&EPA
            United States      Industrial Environmental Research  EPA-600/7-78-120a
            Environmental Protection  Laboratory          June 1978
            Agency        Research Triangle Park NC 27711	
            Characterization of
            Stationary NOX
            Sources: Volume I.
            Results
            nteragency
            Energy/Environment
            R&D Program  Report

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                  RESEARCH REPORTING SERIES


 Research reports of the Office of Research and Development, U.S. Environmental
 Protection Agency, have been grouped into nine series. These nine broad cate-
 gories were established to facilitate further development and application of en-
 vironmental technology. Elimination of  traditional grouping was  consciously
 planned to foster technology transfer and a maximum interface in related fields.
 The nine series are:

    1. Environmental Health Effects Research

    2. Environmental Protection Technology

    3. Ecological Research

    4. Environmental Monitoring

    5. Socioeconomic Environmental Studies

    6. Scientific and Technical Assessment Reports (STAR)

    7. Interagency Energy-Environment Research and Development

    8. "Special" Reports

    9. Miscellaneous Reports

 This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
 RESEARCH AND  DEVELOPMENT series. Reports in this series result from the
 effort funded under the 17-agency  Federal Energy/Environment Research and
 Development Program. These studies relate to EPA's mission to protect the public
 health and welfare from adverse effects of pollutants associated with energy sys-
 tems. The goal of the Program is to assure the  rapid  development of domestic
 energy supplies in an environmentally-compatible manner by providing the nec-
 essary environmental data and control technology. Investigations include analy-
 ses of the transport of energy-related pollutants and their health and ecological
 effects; assessments  of, and development of, control technologies  for  energy
 systems; and integrated assessments of a wide'range of energy-related environ-
 mental issues.
                        EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for  publication. Approval does not signify that the contents necessarily reflect
the  views and policies of the Government, 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 Informa-
tion Service, Springfield, Virginia 22161.

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                                  EPA-600/7-78-120a
                                             June 1978
  Emission  Characterization
of Stationary  NOX  Sources:
        Volume  I.  Results
                     by

     K.G. Salvesen, KJ. Wolfe, E. Chu, and M.A. Herther

    Acurex Corporation/Energy and Environmental Division
                485 Clyde Avenue
           Mountain View, California 94042
             Contract No. 68-02-2160
            Program Element No. EHE624A
          EPA Project Officer: Joshua S. Bowen

       Industrial Environmental Research Laboratory
         Office of Energy, Minerals, and Industry
           Research Triangle Park, NC 27711
                  Prepared for

       U.S. ENVIRONMENTAL PROTECTION AGENCY
          Office of Research and Development
              Washington, DC 20460

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                                   PREFACE







       This  is the third  in a  series of  10  special  reports  to  be



documented in the "Environmental Assessment of  Stationary Source  NO
                                                                   A


Combustion Modification Technologies"  (NO   E/A).  The  NO  E/A  is  a
                                         X              A


36-month program which began in July 1976.  The program has  two main



objectives:  (1) to identify the multimedia environmental impact  of



stationary combustion sources  and NO  combustion modification  controls,
                                    A


and (2) to identify the most cost-effective, environmentally sound NOY
                                                                     A


combustion modification controls for attaining and maintaining current and



projected N02 air quality standards to the year 2000.  The reports



resulting from this effort will document the economic, environmental and



operational impact of reducing NO  to a given level on specific
                                 A


combustion sources with current and emerging control technology.  This



information is intended for use by:



       •   Equipment manufacturers and users concerned with selecting the



           most appropriate control techniques to meet regulatory standards



       •   Control R&D groups concerned with providing a sufficient



           breadth of environmentally sound control techniques to meet the



           diverse control implementation needs in N0~ critical Air



           Quality Control Regions



       •   Environmental planners involved in formulating abatement



           strategies to meet current or projected air quality standards
                                    m

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       The program  structure  incorporating the above objectives is shown



 in Figure P-l.   The rectangular  symbols  denote specific subtasks while the



 oval  symbols  show program output.   The arrows show the sequence of



 subtasks and  the major  interactions among tasks.   The top half of the



 figure shows  the initial  effort  to  set preliminary source/control



 priorities.   These  efforts are  documented in the  "Preliminary



 Environmental  Assessment  of Combustion Modification Techniques," October



 1977, EPA report 600/7-77-119a.   The bottom half  of the figure shows the



 major program efforts which are  currently underway.



       The  two major tasks in the NO  E/A are:  (1) Process Engineering
                                     A


 and  Environmental Assessment, and (2) Systems Analysis.  In the first



 task, the environmental,  economic,  and operational impacts  of specific



 source/control combinations will  be assessed.  On the basis of this



 assessment, the incremental multimedia impacts from the use of combustion



 modification  NO controls will be identified and  ranked.  The systems
                /\


 analysis task  will  in turn use these results to identify  and  rank the most



 effective source/control  combinations to  comply,  on a local basis,  with



 the  current NOp air quality standards and  projected NO,, related



 standards.  As  shown  in Figure P-l,  the supporting  tasks  for  these  efforts



 are  the Baseline Emissions  Characterization,  Evaluation of  Emission



 Impacts and Standards, and  Experimental Testing.



       The emissions characterization  documented  in  this  report supports



both the environmental assessment task and the  systems  analysis.  The



major objective  is  to assess  the multimedia  pollution potential  of



effluent streams from uncontrolled  stationary  fuel  combustion  sources.



This will be accomplished  by:   (1)  updating  and refining  emission



estimates from  earlier emissions  inventories,  and  (2) approximating





                                    iv

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EMISSION
CHARACTERIZE! ION (Bl)
COMPILE COMBUSTION
SOURCE PROCESS
BACKGROUND
t

GENERATE MULTIMEDIA
EMISSION INVENTORY



IMPACTS ?.
STANDARD, (••?)
CHARACTERIZE PRIMARY
& SECONDARY MULTI-
MEDIA POLLUTANTS
*
DEFINE MULTIMEDIA
ENVIRONMENTAL GOALS


GENERATE EMISSION
PROJECTIONS & REGIONAL
VARIATIONS


L
EXPERIMENTAL F
TESTING (B3) I
ROCESS ENGINEERING &
NVIRONMENTAL ASSESSMENT
COMPILE N0x
CONTROL PROCESS
BACKGROUND
'
1
EVALUATE DATA ON
INCREMENTAL EMISSIONS
WITH N0x CONTROLS
,
j—^^"^^

-\
(B5)
— »—
- ^PRELIMINARY SOURCE?\

PROJECT N02
ENVIRONMENTAL
GOALS


DEFINE SAMPLING
AND ANALYSIS
REQUIREMENTS
t
CONDUCT FIELD
TESTS
-*— — -
f CONTROL PRIORITIES ON\
[BASIS OF POTENTIAL If-1-K'
VACT & PROJECTED USE /
X^Tl-^
i

GENERATE CONTROL
TECHNOLOGY PROCESS
STUDIES OF MAJOR
SOURCES
p
COMPARE  BASELINE
EMISSIONS  TO MULTIMEDIA
ENVIRONMENTAL GOALS
    BASELINE IMPACT
    ASSESSMENT
IMPACT CRITERIA
STANDARD PROJECTIONS
COMPARE CONTROLLED
EMISSIONS TO
MULTIMEDIA GOALS
  SELINE AND
CONTROLLED EMISSION
DATA
                                                                      RANKING OF POTEN-
                                                                      TIAL  IMPACTS WITH
                                                                    OMBUSTION MODIFICAT!0
                                                                      CONTROLS
SYSTEMS
ANALYSIS (C)
DEVELOP PRELIMINARY
MODEL FOR ENVIRONMENTAL
ALTERNATIVES STUDY
'

SCREEN CONTROL
REQUIREMENTS FOR -
AIR QUALITY MAIN-
TENANCE


SELECT AND ADAPT •
REACTIVE AIR QUALITY
MODEL

'
PROJECT SOURCE
GROWTH & AMBIENT
STANDARDS
                                  ASSESS  CONTROL
                                  REQUIREMENTS FOR
                                  ALTERNATE ABATEMENT
                                  STRATEGIES
                                                                                                                                           COMBUSTION MODI-
                                                                                                                                       [FICATION  CONTROL DEVEL-\
                                                                                                                                           OPMENT  PRIORITIES
                                                                                                                                        x-	^
                                                               Figure P-l.   NOX  E/A  approach.

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emissions transport and transformation to obtain estimates of ambient



pollutant concentrations.  The resultant concentrations are then compared



to multimedia impact criteria to flag sources, effluent streams, and



pollutants with potential for adverse environmental  effects.  This



comparison results in an incremental multimedia  impact ranking of



stationary sources and provides the baseline reference for the subsequent



assessment of the environmental, economic,  and operational impacts  of



specific source/control combinations.  Other objectives of the emission



characterization are to:  (1) evaluate regional  emission patterns due to



source, fuel, and emission control distribution, and  (2) project equipment



population, fuel usage, and emissions to the year  2000.  These efforts



support the systems analysis of alternate NO  controls, since regional
                                            X


inventories and  source projections to the year 2000  are required in the



air quality modeling to determine NO  control needs  for meeting and
                                    X


maintaining ambient air quality standards.



       This report is comprised of two volumes.  Volume I contains  the



documentation for generating present and future  emissions inventories and



assessing the pollution impact potential of emissions from specific



equipment/fuel combinations.  Volume II presents the  supporting appendices



for these tasks.

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                             TABLE OF CONTENTS


Section
           PREFACE	     in

           LIST OF ILLUSTRATIONS	     xi

           LIST OF TABLES	     xiii

           ACKNOWLEDGEMENT	     xvii

   1       INTRODUCTION	     1-1

           1.1   Objectives of this Report	     1-2
           1.2   Organization and Structure of Report  	     1-3
           1.3   Technical  Summary 	     1-5

   2       NO  SOURCE CHARACTERIZATION 	       2-1
             A

           2.1   Stationary Fuel  Combustion Sources  	     2-4
           2.2   Periodic or  Nonstandard Operations  	     2-22

           2.2.1   Utility  and Large Industrial  Boilers  	     2-22
           2.2.2   Packaged Boilers  	     2-22
           2.2.3   Warm Air Furnaces	     2-24
           2.2.4   Gas Turbines	     2-27
           2.2.5   Reciprocating  1C Engines	     2-30

           2.3   Equipment  Trends  	     2-32

           2.3.1   Utility  and Large Industrial  Boilers  	     2-32
           2.3.2   Packaged Boilers  	     2-34
           2.3.3   Warm Air Furnaces	    2-35
           2.3.4   Gas Turbines	    2-35
           2.3.5   Reciprocating  1C Engines	    2-36
           2.3.6   Industrial  Process  Trends  	    2-38

           2.4   Mobile Combustion  Sources 	    2-41
           2.5   Noncombustion Sources 	    2-42
           2.6   Fugitive Emissions  	    2-43
           2.7   Conclusions	    2-44

   3        FUELS CHARACTERIZATION AND  CONSUMPTION   	    3-1

           3.1   Fuel  Characteristics	    3-1
           3.2   Fuel  Consumption	    3-6

           3.2.1   Utility  and Large Industrial  Boilers  .....    3-8
           3.2.2   Packaged Boilers  	    3-10
           3.2.3   Warm Air Furnaces and  Other Commercial
                   and Residential  Combustion   	    3-12
                                  VII

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                       TABLE OF CONTENTS  (Continued)

Section

           3.2.4   Gas Turbines	     3-13
           3.2.5   Reciprocating  1C Engines	     3-15
           3.2.6   Industrial Process Heating   	     3-16

           3.3   Regional Fuel Consumption	     3-19

           3.3.1   Utility and Large  Industrial  Boilers   	     3-21
           3.3.2   Packaged Boilers   	     3-23
           3.3.3   Warm Air Furnaces  and  Other  Commercial
                   and Residential Combustion   	     3-24
           3.3.4   Gas Turbines	     3-24
           3.3.5   Reciprocating  1C Engines	     3-25
           3.3.6   Industrial Processes   	     3-26

           3.4   Energy Scenario  Development  	     3-27

           3.4.1   Energy Alternatives  	     3-28
           3.4.2   Key Uncertainties  in Scenario Development  .  .  .     3-34

           3.5   Equipment Scenarios  	     3-37

           3.5.1   Stationary Source  Type	     3-37
           3.5.2   Equipment Attrition Rates  	     3-37
           3.5.3   Summary	     3-38

    4       MULTIMEDIA EMISSIONS INVENTORIES   	     4-1

           4.1   Emission Factors  	     4-2

           4.1.1   Utility and Large  Industrial  Bo-ilers	     4-3
           4.1.2   Packaged Boilers   	     4-6
           4.1.3   Warm Air Furnaces	     4-10
           4.1.4   Gas Turbines	     4-11
           4.1.5   Reciprocating  1C Engines	     4-13
           4.1.6   Industrial Process Combustion  	     4-14

           4.2   Inventory of Control Implementation 	     4-18

           4.2.1   Particulate Control 	     4-20
           4.2.2   SOX Control	     4-22
           4.2.3   NOx Control	     4-23
           4.2.4   Regional  Controls  	     4-24

           4.3   Projected  Emissions  Regulations  	     4-25

           4.4   National  Emissions Inventory — 1974  	     4_31

           4.4.1   Stationary Source  Sector Emissions  	     4_31
           4.4.2   Summary  of Air  Pollutant Emissions	     4_32
                                 vn i

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Section
                       TABLE OF CONTENTS  (Continued)
           4.5   National Emissions  Inventories  —  1985,  2000
Page

4-38
           4.5.1   Summary of Air Pollutant Emissions	     4-41
           4.5.2   Summary and Conclusions	     4-50

           4.6   Regional Emissions Inventory   	     4-53

           4.6.1   Conclusions		     4-55

   5       SOURCE ANALYSIS MODEL 	     5-1

           5.1   Source Analysis Model 	     5-1

           5.1.1   Gaseous Effluent Streams  	     5-2
           5.1.2   Liquid and Solid Effluent Streams 	     5-15

           5.2   Data Requirements	     5-19

           5.2.1   Emission Rates	     5-21
           5.2.2   Point Source Stack Heights   	     5-21
           5.2.3   Urban/Rural Air Quality Control Regions
                   (AQCRs)	     5-22
           5.2.4   Urban/Rural Equipment Splits  	     5-23
           5.2.5   Urban and Rural  Ambient Pollutant
                   Concentrations  	     5-23
           5.2.6   Average Source Fuel Consumption 	     5-25

           5.3   Source Analysis Modeling Results  	     5-25

           5.3.1   Gaseous Pollution Potential  Rankings  	     5-26
           5.3.2   Liquid and Solids Pollution
                   Potential  Ranking 	     5-37

           5.4   Conclusions	     5-45

                      TABLE OF CONTENTS FOR VOLUME II

Section                                                                Page

   A       REGIONAL FUEL CONSUMPTION TABLES FOR 1974	     A-l

   B       NATIONAL FUEL CONSUMPTION TABLES FOR 1984, 2000 ....     B-l

   C       NATIONAL CRITERIA POLLUTANT EMISSIONS FOR 1974  ....     C-l

   D       EMISSION INVENTORY  	     D-l

   E       REGIONAL STATIONARY SOURCE COMBUSTION CONTROLS  ....     E-l
                                  IX

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                       TABLE OF CONTENTS (Concluded)

Section                                                               Page

   F      NATIONAL SOURCE POLLUTION POTENTIAL ASSESSMENT
          FOR 1974	    F-l

   G      POLLUTION POTENTIAL SUMMARIES FOR THE ENERGY
          PROJECTION SCENARIOS IN 1985 AND 2000	    G-l

   H      POLLUTION POTENTIAL TRENDS TO THE YEAR 2000
          FOR THE ENERGY PROJECTION SCENARIOS  	    H-l

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                           LIST OF ILLUSTRATIONS
Figure                                                                Page

 P-l       NO  E/A Approach	    v
             A

 1-1       Emissions characterization approach 	    1-4

 2-1       Sources of nitrogen oxide emissions 	    2-3

 2-2       Characteristic emissions of oil burners during one
           complete cycle  	    2-25

 2-3       Gas turbine generator emissions due to power
           variations	    2-28

 2-4       The effect of turbine speed and air-fuel  ratio on
           NO  concentrations	    2-29
             A

 2-5       Effect of A/F ratio on emissions in a gasoline
           engine	    2-31

 3-1       Regional fuel  distributions 	    3-20

 3-2       Regional fuel  distributions for utility and large
           industrial  boilers  	    3-22

 3-3       Energy scenarios  	    3-29

 4-1       Energy representation in the environmental  scenario.
           (Assuming only one NSPS, constant  between  time
           limits) .  .  ._	    4-28

 4-2       Distribution of anthropogenic NO  emissions
           for the year 1974	    4-34

 4-3       NOX emissions  projections --  stationary sources
           (reference  scenario  -- high nuclear)   	    4-51

 4-4       NOX emissions  projections --  stationary sources
           (reference  scenario  -- low nuclear) 	    4-52

 5-1       Ground-level concentration -- Gaussian  plume  	    5-5

 5-2       Limits of integration for point sources 	    5-7

 5-3       Ground-level concentration -- distributed  sources .  .  .    5-13

 5-4       Limits of integration for distributed  sources  	    5-14

 5-5       Air impact  analysis  calculation sequence   	    5-16
                                   XI

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                     LIST OF ILLUSTRATIONS  (Concluded)


Figure                                                                Page

 5-6       Liquid and solid impact analysis calculation
           sequence	    5-20

 5-7       Air Quality Control Regions (AQCRs) 	    5-24
                                xn

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                                LIST OF TABLES


Table                                                                  Page

2-1        Summary of Utility and Large  Industrial  Boiler
           Characterization  	     2-5

2-2        Summary of Packaged  Boiler Characterization  	     2-8

2-3        Summary of Warm Air  Furnaces  Characterization 	     2-10

2-4        Summary of Gas Turbine Characterization  	     2-12

2-5        Summary of Reciprocating 1C Engine Characterization  .  .     2-13

2-6        Summary of Industrial Process Heating Charac-
           terization  	     2-14

2-7        Summary of Advanced  Combustion Systems   	     2-17

2-8        Significant Stationary Fuel Combustion Equipment
           Types/Major Fuels 	     2-19

2-9        Effect of Nonstandard Operating Procedures on the
           Effluent Streams from a Dry Bottom Pulverized Coal-
           Fired Boiler	     2-23

3-1        Properties and Trace Elements of Representative
           Fossil Fuels  	     3-5

3-2.        1974 Stationary Source Fuel Consumption  (EJ)	     3-7

3-3        1974 Utility Boiler  Fuel  Consumption (EJ)	     3-9

3-4        1974 Packaged Boiler Fuel  Consumption (EJ)	     3-11

3-5        1974 Warm Air Furnace and  Other Commercial and
           Residential Combustion Fuel Consumption  (EJ)  	     3-14

3-6        1974 Gas Turbine Fuel Consumption (EJ)	     3-14

3-7        1974 Reciprocating 1C Engine Fuel Consumption (EJ)   .  .     3-17

3-8        1974 Industrial Process Heating Production  	     3-18

3-9        1974 Refinery Process Heating Fuel Consumption (EJ)  .  .     3-18

3-10       Forecasts of Total U.S. Energy Consumption in 1985
           and 2000 (EJ)	     3-30
                                  xin

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                          LIST  OF TABLES  (Continued)
Table
3-11       1985 Stationary  Source  Fuel  Consumption:   Reference
           Case -- High Nuclear  (EJ)  ...............     3-39

3-12       2000 Stationary  Source  Fuel  Consumption:   Reference
           Case - High Nuclear  (EJ)  ...............     3-40

3-13       1985 Stationary  Source  Fuel  Consumption:   Reference
           Case — Low Nuclear  (EJ)   ...............     3-41

3-14       2000 Stationary  Source  Fuel  Consumption:   Reference
           Case — Low Nuclear  (EJ)   ...............     3-42

4-1        Utility Boiler Criteria Pollutant  Emission
           Factors (ng/J)   ....................     4-4

4-2        Packaged  Boiler  Criteria  Pollutant Emission
           Factors (ng/J)   ...................  .     4-7

4-3        Warm Air  Furnace and  Miscellaneous Commercial  and
           Residential Combustion  Criteria  Pollutant  Emission
           Factors (ng/J)   ....................     4-11

4-4        Gas Turbine Criteria  Pollutant Emission
           Factors (ng/J)   ....................     4-12

4-5        Reciprocating  1C Engines  Criteria  Pollutant  Emission
           Factors (ng/J)   ....................     4-14

4-6        Industrial Process Combustion Criteria Pollutant
           Emission  Factors (g/kg  Product)  ............     4-16

4-7        Refinery  Process Heating  Criteria  Pollutant  Emission
           Factors (ng/J)   ....................     4-17

4-8        Average Participate Collection   ............     4-21

4-9        Estimated Future NSPS Controls   ............     4-26

4-10       Annual Criteria  Pollutant Emissions By Sector
           (Uncontrolled NO ) (Gg) ................     4-33
                            /\

4-11       Summary of 1974  Stationary Source  NO  Emissions
           By Fuel — Gg ........... * .........     4.35

4-12       Comparison of Controlled and Uncontrolled  Annual
           Stationary Source NOV Emissions  .... ........     4-36
                               X
                                   xiv

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                         LIST OF TABLES  (Continued)


Table                                                                  Page

4-13       Summary of Air  and Solid  Pollutant  Emissions  From
           Stationary Fuel  Burning Equipment  (Gg)   	     4-37

4-14       NOX Mass Emission Ranking of  Stationary Combustion
           Equipment and Criteria Pollutant and  Fuel  Use Cross
           Ranking	     4-39

4-15       Summary of Annual NOX Emissions from  Fuel  User
           Sources (1985):  Reference  Scenario ~ Low Nuclear   .  .     4-42

4-16       Summary of Annual NOX Emissions from  Fuel  User
           Sources (2000):  Reference  Scenario — Low Nuclear   .  .     4-43

4-17       Summary of Annual NOX Emissions from  Fuel  User
           Sources (1985):  Reference  Scenario — High Nuclear  .  .     4-44

4-18       Summary of Annual NOX Emissions from  Fuel  User
           Sources (2000):  Reference  Scenario -- High Nuclear  .  .     4-45

4-19       Year 1985 — NOX Mass Emissions Ranking for Stationary
           Combustion Equipment and  Criteria Pollutant Cross
           Ranking	     4-46

4-20       Year 2000 -- NOX Mass Emissions Ranking for Stationary
           Combustion Equipment and  Criteria Pollutant Cross
           Ranking	     4-48

4-21       Distribution of Regional  Uncontrolled NO   Emissions
           (Gg) ~ 1974	?	     4-54

5-1        Total Pollution Potential Ranking (Gaseous) Stationary
           Sources in Year 1974	     5-27

5-2        Average Source Pollution  Potential  Ranking (Gaseous)
           Stationary Sources in Year 1974	     5-29

5-3        NOX Pollution Potential  Ranking Stationary Sources
           in 1974	     5-31

5-4        Total Pollution Potential Ranking (Gaseous) Stationary
           Sources in Year 1985	     5-33

5-5        Total Pollution Potential Ranking (Gaseous) Stationary
           Sources in Year 2000	, .  .  .     5r35

5-6        Total Pollution Potential Cross Ranking (Gaseous)
           Stationary Sources in Year 1974	     5-38
                                    xv

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                         LIST OF TABLES (Concluded)


Table                                                                  Page

5-7        Utility Boilers  — Pollution Potential  of Single
           Pollutants	,  .     5-40

5-8        Packaged Boilers  —  Pollution  Potential  of Single
           Pollutants	     5-41

5-9        Gas Turbines, Reciprocating  1C Engines,  and Industrial
           Process Heating  -- Pollution Potential  of Single
           Pollutants	     5-42

5-10       Pollution Parameters  (Liquid and  Solid)  Stationary
           Sources in Year  1974	     5-43

5-11       Total Pollution  Potential Ranking  (Liquid  and Solid)
           Stationary Sources in  Year 1974	     5-44

5-12       Total Pollution  Potential Ranking  (Gaseous)
           Stationary Sources in  Year 1974	     5-50

5-13       Total Pollution  Potential Ranking  (Gaseous)
           Stationary Sources in  Year 1985	     5-52

5-14       Total Pollution  Potential Ranking  (Gaseous)
           Stationary Sources in  Year 2000	     5-54
                                   xvi

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                              ACKNOWLEDGEMENT







       Acurex extends its appreciation for the valuable assistance



provided by the following individuals and their organizations:  H. Melosh



of Foster Wheeler Corp.; G. Bouton and S. Potterton of Babcock and Wilcox



Co.; G. Devine, C. Richards and J. Drenning of Combustion Engineering Co.;



F. Walsh and R. Sadowski of Riley Stoker Corp.; S. Barush of the Edison



Electric Institute; D. Dell'Agnese of the Cleaver Brooks Division,



Aqua-Chem Corp.; W. Day of General Electric Co.; and S. Mosier of Pratt



and Whitney Corp.  Thanks are also in order to D. Bell, J. Copeland, K.



Woodard, D. Trenholm, C. Sedman, and G. Crane of the Emission Standards



and Engineering Division, of the Office of Air Quality and Planning



Standards, of the EPA.



       Special thanks are extended to Dr. J.  Bowen and R.  Hall of the



Combustion Research Branch of EPA for their careful  review and comments



during this program.
                                  xvn

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                                  SECTION 1




                                 INTRODUCTION








        Since  the  Clean  Air Act of 1970,  a moderate level  of NO  control



has been  developed  and  implemented for many stationary combustion  NO



sources.   However,  recent  EPA studies  show that  stationary source  controls



must be  increased to  maintain N02 ambient air  quality.  The need for



additional  stationary NO   controls results from  easing  of mobile source
                        A


emission  standards,  increasing stationary source NO   emissions,  and  the



prospect  of a short-term NO,,  air  quality standard.



       Since NO  controls  now are being  implemented  and additional
               /\


controls  will be developed  in the future,  there  is a pressing  need to



affirm that these controls  are environmentally sound and  ensure  that the



timing and  implementation  of  emerging  controls will  allow stationary NO
                                                                       X


sources to meet future  air  quality standards.  The NO   E/A program



addresses these needs by:   (1)  identifying the multimedia environmental



impact of stationary  combustion NO sources, (2)  identifying the
                                   A


incremental multimedia  environmental impact  of combustion modification



NO  controls, and (3) identifying  the  most cost-effective source/control



combinations to maintain alternate ambient N02 standards  through the



year 2000 in N02 critical  areas.
                                   1-1

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1.1    OBJECTIVES OF THIS  REPORT



       The emissions characterization effort supports the NO  E/A
                                                             ^


objectives by compiling and evaluating data on current and projected



stationary source fuel consumption and multimedia emissions.  These



results  are  used in the NO  E/A to set priorities on  stationary  source
                           /\


equipment types according to  national or  regional emissions.



Additionally, the emission estimates generated  in this task  are  used



 together with estimates of pollutant impact criteria to  define the  impact



 potential of  specific  source/fuel  combinations  during baseline,



 uncontrolled  operation.   The  resulting  estimate of  impact potential  is



 used as a reference for the  subsequent  assessment  of the impact  potential



 of NO  combustion modification controls.   The results also are used to
      A


 highlight areas where  additional R&D is  required to quantify baseline



 impacts or control requirements.



        The major steps  in the emissions  characterization task are  as




 fo11ows:



        •   Categorize  stationary NO   source  equipment/fuel  combinations
                                    A


            according to pollutant formation  potential



        •   Quantify current stationary source fuel consumption,  by



            equipment type, on a regional  and national basis



        •   Compile multimedia effluent emission factors  for the



            combinations of equipment/fuel/effluent streams identified as



            significant




        t   Develop a national and regional multimedia emissions  inventory



            for stationary combustion sources for 1974



        •   Estimate the extent of NO  controls on a  national basis-
                                     r\                             '


            generate a controlled  national NO  emissions inventory





                                     1-2

-------
       •   Formulate energy,  equipment,  and  control  scenarios



           representative  of  projected  national  trends;  project national



           emissions to the year  2000



       t   Develop a source analysis modeling  methodology  to  rank  various



           source/fuel combinations according  to  pollution  potential



       •   Provide problem definition and  priorities  for future research



           and controls development



1.2    ORGANIZATION AND STRUCTURE OF REPORT



       Figure 1-1 shows the approach of the  emissions characterization



task and the organization  of  this report.  The preliminary



characterization of NO  equipment sources, compilation of emission
                      /\


factors, and determination of fuel consumption which resulted in the 1974



controlled national emissions inventory are  documented in the "Preliminary



Environmental Assessment of Combustion Modification Techniques"  (Reference



1-1).  Section 2 of this report describes the characterization  and



classification of NO  sources.  This classification was carried through
                    X


the environmental rankings and will be used  for process engineering



efforts and systems analyses  in future tasks.  Section 2 includes a



summary of sources and effluent streams that are of potential concern as



NO  sources.
  A


       Section 3 summarizes data on fuels composition and usage.  Both



regional and national fuel usage are needed  to generate comprehensive



national and regional emissions inventories  for 1974.  National fuel



consumption was projected  through the year 2000, considering several



possible conditions such as conservation, use of nuclear power  and coal



conversion.  These scenarios  are required to generate the future
                                    1-3

-------
      Section 4
                                           Section 2
                                                                                Section  3
       Select
     pollutants
      Evaluate
    emission data
       Develop
  emission factors
 Develop controlled
  emission factors
   Categorize NOX
 equioment sources
    Determine sector
    fuel consumptions
      Identify
    waste streams
    Define equipment
    fuel consumptions
national and regional
 baseline emissions
  inventories 1974
Obtain  regional equipment
    fuel consumptions
Controlled emissions
   inventory 1974
  Project emission
       factors
   Develop control
      scenarios
Contrslled emissions
inventory 1985,  2000
1 Characterize
sinale sources
"



(Determine urban/rur.al
equipment distributions

Develop energy
scenarios


1 Obtain sector
fuel projections

(Determine
population exoosures
1.





Develop
equipment scenarios










1 Project
equipment distribution



t

(Project
fuel consumption






Assess
late technologies

                                        Assessment of
                                      pollution potential
               Figure  1-1.   Emissions  characterization approach.
                                                1-4

-------
emissions inventories  in  Section  4  and  to  conduct the source analysis



modeling in Section  5.



       In Section 4, multimedia effluents  are quantified for the



combinations of equipment types,  fuels,  and  effluent streams identified in



Sections 2 and 3.  Both a national  emissions inventory and  regional



inventories are presented for  1974.   Additionally,  the current and



projected implementation  of  NO  controls  is  estimated to yield
                               A


controlled NO  inventories for 1974,  1985, and 2000.
             /\


       The energy projections,  equipment distribution trends,  and  future



environmental regulations from Section 4 are integrated  in  Section 5  with



urban/rural equipment  distributions  and  source population proximities  to



provide inputs to the  Source Analysis Model  (SAM).   The  SAM approximates



pollutant transport  to estimate ground  level  pollutant concentration



profiles.  These concentrations are compared  to pollutant impact criteria



to estimate the population potentially exposed  to adverse levels of



pollutant concentrations.  These  results are  used to  rank sources



according to their multimedia  environmental  impact.   The results highlight



where R&D is needed  to further  quantify impact  potential or  to control



adverse emission levels for specific source/pollutant combinations.   It



should be noted here that the  results of this  study  are  meant  as



qualitative indicators of potential problems  rather  than rigid priorities.



1.3    TECHNICAL SUMMARY



       In this report, gaseous,  liquid, and  solid effluents  from



stationary sources are assessed  .  National  and regional emissions



inventories are developed for  the year 1974.   Then,  emissions  are



projected to the years 1985 and 2000 for five  energy  scenarios which



represent alternate  energy futures.  Rankings  of  stationary sources are





                                    1-5

-------
presented for national emissions in years 1974, 1985, and  2000.   Using



these data as inputs, a source analysis model was developed  to evaluate



the total pollution potential of stationary combustion sources.   Rankings



of pollution potential are provided for 1974 and for the years 1985  and



2000 based on the reference high nuclear energy scenario with stringent



New Source Performance Standard (NSPS) controls.



       Major results of this report are as follows:


       t   Utility boilers generate about 50 percent of stationary source



           NO  emissions, packaged boilers about 20 percent, and  all
             A


           other anthropogenic sources the remaining 30 percent.   Although



           there are over 70 equipment/fuel combinations,  the 30  most



           significant sources account for about 90 percent  of all



           combustion related NO  emissions.  Tangential coal-fired
                                X


           utility boilers have the highest total nationwide NO
                                                               /\


           emission loading* while reciprocating 1C engines  firing natural



           gas are the second highest.



       •   NO  reductions from implementing controls were negligible in
             A


           1974.  Based on a survey of boilers in areas with NO
                                                               A


           emission regulations,  it is estimated that applying NO
                                                                 X

           controls resulted in a 3.0 percent reduction in nationwide



           utility boiler emissions.   This  corresponds to a  1.6 percent



           reduction in total  stationary fuel combustion  emissions.


       t   Under the low nuclear  growth scenario,  total  NO  emissions
                                                          X


           are projected to  increase  by about 30 percent  by the year 2000,



           even under stringent NSPS  control.  Utility boiler emissions



           are projected to  increase  by about 80 percent  over 1974 levels,



           even with NSPS implementation.   However,  if nuclear energy  is




                                   1-6

-------
used to provide a larger share of national electrical  needs,



these projected NO  increases will be significantly  lower.
                  J\


Regional emissions inventories developed for 1974 show



significant regional variations  in NO  by equipment/fuel
                                     A


type.  These variations result from both the regional  fuel mix



and from the distribution of stationary source equipment.



The 1974 source assessment ranking indicates that coal-fired



utility and stoker-fired boilers have the largest pollution



impact potential of all stationary sources.  Beryllium has the



largest potential impact of all pollutant species.  Moreover,



of all fossil fuels, coal firing generates the largest



emissions of beryllium.  Since use of coal is projected to



increase significantly from 1974 to the year 2000, the



pollution potential  of coal-fired stationary sources should



increase proportionally during this period.
                         1-7

-------
                          REFERENCES FOR SECTION 1

1-1.   Mason,  H.  B.,  et.  al.,  "Preliminary Environmental  Assessment of
      Combustion Modification Techniques:  Volume II,  Technical Results,"
      EPA-600/7-77-119b,  NTIS-PB 276 68I/AS,  Acurex Corp.,  October 1977.
                                   1-8

-------
                                  SECTION  2
                        NOV  SOURCE  CHARACTERIZATION
                          A
       This section  presents  a  preliminary  characterization  of  NO
                                                                 A


sources that will be used to  structure the  environmental, assessment  and



process engineering  efforts in  the NO  E/A  program.   The  main objective
                                     A


is to categorize equipment design according to characteristics  which



affect the formation and/or control potential of multimedia  pollutants.



Emphasis is on stationary combustion sources of NO .  However,  other
                                                  A


sources of NO  also  are of interest in this program,  since the  extent to
             J\


which NO  controls are needed for stationary combustion sources depends
        A „


on how well these other sources can be controlled.



       To characterize NO  sources, the following steps were performed:
                         A


       •   Identify significant sources of  NO ; group sources according
                                             A


           to formative mechanism and nature of release into the



           environment



       t   Categorize stationary combustion sources according to equipment



           and/or fuel characteristics affecting the  generation and/or



           control of combustion generated  pollution



       t   Qualify equipment fuel categories on the basis of current and



           projected use and design trends; develop a provisional list of



           equipment/fuel combinations to be carried  through subsequent
                                    2-1

-------
           emissions inventories, process studies, and environmental




           assessments



       •   Identify effluent streams from stationary combustion  source



           equipment/fuel categories which may be perturbed when N0x



           combustion modification controls are used



       •   Identify operating modes (transients, upsets, maintenance)



           which perturb emissions when using NO  combustion
                                                /\


           modification controls



       Significant sources of NO  are grouped in Figure 2-1 according to
                                J\


the way NO  is released into the atmosphere and the mechanisms leading
          A


to its formation.  On a global basis, natural emissions caused by



biological decay and lightning account for about 90 percent of total NO
                                                                       A


emissions.  However, in urban areas up to 90 percent of ambient NO  is
                                                                  n,


produced by manmade sources — primarily in combustion effluent streams.



The seven major categories of stationary sources bracketed under "fuel



combustion" in the figure are emphasized throughout the NO  £/A.
                                                          X


       Stationary combustion sources that may have a significant impact on



NOX emissions are categorized in Section 2.1.   Transient and nonstandard



conditions are discussed in Section 2.2.  Section 2.3 describes major



trends in equipment types; the equipment categories and trends described



in this section are the basis for the inventories in Section 4 and the



source analysis modeling in Section 5.   Mobile emissions are described



briefly in Section 2.4, noncombustion sources  are discussed in Section



2.5,  and fugitive emissions are  described  in  Section 2.6.   A general



assessment of data is  given in Section  2.7.
                                    2-2

-------
ro
i
                  Sources of
                  nitrogen  —
                  oxides
                                     Combustion
                                     effluent stream
                                     emissions
Noncombustion
effluent
stream	
                                     emissions
                                     (Section 2.5)
                                     Fugi ti ve
                                    •emissions—~
                                     (Section 2.6)
                                                            •Stationary-	
                                                             (Section 2.1)
                                                                                  -Fuel 	
                                                                                   combustion
                                             '-Incineration
                                                             Mobile
                                                             "(Section 2.4)
                                                            rNatural-
                                                            • Anthropogenic
                                                                  -Utility Boilers
                                                                  -Packaged Boilers
                                                                  -Warm Air Furnaces
                                                                  -Gas Turbines
                                                                  -Reciprocating 1C Engines
                                                                  -Industrial  Process  Combustion
                                                                  -Advanced Combustion Processes
                                  Emphasis
                                     of
                                  NOX E/A
-Nitric acid
-Adipic acid
 Explosives
                                                                  -Fertilizer
                                                                  -Nitration

                                                                   Nitrogen cycle
                                                                   Lightning

                                                                  -Open burning
                                                                  "Forest fires
                                                                  -Structural fires
                                                                  -Minor processes
                                            Figure  2-1.   Sources of nitrogen oxide  emissions.

-------
2.1    STATIONARY FUEL COMBUSTION SOURCES



       The major categories of stationary fuel combustion sources  are



summarized in Tables 2-1 through 2-6.  These tables  list the major designs



in each sector, and the variations  in design and fuels  which are  known  to.



affect emissions.  The primary design types are those projected for



widespread use  in the 1980's  and thus, are candidates for application of



NO  controls.   Secondary design types are those that are either
   /\


diminishing  in  use or are  unlikely  candidates  for widespread use  of N0x



controls  in  the near future.  Secondary  design types will be considered in



this  report, but  not in subsequent  NO  E/A studies.   Major  design
                                     A


 characteristics of each firing type are  given  in these  tables  to  provide



 general  descriptions of combustion  sources.  The effluent streams  and



 operating modes presented  in  these  tables represent  general operating



 conditions and may vary for  different combustion units.  The effluent



 streams  identified are  inputs for the emissions inventory in Section 4  and



 the  pollution potential ranking in  Section 5.  Because  quantitative data



 on the effects  of transient  and nonstandard operating conditions were



 sparse,  these data were not  considered further in the emissions inventory.



       Table 2-7 describes several  alternate or advanced energy systems



 that  are in  developmental  stages.   A number of these systems are  expected



 to be used commercially in the 1980's and 1990's.



       The final  categorization of  stationary  combustion sources  is



 presented in Table 2-8.  This table shows the  equipment/fuel categories



 that  merit separate consideration in the emissions inventory in Section 4



 and  the  ranking of pollution  potential in Section 5.
                                    2-4

-------
                TABLE 2-1.   SUMMARY OF UTILITY AND LARGE INDUSTRIAL BOILER CHARACTERIZATION  (Reference  2-2)


Design Type
Tangential





















Single Mall








Design
Characteristics
Fuel and air nozzles
in each corner of
the combustion
chamber are directed
tangent i ally to a
small firing circle
in the chamber.
Resulting spin
of the flames mixes
the fuel and air in
the combustion zone.














Burners mounted
to single furnace
wall — up to
36 on single wall.









Process Ranges
Input Capacity;
73 MW to 3800 MW

Steam Pressure:
18.6 MPa (subcritical)
26.2 HPa (supercritical)

Steam Temperature:
755K to 840K
Furnace Volume:,
Up to 38,000 m

Furnace Pressure
50 Pa to
1000 Pa
Furnace Heat Release:
Coal *- 104 to 250
kW/mJ
Oil, gas *- 208 to
518 kW/mJ
Excess Air
25% coal
10* oil
8% gas
Units typically limited
in capacity to about
400 MW (electric) because
of furnace area.








Fuel Consumption
(*)
67* coal fired
18* oil fired
15* gas fired




















43% coal
22* oil fired
35* gas fired









Effluent Streams
Gaseous
Flue gas contain-
ing flyash, vola-
tilized trace
elements, SO,
NO, other e
pollutants.

Liquid
Scrubber streams,
as.i sluicing
streams, wet
bottom slag
streams.

Solid
Solid ash removal

Flyash removal






Gaseous
Flue gas contain-
ing flyash, vola-
tilized trace
elements, S0?,
NO, other
pollutants.
Ljquid
Scrubber streams,
ash sluicing
streams, wet
bottom slag
streams.

Solid
Solid ash removal
Flyash removal

Operating
Modes
Soot blowing, on-
off transients,
load transients,
upsets, fuel
additives, rap-
ping, vibrating.


















Soot blowing, on-
off transients
load transients,
upsets, fuel
additives, rap-
ping, vibrating.






Effects of Transient
Nonstandard
Operation
During startup,
NOX emissions are
low since flame
temperatures not
developed. During
load reductions,
emissions of NO
decrease because
of lower flame
temperatures.
NOX should de-
crease following
soot blow due to
Improved heat
transfer.










During startup,
NOX emissions are
low since flame
temperatures not
developed. Dur-
ing load reductions,
emissions of NOX
decrease because
of lower flame
temperatures.
NOX should de-
crease following
soot blow due to
improved heat
transfer.




Trends
Trend toward
coal firing in
new units; con-
version to oil
and coal in
existing units.

19.4* of current
installed units.















Trend toward
coal firing in
new units; wet
bottom units no
longer manufac-
tured due to
operational
problems with
low sulfur coals
and high combus-
tion tempera-
tures promoting
NO
*V
59* of current
installed units.


Future
Importance
Pr imary





















'rimary







ro
i
01
                                                                                                                    T-847

-------
TABLE 2-1.   Continued


Design Type
Horizontally
Opposed Wall















Turbo
Furnace












Design
Characteristics
Burners are mounted
on opposite furnace
walls -- up to 36
burners per wall.













Air and fuel fired
down toward furnace
bottom using burners
spaced across
opposed furnace
walls. Flame propo-
gates slowly passing
vertically to the
upper furnace. NO
is usually low due
to long combustion
time and relatively
low flame tempera-
ture.



Process Ranges
Units typically designed
in sizes greater than
400 HW (electric).














Units typically designed
in sizes greater than
400 MW (electric)











Fuel Consumption
{*)
32* coal
21* oil
47* gas
(includes turbo
furnace)












32* coal
21* oil
47% gas
(includes
horizontally
opposed wall)










Effluent Streams
Gaseous
Flue gas contain-
ing flyash,
volatilized trace
elements, SO,,
NO, other i
pollutants.

Liquid
Scrubber streams,
ash sluicing
streams, wet
bottom slag
streams.

Solid
Solid ash removal
Flyash removal
Gaseous
Flue gas contain-
ing flyash,
volatilized trace
elements, SO,,
NO, other t
pollutants.

Liquid
Scrubber streams,
ash sluicing
streams, wet
bottom slag
streams.


Operating
Modes
Soot blowing, on-
off transients,
load transients,
upsets, fuel
additives, rap-
ping, vibrating.











Soot blowing, on-
off transients,
load transients,
upsets, fuel
additives, rap-
ping, vibrating.








Effects of Transient,
Nonstandard
Operation
During startup,
NO emissions are
low since flame
temperatures not
developed. Dur-
ing load reductions,
emissions of NO
decrease because
of lower flame
temperatures.
NO should de-
crease following
soot blow due to
improved heat
transfer.



During startup,
NO emissions are
low since flame
temperatures not
developed. Dur-
ing load reductions,
emissions of NO
decrease because
of lower flame
temperatures.
NO should de-
crease following
soot blow due to
improved heat
transfer.


Trends
Trend toward
coal firing and
conversions to
oil and coal
firing; again,
wet bottoms
being phased
out.
8.2* of current
installed units.
units.






Trend toward
coal firing —
(capacity in-
cluded with
opposed wall).









Future
Importance
Pr imary
















Primary











T-847

-------
                                                         TABLE 2-1,   Concluded


Design Type
Cyclone















Vertial and
Stoker















Design
Characteristics
Fuel and air intro-
duced circumferen-
tially into cooled
furnace to produce
swirling, high tem-
perature flame;
cyclone chamber
separate from main
furnace; cyclone
furnace must operate
at high temperatures
since it is a slag-
ging furnace.




Vertical firing re-
sults from downward
firing pattern.
Used to a limited
degree to fire
anthracite coal.

Stoker projects fuel
into the furnace
over the fire per-
mitting suspension
burning of fine
fuel particles.
Spreader stokers
are the primary
design type.


Process Ranges
Furnace Heat Release:
4.67 to 8.28 MW/mJ














Surface Heat Release:
1.1 to 1.9 MW/m^















Fuel Consumption
(X)
92* coal
4* oil
4* gas













100* coal

















Effluent Streams
Gaseous
Flue gas contain-
ing flyash, vola-
tilized trace
elements, SO,,,
NO, and othef-
pollutants.

Liquid
Scrubber streams

Solid
Solid ash removal

Flyash removal


Gaseous
Flue gas contain-
ing flyash, vola-
tilized trace
elements, S0? ,
NO, and other
pollutants.

Liquid
Scrubber streams

Solid
Solid ash removal

Flyash removal


Operating
Modes
Soot blowing, on-
off transients,
load transients,
upsets, fuel
additives, rap-
ping, vibrating.










Soot blowing, on-
off transients
load transients,
upsets, fuel
additives, rap-
ping, vibrating.










Effects of Transient
Nonstandard
Operation
During startup,
NO emissions are
low since flame
temperatures not
developed. Dur-
ing load reductions,
emissions of NO
decrease because
of lower flame
temperatures.
NO should de-
crease following
soot blow due to
improved heat
transfer.


During startup,
NO emissions are
low since flame
temperatures not
developed. Dur-
ing load reductions,
emissions of NO
decrease becausl
of lower flame
temperatures.
NO should de-
crease following
soot blow due to
improved heat
transfer.



Trends
Two cyclone
boilers sold
since 1974
have not proven
adaptable to
emissions regu-
lations. Must
operate at high
temperatures re-
sulting in high
thermal NO
fixation; also
operational
problems with
low sulfur coal.
3.3* of installed
units.
Since anthracite
usage has de-
clined, vertical
fired boilers are
no longer sold.

Design capacity
limitations and
high cost have
caused stokers
usage to diminish.

9.9* of current
installed units.



Future
Importance
Secondary















Secondary















rvs
i
                                                                                                                          T-847

-------
                                  TABLE 2-2.  SUMMARY OF  PACKAGED  BOILER CHARACTERIZATION


Design Type
Water-tube












Scotch
Firetube














HRT Fire-
tube








Design
Characteristics
Combustion gases
circulate around
boiler tubes that
have water passing
through them.
Essentially the
only type of boiler
available above 29
MW (heat input).





Cylindrical shell
with one or more
furnaces in the
lower portion. Com-
bustion takes place
in front section.
Combustion products
flow back to rear
combustion chamber,
flow through tubes
to smoke box, then
discharge.




Hot gases pass to
back of unit, enter
horizontal tubes,
returning to front
of the boiler then
exit through smoke
box.


Typical
Operational
Values
Oil-Fired Watertube:
Capacity: 38 MW
Furnace volume:
123 m3
Heat release:
310 kW/m3
Burner type:
steam atomization
Fuel preheat:
392K
Stack temperature:
422K
Excess oxygen: 5X

Scotch Firetube-Oil:
Capacity: 2.9 MU
Furnace volume:
2.5 m3
Heat release:
1190 kW/m3

Operating pressure
1030 kPa

Burners:
Air atomizing (2)
Fuel preheat:
3?1K
Excess oxygen:
4.9X









Fuel Consumption
(*)
41* coal
21X oil
38% gas










59X oil
41* gas














55* oil
35* gas









Effluent Streams
Gaseous
Flue gas
Particulate
catch
Hopper ash

liquid
Ash sluicing
water
Scrubber streams

Solids
Solid ash
removal
Flue gas
Bottom ash














Flue gas
Bottom ash








Operating
Modes
Soot blowing,
on-off transients,
upsets, fuel ad-
ditives.









On-off transients,
load transients,
upsets, fuel ad-
ditives.












On-off transients,
load transients,
upsets, fuel ad-
ditives.





Effects of Transient,
Nonstandard
Operation
During startup,
low NOX emissions.

During load
reductions NOX
lowered.
Soot blowing
should cause lower
gas temperature
due to improved
heat transfer,
thus lowering NOX.

Changes in firing
rate have little
effect on NOX
emissions from
firetubes. Fuel
oil temperature
increases tend to
decrease NO*
emissions.







Changes in firing
rate have little
effect on NOX
emissions from
firetubes. Fuel
oil temperature
increases tend to
decrease NOx
emissions.


Trends
Pulverized coal
and stokers for
large watertubes.










Scotch firetubes
currently show
growth over other
firetube designs.












Trend toward de-
creasing use of
HRT.







Future
Importance
Pr imary












Primary















Secondary







ro
i
OD
                                                                                                                      T-849

-------
                                                 TABLE 2-2.  Concluded

Design Type
Firebox
Firetube





Cast Iron
Boilers










Steam and
Hot Water
Units







Design
Characteristics
Combustion gases
enter front of first
tube pass, travel to
rear smoke box, re-
turn through second
pass to gas outlet
at the boiler front.
Gases rise through
vertical section,
and discharge
through the exhaust
duct. Water is heat-
ed as it passes up-
wards through the
watertubes .









Besides small resi-
dential units, shell
boilers, compact,
locomotive, short
firebox, vertical
firetube, straight
tube, and coal re-
search designs are
grouped here.
Typical
Operational
Values






Cast Iron:
Distillate oil
Capacity: 0.38 MU
Furnace volume:
0.57 m3
Heat release:
673 kW/m3

Operating pressure:
103 kPa
Burner type:
Pressure
atomizing (1)
Fuel preheat:
None
Excess oxygen:
4.4%










Fuel Consumption
{*)
53% oil
57% gas





59% oil
41% gas










1.5% coal
56% oil
42.5% gas







Effluent Streams
Flue gas
Bottom ash





Flue gas
Bottom ash










Flue gas









Operating
Modes
On-off transients,
load transients,
upsets, fuel ad-
ditives.



On-off cycling,
transients










On-off cycling,
transients







Effects of Transient,
Non standard
Operation
Changes in firing
rate have little
effect on NOx emis-
sions from firetubes.
Fuel oil temperature
increase. tend to de-
crease NOx emissions.





















Trends
Decreasing use of
firebox firetubes


























Future
Importance
Secondary





Secondary










Secondary








T-849
ro
i

-------
                                TABLE 2-3.  SUMMARY OF WARM AIR  FURNACES CHARACTERIZATION


Design Type
Commercial
and Resi-
dential
Central
Warm Air
Furnaces















Space
Heaters













Design
Characteristics
Furnaces in central
heaters enclosed in
steel casing; fuel
burned in combustion
space of heat ex-
changers. Heat ex-
changers have a
single combustion
chamber, either
cylindrical or di-
vided into indivi-
dual sections;
combustion gases
pass through secon-
dary gas passages of
the heat exchanger
and exit through
flue.



Room heaters self-
contained; equipped
with a flue if oil
fired. Heat by
radiation, or natural
or forced air cir-
culation.









Design Ranges
Typical Gas-Fired Forced
Air Furnace

Heat exchanger
area: 2.8 to 3.3 ra2
Draft system:
Natural
Excess combustion air:
20* to 50%
Overall heat
transfer coefficient:
11.3 to 17 W/m2K
Combustion chamber
pressure:
± 49.8 Pa
Exit flue gas
temperature:
506 to 617K
Overall efficiency:
75* to 80%
On-off operation















Fuel Consumption
(*)
31* distillate
oil
69* gas
(Miscellaneous
combustion fuels
such as wood, LPG,
etc. combined
with natural gas.)













23* distillate
oil
73* gas
(Miscellaneous
combustion fuels
such as wood, LPG,
etc., combined
with natural gas.)
(Includes other
residential com-
bustion.)





Effluent Streams
Flue gas




















Flue gas














Operating
Modes
On-off cycling,
transients



















On-off cycling,
transients












Effects of Transient,
Nonstandard
Operation
NOX emissions levels
rise at a steady rate
after initial jump due
to ignition, drop off
quickly after the
burner is turned off.

NOX emissions increase
with on time of
burner. Improper
burner adjustment,
damaged components,
increase NOX by as
much as 50*.







NOX emissions levels
rise at a steady rate
after initial jump due
to Ignition, drop off
quickly after the
burner Is turned off.

NOX emissions increase
with on time of
burner. Improper
burner adjustment,
damaged components,
increase NOX by as
much as 50%.


Trends
Oil firing in new
units, trend to
ligh efficiency in
new units.

General decline in
natural gas usage;
increase in elec-
tric heat, trend
toward using low
40X burners; in-
creased use of high
efficiency burners.








Oil firing in new
units, trend to
high efficiency in
new units.

General decline in
natural gas usage;
increase in elec-
tric heat, trend
toward using low
NOX burners; in-
creased use of high
efficiency burners.


Future
mportance
'rimary




















Secondary













ro
i
                                                                                                                       T-850

-------
TABLE 2-3.   Concluded
Design Type
Other
Residential
Combustion











Design
Characteristics
Miscellaneous
equipment includes
ranges and ovens,
clothes dryers,
fireplaces, swimming
pool heaters, re-
frigerating and air-
conditioning equip-
ment.





Design Ranges














Fuel Consumption
(X)














Effluent Streams
Flue gas













Operating
Modes
On-off cycling,
transients












Effects of Transient,
Nonstandard
Operation
NOX emissions levels
rise at a steady rate
after initial jump due
to ignition, drop off
quickly after the
burner is turned off.

NOX emissions increase
with on time of
burner. Improper
burner adjustment,
damaged components,
increase NOX by as
much as 5C#.
Trends
Increased use of
electric heat;
high efficiency in
new units.










Future
Importance
Secondary













                                                                      T-850

-------
                                     TABLE 2-4.   SUMMARY OF GAS TURBINE CHARACTERIZATION

Design Type
Utility and
Industrial
Simple and
Regenera-
tive Cycles











Combined
Cyc 1 es ,
Repowering











Design
Characteristics
Rotary internal com-
bustion engines.
Simple gas turbine
consists of compres-
sor, combustion
chamber, and tur-
bine. Fuel is burn-
ed before quenching.
Hot gases quenched
by secondary combus-
tion air, expanded
through a turbine
providing shaft
horsepower.
Regenerative cycles
use hot gases to
preheat inlet air.
;omb1ned cycle is a
>asic simple cycle
unit exhausting to
a waste heat boiler
to recover thermal
energy. Repowering
adds a combustion
;urbine to an exist-
ng steam plant, in-
volving the mechani-
cal or thermal
integration of the
combustion or steam
cycles.
Typical
Operational
Values
Utility Gas Turbine
Simple Cycle

Capacity: 92.3 MW
Specific fuel
consumption:
11.67 MJ/kWh
Compression ratio:
10:1
Exhaust flow:
345 kg/s
Exhaust temp:
822K




Utility Gas Turbine
Combined Cycle
Capacity:
364.5 MW (4 turbines)
Specific fuel consump-
tion:
8.56 MJ/kWh
Compression ratio:
10:1
Exhaust flow:
256 kg/s (1 turbine)
Exhaust temperature:
811K

Fuel Consumption
(*)
45% gas
55X oil












negligible













Effluent Streams
Flue gas












Flue gas













Operating
Modes
On-off transient,
load following,
idling at spin-
ning reserve.











On-off transient,
load following,
idling at spin-
ning reserve.










Effects of Transient,
Nonstandard
Operation
NOX emissions general-
ly increase with in-
creasing power.
Increased turbine com-
pressor inlet tempera-
tures cause NOX to
increase. Behavior of
NOX is directly
related to rpm when
corrected to a con-
stant percent 0,.
£.




NOX emissions general-
ly increase with in-
creasing power.
Increased turbine com-
pressor inlet tempera-
tures cause NOX to
increase. Behavior of
NOX is directly
related to rpm when
corrected to a con-
stant percent 0,.
r z


Trends
Trend to higher
turbine inlet
temperatures,
larger
capacity and
oil firing in
new units;
rapid growth
projected.








Use of combined
cycles should in-
crease because of
improved heat rate
and fuel flexi-
bility of unit.









Future
Importance
Primary












Secondary












ro

—j
ro
                                                                                                                         T-851

-------
                        TABLE  2-5.   SUMMARY OF RECIPROCATING 1C ENGINE CHARACTERIZATION


Design Type
Compression
Ignition,
Turbo-
Charged,
Naturally
Aspirated










Spark
Ignition,
Turbo-
Charged,
Aspirated











Blower
Scavenged






Design
Characteristics
Air or an air-and-
gas mixture is com-
pression heated in
cylinders.- Diesel
fuel is then in-
jected into the hot
gas, causing spon-
taneous ignition.








Combustion is spark
initiated. Natural
gas or gasoline is
either injected or
premixed with the
combustion air in
a carbureted system.









Air charging by
means of a low
pressure blower,
which also helps
purge exhaust gases.





Process Ranges







































Fuel Consumption
(*)
67% gas
15* diesel
11% gasoline
7% dual (oil
and gas)
(all 1C engines)










67% gas
15* diesel
11% gasoline
7% dual (oil
and gas)
(all 1C engines)










67* gas
15% diesel
11% gasoline
7% dual (oil
and gas)
(all 1C engines)




Effluent Streams
Exhaust gas















Exhaust gas















Exhaust gas






Operating
Modes
On-off transients,
idling, upsets














On-off transients,
idling, upsets














On-off transients,
idling, upsets





Effects of Transient,
Nonstandard
Operation
NOX emissions peak
near stoichiometric
air-to-fuel ratio.
HOX emissions
diminish with decreas-
ing load, greater
speed and timing re-
tard.








NOX emissions peak
near stoichiometric
air-to-fuel ratio.
NOX emissions
diminish with decreas-
ing load, greater
speed and timing re-
tard.








NOX emissions peak
near stoichiometric
air-to-fuel ratio.
NOX emissions
diminish with decreas-
ing load, greater
speed and timing re-
tard.


Trends
1C engines finding
use for compressor
applications on
pipelines; low
growth rate of
diesel units; 1C
engines increas-
ingly being re-
placed by gas tur-
bines for standby
applications in
buildings, hos-
pitals, etc., be-
cause of space,
weight, noise,
vibration.
1C engines finding
use for compressor
applications on
pipelines; low
growth rate of
diesel units; 1C
engines increas-
ingly being re-
placed by gas tur-
bines for standby
applications in
buildings, hos-
pitals, etc., be-
cause of space,
weight, noise,
vibration.
Hew large units
tending toward
:urbocharging






Future
Importance
Primary















Primary















Secondary





ro
                                                                                                                      T-852

-------
                          TABLE 2-6.  SUMMARY OF INDUSTRIAL PROCESS  HEATING  CHARACTERIZATION
ro

Process Type
Cement
Kilns






Glass
Melting
Furnaces







Annealing
Lehrs





Coke Oven
Underfire









Design
Characteristics
Kilns are rotary
cylindrical devices
up to 230m in
length. Feedstock
moves through kiln
in opposite direc-
tion from products
of combustion
Continuous reverbera-
tory furnaces; end
port or side port.
Flame burns over
glass surface; com-
bustion gas exits
through opposite end
exhaust stack after
heattng the combus-
tion air.
Used to control the
cooling of gas to
prevent stains.
.ehrs fired by at-
mospheric, premix,
or excess air
lurners.
'reduce metallurgi-
cal coke from coal
Tom the distil-
ation of volatile
matter producing
coke oven gas; done
n long rows of slot
;ype ovens; fuel gas
upplies required
leat. Spent combus-
ion gas heats inlet
air.

Process Ranges
Kiln product temperature:
1.756K






Furnace temperatures:
1528 to 1583K















Flue temperature:
1500K









Fuel Consumption
(X)
45% gas
40* coal
15% oil





Natural gas- and
oil-fired; coal
is unsuitable due
to impurties.






Natural gas- and
oil-fired; coal
unsuitable




Blast furnace gas
and coke oven gas
are primary fuels









Effluent Streams
Combustion pro-
ducts and en-
trained substan-
ces from feed-
stock



Combustion pro-
ducts and en-
trained substan-
ces from feed-
stock





Combustion pro-
ducts





Combustion pro-
ducts









Operating
Modes
Charging opera-
tions, upsets,
starting tran-
sients




Charging opera-
tions, upsets,
starting tran-
sients






Upsets, transients






Charging opera-
tions, upsets,
starting tran-
sients









Trends
Coal firing in new
units; energy im-
provements due to
grate preheaters
and shorter, less
energy intensive
kilns.

Trend toward use
of electric
melters, or elec-
trically assisted
conventional melt-
ers; use of oil
instead of gas in
fossil fuel units.









Projected fuel
consumption about
5< annual








Future
Importance
Primary







Primary









Primary






Primary









                                                                                                            T-853

-------
                                                  TABLE 2-6.   Continued
ro
i

Process Type
Steel
Sintering
Machines










Open
Hearth
Furnaces







Brick and
Ceramic
Kilns










Design
Characteristics
Used to agglomerate
ore fines, flue
dust, and coke
breeze for charging
of a blast furnace.
These products
travel on a travel-
ing grate sintering
machine; after ig-
nition, is forced up
through the mixture
causing fusion and
agglomeration.
The charge is melted
in a shallow hearth
by heat from a flame
passing over the
charge and radiation
from the heated dome.
Spent combustion
gases preheat the
inlet combustion
gases.
Tunnel or periodic
kiln used most often.
Periodic: hot gases
drawn over bricks,
down through them by
underground flues,
and out of the oven
to the chimmey.
Tunnel: cars carry-
ing bricks travel by
rail through kiln at
about one car per
hour.

Process Ranges























Kiln product
temperatures: 1367K











Fuel Consumption
(X)
Low Btu gas












Low Btu gas such
as blast furnace
gas







Oil, gas, or coal
(coal use less
common)











Effluent Streams
Combustion pro-
ducts and en-
trained substan-
ces from feed-
stock








Combustion pro-
ducts and en-
trained substan-
ces from feed-
stock





Combustion pro-
ducts and en-
trained substan-
ces from driers
and feedstocks.








Operating
Modes
Upsets, starting
transients











Charging, upset-
ing, starting
transients.







Upsets, starting
transients,
charging











Trends
Operation declin-
ing because of
system incompata-
bility; pelletiz-
ing replacing
sintering lines







Basic oxygen
furnace in new
units; fuel con-
sumption decreas-
ing by 8% per year





Tunnel kilns in
new units; con-
tinuous produc-
tion with heat
recovery








Future
Importance
Primary












Primary









Primary












T-853

-------
                                                 TABLE 2-6.  Concluded
ro



01

Process Type
Catalytic
Cracking









Process
Heaters




Refinery
and Iron
and Steel
Flares
Design
Characteristics
Preheated gas and
oil is charged to a
moving stream of hot
regenerated catalyst.
The gas and oil is
cracked in the re-
actor; products pass
through cylone for
separation and are
then cut into pro-
ducts in fraction-
ator.
Two basic types —
mechanical draft and
forced draft. Con-
structed as either
horizontal box or
vertical cylindrical.
Used for the control
of gaseous combusti-
ble emissions from
stationary sources

Process Ranges
Process temperature:
840 to 922K
Fuel consumption:
829 kJ/f feedstock.

















Fuel Consumption
(*)
Oil, gas, or
electricity









70% process gas





Waste gas




Effluent Streams
Combustion pro-
ducts and volati-
lized products or
catalysts








Combustion pro-
ducts




Combustion pro-
ducts


Operating
Modes
Starting tran-
sients, charging









Upsets, starting
transients




Upsets, transients




Trends
Growth about 2%
annually









New units are
mechanical draft
with combustion
air preheater






Future
Importance
Primary









Primary





Primary



t-853

-------
                                                   TABLE  2-7.   SUMMARY  OF  ADVANCED  COMBUSTION  SYSTEMS
                Advanced Combustion
                      System
          Process Description
               Advantages
State of Development
                Repowering
Addition of a combustion turbine  to  an
existing steam plant,  involving the
mechanical or thermal  integration of the
combustion and the steam cycle.
Improved efficiency
 Currently available
                Pressurized Boi.lers
Pressurized boilers operate at  furnace
pressures up to about 1  million pascals,
or about 10 atmospheres.   Suited to  gas
and oil or other fuels which can be  introduced
into the combustion furnace under pressure.
Major application will probably involve
fluidized bed combustion.
                                                                                       Increased heat transfer; higher volumetric
                                                                                       heat release; reduced boiler size
                                                 Currently available
                Low Btu Coal
                Gasification
ro
Gas produced from coal  by fixed bed,  entrained
bed, fluidized bed gasification or with oil.
Gas produced by these processes can be con-
verted into pipeline quality gas by water
gas shift and methanation.
Produce fuels suitable for  conventional
steam plants and combined cycle  turbine-
steam plants

Economical  advantages  in using onsite
production  of low Btu  gas for combined
cycle gas turbines
 Pilot  plants —  (1983-1985)
 20 x 106 m3 capacity unit -
 1983
                Fluidized Bed
                Combustion
                 Advanced HT  Gas
                 Turbine Steam
                 Cycles
Air is blown through granular bed of noncombus-
tible materials, (coal ash or lime)  causing
granulated bed particles to become suspended.
Fuel, normally crushed coal, pneumatically In-
jected near the bottom of bed and combusted  at
temperatures between 1033K and 1367K.   Operat-
ing pressures range from atmospheric to 25
atmospheres.  High-pressure units are designed
to be used in combined gas turbine/steam cycles
in which the fluidized bed unit acts as external
combustor for the gas turbine and a steam gen-
erator for steam turbine.
   High heat transfer  ratio  and volu-
  metric heat releases
   Reduction of ash  fouling  and high
   temperature corrosion resulting
   from low combustion temperature
   Burn low grade  fuels more readily than
   conventional boilers
30 MW atmospheric —
being demonstrated
 Present combined cycle units are economically
 feasible only for intermediate range plants,
 but  increasing inlet temperatures to 1972K
 would  Improve unit efficiency to about 50
 percent.  Coupling this new design to a nearby
 low  Btu gasification unit would give a total
 efficiency of about 38 percent, which compares
 favorably to present day coal-fired steam
 plants.
Increase efficiency
Commercially available mid-
1980's
                                                                                                                                                            T50TT

-------
                                                                          TABLE  2-7.   Concluded
                Advanced Combustion
                      System
                                Process Description
                                                              Advantages
                                                                                                                                       State of Development
                Binary Cycle
                Topping and
                Bottoming
                      There are two types of binary cycles:   the
                      topping cycle, which uses a high temperature
                      cycle to "top" a low temperature cycle and
                      the bottoming cycle which uses ammonia or
                      other suitable fluids and the exhaust  heat  of
                      a steam cycle.
                                                  Increase  conventional steam plant
                                                  efficiencies  to  50 or 60 percent
                                           Demonstration plants early 1980's
                MHO Open  Cycle
ro

CO
                      Magnetohydrodynamic (MHD) generators convert
                      mechanical energy to electrical  energy
                      by interaction of moving conducting fluid
                      and a stationary magnetic field.  Open
                      cycle processes may use fossil  fuel
                      combustion products as a conducting fluid
                      simply by seeding with an ionized salt of
                      potassium or cesium.  A waste-heat boiler
                      is used in conjunction with HMD unit to
                      recover thermal energy from the exhaust
                      gases,	
                                                  Projected  cycle efficiencies are
                                                  50  percent with potential for as high
                                                  as  60  percent  1n the  long terra
                                            50 HW demonstration  plant  late  1980's
Catalytic
Combustion
Catalytic combustion 1s being applied for gas
turbine combustors and area sources.   By premix-
ing fuel and air, temperatures in adiabatic
catalytic combustion section can be lowered to
approximately the turbine inlet temperature.
System relies on catalyst to rapidly combust
lean mixtures that result from the total premix-
ing.  Excellent catalyst; performance at tempera-
tures up to 1756K (2700F) has been demon-
strated for short periods of time (75 hours)  in
feasibility studies.
Greatly reduce thermal  NO ; improve
unit efficiency
Gas turbine demonstration
1980
                                                                                                                                                             T-606

-------
   TABLE 2-8.  SIGNIFICANT STATIONARY FUEL COMBUSTION EQUIPMENT
               TYPES/MAJOR FUELS
Utility Sector (Field Erected Watertubes)
    Tangential
    Wall Fired
    Horizontally Opposed and Turbo Furnace
    Cyc1 one
    Vertical and Stoker
Packaged Boiler Sector
    Watertube 29 to 73 MWa  (100 to 250 MBtu/hr)
    Watertube <29 MWa (<100 MBtu/hr)
    Firetube Scotch
    Firetube HRT
    Firetube Firebox
    Cast Iron
    Residential
Warm Air Furnace Sector
    Central Heaters
    Space Heaters
    Other Residential Combustion
PC — Pulverized  coal
C  — Stoker  coal  or  other  coal
0  -- Oil
G  ~ Gas
PG — Process  gas
   Fuel
PC, 0,  G
PC, 0,  G
PC, 0,  G
PC, 0
C

PC, 0,  G,  PG
C, 0, G, PG
0, G, PG
C, 0, G, PG
C, 0, G, PG
0, G
C, 0, G

0, G
0, G
0, G
 *Heat  input
 3Heat  output
                                2-19

-------
                      TABLE 2-8.  Continued
Gas Turbines
    Large >15 MWb  (>20S000  hp)                          0, G
    Medium 4 to  15 MWb  (5,000  to  20,000 hp)             0, G
    Small <4 MWb (<5,000  hp)                            0, G
Reciprocating  1C Engines
    Large Bore  >75 kW/cylb  (>100  hp/cyl)               0, G
    Medium  75  kW to  75  kW/cylb (100 hp to              0, G
    100  hp/cyl)
    Small <75  kWb (<100 hp)                            0, G
 Industrial  Process Heating
     Glass  Welters
     Glass  Annealing Kilns
     Cement Kilns
     Petroleum Refinery
       Process Heaters
       Catalytic Crackers
 PC — Pulverized coal
 C  —• Stoker coal or other coal
 0  -- Oil
 G  — Gas
 PG — Process  gas
 j^Heat  input
  Heat  output
                                2-20

-------
                      TABLE 2-8.   Concluded
    Brick and Ceramic Kilns

    Iron and Steel

      Coke Oven Underfire

      Sintering Machines

      Soaking Pits and Reheat Ovens
PC ~ Pulverized coal
C  -- Stoker coal or other coal
0  — Oil
6  ~ Gas
PG — Process gas
                                2-21

-------
2.2  PERIODIC OR NONSTANDARD OPERATIONS
2.2.1    Utility and Large Industrial Boilers
     Emissions during nonstandard operation have not been extensively
quantified.  Table 2-9 summarizes the qualitative effects of  nonstandard
operating procedures on effluent streams for a dry  bottom,  coal-fired
boiler (Reference 2-1).
     During startup, when flame temperatures have not  developed,  NO
                                                                   X
emissions generally are low.  However, particulate  emissions  may  be high
since precipitators are generally not energized during startup.   In
addition, unburned carbon may be emitted due to poor mixing in the
combustion region.
     NO  emissions should decrease as furnace temperatures  are lowered
       A
during load reductions.  However, if excess air levels  are  increased  to
maintain steam temperatures, NO  emissions actually may increase.  A
                               /\
recent study shows that particulate emissions per unit  of heat input
decrease with load reduction (Reference 2-2).
     Particulate emissions increase during soot blowing as  the tube
surfaces are cleaned.  N0x emissions should decrease after  soot blowing
because of the lower gas temperatures caused by increased heat transfer
through the tube walls.  Failures of equipment such as  air  preheaters may
also reduce N0x emissions by causing lower flame zone  temperatures.   If
additives  are used to control S02 emissions, both bottom ash  and
particulate emissions may increase by over 50 percent  of the  normal
emission levels (References 2-3, 2-4).
2.2.2    Packaged Boilers
     Since large packaged boilers >29 MW heat input (>100 MBtu/hr) operate
much like utility boilers, the effects of transients and nonstandard
                                    2-22

-------
    TABLE 2-9.   EFFECT OF NONSTANDARD OPERATING PROCEDURES ON THE
                EFFLUENT STREAMS FROM A DRY BOTTOM PULVERIZED COAL-
                FIRED BOILER (Reference 2-l)a
Procedure
Soot blowing
Startup, shutdown
Load change
Fuel additives
Rapping, vibrating
Flameout
Upset
Equipment failure
Frequency
3 to 4/day
12 to 50/yr
I/day
Continuous if used
3 to 4/day

-------
operations should be similar to those discussed  in Section  2.2.1-   For
smaller packaged boilers, combustion characteristics  are  significantly
different.  Although quantitative  data for  nonstandard  operating
conditions are sparse,  load changes  are  known  to have a relatively small
effect on NO  emissions  (Reference 2-5).   However,  increasing the fuel
            J\
preheat temperature of  oil-fired  boilers  may increase NOX emissions.  At
low  preheat temperatures, the  atomizing  pressure is  not sufficient to
properly  atomize the colder, more viscous oil; this  results in lower
atomization efficiency.
2.2.3  Warm Air  Furnaces
        The  transient  and nonstandard operations of warm air furnaces
 include on-off cycling and  out-of-tune  or worn burner operation
 (Reference  2-6).
        During ignition and  shutdown transients, some pollutants reach peak
 levels.  In some cases, these  peaks account for most of the pollutants
 emitted.  Figure 2-2 (Reference 2-7) shows emission  levels from oil
 burners for one complete cycle.  Most of the CO and  HC emissions are
 produced during ignition and after the  burner has been shut off.
 Particulates peak during ignition, but  taper off steadily until the burner
 is  shut off.
        The initial peak at  ignition is  caused by the inability of the cold
 refractory to support complete combustion.  This incomplete combustion
 produces peaks in the HC, CO,  and particulate emissions.  As the
 refractory warms up, more complete combustion occurs, thus decreasing
 combustible emissions.  After  shutdown, some fuel leaks from the nozzle,
 which produces another peak in both the CO and HC emissions (Reference
 2-7).  This can be controlled  to some degree by using a solenoid.
                                     2-24

-------
 Filterable
Particulate
             Burner
               On
Burner
 Off
Burner
  On
                                                               I
Burner
 Off
                     Time •»
                                                         Time *
        HC
             Burner         Burner
               On            I Off
                                             CO
                        Burner       Burner
                         |0n         I Off
                     Time
                                                         Time -
             Figure  2-2.   Characteristic  emissions  of oil burners
                            during one complete cycle (Reference 2-7),
                                      2-25

-------
       The transient emissions of NO  generally correspond  to the
                                    /\


thermal history of the firebox.  At startup,  the emissions  increase



rapidly as the temperature rises above  the  thermal  NO  threshold.
                                                      X


During the cycle, the emissions continue  to increase at a gradual rate as



the refractory firebox is heated causing  a  corresponding increase in the



temperature of the combustion  gases.  At  shutdown,  NO  emissions
                                                      A


decrease rapidly  as the  gas  temperature is  quenched by incoming air.



       Transient  emissions characteristics  of gas burners should be very



similar to those  of oil  burners.  However,  the HC and CO emissions that



occur  after shutoff  in gas burners  are  probably not as high as those from



oil  burners,  since gas leaks are minimal  after burner shutoff.



       The  duration of the "on" period  within a cycle of a coal-fired warm



air  furnace  does  not  significantly  affect polycyclic organic matter (POM)



and  particulate  emissions  (Reference  2-8).   However, particulate and POM



 loadings  generated during the "off" transient are higher than those



 produced  during  the  "on" transient  for  coals with volatile matter contents



 greater  than  20  percent. This phenomenon is caused by incomplete



 combustion  of tars  emitted from the  volatile coal.   Data trends from two



 samples  show that NO   emissions  increase  as the "on" time of a cycle is
                     J\


 increased.



        Improper  burner adjustment,  dirty  burner cups or nozzles, or



 damaged  components  can significantly  increase pollutant emissions.



 Extensive field  testing  of oil burners  is reported  in References 2-9 and



 2-10.  This testing  shows that with proper  maintenance, smoke, CO, HC, and



 N0x emissions are reduced  by over  50  percent, while filterable



 particulate is reduced  by almost  25 percent.
                                     2-26

-------
       For gas burners,  tuning,  cleaning,  and replacement  of  worn  burner



components should  not  have  as  drastic an  effect.   Gas  burners provide much



cleaner combustion,  and  can  be expected to stay tuned  for  extended  periods


with no maintenance  problems.



2.2.4  Gas Turbines



       The transient and nonstandard operations of gas turbines  can  be



separated into three groups:   operational  variations,  startup/shutdown,



and equipment failures.   Operational variations include changes  in  load,



speed, power, ambient  conditions,  and variations in fuel  quality.



       Generally,  gas  turbines are designed to operate most  efficiently at



their  rated  capacity.   However, deviations from these  rated  conditions are


often  necessary, which can  cause the gas turbines to lose efficiency as



well as change emissions characteristics.


       The most  frequently changed operational variables are  load  and/or



speed.  Two  studies  (References 2-11 and 2-12) have indicated that



generally, CO, NO   and HC emissions vary with change in power or load as
                 A


shown  in  Figure  2-3.


       The profile of NO  emissions resulting from changes in turbine
                         /\


speed  is  shown  in  Figure 2-4 (Reference 2-13).  These  data show  that the


behavior  of  NO   emissions with changes in rpm is inherently related to
              A

the air-to-fuel  ratio when  corrected to a constant percent oxygen.   Gas



turbine  ambient  operating conditions also affect pollutant emissions



 (Reference 2-12).   NO  emissions increase with increased compressor
                      X


inlet  temperature, whereas  CO and HC decrease.


       Few data  presently are available on emission characteristics during



startup/shutdown or  equipment failures.  However, CO,  HC, smoke  and



particulate  emissions should increase during these periods because of
                                     2-27

-------
ro
i
po
CO
                                                                             Maximum
                                                                              power
                                 Figure 2-3.  Gas turbine generator emissions due to
                                              power variations  (Reference 2-11 and 2-12).

-------
   100
    90
E
Q.
Q.
C
o
O)
o
c
o
o

 X
o
    80
70
    60
50
    40
    30
    20
              Legend


              O  NOX  as-measured

                  N0xa corrected to 15% 02
                                                               9

                                                               4
       40     42      44      46      48     50     52

                       Power  turbine  speed,  rpm  x  102
                                                       54
        56
      110.8  103.8
                         92.8           81.1

                           Air-fuel  ratio
71.6    64.6
       N00 basis
       Figure  2-4.
                The effect of turbine speed and air-fuel  ratio

                on NO  concentrations (Reference 2-13).
                     A
                                   2-29

-------
incomplete combustion.  Under these conditions,  air-to-fuel  ratios are not



stable and combustion temeratures are  low.   NO   emissions  diminish
                                              >\


therefore, because of the lower combustor temperatures.



2.2.5  Reciprocating 1C Engines



       Nonstandard operating conditions  include  load  change,  startup and



shutdown transients, and upsets such as  fuel  or  electrical  system



failure.  Large 1C engines used for power generation  or  pipeline



compression applications are generally well  maintained for  economy.



Moreover, they are run steadily for many hours at  their  most  efficient



operating condition.  However, smaller engines are not maintained as well,



and  frequently are operated  in transient modes.  Transients  affect



emissions largely through their influence on air-to-fuel ratios.  Figure



2-5  (Reference 2-14) presents emission trends caused  by  these variations



for  a typical gasoline engine.  This figure  shows  that NO   emissions
                                                         /\


peak near the air-to-fuel stoichiometric ratio.



       Other operational variations such as  load,  engine speed,  and  spark



timing also  affect pollutant emissions.  In  general,  NO  emissions
                                                       j\


diminish  with decreasing load, greater speed, and  retarded  timing.



Variations  in ambient temperature also affect emissions  of  pollutants.



Recent experiments on automotive gasoline engines  indicate  that  ambient



temperature  reductions  increase HC  and CO.   However,  NO  levels  are  not
                                                       /\


greatly  affected  by  changes  in ambient temperature (References 2-15


through  2-18).



       Most  stationary engines burn No.  2 diesel fuel or natural gas.  The



properties  of pipeline quality natural gas are essentially  constant, but



field gas can vary in composition and  sulfur content.  These  variations



affect the  emissions of all  gaseous pollutants as  well as  the engine
                                     2-30

-------
01
C
o
0!
•P
fC
10
12
                              14           16           18

                                   Air-to-fuel  ratio
                                                            20
              Figure 2-5.  Effect  of A/F  ratio  on  emissions  in a gasoline

                           engine  (Reference  2-14).
                                          2-31

-------
performance.  For diesel oils, the most  important  properties  are
viscosity, cetane number, distillation point,  and  sulfur  and  ash content.
In general, only the sulfur content  varies  significantly  in commercial
grade fuels, and hence only SCL emissions  are  affected noticeably by
normal fuel variations.
2.3    EQUIPMENT TRENDS
       The  trends  in equipment use are a major consideration  in
categorizing  important  NO  sources and assessing their future pollution
                         X
potential.  This  section discusses these trends for the stationary N0x
sources  given in  Section 2.1.
2.3.1  Utility and Large  Industrial  Boilers
        The trend  in utility  boiler design  is  towards coal firing.
According to  manufacturers  (References  2-19 through 2-23), no oil- or
 gas-fired units have  been  sold for the past 2 years and many previously
ordered  oil units  have  been  converted to coal  firing during the design
 phase (Reference  2-19).   In  addition, government agencies are applying
 pressure on utilities  and  industries to  switch to coal as their primary
 fuel.  For example, the Department of Energy (DOE) is prohibiting the use
 of either natural  gas  or  oil  by  selected major industrial users of fuel.
 In addition,  DOE is preparing to serve  "construction orders," requiring
 that major fuel burning installations (MFBIs) design alternatives to oil
 or gas firing.  MFBIs  are  defined as units firing 29 MW  (heat input) of
 fuel in  a single combustion  unit.  For  new construction  however, MFBIs may
 be as small as 15 MW (heat input),  if combined with one  or more other
 combustors (Reference 2-24).
        Tangential, single wall,  and  opposed wall firing  (including turbo
 firing)  are the most common  utility  designs.   Tangential boilers have  a
                                     2-32

-------
wide capacity range, while  single wall  firing is typically limited in
capacity to 400 MW  (electric),  and opposed wall  firing is generally used
for larger sizes  (>400  MW electric).   Tangential units currently represent
about 43 percent  of  new sales.
       The trend  of  the last 10 years to larger  capacities appears to have
slowed.  In fact, many  utilities have chosen to  install  two small  boiler
units rather than a  single  larger unit.  When larger boiler capacities
were used, division  walls in the combustion chamber were employed --
particularly for  oil  and gas firing.   This increased the available heat
transfer surface  and produced two smaller combustion chambers  with
aerodynamic and  combustion  characteristics similar to smaller  units.
Large coal-fired  furnaces,  however, generally do not use division walls
because they cannot  be  cleaned  easily by soot blowing (Reference 2-19).
Since coal will  be  used more extensively for utility boilers,  using
divided combustion  chambers is  not expected to be a significant trend in
the future.
       Stokers,  cyclones, and vertical  firing are now seldom used for new
utility boilers.  Cyclone furnaces were being sold as late as  1974, but
because the units have  not  proven adaptable to emissions regulations,
sales  have  halted.   Cyclone furnaces  were originally developed by Babcock
& Wilcox to burn  Illinois coal, which has a low ash fusion temperature.
Recently they  have  been used to burn  lignite.  Because the cyclone furnace
 is designed to  operate  as a slagging furnace, it must operate at high
combustion  temperatures (Reference 2-25).  Since high temperatures result
 in high thermal  NO   formation,  cyclone furnaces have become unpopular.
                   J\
However, cyclones may be used in the future to fire some  lignites.
Vertical fired  furnaces fire anthracite coal, which is  difficult  to  burn
                                     2-33

-------
in conventional boilers because of its low volatile content.   Since
anthracite use as a utility boiler fuel is decreasing,  vertical  furnaces
are no longer sold and few are found in the field.
       Wet bottom furnaces are also no longer manufactured.   This  design
has operational problems with low sulfur coal and a high  combustion
temperature which promotes NO  formation.
                             A
2.3.2  Packaged Boilers
       Trends toward coal burning packaged boilers are  less  certain.   In
the past, pulverized coal has seldom been used in packaged watertube
boilers because of the capital costs involved with coal pulverization  and
handling equipment.  However, the availability and competitive cost of
coal compared to oil will probably lead to increasing use of  pulverized
coal in larger packaged watertube units.  Coal-fired units as small as
20 MW  (heat  input) are now being marketed (Reference 2-26).   However,  the
growth in pulverized coal-fired packaged boilers is only  speculative  at
this point,  since no manufacturer has yet received any  purchase  order  for
this type of boiler (Reference 2-30).  Stoker-fired packaged  boiler use
(<29 MW heat input) is expected to increase.  In addition, new oil-fired
boilers are  presently being designed with the capability  of  adapting  to a
stoker-fired coal system  (References 2-27, 2-28, and 2-29).
       Sales data show that firebox units have diminished in  popularity
during the  past  5 years  (Reference 2-31).  Scotch firetubes  are  currently
the most  popular type of  oil-fired boiler.  Although no units are  being
sold strictly  for gas firing, dual fuel (oil- and gas-firing) units are
being  designed for areas  where coal is not available.
       Cast  iron boilers  are being installed in increasingly smaller  sizes
for hot water  heating applications instead of for steam applications.   The
                                    2-34

-------
average capacity of  cast  iron  boilers may reach as low as  15  kW  (heat
input) in the next few  years.   However,  no major equipment  design changes
are expected for these  units  (Reference  2-32).
2.3.3  Warm Air Furnaces
       According to  U.S.  Census statistics for  1970,  over  55  percent of
the nation's heating units  were warm air furnaces.  About  67  percent of
these  units burned natural  gas, while distillate fuel  oil  was  fired in
23 percent of the units.   Coal, wood, and various bottled,  tank, or LP gas
accounted for the remaining 10 percent of the fuel used.   There  has been a
continuing trend in  the recent past toward commercial  and  residential warm
air furnaces which use  natural gas.  However, the percentage  of  equipment
in the entire residential and  commercial sector fueled by  natural gas is
expected to drop from 37  percent in 1974 to 35 percent by  1985,  and to 32
percent by 2000  (Reference 2-33).  Moreover, the use of fossil fuels of
all types in this sector  is expected to  drop from 79 percent  in  1974 to 57
percent in 2000.  Nationwide,  the most important fuels for warm  air
furnaces will still  be  natural gas and distillate oils.
       Current research efforts mainly emphasize the design of low
emission burners and the  improvement of  furnace efficiency.
2.3.4  Gas Turbines
       The growth of gas  turbines has been extremely rapid  since the
mid-1960's because of their low initial  costs,  ease of maintenance, high
power-to-weight ratio,  reliability, and  short delivery time.
       Large gas turbines recently have  shown a trend toward  higher
capacities and improved heat  rates.  A recent survey of users  (Reference
2-34)  indicates that combined  cycle turbines are the preferred future
design for intermediate or  baseload applications because of their
                                     2-35

-------
improved heat rate and fuel flexibility.  In contrast,  simple cycle
turbines are preferred for peaking.  In the same survey,  users  predicted
that gas turbines will continue to supply about 10 percent  of the  total
electrical generating capacity through at least 1985.   Because  of  this
significant growth, large gas turbines will be a major  equipment type in
the future and thus will be dealt with separately here.
       The trend of using gas turbines for baseload  electricity generation
was interrupted during the OPEC oil embargo.  Because of  the  uncertain
petroleum  situation, the orders for combined cycle gas  turbine  generators
dropped  sharply.  According to a current survey, the demand for combined
cycle  gas  turbine generators  is still  low.  However, sales  may rise
rapidly  if construction of nuclear and fossil fuel power  plants continues
to  be  delayed  (References  2-35 and 2-36).
       The growth of combined cycle gas turbine generators  depends on
their  potential for burning coal derived fuels.  Currently, DOE and EPRI
are pursuing research programs in  gas  turbine development.  The first of
these  programs  is  investigating the development of high temperature gas
turbines burning  coal derived fuels; the second is considering
pressurized, fluidized  beds that will  burn coal to replace  the  oil
combustor  cans  in the gas  turbines.  There is a good possibility that
these  advanced  systems  will be commercialized before 2000,  perhaps as
early  as the  late  1980's  (Reference 2-37).
2.3.5   Reciprocating  1C Engines
 Large-Power Engines
        Most  of  the  large  engines used  for  electric power  generation are
 owned  by municipal  power  companies and are used for  baseload  generation in
 areas  where  construction  of  large  steam  generating plants is  not
                                     2-36

-------
justified.   Power companies either purchase electricity from nearby large
utilities — if electricity is available and cost-effective -- or purchase
large reciprocating 1C engines for onsite power generation.
       Emergency standby power for nuclear reactors was recently
considered to be the most rapidly growing application for high-power
diesel engines.  Because these engines satisfy a quick startup requirement
that gas turbines do not, industry representatives indicate that the
high-power diesel engines have virtually no competition for this market
(Reference 2-14).  However, future trends in this market area are
unpredictable because nuclear power generation in the near future is
uncertain.
       High-power engines are used in municipal sewage treatment plants to
generate electricity and pump water from digester gas.  Reciprocating 1C
engines are being used increasingly in areas where the digester gas can be
burned to supplement other more expensive fuels (Reference 2-14).
Medium-Power Engines
       Many users currently are purchasing diesel rather than gasoline
engines, particularly for high load and usage applications.  Diesels are
being used for agricultural applications because they give good fuel
economy and can meet the expanding irrigation and shaft power markets.
Although natural gas fueled engines had wide application for agricultural
irrigation in the past, many major engine manufacturers plan to
discontinue this product line by 1980, primarily because of uncertainty in
the availability of natural gas (Reference 2-14).
       Medium-power reciprocating engines face competition from substitute
power sources in nearly all applications.  Direct purchase of electricity
and the use of electric motors result in lower maintenance, and lower
                                    2-37

-------
initial and operating costs for small  general  industrial  and  agricultural
applications.  Thus, markets for medium-power  reciprocating engines  are
declining except where electricity  is  inaccessible  or  impractical
(Reference 2-14).
       Gas turbines  are  also competing strongly with reciprocating
engines,  although  initial  costs of  most small  gas turbines (300 to
1500 hp)  exceed  those of similar size  reciprocating engines.   Gas  turbines
are better suited  for most standby  applications in  hospitals  and
commercial buildings where space, weight,  noise, and vibration are
constraints  (Reference  2-14).
 Low-Power Engines
        In this sector,  low-power  engines are being  replaced by electric
 motors.   However,  use  of small  engines (<15 hp) for homes, lawns and
 gardens, and off-road  vehicles  has  grown substantially in the last few
 years (Reference 2-14).   Since  most of these uses are for nonessential
 services, continued growth depends  heavily on future economic and fuels
 stability.
 2.3.6  Industrial Process Trends
 Iron  and Steel  Industry
        Use of sintering lines is declining at the rate of about
 3.4 percent annually because they cannot accommodate rolling mill scale
 contaminated with rolling oil.   Pelletizing, the preferred process, will
 eventually replace  sinter lines because it can  handle rolling mill  scale
 and  has  reduced energy  requirements and emissions.  Although  pelletizing
 uses  primarily  gasoline  and diesel  fuels, the Bureau of  Mines  has found no
 major problems  with firing pulverized  coal  in this  process.   Currently,
                                      2-38

-------
pellet systems with provisions for coal firing  are  under consideration
(Reference 2-38).
       Open hearth furnaces  are now  being replaced  in the  steel  industry
by the basic oxygen furnace.  In fact, fuel consumption in open  hearth
furnaces is decreasing at  about 8 percent per year  (Reference  2-39).
However, open hearth furnaces are still an  important source of NO
                                                                 A
emissions because of existing furnaces, which have  very high combustion
air preheat temperatures,  high operating temperatures, and practice oxygen
lancing.
       Because continuous  casting of molten metal is becoming  the
preferred method for iron  and steel making, the need for soaking pits and
reheat furnaces is diminishing.  However, the growth in the overall iron
and steel industry is strong enough to still support a 2.8 percent annual
increase in process fuel consumption (Reference 2-39).  In addition,
present projections show a 5.7 percent annual increase in fuel consumption
for coke ovens (Reference  2-39).
Glass Industry
       The current trend in the glass industry  is towards electric
                       *•
melters, or at least electrically assisted conventional melters.  In
addition, fuel oil is increasingly being used in place of natural gas
because of natural gas shortages and price  increases.  Coal, for the most
part, is an unacceptable fuel for the glass industry because of  its
impurities.  However, coal gasification may become  a useful and
economically viable fuel source for the glass industry.
Cement Industry
       It is expected that many cement industries will convert to coal
firing in the near future  as a result of DOE directives (Reference 2-24).
                                     2-39

-------
According to current DOE statistics, 90 percent  of  all  cement plants
should be able to use coal by 1980, compared to  66  percent  in 1976 and
76 percent today (Reference 2-24).  The cement  industry has reduced energy
consumption by using grate preheaters and quicker,  less energy intensive
kilns.  One further improvement may be to replace traditional rotary kilns
with fluidized bed kilns.  Volatiles and ash are sent to the flue via an
indirect heat exchanger  in the fluidized bed kiln,  making it unnecessary
to plug  in the conventional kiln preheaters.
       Cement industry figures show that the industry has grown at:an
average  rate of  about 1.9 percent annually over  the past 20 years.
Industry projections, however, predict a greater growth in  the next few
years  of between 2.6 to  4.1 percent per year (Reference 2-40).
Petroleum  Refining
       Current trends are toward mechanical draft process heaters with a
combustion  air preheater, primarily because they conserve more energy than
natural  draft heaters.
       Process heaters  are fueled primarily (60  to  80 percent) by process
gas,  a byproduct of the  refinery process.  The auxiliary fuel is  generally
oil.   However, oil consumption will probably decline as more process gas
with  a lower sulfur content is used.  Recently promulgated  regulations
limit  atmospheric sulfuric oxide emissions from  process heaters,  requiring
use of low  sulfur process gas.  It has been estimated that  these
regulations will reduce  current oil consumption  by  as much  as 28  percent
(Reference  2-41).  A 2.7 percent annual increase in  process heating is
projected  for 1980, and  a 2.9 percent annual increase for 1985 (Reference
2-40).
                                    2-40

-------
       Catalytic cracking capacity increased by about  1.7 percent per year



between 1960 and 1973.  Future growth will depend on energy and



environmental policy, and on the demand for  low sulfur fuel oil.  Present



estimates of future growth are from 1 to 3 percent per year (Reference



2-40).



Brick and Ceramics



       The brick and ceramics industries are lowering manufacturing costs



through high-volume continuous production with heat recovery where



feasible.  Tunnel kilns increasingly are being used.   In the future, these



kilns will be the principal type within these industries.



       Both pulverized coal and coal gas firing are being used more



frequently in the brick and ceramics industries.  Since sulfur can affect



the quality of the brick by changing its color, glazing, etc., low sulfur



coal is required.  Thus, long-term predictions of coal use in these



industries are uncertain, since they depend on the availability of low



sulfur coal (Reference 2-39).



2.4    MOBILE COMBUSTION SOURCES



       Mobile combustion sources are the second major cause of atmospheric



NO  emissions.  Although a detailed assessment of mobile sources is not
  J\


within the scope of this program, these sources still must be defined to



understand the total impact of NO  emissions.  NO  emissions estimates
                                 X               A


from mobile sources will be included in Section 4 so that stationary and



mobile sources can be compared.



       Mobile sources include both highway and nonhighway vehicles.



Highway vehicles can be divided into the following categories:



       •   Passenger cars and light-duty trucks powered by gaseous  (LPG,



           CNG, LNG), diesel, or gasoline fuels
                                    2-41

-------
       •   Heavy-duty trucks powered by gaseous (LPG, CNG, LNG), diesel,
           or  gasoline fuels
       •   Motorcycles powered by gasoline
Nonhighway vehicles can be divided into the following categories:
       •   Aircraft
       •   Locomotives
       t   Vessels — further divided into inboard and outboard
       •   Small general utility engines ~ snowmobiles, minibikes, dune
           buggies, small electric generators, etc.
2.5    NONCOMBUSTION SOURCES
       Noncombustion NO  emissions are produced by several primary
                       X
chemical manufacturing processes.  Although none of these processes have
significant emissions on a national scale, they are often serious sources
of pollution locally.  The most important of these processes  are:
       •   Nitric acid manufacture
       •   Adipic acid manufacture
       •   Explosives manufacture
Emissions from these sources are discussed below.
Nitric Acid Manufacture
       Nitric acid, HN03, is usually manufactured by ammonia  oxidation.
This acid  is used primarily for nitrate fertilizers (-15 percent),  and for
organic chemical manufacture, steel pickling, and military munitions  (25
percent).  Emissions from nitric acid plants are not significant on a
national  scale, but are frequently of great concern locally.  Catalytic
burners,  typically used to control NO   reduce the N00 concentration
                                     *               c.
of  the  tail gas and produce a colorless stream consisting mostly of N2,
0,  and C0.
                                    2-42

-------
        The projected growth rate for the  industry  is  7,2  percent  annually



 (Reference 2-40).



 Adipic Acid Manufacture



        Adipic acid, (CH2)4 (COOH)2, is manufactured by catalytic



 oxidation of cyclohexane, with cyclohexanone and cyclohexanol as



 intermediates.   Although emissions from adipic acid plants may not be



 significant on  a national scale, they can be very serious on a localized



 basis  —  only five plants produce nearly 1.5 billion tons annually



 (Reference 2-42).  The industry as a whole has recently slowed its



 historically rapid growth.   In fact, growth is expected to decrease from



 approximately 7 percent annually to about 4 percent annually over the next



 3  years  (Reference 2-42).



 Explosives Manufacture



        Explosives can  be divided into  four major classifications:   bulk



 explosives,  propellants,  initiating agents,  and specialty explosives.  The



 bulk explosives  and propellants are manufactured by reacting concentrated



 acids  with an organic  material in a nitration  step.   Acid fumes  from the



 nitration  step  are a serious  pollutant  emission if  they are not  recovered



 and recycled.  Growth  in  the  explosives  industry is  highly dependent on a



 number of  fluctuating  factors  and therefore  cannot  be  accurately projected.



 2.6    FUGITIVE  EMISSIONS



       The final  sources  of atmospheric  NO  emissions  are man-made and
                                           A


 natural fugitive  emissions.   These  sources generally are  not controlled,



except to  eliminate the  source in extreme  cases,  and their evaluation is



not within the scope of the present  assessment.  However,  estimates of



NO  emissions from  these  sources  will be made  in Section  4 for
  A


comparison with other  NO  sources.
                        A
                                2-43

-------
      Manmade  sources  of  fugitive  NO  emissions include:
                                     J\
      •    Open  burning of municipal  waste,  landscape refuse, agricultural
           field refuse, wood  refuse, and bulky industrial refuse
      •    Grain elevators ,
      t    Forest fires -- both  accidental  and controlled burning
      •    Structural  fires  — both accidental and planned
      t    Minor processes --  such  as welding and acid pickling
2.7    CONCLUSIONS
       The most important  source of N0₯ emissions is the utility boiler
                                      A
category.  This sector is  generally well documented, especially for
information concerning fuel  consumption and  composition, the amount of
electrical power generated,  and installed capacity.   Because this sector
is strictly regulated, boiler  parameters are also well documented.
However,  data are lacking  on furnace design  characteristics for older
equipment.  Although general  information is  available, specific data on
furnace  populations and distribution, unit load factors, use of mixed fuel
firing,  and furnace design trends are difficult to obtain.  In this
report,  missing data were  supplied, in part, by industry contacts, but
more complete information  is needed.  There  is also little information
available on fuel use practices --  particularly statistics on fuel origin,
blending, switching, and backup.  Potentially valuable information on how
new equipment is put on line and older equipment retired is also generally
unavailable.
       Because of the wide range of packaged boiler types and their lack
of strict regulation, data on  packaged boilers is not as complete as data
for other sectors.  In addition, the equipment categorizations defined in
this report are not entirely consistent with previous emissions
                                    2-44

-------
inventories and  industry surveys.  Although  data for sales  of  new packaged
boilers are comprehensive,  little  information  is available  on  boiler  fuel
switching, retirement practices, operational maintenance,  and  burner
distribution.  As a result, the final  categorization of  equipment  types  is
based strongly on recent sales.
       Warm air  furnace equipment  distributions  are  based mainly  on recent
U.S. Census estimates which are considered reliable.   Data  for  other
residential and  commercial  combustion  equipment  types  included  in  this
sector also came from the U.S. Census  Bureau.  However, these data are not
as useful because specific  details are  lacking -- particularly  the fuel
consumed by various equipment types.
       Data for the gas turbine sector  are fairly accurate  because they
are based on recent installed capacity  estimates.  These estimates came
from the Turbine Standard Support  and Environmental  Impact  Statement
prepared to support a NSPS for gas turbines.  One obvious data  gap,
however, is the absence of  information  on smaller capacity  units.  Because
of uncertainty in the availability of clean fuels, the growth of the gas
turbine industry is difficult to predict.
       Data for the reciprocating  1C engine sector came mainly  from the
recent standard support document and are considered  to be of relatively
high quality.   Applications, installed  capacities, load factors,  and fuels
are well documented.  Very small gasoline engines, like those used on
lawnmowers, chainsaws, etc., have  been  excluded  because statistics on
their distribution and use  are very difficult to obtain.
       Process heating sector data are  of good quality for  the  processes
included in this report.  A number of minor processes  were  excluded from
this sector because of their relatively minor applications.  The  major
                                    2-45

-------
processes,  and those which may be subject to combustion control in the
future, are included in this sector.  Although not all noncombustion
processes are discussed in this report, the major noncombustion processes
are considered.  Of greatest concern in this sector are those processes,
like nitric acid plants, which may cause serious local pollution problems.
       Other equipment or process sources of NO  mentioned here are not
                                               /\
covered extensively in this report, but are included only to make the data
complete.  In most cases, existing data on many of these less important
sources  are limited.
                                    2-46

-------
                          REFERENCES FOR SECTION 2
2-1.   McKnight, J. S., "Effects of Transient Operating Conditions on
       Steam-Electric Generator Emissions," EPA-600/2-75-022, Research
       Triangle Institute, August 1975.

2-2.   Mason, H. B., et al., "Preliminary Environmental Assessment of
       Combustion Modification Techniques, Volume II, Technical Results,"
       EPA-600/7-77-119b, NTIS-PB 276 681/AS, Acurex Corporation,
       October 1977.

2-3.   Robison, E., "Application of Dust Collectors to Residual Oil-Fired
       Boilers in Maryland," (Draft) Bureau of Air Quality Control
       Technical Memorandum, Department of Health and Mental Hygiene,
       State of Maryland, December 1974.

2-4.   "Final Environmental Impact Statement -- Coke Oven Emissions," U.S.
       Department of Labor, OSHA, August 1976.

2-5.   Cato, G. A., et al., "Field Testing:  Application of Combustion
       Modifications to Control Pollutant Emissions from Industrial
       Boilers — Phase I," EPA-650/2-74-078a, NTIS-PB 238 920/AS,
       October 1974.

2-6.   Offers, G. R., et al., "Control of Particulate Matter from Oil
       Burners and Boilers," EPA-450/3-76-005, NTIS-PB 258 495/IBE,
       April 1976.

2-7.   Hall, R. E., et al., "A Study of Air Pollutant Emissions from
       Residential Heating Systems," EPA-650/2-74-003, NTIS-PB 229 697/AS,
       January 1974.

2-8.   Giammar, R. D., et al.,  "Emissions from Residential and Small
       Commercial Stoker-Coal-Fired Boilers Under Smokeless Operation,"
       EPA-660/7-76-029,  NTIS-PB 263 891/4BE, October 1976.

2-9.   Barrett, R. E., et al.,  "Field Investigation of Emissions From
       Combustion Equipment for Space Heating," EPA-R2-73-084a,
       NTIS-PB 263 891/4BE, June 1973.

2-10.  Copeland, J. E., et al., "Soiling Characteristics and Performance
       of Domestic and Commercial Oil-Burning Units," APTIC Report 76132,
       January 1968.

2-11.  Roessler, W., et al., "Assessment of the Applicability of
       Automotive Emission Control Technology to Stationary Engines,"
       .EPA-650/2-74051, NTIS-PB 237 115/AS, July 1974.

2-12.  "Standards Support and Environmental Impact Statement, Volume  I:
       Proposed Standards of Performance of Stationary Open Turbines,"
       EPA-450/2-77-017a, September 1977.
                                    2-47

-------
2-13.   Dietzmann,  H.,  and Springer, K., "Exhaust Emissions from Piston  and
       Gas Turbine Engines Used in Natural Gas Transmission," Southwest
       Research Institute, AR-923, January 1974.

2-14.   Offen, G.  R., et al., "Standard Support and Environmental  Impact
       Statement  for Reciprocating Internal Combustion Engines,"  Acurex
       Report TR-78-99, Acurex Corporation, March 1978.

2-15.  Grinberg,  L., and Morgan, L., "Effect of Temperature on Exhaust
       Emissions," SAE Paper 740527, June 1974.

2-16.  Ashby, H.  A., et al., "Vehicle Emissions — Summer to Winter," SAE
       Paper 741053, October 1974.

2-17.  Miles, D.  L., and Hamfeld, M. F., "The Effect of Ambient
       Temperature on  Exhaust Emissions of Cars with Experimental Emission
       Control," SAE Paper 741052, October 1974.

2-18.  Polak,  J. C., "Cold Ambient Temperature Effects on Emissions from
       Light-Duty Motor Vehicles," SAE Paper 741051, October 1974.

2-19.  Personal communication with H. J. Melosh III, Foster Wheeler
       Corporation, June  1977.

2-20.  Personal communication with G. Bouton, Babcock & Wilcox, June 1977.

2-21.  Personal communication with G. Devine, Combustion Engineering,
       June  1977.

2-22.  Personal communication with F. Walsh and R. Sadowski, Riley Stoker
       Corporation, November 1976.

2-23.  Personal communication with S. Baruch, Edison Electric Institute,
       December 1976.

2-24.  Davis,  J.  C., "Conversion to Coal Firing Picks Up Steam,"  Chemical
       Engineering, February 14, 1977.                           	

2-25.  Ctvrtnicek, T.  E., "Applicability of NO  Combustion Modifications
       to Cyclone Boilers (Furnaces)," EPA-600/7-77/006, NTIS-PB  263
       960/7BE, Monsanto Research Corporation, January 1977.

2-26.  Power Magazine Plant Design Issues, 1977.

2-27.  Personal communication with S. T. Potterton, Babcock and Wilcox,
       June 1977.


2~28'  ^°;^7communication with C. L. Richards, Combustion Engineering,


2-29.  Personal communication with D. Dell'Agnese, Cleaver Brooks
               ,  Aqua-Chem Corporation, July 1977.   edver BrooKS
                                    2-48

-------
2-30.   Personal communication with J. Drenning, Combustion Engineering,
       June 1977.

2-31.   "Current Industrial Reports,  Steel Power Boilers," 1968-1975, U.S.
       Department of Commerce, Bureau of the Census.

2-32.   Personal communication with L. Kurtz, Hydronics Institute,
       June 1977.

2-33.   Dupree, W. G., and Corsentino, J. S., "Energy Through the Year 2000
       (Revised)," Bureau of Mines,  December 1975.

2-34.   "1975 Sawyer's Gas Turbine Catalog," Gas Turbine Publications,
       Inc., Stamford, Connecticut,  1975.

2-35.   Personal communication with W. Day, General Electric Co., June 1977.

2-36.   Personal communication with S. Mosier, Pratt and Whitney Corp.,
       June 1977.

2-37.   Personal communication with W. Crim, DOE, July 1977.

2-38.   Frommer, D. W., et al., "The  Changing Fuel Situation for the
       Mineral Industries," Mining Congress Journal, December 1975.

2-39.   Ketels, P. A., et al., "A Survey of Emissions'Control and
       Combustion Equipment Data in  Industrial  Process Heating," Institute
       of Gas Technology, Final Report 8949, October 1976.

2-40.   Foley, G., "Industrial Growth Forecasts," Stanford Research
       Institute Contract 68-02-1320, September 1974.

2-41.   Dykema, 0., and Kemp, V.,  "Inventory of Combustion-Related
       Emissions from Stationary Sources (First Update),"
       EPA-600/2-77-066a, NTIS-PB 266 109/8BE,  March 1977.

2-42.   Durocher, D., et al., "Screening Study to Determine Need for
       Standards of Performance for  New Adi pic Acid Plants,"
       GCA-TR-76-16-G.
                                    2-49

-------
                                  SECTION 3
                   FUELS CHARACTERIZATION AND CONSUMPTION

       This section characterizes  fuel  composition  and consumption  for
equipment and fuel combinations  described in  Section  2.   These  data are
important input for the Section  4  emissions  inventory and the Source
Analysis Model in Section 5.   Since  fossil fuels  account  for almost all  of
the energy consumed by stationary  combustion  sources  nationally,  the
survey includes only these fuels.  Section 3.1  describes  the
characteristics of the three major fossil  fuels and their derivatives.
Section 3.2 summarizes the annual  fuel  consumption  by the major  stationary
source equipment sectors and by  individual equipment  types within each
sector.  Regional fuel consumptions  for  stationary  source sectors and for
individual equipment types are presented  in Section 3.3.   Projections of
fuel consumption for 1985 and  2000 are  given  in Section 3.4.
3.1    FUEL CHARACTERISTICS
       Fuel characteristics are  required  in the present study to  specify
emission factors for combustion-generated pollutants  (NOX, S02,  trace
metallics, organics).  Fossil fuels  show  large  variations in chemical and
physical properties due to variations  in  origin and processing.   To
estimate multimedia effluents produced  by combustion  sources,
representative fuel properties were  determined  for  a  range of fuels from
different geographic regions.  This  approach  was  taken because  data were
                                     3-1

-------
insufficient to treat  each fuel  type separately.  Data were  insufficient
in the following areas:
       •   Comprehensive data which relate fuel consumption  to  fuel  origin
           and its properties are lacking
       0   Emission factors are not available for all types  of  fuel  and
           are often given in terms of average fuel properties
       •   There are no  comprehensive data which quantify the effects  of
           various fuel  cleaning practices such as blending, washing,
           desulfurization, and demetallization by fuel suppliers
       •   Fuel consumption for a given fuel source or region is highly
           variable, making precise characterization impossible
           (Reference 3-1)
       The approach for  compiling fuel composition was based on the
requirements for the emission factor specification discussed in
Section 4.  For emissions of SO,,, particulate, and trace metals, the
stack concentration of pollutants is highly dependent on fuel composition
and less dependent on  combustion conditions or specific equipment type.
Thus, for these pollutants, it is necessary to directly relate emission
factors to fuel concentration.  For NO   CO, HC and organics, emissions
                                      A
are kinetically controlled and depend both on combustion conditions and
fuel content.  For these pollutants, variations in emission factors due  to
differences in fuel content are  treated by specifying representative
emission factors for each equipment/fuel  combination,  e.g.,  tangential
utility boilers firing bituminous coal  and watertube packaged boilers
firing residual oil, rather than directly relating emissions to fuel
content.
                                    3-2

-------
       Trace elements invariably contaminate  liquid  and solid fuels.   This
is an especially important factor  to  consider  in  the combustion  of
residual fuel oil and coal,  since  these  fuels  have high concentrations  of
trace elements and are burned  in large quantities each  year.   In  this
study, the trace metal emission loading  from the combustion of natural  gas
and distillate oil is assumed  negligible compared to residual  oil  and coal
combustion.  This assumption will  have essentially no impact  on estimated
total trace element emissions  from stationary  sources.
       Trace element concentrations typically  vary within  a single
coal-producing region, and even within a single seam (Reference 3-2).
Since the trace element content of individual  coal samples is  highly
variable, representative concentration levels  for coal  were determined.
More detailed evaluation of  the trace element  content of various coals  is
unjustified because:  (1) the  availabile data  on trace  element emission
factors are generally of poor  quality, and  (2) establishing representative
values using highly varying  data is inaccurate.  One study, in fact,
suggests that trace element  emissions from  fossil fuels are so variable
that they must be determined on a  plant-to-plant basis  for a rigorous
analysis (Reference 3-3).
       Characterization of trace elements in residual fuel oils is even
more difficult than for coal because:  (1)  trace elements  in residual fuel
oils vary even more than those in  coal,  and (2) specific data  on the
origin, refinery practices and blending  techniques of the  residual oil
used at the burner are lacking.  Demetallization, desulfurization,
blending of various, grades of  oil  that varies  from refinery to refinery,
and supply and demand strongly influence  the transportation and final
destination of petroleum products.  Because the petroleum  market  is always
                                    3-3

-------
changing, rigid assumptions about refinery origins cannot  be made.   As a
result, only one average set of trace element concentrations is  given for
residual fuel oil.   Table 3-1 displays the trace element concentrations
and summarizes other important properties of each of the major fossil fuel
types (References 3-4,  3-5, and 3-6).  These properties will  be  used
throughout the remainder of this section.
       The characterization of the sulfur content of coal  and heavy  oil,
and the ash content of coal was made for three fuel classes.  This was
because the variation of these properties is so large that a  single
representative class would be unrealistic.  Sulfur (S) and ash (A)
contents of the following fuels are considered representative of the
fossil fuels consumed by stationary sources:
       •   Petroleum fuels
           --  Residual  fuel  oil
               •   Interior province  (high sulfur)  --  2.0 percent S
               •   Eastern province  (medium  sulfur)  —  1.0 percent S
               •   Western province  (low  sulfur)  — 0.5  percent  S
           —   Distillate  fuel  oil, 0.25  percent  S
           —   Gasoline, <0.05  percent S
       •    Coal
           --   Bituminous  and sub-bituminous
               •    Interior province  (high sulfur) - 2.8 percent S,
                   9  percent A
              •    Eastern province (medium sulfur) — 2.2  percent S,
                   9.2 percent A
              •   Western province (low sulfur) - 1.6 percent S,
                  8.7 percent A
                                   3-4

-------
          TABLE  3-1.   PROPERTIES AND TRACE  ELEMENTS OF REPRESENTATIVE  FOSSIL FUELS (References  3-4, 3-5, and  3-6)
CO

en

Ash %
Sulfur %
Heating Value3
AT (ppm)
Sb
As
Ba
Be
Bi
B
Cd
Co
Cr
Cu
Pb
Mn
Hg
Mo
Ni
P
Se
V
Zn
Zr
Anthracite
Coal
11.9
0.6
30,238
—
0:1
9.3
54
2.8
0.1
1.0
0.1
84
112
70
8.3
169
0.3
9.3
47
—
0.2
12
31
45
Sub-bituminous and
Bituminous
High S Medium S
9. 9.2
2.8 2.2
27,912 27,912
12,240
1.3
15
36
1.7
1.
114
2.9
9.1
14.
40.
14
53
0.2
8.0
22
63
2.0
33
312
72
Low S
8.7
1.6
23,260
10,200
1.1
13
30
1.5
0.8
95
2.4
7.6
12.
33
12
45
0.2
6.7
19
53
1.7
28
260
60
Lignite
Coal
12.8
0.4
18,608
8,160
0.9
10
24
1.2
0.7
76
2.0
6.1
10.
26
9.2
36
0.1
5.3
15
42
1.3
22
208
48
Residual Fuel Oil
High S Medium S
Trace Trace
2.0 1.0
39,021
753
0.2
0.2
39
—
—
3.0
2.0
30.
30r
25.
19
25
O.T
2.5
1,208
—
10
1,803
40
19
Low S
Trace
0.5






















Distillate
Oil
0
0.25
39,021
Trace



















i




















Gasoline
0
<0.05
34,840
Trace



















1




















Natural
Gas
0
<0.1
37,259
Trace



















\




















            aH.V.  in kJ/kg -- coal
                   kJ/X — oil
                        — gas
                                                                                                                     10
                                                                                                                     CO

-------
           —   North  Dakota lignite, 0.4 percent S, 12.8 percent  A
           —   Pennsylvania anthracite, 0.6 percent S, 11.9 percent  A
       •   Natural  gas,  <0.1 percent S
       The medium sulfur levels of coal and residual oil correspond  to the
average sulfur concentration of fuels used in U.S. utilities  in 1974
(Reference 3-7).   Although data on fuel sulfur composition are available
for the utility boiler sector, there are relatively few data  available for
other sectors.  When  consumption data for fuels were not available by
specific sulfur content, medium sulfur concentrations are used where
applicable.
3.2    FUEL CONSUMPTION
       Estimates of fuel consumption for stationary sources (or annual
product output for process heating sources) are presented in  this
subsection.  Fuel consumption was compiled for the year 1974, since  this
was the most recent year for which comprehensive and complete regional
data were available.   For comparative purposes it was important that  both
the national and regional fuel consumption data represented the same
year.  Table 3-2 summarizes total annual consumption for coal, petroleum,
and gas.  These totals do not reflect total energy consumed by stationary
sources, because some of the process industries and nonfossil fuel use
have not been  included.
       Total U.S. energy use in 1974 totaled about 77 EJ (72 x 1015  Btu)
(Reference 3-8),  of which 94 percent was supplied by the fossil fuels  —
coal, petroleum,  and  natural gas.  Approximately 57 percent of the total
energy was used by stationary sources.  Fossil fuels furnished 92  percent
of the energy for these stationary sources; the remainder was supplied  by
nuclear, hydroelectric,  and other miscellaneous sources such  as waste
                                    3-6

-------
    TABLE  3-2.   1974 STATIONARY SOURCE FUEL CONSUMPTION (EJ)a
Equipment
Sector
Utility Boilers
Packaged Boilers0
Warm Air Furnaces
and Miscellaneous
Combustion
Gas Turbines
Reciprocating
1C Engines
Total
Coal
10.833
3.470
— —
—
—
14.303
Oil
3.483
5.780
2.132
0.844
0.328d
12.567
Gas
4.906
6.323b
5.542
0.681
0.914s
18.366
Total
Fuel
19.222
15.573
7.674
1.525
1.242
45.236
aEJ/yr = 1018 J/yr
 Includes process gas
cThis sector includes steam and hot water units
 Includes gasoline and oil portion of dual fuel
elncludes natural gas portion of dual fuel
                                3-7

-------
fuels, wood, and geothermal .  Of the total amount  of  fossil  fuels burned
in stationary sources, coal contributed 26 percent,  natural  gas 44
percent, and petroleum 30 percent.  Unlike petroleum,  which  is also a
major source of energy for transportation, coal  and  natural  gas are used
primarily in stationary applications.
       The following discussion presents estimates  of  fuel consumption and
reviews information sources for the major equipment  sectors  identified in
Section 2.
3.2.1  Utility and Large Industrial Boilers
       Fuel consumption estimates for utility boilers  are reasonably
comprehensive due to the regulation of the industry.   Table 3-3 gives  a
detailed summary of the fuel consumed by significant utility  boiler
equipment types.  This summary was derived from  the  following sources:
       •   Federal Power Commission (FPC) — fuel consumption by type  of
           fuel and sulfur content (References 3-7 and 3-9)
       •   GCA — analysis of FPC-67 tapes to provide  data on the  total
           number of boilers and the fuel breakdowns (Reference 3-10)
       •   Monsanto ~ analysis of the cyclone boiler  population and fuel
           consumptions (Reference 3-11)
       •   Office of Air Quality and Planning Standards (OAQPS)  --
           analysis of lignite fired steam generators  (Reference 3-12)
       •   A.  D.  Little —  analysis  of the electric utilities  and
           equipment  manufacturers (Reference 3-13)
       •   Battelle —  analysis of the boiler population and  fuels  for
           nonutility application  (Reference 3-14)
       •    Bureau  of  Mines  —  data on  domestic coal production  and  end use
           by state;  data on  petroleum products  (Reference 3-15)
                                    3-8

-------
                              TABLE 3-3.  1974 UTILITY BOILER FUEL CONSUMPTION (EJ)






Utility Boilers


Tangential
Single
Wall Fired
Horizontally
Opposed Wall and
Turbo Furnace
Cyclone
Vertical and
Stoker
"O I/I
t- C 3
3 10 O
<*- C
i—  ••- 3
z: OQ ui
2.624
1.513

0.423


0.158
0.110

•o 
C 3


3  'r-
§"
3 C *J
E 2
-C 3 1
O1-4-) J3
•r- i- 3
OC OO t/)
1.584
0.914

0.255


1.292
0.110

•O t/>
C 3
•0 0
c:
i-  ••-
3 3 E
K- 0 3
r- C 4J
3 *r- •*—
 J3
O-r- 3
_l CD CO
0.869
0.501

0.140


—
—







0}
•r-
§,
0.053
0.011

0.021


0.137
0.009





01
44
u
ID
L.
i
—
_

—


—
0.109








r—
« r—
5.130
2.939

0.839


1.587
0.338



•o
I. c

t^.
*3 15
OO 3
-O 4)
O> */> 3
•i- (1) t.
2: ce   -O O!
^» t3
o « S
_l Of U
0.636
0.637

0.258


0.037
—



T9

«

15
3
t--0 01
IB «^ ^J
*> Wl 3
|2(So
1.324
1.326

0.536


0.077
—





41
+>
r^
.^«
in
S
0.036
0.169

0.015


—
_








r~
a
1.360
1.495

0.551


0.077
_







•jj
t.
•*-> VI
1.134
2.453

1.258


0.061
_






^^
<
F- 
-------
      •   Power Magazine  -- miscellaneous  information on various
          equipment and fuel  trends  (Reference 3-16)
      Two simplifications were  used  in  arriving at these estimates:
      •   Distillate oil  and  kerosene  are  combined with the residual fuel
          oil category, since distillate oil  accounted for only about
          5  percent of utility  steam plant total oil consumption
          (References 3-14  and  3-17)
       •   Coke,  coke breeze,  refuse, process  gas, wood, bagasse, black
          liquor,  sewage  sludge,  etc.,  are negligible for utility boiler
          application
       It was found that coal  accounted  for 56 percent of the fuel
consumed  by  utility boilers,  natural  gas 26 percent, and oil 18 percent.
Coal-fired utility boilers used  about 76 percent of the total energy
supplied  by  coal  to all  stationary sources.  Utility boilers burned only
28 percent of both oil  and gas  fuels  consumed  by stationary sources.
3.2.2  Packaged  Boilers
       Fuel  consumption  data for packaged boilers are not as reliable as
data for  utility boilers,  due  to the  diversity of packaged boiler designs,
the wide  variety of applications,  the lack  of  regulation and documented
data, the large  number  of  installed  units and  their characteristic wide
fuel flexibilities.  Table 3-4  lists  fuel consumption estimates for
packaged  boiler  designs  that  consume  significant amounts of fuel.  These
estimates were derived from  a  number  of  sources:
       •   Battelle —  analysis  of the  national boiler population by
          capacity and  fuel  (Reference  3-14)
       •   Battelle — analysis  of the  equipment design distribution
           (Reference 3-18)
                                    3-10

-------
                                TABLE 3-4.  1974  PACKAGED BOILER FUEL CONSUMPTION  (EJ)
CA>
Packaged Boilers
Wall Firing
Water tube
>29 MWa
Stoker
Watertube
>29 MW3
Single Burner
Watertube
<29 MWa
Single Burner
Scotch Firetube
<29 MWa
Single Burner
HRT Firetube
<29 MWa
Single Burner
Firebox Firetube
Single Burner
Cast Iron Boiler
Stoker Watertube
<29 MW*
Stoker Firetube
<29 MM*
Steam or Hot
Water Units
(Residential
Only)
Anthracite
—
—
—
—
—
—
—
0.021
0.042
0.014
Bituminous
or
Lignite
0.510
0.466
0.317
—
— ,
—
—
1.533
0.556
0.011
Total
Coal
0.510
0.466
0.317
^
—
—
—
1.554
0.598
0.025
Residual
Oil
0.637
—
0.595
0.945
0.370
0.609
0.195
—
—
0.069
Distillate
Oil
0.085
^
0.103
0.446
0.263
0.403
0.181
—
—
0.880
Total
Oil
0.722
—
0.698
1.391
0.633
1.012
0.376
—
—
0.949
Natural
Gas
0.928
—
1.690
0.972
0.535
0.899
0.264
—
—
0.737
Process
Gas
0.130
—
0.130
0.019
—
0.019
—
—
—

Total
Fuel
2.290
0.466
2.835
2.382
1.168
1.930
0.640
1.554
0.598
1.711
              Heat input

-------
       •   U.S. Department of Commerce - data on boiler sales  for  1968 to
           1974 (Reference 3-19)
       •   The Research Corporation of New England (TRC) —  historical
           trends in packaged boiler fuels (Reference 3-20)
       The assumptions used to estimate fuel consumption for  packaged
boilers included the following:
       •   All boilers greater than 29 MW (100 MBtu/hr) input capacity  are
           watertube designs and are single wall fired
       •   Pulverized coal is not fired in units with input  capacity less
           than 29 MW
       •   All coal for residential and commercial heating is burned in
           steam and hot water units
       In 1974, energy supplied to packaged boilers was 34 percent  of the
total fossil fuel consumed by stationary sources for energy conversion.
Of this total consumption, 24 percent of total coal, 46 percent of  total
oil, and 34 percent of total gas used by stationary sources was consumed
by packaged boilers.  Coal, the most widely used fuel in utility boilers,
is also used widely in industrial boilers for the larger watertube
pulverized and stoker units.  At present, coal is less seldom used  in the
new firetube or the smaller watertube boilers because the ease of
transportation and distribution of oil  and gas fuels is important to users
of packaged boilers.
3-2-3  Warm Air Furnaces and Other Commercial and Residential Combustion
       In this sector, the range of equipment designs and large number  of
units cause uncertainties in the fuel consumption estimates.  Estimated
fuel consumption for commercial and residential combustion as well  as for
various cooking appliances, clothes dryers, refrigeration units, etc.,
                                    3-12

-------
listed as "other" is presented in Table 3-5.  The major  source  for  these
estimates was the 1970 U.S. Census  (Reference 3-21).
       The basic assumptions used in making these estimates were:
       •   The amount of wood, refuse, and other nonfossil fuels burned in
           warm air furnaces is minimal
       •   Units fueled by tank, bottled or liquefied petroleum gas are
           not a large portion of the total.  Since these units are
           generally located in rural areas and cause no localized
           impacts, they were combined with natural gas-fired units.
       •   Coal firing in warm air furnaces is insignificant
       Total warm air furnace fuel consumption in 1974 represented about
17 percent of the total used in stationary sources for energy conversion.
The natural gas consumption in this sector is in the same range as that
for utility and packaged boilers, whereas the amount of oil is  less.
3.2.4  Gas Turbines
       Because there are relatively few types of major applications and
manufacturers of gas turbines and the utility applications are regulated,
the 1974 estimates of fuel consumption for gas turbines are of high
quality.  Table 3-6 gives the fuel consumption estimates for the three gas
turbine capacity ranges.  These estimates are derived from a number of
sources:
       •   Gas Turbine (GT)-Standards Support Document — installation and
           generation for all applications and capacity ranges  except
           utilities (Reference 3-22)
       •   FPC — installation, generation, and fuel consumption for.all
           utility and pipeline applications  (References 3-9 and 3-23)
                                    3-13

-------
TABLE 3-5.   1974 WARM AIR  FURNACE  AND  OTHER  COMMERCIAL AND RESIDENTIAL
            COMBUSTION FUEL  CONSUMPTION  (EJ)
Warm Air Furnaces
Warm Air Central
Furnaces
Warm Air Room Heaters
Miscellaneous
Commercial /Residential
Combustion
Distillate
Oil
1.405
0.727
~~
Natural
Gasa
3.091
1.451
1.0
Total
Fuel
4.496
2.178
1.0
        Includes bottled, tank or LPG
           TABLE 3-6.   1974 GAS  TURBINE  FUEL  CONSUMPTION  (EJ)
Gas Turbines
Gas Turbines
Gas Turbines
4 MW to 15 MWk
Gas Turbines
<4 MWb
Natural
Gas
0.212
0.468
0.001
Oil3
0.264
0.579
0.001
Total
0.476
1.047
0.002
             Includes distillate, diesel, residual oils
                   output
                               3-14

-------
       •   Sawyer's GT Catalog  —  miscellaneous  information  on  utility and
           pipeline applications  (Reference  3-24)
       •   GT International  —  data  on  gas turbine  electric  utility
           installations  (Reference  3-25)
       These estimates were  made  on  the  basis  of the  following  assumptions:
       •   Typical specific  heat  rates  for the three  capacity ranges were
           10.9 MJ/kWh (10,300  Btu/kW-hr), 13.9 MJ/kWh  (13,200  Btu/kW-hr)
           and 16.4 MJ/kWh (15,500 Btu/kW-hr)  for large, medium, and small
           capacity turbines, respectively
       •   Specific fuel  consumption  does not  vary  significantly with
           load, which means total fuel  consumption can be determined
           directly from  specific  fuel  consumption  and  generation totals
       •   The amount of  alternate fuels, such as gasified or liquefied
           coals, shale oil, process  gas, pulverized  coal, or refuse,
           burned in turbines is negligible
       The total energy consumed by  gas  turbines was  about 3.4  percent of
the total stationary source  fuel consumption in 1974.   As Table 3r6 shows,
medium-capacity units consumed more  fuel than  the large units.  The bulk
of the fuel consumption of these medium-capacity turbines was either in
the oil and gas industry, where equipment operates  almost constantly, or
in private sector electricity generation, where equipment operates about
three-quarters of the time.
3.2.5  Reciprocating 1C Engines
       This sector represents an extremely wide range of designs,
applications and manufacturers.  A recent study (Reference 3-26), however,
has characterized reciprocating 1C engines by  installed capacity and
annual generation by fuel, and data from this  study have been used
                                    3-15

-------
extensively for this  sector.   For  consistency with other sections of this
report, data from Reference  3-9 have  been used for installed capacity,
annual generation,  and  fuel  consumption of 1C engines used by electrical
utilities.  Table 3-7 gives  fuel consumption figures for significant
equipment types determined in Section 2.
       The following  assumptions were used in arriving at these estimates:
       t   Specific fuel  consumption  averaged 9.9 MJ/kWh (7000 Btu/hp-hr),
           11.3 MJ/kWh  (8000 Btu/hp-hr), and 11.3 MJ/kWh for large-,
           medium-, and small-capacity ranges, respectively
       •   Specific fuel  consumption  does not vary significantly with
           load,  so that  overall fuel consumption can be determined from
           specific fuel  consumption  and generation totals
       •   No  gasoline  is burned in large- or medium-capacity equipment
       •   No  natural gas is burned in small-capacity equipment
       The total  energy consumed by this sector is about 3 percent of the
 total consumption of  fuel used for energy conversion in stationary
 sources.   Natural gas is  the major fuel, particularly in the large-bore
 units.  The major user  of natural  gas-fired, large-bore engines is the oil
 and gas  industry, where units usually operate over 8000 hours a year.
 3-2.6  Industrial Process Heating
        Production totals  for various  processes within this sector are used
  instead of fuel consumption  totals.  This was done because emission
  factors for  industrial  process heating are usually presented in terms of
      uction totals.  Moreover, production figures are more reliable than
  energy consumption  statistics for  heating operations in most industries.
            e  3-8 gives  production  data for the major process heating
  industries, and TahiQ o 0
                 iau'e j-g gives fuel  consumption data for refinery process
                                     3-16

-------
                           TABLE 3-7.  1974 RECIPROCATING 1C ENGINE FUEL CONSUMPTION (EO)
co
i
Reciprocating 1C Engines
Compression Ignition
>75 kW/cyia
Spark Iqnition
>75 kW/cyla
Compression Ignition
75 kW to 75 kW/cyla
>1000 rpm
Spark Ignition
75 kW to 75 kW/cyla
>1000 rpm
Compression Ignition
<75 kWa
Spark Ignition
<75 kWa
Natural
Gas
—
0.813
—
0.043
—
—
Distillate
on
(Diesel)
0.054
—
0.129
•~*
—
• —
Gasoline
—
—
—
0.084
—
0.049
Dual
(011 + Gas)
0.058 Gas
0.012 011
—
—
—
-
—
Total
Fuel
0.124
0.813
0.129
0.127
—
0.049
                'Power output

-------
    TABLE 3-8.  1974 INDUSTRIAL PROCESS HEATING PRODUCTION
  Industrial Process Heating
Annual Production
   Cement Kilns



   Glass Melting Furnaces



   Glass Annealing Lehrs



   Coke Oven Underfire



   Steel Sintering Machines



   Open Hearth  Furnaces



   Brick and Ceramic  Kilns



   Catalytic Cracking



   Refinery Flares



    Iron  and Steel  Flares
 7.696 x 107 Mg



 1.542 x 107 Mg



 1.542 x 107 Mg



 5.701 x 107 Mg



 4.851 x 107 Mg



 3.227 x 107 Mg



 3.158 x 107 Mg



 2.294 x 1011  £ feed



 7773 Mg N0/yra
           ^\


 318 Mg N0/yra
          X
     NO  estimates
TABLE 3-9.   1974 REFINERY PROCESS HEATING FUEL  CONSUMPTION (EJ)
Heater Type
Natural draft
Forced draft
Total
Gas
1.119
0.128
1.247
Oil
0.256
0.081
0.337
Total Fuel
1.375
0.209
1.584
                              3-18

-------
heaters.  Complete statistics are  kept  by industry associations,  so  there
are many reliable sources for these  data.   The  primary sources  for these
statistics were:
       •   Walden -- data on the iron and  steel  industry  (Reference  3-27)
       •   Bureau of Mines — data on the  iron  and steel  industry, cement
           industry, brick and ceramic  industry (Reference  3-15)
       •   Institute of Gas Technology  (IGT)  —  data on cement  kilns,
           glass manufacturers, petroleum  refineries,  cement  industry
           (Reference 3-28)
       •   TRC — data on brick and  ceramic kilns  (Reference  3-20)
       •   Lockheed — data on refinery flares  (Reference 3-29)
       •   KVB — data on refinery process  heaters  (Reference 3-30)
3.3    REGIONAL FUEL CONSUMPTION
       Regional fuel consumptions  were  compiled  by equipment  design  type.
In this way, regional differences  in both fuel  consumption  and  equipment
type could be evaluated.
       Census Bureau regions were  used  to  partition national  fuel
consumption geographically.  These regions  are  also used  in data  compiled
by FPC and the Bureau of Mines.  Since  the majority of our  data come from
these sources, using the same regional  divisions causes minimal data
adjustment.  Figure 3-1 displays these  regional  divisions.  The codings on
this map represent areas having their energy  consumption  met  by over 40
percent of either oil, coal, or natural gas.  This figure shows that oil
is the major fuel used in the East Coast.   The  West Coast and Southwest
are supplied largely by natural gas, and  the  Midwest relies primarily  on
coal for its fossil fuel requirements.
                                     3-19

-------
Co
i
IX)
o
 6% C
37% 0
57% G
                                                         43% C
                                                         18% 0
                                                         39% G
                                                                                            28%  C
                                                                                            45%  0
                                                                                            27%  G
          52% C
          18% 0
          30% G
                                                                                        -N
                                                                                  ENGLAND^
                                               WEST NORTH
                                                 i»
                                                 CENTRAL
    NORTH
    &5?
    WYKV
CENTRAL

                                                                               SOUTH

                                                                              ATLANTIC
 SOUTH
 .8SB8S.
CENTRAl?
                                     37% C
                                     21% 0
                                     42% G
                                                                                                6% C
                                                                                               77% 0
                                                                                               17% G
                                                                               36% C
                                                                               39% 0
                                                                               25% G
                                 Figure 3-1.   Regional  fuel distributions.
                                                                                         >40% oil

                                                                                         >40% coal
                                                                                         >40% gas
                                                                           (Except South Atlantic,
                                                                           where oil  represents 39%
                                                                           total fuel  consumption.)

-------
       In the following discussion,  the  sources  and  reliability of  the
fuel consumption estimates  are  given.  Tabular  summaries  of  regional  fuel
consumption are presented  in Appendix  A  of Volume II  (Tables  A-l to
A-44).  These totals do not reflect  total  energy consumed by stationary
sources because electrical  inputs  from nonfossil  fuel  sources are
excluded.  The same basic  assumptions  that were  used  to  simplify the
estimates of national fuel  consumption by  sector  are  also used  here for
regional consumption.
3.3.1  Utility and Large  Industrial  Boilers
       Regional fuel consumption estimates for  utility boilers  are
considered very accurate  because of  the  excellent correlation between
independent data sources.   The  following sources  were  used:
       •   FPC — fuel consumption by  type of fuel and sulfur content
           (Reference 3-31)
       •   Bureau of Mines  -- data on  domestic  fossil  fuel production and
           end use by state (Reference 3-32)
       •   National Emissions Data System  (NEDS)  — fuel  consumption  by
           region and end  use (Reference 3-33)
       •   Battelle — analysis of boiler  populations  and fuels
           (Reference 3-14)
The FPC data was used to  determine the regional  distribution  of coal, oil,
and gas because they were  the best documented.   These  data were
supplemented by data on large industrial boilers  from  Battelle.
       Figure 3-2 shows the regional distribution of  fuel use for utility
and large industrial boilers.   The coding  designations indicate areas
where a single fuel represents  more  than 50 percent  of the total fuel
consumption.  As shown, coal is the  most common  fuel  in  the  Midwest,  while
                                     3-21

-------
I
no
ro
                                                        66% C
                                                         2% 0
                                                        32% G
                                                                                             55%  C
                                                                                             42%  0
                                                                                              3%  G
                                                                               SOUT
                                                                               •XWX/V*.
                                                                              ATLANTIC
  OUTH
  m&
CENTRAL
                                                                                                 9% C
                                                                                                88% 0
                                                                                                 3% G
65% C
26% 0
 9% G
                                                                                           >50% oil

                                                                                           >50% coal

                                                                                           >50% gas
               Figure 3-2.  Regional  fuel distributions for utility and  large industrial boilers.

-------
in the far West and New England,  oil  is  the most widely used fuel.   The
West-South-Central region  is  heavily  dominated  by natural  gas use.   Tables
A-l to A-9 in Appendix A of Volume  II  present  regional  summaries  of
utility boiler fuel consumption.
3.3.2  Packaged Boilers
       Regional fuel consumption  estimates  for  packaged boilers were
determined from the following sources:
       •   Battelle -- analysis of  equipment design  distribution
           (Reference 3-18)
       •   Battelle -- analysis of  national  boiler population by  capacity
           and fuel (Reference 3-14)
       t   NEDS — fuel consumption by region  and end  use  (Reference 3-33)
       t   Catalytic — regional  sales data from the Hydronics Institute
           (Reference 3-34)
       •   Bureau of Mines ~  data  on  domestic  fuel  production and end  use
           by state (Reference 3-32)
       •   U.S. Department of Commerce — data  on boiler sales, 1968 to
           1974 (References 3-19)
       Fuel consumption data  for  the  packaged  boiler sector  are not  as
accurate as for utility boilers.  Tables A-10  to A-18  in Volume II give
these regional fuel consumption data.  Nonetheless,  there  was good
correlation between all data  sources  except the Bureau  of  Mines petroleum
data, because they include space  heating uses.   The  same fuel
distributions as in the utility and large industrial boiler  sector are
prevalent in the packaged  boiler  sector. Oil  is a major fuel in  New
England.  Both natural gas and oil  are used on  the West Coast, with
natural gas receiving slightly higher  usage.
                                    3-23

-------
3.3.3  Warm Air Furnaces and Other Commercial and Residential  Combustion
       NEDS data (Reference 3-33) were used to develop the  residential
fuel consumption inventory.  These data correlate with the  Bureau  of  Mines
household energy consumption values (Reference 3-32).  Tables  A-19 to A-22
present regional fuel consumption values.  Natural gas and  oil are the
major fuels used in warm air furnaces.  Coal use in this sector represents
about 1.5 percent of total coal usage and less than 0.1 percent of this
sector's total energy consumption, according to Bureau of Mines fuel
consumption data.  Hence, coal  use is not considered in this sector.
Natural gas is the preferred fuel, strongly dominating the Middle
At Jamie, East-North-Central,  East-South-Central,  West-South-Central, and
Pacific regions.
3.3.4  Gas Turbines
       Since major gas turbine  applications for utilities are closely
regulated, estimates of fuel consumption for gas turbines are accurate.
Other gas turbine applications  can be traced by manufacturer.
       The following sources were used for our estimates:
       •   Electric World -- Annual  statistical  report (Reference  3-35)
           for regional distribution of gas turbines  by installed  capacity
       •   NEDS — fuel consumption  by region  and  use (Reference 3-33)
       •   Bureau of Mines —  data on domestic fossil  fuel  production and
           end use (Reference  3-36}
       •   Sawyer's GT Catalog  — miscellaneous  information on utility and
           pipeline applications  (Reference 3-24)
       •   GT International -  data  on gas turbine  utility installations
           (Reference 3-25)
                                    3-24

-------
       •   Bureau of Mines -- data  on  gas  turbine  utility installations  by
           state (Reference 3-32)
       Electric World is an excellent  source  of  data,  since  it  separates
reciprocating 1C engines from gas turbines.   The other  data  sources do not
make this distinction.  In this  sector,  distillate oil  and natural gas are
used primarily.  Distillate oil  is  the primary fuel  in  the New  England and
Middle Atlantic regions.  The West-North-Central,  East-North-Central,
Mountain and Pacific regions are primarily supplied  by  natural  gas.
Tables A-23 to A-26 present these fuel consumption data.
3.3.5  Reciprocating 1C Engines
       The recent standard support  document (Reference  3-37) was used to
categorize the wide range of designs,  applications,  and manufacturers of
reciprocating 1C engines.  These classifications were partitioned into
regions using the following sources:
       •   Standard support document for Reciprocating  1C Engines —
           characterization of reciprocating  1C  engines by capacity, and
           annual generation by fuel (Reference  3-37)
       •   NEDS ~ fuel consumption by region and  end use (Reference 3-33)
       •   American Gas Association — regional  installed horsepower for
           gas transport (Reference 3-38)
       •   Senate Committees - National  Energy Transportation — data on
           pipeline usage for oil transport (Reference  3-39)
       •   American Gas Association — 1974 data on  gas production
           (Reference 3-40)
       •   FPC — data on electric  energy  production by industry
           (Reference 3-41)
                                    3-25

-------
       Where comparison was possible, there was good correlation  between
data sources.  Tables A-27 to A-35 give summaries of fuel  consumption
data.  Distillate oil, natural gas, and dual fuels  (oil and  gas)  are the
major fuel categories in this sector.  Again, New England  is dominated  by
oil usage, while natural gas is the major fuel in the Southwest.  The
Pacific region uses both oil and natural gas and the Midwest is dominated
by dual fuel usage.
3.3.6  Industrial Processes
       Regional production totals instead of fuel consumption were used to
estimate emissions for industrial processes because emission factors are
usually given in terms of production totals for industrial processes.
There are a number of reliable sources that provide accurate information.
These sources have compiled data mainly from industry statistics.
       The following sources were used:
       •   Monsanto -- data on glass melting (Reference 3-42)
       •   Wai den ~ data on iron and steel (Reference 3-27)
       •   Radian -- data on iron and steel (Reference 3-43)
       •   Bureau of Mines -- commodity data summarized (Reference 3-15)
       t   IGT — data on cement kilns, glass manufacturers, petroleum
           refineries, and the cement industry (Reference 3-23)
       •   EPA Development Document -- data on petroleum refineries
           (Reference 3-44)
       •   Gordian Associates — data on petroleum refining, cement,
           steel, and glass (Reference 3-45)
       •   Lockheed — data on refinery flares (Reference 3-29)
Tables A-36 to A-44 provide summaries of regional  process heating data.
                                    3-26

-------
3.4    ENERGY SCENARIO DEVELOPMENT
       Energy projections are needed  in  this  study to  estimate  the trends
and order-of-magnitude potential  environmental  problems  from  stationary
source combustion.  Since energy  supply  and  allocation can  vary greatly,
several projections for energy  growth and  equipment/fuel  use  were selected
and carried through the evaluation  of potential  environmental problems.
The scenarios were selected to  cover  the range  of  probable  developments in
energy supply and consumption.  Factors  considered in  selecting the
scenarios were:
       •   Energy Conditions
           —  Fuel availability  and  cost
           --  Federal regulations
       t   Equipment Conditions
           --  Evolving design  trends
           ~  Environmental constraints on equipment  design  (i.e., wet
               bottom boilers promoting  thermal  NO )
                                                   A
       •   Environmental Conditions
           —  Federal regulations
           —  Control technology advances
       Section 3.4.1 discusses  how  alternative  energy  scenarios were
selected and developed from the available  literature.  Section  3.4.2
describes the sources used for  determining future  equipment use trends.
The environmental control scenario  is discussed  in Section  4.3.  These
future patterns are then used to  develop emission  inventories for years
1985 and 2000 in Section 4, and to  rank  the pollution  potential of sources
in Section 5.
                                     3-27

-------
3.4.1  tnergy Alternatives
       Five different energy scenarios were examined.   The main  factors
considered in each alternative were:  (1) the effect of government
regulations and policies on the rate of growth in demand for  energy
resources, (2) the equipment additions, by fuel type, required to  meet
demand and source attrition, and (3) the effect of oil-to-coal,
gas-to-coal, and gas-to-oil conversions on fuel consumption.  The  five
energy alternatives are:
       •   Reference — low nuclear
       •   Reference -- high nuclear
       •   Conservation
       •   Electrification
       •   Synthetics
Figure 3-3 shows the mix of fuels and equipment types for each scenario.
These alternatives encompass a variety of contingencies  in both  total
energy demand and demand for specific fuels which lead  to important
differences in the type and quantity of pollutants released.
Development of Energy Scenarios
       In selecting energy alternatives, background information  was
obtained from DOE (References 3-49, 3-50), and to a lesser extent  from
References 3-34 through 3-65.  The DOE projections were  used  to  take
advantage of the technical expertise and the wide circulation of their
results.  Also, as shown in Table 3-10, scenarios developed by other
groups do not vary significantly from projections by DOE.  Indeed,  several
of  these projections are based heavily on DOE results.   A number of
earlier fuel supply/demand studies have become largely  obsolete  due to  the
OPEC oil embargo in the fall of 1973.
                                    3-28

-------
                                                                 Fuel  Types
Equipment Sectors
                80 -,
            s_
            iu


            £

            3
co
 t
ro
on
pt
cons
                 40  •
ro
0



I
^
X
X
X
X
1=1
m^^m
0
•••«
CO



|
—
^
X
x
X
x
X
X
X
X
XJ
X
X
X
0
M«VI
^^^
00
H

-------
  TABLE 3-10.   FORECASTS OF TOTAL U.S.  ENERGY CONSUMPTION IN 1985
               AND 2000 (EJ)
Energy Projections
Dupree and West
National Petroleum Council
Project Independence -- Business as Usual
Energy Policy Project -- Historical
Organization for Economic Cooperation and
Development -- Base
DOE — No New Initiatives3
EEI ~ Medium Growth
Mobil Oil
Dupree and Corsentino
DOE — 1976 Reference3
1985
122.93
118.58
114.95
122.26
120.49
113.09
109.93
105.72
109.13
108.87
2000
202.26
N/A
N/A
197.10
N/A
174.41
N/A
N/A
172.26
N/A
l^lajor references  used
                               3-30

-------
Descriptions of Scenarios
       Reference Case — High  Nuclear
       This case assumes that  current consumption patterns continue with
no major design or efficiency  improvements in the residential, commercial
or industrial sectors.  This scenario does not assume passage of any
energy conservation  actions which  are currently under consideration by
Federal and State legislatures.  However,  the dependence of energy demand
on energy cost is considered.
       On the supply side, oil  and gas production draws on the remaining
recoverable domestic resources,  without the benefits of tertiary or any
other new recovery methods.  Coal  and nuclear powerpi ants continue to
expand to meet electricity demand, limited only by the ability to
construct or convert plants.   Nuclear powerplants are projected to meet 65
percent of the demand for new  power generation by the year 2000.  Other
energy sources such  as  geothermal, hydroelectric, and urban waste are
projected to grow as required  to meet energy demand, without pushing the
technical development of the technology.   In addition, it is assumed that
there are no unforeseen energy developments which would make their use a
high national priority.
       Reference Case -- Low Nuclear
       The low nuclear  case again  assumes  that current consumption
patterns continue with  no specific improvements in the residential,
commercial, and industrial sectors.  Coal  and nuclear powerplants continue
to meet new electricity capacity demand.   However,, this scenario assumes a
lower use of nuclear power and  a higher use of coal.  Nuclear power
accounts for 35 percent of new  generating  capacity through the year 2000,
whereas coal accounts for 65 percent.  This scenario would occur if there
                                     3-31

-------
was increased pressure to use our coal  resources  to  meet future energy
demand, and if the use of nuclear powerplants  continues to be low because
of concerns about safety, waste disposal,  safeguard  costs, or uranium
costs.
Conservation
       The conservation scenario was  developed  to examine energy
conservation efforts such as improving  energy  conversion efficiency and
increasing the use of energy resources  presently  available.   This means
increasing the recovery of gas and oil  (secondary, tertiary recovery) and
using  waste materials from recycling  and energy conversion.   Thus, energy
demand is effectively reduced, but the  major sources  of energy remain
essentially the  same.  Additionally,  it is  assumed that new  secondary
sources requiring some end user initiative  will be implemented (municipal
refuse, agricultural wastes etc.).  The key assumptions are:
        •   Domestic oil and gas production  are  increased by  implementing
           new recovery technologies
        •   Waste materials are used as  fuels
        •   Solar heating and cooling, and  geothermal  heat are implemented
           to reduce the need for fossil fuels  in process heating and
           residential or commercial  space  heating
        t   Thermal efficiency standards are set for  residential  and
           commercial buildings
        •   Efficiency guidelines are  implemented  for  industrial  and
           commercial applications
        Electrification
        This scenario maximizes potential end uses of  electricity and  uses
as much electric generating capacity  as possible.  In  addition,  existing
                                    3-32

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oil- and gas-fired equipment  is  converted  to  coal  where  possible.  Key
assumptions considered  in this scenario  include:
       •   Coal firing  is used in  new  boilers  greater than 29 MW  (heat
           input)
       •   Nuclear power is maximized  in new  utility generating capacity
       •   Oil and gas  firing in space heating equipment  in  new buildings
           is restricted
       •   Natural gas  firing in new packaged  boilers is  replaced  by coal
           and, to a  lesser extent, by oil
       •   Half of the  natural gas  units in the process  heating sector  are
           replaced by  electricity
       t   Existing oil- and  gas-fired packaged boilers  are  converted to
           coal firing  where  practical
Synthetics
       This scenario  considers the  effects of  increased  supply of
synthetic liquids and gaseous fuels.   It evaluates the impact of drawing
on vast resources of  coal and oil  shale to produce liquid and gaseous
fuels as direct substitutes for  petroleum  fuels.   Of the  five scenarios,
this scenario results in the  smallest  disruption  in end  use  equipment
types.  The total energy projected  is  quite close  to the  reference
scenario, although much less  oil and natural  gas  are consumed.  This
scenario also assumes that growth  in electric  generating  capacity  is
largely met by light  water reactors, so that  new  coal production can be
used for synthetics.  Key assumptions  considered  are:
       •   Enhanced recovery  of  oil and  gas (using new recovery
           technologies, i.e., tertiary, secondary recovery)
                                     3-33

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       •   New fuels produced from
           --  Coal
           —  Oil  shale
           —  Biomass
The primary impacts  here are in the packaged boiler and small combustion
equipment sectors.   This sector depends largely on synthetic gases  and
liquids -derived from coal, because oil- and gas-fired boilers in this size
range generally cannot be converted to burn coal economically and
efficiently with present technology.
3.4.2   Key Uncertainties in Scenario Development
        The scenarios developed in this section are based on highly
speculative future conditions.  Thus, these scenarios only serve to
bracket possible future energy conditions, so that potential environmental
impacts associated with these energy conditions can be assessed.
        Coal
        Although these are potential environmental problems when recovering
and using large quantities of coal, the trend toward increased coal use is
expected to continue.  This trend is being accelerated by Federal
legislation such as the Energy Supply and Environmental Coordination Act
(ESECA) which was passed in 1974 following the OPEC oil embargo.  This
legislation was designed to reduce our dependence on foreign oil through
expanded use of abundant coal reserves.  ESECA was amended in 1975  by the
Energy  Policy and Conservation Act (EPCA) which gave DOE authority  to
order utilities and other major fuel burning installations (MFBIs)  to
include a capability for coal firing in new plants.  MFBIs, defined as
sources with at least 29 MW heat input from a single combustion unit,
essentially are forced to burn coal unless this action poses a
                                    3-34

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"significant risk" to public  health  or significantly impairs the
reliability of service.
       The growth in coal  consumption, however,  is predicated on numerous
contingencies in fuel supply  and  energy/environmental  technology.   One
example is the projected cost and reliability of flue  gas  desulfurization
(FGD) systems.  Current SOX regulations  have  severely  limited the  use of
most Eastern coal — about 35 percent  of our  coal  resources.   Thus,  if FGD
systems are successful, it will mean less use of low sulfur  Western  coals
by Eastern utilities.
       However, if FDG systems prove unfavorable for any number  of
reasons, existing rail and barge  systems may  not be  able to  handle the
large increase in low sulfur  Western coal  that must  be transported to
Eastern users.  In addition,  the  technical  and economic feasibility  of
coal conversion is still uncertain.   Although a  number of  coal conversion
techniques are nearing the demonstration stage,  the  potential  reduction in
conversion efficiency and  associated increases in electricity costs  are
major concerns.
       Oil
       Changes in import prices and  supply are major areas of uncertainty
in projecting oil consumption.  In addition,  the development  of  Outer
Continental Shelf oil and Alaska  oil  will  have regional effects  on
supply.  Also, since domestic supplies of petroleum  are limited, means are
being sought to reduce consumption of  liquid  fuels while increasing  their
synthesis from other sources.   However,  the technical  and  economic
feasibility of several of  these processes  has not been demonstrated.
                                     3-35

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       Natural  Gas
       Domestic production of natural gas is declining rapidly.  A
proposed pipeline to deliver gas from Alaska in the mid-eighties will
increase production temporarily.  However, production will probably
decline rapidly after this source is exhausted unless recovery and
extensive offshore development is pursued.  Unfortunately, these
developments are not considered to be economical by the industry at
today's regulated prices.  However, if price controls on interstate
natural gas are eliminated, there may be incentive for further development
and gas production.  In addition to the uncertainty concerning
deregulation, technology for development of alternative synthetic gas is
questionable.  This will affect the supply of gas, since the shortfall in
gas supplies in the 1980's will have to be made up by synthetic gas,
primarily from coal.
       Alternate Energy Sources
       There are large uncertainties in the development of alternate
energy sources.  Oil shale presents major developmental, environmental and
financial problems.  Production of oil from oil shale is minimal  and
problems such as restoring land scarred by mining, disposing of enormous
amounts of oil  shale refuse, and providing for large amounts of water
required for refineries are serious developmental  problems.  Hydroelectric
sources generate some of the cheapest electricity in the United States —
however, hydroelectric applications are severely limited by geography.
Geothermal sources are also geographically limited and face uncertain
technical development.  Both thermal and photoelectric solar conversion
are not economical at present for central power generation.  Their use is
highly dependent on the future cost and availability of alternate fuels.
                                    3-36

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3.5    EQUIPMENT SCENARIOS
       This subsection describes  the methods  used  to  divide  total
projected energy use into application  sectors  and  into  individual
equipment types within each sector.  This  discussion  is followed by
summary tables of energy consumption by  sector for the reference scenarios
in 1985 and 2000.
3.5.1  Stationary Source Type
       Projected increases in energy consumption for  specific equipment
types were obtained primarily from projections by  trade organizations and
government agencies.  When these  projections were  not available,
historical energy consumption or  projected new plant  capacities were
extrapolated to the year 1985 or  2000.   Clearly, the  projected increases
in energy consumption are uncertain — sudden changes in demand or
consumption patterns, or economic factors  such as  price controls and
availability of raw materials, could alter them.   However, every attempt
was made to cross check the various projections to develop results as
accurately as possible.  In addition,  by looking at several  scenarios the
most likely changes in energy growth are considered and the  range of
equipment projection uncertainties are bracketed.
3.5.2  Equipment Attrition Rates
       Estimates of equipment attrition  are used to determine the rate at
which 1974 energy consumption is  replaced  by new equipment,  since new
equipment must comply with new source  performance  controls.  Two
approaches were used here.  The first  approach was to relate the number of
projected plant closings to 1974  plant capacity levels.  When sufficient
data were not available to generate these  estimates,  a second method,
based on known equipment lifetimes, was  used.  With this method, equipment
                                    3-37

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lifetimes were directly converted to attrition rates.  For example,  if  a
utility boiler has an estimated 50 year economic life, the attrition  rate
was assumed to be 2 percent per year.  For the most part, attrition rates
for each sector were based on limited historical data, so engineering
judgement was required to apportion the attrition rates among specific
equipment types.
3.5.3  Summary
       Energy projections by specific equipment/fuel types were generated
for 1985 and 2000 for five energy scenarios.  The resulting projections
are carried through the emission projections, discussed in Section 4, and
the Section 5 evaluation of pollution potential.  Summaries of energy
consumption in the reference scenarios  are given in Tables 3-11 through
3-14.   Appendix 8 of Volume II gives detailed energy usage by specific
equipment type for these scenarios.
                                    3-38

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       TABLE 3-11.   1985.STATIONARY SOURCE FUEL CONSUMPTION:
                    REFERENCE CASE -- HIGH NUCLEAR (EJ)
Equipment
Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces
and Miscellaneous
Combustion
Gas Turbines
Reciprocating
1C Engines
Total
Coal
19.278
1.967
— •
—
—
21.245
Oil
2.775
7.937
2.898
0.968
0.436C
15.014
Gas
3.265
6.653a
4.748
1.194
0.457d
16.317
Total
Fuel
25.318
16.557
7.646
2.162
0.893
52.576
 Includes process gas
 This sector includes steam and hot water units
Includes gasoline and oil portion of dual fuel
dlncludes natural gas portion of dual fuel
                                 3-39

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       TA3LE 3-12.   2000 STATIONARY SOURCE FUEL CONSUMPTION:
                    REFERENCE CASE -- HIGH NUCLEAR (EJ)
Equipment
Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces
and Miscellaneous
Combustion
Gas Turbines
Reciprocating
1C Engines
Total
Coal
24.398
2.763
— -
--
__
27.161
Oil
4.339
8.802
2.800
1.752
0.472C
18.165
Gas
_„
5.949a
6.634
1.390
0.240d
15.213
Total
Fuel
28.737
18.514
9.434
3.142
0.712
60.539
 Includes  process  gas
 This  sector  includes  steam and  hot  water units
'Includes  gasoline and oil  portion of dual  fuel
 Includes  natural  gas  portion  of dual fuel
                               3-40

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      TABLE 3-13.   1985  STATIONARY SOURCE FUEL CONSUMPTION-
                    REFERENCE CASE -- LOW NUCLEAR (EJ)
Equipment
Sector
Utility Boilers
Packaged Boilersb
Warm Air Furnaces
and Miscellaneous
Combustion
Gas Turbines
Reciprocating
1C Engines
Total
Coal
33.737
3.442
— —
—
—
37.179
Oil
2.775
7.937
2.898
0.968
0.436C
15.014
Gas
3.265
6.653a
4.748
1.194
0.457d
16.317
Total
Fuel
39.777
18.032
7.646
2.162
0.893
68.510
Includes  process gas
3This  sector includes steam and hot water units
"Includes  gasoline and oil  portion of dual fuel
 Includes  natural gas portion of dual fuel
                                3-41

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       TABLE  3-14.   2000 STATIONARY SOURCE FUEL CONSUMPTION:
                    REFERENCE CASE -- LOW NUCLEAR (EJ)
Equipment
Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces
and Miscellaneous
Combustion
Gas Turbines
Reciprocating
1C Engines
Total
Coal
42.697
4.835
— —
—
—
47.532
Oil
4.339
8.802
2.800
1.752
0.472C
18.165
Gas
—
6.949a
6.634
1.390
0.240d
15.213
Total
Fuel
47.036
20.586
9.434
3.142
0.712
80.910
 Includes  process  gas

}This  sector  includes  steam  and  hot  water  units
*
'Includes  gasoline and oil portion of  dual  fuel

 Includes  natural  gas  portion  of dual  fuel
                               3-42

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                          REFERENCES  FOR  SECTION 3
3-1.   Mezey, E. J., et al.,  "Fuel  Contaminants,  Volume  1,  Chemistry  "
       EPA-600/2-76-177a, NTIS-PB 256  020/AS,  Battelle-Columbus
       Laboratories, July 1976.

3-2.   Ctvrtnicek, T., "Evaluation  of  Low  Sulfur  Western  Coal
       Characteristics, Utilization, and Combustion  Experience,"
       EPA-650/2-75-046, NTIS-PB 243 911/AS, May  1975.

3-3.   "Coal-Fired Power Plant Trace Element Study — A  Three-Station
       Comparison," Radian Corporation, EPA Region VIII,  September 1975.

3-4.   Ruch, R. R., et al.,  "Occurrence and Distribution  of Potentially
       Volatile Trace Elements in Coal," EPA-650/2-74-054,  NTIS-PB 238
       091/AS.

3-5.   Magee, E. M., et al.,  "Potential Pollutants in Fossil Fuels,"
       EPA-R2-73-249, NTIS-PB 225 039/7AS,  June 1973.

3-6.   Vitez, B., "Trace Elements in Flue  Gases and  Air Quality Criteria,"
       Vol. 80, No. 1, Power  Engineering,  January 1976.

3-7.   FPC News, Vol. 8, No.  13, March 28,  1975.

3-8.   Dupree, W. G., and Corsentino,  J. S., "Energy Through the Year 2000
       (Revised)," U.S. Bureau of Mines, December 1975.

3-9.   FPC News, Vol. 8, No.  23, June  6, 1975.

3-10.  Surprenant, N., et al., "Preliminary Emissions Assessment of
       Conventional Stationary Combustion  Systems, Volume II,"
       EPA-600/2-76-046b, NTIS-PB 252  175/AS,  GCA Corporation, March 1976.

3-11.  Ctvrtnicek, T. E., "Applicability of NO Combustion  Modifications
       to Cyclone Boilers (Furnaces)," EPA-600/7-77/006,  NTIS-PB 263
       960/7BE, Monsanto Research Corporation, January 1977.

3-12.  "Standard Support and  Environmental  Impact Statement for Standards
       of Performance:  Lignite-Fired  Steam Generators,"  (Final Draft),
       A. D. Little, Incorporated,  EPA, March  1975.

3-13.  Smith, D. W., et al.,  "Electric Utilities  and Equipment
       Manufacturers' Factors in Acceptance of Advanced  Energy," A. D.
       Little, Incorporated,  ADL-77771, September 1975.

3-14.  Putnam, A. A., et al., "Evaluation  of National Boiler Inventory,"
       Battelle-Columbus Laboratories, EPA-600/2-75-067,  NTIS-PB 248
       100/AS, October 1975.

3-15.  "Minerals Yearbook 1973 — Metals,  Minerals,  and  Fuels,  Volume I,"
       U.S. Bureau of Mines.
                                     3-43

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3-16.  Power. Plant Design Issues, 1971 through 1976.

3-17.  FPC News, Vol. 9, No. 3, January 16, 1976.

3-18.  Locklin, D. U. et al., "Design Trends and Operating  Problems  in
       Combustion Modification of Industrial Boilers,"  EPA-650/2-74-032,
       NTIS-PB 235 712/AS, Battelie-Columbus Laboratories,  April  1975.

3-19.  "Current Industrial Reports, Steel Power Boilers," 1968  through
       1975, U.S. Department of Commerce, Bureau of the Census.

3-20.  Hopper, T. G., et al., "Impact of New Source Performance Standards
       of 1985 National Emissions from Stationary Sources,"  Volume 1,
       Final Report, The Research Corporation of New England, October 1975.

3-21.  "Statistical Abstract of the United States 1975," (86th Annual
       Edition), U.S. Department of Commerce, Bureau of the  Census,  1975.

3-22.  "Standards Support and Environmental Impact Statement, Volume I:
       Proposed Standards of Performance of Stationary Open  Turbines,"
       EPA-450/2-77-017a, September 1977.

3-23.  "Gas Turbine Electric Plant Construction Cost and Annual Production
       Expenses, First Annual Publication — 1972," FPC S-240, Federal
       Power Commission, 1972.

3-24.  "1975 Sawyer's Gas Turbine Catalog," Gas Turbine Publications,
       Incorporated, Stamford, Connecticut, 1975.

3-25.  "Gas Turbines in U.S. Electrical Utilities," Gas Turbine
       International, March through June 1976.

3-26.  Offen, G. R., et al., "Standard Support Document and  Environmental
       Impact Statement for Reciprocating Internal Combustion Engines,"
       Aerotherm Project 7152, Acurex Corporation, November  1975.

3-27.  Goldish, J. et al., "Systems Study of Conventional Combustion
       Sources in the Iron and Steel Industry," EPA-R2-73-192, NTIS-PB 226
       294/AS, April 1973.

3-28.  Ketels, P.A., et al., "A Survey of Emissions Control  and Combustion
       Equipment Data in Industrial Process Heating," Institute of Gas
       Technology, Final Report 8949, October 1976.

3-29.  Klett, M. G., and Galeski, J. B., "Flare Systems Study," Lockheed
       Missiles and Space Co., Inc., EPA-600/2-76-079, NTIS-PB 251 664/AS
       March 1976.

3-30.  Hunter, S. C., "Application of Combustion Modifications to
       Industrial Combustion Equipment," Proceedings of the  Second
       Stationary Source Combustion Symposium Volume III, Stationary
       Engine, Industrial Process Combustion Systems, and Advanced
       Processes, EPA-600/7-77-073c, NTIS-PB 271 757/7BE, July 1977.
                                    3-44

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3-31.  "Consumption of  Fuel  by Electric Utilities for Production  of
       Electric Energy  by  State,  Kind of Fuel and Type of Prime Mover
       Year of 1974," FPC  News Release No.  22686, October 20,  1976.

3-32.  Crump., L. H.f "Fuels and  Energy Data:  United States by States and
       Census Divisions, 1974," Bureau of Mines Information Circular 8739,
       •* •/ * / •

3-33.  "1973 National Emissions Data Systems (NEDS)  Fuel  Use Report,"
       National Air Data Branch,  U.S. Environmental  Protection Aqencv
       EPA-450/2-76-004, NTIS-PB  253 908/8BE, April  1976.

3-34.  Thompson, 0. F., et al., "Survey of Domestic, Commercial,  and
       Industrial Heating  Equipment and Fuel Usage," Final Report, EPA
       Contract 68-02-0241,  August 1972.

3-35.  "Installed Capacity of Utility Generating Plants by States and Type
       (December 31,  1975  — Preliminary)," Electrical World V. 185(6):
       59, March 15,  1976

3-36.  U.S. Bureau of Mines, "Mineral Yearbook 1974," 1976.

3-37.  Offen, 6. R.,  et al., "Standard Support and Environmental  Impact
       Statement for  Reciprocating Internal Combustion Engines,"  Acurex
       Report TR-78-99, Acurex Corporation, March 1978.

3-38.  Urban, Charles M.,  and Springer, K.  J., "Study of Exhaust  Emissions
       from Natural Gas Pipeline  Compressor Engines," prepared for the
       American Gas Association,  February 1975.

3-39.  U.S. Geological  Survey and Congressional Research Service,
       "National Energy Transportation, Vol. I — Current Systems and
       Movements," prepared for the Senate Committees on Energy and
       Natural Resources and Commerce, Science and Transportation, Senate
       Publication Number  95-15,  May 1977.

3-40.  American Gas Association,  "1974 Gas Facts," 1975.

3-41.  "Production of Electric Energy by Industrial  Establishments,"
       Electric Power Statistics, monthly issues for 1974.

3-42.  Reznik, R. B., "Source Assessment:  Flat Glass Manufacturing
       Plants," Monsanto Research Corporation, EPA-600/2-76-032b,
       March 1976.

3-43.  Katari, V. S., and  Gerstle, R. W., "Industrial Process  Profiles  for
       Environmental  Use:   Chapter 24.  The Iron and Steel  Industry,"
       Radian, EPA-600/2-77-023x, NTIS-PB 266 226/OBE, February 1977.

3-44.  "Development Document for  Effluent Limitations Guidelines  and New
       Source Performance  Standards for the Petroleum Refining Point
       Source Category," Office of Water and Hazardous Materials, U. S.
       Environmental  Protection Agency, April 1974.
                                     3-45

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3-45.  "The Potential for Energy Conservation in Nine Selected  Industries
       — The Data Base," Gordian Associates, Inc., FEA/D-74/143,
       June 1974.

3-46.  "Project Independence, Project Independence Report," Federal  Energy
       Administration, November 1974.

3-47.  "Fuel and Energy Price Forecasts, Final Report, Volume II --  Data
       Base," Stanford Research Institute, EPRI EA-433, February 1977.

3-48.  "Fuel and Energy Price Forecasts, Final Report, Volume I --
       Report," Foster Associates, Inc., EPRI EA-411, April 1977.

3-49.  "1976 National Energy Outlook," Federal Energy Administration,
       FEA/N/75/713, February 1976.

3-50.  "A National Plan for Energy Research, Development & Demonstration:
       Creating Energy Choices for the Future," ERDA-48, Volume 2 of 2.

3-51.  "The National Energy Plan," Executive Office of the President,
       Energy Policy and Planning, 1977.

3-52.  "United States Energy Through the Year 2000 (Revised)," Bureau of
       Mines, 1975.

3-53.  "Energy Perspectives 2," U.S. Department of the Interior, 1976.

3-54.  "Energy Statistics," U.S. Senate, Finance Committee, 94:1,
       July 1975.

3-55.  Chapman, L. D., et al., "Electricity Demand:  Project Independence
       and the Clean Air Act," Oak Ridge National Laboratory,
       ORNL-NSF-EP89, November 1975.

3-56.  "Proceedings of the Workshop on Analysis of 1974 and 1975 Power
       Growth," Electric Power Research Institute, EPRI EA-318-SR,
       December 1976.

3-57.  "The National Power Survey Task Force Report:  Energy Conversion
       Research," Federal Power Commission, June 1974.

3-58.  Benedict, M., "U.S. Energy:  The Plan That Can Work," from
       Technology Review, May 1976.

3-59.  "Resources for the Future — Annual Report for the Year Ending
       September 30, 1976," Resources for the Future.

3-60.  "An Integrated Technology Assessment of Electric Utility Energy
       Systems, First Year Report (Draft), Volume 1:  The Assessment,"
       Teknekron, Inc.

3-61.  Bomke, E. H., "A Forecast of Power Developments, 1975-2000."  Power
       Engineering. ASME 75-Pwr-5, 1975.
                                    3-46

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3-62.  "The Potential for Energy Conservation —Substitution for Scarce
       Fuels, A Staff Study," Executive Office of the President, Office of
       Emergency Preparedness, January 1973.

3-63.  Wright, R. R., "The Outlook for Petroleum Power Plant Fuels,"
       American Petroleum Institute, ASME 76-1PC-PWR-6, 1976.

3-64.  "Status:  Significant U.S. Power Plants in Planning or
       Construction," Presential Task Force on Power Plant Acceleration,"
       Federal Energy Administration, July 1976.

3-65.  Gordon, R. L., "Historical Trends in Coal Utilization and Supply,"
       Pennsylvania  State University, Bureau of Mines, OFR 121-76.
                                     3-47

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                                  SECTION 4



                      MULTIMEDIA EMISSIONS INVENTORIES







       This section presents  national  and regional  multimedia emissions



inventories for the stationary NO  sources and fuels identified  in
                                  A


Section 2.  The national  inventory  considers  NO ,  SO  and  particulate
                                                />    /\


controls applied to new  and existing utility  boilers.  Projected  national



inventories (1985 and 2000) have been  included and  reflect the emissions



reductions due to anticipated NSPS  regulations for  select  stationary



sources and the reference  energy scenarios given in Section 3.4.1.



Regional NO  emissions inventories  are presented for 1974  for
           /\


uncontrolled stationary  sources.



       Multimedia pollutants  inventoried include the primary criteria



pollutants (NO , SO , CO,  HC,  and particulates), sulfates, POMs,  trace
              J\    /\


metals, and liquid and solid  effluent  streams.  Insufficient data exist to



quantify emissions for other  stationary source pollutants.  The  1974



national emissions inventory  for  NO was extended  to include sources of
                                    /\


NO  other than stationary  combustion sources  (mobile, noncombustion,
  j\


fugitive) in order to compare the relative contributions  of all  NOX




sources.



       Results presented  here are only for criteria pollutants;  results



for sulfates, POMs, trace  metals, and  liquid  and solid effluent  streams



are given in Appendix D  of Volume II.
                                     4-1

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       ihe inventories in this section form  a basis  for  assessing
stationary source pollution potential in the Section 5 source analysis
modeling.  Data gaps identified here highlight  areas where  further testing
is needed.
       The emissions inventories were generated through  the following
sequence:
       •   Compile multimedia emission factor data (Section 4.1)
           —  Base fuel derived pollutant emission  factors on  trace
               composition of fuels
           ~  Base combustion derived pollutant emission factors on unit
               fuel consumption for specific equipment designs
       •   Inventory degree of implementation of NO  , SO ,  and
                                                   /\    A
           particulate controls (Section 4.2)
       •   Develop future environmental scenarios (Section  4.3)
       •   Generate national emissions inventories for 1974 (Section 4.4)
       t   Project national emissions inventories for 1985,  2000
           (Section 4.5)
       •   Generate regional inventories (Section 4.6)
4.1    EMISSION FACTORS
       This section presents uncontrolled emission factors  for  significant
stationary sources of N0x.  Emission factors were compiled  for  the
following fuels:  lignite, bituminous, and anthracite coal;  distillate and
residual oil, and natural gas.  Since emissions data from process gas
utilization are lacking, emission factors for natural gas were  used  for
this fuel.  Whenever possible, emission factors are  expressed  in  terms of
fuel inputs, i.e., nanograms N02 per Joule heat input.   For the
                                    4-2

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industrial process  heating  sector,  emission factors are expressed as a
function of product output.
       Emissions of criteria pollutants, N0x, SOX, HC, CO, and total
particulate have been  extensively tested.  The quality of the emission
factors for these pollutants is generally high.  Unfortunately, the
quality of the measurements  for other species — POMs, sulfates,  and trace
elements — varies  widely.   Tables  of emission factors for criteria
pollutants have been  included in this section, while those for ROMs.,
sulfates and trace  metals  are given in Appendix D of Volume II.
       The emission factors  were obtained from AP-42 (Reference 4-1) and
its supplements, from  a survey of existing literature, and from
preliminary results of ongoing test programs.  Whenever possible, AP-42
and its supplements have been used  as sources, since they usually reflect
the most recent test  results.  Where emission factors are not available
for specific design types,  emission factors have been estimated from test
results on similar  equipment.  Where a range of emission factors is
available, an  average  value  has been assigned.  Each of the following
subsections includes  a discussion of the data sources for the emission
factors, along with the rationale for their selection and their relation
to AP-42 emission factors.
       All emission factors  represent uncontrolled operating conditions
 (without pollution  control  devices) for the major equipment types outlined
 in Section 2,  except  where  noted.
4.1.1  Utility and  Large Industrial Boilers
       Table 4-1 gives uncontrolled emission factors for the criteria
pollutants from utility boilers.  NO  emission factors for these boilers
                                     /\
were  largely obtained  from  AP-42 supplements (References 4-2,  4-3).   These
                                     4-3

-------
TABLE 4-1.   UTILITY BOILER CRITERIA  POLLUTANT EMISSION  FACTORS (ng/J)
Equipment Type
Utility Boilers
Tangential
Anthracite
Bituminous and Sub-bituminous
Lignite
Residual Oil
Distillate 011
Natural Gas
Single Mall Fired
Anthracite
Bituminous and Sub-bituminous
Lignite
Residual 011
Distillate Oil
Natural Gas
Opposed Wall and Turbo Furnace
Anthracite
Bituminous and Sub-bituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Cyclone
Anthracite
Bituminous and Sub-bituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Vertical and Stoker
Anthracite
Bituminous and Sub-bituminous
Lignite
N0x


275
275
245
153
153
129

322
322
353
322
322
301

322
322
353
322
322
301

559
559
374
219
219
241

269
269
269
•»*'


585S
602S
808S
482S
434S
0.3

585S
602S
808S
482S
434S
0.3

585S
602S
808S
482S
434S
0.3

585S
679S
808S
492S
6.0
0.3

585S
679S
808S
Parti culatesa>b


261 A
195A
175A
30. 5S + 8.6 (30.5)
6.0
2.2,- 6.5 (4.3)

261 A
186A
175A
30. 5S + 8.6 (30.5)
6.0
2.2 - 6.5 (4.3)

261 A
186A
175A
30.5S + 8.6 (30.5)
6.0
2.2 - 6.5 (4.3)

35. 7A
35. 7A
174. 5A
30. 5S + 8.6 (30.5)
6.0
2.25 - 6.4 (4.3)
4
30. 5A
233A
188A
CO


15.5
11.2
27.1
8.6
15.5
7.3

15.5
21.9
27.1
13.3
15.5
11.6

15.5
8.6
27.1
12.5
15.5
10.7

15.5
18.1
27.1
15.5
15.5
7.3

92.0
35.7
53.7
HC


0.43
0.86
8.2
0.86
6.0
0.86

0.43
0.86
8.2
0.86
6.0
0.86

0.43
0.86
8.2
0.86
6.0
0.86

6.45
6.45
8.17
6.02
6.02
6.02

3.01
5.59
8.17
                                                                                     LO
                                                                                     I
aS represents the percent sulfur in
 Numbers in parentheses are  average
the  fuel, A represents the percent ash  in the fuel.
values.
                                     4-4

-------
values agree with measurements  from utility boiler field testing



(References 4-4 through  4-11).   However,  values for cyclone furnaces and



lignite-fired boilers were  obtained from more recent studies (References



4-12, 4-13).



       Emission factors  for S0x,  particulate, HC,  and CO were gathered



from the available  literature for tangential, single wall,  and opposed



wall bituminous coal-fired  furnaces (References 4-4 through 4-11).   Since



there are very few  available data for vertical  fired boilers, AP-42



emission factors  (Reference 4-1)  were used.   Emission factors for  HC and



CO from tangential,  single  wall,  and opposed wall  residual  oil-fired



boilers were obtained from  References 4-4 through  4-11.   These numbers  are



considerably lower  than  AP-42 values.  Particulate and SO  emission
                                                          A


factors from AP-42  used  here are  in excellent agreement  with recent  field



test results (References 4-2, 4-3).   AP-42 and  its supplements were  also



used as a source  of emission factors for distillate oil.



       POM values for utility boilers were obtained from References  4-11



and 4-14.  Additional data  were  sought both  in  the literature and  by



contacting principal EPA investigators (References 4-15  through 4-19).   No



additional POM data from stationary combustion  sources considered  in this



report have been  published.  However, a number  of  field  test programs are



underway or have  recently been concluded.  These programs include



measurements of POM emissions from coal- and oil-fired steam generators,



but the data have not yet been  released pending sample analysis and  review



by EPA project officers.  Since  values from available data  for coal-fired



powerplants vary  by two  or  three  orders of magnitude -.- depending  upon  the



equipment type — the highest value was conservatively suggested for use



in the inventories.
                                     4-5

-------
       Sulfate emission factors for coal-fired  utility  boilers  wer«=


determined from field zesting (Reference 4-20).


       Emission factors for trace metals for this  sector  come from


References 4-21 through 4-28.  There is fair agreement  on  the partitioning


and enrichment properties of specific trace elements  presented  in these


studies; however, the agreement is not sufficient  to  warrant  the  use of


any more than average trace metal concentrations  in the fuel.   Thus,  these


emission factors are estimates rather than exact  values,  and  must be


applied carefully-


       Solid and liquid emission values for utility boilers come  from


References 4-22, 4-29, and 4-30.  These values  are only of fair quality


since control applications and efficiencies vary  widely for different


utility boilers.


4.1.2  Packaged Boilers


       Packaged boilers have been grouped into  two categories  according to


capacity:  boilers with thermal input capacities  between 29 MW  and 73 MW


(100 to 250 MBtu/hr), and those with less than  29 MW  thermal  input


capacity.  Table 4-2 presents uncontrolled emission factors for the


criteria pollutants for these two classes of boilers.   The emission


factors come from field testing of industrial boilers (References 4-31  and


4-32) as well as AP-42 and its supplements (References  4-1 through 4-3).


       The firing and emission characteristics  of  the large industrial


boilers (>73 MW heat input) are similar to those  of utility boilers.  CO


and HC emission factors used here for bituminous  coal,  oil, and gas were


obtained from field tests (References 4-31 and  4-33)  and  are  considerably


lower than those supplied by AP-42.  Emission factors for  NO
                                                            x'

particulates, and SO  for large packaged boilers  came from both field
                                    4-6

-------
TABLE 4-2.   PACKAGED BOILER CRITERIA POLLUTANT EMISSION FACTORS  (ng/J)
Equipment Type
Wall Fired Water-tubes
29 MW to 73 MW (input)
Anthracite
Bituminous and Lignite
Residua] Oil
Distillate Oil
Natural Gas
Process Gas
Stoker Watertubes
29 MW to 73 MW (input)
Anthraci te
Bituminous and Lignite
Single Burner Watertubes
<29 MW (input)
Residual Oil
Distillate Oil
Natural Gas
Process Gas
' Scotch Firetubes
Residual Oil
Distillate Oil
Natural Gas
Process Gas
Firebox Firetubes
Residual Oil
Distillate Oil
Natural Gas
Process Gas
HRT Firetubes
Residual Oil
Distillate Oil
Natural Gas
Cast Iron Boilers
Residual Oil
Distillate Oil
Natural Gas
Stoker Watertubes
<29 MW (input)
Anthracite
Bituminous and Lignite
N0x


322
322
322
322
301
301


269
269


184
67.5
98.9
98.9

184
67.5
98.9
98.9

184
67.5
98.9
98.9

184
67.5
98.9

184
67.5
51.6


179
179
soxa


585S
559S
408S
434S
0.3
-


584. 7S
756. 6S


482S
434S
3.4
-

4825
434S
0.3
-

482S
434S
0.3
-

482S
436S
0.3

482S
434S
0.3


585S
672S
Parti culates3


261A
186A
30. 5S + 8.6
7.74
1.72
—


30. 5A
233A


30. 5S + 8.6
8.2
3.4
-

30. 5S + 8.6
7.3
2.6
-

30. 5S + 8.6
7.3
2.6
-

83
3.9
2.6

.30.55 + 8.6
3.7
2.6


31 A
232A
CO


0.6
0.04
3.9
-
9.0
—


92
25


3.4
1.6
8.6
-

3.4
1.6
8.6
-

3.4
1.6
8.6
—

3.4
1.7
8.6

3.4
1.6
8.6


92
21
HC


0.43
2.2
3.0
3.0
3.9
—


3.0
4.3


0.86
0.43
• 1.7
-

0.86
0.43
1.7
-

0.86
0.43
1.7
—

0.9
0.4
1!.7

0.86
0.43
1.7


3.0
18
3
in
T
I—







































     aS represents sulfur of fuel, A represents percent ash of the fuel.
                                    4-7

-------
                         TA3LE 4-2.   Concluded
Equipment Type
Stoker Firetubes
Anthracite
Bituminous and Lignite
Residential Steam Units
Anthracite
Bituminous and Lignite
Residual Oil
Distillate Oil
Natural Gas
N0x

179
179

179.3
179.3
162
55
34.4
",'

585S
672S

585S
679S
481.5
434S
0.26
Particulates3

31A
232A

307
358.2
83
7.7
4.3
CO

92
21

138
1612.5
15.48
30.5
8.6
HC

3.0
18

307
358.2
3.01
4.73
3.4
                                                                     CO
                                                                     O
                                                                     in
      aS represents sulfur of fuel, A represents percent ash of the fuel.
testing (References 4-31 and 4-33) and AP-42  and  its  supplements
(References 4-1 through 4-3).  There  is  excellent correspondence between
these two data sources.  Since there  has  been  very little field testing of
boilers firing anthracite coal, AP-42 emission factors for this fuel could
not be cross-checked with other sources.
       Emission factors for packaged  boilers  with less than 2Q MW heat
input capacity came largely from field testing of industrial and
commercial boilers, and space heating units at baseline operating
conditions (References 4-31 through 4-34).  The data  were averaged where
baseline data were available for more than one unit  of a specific design
type.  When test data were not available  for  a specific equipment/fuel
combination, AP-42 values or test data from similar  equipment were used.
       In general, these is excellent correspondence  between AP-42
supplements (References 4-2, 4-3) and field testing  (References 4-31
through 4-34) for N0x, SC>x, and particulate emissions from packaged
                                    4-8

-------
boilers.  The only  area  of significant disagreement is the emission
factors for small packaged oil-fired boilers, where values from field
testing (References  4-31 through 4-34) are considerably lower than values
from the AP-42 supplement (Reference 4-3).  In general, small watertube,
scotch firetube, firebox firetube, HRT firetube, and cast iron boilers
fired by single burners  have similar combustion characteristics and thus,
similar emission factors.
       POM emission  factors for packaged boilers came from recent field
testing (References  4-35 through 4-37) and AP-33 (Reference 4-14).  Again,
there are differences  of several orders of magnitude between AP-33 values
and the results of  recent field tests.  Because the data available are
sparse and vary widely,  the highest values have been given.  In addition,
it was assumed that  scotch firetubes, HRT firetubes and firebox firetubes
have the same POM emission characteristics, and that shell boilers and
cast iron boilers also have similar POM emission characteristics.  The
data show a trend toward larger POM emissions from smaller units.  This  is
reasonable since smaller boilers usually are less carefully regulated than
large ones, and have less efficient firing and operation.
       Field testing data for sulfate emissions and trace elements from
packaged boilers also  are sparse.   Some field tests have been performed
(Reference 4-32), but  few data are quantified.  It has been assumed that
trace element emission factors are similar for large packaged and utility
boilers since they  usually have similar operating characteristics.
However, this assumption does not hold for small packaged boilers.  In
addition, care must  be exercised in using trace element factors,  since
they may vary by two or  more orders of magnitude depending on the fuel.
                                     4-9

-------
       Liquid and solid emission factors were obtained  from References
4-22 and 4-38.  Almost all of the solid and  liquid  effluents are generated
by coal-burning boilers.  Since the  implementation  and  efficiency of
control varies widely within this sector, these  emission  factors are only
of fair quality.
4.1.3  Warm Air Furnaces
       Table 4-3 displays uncontrolled emission  factors for the criteria
pollutants from warm air furnaces.   NO  emission  factors  come from field
                                      A
tests  (Reference 4-34) and from an AP-42 supplement (Reference 4-3).
Emission factors for the remaining criteria  pollutants  come from field
testing (References 4-34, 4-39 and 4-40), studies (References 4-41, and
4-42), and AP-42 supplements (References 4-2, and 4-3).   In general, the
agreement between these sources of data is excellent.   Since values from
AP-42  supplements accurately represent the emission characteristics of
warm air furnaces, most of the emission factors for warm  air furnaces come
from these supplements.
       Little testing has been done  on POMs  emitted from  warm air
furnaces, particularly during the on-off cycle transient  which is expected
to promote POM formation.  The little data available are  mainly from AP-33
(Reference 4-14).  Because supporting data are lacking  and  most POM tests
have been inconsistent, the values in Appendix D  are only an
order-of-magnitude estimate of POM emissions.
       Sulfate emission factors from warm air furnaces  are  not yet
available.
       Trace element emission factors for warm air  furnaces cannot be
determined from the existing data.  The only significant  source should be
                                    4-10

-------
the small number of coal-fired units that are insignificant on  a  national

scale, but could present  localized pollution problems.

       The only solid  or  liquid effluent generated by this  equipment

sector is the bottom ash  from coal combustion.   An emission factor was

obtained from Reference 4-22.  Again, this effluent stream  is

insignificant nationally,  but could cause some  regional  problems.

4.1.4  Gas Turbines

       Emission factors for  gas turbines come from field studies

(References 4-43, 4-44, and  4-45)  and an AP-42  supplement (Reference 4-46),
     TABLE 4-3.  WARM AIR  FURNACE AND MISCELLANEOUS COMMERCIAL AND
                 RESIDENTIAL  COMBUSTION CRITERIA POLLUTANT
                 EMISSION  FACTORS (ng/J)
Equipment Type
Warm Air Central Furnace
Oil
Natural Gas
Warm Air Room Heaters
Oil
Natural Gas
Mi seel 1 aneous Combusti on
Natural Gas
N0x

61.0
34.4

61.0
34.4

34.4
SO/

434S
0.358

434S
0.258

0.258
Parti culatesc

7.7
2.2 - 6.5 (4.3)

7.7
2.2 - 6.5 (4.3)

2.2 - 6.5 (4.3)
CO

31
12

31
12

12
HC

4.7
3.4

4.7
3.4

3.4
aS represents  percent.sulfur in the fuel.

bAll  miscellaneous combustion fuels (wood, LPG, etc.) combined with
 natural  gas.

GNumbers  in parentheses denote average values.
                                     4-11

-------
TABLE 4-4.  GAS TURBINE CRITERIA POLLUTANT EMISSION FACTORS (ng/J)
Equipment Types
Gas Turbines
I >15 KM (output)
Natural Gas
Diesel oil
Gas Turbines
4 MM to 15 MU
(output)
Natural Gas
Diesel oil
Gas Turbines
<4 MM (output)
Natural Gas
Diesel oil
N0x
!
1
I
j
195
365

194
365

194
365
S0x

2.2
10.7

2.2
10.7

2.2
10.7
Part.

6.0
16.0

6.0
15.5

6.0
15.5
CO

49. Q
47.0

49.4
47.3

49.4
47.3
HC

8.6
8.6

8.2
9.9
'
8.2
9.9
                                4-12

-------
Table 4-4 gives uncontrolled emission factors for the criteria pollutants,
taken primarily from the  recent Gas Turbine Standard Support Document
(Reference 4-43).   Values from the AP-42 supplement for non-NO  criteria
                                                               X
pollutants are in  excellent agreement with values from field studies
(References 4-44 and 4-45).
       Emission factors for ROMs and sulfates from gas turbines  cannot be
determined at present since extensive field testing has not  been
conducted.  There  are no  liquid or solid effluents resulting from
combustion related  gas turbine operation.
4.1.5  Reciprocating 1C Engines
       The range of equipment design combinations for reciprocating 1C
engines is so varied that it is impractical to identify emission factors
for each equipment/fuel combination.  Consequently, reciprocating  1C
engines have been  categorized as either spark ignition or  compression
ignition engines in three capacity ranges.   Table 4-5 presents
uncontrolled emission factors for the criteria pollutants  for these
equipment types.
       NO  emission factors have been derived from values  presented in a
         J\
current 1C engine  study (Reference 4-47).   Non-NO  criteria  pollutant
                                                  /\
emission factors come from recent AP-42 supplements (References  4-2 and
4-46) and correspond closely with the results of field tests
(Reference 4-48).
       Data are insufficient to quantify emission factors  for ROMs,
sulfates, and trace elements from reciprocating 1C engines.   Trace element
concentrations will vary  by orders of magnitude — depending on the fuel
and the operating  characteristics of the reciprocating engine measured.
Because of these variations, it is impossible to determine specific
emission factors to span  this range of operating conditions.  There are no
                                     4-13

-------
 TABLE 4-5.  RECIPROCATING  1C ENGINES CRITERIA  POLLUTANT  EMISSION
             FACTORS  (ng/J)
Equipment Types '
Compression Ignition
>75 kW/cyl (output)
Distillate Oil
Dual Fuela
Spark Ignition
>75 kW/cyl (output
Natural Gas
CI 75 kW to
75 kW/cyl (output)
>1,000 rpm
Distillate Oil
SI 75 kW to
75 kW/cyl (output)
>1,000 rpm
Natural Gas
Gasoline
CI <75 kW (output)
2-4 cyl
Distillate Oil
SI <75 kW (output)
2-4 cyl
Gasoline
NO
A

1,741
1,023

1,552

1,741

1,552
1,195

1,677

774
S0x

95.9
—

0.22

95.9

0.22
16.3

95.9

16.8
Part.

103
—

—

103

—
19.8

95.9

19.8
CO

313
—

177

313

177
12,081

313

12,081:
HC

115
—

555

115

555
405

115

405
oil and gas
                                4-14

-------
liquid or solid effluents  resulting from combustion related 1C engine



operation.



4.1.6  Industrial  Process  Combustion



       Direct process  heat from fuel combustion has a wide range of



industrial applications  and is  produced by many different types  of



equipment.  In addition, process heat is generated in many industries  by  a



large number of small-scale processes which as a whole may have



significant impact  but are hard to quantify individually.  Nevertheless,



there are several  major  industrial pollution sources, and these  industries



are discussed here.  Uncontrolled emission factors for the criteria



pollutants, based  on product output, are presented in Table 4-6.  Refinery



process heating emission factors are presented in Table 4-7.



       Cement and  glass  industries which use kilns, furnaces,  and ovens to



heat raw materials, are  significant sources of NO .  Emission  factors
                                                  A


for NO  from these  processes primarily come from a recent study  of these
      A


industries (Reference  4-49).  Non-NO  criteria pollutant emission
                                     /\


factors have been  determined partially from AP-42 values (Reference 4-1).



Very few data are  presently available for sulfate, POM, and trace element



emissions from cement  kilns.  Sulfate emission factors come from Reference



4-50, although the  values  presented are questionable.  Solid emission



factors for the cement industry come from Reference 4-51.  These values



also are questionable  since total particulate loadings from the



particulate control device may include emissions from grinding,  dryers and



other processes, as Well as particulates from combustion.• Solid and



liquid effluents from  the  glass industry are insignificant, since natural
                                     4-15

-------
   TABLE 4-6.   INDUSTRIAL  PROCESS  COMBUSTION  CRITERIA POLLUTANT EMISSION

                FACTORS  (g/kg PRODUCT)
Process Types
Cement Kilns
Glass Melting Furnaces
Glass Annealing Lehrs
Coke Oven Underfire
Steel Sintering Lines
Open Hearth Furnaces
Brick & Cement Kilns
Catalytic Cracking
Refinery Flares
Iron & Steel Flares
N0x
1.30
3.68
0.69
0.07
0.52
0.62 oil
0.37 gas
0.25
0.208
b
S0x
5.09
2.12
NA
2.84
0.71
0.70
0.54
1.419
NIL
Part.
122
1.0
NA
37.7
10.0
6.0
65.0
0.699
NIL
CO
NA
NA
NA
NA
22.0
NA
0.1
39. 18
NIL
HC
NA
NA
NA
NA
NA
NA
0.04
0.63
0.43C
     Feed
 Production  is  not quantifiable.   Estimate of NO   is made  in  Section  3.2.6.
                                               J\

t

'g  HC/&  requiring capacity
                                    4-16

-------
    TABLE 4-7.  REFINERY PROCESS  HEATING CRITERIA  POLLUTANT  EMISSION

                FACTORS  (ng/J)
Heater Type
Natural Draft
Forced Draft
Fuel
Gas
Oila
Gas
Oild
NOX
70.1
154.8
110.5
184.5
S0x
860SC
627Sb
860SC
627S&
Part.
8.6
78.4
8.6
78.4
CO
NIL3
NIL
NIL
NIL
HC
12.9
13.1
12.9
13.1
    ^Assumed  fuel  oil  nitrogen content of 0.2 percent and a fuel

      nitrogen conversion to NO of 50 percent
           oil  sulfur content (weight percent)



     cRefinery gas sulfur content



     ^Negligible emissions
gas and low sulfur oil are the major fuels.  Coal is not used because it



has a high level of impurities.


       The iron and steel industry produces  large quantities of N0x



emissions from its ovens and furnaces.  Most of the emissions come from



coke oven underfiring, steel sintering machines, and open hearth


furnaces.  Emission factors for NQY for the  iron and steel industry have
                                  3\


been determined from Reference 4-52.  Other  criteria pollutant factors



come from References 4-52 and 4-53.   Solid effluents are negligible from



coke ovens, since coke ovens are  predominantly gas  fired and particulate



collectors are seldom installed.  An  emission  factor for liquid effluents
                                     4-17

-------
comes from a screening document for the  iron  and  steel  industry (Reference



4-54).  A solids emission factor for  steel  sintering  was  obtained  from



Reference 4-52.  The emission factors for open  hearth furnaces  were



obtained from Reference 4-54.



       The petroleum industry also produces NO  emissions from  refinery
                                              A


flares, fluid catalytic crackers and  process  heaters.   NO  emission
                                                          A


factors for refinery flares and catalytic crackers were obtained from a



recent study of process heating (Reference  4-49).  NO  emission factors
                                                      A


for  refinery process heaters were obtained  from a recent  study  of



combustion technology for controlling NO  from  petroleum  process heaters
                                         X


(Reference 4-55).  The values reported here are for both  natural draft and



forced draft refinery heaters firing  gas and  oil.  Emission  factors for



non-NO  criteria pollutants come from AP-42 (Reference  4-1)  and from
      A


emission studies (References 4-53 and 4-56).  Noncriteria emission  factors



are  not available.  Liquid and solid  effluents  are insignificant.



4.2    INVENTORY OF CONTROL IMPLEMENTATION



       Emissions from stationary combustion sources are highly  dependent



on the fuel type and the control equipment  used.  Emissions  of



particulates from large point sources are extensively controlled.   Since



NO   emissions are less extensively regulated, however,  there are few
  A


NO   controls applied to existing equipment.   The  effects  of  SO
  A                                                           X


controls on total emissions are also  insignificant.   This subsection



describes the degree of control which now exists  for  particulates,  SO
                                                                      A


and  NO .   The section 3 estimates of  stationary source  fuel  consumption
      A


are coupled with the emission factors presented in Section 4.1  and  the



control factors developed here to determine total emission loadings.



These emissions inventories are presented in  Section  4.4  for
                                    4-18

-------
controlled participate  and  SO  emissions and uncontrolled and controlled
                              A


NO  emissions for 1974.
  A.


       The incentive  for  control  development is caused by two separate



regulatory mechanisms,  the  Federal  Standards of Performance for New



Stationary Sources  (NSPS) and State Implementation Plans (SIPs).   These



regulations are  intended  to assist  in air quality maintenance and



attainment of future  air  quality  goals.



       The Clean Air  Act  of 1970  requires that EPA establish standards of



performance for  all major new stationary sources.  These standards must



set levels of control that  reflect  the degree of emission reduction for



stationary sources  that can be achieved  using Best Available Control



Technology (BACT) —  taking cost  into consideration.



       The major objectives of New  Source Performance Standards are to



mitigate air pollution  problems systematically and cost-effectively by



concentrating on new  rather than  existing sources.  The basis for this



approach is to maximize the opportunities for economic growth within  the



constraints of environmental goals  by requiring new sources to operate as



cleanly as possible.  It  also recognizes that retrofit controls are more



costly than incorporating controls  during the design phase.  Moreover, in



some cases, retrofit  controls cannot reflect the best technology because



of  incompatibilities  with existing  structures and operational requirements.



       The other regulations are  State Implementation Plans (SIPs).  The



primary responsibility  for  implementing SIPs lies with the states.  If



NSPS are not sufficient to  attain or to maintain National Ambient Air



Quality Standards (NAAQS)  in control regions, then additional emission



standards are set by  the  states through SIPs.
                                     4-19

-------
       The control factors developed here reflect the  use  of  these
mechanisms.  Although at present the impact of  NSPS  on nationwide emission
loadings is small, in future years NSPS regulations  should significantly
reduce total levels of mass emissions.
4.2.1  Particulate Control
       Centrifugal collectors and electrostatic precipitators  are the most
widely used particulate controls for stationary combustion sources.   Since
coal- and oil-fired boilers contribute approximately 98 percent  of utility
boiler particulate emissions, the controls on these  boilers are  of
paramount  importance.  Gas-fired boiler particulate  emissions  are
negligible by comparison and will not be considered  further in this
section.   Representative values for the percent of particulate controls  in
the utility and industrial sector and the impacts of these controls  on
total particulate emissions are presented below.
4.2.1.1  Utility and Large Industrial Boilers
       Several recent particulate studies (References  4-22, and  4-42)  have
provided information on the particulate controls installed on utility
boilers.  Table 4-8 shows the percent of particulates  collected  from
utility boilers.  Twelve percent of pulverized coal-fired  boilers  have no
collection devices, and approximately 35 percent of  oil-fired boilers  are
not controlled.
       Assuming representative efficiencies for control equipment  types,
it has been estimated that 75 percent of the particulates  generated  in
residual oil-fired boilers are not collected.  More  importantly,  35
percent cf the flyash formed in pulverized coal-fired  boilers, 25  percent
of the flyash in cyclone boilers and 50 percent of the flyash in  stokers
are also not collected.
                                    4-20

-------
4.2.1.2  Industrial Boilers
       A recent source assessment document  for  industrial  boilers
(Reference 4-56) was used to determine the  distribution  of controls for
pulverized coal-fired boilers, stokers, and residual  and distillate
oil-fired boilers.  Approximately 75 percent  of  small  industrial  stokers
(<29 MW input,  100 MBtu/hr) and 30 percent  of the  larger boilers  are not
controlled.   It is assumed that controls  for  small  pulverized coal
industrial boilers (<29 MW input) are not significant.   As shown  in Table
4-8, about 50 percent of particulate emissions from large  coal-fired
industrial boilers are collected.  However, for  smaller  units,  95 percent
of the particulates from residual oil-fired boilers and  85 percent  of the
particulates  from  small coal stokers are  released  to  the atmosphere.
4.2.1.3   Industrial Processes
       In the industrial sector, the cement industry  uses  cyclones  and
electrostatic precipitators as particulate  controls.   Table 4-8 shows that
approximately 82 percent of particulate emissions  are.  removed from  the
effluent stream by control devices (Reference 4-57).
4.2.2  SO  Control
       Flue gas desulfurization and low sulfur fuels were  examined  for
their applicability and effectiveness as  NO  controls.   Coal  cleaning
currently has insignificant use nationwide.   Two recent  surveys of  flue
gas desulfurization (References 4-58 and  4-59) indicated that the total
installed capacity of FGD equipment on utility sized boilers  is about
5000 MWe.  Compared to the total installed  electricity capacity of  about
350,000 MWe (Reference 4-60), the effect  of FDG  is  very  small.
                                    4-22

-------
       The primary means  of  meeting local S0x control regulations is by



using low sulfur fuel either by itself or in blends with high sulfur



fuel.  Since the sulfur concentration in these fuels is strictly monitored



at the utility level, the use of utility fuel consumption and sulfur



concentration data will result in a controlled inventory.  Since the



utility sector uses most  of  the sulfur containing coal  and oil  and  is  the



most heavily regulated, the  controlled utility inventory combined with



uncontrolled emissions  in the remaining sectors serves  as the 1974



controlled SO  inventory.  In the future however, the Clean Air Act
             f\


Amendments of 1977, which require SO  emissions to be reduced as a
                                     /\


function of sulfur in the fuel rather than as total emission loadings,



will eliminate the use  of low sulfur coals as a control method.



4.2.3  NO  Control
         A       ~~
       NO  controls were  obtained by applying state and local  NO
         A                                                       A


regulations (Appendix  E)  to  combustion equipment within each region.   For



the reference year 1974,  the 1971 NSPS regulations had no effect on



emissions due to the 3 to 5  year time lag between equipment orders and



startup.  As Table E-l in Volume II shows, utility boilers are the most



extensively regulated  sector,  whereas gas turbines and large packaged



boilers are regulated  only in  certain regions.  However, examination of



data shows that only utility boilers are controlled with greater than  1



percent effect on nationwide emission loading.  Thus, only utility boilers



are discussed in this  section.



       In calculating  the effect of NO  controls for utility boilers,
                                       A


the uncontrolled emissions of  a specific boiler were reduced by the  ratio



of the controlled to the  uncontrolled emission factor.  For example,  if



the emission limitation for  oil fueled boilers is 129 ng/J and the
                                     4-23

-------
uncontrolled emission factor is 153 ng/J, then  the  reduction of NOX
emissions (assuming 100 percent compliance)  is  16 percent.   A more
detailed explanation of the methodology  is given  in Appendix D of
Volume II.
       The degree of current control for coal-fired utility boilers is
small.  However, this control is increasing  as  retrofit  controls are used
and new units designed to meet the NSPS  are  installed.   Comparisons of  the
controlled and uncontrolled NO  emission rates  are  presented in
                              ^
Section 4.4.
4.2.4  Regional Controls
       State and local standards for new and existing  sources  are given  in
Appendix E.  In certain areas, standards for new sources  are the same as
the Federal NSPS, and were omitted.  In  areas such  as  Los Angeles,
regional controls may be much more stringent than NSPS regulations,  in
order to reduce localized pollution problems or to  comply with SIPs.
       The regional emissions regulations survey can be  somewhat
misleading.  In some areas, units may not be in compliance  with emission
standards because of local variances or  lack of enforcement.   In addition,
some units may actually be controlled to levels below  the current
regulation or have added controls for energy conservation or community
relations.  For these reasons, obtaining an accurate estimate  of regional
controls is extremely difficult and of questionable accuracy.
       Section 4.4 shows that the decrease in national emissions due to
NCx controls is approximately 1.6 percent.  Because of this minor effect
and the uncertainty in estimating regional controls, further assessment  of
regional controls is unwarranted.
                                    4-24

-------
4.3    PROJECTED EMISSIONS REGULATIONS
       This subsection describes  the  methodology for projecting emissions
into the future, and includes  consideration of projected New Source
Performance Standards.  These  emissions  projections are used in Section
4.5 to project national emissions inventories  and in Section 5  to  assess
the potential environmental  impacts of stationary combustion sources.
       By law, NSPS are reviewed  and  revised for additional  stringency as
advanced control technology  is  developed and demonstrated.   Candidate NSPS
technologies include not only  stack controls,  but also  process  changes and
the impacts of variations in fuels, combustion methods,  and  raw
materials.  Thus, the projected promulgation of NSPS must reflect  a
gradual process that provides  for the lead  times needed to develop control
methods, test procedures, and  technical  enforcement capabilities.
       Table 4-9 displays the  most stringent NO  controls that  probably
                                                A
can be achieved if NO  control  development  efforts are  expanded and
                     A
accelerated (References 4-53 and  4-61 through  4-72).   In some cases, the
control technology has already  been demonstrated.
       The NSPS projections were  combined with the following factors to
arrive at emissions projections:
       o   (Growth or decline)  in energy consumption
       •   Replacement of obsolete sources
       •   Fuel switching
The NSPS projections were imposed on  all capacity additions  within a
sector, including new source growth,  units  replacing obsolete sources, and
fuel switching to coal.  Each  of  these influences on emissions  projections
are incorporated in the emission  projection equation developed  here.
                                     4-25

-------
TABLE 4-9.  ESTIMATED FUTURE NSPS CONTROLS
Equipment Types
Utility and Large
Industrial Boilers
((>73 MW)a


Large Packaged Boilers
O7.3) MW)a


Small Packaged Boilers
« 7.3 MW)a


Small Commercial and
Residential Units

Gas Turbines
aThermal input
Fuel
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
Oil
Gas


Date Implemented
1971
1978
1981
1985
1988
1971
1971
1979
1985
1990
1979
1979
1981
1979
1979
1983
1983
1978
1983

Standard (ng/J)
300
258
215
172
129
129
86
258
215
172
129
86
50% reduction
129
86
30
17
129
86

                    4-26

-------
                            TABLE 4-9.,  Concluded
Equipment Types
1C Engines
Process Combustion
Fuel
Dist. Oil
Natural Gas
Gasoline

Date Implemented
1979
1985
1979
1985
1979
1985
1981
1990
Standard (ng/0)
1390
1040
1240
930
950
710
20% reduction
40% reduction
Thermal  input

    Figure  4-1  shows  the effects of these parameters on total energy
    consumption for  coal-fired utility boilers in one of the reference
    scenarios.   As  shown in this figure, the energy consumed by sources that
    have switched to  coal  firing helps offset some of the lost capacity due to
    due  to  source obsolescence and reduce requirements for additional energy
    growth  within a  sector.
           This methodology does not specifically consider the growth of
    nuclear sources  since  nuclear growth has already been separated from
    stationary  fossil  fuel  consumption projections in Section 3.  However, it
    is implicitly considered in that it greatly influences the level of fossil
    fuel  combustion  needed  to meet national energy demands.
           To estimate the  total emissions resulting from the gradual
    implementation of  NSPS  NO  controls on new sources (Table 4-9) and
                             /\
    continued operation of  old sources that are not required to comply with
    NSPS, the following equation was used:
                                        4-27

-------
Stationary
  source
  energy
                                                  New source growth
                                       eplacement by  new  sources
                                                       Switching
              £nergy from old sources
              hot subject to NSPS
                       Year
            Figure  4-1.   Energy  representation  in  the  environmental  scenario
                         (Assuring only one NSPS,  constant  between  time limiis).
                                     4-28

-------
        a
EMM =
                   * V -(Xi+l  -  V   NSPSi  +   (*N)  (EF)  (CFN)
                                  NSPSa                               (4-1)
where EMN = total emissions  in  year  N  reflecting  NSPS control of
            appropriate  sources
        a = denotes  last NSPS  increment  for  summation to year N
        N = end year of  summation
        i = denotes  number of NSPS control  level  changes for source type
        W = total energy consumption
        X = total energy consumption due to  old sources
     NSPS = allowable emission  factor  under  new source performance standard
       EF = uncontrolled emission factor
      CF,. = control  factor reflecting  current  stationary source controls
            (the methodology for deriving this is  given in Appendix D)
       The summation equation indicates  the  potential for NO  emission
                                                            A
reduction through implementation of  stringent  NO   controls.  It accounts
                                                A
for increasingly stringent NSPS controls  by  summing the individual
influences of each control between the specified  time limits.  Thus, if a
source type has three increasingly stringent NSPS  to the year 2000, then
this summation equation  will be comprised of three separate sets of terms,
representing the individual  NSPS that  are summed  to yield total emissions
to 2000.
                                    4-29

-------
       Equation 4-1 has two major components.   The  first  component of this



equation accounts for energy consumption  by  new sources which must comply



with NSPS controls.  Within this first major component, the  two terms



represent energy sources that must comply with  NSPS controls.   First,



growth in energy consumption is met by new sources  (W-+-|  - W-)  which



must comply with NSPS controls.  Second,  obsolete sources replaced by new



units, and sources which switch fuels (X^ - X.+^) must also  meet  NSPS



controls.  Of course, since additional energy is added here  by  fuel



switchings energy is subtracted from the  original fuel consumption sector.



       The second major component of this equation represents energy



consumption from old sources that are not required to meet NSPS



constraints.  These sources may be controlled at the present time  or  may



be required to retrofit NO  controls at some future time.  Such control
                          A


is accounted for by the factor CF.



       Energy consumption was assumed to  follow a compound growth  rate,
                                        B)Y
where B = compound energy use growth rate for each specific equipment type



          under consideration



      Y = number of elapsed years



Source obsolescence is accounted for by a simple decline rate,






                            XN = WQ x Y x A                          (4-3)







where A = specific source obsolescence rate, and XN is in the energy from



          old sources.
                                    4-30

-------
A 50-year life was  assumed  for utilities and large combustion equipment



(i.e., A =  .02); correspondingly shorter lives were assumed for other



equipment types.  For  simplicity,  the capacity lost due to source



obsolescence for oil  and  gas sources was assumed to be replaced by coal



burning equipment,  whenever possible.



4.4    NATIONAL  EMISSIONS INVENTORY -- 1974



       This section presents an inventory of major combustion related



pollutants  originating from stationary fuel burning sources of NO .   The
                                                                  j\


inventory includes  the criteria pollutants NO , SO , CO, HC,  and
                                              A    A


particulates emitted from gaseous  effluent streams.  A more complete



emissions inventory is given in Appendix D in Volume II by equipment  type



for  17 fuel categories and  the following pollutants:  criteria pollutants,



sulfates, trace  metalics, ROMs and trace elements in hopper ash and flyash.



4.4.1  Stationary  Source Sector Emissions



       Tables  C-l  through C-6 in Appendix C, provide 1974 criteria



pollutant emissions and totals for the following sectors:



       •    Utililty Boilers — Table C-l



       •    Packaged Boilers — Table C-2



       •    Warm  Air Furnaces -- Table C-3



       •    Gas Turbines --  Table C-4



       •    Reciprocating 1C Engines — Table C-5



       •    Industrial  Process Heating — C-6


The  emission estimates are  for 1974, because this is the most recent  year



for  which comprehensive fuel consumption data are available for both  the



nation and  individual  regions.  All units are in Gg per year.  These



tables give uncontrolled emission  figures for N0x and controlled



emission figures for SO  and particulates.
                        /\
                                     4-31

-------
       Table 4-10 summarizes the total emissions from the sectors  listed
above.
4.4.2  Summary of Air Pollutant Emissions
       The distribution of anthropogenic NO  emissions  nationwide  is
                                           A
shown in Figure 4-2 for 1974.  Stationary source emissions  are subdivided
by sector and fuel type in Table 4-11.  The estimates of utility boiler
emissions account for the reduction from using of NO  controls as
                                                    A
discussed in Section 4.2.  Based on a survey of boilers in  areas with
NOV emissions regulations, it is estimated that application of NO
  A                                                              A
controls in 1974 resulted in a 3.0 percent reduction in nationwide  utility
boiler emissions as shown in Table 4-12.  This corresponds  to a  1.6
percent reduction in stationary fuel combustion emissions.  Reductions
resulting from controls on other sources was negligible in  1974.
       In general, the stationary source NO  emissions totals and the
                                           A
distribution of NO  emissions among equipment types for 1974 show  little
                  "
change from 1972 inventories.  Also, the current inventory  shows generally
good  agreement with recent inventories from EPA's Office of Air  Quality
Planning and Standards and other groups.  One difference in the  inventory
is for industrial packaged boilers.  Here, recent estimates by various
groups differ by as much as a factor of 2 -- primarily due  to uncertainty
in total fuel consumption for this sector.
       The emissions inventory summaries for other pollutants are  shown on
Table 4-13.  The data for the criteria pollutants are regarded as  good and
the results of the current inventories are in reasonable agreement  with
other recent inventories.  The data for the noncriteria pollutants  and
liquid or solid effluent streams, however, were sparse  and  exhibited  large
scatter.  The emission factors for POMs, for example, varied by  as much  as
                                    4-32

-------
     TABLE  4-10.   ANNUAL CRITERIA POLLUTANT EMISSIONS BY SECTOR
                   (UNCONTROLLED NOX) (Gg)
Equipment Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces and
Miscellaneous Combustion
Gas Turbines
Reciprocating 1C Engines
Industrial Process Heating
Total
NO/
5,741
2,345
321
440
1 ,857
426
11,130
soxb
16,768
6,405
232
10.5
19.6
622
24,057
HC
29.5
72.1
29.7
13.7
578
166
889
CO
269.6
175.4
133
73.4
1,824
9,079
11,554
Part.
5,965
4,930.3
39.3
17.3
21.5
4,766
15,739
 N02  basis

DS02  basis
                                 4-33

-------
Noncombustion 0.9%

     Fugitive 2.3%
                              Incineration 0.2%
                                Stationary fuel combustion
                                         51.3%
Mobile sources
    45.3%
Stationary Fuel Combustion
Fugitive Emissions
Noncombustion
Incineration
Mobile Sources
TOTAL
Ga
10,957
498
193
40
9,630
21,318
1 ,000 tons
12,078
548
212
44
10,600
23,482
Percent
Total
(51.3)
(2.3)
(0.9)
(0.2)
(45.3)
100
  Figure 4-2.
       Distribution of anthropogenic NO  emissions
       for the year 1974.
                            4-34

-------
   TABLE 4-11.
SUMMARY OF 1974 STATIONARY SOURCE NO a
EMISSIONS BY FUEL -- Gg             x
(Percent of Total)
Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces
Gas Turbines
Reciprocating 1C
Engines
Industrial Process
Heating
Noncombustion
Incineration
Fugitive
Total
Coal
3,564
(30.5)
679.7
(5.8)

—
—
—
—
—
4,243.7
(36.3)
Oil
848
(7.3)
886
(7.6)
131
(1.1)
308
(2.6)
456C
(3.9)
—
—
—
—
2,629
(22.5)
Gas
1156
(9.9)
779
(6.7)
190
(1.6)
132
(1.1)
1400
(12.0)
—
—
—
—
3,657
(31.3)
Total
5568
(47.6)
2344.7
(20.1)
321
(2.8)
440
(3.7)
1856
(15.9)
426
(3,6)
193
(1.7)
40
(0.4)
498
(4.3)
11,687
 N02  basis


 Includes steam  and  hot water  commercial and residential heating units

%
'Includes gasoline
                            4-35

-------
     TABLE 4-12.  COMPARISON OF CONTROLLED. AND UNCONTROLLED ANNUAL

                   STATIONARY SOURCE  N0xa EMISSIONS
Sector and Equipment Type
Utility Boilers
Tangential
Wall Firing
Horizontally Opposed
Cyclone
Vertical and Stoker
TOTAL UTILITY
Package Boilers
Commercial and Residential Furnaces
Gas Turbines
Reciprocating 1C Engines
Industrial Process Heating
TOTAL
Fuel

Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
Coal
All
All
All
All
All
All
All
1974
Controlled
NO^ (Gg)

1,408
205
138
945
458
649
271
169
352
849
16
15
93
5,568
2,345
321
440
1,857
426
10,957
1974
Uncontrolled
NOJJ (Gg)

1,409
208
146
946
481
738
271
175
379
863
17
15
93
5,741
2,345
321
440
1,857
426
11,130
Percent
Reduction
(%)

0.1
1.4
5.5
0.1
4.8
12.3
0
5.1
6.7
1.6
6.0
0
0
3.0
	
—
—
—
-
1.6
                                                                                 10
                                                                                 in
"NO, basis
 Controlled by regulations existing December 1976
                                     4-36

-------
                        TABLE 4-13.  SUMMARY  OF AIR AND SOLID POLLUTANT EMISSIONS FROM  STATIONARY
                                      FUEL BURNING EQUIPMENT  (Gg)
Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces
& Misc. Comb.
Gas Turbines
Recip. 1C Engines
Process Heating
TOTAL
N0xb SOX HC
5,568 16*768 29.5
2,345 6,405 72.1
321 232 ,29.7
440 10.5 13.7
1,857 19.6 578
426 622 166
10,957 24,057 889
CO
270
175
132.6
73.4
1,824
9,079
11,554
Part. Sul fates POM AshTtonoval As$h taSlal
5,965 231 0.01 - 1.2 6.2 24.8
4,930 146 0.2 - 67.8 1.1 4.4
39.3 6.4 0.06
17.3 a
21.5 a a __
4,766 a a __
15,739 383 69 7.3 29.2
I
co
              No emission factor available


             bControlled NOX> N02 basis


             °Based on 80 percent hopper and flyash removal by sluicing methods; 20  percent dry solid removal

-------
two orders of magnitude.  Table 4-13 shows estimates of total  POM



emissions.  There are several ongoing field test programs which  are



sampling noncriteria pollutants.  The current inventory will be  updated



with these results as they become available.  Table 4-14 ranks



equipment/fuel combinations by annual nationwide NO  emissions and lists
                                                   A


the corresponding ranking based on fuel consumption and emissions of



criteria pollutants.  Although there were over 70 equipment/fuel



combinations inventoried, the 30 most significant combinations account for



about 90 percent of NO  emissions.  However, the ranking of specific
                      f\


equipment/fuel types depends both on total installed capacity and emission



factors.  A high ranking, therefore, does not necessarily imply that a



given source is a high emitter.  In general, coal-fired sources rank high



in SO  and participate emissions, while 1C engines dominate CO and
     A


hydrocarbon emissions.



       These pollutant emission values are used in the Section 5 source



analysis modeling to provide a pollution potential ranking of stationary



combustion sources.



4.5    NATIONAL EMISSIONS INVENTORIES — 1985, 2000



       This section presents emissions inventories for 1985 and 2QOO for



combustion related pollutants resulting from stationary fuel burning NO



sources for the reference scenarios.  (The reference scenarios are



discussed In Section 3.4).  These emissions inventories are a culmination



of the projected 1985 and 2000 fuel consumption data presented in Section



3.5.3 and the control projections developed in Section 4.3.  These



inventories include the criteria pollutants NO , SO , CO, HC, and
                                              "    &


particulates emitted from gaseous effluent streams.  Secondary emphasis
                                    4-38

-------
               TABLE  4-14.   N0xa MASS  EMISSION RANKING  OF STATIONARY  COMBUSTION EQUIPMENT
                             AND CRITERIA POLLUTANT AND  FUEL USE CROSS RANKING
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Sector
Utility Boilers
Reciprocating 1C
Engines
Utility Boilers
TEftility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Reciprocating 1C
Engines
Packaged Boilers
Packaged Boilers
Utility Boilers
Packaged Boilers
Utility Boilers
Packaged Boilers
Packaged Boilers
Utility Boilers
Pack-age'd Boilers
Industrial
Process Comb.
Utility Boilers
Packaged Boilers
Equipment Type
Tangential
>75 kW/cylc
Wall Firing
Cyclone
Wall Firing
Wall Firing
Horizontally Opposed
75 kW to 75 kW/cylc
Wall Firing WTd >29 MWb
Stoker Firing WTd <29 MWb
Horizontally Opposed
Wall Firing WTd >29 MWb
Tangential
Scotch FTe
Single Burner WTd <29 MWb
Horizontally Opposed
Single Burner WTd <29 MWb
Refinery Heaters
Forced & Natural Draft
Tangential
Firebox FTe
Fuel
Coal
Gas
Coal
Coal
Gas
Oil
Gas
Oil
Gas
Coal
Coal
Oil
Oil
Oil
Gas
Oil
Coal
Oil
Gas
Oil
Annual NOX
Emissions
(Mg)
1,410,000
1,262,000
946,000
863,500
738,300
481,000
378,700
325,000
318,500
278,170
270,800
232,480
208,000
203,990
180,000
177,900
164,220
147,350
146,000
139,260
Cumulative
(Mg)
1,410,000
2,672,000
3,618,000
4,481,500
5,219,800
5,700,800
6,079,500
6,404,500
6,723,000
7,001,170
7,271,970
7,504,450
7,712,450
7,916,440
8,096,440
8,274,340
8,438,560
8,585,910
8,731,910
8,871,170
Cumulative
(Percent)
12.7
24.0
32.5
40.3
46.9
51.2
54.6
57.5
60.4
62.9
65.3
67.4
69.3
71.1
72.7
74.3
75.8
77.1
78.5
79.7
Fuel
Rank
1
21
3
6
4
8
14
>30
16
7
23
26
12
11
5
>30
>30
>30
13
17
SOX
Rank
1
>30
2
3
>30
9
>30
>30
>30
4
5
16
10
11
>30
17
8
29
>30
13
CO
Rank
7
4
6
12
13
17
24
3
29
11
>30
>30
27
>30
>30
>30
>30
>30
>30
>30
HC
Rank
16
1
23
9
28
27
>30
3
19
4
>30
26
>3Q
>30
22
>30
>30
18
>30
>30
Part.
Rank
2
>30
5
13
>30
18
>30
26
>30
1
7
22
19
16
>30
27
9
21
>30
20
                                                                                                                      _
                                                                                                                      CJ
                                                                                                                      CO
dN02 basis
bHeat input
cHeat output
 Watertube
eF ire tube

-------
                                                    MMf 4*14.
I
                                                             •NttfM
                                                                        emulative
                                                                           (MB)
                                                               Cumulative
                                                               (Percent)
                                               Fuel
                                               Rank
                                              SOv
                                              Rank
                                           CO
                                          Rank
                                    HC
                                   Rank
                              Part.
                              Rank
                             CM
                             oo
n
22
21
24
2$
      »Mtft*4
          ilr FUTMCCS
      Pa*ft»ge4 toitart
     If
       VWiC* w*  ^v** WP
fefffer«l
Stole? Firing H* <*9
                         »lf HI*
                        ffcrert I tetttrtt arafl
tMt
011
Oil
Gas
CoaT
tat
on
Oil
Sas
1tS.9ft
118.500
116.430
106,300
102,040
 98,010
 97.400
 54,000
8,996,520
9,115.020
9.231.450
9,337.750
9,439,790
3.537,800
9.635.200
9,729.200
9.821.808
9.912.708
80.8
81.9
82.9
83.9
84.8
85.7
86.6
87.4

88.2

89.1
>30
 30
 27
  2
 29
 19
>30
>30

 15

>30
  7
>30
 15
>30
  6
>30
>30
>30

>30

 12
 28
 15
>30
 10
>30
>30
>30
 22

>30

>20
 29
 14
>30
  8
 10
>30
 30
 13
                                                                                                                             >30
  8
>30
 23
 25
  6
>30
>30
>30

 30

 10

-------
was given to sulfates,  trace metallics, ROMs and trace elements in hopper
ash and flyash.
4.5.1  Summary of  Air Pollutant Emissions

       Tables 4-15 through 4-18 summarize total N0₯ emissions from fuel
                                                   A
user sources for 1985 and 2000 respectively, for the reference scenarios.
NOX emissions show little change between 1985 and 2000 for the high
nuclear scenario,  even  through fuel consumption rises by 41 percent.   This
is a result of progressively stringent NO  controls enforced through  the
                                          A
use of NSPS.  The  low nuclear scenario shows an increase in NO
                                                               A
emissions even with the implementation of NSPS.  This is a result  of  the
large increase in  fossil  fuel combustion within this scenario particularly
for coal firing.
       NO  mass emissions rankings of stationary combustion equipment
         A
are presented in Tables 4-19 and 4-20 for 1985 and 2000 respectively, for
the reference high nuclear scenario.  The 30 most significant sources
account for over 90 percent of total NO  emissions.  Tangential boilers
                                        A
appear to be the most significant NO  source through the year 2000 if
                                     A
projected trends continue.  Coal-fired stationary sources generally should
increase their share of NO  emissions and dominate the highest
                           A
rankings.  Coal-fired sources also rank high in SOX and particulate
emissions.  Natural gas-fired combustion sources show lower N0x
emissions rankings on this list due to decreases in fuel consumption  and
implementation of  NSPS  controls.  In 2000, the highest natural gas source
is tenth on the ranking,  compared to second in 1974.  Oil-fired sources
also show a gradual decrease in NOV emissions due to their attrition  and
                                   A,
replacement with coal-fired sources.  These rankings, however, are based
on projected equipment  fuel consumption and growth rates, and
                                     4-41

-------
TABLE 4-15.
SUMMARY OF ANNUAL  NO  a  EMISSIONS FROM FUEL USER  SOURCES (1985)
REFERENCE SCENARIO -* LOW  NUCLEAR
Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces
Gas Turbines
Reciprocating
1C Engines
Process Heating
Noncombustion
Incineration
Total by Fuels
NO Production -- Gg
x (X of Total)
Gas
711.0
(5.84)
743.0
(6.10)
136.0
(1.12)
171.0
(1.40)
627.0
(5.15)
«
—
—
2,338.0
(19.19)
Coal
6053.6
(49.68)
674.0
(5.53)
~
~
~
—
--
—
6,727.0
(55.21)
Oil
646.0
(5.30)
915.0
(7.51)
125.0
(1.03)
375.0
(3.08)
456.0
(3.74)
—
—
--
2,517.0
(20.66)
Total
By Sector — Gg
(* of Total)
7,410.0
(60.82)
2332.2
(19.14)
261.0
(2.14)
546.0
(4.48)
1,083.0
(8.89)
260.0
(2.13)
239.0
(L96)
53.0
(0.44)
12,184.0
Cummulative
(*)
60.82
79.96
82.10
86.58
95.47
97.60
99.57
100.0

                                                                    T-871
   °N02 basis
                                 4-42

-------
TABLE 4-16. SUMMARY OF ANNUAL NO a  EMISSIONS FROM FUEL USER SOURCES (20001
            REFERENCE SCENARIO -* LOW  NUCLEAR               iUUKLtb (2000)
Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces
Gas Turbines
Reciprocating
1C Engines
Process Heating
Nonconbustion
Incineration
Total By Fuels
NOV Production — Gg
* (X of Total)
Gas
—
548.0
(3.76)
139,0
(0.95)
192.0
(1.32)
288.0
(1.98)
.
—
—
1,167.0
(8.01)
Coal
9,337.0
(64.10)
785.0
(5.39)
--
—
~
—
—
—
10,122.0
(69.49)
Oil
767.0
(5.27)
861.0
(5.91)
103.0
(0.70)
379.0
(2.60)
470.0
(3.23)
--
—
'
2,580.0
(17.71)
Total
By Sector ~ Gg
(* of Total)
10,104.0
(69.36)
2,194.0
(15.06)
242.0
(1.67)
571.0
(3.92)
758.0
(5.20)
300.0
(2.07)
322.0
(2.21)
76.0
(0.52)
14,567.0
Cummulative
(X)
72.07
83.32
85.54
89.61
95.02
97.16
99.46
100.0

                                                                      T-872
     aN02 basis
                                  4-43

-------
TABLE 4-17.   SUMMARY  OF ANNUAL NO a EMISSIONS FROM FUEL USER SOURCES  (1985):
              REFERENCE SCENARIO -* HIGH NUCLEAR
Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces ,
Gas Turbines
Reciprocating
1C Engines
Process Heating
Noncombustion
Incineration
Total by Fuels
NO,, Production -- Gg
x (% of Total)
Gas
712.0
(6.53)
743.0
(6.81)
136.0
(1.25)
171.0
(1.57)
627.0
(5.75)
—
--
—
2,389.0
(21.91)
Coal
5,062.0
(46.42)
385.0
(3.53)
»f*
—
—
—
__
~-
5,447.0
(49.95)
Oil
646.0
(5.92)
915.0
(8.39)
125.0
(1.15)
375.0
(3.44)
456.0
(4.18)
—
—
—
2,517.0
(23.08)
-Total
By Sector ~ Gg
(* of Total)
6,420.0
(58.87)
2,043.0
(18.73)
261.0
(2.39)
546.0
(5.00)
1,083.0
(9.93)
260.0
(2.38)
239.0
(2.19)
53.0
(0.50)
10,905.0
Cummulative
(*)
58.87
77.61
80. OC
85.01
94.94
97.32
99.51
100.0

     aN02 basis
                                                                   T-873
                                 4-44

-------
TABLE 4-18.
          SUMMARY OF ANNUAL N0ya EMISSIONS  FROM  FUEL USER SOURCES (2000)
          REFERENCE SCENARIO -^ HIGH  NUCLEAR
Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces
Gas Turbines
Reciprocating
1C Engines
Process Heating
Noncombustion
Incineration
Total By Fuels
NOV Production — Gg
x (X of Total)
Gas
—
548.0
(5.40)
139.0
(1.37)
192.0
(1.89)
288.0
(2.84)
—
—
—
1,167.0
(11.50)
Coal
5,259.0
(51.80)
448.0
(4.41)
~
~
—
«
—
--
5,707.0
(56.22)
Oil
767.0
(7.56)
861.0
(8.48)
103.0
(1.01)
379.0
(3.73)-
470.0
(4.63)
—
—
--
2,580.0
(25.41)
Total
By Sector ~ Gg
(% of Total)
6,026.0
(59.36)
1,857.0
(18.29)
242.0
(2.38)
571.0
(5.62)
758.0
(7.47)
300.0
(2.96)
322.0
(3.17)
76.0
(0.75)
10,152.0
Cummulative
(*)
59.36
77.65
80.03
85.56
93.13
96.08
99.25
100.0
T-fl7d
aN02 basis
                              4-45

-------
             TABLE  4-19.   YEAR 1985 — NOX MASS EMISSIONS RANKING FOR STATIONARY COMBUSTION EQUIPMENT
                           AND CRITERIA POLLUTANT CROSS RANKING
 I
-e»
en
Rank Sector
1 Utility Boilers
2 Utility Boilers
3 Utility Boilers
4 Utility Boilers
5 Reciprocating 1C
Engines
6 Utility Boilers
7 Utility Boilers
8 Utility Boilers
9 Reciprocating 1C
Engines
10 Gas Turbines
11 Packaged Boilers
12 Packaged Boilers
13 Packaged Boilers
14 Packaged Boilers
15 Utility Boilers
16 Reciprocating 1C
Engines
17 Packaged Boilers
18 Utility Boilers
19 Packaged Boilers
20 Packaged Boilers
21 Reciprocating 1C
Engines
Equipment Type
Tangential
Hall Firing
Cyclone
Wall Firing
SIe>75 kW/cyl1?
Horizontally Opposed
Hall Firing
Horizontally Opposed
CIf 75 kU to 75 kH/cyl"
Simple Cycle 4 MW to 15 MWb
Wall Firing HTC >29 MWa
Wall Firing HTC >29 MM*
Scotch FTd <29 MW
Single Burner WTC <29 MHa
Tangential
SI^>75 kU to 75 kW/cylb
Stoker Firing WTC <29 MWa
Horizontally Opposed
Firebox FTd <29 MHa
Single Burner WTC <29 HWa
CIf>75 kH/cyl
Fuel
Coal
Coal
Coal
Gas
Gas
Coal
011
Gas
Oil
Oil
Gas
011
011
Gas
011
Gas
Coal
Oil
Oil
Oil
Oil
Annual
NO. Emissions
* (Mg)
2,413,820
1,530,400
678,820
564,900
537,000
437,450
396,990
306,840
289,010
274,480
268,340
223,890
210,190
207,310
185,290
178,720
158,220
146.310
143,500
137,260
127,060
Rank
1
2
3
>30
>30
4
7
>30
29
>30
>30
13
6
>30
8
>30
5
17
10
12
>30
CO
Rank
5
4
16
14
3
22
20
26
8
10
27
>30
>30
19
28
1
18
>30
>30
>30
15
HC
Rank
9
17
13
>30
1
>30
>30
>30
6
14
18
28
>30
24
>30
3
7
>30
>30
>30
10
Part
Rank
1
4
12
, 30
>30
7
19
>30
23
26
>30
17
13
>30
20
>30
5
29
16
18
>30
aHeat input cHatertube eSpark Ignition
bHeat output dFiretube Compression Ignition

-------
                                            TABLE 4-19.    Concluded
Rank Sector
22 Utility Boilers
23 Gas Turbines
24 Gas Turbines
25 Packaged Boilers
26 Packaged Boilers
27 Packaged Boilers
28 Reciprocating 1C
Engines
29 Packaged Boilers
30 Warm Air Furnaces
Equipment Type
Tangential
Simple Cycle 4 MW to 15 HWb
Simple Cycle >15 MWb
Scotch FTd <29 HWa
Hall Firing WTC >29 HUa
HRT Boiler
CIf>75 kW/cylb
Firebox FTd<29 MMa
Warm Air Central Furnace
Fuel
Gas
Gas
Oil
Gas
Coal
Oil
Dual
Gas
Gas
Annual
NO Emissions
X (Mg)
126,170
118,150
99,251
93,700
93,410
88,630
88,390
86,800
82,520
SOX
Rank
>30
>30
>30
>30
14
16
>30
>30
>30
CO
Rank
>30
13
17
29
>30
>30
25
>30
11
HC
Rank
>30
19
23
30
>30
>30
4
>30
11
Part-
Rank
>30
>30
>30
>30
9
15
>30
>30
27
T-8S9
 Heat input
bHeat output
cWatertube
dFiretube
Spark Ignition
Compression Ignition

-------
                    TABLE  4-20.   YEAR 2000 -- NOx  MASS EMISSIONS  RANKING  FOR STATIONARY  COMBUSTION EQUIPMENT
                                   AND CRITERIA POLLUTANT  CROSS RANKING
.£»
00
Rank
i
2
3
4
6
6
r
8
9
10
11
\2
13
14
15
16
17
16
19
20
21
Sector
Utility Boilers
Utility tollers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Reciprocating 1C
Engines
Gas Turbines
Packaged Boilers
Reciprocating 1C
Engines
Packaged Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Reciprocating 1C
Engines
Utility Boilers
Reciprocating 1C
Engines
Packaged Boilers
Packaged Boilers
Gas Turbines
Gas Turbines
Equipment Type
Tangential
Wall Firing
Horizontally Opposed
Cyclone
Hall Firing
Tangential
CIf75 kH to 75 kH/cylb
Simple Cylce 4 MW to 15 HWb
Stoker Firing HTC<29 «M*
SlVs kH/ey1b
Hall Firing HTC>29 MHa
Scotch FTd 29 NWa
Single Burner WT<29 MH8
SIe75 kU to 75 kH/cy1b
Horizontally Opposed
CI*>75 kH/cylb
Single Burner WTC<29 MW*
Firebox FTd<29 MK8
Simple Cyele>15 MUb
Simple Cycle 4 HW to 15 MWb
Fuel
Coal
Coal
Coal
.Coal
Oil
Oil
Oil
011
Coal
Gas
011
Oil
Gas
Gas
Gas
011
Oil
011
011
011
Gas
Annual
w* Kr"
2,704,100
1,838.820
582.530
450,260
450,130
279,610
269,810
256,590
244,070
201,700
199,660
197.720
195.030
181,780
167,250
165,900
159,460
140,960
134,980
122,020
110,390
SO
Rank
1
2
4
S
9
10
>30
>30
3
>30
23
6
>30
>30
>30
16
>30
14
12
>30
>30
CO
Rank
6
4
20
2S
17
22
10
15
16
5
>30
>30
>30
24
2
>30
13
>30
>30
9
19
HC
Rank
10
16
>30
21
29
>30
7
18
5
1
28
>30
23
27
3
>30
9
>30
>30
13
22
Part.
Rank
4
5
7
14
18
19
28
>30
2
>30
21
15
>30
>30
>30
26
>30
22
20
27
>30
                   aHeat Input
                   °Heat output
cHatertUbe


dF1retube
                                                                       eSpark Ignition
                                                                        Compression Ignition

-------
                                               TABLE  4-20.   Concluded
Rank
22
23
24
25
26
27
28
29
30
Sector
Packaged Boilers
Packaged Boilers
Reciprocating 1C
Engines
Packaged Boilers
Gas Turbines
Warm Air Furnaces
Packaged Boilers
Ind. Process Comb.
Packaged Boilers
Equipment Type
Hall Firing tfTc>29 MWa
Stoker WTC>29 MWa
CIf>75 kW/cylb
HRT Bo Her
Simple Cycle >15 MWb
Warm Air Central Furnace
Scotch FT|J<29 MHa
Refinery Htr. Nat. Draft
Firebox FTb<29 MWa
Fuel
Coal
Coal
Dual
(011 and Gas)
on
Gas
Gas
Gas
Dual
(Oil and Gas)
Gas
Annual
NO Emissions
x «Mg)
105,180
87,612
84,080
83,370
81,550
77,640
74,320
73,260
68,850
SO
Rank
11
8
>30
15
>30
>30
>30
>30
->30
CO
Rank
>30
30
26
>30
14
11
>30
>30
>30
HC
Rank
>30
>30
14
>30
17
11
>30
8
>30
Part-
Rank
9
8
>30
17
>30
29
>30
>30
>30
T-860
"Heat input
                                   Hater-tube
                                                               Spark Ignition
 Heat output
                                  "Firetube
                                                              Compression Ignition

-------
implementation of tentative NSPS controls.  Thus,  because of the



uncertainty of these projections, these rankings again  should be



considered only as qualitative indications of future  trends,  not as



quantitative conclusions.



4.5.2  Summary and Conclusions



       The present level of NO  controls will not  significantly reduce
                              n


NO  emissions in the year 2000 period.  Curve 1 of Figures  4-3 and 4-4
  ^


shows that under current controls, NO  should increase  by 30  percent by
                                     A


the year 2000 with the high nuclear scenario and by about 80  percent with



the low nuclear scenario.  Utility boiler NO  emissions  should represent
                                            /\


most of that increase because of the high demand for  electricity through



the year 2000.



       At present, RSPS have only been set for large  boilers  — 73 MW heat



input (250 MBtu/hr) and nitric acid plants.  These standards  represent



only a small portion of the NSPS control potential.   Obviously,  more



stringent controls are required to contain NOX emissions  in the 1990's.



Curve 2 of Figure 4-3 shows the result of applying increasingly stringent



controls to stationary sources for the high nuclear case.   In  1985,  total



N0x emissions with NSPS control show no significant change  from 1974.



However, as the controls schedule becomes increasingly more stringent,



total N0x emissions drop slightly from the 1974 value —  a  reduction of



7 percent.  NOX emissions from utility boilers without NSPS control



increase by about 27 percent in 1985 as shown in Curve 3.   However,  with



increasingly stringent NSPS controls, these emissions are reduced to 8



percent over the 1974 level by the year 2000 as shown in  Curve 4.
                                    4-50

-------
                                                                                        ) Total NOX - present controls


                                                                                       2) Total NOX - NSPS controls


                                                                                          Utility Boilers - present controls


                                                                                       7)utility Boilers - NSPS controls
                     15
en
                     10
1974
a,,-
                                                    1985
                             basis
                                                                                         2000
                                  Figure 4-3.   NOX  emissions  projections —  stationary sources
                                                 (reference scenario --  high nuclear).

-------
tn
                                                                                               Total  NOX -- present controls
                                                                                                     NOX - NSPS controls
                                                                                              k
                                                                                             3/Utility Boilers - present controls

                                                                                             Outlllty Boilers.- NSPS controls
                                                                                           2000
                            N02 basis
                                    Figure 4-4.  N0xa  emissions projections --  stationary sources
                                                  (reference scenario  --  low nuclear).

-------
       However,  If  nuclear power growth remains low due to concerns about


safety, cost,  leadtime,  and waste disposal, fossil fuel combustion sources


will have to meet most of the increasing energy demand.  Curve 2 of


Figure 4-4 shows that  total N0x emissions increase by about 30 percent,


even with strict NSPS  controls under the reference low nuclear scenario.


Utility boiler N0x  emissions increase by about 80 percent over 1974


emission levels  even with NSPS control, as shown by Curve 4.  Thus, it  is


clear that even  stringent NSPS controls are not sufficient to reduce NO
                                                                       x

levels for large  increases in fossil fuel consumption in this scenario.


       Argonne (Reference 4-64) also has shown that even with aggressive


setting of NSPS,  under a low nuclear growth scenario, NO  emissions
                                                         A

still  increase substantially over the 1975 to 1990.period.  In fact, 1990


emissions are  projected to be about 44 percent higher than 1975 levels.


The Argonne  projections are somewhat higher than the results in this


section, since they used higher energy growth rates for most sectors.


       Thus, current controls are probably not sufficient to suppress


NO  emissions  growth in the future.  Moreover, even implementing a
   A

strict set of  NSPS  controls may not be sufficient to maintain current


NO  levels  if  coal  usage increases due to continued low nuclear energy
   A

growth.  Thus, to maximize the effectiveness of the N0x control


 strategy, high priority should be given to sources that are experiencing


rapid  growth and generate high NO .
                                  A

 4.6   REGIONAL EMISSIONS  INVENTORY


       This  section presents regional emissions inventories for combustion


 related  pollutants  resulting from stationary combustion sources of  N0x.


 Table  4-21  summarizes NO  emissions for  the nine  reqions  discussed  in
                         /\

 Section  3.3.   These inventories result from the regional  fuel consumption
                                     4-53

-------
                       TABLE 4-21.
DISTRIBUTION OF REGIONAL  UNCONTROLLED NO a EMISSIONS
(Gg) -- 1974                             x
Sector and Equipment
Type
Utility Boilers
Tangential
Wall Fired
Horizontally
Opposed
Cyclone
Vertical and Stoker
Subtotal
Packaged Boilers
Commercial and
Residential Furnaces
Gas Turbines
1C Engines
Process Heating
Subtotal
Total
Fuel

Coal
Oil
Gas
Coal
Oil
Gas
Coal
011
Gas
Coal
Oil
Gas
Coal
All
All
All
A11
All
All

All
New
England

7.5
30.6
0.4
5.0
70.9
2.1
1.4
61.6
2.2
1.5
2.5
0.1
0.5
186.5
142.0
9.5
131.0
11.7
0.5
294.7
481.7
Middle
Atlantic

161.8
55.7
1.9
108.3
128.8
9.6
31.0
37.4
4.9
98.6
4.5
0.2
10.4
653.1
361.3
31.2
66.8
60.5
61.4
81.2
1234.3
E-N-
Central

477.8
10.4
5.1
321.0
24.0
26.0
91.8
8.8
13.3
292.3
0.8
0.5
30.8
1302.6
603.0
65.5
19.3
247.7
84.4
1019.9
2322.5
W-N-
Central

132.9
1.4
15.0
89.3
3.1
75.8
25.5
1.2
38.9
81.2
0.1
1.4
8.6
474.4
175.1
22.7
36'. 7
359.4
24.5
618.4
1092.8
South
Atlantic

281.6
61.2
9.4
189.2
141.5
47.3
54.1
37.1
24.3
172.2
5.0
0.9
18.1
1041.9
400.5
56.5
33.8
79.4
17.5
587.7
1629.6
E-S-
Central

220.4
3.8
2.2
148.1
8.7
10.9
42.4
3.2
5.6
134.8
0.3
0.2
14.2
594.8
166.5
22.9
9.4
129.6
26.3
354.7
949.5
W-S-
Central

18.6
9.0
90.5
12.5
20.8
456.6
3.6
7.7
234.1
11.4
0.7
9.1
1.2
875.8
243.3
42.6
83.9
681.8
144.3
1195.9
2071.7
Mountain

97.8
4.5
8.7
65.7
10.3
43.9
18.8
3.8
22.5
59.8
0.4
0.9
6.3
343.4
93.3
25.4
52.3
206.2
2.8
380.0
723.4
Pacific

11.4
31.8
13.1
7.7
73.4
66.3
2.2
17.0
34.0
7.0
2.6
1.3
0.8
268.6
189.9
44.4
7.3
74.4
48.2
364.2
632.8
Total

1409.8
208.4
146.3
946.8
481.5
738.5
270.8
178.0
379.8
858.8
16.9
14.6
90.9
5741.1
2374.9
320.7
440.5
1850.7
410.0
5396.8
11137.0
aN02 basis
                                                                                                                 T-861

-------
data for 1974 presented in Section 3 and emission factors given in Sec-



tion 4.  These emission estimates are for uncontrolled NO  only, since as
                                                          J\

discussed in Section  4.2.4, the impact of NO  control implementation on
                                             A

a regional basis  is  small  in 1974.



       Over 40 percent  of  all NOX emissions from utility boilers are



from the East-North-Central and the South Atlantic regions.  The New



England region produces less than 5 percent of utility boiler NO
                                                                 x


emissions.  In addition, areas such as New England and the Far West may be



most strongly affected  by  fuel switching to coal since they are heavily



dominated by oil  and  gas firing.  The East-North-Central and South



Atlantic regions  generate  over 40 percent of the NO  emissions, from
                                                    A


 packaged boilers.   Considering all stationary sources, the



 East-North-Central  and  West-South-Central regions of the nation generate



 the highest  levels  of NO , representing about 40 percent of the total
                         A


 emissions.



        The  regional  inventories developed here  show  significant localized



 variations  of NO   emissions by fuel/equipment type.  These variations
                 x                                                      -j.


 result from both  the regional fuel mix variations and the distribution of



 stationary  source types.  Thus, a national policy of N0x control must  be



 broad  enough  to  encompass  these regional variations  in developing



 strategies  for  future NO  emissions reductions.
                         A


 4.6.1   Conclusion


        In  general,  the  emission totals generated  in  the  criteria pollutant



 inventory are considered to be of relatively  high quality.   However,  the



 emissions  inventory projections are based on  tenuous assumptions  about



 future conditions.   Because of the  inherent uncertainties  in  these



 projections,  they should be considered only  as  qualitative indicators of
                                      4-55

-------
energy and environmental contingencies.   The  regional  emissions
inventories are felt to be of good quality, except  for the packaged boiler
sector, where the data for oil-fired units  show  some discrepancy.  The
quality of sector emissions ranges from good  for utility boilers; to fair
to good for the warm air furnace, gas turbine, and  reciprocating 1C engine
sectors; to fair for the packaged boiler  and  industrial  process heating
sectors.
       Preliminary estimates of sulfates, ROMs,  and trace element
emissions are of poor quality because data  are very sparse and
inconsistent.  Liquid and solid pollutants  (trace elements)  from
stationary source combustion are also of  very poor  quality,  which is due,
in part, to a lack of exact monitoring of fuel composition.   Several
comments can be made about the quality of the pollutant  data in the
inventory:
       •   In the packaged boiler sector, fuel consumption,  equipment
           emission factors and emissions are difficult  to quantify.  This
           is due to the large capacity range of the equipment sector, the
           lack of regulation, the diversity  of  equipment design, and the
           extremely large population of this sector.
       t   The industrial process combustion  sector is also  extremely
           difficult to quantify.  The difficulty arises from the lack of
           data on specific fuel properties and  poor fuel consumption
           data.  Further complexities are  the large number  of process
           heating applications, and the variations in equipment design
           and combustion practices from  industry to industry.
                                    4-56

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      •   POM  emissions were treated as a single pollutant because few
          data were  available for specific POM compounds.  Even the
          available  POM data exhibited large scatter which warranted
          reporting  upper and lower extremes for the emission factors and
          emission rates.  Extensive testing is needed in all sectors.
      •   Transient  or nonconventional operations and their effect on
          multimedia emission rates were treated only superficially.
          Test data  were generally unavailable except in space heating
          applications where some transient data were available.  Test
          data are needed before these effects can be quantified.
       Subsequent efforts to update the inventory will improve the
estimates of noncriteria  pollutants and liquid  and solid  effluents,
pending  new  test results.  Through the remainder of the N0x E/A program,
related  research programs and testing will be monitored to continually
update the emissions inventories  developed in this section.  This will
ensure that  these  inventories are current  and reflect the most accurate
data available.
                                     4-57

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                          REFERENCES FOR SECTION 4
4-1.   "Compilation of Air Pollutant Emission Factors  (Second  Edition),"
       U.S. Environmental Protection Agency, AP-42, April  1973.

4-2.   "Supplement No. 6 for Compilation of Air Pollutant  Emission Factors
       (Second Edition)," U.S. Environmental Protection Agency,  Office of
       Air and Waste Management, Office of Air Quality Planning  and
       Standards, April 1976.

4-3.   "Supplement No. 3 for Compilation of Air Pollutant  Emission Factors
       (Second Edition), "U.S. Environmental Protection Agency,  Office of
       Air and Waste Management, Office of Air Quality Planning  and
       Standards, July 1974.

4-4.   "Proceedings of the Stationary Source Combustion Symposium
       Volume III -- Field Testing and Surveys,"  EPA-600/2-76-152c,
       NTIS-PB 257 146/AS, June 1976.

4-5.   "Proceedings of the Stationary Source Combustion Symposium
       Volume II — Fuels and Process Research and Development,"
       EPA-600/2-76-152b, NTIS-PB 256 321/AS, June 1976.

4-6.   Bartok, W., et al., "Field Testing:  Application of Combustion
       Modifications to Control NOx Emissions for Utility  Boilers," Exxon
       Research  and Engineering Company, EPA-650/2-74-006,
       NTIS-PB 237 344/AS, June 1974.

4-7.   Bartok, W., et al., "Systematic Field Study of  NOx  Emission Control
       Methods for Utility Boilers," GRU.4GNOS.71, Esso Research and
       Engineering, Office of Air Programs, Environmental  Protection
       Agency, December 1971.

4-8.   Selker, A. P., "Program for Reduction of NOx from Tangential
       Coal-Fired Boilers, Phase  II," Combustion  Engineering,  Inc.,
       EPA-650/2-73-005a, NTIS-PB 245 162/AS, June 1975.

4-9.   Selker, A. P.,  "Program for Reduction of NOx from Tangential
       Coal-Fired Boilers, Phase  Ila," Combustion Engineering, Inc.,
       EPA-650/2-73-005b, NTIS-PB 246 889/AS, August  1975.

4-10.  McCann, C., et  al., "Combustion Control of Pollutants from
       Multi-Burner Coal-Fired Systems," U.S. Bureau  of Mines,
       EPA-650/2-74-038, NTIS-PB  233 037/AS, May  1974.

4-11.  "The  Proceedings of the NOx Control Technology Seminar,"  San
       Francisco, California, Electric Power Research  Institute, SR-39,
       February  1976.
                                     4-58

-------
4-12.  Ctvrtnicek  T.E    "Applicability of NOx Combustion Modifications to
       Cyclone Boilers  (Furnaces),"  EPA-600/7-77/006,  NTIS-PB 263 960/7BE
       Monsanto Research  Corporation,  January 1977.                »ou//ot,

4-13   "Standard Support  and  Environmental Impact Statement for Standards
       of Performance:  Lignite-Fired  Steam Generators,"  Draft Final   A D
       Little, Inc., for  the  Environmental Protection  Agency,  March 1975."

4-14.  "Sources of Polynuclear  Hydrocarbons in the Atmosphere," U.S. Dept
       of Health, Education and Welfare,  AP-33.

4-15.  Personal communication with D.  Trenholm,  Emission  Standards
       Division, Environmental  Protection Agency,  August  1977.

4-16.  Personal communication with R.  Bennett,  Environmental  Protection
       Agency, August 1977.

4-17.  Personal communication with P.  Jones,  Battelle  Memorial  Institute
       August 1977.

4-18.  Personal communication with J.  Harris,  A.D. Little,  Inc.,
       August 1977.

4-19.  Personal communication with J.  Manning,   Environmental  Protection
       Agency, August 1977.

4-20.  Homolya, J.B., et  al., "A Characterization  of the  Gaseous  Sulfur
       Emissions from Coal and  Coal-Fired Boilers," presented  at  the
       Fourth National Conference on Energy and  the Environment,
       Cincinnati, Ohio,  October 1976.

4-21.  "Coal-Fired Power  Plant  Trace Element  Study ~  A Three-Station
       Comparison," Radian Corporation, EPA Region VIII,  September 1975.
                                                                       ^
4-22.  Suprenant, Norman, et al., "Preliminary  Emissions  Assessment of
       Conventional Stationary  Combustion Systems, Volume II,"
       EPA-600/2-76-046b, NTIS-PB 252  175/AS, GCA  Corporation,  March 1976.

4-23.  Vitez, B., "Trace  Elements in Flue Gases  and Air Quality Criteria,"
       Volume 80, No. 1,  Power  Engineering, January 1976.

4-24.  Klein, David H., et al.,  "Pathways of Thirty-Seven Trace Elements
       Through Coal-Fired Power  Plants,"  Environmental Science  and
       Technology, Volume 9, No. 10, pp..  973-979,  October 1975.

4-25.  "Trace Elements in a Combustion System,"  Battelle-Columbus
       Laboratories,  EPRI Final  Report 122-1, January  1975.

4-26.  Lee,  R.E., Jr., "Concentration  and Size of  Trace Metal  Emissions
       From  a Power Plant, a Steel Plant,  and a  Cotton Gin," Environmental
       Science and Technology.  Volume  9,  No. 7,  pp. 643-647.
                                    4-59

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4-27.  Davison, R. L., et al., "Trace Elements  in Fly Ash  —  Dependence of
       Concentration on Particle Size," Environmental Science and
       Technology, Volume 95 No. 13, pp. 1107-1113,  December  19/4.

4-28.  Kaakinen, J.W., et al., "Trace Element Behavior  in  a Coal-Fired
       Power Plant," Environmental Science and  Technology.  Volume 9,  No.  9
       pp. 862-869, September 1975.

4-29.  "Steam-Electric Plant Air and Water Quality Control  Data for the
       Year Ended December 31, 1972," FPC-S-246, Federal Power Commission,
       March 1975.

4-30.  Princiotta, F., "Sulfur Oxide Throwaway  Sludge Evaluation Panel
       (SOTSEP), Volume I:  Final Report, Executive  Summary,"
       EPA-650/2-75-010a.

4-31.  Cato, G.A., et al., "Field Testing:  Application of  Combustion
       Modifications to Control Pollutant Emissions  from Industrial
       Boilers -- Phase I," KVB Engineering, Inc. EPA-650/2-74-078a,
       NTIS-PB 238 920/AS, October 1974.

4-32.  Cato, 6.A., et al., "Field Testing:  Trace Element and  Organic
       Emissions from Industrial Boilers," KVB  Engineering, Inc.,
       EPA-600/2-76-086b, NTIS-PB 261 263/AS, October 1976.

4-33.  Cato, G.A., et al., "Field Testing: Application of Combustion
       Modifications Control to Pollutant Emissions  from Industrial
       Boilers — Phase II," KVB Engineering, Inc.,  EPA-600/2-76-086a,
       NTIS-PB 253 500/AS, April 1976.

4-34.  Barrett, R.E., et al., "Field Investigation of Emissions  from
       Combustion Equipment for Space Heating," BatteHe-Columbus
       Laboratories, EPA-R2-73-084a, NTIS-PB 223 148, June  1973.

4-35.  Hall, R. E., "The Effect of Water/Distillate  Oil Emulsions on
       Pollutants and Efficiency of Residential and  Commercial  Heating
       Systems," APCA Paper No. 75-09.4, 68th Annual Meeting of the Air
       Pollution Control Association, Boston, Massachusetts,  June 1975.

4-36.  Giammar, R.D., et al., "The Effect of Additives  in Reducing
       Particulate Emissions from Residual Oil  Combustion," ASME
       75-WA/CD-7.

4-37.  Giaramar, R.D., et al., "Particulate and  POM Emissions  from a Small
       Commercial Stoker-Fired Boiler Firing Several Coals,"  Paper  No.
       76-4.2, 69th Annual Meeting of the Air Pollution Control
       Association, Portland, Oregon, June 1976.

4-38.  Robison, E., "Application of Dust Collectors  to Residual  Oil-Fired
       Boilers in Maryland," Draft, Bureau of Air Quality Control
       Technical Memo, State of Maryland, December 1974.
                                    4-60

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4-39.  Levy, A., et  al.,  "Research Report on a Field Investigation of
       Emissions from  Fuel  Oil  Combustion for Space Heating "
       Battelle-Columbus  Laboratories, American Petroleum Institute
       November 1971.

4-40.  Hall, R.E., et  al.,  "Study of Air Pollutant Emissions from
       Residential Heating  Systems," EPA-650/2-74-003,  NTIS-PB 229 697/AS
       January 1974.                                                     '

4-41   Brown, R.A.,  et al.,  "Feasibility of a Heat and  Emission  Loss
       Prevention  System  for Area Source Furnaces," Acurex Corporation
       EPA-600/2-76-097,  NTIS-PB 253 945/AS, April 1976.

4-42.  Off en, G. R., et al., "Control of Particulate Matter from Oil
       Burners and Boilers," Acurex Corporation,  EPA-450/3-76-005,  NTIS-PB
       258 495/1BE,  April 1976.

4-43.  "Standards  Support and Environmental Impact Statement,  Volume  I:
       Proposed Standards of Performance of Stationary  Open Turbines,"
       EPA-450/2-77-017a, September 1977.

4-44.  Hare, C. T.,  et al.,  ''Exhaust Emissions from Uncontrolled Vehicles
       and Related Equipment Using Internal Combustion  Engines,  Part  6:
       Gas Turbine Electric Utility Power Plants," Southwest Research
       Institute,  Environmental  Protection Agency, February 1974.

4-45.  Dietzmann,  H.E., and Springer, K.J., "Exhaust Emissions from Piston
       and Gas Turbine Engines  Used in Natural Gas Transmission,"
       Southwest Research  Institute, AR-923, January 1974.

4-46.  "Supplement No. 4  for Compilation of Air Pollutant Emission  Factors
       (Second Edition)," U.S.  Environmental Protection Agency,  Office of
       Air and Waste Management, Office of Air Quality  Planning  and
       Standards,  January 1975.

4-47.  Offen, G.R.,  et al.,  "Standard Support and Environmental  Impact
       Statement for Reciprocating Internal Combustion  Engines," Acurex
       Report TR-78-99, Acurex  Corporation, March 1978.

4-48.  Hare, C.T., and Springer, K. J., "Exhaust Emissions from
       Uncontrolled  Vehicles and Related Equipment Using Internal
       Combustion  Engines.   Final Report, Part 5:  Heavy-Duty Farm,
       Construction, and  Industrial Engines," Southwest Research
       Institute,  October 1973.

4-49.  Ketels, P.A., et al., "A Survey of Emissions Control and  Combustion
       Equipment Data  in  Industrial Process Heating," Institute  of Gas
       Technology, Final  Report 8949, October 1976.

4-50.  Richards, J.  and Gerstle, R., "Stationary Source Control  Aspects  of
       Ambient Sulfates:  A Data-Based Assessment," (unpublished draft
       report) EPA Contract No.  68-02-1321, PEDCo Environmental, February
       1976.
                                     4-61

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4-51.  "Development Document for Effluent Limitation Guidelines  and  New
       Source Performance Standards for the Cement Manufacturing Point
       Source Category," EPA-440/l-74-005a, GPO 5501-00866,  NTIS-PB  238
       610/AS, January 1974.

4-52.  Goldish, J., et al., "Systems Study of Conventional Combustion
       Sources in the Iron and Steel Industry," EPA-R2-73-192, NTIS-PB
       226 294/AS, April 1973.

4-53.  Hopper, T.G., et al., "Impact of New Source Performance Standards
       on 1985 National Emissions from Stationary Sources,"  Volume 1,
       Final Report, The Research Corporation of New England, October 1975.

4-54.  "Development Document for Effluent Limitation Guidelines  and  New
       Source Performance Standards for the Steel Making Segment  of  the
       Iron and Steel Manufacturing Point Source Category,"
       EPA-440/l-74-024a, GPO 5501-00906, NTIS-PB 238 837/AS, June 1974.

4-55.  Hunter, S.C., "Application of Combustion Modifications to
       Industrial Combustion Equipment," Proceedings of the  Second
       Stationary Source Combustion Symposium Volume III.  Stationary
       Engine, Industrial Process Combustion Systems, and Advanced
       Processes," EPA-600/7-77-073c NTIS-PB 271 757/7BE, July 1977.

4-56   Hydrocarbon Pollutant Systems Study, Volume 1 — Stationary
       Sources, Effects, and Control," MSA Research Corporation,
       NTIS-PB-219-073, October 1972.

4-57.  Personal communication with R. D. MacLean, Portland Cement
       Manufacturer's Association, January 1977.

4-58.  "Flue Gas Desulfurization Survey July-August 1976," PEDCo
       Environmental, Cincinnati, Ohio, 1976.

4-59.  "The Wet Scrubber Newsletter," No. 2-28, The Mcllvaine Company,
       Northbrook, Illinois, October 31, 1976.

4-60.  FPC News, Vol. 8, No. 23, June 6, 1975.

4-61.  Chaput, L.S., "Federal Standards of Performance for New Stationary
       Sources of Air Pollution, A Summary of Regulations,"  Environmental
       Protection Agency, November 1976.

4-62.  Personal communication with G. McCutchen, Emission Standards  and
       Engineering Division, Office of Air Quality Planning  and Standards,
       Environmental Protection Agency.

4-63.  Habegger, L., "Priorities and Procedures for Development of
       Standards of Performance for New Stationary Sources of Atmospheric
       Emissions," Argonne National Laboratory, EPA-450/3-76-020, May 1976.
                                    4-62

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4-64.   Habegger, L.J., and  Cirillo,  R.R.,  "Priorities  for  New  Source
       Performance Standards," Argonne  National  Laboratory,  APCA  76-21 6
       June 1976.                                                      '  '

4-65.   Federal Register, Volume 42, No.  139,  July 20,  1977.

4-66.   "Petroleum Refinery Fluid  Catalytic  Cracking Unit  Catalyst
       Regenerators," Federal Register,  Part  VI,  June  24, 1977.

4-67.   Personal communication with  D. Bell, Emission Standards  and
       Engineering Division, Office of  Air  Quality Planning  and Standards
       (OAQPS), Environmental Protection Agency.

4-68.   Personal communication with  J. Copeland,  Emission  Standards  and
       Engineering Division, OAQPS, Environmental Protection Agency.

4-69.   Personal communication with  K. Woodard,  Emission Standards and
       Engineering Division, OAQPS, Environmental Protection Agency.

4-70.   Personal communication with  D. Trenholm,  Emission  Standards  and
       Engineering Division, OAQPS, Environmental Protection Agency.

4-71.   Personal communication with  C. Sedman, Emission  Standards  and
       Engineering Division, OAQPS, Environmental Protection Agency.

4-72.  Personal communication with  G. Crane,  Emission  Standards and
       Engineering Division, OAQPS, Environmental Protection Agency.
                                     4-63

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                                  SECTION 5
                            SOURCE ANALYSIS MODEL

       The growth projections  and emissions data of Sections  3  and  4,  used
to generate emissions  inventories,  help to indicate the pollution
potential of sources or  groups of sources.  However,  in those sections,
source rankings based  on  total pollutant emission loading neglected
important factors such as the  total  number of people exposed  and the
ambient level to which they were  exposed.   Therefore,  these and other
factors were incorporated into a  Source Analysis Model (SAM).   This model
was used to more accurately estimate the pollution potential  of a source
and to compare it to other sources.
5.1    SOURCE ANALYSIS MODEL
       This model is based on  the hypothesis that the  impact  of a
particular type of source (e.g.,  tangential coal-fired boilers) is
directly proportional  to:   (1) the  ground-level  concentration of pollutant
species due to a single  source compared to an impact threshold  limit,  (2)
the number of people exposed to that concentration from a single source,
and (3) the total number  of sources  of that type nationwide.  It is
similar to other models  — in  particular,  a model developed by  Monsanto
(Reference 5-1).  The  primary  difference between the SAM and  the Monsanto
model is the way each  treats population exposure and background ambient
pollutant concentration.   The  SAM makes more direct use of available  data
                                     5-1

-------
than other models — particularly for flue gas effluents.   With this
model, simple dispersion calculations for gaseous streams  can  easily be
done.  Liquid and solid effluent streams must be handled more
approximately due to the complicated pathway from source to receptor.
       Section 5.1.1 describes how the model is applied to gaseous
effluent streams and Section 5.1.2 describes how it treats liquid  and
solid streams.  Section 5.2 discusses the data which  is used for the
analyses made in this report.  The results of the analyses are discussed
in Section 5.3, and the implications of the results are discussed  in
Section 5.4.
5.1.1  Gaseous Effluent Streams
       Using the source impact hypothesis described above,  the impact  of
the  gaseous effluent streams from all sources of type i can be defined as
                            IPJ  I  /VXkAdA                  (5-1)
                             j       k  J
where    I.. = impact due to all sources of type i (e.g., bituminous
              coal-fired tangential boilers)
          j = an index identifying each of the individual sources
         P. =  population density near source j
          J
          k = index identifying each pollutant species (e.g., N0?)
        Xjk = ground level concentration of species k due to source j
        XkA = permissible ground level concentration of species k
              (i.e., concentration below which adverse health effects
              are negligible)
         dA = an element of area near the source
                                    5-2

-------
This definition, then, ascribes  a high impact factor to sources that
expose many people to high  pollutant concentrations.  Because detailed
input data are required, a  direct calculation of this factor for all
combustion sources is not warranted for present purposes.   However, the
problem can be made manageable  by approximations.  These approximations
are described as the equation  is discussed,  term by term,  in the rest of
this section.  Point sources are discussed in Section 5.1.1.1 and
distributed sources (e.g.,  residential heaters) are discussed in 5.1.1.2.
A flow chart illustrating the major elements of both calculations is shown
later in Figure 5-5.  The reader may find it useful to refer to this while
reading the following sections.
5.1.1.1  Point Source Calculations
Allowable Concentrations
       The allowable ground level concentrations (Xi,A) can be defined in
several ways.  If the cajculated impacts are to be used for comparing
sources to one another, the concentrations must represent  a consistent set
of  values indicating the relative toxicity of each pollutant.  Because one
                                                                       j,
of  the most current and complete lists of these values is  found in the
Multimedia Environmental Goals,  or MEGs (Reference 5-2), the values found
there, specified as XkMEG,   will be used throughout this report.   These
values represent the assumed maximum permissible concentration of a
chemical species that causes no  adverse health effects in  humans.
       The impact factor is defined here as  proportional to the
ratio xk/XkMEG — that is,  a linear dose-response curve is-assumed.
Although there is evidence  that  the curve may be highly nonlinear in some
cases, the lack of data in  this  area and the increased complication of
                                     5-3

-------
including such details in the assessment justify  defining  the impact
factor as above.
Calculation of Ground Level Concentration
       If reactions between pollutant species  are neglected,  and uniform
topology is assumed, the ground level concentration  of a pollutant issuing
from a point source of gaseous emissions (Xjk) can be  calculated from a
Gaussian plume dispersion formula.  The pollutant emission  rate, the stack
height, and meteorological information are the only  required  inputs.
(See, for example, Reference 5-3).  For the  analyses in  this  report, the
wind: speed (4 m/s) and atmospheric stability class (D)  were assumed
constant for all sources and locations.  These values  represent averages
across the nation and throughout the year.
       Given the meteorological data above and an assumed mixing height of
1500 m, the ground level concentration along the  plume centerline, x^,
normalized with the source emission rate for species k,  Q... ,  can be
plotted as a function of distance from the source as shown  in Figure 5-1.
Each curve represents one value of the stack height, H.  These curves can
be generated easily on a computer and, given the  assumptions  above,
require only stack height as an input parameter.   Actual stack height is
used and the buoyancy effects which cause a  slightly higher effective
emission height are ignored.  Once the ratio X../Q.. is  determined,
the ground-level concentration is found by multiplying the  ratio by the
pollutant emission rate, Q.. .
                          JK
Calculation of the Integral:  Limits of Integration
       To determine the impact factor, the integral
                            Xjk/xkMEG dA                              (5-2)
                                     5-4

-------
                               H = Stack Height, m
                               L = Mixing Height, m
                1                10

                   Distance, km
Figure  5-1.
Ground  level concentration
Gaussian plume.
                      5-5

-------
must be evaluated.  However, this poses two problems.   The first problem
is that in the discussion above, a method for  calculating the plume
center line concentration is given but results  are  not  given for
off-centerline concentrations.  The second problem is  defining the limits
of the integration.
       The problem of off-centerline concentrations  is  solved by assuming
that the ground-level concentration is a function  only  of the distance
from the source, r, and is given by the centerline value  in Figure 5-2.
This assumption  is much the same as the assumption that the wind direction
is random over time.  Using this assumption, the integral  can be given in
the form
                    27T/xkMEG  /   r X1lf (r) dr                       (5-3)
                              a
where the limits of integration, r = a,b are still undefined.   This  form
of the integral was used in the analyses.  It can be quickly evaluated  on
a computer.
       The limits of integration in Equation 5-3 might be defined
practically by integrating over all areas in which the ground  level
concentration exceeds the maximum allowable concentration.  This approach
assumes that concentrations less than the maximum allowable
                 MPf*
concentration, X^   , are not harmful and should not contribute to
the integral.  However, this approach places a large dependence on the
accuracy of the MEG.  To account for possible inconsistencies  in the MEGs,
a safety factor of 10 was used.  Hence, the integral was evaluated over
those regions where X ••> 0.1 X.MES.
                     J K        K
                                    5-6

-------
  •1-3
  X
f
0.1  x
      MEG
              a                            b
                 Distance from source, r
      Figure 5-2.  Limits  of integration for point sources.
                                 5-7

-------
       These limits are shown graphically  in Figure  5-2.   The ground-level
concentration of a particular species, k,  is plotted as  a  function of
distance from the source.  The limits of integration,  a  and  b,  are shown
as the two points at which the ground level concentration  due to  the
source just equals 0.1 XkMEG.  The integration  is performed  over  the
shaded area.
Inclusion of Natural Background
       In many areas, the background concentration of  a  particular
pollutant may approach or exceed the concentration (X-k) due to a single
source.
       Since adding sources  in regions with high existing  background
levels may cause ambient pollutant concentrations which  are  harmful,  the
background, X.  , should be included in the definition  of the impact
factor.  The background is included here by replacing  the  integrand
X-k/XkMEG with (X,k + XkB)/XkMEG.  This approach, although somewhat
conservative, was selected because the plume center line dispersion
calculation was made assuming zero background concentration.  Use of XR  in
the numerator thus compensates for the simplified dispersion calculation.
The modified integrand requires that the limits of integration be modified
                                                               MFP
to allow integration over regions where X-k is  less than 0.1 X|<
criteria, but (Xjk + Xk ) is not.  Accordingly, the  lower  limit of
integration (a)  is defined as the lesser of the distances  at which
either:  (1) xjk = 0.1 XkMEG, or (2) (xjk + XkB) = 0.1 XRMEG and
X-  >0 1 X B
       Similarly, the upper  limit (b) is the larger of the distances that
satisfy the above conditions.  This definition  ensures that  the
integration is  performed over regions where either:
                                    5-8

-------
       1.   The  ground level concentration  due  to  the  source  (x-J exceeds
                                                              J K
           the  impact criteria
       2.   The  resulting ground level concentration (which is the sum of
           X..,  and the background due to other  sources (X    + X B)
            J*                                            jk    k  '
           exceeds the criteria and x,k constitutes a significant
           portion (10 percent) of that concentration
       These criteria are used in the analysis  to define the exposed
impact area. The value of the integral
                                   (Xjk + XkB) r dr                  (5-4)
                               a
between these two limits gives an indication of the impact of pollutant k
from source j.
Impact Parameter
       Just as the integral above indicates the impact of a single
pollutant from a particular source, a sum over pollutant species indicates
the impact (excluding population density effects) due to all pollutants.
Hence, three impact parameters are defined:

                                         b
                IP/  =  £  2^/XkMEG   /   (Xjk) r dr               (5-5)
                         k              a

             IP/  -2  2,/xkMEG  /   (Xjk + XkBR) r dr             (5-6)
                     k
                                      b
             IP.U   =2   2TT/XkMEG   /    (Xjk + Xk  ) r dr          (5-7)
                                    5-9

-------
        RR
where xk   is the average rural background concentration  of species k, and


  Rl I
X,    is the average urban background.  Since  each  single  source



realistically cannot be considered separately and  assigned  an individual



local background concentration and local population  density,  only two



cases are considered:  those in a rural setting  and  those in  an urban



setting.  All sources are included in one of  these categories.



       The first impact parameter, IP. , represents  the impact  of
                                     J

source j in an area in which there is no natural background,  i.e.,  a


                                                            R         U
pristine environment.  The second and third parameters, IP-  and IP. ,
                                                           J        j


represent the impact of the source in a noticeably impacted rural  and an



urban setting, respectively.



Population Density



       At this point, the impact parameters represent  sums  over area



integrals of pollutant concentrations.  The population in the high



concentration area has not been considered.   Because it is  impractical to



multiply the impact parameter for each source  by the local  population



density, only two different values of the density are  used:   a  rural



value, PRS and an urban value, Py.  Classifying each source as  either



rural or urban,  the single source impact factors (for  source  j)  are •


defined as
and
                          IF..R = (PR) x (IP..R)                       (5-8)
                          IFjU = (PU) x (IP..U)                       (5-9)
                                    5-10

-------
       These factors, then, represent  a  measure of the environmental
impact (more specifically, human health  impact) of a single source  such  as
one boiler located in either a rural or  an  urban area.
Total  Impact
       The impact of all sources of the  same type — some urban  and some
rural  ~ can be calculated by

                    IF..1 = (NR) (IFjR) + (Ny) (IF.jU)                (5-10)

where NR and Ny are the number of rural  and urban sources,  respectively.
The average impact of a single source  then  becomes

                         IFjaV9 + IFJT/(NR + V                    (5~11)
       These two numbers (the total impact  factor and  the average source
impact factor) represent numbers by which the impacts  of sources of
different types can be compared.
5.1.1.2  Distributed Sources
       The model described above can also be applied to  distributed
sources — sources such as home furnaces whose  emission  rates are constant
over a large area.  The basic change in  the model is in  the  dispersion
calculation.
       For distributed sources, a model  from Holzworth  (Reference 5-4) is
used which predicts a ground level concentration along the wind direction
as
       Xjk/Qjk = 3.405 x°J15                 x<7312                 (5-12)

       X.UAK = 9.36 + (8.33 x 10"5)  x  - 3535/x    x  >  7312 meters   (5-13)
                                     5-11

-------
where         x = distance from source edge  along  wind  (m)
                                                          o
            X-k = ambient concentration of species k  (g/m ),  due to


                  source type j
                                                         2
            Q.K = source emission rate of species  k  (g/m  •  s),  due


                  to source type j

Here the mixing height and wind speed are the  same as  in the  Gaussian


model.  This predicted concentration profile is shown  in Figure  5-3.   For

this case, the area integral of concentration  can  be put into the form
 MEG  f
t     J    X,-
                                         jk  (x) dx                   (5-14)
where S  x is the maximum length of the source along the wind  direction

and the source area is assumed to be square.  The lower limit  of

integration is defined in the same way as for the point sources; the  upper


limit (b) is equal to S^^.  These limits are shown graphically in

Figure 5-4 where the area for the integration is shown cross-hatched.

       Again, as with point sources, three impact parameters are defined




                 '"/ •  I   We*"6  /  "Jk*                 (
                          i.               Q
                 Tn R     V  c   /  MEG   f  ,        BR\  .          /r
                 l?i  =   /   Smax/xk     J  (Xik + Xk   )  dx         (£
                   J      ^ >   maA  K     ~i    J K     K
                          k               3


                                           b

                 IPiU =   S  W^  /    «X*k +  XkBU) dx        (5-17)
                   J      *—/   lliaA  r>           J l\    H
                          k               a
                                    5-12

-------
in
co
Xjk/Qjk
                                                           X^  =  Ambient concentration of species k
                                                           Q-.  =  Source  emission rate of species k
                                       Distance  from  upwind city  limit
                           Figure 5-3.   Ground-level  concentration -- distributed sources

-------
en
i
      x"EG/Q
                                                         X =  Ambient  concentration
                                                         Q =  Source emission  rate
                                                         x =  Distance from upwind city limit
                                                                                              b = x
                                                                                                   max
                             Figure 5-4.  Limits of integration for distributed sources.

-------
These parameters are sums over  the integrals of each species with
corrections for local background.   They are used to generate total and
average impact factors  in the same way as were the point source impact
parameters.
5.1.1.3  Summary of Air  Impact  Assessment Methodology
       The methodology  described above is summarized in the flow chart of
Figure 5-5.  First, integrals for  the ground level concentration due to a
source are calculated over  the  area in which the concentration due to that
source is appreciable,  accounting  for background concentrations from
natural and all other anthropogenic sources.  These integrals are not
impact factors but indicate the contribution of each species to the total
impact factor.  Next, these single species integrals are summed over all
emitted species to obtain impact parameters.  The impact parameters for
urban and rural sources  are then multiplied by urban and rural population
densities, respectively, to produce single-source impact factors.  The
resulting numbers indicate  the  impact of a single source in a rural or
urban location.  Multiplying these single source factors by the respective
                                                                        ~i
numbers of urban and rural  sources gives the total air impact factor for
sources of the type considered.  Dividing this factor by the total number
of  sources gives the average impact factor for the sources.  The total and
average impact factors  are  the  primary indicators of interest in the
source analysis.
5.1.2  Liquid and Solid  Effluent Streams
       It  is difficult  to evaluate the impact of solid and liquid effluent
streams in as much detail as gaseous streams.  This is primarily because a
large number of variables are involved in dispersion of liquid and solid
                                     5-15

-------
                         Define source pollutant
                         flow rates, Q..
                   Point  source     I Distributed source
        Input source
        stack height

         Input  source
          dimensions
Calculate single species impact
integral from gaussian dispersion
formula


   1 jk = -fe  I 
-------
                              NOMENCLATURE
Q..      Emission rate of species k from source j
 JK




        Ground level concentration of species k due to source j





        Distance from point source along wind direction





        Distance along wind direction for distributed source
S       Total  length of  distributed  source
 max
        Point  source  stack  height




        Mixing height
 Xk      Multimedia  Environmental  Goal  (MEG) for species k (represents

        maximum permissible  concentration)




  BU
 Xi.      Average urban  background  concentration of species k




  RR
 Xk      Average rural  background  concentration of species k





 I-kN    Natural single species  impact  integral





 IjkR    Rural  single species impact  integral





 I-.U    Urban  single species impact  integral
 JK




 IP.N    Natural source impact parameter
  J




 IP-R    Rural  source impact  parameter
  J




 IP.U    Urban  source impact  paramenter






                          Figure 5-5.  Continued





                                   5-17

-------
                              NOMENCLATURE
   p
IF,      Rural  single  source  impact factor
  J



IF.      Urban  single  source  impact factor
  J
PR      Average rural  population  density



PM      Average urban  population  density
IF.     Total  source impact factor
  J
IF.av9  Average source impact factor
  j
N,      Number of sources of type j  in  rural  location
 O



N-      Number of sources of type j  in  urban  location
 J
                         Figure 5-5.  Concluded



                                   5-18

-------
effluents  and certain required  input  data are scarce.  Consequently,  a
more approximate method was used.
       The approach chosen is very similar to the SAM/IA procedure
(Reference 5-5) which uses a rapid screening procedure for assessing  the
impact of  liquid and solid effluent streams.  The procedure, shown
schematically in Figure 5-6, compares the concentration of each species  in
the effluent stream to MATE (Minimum Acute Toxicity Effluent)
concentrations.  The MATE concentrations are one type of Multimedia
Environmental Goal (MEG) derived  by Research Triangle Institute
(Reference 5-6).  They describe approximate threshold concentrations  which
may cause  harmful responses in  humans under acute exposure.
       The assessment procedure compares the concentration of each species
in the effluent stream to the MATE.  The resulting ratio is  termed the
single species hazard factor.   The degree of hazard for each effluent
stream is  defined as the sum of these quantities over all pollutant
species, and the impact factor  for the effluent stream is defined as  the
product of the hazard factor and  the effluent stream flowrate.   (If a
source has more than one effluent stream, the source impact  factor is
defined as the sum of the impact  factors for each liquid or  solid effluent
stream.)
       Finally, the total impact  factor for the source type is defined as
the product of the single source  impact factor and the number of sources.
This total impact factor is used  for source-to-source comparisons.
5.2    DATA REQUIREMENTS
       The effectiveness of the source analysis model in highlighting
potential  environmental problems  and in ranking sources depends totally on
the accuracy of the input data.  Data required for the model include  the
                                     5-19

-------

Determine pollutant concentration
in each effluent stream, C...
J i K
j = source
k =• pollutant
i = stream
_ j_
Compare C... to MATE to determine
J 1 K
hazard factor
„ _ jik
Hjik CikMATE
1
Calculate degree of hazard for
each effluent stream
• •>„ • l V
1
Calculate stream impact factors
FJI • 
-------
                              NOMENCLATURE
       cjik   Concentration of pollutant species k  in effluent stream
              i  of source j
       Njik   Hazard factor
       Oj-j     Degree of hazard for effluent  stream  i of source j
       Qji     Flow rate of effluent  stream i of source j (g/s)
              Stream impact factor
              Single source impact factor
              Total source impact factor
                          Figure  5-6.   Concluded
effluent stream  flow  rate for each  pollutant,  source  characteristics such
as discharge rate  and stack  height,  population exposure to specific source
types in urban and  rural  areas and  ambient  background pollutant
concentrations.  This section discusses  the sources used for obtaining
input data.
5.2.1  Emission  Rates
       Emission  factors were compiled  in Section  4.1  for specific
equipment/fuel types.  The effluent  stream  pollutant  concentrations
required for the Source Analysis Model were based directly on these data.
Tabular summaries of  the  emission factors are  given in Section 4.1.
5.2.2  Point Source Stack Heights
       Stack heights  of stationary  sources  were obtained by three
methods.  First, stack heights of utility boilers were obtained from
statistics of the power industry (Reference 5-7). Stack heights for oil-,
gas-, and coal-fired  boilers were obtained  statistically from a large set
                                     5-21

-------
of data and are felt to be of highest quality.   Next,  stack  heights for
packaged boilers were obtained from related  survey  documents  (References
5-8, and 5-9).  The accuracy of this data  is only fair,  since the packaged
boiler sector is made up of widely varying equipment types and
applications, therefore stack heights vary.  Stack  heights for the
remaining sectors came from both trade and industry associations  as well
as government agencies (References 5-10 through  5-16).
5.2.3  Urban/Rural Air Quality Control Regions (AQCRs)
       The population densities in the source vicinity needed for the
impact factor calculation (Equation 5-8, 5-9) were  estimated  by
classifying each Air Quality Control Region  (AQCR)  into  one of the
following three categories:
       •   Urban AQCRs -- AQCRs containing a Standard Metropolitan
           Statistical Area (SMSA) with population  greater than 700,000
                                                              o
           and population density greater than 50 people/(km)
       •   Rural AQCRs — AQCRs having a population density less  than
                         •j
           50 people/(km) , containing no SMSAs  with a population of
           more than 700,000
       •   Mixed AQCRs — AQCRs having large urban  and rural  sections.
           For example, AQCR 217 (San Antonio) has  a population density of
           15 people/(km)2, with an SMSA population of greater than
           700,000.  In such an AQCR, the SMSA is considered  urban and  the
           rest of the area is considered rural.
Information sources used for this categorization include:
       •   EPA — Air Quality and Emission Trends Annual Report —
           population and land areas of AQCRs (Reference 5-17)
       t   Bureau of Census — land area of  SMSAs (Reference  5-18)
                                    5-22

-------
      0    Bureau of Census — Statistical  Abstract -- populations of
          cities and SMSAs and future  population projections  (Reference
          5-19)
Figure 5-7 displays the AQCR categorization.   Although only 20 percent of
the AQCRs are urban, these represent  50 percent of the national population.
5.2.4  Urban/Rural Equipment Splits
      Stationary combustion sources  were grouped according to urban and
rural locations using National Emissions Data System (NEDS) (Reference
5-20) fuel consumption data.  The  amount of fuel consumed in each AQCR was
determined for each equipment type.   Then,  these AQCR fuel consumptions
were grouped into categories representing urban and rural areas (AQCRs).
The urban/rural equipment split was assumed equal to the urban/rural fuel
split.  For mixed urban/rural AQCRs,  the equipment population was prorated
by the proportion of the population in  the  urban area (SMSA) and the rural
area of the AQCR.
5.2.5  Urban and Rural Ambient Pollutant Concentrations
      In accordance with the Clean Air Act,  ambient air quality data
resulting from air monitoring operations of state, local, and federal
networks must be reported each calendar quarter to the Environmental
Protection Agency.  The EPA Storage and Retrieval of Aerometric Data
(SAROAD) system is the repository  for these data.  EPA periodically
publishes summaries of all data submitted and these summaries are
available to the  public upon request.   The  summaries were used in the
Source Analysis Model for background  concentrations of criteria.
Pollutants,  and most noncriteria pollutants (Reference 5-21 through 5-27).
      Trace element values not reported from SAROAD were obtained from
current  published reports (Reference  5-28 through 5-33).  Since these data
                                   5-23

-------
01
I
ro
                 Population Densities [people/(km )]


                        >50 — urban AQCR.



                        <50 with large urban area -- mixed AQCR.




                        <50 without large urban area -- rural AQCR.

-------
are generally for  isolated  geographical  areas,  the overall  data quality on



a national basis is poor.



5.2.6  Average Source Fuel  Consumption



       Average fuel consumptions  for  utility boilers were obtained  for



each firing type and fuel from  analysis  of FPC-67 tapes.   These values



were used to determine  the  total  number  of sources in each  equipment



sector (References 5-34 and 5-35).  Average fuel  consumptions  for packaged



boiler equipment types  came from  recent  EPA documents (References 5-36  and



5-37).  The packaged boiler data  are  not as accurate as the utility data,



since this sector  is large  and  varied.   Consumption data  for the remaining



combustion sources were obtained  from both published data,  trade, and



industrial associations and government  agencies (References 5-38 through



5-44).  These values are of fair  quality.   The  size ranges  of  most  of



these equipment types are large,  and  thus  it is difficult to define an



average value.



5.3    SOURCE ANALYSIS  MODELING RESULTS



       Relative rankings of the pollution  impact potential  of  stationary



combustion sources are  given in this  subsection for gaseous, and liquid



and  solid effluents.  Pollution impact  potentials were evaluated for the



criteria pollutants  —  N0v, SOV,  CO,  HC, and particulates — as well
                          X     A


as sulfates, trace metallic*,  POMs  and  trace elements.  Separate rankings



are  given for gaseous pollutants  and  for liquid and solid pollutants.



Pollution impact potential  is  also  projected to 1985 and 2000.  The



rankings in this section are based  on the low nuclear reference energy



projection scenario  described  in  Section 3.4.1.
                                     5-25

-------
5.3.1  Gaseous Pollution Potential Rankings



       A ranking of gaseous pollution potential for the  30 most



significant sources in 1974 is given in Table 5-1.  The  "total  impact



factor" shown in the final column of the table is the composite  impact



factor (defined in Section 5.1.1) for all gaseous species included  in the



emissions inventory.  Thus, to rank a specific equipment type, the



following were considered:  (1) emission rates and effluent  toxicity, (2)



total number of sources installed nationwide, (3) ambient background  near



each source, and (4) the population exposed to each effluent  from that



equipment type in urban and rural areas.



       Table 5-2 ranks sources on the basis of the "average  source  impact



factor," defined in Section 5.1.1 as the total impact factor  divided  by



the  total number of sources (both urban and rural).  This impact factor



includes the same four considerations described for the  total pollution



potential factor of Table 5-1.  Comparing Table 5-2 to Table  5-1 shows



whether  a high impact factor  is the result of many "moderately dirty"



sources  or only a few "very dirty" sources.



       Table 5-3 lists the 30 sources with the highest NO  pollution
                                                         /\


potential.  The impact factors on this table are the single  pollutant



impact factor for NO  described in Section 5.1.1.  They  exclude
                    J\


background concentrations, population densities and total number of



sources.  A high ranking indicates a large area (urban or rural) exposed



to high  NO  levels from a single source.
          A


       Because the future growth of each source type is  a major



consideration in developing effective control priorities, the total



pollution potential rankings of stationary sources for 1985  and  2000  are



given  in Tables 5-4 and 5-5, respectively.  The cross rankings  in  1985 and
                                    5-26

-------
                                 TABLE 5-1.   TOTAL POLLUTION POTENTIAL  RANKING (GASEOUS)
                                              STATIONARY  SOURCES IN YEAR 1974
ro
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Sector
Packaged Boilers
Packaged Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Packaged Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Utility Boilers
Packaged Boilers
Equipment Type
Stoker Firing WTC <29 MWa
Stoker Firing FTd <29 MWa
Tangential
Wall Firing
Wall Firing WTC >29 MWa
Stoker Firing WT0 <29 MWa
Vertical & Stoker
Cyclone
Horizontally Opposed
Tangential
Wall Firing
Horizontally Opposed
Wall Firing WT0 >29 MWa
Scotch FTd <29 MWa
Firebox FTd <29 MWa
Tangential
Scotch FT*1
Fuel
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Oil
Oil
Oil
on
Oil
Oil
Gas
Gas
Total Impact Factor
6.73 x 1011
5.59 x 1011
1.42 x 1011
1.09 x 1011
7.78 x 1010
7.64 x 1010
5.69 x 1010
4.12 x 1010
2.10 x 1010
2.65 x 109
2.22 x 109
1.13 x 109
7.02 x 108
5.50 x 108
3.64 x 108
3.20 x 108
2.88 x 108
              aHeat Input
              bHeat output
              cHatertube
              dFiretube

-------
                                                          TABLE 5-1.   Concluded
01
I
ro
Co
Rank
18
19
20
21
22
23
24
25
26
27
28
29
30
Sector
Ind. Process Comb.
Reciprocating 1C
Engines
Packaged Boilers
Packaged Boilers
Packaged Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Ind. Process Comb.
Packaged Boilers
Gas Turbines
Ind. Process Comb.
Equipment Type
Coke Oven Underfire
SIe >75 kW/cylb
Single Burner WT0 <29 MWa
HTR Boiler <29 MWa
Brick & Ceramic Kilns
Horizontally Opposed
Wall Firing
Cyclone
Wall Firing WTC >29 MWa
Cement Kilns
Cast Iron
Simple Cycle >15 MWb
Refinery Htr. Nat. Draft
Fuel
Processed Material
Gas
Oil
Oil
Processed Material
Gas
Gas
Oil
Gas
Processed Material
Oil
Oil
Gas
Total Impact Factor
2.84 x 108
2.3 x 108
2.28 x 108
2.25 x 108
2.01 x 108
1.61 x 108
1.28 x 108
1.27 x 108
2.72 x 107
2.71 x 107
2.47 x 107
2.39 x 107
2.22 x 107
                "Heat input


                bHeat output


                cWatertube


                dFiretube


                eSpark ignition

-------
                            TABLE 5-2.   AVERAGE SOURCE  POLLUTION  POTENTIAL RANKING  (GASEOUS)

                                         STATIONARY SOURCES IN YEAR  1974
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Sector
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Utility Boilers
Packaged Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Equipment Type
Horizontally Opposed
Cyclone
Tangential
Wall Firing
Wall Firing WTC >29 MWa
Stoker Firing WTC <29 MWa
Stoker Firing WTC <29 MWa
Vertical and Stoker
Stoker Firing FTd <29 MWa
Horizontally Opposed
Tangential
Cyclone
Wall Firing
Horizontally Opposed
Wall Firing WTC >29 MWa
Wall Firing
Tangential
Cyclone
Fuel
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Oil
Oil
Oil
Oil
Oil
Oil
Gas
Gas
Gas
Average Impact Factor
4.26 x 108
3.52 x 108
3.11 x 108
1.76 x 108
1.21 x 108
8.45 x 107
8.35 x 107
7.34 x 107
2.29 x 107
1.52 x 107
1.39 x 107
3.27 x 106
2.21 x 106
1.76 x 106
7.71 x 105
2.49 x 105
1.54 x 105
9.55 x 104
en
i
PO
10
             aHeat input


             bHeat output


             °Watertube


             dF1retube

-------
                                                     TABLE  5-2.   Concluded
tn
 I
CO
O
Rank
19
20
21
22
23
24
25
26
27
28
29
30
Sector
Gas Turbines
Ind. Process Comb.
Ind. Process Comb.
Gas Turbines
Packaged Boiler
Packaged Boiler
Ind. Process Comb.
Ind. Process Comb.
Ind. Process Comb.
Packaged Boilers
Ind. Process Comb.
Packaged Boilers
Equipment Type
Simple Cycle >15 MWb
Refinery Htr. Nat. Draft
Refinery Htr. Forced Draft
Simple Cycle >15 MWb
Wall Firing WTC >29 MWa
Single Burner WTC <29 MWa
Refinery Htr. Forced Draft
Refinery Htr. Nat. Draft
Coke Oven Underfire
Scotch FTd <29 MWa
Cement Kilns
Scotch FTd <29 MWa
Fuel
Oil
Oil
Oil
Gas
Gas
Oil
Gas
Gas
Processed Material
Gas
Processed Material
Oil
Total Impact Factor
8.70 x 104
6.60 x 104
5.81 x 104
5.80 x 104
5.26 x TO4
3.21 x 104
2.73 x 104
2.09 x 104
1.92 x 104
1.26 x 104
1.?4 x 104
1.20 x 104
                 Heat input


                bHeat output


                °Watertube
                                                                                                                     T-621
                 Firetube

-------
                                         TABLE 5-3.   N0xe POLLUTION POTENTIAL  RANKING
                                                       STATIONARY SOURCES IN  1974
en
i
CO
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Sector
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Gas Turbines
Gas Turbines
Ind. Process Comb.
Equipment Type
Cyclone
Horizontally Opposed
Horizontally Opposed
Horizontally Opposed
Cyclone
Tangential
Horizontally Opposed
Tangential
Tangential
Wall Firing
Tangential
Wall Firing
Wall Firing
Cyclone
Simple Cycle >15 MWb
Simple Cycle >15 MWb
Refinery Htr. Forced Draft
Fuel
Bituminous
Lignite
Gas
Bituminous
Lignite
Bituminous
Oil
Lignite
Gas
Lignite
Oil
Bituminous
Gas
Gas
Oil
Oil
Oil
NOX Impact Factor
4.97 x 109
3.40 x 109
2.80 x 109
2.78 x 109
2.44 x 109
9.82 x 108
9.21 x 108
8.22 x 108
3.79 x 108
2.88 x 108
2.55 x 108
2.43 x 108
2.30 x 108
1.37 x 108
1.24 x 108
1.24 x 107
5.14 x 107
                  Heat input
                  Heat output
                  cWatertube
                  dFiretube
                                                                                                               TOT
                  ENO, basis

-------
                                                        TABLE 5-3.   Concluded
CO
ro
Rank
18
19
20
21
22
23
24
25
26
27

28

29
30

Sector
Utility Boilers
Utility Boilers
Ind. Process Comb.
Packaged Boilers
Packaged Boilers
Ind. Process Comb.
Packaged Boilers
Ind. Process Comb.
Packaged Boilers
Reciprocating 1C
Engines
Reciprocating 1C
Engines
Packaged Boilers
Reciprocating 1C
Engines
Equipment Type
Wall Firing
Cyclone
Refinery Htr. Nat. Draft
Wall Firing WT0 >29 MWa
Wall Firing WTC >29 MWa
Refinery Htr. Forced Draft
Wall Firing WTC >29 MWa
Refinery Htr. Nat. Draft
Stoker Firing WTC >29 MWa
CIe >75 kW/cylb

SIf >75 kW/cylb

Stoker Firing WTC <29 MWa
CIe >75 kW/cylb

Fuel
Oil
Oil
Oil
Oil
Bit./Lig. Coal
Gas
Gas
Gas
Bit./Lig. Coal
Oil

Gas

Bit./Lig. Coal
Dual (Oil + Gas)

NO Impact Factor
4.81 x 107
4.07 x 107
3.89 x 107
2.59 x 107
2.59 x 107
2.45 x 107
2.25 x 107
1.26 x 107
6.00 x 106
4.09 x 106

3.51 x 106

2.47 x 106
1.97 x 104

               aHeat  input
                Heat  output
               :Watertube
                Firetube
               Compression ignition
                Spark  ignition

-------
                                 TABLE  5-4.   TOTAL  POLLUTION POTENTIAL RANKING (GASEOUS)
                                              STATIONARY SOURCES  IN  YEAR 1985
en
CO
oo
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Sector
Packaged Boilers
Packaged Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Packaged Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Utility Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Equipment Type
Stoker Firing WTC <29 MWa
Stoker Firing FTd <29 MWa
Tangential
Wall Firing
Vertical and Stoker
Wall Firing WTC >29 MWa
Stoker Firing WTC >29 MWa
Horizontally Opposed
Cyclone
Tangential
Wall Firing
Wall Firing WTC >29 MWa
Horizontally Opposed
Scotch FTd <29 MWa
Firebox FTd <29 MWa
Scotch FTd <29 MWa
Single Burner WTC <29 MWa
Fuel
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Oil
Oil
Oil
Oil
Oil
Oil
Gas
Oil
Total Impact Factor
4.19 x 1011
3.48 x 1011
3.04 x 1011
2.34 x 1011
5.00 x 1010
4.84 x 1010
4.76 x 1010
4.55 x 1010
3.69 x 1010
2.31 x 109
1.05 x 109
1.04 x 109
9.83 x 108
8.24 x 108
5.46 x 108
3.87 x 108
3.43 x 108
               dHeat input
               bHeat output
               cWatertube
               dFiretube
                                                                                                           T-614

-------
                                                               TABLE  5-4.   Concluded
CO
Rank
18
19
20
21
22
23
24
25
26
27
28
29
30
Sector
Packaged Boilers
Ind. Process Comb.
Ind. Process Comb.
Utility Boilers
Reciprocating 1C
Engines
Utility Boilers
Utility Boilers
Packaged Boilers
Ind. Process Comb.
Gas Turbines
Ind. Process Comb.
Reciprocating 1C
Engines
Gas Turbines
Equipment Type
HRT Boilers <29 MWa
Coke Oven Underfire
Brick and Ceramic Kilns
Cyclone
SIe >75 kW/cylb
Horizontally Opposed
Wall Firing
Cast Iron Boilers
Cement Kilns
Simple Cycle >15 MWb
Refinery Htr. Nat. Draft
CIf >75 kW/cylb
Simple Cycle >15 MWb
Fuel
Oil
Processed Mat'l
Processed Mat1 1
Oil
Gas
Gas
Gas
Oil
Processed Mat'l
Oil
Gas
Oil
Gas
Total Impact Factor
3.38 x 108
3.15 x 108
2.23 x 108
1.13 x 108
1.08 x 108
9.48 x 107
8.30 x 107
3.73 x 107
3.00 x 107
2.67 x 107
2.45 x 107
2.26 x 107
1.81 x 107
                      Heat  input
                     bHeat  output
                     cWatertube
                     dFiretube
                     eSpark ignition
                      Compression ignition
                                                                                                                              T-614

-------
                                 TABLE 5-5.  TOTAL POLLUTION  POTENTIAL RANKING (GASEOUS)

                                              STATIONARY SOURCES IN YEAR 2000
01
i
CO
en
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Sector
Packaged Boiler
Packaged Boiler
Utility Boilers
Utility Boilers
Packaged Boilers
Packaged Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Ind. Process Comb.
Packaged Boilers
Equipment Type
Stoker Firing WTC <29 MWa
Stoker Firing FTd <29 MWa
Tangential
Wall Firing
Wall Firing WTC >29 MWa
Wall Firing WTC >29 MWa
Horizontally Opposed
Vertical and Stoker
Cyclone
Tangential
Wall Firing
Horizontally Opposed
Wall Firing WTC >29 MWa
Scotch FTd <29 MWa
Firebox FTd <29 MWa
Coke Oven Under fire
HRT Boilers <29 MWa
Fuel
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Oil
Oil
Oil
Oil
Oil
Oil
Processed Mat'l
Oil
Total Impact Factor
6.59 x 1011
5.47 x 1011
4.46 x 1011
3.43 x 1011
7.62 x 1010
7.48 x 1010
6.66 x 1010
4.13 x 1010
2.70 x 1010
3.85 x 109
3.32 x 109
1.62 x 109
1.28 x 109
1.02 x 109
6.78 x 108
4.25 x 108
4.19 x 108
               dHeat input


               bHeat output


               cWatertube


               dFiretube

-------
                                                           TABLE  5-5.   Concluded
Ol
 I
oo
cr>
Rank
18
19
20
21
22
23
24
25
26
27
28
29
30
Sector
Packaged Boilers
Packaged Boilers
Ind. Process Comb.
Utility Boilers
Packaged Boilers
Reciprocating 1C
Engines
Ind. Process Comb.
Gas Turbines
Gas Turbines
Reciprocating 1C
Engines
Ind. Process Comb.
Ind. Process Comb.
Ind. Process Comb.
Equipment Type
Single Burner WTC <29 MWa
Scotch FTd <29 MWa
Brick and Ceramic Kilns
Cyclone
Cast Iron Boilers
SIe >75 kW/cylb
Cement Kilns
Simple Cycle >15 MWb
Simple Cycle >15 MWb
CIf >75 kW/cylb
Refinery Htr. Nat. Draft
Open Hearth Furnaces
Refinery Htr. Nat. Draft
Fuel
Oil
Gas
Processed Mat'l
Oil
Oil
Gas
Processed Mat'l
Oil
Gas
Oil
Gas
Processed Mat'l
Oil
Total Impact Factor
4.15 x 108
3.90 x 108
3.00 x 108
9.34 x 107
4.63 x 107
4.55 x 107
4.04 x 107
3.82 x 107
3.41 x 107
3.03 x 107
2.98 x 107
2.41 x 107
1.89 x 107
                   Heat  input


                  bHeat  output


                  cWatertube


                  dFiretube


                  eSpark ignition


                   Compression ignition

-------
2000 of the 30 highest stationary sources in 1974 are summarized  in  Table
5-6, showing changes  in ranking  for  these years.
       Trends in pollution  potential  through the  year 2000 are  presented
for the three major fuels for  the reference, conservation,
electrification, and  synthetics  scenarios in Appendix H  of Volume  II.  The
tables for each scenario are given as follows:
       •   Reference  high nuclear:   Figures  H-l to H-5
       •   Reference  low nuclear:   Figures H-6 to H-10
       •   Conservation:  Figures H-ll to H-15
       •   Electrification:  Figures  H-16 to H-20
       9   Synthetics:  Figures  H-21  to H-25
These trends are based on the  total  impact factor (Equation 5-10) which
considers all sources nationwide,  ambient pollutant backgrounds, and the
exposed population.
       Finally, Tables 5-7  through 5-9 summarize  single  source  pollution
potentials for each pollutant, equipment, fuel combination considered in
this assessment.  These potentials are based on single pollutant impact
factors that consider ambient  pollutant backgrounds but  exclude exposed
population densities  and total equipment  population.   In these  tables,
pollutants are denoted by XXX  if  they have a high pollution potential or
single species impact factor in  a region  with no  natural background.
Pollutants which have high  concentrations only when emitted into regions
already containing typical  rural  or  urban background levels are denoted by
XX and X, respectively.
5.3.2  Liquid and Solids Pollution Potential Ranking
       Few data are available  to  assess the  pollution potential of solid
and liquid effluent streams.   In  fact, the only liquid and solid emission
                                     5-37

-------
                                  TABLE  5-6.   TOTAL POLLUTION POTENTIAL  CROSS RANKING  (GASEOUS)
                                               STATIONARY  SOURCES IN YEAR 1974
en
i
oo
CO
1974
Ranking
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Sector
Packaged Boilers
Packaged Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Packaged Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Packaged Boilers
Packaged boilers
Utility Boilers
Packaged Boilers
Equipment Type
Stoker Firing WTC <29 MWa
Stoker Firing FTd <29 MWa
Tangential
Wall Firing
Wall Firing WTC >29 MWa
Wall Firing WTC >29 MWa
Vertical and Stoker
Cyclone
Horizontally Opposed
Tangential
Wall. Firing
Horizontally Opposed
Wall Firing WTC >29 MWa
Scotch FTd <29 MWa
Firebox FTd <29 MWa
Tangential
Scotch FTd <29 MWa
Fuel
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Oil
Oil
Oil
Oil
Oil
Oil
Gas
Gas
1985
Ranking
1
2
3
4
6
7
5
9
8
10
11
13
12
14
15
>30
16
2000
Rank ing
1
2
3
4
5
6
8
9
7
10
11
12
13
14
15
>30
19
                Heat input


                bHeat output


                cWatertube

                dFiretube

-------
                                                            TABLE 5-6.   Concluded
OJ
1974
Ranking
18
19
20
21
22
23
24
25
26
27
28
29
30
Sector
Ind. Process comb.
Reciprocating 1C
Engines
Packaged Boilers
Packaged Boilers
Ind. Process Comb.
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Ind. Process Comb.
Packaged Boilers
Gas Turbines
Ind. Process Comb.
Equipment Type
Coke Oven Underfire
SIe >75 kW/cylb
Single Burner WTC<29 MWa
HRT Boilers
Brick and Ceramic Kilns
Horizontally Opposed
Wall Firing
Cyclones
Wall Firing WTC >29 MWa
Cement Kilns
Cast Iron Boilers
Simple Cycle >15 MWb
Refinery Htr. Nat. Draft
Fuel
Processed Mat'l
Gas
Oil
Oil
Processed Mat'l
Gas
Gas
Oil
Gas
Processed Mat'l
011
Oil
Gas
1985
Ranking
19
22
17
18
20
23
24
21
>30
26
25
27
28
2000
Ranking
16
23
18
17
20
>30
>30
21
>30
24
22
25
28
                   aHeat Input
                   bHeat output
                   cWatertube
                   dF1retube
                   eSpark Ignition
                    Compression Ignition
                                                                                                                          T-616

-------
                              TABLE 5-7.   UTILITY BOILERS  -- POLLUTION  POTENTIAL OF SINGLE  POLLUTANTS
Equipment


Tangential




Wall Firing




Cyclone



Vertical & Stoker

Fuel
Bituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Bituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Bituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Anthracite
Bituminous
Lignite
NOX
X

XX
XX
XXX
X
X
X
X
XXX
XXX
XX
X

XXX



S0x
XXX
XX
XXX
X

XXX

X


XXX
XX
X





HC


















CO


















Part.
XXX
XXX









XXX






so3


















POM


















Ba


















Be
XXX
XXX



XXX
XXX



XXX
XXX



XXX
XXX
XXX
B


















Cr
XX
X
XXX




X


XXX
XX
X





Co


















Cu


















Pb


















Mn


















Hg


















Mo


















Ni


XXX




XXX




XXX





V


XXX









XXX





Zn


















Zr


















As


















Bi


















Al
XXX
XXX








XXX
XXX






Sb


















Cd


















Se


















P


















Sr


















in
i
        XXX -- Pristine environment
        XX — Rural environment
         X — Urban environment

-------
                            TABLE  5-8.   PACKAGED BOILERS  — POLLUTION POTENTIAL OF SINGLE  POLLUTANTS
XXX --  Pristine environment
 XX —  Rural environment
  X --  Urban environment
alJatertube
bFiretube
cHeat. input
Equipment

Wall Firing WTa


Stoker .Firing WTa
>29 HWC
Single Burner WTa
<29 HWC


K
Scotch FTn


h
Firebox FTD


Stoker Firing WTa
<29 MWC

Stoker Firing FTb


HRT Boiler

Fuel
lituminous/
Lignite
Residual Oil

Bituminous/
Lignite
Residual Oil


Distillate Oil
Natural Gas
Process Gas
Residual Oil

Disti'Hate Oil
Residual Oil

Anthracite
Bituminous/
Lignite
Anthracite
Bituminuous/
Lignite
Distillate Oil
Residual Oil

NOX
X

X



X




X






X





j 	 „
S0x
XXX

X

XXX

X





X


X


XXX

XXX


X

HC








CO









































Part.


















XXX

XXX




so3













	










POM









XXX
XXX
XXX
XXX

XXX
8a















XXX |
1


X
X

XXX
XXX









Be
XXX



XXX












XXX
XXX
XXX
XXX




T1




Cr












X




j
x



1
1
j XXX







XXX
XXX





r, "[ 	
Co j Cti
f'h 1 Mn I HgT Mo
JL 1... ...J _.
!

X
	








	












~




























" ~l




































































Ni


XXX



ixxx
1
1















._ 	



XXX


XXX







XXX

V






XXX


















Zn

























Zr

























As






















1


Si

























Al


















XXX






Sb

























Cd

























Se

























P
























Sr























•»
u>
CVJ
1
























-------
                     TABLE  5-9.   GAS TURBINES, RECIPROCATING  1C ENGINES,  AND INDUSTRIAL  PROCESS HEATING -•
                                   POLLUTION  POTENTIAL  OF SINGLE  POLLUTANTS
Equipment
Simple Cycle
>15 MWa
Compression Ignition
>75 kW/cyld
Spark Iqnition
>75 kW/cyl
Coke Oven Underfire
Brick & Ceramic Kilns
Refinery Heaters --
Natural Draft
Refinery Heaters --
Natural Draft
tefinery Heaters --
Forced Draft
tefinery Heaters --
Forced Draft
Fuel
Distillate Oil
Natural Gas
Distillate Oil
Dual (Oiland Gas)
Natural Gas
Processed Material
Processed Material
Gas
Oil
Gas
Oil
NOX
XXX
XXX
XXX
XXX
XXX


XXX
XXX
XXX
XXX
S0x
XXX





XXX

XXX
HC









CO









Part.
XXX


XXX
XXX

XXX

XXX
so3









POM









Ba









Be









B









Cr









Co









Cu









Pb









Mn









Hg









Mo









Ni









V









Zn









Zr









As









Bi









Al









Sb









Cd









Se









P









Sr









cn
     XXX — Pristine environment
     XX — Rural environment
      X — Urban environment
     Heat output

-------
streams  which have been characterized  to  any extent are the ash discharge
streams  of utility and large  industrial  boilers.   Although these sources
are the  only ones considered  in  this  assessment,  they account for well
over 90  percent of all combustion-generated solid and liquid wastes.
       Table 5-10 lists solid  and  liquid  impact parameters (as described
in Section 5.1.2).  These  impact parameters indicate the degree of hazard
within each effluent stream.   They are obtained by comparing the
concentration of each species  in the  effluent stream to a specific MATE.
The sum of the ratios for  all  pollutants  in the effluent stream is then an
indication of the unit pollution potential  of each effluent stream.
       The ranking of pollution  potential  from liquid and solid effluent
streams is given in Table  5-11.  This  ranking is  based on total impact
fators that reflect the toxicity of the  effluent  for a particular boiler
type, and the total quantity  of  emissions  (as defined in Section 5.1.2).
            TABLE 5-10.  POLLUTION PARAMETERS (LIQUID AND SOLID)
                         STATIONARY SOURCES IN YEAR 1974

Anthracite coal
Bituminous coal
Lignite coal
Residual oil
Distillate oil
Natural gas
Bottom Ash
(solid)
0=045
0.139
0.119
0.496
0
0
Bottom Ash
(slurry)
0.000024
0.000015
0.000014
0.000012
0
0
Flvash
(solid)
0.051
0.112
0.082
0.723
0
0
                                     5-43

-------
    TABLE 5-11.   TOTAL POLLUTION POTENTIAL  RANKING (LIQUID AND SOLID)
                  STATIONARY SOURCES  IN  YEAR 1974
Rank
1
2
3
4
5
6
7
8
9
10
11
12
Sector
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Utility Boilers
Packaged Boilers
Utility Boilers
Packaged Boilers
Utility Boilers
Utility Boilers
Equipment Type
Tangential
Wall Firing
Tangential
Wall Firing
Cyclone
Stoker Firing WTb >29 MWa
Horizontally Opposed
Wall Firing WTb >29 MWa
Horizontally Opposed
Wall Firing WTb >29 MWa
Cyclone
Vertical and Stoker
Fuel
Coal
Oil
Oil
Coal
Coal
Coal
Oil
Oil
Coal
Coal
Oil
Coal
Total Impact Factor
621 x 1012
472 x 1012
468 x 1012
357 x 101Z
349 x 1012
191 x 1012
189 x 1012
114 x 1012
101 x 1012
53 x 1012
52 x 1012
29 x 1012
                                                                   T-865
 Heat input
uWatertube

-------
These factors are obtained  by multiplying the impact parameters for

specific effluent streams by  the  respective single source effluent stream

flow rate and the total  number of sources nationwide.

5.4    CONCLUSIONS

       In this study,  a  Source Analysis Model was developed to identify

and rank potential environmental  problems due either to specific

pollutants from a single effluent stream or from the entire source.   The

model can indicate impact potential  either for a single source or  the

nationwide aggregate of  sources considering population  proximity to  the

source.  This model will  be used  during the NO  Control Environmental
                                               /\

Assessment Program to  screen  potential  problems and evaluate control

options as detailed multimedia emissions data become available from  the

field test programs of the  EPA and other agencies.   For the present  study,

available data for use in the model  were compiled for  source emissions,

human health  impact threshold criteria, population  densities near  the

sources, and  emission  growth  rates.   Although these data are not as

complete as desired, they were used  with the SAM model  to obtain a

tentative indication of  potential problem areas.  The  following list

summarizes capabilities  of  the SAM model and notes  specific cases  which

were run in this study:
            Source Analysis
          Model Capabilities                        Test_Cases

   0  Total nationwide  impact        — Total gaseous effluent stream
      factors for specific              pollution potential  ranking for
      source types,  considering         1974 (Table 5-1)
      population exposure and all
      pollutants inventoried  for     — Average gaseous effluent stream
      gaseous effluent  streams          pollution potential  ranking for
                                         1974 (Table b-2)
                                     5-45

-------
            Source Analysis
          Model Capabilities

   •  Total nationwide impact
      factors for all pollutants
      inventoried for liquid and
      solid effluent streams

   »  Projections of total nation-
      wide impact factors
   •  Single source, single
      pollutant impact not
      considering population
      exposure
           Test Cases

Total liquid and solid effluent
stream pollution potential ranking
for 1974 (Table 5-11)
Total gaseous effluent stream
pollution potential ranking for
1985 and 2000 (Tables 5-4, 5-5)

Total gaseous effluent stream
pollution potential cross ranking
for 1974, 1985 and 2000 (Table 5-6)

NOX single source pollution
potential ranking for stationary
sources (Table 5-3)

Pollution potential of single
pollutants from utility boilers,
packaged boilers, gas turbines,
1C engines and industrial process
heating (Tables 5-7 to 5-9)
Additional impact factor results are tabulated in Appendices F, G, and H

of Volume II.

       Although the impact factor results generated in this study are

useful for detecting gross qualitative trends, firm quantitative

conclusions are precluded by inadequacies in the data and the uncertainties

in projected energy usage.  Key data needs are as follows:

       •   Multimedia source emissions data

           —  Most of the noncriteria pollutant emissions data are for

               compound classes or sample fractions; species

               concentrations are needed for compound classes showing

               pollution potential
                                   5-46

-------
—  POM and trace element data are sparse and exhibit  large
    scatter from different samplings.  Emissions of these
    pollutants are highly dependent on the origin of the fuel
    and the specific stationary source and effluent stream from
    which the data were obtained.
—  Data on emissions during transient or nonstandard  operation
    are virtually nonexistent.  New tests are needed if these
    effects are to be considered.
—  Liquid and solid emissions data are only quantified for the
    utility and large industrial  boiler equipment sector.
    Although this sector represents the major portion of liquid
    and solid pollution  potential,  further study of packaged
    boilers and industrial  process  heating effluent streams
    should be pursued.   In  addition,  the  fractions  of total ash
    which are emitted as bottom ash and flyash vary from boiler
    type to boiler type.  However,  sufficient data  were not
    available to estimate this effect.
Health impact threshold  criteria
—  The Multimedia Environmental  Goals (MEGs) are preliminary,
    and for screening purposes only-   They are not  ambient
    standards, but rather indications of ambient concentrations
    at which health effects from continuous exposure should be
    investigated.  In addition, compounds were not  speciated.
    Since one health effects value was used to represent the
    entire pollutant class, various highly toxic species were
    not considered.
                         5-47

-------
       •   Population exposure to source emissions
           --  Specific values for average  source  size  and urban/rural
               splits were in many cases based  on  poor  quality data.   For
               utility and large industrial  boilers,  and  most packaged
               units, the data were adequate.   However, for internal
               combustion engines and  industrial process  heating,  data
               exhibited a wide range  of values making  specification
               difficult.
       Most  of these data needs are being addressed  in  ongoing assessments
 by the EPA.  As the data become available,  they are  being added to the
 Source Analysis Model data base to augment  and  update the present
 results.  The conclusions from the results  using the  current  data  base  are
 summarized below.
       The 1974 total pollution potential rankings,  Table 5-1,  indicate
 that watertube and firetube stokers of less  than 29 MW  input  capacity have
 the largest  total impact factors of all stationary sources.   However,
 tangential and wall fired boilers have the  next highest rankings and
 similar pollution impact factors.  The difference  in  impact factors for
 the three sources is within the uncertainty of the data.
       Stoker fired boilers have the highest total pollution  potential
 ranking — primarily because of the influence of beryllium.   This  trace
metal  has a threshold limit value two  orders of magnitude lower than any
 other  pollutant considered here.  Because of this, sources  with the
 highest levels of beryllium emissions  will  dominate  the pollution
 potential  ranking irregardless of the  impact potential  from other
 pollutants.
                                    5-48

-------
       Of all fossil fuels,  coal  firing generates the highest emissions  of
beryllium.  Although utility and  large industrial boilers are the largest
stationary source coal users,  they generally have lower beryllium
emissions than stoker fired  boilers.   For example,  a recent trace metal
study (Reference 5-45) has shown  that  a coal-fired  boiler with an
electrostatic precipitator can collect about  81 percent of total  beryllium
in coal.  With future extensive use of particulate  control devices on
utility and large industrial  boilers,  reductions in beryllium should
continue to be significant.   However,  small  stokers --  the second largest
stationary source coal users  — have  negligible particulate controls.(<15
percent) causing high beryllium levels in the flue  gas.  This, coupled
with the fact that  industrial  boilers  generally have low stacks,
contributes to the  high  pollution  potential  ranking of  stokers.
       To illustrate this hypothesis,  the Source Analysis Model was run
without beryllium for 1974,  1985,  and  2000.   These  rankings given in
Tables 5-12 to 5-14, show that without beryllium, tangential  and  wall
fired utility boilers using  coal  have  the highest pollution potential.   In
addition, oil fired units are  significant contributors  to total pollution
potential when the  dominant  effect of  high beryllium levels in coal is
excluded.  These results  illustrate that pollution  potential  rankings are
highly dependent on the  accuracy  of both emissions  data and impact data.
If the health impact threshold of beryllium were raised, the ranking of
combustion sources  would  change significantly.
       As shown in  Table  5-2,  opposed  wall fired boilers have the highest
average source pollution  potential.  This impact value  was obtained by
dividing the total  impact factor  by the total number of sources of a
specific equipment  type.  Opposed wall fired units  are  used for the larger
                                     5-49

-------
 i
01
o
                                  TABLE 5-1?.   TOTAL POLLUTUTION  POTENTIAL RANKING0 (GASEOUS)
                                                STATIONARY SOURCES  IN YEAR 1974
Rdfik
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Sector
-
Utility Boilers
Ut il ity Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Ind. Process Comb.
Equipment Type
TarK'^ritial
Wall Firing
Tangential
Wall Firing
Cyclone
Stoker Firing WTd <29 MWa
Horizontally Opposed
Horizontally Opposed
Wall Firing WTd >29 MWa
Scotch FTe <29 MWa
Wall Firing WTd >29 MWa
Firebox FTe <29 MWa
Stoker Firing WTd >29 MWa
Scotch FTe <29 MWa
Stoker Firing FTe <29 MWa
Coke Oven Under fire
Fuel
Coal
Coal
Oil
Oil
Coal
Coal
Coal
Coal
Oil
Oil
Coal
Oil
Coal
Gas
Coal
Processed Mat'!
Total Impact Factor
7.85 x 109
3.85 x 109
2,65 x 109
2.24 x 109
1,84 x 109
1.46 x 109
1.15 x 109
1.15 x 109
7.02 x 108
5.49 x 108
4.53 x 108
3.64 x 108
2.51 x 1.03
2.88 x 108
2.85 x 108
2.84 x 108
                  dHeat input
                  bHeat output
                  cWithout beryllium
                   Watertube
                  eFiretube
                                                                                                    T-862

-------
                                                        TABLE  5-12.   Concluded
m
i
en
Rarm
1?

13
19
i *
HI
22
23
24
25
26
11
28
29
30
Secto*-
Reciprocating 1C
Engines
Packaged boilers
Packaged Bo, lers
ind. Process Comb. •
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Ind. Process Comb.
Packaged Boilers
Gas Turbines
Ind. Process Comb.
Equipment Type
SI >75 kW/cy1b

Single Burner WTd 29 MWa
Cement Kilns
Cast Iron Boilers
Simple Cycle >15 MWb
Refinery Htr. Nat. Draft.
Fuel
Gas

Oil
Oil
Processed Mat 1
Gas
Gas
Oil
Coal
Gas
Gas
Processed Mat ' 1
Oil
Oil
Gas
Total Impact Facto
2.31 x 103

2.28 x 108
2.25 x 108
2.00 x 108
1.61 x 108
1.28 x 108
1.27 x 108
5.78 x 107
3.?2 M 10 7
2.79 x 107
2.71 x 107
2.47 x 107
2.38 x 10''
2.22 x 107
                        Heat input


                        Heat output


                        GWithout beryllium


                        dWatertube


                        eFiretube

-------
en
i
en
IX)
                                 TABLE  5-13.  TOTAL POLLUTION  POTENTIAL RANKING0 (GASEOUS)
                                               STATIONARY  SOURCES IN  YEAR 1985
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Sector
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Utility Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Ind. Process Comb.
Packaged Boilers
Ind. Process Comb.
Equipment Type
Tangential
Wall Firing
Tangential
Wall Firing
Horizontally Opposed
Cyclone
Wall Firing WTd >29 MWa
Horizontally Opposed
Stoker Firing WTd >29 MWa
Scotch FTe <29 MWa
Firebox FTe <29 MWa
Scotch FTe <29 MWa
Single Burner WTd <29 MWa
HRT boilers <29 MWa
Coke Oven Under fire
Wall Firing WTd >29 MWa
Brick & Ceramic Kilns
Fuel
Coal
Coal
Oil
Oil
Coal
Coal
Oil
Oil
Coal
Oil
Oil
Gas
Oil
Oil
Processed Mat'l
Coal
Processed Mat'l
Total Impact Factor
1.13 x 1010
4.46 x 109
2.31 x 109
1.95 x 109
1.92 x 109
1.62 x 109
1.04 x 109
9.83 x 108
9.10 x 108
8.24 x 108
5.46 x 108
3.87 x 108
3.43 x 108
3.38 x 108
3.15 x 108
2.82 x 108
2.23 x 108
                     "Heat input
                     bHeat output
                     cWithout beryllium
                     dWatertube
                                                                                                        T-863
                     "Firetube

-------
                                                     TABLE  5-13.   Concluded
on
i
en
Rank
Factor '
18
19
20
21
22
23
24
25
26
27
28
29
30
Sector
Packaged Boilers
Packaged Boilers
Utility Boilers
Reciprocating 1C
Engines
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Ind. Process Comb. '
Gas Turbines
Reciprocating 1C
Engines
Ind. Process Comb.
Utility Boilers
Equipment Type
Stoker Firing WTd >29 MWa
Stoker Firing FTe <29 MWa
Cyclone
SI> 75 kW/cylb
Horizontally Opposed
Wall Firing
Vertical & Stoker
Cast Iron Boilers
Cement Kilns
Simple Cycle >15 MWb
CI> 75 kW/cylb
Refinery Htr. Nat. Draft
Tangential
Fuel
Coal
Coal
Oil
Gas
Gas
Gas
Coal
Oil
Processed Mat ' 1
Oil
Dual (oil + gas)
Gas
Gas
Total Impact
2.18 x 108
1.78 x 108
1.13 x 108
1.08 x 108
9.48 x 107
8.30 x 107
5.07 x 107
3.73 x 107
3.00 x 107
2.67 x 107
2.63 x 107
2.45 x 107
2.33 x 107
                       aHeat input
                        Heat output
                       GWithout beryllium
                       dWatertube
                                                                                                                TT86T
                       KFiretube

-------
                                 TABLE  5-14.   TOTAL POLLUTION POTENTIAL RANKING0 (GASEOUS)
                                                STATIONARY  SOURCES  IN  YEAR 2000
CJ1
Ul
-p.
                     "Heat input
                     bHeat output
                     cWithout beryllium
                     dUatertube
Rank
Factor
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Sector
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Packaged Boilers
Utility Boilers
Packaged Boilers
Utility Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Ind. Process Comb. .
Packaged Boilers
Packaged Boilers
Packaged Boilers
Packaged Boilers
Ind. Process Comb.
Equipment Type
Tangential
Wall Firing
Wall Firing
Horizontally Opposed
Wall Firing WTd >29 MWa
Horizontallly Opposed
Stoker Firing WTd <29 MWa
Cyclone
Scotch FTe <29 MWa
Firebox FTe <29 MWa
Wall Firing WTd >29 MWa
Coke Oven Underfire
HRT Boilers <29 MWa
Single Burner WTd <29 MWa
Scotch FTe < 29 MWa
Stoker Fired WTd >29 MWa
Brick & Ceramic Kilns
Fuel
Coal
Coal
Oil
Coal
Oil
Oil
Coal
Coal
Oil
Oil
Coal
Processed Mat'l
Oil
Oil
Gas
Coal
Processed Mat'l
Total Impact
1.37 x 1010
4.51 x 109
3.28 x 109
2.46 x 109
1.66 x 109
1.61 x 109
1.43 x 109
1.21 x 109
1.02 x 109
6.78 x 108
4.35 x 108
4.25 x 108
4.19 x 108
4.15 x 108
3.90 x 108
3.40 x 108
3.00 x 108
" • ~ •• -™ • ' • • 	 — _ _ + 	
                     'Firetube

-------
                                                        TABLE  5-14.   Concluded
en
i
en
en
Rank
Factor
18
19
20
21
22
23
24
25
26
27
28
29
30
Sector
Packaged Boilers
Utility Boilers
Packaged Boilers
Reciprocating 1C
Engines
Utility Boilers
Utility Boilers
Gas Turbines
Gas Turbines
Reciprocating 1C
Engines
Ind. Process Comb.
Ind. Process Comb.
Ind. Process Comb.
Reciprocating 1C
Engines
Equipment Type
Stoker Fired FTe <29 MWa
Cyclone
Cast Iron Boilers
SI >75 kW/cy1b
Vertical & Stoker
Tangential
Simple Cycle >15 MWb
Simple Cycle >15 MWb
CI >75 kW/cylb
Refinery Htr. Nat. Draft
Open Hearth Furnaces
Refinery Htr. Nat. Draft
CI >75 kW/cylb
Fuel
Coal
Oil
Oil
Gas
Coal
Oil
Oil
Gas
Dual (oil + gas)
Gas
Processed Mat'l
Oil
Oil
Total Impact
2.79 x 108
9.34 x 107
4.63 x 10''
4.55 x 107
4.19 x 107
3.85 x 107
3.82 x 107
3.41 x 107
3.20 x 107
2.98 x 107
2.41 x 107
1.89 x 107
1.43 x 107
                      °Heat input
                      bHeat output
                      cWithout beryllium
                      dWatertube
                      eFiretube

-------
capacity ranges (>400 MW electric).  Because of their  large  size  and



resulting high fuel consumption, opposed wall boilers  have a high  average



source pollution potential.  However, this result must  be used  with  care



since the ranking  is not normalized for energy consumption.   For  example,



a 600 MW (electrical output) opposed wall fired boiler  may have less



pollution potential than three 200 MW (electric output) single  wall  fired



boilers required to supply the same power.  This ranking  is  primarily



intended to  assess characteristic average source impacts.  Stokers are



lower  in the  ranking because their impact is a result  of many smaller



sources rather than a fewer large single sources.



       Table  5-3 shows that cyclone boilers have the highest  single  source



NO   impact.   This  is primarily because uncontrolled NO  emissions  from
  X                                                    A


cyclone (coal-fired) boilers are more than double the  emissions from



tangential units and about 75 percent higher than wall  fired  units.



However, the  total nationwide pollution potential of cyclones should



decline in the future since the use of cyclones will decrease due  to their



high levels  of emissions.



       Since  use of coal is projected to greatly increase, the  predominance



of coal-fired  units in the 1974 source rankings is reinforced for  1985  and



2000.  Stoker  fired units  are projected to remain the  source  type  with



highest pollution  potential in the 1980's and 1990's because  of the



dominant effect of beryllium emissions.  If beryllium  is not  considered in



the  modeling,  or if stringent controls are projected for stoker



particulate  emissions, tangential coal fired-boilers again become  the



major  source  of pollution  potential through the year 2000.   In  general,



oil-fired units are the second most significant group,  with  natural
                                    5-56

-------
gas-fired units  having  the least pollution potential because of projected
decreases in natural  gas  consumption.
       The reference  low  nuclear scenario shows the largest pollution
potentials through  the  year 2000.  As mentioned earlier, this scenario
postulates that  coal-fired units will meet most of the increased demand
for power generation, and nuclear power will  only play a secondary role.
As coal use increases under this scenario, the pollution potential  impacts
from fossil fuels will  increase proportionally.  This,  of course,  does not
consider the environmental effects of nuclear powerplants.   A careful
assessment of  the potentials for environmental degradation  from nuclear
powerplants could result  in these plants having higher  impacts  than coal
fired units.   Under this  condition,  the reference high  nuclear  case may
have the highest overall  pollution potential  impact.
       The synthetics scenario yields the lowest total  pollution
potential.  This low  pollution potential results primarily  from using
synthetic liquids and gases instead  of coal  for stationary  combustion.  In
addition, nuclear power is largely relied upon for power generation,  so
that coal is saved  for  use as a feedstock for gasification  and
liquefaction processes.  One possibly significant factor not considered
here is the pollution potential of intermediate fuel  conversion
processes.  Since the intent of the scenario  development was only  to
examine trends in pollution potential from end-use stationary combustion
equipment, these intermediate sources were not considered.   However,  a
more rigorous  analysis  of total emission loadings for each  scenario may
show these intermediate conversion steps to be highly significant.
       The major trace  elements with significant pollution  potential  are
beryllium, chromium,  nickel, vanadium, and aluminum.  Trace element
                                     5-57

-------
pollution appears to be significant for utility  and  packaged  boilers
firing roa1 or haavy oil.  Beryllium, as already noted  has  high  pollution
potential because of its toxicity.  Nickel also  is a  toxic  effluent from
both oil- and coal-firing.  Vanadium and chromium appear  to be significant
in residual oil-firing because of their high toxicity-   In  contrast,
aluminum is significant in both coal- and oil-firing  because  of  the
magnitude of emissions rather than the toxicity.  For example, aluminum
emissions  (ppm) are 30 to 40 times higher for bituminous  coal than  for
other trace elements considered in this assessment.   In  fact, aluminum is,
in  general, the most abundant trace element in coal  --  representing in
some  cases up to 2 percent of total coal (Reference  5-45).
       Tangential coal-fired boilers have the highest liquid  and solid
effluent stream pollution potential, as a result  of  high  installed
capacity and selective partitioning of toxic trace elements within  the
flyash and bottom ash streams.  Stoker fired boilers  do  not have a  high
ranking.   Since the use of particulate controls  is low  for  smaller  units,
toxic elements like beryllium go out the stack rather than  being collected
in the flyash hopper as a solid effluent.  Oil-fired  combustion  sources
are second and third on the ranking because of high  concentrations  of
vanadium and nickel in the ash from residual oil-firing.  In  addition  to
their toxicity, vanadium and nickel are usually  highly  concentrated in the
bottom ash and flyash streams of combustion units.   Thus, the pollution
potential of liquids and solids from stationary  source  combustion is
highly dependent not only on the overall fuel consumption of  the equipment
type, but  also on the selective partitioning of  toxic trace elements
within the liquid and solid effluent streams and  the  degree of pollutant
controls.
                                    5-58

-------
                          REFERENCES FOR  SECTION  5
5-1.    Eimutis, E.C., et al., "Air, Water,  and  Solid  Residue
       Prioritization Models for Conventional Combustion  Sources,"
       Monsanto Research Corporation,  EPA-600/2-76-176  NTIS-PB  257 103
       July 1976.

5-2.    Cleland, J.G., and Kingsbury, G.L.,  "Multimedia  Environmental Goals
       for Environmental Assessment,"  Research  Triangle Institute,
       EPA-600/7-77-136a&b, NTIS-PB 276 919/AS,  NTIS-PB 276 919/AS,
       November 1977.

5-3.    Turner, D.B., "Workbook of Atmospheric Dispersion  Estimates,"
       National Air Pollution Control  Association,  1969.

5-4.    Holzworth, G., "Mixing Heights, Wind Speeds, and Potential For
       Urban Air Pollution Throughout  the Contiguous  United States,"
       Office of Air Programs, U.S. Environmental Protection Agency,
       January 1972.

5-5.    "SAM I/A:  A Rapid Screening Method  for  Environmental Assessment of
       Fossil Energy Process Effluents," EPA-600/7-78-015,
       NTIS-PB 277 088/AS, August 1977.

5-6.    Personal communications with G., Kingsbury,  Research Triangle
       Institute, August 1977,

5-7.    Plant Design Report, Power, Volume 118,  No.  12., December 1974.

5-8.    Ehrenfeld, J. R,, et al., "Final Report:  .Systematic Study of Air
       Pollution from Intermediate-Size Fossil-Fuel Combustion Equipment,"
       Walden Research Corporation, EPA Contract No.  CPA  22-6985, July
       1971.

5-9.    "Survey of Domestic, Commercial and  Industrial Heating Equipment
       and Fuel Usage," Catalytic Final Report,  EPA Contract 68-02-0241,
       August 1972,

5-10.   Personal communication with S.  Youngblood, Acurex  Corporation,
       August 1977.

5-11.   Shreve, R.. "Third Edition, Chemical Process Industries," Purdue
       University^ McGraw-Hill Book Company, 1967.

5-12.   Reznik, R. B., "Source Assessment:   Flat  Glass Manufacturing
       Plants," Monsanto Research Corporation,  EPA-600/2-76-032b,
       NTIS-PB 252 356/AS, March 1976.

5-13.   Considine, D. M. (ed.), "Chemical and Process  Technology
       Encylopedia," McGraw-Hill Book  Company,  1974.
                                    5-59

-------
5-14.   Bieser, C.O., "Identification and Classification  of  Combustion
       Source Equipment," Processes Research  Incorporated,  EPA R2-73-194,
       NTIS-PB 218 933, February 1973.

5-15.   Klett, M.G., and Galeski, J. B., "Flare Systems Study," Lockheed
       Missiles and Space Company, Inc., EPA  600/2-76-079,
       NTIS-PB 251 644/AS, March 1976.

5-16.  Hunter, S.C., "Application of Combustion Modifications  to
       Industrial Combustion Equipment," Proceedings of  the Second
       Stationary Source Combustion Symposium Volume III, Stationary
       Engine, Industrial Process Combustion  Systems, and Advanced
       Processes, EPA-600/7-77-073c, NTIS-PB  271 757/7BE, July 1977.

5-17.  "The  National Air Monitoring Program:  Air Quality and  Emissions
       Trends Annual Report Volume II," EPA-450/l-73-001b,
       NTIS-PB 227 272/2, August 1973.

5-18.  "1970 Census of Population, Volume 1 « Characteristics of
       Population, Part 1, U.S. Summary — Section 1," U.S.  Bureau  of the
       Census, April 1973.

5-19.  "Statistical Abstract of the United States 1976," 97th  Annual
       Edition, U.S. Bureau of the Census, July 1976.

5-20.  "AEROS — Fuel Summary Report," Office of Air Quality Planning and
       Standards, U.S. Environmental Protection Agency,  August 1977.

5-21.  "Air  Quality Data for Metals 1970 Through 1974 from  the National
       Air Surveillance Networks," Environmental Monitoring  and Support
       Lab,  EPA-600/4-76-041, NTIS-PB 260 590/AS, August 1976.

5-22.  "Air Quality Data for Nonmetallic Inorganic Ions  1971 Through
       1974:  From the National Air Surveillance Networks,"
       EPA-600/4-77-003, NTIS-PB 262 397/3BE, January 1977.

5-23.  "National Trends in Trace Metals in Ambient Air 1965-1974,"  U.S.
       Environmental Protection Agency, EPA-450/1-77-003,
       NTIS-PB 264 906/9BE, February 1977.

5-24.  "Air  Quality Data — 1975 Fourth Quarter Statistics,"
       EPA-450/2-77-006, Office of Air and Waste Management, U.S.
       Environmental Protection Agency, May 1977.

5-25.  "Monitoring and Air Quality Trends Report, 1974," EPA-450/1-76-001,
       NTIS-PB 254 044/1BE, Office of Air and Waste Management, U.S.
       Environmental Protection Agency, February 1976.

5-26.  "The  National Air Monitoring Program:  Air Quality and  Emissions
       Trends, Annual Report, Volume 1," EPA-450/l-73-001a
       NTIS-PB 226 490/1, August 1973.                    '
                                    5-60

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5-27.  "Air Quality  Data  --  1973 Annual  Statistics,"  EPA-450/2-74-015,
       NTIS-PB 241 808, Office of Air  and  Waste  Management,  U.S.
       Environmental Protection Agency,  November 1974.

5-28.  Lee, R. E., Jr., et al., "Particle-Size Distribution  of Metal
       Components in Urban Air," U.S.  Department of Health,  Education and
       Welfare, from Environmental Science  and Technology, Volume  2.
       No. 4, April 1968.

5-29.  Gladney, E, S., et al., "Composition and  Size  Distributions  of
       Atmospheric Particulate Matter  in the Boston Area," Department of
       Chemistry, University of Maryland, Environmental Science and
       Technology, Volume 8, No. 6, June 1974.

5-30.  Lee.,  R. E.,  Jr. and vcn Lehmden, D. J.,  "Trace Metal Pollution in
     ,  the Environment," Environmental Protection Agency, National
       Environmental  Research Center, Journal of the Air Pollution Control
       Association, Volume 23, No. 10, October 1973.

5-31.  Lee, R. E., Jr.  ei al., "National Air Surveillance Cascade  Impactor
       Network, IIS Size Distribution Measurements of Trace Metal
       Components," U.S. Environmental Protection Agency, National
       Environmental  Research Center, Environmental Science and
       Tgciinology, Volume 6,  Number 12,  November 1972.

5-32,  Vitez, Bela, "Trace Elements in Flue Gases and Air Quality
       Criteria,"  Power Engineering,  January 1976.

5-33.  DeMaio, L., and  Corn,  M.,  "Polynuclear Aromatic Hydrocarbons
       Associated  with  Particulates in Pittsburgh Air," University of
       Pittsburgh, Journal of the Air Pollution Control Association,
       Volume 16,  No.  2, February 1966,

5-34.  "Steam-Electric  Plant  Air  and  Water Quality Control Data for the
       Year Ended  December 31, 1969," Federal Power Commission,
       February 1973.

5-35.  "Steam-Electric  Plant  Air  and  Water Quality Control Data for the
       Year Ended  December 31, 1972,  FPC-S-246, Federal Power Commission,
       March 1975.

5-36.  Putnam, A.A.,  et al.,  "Evaluation of National Boiler Inventory,"
       Battelle-Columbus Laboratories, EPA-600/2-75-067, NTIS-PB 248
       100/AS, October  1975.

5-37.  Locklin, D.W.  et al.,  "Design  Trends and Operating Problems in
       Combustion  Modification of Industrial Boilers," EPA-650/2-74-032,
       NTIS-PB 235 712/AS, Battelle-Columbus Laboratories, April 1974.

5-38.  Offen, G.R., et  al., "Standard Support and Environmental Impact
       Statement for Reciprocating Internal Combustion Engines," Acurex
       .Corporation, March 1978.
                                    5-61

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5-39.  "Installed Capacity of Utility Generating Plants  by  States  and
       Type, 1976 Statistical Report," Statistical World, March  15,  1976.

5-40.  "Minerals Yearbook 1973 — Metals, Minerals, and  Fuels, Volume I,"
       U.S. Bureau of Mines.

5-41.  Varga, J., et al., "A Systems Analysis Study of the  Integrated Iron
       and Steel Industry," Battelle Memorial Institute, NTIS-PB 184  577,
       May 1969.

5-42.  "Development Document for Effluent Limitations Guidelines and  New
       Source Performance Standards for the Petroleum Refining Point
       Source Category," EPA-440/l-74-014a, GPO 5501-00912, NTIS-PB 238
       612/AS, April 1974.

5-43.  Goldish, J., et al., "Systems Study of Conventional Combustion
       Sources in the Iron and Steel Industry," Walden Research
       Corporation, EPA-R2-73-192,  NTIS-PB 226 294/AS, April 1973.

5-44.  Weant III, G.E. and Overcash, M.R., "Environmental Assessment  of
       Steelmaking Furnace Dust Disposal  Methods," Research Triangle
       Institute, EPA-600/2-77-044, NTIS-PB 264 924/2BE, February 1977.

5-45.  "Coal-Fired Power Plant Trace Element Study, Volume I — A
       Three-Station Comparison," Radian  Corporation,  September 1975.
                                   5-62

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                                TECHNICAL REPORT DATA
'Please r?ad Instnictions on tl-c reverse
                                                 a'v completing!
 i REPORT NO.
 EPA-600/7-78-120a
 4. TITLE AND S'JBTIT-E
 Emission Characterization of Stationary NQx
 Sources: Volume I. Results
 7 AUTHOR(S)
 K.G.Salvesen, K.J.Wolfe, E.Chu, and
  M.A.Herther
                                                      3. SEC: PI f': r3 ACCESS:-':^ <'
                             5. REPORT ">ATE
                              June 1978
                             6. PERFORMING ORGANIZATION CODE
                                                      8. PERFORMING ORGANIZATION REIPORT NC
 . PERFORMING ORGANIZATION' NAME AND ADDRESS
 Acurex Corporation/Energy and Environmental Div.
 485 Clyde Avenue
 Mountain View, California  94042
                             10. PROGRAM ELEMENT NO.

                             EHE624A
                             11. CONTRACT/GRANT NO.

                             68-02-2160
 12. SPOMSORING AGENCY NAME AND ADDRESS
 EPA, Office of  Research and Development
 Industrial Environmental Research Laboratory
 Research Triangle Park, NC 27711
                             13 TYPE OF REPORT AND PERIOD COVERED
                             Special: 1-10/77
                             14, SPONSORING AGENCY CODE
                              EPA/600/13
 is.SUPPLEMENTARY NOTES JERL-RTP project officer is Joshua S.  Bowen,  Mail Drop 65
 919/541-2470.
 16. ABSTRACT
         The report gives results of an inventory of gaseous,  liquid, and solid
 effluents from stationary NOx sources,  projected to the year 2000,  and ranks them
 according to their potential for environmental hazard. It classifies sources accor-
 ding to their pollution formation characteristics, and gives results of a compilation
 of emission factors  and regional and national fuel consumption data for specific
 equipment/fuel types.  It gives results of an emission inventory for NOx, SOx, CO,
 HC, particulates, sulfates, POM, and liquid or solid effluents. It projects emissions
 to 1985 and to 2000 for five energy scenarios, depicting alternative uses of coal,
 nuclear power, and  synthetic fuels. It ranks sources by nationwide  emissions loading
 for 1974, 1985, and 2000. It describes a source analysis model used to estimate pol-
 lution hazard, considering ambient dispersion,  population exposure, background
 concentrations, and health-based impact threshold limits. It applies the model the
 model to the emission inventory to produce source rankings based on both single-
 pollutant and total-multimedia impact factors.
                            KEY WORDS AND DOCUMENT ANALYSIS
                DESCRIPTORS
 Air Pollution         Boilers
 Nitrogen Oxides      Gas Turbines
 Organic Compounds  Internal Combustion
 Inorganic Compounds   Engines
 Fossil Fuels         Ranking
 Dust                 Inventories
 . JIGTRiBUTICM ST VTEMENT
 T;
  i! trailed
                                         b.IDENTIFIERS/OPEN ENDED TERMS
                Air Pollution Control
                Stationary Sources
                Environmental Assess *'
                 ment
                Particulates
                Emission Factors
                19. SECURITY CLASS j I'iii.'. Repo
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