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5%
0.15
24159
0.0
0
0
0.0
0.131















22.40
2.24
2.24
4.48
9.41
41
0
0
41
o.oo !
0.32
0
"2

-0.089
0 315
0.071
0 53
0.334
F-17
-------
NOx CONTROL COSTS - COAL BOILERS cScngr.wkl

NAIUKAL uAS RtbUKN - rt, ITLLUNC UNI IS .-—-.—---
(Farzan/EERC. 1991) Case 8 | SIZE (HW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL {tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft" 3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel
-AMMONIA (mllls/kV-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (nrills/kW-hr)
-CATALYST (mills/kW-hr)
-SOLID/ ASH WASTE DISPOSAL (rallls/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/ky-hr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) -
LEVELIZED BUSBAR COST (mllls/kV-hr) «
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS (J/ton) •
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) •
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL (J/bbl) 22.85
GAS ($/1000 ft"3) 2.61
AMMONIA (J/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ff3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
SOLID/ASH WASTE DISPOSAL ($/ton) 8.00
EFFECT OF CAPACITY

	 	 — 	 	
120 150

0
0
-1019
-45384

1228185

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.115
0.042
-0.174
1.466
5.99
2.39

1.28
0.50
3193
573
0.70
2374
771

0
0
-1273
-56730

1535232

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.104
0.038
-0.174
1.466
5.48
2.29

1.28
0.50
3992
551
0.70
2968
740
200 | 300 340

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.091
0.034
-0.174
1.466
4.88
2.18

1.28
0.50
5322
524
0.70
3957
705

0
0
-2547
-113460

3070463

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.075
0.028
-0.174
1.466
4.15
2.04

1.28
0.50
7983
491
0.70
5936
661

0
0
-2887
-128588

3479858

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.071
0.026
-0.174
1.466
3.95
2.01

1.28
0.50
9048
482
0.70
6728
649
EFFECT OF C.F.

	
200 | 200

0
0
-1279
-56989

1542242

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.091
0.074
-0.174
1.466
4.88
2.47

1.28
0.50
4010
594
0.70
2982
799

0
0
-1931
-86002

2327383

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.091
0.019
-0.174
1.466
4.88
2.07

1.28
0.50
6051
498
0.70
4500
670
EFFECT OF AGE


200 200

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.091
0.034
-0.174
1.466
4.58
2.13

1.28
0.50
5322
513
0.70
3957
689

0
Q
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.177

0.091 ,
0.034
-0.174
1.466
5.47
Z.27

1.28
0.50
5322
546
0.70
3957
734


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts, 1991
Robie. 1991
BP Chemical, 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
IAPCS. 1990
F-18
-------
NOx CONTROL COSTS - COAL: DIFFERENTIAL FUEL COSTS
(Farzan/EERC. 1991) cdlfffcj SIZE (MU)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7ps1a)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS* (1991$/kW):

-Burners
-Ducting
-Fan Upgrade/Replace

- j true tura i
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
r *" » »^ 11 » n ik
— constructi on/ insta 1 1 atl on Laoor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) «
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 20X of PCC
-PROJECT CONTING. (X of PCC+GF+EHOF+Proc) SOX
TOTAL PLANT COSTS (TPC) (1991$/kW) «
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) -
-ROYALTY ALLOWANCE O.OX of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) -
OPERATING ANO MAINTENANCE COSTS (0 i M)
-OPERATING LABOR (OL) (J/kW-yr)
-MAINTENANCE COSTS (MC) ($AW-yr) 2X of TPC
-ADMIN/SUPPORT LABOR (J/kW-yr) 30X of OL+0.4MC
FIXED 0 i M COSTS (J/kW-yr) -
VARIABLE 0 & M COSTS (mills/kV-hr) >
EFFECT OF CAPACITY
120 150 200 300 340

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
14496
0.0
0
0
0.0
0.117

















27.48
2.75
2.75
5.50
11.54
50
0
0
50
0.00
1.00
0
51

-0.089
0.999
0.093
0.73
0.042

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
18119
0.0
0
0
0.0
0.117

















25.13
2.51
2.51
5.03
10.56
46
0
0
46
0.00
0.91
0
47

-0.089
0.914
0.083
0.66
0.038

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117

















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.315
0.071
0.58
0.034

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
36239
0.0
0
0
0.0
0.117

















19.05
1.90
1.90
3.81
8.00
35
0
0
35
0.00
0.69
0
35

-0.089
0.693
0.056
' 0.48
0.028

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
41071
0.0
0
0
0.0
0.117

















18.12
1.81
1.31
3.62
7.61
33
0
0
33"
0.00
0.66
0
34

-0.089
0.659
0.052
0.45
0.026
EFFECT OF C.F.
200 200

30
20
10. OX
0.55
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117

















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.44
0.074

30
20
10. OX
0.33
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117

















22.40
2.24
2.24
4.43
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.66
0.019
EFFECT OF AGE
200 200

25
25
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.110

















22.40
2.24
2.24
4.43
9.41
41
0
0
41
0.00
0.32
0
42

-0.089
0.815
0.071
0.58
0.034

35
15
10. OX
0.73
13080
N/A
N/A
N/A
' 22
10670 t
0.5X
0.15
24159
0.0
0
0
0.0
0.131
I














i
1
22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.32
0
42

-0.089
0.315
0.071
0.58
0.034
F-19
-------
MOx CONTROL COSTS - COAL: DIFFERENTIAL FUEL COSTS


(Farzan/EERC. 1991) cd1fffc| SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft" 3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kM-hr)
-CATALYST (mllls/kW-hr)
-SOLID/ ASH WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS

- -COAL (mills/kW-hr)
-OIL (itiills/kW-hr)
-GAS (raills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mllls/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES (S/kV-yr) -
LEVELIZEO BUSBAR COST (mllls/kW-hr) -
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (lb/MM8tu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) «
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
UNIT
APPLICABLE UNIT PRICING COST
COAL (J/ton) 45.84
OIL (J/bbl) 22.85
GAS (S/1000 ft* 3) 2
AMMONIA (J/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ff 3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
SOLID/ASH WASTE DISPOSAL ($/ton) 8.00
EFFECT OF CAPACITY

	 _„ 	 „_„_ 	 	 	
120

0
0
-1019
-45384

1228185

0.000
0.000
-0.066
0.000
-0.108
-0.174


-2.711

3.201

0.115
0.042
-0.174
0.490
5.99
1.41

1.28
0.50
3193
339
0.70
2374
456
150 200 | 300

0
0
-1273
-56730

1535232

0.000
0.000
-0.066
0.000
-0.108
-0.174


-2.711

3.201

0.104
0.038
-0.174
0.490
5.48
1.31

1.28
0.50
3992
316
0.70
2968
425

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174


-2.711

3.201

0.091
0.034
-0.174
0.490
4.38
1.20

1.28
0.50
5322
289
0.70
3957
389

0
0
-2547
-113460

3070463

0.000
0.000
-0.066
0.000
-0.108
-0.174


-2.711

3.201

0.075
0.028
-0.174
0.490
4.15
1.07

1.28
0.50
7983
257
0.70
5936
345
340

0
0
-2887
-128588

3479858

0.000
0.000
-0.066
0.000
-0.108
-0.174


-2.711

3.201

0.071
0.026
-0.174
0.490
3.95
1.03

1.28
0.50
9048
248
0.70
6728
333
EFFECT OF C.F.


200 | 200

0
0
-1279
-56989

1542242

0.000
0.000
-0.066
0.000
-0.108
-0.174


-2.711

3.201

0.091
0.074
-0.174
0.490
4.88
1.49

1.28
0.50
4010
359
0.70
2982
483

0
0
-1931
-86002

2327383

0.000
0.000
-0.066
0.000
-0.108
-0.174


-2.711

3.201

0.091
0.019
-0.174
0.490
4.88
1.10

1.28
0.50
6051
264
0.70
4500
355
EFFECT OF AGE


200 200

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174


-2.711

3.201

0.091
0.034
-0.174
0.490
4.58
1.16

1.28
0.50
5322
278
0.70
3957
374
!
0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174


-2.711

3.201

0.091
0.034
-0.174
0.490
5.47
1.30

1.28
0.50
5322
311
0.70
3957
419 1


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie, 1991 1.752 $/MM8tu for Coal
Robie, 1991 2.000 $/MM8tu for Gas
Robie. 1991
IAPCS. 1990 0.248 Differential Fuel Cost
F-20
-------
NOx CONTROL COSTS - COAL: DIFFERENTIAL FUEL COSTS
NATURAL GAS REBURN - PC CYCLONE UNITS
(Fanan/EERC. 1991) cd1fffc| SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kV-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:l4.7ps1a)(lOOO ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft*3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace

- j trUC tUra 1
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-ii r Haater
nt r ncokci
TOTAL PROCESS CAPITAL COSTS (PCC) (1991J/kW) -
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 20X of PCC
-PROJECT CONTING. (X of PCC+GF+EHOF+Proc) 30X
TOTAL PLANT COSTS (TPC) (1991$/kV) -
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) -
-ROYALTY ALLOWANCE O.OX of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) -
OPERATING AND MAINTENANCE COSTS (0 8. M)
-OPERATING LABOR (OL) (J/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 2X of TPC
-AOMIN/SUPPORT LABOR ($/kU-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS (J/kW-yr) -
VARIABLE 0 i M COSTS (mills/kW-hr) »
EFFECT OF CAPACITY
120 | 150 | 200

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
O.SX
0.15
14496
0.0
0
0
0.0
0.117

















27.48
2.75
2.75
5.50
11.54
50
0
0
50
0.00
1.00
0
51

-0.089
0.999
0.093
0.73
0.042

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
O.SX
0.15
18119
0.0
0
0
0.0
0.117

















25.13
2.51
2.51
5.03
10.56
46
0
0
46
0.00
0.91
0
47

-0.089
0.914
0.083
0.66
0.033

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
O.SX
0.15
24159
0.0
0
0
0.0
0.117

















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.58
0.034
300

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
O.SX
0.15
36239
0.0
0
0
0.0
0.117

















19.05
1.90
1.90
3.81
8.00
35
0
0
35
0.00
0.69
0
35

-0.089
0.693
0.056
0.48
0.028
340

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
O.SX
0.15
41071
0.0
0
0
0.0
0.117

















18.12
1.81
1.81
3.62
7.61
33
0
0
33
0.00
0.66
0
34

-0.089
0.659
0.052
0.45
0.026
EFFECT OF C.F.
200 200

30
20
10. OX
0.55
13080
N/A
N/A
N/A
22
10670
O.SX
0.15
24159
0.0
0
0
0.0
0.117

















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.44
0.074

30
20
10. OX
0.83
13080
N/A
N/A
N/A
22
10670
O.SX
0.15
24159
0.0
0
0
0.0
0.117

















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.66
0.019
EFFECT OF AGE
200 | 200

25
25
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
O.SX
0.15
24159
0.0
0
0
0.0
0.110

















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.58
0.034

35
15
10. OS
0.73
13080
N/A
N/A
N/A
22
10670
O.SX
0.15
24159
0.0
0
0
0.0
0.131

















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.58
0.034
F-21
-------
NOx CONTROL COSTS - COAL: DIFFERENTIAL FUEL COSTS

(Farzan/EERC. 1991) cd1fffc| SIZE (MU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mllls/kW-hr)
-UREA (mllls/kW-hr)
-ELECTRICITY (mi 11 s/kW-hr)
-CATALYST (rail 1 s/kW-hr)
-SOLID/ASH WASTE DISPOSAL (mllls/kV-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mllls/kW-hr) •
FUEL COSTS
-COAL (mllls/kW-hr)
-OIL (mllls/kW-hr)
-GAS (mills/kW-hr)
IEVELIZEO 0 & M COSTS
-FIXED 0 A M (mllls/kW-hr)
-VARIABLE 0 It M (ml 1 1 s/kV-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mllls/kV-Hr)
LEVELIZEO CAPITAL CHARGES ($/kW-yr) -
LEVELIZED BUSBAR COST (mllls/kW-hr) -
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
UNIT
APPLICABLE UNIT PRICING COST
lOAL ($/ton) 45.84
HL (J/bbl) 22.85
3AS ($/1000 ft* 3) 2.5
AMMONIA ($/ton) 145.00
jREA ($/ton) 220.00
-ILECTRICITY ($/kW-hr) 0.05
:ATALYST COST ($/ft'3) eeo.oo
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
DERATING LABOR ($/man-hr) 21.45
SOLID/ASH WASTE DISPOSAL ($/ton) 8.00
EFFECT OF CAPACITY
	 , ^ _ _ _ 	
120

0
0
-1019
-4S384

1228185

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.001

0.115
0.042
-0.174
1.290
5.99
2.21

1.28
0.50
3193
531
0.70
2374
714
150

0
0
-1273
-56730

1535232

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.001

0.104
0.038
-0.174
1.290
5.48
2.12

1.28
0.50
3992
508
0.70
2968
684
200

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.001

0.091
0.034
-0.174
1.290
4.88
2.00

1.28
0.50
5322
482
0.70
3957
648
300 340

0
0
-2547
-113460

3070463

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.001

0.075
0.028
-0.174
1.290
4.15
1.87

1.28
0.50
7983
449
0.70
5936
604

0
0
-2887
-128588

3479858

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.001

0.071
0.026
-0.174
1.290
3.95
1.83

1.28
0.50
9048
440
0.70
6728
592
EFFECT OF C.F.

200 200

0
0
-1279
-56989

1542242

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.001

0.091
0.074
-0.174
1.290
4.88
2.30

1.28
0.50
4010
552
0.70
2982
742

0
0
-1931
-86002

2327383

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.001

0.091
0.019
-0.174
1.290
4.88
1.90

1.28
0.50
6051
456
0.70
4500
613
EFFECT OF AGE

200 200

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.001

0.091
0.034
-0.174
1.290
4.58
1.96

1.28
0.50
5322
470
0.70
3957
632

0
0
-1698
-75640

204697S

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.001

0.091
0.034
-0.174
1.290
5.47
2.10

' 1.28
0.50
5322
504
0.70
3957
677


Electric Power Monthly. March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991
Robie. 1991
8P Chemical. 1991
Robie. 1991
Robie. 1991 1.752 $/MMBtu for Coal
Robie. 1991 2.500 $/MMBtu for Gas
Robie. 1991
IAPCS. 1990 0.748 Differential Fuel Cost
F-22
-------
NOx CONTROL COSTS - COAL: DIFFERENTIAL FUEL COSTS
NATURAL GAS REBURN - PC CYCLONE UNITS 	 — —
(Farzan/EERC. 1991) cdifffc| SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (8STP:68F:14.7psia)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
~r\ir Header
'Construct 1 on/ instA I l itl on Libor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) -
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 20X of PCC
-PROJECT CONTING. (X of PCC+GF+EHOF+Proc) 30X
TOTAL PLANT COSTS (TPC) (1991$/kW) -
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) »
-ROYALTY ALLOWANCE O.OX of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991JAW) -
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 2X of TPC
-AOMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS ($/kW-yr) »
VARIABLE 0 & M COSTS (mills/kU-hr) *

EFFECT OF CAPACITY
120 150

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
14496
0.0
0
0
0.0
0.117

















27.48
2.75
2.75
5.50
11.54
50
0
0
50
0.00
1.00
0
51

-0.089
0.999
0.093
0.73
0.042


30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
18119
0.0
0
0
0.0
0.117

















25.13
2.51
2.51
5.03
10.56
46
0
0
46
0.00
0.91
0
47

-0.089
0.914
0.083
0.66
0.038

200

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117

















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.58
0.034

300 340

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
36239
•0.0
0
0
0.0
0.117

















19.05
1.90
1.90
3.81
8.00
35
0
0
35
0.00
0.69
0
35

-0.089
0.693
0.056
0.48
0.023


30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
41071
0.0
0
0
0.0
0.117

















18.12
1.81
1.81
3.62
7.61
33
0
0
33
0.00
0.66
0
34

-0.089
0.659
0.052
0.45
0.026

EFFECT OF C.F.
200 200

30
20
10. OX
0.55
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117

















22.40
2.24
2.24
4.48
9.41
41
. 0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.44
0.074


30
20
10. OX
0.83
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117

















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.66
0.019

EFFECT OF AGE
200 | 200

25
25
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.110

















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.58
0.034


35
15
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5%
0.15
24159
0.0
0
0
0.0
0.131

















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.32
0
42

-0.039
0.315
0.071
0.58
0.034
I
«======!
F-23
-------
NOx CONTROL COSTS - COAL: DIFFERENTIAL FUEL COSTS
(Farzan/EERC. 1991) cdlfffc) SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-SAS (1000 ft* 3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mllls/kW-hr)
-UREA (mllls/kU-hr)
-ELECTRICITY (mllls/kW-hr)
-CATALYST (mllls/kW-hr)
-SOLID/ASH WASTE DISPOSAL (mllls/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mllls/kW-hr) -
FUEL COSTS
-COAL (mllls/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 ft M (mllls/kW-hr)
-VARIABLE 0 & M (mills/kU-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) -
LEVELIZED BUSBAR COST (mills/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOVER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) «
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION {tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) •
1 UNIT
APPLICABLE UNIT PRICING | COST
COAL (J/ton) 4S.84
OIL (S/bbl) 22.35
GAS (J/1000 ft*3) 3
AMMONIA (J/ton) 145.00
UREA (J/ton) 220.00
ELECTRICITY (S/kW-hr) 0.05
CATALYST COST (S/ft'3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
SOLID/ASH WASTE DISPOSAL ($/ton) 8.00
EFFECT OF CAPACITY
120 | 150 | 200 | 300 | 340

0
0
-1019
-45384

1228185

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.802

0.115
0.042
-0.174
2.090
5.99
3.01

1.28
0.50
3193
723
0.70
2374
973

0
0
-1273
-56730

1535232

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.802

0.104
0.038
-0.174
2.090
5.48
2.92

1.28
0.50
3992
701
0.70
2968
942

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.802

0.091
0.034
-0.174
2.090
4.88
2.80

1.28
0.50
5322
674
0.70
3957
906

0
0
-2547
-113460

3070463

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.802

0.075
0.028
-0.174
2.090
4.15
2.67

1.28
0.50
7983
641
0.70
5936
863

0
0
-2887
-128588

3479858

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.802

0.071
0.026
-0.174
2.090
3.95
2.63

1.28
0.50
9048
632
0.70
6721
850
EFFECT OF C.F.
200

0
0
-1279
-56989

1542242

0.000
0.000.
-0.066
0.000
-0.108
-0.174

-2.711

4.802

0.091
0.074
-0.174
2.090
4.88
3.10

1.28
0.50
4010
744
0.70
2982
1000
200

0
0
-1931
-86002

2327383

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.801

0.091
0.019
-0.174
2.090
4.88
2.70

1.28
0.50
6051
648
0.70
4500
872
EFFECT OF AGE
200 | 200

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.802

0.091
0.034
-0.174
2.090
4.58
2.76

1.28
0.50
5322
663
0.70
3957
891

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

4.802

0.091
0.034
-0.174
2.090
5.47
2.90

1.28
0.50
5322
696
0.70
3957
936


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Roble. 1991
BP Chemical. 1991
Robie. 1991
Roble. 1991 1.752 $/MMBtu for Coal
Robie. 1991 3.000 $/MM8tu for Gas
Robie. 1991
IAPCS. 1990 1.248 Differential Fuel Cost
F-24
-------
NOx CONTROL COSTS - COAL: DIFFERENTIAL FUEL COSTS
NATURAL GAS REBURN - PC CYCLONE UNITS 	
(Farzan/EERC. 1991) cd1fffc| SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kU-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7ps1a)(1000 ff3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft*3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
A{ _ LI— -^ 	
-AT r neater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kV) -
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 20X of PCC
-PROJECT CONTING. (X of PCC+GF+EHOF+Proc) 30X
TOTAL PUNT COSTS (TPC) (1991$/kW) »
-ESCALATION (OX)
-AFOC (OX)
TOTAL PLANT INVESTMENT (1991$/kV) «
-ROYALTY ALLOWANCE O.OX of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) -
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) (J/kU-yr) 2X of TPC
-ADMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS (J/kW-yr) «
VARIABLE 0 4 M COSTS (mills/ky-hr) -
EFFECT OF CAPACITY
120

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
14496
0.0
0
0
0.0
0.117














27.48
2.75
2.75
5.50
11.54
50
0
0
50
0.00
1.00
0
51

-0.089
0.999
0.093
0.73
0.042
150 | 200

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
18119
0.0
0
0
0.0
0.117














25.13
2.51
2.51
5.03
10.56
46
0
0
46
0.00
0.91
0
47

-0.089
0.914
0.083
0.66
0.038

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117














22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.58
0.034
300 | 340

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
36239
0.0
0
0
0.0
0.117














19.05
1.90
1.90
3.81
8.00
35
0
0
35
0.00
0.69
0
35

-0.089
0.693
0.056
0.48
0.028

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
41071
0.0
0
0
0.0
0.117














18.12
1.81
1.81
3.62
7.61
33
0
0
33
0.00
0.66
0
34

-0.089
0.659
0.052
0.45
0.026
EFFECT OF C.F.
200 | 200

30
20
10. OX
0.55
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117














22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.32
0
42

-0.089
0.315
0.071
0.44
0.074

30
20
10. OX
0.83
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117














22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.32
0
42

-0.089
0.815
0.071
0.66
0.019
EFFECT OF AGE
200 200

25
25
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.110














22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.58
0.034

35
15
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.131














22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.58
0.034
F-25
-------
NOx CONTROL COSTS - COAL: DIFFERENTIAL FUEL COSTS
(Farzan/EERC. 1991) cdifffc| SIZE^(MV)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL { tons/yr)
-OIL (bbl/yr)
-GAS (1000 ff3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kV-hr)
-SOLID/ASH WASTE DISPOSAL (mills/kW-hr)
TOTAL .CONSUMABLES (Excluding Fuel) (mills/kW-hr) -
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (nrills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 4 M (mills/kW-hr)
-VARIABLE 0 & N (milTs/kW-Hr)
-CONSUMABLES (mllls/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) -
LEVELIZED BUSBAR COST (mills/kW-hr) •
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MHBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL (J/bbl) 22.85
GAS (S/1000 ft*3) 3.5
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST (J/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
SOLID/ASH WASTE DISPOSAL ($/ton) 3.00
EFFECT OF CAPACITY
	
120

0
0
-1019
-45384

1228185

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

5.602

0.115
0.042
-0.174
2.891
5.99
3.81

1.28
0.50
3193
916
0.70
2374
1231
150

0
0
-1273
-56730

1535232

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

5.602

0.104
0.038
-0.174
2.891
5.48
3.72

1.28
0.50
3992
893
0.70
2968
1201
200 300 340

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

5.602

0.091
0.034
-0.174
2.891
4.88
3.60

1.28
0.50
5322
866
0.70
3957
1165

0
0
-2547
-113460

3070463

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

5.602

0.075
0.028
-0.174
2.891
4.15
3.47

1.28
0.50
7983
834
0.70
5936
1121

0
0
-2887
-128588

3479858

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

5.602

0.071
0.026
-0.174
2.891
3.95
3.43

1.28
0.50
9048
825
0.70
6728.
1109
EFFECT OF C.F.
200

0
0
-1279
-56989

1542242

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

5.602

0.091
0.074
-0.174
2.891
4.88
3.90

1.28
0.50
4010
936
0.70
2982
1259
200

0
0
-1931
-86002

2327383

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

5.602

0.091
0.019
-0.174
2.891
4.88
3.50

1.28
0.50
6051
841
0.70
4500
1130
EFFECT OF AGE
200 200

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

5.602

0.091
0.034
-0.174
2.891
4.58
3.56

1.28
0.50
5322
855
0.70
3957
1150

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

5.602

0.091
0.034
-0.174
2.891
S.47
3.70

1.28
0.50
5322
388
0.70
3957
1194


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991 1.752 J/MM8tu for Coal
Robie. 1991 3.500 $/MMBtu for Gas
Robie. 1991
IAPCS. 1990 1.748 Differential Fuel Cost
F-26
-------
NOx CONTROL COSTS - COAL: DIFFERENTIAL FUEL COSTS
NATURAL GAS REBURN - PC CTCLUnC UNI 15 ----- ------
(Farzan/EERC. 1991) cd1fffc| SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft'3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Reagent Storage 4 Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Air Maataf*
HI r neater
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) «
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 20X of PCC
-PROJECT CONTING, (X of PCC+GF+EHOF+Proc) 30X
TOTAL PLANT COSTS (TPC) (1991$/kW) «
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) »
-ROYALTY ALLOWANCE O.OX of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) «
OPERATING AND MAINTENANCE COSTS (0 4 M)
-OPERATING LABOR (OL) ($/kU-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 2X of TPC
-ADMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 4 M COSTS ($/kW-yr) »
VARIABLE 0 4 M COSTS (mills/kW-hr) »
EFFECT OF CAPACITY
120 150 200 300 340

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
14496
0.0
0
0
0.0
0.117
















27.48
2.75
2.75
5.50
11.54
50
0
0
50
0.00
1.00
0
51

-0.089
0.999
0.093
0.73
0.042

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
13119
0.0
0
0
0.0
0.117
















25.13
2.51
2.51
5.03
10.56
46
0
0
46
0.00
0.91
0
47

-0.089
0.914
0.083
0.66
0.033

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117
















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.32
0
42

-0.089
0.315
0.071
0.58
0.034

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
36239
0.0
0
0
0.0
0.117
















19.05
1.90
1.90
.3.81
8.00
35
0
0
35
0.00
0.69
0
35

-0.089
0.693
0.056
0.48
0.023

30
20
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
41071
0.0
0
0
0.0
0.117
















18.12
1.81
1.81
3.62
7.61
33
0
0
33
0.00
0.66
0
34

-0.089
0.659
0.052
0.45
0.026
EFFECT OF C.F.
200 | 200

30
20
10. OX
0.55
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117
















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.815
0.071
0.44
0.074

30
20
10. OX
0.33
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.117
















22.40
2.24
2.24
4.43
9.41
41
0
0
41
0.00
0.82
0
42

-0.039
0.815
0.071
0.56
0.019
EFFECT OF AGE
200 200

25
' 25
10. OX
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.110
















22.40
2.24
2.24
4.48
9.41.
41
0
0
41
0.00
0.32
0
42

-0.089
0.815
0.071
0.58
0.034

35
15
10.0%
0.73
13080
N/A
N/A
N/A
22
10670
0.5X
0.15
24159
0.0
0
0
0.0
0.131
















22.40
2.24
2.24
4.48
9.41
41
0
0
41
0.00
0.82
0
42

-0.089
0.315
0 071
0.58
0.034
F-27
-------
NOx CONTROL COSTS - COAL: DIFFERENTIAL FUEL COSTS

1AIUKAL taAS KtdUKfl - ru ITiLUnt Unlld -.«-.--.--
(Farzan/EERC. 1991) cdifffc| SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ff3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mllls/kW-hr)
-SOLID/ ASH WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) «
FUEL COSTS
-COAL (m1lls/kW-hr)
-OIL (m1lls/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (raills/kW-Hr)
-CONSUMABLES (mill s/kW-Hr)
-FUEL (mllls/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) -
LEVELIZED BUSBAR COST (mills/kW-hr) -
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) «
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
1 UNIT
APPLICABLE UNIT PRICING | COST
COAL ($/ton) 45.84
OIL (J/bbl) 22.85
GAS (J/1000 ft'3) 4
AMMONIA (J/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST (J/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL (J/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
SOLID/ASH WASTE DISPOSAL (J/ton) 8.00
EFFECT OF CAPACITY

120

0
0
-1019
-45384

1228185

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

6.402

0.115
0.042
-0.174
3.691
5.99
4.61

1.28
0.50
3193
1108
0.70
2374
1490
150 | 200

0
0
-1273
-56730

1535232

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

6.402

0.104
0.038
-0.174
3.691
5.48
4.52

1.28
0.50
3992
1085
0.70
2968
1459

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

6.402

0.091
0.034
-0.174
3.691
4.88
4.41

1.28
0.50
5322
1059
0.70
3957
1424
300 | 340

0
0
-2547
-113460

3070463

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

6.402

0.075
0.028
-0.174
3.691
4.15
4.27

1.28
0.50
7983
1026
0.70
5936
1380

0
0
-2887
-128588

3479858

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

6.402

0.071
0.026
-0.174
3.691
3.95
4.23

1.28
0.50
9048
1017
0.70
672S
1368
EFFECT OF C.F.

200 | 200

0
0
-1279
-56989

1542242

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

6.402

0.091
0.074
-0.174
3.691
4.38
4.70

1.28
0.50
4010
1128
0.70
2982
1518

0
0
-1931
-86002

2327383

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

6.402

0.091
0.019
-0.174
3.691
4.33
4.30

1.28
0.50
6051
1033
0.70
4500
1339
EFFECT OF AGE

200 | 200

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711'

6.402

0.091
0.034
-0.174
3.691
4.58
4.36

1.28
0.50
5322
1047
0.70
3957
1408

0
0
-1698
-75640

2046975

0.000
0.000
-0.066
0.000
-0.108
-0.174

-2.711

6.402

0.091
0.034
-0.174
3.691
5.47
4.50

1.28
0.50
5322
1081
0.70
3957
1453


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991 1.752 J/MMBtu for Coal
Robie. 1991 4.000 J/MMBtu for Gas
Robie. 1991
IAPCS. 1990 2.248 Differential Fuel Cost
F-28.
-------
NOx CONTROL COSTS - COAL BOILERS c9wsncru.wkl
UKcA NOX-OUT ISNCK-UNCUNTK. J-WALL-rlKtU ----- — ----
(Nalco/Hunt. 1992) Case 9 | SIZE (MV)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ff 3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991SAW):
Ql I»M A«t*
-ourners
-Ducting
-Fan Upgrade/Replace
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
_At f, UBA^PP
Mir ncdicr
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) -
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 305!
TOTAL PLANT COSTS (TPC) (1991$/kU) *
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/ky) *
-ROYALTY ALLOWANCE
-PREPRODUCTION COSTS
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991SAV) »
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (JAW-yr)
-MAINTENANCE COSTS (MC) (J/kW-yr)
-AOMIN/SUPPORT LABOR (J/kW-yr)
FIXED 0 i M COSTS ($AW-yr) »
VARIABLE 0 & M COSTS (mills/kW-hr) >
EFFECT OF CAPACITY
100 200 300 | 400 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

12080
0.0
4
2013
1.5
0.117

















14.78
1.48
1.48
1.48
4.43
24
0
0
24
1.70
0.00
0
25

0.081
0.042
0.000
0.08
0.008

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

24159
0.0
4
4027
1.5
0.117

















11.20
1.12
1.12
1.12
3.36
18
0
0
18
1.38
0.00
0
19

0.040
0.021
0.000
0.04
0.004

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

36239
0.0
4
6040
1.5
0.117

















9.52
0.95
0.95
0.95
2.86
15
0
0
15
0.92
0.00
0
16

0.027
0.014
0.000
0.03
0.003

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

48318
0.0
4
8053
1.5
0.117

















8.49
0.85
0.85
0.85
2.55
14
0
0
14
0.34
0.00
0
14

0.020
0.011
0.000
0.02
0.002

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

79725
0.0
4
13288 i
1.5
0.117

















6.95
0.69
0.69
0.69
2.08
11
0
0
11
0.52
0.00
0
12

0.012
0.006
0.000
0.01
0.001
EFFECT OF C.F.
200 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
0.1X

24159
0.0
4
. 4027
1.5
0.117
•
















11.20
1.12
1.12
1.12
3.36
18
0
0
18
0.25
0.00
0
18

0.066
0.034
0.000
0.04
0.017

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
0.1X

24159
0.0
4
4027
1.5
0.117

















11.20
1.12
1.12
1.12
3.36
18
0
0
18
0.25
0.00
0
18

0.032
0.017
0.000
0.04
0.001
EFFECT OF AGE
200 200

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

24159
0.0
4
4027
1.5
0.106

















11.20
1.12
1.12
1.12
3.36
18
0
0
18
0.25
0.00
0
18

0.040
0.021
0.000
0.04
0.004

40
10
10.0%
0.65
13080
N/A .
N/A
N/A

10670
0.1%'

24159 '
0.0
4
4027 '•
i.s :
0.163 i






'






i



11.20
1.12
1.12
1.12
3.36
13
0 ,
0
18
0.25
0.00
Q
18 ,

0 C40
0 021
0.000
O.Q4
0.004 :
-------
NOx CONTROL COSTS - COAL BOILERS cSwsncru.wkl


(Nalco/Hunt. 1992) Case 9 | SIZE (HU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MU-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kV-hr)
-UREA (mllls/kU-hr)
-ELECTRICITY (mllls/kW-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mllls/kW-hr)
-GAS (mills/kW-nr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mills/kV-hr)
-VARIABLE 0 & M (mills/kU-Hr)
-CONSUMABLES (mllls/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZEO CAPITAL CHARGES ($/kW-yr) =
LEVELIZEO BUSBAR COST (ml lls/kW-hr) -
EMISSIONS
.-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION {tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) ».
-HIGHER CONTROLLED NOx' (Ib/MMBtu)
-HIGHER NOx REDUCTION {tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.35
GAS {$/1000 ft"3) 2.61
AMMONIA ($/ton) 145.00
UREA (S/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST ($/ft~3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY


100 200 300

0
2823
0
232

0

0.000
1.091
0.000
0.000
0.000
1.091

0.019

0.000

0.014
0.008
1.091
0.019
2.98
1.65

0.95
0.50
1367
689
0.65
911
1033

0
5646
0
464

0

0.000
1.091
0.000
0.000
0.000
1.091

0.019

0.000

0.007
0.004
1.091
0.019
2.27
1.52

0.95
O.SO
2734
632
0.65
1823
949

0
8469
0
697

0

0.000
1.091
0.000
0.000
0.000
1.091

0.019

0.000

0.005
0.003
1.091
0.019
1.90
1.45

0.95
0.50
4101
604
0.65
2734
906
400 1 660

0
11293
0
929

0

0.000
1.091
0.000
0.000
0.000
1.091

0.019

0.000

0.004
0.002
1.091
0.019
1.69
1.41

0.95
0.50
5468
588
0.65
3645
882

0
18633
0
1533

0

0.000
1.091
0.000
0.000
0.000
1.091

0.019

0.000

0.002
0.001
1.091
0.019
1.37
1.35

0.95
0.50
9022
563
0.65
6015
845
EFFECT OF C.F.


200 200

0
3475
0
286

0

0.000
1.091
0.000
0.000
0.000
1.091

0.019

0.000

0.011
0.017
1.091
0.019
2.13
1.75

0.95
0.50
1582
728
0.65
1122
1092

0
7123
0
586

0

0.000
1.091
0.000
0.000
0.000
1.091

0.019

0.000

0.006
0.001
1.091
0.019
2.13
1.41

0.95
0.50
3449
589
0.65
2299
883
EFFECT OF AGE


200 200

0
5646
0
464

0

0.000
1.091
0.000
0.000
0.000
1.091

0.019

0.000

0.007
0.004
1.091
0.019
1 93
1.46

0.95
0.50
2734
608
0.65
1823
911

0
5646
0
464

0

O.OOQ
1.091
0.000
0.000
O.QQO
1.091

0.019

0.000

0 007
0.004
1.091 ;
0.019
2.96
1.64

0.95
0.50
2734
S83
0.65
1823
1024


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie, 1991
Robie. 1991
Robie. 1991
F-30
-------
NOx CONTROL COSTS - COAL BOILERS clOwsncr.wkl
UREA NOX-OUT (SNCK-CONiKULLtUJ WAUL
(Nalco/Hunt, 1992) Case 10| SIZE (HU)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (8STP:68F:14.7psia)(1000 ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ff 3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):

'"our ncr 5
-Ducting
-Fan Upgrade/Replace
-C +• pi i/* + i i^al
3 true LUra t
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Meat Exchanger
_Ai r UA*f At*
MI r neater
— Pnnflf' niif^ti nn/Tn^tal l^i^inn 1 ahru*
UUM3 Liuckiun/ l no La I laLiuii UaUUi
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) »
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) 10% of PCC
-PROJECT CONTINGENCY (X of PCC) 30X
TOTAL PLANT COSTS (TPC) (1991$/kV) »
-ESCALATION (0%)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) =
-ROYALTY ALLOWANCE
-PREPRODUCTION COSTS
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991J/kW) -
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (J/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr)
-ADMIN/SUPPORT LABOR (j/kV-yr)
FIXED 0 & M COSTS ($/kU-yr) »
VARIABLE 0 & M COSTS (mitls/kW-hr) =
EFFECT OF CAPACITY
100 | 200 | 300 400 | 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

12080
0.0
4
2013
1.5
0.117


















14.78
1.48
1.48
1.48
4.43
24
0
0
24
1.70
0.00
0
25

0.081
0.042
0.000
0.08
0.008

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

24159
0.0
4
4027
1.5
0.117


















11.20
1.12
1.12
1.12
3.36
18
0
0
18
1.38
0.00
0
19

0.040
0.021
0.000
0.04
0.004

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

36239
0.0
4
6040
1.5
0.117


















9.52
0.95
0.95
0.95
2.86
15
0
0
15
0.92
0.00
0
16

0.027
0.014
0.000
0.03
0.003

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

48318
0.0
4
8053
1.5
0.117


















8.49
0.85
0.85
0.85
2.55
14
0
0
14
0.84
0.00
0
14

0.020
0.011
0.000
0.02
0.002

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

79725
0.0
4
13288
1.5
0.117


















6.95
0.69
0.69
0.69
2.08
11
0
0
11
0.52
0.00
0
12

0.012
0.006
0.000
0.01
0.001
EFFECT OF C.F.
200 | 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
0.1X

24159
0.0
4
4027
1.5
0.117


















11.20
1.12
1.12
1.12
3.36
18
0
0
18
0.25
0.00
0
18

0.066
0.034
0.000
0.04
0.017

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
0.1X

24159
0.0
4
4027
1.5
0.117


















11.20
1.12
1.12
1.12
3.36
13
0
0
18
0.25
0.00
0
18

0.032
O.Q17
0.000
0.04
o.oai
EFFECT OF AGE
200 | 200

20
30
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.1%

24159
0.0
4
4027
1.5
0.106


















11.20
1.12
1.12
1.12
3.36
18
0
0
18
0 25
0.00
0
13

0.040
0.021
0.000
0.04
0.004

40
10
10.0%
0.65
13030
N/A
N/A
N/A

10670
0.1%

24159
0.0
4 •
4027
1 5
0.153


















11.20
1.12
1.12
1 12
3.36 ,
13
3
0
13
0 25
0 CO
0
13

0.040
0 021
0 . 000
O.C4
0 004
F-31
-------
NOx CONTROL COSTS - COAL BOILERS clOwsncr.wkl


(Nalco/Hunt. 1992) Case 10| SIZE (HW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (nrills/kU-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mllls/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 i M COSTS
-FIXED 0 4 M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) -
LEVELIZED BUSBAR COST (nrills/kW-hr) «
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (S/IOOO ff 3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST ($/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL (J/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

	
100 200

0
1783
0
232

0

0.000
0.689
0.000
0.000
0.000
0.689

0.019

0.000

0.014
0.008
0.689
0.019
2.98
1.25

0.60
0.35
759
939
0.45
456
1565

0
3566
0
464

0

0.000
0.689
0.000
0.000
0.000
0.689

0.019

0.000

0.007
0.004
0.689
0.019
2.27
• 1.12

0.60
0.35
1519
837
0.45
911
1395
300 400 660

0
5349
0
697

0

0.000
0.689
0.000
0.000
0.000
0.689

0.019

0.000

0.005
0.003
0.689
0.019
1.90
1.05

0.60
0.35
2278
786
0.45
1367
1310

0
7132
0
929

0

0.000
0.689
0.000
0.000
0.000
0.689

0.019

0.000

0.004
0.002
0.689
0.019
1.69
1.01

0.60
0.35
3038
758
0.45
1823
1263

0
11768
0
1533

0

0.000
0.689
0.000
0.000
0.000
0.689

0.019

0.000

0.002
0.001
0.689
0.019
1.37
0.95

0.60
0.35
5012
713
0.45
3007
1188
EFFECT OF C.F.


200 200

0
2194
0
286

0

0.000
0.689
0.000
0.000
0.000
0.689

0.019

0.000

0.011
0.017
0.689
0.019
2.13
1.35

0.60
0.35
935
1009
0.45
561
1681

0
4499
0
586

0

0.000
0.689
0.000
0.000
0.000
0.639

0.019

0.000

0.006
0.001
0.689
0.019
2.13
1.01

0.60
0.35
1916
758
0.45
1150
1264
EFFECT OF AGE


200 200

0
3566
0
464

0

0.000
0.689
0.000
0.000
0.000
0.689

0.019

0.000

0.007
0.004
0.689
0.019
1.93
1.06

0.60
0.35
1519
792
0.45
911
1321

0
3566
0
464

0

0.000
0.539
0.000
0.000
0.000
0.689

0.019

O.QOO

0.007
0 004
0.689
0.019
2.96
1.24

0.60
0.35
1519
928
0.45
911
1547


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-32
-------
NOx CONTROL COSTS - COAL BOILERS clltsncr.wkl
UKcA NQx-QUT 15NCR-UNCUN 1 K. J-IANutNl 1AL — * 	 	
(Nalco/Hunt. 1992) Case 11 | SIZE (MU)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X vrt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (8STP:68F:14.7psia)(1000 ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Ducting
-Fan Upgrade/Replace
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Air* Maxtor
n i r neater
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kU) *
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 30X
TOTAL PLANT COSTS (TPC) (1991$/kW) »
-ESCALATION (OX)
-AFOC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) »
-ROYALTY ALLOWANCE
-PREPRODUCTION COSTS
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) =
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) (J/kU-yr)
-AOMIN/SUPPORT LABOR ($/kW-yr)
FIXED 0 & M COSTS (J/kW-yr) '
VARIABLE 0 & M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 | 150 | 200 300 | 375

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

12080
0.0
4
2013
1.5
0.117
















14.78
1.48
1.48
1.48
4.43
24
0
0
24
1.70
0.00
0
25

0.081
0.042
0.000
0.08
0 008

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

18119
0.0
4
3020
1.5
0.117
















12.57
1.26
1.26
1.26
3.77
20
0
0
20
1.83
0.00
0
22

0.054
0.028
0.000
0.05
0.005

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

24159
0.0
4
4027
1.5
0.117
















11.20
1.12
1.12
1.12
3.36
18
0
0
18
1.38
0.00
0
19

0.040
0.021
0.000
0.04
0.004

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

36239
0.0
4
6040
1.5
0.117
















9.52
0.95
0.95
0.95
2.86
15
0
0
15
1.12
0.00
0
16

0.027
0.014
0.000
0.03
0.003

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

45298
0.0
4
7550
1.5
0.117
















8.71
0.87
0.87
0.87
2.61
14
0
0
14
0.91
0.00
0
15

0.022
0.011
0.000
0.02
0.002
EFFECT OF C.F.
200 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
0.1X

24159
0.0
4
4027
1.5
0.117
















11.20
1.12
1.12
1.12
3.36
18
0
a
18
0.25
0.00
0
18

0.066
0.034
0.000
0.04
0.017

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
0.1%

24159
0.0
4
4027
1.5
0.117
















11.20
1.12
1.12
1.12
3.36
18
0
0
18
0.25
0.00
0
18

0 032
0.017
0.000
0 04
0 001
EFFECT OF AGE
200 | 200

20
30
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.1X

24159
0.0
4
4027
1.5
0.106
















11.20
1.12
1.12
1.12
3.36
18
0
0
18
0.25
0.00
0
18

0.040
0.021
0.000
0.04
0.004

40
10
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.1%

24159
0.0
4
4027
1.5
0.163
1





I




[




11 20
1.12
1.12
1.12
3.36
18
0
a
18 ;
U.25
0.00 ;
0
18 i

O.C4C
0 021
0.000
O.G4
0.004
F-33
-------
NOx CONTROL COSTS - COAL BOILERS clltsncr.wkl


(Nalco/Hunt. 1992) Case 11 | SIZE (MW)
CONSUMABLES PENALTY

-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MV-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft"3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mllls/kW-hr)
-UREA (mllls/kV-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (m1lls/kW-hr) -
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mi 1 Is/kU-Hr)
-FUEL (mllls/kW-Hr)
LEVELIZED CAPITAL CHARGES (J/kW-yr) »,
LEVELIZED BUSBAR COST (mills/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (lb/MM8tu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) •
-HIGHER CONTROLLED NOx (Ib/MMfltu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) «
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL (S/bbl) 22.85
GAS (J/1000 ft"3) . 2.61
AMMONIA (J/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST ($/ft'3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

	 	
100


0
1783
0
232

0

0.000
0.689
0.000
0.000
0.000
0.689

0.019

0.000

0.014
0.008
0.689
0.019
2.98
1.25

0.60
0.30
911
782
0.40
608
1173
150 200 1 300 375


0
2675
0
348

0

0.000
0.689
0.000
0.000
0.000
0.689

0.019

0.000

0.009
0.005
0.689
0.019
2.58
1.17

0.60
0.30
1367
734
0.40
911
1101


0
3566
0
464

0

0.000
0.689
0.000
0.000
0.000
0.689

0.019

0.000

0.007
0.004
0.689
0.019
2.27
1.12

0.60
0.30
1823
698
0.40
1215
1046


0
5349
0
697

0

0.000
0.689
0.000
0.000
0.000
0.689

0.019

0.000

0.005
0.003
0.689
0.019
1.92
1.05

0.60
0.30
2734
657
0.40
1823
986


0
6686
0
871

0

0.000
0.689
0.000
0.000
0.000
0.689

0.019

0.000

0.004
0.002
0.689
0.019
1.74
1.02

0.60
0.30
3417
637
0.40
2278
956
EFFECT OF C.F.


200 200


0
2194
0
286

0

0.000
0.689
0.000
0.000
0.000
0.689

0.019

0.000

0.011
0.017
0.689
0.019
2.13
1.35

0.60
0.30
1122
841
0.40
748
1261


0
4499
0
586

0

0.000
0.689
0.000
0.000
0.000
0.689

0.019

0.000

0.006
0.001
0.689
0.019
2.13
1.01

0.60
0.30
2299
632
0.40
1533
948
EFFECT OF AGE


200 200


0
3566
0
464

0

0.000
0.689°
0.000
0.000
0.000
0.689

0.019

0.000

0.007
0.004
0.639
0.019
1.93
1.06

0.60
0.30
1823
660
0.40
1215
991

1
0 1
3566
0
464

0

0.000
0.689
0.000
0.000 !
0.000 !
0.689

0.019 I

0.000

0.007
0.004
0.689
0.019
2.96 ;
1,24

1
O.SQ
0.30 :'
1823 •
773 :
0.40 '
1215
1160 :


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
8P Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-34
-------
NOx CONTROL COSTS - COAL BOILERS clZtsncr.wkl
UREA NOx-OUT (5NCR-CONTR. J " lANutNUAU -----------
(Nalco/Hunt. 1992) Case 12| SIZE (MW)
BOILER ANO FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X vrt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:l4.7ps1a)(lOOO ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ff 3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):

-ourners
-Ducting
-Fan Upgrade/Replace
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
— Ai r HAJit 0r
MI r ncofccr
~\*onstPuction/instai lation Laoor
TOTAL PROCESS CAPITAL COSTS (PCC) (i99i$/kw) »
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 30X
TOTAL PLANT COSTS (TPC) (1991J/kW) =
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) -
-ROYALTY ALLOWANCE
-PREPROOUCTION COSTS
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) =
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kU-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr)
-AOMIN/SUPPORT LABOR ($/kW-yr)
FIXED 0 & M COSTS (J/kU-yr) =
VARIABLE 0 & M COSTS (imlls/kW-hr) =
,*========a=*====*===**MS=*==**=-====*====s===,,===,
EFFECT OF CAPACITY
100 | 150 | ZOO 300 | 375

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

12080
0.0
4
2013
1.5
0.117

















14.78
1.48
1.48
1.48
4.43
24
0
0
24
1.70
0.00
0
25

0.081
0.042
0.000
0.08
0.003
=======

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

18119
0.0
4
3020
1.5
0.117

















12.57
1.26
1.26
1.26
3.77
20
0
0
20
1.83
0.00
0
22

0.054
0.028
0.000
0.05
0.005
========

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

24159
0.0
4
4027
1.5
0.117

















11.20
1.12
1.12
1.12
3.36
18
0
0
18
1.38
0.00
0
19

0.040
0.021
0.000
0.04
0.004
========

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

36239
0.0
4
6040
1.5
0.117

















9.52
0.95
0.95
0.95
2.86
15
0
0
15
1.12
0.00
0
16

0.027
0.014
0.000
0.03
0.003
========

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1X

45298
0.0
4
7550
1.5
0.117

















8.71
0.87
0.87
0.87
2.61
14
0
0
14
0.91
0 00
0
15

0.022
0.011
0.000
0.02
0.002
==5=====
EFFECT OF C.F.
200 | 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
0.1%

24159
0.0
4
4027
1.5
0.117

















11.20
1.12
1.12
1.12
3.36
18
0
0
18
0.25
0.00
0
18

0.066
0.034
0.000
0.04
0.017
========

30
20
10. or.
0.82
13080
N/A
N/A
N/A

10670
0.1X

24159
0.0
4
4027
1.5
0.117

















11.20
1.12
1.12
1 12
3.36
18
0
0
18"
0 25
0.00
0
18

0.032
0.017
0.000
0.04
0.001
========
EFFECT OF AGE j
200 200

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.1%

24159
0.0
4
4027
1.5
0.106

















11.20
1.12
1.12
1.12
3.36
18
0
0
18
0.25
0.00
0
18

" 0.040
0.021
0.000
0.04
0.004
========

40
10 1
10.07.1
0.65 (
13080
N/A ;
N/A I
N/A
I
10670 !
0.1%!
j
24159
Q.Q
4
4027
1.5
0.163

















11.20 :
1.12
1.12
1.12
3.36
18
0
0
18
0 25
0 00
0
18

0.040 i
0.021
0.000 ,
0 24
0.004
========
F-35
-------
NOx CONTROL COSTS - COAL BOILERS clZtsncr.wkl
(Nal co/Hunt. 1992) Case 12) SIZE (MU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft"3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel
-AMMONIA (mjlls/kW-nr)
-UREA (m1lls/kW-hr)
-ELECTRICITY (mills/kV-hr)
-CATALYST (mills/kW-hr)
-CATALYST yASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mllls/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mllls/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kU-Hr)
-FUEL (mills/kW-Hr)
LEVELIZEO CAPITAL CHARGES (J/kU-yr) =
LEVELIZEO BUSBAR COST (mllls/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) •
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bb1) 22.85
GAS (J/1000 ft'3) 2.61
AMMONIA ($/ton) • 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST (J/ft'3) 660.00
CATALYST SOLID WASTE DISPOSAL (J/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY
100 | 150 | 200 300 375

0
1337
0
232

0

0.000
0.517
0.000
0.000
0.000
0.517

0.019

0.000

0.014
0.008
0.517
0.019
2.98
1.08

0.45
0.25
608
1012
0.35
304
2024

0
2006
0
348

0

0.000
0.517
0.000
0.000
0.000
0.517

0.019

0.000

0.009
0.005
0.517
0.019
2.58
1.00

0.45
0.25
911
939
0.35
456
1879

0
2675
0
464

0

0.000
0.517
0.000
0.000
0.000
0.517

0.019

0.000

0.007
0.004
0.517
0.019
2.27
0.94

0.45
0.25
1215
S85
0.35
608
1770

0
4012
0
697

0

0.000
0.517
0.000
0.000
0.000
0.517

0.019

0.000

0.005
0.003
0.517
0.019
1.92
0.88

0.45
0.25
1823
825
0.35
911
1649

0
5015
0
871

0

0.000
0.517
0.000
0.000
0.000
0.517

0.019

0.000

0.004
0.002
0.517
0.019
1.74
0.85

0.45
0.25
2278
•794
0.35
1139
1588
EFFECT OF C.F.
200 200

0
1646
0
286

0

0.000
0.517
0.000
0.000
0.000
0.517

0.019

0.000

0.011
0.017
0.517
0.019
2.13
1.17

0.45
0.25
748
1099
0.35
374
2199

0
3374
0
586

0

0.000
0.517
0.000
0.000
0.000
0.517

0.019

0.000

0.006
0.001
0.517
0.019
2.13
0.34

0.45
0.25
1533
737
0.35
766
1573
EFFECT OF AGE
200 200

0
2675
0
464

0

0.000
0.517
0.000
0.000
0.000
0.517

0.019

0.000

0.007
0.004
0.517
0.019
1.93
0.38

0.45
0.25
1215
829
0.35
608
1658

0
2675
0
464

0

0.000
0.517
0.000
0.000
0.000
0.517

0.019

0.000

O.Q07
0.004
0.517
0.019
2.96
1.07

0.45
0 25
1215
999
0.35
608
1997


Electric Power Monthly. March 1991
Electric Power Monthly, March 1991
Gas Facts, 1991
Robie, 1991
BP Chemical, 1991
Robie. 1991
Robie, 1991
Robie. 1991 "
Robie. 1991
F-36
-------
NOx CONTROL COSTS - COAL BOILERS cl3wscru.wkl
iUK-UNUUN TROLL tU (LOLD olUt) - WALL
(Roble, 1991) Case 13 | SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
RE3URN FRACTION
FLUE GAS FLOURATE (9STP:68F:14.7psia)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft'3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Air Haater
n 1 ( nco LCI
-Construct 1 on/ instai 1 at i on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) -
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) ' 10%
•TOTAL PLANT COSTS (TPC) (1991$/kW) -
-ESCALATION (OX)
-AFOC (OX)
TOTAL PLANT INVESTMENT (1991$/kV) -
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) »
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 i M COSTS (J/kW-yr) «
VARIABLE 0 & M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 200 | 300 400 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

12080
1.0
4
2013
0.0
0.117


1.96
29.80
6.01
17.73
7.17
44.16
2.16
67.59


177
17.66
17.66
17.66
17.66
247
0
0
247
0.88
4.94
0
253

0.417
9.889
1.312
7.55
0.714

30
20
• 10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
l.Q
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187'
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

36239
1.0
4
6040
0.0
0.117


1.26
19.20
3.87
11.42
4.62
28.46
1.39
43.56


114
11.38
11.38
11.38
11.38
159
0
0
159
0.57
3.19
0
163

0.218
6.372
0.830
4.82
0.456

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

48318
1.0
4
8053
0.0
0.117


1.13
17.12
3.45
10.18
4.12
25.36
1.24
38.82


101
10.14
10.14
10.14
10.14
142
0
0
142
0.51
2.84
0
145

0.193
5.679
0.740
4.30
0.406

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

79725
1.0
4
13288
0.0
0.117


0.92
14.01
2.82
8.33
3.37
20.76
1.01
31.77


83
8.30
8.30
8.30
8.30
116
0
0
116
0.42
2.32
0
119

0.164
4.649
0.607
3.52
0.333
EFFECT OF C.F.
200 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.165
7.494
0.949
3.44
1.474

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4 55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.338
7.494
1.001
7 24
0.221
EFFECT OF AGE
200 | 200

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.106


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0 258
7 494
0.980
5 68
0.537

40
10
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.0%

24159
l.Q
4
4027
0.0
0.163


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13 38
13.38
187
Q
0
187
0 57
3 75
Q
192

0.253
7 494
0.93Q
5 S3 ,
0.537
F-37
-------
NOx CONTROL COSTS - COAL BOILERS c!3wscru.wkl

5CK-UNUUN TROLLED 1 LULU ilUtJ • WALL _.»__.--.--
(Robie, 1991) Case 13 | SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kV-hr)
-CATALYST (mllls/kW-hr)
-CATALYST WASTE DISPOSAL (mllls/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) •
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) »
LEVELIZEO BUSBAR COST (mllls/kW-hr) -
EMISSIONS
-UNCONTROLLED NOx (l.b/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMStu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) *
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (S/1000 ft~3) 2.61
AMMONIA ($/ton) 145.00
UREA (J/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST (J/ft'3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

	 „ 	 . 	 . 	
	
100 200 300

1068
0
3217
0

341303

0.272
0.000
0.283
0.583
0.007
1.145

0.000

1.564

1.326
0.714
1.145
1.564
29.72
9.97

0.95
0.15
2430
2336
0.25
2426
2669

2137
0
7978
0

682606

0.272
0.000
0.350
0.583
0.007
1.212

0.000

1.564

0.998
0.537
1.212
1.564
22.53
8.27

0.95
0.15
4860
1937
0.25
4253
2214

3205
0
12739
0

1023909

0.272
0.000
0.373
0.583
0.007
1.235

0.000

1.564

0.847
0.456
1.235
1.564
19.15
7.47

0.95
0.15
7291
1749
0.25
6379
1999
400 660

4273
0
17501
0

1365212

0.272
0.000
0.384
0.583
0.007
1.246

0.000

1.564

0.755
0.406
1.246
1.564
17.07
6.97

0.95
0.15
9721
1633
0.25
8506
1366

7051
0
29879
0

2252600

0.272
0.000
0.398
0.583
0.007
1.260

0.000

1.564

0.619
0.333
1.260
1.564
13.97
6.23

0.95
0.15
16039
1460
0.25
14034
1668
EFFECT OF C.F.


200 200

1315
0
4910
0

420065

0.272
0.000
0.350
0.948
0.011
1.581

0.000

1.564

0.983
1.474
1.581
1.564
32.53
12.03

0.95
0.15
2991
2819
0.25
2617
3221

2695
0
10065
0

861134

0.272
0.000
0.350
0.462
0.005
1.090

0.000

1.564

1.008
0.221
1.090
1.564
22.53
7.02

0.95
0.15
6132
1645
0.25
5365
1880
EFFECT OF AGE


200 200

2137
0
7978
0

682606

0.272
0.000
0.350
0.583
0.007
1.212

0.000

1.564

0.998
0.537
1.212
1.564
20.34
7.88

0.95
0.15
4860
1847
0.25
4253
2111

2137
0
7978
a

682606

0.272
0.000
0.350
0.583
O.QQ7
1.212

0.000

1.564

0.998
0.537
1.212
1.564
31.21
9.79

.0.95
0.15
4860
2295
0.25
4253
2622


Electric Power Monthly, March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
8P Chemical . 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-38
-------
NOx CONTROL COSTS - COAL BOILERS cHwscrc.wkl
iLK-tUNI KOLLtU (COLD Slut} - wAUL-rlKtU -----------
(Robie. 1991) Case 14| SIZE (HU)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ft~3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft'3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Ai r Moaf ttr*
n\ i neater
-Construct i on/ 1 nsta 1 1 at i on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kU) »
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 10X
TOTAL PLANT COSTS (TPC) (1991$/kW) =
-ESCALATION (OX)
-AFOC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) »
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991J/kU) =
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) (J/kU-yr) 4X of TPC
-AOMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 8, M COSTS (J/kW-yr) =
VARIABLE 0 4 M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 200 300 | 400 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

12080
1.0
4
2013
0.0
0.117


1.96
29.80
6.01
17.73
7.17
44.16
2.16
67.59


177
17.66
17.66
17.66
17.66
247
0
0
247
0.38
4.94
0
253

0.417
9.889
1.312
7.55
0.714

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

36239
1.0
4
6040
0.0
0.117


1.26
19.20
3.87
11.42
4.62
28.46
1.39
43.56


114
11.38
11.38
11.38
11.38
159
0
0
159
0.57
3.19
0
163

0.218
6.372
0.830
4.82
0.456

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

48318
1.0
4
8053
0.0
0.117


1.13
17.12
3.45
10.18
4.12
25.36
1.24
38.82


101
10.14
10.14
10.14
10.14
142
0
0
142
0.51
2.84
0
145

0.193
5.679
0.740
4.30
0.406

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

79725
1.0
4
13288
0.0
0.117


0.92
14.01
2.82
8.33
3.37
20.76
1.01
31.77


83
8.30
8.30
8.30
8.30
116
0
0
116
0.42
2.32
0
119

0.164
4.649
0.607
3.52
0.333
EFFECT OF C.F.
200 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.165
7.494
0.949
3.44
1.474

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13 43
5 44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.338
7.494
1.001
7.24
0 221
EFFECT OF AGE
200 | 200

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.106


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0 268
7 494
o.sao
5 68
0.537

40
10
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.0%

24159
1.0
4
4027
0.0
0.163


1.49
22.59
4.55
13.43
5.44
33 47
1.63
51.23


134
13.33
13.38
13.38
13 38
187
0
a
187
0.57
3.75
0
192

0.268
7.494
0 380
5 58
0.537
F-19
-------
NOx CONTROL COSTS - COAL BOILERS c!4wscrc.wkl

SIR-CON [ROLLED (COLD Slut] • WALL-rtKtu -----------
(Roble. 1991) Case 14| SIZE (HU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft"3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kU-hr) *
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 8. M (mil Is/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) «
LEVELIZEO BUSBAR COST (mills/kW-hr) -
EMISSIONS
-UNCONTROLLED NOx (1b/MM8tu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS (S/ton) -
UNIT
APPLICABLE UNIT PRICING COST
COAL (S/ton) 45.84
OIL (J/bbl) 22.85
GAS (1/1000 ft"3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ft~3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

	 	 . 	 	 	
100 | 200 300 400 | 660

675
0
3217
0

341303

0.172
0.000
0.283
0.583
0.007
1.044

0.000

1.564

1.326
0.714
1.044
1.564
29.72
9.87

0.60
0.10
1519
3700
0.15
1367
4111

1349
0
7978
0

682606

0.172
0.000
0.350
0.583
0.007
1.112

0.000

1.564

0.998
0.537
1.112
1.564
22.53
8.17

0.60
0.10
3038
3062
0.15
2734
3402

2024
0
12739
0

1023909

0.172
0.000
0.373
0.583
0.007
1.135

0.000

1.564

0.847
0.456
1.135
1.564
19.15
7.37

0.60
0.10
4557
2761
0.15
4101
3068

2699
0
17501
0

1365212

0.172
0.000
0.384
0.583
0.007
1.146

0.000

1.564

0.755
0.406
1.146
1.564
17.07
6.87

0.60
0.10
6075
2575
0.15
5468
2862

4453
0
29879
0

2252600

0.172
0.000
0.398
0.583
0.007
1.159

0.000

1.564

0.619
0.333
1.159
1.564
13.97
6.13

0.60
0.10
10025
2298
0.15
9022
2553
EFFECT OF C.F.

	 „. 	 	
	
200 200

830
0
4910
0

420065

0.172
0.000
0.350
0.948
0.011
1.481

0.000

1.564

0.983
1.474
1.481
1.564
22.53
11.93

0.60
0.10
1869
4473
0.15
1682
4969

1702
0
10065
0

861134

0.172
0.000
0.350
0.462
0.005
0.990

0.000

1.564

1.008
0.221
0.990
1.564
22.53
6.92

0.60
0.10
3832
2594
0.15
3449
2882
EFFECT OF AGE


200 | 200

1349
0
7978
0

682606

0.172
0.000
0.350
0.583
0.007
1.112

0.000

1.564

0.998
0.537
1.112
1.564
20.34
7.78

0.60
0.10
3038
2918
0.15
2734
3243

1349
0
7978
0

682606

0.172
0.000
0.350
0.583
0.007
1.112

O.OQQ

1.564

0.998
0.537
1.112
1.564
31.21
9.69

0.60
0.10
3038
3634
0.15
2734
4037


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
8P Chemical. 1991
Robie. 1991
Robie, 1991
Robie. 1991
Robie, 1991
F-40
-------
NOx CONTROL COSTS - COAL BOILERS clStscru.wkl
SCR-UNCONTROLLEO (COLO SIOEJ-TANGENTIAL 	
(Robie. 1991) Case 15) SIZE (HW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (8STP:68F:14.7psia)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ff 3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
Ai •• UAa^Aw
-Ai r neater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) *
-GENERAL FACILITIES (GF) 10% of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 10%
TOTAL PLANT COSTS (TPC) (1991$/kW) »
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991J/kV) -
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) -
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS ($/kU-yr) =
VARIABLE 0 8. M COSTS (imlls/kU-hr) =
=23= =3 sssaxBssaass ==3333333333=33=3 =33= 3333=33=33==
EFFECT OF CAPACITY
100 ISO | 200 300 | 375

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

12080
1.0
4
2013
0.0
0.117


1.96
29.80
6.01
17.73
7.17
44.16
2.16
67.59


177
17.66
17.66
17.66
17.66
247
0
0
247
0.88
4.94
0
253

0.417
9.889
1.312
7.55
0.714
=======

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

18119
1.0
4
3020
0.0
0.117


1.67
25.34
5.11
15.07
6.10
37.55
1.83
57.47


150
15.01
15.01
15.01
15.01
210
0
0
210
0.75
4.20
0
215

0.318
8.408
1.104
6.39
0.604
=333=333

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537
33S53SSS

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

36239
1.0
4
6040
0.0
0.117


1.26
19.20
3.87
11.42
4.62
28.46
1.39
43.56


114
11.38
11.38
11.38
11.38
159
0
0
159
0.57
3.19
0
163

0.218
6.372
0.830
4.82
0.456
3333333S

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

45298
1.0
4
7550
0.0
0.117


1.16
17.56
3.54
10.45
4.23
26.03
1.27
39.84


104
10.41
10.41
10.41
10.41
146
0
0
146
0.52
2.91
0
149

0.198
5.828
0.759
4.41
0.417
========
EFFECT OF C.F.
200 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192
=33=====
0.165
7.494
0.949
3.44
1.474
========

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192
========
0 338
7.494
1.001
7.24
0.221
========
EFFECT OF AGE ;
200 200 i

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.0%

24159
1.0
4
4027
0.0
0.106


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192
==3=333=
0.268
7.494
0.980
5.68
0.537
========

40 '
10
10.0%
0.65
13080
N/A
N/A
N/A

10670 i
0.0% |
1
24159 !
1.0 .
4 !
4027 !
0.0 '
0.163 .


1.49 1
22.59 j
4.55 '
13.43
5.44 .
33.47
1.63 i
51.23
	 1


134 !
13.38
13.38
13.38
13.38 I
187 |
0 :
0 .
187 _
0 67
3.75
0
192

0.268
7 494
0.980
5.68 ,
0 537
========
F-41
-------
NOx CONTROL COSTS - COAL BOILERS clStscru.wkl

oLK-UNWUni KULLtD (COLD 51Ut J*IANiJtNI 1AL -----------
(Robie. 1991) Case 1S| SIZE (HW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (m1lls/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mllls/kW-hr)
-CATALYST (nrills/kV-nr)
-CATALYST WASTE DISPOSAL (mins/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kU-hr)
-GAS (mills/kW-hr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mllls/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) «
LEVELIZED BUSBAR COST (mills/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) *
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS (S/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (S/1000 ft* 3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ff3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

	 „ 	 ....... 	
	 .. 	 ....... 	
100

675
0
3217
0

341303

0.172
0.000
0.283
0.583
0.007
1.044

0.000

1.564

1.326
0.714
1.044
1.564
29.72
9.87

0.60
0.10
1519
3700
0.15
1367
4111
150 200 300 375

1012
0
5598
0

511955

0.172
0.000
0.328
0.583
0.007
1.090

0.000

1.564

1.122
0.604
1.090
1.564
25.27
8.82

0.60
0.10
2278
3306
0.15
2050
3673

1349
0
7978
0

682606

0.172
0.000
0.350
0.583
0.007
1.112

0.000

1.564

0.998
0.537
1.112
1.564
22.53
8.17

0.60
0.10
3038
3062
0.15
2734
3402

2024
0
12739
0

1023909

0.172
0.000
0.373
0.583
0.007
1.135

0.000

1.564

0.847
0.456
1.135
1.564
19.15
' 7.37

0.60
0.10
4557
2761
0.15
4101
3068

2530
0
16310
0

1279886

0.17?
0.000
0.382
0.583
0.007
1.144

0.000

1.564

0.775
0.417
1.144
1.564
17.52
6.98

0.60
0.10
5696
2615
0.15
5126
2906
EFFECT OF C.F.


200 200

830
0
4910
0

420065

0.172
0.000
0.350
0.948
0.011
1.481

0.000

1.564

0.983
1.474
1.481
1.564
22.53
11.93

0.60
0.10
1869
4473
0.15
1682
4969

1702
0
10065
0

861134

0.172
0.000
0.350
0.462
0.005
0.990

0.000

1.564

1.008
0.221
0.990
1.564
22.53
6.92

0.60
0.10
3832
2594
0.15
3449
2882
EFFECT OF AGE


200 200

1349
0
7978
0

682606

0.172
0.000
0.350
0.583
0.007
1.112

0.000

1.564

0.998
0.537
1.112
1.564
20.34
7.78

0.60
0.10
3038
2918
0.15
2734
3243

1349
0
7978
Q

682606

0.172
0.000
0.350
0.583
0.007
1.112

0.000

1.564

0,998
0.537
1.112
1.564
31.21
9.69

0.60
0.10
3038
3634
0.15
2734
4037


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical, 1991
Robie. 1991
Robie, 1991
Robie, 1991
Robie. 1991
F-42
-------
NOx CONTROL COSTS - COAL BOILERS clBtscrc.wkl
SCR-CONTROLLEO (COLO SIDE) - TANGENTIAL 	
(Roble. 1991) Case 16| SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (8STP:68F:14.7psia)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft'3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kU):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Air Hajtor
MI r neater
— Construct! on/ insta 1 1 ati on Laoor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) »
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) • 10%
TOTAL PLANT COSTS (TPC) (1991$/kU) »
-ESCALATION (OX)
-AFOC (OX)
TOTAL PLANT INVESTMENT (1991$/kU) *
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) »
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (S/kW-yr)
-MAINTENANCE COSTS (MC) (J/kW-yr) 4% of TPC
-AOMIN/SUPPORT LABOR (J/kW-yr) 30X of OLf0.4MC
FIXED 0 & M COSTS ($/kW-yr) =
VARIABLE 0 4 M COSTS (mi 1 Is/kW-hr) =
EFFECT OF CAPACITY
100 ISO 200 300 375

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

12080
1.0
4
2013
0.0
0.117


1.96
29.80
6.01
17.73
7.17
44.16
2.16
67.59


177
17.66
17.66
17.66
17.66
247
0
0
247
0.88
4.94
0
253

0.417
9.889
1.312
7.55
0.714

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

18119
1.0
4
3020
0.0
0.117


1.67
25.34
5.11
15.07
6.10
37.55
1.83
57.47


150
15.01
15.01
15.01
15.01
210
0
0
210
0.75
4.20
0
215

0.318
8.408
1.104
6.39
0.604

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

36239
1.0
4
6040
0.0
0.117


1.26
19.20
3.87
11.42
4.62
28.46
1.39
43.56


114
11.38
11.38
11.38
11.38
159
0
0
159
0.57
3.19
0
163

0.218
6.372
0.830
4.82
0.456

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

45298
1.0
4
7550
0.0
0.117


1.16
17.56
3.54
10.45
4.23
26.03
1.27
39.84


104
10.41
10.41
10.41
10.41
146
0
0
146
0.52
2.91
0
149

0.198
5.828
0.759
4.41
0.417
EFFECT OF C.F.
200 | 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
0.0%

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.165
7 494
0.949
3.44
1.474

30
20
10.0%
0.82
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0 67
3.75
0
192

Q 338
7 494
1 001
7 24
0 221
EFFECT OF AGE ,
200 | 200 j

20
30
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.0%

24159
1.0
4
4027
0.0
0.106


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
O.S7
3.75
0
192

0.258
7 494
0.980
5 58
0.537
i
40
10
10.0%!
0.65 '
13080
N/A
N/A
N/A

10670 1
0.0%
i
24159
1.0 '
4
4027 '
0.0 •
0.153


1.49
22.59
4.55
13.43 ;
5.44
33 47
1.53
51.23


134
13.38
13 33
13.38
13.35
137
0
0
137
0 67
3 75
0
192

0.263
7.494
0.930
5.63
0 537
F-43
-------
NOx CONTROL COSTS - COAL BOILERS clStscrc.wkl

MtK-LUNIKULLtU (LULU JiUtJ * lAHvatHllAL -----------
(Robie. 1991) Case 16| SIZE (HW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft"3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (nHlls/kV-hr)
-UREA (mllls/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (m1lls/kU-hr)
-CATALYST WASTE DISPOSAL (nnlls/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) «
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZEO 0 8. M COSTS
-FIXED 0 & M (mi 1 1 s/ktf-hr)
-VARIABLE 0 & M (mills/kV-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES (1/kW-yr) «
LEVELIZED BUSBAR COST (mills/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION {tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (J/1000 ft"3) 2.61
AMMONIA ($/ton) 145.00
UREA (J/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST ($/ff 3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY

	
	 . 	 . 	
100

506
0
3217
0

341303

0.129
0.000
0.283
0.583
0.007
1.001

0.000

1.564

1.326
0.714
1.001
1.564
29.72
9.83

0.45
0.05
1215
4605
0.10
1063
5262
150 200 | 300 | 375

759
0
5598
0

511955

0.129
0.000
0.328
0.583
0.007
1.047

0.000

1.564

1.122
0.604
1.047
1.564
25.27
8.78

0.45
0.05
1823
4112
0.10
1595
4700

1012
0
7978
0

682606

0.129
0.000
0.350
0.583
0.007
1.069

0.000

1.564

0.998
0.537
1 ,069
1.564
22.53
8.12

0.45
0.05
2430
3807
0.10
2126
4351

1518
0
12739
0

1023909

0.129
0.000
0.373
0.583
0.007
1.092

0.000

1.564

0.847
0.456
1.092
1.564
19.15
7.32

0.45
0.05
3645
3432
0.10
3190
3922

1898
0
16310
0

1279886

0.129
0.000
0.382
0.583
0.007
1.101

0.000

1.564

0.775
0.417
1.101
1.564
17.52
6.93

0.45
0.05
4557
3249
0.10
3987
3713
EFFECT OF C.F.


200 | 200

623
0
4910
0

420065

0.129
0.000
0.350
0.948
0.011
1.438

0.000

1.564

0.983
1.474
1.438
1.564
22.53
11.89

0.45
0.05
1496
5570
0.10
1309
6366

1277
0
10065
0

861134

0.129
0.000
0.350
0.462
0.005
0.947

0.000

1.564

1.008
0.221
0.947
1.564
22.53
6.88

0.45
0.05
3066
3223
0.10
2683
3683
EFFECT OF AGE

	
200 200

1012
0
7978
0

682606

0.129
0.000
0.350
0.583
0.007
1.069

0.000

1.564

0.998
0.537
1.069
1.564
20.34
7.74

0.45
0.05
2430
3628
0.10
2126
4146

1012
0
7978
0

682606

0.129
0.000
0.350
0.583
0.007
1.069

0.000

1.564

0.998
0.537
1.069
1.564
31.21
9.65 '

0.45
0.05
2430
4522
0.10
2126
5168


Electric Power Monthly, March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-44
-------
NOx CONTROL COSTS - COAL BOILERS c!7wscrh.wkl
SCR-CONTROLLED (HOT SIDE) - WALL-FIRED 	
(Roble. 1991) Case 17| SIZE (HW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ft~3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ff3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System and Additions
-Flue Gas Heat Exchanger
-Air Heater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) *
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 15X
TOTAL PLANT COSTS (TPC) (1991$/kU) =
-ESCALATION (OX)
-AFDC (OX)
TCTAL PLANT INVESTMENT (1991$/kW) »
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991JAW) »
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 4 M COSTS ($/kW-yr) »
VARIABLE 0 & M COSTS (mills/kW-hr) -
EFFECT OF CAPACITY
100 150 | 200 | 300 | 375

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
2.7X

12080
1.0
4
2013
0.0
0.117


17.72
6.60
7.02
6.01
78.13
1.41
14.47


131
13.14
13.14
13.14
19.70
190
0
0
190
0.66
3.81
0
195

0.417
7.619
1.039
5.90
0.558

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
2.7X

18119
1.0
4
3020
0.0
0.117


15.07
5.61
5.97
5.11
66.43
1.20
12.30


112
11.17
11.17
11.17
16.75
162
0
0
162
0.56
3.24
0
166

0.318
6.478
0.873
4.98
0.471

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
2.7X

24159
1.0
4
4027
0.0
0.117


13.43
5.00
5.32
4.56
59.21
1.07
10.97


100
9.96
9.96
9.96
14.93
144
0
0
144
0.50
2.89
0
148

0.268
5.774
0.773
4.43
0.419

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
2.7X

36239
1.0
4
6040
0.0
0.117


11.42
4.25
4.52
3.87
50.34
0,91
9.32


85
8.46
8.46
8.46
12.70
123
0
0
123
0.42
2.45
0
126

0.218
4.909
0.655
3.76
0.355

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
2.7X

45298
1.0
4
7550
0.0
0.117


10.44
3.89
4.14
3.54
46.05
0.83
8.53


77
7.74
7.74
7.74
11.61
112
0
0
112
0.39
2.25
0
115

0.198
4.490
0.598
3.44
0.325
EFFECT OF C.F.
200 | 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
2.7X

24159
1.0
4
4027
0.0
0.117


13.43
5.00
5.32
4.56
59.21
1.07
10.97


100
9.96
9.96
9.96
14.93
144
0
0
144
0.50
2.89
0
148

0.165
- 5.774
0.742
2.67
1.144

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
2.7X

24159
1.0
4
4027
0.0
0.117


13.43
5.00
5.32
4.56
59.21
1.07
10.97


100
9.96
9.96
9.96
14.93
144
0
0
144
0.50
2.89
0
148

0.338
5.774
0.794
5.66
0.173
EFFECT OF AGE ,
200 | 200

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
2.7X

24159
1.0
4
4027
0.0
0.106


13.43
5.00
5.32
4.56
59.21
1.07
10.97


100
9.96
9.96
9.96
14.93
144
0
0
144
0.50
2.89
0
148

0.268
5.774
0.773
4.43
0.419

40
10
10.0%
0.65
13080
N/A
N/A
N/A i

10670
2.7%;

24159
1.0 •
4
4027
0.0 .
0.163 •


13.43 '
5.00
5.32
4.56
59.21
1.07
10 97


100 ;
9 96 i
9 96 ,
9 96
14.93
144
0 •
0
144 -
0.50
2 89
0
148

0 258
5 774
0 773
4.43 .
0.419
F-45
-------
NOx CONTROL COSTS - COAL BOILERS c!7wscrh.wkl

SuK-CONTKULLtD [nil Slue/ ~ wALL-HKtU -----------
(Robie. 1991) Case 17| SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mi1ls/kW-hr)
-CATALYST (imlls/kV-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hp)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) »
LEVELIZED BUSBAR COST (mills/kW-hr) *
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bb1) 22.85
GAS (J/1000 ft'3) 2.61
AMMONIA ($/ton) 145.00
UREA {$/ton) 220.00
ELECTRICITY ($/kW-hr) - 0.05
CATALYST COST ($/ff 3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR (S/man-hr) 21.45
EFFECT OF CAPACITY


100

675
0
5236
6271



0.172
0.000
0.460
0.583
0.007
1.222

0.505

0.000

1.036
0.558
1.222
0.505
22.90
7.34

0.60
0.15
1367
3058
0.20
1215
3440
150

1012
0
9109
9406



0.172
0.000
0.533
0.583
0.007
1.295

0.505

0.000

0.875
0.471
1.295
0.505
19.47
6.57

0.60
0.15
2050
2735
0.20
1823
3077
200

1349
0
12983
12541



0.172
0.000
0.570
0.583
0.007
1.332

0.505

0.000

0.778
0.419
1.332
0.505
17.35
6.08

0.60
0.15
2734
2533
0.20
2430
2850
300 | 375

2024
0
20731
18812



0.172
0.000
0.607
0.583
0.007
1.369

0.505

0.000

0.660
0.355
1.369
0.505
14.75
5.48

0.60
0.15
4101
2283
0.20
3645
2568

2530
0
26541
23515



0.172
0.000
0.622
0.583
0.007
1.383

0.505

0.000

0.604
0.325
1.383
0.505
13.49
5.19

0.60
0.15
5126
2160
0.20
4557
2431
EFFECT OF C.F.

	
200 | 200

830
0
7990
7718



0.172
0.000
0.570
0.948
0.011
1.701

0.505

0.000

0.763
1.144
1.701
0.505
17.35
9.06

0.60
0.15
1682
3776
0.20
1496
4248

1702
0
16379
15821



0.172
0.000
0.570
0.462
0.005
1.210

0.505

0.000

0.788
0.173
1.210
0.505
17.35
5.09

0.60
0.15
.3449
2121
0.20
3066
2386
EFFECT OF AGE


200 200

1349
0
12983
12541



0.172
0.000
0.570
0.583
0.007
1.332

0.505

0.000

0.778
0.419
1.332
0.505
15.67
5.79

0.60
0.15
2734
2410
0.20
2430
2711

1349
0
12983
12541



0.172
0.000
0.570
0.583 '
0.007
1.332

0.505

Q.OGO

0.778 .
0.419
1.332
0.505
24. 04
7.26

0.60
0.15
2734
3022
0.20
2430
3400


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-46
-------
NOx CONTROL COSTS - COAL BOILERS clStscrh.wkl
SCR-CONTROLLED (HOT SIDE) - TANGENTIAL 	
(Robie. 1991) Case 18 | SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X v»t)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOURATE (8STP:68F:14.7psia){1000 ft~3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991J/ky):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System and Additions
-Flue Gas Heat Exchanger
-Air Heater
-Construction/ Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) »
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (£HOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 15X
TOTAL PLANT COSTS (TPC) (19911/kW) »
-ESCALATION (0%)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) =
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991J/kW) »
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-ADMIN/SUPPORT LABOR (J/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS ($/kW-yr) =

VARIABLE 0 & M COSTS (mills/kU-hr) =
33=X===3333333==========3==33333=3=3===3X==S====:=33
EFFECT OF CAPACITY
100 150 200 | 300 37S

30
20
10. OX
0.6S
13080
N/A
N/A
N/A

10670
2.7X

12080
1.0
4
2013
0.0
0.117


17.72
6.60
7.02
6.01
78.13
1.41


14.47


131
13.14
13.14
13.14
19.70
190
0
0
190
0.66
3.81
0
195

0.417
7.619
1.039
5.90

0.558
3=5==S3

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
2.7X

18119
1.0
4
3020
0.0
0.117


15.07
5.61
5.97
5.11
66.43
1.20


12.30


112
11.17
11.17
11.17
16.75
162
0
0
162
0.56
3.24
0
166

0.318
6.478
0.873
4.98

0.471
3333=3X3

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
2.7X

24159
1.0
4
4027
0.0
0.117


13.43
5.00
5.32
4.56
59.21
1.07


10.97


100
9.96
9.96
9.96
14.93
144
0
0
144
O.SO
2.89
0
148

0.268
5.774
0.773
4.43

0.419
=3533333

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
2.7X

36239
1.0
4
6040
0.0
0.117


11.42
4.25
4.52
3.87
50.34
0.91


9.32


85
8.46
8.46
8.46
12.70
123
0
0
123
0.42
2.45
0
126

0.218
4.909
0.655
3.76

0.355
3333333S

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
2.7X

45298
1.0
4
7550
0.0
0.117


10.44
3.89
4.14
3.54
46.05
0.83


8.53


77
7.74
7.74
7.74
11.61
112
0
0
112
0.39
2.25
0
115

0,198
4.490
0.598
3.44

0.325
===%33==
EFFECT OF C.F.
200 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
2.7X

24159
1.0
4
4027
0.0
0.117


13.43
5.00
5.32
4.56
59.21
1.07


10.97


100
9.96
9.96
9.96
14.93
144
0
0
144
0.50
2.39
0
148

0.165
5.774
0.742
2.57

1.144
33======

30
20
'10. OX
0.82
13080
N/A
N/A
N/A

10670
2.7X

24159
1.0
4
4027
0.0
0.117


13.43
5.00
5.32
4.56
59.21
1.07


10.97


100
9.96
9.96
9.96
14.93
144
0
0
144
0.50
2.39
0
148

0.338
5.774
0.794
5.66

0.173
========
EFFECT OF AGE !
200 200 !

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
2.7X

24159
1.0
4
4027
0.0
0.106


13.43
5.00
5.32
4.56
59.21
1.07


10.97


100
9.96
9.96
9.96
14.93
144
0
0
144
0.50
2.89
0
148

0.268
5 774
0.773
4 43

0.419
========

40 !
10 !
io.o%|
0.65 !
13080 !
N/A :
N/A i
N/A ,

10670
2.7%,

24159 :
1.0
4
4027
0.0 '
0 163


13.43
5.00
5.32
4.56
59.21
1.07


10.97 ;


100 •
9.96 '
9.98
9.96
14.93 ;
144'
a
a
144
0 50
2 39
a
143

0.263
5.774
0.773
4 43

0 419
========
F-47
-------
NOx CONTROL COSTS - COAL BOILERS clStscrh.wkl


(Robie. 1991) Case 18| SIZE (MU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mllls/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kU-hr) *
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/ky-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) »
LEVELIZED BUSBAR COST (mills/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) •
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS (J/ton) -
1 UNIT
APPLICABLE UNIT PRICING | COST
COAL (J/ton) 45.84
OIL (J/bbl) 22.85
GAS (J/1000 ff 3) 2.61
AMMONIA (J/ton) 145.00
UREA (J/ton) 220.00
ELECTRICITY (J/kW-hr) • 0.05
CATALYST COST (J/ff3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY

	
	
100

506
0
5236
6271



0.129
0.000
0.460
0.583
0.007
1.179

0.505

0.000

1.036
0.558
1.179
0.505
22.90
7.30

0.45
0.10
1063
3909
0.15
911
4560
150 200

759
0
9109
9406



0.129
0.000
0.533
0.583
0.007
1.252

0.505

0.000

0.875
0.471
1.252
0.505
19.47
6.52

0.45
0.10
1595
3493
0.15
1367
4076

1012
0
12983
12541



0.129
0.000
0.570
0.583
0.007
1.289

0.505

0.000

0.778
0.419
1.289
0.505
17.35
6.04

0.45
0.10
2126
3234
0.15
1823
3773
300

1518
0
20731
18812



0.129
0.000
0.607
0.583
0.007
1.326

0.505

0.000

0.660
0.355
1.326
0.505
14.75
5.44

0.45
0.10
3190
2912
0.15
2734
3397
375

1898
0
26541
23515



0.129
0.000
0.622
0.583
0.007
1.340

0.505

0.000

0.604
0.325
1.340
0.505
13.49
5.14

0.45
0.10
3987
2755
0.15
3417
3214
EFFECT OF C.F.


200 200

623
0
7990
7718



0.129
0.000
0.570
0.948
0.011
1.658

0.505

0.000

0.763
1.144
1.658
0.505
17.35
9.02

0.45
0.10
1309
4831
0.15
1122
5637

1277
0
16379
15821



0.129
0.000
0.570
0.462
0.005
1.167

0.505

0.000

0.788
0.173
1.167
0.505
17.35
5.05

0.45
0.10
2683
2704
0.15
2299
3154
EFFECT OF AGE


200 200

1012
0
12983
12541



0.129
0.000
0.570
0.583
0.007
1.289

0.505

0.000

0.778
0.419
1.289
0.505
15.67
5.74

0.45
0.10
2125
3076
0.15
1823
3588

1012
0
12983
12541



0.129
0.000
0.570
0.583
0.007
1 289

0.505

O.OOQ

0.778
0.419
1.289
0.505
24 04
7.21

0.45
0.10
2126
3863
0.15
1823
4507


Electric Power Monthly, March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie, 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-48
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST COST
SCR-CONTROLLEO (COLO SIDE) - WALL-FIRED 	
(Robie. 1991) VARY CATALYST COST| SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (8tu/?b)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (0STP:68F:14.7psia){1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft* 3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
_Ai f Maatav*
-Ml r nearer
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) -
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 10X
TOTAL PLANT COSTS (TPC) (1991$/kW) »
-ESCALATION (OX)
-AFOC (OX)
TO'AL PLANT INVESTMENT (1991$/kW) -
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kU) -
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (J/kV-yr)
-MAINTENANCE COSTS (MC) (J/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS (J/kW-yr) '
VARIABLE 0 4 M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 200 300 400 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

12080
1.0
4
2013
0.0
0.117


1.96
29.30
6.01
17.73
7.17
44.16
2.16
67.59


177
17.66
17.66
17.66
17.66
247
0
0
247
0.88
4.94
0
2S3

0.417
9.389
1.312
7.55
0.714

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.33
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

36239
1.0
4
6040
0.0
0.117


1.26
19.20
3.87
11.42
4.62
28.46
1.39
43.56


114
11.38
11.38
11.33
11.38
159
0
0
159
0.57
3.19
0
163

0.218
6.372
0.830
4.82
0.456

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

48318
1.0
4
8053
0.0
0.117


1.13
17.12
3.45
10.18
4.12
25.36
1.24
38.82


101
10.14
10.14
10.14
10.14
142
0
0
142
0.51
2.34
0
145

0.193
5.679
0.740
4.30
0.406

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

79725
1.0
4
13288
0.0
0.117


0.92
14.01
2.82
8.33
3.37
20.76
1.01
31.77


83
8.30
8.30
8.30
8.30
116
0
0
116
0.42
2.32
0
119

0.164
4.649
0.607
3.52
0.333
EFFECT OF C.F.
200 | 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.165
7.494
0.349
3.44
1.474

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0 333
7.494
1.001
7.24
0.221
EFFECT OF AGE
200 200

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.106


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.930
5.68
0.537

40
10
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.0%

24159
1.0
4
4027
0.0
0.163


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.33
187
0
0
187
0.67
3.75
0
192

0.253
7.494
0.330
5.68
0.537
F-49
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST COST

SCn-CON TROLLED (COLD ilUtJ - WALL-rlKtU -----------
(Robie. 1991) VARY CATALYST COST) SIZE (HW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mllls/kV-nr)
-UREA (m111s/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kV-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-nr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mllls/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kV-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) -
LEVELIZED BUSBAR COST (mllls/kW-hr) -
EMISSIONS
*
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
UNIT
APPLICABLE UNIT PRICING COST
COAL (J/ton) 45.84
OIL ($/bbl) 22.85
GAS (S/1000 ft" 3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) ' 0.05
CATALYST COST ($/ft"3) 300.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-nr) 21.45
EFFECT OF CAPACITY

	 . 	 . 	 _ 	
	
100 200 300 400 660

675
0
3217
0

341303

0.172
0.000
0.283
0.265
0.007
0.726

0.000

1.564

1.326
0.714
0.726
1.564
29.72
9.55

0.60
0.10
1519
3580
0.15
1367
3978

1349
0
7978
0

682606

0.172
0.000
0.350
0.265
0.007
0.794

0.000

1.564

0.998
0.537
0.794
1.564
22.53
7.85

0.60
0.10
3038
2943
0.15
2734
3270

2024
0
12739
0

1023909

0.172
0.000
0.373
0.265
0.007
0.817

0.000

1.564

0.847
0.456
0.817
1.564
19.15
7.05

0.60
0.10
4557
2642
0.15
4101
2936

2699
0
17501
0

1365212

0.172
0.000
0.384
0.265
0.007
0.828

0.000

1.564

0.755
0.406
0.828
1.564
17.07
6.55

0.60
0.10
6075
2456
0.15
5468
2729

4453
0
29879
0

2252600

0.172
0.000
0.398
0.265
0.007
0.841

0.000

1.564

0.619
0.333
0.841
1.564
13.97
5.81

0.60
0.10
10025
2179
0.15
9022
2421
EFFECT OF C.F.

--- — ..... — ....
200 | 200

830
0
4910
0

420065

0.172
0.000
0.350
0.431
0.011
0.964

0.000

1.564

0.983
1.474
0.964
1.564
22.53
11.41

0.60
0.10
1869
4279
0.15
1682
4754

1702
0
10065
0

861134

0.172
0.000
0.350
0.210
0.005
0.738

0.000

1.564

1.008
0.221
0.738
1.564
22.53
6.67

0.60
0.10
3832
2500
0.15
3449
2777
EFFECT OF AGE


200 200

1349
0
7978
0

682606

0.172
0.000
0.350
0.265
0.007
0.794

0.000

1.564

0.998
0.537
0.794
1.564
20.34
7.47

0.60
0.10
3038
2799
0.15
2734
3110

1349
0
7978
0

682606

0.172
0.000
0.350
0.265
0.007
0.794

0.000

1.564

0.998
0.537
0.794
1.564
31.21
9.37

Q.6Q
0.10
3033
3514
0.15
2734
3905


Electric Power Monthly, March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-50
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST COST
SCR-CONTROLLED (COLO SIDE) - WALL-FIRED 	
(Robie. 1991) VARY CATALYST COST| SIZE (MW)
801 LER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (8tu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft*3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kV):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage i Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
A i *• Ua» + a»
-Air neater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) =
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 10X
TCTAL PLANT COSTS (TPC) (1991$/kU) =
-ESCALATION (OX)
-AFDC (OX)
TCTAL PLANT INVESTMENT (1991$/kW) =
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TCTAL CAPITAL REQUIREMENT (TCR) (1991J/ky) »
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (J/kW-yr)
-MAINTENANCE COSTS (MC) (J/kW-yr) 4X of TPC
-ADMIN/SUPPORT LABOR ($/kU-yr) 30X of 0L+0.4MC
FIXED 0 & M COSTS ($/kW-yr) =
VARIABLE 0 & M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 200 | 300 400 | 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

12080
1.0
4
2013
0.0
0.117


1.96
29.80
6.01
17.73
7.17
44.16
2.16
67.59


177
17.66
17.66
17.66
17.66
247
0
0
247
0.88
4.94
0
253

0.417
9.889
1.312
7.55
0.714

30
20
10. OX
0.6S
13080
N/A
N/A
N/A

10670
O.OX

24159
• i.o
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

36239
1.0
4
6040
0.0
0.117


1.26
19.20
3.87
11.42
4.62
28.46
1.39
43.56


114
11.38
11.38
11.38
11.38
159
0
0
159
0.57
3.19
0
163

0.218
6.372
0.830
4.82
0.456

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

48318
1.0
4
8053
0.0
0.117


.1.13
17.12
3.45
10.18
4.12
25.36
1.24
38.82


101
10.14
10.14
10.14
10.14
142
0
0
142
0.51
2.84
0
145

0.193
5.679
0.740
4.30
0.406

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

79725
1.0
4
13288
0.0
0.117


0.92
14.01
2.82
8.33
3.37
20.76
1.01
31.77


33
8.30
8.30
8.30
8.30
116
0
0
116
0.42
2.32
0
119

0.164
4.649
0.607
3.52
0.333
EFFECT OF C.F.
200 | 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0 165
7.494
0.949
3.44
1.474

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13 43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.338
7.494
1.001
7.24
0.221
EFFECT OF AGE
200 | 200

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.106


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
137
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.58
0.537

40
10
10.0%
0.65
13080
N/A '
N/A '
N/A

10670
0.0%*

24159
1.0
4
4027
0.0
0.163


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13 33 :
13.38
13.38 •
187
0
0 '
137
0 57
3.75 ,
0
192 ,

0 258
7.494
0.980
5.58
0.527
F-51
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST COST


(Robie. 1991) VARY CATALYST COST) SIZE (HW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MV-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft"3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kV-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mllls/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) «
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (m1lls/kV-hr)
-GAS (mills/kW-hr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) -
LEVELIZED BUSBAR COST (mills/kW-hr) -
EMISSIONS
-UNCONTROLLED NOx (lb/MM8tu)
-LOWER CONTROLLED NOx (lb/MM8tu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS (J/ton) >
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS (S/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (J/1000 ff 3) 2.61
AMMONIA ($/ton) 145.00
UREA (J/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST (J/ff3) 400.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY

	 	 	
	 — 	 	
100

675
0
3217
0

341303

0.172
0.000
0.283
0.354
0.007
0.815

0.000

1.564

1.326
0.714
0.815
1.564
29.72
9.64

0.60
0.10
1519
3614
0.15
1367
4015
200

1349
0
7978
0

682606

0.172
0.000
0.350
0.354
0.007
0.882

0.000

1.564

0.998
0.537
0.882
1.564
22.53
7.94

0.60
0.10
3038
2976
0.15
2734
3306
300

2024
0
12739
0

1023909

0.172
0.000
0.373
0.354
0.007
0.905

0.000

1.564

0.847
0.456
0.905
1.564
19.15
7.14

0.60
• o.io
4557
2675
0.15
4101
2973
400 1 660

2699
0
17501
0

1365212

0.172
0.000
0.384
0.354
0.007
0.916

0.000

1.564

0.755
0.406
0.916
1.564
17.07
6.64

0.60
0.10
6075
2489
0.15
5468
2766

4453
0
29879
0

2252600

0.172
0.000
0.398
0.354
0.007
0.930

0.000

1.564

0.619
0.333
0.930
1.564
13.97
5.90

0.60
0.10
10025
2212
0.15
9022
2457
EFFECT OF C.F.


200 200

830
0
4910
0

420065

0.172
0.000
0.350
0.575
0.011
1.108

0.000

1.564

0.983
1.474
1.108
1.564
22.53
11.56

0.60
0.10
1869
4332
0.15
1682
4814

1702
0
10065
0

861134

0.172
0.000
0.350
0.280
0.005
0.808

0.000

1.564

1.0Q8
0.221
0.808
1.564
22.53
6.74

0.60
0.10
3832
2526
0.15
3449
2806
EFFECT OF AGE


200 | 200

1349
0
7978
0

682606

0.172
0.000
0.350
0.354
0.007
0.882

0.000

1.564

0.998
0.537
0.382
1.564
20.34
7.55

0.60
0.10
3038
2832
0.15
2734
3147

1349
0
7978
0

682606

0.172
0.000
0.350
0.354
0.007
0.882

0.000

1.564

0.998
0.537
0.882
1.564 j
31 21
9 46

0.60
0.10
3038
3548
0.15
2734
394Z


Electric Power Monthly, March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991
Robie. 1991
8P Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-52
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST COST
SCR-CONTROLLEO (COLO SIDE) - WALL-FIRED 	
(Robie. 1991) VARY CATALYST COST| SIZE (MW)
BOILER AND FUEL SPECIFICATIONS

BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kV-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft*3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
Ai v UAA^AV*
-AT r neater
•Construct i on/Installati on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kU) >
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 10X
TOTAL PLANT COSTS (TPC) (1991$/kW) »
-ESCALATION (OX)
-AFOC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) -
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) -
OPERATING AND MAINTENANCE COSTS (0 i M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-ADMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS ($/kW-yr) »
VARIABLE 0 i M COSTS (mi lls/kV-hr) =
EFFECT OF CAPACITY
100 | 200 300 | 400 660


30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

12080
1.0
4
2013
0.0
0.117


1.96
29.80
6.01
17.73
7.17
44.16
2.16
67.59

177
17.66
17.66
17.66
17.66
247
0
0
247
0.88
4.94
0
253

0.417
9.889
1.312
7.55
0.714


30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23

134
13.38
13.38
13.38
' 13.38
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537


30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

36239
1.0
4
6040
0.0
0.117


1.26
19.20
3.87
11.42
4.62
28.46
1.39
43.56

114
11.38
11.38
11.38
11.38
159
0
0
159
O.S7
3.19
0
163

0.218
6.372
0.830
4.82
0.456


30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

48318
1.0
4
8053
0.0
0.117


1.13
17.12
3.45
10.18
4.12
25.36
1.24
38.82

101
10.14
10.14
10.14
10.14
142
0
0
142
0.51
2.84
0
145

0.193
5.679
0.740
4.30
0.406


30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

79725
1.0
4
13288
0.0
0.117


0.92
14.01
2.82
8.33
3.37
20.76
1.01
31.77

83
8.30
8.30
8.30
8.30
116
0
0
116
0.42
2.32
0
119

0.164
4.649
0.607
3.52
0.333
EFFECT OF C.F.
200 200


30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23

134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.165
7.494
0.949
3.44
1.474


30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.53
51.23

134
13.38
13 38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.338
7 494
1.001
7.24
0.221
EFFECT OF AGE
200 200


20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.106


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23

134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537
i
1
i
40 ,
10
10.0%
0.65
13080
N/A i
N/A
N/A

10670 !
0.0%

24159
1.0
4 '
4027 .
0.0 !
0.163 ;


1.49 •
22.59
4 55 >
13.43 •
5.44
33.47
1.63
51.23

134
13.38
13.38
13.38
13.38
187
0
0
187
0.57
3 75
0 ;
192

0 253 .
7.194
0 980
5.58
0 537
F-53
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST COST

M.K-(,UN 1 KULLClf HULL) MUtJ - IMLL-rlKcU -----------
(Rob1«, 1991) VARY CATALYST COST) SIZE (HW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ff 3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mllls/kV-hr)
-UREA (mUls/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kV-hr)
-CATALYST WASTE DISPOSAL (imlls/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) *
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kU-hr)
-GAS (mllls/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M {mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mi 1 Is/kU-Hr)
-FUEL (mllls/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) =
LEVELIZED BUSBAR COST (mills/kW-hr) -
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) «
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION {tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) «
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL (S/bbl) 22.85
GAS ($/1000 ff 3) 2.61
AMMONIA (S/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) • 0.05
CATALYST COST ($/ff 3) 500.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY

	 	
100

675
0
3217
0

341303

0.172
0.000
0.283
0.442
0.007
0.903

0.000

1.564

1.326
0.714
0.903
1.564
29.72
9.73

0.60
0.10
1519
3647
0.15
1367
4052
200 300 400 | 660

1349
0
7978
0

682606

0.172
0.000
0.350
0.442
0.007
0.971

0.000

1.564

0.998
0.537
0.971
1.564
22.53
8.03

0.60
0.10
3038
3009
0.15
2734
3343

2024
0
12739
0

1023909

0.172
0.000
0.373
0.442
0.007
0.993

0.000

1.564

0.847
0.456
0.993
1.564
19.15
7.22

0.60
0.10
4557
2708
0.15
4101
3009

2699
0
17501
0

1365212

0.172
0.000
0.384
0.442
0.007
1.005

0.000

1.564

0.755
0.406
1.005
1.564
17.07
6.73

0.60
0.10
6075
2522
0.15
5468
2803

4453
0
29879
0

2252600

0.172
0.000
0.398
0.442
0.007
1.018

0.000

1.564

0.619
0.333
1.018
1.564
13.97
5.99

0.60
0.10
10025
2245
0.15
9022
2494
EFFECT OF C.F.


200 200

830
0
' 4910
0

420065

0.172
0.000
0.350
0.718
0.011
1.251

0.000

1.564

0.983
1.474
1.251
1.564
22.53
11.70

0.60
0.10
1869
4386
0.15
1682
4874

1702
0
10065
0

861134

0.172
0.000
0.350
0.350
0.005
0.878

0.000

1.564

1.008
0.221
0.878
1.564
22.53
• 6.81

0.60
0.10
3832
2552
0.15
3449
2336
EFFECT OF AGE


200 200

1349
0
7978
0

682606

0.172
0.000
0.350
0.442
0.007
0.971

0.000

1.564

0.998
0.537
0.971
1.564
20.34
7.64

0.60
0.10
3038
2865
0.15
2734
3184

1349
0
7978
0

682606

0.172
0.000
0.350
0.442
0.007
0.971

0.000

1.564

0.998
0.537
0.971
1.564
31.21
9. 55

0.60
0.10
3038
3581
0.15
2734
3979


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-54
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST COST
SCR-CONTROLLED (COLD SIDE) - WALL-FIRED 	
(Roble. 1991) VARY CATALYST COST] SIZE (MU)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (8tu/1b)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (8STP:68F:14.7psia)(1000 ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft~3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Ai f Maa**i>
-MI r neater
-Construct 1 on/ Instal I at 1 on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) >
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 10X
TOTAL PLANT COSTS (TPC) (1991$/kW) »

-ESCALATION (OX)
-AFOC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) -
-ROYALTY ALLOWANCE O.SX of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991J/kW) »
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 i M COSTS ($/kW-yr) -
VARIABLE 0 & M COSTS (mills/kW-nr) -
EFFECT OF CAPACITY
100 200 300 | 400 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

12080
1.0
4
2013
0.0
0.117


1.96
29.80
6.01
17.73
7.17
44.16
2.16
67.59

177
17.66
17.66
17.66
17.66
247

0
0
247
0.38
4.94
0
253

0.417
9.389
1.312
7.55
0.714

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23

134
13.38
13.38
13.38
13.38
187

0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

36239
1.0
4
6040
0.0
0.117


1.26
19.20
3.87
11.42
4.62
28.46
1.39
43.56

114
11.38
11.38
11.38
11.38
159

0
0
159
0.57
3.19
0
163

0.218
6.372
0.830
4.82
0.456

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

48318
1.0
4
8053
0.0
0.117


1.13
17.12
3.45
10.18
4.12
25.36
1.24
38.82

101
10.14
10.14
10.14
10.14
142

0
0
142
0.51
2.84
0
145

0.193
5.679
0.740
4.30
0.406

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

79725
1.0
4
13288
0.0
0.117


0.92
14.01
2.82
8.33
3.37
20.76
1.01
31.77

83
8.30
8.30
8.30
8.30
116

0
0
116
0.42
2.32
0
119

0.164
4 649
0.607
3.52
0.333
EFFECT OF C.F.
200 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23

134
13.38
13.38
13.38
13.38
187

0
0
187
0.67
3.75
0
192

0.165
7.494
0.949
3.44
1.474

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13 43
5 44
33.47
1.63
51.23

134
13.38
13.38
13.38
13.38
187

0
0
187
0.67
3.75
0
192

0 338
7.494
1.001
7.24
0.221
EFFECT OF AGE |
200 | 200 1

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
0.0%

24159
1.0
4
4027
0.0
0.106


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23

134
13.38
13.38
13.38
13.38
187

0
0
187
0.67
3.75
0
192

0.268
7 494
0.980
5 68
0.537
l
40 j
10 ;
10.0%!
0.65 !
13080 !
N/A
N/A ;
N/A
1
10670 !
0.0%;
1
1
24159 !
1.0
4 1
4027 i
0.0 !
0.163 ,


1.49
22.59 ;
4.55 i
13.43 '
5.44 .
33.47 .
1.63
51.23 '

134
13.38
13.38 •
13.38
13.38
187 i
i
0
0 ;
187
0.57
3.75
0
192

0.263
7 494
0.980
5 58
0 537 '
F-55
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST COST


(Robte, 1991) VARY CATALYST COST) SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-nrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kV-nr)
-UREA (mills/kW-hr)
-ELECTRICITY (mllls/kW-nr)
-CATALYST (mills/kV-nr)
-CATALYST WASTE DISPOSAL (mllls/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mllls/kU-hr) «
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mi lls/kW-Hr)
-FUEL (mllls/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) -
LEVELIZED BUSBAR COST (mills/kW-hr) -
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) «
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
1 UNIT
APPLICABLE UNIT PRICING | COST
COAL (J/ton) 45.84
OIL ($/bbl) 22.85
GAS ($/1000 ft~3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST ($/ft"3) 600.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

	
100 | 200 300 400 660

675
0
3217
0

341303

0.172
0.000
0.283
0.530
0.007
0.991

0.000

1.564

1.326
0.714
0.991
1.564
29.72
9.82

0.60
0.10
1519
3680
0.15
1367
4089

1349
0
7978
0

682606

0.172
0.000
0.350
0.530
0.007
1.059

0.000

1.564

0.998
0.537
1.059
1.564
22.53
8.11

0.60
0.10
3038
3042
0.15
2734
3380

2024
0
12739
0

1023909

0.172
0.000
0.373
0.530
0.007
1.082

0.000

1.564

0.847
0.456
1.082
1.564
19.15
7.31

0.60
0.10
4557
2742
0.15
4101
3046

2699
0
17501
0

1365212

0.172
0.000
0.384
0.530
0.007
1.093

0.000

1.564

0.755
0.406
1.093
1.564
17.07
6.82

0.60
0.10
6075
2556
0.15
5468
2839

4453
0
29879
0

2252600

0.172
0.000
0.398
0.530
0.007
1.106

0.000

1.564

0.619
0.333
1.106
1.564
13.97
6.08

0.60
0.10
10025
2278
0.15
9022
2531
EFFECT OF C.F.
	

200 | 200

830
0
4910
0

420065

0.172
0.000
0.350
0.862
0.011
1.395

0.000

1.564

0.983
1.474
1.395
1.564
22.53
11.84

0.60
0.10
1869
4440
0.15
1682
4934

1702
0
10065
0

861134

0.172
0.000
0.350
0.420
0.005
0.948

0.000

1.564

1.008
0.221
0.948
1.564
22 53
6.88

0.60
0.10
3832
2578
0.15
3449
2865
EFFECT OF AGE


200 200

1349
0
7978
0

682606

0.172
0.000
0.350
0.530
0.007
1.059

0.000

1.564

0.998
0.537
1.059
1.564
20.34
7.73

0.60
0.10
3038
2898
0.15
2734
3220

1349
0
7978
0

682606

0.172
0.000
0.350
0.530
0.007
1.059

0.000

1 564

0.998
0.537
1.059
1.564
31.21
9.64

0.60
0.10
3038
3614
0.15
2734
4015


Electric Power Monthly, March 1991
Electric Power Monthly, March 1991
Gas Facts, 1991
Robie, 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-56
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST COST
SCR-CONTROLLEO (COLO SIDE) - WALL-FIRED 	
(Robie. 1991) VARY CATALYST COST) SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS ,
REBURN FRACTION
FLUE GAS FLOVRATE (0STP:68F:14.7psia)(1000 ft*3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kU):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
Ai p Maa + A*
-MI r neaier
-Construct! on/ Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kU) -
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 10X
TOTAL PLANT COSTS (TPC) (1991$/kW) '
-ESCALATION (OX)
-AFDC (OX)

TO'AL PLANT INVESTMENT (199l$/kW) »
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (199U/kW) =
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) (J/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS ($/kW-yr) >
VARIABLE 0 & M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 | 200 | 300 400 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

12080
1.0
4
2013
0.0
0.117


1.96
29.80
6.01
17.73
7.17
44.16
2.16
67.59


177
17.66
17.66
17.66
17.66
247
0
0

247
0.88
4.94
0
253

0.417
9.889
1.312
7.55
0.714

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0

187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

36239
1.0
4
6040
0.0
0.117


1.26
19.20
3.87
11.42
4.62
28.46
1.39
43.56


114
11.38
11.38
11.38
11.38
159
0
0

159
0.57
3.19
0
163

0.218
6.372
0.830
4.82
0.455

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

48318
1.0
4
8053
0.0
0.117


1.13
17.12
3.45
10.18
4.12
25.36
1.24
38.32


101
10.14
10.14
10.14
10.14
142
0
0

142
0.51
2.84
0
145

0.193
5.679
0.740
4.30
0.406

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

79725
1.0
4
13288
0.0
0.117


0.92
14.01
2.82
8.33
3.37
20.76
1.01
31.77


S3
8.30
8.30
8.30
8.30
116
0
0

116
0.42
2.32
0
119

0.164
4.649
0.607
3.52
0.333
EFFECT OF C.F.
200 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0

187
0.67
3.75
0
192

0.165
7.494
0.949
3.44
1.474

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0

187
0.67
3.75
0
192

0.338
7.494
1.001
7 24
0.221
EFFECT OF AGE
200 | 200

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.106


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0

187
0.67
3.75
0
192

0.263
7.494
0.980
5 68
0.537

40
10
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.0%

24159
1.0
4
4027
0.0
0.163


1.49 •
22.59
4.55 •
13.43 :
5.44
33 47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0 !
0 i
1
187 '
0.67
3.75
0
192

0 258
7.494
0 980
5 68
0.537
F-57
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST COST

iLK-CUNIKULLtU (LULU alUCJ " W«UL-rlKtU -----------
(Robi«. 1991) VARY CATALYST COST) SIZE (MU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mllls/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (m11ls/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (itillls/kW-nr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (m11ls/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mllls/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mllls/kW-Hr)
LEVELIZEO CAPITAL CHARGES (J/kW-yr) •
LEVELIZEO BUSBAR COST (mllls/kW-hr) -
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) *
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (S/1000 ft'3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) ' 0.05
CATALYST COST ($/ft"3) 700.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

. 	 	
	 	 	 . 	
100

675
0
3217
0

341303

0.172
0.000
0.283
0.619
0.007
1.080

0.000

1.564

1.326
0.714
1.080
1.564
29.72
9.90

0.60
0.10
1519
3713
0.15
1367
4126
200 300 | 400 | 660

1349
0
7978
0

682606

0.172
0.000
0.350
0.619
0.007
1.148

0.000

1.564

0.998
0.537
1.148
1.564
22.53
8.20

0.60
0.10
3038
3075
0.15
2734
3417

2024
0
12739
0

1023909

0.172
0.000
0.373
0.619
0.007
1.170

0.000

1.564

0.847
0.456
1.170
1.564
19.15
7.40

0.60
0.10
4557
2775
0.15
4101
3083

2699
0
17501
0

1365212

0.172
0.000
0.384
0.619
0.007
1.181

0.000

1.564

0.755
0.406
1.181
1.564
17.07
6.91

0.60
0.10
6075
2589
0.15
5468
2876

4453
0
29879
0

2252600

0.172
0.000
0.398
0.619
0.007
1.195

0.000

1.564

0.619
0.333
1.195
1.564
13.97
6.16

0.60
0.10
10025
2311
0.15
9022
2568
EFFECT OF C.F.


200 200

830
0
4910
0

420065

0.172
0.000
0.350
1.005
0.011
1.538

0.000

1.564

0.983
1.474
1.538
1.564
22.53
11.99

0.60
0.10
1369
4494
0.15
1682
4993

1702
0
10065
0

861134

0.172
0.000
0.350
0.490
0.005
1.018

0.000

1.564

1.008
0.221
1.018
1.564
22.53
6.95

0.60
0.10
3832
2605
0.15
3449
2894
EFFECT OF AGE


200 | 200

1349
0
7978
0

682606

0.172
0.000
0.350
0.619
0.007
1.148

0.000

1.564

0.998
0.537
1.148
1.564
20.34
7.82

0.60
a. 10
3038
2932
0.15
2734
3257

1349
0
7978
Q

682606

0.172
0.000 '
0.350 I
O.S19 :
0.007
1.148

O.OOQ

1.564

0.998 !
0 537
1.148 '
1 564 I
31 21 .
9.73 •

0.6Q
0.10
3038
3647
0.15
2734
4052


Electric Power Monthly, March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie, 1991
Robie. 1991
Robie, 1991
F-58
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST LIFE
SCR-CONTROLLED (COLO SIDE) - WALL-FIRED — 	 	
{Robie. 1991) VARY CATALYST LIFE) SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
RE3URN FRACTION
FLUE GAS FLOURATE (9STP:68F:14.7psia)(1000 ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991JAW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
A 1 *• UA»t^B>
-Ai r neater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) *
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10% of PCC
-PROJECT CONTINGENCY (X of PCC) 10X
TOTAL PLANT COSTS (TPC) (1991$/kW) =
-ESCALATION (0%)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) *
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) *
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kV-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR ($/kV-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS ($/kU-yr) »
VARIABLE 0 & M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 | 200 | 300 400 | 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

12080
1.0
2
2013
0.0
0.117


1.96
29.30
6.01
17.73
7.17
44.16
2.16
67.59


177
17.66
17.66
17.66
17.66
247
0
0
247
0.38
4.94
0
253

0.417
9.389
1.312
7.55
0.714

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
2
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

36239
1.0
2
6040
0.0
0.117


1.26
19.20
3.87
11.42
4.62
28.46
1.39
43.56


114
11.38
11.38
11.38
11.38
159
0
0
159
0.57
3.19
0
163

0.218
6.372
0.830
4.32
0.456

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

48318
1.0
2
8053
0.0
0.117


1.13
17.12
3.45
10.18
4.12
25.36
1.24
38.82


101
10.14
10.14
10.14
10.14
142
0
0
142
0.51
2.84
0
145

0.193
5.679
0.740
4.30
0.406

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

79725
1.0
2
13288
0.0
0.117


0.92
14.01
2.82
8.33
3.37
20.76
1.01
31.77


83
8.30
8.30
8.30
8.30
116
0
0
116
0.42
2.32
0
119

0.164
4.649
0.607
3.52
0.333
EFFECT OF C.F.
200 | 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
o.or.

24159
1.0
2
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.165
7.494
0.949
3.44
1.474

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
2
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.338
7.494
1.001
7 24
0.221
EFFECT OF AGE
200 | 200

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
2
4027
0.0
0.106


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5 58
0.537

40
10
10.0%
0.65
13080
N/A
N/A
N/A

10670
-0.0%

24159
1.0
2
4027
0.0
0.163


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51 23


134
13.38
13.38
13.33
13.33
187
0
G
187
0 57
3.75
0
192

0.268
7 494
0.980
5 63
0.537
F-59
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST LIFE

3LK-COni NULLED (COLD SlUt) - wALL-rlKtU 	 	
(Robie. 1991) VARY CATALYST LIFE) SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mllls/kW-hr)
-CATALYST (mills/kW-nr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) «
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZEO 0 4 M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) «
LEVELIZED BUSBAR COST (mills/kV-nr) -
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS (S/ton) »
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) •
UNIT
APPLICABLE UNIT PRICING COST
COAL (J/ton) 45.84
OIL ($/bbl) 22.85
GAS (J/1000 ff 3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY


100 200 | 300 400 660

675
0
3217
0

341303

0.172
0.000
0.283
1.195
0.014
1.663

0.000

1.564

1.326
0.714
1.663
1.564
29.72
10.49

0.60
0.10
1519
3932
0.15
1367
4369

1349
0
7978
0

682606

0.172
0.000
0.350
1.195
0.014
1.731

0.000

1.564

0.998
0.537
1.731
1.564
22.53
8.79

0.60
0.10
3038
3294
0.15
2734
3660

2024
0
12739
0

1023909

0.172
0.000
0.373
1.195
0.014
1.754

0.000

1.564

0.847
0.456
1.754
1.564
19.15
7.99

0.60
0.10
4557
2993
0.15
4101
3326

2699
0
17501
0

1365212

0.172
0.000
0.384
1.195
0.014
1.765

0:000

1.564

0.755
0.406
1.765
1.564
17.07
7.49

0.60
0.10
6075
2807
0.15
5468
3119

4453
0
29879
0

2252600

0.172
0.000
0.398
1.195
0.014
1.778

0.000

1.564

0.619
0.333
1.778
1.564
13.97
6.75

0.60
0.10
10025
2530
0.15
9022
2811
EFFECT OF C.F.


200 200

830
0
4910
0

420065

0.172
0.000
0.350
1.942
0.022
2.487

0.000

1.564

0.983
1.474
2.487
1.564
22.53
12.94

0.60
0.10
1869
4850
0.15
1682
5388

1702
0
10065
0

861134

0.172
0.000
0.350
0.947
0.011
1.480

0.000

1.564

1.008
0.221
1.480
1.564
22.53
7.41

0.60
0.10
3332
2778
0.15
3449
3087
EFFECT OF AGE


200 200

1349
0
7978
0

682606

0.172
o.ooo-
0.350
1.195
0.014
1.731

0.000

1.564

0.998
0.537
1.731
1.564
20.34
8.40

0.60
0.10
3038
3150
0.15
2734
3500

1349
0
7978
0

682606

0.172
0.000
0.350
1.195
0.014
1.731

0.000

1.564

Q.998
0.537
1.731
1.564
31.21
10.31

0.60
0.10
3038
3866
0.15
2734
4295


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
8P Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-60
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST LIFE
SCR-CONTROLLED (COLO SIDE) - WALL-FIRED 	
(Roble. 1991) VARY CATALYST LIFE| SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER ASE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV { Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X vrt)
GROSS HEAT RATE (Btu/kV-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (8STP:68F:14.7psia)(1000 ft" 3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Ai r Heater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kU) »
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 10%
TO'AL PLANT COSTS (TPC) (1991$/kW) »
-ESCALATION (OX)
-AFDC (OX)
TCTAL PLANT INVESTMENT (1991$/kW) =
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) *
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) (J/kV-yr) 4X of TPC
-ADMIN/SUPPORT LABOR ($/kU-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS (J/kW-yr) =
VARIABLE 0 & M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 | 200 | 300 400 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

12080
1.0
3
2013
0.0
0.117


1.96
29.80
6.01
17.73
7.17
44.16
2.16
67.59


177
17.66
17.66
17.66
17.66
247
0
0
247
0.88
4.94
0
253

0.417
9.889
1.312
7.55
0.714

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
3
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537
========

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

36239
1.0
3
6040
0.0
0.117


1.26
19.20
3.87
11.42
4.62
28.46
1.39
43.56


114
11.38
11.38
11.38
11.38
159
0
0
159
0.57
3.19
0
163

0.218
6.372
0.830
4.82
0.456
SSSS3SSS

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

48318
1.0
3
8053
0.0
0.117


1.13
17.12
3.45
10.18
4.12
25.36
1.24
38.82


101
10.14
10.14
10.14
10.14
142
0
0
142
0.51
2.84
0
145

0.193
5.679
0.740
4 30
0.406
========

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

79725
1.0
3
13288
0.0
0.117


0.92
14.01
2.82
8.33
3.37
20.76
1.01
31.77


83
8.30
8.30
8.30
8.30
116
0
0
116
0.42
2.32
0
119

0.164
4.649
0.607
3.52
0.333
========
EFFECT OF C.F.
200 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
3
4027
0.0
0.117


•1.49
22.59
4 55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.165
7 494
0.949
3.44
1.474
assssssss:

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
3
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.338
7.494
1 001
7 24
0.221
EFFECT OF AGE
200 | 200

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
3
4027
0.0
0.106


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537
========

40
10
10.0%
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
3
4027
0.0
0 163


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51 23


134
13.38
13.38
13.38
13.38
187
a
Q
187
0 67
3.75
Q
192

0.258
7 494
0.980
5.68
0.537
F-61
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST LIFE

JUK-CUN 1 KOLLtU (LULU 31UCJ ~ WMUL-rlKtU --—•----—
(Roble. 1991) VARY CATALYST LIFE| SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MV-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft" 3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mllls/kW-hr)
-UREA (mil1s/kW-hr)
-ELECTRICITY (mills/kV-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mllls/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) *
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kV-hr)
-VARIABLE 0 & M (nrills/kW-Hr)
-CONSUMABLES (mi lls/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) -
LEVELIZEO BUSBAR COST (mills/kW-hr) *
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS (S/ton) '
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) «
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bb1) 22.85
GAS (S/1000 ff 3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

	 	 „
	 .... — .. 	
100 200 300

675
0
3217
0

341303

0.172
0.000
0.283
0.787
0.009
1.251

0.000

1.564

1.326
0.714
1.251
1.564
29.72
10.08

0.60
0.10
1519
3777
0.15
1367
4197

1349
0
7978
0

682606

0.172
0.000
0.350
0.787
0.009
1.318

0.000

1.564

0.998
0.537
1.318
1.564
22.53
8.37

0.60
0.10
3038
3139
0.15
2734
3488

2024
0
12739
0

1023909

0.172
0.000
0.373
0.787
0.009
1.341

0.000

1.564

0.847
0.456
1.341
1.564
19.15
7.57

0.60
0.10
4557
2839
0.15
4101
3154
400 | 660

2699
0
17501
0

1365212

0.172
0.000
0.384
0.787
0.009
1.352

0.000

1.564

0.755
0.406
1.352
1.564
17.07
7.08

0.60
0.10
6075
2653
0.15
5468
2947

4453
0
29879
0

2252600

0.172
0.000
0.398
0.787
0.009
1.366

0.000

1.564

0.619
0.333
1.366
1.564
13.97
6.34

0.60
0.10
10025
2375
0.15
9022
2639
EFFECT OF C.F.

	
200 200

830
0
4910
0

420065

0.172
0.000
0.350
1.279
0.015
1.816

0.000

1.564

0.983
1.474
1.816
1.564
22.53
12.27

0.60
0.10
1869
4598
0.15
1682
5109

1702
0
10065
0

861134

0.172
0.000
0.350
0.624
0.007
1.153

0.000

1.564

1.008
0.221
1.153
1.564
22.53
7.08

0.60
0.10
3832
2655
0.15
3449
2950
EFFECT OF AGE

. . 	
---------------
200 200

1349
0
7978
0

682606

0.172
0.000
0.350
0.787
0.009
1.318

0.000

1.564

0.998
0.537
1.318
1.564
20.34
7.99

0.60
0.10
3038
2996
0.15
2734
3328

1349
0
7978
0

682606

0.172
O.OQO
0.350
0.787
0.009
1
1.318

0.000

1.564

0 998
0.537
1.318
1.564 ;
31.21
9.90

0.60
0.10
3038
3711
0.15
2734
4123


Electric Power Monthly, March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie, 1991
BP Chemical, 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-62
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST LIFE
SCR-CONTROLLEO (COLD SIDE) - WALL-FIRED 	
(Robie, 1991) VARY CATALYST LIFE| SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (8tu/1b)
OIL FRACTION
FUEL ASH CONTENT (X «rt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft" 3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (199U/kW):
-Burners
-Ducting
-Fan Upgrade/ Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-A i v* Uaataf*
Ml r neater
-Construct! on/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCG) (1991J/kW) -
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 10X
TOTAL PLANT COSTS (TPC) (1991$/kW) -
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kU) »
-ROYALTY ALLOWANCE O.SX of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) -
OPERATING AND MAINTENANCE COSTS (0 i M)
'-OPERATING LABOR (OL) (J/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 i M COSTS ($/kW-yr) »
VARIABLE 0 & M COSTS (mills/kW-hr) «
EFFECT OF CAPACITY
100 200 | 300 400 | 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

12080
1.0
4
2013
0.0
0.117


1.96
29.80
6.01
17.73
7.17
44.16
2.16
67.59


177
17.66
17.66
17.66
17.66
247
0
0
247
0.38
4.94
0
253

0.417
9.389
1.312
7.55
0.714

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

36239
1.0
4
6040
0.0
0.117


1.26
19.20
3.87
11.42
4.62
28.46
1.39
43.56


114
11.38
11.38
11.38
11.38
159
0
0
159
0.57
3.19
0
163

0.218
6.372
0.830
4.82
0.456

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

48318
1.0
4
8053
0.0
0.117


1.13
17.12
3.45
10.18
4.12
25.36
1.24
38.82


101
10.14
10.14
10.14
10.14
142
0
0
142
0.51
2.84
0
145

0.193
5.679
0.740
4.30
0.406

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

79725
1.0
4
13288
0.0
0.117


0.92
14.01
2.82
8.33
3.37
20.76
1.01
31.77


83
8.30
8.30
.8.30
8.30
116
0
0
116
0.42
2.32
0
119

0.164
4.649
0.607
3.52
0.333
EFFECT OF C.F.
200 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.165
7 494
0.949
3.44
1.474

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
a
0
187
0.67
3.75
0
192

0.338
7.494
1.001
7 24
0.221
EFFECT OF AGE
200 | 200

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
4
4027
0.0
0.106


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0 258
7.494
0.980
5.68
0.537

40
10
10.0%
0.65
13080
N/A
N/A
N/A

10670
0.0%'

24159
1.0
4
4027 '
0.0 !
0.163 '
I
1
i
1.49 1
22.59
4 55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38 i
13.38 !
13.38 I
187
0
0
187
0.57
3.75
0
192

0 253
7 494
0 380
5.53
0 537
F-63
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST LIFE


(Roble. 1991) VARY CATALYST LIFE) SIZE (HW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft"3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mllls/kW-hr)
. -CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mnis/kW-hr) »
FUEL COSTS
-COAL (ntills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mllls/kW-hr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES (J/kW-yr) »
LEVELIZED BUSBAR £OST {mills/kW-hr) •
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS (J/ton) »
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS (J/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (J/1000 ft"3) 2.61
AMMONIA (J/ton) 145.00
UREA.($/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST (J/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL (J/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY

	
100 200 300 400 | 660

675
0
3217
0

341303

0.172
0.000
0.283
0.583
0.007
1.044

0.000

1.564

1.326
0.714
1.044
1.564
29.72
9.87

0.60
0.10
1519
3700
0.15
1367
4111

1349
0
7978
0

682606

0.172
0.000
0.350
0.583
0.007
1.112

0.000

1.564

0.998
0.537
1.112
1.564
22.53
8.17

0.60
0.10
3038
3062
0.15
2734
3402

2024
0
12739
0

1023909

0.172
0.000
0.373
0.583
0.007
1.135

0.000

1.564

0.847
0.456
1.135
1.564
19.15
7.37

0.60
0.10
4557
2761
0.15
4101
3068

2699
0
17501
0

1365212

0.172
0.000
0.384
0.583
0.007
1.146

0.000

1.564

0.755
0.406
1.146
1.564
17.07
6.87

0.60
0.10
6075
2575
0.15
5468
2862

4453
0
29879
0

2252600

0.172
0.000
0.398
0.583
0.007
1.159

0.000

1.564

0.619
0.333
1.159
1.564
13.97
6.13

0.60
0.10
10025
2298
0.15
9022
2553
EFFECT OF C.F.
	
	

200 200

830
0
4910
0

420065

0.172
0.000
0.350
0.948
0.011
1.481

0.000

1.564

0.983
1.474
1.481
1.564
22.53
11.93

0.60
0.10
1869
4473
0.15
1682
4969

1702
0
10065
0

861134

0.172
0.000
0.350
0.462
0.005
0.990

0.000

1.564

1.008
0.221
0.990
1.564
22.53
6.92

0.60
0.10
3832
2594
0.15
3449
2882
EFFECT OF AGE I
	 1

200 | 200 1

1349
0
7978
0

682606

0.172
0.000
0.350
0.583
0.007
1.112

0.000

1.564

0.998
0.537
1.112
1.564
20.34
7.78

0.60
0.10
3038
2918
0.15
2734
3243

1349
0
7978
Q

682606

0.172 i
0.000
0.350
0.583 '
0.007
1.112
SSSSSSXS i
0.009
,
1.564

3.993
0.537
1.112
1.564
31 21
9.69

Q.60
0.10
3038
3634
0.15
2734
4037


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-64
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST LIFE
SCR-CONTROLLED (COLO SIDE) - WALL-rlRtO — 	 	
(Roble. 1991) VARY CATALYST LIFE) SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ft*3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft~3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991J/kV):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
A i _ UAatam
-AI r neater
-Const ruct i on/ Insta 1 i at i on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) «
-GENERAL FACILITIES (GF) 10% of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 10%
TOTAL PLANT COSTS (TPC) (1991$/kW) »
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kU) -
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kU) *
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-ADMIN/SUPPORT LABOR ($/kU-yr) 30X of OL+0.4MC
FIXED 0 4 M COSTS (J/kW-yr) »
VARIABLE 0 4 M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 | 200 300 | 400 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

12080
1.0
5
2013
0.0
0.117


1.96
29.80
6.01
17.73
7.17
44.16
2.16
67.59

177
17.66
17.66
17.66
17.66
247
0
0
247
0.88
4.94
0
253

0.417
9.889
1.312
7.55
0.714

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
5
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23

134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

36239
1.0
5
6040
0.0
0.117


1.26
19.20
3.87
11.42
4.62
28.46
1.39
43.56

114
11.38
11.38
11.38
11.38
159
0
0
159
0.57
3.19
0
163

0.218
6.372
0.830
4.82
0.456

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

48318
1.0
5
8053
0.0
0.117


1.13
17.12
3.45
10.18
4.12
25.36
1.24
38.82

101
10.14
10.14
10.14
10.14
142
0
0
142
0.51
2.84
0
145

0.193
5.679
0.740
4.30
0.406

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

79725
1.0
5
13288
0.0
0.117


0.92
14.01
2.82
8.33
3.37
20.76
1.01
31.77

83
8.30
8.30
8.30
8.30
116
0
0
116
0.42
2.32
0
119

0.154
4.649
0.607
3.52
0.333
EFFECT OF C.F.
200 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
5
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23

134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.165
7.494
0.949
3.44
1.474

30
20
10.0%
0.82
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
5
4027
0.0
0.117
•

1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23

134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0,338
7.494
1.001
7.24
0.221
S2====S=
EFFECT OF AGE 1
	 1
200 | 200 !

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
5
4027
0.0
0.106


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23

134
13.38
13.38
13.38
13.38
187
0
0
187
0.57
3.75
0
192

0.268
7.494
0.980
5.63
0.537
=z====s=
1
40 i
10 ;
10.0%
0.65
13080 ;
N/A '
N/A
N/A

10670
O.OXj
j
24159 ;
1.0 ;
S '
4027 .
o.o .
0.163 i


1.49
22.59
4.55 •
13.43
5.44
33.47
1.63
51.23

134
13.38 ,
13.38
13.38
13.38 i
187
0
0
187
0.67
3 75
Q
192

0 268
7 494
0.980
5 53
0.537 ,
F-65
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST LIFE

5CK-CUN 1 ROLLtU VLULU alUCJ - wALL-rlKCU ---------
{Robie. 1991) VARY CATALYST LIFE) SIZE (HW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft* 3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (m1l1s/kW-hr)

TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) -
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (nrills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mllls/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (nrills/kV-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) «
LEVELIZED BUSBAR COST (mills/kW-hr) •
EMISSIONS
-UNCONTROLLED NOx (lb/MM8tu)
-LOWER CONTROLLED NOx (Ib/HMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) >
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL (J/bbl) 22.85
GAS (J/1000 ff 3) 2.61
AMMONIA (J/ton) 145.00
UREA ($/ton) • 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ft*3) 660.00
CATALYST SOLID WASTE DISPOSAL (J/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY

	 „ .. 	
	
100 200

675
0
3217
0

341303

0.172
0.000
0.283
0.461
0.005

0.921

0.000

1.564

1.326
0.714
0.921
1.564
29.72
9.75

0.60
0.10
1519
3653
0.15
1367
4059

1349
0
7978
0

682606

0.172
0.000
0.350
0.461
0.005

0.988

0.000

1.564

0.998
0.537
0.988
1.564
22.53
8.04

0.60
0.10
3038
3016
0.15
2734
3351
300

2024
0
12739
0

1023909

0.172
0.000
0.373
0.461
0.005

1.011

0.000

1.564

0.847
0.456
1.011
1.564
19.15
7.24

0.60
0.10
4557
2715
0.15
4101
3017
400 660

2699
0
17501
0

1365212

0.172
0.000
0.384
0.461
0.005

1.022

0.000

1.564

0.755
0.406
1.022
1.564
17.07
6.75

0.60
0.10
6075
2529
0.15
5468
2810

4453
0
29879
0

2252600

0.172
0.000
0.398
0.461
0.005

1.036

0.000

1.564

0.619
0.333
1.036
1.564
13.97
6.01

0.60
0.10
10025
2251
0.15
9022
2502
EFFECT OF C.F.


200 | 200

830
0
4910
0

420065

0.172
0.000
0.350
0.749
0.009

1.280

0.000

1.564

0.983
1.474
1.280
1.564
22.53
11.73

0.60
0.10
1869
4397
0.15
1682
4886

1702
0
10065
0

861134

0.172
0.000
0.350
0.366
0.004

0.892

0.000

1.564

1.008
0.221
0.892
1.564
22.53
6.82

0.60
0.10
3832
2557
0.15
3449
2841
EFFECT OF AGE


200 | 200

1349
0
7978
0

682606

0.172
0.000
0.350
0.461
0.005

0.988

0.000

1.564

0.998
0.537
0.988
1.564
20.34
7.66

0.60
0.10
3038
2872
0.15
2734
3191

1349
0
7978
0

682606

• 0.172
0.000 '
0.350
0.461
0.005

0.988

0.000

1.564

0.998 '
0.537 :
0.988 ;
1.564
31 21 '
9.57

0.60
0.10
3038
3587
0.15
2734
3986


Electric Power Monthly. March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical . 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-66
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST LIFE
SCR-CONTROLLED (COLO SIDE) - WALL-FIRED — 	
(Robie. 1991) VARY CATALYST LIFE) SIZE (MV)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft'3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
» Ai r Moatar*
nir neo tcr
-Construct 1 on/ [ nsta 1 1 at i on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (199l$/ky) -
-GENERAL FACILITIES (GF) 10% of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10% of PCC
-PROJECT CONTINGENCY (X of PCC) 10X
TOTAL PLANT COSTS (TPC) (1991$/kW) *
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) -
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) >
OPERATING AND MAINTENANCE COSTS (0 8. M)
-OPERATING LABOR (OL) (S/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-ADMIN/SUPPORT LABOR (J/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS ($/kV-yr) »
VARIABLE 0 & M COSTS (imlls/kW-hr) =
EFFECT OF CAPACITY
100 | 200 | 300 400 | 660

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

12080
1.0
6
2013
0.0
0.117


1.96
29.80
6.01
17.73
7.17
44.16
2.16
67.59


177
17.66
17.66
17.66
17.66
247
0
0
247
0.88
4.94
0
253

0.417
9.889
1.312
7.55
0.714
=a=a*==

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
6
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.268
7.494
0.980
5.68
0.537
*=S===**

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

36239
1.0
6
6040
0.0
0.117


1.26
19.20
3.87
11.42
4.62
28.46
1.39
43.56


114
11.38
11.38
11.38
11.38
159
0
0
159
0.57
3.19
0
163

0.218
6.372
0.830
4.82
0.456
aaeasasss:*;

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

48318
1.0
6
8053
0.0
0.117


1.13
17.12
3.45
10.18
4.12
25.36
1.24
38.32


ior
10.14
10.14
10.14
10.14
142
0
0
142
0.51
2.84
0
145

0.193
5.679
0.740
4.30
0.406

30
20
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

79725
1.0
6
13288
0.0
0.117


0.92
14.01
2.82
8.33
3.37
20.76
1.01
31.77


83
8.30
8.30
8.30
8.30
116
0
0
116
0.42
2.32
0
119

0.164
4.649
0.607
3.52
0.333
EFFECT OF C.F.
200 | 200

30
20
10. OX
0.40
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
6
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
3.75
0
192

0.165
7.494
0.949
3.44
1.474

30
20
10. OX
0.82
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
6
4027
0.0
0.117


1.49
22.59
4.55
13.43
5.44
33.47
1.53
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.57
3.75
0
192

0.338
7.494
1.001
7 24
0.221
EFFECT OF AGE
200 200

20
30
10. OX
0.65
13080
N/A
N/A
N/A

10670
O.OX

24159
1.0
6
4027
0.0
0.106


1.49
22.59
4.55
13.43
5.44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0.67
' 3.75
0
192

0.258
7.494
0.980
5.68
0 537

40
10
10.0%
0.65
13080
, N/A
N/A
N/A

10670
0.0%

24159
1.0
6
4027
0.0
0.163


1.49
22.59
4.55
13.43
5 44
33.47
1.63
51.23


134
13.38
13.38
13.38
13.38
187
0
0
187
0 67
3.75
Q
192

0.253
7 494
0.960
5 68
0 537
F-67
-------
NOx CONTROL COSTS-COAL BOILERS : VARY CATALYST LIFE


(Rob1«. 1991) VARY CATALYST LIFE| SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft* 3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mllls/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mllls/kW-hr)
-CATALYST (mllls/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZEO 0 1 M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) >
LEVEL I ZED BUSBAR COST (mills/kW-hr) -
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) •
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION {tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (S/1000 ft'3) 2.61
AMMONIA (S/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST ($/ft'3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

	 . 	 	
100 200 300 | 400 | 660

675
0
3217
0

341303

0.172
0.000
0.283
0.380
0.004
0.838

0.000

1.564

1.326
0.714
0.838
1.564
29.72
9.66

0.60
0.10
1519
3622
0.15
1367
4025

1349
0
7978
0

682606

0.172
0.000
0.350
0.380
0.004
0.906

0.000

1.564

0.998
0.537
0.906
1.564
22.53
7.96

0.60
0.10
3038
2985
0.15
2734
3316

2024
0
12739
0

1023909

0.172
0.000
0.373
0.380
0.004
0.929

0.000

1.564

0.847
0.456
0.929
1.564
19.15
. 7.16

0.60
0.10
4557
2684
0.15
4101
2982

2699
0
17501
0

1365212

0.172
0.000
0.384
0.380
0.004
0.940

0.000

1.564

0.755
0.406
0.940
1.564
17.07
6.66

0.60
0.10
6075
2498
0.15
5468
2776

4453
0
29879
0

2252600

0.172
0.000
0.398
0.380
0.004
0.9S3

0.000

1.564

0.619
0.333
0.953
1.564
13.97
5.92

0.60
0.10
10025
2221
0.15
9022
2467
EFFECT OF C.F.


200 | 200

830
0
4910
0

420065

0.172
0.000
0.350
0.617
0.007
1.146

0.000

1.564

0.983
1.474
1.146
1.564
22.53
11.60

0.60
0.10
1869
4347
0.15
1682
4830

1702
0
10065
0

861134

0.172
0.000
0.350
0.301
0.003
0.826

0.000

1.564

1.008
0.221
0.826
1.564
22.53
6.76

0.60
0.10
3832
2533
0.15
3449
2814
EFFECT OF AGE


200 200

1349
0
7978
0

682606

0.172
0.000
0.350
0.380
0.004
0.906

0.000

1.564

0.998
0.537
0.906
1.564
20.34
7.53

0.60
0.10
3038
2841
0.15
2734
3157

1349
0
7978
0

682606
i
1
0.172 \
0.000
0.350
0.380 i
0.004 1
0.906 j

0.000

1.564 <
,
0.993 i
0 537
0.906
1.564 '
31.21 i
9.49 '
'
0.60
0.10
3038
3556
0.15
2734
3952


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
8P Chemical. 1991
Robie, 1991
Robie. 1991
Robie. 1991
Robie. 1991
F-68
-------
                                      APPENDIX G
                                 NOX CONTROL COSTS
                               OIL-/GAS-FIRED BOILERS
       The enclosed spreadsheets include cost estimates for the following cases:

       1.   Burners out of service (BOOS) for wall-fired boilers
       2.   Burners out of service (BOOS) for tangential boilers
       3.   Flue gas recirculation (FOR) for wall-fired boilers
       4.   Flue gas recirculation (FOR) for tangential boilers
       5.   Low-NOx burners (LNB) for wall-fired boilers
       6.   Low-NOx burners (LNB) for tangential boilers
       7.   Burners out of service (BOOS) and flue gas recirculation (FOR) for wall-fired boilers
       8.   Burners out of service (BOOS) and flue gas recirculation (FOR) for tangential boilers
       9.   Low-NOx burners (LNB), flue gas recirculation (FOR), and overfire air (OFA) for wall-
           fired boilers
       10.  Low-NOx burners (LNB), flue gas recirculation (FGR), and overfire air (OFA) for
           tangential boilers
       11.  Selective noncatalytic reduction (SNCR)  for wall-fired boilers (uncontrolled)
       12.  Selective noncatalytic reduction (SNCR)  for tangential boilers (uncontrolled)
       13.  Selective noncatalytic reduction  (SNCR) for wall-fired boilers (with combustion
           controls)
       14.  Selective noncatalytic reduction  (SNCR) for tangential boilers (with combustion
           controls)
       15.  Selective catalytic reduction (SCR) for wall-fired boilers (uncontrolled)
       16.  Selective catalytic reduction (SCR) for tangential boilers (uncontrolled)
       17.  Selective catalytic reduction (SCR) for wall-fired boilers (controlled)
       18.  Selective catalytic reduction (SCR) for tangential boilers (with combustion controls)

       Uncontrolled NOX is taken as the average of pre- and post-NSPS current baseline emission
levels (see Table 3-3). For wall-fired retrofit cost cases, the average emission levels for wall- and
opposed-fired boilers are  used. For combustion-controlled NOX emission levels, the average of the
range provided in Table 4-7 for both pre- and post-NSPS boilers is used as a representative control
NOX target.  For FGT controls, the average controlled level is taken from Table 4-10.
                                          -G-l
-------
NOx CONTROL COSTS - GAS/OIL BOILERS glwboos.wkl
BOOS - WALL-FIRED UNITS 	
(Hormlle. 1987) Case 1 | SIZE (MV)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft' 3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kU):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Ai r Heater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) =
-GENERAL FACILITIES (GF) 10% of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 30X
TOTAL PLANT COSTS (TPC) (1991J/kW) =
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) »
-ROYALTY ALLOWANCE O.OX of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991J/kW) =
OPERATING AND MAINTENANCE COSTS (0 i M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR (S/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS ($/kW-yr) =
VARIABLE 0 & M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 | 200 400 | 600 850

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

11706
0.0
0
0
0.0
0.104













0.48
0.05
0.05
0.05
0.17
0.8
0
0
0.8
0.000
0.016
0
0.81

0.256
0.032
0.081
0.148
0.063

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

23413
0.0
0
0
0.0
0.104













0.36
0.04
0.04
0.04
0.13
0.6
0
0
0.6
0.000
0.012
0
0.61

0.165
0.024
0.052
0.097
0.041

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

46826
0.0
0
0
0.0
0.104













0.27
0.03
0.03
0.03
0.10
0.5
0
0
0.5
0.000
0.009
0
0.47

0.119
0.018
0.038
0.070
0.030

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

70239
0.0
0
0
0.0
0.104













0.23
0.02
0.02
0.02
0.08
0.4
0
0
0.4
0.000
0.008
0
0.40

0.104
0.016
0.033
0.061
0.026

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

99505
0.0
0
0
0.0
0.104













0.20
0.02
0.02
0.02
0.07
0.3
0
0
0.3
0.000
0.007
0
0.34

0.095
0.014
0.030
0.055
0.024
EFFECT OF C.F.
200 200

25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
0.3X

23413
0.0
0
0
0.0
0.104













0.36
0.04
0.04
0.04
0.13
0.6
0
0
0.6
0.000
0.012
0
0.61

0.041
0.024
0.015
0.008
0.083

25
35
10. OX
0.65
N/A
22000
18200
0.65

10670
0.3X

23413
0.0
0
0
0.0
0.104













0.36
0.04
0.04
0.04
0.13
0.5
0
0
0.6
0.000
0.012
0
0.61

0.268
0.024
0.083
0 244
0 023
EFFECT OF AGE '.
200 | 200 i

15
45
10.0%
0.40
N/A
22000
18200
0.65

10670
0.3X

23413
0.0
0
0
0.0
0.101













0.36
O.fl4
0.04
0.04
0.13
0.6
0
0
0.6
0.000
0.012
0
0 61

0.165
0.024
0.052
0.097
0 041

40 •
20 ;
10.0%
0.40 i
N/A :
22000
18200
0.65 ,
1
10670 :
0.3%
I
23413
0.0 .
0
0
0.0 i
0.117













0.36
0.04
0.04
0.04
0.13
0.6
0 .
0 i
0.6
0.000
0.01Z
0
0.61

0 165
0.024
0 052
0.097
0 041
G-3
-------
NOx CONTROL COSTS - GAS/OIL BOILERS glwboos.wkl

OUUl - WALL-rlKtU UNI la
(Hormile. 1987) Case 1 | SIZE (HW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MV-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel
-AMMONIA (mills/kW-hr)
-UREA (mllls/kW-hr)
-ELECTRICITY (mills/kV-hr)
-CATALYST (mllls/kV-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES (J/kW-yr) *
LEVELIZED BUSBAR COST (mills/kW-hr) '
EMISSIONS
-UNCONTROLLED NOx (lb/MM8tu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) *
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) =
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL (J/bbl) 22.85
GAS ($/1000 ft'3) 2.61
AMMONIA ($/ton) 145.00
UREA (S/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ft'3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY
	
	

100 200

0
0
0
0
1192
3879

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.042
0.063
0.000
0.107
0.08
0.24

0.45
0.30
280
295
0.35
187
442

0
0
0
0
2384
7758

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.028
0.041
0.000
0.107
0.06
0.19

0.45
0.30
561
242
0.35
374
363
400

0
0
0
0
4769
15517

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.020
0.030
0.000
0.107
0.05
0.17

0.45
0.30
1122
213
0.35
748
319
600 1 850

0
0
0
0
7153
23275

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.017
0.026
0.000
0.107
0.04
0.16

0.45
0.30
1682
202
0.35
1122
303

0
0
0
0
10134
32973

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.016
0.024
0.000
0.107
0.04
0.16

0.45
0?30
2383
195
0.35
1589
293
EFFECT OF C.F.


200 200

0
0
0
0
596
1940

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.009
0.083
0.000
0.107
0.06
0.27

0.45
0.30
140
339
0.35
93
509

0
0
0
0
3875
12607

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.043
0.023
0.000
0.107
0.06
0.18

0.45
0.30
911
230
0.35
608
344
EFFECT OF AGE

	
	
200 200

0
0
0
0
2384
7758

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.028
0.041
0.000
0.107
0.06
0 19

0.45
0.30
561
242
0.35
374
362

0
0
0
0
2384
7758

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.023
0.041
0.000
0.107
0.07
0.20

0.45
0.3Q
561
245
0.35
374
368


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
G-4
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gZtboos.wkl
BOOS - TANGENTIAL-FIRED UNITS 	
(Mormile. 1987) Case 2 | SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (8tu/lb)
NATURAL GAS HHV (Btu/1b)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/ky-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ft" 3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ff 3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Rep i ace
-Structural
-Reagent Storage & Distribution
HaUflw D«a(«^rt*«/Pa^al uet
-uewux Keactor/Ldta i yst
-Control System
-Flue Gas Heat Exchanger
A * — Uaa + ttv*
-Ai r neater
-Construct! on/Installati on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) »
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 30%
TOTAL PLANT COSTS (TPC) (1991$/kW) »
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991J/kW) »
-ROYALTY ALLOWANCE O.OX of PCC
-PREPRODUCTION COSTS 2% of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) =
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (J/kV-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR (S/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS (J/kW-yr) =
VARIABLE 0 & M COSTS (mi 11 s/kW-hr) =
EFFECT OF CAPACITY
100 | 200 400 | 600 900

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

11706
0.0
0
0
0.0
0.104












0/48
0.05
0.05
0.05
0.17
0.8
0
0
0.8
0.000
0.016
0
0.81

0.256
0.032
0.081
0.148
0.063

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

23413
0.0
0
0
0.0
0.104












0.36
0.04
0.04
0.04
0.13
0.6
0
0
0.6
0.000
0.012
0
0.61

0.165
0.024
0.052
0.097
0.041

25
35
10. OX
0.40
N/A
22000
13200
0.65

10670
0.3X

46826
0.0
0
0
0.0
0.104












0.27
0.03
0.03
0.03
0.10
0.5
0
0
0.5
0.000
0.009
0
0.47

0.119
0.018
0.038
0.070
0.030

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

70239
0.0
0
0
0.0
0.104












0.23
0.02
0.02
0.02
0.08
0.4
0
0
0.4
0.000
0.008
0
0.40

0.104
0.016
0.033
0.061
0.026

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

105358
0.0
0
0
0.0
0.104












0.20
0.02
0.02
0.02
0.07
0.3
0
0
0.3
0.000
0.007
0
0.34

0 094
0.013
O.Q30
0.055
0.023
EFFECT OF C.F.
200 | 200

25
35
10.0%
0.10
N/A
22000
13200
0.65

10670
0.3%

23413
0.0
0
0
0.0
0.104












0.36
0.04
0.04
0.04
0.13
0.6
0
0
0.6
0.000
0.012
0
0.61

0.041
0.024
0.015
0.008
Q.Q83

25
35
10. OX
0.65
N/A
22000
18200
0.65

10670
0.3X

23413
0.0
0
0
0.0
0.104












0.36
0.04
0.04
0.04
0.13
0.6
0
0
0.6
0.000
0.012
0
0.61

0 263
0.024
0.083
0.244
0.023
EFFECT OF AGE
200 200

15
45
10.0%
0.40
N/A
22000
18200
0.65

10670
0.3%

23413
0.0
0
0
0.0
0.101












0.36
0.04
0.04
0.04
0.13
0.5
0
0
0.6
0.000
0.012
0
0 61

0.165
0.024
0.052
0 097
0.041

40
20
10. OX.
0.40
N/A
22000
18200
0.65

10670
0 . 3°/.

23413
O.Q
0
0
0.0
0.117












0.36
0.04
Q.04
0 04
0.13
0 6
a
0
0 6
0 000
Q.012
,1
0 61

0 155
0 02-1
0.052
0 :97
0.041
G-5
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gZtboos.wkl
(Mormile. 1987) Case 2 | SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft* 3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (m111s/kW-hr)
-ELECTRICITY (mills/kV-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kV-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) -
LEVELIZED BUSBAR COST (mills/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION { tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) *
-HIGHER CONTROLLED NOx (lb/MM8tu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL (J/ton) 45.84
OIL ($/bbl) 22.85
GAS (J/1000 ff 3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST (J/ft'3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY
100 200 400 | 600 | 900

0
0
0
0
1192
3879

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.042
0.063
0.000
0.107
0.08
0.24

0.30
0.20
187
442
0.25
93
884

0
0
0
0
2384
7758

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.028
0.041
0.000
0.107
0.06
0.19

0.30
0.20
374
363
0.25
187
726

0
0
0
0
4769
15517

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.020
0.030
0.000
0.107
0.05
0.17

0.30
0.20
748
319
0.25
374
639

0
0
0
0
7153
23275

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.017
0.026
0.000
0.107
0.04
0.16

0.30
0.20
1122
303
0.25
561
607

0
0
0
0
10730
34912

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.016
0.023
0.000
0.107
0.03
0.16

0.30
0.20
1682
292
0.25
341
583
EFFECT OF C.F.
200 200

0
0
0
0
596
1940

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.009
0.083
0.000
0.107
0.06
0.27

0.30
0.20
93
509
0.25
47
1017

0
0
0
0
3875
12607

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.043
0.023
0.000
0.107
0.06
0.18

0.30
0.20
608
344
0.25
304
689
EFFECT OF ASE
200 200 >

0
0
0
0
2384
7758

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.078
0.029

0.028
0.041
0.000
0.107
0.06
0.19

0.30
0.20
374
362
0.25
187
725

0 •
0 '
Q
0
2384 ;
7753 '

0.000 '
0.000
0.000
0.000 .
0.000 .
0.000

0.000
0.078
0 029

0.028
0.041
0.000
0.107
0.07
0.20 ;

0.30 !
0.20
374
368
O.Z5
187
735


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Roble. 1991
8P Chemical. 1991
Robie. 1991
Robie. 1991
Robie, 1991
Robi'e. 1991
G-6
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gSwfgr.wkl
P5R - WALL-rlKtD UNITS ------ — ---
(Mormile. 1987) Case 3 | SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (8tu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOURATE (9STP:68F:14.7ps1a)(1000 ft~3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft' 3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kV):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
nAunw Daar»tnp* /f*a+" al we^
-uenux KeackOr/Lata i ysi
-Control System
-Flue Gas Heat Exchanger
-Air Heater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kU) «
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 30X
TOTAL PLANT COSTS (TPC) (1991$/kW) =
-ESCALATION (OX)
-AFDC (OX)
'OTAL PLANT INVESTMENT (1991$/kW) »
-ROYALTY ALLOWANCE O.OX of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) »
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kV-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-ADMIN/SUPPORT LABOR ($/kW-yr) 30X of QL+0.4MC
FIXED 0 & M COSTS (J/ktf-yr) *
VARIABLE 0 4 M COSTS (mi lls/kU-hr) =
EFFECT OF CAPACITY
100 | 200 | 400 600 | 850

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

11706
0.0
0
0
0.0
0.104














7.76
0.78
0.78
0.78
2.79
12.9
0
0
12.9
0.000
0.258
0
13.1

0.256
0.515
0.139
0.364
0.156

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

23413
0.0
0
0
0.0
0.104














5.88
0.59
0.59
0.59
2.12
9.8
0
0
9.8
0.000
0.195
0
10.0

0.165
0.390
0.096
0.261
0.112

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

46826
0.0
0
0
0.0
0.104














4.46
0.45
0.45
0.45
1.60
7.4
0
0
7.4
0.000
0.148
0
7.5

0.119
0.296
0.071
0.194
0.083

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

70239
0.0
0
0
0.0
0.104














3.79
0.38
0.38
0.38
1.36
6.3
0
0
6.3
0.000
0.126
0
6.4

0.104
0.252
0.061
0.167
0.071

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

99505
0.0
0
0
0.0
0.104














3.30
0.33
0.33
0.33
1.19
5.5
0
0
5.5
Q.OOO
0.109
0
5.6

0.095
0.219
0.055
0.147
0.063
EFFECT OF C.F.
200 200

25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
O.OX

23413
0.0
0
0
0.0
0.104














5.83
0.59
0.59
0.59
2.12
9.3
0
0
9.8
0.000
0.195
0
10.0

0.041
0.390
0.059
0 049
0.5Q4

25
35
10. OX
0.65
N/A
22000
18200
0.65

10670
O.OX

23413
0.0
0
0
0.0
0.104














5.38
0.59
0.59
0 59
2.12
9.8
0
0
9.8
0.000
0.195
0
10.0

0.258
0.390
0.127
0 511
0.048
EFFECT OF AGE
200 | 200

15
45
10.0%
0.40
N/A
22000
18200
0.65

10670
0.0%

23413
0.0
0
0
0.0
0.101














5.88
0.59
0.59
0.59
2.12
9.3
0
0
9.8
0 000
0.195
0
10 0

0.165
0.390
0.096
0.261
0 112

40
20
10.0'/.
0.40
N/A
22000
13200
0.55

10670
0 . 0%

23413
0.0
0
0
0 0
0.117














5.38
0.59
0.59
0.59
2.12
9.3
Q
0
9.8
0 OQO
0 195
G
10 a

0.165
0.390
Q.C96
0 251
0 112
G-7
-------
NOx CONTROL COSTS - GAS/OIL BOILERS g3wfgr.wkl
FGK - WALL-FIRED UNITS
(Mormile. 1987) Case 3 | SIZE (HU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA {tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (m1lls/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELI2ED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) *
LEVELIZED BUSBAR COST (mills/kW-hr) *
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) •
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
1 UNIT
APPLICABLE UNIT PRICING | COST
COAL ($/ton) 45.84
OIL (J/bbl) 22.35
GAS (J/1000 ft"3) ' 2. SI
AMMONIA (J/ton) 145.00
UREA ($/ton) • 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST (J/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL (J/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY
100 | 200 400 | 600 850

0
0
155
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
Q.OOQ

0.104
0.156
0.022
0.000
1.36
0.67

0.45
0.25
374
628
0.35
187
1257

0
0
309
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
0.000

0.074
0.112
0.022
0.000
1.03
0.50

0.45
0.25
748
471
0.35
374
942

0
0
618
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
Q.QQO

0.055
0.083
0.022
0.000
0.78
0.38

0.45
0.25
1496
360
0.35
748
720

0
0
927
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
0.000

0.048
0.071
0.022
0.000
0.67
0.33

0.45
0.25
2243
310
0.35
1122
620

0
0
1314
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
0.000

0.042
0.063
0.022
0.000
0.58
0.29

0.45
0.25
3178
274
0.35
1589
548
EFFECT OF C.F.
200 200

0
0
77
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
O.QQO

0.056
0.504
0.022
0.000
1.03
1.76

0.45
0.25
187
1650
0.35
93
3300

0
0
502
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
0.000

0.090
0.048
0.022
0.000
1.03
0.34

0.45
0.25
1215
320
0.35
608
640
EFFECT OF AGE
200 200

0
0
309
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022
,
0.000
0.000
Q.QOO

0.074
0.112
0.022
0.000
1.01
0.50

0.45
0.25
748
465
0.35
374
930

0
0
309
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
o.ooa
0.000

0.074
0.112
0.022
a. ooo
1 17
0 54

Q.45
0.25
748
508
0.35
374
1015


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts, 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
G-8
-------
NOx CONTROL COSTS - GAS/OIL BOILERS g4tfgr.wkl
FGR - TANGENTIAL-FIRED UNITS 	
(Mormile. 1987) Case 4 | SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOURATE (8STP:68F:14.7psia)(1000 ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ff 3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
ftaflftv D ««(•*«•• / f* a^ a 1 \jc^
-uenux Keactor/ Lata i yst
-Control System
-Ftue Gas Heat Exchanger
A i *• UAa^a«>
-fti r neater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (199U/kW) »
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 30%
TOTAL PLANT COSTS (TPC) (199l$/kW) -
-ESCALATION (0%)
-AFDC (0%)
TOTAL PLANT INVESTMENT (1991$/kU) =
-ROYALTY ALLOWANCE 0.0% of PCC
-PREPROOUCTION COSTS 2% of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (199l$/kW) =»
OPERATING AND MAINTENANCE COSTS (0-& M)
-OPERATING LABOR (OL) {J/kW-yr)
-MAINTENANCE COSTS (MC) (J/kV-yr) 4% of TPC
-ADMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS (J/kW-yr) =
VARIABLE 0 & M COSTS (mills/kW-hr) =
= = = aE333S3S3SSS3333S3SSS.2=::sa:32tK3SS = = = 5SS:± = = S ========
EFFECT OF CAPACITY
100 200 | 400 600 | 900

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

11706
0.0
0
0
0.0
0.104












7.76
0.78
0.78
0.78
2.79
12.9
0
0
12.9
0.000
0.258
0
13.1

0.256
0.515
0.139
0.364
Q.156
=3====s

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

23413
0.0
0
0
0.0
0.104












5.88
0.59
0.59
0.59
2.12
9.8
0
0
9.8
0.000
0.195
0
10.0

0.165
0.390
0.096
0.261
0.112
========

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.0%

46826
0.0
0
0
0.0
0.104












4.46
0.45
0.45
0.45
1.60
7.4
0
0
7.4
0.000
0.148
0
7.5

0.119
0.296
0.071
0.194
0.083
========

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

70239
0.0
0
0
0.0
0.104












3.79
0.38
0.38
0.38
1.36
6.3
0
0
6.3
0.000
0.126
0
6.4

0.104
0.252
0.061
0.167
0.071
=S===333

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

105358
0.0
0
0
0.0
0.104












3.22
0.32
0.32
0.32
1.16
5.3
0
0
5.3
0.000
0.107
0
5.5

0.094-
0.214
0.054
0.145
0.062
====a==3
EFFECT OF C.F.
200 200

25
35
10.0%
0.10
N/A
22000
18200
0.65

10670
0.0%

23413
0.0
0
0
0.0
0.104












5.88
0.59
0.59
0.59
2.12
9.8
0
0
9.8
0.000
0.195
0
10.0

"0.041
0.390
0.059
0.049
0.504
========

25
35
10.0%
0.65
N/A
22000
18200
0.65

10670
0.0%

23413
0.0
0
0
0.0
0.104












5.88
0.59
0.59
0.59
2.12
9.8
0
0
9.8
0 000
0.195
0
10.0

0.268
0.390
0.127
0.511
0.048
========
EFFECT OF AGE
200 | 200 ,

15
45
10.0%
0.40
N/A
22000
18200
0.65

10670
0.0%

23413
0.0
0
0
0 0
0.101












5.88
0.59
0.59
0.59
2.12
9.8
0
0
9.3
0.000
0.195
0
10.0

0.165
0 390
0.096
0.261
0.112
i
40
20
10.0%
0.40
N/A
22000
18200
0.65

10670
0.0%,

23413
0.0
0 i
0
0.0
0.117












s.aa
0.59
0 59
0 59
2.12
9 a
0
0
9. a
0 000
0.195
0
10.0

0 165
0 390
0 096
0 261
0.112
======== ========
G-9
-------
NOx CONTROL COSTS - GAS/OIL BOILERS g4tfgr.wkl


( Monni le. 1987) Case 4 | SIZE (MU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft"3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel
-AMMONIA (mills/kW-nr)
-UREA (mllls/kU-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kU-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mllls/kW-hp)
-GAS (mllls/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mllls/kU-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) -
LEVELIZED BUSBAR COST (mills/kW-hr) «
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) *
UNIT
APPLICABLE UNIT PRICING COST
COAL (J/ton) 45.84
OIL (J/bbl) 22.85
GAS (S/1000 ft" 3) 2.61
AMMONIA ($/ton) • 145.00
UREA ($/ton) 220.00
ELECTRICITY (S/kW-hr) 0.05
CATALYST COST (S/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY

	 	
100 200 | 400 600 900

0
0
155
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
0.000

0.104
0.156
0.022
0.000
1.36
0.67

0.30
0.20
187
1257
0.25
93
2514

0
0
309
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
0.000

0.074
0.112
0.022
0.000
1.03
0.50

0.30
0.20
374
942
0.25
187
1884

0
0
618
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
0.000

0.055
0.083
0.022
0.000
0.78
0.38

0.30
0.20
748
'720
0.25
374
1440

0
0
927
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
0.000

0.048
0.071
0.022
0.000
0.67
0.33

0.30
0.20
1122
620
0.25
561
"1240

0
0
1391
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
O.QQO

0.041
0.062
0.022
0.000
0.57
0.29

0.30
0.20
1682
537
0.25
841
1074
EFFECT OF C.F.


200 200

0
0
77
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
0.000

0.056
0.504
0.022
0.000
1.03
1.76

0.30
0.20
93
3300
0.25
47
6600

0
0
502
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
O.QOO

0.090
0 048
0.022
0.000
1.03
0.34 .

0.30
0.20
608
640
0.25
304
1279
EFFECT OF AGE


200 200

0
0
309
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
Q.QOO

0.074
0.112
0.022
0.000
1.01
0.50

0.30
0.20
374
930
0.25
187
1860

0
0
309
0
0
0

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.000
o.ooa

0.074
0.112
0.022
0.000
1.17
0.54

0.30
0.20
374
1015
0.25
187
2031


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
8P Chemical, 1991
Robie. 1991 - -
Robie. 1991
Robie. 1991
Robie. 1991
G-10
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gSwlnb.wkl
LN8 - WALL-FIRED UNITS 	
(Mormile. 1987) . Case 5 | SIZE (MV)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (0STP:68F:14.7psia)(1000 ff3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft'3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
n_UAv Daa/»tn»*/r*a+a1 uet
-LJenUX KeactQr/uata 1 ySt
-Control System
•Fl us Gas Heat Exchanger
-Ai f Haatar-
~Hi r neater
"Construct! on/ Insta 1 1 at i on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) «
-GENERAL FACILITIES (GF) 10% of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 30X
TOTAL PLANT COSTS (TPC) (1991$/kW) =
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991 JAW) =
-ROYALTY ALLOWANCE O.OX of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) *
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (J/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR (J/kW-yr) 30X of OL+0.4MC
FIXED 0 4 M COSTS (J/kW-yr) =
VARIABLE 0 i M COSTS (mi 1 1 s/kW-hr) »
EFFECT OF CAPACITY
100 200 400 | 600 850

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

11706
0.0
0
0
0.0
0.104












22.12
2.21
2.21
2.21
7.96
36.7
0
0
36.7
0.000
0.734
0
37.45

0.256
1.469
0.253
0.791
0.339

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

23413
0.0
0
0
0.0
0.104












16.76
1.68
1.68
1.68
6.03
27.8
0
0
27.8
0.000
0.556
0
28.38

0.165
1.113
0.183
0.584
0.250

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

46826
0.0
0
0
0.0
0.104












12.70
1.27
1.27
1.27
4.57
21.1
0
0
21.1
0.000
0.422
0
21.51

0.119
0.843
0.137
0.440
0.188

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

70239
0.0
0
0
0.0
0.104












10.80
1.08
1.08
1.08
3.89
17.9
0
0
17.9
0.000
0.359
0
18.29

0.104
0.717
0.117
0.375
0.161

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

99505
0.0
0
0
0.0
0.104












9.40
0.94
0.94
0.94 •
3.38
15.6
0
0
15.6
0.000
0.312
0
15.91

0.095
0.624
0.103
0.329
0.141
EFFECT OF C.F.
200 200

25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
O.OX

23413
0.0
0
0
0.0
0.104












16.76
1.68
1.68
1.68
6.03
27.8
0
0
27.8
0.000
0.556
0
28.38

0.041
1.113
0 146
0.130
1.336

25
35
10. OX
0.65
N/A
22000
18200
0.65

10670
O.OX

23413
0.0
0
0
0.0
0.104












16.76
1.68
1.68
1.68
6.03
27.8
0
0
27 8
0.000
0.556
0
28.33

0.268
1.113
0.214
1 037
0 098
EFFECT OF AGE
200 | 200

15
45
10. OX
0.40
N/A
22000
18200
0.65

10670
0.0%

23413
0.0
0
0
0.0
0.101












16.75
1.68
1.68
1.68
6.03
27.8
0
0
27.8
0.000
0.556
0
28 38

0.155
1 113
0 183
0.584
o.zsa

40
20
10.0%
0.40
N/A
22000
18200
0.65

10670
0.0%

23413
0.0
0
0
0.0
0.117












16 76
1.68
1.68
1.68
5.03
27.8
0
a
27. 8
o.oco
0.556
Q
28 38

0 155
1.113
0 183
0.581
0 250
G-ll
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gSwlnb.wkl
(Mormlle. 1987) Case S | SIZE (MU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yp)
-OIL (bbl/yr)
-GAS (1000 ft"3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (m1lls/kV-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mllls/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (imlls/kW-hr) »
FUEL COSTS
-COAL (mllls/kW-hr)
-OIL (mllls/ky-hr)
-GAS (mills/kW-hr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mllls/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mllls/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kU-yr) =•
LEVELIZEO BUSBAR COST (mllls/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL (S/bbl) 32.85
GAS (S/1000 ft" 3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST (J/ft'3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY
100 | 200 | 400 600 850

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.226
0.339
0.000
0.000
3.88
1.67

0.45
0.25
374
1568
0.30
280
2090

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.167
0.250
0.000
0.000
2.94
1.26

0.45
0.25
748
1178
0.30
561
1570

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.126
0.188
0.000
0.000
2.23
0.95

0.45
0.25
1496
891
0.30
1122
1187

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.107
0.161
0.000
0.000
1.90
0.81
%
0.45
0.25
2243
758
0.30
1682
1011

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.094
0.141
0.000
0.000
1.65
0.71

0.45
0.25
3178
661
0.30
2383
381
EFFECT OF C.F.
200 200

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.148
1.336
0.000
0.000
2.94
4.84

0.45
0.25
187
4539
0.30
140
6053

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.182
0.098
0.000
0.000
2.94
0.80

0.45
0.25
1215
747
0.30
911
996
EFFECT OF AGE
200 | 200

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.167
0.250
0.000
O.OGO
2 as
1.24

0.45
0.25
748
1160
0.30
561
1547

0
0
a
0
0
0

0.000
0.000
0.000
0.000
O.OQO
Q 000

O.OOQ
0.000
O.QOO

0.167
0.250
0.000
0 000
3.33
1,37

0.45
0.25
748
1232
0.30
551
1710


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts, 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
G-12
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gBtlnb.wkl
LN8 - TANGENTIAL-FIRED UNITS 	
(Mormile. 1987) Case 6 | SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ff 3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft~3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/ Replace
-Structural
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
.Ail* Maat a»»
Mi r neater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) =
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 30%
TOTAL PLANT COSTS (TPC) (1991$/kW) -
-ESCALATION (0%)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991JAW) -
-ROYALTY ALLOWANCE O.OX of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) =
OPERATING AND MAINTENANCE COSTS {0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-ADMIN/SUPPORT LABOR (J/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS (J/kW-yr) »
VARIABLE 0 & M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 200 400 | 600 | 900

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

11706
0.0
0
0
0.0
0.104














22.12
2.21
2.21
2.21
7.96
36.7
0
0
36.7
0.000
0.734
0
37.45

0.256
1.469
0.253
0.791
0.339

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

23413
0.0
0
0
0.0
0.104














16.76
1.68
1.68
1.68
6.03
27.8
0
0
27.8
0.000
0.556
0
28.38

0.165
1.113
0.183
0.584
0.250

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

46826
0.0
0
0
0.0
0.104














12.70
1.27
1.27
1.27
4.57
21.1
0
0
21.1
0.000
0.422
0
21.51

0.119
0.843
0.137
0.440
0.188

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

70239
0.0
0
0
0.0
0.104














10.80
1.08
1.08
1.08
3.89
17.9
0
0
17.9
0.000
0.359
0
18.29

0.104
0.717
0.117
0.375
0.161

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

105358
0.0
0
0
0.0
0.104














9.18
0.92
0.92
0.92
3.31
15.2
0
0
15.2
0.000
0.305
0
15.55

0.094
0.510
0.101
0.322
0.138
EFFECT OF C.F.
200 200

25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
O.OX

23413
0.0
0
0
0.0
0.104














16.76
1.68
1.68
1.68
6.03
27.3
0
0
27.8
0.000
0.556
0
28.38

0.041
1.113
0.146
0.130
1.336

25
35
10. OX
0.65
N/A
22000
18200
0.65

10670
O.OX

23413
0.0
0
0
0.0
0.104














16.76
1.68
1.68
1.68
6.03
27.8
0
0
27.8
0.000
0.556
0
28.38

0.268
1.113
0.214
1.037
0 G98
EFFECT OF AGE
200 1 200

15
45
10.0%
0.40
N/A
22000
18200
0.65

10670
O.OX

23413
0.0
0
0
0.0
0.101














16.76
1.68
1.68
1.68
6.03
27.8
0
0
27.8
0.000
0.556
0
28.38

0.165
1.113
0.183
0.534
0.250

40
20
10.0%
0.40
N/A
22000
18200
0.65

10670
0.0%

23413
0.0
0
0
0.0
0.117














16.75
1.68
1.68
1.68
6.03
27.8
0
0
?7.a
0 000
0.556
0
23.38

0.165
1.113
0 133
0 53
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gBtlnb.wkl
LNB - TANGENT lAL-rlRtO UNI la „.— .—--
(Mormile, 1987) Case 6 | SIZE (MU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft"3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 4 M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES (S/kW-yr) *
LEVELIZED BUSBAR COST (mllls/kW-hr) -
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) =
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS (J/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (S/1000 ft'3) 2.61
AMMONIA ($/ton) 145.00
UREA (J/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST (J/ff3) 660.00
CATALYST SOLID WASTE DISPOSAL (J/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY
100 200 | 400

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.226
0.339
0.000
0.000
3.88
1.67

0.30
0.15
280
2090
0.25
93
6271

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.167
0.250
0.000
0.000
2.94
1.26

0.30
0.15
561
1570
0.25
187
4711

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.126
0.188
0.000
0.000
2.23
0.95

0.30
0.15
1122
1187
0.25
374
3562
600 900

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.107
0.161
0.000
0.000
1.90
0.81

0.30
0.15
1682
1011
0.25
561
3033

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.092
0.138
0.000
0.000
1.61
0.69

0.30
0.15
2524
862
0.25
841
2586
EFFECT OF C.F.
200 200

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.148
1.336
0.000
0.000
2.94
4.84

0.30
0.15
140
6053
0.25
47
18158

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

o.aoo
0.000
0.000

0.182
0.098
0.000
0.000
2.94
0.80

0.30
0.15
911
996
0.25
304
2988
EFFECT OF AGE
200 200

0
0
0
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0.000

0.167
0.250
0.000
0.000
2.88
1.24

0.30
0.15
561
1547
0.25
187
4642

0
0
Q
0
0
0

0.000
0.000
0.000
0.000
0.000
0.000

0.000
0.000
0 000

0.167
0.250
O.OOQ
0.000
3.33
1.37

0.30
0 15
561
1710
0 25
187
5130


Electric Power Monthly. March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991
Robie. 1991
8P Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
G-14
-------
NOx CONTROL COSTS - GAS/OIL BOILERS g7wbofg.wkl
BOOS + rGK - WALL-rJKtU UNJIS -_„—-. — -
(Moral le. 1987) Case 7 | SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (0STP:68F:14.7psia)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):

•Burners
-Ducting
-Fan Upgrade/Replace

-3 true tura i
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
_Ai f Maa^ar
Ml r neaier
-Construct i on/ 1 nstal 1 at 1 on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kU) -
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 30X
TCTAL PLANT COSTS (TPC) (1991$/kW) =
-ESCALATION (OX)
-AFDC (OX)
TCTAL PLANT INVESTMENT (1991$/kW) =
-ROYALTY ALLOWANCE O.OX of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) =
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (J/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-ADMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 4 M COSTS (J/kW-yr) =
VARIABLE 0 & M COSTS (rmlls/kW-hr) =
= = = 5=:* = = 3aa3a33333 = a3 = 3 = S3a = = = = = = = = Z2:3 = = 3; = s: = = s:s=; = = —
EFFECT OF CAPACITY
100 200 400 | 600 S50

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

11706
0.0
0
0
0.0
0.104

















8.25
0.83
0.33
0.33
2.97
13.7
0
0
13.7
0.000
0.274
0
14.0

0.256
0.548
0.143
0.379
0.162
=======

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

23413
0.0
0
0
0.0
0.104

















6.25
0.63
0.63
0.63
2.25
10.4
0
0
10.4
0.000
0.208
0
10.6

0.165
0.415
0.099
0.272
0.116
33333333

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

46826
0.0
0
0
o'.o
0.104

















4.74
0.47
0.47
0.47
1.71
7.9
0
0
7.9
0.000
0.157
0
8.0

0.119
0.315
0.073
0.203
0.087
35=533=5

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

70239
0.0
0
0
0.0
0.104

















4.03
0.40
0.40
0.40
1.45
6.7
0
0
6.7
0.000
0.134
0
6.8

0.104
0.268
0.063
0.174
0.074
=55=5=55

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

99505
0.0
0
0
0.0
0.104

















3.51
0.35
0.35
0 35
1.26
5.8
0
0
5.8
0 000
0.116
0
5.9

0.095
0.233
0.056
0.154
0.066
======ss
EFFECT OF C.F.
200 200

25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
0.3%

23413
0.0
0
0
0.0
0.104

















6.25
0.63
0.53
0.63
2.25
10.4
0
a
10.4
0 000
0.208
0
10.8

0.041
0.415
0.062
0.052
0 533
= = 3 = 3j = = =

25
35
10. OX
0.65
N/A
22000
18200
0.65

10670
0.3X

23413
0.0
0
0
0.0
0.104

















6.25
0.63
0.63
0.63
2.25
10.4
0
0
10.4
0.000
0.208
0
10.6

0.263
0.415
0.130
0.529
0 050
========
EFFECT OF AGE
200 | 200

15
45
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

23413
0.0
0
0
0.0
0.101

















6 25
0.63
0.63
0.63
2 25
10.4
0
0
10.4
0.000
0.208
0
10.5

0 165
0 415
0 099
0.272

40
20
10.0%
0.40
N/A
22000
13200
0.65

10670
0.3%

23413
0.0
0
0
0.0
0.117

















6 25
0.63
0 63
0.53
2 25
10.4
a
a
10.4
0.000
0.208
0
10.5

0 153
0 415
3 099
0 272
0.115 1 0.116
=3S====a j = = = = = = = =
G-15
-------
NOx CONTROL COSTS - GAS/OIL BOILERS g7wbofg.wkl
(Mormile. 1987) Cast 7 | SIZE (HU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MV-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft"3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel
-AMMONIA (mi11s/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (m111s/kW-hr)
-CATALYST (mi11s/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kV-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (nills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES (J/kW-yr) =
LEVELIZED BUSBAR COST (mills/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (lb/MM8tu)
-LOWER CONTROLLED NOx {Ib/MMBtuj
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) *
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) •
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (J/1000 ft'3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY
100 200 | 400 600 850

0
0
155
0
1192
3879

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.108
0.162
0.022
0.107
1.45
0.81

0.45
0.25
374
761
0.30
280
1015

0
0
309
0
2384
7758

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.078
0.116
0.022
0.107
1.10
0.64

0.45
0.25
748
596
0.30
561
795

0
0
618
0
4769
15517

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.058
0.087
0.022
0.107
0.83
0.51

0.45
0.25
1496
479
0.30
1122
639

0
0
927
0
7153
23275

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.050
0.074
0.022
0.107
0.71
0.45

0.45
0.25
2243
426
0.30
1682
568

0
0
1314
0
10134
32973

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.044
0.066
0.022
0.107
0.62
0.41

0.45
0.25
3178
388
0.30
2383
517
EFFECT OF C.F.
200 200

0
0
77
0
596
1940

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.059
0.533
0.022
0.107
1.10
1.97

0.45
0.25
187
1850
0.30
140
2467

0
0
502
0
3875
12607

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.093
0.050
0.022
0.107
1 10
0.46

0.45
0.25
1215
435
0.30
911
580
EFFECT OF AGE
200 | 200 .

0
0
309
0
2384
7758

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
Q.Q29

0.078
0.116
0.022
0.107
1.07
0.63

0.45
0.25
748
590
0.30
561
786

a
0
309 '
a
2384
7758

0.000
0.000 .
0.022
0.000
0.000
0.022

0.000
0.078
0. 023

0.079
0.116
0.022
0.107 .
1 24
0.68 .

0.45
0.25
748
635
0.30 .
561
847


Electric Power Monthly, March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
G-16
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gBtbofg.wkl
BOOS + FGR - TANotNTIAL-HKtu UNI 15 -—.—-.. —
(Mormlle. 1987) Case 8 | SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7psia)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CA'ALYST LIFE (yrs)
CA'ALYST VOLUME (ft'3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
nAUAu Oaaf*^nv»/ra^al v>* +•
-uenux Keactor/Ldta i yst
-Control System
-Fl ue Gas Heat Exchanger
~Ai r Heater
-Construct! on/ Instal 1 at i on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) *
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 30%
TOTAL PLANT COSTS (TPC) (1991$/kW) '
-ESCALATION (0%)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) =
-ROYALTY ALLOWANCE O.OX of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991J/kW) »
OPERATING AND MAINTENANCE COSTS (0 i M)
-OPERATING LABOR (OL) (J/kV-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4% of TPC
-ADMIN/SUPPORT LABOR (S/kU-yr) 30% of OL+0.4MC
FIXED 0 & M COSTS ($/kW-yr) =
VARIABLE 0 & M COSTS (mills/kW-hr) *
EFFECT OF CAPACITY
100 200 400 | 600 900

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

11706
0.0
0
0
0.0
0.104












8.25
0.83
0.83
0.83
2.97
13.7
0
0
13.7
0.000
0.274
0
14.0

0.256
0.548
0.143
0.379
0.162

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

23413
0.0
0
0
0.0
0.104












6.25
0.63
0.63
0.63
2.25
10.4
0
0
10.4
0.000
0.208
0
10.6

0.165
0.415
0.099
0.272
0.116

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

46826
0.0
0
0
0.0
0.104












4.74
0.47
0.47
0.47
1.71
7.9
0
0
7.9
0.000
0.157
0
8.0

0.119
0.315
0.073
0.203
0.087

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

70239
0.0
0
0
0.0
0.104












4.03
0.40
0.40
0.40
1.45
6.7
0
0
6.7
0.000
0.134
0
6.8

0.104
0.268
0.053
0.174
0.074

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.3X

105358
0.0
0
0
0.0
0.104












3.43
0.34
0.34
0.34
1.23
5.7
0
0
5.7
0.000
0.114
0
5.8

0.094
0.228
0.055
0.151
0.064
EFFECT OF C.F.
200 | 200

25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
0.3X

23413
0.0
0
0
0.0
0.104












6.25
0.63
0.63
0.63
2.25
10 4
Q
0
10.4
0 000
0.208
0
10 6

0.041
0.415
0.062
0.052
0.533

25
35
10. OX
0.65
N/A
22000
18200
0.65

10670
0.3X

23413
0.0
0
0
0.0
0.104












6.25
0.63
0.63
0.63
2.25
10.4
0
0
10.4
0.000
0.208
0
10.6

0 268
0 415
0 130
0.529
0.050
EFFECT OF AGE
200 | 200

15
45
10.0%
0.40
N/A
22000
18200
0.65

10670
0.3%

23413
0.0
0
0
0.0
0.101












6.25
0.63
0.63
0.63
2.25
10.4
0
0
10.4
0 000
0.208
0
10.6

0.165
0 415
0 099
0.272
0.115
= = S = S = = =I

40
20
10.0%
0.40
N/A
22000
18200
0.65

10670
0.3%

23413
0.0
0
0
0.0
0.117












6 25
0 53
0.63
0 53
2.25
10.4
0
0
10.4
0.000
0.208
0
10.5

0 165
0 415
Q . 039
0.272
0 115
G-17
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gStbofg.wkl


(Hormlle. 1987) Case 8 | SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MV-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft" 3/yp)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kU-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mllls/kW-hr)
-VARIABLE 0 & M (m1l1s/kW-Hr)
-CONSUMABLES (mills/kU-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) »
LEVELIZED BUSBAR COST (mills/kU-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
-HIGHER CONTROLLED NOx (lb/MM8tu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (S/1000 ft'3) 2.61
AMMONIA ($/ton) 145.00'
UREA (S/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05 '
CATALYST COST ($/ff 3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

	 	
100 200 | 400 600 900

0
0
155
0
1192
3879

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.108
0.162
0.022
0.107
1.45
0.81

0.30
0.15
280
1015
0.20
187
1523

0
0
309
0
2384
7758

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.078
0.116
0.022
0.107
1.10
0.64

0.30
0.15
561
795
0.20
374
1192

0
0
618
0
4769
15517

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.058
0.087
0.022
0.107
0.83
0.51

0.30
0.15
1122
639
0.20
748
958

0
0
927
0
7153
23275

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.050
0.074
0.022
0.107
0.71
0.45

0.30
0.15
1682
568
0.20
1122
852

0
0
1391
0
10730
34912

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.043
0.064
0.022
0.107
0.60
0.41

0.30
0.15
2524
510
0.20
1682
765
EFFECT OF C.F.

	
	 	
200 200

0
0
77
0
596
1940

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.059
0.533
0.022
0.107
1.10
1.97

0.30
0.15
140
2467
0.20
93
3701

0
0
502
0
3875
12607

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.093
0.050
0.022
0.107
1.10
0.46

0.30
0.15
911
580
0.20
603
870
EFFECT OF AGE


200 200

0
0
309
0
2384
7758

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.078
0.029

0.078
0.116
0.022
0.107
1.07
0.63

0.3Q
0.15
561
786
0.20
374
1179

Q
0
309
0
2384
7758

0.000
0.000
0.022
0.000
0.000
0 022

0.000
0.078
0.029

0 078
0.116
0 022
0 107
1.24
0.63

0.30
0.15
551
847
o.eo
374
1270


Electric Power Monthly, March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991 -
Robie. 1991
BP Chemical. 1991
Robie, 1991
Robie. 1991
Robie. 1991
Robie. 1991
G-18
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gSwlnfgo.wkl
LNB + FGR + OFA - WALL-FIRED UNITS 	
(Carnevale/Yee. 1989) Case 9 | SIZE (MU)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7ps1a)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft*3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kU):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
Ail* UA9 + AM
-Ai r neater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kU) »
-GENERAL FACILITIES (GF) 10% of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 30X
TOTAL PLANT COSTS (TPC) (1991$/kW) =
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) =
-ROYALTY ALLOWANCE O.OX of PCC
-PREPRODUCTION COSTS 2% of TPC
-INVENTORY CAPITAL (OX)
TO'AL CAPITAL REQUIREMENT (TCR) (1991$/kW) =
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (J/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-ADMIN/SUPPORT LABOR (J/kU-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS ($/kW-yr) =
VARIABLE 0 & M COSTS (mi lls/kW-hr) -
EFFECT OF CAPACITY
100 | 200 | 400 600 850

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.5X

11706
0.0
0
0
0.0
0.104
.












42.70
4.27
4.27
4.27
15.37
70.9
0
0
70.9
0.000
1.418
0
72.3

0.256
2.835
0.417
1.404
0.601

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.5X

23413
0.0
0
0
0.0
0.104













32.36
3.24
3.24
3.24
11.65
53.7
0
0
53.7
0.000
1.074
0
54.3

0.165
2.149
0.307
1.048
0.449

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.5X

46826
0.0
0
0
0.0
0.104













24.52
2.45
2.45
2.45
8.83
40.7
0
0
40.7
0.000
0.814
0
41.5

0.119
1.628
0.231
0.791
0.339-

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.5X

70239
0.0
0
0
0.0
0.104













20.85
2.09
2.09
2.09
7.51
34.6
0
0
34.6
0.000
0.692
0
35.3

0.104
1.385
0.197
0.674
0.289

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.5X

99505
0.0
0
0
0.0
0.104













18.14
1.81
1.81
1.81
6.53
30.1
0
0
30.1
0.000
0.602
0
30.7

0.095
1.205
0.173
0.589
0.252
EFFECT OF C.F.
200 200

25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
0.5%

23413
0.0
0
0
0.0
0.104













32.36
3.24
3.24
3.24
11.65
53.7
0
0
53.7
0.000
1.074
0
54 8

0 041
2 149
0.270
0.246
2.527

25
35
10. or.
0.65
N/A
22000
18200
0.65

10670
0.5X

23413
0.0
0
0
0.0
0.104













32.36
3 24
3.24
3.24
11.65
53.7
0
0
53.7
0.000
1.074
0
54 3

0.268
2.149
0 338
1.791
0 169
EFFECT OF AGE .
200 | 200 :

15
45
10.0%
0.40
N/A
22000
18200
0.65

10670
0.5%

23413
0.0
0
0
0.0
0.101













32.36
3.24
3.24
3.24
11 65
53.7
0
0
53.7
0.000
1.074
0
54.3

0.165
2.149
0.307
1.043
0.449
!
40 .
20
10.0%
0.40 ;
N/A
22000
18200 ;
0.65 '

10670
0 . 5% .
1
23413
0.0 ,
0
o •
0.0 '
0.117 '













32.36
3.24
3.24
3.24
11 65
53 7
0
0
53 7
0 000
1 074
Q
54.3

0.165
2 149
0.307
1.348
0.449
G-19
-------
NOx CONTROL COSTS - GAS/OIL BOILERS g9wlnfgo.wkl
LNB * roK + OrA - WALL-rlKtu UNI 13 ---•—•—-
(Carnevale/Yee. 1989) Case 9 | SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ff 3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel
-AMMONIA (mllls/kW-hr)
-UREA (mllls/kW-hr)
-ELECTRICITY (mills/kV-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kU-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) >
LEVELIZED BUSBAR COST (mills/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) *
UNIT
APPLICABLE UNIT PRICING COST
COAL (S/ton) 45.84
OIL ($/bbl) 22.85
GAS (J/1000 ff 3) 2.61
AMMONIA (J/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST (J/ff 3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY
100 200 400 600 850

0
0
155
0
1987
6465

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.401
0.601
0.022
0.178
7.50
3.34

0.45
0.10
654
1789
0.25
374
3131

0
0
309
0
3974
12931

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.299
0.449
0.022
0.178
5.68
2.57

0.45
0.10
1309
1376
0.25
748
2408

0
0
618
0
7948
25861

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.226
0.339
0.022
0.178
4.31
1.99

0.45
0.10
2617
1067
0.25
1496
1868

0
0
927
0
11922
38792

0.000
a. ooo
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.192
0.289
0.022
0.178
3.66
1.73

0.45
0.10
3926
924
0.25
2243
1617

0
0
1314
0
16890
54955

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.168
0.252
0.022
0.178
3.18
1.53

0.45
0.10
5561
819
0.25
3178
1433
EFFECT OF C.F.
200 200

0
0
77
0
994
3233

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.281
2.527
0.022
0.178
5.68
9.49

0.45
0.10
327
5084
0.25
187
8897

0
0
502
0
6458
21012

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.314
0.169
0.022
0.178
5.68
1.68

0.45
0.10
2125
900
0.25
1215
1576
EFFECT OF AGE
200 200

0
0
309
'0
3974
12931

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
O.Q48

0.299
0.449
0.022
0.178
5.56
2.53

0.45
0.10
1309
1357
0.25
748
2374

a
0
309
0
3974
12931

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0 130
0.048

3.299
0.449
0.022
0.178
6 44
2.73

0.45
0.10
1309
1491
0.25
748
2610


Electric Power Monthly. March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical, 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
G-20
-------
NOx CONTROL COSTS - GAS/OIL BOILERS glOtlnfo.wkl
LNB+-FGR+OFA - TANGENTIAL-FIRED UNITS 	
(Carnevale/Yee. 1989) Case 10| SIZE (MW)
BOILER AND FUEL SPECIFICATIONS

BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/lcW-hr)
EFFICIENCY LOSS
RE3URN FRACTION
FLUE GAS FLOWRATE (8STP:68F:14.7psia)(1000 ft"3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft'3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
•Burners
-Ducting
-fan Upgrade/Replace

- j t rue tura i
-Reagent Storage & Distribution
HafUOv D«ar»^rtr*/Pa^al uet
-Uenux Keacior/Lata lyst
-Control System
-Flue Gas Heat Exchanger
Ai ^ UaA^Af*
-MI r neater
-Construct! on/ 1 nsta 1 1 at 1 on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) *
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 30X
TOTAL PLANT COSTS (TPC) (1991$/kW) =
-ESCALATION (OX)
-AFDC (0%)
TCTAL PLANT INVESTMENT (1991$/kW) =
-ROYALTY ALLOWANCE O.OX of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TCTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) =
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) (J/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 i M COSTS ($/kW-yr) =
VARIABLE 0 8, M COSTS (mills/kU-hr) =
S = Sas«SSSS3S3 = SS3S = S = B*»sa3SSS = 3 = = = £B3SS = = = S = = = S = 3
EFFECT OF CAPACITY
100 | 200 | 400 600 900


25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.5X

11706
0.0
0
0
0.0
0.104














42.70
4.27
4.27
4.27
15.37
70.9
0
0
70.9
0.000
1.418
0
72.3

0.256
2.835
0.417
1.404
0.601
=5=SSSS


25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.5X

23413
0.0
0
0
0.0
0.104














32.36
3.24
3.24
3.24
11.65
53.7
0
0
53.7
0.000
1.074
0
54.8

0.165
2.149
0.307
1.048
0.449
ssssssss


25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.5X

46826
0.0
0
0
0.0
0.104














24.52
2.45
2.45
2.45
8.83
40.7
0
0
40.7
0.000
0.814
0
41.5

0.119
1.628
0.231
0.791
0.339
========


25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.5X

70239
0.0
0
0
0.0
0.104














20.85
2.09
2.09
2.09
7.51
34.6
0
0
34.6
0.000
0.692
0
35.3

0.104
1.385
0.197
0.674
0.289
SSS====S


25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.5X

105358
0.0
0
0
0.0
0.104














17.73
1.77
1.77
1.77
6.38
29.4
0
0
29.4
0.000
0.589
0
30.0

0.094
1.177
0.169
0.576
0.247
===S = 33S:
EFFECT OF C.F.
200 200


25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
0.5%

23413
0.0
0
0
0.0
0.104














32.36
3.24
3.24
3.24
11.65
53.7
0
0
53.7
0.000
1.074
0
54.8

0.041
2.149
0.270
0.246
2.527
========


25
35
10. OX
0.65
N/A
22000
18200
0.65

10670
0.5%

23413
0.0
0
0
0.0
0.104














32.36
3.24
3.24.
3.24
11.65
53.7
0
0
53.7
0 000
1.074
0
54 8

0.268
2 149
0.338
1 791
0.169
========
EFFECT OF AGE
200 | 200


15
45
10.0%
0.40
N/A
22000
18200
0.65

10670
0.5%

23413
0.0
0
0
0.0
0.101














32.36
3.24
3.24
3.24
11.65
53.7
0
0
53.7
0.000
1.074
0
54.8

0.165
2.149
0.307
1.048
0.449
=====S==


40
20
10.0%
0.40
N/A
22000
18200
0.65

10670
0.5%

23413
0.0
0
Q
0.0
0.117














32.36
3.24
3.24
3.24
11.65 ,
53.7 |
0
0
53.7
o.cco
1.074
a
54 3

0.155
2.149
0.307
1 048
0 449 i
========
G-21
-------
NOx CONTROL COSTS - GAS/OIL BOILERS glOtlnfo.wkl


(Carnevale/Yee. 1989) Case 10| SIZE (HU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ff3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kV-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) -
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kU-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($AW-yr) -
LEVELIZED BUSBAR COST (mills/kW-hr) -
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
• UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (J/1000 ft' 3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ft'3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

	 	 	 _. 	 . 	 	 „„ 	
100 200

0
0
155
0
1987
6465

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.401
0.601
0.022
0.178
7.50
3.34

0.30
0.10
374
3131
0.20
187
6262

0
0
309
0
3974
12931

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.299
0.449
0.022
0.178
5.68
2.57

0.30
0.10
748
2408
0.20
374
4816
400 600 900

0
0
618
0
7948
25861

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.226
0.339
0.022
0.178
4.31
1.99

0.30
0.10
1496
1868
0.20
748
3736

0
0
927
0
11922
38792

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.192
0.289
0.022
0.178
3.66
1.73

0.30
0.10
2243
1617
0.20
1122
3235

0
0
1391
0
17883
58187

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.164
0.247
0.022
0.178
3.11
1.50

0.30
0.10
3365
1405
0.20
1682
2810
EFFECT OF C.F.


200 200

0
0
77
0
994
3233

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.281
2.527
0.022
0.178
5.68
9.49
•
0.30
0.10
187
8897
0.20
93
17795

0
0
502
0
6458
21012

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.314
0.169
0.022
0.178
5.68
1.68

0.30
0.10
1215
1576
0.20
608
3152
EFFECT OF AGE |


200 | 200 :

0
0
309
0
3974
12931

0.000
0.000
0.022
0.000
0.000
0.022

0.000
0.130
0.048

0.299
0.449
0.022
0.178
5.56
2.53

0.30
0.10
748
2374
0.20
374
4748
i
Q '
0 i
309 j
0 i
3974 |
12931 !

0.000
0.000 !
0.022
0.000
O.QOO ;
0.022 •
t
0.000 '
0.130 i
0 048 !

0.299 ,
0.449
0.022 '
0.178
6.44 '
2.78

0.30
o.io ;
748
2610
0.20 .
374
5219


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
G-22
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gllwsncu.wkl
UREA NOX-OUT (SNCR-Unv.ONrKUt.LtUj - WALL -----------
(Springer. 1992) Case ll| SIZE (HW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (8tu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/ky-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (8STP:68F:14.7psia) (1000 ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):

-curners
-Ducting
-Fan Upgrade/Replace

- j true tura i
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-A i !• Maafav*
>i i r neater
-Construct i on/ Instal 1 at i on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) »
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) 10% of PCC
-PROJECT CONTINGENCY (X of PCC) 30%
TOTAL PLANT COSTS (TPC) (1991J/kw) =
-ESCALATION (0%)
-AFDC (0%)
TOTAL PLANT INVESTMENT (1991$/kW) »
-ROYALTY ALLOWANCE
-PREPROOUCTION COSTS
-INVENTORY CAPITAL (0%)
TOTAL CAPITAL REQUIREMENT (TCR) (1991J/kW) =
OPERATING AND MAINTENANCE COSTS (0 & M)
-CPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr)
-AOMIN/SUPPORT LABOR ($/kV-yr)
FIXED 0 8. M COSTS (J/kW-yr) =
VARIABLE 0 i M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 200 | 400 600 | 850

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

11706
0.0
0
0
1.5
0.104

















6.60
0.66
0.66
0.66
1.98
11
0
0
11
2.55
0.00
0
13

0.131
0.069
0.000
0.08
0.034

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

23413
0.0
0
0
1.5
0.104

















5.00
0.50
0.50
0.50
1.50
8
0
0
8
1.68
0.00
0
10

0.066
0.034
0.000
0.04
0.017

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

46826
0.0
0
0
1.5
0.104

















3.79
0.38
0.38
0.38
1.14
6
0
0
6
0.84
0.00
0
7

0.033
0.017
0.000
0.02
O.Q09

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1%

70239
0.0
0
0
1.5
0.104

















3.22
0.32
0.32
0.32
0.97
S
0
0
5
0.57
0.00
0
6

0.022
0.011
0.000
0.01
0.006

25
35
10.0%
0.40
N/A
22000
18200
0.65

10670
0.1%
•
99505
0.0
0
0
1.5
0.104

















2.80
0.28
0.28
0.28
0.84
4
0
0
4
0.41
0.00
0
5

0.015
0.008
0.000
0.01
0.004
EFFECT OF C.F.
200 200

25
35
10.0%
0.10
N/A
22000
18200
0.65

10670
0.1%

23413
0.0
0
0
1.5
0.104

















5.00
0.50
0.50
0.50
1.50
3
0
0
3
0.25
0.00
0
a

0.263
0 137
0.000
0.04
0.411

25
35
10.0%
0.65
N/A
22000
18200
0.65

10670
0.1%

23413
0.0
0
0
1.5
0.104

















5.00
0.50
0.50
0.50
1.50
8
0
0
3
0.25
0.00
0
8

0.040
0.021
0.000
0.04
0 004
EFFECT OF AGE
200 | ZOO

15
45
10.0%
0.40
N/A
22000
18200
0.65

10670
0.1%

23413
0.0
0
0
1.5
0.101

















5 00
0.50
0.50
0.50
1.50
8
0
0
3
0.25
0.00
0
a

0.056
0.034
0.000
0.04
0 017

40
20
10.0%
0.40
N/A
22000
18200
0.65

10670
0.1%

23413
0.0
0
0 i
1.5 '
0.117















i

5.00
0.50
0.50
0.50
1.50
8
0
0
3
0 25
0.30
0
3

0 056
0.034
0.300 •
0.04
0.017
G-23
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gllwsncu.wkl

UKtfl rtUX-UUl (5NLK-UNCUN 1 KULLtU/ - HALL -----------
(Springer. 1992) Cast ll| SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mins/kW-hr)
-UREA (mllls/kW-hr)
-ELECTRICITY (mllls/kW-hr)
-CATALYST (mllls/kV-hr)
-CATALYST WASTE DISPOSAL (mllls/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZEO 0 4 M COSTS
-FIXED 0 & M (mllls/kW-hr)
-VARIABLE 0 & M (mi 11 s/kV-Hr)
-CONSUMABLES (mil Is/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) «
LEVELIZED BUSBAR COST (mills/kU-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (lb/MM8tu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (S/1000 ft"3) 2.61
AMMONIA ($/ton) 145. 00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL (J/ton) 315.00
OPERATING LABOR (S/man-hr) 21.45
EFFECT OF CAPACITY

	 	
100 200 400 | 600 850

0
823
0
0
397
1293

0.000
0.517
0.000
0.000
0.000
0.517

0.000
0.026
0.010

0.023
0.034
0.517
0.036
1.36
1.00

0.45
0.25
374
935
0.30
280
1246

0
1646
0
0
795
2586

0.000
0.517
0.000
0.000
0.000
0.517

0.000
0.026
0.010

0.011
0.017
0.517
0.036
1.00
0.87

0.45
0.25
748
813
0.30
561
1084

0
3292
0
0
1590
5172

0.000
0.517
0.000
0.000
0.000
0.517

0.000
0.026
0.010

0.006
0.009
0.517
0.036
0.72
0.77

0.45
0.25
1496
722
0.30
1122
963

0
4938
0
0
2384
7758

• 0.000
0.517
0.000
0.000
0.000
0.517

0.000
0.026
0.010

0.004
0.006
0.517
0.036
0.59
0.73

0.45
0.25
2243
685
0.30
1682
914

0
6995
0
0
3378
10991

0.000
0.517
0.000
0.000
0.000
0.517

0.000
0.026
0.010

0.003
0.004
0.517
0.036
0.51
0.70

0.45
0.25
3178
659
0.30
2383
879
EFFECT OF C.F.

	
	
200 200

0
411
0
0
199
647

0.000
0.517
0.000
0.000
0.000
0.517

0.000
0.026
0.010

0.046
0.411
0.517
0.036
0.86
1.99

0.45
0.25
187
1861
0.30
140
2481

0
2675
0
0
1292
4202

0.000
0.517
0.000
0.000
0.000
0.517

0.000
0.026
0.010

0.007
0.004
0.517
0.036
0.86
0.71

0.45
0.25
1215
668
0.30
911
891
EFFECT OF AGE


200 | 200

0
1646
0
0
795
2586

0.000
0.517
0.000
0.000
0.000
0.517

0.000
0.026
0.010

0.011
0.017
0.517
0.036
0.84
0.82

0.45
0.25
748
768
0.30
561
1024

0
1646
Q
a
795
2536

O.OOQ
0.517
0.000
0.000
0.000
0.517

0.000
0.026
0.010

0.011
0.017
0.517
0.036
0 97
0.86

0.45
0.25
748
804
0.30
561
1071


Electric Power Monthly, March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991
Robie. 1991
8P Chemical. 1991
Robie. 1991
Robie. 1991
Robie, 1991
Robie, 1991
G-24
-------
NOx CONTROL COSTS - GAS/OIL BOILERS g!2wsncc.wkl
UREA NOx-OUT (SNCR-CONTROLLED) - WALL 	
(Springer. i992) Case 12| SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV { Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X vrt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (8STP:68F:14.7psia)(1000 ft*3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs) ,
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-OeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
Ail" UAAt AV>
-AI r neacer
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) -
-GENERAL FACILITIES (GF) 10% of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 30%
TOTAL PLANT COSTS (TPC) (1991$/kW) =
-ESCALATION (OX)
-AFOC (OX)
TO'AL PLANT INVESTMENT (1991$/kW) »
-ROYALTY ALLOWANCE
-PREPROOUCTION COSTS
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) -
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr)
-ADMIN/SUPPORT LABOR (J/kW-yr)
FIXED 0 & M COSTS (J/kW-yr) =•
VARIABLE 0 i M COSTS (mills/kW-hr) »
EFFECT OF CAPACITY
100 | 200 | 400 600 850

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

11706
0.0
0
0
1.5
0.104














6.60
0.66
0.66
0.66
1.98
11
0
0
11
2.55
0.00
0
13

0.131
0.069
0.000
0.08
0.034

25
35
10. OX
0.40
N/A
22000
13200
0.65

10670
0.1X

23413
0.0
0
0
1.5
0.104














5.00
0.50
0.50
0.50
1.50
8
0
0
8
1.68
0.00
0
10

O.Q66
0.034
0.000
0.04
0.017

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

46826
0.0
0
0
1.5
0.104














3.79
0.38
0.38
0.38
1.14
6
0
0
6
0.84
0.00
0
7

0.033
0.017
0.000
0.02
0.009

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

70239
0.0
0
0
1.5
0.104














3.22
0.32
0.32
0.32
0.97
5
0
0
5
0.57
0.00
0
6

0.022
0.011
0.000
0.01
0.006

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

99505
0.0
0
0
1.5
0.104














2.80
0.28
0.28
0.28
0.84
4
0
0
4
0.41
0.00
0
5

0.015
0.008
0.000
0.01
0.004
EFFECT OF C.F.
200 200

25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
0.1X

23413
0.0
0
0
1.5
0.104














5.00
0.50
0.50
0.50
1.50
a
0
0
8
0.25
0.00
0
3

0.253
0.137
0.000
0.04
0.411

25
35
10. OX
0.65
N/A
22000
18200
0.65

10670
0.1X

23413
0.0
0
0
1.5
0.104














5.00
0.50
0.50
0.50
1.50
3
0
0
8
0.25
0.00
0
8

0.040
0.021
0 000
0.04
0.004
EFFECT OF AGE :
200 | 200 !

15
45
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1%

23413
0.0
0
0
1.5
0.101














5.00
0.50
0.50
0.50
1.50
8
0
0
8
0.25
0.00
0
8

0.066
0 034
0.000
0 04
0.017
j
40 *
20 '
10. OX1
0.40 :
N/A :
22000 :
18200 '
0.65 ;

10670 i
0.1%;

23413
0.0
0 i
0 i
1.5 '
0.117














5.00
0.50
0.50 •
0.50
1.50
a
0
0
3
0.25
0.00
a
3

0 065
0.324
0.200
0 04
0.017
G-25
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gl2wsncc.wkl


(Springer. 1992) Case 12| SIZE (HU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft*3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mi lls/kV-hr)
-CATALYST (mllls/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) =
FUEL COSTS
-COAL (imlls/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mi 1 Is/kU-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) -
LEVELIZED BUSBAR COST (mills/kW-hr) «
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) «
UNIT
APPLICABLE UNIT PRICING COST
COAL (J/ton) 45.84
OIL (S/bbl) 22.85
GAS (J/1000 ft~3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ff 3) 660.00
CATALYST SOLID WASTE DISPOSAL (J/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

	 . 	
100

0
549
0
0
397
1293

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0.023
0.034
0.344
0.036
1.36
0.82

0.30
0.20
187
1546
0.25
93
3093
200 1 400 600 850

0
1097
0
0
795
2586

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0.011
0.017
0.344
0.036
1.00
0.69

0.30
0.20
374
1302
0.25
187
2605

0
2194
0
0
1590
5172

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0.006
0.009
0.344
0.036
0.72
0.60

0.30
0.20
748
1122
0.25
374
2244

0
3292
0
0
2384
7758

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0.004
0.006
0.344
0.036
0.59
0.56

0.30
0.20
1122
1047
0.25
561
2095

0
4663
0
0
3378
10991

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0.003
0.004
0.344
0.036
0.51
0.53

0.30
0.20
1589
996
0.25
794
1992
EFFECT OF C.F.

	
	
200 200

0
274
0
0
199
647

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0.046
0.411
0.344
0.036
0.86
1.81

0.30
O.ZO
93
3399
0.25
47
6798

0
1783
0
0
1292
4202

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0 007
0.004
0.344
0.036
0.86
0.54

0.30
0.20
508
1014
0.25
304
2028
EFFECT OF AGE


200 200

0
1097
0
0
795
2536

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0.011
0.017
0.344
0.036
0 84
0.65

0.30
0.20
374
1213
0.25
187
2427

0
1097
0
0
795
2586

O.OOQ
0.344
0.000
0.000
0.000
0.344

0.000
0.025
0.010

0.011
0.017
0 344
0.035
0 97
0.69

0 30
0.20
374
1234
0.25
187
2563


Electric Power Monthly. March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991
Robie, 1991
8P Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
G-26
-------
NOx CONTROL COSTS - GAS/OIL BOILERS g!3tsncu.wkl
UREA NOx-OUT (SNCK-UNLUNIR) -lANutflliAL -----------
(Springer. 1992) Case 13| SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (8tu/kW-hr)
EFFICIENCY LOSS
REBLJRN FRACTION
FLUE GAS FLOWRATE (0STP:68F:14.7psia)(1000 ft*3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
•Burners
-Ducting
-Fan Upgrade/ Re pi ace
•Structural
-Reagent Storage i Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
_ A | .• Ua«f At*
nir neater
•Construct! on/Instal 1 ati on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) »
-GENERAL FACILITIES (GF) 1 OX of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 30X
TOTAL PLANT COSTS (TPC) (1991$/kU) *
-ESCALATION (OX)
-AFOC (OX)
TO'AL PLANT INVESTMENT (1991$/kV) =
-ROYALTY ALLOWANCE
-PREPROOUCTION COSTS
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991S/kW) »
OPERATING AND MAINTENANCE COSTS (0 i M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) (S/kW-yr)
-AOMIN/SUPPORT LABOR ($/kU-yr)
FIXED 0 81 M COSTS (J/kW-yr) =
VARIABLE 0 & M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 | 200 400 | 600 900

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

11706
0.0
0
0
1.5
0.104












6.60
0.66
0.66
0,66
1.98
11
0
0
11
2.55
0.00
0
13

0.131
0.069
0.000
0.08
0.034

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

23413
0.0
0
0
1.5
0.104












5.00
0.50
0.50
0.50
1.50
8
0
0
8
1.68
0.00
0
10

0.066
0.034
0.000
0.04
0.017

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

46826
0.0
0
0
1.5
0.104












3.79
0.38
0.38
0.38
1.14
6
0
0
6
0.84
0.00
0
7

0.033
0.017
0.000
0.02
0.009

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

70239
0.0
0
0
1.5
0.104












3.22
0.32
0.32
0.32
0.97
5
0
0
5
0.57
0.00
0
6

0.022
0.011
0.000
0.01
0.006

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

105358
0.0
0
0
1.5
0.104












2.74
0.27
0.27
0.27
0.82
4
0
0
4
0.38
0.00
0
5

0.015
0.008
0.000
0.01
0.004
EFFECT OF C.F.
200 | 200

25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
0.1X

23413
0.0
0
0
1.5
0.104












5.00
0.50
0.50
0.50
• 1.50
3
0
0
3
0.25
0.00
0
8

0.263 '
0.137
Q.OQO
0.04
0.411

25
35
10. OX
0.65
N/A
22000
18200
0.65

10670
0.1X

23413
0.0
0
0
1.5
0.104












5.00
0.50
0.50
0.50
1.50
8
0
0
8
0.25
0.00
0
3

0.040
0.021
0.000
0 04
0.004
EFFECT OF AGE
200 200

15
45
10. OX
. 0.40
N/A
22000
18200
0.65

10670
0.1X

23413
0.0
0
0
1.5
0.101












5.00
0.50
0.50
0.50
1.50
8
0
. 0
8
0.25
0.00
0
3

0.066
0.034
0.000
0 04
0 017

40
20
10.0%
0.40
N/A
22000
18200
0.65

10670
0.1%

23413
0.0
0
0
1.5
0.117












5.00
0.50
0.50
0.50
1.50
8
0
0
8
0.25
0.00
0
A

0.366
0.034
0 000
0 04
0 017
G-27
-------
NOx CONTROL COSTS - GAS/OIL BOILERS glStsncu.wkl

UKtA NCJX-UUI (5NCK-UNUQNIKJ -lANOtm 1AL -----------
(Springer. 1992) Case 13| SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft"3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (ml lls/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mflls/kU-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kV-hr)
-GAS (mllls/kW-hr)
LEVELIZEO 0 & M COSTS
-FIXED 0 4 M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES (J/kW-yr) =.
LEVELIZED BUSBAR COST (mills/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (lb/MM8tu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS (J/ton) *
-HIGHER CONTROLLED NOx (lb/MM8tu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NO/ REMOVAL COST EFFECTIVENESS ($/ton) =
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (J/1000 ff 3) 2.61
AMMONIA (S/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST ($/ft~3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

	 _. 	 .
100 | 200 | 400 600 900

0
549
0
0
397
1293

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0.023
0.034
0.344
0.036
1.36
0.82

0.30
0.15
280
1031
0.20
187
1546

0
1097
0
0
795
2586

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0.011
0.017
0.344
0.036
1.00
0.69

0.30
0.15
561
868
0.20
374
1302

0
2194
0
0
1590
5172

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0.006
0.009
0.344
0.036
0.72
0.60

0.30
0.15
1122
748
0.20
748
1122

0
3292
0
0
2384
7758

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0.004
0.006
0.344
0.036
0.59
0.56

0.30
0.15
1682
698
0.20
1122
1047

0
4938
0
0
3577
11637

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0.003
0.004
0.344
0.036
0.49
0.53

0.30
0.15
2524
659
0.20
1632
989
EFFECT OF C.F.


200 | 200

0
274
0
0
199
647

0.000
0.344
0.000
0.000
0.000
0.344

•Q.OOO
0.026
0.010

0.046
0.411
0.344
0.036
0.86
1.81

0.30
0.15
140
2266
0.20
93
3399

0
1783
0
0
1292
4202

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0.007
0.004
0.344
0.036
0.86
0.54

0.30
0.15
911
676
• 0.20
608
1014
EFFECT OF AGE


200 200

0
1097
0
0
795
2586

0.000
0.344
0.000
0.000
0.000
0.344

0.000
0.026
0.010

0.011
0.017
0.344
0.036
0.84
0.65

0.30
0.15
561
809
0.20
374
1213

0
1097
0
0
795
2586

0.000
0.344
0.000
0.000 ,
0.000 |
0.344

0.000
0.026
0.010

0.011
0 017
0.344
0 036
0 97
0.69

0.30
0.15
561
356
0.20
374
1284


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie, 1991
Robie. 1991
Robie. 1991
Robie. 1991
G-28
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gUtsncc.wkl
UREA Nux-OUT (SNCR-CUNIKUU) -lANutNllAL -----------
(Springer. 1992) Case 14| SUE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOURATE (9STP:68F:14.7psia)(1000 ft" 3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft'3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):

"Burners
-Ducting
-Fan Upgrade/Replace

- jtruc tura t
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Ai f Hoat «f
MI r neater
-Const ructi on/ Instal 1 at i on Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) *
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10* of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC) 30%
TOTAL PLANT COSTS (TPC) (1991J/kW) »
-ESCALATION (OX)
-AFDC (OX) .
TOTAL PLANT INVESTMENT (i99U/ku) -
-ROYALTY ALLOWANCE
-PREPRODUCTION COSTS
-INVENTORY CAPITAL (OX)
~OTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) =
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (J/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr)
-AOMIN/SUPPORT LABOR ($/kU-yr)
FIXED 0 & M COSTS ($/kW-yr) »
VARIABLE 0 i M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 200 | 400 600 | 900

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

11706
0.0
0
0
1.5
0.104

















6.60
0.66
0.66
0.66
1.98
11
0
0
11
2.55
0.00
0
13

0.131
0.069
0.000
0.08
0.034

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

23413
0.0
0
0
1.5
0.104

















5.00
0.50
0.50
0.50
1.50
8
0
0
8
1.68
0.00
0
10

0.066
0.034
0.000
0.04
0.017

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

46826
0.0
0
0
1.5
0.104
(
















3.79
0.38
0.38
0.38
1.14
6
0
0
6
0.84
0.00
0
7

0.033
0.017
0.000
0.02
0.009

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

70239
0.0
0
0
1.5
0.104

















3.22
0.32
0.32
0.32
0.97
5
0
0
5
0.57
0.00
0
6

0.022
0.011
0.000
0.01
0.006

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1X

105358
0.0
0
0
1.5
0.104

















2.74
0.27
0.27
0.27
0.82
4
0
0
4
0.38
0.00
0
5

0.015
0.008
0.000
0.01
0.004
EFFECT OF C.F.
200 200

25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
0.1X

23413
0.0
0
0
1.5
0.104

















5.00
0.50
0.50
0.50
1.50
8
0
0
8
0.25
0.00
0
a

0.263
0.137
0.000
0.04
0.411

25
35
10. OX
0.65
N/A
22000
18200
0.65

10670
0.1%

23413
0.0
0
0
1.5
0.104

















5.00
0.50
0.50
0.50
1.50
8
0
0
8
0.25
0.00
0
8

0.040
0.021
0.000
0 04
0.004
EFFECT OF AGE j
200 200 ;

15
45
10. OX
0.40
N/A
22000
18200
0.65

10670
0.1%

23413
0.0
0
0
1.5
0.101

















5.00
0.50
0.50
0.50
1.50
3
0
0
8
0.25
0.00
0
3

0.066
0.034
0.000
0 04
0 017

40
20
10.0%:
0.40 '
N/A
22000
18200 •
0.65 i

10670 i
0.17.

23413
0.0
0
0
1.5
0.117

















5.00
0.50
0.50
0.50
1.50
3
0
0
a
0.25
0 CO
0
3

0.056
0.034
0 000
O.C4
0.017
G-29
-------
NOx CONTROL COSTS - GAS/OIL BOILERS gUtsncc.wkl


(Springer. 1992) Case 14| SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MV-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel
-AMMONIA (mllls/kW-hr)
-UREA (mllls/kW-hr)
-ELECTRICITY (mnis/kV-hr)
-CATALYST (mllls/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-nr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) *
FUEL COSTS
-COAL (mllls/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZEO 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mil Is/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kW-yr) -
LEVELIZEO BUSBAR COST (m1lls/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMfltu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
. -HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL ($/bbl) 22.85
GAS (S/1000 ft'3) 2.51
AMMONIA ($/ton) 145.00
UREA (S/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST ($/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL (J/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY
	
	 	 —

100

0
366
0
0
397
1293

0.000
0.230
0.000
0.000
0.000
0.230

o.ooo'
0.026
0.010

0.023
0.034
0.230
0.036
1.36
0.71

0.20
0.10
187
1331
0.15
93
2662
2pO | 400

0
731
0
0
795
2586

0.000
0.230
0.000
0.000
0.000
0.230

0.000
0.026
0.010

0.011
0.017
0.230
0.036
1.00
0.58

0.20
0.10
374
1087
0.15
187
2174

0
1463
0
0
1590
5172

0.000
0.230
0.000
0.000
0.000
0.230

0.000
0.026
0.010

0.006
0.009
0.230
0.036
0.72
0.48

0.20
0.10
748
907
0.15
374
1813
600 900

0
2194
0
0
2384
7758

0.000
0.230
0.000
0.000
0.000
0.230

0.000
0.026
0.010

0.004
0.006
0.230
0.036
0.59
0.44

0.20
0.10
1122
832
0.15
561
1665

0
3292
0
0
3577
11637

0.000
0.230
0.000
0.000
0.000
0.230

0.000
0.026
0.010

0.003
0.004
0.230
0.036
0.49
0.41

0.20
0.10
1682
773
0.15
841
1547
EFFECT OF C.F.

	
200 200

0
183
0
0
199
647

0.000
0.230
0.000
0.000
0.000
0.230

0.000
0.026
0.010

0.046
0.411
0.230
0.036
0.86
1.70

0.20
0.10
93
3184
0.15
47
6363

0
1189
0
0
1292
4202

0.000
0.230
0.000
0.000
0.000
0.230

0.000
0.026
0.010

0.007
0.004
0.230
0.036
0.86
0.43

0.20
0.10
608
799
0.15
304
1598
EFFECT OF AGE


200 200

0
731
0
0
795
2586

0.000
0.230
0.000
0.000
0.000
0.230

0.000
0.026
0.010

0.011
0.017
0.230
0.036
0.84
0.53

0.20
0.10
374
998
0.15
187
1996

0
731
0
0
795
2586

0.000
0.230
0.000
0.000
0.000
0 230

0.000
0.026
0.010

0.011
0.017
0.230
0.036 '
0.97
0 57

0.20
0.10
374
1069
0.15
187
2138


Electric Power Monthly. March 1991
Electric Power Monthly, March 1991
Gas Facts, 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie, 1991
G-30
-------
NOx CONTROL COSTS - GAS/OIL BOILERS glSwscru.wkl
SCR - UNCONTROLLED - WALL-FIRED UNITS 	
(Johnson. 1991) Case 1S| SIZE (HW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (8STP:68F:14.7psia)(1000 ft~3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft'3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kU):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Air Heater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991S/kV) •
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10% of PCC
-PROCESS CONTINGENCY (Proc) 10% of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 40X
TO'AL PLANT COSTS (TPC) (1991$/kU) -
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991$/kW) =
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPROOUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TQ-AL CAPITAL REQUIREMENT (TCR) (1991$/kW) =
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (J/kW-yr)
-MAINTENANCE COSTS (MC) (J/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR (J/kW-yr) 30X of OL+0.4MC
FIXED 0 & M COSTS ($/kW-yr) =
VARIABLE 0 i M COSTS (mills/kW-hr) -
EFFECT OF CAPACITY
100 200 | 400 | 600 850

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

11706
1.0
4
1951
0.0
0.104


4.51
12.85
13.41
3.00
32.02
6.61


19.53
0.77
97.70
9.77
9.77
9.77
46.90
174
0
0
174
0.49
3.48
0
178

0.256
6.956
0.912
3.25
1.391

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

23413
1.0
4
3902
0.0
0.104


3.41
9.74
10.16
6.06
24.27
5.01


14-. 80
0.59
74.04
7.40
7.40
7.40
35.54
132
0
0
132
0.37
2.64
0
135

0.165
5.272
0.682
2.45
1.048

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

46826
1.0
4
7804
0.0
0.104


2.59
7.38
7.70
4.60
18.39
3.79


11.22
0.44
56.11
5.61
5.61
5.61
26.93
100
0
0
100
0.28
2.00
0
102

0.119
3.995
0.515
1.85
0.793

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

70239
1.0
4
11706
0.0
0.104


2.20
6.28
6.55
3.91
15.64
3.23


9.54
0.38
47.71
4.77
4.77
4.77
22.90
85
0
0
85
0.24
1.70
0
87

0.104
3.397
0.439
1.58
0.675

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

99505
1.0
4
16584
0.0
0.104


1.91
5.46
5.70
3.40
13.60
2.81


8.30
0.33
41.51
4.15
4.15
4.15
19.92
74
0
0
74
0,21
1.48
0
76

0.095
2.955
0.383
1.37
0.588
EFFECT OF C.F.
200 | 200

25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
O.OX

23413
1.0
4
3902
0.0
0.104


3.41
9.74
10.16
6.06
24.27
5.01


14.80'
0.59
74.04
7.40
7.40
7.40
35.54
132
0
0
132
0.37
2.54
0
135

0.041
5 272
0.545
0.60
6.121

25
35
10. OX
0.65
N/A
22000
18200
0.65

10670
O.OX

23413
1.0
4
3902
0.0
0.104


3.41
9.74
10.16
6.06
24.27
5.01


14 80
0.59
74.04
7.40
7 40
7.40
35 54
132
0
0
132
0.37
2.64
0
135

0.263
5.272
0.713
4 06
0 384
EFFECT OF AGE j
200 200 j

15
45
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

23413
1.0
4
3902
0.0
0.101


3.41
9.74
10.16
6.06
24.27
5.01


14 80
0.59
74.04
7.40
7.40
7.40
35.54
132
0
0
132
0.37
2.64
0
135

0.165
5.272
0 682
2.45
1.048

40 :
20 ,
10. OX!
0.40 i
N/A !
22000 ,
18200 ;
0.65 {
i
10670 :
0.0%;

23413 i
1.0
4 i
3902 '
0.0 :
0.117


3 41
9.74
10.16
6 06
24 27 •
5.01


14.80
0.59 '
74.04
7.40 ,
7 40
7.40
35.54
132
0
0
132
0 37
2 64
0
135

0.165
5.272
0.682
2 45
1 048
G-31
-------
NOx CONTROL COSTS - GAS/OIL BOILERS glSwscru.wkl
cm nurouToni i en UAI i .PTDrn IIMTTC - ......

(Johnson. 1991) Case 15| SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MV-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mllls/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mms/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kV-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mllls/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mill s/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES (J/kW-yr) *
LEVELIZED BUSBAR COST (mil1s/kW-hr) -
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) «
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) -
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL (J/bbl) 22.85
GAS ($/1000 ft"3) 2.61
AMMONIA (J/ton) 145.00
UREA (J/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST (J/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL (J/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY

	 	 	 „ 	 . 	 . 	 	 	
100 | 200 | 400 | 600 | 850

311
0
3291
0
0
0

0.129
0.000
0.470
0.919
0.011
1.528

0.000
0.000
0.000

0.927
1.391
1.528
0.000
18.44
9.11

0.45
0.10
654
4879
0.15
561
5692

623
0
8237
0
0
0

0.129
0.000
0.588
0.919
0.011
1.646

0.000
0.000
0.000

0.698
1.048
1.646
0.000
13.98
7.38

0.45
0.10
1309
3953
0.15
1122
4612

1246
0
18129
0
0
0

0.129
0.000
0.647
0.919
0.011
1.705

0.000
0.000
0.000

0.528
0.793
1.705
0.000
10.59
6.05

0.45
0.10
2617
3240
0.15
2243
3780

1868
0
28020
0
0
0

0.129
0.000
0.666
0.919
0.011
1.725

0.000
0.000
0.000

0.450
0.675
1.725
0.000
9.01
5.42

0.45
0.10
3926
2902
0.15
3365
3386

2647
0
40385
0
0
0

0.129
0.000
0.678
0.919
0.011
1.736

0.000
0.000
0.000

0.392
0.588
1.736
0.000
7.84
4.95

0.45
0.10
5561
2652
0.15
4767
3094
EFFECT OF C.F.
	

200 | 200

156
0
2059
0
0
0

0.129
0.000
0.588
3.675
0.042
4.434

0.000
0.000
0.000

0.680
6.121
4.434
0.000
13.98
27.19

0.45
0.10
327
14562
0.15
280
16989

1012
0
13385
0
0
0

0.129
0.000
0.588
0.565
0.006
1.288

0.000
0.000
0.000

0.714
0.384
1.288
0.000
13.98
4.84

0.45
0.10
2126
2593
0.15
1823
3025
EFFECT OF AGE


200 | 200

623
0
8237
0
0
0

0.129
0.000
0.588
0.919
0.011
1.646

0.000
0.000
0.000

0.698
1.048
1.646
0.000
13.67
7.29

0.45
0.10
1309
3906
0.15
1122
4556

623
0
8237
0
0
0

0.129
0.000
0.588
0.919
0.011
1.646

0.000
0.000
0.000

0.693
1.048
1.646
0.000
15 33
7 91

0.45
0.10
1309
4237
0 15
1122
4943


Electric Power Monthly, March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. L991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
G-32
-------
NOx CONTROL COSTS - GAS/OIL BOILERS g!6wscrc.wkl
SCR - CONTROLLtu - WALL-MKCU Unlli — .—„—
(Johnson. 1991) Case 16| SIZE (HU)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F:14.7ps1a)(1000 ft'3/hr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
"Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Air Heater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kU) »
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10X of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) . 40%
TOTAL PLANT COSTS (TPC) (1991J/kW) =
-ESCALATION (OX)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991J/kW) =
-ROYALTY ALLOWANCE 0.5X of PCC
-'REPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991JAW) •
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) (J/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 4 M COSTS (J/kU-yr) =
VARIABLE 0 & M COSTS (mills/kW-hr) «
EFFECT OF CAPACITY
100 | 200 400 | 600 | 850

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

11706
1.0
4
1951
0.0
0.104


4.51
12.85
13.41
8.00
32.02
6.61


19.53
0.77
97.70
9.77
9.77
9.77
46.90
174
0
0
174
0.49
3.48
0
178

0.256
6.956
0.912
3.25
1.391

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

23413
1.0
4
3902
0.0
0.104


3.41
9.74
10.16
6.06
24.27
5.01


14.80
0.59
74.04
7.40
7.40
7.40
35.54
132
0
0
132
0.37
2.64
0
135

0.165
5.272
0.682
2.45
1.048

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

46826
1.0
4
7804
0.0
0.104


2.59
7.38
7.70
4.60
18.39
3.79


11.22
0.44
56.11
5.61
5.61
5.61
26.93
100
0
0
100
0.28
2.00
0
102

0.119
3.995
0.515
1.85
0.793

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

70239
1.0
4
11706
0.0
0.104


2.20
6.28
6.55
3.91
15.64
3.23


9.54
0.38
47.71
4.77
4.77
4.77
22.90
85
0
0
85
0.24
1.70
0
87

0.104
3.397
0.439
1.58
0.675

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

99505
1.0
4
16584
0.0
0.104


1.91
5.46
5.70
3.40
13.60
2.81


3.30
0.33
41.51
4.15
4.15
4.15
19.92
74
0
0
74
0.21
1.48
0
76

0.095
2.955
0.383
1.37
0.588
EFFECT OF C.F.
200 | 200

25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
O.OX

23413
1.0
4
3902
0.0
0.104


3.41
9.74
10.16
6.06
24.27
5.01


14.80
0.59
74.04
7.40
7.40
7.40
35.54
132
0
0
132
0.37
2.64
0
135

0.041
5.272
0.645
0.60
6.121

25
35
10. OX
0.65
N/A
22000
18200
0.65

10670
O.OX
•
23413
1.0
4
3902
0.0
0.104


3.41
9.74
10.16
6.06
24.27
5.01


14.80
0.59
74.04
7.40
7.40
7.40
35.54
132
0
0
132
0.37
2.64
0
135

0.268
5 272
0.713
4 06
0.384
EFFECT OF AGE
200 | 200

15
45
10. OX
0.40
N/A
22000
18200
0,65

10670
0.0%

23413
1.0
4
3902
0.0
0.101


3.41
9.74
10.16
6.06
24.27
5.01


14.80
0.59
74.04
7.40
7.40
7 40
35.54
132
0
0
132
0.37
2.64
0
135

0.165
5.272
0.682
2.45
1 048

40
20
10.0%
0.40
N/A
22000
18200
0.65

10670
0.0%:
j
23413 1
i.o !
4
3902 1
0.0
0.117


3.41
9.74
10.16
6 06
24.27
5.01


14 30
0.59
74 04
7 40
7.40
7.40
35 54
132
0
0
132
0.37
2 64
0
135 ,

0 16 =
5.272
0 582
2 45
1 :<13
G-33
-------
NOx CONTROL COSTS - GAS/OIL BOILERS glSwscrc.wkl
«ro . rnwToni i fn - UAI i -cTBFn UNITS -... 	 .....
(Johnson. 1991) Case 16| SIZE (HU)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MV-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft"3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-nr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) »
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kU-hr)
LEVELIZED 0 1 M COSTS
-FIXED 0 i M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mi lls/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES (J/kW-yr) »
LEVELIZED BUSBAR COST (mills/kW-hr) »
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) =•
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS (J/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL (J/ton) 45.84
OIL ($/bbl) 22.85
GAS (J/1000 ft~3) 2.61
AMMONIA (J/ton) 145.00
UREA (J/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST (J/ft'3) 660.00
CATALYST SOLID WASTE DISPOSAL (J/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY
	
100 200 400 | 600 | 850

208
0
3291
0
0
0

0.086
0.000
0.470
0.919
0.011
1.485

0.000
0.000
0.000

0.927
1.391
1.485
0.000
18.44
9.07

0.30
0.05
467
6798
0.10
374
8498

415
0
8237
0
0
0

0.086
0.000
0.588
0.919
0.011
1.603

0.000
0.000
0.000

0.698
1.048
1.603
0.000
13.98
7.34

0.30
0.05
935
5502
0.10
748
6877

830
0
18129
0
0
0

0.086
0.000
0.647
0.919
0.011
1.662

0.000
0.000
0.000

0.528
0.793
1.662
0.000
10.59
6.01

0.30
0.05
1869
4503
0.10
1496
5629

1246
0
28020
0
0
0

0.086
0.000
0.666
0.919
0.011
1.682

0.000
0.000
0.000

0.450
0.675
1.682
0.000
9.01
5.38

0.30
0.05
2804
4031
0.10
2243
5039

1765
0
40385
0
0
0

0.086
0.000 '
0.678
0.919
0.011
1.693

0.000
0.000
0.000

0.392
0.588
1.693
0.000
7.84
4.91

0.30
0.05
3972
3681
0.10
3178
4601
EFFECT OF C.F.
	
200 200

104
0
2059
0
0
0

0.086
0.000
0.538
3.675
0.042
4.391

0.000
0.000
0.000

0.680
6.121
4.391
0.000
13.98
27.15

0.30
0.05
234
20355
0.10
187
25443

675
0
13385
0
0
0

0.086
• o.ooo
0.588
0.565
0.006
1.245

0.000
0.000
0.000

0.714
0.384
1.245
0.000
13.98
4.80

0.30
0.05
1519
3598
0.10
1215
4497
EFFECT OF AGE

200 | 200

415
0
8237
0
0
0

0.086
0.000
0.588
0.919
0.011
1.603

Q.OOO
0.000
0.000

0.698
1.048
1.603
0.000
13.67
7.25

0.30
0.05
935
5436
0.10
748
6794

415
0
8237
0
Q
0

0.086
O.OOQ
0.583
0.919
0.011
1.603

o.oco
O.GOQ
O.OCO

0.698
1 048
1.603
O.OOQ
15 83
7 87

0 30
0 05
935
5899
0.1Q
743
7374
*

Electric Power Monthly, March 1991
Electric Power Monthly, March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie, 1991
Robie, 1991
G-34
-------
NOx CONTROL COSTS - GAS/OIL BOILERS g!7tscru.wkl
SCR - UNCONTKOLLtO - lANutNUAL-rlKtu -------- — -
(Johnson. 1991) Case 17| SIZE (MW)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (9STP:68F: 14.7ps1a)(1000 ft'3/nr)
NH3/NO RATIO FOR SCR (molar)
CATALYST LIFE (yrs)
CATALYST VOLUME (ft"3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
•Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage 4 Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Air Heater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kU) *
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10% of PCC
-PROJECT CONTINGENCY (% of PCC+EHOF+Proc) 40X
TCTAL PLANT COSTS (TPC) (1991$/kU) »
-ESCALATION (07.)
-AFDC (0%)
TCTAL PLANT INVESTMENT (1991$/kW) »
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) »
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-AOMIN/SUPPORT LABOR (J/kW-yr) 30X of OL+0.4MC
FIXED 0 8. M COSTS (J/kW-yr) *
VARIABLE 0 & M COSTS (mills/kW-hr) -
EFFECT OF CAPACITY
100 200 400 | 600 900

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

11706
1.0
4
1951
0.0
0.104


4.51
12.85
13.41
8.00
32.02
6.61


19.53
0.77
97.70
9.77
9.77
9.77
46.90
174
0
0
174
0.49
3.48
0
178

0.256
6.956
0.912
3.25
1.391

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

23413
1.0
4
3902
0.0
0.104


3.41
9.74
10.16
6.06
24.27
5.01


' 14.80
0.59
74.04
7.40
7.40
7.40
35.54
132
0
0
132
0.37
2.64
0
135

0.165
5.272
0.682
2.45
1.048

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

46826
1.0
4
7804
0.0
0.104


2.59
7.38
7.70
4.60
18.39
3.79


11.22
0.44
56.11
5.61
5.61
5.61
26.93
100
0
0
100
0.28
2.00
0
102

0.119
3.995
0.515
1.85
0.793

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

70239
1.0
4
11706
0.0
0.104


2.20
6.28
6.55
3.91
15.64
3.23


9.54
0.38
47.71
4.77
4.77
4.77
22.90
85
0
0
85
0.24
1.70
0
87

0.104
3.397
0.439
1.58
0.675

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

105358
1.0
4
17560
0.0
0.104


1.87
5.34
5.57
3.32
13.30
2.74


8.11
0.32
40.57
4.06
4.06
4.06
19.47
72
0
0
72
0.20
1.44
0
74

- 0.-Q94
2.889
0.375
1 34
0.575
EFFECT OF C.F.
200 200

25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
O.OX

23413
1.0
4
3902
0.0
0.104


3.41
9.74
10.16
6.06 '
24.27
5.01


14.80
0.59
74.04
7.40
7.40
7.40-
35.54
132
0
0
132
0.37
2.64
0
135

0.041
5 272
0.645
0.60
6 121

25
35
10. OX
0.65
N/A
22000
13200
0.65

10670
0.0%

23413
1.0
4
3902
0.0
0.104


3.41
9.74
10.16
6.06
24.27
5.01


14.80
0.59
74.04
7.40
7.40
7.40
35.54
132
0
0
132
0.37
2.54
0
135

0.268
5 272
0 713
4 06
0 384
EFFECT OF AGE
200 200

15
45
10. OX
0.40
N/A
22000
18200
0.65

10670
0.0%

23413
1.0
4
3902
0.0
0.101


3.41
9.74
10.16
6.06
24.27
5.01


14.80
0.59
74.04.
7.40
7.40
7.40
•35.54
132
0
0
132
0.37
2.64
0
135

0.165
5 272
0.682
2.45
1.048

40
20
10.0X1
0.40
N/A '
22000
18200
0.65

10670 i
O.Q%;

23413
1.0
4
3902
0.0
0.117


3.41
9.74
10 16
6.C6
24.27
5.01


14.80
0.59
74.04
7.40
7.40 '
7.40
35.54 ,
132
0
0
132
0 37
2.54
0
135

0.155
5 272
0 632
2 45
1 G48
G-35
-------
NOx CONTROL COSTS - GAS/OIL BOILERS g!7tscru.wkl
(Johnson. 1991) Case 17| SIZE (MW)
CONSUMABLES PENALTY
-AMMONIA (tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)
-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft'3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mills/kW-hr)
-UREA (mills/kW-hr)
-ELECTRICITY (mllls/kW-hr)
-CATALYST (mllls/kW-hp)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) *
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/ky-hr)
LEVEL I ZED 0 & M COSTS
-FIXED 0 8. M (mills/kU-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mllls/ky-Hr)
LEVELIZED CAPITAL CHARGES (J/kW-yr) »
LEVELIZEO BUSBAR COST (mills/kW-hr) *
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EfFECTIVENESS ($/ton) *
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yr)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL (J/ton) 45.84
OIL (J/bbl) 22.85
GAS (J/1000 ft"3) 2.61
AMMONIA ($/ton) 145.00
UREA ($/ton) 220.00
ELECTRICITY (J/kW-hr) 0.05
CATALYST COST ($/ft"3) 660.00
CATALYST SOLID WASTE DISPOSAL ($/ton) 315.00
OPERATING LABOR (J/man-hr) 21.45
EFFECT OF CAPACITY
100

208
0
3291
0
0
0

0.086
0.000
0.470
0.919
0.011
1.485

0.000
0.000
0.000

0.927
1.391
1.485
0.000
18.44
9.07

0.30
0.05
467
6798
0.10
374
8498
200 | 400 | 600 | 900

415
0
8237
0
0
0

0.086
0.000
0.588
0.919
0.011
1.603

0.000
0.000
0.000

0.698
1.048
1.603
0.000
13.98
7.34

0.30
0.05
935
5502 '
0.10
748
6877

830
0
18129
0
0
0

0.086
0.000
0.647
0.919
0.011
1.662

0.000
0.000
.0.000

0.528
0.793
1.662
0.000
10.59
6.01

0.30
0.05
1869
4503
0.10
1496
5629

1246
0
28020
0
0
0

0.086
0.000
0.666
0.919
0.011
1.682

0.000
0.000
0.000

0.450
0.675
1.682
0.000
9.01
5.38

0.30
0.05
2804
4031
0.10
2243
5039

1868
0
42858
0
0
0

0.086
0.000
0.680
0.919
0.011
1.695

0.000
0.000
0.000

0.383
0.575
1.695
0.000
7.66
4.84

0.30
0.05
4206
3628
0.10
3365
4535
EFFECT OF C.F.
200 | 200

104
0
2059
0
0
0

0.086
0.000
0.588
3.675
0.042
4.391

0.000
0.000
0.000

0.680
6.121
4.391
0.000
13.98
27.15

0.30
0.05
234
20355
0.10
137
25443

675
0
13385
0
0
0

0.086
0.000
0.588
0.565
0.006
1.245

0.000
0.000
0.000

0.714
0.384
1.245
0.000
13.98
4.30

0.30
0.05
1519
3598
0.10
1215
4497
EFFECT OF AGE
200 200

415
0
8237
0
0
0

0.086
0.000
0.588
0.919
0.011
1.603

0.000
0.000
0.000

0.698
1.048
1.603
0.000
13.67
7.25

0.30
0.05
935
5436
0.10
748
6794

415
Q
8237
0
Q
0

0.036
0.000
0.588
0.919
0.011
1.603

0.000
0.000
0.000

0.698
1.048
1.603
0.000
15.83
7 87

0.30
0.05
935
5899
0.10
748
7374


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts, 1991
Robie. 1991
BP Chemical. 1991
Robie. 1991
Robie. 1991
Robie. 1991
Robie. 1991
G-36
-------
NOx CONTROL COSTS - 3AS/OIL BOILERS glStscrc.wkl
SCR - CUNTKULLCU - TANutHI lAL-rlKtu ------ — ---
(Johnson. 1991) Case 18 | SIZE (HV)
BOILER AND FUEL SPECIFICATIONS
BOILER AGE (Years)
BOILER BOOK LIFE (Years)
ANNUAL DISCOUNT (INTEREST) RATE
CAPACITY FACTOR
COAL HHV (Btu/lb)
NATURAL GAS HHV (Btu/lb)
OIL HHV (Btu/lb)
OIL FRACTION
FUEL ASH CONTENT (X wt)
GROSS HEAT RATE (Btu/kW-hr)
EFFICIENCY LOSS
REBURN FRACTION
FLUE GAS FLOWRATE (0STP:68F:14.7psia)(1000 ft"3/nr)
NH3/NO RATIO FOR SCR (molar)
•CATALYST LIFE (yrs)
CATALYST VOLUME (ft "3)
UREA NSR (molar)
CAPITAL LEVELIZATION (RECOVERY) FACTOR
CAPITAL COSTS
PROCESS COSTS (1991$/kW):
-Burners
-Ducting
-Fan Upgrade/Replace
-Structural
-Reagent Storage & Distribution
-DeNOx Reactor/Catalyst
-Control System
-Flue Gas Heat Exchanger
-Air Heater
-Construction/Installation Labor
TOTAL PROCESS CAPITAL COSTS (PCC) (1991$/kW) »
-GENERAL FACILITIES (GF) 10X of PCC
-ENGINEERING/HOME OFFICE FEES (EHOF) 10X of PCC
-PROCESS CONTINGENCY (Proc) 10% of PCC
-PROJECT CONTINGENCY (X of PCC+EHOF+Proc) 40X
TOTAL PLANT COSTS (TPC) (1991$/kW) -

-ESCALATION (0%)
-AFDC (OX)
TOTAL PLANT INVESTMENT (1991JAW) =
-ROYALTY ALLOWANCE 0.5X of PCC
-PREPRODUCTION COSTS 2X of TPC
-INVENTORY CAPITAL (OX)
TOTAL CAPITAL REQUIREMENT (TCR) (1991$/kW) *
OPERATING AND MAINTENANCE COSTS (0 & M)
-OPERATING LABOR (OL) ($/kW-yr)
-MAINTENANCE COSTS (MC) ($/kW-yr) 4X of TPC
-ADMIN/SUPPORT LABOR ($/kW-yr) 30X of OL+0.4MC
FIXED 0 4 M COSTS (J/kW-yr) =
VARIABLE 0 S M COSTS (mills/kW-hr) =
EFFECT OF CAPACITY
100 200 400 600 | 900

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

11706
1.0
4
1951
0.0
0.104


4.51
12.85
13.41
8.00
32.02
6.61


19.53
0.77
97.70
9.77
9.77
9.77
46.90
174

0
0
174
0.49
3.48
0
178

0.256
6.956
0.912
3.25
1.391

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

23413
1.0
4
3902
0.0
0.104


3.41
9.74
10.16
6.06
24.27
5.01


14.80
0.59
74.04
7.40
7.40
7.40
35.54
132

0
0
132
0.37
2.64
0
135

0.165
5.272
0.682
2.45
1.048

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

46826
1.0
4
7804
0.0
0.104


2.59
7.38
7.70
4.60
18.39
3.79


11.22
0.44
56.11
5.61
5.61
5.61
26.93
100

0
0
100
0.28
2.00
0
102

0.119
3.995
0.515
1.85
0.793

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

70239
1.0
4
11706
0.0
0.104


2.20
6.28
6.55
3.91
15.64
3.23


9.54
0.38
47.71
4.77
4.77
4.77
22.90
85

0
0
85
0.24
1.70
0
87

0.104
3.397
0.439
1.58
0.675

25
35
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

105358
1.0
4
17560
0.0
0.104


1.87
5.34
5.57
3.32
13.30
2.74


8.11
0.32
40.57
4.06
4.06
4.06
19.47
72

0
0
72
0.20
1.44
0
74

0.094
2.889
0.375
1.34
0 575
EFFECT OF C.F.
200 200

25
35
10. OX
0.10
N/A
22000
18200
0.65

10670
O.OX

23413
1.0
4
3902
0.0
0.104


3.41
9.74
10.16
6.06
24.27
5.01


14.80
0.59
74.04
7.40
7.40
7.40
35.54
132

0
0
132
0.37
2.64
0
135

0.041
5.272
0.645
0.60
6.121

25
35
.10. OX
0.65
N/A
22000
18200
0.65

10670
O.OX

23413
1.0
4
3902
0.0
0.104


3.41
9.74
10.16
6.06
24.27
5.01


14.80
0 59
74.04
7.40
7.40
7.40
35.54
132

0
0
132
0.37
2.54
0
135

0.263
5.272
0.713
4 06
0.384
EFFECT OF AGE
200 200

15
45
10. OX
0.40
N/A
22000
18200
0.65

10670
O.OX

23413
1.0
4
3902
0.0
0.101


3.41
9.74
10.16
6.06
24.27
5.01


14.80
O.S9
74.04
7.40
7.40
7.40
. 35.54
132

0
0
132
0.37
2.64
0
135

0.165
5.272
0.682
2.45
1.048

40
20
10.0%
0.40
N/A
22000
18200
0.65

10670
0.0%
I
23413 '
1.0 :
4 !
3902
0.0
0.117


3.41
9.74
10.16
6 06
24.27
5.01


14.80 .
0 59
74.04
7.40
7.40
7 40
35.54
132 ;
I
0
o .
132
0.37
2.64
0
135

' 0.155
5 272
0 652
2.45 •
1 048
G-37
-------
NOx CONTROL COSTS - GAS/OIL BOILERS glStscrc.wkl

5UK - CONTROLLcD - lAHutNl lAL^rlKtu .-••——-
(Johnson. 1991} Case 18 1 SIZE (MV)
CONSUMABLES PENALTY
-AMMONIA {tons/yr)
-UREA (tons/yr)
-ELECTRICITY (MW-hrs/yr)

-COAL (tons/yr)
-OIL (bbl/yr)
-GAS (1000 ft*3/yr)
CONSUMABLES OPERATING COSTS (Excluding Fuel)
-AMMONIA (mUls/kW-hr)
-UREA (mUls/kW-hr)
-ELECTRICITY (mills/kW-hr)
-CATALYST (mills/kW-hr)
-CATALYST WASTE DISPOSAL (mills/kW-hr)
TOTAL CONSUMABLES (Excluding Fuel) (mills/kW-hr) *
FUEL COSTS
-COAL (mills/kW-hr)
-OIL (mills/kW-hr)
-GAS (mills/kW-hr)
LEVELIZED 0 & M COSTS
-FIXED 0 & M (mills/kW-hr)
-VARIABLE 0 & M (mills/kW-Hr)
-CONSUMABLES (mills/kW-Hr)
-FUEL (mills/kW-Hr)
LEVELIZED CAPITAL CHARGES ($/kU-yr) »
LEVELIZED BUSBAR COST (mills/kU-hr) -
EMISSIONS
-UNCONTROLLED NOx (Ib/MMBtu)
-LOWER CONTROLLED NOx (Ib/MMBtu)
-LOWER NOx REDUCTION (tons/yr)
-LOWER NOx REMOVAL COST EFFECTIVENESS ($/ton) *
-HIGHER CONTROLLED NOx (Ib/MMBtu)
-HIGHER NOx REDUCTION (tons/yc)
-HIGHER NOx REMOVAL COST EFFECTIVENESS ($/ton) »
UNIT
APPLICABLE UNIT PRICING COST
COAL ($/ton) 45.84
OIL (S/bbl) 22.85
GAS (J/1000 ft* 3) 2.61
AMMONIA ($/ton) 145.00
UREA (J/ton) 220.00
ELECTRICITY ($/kW-hr) 0.05
CATALYST COST ($/ft*3) 660.00
CATALYST SOLID WASTE DISPOSAL (S/ton) 315.00
OPERATING LABOR ($/man-hr) 21.45
EFFECT OF CAPACITY

............................... _.. ....
100 200 400 | 600 900

138
0
3291

0
0
0

0.057
0.000
0.470
0.919
0.011
1.456

0.000
0.000
0.000

0.927
1.391
1.456
0.000
18.44
9.04

0.20
0.05
280
11294
0.10
187
16941

277
0
8237

0
0
0

0.057
0.000
0.588
0.919
0.011
1.574

0.000
0.000
0.000

0.698
1.048
1.574
0.000
13.98
7.31

' 0.20
0.05
561
9134
0.10
374
13701

554
0
18129

0
0
0

0.057
0.000
0.647
0.919
0.011
1.633

0.000
0.000
0.000

0.528
0.793
1.633
0.000
10.59
5.98

0.20
0.05
1122
7470
0.10
748
11204

830
0
28020

0
0
0

0.057
0.000
0.666
0.919
0.011
1.653

0.000
0.000
0.000

0.450
0.675
1.653
0.000
9.01
5.35

0.20
0.05
1682
6683
0.10
1122
10024

1246
0
42858

0
0
0

0.057
0.000
0.680
0.919
0.011
1.666

0.000
0.000
0.000

0.383
0.575
1.666
0.000
7.66
4.81

0.20
0.05
2524
6010
0.10
1682
9015
EFFECT OF C.F.

	
200 200

69
0
2059

0
0
0

0.057
0.000
0.588
3.675
0.042
4.362

0.000
0.000
0.000

0.680
6.121
4.362
0.000
13.98
27.12

0.20
0.05
140
33889
0.10
93
50833

450
0
13385

0
0
0

0.057
0.000
0.588
0.565
0.006
1.217

0.000
0.000
0.000

0.714
0.384
1.217
0.000
13.98
4.77

0.20
0.05
911
5960
0.10
608
8940
EFFECT OF AGE

	
200 | 200

277
0
8237

0
0
0

0.057
0.000
0.588
0.919
0.011
1.574

d.OOO
0.000
0.000

0.698
1.048
1.574
0.000
13.67
7.22

0.20
0.05
561
9023
0.10
374
13535

277
0
8237

0
0
0

0.057
0.000
0.588
0.919 !
0.011 '
1.574 i

0.000
0.000
0.000

0.698
1.048
1.574 i
0.000 ,
15.83 ,
7.84

0.20
0.05
561
9796
• 0.10
374
14694


Electric Power Monthly. March 1991
Electric Power Monthly. March 1991
Gas Facts. 1991
Robie. 1991
BP Chemical. 1991
Robie, 1991
Robie, 1991
Robie. 1991
Robie. 1991
G-38
-------
                          APPENDIX H




DATA BASE ON CO, HC, AND UBC UNDER BASELINE AND LOW-NOX OPERATION
                             H-l
-------
NESCAUM UTILITY BOILER NOx EVALUATION — CO AND UNBURNED CARBON DATA, PULVERIZED COAL FIRED BOILERS
Boiler Unit and Capacity
(maximum continuous rating. MWe)
WALL-FIRED UNITS:
Scotland. UK: Orax Unit 6
Opposed Fired. 660 MW










EPOC Matsuura Unit 1
Opposed Fired. 1000 MW
CEGB Eggborough Unit 2
Wall Fired, 500 MW





Alleghany Power: Pleasants Unit 2
Opposed Fired. 650 MW


ELKRAFT Power Co.: ASNAES Unit 4
Wall Fired. 285 MW

Ohio Edison: Edgewater Unit 4
Wall Fired. 100 MW

UK: NEI-ICL
Wall Fired. 500 MW














Load
(MWe)

660











1000

500






626



278


100


500















NOx
Control
Type

LNB










basel ine
LNB

LN8



baseline
(unit 1)

OFA
LNB
LNB. OFA
baseline
LNB

baseline
LNB

baseline
LNB






basel me








Burner
Type

Mark III











HT-NR

CF/SF
MK-II






CF/SF
CF/SF wit

BWE


XCL


F. Wall















Fuel

U.K.
Bituminous










Bituminous








U.S. Bituminous

i OFA

H.Vol Polish





















Emissions
NOx
Ib/MMBtu

0.44
0.53
0.55
0.45
0.52
0.58
0.49
0.52
0.45
0.51
0.56
1.11
0.13-0.30

0.60
0.57
0.52
0.45
1.03
0.92
0.84
0.65
0.41
' 0.33
0.95
0.49

0.99
0.47
0.53
0.71
0.36
0.45
0.45
0.49
0.53
0.60
0.64
0.73
0.76
0.77
0.79
0.80
0.83
0.85
0 88
0.91
NOx
ppm93%02

328
395
410
340
393
435
365
391
335
382
422
832
101-228

450
425
390
340
770
690
630
490
310
250
710
370

740
350
400
530
270
335
340
370
400
450
480
550
570
580
590
600
620
640
660
685
UBC
X

6.5
3
2
4
2.5
2
3
1.8
3.3
1.5
1
1-1.5
.45-4

3
7
5.5
7.2
1.2
1.9
2.5
2.5
2.5

2.5
<5

5
6
2.8
2.2
7
5.5
5
4
3.5
1.75
0.75
5
5.2
5
4.5
4.3
3.8
3.2
2.6
2 1
CO
ppm33'/.02






















40-50
40
100
40



60
115
20
50
25
10
10
10
15
9
80
60
45
38
30
25
23
21
20
Source

King. 1991











Uemura, 1991

Beard. 1989






Vatsky. 1939



Pederson.
1991

La Rue. 1S89


Allen, 1991















H-3
-------
NESCAUM UTILITY BOILER NOx EVALUATION -- CO AND UNBURNEO CARBON DATA. PULVERIZED COAL FIRED BOILERS
Boiler Unit and Capacity
(maximum continuous rating. HWe)
WALL-FIRED UNITS:
Germany: RUE
Wall Fired. 600 HW



-







ENEL: Vado Ligure Unit 4
Opposed Fired. 330 HW



Riley Stoker Coal Burner Test
Facility. Wall Fired
100 MMBtu/hr




Arizona Pub. Svc.: Four Corners 4
Opposed Fired. BOO MW

Georgia Power Co.: Hammond Unit 4
Oposed Fired. 500 HW


Load
(MWe)

75







600




330











800


500



NOx
Control
Type

OFA







baseline




OFA


basel ine

LNB



baseline


LNB

baseline
LNB

AOFA
baseline
Burner
Type














Cell




ccv



Flare


CF/SF






Fuel

Rhinisch brown
coal











U.S. Eastern
Bituminous



U.S. Eastern
Bituminous





U.S.
Sub-bituminous

U.S. Eastern
Bituminous


Emissions
NOx
Ib/HMBtu

0.27
0.26
0.24
0.21
0.19
0.17
0.15
0.13
0.45
0.42
0.37
0.29
0.26
0.52
0.57
0.63
0.78
0.93
0.31
0.40
0.45
0.59
0.67
0.72
0.79
0.50

1.27
0.55-0.7

0.9-0.95
1-1.2
NOx
ppm@3%02

205
195
180
160
145
125
110
100
340
317
280
220
195
390
427
472
584
700
230
300
340
440
500
540
590
375

950
412-525

675-712
750-900
UBC
%














12
8
7.7
6
5.5







0.1

0.1
5.5-8

9.5-10
4.5-5
CO
ppm03%02

20
20
20
20
20
20
180
260
10
10
10
100
400
8
8
8


100
78
75
60
75
67
65
20-40

<4Q
10-20

10-15
30-100
Source

Hem. 1989












Tarli. 1991




Lisauskas.
1989





Vatsky. Lu,
1991

Sorge. 1992



H-4
-------
NESCAUM UTILITY BOILER NOx EVALUATION — CO AND UNBURNED CARBON DATA. PULVERIZED COAL FIRED BOILERS
Boiler Unit and Capacity
(maximum continuous rating, MWe)
TANGENTIAL UNITS:
ENEL: Fuslna Unit 2
Tangential, 160 MW

PSCC: Valmont Unit 5
Tangential. 165 MU

Kansas P&L: Lawrence Unit 5
Tangential. 400 MW
PSCC: Cherokee Unit 4
Tangential. 350 MU
Labadie Unit 4
Tangential , 600 MW
Lansing Smith Unit 2
Tangential. 200 MW

CYCLONE UNITS:
Nelson Oewey Unit 2
Cyclone, '100 MW
Ohio Edison: Niles Unit 1
Cyclone, 108 MW
Babcock & Wilcox SBS (pilot scale)
Cyclone. 6 MMBtu/hr
TURBO FURNACE:
PSI: Wabash Unit 5
Turbo Furnace, 105 MW
Load
(MWe)
160

165

300
380
600
200

100
108

95
NOx
Control
Type
LNB/OFA
baseline
LNB/OFA
baseline
LNB/OFA
baseline
LNB/OFA
baseline
LNB/OFA
basel ine
LNB/OFA
LNB/OFA
baseline
coal
reburn
baseline
NG
reburn
baseline
reburn
basel ine
LNB
baseline
Burner
Type
LNCFS

LNCFS

PM
LNCFS
LNCFS
LNCFS II
LNCFS III




Riley CCV
Fuel
U.S. Eastern
Bituminous

U.S. Western
Bituminous

U.S. Bituminous
U.S. Western
Bituminous
U.S. Bitum/
Subbituminous
U.S. Eastern
Bituminous

U.S. Bituminous
U.S. Eastern
Bituminous
Indiana bitum

Emissions
NOx
lb/MM8tu
0.55
0.53
0.47
0.40
0.35
0.30
0.67
0.27
0.40.
0.67
0.53
0.24-0.3
0.43-0.5
0.27
0.53
0.45
0.50-0.69
0.40
0.34
0.6-0.65
0.36
0.81
0.37
0.94
0.4-0.8
1.37
0.45
0.85
NOx
ppm@3%02
410
400
350
300
265
225
500
200
300
500
400
180-225
325-375
205
400
340
375-520
300
255
450-490
270
610
275
705
300-600
1025
340
640
UBC
X
3.5
8.8
9
9.5
10
10.25
7-9
1.6
1.6
1.6
1.6
0.3
0.4
2.5
2.2
0.5-1
3.8-5.
5.5-6.
4.4-5

30-35
30-35
5.1
3.5
3.5
10
CO
ppm83%02
< 40
< 40
< 40
< 40
< 40
< 40

<30
<30
<30
<30

<30
<30
5-35
20-32
25-65
10-15
90
90
35
<30
<50
<50

Source
Grusha. 1991

Hunt.
Grusha, 1991

Thompson.
1989
Hunt. 1991
Smith. 1992
Hardman, 199

Newell. 1992
Sooth. 1991
Yagiela.
1991
Penterson.
1991
H-5
-------
NESCAUM UTILITY BOILER NOx EVALUATION — CO EMISSION DATA. NATURAL GAS FIRED BOILERS
Boiler Unit and Capacity
(maximum continuous rating, MWe)
ENEL: Fusina Unit 2
Tangential. 160 MU







ENEL: Rossano Unit 4
Opposed Fired. 320 MW





ENEL: Sermide Unit 3
Opposed Fired, 320 MU

B&W XCL Burner
Wall Fired. 120 MBtu/hr



Germany: Arzberg Unit 6
Wall Fired, 220 MW

San Diego G&E: South Bay Unit 1
Wall Fired. 150 MW


Southern Cal Ed. Alamitos Unit 6
Opposed Fired. 480 MW




Southern Cal Ed. Redondo Unit 8
Opposed Fired. 480 MW

New England Power Service Co.
LNB Evaluation Project
Wall Fired. 80 MBtu/hr
Load
(MWe)
160








320






320







220


150



260-
480




480





NOx
Control
Type
LNB







baseline
BOOS (12



baseline
Burner
Type
LNCF








burners)




(18 burners)

BOOS (12

baseline
LNB



baseline
LNB

baseline
fuel
biasing
BOOS
baseline
LNB
w/BOOS
&FGR
BOOS
&FGR
baseline
BOOS

baseline
LNB



burners)


XCL




STS






Todd








TTL/MG22.


Emissions
NOx
Ib/MMBtu
0.05
0.05
0.06
0.07
0.08
0.10
0.12
0.17
0.21
0.26
0.28
0.29
0.31
0.36
0.40
0.41
0.10

0.40
0.09
0.08
0.06
0.04
0.06-0.13
0.06

0.36
0.13

0.14
0.20
0.02-0.08


0.03-0.13

0.84
0.07

0.10
0.07
0.06

NOx
ppm03X02
40
45
50
60
70
80
100
145
175
220
235
245
263
300
330
340
83

333
74
65
SO
33
50-110
50

300
no

113
170
16-65


25-112

700
56

87
60
54

CO
ppm03y.02
175
150
110
80
70
60
50
47
40
280
120
90
32
160
40
25
32


36
46
35
36

15


300

3700
250
0-330


0-700


90

100
12
12

Source
Grusha.
Tarli. 1991







Benanti .
1989





Tarli. 1991


La Rue. 1989




Li sauskas.
1991

Quartucy.
1987


Bayard de
Volo. 1991




McOannel
1991

Afonso
1991

H-6
-------
                                    TECHNICAL REPORT DATA
                            (Please read Instructions on the reverse before completing)
1. REPORT NO.
 EPA-453/R-92-010
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
  Evaluation and Costing  of NOx Controls  for Existing
  Utility Boilers in  the  NESCAUM Region
5. REPORT DATE
  December 1992
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
   Carlo Castaldini
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
  Acurex Environmental Corporation
  Post Office Box 7044
  Mountain View, California  94039
                                                            10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
      68-D1-0146
12. SPONSORING AGENCY NAME AND ADDRESS
  U.S.  Environmental  Protection Agency
  Control Technology  Center (MD-13)
  Office of Air Quality  Planning and  Standards
  Research Triangle Park,  NC .27711
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
  EPA Project Engineer:   William J. Neuffer (919) 541-5435
  NESCAUM Project Manager:   Praven Amar  (617)  367-8540
16. ABSTRACT
  This Technical Report discusses NOx  controls for utility  boilers in the Northeast
  States for Coordinated Air Use Management (NESCAUM) region.   The document  discusses:

    o   Utility boiler  population profile in the NESCAUM  region
    o   Uncontrolled  NOx emissions and factors that affect  NOx emissions
    o   Available NOx controls and their  levels of performance
    o   Cost methodology for determining  the costs of NOx controls
    o   Costs and cost  effectiveness of NOx controls
    o   Impacts of  NOx  controls on combustible emissions
17.
                                KEY WORDS AND DOCUMENT ANALYSIS
                  DESCRIPTORS
                                               b. IDENTIFIERS/OPEN ENDED TERMS  C.  COSATI Field/Group
  NOx Emissions
  Control  techniques for NOx emissions
     from utility  boilers
  Utility Boilers
  Combustion Modifications
18. DISTRIBUTION STATEMENT
                                               19. SECURITY CLASS /Tins Report/
              21. NO OF PAGES
                   426
                                               20. SECURITY CLASS (Tins pagei
                                                                          22. PRICE
EPA Form 2220-1 (R«v. 4-77)   PREVIOUS EDITION is OBSOLETE
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EPA Form 2220-1 (Rev. 4-77) (Reverse)
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