U.S. Environmental Protection Agency Industrial Environmental Research      EPA-600/7'77'119D
Office of Research and Development Laboratory                /•> * u  -t ei^f
                Research Triangle Park, North Carolina 27711 UCIODer I 977
        PRELIMINARY ENVIRONMENTAL
        ASSESSMENT OF COMBUSTION
        MODIFICATION TECHNIQUES:
        Volume II. Technical Results
        Interagency
        Energy-Environment
        Research and Development
        Program Report
                             ~Z

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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  seven series.
 These  seven broad categories were established  to  facilitate further
 development and application of environmental "technology.  Elimination
 of  traditional grouping was consciously planned to  foster technology
 transfer and a maximum interface  in related fields.   The seven 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

 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  systems.   The  goal  of the Program
 is  to  assure the rapid development of domestic  energy supplies in an
 environmentally—compatible manner by providing the necessary
 environmental data and control technology.  Investigations include
 analyses 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 environmental issues.

                            REVIEW NOTICE

This report has been reviewed by the participating Federal
Agencies, and approved for publication.  Approval does riot
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 recommen-
 dation for use.
This document is available to the public through the  National Technical
Information Service, Springfield, Virginia  22161.

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                                   EPA-600/7-77-119b
                                         October 1977
PRELIMINARY  ENVIRONMENTAL
ASSESSMENT  OF COMBUSTION
  MODIFICATION TECHNIQUES:
   Volume II.  Technical Results
                      by
              H.B. Mason, A.B. Shimizu, J.E. Ferrell,
             G.G. Poe, LR. Waterland, and R.M. Evans

                  Acurex Corporation
                  Aerotherm 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, N.C. 27711
                    Prepared for

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

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                                               FOREWORD





       This report documents  results generated during the  first 6 months of EPA Contract 68-02-2160:



"Environmental Assessment of  Stationary Source NOX Combustion Modification Technologies."  The  EPA



Project Officer  is J. S. Bowen and the Deputy Project Officer is R. E. Hall of the Combustion Research



Branch, IERL/RTP.  This  report was prepared  by Aerotherm Division of Acurex Corporation.  Principal



Contributors were:




       t   Preface and Section 1:  Introduction - H. B. Mason




       •   Section 2:  NOX  Source Characterization -A. B. Shimizu and K. Salvesen




       t   Section 3:  Pollutant Characterization - J. E.  Ferrell and G. R. Offen (Aerotherm);



           H. M. Utidijian  and P. Atkins  (Equitable Environmental Health); G. Lauer, A. Lloyd and



           R. MacGregor  (Environmental Research and Technology)




       t   Section 4:  NO   Control Characterization — G. G. Poe, A. Balakrishnan, C. Castaldini,
                         X


           Z. Chiba




       •   Section 5:  Multimedia Emission Inventory of NOX Sources -A. B. Shimizu, K. Salvesen



           and K. Wolfe




       •   Section 6:  Evaluation of Incremental Emissions due to NOV Controls - L. Waterland,
                                                                    A


           C. Castaldini, G.  G. Poe




       •   Section 7:  Environmental Assessment Priorities - R. M. Evans, L. Waterland, G. R. Offen,



           H. B. Mason




       •   Appendices -  K.  Wolfe, M. McDonald, D. Rafinejad




The Program Manager is W. H.  Nurick.   H.  B. Mason is the Project Engineer.  C. B. Moyer provided



technical  review.




       The contributions of the following individuals and  organizations are gratefully acknowledged:



J. S. Bowen, R.  E. Hall, D. G. Lachapelle, W. S. Lanier, G. B. Martin and J. Wasser of the Combustion



Research Branch, IERL; R. Vosper of the Coen Company; S. Greenfield, L. Attaway and L. Husting  of
                                                 iii

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Greenfield, Attaway and Tyler Company; D.  W.  Pershlng and J.  0.  L.  Wendt of the University of Arizona;
D. P. Teixelra and R. M. Perhac of the Electric Power Research  Institute;  and A.  Eschenroeder and
G. Hidy of Environmental Research and Technology.
                                                iv

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                                              PREFACE

       This is the first in a series of 11 special reports to be documented in the "Environmental
Assessment of Stationary Source NOX Combustion Modification Technologies" (NOX E/A).  This preface
describes the organization, approach, and expected results of the NOX E/A and relates this initial
report to the total program.  The Introduction section reviews the background and needs addressed
by the program and by this report.
       The NOX E/A is a 36-month program which began in July 1976.  The program has two main objec-
tives:  (1) to identify the multimedia environmental impact of stationary combustion sources and
NOX combustion modification controls; and (2) to identify the most cost-effective, environmentally-
sound NOX combustion modification controls for attainment and maintenance of current and projected
N02 air quality standards to the year 2000.
       By achieving these objectives, the NOX E/A program will show the economic, environmental  and
operational impact of reducing NOX to a given level on specific combustion sources with current  and
emerging control technology.  This information is addressed to the following groups:
       •   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 N02-
           critical Air Quality Control Regions
       •   Environmental planners involved in formulating abatement strategies to meet current or
           projected air quality standards

NOX E/A Scope and Approach
       The scope and approach of the NOX E/A come largely from its place in the broad program of
assessments of energy systems and industrial processes which is being administered by EPA's Office
of Research and Development.  This assessment program involves a series of coordinated efforts to
evaluate the environmental  impact and control potential of multimedia effluents - air, land and
water - from current and emerging energy and industrial processes.  The results of these efforts

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will define pollution control development needs and priorities,  identify economic and environmental
trade-offs among competitive processes, and will  ultimately guide  regulatory  policy.   This
assessment program is organized in a hierarchy, in which each assessment draws  on the results o
preceding study.  The six major types of assessments now planned are listed below together with spe-
cific assessment programs relevant to the NOX E/A:
       •   Emissions Assessment:  quantify multimedia emissions  from effluent streams of specific
           processes
           -   Emissions Assessment of Conventional  Combustion Systems  (TRW)
       •   Source Assessment:  determine environmental  impact of multimedia emissions from source
           effluent streams and rank sources according to impact
           -   Source Assessment (Monsanto Research Corporation)
       •   Process Environmental Assessment:  determine multimedia environmental  impact of effluent
           streams for a specific process; evaluate pollution control requirements;  identify control
           R&D needs
           -   Fluidized Bed Combustion E/A (Battelle)
           -   Residual  Oil Utilization E/A (Catalytic)
       0   Industry Environmental  Assessment:   conduct industry-wide aggregate  process E/A; rank
           control  development needs for the industry;  identify  environmental trade-offs of alternate
           processes
       •   Pollutant Control Environmental Assessment:   conduct  multi-industry  process E/A of all
           sources  of a  given pollutant; identify most cost-effective,  environmentally acceptable
           control  systems; identify R&D requirements to meet national  emissions standards or local
           air quality goals
           -   NOX  Control  E/A (Aerotherm)
       •    Integrated Technology Assessment:  evaluate environmental, technological  and socioeconomic
           trade-offs for emerging energy systems or processes for use  in deciding regulatory strategy;
           integrate  results of process, industry and pollutant  control E/A's
          -   Integrated Technology Assessment of Electric Utility Energy Systems (Teknekron)
          —   Integrated Assessment of Coal-Based Energy Technology (Planned)
                                                 VI

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       The goal of these assessment activities is to synthesize data and technology from related
programs, and to develop a standardized basis of comparison of the results of the various efforts.
In support of this goal, EPA's  Industrial Environmental Research Laboratories (RTP and Cincinnati)
have established steering committees to coordinate the assessment programs.  This coordination will
make it possible for the NOX E/A to utilize results from the emissions assessments, source assess-
ments, and environmental assessments previously listed, and to provide inputs to the integrated
technology assessments.
       The NOX E/A, as part of  the overall pollutant control E/A activity, will  assess the following
combination of process parameters and environmental impacts:
       •   Fuel combustion stationary NOX sources:  utility, industrial, commercial and residential
           boilers; commercial  and residential warm air furnaces; 1C engines; gas turbines;  indus-
           trial process combustion; advanced energy systems; and minor sources.  Other sources
           (mobile and noncombustion) will be considered only to the extent that they are needed
           to determine the NOX contribution from stationary combustion sources.
       •   Conventional and alternate gaseous, liquid and solid fuels
       •   Combustion modification NOX controls with potential for implementation to the year 2000;
           other controls (tail gas cleaning, mobile controls) will  be considered only to estimate
           the future need for  combustion modifications
       •   Source effluent streams potentially affected by NOX controls
       •   Nonstandard operating conditions during which the emissions may be affected by NOX controls
       •   Primary and secondary gaseous, liquid and solid pollutants potentially affected by NO/
           controls
       t   Pollutant impacts on human health and terrestrial or aquatic ecology
       In order to achieve the  overall objectives of this NO  E/A program (described on the first page
of this preface), strong emphasis will be placed throughout the program on screening and setting
priorities among the combinations of process parameters and potential impacts.   This approach infers
that the major effort will be focused on the sources, controls, and potential impacts which are
likely to be significant in the national NOX abatement strategy.  It also infers that effort in
the early stages of the program will concentrate on near-term source/control needs, while emphasis
will be switched later to longer range control needs to the year 2000.  The comprehensive ranking
                                                VII

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 of the process and impact combinations which  is the principal outcome of the program will not be able
 to be made until  most of the  tasks  in the  program are complete.  Throughout the effort, however,
 priorities will be screened on  the  basis of the most recent findings, which will be periodically
 updated and reevaluated as new  data become available.
        For simplicity, the screening and ranking of alternatives are being conducted in two steps.
 In the first step, potential  source/fuel/control combinations are being screened on the basis of
 significant application in this century.   This requires projecting the use of specific source/fuel
 combinations as well  as estimating  which control systems will be needed to meet current or antici-
 pated N02-related air quality standards.   This in turn will entail process studies of specific source/
 control combinations  and air  quality modeling of N02-sensitive areas which examine NOX abatement
 strategies.
        The second step in screening and ranking alternatives is to prioritize effluent streams/
 operating modes/pollutant combinations on the basis of incremental multimedia impact due to the use
 of NOX controls.   This ranking  will  be done for the significant source/fuel/control combinations
 which result from the first step screening.   In addition, this second step involves compiling emis-
 sions data for specific effluent streams and operating modes, as well as compiling impact criteria
 for specific pollutants.   Iteration between the results of the two steps is necessary to ensure that
 the incremental  impact of NOX controls identified in the second step is considered in estimating
 control  needs  in  the  first step.
 NOX  E/A Program Structure
        As  shown schematically in Figure P-l, the NOX E/A program is structured to incorporate the
 above approach.  The  two major tasks are:   Environmental Assessment and Process Engineering (Task
 85); and Systems Analysis  (Task C).   Each of these tasks is designed to achieve one of the overall
 objectives of the NOX  E/A program cited earlier.   In Task 85, the environmental, economic, and opera-
 tional  impacts of specific source/control  combinations will be assessed.  On the basis of this assess-
ment, the incremental  multimedia impacts  from the use of combustion modification NOX controls will
be identified and ranked.  Task  C will  in  turn use the results of Task B5 to identify and rank the
most effective source/control  combinations  to comply, on a local basis, with the current NOj air
quality standards and projected  NC^-related standards.
       As shown in Figure P-l, the  key tasks supporting Tasks 85 and C are Baseline Emissions  Charac-
terization (Task Bl),   Evaluation of  Emission Impacts and Standards (Task B2), and Emission Data
 (Task B3).  The arrows in Figure P-l show the sequence of subtasks and the major interactions  among
                                                viii

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   EMISSION
   CHARACTERIZATION
      IMPACTS &
      STANDARDS
   COMPILE COMBUSTION

   SOURCE PROCESS

   BACKGROUND
  GENERAL MULTIMEDIA
  EMISSION INVENTORY


CHARACTERIZE PRIMARY
& SECONDARY MULTI-
MEDIA POLLUTANTS
GENERATE EMISSION
PROJECTIONS & REGIONAL

VARIATIONS
COMPARE BASELINE

EMISSIONS TO MULTIMEDIA

ENVIRONMENTAL GOALS
    BASELINE  IMPACT
    ASSESSMENT
IMPACT CRITERIA
STANDARD PROJECTIONS
EXPERIMENTAL
TESTING
                                PROCESS ENGINEERING  &
                                ENVIRONMENTAL  ASSESSMENT
                                                                         COMPILE  N0x

                                                                         CONTROL  PROCESS

                                                                         BACKGROUND
IA
RY


ONAL
— -^


DEFINE MULTIMEDIA
ENVIRONMENTAL GOALS









PROJECT N02
ENVIRONMENTAL
GOALS


DEFINE SAMPLING
AND ANALYSIS
REQUIREMENTS
t
CONDUCT FIELD
TESTS
1
-. 	 -~

EVALUATE DATA ON
INCREMENTAL EMISSIONS
WITH NOX CONTROLS
1

                                                                                                            RELIMINARY  SOURCE
                                                                                                          CONTROL PRIORITIES ON
                                                                                                          BASIS OF POTENTIAL IM-
                                                                                                           'ACT & PROJECTED USE
,

GENERATE CONTROL
TECHNOLOGY PROCESS
STUDIES OF MAJOR
SOURCES


                                COMPARE CONTROLLED
                                EMISSIONS TO

                                MULTIMEDIA GOALS
 ASELINE AND
CONTROLLED EMISSION
DATA
                                                                        RANKING  OF  POTEN-
                                                                        TIAL  IMPACTS WITH
                                                                     COMBUSTION  MODIFICATI
                                                                        CONTROLS
    SYSTEMS
    ANALYSIS
                                                                  DEVELOP PRELIMINARY

                                                                  MODEL FOR ENVIRONMENTAL

                                                                  ALTERNATIVES STUDY
PROJECT SOURCE

GROWTH !, AMBIENT

STANDARDS
                                                                   ASSESS CONTROL

                                                                   REQUIREMENTS FOR

                                                                   ALTERNATE ABATEMENT
                                                                   STRATEGIES



SCREEN CONTROL
REQUIREMENTS FOR
AIR QUALITY MAIN-
TENANCE


SELECT AND ADAPT
REACTIVE AIR QUALITY
MODEL
                                                                                                                                                                       COMPLETED
                                                                                                                                                                       EFFORT
                                                            Figure  P-l.    NOX  E/A  approach.
                                                                                                           COMBUSTION  MODI-
                                                                                                       IFICATION CONTROL  DEVEL-
                                                                                                           OPMENT PRIORITIES

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 tasks.  The oval symbols identify the major outputs of  each task-  The subtasks under  each  main  task
 are shown on the figure from the top to the bottom of the page  in roughly the same order  in which
 they will be carried out.   More detail  is  given  for tasks on the upper half of the figure which
 relate to this report.   An additional  support  task of this program - Identification and Characteri-
 zation of Alternate Clean  Fuels for Area Sources  (Task  B4) - has been omitted for clarity.
        The initial work on this N0x program began by compiling  process data and multimedia  emissions
 data for stationary NO  sources.   Both  uncontrolled baseline emission data as well as  data  for sources
                       X
 using N0x controls were compiled.   Process  and emission data based on test results from related  pro-
 grams will continue to be  incorporated  as  they become available throughout the duration of  the pro-
 gram.
        These data were used to initiate the following preliminary characterizations and data eval-
 uations:  stationary source equipment and  effluent streams, as well as baseline multimedia  emissions
 (Bl); multimedia primary and secondary  pollutants and impacts (B2); stationary source  NOX controls
 and incremental emissions  due to control (B5).  These characterizations and data evaluations,
 together with the preliminary screening of  future source/control requirements (C), are documented
 in this report.  This information  will  serve as a data base for the subsequent comprehensive process
 studies, as well as for refining emission  inventories and impact criteria.  It will also  guide
 decisions on requirements  for subsequent field test programs and on setting priorities for  process
 and environmental  assessment studies.   The  activities which remain to be carried out in each of  the
 tasks are summarized below.

 Task Bl  —Baseline Emission Characterization
        Task Bl  focuses  on  assessing  the multimedia pollution potential of effluent streams  from
 uncontrolled  stationary fuel  combustion sources.  This  involves a generalized (nonsite-specific)
 analysis  of the emission rates  specified in the earlier emission inventory, as well as an analysis
 of  how  pollutants  emitted  are transformed and  transported.  After these emission rates are  updated
with Task B3  test  results,  the  resulting estimates of ground level concentration will  be  compared
to  the estimates of maximum  permissible concentrations  (on an impact basis) generated  in  Task  B2.
This comparison will  indicate which  effluent streams and pollutants pose potential environmental
problems in the absence of  NOX  controls.  This information will serve as a baseline reference  for
the more comprehensive assessment of incremental impacts of NOX controls conducted in  Task  B5,  and
will also highlight effluent streams which may require  control  systems for pollutants  other than
NOX.

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       The efforts carried out in Task B1 (emission inventory, projection of source/fuel usage, and
specification of geographical variations in source/fuel use) will support the final pollution poten-
tial assessment.  The results of this task will also show the potential effect on pollution of growth
trends for specific source/fuel combinations and the proximity of specific sources to population
centers.  These data will also support the air quality modeling of alternate NOX controls in Task C,
where local (AQCR) inventories and source projections to the year 2000 are needed to determine the
NOX controls required to meet air quality standards.

Task B2 - Emission Impacts and Standards
       The goal of Task B2 is to generate a set of pollutant/impact criteria data which can be used
to assess the environmental soundness of effluent streams and NOX control systems in Tasks Bl and
B5.  The scope of the task includes gaseous, liquid, and solid effluents that have a potential im-
pact on human health through inhalation or ingestion via the food chain, or that affect aquatic or
terrestrial flora or fauna.  The result will be a pollutant/impact matrix of conservative estimates
of permissible ambient concentrations.
       During the preliminary characterization of emissions and evaluation of data carried out so
far, emphasis has been placed on gaseous stream pollutants which affect human health through inhala-
tion.  One reason for this is that the vast majority of combustion-generated pollutants which may be
impacted by combustion modification NOX controls is present in gaseous effluent streams.  Another
reason is that it is easier to identify and quantify the impact of inhaled gaseous pollutants on
human health than other kinds of pollutants or receptors.  In addition, the effect of inhaled pol-
lutants is more readily generalized without regard to site-specific impact factors such as regional
flora or fauna and regional food chain vectors.  The site-specific impact criteria are not neglected,
however.  They are generalized somewhat in B2 by considering the most sensitive receptor for each
pollutant regardless of location.  This "worst case" screening approach will in turn be modified in
the individual assessments of B5, where the impacts for specific source/control combinations will be
evaluated for two or more representative ecosystems.  Task B5 will also examine other potential im-
pacts of NOX controls, such as noise or thermal pollution and impact on material systems.
       In addition to the efforts described above, Task B2 will also evaluate and project air quality
standards for N02 and related pollutants.  These projected standards will be used in Task C, where
alternate air quality standards will serve as the criteria for defining future NOX control needs
and, hence, the scope of this program.  Projected standards to be evaluated include:
                                                XI

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        .   Change in level  of  the  current annual arithmetic average standard on the basis of human
            health effects
        •   Short-term NOZ  standard on the basis of human health effects or the role of NOX in the
            formation of photochemical smog
        t   Standards for secondary pollutants from NOX, such as acid nitrates and nitrosamines
        The purpose of these evaluations will not be to suggest standards, but rather to anticipate
 their impact, if and when  promulgated, on control implementation needs.

 Task B3 — Emission Data
        Task B3 will  rely heavily on data from emissions and control development test programs now
 being carried out.   Where  necessary, this data base will be augmented by test programs conducted as
 part of this program.   Test requirements will be defined from the preliminary emission characteri-
 zations and data evaluations documented in this report.  The test approach will follow the Level I
 and Level  II guidelines for sampling, chemical analysis and bioassays now being established by the
 IERL steering committees on environmental assessments.  Although some uncontrolled baseline tests
 will  be conducted, most tests will be on field equipment with extensive NOX control and on prototype
 systems using advanced  NOX-control techniques.

 Task B5 — Environmental  Assessment
        The  relationship of  Tasks B5 and C to the other tasks in the program has been described above.
 Following this  report,  the  effort in Task B5 will generate process data and environmental assessments
 for specific source/control combinations.  These studies will be done in order of descending priority.
 Initially,  the  sources  and  controls involved in current and planned NOX control implementation pro-
 grams will  be  investigated.  The results of these investigations will be used to assess the environ-
 mental  soundness of best available control  technology.  Once this has been completed, minor or emerg-
 ing sources  and advanced controls projected for far-term application will be considered.  The results
 of this effort will help to identify specific environmental problems which should be considered  in
 the control development program and/or future control  implementation strategies.

 Task C - Systems Analysis
       Task C differs from  other tasks in this program in that it is confined to NOX and  secondary
pollutants from NOX (e.g.,  oxidants).   Since the other tasks are aimed at quantifying environmental
 impact,  they must deal not  only with NOx and secondary pollutants from NOX, but with all  other  pol-
lutants  potentially affected by NOX controls.  Air quality modeling of these other pollutants would,
                                                xi i

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ideally, be beneficial in the environmental impact assessment, but beyond the scope of this program
(and generally beyond the state of the art).  The air quality modeling in Task C, therefore, focuses
on the impact of alternate NOX controls on ambient concentrations of N02 and secondary pollutants
from NOX.  The impact on other pollutants is factored into the air quality model  externally during
the final ranking of control systems.
       The Systems Analysis effort will be conducted in two stages.   The first stage, preliminary
screening, will focus solely on controls requirements to maintain the current NOg annual  average air
quality standard.  For this stage, a crude, nonreactive, modified rollback model  will be  used to
scope the most cost-effective combustion modification controls for a number of possible mobile source
control and source growth scenarios.  Two Air Quality Control Regions (AQCRs), encompassing a broad
range of equipment/fuel types and stationary/mobile emissions, will  be modeled.
       The second stage of the Systems Analysis will use a reactive dispersion air quality model to
assess short-term standards and standards based on secondary pollutants from NOX.  In this stage,
three additional AQCRs will be considered.  Gridded inventories and growth projections for specific
AQCRs will be compiled for the more  complex air quality model.
       The results of the efforts discussed here will be documented in a series  of reports as follows:
       •   First Annual Report:  July 1977
       •   Emission and Pollution Potential Characterizations of Stationary Combustion NOX Sources
           (Bl):  September 1977
       •   Process Engineering and Environmental Assessment of NOX Controls for  Utility Boilers:
           January 1978
       •   Process Engineering and Environmental Assessment of NOX Controls for  Industrial Boilers
           (B5):  May 1978
       •   Process Engineering and Environmental Assessment of NOX Controls for  Gas Turbines (B5):
           September 1978
       •   Process Engineering and Environmental Assessment of NOX Controls for  Residential and
           Commercial  Heating Systems (B5):  November 1978
       •   Second Annual  Report:   July 1978
       0   Assessment of Alternate Clean Fuels Use in Area Sources (B4):  September 1978
                                             xm

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 •   Process  Engineering  and  Environmental Assessment of NOX Controls for  1C  Engines  (B5):
     December 1978

 •   Process  Engineering and  Environmental Assessment of NOX Controls for Industrial Process
     Furnaces  (B5):  March 1979

•    Process Engineering and Environmental Assessment of NOX Controls for Advanced Combustion
    Systems (B5):  May 1979
•   Final Report:  July 1979
                                      xiv

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                                         TABLE OF CONTENTS


Section                                                                                        Page

   1       INTRODUCTION	•	      1-1

           1.1  Basis for Current Control Technology Requirements 	      1-1
           1.2  Anticipated Control Technology Requirements 	      1-3

           1.2.1  Attainment of NAAQS	      1-3
           1.2.2  Maintenance of NAAQS	      1-4
           1.2.3  Attainment and Maintenance of Additional NOg Standards  	      1-5

           1.3  Requirements for NOX Control Technology Development 	      1-6
           1.4  Purpose of the NOX E/A	      1-7
           1.5  Purpose of This Report	      1-7

   2       NOX SOURCE CHARACTERIZATION   	      2-1

           2.1  Stationary Fuel Combustion Sources  	      2-4

           2.1.1  Utility and Large Industrial Boilers >73 MW (>250 MBtu/hr)
                  Heat Input	      2-4
           2.1.2  Packaged Boilers  	      2-15
           2.1.3  Warm Air Furnaces and  Other Commercial and Residential
                  Combustion Equipment   	      2-20
           2.1.4  Gas Turbines	      2-30
           2.1.5  Stationary Reciprocating 1C Engines	      2-39
           2.1.6  Industrial Process Heating	      2-41
           2.1.7  Advanced Combustion Processes 	      2-47
           2.1.8  Incineration	      2-53

           2.2  Mobile Combustion Sources 	      2-53
           2.3  Noncombustion Sources 	      2-54
           2.4  Fugitive Emissions  	      2-55
           2.5  Conclusions and Summary	      2-56

           2.5.1  Data Evaluation	      2-56
           2.5.2  Tabulation of Stationary Fuel Combustion Equipment Categories 	      2-57

   3       POLLUTANT CHARACTERIZATION 	      3-1

           3.1  Pollutant Identification and Transformation 	      3-2
           3.2  Pollutant Effects Research Methodology  	      3-14

           3.2.1  Methods to Assess Ambient Pollutant Health Effects	      3-14
           3.2.2  Methods of Assessing Pollutant Impacts on Biota 	      3-23

           3.3  Concentration Estimates  for Screening Combustion Related
                Pollutants	      3-29
           3.4  Summary and Conclusions	      3-54

   4       NOX CONTROL CHARACTERIZATION  	      4-1

           4.1  Survey of NOX Control Regulations	      4-2
           4.2  Combustion Process Modifications	      4-9

           4.2.1  General Concepts on NOX Formation and Control  	      4-9
           4.2.2  Low Excess Air Firing	      4-22
           4.2.3  Flue Gas Recirculation	      4-27
           4.2.4  Off-Stoichiometric Combustion	      4-32
           4.2.5  Load Reduction	      4-37
           4.2.6  Burner Modifications   	      4-42
           4.2.7  Water Injection	      4-48
           4.2.8  Reduced Air Preheat	      4-51
           4.2.9  Ammonia Injection 	      4.54
           4.2.10  Costs of Combustion Process Modifications  	      4-57
                                                 xv

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                         TABLE OF CONTENTS (Continued)

                                                                                     4-74
 4.3  Fuel Denitrification	
                                                                                     4-74
 4.3.1  Oil Denitrifi cation	'.  .  .       4-79
 4.3.2  Coal Denitrifi cation	
                                                                        ....       4-81
 4.4  Fuel Additives	        _         4-84
 4.5  Alternate and Mixed Fuels 	
                                                                          .  .  .       4-84
 4.5.1  Western Coals	               4.35
 4.5.2  Low-Btu Gas	       4.35
 4.5.3  Medium- and High-Btu Synthetic Gas	       4_86
 4.5.4  Synthetic Oil from Coal	       4_86
 4.5.5  Coal-Oil Slurry	       4_86
 4.5.6  Methanol  	       4 07
 4.5.7  Water-Oil Emulsions 	
                                                                                     4-87
 4.6  Alternate Concepts  	  •  	
                                                                                     4 88
 4.6.1  Catalytic Combustion	       A"aQ
 4.6.2  Fluidized Bed Combustion	       ^'qn
 4.6.3  Repowering	       /Tan
 4.6.4  Combined Cycles	       7~^
 4.6.5  High Temperature Gas Turbines	       4"yl

 4.7  Flue Gas Treatment	       4"92

 4.7.1  Dry FGT Processes	       4'95
 4.7.2  Wet FGT Processes	       4~95

 4.8  Evaluation and Summary	       4-96

 MULTIMEDIA EMISSION INVENTORY OF NOX SOURCES 	       5-1

 5.1  Fuels:  Properties and Consumption  	       5-2

 5.1.1  Fuel Properties	       5-2
 5.1.2  Fuel Consumption	       5-4

 5.2  Emission Factors  	       5-15

 5.2.1  Utility and Large Industrial  Boilers   	       5-17
 5.2.2  Packaged Boilers  	       5-19
 5.2.3  Warm Air Furnaces 	       5-22
 5.2.4  Gas Turbines	       5-24
 5.2.5  Reciprocating 1C Engines	       5-24
 5.2.6  Industrial  Process  Combustion 	       5-24

 5.3  Effect of Emission Control Regulations   	       5-27

 5.3.1   Paniculate  Control	       5-29
 5.3.2  SOX Control	       5-31
 5.3.3  NOX Control	       5-31

 5.4  Emissions  Inventory 	       5-32

 5.4.1   Stationary Source Sector Emissions  	       5-33
 5.4.2   Controlled NOX  Emissions	       5-33

 5.5  Summary and Conclusions	       5-42

5.5.1  Summary of NOX Emissions from all  Sources	       5-42
5.5.2  Summary of Air Pollutant Emissions  	       5-45
5.5.3  Comparison with  Data	       5-45
5.5.4  Conclusion	       5-57
                                       xvi

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                       TABLE OF CONTENTS (Continued)


EVALUATION OF INCREMENTAL EMISSIONS DUE TO NOX CONTROLS  	       6-1

6.1  Preliminary Screening 	       6-2

6.1.1  Boilers	       6-3
6.1.2  Reciprocating 1C Engines and Gas Turbines	       6-12
6.1.3  Warm Air Furnaces 	       6-15

6.2  Emissions Data Evaluation	       6-20

6.2.1  Carbon Monoxide	       6-20
6.2.2  Hydrocarbon Emissions	       6-33
6.2.3  Particulate Emissions 	       6-41
6.2.4  Trace Metals	       6-54
6.2.5  Sulfates	       6-60
6.2.6  Organics	       6-69
6.2.7  Nitrates	       6-74

6.3  Evaluation and Summary	       6-76

ENVIRONMENTAL ASSESSMENT PRIORITIES  	       7-1

7.1  Evaluation of NOx Control Requirements  	       7-3

7.1.1  Preliminary Screening Model 	       7-4
7.1.2  Selection of the AQCRs	  .       7-11
7.1.3  Summary of Input Data and Evaluation Matrix	  .       7-19
7.1.4  Results	       7-46

7.2  Summary of Source/Control Priorities  	       7-61
7.3  Pollutant/Impact Screening  	       7-66
7.4  Future Effort	       7-74

APPENDIX A - EMISSION INVENTORY

A.I  Noncriteria Pollutant Emission Factors  	       A-l
A.2  Formulation of NOX Emission Control Factors	  .       A-l
A.3  Emission Inventory	  •       A-6

APPENDIX B - 1973 NEDS FUEL USE AND EMISSIONS REPORTS FOR
             LOS ANGELES (024) AND CHICAGO (067)	       B-l

APPENDIX C - MOBILE SOURCE EMISSIONS 	       C-l

APPENDIX D - DISPERSION MODELS FOR HEALTH EFFECTS  	       D-l

D.I  Point Sources	       D-l
                                      xvn

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                                       LIST  OF  ILLUSTRATIONS

Figure
2-1
  2-2      Utility  boiler equipment population based  on  number
          of  installed  units
  2-3       Firing method  versus  boiler size  for  pulverized  coal-fired
           (dry  bottom) utility  boilers
           Sources of nitrogen oxide emissions  .....................       2"3
  2-4      Coal-fired  utility  boiler  combustion  process  flow diagram ..........        2-13
  2-5      Utility  boiler  equipment categories  .....................        2'17
  2-6      Packaged boiler equipment  categories   ....................        2-23
  2-7      Warm air furnaces  and related  combustion  equipment  .............        2-24
  2-8      Important commercial  and residential  combustion  equipment ..........        2-31
  2-9      Basic simple cycle gas turbine  .......................        2-32
  2-10     Important gas turbine equipment types and their  fuels  ............        2-38
  2-11     Important reciprocating 1C engine equipment  types and  their fuels  ......        2-43
  4-1      Nitrogen and sulfur content of U.S.  coal  reserves ..............    t   4-14
  4-2      Conversion of fuel  N in practical combustors   ................        4-16
  4-3      Possible fate of fuel nitrogen contained  in  coal  particles
           during combustion ..............................        4-17
  4-4      Conversion of nitrogen in  coal to NOX ....................        4-19
  4-5      Operating results of Scattergood unit No. 3  of LADWP;
           nitric oxide emissions below 35 ppm .....................        4-41
  4-6      1975 capital cost of OFA on new tangential coal -fired  boilers  ........        4-58
  4-7      1975 capital cost of OFA on existing coal-fired  boilers  ...........        4-59
  4-8      Pyridine HDN with NiMo/Al203 catalyst ....................        4-77
  4-9      Hydrogen consumption versus nitrogen removal   ................        4-78
  5-1      Distribution of anthropogenic NOX emissions  for  the year 1974
           (stationary fuel combustion:  controlled  NOX levels)  ............        5-44
  5-2      Distribution of stationary anthropogenic  NOX emissions for the
           year 1974 (stationary fuel combustion:  controlled NOX levels)  .......        5-47
  6-1      Effect of excess air on emissions from an oil-fired
           warm air furnace
  6-2      Effect of derating on 1C engine HC emissions  ...........                  6_og
  6-3      Effect of retarding ignition on 1C engine HC emissions  ........             6_36
  6-4      Effect of air-to-fuel ratio on 1C engine HC emissions                               c -so
                                                                     ..........       U-JO
  6-5      Effect of decreased manifold air temperature on 1C engine HC emissions  .  .   .       6-39
  6-6      Effect of water injection on 1C engine HC emissions
                                                                     **•
                                                xvi i i

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                                 LIST  OF  ILLUSTRATIONS  (Concluded)
Figure                                                                                        Page
 6-7       Effect  of combustion  air swirl  on  solid emissions with oil  combustion  ....       6-43
 6-8       Effect  of NOX  controls on solid particulate  emissions from
           industrial  boilers   	       6-48
 6-9       Effects of NOX controls on  particulate  size  distribution  from
           oil-fired industrial  boilers	       6-49
 6-10     Smoke levels versus  NOx levels  for large bore  diesel engines   	       6-51
 6-11     Gas  turbine particulate emissions  as  a  function  of  load	       6-53
 6-12     Partitioning of Class I elements	       6-57
 6-13     Partitioning of Class II elements	,	       6-58
 6-14     Sulfate formation regimes of importance 	       6-64
 6-15     SOg  conversion vs.  excess oxygen	       6-67
  7-1       Flow chart for the preliminary screening model  	       7-9
  7-2       Distribution of a source into new and old equipment	       7-28
  7-3       Cumulative cost and reduction in ambient concentration for  application
           of the controls in Table 7-31  (preliminary process  data,  Los Angeles,
           2000, nominal  growth, 1973 concentration = 132 yg/m3)  	       7-54
  7-4       Cumulative cost and reduction in ambient concentration for  application
           of the controls in Table 7-32 (preliminary process  data,  Chicago,  2000,
           nominal growth, 1973 concentration =  96 yg/m3)	       7-55
 A-l       Sample emission listing 	       A-7
  C-l       Speed variation of speed adjustment factors  for  oxides of nitrogen   	       C-5
                                                xix

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                                          LIST  OF  TABLES

Table
 2-1        Design  and  Operating  Characteristics of Utility  Boilers  	       2-11
 2-2        Combustion  Related  Effluent  Streams  from a  Utility Boiler	       2-14
 2-3        Effect  of Nonstandard Operating Procedures  on  the Effluent
           Streams from a  Dry  Bottom  Pulverized Coal-Fired  Boiler  	       2-16
 2-4        Typical Design  and  Operating Characteristics of  Packaged Boilers	       2-21
 2-5        Packaged Boiler Effluent Streams  	       2-22
 2-6        Design  and  Operating  Characteristics of a Typical  29 KW
           Gas-Fired Forced Air Furnace
                                                                                               2-28
 2-7       Design and Operating Characteristics  of a  Typical  29  KW
           Oil-Fired Forced Air Furnace  	        2-29
 2-8       Operating Characteristics  of a Typical  Electrical  Utility Gas
           Turbine and a Combined Cycle Unit (Oil  Fuel)	        2-36
 2-9       Typical Operating Characteristics of  a  Simple Cycle and a
           Regenerative Cycle Medium  Capacity and  a Simple Cycle Small
           Capacity Gas Turbine	        2-37
 2-10      Design and Operational Adjustments Which Affect Emissions
           for 1C Engines	        2-42
 2-11      Significant Industrial Process Heating  Equipment Types  	        2-48
 2-12      Advanced Combustion Systems - State of  Development  	        2-49
 2-13      Significant Stationary Fuel Combustion  Equipment Types/Major Fuels  	        2-58
 3-1       Preliminary Pollutant Catalog 	        3-4
 3-2       Methods for Determining Health Effects  of  Air Pollutants  	        3-15
 3-3       Methods of Assessing Pollutant Impacts  Upon Aquatic and
           Terrestrial Systems	        3-24
 3-4       Estimation of Concentrations for Screening Combustion-Generated
           Pollutants	        3-30
 3-5       Environmental Significance of Some Chemicals  That May Exist in Airborne,
           Liquid, and Solid Effluents from Stationary Combustion Sources  	        3-45
 4-1       Current or Planned Federal Standards  of Performance  for New
           Stationary Sources  	        4.4
 4-2       Summary of State and Local NOX Emission Standards 	        4.5
 4-3       Factors Controlling the Formation of  Thermal  NOX  	        4-13
 4-4       Summary of Combustion Process.Modification Concepts  	           4_2i
 4-5       Summary of Results with Low Excess Air  Firing	           4.23
 4-6       Summary of Results with Flue Gas Recirculation	           4_2g
 4-7       Summary of Results with Off-Stoichiometric Combustion	               4.34
 4-8       Summary of Results with Load Reduction	                 .  ,„
                                                 xx

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                                   LIST OF TABLES (Continued)

4-9       Summary of Results with Burner Modifications  	       4-44
4-10      Summary of Results with Water Injection 	       4-49
4-11      Summary of Results with Reduced Air Preheat	       4-52
4-12      Summary of Results with Ammonia Injection 	       4-56
4-13      1974 Estimated Investment Costs for Low Excess Air Firing on
          Existing Boilers Needing Modifications	       4-61
4-14      1975 Installed Equipment Costs for Existing PG&E Residual
          Oil-Fired Utility Boilers	       4-62
4-15      LADWP  Estimated  Installed 1974 Capital Costs for NOX Reduction
          Techniques on Gas- and Oil-Fired Utility Boilers	       4-64
4-16      1975 Differential Operating Costs of OFA on New and Existing Tangential
          Coal-Fired Utility Boilers	       4-65
4-17      Cost Impacts of  NOX  Controls for Large Bore Engines	       4-68
4-18      Typical  1974 Baseline Costs for Large  (>75 kW/Cylinder) Engines 	       4-69
4-19      Impact of NOX Emission Control on the  Installed 1975 Capital Cost
          of  Gas Turbines	<	       4-71
4-20      1975 Costs for Water Injection, Mills/kWhr   	       4-72
4-21      Hydrodesulfurization Performance of the Gulf Process   	       4-75
4-22      Solvent Refined  Coal  Tests	       4-80
4-23      Fuel Additives with  Possible Peripheral Benefits to _NOX
          Control  Techniques in Boilers  	       4-83
4-24      Summary of FGT Processes	       4-93
4-25      1974 Cost Estimates  for Combustion Flue Gas Treatment  Processes 	       4-97
4-26      Summary of NOX Control Technology	       4-98
4-27      Overall  Evaluation of NOX Control Techniques  	       4-102
5-1       Properties and Trace Elements  of Representative Fossil Fuels  	       5-5
5-2       1974 Stationary  Source Fuel Consumption 	       5-7
5-3       Utility Boiler Fuel  Consumption  (kJ x  10~15)  	       5-8
5-4       1974 Packaged Boiler Fuel Consumption  (kJ x  10"1S)	       5-10
5-5       1974 Warm Air Furnace and Other Commercial/Residential
          Combustion (kJ x 10"15)	       5-12
5-6       1974 Gas Turbine Fuel Consumption  (kJ  x 10"15)	       5-12
5-7       1974 Reciprocating 1C Engine Fuel Consumption (kJ  x 10"15)	       5-14
5-8       1974 Industrial  Process Heating Production   	       5-16
5-9       Utility Boiler Criteria Pollutant Emission Factors  (ng/J)	       5-18
5-10      Package  Boiler Criteria Pollutant Emission Factors  (ng/J)  	       5-20
                                               xxi

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                                    LIST OF TABLES  (Continued)

 5-11      Warm Air Furnace  and  Miscellaneous Commercial and Residential
           Combustion Criteria Pollutant Emission Factors  (ng/J)
 5-12      Gas Turbine Criteria Pollutant  Emission  Factors  (ng/J)   •  •  •  •  .......        5"25
 5-13      Reciprocating 1C  Engine  Criteria  Pollutant  Emission  Factors  (ng/J)   .....        5-26
 5-14      Industrial  Process  Combustion Criteria Pollutant Emission
           Factors (g/kg Product)   ...........................        5'ZB
 5-15      Average Parti cul ate Collection   .......................        5"30
 5-16      NOX Control Factors .............................        5'32
 5-17      1974 Criteria Pollutant  Emissions for the Utility Boiler Sector
           (Uncontrolled NOX)  1,000 Mg/yr   .......................        5-34
 5-18      1974 Criteria Pollutant  Emissions for the Package Boiler Sector
           (Uncontrolled NOX)  1,000 Mg/yr   .......................        5-35
 5-19      1974 Criteria Pollutant  Emissions for the Warm Air Furnace and
           Misc-Combustion Sector  (Uncontrolled NOX) 1,000 Mg/yr  ............        5-36
 5-20      1974 Criteria Pollutant  Emissions for the Gas Turbine  Sector
           (Uncontrolled NOX)  1,000 Mg/yr   .......................        5-37
 5-21      1974 Criteria Pollutant  Emissions for the Reciprocating  I.C.
           Engine Sector (Uncontrolled NOX)  1,000 Mg/yr  ................        5-38
 5-22      1974 Criteria Pollutant  Emissions for the Industrial Process  Heating
           Sector (Uncontrolled NOX) 1,000 Mg/yr ....................        5-39
 5-23      Criteria Pollutant  Emissions by Sector  (Uncontrolled NOX)  1,000  Mg/yr  ....        5-40
 5-24      Comparison  of Controlled and Uncontrolled Stationary Source  NOX
           Emissions .... ..............................        5-41
 5-25      Summary of  1974 U.S.  Anthropogenic NOX Emissions  ..............        5-43
 5-26      Summary of  1974 Stationary Source NOX Emissions by Fuel  —
           1,000 Mg (Percent of Total)  .........................        5-46
 5-27      1974 Summary of Air and  Solid Pollutant  Emission from
           Stationary  Fuel  Burning  Equipment (1,000 Mg)  ................        5-48
 5-28      Fuel  Consumption  Ranking of Stationary Combustion Sources  ..........        5-49
 5-29      SOX Mass  Emission Ranking of Stationary  Combustion Equipment  ........        5-50
 5-30      CO  Mass  Emission  Ranking of Stationary Combustion Equipment  .........        5-51
 5-31       HC  Mass  Emission  Ranking of Stationary Combustion Equipment  .........        5-52
 5-32       Paniculate Mass  Emission Ranking of Stationary Combustion Equipment  ....        5-53
 5-33       NOX Mass  Emission Ranking of Stationary  Combustion Equipment and
           Criteria  Pollutant  and Fuel  Use Cross Ranking ................        5-54
5-34       Comparison  of Stationary Uncontrolled NOX Emissions  (1,000 Mg)  .......        5-56
5-35       Comparison  of Stationary Source Annual Fuel Consumption
           Estimates (1015 kJ)  .............................        5-58
5-36       Comparison  of Current Stationary  Emission Estimates  Data with
           Previous Studies  (1,000  Mg)  .........................        5-59
                                              xxi i

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                                   LIST OF TABLES  (Continued)

6-1       Postulated Effect of Combustion Conditions on Flue Gas Emissions
          from Boilers	       6-4
6-2       Postulated Overall Effect of Combustion  NOX Controls on Flue
          Gas Emissions from Boilers	       6-10
6-3       Postulated Effects of Combustion Conditions on Emissions from
          1C Engines and Gas Turbines	       6-13
6-4       Postulated Overall Effect of Combustion  NOX Controls on
          Emissions from 1C Engines   	       6-16
6-5       Postulated Overall Effect of Combustion  NOX Controls on
          Emissions from Gas Turbines	       6-18
6-6       Effect of Low-N0x Operation on  Incremental Emissions and
          System Performance for  Residential Warm  Air Furnaces   	       6-22
6-1       Representative Effects  of NOX Controls on CO Emission  from
          Utility  Boilers  	       6-24
6-8       Effects  of NOX Controls on CO Emissions  from Industrial Boilers  	       6-28
6-9       Representative Effects  of NOX Controls on CO Emissions from
          1C Engines	       6-31
6-10      Representative Effects  of NOX Controls on CO Emissions from
          Gas Turbines	       6-32
6-11      Representative Effects  of NOX Controls on Vapor  Phase  Hydrocarbon
          Emissions from Industrial Boilers  	       6-35
6-12      Summary  of the Effects  of NOX Controls on Vapor  Phase  Hydrocarbon
          Emissions from Gas Turbines	       6-40
6-13      Effects  of NOx Controls on Particulate Emissions  from  Coal-Fired
          Utility  Boilers	       6-45
6-14      Effects  of NOX Controls on Emitted Particle Size Distribution
          from  Coal-Fired  Utility Boilers	       6-46
6-15      Relationship  Between  Smoke, EGR, and  Retard  	       6-52
6-16      Mechanisms that  Convert Sulfur  Dioxide to Sulfates   	       6-61
6-17      SOX Summary	'	       6-68
6-18      Summary  of Process Modifications to Reduce Acid  Smut Fallout   	       6-70
6-19      Summary  of POM Emission Tests	       6-73
6-20      Nitrate  Formation Mechanisms   	       6-75
6-21      Evaluation of Incremental Emissions Due  to NOX Controls Applied
          to Boilers	       6-77
6-22      Evaluation of Incremental Emissions Due  to NOx Controls Applied
          to 1C Engines	,	       6-78
6-23      Evaluation of Incremental Emissions Due  to NOX Controls Applied
          to Gas Turbines	       6-79
                                               xxiii

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                                    LIST OF TABLES (Continued)

 7-1        Summary  of Available Air  Quality Models 	
 7-2        NOX Impacted  AQCRs  and AQMAs (Rolling Quarters Average) 	       7"13
 7-3        Air Pollution Characteristics of the NOX Impacted AQCRs and AQMAs 	       7-16
 7-4        Characteristic Groups of  NOX Impacted AQCRs and AQMAs 	       7"18
 7-5        1973 NOX Emissions  and Fuel Use for Los Angeles, AQCR 024	       7-21
 7-6        1973 NOX Emissions  and Fuel Use for Chicago, AQCR 067	       7-22
 7-7        Maximum  Annual  Average N02 Concentration, Los Angeles, AQCR 024 	       7-23
 7-8        Maximum  Annual  Average N02 Concentration, Chicago, AQCR 067 	       7-23
 7-9        Annual Average NO?  Concentration Used for Model Calibration
           (wg/m3)	       7-23
 7-10      Average  Growth Rates in Annual Fuel Use for Stationary Sources
           in  Chicago, AQCR  067	       7-25
 7-11       Increase in Fuel  Use in Future Years for Chicago, AQCR 067, 1973 Base ....       7-25
 7-12       Average  Growth Rates in Annual Fuel Use for Stationary Sources in
           Los Angeles,  AQCR 024	       7-27
 7-13       Increase in Fuel  Use in Future Years for Los Angeles, AQCR 024;
           1973 Base	       7-27
 7-14       Equipment Retirement Rates  	       7-29
 7-15       Mobile Source Emission Factors (g/km) and Annual Growth Rates  	       7-31
 7-16       Mobile Source NOX Emissions (All Values in Gg/yr Expressed as  N02)  	       7-32
 7-17       Fuel  Costs in the Chicago AQCR, 1973-2000	       7-33
 7-18       Fuel  Costs in the Los Angeles AQCR, 1973-2000	       7-34
 7-19       Cost of  NOX Controls for Coal-Fired Utility Boilers	       7-36
 7-20       Cost  of  NOX Controls for Gas- and Oil-Fired Utility  Boilers	       7-37
 7-21        Cost  of  NOX Controls for Coal-Fired Industrial Watertube Boilers  	       7-38
 7-22       Cost  of  NOX Controls for Gas- and Oil-Fired Industrial Watertube
           Boilers	       7-39
 7-23       Cost  of  NOX Controls for Gas- and Oil-Fired Industrial Firetube
           Boilers	       7-40
7-24       Cost  of  NOX Controls for Gas- and Oil-Fired Residential Furnaces  	       7-41
7-25       Cost  of  NOX Control for Gas Turbines	       7-42
7-26        Cost  of  NOX Controls for  1C Engines	       7.43
7-27       Cost of  NOX Controls for  Industrial Process Furnaces	       7.44
7-28       Evaluation Matrix, Growth Scenarios 	       7.47
7-29       Evaluation Matrix:  Base Year Concentration and Source Weighting
           Factors  for Los Angeles	       7.45
                                                xxiv

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                                   LIST OF TABLES (Continued)





7-30      Evaluation Matrix:  Base Year Concentrations and Source
7-31

7-32
7-33

7-34

7-35
7-36
7-37

7-38

7-39
A-l
A- 2
A- 3

A-4
A- 5
A-6
A- 7
A- 8
A-9
B-l
B-2
B-3
B-4
C-l
C-2

C-3
C-4
C-5

Control Prioritization for Los Angeles (2000, Equal Source
Weighting) 	
Control Prioritization for Chicago (2000, Equal Source Weighting) 	
Summary of Control Levels Required to Meet N02 Standard in
Los Angeles, AQCR 024 	
Summary of Control Levels Required to Meet NOg Standard in
Chicago, AQCR 067 	
Evaluation of NOX E/A Source Priorities 	
Summary of NOX E/A Source/Control Priorities 	
Comparison of Pollutant Emission Levels with NOX Controls to Maximum
Allowable Emissions 	
Comparison of Baseline Pollutant Emission Levels to Maximum
Allowable Emissions 	
Summary of Potential Pollutant/Combustion Source Hazards 	
Sector I Noncriteria Pollutant Emission Factors 	
Metal Emission Factors (ng/J) -Sector I 	
Packaged Boiler Sulfate and POM Emission Factors Liquid and Solid
Ash Stream Generation Factors 	
Warm Air Furnace POM Emission Factors 	
Fuel Type Codes 	 	
Emission Inventory - Group I Pollutants 	
Emission Inventory — Group II Pollutants 	
Emission Inventory - Group III Pollutants 	
Emission Inventory — Group IV Pollutants 	
NEDS Annual Fuel Summary for Chicago, AQCR 067 	
NEDS Annual Emissions Report for Chicago, AQCR 067 	
NEDS Annual Fuel Summary for Los Angeles, AQCR 024 	
NEDS Annual Emission Report for Los Angeles, AQCR 024 	
Vehicle Polutation and Annual Distance Traveled vs. Vehicle Age 	
Deterioration Factors for Light-Duty Passenger Cars and Light-
Duty Trucks 	
Los Angeles AQCR Registered Vehicle Population 	
Chicago AQCR Registered Vehicle Population 	
Vehicle Distribution as a Percentage of all Registered Trucks
and Automobiles 	

. . 7-51
. . 7-52

. . 7-57

. . 7-59
, . 7-63
7-67

. . 7-69

. . 7-70
. . 7-73
. . A-2
A- 3

. . A-4
. . A-5
. . A-8
. . A-9
A-25
A-32
. . A-39
. . B-3
B-4
. . B-8
. . B-9
. . C-3

. . C-4
. . C-7
. . C-8

. . C-1C
                                               XXV

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                                   LIST OF TABLES (Concluded)


C-6       Mobile Source Emission Factors g/km 	     C-10

C-7       A Comparison of the Calculated Vehicle Population and the
          Registered Vehicle Population (1,000 Vehicles)   .  .  .	     C-10

C-8       Mobile Source Emission Factors (g/km) and Annual  Growth Rates 	     C-14

C-9       Mobile Source Emissions of Oxides of Nitrogen in  the Los Angeles
          AQCR (Gg/year)	     C-15

C-10      Mobile Source Emissions of Oxides of Nitrogen in  the Chicago AQCR
          (Gg/year)	     C-15

D-l       Sample Calculations of (Xu/e) Max for Point Sources in the
          Chicago AQCR	     D-3
                                              xxvi

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                                              SECTION  1
                                            INTRODUCTION

       Since the Clean Air Act of 1970, a moderate level of NOX control has been developed and/or
implemented for a variety of stationary combustion NOX sources.  Recently, however, EPA has deter-
mined that additional stationary source control technology is needed to maintain N02 air quality.
The need for this additional technology is caused by the relaxation of mobile source standards,  the
increasing growth of stationary source NOX emissions, and the consideration by the EPA of more
stringent N02 air quality standards.
       With more NO  controls being implemented in the field and expanded control development antic-
ipated for the future, there is currently a need to (1) ensure that the current and emerging control
techniques are environmentally sound, and compatible with efficient and economical operation of  sys-
tems to which they are applied and  (2) ensure that the scope and the timing of the new control devel-
opment program are adequate to allow stationary sources of NO  to comply with potential air quality
standards.  The NO  E/A program addresses these needs by (1) identifying the incremental multimedia
environmental impact of combustion modification NO  controls, and (2) identifying specific source/
control combinations which will make it possible to maintain alternate ambient N02 standards in  the
most cost-effective manner to the year 2000 in N02-critical areas.  As a prelude to the NO  E/A
program, this report documents the preliminary characterization and data evaluation of the equipment,
controls, emissions, and environmental impacts to be considered in the program.

1.1    BASIS FOR CURRENT CONTROL TECHNOLOGY REQUIREMENTS
       In 1971, following provisions of the 1970 Clean Air Act amendments, the EPA promulgated a
primary and secondary National Ambient Air Quality Standard (NAAQS) for N02 of 100 ug/m3 (annual
average).  Ambient N02 measurements made with the Jacob-Hocheiser Federal Reference Method in that
year showed that 47 Air Quality Control Regions (AQCRs) were in violation of the standard.  At that
time, the EPA NO  abatement strategy for attaining and maintaining the NAAQS for N02 relied heavily
on NO  controls for mobile sources.  As mandated by the Clean Air Act, light duty vehicle  (LDV)
emissions were to be reduced by 90 percent to a level of 0.25 g N02/km (0.4 g/mile) by 1976.  Sta-
tionary sources were to be regulated through EPA Standards of Performance for New Stationary  Sources,

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 which would  be  set  as  technology became available on the basis of the best system of emissions  re-
 duction.   Additional standards for new or existing sources required to achieve air quality in the
 AQCRs would  be  set  through the State Implementation Plans.
        To  support this abatement strategy, EPA set up a stationary source NOX control development
 program.   This  program concentrated on controlling NOX through combustion process modifications,
 since earlier studies  by the National Air Pollution Control Administration (Reference 1-1} showed
 that this  approach  was the easiest to implement and the most cost effective.   Because of the strong
 emphasis placed on  controlling mobile sources at that time, a limited scope was set for the sta-
 tionary source  control development program.  As a result, the stationary source program has focused
 on achieving a  moderate level of control for conventional equipment categories readily amenable to
 combustion process  modification.  At the same time, equipment users and manufacturers have con-
 ducted  programs for developing NO  controls.  The technology developed and/or disseminated by these
 programs in  the EPA and the private sector has brought about widespread implementation of stationary
 source  NOX controls.
        Stationary source NO  controls have been applied to existing utility boilers,  large indus-
 trial boilers and gas turbines in a number of areas as part of State Implementation Plans (see
 Section 4.1).   As more areas regulate stationary sources and smaller equipment is brought under regu-
 lation  in  some  areas, the trend is to widespread use of retrofit NOX controls.  In addition,  new
 sources with factory-installed NOV controls are being commissioned in compliance with the EPA Stan-
                                 A
 dards of Performance for New Stationary Sources set in 1971 for large steam generators firing gas,
 oil  and coal (except lignite).  A standard for lignite coal firing and a more stringent standard for
 bituminous coal  firing have been recommended.  Draft standards for gas turbines and stationary  1C
 engines are  in  preparation and standards for intermediate boilers are under study.
       This  increasing regulation of both new and existing sources of NO  emissions points, in the
 1980's,  to widespread implementation of moderate NOX controls on major equipment types.   Further-
more, these moderate NOX controls correspond to the moderate level of technology being generated in
the control development program in accordance with the original NOX abatement strategy.   Recent
reappraisals  of this abatement strategy,  however, have raised questions about whether or not this
degree of  control development  and implementation is adequate to meet N02 air quality goals.
                                                 1-2

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1.2    ANTICIPATED CONTROL TECHNOLOGY REQUIREMENTS
       In the past 3 years, several developments  have brought about changes in the national
NOX abatement strategy:
       •   Reclassification of AQCRs violating the N02 NAAQS
       •   Relaxation of the LDV NOX standards
       •   Projections of continued rapid growth  of stationary NO  sources
       •   Increasing use of coal in stationary sources
       •   Emergence of advanced energy systems with potential environmental problems
       •   Consideration of additional N02 air quality standards
These developments have, in turn, changed the existing implementation requirements for NO  controls —
or added new requirements - for accomplishing the three goals of the abatement strategy:
       •   Attain the current NAAQS
       •   Maintain the current NAAQS
       t   Attain and maintain anticipated new N02-related air quality standards
The current thinking on anticipated implementation requirements for controls in each  of these areas
is reviewed below.
1.2.1  Attainment of NAAQS
       The outlook for attaining the NAAQS has actually improved.  In 1973, the EPA announced that
the Federal Reference Method for ambient N02 measurement had in many cases been overestimating N02
concentrations  (Reference 1-2).  Using other analytical techniques, EPA remeasured air quality in
the 47 AQCRs where the standards were suspected of being violated.  The results showed that only
five regions (Los Angeles, New York, Chicago, Denver, Salt Lake City) were violating  the standards.
Subsequent measurements with the new Federal Reference Method (chemiluminescent analyzer) or equi-
valent have shown that as many as 16 AQCRs may have annually-averaged N02 levels equal to or greater
than the NAAQS  (Reference 1-3).  However, of the  AQCRs in violation, only the South Coast Air Basin
in the Los Angeles area has a severe problem.  There, NOX emission regulations have been set for
new and existing utility boilers, large industrial boilers, and gas turbines.
       In spite of the fact that the NOX control  problem is not as severe as originally estimated
nationwide, it has recently been determined that  additional NOX controls will  have to be implemented
                                                  1-3

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 in  the South Coast Air Basin to attain and maintain N02 air quality (Reference 1-4).  Source/control
 options are currently being evaluated to define the most cost-effective regulatory approach.  These
 near-term  control requirements appear to be largely covered by the current NOX control development
 program.   Ultimate attainment may, however, require more advanced control technology than is being
 generated  by the  current development program (see Section 7 and References 1-5, 1-9).

 1.2.2  Maintenance of NAAQS
       The fact that the attainment of NAAQS will be less difficult than anticipated has caused the
 emphasis for maintenance to shift from mobile source control  to stationary source control.  Because
 of  the errors  in  the Federal Reference Method, in 1973 the EPA Administrator delayed implementation
 of  the light duty vehicle statutory standard - 0.25 g/km (0.4 g/mile)  - and set an interim standard
 at  1.25 g/km (2.0 g N02/mile).  Subsequently the Energy Supply and Environmental  Coordination Act of
 1974 delayed the  statutory LDV standard to 1978 and maintained the interim standard at 1.25 g/km.
 The Clean  Air  Act Amendments of 1977, passed by Congress in August, further extend the emission
 schedule as follows:
                           1977 through 1980 - 1.25 g My km (2.0 g/mile)
                           1981 on           -0.62 g N02/km (1.0 g/mile).
 The earlier statutory standard of 0.25 g/km is retained as a research  objective for manufacturers.
       Several studies have evaluated the impact that these changes in mobile source NO  regulation
 will have  on the  overall NO  abatement strategy.  EPA's Office of Air  Quality Planning and Standards
 (OAQPS) conducted a study in 1973 to analyze the NO  abatement strategy in view of changes in air
                                                   X
 quality data and  source growth projections.  The OAQPS report (Reference 1-5) concluded:  (1) the
 statutory  LDV  standard is not needed in most areas to attain and maintain the NAAQS; (2) in the
 1980's, more control of stationary sources will be needed to maintain  the NAAQS; and (3) control of
 stationary sources will be more effective and less costly in the 1980's than extensive control of
 mobile sources.   As a result of this study, OAQPS recommended that the stationary source NO  control
 program be expanded to generate the additional technology needed to maintain air quality.
       Subsequent studies reinforced these conclusions on the combined effect of stationary source
 growth and the relaxation of the LDV standard.  Projections of the growth of stationary sources
 nationwide (References 1-6, 1-7) showed that even with vigorous implementation of best available
 control  technology through Standards of Performance for New Stationary Sources, nationwide NO
 emissions  would increase by at least 25 percent by 1990.  This study,  and a recent EPA assessment of
air quality maintenance strategies, (Reference 1-8) concluded that increased controls for stationary
sources  must be implemented.

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       Another study of the air quality impact of LDV emission controls and source growth (Reference
1-9) conducted by EPA and the Department of Transportation (DOT) also showed that N02 air quality
violations will increase unless more stringent stationary source controls are applied.  Of 10 cities
analyzed in this study, at least 6 are projected to fail to maintain the NAAQS in 1985, even with the
most restrictive mobile source standards.  This projected failure is attributed to the expected in-
crease in source emissions as well as to the moderate level of control mandated for these sources.
The study also examines the cost-effectiveness, on a national basis, of several mobile and stationary
source control options.  Although the cost data will be subject to revision as better process studies
become available, the results show that control of stationary sources to a level  of 50 to 75 percent
below uncontrolled levels is four times more cost-effective than reduction of LDV emissions  from
1.25 g/km (2 g/mile) to 0.25 g/km (0.4 g/mile).
       An additional factor in the maintenance of NOp air quality is the increasing use of coal
in
stationary sources as part of the National Energy plan.  Coal typically has a higher NOV emission
                                                                                       A
potential than other fuels.  Both the Energy Supply and Environmental Coordination Act (Reference
1-10) and Senate Bill 977  (Reference 1-11) mandate extensive use of coal in new and existing large
combustion sources to reduce our dependence on imported oil.  This increased use of coal, coupled
with projected utilization of high-nitrogen shale oil, could have a dominant effect on future sta-
tionary source NO  emissions (Reference 1-12).  Along with this increased use of coal, a number of
advanced energy systems are being developed to efficiently use coal or coal-derived fuels.   The in-
creased use of coal and the application of the advanced energy systems within acceptable environ-
mental limits will require the use of advanced NO  control techniques.
       In summary, recent  analyses of the requirements for maintaining NAAQS point to the need for
developing and implementing more advanced NOX controls for the 1980's and 1990's than was previously
thought.  The reevaluation of the LDV standard, the projected growth of stationary sources, and
increased emission from the use of coal are the main factors in this change of strategy.

1.2.3  Attainment and Maintenance of Additional NO? Standards
       While the above discussion deals with the requirements for stationary source controls to
achieve and maintain the current NAAQS  (100 yg/m3, annual average), there is also the possibility
that separate NOX control  requirements will be needed to attain and/or maintain additional N02~
related standards.  The current NAAQS was based on the fact that long-term exposure to N02 increases
human susceptability to chronic respiratory infection (Reference 1-13).  Short-term impacts of N02
on human health and the role of N02 in photochemical smog formation were not included in setting  the
standard.  Recent data on  the health effects of N02 suggest that the current NAAQS should  be
                                                1-5

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 supplemented with a limitation on short-term exposure (References 1-8 and 1-14 to 1-16), and  the  Clean
 Air  Act Amendments of 1977 require that the EPA consider setting a short-term N02 standard for a  period
 not  to exceed  3  hours.  The OAQPS will consider the basis for a short-term standard, as well  as poten-
 tial  revisions to the current standard, in 1978 when the N02 air quality criteria document (Reference
 1-13)  is  updated (References 1-17, 1-18).
       For the longer term, EPA  is continuing to evaluate the need for additional NOX regulation  as
 part of the oxidant control strategy or for control of pollutants for which NOX is a precursor, e.g.,
'nitrates  and nitrosamines  (References 1-8, 1-16, 1-17, 1-18, 1-20).  The Clean Air Act Amendments of
 1977 require the National  Commission on Air Quality to analyze the health effects of pollutants which
 are  derivatives  of oxides  of nitrogen.  Potential regulations resulting from these studies could  be
 in the form of source emission controls or additional ambient air quality standards.  In either case,
 additional stationary source control technology could be required to comply with the standards.

 1.3    REQUIREMENTS FOR NOV CONTROL TECHNOLOGY DEVELOPMENT
                           A
       The need  to develop NOX control technology can be divided into two areas:  (1) near-term
 application of existing technology, and (2) far-term development and implementation of advanced
 techniques not covered  by  the current development program.
       In answer to the first of these needs, the present control development program is demon-
 strating  the effectiveness of moderate combustion modification controls on major equipment types.
 At the same time, the economic,  energy, and operational impacts of these controls are being identi-
 fied.  Recently, the need  to assess the possible effect of NOX controls on other pollutants and their
 eventual  impact  on the  environment has also been emphasized.  In fact, the assessment of the  environ-
 mental impact  of both energy systems and pollutant control systems has taken on a major role  in the
 EPA/ORD R&D program, as is clearly shown by the extensive assessment activity discussed in the pref-
 ace  of this report.
       To meet far-term needs, development of new control technology will be apparently needed to
 meet the  more  stringent and widespread control requirements suggested in current planning studies.
 This would require an expanded control development program including:
       1.   Greater levels  of control for major design types
       2.   Controls for secondary design types not currently considered
       3.   Controls for alternate fuels and advanced energy systems planned for the 1980's and 1990's.
                                                  1-6

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1.4    PURPOSE OF THE NOX E/A
       The NOX E/A directly supports both the  near-  and  far-term needs described above through two
main activities.  First, it will provide comprehensive process engineering and environmental assess-
ment studies of both current and emerging combustion modification techniques.  These studies will
show the environmental, economic, energy, and  operational impacts of achieving a given level of
control for major stationary sources of NOX.   For current technology, these impacts can be considered
in the selection of control techniques.  For advanced technology, the control development program
can be planned with these impacts clearly in mind.
       Second, systems  analyses will be conducted of the impact of the application of combustion
modification controls on ambient N02 air quality.  These system analyses will show which combination
of control techniques is most  effective in  achieving alternate air quality goals in specific AQCRs.
These  results are intended  for guidance of  the second requirement in Section 1.3.  Additionally,
these  results will  set  the  scope of the process  engineering and environmental assessment efforts
within the NOX  E/A.  The overall approach of the NOX E/A is discussed in the Preface.
1.5    PURPOSE OF THIS  REPORT
       The NOX  E/A  activities  documented in this report  began with compiling and evaluating data
and defining  the program approach and  priorities.  The initial activity was thus a first-pass review
of existing  data and techniques  for all areas  of the program.  As discussed in the Preface, the
subsequent effort will  focus on  generating  new results in specific support tasks.  This pre-
liminary  report will serve  to  initiate these efforts and to establish the approach and level of
effort to be  used in various subtasks.  The objectives of this report are to (1) document the scope
of the NOX E/A  in terms of  sources, pollutants,  impacts, and controls to be considered; (2) evalu-
ate data  on  impact  criteria, control effectiveness,  baseline multimedia emissions, and incremental
impacts of NO   controls; and (3) define preliminary  priorities on source/control combinations and
effluent  stream/impacts to  be  considered.
       The report is structured  according to these objectives.  Sources of NOX, pollutants and their
impact, and  stationary  source  NO  controls  are reviewed  in Sections 2, 3, and 4 respectively.  Data
on multimedia impact criteria, control  status  and effectiveness, baseline emissions, and the incre-
mental multimedia impact of NOX controls are summarized  in Sections 3, 4, 5, and 6.  Some prelimi-
nary screening and  prioritization in these  areas are also done in these sections.  The main  conclu-
sions  from the data of  Sections 2 through 6 and  the  preliminary definition of priorities for the  NO
                                                  1-7

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E/A are summarized in Section 7.   Specific  subobjectives  addressed in  the subsequent sections
are as follows:
       •   Establish categories of stationary  fuel  combustion  NOX  sources to  be assessed in the NOX
           E/A (Section 2)
       •   Identify source  effluent streams and  operating modes  for which the emissions  may be per-
           turbed by the use of NOX controls (Section  2)
       •   Establish a preliminary set of pollutants and  their impacts to be  considered  in  the
           source/control  environmental  assessments (Section 3]
       •   Compile and evaluate dose/response  data  on  multimedia pollutant impact; tabulate impact
           criteria for use in preliminary  screening of the impact of source/effluent  stream/control
           combinations (Section  3)
       •   Identify possible approaches  and problems in conducting a generalized  (nonsite specific)
           impact assessment (Section  3)
       •   Survey available NOX control  techniques  and specify the combustion modification  technology
           to be addressed  in the program (Section  4)
       •   Evaluate the status, effectiveness, cost, and  operational impact of  current and  emerging
           combustion modification techniques  (Section 4)
       •   Compile and evaluate NOX emissions  data  for all NOX sources; generate  controlled nation-
           wide  NOX inventory (Section 5)
       •   Compile and evaluate emission  data  on pollutants other  than NOX for  stationary fuel com-
           bustion NCL sources; generate  nationwide emissions  inventory (Section  5)
                     A
       •   Evaluate the effect of NO  controls on emissions of pollutants other than NOV (Section 6)
                                    ซ                                                  X
       •   Define preliminary source/control priorities based  on projected control implementations
           requirements (Section  7)
       •   Define preliminary effluent stream/pollutant priorities  based  on potential  impact re-
           sulting from the use of NO  controls  (Section  7).\
                                    X
                                                1-E

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                                       REFERENCES FOR SECTION 1


1-1.    Bartok,  W.,  et al.5  "Systems Study of Nitrogen Oxide Control  Methods  for Stationary  Sources,
       Vol.  II," Prepared for National Air Pollution Control Administration, NTIS-PB 192 789.

1-2.    Federal  Register Volume 38, No. 110, June 8, 1973, pp. 15174-15185.

1-3.    Personal communication with E.  Lewis, Office of Air Quality Planning  and Standards,  U.S.  EPA,
       September 3, 1975.

1-4.    "Progress Report - Control Strategy for Oxides of Nitrogen in the South  Coast Air Basin,"
       California Air Resources Board, Memo No.  76-16-4, August  24,  1976.

1-5.    Crenshaw, J. and A,  Basala, "Analysis of Control Strategies to Attain the National Ambient
       Air Quality Standard for Nitrogen Dioxide."  Presented at the Washington Operation Research
       Council's Third Cost Effectiveness Seminar, Gaithersburg, Md.s March  18-19,  1974.

1-6.    Hopper,  T. G. and W. A. Marrone, "Impact of New Source Performance Standards on  1985 Emissions
       from Stationary Sources."  The Research Corporation, May  1975.

1-7.    McCutchen, G. D., "NOX Emission Trends and Federal Regulation," presented at AIChE 69th Annual
       Meeting, Chicago, Nov. 28 - Dec. 2, 1976.

1-8.    "Air Program Strategy for Attainment and Maintenance of Ambient Air Quality  Standards and
       Control  of Other Pollutants," Draft Report, U.S. EPA, Washington, October 18,  1976.

1-9.    "Air Quality, Noise and Health - Report of a Panel of the Interagency Task Force on  Motor
       Vehicle Goals Beyond 1980," Department of Transportation, March 1976.

1-10.  "Energy Supply and Environmental Coordination Act," Public Law 93-319.

1-11.  "National Petroleum and Natural Gas Conservation and Coal Conversion  Act of  1975," Senate Bill
       977 (first introduced as 1777 on May 20, 1975).

1-12.  Sarofim, A. F., et al., "Mechanisms and Kinetics of NO* Formation:  Recent Developments,"
       presented at the 69th Annual Meeting, AIChE, Chicago, Illinois, November 1976.

1-13.  "Report on Air Quality Criteria for Nitrogeh Oxides," AP-84,  Science  Advisory Board,
       U.S. EPA, June 1976.

1-14.  Stephens, R. H., et al., "Standard Support and Environmental  Impact Statement for Standards
       of Performance:  Lignite-Fired Steam Generators."  EPA Office of Air  Quality Planning and
       Standards, March 1975.

1-15.  "Scientific and Technical Data Base for Criteria and Hazardous Pollutants - 1975 ERC/RTP
       Review," EPA-600/1-76-023, NTIS-PB 253 942/AS, Health Effects Research Laboratory, U.S. EPA,
       January 1976.

1-16.  French, J. G., "Health Effects from Exposure to Oxides of Nitrogen,"  presented at the
       69th Annual Meeting, AIChE, Chicago, Illinois, November 1976.

1-17.  "Control Strategy for Nitrogen Oxides," memo from B. J. Steigerwald,  Office  of Air Quality
       Planning and Standards, September 1976.

1-18.  "Report on Air Quality Criteria:  General Comments and Recommendations," Report to the
       U.S. EPA by the National Air Quality Advisory Committee of the Science Advisory Board,
       June 1976.

1-19.  Personal communication with M. Jones, Strategies and Air  Standards Division, Pollutant
       Strategies Branch, September 15, 1976.

1-20.  "Control of Photochemical Oxidants -Technical Basis and Implications of Recent Findings,"
       EPA 450/2-75-005, EPA Office of Air and Waste Management, OAQPS, July 1976.

1-21.  "Scientific and Technical Assessment Report on Nitrosamines,"  EPA 600/6-77-001, EPA Office
       of Research and Development, November 1976.
                                                  1-9

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                                             SECTION 2



                                    N0y SOURCE CHARACTERIZATION
                                      A          *



       This section presents a preliminary characterization of NO  sources for use in prioritizing and



simplifying the environmental assessment and process engineering efforts in this program.  The main



objective of this preliminary characterization is to categorize equipment design according to char-



acteristics which affect the formation and/or control of multimedia pollutants.  Emphasis is on sta-


tionary combustion sources of NO .  However, the remaining sources of NO  are also of interest in
                                X                                       X

this program, since the degree of control for emissions from these sources governs the extent to



which NO  controls are needed for stationary combustion sources.   The equipment categories described


in this section will be used as the basis of the emission inventory in Section 5 and the preliminary



source prioritization in Section 7.  Subsequently, these categories will be further refined as  part


of the process engineering studies in Task B5 (see Preface).
       In order to make this preliminary characterization of NO  sources,  the following  steps  were
taken:
       •   Identify significant sources of NO ; group according to formative mechanism and nature
                                             X


           of release into the atmosphere



       •   Categorize stationary combustion sources according to equipment and/or fuel character-



           istics affecting the generation and/or control of combustion-generated pollution



       •   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



           the subsequent emission inventories, process studies, and environmental assessments



       t   Identify effluent streams from stationary combustion source equipment/fuel categories



           which may be perturbed by the use of NO  combustion modification controls



       •   Identify operating modes (transients, upsets, maintenance) for which the emissions may



           be perturbed by NO  combustion modification controls
                             A
                                                2-1

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        The following paragraphs  summarize  the approach  used  in  each  step  of this  sequence.
        Significant sources  of NO  have  been  identified  in  several  previous  studies  (References 2-1
 through 2-5).   These sources  are grouped in  Figure  2-1  according  to  the way N0x  is  released into
 the atmosphere and the mechanisms leading  to its  formation.   Primary emphasis  in  the N0x E/A is
 on the seven major categories of stationary  fuel  combustion  sources  bracketed  on  the figure:
        •   Utility and large  industrial boilers >73 MW  (250  x 106  Btu/hr) heat input
        t   Industrial and commercial  packaged watertube and  firetube boilers
        •   Commercial and residential warm air furnaces
        •   Utility and industrial gas turbines
        •   Reciprocating 1C engines
        t   Industrial process combustion equipment
        •   Advanced combustion processes
 The remaining sources will  be considered only as  required  to determine the  relative  amount  of  NO
 contributed by combustion sources on  a  regional or  national  basis.
        The major source category groupings in Figure  2-1 are broad,  particularly  for stationary fuel
 combustion sources,  in that they each encompass a number of  design variations  and fuels.  Since
 many of these  design variations  affect  the emission rates  of combustion-generated pollutants and
 the applicability and effectiveness of  NO  controls,  they  may merit  separate consideration  in  the
 emission inventories and environmental  assessments.   The stationary  fuel  combustion  source  groupings
 are therefore  further subdivided in this section  according to the  following factors  which are  known
 to  influence combustion-generated air pollution:
        •   Combustion chamber configuration
        •    Combustion intensity
        •    Temperature-time history of  combustion gases
        •    Aerodynamics  of  fuel-air mixing
        •    Fuel  composition (bound nitrogen, trace  elements) and  combustion conditions  (flame  tem-
            perature,  excess air  requirements)
Where possible,  these  factors  are interpreted in  light  of  existing source emission  data and experience
in applying NO   controls  to determine appropriate source categories.  These data  are reviewed  in
Sections 4 and 5.
                                                2-2

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Sources of
nitrogen-=—
oxides
                 Combustion
                 •effluent strea
                 emissions
Nonconbustlon
ef f 1 went
stream  	
emissions
(Section 2.3)
                  Fugitive
                —emissions —
                  (Section 2.4)
                                              Stationary
                                              '(Section Z.lT
                                                                    Fuel
                                                                   "combustion'
                                                 —Incineration
                                               Mobile
                                               (Section 2.2)
                                             ,—Natural
                                             — Anthropogenic
                                                                    —Utility boilers

                                                                    — Packaged boilers

                                                                    — Warm air furnaces

                                                                    — Gas turbines

                                                                    — Reciprocating 1C engines

                                                                    — Industrial process combustion

                                                                    -'Advanced combustion processes
                               Emphasl*
                             \of
                             ' NO. E/A
r-NUHc add

-Ad1p1c add

  Explosives

-Fertilizer

-Nitration
C                                                                      Nitrogen cycle

                                                                      Lightning


                                                                    - Open burning

                                                                    - Forest fires

                                                                    - Structural fires

                                                                    — Minor processes
                         Figure  2-1.    Sources  of  nitrogen  oxide  emissions.
                                                             2-3

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        The number of equipment/fuel combinations resulting from this categorization is  far
 too large (approximately  150)  to  treat comprehensively at the same level of detail in this  program.
 Accordingly,  preliminary  prioritization of  these equipment/fuel combinations  is  undertaken  in
 Section 7, based on the quantification of source emissions and the evaluation of the potential
 applications  of NO  control  for various equipment/fuel types.  In addition, some preliminary screen-
                   A
 ing of equipment and fuels  can be done in advance.  There are a number of equipment designs in  the
 field which are no longer being manufactured.  Since the bulk of these sources are scheduled to
 be retired and have not been retrofitted with N0x controls, they are outside  the scope  of the en-
 vironmental assessment study.   These  older  types of equipment are noted in this  section and generally
 grouped together rather than categorized separately.  They will be carried through the  emission in-
 ventory in Section 5 but  will  generally be  deemphasized in subsequent process studies.
        The final  step in  the source characterization is the identification, for  each major source
 category, of  the effluent streams and nonstandard operating conditions which may be affected by the
 use of NO  controls.   This  exercise is a prelude to the subsequent B3 test programs and B5 process
 studies,  where the quantification of  the impact of NO  controls on multimedia effluent streams, in-
 cluding nonstandard operation,  will be addressed.  Emissions data, where available, are reviewed in
 Sections  4 and 6  for baseline  and controlled operation, respectively.
        The following  sections  follow  the characterization sequence outlined for the major equipment
 categories in  Figure  2-1.  The  concluding section presents the provisional  list of combustion sources
 used  in subsequent sections  of  this report.  Data gaps and need for further compilation are also
 pointed out.

 2.1     STATIONARY  FUEL COMBUSTION  SOURCES
        This section provides a  preliminary  characterization of the seven major categories of sta-
 tionary fuel combustion sources of atmospheric NO  emissions.  The description of equipment design
                                                 A
 and applications is followed by typical operating characteristics and an effluent stream identifica-
 tion.   Detailed estimates of multimedia effluents for the source categories identified  here are
 presented  in Section 5.

 2.1.1   Utility and Large  Industrial Boilers >73 MW (>250 MBtu/hr) Heat Input
        For purposes of this study, the utility and large industrial boiler category will encompass
 all field-erected watertube boilers with a  heat input greater than 73 MW (250 MBtu/hr)  corresponding
 to an electrical generating capacity of about 25 MW.  This category includes  the vast majority  of
field-erected  boilers used for utility or industrial electric power generation.  Some industrial
                                                2-4

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boilers used for process steam extend into the utility boiler capacity range.  Also, some utility
and industrial field-erected units, particularly older installations, have input capacities below the
73 MW specification.  In both cases, however, the designs are generally similar to the smaller util-
ity boilers within the above capacity range.  For purposes of estimating emissions and evaluating the
applicability of NOX controls, these designs can therefore be effectively grouped with the utility
boilers.  Field-erected watertube boilers operate at steam temperatures up to 840K (1.050F) and steam
pressures up to 26 MPa (3,800 psi).  Although depending upon manufacturer, most units greater than
about 750 MW operate at supercritical steam pressures above 24 MPa (3,500 psi) (Reference 2-6).
Utility boilers recover up to 90 percent heat by a water-walled combustion chamber in combination
with superheaters, reheaters, economizers, and air preheaters, with about half the heat being ab-
sorbed by radiant heat transfer to the furnace walls.
       Fuels used in utility boilers include pulverized bituminous, subbituminous, and lignitic
coals; residual and crude oils; and natural gas.  Coals are burned in either dry bottom or wet bot-
tom (slag tap) furnaces.  Dry bottom furnaces operate at bulk furnace temperatures below the  ash  fusion
point and ash is removed as a solid.  Wet bottom furnaces melt the ash and remove slag through a  bot-
tom tap.  Although wet bottom furnaces were once popular for burning slagging coals with low
ash-fusion temperatures, they are no longer being manufactured due to operational problems with low
sulfur coals and because their high combustion temperatures promote NO  formation.  As a result,  wet
bottom furnaces will generally be treated as a subset of each specific equipment type rather  than
treated separately.
       Although coal, residual oil, and natural gas are the main fuels used in field-erected  water-
tube boilers, process gas and solid wastes are sometimes burned.  These secondary fuels are burned
almost exclusively in the industrial applications, where product gases or waste fuels are produced
as by-products of the industrial process, and where fuel quality is of less importance.  Coal, nat-
ural gas, and petroleum products accounted for 56.4 percent, 25.5 percent, and 18.1 percent of the
total fuel consumption in large watertube boilers in 1974.  About 85 percent of this fuel was used
to generate electricity.
       The major combustion-related difference between boilers in this sector is furnace design.
Four major manufacturers supply the following primary burner/furnace configurations:
       t   Tangential-firing (Combustion Engineering, Inc. - CE)
       •   Single-wall  firing (Foster Wheeler Energy Corp. - FW, Babcock and Wilcox Co. - B&W,
           Riley Stoker Corp. - RS)
       t   Horizontally-opposed wall-firing (B&W, FW)
       •   Turbofurnace (RS)

                                                2-5

-------
       In a tangential  furnace,  arrays of fuel  and air nozzles are located at the same elevation
in each of the four corners of the combustion chamber.  Each nozzle is directed tangentially to a
small firing circle in the center of the chamber.   The resulting spin of the four "flames" creates
high turbulence and thorough mixing of fuel  and air in the combustion zone.  Additional levels of
nozzles are mounted 2 to 3.5 meters apart for larger capacity furnaces.
       In single-wall firing furnaces, burners  are mounted normal  to a single furnace wall.  These
units are typically limited in output capacity to  about 400 MW because of furnace wall area.  When
larger capacity is required, horizontally-opposed  wall-firing furnaces are normally used.  Boilers with
single wall firing tend to be older on the average than opposed wall firing boilers as a result of
recent trends towards boilers with larger capacity.
       In horizontally-opposed wall-firing furnaces, burners are mounted on opposite furnace walls.
This is the most recently developed firing configuration, and is found on the newer units.  Due to
capital costs of fuel handling equipment, opposed-wall firing furnaces are limited to the larger
(>400 MW output) boilers (Reference 2-6).  Riley Stoker Corporation manufactures a version of the
horizontally-opposed wall-firing furnace under the Turbofurnace label  with burners mounted on
downward inclining furnace walls.
       individual burners on single and opposed wall units are usually of the register type and
have capacities in the 22 MW (-75 MBtu/hr) to 48 MW (-165 MBtu/hr)  range; up to 72 burn-
ers can be mounted on the furnace walls.  The pulverized coal  is entrained by about 20 percent  of
the primary air and introduced into the combustion chamber at a velocity of about 25 m/s (~80 ft/s)
where turbulent mixing with the remainder of the combustion air occurs.  Natural gas is injected at
velocities up to sonic through nozzles located in  the register throat.  Residual oil is preheated
and injected through atomizers using high pressure steam (-95 percent of sales), air (~1  percent of
sales) or mechanical means (-4 percent of sales) (Reference 2-7).   For all  of these fuels, secondary
preheated 395 to 590K (250F to 600F) air enters at speeds of about 60 m/s (-200 ft/s) for oil and
gas and about 37 m/s (-120 ft/s) for pulverized coal (Reference 2-8).
       Three other firing methods exist but are seldom encountered in new utility-size units:  stokers
(B&W, CE, FW, RS), cyclone furnaces (B&W), and vertical-firing units (CE).  Cyclone furnaces were being
sold as late as 1974, but because the units have not proven adaptable for emissions reasons, sales have
halted.  Cyclone furnaces were originally developed by B&W to burn low ash fusion temperature,
Illinois coal, but they have recently been used successfully with  lignite.  In this design, fuel
and air are introduced circumferentially into the  water-cooled cyclone furnace to produce a highly
                                                2-6

-------
swirling, high temperature flame.  The cyclone furnace must operate at high combustion temperatures
(Reference 2-9), since it 1s designed to operate as a slagging furnace.  Since high temperatures re-
sult in high thermal N0x formation, the cyclone furnace has lost its market.  In spite of this, cy-
clone furnaces will be discussed 1n subsequent sections of this report because of the relatively
high number being used in the North Central area of the U.S.
       Vertical-firing furnaces were developed for pulverized fuels before the advent of water-
walled combustion chambers.  They were previously used to a limited degree to fire anthracite coal.
Anthracite, because of its low volatile content, is difficult to burn in conventional boilers.  The
long residence time resulting from the downward firing pattern in vertical furnaces was effective in
achieving ignition and char burnout for anthracite.  With the decline of anthracite as a utility
fuel, vertical furnaces are no longer sold and few are found in the field.  Stoker-fired furnaces
for utilities are also seldom found in the field, primarily due to the trends toward larger capacity
boilers.  Design capacity limitations and high costs have made the stoker uncommon in utility boilers.
In the interest of complete emission totals, vertical firing and stoker-fired boilers will  be in-
cluded in Section 5 as a single equipment type.
       The distribution of utility boilers by firing type and fuel for 1974 is shown in Figure 2-2.
The totals listed were derived from a systems study by GCA (Reference 2-10) and a boiler inventory
by Battelle (Reference 2-11).  Power Magazine Plant Design Surveys (Reference 2-12) were used to
update the GCA data to 1974, and the Monsanto Research Corporation's Cyclone Boiler study (Reference
2-9) was also consulted for this firing type.
       Figure 2-2 is based on number of installed units of each design type.  Because of differences
in average capacity among the different designs, it does not accurately reflect the distribution
by installed capacity.
       The alternate picture of distribution by installed capacity is shown in Figure 2-3 for coal-
fired boilers.  Note that tangential-firing, wall-firing, and opposed-wan-firing units account for
40 percent, 36 percent, and 14 percent of the fuel consumed by utility boilers.  The trend of the
last 10 years to larger capacities appears to have slowed, with many utilities electing to install
two small boiler units rather than a single larger unit.  The trend to larger boiler capacities
brought with it the use of combustion chamber division walls.   This increased the available heat
transfer surface and essentially yielded two smaller combustion chambers with aerodynamic and com-
bustion characteristics similar to smaller units.  Large coal-fired furnaces, however, have generally
not used division walls, because they cannot readily be cleaned by soot blowing (Reference 2-6).
                                                 2-7

-------



60 -

56 -
52 -
48 -
44 -
40 -
36 -
32 -
28 -
24 —


20 -
16 -

12 -


—

4 -

I
Wall firing ^
2,212 units
(59.2%)
Dual fueled



Gas




Oil








Coal






Total: 3,738 units

-•




Tangential
724 units
(19.4%)
Dual
Gas
Vertical and
oil stoker
371 units Horiz. opposed
(q.0ฐ/) 3(17 units
	 1 (8.2%)
Dual
Gas Cyclones
fml 1 ฐ1 unit-
Oi1 (3.3%)

Loai Coal and dual
Figure 2-2.   Utility boiler equipment population  based on
             number of installed units (Reference 2-10).
                          2-8

-------
I

-------
Since coal will be used more extensively for utility boilers, this practice of dividing combustion
chambers is not expected to be prominent in the future.
       According to the manufacturers of utility boilers (References 2-6, 2-14 through 2-17),  no
oil- or gas-fired units have been sold for at least 2 years and many previously ordered oil  units
have been converted to coal-firing during the design phase (Reference 2-6).  The industry had  a par-
ticularly depressed sales year in 1976, and the 1977 outlook appears equally dismal.  Economic re-
cession in combination with increased energy costs, mild summer load peaks, and a 1975 reserve
capacity  of the utility industry of about 37 percent as well as uncertainty about the nation's en-
ergy policy have acted to produce this situation (Reference 2-6).

2.1.1.1   Operating Characteristics
       Typical design and operating characteristics for utility boilers are given in Table 2-1.
For one of these characteristics - throttle pressure — there is a recent trend away from supercriti-
cal back  to subcritical.  Less than 20 percent of the 1975 utility boiler orders specified super-
critical  pressures, compared with nearly 40 percent in 1971 (Reference 2-12).  Throttle temperatures
are remaining  at about 840K (1,050F) due to material limitations.
       Significant new trends in furnace design are just beginning to emerge in response to the re-
cent emphasis  on coal-fired units, particularly those capable of burning lower grade Western coals.
Furnace volumes for coal firing —which have always been greater than those of furnaces designed to
burn oil  or gas - are expected to increase to a maximum of about 28,000 m3 (1 x 106 ft3), with aver-
age volumetric heat release decreasing to around 122 to 165 kJ/m3s (12,000 to 16,000 Btu/ft3 hr)
for coal.  The movement towards coal-fired units has also caused a marked decrease in the use of
pressurized furnaces.  More than 85 percent of the 1975 orders were for either balanced draft or
slightly  negative pressure furnaces, compared to less than 45 percent in 1971 (Reference 2-12).

2.1.1.2   Utility Boiler Combustion Process and Effluent Stream Characterization
       Utility boilers have several multimedia effluent streams which may be affected by altering
the combustion process to control N0x formation.  This section briefly discusses the combustion pro-
cess in utility boilers and identifies the multimedia effluent streams emitting from these units.
It also includes a listing of nonconventional operating practices which may affect the makeup  of
these effluent streams.  The following discussion concentrates on coal since it is the main  fuel
now used  in utility boilers, and it requires more process equipment than other fuels.
                                                 2-10

-------
             TABLE 2-1.  DESIGN AND OPERATING CHARACTERISTICS
                         OF UTILITY BOILERS (Reference 2-12)
Input capacity
Steam pressure
Steam temperature


Furnace volume


Furnace pressure


Furnace heat release
Excess air
73 MW to 3,800 MW
(250 MBtu/hr to  13,000 MBtu/hr)
-18.6 MPa (2,700 psi) subcritical

-26.2 MPa (3,800 psi) supercritical


755 to 840K (900 to 1.050F)


Up to 28,000 m3 (1 x 106 ft3)


(-50) to 1,000 Pa (-0.2 to 40 in. H90)
Coal, 104 to 250 kJ/m3s
(10,000 to 24,000 Btu/ft3hr)

Oil and gas, 208 to 518 kJ/m3s
(20,000 to 50,000 Btu/ft3hr)
25 percent coal

10 percent oil

 8 percent gas
                                       2-n

-------
       Types of processes in utility boilers include fuel  combustion, flue gas cleaning, ash
removal, and fireside boiler tube cleanup.   Figure 2-4 gives a flow diagram for a typical pulverized
coal-fueled boiler, showing how these four  processes relate to each other.
       The fuel combustion process in utility boilers produces bottom or hopper ash, combustion
gases, volatilized noncombustible contaminants of the fuel, and suspended ash entrained in the hot
flue gases.  Coal usually contains between  5 and 15 percent ash and up to about 60 trace elements.*
Residual fuel oils contain less than 0.2 percent ash, but  may have significant amounts of trace
metallics, particularly vanadium.  Natural  gas contains virtually no ash or trace element constituents.
       Up to 65 percent of the ash in coal  is entrained in the hot combustion gases and either de-
posited on various boiler parts or carried  out of the boiler to the flyash collection system.  Flue
gas cleanup generally consists of particulate removal equipment (cyclone, electrostatic precipitator,
or baghouse).  Sulfur dioxide removal devices are employed on less than 5 percent of current installa-
tions.  The flyash collection equipment usually produces a dry solid waste stream which is removed
either in the dry state or by a wastewater  sluicing stream which is diverted to an ash settling pond.
A recent analysis of power plant data (Reference 2-10) shows that about 80 percent of utility boilers
remove ash by sluice water, and the remaining 20 percent use dry removal.
       The entrained ash deposited on furnace walls or other heat transfer sections may reduce heat
transfer efficiency and lead to severe slagging or fouling if not removed.  Soot blowing systems
using steam or compressed air are used to maintain fireside tube surfaces on a regular schedule
depending upon fuel and load.  The soot blown off the boiler tubes becomes entrained in the flue
gases or settles in the superheater or economizer ash hoppers.
       Coal ash which is not entrained in combustion gases either falls dry to the furnace hopper
(dry bottom) or melts and adheres to the furnace wall and  flows into a slag tank (wet bottom).  Dry
ash is removed by way of a pneumatic conveyance system or by a wastewater sluicing stream to an ash
settling pond.  Superheater and economizer  ash hoppers generally produce insignificant amounts of
ash compared to the furnace hopper and the  flyash collection system.  Table 2-2 summarizes the
effluent streams associated with the combustion process in utility boilers.
       Several periodic or nonstandard operating procedures can affect the composition of the var-
ious effluent streams discussed above.  Although sootblowing was described above because it  is so
commonly used, it is also included in the following periodic or nonstandard operations:
 Trace defined as <1 percent by weight of coal
                                               2-12

-------
I
GO
                        WASTE WATER
                               WATER
                     ( AIR EMISSIONS)
                      •—-f—'
                                                               STACK
                       BOILER TUBE
                        CLEANING
                        FIRESIDE
 AIR EMISSION

  SOOT BLOWER
*"STEAM}
  OR
  AIR      i
      	I
  r
  FLYASH
COLLECTION
AND/OR S02
 SCRUBBING
  DEVICE
                               FUEL'
                      COMBUSTION AIR	-ป•
        STEAM
     GENERATING
       BOILER
                              WATER-
  I
LJ
FLUE GASES
                                                BOTTOM ASH
                                                                              SOLID WASTE
                       /WASTE WATER TO
                          ASH HANDLING
                       V     SYSTEM

                                             ASH
                                          HANDLING
                                           SYSTEM
                                             I.
                                                         \  AIR  EMISSIONS )
                        SOLID WASTES
                                        ( WASTE WATER)
                       Figure 2-4.   Coal-fired utility boiler combustion process flow diagram.

-------
TABLE 2-2.  COMBUSTION RELATED EFFLUENT STREAMS FROM A UTILITY BOILER
Stream/ Fuel
Gaseous effluent
streams
Liquid effluent
stream
Solid
Pulverized Coal
Flue gas containing
flyash, volatilized
trace elements, S0p>
NO, other pollutants
Scrubber streams
Ash sluicing
stream
Wet bottom slag
stream
Solid ash
removal
Fuel Oil
Flue gas containing
volatilized trace ele-
ments, flyash, NO, S02
other pollutants
Scrubber stream
Ash sluicing
stream (if any)
Solid ash removal
(if any)
Natural Gas
Flue gas containing
NO, other pollutants
None
None

-------
       •   Sootblowing
       •   Startup or shutdown transients
       •   Load changes
       •   Fuel additives
       •   Rapping or vibrating
                                                                               \
       •   Flameout
       t   Upsets
       •   Equipment failure
       Table 2-3 shows how often these operations take place and the effluent streams which they
may affect.

2.1.1.3  Utility and Large Industrial Boiler Equipment Categories
       Figure 2-5 shows the important types of utility boiler equipment, based on current distribu-
tion, fuel consumption, and projected growth.  Vertical and stoker units make up a relatively small
fraction of the total, but are included for completeness.  No differentiation is made between dry
and wet bottom coal burning boilers of a specific design type.  Since distillate oil  and crude
oil make up a very small portion of the total petroleum fuels, they have been included in residual
oil totals in all cases.
       These equipment type/fuel combinations will be carried through for quantification of emissions
in Section 5.

2.1.2  Packaged Boilers
       This equipment category is comprised of all industrial, commercial and residential packaged
boilers.  In general, they have an input capacity of less than 75 MW (250 MBtu/hr).  Some packaged
boilers have a larger capacity but they are small in number and are sufficiently close in design to
units below 75 MW to be included in this category.
       Packaged boilers are constructed in watertube, firetube, cast iron, and shell  designs.  Each
of these designs has a fairly distinct capacity range.   These units are fueled primarily by residual
and distillate oil,  natural  gas, and stoker coal.  In addition, liquid and solid waste fuels and pro-
cess gases are sometimes used.  In terms of installed units, packaged boilers far outnumber field-
                                                                                            \
erected boilers.   Packaged boilers, however, consume only about 91 percent as much fuel as field-erected
                                                2-15

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TABLE 2-3.  EFFECT OF NONSTANDARD OPERATING PROCEDURES
            ON THE EFFLUENT STREAMS FROM A DRY BOTTOM
            PULVERIZED COAL-FIRED BOILER (Reference 2-18)
  (• Indicates possible affect on stream composition)
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

-------
           rTangentially  fired
Utility
boilers
             Single
             "wall fired
             Horizontally
             ^opposed wall
             "fired and
             Turbofurnace
             _Cyclone
             "furnace
             ^Vertical and
             "stoker  fired
r- Pulverized coal
  Residual fuel oil
L Natural gas
  Pulverized coal
 •Residual fuel oil
  Natural gas
  Pulverized coal
 •Residual fuel oil
 •Natural gas
rCrushed coal
  Residual fuel oil
                                      L-Natural  gas
  Coal
             Figure 2-5.   Utility boiler equipment categories.
                                   2-17

-------
boilers annually.   Packaged boilers are primarily used'for industrial process steam; commercial
and residential  heating; and hot water supply.
       Due to the large capacity range of packaged boilers -and the large number of distinct
designs - the discussion of this equipment category is divided into three parts:  watertube
boilers, firetube boilers, and all  other types  of boilers.

Watertube Boilers
       Watertube boilers are essentially the only packaged boiler design available above about
9 MW  (30 MBtu/hr) input.  Packaged watertubes are fueled by residual or distillate oil, natural gas,
process gases, stoker and pulverized coal, and  waste fuels.
       1975 sales statistics (Reference 2-19) show that  86 percent of packaged watertube boilers were
burner-fired and 14 percent were stoker-fired.   Fuel oil is used in about 50 percent of the burner-
fired  units.  About 75 percent of these units fire residual oil  and 25 percent fire distillate oil.
About  40 percent of the burner-fired units have dual gas and oil capabilities.  Units limited only
to natural gas firing make up the remaining 10  percent.   Units larger than about 30 MW GJ/hr
(TOO MBtu/hr) input are typically equipped with the one  or more  utility burners mounted in the wall
firing configuration and commonly burn residual oil or natural gas.  (Most new boilers have both
capabilities.)
       Steam is used as the atomization method  for 70 to 80 percent of oil-fueled boilers (Ref-
erence 2-7).  Mechanical or air atomization is  also used, but much less frequently.  Gas burners
are usually of the register type.  Coal and other solid  fuel  stokers commonly used are spreader
(-50 percent), overfeed (-10 percent), and underfeed (~20 percent) (Reference 2-7).  Pulverized,
hand-fired, and miscellaneous firing methods comprise the remaining 20 percent.
       In the past, pulverized coal has seldom been used in packaged watertube boilers due to the
capital costs involved with coal pulverization  and handling equipment.  The availability and competi-
tive cost of coal compared to oil are leading to the increased use of pulverized coal in the larger
packaged watertube units.  Capacities down to 20 MW (70 MBtu/hr) are now being marketed (Reference 2-12).
       Watertube boilers smaller than 30 MW are fired by single  burners and use primarily dis-
tillate oil  or natural gas.  The 1975 sales indicate that about  30 percent of these units are natural
gas fueled and about 45 percent are oil fueled.  Two fuel capabilities, natural gas and oil, exist
in about 25 percent of the units.  The most common atomization methods are mechanical pressure
atomizing, which accounts for about 70 percent  and air atomizing, which accounts for about 30 percent
(Reference 2-19).   Coal firing is available only in stoker units.
                                                2-18

-------
       The smaller water-tube boilers are mainly  used  for  Industrial  process .steam.   Some  commercial
space heating is also done with these units, although they  are  somewhat  large  to  be  regularly  used
for this purpose (Reference 2-20).

Firetube Boilers
       In firetube boilers, the products of combustion are  directed  from the combustion chamber
through straight tubes which are submerged in water.   Because of  the sensitivity  to  fouling with
this design, firetube boilers normally  burn fuel  oils and natural  gas rather than high ash fuels
like coal.  Residual oil and natural gas are the main fuels for the  larger firetube  boilers, while
natural gas and distillate oil predominate in the smaller units.   Firing is by single burner.
Rotary, mechanical, or air atomization  are used  for oil firing.   Atmospheric burners are predominantly
used for natural gas firing.
       Scotch, firebox, and horizontal  return tube (HRT) are the  three main types of firetube units
in  the field at the present time.   Recent sales  indicate that the firebox unit has diminished in
popularity over the past 5 years (Reference 2-21).  Scotch  firetubes,  in which  the burner flame is
contained within an elongated combustion chamber surrounded by water, are the most popular with
efficiencies of 80 percent.  The rear wall of the furnace in scotch  firetubes  is either water-lined
(wet-back) or refractory-lined (dry-back).  Firebox units are constructed with  internal, steel
encased, water-jacketed fireboxes which produce  good  circulation  and  efficiencies of 80 percent.
HRT boilers have the advantage of low cost, but  their efficiency  seldom  exceeds 70 percent
(Reference 2-22).  Brickset (external)  or internal furnaces are available for HRT units.   Firetube
boilers are used for commercial and domestic space heating; larger units are also used for indus-
trial process steam.

Other Packaged Boilers
       Cast iron boilers are available  with input capacities up to 4  MW  (13.5  MBtu/hr) and operate
almost exclusively on distillate oil and natural  gas  fuels.  These boilers are  designed to supply
low pressure steam or hot water and are used primarily for  air  or water  heating systems.  The pri-
mary advantage to cast iron boilers for heating  is that they require  a very low level of maintenance
and have a high reliability and lifetime.  On the other hand, their  cost is typically higher than
the cost of a comparable firetube boiler.
       Other packaged boilers include several which are used for  residential and  commercial heating
or  hot water, including shell boilers and residential  steam and hot  water units.  This group also
includes several designs which are  obsolete or insignificant on a national scale.  Included among
these are compact, locomotive, short-firebox, and vertical  firetube  designs, and  straight tube,
                                                2-19

-------
anthracite, and bituminous coal research watertube designs.  Because of the importance of the  pack-
age boiler sector, these designs will be dealt with under the single category - steam and hot
water units.

2.1.2.1  Operating Characteristics
       Typical operating characteristics for natural gas- and residential oil-fueled watertube
boilers, a  small watertube boiler, a cast iron boiler and a scotch firetube boiler are presented
in Table 2-4.
2.1.2.2  Effluent Stream Characterization
       Flue gases are usually  the only combustion-related effluent stream originating from packaged
boilers.   In  the  case where pulverized or stoker coal, solid wastes, or other high ash fuels are
burned, both  liquid and solid  effluent streams may be produced if ash collection and flue gas
cleanup systems are used.  Table 2-5 lists the effluent streams associated with each of these fuels.

2.1.2.3   Packaged Boiler  Equipment Categories
       Figure 2-6 shows the significant types of packaged boilers and the fuels burned in each type.
The  selection was based on distribution, similarities in equipment design, and projected growth.
Gaseous fuels include process,  natural and tank gases.  Stoker units are typically underfeed in
this capacity range.  Oil fuels include distillates and residuals.

2.1.3 Warm Air Furnaces  and Other Commercial and Residential Combustion Equipment
       This category is made up of residential and commercial warm air furnaces used for comfort
heating,  plus miscellaneous commercial and residential appliances used in cooking, refrigeration,
air  conditioning, clothes drying, etc.  Figure 2-7 gives an overview of the equipment types.   The
letters on the right-hand side of the figure indicate which fuels are used in each kind of unit.
       There  are  two basic types of  commercial and residential warm air furnaces: space heaters,
where the  unit is located in the room or area it heats; and central heaters, which use ducts to
transport  and discharge warm air into the heated space.

Space Heaters
       Space  heaters are  room  heaters,  floor furnaces, wall furnaces which discharge  heated  air
directly  into the space  to be  heated, and central  heaters.  Central heaters  are  the  largest  majority
of warm air furnaces and  are discussed  separately  in  the following  subsection.   The  capacity of room
                                                 2-20

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TABLE 2-4.  TYPICAL DESIGN AND OPERATING CHARACTERISTICS OF PACKAGED BOILERS

Design
Fuel
Input capacity MW
(MBtu/hr)
Furnace volume m3
(ft3)
Heat release kJ/m3s
(MBtu/ft3 hr)
Operating pressure kPa
(psig)
Burner type (number)
Fuel preheat K
(F)
Stack temperature K
(F)
Excess oxygen %
(Reference 2-23)
Water-tube
Natural gas
44
(150)
154
(5,450)
285
(0.0275)
NA
Ring (1)
None
422
(300)
5
(Reference 2-23)
Watertube
Residual fuel oil
38
(130)
123
(4,340)
310
(0.030)
NA
Steam atomization (2)
392
(210)
422
(300)
7.1
(Reference 2-23)
Watertube
Natural gas
8.5
(29)
21.4
(755)
397
(0.0384)
NA
Ring (1)
None
567
(560)
0.9
(Reference 2-20)
Scotch fire tube
Residual fuel oil
2.9
(10)
2.5
(87)
1,190
(0.114)
1,030
(150)
Air atomizing (2)
371
(208)
NA
4.9
(Reference 2-20)
Cast iron
Distillate fuel oil
0.38
(1-3)
0.57
(20)
673
(0.065)
103
(15)
Pressure atomizing (1)
None
NA
4.4

-------
                                        TABLE 2-5.  PACKAGED BOILER EFFLUENT  STREAMS

Gaseous streams
Liquid stream
Solid stream
Pulverized Coal
Flue gas contain-
ing flyash, vola-
tilized trace ele-
ments, SOg, NOX,
other pollutants
Ash sluicing
water, wet
scrubber stream
Solid ash
removal
Stoker Coal
Flue gas contain-
ing flyash, vola-
tilized trace ele-
ments, S02, NOX,
other pollutants
Ash sluicing
water, wet
scrubber stream
Solid ash
removal
Fuel Oil
Flue gas contain-
ing flyash, vola-
tilized trace ele-
ments, S02, NOX,
other pollutants
None
Solid ash
removal (if any)
Natural Gas
Flue gas containing
NO, other pollutants
None
None
ro
ro

-------
           ,_Watertubes  	
             29 MW to 73 MW
Packaged
boilers
             -Watertubes
              29  MW
             •Firetubes
              9 MW
            — Cast iron boilers
              Miscellaneous
             -residential hot
              water units
                                     r— Scotch
HRT
                                     —Firebox-
             -Gas
             -Oil
             -Pulv coal
             -Stoker coal
              Gas
             • Oil
             •Stoker coal
 •Oil
 • Gas
 •Oil
 Gas
 •Stoker coal
 •Oil
 • Gas
 •Stoker coal

 Oil
 Gas

r-Oil
  Gas
                                                    L Stoker coal
            Figure 2-6.   Packaged boiler equipment categories.
                                     2-23

-------



Commercial ,
residential • • ••
heating

Warm air
furnaces


Central
heaters
Space
heaters

p-Forced air
-Gravity
-Floor
- Room —
-Wall

                  Miscellaneous
                I— combustion —
                  equipment
                                                                    - C,0,G
                                                                    - 0,6
                                                        Ranges (cooking) - G
                                                       .Ovens (cooking) — G
                                                        Clothes drying — G
                                                        Swimming pool
                                                        heaters — G
'-Fireplaces - W,C
C — coal
0 - oil-distillate
G — gas including natural,
    LPG, SNG bottled, tank
W - wood
Other
      Figure 2-7.  Warm air furnaces and related combustion  equipment.
                                    2-24

-------
heaters, floor furnaces, and wall furnaces  seldom  exceeds  108 MJ/hr  (100,000  Btu/hr).   The  1970
Census shows that less than 9 percent  of  the  nation's  heating 1s  done  by  space  heaters  and  that more
than 98 percent of these are either gas-  or oil-fired  (55  percent by natural  gas,  43 percent by
distillate fuel oil).
       Room heaters are self-contained, free-standing  units which are  equipped  with a flue  if fueled
by oil; floor- and wall-mounted  furnaces  are  always  vented to the atmosphere.   These units  heat by
either radiation or natural or forced  air circulation.   Because of the large  variety of manufacturers
and the uncertainty as to  the age, location,  and condition of space heaters,  the design and operat-
ing characteristics of these heaters are  difficult to  quantify.   As a  result, implementation of NO
controls for these units is unlikely.  Because  of  their  relative  unimportance for  this study, all
space heaters will be subsequently treated  as a single equipment  type.
Central Heaters
       The large majority  of warm air  furnaces  (about  60 percent  of new units)  (Reference 2-24)  are
forced-air central furnaces with capacities up  to  about 88 kU  (~300,000 Btu/hr).  These heaters  are
operated either by gravity or by a pressure blower (forced-air system)  for air discharge and return.
Central gravity-operated furnaces rarely  exceed 44 kW  (150,000 Btu/hr).  The furnace in these cen-
tral heaters is enclosed in a rectangular steel casing, and fuel  is burned in the primary combustion
space of a metal-walled heat exchanger.   Heat exchangers in these warm-air furnaces have a single
combustion chamber, which  is usually cylindrical or  divided into  a series of individual  sections.
Cylindrical combustion chambers  are normally  used  with a single-port,  oil-fired burner;  and the
sectional type is used with multiple gas-fired  burners.  Combustion products pass through secondary
flue gas passages of the heat exchanger and exit through a flue to the atmosphere.
        Central warm  air  furnaces are  usually  classified  into  four types:
        •    Downflow,  in  which  the  blower  is mounted  above  the heat exchanger, the  flue  gas  discharges
            at  the  side or  top,  and the warm air discharges at the side
        •    Upflow  or "high boy", in which the blower is  mounted below  the heat  exchanger  and the
            warm air  and  the flue gas  discharge  from  the  top of the unit
        •    Horizontal, in  which  the blower  is mounted  adjacent to the  heat exchanger, the flue
            gas discharges  from  the side,  and  warm  air  exits at the end of the unit
        •    Basement  or "low boy", similar to  the horizontal,  except  that  the  flue  gas  discharges
            at  the  end of the unit and  the warm air exits at the top
                                                 2-25

-------
The main difference between these four types of furnaces is how the blower and the heat exchanger
are located in relationship to each other.  Since there are only minimal differences in the  burner
and combustion chamber design for the above types and natural circulation units, they will be  dealt
with as a single equipment type for subsequent emissions inventories.
       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.  Coal, wood and various bottled, tank, or LP gas accounted for the
remaining 10 percent of fuel used.  Although there has been a continuing trend in the recent past
toward commercial and residential warm air furnaces which use natural gas, the percentage of equip-
ment 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 decline further to 32 percent by 2000 (Ref-
erence 2-25).  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.  On a national scale, the most important fuels  for
warm air furnaces are still natural gas and distillate oils.  Other fuels will not be considered
except coal, which is still used for space and central heating in some areas and could present
localized pollution problems.
Miscellaneous Combustion Equipment
       Other commercial and residential combustion equipment in this sector includes ranges and
ovens, clothes dryers, fireplaces, swimming pool heaters, and refrigeration and air conditioning
equipment.  Gas was used for about half of all cooking in 1973, and electricity for the remaining
half.  Although there were more than 40 million clothes dryers in 1974 (Reference 2-26), no data are
available as to how many were fueled by gas.  Refrigeration and air conditioning are typically
electrical vapor compression units.  A few absorption units fired with natural or bottled gas are
used in domestic application.
       The emissions from domestic cooking are small compared to warm air furnaces.  They are mostly
of concern for the part they play in indoor air pollution rather than for their contribution to
AQCR or national NOX loadings.  Low-N0x burners for domestic gas combustion are presently being
developed by the gas industry (Reference 2-27).  Efforts to characterize indoor air pollution  and
develop low pollution burners will be monitored throughout the NO  E/A, but these efforts will re-
ceive secondary emphasis in the process engineering and environmental assessment studies.  These
miscellaneous domestic combustion sources will subsequently be dealt with as a single category.
                                                2-26

-------
2.1.3.1  Operating Characteristics
       Operating characteristics will  be  given  only for central  warm air furnaces,  since typical
characteristics of space heaters and miscellaneous  combustion  equipment in this  sector are difficult
to generalize.
       One of the most Important operational  characteristics of  all  comfort heating devices  is  their
cyclic operating mode.  Typical residential warm air heaters have  about two to five cycles per  hour,
with a 30 to 50 percent on-time (Reference  2-20).   This cyclic operation is important  to this program
for two reasons.  First, the  emissions from furnaces during startup  and shutdown may be substantially
higher than during continuous operation and may also be affected by  the application of NO   controls.
Second, the thermal efficiency of  these furnaces is substantially  lowered  by heat losses to  the flue
during downtime, offsetting any gains  in  efficiency which may  come from low-NO , high-efficiency
burners.
       The gas burners on warm air furnaces are naturally aspirated  types  made up of three to four
Venturis, with distribution pipes  consisting  of rows of small  orifices.  The primary air is  drawn
into the venturi by the gas pressure and  premixes with  the gas before  igniting.  The primary
air/fuel ratio can be controlled by small shutters  at the end  of each  venturi.  Secondary  air from
the furnace room enters around the burners  to reduce the overall flame temperature  and  allow complete
combustion.  These units are  also  equipped  with draft diverters  to dilute  the flue  gas  stream and
prevent downdrafts from blowing out the pilot.
       Typical operating conditions of a  29 kW  (100;000 Btu/hr)  residential  gas-fired warm air
furnace are given in Table 2-6.
       Oil-fired forced air furnaces are  now  being  made with overall  volumes not much  greater than
gas-fired versions.  There are considerable differences between  the  two types of units  in  internal
operation, however.  In an oil-fired central  heater, the heat  is supplied  by a gun-type oil  burner
made up of a combustion air blower, motor,  damper,  fuel  pump,  spark  ignition system, main  air tube
and swirlers, and fuel nozzle.  The flow  rate of the fuel is determined by the oil  nozzle  orifice
size,  and the total air flow  rate  by the  blower and damper.  The proper air/fuel ratio  is  adjusted
with the damper until the optimum  CO and  smoke  levels are achieved.   The burner  is  mounted in a
refractory or refractory-felt-lined combustion  chamber  which is  cooled by  air circulating  through
the housing.  From the combustion  chamber,  the  flue gas passes through a heat exchanger and then
out the stack.  The absence of a pilot flame  and the use of a  forced draft system make a draft
diverter in the flue unnecessary.   The burner blower may supply  the  full pressure to exhaust the
gas from the stack, or it may rely partially  on the buoyancy forces  downstream of the  stack.
Table 2-7 lists typical operating  conditions  for an oil-fired  home heating furnace.
                                                 2-27

-------
  TABLE 2-6.  DESIGN AND OPERATING CHARACTERISTICS OF A TYPICAL 29 KW
              GAS-FIRED FORCED AIR FURNACE
Heat exchanger area:


Draft system:


Excess combustion air:


Overall heat transfer
coefficient kW/(m2K)


Combustion chamber pressure


Exit flue gas temperature:
(Before flue gas diverter)


Overall steady state efficiency


Common operating mode:
2.8 to 3.3 m2 (30 to 35 ft2)


Natural


20 to 50 percent


11.3 to 17 (2 to 3 Btu/hr-ft2F)



ฑ49.8 Pa (ฑ0.2 in. H20)


506 to 617K (450 to 650F)



75 to 80 percent


On/off
                                   2-28

-------
 TABLE 2-7.  DESIGN AND OPERATING CHARACTERISTICS OF A TYPICAL
             29 KW OIL-FIRED FORCED AIR FURNACE
Heat exchanger area:
Draft system:
Excess combustion air:
Overall heat transfer
  coefficient:
Combustion chamber
  pressure:
Exit flue gas
  temperature:
Overall steady state
  efficiency
Operation mode:
1.9 to 2.8 m2 (20 to 30 ft2)
Forced
20 to TOO percent
11.3 to 17 W/(m2K) (2 to 3 Btu/ft2hr F)

12.45 Pa to 49.8 Pa (0.05 to  0.2 in.  H20)

533 to 756K (500 to 900F)
70 to 80 percent
On/off
                             2-29

-------
2.1.3.2  Effluent Stream Characterization
       Flue gases are generally the only combustion-related effluent from these equipment types.
In the rare case of a solid-fueled warm air furnace, a solid waste stream consisting of dry ash
would result.  The composition of the flue gas depends on the kind of fuel used and its combustion
characteristics, which are determined in part by the design and controls employed in the unit.
Another important factor in flue gas composition is the cyclic nature of normal warm air furnace
operation.
       Periodic operating practices for this equipment sector include unit servicing (especially
burner tuning or replacement), and unit cleaning.   While these practices can increase thermal  effi-
ciency, they do not usually help reduce NO  emissions.

2.1.3.3  Warm Air Furnace Equipment Categories
       Figure 2-8 shows the equipment in this sector which will  be treated in subsequent sections
as potentially important sources of NO  emissions.   These types of equipment have been selected on
the basis of distribution, potential growth, fuel  burned, and the potential  for applying N0x control.

2.1.4  Gas Turbines
       Gas turbines are rotary internal combustion engines fueled by natural gas, diesel or dis-
tillate fuel oils, and occasionally residual or crude oils.  These units range in capacity from
30 kW  (40 hp) to over 75 MW (100,000 hp) power output and may be installed in groups for larger power
output.  As shown in Figure 2-9, the basic gas turbine consists of a compressor, combustion chambers,
and a  turbine.  The compressor delivers pressurized combustion air to the combustors at compression
ratios of up to 20 to 1.  Injectors introduce fuel into the combustors and the mixture is burned with
exit temperatures up to 1,370K (2.000F) before quenching.  The hot combustion gases are rapidly quenched
by secondary dilution air and then expanded through the turbine which drives the compressor and pro-
vides  shaft power.  In some applications, exhaust gases are also expanded through a power turbine.
       While simple-cycle gas turbines have only the three components described above, regenerative-
cycle  gas turbines also use hot exhaust gases (700K to 870K, 800F to 1.100F) to preheat the inlet
air between the compressor and the combustor.  This makes  it possible to recover some of the  thermal
energy in the exhaust gases and to increase thermal efficiency.  A third type of turbine is the
combined-cycle gas turbine.  This is basically a simple-cycle unit which exhausts to a waste  heat
boiler to recover thermal energy from the exhaust gases.   In some cases, this waste heat boiler  is
also designed to burn additional fuels to supplement steam production, a process which  is referred
to as supplementary firing.
                                                2-30

-------

Warm air
furnaces

Central
heaters
Space
heaters
-Forced air
-Gravity
-Floor
- Room -
-Wall
                                                       -I C.O.G
                                                       H  0,6
         C - Coal
         0 - Oil, distillate
         G-Gas, including natural, LPG, SNG bottled, tank

Figure 2-8.  Important commercial and residential combustion equipment.
                                 2-31

-------
CO
ro
                      r
                                                                            A
Fuel
                        Air
                        Air
                                                 Combustion
                                                 chamber
                           Exhaust
                           gases   ^
                                            Compressed
                                           .air
                                Compressor
                          Turbine
                      j                   Stationary gas turbine
Load
                                                                                     Rotary V-
                                                                                     energy
                                      Figure  2-9.   Basic  simple cycle gas  turbine.

-------
       On some gas turbine units the combustor  1s  placed  axlally  between  the  compressor and the
turbine.   In this design, the combustor may be  made  up of a  series  of  Individual  "cans" encircling
the drive shaft or of two concentric cylinders  mounted so as  to produce a single  annular combustion
chamber (hence the terms canannular or annular  combustor  designs).  These units are generally an
outgrowth of aircraft turbine design technology, and are  often referred to as aircraft derivative
turbines.  On other gas turbines, the combustor 1s a single  large volume, which is connected to the
compressor and turbine by ducting, but which  is not  necessarily physically located between the com-
pressor and the turbine.  This design is obviously strictly  for stationary or industrial applications
and is referred to as such.
       Gas turbines have been extremely popular in the past  decade  because of the relatively short
construction lead times; low cost; ease and speed  of installation;  low physical profile (low build-
ings, short stacks, little visible emissions, quiet  operation).   In addition, features like remote
operation, low maintenance, high power-to-weight ratio, and  short startup time have added to their
popularity.  Primary applications of gas turbines  include electrical generation (peaking and base-
load), pumping, gas compression, standby electricity generation,  and miscellaneous industrial  uses.
By far the largest use of gas turbines is  for peaking power  (>2,000 hrs/yr).
       Stationary gas turbines are typically  divided into three capacity  ranges:
       •   Large capacity, including multiple and  combined cycle  >15 MW (20,000 hp) output
       •   Medium capacity 4 MW to 15 MW (5,000 to 20,000 hp) output
       •   Small capacity <4 MW (5,000 hp) output

Large-Capacity Gas Turbines
       Large-capacity gas turbines range up to  100 MW (134,000 hp)  power  output, while combined-cycle
and multiple turbines range up to 1,230 MW.   These equipment  types  are used almost exclusively by
electric  utilities.  Since equipment of this  size  does not lend itself to large-scale production runs,
lead  times of 6 to 24 months for these units  are not uncommon.  The majority of installed gas turbines
are simple cycle units, and the industrial types are slightly more  common than aircraft-derived turbines.
       Simple- and combined-cycle turbines offer the greatest possibilities for N0x control with
dry combustion controls, especially since  the high turbine inlet  temperature  of regenerative-cycle
turbines  has decreased their popularity.   Similarly, industrial gas turbines  have much more potential
for combustor redesign than do the compact, physically-restricted,  aircraft derivative units.
                                                2-33

-------
       Although gas turbines presently account for about 8 percent of installed electrical generat-
ing capacity, they actually generate less than 2 percent (Reference 2-28).  Over 90 percent of gas
turbine capacity sold in the U.S. now goes to electrical utilities, and this percentage is continu-
ing to increase.  Shipments of gas turbines in 1975 were down considerably (-65 percent) over pre-
ceding years, but the gas turbine fraction of total electrical  generating equipment shipments
declined only 7 percent (Reference 2-29).
       Recent trends in large gas turbines have been towards higher capacities and improved heat rates.
For the future, a recent survey of users (Reference 2-30) indicates that combined-cycle turbines
are the preferred design for intermediate or base load applications because of their improved heat
rate and fuel flexibility.  Simple-cycle turbines are preferred for peaking.   In the same survey,
users predicted that gas turbines will continue to contribute about 10 percent of the total electrical
generating capacity through at least 1985.  Because of this projected growth, large gas turbines
will subsequently be studied as a distinct equipment type.

Medium-Capacity Gas Turbines
       Medium-capacity gas turbines are used primarily for electrical standby generation, pipeline
compression and pumping, and industrial electricity generation  — although they also have a wide
variety of other applications.  Most turbines of this capacity  are simple-cycle units; only a small
fraction are regenerative-cycle, and there are essentially no combined-cycle, medium-capacity tur-
bines.  Combustion modification on these units has been strongly directed toward the development
of dry combustor controls, but the only commercially-available  control methods are water or steam
injection.
       Because of the trend in utilities toward larger units and the movement in the oil and gas
industry toward smaller capacities, fewer medium-capacity gas turbines are now sold per year than
either of the other two sizes.  In the oil and gas industry, units in this medium-capacity range
operate about 8,000 hours per year; standby electric generation units may not exceed 200 hours
per year.  Units used for private industrial electricity generation, the third major application
of this equipment, operate nearly full time.  Because of their relatively large population, high
application, and a fairly distinct distribution, medium-capacity gas turbines will subsequently be
treated as a distinct equipment type.

Small-Capacity Gas Turbines
       Small-capacity gas turbines are used by both the gas and oil industry and for standby elec-
tricity generation.  These units represent less than 5 percent of the total installed gas  turbine
                                                2-34

-------
capacity in the U.S.  All small-capacity  turbines  are  simple-cycle designs,  since regeneratl ve-
or combined-cycle turbines are not economical  for  these applications.   Since the  concentration of
these units 1n gas and oil plants and  in  power plants  for emergency electricity generation  could
present localized problems of NOX> these  units will  be grouped into a  single equipment  type within
the gas turbine sector.

2.1.4.1  Operating Characteristics
       Although operating characteristics vary within  each capacity range, it is  still  possible to
present typical data for representative equipment.   Table 2-8  gives design and  operating character-
istics for two large-capacity utility  gas turbines  fired with  distillate oil  fuel.  Note the specific
fuel consumption gained by the combined-cycle  unit.  Table 2-9 presents operating  data  for  typical
small- and medium-capacity gas turbines.   The  medium-capacity  columns  compare simple- and regenerative-
cycle turbines, and clearly  show the advantages in  specific fuel  consumption  of the regenerative cycle.
       Stationary gas  turbines are normally operated at constant  speed and output.  Nonstandard
operating practices for these units  include startup and shutdown  transients,  load  following, speed
or  power variation, servicing, and upsets such as  fuel  system  failure,  turbine  or  compressor break-
age, or downstream equipment failure.  Startup and  shutdown transients  are especially important in
the large utility units used for peaking  purposes which are operated daily for  only short periods
of  time.

2.1.4.2  Effluent Stream Characterization
       Exhaust gases are the only combustion-related effluent  stream from gas turbines.  The composi-
tion of this  stream depends  on the fuel being  burned and on the general design  and combustion char-
acteristics of the  unit.  Nonstandard  operating practices also affect  the stream  composition, generally
reducing combustion efficiency and increasing  unburned hydrocarbons or carbon monoxide.

2.1.4.3  Important  Equipment Types
       Figure 2-10 shows the important types of gas turbines and  fuels  which  will  be carried through
to  Section 5  for emission characterization and into the subsequent Task Bl emission projections.
These types of equipment have been selected on the  bases of present distribution,  projected growth,
and operating characteristics.
                                                2-35

-------
            TABLE 2-8.  OPERATING CHARACTERISTICS OF A TYPICAL
                        ELECTRICAL UTILITY GAS TURBINE AND A
                        COMBINED CYCLE UNIT (OIL FUEL)
                                       Utility
                                         GT
                       Combined
                     Cycle Plant
Cycle type
Output capacity rating, MW
Specific fuel consumption
MJ/kW-hr (Btu/kW-hr)
Compression ratio
Exhaust flow kg/s
Exhaust temp K
(F)
S


92.3
11.67
(11,058)
10:1
345
(760)
822
(1,020)
Combined
364.5 (4 turbines)
8.56
(8,114)
10:1
256 (1 turbine)
(563)
811
(1,000)
                                   2-36

-------
    TABLE 2-9.    TYPICAL OPERATING CHARACTERISTICS OF A SIMPLE CYCLE
                 AND A REGENERATIVE CYCLE MEDIUM CAPACITY AND A SIMPLE
                 CYCLE SMALL CAPACITY GAS TURBINE

Cycle type
Fuel
Output capacity MW
Compression ratio
Exhaust flow kg/s
(lb/s)
Exhaust temp K
(F)
Medium
Simple
Distillate
fuel oil
10.9
(14,600)
-8:1
52
(114)
806
(990)
Capacity
Regenerative
Distillate
fuel oil
10.3
(13,750)
-8:1
52
(114)
817
(1,010)
Small capacity
Simple
Distillate
fuel oil
4.2
(5,660)
4.6:1
35
(77.4)
742
(875)
Reference 2-31
                                  2-37

-------
Gas turbines -
                   'Utility and
                    combined cycle
                    15 MW output
Medium capacity  _
4 to 15 MW output
                    Small  capacity
                   _<4 MW output
                                           Natural gas
                                           Diesel fuel
                                           Natural gas
                                           Diesel fuel
                                           'Natural gas
                                           Diesel fuel
     Figure  2-10.   Important gas turbine equipment
                   types  and their fuels.
                           2-38

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2.1.5  Stationary Reciprocating 1C Engines
       Reciprocating 1C engines for stationary applications  range  in  capacity  from  750 W  (1 hp) to
37 MW (50,000 hp).  These engines are either compression  ignition  (CI)  units fueled by diesel oil
or a combination of natural gas and diesel  oil (dual),  or spark  Ignition  (SI)  units fueled by natural
gas or gasoline.
       Stationary reciprocating 1C engines  use two  methods to  Ignite  the  fuel-air mixture in the
combustion chamber.  In CI engines, air  is  first compression-heated in  the cylinder, and  then
diesel fuel is injected into  the hot air where ignition is spontaneous.   In SI engines, combustion
is spark-initiated, with  the  natural gas or gasoline  introduced  either  by injection or premixed
with the combustion air in a  carburetted system.  Either  2-  or 4-stroke power  cycle designs with
various combinations of fuel  charging, air  charging,  and  chamber design are available.
       Reciprocating 1C engines come in  a wide range  of sizes, are portable, can provide transient
power, and are both cost  and  energy efficient in the  medium  size ranges.  Therefore, they are fre-
quently  located  in or  adjacent to urban  centers  where power  demands are greatest and pollution prob-
lems most acute.  These units  are used in a variety of  applications because of their relatively
short  construction and installation time and the fact that they  can be  operated remotely.  Applica-
tions  range from shaft power  for  large electrical generators to  small air compressors and welders.
       As a whole, 73  percent of installed  1C engine  capacity  is fueled by natural  gas, 16 percent by
diesel oil and 11 percent by  gasoline.   In  terms of installed  capacity, the oil and gas industry is
the  leading user of stationary 1C engines for pipeline  and production applications,  followed by gen-
eral industrial  users, electric power generation, and agriculture.  In  terms of annual energy pro-
duction, oil  and gas industry applications  again come first, followed by  general industrial and
electrical generation  applications.
       Because of the  large variety of designs for  stationary  1C engines, they are  typically divided
into four major  subgroups based on capacity:
       •   Large bore, high power:  >75  kW/cyl <>100  hp/cyl)
       •   Medium power:   75  kW to 75 kW/cyl  (100 hp  to 100  hp/cyl),  >1,000 rpm
       •   Small:  15  kW  to 75 kW  (20 hp to 100  hp)
       •   Very  small: <15 kW (<20 hp)
                                                2-39

-------
Large Bore 1C Engines
       Large bore 1C engines are typically high-power,  low or medium speed, 4-stroke CI units fueled
by diesel oil or dual fuel or 2- or 4-stroke SI units operating on natural gas.  Dual-fueled engines
and natural-gas-fueled spark ignition units account for 93 percent of all the fuel consumed by these
large capacity engines.  The majority of these engines  are used for compressors for the oil and gas
industry.  These units have high average capacities, high load factor, and are operated continuously
to produce large amounts of energy.  Units used for electrical generation have large capacity, but
are far fewer in number than engines used in the oil and gas industry.  Major manufacturers of large
bore 1C engines estimate a 5 to 10 percent annual growth of sales for these units, primarily for
standby, emergency electrical generation, and natural gas pipeline pumping.

Medium Power 1C Engines
       The primary manufacturers of medium power units  are also the major manufacturers of similar
capacity units for trucks, tractors, and construction equipment.   As a result, medium power sta-
tionary engines tend to be modified mobile engines with rotative  speeds in excess of 1,000 rpm.
Engines in this capacity range usually burn either diesel or gasoline rather than natural gas.
Major applications are in construction, agriculture, and industry for shaft power, pumping, and com-
pressing.  About 50 percent of the fuel consumed by these units is diesel oil, 33 percent gasoline,
and the remainder natural  gas.  Growth of sales for this size range continues at about 3 to 5 per-
cent per year.

Small 1C Engines
       Small 1C engines are mainly one- or two-cylinder units fueled by gasoline and occasionally
diesel  oil.  Primary applications for this equipment are generator sets, refrigeration compressors
for trucks and rail cars, small pumps, and off-the-road  vehicles.
Very Small 1C Engines
       Although there are more very small 1C engines than units of any other capacity range, they
consume very little energy on a national scale because  of their extremely low annual use rate
(-50 hrs/year)  and small  size.  Most engines in this category are single-cylinder, gasoline-fueled
units used primarily for lawn and garden equipment and  chainsaws.  Accurate quantification of this
equipment group is difficult due to the large number of sales, the extremely large population, low
energy  consumption, and the difficulty of determining the annual  use rate.  On both a national and
                                                2-40

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local  scale, this grouping 1s Insignificant  1n  terms  of total  NO   emissions  due  to  their  low  total
fuel consumption.
2.1.5.1  Operating Characteristics
       General operating conditions for  1C engines  for the  four groups within  this  sector are im-
possible to quantify because of the large number  of possible equipment designs and  choices of fuel
which affect the operation of an engine.  Several of  the design features and operational  adjust-
ments which may influence combustion-related polUitant formation  are  listed  in Table 2-10.
2.1.5.2  Effluent Stream Characterization
       Exhaust gas is the only effluent  stream  from 1C engines  under  normal  conditions.   However, oil
and cooling water that  are replaced during maintenance need to  be disposed of  properly.   Large sta-
tionary  1C engines usually operate at constant  load and speed.  Nonstandard  operating conditions in-
clude  load change, startup and shutdown  transients, and upsets  such as fuel  or electrical system failure.
2.1.5.3  1C Engine Equipment Categories
       The absence of adequate data on any but  the  simplest equipment division requires the use of
equipment groupings defined above.  Figure 2-11 indicates the equipment type breakdown which will
be  used  for subsequent  quantification in Section  5.
2.1.6  Industrial Process Heating
       Significant quantities of fuel  are consumed  by industrial  process heating equipment in a
wide variety of  industries, including iron and  steel  production,  glass manufacture, petroleum re-
fining,  cement manufacture, sulfuric  acid manufacture, and  brick  and ceramics manufacture.  In
addition, there  are dozens of industrial processes  that burn smaller amounts of fuel, such as coffee
roasting, drum cleaning, paint curing ovens, and  smelting of metal ores, to  name only a few.
2.1.6.1  Process Descriptions and Operating  Conditions
       Process descriptions are given below  for those industries  which use significant amounts of
process  heat.
2.1.6.1.1  Iron and Steel Industry
       The iron and steel industry is one of the  major contributors to combustion-related process
NOX emissions.  The most important combustion processes are sinter lines, coke ovens, open hearth
furnaces, soaking pits  and reheat furnaces.   The  remaining  combustion-related  processes  (pelletizing,
                                                2-41

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 TABLE 2-10.   DESIGN  AND OPERATIONAL ADJUSTMENTS  WHICH AFFECT
              EMISSIONS  FOR 1C  ENGINES  (Reference 2-32)
         Design
  Operational Adjustment
 Surface  to  volume  ratio
 Bore and stroke
 Valve overlap
 Displacement/cylinder
 Strokes/power cycle
 Chamber  design
 Compression ratio
 Air  charging:
  Naturally aspirated
  Blower scavenged
  Turbocharged
 Fuel  charging:
  Direct injection
  Indirect injection
  Carburetted
Engine cooling
Air-to-fuel ratio
Torque (mean effective
pressure)
Speed
Spark timing
Fuel injection timing
Fuel properties
Lubrication and maintenance
                             2-42

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Reciprocating
1C engines
                    Large bore
                  ^~    kW/cyl '
Medium power
75 kW to  75 kW/cyl
                  L Smal1
                   <75  kW
                            Natural gas


                            Diesel oil


                            Dual fuel
Natural gas


Diesel oil


Gasoline
                            Gasoline
         Figure  2-11.   Important reciprocating 1C engine
                        equipment types and their fuels.
                                2-43

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heat treating, and finishing) are less important because they use relatively  small  amounts  of fuel
(Reference 2-33).
       Sintering machines are used to agglomerate ore fines, flue dust, and coke  breeze  for charging
of  a blast furnace.  The use of this operation is presently declining at the  rate of  about  3.4 per-
cent annually  because of its inability to accomodate rolling mill scale which  is  contaminated with
rolling  oil.
       Coke  ovens produce metallurgical coke from coal by the distillation of  volatile matter pro-
ducing coke  oven gas.   The  fuels commonly used in this process are coke oven  gas  and  blast  furnace
gas.  Although NO  emissions are minimized by slow mixing in combustion chambers, they are  nonethe-
less substantial because of the very large quantity of fuel consumed in this process.  Present pro-
jections show  a 5.7  percent annual increase in fuel consumption for coke ovens.
       Open  hearth furnaces are now being replaced in the U.S. steel industry  by  the  basic  oxygen
furnace, but are still  an important source of NO  emissions because of the very high  combustion air
preheat  temperatures, high  operating temperatures, and the practice of oxygen  lancing.   Fuel  con-
sumption in  open hearth furnaces is presently decreasing about 8 percent per year.
       Soaking pits  and reheat furnaces are used to heat steel billets and ingots to  correct  working
temperatures prior to forming.  Current trends are toward continuous casting of molten metal,  and
the need for these units is being eliminated.  At present however, soaking pits and reheating furnaces
still consume  more fuel than any other single process in the steel industry.   In  spite of the fact
that soaking pits and reheat furnaces are being phased out, consumption of process  fuel  continues
to  increase  at an annual rate of about 2.8 percent in the iron and steel industry as  a whole.
2.1.6.1.2  Glass Industry
       In the  glass  industry, melting furnaces and annealing lehrs are the two fuel combustion pro-
cesses of greatest importance.  Melters in the glass industry are continuous  reverbatory furnaces
fueled by natural gas and oil.  Coal is not suitable for these furnaces because of  its inherent
impurities.  Annealing lehrs control the cooling of the formed glass to prevent stains from occur-
ing.  Some lehrs are direct-fired by atmospheric, premix, or excess-air burners.  About  80  percent
of the total  industry fuel  consumption goes for melting, while annealing lehrs consume about 15 per-
cent.   There is a current trend in the glass industry towards electric melters, or  at least elec-
trically-assisted conventional melters.  But until it becomes clearer which fuels are going to be
available in the future, no definite trends will emerge.  Present trends toward fuel  oil in place  of
natural   gas have begun as a result of natural gas shortages and price increases.
                                                2-44

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2.1.6.1,3  Cement Industry
       Cement kilns are the major combustion  processes  1n  the cement Industry.   These  kilns  are
rotary cylindrical devices up to 230 m  (750 feet)  1n length which contain  a feedstock  combination
of calcium, silicon, aluminum, Iron, and  various other  trace metals.   This mixture  of  elements In
the form of various combinations of clay,  shale, slate, blast furnace slag, iron ore,  silica  sand,
limestone, and chalk slowly moves through  the kiln as products of fossil fuel combustion move in an
opposite direction.  Temperatures of the  material  during the process  may reach  1.756K  (2.700F).
       Coal, fuel oil, and natural gas  are the main fuels  used 1n cement kilns.   Natural gas  accounts
for 45 percent of the fuel consumed, coal  for 40 percent,  and fuel  oil  for 15 percent.  The major
effluent stream for this  process is the exhaust gas which  passes  through the entire  length of the
kiln and may entrain additional particulate or trace metals from  the  kiln  feedstock.   Cement  indus-
try figures show that the industry has  grown  an average 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  2-34).
                            I
2.1.6.1.4  Petroleum Refineries
       A wide variety of  process combustion takes  place in the petroleum refining industry, including
catalyst regenerating in  the catalytic  cracker, catalytic  reforming,  process heating,  delayed coking,
and hydrotreating and flaring of waste  gases.   Catalytic cracking is  required for a  large portion of
gasoline production.  Fuel is consumed  in  this operation in the catalyst regeneration  procedure which
removes coke and  tars from the catalyst surface.   Temperatures during this  process are moderate,
ranging from 840  to 922K  (1,050 to 1.200F), but fuel  requirements are on the order of  829 kJ/1
 (150,000 Btu/Bbl) feedstock.  Catalytic cracking capacity  increased about  1.7 percent  per year between
1960 and 1973.  Future growth will depend on  energy and environmental  policy and particularly the
demand for low sulfur fuel oil.  Present  estimates of future growth are from 1 percent to 3.0 percent
per year (Reference 2-34).
       Catalytic  reforming, where certain  saturated ring hydrocarbons are  converted  into aromatic
compounds, typically utilizes oil, gas, or electricity  as  its primary fuel.  Process heaters  serve
to heat refinery  process  streams prior  to distillation. They are generally large combustion  units
firing heavy residual oil and high sulfur-bearing  gas streams. Delayed coking  is an energy extensive
process which uses severe cracking to convert residual  pitch and  tar to gas, naptha, heating  oil and
other more valuable products.  Hydrotreating  is a  process  designed to remove impurities such  as
sulfur, nitrogen, and metals to prepare cracker or reformer feedstock.
                                                2-45

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       Process heating fuels used by the refinery industry are primarily natural gas and refinery
 gas, along with some residual oils and petroleum coke.  Projections are for a 2.7 percent annual
 increase  in process heating to 1980, and 2.9 percent per year to 1985 (Reference 2-34).  The fuel
 mix  for the future is highly dependent on both availability and costs of the preferred fuels, and
 is therefore  very difficult to project until national energy priorities are established and the ques-
 tion of natural gas price regulations is settled.

 2.1.6.1.5 Brick and Ceramic Kilns
       Brick  and ceramic kilns for curing clay products are other major users of process heating
 fuels.  Products of these kilns include structural bricks, structural and facing tile, vitrified
 clay pipe, and other related items.  Typically a kiln is operated in conjunction with a drier which
 recovers  part of the heat contained in the exhaust gases.  Kilns are fueled by coal, oil, or gas
 (depending on the availability of fuel and the product being cured) for batch runs of 50 to 100 hours
 at temperatures around 1.367K (2,OOOF).  Combustion products are ducted from the kiln to a drier,
 where wet clay products undergo an initial drying procedure.  Occasionally, when higher temperatures
 are  needed for drying, a secondary combustion process is used in the drier itself.
       Since  brick production in the past has shown a strong correlation with the country's economic
 health, reliable projections of future growth for the industry are difficult to make.
 2.1.6.1.6  Sulfuric Acid Manufacture
       Sulfuric acid, H-SO., is manufactured by contact processes which are classified by their
 feedstocks: elemental sulfur burning, spent acid and hydrogen sulfide burning, and sulfide ore and
 hydrogen  sulfide smelter gas burning.  These three processes account for 68 percent, 18 percent,
 and  14 percent of domestic production, respectively.  Total U.S. production of H-SO. in 1974 was
 estimated to  be 29.1 Tg (32,000,000 tons), the bulk of which was used by phosphate fertilizer manu-
 facturers, chemical  manufacturers, and the iron and steel industry.
       Combustion related emissions - including N0x - are a result of the initial burning of the
sulfur in the feedstock with natural gas or fuel  oil.  The growth of sulfuric acid industry is
estimated at 4.6 percent per year through 1980 (Reference 2-35).

2.1.6.2  Effluent Stream Characterization
       In all  cases  of process combustion described above, the only effluent stream from the com-
bustion process  is the combustion product stream itself.  In those cases where high particle loading
occurs  as a result of coal  combustion or dust entrainment (bricks, cement), a collection device is
normally used on the stream, producing either an additional liquid or dry solid effluent stream.
                                                2-46

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For several  processes, additional contaminants such as trace metals enter the stream from the pro-
duct, as In cement kilns or glass melters.  Because of process requirements, these contaminants are
expected to continue to enter the gas stream whether or not combustion control measures are Imple-
mented.  Table 2-11 lists the combustion-related effluent streams associated with each of the
industrial processes described above.

2.1.7  Advanced Combustion Processes
       Several alternate or advanced energy systems are currently in various stages of development,
and a number of these are expected to see commercial applications in the 1980's and 1990's.  Here,
the most important of these processes and their related equipment will be discussed in terms of
their possible impacts on pollutant emissions.  A more detailed process description and review of
NO  control options for these systems are given in Section 4.
       There are two alternate energy systems which are already commercially available:
       i   Repoweri ng
       •   Pressurized boilers
 In addition, three other processes are expected to become available within the next decade which
will  have significant potential  impact on polluta'nt emissions:
       •   Combined cycles/coal  gasification
       •   Fluidized bed combustion
       •   High temperature gas  turbines
 Processes which may eventually become commercially feasible alternatives, but which still  require a
 good  deal of development, include:
       t   Catalytic combustion
       •   Magnetohydrodynamics
       •   Binary  cycles
Table 2-12 shows the state of development of each of these advanced combustion systems.
       The following subsection  briefly describes each process and Its projected operating charac-
teristics, if available.  In addition, current prospects for Implementing each process are given.
Since there is little or no commercially Installed capacity for these processes, they are not in-
cluded 1n emission quantifications presented in Section 5.  However, subsequent emissions projections
                                                2-47

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             TABLE 2-11.  SIGNIFICANT INDUSTRIAL PROCESS HEATING
                          EQUIPMENT TYPES
                                     Gaseous Effluent Stream Description
Iron and Steel Industry
    Coke oven underfire
    Sintering

    Open hearth furnaces

    Soaking pit and
    reheat ovens
Glass Industry
    Melters

    Annealing lehrs
Cement Industry
    Kilns

Petroleum Refining
    Catalytic cracking

    Process heaters
Brick and Ceramics
    Kilns
Combustion products
Combustion products and entrained
substances from feedstock
Combustion products and entrained
substances from feedstock
Combustion products
Combustion products and entrained
substances from feedstock
Combustion products
Combustion products and entrained
substances from feedstock
Combustion products and volatilized
products or catalysts
Combustion products
Combustion products and entrained
substances from driers and feedstock
                                   2-48

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      TABLE 2-12.  ADVANCED COMBUSTION SYSTEMS - STATE OF DEVELOPMENT
Repowering

Pressurized boilers

Low Btu coal gasification

Fluidized bed combustion

Advanced HT gas turbine
steam cycle

Binary cycle

   Topping

   Bottoming

MHD open cycle

Catalytic combustion
Currently available

Currently available

Pilot plants, late 1970'sc

Pressurized demo plant 19814

Commercially available 1984
Demo plant 100 MW 1981

Demo plant 1981
50 MW demo plant 1984
Gas turbine demonstration 1980
 Reference 2-38
Reference 2-37
"Reference 2-36
 Aerotherm estimate
                                   2-49

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will include these units as emission sources.  Also, a special process engineering  report  will  be
done as part of this NO  E/A to address the developmental status and the projected  economic  and
                       X
environmental problems for these processes.

Repoweri ng
       Repowering is broadly defined as the addition of a combustion turbine to an existing steam
plant, involving the mechanical or thermal integration of the combustion or steam cycles (Ref-
erence 2-39).  More specifically, repowering has meant the conversion of an existing steam boiler
or boilers in the power output capacity range of 30 to 75 MW to an unfired heat recovery steam gen-
erator  (HRSG) with the addition of a conventional simple cycle gas turbine (or turbines) in the output
capacity range of 15 to 120 MW.  This turbine is used to drive a mechanical electrical generator and
exhausts to the HRSG.  In another variation known as supplementary firing, a turbine is added, but
the firing capabilities of the boilers are maintained.  Still another variation — less efficient than
the previous two - uses part of the gas turbine exhaust to preheat the HRSG feed water and the re-
mainder to operate the boiler.  There are a number of advantages to repowering existing systems
(Reference 2-38):
       •   Large capital outlay for new equipment, facilities, and sites may be deferred until pres-
           ent uncertainties in electrical utility growth demands are resolved
       t   New order lead time is reduced
       •   Equipment heat rate is improved and environmental impact is reduced
       •   Flexibility is improved and firm power reliability increased, since the gas turbine may
           be run independently
       The characteristic effluent streams emitted by both conventional gas turbines and boilers
will be present in the combined systems, although supplementary firing will result in different
combustion characteristics than in conventional boilers.

Pressurized Boilers
       Pressurized boilers, often referred to as supercharged boilers, operate at furnace  pressures
up to about a million Pascal, or about 10 atmospheres.  Presently, several of these units  are being
operated in Europe (Reference 2-37), but none of the utility size are installed in this country.
This design has several advantages over conventional boilers, including increased heat transfer
within the furnace, higher volumetric heat release, and reduced boiler size.  Pressurized  boilers
are particularly suited to gas and oil or other fuels which can be introduced into the combustion
                                                2-50

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furnace under pressure.  In the U.S., 1t appears that the major  application  of  pressurized  boilers
will Involve fluidlzed bed combustion discussed below.

F1u1d1zed Bed Combustion
                                                 •
       In fluldized bed combustion, air 1s blown through a  bed of granular noncombustlble material,
such as coal ash or lime, causing the granulated bed particles to become  suspended.   Fuel,  normally
crushed coal, 1s pneumatically injected near  the bottom of  the bed where  It  1s  combusted at tem-
peratures between 1,033 to 1.367K (1,400 to 2.000F).  Although the flyash particles entrained  in the
combustion gases from  fluidized bed combustion have a high  carbon content, these  particles  are
trapped in particulate collection devices and reinjected to ensure efficient combustion.  Sulfur
control through an SO- sorbent bed such as CaCO, or dolomite is  a distinct possibility, and reduc-
tion of thermal NO  is a direct result of the inherently low combustion temperature of the  fluidized
bed process.  Operating pressures range from  atmospheric to as high  as 25 atmospheres.  Higher pres-
sure units are designed to be used in a combined gas turbine steam cycle  in  which the fluidized bed
unit will act as an external combustor for the gas turbine  and a steam generator  for the steam
turbine.  Fluidized bed combustion — especially the pressurized  design —offers several advantages,
including:
       •   High heat transfer rates and volumetric heat release
       •   Reduction of ash fouling and high  temperature corrosion as a result of low combustion
           temperatures
       •   Ability to  burn lower grade fuels  more readily than conventional  boilers

Coal Gasification/Combined Cycle Gas Turbines^
       Low-Btu gas from coal is rich in hydrogen and carbon monoxide, with a heat content of 4.7 to
14.9 MJ/m3 (125 to 400 Btu/ft3).  It is the product of the  partial combustion of  a mixture  of coal,
air, and steam.  This  gas can be converted into pipeline quality gas by two  additional processes,
water  gas shift and methanation.  Long-term economical advantages, however,  will  come from  onsite
production of low-Btu  gas for combined cycle  gas turbines.
       There are three candidate processes for producing gas from coal as a  fuel  for both conven-
tional steam plants and combined cycle turbine-steam plants.   These  processes are known as  fixed
bed, entrained bed, and fluidized bed gasification.  In addition, the chemically-active fluidized
bed (CAFB) gasifier shows promise for use with high sulfur  coal.   CAFB gasification, when used
                                                2-51

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with high sulfur petroleum residuum or asphalts, is expected to remove up  to  95  percent of the sul-
fur and a large portion of the vanadium as well as other trace metals.

High Temperature Gas Turbine Steam Cycle
       High temperature gas turbines for use on combined gas turbine steam cycles firing  low-Btu
gas are currently projected to be commercially available about 1984.  Present combined  cycle  units
are economically feasible only for intermediate range plants, but increasing  inlet temperatures to
1.972K (3.000F) would improve unit efficiency to about 50 percent.  Coupling  this new design  to a
nearby low-Btu gasification plant would give a total plant efficiency of about 38 percent  (Ref-
erence 2-36), which compares favorably to present day coal-fired steam plants.  The high temperature
of the combustion zone in this kind of a unit, however, would increase thermal N0x formation  for
which dry controls or water injection techniques have not been developed.

Catalytic Combustion
       Catalytic combustion is being vigorously pursued for application to gas turbine  combustors
and area sources.  By total premixing of the fuel and air, temperatures in the adiabatic catalytic
combustion section can be lowered to approximately the turbine inlet temperature, and effectively
eliminate thermal NOX generation.  The system relies on the catalyst to rapidly and completely com-
bust the typically lean mixtures that result from the total premixing.  Excellent catalyst perfor-
mance at temperatures up to 1,756K (2.700F) has been demonstrated for short periods of  time (75 hours)
in feasibility studies (Reference 2-40).

MHD Open Cycle
       Magnetohydrodynamic (MHD) generators convert mechanical energy to electrical energy by the
interaction between a moving conducting fluid and a stationary magnetic field.  Open cycle processes
may use fossil fuel combustion products directly as a conducting fluid simply by seeding with an
ionized salt of potassium or cesium.  A waste heat boiler is used in conjunction with the  MHD unit
to recover thermal energy from the exhaust gases.  Projected cycle efficiencies are 50  percent with
potential for as high as 60 percent in the long term.
Binary Cycle
       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 and the exhaust heat
of a steam cycle.  Each of these processes can increase conventional  steam plant efficiencies to
                                                2-52

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50 or 60 percent.   Although these conversion techniques will  have  little  affect  on  the  combustion
process themselves, the Increased efficiency achieved will  reduce  pollutant emissions accordingly.
2.1.8  Incineration
       Nearly 50 percent of the urban and industrial waste  generated  in the U.S.  is burned in in-
cinerators (Reference 2-41).  Incineration is given secondary emphasis in this assessment.  Emission
estimates are given in Section 5.4 for comparison with other  NO  sources.  The major types of incin-
eration equipment are:
       •   Municipal incinerators - single or multiple chamber units  with a capacity of greater
           than 45 Mg per day and typically incorporating some form of particulate control device
       t   Industrial/commercial incinerators - single or multiple chamber units  having a capacity
           of from 23 Kg to 1,800 Kg per hour and occasionally have emission control devices
       t   Miscellaneous trench, domestic, flue  fed, pathological, or controlled  air incinerators
 2.2    MOBILE COMBUSTION SOURCES
       Mobile combustion sources are the second  major cause of atmospheric NO  emissions.  Although
 this  sector is not within the scope of the assessment, it is  defined  in this section and NO  emission
 estimates from mobile sources are included in Section 5.4 to  accurately compare stationary and mobile
 sources.
       Mobile sources include both highway and nonhighway vehicles.   Highway vehicles can be divided
 into  the  following categories:
       t   Passenger cars and light trucks powered by gaseous (LPG, CNG, LNG), diesel  or gasoline
           fuels
       •   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 subcategories:
       •   Aircraft
       •   Locomotives
       •   Vessels - further divided into inboard and outboard
       •   Small general utility engines —snowmobiles, minibikes, dunebuggies,  small electric
           generators, etc.
                                                2-53

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 2.3     NONCOMBUSTION SOURCES



        Noncombustion NO  emissions are produced by several primary chemical  manufacturing processes.
                       A


 Although  none of  these processes are significant on a national scale  in  terms  of absolute emissions,



 they  are  often  cited as serious local sources of pollution.  The most important  of these  processes



 are:




        •    Nitric acid manufacture




        •    Adipic acid manufacture




        •    Explosives manufacture




        Certain  secondary chemical processes are also sources of NO ,  including fertilizer manufac-
                                                                  A


 ture  and  various  chemical  nitration processes.




        Since these noncombustion sources of NO  are of interest to this  assessment for making  com-



 parisons  of relative emissions, they will  be carried through to the Section  5  emission inventory.





 Nitric Acid Manufacture




        Nitric acid, HN03>  is  manufactured  in the U.S. by the oxidation of ammonia.  The primary uses



 of this acid are  for nitrate  fertilizers (-60 percent); industrial explosives  (-15 percent); and



 various organic chemical manufacture, steel pickling, and military munitions (25 percent).  Emissions



 from  nitric acid  plants are not significant on a national scale, but  on  a local  basis they are fre-



 quently of great  concern.  The tail gas or off-gas emanating from the HNO, plant contains about



 0.3 percent NO  (NO, N0~).  Catalytic burners are typically used to control  NO   on these  plants by
              X       ฃ.                                                       X


 reducing  the NO,,  concentration of the tail gas to produce a colorless stream consisting mostly of



 N2> 02 and C02-




        The projected growth rate for the industry is 7.2 percent annually.





 Adipic Acid Manufacture




        Adipic acid  (CH2).  (COOH)2, is manufactured by the catalytic oxidation  of cyclohexane,  with



 cyclohexanone and cyclohexanol as intermediates.  Greater than 90 percent of the adipic acid  pro-



 duction is  used to manufacture nylon 6/6,  while the remainder  is  used for various plasticizers,



 synthetic  lubricants, etc.  Although emissions from adipic acid plants may not be significant  on



 the national scale, they may  be very serious on a localized basis, as only five  plants produce nearly



1.5 billion tons annually (Reference 2-42).  The N(?x produced by the  initial oxidation step of the



process is stripped from the adipic acid/nitric acid solution with air and steam.   NO and NO,,
                                                2-54

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are recovered by absorption 1n nitric add as part of  the process  rather  than as a pollution control
measure.  The industry as  a whole  has  undergone a recent slowing of a historically rapid growth,
dropping from an approximate  7  percent annual  growth from 1965 to 1971  to an expected 4 percent per
year growth  rate over the  next  three years (Reference 2-42).

Explosives Manufacture
        Explosives  can be divided into  four primary classifications: bulk  explosives,  propellants,
 initiating agents,  and specialty explosives.   The major bulk explosives and propellants are  nitro-
 glycerine, nitrocellulose, 2-,  4-, 6-trinitrotoluene, and cyclotrimethylene trinitrimine.  The  re-
mainder of the  explosives  classifications is  produced in quantities much  smaller than those  mentioned
 and will not be considered here.

        The bulk explosives and  propellants are manufactured by essentially the  same process, which
 consists of  reacting concentrated acids with  an organic material in a nitration step.   Acid  fumes
 result from  the nitration  step, and are a form of 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.

 2.4    FUGITIVE EMISSIONS
        The final source of atmospheric NO  emissions is man-made and natural  fugitive emissions.
 These sources are  generally uncontrolled except through elimination of  the source and are not within
 the scope of the present assessment.  Estimates of the N0x emissions from these sources will be made
 in Section 5.4 for comparison with other NO  sources.
        Man-made sources of fugitive NO  emissions include:
        •  Open burning of municipal waste, landscape refuse, agricultural field refuse, wood
           refuse, and bulky industrial refuse
        •  Grain elevators
        •  Forest  fires -both  accidental and controlled burns
        •  Structural fires  - both accidental  and planned
        •  Minor processes - such as welding  and acid pickling
 Natural fugitive emissions result from nitrogen fixation in the biological nitrogen cycle  and  from
 lightning  (References 2-43 and  2-44).
                                                2-55

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2.5    CONCLUSIONS AND SUMMARY
       This section presents final comments on the general quality and comprehensiveness  of the
data  used to make the selection of equipment categories for the subsequent parts of  this  N0x E/A.
A  summary of the significant stationary fuel combustion equipment categories and their major fuels
specified in this section is presented.

2.5.1  Data Evaluation
       In general, the quality of data reviewed during the screening of various equipment sectors
was  adequate for this preliminary characterization.  The data on new equipment design characteristics
and  operating  practice was good.  The data on field population and operating practice for older
equipment was  only marginal and will need to be augmented as part of the subsequent  process  studies.
       The  utility boiler category - the most important from a NOX standpoint - is generally very
well  documented, especially in the areas of fuel consumption and composition, electrical power genera-
tion,  and installed capacity.  One large data gap exists, however, in 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 diffi-
cult to  obtain.  The data gap was filled, in part, by industry contacts, but more complete  informa-
tion  is  needed.  A further weakness  is the lack of available information on fuel use practices, par-
ticularly statistics on fuel origin, blending, switching, and backup.  Finally, potentially  valuable
information on how new equipment is  put online and older equipment retired, was generally unavail-
able.
       Since there are more kinds of packaged boilers than any other type of equipment, the  com-
pleteness of the data on packaged boilers is more questionable than the data for any other  sector.
A  further difficulty with packaged boilers is the fact that the equipment is categorized  differently
in different studies.  The data available for new unit sales are comprehensive.  However, only sparse
information is available on boiler fuel switching, retirement practices, operational maintenance,
or burner distribution.  As a result, the final selection of equipment is based strongly  on recent
sales.  This should make it applicable to the future emission control studies, in spite of  the
relative lack of data.
       Warm air furnace equipment selection is mainly based on the most recent U.S.  Census  estimate,
and is considered to be of highest quality.   Statistically, because of the very large number of
units being  considered, this sector  is undoubtedly very accurate.  Data on other residential and
commercial  combustion equipment included in this sector also come from the U.S. Census Bureau.
                                                 2-56

-------
However, the data are considered to be of fairly  low quality  1n  terms  of combustion-generated  air
pollution because of the lack of specific details,  particularly  for the fuel  consumed  by  various
equipment types.  Additional Information for  these  other residential and commercial  combustion equip-
ment types 1s required to complete this sector.
       Data on the gas turbine sector are considered to  be  fairly  accurate  as a  result of recent
installed capacity estimates in the Gas Turbine Standard Support Document.  One  obvious data gap,
however, is the absence of  information on the smaller  capacity units and their operational practices.
Because the availability of clean fuel and  pending  air pollution regulations  are uncertain, the
growth of the gas turbine industry is difficult to  predict.   Further information regarding electric
utility practice during peaking periods, fuel  or  equipment  switching during times of low  air quality,
and combined-cycle use is needed to make the  data on this sector complete.
        Data for the  reciprocating 1C engine sector  came  for the  most part from the recent standard
support document and are considered to be of  relatively  high  quality.   Application,  installed
capacities, load factors, and fuels are well  documented.  Very small gasoline engines, like those
used on lawn mowers, chain  saws, etc., have been  excluded because  statistics  on  their  distribution
and use are impossible to obtain.  This exclusion,  however, should have very  little  effect on  the
sector  totals.
        Data on  the process  heating sector 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
small applications.  The major processes, however,  and those  which may be subject to combustion
control in the  future, have been included so  that the  major portion of the  sector should be covered.
        Although noncombustion processes far outnumber  those discussed  in this report,  the major
ones have been  included.  Of greatest concern in  this  sector  are those processes, like nitric  acid
plants, which may cause serious local pollution problems.
        The other equipment  or process sources of  NO mentioned here are not covered  extensively,
                                                    A
but included for completeness.  As a result,  extensive data have not been gathered.  In most cases,
however, existing data on many of these less  important areas  are limited at best.

2.5.2  Tabulation of Stationary Fuel Combustion Equipment Categories
       The preliminary characterization of  the seven major  fuel  combustion equipment categories has
identified equipment designs having significantly different potential  for formation  and/or control
of combustion-generated pollutants.  Table  2-13 shows  the resulting equipment/fuel categories
                                                2-57

-------
             TABLE 2-13.  SIGNIFICANT STATIONARY FUEL COMBUSTION
                          EQUIPMENT TYPES/MAJOR FUELS

Utility Sector (Field Erected Watertubes)                         Fuel
    Tangential                                                  PC, 0, G
    Wall fired                                                  pcป ฐ> G
    Horizontal opposed and Turbofurnace                         PC, 0, G
    Cyclone                                                     PC, 0
    Vertical and stoker                                         C

Packaged Boiler Sector
    Watertube 29 to 73 MWa                                      PC, 0, G, PG
    (100M to 250 MBtu/hr)
    Watertube <29 MWa                                           C, 0, G, PG
    (<100 MBtu/hr)
    Firetube scotch                                             0, G, PG
    Firetube HRT                                                C, 0, G, PG
    Firetube firebox                                            C, 0, G, PG
    Cast iron                                                   0, G
    Residential                                                 C, 0, G

Warm Air Furnace Sector
    Central heaters                                             0, G
    Space heaters                                               0, G
    Other residential combustion                                0, G

Gas Turbines
    Large >15 MWa (>20,000 hp)                                  0, G
   . Medium 4 to 15 MWa
    (5,000 to 20,000 hp)                                        0, G
    Small <4 MWa (<5,000 hp)                                    0, G
Reciprocating 1C Engines
    Large bore >7
    (>100 hp/cyl)
Large bore >75 kW/cyla                                      0, G
    Medium 75 kW to 75 kW/cyla                                  0, G
    (100 hp to 100 hp/cyl)
                ,a
    Small <75 kWa (<100 hp)                                     0, G

                                   2-58

-------
                          TABLE 2-13.  Concluded

Industrial  Process Heating
    Glass me Hers
    Glass annealing lehrs
    Cement kilns
    Petroleum
        Catalytic crackers
        Process heaters
    Brick and ceramic kilns
    Iron and steel coke oven
        Underfi re
    Iron and steel sintering machines
    Iron and steel soaking pits and reheat ovens
    PC — Pulverized coal
    C  — Stoker coal or other coal
    0  -Oil
    G  - Gas
    PG — Process gas

 aHeat input
                                  2-59

-------
which may merit separate consideration in the subsequent emission inventories, process studies and
test programs.  Generally, obsolete designs and minor equipment types not expected to play a role
in future NO  control programs have been included as  subsets  of the major categories shown.  The
other NO  sources play only a peripheral  role in the  NO  E/A  and were not categorized beyond the
course groupings listed in the introduction to this section.
                                               2-60

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                                     REFERENCES FOR SECTION 2

2-1.    Bartok, W.  et al., "Systems Analysis of Nitrogen Oxide Control Methods for Stationary
       Sources -Volume II," prepared for National A1r Pollution Control Administration, NTIS-PB 192
       789, Esso,  1969.
2-2.    "OAQPS Data File of Nationwide Emissions, 1971," Office of A1r Quality Planning and Standards,
       Environmental Protection Agency, May 1973.
2-3.    Emission Data from the National Emission Data System (NEDS), EPA, Research Triangle Park,
       North Carolina, 1976.
2-4.    Shimizu, A. B. et al., "NOX Combustion Control Methods and Costs for Sources; Summary Study,"
       EPA-600/2-75-046, NTIS-PB 246 750/AS, September 1975.
2-5.    "Air Quality and Stationary Source Emission Control," U.S. Senate Public Works, 94:1, 94-4,
       March 1975.
2-6.    Personal communication with H. J. Melosh III, Foster Wheeler Corporation.
2-7.    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, April 1974.
2-8.    Breen, B. P., "Combustion in Large Boilers:  Design and Operating Effect on Efficiency and
       Emissions,"  16th International Symposium on Combustion, Cambridge, Massachusetts, August 1976.
2-9.   "Applicability of NOX Combustion Modification to Cyclone Boilers (Furnaces)," Monsanto
       Research Corporation, 1976.
2-10.  Surprenant,  Norman et al., "Preliminary Emissions Assessment of Conventional Stationary Com-
       bustion Systems, Volume II, -Final Report," EPA-600/2-76-046b, NTIS-PB 252 175/AS, March 1976.
2-11.  "Evaluation  of National Boiler Inventory," EPA-600/2-75-067, NTIS-PB 248 100/AS, Battelle
       Columbus Laboratories, October 1975.
2-12.  "Power" Magazine Plant Design Issues, 1971.
2-13.  Personal communication with R. Hall, EPA-RTP (EEI Data), November 1976.
2-14.  Personal communication with 6. Bouton, Babcock & Wilcox, December 1976.
2-15.  Personal communication with G. Devine, Combustion Engineering, December 1976.
2-16.  Personal communication with F. Walsh and R. S. Sadowski, Riley Stoker Corporation,
       November 1976.
2-17.  Personal communication with S. Barush, Edison Electric Institute, December 1976.
2-18.  McKnight, J. S., "Effects of Transient Operating Conditions on Steam-Electric Generator
       Emissions,"  EPA-600/2-75-022, NTIS-PB 247 701/AS, Research Triangle Institute, August 1975.
2-19.  Personal Communication with R. R. Vosper, Coen Company, January 1977.
2-20.  "Field Investigation of Emissions from Combustion Equipment for Space Heating," EPA-R2-73-084a,
       NTIS-PB 223  148, Battelle Columbus Laboratories, June 1973.
2-21.  "Current Industrial Reports, Steel Power Boilers," 1968-1975, U.S. Department of Commerce,
       Bureau of the Census.
2-22.  Shields, C.D., "Boilers, Types, Characteristics and Functions," McGraw Hill, 1961.
2-23.  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,
       KVB Engineering, October 1974.
                                                 2-61

-------
2-24.   "Statistical  Highlights -Ten Year Summary 1963-1972, and Total Industry Factory Shipments
       in Units," Gas Appliance Manufacturers Association, January 1974.

2-25., Dupree, W. G., and J.  S. Corsentino,  "Energy Through the Year 2000 (Revised)," Bureau of
       Mines, December 1975.

2-26.   "Statistical  Abstract of the United States 1975," 96th Annual Edition, U.S. Department of
       Commerce, Bureau of the Census, 1975.

2-27.   "American Gas Association Research and Development 1976," American Gas Association, 1976.

2-28.   "FPC News," Volume 8, No. 23, June 6,  1975.

2-29.   Durkee, K. R., et al., "Standards Support and Environmental Impact Statement -An Investiga-
       tion of the Best Systems of Emission Reduction for Stationary Gas  Turbines," EPA Office of
       Air Quality Planning and Standards, July 1976.

2-30.   "1975 Sawyer's Gas Turbine Catalog,"  Gas Turbine Publications, Inc.,  Stamford, Connecticut,
       1975.

2-31.   "Diesel & Gas Turbine Worldwide Catalog," Volume 41, Oshkosh, Wisconsin, 1976.

2-32.   Offen, G. R., et al., "Standard Support Document and Environmental Impact Statement -
       Reciprocating Internal Combustion Engines,"  Aerotherm Project 7152, Acurex Corporation,
       November  1975.

2-33.   Ketels, P. A., et al., "A Survey of Emissions Control and Combustion  Equipment Data in
       Industrial Process Heating," Institute of Gas Technology, June 1976.

2-34.   Foley, G., "Industrial Growth Forecasts," Stanford Research Institute, Contract No. 68-02-1320,
       September 1974.

2-35.   Hopper, Thomas G. and William A. Morrone, "Impact of New Source Performance Standards of 1985
       National  Emissions from Stationary Sources," Vol. I, Final Report  (Main text and Appendices  I
       through III), October 1975.

2-36.   "The National Power Survey Energy Conversion Research," Federal Power Commission, June 1974.

2-37-   Pfenninger, H., and G. Yannakopoulos,  "Steam Power Stations With Pressure-Fired Boilers,"
       (reprinted from Brown Boveri Publication No. CH-T020053 E) Combustion. September 1976.

2-38.   Ahuja, Ashok, "Repowering Pays Off for Utility and Industrial Plants," Power Engineering,
       July 1976.

2-39.  Gerstin,  R. A., "A Technical and Economic Overview of the Benefits of Repowering,"
       ASME 75-GT-16.

2-40.   "Development  of Catalyst and System Design Criteria for Catalytic  Combustors with Applica-
       tion to Stationary Sources," Aerotherm/Acurex Monthly Progress Report 7135-18, Contract
       68-02-2116.

2-41.   "Compilation  of Air Pollutant Emission Factors (Second Edition),"  U.S. Environmental Pro-
       tection Agency, AP-42, April 1973.

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

2-43.   Robinson, E.   and R. C. Robbins, Journal of Air Pollution Control Association, 20_, 303, 1970.

2-44.   Skinner,  K. J., "Nitrogen Fixation," Chemical & Engineering News,  October 1976.
                                                2-62

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                                              SECTION 3
                                     POLLUTANT CHARACTERIZATION

       Stationary combustion sources produce a variety of effluents which, depending on the locale,
may have effects on the environment ranging from negligible to significant.  To determine the incre-
mental  impact of applying NOX controls to stationary combustion sources, the environmental effects
of both controlled and uncontrolled sources must be evaluated.  This requires first an inventory of
the emissions from the sources and then a means to relate these emissions to changes in the environ-
ment.  Even though the impact of stationary source combustion facilities on the environment has been
the subject of intense controversy for over a decade, wide gaps exist in our knowledge of both the
quantities and the effects of their emissions on the environment.  This report summarizes the current
state of the art in both areas.  Section 3 will concentrate on potential effects of these emissions
on the environment; existing data on combustion-related emissions, with and without NO  controls,
are summarized in Sections 5 and 6.
       Although this section contains information on the impact of various pollutants, it is not an
environmental impact statement in the traditional (NEPA) sense.  The NOX environmental assessment
is intended to provide a general view of the need for NOX controls and the potential for creating
additional problems as NO  emissions are reduced.  The program generally considers various categories
of combustion sources and rarely focuses on one specific site.  Environmental effects are therefore
generalized and individual sites may be found where problems are either enhanced or reduced because
of local conditions.  The consideration of local ecology and the effects of a specific combustion
source will be left to traditional environmental impact statements for that site.   In addition,
since this report considers diverse equipment types and potential sites, a different approach
has been taken to set threshold values.   The usual  approach works from the process emissions,
using dispersion estimates to get ambient concentrations.   The ambient concentrations are then
compared to threshold pollutant levels,  which then determines whether controls are needed.  In
this specific effort, we are attempting  to work backwards.
       Section 3 attempts to assess the  available data on human health effects and terrestrial and
aquatic ecosystem responses to estimate  potentially significant concentration ranges.  These
                                                  3-1

-------
estimates will then be used to alert control system designers if NOX controls cause other pollutants
to approach significant concentrations.  The concentrations Indicated in Section 3 will be used to
evaluate and compare NO  control  approaches which may produce other pollutant problems.  This
evaluation will remain somewhat subjective, since the data base is inadequate to support precise
quantitative decisions.
       The pollutant levels defined in Section 3 will be used to determine sampling requirements for
airborne, liquid, and solid effluent streams in the tests to be performed under the NOX E/A program.
The threshold levels will also be used to help order the matrix of combustion sources and control
options considered in Section 7 of this report.  The data presented herein are preliminary,  however,
and deserve further refinement before they are used extensively for other than program planning.   The
present data will be substantially expanded as the NOY E/A progresses.
                                                     A
       The bioassay work to be performed on actual combustion source effluents will  provide  a
better understanding of actual pollutant effects, particularly pollutant synergisms  or antagonisms.
Impact assessment work could thus overlap other ongoing environmental  assessments,  so that close
coordination between programs becomes important.  It is also possible that the information obtained
on other studies could substantially augment the data base available for this study.
       A preliminary search of the literature on environmental impacts has been made, and the results
will be discussed in the remainder of Section 3.  To lay the foundations for the quantitative data
presented later, Section 3.1 considers possible pollutants which may be attributed to stationary
source combustion and  Section 3.2 describes the research methodologies used to establish exposure
levels.  Section 3.3 summarizes the results available to date, while Section 3.4 discusses these
data and recommends some short-term activities under this program to improve their quality.
3.1    POLLUTANT IDENTIFICATION AND TRANSFORMATION
       Many chemical compounds, comprised of diverse elements, have at one time or another been
identified as components of effluent streams from stationary source combustion.  These substances
can be considered in four general categories:
       t   Gaseous effluents from normal operation  (CO, C02, HgO, NO, N02> S02, SO,)
       •   Inorganic compounds from the ash component of the fuel
       •   Organic compounds generated by incomplete combustion of the fuel, primarily in off-design
           operation (especially transient and upsets)
                                                 3-2

-------
       i   Solid and liquid effluent streams  (boiler wash,  S02  scrubbing  residue,  etc.)
The existence of|a species 1n measurable concentrations may vary widely,  depending on source type,
fuel type, operating load, maintenance procedures, and types  of production control equipment employed.
       For some NOX control methods, little or no data on pollutant emissions are available.  To
insure that potentially harmful, but presently unidentified pollutants do not escape analysis because
of lack of data, this report will consider a wide list of possible pollutants.  This list, presented
in Table 3-1,* will be used to determine which pollutants should be considered when effects on
human health and terrestrial and aquatic life are evaluated.
       Table 3-1 is set up by general classes of compounds  and  then divided into specific compounds,
where warranted by the data.  Typical sources of the pollutant, emission  stream, and whether the
compound is emitted during normal or nonstandard operations are shown.  Where possible, typical
emission ranges are shown, along with the estimated persistence of the primary pollutant and the
measured values of ambient concentration where known (based principally on measurements in the
Los Angeles Basin).  These ambient concentrations are from  all sources, although the percentage  which
can be attributed to combustion sources has been estimated  in the adjacent column.
       It should be emphasized that large variations in ambient concentrations of air pollutants can
occur, depending on proximity to the source, meteorological conditions, location within the U.S.,
time of day, etc.  Consequently, the values given are subject to large variation, but provide some
typical ranges.  The ambient data were taken from the California Aerosol  Characterization
Experiment (ACHEX) Study  (References 3-1 and 3-2), and "California Air Quality Data"  (Reference
3-3); detailed hydrocarbon data for the Los Angeles Basin were determined by the EPA and the
California Air Resources  Board (CARB); and elemental composition data were taken from Flocchini,
Cahill, et al., (Reference 3-4), as well as the ACHEX study.  Data on some of the more exotic
species were taken from the report of Hanst, et al., (Reference 3-5).
       The persistence of both primary and secondary pollutants has been estimated qualitatively.
The tabulated values of low, medium, and high persistence correspond approximately to ranges of
<0.1, 0.1 to 1.0, and >1.0 days respectively.  For the organic  hydrocarbons, persistence is defined
in terms of half-life, based on reaction with the hydroxyl  radical.
       Finally, Table 3-1 shows a list of known or speculated secondary pollutants (which may result
from the listed primary pollutants), their concentrations relative to the precursor pollutants,
 Table 3-1 is not intended to be definitive.   It will be revised as work proceeds and the species  list
 will be expanded or contracted as required.   Many entries which are currently blank will be
 completed as further data are obtained.
                                                 3-3

-------
TABLE 3-1.  PRELIMINARY POLLUTANT CATALOG
            a.  NITROGEN CONTAINING COMPOUNDS



Species
NO




NO,
ฃ








NH3




HCN



Ami nes

Nitrous
Acid




Source
Coal

Oil
Gas





Coal x
\
Oil 1
/

Gas )
j
y
)

Coal

Oil

Gas
Coal,

Oil
Gas
Coal
Oil











Coal




Stream
Flue
gas



Flue
gas








Flue
gas



Flue
gas


Flue
gas
Flue
gas

\
Occurrence
in
-a o
*- "i—
•o 
-------
                                                              TABLE 3-1.
PRELIMINARY POLLUTANT CATALOG
b.  SULFUR CONTAINING COMPOUNDS
I
U1


Species


so2









so3





Source


Coal






Oil

Gas
Coal

on
Gas


Stream


Flue
gas








Flue
Gas



Occurrence
en
c
•o o
I- -r-
 O
X






X


X

X

V)
C
. 0
C •!-
a •<->
i/> i-
C OJ
o o.
z o
















Emissions
Quantity
(ppm)

2800













2800 )

<500
200

200
<50







Primary
Pollu-
tant
Persis-
tencea

•






Medium




Low


Measured
Ambient
Concen-
tration
(ppm)







0.005-

0.30



0.005



% From
Combus-
tion
Source








<95




<95



Possible
Secondary
Pollu-
tants

SO,
3
H2S04
Inorganic
sul fates
&
sulfites



H2S04
Inorganic
sulfates
sulfites



Quantity
Formed
Relative
to Pri-
mary Pol
lutant

Medium

Medium

Medium





Medium
Medium



Secon-
dary
Pollu-
tant
Persis
tence3

Low

Low

Low





Low
Low




Measured
Ambient
Concen-
tration
(ppm)



<.001

1-20,
ugnf




1-203
ugnT




Comments











•





-------
TABLE 3-1.
Continued
b.  Concluded



Species



H2S04
t t
Metal-
lic
sul-
fates
H2S03
ฃ 3
cos

H2S,
Organ-
ic sul-
fur com-
pounds ,
cs,.
z
thio-
sul-
fates



Source



All
sources
Coal,
Oil


All

All

Coal,
Oil
Cac
via j










Stream



Flue
gas

















Occurrence
v)
c
i- •!-
IO 4-*
-0 10
f- S—
ns 01
4-> Q.
co o
X

X



X












*/)
c
• o
(O +->
-M IO
tf> t-
d 01
o n.
•z. o








X

X











Emissions
Quantity
(ppm)

200

Small



200

Very
small
Very
small









Primary
Pollu-
tant
Persis-
tence3

Low

High



Low

High

Vari-
able









Measured
Ambient
Concen-
tration
(ppm)

<0.005







Very
small
H2S-
0.001-
0.025









% From
Combus-
tion
Source

<90









H2S-
<50










Possible
Secondary
Pollu-
tants

Inorganic
sul fates




Inorganic
sulfates











Quantity
Formed
Relative
to Pri-
mary Pol-
lutant

Medium





Medium












Secon-
dary
Pollu-
tant
Persis-
tence3

High





Medium













Measured
Ambient
Concen-
tration
(ppm)























Comments













Upsets:
HgS may
be as
high as
-2000
ppm for
short
times




-------
TABLE 3-1.
PRELIMINARY POLLUTANT CATALOG
c.  HYDROCARBON COMPOUNDS
Species

Alkanes








Alkenes













Alkynes


Source

Coal


Oil


Gas


Coal

Oil

Gas









Coal
Oil
Gas
Stream

Flue
gas







Flue
gas












Flue
Gas

tandard ฐ|
perations ฃ
	 -ป
0-&~


























onstan. 3
perations g
ZO
X


X


X


X

X

X









X
X
X
Emissions
Quantity
(ppm)

<150 s


<25


<50 ;


<150

<10

<25
i








<10
<5
<5



























Primary
Pollu-
tant
Persis-
tence a


"

Medium







Low












High

Measured
Ambient
Concen-
tration
(ppm)



























% From
Combus-
tion
Source



























Possible
Secondary
Pollu-
tants

Aldehydes
Adds
Ke tones
Alcohols
Nitrates
Nitrites
Peroxy-
acyl Ni-
trates
Aldehydes
Acids
Ke tones
Alcohols
Epoxi des
Peroxi des
Nitrates
Nitrites
Peroxy-
acyl Ni-
trates
Nitrocar-
boxylic
acids



"Quantity
Formed
Relative
to Pri-
mary Pol-
lutant

Medium
Small
Small
Small
Medium
Medium
Medium


Medium
Small
Small
Small
Small
Small
Medium
Medium


Medium


Small



Secon-
dary
Pollu-
tant
Persis-
tence a

High
High
Medium
Med i urn
Medium
Low
Medium


High
High
Medium
Medium
Medium
Medium
Medium
Low


Medi urn


Medium



Measured
Ambient
Concen-
tration
(ppm)

<0.06








<0.06
<0.05-6
<0.05














Comments



























Oxygenated Hydrocarbons
Alde-
hydes








Carbox-
yllc
acids

Ke tones


Coal

Oil






Gas
Coal

Oil
Gas
Coal
Oil
Gas
Flue
Gas








Flue
Gas


Flue
Gas


















X

X






X
X

X
X
X
X
X
<10

5



(utility)
2.5 -
200
[indus-
tri al }


<5
<200

5-12
<3



)
(
}
)
!




High







High


Medium













10.08
















<10




Acids

Alcohols

Organic
aerosol
Peroxy-
acyl
nitrates

Organic
aerosol
Esters

Acids


Medium

Small

Small



Medi urn

High

Small

Medium


High

Medium

High



Medi urn

High

Medium

High




































            3-7

-------
TABLE 3-1.  Continued
            c.  Continued



Species



Source



Stream
Occurrence

"S.ฐ
re 4J
T3 IO
c i-
 <50




Phenols


Cresols
Oxygen-
ated com-
pounds
(acids,
alde-
hydes ,
perox-
ides)
Nitroben-
zenes
Peroxy
benzoyl
nitrates







Peroxides

Hydro-
peroxides

Qui nones
Carboxylic
acids
Ketones
Al dehydes
Dimers
Medium


Medium


Small






Small


Small







&>
-s
tu
cr
m — •
< <*
3d
n>
3 0.
"
-------
TABLE 3-1.  Continued
            c.  Continued



Species
=^^=ป=™i=
'henan-
threne












Fl uoran-
threne











Pyrene












Benzo-
(a)py-
rene











Source
Coal










Oil

Gas
Coal









Oil

Gas
Coal










Oil
Gas
Coal








Oil
Gas



Stream
Flue
gas












Flue
Gas











Flue
Gas











Flue
Gas









ccurrence
„,
c
•o o
I Standar
| Operati
X










X


X









X


X










X

X








X

i/i
• o
| Nonstan
1 Operati













X












X












X










X


jnissions
uantity
(ppb)
0.01-0.3\
utility)

0.3-3
indus-
trial)

9-2300
residen-}
tial)


0.7-3.7

0.04 ,
0.003-
0.5
(utility)
0.8-10
[indus-
trial)
13-350
[residen-
tial)

0.02-1.8 1

0.04-3.4 i
0.01-0.5 \
(utility)
0.06-4.5
(indus-
trial)

2-2500
(residen- )
tial) f

)

0.005-2.2
0.05-7.5
D. 003-0.1 v
(utility)
D.007-2.2
(indus-
trial)
3.008-800
(residen- ;
tial)


0.006-.3
0.006-.1

Primary
Pollu-
tant
Persis-
tence8







Medium













Medium












Medium











Medium





Measured
Ambient
Concen-
tration
(ug/m9)







0-3













0-3












1-35











5-40






* From
Combus-
tion
Source







<50













<50












<50











<50






Possible
Secondary
Pollu-
tants
Peroxides


Hydroper-
oxfdes


Qui nones
Carboxy-
lic
acids
Ketones
Al dehydes
Dimers
Peroxides


Hydro-
peroxides

Qui nones

Carboxy-
lic acids
Ketones
Aldehydes
Dimers
Peroxides

Hydro-
peroxides


Qui nones
Carboxy-
lic
acids
Ketones
Aldehydes
Dimers
Peroxides

Hydro-
peroxides

Quinones
Carboxy-
lic acids
Ketones
Aldehydes
Dimers
Quantity
Formed
Relative
to Pri-
mary Pol-
lutant
1
Z
a>
—
 fD
3 3
rt- &.
3
to



cu
ง•5
_i.
D>
1?
T"— •
11
3 3
e+ Q.
a
ta

Secon-
dary
Pollu-
tant
Persis-
tence3
fedi urn


.ow



Medium
4edi urn


.ow
.ow
High
Medium


.ow


Medium

tedium

.ow
.ow
High
tedi urn

Low



Medium
Medi urn


.ow
.ow
High
Medium

Low


Medi urn
Medium

Low
Low
High

Measured
Ambient
Concen-
tration
(ppm)






















































omments J?
t—



















































  3-9

-------
TABLE 3-1.
Continued
c.  Continued
Species

Benzo-
( e ) py-
rene











Perylene














Anthran-
threne












Benzo-
(ghi)-
perylene









Source

Coal










Gas


Coal














Coal










Gas


Coal








Oil

Gas
Stream

Flue
gas





















































Occurr
ifl 'ฃ
ซ 0)
ซ-ป Q.
l/l O

X













X














X













X








X


Nonstan. 3
Operations %












X




























X













X
[missions
uanti ty
(ppb)
\
.007-
.15
utility)
.02-1.7
Indus-
rial)
.0-330 }
residen-
tial)


.006-. 5


0.005- \
0.015
utility)
0.35
indus-
trial)

0.1-770
residen-
tial)





0.001-
0.007
(utility
0.06
(indus-
trial)
0.26-100
( res i den
tial)


.02-. 06


0.003-
0.22
(utility
1
(indus-
trial)
0.11-440
( res i den
tial)


.08

.55-. 70
Primary
Pollu-
tant
Persis-
tence3







Medi urn














Medium













Medium












Medium






Measured
Ambient
Concen-
tration
(yg/m3)







1-25














0-1













1












2-45






% From
Combus-
tion
Source







<50














<50













<50












<50






'ossible
Secondary
Pollu-
tants

Peroxides


Hydro-
jeroxides

Qui nones

Carboxy-
lic
acids
Ketones
Mdehydes
Dimers
Peroxides


Hydro-
peroxides


}ui nones

Carboxy-
lic
aci ds
Ketones
Aldehydes
Dimers
Peroxides


Hydro-
peroxides

Qui nones

Carboxy-
lic
aci ds
Ketones
Aldehydes
Dimers
Peroxi des


Hydro-
peroxides
Qui nones
Carboxy-
lic
acids
Ketones
Aldehydes
Dimers
Quantity
Formed
Relative
to Pri-
mary Pol-
lutant
Q>
-i
o-
(ft
^~
•o
m
s
a.
I
ง
m
^
3
i

^
fa
eป
O"
n>
—
%
1
O-
i
ง

3*
5.
3
i
3


Cv
O -I
3 -*
m o-
< m
o'S
1-S
3 3
-_*-i.
S



at
ป'
s1
_
f
(D
Q.
I
ง

m
3
1
3
r*
Secon-
dary
Pollu-
tant
Persis-
tence3

Medium


Low


Medium

Medium


.ow
Low
High
Medium


Low



Medium

fedi urn


.ow
.ow
High
Medium


Low


Medium

Medium


.ow
-OW
High
Medium


Low

Medium
Medium


Low
Low
High
leasured
mbient
loncen-
tratlon
(ppm)
























































lomments
























































  3-10

-------
TABLE 3-1.  Continued
            c.  Concluded



Species

•
Benz-
a)
nthra-
cene







Chrysen










Coronen

















Source


Coal









Coal







Oil


Coal











Oil

Gas



Stream


Flue
Gas








Flue
Gas









Flue
Gas













ccurrence
(/>
c
3 O
4J
n
t-
I

X









X







X


X











X


t/J
c
. o
a +>
+J (D
10 ซ-
: OJ
o o.
9EO




































X


Emissions
Quantity
(ppb)

















-,





0.001- \
0.017
(utility)
0.005-
0.06
(indus-
trial)
0.22-1.8
(residen-
tial)



.5

.004-. 85 ,

rimary
ollu-
ant
ersis-
encea

ledium









Medium

















Medium








Measured
tonblent
Concen-
tration
(jig/m3)

0-20



























0-20









i From
Combus-
tion
Source

<50



























<50









Possible
Secondary
Pollu-
tants

Peroxides

Hydro-
peroxides
Qui nones
Carboxy-
lic
acids
Ketones
Aldehydes
Dimers
Peroxides

Hydro-
peroxides
Qui nones
Carboxy-
lic
acids
Ketones
Aldehydes
Dimers
Peroxides


Hydro-
peroxi des


Quinones
Carboxy-
lic
acids

Ketones
Al dehydes
Dimers
Juantity
Formed
Relative
to Pri-
mary Pol-
lutant
W
O)
cr
n>
o
ro
D-
3
tea

m
a
3
i

D>
O>
Z
ID
W
1
Q.
(O
ง
m
3
I
3
pf
s
O>

^
?
Tt
3
0.
3
0
3
m
<
•5
|
H
rt-
Secon-
dary
Pollu-
tant
Persis-
tence8

Medium

Low
tedium
Medi urn


.ow
Low
High
ledium

Low

Medium
Medium


Low
Low
High
Medium


Low



Medium
Medium



Low
Low
High

(easured
Ambient
:oncen-
tration
(ppm)








































lomments






































   3-11

-------
TABLE 3-1.  PRELIMINARY POLLUTANT CATALOG
            d.  TRACE ELEMENTS



Species



Source



Stream
Occurrence
i/i •
c
1$
ff> <4->
12
ซ 0)
•*-* fr
CO O
l/>
C "1-
(D 4->
•M IB
t/> fc.
C OJ
ฃS



Emissions Quant1tyb
(
Bottom Ash
jpm)
Flyash
PFG

Primary
Pollu-
tant
Persis-
tence*

Measured
Ambient
Concen-
tration
ng/m9


% From
Combus-
tion
Source



Possible
Secondary
Pollutants



Comments
TRACE ELEMENTS
Aluminum
Antimony
Arseni c
Bari urn
: Bromine
Cadmium
Calcium
Cerium
Cesium
Chromium
Cobalt
Copper
Dyprosium
Erbium
Europium
Fluorine
Gadolinium
Germanium
Gold
Hafnium
Holmium
Iodine
Iron
Iridium
Lanthanum
Lead
Lutetium
Magnesium
Manganese
Mercury
Molybdenum
Neodymium
Nickel
Osmium
Palladium
Phosphorus
(as Phos-
phates)
Platinum
Potassium
Praseodymium
Rhenium
Rubidium
Ruthenium
Coal










































\











































Flue
gas,
solid
ash









































X










































1










































1



















































<200
<5



<10
<1
<2

<5
<5
<0.1
<10
<1
•^ 	

<0.1
<50

<1




<200


-------
                                                           TABLE 3-1.   Concluded
                                                                       d.  Concluded

Species
Samarium
Scandium
Selenium
(as com-
pounds)
Silicon
Sodium
Strontium
Tantalum
Tellurium
Terbium
Thai i urn
Tin
Titanium
Tungsten
Vanadium
Ytterbium
Yttrium
Zinc
Zirconium

Source
r
Coal



































Stream


















Occurrence
1 Standard
Operations
)



































INonstan.
Operations



















Emissions Quantity
(F
Bottom Ash
<2
<100



< 10000
<15
<3
<1
<0.5
<1
<2

<20

<5
<100

<100
Pm)
Flyash
<5
<100

r*n 1
	 1.0 day
 Emission quantities are presented in three categories;  Bottom  Ash  is  all  solid material  removed  ahead  of  particulate
 removal devices; Flyash is the ash removed in the electrostatic  precipitator or other particulate  control  device, and
 PFG is the material which escapes the particulate control  device either as fine ash or vapor.
 Note that quantities are in ppm by weight of the  total material  in that category,
 of the ash which escapes collection and goes up the  stack.
                                                                                   i.e.,  cerium is  less  than  0.05%  (500 ppm)
                                                            3-13

-------
their persistence measured as above, and any known data on their ambient concentrations.  These data
are principally from the Los Angeles Basin.  The reader is reminded that Table 3-1 contains prelimi-
nary information and will be added to or condensed during the next year, as additional data become
available.
3.2    POLLUTANT EFFECTS RESEARCH METHODOLOGY
       A variety of research techniques has been used to evaluate the toxicity of pollutants.  The
following subsections discuss these techniques and their relevance to the current program; research
methods which evaluate human health effects are considered in the first subsection, aquatic and
terrestrial effects are considered in the second.
3.2.1  Methods to Assess Ambient Pollutant Health Effects
       Research methods which elucidate the toxic effects of inhaled substances have involved:
       t   Long- and short-term laboratory studies in animals
       •   Short-term experimental exposures of human volunteers
       •   Case reports
       •   Industrial hygiene reports
       •   Epidemiologic studies of occupationally-exposed workers
       •   Community epidemiologic studies, involving either the general population or selected
           subgroups such as children and asthmatics
When the results of such studies are evaluated to estimate ambient exposures which adequately protect
the health of the general population, the uncertainties, ranges of applicability, and disadvantages
inherent in a particular method must be considered.
       Table 3-2 briefly discusses these basic research methods and tabulates their advantages and
limitations.  The following points should be emphasized:
       •   While animal study is the only practical  method for assessing long-term response to
           controlled pollutant exposure, extrapolation from animal to human effects is qualitative
           at best.  Animal study is therefore most effective in identifying possible pollutant
           effects and in generating new hypotheses regarding mechanisms of action rather than in
           developing quantitative data on exposure thresholds.
                                                 3-14

-------
                                             TABLE  3-2.  METHODS FOR DETERMINING HEALTH EFFECTS OF AIR POLLUTANTS
                       Method
        Brief Description
             Advantages
                                                                                                                               Limitations
                 Animal toxicology
00
I
• Rats, mice, rabbits, guinea
pigs, beagles, cats, and mon-
keys are often used in animal
studies.  Typically one group
of animals is placed in an
exposure chamber to which the
pollutant is added at a spec-
ified rate and concentration
for a selected period of time.
A second, identical group of
control animals is also placed
in an exposure chamber contain-
ing filtered air for the same
exposure schedule as the ex-
perimental group.
  The animals may inhale the
pollutant normally or through
a mask, mouthpiece, or intratra-
cheal cannula, or a pneumo-.
thorax may be performed.
  Mortality following exposure
may be observed to determine an
LD50.  The animals may be
tested for pulmonary function,
increased susceptibility to
bacterial infection, morpho-
logic changes in tissue, cells,
or cellular components,
changes in enzyme activity, or
alteration of protein and lipid
molecular structure.
  Animals may also be sacri-
ficed for histo-pathological
examination at various se-
lected intervals.
t Easier and less expensive to
perform than human studies; re-
sults can be obtained fairly
rapidly.

• Various modes of administration
are possible:  continuous, inter-
mittent, inhalation, direct intra-
tracheal insufflation, intravenous
injection, intrapleural inocula-
tion, pneumothorax.

t Nearly unlimited freedom of ex-
perimental design; animals can be
sacrificed at any time.

• Mechanisms of injury can be
determined.

• Is the only reasonable method
for assessing long-term response
to controlled pollutant exposure.
Small animals, e.g., rats and
mice, may be exposed for their
natural life-span.

• Intraspecies variation in re-
sponse due to genetic differences
can be reduced by use of inbred
strains.

• A variety of subject types may
be exposed:  old, young, healthy,
with or without preexisting
chronic cardiac or respiratory
disease or acute respiratory ill-
ness.

• A larger number of subjects may
be exposed in comparison to exper-
imental human exposures.

• A wider range of pollutant con-
centrations and total  dosages may
be administered (lethal  and sub-
lethal doses), hence a maximal
dose-response curve can be estab-
lished.
• Severe limitations
(quantitative, qualitative,  mech-
anistic) in extrapolation  to human
effects.

• Subjective information cannot
be elicited from the subject.

• The degree to which the  animal
model approximates the human re-
sponse or disease mechanisms is
not known (great interspecies
variation).

t Use of healthy animals (appro-
priate human disease models  in
laboratory animals may not exist)
limits the sensitivity of  the
animal exposure.

• Should-be relied upon only when
human data are insufficient  or un-
available.

t Is best used for generating new
hypotheses regarding mechanisms of
action, for identifying new
effects not previously observed
in humans, for indicating  areas in
need of further human study.

-------
                                                   TABLE  3-2.  CONTINUED
                                                                                                                                       co
                                                                                                                                       oo
      Method
        Brief Description
             Advantages
                                                    Limitations
Experimental Human
Exposures
 • Experimental human studies
 usually  involve measurement of
 pulmonary function before,
 during and after air pollutant
 exposure.  Volunteers selected
 for participation are usually
 required to give a personal
 history of such characteris-
 tics as allergies, asthma,
 chronic respiratory or heart
 disease, smoking habits, etc.
 A physical examination is
 given before exposure and
 baseline measurements of
 pulmonary function, such
 metabolic parameters as heart
 rate, temperature, blood pres-
 sure, etc. are recorded.  Ex-
 posures are usually conducted
 in an exposure chamber sup-
 plied with filtered air plus
 the pollutant; and exposure
 conditions (concentration,
 temperature, humidity, etc.)
 are rigorously monitored and
 controlled.  Alternatively,
 exposures may be conducted
 in a body plethysmograph.
 Subjects may breathe normally
 or through a mouthpiece.  They
 may remain at rest or they
 may exercise intermittently
 or continuously.
  During exposures, the Inves-
 tigator may record signs such
 as coughing, wheezing, etc.
 and take measurements of vari-
 ous pulmonary parameters. Pul-
monary function would again be
 tested following exposure; sub-
jects would be interviewed for
subjective responses or symp-
toms (e.g., eye irritation, fa-
tigue, throat or nose irrita-
tion, etc.), and given a phy-
 sical examination.
• Extrapolation of results  from one
species to another is eliminated.

• The actual exposure time, pollu-
tant concentration, mode of adminis-
tration, total respired volume of
air, atmospheric conditions (humid-
ity, temperature, etc.) can be pre-
cisely controlled.

• A single pollutant or any desired
combination of pollutants may be ac-
curately administered.

• Subjects' characteristics that may
influence response can be identified
(e.g., age, state of health, pre-
existing chronic respiratory or car-
diac disease, history of asthma or
allergy, smoking, etc.); each sub-
ject can serve as his own control,
thus controlling for many covari-
ates.

• Subjective responses can  be elic-
ited from volunteers (e.g., sub-
sternal soreness, eye or throat
Irritation, etc.).

• Differential effects of exercise,
temperature and/or humidity can be
observed.

• From such studies it is theore-
tically possible to determine a
dose-response curve or to estab-
lish a minimal effective dose.
• The study designs possible (in
terms of mode of administration,
pollutant dose, range of physio-
logical response that can be meas-
ured) are limited by considera-
tions of ethics, cost, and time
required.

i Cost and inconvenience to the
subjects involved usually dictate
that exposures be brief - several
hours to several days; hence,
effects of chronic or long-term
exposure cannot be observed.

• Exposures usually involve less
than 10 subjects because of ex-
pense and availability of labor-
atory facilities.

• Although some hypersusceptibles
have been studied, most human
studies have involved "healthy
young adult volunteers" — a group
unrepresentative of the general
population.

• Due to the complexity of the
pollutant mixture found in ambi-
ent air, the actual atmospheric
exposure cannot be adequately
duplicated in an experimental
chamber.

• There  is some degree of risk to
the exposed subjects of discom-
fort - not of inevitable injury.

-------
                                                   TABLE 3-2.   CONTINUED
      Method
        Brief Description
             Advantages
                                                                                                              Limitations
Experimental Human
Exposures
(Concluded)
  Aside from testing pulmonary
function, an investigator may
study cardiac or metabolic re-
sponses or perform biochemical
analyses of blood or urine.
Reports of Occupa-
tional Exposures
(Nonepidemiologic
and Epidemiologic)
• Several methods of report-
ing occupational exposures
are available;  (1) the case
history describing a single
subject's response to a
particular episode (usually
accidental exposure to an
extremely high concentra-
tion of a pollutant);
(2) an epidemiologic analy-
sis in which workroom con-
centrations are estimated
or measured and partial
medical histories, sub-
jective complaints or
physical exams are obtained
from the workers exposed in
an attempt to relate expo-
sure to present state of
health (often exposures and
health effects are recorded
before and after improve-
ments in workroom practices,
ventilation, or control
equipment are instigated, al-
lowing comparison of de-
creased health effects from
reduced exposures); (3) retro-
spective or prospective
studies (historical or other-
wise) in which a study popu-
lation is identified and ex-
posures are reconstructed
or a study population is se-
lected and followed through
time to establish medical
and exposure histories.
• It is often possible to observe
the effects of exposure to isolated
pollutants at concentrations much
higher than those likely to occur
in ambient air; hence, this is the
sole means by which the upper end of
a dose-response curve can be estab-
lished, e.g., SOg in ore smelters,
NOX in nitration plant workers, COg
in meat packers, etc.

• Combination of pollutant exposure
plus a work/stress factor is more
likely to produce measurable health
effects than would exposure regimes
of an experimental study.

• Where adequate work histories are
available, chronic effects of long-
term, intermittent exposures may
be determined.

• Possibility of accurately charac-
terizing the pollutant dose is
greater than for a community epid-
emiologic study, although not as
good as an experimental  study.
 •  Much of the  data  collected is  of
 a  subjective nature as  workload
 and workroom procedures usually
 preclude extensive  physical
 exams.

 •  The study population  is  usually
 nonrepresentative of the general
 population in  that  workers are
 predominantly  male, 18  to  65 years
 of age, and sufficiently healthy
 to be working.

 •  Occupational exposure studies
 may generally  be regarded  as in-
 advertent experiments with only
 limited control of  exposure
 conditions.

 •  Occupational exposures are not
 directly comparable with ambient
 exposures both because  industrial
 workers are a nonrepresentative
 subgroup of the general population
 and because an occupational  expo-
 sure is intermittent (8 to 10
 hours per day, 5 days per week)
while an ambient exposure  is con-
tinuous; theoretically, an inter-
mittent exposure is presumed to
be less injurious than a contin-
uous exposure of equivalent  total
dose (concentration x time) be-
cause a time  period for recovery
 is present.

-------
                                                  TABLE 3-2.  CONCLUDED
      Method
        Brief Description
             Advantages
                                                                                                              Limitations
                                                                                                                                       CO
                                                                                                                                       CO
Community Epidem-
ic! ogic Studies
t Several types of epidemiology
studies have been performed to
evaluate the health effects of
air pollutants:  (1) a study
population is identified and
some measurement of health
effects (clinical examination,
questionnaire, telephone inter-
view, etc.) is compared with
concurrent pollutant charac-
terizations for that locality;
(2) a study essentially similar
to type (1) above but in which
health effects and pollutant
levels are assessed at inter-
vals for a period of time (a
school year, 2 years or longer,
weekly for several months,
etc.); (3) selected mortality
or morbidity rates for a given
area are compared with the pol-
lutant characterization for
that area on a yearly, monthly,
weekly, etc. basis and an at-
tempt is made to establish
statistical correlations be-
tween air pollution factors
and morbidity or mortality.
  The study population can in-
volve the community-at-large,
children, the elderly, suscep-
tible groups such as asthma-
tics, nonsmokers, etc.
  Health parameters observed
have included eye irritation,
subjective complaints, pul-
monary function, acute respir-
atory illness prevalence and
Incidence, mortality rates
from lung cancer and other
pulmonary or cardiac causes.
• Study group is experiencing a
real life exposure (as opposed to
artificial  exposures encountered
in experimental studies).

• Exposure over longer periods of
time (months-to-years) can be
studied.

• Hypersusceptible individuals are
inevitably included.

• Currently only means known  to
study chronic low-level  exposure
in humans.
• Can only establish a statistical
association; potentially causal
relationships can be indicated but
not easily established.

• Inconsistency in reporting ex-
posure data (annual maximum, dally
maxima, annual mean, hourly aver-
ages, etc.) makes Interpretation
of various studies difficult.

t Extremely difficult to charac-
terize actual ambient atmospheres
due to complexity of pollutant
mixtures; hence, it is difficult
to associate any health effect
with a single pollutant.

• Exposures of all Individuals in
the community are characterized by
a few monitoring stations.  Micro-
meterology of community may result
in large variations in actual ex-
posure levels.

•Big indoor/outdoor differences
in exposure  levels are known to
exist, but have not been allowed
for in studies to  date.

• To identify statistical  strengths
of various pollutants  or atmos-
pheric conditions  that may influ-
ence the health effect studied,
the investigator must  assume that
there is no  synergism  or antagon-
ism between  variables  and  that the
relationship between each  vari-
able and the health effect is
linear.

• The establishment of experimental
groups and proper controls is  dif-
ficult. Exposed  populations have a
flux of subjects  in and out.

• Results over currently available
time periods  (~1  to 10 years)  may
be obscured  by other effects.

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      •   Experimental  human  exposures must be short; hence, potential effects of long-term
          continuous  exposure to a particular substance must be inferred from results of short-term
          human exposures  and long-term animal studies.
      •   Although  the  community epidemiologic stgdy involves a real life exposure over a period
          of  time  (weeks-to-years), there are great difficulties both in characterizing the ambient
          pollutant mixture and in defining the actual exposure of individual members of the study
          population.   Therefore, associating any single pollutant with a particular health effect
          is  difficult, and must rely on related evidence from studies of animal  or human (experi-
          mental and  occupational) exposures.
       Since the data  base  available on health effects of pollutant exposure (i.e., long-term,  low-
level  exposure)  is  limited, identification of an ambient concentration at which a  particular health
effect may be  expected to occur is not possible.  Conversely, it would be equally  difficult  to
attempt an identification of pollutant levels from which no adverse health effect  would be expected.
Indeed, for many substances considered in this report, the published literature contains no  accounts
of human or animal  exposures at levels that approximate, even within several  orders of magnitude,
ambient concentrations typical of community exposures.
       Lack  of suitable data presents great difficulties in situations requiring use of an ambient
pollutant level  to  indicate when attention should be given to possible health effects from continu-
ous, long-term exposure. Consequently, a method for estimating permissible ambient concentra-
tions for community exposure using occupational threshold limit values (TLVs) and  LDBOs (the
dose that is  lethal  to 50 percent of the experimental animal population) from animal  toxicologic work
has been suggested  for comparison by Research Triangle Institute (RTI) (Reference  3-6).
       However,  there  are obvious limitations to direct analogies between occupational  exposures or
animal LD50s and continuous exposure of the general population.  Occupational TLVs were originally
designed to protect  most (95 percent) of the exposed working force.   But these TLVs may not  necessar-
ily be the same as  the threshold limits for an entire community.  Occupational  exposure is inter-
mittent (8 hours per day, 5 days per week, 50 or less weeks per year), whereas community exposure
is continuous.  For  the  same total dose (concentration x time) an intermittent exposure is generally
assumed to be  less  harmful  than continuous exposure, because intermittent exposure allows a  period
for recovery.* This differential  toxicity allows  the occupational  standard to specify a larger
total  dose than may  be acceptable for a community  exposure.
 There  are  several  substances  which are exceptions to this assumption; some degree of immunity may
 be developed during a continuous  exposure.   Hence, symptoms of toxicity may be more severe during
 an intermittent exposure.
                                                 3-19

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       In addition, an occupational  TLV is designed for a group of people that does not represent
the general  population.  The industrial working force likely to be exposed to a potentially toxic
substance is generally male, 19 to 65 years of age, and medically fit to be working; this subgroup
excludes many women, the aged, persons not fit enough to work, and infants and children.  Children
and infants  particularly are considered to be hypersusceptible, on a body weight basis, to some
inhaled substances.  These differences in population characteristics and exposure time constrain
analogies between occupational TLVs  and permissible community exposures.
       Using LD50 values to estimate ambient levels for continuous exposure is subject to the limitations
inherent in any animal study, primarily difficulties in quantitative extrapolation from animal to human
effects.  Furthermore, there are many uncertainties involving the degree to which the animal  tested
approximates the human response or disease mechanism.  Therefore, there is no exact proportional
relationship between animal LD50s and human no-effect levels for all pollutants.
       Acknowledging these difficulties, RTI (Reference 3-6) has  developed a  formula,  based on TLV
and LD50 data, to estimate the concentration of a  pollutant  or pollutant mixture  to which  the
general public may be continuously exposed without hazard to health.   This concentration was
defined by RTI as "the pollutant concentration (yg/m3)  for which  continuous  exposure with  100  per-
cent absorption causes a stationary  maximum body concentration equal  to 0.05  percent of LD50 value
of the-compound, assuming a biological half-life of 30  days" (Reference 3-6,  page 36).   From analy-
ses of present TLV standards, RTI reasoned that a  stationary maximum body burden  of 0.05 percent  of
the oral LD50 value for rats can be  considered safe.
       Linear regression analyses of the relationship between TLVs and LD50 values were performed.
This was unsuccessful (correlation coefficient of  0.61  for 191 substances; correlation coefficient
of 0.70 when 50 agricultural chemicals were added); however, it was pointed out that a poor  corre-
lation was not surprising, considering the wide range of TLVs for a given LD50 value.   The basic
relationship of TLV to LD50 was then compared with derived numerical relationships which describe
pollutant uptake, excretion, and accumulation on a body weight and respiratory frequency basis.
From these comparisons, equations were derived to  estimate permissible ambient exposures incorporating
a number of  assumptions and safety factors.  Two of these equations are used in the present report
to estimate  pollutant concentrations for continuous exposure:  (1) x = 1.65 x 10"3  (TLV), and
(2) x = 4.77 x 10~5 (LD50), where x  is the permissible ambient concentration and LD50 is the oral
LD50 for rats.
                                                3-20

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       RTI emphasizes that these estimated concentrations,  x,  are  not applicable  to  known  or  suspected
mutagens, carcinogens, or teratogens, and are  applicable  only  to substances  whose biological  half-life
is short compared to the assumed life of the individual.   In addition,  these formulae,  based  upon a
"one-compartment model with a single, first-order  excretion rate," do not  take  account  of  synergistic
actions between two or more pollutants, and assume:   (1)  that  all  pollutants entering the  respiratory
system are retained by the body, and  (2) that  animal  LD50 values are  applicable to man  (Reference
3-6).  Other assumptions and safety factors incorporated  into  calculation  of permissible concentra-
tions include:
       1.  The inhaled pollutant is evenly distributed  throughout  the body
       2.  The absorption factor equals 1; i.e., all  of the inhaled pollutant is  absorbed
       3.  The rate of excretion is proportional to  the body concentration of the pollutant
       4.  The biological half-life of pollutants  in  the  body  is 30 days
       5.  A safety factor of 40/168  is applied to TLVs in  converting intermittent to continuous
           exposure episodes on a weekly basis
       6.  A safety factor of 0.5 is  introduced to insure protection  of infants and children,  since
           one-year-old infants have  approximately twice  the respiratory frequency of an adult
       7.  Based on present TLV standards, a body  burden  of 0.05 percent (0.0005) of the oral  LD50
           for rats can be considered safe for continuous exposure
       The primary weakness of RTI's work is the many assumptions  made, even though simplifying
assumptions are necessary if a single expression is  to  predict safety levels for a wide variety
of  pollutants.  Assumptions concerning biological  half-lives were  made to  insure the greatest
degree of safety (e.g., many inhaled  substances have  half-lives  in  man of much  less than 30 days,
Tables 4 and 5 in Reference 3-6).  Assumptions concerning rates  of excretion, age differences  in
respiratory uptake, and corrections for the weekly,  intermittent nature of occupational  exposures
are also reasonable.  However, assumptions of  100  percent absorption  rates, even distribution  of
inhaled pollutants throughout the body, and the applicability of animal LD50 data to man may limit
the usefulness of these calculations.  The estimates  also do not consider  the irritant or disease-
producing effects of inhaled substances that are retained in the lungs and not  absorbed, or the
selective concentration of absorbed substances in  particular organs or tissues.   Furthermore,  for
many substances the extent to which the animal model  approximates  the human  response is not known;
therefore the validity of the RTI model in such a  situation is not known.
                                                3-21

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       In Table 1  of their report,  RTI compares their estimates for continuous exposure with preex-
isting ambient standards.   The results indicate that RTI's estimates are usually conservative, but
best applied to indicate orders of  magnitude rather than specific concentration levels.
       In spite of its limitations, the RTI model  is extensively used in this report to estimate
ambient pollutant levels below which adverse health effects from continuous exposure would be unlikely
to occur.  It is a reasonable model in situations  where insufficient or no toxicologic, occupational,
or epidemiologic evidence concerning health effects of chronic exposure is  available.   However,  for
this report three additional limitations must be considered.
       One limitation is that compensating safety  factors for some hypersusceptible portions of the
general population are not incorporated into the model.   This group includes asthmatics,  persons
with chronic obstructive pulmonary  disease such as chronic bronchitis and emphysema, and persons
with other pulmonary or cardiac insufficiencies.
       A second limitation is that  many pollutants exhibit significant temporal  variations in
ambient concentration, because of source characteristics, meteorology, or atmospheric reactions.
The model developed by RTI estimates a concentration for continuous exposure and does not consider
fluctuations in ambient concentration.  As ambient pollutant  levels fluctuate, it may be necessary
to consider acute as well  as chronic effects of exposure.  For some pollutants,  short-term exposures
produce effects that are unlike those observed during long-term exposure.  For example, nitrogen
dioxide exposure for short periods  (several hours  to several  days) at near-ambient levels produces
irritation to the lung and reversible lesions in the pulmonary tissue.  However, there is some
evidence that continuous exposure for several years or more at near-ambient levels of nitrogen
dioxide may cause emphysema in experimental animals.  It is possible that a maximum permissible
concentration for continuous exposure based on observed acute effects (the effects reflected in many
LD50 values), may not adequately protect the exposed population from effects that may result from
long-term exposure.
       For substances for which a demonstrated difference between acute and chronic effects exists
and which exhibit fluctuations in ambient levels (due either to diurnal patterns of emissions and
atmospheric reactions or due to occasional air pollution episodes), several permissible ambient
concentrations may have to be stipulated.  One concentration would protect against chronic effects
by continuous exposure, while a second concentration would protect against acute effects.  For example,
Loth EPA's Office of Air Quality Planning and Standards (OAQPS) and the Congress are currently
evaluating the need for a  short-term N02 ambient air standard to supplement the current
standard based on annual averages.
                                                 3-22

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       A third limitation to the RTI model is that when  two or more  substances are present in the
Inhaled air, their interaction may produce additive, antagonistic or synergistic effects.  The possi-
bility of synergistic or potentiating interaction between two pollutants  has significant implications
for the exposed population.  When two truly synergistic  substances are simultaneously inhaled, for
example an irritant gas (S02) and particulate aerosols,  the toxicological response is a greater
degree of irritation or decrease in pulmonary function than would be expected if the irritant effects
of each substance, taken separately, had simply been added.  Therefore, to estimate maximum concentra-
tions for continuous exposure, the simultaneous presence of two synergistic pollutants would require
lower maximum concentrations for each than would be necessary if either substance were present alone.
       Unfortunately there is little quantitative information available on pollutant synergisms.
The degree of potentiating effect, such as that suspected to occur between SO- and particulates,  can
be highly variable depending upon species tested, ambient temperature, humidity, and specific physico-
chemical type and size of particulate used.  Since these interactions are highly individual,  there
is no general formula for estimating maximum concentrations for continuous exposure which could
incorporate a safety margin to accommodate such interactions.  Synergism as defined above is  entirely
different from a defined chemical reaction in the atmosphere between  two individual  pollutants
which produces a new chemical species of greater toxicity; for example, the well  known reaction between
atmospheric ozone or other photochemical oxidants and sulfur dioxide which produces  the more  irritant
sulfur trioxide/sulfuric acid/acid sulfate continuum.
       The limitations discussed above must be carefully considered  in evaluating the preliminary
screening concentrations presented in Section 3.3.  Again it should be emphasized that these  levels
are intended to provide order-of-magnitude guidance on pollutant toxicity, not exact exposure levels.

3.2.2  Methods of Assessing Pollutant Impacts on Biota
       Principal techniques for evaluating impacts of pollutants on terrestrial  and aquatic biota
are identified, described, and briefly critiqued in Table 3-3.  Three levels of evaluation are
addressed:
       •   "First Estimate" Techniques.  This includes methods for making a rapid (and preliminary)
           assessment of the potential for a specific chemical or class of chemicals, at known
           concentrations, to adversely affect aquatic or terrestrial biota.  Methods include
           reviewing reports and other publications which summarize  known concentrations at which
           specific chemicals produce damage.
                                                 3-23

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                          TABLE 3-3.  METHODS OF ASSESSING POLLUTANT IMPACTS UPON AQUATIC AND TERRESTRIAL  SYSTEMS
                                     PART A.   "FIRST ESTIMATE" TECHNIQUES
         Method
                      Description
               Comments on Suitability
 Literature/Information
 Survey
 Generalized,  broad  literature review to identify known
 environmental  significance of a pollutant class or
 particular  chemical species.  Information for review
 includes  all  summary documents and publications/re-
 ports  describing the following:
    t   Distribution  and levels of pollutant(s) in
       compartments  of the environment
    •   Sources  of the pollutant(s)
    t   Pathways available for pollutant transport
       into  these compartments
    t   Potential toxic, bioaccumulatlon, and synergis-
       t1c effects
    •   Kinetics of pollutant accumulation in biotic
       tissues
    •   Transformation products that may be of environ-
       mental  Importance
State of the art.   Useful  for rapidly screening for
potential biotic impacts of various pollutant con-
centrations.  Values expressed in literature are not
usually reliable for site-specific situations, but
such values are often useful  for identifying whether
or not specific studies should be undertaken.
 Bioassay Results
 Review
 Review of  results of specific bioassay and environ-
 mental physiology experiments that have assessed
 impacts of the specific pollutants of interest, upon
 various species.
State of the art.  Useful for rapidly obtaining ex-
perimentally-derived data on acute effects of pol-
lutants on biota.  Normally, there are limitations
for direct use in site-specific circumstances be-
cause of potential chemical/physical Interactive
phenomena that will likely occur at a specific site.
Modeling of Permissible
Concentrations
Based upon LD50 data and other information from the
literature.  A derivation of pollutant hazard criteria
for a particular situation, which specifies safe or
permissible concentrations for various pollutants of
interest.  Comparison of these derived concentrations
with concentration levels anticipated for a particu-
lar source.
Theoretical.  Has been used in a preliminary way as
described in EPA report EPA-600/2-76-155 (Reference
3-6), but must be field and laboratory tested before
it will be of general applicability.
National Monitoring
Networks
Widely distributed networks of sampling stations where
physical, chemical, and biological samples are rou-
tinely collected for analysis are a part of the U.S.
Water Pollution Surveillance System, which includes
STORET retrieval.  Other surveillance networks mon-
itoring air chemistry, pesticide, and other chem-
icals in soils, water, and vegetation.
State of the art.  Such networks generally monitor
ambient conditions and trends and compare values to
standards and guidelines so enforcement or other
corrective actions can be rapidly taken.  In the
process, huge quantities of data on ambient chemical
concentrations in various substrata are obtained,
organized, and stored In computer-retrievable fash-
ion, available for use by the public.  The magni-
tudes of the various national network monitoring pro-
grams make their data useful for an initial screening
of potential pollution problems caused by incremental
 additions from contemplated action.

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                                          TABLE 3-3    METHODS  OF ASSESSING POLLUTANT  IMPACTS UPON AQUATIC AND TERRESTRIAL SYSTEMS
                                                      PART B.   EXPERIMENTAL ESTABLISHMENT OF IMPACT CONCENTRATIONS
                     Method
                                                             Description
                                                                        Comments on Suitability
             Short-term Static
Standard tests to determine the concentration level
of a pollutant which will  kill  50 percent of the ex-
perimental subjects during a specific exposure period
(the LCijo, or lethal concentration for 50 percent of
the individuals).  Toxicity curves are constructed
from experimental results  to allow mortality predict-
ing at various concentrations and exposure times and
determination of toxicity  thresholds.  It is impor-
tant to recognize that a wide variety of special  bio-
assy techniques and associated  hypotheses are used.
State of the art.   Is routinely  employed to test
toxicity of chemicals; the bulk  of  information which
would be available  for individuals  taking the ap-
proaches identified in Part A has come  from this
method.  LC5Q concentrations are obviously well
above the level where impacts on organisms could
initially occur.  Must be applied to  a  great many
species and at all  life stages for  data to have wide-
spread utility, and must be interpreted with cogni-
zance that effects other than death (such as altered
reproduction and survivorship) can  be very important
to individuals, populations, and ecosystems.   Such
acute tests do not account for these  sublethal  ef-
fects.  Moreover, toxicities differ with water
quality and other conditions.
             Chronic Bioassy
INJ
in
Standard tests to determine the effects  of long  term
exposure to a chemical on growth, reproduction,  sur-
vival, avoidance behavior, swimming performance, etc.
Continuous monitoring of physiological and behavioral
responses, such as blood physiology, locomotion, feed-
ing activity, breathing rate (opercular  movement),etc.
permits detection of responses to pollutants  at  stress-
ing concentrations far below concentrations which re-
sult in death.  Chronic tests are employed to help es-
timate long-term safe concentrations.
State of the art.  Although not as widely  "proven"  or
accepted as short-term  (acute) tests,  is becoming in-
creasingly important. As  with acute bioassay  results,
one must be careful in  extrapolating results  from
toxicity experiments on one population of  a species
to other populations of the species inhabiting  dif-
ferent environments.  Because chronic bioassays re-
quire such long experimental periods,  it has  been
customary to estimate long-term safe concentrations
by using acute bioassays  in combination with  applica-
tion factor derivations.
             Fumigation Experiments
Standard tests to determine the concentration  levels
of gaseous pollutants which will  cause chlorosis,
necrosis, or other visible symptoms of damage  to ter-
restrial plants.  Single pollutants or mixtures of
different pollutants can be introduced into  the
fumigation chambers to test interactive phenomena.
Histological and/or physiological  examinations can
be made of experimental subjects  to detect nonvisible
responses to pollutants.
State of the art.  Results are not readily extra-
polatable from area to area, since changes in rela-
tive humidity, soil moisture, temperature, etc. in-
fluence the susceptibility of plant individuals to
airborne pollutants.  Fumigation experiments are be-
ing conducted to a lesser extent on animals as well.
             Bioaccumulation
             Experiments
Tests to determine transfer and accumulation of  chem-
icals in different ecosystem compartments  (e.g., sub-
strate to producers to primary consumers to secondary
consumers to tertiary consumers) through monitoring
the concentration of a known quantity of a chemical
introduced into the test medium, in  various links  in
a single food chain.
Experimental.   Such tests have not been widely em-
ployed.  They  are useful  in identifying indicator
species which  magnify the substance of interest, so
that their indicators can be utilized in site-spec-
ific field situations to  biomonitor pollution
levels.

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                                         TABLE 3-3.  METHODS OF ASSESSING POLLUTANT IMPACTS UPON  AQUATIC AND TERRESTRIAL SYSTEMS
                                                     PART C.  SITE-SPECIFIC TECHNIQUES
                     Method
                      Description
              Comments on Suitability
                                                                                                                                                         CT>
                                                                                                                                                         00
             Elemental and Compound
             Analyses
 Analyze  air, water, and soil media, and tissues or
 whole  organisms of selected species by screening
 methods  (spark source mass spectrometry, atomic
 fluorescence spectrophotometry, anodic voltametry,
 etc.), and element or compound-specific methods
 (atomic  absorption spectroscopy, flameless atomic
 absorption spectrophotometry, thin-layer and gas
 chromatography, etc.), to determine levels of vari-
 ous pollutants in abiotic and biotic compartments
 of the site ecosystem.  Compare values with those
 in literature to determine potential problems.
State of the art.
             Effluent Bioassay
Conduct controlled, long-term bioassays in situ
or using mobile laboratories stationed close to
effluent location, to determine effects of efflu-
ent on aquatic organisms selected for their known
susceptibility to pollutants at specific concentra-
tions.  Generally, all life stages of the test or-
ganism are tested.
State of the art.  This methodology Is expected to
become much more widely used by agencies and indus-
try in the future.
ro

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                                                                 TABLE 3-3.  Concluded
                                                                             PART C.  Concluded
Method
Stress Determinations
by Color Imagery
Monitoring Physiological
Processes
Monitoring Histological
Characters
Indicator Species
Modeling
Description
Use of color and color infrared aerial imagery in
conjunction with ground-truthing to identify stress
signatures and to determine extent and intensity of
pollution damage to crop and woodland species.
Measurement of stress caused by pollutants can po-
tentially be conducted by collecting test subjects
living in treatment and control sites and examining
them for abnormal physiological function. General
adaptation syndrome, immune response, biochemical
reactions, and other physiological processes are
thought to provide stress signatures of sufficiently
high resolution so as to document chronic stress
damage long before demographic changes or shifts
in species composition will be evidenced from pol-
lution challenge.
Approach and rationale similar to that described for
physiological, but applied to lung tissue, adrenal
glands, gills, etc.
Monitoring abundance, biomass, distribution, behavior,
etc. of species known to react in predictable ways to
pollutants.
Use of ecosystem level models to describe and predict
effects of pollution challenge; to segregate pollu-
tant effects from natural variations occurring within
the site ecosystem.
Comments on Suitability
Experimental to state of the art. Permits rapid as-
sessment of major pollution damage to vegetation in
vicinity of operational facility. Can also serve to
identify areas of vegetation stress over broad
regions.
Theoretical and experimental . Warrants considerable
future effort, because of the presumed sensitivity
and resolution of such a monitoring approach. Is
presently being investigated at site of coal-fired
electric generating station in Montana. Use of fish
respirometers (etc.) to detect stress should be con-
sidered state of the art. Methodology, in broadest
application, can be applied to plants as well,
through measurement of formation, trans location,
action of auxins, or water stress, susceptibility
to nutrient stress, etc.
Experimental and state of the art. Has considerable
promise for detecting chronic damage in aquatic and
terrestrial organisms.
State of the art.
Theoretical and in early experimental phases. Re-
quires extensive information input from all eco-
system compartments so, until perfected, will be
costly and time-consuming.
Ul

ro

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           Also, included under "First Estimate" techniques are broad,  national monitoring networks
           which maintain periodic surveillance on levels of certain chemicals  in  various  substrata.
           Concentration values resulting from such networks can  identify  locations where  pollution
           levels exceed permissible standards and where more detailed  investigation  of  effects  is
           necessary.
       •   Experimental Establishment of Impact Concentrations.   Included  herein are  methods  appro-
           priate for experimentally establishing the concentrations at which specific chemicals
           will cause lethal or sublethal damage in sensitive species of aquatic and  terrestrial
           biota.  Results from these tests should be sufficiently general that they  could be used
           in the general information base and in publications and reports for future screening.
       •   Site-Specific Techniques.  These are methods to ascertain whether pollutants at a parti-
           cular site have affected local aquatic and terrestrial  ecosystems, or species within the
           ecosystems
       All extant techniques are limited.  For example, most approaches that have been used to test
 a specific chemical have failed to evaluate interactive phenomena  such as synergistic, additive, or
 antagonistic behaviors of associated chemicals in the effluent stream, as they relate to effects on
 organisms.  Potential ecotypic differences in tolerances to chemicals by populations of a species
 in different areas remain unexplored.   Assumptions that closely-related taxa have similar chemical
 tolerances to taxa used in test situations are questionable, yet are usually necessary because
 of the extremely limited number of different species  which have been investigated for pollution
 tolerance.  Pollutant effects on different life stages of a species are often overlooked and sub-
 lethal effects are largely undetermined.   Effects of  alternative culturing times/techniques on sus-
 ceptibility of test organisms and the capability of natural  (and cultured) populations to acquire
 resistance to particular pollutants in general remain unexplored.   Because of these and many other
 limitations of available methods, conventional experimental  techniques often yield data which have
 little value in assigning "safe" or permissible levels of toxicant emissions.
       Moreover, certain site-specific techniques are rather crude and cannot incorporate the controls
 necessary to establish causative relationships when damage is noted.  Because of these and other
problems,  data generated from the techniques identified in Table 3-3 are limited in utility.  However,
the acceleration of toxicant testing programs which incorporate subroutines to segregate some of
these problems will  result in better data.
                                                 3-28

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      The  current effort used only the very general first  estimate  procedures  to  set  the  limits
indicated 1n  Section 3.3; these limits will be further refined  as  the  program progresses.  Much
basic data  on the incremental effects of NOX controls on the biota will be  collected in the bioassay
testing  to  be conducted in the future under this program.

3.3    CONCENTRATION ESTIMATES FOR SCREENING COMBUSTION RELATED POLLUTANTS
       Using the methods described previously  (and recognizing  the limitations  of  these methods),
preliminary screening concentrations were generated for those pollutants from Table 3-1 for which the
supporting information could be obtained or estimated.  These results  are presented in Table 3-4
for human health effects and in Table 3-5 for  effects on terrestrial and aquatic biota.  These data
will be used elsewhere in this report (Section 7) for preliminary  screening and priority setting.
The data presented herein will be reviewed under both the impact assessment and test data  collection
tasks of the NO  environmental assessment program.  The results will be revised, whenever  new infor-
mation requires.  The presentation of only the calculated levels herein does not reflect the large
volume of data on health effects which has been collected and reviewed.
       The concentration values presented in Table 3-4 (except  when  an ambient  air standard existed
and could be used instead) were generated according to the  RTI  method  presented in Section 3.2.  The
levels to be used for screening were generated from the occupational threshold  limit value (whenever
one existed for the species) by the equation
                                        x = 1.65 • 10-8 (TLV)

using the 8-hour time-weighted average (TWA) TLV.  In cases where  a  TLV was unavailable, concentra-
tions were estimated from LDBOs by the equation
                                       x = 4.77  • 10'5  (LD50)
Oral LD50 values for rats were preferred, followed by oral  LD50 data for mice,  and intraperitoneal
and subcutaneous LD50s.  In a few cases, TDLo  (lowest published toxic  dose) and LDLo (lowest published
 lethal dose) were used.
       Although the RTI formulae have been discussed previously, it  should  be repeated that these
estimates are, at best, a rough approximation.   Rather than the specific concentration derived from
these calculations, the general order of magnitude  (1 ppm,  10"1  ppm, 10"2 ppm,  etc.) should be
regarded as the result of such estimation.  Two  comments made in Section 3.2 should be considered
carefully in making use of the results in Table  3-4.
                                                  3-29

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TABLE 3-4.   ESTIMATION OF CONCENTRATIONS FOR SCREENING COMBUSTION-GENERATED POLLUTANTS

    Recommended Occupational TLV
    NIOSH       ACSIH        ACGIH
Substance
ORGAN I CS
methane
ethane
propane
n-butane
ethyl ene
propylene
butyl ene
1,3-buta-
diene
acetylene
methyl
acetylene
cyclohexane
cyclohexene
formal de-
dehyde
acetalde-
hyde
butyral-
dehyde
crotonal-
dehyde
acrolein
acetone
methyl
ethyl
ketone
cyclo-
hexanone
(Ref. 3-7)
8-hr TWA
ppm ,
(mg/uf)

b
b
b
b
b
b
b
b
2,500
(2,662)
b
b
b
b
b
b
b
b
b
b
b
(Ref. 3-8)
8-hr TWA
ppm ,
(mq/m3)

b
b
b
600
(1,400)
b
b
b
1,000
(2,200)
b
1,000
(1,650)
300
(1,050)
300
(1,015)
2
(3)
100
(180)
b
2
(6)
0.1
(0.25)
1,000
(2,400)
200
(590)
50
(200)
(Ref. 3-8)
15-mln STEL
ppm ,
(mq/in

b
b
b
.750
(1,610)
b
b
b
1,250
(2,750)
b
1,250
(2,060)
375
(1,300)
300
(1,015)
2
(3)
150
(270)
b
6
(18)
0.3
(0.75)
1,250
(3,000)
250
(740)
50
(200)
Estimated
Cone.
ppm,

-------
                                   TABLE 3-4.   Continued
Recommended Occupational TLV
Substance
ORGAN I CS
methanol
ethanol
propanol
ethyl ene
glycol-
vapor
parti cul ate
dimethyl
ether
diethyl
ether
ethyl ene
oxide
formic
acid
acetic
acid1
propionic
acid
formates :
ethyl
formate
methyl
formate
acetates:
ethyl
acetate
methyl
acetate
n-propyl
acetate
isopropyl
acetate
n -butyl
acetate
sec-
butyl
acetate
tert-
butyl
acetate
NIOSH
8-hr TWA
ppm ,
(mg/mj)

200
(262)
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
ACGIH
8-hr TWA
ppm ,
(mg/m }

200
(260)
1,000
(1,900)
200
(500)
100
(260)
(10)
b
400
(1,200)
50
(90)
5
(9)
10
(25)
b
100
(300)
TOO
(250)
400
(1,400)
200
(610)
200
(840)
250
(950)
150
(710)
200
(950)
200
(950)
ACGIH
!5-m1n STEL
ppm ,
(mg/m )

250
(310)
1,000
(1,900)
250
(625)
125
(325)
(20)
b
500
(1,500)
75
(135)
5
(9)
15
(37)
b
150
(450)
150
(375)
400
(1,400)
250
(760)
250
(1,050)
310
(1,185)
200
(950)
250
(1,190)
250
(1,190)
Estimated
Cone.
ppm,
(mq/m )

0.33
(0.43)
1.67
(3.14)
0.34
(0.83)
0.16
(0.43)
(0.02)
-
0.65
(1.98) v
0.08
(0.15)
0.008
(0.01)
0.02
(0.04)
(0.07)
0.16
(0.49)
0.16
(0-41)
0.64
(2.31)
0.33
(1.01)
0.33
(1.39)
0.38
(1.57)
0.25
(1.17)
0.33
(1.57)
0.33
(1.57)
Justification for Estimate

x • 1.65 x 10'3 (262).
x - 1.65 x 10'3 (1900).
x • 1.65 x 10'3 (500).
x = 1.65 x 10~3 (260).
x = 1.65 x 10"3 (10).
Non-toxic within estimated range of
emissions.
x = 1.65 x 10"3 (1200).
x = 1.65 x 10"3 (90).
x = 1.65 x 10~3 (9).
x = 1.65 x 10"3 (25).
Oral LD50, rat: 1510 ma/kn
x ซ 4.77 x 10'5 (1510).
x = 1.65 x 10"3 (300).
x * 1.65 x 10"3 (250).
x = 1.65 x 10'"3 (1400).
x = 1.65 x 10'3 (610).
x - 1.65 x 10'3 (840).
x = 1.65 x 10~3 (950).
x = 1.65 x 10'3 (710).
x • 1.65 x 10"3 (950).
x = 1.65 x 10'3 (950).
References

3-6
3-6
3-6
3-6
3-6
-
3-6
3-6
3-6
3-6
3-6, 3-9
3-6
3-6
3-6
3-6
3-6
3-6
3-6
3-6
3-6
                                   3-31

-------
                                   TABLE 3-4.  Continued
Recommended Occupational  TLV
Substance
ORGAN ICS
Isobutyl
acetate
propionates:
methyl
propionate
ethyl
propionate
acetic
anhydride
maleic
anhydride
succinic
anhydride
peroxyacetic
acid
benzene


toluene








ethyl
benzene
cumene
styrene
cresol
vinyl-
toluene
p-t-butyl
toluene
NIOSH ACGIH
8-hr TWA 8-hr TWA
ppm , ppm ,
(mq/m ) (mq/m )

b


b
b
b

b

b

b
1
(3.2)
(See
ref. 3-11)
100
(375)
8-hr
TWA
200
(750)
10-
min.
ceil-
ing
b
b
b
b
b
b

150
(700)

b
b
5
(20)
0.25
(1)
b"

b
10
(32)

100
(375)








100
(435)
50
(245)
100
(420)
(22)
100
(480)
10
(60)
ACGIH
15-mln STEL
ppm ,
(mq/m )

187
(875)

b
b
5
(20)
0.25
(1)
b

b
25
(80)

150
(560)








125
(545)
75
(365)
125
(525)
5
(22)
150
(720)
20
(120)
Estimated
Cone.
ppm,
(mq/m )

0.24
(1.16)

0.03
(0.12)
0.04
(0.17)
0.01
(0.03)
0.0004
(0.002)
_
(0.124)
(0.073)
_
(lng/n,3)

0.16
(0.62)








0.16
(0.72)
0.08
(0.4)
0.16
(0.69)
0.01
(0.04)
0.16
(0.79)
0.02
(0.1)
Justification for Estimate

x = 1.65 x 10'3 (700).


Oral LDLo, rabbit: 2550 mg/kg;
x • 4.77 x lO-5 (2550).
Oral LD50, rat: 3500 mq/ka
x • 4.77 x 10-5 (3500).
x = 1.65 x 10"3 (20).

x = 1.65 x in"3 (1).

Subcutaneous TDLo, rat;K2600 mq/ka/65
weeks; x ซ 4.77 x 10"s (2600).
Oral LD50, rat: 1540 mq/ka-
X • 4.77 x 10"5 (1540).
Suspected carcinoaen.


x = 1.65 x 10"3 (375).








x = 1.65 x 10~3 (435).
x = 1.65 x 10"3 (245).
x = 1.65 x 10"3 (420).
x = 1.65 x 10"3 (22).
x = 1.65 x TO"3 (480).
x • 1.65 x 10"3 (60).
References

3-6


3-6, 3-9
3-6, 3-9
3-6

3-6

3-6, 3-9

3-6, 3-9
3-6,
3-10, 3-11

3-6








3-6
3-6
3-6
3-6
3-6
3-6
                                    3-32

-------
                                   TABLE 3-4.   Continued
Recommended Occupational TLV
NIOSH
8-hr TWA
ppm 3
Substance (mq/m )
ORGANICS
nltro-
anillne
naphtha-
lene
blphenyl

PCB's
(as chloro-
diphenyl)
42% chlorine

54% chlorine

anthracene

phenanthrene

fluoran-
thene
pyrene

benzo(a)-
pyrene
benzo(e)-
pyrene
perylene

anthanth-
rene
benzo(ghi)-
perylene
coronene

b

b
b




b

b

b

b

b

b

b

b

b

b

b
b
ACGIH
8-hr TWA
PPm 3
(mg/m )

1
(6)
10
(50)
0.2
(1)



-
(1)
.
(0.5)
b

b

b

b

b

b

b

b

b
b
ACGIH
15-nln STEL
ppm 3
(mq/m )

2
(12)
15
(75)
0.2
0)



-
(1)
-
(0.5)
b

b

b

b

b

b

b

b

b
b
Estimated
Cone.
ppm,
(mn/m )

0.002
(0.01)
(lng/m3)
0.0003
(0.002)



-
(lng/m3)
•
(lng/m3)
_
(lng/m3)
_
(0.03)
_
(0.09)
_
(lng/n3)
.
(lng/n3)
_
(lng/m3)
.
(lng/m3)
^

-
_
Justification for Fstim.te

x - 1.65 x 10"3 (6).

Suspected carcinogen.
x •= 1.65 x 10'3 (1).




Suspected carcinoaen.

Suspected carcinoaen.

Suspected carcinooen.

Oral LD50, mice: 700 mci/kn
x ' 4.77 x lO-5 (700).
Oral LD50, rat: 2000 mo/kq
x =• 4.77 x 10'5 (2000)
Suspected carcinoaen.

Suspected carcinogen.

Suspected carcinogen.

By analogy with naphthalene.

Insufficient toxicologic information
to estimate an exposure.
Insufficient toxicologic Information
to estimate an exposure.
Insufficient toxicologic Information
References

3-6

3-6, 3-10
3-6




3-6, 3-10

3-6, 3-10

3-6, 3-10

3-6, 3-9

3-6, 3-9

3-6, 3-10

3-6, 3-10

3-6, 3-10







                                    3-33

-------
TABLE 3-4.  Continued
NAAOS
(Ref. 3-12)
Cone.
ppm.
Substance (mg/m )
GASES AND
PARTICULATES
carbonates
ammonium a
carbonate
ammonium a
bicarbonate
potassium a
carbonate
carbonyls
nickel a
carbonyl
iron penta- a
carbonyl
carbon a
(elemental )
carbides
calcium a
carbide
iron a
carbide
silicon a
carbide
tungsten a
carbide
nitric acid a
nitrates a
nitrites a
cyanides
hydrogen a
cyanide
metallic a
cyanides
ammonia a
cyanates a
Recommended Occupational TLV
NIOSH ACGIH AC6IH
8-hr TWA 8-hr TWA 15-mln STEL
pom , ppm , ppm ,
(mg/mj) (mg/m ) (mg/nr)


b
b
b

b
b
b

b
b
b
b
2
(5)
b
b

b
b
50
b


b
b
.b

0.05
(0.35)
0.01
(0.08)
(3^5)

b
(i)
(10)
(5)
2
(5)
b
b

10
(11)
b
25
(18)
b


b
b
b

0.05
(0.35)
0.01
(0.08)
(7)

b
(2)
(20)
(10)
4
(10)
b
b

15
(16)
b
35
(27)
b
Estimated
Cone.
ppm.
(mq/mj)


(0.004)
(0.012)
(0.09)

(1 ng/m3)
0.02 ppb
(0.0001)
(0.006)


(0.002)
(0.02)
(0.008)
0.003
(0.008)
(0.008)
(0.008)

0.016
(0.018)
0.016
0.06
(0.04)
0.016
Justification for Estimate References


intravenous LD 50, mice: 96 nig/kg;
x * 4.77 x 10-5 (96)
Intravenous LD 50, mice: 245 rag/kg;
x - 4.77 x 10-5 (245)
Oral LD 50, rat: 1870 mg/kg;
x = 4.77 x ID"5 (1870)

Suspected carcinogen .
x = 1.65 x 10"3 (0.08)
x - 1.65 x 10"3 (3.5)

By analogy to calcium hydroxide,
calcium carbide is non-toxic with-
in range of estimated emissions.
TLV for soluble iron salts;
x = 1.65 x 10'3 (j)
TLV for nuisance particulates;
x ป 1.65 x ID'3 (10)
TLV for insoluble tungsten compounds
x = 1.65 x ID'3 (5)
x = 1.65 x 10"3 (5)
By analogy to nitric acid.
By analogy to nitric acid.

x = 1.65 x 10"3 (11)
By analogy to hydrogen cyanide.
x * 1.65 x 10"3 (25)
By analoav to hvdrnopn cvanidp.


3-6, 3-9
3-6, 3-9
3-6, 3-9

3-6, 3-10
3-6
3-6


3-6
3-6
; 3-6
3-6



3-6

3-6

  3-34

-------
NAAQS
                      .TABLE 3-4.  Continued
Rtconnended Occupational TLV
Cone.
ppm.
Substance (mg/iO
GASES AND
PARTICULATES
amines, Imines,
1m1des
methyl ami ne a
ethyl ami ne a
ethyl ene- a
dlamine
dl ethyl- a
ami'ne
cyclohexyl- a
amine
aniline a

m'trlles a
nitro compounds
nltro- a
methane
2-nitro- a
propane
nltro- a
benzene
amides
acetamlde a

formamide a

azo compounds
azobenzene a

azoxy compounds
azoxybenzene a
sulfurlc add a

ammonium a
sulfate
metallic a
sul fates
NIOSH
8-hr TWA
ppm ,
,
(1 ug/mj)
0.033
(0.050)

1 3>
(1 ng/m3)

- 3
(1 ng/m )
(0.002)
(0.003)
.
(0.002)
Justification for Estimate




x • 1.65 x 10"3 (12)
x • 1.65 x 10"3 (18)
x ซ 1.65 x 10"3 (25)

x • 1.65 x 10"3 (75)

x • 1.65 x 10"3 (40)

x •= 1.65 x 10"3 (19)

By analogy to hydrogen cyanide.

x - 1.65 x 10"3 (250)

x = 1.65 x 10"3 (90)

x •= 1.65 x 10"3 (5)


Suspected carcinogen.

x = 1.65 x 10"3 (30)


Suspected carcinogen.


Suspected carcinogen.
x • 1.65 x 10"3 (1)

Oral LD 50, rat:, 58 mg/kg;
x ซ 4.77 x 10"9 (58)
By analogy to sulfurlc acid.

References




3-6
3-6
3-6

3-6

3-6

3-6

3-6

3-6

3-6

3-6


3-10

3-6, 3-9


' 3-10


3-10
3-6

3-6, 3-9


                                     3-35

-------
TABLE 3-4.  Continued
NAAQS Recommended Occupational TLV
NIOSH ACGIH ACGIH Estimated
Cone. 8-hr TWA 8-hr TWA !5-m1n STEL Cone.
ppm, ppm , ppm , ppm- ppm.
Substance (mg/m ) (ng/m ) (nq/m ) (mq/m ) (mq/m )
GASES AND
PARTICIPATES
sulfurous a b
acid
metal He a b
sulfites
sul fides
carbon a b
dlsulfide
hydrogen a b
sulfide
carbonyl a b
sulfide
metallic
thiosulfates
calcium a b
thiosulfate
magnesium a b
thiosulfate
elemental a b
sulfur
mercaptans
ethyl a b
mercaptan
sulfoxides
methyl a b
su If oxide
thiocyanates
ammonium a b
thiocyanate
potassium a b
thiocyanate
sodium a b
thiocyanate
sulfur 0.03 2
dioxide (0.08) (5)
annual arithmetic
mean
0.14
(0.365)
24-hour annual
maximum

b
b
20
(60)
10
(15)
b

b
b
(10)
0.5
(1)

b

b
b
b
5
(13)


b
b
30
(90)
15
(27)
b

b
b
b
0.5
(1)

b

b
b
b
5
(13)


(0.027)
(0.027)
0.032
(0.099)
0.016
(0.025)
0.016
(0.041)

(0.027)
(0.038)
(0.016)
0.0008
(0.0016)

(0.001)

(0.024)
(0.041)
(0.036)
0.03
(0.08)
0.14
(0.365)
Justification for Estimate References

By analogy to sulfur dioxide, with
allowance for differences In
molecular weight.
By analogy to sulfur dioxide, with
allowance for differences In
molecular weight.
x * 1.65 x 10"3 (60)
x = 1.65 x 10"3 (15)
By analogy to hydrogen sulfide.

intraperitoneal LDLo, rat: 573 mg/kg;
x = 4.77 x TO'5 (573)



3-6
3-6


3-6,
3-9
Intraperitoneal LDLo, rat: 805 mg/kg; 3-6,
x = 4.77 x 10"5 (805) 3-9
TLV for nuisance dusts;
x = 1.65 x 10'3 (10)
x = 1.65 x 10"3 (1)

Oral LD 50, rat: 20mg/kg;
x = 4.77 x ID'5 (20)

Intraperitoneal LDLo, mice: 500 mg/kg
x = 4.77 x 10"5 (500)
Oral LD 50, rat: 854 mg/kg;
x = 4.77 x 10'5 (854)
Oral LD 50, rat: 764 mg/kg;
x * 4.77 x 10"5 (764)
Annual arithmetic mean, federal
air quality standard.
24-hour maximum not to be exceeded
more than once per year, federal
air quality standard.
3-6
3-6

3-6, 3-9

3-6,
3-9
3-6,
3-9
3-6,
3-9
3-12
3-12
 3-36

-------
NAAQS
                      TABLE 3-4.  Continued
Recommended Occupational TLV
Cone.
ppm.
Substance (mg/m )
GASES AND
PARTICIPATES
sul fur a
tH oxide
carbon 9
monoxide (10)
8-hour annual
maximum
35
(40)
1-hour annual
maximum
nitric a
oxide
nitrogen 0.05
dioxide (0.1)
NIOSH
8-hr TWA
ppm 3
(ma/mj)


b
35
(38)

200 (ceiling)
(220)


25
(30)
1
(1.8)
ACGIH
8-hr TWA
,PP"> 3
.._0n.q/m )


b
50
(55)




25
(30)
5
(9)
ACGIH
lS-ra1n STEL
ppm,
(irw/m3)


b
400
(440)




35
(45)
5
(9)
annual arithmetic
mean
carbon a
dioxide
30

phosphorus a
pentoxide
phosphorous a
sesquioxide
elemental a
oxygen
ozone 0.08
(0.16)
1-hour annual
maximum
metallic a
phosphates
metallic a
hydrides
elemental a
hydrogen
selenium a
compounds
hydrogen a
chloride
potassium a
chloride
sodium a
chloride

10,000
(18,000)
,000 celling
(54,000)
b
b
b

b



b

b

b

b

b

b
b


5,000
(9,000)


b
b
b

0.1
(0.2)


b

b

b

.
(0.2)
5
(7)
b
b


15,000
(18,000)


b
b
b

0.3 .
(0.6)


b

b

b


(0.2)
5
(7)
b
b

Estimated
Cone.
, ppms
(tnq/m3)


(0.002)
9
10

35
(40)


0.04
(0.05)
0.05
(0.1)


8.25
(14.85)


(0.002)
(0.0002)


0.08
(0.16)








_
(0.0003)
0.008
(0.012)
(0?12)
.
(0.14)
Justification for Estimate References


By analogy to sulfuric acid
8-hour maximum, not to be exceeded 3-12
more than once per yซr, federal
ambient air standard.

1-hour maximum, not to be exceeded 3-12
more than once per year, federal
ambient air standard.

x - 1.65 x 10"3 (30) 3-6

Annual arithmetic mean, federal 3-12
ambient air standard.


x - 1.65 x 10"3 (9,000) 3-6



By analogy with phosphoric acid; , 3-6
(TLV Of 1 mg/m3); x •= 1.65 x 10"J(1)
By analogy with PjOi;; fy^e ^s
approximately 10 times more toxic.
Non-toxic within estimated range of
emissions.
Annual 1-hour maximum, not to be 3-12
exceeded more than once per year;
NAAQS for photochemical oxidants-

Non-toxic within estimated range of
emissions.
Non-toxic within estimated range of
emissions.
Non-toxic within estimated range of
emissions.
x - 1.65 x 10"3 (.2); (as Se) 3-6

x ซ 1.65 x 10"3 (7) 3-6

IntrapeHtoneal LDLo, rat: 2430 mg/kg; 3-6, 3-9
x • 4.77 x 10"5 (2430)
Oral LD 50, rat: 3000 mg/kg; 3-6, 3-9
x • 4.77 x ID'5 (3000)
                                     3-37

-------
               NAAQS
                      TABLE  3-4.   Continued

Recommended Occupational  TLV
NIOSH
Cone. 8-hr TWA
ppm , ppm 3
Substance (nq/m ) (mg/m )
GASES AND
PARTICIPATES
hydrogen a b
bromide
potassium a b
bromide
sodium a b
bromide
hydorgen a b
fluoride
potassium a b
fluoride
sodium a b
fluoride
hydrogen a b
iodide
potassium a b
Iodide
sodium a b
iodide
total 0.24 b
ACGIH
8-hr TWA
ppm ,
(mq/m )

3
(10)
b
b
3
(2)
b
b
b
b
b
b
ACGIH . Estimated
15-raln STEL Cone.
ppm. pprc^
(mqV) (ma/nr)

(10)
b
b
3
(2)
b
b
b
b
b
b

0.005
(0.016)
0.0002
(0.001)
(0.167)
0.005
(0.003)
(0.012)
(0.009)
0.005
(0.016)
(0.089)
(0.207)

Justification for Estimate References

x - 1.65 x 10'3 (10)
Ry analogy with bromide (TLV of ,
0.1 ppm, 0.7mg/m3); x ซ 1.65 x 10
(0.7)
Oral LD 50, rat:3500 ma/kg;
x = 4.77 x ID'5 (3500)
x = 1.65 x 10"3 (2)
Oral LD 50, rat:cZ45 rag/kg;
x = 4.77 x 10"5 (245)
Oral LD 50, rat: 180 mg/kg;
x = 4.77 x 10-5 (180)
By analogy with hydrogen bromide.
Oral LDLo, mice: 1862;
x = 4.77 x 10-5 (1862)
Oral LD 50, rat: 4340 mg/kg;
x = 4.77 x 10-5 (4340)
NAAQS for hydrocarbons selected for

3-6
3-6
3-6, 3-9
3-6
3-6, 3-9
3-6, 3-9

3-6, 3-9
3-6, 3-9
3-13
hydrocarbons  (0.16)
            3-hour (6-9am)
            annual maximum

total
particulate    (0.26)
            24-hour annual
              maximum
              (0.075)
            1-year geometric
               mean
                                               achievement of NAAQS for  photochem-
                                               ical oxidants, health effects not
                                               observed at these  levels-

                                             24-hour maximum, not to be  exceeded     3-12
                                    (0.26)      more than once per year,  federal
                                               ambient air standard.
                                             Annual geometric mean,federal           3-12
                                   (0.075)      ambient air standard.
                                                  3-38

-------
TABLE 3-4.  Continued
Recommended
Occupations! TLV
ACGIH ACGIH
8-hr TWA 15 mln STEL
Substance (mq/m3) (mq/m3)
ELEMENTS
aluminum 10 10
(as A1203)
antimony 0.5 0.75
compounds
(as Sb2)
arsenic 0.5 0.5
barium, 0.5 0.5
soluble
compounds
beryllium 0.002 0.025
bismuth b b
boron oxide 10 20
cadmium
oxide 0.05 0.05
fume,
as Cd
salts, 0.05 0.15
as Cd
calcium 5 5
oxide
cerium b b
cesium b b
chromium b b
insoluble
forms
chromic 0.1 0.1
acid and
chromates,
as Cr03
soluble 0.5 0.5
salts, as
Cr
cobalt 0.1 0.1
copper 1 2
dysprosium b b
Estimated
Cone,
(mq/m3)

0.0165
0.825
uo/m3
0.825
uq/tn3
0.825
ua/m3
3.3,
na/m
0.016
0.0165
82.5,
ng/m
82.5,
ng/m
O.OD825
0.0026
0.0033
1 ,
ng/m
0.165
ug/m3
0.825
ug/m3
0.165
ug/m3
1.653
uq/m
0.003
	 	 ... , Justification for Estimate

TLV for nuisance dusts: x ซ 1 65 x IT3 (10) .
x • 1.65 x 10'3 (0.5).
x = 1.65 x 1C"3 (0.5).
x * 1.65 x 10'3 (0.5).
x = 1.65 x 10~3 (0.002).
Based on TLV for bismuth telluride; x * 1 ซ5 x
10-3 (10).
x * 1.65 x 10'3 (10).
x = 1.65 x 10~3 (0.05)
x = 1.65 x 10"3 (0.05).
x = 1.65 x 10"3 (5).
Member of lanthanide series-, by analoqy to yttrium
with corrections for difference in atomic weiqht.
'Based on TLV for cesium hydroxide; x = 1.65
x ID'3 (2).
Suspected carcinoqen.
x * 1.65 x 10'3 (n.l)
x = 1 65 x 10"3 (0.5).
x * 1 65 x 10'3 (0.1).
x - 1.65 x TO"3 (1).
Member of lanthanide series; by analony to yttrium
Jtefere
3-6
3-6
3-6
3-6
3-6
3-6,
3-6
3-6
3-6
3-6

3-6,
3-6
3-6
3-6
3-6
3-6

nccs






3-8





3-B





 3-39

-------
TABLE 3-4.   Continued
Recommended
Occupational TLV
ACGIH ACGIH
8-hr TWA 15-mln STEL
Substance (mo/m3) (mq/m3)
ELEMENTS
erbium b b
europi urn b b
gadolinium b b
gallium b b
germanium b b
gold b b
hafnium 0.5 1.5
hoi mi urn b b
iridium b b
iron 5 10
oxide
iron 1 2
soluble
salts,
as Fe
lanthanum b b
lead 0.15 0.45
arsenate,
as Pb
lead; 0.15 0.45
inoraanic,
as Pb
lithium b b
lutetium b b
manganese 5 5
and com-
pounds ,
as Mn
magnesium 10 10
oxide
fume
Estimated
Cone.
(mq/m3)

0.0031
0.0028
0.0029
0.0052
0.001
-
0.0008
0.003
3.2
ng/m3
0.00825
1.65,
un/m
0.0026
0.2475
ug/m3
0.2475
ug/m3
0.017
0.0032
0.00825
0.0165
Justification for Estimate

Member of lanthanide series;by analooy to
yttrium with correction for difference 1n atomic
weinht.
Member of lanthanide series; by analony to
yttrium with correction for difference 1n atomic
weight.
Member of lanthanide series by analogy to
yttrium with correction for difference in atomic
weioht.
Subcutaneous LDLo, rat' 110 mq/kg; x • 4.77 x
10-5 (110).
Based on TLV for germanium tetrahydridej x =1.65
x 10-3 (0.6).
Non-toxic within range of estimated emissions.
x = 1.65 x ID"3 (0.5).
Member of lanthanide series; by analony to
yttrium with correction for difference 1n atomic
weight.
Member of platinum group? by analogy to platinum
with correction for difference in atomic weioht.
x = 1.65 x 10"3 (5).
x = 1 65 x 10"3 (1)
Member of lanthanide series; by analogy to
yttrium with correction for difference in
atomic weight.
x = 1.65 x 10'3 (0.15)
x = 1.65 x 10"3 (0.15).
Intraperitoneal LDLo, rat: 360 ma/krj; x = 4 77
x 10-5 (360). '
Member of lanthanide series ; by analooy to
yttrium with correction for difference in atomic
weioht.
x = 1.65 x 10'3 (5)
x = 1.65 x 10'3 (10).
                                                              References  >L
                                                                3-6, 3-9





                                                                3-6, 3-8









                                                                3-6
                                                                3-6
                                                                3-6
                                                                3-6
                                                                3-6
                                                                3-6,  3-9
                                                                3-6
                                                                3-6
3-40

-------
TABLE 3-4.  Continued
Substance
ELEMENTS
mercury
all forms,
as Hg
tlkyl
compounds ,
is Hg
molybdenum,
as Mo
Insoluble
compounds
soluble
compounds
neodymi urn
nickel,
soluble
compounds ,
as Ni
niobium
osmium
palladium
platinum
potassium
praseo-
dymi urn
rhenium
rhodium
rubidium
ruthenium
samarium
scandium
selenium
compounds ,
as Se
Recommended
Occupational TLV
ACGIH ACGIH
8-hr TWA 15-mln STEL
iiHQ/nv^) (ntQ/tn^i

0.05 0.15
0.01 0.03
10 20
5 10
b b
0.1 0.3
b b
0.002 0.006
b b
0.002 0.002
b b
b b
b b
0.1 0.3
b b
b b
b b
b b
0.2 0.2
Estimated
Cone

82.5,
ng/m
16.5,
ng/m
0.0165
0.00825
0.0027
0.165
ug/m3
0.143
3.3
1.8
ng/mj
3.3
ng/m3
-
0.0026
0.013
0.165
ng/m3
0.21
1.7
ng/m3
0.0028
0.19\
0.33
ug/m
	 Justification for Es1;1nซtป 	 References

x - 1.65 x ID"3 (0.05) 3.6
x • 1.65 x 10'3 (0.01) 3_6
x • 1.65 x 10'3 (10) 3.6
x • 1.65 x 10"3 (5) 3-6
Member of lanthanide series; by analoqy to
yttrium with correction for difference in atomic
weight.
x • 1.65 x 10'3 (0.1). . 3-6
Oral LD50, rat, for potassium niobate: 3000 3-6, 3-9
mg/kg; x - 4.77 x ID'S (3000).
Based on TLV for osmium tetroxide, as Os; 3-6
x ' 1.65 x 10-3 (0.002).
Member of platinum group; by analogy to platinum
with correction for difference in atomic weight.
Based on TLV for platinum salts, as Pt; 3-6
x - 1.65 x 10-3 (0.002).
Non-toxic within estimated range of emissions.
Member of lanthanide series; by analogy to
yttrium with correction for difference in
atomic weight.
Intraperltoneal LD50, mice, for rhenium * 3-6, 3-9
trichloride: 280 mg/kg; x ซ 4.77 x 10ฐ (280).
x - 1.65 x 10'3 (0.1). 3-6
By analogy to lithium with correction for
difference 1n atomic weight.
Member of platinum group; by analogy to platinum
with correction for difference 1n atomic weight.
Member of lanthanide series, by analogy to
yttrium with correction for difference In atomic
weight.
Oral LD50, mice, for scandium trichloride: 3-6, 3-9
4000 mg/kg; x • 4.77 x 10"5 (4000).
x • 1.65 x 10"3 (0.2). 3-6
3-41

-------
TABLE 3-4.  Continued
Substance
ELEMENTS
silicon
silver
and
soluble
compounds ,
as Ag
sodium
strontium
tantalum
tellurium

terbium


thallium

thorium
thulium


tin
titanium,
as titanium
dioxide
tungsten
insoluble
soluble
uranium
compounds,
as U
vanadium
oxide, as V
dust
fume
ytterbium


yttrium
zinc chloride
fume
zinc oxide
fume
zirconium
Recommended
Occupational TLV
ACGIH ACGIH
8-hr TWA !5-n1n STEL
(mg/m3) (mq/m3)

10
0.01




b
b
5
0.1

b


0.1

b
b


2
10


5
1
0.2



0.5
0.05
b


1
1
5
5

20
0.03




b
b
10
0.1

b


0.1

b
b


4
20


10
3
0.6



1.5
0.05
b


3
2
10
10
Estimated
Cone,
(mq/m3)

0.0165
16.5,
ng/m



-
0.0433
0.008
0.165
ng/m3
0.0029


0.165
Jjg/m3
1 jig/m3
0.0031


0.0033
0.0165


0.0082
0.0016
0.33 ug/m3



0.825 ug/m3
82.5 ug/m3
0.0032


0.0016
1.65 ug/m3
0.00825
0.0082
8
Justification for Estimate References ^

TLV for nuisance partlculates; x ซ 1.65 x 3-6
10-3 (10).
x - 1.65 x 10"3 (0.01). 3-6




Non-toxic within estimated range of emissions.
IntrapeHtoneal LD50, mice, for strontium 3-6, 3-9
chloride: 908 mg/kg; x ซ 4.77 x 10-5 (908).
x = 1.65 x 10"3 (5). 3-6
x - 1.65 x 10'3 (0.1). 3-6

Member of lanthanide series; by analogy to
yttrium with correction for difference 1n atomic
weight.
TLV for soluble thallium salts (as Tl); 3-6
x ซ 1.65 x ID'3 (0.1).
Radioactive, suspected carcinogen. 3-6, 3-10
Member of lanthanide series; by analogy to
to yttrium with correction for difference 1n
atomic weight.
TLV for Inorganic tin compounds (as Sn); 3-6
x-- 1.65 x ID'3 (2)
TLV for nuisance particulates; x = 1.65 x 10"3 (10)3-6


x • 1.65 x 10'3 (5) 3-6
X = 1.65 x 10"3 (1) 3-6
x * 1.65 x 10"3 (0.2) 3-6.



x ซ 1.65 x 10'3 (0.5) 3-6
X = 1.65 x 10'3 (0.05) 3-6
member of lanthanide series; by analogy
to yttrium with correction for difference
1n atomic weight
x * 1.65 x 10'3 (1) 3-6
x = 1.65 x 10"3 (1) 3-6
x - 1.65 x 10"3 (5) 3-6
TLV for zirconium compounds (as Zr); 3-6
 3-42

-------
                               TABLE  3-4.  Continued
Recommended Occupational TLV
NiOSH
8-hr TWA
PP1",
Substance (mg/mj)
MISCELLANEOUS
SECONDARY
POLLUTANTS
peroxyacetyl- b
nitrate

nitrocarboxylic
acids
m-nitrobenzolc b
acid
p-nitrobenzoic b
acid
cyclic
aldehydes
fufural b

phenol b

dicarboxylic
acids
oxalic b
acid
malonic b
acid
nitrobenzene b

hydroperoxides
t-butyl b
hydroperoxide
hydrogen b
peroxide
quinone b

carbonaceous b
particulate
matter
nitrosamines b

ACGIH
8-hr TWA
PPm,
(M/ซ|3)


b




b
b


5
(20)
5
(19)


_
(1)
b
1
(5)

b
1
(1.4)
0.1
(0.4)
b

b

ACGIH
15-mln STEL
ppm
(mq/m3)


b




b
b


15
(60)
10
(38)


_
(2)
b
2
(10)

b
2
(2.8)
0.3
(0.1)
b

b

Estimated
Cone.
(mq/m3)


0.08
-



(0.032)
(0.093)


0.008
(0.033)
0.008
(0.031)
*

_
(0.0016)
(0.062)
.
(0.008)

(0.019)
0.0016
(0.0023)
0.00016
(0.00066)
(0.016)

_
1 ug/m3
8
Justification for Estimate References *-


Annual 1-hour maximum, not to be
exceeded more than once per year;
NAAQS for photochemical oxidants.


Intraperitoneal LD50, rat: 670 mg/kg;
x * 4.77 x 10"5 (670)..
Oral LD50. rat: 1960 mg/kg;
x - 4.77 x 10'5 (I960).


x - 1.65 x 10'3 (20)

x - 1.65 x 10'3 (19)



x - 1.65 x 10"3 (1)

Oral LD50, rat: 1310 mg/kg;
x - 4.77 x lO'5 (1310).
x =1.65 x ID'3 (5)


Oral LD50, rat: 406 mg/kg;
x ซ 4.77 x 10"5 (406).
x " 1.65 x lO'3 (1.4)

x ซ 1.65 x 10'3 (0.4)

TLV for nuisance-dusts;
x - 1.65 x 10'3 (10).

Suspected carcinogens.



3-12




3-6, 3-9
3-6, 3-9


3-6

3-6



3-6

3-6, 3-9
3-6


3-6, 3-9
3-6

3-6

3-6

3-6, 3-10

                                  3-43

-------
                           TABLE 3-4.  Concluded

Footnotes
  a        a National Ambient A1r Quality Standard does not exist for
           this substance
  b        an occupational standard does not exist for this substance

Abbreviations
  LDLo     lowest published lethal  dose
  NAAQS    National Ambient Air Quality Standard
  STEL     short-term exposure limit
  TLV      threshold limit value
  TWA      time-weighted average
  x        maximum permissible concentration for continuous exposure
o
01
                                   3-44

-------
TABLE 3-5.  ENVIRONMENTAL SIGNIFICANCE OF SOME  CHEMICALS THAT WAV EXIST  IN AIRBORNE, LIQUID, AND SOLID EFFLUENTS FROM STATIONARY COMBUSTION SOURCES
            PART A.   CARBON AND NONMETALLIC  COMPOUNDS I/
Element or
Chemical Class
Paraffins (alkanes)

Oleflns (alkenes)



Alkynes
Cyclic AHphatics
Aldehydes


Carboxylic Acids
Single Ring Aroma tics


Poly nuclear AroMtics

Carbonates



Carbonyls
Carbon
Nitrates
Nitrites
Atmonium Compounds

Organic N Compounds
cyanates
amines



nltriles
nitro compounds






Toxic
Aquatic 3/
(ppm)
10-100

10-100




<1
1-10


0.7
1-10


1.02-2.0

33



10-100

10-100
0.05
1-10


0.1
0.08



2







Levels 2/
Terrestrial 4/
(mg/kg) 5/
658

42



8
8
13.8


0.2
12


10

7



8
440
10-20 ppb
1
20 ppro


0.5 ppm
265



7
7






Synerglstlc Potential
or Other Interaction
Photo-oxidation with
NOX yields some PAN
Ozonated hexene causes
plant damage
When Irradiated, causes
plant damage
4
4
Synerglstlc with NO
and Irradiation In
causing plant damage
4
Synerglstlc with NO,
and Irradiation 1n
causing plant damage
Synerglstlc with ferric
oxide
Buffering action and
affect on pH may con-
tribute to toxlclty of
high pH
4
4
4
4
Anroonla Increases
rate of S02 oxidation

4
Quaternary amines
extract metal
cyanides from highly
alkaline solutions
4
Nitrosation of water
soluble pesticides
under acidic conditions
increases variety of N-
nitroso compounds
Formation of nitros-
amines enhanced by
thio-cvanate ion
Index of
Bioaccumulation
Potential
4

4



4
1
4


4
4


4

4



4
4
4
4

4

4
4



4
4






Index of
Impact
Aquatic
4

4



4
1
4


4
4


4

4



4
4
4
4

4

4
4



4
4






Biological
Potential 6/
Terrestrial
4

4



4
1
4


4
4


4

4



4
4
4
4

4

4
4



4
4






U.S. Occupational
Standards (mg/m3)
658 mg/kg

4



8 ng/kg
77 ng/kg
13.8 ppm


0.2 mg/kg
12


700





7 nig/kg
3.5 mg/kg

10 ppm



140
10 ppm



0.05 ppm
2






References
3-14,15

3-14,16,17



3-14
3-14
3-14,18,19


3-14,20
3-14,18


'3-14,19,21

3-14,19,20



3-14
3-14
3-14
3-14,20,22

3-14,19,23

3-14,20
3-14,20,24



3-14,19
3-14,18,25







-------
TABLE 3-5(a).  CONCLUDED
Element or
Chemical Class
i mines
amides
imides
azo compounds
azoxy compounds
Sul fates
Sulfites
Sul fides
Sulfur
Organic S Compounds
mercaptans
sulfoxiHes
thlocyanates
Oxides


Oxygen


"
Hal ides

Toxic Levels 2/
Aquatic 3/ Terrestrial 4_/
(ppm) (mg/kg) 5/
14
125
0.1
18
4
6.25 20
203 3 ppm
<40 ppm
48 ppm

15 mg/m3
8
5
3.6 0.5-0.7 ppm


1 1 ppm



0.10 ppm

Synergistic Potential R1
or Other Interaction
4
4
4
4
4
4
4
4
4

4
4
4
Sulfur dioxide syner- .
gistlc with NO- at
0.5-2.5 ppb
Ozone synergistic with
S02
Ozone synergistic with
PAN
4

accumulati
4
4
4
4
4
4
4
4
4

4
4
4
4


4



3

Index of
)n Impact
Aquatic
4
4
4
4
4
4
4
4
4

4
4
4
4


4



1

Po1en??aia6/ ป"S- 0ซW
Terrestrial Standards (ing/
4
4
4
4
4
4 1
4 5 ppm
4 20 ppm
4 T ppm

4 800 mg
4
4
4 0.2


4 200



1 0.1 ppm

Si — -
3-19
3-14
3-20
3-14 •
3-14
3-14,20
3-14,20
3-14,18
3-14,26

3-14
3-14
3-14
3-14,22,27,
28

3-14,22,29



3-14,18,30,
31

-------
TABLE 3-5.  ENVIRONMENTAL SIGNIFICANCE OF SOME CHEMICALS THAT MAY EXIST IN AIRBORNE,  LIQUID,  AND SOLID EFFLUENTS FROM STATIONARY COMBUSTION SOURCES
            PART B.  METALLIC INORGANIC COMPOUNDS I/
Element or
Chemical Class
ATuMlnuM

Antinomy
Arsenic
Beryl HIM

BISMth
CadnlM



Calclw








Cerium
CซSllM





Chromium


Copper



Dysprosium
Erbium
Europium
Gadolinium
Gallium
Germanium
Toxic Levels 2/
Aquatic 37 Terrestrial 4/
(ppm) (mg/kg) 5/
0.320 1 ppm

10-100 2
0.520 1.4
0.15 10

150
0.0026 2



0.5-10 5




*



0.14 4
100





0.016 1


1-10 2



196
30
156
25
37
1.5 586
- Synerglstic Potential B1
or Other Interaction
Toxicity of Al complexes
1s pH dependent
4
4
Toxldty decreases with
Increasing water hardness
4
Concentration factor
greatest at low salinity
Synerglstic with Cu
and Zn
Ca In water reduces
compounds of Pb, Zn,
and Al
Ca requirement 1s less
If Hg concentration 1s
high
High K concentration
Increases tolerance for
high Ca concentration
4
K In water has a slight
depressing effect on Cs
toxicity
Concentration In clams
varied inversely as log
function of estuary
salinity
2mg chromium/1 Intensi-
fied plant injury
caused by nickel
Cu, Cd, and Zn exert
synergisttc effects
Toxlclty decreases with
Increasing water hard-
ness
4
4
4
4
4
4
Index of
oaccumulatlon
Potential
3

4
2
4

3
2



3








3
3





3


4



4
4
4
4
3
3
Index of Biological
Impact Potential 6/
Aquatic
2

4
1
1

2
1



3








2
4





2


1



4
4
4
4
4
4
Terrestrial
3

4
1
1

2
2



3








3
3





3


1



4
4
4
4
4
4
U.S. Occupational p.*.,-.,,-.
Standards (mg/m') tefepences
4.6 3-14,16,32

0.5 3-14
1 3-14.19
2 y/m3 3-14,19,30

3-16
2 3-14,16,19,
33


3-14,16,19,
32







3-14,16,19
3-14,16,19





1 3-14,16,19,
20,34

1 3-14,30,33,
35,36



3-14
3-14
3-14
3-14
3-14,34
3-14,17,34

-------
TABLE 3-5(b).  CONTINUED
Element or
Chemical Class
Gold
Hafnium
Hoi mi urn
IHdium
Iron
Lanthanum
Lead

Lithium



Lutetlum
Magnesium

Manganese











Mercury
















Toxic Levels 2/ „ nn-alQti. pntpntiii Index of Index of Biological
Aquatic 3/ Terrestrial 4/ / ^l.__ , ... . j.V_J Bioaccumulation Impact Potential 6/
(ppm) (mg/kg) 5/ or er n erac 1on Potential Aquatic Terrestrial
0.40 30 4 423
0.06 75 4 423
270 4 444
4 444
0.2 7 4 323
0.15 3.5 4 323
0.01-1.0 42 Pb toxlcity reduced 2 1 3
in hard water
22 mg/m3 Efflux of Na and Ca in 3 3 3
cyanide abolished by
replacing Ca with Hg
and Na with LI
161 4 444
50 - 14 Mg reduces excessive 4 33
Zn uptake
n z.n 5 0.5 MnCl.,.4H,0 less toxic 4 33
at Tow salinities
With decreasing salinity
the concentration factor
of Mn increases
Mn Injury 1n plants in-
tensified by Mo & NOo
Mn reduces severity of
Co poisoning in tomatoes
NH4NOj reduces toxlcity
to plants
Mn antagonistic to toxic
action of Ni
0.0034 2 The toxic effects of mer- 1 1 1
curie salts are accen-
tuated by the presence of
trace amounts of Cu
In varying concentrations
NaCl exhibits first a
synergistlc effect, then
an antagonistic effect
toward the toxiclty of
HgClj
Synergistlc effects found
in all 2 and 3 factor
combinations of HgCl?,
Pb(NOj)2. and ZnS04
Hg with anionic detergents
is more than addltively
toxic
Hg more toxic at low salinities
U.S. Occupational „ -
3-14,16,19
0.5 3-14,16
3-14

3-14,16,19
3-14,16,19
150 U/m3 3-14,16,19,
37
3-14,16,19



3-14
4.1 3-16,19,25

5 3-14,16,19











0.1 3-14,16,19,
32

















-------
TABLE 3-5(b).  CONTINUED
Element or
Chemical Class
Heodymium
Nickel




Niobium
Osmium
Palladium
Platinum
Potassium










Praseodymium
Rhenium
Rubidium
Ruthenium
Samarium
Scandium
Selenium






Silver

Sodium



Toxic Levels 2/ Svncrai-tic Potpntlil
Index of
Aquatic 3/ Terrestrial 4/ „ nthA int.ซrTi Bioaccumulation
(ppra) (mg/kg) 5/ or Other Inte|-actlฐn Potential
17 ug/kg 4
0.07 .5 N1 more toxic at higher
salinities
Cu/N1 and Cr/Cu/Ni an-
tagonistic
Cr/NI synergistic
130 4
0.1 4 4
19 4
0.014 . 0.9ug/kg 4
3.0 6 Excessive K increases
tolerance for high con-
centrations of Ca and Hg
Tox1c1ty of K to fish re-
duced by Ca
K In saline irrigation
water prevents intake of
excessive amounts of NaCl
Increase in K decreases
herbicidal effectiveness
of CuS04
4 4
692 4
1160 4
4
9 4
93 4
2.0 0.2 As and Se are antagon-
istic
High sulfates diminish
uptake of Se
Toxicity decreases with
increasing water
hardness
0.003 1 Toxlcity decreases with
increasing water
hardness
0.3 1 Ca/Na and Ca/K act
antagonistically
Na is effective in
reducing excessive
In uptake
4
4




4
4
4
4
4










4
4
3
3
4
3
1






1

4



Index
Impac
Aquati
4
1




4
4
4
1
3










4
4
4
4
4
4
2






1

3



of Biological „ s Occupati
t Potential 6/ standards (mg
c Terrestrial =>lanoaras *ป9
3
2 1




3
2 2 wg/m3
2
1 4.6 u/m3
3 0.1







*


3
3
3
4
3
3
1 0.05






1 10 y/m3

3 2



onal
/mj)
3-14
3-14,16,19,
32



3-14
3-14
3-14
3-14
3-14,16,19,
32









3-14
3-14
3-14
3-16
3-14,16
3-14,16
3-14,35,38






3-14,19.30,
39

3-14,16,26,
V
Jt



-------
                                                                   TAULt  3-btbJ.  CuNLLUUbU
Element or
Chemical Class
Strontium

Toxic Levels 2/
Aquatic 3/ Terrestrial 4/
(ppm) tmg/kg) 5/
1200 123

Synergistic Potential
or Other Interaction
Marked antagonistic
action between N1NO?
Index of
Bioaccumulation
Potential
2

Index of Biological .. , „ ..< ,
Impact Potential 6/  Indicates
   only the single concentration was tested and found harmful or harmless.

-' The following aquatic organisms were used for determination of nearly all the toxic level results reported: brook trout, rainbow
   trout, fathead minnow, blueglll, daphnlds, ampMbods, and midges.

y The following terrestrial organisms were used for determination of nearly all the toxic level results reported:   rat,  mouse.
   guinea pig, dog, and cat.

-1 mg/kg 1s the amount of substance administered (Ingested or Injected) per kilogram of test organism weight,

& Relative toxicity of chemical classes disregarding emission factors.

-------
      •   In most cases, the concentration for  continuous  exposure,  estimated  from  the  RTI  formula,
          was far lower than concentrations  that  have  been studied  in animal or  human exposures or
          have been measured in community or occupational  epidemiologic  studies.  For this  reason,
          these estimated exposure  levels cannot  be compared to any  specific toxicologic  results
          except for the general observation that,  for most substances,  estimated levels were
          below levels at which adverse  health  effects have actually been  observed.  For example,
          mechanical application of the  above formulae for CCL  produces  an estimated concentration
          limit of 8 ppm versus a natural background level  of 330 ppm.
       i   The estimates presented are  for continuous exposure to a  single  pollutant.  Estimates
          were not made for short-term exposure nor was any consideration  given  to  pollutant
          synergisms or antagonisms which would influence  the concentrations presented  herein.
       It  should be stressed that these concentration limits are for  screening  purposes  only.  They
are not standards but rather preliminary  indications of ambient  concentrations  at which  health effects
from continuous exposure should be investigated.
       In  addition to the review which  resulted  in Tables 3-4 and 3-5,  the  current NOX ambient air
quality standard was reviewed in greater  detail  as described below.
       The National Ambient Air Quality Standard for oxides of nitrogen is  based  on  only one oxide of
nitrogen -nitrogen dioxide.  Nitric oxide  (NO)  is also a common constituent of ambient  air pollu-
tion, but  is  nonirritant and does not appear  to  cause adverse health  effects at typical  ambient
concentrations.  The national primary and secondary  standard for nitrogen dioxide, promulgated in
April of 1971, is an annual arithmetic  mean of 100 ug/m3 (0.05 ppm).
       The health criteria upon which this standard  was based included few  reports of human or animal
response following exposure to low levels of  nitrogen dioxide.  Most  of the available toxicologic
literature pertained to nitrogen dioxide  concentrations higher than  those expected to occur in
ambient air.  The national standard  for nitrogen dioxide was mostly  based on a  community epidemiologic
study in Chattanooga, Tennessee, in  which increased  acute respiratory illness,  increased bronchitis
among elementary school children, and decreased  pulmonary function of elementary  school  girls were
associated with long-term exposure to elevated levels of nitrogen dioxide (0.062-0.109 ppm,
117-205 ug/m3) and suspended nitrates (4-6 yg/m3).   Although the analytical method used  in this
                                                3-51

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study to measure nitrogen dioxide has been proven Inaccurate (resulting in a  reevaluation  of this

study), this reevaluation found insufficient cause to justify revising the national  standard.*


       The  National Academy of Sciences' Committee on Medical and Biological  Effects  of  Environmental

Pollutants  analyzed and evaluated health effects of air pollutants in 1973.   They  concluded  that

although the data  base available for setting standards was inadequate, results of  research since the

standards were  adopted have generally supported these standards.


            "None of the panels were satisfied with the data base available currently  for
       setting  the standards.  Nevertheless, in general, these panels found that the  evidence
       that has accumulated since the promulgation of the Federal ambient air quality stan-
       dards by the EPA Administrator on April 30, 1971 supports those standards.  In fact,
       the  safety  factors provided by the air standards are much smaller than is usual in
       regulating  other environmental pollutants such as radioactivity.  At the same  time,
       the  health  risks generated when the air quality limits are exceeded are also  less
       severe and  usually more transitory than those for other pollutants.  On balance, the
       panels found no substantial basis for changing the standards.  However, the Panel on
       Nitrogen Dioxide suggested that consideration be given to establishing an hourly as
       well as an  annual standard for N02" (Reference 3-42, p.6).

       Other reviews of research on health effects of nitrogen dioxide published since adoption of

the  Federal standard (References 3-41 and 3-43) generally agree with this statement.  In addition,

the  NAS report states:


            "There  is sufficient information from both human and animal studies to determine
       the  levels  of N02 which may contribute to toxic, often fatal, reactions.  There is
       some evidence to show that prolonged exposure to N02 levels of 117 yg/m3 — 205 ug/m3
       can  contribute to increased prevalence of chronic bronchitis, increased incidence of
       acute lower respiratory disease and diminished pulmonary function in school children.
       Unanswered  questions still remain with respect to short-term exposure of NO? and the
       effect on acute and chronic disease, those levels of NOg which may contribute  to
       systemic effects and levels of N02 which may be necessary to control possible  adverse
       health effects from suspended nitrates" (Reference 3-41).


       In view of  these "unanswered questions" concerning short-term nitrogen dioxide exposures, the

Office of Air Quality Planning and Standards has decided to defer consideration of a  short-term

standard to 1978 when the N02 air quality criteria document is revised.


       Recently, the reference method for nitrogen dioxide was replaced with a new measurement

principle and calibration procedure (Reference 3-44).  EPA received some comments that a new refer-

ence method makes  reevaluation of the present standard necessary.  The EPA responded  that a reevalu-

ation was not needed, as the NAAQS incorporated an adequate margin of safety to allow for uncertain-

ties in measurement errors.
 An excellent discussion of these subsequent studies is offered in EPA's Scientific  and Technical
 Data Base for Criteria and Hazardous Pollutants (Reference 3-41).
                                                3-52

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       Other speculations on the possibility of revised  nitrogen  oxides  air  quality  standards  have
centered on the problem of nitrates and nitrosamines  (Reference 3-45).   In several personal  conmuni-
cations with members of ,EPA's Office of Air Quality Planning  and  Standards,  the  current  status  of the
federal standard for nitrogen dioxide was discussed specifically  with  reference  to   (1)  potential
changes in the annual average level due solely to  the  health  effects of  nitrogen dioxide,   (2)  the
introduction of a short-term standard to protect health, and   (3) a more stringent standard  as  a
guide to reducing nitrates or nitrosamines.
       Within EPA, a schedule has been prepared to revise  all  six criteria documents  on  which the
federal air quality standards are based over the next  3  to 4 years.  The  criteria document for photo-
chemical oxidants will  be revised first, followed  by  that  for hydrocarbons,  nitrogen  dioxide, carbon
monoxide and, finally,  sulfur dioxide and particulates,  which  will be  revised  together.  The revised
criteria document for nitrogen dioxide should be ready early  in 1978.  Full  public hearings  will be
held,  and within a year or so from that time, a decision is expected on  whether  the present  federal
standard for nitrogen dioxide will be revised.
        No decision on a revision of the present nitrogen dioxide  standard based  on health effects is
expected until after the criteria document has been revised.   Short-term exposures to nitrogen dioxide
 have been a serious concern; however, as EPA assesses  the  present situation, insufficient data are
available to support the promulgation of a short-term standard for N02.
        Finally, it appears that a change in the present  nitrogen  dioxide standard as a guide to
reducing nitrates or nitrosamines is unlikely within  the next  5 years.   EPA  is aware of  the
evidence from recent Community Health and Environmental  Surveillance System  (CHESS) studies
 linking suspended nitrates to adverse health effects.  However, this evidence  by itself
does not justify a new  Federal standard.  There is also  evidence  that nitrates may not
exist  as particulates,  but as nitric acid vapor; both  lines of investigation are being pursued.
        Current knowledge of nitrogen oxides reactions  in the ambient air does  not provide convincing
evidence that ambient nitrogen oxides are transformed  to ambient  nitrosamines.   Unless there is
evidence that nitrogen  dioxide promotes formation  of nitrosamines in the  body, EPA does  not  foresee
changes in the federal  standard.  It appears, then, that unless legal action specifically forces
EPA to promulgate a new or revised standard for nitrogen dioxide,  EPA foresees no change in  the
present standard until after the criteria document is  revised.
                                                  3-53

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3.4    SUMMARY AND CONCLUSIONS
       The purpose of the impact assessment task is to provide useful limits on pollutant emissions
to assist in the evaluation of NOX control  techniques.  These emission limits will be used within
the NO  environmental assessment to reduce  the possibility that recommended control strategies will
reduce NO  emissions only to increase other pollutants to unacceptable levels.  As such, the focus of
the effort reported in Section 3 has been to develop approximate limits on the ambient concentrations
of a variety of pollutants.  Relatively little filtering of substances (elimination of species because
of low ambient concentrations) has been performed to date.  Instead, data for a large number of species
have been tabulated for use in screening from this stage on.   Thus, the results presented in Section
3 set the stage for three levels of activity related to impact assessment:
       •   Initial program planning activities will identify  both N0v control  processes with poten-
                                                                    A
           tial emission problems and pollutants which may be emitted in quantities that approach
           the threshold concentrations.  This activity is initiated in Section 7 and will  continue
           through the near future.  The results will  guide the selection of processes for further
           review, selection of pollutants  requiring particular attention, and planning of tests
           to be conducted under the NO  E/A.
       •   Additional activity under Task B.2 will  reinforce  the data presented in Section 3, culmi-
           nating in the B.2 special report on impact  assessment.   Activities will include refinement
           of the health effects data base  by additional personal  contacts with researchers in the
           area and by including data on human health  effects from ingestion as well  as inhalation.
           The examination of pollutant effects on aquatic and terrestrial biota will be substan-
           tially augmented through an expanded literature search and through personal contacts with
           key researchers.
           As additional data become available in the  extended B.2 study on both human health and
           terrestrial/aquatic effects, an  attempt will be made to refine the current levels.  This
           will reflect additional  data obtained during this  study and will attempt to integrate all
           effects data (human, aquatic, terrestrial)  for a substance into one limiting concentration.
       •   Activities in the testing phase  of this program will also address many issues currently
           unresolved for lack of specific  data.  Particular  issues include the actual emissions
           from combustion sources  employing NOX controls (especially liquid and solid effluents),
           pollutant fates in the atmosphere, and the  cumulative effect of actual pollutant concen-
           trations.   The data obtained in  the course  of testing under this and other programs, when
                                                 3-54

-------
           integrated  Into the B.2 data base, should substantially Increase confidence in the resulting
           concentration  limits.
       In  addition to  the data presented in Section 3.3 and the qualifications to the data presented
herein, other questions have arisen which will be addressed in the program planning activities and
in the continuing efforts under B.2.  The topics listed below will require further attention as the
NOV E/A proceeds:
  X
       •   Early in the planning process, the interaction of the impact assessment task of this
           program with other ongoing EPA programs will be considered.  Many aspects of the present
           program may benefit from data being obtained from other efforts, particularly the other
           environmental  assessments.  During the near-term activities, the impact assessment task
           will be reexamined to minimize duplication with other programs.
       •   Also during the current activities, internal efforts of the EPA to set standards, parti-
           cularly as  these efforts are affected by recent legislative actions, will be reviewed to
           ensure that all future activities in this program are based on an accurate view of poten-
           tial regulatory actions.
       0   As the research proceeds for the B.2 task on impact assessment, there are three elements
           which must be considered:
           -   The influence of fugitive and nonstandard emissions (for example soot-blowing, boiler
               wash, startup, shutdown, etc.) in determining permissible concentrations,
           —   The approach to be followed to consider potentially carcinogenic or mutagenic emissions,
           -   The approach to define unacceptable effects on terrestrial and aquatic biota, where
               irreversible effects may more readily be tolerated than in human health.
       •   Finally the role of pollutant interaction (both synergisms and antagonisms) must be con-
           sidered in designing the bioassy experiments to be conducted under the testing phase.
       In general, the effort documented in Section 3 presents preliminary guidelines for permissible
 pollutant concentrations.  These data are a conservative approach to determine whether NOX controls
 are likely to cause unacceptable increases in other pollutants.  Until reinforced by further activity
 during B.2, these data should be considered as qualitative indications of potential problems rather
 than precise quantitative threshold levels.
                                                 3-55

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                                     REFERENCES FOR SECTION 3


3-1.   Hidy, G. M., et al., "Characterization of Aerosols in California," ACHEX, California Air
       Resources Board, Sacramento, California, 1974.

3-2.   Hidy, G. M., in "Proceedings of the Conference on Health Effect of Atmospheric Salts and
       Gases of Sulfur and Nitrogen in Association with Photochemical Oxidant," (T. T. Crocker, Ed)
       California Air Resources Board, Sacramento, 1974, Vol. 2.

3-3.   "California Air Quality Data," California Air Resources Board, 1973 to 1975.

3-4.   Flocchini, R., et al., "Monitoring California's Aerosols by Size and Elemental Composition,"
       Env. Sci. and Tech., Vol. 10:76, 1976.

3-5.   Hanst, P. L., et al., "A Spectroscopic Study of California Smog," EPA 650-4-76-006,
       Environmental Protection Agency, Office of Research and Development, National Environmental
       Research Center, Research Triangle Park, North Carolina, 1975.

3-6.   Handy, R. and A. Schlinder, "Estimation of Permissible Concentrations of Pollutants for
       Continuous Exposure," Research Triangle Institute, EPA 600-2-76-155, NTIS-PB 253 959/AS,
       June 1976.

3-7-   Recommended NIOSH occupational standards obtained from the criteria document for that sub-
       stance.  For example:  National Institute for Occupational Safety and Health.  Criteria for
       a Recommended Standard . .  . Occupational Exposure to Ammonia.

3-8.   "Threshold Limit Values for Chemical Substances and Physical Agents in the Workroom Environ-
       ment with Intended Changes  for 1976," American Conference  of Governmental Industrial
       Hygienists  (ACGIH), Cincinnati, 1976.

3-9.   "Registry of Toxic Effects  of Chemical Substances, 1976 Edition," National Institute for
       Occupational Safety and Health, U.S. GPO, June 1975.

3-10.  "Suspected Carcinogens; a Subfile of the NIOSH Toxic Substances List," National Institute
       for Occupational Safety and Health, DHEW Pub. No. (NIOSH)  75-188, U.S. GPO, June 1975.

3-11.  "Revised Recommendation for an Occupational Exposure Standard for Benzene — INFORMATION,"
       National Institute for Occupational Safety and Health, Newsletter of 25 August 1976.

3-12.  "National Ambient Air Quality Standards," Code of Federal  Regulations, 40 CFR 50.4 to 50.11,
       1  July 1975.

3-13.  "Air Quality Criteria for Hydrocarbons," U.S. Environmental Protection Agency, NAPCA Pub.
       No.  AP-64, U.S.  GPO, March  1970.

3-14.  Cristensen, H.  E.  and T. T. Luginbyhl (Ed), "Registry of Toxic Effects of Chemical Substances,"
       U.S. Department of Health,  Education and Welfare, Rockville, MD, p. 1296, 1975.

3-15.  Middleton, J. T. (Ed), "Air Quality Criteria for Photochemical Oxidants," U.S. Department of
       Health, Education and Welfare, Washington, D.C., 1970.

3-16.  Eisler, R.  and M.  Wapner, "Second Annotated Bibliography on Biological Effects of Metals in
       Aquatic Environments," Environmental Research Laboratory,  EPA 600-3-75-008, NTIS-PB 248 211/AS,
       1975.

3-17.  Piersol, J. R.,  "Effect of  Ethylene on Growth of Carnations:  Preliminary Report," Colorado
       Flower Growers Association, Inc., Bulletin 277, Denver, Colorado, 1973.

3-18.  Lacasse, N. L.  and W. J. Moroz, "Handbook of Effects Assessment Vegetation Damage," Center
       for Air Environment Studies, Pennsylvania State University, University Park, Penn., 1969.

3-19.  McKee,  J. E. and H. E. Wolf (Ed), "Water Quality Criteria (2nd Ed.)," The Resources Agency
       of California, State Water  Resources Control Board Publication 3-A, 1963.

3-20.  Becker, C.  D. and T. 0. Thatcher (Ed), "Toxicity of Power Plant Chemicals to Aquatic Life,"
       Pacific Northwest Laboratories, Richland, Washington, 1973.
                                                3-56

-------
3-21.   Clar,  E.,  "Polycyclic Hydrocarbons, Vol. 2," Academic Press, New York, 1964.

3-22.   Doudoroff, P.  and M. Katz, "Critical Review of Literature on the Toxicity of Industrial
       Wastes and Their Components to Fish.  I. Alkalies, Acids, and  Inorganic Gases," Sewage and
       Industrial Wastes 22(11):  1432-1458,1950.	

3-23.   Greeley,  R. A., et al., "Sulfates and the Environment:  A Review," MTR-6895, The Mitre
       Corporation, McLean, Virginia, 1975.

3-24.   Copenhaver, E. D. and D. S. Harnden (Ed), "NSF-RANN Trace Contaminants Abstracts,"
       ORNL/E15-96, Oak Ridge National Laboratory, Oak Ridge, Tenn.,  1976.

3-25.   Bruups, W. A., "Chronic Toxicity of Zinc to the Fathead Minnow, Pimephales Promelas
       Rafinesque," Trans. Am. Fish Soc. 98:212-279, 1969.

3-26.   "Mercury and Air Pollution:  A Bibliography with Abstracts," U.S. Environmental Protection
       Agency, Office of Air Programs Publication No. AP-114, 1972.

3-27.   Hill, A.  C. and J. H. Bennett, "Inhibition of Apparent Photosynthesis by Nitrogen Oxides,"
       Pergammon  Press, London, 1970.

3-28.  Thompson,  C. R., et al., "Acceptable Limits for Air Pollution  Dosages and Vegetation Effects:
       Nitrogen Dioxide," 67th Annual Meeting  of the Air Pollution Control Association, Paper 74-227,
       Denver, Colo., 1974.

3-29.  Heggestad, H. E., et al.,  "Determining  Acceptable Limits for Air Pollution Dosages and Vege-
       tation Effects:  Ozone," 67th Annual Meeting of the Air Pollution Control Association,
       Paper 74-244, Denver, Colo., 1974.

3-30.  Bowen, H.  J., "Trace Elements in Biochemistry," Academic Press, New York, 1966.

3-31.  Hill, A. C., "Air Quality  Standards for Fluoride Vegetation Effects," Journal of the Air
       Pollution  Control Association 19:331-336, 1969.

3-32.  Doudoroff, P. and M. Katz, "Critical Review of Literature on the Toxicity of Industrial
       Wastes and Their Components to Fish. II.  The Metals, as Salts," Sewage and Industrial
       Wastes 25(7):  802-839,1953.

 3-33.  Eaton, J.  G., "Chronic Toxicity of  a Copper, Cadmium  and Zinc  Mixture to the Fathead Minnow
       (Pimephales Promelas Rafinesque)." Water Research 7(11):  1723-1736, 1973.

 3-34.  Garton, R. R., "Biological Effects  of Cooling Tower Slowdown," 71st National Meeting,
       American  Institute  of Chemical Engineers, Dallas, Texas, 1972.

 3-35.  Davies, P. H. and J. P. Goettle, "Aquatic Life -Western Recommendations for Heavy Metals
       and Other  Inorganic Toxicants in Fresh  Water," Submitted by Colorado Division of wildlife
       for Water  Quality Standards Revision Committee and Colorado Water Quality Control Commission,
       1976.

 3-36.  Hazel, C.  R. and S. J. Meith, "Bioassay of King Salmon Eggs and Sac Lay in Copper Solutions,"
       California Fish and Game 56:121-124, 1970.

 3-37.  Schneider, R. F., "Impact  of Various Metals on the Aquatic Environment," EPA Technical Report
       No. 2, 1971.

 3-38.  Kothny, E. L.  (Ed), "Trace Elements in  the Environment," American Chemical Society Advances
       in Chemistry Series No. 123, Washington, D.C., 1973.

 3-39.  Davies, P- H., et al.,  "Toxicity of Silver to Rainbow Trout  (Salmo Gairdneri)." To be
       published  in Water  Research, 1977.

 3-40.  Sinley, J. R., et al.,  "The Effects of  Zinc on Rainbow Trout  (Salmo Gairdneri)." To  be
       published  in Water  Research.
                                                 3-57

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3-41.   "Scientific and Technical  Data Base for Criteria and Hazardous Pollutants - 1975 ERC/RTP
       Review,"  Health Effects Research  Laboratory,  EPA 600-1-76-023, 1976, NTIS-PB 253 942/AS.

3-42.   "Air Quality and Automobile Emissions  Control,  Vol.  1,  Summary Report," National Academy of
       Sciences  - National  Academy of Engineering, Coordinating Committee on Air Quality Studies,
       prepared  for the Committee on  Public Works, U.S.  Senate, 93-24,  1974.

3-43.   Ziskind,  R.  and D.  Hausknecht, "Health Effects  of Nitrogen  Oxides,"  Science Applications,
       Inc., EPRI 571-1A (PB 251264), 1976.

3-44.   "Nitrogen Dioxide Measurement  Principle and Calibration Procedure,"  Federal Register 41  (232):
       52686-52695, December 1, 1976.

3-45.   Fine, D.  H., et al., "A Possible  Nitrogen  Oxide-Nitrosamine Cancer Link,"  Bull.  Environ.
       Contain. Toxicol.  11(1}:'  18-19, 1974.
                                               3-58

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                                             SECTION  4
                                   NOX CONTROL CHARACTERIZATION

       As  a result of emission control regulations for new and existing stationary sources, there
has been extensive development and implementation of NO  controls in the past 10 years.  Nearly all
                                                       X
current NO  control  applications use combustion process modifications.  Other approaches, e.g.,
modification or switching of fuel, use of alternate energy systems and post-combustion flue gas
treatment  are being evaluated for potential future application along with more advanced combustion
process modifications.   Control development experience has shown that the applicability and effec-
tiveness of combustion process modifications are strongly dependent on the specific equipment/fuel
combination to be controlled, and on whether the control is to be applied to existing field equip-
ment or new units.  Accordingly, control development efforts are directed toward specific equipment
categories and fuel  types.   In general, the following sequence of control development is being pur-
sued for each major equipment/fuel category:
       0    Minor operational adjustments
       •    Minor retrofit modifications
       •    Extensive hardware changes, either retrofit or factory-installed on new units
       •    Major redesign of new equipment
The progress made in this sequence varies with the importance of the source in local  and national
NOX regulatory strategies.   The position in the sequence will also affect how the source/control
combinations will be treated in the NO  E/A.  The developmental status of control, together with
results of field tests,  will influence both the sequence of assessment and the level  of effort in
the subsequent process studies.  As a first step, this section evaluates the user experience, ef-
fectiveness, developmental  status and projected uses of NOX controls in general and of specific
source/control  combinations.  Although the emphasis is on combustion modifications, other control
options are evaluated for potential far-term application.
       The evaluation of NO  control technology in this section is a link in the preliminary prior-
itization  of source/control  combinations concluded in Section 7.  Section 2 gave preliminary group-
ing and screening of fuel  combustion sources.  This section notes current and impending control
                                               4-1

-------
regulations for these sources and relates specific controls to the source  to  identify  which  source/
control combinations are the most promising to achieve given levels of control.   The associated
evaluation of potential adverse environment impacts is given in Section 6.  This  effort  scopes the
source/controls to be evaluated in the near-term effort in the NOX E/A.  The  results are further
evaluated in Section 7 to scope the later effort on far-term applications  of  NOX  controls.   Also
in Section 7, the potential adverse impacts of near-term applications are  screened  to  prioritize
environmental assessment and testing requirements.

4.1    SURVEY OF NOX CONTROL REGULATIONS
       Although the emphasis in the NOX E/A is on assessment of NOX control techniques,  some con-
sideration must be made of the underlying regulatory strategy.   This is because the relative prior-
ities  in the NOV E/A for assessment of the various source/control  combinations depend  largely on
               X
the current and anticipated control implementation requirements to attain and maintain ambient air
quality for NO,,.  The Section 1 Introduction gave a broad overview of NOX control implementation
requirements and indicated the trend toward more widespread use of NO  controls, particularly on
new equipment.  This discussion supplements that overview by citing existing and impending NOX
emission regulations for stationary fuel combustion sources.   It is intended to give perspective to
the subsequent review of the status and trends of control  technology and to assist in  setting prior-
ities on source/control combinations.
       The incentive for NOV control development derives from two separate regulatory  mechanisms,
                           A
the Federal Standards of Performance for New Stationary Sources (NSPS), and the State  Implementation
Plans  (SIPS).  The NSPS are intended largely to assist in air quality maintenance by offsetting in-
creases due to source growth.  The EPA sets NSPS from time to time based on the application  of the
best system of emission reductions.  Part of the NOX control  development effort is  directed  at devel-
oping and demonstrating best systems of emission reduction in support of the  setting of  future NSPS.
The primary responsibility for air quality attainment and maintenance rests with  the states.  Emis-
sion standards in addition to the NSPS are set through the SIPS if required to attain  and/or main-
tain the National Ambient Air Quality Standards in Air Quality Control Regions within  the jurisdic-
tion of the states.   Part of the NOX control development effort is directed at facilitating  com-
pliance with existing standards.
                                                4-2

-------
       Table 4-1  summarizes the current and Impending  NSPS  for" NOX  control  from stationary  fuel
combustion sources.  All current and impending  standards  are  based  on  application  of combustion  pro-
cess modifications.  To date, NOX standards have been  set only for  utility  and  large industrial
boilers.   The technology to support these standards was derived in  part  from  demonstration  of  retro-
fit controls implemented in areas with attainment  problems.   A more stringent standard  is being  con-
sidered for coal-fired units based on technology demonstrated in  control  development since  1971.
No additional stringency is justified for new gas- or  oil-fired units  since no  units of this type
are being sold.  The standard being considered  for gas turbines is  also  based on retrofit technology
demonstrated as part of SIPS.  The standards under study  for  1C engines  and industrial  boilers are
being based on EPA and private sector control development since there  has been  little retrofit con-
trol application for these sources.
       As indicated in Section 1, maintenance of air quality  in the 1980's and  1990's will  require
NOX regulations in addition to those existing or planned.   New source  controls  will  be  emphasized
since experience has shown them to be more effective,  less  costly and  less disruptive than  retrofit
control of existing equipment.  Thus, EPA's Office of  Air Quality Planning and  Standards anticipates
additions to the standards shown on Table 4-1.  These  additions may involve both inclusion of
sources not presently regulated and setting more stringent  standards for sources with current or
impending controls.  In both cases, the driving force  for the  standards will  be the  best systems of
emission reductions demonstrated in the control development program.
       State and local standards for new and existing  stationary fuel  combustion equipment are
listed in Table 4-2.  As is the case for NSPS,  the basis  for the state and local standards  is ap-
plication of combustion process modifications.  This information was obtained through contacts with
local regulatory agencies and from the Environmental Reporter  (Reference 4-1).  Standards for new
sources which are the same as the Federal NSPS  have been  omitted.   With the exception of the
Southern California Air Pollution Control District (SCAPCD), the standards are  largely  directed at
future air quality maintenance rather than attainment.  Some areas  have exercized the option to set
standards more stringent than required for maintenance by the  SIPS.  The SCAPCD has  a serious attain-
ment problem and has accordingly instituted the most comprehensive  and stringent emission regula-
tions.  In fact, the control development in the SCAPCD has  been so  intense that it is useful as  a
guide to the limits of current technology for existing gas- and oil-fired equipment.  The trend  in
the SCAPCD and elsewhere has been toward regulating smaller equipment  categories and tightening  the
regulations on larger equipment.  The SCAPCD regulations  are  currently being  evaluated  as part of
the SIP revision to determine if further emission  reductions  are  practical.
                                                 4-3

-------
                                     TABLE 4-1.   CURRENT OR PLANNED FEDERAL STANDARDS  OF  PERFORMANCE  FOR NEW STATIONARY SOURCES
                                           Source
i
•to
Steam generators; heat input
>73 MW (250 MBtu/hr)
    Gaseous fossil fuel-fired
    Liquid fossil fuel-fired
    Solid fossil  fuel-fired
    (except lignite)
    Mixed fossil  fuel-fired

    Lignite coal-fired
    Wood  residue-fired
                                  Coal-fired (except lignite)
                              Gas turbines; heat input
                              >2.2 MW (7.5 MBtu/hr)
                              Stationary 1C engines
                              Intermediate size steam
                              generators
                                              Status
Promulgated 12-23-71
Promulgated 12-23-71
Promulgated 12-23-71

Promulgated 12-23-71

Proposed 12-22-76
Amended 11-22-76

SSEIS  under review
SSEIS under review

SSEIS under review
Under study
                                 Standard
                                                                                             86  ng/J  (0.2  lb/106 Btu)
                                                                                             130 ng/J  (0.3 lb/106 Btu)
                                                                                             300 ng/J  (0.7 lb/106 Btu)
                                                                                             86X  +  130Y  +  3QOZa
                                                                                                                ng/J
    X + Y + Z
260 ng/J (0.6 lb/106 Btu)
Add wood residue to per-
missible mixed fuel firing
standard
260 ng/J (0.6 lb/106 Btu)
75 ppm (15 percent 02)
                                Reference
36 FR 24877
36 FR 24877
36 FR 24877

36 FR 24877
41 FR 55792
41 FR 51397
                              aX,  Y,  and Z are the percent of total  heat input derived from gaseous,  liquid and solid fossil  fuels
                               Standards Support and Environmental  Impact Statement

-------
TABLE 4-2.  SUMMARY OF STATE AND LOCAL NOX EMISSION STANDARDS6


CALIFORNIAf
Bay Area APCD

Monterey Bay


San Diego
San Joaquln

Kern Co.
Santa Barbara APCD

Counties in SCAPCD:
LA Co.c


Orange Co.c



San Bernardino Co.


Riverside Co.c








New or
Existing

New
All
New
All
All
All
New
New
New
New
Any

All
All
New
Existing

Existing
Existing
Existing
Existing

Existing

Existing

Existing



Equipmentd
Type

Heat transfer
Heat transfer
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Fuel burning

Equipment
Equipment
Equipment
Equipment

Equipment
Equipment
Equipment
Steam generators

Equipment

Equipment

Equipment




Heat Input
Capacity3

>73 (250)
>513 (1,750)

>440 (1,500)
>440 (1,500)
>15 (50)

>520 (1,775)


>520 (1,775)

>520 (1,775)
>520 (1 ,775)
>73 (250)
147-630
'(500-2,150)
>630 (2,150)

>520 (1,775)
147-520
(500-1,775)
>205 (700)

>205 (700)

>520 (1,775)




Gas
Fired

125 ppm
175 ppm
64 kg/hr9
125 ppm
225 ppm
125 ppm
64 kg/hr9
125 ppm
64 kg/hr9
64 kg/hrg
125 ppm

225 ppm
125 ppm
125 ppm
225 ppm

225 ppm
125 ppm
125 ppm
125 ppm

225 ppm

125 ppm

125 ppm



Standard
Oil
Fired

225 ppm
300 ppm
64 kg/hr9
225 ppm/hr
225 ppm
225 ppm
64 kg/hr9
225 ppm
64 kg/hr9
64 kg/hr9
225 ppm

325 ppm
225 ppm
225 ppm
325 ppm

325 ppm
225 ppm
225 ppm
225 ppm

325 ppm

225 ppm

225 ppm

i 	


Coal
Fired



64 kg/hr9


225 ppm
64 kg/hr9
225 ppm
64 kg/hr9
64 kg/hr9



_
-
-

-
-
-
—









Effective
Date


4/19/75


9/16/76


1/1/75


1/1/75

12/31/71
12/31/74

12/31/72

12/31/72
12/31/75
1/1/75
1/1/75

12/31/71

12/31/74

1/1/75



Comments
























Applies to West Central
Area Only
Applies to West Central
Area Only
Applies to Balance of
County

(continued on p. 4-6)

-------
TABLE 4-2.  Continued



SCAPCD





Ventura Co. APCD




CONNECTICUT





DELAWARE
New Castle Co.


DISTRICT OF COLUMBIA
FLORIDA
Tampa
ILLINOIS
Lake, Will, Du
Page, McHenry,
Kara, Grundy,
Kendall, Kankakee,
Macon, St. Clair,
Madison Cos.
Cook Co.


New or
Existing
New
All

All
All
All

New
New
All

All
Existing
New

Existing

All

All


Existing

Existing
Existing


New
Existing
Equipment
Type
Equipment
Fuel burning

Fuel burning
Steam generating
Fuel burning

Fuel burning
Fuel burning
Fuel burning

Fuel burning
Fuel burning
Fuel burning

Fuel burning

6T

Steam generators


Steam generators

Steam boilers
Fuel combustion


Fuel combustion
Fuel combustion

Heat Input
Capacity

523-628
(1,786-2,143)
>628 (2,143)
>163 (555)
161-523
(550-1,786)

>73 (250)
73-630
(250-2,150)
>630 (2,150)
>73 (250)
1.5-73
(5-250)
II



>147 (500)


>29 (100)

>2.9 (10)
>73 (250)


>59 (200)
j >59 (200)

Gas
Fired
64 kg/hr9
225 ppm

125 ppm
125 ppm
300 ppm

64 kg/hr9
125 ppm
250 ppm

125 ppm
86.1 (0.2)
86.1 (0.2)

86.1 (0.2)

387.3 (0.9)

86.1 (0.2)


86.1 (0.2)

86.1 (0.2)
129 (0.3)


86.1 (0.2)
129 (0.3)
Standard6
Oil
Fired
64 kg/hr9
325 ppm

225 ppm
225 ppm
400 ppm

64 kg/hr9
225 ppm
250 ppm

225 ppm
129 (0.3)
129 (0.3)

129 (0.3)

387.3 (0.9)

129 (0.3)


129 (0.3)

129 (0.3)
129 (0.3)


1Z9 (0.3)
129 (0.3)

Coal
Fi red
64 kg/hr9
325 ppm

225 ppm
225 ppm
400 ppm

64 kg/hr9
-
250 ppm


387.3 (0.9)
301 (0.7)

387.3 (0.9)

387.3 (0.9)

129 (0.3)


301 (0.7)

301 (0.7)
387.3 (0.9)


301 (0.7)
387.3 (0.9)
Effective
Date





1/1/77













7/1/76




7/1/75






Comments









Except peaking units at
Mandal ay

Except GT, 1C
Except GT, 1C

Except GT, 1C; variances
permi tted


Except for certain
sources governed by
operation permit
Except lignite


Except cyclone &
horizontally opposed
fired boilers burn-
ing solid fuel



ii n

-------
uonzinuea


INDIANA
MARYLAND
MINNESOTA
NEW MEXICO




NEW YORK
New York City
NORTH CAROLINA
OHIO
OKLAHOMA
SOUTH DAKOTA
TEXAS
Dallas-Fort Worth S
Houston- Calves ton
ACQR'S



VERMONT

New or
Existing
Existing
New
Existing
New
Existing
New
Existing
All
All
All
Existing
Existing
New
All
All



New
New
Equipment
Type
Fuel burning
Fuel burning
Boilers
Coal burning
Coal burning
Gas burning
Gas burning
Oil burning
GT, 1C
Boilers
Boilers
Boilers
Fuel burning
Fuel burning
Steam generators
Opposed fired
Front fired
Tangential fired
Combustion
GT

Heat Input
Capacity
>:73 (250)
>73 (250)
>73 (250)
>73 (250)
>73 (250)
>1 ,055,000 GJ/
yr (1,000,000
MBtu/yr)

II
^73 (250)
>147 (500)
2.73 (250)
>J3 (250)
>15 (50)

>272.200 kq/hr
max (>600,000
Ibs/hr max)
continuous
capacity



2.73 (250)
>73 (250)

Gas
Fired
86.1 (0.2)
86.1 (0.2)
129 (0.3)


86.1 (0.2)
129 (0.3)

86.1 (0.2)
73.2 (0.17)
258.2 (0.6)
86.1 (0.2)
86.1 (0.2)
86.1 (0.2)

301 (0.7)
215.2 (0.5)
107.6 (0.25)
~~
Standard
Oil
Fired
129 (0.3)
129 (0.3)
172.1 (0.4)




129 (0.3)
129 (0.3)
77.5 (0.18)
258.2 (0.6)
129 (0.3)
129 (0.3)
129 (0.3)


—
-
129 (0.3)
129 (0.3)

Coal
Fired
301 (0.7)
215.2 (0.5)
193.6 (0.45)
301 (0.7)
301 (0.7)



86.1 (0.2)
559.4 (1.3)
387.3 (0.9)
301 (0.7)


—
—
-
-
Effective
Date



12/31/74
12/31/74
12/31/74



7/1/72



8/31/72



7/1/71
7/1/73
Conments

Applies to "Priority
Basin A" only — none
at present
Applies to Priority I
AQCR's only








Applies only to
Priority I regions






Except GT
                                                     (continued on  p. 4-8)

-------
                                                                     TABLE 4-2.  Concluded


WYOMING








New or
Existing
New
Existing
New
New
Existing
Existing
New
Existing

Equipment
Type
Gas burning
Gas burning
Oil burning
Oil burning
Oil burning
Oil burning
Solid fired equip
Solid fired equip


Heat Input
Capaci tya


>0.29 (1)
<0.29 (1)
>73 (250)
<73 (250)


Standard15
Gas Oil Coal
Fired Fired Fired
86.1 (0.2)
99 (0.23)
129 (0.3)
258.2 (0.6)
197.9 (0.45)
258.2 (0.6)
301 (0.7)
322.7 (0.75)
*
Ef f ecti ve
Date










Except 1C <59 (200)

Except 1C <59 (200)
Except 1C <59 (200)
Except 1C <59 (200)
Except 1C <59 (200)
Except 1C <59 (200)
Except 1C <59 (200)
Except lignite
aUnless stated otherwise, units are MW (10s Btu/hr)
bUnless stated otherwise, units are ng/J (lb/106 Btu).
ฐRules put into effect before SCAPCD was formed and replaced by SCAPCD rules
dGT refers to gas turbines; 1C refers to reciprocating internal combustion engines
eNOv emission standards in chronological order In so far as possible
f  A
 All ppm standards are at 3 percent 02
9140 Ibs/hr

-------
       In  summary, the sources and emission levels  listed  in  Tables  4-1  and  4-2 establish  the  scope
of sources and levels of controls to be evaluated in  the near-term effort of the NO  E/A to  assess
the incremental impacts of current NOX control  technology.  The remainder of this section  evaluates
the available control technology to establish the source/control  combinations to be emphasized in
the near-term effort.  It also notes the emerging technology  which will  be considered in the far-
term as discussed in more detail in Section 7.

4.2    COMBUSTION PROCESS MODIFICATIONS
       Modifying the combustion process conditions  is the  most  effective and widely used technique
for achieving moderate (40 to 60 percent) reduction in combustion-generated  oxides  of nitrogen.
This subsection evaluates the combustion modification techniques  either  demonstrated or  currently
under development.  The discussion begins by reviewing the formation mechanisms  of  NO and the
general principles for suppressing NO  emissions by process modifications.

4.2.1  General Concepts on NO  Formation and Control
       Oxides of nitrogen formed in combustion  processes  are  due either  to the thermal fixation of
 atmospheric nitrogen in the combustion air, which  produces  "thermal  NOX", or to the conversion of
 chemically-bound nitrogen in the fuel, which produces  "fuel NOX."   For natural gas and light distil-
 late oil firing, nearly all NOV emissions  result from  thermal  fixation.  With residual oil, crude
                              X
 oil, and coal, the contribution from  fuel-bound nitrogen  can  be significant and, in certain cases,
 predominant.
 4.2.1.1  Thermal NOX
       During combustion, nitrogen oxides  are formed by the high temperature, thermal fixation of
 N2.  Nitric oxide (NO) is the major product, even  though  N02  is thermodynamically favored at lower
 temperatures.  The residence time in  most  stationary combustion processes is too short for NO to be
 oxidized to N02>
       The detailed chemical mechanism for thermal  NO  formation is  not fully understood.  However,
 it is widely accepted that thermal fixation in  the post-combustion  zone  occurs according to the
 extended form of the Zeldovich chain  mechanism  (Reference 4-2):

                                         N2 + 0 ?  NO + N                                       (4-1)

                                         N + 02 t  NO + 0                                       (4-2)
                                         N + OH ฃ  NO + H                                       (4-3)
                                                 4-9

-------
assuming that the combustion reactions have reached equilibrium.  Reaction  (4-1)  has  a  large  activa-
tion energy (75.8 kcal/mole) and is generally believed to be rate determining.  Oxygen  atom concen-
trations are assumed to have reached equilibrium according to:
                                        02 + M?0 + 0 + M                                     (4-4)

where M denotes any third substance (usually N2).
       In the flame zone itself, the Zeldovich mechanism with the equilibrium oxygen  assumption is
not adequate to account for experimentally observed NO formation rates.  Several  investigators have
observed the production of significant amounts of "prompt" NO, which is formed very rapidly in the
flame front (References 4-3 through 4-11), but there is no general agreement on how it  is produced.
Prompt NO is believed to stem from the existence of "superequilibrium" radical concentrations
(References 4-11, 4-12, and 4-13) within the flame zone which result from hydrocarbon chemistry and/
or nitrogen specie reactions, such as suggested by Fenimore (Reference 4-14).  To date, prompt NO
has only been explicitly measured in carefully controlled laminar flames, but the mechanism almost
certainly exists in typical combustor flames as well.  Of course, in an actual combustor, both the
hydrocarbon and NO  kinetics are directly coupled to turbulent mixing in the flame zone.
       Recent experiments at atmospheric pressure indicate that under certain conditions the amount
of NO formed in heated N-, Op and Ar mixtures can be expressed as (Reference 4-15):

                                 [NO] = k1 exp (-k2/T)[N2][02]1/2t                             (4-5)
where            [ ] = mole fraction
                 k,, k2 = constants
                 T   = temperature (K)
                 t   = time (sec)
Although this expression certainly will  not adequately describe NO formation in a turbulent flame,
it does summarize thermal NOX formation.   It reflects the strong dependence of NO formation on
temperature.   It also shows that NO formation is directly proportional to N2 concentration and to
residence time, and proportional to the square root of oxygen concentration.
       Based on the above relations, thermal NOX can theoretically be reduced using four tactics:
       •   Reduce local  nitrogen concentrations at peak temperature
       •   Reduce local  oxygen concentrations at peak temperature
                                                4-10

-------
       •    Reduce  the residence time at peak temperature



       •    Reduce  peak temperature




       Since reducing N2 levels is quite difficult, efforts  in  the  field  have  focused  on  reducing



oxygen levels,  peak temperatures, and time of exposure in the N0x-producing regions of a  combustor.


On a macroscopic scale, techniques such as lowered excess air and off-stoichiometric (or  staged)



combustion  have been used to lower local 02 concentrations in boilers.  Since  internal combustion



(1C) engines and gas turbines typically operate at excess air levels  far  greater than stoichiometric,


lowering  excess air levels in these equipment classes does not  control thermal NO .  However, off-
                                                                                 X

stoichiometric  combustion in the form of stratified charge cylinder design has been used  successfully


in 1C engines.



       Flue gas recirculation and reduced air preheat have been used  in boilers to control thermal  NO
                                                                                                     X


by lowering peak flame temperatures.  Analogously, exhaust gas  recirculation (EGR), reduced manifold


air temperature (1C engines) and reduced air preheat have been  applied to 1C engines and gas turbines.



Other techniques designed to lower peak temperatures in prime movers  include water injection and


altered air/fuel ratios.



       Techniques  which reduce residence time at peak temperature have been more easily applied to


prime mover equipment classes.  Although flue gas recirculation (and  EGR) reduces combustion gas



residence time, it acts as a thermal NO  control primarily through temperature reduction.  Tech-


niques which specifically reduce exposure time at high temperatures include ignition retard for 1C



engines and early  quench with secondary air for gas turbines.



       It is important to recognize that the above-mentioned techniques for thermal NOX reduction



alter combustion conditions on a macroscopic scale.  Although these macroscopic techniques have all


been  relatively successful in reducing thermal NOX> local microscopic combustion conditions ulti-


mately determine the amount of thermal NO  formed.  These conditions  are  in turn intimately related



to  such variables  as local combustion intensity, heat removal rates,  and  internal mixing  effects.


Modifying these secondary combustion variables at microscopic levels  requires  fundamental changes



in combustion equipment design.



       For example, recent studies on the formation of thermal  NO in  gaseous flames have  confirmed



that internal mixing can have large effects on the total amount of NO formed (References  4-16,  4-17).



Burner swirl, combustion air velocity, fuel injection angle and velocity, quarl angle  and confinement



ratio all affect the mixing between fuel, combustion air and recirculated products.  Mixing,  in turn,



alters the local temperatures and specie concentrations which control the rate of NO formation.
                                                  4-11

-------
       Unfortunately, generalizing these effects is difficult, because the interactions are complex.
Increasing swirl, for example, may both increase entrainment of cooled combustion products (hence
lowering peak temperatures) and increase fuel/air mixing (raising local combustion intensity).  The
net effect of increasing swirl can be to either raise or lower NOX emissions, depending on other
system parameters.

       In summary, a hierarchy of effects depicted in Table 4-3 produces local combustion conditions
which promote thermal NO  formation.  Although combustion modification technology seeks to affect
the fundamental parameters of combustion, modifications must be made by changing the primary equip-
ment and fuel parameters.  Control of thermal NOV, which began by altering inlet conditions and
                                                A
external mass addition, has moved to more fundamental changes in combustion equipment design.

4.2.1.2  Fuel NOX

       The role of fuel-bound nitrogen as a source of NOX emissions from combustion sources has been
recognized since 1968 (Reference 4-18).  Although the relative contribution of fuel and thermal NO
                                                                                                  A
to total NO  emissions from sources firing nitrogen-containing fuels has not been definitively
established, recent estimates indicate that fuel NOX is significant and may even predominate.   In
one recent study (Reference 4-19), residual oil and pulverized coal were burned in an argon/oxygen
mixture to eliminate thermal NO  effects.  Results show that fuel NO  can account for over 50 per-
                               X                                    X
cent of total NOV production from residual oil firing and approximately 80 percent of total NOV
                X                                                                             A
from coal firing.  Therefore, as coal is increasingly used as a national energy source, the control
of fuel NO  will become more important.

       Fuel-bound nitrogen occurs in coal and petroleum fuels.  However, the nitrogen containing
compounds in petroleum tend to concentrate in the heavy resin and asphalt fractions upon distilla-
tion (Reference 4-20).   Therefore fuel NOX is of importance primarily in residual oil and coal fir-
ing.   The nitrogen compounds found in petroleum include pyrroles, indoles, isoquinolines, acridines,
and porphyrins.   Although the structure of coal is not known with certainty, it is believed that
coal-bound nitrogen also occurs in aromatic ring structures such as pyridine, picoline, quinoline,
and nicotine (Reference 4-20).

       The nitrogen content of residual oil varies from 0.1 to 0.5 percent.  Nitrogen content of
most U.S. coals lies in the 0.5 to 2 percent range (Reference 4-21); anthracite coals contain the
least and bituminous coals the most nitrogen.  Figure 4-1 illustrates the nitrogen content of various
U.S.  coals,  expressed as Ib N02 produced per million Btu for 100 percent conversion of the fuel
                                                 4-12

-------
       TABLE 4-3.  FACTORS CONTROLLING THE FORMATION OF THERMAL NO,
 Primary Equipment
and Fuel Parameters
      Secondary
Combustion Parameters
Fundamental
 Parameters
Inlet temperature,
    velocity
Firebox design
Fuel composition
Injection pattern
    of fuel & air
Size of droplets
    or particles
Burner swirl
External mass
    addition
Combustion intensity
Heat removal rate
Mixing of combustion
    products into
    flame
Local fuel-air ratio
Turbulent distortion
    of flame zone
Oxygen level
Peak temp.
Exposure time
    at peak
    temp.
Thermal
  NO..

-------
3,000




c
o
S-
OJ
> 2,000
c
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Figure 4-1.   Nitrogen and sulfur content of U.S.
             coal reserves (Reference 4-22).
                        4-14

-------
nitrogen (Reference 4-22).  The figure clearly  shows that 1f-all  coal-bound nitrogen were converted
to NOX, emissions for all coals would exceed  New Source Performance Standards.   Fortunately, only a
fraction of the fuel nitrogen is converted  to NOX for both oil  and coal  firing, as shown in Figure
4-2 (Reference 4-23).  Furthermore,  the  figure  indicates that fuel nitrogen conversion decreases  as
nitrogen content increases.  Thus, although fuel  NO  emissions  undoubtedly increase with increasing
fuel nitrogen content, the emissions increase is not proportional.  In fact, recent data indicate
only a small increase in  N0ฅ emissions as  fuel  nitrogen increases (Reference 4-24).   From observations
                           A
such as these, the effectiveness of  partial fuel  denitrification  as a NO  control  method seems  doubtful.
       Although the precise mechanism by which  fuel  nitrogen  is converted to NO  is  not understood,
                                                                                A
certain aspects are clear, particularly  for coal  combustion.   In  a large pulverized  coal  utility
boiler, the coal particles are  conveyed  by  an air stream into the hot combustion chamber,  where they
are heated at a rate in excess  of lO^K/sec.   Almost immediately volatile species,  containing  some  of
the coal-bound nitrogen,  vaporize and burn  homogeneously, rapidly (-10 msec) and probably  detached
from the original coal particle.  Combustion  of the remaining solid char is  heterogeneous  and much
slower  (~300 msec).
        Figure 4-3 summarizes what may happen  to fuel  nitrogen during this process  (Reference 4-25).
 In  general, nitrogen evolution  parallels evolution of the total volatiles,  except  during the initial
 10  to  15 percent volatilization in which little nitrogen is released (Reference  4-26).   Both total
mass volatilized and total nitrogen  volatilized increase with higher pyrolysis  temperature; the
nitrogen volatilization increases more rapidly  than  that of the total  mass.   Total mass  volatilized
appears to be a stronger  function of coal composition than total  nitrogen volatilized  (Reference
4-27).  This supports the relatively small  dependence of fuel NOX on coal  composition  observed in
small scale testing (Reference 4-19).
       Although there is  not absolute agreement on how the volatiles separate into species, it ap-
pears that about half the total volatiles and 85  percent of the nitrogeneous species evolved react
to  form other reduced species before being  oxidized.   Prior to oxidation,  the devolatilized nitrogen
may be converted to a small number of common, reduced intermediates, such as HCN and NH3>  in the
fuel-rich regions of the  flame.  The existence  of a  set of common reduced intermediates  would explain
the observations that the form of the original  fuel  nitrogen  compound does  not  influence its  con-
version to NO (e.g., References 4-20, 4-28).  More recent experiments suggest that HCN is  the predom-
inant reduced intermediate (Reference 4-29).  The reduced intermediates  are  then either oxidized  to
NO, or converted to N2 in the post-combustion zone.   Although the mechanism for these  conversions is
not presently known, one  proposed mechanism postulates a role for NCO (Reference 4-30).
                                                4-15

-------

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-------
           VOLATILE FRACTIONS
         (HYDROCARBONS, RN etc.)
                 KN
                                                          ASH
                                                        VIRTUALLY
                                                         NITROGEN
                                                          FREE
Figure 4-3.   Possible fate  of fuel nitrogen contained in
              coal  particles  during combustion  (Reference 4-25).
                              4-17

-------
       Nitrogen retained in the char may also be oxidized to NO, or reduced to N2 through  heteroge-
neous reactions occurring in the post-combustion zone.  However, it is clear that the  conversion of
char nitrogen to NO proceeds much more slowly than the conversion of devolatilized nitrogen.   In
fact, based on a combination of experimental and empirical modeling studies, it  is now believed
that 60 to 80 percent of the fuel NO  results from volatile nitrogen oxidation (References 4-26,
                                    X
4-31).  Conversion of the char nitrogen to NO is in general lower, by factors of two to three, than
conversion of total coal nitrogen.
       Regardless of the precise mechanism of fuel NOX formation, several general trends are evident,
particularly for coal combustion.  As expected, fuel nitrogen conversion to NO is highly dependent
on the fuel/air ratio for the range existing in typical combustion equipment, as shown in Figure 4-4.
Oxidation of the char nitrogen is relatively insensitive to fuel/air changes, but volatile NO forma-
tion is strongly affected by fuel/air ratio changes.
       In contrast to thermal NO , fuel NO  production is relatively insensitive to small changes in
combustion zone temperature (Reference 4-28).  Char nitrogen oxidation appears to be a very weak
function of temperature, and although the amount of nitrogen volatiles appears to increase as temper-
ature increases, this is believed to be partially offset by a decrease in percentage conversion.
Furthermore, operating restrictions severely limit the magnitude of actual temperature changes at-
tainable in current systems.
       As described above, fuel NO emissions are a strong function of fuel/air mixing.  In general,
any change which increases the mixing between the fuel and air during coal devolatilization will
dramatically increase volatile nitrogen conversion and increase fuel NO.   In contrast, char NO for-
mation is only weakly dependent on initial mixing and therefore may represent a  lower  limit on the
emission level  which can be achieved through burner modifications.
       From the above modifications, it appears that, in principle, the best strategy  for fuel NO
abatement combines low excess air firing, optimum burner design, two-stage combustion  and high air
preheat.   Assuming suitable stage separation, low excess air may have little effect on fuel NO, but
it increases system efficiency.  Before using LEA firing, the need to get good carbon  burnout and
low CO emissions must be considered.
       Optimum burner design ensures locally fuel-rich conditions during devolatilization, which
promotes  reduction of devolatilized nitrogen to N2>  Two-stage combustion produces overall fuel-rich
conditions during the first 1 to 2 seconds and promotes the reduction of NO to NZ through reburning
                                               4-18

-------
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-------
reactions.  High secondary air preheat also appears desirable, because  it  promotes  more complete
nitrogen devolatilization in the fuel-rich initial combustion stage.  This  leaves less  char nitrogen
to be subsequently oxidized in the fuel-lean second stage.  Unfortunately,  it also  tends  to favor
thermal NO formation, and at present there is no general agreement on which effect  dominates.

4.2.1.3  Summary of Process Modification Concepts

       In summary of the above discussion, both thermal and fuel  NOX are kinetically or aerodynami-
cally limited in that their emission rates are far below the levels which would prevail at  equilib-
rium.  Thus, the rate of formation of both thermal and fuel NOV is dominated by combustion  condi-
                                                              A
tions and is amenable to suppression through combustion process modifications.  Although  the
mechanisms are different, both thermal and fuel NOX are promoted by rapid mixing of oxygen  with the
fuel.  Additionally, thermal NO  is greatly increased by long residence time at high temperature.
The modified combustion conditions and control concepts which have been tried or suggested  to combat
the formation mechanisms are as follows:

       t   Decrease primary flame zone 0~ level by

           —   Decreased overall Op level

           —   Controlled mixing of fuel and air

           -   Use of fuel rich primary flame zone

       •   Decrease time of exposure at high temperature by

           -   Decreased peak temperature:

               —   Decreased adiabatic flame temperature through  dilution

               -   Decreased combustion intensity

               —   Increased flame cooling

               -   Controlled mixing of fuel and air or use of fuel  rich primary flame  zone

           -   Decreased primary flame zone residence time

       •   Chemically reduce NOX in post-flame region by

           -   Injection of reducing agent

       Table 4-4 relates these control  concepts to applicable combustion process modifications and
equipment types.   The process modifications are further categorized according to their  role in the
control  development sequence:   operational adjustments, hardware  modifications of existing  equipment
                                                4-20

-------
TABLE 4-4.  SUMMARY  OF COMBUSTION  PROCESS  MODIFICATION  CONCEPTS
Combustion
Conditions

Decrease
primary
flame zone
02 level
Decrease
peak
flame
temperature
Chemically
reduce NOX
in post-
flame region
Control
Concept
Decrease overall
02 level
Delayed mixing
of fuel and air
Increased fuel/
air mixing
Primary fuel-
rich flame
zone
Decrease
adiabatic flame
temperature
Decrease
combustion
intensity
Increased flame
zone cooling/
reduce residence
time
Inject reducing
agent
Applicable
Equipment
Boilers, furnaces
Boiler, furnaces
Gas turbines
Boilers,
furnaces, 1C
Boilers,
furnaces, 1C,
gas turbines
Boilers, furnaces
Boilers, furnaces
Boilers, furnaces
Effect on
Thermal NOX
Reduces 02-rich,
high-NOx pockets
in the flame
Flame cooling and
dilution during
delayed mix re-
duces peak temp.
Reduces local hot
stoichiometric
regions in over-
all fuel lean
combustion
Flame cooling in
low-02, low- temp.
primary zone re-
duces peak temp.
Direct suppres-
sion of thermal
NO mechanism
A
Increased flame
zone cooling
yields lower
peak temp.
Increased flame
zone cooling
yields lower
peak temp.
Decomposition
Effect on
Fuel NOX
Reduces exposure
of fuel nitrogen
intermediaries
to 0-
Volatile fuel N
reduces to N2 in
the absence of
oxygen
Increases
Volatile fuel N
reduces to N2 in
the absence of
oxygen
Ineffective
Minor direct
effect; indirect
effect on mixing
Ineffective
Decomposition
Primary Applicable Controls
Operational
Adjustments
Low excess air
firing
Burner
adjustments
Improved atomi-
zation
Burners out of
service; biased
burner firing
Reduced air
preheat
Load reduction
Burner tilt

Hardware
Modification
Flue gas recircu-
lation (FGR)
Low NOX burners

Overfire air
ports, stratified
charge
Water injection,
FGR


Ammonia injection
possible on some
units
Major
Redesign

Optimum burner/
firebox design
New can design;
premix, prevap.
Burner/firebox
design for two-
stage combustion

Enlarged firebox,
increased burner
spacing
Redesign heat
transfer sur-
faces, firebox
aerodynamics
Redesign convec-
tive section for
NH3 injection

-------
or through factory-Installed controls, and major redesigns of new equipment.  The controls for de-
creased 02 are also generally effective for peak temperature reduction but have not been repeated.
The following subsections review the status of each of the applicable controls.

4.2.2  Low Excess Air Firing
       Reducing the total amount of excess air supplied for combustion is an effective demonstrated
method for reducing NO  emissions from utility and industrial  boilers, residential and commercial
furnaces, warm air furnaces, and process furnaces.   Low excess air (LEA) firing reduces the local
flame zone concentration of oxygen, thus reducing both thermal and fuel  NOX formation.  LEA firing
is easy to implement and increases efficiency.  It is, therefore, used extensively in both new and
retrofit applications, either singly or in combination with other control measures.   The ultimate
level of excess air is limited by the onset of smoke or carbon monoxide  emissions which occurs when
excess air is reduced to levels far below the design conditions.   Fouling and slagging may also in-
crease in heavy oil- or coal-fired applications at very low levels of excess air.
       Low excess air firing is the most widespread NO  control  technique for utility boilers.  This
technique was initially implemented to increase thermal  efficiency and reduce stack gas opacity due
to acid mist.  A number of studies have shown LEA firing to be effective in reducing NOX emissions
without significantly increasing CO or smoke levels (References  4-22, 4-32 through 4-47).   The major
findings are summarized in Table 4-5.
       Firing with excess air levels below 5 percent is  now standard practice on many large oil-  and
gas-fired boilers (Reference 4-32).  Reductions in  NOX levels  average between 15 and 20 percent,
although reductions up to 30 percent for gas and 35 percent for oil-fired boilers have been reported
(References 4-34, 4-40).  For tangentially-fired boilers, practical minimums of approximately 3 to
7 percent excess air for natural gas and oil firing are recommended.  Operating at 10 percent higher
excess air than the minimum established will normally increase NO  emissions by an average of 20
percent for all fuels in these units (Reference 4-38).
       With coal-fired boilers, the minimum practical levels of excess air are higher than for oil
and gas.   Typical  values are 8 to 12 percent, but in some existing units, excess air levels below 15
to 18 percent present operating problems (Reference 4-35).  For tangentially-fired units, minimum
levels of 18 to 25 percent are recommended (Reference 4-38).  For both wall-fired and tangentially-
fired units,  reductions from 12 to 20 ppm (0 percent 02 basis) for each percentage point reduction
in excess air level  have been observed (References  4-35, 4-39, 4-40, and 4-44).  The average  reduc-
tion in NOX levels due to LEA is approximately 20 percent from baseline conditions.  For one
                                                4-22

-------
TABLE 4-5.   SUMMARY OF RESULTS  WITH  LOW  EXCESS AIR  FIRING
Equipment Category/
Fuel
Utility boilers
Gas
Oil
Coal (except
cyclone
boilers)
Industrial water-
tube boilers
Gas
Oil
Coal
Control Method/
Range
Reduce EA to
2% to 5%
Reduce EA to
3% to 7%
Reduce EA to 20%
or lower
Similar to utility
boilers; same
degree of EA reduc-
tion not always
feasible


N0x
Reduction
Up to 30%
Avg =16%
Up to 35%
Avg =19%
Up to 30%
Avg =20%
Wide variations
reported. Ap-
proximately 5%
reduction in
NOX for each
one percent re-
duction in ex-
cess 02- Units
with preheated
air exhibit
greater reduc-
tions than units
with no preheat.
7% reduction NOX
for each one per-
cent reduction in
excess 02
12.5% reduction
in NOy for each
1% reduction in
excess 02
Effect On
Operation/
Maintenance
Flame instability
excess CO & HC
emissions may
occur
Above plus soot,
acid smut possible
Above plus slagging
and corrosion pos-
sible; carbon in
flyash may affect
ESP
Greater operator
surveillance re-
quired to assure
excessive CO & HC
emissions or flame
instability do not
occur
In addition to the
operational prob-
lem above, corro-
sion and slagging
are possible. May
reduce 503.
Efficiency/
Fuel Consumption
Up to 1%
increase
in efficiency
Up to 1.5%
increase
in efficiency
Efficiency in-
creases 0.1% per
1% decrease in
excess air
Extent
Used
Used in all ret-
rofit programs;
no new units be-
ing built
Widely used new
and retrofit
Increasing use for
conservation; in-
clude in new unit
design
R&D
Status
Retrofit develop-
ment to counter
operating
problems
Included as part
of all advanced
control designs
Include in R&D
on external con-
trols & low NOX
burners
                                                                               (continued on p.  4-24)

-------
                                                                          TABLE 4-5.  Concluded
Equipment Category/
Fuel
Industrial firetube
boilers
Gas and oil
Residential warm
air furnaces
Gas and dis-
tillate oil
Internal combus-
tion engines
Gas, dual fuel
and diesel
Control Method/
Range
See industrial WT
and utility boilers
Ineffective in
existing units; EA
reduction from 80%
to 15% achieved in
new low NOX units
with combined NOX
controls
Leaner settings of
A/F ratio by either
reducing fuel input
(essentially de-
rating) or by
increasing the air
input (through in-
stallation or re-
placement of turbo-
charger)
NOX
Reduction
Approximately 5%
reductions NOX
per ]% reduction
in excess 02
No consistent
trend apparent.
Up to 10% reduc-
tions possible.
Reductions of
up to 4.5% NOX
for 1% decrease
in A/F ratio re-
ported. Turbo-
charged and gas-
fired units
show greatest
decreases.
Effect On
Operation/
Maintenance
See industrial
WT boilers
Possible increased
maintenance
frequency
None
Efficiency/
Fuel Consumption
Same as for in-
dustrial WT
boilers
Efficiency in-
creases by
0.1-0.15% per
one percent de-
crease in excess
air
Slight increase
in efficiency
Extent
Used
Prototype only
Increasing use in
new units
Not used;
prototype only
R&O
Status
Include in R&D on
low NOX burners
and external
controls
Development of
burners operat-
ing at lower
excess air
levels (see
Section 4.2.6)
Include in com-
bustion chamber
redesign
i
r\>

-------
turbo-fired unit tested, reductions of approximately 24  ppm for each 1  percent decrease  1n  excess
air level  were noted (Reference 4-35).  Cyclone  boilers  are not well  suited for NO   control  by  LEA
firing.   Excess air levels In cyclone boilers  are  restricted to a  narrow operating  range  to prevent
corrosion and maintain furnace slagging conditions (References 4-41,  4-42).
       The minimum practical level of excess air which can  be achieved  1n existing  boilers,  without
encountering operational problems, depends  upon  factors  in  addition  to  the type of  fuel  fired.
These factors include low load operation, nonunlformity  of  air/fuel  ratio, fuel  and air control lags
during load swings, use of upward burner tilt  to increase steam superheat (for tangentially-fired
boilers), and coal quality variation and ash slagging potential  (for coal-fired boilers).  They tend
to increase the minimum excess air level at which  the boiler can operate safely.
       Other factors such as secondary air  register settings and steam  temperature  control flexibil-
ity also affect the excess air levels.  The boiler combustion control system must be modified so
that the proportioning of fuel and air is adequate under all  operating  conditions.  Uniform distri-
bution of fuel and air to all burners is increasingly important as excess  air  is lowered.  Excess
air levels are also affected if other NO  control  techniques  are employed.   Off-stoichiometric
combustion and operating at reduced load increases the minimum excess air levels whereas switching
from eastern to western coals would decrease the levels  (References  4-34,  4-44,  and 4-48).
       The excess air level setting of a utility boiler  may be affected by considerations other than
the operating limit set by excessive smoke  and CO  emissions.   The maximum plant  efficiency does not
necessarily occur at the minimum excess air level  (Reference 4-47).   For example, problems with
slagging arise in lignite-fired boilers if  excess  oxygen drops below  about 2.5  percent in the fur-
nace (Reference 4-49).  In addition, certain high  sulfur eastern coals  may increase corrosion, if
the excess air is dropped to levels such that  local  reducing  atmosphere pockets  occur (Reference
4-50).  Medium-term tests using corrosion coupons  did not show significantly accelerated rates of
corrosion (Reference 4-35); long-term test  results on actual  furnace  tubes are  underway to clarify
the problem.  New boilers are designed to overcome some  of  the operational  problems associated with
LEA, making it possible to operate at lower levels of excess  air.
       LEA firing is a very effective method for controlling  NOX in  industrial  boilers.  Although
it is not in widespread use as a NOX control technique for  industrial boilers,  LEA  is generally con-
sidered as part of an energy conservation program.   NOX  reductions of up to  44 percent of baseline
levels and efficiency increases up to 2.5 percent  have been reported  (Reference 4-51) using  LEA
firing.  But, it is usually not feasible to reduce the amount of excess air to the  levels used  in
                                                 4-25

-------
utility boilers, since industrial  boilers are required to function automatically over wide variations
of load with a minimum of operator supervision.
       The results of several  studies on industrial  and packaged boilers (References 4-45, 4-52, and
4-53) are summarized in Table 4-5.  Coal-fired watertube boilers showed the largest and most consis-
tent drops in NOX levels, averaging 72 ppm (0 percent 02 basis) for each percent change in excess 02.
Residual oil-fired watertube boilers averaged 24 ppm reduction per 1 percent decrease in 02> while
distillate oil-fired boilers averaged about half that amount.   In most cases, N0x decreased steadily as
excess CL was reduced.  However, for equipment with  premixed burners, the emissions first increase, and
then decrease when the level of excess air is reduced.  For gas-fired watertube boilers, no consistent
reduction in NO  with lowering of excess air is apparent, unless the combustion air is preheated.  For
               X
firetube boilers, an average reduction of 7 ppm for  each 1  percent reduction in excess 02 was observed.
However, for baseline levels lower than 240 ppm, firetube boilers were not very sensitive to excess
02 levels.
       LEA firing is used primarily in residential and commercial furnaces to increase the heater
efficiency, not to control NO .   As excess air is decreased in a furnace, the CO,  HC,  and smoke
levels are minimized, whereas NO  emissions are maximized.   Normal operation of a  furnace is usually
bounded by excessive CO levels at high values of excess air, and excessive smoke levels at low values
of excess air.  However, since the furnace efficiency increases with decreasing excess air levels,
furnaces are usually tuned to operate at the lowest  possible excess air supply for which the flue
smoke level is acceptable.
       The minimum excess air levels for typical warm air furnaces vary widely, ranging from 20 to
80 percent.  The change in NOX emissions from decreasing the excess air therefore  varies.
Table 4-5 summarizes the results of studies on residential  heaters (References 4-51, 4-54, 4-55,
and 4-56).  The trend for warm air furnaces is towards developing burners which will operate at
lower values of excess air to reduce NOX emissions,  while increasing efficiency.  An optimum geom-
etry burner operating at about 15 percent excess air has been designed and tested (Reference 4-57).
Most existing furnaces, however, must operate at excess air levels much higher than 15 percent, as
the heat exchangers are not designed to withstand the flame temperatures resulting from very low
excess air firing (Reference 4-58).  This is discussed further in Section 4.2.6.
       Changes in air-to-fuel  ratio can be used to control  NOX in internal combustion (1C) engines.
NOX emissions are highest from 1C engines at air/fuel ratios slightly higher than stoichiometric.
                                               4-26

-------
Decreasing the ratio towards fuel-rich  conditions  decreases NOX but sharply Increases CO and HC
emissions.  Therefore, the most practical  use of adjusting the air-to-fuel  ratio Is to change the
setting towards leaner operation.   Injection-type  engines are best suited for this  technique since
better control of the air-to-fuel  ratio between  cylinders would be necessary for carburetted en-
gines to approach lean limit operation.   Reference 4-43 surveys the use of  changes  1n the  air-fuel
ratio as a NOX control technique for  1C engines; their findings are summarized in Table 4-5.
       In gas turbines, the overall air-fuel  ratio cannot be modified to control  NO ,  since  the
ratio is determined by the turbine Inlet temperature.   However, local  changes in  the  air-fuel  ratio
may be employed to control NOX-  This is discussed further in Section 4.2.6,  Burner Modifications.
       •Limited data are available  on  the effect  of LEA on industrial  process  furnaces.   In some
cases, the level of excess air may be dictated by  process requirements (Reference 4-59).  Data on
some gas and oil burners  used in process furnaces  show NO  emission reductions  of 2 to  3 percent
for each  1 percent decrease in excess air (References  4-60, 4-61).   An EPA-IERL/RTP study was
recently completed to collect detailed information on  NO  control  methods used  in industrial process
furnaces  (Reference 4-62).
       In summary, changing the overall  fuel-air ratio to control  NO   emissions is  a  simple, feasi-
ble, and effective technique for stationary sources of combustion,  with the  exception of gas turbine
engines.  For certain applications such as utility boilers, LEA firing is presently considered a
routine operating procedure and is incorporated  in all  new units.   Since it  is  efficient and easy
to implement, LEA firing  will see  increasing  use in other applications.   Most sources will require
additional control methods, in conjunction with  LEA, to bring NO  emissions within statutory limits.
In such cases, the extent to which excess  air can  be lowered will  depend upon the other control
techniques employed.  However, virtually all  developmental  programs for advanced  N0x  controls are
placing emphasis on operation at minimum levels  of excess air.   LEA will  thus be  an integral part of
nearly all combustion modification NO  controls, both  current and  emerging,  to  be assessed in the
NOX E/A.

4.2.3  Flue Gas Recirculation
       Recirculation of flue gas (FGR)  or  exhaust  gas  (EGR)  is  a proven  NOX control technique in
which a quantity of combustion products  are externally  recycled into  the primary  combustion air.
The recirculated flue gas dilutes  the reactants, reduces  the attainable  peak  flame temperatures,
and reduces the local  oxygen concentration, thereby lowering the amount of thermal  NOX  formed
(Reference 4-32).   Table 4-6 summarizes  the status  and  effectiveness  of FGR  as  applied  to  stationary
source  combustion equipment.   Throughout  this section,  the amount  of flue gas  recirculation will
                                                4-27

-------
                                                       TABLE  4-6.   SUMMARY  OF  RESULTS WITH  FLUE  GAS  RECIRCULATION
Equipment Category/
Fuel
Utility boilers
Gas
Oil
Coal
Industrial water-
tube boilers
Gas
Oil
Industrial fire-
tube boilers
Oil
•
Control Method/
Range
From 15% to 20%
recirculation of
flue gases to wind-
box; >50% used in
some cases; typi-
cally used with LEA

24% to 33% recircu-
lation of 'flue
gases with combus-
tion air in windbox
Up to 40% recircu-
lation of flue gas
in windbox
NOX
Reduction
Average about
50%
Up to 30%
Up to 15%
Up to 73%
reported
Up to 35%
reported
Up to 40%
Effect On
Operation/
Maintenance
Smoking excessive
vibrations, and
flame instability
occur at high re-
circulation rates
Flame instability
and blowouts at
high recircula-
tion rates
Flame instability
and blowouts at
high recircula-
tion rates
Efficiency/
Fuel Consumption
Small decrease
due to fan re-
quirement
None
None
Extent
Used
Widely used
retrofit; no new
units being built
Negligible
Prototype only
Prototype only
R&D
Status
Retrofit develop-
ment to combat
operational
problems
Inactive
Evaluation for new
unit design
Evaluation for new
unit design
A
I

-------
TABLE 4-6.  Concluded
Equipment Category/
Fuel
Gas turbines
Gas
Oil
Internal combustion
engines
Gas
Dual fuel
Diesel
Control Method/
Range
Up to 26% recircu-
lation of exhaust
gas
Internal recircu-
lation by retard-
ing valve timing,
increasing back
pressure, or reduc-
ing scavenging in
2-stroke engines;
or external recir-
culation, up to 12%,
of exhaust gases to
the intake manifold
(preferably with in-
tercooling of ex-
haust gases)
NOX
Reduction
30% reported
38% reported
Up to 37%
reported
Up to 25%
reported
Up to 35%
reported
Effect On
Operation/
Maintenance
Efficiency/
Fuel Corns umpti on


Increased fouling
of valves and flow
passages, increased
smoke generation,
and contamination
of lubrication oil
possible
Increase in fuel
consumption from
1% up to 8%
reported
Extent
Used
Only on experi-
mental combustors
Only on experi-
mental engines
R&D
Status
Inactive; emphasis
on HgO injection,
can design
Inactive; emphasis
on chamber re-
design for new
units

-------
be defined as the weight fraction of recirculated flow relative to the total flow of  incoming  com-
bustion air plus fuel.
       FGR is widely used in utility boilers burning natural gas, since natural gas combustion pro-
duces mainly thermal NO .  However, since natural gas is becoming less available, utility boilers
                       A
have had to switch to oil.  This has resulted in FGR becoming more prevalent in oil-fired units.
The prospect for FGR on new utility boilers appears unlikely, since no new large oil- or gas-fired
units are planned (Reference 4-63).  Coal-fired units rarely use FGR for N0x control, and the pros-
pect of significant application of FGR to these units appears to be small.  Recent tests, for example,
conducted on a utility boiler burning coal show that flue gas recirculation is ineffective in con-
trolling fuel NO  (Reference 4-64).
       With gas-fired units, NOV reductions of 50 to 70 percent were obtained with 10 to 15 percent
                               X
recirculation rates.  About 45 percent NOX reduction was attained with oil-fired units, but only 15
percent NOV reduction was realized with one coal-fired unit, with flue gas recirculation rate of
          A
about 15 percent.
       Power boilers are usually designed for recirculation of a portion of the flue gases to con-
trol steam superheat temperatures.  However, when this type of control is used, the flue gases are
injected into the bottom of the furnace to reduce the effectivenesss of the radiant section.  This
procedurev however, is relatively ineffective in suppressing NO  (Reference 4-65).
       Retrofit addition of FGR involves addition of ductwork and recirculation fans to convey the
flue gas from a position upstream of the air preheater (344C, 650F) to mix with the preheated com-
bustion air.  The specific modifications required and the operational results are very much depen-
dent on the unique characteristics of the boiler.  On some units, high FGR rates have resulted in
serious operational problems (References 4-66, 4-67).  Boiler vibration and flame instability have
resulted from the higher burner velocities and higher throughput in the furnace.  On most units,
these problems have been successfully combatted through control development tests, usually involving
burner adjustments.  The higher throughput in the furnace with FGR has also resulted in derating of
some units.
       The few new oil and gas boilers designed with FGR have not encountered any operational problem
and have achieved excellent NOX reductions (Reference 4-47).  When combined with other control
methods such as off-stoichiometric combustion, FGR has been effective with limited recirculation  rates.
                                                 4-30

-------
       FGR has been tried only experimentally on Industrial  boilers  (References  4-53, 4-68).  Recent
tests performed on Industrial boilers show that FGR  1s  very  effective  1n  suppressing NO   for gas-
                                                                                       A
fired units.   Mixed results were obtained when FGR was  used  on oil-fired  watertube boilers.  In one
case, NOX reductions of 35 percent were obtained with 24 percent  recirculation (Reference 4-53);
and in another case, only a small (0 to 3 percent) amount of reduction was achieved (Reference 4-68).
Both the boilers experienced flame instability at recirculation rates  above 25 to 27 percent.
       FGR was found to be effective in the case of  an  oil-fired  firetube boiler; approximately 30
percent NOX reduction was obtained with 40 percent recirculation  (Reference 4-68).  This result in-
dicates that effectiveness of FGR in suppressing NOX emissions was dependent upon boiler type.
       Only a few experiments have been conducted on gas turbines with exhaust gas recirculation
 (EGR).  Tests performed on a one-half scale combustor show that NOX  reductions of 38 percent for
 oil and 30 percent for gas were achieved, with an exhaust gas recirculation rate of 26 percent.   No
 adverse effects due to EGR were detected on hydrocarbon and  carbon monoxide emissions.   The tests
 are not conclusive, however.  For oil-fired units, at combustor exit temperatures below 1500F,  emis-
 sions are greater with EGR than with no exhaust gas  recirculation.  However, for gas-fired units,
 EGR reduces NO  emissions for the entire range of combustor  exit  temperature (Reference 4-69).   EGR
 is not being actively pursued in the low-NO  gas turbine combustor development programs.
                                           A
       On 1C engines, EGR can be accomplished by either recycling exhaust gases into the intake
 manifold  (external EGR) or by restricting the discharge of gases  that would normally be exhausted
 from  the  cylinder  (internal EGR).  Externally recirculated gases  can also be cooled before they  are
 reintroduced into the cylinder (Reference 4-43).
       The only data available on the use of cooled, external EGR in large bore engines were for a
 two-stroke blower scavenged test engine.  The use of 20 percent cooled EGR at rated conditions  re-
 sulted in a 55 percent NOX reduction and an increase in smoke to  17 percent opacity.   HG emissions
 were  unchanged and CO emissions increased 72 percent.   By comparison, 20  percent hot EGR resulted
 in NO  reductions of 51 percent at rated conditions  and smoke increases to 27.5 percent opacity.  HC
 emissions were reduced 17 percent and CO emissions were increased 167 percent.   Similar trends were
 reported on tests of cooled EGR on truck-sized engines.
       Internal EGR is available for both two- and four-stroke engines, either naturally-aspirated
 or turbocharged.  It can be used with turbocharged models, due to their leaner operation.  Some  of
 the operational problems encountered include severe  fuel penalties, engine starting difficulties,
                                                4-31

-------
and increased smoke generation.  The primary maintenance problem with E6R systems  is  that  solid  ex-
haust products accumulate in the recirculating system.  This problem is more acute for diesel en-
gines.  When EGR is applied to naturally-aspirated engines, the deposits build up  in  the ducts or
the valves used to control the recirculation rate, and may build up on the intake  valves.
       EGR has only been tried experimentally for internal combustion engines; it  has not  been pur-
sued further because of operational/maintenance problems and the absence of regulations to limit NO
emissions from these sources.
       Tests conducted on a prototype residential oil burner fired at 1  ml/s (0.951 gph) showed FGR
to yield NO  reductions comparable to burner modifications (Reference 4-56).  NOX emission rates of
0.58 g/kg fuel, compared to 2 to 3 g/kg fuel uncontrolled, resulted with 30 percent FGR.   FGR has
not been pursued for residential systems, however, since burner modifications have proven  simple
and less expensive for a comparable level of control  (Reference 4-57).
       In summary, the primary near-term application of FGR is in gas- and oil-fired utility boilers.
Emerging applications are limited.  FGR may see use in industrial boilers on a retrofit or new design
basis, but alternate approaches, e.g., low-NOx burners, off-stoichiometric combustion, are also
being evaluated and may prove more attractive.  Other techniques are more effective for coal-fired
utility boilers, gas turbines and warm air furnaces.   The effectiveness  of FGR with process furnaces
is under evaluation.
4.2.4  Off-Stoichiometric Combustion
       Off-Stoichiometric Combustion (OSC) is a NO  control  technique in which the mixing of fuel
with combustion air is controlled by the use of overfire air (OFA) ports, firing with some burners
out-of-service (BOOS), or biased firing.  Generally, substoichiometric conditions prevail locally
in the primary combustion zone; complete combustion occurs downstream of the burners.  OSC reduces
both thermal and fuel NOX-  Lowering the availability of oxygen in the primary flame zone inhibits
fuel nitrogen conversion, while interstage cooling by flame radiative transfer reduces peak tempera-
tures, which, coupled with the reduced availability of oxygen, decreases the production of thermal NO .
       OSC is a fairly common method of NOX control for utility and large industrial boilers.  It
is usually implemented after simpler techniques, such as low excess air firing, fail to reduce NO
                                                                                                 X
levels below statutory requirements.  Most large boilers, commissioned after 1971 are equipped with
OFA ports.  Older boilers with multiple burners can be adapted to OSC by biased firing, i.e., firing
some burners fuel-rich and others air-rich, or by taking some burners out of service, i.e., oper-
ating them on air only.   Operating on air only, however, may result in a derating of the  units if
                                                4-32

-------
the active burners or fuel delivery system  do  not  have  the capacity to  carry the  extra  fuel  re-
quired to maintain full load.
       Utility boilers have been tested extensively  with  OSC  (References  4-24,  4-32  through  4-41,
4.44, 4-47, 4-49, 4-63, 4-64, 4-70 through  4-79).  Results are summarized in Table 4-7.  Gas-fired
boilers show the greatest reductions  in NOX, with  maximum reductions  of approximately 70 percent
achieved with BOOS firing on one wall-fired and  one  tangentially-fired  unit  (References 4-33, 4-37).
Typical reductions for gas-fired utility  boilers are around 45 to  50  percent (References 4-37, 4-40,
4-73).  Oil-fired boilers are less responsive  to OSC, with normal  decreases  in  NO levels between
25 and 35 percent, although a 55 percent  reduction has  been reported  for  one tangentially-fired
unit with BOOS firing (References 4-33, 4-37,  4-40,  4-73, 4-74).   For coal-fired  boilers operated
with BOOS firing, most NOX reductions  fall  between 30 to  40 percent,  with  50 percent or over
achieved in a few cases (References 4-35, 4-37,  4-40, 4-41, 4-44,  4-64, 4-73, 4-75).
       Recently some tests have been  performed on  tangential  coal-fired boilers equipped with OFA
ports.  NOX levels decreased by 20 to  30  percent when approximately 15 percent of the total  combus-
tion air was diverted through the OFA  ports (References 4-24,  4-39).  A preliminary report on
western coals fired in tangential units, with  95 to  100 percent stoichiometric air at the burners,
showed up to 30 percent reduction in  NOX  emissions (Reference  4-76).  Similarly, both wall-fired
and tangential boilers firing lignite  decreased  NO  emissions  by about  30  percent when the air at
the burners was reduced to approximately  95 percent  of  stoichiometric (Reference 4-49).
       In other tests, a coal-fired Turbofurnace was tested with a few  burners  near the ends of each
 row operated on air only.  NO  reductions of up  to 10 percent resulted when  the air to active burners
was reduced to 80 percent of stoichiometric (Reference  4-35).   However, an attempt at firing one
coal-fired cyclone boiler off-stoichiometrically by  operating the  upper cyclones  under  fuel-lean
conditions did not reduce NO  emissions (Reference 4-41).   A  similar  attempt with an oil-fired
                            X
cyclone boiler, with the upper cyclones operated on  air only  and with an  increase in fuel supply to
the lower cyclones to maintain load,  actually  increased N0x emissions by  50  percent  (Reference 4-40).
       OSC presents a number of potential operational problems when applied  to existing units.  As
mentioned earlier, if a unit does not  have OFA ports, firing with  BOOS can cause  derating, especially
in older coal-fired units with limited pulverizer  capacities.   The best BOOS firing  pattern  for
N0x reduction must be determined empirically for an  individual  boiler.  In general,  air-only burners
in the top row give the best results;  this  configuration  most  closely simulates overfire air  injec-
tion and, hence, two-stage combustion.  In  tests on  two wall-fired oil  units, with four rows
of burners and OFA ports, the optimum  firing pattern was  to have the  third row  from  the bottom
                                                4-33

-------
TABLE 4-7.  SUMMARY OF RESULTS WITH OFF-STOICHIOMETRIC COMBUSTION
Equipment Category/
Fuel
Utility boilers
Gas
Oil
Coal
Industrial boilers
Gas
Oil
Coal
Control Method/
Range
Reduce oxygen level
in primary flame
zone by firing some
or all burners fuel-
rich at about 85% to
95% theoretical air.
Remaining 15% to 25%
of total combustion
air supplied
through OFA ports,
BOOS, or biased
burners; typically
used with LEA.
Similar to that
for utility
boiler
NOX
Reduction
Average between
45% and 50%
Normally between
25% and 35%
Normally between
30% and 40%
Up to 55%
reported
Up to 50%
possible
Up to 39%
reported
Effect On
Operation/
Maintenance
Load curtailment,
flame instability
boiler vibrations,
and excessive CO
and smoke emis-
sions may occur
with retrofit use
In addition to
above, corrosion
and slagging prob-
lems may arise
Similar to those
for utility boilers
for retrofit use
Efficiency/
Fuel Consumption
Generally little
or no adverse
effect
None in new
units; possible
1% decrease with
retrofit
Decrease in
efficiency up
to 3% to 4%
possible
Maximum decrease
of 1% reported
Decreases up to
2% reported
Extent
Used
Retrofit use on
over 100 boilers
in the U.S.;
usage increasing
Inclusion in most
new unit designs
(OFA)
Prototype only
R&D
Status
Retrofit develop-
ment to combat
operational
probl ems
Evaluate corro-
sion potential
(near term);
advanced stag-
ing concepts
(long term)
Evaluation for
new unit design

-------
firing air only.   In these tests, OFA ports used  alone resulted In much lower NOX reductions.   But,
using the combination of BOOS and OFA firing  did  not  result 1n  significant  reductions  from using
BOOS alone (Reference 4-74).
       Fewer BOOS patterns are available  for  staging  with  coal-fired boilers,  since  1t usually  is
not possible to close off Individual coal burners from a pulverizer.  Thus,  all  burners fed by  a
pulverizer are either active or on air only.   In  some coal-fired boiler tests  where  it has  been
possible to vary BOOS patterns systematically, burners firing air only  on the  top rows and on the
outer edges of the burner matrix (for wall-fired  units) tend to be most effective in reducing NO
emissions at full load (References 4-36,  4-39, 4-44,  4-64).  At reduced loads  it  is  not possible
to generalize which BOOS patterns result  in greatest  reductions.   In  one test, at very low load,
all BOOS firing patterns tested increased NOX emissions.   This  increase is attributed  to the in-
creasing levels of excess air required with decreasing load, that make  it impossible to achieve
substoichiometric conditions under any combination of BOOS (Reference 4-44).
       In most of the tests reported, NOX emissions decrease steadily as the stoichiometric air to
active burners is reduced.  Excessive smoke and CO levels  generally limit the extent to which the
burners are fired fuel rich.  The fuel-rich conditions can lead to flame instability, and for coal-
fired boilers, the reducing atmosphere in the primary combustion  zone can accelerate tube corrosion
and slagging (Reference 4-50).
       Two utility companies have recently reported operational  experience with combined OSC and
FGR for gas- and oil-fired boilers (References 4-34,  4-74).  Problems encountered included flame in-
stability, boiler vibrations, load curtailment, restricted boiler load  response capability, tube
failures and stack smoking conditions.  Another utility company reported experience with retrofit
biased firing on a coal-fired boiler; problems reported included increased carbon  losses, decreased
boiler efficiency of about one percentage point at all  load levels and  possible increased tube
wastage on the sidewall near the biased burners (Reference 4-44).   The  IERL/RTP is conducting long-
term field tests to accurately determine  the  effect of OSC on tube wastage.  Corrective measures to
suppress tube wastage are also being examined.  One utility boiler manufacturer uses a  "curtain air"
oxidizing atmosphere at the tube walls to suppress wastage and  control  slagging  (Reference 4-75).
       Few existing industrial boilers have off-stoichiometric  firing capability,  since most smaller
units have only one or two burners and do not come equipped with  OFA  ports.  Large industrial boilers
have multiple burner assemblies which can be  operated with BOOS firing,  although  this  usually results
in a derating of the unit.
                                                4-35

-------
       In actual field tests on a number of Industrial watertube boilers (References 4-53, 4-80),
BOOS firing .achieved maximum reductions in NOX emissions of up to 55 percent for gas-fired boilers,
31 percent for oil-fired boilers, and 39 percent for coal-fired boilers.  These tests showed that
in many cases the overall excess air levels had to be increased during BOOS firing to prevent smok-
ing.  In addition, a square burner pattern proved more effective than a staggered pattern.  And,
removing inner burners in the top row was more effective than other burner changes in controlling
NO  emissions.  Some tests with OSC were also performed on stoker-fired coal units equipped with
  A
air ports, or with auxiliary oil or gas burners which could be fired with air only located above the
grate.  With these units, NO  reductions of up to 26 percent were reported.  However, OSC is not
                            A
effective in cases where baseline NOV levels are already low (Reference 4-53).
                                    A
       Most small to medium size watertube boilers and all firetube units do not have multiple bur-
ners and therefore cannot be'fired using BOOS or biased firing.   These units can be fired off-
stoichiometrically only by installing overfire or side fire air ports.   Recent experimental  results
are available on single burner, oil- and gas-fired, watertube and firetube industrial boilers
equipped with hardware modifications to allow for injection of air downstream of the burner (Refer-
ences 4-52, 4-53).  These results are mixed, although NO  reductions up to 50 percent were reported
for oil- and gas-firing in one watertube unit with side fire air injection.  In two cases of gas-fired
units (a watertube and a firetube boiler), no significant reductions in NOX were obtained with OSC.
Moreover, in the firetube boiler, there was an obvious minimum burner stoichiometry; NO  levels
reached a minimum before rising again as the stoichiometric air to the burner was decreased.   This
behavior is contrary to the behavior of utility boilers and may be due to low-burner momentum under
OSC inhibiting fuel-air mixing close to the burner.
       Operational problems with OSC in industrial boilers are not well documented but are expected
to be similar to the problems experienced in utility boilers.   Some of the problems may never occur
since higher levels of excess air are used in industrial boilers than in utility boilers, and the
overall  excess air levels increase with OSC.  However, increasing the excess air level generally
decreases efficiency.   But, in some tests the reductions in efficiency were usually less than 1 per-
cent (Reference 4-53).   In experiments where overall excess air was carefully controlled, a slight
increase in efficiency resulted (Reference 4-52).
                                                *
       In summary, off-stoichiometric combustion is a widely used, demonstrated technique for control
of thermal  and fuel  NO  from large boilers.   Near-term applications to be considered in the NO  E/A
                      A                                                                       x
include  retrofit use on gas-, oil- and coal-fired utility boilers and use of factory-installed con-
trols  on new coal-fired utility boilers.  Potential emerging applications to be considered include
                                               4-36

-------
use of factory-installed controls on new Industrial  boilers  and use of advanced staging  techniques
for major redesign of utility or industrial  boilers.

4.2.5  Load Reduction
       Thermal  NOX formation generally increases  as  the  volumetric  heat release rate or  combustion
intensity increases.  Reduced combustion intensity can be  brought about by  load reduction, or
derating, in existing units and by use of an enlarged firebox  in new units.  The reduced heat re-
lease rate lowers the bulk gas temperature*  in nonadiabatic  furnaces such as boilers.  Lower bulk
gas temperature in turn, significantly decreases  NOX emissions  (Reference 4-71).
       The heat release rate per unit volume is generally  independent of unit  rated power output.
However, the ratio of primary flame zone heat release to heat  removal  increases  as the unit capacity
is  increased.  This causes NOX emissions for large units to  be  generally greater than for small
units of similar design, firing characteristics,  and fuel.
       The increase in NOX emissions with increased capacity is especially  evident for gas-fired
boilers, since total NO  emissions are due to thermal NO .   However, coal-fired  and oil-fired units
                       A                                 A
behave differently with regard to changes in volumetric  heat release rates.  Up  to 80 percent of the
NO from coal-fired boilers is attributed to fuel nitrogen conversion,  so thermal effects associated
with  volumetric heat release rates have little overall effect.  Load reduction  can strongly affect
firebox aerodynamics, however, and consequently affect fuel  NO  emissions.  Table 4-8 summarizes
field experience with load reduction for NO  control.
       During numerous field test programs, load  reductions  on gas-  and  oil-fired utility boilers
reduced NOX emissions by 10 to 55 percent for load reductions of 18  to  55 percent of maximum rated
capacity.  Gas-fired boilers showed the highest reduction, followed  by  oil- and  coal-fired units
(References 4-35, 4-36, 4-37, 4-40, 4-81).
       A field study of industrial boilers (References 4-53, 4-80) reported that  the decreased N0x
emissions resulting from load reduction were somewhat offset by the  increase in  excess air required
for firing at the reduced load.  The increased excess air was necessary  to  prevent CO and smoke
emissions which were promoted at the reduced load condition.  NOX emissions did  not change at the
lower firing rates.  However, watertube gas-fired boilers equipped with  air preheaters showed a re-
duction in NOX emissions with load reduction caused by a combination of low air preheat  temperatures
 *Bulk gas temperatures are also affected locally by circulation patterns and  the proximity of cold
  surfaces.
                                                 4-37

-------
                                                        TABLE 4-8.  SUMMARY OF RESULTS WITH LOAD REDUCTION
Equipment Category/
Fuel
Utility boilers
Gas
Oil
Coal
Industrial water-
tube boilers
Gas
Oil
Coal
Industrial fire-
tube boilers
Gas
Oil
Control Method/
Range
In existing units
reduce load up to
about 50% by de-
creasing fuel and
air supply to all
burners, or termi-
nating fuel and
air altogether to
some burners. In
new units, lower
volumetric heat re-
lease rates achieved
by up to 30% larger
furnace dimensions.
Reduce load by up to
fuel and air supply
to al 1 burners or
terminating fuel
supply to some
burners
Reduce load up to
80% by reducing fuel
and air supply to
burner
NOX
Reduction
About 50%
25% to 40%
10% to 25%
Up to 30%
Up to 20%
Up to 10%
Up to 20%
Up to 15%
Effect On
Operation/
Maintenance
Increased soot de-
posits necessitate
more frequent use
of soot blowers.
Operational prob-
lems with control
of steam tempera-
ture at reduced
load.
Increased soot de-
posits necessitate
more frequent use
of soot blowers.
Operational prob-
lems with control
of steam tempera-
ture at reduced
load.

Efficiency/
Fuel Consumption
Decrease in
efficiency due
to associated
increase in ex-
cess air levels
at low load
operation
Decrease in
efficiency due
to associated
increase in ex-
cess air levels
at low load
operation
Decrease in
efficiency at
reduced loads
Extent
Used
Limited use for
trimming to
meet standards
Enlarged firebox
routinely used in
new units
Not used for
NOV control
X
Not used for
NO control
R&D
Status
Inactive
Evaluate optimum
heat release rate
for advanced
designs
Evaluate optimum
heat release rate
for use with ex-
ternal controls
or new burners
Evaluate optimum
heat release rate
for use with ex-
ternal controls
or new burners
a
ir
i
i-


I
u>
oo

-------
TABLE 4-8.  Concluded
Equipment Category/
Fuel
Internal combustion
engines
Gas
Dual fuel
Diesel
Gas turbines
Gas and oil
Control Method/
Range
Adjust throttle or
governor setting
to restrict engine
power output in ex-
isting engines, or
equip new engines
with smaller capac-
ity pump or
carburetor
Reduce fuel flow
to combustors
N0x
Reducti on
0.25% to 0.922
per 1 percent
derate
Up to 0.94% per
1 percent derate
0.17% to 0.92%
per 1 percent
derate
10% to 20%
Effect On
Operation/
Maintenance
Increase in HC
and CO emissions
Increase CO and
smoke due to
flame quench
Efficiency/
Fuel Consumption
About 10% in-
crease in bsfc
Results in in-
creased fuel
consumption
Extent
Used
Not used for
N0x control
None at present
R&D
Status
Inactive
Evaluate optimum
can heat release
rate for dry
controls

-------
and poor fuel-air mixing.   NOV reductions of about 20 percent were obtained as the firing  rate was
                             A
dropped to 50 percent of capacity.
       Load reduction can lead to operational problems apart from the obvious drawback  of  limiting
capacity.  Higher levels of excess air are typically required to suppress CO or smoke emissions  thus
leading to an overall reduction in efficiency.   The increased residence time of the combustion gases
at the reduced load can cause steam temperature imbalance in the convective section.  Higher excess
air or flue gas recirculation may be needed to maintain superheat temperatures.   Also, operation at
greatly reduced load may exceed the practical turndown limit of the burners.  Some burners may need
to be taken out of service to maintain good firebox mixing and steam temperature control.
       Most of the above problems can be avoided when the unit is designed to operate at low com-
bustion intensity.  Here,  the use of enlarged fireboxes on new units produces NOX reductions similar
to load reduction on existing units.   Some of the last gas- and oil-fired utility boilers sold were
equipped with enlarged fireboxes.  New coal-fired utility boilers use fireboxes  typically 30 percent
larger than was the practice in the 1960's (Reference 4-63).   This  practice is partly in response to
the New Source Performance Standards set in 1971  and partly to facilitate combustion of lower grade
western coals.  As mentioned earlier, the NOX reduction with coal-firing due to  an enlarged firebox
is largely indirect through the change in firebox aerodynamics.
       Figure 4-5 shows a  dramatic example of the effectiveness of  enlarged firebox,  or load reduc-
tion, in combination with  other techniques (Reference 4-47).   The Scattergood No.  3 unit of the
Los Angeles Department of  Water and Power uses  a firebox rated at an electrical  output of 460 MW but
was converted during construction to fire at about 315 MW to meet the stringent Rule 67 emission
standard in effect when the boiler went online.   With natural  gas firing, operation at the reduced
load in combination with burners out of service and massive FGR yielded emission levels below 35 ppm.
       Load reduction in internal combustion (1C) engines reduces cylinder pressure and temperatures
and thus lowers NOX formation rates.   However,  although NOX exhaust concentrations (i.e., moles of
NOX per mole of exhaust) are reduced, it is possible the reductions will be no greater than the de-
crease in power.   In such  a case, brake specific emissions (i.e., grams NO  per horsepower-hour) are
not reduced,  especially in four-stroke turbocharged engines.
       NOX emission reductions due  to derating  were reported for a  variety of engine types, fuels,
and percentages of derate  in Reference 4-43.  The reductions achieved ranged from 0.45  to  4.17 ug/J
(1.2 to 11.2 g/hp-hr) for  naturally-aspirated or blower scavenged engines and from 0.07 to 3.28  vig/0
(0.2 to 8.8 g/hp-hr) for turbocharged units.  Since these results were obtained with varying  amounts
                                               4-40

-------
 120
 100
o
<*>
n

<
ui
80
^
ง  60
CO
s:
Q.
Q_
   20
         Nitric Oxide Limit for
         Compliance with LA/APCD
                        Rule 67
                                      /
      0
                                       Upper 4 Burners Out of Service
                                       or Overfire Air Ports Open and
                                       Upper 2 Burners Out (33% Off-
                                       StoichioAmetric)
                                               '30%
                                             03
                                            Gas Recirculation Only
                                                        •Test Data 1975
Mw
295
355
ppm
25
33
                   Recirc 50%
                                     72%
                    •Combined 33% Off-Stoichiometric Combustion
                     and Gas Recirculation
                                      I
                                                 L
                                                         1
               100
                       200
    300
LOAD.  MW
400
530
530
   Figure 4-5.   Operating results of Scattergood unit No.  3 of LADWP;
                nitric oxide emissions below 35 ppm (Reference 4-47).
                                 4-41

-------
of derating, it is more informative to compare the effectiveness of this emission control  technique
on a normalized basis - i.e., percent NOX reduction per percent derate.  On this basis  the results
for naturally-aspirated or blower scavenged engines varied from 0.25 to 6.2 whereas those  for turbo-
charged units varied from 0.01 to 2.6.  No relationship was found between normalized effectiveness
and uncontrolled emission level, number of strokes per cycle, or fuel.
       Derating an engine does not require additional  equipment, and the only operating adjustment
is to the throttle or governor setting to restrict engine power output.  However, there are some
problems associated with engine derating that reduce the attractiveness of this NOX reduction tech-
nique.  When derated, the engine's efficiency is reduced, and therefore, the fuel consumption is in-
creased.  For example, the data reported in Reference 4-43 showed an increase in brake specific fuel
consumption  (BSFC) that ranged from 1.1 to 9.6 percent for the large bore engines investigated.
       Moreover, a derated engine must be a bigger, more expensive unit to satisfy a given power
requirement.  In addition, the lower temperature associated with derating an 1C engine increases
HC and CO emissions, because the temperature-dependent reactions that reduce these pollutants are
less active.
       Derating a gas turbine reduces the primary flame zone temperature and increases the residence
time of the hot product gases.  At a constant compressor speed, gases are cooled more at lower loads,
since more excess air is available for diluting.  This dilution produces lower NOV formation.  As
                                                                                 X
the residence time of the hot product gases in the combustor is increased, the production  of NOX may
increase however.
       Data on the exact effect of residence time on NOX emissions from a given gas turbine are
scarce, primarily because other variables (such as mass flowrate) change with a change in  residence
time.  Available data (References 4-69, 4-82), however, indicate that increased residence  time
(which is inversely proportional to air flow) increases NO  emissions.
                                                          A
       In summary, the primary near-term applications  of load reduction/enlarged firebox are for
retrofit of gas- and oil-fired utility boilers and new design of coal-fired utility boilers.  Addi-
tionally,  there may be application to new and existing industrial boilers as standards are set for
these units.  Load reduction for existing units is unattractive due to economic and operational
penalties.   Its  use is thus  avoided except as a last resort to achieve compliance with standards.
4.2.6  Burner Modifications
       Burner or combustor modification for NOX control is applicable to all stationary combustion
equipment  categories.   With  the possible exception of internal combustion engines, modified  burners
                                                4-42

-------
or combustion chambers can be retrofitted  onto  most existing units.   Almost all  burner modifications
use some  form of 1n-flame LEA, OSC, or FGR to reduce NO  emissions.
       For boilers and furnaces, a number of burner parameters affect NOX emissions.  These include
the geometry of the burner and fuel injection system, the method of  fuel injection, the velocity
and degree of swirl of the combustion air, and  the  division  of the total air between primary, second-
ary and teriary streams (References 4-16, 4-77, 4-83, 4-84,  4-85).   The effect of most parameters
depends upon the type of fuel used.  Optimizing these parameters and developing burner design
criteria have been the subjects of recent research  efforts (References 4-25, 4-60, 4-86); a summary
of the results is given in Table 4-9.
       For boilers and furnaces fired with natural  gas, burner parameters which reduce peak and
average flame temperatures produce the least NOX emissions (References 4-85, 4-86).   Entrainment of
cooler gases from the recirculating zones into  the  primary combustion zone is generally desirable.
However, since secondary recirculation patterns may vary considerably (depending on the geometry of
the furnace), burner parameters which reduce NOV in one furnace may  increase NOV levels in another
                                                A                               X
(Reference 4-86).
       Nevertheless, several  low-NO  burners have been developed for industrial furnaces,  including
some unconventional Japanese designs (References 4-61, 4-86).  Full scale test results show reduc-
tions in NOX emissions from 40 to 60 percent.   Subscale tests with single burners of the type  nor-
mally used in utility boilers have indicated that simple changes in burner block and nozzle geometry
and in swirl vane angles can decrease NO  production by up to 55 percent (Reference  4-60).
                                        X
       On oil-fired boilers and furnaces, a number  of modifications are possible for low-NOx burners.
The simplest modification varies the primary to secondary air ratio, swirl  level, and atomization
pressure on conventional burners.   In tests on  a simulated package boiler,  decreases in NOX emis-
sions from about 10 to 30 percent resulted when each of the above parameters was varied individually
(Reference 4-61).  The reductions are caused by changes in flame shape and flow field which produce
fuel-rich regions and dilution of air with combusted products.
       Several low-NOx burners with modified air and. fuel injection techniques have recently been
developed in Japan (References 4-61, 4-87, 4-88, 4-89).  Some of the more innovative methods include:
flame-splitting distributor tips which cause a flower petal flame arrangement, and atomizers with
fuel injection holes of different diameters which create fuel-rich and fuel-lean combustion zones
(References 4-25, 4-61,  4-88).   Up to 55 percent reductions in NOX emissions are reported with the
use of these nozzle tips.   However, the change in flame shape may cause problems due to impingement
on walls  and effectiveness may belreduced as flames interact in multiburner furnaces.
                                                 4-43

-------
TABLE 4-9.  SUMMARY OF RESULTS WITH BURNER MODIFICATIONS
Equipment Category/
Fuel
Utility boilers
Gas
Oil
Coal
Industrial boilers
Gas and oil
Residential and
conmercial furnaces
Oil
Control Method/
Range
Control mixing of
fuel and air at
burner to decrease
flame temp., inter-
nally recirculate
combustion gases,
and/or reduce avail-
ability of oxygen
in primary flame
zone for fuel NO
control ; burner mods
allow greater flex-
ibility with other
controls
Same as for utility
boilers
Optimum burner/
firebox design
using controlled
fuel -air mixing,
internal recircu-
lation and con-
trolled heat trans-
fer for lower
flame temperature
NOX
Reduction
Up to 55% in
single burner
experimental
furnace
About 40% to
55% in single
burner furnaces
35% in field test
on multi burner
furnace
20% to 45%
reported
About 50%
reported
Effect On
Operation/
Maintenance
Flame impingement
on walls possible
with certain bur-
ner types. Soot
emissions may
increase at low ex-
cess air levels.
As above
None
Efficiency/
Fuel Consumption
Associated use
of LEA yields
higher
efficiency
As above
Associated
use of LEA
yields higher
efficiency
Extent
Used
Limited retrofit
use; burner mods
routinely used to
allow use of other
mods (FGR, OSC)
Inclusion in new
unit design; lim-
ited retrofit use
Prototype unit
Field
demonstrations
R&D
Status
Development, test-
ing and commerciali-
zation of low NOX
burner
Develop advanced
low NOX burner
for new units
Approaching com-
mercialization;
advanced low NO
burners under
development
Approaching com-
mercialization
optimum burner/
firebox designs
n
VO
i

-------
                                                                         TABLE 4-9.   Concluded
Equipment Category/
Fuel
Internal combustion
engines
Gas and
diesel fuel

Gas turbines,
gas, kerosene
and diesel oil
Combustion Method/
range


Staged combustion by
fuel rich burning in
antechamber, prior
to completion of
combustion at lower
temperatures in
main chamber
Dry controls through
new can design; pre-
mix, prevap lean pri-
mary zone, controlled
dilution
NOX
Reduction


Approximately 60%

Normal range
Effect On
Operation/
Mai ntenance


None

None
Efficiency/
Fuel Consumption


Fuel consumption
increased by 5%
to 8% in one
design

Possible im-
proved effi-
ciency at
power loads
Extent
Used


None at present

None at present
R&D
Status


Evaluation for
new unit design

Extensive de-
velopment and
testing of ad-
vanced combustor
concepts
I
*.
Ul

-------
       Other fuel-air modifications include a low-NOx burner (offered by at  least  one  company in
the U.S.) for oil- and gas-fired package boilers.  This burner uses shaped fuel  injection  ports and
controlled air-fuel mixing to create a thin stubby ring-shaped flame (References 4-61,  4-87).  With
this modification, reductions in NO  from 20 to 50 percent are claimed.  The most  extensive air-
fuel modifications involve the self-recirculating and staged combustion chamber  type of burners,
used in industrial process furnaces.  These burners are equipped with a prevaporization  or a  precom-
bustion chamber in the windbox.  In the chamber, the fuel is vaporized and premixed with part of
the combustion air, or is allowed to undergo partial combustion under oxygen deficient  conditions
before being discharged into the furnace.  NO  reductions of about 55 percent are  typical  of these
devices.
       On pulverized coal burners, experiments have shown that the amount of NOX produced  in turbu-
lent diffusion flames is strongly dependent on fuel-air mixing.  High velocity axial injection of
fuel delays fuel-air mixing in the central core region of the flame; this produces local off-
stoichiometric conditions which inhibit NOX production.   However, the length of the flame  produced
by this method is generally unacceptable for use in existing boiler configurations (References 4-83,
4-84).
       To reduce NOX emissions without altering the flame form, a triple concentric burner design
with tertiary air supply has been suggested.   In subscale tests, NOX reductions of about 33 to 67
percent have resulted from injecting 50 percent of the total mass of air through the tertiary ports
(Reference 4-25).
       One major utility boiler manufacturer has recently fabricated and tested a  similar  dual reg-
ister pulverized coal burner, designed to produce a limited turbulence, controlled diffusion flame.
The manufacturer claims NOX reductions of 50 percent (Reference 4-90).   In field tests, an existing
boiler equipped with the new burners generated 35 percent less NO  than an identical unit  operating
under similar conditions with old burners (Reference 4-36).
       Another major manufacturer also plans  to install  its own version of a dual  register, divided
air stream burner in all  its new units.  The manufacturer claims that the new burners and  a new
furnace design (which increases burner spacing and reduces the volumetric heat release  rate) will
reduce NOX emissions by 47 percent, when compared to emissions from older units  (Reference 4-91).
       Burner spacing and location have an important effect on NO  production, although  little
quantitative data  are available.   Closer burner spacing increases interaction between adjacent
flames and reduces the ability to radiate to cooling surfaces.  In most new  utility boiler designs,
                                                 4-46

-------
the spacing between burners has been extended.   Future work  1s'planned  to  study  the  influence of
burner-burner and burner-furnace interactions  (Reference  4-25).
       Oil-fired burners used in residential heaters  and  furnaces  have  been  investigated recently,
and optimum burner and system design criteria  have been established  (References  4-55 to 4-58, 4-91,
4-92).   For most burners with refractory-lined combustion chambers,  local  recirculation increased
NO  emissions.   It was also found that for water-cooled and  air-cooled  combustion chambers (which
characteristically have lower N0x emissions),  entrainment from  the external  recirculation zone, which
has a chance to dissipate heat to the cold walls, is  beneficial.   Flame  retention devices were, how-
ever, found to be detrimental for both types of  combustion chambers.  In addition, choke diameter
dimensions as a function of fuel flowrates and optimum swirler  vane  angles were  determined.  Two
burners based on these criteria were constructed, and their  measured NO  emissions were found to be
approximately 50 percent lower than conventional burners  operating under similar conditions.
       In internal combustion engines, the combustion process can  be improved by:
       •   Predesigning chamber geometries to  increase turbulence, as in high swirl  engines
       0   Staging, as in engines with stratified charge, precombustion chambers, or piston heat
           cavities
       •   Using a combination of both, as with  "squish lip" piston heads (Reference 4-43)
       In high swirl units, the improved mixing  promotes  rapid, early combustion which causes high
temperatures for a long period of time.  Delayed ignition can then be used to reduce peak tempera-
tures below the temperatures at which NOX forms, with less production of unburned hydrocarbons and
smoke.  No data are available to compare NO  emissions from  a high swirl unit with those from a
conventional engine when both are retarded as  far as  possible.
       When staged combustion is used, the fuel  charge is introduced into a cavity as a rich  mixture
and then ignited in an oxygen-deficient environment which inhibits NOX formation.  This combusting
mixture then expands into the main chamber where it mixes with additional air at reduced temperatures
which are adequate for combustion, but below those required  for NOX formation.   Reduced temperatures
may, however, reduce the engine efficiency; the  results are  summarized in Table  4-9.
       "Squish lip" designs appear to reduce NOX emission both by  aerodynamic effects and staged
combustion.  The vertical flow pattern created recirculates  burned gases through the combustion zone
within the piston head cavity, thus incorporating a form  of  internal EGR.  A summary of combustion
modifications for reciprocating 1C engines is  given in Reference 4-43.
                                                 4-47

-------
       Much research has been focused recently on the development of low-NOx  gas  turbine combustors
for both stationary and mobile sources (References 4-69, 4-92 through 4-100).   Some  of advanced com-
bustor concepts proposed depart radically from conventional designs.  In general, most combustor
modifications attempt to control NOX emissions by reduced reaction flame temperatures, decreased
residence times, and controlled fuel air mixing.  The techniques employed include leaning out of the
primary zone, increasing of the mass flowrate, earlier quenching with secondary air, air blast  and
air assist atomization, fuel prevaporization, and premixing of fuel and air.  Some of  the more  ad-
vanced designs propose heat removal from the combustion zone, precombustion,  fuel staging, extended
flammability limits for ultra-lean combustion, fuel-rich low-intensity combustion, and staged swirl
mixing and burning.  Most of these designs are still in the conceptual  stage.  The limited tests
performed on experimental test rigs have generally produced encouraging results with NOX reduction
ranging from 35 to 60 percent of conventional combustion; the results are summarized in Table 4-9.
       In summary, new optimized design burners appear to have the capability of reducing NOX con-
centrations 40 to 65 percent from conventional burner designs on gas and oil  fuels.  Similar reduc-
tions are being demonstrated on prototype coal-fired units.   The new low-NOx  burners are designed to
attain controlled mixing of fuel and air in a pattern that keeps the flame temperature  down and dis-
sipates the heat quickly.  Improved burner designs may well  replace the external combustion modifi-
cations now in use and achieve significantly lower NO  emissions.  Thus, although low-NO  burners
have limited current application, they will receive primary emphasis in the NOX E/A for far-term
application.
4.2.7  Water Injection
       Water injection has been shown to reduce flame temperature and is widely used in gas turbines.
Only recently has water injection been tried on utility boilers.  Table 4-10  summarizes the current
state of water injection as a NOX control  method for stationary combustion sources.
       The Ormand Beach, California steam-generating units were tested with water injection to  re-
duce NOX (Reference 4-74).   The boilers,  operating at 75 percent of full load (design  capacity  800
MW) with 10 percent tertiary air, were emitting 400 ppm of NO.  When 0.6 kg of water per kg of  oil
was injected, the emissions were reduced to 228 ppm, a 43 percent reduction.  Higher reductions were
obtained with flue gas recirculation and water injection combined.  For example, with  15 percent gas
recirculation and injection of 0.2 kg of water/kg of oil, NO reduction of nearly 50  percent was
achieved.   Compared to flue gas recirculation, water injection imposes a large  energy  penalty.
Water injection  increased the minimum 02 requirement and significantly lowered  the efficiency.   For
this reason,  water injection  seems to be an unattractive NOX control technique  for utility boilers.
                                                4-48

-------
                                                         TABLE 4-10.  SUMMARY OF RESULTS WITH WATER  INJECTION
Equipment Category/
Fuel
Utility boilers
Oil
Coal
Internal combustion
engines
Gas
Diesel
Dual fuel
Gas turbines
Oil (distillate)
Gas (natural)
Control Method/
Range
Water sprayed into
windbox 0 to 0.6
kg H20/kg fuel
Water injection
0.2 kg H20/kg coal
i
Water induction
0.94 kg H90/kg
fuel i
0.17 to 0.21
kg H20/kg fuel
0.1 to 0.25
kg H20/kg fuel
Direct injection
of atomized ^0
into the primary
zone 0.3 to 1.0
kg H20/kg fuel
0.3 to 1.0
kg H20/kg fuel
NOX
Reduction
0% to 40%
(opposed wall-
firing)
15% (opposed wall
firing)
70%
20% to 40%
50% to 70%
30% to 80%
30% to 80%
Effect On
Operation/
Maintenance
Increases minimum
02 requirement-
burner flame de-
tectability
problem
Better ESP
efficiency
Increases CO and
HC emissions/
rapid buildup of
scale
Increases CO, HC
emissions
Increases HC
emissions/engine
durability
decreases
Small increase
HC and CO
emissions possible
Small increase
HC and CO
emissions possible
Efficiency
Fuel Consumption
Lowers effi-
ciency (by
roughly 10%)
Lowers effi-
ciency
(roughly 10%)
No data
No data
No data
Decreases
efficiency up
to 1%
Decrease
efficiency up
to 1%
Extent
Used
Demonstration only
Southern Calif.
Edison
Demonstration only
Arizona public
service
Experimental /not
used
Experimental /not
used
Experimental /not
used
Extensive retrofit
use; inclusion in
new unit design
R&D
Status
Inactive
Inactive
Inactive
Inactive

Continuing develop-
ment for new and
retrofit use; long-
term emphasis is on
dry controls
4*
to

-------
       Water injection has  not been  tried on industrial  boilers and no experimental or field test
data are available at this  time.   Based on the results  obtained from utility boilers, it appears
that water injection is not a  viable control  technique  for industrial  boilers.
       Water can be introduced with  the intake air or injected directly into the cylinder of inter-
nal combustion engines.  The effectiveness of water injection/induction depends on the degree of
atomization and mixing of the  water  within the combustion  chamber;  the reported effectiveness in
lowering NO  emissions depends almost linearly on the rate at which water is added.  More than 30
percent NO  reductions were obtained, for large bore engines, with  0.5 kg of water per kg of fuel.
However, the effectiveness of water  induction decreases at water-to-fuel ratios greater than one
(Reference 4-43).
       Operational/maintenance problems associated with  water injection include leakage of water
into the crankcase which contaminates the lubricating oil  and rapid buildup of  mineral  scale around
the valves, water injection nozzles, and other components  through which the water flows.   The
availability of water may be a problem for those engines which are  used in remote and frequently
arid locations (Reference 4-43).
       Over 80 percent NO  reductions have been achieved with water injection on gas turbines.
Injecting atomized water directly into the primary zone  of the combustor is most effective in re-
ducing NO .
       The only problems involve  the quality and quantity  of water  injected, since these determine
the operational economics and  life of the gas turbine.   Most utilities which use water injection
have some sort of purification system.   According to industry sources, boiler feed water quality
requirements are more stringent than those for the water injected into gas turbines (Reference 4-69).
       The quantity of water used varies significantly  between turbines and depends on such factors
as mechanical  design, plant location, heat rate,  turbine inlet temperature, fuel characteristics,
and operating mode.   The water to fuel  weight ratios vary  from as low  as 0.5/1  to as high as 1/1
(Reference 4-101).
       The industry and manufacturing sources report that  the water injection process does not appear
to affect turbine life; no  major  problems have been encountered.  However, with water injection the
fuel  consumption  increases  approximately 3 percent for  water/fuel ratios of 1/1.  Water injection
increases the  mass  flow through the  turbine which, in turn, increases  turbine power outout.  Typical
increases in capacity are about 8 percent with a water/fuel ratio of  1/1  (Reference 4-69).
                                                 4-50

-------
       In  summary,  water Injection has been found to be  very effective  1n  suppressing  NO   emissions
from gas turbines.   However, the use of water injection  may  entail  some undesirable  operating con-
ditions, such as  decreased thermal efficiency and increased  equipment corrosion.   It is,  therefore,
an unpopular NOX  reduction technique for all combustion  equipment except for  near-term use on gas
turbines.   In the long term, it is anticipated that water  injection  will be replaced by advanced
combustor  can design.

4.2.8  Reduced Air Preheat
       NOX emissions are strongly influenced by  the effective peak  temperatures in the  combustion
zone.  Thus, any  modification that lowers these  temperatures,  such as reducing the combustion air
temperature, should lower NOX emissions.  Theory indicates that  a 56K (100F)  decrease  in  air preheat
temperature will  result in an approximately 28K  (50F)  reduction  in  the  adiabatic combustion tempera-
ture, which in turn will decrease thermal NOV formation  by 27 percent (References 4-53, 4-72).  Since
                                            A
reduced air preheat does not significantly suppress fuel nitrogen conversion  (Reference 4-102), it is
expected that this control technique would be most effective  on  fuels,  such as natural  gas and dis-
tillate oil, which have low nitrogen content.
      | Reduced air preheat is potentially applicable to  most utility boilers, industrial  boilers
with preheated combustion air, regenerative gas  turbine  units  and turbocharged internal combustion
engines.   This method for controlling NO  usually greatly  lowers fuel economy, however.  New designs
to  reduce stack gas temperatures, for example, and redesigning the convective section of a boiler
for more heat absorption would be necessary to maintain  efficiency.
       Only limited field test data are available on the effect  of reduced air preheat in utility
boilers due to the severe efficiency penalty incurred with this  method.  Some field  test  results and
discussions on reduced air preheat for utility boilers are available in References 4-37, 4-38, 4-40,
4-47, 4-63, 4-70 through 4-73.  Conclusions and  results  from  these references are summarized in
Table 4-11.
       The data for coal showed varying trends,  although a maximum reduction of 75 ppm  (at 0 percent
02) per 56K (100F)  reduction in air temperature  was reported  in  one  case (Reference  4-102).  In
general,  NO  reductions of about 50 percent for  gas-fired  boilers and 40 percent for oil-fired boilers
           A
can be expected with reduced air preheat, however, NOX reductions in coal-fired boilers were very
small (Reference  4-63).
       Industrial boilers that have combustion air preheat are usually  found  in sizes  above 15 f*l
(50 x 10s  Btu/hr) input capacity.  Firetube boilers are  generally not equipped with  air preheaters.
Field test results  on the effects of reduced air preheat are given  1n References 4-45  and 4-53 and
                                                4-51

-------
TABLE 4-11.  SUMMARY OF RESULTS WITH REDUCED AIR PREHEAT
Equipment Category/
Fuel
Utility Boilers
Gas
Oil
Coal
Internal water-
tube boilers
Gas
Oil
Coal
Control Method/
Range
Reduce combustion
air temp, from
typical range of
480K to 590K
to ambient tem-
peratures, less
effective for fuel
N0x
Reduce combustion
air temp, from
typical range of
395K to 620K down to
ambient temperatures
NOX
Reducti on
Up to 25% per 56K
(100F) decrease
in air preheat
temperature
Approx. 7% per
56K (100F) de-
crease in air
temperature
Generally
ineffective
Up to 25% per 56K
(100F) decrease
in air preheat
temperature
Approx. 15% per
56K (100F) de-
crease in air
temperature
No reliable
data available
Effect On
Operation/
Maintenance
Induced draft fan
capacity must be
increased. Pos-
sible flame in-
stability.
Preheated air is
required for pul-
verizer operation.
Coals with higher
moisture contents,
e.g., lignite, re-
quire higher pri-
mary air
temperature.
Same as for util-
ity boilers
Efficiency/
Fuel Consumption
Significant
energy penalty
for existing
units — about
2% drop in
efficiency per
56K (100F) de-
crease in air
preheat tempera-
ture
Same as for
utility boilers
Extent
Used
No use due to
energy penalty
None; trend to
higher preheat
for energy con-
servation
R&D
Status
Inactive
Some evaluation
of alternate
waste heat use
to allow lower
preheat; trend
in new units gen-
erally to higher
preheat
o
^o
1

-------
TABLE 4-11.  Concluded
Equipment Category/
Load
Internal combustion
engines
Gas
Dual fuel
Diesel
Control Method/
Range
For engines with
turbochargers , re-
duce air inlet tem-
peratures typically
from 330K down to
about 31 OK
N0x
Reduction
Up to 2.3% per
IK (1.8F) air
temp decrease
Up to 2.3% per
IK (1.8F) air
temp decrease
Up to 0.7% per
IK (1.8F) air
temp decrease
Effect On
Operation/
Maintenance
Heat exchanger
using air, cold
water supply, or
cooling tower
required
Efficiency/
Fuel Consumption
Up to 1.3% in-
crease in energy
consumption
Up to 0.5% in-
crease in energy
consumption
Up to 1.0? in-
crease in energy
consumption
Extent
Used
Widely used in
large turbocharged
engines
R&D
Status


-------
 are summarized  in Table 4-11.   For both industrial and  utility  boilers,  reduced air preheat reduces



 efficiency,  and is  therefore not a practical control technique  for existing units.   Design changes



 in new  units, such  as  installing or enlarging an economizer, are  required  to regain the waste heat



 which would  otherwise  be lost through the stack.



        Turbocharged internal combustion engines over 373  kW  (500  hp)  output normally have inter-



 coolers between the turbocharger and the intake manifold  to  increase  the air density,  permitting


 higher  mass  flow rates and consequently, higher power output.   However,  the intercooler which de-



 creases the  inlet temperature also causes NO  emissions to decrease.



        Results  of studies cited in References 4-32 and 4-43 are summarized  in Table  4-11.  Reduced



 manifold air temperatures increase the brake specific fuel consumption, but only by  a  small per-


 centage.   Required  hardware changes include the addition of heat exchangers or  the installation of


 larger  heat  exchangers.  For hot, humid climates with no access to large supplies of cold water,



 cooling towers  must  be installed.



        Regenerative  gas turbines use the turbine exhaust gases, which are typically  at temperatures


 ranging from 790K to 975K (800 to HOOF),  to preheat the combustor inlet air.  This  results in a


 significant  improvement in overall  cycle efficiency.   Reference 4-73 tabulates results from tests


 on two  similar turbines:   one operating in  a simple cycle, the other in a regenerative cycle.  The


 heat rate  (thermal energy consumed per unit of power output)  is 18 percent lower for the regenerative


 unit, but the NO  emissions are greater by  more than a  factor of two.



        Reference 4-73 also gives N0v emissions as a function  of combustor inlet temperature as pre-
                                   A


 sented  by Lipfert.   Reducing the combustor  inlet from 850K to 410K (900 to 200F) reduces NO  by


 90 percent.  However, at  lower temperatures, further reduction in combustor inlet temperature is not


 expected to lead to still  lower NO  emissions.



        In summary, reduced air preheat for  gas turbines and for boilers is not a practical control



 technique, unless the energy in the exhaust gases can be utilized effectively for other  purposes.



One way to use this energy is to use combined gas-steam turbine cycles; this will be discussed in


Section 4.6.   Reduced air preheat will  be accorded low priority in the NO  E/A.
                                                                         A



4.2.9  Ammonia Injection




       The post-flame decomposition of NOX  by reducing  agents has recently shown promise as a method


for augmenting  combustion  modifications if  stringent emission limits are to  be  met.  Exxon  has



patented a process  for the  homogeneous  gas  phase selective decomposition of  NOX by  ammonia
                                                4-54

-------
(Reference 4-103).   The gas phase reaction in the temperature  range of 980K (1.400F)  to  1370K
(2.000F)  converts  nitric oxide, in the presence of oxygen  and  ammonia, into nitrogen  and water
vapor (Reference 4-104).
       Results  of  lab scale tests show that the level of NOX reduction depends on the combustion pro-
duct temperature,  initial NOX concentration, and quantity  of ammonia  injected (Reference 4-105).
Based on  the available results, ammonia injection appears  to be most  effective between 980K  (1.300F)
and 1370K (2.000F),  which corresponds to conditions  in the convective section of large boilers.
Maximum NOX reductions, as much as 90 percent, were  obtained at 1230K (1.750F) with molar ratios of
ammonia to initial nitric oxide ranging from 1.0 to  1.5.
       Field tests were conducted on a gas-fired furnace rated at 147 kW (500 MBtu/hr), and on an
oil-fired boiler rated at 41 kW (140 Btu/hr) with both the units retrofitted for NH, injection
                                                                                   
-------
TABLE 4-12.  SUMMARY OF RESULTS WITH AMMONIA INJECTION
Equipment/
Description
Experimental
combustor,
59 kW
(200,000 Btu/hr)
firing either
gas or oil
Experimental
tubular reactor

Oil fired
41 MW
(140 MBtu/hr)
Gas-fired
furnace
147 MW
(500 MBtu/hr)
Temperature
Range Tested
(K)
920-1 ,480
870-1 ,300
870-1 ,300
—

Range of NH3
concentration
(ppm)
0-5,250
400
400
NH,.
. •* - 1 tn 4 5
N0initial
NH,
•j _ -i 4._ n r
wn i i.u t.j
""initial
Range of
Initial NOX
Concentration
(ppm)
100-1,000
250
250
—

Range of
Final NO
(ppm)
10-100
10-100
10-250
30-65%
reduction
30-80%
reduction
Comments/
Remarks
Maximum NOX
reduction occurs
at 1.230K, most
effective with
high initial NOX
concentrations
Maximum NOx
reduction occurs
at 1,230K (with-
out Hฃ injection)
Maximum reduction
occurs at 980K
with Hซ addition
—


-------
injection  include  the presence of ammonia as a primary  pollutant  in  the stack  gas  and potential
reactions  of ammonia with the flyash and sulfur compounds  in  coal  firing.   Since  low  temperature
stack gas  reactions are important here, pilot scale tests  will  be  of limited use.   Full quantifica-
tion of potential  adverse impacts of ammonia injection  will await  full  scale demonstrations with
coal firing.
       In  addition to the above operational concern, there is also the  strategic question of whether
sufficient ammonia would be available in the 1980's and 1990's  for widespread  application in utility
boilers (Reference 4-106).
       In  summary, ammonia injection does not appear to have  near-term  application  for NO  control
                                                                                         X
in  the U.S.  It shows promise for far-term applications, however,  and will  be  given primary emphasis
in  the NOX E/A for assessment of advanced concepts for  the 1980's  and 1990's.

4.2.10  Costs of Combustion Process Modifications
       This section presents the most recent data on capital  and operating  costs of combustion modi-
fication NO  controls for each equipment category.  Except where otherwise  noted, the  costs pre-
sented here are in 1974 dollars.  In some cases, earlier cost figures have  been converted to 1974
dollars by applying appropriate inflation factors.
       In several  cases the costs presented are for combined NO controls.  Generally, the effect-
                                                                X
tiveness of combined NO  controls is not equal to the sum  of the individual effects of each control.
 Likewise, the costs of combined controls are not the sum of the costs of single controls.

4.2.10.1  Utility Boilers
       The cost-effectiveness and related costs of combustion modifications in full-scale combustion
equipment for utility boilers have been fairly well documented.  One of the earliest efforts was
attempted by Esso Research Labs in 1969 (Reference 4-107).  Since  1969, however, it has been shown
 that the effectiveness of control techniques among boilers varies  widely and requires  continuing
 cost-effectiveness evaluations on an individual boiler  basis.   The most recent cost data for both
new and existing tangential, coal-fired utility boilers (Reference 4-108) are  summarized in
 Figures 4-6 and 4-7.  The costs are for the combined use of overfire air ports and  low excess  air
firing, as this is the preferred control system for tangential  coal-fired boilers.  Capital costs
were projected over a unit size range of 25 to 1000 MW. The  corresponding  annual  operating costs
for 500 MW units was 0.006 mils/kWhr for a new unit and 0.021 mils/kWhr for existing  units. Figure
4-6 applies to new unit designs with heating surfaces adjusted  to  compensate for  the  resultant
                                                4-57

-------
    1.00



2  0.75
V,
4A-

(-"  0.50
o
o
   0.25
   0.00
NEW  UNITS INSTALLATION COSTS
           4 WINDBOX FURNACES
               8WINDBOX FURNACES-
           200
     400        600

           UNIT SIZE,  MW
800
1000
   Figure 4-6.  1975 capital  cost of OFA on  new tangential
               coal-fired boilers (Reference 4-39).
                             4-58

-------
    1.50




    1.25



    1.00
•vt-
 _- 0.75
(0
o
o
   0.50
   0.25
   0.00
EXISTING UNITS  MODIFICATION COSTS
4 WINDBOX FURNACES
8 WINDBOX FURNACES
           200
         400        600        800

               UNIT SIZE, MW
                     1000
   Figure  4-7.  1975 capital cost of OFA on existing coal-fired
               boilers  (Reference 4-39).
                            4-59

-------
 changes in heat transfer distribution and rates.   Figure 4-7 applies to existing units with no change
 in heating surface, as these changes must be calculated on an individual unit basis.
        Cost ranges for existing units vary more widely than for new units, since variations in unit
. design and construction can either hinder or aid the installation of a given NOX control system.
 Also, above approximately 600 MW,  single cell-fired boilers exceed a practical size limit and
 divided furnace designs are utilized.  Since a divided tangentially-fired furnace has double the
 firing corners of a single cell furnace, the costs increase significantly.
        It should be kept in mind that although these cost data for utility boilers were developed
 for tangentially coal-fired boilers, the range of costs presented is also generally applicable to
 wall-fired boilers burning coal.  And, the cost of similar combustion modifications on gas- and
 oil-fired utility boilers should be no higher than for the coal-fired units.
        Generally no significant additional  cost for modern units  or units in good condition is re-
 quired for reducing excess air.  However,  some older units may require modifications such as alter-
 ing the windbox by adding division plates,  separate dampers and operators,  fuel  valving,  air regis-
 ter operators, instrumentation for fuel  and air flow and automatic  combustion controls.   Table 4-13
 shows estimated investment costs for low excess air (LEA)  firing  on existing utility boilers (Refer-
 ence 4-109).   These costs are guidelines,  which can vary depending  on the modifications  that are
 required.   As unit size increases, the cost per kW decreases since  the larger units typically have
 inherently greater flexibility and may require less extensive modification.
        The use of low  excess air firing  reportedly increases boiler efficiency by 0.5 to 5 percent.
 Additional savings may result from decreased maintenance and operating costs, so any investment
 costs can  be  offset by savings in  fuel  and  operating expenses.
        As  an  example of cost variations  for combustion modifications among individual existing units,
 several case  studies from Pacific  Gas and  Electric are presented in Table 4-14.   The numbers shown
 are the costs incurred by PG&E during a  recent program to bring eight units into compliance with  local
 NOX emission  regulations.   For the most  part, the conversions involved the combination of windbox flue
 gas recirculation and  overfire air ports.   The average cost of the modifications is about, in 1975
 dollars,  $10/kW (Reference 4-110).
        Another West Coast electric utility  company, the Los Angeles Department of Water and Power
 (LADWP), has  had extensive experience in implementing NOX control techniques on its gas- and oil-
 fired  boilers.   The techniques currently utilized by the Department include burners out-of-service
 (BOOS), overfire air/NOx  ports, and low  excess air.   Although the units are operated with the lowest
                                                4-60

-------
TABLE 4-13.  1974 ESTIMATED INVESTMENT COSTS FOR LOW EXCESS
             AIR FIRING ON EXISTING BOILERS NEEDING MODIFICATIONS
             (Reference 4-109)
Unit Size
(Electrical Output)
(MW)
1000
750
500
250
120
Investment Cost
($/kW)
Gas and Oil
0.12
0.16
0.21
0.33
0.53
Coal
0.48
0.51
0.55
0.64
0.73
                              4-61

-------
                                   TABLE 4-14.  1975 INSTALLED EQUIPMENT COSTS FOR EXISTING PG&E RESIDUAL OIL-FIRED UTILITY BOILERS

                                                (Reference 4-110)
i
o\
po
Unit Name
Pittsburg
#7


Pittsburg
#5 and #6




Contra Costa
19 and #10


Portrero #3



Moss Landing
#6-1 and #7-1

Design Type
CE tangential 1y-
fired, divided


B&W opposed-fired




B&W opposed-fired


Riley turbo-fired



BSW opposed-fired

Year
Online
1972


1964




1965


1972



(?)

Capacity
(MM)
730


330 (each)




345 (each)


206



750 (each)

Modification
Cost
($106)
6.2


7.8 (both)




6 (both)


3.5



2.8

$/kW
8.5


11.8




8.7


17



1.8

Year
Modified
1975


1975




1975


1975



1971

Type of Modification
Windbox FGR, Overfire Air
• Two new 5000 hp FGR fans
• FGR ducting (17% FGR)
• NOX port installation
• No new burner safeguard
system
Windbox FGR, Overfire Air
• Transferred two FGR fans from
other units
• FGR ducting (17% FGR)
• New hopper
• NOX port Installation; one for
each burner column
• New burner safeguard system;
computer, NOX control board,
02 controls on dampers, flame
scanners
Windbox FGR, Overfire Air
• New FGR fans (1 ea.) (17% FGR)
• Nominal awount of new ducting
to wlndbox
• N02 port Installation
Windbox FGR, Overfire A1r
• New FGR fan (17% FGR)
• NOX port installation, nominal
amount of ducting
• New burner safeguard system,
NOX control board, computer
Windbox FGR, Overfire Air
• Existing temperature control
FGR fans replaced with larger
fans
• New flame scanners
a.
*s
ro

















-------
excess  air  possible,  it has been found that when LEA  is combined with other  reduction methods, ex-
cess  air levels must  be increased beyond those normally required.
       The  Department's data indicate a unit efficiency decrease of approximately  1 percent attri-
butable to  BOOS operation.   As found by other operators, LEA tended to  increase efficiency slightly;
a 1 percent decrease  in excess oxygen increased efficiency by about 0.25 percent.  Properly retro-
fitted, overfire  air  had no effect on efficiency.
       The  NOX control  costs incurred by LADWP are shown in Table 4-15  for four different units.  "
The figures for the BOOS techniques reflect the R&D costs that precede  the retrofit.  All costs are
installed equipment costs which include the labor required to implement the  control methods.   The
very low expense  associated with overfire air on the  B&W 235 MW unit is due  to the base year of
the estimate (1964 to 1965), and to the fact that this modification was included in the original
boiler design.
       The  overfire air costs for the B&W 235 MW unit are somewhat low  in Table 4-15.   The LADWP
boilers were, for the most part, modified without much difficulty, and  the associated costs probably
represent the lower limits of the costs for the three NO  reduction tecniques implemented (Reference
                                                        A
4-111).
       In addition to the increased capital costs from including a NOX  reduction system in new or
existing units, the increased unit operating costs must be considered.   These differential operating
costs were  defined for 500 MW new and existing utility boilers and are  shown in Table 4-16 (Refer-
ence 4-108).  The costs are given in 1975 dollars, and the equipment costs shown are determined
from Figures 4-6  and  4-7.  To put these operating costs in perspective, they can be compared to the
percent increase  in generating costs shown at the bottom of Table 4-16.  Except for the case of
older  units, the  difference in operating cost is below 0.1 percent of annual cost.
       In summary, the following are the major economic considerations  that  the boiler operator or
designer may be faced with:
       •   The lowest cost method for reducing NOX emission levels on new and existing units is the
           incorporation of low excess air firing.  Minimal additional   costs are involved.
       •   For most utility boilers, the second lowest cost NOX control method appears to be off-
           stoichiometric combustion by biased firing, "burners out-of-service" (BOOS) or the addi-
           tion of an overfire air system.   Although  lowering excess air (LEA) is implemented con-
           currently  with other control techniques, the excess air levels may have to be  increased
           beyond those normally required.
                                                4-63

-------
                    TABLE  4-15.   LADWP  ESTIMATED  INSTALLED  1974 CAPITAL COSTS FOR NO  REDUCTION

                                 TECHNIQUES  ON  GAS- AND OIL-FIRED UTILITY BOILERS   X

                                 (Reference  4-111)
Unit
Capacity
(MW)
180
235
235
350
Unit
Type
C.E. tangen-
tial ly-fi red
C.E. tangen-
tial ly-fi red
B&W Opposed-
fired
B&W Opposed-
fired
NOX Reduction
Technique
BOOS
LEA
BOOS
LEA
BOOS
Overfire air
LEA
BOOS
Overfire Air
LEA
Implementation
Method
Retrofit
Retrofit
Retrofit
Retrofit
Retrof i t
Original Design
Retrofit
Retrofit
Retrofit
Retrofit
Estimated
Cost
($)
69,400
28,900
75,200
28,900
75,200a
14,000a
28,900
266,000
100,600
28,900
$/kW
0.38
0.16
0.32
0.12
0.32
0.06
0.12
0.76
0.29
0.08
I
at
           1964-65 base year

-------
                  TABLE 4-16.  1975 DIFFERENTIAL OPERATING COSTS OF OFA ON NEW AND EXISTING TANGENTIAL
                               COAL-FIRED UTILITY BOILERS (Reference 4-108) (Net Heat Rate 9,500
                               Btu/kWhr, March 1975 Equipment Costs)

Capital Costs $/kw
Annual Cap. Cost $
Annual Fuel Cost $
Labor & Ma int.6 $
Total Annual Cost $
Electricity Cost9
mils/kWhr
Increase - %
Increase — mils/kWhr
New
Plant
Without
Overfire Air
500.00
40,000,000a
18,000,000ฐ
8,100,000
66,100,000

24.481
-_-
—
New
Plant
With
Overfire Air
500.20
40,016,000
18,000,000
8,100,000
66,116,000

24.487
0.024
0.006
Recent
Existing
With Added
Overfire Air
500.70
40,056,000
18,000,000
8,100,000
66,156,000

24.502
0.086
0.021
Older
Existing
Without
Overfire Air
250.00
20,000,000b
9,000,000d
8,100,000
37,100,000

13.741
___
—
Older
Existing
With Added
Overfire Air
250.70
20,056,000
9,000,000
8,100,000
37,156,000

13.762
0.153
0.021
en
tn
          Based on:   a
                      Annual  fixed charge rate of 16% x 500 $/kW  x  500,000  kW
                     b!6% x 250 $/kW x 500,000 kW
                     C0.70 $/106 Btu coal cost x 5,400 hr/yr x  500,000  kW x 9,500 Btu/kWhr
                     d0.35 $/106 Btu coal cost x 5,400 hr/yr x  500,000  kW x 9,500 Btu/kWhr
                     eLabor and maintenance cost of 3.0 mils/kWhr
                     f5,400 hr/yr at 500 MW - 2,700 gWhr/yr
                     9Cost at plant bus bar; transmission  and distribution  not included

-------
       t   Gas recirculation is more costly to Implement than overflre  air and requires additional
           fan power.  In existing units, the need to reduce unit capacity to  maintain acceptable
           gas velocities through the boiler convective sections may impose an additional  penalty.
       •   In general, the cost of applying any of the control methods  to  an existing  unit will be
           approximately 2 to 3 times that of a new unit design

4.2.10.2  Industrial Boilers
       Cost data for combustion modifications on industrial boilers are virtually nonexistent, since
research and development, including field testing and application of NOX control methods to this
equipment category, is in its early stages.  Only the most broadly-based estimates are available.
The most recent cost data are from a study in which a 5.1 MW (17.5 x 103 Ib steam/hr)  D-type
watertube boiler was modified by adding staged air and flue gas recirculation  capability (Reference
4-53).  The windbox depth was increased and a second set of registers to control the recirculating
flue gas was installed inside the extension.   The cost of these modifications  was estimated at
$5,000; the current cost of new boilers of this type is about $60,000.  The  cost of a  similar modi-
fication on other modern D-type boilers could be as high as $7,500, if the  existing burner  registers
cannot be used.
       Manufacturers of industrial boilers in the 88 MW (300 x 103 Ib steam/hr) range  and  1 mil-
lion dollar cost category estimate that, in general, a staged air installation would add from 2 to 4
percent to the boiler's cost.   For A-type boilers, the added cost would be about 2 percent, and for
D-type boilers about 3 percent.   Another booster air fan, if required, would increase  the modifica-
tion cost by about 1 percent (Reference 4-53).
       In a recent study, costs for retrofitting an existing unit to accept  flue gas recirculation
were estimated (Reference 4-68).  Approximate  costs which include design, installation  and equipment
costs associated with the retrofit of FGR systems were, in 1975 dollars, $20,340 for a 3.51 MW
firetube boiler and $21,190 for a 3.51  MW watertube boiler.  However, these  costs would be  considerably
less for a new boiler.   Reference 4-68 estimates that for a new boiler of  the  size mentioned above,
cost of including an FGR system will  be about $6,900.

4.2.10.3  Internal  Combustion  Engines
       There are few cost data for internal combustion engines, particularly for large (>375
kW or 500 hp)  engines.   Sufficient data exist,  however, to give order of magnitude NO   control
costs for the  following engine categories:
                                                 4-66

-------
      •   Natural gas, dual  fuel,  and diesel  fueled engines above 75 kW/cylinder (TOO hp/
          cylinder)
      •   Small to medium  (<75  kW/cylinder)  diesel fueled engines
      •   Gasoline fueled  engines  (30 to 375 kW/cylinder)
      Costs for large  stationary engines can be estimated based on Reference 4-112 and information
supplied to Reference 4-43.   These  costs, however, relate to emission reduction achieved by engines
tested in  laboratories  rather than  by field installations.  Reference 4-94 indicates, nevertheless,
that these data are representative.
      Table 4-17  lists cost  impacts for control techniques applied to large stationary engines.
These cost impacts may  be related to actual installations using baseline data presented in Table
4-18, which represent most  applications.   Basically, the controls involve an operating adjustment,
however, derating  and manifold air  cooling require hardware additions.   Also, derating is  not  a
viable technique for existing installations unless additional  units are added to satisfy total
power requirements.
      The impact  of the control costs may vary considerably,  given that:
      •   Standby (<200 hr/yr)  application control costs are  primarily a result of initial  cost
          increases from emission  control, whereas continuous service (>6,000 hr/yr) control  costs
          are  largely  a function of fuel consumption penalties
      0   Controls which require additional  hardware with no  associated fuel penalty (e.g., mani-
          fold air-cooling)  may be more cost effective in continuous service (>6,000 hr/yr),  than
          operating adjustments which impose a fuel penalty (e.g., retard,  or air-to-fuel  change)
      •   The  price of fuel  can affect the impact of a control which incurs a fuel  penalty.   For
          example, a control which imposes a fuel penalty of  5 percent for  both gas and diesel
          engines  has  more impact  on the diesel fueled engine because diesel oil  costs more
          (2.20/106 Btu compared to $1.00/106 Btu for natural gas).   This fuel  impact may diminish
          if gas  prices increase more rapidly than oil prices.
      In  contrast to the large  stationary engines, more published cost data exist for smaller
(<375 kW,  500 hp)  gasoline  and diesel engines which must meet State (California) and Federal
emission limits for mobile  applications.   Stationary engines in this size range are versions of
these mobile engines.   Therefore, costs can be estimated based on a technology transfer from mobile
applications to stationary  service,  keeping in mind that in some cases mobile duty cycles  (variable
                                                 4-67

-------
       TABLE 4-17.  COST IMPACTS OF NOX CONTROLS FOR LARGE BORE
                    ENGINES (Reference 4-43)
       Control
                   Cost Impact
Retard
Air-to-fuel changes
Derate

Manifold air cooling

Combinations of above
Control  techniques
Increased fuel consumption
Increased fuel consumption
Fuel penalty, additional hardware, and increased
maintenance associated with additional units
Increased cost to enlarge cooling system, and
increased maintenance for cooling tower water
treatment
Initial, fuel, and maintenance
Increases as appropriate
                                    4-68

-------
 TABLE  4-18.   TYPICAL  1974 BASELINE COSTS FOR LARGE
               (>75  kW/Cylinder)  ENGINES3
Costs
1. Initial ,b $/kW
2. Maintenance,
$/kWhr
3. Fuel and lube,
$/kWhr
Total Operating,
2 + 3
Gas
174
4 x 10'3
10 x ID'3
14 x TO'3
Dual Fuel
174
4 x 10'3
10 x 10~3
14 x TO'3
Diesel
174
4 x 10-3
23 x 10"3
27 x 10"3
aBased on Reference 4-112 and information supplied to
 Reference 4-43 by manufacturers.
 Includes basic engine and cooling system.
                           4-69

-------
load) can differ from stationary duty cycles (rated load).  Thus, costs  (e.g.,  fuel  penalties)
associated with a control technique used 1n a stationary application may vary from the  mobile case.
Control costs for automotive vehicles required to meet State and Federal emission  limits  are  typical
of the costs for small and medium gasoline and diesel fueled engines.  However, more  research is
required to relate specific emission control reductions to initial and operating cost increases for
stationary engine applications.

4.2.10.4  Gas Turbines
       The most recent cost study of NOX controls for gas turbines was performed by the EPA (Refer-
ence 4-69).  Based on information presented in this study, the best available systems of emission
reduction (considering costs) are wet systems, since these can be applied to turbines immediately
at minimal cost impact.   Although dry control techniques are preferable because of their potential
simplicity, their complete development and application to large production turbines is still several
years away.  Cost considerations for dry methods are, therefore, not discussed.
       Table 4-19, derived from Reference 4-69, shows the expected increase in installed turbine
cost that results from using water injection to control NO  to a proposed standard of 75 ppm.   The
impact varies from 0.8 percent for the 820 kU (1100 hp) standby unit to 7.1 percent for the unit
that requires extensive  water treatment equipment.
       Table 4-20 summarizes the operating costs (in mils/kWhr), which would be incurred for 11  dif-
ferent simple cycle turbine plants meeting the proposed 75 ppm standard.   This analysis was part of
a cost model developed in the EPA report (Reference 4-69).
       The first two units in Table 4-20, S-l and S-2, differ only in the number of hours operated
annually.  S-l operates  80 hours, and S-2 operates 200 hours per year.   These units show the highest
percentage impact in terms of the added costs per net kWhr of power generation.   The low number of
hours operated each year increases the cost of producing power, because fixed costs are spread over
a relatively small base.   The estimated impact in both cases was roughly 2.4 percent.
       Cases S-3 and S-4 are 820 kW (1100 hp) units operating the same number of hours, respectively,
as the smaller 261 kW units.  These units can use exactly the same water purification system  as the
smaller units.  Since the costs of producing power Independent of the water injection system  are
identical, the percentage impact is much less, decreasing to less than 1 percent.
       Case 1-1  represents a normal, single shift gas turbine application.  The unit  is operated
2,000 hours per year and  is slightly oversized, which negates any benefits that might be  derived
                                                4-70

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TABLE 4-19.  IMPACT OF NOx EMISSION CONTROL  ON THE  INSTALLED 1975  CAPITAL  COST
             OF GAS TURBINES (Reference 4-69)
Application
A. Standby
1. 261 kW (350 hp)
2. 820 kW (1,100 hp)
B. Industrial
1. 3 MW (4,000 hp) -typical
2. 3 MW - offshore
C. Utility
1 . 66 MW
Installed Cost (1000$)
Without
Control s

56.6
177.9

352.8
352.8

9,900.0
With
Control s

58.0
179.3

366,8
379.8

10,070.0
% Increase

2.4
0.8

4.0
7.1

1.7

-------
                              TABLE 4-20.   1975 COSTS  FOR WATER  INJECTION, MILLS/KWHR
                                            (Reference  4-69)
Item
Unit Size
Hours of Operation
Per Year
Annual 1 zed Fixed
Costs
Operating Cost of
Water Treatment
Hater for Injection
Energy Penalty
Mater Transport
Costs
Output Enhancement
Total
Baseline Costs
Percent Impact
Standby
S-l
261 kH
80
13.65
0.46
' 0.01
0.51
-
-
14.63
611.29
2.39
S-2
261 kW
200
5.46
0.46
0.01
0.51
—
-
6.44
264.79
2.43
S-3
820 kH
80
4.32
0.37
0.01
0.51
—
-
5.21
611.29
0.85
S-4
820 kH
200
1.73
0.37
0.01
0.51
—
-
2.62
264.79
0.99
Industrial
1-1
3 MU
2,000
0.48
0.10
0.01
0.43
—
-
1.02
43.77
2.32
1-2
3 MU
Z.OOO
0.12
0.10
0.01
0.43
—
0.09
0.57
32.53
1.75
1-3
3 MH
3,000
0.12
0.10
0.01
0.43
0.64
0.09
1.21
35.53
3.71
Utility
U-l U-2 U-3 U-4
66 MH
200
2.58
0.11
0.01
0.34
—
-
3.04
180.00
1.69
66 MU
500
1.03
0.11
0.01
0.34
—
-
1.49
85.45
1.75
66 MU
2,000
0.26
0.11
0.01
0.34
-
-
0.72
38.20
1.88
66 MU
8,000
0.06
0.11
0.01
0.34
—
o.n
0.41
26.39
1.56
Offshore
Drilling
Platform
3 MH
8,000
0.23
0.35
-.
0.43
—
0.09
0.92
32.53
2.83
ro

-------
from improved unit output.  For Case 1-2, also a  baseload turbine,  a credit was taken for the im-
proved capacity of the unit.
       The highest cost impact was recorded  in Case  1-3,  which represents  a remote  turbine applica-
tion in an arid climate in which water must  be transported 50 miles at a cost of $0.02 per gallon.
The impact in such cases, including water storage facilities, is  approximately a 3.7  percent  in-
crease in the average cost of generating power.   Since  water injection results in a slight increase
in the power output capacity of the unit, a  credit of 0.05 mills  per kWhr  was taken for the output
enhancement.  A credit for enhanced output was also  taken in the  U-3 unit,  since it is baseloaded.
In all four utility cases, the impact is less than 2 percent per  kWhr.
       Initially, it was thought that the offshore drilling platform would  show the highest cost
impact.  The unit was assumed to use sea water to fuel  the water  purification system,  which in-
volved a substantial increase in the capital and  operating cost of  the system.   The installed cost
of  the water treatment equipment was $27,000, compared  to $14,000 for an onshore application.
Despite these higher costs, the availability of water offset the  costs associated with transporting
water to the remote gas compressing station  application (1-3).  The total  cost of water injection
 for the offshore platform was 0.92 mills/kWhr compared  to 1.21  mills/kwhr  for the remote site.
       In summary, the resulting estimates showed that, except for  standby  units, the  total change
 in  costs probably falls within the range of  0.4 to 1.5  mills per  kWhr for  turbines  used in  industrial
 and utility applications.  This cost is equivalent to about a 2 percent increase in operating costs.
 Control costs for standby units were much higher, ranging from 2  to 14 mills per kwhr, because they
 are used less.  The cost  is equivalent to approximately a 2.5 percent increase in operating costs.

 4.2.10.5  Residential Heating Systems
       Advanced low-NO  burners in new furnace units are  the best options  for NOX control  in space
 heating equipment.  A Blueray unit has been  commercially  available  since 1974 and has  been  widely
 tested in field installations, while a Rocketdyne unit  is undergoing field  demonstration  preparatory
 to  certification and potential commercialization.  With proper maintenance,  both units offer NOX re-
 duction potentials of 50 percent or greater  and fuel savings of 5 percent  or more,  relative to
 standard units.  Using these low-NOx units in new houses  and replacing obsolete conventional units
 in  existing houses would decrease residential NOX emissions nationwide, offsetting  the potential
 emissions increase from population growth, for several  decades.
       The  1975 cost, less  installation, of  the Blueray unit was  $550 (Reference 4-113), compared
 to  conventional warm air furnaces which range from $300 to $500.  The added cost of the low-NOx
                                                 4-73

-------
 unit  may be  justified,  however,  since fuel  savings result from the Improved thermal efficiency.
 Differential  costs  for  the  Rocketdyne unit  are comparable.
        The prospects  for cost-effective NOX control  in existing space heating units are not prom-
 ising.   There are no  modifications which significantly decrease NOX emissions.  Furnace tuning and,
 if required, burner head replacement are strongly recommended for reduction of carbon monoxide and
 smoke and for improving unit efficiency, but thase modifications have little impact on NOX.  Furnace
 tuning (cleaning, nozzle replacement, leak  detection,  sealing and burner adjustment) costs a minimum
 of $40 for the average  residential  unit, while head  replacement costs an additional $25, less installa-
 tion.  This  servicing is usually cost effective since  it saves fuel  and increases safety of operation.

 4.2.10.6  Industrial  Process Heating
        Currently, there is  very  little application of  NOX control  to direct industrial process heat-
 ing equipment.   EPA's Industrial Environmental  Research Laboratory (RTP)' is sponsoring a field test
 program to identify the potential  for NO control  in a diversity of process furnaces,  ovens,  kilns,
 and heaters.   The program,  scheduled for completion  in 1979,  will  provide the data to evaluate
 alternate control options.

 4.3    FUEL  DENITRIFICATION
        To meet future NOV emission standards  for stationary sources, fuel NO  may have to be  reduced
                         A                                                   X
 to levels even  lower  than those  produced by combustion modifications.   "Fuel NO " emission reduction
 from  combustion equipment can  be achieved with  combustion modifications, clean fuel burning,  or by
 extracting the  fuel bound organo-nitrogen prior to burning  (fuel  denitrification).  This section  de-
 scribes the  state of  the art and the potential  application of denitrification of oil and coal.
 4.3.1   Oil Denitrification
        Current  technology for  denitrification derives  from pretreating fuel to remove  sulfur.   Heavy-
 oil cracking  (HOC), hydrodesulfurization  (HDS),  and  coking are the three major refinery processes to
 desulfurize  fuel  oil.   Hydrodesulfurization is  the most widely used and will be the only process dis-
 cussed  here.  HDS produces a very  low sulfur content liquid fuel  and,  at the same time, reduces
 nitrogen by about 20 to 40 percent.  Table  4-21  shows  the performance  and the reducing effect on  the
 nitrogen content of the fuel of  one  such  HDS process.
       Stringent federal and state regulations  for sulfur dioxide  emissions prohibit the direct com-
bustion of high sulfur Middle Eastern and South American  crude oils.   Therefore, virtually all  im-
ported oils are refined  for  partial removal  of  sulfur  before  they  are  used.  Presently two residuum
hydrodesulfurization techniques exist:
                                                4-74

-------
      •   Vacuum gas-oil  hydrodesulfurization (VGO)
      •   Residuum  desulfurization (RDS)
The VGO process, also  known  as  the indirect method, treats only the vacuum gas-oil product of the
vacuum distillation  process  with catalytic hydrodesulfurization, achieving at most 30 to 35 percent
desulfurization.  Since with this process the yields of low sulfur oil are relatively small and
since only vacuum gas-oil  can be treated, the residuum desulfurization technique or direct method
was developed.  The  advantage of residuum desulfurization is that it can catalytically desulfurize
residuum  from the atmospheric distillation process.
       Several  feedstock desulfurization processes are used by major oil companies to produce very
low sulfur solid,  liquid, and gaseous fuels.  The overall desulfurization (HDS) and denitrification
(HDN) chemical  reactions involved are (Reference 4-114):

                (organo-sulfur compound   j  + H  catalyst hydrocarbons +  JH2s)
                {organo-mtrogen compound J     *                          (NH37
 Hydrogen sulfide and ammonia are easily  removed with presently available technology.

               TABLE 4-21.   HYDRODESULFURIZATION PERFORMANCE OF THE GULF PROCESS
          Average of run properties
          for 375F+  product
Gulf HDS Process
Sulfur, Wt %
Nitrogen, Wt %
Nickel , ppm
Vanadium, ppm
Gravity, API
Carbon residue (Rams), Wt%
Heat of Combustion, Btu/lb
Pour Point, F
Viscosity, SUV at F
110
210
Feed3
3.8
0.21
15
45
16.6
8.3



3,500
160
Desulfurized residual fuel oils
Type III
0.3
0.13
1.1
0.8
24.5
3.3
19,250
20

435
55
Type IV
0.1
0.11
0.2
0.1
26.0
2.2
19,350
0

320
53.5
Improved
Type III
0.3
0.13
1.8
3.3
25.4
3.3
19,300
25

375
58
          aKuwait 650F+ charge to HDS
                                                4-75

-------
       Sulfided cobalt-molybdenum on alumina or nickel molybdenum  on  alumina  are typical  catalysts
 in these processes.  HOS and HDN occur simultaneously at suitable  temperature and pressures, but
 the reactions interact with each other In ways which are little understood.   Satterfield  (Reference
 4-114) has conducted an extensive program to uncover the interactions of  catalytic desulfurization
 and denitrification.  Thiophene and pyridine were used as model compounds  because they  represent some
 of the less reactive organo-sulfur and organo-nitrogen compounds.  The maximum conversion  of pyridine
 observed in Satterfield's work was 50 percent, whereas thiophene reached  100  percent  conversion.
 Figure 4-8 presents the results for HDN of pyridine alone on a NiMo/Al203  catalyst and  in  a  number
 of mixtures with thiophene.  Up to 655K, increases in reactor temperature  increase the  percent con-
 version of pyridine to ammonia.  However, as temperature is increased beyond  655K,  the  percent con-
 verted is decreased.
       The effect of thiophene on HDN is two-fold.  Below 600K the presence of sulfur compounds in-
 hibits the HDN reaction, but above 600K the presence of thiophene  enhances the HDN reaction.  This
 enhancement was attributed to the presence of H2S in the reaction, which prevents  the initially sul-
 fided catalyst to become rapidly desulfided.
       Large deposits of shale in the U.S. are seen as a promising source of  further  crude oil,
 but shale oil has a characteristically high concentration of nitrogen, ranging from 1.5 to 2.8 per-
 cent by weight.  More than two thirds of the nitrogen in crude shale oil is present in  the form of
 quinolines (pyridines) and indoles (pyrolles).  Frost, et al. (Reference 4-115),  studied the effect
 of reactor temperature and pressure on the degree of fuel denitrification from crude  shale oil using
 the catalytic hydrogenation method.  Nitrogen contents of the hydrotreated products ranged from
 0.005 to 1.59 weight-percent from the original 2.18 percent in the untreated  crude.   Frost demon-
 strated that denitrification of residual oils can be increased from 20 to 40  percent  removal to
 complete denitrification by progressively increasing the severity of the hydrogenation  process,
 either by increasing temperature or pressure or by changing to a more active  catalyst.
       As severity increases so does hydrogen consumption.   Figure 4-9 shows  the  percent denitrifi-
 cation as a function of hydrogen consumption.  As the amount of hydrogen needed to  denitrify the fuel
 increases, the operating cost of the process also increases significantly-  The majority of  recently
 reported hydrodesulfurization production costs (which produce 20 to 40 percent denitrification) are
between $5.00 and $10.70 per kiloliter of oil ($0.80-1.70/bbl)  (Reference 4-116).  The cost of
hydrogen  is  a major part of this total,  contributing as much as $3.80/kl  ($0.60/bbl)  for a process
using  approximately 170 nm3 of hydrogen  per kiloliter of feed (1000 scf H2/bbl  feed).  In  addition,
the higher pressures associated with increased process severity increase the  initial  investment cost,
                                                 4-76

-------
   80'
c
o
c
o
o
O)
c.
-o
c:
OJ
u
O)
o.
   60-
   40--
   20- -
                   I             I             I
       Partial  pressures  at reactor inlet (bars)
             Thiophene   Pyridine
             A
             +
  0
0.123
0.366
0.122
0.123
0.122
0.123
0.366
    Run No.

5/8, 5/11, 5/38
5/26
5/29, 5/31
5/34, 5/36
          Total  pressure  =11.2 bars
                                                    o
                                                    UN
                  200           300
                    Temperature,  C
                                           400
    Figure 4-8.   Pyridine HDN with NiMo/Al203 catalyst.
                            4-77

-------
     350- -
-a
Ol
C
o
o

c
Ol
01
o
     300-1-
250 - -
     200 __
     150 --
                    2200
                     800
                       20     30     40     50    60    70    80    90

                                  Nitrogen removed, pet of total
                                                                    100
          Figure  4-9.   Hydrogen  consumption versus nitrogen removal
                       (Reference  4-116).

-------
since more expensive  equipment is needed (Reference 4-117).   Hydroprocessing  is  undergoing rapid  tech-
nological development,  as  demands for low-sulfur and low-nitrogen  residual  oil  increase.
       Other  denitrification methods are also being investigated.   Guth  and Diaz  (Reference 4-118)
have patented an  oxidation process to desulfurize and denitrify  petroleum oils;  the  process has
been successfully operated at the pilot scale.  In the Guth and  Diaz  process, the  fuel nitrogen is
oxidized to the extent  that the resultant compounds exhibit preferential solubility  characteristics
in a solvent, usually methanol.  In some cases, pretreatment  of  the oil  to  remove  active  groups which
cause undesirable side  reactions or removal of low-sulfur  fractions prior to  the oxidation step are
necessary to  increase the  efficiency of the process.  The  oil  is separated  from  the  resultant solution
in a gravity  separator.  The extraction of the oxidized  nitrogen compounds  can be  carried out simul-
taneously or  in batches.
       One possible difficulty with this process is that some  oils  tend  to  react nonselectively
during the oxidation step and form undesirable polymers  and coke.   This  problem  can  be alleviated
by  preheating the feed oil to 475 to 660K  (300 to 600F)  for 2  to 20 hours to  permit  the reactive
groups in the oil to combine with other hydrocarbons and thus  become  less active.  Recent tests show
that up to 93 percent denitrification was  achieved with  distillate  oils  and 45 percent with residual
 oils.  This method is currently still under investigation; full  scale experimentation is  expected
 in  the near  future.
       This  denitrification and desulfurization process  is particularly  attractive since  it does not
require hydrogen and it operates at low temperatures and pressures.   Capital  costs range  from $4.50
to  $11.30 per liter per hour ($30 to $75 per  bbl/day) using distillate oil; process  operating costs
 range  from $0.50 to $1  per day (Reference  4-119).  Costs were  not  given  for residual oils, since the
 Guth-Diaz process does not denitrify all residuals.  One major application  of this process is in a
 small  refinery (133 kl/hr or 20,000 bbl/day capacity); the capital  investment would  be relatively
 small  compared with conventional  hydroprocessing.
 4.3.2   Coal  Denitrification
        Besides coal gasification  and liquefaction, alternative processes which  decrease the sulfur
 content of coal are presently being investigated.  Some  of these are:
       •   Solvent refined coal  (SRC)
       •   Meyers process
       •   Hydrothermal desulfurization
However, none of the above processes has shown any promise in removing fuel bound nitrogen from coal.
                                                4-79

-------
       Solvent refined coal is produced by dissolving raw coal In a solvent,  separating the ash from
 the coal by filtration, and reconstituting the coal from the solvent.  The  reconstituted coal  is  free
 of water, low in sulfur, very low in ash, and sufficiently low in melting point  that  it can be
 handled as a fluid, if desired.  Its heat content is higher than that of coal  at a  uniform value  of
 37,177 kJ/kg (16,000 Btu/lb), regardless of the original coal from which it was  prepared.
       Unfortunately, the nitrogen content of solvent refined coal is not reduced.  The results of
 two SRC tests conducted by Pittsburg and Midway Coal Mining Company (Reference 4-120)  in which  the
 nitrogen content was essentially unchanged are as follows:
                              TABLE 4-22.  SOLVENT REFINED COAL TESTS

% c
% H
% S
% N
% 0
% Ash
Feed
Composition
64.76
4.36
4.94
1.85
8.33
15.76
Product
Composition #1
87.50
5.23
0.882
2.040
4.17
0.179
Product
Composition #2
87.32
5.11
0.944
1.909
4.58
0.133
 Increases can be attributed to errors 1n material balance procedures and to the fact that ash was
 removed.  Because of its significantly lower sulfur content and improved heating value SRC has great
 potential for future use as a utility fuel.  Its impact on "fuel NOX" emissions will be insignificant
 since the fuel nitrogen content remains unchanged.  However, NO  emissions on a basis of Ib/MBtu may
 decrease due to the higher heating value of solvent refined coal.
       In the Meyers process,, the pyritic sulfur in the coal is removed by a reaction with ferric
 sulfate in a solution containing ferric and ferrous sulfate and sulfamic acid, the elemental sulfur
 product is extracted with an organic solvent.  Analysis on the product coal showed that the nitrogen
 content was essentially not affected by the Meyers process (References 4-121 and 4-122).
       E. P. Stambaugh of Battelle Memorial Institute (BMI) has also developed a process for re-
moving sulfur from high-sulfur coal.  The Battelle Hydrothermal Coal Process (BHCP) involves heating
a coal slurry and a chemical leachant at moderate temperature and pressure to selectively extract
 the sulfur and some of the ash from the coal.  As with other coal pretreatments, hydrothertnal treat-
ment does not extract the nitrogen (References 4-123 and 4-124).
       In summary,  with present technology, only liquid fuels can be denitrified.  High temperature,
high pressure catalytic hydrodesulfurization is the most widely accepted way to denitrify residual oil.
                                               4-80

-------
No new Improved  technology has been investigated on  a  full  scale  basis,  although some  new processes
have been  developed and tested with pilot scale facilities.
       The present HDN processes have several disadvantages  that  contribute  to  the  ever increasing
cost of desulfurization and denitrification.  First, it  is  costly to use hydrogen to remove  sulfur
and nitrogen.   Hydrogen must be produced by pyrolyzing hydrocarbon materials or through combustion
of hydrocarbons to form carbon monoxide, which  is  subsequently reacted catalytically with water  at
high temperature.  Second, the process requires a  heterogeneous catalyst.  The  surface of the  solid
catalyst tends to become fouled (particularly when residual  oils  are desulfurized), making the pro-
cess  inefficient or not feasible with some  residual  fuels.   And thirdly, the process requires  high
 temperatures and high pressures, which necessitates  expensive equipment.  The nitrogen content
of coal is not easily reduced unless the coal is first converted  to a liquid fuel (i.e.,  coal
liquefaction).  Presently, no coal desulfurization .processes have any significant effect  on  fuel
nitrogen.

 4.4    FUEL ADDITIVES
        Fuel additives have been used for many years  as agents to  reduce  soot and ash deposits  on
 heat transfer surfaces and to minimize the  corrosion effects of these deposits.   Fuel  additives
 have contributed to improved equipment performance and maintenance, but  recently, fuel  additives
 have been  investigated as possible aids in  reducing  nitrogen oxide emissions from small steam  gen-
 erators,  gas turbines, and 1C engines.
        Additives can theoretically reduce NO  emissions  through one or a combination of the  follow-
                                            X
 ing effects (Reference 4-125):
        •   Catalytic reduction or decomposition of NO  to N2
        •   Reduction of local concentration of  atomic  oxygen
        •   Reduction of flame temperature through  increased thermal radiation and dilution
        •   Delay of ignition timing in 1C engines
        •   Decrease of fuel/air mixing through  a change  in  spray  fluid dynamics
        A  number of investigators have experimented with  numerous  fuel additives in  order  to  reduce
 NO  emissions.  Shaw (Reference 4-125) investigated  approximately 70 additives  in a jet-fueled gas
   A
 turbine combustor.  The organometallic additives,  cobalt, iron, copper,  and  manganese  were added
 to the fuel in 0.5 percent by weight concentrations.  They  acted  as reducing and decomposing catalysts
 and reduced N0x by 15 to 30 percent.
                                                 4-81

-------
       McCreath (Reference 4-126) investigated the effect of additives on NOX emissions  from diesel
engines.  He found that both isoamyl nitrate and ditertiary butyl peroxide, which  reduced  the igni-
tion delay, could reduce the nitrogen oxides content of the exhaust gas by 15 to 18  percent  using
0.15 moles of additives per liter of diesel fuel.  Other organometallic compounds  in concentrations
of  1 percent by volume reduced NO  by 16 percent in laboratory burners (Reference  4-127).

       One of the more comprehensive studies on fuel additives was reported by Martin, Pershing, and
Berkau  (Reference 4-128).  Over 200 currently marketed additives were tested on diesel fuel  and
burned  in an experimental furnace.  No NO  reduction was reported; instead, some of the  nitrogen
containing additives increased NO  emissions.  In continuation of their work (Reference 4-129), four
                                 A
of  the most widely publicized materials (Trimex, Pace, KAP, and Glo-Klen) were tested in a 40 kW
(54 hp) firebox-firetube packaged boiler firing residual oil.   The additives were  blown  into  the
primary combustion zone, but the effect on NO  emissions under all conditions investigated was in-
significant, and particulate emissions increased significantly.  A good state-of-the-art review of
combustion additives may be found in Reference 4-130.

       One problem with additives is since liquid and solid fuel  additives contain large quantities
of  solids and inerts, including potentially corroSive salts or toxic metals, they  can create a
severe air pollution hazard or can be otherwise deleterious to equipment and surroundings.  Also,
at  $2 to $20 dollars per kilogram, fuel  oil additives  can be very expensive (Reference 4-128).

       Another potential  use of fuel additives is in combination  with well established NO  control
                                                                                         X
techniques; they suppress some of the negative effects that the control  techniques have on other
pollutants and combustion equipment performance.  For example, for large multiburner boilers firing
residual oils and coal, off-stoichiometric combustion  through  staged firing and low excess air are
well known combustion modification techniques with definite NO  reduction effects.  The degree of
implementation of these techniques is limited by adverse side  effects such as

       •   Localized reducing atmosphere leading to heat transfer surface corrosion especially
           with high sodium and high vanadium fuels

       •   Decreased convective heat transfer leading  to loss  in  superheater steam temperatures

       •   Fouling and corrosion of air  heaters

       •   Increased hydrocarbon particulate matter causing boiler efficiency loss

Additives  with high metallic concentrations which act as oxidation-promoting catalysts can help alle-
viate  these adverse side  effects, thus,  theoretically allowing increased  flexibility of  NOX  reducing
combustion modifications  (References 4-131  and 4-132).  This concept has yet to  be investigated, but
could  result in  lower NOX emissions.   Some of the benefits of fuel additives toward NO   reduction are
                                                                                      X
listed  in  Table  4-23.   Most of these additives are used in utility and large industrial  boilers.

                                               4-82

-------
                                                 TABLE 4-23.  FUEL ADDITIVES WITH POSSIBLE PERIPHERAL BENEFITS TO NO..
                                                              CONTROL TECHNIQUES IN BOILERS
                       Additive Function
                    Combustion  improver
00
OJ
                    Corrosion  inhibition
                    Antifoul ing
                     Soot,  smoke  and  carbon
                     particulate  reduction
      Possible  Benefits  to
     NO  Control  Techniques
Increased flexibility of:
  Low excess air
  Off stoichiometric combustion
  Flue gas recirculation
  Alternate fuel usage
  Combination of the above

Increased flexibility of:
  Low excess air
  Off stoichiometric combustion
  Alternate fuel usage
  Combination of the above

Increased flexibility of:
  Low excess air
  Off stoichiometric combustion

Increased flexibility of:
  Low excess air
  Flue gas recirculation
  Off stoichiometric combustion
       Applicable Fuel
Distillate and residual oils,
coal, mixed fuels
                                                                                       Residual  oil  and  coal
Residual oil and coal
Distillate and residual
oil, coal
 Manufacturer Suggested
      Addition Rate
Oil -0.01  to  0.1  mol  %
Coal -0.01  to 0.02  wt ?.
                                  Oil - 0.01 to 0.1 mol  %
                                  Coal - -0.005 wt %
Oil - 10 to 1,000  ppm
Coal -0.01 to 0.02 wt  %
Oil -0.92 to 0.96 g/1
Coal - -0.04 wt %

-------
       In summary, the results of recent studies on fuel additives for NOX control  have  been  mixed.
In some cases additives had a significant effect on NO emissions, while in other studies they did not.
Overall, the use of additives for controlling NOX* is not attractive due to added cost, serious op-
erational difficulties and the presence of the additives as pollutants in the exhaust gas.  However,
it has been proposed that some fuel additives may provide a peripheral benefit to NOX control, by
allowing increased flexibility in applying combustion modification techniques.  The potential for
adverse environmental impacts due to this practice will be considered in the NOX E/A.

4.5    ALTERNATE AND MIXED FUELS
       One alternate NO  reduction method involves the use of a fuel with a low-nitrogen content
(to suppress fuel NO ) and/or one that burns at a lower temperature (to reduce thermal N0x).  Fuels
with relatively small amounts of sulfur and chemically-bound nitrogen are referred to as "clean"
fuels, and are most desirable from an environmental point of view.
       Natural gas firing (a "clean" fuel) is an attractive NO  control strategy; it produces no
                                                              X
fuel NO  and it provides flexibility for implementing combustion modification techniques.  However,
since natural gas is becoming increasingly scarce,  many large users are having to switch to coal.
       At present, coal  contributes only about 18 percent of the energy utilized in the  U.S. annually,
but the production of coal  has been projected to increase 72 percent from 56.1 Tg (618 x 106 tons)  in
1974 to 94.4 Tg (1,040 x 10s tons)  in 1985 (Reference 4-133).   Since the direct combustion of coal
adversely affects the environment,  there is a tremendous research effort directed toward making cleaner
fuels not only from coal,  but also  from other sources.   A brief discussion on combustion experience
with these fuels and on the prospects for low NO  emissions follows.
4.5.1  Western Coals
       The direct combustion of western subbituminous coals in large steam generators generally pro-
duces lower N0x emissions.   Three mechanisms are responsible for lower NO  emissions:  first, western
coals, in general, contain  less bound nitrogen than eastern coals on a unit heating  value basis;
second, the excess 02 in a  steam generator burning western coal can be maintained at very low levels;
and third, the high moisture content of western coal produces lower flame temperatures.
       N0x emissions for an 88 MW (130,000 Ib steam/hr) industrial boiler firing pulverized western
coal at baseline conditions were 24 percent lower than for eastern coals (Reference  4-48).   NO  emis-
sions remained unchanged when firing western coal in stokers.  However, the slope  of the NO  vs. ex-
cess 02 curve for a water-cooled vibrating grate stoker firing western coal (Wyoming Bighorn) was
12 ppm/percent excess 02. compared to 35 ppm/percent excess 02 for eastern coal  (Kentucky Vogue).
                                                 4-84

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      Some specific  problems  associated with burning low-sulfur,  high moisture content  coals  in
combustion equipment  designed  for higher quality coals are listed  below  (Reference 4-134):
      •   Poor  ignition
      •   Reduced  boiler load capacity
      •   Increased  carbon loss
      •   Boiler fouling
      t   High  superheat steam temperature
       •    Flame instability
       •    Increased  boiler maintenance
       •    Reduced  boiler efficiency
       •    Reduced  collection efficiency of electrostatic precipitator (ESP)

 4.5.2  Low-Btu Gas
       NO  emission data are sparse for low-Btu gas, defined here  as having a net heating value of
 3.0 to 5.9 MJ/nm3 (75 to 150 Btu/scf).  The data available from combustion equipment firing low-Btu
 gas show that NO  emissions from a 1.3 MW (4.5 x 10s Btu/hr) furnace firing 100 percent low-Btu gas
                X
 were below 10 ppm (Reference 4-135).   The same furnace burning 100 percent natural gas produced
 60 ppm NO.   The  lower NO  emissions,  ranging from 0 to 10 ppm for  NO, when burning low-Btu gas were
 attributed to both  decreased peak temperature and decreased combustion intensity.   The NO  emissions
 were obtained using an experimental combustor can and air preheat  temperatures up to 1070K (1.250F)
 to simulate gas  turbine conditions.  Compared to natural gas and No. 2 oil, a 50 to 65 percent re-
 duction in NO  emissions  for a 70 to 80 MW gas turbine firing low-Btu gas was projected (Reference
 4-136).   The fuel nitrogen cleanup of this low-Btu gas involves removing mainly NH3 (also 30 to over
 50 percent of the gas is  N2).   The level of NH3 in the gas depends on the particular coal and gasi-
 fication  process used.

 4-5.3  Medium- and  High-Btu Synthetic Gas
       Medium-Btu gas (having  a heating value of about 11.8 MJ/nm3 or 300 Btu/scf) is being considered
 for direct firing,  after  cleanup, in  utility boilers located at the gasifier site with only minor
 modifications to current  state-of-the-art combustion equipment (Reference 4-137).  Another possibility
 being evaluated  is  burning this gas in oxygen-fired steam generators.  Since bulk oxygen is needed
 for the gasifier, the additional cost to supply the steam generator should not be prohibitive, but
 this type of combustion process will  require considerable boiler design changes.
                                                4-85

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       Medium-Btu gas and oxygen should produce combustion temperatures  greater than 2790K (4.000F),
but the total NO  production should still be Insignificant since molecular  and fuel  nitrogen are
absent (Reference 4-138).
       Medium-Btu gas can be upgraded to high- (35.4 to 39.4 MJ/nm3 or 900  to  1,000  Btu/scf) Btu gas.
High-Btu gas is indistinguishable from natural gas, except it may form fuel  NOX if any bound nitrogen
(NH3, HCN, etc.) is present.

4.5.4  Synthetic Oil from Coal
       The physical and  chemical properties of synthetic oil are a function  of the coal  properties
and processing  conditions.  Direct combustion of the oil without pretreatment  represents an  environ-
mental problem, since the oil typically has a high nitrogen content (0.7  to  1.8 percent by weight).
This percentage of nitrogen corresponds to 400 to 1,000 ppm of NOX emissions,  based  on 40 percent
fuel nitrogen conversion, and would require the use of combustion modifications to reduce NO to
acceptable levels (Reference 4-135).
4.5.5  Coal-Oil Slurry
       The need to stretch domestic oil supplies has renewed government interest in  using coal-oil
slurries for direct combustion in steam-generating equipment.  Coal-oil slurries could be made en-
vironmentally acceptable, depending on the quantities of pollutants present  in the coal  and  oil and
the percentages of coal  and oil used in the slurry.  A General Motors program  investigating  the use
of coal-oil slurries concluded that emissions of oxides of nitrogen increase with  increasing coal
concentration and decreasing coal particle size (Reference 4-139).  The quantity of  coal that can be
used is limited by slurry stabilization, combustion equipment performance,  and environmental  aspects
(Reference 4-140).
4.5.6  Methanol
       Currently, the synthesis of methane from natural gas is the major source  of methanol.  But
due to the shortage of natural gas, future production will have to come from  synthetic  gas  generated
from coal.  Baseline NOX emissions from the combustion of methanol in an experimental hot wall  fur-
nace system were reported at 50 to 70 ppm, compared to 240 to 300 ppm for  distillate oil.   With flue
gas recirculation, the NOX emissions from methanol combustion were reduced to 10 ppm or 15  percent
of the baseline level  (Reference 4-141).   The hot wall experimental furnace also showed a 20 percent
increase in stack heat loss (SHL), compared to SHL of 14 percent for distillate  oil (based on 115
percent theoretical  air at a 475K stack temperature).   In gas turbines 74  percent less  NO  was
                                                4-86

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produced using methanol, compared to distillate  oil.   Turbine efficiency levels increased by
6 percent due to higher inlet temperatures.
       Methanol is generally a potentially  attractive fuel  for use in area sources where clean
fuels are necessary for environmental  reasons.   Its  current high price does not justify its use.

4.5.7  Water-Oil Emulsions
       Residual oil emulsions with up  to  35 percent  water were fired in a Scotch packaged boiler
rated at 700 kW (2.5 x 10s Btu/hr).  NOX  emissions were not reduced from the baseline  level  (oil
only) for a given stoichiometric ratio.   This was attributable to the high nitrogen content of
the residual oil; emulsions affect only thermal  NOX  (Reference 4-142).   In the same experiments,
because of the reduction in smoke levels, the boiler could  be operated  at a lower stoichiometric
ratio, which reduced the NO  emissions.
       Emulsions have a definite NO  reduction potential  when distillate oil  is used (Reference
 4-143).  NO  emission levels from emulsions with approximately 50 mass  percent water in distillate
 oil approached the levels obtained from methanol combustion (Reference  4-135).
        In conclusion, the feasibility  of  alternate fuel firing as a NO   control option  is  contingent
 in part on the cost trade-off between  synthetic  fuel  production and the total  control  costs  for NO
 SO and particulates in conventional coal firing.  There is preliminary evidence that  gasification
 may be  more costly than flue gas cleaning of conventional systems.

 4.6   ALTERNATE CONCEPTS
       The recent domestic shortages in conventional  clean  fuels, the rising cost of oil  and gas,
 and above all, the need to limit the pollutant emissions resulting from burning fossil  fuels have
 accelerated the development of alternate  energy  concepts.  Some concepts (e.g., catalytic combustion,
 fluidized bed combustion, and gasifier combined  cycle) are  being developed for their potential not
 only  to increase system efficiency, but also to  reduce total  system emissions.   Other  alternate con-
 cepts (e.g., repowering, high temperature gas turbines) are being developed mainly to  increase ef-
 ficiency and reduce fuel consumption.
        Catalytic combustion systems and high temperature gas turbine developments are  well underway.
 Within the next decade catalytic combustion may  find use in gas turbines and space heating; high
 temperature gas turbines are expected  to  be commercially available in the late 1980's.
        Fluidized bed combustion and combined cycle development are also in progress.  Several  organ-
 izations are building pilot-scale fluidized bed  combustion  units, and commercialization of fluidized
 bed combustors may take place during the  late 1980's.
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       Another alternate concept, repowering, is a method of  upgrading existing power plants to make
them more competitive at today's fuel prices or to make more  efficient use of present fuel contracts;
prospects for widespread use of this concept are presently  uncertain.

4.6.1  Catalytic Combustion
       Catalytic combustion refers to combustion occurring  in close  proximity to a solid surface  which
has a special (catalytic) coating.  A catalyst accelerates  the  rate  of a  chemical  reaction, so  that
substantial  rates of burning should be achieved at low temperatures, avoiding the  formation of  ther-
mal NO .  Moreover, the catalyst itself serves to sustain the overall  combustion process,  thereby
minimizing the stability problems (Reference 4-144 and 4-145).  However,  the overall  success of a
catalytic combustion system in reducing CO and HC to low levels is a function of both heterogeneous
and gas phase reactions; surface reactions alone appear to  be unable to achieve the desired low levels.
       Emissions from catalytic combustion experiments have typically  been:   N0x < 2  ppm,  HC =  4  ppm,
and CO = 10  to 30 ppm.  Both gaseous and distillate fuels have  been  used  and combustion  efficiencies
above 95 percent have been obtained (Reference 4-145).
       The catalyst bed temperature must be held below 1810K  (2800F) to minimize the  formation  of
N0x.  At high temperatures, above 1275K (1.830F), catalyst  activity  decreases.   At present, cata-
lytic combustors are limited by the bed temperature capability.   Excess air can be used  to lower  the
bed temperature; but the use of excess air is unattractive  since  it  also  reduces thermal efficiency
(except in gas turbines).  Further research is underway to  consider  other systems, such  as catalyst
bed cooling, exhaust gas recirculation, and staged combustion to  maintain a low bed temperature.
       Recent tests evaluated the applicability of catalytic  combustors for gas turbines.   Test
fuels used were No.  2 distillate oil  and low Btu synthetic coal gas, for  a  range of pressure,
temperature, and mass flow conditions.  Test results show that  the catalyst bed temperature profile
at the bed exit was very uniform for low Btu gas, but not as uniform for  No.  2  oil.  Exceptionally
low emissions (2 to 3 ppm NO. 20 to 30 ppm CO) were achieved for both fuels, and  unburned hydro-
                            A
carbons (HC) were less than 1  ppm (Reference 4-146).  However,  much  additional  work is needed be-
fore catalytic combustion can be applied to gas turbines in the field.
       Catalytic combustion has been demonstrated to be effective in lowering emissions  of pollutants
such as NOX, CO, and HC, but at present, catalytic combustors are limited by the catalyst bed tempera-
ture capability.   Various government agencies and private industries are  developing catalysts that
will  withstand high temperatures, retain high catalyst activity,  and last longer.   Catalyst combustion
systems are also under development.   It appears that during the next 5 to 10 years, catalyst combus-
tion concepts may be incorporated into new gas turbine and  residential and commercial heating designs.
                                                4-E

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4.6.2   Fluidized  Bed Combustion
       In  its  simplest form, a fluidized bed combustor  (FBC)  contains  a  bed of granular material such
as coal, ash and  sand or limestone.  Hot air is blown through a  distributor in the  base of the com-
bustor vessel  to  "fluidize" the solid particles (I.e.,  the  particles are supported  by  the gas stream
and in rapid motion relative to each other).  This  process  creates  a bed which has  the appearance of
a boiling  liquid  and exhibits many fluid-like properties.
       For coal-fired FBCs, if the temperature of the bed remains above  the combustion temperature
of the coal,  the  FBC process will be self-sustaining.   The  bed temperature is  generally in the range
of 1075 to 1275K (1.500F to 1.900F) and the combustor may be  at  atmospheric pressure (AFBC) or it
may be pressurized (PFBC) (References 4-147 and 4-148).  Energy  added  to the bed by the combustion
process is removed, in a fluidized bed boiler, by the boiler  tubes, heat losses through the walls,
and the gas and solids leaving the bed.
       A 30 MW AFBC pilot plant began operation in  late 1976  (Reference  4-149).  Pressurized sys-
tems are still being tested, with a pilot plant planned for the  early  1980's.
       NO  emissions in fluidized bed systems depend on the equipment; significant  emissions have
         X
 been found in  some reactors (Reference 4-32).  NO   emissions  also depend, though weakly, on coal
 particle size, the type and amount of sulfur acceptor,  and  the amount  of excess air.  However, emis-
 sion levels from pressurized fluidized bed combustors are significantly  less than from atmospheric
 combustors, probably due to greatly increased NOX decomposition  rates  at elevated pressures.
       NO  levels in most coal-fired fluidized bed  experiments conducted at atmospheric pressure
 are on the order of 300 to 500 ppm (Reference 4-150).   NO   emissions from a pressurized FBC, even at
 100 percent excess air, are well below the current  standards  of  300 ng N02/J (0.7 lb/106 Btu).
 Results of 160 ng/J (0.41 lb/106 Btu) have been reported (Reference 4-149).  The principle disad-
 vantages of FBCs, are (1) potentially large amounts of  solid  waste  (the  sulfur acceptor material)
 and (2) heavy particulate loadings in the flue gas.  The feasibility of  an FBC for  power generation
 will depend on developing
       •   Efficient methods for regeneration and recycling of the dolomite/limestone  materials used
           for sulfur capture and removal
       •   Complete combustion through flyash recycle or an effective  carbon burnup cell
       •   A hot-gas particulate removal process to permit  use of the  combustion products in a com-
           bined  cycle gas turbine without excessive blade  erosion
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4.6.3  Repowering
       Repowering adds a combustion turbine to an existing steam plant,  providing additional  capacity
at lower initial capital costs and lower energy costs than other means available  to  a utility.
       Repowering includes:  (1) steam turbine repowering, in which gas  turbines  and new heat re-
covery boilers are added to an existing steam electric generating plant;  (2)  boiler  repowering in
which gas turbines are added to the existing steam generating facilities  for  power generation, re-
quiring the conversion of existing conventional boilers to heat recovery  type boilers;  and  (3) gas
turbine repowering in which a steam generating plant is added to an existing  gas  turbine plant
(References 4-151 and 4-152).
       Depending on the system and power needs, repowering of existing facilities  offers the  follow-
ing  advantages:
       •   There is no need to acquire and develop a new plant site
       t   Repowering generally requires smaller increments of investment, saving  on  fixed  charges
           since major investment on new plants is deferred
       •   Repowering improves heat rate, which lowers fuel consumption
       •   The environmental impact is reduced, with improving schedules  for"  environmental  and site
           related approvals
       t   For boiler and steam turbine repowering, there is no increase  in cooling water requirements
       •   Gas turbines may be operated independently as peaking units, which provides  greater plant
           flexibility
       References 4-151 and 4-152 describe in detail the application of repowering to boiler, gas
turbine, and steam generating plants; savings in capital and operating costs  are  anticipated.  Under
contract from the Electric Power Research Institute, Westinghouse Electric Corporation  is evaluating
repowering conventional steam power plants without replacing the boiler.  The present use of  repower-
ing is very limited.   It may see extensive use in the 1980's if significant increases in  generating
capacity are needed.

4.6.4  Combined Cycles
       Combined cycles may,  in  the long term, reduce emissions of sulfur  oxides,  nitrogen oxides,
particulate matter, and waste heat while generating power at efficiencies higher  than conventional
fossil- and nuclear-fueled steam stations (Reference 4-153).
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      The combined  gas  and steam turbine system consists of  a gas  turbine  using  a  coal-deHved  fuel,
which  exhausts  Into  an  unflred waste-heat-recovery boiler.  At the  gas  turbine  Inlet,  the most
economical large-scale  steam system would operate at  16.5 MPa (2,400  pslg)  with 810K (l.OOOF) throt-
tle steam and 810K (l.OOOF) reheat temperatures.  In  this system, roughly 66  percent of  the power
would  be generated by the gas turbine; the remaining  34 percent would be generated  by  the steam
boiler system  (Reference 4-154).
       Combined cycle efficiency Improves significantly as  the gas  turbine  Inlet  temperature is  in-
creased.  At turbine inlet temperatures of 1,478K (2.200F), an efficiency improvement  of 2 percentage
points per 56K  (100F) increase in turbine inlet temperature is found.
       A feasibility analysis on combined cycle systems was conducted by Solar, a division of Inter-
national Harvester.   The analysis showed that with the presently available  steam  turbines and boilers,
the efficiencies would not be sufficient to  justify a combined cycle.   Therefore, Solar  is developing
new small steam boiler and turbine designs which are  expected to be available by  1980.   Applications
of combined cycles include pipeline, offshore platform, marine, and small electric  utilities
 (Reference 4-155).
       The current status of combined cycles has been reviewed by Papamarcos  (Reference  4-156).   Ac-
 cording to Papamarcos, before combined cycles are commercialized, efficient fuel  conversion processes
 and high temperature gas turbines that can use coal-derived fuels must  be developed.   He estimates
 that  these developments will take place in some 15 to 20 years, and current ERDA  projections concur
with  his estimate.
 4.6.5 High Temperature Gas Turbines
       The efficiency and power output of a  gas turbine increase significantly as the  inlet tempera-
 ture  is increased.  Turbines that are used in the field are limited to  1075 to 1275K (1,500 to  1,800F)
 by the strength of the turbine materials.  A gas turbine firing stoichiometrically  at  temperatures
 above 1.920K (3.000F) would increase power output by  more than 150  percent, and thermal  efficiency
 relative to conventional units.  However, performance gains at higher temperatures  can be realized
 only  if losses  caused by the cooling system  can be kept to  a  minimum  (Reference 4-157).
       The current practice of turbine cooling, using air bled from the compressor, requires bring-
 ing the cooling air to the required pressure.  The power output is  reduced, since a substantial
 Portion of the  cooling air reenters the gas  downstream of at  least  one  of the bucket stages.  Moreover,
once  the cooling air reenters the gas, it decreases the gas temperature, which reduces the energy
available to the turbine and to the heat recovery system in the exhaust stack (Reference 4-156).
                                                  4-91

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       Because a high temperature gas turbine has higher potential  for Increased efficiency and
specific output, various methods which allow high temperatures  are  being considered.  These are:
       •   Water cooling
       •   Advanced air cooling
       t   Steam cooling
       0   Substitution of ceramic compounds
       In current programs, ERDA is funding four turbine manufacturers  (General  Electric,  Westing-
house, Curtiss-Wright, and United Technology) to develop a high temperature  turbine  technology
(HTTT).  And more recently, EPRI has funded a HTTT program at GE.  The  main  emphasis of these pro-
grams is to develop the high temperature portion of the gas turbine for firing temperatures of
1.700K (2,600F) and possibly up to 1,920K (3,OOOF).
       Efficiency will be improved and specific costs will be reduced  over the next  5 to 10 years
in high temperature gas turbine technology.  Leading gas turbine manufacturers are designing high
temperature gas turbines that can be operated up to 1.920K (3.000F) with  cooling of  the blades.  To
cool the blades, water cooling appears to be the most attractive method.
4.7    FLUE GAS TREATMENT
       Flue gas treatment (FGT) processes reduce NO  emissions  from combustion sources  through either
                                                   X
decomposition or oxidation/absorption.  Flue gas treatment has  potential  for use with combustion
modifications when very high removal efficiencies are required.  Much  of  the developmental work in
FGT has been done in Japan (References 4-61, 4-107, and 4-158 through  4-164).
       FGT is currently applied to only a few commercial gas- and oil-fired  boilers.   Research in the
United States in developing flue gas treatment has been minimal, since  needs have been  uncertain.
However, the recent emphasis of stationary source NO  emission  controls  has  encouraged further de-
velopment of FGT in the United States (Reference 4-165).
       FGT processes can be divided into two main categories:   dry processes and wet processes.  Dry
processes reduce NOX by catalytic reduction and operate at about 525K  (700F).  Wet systems remove
NOX by oxidation followed by scrubbing, and operate at 315 to 325K  (100F  to  120F).   Table  4-24
summarizes the available wet and dry processes.
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                              TABLE 4-24.   SUMMARY OF F6T PROCESSES
        Process
     Process Description
                                                                         Comments
Dry  Processes:

Hitachi shipbuilding
process
Selective  reduction
with ammonia
Hydrogen sulfide  process
Char (Bergbau  -  Fors-
chung - Foster Wheeler
Process)
 CuO (Shell/UOP
 flue gas desulfuriza-
 tion process)
CO and H2 in the  presence  of
catalysts selectively  reduce
NOX.  CuO, F6203, Cr203, NiO,
C0304, MnO, V205, and  Pt are
various catalysts that can be
used.
NH3 and 62 in the  presence  of
catalysts, reduce  MOX  to  MO.
Pt, Vanadia, Fe-Cr oxide  mix-
tures, Mo, Cu-Pb are some of  the
catalysts used.

Selective catalytic reduction of
NOX in the presence of H2S  (gas
phase)
A dry adsorption process.
S02, 02 and HjO  in flue gas
are adsorbed  in  the char pores.
Adsorbed S02  reacts with 02 and
H20 to form 1^04  which is  re-
tained by  char pellets.  NOX
is also absorbed by char.

CuO reacts with  S02 in  the  pre-
sence of 02 at 670K to  yield
CuS04
About 98% reduction can be obtained.
No wastestreams are produced.
Major drawback is that this process
requires catalysts which have the
selective behavior for promoting
faster CO/H2 - NO reaction than
CO/H2 - 02 reaction.

Above 90% reductions are achieved.
This process removes NO- and SOX
simultaneously.  Careful tempera-
ture control (480K-590K)
is necessary.
NOX reductions up to 98% are ob-
tained.  Removes NOX and SOX simul
taneously.  Condensation of sulfur
causes catalyst to lose activity.
100% use of H2$ is important since
it is toxic.

High removal rate (95%) for SOX;
only 40-65% of NO- is removed.
S02 can be reduced directly to
elemental sulfur.
Effective for SOX removal (90%),
removes 60-70% of NOX. Low pres-
sure drop through parallel flow
sorbent bed.  Easy regeneration
of sorbent.  No particulate
interference.
 Wet Processes:

 Sodium scrubbing
 (Fujikasui  process)
 Alkali permanganate
 (MON process)
 Sodium-potassium
 permanganate (Nissan
 process)
 Alkali scrubbing
 (Shinko process)
Gaseous  C102  oxidizes  NO to
N02.  N02  scrubbed  with NaC102-
NOX and SO? absorbed  and
oxidized with  alkali  permanga-
nate to form alkali nitrate
and sulfate

Two-step method.  NOX is
removed with NaOH.  Off-gas
is oxidized with permanaganate
and N02 absorbed with NaOH.
NOX is scrubbed  first with
liquid NaOH; off-gas is  sent
to second scrubber - a packed
granular alumina reactor
sprayed with NaOH and NaC102
Over 90% NOX reductions.  Low cost
and easy operation, but requires
waste water treatment because of
by-product effluents.
and
Over 90% NOX removal and virtually
all of S02-  No waste material is
produced.  Scrubbing agent (alkali
KOH) is expensive.

High removal rate (90%) of NOX.
Easy and flexible operation.
Byproduct potassium nitrate is a
fertilizer; however, waste water
treatment is required.

Over 95% of NOX removed with pro-
ducts of NaNOs, NaCl and gaseous
C102-  However, NaC102 is expensive.
                                                                             (Continued on page 4-94)
                                                4-93

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                                       TABLE 4-24.  Concluded
         Process
    Process Description
                                                                            Comments
                                                                                                       CO
                                                                                                       in
Chiyoda Thoroughbred 102
Alkali scrubbing
(Kyowa Kako)
Sodium sulfite
scrubbing
MHI (Mitsubishi Heavy
Industries)
Kureha reduction
Kawasaki magnesium
Chisso ammonia
scrubbing
Kobe steel  process
NO is oxidized by ozone and air.
Aqueous ^504 with an iron cata-
lyst act as scrubbing agents.
NOX is first scrubbed with
NaOH, off-gas is oxidized with
H?02, and then washed with
alkaline hydrogen sulfide or
alkali sulfide

Sodium sulfite reduces NOX to
N2
Ozone is injected into flue
gas; NOX is oxidized to
NgOs; this is reduced to Nฃ
by reacting with CaSOa in the
circulating scrubber liquor

NOX is scrubbed using 3
scrubbers:  sodium acetate,
limestone slurry, and sodium
sulfate and sulfite contain-
ing acetic acid and a cata-
lyst

Magnesium hydroxide slurry is
used as a scrubbing agent to
remove NOX

NOX is removed using ammonia-
cal solution containing a
soluble catalyst
Calcium chloride solution
containing Ca(OCl)2 is used to
reduce NOV
About 60% NOX  removal  efficiency.
Simple and easy  operation.   How-
ever, a relatively  low efficiency
NOX removal process  and requires
wastewater treatment and expensive
ozone.  Additional equipment needed
to remove ozone  from the exit gas
stream.

High NOX removal  (from 4,000 ppm
down to 50 ppm),  but requires
waste water treatment  and sludge
disposal
Over 90% NOX reduction.  Absorbs NO
directly, thereby eliminating costly
oxidizing agents.  Large flowrates
and excess Dฃ hinders NOX reduction.

Simple process, high (over 90%) NOx
removal.  Does not produce waste
water.  However, production of
ozone and the use of high concen-
tration of HNOs are costly.

Removes NOX and SOX simultaneously.
Produces useful gypsum and no waste
water streams.  However, it is a
complex process; and costly.
Removes both NOX and SOX.  Produces
marketable gypsum and calcium nitrate.
Process is complex and costly.

About 60 to 80% of NOX is removed.
Produces byproduct ammonium
sulfate.  Possibility exists
for plume formation.

High NOX removal efficiency is
attained.  Scrubber corrosion is a
problem.
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4.7.1   Dry  FGT  Processes
       Dry  processes  are mainly applied to flue  gas  streams  derived from burning gaseous  fuels.   Each
process developer  utilizes different catalysts,  catalyst  supports,  and bed configurations.   Dry  pro-
cesses  are  basically  simple, require little space, and  require  no reheating of the tailgases.
       Among the many dry process variations, selective catalytic reduction using ammonia  has  been
successful  in treating combustion flue gases for removal  of  NO  .  However, the large  amounts of
                                                              X
ammonia required would increase the consumption  of natural gas  considerably.   In addition,  any
ammonia left in the flue gases may combine with  the  S03/S(L  to  produce a visible plume, and by-
products, such as  ammoniuni-bisulfate, which are  corrosive to boiler tubes.
       Molecular  sieve adsorption is another dry FGT process identified as a  possible NO  control
technique; however, it was developed primarily for noncombustion applications, such as nitric  acid
manufacturing plants.  Molecular sieve adsorption is  not  applicable to the water-containing effluents
from combustion sources due to preferential adsorption  of moisture  and a resultant loss of  active
sites  (Reference  4-166).

4.7.2  Het FGT Processes
       Wet FGT processes utilize more complex chemistry than dry processes (Reference 4-165).  In
the wet processes, strong oxidants such as ozone or  chlorine dioxide are used  to  convert the rel-
 atively inactive  NO in the flue gas to N02 or NpOg for  subsequent absorption.   Thus, most of the
wet processes create by-products such as nitric  acid, potassium nitrate, ammonium sulfate,  calcium
 nitrate, and gypsum.
       Wet FGT processes use either liquid or gaseous chemicals to  complete the required NO oxidation.
 Liquid phase oxidation requires extensive liquid/gas  contact to absorb the inactive NO, thus the use
of liquid phase oxidation processes is limited,  because of the  large size and  pressure drop of the
NO absorber.
       Using ozone or chlorine dioxide to oxidize NO  in the  gas stream prior to the scrubber appears
to be a more successful approach.  Chlorine dioxide  is  expensive, however, and using  it introduces
the problem of disposing of chloride-containing  liquid  discharges.   Ozone is also quite costly,
requiring a great  deal  of electrical  energy to produce.  Also,  where ozone is  utilized, additional
equipment is required for removal of excess ozone from  the final gas stream.   Thus, oxidant cost is
likely to be prohibitive for flue gases with high NOX concentrations.
                                               4-95

-------
       Cost estimates for FGT processes are presented  in Table  4-25,  but these estimates are only
 preliminary since most  FGT processes are  in the  developmental stages  in the U.S.  Compared to com-
 bustion modifications,  FGT is considerably more  expensive,  but  is  capable of greater N0x reduction.
 Increased  costs result  from both higher capital  costs  and costs of chemicals and catalysts.
       In  general, the  dry FGT techniques used in Japan can probably  be applied to gas- and oil-fired
 sources in the U.S.  However, more pilot scale research and field  tests are needed before full  im-
 plementation of dry processes is possible.  Also, the  applicability of  dry  processes to coal-fired
 sources remains to be determined.  Wet processes are less well  developed and costlier than  dry  FGT
 processes, however, wet processes have the potential to remove  NO  and  SO  simultaneously.  Again,
                                                                 A       A
 more  field tests are needed to determine the costs, secondary effects,  reliability,  and waste disposal
 problems.  Flue gas treatment holds some promise as a  control technique for use when high NOX removal
 efficiencies are necessitated by stringent emission standards.
       Ammonia injection, discussed in Section 4.2.9,  is a competitive  process  which may prove more
 cost  effective for NOX  control.  Ammonia injection is  not applicable  to simultaneous NOX/SOX reduc-
 tion, however.
 4.8    EVALUATION AND SUMMARY
       Table 4-26 summarizes current and emerging NOX  control technology for the major  source categories.
 These results show that current technology is dominated by combustion process modification.  Emerging
 technology is also centered around combustion modifications.  Other approaches, such as flue gas treat-
 ment, may be used in the 1980's to augment combustion  modification if required  by  stringent emission
 standards.
       The level  of combustion modification control available for  a given source depends largely on
 the importance of that source in regulatory programs.  Utility  boilers  have been the most extensively
 regulated and accordingly, the technology is the most  advanced.  Available  technology ranges from
 operational adjustments such as low excess air and biased burner firing to  inclusion of overfire air
 ports or low-NOx burners in new units.  Some adverse operational impacts have been experienced with
 use of combustion modification on existing equipment.  In general  these have been  solved through
 combustion engineering or by limiting the degree of control application. With  factory-installed
 controls on new equipment, operational problems  have been minimal.
       The technology for other sources is less well developed.  Control techniques  shown effective
for utility boilers are being demonstrated on existing industrial  boilers.   Here,  as for utility
boilers,  the emphasis in emerging technology is on development  of  controls  applicable to new unit
design.   Advanced  low-NOx burners and/or advanced off-stoichiometric  combustion techniques  are  the
                                                 4-96

-------
TABLE 4-25.  1974 COST ESTIMATES FOR COMBUSTION FLUE GAS TREATMENT
             PROCESSES (Reference 4-160}
Process
Type
Met
Wet
Dry: selective
catalytic
reduction
Dry: selective
catalytic
reduction
Process
Chiyoda Thorough-
bred 102
Sumitomo
(Mo re tana)
Sumi tomo
Sumi tomo
Hitachi
Application
Oil-fired boiler
Oil-fired boiler
Gas-fired boiler
Oil-fired boiler
Oil-fired boiler
Estimated
Capital
Costs
$70-90/kW
$70-100/kW
$40/kW
$93/kW
$60/kW
Estimated
Operating
Costs
(mill/kWhr)
3-4
7
1.2
No Data
No Data

-------
                                                          TABLE 4-26.
SUMMARY OF N0x CONTROL TECHNOLOGY
ID
o>

Equipment/

Fuel

Category
Existing coal-
fired utility
boilers



New coal -fired
utility
boilers





Existing oil-
fired
utility
boilers

Existing
gas -fired
utility
boilers

Oil-fired
industrial
watertube
boilers





Current Technology

Available
Control
Technique
LEA + OSC
(OFA, BOOS,
BBF); new
burners


LEA + OFA;
new
burners





LEA + OSC
+ FGR;
load re-
duction

LEA + OSC
+ FGR;
load re-
duction

LEA + OSC
(OFA,
BOOS,
BBF)




Achievable
NOX Emission
Level ng/J
(lb/106 Btu)
260-300
(0.6 - 0.7)




215-260
(0.5 - 0.6)






110-150
(0.25 - 0.35)



65-85
(0.15 - 0.2)



85-130
(0.2 - 0.3)







Estimated
Differential
Annual Cost
20-30
-------
TABLE 4-26.   Continued
Equipment/

Fuel

Category
Stoker-fired
industrial
watertube
boilers




Gas-fired
industrial
watertube
boilers




Industrial
f i retube
boi 1 ers



Gas turbines



Current Technology

Available
Control
Technique
LEA + OFA







LEA + OSC
(OFA, BOOS,
BBF)





LEA + FGR;
LEA + OSC




Water,
steam
injection


Achievable
NOX Emission
Level ng/J
(lb/10s Btu)
150-190
(0.35 - 0.45)






86-130
(0.2 - 0.3)






65-110
(0.15 - 0.25)




110-150
(0.25 - 0.35)
\



Estimated
Differential
Annual Cost
1.8-2.34/
(kg/hr)a






1.4-1.B4/
(kg/hr)a "






7-14*/ ,
(ka/hr)a




$l-2/kW





Operational
Impact
Possible
~}% increase
in fuel con-
sumption;
corrosion;
slagging of
grate
(retrofit)
-1% increase
in fuel con-
sumption;
flame
instability;
boiler vi-
bration
(retrofit)
~1% increase
in fuel con-
sumption;
flame insta-
bility
(retrofit)
~1% increase
in fuel con-
sumption;
affects only
thermal
Emerging Technology


Near Term
1977-1982
Inclusion of
OFA in new
unit design





Low NOX bur-
ners; OFA in
new unit
design




Low NOx burn-
ers; OFA or
FGR in new
unit design


Advanced com-
bustor de-
signs for
dry NOX con-
trols


Far Term
1983-2000
Fluidized bed
combustion;
ammonia
injection




Optimized
burner/firebox
design; ammonia
injection




Optimized
burner /f i rebox
design



Catalytic com-
bustion; ad-
vanced can
designs





Comments
Current technology
still being
developed





Current technology
still undergoing
development





Development continuing
on current technology




Current technology
widely used



                                                   (Continued on page 4-100)

-------
                                                                       TABLE 4-26.  Concluded

Equipment/

Fuel

Category
Residential
furnaces



1C engines






Industrial
process
furnaces





Current Technology


Available
Control
Technique
Low NOX
burner/
f 1 rebox
design
(oil)
Fine
tuning;
changi ng
A/F



LEA







Achievable
NOX Emission
Level ng/J
(lb/106 Btu)
25-40
(0.06 - 0.1)



1 ,070-1 ,290
(2.5 - 3.0)





85-210
(0.2 - 0.5)







Estimated
Differential
Annual Cost
$0.1 4-0. 29/
kW
(4-8 x 10s
BTUPH)

$0.70-2.00/kW
($0.5-1.5/
BMP)




Unknown









Operational
Impact
~5% decrease
in fuel con-
sumption


5-10% in-
crease in
fuel con-
sumption;
misfiring;
poor load
response
Unknown







Emerging Technology



Near Term
1977-1982
Advanced
burner/fire-
box design
(gas & oil)

Include mod-
erate con-
trol in new
unit design



Low NOX
burners;
development
of external
controls
(FGR, OSC)
on retrofit
basis


Far Term
1983-2000
Catalytic
combustion



Advanced head
designs



*

Possible inclu-
sion in new
unit design










Comments
Current technology
still being tested



Technology still being
tested





Control development
in preliminary stages






-p.
I
o
o
              akg/hr steam produced

-------
most promising concepts.   This holds true for the other  source  categories  as  well.   The  R&D emphasis
for gas turbines, warm air furnaces and reciprocating  1C engines is  on  developing optimized combustion
chamber designs matched to the burner or fuel/air delivery  system.   Control development  for the diverse
types of industrial process equipment is in a preliminary stage.  To date, only minor operational
adjustments have been tried.
       Table 4-27 summarizes the status and effectiveness of  general control  techniques.  As noted
above, a number of techniques are applicable for operational  adjustments and  hardware modifications
of  either new or existing units.  The trend, however,  is toward new  burners or off-stoichiometric
combustion in combination with low excess air.  This approach yields a  higher degree of  control, is
more cost effective and minimizes adverse operational  impacts.
       The final column on Table 4-27 evaluates controls with respect to their treatment in the NO
                                                                                                  A
 E/A.   This evaluation will be discussed further in  Section  7.2  where priorities are set  on near- and
 far-term source/control applications.  This evaluation is also  used  to  scope  the  evaluation of in-
 cremental impacts due to NO  controls discussed in  Section  6.
                           X
       The information in this section initiates the process  engineering studies  of major source
 categories in the NO  E/A.  The preliminary control evaluation  has shown the  need for more data in
 the following areas:
       •   Current control technology
           -   Impact on operation/performance
           -   Economics/control costs
           -   Environmental impact
       •   Emerging control technology
           -   New operating data as it becomes available
           -   Economic estimates
           —   Environmental concerns
 The seven process engineering studies to be performed  in Task 7247 will focus on  these requirements,
 while  many of the data gaps will be filled under Task  7245  or through related ongoing programs.
 Since  most of the current technology has been demonstrated  on utility and  large industrial boilers,
 the first two studies to be performed will cover these categories.
       One especially important area where more accurate data are needed is in differential control
 costs.  During the process engineering studies, all cost procedures  will be standardized and  a
                                                 4-101

-------
                                                     TABLE 4-27.
OVERALL EVALUATION OF N0x CONTROL TECHNIQUES
o
rvj
Control
Technique
Low excess air
(LEA)
Flue gas recircu-
lation (FGR)
Off stoichiometric
combustion (OSC)
incl. OFA, BOOS,
BBF
Load reduction
Burner
modifications
Existing
Applications
Retrofit and new
utility boilers;
some use in indus-
trial boilers
Retrofit use on
many gas- and oil-
fired utility
boilers; demon-
strated on indus-
trial boilers
New and retrofit
use on many util-
ity boilers; dem-
onstrated on in-
dustrial boilers
Some retrofit use
on gas and oil
utility boilers;
enlarged fireboxes
on new coal units
New and retrofit
use on utility
boilers; demon-
strated on resi-
dential furnaces
Effectiveness
10% to 30% for
thermal and fuel
N0x
20% to 50% for
thermal NO,,; no
effect on fuel
N0x
20% to 50% for
thermal and fuel
NOX
0% to 40% for
thermal NO
30% to 60% for
thermal and fuel
N0x
Operational
Impact
Increase in effi-
ciency; amount lim-
ited by smoke or
CO at very low EA
Possible flame in-
stability; in-
creased vibration
No major impact
with new design;
potential for flame
instability, effi-
ciency decrease,
increased corrosion
(coal -fired) with
retrofit
Decrease in effi-
ciency and power
output; limited by
spare capacity and
smoke formation
No major impact
with new design;
retrofit use con-
strained by firebox
characteristics
Projected
Applications
Widespread use for
efficiency in-
crease; incorpor-
ate into advanced
designs all sources
Possible use in new
industrial boiler
designs
Widespread use in
large boilers; in-
corporate into ad-
vanced designs
Enlarged fireboxes
used in new unit
design; limited use
for retrofit
Incorporate into
advanced designs
utility, industrial
boilers, residen-
tial , process fur-
naces, GT; combine
with OSC
Control
Evaluation
for NOX E/A Effort
Primary emphasis near-
term and far-term appli-
cations (all sources);
combined with OSC & bur-
ner mods for far-term appl .
Primary emphasis near-term
applications large boilers;
possible far-term industrial
boiler application
Primary emphasis near-
term and far-term appli-
cations all sources
Secondary emphasis near-
term applications (boilers);
combined with OSC or burner
mods for far-term appl .
Primary emphasis near- and
far- term applications all
sources
                                                                                                                                (Continued on page  4-103)

-------
                                                                     TABLE 4-27.  Continued
o
OJ
Control
Technique
Water, steam
injection
Reduced air
preheat (RAP)
Ammonia injection
Fuel
denitrification
Fuel additives
Alternate and
mixed fuels
Existing
Applications
Widely used for gas
turbines
Widespread use in
large turbocharged
1C engines
Demonstrated on
oil- and gas-fired
industrial boilers
Oil denitrification
accompanies desul-
furization for some
large boilers
Fuel additives for
NOX not used
Combustion of low
nitrogen alternate
fuels being
demonstrated
Effectiveness
30% to 70% for
thermal NOV
A
10% to 40% for
thermal NO
40% to 70% for
thermal and fuel
N0x
10% to 40% for
fuel N0x
Generally in-
effective for dir-
ect NOX reduction
Varies
Operational
Impact
Slight decrease in
efficiency; limited
by CO formation;
power output
increases
Slight decrease in
efficiency, in-
crease power output
Retrofit use lim-
ited; possible ad-
verse environmental
impact
No adverse effects
Byproduct emissions
formed
Varies
Projected
Applications
Use in new gas tur-
bines; possible use
in process furnaces
Continued use in
1C engines
Use in large
boilers in some
areas (1980's)
Use of oil de-
nitrification in
large boilers as
supplement to CM
tech.
Additives for cor-
rosion, fouling,
particulate, smoke,
etc. can provide
increased flexi-
bility with CM tech.
on large boilers
Combined cycles and
residential and
commercial heating
systems
Control
Evaluation
for NOX E/A Effort
Primary emphasis near-term
applications, gas turbines;
possible far- term indus-
trial process application
Secondary emphasis
Primary emphasis far-
term application to large
boilers; evaluate impact
with coal firing
Secondary emphasis; eval-
uate as alternate fuel
Secondary emphasis; con-
sider impact of additives
Secondary emphasis far- term
application; evaluate dif-
ferential impact of fuel
switching; transfer results
of other E/A's .
                                                                                                                              (Continued on page 4-104)

-------
                                                                     TABLE 4-27.  Concluded
I
o
Control
Technique
Catalytic
combustion
Fluidized bed
combustion
Flue gas
treatment (FGT)
Existing
Applications
Only tested in
experimental
combustors
Tested in pilot/
prototype
combustors
Used in Japan on
large boilers
Effectiveness
>90% for thermal
N0x
20% to 50% for
fuel NOX (pres-
surized FBC)
40% to >9Q% for
fuel and
thermal N0x
Operational
Impact
Requires clean
fuel ; combustors
limited by cata-
lyst bed temp.
capability
Requires sulfur
acceptor
Requires temp, con-
trols, catalyst,
scrubbing soln.,
or oxidizing agent;
. possible adverse
environmental impact
Projected
Applications
Gas turbines and
residential and
commercial heating
systems
Combined cycle,
utility boilers,
industrial boilers
(1980's)
Possible supple-
ment to CM for
utility and large
industrial boilers
(1980's)
Control
Evaluation
for NOX E/A Effort
Primary emphasis far- term
applications; compare im-
pact to burner mods, al-
ternate fuels
Transfer results from
FBC E/A; compare impact
to combustion modifications,
conventional combustion
Secondary emphasis; trans-
fer results of other
studies to compare impact
to combustion mods

-------
common basis will be established  for detailed costing of NOX control techniques.  Thus, a more ac-
curate comparison of cost  effectiveness between control options can be made.  The first step 1n
future work on Task 7247 will  be  to focus on establishing this and other standardized procedures.
                                                4-105

-------
                                     REFERENCES FOR SECTION 4


4-1.    Environment Reporter, State Air Laws (2V.)  Bureau of National Affairs, Inc., Washington, D.C.

4-2.    Zeldovich, J., "The Oxidation of Nitrogen in Combustion and Explosions," Acta Physiocheii
        URSS. (Moscow!. Vol. 21, 1946 p. 4.

4-3.    Bowman, C. T. and D. J.  Seery, "Investigation of NO Formation Kinetics in Combustion Pro-
        cesses: "The Methane - Oxygen - Nitrogen Reaction" in Emissions from Continuous Combustion
        Systems, W. Cornelius and W. G. Agnew, eds, Plenum, 1972.

4-4     Bartok, W., et al., "Basic Kinetic Studies  and Modeling of NO Formation in Combustion Pro-
        cesses," AIChE Symposium Series No.  126, Vol. 68, 1972.

4-5.    Halstead, C. J. and A. J. E. Munro,  "The Sampling, Analysis, and Study of the Nitrogen
        Oxides Formed in Natural Gas/Air Flames," Company Report,  Shell Research et al., Egham,
        Surrey, U. K., 1971.

4-6.    Thompson, D., et al., "The Formation of Oxides of Nitrogen in a Combustion System,"
        presented at 70th National AIChE Meeting, Atlantic City, N.J., 1971.

4-7.    Lange, H. B., "NOX Formation in Premixed Combustion:  A Kinetics Model and Experimental
        Data," presented at 64th Annual AIChE Meeting, San Francisco, 1971.

4-8.    Sarofim, A. F. and J. H. Pohl, "Kinetics of Nitric Oxide Formation in Premixed Laminar
        Flames," 14th Symposium (International) on  Combustion, The Combustion Institute, Pittsburgh,
        1973.

4-9.    Iverach, D., et al., "Formations of Nitric  Oxide in Fuel-Lean and Fuel-Rich Flames,"
        ibid., 1973.

4-10.   Wendt, J. 0. L. and J. M. Ekmann, "Effect of Fuel Sulfur Species on Nitrogen Oxide Emissions
        from Premixed Flames," Comb. Flame,  Vol. 25, 1975.

4-11.   Malte, P. C. and D. T. Pratt, "Measurement  of Atomic Oxygen and Nitrogen Oxides in Jet-
        Stirred Combustion," 15th Symposium (International) on Combustion, The Combustion Institute,
        Pittsburgh, 1975.

4-12.   Mitchell, R. E. and A. F. Sarofim, "Nitrogen Oxide Formation in Laminar Methane Air Diffu-
        sion Flames," presented at the Fall  Meeting, Western State Section, The Combustion
        Institute, Palo Alto, Ca., 1975.

4-13.   Bowman, C. T., "Non-Equilibrium Radical Concentrations in Shock Initiated Methane Oxida-
        tion," 15th Symposium (International) on Combustion, The Combustion Institute, Pittsburgh,
        1975.

4-14.   Fem'more, C. P., "Formation of Nitric Oxide in Premixed Hydrocarbon Flames," 13th
        Symposium (International) on Combustion, The Combustion Institute, Pittsburgh, 1971.

4-15.   MacKinnon, D. J., "Nitric Oxide Formation at High Temperatures," J. APCA, Vol. 24, No. 3,
        March 1974, pp. 237-239.

4-16.   Heap, M.  P., et al., "Burner Criteria for NOX Control; Volume I - Influence of Burner
        Variables on NOX in Pulverized Coal  Flames," EPA 600/2-76-061a, NTIS-PB 259 911/AS,
        March 1976.

4-17.   Bowman, C. T., et al., "Effects of Interaction Between Fluid Dynamics on Chemistry or
        Pollutant Formation in Combustion,"  in Proceedings of the Stationary Source Combustion
        Symposium; Volume I - Fundamental Research, EPA 600/2-76-152a, NTIS-PB 256 320/AS,
        June 1976."

4-18.   Shaw, J.  T.  and A.  C.  Thomas, "Oxides of-Nitrogen in Relation to the Combustion of Coal,"
        presented at the 7th International Conference on Coal Science, Prague, June 1968.
                                               4-106

-------
4-19.    Pershing,  D.  W., et al., "Influence of Design Variables on the Production of Thermal and
        Fuel  NO from Residual Oil and Coal Combustion." AIChE Symposium Series. No. 148, Vol. 71,
        1975 j pp.  19~29.
4-20.
Sarofim, A. F., et al., "Mechanisms  and  Kinetics  of NOX Formation:   Recent  Developments,"
presented at 65th Annual AIChE Meeting,  Chicago,  November 1976.
4-21.   Martin, G.  B., and E. E. Berkau, "An  Investigation  of  the  Conversion of Various Fuel
        Nitrogen Compounds to Nitrogen Oxides in Oil Combustion,"  presented at 70th National AIChE
        Meeting, Atlantic City, N.J., August  1971.

4-22.   Habelt, W.  W. and B. M. Howe11, "Control of NO  Formation in Tangentially Coal-Fired Steam
        Generators," in Proceedings of the NOX Control  Technology  Seminar, EPRI SR-39, February 1976.

4-23.   "Air Quality and Stationary Source Emission Control,"  U. S. Senate, Committee on Public
        Works, Serial No. 94-4, March 1975.

4-24.   Pohl, J. H. and A. F. Sarofim, "Fate  of Coal Nitrogen  During Pyrolysis and Oxidation,"
        in Proceedings of the Stationary Source Combustion  Symposium; Volume I - Fundamental
        Research. EPA 600/2-76-152a, NTIS-PB  256 320/AS, June  1976.

4-25.   Heap, M. P., et al., "The Optimization of Burner Design Parameters to Control NOX Formation
        in Pulverized Coal and Heavy Oil Flames," in Proceedings of the Stationary Source Combus-
        tion Symposium; Volume II - Fuels and Process Research and Development, EPA 600/2-76-152b,
        NTIS-PB 256 321/AS, June 1976.

 4-26.   Pohl, J. H. and A. F- Sarofim, "Devolatilization and Oxidation of Coal Nitrogen," presented
        at 16th International Symposium on Combustion,  M.I.T., August 1976.

 4-27.   Blair, D. W., et al., "Devolatilization and Pyrolysis  of Fuel Nitrogen from Single Coal
        Particle Combustion," 16th Symposium  (International) on Combustion, Cambridge, Mass., 1976.

 4-28.   Pershing, D. W., "Nitrogen Oxide Formation in Pulverized Coal Flames," PhD Dissertation,
        University of Arizona, 1976.

 4-29.   Axworthy, A. E., Jr., "Chemistry and  Kinetics of Fuel  Nitrogen Conversion to Nitric Oxide,"
        AIChE Symposium Series, No. 148, Vol. 71, 1975, pp. 43-50.

 4-30.   Axworthy, A. E., et  al., "Chemical Reactions in the Conversion of Fuel Nitrogen to NOX,"
        in Proceedings of the Stationary Source Combustion  Symposium. Volume I, EPA 600/2-76-152a,
        NTIS-PB 256 320/AS,  June 1976.

 4-31.   Pershing, D. W., and J. 0. L. Wendt,  "The Effect of Coal Combustion on Thermal and Fuel NOX
        Production from Pulverized Coal Combustion," presented at  Central States Section, The
        Combustion Institute, Columbus, Ohio, April 1976.

 4-32.   "Control Techniques  for Nitrogen Oxide Emissions from  Stationary Sources -Draft Second
        Edition," Aerotherm  TR-76-222, Acurex Corporation/Aerotherm Division, Mountain View, CA,
        October  1976.

 4-33.   Barr,  W. H., and D.  E. James, "Nitric Oxide Control -A Program of Significant Accomplish-
        ments," ASME 72-WA/Pwr-13.

 4-34.   Barr,  W. H., et al., "Retrofit of  Large Utility Boilers for Nitric Oxide Emissions Pro-
        duction - Experience and Status Report."

 4-35.   Crawford, A. R., et  al., "Field Testing:  Application  of Combustion Modifications to
        Control NOX Emissions  for Utility  Boilers," Exxon  Research and  Engineering Co.,
        EPA  650/2-74-066, NTIS-PB 237 344/AS, June  1974.

 4-36.   Crawford, A. R., et  al., "The Effect  of Combustion  Modification on Pollutants  and Equipment
        Performance of Power Generation Equipment," in  Proceedings of  the  Stationary  Source  Com-
        bustion Symposium; Volume III - Field Testing  and  Surveys, Exxon Research  and  Engineering
        Co.,  EPA 600/2-76-152C, NTIS-PB 257 146/AS.
                                                4-107

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4-37    Blakeslee, C.  E.,  and H.  E.  Burbach, "Controlling NOX Emissions from Steam Generators,"
    '    C. E. Inc., APCA 72-75, 65th Annual  Meeting of Air Pollution Control Association,
        June'18-22, 1972.

4-38.    Blakeslee, C.  E.,  and H.  E.  Burbach, "NOX Emissions from Tangenti ally-Fired Utility
        Boilers, Part II,  Practice," AIChE Symposium Series No.  148, Vol. 71, 1975.

4-39    Selker  A  P , "Program for Reduction of NOX from Tangential Coal-Fired Boilers, Phase II
    '    and Ila/EPA 650/2-73-005a and b, NTIS-PB 245 162/AS and NTIS-PB 246 889/AS, June 1975.

4-40.    Bartok, W., et al., "Systematic Field Study of NOX Emission Control Methods for Utility
        Boilers," ESSO Research and Engineering Co., GRU.4GNOS.71, December 1971.

4-41.    Hollinden, G.  A.,  et al., "NOX Control  at TVA Coal-Fired Steam Plants," ASME Air Pollution
        Control Division,  Proceedings of the Third National Symposium, April 24-25, 1973.

4-42.    "Applicability of NOX Combustion Modifications to Cyclone Boilers (Furnaces)," (Draft)
        Monsanto Research Corp., 1976.

4-43.    "Standard Support Document and Environmental Impact Statement - Stationary Reciprocating
        Internal Combustion Engines," Prepared by Aerotherm Division of Acurex Corporation,
        Mountain View, California for U.S. Environmental  Protection Agency, Contract 68-03-1318,
        Task No. 7, March 1976.

4-44.    Hollinden, G.  A.,  et al., "Evaluation of the Effects of Combustion Modifications in
        Controlling NOX Emissions at TVA's Widow's Creek  Steam Plant," EPRI SR-39, February 1976.

4-45.    "Preliminary Test Results of NOX Controls on Industrial  Boilers -Appendix A,"
        KVB Engineering.

4-46.    McCann, C., et al., "Combustion Control of Pollutants from Multiburner Coal-Fired System,"
        U.S. Bureau of Mines, EPA 650/2-74-038, NTIS-PB 233 037/AS, May 1974.

4-47.    Breen, B. P.,  "Combustion in Large Boilers:  Design and Operating Effects on Efficiency
        and Emissions," KVB, Inc.   Paper presented at the 16th Symposium (International) on
        Combustion, Massachusetts Institute of Technology, Cambridge, Massachusetts, August 15-21,
        1976.

4-48.    Maloney, K. L., "Western Coal Use in Industrial Boilers," Western States Section/The
        Combustion Institute, April  19-20, 1976, Salt Lake City, Utah.

4-49.    "Standard Support and Environmental  Impact Statement for Standards of Performance:
        Lignite-Fired Steam Generators," (First Draft), EPA, March 1975.

4-50.    Locklin, D. W., et al., "Design Trends and Operating Problems in Combustion Modification
        of Industrial  Boilers," Battelle-Columbus Lab., EPA 650/2-74-032, NTIS-PB 235 712/AS,
        April 1974.

4-51.    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.

4-52.    Cichanowicz, J. E., et al.,  "Pollutant Control Techniques for Package Boilers, Phase I
        Hardware Modifications and Alternate Fuels," (Draft Report) Ultrasystems and Foster
        Wheeler, November  1976.

4-53.    Cato, G. A., et al., "Field  Testing:  Application of Combustion Modification to Control
        Pollutant Emissions from Industrial  Boilers -Phase II," KVB Engineering, Environmental
        Protection Technology Series, EPA 600/2-76-086a,  NTIS-PB 253 500/AS, April 1976.

4-54.    Barrett, R. E., et al., "Field Investigation of Emissions from Combustion Equipment for
        Space Heating," Battelle-Columbus Laboratories, EPA-R2-73-084a, NTIS-PB 223 148, June 1973.

4-55.    Combs,  L.  P.,  and  A.  S. Okuda, "Commercial Feasibility of an Optimum Distillate Oil Burner
        Head,"  Final Report, Rocketdyne Division, Rockwell International Corporation.
                                               4-108

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4-56.   Combs,  L.  P.,  and A.  S.  Okuda, "Residential Oil Furnace System Optimization -Phase I "
       Rocketdyne Division,  Rockwell International, EPA 600/2-76-038, NTIS-PB 250 878/AS
       February  1976.

4-57.   Combs,  L.  P.,  and A.  S.  Okuda, "Commercial Feasibility of an Optimum Residential Oil Burner
       Head,"  Rocketdyne Division, Rockwell International, EPA 600/2-76-256, NTIS-PB 259 912/AS
       September 1976.                                                                          '

4-58.   Combs,  L.  P.,  et al., "Integrated Low-Emissions Residential Furnace," 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.

4-59.   Ketels, P. A., et al., "A Survey of Emissions Control and Combustion Equipment Data in
        Industrial Process Heating," Final Report by Institute of Gas Technology for EPA, IGT
       Project No. 8949, June 1976.

4-60.   Shoffstall, D. R., "Burner Design Criteria for Control of NOX from Natural Gas Combustion,
        Volume  I," Institute of Gas Technology. EPA 600/2-76-098a, NTIS-PB 254 167/AS, April 1976.

4-61.    Ando, J., et al., "NOX Abatement for Stationary Sources in Japan," EPA 600/2-76-013b,
        NTIS-PB 250 586/AS, January 1976.

4-62.    Hunter, S.C., et al., "Application of Combustion Technology for NOX Emissions Reduction on
        Petroleum Process Heaters," presented at 83rd National Meeting AIChE, Houston, Texas,
        March 1977.

4-63.   Copeland, J. 0., "Standards Support and Environmental Impact Statement:  An Investigation
        of the Best Systems of Emission Reduction for Nitrogen Oxides from Large Coal-Fired Steam
        Generators," (Draft) EPA, October 1976.

 4-64.   Thompson, R. E., et al., "Effectiveness of Gas Recirculation and Staged Combustion in
        Reducing NOX on a 560 MW Coal-Fired Boiler," EPRI SR-39, February 1976.

 4-65.   Bagwell, F. A., et al., "Utility Boiler Operating Modes for Reduced Nitric Oxide Emissions,"
        Journal of the Air Pollution Control Association, Vol. 21, pp. 702-708, 1971.

 4-66.   Barr, W. H., et al., "Retrofit of Large Utility Boilers for Nitric Oxide Emission
        Reduction - Experience and Status Report," paper presented at the 69th Annual  AIChE
        Meeting, November 30, 1976.

 4-67.   Norton, D. M., et al., "Modifications to Ormond Beach Steam Generators for NOX Compliance,"
        paper presented at the ASME Winter Annual Meeting, November 30, 1975, Houston, Texas,
        ASME Paper No. 75-WA/PWR-9.

 4-68.   Heap, M. P., et al., "Reduction of NO Emissions from Package Boilers," Revised Draft Final
        Report by Ultra Systems, Inc., Irvine, California.

 4-69.   Durkee, K. R., et al., "An Investigation of the Best Systems of Emission Reduction for
        Stationary Gas Turbines -Standards Support and Environmental Impact Statement," (Draft)
        EPA, Research Triangle Park, N.C., July 1976.

 4-70.   Breen,  B. P., "Control of the Nitric Oxide Emissions from Fossil Fueled Boilers," The
        Fourth  Westinghouse International School for Environmental Management, July 15-18, 1973.

 4-71.   Bell, A. W., et al., "Combustion Control for Elimination of Nitric Oxide Emissions from
        Fossil  Fuel Power Plants," 13th International Symposium on Combustion, University of Utah,
        August  23-29, 1970.

 4-72.   Bell, A. V., et al., "Nitric Oxide Reduction by Controlled Combustion Processes," KVB, Inc.,
        Western States Section/Combustion Institute, April 20-21, 1970.

 4-73.    Jain, L.  K., et al., "State of the Art for Controlling NOX Emissions, Part I, Utility
        Boilers," Catalytic, Inc., EPA-R2-72-072a, NTIS-PB 213 297, September 1972.

4-74.    Norton, D. M., et al., "Status of Oil-Fired NOX Control Technology," EPRI-SR-39,
        February 1976.
                                                4-109

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4-75.   Frledrlch, J.  L.. et al.,  "Nitrogen Oxides Reduction," Foster Wheeler Energy Corp.,
        EPRI SR-39, February 1976.

4-76.   Lachapelle, D. G., "Staged Combustion Technology for Tangentially-Fired Utility Boilers
        Burning Western Coal," (Draft) February 1976.

4-77    Muzio, L  J.,  et al., "Package Boiler Flame Modifications for Reducing Nitric Oxide
        Emissions, Phase II of III," Ultrasysterns, Inc., EPA-R2-73-292b, NTIS-PB 236 752,
        June 1974.

4-78    Seabrook, H. and B. P. Breen, "A Practical Approach to NOX Reduction in Utility Boilers,"
        Con Edison Co. of New York and KVB, presented  at American Power Conference,
        April 18-20, 1972.

4-79    Shimizu, A. B., et al.,  "NOX Combustion Control  Methods and Costs for Stationary Sources
        Summary Study," EPA 600/2-75-046, NTIS-PB 246  750/AS, September 1975.

4-80.   Cato, 6. A., et al., "Field Testing:  Application of Combustion Modification to Control
        Pollutant Emissions from Industrial Boilers -Phase I," KVB Engineering,
        EPA 650/2-74-078a, NTIS-PB 238 920/AS, October 1974.

4-81.   Heap, M.P., et al., "Application of NOX Control  Techniques to Industrial Boilers,"
        Ultrasystems,  Inc., presented at the 69th Annual Meeting of the AIChE, Nov. 28-Dec.  2,  1976.

4-82.   Fenimore, C. P-, et al., "Formation and Measurements  of Nitrogen Oxides in Gas Turbines,"
        ASME 70-WA/GT-3, August 3, 1970.

4-83.   Heap, M. P., et al., "Burner Design Principles for Minimum NOX Emissions," EPA 650/2-73-021,
        NTIS-PB 224 210/AS, September 1973.

4-84.   Heap, M. P., et al., "The  Effect of Burner Parameters on Nitric Oxide Formation in Natural
        Gas and Pulverized Fuel  Flames," IFRF, American  Flame Research Committee, Sept. 6-7, 1972.

4-85.   Pershing, D. W., et al., "Relationship of Burner Design to the Control of NOX Emissions
        Through Combustion Modification," EPA 650/2-73-021, NTIS-PB 224 210/AS, Sept. 1973.

4-86.   Shoffstall, D. R., "Burner Design Criteria for Control of Pollutant Emissions from Natural
        Gas Flames," Institute of  Gas Technology, EPA  600/2-76-152b, NTIS-PB 256 321/AS, June 1976.

4-87.   Koppang, R. R., "A Status  Report on the Commercialization and Recent Development History of
        the TRW Low-N0x Burner," TRW Energy Systems Group.

4-88.   Tsuji, S., et  al., "Control  Technique for Nitric Oxide -Development of New Combustion
        Methods," IHI  Engineering  Review, Vol. 6, No.  2.

4-89.   Ando, J., et al., "NOX Abatement for Stationary  Sources in Japan," August 1976
        (Preliminary Draft).

4-90.   Brackett, C. E., and J.  A.  Barsin, "The Dual Register Pulverized Coal Burner - A NOX
        Control Device," EPRI SR-39. February 1976.

4-91.   Vatsky, J., and R.  P.  Welden, "NOX -A Progress  Report," Foster Wheeler Corp., Heat
        Engineering, July-Sept.,  1976, Vol. 48, No. 8.

4-92.   Dickerson, R.  A., and A. S.  Okuda, "Design of  an Optimum Distillate Oil Burner for Control
        of Pollutant Emissions," EPA 650/2-74-047, NTIS-PB 236 647/AS, June 1974.

4-93.   Singh, P.  P.,  et al., "Formation and Control of Oxides of Nitrogen Emissions from Gas
        Turbine Combustion Systems," ASME 72-GT-22, October 1972.

4-94.   Roessler,  et al., "Assessment of the Applicability of Automotive Emission Control
        Technology to  Stationary Engines," Aerospace Corporation, EPA 650/2-74-051, NTIS-PB 237 115/AS,
        July 1974.

4-95.   Spadaccini, L.  J.,  and E.  J.  Szetela, "Approaches to the Prevaporized-Premixed Combustor
        Concept for Gas  Turbines," ASME 75-GT-85.
                                               4-110

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4-96.   Anderson,  David,  "Effects of Equivalence Ratio and Dwell Time on  Exhaust  Emissions from an
       Experimental  Prenrixing Prevaporizing Burner," Lewis  Research Center, ASME 75-GT-69.

4-97.   Cornelius, W., and W. R. Wade, "The Formation and Control of Nitric Oxide in a
       Regenerative Gas  Turbine Burner," General Motors Corp., SAE 700708.

4-98.   Wade,  W.  R.,  et al., "Low Emissions Combustion for the Regenerative Gas Turbine "
       ASME 73-GT-ll, January 1974.

4-99.   White, D. .J., and M. E. Ward, "Dry NOX Control Techniques," EPRI  SR-39, February 1976.

4-100. Hosier, S.  A., et al., "Progress in Development of Low-N0x Gas Turbine Combustors,"
       United Technologies, for presentation at the 69th Annual AIChE Meeting, Nov. 28-Dec. 2, 1976.

4-101. Teixeira,  D.  P-,  "Overview of Water Injection for NOX Control," EPRI SR-39, February 1976.

4-102.  Armento, W. J., and W. L. Sage,  "The Effect of Design and Operation Variables on NOX
        Formation in Coal-Fired Furnaces," Alliance Research Center/B&W Pulverized Coal Combustion
        Seminar, June 19-20, 1973.

4-103.  Lyon, R. K., "Method for the Reduction of the Concentration of NO in Combustion Effluents
        Using Ammonia," U.S. Patent No.  3,900,554, assigned  to Exxon Research and Engineering
        Company, Linden, New Jersey, August 1975.

 4-104.  Lyon, R. K., and J. P. Longwell, "Selective, Non-Catalytic Reduction of NOX by NHs,"
        Proceedings of the NOx Control Technology Seminar. EPRI SR-39, February 1976.

 4-105.  Muzio, L.  J., and T. K. Arand, "Homogeneous Gas Phase Decomposition of Oxides of Nitrogen,"
        EPRI Report FP-253, August  1976.

 4-106.  Teixeira, D. P., "Status of Utility Application of Homogeneous NOX Reduction,"
        Proceedings of the NOX Control Technology Seminar, EPRI SR-39, February 1976.

 4-107.  Bartok, W., et al., "Systems Study of Nitrogen Oxide Control Methods for Stationary
        Sources," Final Report -Volume  II, Esso Research and Engineering, Prepared for NAPCA,
        NTIS-PB 192 789, November 1969.

 4-108.  Blakeslee, C. E., and A. P. Selker, "Program for the Reduction of NOX from Tangential
        Coal-Fired Boilers, Phase I," Environmental Protection Technology Series, EPA 650/2-73-005,
        NTIS-PB 226 547/AS, August  1973.

 4-109.  Lachapelle, D. G., et al.,  "Overview of the Environmental Protection Agency's NOX Control
        Technology for Stationary Combustion Sources," presented at the 67th AIChE Annual Meeting,
        December 1974.

 4-110.  Kelley, D. V., data submitted at the EPRI NOX Control Technology  Seminar, San Francisco,
        by  Pacific Gas and Electric Company, February 1976.

 4-111.  Personal communication - letter  from the Los Angeles Department of Water  and Power to
        Acurex Corporation, May  5,  1975.

 4-112.  "Power Costs, 1974 Report on Diesel and Gas Engines," The American Society of Mechanical
        Engineers (ASME), March  1974.

 4-113.  Personal communication,  R. J. Lenney, Blueray Systems, Inc., Weston, Massachusetts,
        September 1975.

 4-114.  Satterfield, C. N., et al., "Catalytic Desulfurization and Denitrogenation,"
        EPA 600/2-75-063, NTIS-PB 248 101/AS, October 1975.

 4-115.  Frost, C.  M., et al., "Hydrodenitrifi cation of Crude Shale Oil,"  Laramie  Energy  Research
        Center, LERC/RI-75/3, July 1975.

 4-116.  Jimeson, R. M., and L. W. Richardson, "Census of Oil Desulfurization to Achieve
        Environmental Goals," AIChE No.  148, Vol. 71.
                                                 4-111

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4-117.   Personal  communication with Harry F.  Mason  of Chevron  Research Company, Richmond,
        California, January 1977.

4-118.   Guth, E.  D., et al., "Method for Removing Sulfur and Nitrogen in Petroleum Oils,"
        U.S.  Patent No. 3,847,800, Nov.  12,  1974.

4-119.   Personal  communication with E.  D. Guth  - KVB Engineering,  January 11, 1977.

4-120.   Wright, C.  H., "Sulfur and Nitrogen  Balances in  the Solvent Refined Coal Process,"
        Pittsburg and Midway Coal  Mining Company, EPA 650/2-75-011, NTIS-PB 243 893/AS,
        January 1975.

4-121.   Meyers, R.  A., "Desulfurize Coal Chemically," TRW Systems  and Energy -Hydrocarbon
        Processing, June 1975.

4-122.   Personal  communication with Mr.  Van  Nuys  of TRW  Systems  and Energy, Redondo Beach, CA.,
        January 1977-

4-123.   Stambaugh,  E. P., et al.,  "Hydrothermal Coal Desulfurization with Combustion Results,"
        EPA/RTP Contract 68-02-2119.

4-124.   Stambaugh,  E. P., "Battelle Develops  Leaching Process  to Desulfurize Coal," Coal  Age,
        August 1975.

4-125.   Shaw, H., "Reduction of Nitrogen Oxide  Emissions From  a  Gas Turbine Combustor by  Fuel
        Modifications," Journal of Engineering  for  Power, October  1973.

4-126.   McCreath, C. G., "The Effect of Fuel  Additives on the  Exhaust Emissions From Diesel
        Engines," Combustion and Flame,  Vol.  17,  1971 p. 359.

4-127.   Altwicker,  E. R., et al.,  "Pollutants From  Fuel  Oil Combustion and the Effects of
        Additives," Paper No. 71-14, 64th Annual  APCA Meeting, Atlantic City, N.J., June  1971.

4-128.   Martin, G.  B., et al., "Effects  of Fuel Additives on Air Pollutant Emissions From
        Distil late-Oil-Fired Furnaces,"  June  1971.

4-129.   Pershing, D. W., et al., "Effectiveness of  Selected Fuel Additives in Controlling
        Pollution Emissions From Residual-Oil-Fired Boilers,"  EPA  650/2-73-031, NTIS-PB 225 037/AS,
        October 1973.

4-130.   Krause, H.  H., et al., "Combustion Additives for Pollution Control -A State-of-the-Art
        Review,"  EPA 600/2-77-008a, January  1977-

4-131.   Giammar,  R. D., et al., "The Effect  of  Additives in Reducing Particulate Emissions From
        Residual  Oil Combustion,"  Proceedings of the Stationary  Source Combustion Symposium,
        EPA 600/2-76-152c, NTIS-PB 257  146/AS,  Atlanta,  June 1976.

4-132.   Kukin, Ira, "Additives Can Clear Up  Oil-Fixed Furnaces," Apollo Chemical Corp.,
        Environmental Science and  Technology, July  1973.

4-133.   "National  Energy Outlook," FEA/N-75/713,  Federal Energy, Administration, February 1976.

4-134.   Ctvrtnicek, T. E., et al., "Evaluation  of Low-Sulfur Western Coal Characteristics,
        Utilization, and Combustion Experience,"  Monsanto Research Corp., EPA 650/2-75-046,
        NTIS-PB 243 911/AS, May 1975.

4-135.   Martin, G.  B., "Environmental Considerations in  the Use  of Alternate Clean Fuels in
        Stationary  Combustion Processes."

4-136.   Klepetch, R. D., and G. E. Vitti, "Gas  Turbine Combustor Test Results and Combine Cycle
        Systems,"  Combustion, Vol. 45,  No. 10,  pp.  35-38, April  1974.

4-137.   Frendberg,  A., "Performance Characteristics of Exhibiting Utility Boilers When Fired With
        Low-Btu Gas,  Proc. Conf.  on Power Generation -Clean  Fuels Today, EPRI, Monterey,
        California, April  8-10, 1974.
                                                4-112

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4-138.  Joubert,  J.  I.,  and Daniel Bienstock, "Properties of Industrial Fuel Gases Manufactured
       From Coal  Using  Commercially Proven Technology," presented at the Symposium on Environment
       and Energy Conservation, Denver, Colorado, November 1975.

4-139.  Shoffstall, D.,  "Preliminary Combustion Tests of Nine Drums of Stabilized Coal-Oil
       Emulsion," Systems Research Laboratories, Dayton, Ohio, Final Report 3205-43, March 1976.

4-140.  Proceedings of the "Coal-Oil Mixture Combustion Technology Exchange Workshop," sponsored
       by ERDA,  Report No. CONF-76T019, Washington, D.C., October 29, 1976.

4-141.  Martin, G. Blair, "Evaluation of NOX Emission Characteristics of Alcohol Fuels in
       Stationary Combustion Systems," presented at Joint Meeting, Western and Central States
        Sections, The Combustion  Institute, April 21 and 22, 1975, San Antonio, Texas.

4-142.   Hall,  R.  E., "The Effect of Water/Residual Oil Emulsions on Air Pollutant Emissions and
        Efficiency of Commercial Boilers," ASME 75-WA/APC-l, July 14, 1975.

4-143.   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, June 1975.

4-144.   Pfefferle, W. C., et al., "CATATHERMAL Combustion:  A New Process for Low-Emissions Fuel
        Conversion," presented at the 1975 ASME Winter Annual Meeting, Houston, Texas, ASME
        Paper No. 75-WA/FU-l.

 4-145.   Kesselring, J. P., et al., "Catalytic Oxidation of Fuels for NOX Control from Area Sources,"
        EPA Report, EPA 600/2-76-037, NTIS-PB 252 195/AS, February 1976.

 4-146.   DeCorso, S. M., et al., "Catalysts for Gas Turbine Combustors -Experimental Test Results,"
        paper presented at the ASME Gas Turbine Conference and Products Show, New Orleans,
        March 1976, ASME Paper No. 76-GT-4.

 4-147.  LaNauze, R. D., "Fluidized Combustion," Energy World Number 22, December 1975.

 4-148.  "Design and Construction  of a Fluidized-Bed Coal Combustion Sampling and Analytical Test
        Rig," Acurex/Aerotherm Proposal 2167-75-A, October 1975.

 4-149.  "Proceedings of the 4th International Conference on Fluidized Bed Combustion," McLean,
        Virginia, December 1975.

 4-150.  Fennelly, P. F., "Emission Estimates of NOX and Organic Compounds from Fluidized Bed
        Combustion," presented at the International Conference on Photochemical Oxidant and Its
        Control, Raleigh, North Carolina, September 12-17, 1976.

 4-151.  Gerstin, R. A., "A Technical and Economic Overview of the Benefits of Repowering,"
        paper presented at the Gas Turbine Conference and Products Show, Houston, Texas, March 2-6,
        1975, ASME Paper No. 75-GT-16.

 4-152.  Ahuja, A., "Repowering Pays Off for Utility and Industrial Plants," Power Engineering,
        pp. 50-54, July 1976.

 4-153.  Robson, F. L. and A. J. Giramonti, "The Use of Combined-Cycle Power Systems in Nonpolluting
        Central Stations," JAPCA, Vol. 22, pp. 177-180, (1972).

 4-154.  Amos, D.  J., et al., "Energy Conversion Alternatives Study (ECAS), Westinghouse Phase I
        Final  Report, Volume V -  Combined Gas Steam Turbine Cycles," NASA CR-134941, Volume V, 1976.

 4-155.  Stambler, I., "Field Test 5 MW Combined Cycle Package Set for 1978," Gas Turbine World,
        March 1976, pp. 10-13.

 4-156.  Papamarcos, J., "Combined Cycles and Refined Coal," Power Engineering, December 1976,
        pp. 34-42.

 4-157.  Kydd,  P.  H., "An Ultra High Temperature Turbine for Maximum Performance and Fuels
        Flexibility," paper presented at the Gas Turbine Conference and Products Show, Houston,
        Texas, March 2-6, 1975, ASME Paper No. 75-GT-81.
                                                4-113

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4-158.  Force, E.  L., and R.  J.  Ayen, "Catalytic Reduction of 50 to 5000 ppm Nitric Oxide by
        Carbon Monoxide," AIChE  Symposium Series No.  126, Volume 68, 1972.

4-159.  Koutsoukas, E.  P., et al., "Assessment of Catalysts for Control  of NOX from. Stationary
        Power Plants, Phase 1, Volume 1  Final  Report,"  EPA 650/2-75-OOla, NTIS-PB 239 745/AS,
        January 1975.

4-160.  Ando, J.  and  H.  Tohata,  "NOX Abatement Technology in Japan," EPA-R2-73-284, NTIS-PB 222 335,
        June 1973.

4-161.  "Dry Scrubbing  of Utility  Emissions,"  Environmental  Science and  Technology, Volume 9, No.  8.

4-162.  Habib, Y.,  and  W.  F.  Bischoff,  "Dry  System for  Flue Gas  Cleanup," Oil  and Gas  Journal,
        February  24,  1975.

4-163.  Pohlenz,  J. P.,  "The  Shell  Flue  Gas  Desulfurization Process,"  presented at the EPA Flue
        Gas Desulfurization Symposium, Atlanta,  November  1974.

4-164.  Ploeg, J.  E., et al., "How Shell's Flue  Gas Desulfurization Unit has Worked in Japan,"
        Petroleum International, Volume  14,  No.  7,  pp.  50-58, July  1974.

4-165.  Stern, R.,  "The  EPA Development  Program  for NOX Flue Gas Treatment," in Proceedings  of the
        National  Conference on Health, Environmental Effects, and Control Technology of Energy Use,
        EPA Report  600/7-76-002, NTIS-PB 256 845/AS, February 1976.

4-166.  Rosenberg,  H. S.,  "Molecular Sieve NOX Control  Process in Nitric Acid  Plants,"  EPA Report
        EPA 600/2-76-015,  NTIS-PB  250 555/AS, January 1976.
                                              4-114

-------
                                            SECTION 5


                          MULTIMEDIA  EMISSION INVENTORY OF NOV SOURCES
                                                              A




      This section presents an  inventory of multimedia emissions from the stationary fuel  combus-


tion NOX sources and fuels identified  in  Section 2.   Additionally the inventory for NO  emissions


is extended to include all other sources  of NOX (mobile, noncombustion, fugitive)  in order  to compare


the contribution from stationary combustion sources.   The NOX inventory accounts for the degree of


control applied to new and existing  utility boilers.   Multimedia pollutants inventoried  include the


primary criteria pollutants  (NOX,  SOX, CO, HC, particulates), sulfates, polycyclic organic  material


(POM), trace metals, and liquid  or solid  effluent streams.   Results  for sulfates,  polycyclic organic


matter, trace metals, and liquid and solid effluent  streams are given in Appendix  A.   Insufficient


data exist to quantify emissions for the  other potential pollutants  discussed  in Section  3.



      This inventory will serve as  the base for assessing  potential  pollution  problems  in  the


absence of NOX controls and for  weighing  the incremental emission input due to  the use of NOX con-


trols.  The inventory will also  serve  as  the reference for  the subsequent projections to the year


2000 in fuel and equipment use and stationary  source  emissions.   Data gaps  identified  in the emis-


sion factor compilation highlight  areas where  further  testing is needed in  the  NOX E/A or other


programs.



      The emission inventory was  generated through  the following sequence:



      •   Compile fuel consumption  data  for the categories of combustion sources  specified in



          Section 2 (Section 5.1)



          -   Subdivide fuel consumption based on fuel-bound pollutant precursor  composition



      •   Compile multimedia emission data (Section  5.2)



          -   Base fuel-dependent pollutant emission  factors on trace composition of fuels



          -   Base combustion-dependent  pollutant emission factors  on unit fuel consumption for



              specific equipment  designs



      •   Survey the degree to  which  NOV, SOV, particulates are controlled (Section 5.3)
                                       X   A
                                                5-1

-------
       •   Produce emissions inventory (Section 5.4)
       •   Rank sources according to emission rates; compare  to  results  of previous inventories
           (Section 5.5)

5.1    FUELS:  PROPERTIES AND CONSUMPTION
       This section characterizes fuel composition and consumption  required in the emission inventory
for stationary combustion sources of NOX_  U.S. energy use  in  1974  totaled about 77 x 1015 kJ (72 x TO15
Btu) (Reference 5-1), of which 94 percent was supplied by the  fossil  fuels - coal, petroleum,  and
natural gas.  Approximately 57 percent of the total energy was consumed  by stationary source  equip-
ment.  Fossil fuels furnished 92 percent of the energy for these stationary sources,  with  the
remainder supplied by nuclear, hydroelectric, and other miscellaneous sources  such as waste fuels,
wood, geothermal, etc.  Of the total amount of fossil fuels burned  in stationary sources,  coal  and
natural gas contributed 26 and 44 percent, respectively, and petroleum 30  percent.  Unlike petroleum,
which is also a major source of energy for transportation, coal and natural  gas  are consumed pri-
marily in stationary applications.
       The following discussion will focus exclusively on fossil fuels since  they account  for essen-
tially all the energy consumed by stationary sources on a national  basis.   Section 5.1.1 briefly dis-
cusses each of the three major fossil fuels and their derivatives.  Section 5.1.2 gives a  detailed
summary of the amount of each fuel consumed by the major stationary source equipment  sectors and by
individual equipment types within each sector.  In the case of industrial  process heating  sources,
figures on annual production rather than fuel consumption are  given.  No estimates of either fuel
consumption or production are given for mobile, incineration,  and fugitive NO  emission sources.
5.1.1   Fuel Properties
       Because of the variation in origin and processing, fossil fuels show large variations in both
chemical  and physical  properties.  Since data on fuels will be used in this report to estimate multi-
media effluents produced by combustion, it is necessary to represent  the majority of  fuel  variables
by one or more sets of average values.   There were many reasons for taking this  approach:
       •    There  are no comprehensive data which relate fuel consumption with  exact fuel properties
           or origin
       •    Emission factors, with few exceptions, are in terms of average  fuel properties  (see
           Section 5.2)
                                                5-2

-------
      •   No comprehensive data  exist  on the various fuel cleaning practices such as blending,
          washing, desulfurization,  demetalllzatlon, etc., employed by suppliers or users of fuel
      •   The nonhomogeneous  nature  of any fuel  sample, especially coal  and oil, makes exact charac-
          terization Impossible  (Reference 5-2)
An exception to the rule is the sulfur  content of electrical utility fuels which is rigorously
monitored.  It is possible therefore  to define the sulfur content of several  residual  oil  and coal
fuels fairly accurately.  Sulfur  contents of the  following fuels represent the fossil  fuels consumed
by stationary sources:
      •   Petroleum products
          -   Residual fuel oil
              •   High S   -  2.0 percent
              •   Medium S -  1.0 percent
              •   Low S    —  0.5 percent
          -   Distillate fuel oil, 0.25 percent  S
          -   Gasoline, 0.0 percent  S
      •   Coal
          —   Bituminous and  subbituminous
              •   High S   —  2.8 percent (Interior Province origin)
              •   Medium S —  2.2 percent (Eastern Province origin)
              •   Low S    -  1.6 percent (Western Province origin)
          -   North Dakota lignite,  0.4 percent  S
          -   Pennsylvania anthracite, 0.6 percent S
      •   Natural gas, <0.1 percent  S
      The medium sulfur levels of coal and residual  oil  correspond  to  the average  sulfur  concen-
tration of fuels used in U.S.  utilities in 1974 (Reference 5-3).   Data  on  sulfur composition  of the
fuels were available for the utility  boiler sector, but there were relatively little data  available
for the other sectors.  When specific sulfur content for fuel  consumption  data was  not available,
medium sulfur concentration levels were used where applicable.
      The nitrogen content of fuels  was  treated  differently than the sulfur  content.   This is
because,  in contrast to SOV emissions,  NOV emissions  are highly dependent  on  equipment design and
                         X               "
                                                5-3

-------
 combustion conditions and are a composite of thermal NOX and fuel nitrogen  conversion.   Therefore,
 variations in NO  emissions due to fuel nitrogen content are treated by specifying emission
 factors for each equipment/fuel combination, e.g., tangential utility boilers firing bituminous coal,
 watertube package boilers firing residual oil, rather than directly relating emissions  to  fuel nitro-
 gen content.
        Liquid and solid fuels invariably contain some trace element contamination;  this  is especi-
 ally important in the combustion of residual fuel oil and coal  where concentration  levels are
 greatest and large amounts are burned each year.  Natural gas,  distillate oil, and  gasoline are
 assumed to contain no trace elements.   This assumption will have an insignificant impact on total
 trace element emissions from stationary sources.
        It is practical  to use representative concentration  levels  for  coal  since the trace  element
 content of individual  coal  samples  is  highly variable.  Trace element  concentrations typically vary
 within a single  coal-producing region,  and  even  within  a  single  seam (Reference 5-4).  More refined
 specifications of the  trace element content of various  coals are unwarranted at this time because
 the available data on  trace element emission factors  have proven to  be  of  poor quality.   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  (Reference  5-5).
        Trace elements  in residual  fuel  oils are  even more variable than those in coal.  This is
 compounded by the lack of specific  data on  the origin,  refinery  practices,  and blending techniques
 of  the residual  oil  used at the burner.   Demetallization, desulfurization,  and blending of  various
 grades of oil vary from refinery to refinery.  Supply and demand strongly  influence the movement
 of  petroleum. Further,  supply and  demand  requirements  are  difficult to predict so that assumptions
 on  refinery origins  are  bound to change.  As a result,  only a single average set of trace element
 concentrations will  be  used for residual  fuel  oil.   This  will be further justified when emission
 factors  for these elements  are presented  in Section  5.2.
        Table 5-1  gives the  trace element  concentrations and summarizes  other important properties
 of  each  of the major types  of fossil fuels.  These properties will  be  used throughout the remainder
 of  this  section.
 5.1.2  Fuel  Consumption
       This section presents estimates of stationary source fuel consumption (or of annual  production
in the case of process heating sources) needed to estimate multimedia effluents.   The discussion in-
cludes the sources for these estimates and comments as  to the reliability of the estimates.   Fuel
                                                 5-4

-------
                             TABLE 5-1.   PROPERTIES AND TRACE ELEMENTS OF REPRESENTATIVE FOSSIL FUELS (References 5-6, 5-7, 5-8, 5-9)
in
i

Ash %
Sulfur %
Heating Value
Al (ppm)
Sb
As
Ba
Be
Bi
B
Cd
Co
Cr
Cu
Pb
Mn
Hg
Mo .
N1
P
Se
V
In
Ir
Anthracite
Coal
11.9
0.6
30,238 kJ/kg
~
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
Subbituminous 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
0 0
2.0 1.0
39,021 kJ/X.
753
0.2
0.2
39
—
__
3.0
2.0
30.
30.
25.
19
25
0.1
2.5
1,208
-_
10
1,803
40
19
Low S
0
0.5





















Distillate
Oil
0
0.25
39,021 kJ/X,
0


















i


















1
Gasoline
0
0
34,840 kJ/Jl
0




































>
Natural
Gas
0
0
37,259 kJ/m3
0




































i
                                                                                                                                                     n
                                                                                                                                                     en

-------
consumption data were compiled for the year 1974, the most recent period  for  which comprehensive
data were available.  By way of summary, the totals for coal, petroleum,  and  gas  combustion  are given
in Table 5-2.  It is important to note that these totals do not reflect the total  amount of  energy
consumed by stationary sources because the process industries have been excluded  along  with  electrical
inputs originating from nonfossil fuel sources.

5.1.2.1  Utility and Large Industrial Boilers
       Fuel consumption estimates for utility boilers are accurate and comprehensive  in  terms of
both (1) total amount consumed and (2) the fraction due to each type of fuel.  This is extremely
valuable information, since relatively extensive emission factor data are also available  for this
sector.  Table 5-3 gives a detailed summary of the fuel consumed by those utility  boiler  equipment
types determined to be of significance in Section 2.  The following sources of data were  used to
compile this summary:
       •   FPC - fuel consumption by type of fuel and sulfur content (References 5-3, 5-10)
       •   6CA - analysis of FPC-67 tapes to provide data on total  number of boilers and  equipment
           and fuel  breakdown (Reference 5-6)
       •   Monsanto - analysis of cyclone boiler population and fuel  consumption (Reference 5-11)
       •   OAQPS - analysis of lignite-fired steam generators (Reference 5-12)
       •   A. D.  Little — analysis of the electric utilities and equipment manufacturers  (Reference
           5-13)
       •   Battelle  -analysis of boiler population and fuels for nonutility application  (Reference
           5-14)
       •   Bureau of Mines - data on domestic coal production and end use by state; data on petro-
           leum products (Reference 5-15)
       •   "Power" Magazine -miscellaneous information on various  equipment and fuel trends
           (Reference 5-16)
To simplify these estimates, several  basic assumptions were made:
       •   Distillate oil  and kerosene were combined with the residual  fuel oil category.  The
           reason for this is that distillate oil accounted for only about 5 percent of  utility
           steam  plant  total  oil  consumption (References 5-14 and 5-17)
       •   Coke,  coke breeze, refuse, process gas, wood, bagasse, black liquor, sewer sludge, etc.,
           have negligible application in utility boilers
                                                5-6

-------
            TABLE  5-2.   1974 STATIONARY SOURCE FUEL CONSUMPTION

Utility Boilers
Packaged Boilers
Warm Air Furnaces
and Miscellaneous
Combustion
Gas Turbines
Reciprocating
1C Engines
Total
Coal
101S kJ/yr
10.833
3.449
~~
—
_
14.282
Oil
1015 kJ/yr
3.483
5.801
2.132
0.844
0.327C
12.587
Gas
1015 kJ/yr
4.906
6.323a
4.542
0.681
0.913d
17.365
Total
1015 kJ/yr
19.222
15.573
6.674
1.525
1.240
44.234
 Includes  process  gas


DThis  sector  includes  steam and hot water units
M

"Includes  gasoline and oil  portion of dual fuel


 Includes  natural  gas  portion of dual fuel
                                  5-7

-------
                                                      TABLE 5-3.  UTILITY BOILER FUEL CONSUMPTION  (kJ  X  10~>s)







Utility Boilers



Tangential
Single
Wall -Fired
Opposed Wall and
Turbofurnace
Cyclone
Vertical and
Stoker
T3
4- C I/I
3 10 3
t- O
r— V} C
33-1-
t/> O E
C 3
l'iฃ

•^ 3iS
"U •*-* ^
O *i— 3
E: m m
2.624
1.513

0.423

0.158
0.110

•o
C 
ID 3
t- 0
3 I/I C
1- 3 T-

"3 c 3
t/) •!- 4->
Ef

1-1-3
3: ca to
1.584
0.914

0.255

1.292
0.110

•o
f= t/1
10 3
O
s- in c
3 3 -i-

3 T- +J
CO E 1-
3 -O
* 4J JD
S-r- 3
_J CO l/>
0.869
0.501

0.140

—
__









5.130
2.938

0.839

1.588
0.338



T3
C
IO


IO
 3

1.134
2.453

1.258

0.061
_








•*
r— t/I

+J HI
O 3
H~ *'
7.624
6.886

2.649

1.725
0.338

U1
00

-------
Coal accounted for 56 percent of the fuel consumed by utility boilers, natural gas 26 percent, and
oil  18 percent.  Coal consumption In utility boilers Is about 76 percent of the total energy sup-
plied by coal to all stationary sources.  For gas and oil the amounts burned 1n utility boilers
totaled only 30 and 28  percent, respectively, of the total of these fuels consumed by stationary
sources.

5.1.2.2  Packaged Boilers
      Data on the fuel  consumption of packaged boilers are not as reliable as data for utility
boilers.   This is due in part to the large number of installed units, the diversity of design, the
wide variety of applications, and the fuel flexibility of many of these units.  Table 5-4 lists the
fuel consumption  estimates for the boiler designs in this sector which 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
           5-14)
       •    Battelle - analysis of equipment design distribution (Reference 5-18)
       •    U.S. Department of Commerce —data on boiler sales 1968 to 1974 (Reference 5-19)
       •    TRC — historical  trends in package boiler fuels (Reference 5-20)
       The following  assumptions were used to estimate fuel consumption for packaged boilers:
       t    All boilers  greater than 29 MW in capacity are watertube designs and are single-wall
           fired
       •    Pulverized coal is not fired in units of capacity less than 29 MW
       •    All coal burned for residential and commercial heating is used 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, coal  supplied 24 percent of
the energy, oil 42 percent,  and gas 34 percent.  In comparison to the utility boiler sector, it is
clear that easily transported and distributed fuels are important for packaged boilers.  Whereas for
utility boilers coal  is the  most heavily used fuel, in packaged boilers coal is used almost exclu-
sively in  the larger watertube and older stoker units.  Coal is seldom used in the new firetube or
the smaller watertube boilers.
                                                 5-9

-------
                                                       Table 5-4.   1974 PACKAGED BOILER FUEL CONSUMPTION (kJ x 10'15)
01
o
Packaged Boilers
Water-tube Boiler
Wall firing
>29 MW
Watertube Boiler
Stoker
>29 MW
Single Burner
Watertube
<29 MW
Single Burner
Scotch Firetube
<29 MW
Single Burner
HRT Firetube
<29 MW
Single Burner
Firebox Firetube
Single Burner
Cast Iron Boilers
Stoker Watertubes
<29 MW
Stoker Firetubes
<29 MW
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
0.723


_


0.698


1.391


0.633


1.012

0.377

—

—

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

0.641

1.554

0.598

1.711




-------
5.1.2.3  Warm A1r Furnaces  and Other Commercial and Residential Combustion
      Here again, exact  fuel  consumption 1s difficult to estimate because of the extremely large
number of units  in the  field and the large variety of available designs.  Fuel consumption estimates
for commercial and residential as well as various cooking appliances, clothes dryers, refrigeration
units, etc. listed as  "other"  are presented in Table 5-5.  The major source for these estimates was
the 1970 U.S. Census  (Reference 5-21).
      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 units; since these units are generally rurally located, they were combined with
           natural gas-fired units
      •   Coal  is not fired in warm air furnaces, but when used in residential  or commercial
           heating applications, it is burned in steam or hot water units
Total warm air furnace fuel consumption in 1974 represented about 15 percent of the total  used in
 stationary sources for energy conversion.  It is important to note that the amount of natural  gas
 used in  this  sector  is approximately equivalent to the amount used by utility and packaged boilers,
whereas  oil products  are  used considerably less.
 5.1.2.4   Gas  Turbines
       1974 estimates  of  fuel  consumption for gas turbines are considered to be of high quality
 because of the relatively small number of major applications and manufacturers of these units  and
 the regulation of utility application.  Table 5-6 gives the fuel consumption estimates for the
 important gas turbine  capacity ranges defined in Section 2.  These estimates are derived from  a
 number of sources:
       •   GT-Standards Support Document -installation and generation for all applications and
           capacity ranges  except utility (Reference 5-22}
       •   FPC - installation, generation, and fuel consumption for all utility applications
           (References  5-10 and 5-23)
      •   Sawyer's GT Catalog -miscellaneous information on utility and pipeline applications
           (Reference  5-24)
      •   GT International -data on gas turbine electric utility installations (Reference 5-25)
                                                5-11

-------
     TABLE 5-5.  1974 WARM AIR FURNACE AND OTHER
                 COMMERCIAL/RESIDENTIAL COMBUSTION
                 (kJ x 10"15)
Warm Air Furnaces
Warm Air Central
Furnaces
Warm Air Room Heaters
Miscellaneous
Commerci al /Resi dential
Combustion
Distillate
Oil
1.405
0.727
•• ~
Natural
6asa
3.091
1.451
1.0
Total
Fuel
4.497
2.178
1.0
Includes  bottled,  tank or LPG
    TABLE 5-6.   1974 GAS TURBINE FUEL CONSUMPTION
                (kJ x  TO'15)
Gas Turbines
Gas Turbines
>15 MW
Gas Turbines
4 MW to 15 MW
Gas Turbines
<4 MW
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
                       5-12

-------
These estimates were  based  on  the following assumptions:
      •   Typical  specific heat rates for the three capacity ranges were 10.9 MJ/kW-hr (10,300
          Btu/kW-hr),  13.9 MJ/kW-hr (13,200 Btu/kW-hr) and 16.4 MJ/kW-hr (15,500 Btu/kW-hr) for
          large, medium,  and  small capacity turbines, respectively
      •   Specific fuel  consumption does not vary w'ith 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, refuse, etc. burned in turbines is negligible
      •   Supplementary  fjred combined-cycle turbine fuel consumption was minimal in 1974
 The total  energy consumed by gas turbines was about 3.5 percent of the total stationary source fuel
 consumption  in  1974.   As  Table 5-6 shows, medium-capacity units consumed more total fuel than the
 large units.  The  bulk of the fuel consumption for these medium-capacity turbines was either in the
 oil and  gas  industry, where units operate almost constantly, or in private sector electricity gene-
 ration, where units operate about three-quarters of the time.

 5.1.2.5   Reciprocating 1C Engines
       This  sector is composed of an extremely wide range of designs, applications and manufacturers.
 A recent study (Reference 5-26), however, has extensively characterized reciprocating 1C engines in
 terms of installed capacity and annual generation by fuel, and data from this study have been used
 extensively for this sector.  For consistency with other sections of this report, data from Refer-
 ence 5-10 have been used for installed capacity, annual generation, and fuel consumption of 1C engines
 used by electrical  utilities.  Table 5-7 gives fuel consumption figures for the significant types of
 equipment for this sector as determined in Section 2.
       The following assumptions were used in arriving at these estimates:
       •   Specific fuel  consumption averaged 9.9 MJ/kW-hr (7,000 Btu/hp-hr), 11.3 MJ/kW-hr (8,000
          Btu/hp-hr),  and 11.3 MJ/kW-hr for large, medium, and small capacity ranges respectively
       •   Specific fuel  consumption does not vary 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
       t   No natural gas is burned in small capacity equipment
                                                5-13

-------
TABLE 5-7.  1974 RECIPROCATING 1C ENGINE FUEL CONSUMPTION (kJ x 10'15)
Reciprocating 1C Engines
Compression Ignition
>75 kW/cyl
Spark Ignition
>75 kW/cyl
CI
75 kW to 75 kW/cyl
>1000 RPM
SI
75 kW to 75 kW/cyl
>1000 RPM
CI
<75 kW
SI
<75 kW
Natural
Gas
—
0.813
—
0.043
—
— •
Distillate
Oil
(Diesel)
0.054
—
0.129
•—
—
—
Gasoline
—
— —
— •
0.084
—
0.049
Dual
(Oil + Gas)
0.058 Gas
0.012 Oil
•—
—
— •
—
—
Total
Fuel
0.123
0.813
0.129
0.127
—
0.049

-------
      The total energy consumed by this sector 1s about 3 percent of  the total stationary source
energy converston  fuel  consumption.  Much more natural gas 1s used than oil, predominantly in the
large-bore units.  The  major user of natural-gas-flred, large-bore engines is the oil and gas indus-
try,  where units operate essentially full-time.
5.1.2.6   Industrial  Process Heating
       For the industrial process  heating equipment,  production totals for various  processes within
 the  sector were used instead of  fuel consumption  totals.   One  reason for  this approach  is that
 emission factors for industrial  process heating are usually  presented  in  terms  of production totals.
 Also, production figures are far more reliable than energy consumption statistics for the heating
 operations in most industries.
       Table  5-8a  gives production data for the major process heating  industries.   Table 5-8b pre-
 sents refinery process  heating fuel consumption for 1974.  Because the statistics  kept by industry
 associations  are fairly complete, and there are a high number of reliable sources  for this information,
 these data are considered to be of high quality.   The primary sources  for these statistics were:
       •   Walden  —data on the iron and steel industry (Reference 5-27)
       •   Bureau  of Mines —data on the iron and steel industry, cement industry,  brick and  ceramic
           industry  (Reference 5-15}
       •   IGT —data on cement kilns,  glass manufacture, petroleum refineries,  cement industry
           (Reference 5-28)
       •   TRC — data on brick and ceramic kilns  (Reference 5-20)
       •   Lockheed — data on refinery  flaring (Reference 5-29)
       t   KVB - data on refinery process  heaters  (Reference 5-30)

 5.2    EMISSION FACTORS
       This section  presents uncontrolled emission factors for the significant stationary sources of
 NOX  identified in  Section 2 of this report.   Emission factors were compiled for the following fuels:
 lignite, bituminous,  and anthracite coal;  distillate and residual oil, and natural  gas.   Since data
 from process  gas utilization are inadequate, emission factors have not been included for this fuel.
 Whenever possible, emission factors will  be expressed in terms of fuel inputs, i.e., nanograms N02
 Per Joule heat input.   If .emissions are less dependent on fuel  consumption -as in the chemical
 process  industries - they will  be expressed as a  function of product output.
                                                5-15

-------
 TABLE 5-8a.  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 N0x/yra
 318 Mg N0x/yra
aNO  estimates
   A
 TABLE  5-8b.  1974 REFINERY PROCESS HEATING
              FUEL CONSUMPTION  (kJ x  lO'15)
Heater Type
Natural Draft
Forced Draft
Total
Natural Gas
1.119
0.1282
1.2472
Oil
0.2565
0.0806
0.3371
Total
1.3755
0.2088
1.5843
                       5-16

-------
      Criteria pollutants,  NOX, SOX, HC, CO, and total participate,  have  been  extensively  tested
and the quality of  the  resulting emission factors 1s generally  high.  Unfortunately,  the  quality
of the measurements for less studied species - polycyclic organic material  (POM),  sulfates, and
trace elements -varies widely.  Tables of emission factors  for criteria pollutants have  been
included  1n  the text, while  those for ROMs, sulfates and trace  metals and  corresponding emissions
are contained in  Appendix A.
       Figures for  emission  factors have been obtained from  AP-42 (Reference 5-31) and its supple-
ments,  from  a survey of existing literature, and from preliminary results  of ongoing  test programs.
Whenever  possible,  AP-42 and its supplements have been used, since they typically  reflect the most
recent test  results.  In cases where emission factors are not available for specific  design types
from these sources, estimates of emission factors have been  made from test results on similar equip-
ment.  In some  instances, a  range of emission factors is available and in  these cases a representative
average value has been  assigned.  Each of the following subsections includes a discussion of the
sources for  the  data given on emission factors, along with the  rationale for their selection and
their relation  to AP-42 emission factors.  It should be emphasized that the following factors rep-
resent uncontrolled operating conditions without the use of  pollution control devices, except where
noted.
5.2.1  Utility  and Large Industrial Boilers
       Table 5-9 gives  uncontrolled emission factors for the criteria pollutants from utility
boilers.   NO emission  factors for these boilers were obtained  from AP-42  supplements (References
5-32, 5-33).  These values are in good agreement with measurements obtained from utility boiler
field testing (References 5-34 through 5-41).  Values for cyclone furnaces and lignite-fired boilers
were obtained from more recent studies (References 5-11, 5-12).
       Emission  factors for SO , PART, HC, and CO were gathered from a search of the  available
                              A
literature for  bituminous coal-fired, tangential, single-wall-fired or opposed-wall furnaces
(References  5-34 through 5-41).  Because there are very little  available data for  vertical-fired
boilers,  AP-42  emission factors (Reference 5-31) were used for  this inventory.  Emission  factors
for HC and CO from tangential, single- and opposed-wall, residual-oil-fired boilers were  obtained
from References  5-34 through 5-41.  These numbers are considerably lower than AP-42 values. Par-
ticulate  and SOX emission factors from AP-42 used here are in excellent agreement  with represen-
tative field testing (References 5-32, 5-33).  AP-42 and its supplements were also used as  a source
of emission  factors for distillate oil and natural gas, but  these values have not  been verified
since boiler field  tests of these fuels are not available.
                                                 5-17

-------
             TABLE 5-9.  UTILITY BOILER CRITERIA POLLUTANT EMISSION FACTORS  (ng/J)
Equipment Type
Utility Boilers
Tangential
Anthracite
Bituminous and Subbituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Single Wall -Fired
Anthracite
Bituminous and Subbituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Opposed Wall and Turbofurnace
Anthracite
Bituminous and Subbituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Cyclone
Anthracite
Bituminous and Subbituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Vertical and Stoker
Anthracite
Bituminous and Subbituminous
Lignite
NOX


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
V


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
Parta'b


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

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

261A
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)

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
10
in
1-

































S represents the percent sulfur in the fuel, A represents the percent ash in the fuel
Numbers in parentheses are average values
                                            5-18

-------
      Polycyclic organic  matter (POM) values for utility boilers come  from  References  5-41 and
5-42.  Unfortunately,  values for coal-fired power plants vary  by two or three orders of magnitude
depending upon equipment type.   Consequently, a range of values has been given rather than a single
specific value.
      Sulfate emission factors for coal-fired utility boilers were determined from field testing
(Reference  5-43).
      Trace metallic  emission  factors for this sector come from References  5-5, 5-6, 5-9 and 5-44
through  5-48.  There is fair agreement concerning the partitioning and  enrichment properties of
specific trace elements presented in these studies; however, agreement  is not sufficient to warrant
any more than average  trace metal concentrations in the fuel.  As a result,  care must be used in
applying these emission factors.  It should be noted that they are presented here as estimates rather
than as  exact values.
5.2.2 'Packaged  Boilers
       Packaged  boilers were divided into two capacity groupings:  boilers of capacity  of 23 MW
 to  73 MW (100 to 250 MBtu/hr),  and boilers of capacity of less than 29  MW of fuel.  Table 5-10 pre-
 sents uncontrolled emission factors for the criteria pollutants for these two classes of boilers.
 The emission factors given come from industrial boiler field tests (References 5-49 through 5-51)
 and AP-42 and its supplements  (References 5-31 through 5-34).
       The firing and  emission  characteristics of the large industrial  boilers are similar to those
 of  utility boilers.   CO and HC  emission factors for bituminous coal, oil, and gas obtained from the
 results of field tests (References 5-49 and 5-50) are considerably lower than those supplied by
AP-42.  NO ,  particulates, and  SO  emission factors for large packaged  boilers came from both field
          x                      x
tests (References 5-49, 5-50) and AP-42 and its supplements (References  5-31 through 5-33).  There
 is  excellent correspondence between these two data>sources.  Since there has been very  little field
testing of boilers  firing anthracite coal, emission factors for this fuel are from AP-42.
       Emission  factors for the group of packaged boilers less than 29  MW capacity came largely
from field tests of industrial  and commercial boilers at baseline operating  conditions  (References
5-49 through 5-52).  The data were averaged where baseline data were available for more than one unit
of  a specific design type.  If  test data were not available for a specific equipment/fuel combination,
AP-42 numbers or test  data from similar equipment were substituted.
       In  general,  there is excellent correspondence between AP-42 supplements (References 5-32,
5-33)  and  field  testing (References 5-49 through 5-52) for criteria pollutants from packaged boilers.
                                                5-19

-------
    TABLE 5-10.  PACKAGE BOILER CRITERIA POLLUTANT EMISSION FACTORS (ng/J)
Equipment Type
Watertube-Wall Firing
29 MW to 73 MW
Anthracite
Bituminous and Lignite
Residual Oil
Distillate Oil
Natural Gas
Process Gas
Watertube Stoker
29 to 73 MW
Anthracite
Bituminous and Lignite
Watertube
<29 MW
Residual Oil
Distillate Oil
Natural Gas
Process Gas
Firetube Scotch
Residual Oil
Distillate Oil
Natural Gas
Process Gas
Firetube/ Firebox
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
Watertube Stoker
<29 MW
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

184.5
67.5
98.9

184
67.5
51.6


179
179
V


585S
559S
408S
434S
0.3
-


584. 7S
756. 6S


482S
434S
3.4
-

482S
434S
0.3
-

482S
434S
0.3
—

482S
436S
0.3

482S
434S
0.3


585S
672S
Particulates3


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. 5S + 8.6
3.7
2.6


31A
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
S represents sulfur of fuel;  A represents percent ash of the fuel
                                    5-20

-------
                          TABLE 5-10.   Concluded
Equipment Type
Firetube Stoker
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
V

585S
672S

585S
679S
^815
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
                                                                                .0
                                                                                o
                                                                                in
S represents sulfur of fuel; A represents percent ash of the fuel
                                     5-21

-------
The only area of significant disagreement  is  the  emission  factors for small  packaged oil-fired
boilers, where  values from field  testing (References  5-49  through 5-52)  are  considerably lower than
AP-42  supplement values  (Reference 5-33).   In general,  small watertube,  scotch firetube, firebox
firetube, HRT firetube,  and cast  iron boilers fired by  single  burners have quite similar combustion
characteristics and  thus, similar emission  factors.
        POM emission  factors for packaged boilers  came from recent field  testing (References  5-54
through 5-56),  and from  AP-33  (Reference 5-42).   Again, there  are several  orders of magnitude  between
AP-33  values and the results of recent field  tests.  Because available data  are scarce  and available
measurements vary widely, a range has been  presented rather than  specific  values.   In addition,  it
has been assumed that scotch firetubes, HRT firetubes and firebox firetubes  have the same POM  emission
characteristics, and that shell boilers and cast  iron boilers  are also similar.   A  trend toward
larger POM emissions from smaller units is  clearly evident.  Smaller  units are  usually  less  care-
fully  regulated, which means less efficient firing and  operation,  resulting  in  poor combustion.
        Field testing data for sulfate emissions and trace elements from  packaged boilers are quite
sparse.  Some field  testing has been performed (Reference 5-51),  but  little  data have been quantified.
It is  assumed that trace element emission factors will  be similar for large  packaged and utility
boilers since they often have similar operating characteristics to utility boilers.  This assumption
does not hold, however,  for small  packaged  boilers.  Care must be exercised  in  using trace element
factors, since they  may  vary by two or more orders of magnitude depending on the  fuel.

5.2.3  Warm Air Furnaces
       Table 5-11  gives  uncontrolled emission factors for the criteria pollutants from warm air
furnaces.   NOV emission factors have been determined from the results of recent  field tests  (Ref-
             A
erence 5-52)  and from AP-42 supplements (Reference 5-33).  Emission factors  for  the  remaining cri-
teria  pollutants came from field testing (References 5-52, 5-53,  5-57),  studies  (References 5-58,
5-59),  and AP-42 supplements  (References 5-32, 5-33).    In general, the agreement between these dif-
ferent sources  of  data  is excellent.   As a  result, values from AP-42 supplements  are felt to repre-
sent the emission  characteristics  of warm air furnaces accurately, and the majority  of the emission
factors given  for warm  air furnaces  comes  from these supplements.
       Little  testing has been  done on POHs emitted from warm air furnaces.  AP-33  (Reference 5-42)
does report  some POM emissions  data.   Since supporting data are lacking  and  most POM testing is
inconsistent,  these  values,  presented in Appendix A, are only an  order of magnitude  estimate of
POM emissions.
                                                5-22

-------
       TABLE 5-11.  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 A1r Room Heaters
Oil
Natural Gas
Miscellaneous Combustion
Natural Gas
N0x

61.0
34.4

61.0
34.4

34.4
soxa

434S
0.358

434S
0.258

0.258
Part

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
 S  represents percent sulfur  in  the  fuel

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

cNumbers in parentheses  denote average values
                                   5-23

-------
       Sulfate emission factors from warm air furnaces were not available.
       Trace element emission factors for warm air furnaces cannot be determined  from  the existing
data.   The only significant source would be the small number of coal-fired units.  These are in-
significant on a national  scale but could present localized pollution problems.

5.2.4  Gas Turbines
       Emission factors for gas turbines come from field studies (References 5-22, 5-60} and an
AP-42 supplement (Reference 5-61).  Table 5-12 presents uncontrolled emission factors for the cri-
teria pollutants, primarily from the recent Gas Turbine Standard Support Document (Reference 5-22).
Values from the AP-42 supplement in this section for non-NOx criteria pollutants are in excellent
agreement with values from field studies (References 5-60, 5-62).
       Emission factors for POMs and sulfates from gas turbines cannot be determined at present
due to the lack of representative field testing.

5.2.5  Reciprocating 1C Engines
       The range of equipment design combinations for reciprocating 1C engines is so varied that
it is impossible to determine emission factors for each equipment combination using the available
data.  Consequently, reciprocating 1C engines have been categorized as either spark ignition or
compression ignition engines in three capacity ranges.  Table 5-13 presents uncontrolled emission
factors for the criteria pollutants for these equipment types.
       NOV emission factors have been derived from values presented in a current  1C engine study
         A
(Reference 5-26).  Non-N0x criteria pollutant emission factors come from recent AP-42 supplements
(References 5-32, 5-33).  These values correspond closely with the results of field tests (Reference
5-63).
       Sufficient data are not available to quantify emission factors for POMs, 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 this, determining specific emission "factors to span this range of values is
not possible.

5.2.6  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
                                                 5-24

-------
                                  TABLE 5-12.   GAS TURBINE CRITERIA POLLUTANT
                                               EMISSION FACTORS (ng/J)
IM
tn
Equipment Types
Gas Turbine
>15 MW
Natural Gas
Diesel oil
Gas Turbine
4 MW to 15 MW
Natural Gas
Diesel oil
Gas Turbine
<4 MW
Natural Gas
Diesel oil
N0x

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

49.0
47.0

49.4
47.3

49.4
47.3
HC

8.6
8.6

8.2
9.9

8.2
9.9

-------
TABLE 5-13.  RECIPROCATING 1C ENGINE CRITERIA
             POLLUTANT EMISSION FACTORS  (ng/J)

Comp Ignition
>75 kW/cyl
Dist Oil
Dual Fuel
Spark Ignition
>75 kW/cyl
Natural Gas
CI 75 kW to
75 kW/cyl
>1,000 RPM
Dist Oil
SI 75 kW to
75 kW/cyl
>1,000 RPM
Natural Gas
Gasoline
CI <75 kW
2-4 cyl
Dist. Oil
SI 75 kW
2-4 cyl
Gasoline
NOX

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

16.3
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
                       5-26

-------
industries by a large  number of small-scale processes which as  a whole may  have  a  significant  impact,
but which are individually hard to quantify.  Nonetheless, there are  several  industries  which  con-
stitute  the major  pollution sources, and these industries will  be  considered  in  this  section.   Un-
controlled emission  factors for the criteria pollutants  based on product  output  are presented  in
Table 5-14a.  Refinery process heating emission factors  are presented in  Table 5-14b.
       Cement and  glass industries which use kilns, furnaces, and  ovens to  heat  raw materials  are
a significant source of N0x>  Emission factors for N0x from these  processes come primarily from a
recent study of these industries (Reference 5-28).  Non-NO  criteria  pollutant emission  factors
                                                          X
have partially  been  determined from AP-42 values  (Reference 5-31).  Very  few  data  are presently
available for sulfates, ROMs, and trace elements  from cement kilns.   Sulfate  emission factors  come
from Reference  5-64, although the values presented are questionable.
       The extensive use of ovens and furnaces in the iron and  steel  industry results in the produc-
tion of major quantities of NO .  Most of these emissions come  from coke  oven underfiring, steel
sintering machines,  and open hearth furnaces.  Noncriteria pollutant  emissions data from the iron
and steel industry are not available.  NO  emission factors from the  iron and steel industry have
been determined from Reference 5-27-  Other criteria pollutant  factors come from References 5-20 and
5-27.
       Other NO  sources in the petroleum industry are refinery flares, fluid catalytic crackers
               X
and process heaters.  NO  emission factors for refinery  flares  and catalytic  crackers were obtained
from a recent study of process heating (Reference 5-28).  N0x emission factors from refinery process
 heaters were obtained from a recent study conducted by KVB (Reference 5-30).  The  values reported here
are for both natural draft and forced draft refinery heaters firing gas and oil.   The values are ten-
 tative pending  completion of the KVB study.  Emission factors for  other criteria pollutants for re-
 finery process  heaters are based on values reported in AP-42.   Emission factors  for other criteria
 pollutants come from AP-42 (Reference 5-31) and from emission studies (References  5-20,  5-65).  Non-
criteria emission factors are not available.
       The contact process used in the production of sulfuric acid requires burning of sulfur  in a
combustion chamber,  which generates significant N0x emissions.  The emission  factor for  S0x comes
from Reference  5-20.

5.3   EFFECT OF EMISSION CONTROL REGULATIONS
       The preceding section provided estimates of pollutant emission factors for  the major  sta-
tionary combustion sources without accounting for control devices  which are currently being  employed.
Because of both state and local regulations, emissions of SO  and  particulates from  the  large point
                                                            X
                                                 5-27

-------
       TABLE 5-14a.  INDUSTRIAL PROCESS COMBUSTION CRITERIA POLLUTANT
                     EMISSION FACTORS (g/kg PRODUCT)

Cement Kilns
Glass Melting Furnaces
Glass Annealing Lehrs
Coke Oven Underfire
Steel Sintering Lines
Open Hearth Furnaces
Brick & Ceramic 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
C.23
0.203
b
S0x
5.09
2.12
NA
2.84
0.71
0.70
0.54
1.413
NIL
PART
122
1.0
NA
37.7
10-
6.
65.
0.69a
NIL
CO
NA
NA
NA
NA
22.
NA
0.1
39. la
NIL
HC
NA
NA
NA
NA
NA
NA
0.04
0.63
0.43C
ag/l Feed

 Production is not quantifiable.   Estimate  of NO  is  made  in  fuel  consumption  section.
cg HC/1  capacity
             TABLE  5-14b.  REFINERY PROCESS HEATING CRITERIA POLLUTANT
                          EMISSION FACTORS (ng/J) (Reference 5-30)
Heater
Type
Natural
Draft
Forced
Draft
Fuel
Gas
Oil3
Gas
Oil3
NOX
70.1
154.8
110.5
184.5
S0x
860Sb
627SC
860Sb
627SC
PART
8.6
78.4
8.6
78.4
CO
NILd
NIL
NIL
NIL
HC
12.9
13.07
12.9
13.07
     Assumed fuel oil nitrogen content of 0.2 percent and a fuel nitrogen
     conversion to NO of 50 percent

     Refinery gas sulfur content (lb/100 ft3)
     (assumed 10 grain/100 ft3 based on Federal EPA regulations)

     Fuel oil sulfur content (weight percent) (assumed 0.1 percent)

     Negligible emissions
                                    5-28

-------
sources have been extensively controlled.  NOX-emissions have  been  less  extensively  regulated,  how-
ever,  so  NOX controls  applied to existing equipment are less commonplace.  This  section describes  the
degree of control which now exists for participates, SO , and  NO  and applies  these  controls  to
                                                       A        X
applicable equipment to more accurately represent present mass emission  totals.  The emission inven-
tory presented in the  following section gives particulate and  S0v emissions  for  the  controlled state;
                                                                X
only NO   emissions  are given for both uncontrolled and controlled uses for comparison.
5.3.1   Particulate  Control
      The most common types of particulate control equipment  are centrifugal  collectors and electro-
static precipitators.   Coal- and oil-fired boilers contribute  approximately  98 percent of utility
boiler particulate  emissions; hence the controls on these boilers are most important.  Gas-fired
boiler particulate  emissions are insignificant 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.
 5.3.1.1  Utility Boilers
       Information  on the types of controls used on utility boilers of different sizes comes  from
 NEDS  and two recent particulate studies of emissions  (References 5-6, 5-59,  and  5-66).  According  to
 these studies, electrostatic precipitators and centrifugal collectors make up  over 96 percent of the
 particulate controls installed on utility boilers.  Twelve percent  of pulverized coal-fired boilers
 have  no  collection  devices.  Table 5-15 displays the  percent of particulate  collected from utility
 boilers.  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 particulate
 generated in residual  oil-fired boilers is not collected.  More importantly, 35  percent of the flyash
 formed in pulverized coal-fired boilers, 25 percent in cyclone boilers and 50  percent in stokers are
 also  not collected.

 5.3.1.2   Industrial Boilers
       A recent source assessment document for industrial boilers  (Reference 5-67) has been 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)  and
 30 percent of the larger boilers are not controlled.   It is assumed that controls  for small pulverized
 coal  industrial boilers (<29 MW) are insignificant.   As displayed  in Table  5-15, about  50  percent
 of the particulate  emissions from large coal-fired  industrial  boilers are collected.  However,  for
                                                 5-29

-------
TABLE 5-15.  AVERAGE PARTICULATE COLLECTION
Sector
Utility Boilers



Package Boilers





Industrial Pro-
cess Combustion
Equipment/Fuel
All/Pulv. Coal
Cyclone/Coal
Stoker/Coal
All/Residual Oil
29 to 73 MW
Wall-Fired/Pulv. Coal
Stoker/Coal
Wall -Fired/Residual Oil
Wall -Fired/Distill ate Oil
<29 MW
Stoker/Coal
Cement Kilns
Percent Collection
. 65
75
50
25

50
50
5
0
15
88
                  5-30

-------
smaller  units, 95  percent of the particulates from residual oil-fired  boilers and  15 percent of  the
particulates  from  small  coal stokers are released to the atmosphere.
5.3.1.3   Industrial  Processes
       In the industrial sector, the cement industry is controlled  extensively  by  the  use  of cyclones
and electrostatic  precipitators.  Table 5-15 shows that approximately  12  percent of particulate
emissions are not  separated from the effluent stream by collection  devices  (Reference  5-68).
       In Section  5.4 the emissions inventory will be displayed as  a function of controlled parti-
culates.  Since  the large majority of boilers do possess particulate controls,  an  uncontrolled
inventory would  not represent the current impact of controls  implementation.
5.3.2  SOX Control
       To determine the extent of SOX control on stationary combustion sources, the two commercially
available means  of SOX control -flue gas desulfurization  and low-sulfur  fuel -were examined both
 for their extent of use and their effectiveness.  Coal cleaning currently has seen  insignificant
 use nationwide.   Two recent surveys of flue gas desulfurization (References 5-69,  5-70) indicated
 that the total installed capacity of FGD equipment on utility-size  boilers  is about 5,000 MW.   When
 this is compared to the total electrical utility boiler installed capacity of about 350,000 MW
 (Reference 5-10),  the effect of FGD systems is clearly small.
        The primary means of meeting local SO  control regulations is through the use of low-sulfur
fuel either totally  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 concentra-
 tion data will result in a controlled inventory.  Since the utility sector is the most heavily regu-
 lated and uses the large majority of sulfur containing coal and oil, the controlled utility inventory
 combined with uncontrolled emissions of the remaining sectors will  serve as the controlled S0x in-
 ventory.  The SO  inventory presented in Section 5.4, therefore, will  reflect the controlled state
                X
 for all  stationary combustion sources.
5-3.3  NOX Control
       To determine  the extent of NOX  control for stationary  combustion sources, a  different approach
was used than for  particulates and SOX.   In this approach, applicable  state and local  NOX regulations
(summarized in Section  4.1  of this report) were applied to combustion  equipment within the region.
Examination of the regulations showed  that utility boilers are the most extensively regulated, while
gas turbines  and large  packaged boilers  are only regulated in some  regions.  Examination of data on
utility  and gas turbine  installations  and fuel  consumption showed that only controls for utility
                                                 5-31

-------
 boilers would have greater than  a  1  percent  effect.   Thus,  only  utility boilers are considered in
 the following discussion  of NO   controls.
        In calculating  the effect of  NO  controls on utility boiler emissions,  the uncontrolled emis-
 sions of a specific  boiler were  reduced by the ratio  of the controlled  emission factor to the  un-
 controlled factor.   For example, if  the emission limitation for  oil-fueled  boilers  is  129 ng/J and
 the uncontrolled  emission factor is  153 ng/J, then the reduction of N0x  emission  (assuming 100 per-
 cent compliance)  is  (1 -  129/153) or 16 percent.  A more detailed explanation  of  the methodology em-
 ployed to arrive  at  specific control factors is given in Appendix A.  A  systematic  compilation  of
 stationary source equipment and  applicable NO  regulations  yielded the control  factors  listed  in
                                             X
 Table 5-16.

                                 TABLE 5-16.  NOX CONTROL FACTORS

Tangential
Wall -Fired
Horiz. Opposed
Cycl one
Vert, and Stoker
Coal
0.000053
0.0014
0.0014
0.0166
0.00005
Oil
0.014
0.048
0.048
0.039
-
Nat. Gas
0.057
0.124
0.124
0.0
-
       Note that the degree of current control of coal-fired utility boilers is small, while those
which burn oil or gas are significantly controlled.  The control of coal-fired utility boilers is
increasing, however, as retrofit controls are being implemented in a number of areas and as new units
designed to meet the NSPS (300 ng/J) are being installed.  One reason for lack of control of coal-
fired boilers is the prior lack of NOX regulations in states where coal is heavily used, and 'the
comparatively stringent regulations in states which use large amounts of oil and gas.  Comparisons
of the controlled and uncontrolled NOX emission rates will be presented in Section 5.4.
5.4    EMISSIONS INVENTORY
       This section presents  an inventory of major combustion-related pollutants originating from
stationary fuel-burning sources of NOX-   The inventory includes the criteria pollutants:  NOX, SOX,
CO, HC,  and particulates emitted from gaseous effluent streams.  A more complete emissions inventory
is given in Appendix A by equipment type for 17 fuel  categories and the following noncriteria
pollutants:  sulfates, trace  metallics,  ROMs and trace elements in hopper and flyash.
                                               5-32

-------
5.4.1  Stationary Source  Sector Emissions
      Tables 5-17  through 5-22 provide 1974 criteria pollutant emissions and totals for  the fol-
lowing sectors:
      t   Utility  boilers -Table 5-17
      t   Packaged boilers -Table 5-18
      •   Warm  air furnaces —Table 5-19
      •   Gas turbines —Table 5-20
      •   Reciprocating  1C engines —Table 5-21
       •    Industrial  process heating - Table 5-22 (Includes total criteria pollutant emissions for
           oil-  and gas-fired refinery process heaters)
 The emission estimates are for 1974 since this is the most recent period for which comprehensive
 fuel consumption data  are availabe.  All units are in 1000 Mg per year.  Note that these tables give
 uncontrolled emission  figures for NOX and controlled emission figures for SOX and particulates.
       Table 5-23 summarizes the total emissions from the above sectors.

 5.4.2  Controlled NOX  Emissions
       Table 5-24 presents the controlled NOX emissions derived from control factors developed in
 Section 5.3  for  stationary sources.  As discussed in that section, controlled NOV emissions are
                          +
 given for utility boilers only, since gas turbines and packaged boiler NOX regulations were con-
 cluded to have little  effect on sector totals.  This inventory applies existing 1976 state and
 local NOX relations to the 1974 stationary source population.  This hybrid inventory is not intended
 to accurately represent actual  NOX emissions for either year, but merely to indicate the current
 effect of NOX emission regulations.  The degree of utility boiler control is somewhat uncertain
 since some units are not  in compliance with regulations either through variances or lack of enforce-
 ment. Some  units,  on  the other hand, are controlled to levels below the current regulations.   In
 a few areas  utilities  have added NOX control, in the absence of regulations, as part of public
 relation  efforts or for energy  conservation (low excess air firing).  These units have been gen-
 erally excluded  from the  controlled boiler inventory.
                                                5-33

-------
TABLE 5-17.  1974 CRITERIA POLLUTANT EMISSIONS FOR THE UTILITY

             BOILER SECTOR (UNCONTROLLED NOY) 1,000 Mg/yr
                                           /\
Furnace Design
Tangential


Wall -Fired


Opposed Wall


Cyclone


Stoker. & Vertical


Totals
Fuel
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas

NO
X
1,409
208
146
946
481
738.3
270.8
177.7
378.7
863.5
16.6
14-7
90.9
—
—
5,741.2
SO
X
6,999.6
583.3
0.34
4,030.6
598.6
0.74
1,131.6
236
0.38
2,737.4
34.9
0.018
414.7
—
—
16,768.2
HC
4.8
1.36
0.98
2.61
2.15
2.11
0.88
0.55
1.07
10.4
0.46
0.37
1.63
—
—
29.5
CO
"58.3
11.9
8.2
64.4
20.3
28.2
7.55
6.9
13.4
30.0
1.18
0.44
18.4
—
—
269.2
PART
3,178
30.5
4.84
1,734
31.1
10.5
499
!12.9
5.36
193
1.74
0.26
263.8
—
—
5,965
                              5-34

-------
                           TABLE 5-18.   1974 CRITERIA POLLUTANT  EMISSIONS  FOR  THE  PACKAGE

                                        BOILER SECTOR (UNCONTROLLED  NO) 1,000 Mg/yr
                                                                      /\
V
Equipment Design
Type
Watertube
29 MW to 73 MW

Watertube
<29 MW

Fi retube
<29 MW

Other3


Total
Fuel
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas

NOX
290
232.8
318.5
278.17
116.4
180
107
429.25
241.7
4.48
107.7
38.98
2,345
S0x
1,402
269
0.28
2,280
298
5.75
839
1,048
0.72
20.4
242
0.27
6,405
HC
3.10
2.17
3.62
27.66
0.57
2.87
10.1
2.14
4.09
8.24
4.62
2.95
72.13
CO
11.7
2.8
8.4
34.13
2.19
14.5
15.5
8.35
20.69
19.7
28.86
8.61
175.4
PART
935.8
24.3
1.6
2,787.8
24.1
2.8/
1,016
98.7
6.26
8.24
20.8
3.86
4,930.3
                alncludes cast iron and residential  steam and hot  water  units

-------
TABLE 5-19.  1974 CRITERIA POLLUTANT EMISSIONS FOR THE WARM AIR

             FURNACE AND MISC-COMBUSTION SECTOR (UNCONTROLLED NO ) 1,000 Mg/yr
                 - •                                              /\
Equipment
Warm Air Central Furnace

Warm Air Room Heater

Miscellaneous Commercial
and Residential Combustion
Total
Fuel
Oil
Gas
Oil
Gas
Gas

N0x
85.0
106.3
44.0
49.5
34.4
320.6
S0x
152
1.106
78.4
0.37
0.258
232
HC
6.59
10.5
3.41
4.95
4.3
29.7
CO
43.6
36.9
22.0
17.3
12
132.6
i
PART
10.8
13.2
5.58
6.24
3.4 .
39.3

-------
                            TABLE 5-20.   1974 CRITERIA POLLUTANT EMISSIONS FOR THE GAS

                                         TURBINE SECTOR (UNCONTROLLED NO ) 1,000 Mg/yr
                                                                        X
V
10
-J
Equipment Capacity
Range
Gas Turbine
>T5 MW
Gas Turbine
4 MW to 15 MW
Gas Turbine
<4 MW
Total
Fuel
Oil
Gas
Oil
Gas
Oil
Gas

NO
X
97.4
41.3
211
91.2
0.365
0.195
440
S0x
2.81
0.47
6.17
1.04
0.0135
0.0026
10.5
HC
2.25
1.81
5.73
3.84
0.012
0.0094
13.7
CO
12.4
10.34
27.2
23.1
0.047
0.049
73.4
PART
4.22
1.27
8.89
2.79
0.019
0.0070
17.3

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TABLE 5-21.  1974 CRITERIA POLLUTANT EMISSIONS FOR THE RECIPROCATING

             I.C. ENGINE SECTOR (UNCONTROLLED NO ) 1,000 Mg/yr
                                                A
Equipment Capacity
Range
I.C. Engines
>75 kW/cyl

I.C. Engines
75 kW to 75 kW/cyl

I.C. Engines
<75 kW
Total
Fuel
Oil
Gas
Dual
Oil
Gasoline
Gas
Gasoline

NOX
94.0
1,262
71.6
224.6
100.4
66.7
37.5
1,857.2
S0x
5.10
0.17
—
12.3
1.36
0.0091
0.80
19.6
HC
6.13
451
29.1
14.7
33.7
23.9
19.6
578.3
CO
16.6
143
9.6
40.0
1,014.8
7.6
591.9
1,824
PART
5.56
—
13.1
1.65
—
0.96
21.5

-------
               TABLE 5-22.  1974 CRITERIA POLLUTANT EMISSIONS FOR THE INDUSTRIAL PROCESS HEATING SECTOR
                            (UNCONTROLLED NO ) 1,000 Mg/yr
ฃ
\o
Industrial Equipment
Category
Refinery Heaters
Cement Kilns
Glass Melting Furnaces
Glass Annealing Lehrs
Coke Oven Underfire
Steel Sintering Lines
Open Hearth Furnaces
Brick & Ceramic Kilns
Catalytic Cracking
Refinery Flares
Iron & Steel Flares
Total
N0x
147.35
100.0
56.7
10.6
3.99
25.2
20.6
7.26
46.0
7.77
0.32
425.8
S0x
22.67
392.0
32.2
—
161.9
34.1
22.6
16.5
323.0
—
—
1,005.0
HC
20.5
—
—
—
—
—
—
1.26
144.5
—
—
166.3
CO
—
—
—
—
—
1,067.0
—
3.16
8,969.5
—
—
10,039.0
PART
37.2
1126.0
15.2
—
2,149
485
193.6
2,052.7
158
—
—
6,216.7

-------
TABLE 5-23.  CRITERIA POLLUTANT EMISSIONS BY SECTOR

             (UNCONTROLLED NO) 1,000 Mg/yr
                             y\
Equipment Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces and
Miscellaneous Combustion
Gas Turbines
Reciprocating I.C. Engines
Industrial Process Heating
Total
NOX
5,741
2,345
321
440
1,857
425.8
11,130
SOX
16,768
6,405
232
10.5
19.6
1,005
24,440
HC
29.5
72.1
29.7
13.7
578
166
889
CO
269.6
175.4
133
73.4
1,824
10,039
12,514
PART
5,965
4,930.3
39.3
17.3
21.5
ฃ.216.7
17,190

-------
  TABLE 5-24.   COMPARISON OF CONTROLLED AND UNCONTROLLED STATIONARY SOURCE NOX EMISSIONS
Sector and Equipment Type
Utility Boilers
Tangential
Wall-Fired
Opposed Wall
Cyclone
Vertical and Stoker
TOTAL UTILITY
Package Boilers
Conmercial and Residential Furnaces
Gas Turbines
1C Engines
Process Heating
TOTAL
Fuel
Coal
Oil
Gas
Coal
Oil
Gas
Coal
on
Gas
Coal
Oil
Gas
Coal
All
All
All
All
All
All
All
1974
Controlled
N0xa
(1,000 Mg/yr)
1,408
205
138
945
458
649
271
169
352
849
16
15
91
5,566
2,345
321
440
1,857
425.8
10,954
1974
Uncontrolled
NOX
(1,000 Mg/yr)
1,409
208
146
946
481
738
271
178
379
863
17
15
91
5,741
2,345
321
440
1,857
425.8
11,12?
Percent
Reduction
(ซ)
0.1
1.4
5.5
0.1
4.8
12.3
0
5.1
6.7
1.6
6.0
0
0
3.3
	
-
—
-
-
1.7
                                                                                              in
                                                                                              o>
"Controlled  by  regulations  existing December 1976
                                          5-41

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5.5    SUMMARY AND CONCLUSIONS
       This section presents a general summary of the NOX emissions  from all  sources and a more de-
tailed summary of the emissions from stationary fuel combustion  sources.   In  addition, several com-
parisons of the data generated in this study are made with  results of previous studies.  A compre-
hensive emission inventory for all pollutants is given  in Appendix A.
       Conclusions, consisting of rankings of sources on a  mass  emissions  basis and comments on data
quality and data gaps, are also presented.

5.5.1  Summary of NOx Emissions from all Sources
       As discussed in Section 2 (Figure 2-1), NO  emissions result  from both  natural  and anthropo-
genic sources.
Natural NOX Emissions
       Estimates of biologically-generated natural emissions of  oxides of  nitrogen  range  from 175 to
455 Tg (193 to 501 x 106 tons) annually on a global basis (References 5-71 through  5-73).  Addition-
ally, lightning, the major nonbiological natural source of  NO  ,  has  been estimated  to  produce  about
10 Tg (11 x 106 tons) NO per year globally.  By contrast, the estimated man-made oxides of nitrogen
were 48 Tg per year globally (Reference 5-73).   Although man-made emissions are only about 10  percent
of total emissions, man-made sources are by far the most significant in air pollution  due to their
concentration in population centers.  This is illustrated by comparison of the  ambient  concentration
due to natural and man-made sources.  The natural  background ambient N0? concentration  is estimated
at 0.0009 to 0.004 ppm (Reference 5-73).  The NOp concentration  in urban areas, however,  is  typically
between 0.01 to 0.5 ppm.  In N02-critical areas where the ambient concentration approaches the ambient
air quality standard (0.05 ppm), the natural  background level is less than 10  percent  of  the urban
ambient concentration.

Anthropogenic NOX Emissions
       As shown in Table 5-25, U.S.  man-made NO  emissions  for 1974 total about 21  million metric
                                               X
tons (23 million short tons).  The relative contributions of mobile and stationary  sources are about
45 and 55 percent, respectively,  as  illustrated in Figure 5-1.   These fractions are calculated using
controlled N0x emissions.   If uncontrolled figures for N0x  emissions are used,  the  respective  por-
tions would be 48 percent for mobile and 52 percent for stationary NO  emissions.   Stationary  emissions
include  stationary fuel  combustion,  noncombustion processes, fugitive and  incineration  sources.
                                                 5-42

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TABLE 5-25.  SUMMARY OF  1974  U.S.  ANTHROPOGENIC  NO   EMISSIONS
                                                  y\

Fuel Combustion
(Section 5.4)
Incineration
Noncombustion
Nitric Acid
Explosives Mfr
Adi pic Acid
Fugitive Emissions
Controlled Burning
Forest Wildfires
Structural Fires
Other: Grain Silos,
Welding, etc.
Total Stationary
Highway Vehicles
Gasoline
Diesel
Nonhighway Vehicles
Ai rcraf t
Railroads
Vessels
Others: Dune Buggies
Trail Bikes, Con-
struction Equipment,
etc.
Total Mobile
Total NOX
1 ,000 Mg
10,954

40a
193ab
127
51
15
498C
273
90
90
45

11,685 (54%)
7,360C
6,310
1,050
2,270C
350
90
*
170
1,660



9,630
(46%)
21,315
1 ,000 Tons
12,070

44
212
138
56
17
548
300
99
99
50

12,874
8,100
6,940
1,160
2,500
380
100
190
1,830



10,600
23,474
 Reference 5-74
 'Reference 5-75
 "Reference 5-76
                              5-43

-------
     Noncombustion 0.9%


          .Fugitive 2.3%
                                           Incineration  0.2%
                                     Stationary fuel combustion


                                                51-4%
Mobile sources


     45.2%
                1974 Stationary Combustion Source NO  Emissions
                                                    /\
Stationary Fuel Combustion
Fugitive Emissions
Noncombustion
Incineration
Mobile Sources
TOTAL
1,000 Mg
10,954
498
193
40
9,630
21,315
1,000 tons
12,070
548
212
44
10,600
23,474
Percent
Total
(51.4)
(2.3)
(0.9)
(0.2)
(45.2)
100
Figure 5-1.   Distribution of anthropogenic NOX emissions for the year 1974

             (stationary fuel  combustion:  controlled NO  levels).
                                                        /\
                                   5-44

-------
      A detailed listing of stationary NOX sources Is given in Table 5-26 and shown graphically in
Figure 5-2.  Table 5-26 also gives  the contribution of each stationary sector.  Note that combustion
in stationary sources, the  primary  emphasis of this program, accounts for about 94 percent of the
total emissions from stationary  sources.   Note also the relative contribution of each fuel.  Natural
gas accounted for about one-third of the emissions in 1974, with coal accounting for about 40 percent.
Preliminary 1976 data show  a strong trend away from natural gas fuel in the utility sector.
5.5.2  Summary of Air Pollutant  Emissions
      Table 5-27 gives emission totals for the criteria pollutants, sulfates, ROMs, and preliminary
solid and liquid ash stream production.  Criteria pollutant data are taken from Section 5.4 and sul-
fate, POM,! and ash production  data  are from Appendix A.  While totals for the criteria pollutants
are considered to be reliable, the  totals for sulfate, POM, and ash are order-of-magnitude estimates
at best.   Since the quality of available emission factor data for ROMs is poor, POM emissions are
given as  a range.  For  the  upper extreme of this range, POM emissions were derived from the largest
available emission factor,  while at the lower extreme, the smallest emission factors were used.   All
trace element emissions presented in Appendix A are also considered to be order-of-magnitude estimates.
       Rankings of equipment type/fuel combinations on a mass emission basis for the criteria pol-
lutants and energy consumption are  given in Tables 5-28 through 5-33.  The rankings include only the
first 30  sources for each pollutant, which in each case includes the major portion of the emissions
for that  pollutant.  Finally,  Table 5-33 ranks N0x emission control equipment, as  well  as the equipment
rank for  S0x> HC, CO, particulates, and fuel consumption.
5.5.3  Comparison with  Data
       The comparison in Table 5-34 of uncontrolled NOX emissions developed in this study with es-
timates of NO  emissions from  other studies is generally favorable.  Sector definition was compa-
rable In  most cases, with the  possible exception of packaged boilers and warm air furnaces.  Previous
studies did not combine all  packaged boilers but separated them by industrial, commercial, and res-
idential  application.   In addition, space heating was typically used as a sector title under which
were combined commercial and residential  boilers and warm air furnaces.  A further problem with the
package boiler sector is the difficulty in obtaining representative data from an essentially un-
monitored  equipment sector.  The lack of real  sector data requires the use of broad estimates and
results in  emission figures of similar quality when compared to the more recent inventories (NOX
Summary and GCA).   The present estimates  appear very good.
                                                5-45

-------
TABLE 5-26.  SUMMARY OF 1974 STATIONARY SOURCE NOX EMISSIONS
             BY FUEL - 1,000 Mg (Percent of Total)
Sector
Utility Boilers
Packaged Boilers3
Warm Air Furnaces
Gas Turbines
Reciprocating 1C
Engines
Industrial Process
Heating
Noncombustion
Incineration
Fugitive
Total
Coal
3,564
(31.0)
679.7
(5.9)


—
—
—
—
—
4,243.7
(37.0)
Oil
848
(7.4)
886
(7.7)
129
(1.1)
309
(1.9)
456ฐ
(3.9)
—
—
—
—
2,628
(22.1)
Gas
1156
(10.1)
779
(6.8)
190
(1.6)
133
(1.0)
1400
(12.2)
—
—
—
—
3,658
(31.7)
Total
5566
(47.6)
2344.7
(20.1)
320
(2.8)
442
(3.8)
1856
(16.2)
425.8
(3.64)
193
(1.7)
40
(0.34)
498
(4.3)
1 1 ,685
 'includes steam and hot water commercial and residential heating units
 'includes gasoline
                             5-46

-------
Industrial  Process  Combustion 3.652
             Noncombustion  1.6X
      Warm Air  Furnaces  2.7%
        Gas Turbines  3.76X
        Fugitive 4.4%
Incineration 0.3X
                        Reciprocating
                         1C Engines
                           15.9%
                       1974 Stationary Combustion Source NOX Emissions
Utility Boilers
Packaged Boilers
Warm Air Furnaces
Gas Turbines
Reciprocating 1C Engines
Industrial Process Combustion
Noncombustion
Incineration
Fugitive
TOTAL
1 ,000 Mg
5,566
2,345
321
440
1,857
425.8
193
40
498
11,685
1,000 Tons
6.122
2,383
353
484
2,040
470
212
44
548
12,861
Percent
Total
47.6
20.1
2.7
3.76
15.9
3.65
1.6
0.3
4.4
100
  Figure  5-2.   Distribution of stationary anthropogenic NOX emissions for the year 1974
               (stationary fuel combustion:   controlled NOX levels).
                                            5-47

-------
                 TABLE 5-27.  1974 SUMMARY OF AIR AND SOLID POLLUTANT EMISSION  FROM  STATIONARY FUEL

                              BURNING EQUIPMENT (1,000 Mg)

Utility Boilers
Packaged Boilers
Warm Air Furnaces
& Misc. Comb.
Gas Turbines
Reci p. 1C Engines
Process Heating
TOTAL
N0xb
5,566
2,345
321
440
1,857
425.8
10,954
SOX
16,768
6,405
232
10.5
19.6
1005
2^,440
HC
29.5
72.1
29.7
13.7
578
166
889
CO
270
175
132.6
73.4
1,824
10,039
12,511
Part Sul fates POM Dry .S1un1ced ,
cart 5ui rates KWI Ash Removai ASn Removal
5,965 231 0.01 - 1.2 6.18 24.78
4,930 146 0.2 - 67.8 4.41 1.07
39.3 6.4 0.06
17.3
21.5 a a
6,216.7 3
17,190 382 69
_a
o
i






a.
 No emission factor available



Controlled NOV
              X


ฐBased on 80 percent hopper and flyash removal by sluicing methods; 20 percent dry solid removal

-------
      TABLE 5-28.  FUEL CONSUMPTION  RANKING OF STATIONARY COMBUSTION SOURCES
        Source
        Equipment Type
                                                                      Fuel
Annual Fuel
Consumption
 1  Utility Boilers
 2  Warm A1r Furnaces
 3  Utility Boilers
 4  Package Boilers
 5  Utility Boilers
 6  Utility Boilers
 7  Package Boilers
 8  Utility Boilers
 9  Warm Air Furnaces
 10  Warm Air Furnaces
 11  Package Boilers
 12  Utility Boilers
 13  Utility Boilers
 14  Utility Boilers
 15  Refinery Heaters
 16  Package Boilers
 17  Package Boilers
 18  Warm Air Furnaces
 19  Package Boilers
 20  Package Boilers
 21  Reciprocating 1C Engines
 22  Package Boilers
 23  utility Boilers
 24  Package Boilers
 25  Warm Air Furnaces
 26  Package Boilers
27  Package Boilers
28  Package Boilers
29  Package Boilers
30  Gas Turbines
Tangential                            coal         5.130
Central                               gas          3.091
Wall-Firing                           coal         2.938
Watertube <29 MW                      gas          2.820
Wall-Firing                           gas          2.453
Cyclone  Furnace                       coal         1.588
Watertube Stoker  <29 MW               coal         1.554
Wall-Firing                           oil          1.495
Space Heater                          gas          1.451
Central                               oil          1.405
Firetube Scotch                       oil          1.391
Tangential                            oil          1.360
Tangential                            gas          1.340
Horizontally Opposed                  gas          1.258
Natural and Forced Draft              gas          1.247
Watertube >29 MW                      gas          1.058
Firetube Firebox                      oil          1.012
Misc Combustion                       gas          1.0
Firetube Scotch                       gas         0.991
Firetube Firebox                      gas         0.918
>75 kW/cyl                            gas         0.887
Res/Com Steam and Hot Water Units     oil         0.880
Horizontally Opposed                  coal        0.839
Res/Com Steam and Hot Water Units     gas         0.737
Space Heater                          oil         0.727
Watertube >29 MW                      oil         0.723
Watertube <29 MW                      oil         0.698
Firetube HRT                          oil         0.633
Firetube Stoker <29 MW                coal        0.598
4.0 MW to 15 MW                       oil         0.579
                                        5-49

-------
        TABLE 5-29.   SO  MASS EMISSION RANKING OF STATIONARY COMBUSTION  EQUIPMENT
              Sector
        Equipment Type
                                                                           Fuel
    Annual
SO  Emissions
     (Mg)
  1  -Utility Boilers
  2   Utility Boilers
  3   Utility Boilers
  4   Package Boilers
  5   Utility Boilers
  6   Package Boilers
  7   Package Boilers
  8   Package Boilers
  9   Utility Boilers
 10   Utility Boilers
 11   Package Boilers
 12   Utility Boilers
 13   Industrial  Process  Combustion
 14   Package Boilers
 15   Industrial  Process  Combustion
 16   Package Boilers
 17   Package Boilers
 18   Utility Boilers
 19   Package Boilers
 20   Industrial  Process  Combustion
 21   Warm Air Furnaces
 22   Package Boilers
 23   Package Boilers
 24   Warm Air Furnaces
 25  Utility Boilers
26  Package  Boilers
27  Industrial Process Combustion
28  Industrial Process Combustion
29  Industrial Process Combustion
30  Industrial Process Combustion
 Tangential                           coal      7,000,000
 Wall-Firing                         coal      4,031,000
 Cyclone Furnace                     coal      2,740,000
 Watertube Stoker <29 MW             coal      2,293,410
 Horizontally Opposed                coal      1,130,000
 Firetube Stoker <29 MW              coal        876,000
 Watertube Stoker >29 MW             coal        775,700
 Watertube Wall  Firing >29 MW        coal        627,200
 Wall-Firing                         oil         600,000
 Tangential                           oil         583,300
 Firetube Scotch                     oil         504,000
 Vertical  and Stoker                 coal        415,000
 Cement Kilns                         -         392,000
 Firetube Firebox                    oil         337,300
 Catalytic Cracking                   -          323,000
 Watertube <29 MW                    oil         298,000
 Watertube >29 MW                    oil         297,800
 Horizontally Opposed                oil         236,000
 Firetube HRT                        oil         207,000
 Coke Oven Underfire                  -          162,000
 Central                              oil         152,000
 Res/Com Steam and Hot Water Unit    oil         128,700
 Cast Iron                           oil         113,600
 Space  Heater                        oil          78,000
 Cyclone  Furnaces                     oil          35,000
 Res/Com  Steam and  Hot Water Unit    coal         34,450
 Steel  Sintering Machines              -           34,000
 Glass  Melters                         -           32,000
 Refinery  Heaters                     oil          21,000
Brick  Kilns                           -           16,500
                                           5-50

-------
        TABLE 5-30.   CO MASS EMISSION RANKING OF  STATIONARY COMBUSTION EQUIPMENT
              Sector
          Equipment Type
                                                                          Fuel
   Annual
CO Emissions
    (Mg)
 1  Industrial Process Combustion
 2  Industrial Process Combustion
 3  Reciprocating 1C Engines
 4  Reciprocating 1C Engines
 5  Reciprocating 1C Engines
 6  Utility Boilers
 7  Utility Boilers     ?
 8  Warm Air  Furnaces
 9  Reciprocating 1C Engines
10  Warm Air  Furnaces
11  Package Boilers
12  Utility Boilers
13  Utility Boilers
14  Package Boilers
15  Gas Turbines
16  Gas Turbines
17  Warm Air  Furnaces
18  Utility Boilers
19  Package Boilers
20  Utility Boilers
21  Warm Air  Furnaces
22   Reciprocating  1C  Engines
23 Package Boilers
24  Utility Boilers
25  Gas Turbine
26  Warm Air  Furnaces
27  Utility Boilers
28  Package Boilers
29  Gas Turbine
30  Package Boilers
Catalytic Cracking                     -       8,969,000
Steel Sintering Machines               -       1,067,000
75 kW to 75 kW/cyl                 gasoline    1,054,800
<75 kW                             gasoline      592,000
>75 kW/cyl                           gas         142,850
Wall-Firing                          coal         64,400
Tangential                           coal         58,300
Central                              oil          43,600
75 kW to 75 kW/cyl                   oil          40,000
Central                              gas          36,918
Watertube Stoker 29 MW               coal         34,130
Cyclone Furnace                      coal         29,673
Wall-Firing                          gas          28,249
Res/Com Steam and Hot Water Unit     oil          27,910
4 MW to 15 MW                        oil          27,156
4 MW to 15 MW                        gas          23,100
      •ซ
Space Heater                         oil          22,000
Wall-Firing                          oil          20,300
Res/Com Steam and Hot Water Unit     coal         19,670
Vertical and Stoker                  coal         18,400
Space Heater                         gas          17,325
>75 kW/cyl                           oil          16,642
Watertube <105 GJ/hr                 gas          14,530
Horizontally Opposed                 gas          13,461
>15 MW                               oil          12,400
Misc. Comb. & Resid.                 gas          12,000
Tangential                           oil          11,900
Watertube Stoker >29 MW             coal         11,650
>15 MW                               gas          10,340
Watertube >29 MW                     gas            9,478
                                           5-51

-------
             TABLE 5-31.   HC MASS EMISSION RANKING OF STATIONARY COMBUSTION  EQUIPMENT
              Sector
                                              Equipment Type
                                     Fuel
   Annual
HC Emissions
    (Mg)
  1  Reciprocating 1C Engines
  2  Industrial Process Combustion
  3  Reciprocating 1C Engines
  4  Package Boilers
  5  Reciprocating 1C Engines
  6  Reciprocating 1C Engines
  7  Industrial Process Combustion

  8  Warm Air Furnaces
  9  Utility Boilers
 10  Package Boilers
 11   Package Boilers
 12  Warm Air Furnaces
 13  Reciprocating 1C Engines
 14  Gas  Turbines
 15  Warm Air Furnaces
 16   Utility Boilers
 17   Package Boilers
 18   Industrial Process Combustion

 19   Package  Boilers
 20   Gas  Turbines
 21   Warm Air Furnaces
 22   Package Boilers
 23   Utility Boilers
 24   Package Boilers
25   Gas Turbines
26   Package Boilers
27  Utility Boilers
28  Utility Boilers
29  Package Boilers
30  Gas Turbines
 >75 kW/cyl                          gas.       483,000
 Catalytic Cracking                   -        144,500
 75 kW to 75 kW/cyl                  oil        48,461
 Watertube Stoker <29 MW             coal       27,660
 75 kW to 75 kW/cyl                  gas        23,900
 <75 kW                              gas        19,647
 Refinery Heaters Forced             gas        16,089
 & Natural Draft
 Central                              gas        10,548
 Cyclone  Furnace                     coal        10,393
 Firetube Stoker                     coal        10,130
 Res/Com  Steam and Hot Water Unit    coal         8,238
 Central                              oil          6,593
 >75 kW/cyl                           oil          6,127
 4 MW to  15  MW                       oil          5,730
 Space Heater                         gas          4,950
 Tangential                           coal         4,800
 Res/Com  Steam and Hot Water Unit    oil          4,542
 Refinery Heaters  Natural             oil          4,426
 &  Forced Draft
 Watertube >29 MW                     gas          4,126
 4  MW  to  15  MW                       gas          3,840
 Space  Heater                         oil          3,411
 Watertube <29  MW                     gas          2,870
 Wall-Firing                         coal         2,610
 Res/Com  Steam  and  Hot Water Unit    gas          2,506
 >15 MW                               oil          2,251
 Watertube >29  MW                     oil          2,157
Wall-Firing                          oil          2,150
 Wall-Firing                          gas          2,110
Watertube Stoker  >29  MW              coal         2,004
>15 MW                               gas          1,810
                                               5-52

-------
     TABLE  5-32.   PARTICULATE MASS EMISSION RANKING OF  STATIONARY  COMBUSTION  EQUIPMENT
           Sector
                     Equipment Type
                                                                          Fuel
                                                 Annual
                                               Partlculate
                                             Emissions (Mg)
 1  Package Boilers
 2  Utility Boilers
 3  Industrial  Process
 4  Industrial  Process
 5  Utility Boilers
 6  Package Boilers
 7  Industrial  Process
 8  Utility Boilers
 9  Package Boilers
 10  Industrial  Process
 11  Package Boilers
 12  Utility Boilers
 13  Industrial  Process
 14  Utility Boilers
 15  Industrial  Process
 16  Industrial  Process
 17  Package Boilers
 18  Package Boilers
 19  Utility Boilers
 20  Utility Boilers
 21  Package Boilers
 22  Industrial  Process
Combustion
Combustion
Combustion


Combustion


Combustion

Combustion
Combustion
Combustion
23  Package Boilers
24  Package Boilers
25  Industrial Process Combustion
26  Warm A1r Furnaces
27  Reciprocating 1C Engines
28  Utility Boilers
29  Package Boilers
30  Warm Air Furnaces
31  Industrial Process Combustion
Watertube Stoker <29 MW              coal      3,252,000
Tangential                           C0al      3,178,000
Coke Cften Underflre                   -        2,149,000
Brick Kilns                           -        2,052,700
Wall-Fired                           coal      1,734,000
Flretube Stoker                      coal      1,202,000
Cement Kilns                          -       1,126,000
Horizontal Opposed Wall              coal        499,000
Watertube Stoker >29 MW              coal        488,600
Steel Sintering Machines              -         485,000
Watertube, Wall Fired >29 MW         coal        436,400
Vertical and Stoker                  coal        263,800
Open Hearth Furnace                   -         193,600
Cyclone Furnace                      coal        193,000
Catalytic Cracking                    -          158,000
Steel Sintering Machines              -           48,500
Firetube Scotch                      oil          40,210
Firetube HRT                         oil          31,740
Wall-Firing                          oil          31,100
Tangential                           oil          31,100
Firetube Firebox                     oil          26,750
Forced & Natural Draft Refinery      oil          26,429
Heaters
Watertube, Wall-Fired >29 MW         oil          24,320
Watertube <29 MW                     oil          22,950
Glass Melters                         -           15,210
Central                              gas          13,185
75 kW to 75 kW/cyl                   oil          13,132
Horizontally Opposed                 oil          12,852
Res/Com Steam and Hot Water Unit     oil          12,500
Central                              oil          10,789
Forced & Natural Draft Refinery      gas          10,726
Heaters
                                              5-53

-------
TABLE 5-33.  NOX MASS EMISSION RANKING OF
STATIONARY COMBUSTION EQUIPMENT AND CRITERIA  POLLUTANT AND  FUEL  USE  CROSS  RANKING
Sector
1 Utility Boilers
2 Reciprocating 1C
Engines
3 Utility Boilers
4 Utility Boilers
5 Utility Boilers
6 Utility Boilers
7 Utility Boilers
8 Reciprocating 1C
Engines
9 Packaged Boilers
10 Packaged Boilers
11 Utility Boilers
12 Packaged Boilers
13 Utility Boilers
14 Packaged Boilers
15 Packaged Boilers
16 Utility Boilers
17 Packaged Boilers
18 Industrial
Process Comb.
19 Utility Boilers
20 Packaged Boilers
Equipment Type
Tangential
>75 kW/cyl
Wall Firing
Cyclone Furnace
Wall Firing
Wall Firing
Horizontally Opposed
75 kW to 75 kW/cyl
Watertube >29 MW
Watertube Stoker <29 MW
Horizontally Opposed
Watertube >29 MW
Tangential
Firetube Scotch
Watertube <29 MW
Horizontally Opposed
Watertube <29 MW
Forced & Natural Draft
Refinery Heaters
Tangential
Firetube Firebox
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)
13.1
24.8
33.5
41.5
48.4
52.8
56.3
59.4
62.3
64.9
67.4
69.5
71.5
73.4
75.0
76.7
78.2
79.6
80.9
82.2
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
>30
>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

-------
TABLE 5-33.  Concluded
Sector
21 Packaged Boilers
22 Gas Turbines
23 Packaged Boilers
24 Warm Air Furnaces
25 Packaged Boilers
26 Packaged Boilers
27 Gas Turbines
28 Reciprocating 1C
Engines
29 Industrial
Process Comb.
30 Utility Boilers
Equipment Type
Watertube Stoker
4 to 15 MW
Watertube <29 MW
Central
Firetube Stoker <29 MW
Firetube Scotch
>15 MW
>75 kW/cyl
Forced & Natural Draft
Refinery Heaters
Vertical and Stoker
Fuel
Coal
Oil
Oil
Gas
Coal
Gas
Oil
Oil
Gas
Coal
Annual NOX
Emissions
(Mg)
125,350
118,500
116,430
106,300
102,040
98,010
97,400
94,000
92,608
90,900
Cumulative
(Mg)
8,996,520
9,115,020
9,231,450
9,337,750
9,439,790
9,537,800
9,635,200
9,729,200
9,821,808
9,912,708
Cumulative
(Percent)
83.4
84.5
85.6
86.5
87.5
88.4
89.3
90.2
91.0
91.9
Fuel
Rank
>30
30
27
2
29
19
>30
>30
15
>30
SOX
Rank
7
>30
15
>30
6
>30
>30
>30
>30
12
CO
Rank
28
15
>30
10
>30
>30
>30
22
>30
>20
HC
Rank
29
14
>30
8
10
>30
30
13
7
>30
Part
Rank
8
>30
23
25
6
>30
>30
>30
30
>10
                                                                                            CM
                                                                                            CO

-------
                        TABLE 5-34.  COMPARISON OF STATIONARY UNCONTROLLED NOV  EMISSIONS  (1,000 Mg)
                                                                             A
Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces
Gas Turbines
Reciprocating 1C Engines
Process Heating
Noncombustion
Incineration
Other
Total
ESSOa
(1968)
3,490
3,463
909A
B
1,909C
B
218
B
D
9,989
AP-115b
(1970)
4,282
4,327
51 8A
E
E
182
—
73
D
9,382
OAQPSC
(1971)
4,891
4,078
533A
E
E
B
182
36

9,720
N0xd
Summary
(1972)
5,155
2,245
427A
264
1,990
355
135
36
D
10,607
GCAe OAQPSf
(1973) (1974)
5,909
2,009
291A
446
1,491



10,000


550F
15 91G
91
10,161 10,732
Current
(1974)
5,741
2,345
320.6
440
1,857.2
425.8
193
40
—
11,363
I
Ul
          A —Also includes steam and hot water units
          B — Included in packaged boilers
          C - Pipeline and gas plants only
          D — Not included in data
          E — Included in utility and packaged boilers
              depending on use
          F - Includes all petroleum industry emissions
          G — Includes all solid waste disposal
 Reference 5-76

 Reference 5-77

"Reference 5-74

 Reference 5-78
"Reference 5-6
 Reference 5-79

-------
      Table 5-35 compares the energy consumption figures developed in this study to those of other
studies.  Again the overall comparison is  favorable, although direct comparisons cannot be made in
some cases because of differences  in  sector definition.
      Table 5-36 compares criteria pollutant emissions developed in this study to those of OAQPS and
NEDS.   In general, comparisons are favorable.  The only significant difference is in the CO estimate.
Examination of the CO estimates  in this report indicates that nearly 24 percent of these emissions
result from gasoline-fueled reciprocating  1C engines of less than <75 kW (15 hp), and about 41  per-
cent of the total are from medium  capacity gasoline engines.  Because of the nature of the 1C engine
population - especially  units of this capacity range - comprehensive reporting of real data is  diffi-
cult to achieve.  This may explain the discrepancy between an inventory compiled partially through
estimates of fuel consumption and  generation and an inventory relying essentially on reported data.

5.5.4   Conclusion
       The  current inventory  of  stationary combustion-related pollutants concentrated primarily on
the criteria air pollutants.  Estimates of nationwide SO  and particulate emissions reflected present
control implementation and regulations; NO  emission estimates were given in both the uncontrolled
and controlled states.   Mass  emission rankings of stationary combustion equipment for the criteria
pollutants  indicate  the  relative importance of NOV sources with respect to SO , CO, HC, and partic-
                                                 X                           A
ulate  emissions.  In general, the  criteria pollutant inventory is considered to be of relatively high
quality in  terms of  emission  totals.   In terms of sector emissions, however, the quality ranges from
good for utility boilers; fair to  good for the warm air furnace, gas turbine, and reciprocating 1C
engine sectors, to poor  for the  package boiler and industrial process heating sectors.  Secondary
emphasis was placed  on all other multimedia pollutants.  The preliminary estimates of sulfates,
ROMs,  and trace element  emissions  are poor in quality as a result of very sparse and inconsistent
data.   Liquid and solid  stream combustion-related pollutant (trace elements) emissions are also of
very poor quality, partly due to the  unavailability of exact fuel composition monitoring.   Several
comnents can be made about the quality of  the inventory or pollutant data:
       •   The packaged  boiler sector is the most difficult to quantify in terms of fuel consumption,
           equipment emission factors and  emissions.  This is due to the large capacity range of the
           equipment sector, 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 specific fuel and fuel consumption data combined with
                                                5-57

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                          TABLE 5-35.   COMPARISON OF STATIONARY SOURCE ANNUAL FUEL
                                       CONSUMPTION ESTIMATES (1015kJ)
in
S
Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces
Gas Turbines
Reciprocating 1C Engines
Total
OAQPSa
(1971)
14.81
30.66A
—
, —
—
45.47
AP-115b
(1969)
12.81
29.20A
—
—
—
42.01
NOXC
Summary
(1972)
15.59
16.81
10.438
0.939
1.33
45.1
6CAd
(1973)
15.61
13.42
8.36B
1.42
2.12
40.93
Current
(1974)
19.22
15.573B
6.674
1.525
1.240
44.234
              A - Includes 1C engines and warm air  furnaces
              B — Includes steam and hot water units

              Reference 5-74
              Reference 5-77
              Reference 5-78
               Reference 5-6

-------
TABLE 5-36.  COMPARISON OF CURRENT STATIONARY EMISSION ESTIMATES
             DATA WITH PREVIOUS STUDIES (1,000 Mg)
Pollutant
NOX
S0x
HC
CO
Parti culates
OAQPSa
(1974)
12.36A
22.918
1.55B
1.27B
8.00B
NEDSb
(1976)
11.79A
24.35B
0.46B
1.29B
6.47B
OAQPSC
(1974)
10.45A
21 . 36A
1.7B
0.9B
5.9
Current
(1974)
11.36AD
23.44C
0.72C
2.48C
10.97C
      A - Total minus transportation
      B — Stationary fuel combustion only
      C — Fuel combustion minus process heating
      D - Controlled NOX estimates


      Reference 5-80

      Reference 5-81

      Reference 5-79
                                5-59

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           the large number of process heating applications, the variation of equipment design and
           the variation in combustion practices from industry to industry.
       •   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 ranges of emission factors  and emission rates.   Extensive testing
           is needed in all sectors.
       •   Transient or nonconventional  operations and their effect on multimedia emission rate were
           treated only superficially.  Test data were essentially unavailable except in the space
           heating applications where some testing has occurred.   Test data are needed before further
           quantification can proceed.
The compilation of this inventory indicated many areas where further data are  necessary to improve
the quality of this and the subsequent projections which will  result from this inventory:
       •   Utility Boilers
           -   An  extensive geographic population distribution  by equipment design  and fuel
           -   Further data on  noncriteria pollutant  emission  factors  (sulfate,  POM and POM  sub-
               categories, and  trace  elements)
           -   Comprehensive  monitoring  of the trace  metal  content  of  fuels
           —   More conclusive  data on the speciation of trace  element emissions
           -   Comprehensive  testing  of  liquid and solid effluent streams  to identify and  quantify
               combustion-related pollutants
           -   Test data  on the  effect of  nonstandard  operation on  the  composition  of multimedia
               effluent streams
      •    Package  Boilers
           -   Extensive  inventories of population by equipment design, fuel capabilities and con-
               sumption,  capacity, location, and  application
          -   Extensive emission characteristics  of the majority of equipment design  presently
              available
          -   Test data on the effect of nonstandard operation on multimedia effluent stream
              composition
                                                5-60

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      •   Warm Air Furnaces
          -   Data on noncrlterla pollutant formation characteristics
          -   More comprehensive emission factor data for the range of available designs
          -   Extensive data on the effect of cyclic operation on effluent stream composition
      •   Gas Turbines
          -   Extensive data on simple, regenerative, and combined cycle population as a function
              of capacity, fuel, application, and location
          -   Test data on noncriteria pollutant formation characteristics
      i   Reciprocating 1C Engines
          -   Extensive data on equipment distribution by design, fuel, application, and location
          -   Data on noncriteria pollutant formation characteristics
      •   Industrial Process Combustion
          -   Comprehensive inventorying of process combustion sources in terms of function, capacity,
              fuel, and equipment design
          -   Data on process fuel consumption for use with emission factors
          -   Data on emission characteristics with process gas fuels
          -   Data on noncriteria pollutant formation characteristics
      Subsequent updates to the inventory will improve the estimates of noncriteria pollutants  and
liquid and solid effluents pending new test results.  This inventory will  then act as a basis for a
comprehensive assessment of the pollution potential of stationary sources  of N0x<  This will  be
accomplished by integrating two-intermediate tasks:  (1) a fuel use and emission projection  to the
year 2000 and (2) the development of regional and AQCR emission inventories.  The assessment of  pol-
lution potential will be used in assessing baseline and controlled environmental impacts of  N0x  con-
trols in Task B5.
                                                5-61

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                                     REFERENCES FOR SECTION 5


5-1.   Dupree, W. G., and J.  S. Corsentino, "Energy Through the Year 2000 (Revised)," U.S. Bureau
       of Mines, December 1975.

5-2.   Mezey, E. J., et al.,  "Fuel Contaminants, Volume I, Chemistry," EPA 600/2-76-177a,
       NTIS-PB 256 020/AS, Battelle-Columbus Laboratories, July 1976.

5-3.   FPC News, Vol. 8, No.  13, March 28, 1975.

5-4.   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.

5-5.   "Coal-Fired Power Plant Trace Element Study -A Three-Station Comparison," Radian Corpora-
       tion, EPA Region VIII, September 1975.

5-6.   Surprenant, Norman, et al., "Preliminary Emissions Assessment of Conventional Stationary
       Combustion Systems, Volume II," EPA 600/2-76-046b, NTIS-PB 252 175/AS, March 1976.

5-7.   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.

5-8.   Magee, E. M., et al.,  "Potential Pollutants in Fossil Fuels," EPA-R2-73-249, NTIS-PB 225 039/
       7AS, June 1973.

5-9.   Vitez, B., "Trace Elements in Flue Gases and Air Quality Criteria," Vol.  80, No.  1,
       Power Engineering. January 1976.

5-10.  FPC News, Vol. 8, No.  23, June 6, 1975.

5-11.  "Applicability of NOX  Combustion Modifications to Cyclone Boilers (Furnaces)," Monsanto
       Research Corporation,  (Draft) 1976.

5-12.  "Standard Support and  Environmental Impact Statement for Standards of Performance:
       Lignite-Fired Steam Generators," (Draft), A. D. Little, Inc., Office of Air Quality Planning
       and Standards, March 1975.

5-13.  Smith, D. W., et al.,  "Electric Utilities and Equipment Manufacturers' Factors in Acceptance
       of Advanced Energy," A.D. Little, Inc.,  ADL-77771, September 1975.

5-14.  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.

5-15.  "Minerals Yearbook 1973-Metals, Minerals, and Fuels, Volume I," U.S. Bureau of Mines.

5-16.  Power Magazine, Plant  Design Issues, 1971 through 1976.

5-17.  FPC News, Vol. 9, No.  3, January 16, 1976.

5-18.  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.

5-19.  "Current Industrial Reports, Steel  Power Boilers," 1968 through 1975, U.S. Department of
       Commerce, Bureau of the Census.

5-20.  Hopper, T. G., et al., "Impact of New Source Performance Standards of 1985 National
       Emissions from Stationary Sources," Volume I, Final Report, The Research Corporation of
       New England, October 1975.

5-21.  "Statistical  Abstract  of the United States 1975," (86th Annual Edition), U.S. Department
       of Commerce, Bureau of the Census,  1975.

5-22.  Durkee, K. R., et al.,  "Standards Support and Environmental Impact Statement -An  Investiga-
       tion of the Best Systems of Emission Reduction for Stationary Gas Turbines,"  EPA,  July 1976.
                                               5-62

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5-23.  "Gas Turbine Electric Plant Construction  Cost and Annual  Production Expenses, First Annual
      Publication - 1972," FPC S-240,  Federal Power Commission, 1972.

5-24.  "1975 Sawyer's Gas Turbine Catalog,"  Gas  Turbine Publications, Incorporated,  Stamford,
      Connecticut, 1975.

5-25.  "Gas Turbines in U.S. Electrical  Utilities,"  Gas Turbine  International.  March through
      June 1976.

5-26.  Offen, G. R., et al., "Standard  Support Document and Environmental  Impact Statement -
      Reciprocating Internal Combustion Engines," Aerotherm Project 7152, Acurex Corporation,
      November 1975.

5-27.  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.

5-28.  Ketels, P. A., et  al., "A Survey of  Emissions Control and Combustion Equipment Data in
      Industrial Process Heating,"  Institute of Gas Technology, June 1976.

5-29.  Klett, M. G., and  J. B. Galeski, "Flare Systems Study," Lockheed Missiles and Space Co.,
      Inc., EPA 600/2-76-079, NTIS-PB  251  664/AS, March 1976.

5-30.  Personal communication with  K. Hunter of  KVB, Inc.,  principal contributor to  American
      Petroleum Institute Study scheduled  for release in September 1977.

5-31.  "Compilation of Air Pollutant Emission Factors (Second Edition)," U.S.  Environmental Pro-
      tection Agency, AP-42, April  1973.

5-32.  "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.

5-33.  "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.

5-34.   "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.

5-35.   "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.

5-36.  Bartok, W., et al.,""Field  Testing:   Application of Combustion Modifications  to Control NOX
      Emissions for Utility Boilers,"  Exxon Research and Engineering Company,  EPA 650/2-74-066,
      NTIS-PB 237 344/AS, June  1974.

5-37.  Bartok, W., et al., "Systematic  Field Study of NOX Emission Control Methods for Utility
      Boilers," 6RU.4GNOS.71, Esso  Research and Engineering, Office of Air Programs, Environmental
      Protection Agency, December  1971.

5-38.  Selker, Ambrose 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.

5-39.  Selker, Ambrose P., "Program  for Reduction of NOX from Tangential Coal-Fired  Boilers,
      Phase Ha," Combustion Engineering,  Inc., EPA 650/2-73-005b, NTIS-PB 246 889/AS,  August 1975.

5-40.  McCann, C., et al., "Combustion  Control of Pollutants from Multiburner  Coal-Fired Systems,"
      U.S. Bureau of Mines, EPA 650/2-74-038, NTIS-PB 233  037/AS, May 1974.

5-41.  "The Proceedings of the NOX Control  Technology Seminar,"  San Francisco,  California,
      February 1976, Electric Power Research Institute, SR-39.

5-42.  "Sources of Polynuclear Hydrocarbons  in the Atmosphere,"  U.S. Department of Health,
      Education and Welfare, AP-33.
                                                5-63"

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 5-43.  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 Environ-
        ment, October 1976, Cincinnati, Ohio.

 5-44.  Klein, David H. , et al., "Pathways of Thirty-Seven Trace Elements Through Coal-Fired Power
        Plant," Environmental Science and Technology.  Vol. 9, No. 10, pp. 973-979, October 1975.

 5-45.  "Trace Elements in a Combustion System," Battelle-Columbus Laboratories, EPRI Final Report
        122-1, January 1975.

 5-46.  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, Vol.  9, No.  7,
        pp. 643-647.

 5-47.  Davison, Richard L., et al.,  "Trace Elements in Fly Ash  -Dependence of Concentration on
        Particle Size," Environmental  Science and Technology, Vol.  9, No. 13, pp.  1107-1113,
        December 1974.

 5-48.  Kaakinen, J. W.,  et al., "Trace Element  Behavior in Coal-Fired Power Plant,"  Environmental
        Science and Technology, Vol.  9, No.  9, pp.  862-869, September 1975.                   :

 5-49.  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.

 5-50.  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.

 5-51.  Cato, G. A., "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.

 5-52.  Barrett, R.  E., et  al., "Field Investigation of Emissions from Combustion Equipment for
        Space Heating," Battelle-Columbus  Laboratories,  EPA-R2-73-084a,  NTIS-PB  223 148, June 1973.

 5-53.  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.

 5-54.   Hall,  Robert 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.

 5-55.   Giammar, R.  D. , et al.,  "The Effect of Additives  in Reducing Particulate Emissions from
        Residual Oil  Combustion," ASME 75-wa/CD-7.

 5-56.   Giammar, 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.
5"57'  FD^ccn'/^;;; ™,a1;,4TrSฃudฃ of Mr Pollutant Emissions from Residential Heating Systems,"
       EPA-650/2-74-003, NTIS-PB 229 697/AS, January 1974.

5-58.  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.

5-59.  Of fen, G. R. , et al . , "Control of Particulate Matter from Oil Burners and Boilers,"
       Acurex Corporation, EPA -450/3-76-005, April 1976.

5-60.  Hare, Charles T. , et  al., "Exhaust Emissions from Uncontrolled Vehicles and Related Equip-
       ment Using Internal Combustion Engines, Part 6:   Gas Turbine Electric Utility Power Plants,"
       Southwest Research Institute, Environmental Protection Agency, February 1974.

5-61.  "Supplement No.  4 for Compilation of Air Pollutant Emission Factors (Second Edition),"
       u.b   Environmental  Protection Agency, Office of  Air and Waste Management, Office of Air
       Quality Planning and  Standards,  January 1975.
                                                5-64

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5-62.  Dietzmann, H. E., and  K. J.  Springer,  "Exhaust Emissions from Piston and Gas Turbine
      Engines Used 1n Natural Gas  Transmission," Southwest Research Institute, AR-923, January


5-63.  Hare, C. T., and K. J.  Springer,  "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.

5-64.  Richards, J., and R. Gerstle, "Stationary Source Control Aspects of Ambient Sulfates:
      A Data-Based Assessment,"  (unpublished draft report) EPA Contract No. 68-02-1321, PedCo
      Environmental Specialists,  Inc.,  February 1976.

5-65.  "Hydrocarbon Pollutant Systems Study,  Volume 1 -Stationary Sources, Effects, and Control,"
      MSA  Research Corporation,  NTIS-PB 219  073, October 1972.

5-66.  Information from National  Emissions Data System (NEDS), August 28, 1973.

5-67.  Information from National  Emissions Data System (NEDS), May 15, 1974.

5-68.  Personal  communication with Robert D.  Maclean, Portland Cement Manufacturer's Association,
      January 1977.

5-69.  "Flue Gas  Desulfurization  Survey  July-August 1976," PedCo Environmental, Cincinnati, Ohio.

5-70.   "The West Scrubber  Newsletter," No. 2-28, The Mcllvaine Company, Northbrook, Illinois,
      October 31,  1976.

5-71.  Robinson,  E., and R. C.  Robbins,  Journal of the Air Pollution Control Association, pp.  20
       and  303,  1970.

5-72.  Skinner,  K. J.,  "Nitrogen  Fixation," Chemical and Engineering News, October 1976.

5-73.   "Air Quality  and Stationary Source Emissions Control," A Report by the Commission on Natural
       Resources, National Academy of Sciences, National Academy of Engineering, and National
       Research Council, Serial  94-4, March 1975.

5-74.   "OAQPS Data  File of Nationwide Emissions, 1971," Office of Air Quality Planning and Standards,
       EPA, May 1973.

5-75.   "Annual Survey  of Manufacturers 1974 - Fuels and Electric Energy Consumed," U.S. Department
       of Commerce,  Bureau of the Census.

5-76.   Bartok, W., et  al., "Systems Study of Nitrogen Oxide Control Methods for Stationary Sources,
       Volume II," prepared for National Air Pollution Control Administration, NTIS-PB 192 789,
       Esso Research and Engineering, 1969.

5-77.   Cavender,  J.  H., et al.,  "Nationwide Air Pollutant Emission Trends 1940-1970," Publication
      No.  AP-115, EPA, January  1973.

5-78.  Shimizu,  A. B., et  al., "NOX Combustion Control Methods and Costs for Stationary Sources;
      Summary Study," EPA-600/2-75-046, NTIS-PB 246 750/AS, September 1975.

5-79.   "Monitoring and Air Quality Trends Report, 1974," EPA-450/10-76-001 EPA Office of Air Quality
      Planning  and  Standards, February  1976.

5-80.  Personal  communication with C. Masser, National Emissions Data System (NEDS), October 1976.

5-81.   Information from National  Emissions Data System (NEDS), October 26, 1976.
                                                5-65

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                                             SECTION 6
                     EVALUATION OF  INCREMENTAL  EMISSIONS DUE TO NOY CONTROLS
                                                                   A
      Modification of the combustion  process for N0x control can also potentially change emissions
of other combustion-generated pollutants.   If unchecked,  these potential  changes,  referred to as in-
cremental emissions, may have an adverse effect  on the environment, the unit thermal  efficiency, or
the overall system performance.  Since the  incremental emissions are sensitive to  the same combustion
conditions as NOX, they may, with proper engineering, be  held to acceptable levels, or even reduced,
during control development so that the net  environmental  benefit is maximized.  In fact,  control of
incremental emissions of carbon monoxide, hydrocarbons and smoke has been a key part of all past NO
control development programs.  Recent  control development gives increased attention to other poten-
tial pollutants such as sulfates, organics, and  trace metals.  The NO  E/A is quantifying incremental
emission rates and impacts to enable subsequent  control development to constrain any  adverse impacts
of NO controls to acceptable levels.
      This section gives a preliminary evaluation of the demonstrated and potential  effects of
combustion modification NO  controls on incremental  emissions.   The results will serve to scope  and
guide priorities for subsequent NO   E/A efforts  in incremental  emission data compilation, impact
characterization, and control process  studies.   Attention is  focused on flue gas emissions from  the
major sources using near-term NO  controls,  since these situations are the most important in the
program and are the only ones for which any significant data  exist.  Subsequent effort will consider
liquid and solid effluents, minor sources and alternate or advanced N0x controls.   Also,  the dis-
cussion here is concerned only with  estimating incremental  emission rates without  regard  to poten-
tial impact.  Ultimately, the significance  of the incremental emission depends on  the baseline un-
controlled pollutant emission rates  (discussed in Section 5)  and the maximum acceptable ambient  pol-
lutant concentration (discussed in Section  3) as well  as  other factors such as pollutant transport
and transformation.  Preliminary screening  of potential incremental impacts due to N0x controls,
considering these factors, is addressed in  Section 7.3.
      The preliminary evaluation in this section first screens the.matrix of control techniques/
Pollutant pairs to identify potential  incremental  emission problems.  The currently available data
                                                6-1

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on the effects of NO  controls on residual emissions are then  summarized  and  discussed in  terms  of
                    X
verifying  preliminary expectations.  Areas of insufficient data are  identified  and the relative  im-
portance of obtaining requisite data is assessed.  Finally, the areas where future N0x E/A efforts
should be  concentrated are identified and ranked in order of importance.
       In  the discussion that follows, Section 6.1 describes the preliminary  control  technique/
pollutant  screening task.  Here changes in the levels of incremental emissions  are qualitatively
linked to  the combustion conditions resulting from the use of  specific N0x controls.   Areas of poten-
tial  concern, in which an emission increase can be expected, are also noted.  Section  6.2  presents
and evaluates the available data documenting emission changes  on a pollutant-by-pollutant  basis.
Postulated areas of concern are substantiated, where possible, and areas of insufficient data are
noted.  Where insufficient data exist, further discussions of  appropriate pollutant formation mech-
anisms and their implications are presented.
       Based on Sections 6.1 and 6.2, Section 6.3 groups control technique/pollutant pairs into
areas of:
       •   High potential emissions impact, where well-documented data indicate that a particular
           control causes significant increases in emissions of a certain pollutant
       •   Intermediate potential emissions impact, where basic principles indicate that a particu-
           lar control is expected to increase a given emission, but supporting data are missing
       •   Low potential emissions impact, where the data show that emissions are  unaffected or
           decreased when using a given control, or when basic formation mechanisms clearly indicate
           the same conclusion
Areas of high and intermediate potential impact are prioritized for future E/A  consideration and
elucidation.  Areas of low potential impact will be accorded lower priority in  subsequent  E/A efforts.

6.1    PRELIMINARY SCREENING
       To  evaluate incremental emissions due to applying combustion modification NO  controls, it
is helpful  to first outline the areas where expected adverse effects on emission levels may occur.
Such an approach requires linking the N0x control-induced combustion conditions to the expected
changes in  emission levels  through pollutant formation mechanisms.  This is accomplished in Sec-
tion 6.1.1  which addresses  combustion modifications applied to boilers; in Section 6.1.2 which treats
combustion  N0x controls  applicable to stationary internal combustion (1C) engines  and  gas  turbines;
and in Section 6.1.3  which  reviews the data for warm air furnaces.  The discussion  is  separated in
                                                6-2

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this manner because the specific  methods used to achieve low-NOx formation conditions differ sig-
nificantly between these equipment classes.   This is true even though the desired low-NO  combustion
conditions may be similar from  equipment class to class.
       Each of the following  subsections:
       i   Lists the set of N0x combustion controls appropriate to the given equipment class
       •   Lists the altered  combustion conditions resulting from imposing each control
       •   Postulates  the effect  of each combustion condition on the level and speciation of each
          combustion-generated pollutant considered
       •   Evaluates the overall  effect of each combustion modification on the level and speciation
          of each pollutant  by summing individual combustion condition contributions
       •   Identifies  combustion  control/pollutant pairs in which the emission level is  likely to
          increase with use  of NO  control
 This preliminary screening  represents informed speculation based on what is known about  how combus-
 tion NO  controls act, and  how  combustion-generated pollutants are formed.  The primary  purpose is
       A                     t,
 to screen the matrix of control/pollutant pairs for expected adverse emission effects.  Thus, some
 guidance  for  future E/A study can be formulated even in the absence of supporting data.

 6.1.1  Boilers
       The commonly suggested near-term combustion modification N0x controls for boilers were sum-
 marized in Section  4.2.   Applying any one of these modifications will  impose some number of altered
 combustion conditions from the set summarized in Table 6-1.  Table 6-1 also lists the postulated
 effects each resulting combustion condition will have on incremental emissions of carbon monoxide,
 vapor phase hydrocarbon, sulfate, particulates, other organic compounds, and trace metals.
       In this  discussion, vapor phase hydrocarbon (HC) emissions are defined as primary emissions
 of aliphatic, oxygenated, and low molecular weight aromatic organic compounds which exist in the
 vapor phase at  flue gas  temperatures.  Organic emissions are defined as primary emissions of higher
 molecular weight  aromatic compounds which exist largely as a condensed (liquid or solid) phase at flue
 gas temperatures.   Thus, organic emissions will largely consist of polycyclic organic matter (POM)  or
 polycyclic aromatic hydrocarbons (PAH), including polychlorinated and polybrominated biphenyls
 (PCB and PBB) if  they exist.   Vapor phase hydrocarbons include virtually all other emitted organic
 compounds including alkanes,  alkenes, aldehydes, carboxylic acids, and substituted benzenes  (e.g.,
                                                6-3

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TABLE 6-1.  POSTULATED EFFECT OF COMBUSTION CONDITIONS ON FLUE GAS EMISSIONS  FROM BOILERS
Combustion
Condition
Reduced local 0~
concentration
Reduced peak
flame temperature
Increased convec-
tion zone temper-
atures
Decreased gas
velocity
Increased gas
velocity
Increased
residence time
Decreased
residence time
Delayed fuel-
air mixing; off-
stoichiometric
combustion
More turbulent
flame
Increased
local H20
concentration
Increased local
NH3 concentration
CO
Increased
No effect
No effect
No effect
No effect
Possibly decreased
Possibly increased
Possibly increased
Probably no effect
No effect
No effect
Vapor Phase HC
Increased
No effect
No effect
No effect
No effect
Possibly decreased
Possibly increased
Possibly increased
Possibly decreased
No effect
No effect
Sul fate
Decreased
Possibly decreased because of decreased
catalyst metal volatilization and sub-
sequent internal condensation (despite
S03 being favored at low temperatures)
Possibly increased because of increased
convection zone catalyst deposition
Increased because of increased convec-
tion zone catalyst deposition
Decreased because of less catalyst
condensation and deposition in boiler
Possibly increased because of greater
chance for reaction
Possibly decreased
Possibly decreased because of less
potential for SOp oxidation
Possibly increased because of more
intimate SOg, 02, catalyst particle
contact
Possibly increased
Possibly increased through near plume
solution catalysis
Organics
Possibly increased because of poorer com-
bustion efficiency and increased carbona-
ceous particle formation
Possibly increased because of less pyrol-
ysis and subsequent oxidation
Probably no effect
Decreased because of decreased particle
emissions
Increased because of increased particle
emissions
Possibly decreased because of greater
chance for carbon burnout
Possibly increased
Possibly increased because of greater
carbonaceous particle formation
Possibly decreased because of less soot
particle formation
Possibly decreased because of decreased
particle emissions
Possibly decreased because of decreased
particle emissions
                                                                           (Continued on page 6-5)

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                                                              TABLE 6-1.   Continued
  Combustion
   Condition
                                             Particulate
                          Size  Distribution
                                       Mass  Emissions
                                                                                                            Trace Metals
                                        Segregating
                                                                                                                            Nonsegregating
Reduced local CL
concentration
Possible trend to larger
sizes because of less
carbon burnout
Unknown effect:  possibly in-
creased soot emissions be-
cause of greater unburned
carbon particles.  Possibly
reduced because of increased
bottom ash and hopper fall-
out, and greater particle
control efficiency for
larger particles.
Possibly increased because
metals remain vaporized
(don't form less volatile
oxides) longer, resulting
in greater concentration in
smaller particles
 Possibly  reduced because of
 reduced overall  particle
 emissions (larger particles
 formed)
Reduced peak
flame temperature
Probably no effect
Possibly increased because of
reduced slagging and bottom
ash fallout
Possibly reduced with parti-
cle controls because of de-
creased volatilization and
redistribution to small
particles
 Possibly  increased because
 of  reduced  bottom ash
 fallout
Increased
convection zone
temperatures
Probably no effect
Possibly reduced because of
increased convection zone
fouling
Possibly increased because
metals remain vaporized
longer and can segregate to
small particles
Possibly reduced because  of
increased convection  zone
fouling
Decreased gas
velocity
   No effect
Decreased under normal  opera-
tion because of greater
particle deposition and
hopper ash fallout
Decreased because of increased
convection zone deposition
Decreased because of in-
creased convection  zone
deposition
Increased gas
velocity
   No effect
Increased because of less
convection zone particle
deposition and hopper ash
fallout
Increased because of increased
particle emissions
Increased because of in-
creased particle emissions
Increased
residence time
Possible trend to smaller
particles because of poten-
tially increased carbon
burnout
Possibly decreased because
of potentially increased
carbon burnout
Probably no effect
Probably no effect
Decreased
residence time
Possible trend to larger
particles
Possibly increased because
of potentially decreased
carbon burnout
Probably no effect
Probably no effect
                                                                                                                   (Continued on page 6-6)

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TABLE 6-1.  Concluded
Combustion
Condition
Delayed fuel-
air mixing; off-
stoichiometric
combustion
More turbulent
flame
Increased local
H20 concentra-
tion
Increased local
NH? concentra-
tion
Particulate
Size Distribution
Trend to larger particles
Trend to smaller particles
Probably no effect
Trend to smaller particles
(NH4HS04 aerosol)
Mass Emissions
Possibly increased because
of greater soot formation
Possibly decreased because
of decreased soot formation
Possibly decreased with
ESPs because of resistivity
conditioning
Possibly decreased with
ESPs because of NH, (NH4HS04)
conditioning effects
Trace Metals
Segregating
Possibly decreased because
of overall trend to larger
particles, more easily
controlled
Possibly increased because
of overall trend to smaller
particles
Possibly decreased because
of decreased particle
emissions
Unknown effect: greater
proportion of small
particles, but better ESP
efficiency possible
Nonsegrating
Possibly decreased because
larger particles more
easily controlled
Possibly increased because
of overall trend to smaller
particles
Possibly decreased due to
lowered particle emissions
Possible decreased due to
lowered particle emissions

-------
benzene, toluene, xylene,  ethylbenzene, etc.).  This breakdown corresponds  to  that  adopted  1n
References 6-1 and  6-2.
       Sulfate emissions  are addressed 1n Table 6-1 instead of simple SO  emissions  because acid
sulfate aerosol  emissions are far more sensitive to combustion conditions.   About 98 percent of
the original  fuel-bound sulfur introduced into a boiler typically appears  in the flue gas  (Ref-
erence 6-3)  in some form.  Combustion conditions are expected to  have  little effect on total SO
(S02, S03>  H2S04 and metal sulfates) emissions.  However,  effects on the So!/S02 ratio and  the
speciation  of sulfate between HgSO^ and condensed metal  sulfates  can be quite  significant.
       In Table 6-1 comments on particulates  address these emissions as a single pollutant  class.
Effects on  particle composition are considered as effects  on sulfate, trace metal,  and organic
emissions.   Particulate comments are further  subdivided into expected particle size distribution
effects and particulate mass emissions effects.  This  is done for several reasons.   First,  emitted
 size distribution has a significant bearing on eventual  adverse pollutant effects.   Fine particulate
 presents greater adverse health effects than  coarse particulate because fine particles most easily
 penetrate the body's pulmonary defenses, and  remain in the lungs  for longer times.   Furthermore, fine
 particulate remains suspended in the air for  longer times.  Secondly, combustion-produced particle
 size distribution has great impact on  the actual particle  load emitted from boilers  with particulate
 controls.  Fine particulate is less easily caught by these controls.  Particle size distribution
 also significantly affects  the level of trace metal emissions  in  these boilers. As discussed  in
 Section 6.2.4, certain trace elements  tend to concentrate  in the  small particles emitted from  a
 boiler.  Thus, modifications which shift the  emitted particle  size distribution to  smaller  sizes
 would  tend to increase the  emissions of this  group  of  trace metals.  Finally,  as discussed  in
 Section 6.2.5, particle size distribution can have  significant effects on  S02  to S03, and  ultimately
 sulfate, conversion.
       For analogous reasons, trace metal emissions are discussed in  two  subsets  in the table:
 segregating trace metals and nonsegregating trace metals.  Segregating trace elements are  those
 which  tend to concentrate in fine particulate.   Nonsegregating  trace  elements  are  those that  remain
 essentially evenly distributed (on a fractional  mass basis) in particles  of all sizes.  The emissions
 characteristics of each croup are quite different.  Nonsegregating trace metal emissions  are  larqelv
 determined by total particulate mass emissions.  Conversely, segregating  trace metal emissions are
 significantly affected by emitted particle size  distribution and  boiler  temperature-time profile.
                                                6-7

-------
       The entries in Table 6-1 largely refer to a coal-fired utility  boiler with  a  cold side  electro-
static precipitator particulate control.  This type of boiler represents  the most  general  equipment
class for present considerations.  It exhibits all the emissions listed in the table, and  illustrates
the type of effects which can occur with changes in produced particle  size distribution.   As a re-
sult, not all entries in the table refer to all boilers.  For example, natural gas-fired boilers
essentially emit only CO and small quantities of HC.  Thus, all entries under trace  metal, organics,
particulate, and sulfate do not strictly apply to gas-fired boilers.   Similarly certain comments
under particulate, organics, and trace metal headings do not strictly  apply to oil-  or coal-fired
boilers without particulate controls.  For example, many comments are  based on the assumption that
modifications which tend to produce smaller particles would tend to increase particulate mass emis-
sions; this is because particulate controls are less efficient at collecting fine particulate.
Organic (particulate POM), and segregating trace metal emissions would show corresponding  increases
in these instances.  However, on boilers without particulate controls, a  shift in particle size dis-
tribution, at constant mass production, would yield no change in emissions of particulate, organics,
or trace metals.  Still, with suitable interpretation, the table comments essentially describe  what
is expected to occur in any boiler, when the appropriate combustion condition is imposed.
       As indicated in Table 6-1, CO and vapor phase hydrocarbon emissions are expected to be in-
fluenced only by excess boiler Op concentrations.  Changes in furnace  residence times or flame  zone
mixing may also elicit slight changes in these emissions, though these are not expected to be
significant.
       Sulfate emissions are influenced by local  0? concentrations, and by the presence of metal
oxidation catalysts such as vanadium and its oxides.  Thus, changes in the temperature-time profile
in a boiler influence catalyst metal  volatilization, oxidation, and condensation, and thereby in-
fluence S02 to S03 conversion.   For example, reducing peak flame temperature would cause less trace
metal  volatilization.  Subsequently less metal vapor would be available to condense  on gas stream
fine particle surfaces.   Consequently the availability of oxidation catalyst is limited, and less
sulfate production is expected.   Conversely lowered furnace gas velocities would allow increased
amounts of internal  particulate deposition, and thus increased levels  of  SO, production.
                                                                           O
                                                6-8

-------
      Particle size distribution is probably  affected largely by the degree of combustion complete-
ness, and the degree of flame zone mixing.   Incomplete combustion or mixing can yield large particles
with high carbon content.  Particulate mass  emissions will  be affected by: the degree of combustion
completeness (level of carbonaceous soot  formation);  the produced particle size distribution (large
particles tend to fall out as bottom ash  and are more easily collected in particulate control de-
vices); and the temperature profile in the  boiler as  it affects ash slagging.  Special circumstances
exist in boilers equipped with ESPs.   In  these, increased flue gas water vapor, sulfate, or ammonia
(or more appropriately ammonium  bisulfate,  Reference  6-4) concentrations can act to condition the
flyash, thereby increasing ESP collection efficiency, and decreasing net particulate emissions.
      Organic emissions, as we  have defined them here (chiefly POM), are mainly influenced by the
level of particulate emissions and the carbon  content of the particulate.  Thus, conditions which
inhibit complete combustion, and conditions  which increase  particulate load will increase condensible
organic emissions.
      Nonsegregating trace metal emission  levels are essentially functions of total  particulate
mass emissions.  Segregating trace metal  emissions, however, are influenced by the particle size
distribution,  the boiler temperature-time profile, and local 02 concentrations.  Lowered peak tem-
peratures will decrease the extent of  initial  metal volatization, so particle size redistribution
effects are less pronounced.  Increased convection zone temperatures, however, allow volatile metals
to remain in the vapor phase for longer times.  Thus, when  nucleation/condensation eventually occurs,
condensation nuclei have less time to  grow,  and particle size redistribution effects  are more pro-
nounced.  Low  local 0? levels also inhibit  metal oxide formation.  Since metal oxides are, in gen-
eral,  less volatile than the base metal,  low Op levels extend the time the metals exist as vapors.
Again, particle size redistribution effects  will become more pronounced.
      Table 6-1, as discussed above,  outlined the postulated effects of individual,  isolated com-
bustion conditions on the level  of flue gas  emissions.  Table 6-2 summarizes the postulated overall
effects of implementing combustion modification NO controls, each of which, as shown, can effect
several combustion condition changes.  Table 6-2 reflects the cumulative effects of each altered
combustion condition appropriate to a  given  combustion control technique.
      Table 6-2 shows that:
      •   Increased CO and vapor phase hydrocarbon emissions are of major concern only when excess
          air levels are lowered
      •   Sulfate emission levels are expected to decrease or remain unchanged with all controls
          except combustion staging and  ammonia injection
                                                6-9

-------
TABLE 6-2.  POSTULATED OVERALL EFFECT OF COMBUSTION NO. CONTROLS ON FLUE GAS EMISSIONS FROM BOILERS
Combustion
Modification
Low excess air
Staged combustion
Flue gas
recirculation
Reduced air
preheat
Reduced load
Water
injection
Ammonia
injection
Resulting Combustion
Conditions
Reduced local 02 concentra-
tion; decreased gas veloci-
ties; increased furnace
residence time
Reduced local 02 concentra-
tion; reduced peak flame
temperature; increased con-
vection zone temperature;
delayed flame zone mixing
Reduced local 02 concentra-
tion; reduced peak flame
temperature; reduced furnace
residence time; increased
gas velocities; more turbu-
lent flame; increased con-
vective zone temperature
Reduced peak flame tempera-
ture; decreased gas veloci-
ties; increased furnace
residence times; increased
local 0- concentration
Reduced flame temperature;
decreased gas velocities;
decreased furnace residence
times; increased local 0~
concentration
Reduced peak flame tempera-
ture; increased local H20
concentration
Increased local NH3
concentration
CO
Increased
Possibly increased
Possibly Increased
No effect
Decreased
No effect
No effect
Vapor Phase HC
Increased
Possibly increased
Possibly increased
No effect
Decreased
No effect
No effect
Sulfate
Decreased overall because of
lowered 02 availability
Possibly decreased because of
decreased convection zone
catalysis (less volatile metal
redistribution)
Possibly decreased
Possibly decreased
Unknown effect: Less
catalyst volatilization;
but greater local 02
concentrations
Possibly decreased
Possibly increased through
near plume solution
catalysis
Organics
Possibly increased
Possibly increased
Possibly increased
Possibly increased
Possibly decreased
Possibly increased
Decreased with
decreased particle
emissions; no
effect otherwise

-------
TABLE 6-2.  Concluded
Combustion
Modification
Low excess air
Staged
combustion
Flue gas
recirculation
Reduced air
preheat
Reduced load
Water
injection
Arnmonla
injection
Particulate
Size Distribution
Possible trend to larger
sizes
Possible trend to larger
sizes
Probably no effect
Probably no effect
Probably no effect
Probably no effect
Trend to smaller particles
(NH4HS04 aerosol)
Mass Emissions
Possibly decreased because of
increased bottom and ash
fallout and internal deposi-
tion
Unknown effect: possible
increase due to soot forma-
tion; possible decrease due
to larger particles and con-
vection zone depositon and
slagging
Possibly increased due to
increased velocities and
possibility of soot formation
Possibly increased due to •<
less bottom slagging
Probably no net effect
Possibly decreased with ESPs
because of conditioning;
possibly increased otherwise
Possibly decreased with ESPs
because of conditioning;
increased otherwise
Trace Metals
Segregating
Unknown effect: possible in-
crease due to increased
volatility but possible de-
crease with internal deposi-
tion
Possibly decreased because of
decreased repartitioning to
small particles
Possibly decreased because of
decreased repartitioning to
small particles
Possibly reduced because of
less concentration in small
particles
Possibly reduced because of
less concentration in small
particles
Possibly reduced because of
less small particle concen-
tration and lowered particle
emissions
Possibly increased because
larger fraction of small
particles
Nonsegregating
Possibly reduced because of
reduced mineral particle
emissions and internal
particle deposition
Possibly reduced due to
larger particles (more car-
bon) and convection zone
slagging
Possibly increased with
increased particle emissions
Possibly increased with
increased particle emissions
Probably no effect
Possibly decreased with
ESPs, possibly increased
otherwise; follows particu-
late load
Decreased with decreased
particle emissions; no
effect otherwise
                                                                                           Ol
                                                                                           vo

-------
       •   Changes in emitted particle size distribution are  expected  only when imposing staged
           combustion or lowered excess air modifications.  In  these instances  the production  of
           larger particles is expected
       •   Increased particulate mass emissions are of potential  concern  when flue gas  recirculation
           is used
       0   Condensible organic emissions are likely to increase with all  combustion  N0x controls
           except ammonia injection
       •   Increased segregating trace metal emissions are possible when  using  staged combustion,
           flue gas recirculation, and ammonia injection
       •   Nonsegregating trace metal emissions are only of potential  concern when implementing flue
           gas recirculation and reduced air preheat

 6.1.2  Reciprocating 1C Engines and Gas Turbines
       The commonly considered combustion modifications for NO  control applicable to stationary 1C
                                                              X
 engines and gas turbines were summarized in Section 4.2.  The set of combustion  conditions result-
 ing  from  imposing these modifications, and the postulated effects of each  altered  combustion condi-
 tion on the pollutants under consideration are listed in Table 6-3.  The  pollutant classes tabulated
 in Table  6-3 are the same as those considered above for boilers.  However,  since 1C  engines and gas
 turbines  burn natural gas or petroleum distillates (kerosene or diesel fuel) almost  exclusively,
 some of these pollutants are currently of minor importance.  For  example,  trace  metal emissions
 would be  of concern only for residual oil-fired gas turbines, or when  fuel  additives are used with
 distillate oils.
       In Table 6-3 the postulated effects of combustion condition on  incremental  air emissions
 from stationary 1C engines and gas turbines are similar to those  discussed  above for boilers.  Ex-
 ceptions  here stem from the absence of particulate control devices on  1C  engine  and  gas turbine ex-
 haust streams.   In these exhaust streams particulate mass emissions and condensible  organic emissions
 are determined solely by the degree of combustion completeness.   Particle  size  distribution effects
 in the absence of particulate controls, do not influence these emissions.   Similarly, emissions of
 nonsegregating (i.e., nonvolatilizing) trace metals are not affected by all combustion  conditions;
essentially everything introduced with the fuel leaves in the exhaust.  Emissions  of segregating
trace metals  are affected only by the combustion gas temperature-time  profile,  and by local 02 con-
centrations.   These affect the amount of trace metal (and which elements)  that  volatilize, and where
condensation  or deposition occurs.   Thus, because reduced peak  temperatures cause  a lesser degree
                                                 6-12

-------
TABLE 6-3.  POSTULATED EFFECTS OF COMBUSTION CONDITIONS ON EMISSIONS  FROM 1C  ENGINES AND GAS TURBINES
Combustion
Condition
Reduced peak temperature
Reduced residence time
at temperature
Reduced local 0?
concentration
Increased local 0?
concentration
Increased local FUO
concentration
CO
Possibly increased
Possibly Increased due to
incomplete combustion
Possibly increased due to
Incomplete combustion
Reduced
No effect
HC
Possibly increased
Possibly increased due to
incomplete combustion
Possibly increased due to
incomplete combustion
Reduced
No effect
Sul fate
Unknown effect; potentially
increased because S03
favored at lower tempera-
tures; potentially decreased
because of decreased trace
metal volatilization and
deposition
Possibly decreased because
of decreased trace metal
volatilization and subse-
quent deposition
Decreased
Increased
Possibly increased
Organ ics
Possibly increased
Possibly increased due to
incomplete combustion
Possibly increased due to
incomplete combustion
Possibly reduced .
No effect
                                                                                                 (Continued on page 6-14)

-------
TABLE 6-3.  Concluded
Combustion
Condition
Reduced peak
temperature
Reduced
residence time
at temperature
Reduced local 02
concentration
Increased local
Op concentration
Increased local
H-0 concentration
Participate
Size Distribution
Probably no effect
Trend to larger sizes due to
incomplete vaporization and
combustion of fuel droplets
Trend to larger sizes due to
incomplete combustion of fuel
droplets
Trend to smaller sizes
Probably no effect
Mass Emissions
Possibly increased
Possibly increased due to
incomplete combustion
Possibly increased due to
incomplete combustion
Possibly reduced
Probably no effect
Trace Metals
Segregating
Possibly slightly increased
due to decreased volatiliza-
tion and internal deposition
Possible slight increase due
to decreased volatilization
and subsequent internal
deposition
Possible slight increase due
to decreased formation of
less volatile metal oxides,
resulting in less internal
deposition
Possible slight decrease due
to increased oxide formation
and subsequent internal
deposition
No effect
Nonsegrating
No effect
No effect
No effect
No effect
No effect

-------
of segregating metal volatilization and subsequent deposition on internal chamber surfaces, there
will be a slight increase  in  emissions.  Similarly lowered local (L concentrations allow a lesser
degree of metal oxidation,  thereby reducing nonvolatile metal oxide deposition, and slightly in-
creasing exhaust emissions.
      Table 6-4 summarizes each N0x control considered, and its postulated overall effect on the
incremental emissions  from 1C engines.   Table 6-5 is the analogous summary for gas turbines.

6.1.3  Warm Air Furnaces
      Over 90 percent of  residential and commercial warm air furnaces fire either natural gas or
distillate oil.  Emissions oT sulfates and trace metals from these units are thus of minor concern
compared to coal-fired boilers.   About 3 percent of U.S. warm air furnaces still fire coal.  For
these,  sulfates, trace metals and especially ROMs could cause severe localized environmental prob-
lems.   It  is  doubtful  that NO  controls, except for fuel switching, will be developed and implemented
for these  sources,  however, and they will not be considered further here.
       An  additional  factor in evaluating incremental emissions from warm air furnaces is the cyclic
nature of  operation.   Warm air furnaces typically undergo 2 to 5 on/off cycles per hour.  Studies
of emissions  without  NO  controls show that the starting and stopping transients have a strong, some-
times dominant, effect on  total  emissions of CO, HC and particulate (smoke) (References 6-5, 6-6).
The effect of NO   controls on transient emissions is presently unknown.  Incremental steady state
emissions  must eventually  be  weighed against the transient emissions however, for this significance
to be shown.
       The range of combustion process modifications effective for N0x control in warm air furnaces
is more limited than  was  the  case for the larger equipment types discussed above.  This is due both
to the combustion  design  constraints specific to this application and to the low unit capital and
operating  costs which make extensive modification unattractive.  Minor process modifications, pri-
marily burner tuning,  are  ineffective for NO  control in a given unit  (References 6-5, 6-6).  Un-
                                            X
controlled NO emissions  among units with different burner/firebox designs differ by a factor of
             X
two or more,  however  (References 6-6, 6-7).  Thus, the use of low N0x burner/firebox combinations,
for application to  new units, is the prime candidate for NOX control in warm air furnaces.
       The combustion conditions typical of low N0x operation in warm air furnaces are as  follows:
       •   Lower excess air
       •   Reduced  peak flame temperature
                                                 6-15

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                                  TABLE 6-4.  POSTULATED OVERALL EFFECT OF COMBUSTION NOX CONTROLS ON EMISSIONS FROM 1C ENGINES
Combustion
Modification
Retard ignition
Increase air/
fuel ratio
Decrease air/
fuel ratio
Exhaust gas
recirculation
Decrease
manifold air
temperature
Stratified
charge cylinder
design
Derate
Increase speed
Water
injection
Resulting Combustion
Condition
Reduced peak tempera-
ture; reduced time at
temperature
Reduced peak tempera-
ture; increased local
02 concentration
Reduced peak tempera-
ture; reduced local
02 concentration
Reduced peak tempera-
ture; reduced local
Og concentration
Reduced peak tempera-
ture
Reduced peak tempera-
ture; reduced residence
time at temperature;
reduced local 0^
concentration
Reduced peak tempera-
ture
Reduced residence time
at temperature
Reduced peak tempera-
ture; reduced local
02 concentration;
increased local ^0
concentration
CO
Possibly increased due
to incomplete combus-
tion
Decreased
Possibly increased
Possibly increased
Possible increase
Possibly increased
due to incomplete
combustion
Possible increase
Possible increase
due to incomplete
combustion
Possibly increased
due to incomplete
combustion
Vapor Phase HC
Possibly increased due
to incomplete combus-
tion
Decreased
Possibly increased
Possibly increased
Possible increase
Possibly increased
due to incomplete
combustion
Possible increase
Possible increase
due to incomplete
combustion
Possibly increased
due to incomplete
combustion
Sulfate
Potentially decreased
due to decreased metal
catalyst internal
depostion
Increased
Decreased
Decreased
Unknown effect: pos-
sible increase because
SOa favored at lower
temperatures; possible
decrease due to de-
creased catalytic oxi-
dation
Potentially decreased
Unknown effect
Possible decrease due
to decreased catalyst
deposition
Potentially decreased
Organics
Possibly increased
due to incomplete
combustion
Possibly decreased
Possibly increased
due to incomplete
combustion
Possibly increased
due to incomplete
combustion
Possible increase
Possibly increased
due to incomplete
combustion
Possible increase
Possible increase
due to incomplete
combustion
Possible increase
due to incomplete
combustion
91
I


Ol
                                                                                                                                     (Continued on page 6-77)

-------
TABLE 6-4.  Concluded
Combustion
Modification
Retard ignition
Increase air/
fuel ratio
Decrease air/
fuel ratio
Exhaust gas
recirculation
Decrease
manifold air
temperature
Stratified
change cylinder
desi gn
Derate
Increase speed
Water
Injection
Parti cul ate
Size Distribution
Possible trend to larger
sizes due to incomplete
combustion
Possible trend to smaller
sizes
Possible trend to larger
sizes due to incomplete
combustion
Possible trend to larger
sizes due to incomplete
combustion
Probably no effect
Possible trend to larger
sizes
Probably no effect
Possible trend to larger
sizes
Possible trend to larger
sizes
Mass Emissions
Possibly increased due to
incomplete combustion
Possibly decreased
Possibly increased due to
incomplete combustion
Possibly increased due to
incomplete combustion
Possible increase
Possibly increased due to
incomplete combustion
Possible increase
Possible increase due to
incomplete combustion
Possible increase due to
incomplete combustion
Trace Metals
Segregating
Possible slight decrease due
to reduced internal deposi-
tion
Possible slight decrease due
to reduced internal deposi-
tion
Possible slight increase
Possible slight increase
Possible slight increase due
to decreased internal deposi-
tion
Possible slight increase due
to decreased internal deposi-
tion
Possible slight increase
Possible slight increase
Possible slight increase
Nonsegregating
No effect
No effect
No effect
No effect
No effect
No effect
No effect
No effect
No effect

-------
TABLE 6-5.
POSTULATED OVERALL EFFECT OF COMBUSTION  NOX  CONTROLS ON EMISSIONS FROM GAS TURBINES
Combustion
Modification
Water or steam
injection
Lean primary
zone
Early quench
with secondary
air
Increase mass
flowrate
Exhaust gas
recirculation
Air blast or air
assist atomiza-
tion
Reduced air
preheat
Reduced load
Resulting Combustion
Condition
Reduced peak tempera-
ture; reduced residence
time at temperature;
reduced local 02 con-
centration; decreased
local H^O concentration
Reduced peak tempera-
ture; increased local
02 concentration; re-
duced residence time at
temperature
Reduced residence time
at temperature
Reduced residence time
at temperature
Reduced peak tempera-
ture; reduced local 0,
concentration
Reduced peak tempera-
ture; reduced local 0,
concentration
Reduced peak tempera-
ture
Reduced peak tempera-
ture; reduced local 02
concentration
CO
Possibly increased due
to incomplete combus-
tion
Decreased
No effect
Possibly increased due
to incomplete combus-
tion
Possibly increased due
to incomplete combus-
tion
Possibly increased due
to incomplete combus-
tion
Possibly increased
Increased
Vapor Phase HC
Possibly increased due
to incomplete combus-
tion
Decreased
No effect
Possibly increased due
to incomplete combus-
tion
Possibly increased due
to incomplete combus-
tion
Possibly increased due
to incomplete combus-
tion
Possibly increased
Increased
Sulfate
Potentially decreased
Possibly increased
Potentially decreased
Possibly increased due
to decreased catalyst
metal internal deposi-
tion
Potentially decreased
Potentially decreased
Unknown effect: pos-
sible increase because
S03 favored at lower
temperatures; possible
decrease due to de-
creased internal cata-
lyst deposition
Potentially decreased
Organ ics
Possibly increased
due to incomplete
combustion
Possibly decreased
Unknown effect
Possible increase
due to incomplete
combustion
Possibly increased
due to incomplete
combustion
Possibly increased
due to incomplete
combustion
Possibly increased
Possibly increased
                                                                                                 (Continued on page 6-19)

-------
                                                                         TABLE 6-5.  Concluded
Combustion
Modification
Water or steam
injection
Lean primary
zone
Early quench
with secondary
air
Increase mass
flowrate
Exhaust gas
recirculation
Air blast or air
assist atomiza-
tion
Reduced air
preheat
Reduced load
Parti cul ate
Size Distribution
Possible trend to larger
sizes due to incomplete
combustion
Possible trend to smaller
sizes
Possible trend to larger
sizes
Possible trend to larger
sizes
Possible trend to larger
sizes
Possible trend to larger
sizes
Probably no effect
Possible trend to larger
sizes
Mass Emissions
Possibly increased due to
incomplete combustion
Possibly decreased
Possible slight increase
Possible increase due to
incomplete combustion
Possibly increased due to
incomplete combustion
Possibly increased due to
incomplete combustion
Possibly increased
Increased
Trace Metals
Segregating
Possible slight increase due
to decreased internal deposi-
tion
Possible slight increase due
to decreased internal deposi-
tion
Possible slight increase
Possible slight increase due
to decreased internal deposi-
tion
Possible slight increase due
to decreased internal deposi-
tion
Possible slight increase
Possible slight increase due
to decreased internal deposi-
tion
Possible slight increase
Nonsegregating
No effect
No effect
No effect
No effect
No effect
No effect
No effect
No effect
oป



VD

-------
       •   Delayed fuel air mixing and/or  internal  recirculation  of combustion products




       t   Longer residence time




 The  general effects on combustion-generated pollutants  are  largely as  summarized in Table 6-1  for



 boilers.  Taken  individually, the general  expectation is  for the  modified combustion condition to



 increase  incremental emissions.  For example,  Figure 6-1  shows  the effect of lower excess air  on



 CO,  HC and smoke emissions  (Reference  6-8).  However, through careful  engineering during control



 development,  it  has been  possible to achieve 1ow-NOv combustion conditions without adverse incre-
                                                    A


 mental emissions (Reference 6-9).  Table 6-6 shows  a comparison of typical uncontrolled units  and a



 prototype unit with an optimized burner/firebox.   Incremental  emissions  were held constant or  re-



 duced at  the  low-NO , high-efficiency  condition.   Table 6-6  also  shows  incremental  emissions with a



 commercially  available oil emulsifier  burner.  Again, low-NO  operation  was achieved with no adverse



 effects on incremental emissions (Reference 6-10).




       Data on warm air furnace POM emissions  under low-NO   operation are  apparently nonexistent.
                                                          X


 Data on both  transient and steady operation with and without  NO   controls  are  needed to  form a gen-
                                                                A


 eral conclusion  on the total incremental impact of NO   controls.   Additionally,  it  should be empha-



 sized that the incremental emissions data  shown in Table  6-6  are  for well  maintained laboratory



 operation.  Data are needed on long-term field operation  with NO   controls.





 6.2    EMISSIONS DATA EVALUATION




       The previous subsection described the expected incremental  effects  of NO   combustion con- '



 trols on  the  emission of pollutants other  than NO  from stationary combustion  sources.   This sub-
                                                 A


 section supports that development by presenting and discussing  the  available incremental  emissions



 data obtained through several  N0x control   evaluation studies.   The  discussion  is  divided  into  seven



 subsections,  one for each pollutant considered in Section 6.1,  plus an additional discussion of



 nitrate emissions.  It should be noted that data on the emissions  of pollutants  other than CO,



 hydrocarbons, and particulate, as a function of NO  control  implementation,  are  spotty to nonexis-
                                                  X


 tent.  Consequently in these cases  a more  detailed analysis  of  postulated  pollutant formation  mech-



 anisms is  presented.   In light of this, an assessment of  the  relative need to  develop the requisite



 information  can be made.





6.2.1  Carbon Monoxide




       The presence of CO in the exhaust gases of combustion  systems results from incomplete fuel



combustion.   Several  conditions  existing in a combustion  source can give rise  to incomplete combus-



tion.  These  include:
                                                6-20

-------
  2.00
         Smoke
         (10th
         min.)
   1.50-1-
0)
3
Dl

Dl
CJ
T3

(0
   i.oo 4-
   0.50
   0.00
  ,4    I
 /       \   -T—. ef1
/         \     :   "--
            Optimum setting for minimum |
            emissions and maximum       |
            efficiency
                                                         I  +
                                                           46
                                                10
                                                                c
                                                                Ol
                             QJ
                             Q.
                          8 ฃ
                             X
                                                                

                                                                CD
                                                               O
                                                               O
                       40    60     80
                          Excess air,  %
         16  14   12

          Figure 6-1.
          10
8
                                                                co2,
        Effect of excess air on emissions from
        an oil-fired warm air furnace.
        (Reference 6-8).
                                6-21

-------
                      TABLE  6-6.   EFFECT OF LOW-NOX OPERATION ON INCREMENTAL EMISSIONS AND

                                  SYSTEM PERFORMANCE FOR RESIDENTIAL WARM AIR FURNACES

Typical uncontrolled
field units
(References 6-5, 6,6)
Optimum low NOx unit
(Reference 6-9)
Water/distillate oil
emulsion burner: 32% H?0
(Reference 6-10)
Excess
Air
90%
15%
32%
Thermal
Efficiency
(Steady-State)
70%
80%
80%
NO
g/kg fuel
1.1 - 2.7
0.6
0.85
CO
g/kg fuel
1.05
1.0
0.3
HC
g/kg fuel
0.1
0.1

Smoke
Bacharach
3.2
1
~1
r>>
ro

-------
      •   Insufficient 02 availability
      •   Poor fuel/air mixing
      t   Cold wall flame impingement
      •   Reduced combustion temperature
      •   Decreased combustion gas  residence time
As noted in Section 6.1, various combustion  modifications for NO  reduction can produce one or more
                                                                A       ^
of the above conditions.  Consequently,  the  possibility of increased CO emissions due to combustion
NO  controls represents a justifiable concern.
  A
      Since field test programs investigating  NO  controls generally monitor combustion source CO
                                                 X
to provide an indication of combustion efficiency, sufficient data are available to  assess  the effect
these controls have on residual CO emissions.  These data are presented and evaluated in the follow-
ing subsections for utility boilers  (6.2.1.1),  industrial boilers (6.2.1.2), internal  combustion (1C)
engines  (6.2.1.3), and gas turbines  (6.2.1.4).

6.2.1.1  Utility Boilers
      Since large quantities of CO  in the flue gas of utility boilers mean decreased efficiency,
these boilers are operated to keep CO emissions at a minimum.  Furthermore, if flue  gas CO  levels
reach concentrations in excess of 2,000  ppm, severe equipment damage can result because of  explosions
in flue  gas exit passages.  Thus, the degree to which a NOX reduction technique is allowed  to in-
crease CO is limited by other than environmental  concerns.   In general, a NO  control  method is ap-
plied until flue gas CO reaches about 200  ppm.   Further application is then curtailed.
      NO  control effects on CO emissions are  highly dependent on the equipment type and the fuel
fired.   In utility boilers of newer  design,  it  is generally possible to achieve good NOX reduction
without  causing significant CO production.  This is possible because newer burner and furnace designs
allow for better combustion air control  and  longer combustion gas residence time.  In addition, oil-
and coal-fired boilers usually emit  very low CO levels during low-NOx combustion because smoke and
soot production generally occur with these fuels  before significant CO levels are attained.  Since
boiler operators strive to keep combustible  losses to a minimum, conditions which result in soot
formation are avoided, resulting in  correspondingly low CO levels.
      The combustion modifications  commonly applied to utility boilers were discussed in Section 4.2.
A sumnary of the field data on the effects of the more extensively implemented modifications on
CO emissions is shown in Table 6-7.  These data are discussed below for each combustion N0x control.
                                                6-23

-------
    TABLE 6-7.  REPRESENTATIVE EFFECTS OF  NOX  CONTROLS ON CO
                EMISSIONS  FROM UTILITY BOILERS
                (References 6-11, 6-12,  6-13)
NOV Control
A
Low Excess Air











Off-Stoichiometric
Combustion








Fuel
Natural Gas




Oil



Coal




Natural Gas


Oil



Coal



CO Emissions (ppm)a
Baseline
14
86
12
8
14
19
85
15
19
42
20
24
27
27
14
86
12
14
19
85
15
28
24
- 27
17
31
NO Control
y\
68
74
61
8
34
42
53
20
19
93
60
283
81
225
16
67
13
14
21
85
21
37
23
26
40
45
13%  02,  dry  basis.
                               6-24

-------
                    TABLE 6-7.  Concluded

NO Control
A

Flue Gas Recirculation

Load Reduction












Fuel


Natural Gas
Oil
Natural Gas



Oil



Coal



CO Emissions (ppm)a

Baseline

175
21
14
52
12
14
19
30
15
19
20
25
31
24
NOV Control
X
65
9
13
52
15
21
14
5
19
22
41
19
8
12
3% 02, dry basis.
                               6-25

-------
Low Excess Air




       As the data in Table 6-7 illustrate,  lower  excess  air  levels  in utility boilers can have



profound effects on CO emissions.  In virtually all instances,  CO  emissions  increased significantly



when excess 0? levels were reduced 30 to 60  percent.  Gas-fired boilers showed emission increases



up to 400 percent when excess 02 was lowered over  this range, while  oil-fired  boilers were less



sensitive, and showed CO emission increases  from 0 to 120 percent.   However, coal-fired boilers



were the most sensitive to excess air reductions.  Reducing excess 02  by 40  to 60  percent  gave 100



to 1,000 percent increases in CO emissions.





Off-Stoichiometric Combustion




       Off-stoichiometric, or staged, combustion has proven to  be a  very effective N0x  reduction



technique for large steam generators.  As discussed in Section  4.2,  it  can be  implemented  in a



variety of ways including burners out of service, overfire air  ports, and biased firing.   In all



cases, the effectiveness of off-stoichiometric combustion (OSC)  in reducing N0x emissions  depends in



large part on the fraction of total combustion air that can be  introduced into the second  combustion



stage.  It is in this second stage that complete combustion of  the fuel  is achieved.  CO emissions



arise when this second stage combustion does not go to completion prior to quenching  in the convec-



tive section.  This is caused by a combination of the first stage being too fuel rich and  the mixing



of second stage air being too slow for the residence time provided.  During development of retrofit



or new design controls, these parameters are usually selected so that CO emissions are acceptable.




       The effectiveness of OSC in reducing  NO  formation while  keeping CO emissions  low is highly
                                              X


dependent on specific equipment type.  New utility boilers with multiburner furnaces  are especially



amenable to this technique because it is generally not difficult to  adequately distribute  secondary



air and assure complete combustion in these  sources.  Consequently,  implementing OSC  in utility



boilers is expected to elicit little effect  on incremental CO emissions.  This conclusion  is cer-



tainly borne out by the representative data  presented in Table  6-7.





Flue Gas Recirculation




       The use of flue gas recirculation (FGR) for NO  control  has,  in  practice, been restricted
                                                     X


to gas- and oil-fired units.   Tests have shown FGR to be impractical for use in coal-fired equipment



(Reference 6-14).   This is so because, as discussed in Section  4.2,  the technique  is  ineffective in



reducing fuel  NO^ production, the predominant source of NO  in  coal  firing.  When  FGR is implemented,



10 to 30 percent of the total burner gas flow is recycled flue  gas from the  boiler exhaust.  Further



FGR increases  can cause flame instability due to reduced flame  temperatures  and oxygen  availability.
                                                6-26

-------
Theoretically, FGR  can  lead to Increased CO emissions, but unacceptable  flame  instabilities  usually
occur before  the  onset  of CO or smoke production.  Thus, as Table  6-7  shows, the  use  of  FGR  has  not
caused increased  CO emissions.  On the contrary, CO emissions  have generally decreased.

Load Reduction
       Since  load reduction in steam generators necessitates increased excess  air levels to  maintain
good furnace  air/fuel mixing and steam temperature control, increased  CO emissions  using this  NO
reduction technique are not expected.  In addition, the increased  combustion gas  residence time
afforded under  reduced  load would tend to facilitate  complete  CO burnout.  As  Table 6-7  illustrates,
CO emissions  remain relatively unchanged with reduced load.

6.2.1.2  Industrial Boilers
       The bulk of the  data on incremental CO emissions due to NO   controls applied to industrial
                                                                 X
 boilers was obtained in a recently completed field test program (References 6-15  and  6-16).   In  this
 study, CO emissions were reported for both baseline and for low-NO  firing.  Baseline emissions were
 recorded with the boiler operating at 80 percent of rated capacity under normal (or as-found)  con-
 ditions.  Low-NO  testing was implemented until CO emission levels reached 100 to 200 ppm, then  it
 was  curtailed.
       The data obtained during this study are summarized in Table 6-8.  As indicated in the  table,
 baseline CO emissions for industrial boilers are generally insignificant.  However, the  application
 of NO  combustion controls in most cases adversely affected CO levels  because  each  control was im-
 plemented until  CO levels became unacceptable.

 Low  Excess Air
       As noted for utility boilers above, CO emissions from industrial  boilers are also adversely
 affected by excess air levels.  As observed in the field study (References 6-15,  6-16).  Table 6-8
 illustrates that CO emissions from gas- and oil-fired boilers  can  be significantly increased when
 excess oxygen is reduced 20 to 50 percent.  Coal-fired boilers showed  lower incremental  CO emission
 increases.

 Off-Stoichiometric Combustion
       Two methods were used in the industrial boiler study to effect  OSC:  overfire  air and burners
out  of service.   In these tests baseline CO emissions were always  low.  Combustion staging  by both
methods generally resulted in unchanged to slightly increased  CO emissions.
                                                6-27

-------
            TABLE  6-8.   EFFECTS  OF NOX CONTROLS ON CO
                        EMISSIONS  FROM INDUSTRIAL BOILERS
                        (References 6-15,  6-16)
NO Control
rt
Low Excess Air














Off-Stoichiometric
Combustion
• Overfire Air



Fuel
Natural Gas




Distillate Oil


Residual Oil




Coal




Natural Gas

Distillate Oil
Residual Oil


Coal
CO Emissions (ppm)a
Baseline
10
0
0
0
50
47
90
0
0
0
0
0
0
25
70
0
0
25
10
10
0
0
0
0
0
N0ฅ Control
A
10
0
11
900
129
485
150
17
45
100
9
28
205
20
60
0
22
25
10
20
0
0
30
80
49
3X 02, dry basis.
                                6-28

-------
                TABLE 6-8.  Concluded
N0y Control
A
Of f-Stoi chi ometri c
Combustion (Concluded)
• Burners Out of
Service



Flue Gas Recirculation


Variable Air Preheat



Load Reduction




Fuel

Natural Gas

Residual Oil


Natural Gas

Residual Oil

Natural Gas


Residual Oil

Coal
Natural Gas


Distillate Oil

Residual Oil

Coal
CO Emissions (ppm)a
Baseline

10
0
0
10
0
0
10
10
0
0
10
0
322
0
0
0
0
0
50
0
0
0
0
0
NO Control
A

10
0
43
20
0
10
0
75
0
0
0
30
320
0
0
10
0
0
30
0
9
0
0
0
,, dry  basis.
                            6-29

-------
Flue Gas Recirculation




       The data in Table 6-8 show that FGR has little effect on CO emissions.   This  conclusion  sub-



stantiates what was noted in the utility boiler testing discussed previously  (Section  6.2.1.1).





Variable Air Preheat




       As for FGR, the data in Table 6-8 illustrate that varying combustion air temperature has



almost no effect on CO emissions.  This suggests that effects of peak flame temperature on CO emis-



sions were also insignificant.





Load Reduction




       During the cited industrial boiler field test program, load reduction experiments were



performed with the boiler controls on automatic.  Therefore, excess air levels  increased when boiler



load was reduced.  As a consequence, CO emissions remained unchanged, or decreased slightly as load



was reduced.





6.2.1.3  Internal Combustion Engines




       As discussed in Section 4.2, the most common NO  reduction techniques applied to 1C engines



include derating, ignition retard, altering air/fuel (A/F) ratios, reducing manifold air temperatures



(MAT), and water injection.  The effects of each of these NO  controls on engine CO emission levels
                                                            X


are summarized in Table 6-9 (Reference 6-17).




       As indicated, baseline CO emissions from two-cycle engines are generally  lower  than those



from four-cycle engines.  However, derating two-cycle engines increased CO emissions 50 to 100 per-



cent, while derating four-cycle engines actually gave a 60 to 100 percent decrease in  CO levels.




       Retarding ignition generally caused increased CO output for all engines.  This  is somewhat



expected since retarding ignition decreased both peak combustion temperature and combustion gas res-



idence time.   Both increasing A/F ratios and reducing MAT had little effect on  CO levels.  However,



decreasing A/F caused 50 to 100 percent increases in CO emissions.  Water injection did not affect



CO emissions from gas and dual  fuel  engines, but increased diesel engine CO emissions  by 60 to



130 percent.





6.2.1.4  Gas  Turbines




       The  effects of the commonly implemented NO  control techniques on CO emissions  from gas tur-



bines  are summarized in Table 6-10.   From the table, it is apparent that reducing turbine load
                                                6-30

-------
                           TABLE 6-9.   REPRESENTATIVE EFFECTS OF NOX CONTROLS ON CO EMISSIONS FROM 1C ENGINES
                                       (Reference 6-17)
Fuel
Natural Gas
Diesel
Dual Fuel
Engine Type
2-cycle
4-cycle
2-cycle
4-cycle
2-cycle
4-cycle
Baseline
Emissions
(ng/J)
15 - 40
75 - 3350
72 - 325
114 - 546
165
200 - 670
NO Control CO Emissions (ng/J)
Derate
40 - 94
54 - 150
89
100 - 180
244
289
Retard
Ignition
36 - 45
80 - 1000
140 - 628
260 - 654
244 - 267
679 - 1070
Increase
A/F
29 - 31
a
439
288
Decrease
A/F
117
675
244
296
Reduce
MAT
29 - 45
131
71
142 - 550
67
632
Water
Injection
194
464
460 - 606
503 - 507
denotes no data reported.

-------
       TABLE 6-10.  REPRESENTATIVE EFFECTS OF NOX CONTROLS ON  CO
                    EMISSIONS FROM GAS TURBINES
                    (Reference 6-18)
NO Control
X
Load Reduction




Lean Primary Zone

Air Blast/
Piloted Air Blast
Water Injection



Fuel
Natural Gas

Kerosene

Diesel


Natural Gas
Kerosene
Diesel

Kerosene
Diesel
Natural Gas

Diesel


CO Emissions (ppm)a
Baseline
21
102
981
90
63
53
162
102
102
53
195
969
53
147
252
99
135
93
NO Control
A
357
708
1359
285
441
744
900
51
96
99
59
no
36
1134
1512
144
162
30
3% 02, dry basis.  Baseline emissions at full load.  NOX control emissions
at idle for load reduction; at full load for other NOX controls.
                                  6-32

-------
causes dramatic increases  in  CO  production.   This results because gas turbines are typically designed
to operate at optimum efficiency at full  load.   Under full load, combustion efficiencies in excess
of 99 percent are common.   However, combustion  efficiency drops to 90 or 95 percent under idle
or low power conditions, because firing temperature and fuel/air ratios are reduced at the lower
load.  The partially combusted gases are generated by the incoming dilution air and CO emissions in-
crease significantly.
      The other dry N0x control techniques  for gas turbines, notably leaning the primary zone and
air blast  (or air-assist atomization), generally reduce CO levels.  The additional air introduced
into the combustor  when applying these techniques allows more complete fuel combustion.  Thus,
as shown in Table 6-10, CO emissions decrease.
      Wet control  techniques such as water injection tend to quench combustion and give lower com-
bustor temperatures.  This can lead to incomplete combustion and increased CO levels.   Table 6-10
shows that, indeed, CO emissions increase when  water injection is implemented.
6.2.1.5  Summary
       In  summary,  except  for lowering excess air levels, the available data indicate  that NO
combustion modifications have little effect on  CO emissions from boilers.  Low excess  air causes CO
emissions  increases in boilers.   Most NO  controls increase CO emissions from 1C engines 50 to 100
                                        X
percent.  In  contrast, only load reduction and  water injection cause CO increases in gas turbines.
Dry controls  actually decrease CO levels from these sources.
       It  is  clear, therefore, that certain NO   combustion controls can exacerbate CO  emission
problems from stationary combustion sources.  However, this should cause only minor environmental
concern.  Since stationary combustion produces  only about 1 percent of the total nationwide CO bur-
den, slight increases in CO emissions due to NOV controls in these sources should have negligible
                                               X
impact.
6-2.2 Hydrocarbon  Emissions
      Hydrocarbon  (HC) emissions from combustion sources are of environmental concern because of
their role in the atmospheric reactions leading to photochemical smog.  The terms reactive hydro-
carbons, and nonmethane hydrocarbons have been  applied to this pollutant class, which  includes es-
sentially  all vapor phase  organic compounds  emitted from a combustion source.
      Stationary combustion  sources are only minor contributors to ambient HC levels, accounting
for only about 1 percent of the  total nationwide HC emissions (Reference 6-19).  Nevertheless, the
                                               6-33

-------
 possibility of increased stationary source HC emissions  due  to N0x combustion controls is of defi-



 nite  concern.  Like CO emissions,  as  discussed  in  the  previous subsection, HC emissions arise in



 combustion source exhaust gases because of incomplete  combustion.   The  imposition of certain N0x com-



 bustion modification controls can  result  in decreased  combustion efficiency and thereby increase HC



 levels.




       Three general equipment classes are considered  in  the  following  discussion:   boilers,  inter-



 nal combustion engines, and gas turbines.





 6.2.2.1   Boilers




       Field test programs studying the effectiveness  of  NO   controls often monitor flue  gas  HC
                                                           X


 emissions as a supplementary measure  of boiler  efficiency.  Therefore,  some data  on  the effect of



 these controls on HC emissions are available.




       Two recent test programs on utility boilers routinely  measured flue  gas  HC (References 6-11,



 6-12).  However, in virtually all  tests,  both baseline and low-NO   emissions  were less  than 1 ppm



 (or below the detection limit of the  available  monitoring instrument).  Thus, it  was  concluded that



 HC emissions are relatively unaffected by imposing preferred  NO  combustion controls  on large
                                                               X


 utility boilers.




       A  recent field test program investigating NO  controls  applied to  industrial  boilers reported



 more  comprehensive data (References 6-15, 6-16).  These data  are summarized in  Table  6-11, and show



 that  the  use of NO  combustion controls generally does not affect  flue  gas  HC levels.  Some tests show



 a slight  increase in HC emissions, yet others indicate slight  reductions.   Based  on  these data,  it



 seems fair to conclude that HC emissions  from boilers  are virtually unaffected  when  implementing NO



 combustion controls.  However, this conclusion  is not  altogether unexpected.  The presence of unburned



 HC in  flue gases implies poor boiler operating  efficiency; NO  controls which significantly decrease
                                                              X


 efficiency have found little acceptance.





 6.2.2.2   Internal  Combustion Engines




       In contrast to boiler behavior, the use  of NO  combustion controls on  1C engines can have
                                                    X


 significant effects on HC emissions.   Different NO  reduction  techniques  elicit different effects.




       As shown in Figure 6-2, derating causes  HC emissions to increase.  This  increase becomes



more pronounced as load is reduced.  Derating,  in general, causes  a  20  to 130 percent increase in



HC emissions.
                                                6-34

-------
     TABLE 6-11.   REPRESENTATIVE EFFECTS OF NOX CONTROLS ON VAPOR
                  PHASE HYDROCARBON EMISSIONS FROM INDUSTRIAL
                  BOILERS (References 6-15, 6-16)
N0ฅ Control
A
Low Excess Air





Load Reduction


Of f-Stoi chi ometri c
Combustion
• Overfire Air
• Burners Out of Service

Flue Gas Recirculation
Variable Air Preheat

Fuel
Natural Gas



Distillate Oil
Residual Oil

Coal

Natural Gas


Residual Oil
Natural Gas
Distillate Oil
Residual Oil
Natural Gas
Residual Oil

Residual Oil
Natural Gas
Residual Oil

HC Emissions (ppm)a
Baseline
42
10
17
7
. 3
8
35
11
21
42
17
7
8
5
0
0
0
12
35
0
10
15
35
N0ฅ Control
A
34
0
13
8
9
13
25
18
7
45
18
5
8
0
0
0
0
14
15
0
0
13
25
3% 02>  dry basis.
                                 6-35

-------
                            20
                                                      O 2 cycle, blower scavenged
                                                      Q 2 cycle, turbocharged
                                                      & 4 cycle, naturally aspirated
                                                      ^4 cycle, turbocharged
                                                      G  Natural gas
                                                      DF Dual  fuel
                                                      D  Diesel
40
50
60
Figure  6-2.
                        30
                    % Derated
Effect of derating on 1C  engine HC emissions (Reference 6-17),
    1000 T
      20
                                Degree of retard
             Figure  6-3.   Effect of  retarding ignition on  1C  engine
                            HC emissions (Reference 6-17).
                                        6-36

-------
      Figure 6-3 shows  the  effect of Ignition retard on residual HC emissions.  In contrast to the
effects of engine derating,  ignition retard tends to decrease slightly or not affect emissions of
HC.   However, in cases where retarding Ignition initially reduces HC emissions, increasing the degree
of ignition retard seems to  have little further effect.  The data 1n the figure Indicate that HC
emissions decrease on  the average of 30 percent when Ignition 1s retarded 3 to 8 degrees.
      Changing the  air-to-fuel  (A/F) ratio, decreasing manifold air temperature (MAT) and water
injection result in  increased HC emissions.  As shown in Figure 6-4, both increasing and decreasing
the A/F ratio by 10  percent  increases HC levels 20 to 65 percent.  The larger percentage increases
occur in engines with  high baseline emissions.  Figure 6-5 shows analogous effects  when MAT is  de-
creased.  Decreasing MAT 10  to 20K (20 to 40F) increases HC emissions 5 to 50 percent.  HC levels
increase as MAT is further reduced.  Turbocharged engines exhibit the largest percentage emissions
increase.  Water injection also increases HC emissions from 1C engines regardless  of the baseline
HC level, as shown in  Figure 6-6.  Average increases of 16 to 25 percent have been  experienced  for
water/fuel  (W/F) ratios  of 0.1 to 0.25.
       In summary, derating, changing the A/F ratio, decreasing MAT, and water injection tend to sig-
nificantly  increase  HC emissions from 1C engines.  Retarding ignition has little effect.  Derating,
decreasing  MAT, increasing the A/F ratio, and water injection all lower combustion  temperatures.
Decreasing  the A/F ratio reduces combustion Op availability.  Both of these effects tend to lead to
incomplete  combustion,  which would increase HC emissions.  The unchanged or slightly decreased  HC
emissions with ignition  retard is a somewhat unexpected result.   The combustion  conditions  resulting
from retarded ignition (decreased combustion temperatures and residence times) would be expected
to give  rise to increased HC levels.  The reason this does not occur is unclear at this time.

6.2.2.3  Gas Turbines
      Data on incremental HC emissions from NO  combustion controls applied to stationary gas  tur-
                                               X
bines are quite limited.  However, sufficient data are available to allow tentative conclusions to be
formed.  HC emissions,  like  CO emissions, increase significantly with load reduction in gas turbines.
As shown in Table 6-12,  measured HC emissions at full load fall  in the 3 to 50 ppm range.  Idle fir-
ing, with attendant  reduced  combustion efficiency, increases these levels to the 30 to 230 ppm  range.
      The  effects of  other  dry NO  controls applied to gas turbines are mixed.  As Table 6-12  shows,
staged fuel injection  and air assist atomization, or air blast, increase HC emissions.   In contrast,
leaning the primary  zone tends to decrease HC levels.  Increased combustion efficiency due to higher
combustion temperatures  tends to support this latter observation.
                                                6-37

-------
                                                    Q 2 cycle,  blower scavenged
                                                    ฃT] 2 cycle,  turbocharged
                                                    A 4 cycle,  naturally aspirated
                                                    ^ 4 cycle,  turbocharged
                                                    G  Natural gas
                                                    DF Dual fuel
                                                    D  Diesel
20
        -30
-20
  -10         0          10
Percentage change in A/F ratio
          Figure 6-4.   Effect of  air-to-fuel  ratio on  1C engine
                         HC  emissions  (Reference 6-17).
                                    6-38

-------
                                             O 2 cycle, blower scavenged
                                             Q 2 cycle, turbocharged
                                             A 4 cycle, naturally aspirated

                                             ^ 4 cycle, turbocharged
                                              G  Natural gas
                                              DF Dual  fuel
                                              D  Diesel
                          20         30        40
                           Decrease in MAT (ฐF)
60
       Figure 6-5.   Effect of decreased manifold  air temperature on
                      1C engine HC emissions (Reference 6-17).
 1000
             DF
-3
-^
CD
ฃ 100
                    DF
                0.2
           Figure 6-6.   Effect of water injection on 1C  engine
                         HC emissions  (Reference  6-17).
                               6-39

-------
TABLE 6-12.   SUMMARY OF THE EFFECTS OF NOX CONTROLS ON VAPOR PHASE
             HYDROCARBON EMISSIONS  FROM GAS TURBINES
             (Reference 6-18)
NOX Control
Load Reduction
(


Air Blast

Staged Fuel Injection

Lean Primary Zone
Water Injection

Fuel
Natural Gas

Diesel Fuel


Kerosene
Jet-A

Jet-A

Natural Gas
Diesel Fuel
Kerosene
Natural Gas

Diesel Fuel
HC Emissions (ppm)a
Baseline
13
13
53
3
36
30
18
27
18
9
18
9
33
30
3
27
234
141
36
24
NOX Control
74
230
107
30
126
93
96
111
41
11
1215
24
9-12
12
7
12
372
246
27
12
Comment


Baseline at full
load; NOX
control at idle

Idle
Full load
Idle
Full load
Full load

W/F = 0.5
a3% 02, dry basis.
                              6-40

-------
      The effects of applying wet N0x controls on HC emissions are also mixed.  As indicated in
Table 6-12, with water  injection at a water-to-fuel (W/F) weight ratio of 0.5, HC emissions increased
for turbines having  high  baseline HC emissions, but decreased for turbines which emitted low base-
line HC  levels.

6.2.2.4  Summary
      In summary, it can be concluded that incremental hydrocarbon emissions are of little concern
when applying  N0x combustion modification controls to boilers.  In these instances HC emissions are
either unaffected, or actually decrease, when N0x controls are implemented.  Incremental HC emissions
from stationary  1C engines and gas turbines could be of some concern.  However, these should have
little environmental impact because the HC emissions from these equipment classes are far less than
from,  for example, mobile sources, and contribute minimally to the overall atmospheric burden.
6.2.3  Particulate Emissions
      Although  gas-fired units produce negligible amounts of particulates, oil- and coal-fired
stationary  sources currently emit approximately 28 percent of the nationwide particulate and smoke
(Reference  6-19).  Potential adverse effects on these particulate emissions from NO  combustion con-
trols  could therefore have significant environmental impact.
      The  physical  characteristics of particulates from oil- and coal-fired boilers can vary sig-
nificantly.   Particulate  emissions from oil combustion can be composed of soot (condensed organic
matter), cenospheres (hollow char particles), and ash (incombustible mineral matter).  Coal particu-
late emissions are  largely ash, occasionally containing some unburned carbonaceous residue.  Although
the distinctions between  oil and coal particulate are rarely made in published data, they can be im-
portant  for several  reasons.  For one thing, the composition of emitted particulate can have a large
bearing  on  its size  distribution.  And, because most particulate controls collect large particles
much more efficiently than fine particles, size is a key factor in determining how much particulate
can be collected.   In addition, as discussed in Section 6.2.4, emissions of certain trace metals are
highly dependent on  particle size distribution.  Also, as discussed in Section 6.2.5, sulfate pro-
duction  can be significantly affected by particle size distribution and the availability of catalytic
surfaces.   Finally,  as  discussed in Section 6.2.6, polycyclic organic matter (POM) emissions from
combustion  sources occur  largely as solid phase carbonaceous residue.  Thus, the presence of high
soot emissions or emissions of flyash with high carbon content would indicate the possibility of
high POM emissions.
                                                6-41

-------
       The formation of participates  in a combustion  source  is  intimately related to combustion
aerodynamics, the mechanisms of fuel/air mixing, and  the  effects  of these factors on combustion gas
temperature-time history.  Of course, these are also  the  parameters which control N0x formation.
For example, the effects of burner swirl on N0x production were briefly discussed in Section  4.2.
However, swirl is also an  important factor in determining particulate  emission  levels from a  com-
bustor.  As  Figure 6-7 illustrates, there is generally an optimum value of swirl  for a given  com-
bustion system (Reference  6-20).  Burner swirl can also influence emitted particle size distribu-
tions.  Low  swirl values tend to produce soot in the  10 to 40 ym  range.   Increasing swirl  decreases
formation of these large particles, but overswirling  increases the production of  submicron  soot par-
ticles and reduces the extent of burnout of the largest particles.
       Unfortunately the optimum conditions for reducing  particulate formation  (intense, high tem-
perature flames as produced by high turbulence and rapid  fuel/air mixing),  are  not the conditions
for suppressing NO  formation.  Therefore, most attempts  to produce  low-NO  combustion designs have
been compromised by the need to limit formation of particulates.   This  compromise has  generally
produced designs which maintain a well controlled, cool flame, while still  providing  sufficient gas
residence time to completely burn carbon containing particles.
       The NO  combustion  controls currently receiving the most widespread  application  in boilers
             X
are low excess air, off-stoichiometric combustion (OSC),  flue gas  recirculation (for  gas and oil), and
load reduction or enlarged firebox.   As briefly discussed in Section 6.1, the altered  combustion
conditions resulting from  these modifications can be expected to  influence  emitted particulate load
and size distribution.
       Since smoke and particulate emissions tend to increase as  available  oxygen is  reduced
(soot emissions increase and ash particles contain more carbon),  the degree to which  excess air
can be lowered to control  NO  is usually limited by the appearance of smoke in oil- and coal-fired
                            A
units.   Of course,  the  extent to which excess air can be  limited  depends  on equipment  type and de-
sign.   Many modern  burners can operate on as little as 3  to 5 percent excess air.
       Similarly, the degree to which OSC can be employed is frequently  limited by the degree to
which the primary flame zone can be stably operated fuel  rich, how well  the second stage air mixes
with primary stage  combustion products, and the residence time for combustion in  the  second stage.
Soot and carbon particles  formed in the fuel-rich primary stage tend to  resist  complete combustion
downstream of that  stage.
                                                6-42

-------
    1.0
    0.8
Solids
Burden


    0.6

I by wt
of fuel

    0.4
    0.2
      0
4% 0
                      _L
                  J_
                0.6        0.7        0.8        0.9

                     Tangent of Median Air Angle
                                                   1.0
    Figure 6-7.   Effect of combustion air swirl on solid emissions
                 with oil combustion (Reference 6-20).
                                  6-43

-------
        Flue  gas  recirculafion  on  oil-fired  units  can  decrease participate emissions by providing more



 intimate  mixing.   Kamo,  et al.,  (Reference  6-21)  have  demonstrated  that recirculation rates of 40 to



 50  percent on  a  heater-sized,  oil-fired  furnace reduced the  smoke number significantly.




        Load  reduction  on existing units  and use of enlarged  fireboxes on new units cause reduced



 flame  temperatures  through lowered  volumetric  heat release rates.   Although this could cause in-



 creased production  of  particulates,  the  longer furnace residence  times  accompanying reduced load



 offset this  effect  by  providing more time for  complete combustion.
                                                                         ป


        Few data  from actual  field tests  exist  on  the effect  of  NO   combustion  controls on  particulate



 emissions.   Even  less  data exist  on  particle size  distribution  effects.   This  is  unfortunate be-



 cause  of  the importance  of size distribution in determining  actual  particulate emissions from sources



 with particle  controls.   However, the data  which  have  been reported are  presented and  discussed



 below  for utility boilers, industrial boilers, 1C  engines, and  gas  turbines.





 6.2.3.1   Utility  Boilers




        Published  data  on the effects of  NO  reduction  techniques on particulate emissions  from util-
                                          X


 ity boilers  are scattered and  insufficient  for in-depth analysis.   Table  6-13  summarizes the  par-



 ticulate  emissions  data  obtained  during  two recent  field test programs which studied coal-fired



 utility boilers  (References 6-11  and 6-12).   During these studies,  particulate measurements were



 recorded  under baseline  and  low-NO  conditions.   Since these NO  conditions were  generally  produced



 by  a combination  of low  excess air and staged  combustion, the individual  effect of each technique



 on  particulate emissions cannot be determined.   Nevertheless, the data do show that particulate



 emissions are relatively unaffected by "low-NO "  firing in front wall and horizontally opposed fired
                                               X


 boilers.  Tangentially-fired boilers, on the other  hand, exhibit slightly increased particulate



 emissions under "low-NO  " conditions.
                       X



       The effects of  low-NO  firing on carbon (or  combustible) content of  the particulate  are also



 shown  in Table 6-13.  Although the data are quite  scattered, it appears that carbon losses  increase



 for front wall  and horizontally opposed firing under low-NO  conditions,  but decrease  slightly for



 tangential firing.  However,  the changes are small  and may not  be significant.




       The effects of "low-NO " conditions  on particle size distribution  have  also been investigated



to a limited  extent (Reference 6-11).  The  data from a study of particle  size  distribution  in  three



boilers are  summarized in Table 6-14.  As the  table shows, no significant changes were noted  in two



of the  boilers, both of which were tangentially fired.  In the  third, a  horizontally  opposed boiler,
                                                6-44

-------
                         TABLE 6-13.  EFFECTS OF NOx CONTROLS ON PARTICULATE EMISSIONS FROM

                                      COAL-FIRED UTILITY BOILERS (References 6-11, 6-12)
I
Ul
Firing Mode
Front Wall
Horizontally
Opposed
Tangential
Part icul ate Emissions (yg/J)
Baseline
2.00 - 3.39
1.30 - 1.65
3.29 - 3.83
0.86 - 2.21
1.08 - 1.84
Low NOV
A
1.65 - 2.42
1.34 - 1.78
2.40 - 3.60
2.36 - 2.40
1.23 - 2.95
% Carbon on Parti cul ate
Baseline
5.90 - 6.29
2.8 - 5.5
0.53 - 0.69
24.2 - 25.8
0.92 - 1.98
Low NOX
8.46 - 12.4
6.73 - 11.82
0.18 - 0.46
14.8 - 18.8
0.8 - 1.53

-------
               TABLE 6-14.  EFFECTS OF NOX CONTROLS ON EMITTED PARTICLE SIZE DISTRIBUTION
                            FROM COAL-FIRED UTILITY BOILERS
                            (Reference 6-11)
Equipment Type:
Firing Mode
Tangential
Tangential
Horizontally
Opposed
Firing Condition
Baseline
Low NOX
Baseline
Low NOX
Baseline
Low NOX
Average Weight Percent Particles of Size:
>2.5 pm
81.78
80.74
92.75
93.94
92.56
59.37
2.0 ym
9.12
8.91
2.97
1.89
2.59
10.77
1 .5 ym
2.01
2.28
0.70
0.59
0.62
4.08
1.0 ym
2.64
2.92
0.97
0.86
0.96
5.89
0.5 ym
2.92
3.25
1.21
1.10
1.45
9.55
<0.5 ym
1.55
1.88
1.38
1.61
1.84
10.36
CT1
I

-------
a distinct shift to smaller particles  was  noted.  However, the author reported problems with the
sampling and particle sizing equipment in  this test, so the data may not be significant.
6.2.3.2  Industrial Boilers
      The recently completed  industrial  boiler field test program, previously cited in Sec-
tions  6.2.1.2 and 6.2.2.1  (Reference 6-16), also collected some particulate emissions and size
distribution data that  show the effects of several NO  combustion controls.  These particulate emis-
sions  data from several oil- and coal-fired boilers are summarized in Figure 6-8.   The figure shows
changes  in particulate  emissions versus changes in NO  emissions from baseline conditions as a
function of the applied NOX control.
      As Figure 6-8 shows, the effects of N0x controls on particulate emissions are mixed.   For
example, both forms of  off-stoichiometric  combustion tested increased particulate  emissions  by 15
to 90  percent, while flue  gas  recirculation increased emissions by 10 percent.  In contrast, reducing
boiler load and air preheat decreased  particulate emissions 45 and 65 percent, respectively.  Fur-
thermore, low excess air firing generally  lowered particle emissions 25 to 60 percent.
       This last observation suggests  that the effects of furnace gas velocity on  flue gas particle
emissions were quite significant in these  tests.  Low excess air firing decreases  boiler volumetric
gas flowrate, which in  turn decreases  combustion gas velocities.  With lowered gas velocity, more
particulate would be collected as bottom ash, and more ash would deposit on internal boiler  sur-
 faces.  Therefore, flue gas particulate load should decrease.  Figure 6-7 suggests that this phenom-
enon is  important and offsets  the effects  of decreased combustion completeness expected with lowered
excess air levels.
       The above observations  are in general agreement with those of Heap, et a!., (Reference 6-22)
who studied FGR and staged combustion  applied to two oil-fired packaged boilers.  They found that
smoke  emissions increased  slightly when both FGR and staged combustion were applied.
       Cato, et al., (Reference 6-16)  also reported some very limited particle size distribution
data,  shown in Figure 6-9.  This figure shows that, in a distillate oil-fired boiler,.as excess
air levels are lowered, the emitted particle size distribution shifts slightly to  larger sizes.  A
more pronounced shift to larger particle sizes was observed with reduced load in a residual  oil-
fired  boiler.  However, these  data are much too limited to allow any definite conclusions to be
made regarding the effects of  combustion modifications on flue gas particle size distribution.
                                                6-47

-------
        Combustion Modification Method


  O Air temp,  reduction"  O  Staged air
  Q Reduced  firing rate  O  Burner tuneup
  ^ Flue gas recirc.      <ฃ>  Burner-out-of-service

     Reduced  excess air
t
TD
•r-
X
O
QJ
0)
O
•r—
ns
O
c
tu
01
C
O
O
Q •
J.......-.......-.....-.-.........-...-.I...-.....-.-.-.-.... 	

lilป^^^^^^^^^^^^^^^
Best quadrant x:x:x:::x:x|
- +40
- +30
• +20
. +10
0
- -10
A O
•0 C
O
- -30
- -40
0
Worst quadrant
	 1 	 Q 	
+100

      -  ซ- Change in particulates, % -> +
Figure 6-8.   Effect of NOX controls on solid
             particulate emissions from in-
             dustrial  boilers (Reference 6-16)
                     6-48

-------
        TOO
<7I


10
  -a
  o>
t- v>
B  l^
o    •"
IJ .10 r~
 
-------
6.2.3.3   Internal Combustion Engines
       Because  it is quite difficult, time consuming,  and  expensive to measure particulate emissions
from  1C engines directly, virtually no data are available  on  particulate  emission rates from this
equipment class.  Instead, exhaust gas opacity readings have  been  used as a  measure of the particu-
late  emissions.  These readings effectively measure the particulate since a  relationship between
visible smoke and particulate mass emissions has been  established  for  medium power diesel  engines
(References 6-23 and 6-24).  Therefore, 1C engine smoke emissions  are  generally reported as  per-
cent  plume opacity, or as Bosch or Bacharach smoke spot numbers.
       The plumes from most larger bore engines are nearly  invisible when the engine  is operating
at steady-state.  However, applying NO  combustion controls can significantly affect  smoke emissions.
Figure 6-10 shows the relationship between smoke emissions and NO   reduction  as  a function of NO
                                                                 X                             X
control for those engines where data were reported on  both pollutants.  As the  figure  shows, NO
controls  (other than derating) generally increase smoke emissions,  while  derating decreases  smoke
levels.   Ignition retard and exhaust gas recirculation (EGR)  cause the most  significant increases
in smoke  level.
       Since NO  controls which caused smoke levels to exceed 10 percent  opacity  were  considered
               X
unacceptable in the tests summarized in Figure 6-10, none of  the data  points  for  controlled  engines
are above this value.  However, the effect of progressively applying ignition  retard and EGR on
smoke emissions is best demonstrated by data which include higher  smoke levels.   Such  data are
presented in Table 6-15 for two-cycle diesel engines, and clearly  show that  smoke emissions  in-
crease progressively as percentage EGR or degree of retard is increased.

6.2.3.4  Gas Turbines
       The data on particulate emissions from gas turbines resulting from applied NO   controls are
                                                                                    X
also very limited.  However, the available data indicate that incremental particulate  emissions from
N0x controls follow trends similar to those for incremental CO and hydrocarbon  emissions.
       Figure 6-11 shows the effect of turbine load on particle emissions.   Like  CO and HC emissions
(as discussed in Sections 6.2.1 and 6.2.2), particle emissions increase as turbine load is reduced.
As the figure shows, particulate emission increases average 40 percent when  turbine load is  de-
creased .to 30 percent of rated capacity.
                                                6-50

-------
en
i
en
              01
              _Q
              o
              CL
              -C
              u
              
-------
    TABLE 6-15.  RELATIONSHIP BETWEEN SMOKE,
                 EGR, AND RETARD
                 (Reference 6-17)
Engine Type
2-cycle, Blower
Scavenged Diesel





2-cycle,
Turbocharged Diesel


Control3
None
10% EGR
20% EGR
39% EGR
4ฐ advance
None
4ฐ retard
None
4.9% EGR
8.4% EGR
12.1% EGR
Opacity, %
4.7
12
27.5
59
2.7
4.6
10
7.5
10.0
11.5
14.8
 All  EGR data based on hot EGR.
"'injection advance is not a control; data
 included to show trend.
                      6-52

-------
   30
   25
 CD
 t/1

 o
•r—
 in
 C/)
 QJ

 O)
•(->
 10

 3
 O
   20
   15
(O
o.
   10
                                       T
                          X Oil-kerosene  mixture

                          Q Kerosene

                          ANo. 2 oil

                          ONo. 2 oil
                                                     4
                                                        i
                                                         *
     i     i     i    i     i    i     i     i     i
0   10   20   30  40   50  60   70   80   90  100
          %  of gas  turbine peak load
 Figure  6-11.  Gas turbine  particulate emissions  as  a
                function  of  load (Reference 6-25).
                            6-53

-------
       The effect of water injection on particle emissions seems  to  be  related to the specific  in-
jection method used (Reference 6-18).  Some tests show smoke  level reduction  of 1.5 to 1.75 smoke
spot numbers when water injection is used.  Other tests, however, indicate  increased participate
emissions with water injection at peak load.

6.2.3.5  Summary
       In summary, the effects of NO  combustion controls on  particulate emissions  from stationary
                                    A
sources  have been insufficiently studied.  The available data are, in general, too  limited  to form
firm conclusions.  However, some tentative observations are possible:
       •   Only off-stoichiometric combustion seems to adversely  affect parti oil ate emissions from
           boilers
       •   All NO  controls except derating cause increased smoke levels from 1C  engines
       •   Load reduction increases gas turbine particulate emissions
More substantial data — particularly on particle size distribution —are needed to  fully assess the
effects that NO  controls have on particulate emissions.

6.2.4  Trace Metals
       Emissions of trace metals are a concern for combustion sources firing  coal and  residual  oil.
They are a lesser problem in sources firing distillate fuels  since trace metal concentrations in
distillate oils are generally much lower than those in residual oils.  Trace  metals  from stationary
sources are emitted to the atmosphere with the flue gas either as a vapor or  condensed on particu-
late.  The quantity of any given metal emitted, in general, depends on:
       •   Its concentration in the fuel
       •   The combustion conditions in the boiler
       •   The type of particulate control device used, and its collection  efficiency  as a function
           of particle size
       t   The physical and chemical  properties of the element itself
       For present purposes,  the trace metal  composition of the fuel  is considered  a  given quantity,
not subject to manipulation.   Therefore although composition  has a controlling effect  on the abso-
lute trace metal  emissions from a combustion source, it is not considered as  a factor  to explain
the effects  N0x controls  have  on incremental  trace metal emissions.
                                                6-54

-------
      It has become widely  recognized that some trace metals tend to concentrate In certain waste
particle streams from a  boiler (bottom ash, collector ash, flue gas participate), while others do
not (References 6-26 through 6-32).   Based on this phenomenon, three classes of partitioning metals
have been defined  (Reference 6-26).
      •    Class  I:  20 metals (Al, Ba, Ca, Ce, Co, Eu, Fe, Hf, K, La, Mg, Mn, Rb, Sc, Si, Sm, Sr,
           Ta,  Th,  and Ti).   These are found in the bottom ash or slag, the particle collector in-
           let  flyash, and the collector outlet flyash in approximately the same mass concentrations.
      •    Class  II:  9 metals (As, Cd, Cu, Ga, Pb, Sb, Se, Sn, and Zn).  These are not usually found
           in bottom ash or slag, but are found in flyash.  Mass concentrations in particle collector
           inlet  flyash  are generally less than in collector outlet flyash.
       •    Class  III:  Hg, and possibly Se.  These are usually emitted as vapors in the flue gas.
 Another set of  elements  (Cr, Cs, Na, Ni, U, and V) exhibits properties intermediate between Classes I
 and II.
       Other work has shown that the Class II metals, As, Cd, Pb, Sb, Se, and Zn, along with Ni,
 Cr,  and V become  increasingly more concentrated in flyash particles as particle size decreases
 (Reference 6-27).   Cd,  Pb, Ni, Sb, Se, Sn, V and Zn all appear to have a mass mean diameter (MMD)
 of less than 1  ym in the atmosphere.  The more common Class I metals, Fe, Al, and Si, have MMDs
 of 2.5 to 7.0 urn  (Reference 6-33).
       The most logical  explanation for this segregation behavior involves a volatilization-
 condensation mechanism (Reference 6-26).   In its simplest form, the argument says that Class I
 metals have boiling points sufficiently high that they are not volatilized in the combustion zone.
 Instead,  they form a melt of relatively uniform concentration, which becomes both bottom ash or slag,
 and flyash.  Thus, Class I elements remain in a condensed phase throughout the boiler and show little
 partitioning with particle size.  By contrast, Class II metals have boiling points below peak com-
 bustion temperatures,  so they are volatilized in the combustion zone and do not become incorporated
 in the slag. As  combustion gases cool by traveling through the boiler, these elements either form
 condensation nuclei or condense onto other available solid surfaces (predominantly Class I mineral
 particles).  Since the available surface area to mass ratio increases as particle size decreases,
 the Class II elements concentrate in small particles.  This partitioning mechanism is further sub-
 stantiated by observations that certain Class II metals exhibit higher surface concentrations than
 bulk concentrations in  fine particles (Reference 6-34).
                                                6-55

-------
       This simple mechanism described above does  not  fully  account for all  experimental observa-
 tions.   For example, Ca and Cu behave as high boiling  point  metals, whereas  Rb,  Cs, and Mg behave
 as volatile elements.  Therefore, the volatilization-condensation  mechanism  has  been extended  as
 follows  (Reference 6-24):
       •  Trace  elements  in coal are present as aluminosilicates, sulfides, and organometallics
       •  On  combustion,  the aluminosilicates melt  to form  slag or bottom ash,  and flyash
       •  In  the reducing atmosphere during initial stages  of  combustion, metal  sulfides  are  re-
           duced  to  vapor  phase metal; at  the same time the  organic matrix of organometallics
           oxidizes, leaving volatilized metal
       •  Volatilized metals may themselves become  oxidized to less volatile oxides
       •  As  the combustion gas cools, these volatile species  condense onto available  solid sur-
           faces,  and concentrate in small particles
       •  Since  slag and  flue gas are in  contact  for  only a short time,  little  volatile condensa-
           tion in slag occurs
 This  extended  mechanism is indirectly supported by the fact  that Class  I  metals  are largely geo-
 chemical  lithophiles (readily associated with aluminosilicate minerals),  while Class II  metals are
 largely  chalcophiles (readily incorporated into sulfide minerals).
       In all  mechanisms the Class III metals, Hg  and  to some extent Se,  remain  vaporized  through
 the stack and  are emitted  as flue gas vapor components.  Some 90 percent  of  Hg emissions (Ref-
 erence 6-35) and about 20  percent of Se emissions  (Reference 6-26)  are  emitted as vapors.
       Regardless of the exact mechanism for the trace metal partitioning phenomenon, the  partition-
 ing significantly influences trace metal  emissions from combustion  sources with  particulate control
 devices.  All  particle collection devices are more efficient at collecting large particles than
 small particles.  Since Class II metals in flyash  occur in smaller  particles than Class  I  metals,
 a larger fraction of the Class II elements introduced  into a boiler will  be  emitted'from sources
 equipped with  particulate control units.
       This behavior is illustrated by recent trace metal emissions data  from industrial boilers
 (Reference 6-36).   Figure 6-12 shows the concentration  of several  Class  I metals measured  in
 particle samples from different points in a coal-fired  industrial  boiler.  Figure 6-13  shows the
 same profile  for several  Class  II elements.  As the partitioning theory predicts, the concentration
of Class  I metals  remains  fairly constant throughout the boiler.   On the  other hand, flyash
                                                6-56

-------
en

01
en

en
in
c.
o
c
OJ
o
c
o
u
c
0)
E

-------
     10
      5    -- Arsenic
o
c
o
(J
      0
     10
  0

200


100



200


100

  0
 20
      0
    200
      0

  1,000
            • Cadmium
            - Copper
            • Lead
    2.5    -.Tin
    100    --Zinc
    500
             Coal
            X X  Xx
     10    • • Selenium
         Vanadium
            X  X  X  X
                     Furnace
                     bottom
                                 / / / / s
 Upstream
    of
collector
    In
collector
Downstream
    of
col lector
                                                              ^/ / /
                                                                   y
         Figure  6-13.   Partitioning of Class II elements (Reference 6-36).
                                       6-58

-------
concentrations of Class  II  elements increase toward the flue gas exit.  The expected increase  in
concentrations in the  collector effluent ash over collector inlet ash and collected ash is quite
significant.
       By  understanding  trace metal partitioning and concentration in fine particulate, it is  pos-
sible to postulate  the effects N0x combustion controls will have on incremental trace metal emissions.
Several NOX  controls for boilers result in lowered peak flame temperatures (off-stoichiometric com-
bustion, flue gas recirculation, reduced air preheat, load reduction, and water injection).  The
volatilization-condensation theory predicts that if the combustion temperature is reduced, less
Class II metal will  initially volatilize, hence less will be available for subsequent condensation.
Under these  conditions (lowered flame temperature), it is expected that less Class II  metal (the
segregating  trace metals discussed in Section 6.1) will be redistributed to small particulate.
Therefore, in boilers  with-particulate controls, lowered volatile metal emissions should result.
Class I metal (the  nonsegregating trace metals discussed in Section 6.1) emissions should remain
relatively unchanged.
       Lowered local CL  concentrations are also expected to affect segregating metal  emissions from
boilers with particle  controls.  Lowered 02 availability decreases the possibility of volatile metal
oxidation  to less volatile  oxides.  Under these conditions Class II metals should remain in the vapor
phase into the cooler  sections of the boiler.  More redistribution to small  particles  should occur
and emissions should increase.  Again, nonsegregating metal emissions should be unaffected.  This
behavior  is  expected when low excess air is implemented.  Other combustion NO  controls which de-
crease local Op  concentrations (OSC and flue gas recirculation) also reduce peak flame temperature.
For these, the effect  of lowered combustion temperature is expected to predominate.
       The effect of NO   combustion controls on segregating metal emissions from combustion sources
without particle collection devices should be marginal at best.  Particle redistribution will not
affect mass  emissions  because all particulate produced is emitted from these sources.   However, since
trace metal  condensation on internal boiler surfaces undoubtedly occurs, conditions which decrease
the extent of Class II metal  volatilization (lowered peak flame temperature) should cause a slight
increase  in  segregating  metal emissions.  Conversely, conditions which increase metal  volatility
(low local Q2 concentrations) should cause slight decreases in volatile metal emissions.
       No  data currently exist to document the above speculations.  However, such data should  be
easy to obtain in forthcoming emissions assessment programs, if the effects of N0x controls are
studied in test  matrices.  Obtaining such data should be given relatively high priority since  8  of
the 20 most  toxic elements  in air are Class II metals (Reference 6-37).  Changes in the emission
levels for these metals  can have significant environmental impact.
                                                6-59

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 6.2.5  Sulfates
       Ambient sulfate levels are a matter of  increasing concern  in  regions  with  large  numbers of
 combustion sources firing sulfur-bearing coal  and oil  (notably, the  northeast  region  of the U.S.).
 Although  the  direct health effects of high ambient sulfate levels are currently unclear (Refer-
 ences  6-38 and 6-39), high sulfate aerosol concentrations are  known  to  decrease visibility and
 aggravate acid precipitation phenomena.
       Ambient sulfates are comprised of directly emitted sulfates (primary  sulfates) and those de-
 rived  from the atmospheric oxidation of S02  (secondary sulfates).  However,  the relative contribu-
 tion of each  of these to ambient levels is presently unclear.  Recent estimates indicate that pri-
 mary sulfates comprise about 5 to 20 percent of the ambient sulfate  on  a regional basis  (Refer-
 ence 6-39).   However, regional transport processes are extremely  important in determining local
 ambient levels, especially in the Northeast.   Consequently, it is difficult  to separate the effect
 of  secondary  sulfate production from the effect of transported primary  sulfate on a region's ambient
 sulfate level.
       Although the plume chemistry of secondary sulfate formation has  not yet been fully described,
 it  is  generally recognized that SCL can be oxidized to sulfate through  the five mechanisms summarized
 in  Table  6-16.  Of these, it is generally concluded that the first mechanism is of minor importance
 (Reference 6-39).  Similarly, the importance of mechanism 3 is thought  to be minor when compared to
 mechanisms 4 and 5.
       The relative effects of mechanisms 2, 4, and 5 are currently  unknown.  Ambient vanadium
 appears to be strongly related to ambient sulfate, even though vanadium is a high temperature SO-
 oxidation catalyst and is ineffective at room  temperature (Reference 6-41).  Weaker correlations
 exist  between ambient sulfate and ambient iron and manganese.  However, ambient sulfate does not
 correlate with ambient N02 at all  (Reference 6-39).  These facts would  seem to indicate that the
 catalytic mechanisms are the more significant  in producing secondary sulfates.
       On the other hand, recent power plant plume measurements show that the conversion of SO- to
 sulfate aerosol  is essentially zero for the first two hours of plume residence time,  but increases
 quite rapidly thereafter (Reference 6-42).   This could be due to solution pH limitations.  It is
 interesting,  however,  that this time compares quite favorably to the 20 to 90 minute  residence
 time required for the  NO/NO  ratio in a plume to reach an "equilibrium" value of about  0.5, as re-
                           X
 ported by Gordon et al.,  (Reference 6-43).   It is known that NO inhibits S0? oxidation  (Reference
6-44)  presumably by scavenging oxidizing agents (notably ozone).  However work by Davis  et al.,
 (Reference 6-45)  has attempted to  suggest an even more intimate relationship between  ML, NO, and
                                                6-60

-------
        TABLE 6-16.  MECHANISMS THAT CONVERT SULFUR DIOXIDE TO SULFATES (Reference 6-40)
       Mechanism
         Overall Reaction
              Factors  on  Which  Sulfate
            Formation Primarily Depends
1.  Direct photo-
    oxidation
    Indirect photo-
    oxidation
    Air oxidation in
    liquid droplets
4.  Catalyzed oxidation
    in liquid droplets
5.  Catalyzed oxidation
    on dry surfaces
SO,
SO
SO,
NH
          light, oxygen
              water
         smog, water, NO
H2S04
                             2     organic oxidants,
                                 hydroxyl radical (OHซ)
M cr\
"2OU4
           liquid water
                             3   "23
                                                           so:
en     oxygen,  liquid water  ^ SQ=
  2      heavy  metal ions        4
en     oxygen, particulate    „ ^.n
S02       carbon, water     ^ H2bU4
Sulfur dioxide concentration,
sunlight intensity
Sulfur dioxide concentration,
organic oxidant concentration,
OH, M)
         Ammonia concentration, pH
         Concentration of heavy metal
         (V,  Fe,  Mn)  ions, pH
         Carbon particle  concentration
         (surface area)

-------
SOp oxidation.  Existence of this relationship is coupled with  in-plume  production  of ozone  and the
appearance of an "ozone bulge" within the plume.  In support, Levy and Spicer  (Reference  6-46) con-
clude that, although Davis1 postulated reaction sequence is questionable, the  possiblity  of  inter-
actions between NO  photochemistry and sulfate production does  exist and certainly  deserves  further
elucidation.
       Regardless of the possible impact of secondary sulfate production on ambient sulfate  levels,
it is clear that keeping primary sulfate emissions to a minimum is highly desirable.   Since  some
98 percent of the sulfur introduced into a combustion source generally appears in the  flue gas, the
present discussion will assume that one has no control over total sulfur oxide emissions  (the exis-
tence of fuel desulfurization and flue gas desulfurization techniques is ancillary).   Therefore,
the focus here will be on ways to keep the SCL/SCU ratio at a minimum.
       In the present discussion, primary sulfate emissions will be defined as all sulfate emitted
from the stack plus the amount produced in about the first half mile of plume  travel.  These sul-
fates may exist as either sulfuric acid (H^SO.) or as metal or  ammonium sulfates (denoted here as
S07).  The fraction of HpSO, (measured as SO,) in the sulfur oxides emitted from boilers  ranges from
1 to 3 percent from coal-fired sources to 5 to 9 percent for oil-fired boilers (Reference 6-47).
SOT emission levels have not yet been clearly established, though it is thought that these at least
equal H2SO. emissions (Reference 6-48).
       The precise mechanisms for the formation of sulfates in  combustion systems are  not completely
understood.  However, it seems clear that two processes contribute to final flue gas sulfate levels.
The first is homogeneous S02 oxidation in the flame through the reaction:
                                       S02 + 0 + M = S03 + M                                  (6-1)

Although SO- is the thermodynamically favored product at high temperatures, it is currently thought
that some S03 is formed through Equation (6-1).  Subsequent rapid gas quenching then freezes the sys-
tem into a nonequilibrium state.   In any event, any SO, formed  through this reaction will, under
flue gas conditions, combine with available water vapor to form vapor phase sulfuric acid.  This
sulfuric acid will  then either absorb or condense onto available particulate and be emitted as an
aerosol or, in the absence of sufficient particulate, as a vapor which condenses to acid  mist as
soon as plume temperature drops below its acid dew point.
       The second important sulfate formation mechanism is catalyzed heterogeneous S0? oxidation in
post-combustion regions by flue gas particulates and internal boiler deposits.  Several potential
                                                6-62

-------
oxidation catalysts exist  in  suspended and deposited flue gas particulate, including vanadium,
nickel,  iron, manganese  oxides,  and carbon (soot).   Vanadium pentoxlde (VgOg) is a well known
and quite effective oxidation catalyst in the 400 to 700ฐC temperature range.  It is, in fact, used
in the contact  process for the manufacture of sulfuric acid.  However, Fe20, also catalyzes S0?
oxidation at 450  to 850C (Reference 6-49), and Mn02 is an effective catalyst from room temperature
to at least 340C  (References  6-41,  6-50).   Finally, Novakov (Reference 6-51) has recently shown
that even freshly generated soot and graphite particles convert S02 to SO,.
       A third  mechanism,  usually considered to be of importance only in secondary sulfate formation,
deserves some comment here.  This is mechanism 4 in Table 6-16, catalytic oxidation in solution.
Under normal conditions, the  pH  of near plume liquid droplets is low, approximately 3.  At this pH,
SOy solubility  is quite  low,  so  solution chemistry normally contributes negligibly to primary sul-
fate levels in  the near  plume.  However, if sufficient quantities of a basic specie, such as ammonia,
were present to neutralize these droplets, S02 solubility would increase dramatically, leading to
significant amounts of sulfate production through solution catalysis in the near plume.   Consequently,
the use of  post-combustion ammonia injection for NO  control could possibly lead to significantly
increased primary sulfate  emissions.  Of course, much further work is needed in  this area before  any
conclusions can be substantiated.
       It is  important to  note that each of the above mechanisms operates in a different region of
a boiler,  because each has different temperature requirements.  This fact is illustrated in Fig-
ure 6-14, which shows the  relative importance of each mechanism as a function of temperature regime
and corresponding boiler region-  In the flame zone, temperatures are high and sulfate is expected
to be formed  by rapid homogeneous gas phase oxidation.  This corresponds to curve A in the figure.
However, at somewhat  lower temperatures, in the boiler's convective passes, homogeneous reaction
rates are too slow to contribute significantly to sulfate formation.  At these temperatures, cataly-
tic mechanisms  should be most important, as illustrated by curves B and B'.  Curve C represents
solution chemistry and curve  D represents indirect photo-oxidation (mechanism 2 of Table 6-16).
Both of these are normally of importance only in secondary sulfate production.
       The  relative  importance of each mechanism in determining final sulfate levels is not presently
known.  Thus, two curves,  B and  B', are shown in Figure 6-14.  (The two curves also indicate that the
temperature range of  importance  is also uncertain.)  However, it is currently thought that flyash/
soot catalysis  is at  least as important a mechanism in forming sulfate as the high temperature homoge-
neous mechanism.   This view is indirectly supported by the fact that H2SO./S02 ratios from oil-fired
                                                 6-63

-------
en
i
en
                     O>
                     03
                     O
                     ro

                     -P

                     -Q
                     S-
                     fO
OJ
o
G
fO
4-J
.i.
O
CL
                     c
                     (D
                     o
                     OJ
                           0

                           I
                           Residence time  (sec)

                                 10

                          	I
                                                        3600

                                                          I
      Flame
                                     Convection
name  i   lonvection    i       i                     I  Far plume.
zone  ""[   section     *|  stack*|    Immediate plume *T ambient
                           Primary
                           sulfates
                                                      air


                                                       Secondary
                                                     k sulfates
                   High T, homogeneous

                                             B1
                                   Intermediate T,
                                   dry gas-solid
                                   heterogeneous
                                                                                   Photochemical
                           1900
                                175

                             Temperature,  ฐC
                                                      Solution
                                                      chemistry
                        Figure 6-14.  Sulfate formation regimes of  importance  (Reference  6-48).

-------
sources are higher than those  from  coal-fired sources.  Residual oils generally contain more
vanadium and nickel than coal.
      Based on the above,  it  is  possible to speculate on the effects NO  controls might have on
primary sulfate production.  Since  primary sulfate emissions are largely dependent on combustion gas
oxygen availability, boiler temperature-time history, and internal  catalyst availability, combustion
modifications which alter these parameters should affect the amount of SCL converted to sulfate.
      Reduced oxygen availability  should definitely tend to decrease primary sulfate emissions.
Thus, N0x controls which result in  decreased local oxygen availability (e.g., low excess air firing
and off-stoichiometric combustion)  should result in lowered sulfate emission levels.   In fact,
Archer, et al., (Reference  6-52)  have shown, in pilot scale work on two-stage combustion, that SO,
levels  leaving the first combustion stage can be reduced to essentially zero when this stage is
fired fuel rich.
      The effects of boiler temperature time history on sulfate production are significantly more
difficult to sort out because  of  the lack of knowledge about in situ catalytic mechanisms and their
relative importance with respect  to homogeneous SO,, oxidation.   However, the effects  of NO  con-
                                                  C,                                       X
trols on boiler temperature profile and the effect of temperature on oxidation catalyst availability
follow from  the trace metal  discussion presented in Section 6.2.4.   Vanadium, nickel  and their oxides,
which are active S02 oxidation catalysts, are also metals which partition to fine particulate, as  dis-
cussed in Section 6.2.4.  -Therefore, conditions which promote the redistribution of these metals to
accessible surfaces (e.g.,  boiler tubes and other internal boiler surfaces in addition to flue gas
particle surfaces) should promote increased sulfate production.  Thus, as discussed in Section 6.2.4,
combustion conditions which facilitate volatilization-condensation  and partitioning,  such as high  peak
flame temperatures, should  promote  S02 oxidation.   Conversely,  combustion controls which, for example,
lower peak flame temperatures, should decrease sulfate productions.
      Based on the above,  it  is  expected that combustion modifications which lower local 02 levels
(such as low excess air firing),  which lower peak flame temperature  (such as flue gas recirculation,
reduced air preheat, and water injection), or which do both (such as OSC), will decrease the amount
of S02 oxidized to sulfate.  Of course,  care must be taken when implementing any of these controls
not to stimulate excess particulate production.   The catalytic  effects of internally  deposited soot
or flyash could overcome the beneficial  effects  of lower 02 concentration and reduced catalyst
repartitioning.
                                               6-65

-------
       Data confirming these conclusions,  though sparse,  do  exist.   Recent measurements have demon-
strated the expected dependence of sulfate emissions  on  boiler excess  air levels.   Bennett and  Knapp
(Reference 6-53) have shown that particulate sulfate  emissions increase with increasing boiler  excess
02 in oil-fired power plants.  Homolya, et al.,  (Reference 6-47)  report a similar  increase in sulfate
emissions as a percentage of total sulfur  emissions with  increasing  excess 02 in coal-fired boilers.
Their data, shown  in Figure 6-15, show a linear  relationship between the sulfate fraction  of emitted
sulfur and boiler  excess CU-
       Other data  (Reference 6-54),  shown  in Table 6-17  also show that S03 emissions  decrease when
OSC is used to control NO .
       The situation in coal-fired boilers equipped with  electrostatic precipitators  (ESPs)  for
particulate control deserves some further comment.  It is well  known that SO., (or more  appropriately
sulfuric acid) serves to condition low resistivity flyash and  improve  ESP performance in collecting
these particles.   Therefore, it is conceptually possible  that  a decrease  in  primary sulfate  produc-
tion could give rise to increased particulate sulfate emissions.  Though  the  phenomenon seems some-
what unlikely, further work on this  question is definitely needed.
       The problem of acid smut emissions, which is also  related  to  sulfate  formation,  also deserves
some discussion here.  Emissions of  acid smut (large  "globs" of highly acidic  carbonaceous particu-
late) have been experienced recently in several residual  oil-fired utility boilers in the  U.S.
Acid smuts are extremely corrosive and their large size  (up  to  lOOy) leads to  fallout in the vicin-
ity of the power plant.   They are thus of concern both for potential impact on both human  health and
welfare.  Acid smut emissions have been experienced for many years in  Europe  due to their  practice
of firing heavy oil units at lower levels of excess air than was  common  in the U.S. (References  6-8
and 6-55 through 6-58).
       Recently the problem has occurred when certain NO  controls, notably off stoichiometric com-
bustion combined with low excess air, are implemented on  residual oil-fired  units.  It  also  invar-
iably occurs in boilers which were originally designed to fire natural   gas,  but have been  converted
to oil  firing because of fuel  availability problems.
       The exact reasons for the appearance of acid smut emissions are not clearly understood.
However, it is clear that they are related to air heater design and the resulting final flue gas
temperature.   Since natural  gas contains very little1 sulfur, acid mist condensation in  and down-
stream of the air heaters has  never been a concern.  Therefore, air  heaters  in gas-fired boilers
have been designed to give lower flue gas temperatures than corresponding air heaters in oil-fired
                                                 6-66

-------

-------
TABLE 6-17.  S0ฅ SUMMARY (Reference 6-54)
               n

Baseline
LEA
OSC
02 (X)
Boiler
Exit
2.9
1.55
1.5
3.1
3.4
Stack
6.8
5.7
7.72
7.1
so2
S03
ppm Corrected to 3%
ฐ2
944
948
1,000
Avg 974
1,010
968
Avg 989
28
13.5
35.9
Avg 25
14.0
13.9
Avg 14
                    6-68

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units.  However, when these  same  gas-fired units are switched to oil firing, it is possible for
flue  gas temperatures downstream  of the air heater to approach the acid dew point.  In the absence
of parti oil ate emissions,  flue  gas  sulfuHc acid would then condense and reevaporate through the
ductwork and stack  until  ultimately emitted as a finely dispersed mist.
       The appearance of  acid smut  emissions when implementing NO  controls which enhance the pro-
duction of soot  particles  suggests  the possible next step in the smut formation mechanism.  In the
presence of sufficient  particulate, flue gas sulfuric acid condenses onto particle surfaces in suf-
ficient amounts  to  cause  particle agglomeration.  Agglomerated particles then deposit onto ductwork
walls.  These  deposits  continue to  grow through further agglomeration until they become large enough
to spall off the wall.  Thus, emissions of wet acidic "globs" or acid smut occur.
       In  light  of  the  above, acid  smut emissions have been viewed as a combined sulfate production
problem and particulate production  problem.  Attacks on the problem have included both reduction of
acid formation and/or condensation  and suppression of carbon formation or agglomeration.   Table 6-18
summarizes process  modifications  used or proposed in Europe and the U.S. (References 6-55 through
6-58).   It appears  that incremental emissions of acid smut can be suppressed if addressed during
control development.  The potential for acid smut emissions should be considered when implementing
NO  controls on  heavy oil-fired boilers with preheaters and without particle collection devices.

       In  summary,  the  postulated,  and in some cases demonstrated, effects of most NO  combustion
                                                                                     X
controls on primary sulfates are  to decrease emissions or leave them unchanged.  However, since
there are  insufficient  data  to fully substantiate any real conclusion, it seems appropriate to con-
sider incremental sulfate emissions due to NO  combustion modifications of questionable concern,
                                             A
except in  the  case  of acid smuts  and use of post-combustion ammonia injection.  Because ammonia injec-
tion may significantly  increase near plume sulfate production through solution chemistry, its effects
on residual sulfate should be considered of definite concern.
6.2.6  Organics
       In the  true  sense,  the class of organic compounds includes virtually all carbon-containing
compounds except carbon monoxide  and carbon dioxide.  In the present discussion, however, "organics"
will  be used to  describe  only those species not included in the class of compounds referred to as
the criteria pollutant, "hydrocarbons".  Therefore, with few exceptions, hydrocarbon emissions,
discussed in Section 6.2.2,  will  include essentially all organic compounds emitted in the vapor
phase at flue  gas temperature.  The remaining organic emissions, discussed here, are composed
                                                6-69

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                                              TABLE 6-18.   SUMMARY OF PROCESS MODIFICATIONS TO REDUCE ACID SMUT FALLOUT

                                                           (References 6-55 through 6-58)
en
t
Principle
1. Suppress buildup
of acid smut
2. Prevent acid
condensation
3. Neutralize acid
smut
4. Suppress SO,
formation
5. Reduce carbon
emissions
6. Particle
collection
Candidate Techniques
Frequent or continuous
soot blow
Reduced air preheat
Additives: dolomite,
limestone, MgO, NH,
Reduced excess air
Reduced load
Reduced catalytic
activity of superheater
Reduced sulfur in fuel;
mixed distillate/resid.
firing
Increased excess air
Better firebox mixing
Fuel pretreatment to
remove heavy carbon
compounds
Cyclone, ESP or baghouse
Size Range Affected
Large particles
Large particles
Large and small
particles
Large and small
particles
Large and small
particles
Large and small
particles
Large and small
particles
Large and small
particles
Large and small
particles
Large and small
particles
Large and small
particles
Comments
Acid smuts emitted in smaller, dispers-
able, size range; successfully tested at
Eastern Utility; promising option
Reduced efficiency; possible smut buildup
in stack at reduced size range
Reduces (50%) but doesn't eliminate acid
emissions; additives increase particle
loading
Increased efficiency; increased carbon
and CO emissions; limited by NO control
techniques
Not cost effective
Additive coating is partially effective;
operational problems
Distillate availability uncertain
Reduced efficiency; increased S03
Limited by NOX controls
Effective but costly

-------
largely of compounds emitted  from combustion sources 1n a condensed phase.  These compounds can
almost exclusively be classed Into a group known variously as polycycllc organic matter (POM) or
polynuclear aromatic hydrocarbons (PNA or PAH).   The following discussion, then, treats POM emis-
sions from stationary combustion  sources and the effects of NOX controls on these emissions.  In
addition, a discussion  of  nitrosamines is included 1n this subsection, since this class of com-
pounds is quite  important  from an environmental  health standpoint and is not discussed elsewhere.
      Although  polycyclic organic matter can conceivably be formed in the combustion of any hydro-
carbon fuel,  it  is considered more of a problem when associated with soot (carbonaceous particulate)
emissions from coal and oil-fired combustion equipment.  POM is especially prevalent in the emissions
from coal burning, because a  large fraction of the volatile matter in coal (coal tar) is preexisting
POM.
      Although  the precise mechanism of POM formation in flames is complex and variable,  it is pos-
sible to  form a  relatively clear  picture of the overall reaction.   In a reducing atmosphere, at tem-
peratures around 2.000K (conditions common in the center of flames) radical species  of the form,
 • •          •
HC=CH and RCH=CH,  can  rapidly combine and form large polynuclear aromatic molecules  through radical
chain propagation  (References 6-2, 6-59).  As combustion gas cools and chain propagation is quenched,
a variety of  POM species can  remain when combustion is incomplete.  Upon further cooling,  these
species  condense and are emitted  largely as soot or high carbon content particulate.
       POM  emissions have  significant environmental impact because several species are highly car-
cinogenic  (Reference 6-2). The fact that they generally exist as  fine particulate (for reasons
similar  to  those presented in Section 6.2.4 to explain trace metal partitioning to fine particles)
makes them  an even more serious health hazard.
       It is  important  to  again note that although POM formation is possible during  methane combus-
tion, the formation of  these  large aromatic molecules is facilitated by the presence of higher
molecular weight radicals  and C-hL.  Thus, POM production is of only minor concern in gas-fired
systems,  of some concern in oil-fired sources, and of greatest concern in coal-fired equipment.
Whatever  the  combustion source, it is clear that POM emissions should increase under conditions of
poor combustion  efficiency.   Since NO  combustion controls can lead to inefficient combustion and
soot formation,  if not  carefully  applied (especially low excess air and staged combustion), implemen-
tation of these  controls can  most certainly lead to increased POM formation.
      Data to support  this contention, however, are essentially nonexistent, largely because of  the
difficulty of sampling  flue gas streams for POM containing particles and of accurately assaying sam-
ples  for individual POM species.   A recent field test program on oil-fired industrial boilers
                                                6-71

-------
was to include sampling for POM emissions (Reference 6-36),  but  sampling  train  and analytical
problems prevented useful data from being obtained.  Thompson et al.,  recently  reported the effects
of off-stoichiometric combustion and flue gas recirculation  on POM  emissions  from a coal-fired
utility boiler (Reference 6-14).  Their data, shown in Table 6-19,  seem to  indicate that POM emis-
sions do increase with two-stage combustion.  However, they  state that the  sampling and laboratory
analysis procedures used in obtaining the data varied over the sample  set.  Thus,  they  conclude that
POM emissions are not significantly affected by firing mode.  In  a  third  study,  Bennett and Knapp
(Reference 6-53) attempted to investigate the effects of boiler  excess Qฃ on  POM emissions  from an
oil-fired utility boiler.  They found that particulate carbon content  increased  with decreasing
excess 02-  However, because POM assay data varied widely, even  for baseline  condition  analyses, no
conclusion regarding POM emissions was possible.
       A few comments are in order here concerning an extremely toxic subclass of  polynuclear aro-
matic hydrocarbons, the polychlorinated and polybrominated biphenyls (PCBs  and PBBs).  A theoreti-
cal assessment of the possibility of PCB formation in combustion sources  has  been  recently completed
(Reference 6-60).  This study was prompted by a tentative identification  (later  proved  false) of PCBs
in stack emissions from a coal-fired utility boiler (Reference 6-61).  The  theoretical  study con-
cluded that, although PCB formation is thermodynamically possible during  coal and  residual oil  (fuels
which contain some chlorine) combustion, it is unlikely due  to short reaction residence times and
low chlorine concentrations.  However, if PCBs are formed, they would be  expected  to occur under
conditions which promote POM emissions.  Still, other than the aforementioned tentative identifica-
tion, PCBs have never been observed in combustion source emissions.
       The second general compound category considered as an organic emission in the present dis-
cussion is the nitrosamines group.   Nitrosamines (characterized by  the N-nitroso group, N-N=0)  are
formed by the reaction of secondary or tertiary amines with  nitrous acid.   These N-nitroso compounds
are of environmental  concern because nearly 70 percent of these compounds have been found to be
carcinogenic in all  species of laboratory animals (Reference 6-62).
       Primary nitrosamine emissions from various industrial  sources may  affect  ambient levels.
Three recent environmental assessments of these compounds (References 6-62, 6-63,  and 6-64)  have
concluded that primary nitrosamine emissions from stationary combustion sources  are nonexistent.
There are at present, however,  no data to support this contention.
       Combustion sources do,  however, emit the NO  precursors to nitrous acid,  one requisite in-
gredient in nitrosamine formation.   Since nitrate formation  from ambient  NO  is  known to occur, it
is theoretically possible for nitrosamines to be formed in polluted atmospheres  containing  secondary
                                                6-72

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                                      TABLE  6-19.   SUMMARY OF POM EMISSION TESTS
                                                   (Reference 6-14)

Anthracene/Phenanthrene
Methyl Anthracenes
Fl uoranthene
Pyrene
Chrysene/Benz (A)
Anthracene
Total POM
(Percent of Baseline)
Baseline
(yg/m3)a
178.4
53.4
51.5
15.1
0.3
298.7
(100)
2-Stage Combustion
(yg/m3)a
179.3
48.5
110.3
52.1
—
390.2
(131)
15% Gas
Recirculation
(yg/m3)a
145.3
89.4
24.7
23.3
—
282.7
(95)
2-Stage + 15%
Recirculation
(yg/m3)a
230.4
98.3
43.7
46.9
—
419.3
(140)
•-4
OJ
             13% 02,  dry basis.

-------
and tertiary amines.  From such considerations, it is clear that implementing  NO   controls  in  sta-
tionary combustion sources can only serve to decrease ambient nitrosamine  levels.   Thus,  the incre-
mental impact of NO  controls on nitrosamines is beneficial.

6.2.7  Nitrates
       Atmospheric nitrate exists in both organic and inorganic forms.  Organic nitrate consists of
alkyl nitrates and peroxyacylnitrates, of which the most important is peroxyacetylnitrate (PAN).
PAN -which is by far the most abundant organic nitrate and is even the most abundant of all ambient
nitrates (Reference 6-65) - is an eye irritant and causes damage to vegetation.  Inorganic nitrates
include nitric acid and the nitrate salts of various metals and ammonium ion,  of which ammonium
nitrate appears to be the most abundant (Reference 6-66).  Inorganic nitrates  exist in the atmos-
phere as nitrate aerosol.  Although the direct health effects of ambient nitrate aerosols are largely
unknown, atmospheric inorganic nitrate has become a matter of major concern as a contributor to acid
precipitation.
       Although the data are largely lacking, it appears at present that primary nitrate emissions
from stationary or mobile combustion sources are insignificant.  Ambient nitrate seems, instead,
to be a direct result of secondary nitrate production from ambient NO  precursors.  Although the
formation of inorganic nitrate in the atmosphere is not clearly understood, the reactions shown in
Table 6-20 are believed to be important (Reference 6-46).  These reactions are believed to be het-
erogeneous and therefore catalyzed by ambient particulate.   The nitric acid produced through these
reactions seems to be immediately neutralized.  Ambient ammonia is the major neutralizing agent,
giving rise to ammonium nitrate aerosol.  The mechanism for PAN formation is more clearly under-
stood, and is also shown in Table 6-20.
       Since there are apparently no primary nitrate emissions from stationary combustion sources,
the possible effects of combustion NO  controls on these emissions are unimportant.  Indeed, the
use of NO  controls should decrease ambient secondary nitrate levels by decreasing precursor com-
         A
pound emissions.   This is, in fact, one important reason for controlling NO  emissions.
       One possible point of concern in the area of nitrate emission is the proposed use of ammonia
injection for NO  control.  Recent evidence suggests that ambient ammonia levels may be a determining
factor in nitrate aerosol  formation (Reference 6-66).  If this is the case, implementation of ammo-
nia injection could possibly cause increased atmospheric nitrate aerosol production.
                                                6-74

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  TABLE 6-20.  NITRATE FORMATION MECHANISMS
               (References 6-46, 6-66)
A.  Inorganic Nitrate
    6N02 + 3H20    $ 3HN03 + 3HN02       (la)
    3HN02          J HN03 + 2ND
    HO + N02       * HN03                 (2)

    N02 + 03       j N03 +  02             (3a)

    N03 + N02      t N2ฐ5

    N2ฐ5 +  H2ฐ    ฃ 2HN03
 B.  PAN
    R + CH3CHO    J Product + CH3CO     (4a)

    CH3CO + 02 + M t CH3C002 + M         (4b)

    CH3C002 + N02 t  CH3C002N02  (PAN)    (4c)
                      6-75

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6.3    EVALUATION AND SUMMARY
       Based on the discussions in Sections 6.1 and 6.2, N0x control techniques and pollutants can
be classified into one of the following three groups according to potential for increased emissions:
       •   High potential emissions impact, where the data presented in Section 6.2 unambiguously
           show that applying the NO  control results in significantly increased emissions of a
           specific pollutant
       *   Intermediate potential emissions impact, where the preliminary screening exercise in
           Section 6.1 indicates that the N0x control could conceivably cause increased pollutant
           emissions, but confirming data are lacking, contradictory, or inconclusive
       •   Low potential emissions impact, where the data presented in Section 6.2 clearly show that
           specific pollutant emission levels decrease when the NO  control is applied, or where the
           discussion in Section 6.1 definitely indicates a similar conclusion, even though data are
           lacking
These groupings appear in Tables 6-21, 6-22, and 6-23 for NOX combustion controls  applicable to
boilers, 1C engines, and gas turbines, respectively.  These tables are arranged in matrix form,
like Tables 6-2, 6-4, and 6-5 of Section 6.1, and note the level  of potential  environmental  concern
for each NO  control technique/pollutant combination.
       As Table 6-19 illustrates, applying preferred NO  combustion controls to boilers should  have
few adverse effects on incremental emissions of CO, vapor phase hydrocarbons or particulates.   It is
true that indiscriminantly lowering excess air can have drastic effects on boiler CO emissions, and
that particulate emissions can increase with off-stoichiometric combustion and flue gas recircula-
tion.  However, with suitable engineering during development and implementation of these modifications,
adverse incremental emissions problems can be minimized.  In contrast, residual emissions of sulfate,
organics, and trace metals have intermediate to high potential impact associated with applying  almost
every combustion control.  For trace metal and organic emissions, substantiating data are largely
lacking, but fundamental formation mechanisms give cause for justifiable concern.   In the case  of
sulfate emissions, fundamental formation mechanisms suggest that these emissions should remain  un-
changed or decrease with all controls except ammonia injection.  However, complex interactive effects
are difficult to elucidate,  and this pollutant class is sufficiently hazardous to justify expressing
some concern in the present  absence of conclusive data.  The potential effects of post-combustion
ammonia injection on plume sulfate formation deserve special attention.
                                                6-76

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                        TABLE 6-21.   EVALUATION OF INCREMENTAL EMISSIONS DUE TO NOX  CONTROLS APPLIED
                                     TO BOILERS
NOV Control
/\
Low Excess Air
Staged
Combustion
Flue Gas
Recirculation
Reduced Air
Preheat
Reduced Load
Water
Injection
Ammonia
Injection
Incremental Emission
CO
++
0
0
0
0
0
0
Vapor Phase
HC
0
0
0
0
0
0
0
Sulfate
+
+
+
+
+
+
++
Parti cul ate
0
+
+
0
0
+
+
Organ ics
++
++
+
+
+
+
0
Segregating
Trace Metals
+
+
+
0
0
0
+
Nonsegregating
Trace Metals
0
0
+
+
0
0
0
?
-J
          Key:  ++ denotes having high potential emissions impact
                 + denotes having intermediate potential  emissions  impact,  data  needed
                 0 denotes having low potential emissions impact

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                      TABLE  6-22.   EVALUATION  OF  INCREMENTAL  EMISSIONS  DUE TO NOX CONTROLS APPLIED
                                   TO 1C ENGINES
NO Control
/S
Retard
Ignition
Increase A/F
Ratio
Decrease A/F
Ratio
Exhaust Gas
Recirculation
Decrease
Manifold Air
Temperature
Stratified
Charge
Cylinder
Design
Derate
Increase Speed
Water Injection
Incremental Emission
CO
++
0
++
+
0
+
++
+
+
Vapor Phase
HC
+
++
++
+
++
+
++
+
++
Sulfate
0
++
0
0
+
0
+
0
0
Particulate
++
0
+
++
0
+
0
+
+
Organ ics
+
0
+
+
0
+
0
+
+
Segregating
Trace Metals
0
0
+
+
+
+
+
+
+
Nonsegregating
Trace Metals
0
0
0
0
0
0
0
0
0
Ot

3
           Key:   -H- denotes  having high potential  emissions  impact
                  + denotes  having intermediate potential  emission impact,  data needed
                  0 denotes  having low potential emissions impact

-------
                     TABLE 6-23.  EVALUATION OF INCREMENTAL EMISSIONS DUE TO NOX CONTROLS APPLIED
                                  TO GAS TURBINES
NO Control
X
Water or Steam
Injection
Lean Primary
Zone
Early Quench
with Secondary
Air
Increase Mass
Fl owrate
Exhaust Gas
Recirculation
Air Blast/Air
Assist
Atomization
Reduced Air
Preheat
Reduced Load
Incremental Emission
CO
++
0
0
+
+
'o
0
•H-
Vapor Phase
HC
+
0
0
' +
+
+
0
-H-
Sul fate
0
+
0
0
0
0
+
+
Parti cul ate
+
0
+
+
+
+
0
+*
Organics
+
0
+
+
+
+
0
+
Segregating
Trace Metals
+
+
+
+
+
+
+
+
Nonsegregating
Trace Metals
0
0
0
0
0
0
0
0
o>

(O
          Key:  ++ denotes having high potential emissions impact
                 + denotes having intermediate potential emissions impact, data needed
                 0 denotes having low potential emissions impact

-------
       Table 6-22 shows that the incremental emissions of all pollutant  classes  except nonsegre-



gating trace metals have either intermediate or high potential impact when  applying  N0x controls to



1C engines.  Of primary concern are increased CO, vapor phase hydrocarbons  (HC),  and participate



(smoke) emissions.  Of lesser concern are sulfates, orgam'cs, and segregating  trace  metals from



engines burning high sulfur diesel fuels.




       Similarly, NO  controls applied to gas turbines can be expected to adversely  affect all in-
                    X


cremental emissions except nonsegregating trace metals, as Table 6-23 indicates.  Again, increased



sulfate, particulate, organic, and segregating trace metals are of some  concern in those sources



firing high sulfur diesel fuels.  If residual oil firing in gas turbines increases,  these concerns



could become more serious.  Presently, this appears unlikely due to materials  problems, e.g., sul-



fidation with residual oils.




       The incremental emission evaluations of Tables 6-21 through 6-23 are not intended to signify



any potential for adverse environmental impact.  Rather, the evaluation notes  source/control/



pollutant combinations for which emissions may increase due to the use of NO   controls.  Evaluation
                                                                            X


of potential adverse impact requires comparison of the source generated ambient pollutant concentra-



tion with an upper limit threshold concentration of the pollutant based on health or ecological



effects.  A preliminary attempt at such a comparison is made in Section 7.  Prior to that,  some



conclusions may be drawn on the results in this section.




       In general, the data on incremental multimedia emissions due to NO  controls are very sparse.



More data are available for flue gas emissions than for liquid or solid effluent streams.  Even  so,



the only data which allow quantified conclusions are for emissions of criteria pollutants with the



major source/control combinations.  Data on sulfates, trace metals and orgam'cs (POM) are sparse,



experimentally uncertain and highly dependent on fuel properties.  Incremental emissions from liquid



and solid effluent streams and during transient or nonstandard operation are almost nonexistent.



Because of this, they have generally been excluded in the present evaluation.  Test data from on-



going related programs and from the NO  E/A test programs will be needed before the  incremental
                                      X


emissions and impacts can be evaluated for other than flue gas emissions during standard operation.




       Emissions of CO, HC, particulate (smoke) and SO, with or without NO  controls have been con-
                                                      Oi                   X


strained in the past for operational reasons rather than environmental impact.  CO,  HC and smoke



emissions reduce efficiency and may present a safety hazard.  S03 leads to acid condensation and



corrosion.   All  of these emissions are sensitive to combustion process modifications for NO  con-
                                                                                           X


trol.   With the exception of SO,,  incremental emissions tend to increase with  NO  controls, par-
                               ซ3                                                X


ticularly low excess air and off-stoichiometric combustion.  Development experience  has  shown,
                                                6-80

-------
however, that with proper  engineering these emissions can generally be constrained under low-NO
conditions.  This 1s  particularly true for factory-Installed controls on new equipment.  In this
case,  the flexibility for  applying NOX controls with minimal adverse impact is greater than for
retrofit on existing  equipment.   In light of this situation, incremental emissions are seen more as
a constraining  criteria to be addressed during control development than as an immutable consequence
of low-NOx firing.  Moreover, the constraint on emissions for satisfactory operational performance
is generally more stringent than the constraint for acceptable environmental impact.  The environ-
mental constraints will be carried through the N0x E/A impact assessments for all potentially sig-
nificant pollutants,  but they will need to be supplemented by operational constraints in some cases.
       The situation  for other flue gas pollutants is more uncertain.  There is concern that conven-
tional combustion process  modifications - low excess air, off-stoichiometric combustion, flue gas
recirculation -will  increase emissions of sulfates, organics and segregating trace metals from
sources firing  coal  or reiidual  oil.  It should be noted, however, that this conclusion is based on
sparse data or, lacking that, on fundamental speculation.  Clearly, more data are needed.  Little is
known on whether these emissions can be suitably constrained to acceptable levels during control
development.
       With  the firing of clean fuels - natural gas and distillate oil - the main noncriteria pol-
 lutant class  of concern is organics.  This fact will make the testing and assessments of clean fuel
sources -warm air  furnaces, gas turbines, 1C engines - simpler than for boilers and process fur-
naces firing  residual oil  or coal.  Additionally, the clean fuel sources have no liquid or solid
effluent streams.   These considerations do not imply a priori that gas or distillate oil-fired
equipment are more  environmentally  sound.  Rather, the clean fuel sources can be assessed to the same
level of detail as  other sources for less effort.
       In conclusion, there is  reasonable concern that NOX controls will increase incremental emis-
sions of some pollutants.   More data are needed to determine if incremental emissions have a sig-
nificant environmental impact and to suggest corrective action if needed.   In the next section,
a preliminary screening of pollutants on the basis of impact is given and test priorities are
discussed.
                                                6-81

-------
                                     REFERENCES FOR SECTION 6


6-1.   Vapor Phase Organic Pollutants - Volatile Hydrocarbons and Oxidation  Products, National
       Academy of Sciences, Washington, 1976.

6-2.   Participate Polycyclic Organic Matter, National Academy of Sciences,  Washington,  1972.

6-3.   Smith, W. S., and R. A. Taft, "Atmospheric Emissions from Fuel Oil Combustion," USPHS
       Pub. No. 999-AP-2, November 1962.

6-4.   Dismukes, E. B., "Conditioning of Fly Ash with Ammonia," in Symposium on Electrostatic
       Precipitation for the Control of Fine Particles. EPA-650/2-75-016, NTIS-PB 240 440/AS,
       pp. 257-287, January 1975.

6-5.   Barrett, R. E., et al., "Field Investigation of Emissions from Combustion Equipment for
       Space Heating," EPA-R2-73-084a, NTIS-PB 223 148, June 1973.

6-6.   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.

6-7.   Dickerson, R. A., and A. S. Okuda, "Design of an Optimum Distillate Oil Burner for Control
       of Pollutant Emissions," EPA-650/2-74-047, NTIS-PB 236 647/AS, June 1974.

6-8.   Offen, G. R., et al., "Control of Particulate Matter from Oil Burners and Boilers,"
       EPA-450/3-76-005, April 1976.

6-9.   Combs, L. P., and A. S. Okuda, "Residential Oil Furnace System Optimization - Phase I,"
       EPA-600/2-76-038, NTIS-PB 250 878/AS, February 1976.

6-10.  Hall, R. E., "The Effect of Water/Distillate Oil Emulsions on Pollutants and Efficiency of
       Residential and Commercial Heating Systems," Air Pollution Control Association Paper
       75-09.4, June 1975.

6-11.  Crawford, A. R., et al, "The Effect of Combustion Modification on Pollutants and Equipment
       Performance of Power Generation Equipment," in Proceedings of the Stationary Source Combus-
       tion Symposium, Volume III, EPA-600/2-76-152c, NTIS-PB 257 146/AS, June 1976.

6-12.  Crawford, A. R., et al., "Field Testing:  Application of Combustion Modifications to Control
       NOX Emissions for Utility Boilers," EPA-650/2-74-066, NTIS-PB 237 344/AS, June 1974.

6-13.  Hollinden, G.  A., et al., "Evaluation of the Effects of Combustion Modifications in Con-
       trolling NOX Emissions at TVA's Widow's Creek Steam Plant," in The Proceedings of the NOX
       Control Technology Seminar, EPRI SR-39, February 1976.

6-14.  Thompson, R. E., et al., "Effectiveness of Gas Recirculation and Staged Combustion in
       Reducing NOX on a 560 MW Coal-Fired Boiler," in The Proceedings of the NOX Control Technology
       Seminar. EPRI SR-39, February 1976.

6-15.  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.

6-16.  Cato, G. A., et al., "Field Testing:   Application of Combustion Modifications to Control
       Pollutant Emissions from Industrial Boilers -Phase II," EPA-600/2-76-086a, NTIS-PB 253 500/AS,
       April  1976.

6-17.  "Standard Support Document and Environmental Impact Statement — Stationary Reciprocating
       Internal Combustion Engines - Draft," Aerotherm Final Report on Contract 68-02-1318, Task 7,
       Acurex Corporation/Aerotherm Division, Mountain View, CA, November 1975.

6-18.  "Standards Support and Environmental  Impact Statement —An Investigation of the Best Systems
       of Emission Reduction for Stationary Gas Turbines -Draft," prepared  for U.S. EPA, OAQPS,
       July 1976.

6-19.  Surprenent,  N., et al., "Preliminary Emissions Assessment of Conventional Stationary Combus-
       tion Systems,"  GCA-TR-75-26-G(l), GCA Corporation, Bedford, MA., January 1976.
                                                6-82

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6-20.  Gillis, B. G., "Production  and  Emissions  of Solids,  SOX and NOX from Liquid Fuel  Flames,"
      Journal of the Institute of Fuel,  pp.  71-76, February 1973.

6-21.  Kamo, R., et  al.,  "The  Effect of Air-Fuel  Mixing on  Redrculation in Combustion,"  Paper
      CP-62-12, API Research  Conference  on Distillate Fuel Consumption, June 1962.

6-22.  Heap, M. P.,  et al.,  "Reduction of Nitrogen Oxide Emissions from Package Boilers,"  Revised
      Draft Final Report, EPA Contract 68-02-0222, Ultrasystems,  Inc., Irvine, CA,  1976.

6-23.  Bascom, R. C., et  al.,  "Design  Factors that Affect Diesel  Emissions," SAE Paper 710484,
      July 1971.

6-24.  Hills, F. J., et al.,  "CRC  Correlation of Diesel Smokemeter Measurements,"  SAE Paper
      690493, May 1969.

6-25.  Coppersmith,  F. M., et  al., "Con Edison's Gas Turbine Test  Program:   A Comprehensive
      Evaluation of Stationary Gas Turbine Emission Levels," Paper 74-12,  67th Annual APCA
      Meeting, June 1974.

6-26.  Klein, D. H., et al.,  "Pathways of Thirty-Seven Trace Elements  Through Coal-Fired  Power
      Plant," Environmental  Science and  Technology. Vol.  9, No.  10, pp. 973-979,  October  1975.

6-27.  Davison, R. L., et al., "Trace  Elements in Fly Ash," Environmental Science  and Technology,
      Vol. 8, No. 13, pp. 1107-1113,  December 1974.

6-28.  Kaakinen, J.  W., et al.,  "Trace Element Behavior in  Coal-Fired  Power Plant,"  Environmental
      Science and Technology, Vol. 9, No.  9, pp. 862-869,  September 1975.

6-29.  Cato,  G. A.,  and R. A.  Venezia, "Trace Metal and Organic Emissions of Industrial Boilers,"
      Paper  76-27.8, 69th Annual  APCA Meeting,  June 1976.

6-30.   "Coal-Fired Power  Plant Trace Element Study, Vol. I, A Three Station Comparison,"  Radian
      Corp.  report  for EPA  Region VIII,  September 1975.

6-31.  Gladney,  E. S., et al., "Composition and  Size Distributions of  Atmospheric  Particulate
      Matter in Boston Area," Environmental  Science and Technology, Vol. 8, No.  6,  p. 551,
      June 1974.

6-32.  Ensor, D. S., et al.,  "Elemental Analysis of Fly Ash from Combustion of a Low Sulfur Coal,"
      Paper  75-33.7, 68th Annual  APCA Meeting,  June 1975.

6-33.  Lee, R. E., Jr., et al.,  "National Air Surveillance  Cascade Impactor Network  II:   Size
      Distribution  Measurements  of Trace Metal  Components," Environmental  Science and Technology,
      Vol. 6, No. 12, pp. 1025-1030,  November 1972.

6-34.  Bolton, N. E., et  al.,  "Trace Element Measurements at the  Coal-Fired Allen  Steam Plant,"
      Progress Report, February  1973  through July 1973, ORNL-NSF-EP-62, 1974.

6-35.  Billings, C.  E., et al.,  "Mercury  Balance on a Large Pulverized Coal-Fired  Furnace,"
      J.  APCA. Vol. 23,  No.  9, pp. 773-777,  September 1973.

6-36.  Cato,  G. A.,  "Field Testing: Trace Element and Organic Emissions from Industrial  Boilers,"
      EPA-600/2-76-086b, NTIS-PB  261  263/AS, October 1976.

6-37.  Vitez, B., "Trace  Elements  in Flue Gases  and Air Quality Criteria,"  Power Engineering
      pp. 56-60, January 1976.

6-38.  Hegg,  D. A,,  et al.,  "Reactions of Nitrogen Oxides,  Ozone,  and  Sulfur in Power Plant Plumes,"
      EPRI EA-270,  September  1976.

6-39.  Richards, J., and  R.  Gerstle, "Stationary Source Control Aspects of  Ambient Sulfates:   A
      Data Base Assessment,"  PedCo Final Report, EPA Contract No. 68-02-1321, Task  34,  PedCo
      Environmental, Cincinnati,  OH,  February 1976.

6-40.  "Position Paper on Regulation of Atmospheric Sulfates," EPA-450/2-75-007, September 1975.
                                                6-83

-------
6-41.  Corn, M., and R. T. Cheng, J. APCA. Vol. 22, p. 870, 1972.

6-42.  Husai, R. B., et al., "Paniculate Sulfur Formation in Power Plant, Urban and Regional
       Plumes," Paper 13d, AIChE 82nd National Meeting, September 1976.

6-43.  Gordon, 6. E., "Study of the Emissions from Major Air Pollution Sources and Their Atmospheric
       Interactions," NSF-RA-E-74-059, NTIS-PB 242 581, October 1974.

6-44.  Bradstreet, J. W., "Effects of Nitric Oxide'on the Photochemical Oxidation of Sulfur Dioxide
       in Dilute Gas-Air Mixtures," Paper 73-113, 66th Annual APCA Meeting, 1973.

6-45.  Davis, D. D., et al., Science, Vol. 186, p. 733, 1974.

6-46.  Levy, A., and C. W. Spicer, "The Atmospheric Chemistry of NOX," presented at the 69th
       National AIChE Meeting, November 1976.

6-47.  Homolya, J. B., et al., "A Characterization of the Gaseous Sulfur Emissions from Coal  and
       Coal-Fired Boilers," presented at the 4th National Conference on Energy and the Environment,
       Cincinnati, OH, October 1976.

6-48.  Wendt, J. 0. L., University of Arizona, Tucson, AZ, personal  communication, January 1977.

6-49.  Wichert, K., "Chemical Reactions in the Combustion Chamber of a Slag Tap Boiler,"
       Brennstoff-klarme-Kraft, Vol. 9, pp. 104-118, March 1957.

6-50.  Vogel, R. F., et al., "Reactivity of S02 with Supported Metal Oxide -Aluminum Sorbents,"
       Environmental Science and Technology, Vol. 8, No.  5, pp.  432-436, May 1974.

6-51.  Novakov, T., et al., "Sulfates as Pollution Particulates:  Catalytic Formation on  Carbon
       (Soot) Particles," Science. Vol. 186, pp. 259-261, October 18, 1974.

6-52.  Archer, J. S., et al., "Multiphase Combustion of Residual Fuel Oil," J.  Inst.  Fuel, Vol. 43,
       pp. 397-404 and 451-460, 1970.

6-53.  Bennett, R. L., and K. T. Knapp, "Chemical Characterization of Particulate Emissions from
       Oil-Fired Power Plants," presented at the 4th National Conference on Energy and the Environ-
       ment, Cincinnati, OH, October 1976.

6-54.  Hall, R. E., CRB, IERL, U.S. EPA, personal communication.

6-55.  Remeysen, J., "Operations of Large Boilers at Very Low Excess-Air Levels," Paper 1  in
       Current Development in Fuel Utilization, the Institute of Fuel, 1964.

6-56.  Niepenberg, H., "Combustion Control of Oil-Firing Systems Operated at Low Excess Air Levels,"
       Paper 5 in Third Liquid Fuels Conference:  Applications of Liquid Fuels, The Institute of
       Fuel, 1966.

6-57.  Jackson, P. J., "Generating Stations Efficiencies," Paper 8 in Third Liquid Fuels  Conference:
       Applications of Liquid Fuels, The Institute of Fuel, 1966.

6-58.  "Chemistry and Metallurgy," Vol. 5 in Modern Power Station Practice, Central Electricity
       Generating Board, Pergamon Press, New York, 1971.

6-59.  Bittner, J. D., et al., "The Formation of Soot and Polycyclic Aromatic Hydrocarbons in
       Combustion Systems," in Proceedings of the Stationary Source Combustion Symposium.  Vol. I,
       EPA-600/2-76-152a, NTIS-PB 256 320/AS, June 1976.

6-60.  Knierien, H., Jr., "A Theoretical Study of PCB Emissions  from Stationary Sources,"  Monsanto
       Research Corporation, Dayton, OH, Report MRC-DA-577, September 1976.

6-61.  Cowherd, C., Jr., et al., "Hazardous Emission Characterization of Utility Boilers,"
       EPA-650/2-75-066.

6-62.  "Scientific and Technical  Assessment Report on Nitrosamines," EPA-600/6-77-001, November 1976.
                                                6-84

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6-63.  Walker, P., et al.,  "Environmental Assessment  of Atmospheric Nitrosamines," Mitre Corp.,
      McLean, VA, MTR-7152, February  1976.

6-64.  "Assessment of Scientific  Information  on  Nitrosamines,"  Report of the ad hoc Study Group,
      U.S. EPA, Science Advisory Board, August  1976.

6-65.  Stevens, E. R.,  et  al.,  "Recent Developments  in the  Study  of the Organic Chemistry of the
      Atmosphere," J.  APCA. Vol. 6, p.  159,  1969.

6-66.  Grosjean, D.,  et al., "The Concentration, Size Distribution, and Modes of Formation of
      Particulate Nitrate, Sulfate, and Ammonium Compounds in  the Eastern Part of the Los Angeles
      Basin,"  Paper  76-20.3,  69th Annual APCA Meeting, June 1976.
                                                6-85

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                                              SECTION 7
                                 ENVIRONMENTAL ASSESSMENT PRIORITIES

       The  NOX  E/A  program priorities summarized in this section relate directly to the needs and
approach  discussed  in  the Preface and Introduction of this report.   The needs to be addressed by the
\NOX E/A are:

       •   Assess current and impending combustion modification applications to quantify environ-
           mental, economic and operational  impacts

       t   Assess emerging advanced  technology  to  guide  control development

           -   Identify  potential adverse  impacts which  should be addressed  in the control develop-
               ment program

           —   Estimate  which controls will  be  needed  and are most effective to attain air quality
               goals to  the year  2000

 The approach used in the NO  E/A  to  address  these  needs  gives primary emphasis early in the program
                           X
 to assessing current and impending control applications.  Assessment of advanced technology applica-
 tions will  proceed at a  lower level  of effort early  in the program but will be emphasized toward the
 end of the program.  During the program, separate process engineering/environmental assessment re-
 ports will  be generated  for each  major equipment category.  These reports will focus mainly on cur-
 rent technology since it is more  timely from an environmental standpoint and since it has been more
 extensively tested.  The final report will document  the  assessment of far-term applications and will
 update the  earlier assessments of near-term applications.

       To support this approach,  preliminary priorities  are needed for:

       •   The sequence  in which  the major source categories are to be assessed and the level of
           effort devoted to each

       •   The near-term source/control applications to  be assessed

       t   The source/control  combinations to be addressed in the assessment of far-term applications,
           e.g.,  those likely to  see application in  this century
                                                 7-1

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       •   The effluent stream/pollutant combinations to be emphasized in the test programs and



           assessments




       In this report the preliminary source/control  screening is conducted independently of the



pollutant screening.  Initially the source/control combinations are screened on the basis of signifi-



cant near-term or far-term application.  Pollutants for the resultant source/control combinations



are then screened for potential adverse impacts.   The results are then combined to set program



priorities.




       The earlier sections of this report summarized most of the information required to deter-



mine these four priorities.  This section consolidates that information and adds estimates of near-



and far-term source/control requirements to attain and maintain air quality.  The priorities were



then set in the sequence of the above list.  The criteria used are listed below; supporting sections



are indicated in parentheses.





Source Priorities




       •   Current and projected use of specific equipment design/fuel combinations within a source



           category  (Section 2)




       •   Extent of current or impending NOX regulations for the source category (Section 4)




       •   Ranking of source NO  emissions on a national basis (Section 5)




       t   Relative potential for adverse environmental impacts (Section 6)




       •   Current and projected effectiveness of the source in urban NOX abatement (Section 7-1)





Near-Term Source/Control Priorities




       •   Extent of use and effectiveness of controls for the source category  (Section 4)




       •   Near-term need for and effectiveness of specific source/control combinations in urban



           NOV abatement (Section 7.1)
             X




Far-Term Source/Control Priorities




       •   Trends in source use (Section 2)




       •   Developmental status and effectiveness of emerging technology  (Section 4)




       •   Far-term need for specific source/control  combinations in urban areas for various con-



           trol strategy options (Section 7.1)
                                                 7-2

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Effluent Stream/Pollutant/Impact Priorities




       •    Baseline  uncontrolled emissions (Section 5)




       •    Incremental  emissions due to NO  controls (Section 6)
                                          X



       •    Estimated limits on ambient pollutant concentrations (Section 3)




Where possible, these criteria were quantified.  It was not attempted at this stage, however, to



carry a rigorous  quantification through to numerical weighting of priorities.  This is because the



combined effects  of  the general lack of data, the early stage of the program, and the general uncer-



tainty in  the national  NOX abatement strategy would make such an approach unproductive.   The quali-



tative priorities that are set will be updated and reevaluated as new data become available and re-



sults of supporting  program tasks are completed.




       Section 7.1  screens current and advanced combustion modification NOV controls for effective-
                                                                          X


ness in attaining and maintaining the ambient NCL standard.  This evaluation relates to the priori-



tization criteria listed above.  These results, together with the results of previous sections are



evaluated  in Section 7.2 to arrive at preliminary source/control priorities for the near-term and



far-term effort.   Evaluation of potential pollutant/impacts for the near-term source/control combina-



tions is  given in Section 7.3.  Section 7.4 summarizes the conclusions of the preliminary assesement.





7.1    EVALUATION OF N0x CONTROL REQUIREMENTS




       This section  presents the methodology  and results of a preliminary analysis to evaluate NO



control requirements for the attainment and maintenance of the ambient N02 standard.  The results



of this analysis  on  two AQCRs will be used to identify the type and level of NOX emission control



necessary  to meet the N02 ambient air goals.   The main goal of this preliminary analysis is to set



priorities for the NO  E/A program.  Therefore, only ambient N02 concentrations were considered



under the  assumption that their reductions are directly dependent on NOX emission reductions.  There



is no attempt to  consider either NO -HC or N02-oxidant interaction effects on the N02 concentration.



These effects are considered to be beyond the scope of a preliminary analysis.  Moreover, neglecting



these effects is  not expected to significantly alter the priorities based on this analysis.




       A preliminary screening model forms the basis of the analysis.   As described in Section 7.1.1,



it processes the  input  data on emissions, ambient concentrations, and NOX control to identify the



most  cost  effective  control  strategy to attain and maintain the N02 ambient standard.  The principal



components of this systems  model  are the ranking of control methods and the air quality model, which
                                                7-3

-------
 for  this  preliminary  analysis  is  a modified  form  of  rollback.   In  Section  7.1.2 the procedure for
 selecting the  two AQCRs  is described.   Los Angeles and  Chicago  were selected  from a group of NOy
 critical  AQCRs because they  are already in violation of the  N02 standard and  they represent two
 contrasting  NOX problems -mobile source dominated and  stationary  source dominated.  The input data
 for  those two  AQCRs are  described in  Section 7.1.3,  and the  results of the analysis are presented
 in Section 7.1.4.  That  section shows that maximum stationary source controls will  be required if
 there is  to  be a reasonable  chance of achieving the  N02 standard in these  two AQCRs.

 7.1.1   Preliminary Screening Model
        The preliminary screening  model  serves to  coordinate  the  various elements  that  together form
 a cost  effective control strategy for  achieving the  NCL  ambient  standard.   The  requirement of  the
 model  is  that  it provide a useful tool  for relating  emissions to ambient concentrations  and for as-
 sessing the  cost and  effectiveness of  controls for meeting the  NOp  standard.   In  this  case the utility
 of the  model is  judged on the  basis of:
        •   Simplicity of input
        •   Cost  per solution                          '
        t   Flexibility
        •   Relevance  of  results
 The  basic elements that  must be incorporated into the model  are:
        •   Calculation of emissions
        •   Calculation of fuel use
        •   Calculation of cost of control
        •   Ranking of controls for order of application  to reduce source emissions
        •   Relationship  of controlled  emissions to ambient concentration
The first  three  elements listed above  are solely of a "bookkeeping"  nature, whereas the  last two can
range from very  simple to very sophisticated models.   This is especially true of  the air quality
model -the relationship between emissions and ambient concentration.  A general  discussion of air
quality models and the choice of the model for use in the preliminary  phases  of the NO  E/A program
are presented in the following paragraphs.  The other elements  (auxiliary models) of  the screening
model are then briefly described in  the remainder of this subsection.
                                                7-4

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7.1.1-1  Air Quality  Models
      An air quality model  is any methodology for relating atmospheric contaminant concentration
to pollutant source emissions.   Models differ not only in their degree of sophistication but also in
their resolution  and  versatility.   Usually the sophisticated models require considerably more elaborate
input data  than  the simpler  models.  Furthermore, since even they are based on approximate modeling of
physical phenomena, such as  atmospheric turbulence and chemical kinetics, they still require a sig-
nificant calibration  effort  and considerable experience to use them intelligently.  On the other
hand, the lower-order models, .which try to model the atmospheric processes in an integral manner,
are based on certain  correlations  of the available data and lack the resolution of the sophisticated
models.
       The  air  quality  model is the key element of the preliminary screening model.  Therefore,
careful  attention has been given to the choice of the model.  The following factors have been con-
sidered:
       •    The  precision required  for forecasting air quality impacts
       •    The  time and resources  appropriate to this effort
       •    The  availability  of the required meteorological and air quality data for the area of
           interest
       •    The  availability  of a suitable spatially distributed emissions inventory
       •    The  physical size of the area under consideration and the time scale of interest
Since some  degree of  uncertainty is involved in utilizing any available model, disagreement exists
over which  approach is  best.
       Table 7-1  provides a  summary of the basic model  types currently available.*  The key features
of each class of models, their input data requirements, and comparative costs for a similar set of
calculations are  given.  The diversity exhibited by these models lies not only in the basic assump-
tions of the formulation but also  in the refinements, the expense to run, the applicable geographi-
cal and time scales,  and the effort required to calibrate the models.   For the purposes of the pre-
liminary screening analysis  the single most restrictive feature is the input data requirement.
      The  modified rollback model is a simple and inexpensive model  to use and can be readily ap-
plied to assess different control  technologies and strategies.  This model does not effectively
 Table 7-1 was constructed  from  information provided by References 7-1, 7-2, and 7-3.
                                                7-5

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                                                                                TABLE 7-1.   SUMMARY  OF AVAILABLE  AIR QUALITY MODELS
Model
Rollback








Statistical
Trajectory






Markov Chain




Nonreactlve Dis-
persion (COM)




Photochemical
Box





Lagrangian Traject.





Eulerian Photochem/
Diffusion


Multibox Eulerian



Averaging
Type3 Time Accuracy
E Variable Generally
fair to

poor






E 1 hr 300%







E 1 hr - 1 yr 2Q%
for
of exceedance


D/E Variable Fair to good





D 1 hr 200%






D Up to 1 hr 302! - 40%





D 1 hr 20% 03
40% NOz


D 1 hr 30% 03
50ฃ N02


Method
Simple data
correlation







Stat. fit
to chem.


Trace his-
tory of air
mass prior
to arrival
Statistical




Gaussian
plume non-
reacting



• Fully
mixed
• Chem

kinetics
• Allows
advection
• Track air
parcel
• Chem ki-
netics

• Vertical
diffusion
t Difference
equations
ป Chem ki-
netics
• See above
• Integrate
vert.
direct.
Input
Requirements
Source emissions,
base year con-
centration and
emissions





Surface wind
vectors through-
out area, grid-
ded inventory




H1nd fields,
gridded sources,
cal air quality
data

Gridded sources,
stack heights,
joint frequency
dist. for meteo-
rology

Precursor cone. ,
mix depth, temp.
aggregate source
inventory, HC
inventory by class


Gridded inventory,
RHC/NRHC, initial
and boundary condi-
tions, wind speed



Same as above



Same as above



Output
Concentration








Concentration
at 1 receptor
station





Probability of
exceeding some



Concentration
contours for
primary pol-
lutant


Basin wide
concentration





Cone, history
of 1 receptor,
or cone, his-
tory of 1 air
mass


Air basin cone.



Air basin cone.



Secondary
Pollutants
Appendix J,
smog chamber
results, his-
torical cor-
relation




Chemical cor-
relation






Historical
correlation



Correlation, Ap-
pendix J, smog
chamber



Direct, cal-
culation





Direct, cal-
culation




Direct, cal-
culation


Direct, cal-
culation


Costb
Not Including
Inventory
Preparation
$2K








$10K - $15K







$25K - $35K




$10K - $15K





$25K - $50K






$35K - $50K
per
receptor



$150K - $200K



$60K - $80K



Comments
(1) No meteorology; (2) No con-
sideration of source distribution;
(3) No consideration of chemistry;
(4) Not extendable to rural areas;
(5)Secondary pollutant calculations
compound errors in primary; (6)
Very simple, flexible, cheap;
(7) Minimal input data require-
ments
(1) No vertical mixing; (2) May
be useful for rural areas;
(3) No consideration if elevated
sources; (4) Empirical chemical
correlations



(1) Reduced sensitivity to specific
sources via consideration of many,
runs are necessary; (3) Rural
extensions questionable since no
data base
(1) Must relate empirical cor-
relation of NO? precursor — may
offset geographical advantages;
(2) Can treat elevated sources;
(3) Questionable on rural exten-
sion
(1) No geographical differentiation;
(2) Hay possibly be useful for rural;
(3) Must have detailed HC inventory




(1) Can be applied to rural areas;
(2) Can handle elevated sources;
(3) Includes meteorology; (4) Must
nave detailed HC inventory; (5) Eulerian
in vertical direction


(1) See above 1-5



(1) See above 1-4; (2) Integral treatment
of vertical profiles


CTl
                E - empirical;  D - deterministic
               ^Costs — assumes that a suitable inventory is available.  The cost of preparing this is  quite variable and depends on what  has already been  done.

-------
account for changes  in  distribution of emissions over time and space.  Therefore, the accuracy of  •
air quality estimates will  suffer if the emission patterns are significantly altered.  Moreover, the
rollback model  assumes  that meteorology and the NOX-HC and N02-oxidant interaction effects for the
study area will  be  similar  for the :base year and future years.
       The more complex models are designed to explicitly include the physical processes that re-
late emissions  to  ambient pollutant concentrations.  As such, they are most applicable to signifi-
cantly altering emission patterns and can be used to assess the impact on an air basin of selected
control  strategies.   A  wide variety of models with differing degrees of sophistication and applica-
bility falls  into  this  category.  These models can be divided into two classes:  nonreacting disper-
sion (Gaussian  plume) and photochemical diffusion models.  The former approximates the dispersion
process by simple,  experimentally based formulations, whereas the latter starts from the basic prin-
ciples of conservation  of mass and species and develops numerical solution procedures to account for
transport,  turbulent mixing and chemical reactions, especially photochemistry.  These models require
considerably  more  extensive input data, including spatial distribution of sources and meteorological
variables,  than does the rollback model.
       Since  the main purpose of the preliminary systems analysis is to assist in setting priorities
for conducting  detailed process engineering and environmental assessments of the possible source/
control combinations, the model need only provide qualitative results on the cost effectiveness of
the various control  options.  Furthermore, it should serve this function without excessive cost or
undue effort  in input preparation.  Thus, the modified rollback model was selected rather than one
of the more complex, and supposedly more accurate, models described in Table 7-1.  The degree to
which the well  known shortcomings of rollback affect the results is variable, and in some cases
rollback yields results that are in good agreement with even the most complex models.  Furthermore,
the impact of these shortcomings, or assumptions, on the results can be assessed by way of a sensi-
tivity analysis, and this will be done in Sections 7.1.3.2 and 7.1.3.6.  Although rollback was
selected for  use in the preliminary analysis, more complex models, especially ones that include the
relationships between NO  emissions and ozone, as well as other secondary pollutants, will be con-
sidered in  later phases of the program.
       The  form of the  rollback model used here is given by
                                   AC = k  >,(1 - RJ E,W,  + BG                              (7-1)
                                                 7-7

-------
where      AC = ambient concentration
           E. = uncontrolled emissions from source i
           R. = reduction by control of source i
           W. = weighting factor for source i
           BG = background concentration (the background concentration has been assumed to be
                10 ng/m3 for all cases)

The calibration constant, k, is determined by evaluation of the equation at some "base year" for
which the ambient concentration, emissions, etc., are known.  Although parameters such as stack
height and relative position of source and receptor are not explicitly reflected in the model, they
are implicitly included because the model is essentially a correlation between existing emission
patterns and the resulting ambient air conditions.  Moreover, these two factors can be introduced
by assigning proper values to the source weighting factors.

7.1.1.2  Auxiliary Models
       Preparation of the input to the air quality model and processing of the output are the func-
tions of the various auxiliary models.  Figure 7-1 shows the flow of information through the prelimi-
nary screening model.  The functions of the various auxiliary models are described in the following
paragraphs.

Emissions
       The purpose of this portion of the model is to combine the effects of source growth, control,
and weighting (relative impact of the source on the ambient concentration) to compute the net emis-
sions from each source category for use in the air quality model.  Uncontrolled emissions for the
base year and each future year of interest are input for each source category.  Controls to reduce
the emissions are either input or prescribed by the model as necessary to achieve a preset ambient
concentration.  They are input, for example, when it is known that an emission standard will come
into effect for a specific source at some future date.  When the systems model* chooses the control,
it selects from a table of options according to the algorithm (described below) used to set control
priorities.  In addition, provision has been made to weight the emissions from each source in a pre-
determined manner (see Section 7.1.3.6).
*
 Preliminary screening model and systems model are used interchangeably.
                                                7-8

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                                            INPUT BASE  YEAR:
                                              EMISSIONS
                                              AMBIENT CONCENTRATION
                                              CONTROLS
                                              FUEL COSTS
                                      CALCULATE CONTROLLED  EMISSIONS
                                         (USE EXISTING  CONTROLS)
                   CALCULATE AMBIENT
                     CONCENTRATION
   ADD:
NEW SOURCES
NEW CONTROLS
UPDATE:  SOURCE EMISSIONS
        FUEL COSTS
                                             IS THIS THE
                                              BASE YEAR?
                                                      CALIBRATE THE AIR
                                                       QUALITY MODEL
                                                    JL
                                              ORDER THE CONTROLS
                                                    1
                                             APPLY  CONTROLS UNTIL
                                             STANDARD  IS ACHIEVED
                                                      OR
                                           UNTIL ALL CONTROLS USED
                                             CALCULATE  FUEL USAGE
                                          CALCULATE COST OF CONTROL
                                            OUTPUT
                                       IS THIS THE LAST YEAR?
                                                                     I  END   I
        Figure 7-1.   Flow chart for  the preliminary screening  model
                                           7-9

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Prioritization of Controls



       In general, the goal of a regional air pollution control strategy is to achieve a  specified


ambient concentration at the minimum cost to the entire region.  Under this condition, the most cost-


effective method of applying controls is in the order of increasing cost per unit reduction in ambi-


ent concentration.*  This means one should first compute the ambient N02 reduction that could be


obtained by applying each potential control to its respective sources within the region and then


relate these results to the cost associated with the control.  This procedure yields a $/unit ambi-


ent NO- reduction figure for each source/control combination, and permits the combinations to be


ranked and applied on this basis.  That is, the source/control combination which has the lowest cost


per unit reduction in NO,, is applied first and the resulting ambient concentration calculated.  If


the desired level has not been reached, the next most cost-effective combination is used, and so on.


Since this approach is based on a regional optimization of control cost effectiveness, it does not


consider the total reduction potential for every control method; the most cost-effective approaches


are not necessarily the same ones that cause the greatest emission reductions.   Moreover, for sim-


plicity the cost of implementing or enforcing any set of emission or equipment standards has  not


been included in the model.  Nothing, however, prevents a model user from adding these costs,  if


known, to the control costs and allowing the model to proceed as described here.



       The cost per unit reduction in ambient concentration for each control method (CUR.) is  com-
                                                                                        J

puted from




                                         CUR, = CURE../AAC,                                   (7-2)
                                            J       1 J    1




where CURE., is the cost per unit reduction in emissions from source i  as a result of control  j  and
          i J

AAC^ is the change in ambient concentration per unit change in emissions from source i.   In this


terminology, then, the program is structured to apply controls in order of increasing CUR. until  the
                                                                                         J

specified ambient standard is achieved.   It is also within the capability of the program for  the


user to override the selection process and force certain controls to be applied.   For example, legis-


lative action might dictate that certain sources be controlled independent of other considerations.
 This  result  follows  from application of the method of Lagrange multipliers to find the minimum

 cost  of control  subject  to  the  constraints that the standard be met and that the number of any

 particular control not exceed the  number of sources to which it can be applied.
                                                7-10

-------
 Fuel Use
    •   This component of the systems model calculates  the net  fuel  used  (GJ/yr)  for  each  fuel  type.   The
 base year fuel  use, by fuel type, is input for each  source.  Fuel use  is  then  assumed  to  grow  at  the
 same rate as uncontrolled emissions.  Changes in  fuel  consumption can  occur  either from fuel switch-
 ing or by a change in fuel consumption as a result of  a  control  application.   The net  fuel use and
 net change in fuel use (for each fuel type) from  the uncontrolled case are required  in the cost-of-
 control calculation.

 Cost of Control
       The cost of each control method is composed of  two parts  - the  incremental cost of fuel as a
 result of the application of the control and all  other costs.  These basic costs are input by  the
 model user and include the annualized capital cost,  maintenance  and other operational  costs.   The
 incremental cost of fuel is treated separately to facilitate changes in projected fuel prices.  This
 cost is calculated from the price of fuel and the changes in fuel consumption  caused by the control
 method.  Once a control strategy which achieves the  desired ambient level has  been identified, the
 two components of cost are summed for each control method used.  These two costs and their sum, the
 net cost of control, are part of the model output.
 7.1.2  Selection of the AQCRs
       The United States and its territorial possessions  are divided into 247  Air Quality Control
 Regions (AQCRs), largely for administrative reasons, to  effectively manage the national effort to
 attain and maintain a clean environment.  Although air pollution in each of  these regions tends to
 be  characterized by different combinations of emission sources and meteorological conditions,  a
 preliminary analysis of NO  control strategies for all the AQCRs is both impractical and unwarranted.
 This section, therefore, describes the methodology used  to reduce the  number of AQCRs  under considera-
 tion by separating them into four groups, each with  distinctive  air pollution  characteristics.  Analy-
 sis of one member from each of the groups should  be  representative of  the groups as a  whole.   For the
 purposes of the preliminary screening analysis only  two  of these representative AQCRs  are considered.
       The methodology can be summarized briefly  as  follows:
       •   Identify air pollution characteristics, including meteorology, emissions, ambient air
           quality levels, and data availability
       •   Group AQCRs according to their air pollution  characteristics
       •   Select one AQCR to represent each group for further analysis
The  details  of  each of these steps are presented  in  the  following subsections.
                                                7-11

-------
7.1.2.1  Identification of  Important  Characteristics
       One of the main purposes  of  the  environmental  assessment  program is  to identify those controls
which are likely to be needed within  at least  some areas  of  the  U.S.  between  now and the year 2000.
Therefore, only those AQCRs which have,  or  are  expected to have,  a  NOX  problem will  be considered
for  analysis.  These regions belong to  one  of  the following  two  groups:
       •   Priority AQCRs - For  the purpose of  this study, regions  will  be  classified  Priority AQCRs
           if their ambient concentrations  exceed the  N02 standard  when  averaged  over  any consecutive
           four quarters  (i.e.,  a rolling quarter basis rather than the  statutory calendar year basis)
       •   AQMAs* - These are regions which have a high probability of exceeding  the standard by 1985.
           Any region whose ambient NO,  concentration  lies between  80 and 99  yg/m3,  on  a  rolling quar-
             V                        <-
           ter basis, will  be considered an AQMA for NOp.
       The regions which fall into  these two categories were identified  by  OAQPS  (Reference 7-4) and
are  listed in Table 7-2.  It is  recognized  that the "rolling-quarter" method  will  place more regions
into the priority category; however,  it  has the advantage of providing a conservative approach to
identifying  potential problem areas.  Moreover, it increases the  number  of  regions for  consideration
(thus providing a more representative sample) and enhances the possibility  of early  identification
of control technologies which may be  required in the future.  It  is these potential control systems
that are deserving of R&D to insure they are technically  sound, cost- and energy-effective, and en-
vironmentally safe.  The "rolling-quarter"  approach is also consistent with advanced thinking in
OAQPS, as witnessed by the  listing  in Table 7-2 that they supplied.
       In order to divide the AQCRs in Table 7-2 into distinctive groups, the  air  pollution char-
acteristics  and emission properties described below must  be considered.

Mobile Versus Stationary Sources
       The distribution between mobile and  stationary sources will  be considered  because  it signifi-
cantly affects the selection of a control strategy.  The  effectiveness of controlling any particular
source depends, in part, on its total contribution to the problem.  Thus, in  a region like Los
Angeles, where mobile sources account for approximately 66 percent  of the total NO  emissions, sta-
tionary source control, although necessary,  will have less relative impact  on  ambient air quality
than in a region like Detroit, which is  dominated by NO   emissions  from  stationary sources.
*
 AQMA - Air Quality Maintenance Area
                                                 7-12

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TABLE 7-2.   NOX IMPACTED AQCRs AND AQMAs  (ROLLING  QUARTERS AVERAGE)
AQCR Number
024
067
045
174
029
115
123
220
042
043
036
225
015
030
119
056
197
181
078
178
122
173
070
234
131
079
106
018
239
047
City Name
Los Angeles
Chicago
Philadelphia
Canton, Ohio
San Diego
Baltimore
Detroit
Salt Lake City
Springfield
New York City
Denver
Richmond
Phoenix
San Francisco
Boston
Atlanta
Pittsburgh
Steubenville
Louisville
Youngstown
Lansing
Dayton
St. Louis
Charleston, VI. Va.
Minneapolis
Cincinnati
Mew Orleans
Memphis
Milwaukee
Washington, D.C.
Concentration
182
121
121
120
119
116
115
114
113
113
110
103
101
101
100
100
98
98
96
96
90
90
85
85
84
83
83
81
81
80
                                  7-13

-------
Dominant Fuel Type




       The fuel type from which the majority of  stationary  source  NOX  comes  should be considered  in a



grouping strategy.  The type of fuel  used  in stationary  source  combustion  constrains  the effectiveness



and  choice of control options.  For example, NOX emissions  from coal-fired utility boilers  are  not



reduced significantly by FGR, whereas  this technique  is  effective  on gas-  and  oil-fired  boilers.





Stationary Source Type




       Stationary combustion sources  can be divided into the  following categories:




       •   Utility  boilers




       •   Industrial boilers




       •   Commercial/institutional boilers




       •   Residential boilers and furnaces




       •   Internal combustion devices




The  mix of sources  within an AQCR is  important because the  type of control technology and its po-



tential for  reducing emissions are heavily dependent  on  the source type.





Ratio  of HC  Emissions to NOX emissions  (HC/NOX Ratio)




       This  ratio is important because  it  controls the conversion  of NO  to  oxidant.   Therefore, the
                                                                       X


appropriate  control strategy for oxidants  depends on  the ambient levels of these two  pollutants.  If



the  HC/NOV ratio is high, the optimal control strategy relies on N(L reductions, whereas if the ratio
         A                                                         X


is low (a common situation in many cities), the  strategy emphasizes HC reductions, at least for cen-



tral urban areas.  This ratio may, however, be of less importance  in assessing R&D requirements be-



cause  current thinking is that both NO  and HC emissions must be reduced to  simultaneously limit



central urban and downwind oxidant levels.





Ambient Oxidant and NOX Levels




       These two quantities indicate the severity of  the pollution problem.  Also, if these do not



correlate well with NOX emissions it may indicate that the  pollution problem is transported in from



an adjacent AQCR.  In this case an effective air quality program will  require a multi-AQCR strategy.





Solar  Insolation




       Solar energy is an important factor causing temperature  gradients and wind  fields which give



rise to mixing and turbulent diffusion.  In addition, sun light is a key ingredient in the N0-N02-



Oj-HC  interaction.
                                                 7-14

-------
stability  Class
       Stability classes are a function of wind speed and solar  insolation.  They reflect the mechan-
ical turbulence  or mixing in the atmosphere, an important factor in pollutant diffusion and trans-
port.   The EPA Star Program'(Reference 7-9) lists Gifford-Pasquill stability class information as
a bivariate frequency distribution of wind direction and wind speed.  Stability classes are presented
as:
       t   A - Extremely stable
       •   B - Unstable
       •   C - Slightly stable
       •   D - Neutral
       •   E - Stable
 Quality of Data
       A significant feature of any analysis is the quality of the input data.  The complex air
 quality models described in Section 7.1.1 require extremely detailed gridded inventories of NO  and
 RHC* emissions.   A rollback model requires much less detail in the data.  The Aerometric and Emissions
 Reporting System (AEROS) (Reference 7-10), was established by the EPA to be a source of this data.  At
 this time the data in the AEROS system are not of sufficient quality to be solely relied upon.  For
 rollback modeling the deficiencies can usually be overcome (see Section 7.1.3.1).  However, the com-
 plex models require much greater accuracy if they are to be properly utilized.  Data of this quality
 have been prepared for some AQCRs, and their availability will be an important factor in the selec-
 tion of an AQCR for detailed study.
 7.1.2.2  AQCR Groups
       Data for each of the properties described above are shown in Table 7-3.  Some of these data
 are more useful  than others in grouping the AQCRs.  For example, over 90 percent of the AQCRs are
 characterized by Stability Class D, so, this property is not a useful criterion.  The ozone measure-
ments recorded over a 2-year period show order of magnitude variations and are also of questionable
value.   Most of the remaining data originate from the AEROS data bank, are of satisfactory quality,
and were given further consideration.
       Three unsuccessful attempts were made to divide the AOCRs into distinctive groupings.  The
first sought a relationship between high mobile emissions and high HC/NOx ratios; the second a cor-
respondence between a high HC/NO  ratio, a high ozone level, and a high solar insolation level; and
*
 RHC - Reactive hydrocarbons
                                                7-15

-------
  TABLE  7-3.   AIR POLLUTION  CHARACTERISTICS  OF  THE NOX  IMPACTED AQCRs AND  AQMAs
City
Los Angeles
Chicago
Philadelphia
Canton
San Diego
Baltimore
Detroit
Salt Lake City
Springfield
New York City
Denver
Richmond
Phoenix
San Francisco
Boston
Atlanta
Louisville
St. Louis
Cincinnati
Lansing
Dayton
New Orleans
Minneapolis
Steubenville
Memphis
Charleston, W. Va.
Milwaukee
Washington, D.C.
Pittsburgh
Youngstown
AQCR
Number
24
67
45
174
29
115
123
220
42
43
36
225
15
30
119
56
78
70
79
122
173
106
131
181
18
234
239
47
197
178
Mobile
Ststl onaryป
M
66.0-M
63.9-S
54.8-S
56.4-S
70.1-M
58.9-M
52.5-S
54.3-H
54.0-M
61.2-S
54.3-M
66.0-S
76.1-M
70.4-M
53.5-S
55.2-M
78.9-S
75.0-S
56.8-S
64.3-S
57.3-M
77.0-S
57.5-S
90.1-S
58.2-S
88.4-S
53.3-S
55.0-M
77.1-S
53.6-S
Dominant
Fuelb
(ซ)
38-G
42-C
53-0
80-C
54-G
61-0
62-C
33-G
66-0
82-0
58-C
62-0
70-6
42-0
94-0
52-C
85-C
72-C
79-C
47-C
67-C
54-G
55-C
63-C
64-C
95-C
63-C
48-0
90-C
77-C
Station-
ary Com-
bustion0
W
72. -U
56. -U
• 55.6-U
55.6-U
78.4-U
63.9-U
65. -U
58.7-1
55. 3-D
56.3-U
45.3-1
68.8-U
72.7-U
43.5-U
48.6-U
77.0-U
80.6-U
88. 3-D
69.9-U
95.3-1
51.9-U
67.0-1
75.4-U
62.8-U
77.4-U
94.7-U
69.5-U
71.5-U
83.4-U
63.6-U
61 f ford
Pasqulll
Sta-
bility
Class11
452-D
58%-E
—
—
46%-D
49%-D
66%-D
48%-D
—
51S-D
41*-D
463S-D
46S-E
56%-D
70%-D
463S-D
51*-D
57%-D
—
—
57S-D
39%-D
59%-D
—
47%-D
48%-D
65SS-D
51J-D
66X-D
63X-D
HC/NOX
Ratio
.649
.071
.142
.438
.678
1.805
1.340
0.917
1.308
0.975
0.987
0.917
1.604
1.471
1.348
1.122
0.843
0.615
0.972
0.966
1.373
1.171
0.632
0.139
0.801
0.199
2.519
1.052
0.416
0.855
N02
(ug/m')
182
121
121
120
119
116
115
114
113
113
no
103
101
101
100
100
96
85
83
90
90
83
84
98
81
85
81
80
98
96
1 Hour
03e
(M/*1)
376
193
157
95
189
66
115
99
341
211
176
181
117
163
175
157
122
250
118
—
226
136
190
107
—
127
—
180
199
226
Solar
Insolation^
H
L
L
L
H
M
L
M
L
L
H
M
H
M
L
M
M
M
M
L
L
M
M
L
M
M
L
M
L
L
aM - Mobile
 S - Stationary

 Dominant source of NOX by  fuel type, % of stationary source NOX emissions
 6 - Natural Gas
 0 - Oil
 C - Coal

CU - Utility
 I - Industrial

 These values represent the percent occurrence of the dominant stability class within each AQCR.

eBasin average of 99 percentile measurements

 Average dally solar Insolation:
 H i 16.7 MJ/m2
 M i 12.5 MJ/m2
 L < 12.5 MJ/m2
                                                  7-16

-------
the  third a relation  between high mobile emissions and high ozone levels.  None of these resulted in



a significant degree  of  correlation.   For example, ozone formation is not simply a function of solar



insolation and  HC/NOX ratios;  other influences on the ozone formation mechanism have to be considered.



However, a reasonable set of groupings was obtained when the regions were separated into four groups



as shown in Table  7-4.   The major criteria for this grouping are the mobile/stationary source mix,



the major  stationary source type (utility or industrial), and the major fuel type for NO  emissions.



It should  be  noted that all of these have direct bearing on the most suitable control methods for



effectively  reducing NO  emissions.




       Group  1  represents regions that are dominated by stationary sources, with utilities as the



 largest NOX  emitters within the stationary category.  Oil-fueled sources account for the greatest



portion of the  stationary source emissions.  This group is associated with high MO  levels, high



 HC/NOV levels,  and moderate ozone levels.
     X



       Group  2  is  also dominated by stationary sources with utilities as the largest stationary



 source, but  here coal-fueled sources are the dominant emitters of NO .   These regions show moderate



 N0v levels,  medium HC/NO  ratios and relatively low ozone levels.
  X                     A



       Group  3  is  similar to group 2 except that these AQCRs have high NO  levels and high
                                                                         A


 HC/NOX ratios.




       Finally, Group 4 is dominated by mobile sources.  These regions  are characterized by high NO



 levels, high  HC/NO  ratios, and very high ozone levels.  The ozone levels are not unexpected, as



mobile source emissions usually contain high concentrations of precursors for photochemical smog.





7.1.2.3  Selection of the Regions




       One region  is selected to represent each of the four groups.   The choice is primarily dependent



upon how well the  individual AQCR represents the group as a whole, and  on the quality and availability



of emissions  and ambient concentration data.  The four AQCRs are given  below:




       •  Group 1 - New York City




       •  Group 2 - Saint Louis




       •  Group 3 - Chicago




       t  Group 4 — Los Angeles




       For the  preliminary screening of control technologies this group was further reduced to Los



Angeles and Chicago.   These are logical choices for a limited analysis; they are the two most N0x
                                               7-17

-------
    TABLE  7-4.   CHARACTERISTIC  GROUPS OF NOX IMPACTED AQCRs and AQMAs

1. Stationary - Oil - Utility
New York City
Richmond
Boston
Philadelphia
2. Stationary - Coal - Utility
St. Louis
Louisville
Cincinnati
Minneapolis
Steubenville
Memphis
Charleston
Lansing0'
Pittsburg
Youngstown
3. Stationary - Coal - Utility
Chicago
Canton
Detroit
Milwaukee
4. Mobile
Los Angeles
San Diego
Baltimore
Salt Lake City
Springfield
Denver
Phoenix
San Francisco
Atlanta
Dayton
Washington
N0xa

H
H
H
H

M
M
M
M
M
M
M
M
M
M

H
H
H
M

H
H
H
H
H
H
H
H
H
H
H
HC/NOxb

H
H
H
H

M
M
H
M
I
M
L
H
L
M

H
H
H
H

H
H
H
H
H
H
H
H
H
H
H
Ozonec

M
L
L
L

M
L
L
L
L
—
L

L
L

L
L
L
--

H
L
L
L
H
M
L
L
L
M
L
aHigh:  NOX >L 100 yg/m3; Medium:  NOX < 100 yg/m3.

bHigh:  HC/NOX > 0.9; Medium:  0.45 < HC/NOX <. 0.9; Low:  HC/NOX < 0.45.

cHigh:  300 <. Ozone < 400 yg/m3; Medium:  200 <_Ozone < 300 yq/m3;
 Low:   100 ฃ Ozone < 200 yg/m3.

 Lansing is shown in Table 7-3 to be industrial dominated.  Since no utility
 emissions were reported, it was decided to place Lansing in Group 2. ,

                                    7-18

-------
critical AQCRs in the United  States (see Table 7-2), and they represent two opposite categories
with  respect to the  impact  of stationary source control strategies -mobile source dominated versus
stationary  source dominated.   Saint Louis and New York City may be assessed in subsequent analyses.

7.1.3  Summary of Input  Data  and Evaluation Matrix
       The  various  inputs to  the systems analysis model for the two AQCRs are described in this
section.  They are  grouped  into the following categories:
       •    Base year NO   emissions and fuel use
       •    Base year N02 ambient concentrations
       •    Future year growth projections
       •    Fuel costs
       •    Stationary source  controls
The input data and  a brief  discussion of how the values were selected are given for each category.
The section concludes with  a  description of the various scenarios which were investigated with  the
preliminary screening model.

7.1.3.1  Base  Year  NOX Emissions and Fuel Use
       The  base year for all  calculations was 1973, the most recent year for which complete emissions
data are available  from  a variety of reference documents.  Primary sources for fuel  use and emissions
data this year were the  1973  NEDS Annual Fuel Summary Report and the 1973 National Emission Report
(Reference  7-15).   Copies of  the relevant data from these sources are included in Appendix B.   As
described below, these data were checked for consistency with each other and were compared with simi-
lar data from other sources (References 7-16 through 7-20).
       Consistency  was checked first by comparing the emissions and fuel use data from all the  data
sources.  This check was made for each source category, e.g., oil-fired utility power plants.   If
any major discrepancy in emissions was found among the data  sources, the fuel  use data were compared
and,  upon acceptance, used  with an assumed emission factor to calculate the emissions.  For example,
it is known that reported emissions associated with process  gas are often in error fay as much  as an
order of magnitude.  This is  due to the greatly varying heat content of the gas and the use of  inap-
propriate emission  factors.   Therefore, all such emissions were checked for consistency.  The  NEDS
fuel  use and emissions information for electric utilities were also routinely checked against  the
FPC fuel use reports  (Reference 7-18).   This category is such a large contributor that it deserves
                                                7-19

-------
a verification, especially when a simple one is available.   Furthermore,  since  many power plants
in the Los Angeles AQCR implemented some combustion modification  (LEA or  OSC) for  NOX  control  in
1973, emissions were calculated from FPC fuel use data and actual emission  factors as  reported in
Reference 7-19.
       All source categories were checked in a similar manner.  If there  were any  remaining, unex-
plained discrepancies, the EPA Regional Office or appropriate Air Pollution Control  District was con-
tacted.  By this procedure a reasonably consistent set of fuel use-emissions data  was  established
for each AQCR.
       The emission source categories were initially selected to be identical to those in the NEDS
reports.  Individual source categories are necessary in order to account  for distinct growth patterns
and reductions by control for each category.  The NEDS categories were judged to be  sufficient in all
cases except industrial point source external combustion and electric generation point sources.  In
these cases, it was desirable to distinguish between various boiler sizes and types.  Also, source
categories with small emissions or for which little or no control information is available were often
combined.  The source categories and their 1973 emissions and fuel use are given in  Table 7-5 for
Los Angeles and Table 7-6 for Chicago.
7.1.3.2  Base Year N02 Ambient Concentration
       Ambient concentrations for the base year were used to calibrate the air quality model.  The
calibration was then used to relate emissions to ambient concentration in all future year calcula-
tions.  Since the N02 standard is based on the maximum observed annual average throughout the AQCR
for any calendar year, it was deemed reasonable to use this value for the calibration.  However,
other averages, such as the rolling quarter average,* have also been suggested as  a  more representa-
tive basis for a standard.  Maximum values of the 12-month average for the Los Angeles and Chicago
AQCRs are given in Tables 7-7 and 7-8, respectively.   These values are based on averages from one
calendar year, several calendar years, or the largest rolling quarter average during a 3-year
period.  The range of values reflects changes in both emissions and meteorological  conditions.
       Another consideration in the selection of the ambient concentration for calibration of the
model  is that the meteorological  conditions of the base year are "frozen" into the calibration.
Although these conditions do not change muchi on the average, over the 20-year periods being consid-
ered here, year-to-year fluctuations in weather can cause ambient concentrations to  vary by as much
*
 The rolling quarter average is the 12-month average for any four consecutive quarters.
                                                 7-20

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TABLE 7-5.  1973 NOX EMISSIONS AND FUEL USE FOR LOS ANGELES,  AQCR 024
Source
Electric Utilities
Peaking
<50 MW
50 MW - 180 MM
>180 MW
Industrial
1C Engines
'• Ext. Comb. — Large
Ext. Comb. - Small
Area
Industrial Process
Commercial /Institutional
Residential
Furnaces
Other
Solid Waste/Mi sc.
Mobile
Total
NOX Emissions (N02 Basis)
Gg/yr
0.462
3.529
11.308
64.156
14.796
2.891
2.891
12.412
34.505
19.886
9.926
2.586
3.758
353.112
536.237
Gg/yr
79.455
32.990
34.505
19.886
12.512
3.758
353.112
536.237
Percent
14.8
6.2
6.4
3.7
2.3
0.7
65.9
100
Fuel Use (PJ/yr)
Oil
0.0359
13.87
41.23
311.0
3.V9
3.19
8.48
3.147
55.75



439.9
Natural Gas
3.135
4.949
37.11
103.7
9.357
9.599
9.599
45.93
18.64
236.5
231.0
141.5


850.9
Process Gas

20.17
20.17





40.34
                  Gg = 109 grams  =  1.1023 x 103 tons
                  PO = 1015 Joules = 0.947 x 10U Btu

-------
                           TABLE 7-6.  1973 N0ฅ EMISSIONS AND FUEL USE FOR CHICAGO, AQCR 067
                                                A
I

10
ro
Source
Electric Generation
Coal Firing Boilers
011 Firing Boilers
G.T. (Peaking Unit)
Other Pt. Source
Industrial
Water tube Boilers
Flretube Boilers
Area and Other Pt.
Sources
Industrial Process
Coซerc1al/Inst1tut1onal
Residential
Furnaces
Other
Solid Haste
Mobile
Total
NOX Emissions (NO? Basis)
Gg/yr
167.73
12.28
4.52
4.30
84.59
23.90
28.29
41.34
21.39
13.51
1.67
6.33
249.21
659.06
Gg/yr
188.83
136.78
41.34
21.39
15.18
6.33
249.21
659.06
Percent
28.65
20.75
6.27
3.25
2.30
0.96
37.82
100
Fuel Consumptions (PJ/yr)
Oil
33.54
30.96
93.49
28.63
28.63
36.23
20.24
.75.04
36.39
12.79


395.94
Natural Gas
13.50
45.92
45.92
184.22
60.17
132.98
278.16
97.74


858.61
Coal
357.34
49.11
26.08
1.91
5.43
15.19


455.1
Process Gas
9.81
249.84





259.65
                                                 Gg = 10* grains • 1.1023 x 10' tons

                                                 PJ = 10" Joules = 0.947 x 10" Btu

-------
      TABLE 7-7.  MAXIMUM ANNUAL AVERAGE NO? CONCENTRATION,
                  LOS ANGELES, AQCR 024
        yg/ms
                          Method
         150
         141
         132
         182
        Average for 1970-1974 (Reference 7-11)
        Calendar Year 1974 (Reference 7-12)
        Calendar Year 1973 (Reference 7-13)
        Rolling Quarter 1972-1974 (Reference 7-14)
      TABLE 7-8.  MAXIMUM ANNUAL AVERAGE N02 CONCENTRATION,
                  CHICAGO, AQCR 067
yg/m3
                        Method
 lisa
 121
 133
Calendar Year 1974 (Reference 7-12, 26 Observations)
Rolling Quarter 1972-1974 (Reference 7-14)
Calendar Year 1974 (Reference 7-12, 8,283 Observations)
Max. of Calendar Year 1972-1974 (Reference  7-29)
 The highest valid value for any station in 1973 was 76  yg/m3
(Reference 7-14).   The stations reported here did not have  enough
 observations to be valid in 1973.   However, they have retained
 their high levels in later years.   These values for 1974 are
 therefore considered reasonable to use for 1973.
     TABLE  7-9.   ANNUAL  AVERAGE  N02  CONCENTRATION USED FOR
                  MODEL CALIBRATION  (yg/m3)
AQCR
Los Angeles 024
Chicago 067
Nominal
132
96
Alternate
160
120
                             7-23

-------
as 20 percent, even though emission patterns remain the same.  Changes  in meteorological  conditions
could be partially accounted for by changing the calibration, which  can  be  done  easily by changing
the base year ambient  concentration.  This was  not deemed  necessary, because  a suitable range  of
ambient levels is provided by  the various averages given in Tables 7-7  and  7-8.
       Two values of the ambient concentration, given in Table 7-9,  were selected  for  each AQCR.
The nominal value was  taken to be the 1973 calendar year average.  The alternate value was selected,
to represent the opposite end of the range of values in Tables 7-7 and 7-8.   Consideration of  both
values will account for alternate averaging methods and perhaps any  meteorological differences.  In
this way the sensitivity of the results to the  calibration of the model can be evaluated.

7.1.3.3  Future Year Growth Projections
Stationary Sources
       The uncontrolled emissions for future years were projected from fuel use  growth  rates.  The
assumption was made that in the absence of any  further controls, emissions  from  each source category
would grow at the same rate as fuel use in that category.  Growth rates for fuel use were taken from
References 7-21 through 7-26.  Generally, these growth rates apply to an end  use sector (industrial,
residential, etc.); however, in this case they were extended to apply to each  source within the sec-
tor.  Whenever possible, growth rates specific  to the AQCR were used.  In the absence  of these rates,
state, regional or national rates were used.  In addition, the influence of population  growth and any
local limitations on new source growth were considered.
       Two scenarios for each AQCR were used.  The nominal case represents  a moderately conservative
growth influenced by conservation measures and  rising energy costs.  This case is  considered to be
the "most likely to occur" case.  The alternate case represents a higher growth  rate situation,
which is closer to historical growth patterns.  The growth rates used for the  two  AQCRs for the
years 1985 and 2000 are discussed below.
       The two basic sources of growth projections for the Chicago AQCR are the  Ford Foundation energy
study (Reference 7-23) and Federal Power Commission projections (Reference  7-24).  The  nominal growth
case is similar to the "technical  fix" case described in Reference 7-23.  This case represents a con-
scious effort to improve energy efficiency, and a moderate dependence on nuclear power for electricity
generation.  The growth rates and total  growth for the years 1985 and 2000  are given in Tables 7-10
and 7-11.
       The high growth case for Chicago is similar to the "historical growth"  case of  Reference 7-23.
The growth rates  and total  growth for 1985 and 2000 are given in Tables 7-10  and 7-11.   In this case
                                                7-24

-------
           TABLE  7-10.   AVERAGE GROWTH RATES IN ANNUAL  FUEL
                         USE FOR STATIONARY SOURCES IN CHICAGO,
                         AQCR 067
Sector
Electricity Generation
Industrial •
Commercial
Residential
1973-1985 %/yr
Nominal
Oa
3.3
2.9
-0.1
High
1.8
4.4
2.8
0.3
1985-2000 %/yr
Nominal
1.5
3.3
1.5
-1.3
High
3.7
3.2
0.8
0.2
       Growth in electrical  demand is expected to be  met by  an
       increase in nuclear capacity for the short term.
            TABLE 7-11.  INCREASE IN FUEL USE IN FUTURE YEARS
                         FOR CHICAGO, AQCR 067,  1973 BASE
Source Type
Utility Boilers - Coal
Utility Boilers - Oil
Peaking G.T.
Industrial
Commercial
Residential
1973
1.0
1.0
1.0
1.0
1.0
1.0
1985
Nominal
1.034
0.959
1.0
1.434
1.371
0.989
High
1.104
1.8919
1.0
1.612
1.355
1.032
2000
Nominal
1.379
1.096
1.0
2.345
1.710
0.828
High
2.228
1.397
1.0
2.607
1.532
1.063
This large increase is contrary to the trend toward coal; however, oil is
a small  fraction of the utility fuel budget.  Commonweath Edison confirmed
their plans to build several new oil-fired power plants.
                                   7-25

-------
there is substantial growth in nuclear power* and an increasing trend toward electrification.  In
some cases, this trend will result in less fossil fuel consumption than in the nominal case.
       The major sources of fuel use growth projections for the Los Angeles AQCR are References 7-21,
7-25, 7-26, and 7-27-  In addition, the population growth of 1.1 percent/year and the New Source Re-
view Rate, SCAPCD Rule 213, were considered.  Rule 213, in particular, will severely limit the growth
of NO  emissions from industrial and utility point sources.
       Both the nominal and the high cases are composites of the scenarios described in the references
given above.  The nominal case is a reasonable blend of the "medium" type growth projections and the
expected influence of local regulations.  The high case tends to represent a high growth scenario
with effective local regulation (Rule 213).  The growth rates and net growth for the various source
categories are given in Tables 7-12 and 7-13.
       In most cases, it is not sufficient merely to account for the source growth since a new type
of equipment with significantly different emission characteristics may become available.  This possi-
bility has been allowed for by identifying the year of introduction of the new equipment and the
lifetime of the existing equipment.  Starting from the year of introduction, existing equipment is
retired at a constant rate over its lifetime, and new equipment is added to make up the difference
between the overall source growth and the remaining old equipment.  Figure 7-2 illustrates how a
typical source is divided.  Retirement rates used in this analysis are given in Table 7-14.   The
emission characteristics of the new equipment may be the same as the old, or they may be improved
depending upon the level of control desired or required.

Mobile Sources
       Emissions from mobile sources have been treated in a different manner than those from sta-
tionary sources.  The primary reason is that a detailed investigation of mobile source control op-
tions is not of direct interest to this study.  What is needed is the emissions contribution of the
mobile sources for a few representative scenarios.  One scenario has been selected to reflect his-
torical growth in vehicle population and miles traveled and a moderate emission standard.  This is
taken as the nominal case.  The alternate, or low, case is for a reduced growth rate, closer to the
population growth rate, and an emission standard of 0.25 g/km.
*
 The national growth in nuclear power given in Reference 7-23 is considerably modified by FPC projec-
 tions in the Chicago AQCR.
 In effect this rule would prohibit an increase in basin-wide NOX emissions from  specified source
 categories.
                                                7-26

-------
 TABLE 7-12.
AVERAGE GROWTH RATES IN ANNUAL FUEL
USE FOR STATIONARY SOURCES IN LOS
ANGELES, AQCR 024
Source
Utility -Oil
Utility Peaking
Industrial
Commercial
Residential
1973-1985 %/yr
Nominal
1.0
0.5
2.0
2.6
1.2
High
1.7
0.5
2.0
4.3
2.6
1985-2000 %/yr
Nominal
-1.35
0.5
1.0
3.0
0.3
High
0
0.5
1.0
3.9
2.65
TABLE 7-13.  INCREASE IN FUEL USE IN FUTURE YEARS
             FOR LOS ANGELES, AQCR 024; 1973 BASE
Source Type
Utility Oil
Utility Peaking
Industrial
Commercial
Residential
1973
1.0
1.0
1.0
1.0
1.0
1985
Nominal
1.12
1.06
1.26
1.36
1.16
High
1.22
1.06
1.26
1.66
1.36
2000
Nominal
0.92
1.14
1.47
2.12
1.21
High
1.22
1.14
1.47
2.94
2.02
                       7-27

-------
c
o
3
Q.
O
CL
C
OJ
3
CT
    1.0
       1973
                                       Tf
                                  Time  (yrs)
                TO

                Tf
                A

                B
year of introduction of new equipment type

T0 + equipment lifetime

portion of source that is old equipment

portion of source that is new equipment
      Figure 7-2.  Distribution of a  source  into  new and old equipment.

-------
TABLE 7-14.   EQUIPMENT RETIREMENT RATES
Equipment Type
Utility Boilers
Large Industrial Boilers
Small Industrial Boilers
Commercial Boilers
1C Engines
Small Commercial Furnaces— Oil
Residential Furnaces— Oil
Residential Furnaces - Gas
Small Commercial — Gas
Life Time (yr)
50
35
33
33
50
25
25
20
20
Retirement Rate %/yr
2.0
2.9
3.0
3.0
2.0
4.0
4.0
5.0
5.0
                    7-29

-------
       A description of both scenarios for the two AQCRs is given in Table 7-15.  The emission stan-
dard and year of introduction, and the annual growth for the categories considered are shown.  The
emission standards for Chicago are representative of federal standards.  Those for Los Angeles re-
flect the current and proposed standards for California.
       The mobile source emissions for both scenarios and both AQCRs are given in Table 7-16.  De-
tails of how the standards and growth rates were ased to calculate annual emissions are given in
Appendix C.  For vehicles, the following factors were considered:
       •   Number of vehicles
       •   Age distribution
       •   Average miles traveled
       •   Emission factor by model year
In addition, the emission factors were adjusted for deterioration with age and for average trip
speed.  (It is interesting to note the increasing significance of the "other" category.   Much of
this is from rail, ships, construction vehicles, and other off-road vehicles.  It is often argued
that these emissions do not significantly contribute to urban air quality.)

7.1.3.4  Fuel Costs
       Part of the cost of many controls is the increase or decrease in fuel  use as a result of im-
plementing the control method.  Therefore, current and projected fuel costs must be input into the
program.  Fuel costs for 1973 were obtained primarily from FEA (Reference 7-22) and FPC News (Refer-
ence 7-28).  Cost projections to 1985 are based on the "$13/bbl reference case" of Reference 7-22.
Beyond 1985 fuel cost projections are very uncertain.  It may be expected that the relative cost of
energy will continue to increase; however, government price controls could stabilize the cost.
Therefore, fuel prices in the year 2000 were assumed equal  to the 1985 price with two exceptions.
In Los Angeles, the price of industrial  natural  gas was increased to equal that of industrial oil.
In Chicago, the price of industrial oil  was increased to equal that of industrial coal.   Both of
these "equalizations" were done to remove a cost advantage of the "limited" fuel.  Fuel  costs are
given in Tables 7-17 and 7-18 in 1976 dollars.

7.1.3.5  NOV Controls and Control Costs
           A
       This subsection summarizes the data on NOV control techniques and control costs which are in-
                                                A
put to the preliminary screening model.   For each equipment/fuel combination, an existing or emerging
                                                7-30

-------
                              TABLE 7-15.   MOBILE SOURCE EMISSION FACTORS (g/km) AND ANNUAL GROWTH RATES



<1972
1972
1973
1974

1975
1977
1978
1980
1981
1985




1990



1995





2000
Annua'
Growth
Rate
Nominal
LDVC
Calif a
2.9
1.9
1.9
1.2

1.2
0.93
0.93
0.62


































Fed
2.9
2.9
1.9
1.9

1.9
1.2
0.93
0.62


































LDTC
Calif
2.9
1.9
1.9
1.2

1.2
1.2
1.2
0.93
0.62
































Fed
2.9
2.9
1.9
1.9

1.9
1.2
1.2
0.93
0.62

































3.5X

Air-
craft"


z
0

rt-
ง
3






.30
d.
0
rt-
O
z












3












IX
Low

LDVC
Calif
2.9
1.9
1.9
1.2

1.2
0.93
0.93
0.62
0.25
































Fed
2.9
2.9
1.9
1.9

1.9
1.2
0.93
0.62
0.62
0.25






























LDTC
Calif
2.9
1.9
1.9
1.2

1.2
0.93
0.93
0.62
0.25
































Fed
2.9
2.9
1.9
1.9

1.9
1.2
0.93
0.62
0.62
0.25














•

IX

Air-.
craftb

o
CD
0>
rt-
o'
3




.30
TO
ro
o.
c
n
^f
o
.40
Q-
r>
o'
.50
ro
a.
c
o
o'
t

IX


Both Cases/Both AQCRs

HDGC
11.7
11.7
11.7
11.7

7.0
5







































IX

HDDC
27.4
27.4
22.8
22.8

13.7
9.8







































IX

Rail, ships, etc.

z
o
3
Id
c
o> '
o'
3





















IX

aReference C-ll
Reference C-23
CLDV - light-duty vehicles, LOT - light duty trucks,  HDG - heavy-duty gasoline,
 HDD - heavy-duty dlesel.

-------
                                     TABLE  7-16.   MOBILE SOURCE NOX EMISSIONS (All  Values in Gg/yr Expressed as N02)
--J
OJ




LDV
LOT
HDG
HDD
Aircraft
Other
Total
Los Angeles - AQCR 024

107 3

224.0
27.7
20.2
25.3
4.8
51.6
353.6
1985

Nominal
84.5
12.9
12.2
9.6
3.8
59.8
182.8
Low
40.2
5.6
12.2
9.6
3.7
59.8
131.2
2000

Nominal
121.0
13.6
8.8
9.2
4.4
69.5
226.5
Low
24.9
2.8
8.8
9.2
3.1
69.5
118.3
Chicago - AQCR 069

1Q7'3

155.0
6.7
12.2
26.5
35.9
13.4
249.7
1985

Nominal
61.0
3.9
7.3
10.0
28.5
15.1
125.8
Low
44.6
1.8
7.3
10.0
28.3
15.1
107.1
2000

Nominal
81.4
3.9
5.2
9.6
32.8
17.6
150.5
Low
17.0
0.6
5.2
9.6
23.5
17.6
73.5

-------
TABLE 7-17.  FUEL COSTS IN THE CHICAGO AQCR, 1973-2000
Fuel Costs
Utility
Coal
Oil
Natural Gas
Industrial
Coal
Oil
Natural Gas
Process Gas'3
Commercial
Coal
Oil
Natural Gas
Residential
Coal
Oil
Natural Gas
Fuel Costs ($/GJ)a
1973

0.77
1.38
1.01

0.83
0.87
2.39
0.87

1.36
2.34
1.15

1.58
2.34
1.42
1985

0.93
1.55
3.96

1.40
0.96
4.05
0.96

2.00
2.64
2.18

2.34
2.65
2.41
2000

0.93
1.55
3.96

1.40
1.40
4.05
1.40

2.00
2.64
2.18

2.34
2.65
2.41
       aFuel costs are in  1976 dollars.

       bThe cost of industrial process gas was
        arbitrarily set equal to the cost of
        industrial oil.
                           7-33

-------
TABLE 7-18.  FUEL COSTS IN THE LOS ANGELES AQCR, 1973-2000
Fuel Type
Utility
Low Sulfur
Oil
Natural Gas
Industrial
Oil
Natural Gas
Process Gasb
Commercial
Oil
Natural Gas
Residential
Natural Gas
Fuel Costs ($/GJ)a
1973
2.49
0.74
2.00
0.77
0.77
2.42
1.14
1.36
1985
2.81
2.87
2.17
1.21
1.21
2.72
2.39
2.50
2000
2.81
2.87
2.17
1.21
1.21
2.72
2.39
2.50
          Fuel  costs  are 1976  dollars.

          The  cost  of industrial  process  gas  was
          arbitrarily set equal  to  the  cost of
          industrial  natural gas.
                           7-34

-------
control  technology is identified as being capable of achieving a given NO  emission level.  In addi-
tion, the differential  costs associated with the control technology are presented.  For the most part,
these data are compiled from the information in Section 4 of this report.  As noted there, good,
reliable cost data for many -NOX control techniques are not available.  In those cases where this is
so, best projected estimates are made based on the available data.
       Control costs and other process data are presented in Tables 7-19 through 7-27 for the follow-
ing equipment/fuel combinations:
       •   Coal-fired utility boilers (Table 7-19)
       •   Gas- and oil-fired utility boilers (Table 7-20}
       •   Coal-fired industrial watertube boilers (Table 7-21)
       •   Gas- and oil-fired industrial watertube boilers (Table 7-22)
       •   Gas- and oil-fired industrial firetube boilers (Table 7-23)
       •   Gas- and oil-fired residential furnaces (Table 7-24)
       •   Gas turbines (Table 7^25)
       •   1C engines (Table 7-26)
       t   Industrial process furnaces (Table 7-27)
 It was assumed that most stationary combustion sources of NOX can be divided into these categories
 (the exceptions number only a few).  The data presented represent expected typical ranges or average
values over the entire spectrum of firing types and sizes within each category.
       For a given NO  emission level, the tables present a single or combined control  technique
capable of achieving that level, taking into account effectiveness, cost, availability, applicability,
and operational impact.  Environmental problems, however, were not considered in arriving at these
selections.  In those cases where the "earliest year available" is blank, the technology is consid-
ered available now.   The differential control costs are shown in terms of both initial  investment
and annual costs in 1976 dollars.  The annual costs include the differential costs of capital, raw
materials, maintenance, and utilities.  However, they do not include the cost associated with a
change in fuel consumption.   The effect on fuel  consumption is tabulated separately in each table
in accordance with the earlier discussion on the cost model  (see Subsection 7.1.1.2)."  Details on
other cost assumptions are discussed in Section  4.
       Two other NO   control  methods not mentioned in these tables are ammonia injection and oil de-
nitrification.   Ammonia injection is an emerging technology projected to be commercially available
                                                7-35

-------
                                            TABLE 7-19.   COST OF NOX  CONTROLS  FOR  COAL-FIRED UTILITY BOILERS3
CO
CT1
New or
Existing
Equipment
Existing0
Newd
Emission
Level
(ng/J)
344
301
258
215
172
129
Control
Technique'3
LEA
LEA + OSC
LEA + OSC
Advanced Design 1
Advanced Design 2
Advanced Design 3
Earliest
Year
Available
~
—
1982
1984
1987
1990
Differential Control Costs
Initial Investment
($/kW)
0.6
1-1.5
0.2
0.5-1
1-2
2-7
Annual Cost
($AW)
0.1
0.2-0.3
<0.1
0.1-0.2
0.2-0.5
0.5-1.2
Effect on
Fuel Consumption
<1% decrease
<1% increase
--
--
--
--
                  aAmmonia injection may also be used with any of the combustion modification control  methods.   This  results in
                   an additional 50 percent reduction in NOX emissions.
                   See Section 4 for control technique characterization.
                  cThe emissions level for existing uncontrolled units is assumed to be 387 ng/J.
                  ^The emissions level for newly constructed units is assumed to be 301 ng/J.

-------
                    TABLE  7-20.   COST OF NOX CONTROLS FOR GAS- AND OIL-FIRED UTILITY BOILERS3
New or
Existing
Equipment
Existing0
New
Emission
Level
(ng/J)
215
143
107
Control
Technique^
LEA
LEA + OSC
LEA + OSC + F6R
Earliest
Year
Available
—
—
--
Differential Control Costs
Initial Investment
($/kW)
0.3
0.5-1
6-12
Annual Cost
($/kW)
<0.1
0.1-0.2
1-2
Effect on
Fuel Consumption
<1% decrease
1% increase
~\% increase
No new units
 Ammonia injection may also be used with any of the combustion modification control  methods.   This results in
 an additional 50 percent reduction in NOX emissions.
 See Section 4 for control technique characterization.
cThe emissions level for existing uncontrolled units is assumed to be  258 ng/J.

-------
                                      TABLE 7-21.  COST OF NOX CONTROLS FOR COAL-FIRED INDUSTRIAL WATERTUBE BOILERS3
to
oo
New or
Existing
Equipment
Existing*1
Newd
Emission
Level
(ng/J)
193
172
189
163
129
Control
Technique'3
LEA
LEA + OSC
LEA
LEA + OSC
Advanced Design
Earliest
Year
Available
—
—
--
1980
1985
Differential Control Costs
Initial Investment
($/(kg/hr))c
22
55
15
44
110-176
Annual Cost
($/(kg/hr))c
4.9
11.
3.3
8.8
22-35
Effect on
Fuel Consumption
1% decrease
<]% increase
1% decrease
--
--
                       Ammonia injection may also be used with any of the combustion modification control methods.  This results in
                       an addition 50 percent reduction in NOX emissions.
                       See Section 4 for control technique characterization.
                      ckg/hr — kg steam per hour
                       The uncontrolled emissions level is assumed to be 215 ng/J.

-------
                                 TABLE 7-22.  COST OF NO*  CONTROLS  FOR  GAS- AND  OIL-FIRED  INDUSTRIAL  WATERTUBE BOILERSa
i
to
vo
New or
Existing
Equipment
Existing*1
Newd
Emission
Level
(ng/0)
120
108
116
103
66
64
43
Control
Technique"
LEA
LEA + OSC
LEA
LEA + OSC
Advanced Design ]
Advanced Design 2
Advanced Design 3
Earliest
Year
Available
--
--
~
1978
1981
1983
1985
Differential Control Costs
Initial Investment
($/(kg/hr))c
22
44
18
33
55
73
88-154
Annual Cost
($/(kg/hr))c
4.4
8.8
3.3
6.6
11
14.3
18-31
Effect on
Fuel Consumption
1% decrease
<1% increase
1% decrease
—
--
--
~
                     Ammonia Injection may also be used with any of the combustion modification control methods.  This results  in
                     an additional  50 percent reduction in NOX emissions.
                     See Section 4  for control  technique characterization.
                    ckg/hr - kg steam per hour.
                     The uncontrolled emissions level  is assumed to be  129  ng/J.

-------
                                   TABLE 7-23.  COST OF NOX CONTROLS FOR GAS- AND OIL-FIRED INDUSTRIAL FIRETUBE BOILERS
-J
o
New or
Existing
Equipment
Existing0
Newc
Emission
Level
(ng/J)
108
77
108
86
65
43
Control
Technique3
LEA
LEA + FGR
LEA
LEA + FGR
Advanced Design 1
Advanced Design 2
Earliest
Year
Available
--
--
--
1978
1981
1985
Differential Control Costs
Initial Investment
($/{kg/hr))b
0.66
3.7
0.44
1.59
2.41
3.3
Annual Cost
($/(kg/hr))b
0.13
0.66
0.09
0.31
0.48
0.66
Effect on
Fuel Consumption
1% decrease
<1% increase
1% decrease
~
--
—
                    aSee Section 4  for  control  technique characterization.
                    bkg/hr - kg steam per  hour.
                    cThe uncontrolled emissions level  is assumed  to  be  129 ng/J.

-------
                TABLE 7-24.  COST OF NOX CONTROLS FOR GAS- AND OIL-FIRED RESIDENTIAL  FURNACES
New or
Existing
Equipment
Existing11
Newb
Emission
Level
(ng/J)
None
26
17
8.6
Control
Technique3

New Burner
Advanced Design 1
Advanced Design 2
Earliest
Year
Available

1978
1981
1984
Differential Control Costs
Initial Investment
($/kW)

1.37-2.05
2.05-3.42
3.42-5.11
Annual Cost
($/kW)

0.14-0.29
0.29-0.4
0.32-0.68
Effect on
Fuel Consumption

5% decrease
7% decrease
~\Q% decrease
See Section 4 for control  technique characterization.
The uncontrolled emissions level  is assumed to be 43 ng/J.

-------
                                                    TABLE 7-25.   COST OF NOX CONTROL FOR GAS TURBINES
 i
*•
ro
New or
Existing
Equipment
Existi ngb
New5
Emission
Level
(ng/J)
120
120
86
43
Control
Technique3
Water Injection
Water Injection
Advanced Design 1
Advanced Design 2
Earliest
Year
Available
—
—
1981
1984
Differential Control Costs
Initial Investment
($/kW)
3-20
3-20
10-30
20-50
Annual Cost
($/kW)
0.5-2
0.5-2
2-6
4-10
Effect on
Fuel Consumption
}% increase
1* increase
—
—
                     See Section 4 for control technique  characterization.



                     The uncontrolled emissions  level  is  assumed  to  be  172  ng/J.

-------
                                                      TABLE 7-26.  COST OF NOX CONTROLS  FOR  1C  ENGINES
I
4*
U)
New or
Existing
Equipment
Existing
Newb
Emission
Level
(ng/J)
1,053
1,338
737
Control
Technique3
Fine Tuning,
Changing A/F
Fine Tuning,
Changing A/F
Advanced Design
Earliest
Year
Available
--
1980
1983
Differential Control Costs
Initial Investment
($/kW)
--
--
13.40-26.80
Annual Cost
($/kW)
0.67-2.01
0.54-1.30
2.70-5.40
Effect on
Fuel Consumption
10% increase
5% - 10% increase
--
                      See Section 4 for control technique characterization.


                      The uncontrolled emissions level is assumed to be 1,504 ng/J.

-------
                        TABLE 7-27.  COST OF NOX CONTROLS FOR INDUSTRIAL PROCESS FURNACES
New or
Existing
Equipment
Existing
New
Emission
Level
(ng/J)
258
172
258
129
86
Control
Technique3
LEA
LEA + F6R
LEA
Advanced Design 1
Advanced Design 2
Earliest
Year
Available
—
1978
—
1981
1987
Differential Control Costs
Initial Investment
($/kW)
1.01
5.80
0.68
3.74
5.11
Annual Cost
($/kW)
0.22
1.01
0.14
0.76
1.01
Effect on
Fuel Consumption
1% decrease
1% increase
1% decrease
~
—
aSee Section 4 for control technique characterization.

-------
in the period  1981  through 1983.   It is seen to have applicability to utility and large industrial .
watertube boilers with  typical  NOX reductions of about 50 percent of the existing emission level.
Annual costs  have been  estimated at $5/kW to $10/kW and 0.88 $/(kg/hr)* to 1.98 $/(kg/hr) for utility
and industrial  boilers, respectively.  A major portion of these costs is the charge for ammonia.
There seems to be no significant effect on fuel consumption.
      Denitrification  usually accompanies desulfurization of oil.  The nitrogen content of the oil
is reduced  such that NO  reductions of 10 to 40 percent from baseline can be achieved.  Desulfuriza-
                       A
tion typically adds $0.8 to $1.7 per barrel to the cost of residual or crude oil.  Denitrification
as a NOX control  method is applicable to residual oil-fired utility and large industrial boilers.
      The  annual control costs are given in terms of cost per unit output (8.9 $/kW).  In order to
utilize  these values in the systems analysis it is necessary to estimate the average unit size in
each of  the various source categories.  The most effective procedure for doing this is to estimate
an average  annual capacity factor for each source type and combine this with the fuel  use.  This re-
sults in a  total  installed capacity for the particular source (total capacity = annual fuel use x
annual capacity factor).  From this the total cost to control the source can be calculated (example:
total capacity in MW x  $/MW for the control method = total cost of the control method).
7.1.3.6   Evaluation Matrix
       In order to  adequately assess the level of emission reduction required to meet the N02 stan-
dard in  1985  and 2000 many combinations of the growth scenarios and base year calibrations could be
considered.   These  combinations would all be derived from variations of the following four basic fea-
tures:
      •   Stationary source growth rate
      •   Mobile source growth rate
      •   Values of the base year ambient concentration used for calibration of the air quality model
      •   Value of the source weighting factors for power plants and mobile sources
      The  first three  of these have been discussed previously.  The purpose of varying the source
weighting factor is to  evaluate the sensitivity of the results to the significance, or weighting,
given to a particular source category.  For example, it may be that because power plants emit from
high stacks,  a portion  of their NOX emissions does not contribute to the ambient N02 concentration in
the AQCR.  This may be  due to transport out of the AQCR or different NO to N02 conversion rates for
ground level  and elevated sources.  Therefore, it is of interest to examine what impact a reduction
*
 kg of steam per hour

-------
 in the significance of power plant emissions  has  on  the  results.   Conversely,  it has  often been
 argued that mobile source emissions  are a more  significant contribution  to  high ambient  N02 levels
 than other sources, since they emit  both oxidant  precursors  (recall  that HQ^ is formed from N0x dur-
 ing the  photochemical process) at the  same elevation as  the  primary  receptors.   Therefore,  the im-
 pact of  increasing the significance  of the mobile  sources was also considered.
       The evaluation matrix is  a combination of  two parts.  The  first part consists  of  the various
 combinations  of  growth scenarios for stationary and mobile sources and whether  or  not control of
 stationary sources is attempted.  A  description of each  of these  cases considered  is  given  in Table
 7-28.  The same  combination of scenarios was used  for both Los Angeles and  Chicago, and is  considered
 to bracket all reasonable combinations of growth scenarios for mobile and stationary  sources.
       The second part of the evaluation matrix is formed from combinations of  the base year ambient
 concentration and the source weighting factors.  A change in the  base year  concentration is used to
 examine  the sensitivity  of the results to assumptions made in identifying this  level.  It also seems
 to show  the sensitivity  of the results to moderate changes in source-receptor spatial relations due
 to growth or  the application of  controls.  This portion  of the evaluation matrix is given in Tables
 7-29 and 7-30.   For each entry in these tables  all the cases in Table 7-28  were evaluated.  The re-
 sults for this matrix of simulations for the years 1985  and  2000  are discussed  in the following
 section.

 7-1.4  Results
       The preliminary screening model  was utilized to compute ambient concentrations and required
 levels of control using  the assumptions described  in Section 7.1.3.  The results of these calcula-
 tions are presented and  discussed in this section.  Only a limited number of cases, selected as repre-
 sentative of  the entire  matrix of cases, will be described.   The results are not intended to be pre-
 dictions of future ambient concentration, because  the limitations of the model  and the uncertainty
 of the input  data preclude such expectations.  Rather, the results are indicative of  the effective-
 ness of and the need for control  of various sources.
       Two types of results are described.   The first is the ranking of the controls  in order of
cost-effectiveness.   This is  intended to provide guidance for the development of control  methods and
strategies.   The second is  an indication of the degree of control required  to meet the annual stan-
dard.   These  results  on  the extent  of control implementation to attain and maintain the standard are
also  compared  with  conclusions  from similar studies.
                                                7-46

-------
         TABLE 7-28.  EVALUATION MATRIX, GROWTH SCENARIOS
      Nominal growth for all sources
      Controls applied to meet std of 100 yg/m3 in 1985,  2000


AN    Nominal growth for all sources
      No controls beyond those in use as of 1976
AM    Nominal growth for stationary sources
      Low growth mobile sources
      Controls applied to meet std of 100 yg/m3 in 1985,  2000
AH    High growth for all stationary sources
      Nominal growth for mobile sources
      Controls applied to meet std of 100 yg/m3 in 1985,  2000
                             7-47

-------
  TABLE 7-29.  EVALUATION MATRIX:  BASE YEAR CONCENTRATION AND
               SOURCE WEIGHTING FACTORS FOR LOS ANGELES
Power Plant
Weighting Factor3
1
2
3
4
5
6
7
8
1.0
1.0
0.7
1.0
0.7
0.7
1.0
0.7
Mobile
Weighting Factor
1.0
1.0
1.0
1.2
1.2
.1.0
1.2
1.2
Base Year (1973)
Ambient Concentration
132
160
132
132
132
160
160
160
For Los Angeles a power plant weighting factor of 0.7 was selected
as a lower value for power plant sources.   This was because the
inversion layer above Los Angeles deflects emissions back into the
air basin, thereby partially off-setting the effect of elevated
sources.  Thus, a significant reduction in weighting for power
plant emissions would not be expected.
                               7-48

-------
   TABLE 7-30.  EVALUATION MATRIX:  BASE YEAR CONCENTRATIONS
                AND SOURCE WEIGHTING FACTORS FOR CHICAGO*

1
2
3
4
5
6
7
8
Power Plant
Weighting Factor
1.0
1.0
0.5
0.2
1.0
1.0
0.5
0.2
Mobile Weighting
Factor
1.0
1.2
1.2
1.0
1.0
1.2
1.2
1.0
Base Year (1973)
Ambient Concentration
(yg/m3)
96
96
96
96
120
120
120
120
aDispersion of emissions from high stacks may have a very pro-
 nounced effect on the impact of elevated sources in the Chicago
 AQCR.  For these sources Yeager (Reference 7-30) has suggested
 a source weighting factor of 0.356 as appropriate for nonreac-
 ting species for regions such as Chicago.  Consequently, two
 reduced values of the power plant weighting factor were con-
 sidered.
                                 7-49

-------
7.1.4.1   Ranking of Controls
       The order in which controls are applied by the screening model is based on the cost per unit
reduction in ambient concentration.  As explained in Section 7.1.1 this approach allows for considera-
ion of the impact of each source/control combination on the ambient air quality.  It differs, however,
from the customary method of evaluating the cost-effectiveness of controls based on the reduction in
emissions.  For the air quality model used here, these two approaches yield the same result if all
source weighting factors are equal.  In the present analysis power plant weighting factors less than
1.0 and mobile source weighting factors greater than 1.0 are also considered.  This has the effect
of reducing the cost-effectiveness of power plant controls, i.e., the cost per unit reduction in
ambient concentration increases.  In both Los Angeles and Chicago this results in a moderate shift
downward of the power plant control in the overall  control ordering.   Control rankings for Los Angeles
and Chicago are given in Tables 7-31 and 7-32 for the year 2000 and for equal source weighting fac-
tors.  Although the ranking is based on changes in  ambient concentration the percent reduction listed
for each control is the reduction of the uncontrolled emissions.*  The controls have been divided
into three groups according to their cost-effectiveness.  Control levels will be described in terms
of which group of controls is required to meet the  ambient standard.   Group I consists of all  the
controls that result in a net dollar savings.  These include modifications to residential  and small
commercial furnaces and most low excess air controls.  The net savings results from the decrease in
fuel consumption associated with the control  method.  Group II contains the combustion modification
controls that require hardware changes — off-stoichiometric combustion, flue gas recirculation,  etc.
In some cases these controls are applied in conjunction with some from Group I, e.g., low excess air
plus off-stoichiometric combustion.  The last set of controls, Group  III, consists of the addition
of ammonia injection to those controls in Group II  for which this technique is applicable.
       Tables 7-31  and 7-32 show that, with the exception of residential and small  commercial  furn-
aces, the maximum reduction in stationary source NOV emissions by combustion modification is about
                                                   X
20 to 60 percent.   The addition of ammonia injection increases this to 50 to 80 percent.  It should
also be noted that there are no controls for two potentially significant source categories - indus-
trial processes and large commercial sources.   These were omitted primarily because of the extremely
*
 New equipment types with factory-installed NOX controls are included as control methods.  The cost
 associated with new equipment designs is that portion of the cost attributable to the NOx control
 features (i.e., excludes R&D costs as these may be subtotaled in the estimate of the initial cost  of
 the equipment).
+
'Commercial  sources were divided into two groups -one that represents furnaces similar to residential
 furnaces,  although larger;  the other "large sources" consist of firetube boilers, large forced air
 heaters, and other miscellaneous types.   For the purposes of control the latter group was considered
 too diverse to assign specific control  methods.
                                               7-50

-------
          TABLE 7-31.  CONTROL PRIORITIZATION FOR LOS ANGELES
                       (2000, EQUAL SOURCE WEIGHTING)
Rank



1 <


f i
2
3
4
5
6
7
V. 8






II <






9
10
11
12
13
14
15
16
17
18
19
20
,21
( 22
III ) 23
1 24
Us
Source/Control
RES. FURN NEW BURNER
SM COMM FURN NEW D.
IND (WTB) LEA
SM COMM FURN A.D. #1
COMM/ INST FURN A.D. #2
RES. FURN A.D. #1
RES. FURN A.D. #2
IND (FTB) LEA
SM PP LEA+OSC
1C ENGINES ADO A/F
aMED PP TO 250 PPM
1C EHG.-NEW ADJ A/F
1C ENG.-NEU A.D.
3LA PP TO 250 PPM
SM PP LEA+OSC+FGR
1C ENGINE-EGR
aCCGT-NEW-H20 INJ
CCGT-NEU A.D. #1
CCGT-MEW A.D. #2
IND (WTB) LEA+OSC
IND (FTB) LEA+FGR
LA PP C.M.+NH3 INJ
MED PP C.M.+NH3 INJ
SM PP C.M.+NH3 INJ
IND (WTB) C.M.+NH3
Cost Per Unit
Change in Air Quality
106$/(ug/m3)
-15.4
-14.6
-13.9
-12.7
-13.3
-11.4
-11.3
- 3.67
1.57
2.18
2.43
2.48
0.305
2.50
2.74
4.10
4.13
3.38
3.94
5.00
6.57
6.74
7.59
8.25
13.4
* Red/Unit
40
40
7
60
80
60
80
17
45
30
16
11
51
16
58
20
30
50
75
17
40
79
79
79
42
                                                                            in
                                                                            CO
Required to meet present legislated emission  levels.

A.D. -Advanced design
C.M. - Combustion modifications (LEA, OSC, FGR)
COMM - Commercial
CCGT - Combined cycle gas turbine
EGR - Exhaust gas recirculation
FGR — Flue gas recirculation
FTB - Firetube boiler
FURN - Furnace
H20 INJ - Water injection
I, IND - Industrial
INST - Institutional
LA - Large
LEA - Low excess air
HED - Medium
OSC - Off-stoichiometric combustion
PP — Power plant
RES - Residential
SM -Small
WTB - Watertube boiler
                                  7-51

-------
              TABLE 7-32.  CONTROL PRIORITIZATION FOR CHICAGO
                           (2000 EQUAL SOURCE WEIGHTING)
Rank
1





I <











"<





2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
/ 29


III


30
, 31
32
33
34
35
:36
Source/Control
RES. NEW BURNER
RES. FURN A.D.iH
RES. FURN A.D.I2
SM COMM FURN NEW D
SM COMM FURN A.D.#1
SM COMM FURN A.D.#2
IWTB-OIL LEA
N IWTB-C LEA
N IWTB-0 LEA
IWTB-COAL LEA
PP-OIL LEA
N IFTB-0 LEA
IFTB-OIL LEA
PP-COAL LEA
N PP-C LEA+OSC 1982
N PP-C A.D.#2 1987
PP-COAL LEA+OSC
N IFTB-0 LEA+FGR
N IWTB-0 LEA+OSC
N IWTB-0 A.D.#2 1983
N IWTB-C LEA+OSC
N IFTB-0 A.D.#2 1985
PP-OIL LEA+OSC
IWTB-COAL LEA+OSC
N IWTB-C A.D.fl 1985
IFTB-OIL LEA+FGR
PP-OIL LEA+OSC+FGR
IWTB-OIL LEA+OSC
IWTB-COAL C.M.+NH3
PP-COAL C.M.+NH3
N PP-C A.D.#2+NH3
N IWTB-0 A.D.I2+NH3
PP-OIL C.M.+NH3
N IWTB-C A.D.+NH3
IWTB-OIL C.M.+NH3
G.T. (PEAK) H20 INJ
Cost Per Unit
Change in Air Quality
106$/(pg/m3)
-43.8
-40.2
-38.3
-20.5
-18.6
-19.7
- 3.98
- 3.47
- 2.94
- 2.62
- 0.923
- 0.673
- 0.408
- 0.397
0.294
0.335
0.709
0.789
0.821
0.712
0.918
1.01
1.04
1.76
1.79
1.94
1.97
2.39
4.29
4.51
4.56
5.22
5.25
6.14
6.46
11.16
% Red/Unit
40
60
80
40
60
80
6
12
10
10
16
17
17
11
14
43
22
40
20
50
24
67
45
20
40
40
58
17
60
55
71
75
79
70
58
30
N - New
C - Coal
0 - Oil
A.D.  -Advanced design
C.M.  -Combustion modifications (LEA, OSC, FGR)
COMM - Commercial
CCGT - Combined cycle gas turbine
EGR - Exhaust gas recirculation
FGR - Flue gas recirculation
FTB - Firetube boiler
FURN - Furnace
H20 INJ -Water injection
I, IND - Industrial
INST - Institutional
LA — Large
LEA - Low excess air
MED - Medium
OSC - Off-stoichiometric combustion
PP - Power plant
RES -Residential
SM - Smal1
WTB -Watertube boiler
                                   7-52

-------
diverse equipment types  in  these categories.  Control costs and emission reduction information would
be little more than guesswork.   Certainly there is potential for reduction in both categories; how-
ever, omission of control methods did not have significant impact on the conclusions.  To verify
this, all the cases were run with a specified reduction in emissions from these two categories of
20 percent  in 1985 and 60 percent in 2000.  The result was to slightly decrease the control level
necessary to meet the ambient standard.  In most cases one or two fewer other sources required control.
       In Tables  7-31 and 7-32 there are a few entries that appear to be out of order.  For example,
in Table 7-31 entry number  13 is more cost effective than the preceding entries.  This is a conse-
quence  of the ranking process in the screening model.  Second generation advanced designs of new
equipment were  forced to follow the new design in ranking.  (In the example above, Entry 13 is the
second  generation advanced  design for internal combustion engines.)  This was done for two reasons.
The first,  and  most obvious, is that the new design will be available before its own second genera-
tion and should therefore be given first consideration.  The second is that the need for a second
generation  advanced design  can be assessed independently of its relative cost advantage.  If the
new design  did  not provide  sufficient reduction there would be some incentive to accelerate develop-
ment of more  advanced  designs.
       Figures  7-3 and  7-4  show the cumulative cost and reduction in ambient concentration resulting
from the application of the controls in the order given in Tables 7-31 and 7-32 respectively.   The
location of most  of the controls is indicated on the figures.  The most striking feature of both fig-
ures is that  the  cumulative net cost for stationary control, up to ammonia injection, is negative.
This result is  heavily  dependent upon the fuel savings or fuel penalties assigned to the control
methods and upon  the price  of fuel.  The major contributions (>60 percent) to the cost savings are
the second  generation advanced designs for residential and commercial furnaces (10 percent fuel
savings).   Without these two the break-even point occurs at a much lower level of control.  This
strongly suggests that  the  improved designs for these two sources should be vigorously promoted not
only for the  emission reduction but also for the significant fuel and cost savings potential.
       Another  interesting  feature of these figures is that the total reduction in ambient concen-
tration from  all  the controls is clearly evident.  Those source/control combinations which have the
                                               7-53

-------
             O
             o
             
-------
    +J
    1C
    in
    o
    o
10
                                    15       20       25      30       35


                                Cumulative reduction in ambient concentration
                                                 40
                                                                                     45
Figure 7-4.   Cumulative cost and  reduction in ambient concentration for application of the
              controls in Table  7-32  (preliminary process  data,  Chicago, 2000,  nominal
              growth, 1973 concentration = 96 ug/m3).

-------
greatest reduction potential can be easily  identified.*  This  information  is  more useful  than cost
effectiveness along in setting priorities for standards or control  development.
       The results and implications of Figures 7-3 and 7-4 are  considered  to  be  very tentative at
this point and are critically dependent upon the process and cost  information, the modeling  assump-
tions, the growth scenarios, and the source weighting factors.
       Control rankings such as those discussed above are created  for each case  of the evaluation
matrix.  These rankings are then used to establish the level of control needed for each case.   These
results are  discussed in the following paragraphs.

7.1.4.2  Ambient Air Quality
       The overall purpose of the preliminary screening effort  is  to identify the  extent of  combus-
tion modifications that are likely to be needed in the future to attain and maintain  NO -related
                                                                                       A
ambient standards.  Results from this analysis are, therefore,  presented in terms  of  the general
degree of control required to meet the annual average NOo standard.  This  method of presenting  the
results is used to avoid obscuring comparisons of the various cases by the details of exactly
which control methods are required.  The degrees of control (0, 1,  2, 3; see Table 7-33) are
defined in terms of the groupings given in Tables 7-31 and 7-32.
       Results for approximately half of the cases described in the previous section  (Section 7.1.3)
are presented here.  These represent the extremes of the base year ambient concentrations, the two
mobile growth and control scenarios, the two stationary source  growth scenarios, and the case of re-
duced power  plant impact and increased mobile impact.  These cases effectively bound all the scenarios
examined.  Differences in results between these cases and those not discussed are minor.
             The results for Los Angeles are given in Table 7-33.  For each combination of growth scenario,
base year concentration and source weighting factor, the required  level of control for both  1985 and
2000 is shown.  The most obvious conclusion is that the control level required is dominated  by  the
assumptions  on the mobile source emissions.  This is not really surprising since mobile sources
accounted for 66 percent of the NOX emissions in 1973.  In the  low mobile  case the combination  of
low growth (1 percent per year) and stringent controls (0.25 g/km in 1981) results in a 63 percent
*
 The distance along the horizontal  axis in Figures 7-3 and 7-4 is a measure of the potential impact
 on ambient concentration of each control  method.  It is a combination of the total emissions con-
 tribution of the source and the effectiveness of the control method.  In the case of combinations
 of controls (LEA+OSC) or improvements in  design (second generation) only the additional improvement
 is credited to the method.
                                                7-56

-------
           TABLE 7-33.   SUMMARY OF CONTROL LEVELS REQUIRED TO MEET N02 STANDARD IN LOS ANGELES, AQCR 024
r
in
Case
Nominal Growth
Low Mobile
High Stationary
BYR = 132 yg/m3
PP = 1.0
MS = 1.0
1^""^
^"3
C 1^^
^^"0
2^-"^
^•^v
PP = 0.7
MS = 1.2
ฐ^^
^^
0 /^""
^U
^^^
/^*
BYR = 160 ug/m3
PP = 1.0
MS = 1.0
3 1^"""
^^
2>^
^l
3>^^^
^v
PP = 0.7
MS = 1.2
3^/^"
^^V
ฐ^^^
^ง
V^^
^^V
0 — No additional control required
1 -Controls from Group I
2 — Controls from Groups I and II
3 — Controls from Groups I, II, and III
V - Violation of NAAQS, insufficient controls to meet ambient
standard
                                                                                             1985.
                                                                                                 2000
                 PP - Power plant weighting factor
                 MS - Mobile  source weighting factor
                 BYR  - Base year ambient concentration for calibration

-------
reduction in mobile emissions in 1985 and a 66 percent reduction in 2000.  This more than offsets the
growth in stationary sources and results in a net reduction in total emissions of 36 percent and 38
percent respectively.  This level of reduction is enough to achieve the ambient standard except in
the 160 pg/m3 base year case.  Even in the nominal mobile case, a slight increase in the weighting
of the mobile sources has significant impact in 1985.
       In contrast to the low mobile cases, maximum control is needed for all other cases in 2000,
and also for the high base year ambient concentration case in the near term (1985).  Both of these
are again consequences of the dominance of the mobile sources -control of the stationary sources
cannot yield sufficient emission reduction to offset growth and the large mobile source emissions
contribution.
       These results strongly suggest that all possible stationary source control  methods may have
to be implemented.  According to the results discussed above, which admittedly are based only on N02
ambient goals, a less vigorous approach could be justified only if all  of the most favorable assump-
tions were valid (i.e., low base year concentration, low mobile growth, strict and effective mobile
control, and validity of the higher mobile weighting assumption).  It is unreasonable to expect  that
all of this will happen and imprudent to plan1control  development on such  an  assumption.  For the
short term the current combustion modification control technology might be sufficient if a  favorable
mobile situation exists.  For the longer term, however, all the advanced control  methods presently
considered should be pursued, including ammonia injection, and research on even more effective
methods seems justified.
       The results for Chicago are shown in Table 7-34.  Control  of stationary sources is required
in all cases except for 1985 if the base year (1973) concentration of 96 yg/m3 is  appropriate.   The
principal reason for this (no control in 1985) is that the reduction in mobile source emissions*
counterbalances the growth in stationary sources.  For example, in the  nominal growth case,  mobile
source emissions in 1985 are 123 Gg below their 1973 level; whereas, stationary sources have in-
creased by only 112 Gg.   In the high stationary growth case, however, an increase  of 154 Gg for  sta-
tionary sources in 1985 is enough to require a small amount of control.  Even with the low base  year
concentration the complete range of combustion modification controls is needed in  the year 2000.
For the high base year concentration cases combustion modifications and ammonia injection are not
always sufficient,  and even in the low mobile case combustion modification controls are needed.
*
 Mobile source emissions in 1985 are reduced by 50 and 57 percent of the 1973 level for the nominal
 and low mobile cases, respectively.
                                                7-58

-------
                  TABLE 7-34.  SUMMARY OF CONTROL LEVELS REQUIRED TO MEET N02 STANDARD IN CHICAGO, AQCR 067
Ul
<0
                Case
          Nominal  Growth
           Low  Mobile
           High Stationary
                                      BYR = 96 yg/m3
                             PP
                             MS
1.0
1.0
PP = 0.5
MS = 1.2
PP
MS
0.2
1.0
                                       BYR = 120 yg/m3
PP
MS
1.0
1.0
PP = 0.5
MS = 1.2
PP
MS
0.2
1.0
           0 — No additional  control  required
           1 - Controls from  Group  I
           2 - Controls from  Groups I and  II
           3 — Controls from  Groups I, II,  and  III
           V - Violation of NAAQS,  insufficient controls  to meet ambient standard
                                                                                                                    2000
           PP — Power plant weighting factor
           MS -Mobile source weighting factor
           BYR - Base year ambient concentration  for calibration

-------
(The 1973 mobile emissions constitute 38 percent of the total; consequently, mobile emissions are
not as dominant as in Los Angeles.)
       The conclusions for the Chicago AQCR are essentially the same as for Los Angeles.  For the
long term all combustion modifications will be required and, in some cases, will not be sufficient
to meet the annual standard.  In the short term, combustion modifications are needed unless the low
base year concentration is valid (see Section 7.1.3.2 for a discussion of this value).
       These conclusions can be qualitatively extended to many of the AQCRs identified in  Table
7-2 as Priority AQCRs and AQMAs.  Those that are heavily mobile dominated (Group 4, Table  7-4)
will respond to stationary source control in much the same manner as Los Angeles.   It is quite
likely that for these AQCRs, mobile source controls (0.63 g/km) would be sufficient for the short
term; however, combustion modifications to stationary sources would be required in the long term.
The stationary source dominated AQCRs, particularly those in the upper half of Table 7-2,  will
likely require combustion modifications, and perhaps ammonia injection, in both the near term and
far term.

7.1.4.3  Comparison with Related Studies
       The conclusions for the required control levels for both Los Angeles and Chicago are very
similar to those of other studies,  for example, the DOT study (Reference  7-29) and an EPA study  (Ref-
erence 7-30). Both of these studies reported that neither Los Angeles nor Chicago could achieve the
ambient standard with even maximum stationary source control and 0.25 g/km mobile controls.   The re-
sults here indicate that it may be possible in favorable circumstances.  The primary differences be-
tween the present analysis and the two cited above are in the growth rates and the base year ambient
levels for which the models were calibrated.  The DOT study allowed stationary sources to  grow  at
3.9 percent per year.  The EPA study considered 5 percent per year growth and a base year  concentra-
tion of 182 pg/m3.  Because of growth restrictions in Los Angeles (see Section 7.1.3.3), an effective
annual growth of about 1 percent per year for the aggregate of the stationary sources was  used  in
this work.  In Chicago, electric power plant growth was much less than 3.9 percent, primarily be-
cause of growth in nuclear capacity.  These factors account for the difference between never meeting
the standard and possibly meeting the standard.  These differences also help to illustrate the  in-
fluence of the basic assumption (growth rate, base year concentration, and source weighting factors)
on the quantitative results.  However, the following qualitative conclusions remain the same.
                                                7-60

-------
7-1.4.4  Conclusions
       The conclusions of this portion of the  analysis  can  be  summarized as follows:
       t   NOX controls for residential furnaces  and  small  commercial furnaces yield substantial
           reductions in fuel use and can significantly effect the  break-even point in the cost
           for stationary source control strategies
       •   The order in which controls should  be  implemented is significantly influenced by the fuel
           savings features of the control method and,  of course, the availability of the technology
       •   For the short term, combustion modifications for stationary sources will be needed for
           most of the priority AQCRs.  Both retrofit and "new design" controls should be developed -
           particularly those that also result in an  energy savings
       •   For the long term, all combustion modifications  and ammonia injection will be required.
           This is probably the case even for  the minimum mobile source emissions case (low growth,
           0.25 g/km).

 7.2    SUMMARY OF SOURCE/CONTROL PRIORITIES
       This section combines the results of Section 7-1 with those of other sections to set NO  E/A
 program priorities on sources and source/control  combinations.  The source priorities will  be used
 to determine the order in which the process engineering and environmental assessment studies will  be
 conducted for the major source categories (utility boilers, industrial and commercial  boilers, gas
 turbines, commercial and residential warm air  furnaces, 1C engines and industrial  process combustion
 equipment).  The source priorities will also guide the  level of effort to be devoted to the study of
 each major source category and to individual design types within the category.  These studies will
"focus primarily on near-term source/control  applications; far-term application of  emerging  technology
will  be studied later in the program.   The source/control priorities will  be used  to determine which
source/control  combinations will  be given major or minor emphasis  in the  near-term process  studies
and which will  be  emphasized in the far-term studies.   The source/control  priorities will  also guide
the field test  program.   Other factors  such as site availability and the  potential  for teaming ar-
rangements will  also have a significant role in the test priorities.
       The source  prioritization  used  the following sequence:
       •    Subdivide major source categories (utility boilers)  into source/fuel  categories  (coal-
           fired utility);  further subdivide to major design types (tangential)  likely to be exten-
           sively  controlled for  NO ,  and minor design types (vertical)  not likely to be extensively
           controlled due to dwindling  use and/or lack of control  flexibility

                                                7-61

-------
       •   Assess the extent to which controls are in use or are planned for each source/fuel cate-
           gory
       •   Rank source/fuel categories on basis, of nationwide mass emissions of NOX
       t   Assess the relative baseline environmental impact potential for each source/fuel category
       •   Identify the relative effectiveness of near-term and far-term source control implementa-
           tion in maintaining 'air quality in urban areas
Table 7-35 summarizes the results of this prioritization sequence.   The prioritization is largely
qualitative due to the uncertainty and lack of data in these areas.   The considerations which were
made in constructing Table 7-35 are summarized below.

Source Categorization
       The division of the source/fuel category into major and minor design types  used the results
of Section 2 of this report.  The major design types are those, which in the near-term, will  be
subject to NO  controls.   The designation "major" implies a design  type will  be given primary empha-
sis in the process studies and is a candidate for the field test program.   The  minor design types
are either obsolete or difficult to control  and therefore unlikely  to be subject to  significant  NOX
controls.  The minor design types will be given secondary emphasis  in the process  studies and will
not be candidates for field tests.  It should be noted that minor design types  are not necessarily
insignificant sources of NO .   For example,  cyclone boilers emit 8  percent of stationary source  NO
                           X                                                                      A
and rank fourth among all stationary source design/fuel  combinations (see Table 5-33).  Yet,  the
cyclone combustion characteristics make them very difficult to control for NO .  Their sale has
been discontinued and it  is unlikely many existing units will  be controlled for NO .   Other consider-
ations made in the source categorization  are as follows:
       •   Vertical- and  stoker-fired utility boilers are obsolete;  although they  are amenable to
           some control,  the current application  is insignificant
       •   Firebox and horizontal  return  tube package firetube boilers are dwindling in use in favor
           of the scotch  design;  the vast majority of new sales to meet the planned  NO  standard
           will  be of the scotch  design
       •   Firetube stokers are dwindling in number due  to cost
       •   The  use of NOX controls on space  heaters in the near term is unlikely
       •   Insufficient data are available to divide  industrial  process combustion equipment into
           major  and  minor design  types
                                                7-62

-------
                                TABLE 7-35.  EVALUATION OF NOX  E/A SOURCE PRIORITIES
Source Category
Coal-fired utility
011-flred utility
Gas-fired utility
Coal-fired watertube
011 -fired watertube
Gas- fired watertube
Coal -fired flretube
01l-f1red flretube
Gas-fired flretube
Gas- and oil-fired
gas turbines
Gas- and oil-fired
warm air furnaces
Compression Ignition
1C engines (dlesel
fuel and mixed)
Spark Ignition
1C engines
Industrial process
combustion
Major
Design Types
In E/A Program
Tangential ,
single and
opposed wall-
fired, turbo
Same as above
Same as above
Pulv. Stoker-
spreader
Single and
multl burner
Single and
multlburner

Scotch
Scotch
Industrial ,
utility,
simple cycle
Res., Conn.
furnace
Turbocharged
Turbocharged
naturally
aspirated
Process heat-
ers, furnaces,
kilns
Minor
Design Types
1n E/A Program
Cyclone,
vertical,
stoker
Cyclone

Underfeed/
overfeed


Stoker
Firebox, HRT
Firebox, HRT
Comb, cycle
repowerlng
Space
heaters
Blower
scavenged


Degree of
Control
Implementation
All new sources, moder-
ate for existing sources
Extensive for existing
sources
Same as above
Low for existing,
Impending for new
Same as above
Same as above
Same as above
Same as above
Same as above
Moderate for existing
sources, Impending for
new sources
Increasing use for
energy conservation
Negligible for existing
sources; Intending for
new sources
Same as above
Negligible
Nationwide
NOv Emission
Ranking
1
4
3
5
10
7
14
6
9
11
12
8
2
13
Relative
Impact b
Potential"
H
M
L
H
M
L
H
M
L
L
L-M
L-M
L-H
M-H
Source
Need/Effe
Near term
H
H
H
H
H
H
M
H
H
H
H
H
H
M
Control .
:t1veness
Far term
H
L
L
H
H
M-L
L
H
M-L
H-N
H-M
M-L
M
M-H
Source
Ranking
1n E/A
Program
1
3
8
2
6
11
14
5
12
4
7
10
9
13
"Major refers to sources likely to be controlled for NOx; minor refers to  sources for which controls are unlikely to be Implemented 1n the near term.
bH > high; M = medium; L -  low

-------
The growth projection and design trends taken from Section 2 for this prioritization are  preliminary.
They will be studied in greater detail later and Table 7-35 will be updated as necessary.

Control Implementation
       The information for the "Degree of Control Implementation" column on Table 7-35 is taken from
Section 4.1.  Since the assessment of current controls application is a major objective of the N0x
E/A, the degree of control implementation is a dominant criteria in setting source priorities.  To
date, the vast majority of stationary combustion source NOX controls has been on utility boilers.
Gas and oil units have been the most extensively controlled, but an increasing number of standards
have been set recently for coal units.  No new gas- or oil-fired units are being sold, so N0x controls
for coal units via the New Source Performance Standards (NSPS) will dominate in the future.   Other
sources with current control applications are large industrial boilers and gas turbines.  NSPS are
also planned for these sources along with 1C engines.  The lead time for implementing the standard
and delivering new unit orders is typically several years.  Thus, the degree of control application
for these sources will not be comparable to that for utility boilers in the near term.  This
fact alone is sufficient to rank utility boilers as the top priority in the N0x E/A.

Nationwide Emission Ranking
       The ranking of design/fuel types by nationwide mass emissions of NOX is given in Table 5-33.
These  results have been consolidated on Table 7-35 for the specific source categories listed there.
Nationwide mass emissions are useful for weighting relative emission contributions of various sources
and detecting emission trends independent of local variations.  They are used within the EPA to set
priorities on emission standards.  Use of nationwide emissions does suffer a drawback, however, in
that it does not account for variations among source categories in proximity to population centers
and variations in regional use of specific source/fuel types.  These factors were qualitatively
included in the relative impact potential column.  These  factors will be quantified later in the
NO  E/A and used for a formal ranking of sources according to pollution potential.

Relative Impact Potential
       The ranking of sources by relative impact potential was based on the multimedia emissions
inventory of Section 5 and the evaluation in Section 7.3  of potential adverse  impact  of  these emis-
sions.  Although impacts due to NO  controls were  not  considered  in the evaluation,  the  results 'Of
                                  X
Section 6 were useful in relating design type and  fuel to potential for emissions  of  specific  pol-
lutants (e.g., organic emissions from 1C engines)  where firm  emission data were sparse.   Additionally,
                                                7-64

-------
the proximity of specified sources (e.g., residential  furnaces) to populated areas was also consid-
ered.   As shown on Table 7-35, the relative impact potential resulting from the above considerations
was generally high for coal firing, medium for residual oil firing, and low with the firing of clean
fuels.   The borderline L-M for residential furnaces resulted from the proximity of these sources to
populated areas and the potential for increased emissions during cycling transients.  1C engines were
also a borderline case.  Even though they fire clean  fuels, the emissions of organics are much higher
than for other sources.  Little emission/impact data  are available for industrial process furnaces.
They were rated M-H on the basis of fuel use.

Effectiveness of Source Control in Air Quality Maintenance
       These criteria are  based on the results of the air quality screening analysis discussed in
Section 7-1.  Separate consideration is  given to near-term effectiveness and to far-term effectiveness
in order to isolate effects of design trends and growth projections for source categories.  The
analysis in Section 7.1 showed that the  need for bringing specific source categories under control
is highly uncertain.  The  estimated control needs were found strongly dependent on growth projections,
assumptions on future mobile  source control, measurements of ambient concentrations of NO-, and the
relative weighting of the  NO^ air quality impact emissions from point sources (power plants) and
ground level sources (mobile  sources).   These factors  are all  in a state of flux.  Assuming optimistic
resolution of these factors (in terms of stationary source air quality impact), only moderate control
of major stationary sources will be needed in the near term (1985).  Assuming moderate or pessimis-
tic resolution of these factors, however, implies the  need for extensive near-term control of station-
ary sources.  In the far term (2000), extensive control is generally needed regardless of assumption.
For purposes of setting priorities in the NO  E/A program, the estimated control needs for moderate or
pessimistic assumptions are used.  This  is because the NOX E/A is largely a problem definition study
and its purposes would not be served by  using optimistic assumptions on the potential  for adverse
impact.  For the moderate or worst case  scenarios, the estimated near-term control needs, as shown
on Table 7-35, are generally  high for all source categories.   For the far term, the needs are focused
on extensive control of new sources.  Thus, sources with dwindling new sales due to design trends or
fuel availability are derated in the far term.   As expected, the trend is for increasing use of coal
and oil and decreasing use of gas.   The  projected availability of clean fuels for industrial sources
and gas turbines will  be examined in more detail later in the  program.

Overall Source Ranking
       The  final  column on Table 7-35 gives a qualitative ranking of the 13 source/control categories.
In deciding  this ranking,  the  degree of  control  implementation and the relative impact potential were

                                               7-65

-------
given the most weight.  Based on this ranking, the process and environmental  assessment studies  in
the NO  E/A will be conducted in the follov/ing sequence:
      X
       1.  Utility and large industrial watertube boilers
       2.  Industrial and commercial packaged boilers
       3.  Gas turbines (simple cycle and combined cycle)
       4.  Residential and commercial warm air furnaces
       5.  Reciprocating internal combustion engines
       6.  Industrial process combustion equipment
Within each of these studies, the relative effort for specific source/fuel categories will follow
the order of ranking of Table 7-35.
       The source prioritization discussed above is extended on Table 7-36 to include consideration
of specific source/control combinations.  The table shows which source/control combinations are to re-
ceive major or minor emphasis in the six process studies of near-term applications listed above.
The table also shows preliminary selection of which advanced source/control combinations will  be
evaluated in the later study of far-term applications.  The prioritization of current technology
was based directly on the information in Section 4 (see Tables 4-26 and 4-27).  The prioritization
considered the extent of current applications of specific source/control combinations and the  cost
effectiveness of a given control compared to competitive techniques.  Major emphasis will be given
to the vast majority of source/control  combinations likely to see significant control in the next 5
years.  The selection of advanced techniques for study in the far-term effort was also based on Sec-
tion 4.   The developmental status and schedule as well as the potential availability of competitive
techniques were considered.  The selection of advanced techniques also considered the results  of
Section 7.1  which showed the need for advanced combustion modifications and, possibly, ammonia in-
jection in the 1980's and 1990's.  Advanced techniques which are being covered by other assessment
efforts (e.g., fluidized beds, advanced cycles) will  be given minor emphasis in the far-term effort.

7.3    POLLUTANT/IMPACT SCREENING
       The source/control  combinations  prioritized in Section 7.2 are further evaluated here to
identify specific pollutants which may  cause adverse  environmental impact with or without NO  con-
                                                                                            A
trols.  These results will  be used to set priorities  for the sampling and chemical analyses to be
done during  the later field test programs.  The emphasis in the pollutant/impact screening is on
flue gas emissions.   The data on liquid and solid effluent streams are very sparse.  They will
                                                7-66

-------
                                                     TABLE 7-36.
                                                                    SUMMARY OF NOX  E/A SOURCE/CONTROL PRIORITIES
Source
Ranking
1

3, 8
2

6. 11
14
5. 1Z
4
7
9
10
13
Source
Coil-fired utility
boilers, existing
Co*1-f1red utility
boilers, new
01l-f1red, gas-
fired utility
boilers
Coal -fired water-
tube, Industrial-
pulverized
Coal-fired water-
tube Industrial -
stoker
011-flred. gas-
fired watertube
Coal-fired fire-
tube stoker
Oil-fired, gas-
fired flretube
Sas- * oil-fired
gas turbines
Gas- t oil-fired
warn air furnace
Spark Ignition 1C
engines
Compression Igni-
tion 1C engine
(diesel. mixed fuel
Industrial process
combustion
NEAR TERN EFFORT IN E/A PROGRAM: CURRENT AND IMPENDING APPLICATIONS
Major Emphasis -
Sources1
Tangential, opposed 1
single wall, turbo-fired
Sane as above
Sane as above
Single or multlburner
wall-fired
Spreader
Single or mUlburner
wall-fired

Scotch
Utility. Industrial
simple cycle
Residential, commercial
furnaces
Turbocharged. natural-
ly aspirated
Turbocharged
Process heaters,
furnaces, kilns
Major NO. E/A
Emphasis - Controls
LEA. BBF. BOOS. OFA.
low-NOx burners
LEA 1 OFA; 1ow-NOx
burners, enlarged
firebox
LEA. BBF, BOOS, OFA.
F6R
LEA, BBF. BOOS. OFA.
low-NOx burners
LEA, OFA
LEA, OFA. low-NOx
burners

LEA, FGR. OFA. low-
NOx burners
Hater Injection
Low-NOx burners
Operational tuning,
reduced Inlet air
temperature
Operational tuning
LEA, load reduction,
RAP. FGR. H20
Injection
Minor NOX E/A
Emphasis — Sources
Cyclone, vertical
stoker

Cyclone

Underfeed/overfeed

Firebox, horizontal
return tube
Firebox HRT
Combined cycle,
repowerlng
Space heaters

Blower scavenged
Low-NOx burners
Minor NO, E/A h
Emphasis - Controls"'0
FGR. RAP. Hป0 inj..
load reduction,
NH3 injection
FGR, RAP, H20 Inj..
NHa injection
RAP, HzO Inj., NHs
Injection
Load reduction

Load reduction
LEA
Load reduction
Can modifications

EGR. derate
Derate

FAR TERM EFFORT IN E/A PROGRAM:
ADVANCED TECHNOLOGY
Major
Emphasis
NH3 Injection
Advanced OFA
techniques;
adv. low-NOx
burners, NH3
Injection
Advanced low-
NOx burners,
NH3 Inj.
Advanced low-
NOx burners,
advanced OFA,
NH3 injection
Factory
Installed
OFA. NH3 Inj.
Adv. low-NOx.
burners, adv.
OFA, NH3 Inj.,
alt. fuels

Adv. low-NOx
burners, adv.
OFA, alt. fuels,
catalytic comb.
Adv. can design,
comb, cycles,
alt. fuels.
catalytic comb.
Adv. burner/
firebox des.,
alt. fuels.
catalytic comb.
Chamber redesign,
alt. fuels
Chamber redesign
alt. fuels
loH-NO, burn-
ers. OFA,
alt. fuels
Minor
Emphasis

Flue gas
treatment;
fluldized
beds; adv.
cycles
Chemically
active
fluid bed







Exhaust
gas
treatment


 I
o>
               *Major refers to sources  or controls emphasized In near  term control programs; minor refers to  sources or controls  less  likely to be used.

               bLEA • low excess air;  BBF  • biased burner firing; BOOS  • burners out of service; OFA • overflre air; FGR • flue gas  reclrculatlon; RAP ซ reduced air preheat

-------
therefore be sampled during the test program to obtain the data needed for a pollutant/impact
screening such as done here for flue gas emissions.
       The set of pollutant classes under consideration was described in Section 6 and includes carbon
monoxide, vapor phase hydrocarbons, particulates, sulfates, condensed phase organics, and trace
metals.  Several of these classes can be further speciated into more detailed pollutant groups, which
give a better representation of potential health/welfare hazards, as was done in Section 3.  For ex-
ample, the vapor phase hydrocarbon class is comprised of alkanes, alkenes, alkynes, aldehydes, car-
boxylic acids, and aromatics.  (Of course sulfates, organics, and trace metals are generally emitted
as particulates, but the particulates class has been separately discussed because it is a criteria
pollutant, and because more emissions data on this class of pollutants are available.)
       Baseline emissions for each pollutant species group, as a function of combustion source class,
were tabulated and discussed in Section 5.  In addition, Section 6 tabulated (where data were avail-
able) and discussed the incremental emissions of these pollutant groups as a function of applied NO
combustion control.  The health and welfare aspects of each species/group were discussed in Section
3 in terms of developing a set of maximum ambient screening concentrations.  By combining information
developed in each of those sections with the dispersion model (which relates ground level  pollutant
concentrations to single source emission levels as a function of combustion source) described in Ap-
pendix D, it is possible to flag the pollutants from each combustion source which represent poten-
tial environmental hazards due to applying NO  controls.
       Such a summary appears in Tables 7-37 and 7-38.  Table 7-37 shows baseline emissions, typical
emission levels with NO  controls, maximum ambient screening concentrations (from Section 3), and
derived maximum allowable emission level (from the dispersion model) for the pollutant groups under
consideration.  The pollutant groups listed in Table 7-37 are those for which incremental  emissions
data are available.  Table 7-38 shows a similar summary for those pollutants groups for which little
or no field data exist on the incremental effects of NO  combustion controls.
       From the data presented in Tables 7-37 and 7-38, it is possible to identify those pollutant
groups which are emitted at levels near, or exceeding, the defined maximum allowable emission level.
For current purposes, pollutant group/combustion source combinations are flagged if emission levels
with NOV control data (Table 7-38), or baseline emissions in the absence of incremental NO  control
       A                                                                                  *ป
data (Table 7-38) exceed 10 percent of the maximum allowable level.  These combinations are noted
in Tables 7-37 and 7-38, and further summarized in Table 7-39.
                                                7-68

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   TABLE  7-37.  COMPARISON OF POLLUTANT  EMISSION LEVELS WITH NOX  CONTROLS  TO MAXIMUM ALLOWABLE EMISSIONS
Pollutant Class
Carbon Monoxide





Total Vapor Phase
Hydrocarbons


Partlculates




Combustion
Source

Utility Boilers
Industrial Boilers
Residential Units
1C Engines
Gas Turbines
Utility Boilers
Industrial Boilers
Residential Units
1C Engines
Gas Turbines
Utility Boilers
Industrial Boilers
Residential Units
1C Engines
Gas Turbines
Fuel

Natural Gas
Oil
Coal
All Fuels
Natural Gas
Oil
All Fuels
All Fuels
Natural Gas
Oil
Coal
Natural Gas
Oil
Coal
Natural Gas
Oil
All Fuels
All Fuels
Natural Gas
Oil
Coal
Natural Gas
Oil
Coal
Natural Gas
Oil
Oil
01 1 i Kerosene
Maximum
Ambient
Concentration
(ppb)
9,000





240



(mg/m>)
0.075




Maximum
Allowable
Emission Level
(ppm)

110,000
920,000
529,000
920,000
920,000
2,930
24,500
14,100
24,500
24,500
(g/m3)

0.91
7.65
4.41
7.65
7.65
Baseline
Emissions
(ppm)

23-175
25-46
23-96
0-110
40
90
90-10,300
53-970
0-35
0-30
0-40
10-25
0-15
10-90
20
25
60-4,600
0-230
(g/ป3)

0.01
0.11
0.42-2.73
0.01
0.01-0.63
3.9-5.1
0.01
0.03
0.02-0.04
0.03-0.08
Emissions
with NOX
Control s
(ppm)

25-65
10-35
20-148
0-220
„
90-3,280
51-1,320
> 0-40
| 0-35
~
80-6,400
0-1 ,200
(g/ซ3)

0.60-2.6
<0.03
0.02-1.23b
7.5-10.0b
0.01
0.03
<0.26C
0.04-0.09d
Concern
Flag3








+

++
+
4-t


  + denotes emission with  NOX controls greater than 10 percent of maximum emission  level.
 ++ denotes emission with  NOX controls greater than maximum emission  level.
bNOx control by off-stoichiometric combustion.
CNOX control by exhaust gas recirculation.
 NOX control by derating.

-------
TABLE 7-38.   COMPARISON  OF BASELINE POLLUTANT  EMISSION LEVELS TO MAXIM  ALLOWABLE EMISSIONS
Pollutant Class/Group
Vapor Phase Hydrocarbons'1
Alkanes


Alkenes


Alkynes


Aldehydes


Carboxylic Acids

Aromatics (benzene
and one-ring
derivatives)
ป
Sul fates

Organics (POM's)
Anthracene



Phenanthrene



Combustion Source

Utility Boilers
Industrial Boilers

Utility Boilers
Industrial Boilers

Utility Boilers
Industrial Boilers

Utility Boilers
Industrial Boilers

Utility Boilers
Utility Boilers

Utility Boilers


Utility Boilers
Industrial Boilers
Residential Units

Utility Boilers
Industrial Boilers
Residential Units
Fuel

Natural Gas
Oil
Coal
Oil
Coal

Natural Gas
Oil
Coal
Oil
Coal

Natural Gas
Oil
Coal
Oil
Coal

Natural Gas
Oil
Coal
Oil

Natural Gas
Oil
Coal
Natural Gas
Oil
Coal

Natural Gas
Oil
Coal


Coal
Oil
Coal
Coal

Coal
Natural Gas
Oil
Coal
Coal
Maximum
Ambient
Concentration
(ppb)
4,420


59,500


62,700


2.1


13

0.002
(mg/m3)
0.002

(ppt)

0.14



4,000



Maximum
Allowable
Emission Level
(ppm)

54,000
450,000

725,000
Unlimited

765,000
Unlimited

25.6
214

159
0.024
(9/m3)

0.024
(ppb)


1.71
14.3
8.2

50,000
420,000
240,000
Baseline
Enissions
(ppm)

<80
<15
<10
<40
<150

<80
<15
<10
<40
<150

<5
<5
<10
<5
<10

5
5
<10
2.5-200

2.5
6-12
200
<20
<30
<50
(9/m3)

0
0.047
0.056
(ppb)


0.3
2
0.1-0.3
0.4-1,000

0.1-0.3
0.04
0.7-3.7
0.3-3
9-2,300
Concern
Flag"









4
+
+
++

++
++
•H-
++

++
++


+
+-f
++




 + denotes baseline emissions exceed 10 percent of maximum allowable  level
++ denotes baseline emissions exceed maximum allowable level

Maximum ambient concentration and associated maximum allowable emission level for hydrocarbon
primary health hazards.   Effects of secondary (derived) pollutants  are not considered.

                                                 7-70
species consider only

-------
                                            TABLE 7-38.  CONTINUED
Pollutant Class/Group

Organic? (POM's) (Cent.)
Fluoranthrene





Pyrene





Benzo(a)pyrene





Benzo(e)pyrene




Perylene




Trace Metals
As


B


Ba


Be

81

Cd


Co


Combustion Source



Utility Boilers
Industrial Boilers


Residential Units

Utility Boilers
Industrial Boilers


Residential Units

Utility Boilers
Industrial Boilers


Residential Units

Utility Boilers
Industrial Boilers

Residential Units

Utility Boilers
Industrial Boilers
Residential Units



Utility Boilers

















Fuel



Coal
Natural Gas
011
Coal
Coal

Coal
Natural Gas
Oil
Coal
Coal

Coal
Natural Gas
011
Coal
Coal

Coal
Natural Gas
Coal
Coal

Coal
Coal
Coal



Oil
Coal

Oil
Coal

011
Coal

Coal

Coal

011
Coal

011
Coal
Maximum
Ambient
Concentration
(PPt)

10.900





0.121





0.097





0.097




0.097



(ug/m3)

0.825


IE. 5


0.825


0.0033

16

0.00825


0.165


Maximum
Allowable
Emission Level
(ppb)


133.000
1,110.000


641 .000

1.48
12.4


7.1

1.2
9.9


5.7

1.2
9.9

5.7

1.2
9.9
5.7
(mg/m3)


10.1


201


10.1


0.04

195

1.01


2.0

Baseline
Emissions
(ppb)


0.003-0.5
0.04-3.4
0.02-1.8
0.8-10
13-350

0.01-0.5
0.5-7.5
0.005-2.2
0.6-4.5
2-2,500

0.003-0.1
0.006-0.1
0.006-0.3
0.007-2.2
0.008-800

0.007-0.15
0.006-0.5
0.02-1.7
1-330

0.005-0.015
0.35
0.1-770
(mg/m3)


0.004
0.45

0.068
3.41

0.52
0.65

0.52

0.03

0.006
0.12

0.27
0.11
Concern
Flag*









4-
+
+
+
•M-




+
++

•f

+
++



+•+












++




+

+

* + denotes baseline emissions exceed 10 percent of maximum allowable level
 ++ denotes baseline emissions exceed maximum allowable  level

                                                      7-71

-------
                                            TABLE 7-38.   CONCLUDED
Pollutant Clsss/Group
Trace Metals (Cont.)
Cr

Cu

Hg

Mn

Mo

Hi

Pb

Sb

Se

V

Zn

Zr

Combustion Source

Utility Boilers






















Fuel

Oil
Coal

Oil
Coal

Oil
Coal

Oil
Coal

Oil
Coal

Oil
Coal

Oil
Coal

Oil
Coal

Oil
Coal

Oil
Coal

Oil
Coal

Oil
Coal
Maximum
Ambient
Concentration
(vg/m3)
0.001

1.65

16.5

8.25

8.25

0.165

0.247

0.825

0.33

0.825

1.65

8.2

Maximum
Allowable
Emission Level
(mg/ms)

0.012

20.1

201

101

101

2.0

3.0

10.1

4.0

10.1

20.1

100
Baseline
Emissions
(mg/m3)

0.68
0.43

0.55
1.20

0.008
0.23

0.55
1.58

0.55
0.25

32
0.68

0.62
0.59

0.004
0.04

0.632
0.173

47.5
1.20

0.87
9.36

0.17
0.86
	
Concern
Flag"

++
++









++
+

+
+





++
++

+


 + denotes  baseline emissions exceed  10 percent of maximum allowable level
++ denotes  baseline emissions exceed  maximum allowable level
                                                        7-72

-------
TABLE 7-39.  SUMMARY OF POTENTIAL POLLUTANT/COMBUSTION SOURCE HAZARDS
Pollutant Class/Group
Vapor Phase Hydrocarbons
Total
Aldehydes

Carboxylic Acids
One-Ring Aromatics
Participates

Sul fates

Organics
Anthracene


Pyrene

Benzo(a)pyrene

Benzo(e)pyrene

Peryl ene
Trace Metals
Be
Cd
Co
Cr

Ml

Pb

V

Zn
Combustion Source

1C Engines
Utility Boilers, all Fuels
Oil-Fired Industrial Boilers
Coal -Fired Utility Boilers
Utility Boilers, all Fuels
Coal -Fired Boilers
Oil-Fired Industrial Boilers
Coal- and Oil-Fired Utility
Boilers

Oil-Fired Boilers
Coal-Fired Residential Units
Coal-Fired Utility Boilers
Coal-Fired Residential Units
Boilers, all Fuels
Coal-Fired Residential Units
Coal-Fired Industrial Boilers
Coal -Fired Residential Units
Coal -Fired Boilers
Coal -Fired Residential Units

Coal -Fired Utility Boilers
Coal-Fired Utility Boilers
Oil-Fired Utility Boilers
Coal- and Oil-Fired Utility
Boilers
Oil-Fired Utility Boilers
Coal -Fired Utility Boilers
Coal- and Oil-Fired Utility
Boilers
Oil-Fired Utility Boilers
Coal-Fired Utility Boilers
Coal-Fired Utility Boilers
Emission Exceeds
Potential Hazard
Threshold



X
X
X
X


X

X
X

X

X

X

X

X




X



X


Emission Exceeds
10% of Potential
Hazard Threshold

X
X




X





X

X

X

X



X
X



X

X

X
X
                                7-73

-------
       Table 7-39 illustrates that incremental emissions from large coal- and oil-fired boilers



potentially represent most significant environmental  hazards.  Baseline emissions of participate,



sulfates, and certain POM species from this source class currently exceed the derived maximum allow-



able emissions levels, while emissions of several  other POM species are within an order of magnitude



of the maximum limit.  In addition, while emissions of total  vapor phase hydrocarbons from large



boilers were not identified as being of concern, emissions of several  hydrocarbon classes, notably



oxygenates and aromatics, were flagged.  Finally baseline emissions of several trace metals from



coal- and oil-fired boilers were noted as exceeding,  or falling within a factor of 10 of maximum



levels.  It is interesting to note that'six of the eight flagged elements exhibit Class II, or segre-



gating, behavior; they tend to repartition and concentrate in fine particulate.




       Large coal- and oil-fired boilers were not the only source class associated with pollutant



streams of concern.  Incremental total vapor phase hydrocarbon emissions from 1C engines operating



with dry NO  controls exceeded 10 percent of maximum allowable emissions and therefore  represent
           X


another concern.  In addition, baseline emissions of several  organics  from residential  coal  stokers



exceeded maximum limits.  However, the use of coal firing in  residential heating applications  is



definitely declining, so this source/pollutant combination should not  be considered a priority



concern.




       Based on the information presented in Table 7-9, it is clear that further study  is needed



of NO  controls which could increase emissions of:




       •   Particulates from coal- and oil-fired boilers, e.g., off-stoichiometric combustion  (OSC),



           flue gas recirculation (FGR), and ammonia  injection (NH,)




       •   Sulfates from coal- and oil-fired boilers, e.g., OSC, FGR,  and NH3




       •   Organics from coal- and oil-fired boilers, e.g., low excess air (LEA), OSC,  and FGR




       *   Segregating trace metals from coal- and oil-fired  boilers,  e.g., LEA, OSC, and FGR




       •   Vapor phase hydrocarbons emissions from 1C engines, e.g.,  all controls





7.4    FUTURE EFFORT




       This report has:




       1.  Documented the scope of sources, pollutants, impacts and controls to be considered  in the



           NOX E/A
             A



       2.   Evaluated data on impact criteria, control effectiveness,  baseline multimedia emissions



           and incremental  impacts of NOV controls
                                        X
                                               7-74

-------
       3.   Set preliminary priorities on source/control combinations and effluent stream/pollutants
           to be considered
These results will serve to initiate and scope the next efforts;
       •   Screen and rank the pollution impact potentials of uncontrolled sources and effluents (Bl)
           —   Update the Section 5 emissions inventory
           -   Develop approach to assess emissions during nonstandard operation
           —   Generate growth projections of source/fuel use and emissions
           -   Expand impact analysis of Section 7.3
       •   Generate impact screening criteria for Bl and B5 assessments (B2)
           -   Coordinate with other studies developing impact criteria; finalize human health  im-
               pact criteria of Section 2
           -   Decide approach to generalize terrestrial and aquatic impacts
           -   Develop scenarios for alternate N02 air quality standards for  the Task C air quality
               modeling
       t   Conduct field tests of priority source/control combinations (B3)
           -   Survey candidate test sites for coal- and oil-fired utility and industrial  boilers
               and oil-fired gas turbines using NO  controls
           -   Finalize sampling and analysis requirements based on the E/A steering committee  recom-
               mendations and Section 7 results
       •   Generate process engineering and environmental assessment reports  for utility boilers (B5)
           -   Expand process data and control results of Sections 2 and 4
           -   Develop cost model to standardize control cost estimates
       •   Develop systems analysis model with chemistry and dispersion effects (C)
           -   Update model inputs with cost data from B5 and regional  inventories from Bl
           -   Expand control  assessment of Section 7.1 to consider N02-oxidant reactions and a
               short-term N0? standard
These efforts  are discussed in the Preface and illustrated in Figure P-l.
       The  data  evaluations contained in this report have shown the strong need for  setting priori-
ties  in all areas of  the  program.   Serious data gaps exist for baseline and controlled multimedia
                                                7-75

-------
emissions and impacts.  These data gaps make it impossible to consider to a meaningful level all
potential source/control/effluent stream/pollutant/impact combinations within the scope of the NOX
E/A.  The program results will be most useful if the effort is prioritized to allow comprehensive
assessment of fewer source-impact combinations.  The prioritizations contained in this report have
accordingly set the emphasis of the NOV E/A as follows:
                                      A
       •   Sources:  Major emphasis on stationary fuel  combustion sources firing coal  or  residual
           oil and projected to use a significant degree of NOX controls in the near term; less
           emphasis on sources firing clean fuels; minor emphasis on sources which will  not be
           controlled in the near term
       •   Controls:  Major emphasis on most widely used current applications; less emphasis on ad-
           vanced technology; minor emphasis on control techniques not widely used
       •   Effluent Streams and Pollutants:  Major emphasis on flue gas emissions during  steady-
           state operation; less emphasis on liquid and solid effluent streams; minor emphasis on
           emissions during transient or upset conditions
       •   Impacts:  Major emphasis on human health impacts due to inhalation; less emphasis on ter-
           restrial and aquatic impacts and on human health impacts due to ingestion via  the food
           chain; minor emphasis on materials impacts
                                                 7-76

-------
                                      REFERENCES FOR SECTION 7

7-1.    Eschenroeder, A., "An Assessment of Models for Predicting Air Quality," Environmental Research
       and  Technology, Inc., ERTW-75-03.
7-2.    "Air Quality Models Required Data Characterization," Science Applications, Inc., EPRI EC-131,
       May 1976.
7-3.    Personal communication, Dr. Alan Eschenroeder, Environmental Research and Technology, Inc.
7-4.    Personal communication, Mr. Alan Hoffman, Chief Monitoring Section, EPA, October 1, 1976.
7-5.    AEROS - Emission Summary Report, Office of Air Quality Planning and Standards, U.S. EPA.
7-6.    AEROS - Fuel Summary Report, Office of Air Quality Planning and Standards, U.S. EPA.
7-7.    AEROS - National Emissions Summary Report, Office of Air Quality Planning and Standards, U.S. EPA.
7-8.    "Climatic Atlas of the United States, 1974," U.S. Department of Commerce, Environmental  Science
       Services Administration, Environmental Data Service.
7-9.    Star Program, U.S. Department of Commerce, National Climatic Center, Asheville, North Carolina.
7-10.  "AEROS Manual Series, Volume I:  AEROS Overview," EPA-450/2-76-001, February 1976.
7-11.  Trijonis, J. C., et al., "Emissions and Air Quality Trends in the South Coast Air Basin,"
       EQL Memorandum No. 16, Environmental Quality Laboratory, California Institute of Technology,
       Pasadena, California, January 1976.
7-12.  "Monitoring and Air Quality Trends Report," EPA-450/1-76-001, February 1976.
7-13.  "Air Quality Data - 1973 Annual Statistics," EPA-450/2-74-015, November 1974.
7-14.  Personal Communication, Ms. Pamela Henrichs, Ambient Air Monitoring Section,  Division of Air
       Pollution Control, Illinois Environmental Protection Agency.
7-15.  "1973 National Emissions Report, National Emissions Data System (NEDS) of the Aerometric and
       Emissions Reporting System (AEROS)," EPA-450/2-76-007, May 1976.
7-16.  Babcock, L.  R. and N. L. Nagda, "POPEX - Ranking Air Pollution Sources by Population Exposure,"
       EPA-600/2-76-063, NTIS-PB 261  458/AS, March 1976.
7-17.  "Fuel Use and Emissions from Stationary Combustion Sources," Southern California Air Pollution
       Control District, July 1976.
7-18.  "Steam-Electric Plant Air and Water Quality Control  Data for the Year Ended December 31, 1973,"
       based on FPC Form No. 67 -Summary Report FPC-S-253, January 1976.
7-19.  Bartz, D. R., et al., "Control  of Oxides of Nitrogen from Stationary Sources  in the South
       Coast Air Basin," KVB Report No. 5800-1795, ARB 2-1471,  September 1974.
7-20.  Personal  communication,  Mr. Robert Hilousky, Southern California Air Pollution Control
       District.
7-21.  "Energy Alternatives for California:   Paths to the Future," Rand Corporation, R-1793-CSA/RF,
       December 1975.
7-22.  "National Energy Outlook -1976," FEA/N-75/713, February 1976.
7-23.  "A Time to Choose -America's  Energy Future,"  Final  Report by the Energy Policy Project  of
       the  Ford  Foundation,  1974.
7-24.  Personal  communicatton,  Mr. David Simon, FPC,  Chicago Office.
7-25.  Behrin,  E. and R.  L.  Cooper,  "California Energy Outlook," Lawrence Livermore Laboratory,
       UCRL-J1966,  November 1975 (revised February 1976).
                                                 7-77

-------
7-26.  "Meeting California's Energy Requirements,  1975-2000,"  Stanford Research Institute,  SRI
       Project ECC-2355, May 1973.

7-27.  Personal communication, Mr.  David Smith, Southern California  Edison.

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

7-29.  "Air Quality, Noise and Health," Interim Report,  Interagency  Task  Force  on  Motor  Vehicle Goals
       Beyond 1980, March 1976.

7-30.  Yeager, Kurt, "The Effects of Desulfurization  Methods on  Ambient Air  Quality," Advances in
       Chemistry Series 127, 1973.
                                                7-78

-------
                                             APPENDIX A
                                         EMISSION INVENTORY

       Summary emission tables were presented in Section 5.4.  A complete listing of emissions of the
29 pollutants considered for each equipment type, together with emission factors and NOX control  fac-
tors, is given in this appendix which has been subdivided into three parts.
A.I    NONCRITERIA POLLUTANT EMISSION FACTORS
       Emission factors for noncriteria pollutants for utility boilers are presented in Tables A-l
and A-2.  Factors for packaged boilers and warm air furnaces are in Tables A-3 and A-4, respectively.
Trace element emissions were not computed for other equipment types, and no emission factors appear
here.

A. 2    FORMULATION OF NOX EMISSION CONTROL FACTORS
       Controlled NOX emissions from a particular source type (A) firing a particular fuel  (B) were
calculated as
                    Emissions = (FC) x (UEF)ฃf1 {& + (1 -ฃf1) x (FC) x (UEF)
                                             i               i                  .              (A-l)
                               V                      J v
                                        Term 1                    Term 2

  where
           FC = total fuel consumption of fuel "B" in sources of the type "A"
           UEF = uncontrolled  emission factor for source/fuel "A/B"
           f i :  = fraction of FC burned in  controlled sources located in region "i"
           EFi  = regulated emission factor assuming 100 percent compliance for sources of type "A/B"
                 in region "i" (EFi < UEF)
The first term is a sum over all regions "i" in which local control regulations demand an emission
factor lower than the uncontrolled value.   The second term accounts for the uncontrolled sources.
                                                A-l

-------
                TABLE A-l.  SECTOR I NONCRITERIA POLLUTANT EMISSION FACTORS
1
Equipment Type
Utility Boilers
Tangential
Anthracite
Bituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Single Wall-Fired
Anthracite
Bituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Opposed Wall and
Turbofurnace
Anthracite
Bituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Cyclone
Anthracite
Bituminous & Sub
Lignite
Residual Oil
Distillate Oil
Natural Gas
Vertical & Stoker
Anthracite
Bituminous & Sub
Lignite
Residual Oil
Distillate Oil
Natural Gas
Sul fates
(ng/J)


4.73
16.8
3.01
12.9
3.01


4.73
16.8
3.01
12.9
3.01



4.73
16.8
3.01
12.9
'3.01


4.73
16.8
3.01
12.9
3.01


4.73
16.8
3.01
12.9
3.01

POMs Low
(P9/J)


0.957
0.957
0.957
0.862
0.862
0.313

0.398
0.398
0.398
0.862
0.862
0.313


0.398
0.398
0.398
0.862
0.862
0.313

1.84
1.84
1.84
0.862
0.862
0.313

0.474
0.474
0.474
0.862
0.862
0.313
POMs High
(P9/J)


121.3
121.3
121.3
0.862
0.862
27.48

121.3
121.3
121.3
0.862
0.862
27.48


121.3
121.3
121.3
0.862
0.862
27.48

1.84
1.84
1.84
0.862
0.862
0.313

121.3
f21.3
121.3
0.862
0.862
0.862
Dry Removal Ash
(ug/J)a


0.589
0.520
0.37




0.589
0.520
0.37





0.589
0.520
0.370




0.589
0.520
0.370




0.589
0.520
0.37



Liquid Removal Ash
(ug/J)ป


2.36
2.09
1.46




2.36
2.09
1.46





2.36
2.09
1.46




2.36
2.09
1.46




2.36
2.09
1.46



aAsh generation factors based on 65 percent flyash of coal ash and 70 percent collection
 efficiency.  Assumed 80 percent of utilities use sluice (wet) removal and 20 percent dry
 removal  (Reference A-l).
                                              A-2

-------
TABLE A-2.  METAL EMISSION FACTORS (ng/J) - SECTOR I

Utility Boilers
Anthracite
Bituminous
Lignite
Residual 011
Equipment Type
Utility Boilers
Anthracite
Bituminous
Lignite
Residual 011
Al
86.0
81.6
3.7
Cu
558.9x10-'
356.8x10-'
202.1x10-'
150.5x10"'
Sb
0.77x10-'
12.0x10-'
5.59x10"'
1.2x10-'
Pb
98.9x10-'
176.3x10-'
111.8x10-'
167.7x10-'
As
77.4x10-'
133.3x10-'
107.5x10-'
1.2x