rP1 /Fif)/^ RO-OOQ-     United States       Office of Air Quality       EPA-450/3-80-009a
 '  J/ J         Environmental Protection  Planning and Standards      July 1980
              Agency         Research Triangle Park NC 27711  / ,
              Air
                                            PR 
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                                     EPA-450/3-80-009a
              Proposed Guidelines for
            Determining Best Available
       Retrofit Technology for Coal-Fired
              Power Plants and Other
             Major Stationary Sources
                 Emission Standards and Engineering Division
O
o
                 U.S. ENVIRONMENTAL PROTECTION AGENCY
                    Office of Air, Noise, and Radiation
                 Office of Air Quality Planning and Standards
                 Research Triangle Park, North Carolina 27711

                        July  1980

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This report has been reviewed by the Office of Air Quality Planning and
Standards, Office of Air, Noise, and Radiation, Environmental Protection
Agency, and approved for publication.  Mention of company or product
names does not constitute endorsement by EPA.  Copies are available free
of charge to Federal employees, current contractors and grantees, and
non-profit organizations - as supplies permit - from the Library Services
Office, MD-35, Environmental Protection Agency, Research Triangle Park,
NC 27711; or may be obtained, for a fee, from the National Technical
Information Service, 5285 Port Royal Road, Springfeild, VA 22161.
               Publication No. EPA-450/3-80-009a
                                        ii

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                             CONTENTS

Section                                                          Page

NOTE                                                             11

CONTENTS                                                         111

FIGURES                                                          v111

TABLES                                                           x


         PART II.   RETROFIT GUIDELINES  FOR COAL FIRED POWER PLANTS

1.0  BACKGROUND INFORMATION                                      1-1

     1.1  Introduction                                           1-1
     1.2  Relation to Part  I.                                     1-1
     1.3  Utilization of Part II.                                 1-2

          1.3.1  Purpose                                         1-2
          1.3.2  Data Assumption and Technical
                 Approach                                        1-3
          1.3.3  Content and Limitations                          1-4
          1.3.4  Method of  Use                                   1-4

     1.4  References                                             1-5


2.0  RETROFIT EMISSION CONTROL TECHNIQUES                         2-1

     2.1  General                                                 2-1
     2.2  NO  Emission Reduction Techniques                       2-3

          2.2.1  Low Excess Air                                  2-5
          2.2.2  Staged Combustion                                2-7
          2.2.3  Low NO  Burners                                  2-8
          2.2.4  Flue GSs Red roil at ion                          2-8
          2.2.5  Burners Out-of-Service                          2-9
          2.2.6  Flue Gas Treatment                               2-9
          2.2.7  Derating                                        2-9
          2.2.8  Reduced Air Preheat                              2-10
                                 111

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                            CONTENTS
Section                                                     Page
     2.3  Particulate Emission Control                       2-9

          2.3.1  Electrostatic Precipitators (ESP)           2-9
          2.3.2  Baghouses                                   2-10
          2.3-3  Flyash Scrubbers                            2-11
          2.3.4  Effect of Acid Mist on Particulate          2-12
                  Emissions

     2.4  Emission Control of Sulfur Oxides                  2-13

          2.4.1  General                                     2-13
          2.4.2  Description of Representative Wet and
                  Semi-dry Scrubbing Systems                 2-14

     2.5  Emission Monitoring                                2-28
     2.6  References               '                          2-30

3.0  RETROFIT DESIGN AND COSTS                               3-1

     3.1  General                                            3-1

           3.1.1  Emissions                                  3-1
           3.1.2  Basis of Costs                             3-2
     3.2   Retrofitting to Reduce NO  Emissions              3-6
                                    JS.
           3.2.1  Retrofit Techniques for NO  Control        3-7
                                            J\.
           3.2.2  Retrofit Costs for NO  Control             3-13
                                       X
     3.3   Retrofitting Ductwork and Stacks                  3-17
                                iv

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                          CONTENTS

Section                                                   Page

     3.4  Retrofitting To Control Particulate Emissions   3-19

          3.4.1  General                                  3-19
          3.4.2  Electrostatic Precipitator Design        3-22
          3.4.3  Baghouse Design                          3-26
          3.4.4  Retrofit Costs for Particulate Control   3-28

     3.5  Retrofitting to Control S02 Emissions           3-32

          3.5.1  Retrofit Costs for Wet S02 Control       3-32
          3.5.2  Retrofit Costs for Lime Dry S02 Control  3-35

     3.6  Land Area Requirements                          3-38

     3.7  Emission Monitoring Costs                       3-39

          3.7.1  Retrofit Capital Costs                   3-39
          3.7.2  Operating Costs                          3-43
          3.7.3  Annual Costs                             3-43

     3.8  Time Requirements For Retrofitting              3-44

     3.9  Refernces                                       3-46

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                            CONTENTS

Section

4.0  TECHNIQUES FOR ESTIMATING RETROFIT COSTS FOR
      EMISSION CONTROL
          General                                            ^ 1
     4.2  Working Capital                                     4-1
     4.3  Auxiliary Boiler Costs                              4-1
     4.4  Electrical Energy Penalty                           4-3
     4.5  Other Costs Not Estimated                           4-3
     4.6  Escalation                                          4-6
     4.7  References                                          4-7
   APPENDIX  A -  RETROFITTING  THE  FOUR  CORNERS  POWER STATION     A-l
   APPENDIX  B -  RETROFITTING  THE  MOHAVE  POWER  STATION           B-l
   APPENDIX  C -  RETROFITTING  THE  NAVAJO  POWER  STATION           C-l
   APPENDIX  D -  ANALYSIS OF FGD EFFICIENCY BASED ON EXISTING
                UTILITY BOILER DATA, PREPARED FOR EPA BY
                VECTOR RESEARCH,  INCORPORATED
   APPENDIX  E -  EPA RESPONSE  TO PETITIONS FOR RECONSIDERATION
                                  VI

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                        FIGURES

Figure                                                   Page

2-1    Most highly developed flue gas desulfurzation
       processes                                          2-16
2-2    Typical process flow diagram for lime/limestone
       scrubbing                                          2-21
2-3    General process flow diagram for semi-dry S02
       scrubbing with lime                                2-23
2-4    Semi-dry scrubbing system - Wheelabrator-Frye/
       Rockwell International                             2-27
2-5    Semi-dry scrubbing system - Joy-Niro               2-28
2-6    Semi-dry scrubbing system - Babcock  Wilcox       2-30
3-1    Location of overfire air ports for C-E boilers     3-12
3-2    Arrangement of curtain air ports for F-W and R-S
       boilers                                            3-14
3-3    Typical schedule for retrofitting large power
       plants                                             3-45
                              vli

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                       TABLES

Table                                                       Page

2-1     Characteristics of Commercial Throwaway FGD          2-19
        Processes
2-2     Semi-Dry Scrubbing Systems; Characteristics of
        Some of the Systems Presently Under Construction     2-25
3-1     B$W Low NO  Burner Costs                             3-15
                  .A.
3-2     Overfire Air Port Costs                              3-16
3-3     Values of A and b for Estimating the Cost of
        Utility Boiler Stacks                                3-18
3-4     ESP Specific Collection Area for Various Coals       3-24
3-5     Values of A and b for Estimating Capital and
        Annual Costs of Wet Flue Gas Desulfurization
        Systems                                              3-33
3-6     Electrical Energy Requirements for Wet Flue Gas
        Desulfurization Systems                              3-36
3-7     Minimum Land Area Requirements for Lime and
        Limestone Scrubbing Systems                          3-40
3-8     Sludge Generation for Lime and Limestone Scrubbing
        Systems                                              3-41
4-1     Capital and Annual Costs for Auxiliary Boilers       4-2

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PART I.   GUIDELINE FOR DETERMINING BEST AVAILABLE RETROFIT TECHNOLOGY
1.0   INTRODUCTION

      1.1  Background
      1.2  Applicability

           1.2.1  Phased Program
           1.2.2  Pollutants of Concern

      1.3  Identification of a Source Impairing Visibility

2.0   VISIBILITY IMPACT ANALYSIS

      2.1  Procedures

           2.1.1  Source Information
           2.2.2  Emission Rate Estimates

      2.2  Preliminary Assessment of Improvement in Visibility

           2.2.1  Primary Particulates
           2.2.2  Oxides of Nitrogen
           2.2.3  Sulfur Dioxide
           2.2.4  Other Factors to be Considered

      2.3  Engineering Analysis
      2.4  Energy Impact

           2.4.1  Energy Consumption
           2.4.2  Impact on Scarce Fuels
           2.4.3  Impact on Locally Available Coal

      2.5  Environmental Impact

           2.5.1  Air Pollution Impact
           2.5.2  Water Impact
           2.5.3  Solid Waste Disposal Impact
           2.5.4  Irreversible of Irretrievable Committment of
                  Resources

      2.6  Economic Analysis

           2.6.1  Direct Costs
           2.6.2  Capital Availability
           2.6.3  Local Economic Impacts

      2.7  BART Selection

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PART I.   GUIDELINE FOR DETERMINING BEST AVAILABLE  RETROFIT TECHNOLOGY



     Part I  provides guidance on identifying those sources to  be  analyzed

for BART, assessing the anticipated improvement in visibility, conducting

an engineering analysis, and establishing emission limitations for BART.

Part II  contains an explicit discussion of the engineering analysis

required by Part I.  Part II is primarily for the  analysis of  fossil -

fuel fired power plants with a generating capacity in  excess of 750 MW,

but the  procedures outlined below, in  Part I, may  be used  for  other

existing major stationary sources as well.

1.0  INTRODUCTION

     Section 169A of the Clean Air Act, as amended in  1977, calls for

the protection of visibility in certain mandatory  class I  Federal areas.*   -

Section  169A specifically requires remedying of existing visibility

impairment through installation of Best Available  Retrofit Technology

(BART) for certain existing major stationary sources.

     This document provides guidance to State air  pollution control

agencies on identifying those sources  to be analyzed for BART, assessing

the anticipated improvement in visibility, conducting  an engineering

analysis of available control systems, and establishing emission  limitations

for BART.  The use of this guideline is specifically for fossil fuel

fired power plants with a total generating capacity in excess  of  750

megawatts.  However, the procedures outlined in this document  are appropriate

for BART analysis of any existing major stationary sources.
*Mandatory class I Federal  areas are those areas listed in 40 CFR Part
81, Subpart D.  From this point forward they will  be referred to as
class I areas.

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     BART determinations must be  performed on  a  case-by-case  basis
because the visibility impacts, existing  equipment,  economic  conditions
and other factors which are considered in establishing  the  BART  emission
limitation are dependent on site-specific conditions.   The  intent of
this guideline is to provide a framework  by which consistent  BART determinations
are made.
1.1   BACKGROUND
     Congress was concerned with  the impairment  of visibility in the
nation's parks and wilderness areas, but  it realized remedying existing
impairment in these areas could not be reasonably accomplished overnight.
In order to assure that BART requirements will not be unduly  burdensome
or costly several provisions were included in Section 169A.
These are:
     (1)  BART may not be required by the Administrator for existing
major stationary sources which have been  in operation for more than
fifteen years as of August 7, 1977.
     (2)  BART for fossil-fuel fired power plants with a generating
capacity in excess of 750 megawatts must be determined pursuant to EPA
guidelines.
     (3)  The Administrator may exempt from BART requirements those
sources  he determines do not cause or contribute to significant visibility
impairment in a  class  I area.  This exemption may not apply to fossil -
fuel fired power plants 750 megawatts or greater unless it is demonstrated
to the Administrator  that  the facility is located at such a distance
from a class  I area as  not to cause or contribute to significant visibility
impairment in any such  area.  Any exemption from BART will  be effective

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only upon concurrence by the appropriate Federal  Land Manager.
     (4)  In determining BART for any major stationary source the costs
of compliance, the energy and nonair quality environmental  impacts of
compliance, any existing pollution control  technology in use  at the
source, the remaining useful life of the source,  and the degree of
improvement in visibility anticipated to result from application of
controls shall be considered.
1.1.1.   Pollutants of Concern
     Visibility is caused by the scattering and absorption  of light by
suspended particles and gases.  NOp is a light-absorbing gas  and generally
causes  reddish or yellow-brown atmospheric  discoloration because it
absorbs light at the blue end of the spectrum.   Primary particulates and
secondary aerosols formed from emissions of SO,, and NO  scatter light
                                              w       A
away from and into an observer's line of sight  causing a reduction in
visual  range and atmospheric discoloration.  These three pollutants
(primary particulates, NOX, and $02) are of major concern and should be
studied to determine their contributions to visibility impairment.
Detailed background information can be found in "Protecting Visibility:
An EPA  Report to Congress."*
1.1.2  Phased Program
     EPA established a phased approach to visibility impairment.**
Phase I focuses on controlling those sources which can presently be identified
* This report is available through the National  Technical  Information
Service, Springfield, Virginia.
**Proposed regulations.   May 22, 1980.  45 FR 34762

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as causing visibility impairment.   Phase I  visibility impairment includes
visible plumes emitted from stacks, and single source haze.   Smoke,
dust, or colored gas plumes obscure the sky or horizon.   Single source
haze causes a general whitening of the atmosphere and reduction of
clarity of terrain features.  Both forms of impairment when  "reasonably
attributed" to a source must be regulated under phase I.  As our scientific
and technical understanding of source/impairment relationships improves,
future regulations will address more complex forms of visibility impairment
such as regional haze and urban plumes.
     This guideline is directed toward Phase I analyses.  Although the
number and kind of sources and the type of pollutants included in future
BART analyses may expand, the procedures outlined herein are unlikely to
change substantially. In performing such analyses the State should be
cognizant of possible future requirements which could be imposed on
sources as a result of later phases of the program.  For example, a
major power plant may have a coherent plume caused by primary particulate
emissions which must be analyzed under phase I, and also contribute to
regional  haze through emissions of sulfur dioxide which will be addressed
in  later  phases.  Under phase  I, the source would be analyzed for BART
because it causes visibility impairment in the form of  a distinct plume.
However,  since  the  source may  also contribute to a regional haze, the
State should also analyze control  systems for SCL to determine if a
single system could more efficiently control both pollutants than two
separate  systems or  to evaluate the impact that one type of control
system might have on the future application of control  systems designed
to  control a different pollutant.

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                  PROCEDURES FOR IDENTIFYING SOURCES FOR BART ANALYSIS
     OIL
     a:
     O
                    NO
                   EPA
             CONSULTATION
          AGREES
                           NO
              YES
                         DISAGREE
NO-
                                    YES
                       NO
                                    YES
                                   YES
       EXEMPTION
       GRANTED  FXEMpTION
 N0 ^	1 APPLICATION;.
REQUIREMENT  FILED W/EPA
     YES
                  T   EXEMPTION
                   DENIED  -
                         Federal Land Manager identifies
                         visibility impairment in class I area
                         State identifies source to which
                         impairment is "reasonably attributable"
Source in 28 source category with
"potential  to emit" 250 tons/yr.
                         Source not in operation over
                         15 years as of August 7, 1977
                                                List of sources to be analyzed for
                                                BART provided to  Federal Land Manager,
                                                source, and EPA
Source believes it does not cause or
contribute to significant visibility
impairment
                                                BART Analysis
                                        Figure  1

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1.2  IDENTIFICATION OF A SOURCE IMPAIRING VISIBILITY
     See Figure 1.
     If a Federal  Land Manager identifies visibility impairment in a
class I area, the  State after consultation with EPA and the Federal  Land
Manager must first determine, by visual  observation or other monitoring
technique, the existing major stationary source(s) to which the impairment
is reasonably attributable.  In other words, for the purposes of phase I
of the visibility  program, sources need  only be identified if the
impairment can be  physically traced to them.
     States can use visual observation (either ground-based or with  an
aircraft) or another monitoring technique to determine which source
causes the visibility impairment.  An "Interim Guidance for Visibility
Monitoring" is now available and describes current monitoring methods.
It can be obtained through the Control Programs Development Division,
USEPA, MD-15, Research Triangle Park, N.C.  27711.  Once the existing
major stationary source is identified, the State must conduct an
anlaysis to determine BART for that particular existing major stationary
source.
     The Act limits the requirement for the installation of BART to
those existing major stationary sources  which started operation after
August 6, 1962. An existing major stationary source is a source listed
in Table 1 with a  potential to emit 250 tons per year, or more, of any
pollutant regulated under the Act.
     A source which believes it does not cause or contribute to significant
visibility impairment in a class I area  may apply for an exemption from
BART.  The exemption application must be submitted to the Administrator
according to procedures outlined in 40 CFR 51. 303 (proposed regulations).

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                                  TABLE  1
                   "EXISTING MAJOR STATIONARY SOURCE"
fossil-fuel  fired steam electric plants  of more  than 250 million  British
thermal  units per hour heat input,
coal cleaning plants (thermal dryers),
kraft pulp mills,
Portland cement plants,
primary zinc smelters,
iron and steel mill  plants,
primary aluminum ore reduction plants,
primary copper smelters,
municipal incinerators capable of charging more  than 250 tons of refuse
per day,
hydrofluoric, sulfuric, and nitric acid plants,
petroleum refineries,
lime plants,
phosphate rock processing plants,
coke oven batteries,
sulfur recovery plants,
carbon black plants (furnance process),
primary lead smelters,
fuel conversion plants,
sintering plants,
secondary metal production facilities,
chemical process plants,
fossil-fuel boilers of more  than 250 million British thermal units per
hour heat input,
petroluem storage and transfer facilities with a capacity exceeding
300,000 barrels,
taconite ore processing facilities,
glass fiber processing plants,
charcoal production facilities

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      NO REQUIREMENTS
NO-
      ENERGY IMPACTS
of retrofitting to NSPS
                                             SOURCE  IDENTIFIED
                                               (see  figure  1)
                                             SOURCE  INFORMATION
PRELIMINARY ASSESSMENT OF
IMPROVEMENT IN VISIBILITY
     Is visibility improved by
meeting NSPS emissions levels?
                                  yes
                                             ENGINEERING ANALYSIS
                                                 Analysis  of  the  impacts of
                                                 retrofitting to  NSPS  levels
                  OTHER  ENVIRONMENTAL  IMPACTS
                      of retrofitting  to  NSPS  levels
                                             ECONOMIC  IMPACTS
                                                  of retrofitting  to  NSPS  levels
                                             ALTERNATIVE  CONTROL  SYSTEMS
                                                  if retrofitting to  NSPS  is  found
                                             infeasible,  other  control systems should
                                             be analyzed.
                                             BART  SELECTION
                                                  Emission limitation  established
                                             SIP REVISION
                                      Figure 2

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The Administrator, after appropriate public review, will  grant or deny
the exemption.  The exemption is then effective only upon concurrence by
the Federal Land Manager.
2.0  VISIBILITY IMPACT ANALYSIS
     See Figure 2.
     A visibility impact analysis is necessary to determine the degree
of improvement anticipated from applying an emission control  system.
This can be accomplished by empirical methods, i.e., direct observation
or monitoring, and limited use of single source models.
2.1  PROCEDURES
2.1.1 Source Information
     In order to conduct a visibility analysis the following data
is needed.
     1.  Plant size, capacity, mode of operation
     2.  Emission rates for nitrogen oxides (NO ), particulates, and
                                               J\
         sulfur dioxide (SO ), (grams per second)
                           /\
     3.  Remaining useful life of any existing pollution  control systems
     4.  Remaining useful life of any specific units within the plant
     5.  Remaining plant life
     6.  Stack diameters (meters)
     7.  Stack heights (meters)
     8.  Actual gas velocity (meters per second)
     9.  Stack temperature (degrees Kelvin)
     The above data should be obtained from the plant and should be confirmed
by other data available to the State from in-house, Federal, and local
agency records.  Data for full load conditions should be  used for pre-
liminary visibility impact analysis.  For visibility impact analyses  in

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conjunction with evaluation of BART alternatives,  variations in emission
rates with changes in production may be considered if reliable data
are available.   Other parameters which may also be useful  are opacity
measurements and particle size distribution of emissions.
2.1.2  Emission Rate Estimates
     A representation of current, actual emission  rates, i.e., emission
rates with any existing control systems, is necessary so that the
expected improvement in visibility can be estimated.  These emission
rates can be obtained from various places such as, the source itself,
other control agencies, in-house data, or new emission test data.  They
should represent actual emissions and not estimates based upon theoretical
control efficiencies.
     This data should be thoroughly analyzed for its accuracy based on
present plant conditions.  If the emission rates do not seem appropriate,
in light of the observed visibility impacts, the State should require
additional emission tests, and/or calculate a current emission rate
considering present plant processes, air pollution control  systems
currently in use, and current fuel input.  The differing emission rates
should then be compared and, using good engineering judgment, the one
which most accurately represents the current emission rate  of the
source should be  used.
2.2  PRELIMINARY  ASSESSMENT OF  IMPROVEMENT IN VISIBILITY
     Analytical techniques which assess the visibility anticipated at
various control levels are now  being refined by the Agency.  Background
information on these analytical  techniques can be found in  "The  Development
of Mathematical Models for the  Prediction of Anthropogenic  Visibility

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Impairment"  (EPA-450/3-78-110a,  b,  c).   Two interim guideline documents
"Workbook for Estimating Visibility  Impairment" and "User's Manual  for
the Plume Visibility Model  (PLUVUE)" are available.  The Agency believes
that although the technique described in these two documents is currently
unvalidated, it can provide valuable input in the decision-making
process when combined with engineering judgement regarding the available data.
     These analytical techniques, along with empirical  methods, may be
used to estimate the degree in improvement anticipated  from control of
certain pollutants.
     To assess what improvement in visibility may be obtained by retrofitting,
the existing visibility (based on existing emissions) and the visibility
anticpated if the source met the New Source Performance Standards for
coal-fired power plants* should be compared.  If a perceptible change in
visibility is anticipated, the analysis should continue.  If not, retrofitting
of controls is not necessary.
2.2.1.  Primary Particulates
     Primary particulates are one of the major causes of visibility
impairment generally observed in the form of a distinct plume.  It is
usually a localized effect and can generally be traced  back, by visual
observation or monitoring, to its source.  The improvement anticipated
from controlling primary particulate emissions is (1) the plume disappears,
(2) the effect becomes even more localized, (3) the effect is reduced
perceptibly or (4) the frequency of the impairment decreases so as to
improve visibility.   A common sense approach using comparison photographic
techniques could adequately demonstrate the impact of controlling emissions
for the purposes of Phase I BART determinations.  These photographic
*New Source Performance Standards.  June 11, 1979.  44 FR 33580
**These documents can be obtained through the Control Programs Development
Division, USEPA, MD-15, Research Triangle Park, N.C. 27711

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techniques would involve comparing the  effects  caused  by  a well  controlled



source versus those caused by an  uncontrolled one.   This  comparison



would be of similar sources of equivalent  size  under similar meteorological



and geographical conditions.  For example, if a similar source  has



applied a certain primary particulate control and  its  plume disappeared,



or the impairment was reduced, the source  could be used as an example of



the amount of improvement expected by application  of that control  technology.



For a more specific discussion of the proper use of photographs see



Section 3.3.3. of the interim monitoring guidance.



     If a more precise analysis of the effects  of  particulate matter is



necessary, mathematical and other analytical techniques must  be considered.



The workbook and user's guide referenced in the previous  section describe



the use of such techniques.



2.2.2 Oxides of Nitrogen



     Another major component of visibility impairment  is N0?.   Gaseous



N09 absorbs blue light creating a reddish or yellowish-brown  plume.  NO
                                                                     X


can also act as a precursor of light scattering aerosols.  Current



techniques for reducing NO  emissions may show some improvement in
                          X


visibility, but evidence shows such techniques generally do  not reduce



emissions sufficiently to render the plume unobservable or provide



substantial improvement in visibility.  New, more  effective  control



techniques, presently available only under limited circumstances, could



become viable control alternatives within the next few years.   States should
                                 10

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carefully consider the upcoming improvements in NO  control
                                                  /\
technology when making a BART determination.
     NO  and its effect on visibility can be assessed using  the empirical
       J\
technique described in Section 2.2.1.  If a more precise analysis is
necessary the analytical techniques mentioned previously must be considered.
2.2.3 Sulfur Dioxide
     Sulfur dioxide does not directly affect visibility, but acts as a
precursor of light scattering aerosols.   These fine particles, (sulfates)
by scattering light in the observer - target path, reduce the contrast
and, therefore the clarity and detail, between the target and its
background.  This general reduction in contrast caused by sulfate aerosols
is most often associated with regional haze, but sulfates can and do
contribute to visible plumes and single source haze.  If the visibility
impairment is "reasonably attributable" to the source, as may be the
case in isolated, rural environments, the source should be required to
reduce S02 emissions for BART where improvement in visibility is anticipated.
     Analytical techniques are needed for a precise analysis of SOp and
its effects on visibility.  A discussion of those techniques is found in
the introduction to section 2.2.
2.2.4  Other Factors To Be Considered
     Frequency, duration, and time of occurrence refer to how often an
impairment impacts a class I area, how long this impairment lasts, and
when the impairment occurs.  These are important factors and should be
considered when assessing impacts of control on reducing visibility
impairment.  Relative improvement such as the model predicts will not
always present all the benefits that can be obtained.  For example, the
                                 11

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model  may show an overall  improvement in sky-plume  contrast of 10  percent,
but this may be sufficient to reduce  the frequency  of the  impairment so
that its impact is substantially reduced during periods of maximum
visitor use.  Oftentimes,  a reduction in frequency  and duration will
provide a maximum benefit  for a minimum control effort. Thus, the
temporal extent of the impairment is  of great importance and should be
considered when assessing  anticipated improvements  in visibility.
2.3  ENGINEERING ANALYSIS
     If the preliminary assessment shows visibility will be improved at
NSPS levels, the State then analyzes  the impacts of retrofitting the
source to meet NSPS emission levels.   These impacts would  include the
cost of the control system required to meet NSPS, the additional fuel
consumption, if any, resulting from that system, and any adverse environmental
impacts caused by that system.  A detailed discussion of the energy,
environmental, and economic impacts which should be considered is found
in the following sections.
     A detailed discussion of the costs associated with retrofitting
coal-fired power plants is contained in Part II.  As mentioned there, a
substantial part of the total cost of the control system is the ductwork
required.  A large duct system is oftentimes needed in retrofit systems
because of the constraints involved with the installation of new equipment
into an existing system or process.  The State, in considering alternative
retrofit systems and estimating costs, should be aware of these limitations
in retrofitting.
     As mentioned previously, visibility protection will be addressed in
phases.  Because of this phased approach, the States should consider
                               12

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potential future requirements when determining BART for a source.   In
many cases, control of pollutants causing phase I problems and control
of pollutants causing problems which will be formally regulated in
future phases cannot, and should not, be separated.  It may be more
feasible for the source to control a "future phase" visibility impairment
in conjunction with its phase I requirements than to wait until the
impairment is formally regulated.
2.4  ENERGY IMPACT
     Energy impacts should address energy use associated with the  control
system under investigation and the direct effects of such energy use on
the facility and the community.  Some specific considerations for  energy
impacts are presented below.
2.4.1  Energy Consumption
     The amount, type (e.g., electric, coal, natural gas), and source of
energy required by the control system under consideration should be
identified and compared.  In analyzing for energy consumption, comparisons
can be made in terms of energy consumption per unit of pollution removed
(for example, Btu/ton particulate removed).
2.4.2  Impact on Scarce Fuels
     The type and amount of scarce fuels (e.g., natural gas,  distillate
oil) which are required to comply with the control  requirement should be
identified and compared.  The designation of a scarce fuel may vary from
area to area, but in general a scarce fuel is one which is in short
supply locally and can better be used for alternative purposes, or one
which may not be reasonably available to the source either at present or
in the future.
                                  13

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2.4.3  Impact on  Locally Available  Coal
     A control system which  requires  the  use  of  a  fuel  other  than  locally
or regionally available  coal  should be discouraged if  such  a  requirement
causes significant local economic disruption  or  unemployment.
2.5  ENVIRONMENTAL IMPACT
     The net environmental  impact associated  with  the  emission  control
system should be  determined.   Both  beneficial  impacts  (e.g.,  reduced
emissions attributed to  a control system) and adverse  impacts (e.g.
exacerbation of another  pollution problem through  use  of a  control
system) should be discussed and quantified.   Indirect  environmental
impacts (such as  pollution impacts  at an  off-site  plant which manufactures
chemicals for use in pollution control equipment)  normally  need not  be
considered.  Some specific considerations are presented below.
2.5.1  Air Pollution Impact
     The impact of air pollutants emitted from a gas stream or  a fugitive
emission source can be assessed in  terms  of either quantity of  emissions,
modeled effects on air  quality, or both.   If application of a control
system directly removes or releases other air pollutants (or precursors
to other air  pollutants), then the pollutants affected and the impact of
these emission changes  should be identified.  The analysis can consider
any  pollutant affecting local air quality including pollutants which are
not  currently regulated under the Act, but which may be of special
concern regionally or locally.
2.5.2  Water  Impact
     Relative quantities of water used and water pollutants produced and
discharged as a result  of use of the emission control  system should  be
                                    14

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identified.   Where possible, the analysis  should assess  their effect on
such local  surface water quality parameters as  pH,  turbidity, dissolved
oxygen, salinity, toxic chemical levels  and any other important  considerations,
such as water supply, as well  as on groundwater.  The analysis should
consider whether applicable water quality  standards are  met  and  the
availability and effectiveness of various  techniques to  reduce potential
adverse effects.
2.5.3  Solid Waste Disposal Impact
     The quality and quantity of solid waste (e.g., sludges, solids)
that must be stored and disposed of or recycled as  the result of the
application of an alternative emission control  system, if considered,
should be compared with the quality and  quantity of wastes created  if
the emission control system proposed meeting NSPS for power  plants  is
used.  The composition and various other characteristics of  the  solid
waste (such as permeability, water retention, rewatering of  dried material,
compression strength, Teachability of dissolved ions, bulk density,
ability to support vegetation growth and hazardous  characteristics)
which are significant with regard to potential  surface water pollution
or transport into and contamination of sub-surface  waters or aquifers
should be considered.  The relative effectiveness,  hazard and opportunity
for solid waste management options, such as sanitary landfill, incineration,
and recycling, should be identified and  discussed.
2.5.4  Irreversible or Irretrievable Commitment of  Resources
     The BART decision may consider the  extent  to which  the  emission
control system may involve a trade-off between  short-term environmental
gains at the expense of long-term environmental losses and the extent to
                                 15

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which the system may result in irreversible or irretrievable commitment
of resources (for example, use of the scarce water resources).
2.6  ECONOMIC ANALYSIS
     This analysis should address the economic impacts associated with
installing and operating control systems under consideration for BART.
Costs associated with New Source Performance Standards can be found in
the NSPS Background Information Documents.  Other economic impacts which
should be considered follow.
2.6.1  Direct Costs
     The direct cost for a control method should be presented.   Investment
costs, operations, and maintenance costs and annualized costs should be
presented separately.  Costs should be itemized and explained.   Credit
for tax incentives should be included along with credits for product
recovery costs and by-product sales generated from the use of control
systems.  The lifetime of the investment should be so stated.  The costs
of air treatment, water treatment, and solid waste disposal should be
presented separately.  When considering the addition of control equipment
to that already in place, the cost of incremental control should be
analyzed.  Additionally, the expected useful life of any existing control
equipment should be evaluated on the basis of its expected retirement/
replacement schedule.
     As a guide in determining when control costs become excessive,
comparisons can be made in  terms of certain cost effectiveness ratios.
Such ratios may include the following:
     .  ratio of total control costs to total investment costs
     .  cost per unit of pollution removed  (for example, dollars/ton)
     .  unit production costs (for example, mill/kw-hr, dollars/ton).
                                    16

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In some cases, the unit of production output may be difficult to determine,
as in the case of a plant producing many different products.   In such
cases, unit production costs can be expressed as cost per dollar of
total sales.
     The remaining useful life of the source will  have an effect on the
amortized cost of the anticipated control equipment and, as such, should
be given strong consideration in determining BART.
2.6.2 Capital Availability
     Capital availability addresses the difficulty that some  sources may
face in financing alternative control systems.   Proof of such claims
should be fully documented.
2.6.3 Local Economic Impacts
     Local  economic impacts address the economic feasibility  of BART
requirements and the impact on production decisions of the firm in
response to the level of control.  For example, BART could alter the
economics of the plant to the point where the decision would  be made to
cancel expansion of a facility, to reduce the scale of operation, or to
change the production mix.  The local economic  impacts of such decisions
should be assessed in terms of local employment effects, including
number of jobs, dollars paid in salaries, and changes in employee skill
levels required.  The guideline does not imply that the BART  decision
should force a plant to the brink of shutdown.   The BART decision must
be based on sound judgment, balancing environmental benefits  with energy,
economic, and other impacts.
2.7 Considering Alternative Control Systems
     The State may consider other, alternative  control systems if it
finds the control system which meets NSPS places an unreasonable economic,
                                 17

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energy, environmental burden on the source.  The Agency believes, however,




that BART for the majority of power plants under consideration is the




NSPS.  Arguments against requiring NSPS must be stated in detail.  If




alternative control systems are considered, a complete analysis of the




economic, energy, and environmental impacts of the alternative should be




conducted.




3.0 BART SELECTION




     The State must establish an emission limitation that is BART for a




specific source.  This is then incorporated as part of the SIP the State




submits to EPA.  For fossil-fuel fired power plants with a generating




capacity greater than 750 megawatts, if this emission limitation is one




other  than that for NSPS, a complete discussion of why that alternative




was chosen must be included.  This discussion should include an array of




the alternatives considered, the cost of each alternative, the improvement




on visibility obtained from each alternative, and other important factors




which  affect the selection.
                                    18

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                                  PART II
                                 SECTION 1
                          BACKGROUND INFORMATION

1.1  INTRODUCTION
     This part of the proposed BART guideline  is  for  use  in  assessing
the effectiveness of retrofit control  techniques  and  for  estimating
cost.  They are flexible with respect to specifying control  systems for
implementation of BART.

1.2  RELATION TO PART I
     Part I provides guidance on identifying those sources to be
analyzed for BART, assessing the anticipated improvement  in  visibility,
conducting an engineering analysis, and establishing  emission limitations
for BART.  Part II, as discussed below, contains  an explicit discussion
of the engineering analysis required by Part I.   Part I is general guidance
and is appropriate for the analysis of all  existing major stationary source
categories.
     This Part II provides specific engineering information  on coal-fired
power plants having an operating capacity  in excess of 750 megawatts.  It
provides information for selecting alternative retrofit systems, and
assessing the economic,  energy, and environmental impacts of retrofit
alternatives.  Although  this part is specifically for coal-fired power
plants, much of the engineering information and procedures may be  helpful
when analyzing sources in other source categories.
                                    1-1

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1.3    UTILIZATION OF PART II
1.3.1  Purpose
       The guidelines in this document specify the emission
       levels, emission reduction potential,  and costs corresponding
       to each of the retrofit systems discussed.   By judicious
       application of these data to any plant situation,  an estimate
       of cost and effectiveness of a control may be made for that
       plant.   The guidelines are not intended to provide comprehensive
       cost estimates for retrofitting coal-fired steam generators.
       Comprehensive cost estimates require extensive engineering
       studies such as the preparation of specifications, bid criteria,
       equipment layouts, and detailed drawings.  Because the funds
       needed for these types of studies are usually beyond the budgets
       of most air pollution control agencies, the broad cost estimating
       techniques of this document are recommended.  The cost
       estimating data and procedures of this document will generally
       yield reasonable cost.  Should one suspect that the cost
       estimates of this document would lead to a false conclusion
       on the cost feasibility of retrofitting certain control
       systems, the more comprehensive cost  (and more costly)
       estimating techniques previously described should be used.
       Although the precision of the cost estimates can be improved
       by more costly studies, the accuracy of conclusions on the
       effectiveness of the various systems for reducing emissions
       would generally not be significantly improved by further
       study.
       This document was prepared recognizing that there are techniques
                                                                (* .
       other than those used as the basis for this document that as
       effective as those used for the cost estimates.  Consequently,
       the owner of a coal-fired steam generator should be allowed
       to select other techniques as long as such alternate systems
       perform at a level of effectiveness required by the BART
       determination.
                                  1-2

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1.3.2   Data, Assumptions,  and Technical Approach

       This study resulted from  the need to understand  the  basis
       and methods  of  retrofit  cost analysis that  would  cause
       emission reduction  of nitrogen oxides, particulate,  and
       sulfur oxides.  The cost  modules developed  have  been based
       on the  emission  levels  found  in  EPA background
       documentation (.1,2.,3., and 4^) .  These levels  are  210  and
       260 nanograms per joule heat input (0.5  lbs/10^ Btu
       and 0.6x lb/10^  Btu)  for  NOX from subbituminous
       and bituminous coal respectively; 13 ng/J heat input (0.03
       lbs/10^ Btu) for particulate emissions;  and 90%
       removal of  the  sulfur oxides from the power plant  flue
       gas.   These three pollutants  are  of prime  visibility
       concern although emissions from large, coal-fired,  steam
       generators also  include carbon monoxide, halogens,  trace
       metals, and  hydrocarbons (including polycyclic  organic
       matter) .

       The process  and cost data were obtained  primarily  from
       background  information for  new  source performance
       standards  and  from Pullman  Kellogg in-house work
       (1,2,3,4,and 5).  The data needed for establishing process
       requirements  to retrofit the example power  plants  were
       obtained from information furnished by the power  plants,
       from visual  inspection  of the plant sites during  plant
       visits, and from yearly reports prepared by the  utilities
       (FPC Form 6?).

       The methods considered  for  control of emissions  are:
       boiler  modifications for reduction of nitrogen oxide
       emissions;  particulate  control  using  baghouses and/or
       electrostatic precipitators  (hot or cold side);  and  flue
       gas desulfurlzation by either wet or semi-dry  scrubbing.
                              1-3

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       The  scope of work was directed to designs  for  retrofitting
       power  plants with 750 MW, or larger,  total plant  capacity.
       However, some of the designs can be applied to much
       smaller plants.  The costs developed  here  incorporate  the
       variations  involved in attaining the  plant capacity;
       therefore,  the study accomodates retrofitting  most power
       plants with emission controls.

1.3.3  Content and Limitations

       The  general content and the costs in  this  report  describe
       the  method  and choice of individual retrofit for  emission
       controls.   The  document  also  develops a method for
       determining total retrofit Investment and  annual  operating
       costs.  The content has  been developed  for  engineering
       personnel use such that the States and Federal government
       can  make best available retrofit technology decisions.  It
       is also intended  for  use by those  interested  industry
       personnel  involved in  environmental  control.   The
       appendices  provide examples of retrofit  costs and plant
       layout requirements for three power plants.  Reduction in
       nitrogen  oxide  formation  is  achieved  by  boiler
       modification only; no other control alternatives  have  been
       selected.   Particulate emissions control is limited  to
       baghouses and electrostatic precipitators  (hot and cold
       side). The flue gas desulfurization systems are  designed
       for  wet  or  dry scrubbing.

1.3.4  Method of Use

       Methods  for developing cost data are  described in Section
       3.  The  technique  for  using   these cost modules to
       determine the total retrofit costs  for a power  plant is
       described in Section 4.  Examples are presented in the
       Appendices.
                               1-4

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1.4    REFERENCES
           EPA,  "Electric  Utility  Steam Generating  Units,
          Background Information  for Proposed NOX Emission
          Standards."  EPA-450/2-78-005a, July 1978.
           EPA,  "Electric  Utility  Steam Generating  Units,
          Background Information  for Proposed Particulate Matter
          Emission Standards."  EPA-450/2-78-006a, July 1978.
           EPA,  "Electric  Utility  Steam Generating  Units,
          Background Information  for Proposed SC>2 Emission
          Standards." EPA-450/2-78-007a, August 1978
           EPA,  "Electric  Utility  Steam Generating  Units,
          Background Information  for Proposed SC^ Emission
          Standards Supplement."  EPA-450/2-78-007a-l,  Aug 1979
          Final  report, "Retrofit Guidelines for Coal-Fired
          Power  Plants," Pullman  Kellogg Division of  Pullman
          Incorporated, EPA  Contract No.  68-02-2619,  Work
          Assignment 13, September 1979
                                   1-5

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                            SECTION  2
              RETROFIT EMISSION  CONTROL TECHNIQUES
2.1  GENERAL
     The retrofitting technques  for NOX, S02, and
     particulate emissions  considered  in this document  are  based
     only on commercially available methods for reducing  these
     pollutants.  For NOX,  the emission reduction techniques
     considered include staged combustion (overfire air  and/or
     curtain air)  and low NOX burners.  The  particulate
     collection studies  examined ESP's  (cold or hot  side)  and
     baghouses (fabric filters).

     The maximum control  effectiveness of  the systems  discussed
     in this document is  as follows:
     NOY
     -... i A

      Subbituminous coal         210 nanograms per joule
                                (0.5 lb/106  Btu)
      Bituminous coal           260 nanograms per joule
                                (0.6 lb/106  Btu)
                           2-1

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Particulates
 Fabric Filters            13  nanograms per  joule
 and Electrostatic         (0.03  Ib/lO^ Btu)
 Precipitators

 Scrubbers                 21  nanograms per  joule
                           (0.05  lb/106 Btu)
S0.2
 Wet scrubbers             90  percent  removal of the SC>2
 Dry scrubbers             70  percent  removal of the SC>2

As discussed in Section 2.2 and Section 3,  it may not always
be possible to attain these NOX levels for  all  retrofit
situations.  The EPA position  on  the operating  effectiveness
of particulate and SC^ retrofit  control systems is
discussed  in  Appendices D  and E of  these  guidelines.
Control of SC>2 emissions included studies  of  both  wet
and semi-dry  scrubbing.  The  costs developed  for the wet
scrubbing system include cases  that use lime  or limestone,
Wellman Lord, Mag-ox,  or double  alkali scrubbing.   The
semi-dry scrubbing (lime) uses  the Joy-Niro  process.   This
process uses a spray  dryer followed by a  baghouse for
particulate collection.

The control systems outlined above are discussed  in detail
in the  following sections.
                         2-2

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2.2  NOX  EMISSION CONTROL TECHNIQUES

     There are two distinct mechanisms for forming NOX;  one
     is  fixation of elemental  nitrogen from the air,  and the
     other results from chemically  combined  nitrogen taken from
     fuel, in this case, coal.   Fixation  of  the  nitrogen in air
     can  be limited by reducing  the level of thermal excitation
     caused  by flame temperature.   The principal  methods for
     reducing thermal excitation are:  (a) flue gas recirculation,
     (b)  staged  combustion,  (c) water or  steam injection,
     (d)  reduced air preheat,  and (e) reduced heat-release  rate.

     Formation of NOX by oxidizing  the nitrogen in coal
     constitutes as much as 80 to 90 percent of the total NOX
     emissions from pulverized-coal-fired boilers.  By limiting
     the  combustion air supplied at or near the burners and by
     directing  air to limit   high temperature mixing  of
     volatilized coal,  nitrogen,  and air, nitrogen  oxide
     formation from coal nitrogen can be retarded.  As  the  fuel-
     rich mixture cools by radiating  heat to  the  surrounding
     colder surfaces, the mixture flows  into  the air  rich zone
     and completes combustion at  lower temperatures  -
     temperatures  which  are  less  favorable  for developing
     NOX.  This method,  one of several used to reduce NOX
     emissions, is called staged combustion.   There  are several
     NOx  control techniques discussed in this document  common
     to all four boiler manufacturers including:

     o    Low excess air,
     o    Staged combustion,
     o    Low NOX burners,
     o    Flue gas recirculation,
     o    Burners out-of-service,
     o    Flue gas treatment,
     o    Derating,
     o    Reduced air preheat.
                            2-3

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The sections  that  follow discuss these  techniques and
their potential  adverse side effects.   For  new steam
generators,  NOX emissions from burning Western
subbiturninous  coals  can be reduced  to  a level  of 210
nanograms  per  joule heat input (0.5 lb/10" Btu) and
emissions  from  burning bitumious  coals can be  reduced  to
260 nanograms  per joule  (0.6 lb/10^ Btu) without
significant  adverse side effects  (1).  NOX control  for
new boilers  has to  be  accomplished  by custom  design for
the steam generator  in order to minimize adverse  side
effects  while  limiting NOX emissions.

For existing  steam generators,  it  is  not  possible  to
change  the shape  or  size of the  combustion chamber
substantially  without  replacing the steam  generator.  The
state of the art  for reduction of NOX  by combustion
modification  is  not  developed to the  extent that the
effectiveness  of applying known control techniques  to
existing steam generators can be predicted accurately.  In
addition, it is  not possible to predict the  combustion
conditions where adverse side effects will  become
intolerable  for existing units.   Consequently, reducing
NOX emissions  from  existing steam generators  involves
trial  and  error  as  well  as  application  of sound
engineering  principles.  Western subbituminous  coals  have
less tendency  to  cause  tube wastage and slagging than some
high sulfur Eastern bituminous  coals.   Therefore, the
probability  of success  in reducing NOX emission  by
applying combustion modification techniques is  greater for
Western  coal.   Both Combustion  Engineering (C-E) and
Babcock  and Wilcox (B&W)  steam generators have  been
retrofitted  to reduce  NOX emissions to levels  less
than 210 nanograms  per  joule (0.5 lb/10^ Btu) without
significant  adverse side effects (1).
                        2-4

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2.2.1    Low Excess Air

        About 10 to 20% excess air is needed  in  addition  to  the
        theoretically required air to assure efficient,  stable
        operation of the boiler.  This amount of excess  air is
        needed to cover the  normal +3 percent  fluctuations in
        required  combustion  air,  to aid  soot  burnout,  to
        increase convective  heat transfer, to harden  the  slag,
        and  to minimize tube  wastage  (corrosion).   After
        accommodating the air requirements established by  these
        operating conditions, if excess air can  be  reduced, then
        NOX is reduced either because less oxygen is
        available during volatilization,  or thermal NOX is
        retarded  by low,  oxygen radical  concentrations.
        However, under ideal conditions, well mixed,  adiabatic
        combustion systems  respond  adversely  to  lower  excess
        air, because higher  NOX emissions  result from higher
        adiabatic flame temperatures.  For pulverized-coal-fired
        plants, the reduction in NOX  emissions may  be as
        much as  20%  when applying the low-excess-air control
        method.  When this method is  applied, tight control of
        individual burners must be made with  respect to fuel/air
        ratio.  Although utility boiler  systems usually show
        NOX reductions with  low excess air, the
        effectiveness of  reduced  excess air  varies  for
        individual  boilers and  there  are some associated
        problems which are  discussed  in  the following
        sub-sections.

2.2.1.1  Tube Wastage.- Operation in an environment  with too  low
        excess  air produces a fuel  rich  reducing atmosphere
        which may accelerate the corrosion of the furnace tubes.
        Therefore, there is a lower  limit  for reduction of
        excess air below which  potential adverse  side effects
        begin to accelerate  (I).

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2.2.1.2   Slagging.- Potentially, low  excess  air can accelerate
         slagging (!_) .   The molten  component  of the ash becomes
         slag in the reducing atmosphere  created by low excess
         air.

2.2.1.3   Increased ash combustibles and  CO content.- Low excess
         air operation can have  an  adverse  effect on particulate
         loading if there is an increase  in  unburned carbon  in
         the  ash.   Any  increase  in particulate loading  is
         accompanied by changes in  particulate characteristics
         such as size distribution,  and  ash resistivity which can
         affect the collection efficiency  of ESP's.  The increase
         in unburned carbon may  also result in energy losses  in
         the boiler.   Opacity may  be increased because of  the
         increase in particulate loading which  causes overloading
         of ESP's.   Low  excess  air can  also increase the  CO
         emissions (_!) .

2.2.1.4   Reduced steam superheat.-  When  the amount of excess  air
         is reduced, the flue gas mass flowrate  decreases.   This
         causes a decrease in the heat transfer  rate and may lead
         to a decrease in the superheated  steam temperature.   A
         difference  of up to 28C  (50P) in the superheat  and
         reheat steam temperature may occur.   Also, the reduced
         superheat temperature may  require existing old plants to
         reduce capacity  as  much  as 30%  of  their  rated  power
         output (I) .

2.2.1.5   Reduced  boiler efficiency.-  Low excess  air may  not
         reduce the boiler efficiency because  the energy loss due
         to the increase  in unburned carbon and  CO may be offset
         by the decrease  in energy  loss to the stack  resulting
         from a lower flue gas  temperature.   Efficiency may be
         improved in cases where CO and  ash combustibles are  not
         increased significantly  because combustion control
         settings are tuned more finely  (I).

2.2.1.6   Flame  Stability.- Flame  stability  can be affected by
         reducing excess  air.  Flameouts and  pulsations  not  only
         disrupt  electric  power  generation but also  cause
         potential safety hazards.   Consequently, for all  steam
         generators, there are low  excess  air  conditions that are
         intolerable.
                             2-6

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2.2.2  Staged Combustion

       Staged combustion can be accomplished  in  three  ways.   One
       method is by maldistributing air (over-fire air),  another
       method is by maldistributing fuel (burner-out-of-service),
       and  the  third method involves  special burner  design.   A
       typical  utility boiler operates with an array of  burners,
       each of  which operates  at  the percentage of  excess  air
       specified for the  boiler.   The flame  characteristics
       differ with the individual boiler manufacturer's  design.
       Staged combustion is accomplished  by  redistributing  the
       air  flow such that a cooler  secondary  combustion  zone  is
       encountered by the fuel-rich combustion gases  after  they
       leave the flame basket.  Staged combustion has  two effects
       on NOX production;

       o  Fuel  NOX is reduced because  less oxygen is
         available during volatilization.
       o  Thermal NOX is reduced because the  flame
         temperature does not reach as high a peak as when
         all the heat release occurs  in one  stage.

       The  extent of staged air  can be conveinently  indexed  by
       the  fraction of stoichiometrically-required air  remaining
       at the burner flame baskets. For example, suppose a  six-
       level burner boiler operating with 15% excess air has  five
       operating burner levels with air supplied to six  levels.
       Then one-sixth of the  air supply is  staged, leaving  the
       burners  operating  at  96% (115 x 5/6)  of the required
       stoichiometric air.  This type of  staged combustion  has
       shown reductions of NOX production by  as much as 20 to
       40%  for  pulverized-coal-fired utility  boilers (I).  Staged
       combustion by special burners produces a lazy,  fuel-rich
       flame surrounded  by an  air  envelope.   Limited tests
       indicate that this type of burner can  reduce NOx
                             2-7

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       emissions by as much as 50%.   Potential  adverse  side
       effects of staged combustion are much  the  same  as  those
       discussed in Section  2.2.1.

2.2.3   Low NOy Burners

       Low NOX burners are designed to reduce NOX
       emission levels either alone or'in combination  with the
       use of overfire air ports.  With the low NOX burner
       designs,  it is possible to eliminate or  alleviate the
       potential  problem  that creates  reducing atmosphere
       pockets,  and  the tube wastage associated  with  reducing
       atmospheres should be far less serious.  Low NOx
       burners are  designed to reduce highly turbulent mixing
       between the secondary and primary air streams.  Because of
       low turbulence intensity, the flame length  in low NOX
       burners  will be longer  than  the  flames of normal  high
       turbulence burners, and  these increased flame lengths must
       be  evaluated by the  manufacturer  when retrofitting a
       boiler.  Potential adverse  side effects are much  the same
       as  those discussed in Section 2.2.1.

2.2.4   Flue Gas Recirculation

       The flue-gas recirculation  method of NOX control
       operates by recirculating flue gas to the windbox which
       reduces the formation of thermal NOX by lowering  flame
       temperature and oxygen concentration at the burners.  This
       technique has been tried on an experimental basis and has
       been  found to be relatively  ineffective  in coal-fired
       units.   Also,  the flyash problems in the recirculation
       systems  have not been solved sufficiently to warrant a
       conclusion that  the technique  has  been demonstrated
       effectively  (1).
                                2-':

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2.2.5  Burners Out-Of-Servlce

       This method of NOX control  is accomplished by shutting
       off the pulverizers supplying the upper level burners.
       The technique can be accomplished only  if  the remaining
       pulverizers have enough spare capacity to supply the total
       amount of coal required.   Often,  application  of  the
       technique increases the minimum excess air requirements of
       the boiler, and this may result in efficiency loss in the
       boiler.   Boiler derating may be required when fans are
       already operating  near  their  maximum capacity.   Also,
       intolerable superheat conditions may occur because of a
       resultant shift of the  high temperature  zone towards the
       superheater.  The technique could be useful, however,  for
       both  owners  and  regulatory  agencies,  in helping to
       determine what adverse  side effects might ensue  from
       equipping a unit for overfire air while avoiding the need
       for costly modifications.

2.2.6  Flue Gas Treatment

       The flue gas treatment  method of NOX control has  been
       applied to oil and gas-fired  units  in  Japan.   EPA is
       investigating the  Japanese technology  for potential
       application  to the U.S., coal-fired  situation.   At
       present, this technology is not sufficiently demonstrated
       on coal-fired units to  be considered here (!_).

2.2.7  Derating

       Derating operates by causing a reduction in the volume of
       flue gas which produces a reduction of NOX, both  in
       concentration and mass  flow rate.  Also,  reducing the heat
       release rate reduces  combustion  gas temperatures  more
       rapidly, thereby reducing the rate of  formation of NOX
       from the reactions between  the nitrogen in the  combustion
       air and oxygen.
                             2-9

-------
      NOX control by  derating older units  will  be more
      difficult  because  of  smaller combustion chamber  design
      practiced by boiler manufactures prior to 1971.  The older
      units, with a smaller  firebox,  have higher heat  release
      rates  when compared to the  units  designed  after 1971,
      which  have a 15 to 50% increase in  combustion chamber
      size.

      Usually derating is an undesirable NOX control
      technique.  However,  at times,  it might develop  that
      derating would  be  a preferable alternative  for  utility
      owners who otherwise  would  have  to  make costly steam
      generator modifications.

2.2.8  Reduced Air Preheat

      Reduced air preheat to control NOX emission is  a
      nonviable method because of the need for  a hot  air supply
      to  the  pulverizer  to  heat the coal.  The method causes
      losses in boiler efficiency  because of  heat  losses
      attributable to increased stack gas temperature.

2.3   PARTICULATE EMISSION CONTROL

2.3.1  Electrostatic Precipltators (ESP)

      Electrostatic precipitators function  by  charging and
      collecting particles on collection  electrodes,  and by
      disposing  of the collected ash.  Primary electric power
      supply is  usually 240  or 480  volts of alternating  current.
      Transformer-rectifier  sets are used to convert  the  current
      from  alternating to direct and to  step  up the secondary
      voltage.   High efficiency ESP systems are equipped  with
      power  controls which regulate power at the optimum levels
      for particulate collection.   Secondary voltages range from
                                2-10

-------
       10,000 to 40,000 volts, depending upon the  particulate and
       gas  characteristics.   Rapping  systems  dislodge  the
       collected ash.   These  systems are equipped  with  controls
       which permit  adjustment of  both the frequency  and
       intensity of rapping.  High efficiency ESP  systems  are
       equipped with multiple hoppers and baffles  to minimize the
       tendency for  gases  to  bypass  the electrical  field
       (sneakage).   ESP systems  are capable  of reducing
       particulate emissions  to  levels as low as 13 nanograms per
       joule heat input (0.03 lb/106 Btu)
       Performance of an ESP  is affected by the  following factors
       (2):

       o    Coal ash characteristics  -  size distribution  of
          particulates ,  compositions such as sulfur  content,
          etc .
       o   ESP size - collection area and flow,  cross-sectional
          area for flue gas
       o   Grounded collection surface spacing
       o   Power control design
       o   Gas flow distribution
       o   Rapping control design
       o   Flyash handling system design
       o   Thermal expansion  design
       o   Discharge electrode failure
       o   Maintenance practices
       o   Gas conditioning
2.3.2  Baghouses
       Baghouses used for particulate  emissions  control  are
       effective to the extent of 13  ng/J heat  input (0.03
       lbs/10" Btu) (2^  for best-controlled sources.
       Pressure  drop data  show a range of less than 1.25
       kilopascals (5" H20) to 2.5 kilopascals  (10"  H20),

                                2-11

-------
all at full load.  Air-to-cloth ratios corresponding to
these pressure drops range from 0.58  to  0.91  actual cubic
meters per minute per square meter  (1.9  to  3.0  ACFM/Ft^).
Data  show that  an  air-to- cloth  ratio of 0.61  actual
cubic meters per minute per square  meter (2 ACFM/Ft2)
is a conservative criterion for sizing  a baghouse for a
coal-fired steam generator  with pressure  drops of less
than 1.25 kolopascals (5"H20)  at full  load  gas  volumes.
Although it is not demonstrated on  large sized  electric
utility steam generators,  it is possible that precharging
the particulates before entry into  the bags would permit the
use of much smaller baghouses with  air to cloth ratios of
as much as  1.2 actual cubic meters per  minute  per  square
meter (4 ACFM/Ft2)A.  The  life of a bag  is  estimated to be
at least 2 years if pressure drops  are less than 1.25
kilopascals (5"H90).
                    2-lla

-------
       The  key factors which affect baghouse  performance are
       (2);

       o Bag material,
       o Bag construction,
       o Bag treatment,
       o Baghouse  size,
       o Configuration of baghouse and its control,
       o Techniques  of cleaning,
       o Construction of tube sheet,
       o Process  characteristics,
       o Maintenance practices.

2.3.3  Flyash Scrubbers

       In common  practice,  using scrubbers to  control
       particulates from coal-fired power plants is  done  only  in
       conjunction with  FGD systems.   The  FGD system  can  be
       designed  either for simultaneous removal  of SC>2  and
       particulates (Kellogg-Weir scrubbers,  TCA scrubbers,  etc.)
       or for separate particulate and  sulfur  dioxide removal
       (venturi-spray tower  combination).  Scrubbers  are  capable
       of reducing particulate  emissions to levels as low  as
       21 nanograms per joule heat input (0.05  lb/10^
       Btu)  (2).
                              2-llb

-------
      A  great  variety of scrubber  types and  configurations
      exist.  Some  of the  most widely used  scrubbers are
      venturi,  spray tower,  orifice  impingement,  and
      self-induced spray.   The  basic  principle of  scrubber
      operation involves confronting particulates with impact
      targets which can be either wetted  surfaces or, and most
      frequently, individual  droplets.

      The efficiency of a  wet scrubber is a function of a number
      of variables including  particle characteristics (diameter,
      density, viscosity)  between the particle and the scrubbing
      slurry droplet.  To  obtain  efficient particulate removal,
      the system is designed  for  an  optimum combination of these
      parameters.  This combination  is achieved by using a high
      liquid to  gas ratio (L/G) of scrubbing  slurry  to gas
      stream, and by providing a  high degree of atomization for
      the scrubbing liquid.   The  choice of particulate collector
      must  take into account  the  particle size distribution, the
      required collection efficiency, and  the  overall energy
      consumption (as measured by the pressure  drop across the
      system).

2.3.4 Effect of Acid Mist  on  Particulate Emissions

      Particulate emissions  from coal  can  be affected  by acid
      mist  concentrations.  Reference 2 qhows PGD units on well-
      controlled  coal-fired power  plants  do not  increase
      particulate emissions through  sulfuric acid formation and
      interaction.
                              2-12

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2.4    EMISSION CONTROL OF SULFUR OXIDES

2.4.1   General

       The combustion products  of  the coal-fired, power-
       generation station contain sulfur dioxide.  There are
       several sulfur removal alternatives.  These alternates can
       be  grouped into these  three  principal categories:

       o   Desulfurization of  coal prior to combustion -  either by
          chemical or physical cleaning.
       o   Desulfurization of  coal during  combustion - fluidized
          bed combustion.
       o   Flue gas desulfurization.

       For this project only flue gas desulfurization will be
       considered as a means  for controlling emissions of sulfur
       oxides to the atmosphere.

       There are  several  types  of  FGD processes  that  are
       commercially available now,  and they are grouped  into two
       major categories that  are based on the  product resulting
       from the process:

       o   Throwaway processes  where  all waste streams are
          discarded.
       o   Regenerable processes where the waste stream is  treated
          for regeneration of the sorbent and recovery of sulfur
          compounds  such  as sulfur,  sulfuric  acid,  and
          concentrated H2S.
                              2-13

-------
        Both processes treat the flue gases  using  either  wet,
        semi-dry, or dry desulfurization modes.   Since  dry
        processes, such as dry  scrubbers using boiler  injection
        with limestone, are not within the scope of  this  study,
        they will not be considered  further.  The wet  and semi-
        dry processes are accomplished using either  slurry or
        clear liquor, and these are  further divided  by the  type
        of alkali used for the  scrubbing solution.

        Figure 2-1 illustrates  the  general  classification of
        these FGD processes.  This  figure also indicates the
        nine most highly developed processes at the extreme
        right.

2.4.2    Description of Selected Wet and  Semi-Dry Scrubbing
        Systems

2.4.2.1  S02_control by wet scrubbing.-  Wet scrubbing
        processes have  gone  through  extensive  research,
        development, and full  scale demonstration work.   The
        available  data indicate that wet  scrubbing  will  remove
        both SC>2 and  particulates.   Usually,  the flyash is
        collected upstream  of the  FGD  unit to minimize the
        volume of sludge  and  to  prevent erosion  of  the
        desulfurization  equipment.  The flue gas from the
        boiler, after going through fly  ash removal (ESP, or
        baghouse) ,  enters the scrubber where  the SC>2 is
        removed by the  scrubbing  liquor (either  slurry or
        clear).  The  cleaned  gas then passes  through an
        entrainment  separator to remove  entrained  slurry
        droplets or fine particulate matter in the  gas.   Since
        the  scrubbed  gas  has  been cooled and has had its
                            2-U

-------
                    REGENERABLE ^>
                             SEMI-DRY
                          '(SPRAY DRYER)"
Figure  2-1.- Most  highly developed flue  gas desulfurization processes
                                     2-15

-------
moisture  content increased by the scrubbing  liquor,  it
is often  reheated before it enters  the  stack.   Reheat
minimizes  condensation and corrosion  of  the  equipment
downstream of the scrubber (ductwork, fans), and it also
helps to  avoid plume formation at the  stack  exit.   The
product sludge  is  either discarded  (throwaway)  or
processed  further (regenerable).

The types  of process equipment and operating  parameters
vary widely  for  these  systems.   The principal
differences are  in the  following  equipment  and
chemicals:

o  Scrubbing equipment - The several successful  systems
   already used include packed tower,  horizontal spray
   towers, vertical  spray towers,  tray  columns,  and
   venturi scrubbers.

o  Types  of alkali - For throwaway systems, the types of
   scrubbing media  that have been  used  are either a
   slurry (lime, limestone, or  alkaline  fly  ash)  or a
   clear  liquid  (sodium carbonate,  double alkali,  lime
   chloride and dilute acids).  Regenerable  systems use
   clear  liquids  mostly (sodium  sulfate, ammonia,
   citrated  potassium trisulfate).   The alkali,
   magnesium oxide, has been used as a scrubbing  slurry
   also.

o  Process Design Parameters - Parameters such as
   liquid- to-gas ratio (L/G), gas  velocity,  scrubbing
   medium,  flow configuration  (counter,  cross  or
   cocurrent), and pressure  drop  for the  entire
   scrubbing  system vary  considerably for the PGD
   processes.  These  variables  have a large effect on
   the PGD system operating costs.
                   2-16

-------
A.  Wet  scrubbing throwaway processes

 In the throwaway processes, the product  sulfur  removed
 is waste.   Usually  the waste  stream is  a  sludge
 containing sulfur compounds, unreacted alkali,  fly ash,
 and water.   Table 2-1 shows some  of the  commercially
 available FGD processes.  Further discussion  is  limited
 to wet lime/limestone  processes.

    Wet lime/limestone  processes

    Wet lime and  limestone  systems  make up a  large
    portion  of  the  operating  FGD scrubbers.   Since
    commercial installations have  been  operating  for
    several  years,  the  overall  operability and
    reliability of both systems has  been  proven.  The
    basic process is  fairly simple and very few  process
    steps are involved.  In the first step,  hot gases are
    quenched to saturation temperature and  passed  along
    to  the  scrubbers where a lime  or limestone  slurry
    contacts the gases  for SC>2 removal.  The cleaned
    gases are reheated  and discharged to the atmosphere.

    The lime/limestone  scrubbing slurry is prepared using
    slakers  (lime)  or ball  mills (limestone).   The
    scrubbing  slurry is  collected  in a  tank and
    recirculated to  the  scrubber.   A purge  stream
    containing the net make of sulfite-sulfate  can  be
    oxidized further  by air or oxygen  prior to  entering
    the thickener for separation of the suspended solids.
    Thickened slurry  containing 20 to  40  percent  solids
    can be sent directly to a disposal  pond  or  it  can  be
    filtered.  Filters  are used for further  reduction  of
    sludge  volume by increasing the  solids  content  to
    about 70  vt%.   Clear liquid  is  returned to  the
    system.
                      2-17

-------An error occurred while trying to OCR this image.

-------
         The process has the following characteristics:

         o  One of the lowest capital costs,  as  specific economic
           studies have shown (3.).
         o  Lime/limestone processes are not adversely  affected
           by  fly ash in the system.  They can  remove  both
           S02 and particulates.
         o  S02 removal efficiencies are generally high -
           greater than 90% (,5).
         o  Reserves of lime/limestone are  abundant  in the U.S.
         o  Some of these processes, if not designed properly,
           have problems with plugging, scaling  and corrosion .
         o  Large  liquid-to-gas ratio or substantial gas pressure
           drop occurs in some processes.
         o  The large quantity of waste requires  a large,  lined,
           disposal pond.

         Figure 2-2 illustrates  a typical  process  flow diagram
         for lime/limestone scrubbing.

2.4.2.2  SO? control by semi-dry scrubbing.-   The concept of
         semi-dry  scrubbing for  removal of sulfur  dioxide  from
         flue  gases is relatively  new  to  the electric power
         industry.  As of late 1979  no commercial scale, semi-dry
         scrubbing sytems were in operation.  However,  several
         semi-dry scrubbing  units  are  currently on  order  for
         installation at coal-fired power  plants in  the  United
         States.
                               2-19

-------
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-------
Semi-dry FGD  systems achieve S02 and particulate
removal  by using the  combination of  a  spray  dryer
followed by a conventional particulate control  device.
Figure 2-3 illustrates the general  process  flow scheme
for semi-dry scrubbing  with  lime.  Sulfur dioxide
removal takes place in the spray dryer,  where  the flue
gas that enters flows through a finely  atomized spray of
alkali scrubbing  solution.  This solution uses  either a
sodium based  (soda ash) or calcium based  (lime)  type of
alkali.  The  SC>2  alkali reaction takes  place between
the gas and liquid droplets and/or  between  the  gas and
entrained particulates  (6.,.7) .  At  the  same  time, the
water in the  scrubbing slurry droplets  evaporates due to
the thermal energy provided from the incoming  flue gas.
The  treated  flue gas leaves  the spray  dryer  at  a
temperature of about 28C (50F) above  its dew-point or
about 77C (170P).  This temperature can be controlled
by properly selecting the liquid-to-gas  ratio  at  about
0.4 X 10-1* M3/ SM3, (0.3 Gal/MSCF).   The
reaction product  is a relatively dry, powder mixture of
sulfite, sulfates, and unreacted alkali.  Collection of
the reaction  products containing sulfur and particulates
is accomplished  by  using either an ESP  or  a fabric
filter (baghouse) .  The  fabric filter also serves for
additional S02 removal by reaction between the gas
and  unused   sorbent.   Spent  sorbent  is  usually
discarded.

Operating experience  with  spray dryers  on utility
boilers has been  limited  to pilot-scale test  programs
(8.,.9)-  Test  results  in  these programs  have  indicated
S02 removals  between 50 and 90% with lime alkali at
stoichometric ratios  (SR) of 0.8 to 2.0.   (SR  =  moles
lime/mole SC>2 entering).  Process evaluations also
indicate that semi-dry  processing is economically
attractive only in applications with moderate SC>2
                     2-21

-------
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removal requirements  (approximately 70%  max.)  and with
coals  of low  to  medium sulfur  content.  Some  of the
characteristics of semi-dry scrubbing  include:

o  Dry powdered waste - no sludge
o  High turndown  capabilities
o  No wet-dry  interfaces
o  No plugging or fouling problems
o  Low pressure drop
o  Power consumption about 50%  of most wet-scrubber
   consumption
o  High reliability
o  No corrosion problems
o  No reheat  requirements

The projected advantages of  the semi-dry scrubbing
system and  the positive results of pilot scale testing
have prompted  utilities to give serious consideration to
spray drying  as a means of SC>2 emission control.

There  are  several commercially available  semi-dry
processes  (6_) such  as  those offered  by Wheelabrator-
Prye/Rockwell  International; Joy Manufacturing  Company's
Western Precipitation Division in conjunction with Niro
atomizer; Babcock & Wilcox; and Carborundum.  Of these
four processes only Wheelabrator-Frye/Rockwell  has both
regenerable and throwaway processes.   The other three
are  offered   only  as  throwaway  processes.
Characteristics of some of the semi-dry scrubbing units
currently on  order are listed in Table 2-2.
                     2-23

-------











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A.  Semi-Dry SOg Scrubbing Throwaway Processes

   1.   Wheelabrator-Frye/Rockwell International

   The Wheelabrator system  (spray dryer/baghouse)  when
   operating in an open  loop  is  offered  as a throwaway
   process.   The spray dryer  is equipped  with a multiple
   atomizer and a roof dispenser.  The  alkaline scrubbing
   slurry is a sodium  carbonate  solution.  The  Coyote
   Station located near Beulah, North Dakota (10)  has this
   semi-dry PGD system scheduled for commercial operation in
   1981.   This system will  serve  a  410 MW  lignite-fired
   unit.  The process flow diagram is shown in Figure  2-4.

   2.   Joy/Niro

   The alkaline scrubbing slurry uses  either soda ash or
   lime as  alkali.   The spray-dryer design uses  a single
   atomizer and compound gas  dispenser  to  achieve  adequate
   gas mixing.  Joy/Niro system (spray  dryer/baghouse) has
   developed a recirculation  system in which lime slurry is
   mixed  with recirculated fly ash and  spent reagent, for
   reinjection  into the spray-dryer (patent pending) the
   process flow diagram is  shown in Figure  2-5.   The semi-
   dry FGD  system using a lime scrubbing  slurry  is being
   installed at the Antelope  Station Unit 1, a (440 MW  gross
   capacity).  It is scheduled  for commercial operation in
   1982.

   3.   Babcock & Wllcox

   This system (spray dryer/ESP) consists  of a horizontal
   reactor  using a "Y"  jet  dual  fluid atomizer followed
   directly by an electrostatic precipitator.  The system
   uses a lime scrubbing slurry.  The Laramie River Station
                           2-25

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                          2-27

-------
     Unit 3, whose gross capacity  is  575  MW,  is installing  this
     system (6^).  Commercial  operation should  start in April
     1982.  The process flow diagram  is shown in Figure 2-6.

     4.  Carborundum

     A  De Laval  spray dryer in combination with a baghouse  is
     used for this system (6_) .   A  test program  using the  process
     is underway presently at the  pilot plant located  at  Leland
     Olds Station,  Unit 1.  The  test program includes  uses  of
     either dual, fluid-spray nozzles or  a rotary atomizer.   No
     commercial operation plant is scheduled.

2.5  EMISSION MONITORING

     In order to assure that the lowest NOx,  particulate, and
     S02 emission levels are achieved in  a boiler system,
     emission monitoring  systems must  be  used.   Currently  no
     continuous monitoring systems have  been developed  for
     measuring mass particulate emissions.   However, a variety of
     instruments  are  available for  measuring, indicating,  and
     recording opacity.  These instruments  as well as methods and
     critera for evaluating performance are  given in Reference 11.

     Monitoring S02 and NOX emissions in  units  of mass
     per unit heat input  involves  integrating the  output  of
     S02 and NOX sensors with the  output  of  C02 or
     02 sensors.  Various S02, NOX, C02,  and
     02 sensing  instruments, that  are suitable  for this
     purpose, are described in Reference  11.  Reference  11  also
     discusses how the various outputs are integrated  to  furnish
     continuous  indications and records of S02  and NOX
     emission levels.  In addition, the  reference describes the
     methods and criteria for evaluating  the performance  of
     S02 and NOX emission monitoring systems.
                               2-28

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                                                 X
                                                 o
                                                 o
                                                 u
                                                 o
                                                 u
                                                XI
                                                 (U
                                                 -p
                                                 0)

                                                 en
                                                 C
                                                H
                                                 u
                                                 (0
                                                d
                                                 i
                                                -H

                                                 0)
                                                 I
                                                CM

                                                 0)
                                                 i-l
                                                 3
                                                 tJl
                                                -H
2-29

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2.6    REFERENCES
       1.   EPA,  "Electric  Utility  Steam Generating  Units -
           Background Information  for Proposed NOX Emission
           Standards." EPA-450/2-78-005a, July 1978
       2.   EPA,  "Electric  Utility  Steam Generating  Units -
           Background Information  for Proposed Particulate Matter
           Emission Standards."  EPA-450/2-78-006a, July 1978
       3.   EPA,  "Electric  Utility  Steam Generating  Units -
           Background Information  for Proposed S02 Emission
           Standards." EPA-450/2-78-007a, August 1978.
       4.   EPA,  "Alkali Scrubbing Test Facility;  Summary of
           Testing Through October 1974." EPA-650/2-75-041,  June
           1975
       5.   Lime/limestone wet-scrubbing  test  results at  the  EPA
           alkali scrubbing test facility  capsule report.   NTIS
           PB-258804, May 1975
       6.   Dickerman, J.C., _et al, "Evaluation of Dry Alkali  FGD
           Systems" Radian Corporation.   DCN  78-200-226-03.  31
           March 1978.
       7.   "Spray-Dryer System Scrubs S02", Power Vol. 123.
           No. 1, January 1979
       8.   Estcount, V.F. ^t  al,  "Test  of a  Two-Stage  Combined
           Dry Scrubber/302 Absorber Using Sodium or
           Calcium",  Proceedings of 40th annual meeting  American
           Power Conference,  Chicago,  Illinois,   April 26, 1978
       9.   Janssen, K.E.,  Eriksen,   R.L,  "Basin  Electric's
           Involvements with Dry Flue Gas Desulfurization."  EPA
           symposium  on FGD - Las Vegas  March 5-8, 1979.
      10.   "Coyote Station.   First Commercial Dry FGD  System",
           Presented at the  41st Annual meeting APE,  Chicago,
           April 23-25, 1979
      11.   Handbook - "Continuous Air Pollution Source Monitoring
           Systems", EPA  625/6-79-005, U.S.   Environmental
           Protection Agency, Cincinnati,  Ohio, June  1979
                              2-30

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A.  Letter N. Kotraba, Apitron Division, American Precision
    Industries to D.R. Goodwin, U.S. Environmental Protection
    Agency, Research Triangle Park, North Carolina,
    February 29, 1980.

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                          SECTION 3
                   RETROFIT DESIGN AND  COSTS
3.1    GENERAL
       The key pieces  of  equipment used  to  retrofit pulverized-
       coal-fired, steam  generators for  NOX reduction and  for
       control of S02  and particulates are fixed in
       operational design.  The functional  design for sizing to
       meet emission level requirements  reduce relatively easily
       to  physical layout considerations  and mathematical
       analysis.   Using  the retrofit technology outlined in
       Section  2, this section  presents the  guidelines  for
       determining  retrofit  costs.  It also presents  the
       equations for prorating to other  design conditions.  This
       is  the basis for estimating costs for any desired  retrofit
       situation.  A  typical schedule for retrofitting these
       plants concludes the discussion.
3.1.1   Emissions
       The cost modules  for NOX reduction  are based on the
       best  available  technology  associated with boiler
       modifications to  reduce NOX formation.  This document
       presents costs based  on  these modifications.  Emission
       levels of 210 ng/J heat  input  (0.5  lb/106  Btu)  for
       subbituminous  coal  and  260 nanograms  per  joule
                                3-1

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      heat input (0.6  lbs/10^ Btu) for bituminous coal are
      the basis of the modification costs.1   Actual
      implementation of the modifications discussed  previously
      may not permit this  emission level to be reached,  but  it
      presents the best potential for NOX emission
      reductions.

      The costs for SC>2 control are based on achieving
      S02 reductions in the flue gas of up to 90%.2   For
      particulate  control,  the cost  modules are based  on
      achieving emission levels of  13  ng/J heat  input  (0.03
      lb/106 Btu).3

3.1.2    Basis of Costs

      The costs of an  emission control systems are  estimated  as
      capital  costs and annualized  cost.   The capital  cost
      represents the initial  investment necessary to  install and
      commission the system.  All costs are  based on  3r*d-quarter
      1979  dollars.  Annualized costs  represent  the cost  of
      operating and maintaining the  system  and  the charges
      needed to recover  the capital  investment,  which are
      referred to as fixed costs.  The cost  of land  for  sludge
      disposal  is  not included in this study.  Land  used for
      sludge disposal is considered  to have zero value  once
      sludge disposal  at that site has ceased.

      Capital  costs  consist  of direct and indirect  costs
      incurred  up  to  the tie-in and startup  of the retrofit.
      Direct costs include the costs of various items  of
      equipment and the labor and material  (construction costs
      including field  overhead)  required for  installing these
      items  and interconnecting the systems.  Indirect costs
                             3-2

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         include such  items as  freight,  procurement,  and
         allocated  costs associated with  the purchase  and
         installation of the control equipment.

3.1.2.1   Direct costs.^  -  The purchased  cost  of the
         equipment and  the cost of installing it are considered
         direct  costs.  The  cost of an equipment  item  is  the
         purchase price paid  to the equipment supplier on a
         free-on-board  (f.o.b.) basis;  this does not include the
         freight charges.  Installation  costs  cover  the
         interconnection of  the  system,  which involves piping,
         electrical,  and the other work needed to commission it
         such as  the cost of  securing permits and the cost of
         insurance for  the equipment and  personnel on site.  The
         costs of foundations, supporting  structures, enclosures,
         ducting, control  panels,  instrumentation, insulation,
         painting,  and  similar  items are attributed  to
         installation.   Costs  including  site development,
         relocation or alteration of  existing facilities,
         administrative  facilities, construction of access roads
         and walkways,  and  establishing rail, barge, or truck
         facilities  have not  been included  in developing  the
         retrofit costs  except as noted;  they  must be determined
         on an individual  basis for a specific  plant.

3.1.2.2   Indirect costs.1*-  The indirect  costs  include
         freight from point of origin and  indirect capital  costs.
         The indirect capital  costs consist of several cost items
         which are  calculated  as  percentages of the  total
         installed cost  (TIC), the direct costs as noted above.
         The indirect capital  costs include the following  items:
                             3-3

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A.  'Interest - Interest covers  costs accrued on borrowed
   capital during construction.  (About 10% of the  TIC.)
B.  Engineering costs - These  costs include administra-
   tive,  process, project,  and general costs; design and
   related functions for specifications; bid analysis;
   special studies; cost analysis; accounting; reports;
   procurement;  travel expenses;  living  expenses;
   expediting; inspection;  safety;  communications;
   modeling, pilot plant  studies;  royalty  payments
   during construction; training of plant personnel;
   field  engineering;  safety  engineering; and consultant
   services.  (About 10% of  the TIC.)
C.  Taxes - Include  sales, franchise,  property,  and
   excise taxes.  (About 1.4%  of the TIC.)
D.  Allowance  for shakedown  -  Includes costs associated
   with system startup. (About 5% of the TIC.)
E.  Spare  parts - Represent  costs of items stocked  in an
   effort to  achieve 100 percent process availability;
   such items  include pumps,  valves,  controls, special
   piping and  fittings, instruments, spray nozzles,  and
   similar equipment not included in base cost modules.
   (About 0.5% of the TIC.)
F.  Contingency costs  - Includes costs resulting  from
   malfunctions, equipment  design alternations,  and
   similar unforeseen sources.  (About 20% of the  TIC).
G.  Contractors fee and expenses - Includes costs  for
   field labor  payroll,  supervision field  office,
   administrative  personnel,  construction offices,
   temporary  roadways,  railroad trackage, maintenance
   and welding shops,  parking  lot,  communications,
   temporary  piping,  electrical, sanitary  facilities,
   rental equipment, unloading and storage of materials,
                         3-4

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travel  expenses, permits,  licenses, taxes, insurance,
overhead,  legal  liabilities, field  testing of
equipment,  and labor relations.  Contractor fees and
expenses  are about 5% of the  TIC.  The indirect  cost
for a given estimate  is  about 58.6% of  the TIC.
Indirect  costs have been added to  all  costs
presented in this document.
                  3-5

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3.2  RETROFITTING TO REDUCE N0v EMISSIONS
                              X

     The  effectiveness  of  applying  currently  available
     retrofit  control  for  NO   emissions  to  new coal-fired
                            X                        /
     power  plants is 210 ng/J  heat  input (0.5 lbs/10
     Btu)  for  subbituminous coal  and 260 ng/J heat input
     (0.6  lbs/10   Btu)  for bituminous  coal.    However,  these
     levels  may not  always be  achievable for existing units as a
     result  of intolerable adverse  side effects.   For new units
     adverse side effects can  be  avoided by proper original
     design, but  with existing units it is more difficult to
     apply the techniques while avoiding effects are discussed in
     Section 2.2.
     Expert  advice from steam  generator manufacturers and/or
     combustion engineers is recommended in conjunction with decision
     making  on best  available  retrofit technology for NO
                                                        X
     control.
                                  3-6

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3.2.1    Retrofit Techniques for N0y_ Control

3.2.1.1  Plant data requirements.-  When considering retrofitting
         a particular boiler for NOX control in a plant, the
         following information related to existing boiler design
         and operation should be gathered:

         o  Type of boiler (single-wall, opposed-wall,
            tangential, or arch-fired)
         o  Manufacturer of the boiler
         o  Type of existing burners (arrangment, burner type,
            and burner capacity)
         o  Existing NOX control and monitoring equipment
         o  Drawings of burner arrangement,
         o  Existing NOX emissions level and State NOx
            emissions limit
                              3-7

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3.2.1.2  Design  parameters.-  There are  several  key elements
         involved in retrofitting  steam generators for  NOx
         control.  Each element is addressed  separately in the
         following paragraphs  to clarify its importance.

         A.   Type of boiler  - Steam  generator designs  vary
            between  manufacturers.   Also  individual
            manufacturers may offer  more  than one  type of
            design, and they  change  their designs over the  years
            to accomodate changed fuels,  design improvements,
            and  government regulations.  Consequently, retrofit
            designs for coal-fired steam generators have  to be
            customized for the needs of each unit.
         B.  Overfire air - Overfire  air may range from 15 to 30%
            of the total air.  The  suggested value depends on
            the  manufacturer  and  type of boiler.  Overfire air
            is effective for  Foster  Wheeler,  Riley Stoker, and
            C-E  boilers and  is one of the  key elements for
            NOX  control in these  units.  B&W (5.) does  not
            recommend overfire air.  When applying overfire air,
            ports must be cut in  the firebox, and the  wall  tubes
            have to be modified to make  space for the air port
            and  tilt  mechanism.   Additional  windbox
            modifications for  connecting the  duct to the
            overfire air ports and  the  individual air control
            dampers are required to complete the overfire air
            port retrofit. The overfire air jet velocity used
             is  6l  M/sec  (200 feet per  second), to  provide
            sufficient jet penetration depth.
                              3-8

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 C.  Curtain air ports - Curtain air  ports  are  applied
    only to the Foster  Wheeler and Riley Stoker boilers.
    The main objective  in using curtain air  ports is to
    minimize slagging and tube wastage  problems.   The
    same  air jet  velocity,  61  M/sec  (200 feet  per
    second) used for overfire air is used in sizing  the
    curtain air ports.  The  addition of ducts  and
    individual  air-flow control dampers is  needed in
    addition to the wall tube modifications  and  firebox
    wall cutting.   Curtain air ports  are designed  and
    installed in a manner to surround  the  bottom,  the
    right  and  the  left sides of the  entire burners.
    Overfire air ports  occupy the top  row  of burners.
    The amount  of  curtain air used is  10$ of  the total
    air and  this is distributed  equally among  all
    curtain air ports.  Again, the  application and
    effectiveness  of  using curtain air  ports  are
    dependent on the type and  year of manufacture  of  the
    boilers.
D.  Low NOX  burners - B&W low  NOx burners have
    been tested and  can  be applied  to existing  units.
    Poster Wheeler data  on  low NOX burners indicate,
    it may not always be effective or possible to apply
    low NOX  burners to existing  old units. When
    retrofitting existing plants with low NOx
    burners,  rearrangement  of  the burners in  the  firebox
    wall might be necessary.   This modification involves
    several  operations including:

    o    modification   of  the  membrane   tubes  to
       accomodate the low NOx  burners
    o   modification  of  the  membrane tubes  to  close
       the holes where the  original burners existed
    o    re-piping  the coal feed  lines   from  the
       pulverizer
                           3-9

-------
    o   modification of  the  windbox  to add  a
       compartment for better  control  of air/fuel
       ratios

    o  tuneup or retrofitting the  NOx  emission
       monitoring system.

E.  Combustion air  control

    o  Babcock & Wilcox uses a compartmentalized windbox
       to  provide secondary air flow metering  and flow
       control  for each pulverizer.   The result  is  a
       rigid  coal/air ratio control  to  each burner group
       and flexibility to operate with  lower  total
       excess air  while  maintaining  an  oxidizing
       atmosphere around each burner.   The  Dual Register
       burner and  the  compartmentalized  windbox  are
       coupled together for this system.  Excess  air in
       the system ranges from 15 to  2Q%.

    o  C-E boilers  use  twenty percent excess  air.  The
       air/fuel   ratio  is  kept slightly  above
       stoichiometric at the burners.   Twenty percent of
       the total air is used as overfire  air.

    o  Twenty percent  excess air  is  used for Poster
       Wheeler boilers.  The percentage of  overfire air
       is  30% and curtain air is 10/8 of the total  air.

    o   Twenty  percent excess air  is  used  for  R-S
       boilers.  Overfire air is 30% and  curtain  air is
       IQ% of the total air.
                          3-10

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3.2.1.3  Retrofit calculation  procedures. -
        A.  Dual Register Burners for Babcock &  Wilcox Steam
            Generators - As mentioned In the previous  sections,
            for  the  B&W boilers, the  Dual Register burners
            coupled with modified windbox  compartments  is the
            technique recommended for NOX control.  The
            existing cell burner, and each  coal  nozzle  must be
            replaced by an individual dual register burner.  The
            dual register  burners  have  a  rating  equal
            approximately that of a coal nozzle  or one-third of
            that of  a cell  burner,  and therefore,  the  total
            number of the Dual Register burners  installed will
            be three times that of the cell burners.

         B. Sizing  of Overfire  Air (OPA)  Ports & Curtain Air
            (CA) Ports  - The burner arrangement dictates the
            number  and  location of  overfire  air  ports and
            curtain  air ports.   For this  study C-E, F-W, and
            Riley Stoker  boilers are  retrofitted   with
            overfire-air ports,  but only F-W and Riley  Stoker
            boilers will be  retrofitted with curtain  air  ports.
            The  location of the overfire air ports is,  in
            principle, always at  the top of each topmost  burner
            of  each  vrtical burner  column,  for all   three
            boilers.  (see Figure 3-1)  In the figure, (A)  is an
            example of the normal location of the OFA  port in a
            C-E  boiler.  where  the firbox  structure does not
            allow the OFA ports to be located directly on  top of
            burners, the OFA  port is offset but  near  the  burner
            top.  C-E has retrofitted OFA  ports  in a manner
            similar to (b) for NOX control tests at Alabama
            Power Company's,  Barry Unit 2 (6).
                                3-11

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         o
         o
         o
         o
         o
         o
         o
        (A)
                    OFA PORT
                      (TYP)
(OFFSET
 CONFIGURATION)


OR
                         BURNER
                          l (TYP)
                                          O
                                          O
                                          o
                  o
                                          o
                  (B)
Figure 3-1-  Location of overfire  air ports for C-E  boilers,
                          3-12

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             Figure  3-2 shows the arrangement  of  the curtain air
             ports  for the  Poster  Wheeler  and Riley Stoker
             boilers.

             Prom  Figure 3-2, you can see that  the  number of OFA
             ports  is  equal  to  the  number of  burner columns, N,
             and the number of  curtain air ports is  (N +  2M)  where
             M  = number of burners per column.  The  size of each
             OFA port  is based  on the overflre  air required  at an
             inlet  velocity of  61 M/sec (200  Pt/sec).

             In order  to minimize the number of wall tubes  which
             will  be affected and  to minimize  impairment of the
             firebox wall in retrofitting OPA  ports, a 2:1  ratio
             of height  and width is used.

3.2.2    Retrofit  Costs for NOX Control

3.2.2.1  Burner module  cost.-

         A.   Retrofit  Capital Cost -

             The low NOX burner module costs  for B&W  retrofit
             are given  in Table 3-1.  A boiler  manufacturer's fee
             of $60,000 for an  engineering analysis  of the firebox
             should  be  added  to the total retrofit  cost for the
             boiler  once the burner module costs are  determined.
                               3-13

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        n
                    N=No.  OF BURNER COLUMN
                x
                x
                X    X
                          X
                               X
                          XXX
                                     X
                                          OFA PORT
                                            (TYP)
J
                                                       M=  No.  OF
                                                       BURNER IN
                                                       ONE COLUMN
          X   : REPRESENTS  BURNERS
             : REPRESENTS  CURTAIN AIR PORTS
Figure 3-2.- Arrangement of  curtain air ports, for F-W and R-S boilers,

                                    3-14

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             TABLE 3-1.- B&W LOW NOX  BURNER  COSTS
             Burnera(MW=3.5)                  $  61,800
             Piping                             1,000
             Instruments                        8,000
             Insulation, paint                    100
             Freight                            4,100
             Construction Cost                  59,000
               Total Installed Cost            134,000
             Indirect Capital Costb              79,000
               Total Module Cost Per  Burner    $213,000

         B.  Annual Costs -
             Annual costs for B&W low NOX burner retrofit
             systems should be estimated  at 17.2 percent of the
             total capital cost.   No  allowance should be  made for
             maintenance because maintenance costs for the new
             burners should be much the  same as  maintenance  costs
             for the old style burners.  No  allowance is  made for
             additional operation labor  or energy  costs.

3.2.2.2  Overfire air ports.-

         A.  Retrofit Capital Cost -
             The cost  of an overfire air  port  for C-E,  PW, and
             R-S retrofits includes port and membrane wall  tubes
             modifications, port  tilt  mechanism,  air  flow
             controls,  windbox and ducts additions, and the boiler
             manufacturer's engineering  analysis of the firebox. A
             boiler manufacturer's  fee  of  $60,000  for  an
             engineering analysis of  the firebox should  be  added
             to the total retrofit cost for the boiler  once the
             burner module costs  are  determined.  The module  cost
             of an overfire air  port  is  given  in Table 3-2.
aBurner cost based on Dual  Register  burner,  three burners
required for each cell burner  replaced
bSee Section 3.1.2 for definition  of indirect  capital costs
                                 3-15

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            TABLE 3-2.- OVERFIRE-AIR PORT COSTS

            Port fabrication                    $ 12,500
            Duct work and windbox modification     4,500
            Instruments and controls               6,500
            Freight                                1,500
            Subcontract                            4,500
            Construction Cost                     56,000
              Total Installed Cost                85,500
            Indirect Capital Costa                50,100
              Total Module Cost Per Port        $135,600

         B.  Annual Costs -

            Annual costs for  overfire  and  curtain  air ports
            should be estimated at 22.2 percent of total  capital
            costs.  This allows  17.2 percent for amoritization
            and  5.0 percent for maintenance and supplies.

3.2.2.3  Curtain  Air Ports.-

         A.  Retrofit Capital Cost -

            Cost of a curtain air port is taken as 63%  of an  OPA
            port or $ 85,000/port.  The  boiler manufacturer's
            engineering analysis  should be  included  in  the  OFA
            ports  costs as given in Section 3.2.2.2

         B.  Annual Costs -

            See  Section 3.2.2.2 B

3.2.2.4  Combustion air fan.-  No costs for additional  combustion
         air fans are estimated for special burner, overfire air,
         and curtain air modules.
aSee Section 3.1.2 for  definition  of  indirect capital costs
                               3-16

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3.3     RETROFITTING DUCTWORK AND STACKS

        For most existing power plants, there  will not be enough
        space  to  locate retrofit systems between the steam
        generator and the existing stack.   Although  it might  be
        possible  to remove existing  air pollution control
        systems to make room for the retrofit  system between the
        steam generator and the stack, this would usually  make
        it necessary to shut down the steam generator for  more
        than  one year while  the  retrofit  system  is  being
        installed.   Consequently,  retrofitting  will usually
        involve  installing the  retrofit system  beyond the
        existing stack.  This will increase the length of  duct
        work  required to retrofit  an  air pollution control
        system to an existing steam generator  and  stack.

        The  additional length  of  ductwork  required  for
        retrofitting is the length of ductwork needed to  connect
        the retrofit system  to  the  existing  ductwork near the
        stack and the length  of ductwork needed  to return the
        cleaned gases from the retrofit system to the existing
        stack.  Otherwise the lengths of ductwork needed for  a
        new or a retrofit air pollution control system are  much
        the same.

        Analysis of the costs  of  ductwork  for  retrofit
        situations  indicates  that  15 percent  of the  total
        capital costs of a new air pollution control system  is  a
        liberal allowance for  the additional cost  of ductwork
        for a retrofit system.13,14   in special cases where
        space  limitations make  it  necessary to  locate the
        retrofit air pollution  control system remote from the
        existing  stack it may be less costly to erect  a new
        stack in conjunction with  the retrofit system thereby
        decreasing the length of ductwork  needed to  connect the
        retrofit system to the stack.   Table 3-3 shows estimated
        capital costs of new stacks.15
                             3-17

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The diameter of stack needed should be estimated using a
gas volume of 3760 actual cubic feet per minute per
gross megawatt of steam generator capacity and a linear
gas velocity at the outlet of 65 feet per second.
In cases where SO- control systems are to be retrofitted
it may be necessary to reline or to replace the existing
stack to provide for corrosion resistance.  These costs are
not included in the cost estimates of this document.
TABLE 3-3.  Values of A and B for Estimating the Cost
            of Utility Boiler Stacks
Inside
Stack Diameter
at Outlet
Feet
15
20
30
40
Where Y = AHb
Y = Capital cost  (direct and indirect) third quarter
    1979 dollars
H - Stack height  - feet  (range between 250 and 1200
    feet)
Costs include - concrete shell, foundations, and  steel
    liner
Designed for -
    Windload - 40 pounds per square foot
    soil bearing  - 4500  pounds per square foot
    seismic conditions  - Zone 1 (minor risk)
A
0.185
0.393
2.184
4.377

2
2
2
2
B
.625
.535
.330
.262

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3.4      RETROFITTING TO CONTROL  PARTICULATE EMISSIONS

3.4.1    General

         Electrostatic precipitators  and baghouses  are  most
         commonly used for high efficiency  removal  of
         particulates from the combustion gases of coal-fired
         steam generators.  When  flue gas desulfurization  systems
         are required, particulate  scrubbing is  often
         incorporated into the  air  pollution control system,
         although,  of course,  scrubbing  can be  used  for
         particulates in systems  when sulfur is not a problem.

         When an ESP is installed before the air preheater, it is
         called a hot-side ESP.   When it is installed between the
         air preheaters and stack,  it is called a cold-side ESP.

         Baghouses for high efficiency  particulate control have
         become more  widespread recently, especially when the
         coal ash is difficult .to collect with an ESP.   Baghouses
         are located downstream  of  the  air preheater.

         There are other particulate  collectors such as cyclones
         and settling chambers,  but  they are not efficient enough
         to  reduce particulate emissions to the levels required
         by  current new source performance standards.

         The three  alternatives  to be  explored  for  this
         particulate emissions control  retrofit study are:

         0 Upgrading either cold-side or hot-side EPS systems
         0 Installing baghouses
         0 Installing scrubbers  in  conjunction with  flue  gas
          desulfurization  while retaining the  existing
          particulate controls.
                                   3-19

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Various levels  of particulate  emission control  can be
achieved by retrofitting ESP's based on  various  specific
collection areas.  The efficiency achieved by  baghouses has
been demonstrated to control  particulate emissions to
levels  less than  13 nanograms/joule (0.03 lb/106 Btu)
with an air to cloth  ratio of 0.61 actual cubic meters per
minute  per square  meter (2 ACPM/ft2)  and with pressure
drops of less  than 1.25 kilopascals (5  in.  I^O) in
the filter at  the  full-load gas volume.3

The EPA position  on  aspects  involved  with  the  operating
effectiveness  of the  electrostatic  precipitator and
baghouse  systems of  this document  are discussed in
Appendix E of  these guidelines.

Unlike techniques  for NOX emission reduction, the
principal systems for particulate  emissions control -
ESP's  and baghouses,  can  be  applied  to  all  four
manufacturer's boilers.  Key elements in retrofitting an
existing plant for particulate  emissions control  include
the following  items:

o    The total  collection  area and  arrangement  of the
    existing particulates collection equipment  (ESP's or
    baghouses) must be  known.
o   The available plant space for  retrofitting  ESP's, or
    baghouses,  or scrubbers must  be  established  and  must
    be determined to  be adequate.  Unlike NOx emission
    reduction  retrofits, the retrofitting for particulate
    emissions  requires  significant additional plant  space.
    Relocation of existing  equipment, and addition  of flue
    gas ducts  and fans  may  be involved.   The  existing plot
    plan affects  the  retrofit cost because the  choice of
    arrangement  for the retrofitted equipment is very much
                          3-20

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dictated  by  it.   Detailed  information  about  the
avilability of additional space is a vital element for
an economic retrofit.
Flue gas flow rate and its temperatures in and out  of the
air preheater and out of the economizer must be known.
These data govern the size of the retrofitted system.
                      3-21

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3.H.2  Electrostatic Precipitator Design

       The design of a  new  ESP system should  be  based on  the
       performance data of  the  existing  ESP system  firing  the
       same  coal whenever possible.   In case there are  no such
       data  available, coal ash analysis provides  valuable data
       for selecting the size and type of  ESP  required to achieve
       the desired efficiency.  Ash resistivity  is  a major  factor
       affecting the size of an ESP system.  The resistivity of
       ash entering the  air preheater is much  less  when  it  is at
       temperatures of 316 to  482C  (600  to 900P) compared to
       its resistivity  at  the air preheater outlet  where  the
       temperature is about 149C (300F).  Therefore,  with high
       resistivity ash coal, it is easier  to collect  on  the  hot
       side  than on the  cold side.  The following factors must be
       taken into  account in  deciding whether a  hot-side or a
       cold-side ESP system  is to be used  (3.) :

       o  Space available for the retrofit system
       o  Temperature-resistivity characteristics of the  fly  ash
       o  Specific collection area requirements
       o  Differences  in gas  volume caused by temperature
          differences
       o  Differences in gas  volume caused by  air leakage  into
          the air  preheater
       o  Differences  in  construction requirements  caused by
          temperature differences

       Analysis of the data  on ESP's in Reference  3  shows  that
       ESP systems can  limit  particulate  emissions  from steam
       generators to levels less than 13  nanograms  per  joule
       (0.03 lbs/106 Btu).   The size of the system  required
       to meet  a given  emission  level depends  upon  ash
       characteristics and the level of control  required.
                                   3-22

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The factors  that  have been discussed dictate that  the
features  in  the following list need to be included in ESP
retrofit  systems  for control of particulate emissions from
large steam  generators.

o  Either a cold-side system  or  a hot-side system is
   chosen and the choice depends on circumstances  such as
   the additional space  required and  available,  and the
   possibility for installing the ductwork on either the
   entrance side or  the  downstream side  of  the  air
   preheater.
o  Sufficient electrical  sectionalization should  be
   included  in the ESP  system to  ensure that adequate
   collecting  surface  area will be  available should a
   breakdown occur in one of the sections.
o  Automatic power controls should be provided as  well as
   instrumentation showing; 1) primary voltage, 2) primary
   current,  3)  secondary voltage,  4) secondary current, 5)
   spark  rate for each individual section.
o  Insulation should be sufficient to minimize temperature
   drops  which would cause acid attack.
o  Enough flue-gas-flow,  cross-sectional area should be
   included  to ensure maintaining the  system  in  the high
   collection efficiency range.
o  Provisions should be  made for good flue gas  velocity
   distribution  in the  gas passages,  even  at  partial
   loading.
o  Sectionalization of  the  rapping system for difficult
   dust should be about 139 square meters (1,500 ft^)
   of collecting  plate area per rapping section.
o  Separate  electrical  sectionalization  should  be about
   one section for each 5 MW of gross generating capacity.

Retrofitting can  achieve the following limits  indicated in
Table 3-4 that follows (3):
                            3-23

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TABLE 3-4.-ESP SPECIFIC COLLECTION AREA (SCA) FOR VARIOUS COALSa
Coal Sulfur
 Content %

     .8
     .8
     .8
     .8
     .8
     .8
    3.5
    3.5
    3.5
Emission Limit
 (lb/10  Btu)

     .03
     .03
     .05
     .05
     .10
     .10
     .03
     .05
     .10
ESP Type

  Hot
  Cold
  Hot
  Cold
  Hot
  Cold
  Colda
  Colda
  Colda
    SCA3
Ft /1000 SCFM

    650
   1000
    550
    800
    400
    650
    360
    300
    240
aHot side ESP's not normally used with 3-5% S coal

         The following data can be used for estimating  the  flue
         gas volume once the gross MW capacity of the unit  is
         known:
         Coal Heating Value
           (as burned):
         Heat Rate:

         "F" Factor  (11):
         Excess Air at Economizer:
         Flue Gas Temperature  out
          of Economizer  (Hot Side)
                         Variable, depending  on
                         the  coal
                         2.924 X 103 j/K'WSec
                         (10,000 Btu/KW  Hr)
                         2.64 x 10-7 Dry
                         Standard Cubic
                         metres per  joule
                         (9,820 SCF/1Q6  Btu)
                         at Q% excess  air  and
                         20C (68F)
                         25$

                         343C (650F)
                               3-24

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         Excess  Air Out of Air
          Preheater:
         Flue  Gas Temperature out of
          Air  Preheater (Cold Side):      l49C (300P)
         Water Content of Flue Gas:       10% of dry gas  volume

3.4.2.1  Hot-side precipitator.-  The major  problem encountered
         in retrofitting hot-side ESP systems to an existing
         plant is insufficient space for fitting the hot-side  ESP
         between the  economizer and air preheater.   If there  is  a
         space problem, either the air preheater has to be moved
         and  relocated to allow for duct work, or considerations
         must be  given  to  retrofitting  with  cold-side  ESP
         systems.

         Duke  Power Company  has  retrofitted  both  hot-and cold-
         side  ESP systems at their utility plants (16).   Duke
         Power's hot-side ESP retrofits to their C-E boilers  was
         achieved without relocating the air  preheaters  because
         space was available for ducting tie-ins.

         For Duke Power hot-side retrofits,  the flue gas  duct  was
         partitioned  into two parts at the horizontal section in
         front of the air preheater.  Hot  flue gas was guided
         into  a  new duct, stemmed from one side of the partition,
         and was routed to the hot-side ESP  system.  The return
         gas  from the ESP system was directed into a new duct
         that  lead back to the  other partition and flowed into
         the  air preheater.

         When  the existing gas passage ducting does not allow  for
         any modification, the only alternative to retrofitting
         with  hot-side ESP systems is to remove the air preheater
         and  relocate it in  order to provide enough space for  the
         duct  work.   This installation involves shutdown time.
         The  retrofit work must  be based on  individual  designs
         for  each situation.
                                 3-25

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3.4.2.2   Cold-side  precipitator.-  Retrofitting cold-side  ESP
         systems  to an existing plant  involves connecting  and
         adding ducting to the existing  flue-gas outlet of  the
         air preheater or the existing  ESP.   The exit flue-gas
         duct from  the ESP systems  is connected to the ID fan,
         stack, or  scrubber system  depending upon plant design.

3.4.2.3   Flue Gas Conditioning
         The specific collecting  surface  area values of Table  3-4
         do not reflect the possible  beneficial effect of flue
         gas  conditioning  agents    such as  sulfur  trioxide,
         sulfuric acid, or ammonia.  Although it  is possible that
         use of  these agents would reduce the size of the  ESP
         required   to  meet  a given level  of control,  the
         conservative estimates  of  Table  3-4  should be used  for
         cost  estimating.  However,  if  an owner elects to  use
         flue  gas  conditioning  to  implement a  best  available
         retrofit technology decision,  this should be allowed
         with  a provision that the  emission  limitations of  the
         BART decision  must be  met.

3.4.3    Baghouse Design

         The type of baghouse considered in this retrofit  study
         is the inside-out, multicompartment, reverse-air design.
         Of course  other baghouse  designs,  such as outside-in
         filtration, pulse-jet cleaning,  and  shake cleaning  can
         be used  as alternatives.

         The design criteria and design  features  of the baghouse
         systems  to be used in this  retrofit  study are summarized
         in the following list:
                                3-26

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o  Air to cloth  ratio is 0.61 actual  cubic meters per
   minute per square  metre  (2 ACFM/Ft2) to handle
   full  load  gas  volume at pressure  drops less than
   1.25 kilopascals  (5"  H20)
o  Reverse-air cleaning
o  Multicompartment  system
o  Provision for isolating  each compartment for cleaning
   or maintenance  while the other  compartments  are  on
   line
o  Provision for automatic  cleaning on a compartment  by
   compartment  basis with controls  for adjusting the
   quantity of reverse air, the frequency of cleaning,
   and the duration  of cleaning
o  Provision for instruments indicating pressure drop
   and temperature in and out of the baghouse
o  Adequate  insulation to minimize  temperature drops
   which would cause  acid attack on the baghouse
                  3-27

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3.4.4     Retrofit Costs  For Particulate Control

3.4.4.1   Electrostatic Precipitators.-   The following equation
          should be used to estimate the capital cost of retrofit
          electrostatic precipitator (ESP)  systems.

               Cold Side ESP Systems
                    y - 3635 (X)'6404

               Hot Side ESP Systems
                    y = 414.5 (X)'8129

          Where:
               y = total capital cost in third quarter 1979
                   dollars
               x = square feet of collecting surface area

          These costs include the direct and indirect costs of
          the ESP including ash removal and the additional cost
          of retrofit ductwork (15 percent).  The costs are derived
          from the costs used to support the new source performance
          standards for new electric generating units.

          The total collecting surface area required can be
          determined using 1) the data of Table 3-4, 2) data on
          the size of each steam generator to be studied, 3) data
          on the ESP collecting surface area installed, and
          4) data on the coal characteristics.  With low sulfur
          coal more collecting surface area is usually needed
          than for high sulfur coal.  In most cases it will not be
          possible to retrofit a hot side ESP.  However, since
          some hot side ESP's have been retrofitted, cost data is
          included.    When the necessary data has been obtained
          from the power plant, cost estimates can be made.
                                 3-22

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Once the levels of control to be studied are selected
(usually by those responsible for visibility impact
analysis) the specific collecting surface areas (SCA)
should be selected from Table 3-4.  For cases not
covered by the table, ESP vendors should be consulted
for advice or engineering judgments should be made.
Total gas volume should be computed using the following
estimates:

     Hot Side ESP Systems
          Gas volume = 4730 ACFM per megawatt at 650F

     Cold Side ESP Systems
          Gas volume = 3760 ACFM per megawatt at 300F

Although actual gas volume may be less than the foregoing
values, these estimates provide a safety factor for
cost estimating.  These gas volume values should not be
used for enforcement purposes when test data show
different values.

Once the total collecting surface area requirements are
estimated using the data on gas volume and collecting
surface area, any installed collecting surface area
should be deducted to determine retrofit requirements.
The example on the Navajo plant of Appendix C shows how
the foregoing technique is applied.  Once the additional
ESP area has been estimated the capital cost of the
retrofit system should be computed using the applicable
capital cost equation.

Annual costs should be estimated using the following
equations:
     Cold Side ESP Systems - y = 965.03  (x)0'6381
     Hot Side ESP Systems  - y = 111.54  (x)'8099
                         3-29

-------
              y = annual costs - third quarter 1979 dollars
                  per year
              x = retrofit collecting surface area required -
                  square feet

         Annual costs can be estimated in units of mills per
         kilowatt hour by dividing the dollar values by annual
         power generation.  In the absence of data from the plant,
         annual power generation should be estimated assuming the
         steam-electric generating system operates at 65 percent
         of net  (not gross) generating capacity during the year.
         In determining net generating capacity the electric
         power requirements of the retrofit systems should be
         deducted from the net generating capacity of the plant
         prior to retrofitting.

         ESP  retrofit costs should be estimated separately for
         each steam  generator.  As previously stated, the  costs
         include both direct and indirect costs and provide  an
         allowance for the additional cost of retrofit ductwork.
         Other costs that are not included but that might  be
         involved are discussed in Sections 4.2,  4.4, 4.5, and  4.6,

         The  electrical energy  requirements of ESP systems afe
         estimated to be  2.810  kilowatts per  1000 square  feet of
                                        13
         collecting  surface area added.    This value or  a value
         obtained by consultation with  ESP vendors should be
         used to estimate  the requirements for replacement of
         electric generating  capacity as discussed in Section 4.4.

3.4.4.2  Baghouses.  - The  following  equations  should be  used to
         estimate the capital cost of baghouses  for  any  retrofit
         situations:

               y  = 173420  (x)0'8384 without booster fan
          or
               y = 174987 (x)-8563 with booster fan
                                    3-30

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Where:

     y = capital costs - third quarter 1979 dollars

     x = size of baghouse - megawatts

These equations are applicable for full or partial gas
treatment.   For example where a 500 megawatt unit is to
be retrofitted for filtration of 70 percent of the flue
gas, baghouse size would be 350 megawatts.  A booster
fan should be provided in cases where only a baghouse
is to be retrofitted.  If the baghouse is to be
retrofitted in conjunction with SO^ control, the cost
of the booster fan is included in the SC^ control cost
estimate.

The baghouse capital cost equations include the direct
and indirect costs of the baghouse additional retrofit
ductwork, and the ash removal systems for a 2-to-l air
to cloth ratio, reverse air baghouse.  The costs do not
include those discussed in Section 4.2, 4.4, 4.5, and
4.6.  The data needed for baghouse cost estimates are
data on the size of each steam generator  (gross megawatts)
and the foregoing equations.  The capital and annual
costs are derived from the cost data used to support the
new source performance standards for electric utility
steam generators and include a 15 percent allowance for
additional retrofit ductwork.   Cost
separately for each baghouse system.
additional retrofit ductwork.    Costs should be estimated
Annual costs for baghouses should be estimated using
the following equations:
     y = 31090  (X)'8494
     y = 21934  (x)*9358
                          3-31

-------
         Where:

              y = annual costs  - third quarter  1979 dollars per year
         and
              x = baghouse capacity  - megawatts

         These costs can be converted to units  of mills per
         kilowatt hour using the techniques described  in
         Section 3.4.4.1.

         The  electrical energy  requirements of  baghouses  are
         estimated  to be 6.615  kilowatts per megawatt  of  baghouse
         capacity.    This value should be used to  estimate  the
         capital cost of replacing  electric generating capacity
         as discussed in Section 4.4 and for estimating unit
         annual costs as discussed  in Section  3.4.4.1.

         Other costs  that may be involved with  retrofitting  but
         not  included in the foregoing  cost estimates  are discussed
         in Sections  4.2, 4.4,  4.5,  and 4.6.

3.5      Retrofitting To Control 502 Emissions

3.5.1    Retrofit  Costs  For Wet SCU Control

         Table  3-5  shows  the values of  A and  b  to  be  used in
         estimating retrofit costs  for  various  flue gas
                                        ?
         desulfurization systems where:

               y   Axb
         and
               y  =  capital  cost  -  third  quarter 1979 dollars

               x  =  size  of  system -  megawatts
                                3-32

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     TABLE 3-5.- VALUES OF A AND b FOR ESTIMATING CAPITAL AND
          ANNUAL COSTS OF WET FLUE GAS DESULFURIZATION SYSTEMS
       SYSTEM
  CAPITAL COSTS
  THIRD QUARTER
  1979 DOLLARS
                  ANNUAL COSTS
                  THIRD QUARTER
                  1979 DOLLARS
                    PER YEAR
Lime FGD
  Eastern 3-5IS
  Eastern 7. 048
  Western 0.8*8
  Anthracite
  Lignite
1.715x10)
1.874x10
1.450x10
166.0x10)
166.2x10'
6
0.6612
0.6663
0.6546
   1
   1
  494x10:
528.2x10:
  405x10:
61.62x10:
61.92x10'
0.7107
0.7264
0.7052
   1
   1
Limestone FGD
  Eastern 3.5%S
  Eastern 7.0IS
  Western 0.8%S
2.321x10"
2.373x10
1.756x10
   0.6375
   0.6563
   0.6455
             656.4x10:
             672.0x10:
             508.3x10'
           0.6803
           0.7020
           0.6828
Mag-Ox FGD
  Eastern 3.SIS
  Eastern 7.0IS
2.708x10)
2.790x10
   0.6279
   0.6464
             810.9x10:
             811.6x10'
           0.6623
           0.6869
Double Alkali FGD
  Eastern 3.5IS
  Western 7.0IS
2.624x10)
2.791x10
   0.6194
   0.6274
             712.0x10:
             735.6x10'
           0.6745
           0.6955
Wellman Lord FGD
  Eastern 3.SIS
  Western 7.0IS
2.573x10)
2.542x10*
   0.6156
   0.6307
             784.1x10:
             775.8x10'
           0.6415
           0.6539
                                 3-33

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The costs include the direct and indirect costs of:
     Feed storage and handling
     Scrubbing
     Plume reheat to 175F
     Liquor treatment
     Sludge disposal
and  Booster fans

The costs include one spare scrubbing module and booster
fan for each steam generator and allow 15 percent for
the additional cost of retrofit ductwork.  The design
effectiveness of the systems shown in Table 3-5 is
90 percent removal of S02-  The EPA position on aspects
involved with the operating effectiveness of the wet SO^
scrubbing systems of this document is discussed in
Appendices D and E of these guidelines.  The costs are
derived from the costs used to support the new source
performance standards for new steam electric generating
      7
units.
                         3-34

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     The cost equations can be used for partial scrubbing cost
estimates.   The size of scrubbing system for partial scrubbing
should be calculated by the following equation:

               = CSG * p
                   0. 9

     Where CgCR = Size of scrubbing system for partial
                    scrubbing-megawatts
           CgG  =  Size of steam generator-gross megawatts
     and   P    =  Percent SO- removal desired

Once the size of the scrubbing system is computed, the capital
cost should be estimated using the applicable values of A and b
from Table 3-5.  For most cases the least costly system (usually
lime scrubbing) should be selected.  Data on coal characteristics
and steam generator size (gross megawatts) are all that are
needed to estimate retrofit costs.  Costs should be estimated
separately for each steam generator.

     For partial scrubbing of less than 75 percent of the flue
gases plume reheat is usually not necessary since the bypassed
flue gas will usually heat the combined gas from the scrubber
to at least the combined gas from the scrubber to at least
175F.  The capital costs estimated using Table 3-5 can be
adjusted by deducting $6 for each megawatt of scrubber capacity
for cases where no plume reheat system is necessary.    Case
2A of Appendices A, B, and C show examples of capital and
annual cost estimates for partial scrubbing.

     Annual costs should be estimated using the data of
                                     2
Table 3-5 and the following equation:

-------
                         Y  =  AXb
               Where      Y  =  annual  scrubbing  costs  -
                               Third quarter  1979  dollars  per year
                         X  =  scrubber capacity - megawatts
          For  partial  scrubbing cases that  do  not  include  a reheater
          $4200 per year  per  megawatt of  scrubber  capacity should be
                                     13
          deducted from annual  costs.     Unit  annual costs can be
          estimated using the techniques  described in  Section 3.4.4.1.
               Electrical  energy requirements  for  wet scrubbing systems
                                                   2
          should be  estimated as shown  in Table  3-6  .  Auxiliary boiler
          capacity for  reheating from 125 to  175F  should be estimated
          at 210, 000 Btu per  hour heat  input per megawatt of scrubber
          capacity.

               Other costs that may be  involved  with  retrofitting but
          are not included in the foregoing estimates are discussed in
          Sections 4.2,  4.3,  4.4, 4.5,  and 4.6.

3.5.2     Retrofit Costs  for  Lime Dry S02 Control

               The total  indirect and direct  capital  cost of lime dry
          scrubbing  systems should be estimated  at 125 third quarter
          1979 dollars  per kilowatt of  scrubber  capaticy.    These costs
          include:
               Feed  Storage and Handling
               Dry Scrubbing
               Sludge Disposal
               Booster  Fans
               and Retrofit Ductwork

          The design effectiveness of the system is  70 percent removal
          of S0~ .  The  costs  include 15 percent  allowance for the
          additional cost  of  retrofit ductwork.
                                     3-36

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         TABLE 3-6.   ELECTRICAL ENERGY REQUIREMENTS
              FOR WET FLUE GAS DESULFURIZATION2
     System
Electrical Energy Required
    Percent of Scrubber
Capacity (Gross Megawatts)
Lime Scrubbing
  0-3.5 percent sulfur
      7.0 percent sulfur
           3.5
           3.5
Limestone Scrubbing
  0-3.5 percent sulfur
      7.0 percent sulfur
           3.5
           4.3
Double Alkali Scrubbing
  0-3.5 percent sulfur
      7.0 percent sulfur
           3.1
           3.1
Magnesium Oxide Scrubbing
  0-3.5 percent sulfur
      7.0 percent sulfur
           5.9
           9.4
Wellman Lord Scrubbing
  0 - 3.5 percent sulfur
      7.0 percent sulfur
          13.3
          25.9
                                3-37

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               The  annual  costs  of  dry scrubbing  are  estimated at
          41,500  third quarter 1979 dollars  per year  for each megawatt
          of scrubbing system capacity.

               Electrical  energy requirements  for dry scrubbing should
          be estimated at  16.9 kilowatts  per megawatt of scrubber
          capacity.

               Annual costs can be  converted to unit  annual costs using
          the techniques described  in Section  3.4.4.1.   Other costs
          involved  with retrofitting but  are not  included in the fore-
          going estimates  are discussed in Sections 4.2, 4.4, 4.5, and
          4.6.

3.6       LAND AREA REQUIREMENTS

               Additional  space is  needed for  retrofit air pollution
          control systems  except for NO  steam generator modifications
                                       X
          where the necessary hardware can be  fitted within existing
          structures.  In most cases it will be necessary to locate
          retrofit  particulate and  S02 emission control systems on the
          other side of the existing stack from the steam generator.
          Although  it might be possible to locate part of the retrofit
          systems between the stack and the steam generator by removing
          existing  air pollution control  systems, usually this is not
          a viable  option since removing  existing equipment would involve
          extended, costly shutdown of the steam generator.

               For  electrostatic precipitators a minimum of  12.5  square
          feet of space is needed for each 1000 square feet  of collecting
          surface area added.    Minimum baghouse space requirements
          should be estimated at 37 square feet per megawatt of baghouse
          capacity.    These space  requirements are for a 2  to 1  air
          to cloth ratio baghouse and do  not include space for ash
                                       3-38

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         storage or disposal.

              Table 5-7  shows  space requirements for wet lime,  wet
         limestone, and  dry lime scrubbing systems.     These estimates
         include space for feed storage and handling, scrubbers,  and
         liquor  treatment  but  do not include space for sludge disposal.
         Table 3-8 shows values for estimating S02 sludge generation.13
         A 50  percent  solids content should be used  for all cases
         except  for low  sulfur Western  coals or for  Eastern coal  cases
         where a special oxidation system is to be installed.   For
         those cases 70  percent solids  content should be used.   Sludge
         volumes can be  converted to area by assuming a. pond depth and
         life.   A pond depth of 50 feet and a life of 20 years  should
         be used except  for site specific situations where other  values
         are a more logical choice.

              The foregoing values should be used to identify potential
         space problems  involved with retrofitting.   If space problems
         are identified, more  comprehensive studies  than those  of this
         document will be  needed to indicate potential solutions.

3.7      EMISSION MONITORING COST

              The retrofit cost for emissions monitoring systems
         (18,  19,  20)  is divided into two categories:

3.7.1    Retrofit Capital  Costs

         Monitoring Equipment

              S02/N0 System (I/Boiler)
              Analyzer,  Remote Readout   Control =         $30,000
              Installation Cost                  =          22,000
              Total Installed  Cost               =          52,000
              Indirect Capital Costa             =          30,000
              Field Certification Fee            =          10,000
              Total S02/N0 System:                =          92,000
         aRefer  to  Section  3.2.1  for  definition
                                       3-39

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         TABLE 3-7.   MINIMUM LAND AREA REQUIREMENTS FOR
           LIME AND LIMESTONE SCRUBBING SYSTEMS13
     System
Minimum Land Area Required
    (Square Feet Per
Megawatt Scrubber Capacity)
Wet Lime Scrubbing
  0.5 percent sulfur
  3.5 percent sulfur
           80
          180
Wet Limestone Scrubbing
  0.5 percent sulfur
  3.5 percent sulfur
           80
          140
Dry Lime Scrubbing
  (Includes Baghouse)
           80
                              3-40

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         TABLE 3-8.  SLUDGE GENERATION FOR LIME AND
               LIMESTONE SCRUBBING SYSTEMS13
     System
  Sludge Generation
(Cubic Feet Per Year
   Per Megawatt For
1 Percent Sulfur Coa1)
Wet Lime Scrubbing
  (50 percent solids)
       6,000
Wet Lime Scrubbing
  (70 percent solids)
       4,000
Wet Limestone Scrubbing
  (50 percent solids)
       7,000
Wet Limestone Scrubbing
  (70 percent solids)
       5,000
Dry Lime Scrubbing
       6,000
                              3-41

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Opacity System (I/Boiler)
Transmissiometer, Remote Readout,
 Converter Unit,  Air Flush Equip.,
 and Miscellaneous                      =         $15,000
Installation Cost                       =          26,000
Total Installed Cost                    =          14,000
Indirect Capital  Costa                  =          24,000
Field Certification Fee                 =           5,000
 Total Opacity System:                            $68,000

Oxygen Analyzers  (2/Boiler)
Probe, Shield, Umbilical 
 Controller                             =         $40,000
Installation Cost                       =          37,OOP
Total Installed Cost                    =          77,000
Indirect Capital  Cost a                 =          45,000
Field Certification Fee                 =         	5,000
 Total Oxygen Analyzers:                         $127,000

Strip Chart Recorders 3/Boiler)         =         $ 6,000
 Installation Cost                      =           6,000
 Total Installed Cost                   =          12,000
 Indirect Capital Costa                 =           7,000
  Total Strip Chart Recorders:                    $19,000
Data Processor (I/Plant)
 Processor, Software Pkg., Cabinet
 $ Reason Code Panel                    =          $50,000
 Installation Cost                      =           25,000
 Total Installed Cost                   =           75,000
 Indirect Capital Costa                 =           44,000
 Field Certification Fee                =            2,000
  Total Data Proces:                              $121,000
aRefer to Section 3.2.1 for definition
                           3-42

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3.7.2     Operating Costs

          Operating Costs Plant
            Labor 1 man per shift with 3
             shifts @ $11/MH
            Annual Labor Cost                     =         $96,100
            Material and Miscellaneous            =           5,900
                                        Total     =        $100,000

3.7.3     Annual Costs
               Annual costs should be estimated at 17.2 percent of
          capital costs plus $100,000 per year per plant as given above,
           Annual operating costs based on 365 days per year and
           24 hours per day.
                                      3-43

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3.8   TIME REQUIREMENTS FOR RETROFITTING

     Figure 3-3  presents  a typical engineering,  procurement and
     construction schedule for  retrofitting a  large  power plant
     for NOX, particulate, and  S02 control.  The  elapsed
     time from contract award to plant operation  is 60  months.
     The engineering time  span  is 26 months, and procurement is
     36 months.  Purchasing is  completed when the final purchase
     order  is released;  however,  inspection, expediting,  and
     traffic  are  involved until the last of  the  materials are
     delivered.  The construction span is  33 months.  This span
     allows four months for tie-in to the existing  equipment, and
     it is based  on staggering the shutdown  of the units.  No
     special unit  shutdowns would  be required;  normal plant
     shutdowns would be  utilized to  tie into  the existing
     equipment.  The time  periods shown in Figure  3-3  can vary
     considerably if other factors such as economic, political,
     or international situations become involved.
                                3-44

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3.9   REFERENCES
     1.  EPA, "Electric Utility Steam Generating Units  -
         Background Information for Proposed NO  Emission
         Standards."  EPA-450/2-78-005a, July  1978.
     2.  EPA, "Electric Utility Steam Generating Units  -
         Background Information for Proposed SO- Emission
         Standards."  EPA-450/2-78-007a, August  1978.
     3.  EPA, "Electric Utility Steam Generating Units  -
         Background Information for Proposed Particulate Matter
         Emission  Standards."  EPA-450/2-78-006a,  July  1988.
     4.  Wright, J.,  "Cost  Analysis of  Lime Based  Flue  Gas
         Desulfurization  Systems  for New  500 MW  Utility Boilers"
         PEDCo  Contract No.  68-02-2842, Assignment 25,
         January 1979.
     5.  Meeting Notes, Dr.  K. Hsiao, Pullman  Kellogg  - Meeting
         with E.J.  Campobenedetto, Babcock and Wilcox  Co.,
         Barberton, Ohio, March 19,  1979.
     6.  Meeting Notes, Dr.  K. Hsiao, Pullman  Kellogg  - meeting
         with D.J.  Frey,  Combustion  Engineering, Windsor,  CT,
         March  21,  1979,  and letter  from  D.J.  Frey of  March 26,
         1979.
      7.  Meeting Notes, Dr.  K. Hsiao, Pullman  Kellogg  - meeting
         with A.H.  Rawdon,  et al., Riley  Stoker  Corporation,
         Worcester, MA, March 20, 1979.
      8.  J.  Vatsky, "Attaining Low NO   Emissions by Combining
          low Emission Burners and Off-Stoichiometric Firing",
          Foster-Wheeler Energy Corp.  Paper presented at 70th
          annual meeting of  AIChE  November 1977.
      9.  J.  Vatsky,  "Experience  In Reducing NO  Emission on
         Operating Steam  Generators"  Foster-Wheeler Energy
          Corp., Livingston, NJ internal document.
      10. Meeting  Notes,  Dr. K.  Hsiao,  Pullman  Kellogg  - meeting
         with H.J.  Melosh,  III et al.,  Foster  Wheeler  Energy
          Corporation, Livingston, NJ, March 2, 1979.
                               3-46

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11.   C.E.  Brackett and J.A. Barsin, "The Dual Register
     Pulverized Coal Burner" paper presented to EPRI NO
                                                       X
     Control Technology Seminar, San Francisco, CA, Feb.
     1976.
12.   A.H.  Rawdon and S.A.  Johnson, "Control of NO  Emissions
                                                 .A.
     from Power Boilers" Paper presented at the annual meeting
     of the Institute of Fuel, Adelside, Australia,
     November 1974.
13.   Final Report, Retrofit Guidelines for Coal-Fired Power
     Plants, Pullman Kellogg Division, EPA Contract No.
     68-02-2619, Work Assignment No. 13, September 1979.
14.   Letter N.  Master, Pullman Kellogg to J. Copeland, EPA,
     September 19, 1979.
15.   Capital Costs of Free Standing Stacks, EPA Contract No.
     68-02-099, Vulcan Corporation, Cincinnati, Ohio,
     August 1973.
16.   Telephone conversation Dr. K. Hsiao, Pullman Kellogg with
     Mr.  Franklin Jackson, Duke Power Co., May 1, 1979.
17.   Letter John C. Buschmann, Niro Atomizer Incorporated to
     Don R. Goodwin, Office of Air Quality Planning and Standards,
     U.S.  Environmental Protection Agency, February 26, 1980.
18.   Letter from K.A. Kedtke, Leon Siegler, Inc., to
     N. Master, Pullman Kellogg, Budgetary Quote, June 29,
     1979.
19.   Letter from R.F. Crowthen, Dynatron, Inc., to N. Master,
     Pullman Kellogg, Budgetary Quote, June 26, 1979.
20.   Letter from L.N. Roten, Thermo Electron to Dr. K. Hsiao,
     Pullman Kellogg, Budgetary Quote, June 25, 1979.
                             3-47

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                           SECTION 4
           TECHNIQUES FOR ESTIMATING TOTAL RETROFIT
                  COSTS FOR EMISSION CONTROL

4.1    GENERAL

       The  cost of a power plant retrofit  is estimated  in terms
       of capital  cost  and annualized cost (!_) .  Capital cost
       represents the initial investment necessary  to install and
       commission the retrofit, and the capital costs consist of
       the  direct  and  indirect costs  that  are defined  in
       Section 3.2.1.  Annualized costs are composed of  direct
       and  fixed  charges.  Working capital,  that is the money
       required to operate  the plant  after completion  of  the
       retrofit, should also be included  in the retrofit cost.
       Specific cost  estimating examples are  given  in
       Appendices A, B,  and C.
4.2    Working Capital

       Working capital  is  the money  set  aside to operate  the
       plant  after completion of the  retrofit.  The  working
       capital  should be estimated as 25$  of  the total  annual
       operating costs (direct  and fixed).
4.3    Auxiliary Boiler Costs

       When plume reheat  is required  the capital  cost  of an
       auxiliary boiler should  be included  in  the  total  capital
       cost estimate.  Section 3.5.1 describes the techniques
       that should be used  to estimate the size  of auxiliary
       boiler needed.  The annual costs of  plume reheat steam are
       included in the  annual cost estimates of  Table  3.4.
       Table 4-1 should be used to estimate  the  capital  cost of
       auxiliary boilers.
                             4-1

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                       TABLE 4-1
     CAPITAL AND ANNUAL COSTS (2) FOR AUXILIARY2
   BOILERS GREATER THAN 250 x 106Btu/Hr HEAT INPUT
                     Capital Cost (a)

                      $/lo6 Btu/Hr Heat input capacity
Boiler                                 33,150
Pollution Control (b)                  4.755
                         total         37.885

                  Annual Boiler Costs  (a)

                     $/106 Btu/heat input (a)
Boiler Fixed Costs                     1.00
Pollution Control Fixed Costs (b)      0.14
Boiler 0 & M                           1.43
Pollution Control 0 & M(b)             0.43
                         total         3.00(a)

                      Steam Costs (a)

                     $/l()6 Btu of steam  (c)
Boiler Less Fuel Cost                  3.75
Fuel Cost (d)                          0.63
                         total         4.38  (a)

(a)  Third quarter 1979 dollars
(b)  Includes systems for 90 percent S02 removal and
     particulate emission reduction to 0.03 lb/10" Btu
(c)  Assumes 80 percent boiler efficiency
(d)  Assumes $0.50/10^ Btu fuel cost for Western power
     plants.  This value should be adjusted for fuel  costs
     for plant studied.
                          4-2

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4.4    Electrical Energy Penalty

       The total capital cost of a retrofit system  includes the
       capital cost of replacing  the generating capacity lost
       because of the electric power requirements  of the  retrofit
       systems.  This capital cost is $1,046 for each kilowat of
       capacity required by the retrofit systems. d>3,4)

       Sections 3.4 and 3.5 describe the techniques to  be used
       for estimating retrofit  electric power requirements for
       partlculate and S02 control.

4.5    Other Costs Not Estimated

       There are other capital and annualized costs  involved in
       conjunction with retrofits that are  not estimated  in this
       document.  This section identifies these cost  elements and
       provides guidance on factoring these costs into  decision
       making on best available  retrofit  technology  (BART)
       determinations.

       Other  potential  costs  that are  not  included  in  the
       estimates of this document are identified as  follows:

       1.   Cost of land
       2.   Cost  of  relocating  facilities to make  room  for the
       retrofit systems
       3.   Cost of altering existing facilities to  accommodate
       the retrofit systems
       4.   Cost of providing additional  facilities for additional
       employees such as offices, locker rooms, etc.
                               4-3

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5.  Cost of  downtime for installing retrofits
6.  Cost of  stacks

The  cost estimates  of  this  document  provide  ample
allowances  for grading,  excavating, piling,  and for
temporary construction facilities, etc.

In some cases,  additional land may need to be  purchased  to
make up for  the space  needed for retrofit  systems.  Since
the cost of  this land  can usually be  recovered when the
land is no longer needed, it is not included as a capital
cost.  It is recognized,  however, that  necessary funds
would have to be made  available for  such land purchases
and that annual costs  would result.   In the case of land
for sludge disposal, it is assumed that once  the land  is
used, it would  not  be  possible to reclaim  the  land for any
useful purpose.  More  study is needed to show that land
used for sludge disposal can be reclaimed  for  future use.

Since most power plants have not been designed for  future
large retrofit  systems,  it is likely  that most  retrofit
cases will involve  relocation of  some  facilities such  as
shops,  offices, or coal storage and handling  systems.
These capital costs will also cause an increase in  annual
costs.

Types of alterations that might be required to accommodate
retrofit systems  are  the cost  of  relining  stacks  to
compensate  for more  corrosive  gas  conditions or for
reinforcing existing ductwork to  compensate  for changed
flue gas pressure conditions, or  costs for major changes
to structures to accommodate NOY combustion modifi-
                              A
cations.  The costs of nominal alterations in  conjunction
                         4-4

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with NOX combustion modifications is included in  the
cost  estimates of  this document.   Based  on boiler
manufacturer's  advice, it may also be necessary to modify
boiler  pressure parts to control  steam  conditions to
specifications.   These costs are site-specific and are not
estimated in this document.

The cost of downtime  is  also significant.   The  costs of
this  document  assume that  no  additional  downtime is
required for retrofitting.  The way downtime  is avoided is
by making all necessary changes to the existing system and
by tieing in the retrofit systems during normal outages or
during unscheduled outages attributable  to factors  other
than retrofitting.  As shown by Figure 3-8, these types of
changes can be  made during a 5-year period.   If  downtime
is necessary, the following factors should be taken into
account in assessing  costs.

1.  The cost of purchased power.  Usually purchased  power
costs more than the cost  of  generating  power within the
system.  However, at times  the added  cost  of  purchased
power is reduced if the  purchasing power  system sells a
like  amount at the  same price  in  conjunction with an
exchange agreement.

2.  The cost of power generation and distribution.   Even
if it  is  not necessary to purchase  power from another
system, downtime can  involve significant additional costs.
Downtime  may make it necessary  for a  power system to
generate power  at a  less efficient plant or at a  plant
firing more costly fuel.  Power transmission losses  also
need to be considered.  For the plants of Appendices A, B,
and C, it is most likely that any downtime  that would make
it necessary to  generate power elsewhere would involve
significant additional fuel costs.
                          4-5

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       3.  Loss of Productivity.  When a steam generator is down,
       some  labor,  supplies,  and services costs  continue.
       Although these costs are small  in  comparison to other
       downtime costs, they should  be considered  in  sufficient
       depth to classify them in their proper perspective.

       Another cost that is not estimated in this  document is the
       cost  of transporting sludge from  the liquor  treatment
       system  to the disposal site.   This cost is  estimated at $2
       per ton per mile.  Such costs are not estimated because it
       is  not certain how far  the  sludge would  have to  be
       transported.
4.6    Escalation
       The  costs  of  this  document are based on  September 1979
       dollars.   Section 3.8 presents  data on  schedules  for
       retrofitting which  can be used  in conjunction  with
       economic data not given in  this document to  estimate the
       effect of escalation  on capital costs.
                              4-6

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4.7   REFERENCES
        Wright, J.,  "Cost Analysis of Lime Based  Flue Gas
        Desulfurization  Systems for New 500 MW  Utility Boilers",
        PEDCo Contract No.   68-02-2842,  Assignment 25, January
        1979.
        Impact Analysis of Selected Control Levels  for New
        Industrial Boilers, Preliminary Draft, Office  of Air
        Quality Planning and Standards, U.  S. Environmental
        Protection Agency, Research Triangle Park, North Carolina
        June 1980.
        EPA,  "Electric Utility Steam Generating Units -
        Background Information for Proposed SC^ Emission
        Standards".  EPA-450/2-78-00?a, August  1978.
        EPA,  "Electric Utility Steam Generating Units -
        Background Information  for  Proposed  Particulate Matter,
        Emission Standards".  EPA-450/2-78-006a, July 1978.
                              4-7

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                       APPENDIX A






EXAMPLES FOR RETROFITTING THE FOUR  CORNERS  POWER  STATION
                            A-l

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                            CONTENTS
SECTION                                                     PAGE

CONTENTS                                                    A-ii
TABLES                                                      A-iv
FIGURES                                                     A-vi

A-1.0  GENERAL                                              A-l

       A-l.l  Retrofit Alternatives                         A-l
       A-l.2  Plant Characteristics                         A-ll
       A-l.3  Existing Facility Relocations                 A-13
       A-l.4  Flue Gas Ducting Requirements                 A-14

A-2.0  BACKGROUND DATA                                      A-16

       A-2.1  Plant Description                             A-16
       A-2.2  Steam Generator Description                   A-17
       A-2.3  Existing NOX Control                          A-19
       A-2.4  Existing Particulate  Control                 A-20
       A-2.5  Existing S02 Control                          A-20

A-3.0  PLANT SURVEY FORM                                    A-21

       A-3-1  Company and Plant Information                 A-21
       A-3.2  Plant Data                                    A-21
       A-3-3  Boiler Data                                   A-22
       A-3.4  Fuel Data                                     A-28
       A-3-5  Atmospheric Emissions                         A-29
       A-3-6  Particulate Removal                           A-30
       A-3.7  Scrubber Train Specifications                 A-31
       A-3-8  Calcining and/or Slaking Facilities           A-33
       A-3.9  Disposal of Spent Liquor                      A-33
                               A-11

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                            CONTENTS
SECTION                                                      PAGE

       A-3.10 Cost Data                                      A-35
       A-3-11 Major Problem Areas                            A-36
       A-3-12 Methods of Measuring Emissions                 A-39

A-4.0  RETROFIT DESCRIPTION                                  A-40

       A-4.1  NOX Emission Control                           A-40
       A-4.2  Particulate Emission Control                   A-46
       A-4.3  S02 Emission Control                           A-46

                                                             A- ^0
A-5.0  RETROFIT COSTS

A-6.0  REFERENCES                                            A-53
                               A-iii

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                             TABLES
Table                                                       Page

A-l   Retrofit for NOX Reduction                            A-41
A-2   Retrofit Data for Electrostatic Precipitators and
       Baghouses - Units 1 and 2                            A-47
A-3   Retrofit Data for Electrostatic Precipitators and
       Baghouses - Unit 3                                   A-48
A-4   Retrofit Data for Electrostatic Precipitators and
       Baghouses - Units 4 and 5                            A-49
A-S   Capital Investment Costs for Retrofitting
      the Four Corners Power Plant                          A-51
A-6   Annual Costs for Retrofitting the Four Corners
       Power Plant                                          A-52
                                 A-iv

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                             FIGURES
FIGURE                                                       PAGE

A-l   Addition of wet SC>2 scrubbing modules.                 A-2
A-2   Arrangement of wet SC>2 scrubbing modules  for
       Units 1, 2, and 3.                                    A-3
A-3   Addition of wet S02 scrubbing and particulate
       emission control modules.                             A-4
A-4   Arrangement of cold side ESP's and wet SO^
       scrubbing modules for Units 1, 2, and 3-              A-5
A-5   Addition of dry 862 scrubbing modules with
       baghouses.                                            A-7
A-6   Arrangement of dry S02 scrubbing and baghouse
       modules for Units 1, 2, and 3.                        A-8
A-7   Arrangement of wet S02 scrubbing modules  for
       Units 4 and 5.                                        A-9
A-8   Arrangement of baghouse and wet S02 scrubbing
       modules for Units 4 and 5.                            A-10
A-9   Arrangement of semi-dry SC>2 scrubbing (spray-
       dryer) and baghouse modules for Units 4  and 5.        A-12
A-10  General plot plan of the Four-Corners power station.   A-18
A-11  Retrofit arrangement of OFA and CA ports  for Units
       1 and 2 - Riley-Stoker boilers.                       A-43
A-12  Retrofit arrangement of OFA and CA ports  for
       Unit 3 - Foster Wheeler boiler.                       A-44
A-13  Retrofit for Units 4 and 5 with 54 sets of Dual
       Register (B&W) burners and compartmentized windbox.   A-45
                               A-v

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                           SECTION A-l
                            GENERAL
A-l.l  RETROFIT ALTERNATIVES

       Pour alternatives  for  retrofitting each boiler at the Pour
       Corners Power  Plant  were considered  in this appendix  to
       demonstrate  the  use  of the techniques described in Section 3
       of the report.   All  alternatives include maximum NOX
       control and  the  installation of opacity, S02j NOX
       emission monitoring  systems.  Since some of the aspects  of
       these alternatives differ for the boilers to which  they
       apply,  they have  been grouped  by unit numbers  for the
       discussion.  Alternatives for the Unit 1,2, and 3 boilers
       are as follows:

       Alternative  1  -  Add  wet S02 scrubbing to each unit to
       achieve 90%  S02  removal.  The existing venturi
       scrubbers are  retained to control particulate emissions  to
       a level of 21  ng/J heat input (0.05 lbs/106 Btu).
       Figures  A-l and A-2  show the  general arrangement  plot
       plans with the addition of the S02 scrubbing modules.

       Alternative  2  -  Remove the  existing  venturi particulate
       scrubbers and  add  wet  S02 scrubbing to achieve 90%
       S02 removal  for  each unit.  Also, add high-efficiency,
       cold-side electrostatic precipitators (ESP's) for control
       of particulate emissions  to a level of 13 ng/J heat  input
       (0.03 lbs/106  Btu).  Figures A-3 and A-4 show the
       general arrangement  plot  plan with the added S02
       scrubbing modules  and  cold-side ESP's.

       Alternative  2a - The retrofit for  particulate removal  in
       Alternative 2a  is  to the  same  emission level as for
       Alternative 2,  but  baghouses  have been  used  for  cost
       comparisons  with Alternative 3.  The wet S02 scrubbing
                               A-l

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in this case  is  based on 70% S02 removal for  cost
comparison with  semi-dry scrubbing of Alternative  3.

Alternative 3 -  The  existing venturi particulate  scrubbers
are removed  in  this case and  semi-dry  (spray  drying)
S02 scrubbing is added for 70% S02 removal.
Baghouses  are used as dry collectors,  for control of
particulate  emissions  to  a level of  13  ng/J heat input
(0.03  lbs/106 Btu) .  Figures A-5 and A-6 show the
general  arrangement using the  dry scrubb ing/baghouse
modules .

The three alternatives  considered  as examples  for
retrofitting the Units 4 and 5 boilers are:
Alternative 1  -  Add wet S02 scrubbing to achieve
S02 removal and  retain the existing ESP and
particulate removal for control to an emission level  of 21
ng/J heat input  (0.05 lb/106 Btu).  Figures A-l and
A-7 show the  general  arrangement of  the  plant  with the
added S02 scrubbing modules.

Alternative 2 - This option  adds  baghouses  plus wet
S02 scrubbing  for  90% S02 removal, and it retains
the existing ESP's and particulate removal  for control to
an emission level  of 13 ng/J heat input (0.03 lbs/10^
Btu).  Figures  A-3  and  A-8 show  the  plant's  general
arrangement with the added S02 scrubbing modules  and
baghouses .

Alternative 2a - Alternative 2a includes the same retrofit
for particulate  removal emission levels as  Alternative 2,
but baghouses have  been used  for  cost comparison  with
Alternative 3. The S02 scrubbing is based on 70%
S02 removal for  cost comparison with semi-dry
scrubbing in Alternative 3.
                        A-6

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       Alternative  3  -  Dry  S02 scrubbing (spray drying) is
       added for  70%  SC>2  removal.  Baghouses are used for dry
       collectors and,  combined with the existing ESP's,  provide
       for particulate  removal to a level  of  13 ng/J heat  input
       (0.03 lbs/106  Btu).  Figures A-5 and A-9 show the
       general arrangement  with the added dry scrubbing modules.
       Section A-6  describes  the techniques used for estimating
       costs.

A-1.2  PLANT CHARACTERISTICS

       The characteristics  of the plant site,  existing equipment,
       and the space  requirements  for the  retrofit example  are
       shown in the following list (!_) :

       A.   The station  is located on a 1000 acre tract of land.
       B.    Particulate  removal  for Units 1,2,  and  3 is
           accomplished using two venturi scrubbers per unit.
       C.    Units  4  and  5  have  cold  side  precipitators  for
           particulate  removal.
       D.   Each boiler  for  Units 1,2 and 3 is  provided with two,
           forced draft (FD); three, primary-air (PA); and two,
           induced-draft  (ID) fans.
       E.   Each boiler  for  Units 4 and 5 is provided with  four,
           forced-draft (FD)  and two primary-air (PA) fans.
       F.   The number of  SC>2  scrubbing modules  is based on
           the total  calculated flue gas rate from each boiler.
       G.   One SC>2  scrubbing  module is provided as a common
           spare  for  each group of modules per  boiler.
       H.   One flue gas reheater is required per wet S02
           scrubbing  module for 90% 862 removal.
       I.   One flue  gas  booster  fan is required per scrubbing
           module.
       J.   The individual  scrubbing modules are provided with
           dampers.  This provision allows the  individual modules
           to  be  isolated for maintenance.
                               A-ll

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       K.   Retrofit equipment tie-in  to  the power plant  is  based
           on completion during a normal  power plant maintenance
           turn-around 'of 3 to 6 weeks.
       L.   An emergency bypass is provided around each S02
           scrubbing system to allow  emergency operation  of  the
           boiler  in  the  event  of  a major  FGD malfunction.
           Bypassing of the particulate  control equipment  is  not
           provided.

A-1.3   EXISTING FACILITY RELOCATIONS

       Major revamp work that  would  be  required to install  the
       equipment needed for S02 and particulate control
       includes relocation  of some  existing buildings and/or
       systems.  The requirements  for the alternatives being
       considered are:

       Alternative 1 - The following  equipment relocation  would
       be  necessary to allow  for  the  space  requirements  of  the
       wet S02  scrubbing systems.

       A.   For  Units 1,2, and 3, relocation of all  buildings
           situated east and  north of the unit is necessary.
       B.   For  Units  1,2, and  3, the  scrubbers are  located  on
           structures built  over the  cooling water  discharge
           canal.
       C.   For  Units 4 and 5,  no  major  equipment relocation  is
           required.

       Alternative 2 - All equipment  relocation considerations of
       alternative 1 also apply to this  alternative.   In addition
       the following items must be relocated.

       A.   For  Units  1,2, and  3, relocation is needed  for  the
           ready to use coal  pile and  some of  the coal  conveying
           equipment.
                              A-13

-------
      B. For Units  4 and 5, relocation  of the blend coal pile
         is required,  to  provide  space  for installing the
         baghouses.

      Alternative  3  -  Equipment relocation  requirements of
      Alternative  1  also apply to this alternative.   In
      addition,  the following items  must  be relocated.

      A. For Units  1,2, and 3,  relocation of the ready to use
         coal pile  and  some of the coal  conveying equipment is
         required.
      B. For Units  4  and 5, relocation  of the blend coal pile
         is required,  to  provide  space  for installing the
         baghouses  and  booster fans.

A-1.4  FLUE GAS DUCTING  REQUIREMENTS

      Bypass duct and  dampers  are provided to enable the flue
      gas to bypass the SC^ scrubbing system  completely
      under  emergency conditions.   For  all five  units, the
      bypass duct is upstream of the S02  scrubbing system.
      Emergency bypassing  of  particulate  control equipment is
      not  considered.   Bypass duct locations  for  the three
      alternatives are indicated below:

      Alternative 1

         Units  1,2  and 3.-  The bypass duct  is  taken from  the
         plenum located between the ID fan and the booster  fan.
         Figure A-2 indicates this relationship.

         Units 4 and 5.- The bypass duct is taken from the inlet
         duct just between the  existing ESP and  the booster fan.
         See  Figure  A-7  for  a  graphic  indication  of this
         ducting.
                             A-14

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Alternative  2

Units 1,2 and  3*-  Bypass duct is  taken from the plenum
located between  the  scrubber and the booster fan.   Figure
A-4 shows the  elevation view for  the  cold side ESP  and
S02 scrubbing  modules.

Units 4 and  5.-  Bypass  duct is taken after the baghouse,
just before  the  scrubber.  Figure A-8 shows the elevation
view for the baghouse  and SC>2 scrubbing modules.

Alternative  2a

The bypass duct  is the  same as for  Alternative 2.  This
duct can also  be used  during normal  operation to divert
about 22% of  the  total flue gas  that  does not require
treatment, since the module removes 90% S02, and  this
alternate requires only  70% SC>2 removal.  The bypass
duct also provides the  flue gas requirements for reheat.

Alternative  3

The bypass duct  is taken just ahead  of  the spray dryer,
and  it ties  into the  duct to  the baghouses.   This
location of  the  emergency bypass permits operation  of  the
baghouse for particulate control  when  a spray dryer  is
out of service.  Figure A-6 and A-9 show the elevation
views for the dry scrubbing and  baghouse modules,  and
they indicate  this relationship.
                      A-15

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                          SECTION  A-2
                        BACKGROUND DATA
A-2.1   PLANT  DESCRIPTION (_1_,_2)

       The Four Corners Power  Plant consists  of  five  thermo-
       electric generation  units that develop a  total plant
       capacity  of 2085 MW(net)  and 2181 MW(gross).  The capacity
       for each  boiler is:
Unit No.
Gross MW
Net MW
1
190
175
2
190
175
3
245
225
4
778
755
5
778
755
       Units 1,  2, and 3 are owned and operated by Arizona Public
       Service (APS).  Units 4  and  5 are jointly owned  by six
       electric  utilities and operated by APS.  The participating
       utilities are Southern California Edison Co.,  48$;  APS
            Public Service of New Mexico 13%;  Salt River Project
            Tucson Gas and Electric Co., 7%;  and El Paso Electric
       Co.,  1%.

       All  five units are  pulverized-coal-fired,  dry-bottom
       boilers,  where  about 2Q%  of  the  ash in  the coal  is
       retained  as bottom ash. The remaining  ash is entrained  in
       the flue  gas  and  is collected by using either  a Venturi
       Wet  Scrubber  System  or  an Electrostatic Precipitator
       (ESP).  There  are four flue gas stacks.  Units 1  and 2 are
       served by a common stack that is 250  feet high and  has  an
       18.5-foot I.D.  The stack for Unit 3  is also 250  ft high,
       but it has a  15-foot I.D.   The two stacks for Units 4 and
       5 are 300 feet high and have 28.5-foot I.D's.
                              A-16

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       Units  1  and  2 each have  two,  horizonta 1-shaft
       regenerative, Ljungstrom  air preheaters.   Unit 3 has the
       same preheaters as  Units  1 and 2 but with  vertical  shafts.
       Units  4  and  5 each have two, horizontal-shaft,
       regenerative,  Ljungstrom air preheaters, and they each
       have a  tubular air  preheater.

       The bottom  ash is  conveyed hydraulically to dewatering
       bins  and  then trucked either  to  the ash disposal  pond
       (bottom ash from Units 1, 2, and  3)  or to the coal mine
       (bottom  ash from  Units 4 and  5).   The  water after
       separation  (decanted water)  is returned to Morgan Lake.

       Two, 100-foot I.D.   thickeners serve Units 1,  2,  and 3 for
       clarifying  spent ash liquor.  The solids concentration of
       the thickener underflow is about 40 wt%.  The  plant has a
       brine concentrator  to treat  the water from the ash  pond.

       Circulating, cooling-water discharge canal is located
       between Units 3 and  4.  The  Instrument and Plant  Air
       Compressor Building  is  located between  Units  2  and 3-
       Units 4 and 5 have  nine coal mills per unit,  plus a spare
       one.  Units 1, 2, and 3 have three  coal  mills per unit,
       working at  full capacity, and they have no spares.  Figure
       A-10 shows  a general plot plan arrangement  for the Four
       Corners power station.

A-2.2  STEAM GENERATOR DESCRIPTION

       Units 1 and 2 have  a total generating  capacity of 350 MW
       (net)  and  380 MW  (gross).   Each unit consists  of a
       balanced-draft, Riley-Stoker (R-S),  175 MW  (net),  190 MW
       (gross) boiler.  Both units  went into operation in  1963-
                              A-17

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       Unit 3 uses a balanced-draft, Foster-Wheeler (F-W),  225 MW
       (net), 245 MW (gross)  boiler.  Unit 3 started operating in
       1964.

       Units 4 and 5 have a total  generating capacity of 1510 MW
       (net)  and 1556 MW  (gross).   Each unit  consists of a
       pressurized, Babcock & Wilcox (B&W), 755 MW (net), 778 MW
       (gross) boiler. Unit 4 was  started  in  1969 and Unit 5 in
       1970.  Fireboxes for the  five boilers were designed prior
       to  1970.

       For Units  1,2,  and 3, there are  two  forced-draft (FD),
       three primary-air (PA) and  two induced-draft (ID)  fans per
       unit.   Units 4 and 5  have four FD and two PA  fans per
       unit.  Paddle-type fans are used for the units.

A-2.3   EXISTING NOX CONTROL

       There are  five boilers at the Four  Corners Station.   Units
       1  and 2  use Riley Stoker boilers  that  are of  the
       horizontal, single-wall-fired  type.   The burners are
       arranged  in six vertical  columns  with three burners on
       each column.  Retrofit work has  been performed for NOX
       reduction  through burner  modifications.  The retrofit work
       was developed, and installed by APS  using a KVB spoiler
       design  (3.).  There are  no data avaialble to  show the
       effectiveness and results of the retrofit.  Unit 3 has a
       Foster Wheeler, horizontal, single-wall-fired boiler.  The
       burners are arranged  in  four vertical  columns with five
       burners in  each column.  Plant data show that no  retrofit
       work for NOX reduction purposes  has been done on
       Unit  3.   Units 4 and  5  are B&W boilers of  the
       opposed-wall-fired type.   The  burners on each  unit are
       arranged in six vertical columns  on  each opposite wall.
                             A-19

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      The  burners  are the  B & W's,  high-intensity-ce11 ,
      turbulence burners.   All  burners are contained in a single
      windbox.  Units  4 and  5 were installed  originally  with
      flue-gas (PG) recirculation  systems; however,  the FG
      recirculation system has  been  taken out because of  severe
      mechanical difficulties  associated with the fans.

A-2.4  EXISTING PARTICIPATE CONTROL  (2)

      Boilers  1,  2,  and 3 each use two  venturi,  wet-scrubber
      systems for collecting  flyash  from the  flue  gas.  The
      venturi  scrubber systems remove about  98% of  the  flyash
      from  the flue gas. Boilers  4 and 5 each are equipped  with
      two cold-side ESP's manufactured  by  Research Cottrell.
      These ESP's collect about 97%  of the flyash from the  flue
      gas.  The total existing ESP collection area per boiler  is
      373,000  ft2.

A-2.5  EXISTING S02 CONTROL

      S02 emission control is  accomplished by using low
      sulfur  subbituminous coal as fuel.
                              A-20

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                             SECTION A-3
                          PLANT SURVEY FORM


A-3.1  COMPANY AND PLANT INFORMATION (J.,.2)

       1. Company Name:  Arizona Public Service Company

       2. Main Office:   P.O.  Box 21666, Phoenix Arizona  85036

       3. Plant Manager:  Mr.  B.E.  Haelbig

       4. Plant Name:    Four Corners Power Plant

       5. Plant Location:  Fruitland, San Juan County, New Mexico

       6. Person to Contact For Further Information:  Mr. J. Weiss

       7. Position:  Senior Environmental Eng.  Special Projects

       8. Telephone Number:  (602) 271-2292

       9. Date Information Gathered:  May 8 - May 10, 1979

      10. Participants In Meeting                     Affiliation

          D. Campbell                     APS/Acting Manager of Eng,
                                            Four Corners Plant
          J. Weiss                        APS/Senior Environmental
                                            Eng. Special Projects
          N. Gonzalez                     Pullman Kellogg
          R. Redman                       Pullman Kellogg
          R. Roberts                      Pullman Kellogg

A-3.2  PLANT DATA (APPLIES TO ALL BOILERS AT THE PLANT)


                                         BOILER NO.

                                     12345
     Capacity, MW, Net,             175  175  225  755  755

     Service (Base,Peak)            BASE BASE BASE BASE BASE

     FGD System Used?                NO   NO   NO   NO   NO
                             A-21

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A-3.3  BOILER DATA

       1. Maximum Continuous Heat Input (MM Btu/Hr):
          Unit 1 or 2       Unit 3        Unit 4 or 5
              1760           2230         7040 (assuming 755 MW
                                                net peak)

       2. Maximum Continuous Generating Capacity:
          Unit           1    2    3    4    5
          Gross(MW)     190  190  245  778  778
          Net (MW)      175  175  225  755  755

      2a. Maximum Heat Input (MM Btu/Hr):

          Unit 1 or 2       Unit 3        Unit 4 or 5
          1006 Btu/K WHR     2230         7460 (assuming 800 MW
                                                net peak)

       3. Flue Gas Temperature to Stack:  120F(Units  1,2,3);
          220F(Units 4,5)
       4. Maximum Continuous Flue Gas Rate  to Stack:

          Unit 1 or 2       640,000 ACFM at  120F
          Unit 3            800,000 ACFM at  120F
          Unit 4 or 5    3,000,000 ACFM at  220F

          These values are  typical continuous flue gas  flows at
          full load.  Flows can vary +_ 10$, depending  on excess
          air, coal composition, and water  injection  rate.

       5. Flue Gas Analysis:

          Flue Gas Component       Units  1-2-3      Units  4-5
                5802                  4.3-7.0       3.8-5-7
                %C02                 12 -  14.8      13.6 -  15.3
                fN2                80.6-81.5     80.6-81.5
            (and inerts)
                                 A-22

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     6. Flue Gas Recirculation For NOX Control3:

     7. Boiler Manufacturer: R-S (Units 1,2);  FW (3); B&W (4,5)

     8. Years Boilers Placed In Service: 1963  (1,2); 1964 (3)
                                          1969 (4); 1970 (5)

     9. Boiler Service (Base Load, Peak, etc.):  Base
    9a. Wet Bottom 	-	 Dry Bottom   X

                                Units:  1/2	 345
   10.  Stack Height Above Grade (Ft):  250  250  300  300
   lOa. Stack Diameter5 (Ft):           17.7   14  28.5  28.5

   lOb. Velocity Of Gas (Exit):

                           Stack 1-2  Stack 3  Stack 4  Stack 5
   Flue Gas Velocity (fps)
    Leaving Stack            43-86       87       78      78
   At Full Load (Net)      (175-350 MW)(225 MW) (755 MW) (755 MW)

   lOc. Exit Gas Temperature (F):

                           115-122     122-130  205-245  205-245

   lOd. Number Of Liners/Boiler: 1 for each stack
aFG recirculation originally installed for units 4 & 5. Later
  was taken out due to severe mechanical difficulties.
^Stack diameter at top. For units 1,2, and 3 includes liner.

                              A-23

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     11.   Boiler Operations  (Hours/Year-1978):

          Unit  1      Unit  2      Unit  3      Unit  4      Unit  5
           6994        7933       7296        5300       4874

     Ha.  Boiler Operations  (Hours/Year    full  load):  N/A

     12.   Boiler Capacity  Factora:   (1978):
                                      Units
                        12345
                      67.60    83.87    72.55    49.62    48.35

     13.   Boiler Operating  Pressure  (psig):
                                      Units
                           1  & 2         3          4  & 5
                           1925       2125        3590

     14.   Boiler Superheat  Heat Temperature  (F):

                           1005       1005        1000

     I4a.  Boiler Reheat Temperature  (F):

                           1005       1005        1000

     I4b.  Economizer B.F.W.  Outlet Temperature (F):

                            510        560         650

     15.   Ratio Of Fly Ash/Bottom Ash = 80/20
a Defined as:
                     KWH GENERATED IN YEAR
     (Net) Max Cont.  Generating Capacity in KW x 8760 HR/YR

                              A-24

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16.  Burners:


     Type
     Manufacturer

     No.Per Unit
     Coal (#/Hr/
      Burner)
     Primary Air
      (% of Total)
     Secondary Air
      (% of Total)
     Total Excess
      Air
                  Units
1&2
Flair
APS/
Design
18
3
Flair
Foster/
Wheeler
18
4&5
Cell
Babco
Wile
18 ce
                                                      54 burner
                                                       nozzles
10,280
15%
85%
2Q%
14,450
10$
90%
2Q%
50,000
N/A
N/A
18%
17.  Fans ( FD & ID) :
     Forced Draft
      Type
      Manufacturer

     Induced Draft
      Type
      Manufacturer
     Primary Air
      Type
      Manufacturer
     No. Per Unit
      F.D.
      I.D.
      P.A.
(FD)
 Air  Foil
 Green Fuel
 Economizer Co.
(ID)
 Paddle Wheel
 American Std.
(PA)
 Radial
 Buffalo Forge
  Company
Air Foil
Westinghouse/
 Sturtevant

Paddle Wheel
American Std.

Radial
Westinghouse/
 Sturtevant
Air Foil
Westinghouse/
 Sturtevant

   N/A
   N/A

Air Foil
Clarage Fan
2
2
3
2
2
3
4
N/A
2
                               A-25

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                                     Units
                      1&2
                                4&5
     Rating  (CFM each)
      F.D.            258,000
      I.D.            387,000
      P.A.             68,250
              292,000         535,000
              435,000           N/A
               75,920 (calc.) 218,000
     Differential Pressure (inches of water)
      F.D.
      I.D.
      P.A.
11.6
16.0
24.5
10.25           23.7
12.04           N/A
24.5 (approx)   37
18.   Windbox
     Compartment      Single
     Controlled       Register
     Mode of control  Manual
               Single
               Register
               Manual
                Single
                Register
                Manual
19.  Steam Temperature Control (Superheated & Reheated):
     Attemporator
      Cap. Ib/hr
73,000
40,000
225,000
20.  Pressure Profile Throughout The Unit:
     Units 1-2-3
     Balanced Draft
           Unit 4-5
           Pressurized
                               A-26

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21.  Air Preheater:
                                     Units
     Type

     No. Per Unit
     Flue gas ATe
     Air ATe
     Design flow:
      Gas Mlb/Hr
      Air Mlb/Hr
     DesignA P
     (in.  of H20)
     Flue gas inlet
      Temp F
     Air preheater
      outlet temp.
     Flue gas pre-
      outlet temp.
 1&2

Ljungstrom
Horizontal
    2
 434F
 562F
Ljungstrom
Vertical
    2
 418F
 516F
   4&5

.  Ljungstrom/
Tubular/Horiz.
      2/1
414F
485F
1,790
1,462
3.40
720
642F
286F
2,285
1,980
2.70
720
596F
302F
7,100
6,290
3.2
655
565F
24lF
22.  Number Of Sections Of Air  Ducts:
22a. Size Of Air Ducts:

     Each of the air ducts on  Units  1  and  2 has  a  cross  sectional
     area equal to approximately 120  square feet.   Each of the
     air ducts  on Unit 3 has a  cross sectional  area  equal to
     approximately 191.8  square feet.   Unit 4&5  not  available.
     e These figures correspond  to  normal  operating
     conditions at rated  full  load.
                              A-27

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       23.   Number Of Flue Gas Ducts:
                                           Units
                             1&2              3          4&5
       23a.  Size Of Flue Gas Ducts:

            Each  of the flue  gas ducts  on  Units  1 and  2  has  a
            cross  sectional area  equal to approximately 132 square
            feet.   Each of the flue gas ducts on Unit 3 has a  cross
            sectional area equal to approximately 186.4 square
            feet.   Unit 4&5 not available.
A-3.4  FUEL  DATA
       1.   Coal  Analysis  (as received) (%):  Max.   Min.   Avg.
           S                               ___    ___    o.7
           Ash                             	        22

       2.   Total Ultimate Analysis (Wt5&)

           Component                           Average
           Ash                                22
           S                                    .7
           Moisture                           10.8
           Oxygen                             10.4
           Hydrogen                            3.76
           Nitrogen                            0.84
           Carbon                             51.4
           Btu/lb                             8800
                              A-28

-------
A-3.5   ATMOSPHERIC  EMISSIONS

       1.   Applicable Emission Regulations:  Particulates   S00   NO
                                               " - --         ' ~ "_   " ~5

           a)  Current requirements           (1,2,3)  0.05    -   0.7
                                            (4,5)   0.50       FED
              Maximum allowable emissions
              Lb/MM Btu  input to boiler

           b)  Future requirements            For Dec.1982  0.53  0.5
                                            (4,5)   0.05

       2.   Plant  Program For Particulates:

           Units  1,2 and 3 have a total of six Chemico venturi  wet
           scrubbers, each  scrubber module handling  400,000  -
           500,000  ACFM @ 340F.

           Units 4  and 5 have  Research  Cottrell electrostatic
           precipitators.  The  flue gas flow  from Unit 4 or 5  to
           the corresponding precipitator is 3.1 x 10^ ACFM @
           250F.

       3.   Plant  Program For S02 Reduction:  Use of low sulfur
                                                coal

       4.   Plant  Program For NOX Reduction:  Modified burners
           in  Units 1 & 2. (KVB NOX spoilers installed).
                              A-29

-------
A-3.6  PARTICULATE REMOVAL

       1.  Type

           Type
           Manufacturer
    Units 1-2-3
 Venturi Wet Scrubber
      Chemico
           Efficiency %
           design/actual        99.6/99.6
           Specific collection
           area                    N/A
           Total collection3
           area                    N/A
          Units 4-5
          E.S.P.
          Research
           Cottrell

          97/97

          138 Ft2/1000

      373,000 Ft2/BLR
           Design basis, sulfur of fuel:  0.1%
           Emission rate Lb/MM Btu (under normal operation
           conditions):
           Unit
           S02
           NOX
           Total
           particulates
1 or 2
               or 5
0.9-1.5
0.58-0.7
0.9-1.5
0.8-1.4
l.U-1.9
0.7-1.1
0.02-0.05
0.02-0.05
0.25-0.5
       2.  Solids Collection System:

           Present operating condition:15
           At maximum capacity:       Yes)(    No
  a For each boiler there are two cold  side ESP's  with  each
   having 16 electrical  sections for  a  total  of  32 electrical
   sections per boiler.
  b Bottom ash is hydraulic  conveyed  to  dewatering bins &  then
   trucked to coal mine  (for units  4&5).  The  dewatered  bottom  ash
   is trucked to ash disposal pond  and  used to  sand blast.  Fly ash
   is pneumatically conveyed and sent to  storage silo  and  then
   trucked to the coal mines.
                                 A-30

-------
       The  inlet fly ash loading range is  12-20 Ib/lO  Btu
       The  inlet bottom ash loading range  is  3-5 lb/10^ Btu

       The  inlet flue  gas  temperature is 280-350F for Units
       1-2-3,  and 230-280F for Units 4-5.

A-3.7   SCRUBBER TRAIN SPECIFICATIONS (for  venturi scrubbers)

       1. Scrubber:
          Type
 Chemco wet venturi
          Liquid/gas ratio 16.9 gpm/1000  ACFM  (Units 1,2 and 3)
         Gas velocity
Information not  available (Varies to
maintain pressure  differential.
          Materials of
          construction
Top gas inlet  -  unlined carbon steel
wetted center;  316  stainless steel
high  gas velocity  throat;  316
stainless  steel intermediate plumb
carbon  steel  lined with  polyester
glass reinforced resin.   All other
scrubber shell sections and  supports
are coated with  polyester glass resin.
Internal mist  eliminators  are  of
polypropylene  glass reinforced.
                             A-31

-------
    Internals:
     Type
     No.  of stages
Internal mist eliminator
6 pass arrangement
    Type and size of
      packing material
Slats and spacers in a 30' OD x 13' ID
 and 3V OD x 15' ID
    Packing thickness
     per stage:           2 9/16"

    Material of construction:

     Packing - polypropylene glass reinforced
     Supports - 316 stainless steel/fiberglass

2.  Clean Water Tray (at top of scrubber): N/A

3.  Mist Eliminator (M.E.)
    Type
    No. of passes
    Space between vanes
    Angle of vanes
    Size of M.E.
    Distance between top of liquid
     inlet and bottom of M.E.

    Position
    Materials
    Method of cleaning
               Baffle
               6
               3"
               55
               2'3 3/8"

               78' (Units 1&2)
               85' (Unit 3)
               Vertical gas  flow
                Horizontal blade
                eliminators
               Polypropylene
                Fiberglass reinforced
               Annual  overhaul  and
                periodic sprays
                             A-32

-------
A-3.8  CALCINING AND/OR SLAKING FACILITIES

       One  lime slaker, having  an  average on-line  capacity of
       0.42  tons per hour, serves the scrubber systems on Units
       1-2-3.

       1.   Source Of Water For Slurry Make-up  Or  Slaking Tank:

           Morgan  Lake is the  source of make-up  water  to  the
           slaking  tank.

A-3.9  DISPOSAL OF  SPENT LIQUOR

       1.   Transporting:

           Fly ash  from Units 1-2-3  is  slurried  from  the
           thickener to the ash ponds at the rate  of 18  tons/hr
           for  Unit 1 and 2 and 20 tons/hr for  Unit 3.

           Fly  ash  from Units 4-5 is trucked to  the  Navaj o Mine
           pit  at the rate of 71 tons/hr for each unit.

           There is no  scrubber sludge to dispose of.

       2.   Oxidizer:

           This section is not applicable to the systems at the
           Four Corners Power Plant.
                             A-33

-------
    Source of water and pressure:       Morgan Lake @ 60-80 PSI
    Flow rate during cleaning:          Not available
    Frequency and duration of cleaning: Not available

4.  Reheater:

    Type:  Steam coils SS-316-L Units 1-2-3 (No longer in
    operation)

5.  Scrubber Pressure Drop Data (inches of water):

                                        Units 1-2-3
    Particulate scrubber                25" W.G.
    Mist eliminator                     2" W.G.
    Reheater                            Removed
    Ductwork                            Not available

    Total FGD system                    Not applicable
    Total part system                   28" W.G.

6.  Fresh Water Make-up Flow Rates:

    The Four Corners Power Plant has no S02 scrubbers, but
    it does have particulate scrubbers on Units 1-2-3.  Units 4
    and 5 have no scrubbers.  Steam and cooling water blowdown
    are not available as make-up to the scrubber  systems  on
    Units 1-2-3.  Morgan Lake provides the make-up water  for
    the particulate scrubbing systems on Units 1-2-3.

7.  Bypass System: None
                             A-34

-------
        3.   Clarifiers  (thickeners):

            Number:   2
            Dimensions:   100 Ft.  I.D.
            Concentration  of solids in underflow:  40 wt/6 solids
            Amount  of flocculant:  None

        4.   Rotary Vacuum  Filter:  N/A

        5.   Sludge  Fixation:  N/A

A-3.10  COST DATA

        The original estimated cost  for the  installation  of
        particulate  scrubbers on Units 1-2-3 was $6,900,000.  The
        final  installed  cost, including the costs of replacement
        of  the recycle  pump  and installation  of the lime feed
        system was  $27,780,000.   The operating and maintenance
        costs  during the year of 1978 for the scrubbers  on  Units
        1-2-3  were:

        Operation of the facilities          $  250,000
        Flyash &  sulfur  sludge removal          954,000
        Replacement  power  costs               2 ,649 ,000
                    Operations Total         $3,853,000
        Maintenance                           2,798,000
                    Total                    $6,651,000
                             A-35

-------
A-3.11   MAJOR PROBLEM AREAS:  (Corrosion, Plugging, etc.)

        1.  302 Scrubber, Circulation Tank, Pumps, and Nozzles  -
           Problem/Solution:

           Corrosion problems were  experienced  with the stainless
           steel linings, and erosion problems occurred with  the
           coating used in the scrubber.   Also,  corrosion  and
           erosion problems were encountered with the pumps  related
           to the  scrubbers.   Initial operation of the scrubbers
           resulted  in  severe pluggage which  was reduced by  the
           addition of lime to control the pH.  Pluggage of  nozzles
           within  the system is still  a  problem with small chunks
           flaking  off within the  scurbber  system  and being
           recycled to the nozzles.  The system does not have
           S02 removal capabilities at this time, and no
           circulation tank is being  used.

        2.  Mist Eliminator - Problem/Solution:

           The original mist eliminators  were  constructed  from a
           polyethylene material  and were  very flammable.   As a
           result  of repairs in the scrubber areas, there were  two
           serious fires that  resulted in  extended down  time to
           repair  damage.  Mist modules  have since  been  changed to
           a fiberglass material that is less  flammable.   Another
           problem related to  the mist eliminators was fouling,
           that required more water to keep  the modules  clean than
           the design called for. This problem  has  been  alleviated
           by the  addition of lime for pH  control.

        3.  Reheater - Problem/Solution:

           The reheaters  for  these  units were  a  316L  stainless
           steel which  was found to be very  sensitive to the acid
           mist in the  flue gases. After a few months of use,  the
                              A-36

-------
   reheaters  were  no longer servicable and have since been
   removed  from  service.  Revoval of  the  reheaters caused
   serious  stack deterioration problems  resulting in the
   necessity  to  replace the stack liners.

4.  Venturi  Scrubber, Circulation Tanks and Pumps -  Problem/
   Solution:

   Shortly  after startup, the scrubber venturi and recycle
   pumps had a  serious  erosion-corrosion problem and
   required redesigning.  The venturi  of  the scrubber was
   modified to   include  acid  brick  to prevent
   erosion-corrosion in the throat area.  The recycle  pumps
   were replaced with  a  rubber lined  pump  to improve the
   reliability of  the  pump system.

5.  I.D. Booster  Fan and Ductwork - Problem/Solution:

   The original  ID fans were a 316 stainless steel.  Due  to
   vibration  problems  these failed and  had  to be replaced
   with inconel  fans.   Since that time,  the only problem
   has been the  erosion on the blades due  to ash carryover
   from the venturi scrubber.  The duct from the ID  fans  to
   the stack  was originally lines with 316L  stainless  steel
   and was plug welded to a carbon steel sheel.   This
   arrangement resulted in deterioration and failure of the
   stainless  steel in  the area of the  welds.  This lining
   has since  been  replaced with a fiberglass lining and  is
   repaired on an  annual basis.

6.  Limestone  Milling System  or Lime Slaking  -
   Problem/Solution:

   The present system  is a quick lime  system with a  batch
   slaking  process and problems in this area relate to the
   size of the  slaking  unit and  the relatively short

                      A-37

-------
   slaking period required  to  fill  the  batch tanks.  This
   short  time does not permit  continuous  operation of the
   slaking unit at designed temperatures  which has caused
   some carryover of lime  into  the  grits  system.  Scaling
   of the system continues to be  a problem in  the  lime
   slaker area due to the  hard  water that is being used for
   this process.

7.  Sludge Treatment and Disposal -  Problem/Solution:

   This item is not applicable  to the  scrubbing  system at
   the Four Corners Power  Plant.   However, the  following
   comments  apply to  fly  ash  disposal from the scrubber
   systems.

   Flyash from the  scrubber operation  is settled in
   thickeners and pumped to settling ponds  for dewatering.
   This  has  been  a  relatively  reliable system.   The
   principal problem  has  been chips  from the  scrubber
   operation causing plugging  or fouling  of the  underflow
   removal piping.  On occasion, this  has resulted in the
   failure of the thickener rakes and  a subsequent outage
   of the thickener for clean  out and repair.

8. Description of  scrubber control  methods  under
   fluctuating  load.

   Scrubber  control consists  of  adding  lime  and
   recirculating slurries until the specified pH limits and
   percents  of  solids  are  obtained.  Frequent  scaling of
   the pH probes which are located  in the scrubber  recycle
   slurries  have occured.   Good pH  control  is essential for
   scale-free  operation,  especially  when the scrubber
   liquids are  recycled.
                        A-38

-------
A-3.12  METHODS OF MEASURING EMISSIONS

        EPA methods 6,7  and 5 respectively, are  used to measure
        S02, NOX and particulate emissions.
                              A-39

-------
                            SECTION A-4
                       RETROFIT DESCRIPTION
A-4.1   MOX EMISSION CONTROL

       Table A-1  develops  details  of the  retrofit  examples
       investigated for NOX  reduction to boilers 1,2,3,4  and 5.

       Figure A-11 shows the  arrangement  of the  burners,  the
       overfire air (OFA)  ports, and the curtain  air  (C.A.)  ports
       for  the  Number 1 and 2 boilers.   Figure  A-12 shows  the
       arrangement of the  burners, the OFA ports,  and  the curtain
       air ports for the Number 3 boiler.

       Figure A-13  indicates the  burner arrangement  and windbox
       compartment modifications  for Boilers  4 and  5  after being
       retrofitted.  Eighteen sets of cell burners are  in use, and
       each  cell burner has  three cone nozzles.  The  number of  sets
       of  cell burners is  different  on each wall.  One wall has 8
       sets  of  burners, and the  opposite  wall has  10 sets.
       Assuming each cone  nozzle  is equivalent to an  individual,
       dual-register burner,  54 sets of dual register burners would
       be  required for a retrofit.   It may be necessary to provide
       a total  rearrangement of  burners   to  accomodate  the
       different flame characteristics of the   B&W,  dual-register
       burner.  The windbox  is compartmented horizontally as part
       of  the retrofit.  A vertical  partition at the  middle of  each
       compartmented windbox facilitates  air distribution.
       secondary air control dampers are provided  at both ends of
       each  compartmented windbox.
                                A-40

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-------
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              (B&W)  burners  and  compartmentized windbox.
                                 A-45

-------
A-4.2  PARTICULATE  EMISSION CONTROL

       The related  data  and  the  calculated results  for
       particulate  emission control retrofit work for Units  1 & 2
       are shown  in Table A-2.   Unit 3 data  are  shown in Table
       A-3,  and Table A-4 has the information for Units 4 and  5.
       For Units 1,2 &  3,  hot side ESP  retrofitting  was not
       considered  due  to  space  limitations  and  relocation
       requirements for  the air preheaters.

A-4.3  S02 EMISSION CONTROL

       System requirements are based on 90% S02 removal for
       wet scrubbing  and 70% S02 removal for dry scrubbing
       with 0.7 percent  sulfur coal.

       Sizes  have been  selected based on meeting S02 removal
       requirements.

       To evaluate  the  dry scrubbing systems,  the corresponding
       number of  wet  scrubber modules1 that  would produce a  70%,
       S02 removal  has  been used.  Also, the flue gas rate to
       be bypassed  given in the table is the appropriate  rate  to
       produce the  effectively 7Q%, S02 removal when using a
       90%,  wet S02 removal system.

-------
 TABLE A-2.- RETROFIT DATA FOR ELECTROSTATIC PREGIPITATORS
                     AND BAGHOUSES - UNITS 1 AND 2
Power Plant:
Boiler No.
Gross MW/Boiler:
Flue Gas (ACFM/Boiler
  300F
  68F (SCFM)
  170pa
  125Fb
  Four Corners
  #1 & #2
  190
2610 SCFM/MW 8 68F):
  713,800
  495,900
  623,400
  576,100
Per Boiler

Total Req'd Particulate
Collection Area (FT2)
Existing Collection Area
 (FT2)
Collection Area to be
 Added (FT2)
No. of ESP Trains
No. of ESP Modules/Train
Total No. of Modules to be
 Added
Total Area Added (F+2)

ESP Electrical Sectionalizing

Total No. of Electrical
Sections Required Per 5 MW
Existing Electrical Sections
No. of Elec. Sec/New Module
Total No. of Elec. Sections
 Added
                  Total
        Cold Side
           ESP
                                            Wet
Baghouse

Scrubbing
Dry
MW/Section
       713,800     356,900

          0           0

       713,800     356,900
           2
          11

          22           20
       712,800     369,460
          38
           0
           2

          44

          44

           4.32
         311,700

            0

         311,700
            17
         314,000
alncludes water from dry scrubbing

^Includes 13.3 percent water from wet scrubbing
                               A-47

-------
 TABLE A-3.- RETROFIT DATA FOR ELECTROSTATIC PRECIPITATORS
                       AND BAGHOUSES - UNIT 3
Power Plant:
Boiler No.
Gross MW/Boiler:
Flue Gas (ACFM/Boiler):
  300F
  68F (SCFM)
  170pa
                          Four Corners
                          #3
                          245

                          920,400
                          639,450
                          803,800
                          742,900
Per Boiler

Total Req'd Particulate
Collection Area (FT2)
Existing Collection Area
(FT2)
Collection Area to be
Added (FT2)
No. of ESP Trains
No. of ESP Modules/Train
Total No. of Modules to be
Added
Total Area Added (F + 2)

ESP Electrical Sectionalizing

Total No. of Electrical
 Sections Required Per 5 MW
Existing Electrical Sections
No. of Elec. Sec/New Module
Total No. of Elec. Sections
 Added
                  Total
                               Cold Side
                                  ESP
                               920,400

                                   0

                               920,400
                                   3
                                  10

                                  30
                                   972,000
     Baghouse
 Wet            Dry
     Scrubbing	
460,200

    0

460,200
    25
    461,800
                                  50
                                   0
                                   2

                                  60
                                  60
402,000

    0

402,000
   22
    406,400
MW/Section
                                   4.13
alncludes water from dry scrubbing

blncludes 13-3 percent water from wet scrubbing
                               A-48

-------
 TABLE A-4.- RETROFIT DATA FOR ELECTROSTATIC PRECIPITATORS
                    AND BAGHOUSES - UNITS 4 AND 5
Power Plant:
Boiler No.
Gross MW/Boiler:
Flue Gas (ACFM/Boiler)
  300F
  68F (SCFM)
  170Fa
  125Fb
  Four Corners
  #4 & #5
  778

2,923,000
2,031,000
2,553,000
2,359,000
                                                Baghouse
Per Boiler

Total Req'd Particulate
Collection Area (FT2)
Existing Collection Area
(FT2)
Collection Area to be
 Added (FT2)
No. of ESP Trains
No. of ESP Modules/Train
Total No. of Modules to be
 Added
Total Area Added (F+2)

ESP Electrical Sectionalizing

Total No. of Electrical
 Sections Required Per 5 MW
Existing Electrical Sections
No. of Elec. Sec/New Module
Total No. of Elec. Sections
Added
                  Total

MW/Section
Cold Side
ESP
2,923,000
373,000
2,550,000
8
10
80
2,592,000
Wet
Scrubbing
1,461,500 1,
0
1,461,500 1,
80
1,477,800 1,
Dry
276,500
0
276,500
7
293,000
         155
          32
           2
         160
         192
           4.03
alncludes water from dry scrubbing

^Includes 13.3 percent water from wet scrubbing
                               A-49

-------
                          SECTION  A-5
                        RETROFIT COSTS
Retrofit  capital  and annualized  costs for  the alternatives
discussed  in  Section A-l are included  in this section.   The  total
required plant  investment costs  given  for each alternative do  not
include the  costs  of removing and/or  relocating any existing
equipment  that  may be associated  with  the  particular retrofit
alternative.   The  cost for land  required  for  sludge disposal
(from S02  removal) and the associated  sludge transportion  to
the  disposal  site are  not included  in  the  retrofit plant
investment or annualized operating costs.   Also, the following
cost items are  realized but not included  in the total retrofit
capital and annualized costs:

(1)  Site  preparation
(2)  Cost  of  down-time
(3)  Additional  stack lining if  flue  gas  desulfuri zat ion  is
     installed
(4)  Costs for  removing ventiru scrubbers on Units 1, 2,  and 3

Working capital, the money required to operate the new equipment
associated with  the retrofit, has been calculated  for each
retrofit alternative.
                            A-50

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Cost
Item
           TABLE A-5  CAPITAL INVESTMENT COSTS FOR RETROFITTING
         THE FOUR CORNERS POWER PLANT - MILLIONS OF THIRD QUARTER
                             1979 DOLLARS (a)
       Alternative
                                                    2a
1.  NOx Control
2.  Partlculate control
3.  S02 control
4.  Emission Monitoring
5.  Auxiliary Boiler
6.  Replacement of Power
    Generating Capacity
7.  Working Capital
                     total
28.93
0.00
370.88
1.65
17.35
79.85
36.52
535.18(c)
28.93
161.55
370.88
1.65
17.35
97.52
45.08
722.96(c)
28.93
137.71
303.93
1.65
0
77.19
35.63
585.o4(c)
28.93
(b)
272.63(b)
1.65
0
38.54
23.91
365.66(c)
Millions of Dollars per
  Kilowatt Gross Generating
  Capacity
245.38
331.48
268.24
167.66
(a)  Includes direct and indirect costs
(b)  Costs of particulate and S02 control are combined
(c)  See Section 4.5 for other cost  not estimated
                                A-51

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        TABLE A-6  ANNUAL COSTS FOR RETROFITTING THE FOUR CORNERS

    POWER PLANT - MILLIONS OF THIRD QUARTER 1979 DOLLARS PER YEAR (a)
Cost

Item
        Alternative
                                                    2a
1.  NOx Control

2.  Particulate Control

3.  S02 Control

4.  Emission Monitoring

                    total
4.6588
0
140.974
0.467
4.658
34.418
140.974
0.467
4.658
26.439
110.953
0.467
4.658
(b)
90.510(b)
0.467
144.099U) I80.337(c) 142.517U)  95.635(c)
Millions per kilowatt hour
  of net power generation
  (current net less retrofit
  power requirements at
  65 percent of maximum net
  load)
 12.774
15.901
12.443
8.200
 (a)  Includes fixed capital charges.

 (b)  Costs of Particulate and SO- control are combined.

 (c)  See Section 4.5 for other costs not estimated.
                                 A-52

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                  SECTION  A-6
                  REFERENCES
Meeting notes - N.  Gonzalez/N. Master, Pullman Kellogg -
meeting  with D.J.  Campbell/J.  Weiss, Arizona Pulbic
Service,  Pruitland,  NM,  8  May  1979
Letters from C.D.   Jarman,  Arizona Public Service  to N.
Master, Pullman Kellogg, 5 July  1979
Meeting notes - N.   Gonzalez/N.  Master, Pullman Kellogg
                   Weiss,  et al, Arizona Public  Service
                  Copeland, EPA,  Phoenix, Arizona, 17
- meeting with J.
and S.   Cuffe/J.
July 1979
Letters from J.C.
                                                Master,
                   Evans,  Snell  & Wilmer to N.
Pullman Kellogg,  1 June  and  9 August 1979
Drawings received from APS:
Bechtel DWG 73005-2,  Plot  Plan,  Rev 2, 2-20-70
Ebasco DWG G-162385,  Plot  Plan,  Rev 3-A, 9-17-63
Ebasco DWG G-162390,  General Arrangement Section A-A,
Rev 5, 11-13-62
Ebasco DWT G-171673,  General Arrangement Section A-A,
Rev 4, 3-6-64
Bechtel DWG 73496-1,  General Arrangement Section, Rev 1,
2-14-68
                       A-53

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                   APPENDIX B






EXAMPLES OF RETROFITTING THE MOHAVE POWER  STATION

-------
                            CONTENTS
 SECTION
PAGE
 CONTENTS
 FIGURES
 TABLES
B-ii
B-iii
B-iv
 B-1.0   GENERAL
        B-l.l  Retrofit  Alternatives
        B-1.2  Plant  Characteristics
        B-1.3  Flue Gas  Ducting  Requirements
B-l
B-l
B-4
B-6
 B-2.0   BACKGROUND  DATA
        B-2.1   Plant  Description
        B-2.2   Steam  Generator  Description
        B-2.3   Existing  NOX  Control
        B-2.4   Existing'Particulate   Control
        B-2.5   Existing  S02  Control
B-13
B-13
B-14
B-16
B-16
B-l?
 B-3.0  PLANT SURVEY FORM                                    B-18
        B-3.1  Company and Plant  Information                 B-18
        B-3.2  Plant Data                                    B-18
        B-3.3  Boiler Data                                   B-19
        B-3.4  Fuel Data                                     B-21
        B-3.5  Atmospheric Emissions                         B-22
        B-3.6  Particulate Removal                           B-22
        B-3-7  Fresh Water Make-Up Flow Rates and Points of
                Addition                                     B-23
 B-4.0  RETROFIT DESCRIPTION
        B-4.1  NOX Emission Control
        B-4.2  Particulate Emission Control
B-24
B-24
B-24
B-5.0   RETROFIT COSTS
B-6.0   REFERENCES
B-29
B-32

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                             FIGURES
FIGURE                                                      PAGE

B-l   Addition of wet 862 scrubbing modules.                B-2
B-2   Addition of baghouses and wet SC>2 scrubbing
       modules.                                             B-3
B-3   Addition of dry S02 scrubbing modules with
       baghouses.                                           B-5
B-4   Plan arrangement of wet S02 scrubbing modules.        B-7
B-5   Elevation arrangement of wet S02 scrubbing
       modules.                                             B-8
B-6   Arrangement of ducting for baghouses and  wet  862
       scrubbing systems.                                   B-9
B-7   Arrangement of wet SC>2 scrubbing and baghouse
       modules.                                             B-10
B-8   Arrangement of dry 862 scrubbing and baghouse
       modules.                                             B-12
B-9   General plot plan of the Mohave power station.        B-15
B-10  Location of OFA ports and ducts for a twin  furnace
       Mohave boiler.                                       B-27
                              B-iii

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                             TABLES
Table                                                       Page

B-l   Retrofit for NOX Reduction                            B-25
B-2   Retrofit Data for Electrostatic Precipitators and
       Baghouses - Units 1 and 2                            B-28
B-3   Capital Investment Costs for Retrofitting the
       Mohave Power Plant                                   B-30
B-4   Annual costs for Retrofitting the Mohave
       Power Plant                                          B-31
                            B-iv

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                          SECTION B-l
                            GENERAL
B-l.l  RETROFIT ALTERNATIVES

       The four alternative examples considered In this appendix
       follow.   All  alternatives include maximum NOX control
       and the  installation of emission monitoring systems  for
       opacity,  S02>  and NOX.

       Alternative 1  - Add wet scrubbing to achieve 90% S02
       removal and  retain the existing ESP's for particulate
       emissions  control to a  level of 21 ng/J heat input (0.05
       lb/10" Btu).  Figure B-l shows the general arrangement
       of the plant  with the addition of the wet SOj
       scrubbing  modules.

       Alternative  2 -  This  option adds baghouses  plus  wet
       S02 scrubbing  for 90% S02 removal,  and it keeps
       the existing  ESP's for  control of particulate emissions  to
       a level  of 13  ng/J heat input (0.03  lbs/106 Btu).
       Figure B-2 shows  the plant's general arrangement with  the
       added S02  scrubbing modules and baghouse modules.

       Alternative 2a - The retrofit for particulate control  in
       Alternative 2a is  the  same as for Alternative 2, using
       baghouses  for  cost  comparison with Alternative 3-   The  wet
       S02 scrubbing  in  this case is based  on 7Q% SO^
       removal  for cost comparison with  semi-dry scrubbing  in
       Alternative 3-
                                B-1

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       Alternative 3 - Semi-dry S02 scrubbing  (spray drying)
       for  70% SC>2 removal is used in this  case.   Also
       baghouses  are used as  dry collectors with the  existing
       ESP's  for  control of particulate emissions to  a  level of
       13  ng/J heat  input (0.03 lbs/106 Btu).  Figure B-3
       shows  this general arrangement with the addition of the
       S02  scrubbing modules and baghouses.

B-1.2  PLANT  CHARACTERISTICS

       Major  revamp  work required to install  the S02 and
       particulate control equipment does not  involve  relocation
       of  existing equipment.  Characteristics of  the  plant  site,
       existing equipment,  and  space  requirements for  each
       retrofit example are shown in the following list  (I).

       A.  The existing electrostatic precipitators  are located
          downstream of the air preheater (cold  side).
       B.  Each of the two boilers has two primary-air (PA) fans
          and two forced-draft (PD) fans.
       C.  The number of SC^ scrubbing modules  used is  based
          on the  total calculated flue-gas rate  from  each
          boiler.
       D.  One S02 scrubbing module per boiler is  provided as
          a spare.
       E.  One flue-gas reheater is required for each  wet  S02
          scrubbing  module for 90% S02 removal.
       F.   One  flue-gas,  booster  fan is required  for  each
          scrubbing  module.
       G.   The individual  scrubbing  modules  are provided with
          dampers.   This provision allows the individual modules
          to be  isolated for maintenance.
       H.   Tie-in of retrofit equipment to  the  power  plant is
          based  on  completion during  normal power  plant
          maintenance turn-arounds of 3 to 6  weeks.
                                 B-4

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       I.  Tie-ins  to the existing  stack are the basis  for  the
          retrofit examples and  are  realized to be  extremely
          difficult.  Addition of  a  new  stack is  a possible
          alternative but was not  considered for estimating  the
          costs  for retrofitting  the  plant.
       J.  An  emergency bypass is provided around each SOg
          scrubbing  system to allow operation of the  boiler in
          the event  of a major FGD malfunction.  Bypassing of the
          particulate control equipment is not provided.

B-1.3  FLUE GAS DUCTING REQUIREMENTS FOR RETROFITTING

       Bypass duct and dampers  are  provided to enable the  flue
       gas to completely bypass the  S02 scrubbing system.
       Bypass duct  locations  for the  three alternatives  are
       indicated below:

       Alternative  1 -  The  emergency  bypass duct  is  located
       adjacent to the stack upstream  of the wet S02
       scrubbing module  booster  fans.   Figure B-A  shows  the
       additional  ducting requirements for the retrofit.   Figure
       B-5 shows the elevational view  for the S02 scrubbing
       module.

       Alternative 2 - The emergency bypass  duct is  taken after
       the baghouse, just before the scrubber modules  as  shown in
       Figure B-6.   Figure B-7 shows the elevation view for the
       S02 scrubbing and baghouse modules.

       Alternative 2a - The  bypass  duct is  the same  as used in
       Alternative 2.  This  duct can also be used during normal
       operation to  divert about 22.2% of the total flue  gas  that
       does  not need to be treated,  since the module  remove 90%
       S02 and this  alternate requires only 70%  overall
       S02 removal.  The bypass duct also provides the  flue
       gas requirements for  reheat.
                              B-6

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Alternative  3  - The bypass duct is taken  ahead  of  the
spray dryer and tied  into  the  duct going  to  the baghouses.
This location of the  emergency bypass permits operation of
the baghouse  for particulate control when a  spray dryer is
out of service.  Figure  B-8  shows  the  elevation  view for
the dry-scrubbing and baghouse modules.
                       B-ll

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                          SECTION B-2
                        BACKGROUND DATA
B-2.1  PLANT  DESCRIPTION (,2)

       The  Mohave Generating Station is  owned jointly by Southern
       California Edison, (5656),  The  Los Angeles Department  of
       Water  and Power, (20%), Nevada  Power Company, (1456),  and
       the  Salt River Project, (10%).  It is operated by Southern
       California Edison (SCE).

       Total  plant capacity is 1580  MW(net) and 1640 MW(gross).
       It consists  of two, 790  MW(net),  820  MW(gross),
       forced-draft, pressurized-firebox, pulverized-coal-fired ,
       steam  generators. The  two,  Combustion Engineering  (CE)
       boilers are equipped  with tilting tangential  burners.
       Each boiler has 8 burner sets,  and each  burner set  has  10
       burner nozzles.  There are, therefore, 80  burners  per
       boiler.  The coal feed  rate  per  boiler is approximately
       856,000 Ibs/hr.

       Pulverized subbituminous coal slurry is dewatered  in
       centrifuges before the coal is  fed into  the burners.

       The  flue gas duct runs vertically  down  from the  rear  side
       of each boiler, and it turns  90  to the horizontal.   The
       duct is then branched into two  ducts, each connected to an
       electrostatic precipitator.  Ducts from  each  precipitator
       combine into one duct and are connected  to one side of the
       single 500 ft.  stack.
                             B-13

-------
      Bottom ash from  the boiler bottoms  is  mixed with water and
      is transferred,  as slurry, to three settling tanks.   The
      ratio  of  fly  ash to bottom ash  is  70/30.   The water
      overflow from each  tank  is  stored in a fourth tank for
      further settling of  the ash, and then it is recycled  to
      complete the "closed-loop" slurry loop.  The flyash  from
      the precipitators is  pneumatically transported to a dry
      ash storage bin.

      The ash disposal site is  sized for 30 years of disposal
      capacity.

      The  flyash and  the  closed-loop,  wet-ash,  collecting
      systems are  currently  operating at full  capacity.
      Therefore, the capacity of each collecting system  has  to
      be increased for any  increase in the amount of  collected
      particulates  that  occurs as  a  result  of  retrofitting.
      Figure B-9 shows the  general plot plan arrangement for the
      Mohave power station.

B-2.2  STEAM GENERATOR  DESCRIPTION

      Each boiler uses a  forced draft system,  and the firebox is
      operated at 21"  1^0,  positive pressure.   Any further
      increase  in  the firebox  pressure  to compensate for
      pressure  drop  with  the additional emission control
      equipment may result in problems  of flue  gas leakage.
      Therefore, the addition  of  induced draft (ID)  fans  have
      been considered  for  the retrofit examples.  The  existing
      boiler design does  not allow for the use of new FD fans as
      an  alternative to the addition  of the ID  fans.   Each
      boiler has two primary air fans (PA) and two forced-draft
      fans (FD) operating  in parallel.
                             B-14

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       The  two, CE 790 MW (net) boilers  are tangentially  fired
       and  twin furnace designs.   Neither  boiler is equipped with
       over fire air ports.   The boilers  are the  dry bottom
       type.

       Vertical-shaft, regenerative,  Ljungstrom air  preheaters
       are  used. There are two air preheaters per boiler.

B-2.3  DESCRIPTION OF EXISTING NOX CONTROLS  (3.)

       Presently there are no specific controls  for NOX
       emission in the plant.  Originally, an NOX monitoring
       device  was designed and installed  at  the  plant  by SCE, but
       it is no longer  in  operation because of maintenance
       problems.  No retrofit work for NOX reduction has ever
       been done.

B-2.4  DESCRIPTION OF EXISTING PARTICULATE CONTROLS (j4)

       The  existing particulate controls  consist of two  sets per
       boiler of  cold  side,   Research-Cottrell,  Inc.,
       electrostatic precipitators.  The  manufacturer's guarantee
       was  91.9% removal  efficiency, at  2,300,000 ACFM per
       boiler,  with flue gas temperature  at  268F, and with coal
       sulfur  contents over  0.3 wt/6 .   Expected performance was
       98.6/6 under similar conditions.

       Installation of the cold side ESP's was  completed  in 1970
       and  they have a life  expectancy of 35 years.   Two  sets of
       ESP's are operated  in parallel for each  boiler.   Each
       precipitator unit is  enclosed in a 3/16"  thick  steel  shell
       and   is  segmented  into four mechanical units.   Each
       precipitator is equipped with sixteen ash hoppers.   Each
       mechanically segmented unit has 37 flue-gas passages (38
       collecting plates) that are 9-inches  wide.  The units are

                               B-16

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       30-feet high and 21-feet  long, and they are  segmented into
       three  sections.  The inlet  section is  9-feet  long in the
       flue gas flow direction and the second and third  sections
       are each 6-feet long.   The  total  effective collecting
       plate  surface area  is  220,000  square  feet for  each
       precipitator.

       Each  precipitator has  1,036  discharge  electrodes.
       Electrically, each unit consists of four  sections in the
       gas flow direction, while there are only three mechanical.
       The high voltage, uni-directional, power  supply  for the
       discharge electrodes is supplied by silicon  transformer-
       rectifier (T-R) sets.   One  electrical control   unit  is
       provided for  each  T-R  set which senses  spark  rate,
       current, and voltage.  The  control unit maintains  optimum
       current and voltage conditions automatically  and limits
       the voltage and current to the  T-R  set  rating.   The
       collecting plates in each precipitator are cleaned of fly
       ash by means of 64  magnetic impulse,  gravity  impact
       rappers.  The discharge  electrodes of  each  precipitator
       are cleaned of fly ash by means of 32  magnetic  impulse,
       gravity impact rappers.   The  precipitator  control  room is
       situated on the roof of each  precipitator.   Control panels
       for the existing precipitators occupy  the entire  control
       room,  and no space is available for  additional  controls
       for additional precipitators.   Fly  ash from  the
       precipitator hoppers are  pneumatically transported to a
       dry ash storage  bin.   Flue-gas  exit  ducts from two
       precipitators and merge into  a single  duct  that  connects
       to  the stack.   The  corresponding  duct  from the  other
       boiler is connected to the  other side  of the  stack.

B-2.5  EXISTING SOo CONTROL DESCRIPTION
                 c.
       The SOg emission control  is the use of low sulfur
       subbituminous coal as  fuel for the steam generators

                               3-17

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                               SECTION B-3
                            PLANT SURVEY FORM
B-3.1  COMPANY AND PLANT INFORMATION (1)

       1.  Company Name:   Southern California Edison Company
       2.  Main Office:    2244 Walnut Grove Avenue, P.O.  Box 800,
                         Rosemead, California  91720
       3.  Plant Manager: Mr. R.S. Currie, Mgr.  of Steam Generation
       4.  Plant Name:     Mohave Generating Station
       5.  Plant Location:  Clark County,  Laughlin, Nevada  89046
       6.  Person to Contact For Further Information: Mr. Lee Brothers
       7.  Position:      Senior Engineer
       8.  Telephone Number:  (213) 572-1630
       9.  Date Information Gathered:  April 23  - April 25, 1979
      10.  Participants in Meeting                    Affiliation

          L. Brothers                                    SCE
          N. Gonzalez                              Pullman Kellogg
          K. Hsiao                                 Pullman Kellogg
          N. Master                                Pullman Kellogg
          R. Redman                                Pullman Kellogg

B-3.2  PLANT DATA (APPLIES TO ALL BOILERS AT THE PLANT)

                                           Boiler No.
       Capacity, MW (net)                  790    790
       Service (Base,Peak)                 Base   Base
       FGD System Used?                     No     No
                                 B-18

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B-3.3  BOILER DATA

       1.  Maximum Continuous Heat Input:   16,700      MM BTU/HR
                                      I.   8.35 x 109 BTU/HR
                                     II.   8.35 x 109 BTU/HR

      1a.  Maximum Heat Input:          16,700          MM BTU/HR
      2.  Maximum Continuous Generating Capacity (Gross) 820 MW
                                                   (Net) 790 MW
      3.  Flue Gas Temperature:    270-300 (@ STACK)   F
      4.  Maximum Continuous Flue Gas Rate 4.2 x lp6_ ACFM g  60F

                                       I.  2.1 x 106 SCFM
                                      II.  2.1 x 106 SCFM

      5.  Flue Gas Analysis:         Not  Available
      6.  Flue Gas Recirculation
          For NOX Control:        YES	 NO      X
      7.  Boiler Manufacturer:        C.E. (I,II)
      8.  Years Boilers Placed  In Service:  1971 (I), 1971 (II)
      9.  Boiler Service (Base  Load, Peak, etc.):  Base
      9a.  Wet Bottom 	 Dry Bottom    X
      9b.  Firing Type:   PCTA
     10.  Stack Height Above Grade:  500  FT.
     lOa.  Stack Diameter (ft.):   33' ID at Outlet
     lOb.  Velocity Of Gas (Exit):  120 Ft/Sec at Full Load
     lOc.  Exit Gas Temperature:   300F
     lOd.  Number of Liners/Boiler:  One (One stack for two boilers)
     11.  Boiler Operations:  Hours/Year  (1977):  (I) 6194, (II)  6872,
     11a.  Boiler Operations:  Hours/Year  @ Full Load:  Not Available
     12.  Boiler Capacity Factora:(I) 56.1*,(II) 66.1*
     13.  Boiler Operating Pressure:  3500 PSIG @ Turbine Inlet
  aDefined as:
       KWH GENERATED IN YEAR	
       (Net)  Max Cont.   Generating Capacity in KW x 8760 HR/YR
                                 B-19

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14.  Boiler Superheat Heat Temperature:   1000
I4a. Boiler Reheat Temperature:	1000	
I4b. Economizer B.F.W. Outlet Temperature: N/A F
I4c. Superheater AP = 200 psi
15.  Ratio of Fly Ash/Bottom Ash = 70/30

16.  Burners:

     Type:  Tilting Tangential
                                MM BTU/HR
                                #/HR/Burner
                                % of Total
                                % of Total
                                % of Total
                                % of Total
17.  Fans [F.D. & ID] :

     Type:  FD, PA
     Manufacturer:  American Standard (FD), Westinghouse (PA)
     No. Per Unit:  2-PA, 2-FD
     Rating:  305,000 ACFM Each (PA), 125,000 ACFM (FD)
       p:     32.5 (FD), 31.2 (PA) H20
     HP:  FD 7000, PA 1750
Manufacturer:
No. Per Unit:
Rating:
Coal:
Primary Air:
Secondary Air
Tertiary Air:
Total Excess
C.E.
80
130.5
10,700
24.4


NONE
Air: 15
                           B-20

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      18.  Steam Temperature Control (Superheated & Reheated):  By
           Burner Tilt,  Attemporator Controls Superheated & Reheat
           Steam

           Attemporator  (Capacity):   Not Available

      19.  Air Preheater:

           Type:  Ljungstrom Vertical Shaft,  Regenerative
           No.:   2/Boiler
           Flue Gas AT:   425F
           Air AT   553F  (Secondary Air)/595F (Primary Air)
           Calculated Flow Rate:   4890M Ibs/Hr per A.P.  (Gas)
                                  4360M Ibs/Hr Air A.P.  (Air)
           Calculated*? 3.2" H20 (Air Side)
           Flue Gas Inlet  Temp.:   730 F
B-3.4  FUEL DATA
       1. Coal Analysis (as received)  (%}:    MAX.  I   MIN.  |  AVG.
                                                              0.5
          Ash

       2. Total Ultimate Analysis (wt!&)
                      As Received
          	  I   1.0
Dry Basis
As Mined
S:
Ash:
N:
Moisture:
C:
02 :
H2:
HHV (BTU/LB):
0.19
4.85
0.53
57.59
28.44
6.29
2.11

0.44
11.43
1.24

67.07
14.85
4.97
12,200



12.70



12,200
                                 B-21

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B-3.5  ATMOSPHERIC EMISSIONS
       1.  Applicable Emission Regulations  Particulates  SO   NOX
          a)   State of Nevada
              Current Requirements
              Max.  Allowable Emissions
              Lb/MM Btu Input To Boiler
 0.0675
    0.6  NONE
       2. Plant Program For Particulates:   Cold Side ESP's
       3. Plant Program For S02 Reduction:  Use of Low Sulfur Coal
       4. Plant Program For NOX Reduction:  No Overfire Air.  Use
          of Tangential Burners

B-3.6  PARTICULATE REMOVAL
          Type
Mech.
E.S.P.
FGD
          Manufacturer...                  	
          Efficiency:  Design/Actual...
          Emission Rate Lb/Hr (Total)3
                       Gr/SCFM...
                       Lb/MM Btu...
          Specific Collection Area (ft2/1000 ACFM)
          (Design/Operating):
          Total Collection Area:  440,000 Ft2/Boiler
          Design Basis, Sulfur Content
          Of Fuel...
         Research
         Cottrel
          97.9/98.6
           850
          0.24
          0.05

           191/143
          0.5
  aAt maximum continuous load
                                 B-22

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       2. Solids Collection System

          Present Operating Condition:  Bottom Ash Goes To Dewatering
                                        Bins and Then Trucked Away3
                                        Closed Loop Bottom Ashb
          At Maximum Capacity:          YES   X    NO 	
          Minimum Particulate Capturing Size:    1 Micron
          Particulate Loading Into Collector:    GR/Cu-Ft flue gas
          Unburned Carbon %:  N/A

B-3.7  FRESH WATER MAKE-UP FLOW RATES AND POINTS OF ADDITION

       Steam Blowdown Ratec;    None    GPM
       Availability of Blowdown;    None    GPM
       C.W. Blowdown Rate0:     N/A     GPM
  aAsh disposal area based on 35 years
  bFlyash from ESP is pneumatically conveyed to storage silos,
   wetted down in the unloader & trucked away
  Available water source for future SOg wet scrubber
                                 B-23

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                           SECTION B-4
                      RETROFIT DESCRIPTION
B-4.1  NOX EMISSION CONTROL

       The retrofit work investigated  for NOX reduction
       involves installation  of  overfire air  (OPA) ports  and the
       associated tilt drive  mechanisms, duct work, and  control
       air dampers  for  each  branch air duct to each OFA port.
       Also,  a new NOX control and  monitoring instrument
       system would be required  for each boiler unit.  Based on
       discussions with Combustion  Engineering, 2Q% excess air is
       recommended for boiler operation,  and 20% of this total
       air is the design rate for the  OFA.   The air temperature
       at the inlet to the  firebox  is  635F,  and the pressure is
       estimated at 34.2" H20.   The calculated  required OFA
       per boiler is 672,540  ACFM.   Using 200 feet per second for
       OFA jet velocity, 16 square  OFA ports, each 22 1/2"  x 22
       1/2",  are required.  Two  OFA ports are installed  together
       at the top of each tangential burner  set.  The associated
       work required includes redesign of pressure ports,  cutting
       the firebox wall, ductwork,  and added  air dampers.  These
       items  are shown in Table  B-l.   The locations of OFA ports
       are shown in Figure  B-10.

B-4.2  PARTICULATE EMISSION CONTROL

       The calculated number  of  modules for  ESP and baghouse use,
       for particulate control, and  the  data related  to these
       modules are shown in Table B-2.
                                 B-24

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          TABLE B-1.- RETROFIT FOR NOX REDUCTION
Units                                    1	&     #2

Boiler MW (MW/Boiler)                           820
Boiler Manufacturer                             C-E
Burners:  Type                               Tangential
          Arrangement

No. Burners/Vertical Column                      10
No. of Burner Columns                             8
Theoretical Air SCFM/Boiler                 1,464,700
Excess Air %                                    20
Air Temp. At Preheater Outlet (F)             635

TYPE OF RETROFIT

1.  Overfire Air (OFA)                         Yes
    % of OFA to Total Air                       20
    Total OFA ACFM                           672,540
    No. of OFA Ports                            16
    Size of OFA Port                        H        W
                                         22 1/2" X 22 1/2"
    Air ACFM per OFA Port                    42,034

2.  Curtain Air (C.A.)                          N/A
    % of C.A. to Total Air                       "
    Total C.A. ACFM                              "
    No. of C.A. Port                             "
    Size of C.A. Port                            "
    Air ACFM/C.A. Port                           "

3.  Low NOX Burners                              N/A

4.  Compartmented Windbox                        N/A
                                B-25

-------
    TABLE B-1.- RETROFIT FOR NOV REDUCTION (Continued)
Units                                     1	&     #2

ASSOCIATED MODIFICATION WORK
 REQUIRED:

    Cutting of OFA Port                         Yes
    Cutting of C.A. Port                         No
    Removing & Modification of
     Membrane Wall Tubes/Boiler
     (Approximate No. of Tubes)                 120
    Windbox Modification                         No
    Duct Connection (Addition)                  Yes
    OFA Tilt Drive Mechanism                    Yes
    Control To Each OFA & C.A. Port             Yes
                               B-26

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-------
      TABLE B-2.- RETROFIT DATA FOR ELECTROSTATIC PRECIPITATORS
                          AND BAGHOUSES
Power Plant:
Boiler No.
Gross MW/Boller:
Flue Gas ACFM/Boiler:
  300F
  170F
  125F
   68F
Mohave Power Generating Station
#1 & #2
820

3,080,600
2,690,300^
2,486,300b
2,140,200
Per Boiler

Total Req'd Particulate
Collection Area (FT2)
Existing Collection Area
(FT2)
Collection Area to be Added
(FT2)
No. of ESP Trains
No. of ESP Modules/Train
      Cold Side
         ESP

     3,080,600

       440,000

     2,640,600

         8
        10
Total No. of Modules to be Added  80
Total Area Added (P+2)         2,592,000

ESP Electrical Sectionallzing

Total No. of Electrical Sections
Required Per 5 MW                164
Existing Electrical Sections      32
No. of Elec. Sec/New Module        2
Total No. of Elec. Sections
Added                            160
                  Total          192
    Baghouse
Wet            Dry
    Scrubbing	

1,540,300    1,345,150
1,540,300    1,345,150
                     84           74
                  1,551,732     1,367,002
MW/Section                         4.27

a Includes water from dry scrubbing
b Includes water from wet scrubbing
c 2610 SCPM/MW  820 MW
                               B-28

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                          SECTION  B-5
                        RETROFIT COSTS
Retrofit  capital  and  annualized costs are  included  in  this
section for  the alternatives discussed in Section B-l.   The  total
required plant investment costs  given for each alternative do not
include  the  costs  of  removing and/or  relocating  any existing
equipment that may be  associated with  the  particular retrofit
alternative.  The  cost for land required  for  sludge disposal
(from S02 removal) and the associated sludge transportion to
the  disposal site  are  not included  in  the  retrofit  plant
investment or annualized operating costs.   Also,  the  following
cost items are realized but not included  in the total retrofit
capital and  annualized costs:

(1)  Site preparation
(2)  Cost of down-time
(3)  Additional  stack lining, if flue gas desulfurization is
     installed

Working capital, the money required to operate the new  equipment
associated  with  the retrofit, has been calculated  for  each
retrofit alternative.
                              B-29

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         TABLE B-3.   CAPITAL INVESTMENT COSTS FOR
           RETROFITTING THE MOHAVE POWER PLANT , ,
         MILLIONS OF THIRD QUARTER 1979 DOLLARS1 J
                                           Alternative
1.
2.
3.
4.
5.
6.
7.
Cost Item
NO Control
Particulate Control
S02 Control
Emission Monitoring
Auxiliary Boiler
Replacement of Power
Generating Capacity
Working Capital
TOTAL
1
4.46
0
234.82
0.73
13.05
60.04
23.24
336.34 CO
2
4.46
96.18
234.82
0.73
13.05
71.39
27.88
448.51 CO
3
4.46
96.18
191.55
0.73
0
58.05
22.81
373.78^
4
4.46
_.Cb)
205.00^
0.73
0
28.98
17.27
256. 44^
Millions of Dollars Per
  Kilawatt of Gross
  Generating Capacity       205.09      273.48      227.91       156.37
(a)  Includes direct and indirect costs.

(b)  Costs for particulate and S02 control are combined.

(c)  See Section 4.5 for other costs not estimated.


                                B-30

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         TABLE B-4.  ANNUAL COSTS FOR RETROFITTING
            THE MOHAVE POWER PLANT - MILLIONS OF
           THIRD QUARTER 1979 DOLLARS PER YEAR(a)
       Cost Item
1.  NO  Control
      J\-

2.  Particulate Control
3.  S02 Control

4.  Emission Monitoring
          TOTAL
0.772
0.000
91.931
0.263
0.772
18.563
91.931
0.263
0.772
18.563
71.643
0.263
0.772
__0>)
68.060^
0.263
92.966^   111.529(c)
Millions Per Kilawatt Hour
  of Net Power Generation
  (Current Net Less Retrofit  10.723
  Power Requirements at
  65 Percent of Maximum Net
  Load)
            12.957
10.511
7.817
(a)  Includes fixed capital charges.

(b)  Costs of Particulate and SO,, control are combined.

(c)  See Section 4.5 for other costs not estimated.

                              B-31

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                  SECTION  B-6
                  REFERENCES
Meeting notes - N.  Gonzalez/N. Master, Pullman Kellogg -
meeting with L.E.  Brothers,  Southern California  Edison,
Mohave Plant Site,  24  April  1979
Meeting notes - N.  Gonzalez/N. Master, Pullman Kellogg -
meeting with L.E.  Brothers,  et al,  Southern  California
Edison and S. Cuffe/J.  Copeland,  EPA, 19 July 1979
Technical data for Mohave units  1  and 2 Electrostatic
Precipitators, SCE,  internal document
Drawing  received  from SCE  Bechtel DWG 74212-17,  Plot
Plan, Rev 17, 3-19-79
                     B-32

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                    APPENDIX C






EXAMPLES FOR RETROFITTING THE NAVAJO POWER STATION

-------
                            CONTENTS

SECTION                                                    PAGE

CONTENTS                                                   C-ii
FIGURES                                                    C-iii
TABLES                                                     C-iv

C-1.0  GENERAL                                             C-l
       C-l.l  Retrofit Alternatives                        C-l
       C-l.2  Plant Characteristics                        C-4
       C-l.3  Equipment Location Changes for               C-6
                Retrofitting
       C-l.4  Flue Gas Ducting Requirements                C-7

C-2.0  BACKGROUND DATA                                     C-12
       C-2.1  Plant Description                            C-12
       C-2.2  Steam Generator Description                  C-14
       C-2.3  Existing NOX Control                         C-14
       C-2.4  Existing Particulate  Control                C-l6
       C-2.5  Existing S02 Control                         C-17

C-3.0  PLANT SURVEY FORM                                   C-18
       C-3.1  Company and Plant Information                C-18
       C-3.2  Plant Data                                   C-18
       C-3.3  Boiler Data                                  C-19
       C-3.4  Fuel Data                                    C-21
       C-3-5  Atmospheric Emissions                        C-21
       C-3.6  Particulate Removal                          C-22
       C-3.7  Fresh Water Make-Up Flow Rates and
               Points of Addition                          C-22

C-4.0  RETROFIT DESCRIPTION                                C-23
       C-4.1  NOX Emission Control                         C-23
       C-4.2  Particulate Emission Control                 C-23

C-50   RETROFIT COSTS                                      C-25

C-6.0  REFERENCES                                          C.-2R
                              C-ii

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                             FIGURES
FIGURE                                                       PAGE

C-l   Addition of wet SC>2 scrubbing  modules.                 C-2
C-2   Addition of ESP's and S02 scrubbing  modules.           C-3
C-3   Addition of dry S02 scrubbing  modules  with
       baghouses.                                            C-5
C-4   Arrangement of wet S02 scrubbing  modules.              C-8
C-5   Arrangement of wet 862 scrubbing  and ESP modules.      C-9
C-6   Arrangement of dry SC>2 and baghouse  modules.           C-11
C-7   General plot plan of the Navaj o power  station.         C-13
C-8   Schematic of air, flue gas, and coal conveying
       for the twin furnace Navajo boiler.                  C-15
                              C-iii

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                             TABLES
Table                                                       Page

C-l   Retrofit Data for Electrostatic Precipitators and
       Baghouses - Units 1, 2, and 3                        C-24
C-2   S02 Scrubber Modules for Navajo Power Plant           C-25
C-3   Navajo Plant, Raw Materials and Utilities
       Requirements - Alternative 1 and 2, Wet Scrubbing    C-27
C-4   Navajo Plant, Raw Materials and Utilities
       Requirements - Alternative 2a, Wet Scrubbing at 70%
       S02 Removal                                          C-28
C-5   Navajo Plant, Semi-dry Scrubbing Raw Materials
       and Utilities Requirements - Alternative 3, Semi-dry
       Scrubbing at 70% S02 Removal                         C-29
C-6   Navajo Plant - Estimated Flue Gas Ductwork
       Requirements                                         C-30
C-7   Navajo Plant - Capital and Investment Costs for
       Alternative 1                                        C-32
C-8   Navajo Plant - Annual Operating Cost for
       Alternative 1                                        C-33
C-9   Navajo Plant - Capital and Investment Costs for
       Alternative 2                                  '      C-34
C-10  Navajc Plant - Annual Operating Cost for
       Alternative 2                                        C-35
C-ll  Navajo Plant - Capital and Investment Costs for
       Alternative 2a                                       C-37
C-12  Navajo Plant - Annual Operating Cost for
       Alternative 2a                                       C-38
C-13  Navajo Plant - Capital and Investment Costs for
       Alternative 3                                        C-40
C-14  Navajo Plant - Annual Operating Cost for
       Alternative 3                                        C-41
C-15  Summary  of Retrofit  Capital Costs - Navajo
       Power Plant                                          C-43
C-l6  Summary  of Retrofit  Annual Costs - Navajo
       Power Plant                                          C-44
                               C-iv

-------
                          SECTION C-l
                            GENERAL
C-l.l  RETROFIT  ALTERNATIVES

       Pour alternative  examples for retrofitting the Navajo
       Power  Plant  were  considered  in  this  appendix  to
       demonstrate  the use of the methods developed  in  Section 3
       of the report.  Alternatives for  the  Units 1,2,  and 3
       boilers follows.  Since  the  Navajo steam generators are
       designed  for maximum NOX control,  no NOX
       retrofitting is necessary.  All alternatives  include the
       installation of emission monitoring systems  for opacity,
       S02,  and  NOX.

       Alternative  1  - Wet S02 scrubbing  for  90$ S02
       removal is added to existing ESP's to  provide  21 ng/J heat
       input (0.05  lb/10^ Btu) particulate  levels.  Figure
       C-l  shows the  plant general arrangement  with  the addition
       of the  S02 scrubbing modules.

       Alternative  2  - Alternative  2 upgrades the  existing ESP
       collection  area by adding of high-efficiency  cold-side
       ESP's.  Wet S02 scrubbing is also added.  The  resultant
       system  provides 90% S02 removal and  particulate
       emissions limitation to a leel of  13 ng/J heat input  (0.03
       lb/10"  Btu).   Figure C-2 shows the general arrangement
       when  the  S02 scrubbing and cold side ESP modules are
       included.

       Alternative  2a - The retrofit for  particulate  control is
       the  same  as  for Alternative 2,  but baghouses  have been
       used for cost comparison with Alternative 3.   The wet
       S02  scrubbing  is based on 70$ S02  removal for  cost
       comparison with semi-dry scrubbing of  Alternative 3.
                               C-1

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       Alternative 3 - Semi-dry S02 scrubbing (spray drying)
       to  1Q%  SQ2 removal is provided for this option.   By
       using baghouses as dry collectors with the existing ESP's.
       particulate emissions  are  controlled  to  a level  of  0.03
       Ib/MM Btu.  Figure C-3 shows the general arrangement  plot
       plan with  the addition of the S02 scrubbing modules
       and baghouses.

C-1.2  PLANT CHARACTERISTICS  U,2.,3.)

       Characteristics of the plant site, existing equipment, and
       space  requirements  for retrofit  are  presented in  the
       following  list:

       A.  The  Navajo Station  is located on  a  1021 acre  tract of
          land.
       B.  Major  revamp work to install the equipment for SC>2
          and  particulate control  requires relocation of existing
          equipment.
       C,  The  existing electrostatic precipitator is on  the hot
          side of the air preheater system.
       D.  The  existing ash disposal site is located on 765  acres
          about  two miles east of  the plant.
       E.  Each  boiler  has  two  primary-air  (PA) fans,  four
          forced-draft  (PD) fans,  and four  induced-draft  (I.D.)
          fans.
       P.  The  number  of  S02 scrubbing modules used is based
          on  the total calculated flue gas  rate from  each
          boiler.
       G.  One  S02 scrubbing module  per boiler is provided as
          a spare.
       H.  One  flue  gas  reheater is  required for each wet S02
          scrubbing module for Alternatives 1 and 2.
       I.  One flue  gas  booster fan  is  provided  per  scrubbing
          module.
                                 C-4

-------
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-------
       J.  The individual  scrubbing modules  are provided  with
          dampers. This provision allows the  individual modules
          to  be  isolated for maintenance.
       K.  Tie-in of  retrofit  equipment  to  the power  plant is
          based  on  completion  during  normal  power plant
          maintenance    turn-arounds of 3 to  6  weeks.
       L.  An  emergency bypass is provided  around each  S02
          scrubbing system to allow operation  of  the boiler in
          the event of a major FGD malfunction.   Bypassing of  the
          particulate control equipment is not provided.

C-1.3  EQUIPMENT LOCATION CHANGES FOR RETROFITTING

       Major  revamp work to install the equipment for  S02 and
       particulate control requires relocation  of  some existing
       buildings and/or  systems.   The  requirements  for the
       alternatives being considered are:

       Alternative 1

       The following  equipment relocation  is  necessary to allow
       for space requirements of the SO^ scrubbing  system:

       o  Warehouse,  shops, and miscellaneous  building presently
          located east of the boiler house will  have  to be moved
          north  of cooling towers, Unit 3
       o  The ash pipe way that presently runs from the boiler to
          the ash system also needs to be  relocated.

       Alternative 2

       The first two equipment  relocation requirements for
       Alternative 2, to retrofit for S02  scrubbing,  are the
       same as the two needed for Alternative 1.
                                C-6

-------
       o  A  third  requirement  when retrofitting with cold-side
          ESP's  in addition to S02 scrubbing requires moving
          the entire ash  system to the  east of  the  water
          treatment section that is presently located east of the
          boiler house.

       Alternative 2a  - Plot plans for this  alternative are  not
       included.   The space  requirements are less  than  for
       alternative 1 or 2, since the number of wet S02
       scrubbing modules  required  is less.

       Alternative 3 - The equipment relocation requirements to
       retrofit  for semi-dry 869 scrubbing are the same as
       those for Alternative 1.

C-1.4  FLUE  GAS  DUCTING REQUIREMENTS

       Bypass ducting  and dampers  are provided to enable the flue
       gas to go around the SC>2 scrubbing system.  Bypass
       ducting is  located for  the  three alternatives as indicated
       in the following paragraphs:

       Alternative 1 - The bypass  duct is taken from the  plenum
       located between the  ID fan and the  booster fan.   After
       bypassing the SC>2  scrubbing system, the bypass duct
       joins the duct  to  the stack.  Figure C-4 shows the general
       arrangement of  the scrubbing module and associated ducting
       with  tie-ins to the existing breeching.

       Alternative 2 - The bypass  duct is  taken after  the  cold
       side  ESP's.  Figure C-5 shows the  general arrangement of
       the precipitators  and SC>2 scrubbing modules including
       location  of the emergency,  SC>2 scrubbing system
       bypass.
                               C-7

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Alternative 2 a - The  bypass duct  is  arranged in the  same
manner as for Alternative 2.  This duct can also be  used
during normal operation  to divert about  22.2% of the total
flue gas that does  not require treatment, since the modules
remove 90% S02 and  this  alternate requires only 70%
SC>2 removal.   The bypass duct also  provides the flue gas
requirements  for  reheat.

Alternative 3 - The bypass duct is  taken ahead of the spray
dryer and then ties  into ducting  to  the baghouses.   This
location of the emergency bypass permits operation of the
baghouses for particulate control when a spray dryer is out
of service.  Figure C-6  shows the general arrangement of the
dry scrubbing module.
                           C-10

-------
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-------
                          SECTION C-2
                        BACKGROUND DATA
C-2. 1   PLANT DESCRIPTION (,2)

       The Navajo  station is  jointly  owned  by  several
       governmental and private utilities.   The station is
       operated by Salt River Project Agricultural Improvement
       and  Power District (SRP).

       Total plant capacity is 2250 MW (net) and 2M15 MW (gross).
       The  station consists  of three 750 MW (net),  805 MW
       (gross), pulverized- coal- fir ed ,  super critical- steam
       generating units manufacturered by Combustion Engineering
       (C.E.).  The units use balanced draft systems.

       A typical subbituminous coal burned at Navajo has a sulfur
       and  ash  weight percent of  0.5 and 10  to  12 respectively.
       The  coal is mined, by Peabody Coal  Company,  in the Black
       Mesa area located in Northern Arizona.  The coal feed  rate
       to each  boiler is in the  range  of 300-335 TPH (wet basis).
       The  coal ash content varies with  coal deliveries.  At the
       present  time ash content  rejection point  is 16
       Each boiler has a 775-foot high, 25-foot I.D. stack.  The
       flue gas  from each steam generator  passes through a high
       efficiency (+99.5%) Joy-Western hot  side electrostatic
       precipitator and  is  discharged to atmosphere  from the
       stack at  a velocity of about  100 ft/sec (at full load),
       and at a  temperature  of 300F.  Figure C-7 shows the
       general plot plan for the Navajo power station.
                              C-12

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C-13

-------
C-2.2   STEAM GENERATOR DESCRIPTION  (,3.)

       The  three Combustion  Engineering boilers  are  equipped
       withr tilting tangential burners  rated at 157.5 x 10"
       MM BTU/Hr/burner,  and  they are twin  furnace  designs.
       There are 56 burners per boiler.   Each  burner fires coal
       at a rate of 12,000 (maximum)  and  11,428 (normal)  Ibs/hr.
       The  total continuous heat input  to  the plant is  21,665.55
       MM Btu/Hr  with  boilers I,  II,  III  having  7,455.44,
       6,789.21, and 7,420.9 MM BTU/Hr  respectively.  Each boiler
       is equipped for overfiring.

       Each of  the boilers has  two  primary-air (PA)  fans,  two
       forced-draft (FD) fans, and  four  induced-draft (ID)  fans.
       The  PA fans (Howden) are used  for coal conveying, and they
       utilize  about 155& of the  total  air.   The FD and  ID fans
       are  manufacturered by Westinghouse.  Each boiler  has  two
       vertical shaft, regenerative  Ljungstrom air preheaters.
       The  burner  rating is 7.5 tons/hr.   Each mill feeds coal to
       eight burners, and there are seven mills per boiler.  The
       number of burners per  boiler  is 56.   The coal  feed rate
       per  boiler  is 300 to 335 tons  per hour.   The  three  C-E
       boilers  are of dry bottom type with a Fly Ash/Bottom  Ash
       ratio of 80/20.   The bottom  ash  slurry is dewatered  and is
       sent by  truck to  a disposal  pond with 35 years of disposal
       capacity.   Figure C-8 shows  a schematic of  the  air, flue
       gas, and coal conveying provision for each boiler.

C-2.3  DESCRIPTION OF EXISTING NOX  CONTROLS

       Presently,  there  are 16 overfire air  ports on each boiler.
       The  dimensions of the  OFA ports is unknown.   The OFA is
       presently  set at minimum for air-flow cooling of  the
       registers.  Automatic control is available for opening the
       dampers.   The current operation  involves  hand-loaded,
                              C-14

-------
      COAL PIPING
      TO BURNER
      TYP. EACH
      PULVERIZER
     BURNER
NOTE:
7 BURNERS PER
CORNER FOR A
TOTAL OF 56
BURNERS PER
BOILER.
Figure  C-8.- Schematic  of air,  flue gas,  and coal  conveying for
              the twin furnace Najavo boiler.
                                   c-15

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       Bailey positioners for  damper control of the  OFA.   Manual
       control is used for adjusting the tilt.  One  handwheel is
       provided for each OFA register.  Tests  conducted by SRP
       indicated no change in  NOX emission level when  going
       from the  minimum  to the maximum  openings of  the OFA
       ports.

C-2.H   EXISTING PARTICULATE CONTROLS (2,3)

       Each boiler is equipped with  hot-side  precipitators
       manufactured by Western Precipitators,  a division of Joy
       Manufacturers.   There  are 16 mechanical  flow sections,
       each containing  48 collection panels.   There  are 6
       electrical sections for each mechanical section or a  total
       of 96 electrical  sections for each  boiler.   This is
       equivalent to 8.39 MW per electical  section.  The design
       efficiency of these precipitators is 99.5$.   The  specific
       collection  area is 307  (design)/270  (operating) square
       feet per 1000 ACFM flue gas.  The design basis for  these
       ESP's is based on coal  with a 0.5%  (wt) , sulfur  content.
       The particulate emission rate, at maximum continuous  load
       from these ESP's, is 468 Ibs per hour per boiler, or  0.02
       Ibs per 10 Btu heat input (the  designed emission
       rate).  Total  collection area per boiler  is  1,209,600
       ft^.  Controls for each precipitator includes the
       following items:

       o  A-C supply volt meter
       o  A-C current meter
       o  Spark rate meter
       o  D-C volt meter
       o  D-C current meter
                              c-16

-------
       There are 6  field monitors  for each two  chambers  or a
       total of 48 monitors  per  boiler.  Each monitor  can  ground
       out one  chamber  to take readings of one chamber  and one
       field.   This  allows a read  out of any one of the 96 fields
       per precipitator.

C-2.5  EXISTING S02  CONTROL  DESCRIPTION

       There are no  current  SOg  emission controls except that
       low sulfur coal  is used as  fuel  for  the steam generators.
                               C-17

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                             SECTION C-3
                          PLANT SURVEY FORM


C-3.1  COMPANY AND PLANT INFORMATION (1,1,1)

       1.  Company Name:   Salt River Project

       2.  Main Office:    P.O.  Box 1980, Phoenix, Arizona  85001

       3.  Plant Manager:  Mr.  Harold Voeple

       4.  Plant Name:    Navajo Generating Station

       5.  Plant Location:  Page, Arizona 86040, Coconino County

       6.  Person To Contact For Further Information:
                                                    Mr. John McNamara

       7.  Position:      Associate General Manager-Power

       8.  Telephone Number-,  (602) 273-2851

       9.  Date Information Gathered:  April 17 - April 20, 1979

      10.   Participants in Meeting                    Affiliation

           Richard F.  Durning                             SRP
           John R.  McNamara                               SRP
           Donald W.  Moon                                 SRP
           Richard H.  Silverman                           SRP
           Gregory T.  Whalen                              SRP
           Norman Master                            Pullman Kellogg
           Nora Gonzalez                            Pullman Kellogg
           Ronnie Redman                            Pullman Kellogg

C-3.2  PLANT DATA (APPLIES TO ALL BOILERS AT THE PLANT)


                                          BOILER NO.

                                      123
       CAPACITY, MW (NET)             750    750    750
       SERVICE (BASE,PEAK)            BASE   BASE   BASE
       FGD SYSTEM USED?                NO     NO     NO
                                C-18

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C-3.3  BOILER DATA

       1.  Maximum Continuous Heat Input:_ 21^665-55.  __MM Btu/Hr
                                      I.  TT^SfTTRT x To6
                                     II.  6,789.21 x 100
                                     III.   7,420.9  x 10

       la. Maximum Heat Input:  21,665.55	MM Btu/Hr

       2.  Maximum Continuous Generating Capacity (Gross) 805 MW
                                                    (Net) 750 MW

       3.  Flue Gas Temperature:   300  (AT STACK)	P

       4.  Maximum Continuous Flue Gas Rate 9.34 x 10  ACFM @ 300F

                             BOILER     I.  3.23 MMACFM @ 307F
                             BOILER    II.  2.94 MMACFM % 282F
                             BOILER   III.  3.17 MMACFM % 298F

       5.  Flue Gas Analysis: Before Precipltator Op (3 - 3.5%)

       6.  Flue Gas Recirculation:    Yes	 No	X
           For NOX Control

       7.  Boiler Manufacturer:  C.E. (I,II,III)

       8.  Years Boilers Placed In Service:   Initial Firing 1974 (I),
           1974 (II), 1975 (III)

       9.  Boiler Service (Base Load, Peak,  Etc.):  Base Load
       9a. Wet Bottom	Dry Bottom	X	
       9b. Firing Type    PCTA

      10.  Stack Height above Grade:  775 ft. Per Boiler
      lOa. Stack Diameter (Ft,):  25' ID at Outlet
      lOb. Velocity Of Gas (Exit):  100-110 Ft/Sec at Full Load
      lOc. Exit Gas Temperature:  300F
      lOd. Number Of Liners/Boiler:  One (One stack per boiler)

      11.  Boiler Operations: Hours/Year (1978): (I) 7640, (II) 8077,
           (III) 7295
      lla. Boiler Operations:  Hours/Year % Full Load: (I) 7640,
           (II) 8077, (III) 7295

      12.  Boiler Capacity Factor13^1) 76.4%,(II) 82.1%,(III) 76.0%
      13.  Boiler Operating Pressure:  3800 PSIG @ Water Wall
           Outlets3

   aBase Load - Operates @ 100% Capacity
   bDefined as:
        KWH GENERATED IN YEAR
        (Net) Max Cont.Generating Capacity in KW x 8760 HR/YR
                                   C-19

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    14.   Boiler  Superheat  Heat  Temperature:   1005   F
    I4a.  Boiler  Reheat  Temperature:           1002   F
    I4b.  Economizer  B.F.W.  Outlet  Temperature:   631 F  @  Full  Load
    I4c.  Superheater delta P  =  200 psi

    15.   Ratio of Fly Ash/Bottom Ash  =  80/20

    16.   Burners c:

            Type:   Tilting Tangential
            Manufacturer:   Combustion Engineering  (C.E.)
            No.  Per  Unit:   56
            Rating:   157.5 x  105    MM Btu/Hr
            Coal:     15,000/11,428     #/Hr/Burner (Max./Normal)
                                       7.5  T/HR/BURNER
            Primary  Air:        15       %  of Total
            Secondary Air:              %  of Total
            Tertiary Air:     None       %  of Total
            Total Excess  Air:  20       %  of Total

    17.   Fans [F.D.  & I.D.

            Type:   Square  Cage  (FD,PA,ID)
            Manufacturer:   Westinghouse (FD,ID), Howden (PA)
            No.  Per  Unit:   2-PA, 4-FD,  4-ID
            Rating:d
            Regenerative  Air  Preheater  Inlet =  10.80"
            Regenerative  Air  Preheater  Outlet = 5.50"
            Windbox  = 3.50" H20
            Furnace  = 0.0" H20
            Draft At Regenerative  Or  Air  Preheater Outlet = -14.90
            H20

    18.   Windbox

            Main:   Equipped With Overfire Air
            Branch:
            Control:

    19.  Steam Temperature  Control
        (Superheated & Reheated)

            Attemporator  (Capacity):  216M Ibs/hr for superheat
            temperature control;  4^ MCR (Capacity) Feed Water To
            Firing Rate Ratio
c 7 Mills/Boiler 56 Burners = 300-335 TPH (Operating)
      8 Burners/Mill
      Each Mill 60 Tons/Hr (Design) dat Design Loads
d At design loads
                               C-20

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20.   Air Preheater

     Type:   Vertical Shaft, Regenerative Lungstrom
     No.:   2/Unit
     Flue Gas AT = 398F
     Air AT 507F (Secondary)/534F (Primary)
     Design Flow Rate; 6.875M Ibs/hr GAS 5,95PM Ibs/hr AIR
     Design AP  5.3" HT (AirsideT
            Flue Gas Inlet Temp.;  650 F

C-3.4  FUEL DATA

       1.  Coal Analysis (as received)

           S %

           Ash %

       2.  Total Ultimate Analysis
                                       MAX.
                                                      MIN.
    AVG.
                                                     I  0.5
                                        22
                                                       8
     10
    Ash...
    N. . .
    Moisture...
    u   
    o2...
    H2...
    Chlorine...
    HHV  (Btu/Lb)...
                                 0.50
                                10.43
                                 1.00
                                10.27
                                 61.29
                                 12.13
                                  4.37
                                 0.01
                                        10,725

C-3.5  ATMOSPHERIC EMISSIONS

       1.  Applicable Emission Regulations  PARTICULATES  SCs  NOY
    a)  Current Requirements
        Max. Allowable Emissions
        Lb/MM Btu Input To Boiler
                                                0.1
1.0  0.7
    (State)
     0.5
    (FEDERAL)
2.  Plant Program for Particulates:   Hot Side ESP's

3.  Plant Program For S02 Reduction:   Use of Low Sulfur Coal

4.  Plant Program For NOX Reduction:   C.E. Boiler with
    Tangential Firing and Overfire Capacity
                            c-21

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C-3.6  PARTICULATE REMOVAL

       1.   Type                             MECH.     E.S.P.     FGD

           Manufacturer...                            Joy
                                            	   Western6*^*	
           Efficiency:   Design/Actual...              99.5/99.5

           Emission Rate ef LB/HR...                     468

                          GR/SCFM...                   0.007 I
                                                       0.009 II
                                                       0.010 III

                         Lb/MM Btu...                   0.02

           Specific Collection Area (ft2/1000 ACFM)
           (Design/Operating):                         307/270

           Total Collection Area:   1,209,600 SF

           Design Basis, Sulfur Content
           Of Fuel...                                  0.5 WT$ S

       2.   Solids Collection System:

           Present Operating Condition:

           SBottom Ash Slurry to Dewatering Bins and Then
           Trucked Away To Disposal Area, Fly Ash Pneumatic
           Conveyed To Hopper (Truck 75 tons)

           At Maximum Capacity...                YES   X    NO
           Minimum Particulate Capturing Size...  1 Micron
           Unburned Carbon %:  <0.03

C-3.7  FRESH WATER MAKE-UP FLOW RATES AND POINTS OF ADDITION:

       Steam Slowdown Rate     None    GPMn
       Availability of Slowdown None GPM
       C.W. Blowdown Rate        N/A   GPMn
  eAt Maximum Continuous Load
  fESP-l6 Sections (Chambers)/Unit (48 Panels/Unit), 96 Total
   Electrical Sections
  8Ash Disposal Pond Based On 35 Years Life
  "Available Water Source For Future S02 Wet Scrubber
                                   C-22

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                           SECTION  C-4
                      RETROFIT  DESCRIPTION
c-4.1  NOX EMISSION CONTROL

       The existing OFA ports  require added automatic, tilt-drive
       mechanisms,  tied to the  burner tilt mechanism, for NOX
       control.   Twenty percent excess  air  is recommended with
       the OFA set  at  a flow  rate  of 20%  of  the total air.   New
       NOX monitoring  systems  will  be installed for NOX
       emission monitoring for  each boiler.

C-4.2  PARTICULATE  EMISSION CONTROL

       The retrofit work to be done  for particulate  emission
       control is shown in Table C-l.
                               C-23

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      TABLE C-l.- RETROFIT DATA FOR ELECTROSTATIC PRECIPITATORS
                  AND BAGHOUSES - UNITS 1, 2, AND 3
Power Plant:
Boiler No.
Gross MW/Boiler:
Flue Gas ACFM/Boiler
  300F
  170F
  125F
   68F
Navajo Generating Station
#1, 2 & 3
805

3,024,250
2,641,015
2,440,890
2,101,051
Per Boiler

Total Req'd Particulate
Collection Area (FT2)
Existing Collection Area
(FT2)
Collection Area to be Added
(FT2) - Hot Side
No. of ESP Trains
No. of ESP Modules/Train
Total No. of Modules to be
Added
Total Area Added - (P+2)

ESP Electrical Sectionalizing
      Cold Side
         ESP

     3,024,250

     1,209,600

     1,814,650

         8
         7

        56
     1,814,400
Total No. of Electrical Sections
Required Per 5 MW                 161
Existing Electrical Sections       96
No. of Elec. Sec/New Module         2
Total No. of Elec. Sections
Added                             112
                  Total           208

MW/Section                          3.87
                                            Wet
     Baghouse

     Scrubbing
  Dry
1,512,125

    0

1,512,125
    82
1,514,786
1,320,508

    0

1,320,508
   72
1,330,056
                               C-24

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                          SECTION C-5
                        RETROFIT COSTS
Retrofit  capital  and annuallzed  costs are  included  in this
section for  the  alternatives discussed  in Section C-l.  The total
required plant investment costs given for each alternative do  not
include  the  costs of removing and/or  relocating any existing
equipment that may be associated  with  the particular retrofit
alternative.  The cost for land  required for  sludge disposal
(from S02 removal) and the associated sludge transportion  to
the  disposal site are  not included in  the  retrofit plant
investment or annualized operating  costs.   Also,  the following
cost items are realized but not included  in the total retrofit
capital and  annualized costs:

(1)  Site preparation
(2)  Cost of  down-time
(3)  Additional  stack lining, if flue gas desulfurization  is
     installed

Working capital, the money required to  operate the new equipment
associated with the retrofit, has  been  calculated  for each
retrofit alternative.
                               C-25

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     TABLE C-2.  - CAPITAL INVESTMENT COSTS FOR RETROFITTING THE
   NAVAJO POWER PLANT -  MILLIONS OF THIRD QUARTER 1979 DOLLARS '


COST ITEM                          ALTERNATIVE

                               1         2         2a        5

1.  NO  Control               0.00      0.00       0.00    0.00
      Jv
2.  Particulate Control       0.00    110.52     110.52
3.  S02 Control             348.00    348.00     283.44   301.:
4.  Emission Monitoring       1.04      1.04       1.04     1.04
5.  Auxiliary Boiler         19.21     19.21       0        0
6.  Replacement of Power
      Generating Capacity    88.41    104.43      84.79    42.68
7.  Working Capital          54.11     41.25      55.50    25.14
                  Total     490,77*^ 624.45  (c^ 513.79^ 570.74(c^

Millions of Dollars per
  Kilowatt of Gross
  Generating Capacity       205.22    258.57     212.75    153.52

(a)  Includes direct and indirect costs
(b)  Costs for particulate and S02 control are combined
(c)  See Section 4.5 for other costs not estimated
                               C-26

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      TABLE C-5. - ANNUAL COSTS FOR RETROFITTING THE
NAVAJO POWER PLANT - MILLIONS OF THIRD QUARTER 1979 DOLLARS
                       PER YEAR^

COST ITEM                          ALTERNATIVE

                              1         2         2a
1.  NO  Control             0.000     0.000      0.000      0.000
      .A.
2.  Particulate Control     0.000    28.562     28.562
3.  S02 Control           156.112   156.112    105.117    100.222^
4.  Emission Monitoring     0.551     0.551      0.551      0.551
              Total       136.443^165.005^ 154.010(c) 100.551(c)

Mills per Kilowatt hour of
  net generation (current
  net less retrofit power
  requirements at 65
  percent of maximum
  net load)                11.066    15.478     10.851      7.993

(a)  Includes fixed capital charges
(b)  Costs of particulate and S02 control are combined
(c)  See Section 4.5 for other costs not estimated.
                               C-27

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                  SECTION C-6
                  REFERENCES
Meeting notes - N.  Gonzalez/N.  Master,  Pullman  Kellogg  -
meeting with R.H.  Silverman,  et al,  Salt  River  Project,
Phoenix, Arizona,  16 April 1979
Meeting notes - N.  Gonzalez/N.  Master,  Pullman  Kellogg  -
meeting with G. Whalen,  et al,  Salt  River Project,  Page,
Arizona, 17/18/19  April  1979
Letters from J.R.  McNamara,  Salt River Project  to N.
Master, Pullman Kellogg, 27 April,  17 May and 2'7  August,
1979
Meeting notes - N.  Master/W.  Talbert, Pullman  Kellogg  -
meeting with J.O.  Rich,  et al,  Salt  River Project and J.
Copeland,  EPA, Phoenix,  Arizona, 20  July  1979
Drawings received  from SRP:
Bechtel DWG A-665-C125  Site  General  Arrangement  Plan,
Rev 5, 7-8-74.
Bechtel DWG A-665-M421 General  Arrangement Section, Rev
6, 3-29-76
                        C-2B

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                              APPENDIX D

ANALYSIS OF FGD SYSTEM EFFICIENCY BASED ON EXISTING UTILITY BOILER DATA,
           PREPARED FOR EPA BY VECTOR RESEARCH,  INCORPORATED

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VBJ-EPA7.3-FR79-1                  OAQPS-78-LVI-B-13
                  ANALYSIS OF  FGD

            SYSTEM EFFICIENCY BASED ON

           EXISTING UTILITY BOILER DATA
                       R. FARRELL


                        T. DOYLE


                       N. ST.CLAIRE
                      NOVEMBER 1979



                     TECHNICAL REPORT



                        Preoared for
              Office of Air Quality Planning and Standards
               Emission Standards and Engineering Division
                  Environmental Protection Agency


        VECTOR RESEARCH, INCORPORATED


                 Ann Arbor, Michigan

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                                CONTENTS



                                                                   Page

1.0  INTRODUCTION AND SUMMARY	1-1

2.0  PREDICTED BEHAVIOR OF THIRTY-DAY AVERAGES OF EFFICIENCY ... 2-1

     2.1  Scope Of Analysis	2-5
     2.2  Analysis Results	,	2-7
     2.3  Methodology	,	2-37

3.0  DESCRIPTIVE STATISTICS ON FGD SYSTEM EFFICIENCY DATA ....  3-1

     3.1  Data Set	3-1
     3.2  Lognormal  Transformation  	  3-2

          3.2.1  The Untransformed Variable 	  3-2
          3.2.2  The Transformed Variable	3-5

     3.3  Estimated Parameters and Comparability Among Units  .  .  3-7

          3.3.1  Means and Standard Deviations  	  3-7
          3.3.2  Autocorrelation	3-11
          3.3.3  Autoregressive Model  	  3-13

     3.4  Possible Confounding Factors  	  3-13

4.0  COMPARISON WITH ENTROPY RESULTS  	  4-1

     4.1  Predicted Exceedences 	  4-1
     4.2  Process Structure 	  4-2
     4.3  Differences Among Sites 	  4-4

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                    1.0  INTRODUCTION AND SUMMARY

     The Environmental Protection Agency (EPA) promulgated new standards
of performance for electric utility steam generating units, on
June 11, 1979.  In addition to restricting the levels of pollutants that
these units emit into the atmosphere, the standards require a 90 percent
reduction in potential S02 emissions if they exceed 0.60 Ib/million
3TUs of heat input.  On August 10, 1979, a petition for reconsideration
of these standards was submitted to EPA by the Utility Air Regulatory
Grouo (UARG).l  Part of this petition requested that EPA reconsider the
90 percent removal  requirement.  This request was based on analyses per-
formed by Entropy Environmentalists, Incorporated, which were documented
in Appendix. B of the UARG Petition entitled "A Statistical Evaluation of
the EPA FGD System Data Base Included in the Subpart DA NSPS Docket".
The analysis included a numerical simulation of 1,000 years of flue gas
desulfurization (FGD) efficiency to examine the impact of the 90 percent
efficiency standard promulgated by EPA.
     Vector Research, Incorporated, (VRI) is under contract to EPA to
provide statistical and analytical support to the Agency on an as needed
basis.  On November 1, 1979, VRI was tasked to simulate or otherwise
analytically describe FGD system efficiency to permit examination of the
questions raised by the Entropy findings.  The primary purpose of the
task was to determine the levels of system efficiency and variability in
^Petition for Reconsideration, Docket Number OAQPS-78-1. "

-------
this efficiency that would be necessary to maintain at most one exceed-
ence ner year for a thirty-day rolling average on a 90 percent efficiency
standard.  The VRI simulation was to be based on analysis of data pro-
vided by EPA describing the efficiency of 11 flue gas desulfurization
units and to additionally describe results over a wide range of facility
parameters.  The data analysis and simulation results were to be  suoplied
to EPA within two weeks of initiation of the task.  The authors were
supported in this effort by Dr. Richard Cornell, a VRI associate, and
other VRI staff.
     This report presents the results of VRI's analysis activities  and  is
organized into four chapters.  This  introductory chapter provides a
description of the task and a summary of major results.  The second chap-
ter describes the results obtained concerning the behavior of various
thirty-day averages for p'arametrically described FGD systems.  The  range
of parameters used in generating these results was based in part  on the
statistical analysis of the data.  This analysis is discussed in  chapter
three.  The final chapter then discusses comparisons between VRI's
results and those reported by Entropy Environmentalists, Incorporated.
     The major conclusions of this analysis were as follows:
     (1)  The use of thirty-day moving averages of efficiency results  in
          low-variability efficiency measurements at a facility,  even
          when  the daily data  shows  much larger variability.  This
          results in averages which  cluster much more closely around the
          central value of the efficiency measurements than do  the  daily
          efficiencies.
     (2)  Existing facilities  show significant correlations in  the
          efficiencies of sulfur removal on successive days.  These
          autocorrelations, as well  as the median levels of efficiency

-------
     and the fundamental variability of the process, influence the


     closeness wi ch which thirty-day averages will remain clustered


     about their mean.


(3)   The minimum long run average efficiency levels (described here


     in terms of the geometric mean) at which a facility must be


     operated in order that the ratio at which thirty-day rolling


     averages occur below 90, 89, 88, 87, 86, or 85 percent be held


     to one per year are shown in exhibit 1-1 for facilities with


     autocorrelations of 0.7 and various fundamental  variability


     levels, some of which clearly represent good engineering and


     operating practice and some of which may not.  Exhibit 1-2


     shows similar data but for a failure rate of one failure per


     ten years.   As the exhibits show,  the rate of occurence of


     30-day rolling averages below 90 percent would be above one per
                                                            >

     year for facilities wiht a 92 percent geometric mean efficiency


     and daily variaility anywhere from 0.20 to 0.60.  These


     facilities  would, however, have rates below one per year if the
                                                                   *
     threshold were 89 percent and the daily variability were no


     greater than 0.26, or if the threshold were 88 percent and the


     daily variability was no greater than 0.32, or if the threshold


     were 87 percent and the daily variability was no greater than


     0.38, or if the threshold were 86 percent and the daily


     variability was no greater than 0.43> or if the threshold were


     85 percent and the daily variability was no greater than 0.48.

-------
EXHIBIT 1-1:
MINIMUM GEOMETRIC MEAN EFFICIENCIES REQUIRED
TO MAINTAIN NO MORE THAN ONE FAILURE PER YEAR
Daily
Std. Dev.
(in log)
.20
.21
.22
.23
.24
.25
.26
.27
.28
.29
.30
.31
.32
.33
.34
.35
.36
.37
.38
.39
.40
.41
.42
.43
.44
.45
.46
.47
.48
.49
.50
.51
.52
.53
.54
.55
.56
.57
.53
.59
.60
Std. Dev.
of
30-Day
Minimum Efficiency
For Threshold Shown
Average1 q0.
1 *
1 *
I 
I 
\ 
(
I 
(^ *
i 
(-
1 *
^ 
I 
\ *
I 
\ *
\ 
I 
I *
( .
(.

(-
1 
^ 
I 
t 
^ 
( .
I 
I 
I 
1 
1 *
I 
( 
I 
\ *
( .
^ 
I 
0063)
0071 }
0075)
0079)
0082)
0086)
0090)
0093)
0097)
0101)
0105)
0109)
0112)
0116)
0120)
0124)
0128)
0133)
0137)
0141)
0145)
0150)
0154)
0158)
0163)
0167)
0172)
0177)
0182)
0186)
0191)
0196)
0201)
0206)
0212)
0217)
0222)
0223)
0233)
0239)
0245)
92
92
92
92
92
92
92
92
92
.2
.3
.3
.4
.5
.6
.7
.8
.9
93.0
93
93
93
93
93
93
93
93
93
93
94
94
94
94
94
94
94
94
94
94
94
94
95
95
95
95
95
95
95
95
95
.1
.2
.3
.4
.5
.6
.7
.8
.8
.9
.0
.1
.2
.3
.4
.4
.5
.6
.7
.8
.9
.9
.0
.1
.2
.2
.3
.4
. 5
.5
.6
<89%
91.4
91.5
91.6
91.7
91.8
91.9
92.0
92.1
92.2
92.3
92.4
92.5
92.6
92.7
92.8
92.9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.7
93.8
93.9
94.0
94.1
94.2
94.2
94.3
94.4
94.5
94.6
94.7
94.8
94.9
94.9
95.0
95.1
95.2
<88%
90.
90.
90.
90.
91.
91.
91.
91.
91.
91.
91.
91.
92.
92.
92.
92.
92.
92.
92.
92.
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
93.
94.
94.
94.
94.
94.
94.
94.
94.
94.
6
7
8
9
1
2
3
4
5
6
7
9
0
1
2
3
4
5
6
7
8
9
0
1
2
3
4
5
6
7
8
9
0
1
2
3
4
5
6
7
7
<87%
89.8
89.9
90.1
90.2
90.3
90.4
90.6
90.7
90.8
90.9
91.1
91.2
91.3
91.4
91.5
91.6
91.8
91.9
92.0
92.1
92.2
92.3
92.4
92.6
92.7
92.3
92 9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.7
93.3
93.9
94.0
94.1
94,2
94.3
<86%
89.
89.
89.
89.
89.
89.
89.
90.
90.
90.
90.
90.
90.
90.
90.
91.
91.
91.
91.
91.
91.
91.
91
92.
92.
92.
92.
92.
92.
92.
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
0
2
3
4
6
7
8
0
1
2
4
5
6
3
9
0
1
3
4
5
6
7
9
0
1
2
3
5
6
7
8
9
0
1
2
3
4
6
7
8
9
<85%
88.2
83.4
88.5
88.7
88.8
89.0
89.1
89.3
89.4
89.5
89.7
89.8
90.0
90.1
90.2
90.4
90.5
90.6
90.8
90.9
91.0
91.2
91.3
91.4
91 5
91.7
91.8
91.9
92.0
92.2
92.3
92.4
92.5
92.6
92.7
92.9
93.0
93.1
93.2
93.3
93.4
                            Facility autocorrelation = 0.7
 xln computing the 30-day average variability, a geometric mean
 emission  level of 92?' was assumed.

-------
  EXHIBIT 1-2:   MINIMUM  GEOMETRIC MEAN EFFICIENCIES REQUIRED TO
                MAINTAIN NO MORE THAN ONE FAILURE PER TEN YEARS
 Daily         Std.  Dev.           Minimum Efficiency
Std. Dev.       of 30-Day           For Threshold Shown
(in log)       Average

                             <90%  <89%  <88%  <87%  <86%  <85%
    .20
    .21
    .22
    .23
    .24
    .25
    .26
    .27
    .28
    .29
    .30
    .31
    .32
    .33
    .34
    .35
    .36
    .37
    .38
    .39
    .40
    .41
    .42
    .43
    .44
    .45
    .46
    .47
    .48
    .49
    .50
    .51
    .52
    .53
    .54
    . 55
    .56
    .57
    .58
    .59
    .60

                                 Facility autocorrelation  =0.7
(.0068)
(.0071)
(.0075)
(.0079)
(.0082)
(.0086)
(.0090)
(.0093)
(.0097)
(.0101)
(.0105)
(.0109)
(.0112)
(.0116)
(.0120)
(.0124)
(.0128)
(.0133)
(.0137)
(.0141)
(.0145)
(.0150)
(.0154)
(.0158)
(.0163)
(.0167)
(.0172)
(.0177)
(.0182)
(.0186)
(.0191)
(.0196)
(.0201)
(.0206)
(.0212)
(.0217)
(.0222)
(.0228)
(.0233)
(.0239)
(.0245)
92
92
92
92
93
93
93
93
93
93
93
93
93
93
94
94
94
94
94
94
94
94
94
94
95
95
95
95
95
95
95
95
95
95
95
95
95
96
96
96
96
.6
.7
.8
.9
.0
.1
.2
.3
.4
.5
.6
.7
.8
.9
.0
.1
.2
.3
.4
.5
.6
.7
.8
.9
.0
.0
.1
.2
.3
.4
.5
.5
.6
.7
.8
.8
.9
.0
.1
.1
.2
91.
91.
92.
92.
92.
92.
92.
92.
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
95.
95.
95.
95.
95.
95.
95.
95.
95.
95.
95.
8
9
1
2
3
4
5
7
8
9
0
1
2
3
4
5
6
8
9
0
1
2
3
4
4
5
6
7
8
9
0
1
2
3
o
o
4
5
6
7
8
8
91.
91.
91.
91.
91.
91.
91.
92.
92.
2.
92.
92.
92,
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
93.
94,
94.
94.
94.
94.
94.
94.
94.
94.
94.
95.
95.
95.
95.
95.
95.
1
2
3
5
6
7
9
0
1
2
4
5
6
7
8
0
1
2
3
4
5
6
7
8
9
0
1
2
3
4
5
6
7
8
9
0
1
2
3
4
5
90.
90.
90.
90.
90.
91.
91.
91.
91.
91.
91.
91.
92.
92.
92.
92.
92.
92.
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
95.
95.
3
5
6
8
9
0
2
3
5
6
7
9
0
1
2
4
5
6
7
9
0
1
2
3
4
5
7
8
Q
0
i
2
3
4
5
6
7
8
9
0
1
89.6
89.7
89.9
90.1
90.2
90.4
90.5
90.7
90.8
90.9
91.1
91.2
91.4
91.5
91.5
91.8
91.9
92.0
92.2
92.3
92.4
92.6
92.7
92.8
92.9
93.1
93.2
93.3
93. 4
93.5
93.6
93.7
93.9
94.0
94.1
94.2
94.3
94.4
94.5
94.6
94.7
88.
89.
89.
89.
89.
89.
89.
90.
90.
90.
90.
90.
90.
90.
91.
91.
91.
91.
~-91.
91.
91.
92.
92.
92.
92.
92.
92.
92.
9?.
93.
93.
93.
93.
93.
93.
93.
93.
94.
94.
94.
94.
8
0
2
3
5
7
8
0
1
3
5
6
8
Q
i
2
5
5
6
8
9
0
2
3
4
6
7
3
9
1
2
3
4
5
7
8
9
0
1
2
*
1
 In computing  the  30-day average variability,  a geometric mesn
emission level  of  92?' was assumed.

-------
                                   1-6
          The rates would be below one occurence per ten years for

          combinations of thresholds and daily variabilities as follows:

               Threshold             Daily Variabil ity

                  89%              no greater than 0.21
                  88%              no greater than 0.27
                  87%              no greater than 0.32
                  86%              no greater than 0.37
                  85%              no greater than 0.41

          Data for auto correlations other than 0.7 can be found  in  the

          body of the report.

     (4)  There is very little change in these estimates of minimum  effi-

          ciencies when the assumptions concerning the type of statisti-

          cal distribution used to represent the efficiency data  are

          varied.  Both normal and lognormal distributions provide rea-

          sonable fits to the existing daily efficiency data, with the

          lognorma! probably slightly better than the normal.  (Because

          the lognormal distribution appears to fit the data better  than

          the normal, it has been used in generating exhibits 1-1 and

          1-2, and in general throughout the analyses.). Both distribu-

          tional assumptions produce very similar  results  in terms of the

          predicted behavior of thirty-day  averag >s taken  on a rolling

          basis.

These conclusions, as well as many other observations,  are discussed in

more detail  in the body of-this report.

-------
    2.0  PREDICTED BEHAVIOR OF THIRTY DAY AVERAGES OF EFFICIENCY

     This chapter describes the main results of this analysis.  The
principal question of interest is the behavior of thirty-day moving
averages of efficiency, and specifically the rate at which  such averages
would dip below selected thresholds.  The behavior of the moving  or
rolling average was examined,for various true (average)  efficiencies,
variabilities, and time dependencies.
      In a setting where penalties could be imposed when such  averages
fell below a regulatory threshold, EPA would expect to  set  the threshold
level so that facilities designed, constructed, and operated in
accordance with good engineering practice would produce  very infrequent
threshold crossings, while facilities not in accord with good  engineering
practice wouTd show averages below the threshold on a more  frequent
basis.  That is, the threshold should correspond to some value
approximately at the minimum expected to be seen regularly  from
well-engineered and operated facilities.  This analysis  is  not designed
to analyze what levels of performance correspond to good engineering
practice, but to show the relation between the operating characteristics
of a facility and the rates at which various threshold  values  of
thirty-day averages would be crossed.  This information  can then  be
combined by EPA with expert knowledge of the achievable  levels of
engineering and ooerating performance in designing regulatory  policies.
     Although the precise method of computing the thirty-day average
might vary somewhat, this analysis has assumed that a daily average
efficiency is generated each day from more frequent measurements  of
emissions, and that these daily averages ara then averaged  for a  period

-------
                                 2-2
of thirty days.  Such thirty-day averages might be computed  each  day,



each week, each month, or at any other frequency, based  on the  thirty-day



period ending with the computation day.  The behavior of averages  at



various computation frequencies will be  discussed.  We believe  that this



general scheme contains most policies of interest.  In the case  of



possible changes in the arecise methods  of  computing  averages  from hourly



or more frequent data, the analysis encompasses policies with  essentially



the same effects as those which might be adopted.  All the analyses have



assumed that data would be available for each  day of  operations.



     In order to predict the behavior of the averages involved,  assump-



tions must be made about several basic properties of  the measurements  of



scrubbing efficiency  at a facility.  These  assumptions concern  the long-



run level of scrubbing efficiency  achieved, the type  and amount of daily



variability which will be observed, and  any temporal'patterns  or correla-



tions which might be  expected  in the observed  efficiency.



     Before presenting any numerical analyses  of  the  issues, it is neces-



sary to define the various types of measurements  which were  used in



describing and analyzing the process.  The  level  of  scrubbing  efficiency



achieved will be discussed in  terms of several  different related quanti-



ties.  For some ourposes, it is  necessary  to consider the  measured daily



efficiency:  this quantity is  produced by  reducing more  frequent measure-



ments  of  inlet and outlet sulfur concentrations  to  a  daily  efficiency



figure.  These measurements may  also be  considreed  in  terms  of  the equiv-



alent  measurements of emissivity,  which  is  1-efficiency,  so  that an



efficiency of 90 percent corresponds to  an  emissivity  of 10  percent.



     Daily efficiency or emissivity measurements  (which  were the basic



data used in the detailed data analyses  of  actual  facilities,  as

-------
                                 D 2-3
described in chapter 3.0, and which also form a basis  in  terms  of  which
all these analyses were conducted) are observed to  vary when  measured
repeatedly at a single facility.  This variation is stochastic  or
probabilistic, rather than deterministic,  in nature.   That  is,  the exact
measurement which will be obtai  ^d at some future time is not completely
determined from our knowledge of the process, but includes  elements of
randomness.
     Describing the randomness in the daily measurements  involves
describing the distribution of the daily measurements  (that is,  the
frequencies with which the measurement takes on various values)  and the
interrelations among the daily measurements for different days.  The
distribution of the daily measurements is  typically described in terms  of
a measure of the center of the measurements observed  (such  as the
mean, the geometric mean, or the median) a measure  of  the variability of
the measurements about this center (such as the standard  deviation or
geometric standard deviation), and the particular shape or  type  of
distribution which descirbes the variability (such  as  the normal or
lognormal distribution).  The interrelationships between  measurements on
various days are typically measured in terms of the correlation  between
measurements on successive days.
     The mean (sometimes called the arithmetic mean) of the measurements
is simply the long-run average of the measurements.  The  geometric mean
is the value which would he obtained by taking the  antilogarithm of the
mean of the logarithms of the measurements.  The geometric  mean  of
measurements is always less than the arithmetic mean,  no  matter  how the
measurements are distributed.  The median  of measurements is  the value
such that 50 percent of the measurements are above  it  and 50  percent

-------
below.  The standard deviation of measurements is the root-mean-square


average of the deviations of the measurements about their own mean.  The


geometric standard deviation^ is the root-mean-square average of the


deviations of the logarithms of the measurements about the mean of the


logarithms.  The correlation (or autocorrelation), of a sequence of


measurements varies between -1 and +1.  a correlation of +1 indicates


perfect correlation  that is, in our case, successive measurements at  a


single facility would be identical.  A correlation of 0 indicates  no


dependence between successive measurements.  Correlations below 0


indicate that high measurements are followed by low and low by high.


     All of these terms may be applied to any sequence of measurements.


In the specific problem at hand, they may be applied to daily efficiency


measurements, daily emissivity measurements, or thirty-day averages of


either.  Generally, daily efficiencies are  discussed in this analysis  in


terms of the geometric mean emissivity (or  the equivalent efficiency)  and


the geometric standard deviation of emissivity.  This geometric standard


deviation may be thought of as a percentage variability in the measure-
                                                                        

ments so that a geometric standard deviation of 0.20 would indicate  a


daily variation of about 20 percent of the  daily mean.  These scales  of


measurement were chosen because they were those which had been used  in


past  studies of the same general topics.  The thirty-day averages  are


typically  discussed in terms of the frequencies with which particular


levels of emissivity would be exceeded by the thirty-day averages  or  in


terms of their mean and standard deviation  (arithmetic, not  geometric).

-------
                                 2-5
2.1  SCOPE OF ANALYSES
     In the specific problem  at hand,  the  evidence  supports  the  use of a
model in which observed dependencies  in  sequences of  efficiency  measure-
ments are viewed as produced  by correlations  between  immediately succes-
sive days.  The evidence on this point is  discussed in  the next  chapter.
In such a model (an autoregressive model of laq  one)  the  only  correlation
parameter required to describe the pattern is the basic correlation
between the observations on successive days.  All other dependencies are
then computable from this correlation  coefficient.  In  terms of  these
oarameters, the region of the oarameter  space examined  in this analysis
was:
     (1)  Long-run geometric  mean emissivities of six percent  to nine
          percent, with particular attention  to  the value of eight
          percent, corresponding to a  92 percent efficiency.1
     (2)  Daily geometric standard deviations of 0.20 to  0.50  and
          distributions of measurements  described by  a  probability
          distribution of emissivities similar to the lognormal  or normal
          distribution, probably having  more  similarity to the lognormal
          (see chapter 3.0).  It must  be remembered that  these daily
          variabilities in emissivity  lead to much  smaller variabilities
          in the thirty-day-efficiency.  For  example, a typical  facility
          with daily emissivities of  the order of nine  percent with a
IAIthough the 92 percent figure  is  not  the  geometric  mean  efficiency
 but the efficiency corresponding to  the  geometric mean  of emissivity,
 we will, when aoprooriate,  refer to  such values  as  geometric  means
 without intending to mislead.

-------
                                   2-6
          50 percent variability would have daily efficiencies of 91


          percent, with a daily error of 4.5 percent, and thirty-day


          average efficiencies of about 91 percent with a variability of


          only about one percent.


     (3)  Uay-to-day correlations between successive observations of 0.0


          to 0.7.


The results of this analysis address three topics:


     (1)  The average number of times per year that thirty-day average


          efficiencies, computed daily (360 times per "year"), would be


          below various thresholds as a function of the facility operat-


          ing parameters assumed.


     (2)  The minimum long-run level of efficiency which a  facility would


          have to maintain to limit its average threshold crossings on


          the same rolling average to one per year, one per  two years,
                                                                 at


          one per five years, or one per  ten years as a function of the


          level of variability and correlation of daily observations at


          the facility.  These efficiencies are presented in  terms  of
                                                                        9

          geometric means, keeping the method of description  for  all


          daily data consistent.  At these levels, the long-run rate of


          excessive emissivity measured in terms of thirty-day  rolling


          averages, would be held to the  one per year or other  ratj as


          qiven.  The actual number of excesses in a  specific year  would,


          of course, vary, so that at a rate of one per year, some  years


          would have t^o, for example, and others zero.


     (3)  The potential effects  of changing the frequency of  computation


          of the  averages on the rate at  which threshold crossing would


          occur.

-------
                                 2-7
Following the presentation of these results, a  very  brief  section
discusses the methods of computation used  to generate  the'  estimates.

2.2  ANALYSIS RESULTS
     The most basic and fundamental results of  this  analysis  simply
describe the mean, standard deviation, and distribution  of the  thirty-day
averages as functions of the elementary  orocess parameters describing the
level of efficiency, the variability of  the daily  observations,  and the
autocorrelation.  Exhibit 2-1 shows the  means and  standard deviations of
the thirty-day rolling averages for a  sampling  of  parameter values  in the
region examined.  Several observations can be made from  that  data.   The
most basic is simply that the mean efficiency is different than  the
efficiency level described by the geometric mean emissivitv.  This
difference simply reflects the differences in meaning  between the^mean
and the geometric mean.  The difference  would remain even  if  the data had
beem normally distributed:  the geometric mean  of  a  normally-distributed
datum is not identical to its mean, and  the relation between  the two
                                                                         *
values in the parameter region of interest is almost precisely  the
relation between the same parameters in  the lognormal  distribution.
     A second observation is that the  variabilities  of the thirty-day
averages are much lower than the variabilities  of  the  daily data.  This
reduction in variability is the basic  reason why taking  averages of
sequences of observations is useful in obtaining consistent estimates of
actual performance levels.  The third  observation  which  can be  made from
the exhibit is that both the mean and  the  standard deviation  of the
thirty-day averages are clearly influenced by the  variability  and
autocorrelation in the efficiency process, as well as  by the  level  of
efficiency.

-------
                                      D 2-8



     EXHIBIT 2-1:   MEAN AND STANDARD DEVIATION  OF  30-DAY AVERAGES

            Process  Parameters                            Thirty-Day  Average

Geom.  Mean     Geom.  Std.  Dev.   Autocor.            Mean            Std.  Dev.

   .9100              .2000             0.0000              .9032              .0034
   .9100              .2000              .3000               9032              .0045
   .9100              .2000              .5000              .9082              .0057
   .9100              .2000              .7000              .9082              .0075
   .9100              .3000             0.0000              .9059              .0053
   .9100              .3000              .3000              .9059              .0070
   .9100              .3000              .5000              .9059              .0088
   .9100              .3000              .7000              .9059              .0118
   .9100              .4000             0.0000              .9025              .0074
   .9100              .4000              .3000              .9025              .0098
   .9100              .iCCO              .5000              .9025              .0122
   .9100              .4000               7000              .9025              .0163
   .9100              .5000             0.0000              .8980              .0099
   .9100              .5000              .3000              .8980              -0130
   .9100              .5000              .5000              .3930              .0162
   .9100              .5000              .7000              .8980              .0215
   .9200              .2000             0.0000              .9134              .0030
   .9200              .2000              .3000  -            .9184              .0040
   .9200              .2000              .5000              .9134              .0051
   .9200              .2000              .7000              .9184              .0063
   .9200              .3000             0.0000              .9163              .0047
   .9200              .3000              .3000              .9163              .0063
   .9200              .3000              .5000              .9163              .0073
   .9200              .3000              .7000               9163              .0105
   .92CO              .4000             0.0000              .9133              .0066
   .9200              .4COO              .3000              .9133              .0087
   .9200              .4000              .5000              .9133              .0109
   .9200              .4000              .7000              .9133              .0145
   .?2CO              .5000             0.0000              .9093              .0083
   .9200               5COO              .3000              .9093              .0116
   .9200              .5000              .5000              .9093              .0144
   .9200              .5000              .7000              .9093              ..D191
   .9300              .2000             0.0000              .9236              ^0025
   .9300              .2000              .3000              .9236              .0035
   .9300              .2000              .5000              .9236              .0044
   .9300              .2000              .7000              .9286              .0059
   .9300              .3000             0-0000              -9263              .0041
   .9300              .3000              .3000              .9253              .0055
   .9300              .3000               5000              .3253              .0068
   .9300              .3000              .7000              .9268              .0092
   .9300              .4000             C 0000              .9242              .0053
   .9300              .4000              .3000              -9242              .0076
   .9300              .4000               5COO               9242              .0095
   .9300              -4000              .7000              -9242              .0127
   .9300              .5000             0.0000               9207              .00.77
   .9300              .5000              .3000              .9207              .0101
   .9300              .5000              .5000              .9207              .0125
   .9300              .5000              .7000              .9207              .0167
   .9400              .2000             0.0000              .9338              .0023
   .3400              .2000              .3000        -      .9333              .0030
   .9400              .2000              .5000              .9333              .0038
   .9^00              .2000               7000              .9388              .0051
   .9400              .3030             O.COOO              .9372              .0035
   .9400              .3000              .3000              .9372              .0047
   .9400              .3000              .5000              .9372              .0059
   .94CO              .3000              .7000              .9372              .0073
   .9400              . 4COC             O.OCOO               9350              .CC49
   .9400              .4000              .3000              .9350              .C065
   .9400              .4000               5000              .9350              .0082
   .iOO              .4CCO              .7000              .9350              .0109
   .9400              .5CCO             O.OOCO              .9320              .0066
   .9400              .5000              .3CCO              .9320              .0087
     94CO              .5000              .5CCO              .9320              ,0108
   .9*100              .5000              .7000              .9320              .0143

-------
                                 />2-9
     Additional analyses not easily  presented  in  tabular form addressed
the shape of the distribution of  the  thirty-day rolling  averages.
Questions had been raised  about whether  these  averages would be distrib-
uted normally.  The distribution  was  found  to  be  very nearly,  although
not exactly, normal.  Although the averages were  much more  nearly  normal
than the approximately lognormal  daily measurements, all  of the analyses
took account of the remaining non-normal ity; no results  were based on
normal  approximations.
     The data in exhibit 2-1 was  presented  in  terms  of facility operating
parameters which were simply chosen  to sample  the region of greatest
interest.  The actual values of the  basic process parameters are avail-
able for some experiments  at specific facilities.  Exhibit  2-2 shows the
parameters describing the  processes  at these facilities.  The .^tual
statistical analysis of the data  to  produce these estimates of the
parameters is described in chapter 3.0.  Exhibit  2-3 shows  the means and
standard deviations of thirty-day average efficiency observations  which
would be expected if a new facility  with a  92  percent geometric mean
efficiency had the same operating conditions (process variability  and
autocorrelation) as with each of  the  individual existing facilities.
     As can be seen in these exhibits, there is considerable variation
among the results at the individual  sites.   There cannot be a strictly
statistical decision as the degree to which any particular  site repre-
sents good engineering and ooerating  practices, state-of-the-art systems,
wall-calibrated and maintained measuring equipment,  and  otherwise  is
appropriate for use in extrapolations to future facilities.  Any analyses
of these issues must be made by engineers rather  than statisticians.
Accordingly, the remaining analyses  of the  behavior  of the  thirty-day

-------
                            2-10
     EXHIBIT 2-2:   PROCESS  PARAMETERS  OF  ACTUAL  FACILITIES
      Unit
Louisville North
Louisville South
Pittsburgh I
Pittsburgh II
Philadelphia
Chicago
Shawnee TCA
Shawnee Venturi
Conesville A
Conesville B
Lawrence
Geometric
Mean
84.4
83.3
80.8
85.4
97.0
89.2
88.5
96.0
86.0
92.5
95.4
Geometric
Standard
Deviation
.295
.343
.234
.212
.359
.118
.182
.368
.447
.474
.835
Auto-
Correlation
.6955
.6949
.4683
-.1428
.2524
.6983'
.5995
.8897
.7131
.6255
.6386

-------
                                       2-n
            EXHIBIT 2-3: THIRTY-DAY AVERAGE MEAN AND STANDARD
                         DEVIATION FOR 92%-EFFICIENT FACILITIES WITH
                         VARIABILITY AND AUTOCORRELATION OF ACTUAL
                         FACILITIES

                                                             Standard
Variability and                                 Mean         Deviation
Autocorrelation
from:              Louisville North            91.64%          1.03%

                   Louisville South            91.52%          1.22%

                   Pittsburgh I                91.78%          0.57%

                   Pittsburgh II               91.82%          0.32%

                   Philadelphia                91.47%          0.73%

                   Chicago                     91.94%          0.39%'

                   Shawnee TCA                 91.87%          0.52%

                   Shawnee Venturi             91.44%          2.05%

                   Conesville A                91.16%          1.66%

                   Conesville B                91.05%          1.48%

                   Lawrence                    88.70%          3.702

-------
                                   2-12
average processes will continue to be presented, as was the initial



material in exhibit 2-1, in general parametric terms.  The appropriate



cases from these parametric results may then be selected by engineers to



be used in any further analyses.



     In using the parametric results, it may be aopropriate to  examine



the expected behavior of processes with one or more parameters  equal  to



those of specific existing facilities (as was done in  generating  exhibit



2-3), or to consider the fact that the measurements from existing



facilities are from finite, and generally fairly limited, data  samples,



and to consider the possible errors in estimation which may be  present.



When this second technique is used, it may be of interest to  know that



the  Shawnee TCA and Pittsburgh II (taken together, assuming  that their



true long-run levels of variability are identical as the data suggests)



have a 95 percent confidence interval on the long-run  geometric  standard



deviation running from 0.16 to 0.23, and that Lousiville North  and South



taken together have a 95 percent confidence interval from 0.29  to 0.36.



(The corresponding 99 percent intervals are from 0.15  to 0.25 for Shawnee



TCA and Pittsburgh II and 0.28 to 0.38 for the Louisville facilities.)



     Exhibit 2-4 shows the rate (in occurrences per 360-day year) at



which 30-day averages of efficiency computed daily would fail to  meet a



threshold level of 90 percent efficiency for a facility with, an  actual



efficiency level of 92 percent* and variability parameters as shown.



Each estimated rate is shown with an associated standard error  of



estimate in parentheses.  These estimates are for a facility  with a



lognormal distribution of emissivity.  Facilities with high values of
^Corresponding to a  geometric mean  emissivity  of  eight  percent.

-------
G
E
0
M
                                     X'2-13


              EXHIBIT 2-4:   FREQUENCY  OF  OCCURENCE (OCCASIONS PER YEAR)
                            OF  BELOW - 9Q% AVERAGES IN A 92% EFFICIENT
                            FACILITY WITH LOGMORMAL OBSERVATIONS

                                      PROCESS AUTOCORRELATION

                      0               0.3             '  0.5               0.7
                  0.0               0.002  (.002)     0.189  (.031)     2.514  (.095)
T
R
I
C      .          0.320  (.0215)    2.670  (.0865)    9.900  (.332)    25.045  (.77UL;
       0

D
A
I
L   				
Y

V
A
R      ,         10.233  (.180)    26.3935 (.186)    41.2375 (.3975)   62.4455 (.736b)
I     '4
A
S
I
L   			
I
T
Y

                 52.241  (.2655)   72.1565 (.3950)   87.608  (.5515)  102.496  1.9325)
                                     Lognormal distribution.
                                     Figures  in parentheses are standard errors.

-------
                                 J) 2-14






either variability (40 percent or greater) or day-to-day correlation  (0.7


or greater) would be expected to fail to meet the threshold more than one


time per year, with facilities with high values of both variability and



correlation failing to meet the threshold for major fractions of their


operating days.


     Exhibit 2-5 shows a comparison of these results with those which



would be expected on similar facilities where the variability of the


emissivity was normal^  rather than lognormal.  As can be seen in  the


exhibit, the pattern of dependency between the plant operating parameters



and the rate at which the threshold is not met remains essentially the


same.  That is, the rate of threshold failures does not depend in  any


major way on the shape of the statistical distribution of the


observations (within the general area of reasonability).



     Exhibit 2-6 shows the expected rate at which thirty-day averages
                                                                 s

below thresholds other than 90 percent would occur for various



variability and correlation parameters.  Exhibits 2-7 through 2-9  show


this same information for geometric mean emissivities other than eight


percent (corresponding to more or less efficient facilities).  All  of


these exhibits were derived using the lognormal distribution of emis-


sivity observations; rates of threshold  failure for the normal case


differ by only small amounts, just as in the 92 percent-efficient  cases.



     Exhibits 2-10 through 2-13  show the efficiency levels  (1.00 -



geometric mean emissivities) at which facilities with various variability


and correlation parameters would maintain a rate of threshold failure no



higher than one per year (with rolling averages computed daily).   These
^Truncated at 0 efficiency.

-------
EXHIBIT 2-5:
          D 2-15

FREQUENCY OF OCCURENCE (OCCASIONS  PER  YEAR)  OF
BELOW-90% AVERAGES IN A 92% EFFICIENT  FACILITY
WITH NORMAL OR LOGNORMAL OBSERVATIONS
                         PROCESS  AUTOCORRELATION

                         0.3                0.5
                                               0.7




G
c
0
VI
E
T
R
I.
/
.3

0
A
I
i
L
Y
V
A
R 4
I
A
B
T
I
L   -^_
*
T
Y
Lognormal :
0.0 0.002 (.002)
Normal :
0.0 0.009







Lognormal :
0.320 (.0215) 2.670 (.0865)
Normal :
0.090 1.639






Lognormal :
10.233 (.180) 26.3935 (.186)
Normal :
7.742 22.777






1 	 	 . 	 T .

0.189 (.031) 2.514 -(-095)

0.051 1.206








9.900 (.332) 25.045 (.7705}

6.678 ?1.403







41.2375 (.3975) 62.4*55 (.7365)

39.689 64.527






_
Lognormal:
   52.241   (.2555)    72.1565  (.3950)    87.608  (.5515)  102.496  1.9325)

Normal:
   52.051
       75.^49
92.764
112.50
                               Lognormal  distribution cases  above
                                  normal  cases.

                               Figures  in parentheses are  standard
                                  errors.

-------
                                      2-16
             EXHIBIT  2-6:  FREQUENCY OF OCCURENCE (OCCASIONS PER YEAR) OF
                          BELOW-THRESHOLD AVERAGES IN A 92% EFFICIENT FACILITY

                          (with standard errors in parentheses)
                                     PROCESS AUTOCORRELATION
0
M
E
I
R
r
c

0
A
I
L
Y

V
A
R
I
A
3
I
L
I
T
Y

30-day u
30-day a
eff<90%

'2 " <88%
" <37%
11 <36%
" <35%
30-day u
30-day a
eff<90%
, ' <89%
1 
-------
                                       2-17
             EXHIBIT 2-7:
FREQUENCY OF OCCURENCE (OCCASIONS PER YEAR)  OF
BELOW-THRESHOLD AVERAGES IN A 94% EFFICIENT FACILITY

(with standard errors in parentheses)
                                      PROCESS AUTOCORRELATION
G
E
0
M
E
I
a
i
c

Q
A
I
L
Y

V
A
R
I
A
3
I
L
I
T
Y

30-day u
30-clay a
eff<30r0
5 " <89%
'< " <38%
11 <37%
11 <86S
11 <85%
30-day u
30-day cr
eff<90%
., " <39%
<0 " 
-------
                                       2-18
EXHIBIT 2-8:
G

0
M
E
I
R
I
C

0
A
I
L
Y

V
A
R
I
A
3
I
L
I
T
Y
                           FREQUENCY OF OCCURENCE (OCCASIONS PER YEAR) OF
                           BELOi-I-THRESHOLD AVERAGES IN A 93% EFFICIENT FACILITY
                           (with standard errors In parentheses)

                                      PROCESS AUTOCORRELATION

30-day u
30-day a
eff<90%
7 " <89%
* " <88%
" <37W0
" 
-------
                                     >2-19
             EXHIBIT 2-9:
FREQUENCY OF OCCURENCE (OCCASIONS PER YEAR)  OF
BELOW-THRESHOLD AVERAGES IN A 91% EFFICIEN,  FACILITY

(with standard  errors  in  parentheses)
                                      PROCESS AUTOCORRELATION
G
E
0
M

T
R
I
C

0
A
r
L
Y

V
A
R
I
A
8
I
L
I
T
Y

30-day u
30-day a
eff<90
2 " <89%

11 
-------
                                   />2-20
      EXHIBIT 2-10:
MINIMUM GEOMETRIC  MEAN  EFFICIENCIES REQUIRED
TO MAINTAIN NO MORE  THAN  ONE  FAILURE PER YEAR
Daily
Std. Dev.
(in log)
.20
.21
.22
.23
.24
.25
.26
.27
.28
.29
.30
.31
.32
.33
.34
.35
.36
.37
.38
.39
.40
.41
.42
.43
.44
.45
.46
.47
.48
.49
.50
.51
.52
.53
.54
.55
.56
.57
.58
.59
.50
Std. Dev.
of 30-Day
Average'
(.0054)
(.0057)
(.0060)
(.0063)
(.0065)
(.0068)
(.0071)
(.0074)
(.0077)
(.0080)
(.0083)
(.0087)
(.0090)
(.0093)
(.0096)
(.0099)
(.0103)
(.0106)
(.0109)
(.0113)
(.0116)
(.0119)
(.0123)
(.0127)
(.0130)
(.0134)
(.0138)
(.0141)
(-.0145)
(.0149)
(.0153)
(.0157)
(.0161)
(.0165)
(.0169)
(.0174)
(.0178)
(.0182)
(.0187)
(.0192)
(.0196)
                                   Minimum Efficiency
                                   For Threshold Shown
<90%

 91.8
 91.9
 92.0
 92.1
 92.1
 92
 92
 92
 92
 92
                           92.6
                           92.7
                           92.8
                           92.9
                           93.0
                           93.1
                           93.1
                           93.
                           93.
                           93.4
                           93.6
                           93.6
                           93.7
                           93.8
                           93.9
                           94.0
                           94.0
                           94.
                           94.
                           94.
                           94.
                           94.
                           94.
                           94.6
                           94.7
                           94.7
                           94.8
                           94.9
                           95.0
                           95.0
                                 91.0
                                 91
                                 91
                                 91
                                 91
                                 91
                                 91
                                 91
                                 91
                1
               ,2
               ,3
               ,4
                4
               ,5
               ,5
               ,7
             91.8
             91.9
             92.0
             92.1
             92.2
             92.3
             92.4
             92.
             92.
             92.
             92.
             92.9
             93.0
             93.1
             93.2
             93.3
             93.4
             93.4
             93.5
             93.6
             93.7
             93.8
             93.9
             94.0
             94.0
             94.1
             94.2
             94.3
             94.4
             94.5
             94.5
<88%

90.1
90.3
90.4
90.5
90.6
90.7
90.8
90.9
91.0
91.1
91.2
91.3
91.4
91.5
91.6
91.7
91.8
91.9
92.0
92.1
                           93.5  92.8  92.2
92.
92.
92.
92.
92.
92.8
92.8
92.9
93.0
93.1
93
93
               .2
               ,3
93.4
93.
93.
93.
93.8
93.9
93.9
94.0
      89.3
      89.4
      89.6
      89.7
      89.8
      89.9
      90.0
      90.1
      90.2
      90.3
      90.4
      90.6
      90.7
      90.8
      90.9
      91.0
                   91.
                   91,
                   91.
                   91,
                   91.
                   91.
                   91,
91.8
91.9
92.0
92.1
92.2
92.4
92.5
92.6
92.7
92.8
92.9
93.0
                   93.
                   93.
                   93.
                   93.
                                                   <86%   <85%
88.5
88.6
88.7
88.9
89.0
89.1
89.2
89.4
89.5
89.6
89.7
89.8
89.9
90.1
90
90
90
90
90.6
90.8
90.9
91.0
91.1
91.2
91.3
        ,2
        .3
         4
         5
                         91.4
                         91.
                         91.
                         91.8
                         91.9
                         92.0
92.
92.
92.3
92.4
92,5
92.6
92.7
92.3
                   93.4   92-9
                   93.5   93.0
87.7
87.8
87.9
88.1
88.2
88.3
88. b
88.6
88.7
83.8
89.0
89.1
89.2
89.4
89.5
89.6
89.7
89.8
90.0
90.1
90.2
90.3
90.5
90.6
90.7
90.8
90.
91.
91.
91.
91.
91.
91.
91.8
91.9
92.0
92.1
                    ,9
                    ,1
                    ,2
                    ,3
                    ,4
                    ,5
                    ,6
            92.2
            92.3
            92.4
            92.5
                                      Facility autocorrelation = 0.55
T
 In computing the 30-day average  variability, a geometric mean emission
 level of 92% was assumed.

-------
                                   2-21
  EXHIBIT 2-11:
Daily
Std. Dev.
(in log)
.20
.21
.22
.23
.24
.25
.26
.27
.28
.29
.30
.31
.32
.33
.34
.35
.36
.37
.38
.39
.40
,41
.42
.43
.44
.45
.46
.47
.48
.49
.50
.51
.52
.53
.54
.55
.56
.57
.58
.59
.60
Std. Dev.
of 30-Day
Average'
(.0058)
(.0061)
(.0064)
(,0067)
(.0070)
(.0073)
(.0076)
(.0080)
(.0083)
(.0086)
(.0089)
(.0093)
(.0096)
(.0099)
(-0103)
(-0106)
(.0110)
(.0113)
( 0117)
(.0121)
(.0124)
( 0128)
(.0132)
.0135)
(.0139)
(.0143)
(.0147)
(.0151)
(.0155)
(.0159)
(.0164)
(.0168)
(.0172)
(.0177)
(.0181)
(.0136)
(.0190)
(.0195)
(.0200)
(.0205)
(.0210)
MINIMUM GEOMETRIC MEAN  EFFICIENCIES REQUIRED
TO MAINTAIN MO MORE THAN  ONE  FAILURE PER YEAR
                           Minimum Efficiency
                           For Threshold Shown
          <90%  <89%  <88%
                           91.9
                           92.0
                           92.1
                           92.
                           92.
                           92.
                           92.
                           92.
            ,2
            ,3
            ,3
            ,4
            ,5
                           92.6
                           92.7
                           92.8
                           92.9
                           93.0
                           93.0
                           93.1
                           93.2
                           93.3
                           93-4
                           93.5
                           93.6
                           93.6
                           93.7
                           93.8
                           93.9
                           94.0
                           94.0
                           94.1
                           94
                           94
                           94
                           94
                           94
                           94
                           94
                           94.8
                           94.8
                           94.9
                           95.0
                           95.1
                           95.1
                           95.2
                91.1
                91,
                91.
91.4
91
91
91
91.8
91.9
92.0
92.1
92
92
92
92.4
92.5
92,6
92.7
92-8
92.9
93.0
                93.
                93.
                93,
                93.
                93.
                93.
                93.6
                93.7
                93.8
                93.9
                94.0
                94.
                94.
                94,
                94.3
                94.4
                94.5
                94.6
                94.6
                94.7
90.3
90.4
90.5
90.6
90.7
90.8
90.9
91.0
91.1
91.2
91.3
91.4
91.5
91.7
91 8
91.9
92.0
92.1
92.
92,
92.4
92.5
92.6
92.7
92.8
92.9
92.9
93.0
                        .2
                         3
      93
      93
      93
      93
      93
      93
      93
      93.8
      93.9
      94.0
      94.1
      94.2
      94.2
89.5
89.6
89.7
89.8
89.9
90.0
90.2
90.3
90.4
90.5
90.6
90.7
90.8
91.0
91.1
91-2
91 3
91.4
91.5
91.6
91.7
91 8
91.9
92.0
            92.
            92.
            92.
            92.
      92.6
      92.7
      92.8
      92.9
      93.0
      93.
      93.
      93.
      93.
      93.
      93.
      93.
      93.3
                                                  <86%   <85%
88.6
88.8
88.9
89.0
89.2
89.3
89.4
89.5
89.7
89.8
89.9
90.0
90
90
90
90
90
90-7
90.9
91.0
91-1
91-2
91.3
91.4
91.5
91.7
91.8
91.9
92.0
      92
      92
      92
      92
      92
      92
      92.3
      92.9
      93.0
      93.1
      93.2
      93.3
87.8
88.0
88.1
88.2
88.4
88.5
88.6
88.8
38.9
89.0
89.2
89.3
89.4
89-6
89.7
89.8
89-9
90.1
90.2
90.3
90.5
90 6
90.7
90.8
90.
91.
91.
91.
91.
91.
91.
      91.8
      91.9
      92.0
      92.1
      92.2
      92.4
      92.
      92.
      92.
      92.3
                                     Facility autocorrelation =  0.60
1
 In computing  the  30-day average variability, a geometric mean  emission
 level  of 92?i  was  assumed.

-------
   EXHIBIT 2-12:
MINIMUM GEOMETRIC  MEAN  EFFICIENCIES REQUIRED
TO MAINTAIN NO MORE  THAU  ONE FAILURE PER YEAR
Daily
Std. Dev.
(in log)
.20
.21
.22
.23
.24
.25
.26
.27
.28
.29
.30
.31
.32
.33
.34
.35
.36
.37
.33
.39
.40
.41
.42
.43
.44
.45
.45
.47
.48
.49
.50
.51
.52
.53
.54
. 55
.56
. 57"
.53
.59
.60
Std. Dev.
of 30-Day
Average'
(.0052)
(.0066)
(.0069)
(.0072)
(.0076)
(.0079)
(.0082)
(.0086)
(.0039)
(.0093)
(.0096)
(.0100)
(.0104)
(.0107)
(.0111)
(.0115)
(.0118)
(.0122)
(.0126)
(.0130)
(.0134)
(.0138)
(.0142)
(.0146)
(.0150)
(.0154)
(.0159)
(.0163)
(.0167)
(.0172)
(.0176)
(.0181)
(.0185)
(.0190)
(.0195)
(.0200)
(.0205)
(.0210)
(.0215)
(.0220)
(.0226)
                                 Minimum Efficiency
                                 For Threshold  Shown
                           <90%  <89%
                           92.0
                           92.
                           92.
                           92.
                           92.
                           92.
                           92.
                           92.
                           92.8
                           92.8
                           92.9
                           93.0
                           93
                           93
                           93
                           93
                           93
                           93.6
                           93.6
                           93.7
                           93.8
                           93.9
                           94.0
                           94.1
                           94.
                           94.
                           94.
            .1
            ,2
             3
                           94.4
                           94.5
                           94.5
                           94.5
                           94.7
                           94.8
                           94.
                           94.
                           95,0
                           95.1
                           95.2
                           95.2
                           95.3
                           95.4
            ,9
            ,9
                91.
                91,
                91.4
                91.5
                91.6
                91.7
                91.8
                91.9
                92.0
                  ,1
                  ,2
                  ,3
                  ,4
                  ,5
92.
92.
92.
92.
92.
92.6
92.7
92.8
92.9
93.0
93.1
                  ,2
                  ,3
                  ,4
                  ,5
93.
93.
93.
93.
93.6
93.7
93.7
93.8
93.9
94.0
94.
94.
94.
94.
94.4
94.5
94.6
94.7
94.8
94.9
94.9
90.4
90.5
90.6
90.8
90.9
91.0
91.1
91.2
91.3
91.4
91.5
91.6
91.7
91.8
92.0
92.1
92.
92.
92.
92.
92.6
92.7
92.8
92.9
93.0
93.1
93.2
93.3
                         2
                        ,3
                        ,4
                         5
93.4
93.5
93.6
93.7
93.7
93.8
93.9
94.0
94.1
9^.2
94.3
94.4
94.5
89.6
89.7
89.9
90.0
90.1
90.2
90.3
90.5
90,6
90.7
90.8
90.9
91.1
91.2
91.3
91.4
91.5
91.6
91.7
91.8
92.0
92.1
92
92
92
92
92
92
92.8
92.9
93.0
                            93.
                            93.
   ,4
   .5
93.
93.
93.6
93.7
93.3
93.9
94.0
                                 <86%   <85%
      88.8
      88.9
      89.1
      89.2
      89.3
      89.5
      89.6
      89.7
      89.9
      90.0
      90.1
      90.2
      90.4
      90.5
      90.6
      90.7
      90.9
      91.0
      91.1
      91.2
      91.3
      91.5
      91.6
      91.7
      91.8
      91.9
      92.0
      92.1
      92.3
      92.4
      92.
      92.
      92.
93.3  92.8
                                  93.5
                                  93.6
      88.0
      88.2
      88.3
      88.4
      88.6
      88.7
      88.9
      89.0
      89.1
      89.3
      89.4
      89.5
      89.7
      89.8
      89.9
     90.1
      90.2
      90.3
      90.5
      90.6
      90.7
      90.8
      91.0
      91
      91
      91
      91
      91
      91.7
      91.8
      91
      92
      92
      92
                                        92.5
92.9  92.4
93.0
93.1
93.2
93.3
            92.6
            92.8
            92.9
            93.0
            93.1
                                     Facility autocorrelation  =  0.65
1
 In computing  the 30-day  average variability, a geometric  mean  emission
 level  of 92/j  was assumed.

-------
                                /) 2-23
  EXHIBIT  2-13:
MINIMUM GEOMETRIC MEAN EFFICIENCIES REQUIRED
TO MAINTAIN NO MORE THAN ONE FAILURE PER YEAR
Daily
Std. Dev.
(in log)
.20
.21
.22
.23
.24
.25
.26
.27
.28
.29
.30
.31
.32
.33
.34
.35
.36
.37
.33
.39
.40
.41
.42
.43
.44
.45
.46
.47
.48
.49
.50
.51
.52
.53
.54
.55
. 56
.57
.53
.59
.60
Std. Dev.
of 30-Day
Average'
 (.0068)
(.0071)
(.0075)
(.0079)
(=0082)
(.0086)
(.0090)
(.0093)
(.0097)
(.0101)
(.0105)
(.0109)
(.0112)
(.0116)
(.0120)
(.0124)
(.0128)
(.0133)
(.0137)
(.0141)
(.0145)
(.0150)
(.0154)
(.0158)
(.0163)
(.0167)
(.0172)
(.0177)
(.0182)
(.0186)
 (.0191)
(.0196)
(.0201)
(.0206)
(.0212)
(.0217)
(.0222^
(.0228^
(.0233)
(.0239)
(.0245)
Minimum Efficiency
For Threshold Shown
<90%
92.2
92.3
92.3
92.4
92.5
92.6
92.7
92.8
92.9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.7
93.3
93.8
93.9
94.0
94.1
94.2
94.3
94.4
94.4
94.5
94.6
94.7
94.8
94.9
94.9
95.0
95.1
95.2
95.2
95.3
95.4
95.5
95.5
95.6
<89%
91.4
91.5
91.6
91.7
91.8
91.9
92.0
92.1
92.2
92.3
92.4
92.5
92.6
92.7
92.8
92.9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.7
93.8
93.9
94.0
94.1
94.2
94.2
94.3
94,4
94.5
94.6
94.7
94.8
94.9
94.9
95.0
95.1
95.2
<88%
90.6
90.7
90.8
90.9
91.1
91.2
91.3
91.4
91.5
91.6
91.7
91.9
92.0
92.1
92.2
92.3
92.4
92.5
92.6
92.7
92-8
92.9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.7
93.8
93.9
94.0
94.1
94.2
94.3
94.4
94. 5
94.5
94.7
94.7
<87%
89.8
89.9
90.1
90.2
90.3
90.4
90.6
90.7
90.8
90.9
91.1
91.2
91.3
91.4
91.5
91.6
91.8
91.9
92.0
92.1
92.2
92.3
92.4
92.6
92.7
92.8
92 9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.7
93.8
93.9
94.0
9^. 1
9^.2
94.3
<86%
89.0
89.2
89.3
89.4
89.6
89.7
89.8
90.0
90.1
90.2
90.4
90.5
90.6
90.8
90.9
91.0
91.1
91.3
91.4
91.5
91.6
91.7
91 9
92.0
92.1
92.2
92.3
92.5
92.6
92.7
92.8
92.9
93.0
93.1
93.2
93.3
93.4
93.5
93.7
93.8
93.9
<85%
88.2
88.4
88.5
88.7
88.8
89,0
89.1
89.3
89.4
89.5
89.7
89.8
90.0
90.1
90.2
90.4
90.5
90.6
90.8
90.9
91.0
91.2
91.3
91.4
91 5
91.7
91.8
91.9
92.0
92.2
92.3
92.4
92.5
92.6
92.7
92.9
93.0
93.1
93.2
93.3
93.4
                                     Facility autocorrelation = 0.70

In computing the 30-day average variability,  a geometric mean emission
level  of 92" was assumed.

-------
minimum efficiency critical values are accurate to within at least 0.2

percent (two tenths of one percent).  Exhibits 2-14 througn 2-25 show

similar data for threshold failure rates of one per two years, one per

five years, and one per ten years.  (Given the randomness of the process,

there is no set of operating conditions that can achieve a true zero rate

of failure; some failures will occur  randomly under any conditions.)

     Policies in which averages are computed less frequently than daily,

but are still thirty-day averages  for the last thirty-days at  the time  of

computation (for example, averages computed weekly or monthly) would, of

course, result in fewer threshold  failures per year for all  facilities,

whether or not operated in accordance with good practice, simply because

there would be fewer occasions per year on which failures could occur.

The effect on the rate of  failures per year is, in fact, exactly

proportional to the frequency of  computation of the average.^  Thus,  if
                                                                 ^

weekly averaging were used,  in which  a  thirty-day average was  computed

for the thirty-day period  ending,  for example, on each  Friday,  the  rate

of threshold failures per year for any  set of operating parameters would
                                                                        *
simply be one-seventh of that shown  in  the preceding  exhibits.   If

averages are computed once every  thirty days, the rate  of  failures  per

year would be one-thirtieth  of that  in  the exhibits,  etc.  The exhibited

critical operating levels  at which  one  failure per year would  occur,  of

course, no longer apply  if the frequency  of  average computation  is

changed.
     s  fact  can  be  proven  completely mathematically for all  the pro-
  cesses  considered here,  whether involving the normal, lognormal,  or
  other distribution.   Somewhat in violation of intuition, the proposition
  remains true  no matter what the correlation structure of the daily
  observations.

-------
                         P2-25

   EXHIBIT  2-14:  MINIMUM GEOMETRIC MEAN  EFFICIENCIES REQUIRED TO
                 MAINTAIN NO MORE THAN ONE  FAILURE PER TWO YEARS
 Daily        Std. Dev.           Minimum Efficiency
Std.  Oev.      of 30-Day           For Threshold Shown
(in log)       Average^
                                 <89%  <88%   <87%  <86%   <85eS
   .20        (.0054)       91.9  91.1  90.3  89.5  88.7  87.9
   .21        (.0057)       92.0  91.2  90.4  89.6  88.8  88.0
   .22        (.0060)       92.1  91.3  90.5  89.7  83.9  38.1
   .23        (.0063)       92.2  91.4  90.6  89.3  89.0  88.3
   .24        (.0065)       92.3  91.5  90.7  89.9  89.2  88.4
   .25        (.0068)       92.4  91.6  90.8  90.1  89.3  88.5
   .26        (.0071)       92.4  91.7  90. 9  90.2  89.4  88.7
   .27        (.0074)       92,5  91.8  91.0  90-3  89.5  88.8
   .28        (.0077)       92.6  91.9  91.1  90.4  89.7  88.9
   .29        (.0080)       92,7.92.0  912  90.5  89.8  89.1
   .30        (.0083)       92.8  92.1  91.4  90.6  89.9  89.2
   ,31        (.0087)       92.9  92.2  91 5  90.7  90.0  89.3
   .32        (.0090)       93.0  92.3  91.6  90.9  90.2  89.5
   .33        (.0093)       93.1  92.4  91.7  91.0  90.3  89.6
   .34        (.0096)       93.1  92.5  91.8  91.1  90.4  89.7
   .35        (.0099)       93.2  92.5  91.9  91.2  90.5  89.3
   .36        (.0103)       93,3  92.6  92.0 '91. 3  90.6  90.0
   .37        (.0106)       93.4  92.7  92.1  91.4  90.3  90.1
   .38        (.0109)       93.5  92.8  92.2  91.5  90.9  90.2
   .39        (.0113)       93.6  92.9  92.3  91.6  91.0  90.3
   .40        (.0116)       93.6  93.0  92.4  91.7  91.1  90. 5
   .41        (.0119)       93.7  93.1  92.5  91.8  91.2  90.6
   .42        (.0123)       93.8  93.2  92-5  92.0  91.3  90.7
   .43        (.0127)       93.9  93.3  92.7  92.1  91.4  90.8
   .44        (.0130)       94.0  93.4  92.8  92.2  91.6  91.0
   .45        (.0134)       94.1  93.5  92.9  92.3  91.7  91.1
   .46        (.0138)       94.1  93.5  93.0  92.4  91.3  91.2 
   .47        (.0141)       94.2  93.6  93.1  92.5  91.9  91.3
   .48        (.0145)       94.3  93.7  93.2  92.6  92.0  91.4
   .49        (.0149)       94,4  93.8  93.3  92.7  92.1  91.5
   .50        (.0153)       94.5  93.9  93.3  92.8  92.2  91.7
   .51        (.0157)       94.5  94.0  93. 4  92,9  92.3  91.8
   .52        (.0161)       94.6  94.1  93.5  93.0  92.5  91.9
   .53        (.0165)       94.7  94.2  93.6  93.1  92.6  92.0
   .54        (.0169)       94.8  94.2  93.7  93.2  92.7  92.1
   .55        (.0174)       94.8  94.3  93.8  93.3  92.8  92.3
   .56        (.0178)       94.9  94.4  93.9  93.4  92.9  92.4
   .57        (.0132)       95.0  94,5  9^.0  93.5  93.0  92,5
   .53        (.0187)       95.1  94 6  94.1  93.6  93.1  92.5
   .59        (.0192)       95.1  94.7  94.2  93,7  93.2  92.7
   .60        (.0196)       95.2  94.7  94.3  93.8  93.3  92.3

                                 Facility autocorrelation =0.55
 ln computing the 30-day average  variability, a geometric mean
 emission level  of 92% was  assumed.

-------
 EXHIBIT  2-15:
MINIMUM GEOMETRIC MEAN EFFICIENCIES REQUIRED  TO
MAINTAIN NO MORE THAN ONE FAILURE PER TWO YEARS
Daily
Std. Dev.
(in log)
.20
.21
.22
.23
.24
.25
.26
.27
.28
.29
.30
.31
.32
.33
.34
.35
.36
.37
.38
.39
.40
,41
.42
.43
.44
.45
.46
.47
.48
.49
.50
.51
.52
.53
.54
.55
.56
.57
.58
.59
.50
Std. Dev.
of 30 -Day
Average^
(.0058)
(.0061)
(.0064)
(.0067)
(.0070)
(.0073)
(.0076)
(.0080)
(.0033)
(.0086)
(.0089)
(.0093)
(.0096)
(.0099)
(.0103)
(.0106)
(.0110)
(.0113)
(.0117)
(.0121)
(.012-')
(.012":)
(.013',)
(.013:;
(.0139)
(.0143)
(.0147)
(.0151)
(.0155)
(.0159)
(.0164)
(.0168)
(.0172)
(.0177)
(.0181)
(.0186)
(.0190)
(.0195)
(.0200)
(.0205)
(.0210)
                                 Minimum Efficiency
                                 For Threshold Shovin

                           <90%  <89%  <88%  <87%  <86%   <85%
92.0
92.1
92.2
92.3
92.4
92.5
92.6
92.7
92.8
92.8
92.9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.6
93.7
93.8
93,9
94.0
94.1
94.1
94.2
94.3
94.4
94.5
94.5
94.6
94.7
94.8
94.9
94.9
95.0
95.1
95.2
95.2
95.3
95.4
91.2
91.3
91.4
91.5
91.6
91.7
91.8
91.0
92.0
92.1
92.2
92.3
92.4
92.5
92.6
92.7
92.8
92.9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.6
93.7
93.8
93.9
94.0
94.1
94.2
94.3
94.3
94.4
94.5
94.6
94.7
94.8
94.9
94.9
90.4
90.5
90.6
90.8
90.9
91.0
91.1
91.2
91.3
91.4
91.5
91.6
91.7
91.8
91.9
92.1
92.2
92.3
92.4
92.5
92.6
92.7
92.8
92.9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.6
93.7
93.8
93.9
94.0
94.1
94.2
94.3
94.4
94.5
89.6
89.7
89.9
90.0
90.1
90.2
90.3
90.5
90.6
90.7
90.8
90.9
91.0
91.2
91.3
91.4
91.5
91.6
91.7
91.8
92.0
92.1
92..:
92.2
92.4
92.5
92.6
92.7
92.8
92.9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.7
93.3
93.9
94.0
88.8
88.9
89.1
89.2
39.3
89.5
89.6
89.7
89.9
90.0
90.1
90.2
90.4
90.5
90.6
90.7
90.9
91.0
91.1
91.2
91.3
91.4'
91.6
91.7
91.8
91.9
92.0
92.1
92.3
92.4
92.5
92.6
92.7
92.8
92.9
93.0
93.1
93.2
93.3
93.4
93.5
88.0
88.2
88.3
38.4
88.6
88.7
88.9
89.0
39.1
89.3
89.4
89.5
39.7
89.8
39.9
90.1
90.2
90.3
90.5
90.6
90.7
90.8
91.0
91.1
91.2
91.3
91.5
91.6
91.7
91.8
91.9
92.1
92.2
92.3
92.4
92.5
92.6
92.8
92.9
93.0
93.1
                                 Facility autocorrelation =0.60
In computing the 30-day average variability, a geometric mean
emission level  of 92% was assumed.

-------
                          > 2-27


  EXHIBIT 2-15:  MINIMUM  GEOMETRIC  MEAN  EFFICIENCIES  REQUIRED TO
                 MAINTAIN  NO MORE THAN ONE  FAILURE  PER  TWO  YEARS
Daily
Std. Dev.
(in log)
Std. Dev.
of 30-Day
Average^
Minimum Efficiency
For Threshold Shown
<90%
.20
.21
.22
.23
,24
.25
.26
.27
.28
.29
.30
.31
.32
.33
.34
.35
.36
.37
.38
.39
.40
.41
.42
.43
.44
.45
.46
.47
.48
.49
.50
.51
.52
.53
,54
.55
.56
.57
.58
.59
.60
(.0062)
(.0066)
(.0069)
(.0072)
(.0076)
(.0079)
(.0082)
(.0086)
(.0039)
(.0093)
(.0096)
(.0100)
(.0104)
(.0107)
(.0111)
(.0115)
(.0118)
(.0122)
(.0126)
(.0130)
(.0134)
(.0138)
(.0142)
(.0146)
(.0150)
(.0154)
(.0159)
. (.0163)
(.0167)
(.0172)
(.0176)
(.0131)
(.0185)
(.0190)
(.0195)
(.0200)
(.0205)
(.0210)
(.0215)
(.0220)
(.0226)
92.
92.
92.
92.
92.
92.
92.
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
93.
93.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
95.
95!
95.
95.
95.
95.
95.
95.
95.
1
2
3
4
5
6
7
8
9
0
1
2
3
4
5
6
6
7
8
9
0
1
2
3
3
4
5
6
7
7
8
9
0
1
1
2
3
4
4
5
5
<89% <88%
91.
91.
91.
91.
91-
91.
92.
92.
92.
92.
92.
92.
92.
92.
92.
92,
93.
93.
93.
93.
93.
93.
93.
93.
93.
93.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
95.
95.
95.
3
5
6
7
8
9
0
1
2
f\
0
4
5
6
7
8
Q
6
1
2
3
4
5
6
7
8
9
0
0
1
2
3
4
5
6
7
7
8
9
0
1
2
90.
90.
90.
90.
91.
91.
91.
91.
91.
91.
91.
91.
91.
92.
92.
92.
92.
92.
92.
92.
92.
92.
93.
93.
93-
93.
93.
93.
93.
93.
93.
93.
94.
94.
94.
94.
94.
94.
94.
94.
94.
6
7
8
9
0
2
3
4
5
6
7
8
9
0
2
3
4
5
6
7
8
9
0
1
2
3
4
5
6
7
8
9
0
1
2
3
4
4
5
6
7
<87%
89.8
89.9
90.0
90.2
90.3
90.4
90.5
90.7
90.8
90.9
91.0
91.1
91.3
91.4
91.5
91.6
91.7
91.9
92.0
92.1
92.2
92.3
92.4
92.5
92.6
92.7
92.9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.7
93.8
93.9
94.0
94.1
94.2
94.3
<86% <85%
89.
89.
89.
89.
89.
89.
89.
89.
90.
90.
90.
90.
90.
90.
90.
91.
91.
91.
91.
91.
91.
91.
91.
92.
92.
92.
92.
92.
92.
92.
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
0
1
3
4
5
7
8
9
1
2
3
5
6
7
9
0
1
2
3
5
6
7
8
0
1
2
3
4
5
6
8
9
0
1
2
3
4
5
6
7
3
88.2
88.4
88.5
88.6
88.8
88.9
89.1
89.2
89.4
89.5
89.6
89.8
89.9
90.1
90.2
90.3
90.5
90.6
90.7
90.9
-91.0
91.1
91.2
91.4
91.5
91.6
91.8
91.9
92.0
92.1
92.2
92.4
92.5
92.6
92.7
92.8
92.9
93.1
93.2
93.3
93.4
                                 Facility autocorrelation =  0.65
ln computing the 30-
-------
                          2-28


   EXHIBIT 2-17:   MINIMUM GEOMETRIC MEAN EFFICIENCIES REQUIRED TO
                  MAINTAIN NO  MORE THAN ONE FAILURE PER TWO YEARS
Daily
Std. Dev.
(in log)

.20
.21
.22
.23
.24
.25
.26
.27
.23
.29
.30
.31
.32
.33
.34
.35
.36
.37
.33
.39
.40
.41
.42
.43
.44
.45
.46
.47
.48
.49
.50
.51
.52
.53
.54
.55
.56
.57
.58
.59
.60
Std. Dev.
of 30-Day
Average^

(.0063)
(.0071)
(.0075)
(.0079)
(.0082)
(.0086)
(.0090)
(.0093)
(.0097)
(.0101)
(.0105)
(.0109)
(.0112)
(.0116)
(.0120)
(.0124)
( 0128)
( 0133)
(.0137)
(.0141)
(.0145)
(.0150)
(.0154)
(.0158)
(.0163)
(.0167)
(.0172)
(.0177)
(.0182
(.0186)
(.0191)
(.0196)
(.0201)
(.0206)
(.0212)
(.0217)
(.0222)
(.0228)
(.0233)
(.0239)
(.0245)
Minimum Efficiency
For Threshold Shown
<90%
92.3
92.4
92.5
92.6
92.7
92.8
92.9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.7
93.8
93.9
93.9
94.0
94.1
94.2
94.3
94.4
94.5
94.6
94.6
94.7
94.8
94.9
95.0
95.1
95.1
95.2
95.3
95.4
95.4
95.5
95.6
95.7
95.7
95.8
<39%
91.5
91.6
91.7
91.9
92.0
92.1
92.2
92.3
92.4
92.5
92.6
92.7
92.8
92.9
93.0
93.1
93 2
93.3
93.4
93.5
93.6
93.7
93.8
93.9
94.0
94.1
94.2
94.3
94.4
94.5
94.6
94.6
94.7
94.8
94.9
95.0
95.1
95.2
95.2
95.3
95.4
<88%
90.7
90.9
91.0
91 1
91.2
91.4
91.5
91.6
91.7
91.8
91.9
92.1
92.2
92.3
92.4
92.5
92.6
92.7
92.8
92.9
93.1
93.2
93.3
93.4
93.5
93.6
93.7
93.8
93.9
94.0
94.1
94.2
94.3
94.3
94.4
94.5
94.6
94.7
S4.3
94.9
95. Q
<37%
90.0
90.1
90.2
90.4
90,5
90.6
90.8
90,9
91.0
91.1
91.3
91.4
91.5
91.6
91.8
91-9
"92 C
92.1
92.2
92.4
92.5
92,6
92.7
92.8
92.9
93.0
93.1
93.3
93.4
93.5
93.6
93.7
93.8
93.9
94.0
94.1
94.2
94.3
94.4
94.5
94.6
<86%
89.2
89.3
89.5
89.6
89.8
89.9
90.1
90.2
90.3
90.5
90.6
90.7
90.9
91.0
91.1
91,3
91 4
91.5
91.6
91.3
91.9
92.0
92.1
92.3
92.4
92.5
92.6
92.7
92.8
93.0
93. 1
93.2
93.3
93.4
93.5
93.6
93.7
93.8
93.9
94.0
94.2
<35%
88,4
88,6
83.7
88.9
89.0
89.2
39.3
89.5
89.6
89.8
89.9
90.1
90.2
90.4
90.5
90 6
90.8
90.9
91.0
91.2
"91.3
91.4
91.6
91.7
91.8
92.0
92.1
92.2
92.3
92.5
92.6
92.7
92.8
92.9
93.1
93.2
93.3
93.4
93.5
93.6
93.7
                                 Facility autocorrelation =  0.70
ln computing the 30-day average variability, a geometric mean
emission level  of 92% was assumed.

-------
                            2-29
   EXHIBIT 2-13:   MINIMUM  GEOMETRIC MEAN EFFICIENCIES REQUIRED TO
                  MAINTAIN  MO MORE THAN ONE FAILURE PER FIVE YEARS
 Daily        Std.  Oev.           Minimum Efficiency
Std.  Dev.      of 30-Day           For Threshold Shown
(in log)       Average^
                            <90%  <89%  <88%  
-------
                        O 2-30
  EXHIBIT  2-19:
MINIMUM GEOMETRIC MEAN EFFICIENCIES REQUIRED TO
MAINTAIN NO MORE THAN ONE FAILURE PER FIVE YEARS
                                 Minimum Efficiency
                                 For Threshold Shown

                           <90%  <89%  <88%   <37%  <86%   <85%
(.0058)
.0061
(.0064)
(.0067)
(.0070)
(.0073)
(.0076)
(.0080)
(.0083)
(.0086)
(.0089)
(.0093)
(.0096)
(,0099)
(.0103)
(.0106)
(.0110)
(.0113)
(.0117)
(.0121)
(.0124)
(.0128)
(.0132)
(.0135)
(.0139)
(.0143)
(.0147)
(.0151)
(.0155)
(.0159)
(.0164)
(.0168)
(.0172)
(.0177)
(.0181)
(.0186)
(.0190)
(.0195)
(.0200)
(.0205)
(.0210)
92.
92.
92.
92.
92.
92.
92.
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
93.
93.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
95.
95.
95.
95.
95.
95.
95.
95.
95.
2
3
4
5
6
6
7
8
9
0
1
2
3
4
5
6
7
8
9
9
0
1
2
3
4
4
5
6
7
8
9
9
0
1
2
2
3
4
5
5
6
91.
91.
91.
91.
91.
91.
92.
92.
92.
92.
92.
92.
92.
92.
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
93.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
95.
95.
95.
4
5
6
7
8
9
0
1
2
3
4
5
6
7
8
9
0
1
2
3
4
5
6
7
8
9
0
1
-\
3
3
4
5
6
7
8
9
g
0
1
2
90.
90.
90.
90.
91.
91.
91.
91.
91.
91.
91.
91.
92.
92.
92.
92.
92.
92.
92.
92.
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
93.
94.
94.
94.
94.
94.
94.
94.
94.
94.
6
7
8
9
i
2
3
4
5
6
8
9
0
1
2
O
4
5
6
7
8
9
0
1
2
3
4
5
6
7
8
9
0
1
2
3
4
K
5
7
3
89.
89.
90.
90.
90.
90.
90.
90.
90.
90.
91.
91.
91.
91.
91.
91,
91.
91.
92.
92.
92.
92.
92.
92.
92.
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
93.
94.
94.
94.
94.
8
a
1
2
3
4
6
7
8
9
1
2
3
4
5
7
8
9
0
1
r\
3
5
6
7
8
9
0
1
2
3
4
5
6
-7
8
9
0
1
2
3
89.
89.
89.
89.
89.
89.
89.
90.
90.
90.
90.
90.
90.
90.
90.
91.
91.
91.
91.
91.
91.
91.
91.
92.
92.
92.
92.
92.
92.
92.
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
0
2
3
4
6
7
8
0
1
2
4
5
6
8
9
0
1
3
4
5-
6
3
9
0
1
2
3
5
5
7
8
9
0
1
2
3
5
6
7
8
9
88.2
88.4
88.5
88.7
88.8
89.0
89.1
89.3
89.4
89.5
89.7
89.8
90.0
90.1
90.2
90.4
90.5
90.5
90.8
90.9
91.0
91.2
91.3
91.4
91.5
91.7
91.8
91.9
92.0
92.2
92.3
92.4
92.5
92.6
92.3
92.9
93.0
93.1
93.2
93.3
93.4
                                 Facility autocorrel ation = 0.60
ln computing the 30-day average variability, a geometric mean
emission level  of 92% was assumed.

-------
                         D  2-31
   EXHIBIT  2-20:  MINIMUM GEOMETRIC MEAN EFFICIENCIES REQUIRED TO
                 MAINTAIN NO MORE THAN ONE FAILURE PER FIVE  YEARS
 Daily        Std. Dev.           Minimum Efficiency
Std.  Dev.      of 30-Day           For Threshold  Shown
(in log)       Average^
                           <90%  <89%  <88%   <87%  <86%   <85%

   .20        (.0062)       92.3  91.5  90.8  90.0  89.2  88,4
   .21        (.0066)       92.4  91.6  90.9  90.i  89.4  88.6
   .22        (.0069)       92.5  91.8  91.0  90.3  39.5  88.8
   .23        (.0072)       92.6  91.9  91.1  90.4  89.6  88.9
   .24        (.0075)       92.7  92cO  91.2  90.5  89.8  89.1
   .25        (.0079)       92.8  92,1  91.4  90.6  89.9  89.2
   .26        (.0082)       92.9  92.2  91.5  90.8  90.1  89.4
   .27        (.0086)       93.0  92.3  91.6  90.9  90.2  89,5
   .28        (.0089)       93.1  92.4  91.7  91.0  9Q. 3  89.7
   .29        (.0093)       93.2  92.5  91.8  91.2  90.5  89.8
   .30        (.0096)       93.3  92.6  92.0  91.3  90.6  89.9
   .31        (.0100)       93.4  92.7  92.1  91.4  90.8  90.1
   .32        (.0104)       93.5  92.8  92.2  91.5  90.9  90.2
   .33        (.0107)       93.6  92.9  92.-  91.7  91.0  90.4
   .34        (.0111)       93.7  93.0  92.4  91.8  91.1  90.5
   .35        (.0115)       93.8  93.1  92.5  91.9  91.3  90.7
   .36        (.0118)       93.9  93.2  92.6  92.0  91.4  90.8
   .37        (.0122)       94.0  93.3  92.7  92.1  91.5  90.9
   .38        (.0126)       94.0  93.4  92.9  92.3  91.7  91.1
   .39        (.0130)       94.1  93.5  93.0  92.4  91.8  91.2
   .40        (.0134)       94.2  93.6  93.1  92.5  91.9  91.3
   .41        (.0138)       94.3  93.7  93,2  92.6  92.0  91.5
   .42        (.0142)       94.4  93.8  93.3  92.7  92.2  91.6
   .43        (.0146)       94.5  93.9  93.4  92.8  92.3  91.7
   .44        (.0150)       94.6  94.0  93.5  92.9  92.4  91.8
   .45        (.0154)       94.7  94.1  93.6  93.0  92.5  92.0
   .46        (.0159)       94.7  94.2  93.7  93.2  92.6  92.1  '
 '  .47        (.0163)       94.8  94.3  93.8  93.3  92.7  92.2
   .48        (.0167)       94.9  94.4  93.9  93.4  92.9  92.4
   .49        (.0172)       95.0  94.5  94.0  93.5  93.0  92.5
   .50        (.0176)       95.1  94.6  94.1  93.6  93.1  92.6
   .51        (.0181)       95.1  94.7  94.2  93.7  93.2  92.7
   .52        (.0185)       95.2  94.7  94.3  93.8  93.3  92.8
   .53        (.0190)       95.3  94.8  94.4  93.9  93.4  93.0
   .54        (.0195)       95.4  94.9  94.5  94.Q  93.5  93.1
   .55        (.0200)       95.5  95.0  94.5  94.1  93.6  93.2
   .56        (.0205)       95.5  95.1  94.5  94.2  93.7  93.3
   .57        (.0210)       95.6  95.2  94.7  94.3  93.9  93. J.
   .58        (.0215)       95.7  95.3  94.3  94.4  94.0  93.5
   .59        (.0220)       95.8  95.3  94.9  94.5  94.1  93.6
   .60        (.0226)       95.3  95.4  95.0  94.6  94.2  93.7

                                 Facility autocorrelation =  0.65
 In computing the 30-day average  variability, a geometric mean
 emission level  of 92% was  assumedl

-------
                           2-32
  EXHIBIT 2-21:
MIMIMUM GEOMETRIC MEAM EFFICIENCIES REQUIRED TO
MAINTAIN HO MORE THAN ONE FAILURE PER FIVE YEARS
                                 Minimum Efficiency
                                 For Threshold Shown
          <9Q7,  <89%
                                                           <85%
(.0063)
(.0071)
(.0075)
(.0079)
(.0082)
(.0086)
(.0090)
(.0093)
(.0097)
(.0101)
(.0105)
(.0109)
(.0112)
(.0116)
(.0120)
(.0124)
(.0128)
(.0133)
(.0137)
(.0141)
(.0145)
(.0150)
(.0154)
(.0158)
(.0163)
(.0167)
(.0172)
(.0177)
(.0182)
(.0186)
(.0191)
(.0196)
(.0201)
(.0206)
(.0212)
(.0217)
(.0222)
(.0228)
(.0233)
(.0239)
(.0245)
92.
92.
92.
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
93.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
94.
95.
95.
95.
95.
95.
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95.
95.
95.
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95.
96.
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4
6
7
8
9
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1
2
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6
7
8
Q
6
i
2
*>
4
4
5
6
7
8
9
0
1
1
2
3
4
5
r*
6
7
8
8
9
0
1
91.
91.
91.
92.
92.
92.
92.
92.
92,
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
93.
94.
94.
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94.
94.
94.
94.
94.
94.
94.
94.
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95.
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7
8
9
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2
3
4
5
6
7
8
0
i
2
3
4
5
6
7
8
9
0
1
2
3
4
5
6
6
7
8
9
0
1
2
3
3
4
5
6
~j
90.
91.
91.
91.
91.
91.
91.
91.
92.
92.
92.
92.
92.
92.
92.
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92.
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93.
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93.
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93.
93.
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9
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3
5
6
7
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2
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1
2
3
4
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8
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1
2
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5
5
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7
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6
1
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3
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90.
90.
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91.
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93,
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94.
94.
94.
94.
94.
94.
94.
2
3
5
6
7
9
0
2
3
4
5'
7
3
9
1
2
3
4
5
7
8
9
0
1
2
3
5
6
7
8
9
0
1
2
3
4
r-
6
7
8
9
89.
89.
89.
89.
90.
90.
90.
90.
90.
90.
90.
91.
91.
91.
91.
91.
91.
91.
92.
92.
92.
92.
92.
92.
92.
92.
93.
93.
93.
93.
93.
93.
93.
93.
93.
94.
94.
94.
94.
94.
94.
4
6
7
9
6
2
3
5
6
8
9
0
9
3
4
6
7
8
0
1
2
3
5
6
7
8
0
1
2
3
4
5
6
8
9
0
1
?
3
4
5
88.7
88.8
89.0
89.2
89.3
89.5
89.6
89.8
89.9
90.1
90.2
90.4
90.5
90.7
90.8
91.0
91.1
91.3
91.4
91.5
91.7
91.3
91.9
92.1
92.2
92.3
92.5
92.6
92.7
92.8
92.9
93.1
93.2
93.3
93.4
93.5
93.7
93.8
93.9
94.0
94.1
                                  Facility  autocorrelation =  0.70
In  computing  the  30-day  average  variability,  a  geometric  mean
emission  level  of 92" was  assumed.

-------
                        ^2-33
   EXHIBIT  2-22:  MINIMUM GEOMETRIC MEAN  EFFICIENCIES REQUIRED TO
                 MAINTAIN MO MORE THAN ONE FAILURE PER TEN YEARS
 Daily        Std. Dev.           Minimum Efficiency
Std.  Dev.      of 30-Day           For Threshold Shown
(in log)       Average^
                           <90%  <39%  <88%   <87%  <865   <85%
   .20        (.0054)       92.1  91.3  90.6  89.8  89.0  38.2
   .21        (.0057)       92.2  91.5  90.7  89.9  89.1  83.3
   .22        (.0050)       92.3  91.6  90.8  90.0  89.3  83.5
   .23        (.0063)       92.4  91.7  90.9  90.2  89.4  88.6
   .24        (.0065)       92.5  91.8  91.0  90.5  89.5  88.8
   .25        (.0068        92.6  91.9  91.1  90.4  89.7  88.9
   .26        (.0071)       92.7  92.0  91.3  90.5  89.8  89.1
   .27        (.0074)       92.8  92.1  91.4  90.7  89.9  89.2
   .28        (.0077)       92.9  92.2  91.5  90.8  90.1  89.4
   .29        (.0080)       93.0  92.3  91.6  90.9  90.2  89.5
   .30        (.0083)       93.1  92.4  91.7  91.0  90.3  89.6
   .31        (.0087)       93.2  92.5  91.8  91.1  90.5  89,8
   .32        (.0090)       93.3  92.6  91.9  91.3  90.6  89.9
   .33        (.0093)       93.4  92.7  92.0  9U4  90.7  90.1
   .34        (.0096)       93.5  92.8  92.2  91.5  90.8  90.2
   .35        (.0099)       93.5  92.9  92.3  91.6  91.0  90.3
   .36        (.0103)       93.6  93.0  92.4  91.7  91.1  90.5
   .37        (.0106)       93.7  93.1  92.5  91.8  91.2  90.6
   .38        (.0109)       93.8  93.2  92.6  92.0  91.3  90.7
   .39        (.0113)       93.9  93.3  92.7  92.1  91.5  90.9
   .40        (.0116)       94.0  93.4  92.8  92.2  91.6  91.0
   .41        (.0119)       94.1  93.5  92.9  92.3  91.7  91.1
   .42        (.0123)       94.2  93.6  93.0  92.4  91.8  91.2
   .43        (.0127)       94.2  93.7  93.1  92.5  91.9  1.4 .
   .44        (.0130)       94.3  93.8  93.2  92.6  92.1  91.5
   .45        (.0134)       94.4  93.9  93.3  92.7  92.2  91.6
   .46        (.0138)       94.5  93.9  93.4  92.8  92.3  91.7
   .47        (.0141)       94.6  94.0  93.5  93.0  92.4  91.9
   .48        (.0145)       94.7  94.1  93.6  93.1  92.5  92.0
   .49        (.0149)       94.7  94.2  93.7  93.2  92.6  92.1
   .50        (.0153)       94.3  94.3  93.3  93.3  92.7  92.2
   .51        (.0157)       94.9  94.4  93.9  93.4  92.9  92.3
   .52        (.0161)       95.0  94.5  94.0  93.5  93.0  92.5
   .53        (.0165)       95.1  94.6  94.1  93.6  93.1  92.6
   .54        (.0169)       95.1  94.6  94.2  93.7  93.2  92.7
   .55        (.0174)       95.2  9-1.7  24.3  93.3  92,3  92.3
   .56        (.0178)       95.3  94.3  94.3  93.9  93. &  92.9
   .57        (.0182)       95.4  94.9  94.4  94.0  93.5  93.0
   .58        (.0187)       95.4  95.0  94.5  94.1  93.5  93.2
   .59        (.0192)       95.5  95.1  94.6  94.2  93.7  93.3
   .60        (.0196)       95.5  95.1  34.7  94.3  92.3  33.^

                                 Facility autocorrelation =0.55
 In computing the 30-day average  variability, a geometric fie an
 emission level  of 92" was assumed.

-------
                         ; 2-34
  EXHIBIT 2-23:
MINIMUM GEOMETRIC MEAH EFFICIENCIES REQUIRED TO
MAINTAIN NO MORE THAN ONE FAILURE PER TEN YEARS
Daily
Std. Dev.
(in log)
.20
.21
.22
.23
.24
.25
.26
.27
.28
.29
.30
.31
.32
.33
.34
.35
.36
.37
.38
.39
.40
.41
.42
.43
.44
.45
.46
.47
.48
.49
.50
.51
.52
.53
.54
.55
.56
.57
.58
.59
,60
Std. Dev.
of 30-Day
Average^
(.0058)
(.0061)
(.0064)
(.0067)
(.0070)
(.0073)
(.0076)
(.0080)
(.0083)
(.0086)
(.0089)
( . 0093 )
(.0096)
(.0099)
(.0103)
(.0106)
(.0110)
(.0113)
(.0117)
(.0121)
(.0124)
(.0123)
(.0132)
(.0135)
(.0139)
(.0143)
(.0147)
(.0151)
(.0155)
(.0159)
(.0164)
(.0168)
(.0172)
(.0177)
(.0181)
(.0136)
(.0190)
(.0195)
(.0200)
(.0205)
(.0210)
                                 Minimum  Efficiency
                                 For Threshold Shown
                                        <88%   <87%  <86%   <85%
92.3
92.4
92.5
92.6
92.7
92.8
92.9
93.0
93.1
93.2
93.3
93.3
93.4
93.5
93.6
93.7
93.8
93.9
94.0
94.1
94.2
94.3
94.3
94.4
94.5
94.6
94.7
94.8
94.8
94.9
95.0
95.1
95.2
95.2
95.3
95.4
95.5
95.6
95.6
95.7
95.8
91.5
91.6
91.7
91.3
91.9
92.0
92.1
92.3
92.4
92.5
92.6
92.7
92.8
92.9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.7
93.8
93.9
94.0
94.1
94.1
94.2
94.3
94,4
94.5
94.6
94.7
94.8
94.9
94.9
95.0
95.1
95.2
95.3
95.4
90.7
90.8
91.0
91.1
91.2
91.3
91.4
91.6
91.7
91.8
91.9
92.0
92.1
92.2
92.4-
92.5
92.6
92.7
92.8
92.9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.7
93.8
93.9
94.0
94.1
94.2
94.3
94.4
94.5
94.5
94.7
94.8
94.8
94.9
89.9
90.1
90.2
90.3
90.5
90.6
90.7
90.8
91.0
91.1
91.2
91.3
91.5
91.6
 91.7
91.8
92.0
92.1
92.2
92.3
92.4
92.5
92.6
92.8
92.9
93.0
93.1
93.2
93.3
93.4
93.5
93.6
93.7
93.8
93.9
94.0
94.1
94.2
94.3
94.4
94.5
89.2
89.3
89.4
89.6
89.7
89.9
90.0
90.1
90.3
90.4
90.6
90.7
90.8
90.9
91.1
91.2
91.3
91.5
91.6-
91.7
91.8
92.0
92.1
92.2
92.3
92.4
92.5
92.7
92.8
92.9
93.0
93.1
93.2
93.3
93.5
93.6
93.7
93.3
93.9
94.0
9*. 1
88.4
88.5
88.7
88.8
89.0
89.1
89.3
89.4
89.6
89.7
89.9
90.0
90.2
90.3
90.4
90.6
90.7
90.8
91.0
91.1
91.2
91.4
91.5
91.6
91.8
91.9
92.0
92.1
92.3
92.4
92.5
92.6
92.7
92.9
93.0
93.1
93.2
93.3
93.4
93.6
93.7
                                  Facility  autocorrelation =0.60
-In  computing  the  30-day  average  variability,  a geometric mean
emission  level  of 92* was  assumed.

-------
                           2-35
   EXHIBIT  2-24:  MINIMUM GEOMETRIC MEAM  EFFICIENCIES REQUIRED TO
                 MAINTAIN NO MORE THAN ONE FAILURE PER TEN YEARS
 Daily        Std. Dev.           Minimum Efficiency
Std.  Dev.      of 30-Day           For Threshold Shown
(in log)       Average1
                           <90%  <89%  <88%   <87%  <86%
   .20        (.0062)        92.4  91.6  90.9  90.1  89.4  88.6
   .21        (.0066)        92.5  91.8  91.0  90.3  89.5  88.8
   .22        (.0069)        92.6  91.9  91.1  90.4  89.7  88.9
   .23        (.0072)        92.7  92.0  91.3  90.5  89.8  89.1
   .24        (.0076)        92.8  92.1  91.4  90.7  89.9  89.2
   .25        (.0079)        92.9  92.2  91.5  90.8  90.1  89.4
   .26        (.0082)        93.0  92.3  91.6  90.9  90.2  89.5
   .27        (.0086)        93.1  92.4  91.8  91.1  90.4  89.7
   .23        (.0089)        93.2  92.6  91.9  91.2  90.5  89.8
   .29        (.0093)        93.3  92.7  92.0  91.3  90.7  90.0
   .30        (.0096)        93.4  92.8  92.1  91.5  90.8  90.1
   .31        (.0100)        93.5  92.9  92.2  91.6  90.9  90.3
   .32        (.0104)        93.6  93.0  92.3  91.7  91.1  90.4
   .33        (.0107)        93.7  93.1  92.5  91.8  91.2  90.6
   .34        (.0111)        93.8  93 2  92 6  92 0  91 3  90.7
   .35        (  0115)        93  9  93,3  92 7  92 1  91.5  90.9
   .36        (.0118)        94.0  93.4  92.8  92.2  91.6  91.0
   .37        (,0122)        94.1  93.5  92.9  92.3  91.7  91.1
   .38        (.0126)        94.2  93.6  93.0  92.4  91.9  91.3
   .39        (.0130)        94.3  93.7  93.1  92.6  92.0  91.4
   .40        (.0134)        94.4  93.8  93.2  92.7  92.1  91.5
   .41        (.0138)        94.5  93.9  93.3  92.8  92.2  91.7
   .42        (.0142)        94.5  94.0  93.5  92.9  92.4  91.8
   .43        (.0146)        94.6  94.1  93.6  93.0  92.5  91.9
   .44        (.0150)        94.7  94.2  93.7  93.1  92.6  92.1
   .45        (.0154)        94.8  94.3  93.8  93.2  92.7  92.2 ,
   .46        (.0159)        94.9  94.4  93.9  93.4  92.8  92.3
   .47        (.0163)        95.0  94.5  94.0  93.5  93.0  92.5
   .43        (.0167)        95.1  94.6  94.1  93.6  93.1  92.6
   .49        (.0172)        95.1  94.6  94 2  93.7  93.2  92.7
   .50        (.0176)        95.2  94.7  94.3  93.8  93.3  92.8
   .51        (.0181)        95.3  94.8  94.4  93.9  93.4  92.9
   .52        (.0185)        95.4  94.9  94.5  94.0  93.5  93.1
   .53        (.0190)        95.5  95.0  94.5  94.1  93.5  93.2
   .54        (.0195)        95.5  95.1  94.6  94.2  93.7  93.3
   .55        (.0200)        95.6  95.2  94.7  94.3  93.9  93.4
   .56        (.0205)        95.7  95.3  94.8  94.4  94.0  92.5
   .57        (.0210)        95.3  95.3  94.9  9^.5  94.1  93.5
   .58        (.0215)        95.8  95.4  95.0  94.5  94.2  93.8
   ,59        (.0220)        95.9  95.5  95.1  94.7  94.3  93.9
   .60        (.0226)        96.0  95.6  95.2  94.3  94.4  94.0

                                 Facility  autocorrelation = 0.65
 ln computing  the 30-day average variability,  a  geometric
 emission  level of 92% was assumed.

-------
                         />  2-36
   EXHIBIT  2-25-  MINIMUM GEOMETRIC  MEAN  EFFICIENCIES REQUIRED TO
                 MAINTAIN NO MORE THAN ONE FAILURE PER TEN YEARS
 Daily        Std. Dev.           Minimum Efficiency
Std.  Dev.      of 30-Day           For Threshold  Shown
(in loq)       Average^
                           <90%  <89%  <88%   <87%  <86%   <85%
   .20        (.0068)        92.6   91.8  91.1  90.3  89.6  88.8
   .21        (-0071)        92.7   91.9  91.2  90.5  89.7  89.0
   ,22        (.0075)        92.8   92.1  91.3  90.6  89.9  89/2
   .23        (.0079)        92.9   92.2  91.5  90.8  90.1  89.3
   .24        (.0082)        93.0   92.3  91.6  90.9  90.2  39.5
   .25        (.0086)        93.1   92.4  91.7  91.0  90.4  89.7
   .26        (.0090)        93.2   92.5  91.9  91.2  90.5  89.8
   .27        (.0093)        93.3   92.7  92.0  91.3  90.7  90.0
   .28        (.0097)        93.4   92.8  92.1  91.5  90.8  90.1
   .29        (.0101)        93.5   92.9  92.2  91.6  90.9  90.3
   .30        (.0105)        93.6   93.0  92.4  91.7  91.1  90.5
   .31        (.0109)        93.7   93.1  92.5  91.9  91.2  90.6
   .32        (.0112)        93.8   93.2  92.6  92.0  91.4  90.8
   .33        (.0116)        93.9   93.3  92.7  92.1  91.5  90.9
   .34        (.0120)        94.0   93.4  92.8  92.2  91.6  91.1
   .35        (.0124)        94.1   93.5  93.0  92.4  91.8  91.2
   .36        (.0128)        94.2   93.5  93.1  92.5  91.9  91.3
   .37        (.0133)        94.3   33.8  93.2  92.6  92.0  91.5
   .38        (.0137)        94.4   93.9  93.3  92.7  92.2  91.6
   .39        (.0141)        94.5   94.0  93.4  92.9  92.3  91.8
   .40        (.0145)        94,6   94.1  93.5  93.0  92.4  91.9
   .41        (.0150)        94.7   94.2  93.6  93.1  92.6  92.0
   .42        (.0154)        94,8   94.3  93.7  93.2  92.7  92.2
   .43        (.0158)        94.9   94.4  93.8  93.3  92.3  92.3
   .44        (.0163)        95.0   94.4  93.9  93.4  92.9  92.4
   .45        (.0167)        95.0   94.5  94.0  93.5  93.1  92.6
   .46        (.0172)        95.1   94.6  94.1  93.7  93.2  92.7
   .47        (.0177)        95.2   94.7  94.2  93.8  93.3  92.8
   .48        (.0182)        95.3   94.8  94.3  93.9  93.4  92.9
   .49        (.0186)        95.4   94.9  94.4  94.0  93.5  93.1
   .50        (.0191)        95.5   95.0  94.5  94.1  93.6  93.2
   .51        (.0196)        95.5   95.1  94.6  94.2  93.7  93.3
   .52        (.0201)        95.6   95.2  94.7  94.3  93.9  93.4
   .53        (.0206)        95.7   95.3  94.3  94.4  94.0  93.5
   .54        (.0212)        95.8   95.3  94.9  94.5  94.1  93.7
   .55        (.0217)        95.3   95.4  95.0  94.6  94.2  93.3
   .56        (.0222)        95.9   95.5  95.1  94.7  94.3  93.9
   .57        (.0223)        96.0   95.6  95.2  94.8  9^.4  94.0
   .58        (.0233)        96.1   95.7  95.3  94.9  94.5  94.1
   .59        (.0239)        96.1   95.8  95.4  95.0  94.6  94.2
   .60        (.0245)        96.2   95.8  95.5  95.1  94.7  94.3

                                   Facility autocorrelation =  0.70
  lln  computing the 30-day average  variability, a geometric mean
   emission level  of 92* was assumed.

-------
                                 /) 2-37
2.3  METHODOLOGY
     Monte-Carlo simulation techniques were used to generate  the  data  in
for the lognormal-distribution processes in exhibits 2-4 through  2-9.
The IBM Scientific Subroutine Packaqe uniform random number generator
RANDU was used to generate the basic pseudo-random number  stream  for the
analyses.  Box and Muller's technique was used  for generating
pseudo-random normal random deviates (with an accuracy in  the  resultant
distribution of at least six digits}.1  Lognormal deviates were
generated by the exponential function from these normal deviates.   All
the estimates were generated using non-overlapping random-number  streams
of 720,000 days (2,000 years).  The standard errors of the estimates were
estimated by treating the 2,000 years as four replicated experiments of
500 years each.  The computations were performed to 32 and 64  bit
accuracy on a Hewlett-Packard Series 1000 Model F computer, and the runs
consumed about 40 CPU hours of computation.  The simulation was checked
by comparing statistics for which exact results were known from theory,
and all cases agreed to three or more digit accuracies (with  sample
                                                                        *
periods of 8,000,000 days in this testing).
     The normal-distribution estimates were generated by exact solution
of the mathematical system, to accuracy of five or more decimals.
Completely exact solutions of the lognormal case were not  available,
which led to the use of Monte-Carlo simulation.  The critical  values
given in exhibits 2-10 through 2-25 could not be found with the required
accuracy by simulation in the two-week term of  this analysis,  because
*This technique is significantly more  accurate  in  its  results  than
 those usually used in good statistical practice.   It  was  used because  of
 the requirement to estimate  very  small probabilities.

-------
                                 /> 2-38
such a determination by simulating all points necessary to search for the
critical  values would have required approximately 2000 hours of computer
time.  Accordingly, mathematical methods were used to compute these
values to within 0.2 percent.  These methods, although derived from
standard techniques, were developed specifically for this analysis.  The
techniques involve first using  series approximations to the lognormal
distribution function and to its thirtieth convolution with itself,  so  as
to obtain accurate estimates of the third and fourth moments and
cumulants of the statistical distribution of the thirty-day averages.
(The first and second moments are known exactly in closed form.)  These
estimates are then used in Edgeworth and Cornish-Fisher series expansions
of the distribution of the thirty-day averages, from which expected  rates
of threshold failures and critical values can be completed.  It was  found
that only one non-normal term of the Edgeworth expansion was required  to
achieve the desired accuracy.   These methods were compared with the
simulation techniques to verify their accuracy (and the accuracy  of  the
computer implementations used.)  All  results were within 0.1 percent of
the  correct values as determined by simulation, indicating that the
expansions are somewhat more accurate in the region of interest than the
guaranteed bound of 0.2 percent we obtained  analytically.  The exact
expression used to compute the  critical minimum-efficiency values
reported above is  given in exhibit 2-25.

-------
                                                        2-39
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-------
                                  03-1
      3.0  DESCRIPTIVE STATISTICS ON FGD SYSTEM EFFICIENCY DATA

     Basic descriptive statistics were required in construction of  the
model simulating the variable efficiency of steam generating units.  The
appropriate model structure and statistical distribution characteristics
were determined from an examination of observations reoorted from eleven
operating units.  In addition, operating system parameters were varied
over ranges determined partly on the basis of parameter estimates made
from the data.  This chapter consists of four sections describing the
observations and statistical analyses of them.
     Section 3.1 defines the variable analyzed and describes the data
base used.  A lognormal description of the analysis variable was used by
EPA and Entropy in previous analysis of this data.  Section 3.2 discusses
the aopropriateness of such a description.  As was shown in the analysis
reported in chapter 2.0, the issue of distributional form has little
influence on the principal results.  In section 3.3 the means, standard
deviations, and autocorrelation factors are presented for each of the
eleven units.  Differences in these parameters among the eleven units are
also noted.  Additionally, the appropriateness of a first-order
autogressive model is discussed.  Section 3.4 discusses possible
confounding of results caused by variation in the sulfur content of
untreated emissions.

3.1  DATA SET
     Data on the efficiency factor from eleven electric utility steam
generating units were provided to VRI by the EPA.  The data which was
received in printed tabular form was believed to be that previously

-------
                                 3-2
analyzed by EPA and Entropy.  The eleven units, the number of observa-

tions from each and the time period in which the observations were made

are described in exhibit 3-1.  Each observation represents a twenty-four

hour average of FGO system efficiency calculated from the unput and

output emission levels at each unit.  (Efficiency was defined as the

percentage of S02 removed from the gas flow through the scrubbing

process.)

     As shown in exhibit 3-1, the amount and time frame of the data

differed significantly from one unit to the next.  The limited number of

observations from the Philadelphia and Pittsburgh II units make the data

from these two facilities of limited use.  The twenty-four data points

from Conesville A and the twenty-one from Conesville B represent the only

measurements taken over a six-month period.  F.jrther, the data set for

any individual unit was generally characterized by intermittant data

voids.  This scattering of data points limits  the degree of certainty

with which any inferences concerning the correlation structure of the

process should be reviewed.
                                                                        f



3.2  LOGNORMAL TRANSFORMATION

3.2.1  THE UNTRANSFORMED VARIABLE

     An analysis of the distribution of the efficiency values for each  of

the units indicated that at least four were clearly negatively skewed

(see exhibit 3-2).  Skewness, the third moment about the mean, measures

the degree to which a distribution is unbalanced or "off-center".  A

negative skewness factor indicates a distribution with a long left-hand

tail.  A variable with a normal distribution is balanced and has a

skewness of zero.  Two of the units with significant skewness were also

-------
                                   />3-3
                 EXHIBIT 3-1:   ANALYSIS  DATA BASE  DESCRIPTION
Steam Generating
      Unit
Louisville North
Louisville South
Pittsburgh I
Pittsburgh II
Philadelphia
Chicago

Shawnee TCA
Shawnee Venturi
Conesville A
Conesville B
Lawrence
  Number of
Observations
Time Period During Which
 Observations Were Made
66
89
20
11
8
52
42
31
24
21
30
July
July
Sept
Nov.
Sept
Aug.
July
Dec.
Dec.
June
June
Jan.
21,
21,
. 14
10,
. 18
9,
30,
7,
7,
15,
15,
16,
1977
1977
, 1977
1977
, 1977
1977
1978
1978
1978
1978
1978
1979
- Dec.
- Dec.
- Nov.
- Dec.
- Oct.
- Nov.
- Sept
- Jan.
- Jan.
- Dec.
- Dec,
- Feb.
23
23
9,
6,
9,
23
. 8
25
29
13
13
21
, 1977
, 1977
1977
1977
1977
, 1977
, 1978
, 1979
, 1979
, 1978
, 1978
, 1979
(156
(156
(57
(27
(22
(107
(41
(49
(51
days)
days)
days )
days)
days)
days)
days)
days)
days)
(183 days)
(133
(37
days)
day?)

-------



























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found to have a significantly non-zero kurtosis.  Kurtosis, a  function  of
the fourth moment about the mean,  is often considered  to measure  the
degree of peakedness in the distribution.  A positive  value indicates a
higher peak (and longer tails) than in the normal distribution  and  a
negative value indicates a flatter peak.  A variable with a normal
distribution has a kurtosis of zero.
     Since the negative skewness was a significant and consistant feature
of the efficiency variable, the loge transformation performed  by  both
EPA and Entropy in previous analyses of the data might be expected  to
produce a variable with a more normal distribution.

3.2.2  THE TRANSFORMED VARIABLE
     The transformation variable used is log (1-efficiency).   For most  of
the units, the transformation improved the normality of the distribution
significantly.  This improvement can be seen in the skewness and  kurtosis
values for the untransformed and transformed variable, displayed  in
exhibit 3-2.  The significance column of the display indicates  the
certainty with which the sample statistic implies an actual departure
from the normal distribution.
     Exhibit 3-3 presents the arithmetic medians, means, and standard
deviations predicted for the observations under the lognoraal  assumption..
Comparison of these predicted values with the actual sample statistics
provides an intuitive feel for the goodness of fit of  the lognormal
distribution.  The lognormal assumption results in accurate predictions
except in the estimates of standard deviations at the Conesville  and
Lawrence units.

-------
                                   /> 3-6
         EXHIBIT 3-3:  COMPARISON OF ARITHMETIC VALUES PREDICTED BY
                       THE LOGNORMAL DISTRIBUTION ASSUMPTION WITH
                       ESTIMATES FROM THE OBSERVATIONS
Unit
                   Arithmetic Values Predicted
                    By Lognormal  Assumptions
          Median
     Standard
Mean Deviation
                                       Observed Estimates  From
                                       Untransformed Variable
Median
     Standard
Mean Deviation
Louisville North
Louisville South
Pittsburgh I
Pittsburgh II
Philadelphia
Chicago
Shawnee TCA
Shawnee Vanturi
Conesville A
Conesville B
Lawrence
84.4
83.3
30.8
85.4
97.0
89.2
88.5
96.0
86.0
92.5
95.4
83.8
82.2
80.2
85.0
96.8
89.1
88.3
95.8
84.5
91.6
93.4
4.9
6.2
4.5
3.2
1.2
1.3
2.2
1.6
7.3
4.2
6.6
84,6
83.3
81.2
86.1
96.7
83.9
88.5
95.7
84.1
91.9
95.3
83.8
82.3
80.3
85.1
96.8
89.1
88.3
95.8
84.7
91.7
93.6
4.7
5.9
4.6
3.4
1.2
1.3
2.2
1.5
6.1
3.5
5.3
     lognormal distributions:  (the quantity' (1-efficiency) is lognormally
 distributed).
     Median = e^                                y= mean of logarithmic variable.
                  2/2                        a= Standard deviation of log-
             f\ f\  i1-*
     Mean
= e e
                         arithmic variable.
     Standard Deviation = eyea /2(ea -1)1/2

-------
                                 3-7
     In spite of the apparent better agreement between  the lognormal
distribution and that data, 'Kolmogorov-Smirnov tests comparing both
normal and lognormal distributions with the data  indicated that  either
assumption could be accepted.
     Overall, then, the lognormal distribution presents a slightly better
characterization of the efficiency data than the  normal.  However, from
the available data, it is evident that the lognormal description  is  not
an ideal  fit for all cases, and that the distribution is also very nearly
normal in many of the cases.

3.3  ESTIMATED PARAMETERS AND COMPARABILITY AMONG UNITS
3.3.1  MEANS AND STANDARD DEVIATIONS
     Exhibit 3-4 presents the medians, means, and standard deviations of
the transformed variable, log (1-efficiency).  The differences in the
means and standard deviations among the eleven units can readily  be  seen
from examination of the exhibit.  Statistical tests- were performed  on
the differences in means and variances for each pair of units.   (The
variance is the square of the standard deviation.)  The results  of these
tests are presented in exhibits 3-5 and 3-6.  The level of significance
indicates the probability of the observed difference occurring by chance
if, in reality, there was no difference between the two means (or
variances).  For example, the significance of the difference  in  variances
between the Louisville South and Pittsburgh I units is  .0305.  This  means
that if there were really no difference in the variances at these units,
^T-tests were performed on the means and F-tests on  the  variances.

-------
                           P3-8
EXHIBIT 3-4:   ESTIMATED PARAMETERS OF TRANSFORMED  VARIABLE
 UNIT
MEDIAN
Louisville North
Louisville South
Pittsburgh I
Pittsburgh II
Philadelphia
Chicago
Shawnee TCA
Shawnee Venturi
Cones vi lie A
Cones vi lie B
Lawrence
-1.S836
-1.7910
-1.6885
-1.9729
-3.5143
-2.2047
-2.1840
-3.1353
-1.8793
-2.5170
-3.0791
-1.8608
-1.7868
-1.6492
-1.9223
-3.4927
-2.2217
-2.1608
-3.2270
-1.9626
-2.5884
-3.0714
MEAN (y)   STANDARD DEVIATION (a)





                  .295



                  .343



                  .234



                  .212



                  .359



                  .118



                  .182*



                  .368



                  .447



                  .474



                  .835

-------
                                                          />3-9
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                                                                                                     V  
                                                                                                     
-------
                                                    ^3-10
    LU
 Ll I 1  I
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 LU <
    LU
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                                                                                               OJ
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                                                                                                U
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                                                                                               r.
                                                                                               55
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                                                                                                e 
-------
                                   3-11
3.05 percent of random samples drawn from these units would produce a

difference in sample variance of the observed magnitude.  A significance

level of .05 or lower is usually considered to be clear evidence of a

difference.

     The variances at the Chicago and Shawnee TCA units were signifi-

cantly lower than the variances at almost all  of the other units.  EPA

officials noted that both of these units are well run and a low

variability in efficiency was expected.  The Pittsburgh II unit was

described as being similar to the Shawnee TCA units, but because of the

limited number of observations the results are of less interest.  The

significantly high variance at the Lawrence unit is believed by EPA

officials to be the result of an unusually low sulfur content of the

coal.

     Because of the highly significant differences in the variances among

the units examined and the inaccurate estimation of variance at the

Conesville and Lawrence units, it is not appropriate to combine these

variances for analysis.




3.3.2  AUTOCORRELATION

     The lag-one autocorrelation estimates for each of the eleven units

are presented in exhibit 3-7, along with the number of observations from

which the estimates were drawn and the significance of the factor.  (The
        s
observations included were those for which there was also an observation

on the preceding o*" succeeding day.)  The level of significance is

dependent on the number of observations, hence the autocorrelation factor

of 0.5255 at the Conesville B unit is not significant because it is based

on only seven observations while the autocorrelation factor of 0.5995 at

-------
          EXHIBIT 3-7:   FIRST-ORDER AUTOCORRELATION  FACTORS
                        ON THE VARIABLE LOG (1 - EFFICIENCY)
      UNIT
Autocorrelation    Significant at
                     .05 level
Louisville North
Louisville South
Pittsburgh I
Pittsburgh II
Philadelphia
Chicago
Shawnee TCA
Shawnee Venturi
Conesvilie A
Conesvilie B
Lawrence
49
72
11
7
5
37
37
25
13
7
27
.6955
.6949
.4683
-.1428
.252*
.6983
.5995
.8897
.7131
.6255
.6386
yes
yes
no
no
no
yes
yes
yes
yes
no
yes
The autocorrelation was determined by comparing day 't1  with day 't-V;
the data was not collapsed and missing data was not filled in, so that
only the observation days which were preceded or followed by another
observation day were included.

-------
                                  3-13
Shawnee TCA is significant.  It seems almost certain that first-order



autocorrelation does, in fact, exist at most or all units.  Entropy  used



an estimate of 0.7 in their simulation model.  This appears to  be  an



appropriate value if the model is dealing with a unit  similar  to one of



the Louisville units.  However, for units more similar to the  Shawnee  TCA



unit, 0.6 would be a more reasonable estimate.  Differences in  opera-



tional procedures at the units are an unknown but probably relevant



factor.







3.3.3  AUTOREGRESSIVE MODEL



     The possibility of autocorrelation factors associated with lags of



two or more was also examined.  A first-order autogressive model is one



in which the variable in time  "t" is a function of the same variable in



time "t-1".  A second-order autogressive model was compared with a



first-order autogressive model.  A comparison of the residual  led  to the



conclusion that the first-order autogressive model is appropriate.  A



further examination of partial correlations up to a lag of ten  led to  the



conclusion that the first-order autogressive model is appropriate.







3.&  POSSIBLE CONFOUNDING FACTORS



     It is recognized that many other factors mav be related to the



efficiency variable.  It was suspected that the efficiency factor  at a



given unit might be related to the level of sulfur in  the raw  emissions.



Data was available for all  but the Lawrence unit on the pounds  per



million BTUs of sulfur in the  gas before processing.  The Pittsburgh I



and Conesville scrubbers processed gas with a significantly higher



average sulfur content than the other units (see exhibit 3-8).  Mo

-------
                               J) 3-14
          EXHIBIT 3-8:   COMPARISON OF MEAN SULFUR CONTENT OF
                        INPUT  EMISSIONS AND MEAN EFFICIENCY
      UNIT


Louisville North

Louisville South

Pittsburgh I

Pittsburgh II

Philadelphia

Chicago

Shawnee TCA

Shawnee Venturi

Conesvilie A

Conesvilie B

Lawrence
MEAN SULFUR CONTENT
OF INPUT EMISSIONS
    (Ib/MMBTU)
      5.653

      5.687

      6.647

      5.462

      5.049

      5.643

      5.555

      5.660

      7.793

      7.359

      NA
   MEAN OF EFFICIENCY
 (Arithmetic Equivalent
of Transformed Variable)
          83.8

          82.2

          80.2

          85.0

          96.8

          89.1

          88.3

          95.8

          84.5

          91.6

          93.4

-------
                                  3-15
relationship appeared to exist, however, between mean efficiency at a
unit and the mean level of sulfur before scrubbing.
     Within individual units, statistically significant correlations
between efficiency and sulfur content were found at tv/o units, the
Chicago unit and the Shawnee TCA unit.  At the Shawnee TCA unit, the
relationship was the expected negative one (-.45) with increasing sulfur
content leading to decreasing efficiency.  At the Chicago unit, however,
a positive correlation (.47) was found, with increasing sulfur content
leading to increasing efficiency.
     On the basis of the evidence, then, one must conclude that there is
no predictable relation between the actual levels of sulfur emissions
before scrubbing and the efficiency of the scrubbing operation, and that
the analyses reported here are not contaminated by any confounding effect
of this nature.
     Many additional factors are of probable relevance in determining the
efficiency levels of scrubbers.  Operating procedures can be altered to
compensate for high or low sulfur content as well as high or low electri-
city demands.  The location and type of measuring device used can affect
efficiency readings.  The age, type, and condition of the scrubber
equipment may also affect efficiency.  The present data set does not
offer any evidence of the types or magnitudes of any effects from these
or other sources.

-------
                4.0  COMPARISON WITH ENTROPY RESULTS

     This chapter summarizes the degree to which the findings in the
preceding chapters appear to agree with the results developed by Entropy
Environmentalists, Incorporated.  It is organized into two sections which
parallel the material presented in chapters 2.0 and 3.0.  In the first
section the number of exceedences predicted by Entropy are compared to
those predicted by VRI, with a potential explanation of the observed
differences.  The second section compares the VRI and Entropy descrip-
tions of the statistical structure characterizing the efficiency of
eleven flue gas desulfurization (FGD) units at eight electric utility
sites.  The disparities between the Entropy and VRI estimates of process
parameter values are examined, and rationales for these differences are
discussed.

4.1  PREDICTED EXCEEDEMCES
     Although the details of Entropy's 1,000 year simulation were  not  .
available, VRI believes the ITU  >rial presented in chapter 2.0 nearly
replicates the Entropy approach.  Some differences between the VRI and
Entropy s'^ulated data are attributable to the inherent random nature of
the simulation process itself and the slight improvement in confidence
levels of VRI's figures produced as a consequence of the doubling  of the
number of simulated years (2,000 instead of 1,000).  Where VRI used
parameters comparable to those reported by Entropy, reasonably similar
numbers of exceedences wera predicted.
     Although these results shew generally the same pattern of effects,
there are differences greater than can be explained by chance effects.

-------
                                 D 4-2
In view of the great care taken in this analysis, including special
rechecking of the disparate results, we suspect  that the Entropy  results
are probably less accurate where differences exist, possibly d e  to the
use of less accurate random number generation and transformation  tech-
niques.  In this connection, it is worth noting  that VRI's estimates were
generated using methods considerably more precise than usually found in
good statistical practice.  This extra precision was required in  view of
the requirements to make accurate estimates of extremely small
probabilities.
     Despite these minor differences, VRI's results substantiate
Entropy's conclusion that the number of exceedences per year is extremely
sensitive to the median (or mean) FGD system efficiency and the varia-
bility in this efficiency.  VRI-simulated values nearly replicate
Entropy's findings that the degree of autocorrelation can affect,  the
number of exceedences although with less impact  than variation in the
mean and variance.  VRI's analyses also provide  information not provided
by Entropy such as the data in exhibits 2-10 through 2-15; in these
areas, no comparisons are possible.

4.2  PROCESS STRUCTURE
     Analysis of the 24-hour FGD efficiency data indicate that the
measured values of efficiency are not symetrically distributed about
their mean, generally weakening any normal distribution hypothesis.
VRI's analysis agrees with the Entropy and EPA findings that the  quantity
(1-efficiency) has a distribution which can be reasonably approximated  by
a lognormal distribution.  There are many other  candidate distributions

-------
                                D 4-3
which might equally well be used to describe the observed distribution  of
efficiency values.  As shown in chapter 2.0, adoption of other distribu-
tions would not significantly influence the analysis results, but  instead
might confuse major differences between the Entropy and VRI results with
insignificant discrepancies.  Consequently, the above analysis used pri-
marily the lognormal distribution hypothesis proposed by EPA and con-
curred with by Entropy.
     Entropy further found that the FGD efficiency data had significant
first-order autocorrelation.  VRI's results upheld this finding even
though VRI's estimate of autocor -elation was based on consecutive  calen-
dar days rather than the method suggested by Entropy's statistical con-
sultant which collapsed serial data into a string of days for which data
were available.  In addition, VRI's negative finding on the presence of
higher order autocorrelation helped to validate the Entropy implicit
assumption that first-order (one day) lags were sufficient to describe
process time dependencies.
     VRI used a data base which appeared to be approximately, but  not
exactly, the same as that employed in the Entropy analysis.  Specific
differences between the data provided are evidenced:  (I) by disparities
in the numbers of observations at particular sites; and  (2) by differ-
ences in numerical estimates.  Disparities in the numbers of observations
occurred for two of the utilities reported, i.e.:
                                      Number of Observations
                       Site              VRI      Entropy
                    Chicago              52         35
                    Shawnee TCA          42         37

-------
                                 /> 4-4
Entropy does not report the number of observations from the Laurence


unit, so comparisons cannot be made.  VRI-estimated parameter values  for


0 and y generally differ from Entropy's estimates by no more than two


percent except for the following sites.


                            Logarithmic Parameter Values
Site
Chicago
Shawnee TCA
Lawrence
UVRI
-2.222
-2.161
-3.071
E
-2.206
-2.168
-3.437
UVRI
.118
.182
.835
*E
.106
.186
.676
UVRI
.698
.600
.639
E
.86
.65
N/A
As noted above, VRI and Entropy were not using identical data bases  for


the Chicago and Shawnee TCA sites.  It is expected  chat the differences


at the Lawrence site may also be the result of a different data base.


Finally, the Entropy data base combined observations from the Louisville
                                                                ^


north and south units into a single site (Cane Run) while they were


treated separately in VRI's analysis.  Entropy notes that averaging  the


results of these two units reduces the overall variability of the  com-
                                                                       *

bined sites.  This effect is illustrated by the difference between the


two VRI logarithmic estimates of   for Louisville (0.295 and 0.343)  and


the single 'average Louisville estimate reported by  Entropy (0.289).






4.3  DIFFERENCES AMONG SITES


     VRI and Entropy agree in finding that the evidence from existing


utility boiler units shows statistically significant differences  in  the


levels of variability at different sites.  VRI has  assumed that at least


some of its variability represents differences in engineering design and


operating practices, including some designs and/or  operating practices

-------
which may not represent the future  state  of  the  art  for  boiler  units.
VRI therefore did not combine  all the  data  together  to estimate future
site variability.  Entropy, in  its  analysis  of these  differences,  did
combine the data to generate forecasting  intervals,  discussed  in terms of
levels of correctness.  In this  analysiss Entropy  assumed  that  future
sites would have levels of variability  distributed as broadly  as the
variabilities observed at existing  sites.  Thus, Entropy assumed that  the
data from each of the existing  sites constitutes a sample  representating
appropriate state of the art design arid operating  practices  which  would
be used in future facilites.  Without  this  assumption, there is no
justification for using forecasting intervals based  on the complete  range
of variabilities.
     Rather than adopt this strong  assumption, VRI has chosen  to present
the bulk of its results in parametric  form covering  the  range  of
variabilities, leaving engineering  analysis  (combined with the  data  from
chapters 2.0 and 3.0) to identify the  levels of  variability  which  should
actually be expected at future  sites.   EPA  personnel  suggested  that
Shawnee TCA and Pittsburgh II might be  the  best  representatives of future
practices.  Statistical analysis of these two sites  suggests that  they
had a common variability.  Accordingly, a confidence  interval  for  the
variability at these sites was  presented  in  chapter 2.0.  A  confidence
interval is also presented there for the  Louisville  units.

-------
                 APPENDIX E






EPA RESPONSE TO PETITIONS FOR RECONSIDERATION

-------
     SSSS3S
MM     II III aTll
Him __ |i m ft* _   .SUWnaMMMfc

     	 --- 
         E-l
              Wednesday
              February 6, 1980
              Part  IV

              Environmentai
              Protection Agency
              Standards of Performance for
              Stationary Sources for Electric Utility
              Steam Generating Units; Decision in
              Response to Petitions for
              Reconsideration

-------
8210       Federal Register / Vol. 45, No. 26 /  Wednesday, February 6, 19HO / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY

40 CFR Part 60

(FflL 1404-6]

Standards of Performance for New
Stationary Sources; Electric Utility
Steam Generating Units; Decision in
Response to Petitions for
Reconsideration

AGENCY: Environmental Protection
Agency [EPA).
ACTION: Denial of Petitions for
Reconsideration of Final Regulations.
 SUMMARY: The Rnvironmenlnl Defense
 Fund, Kansas City-Power and Light
 Company, Sierra Club, Sierra Pacific
 Power Company and Idaho Power
 Company. Stata of California Air
 Resources Board, and Utility Air
 Regulatory Group submitted petitions
 for reconsideration of the revised new
 source performance standards for
 electric utility steam generating units
 that were promulgated on June 11,1979
 (41 FR 33580). The petitions were
 evaluated collectively since the
 petitioners raised several overlapping
 issues. When viewed collectively, the
 petitioners sought reconsideration of the
 standards of performance for sulfur
 dioxide (SO2). participate matter, and
 nitrogen oxides (NO,). In denying the
 petitions, the Administrator found that
 tht> petitioners had failed to satisfy the
 statutory requirements of section
 307{dj(7)(B) of the Clean Air Act. That
 is,  the petitioners failed to demonstrate
 either (1) that-it was impractical to raise
 their objections during the period for
 public comment or (2) that the basis of
 their objection arose after the close of
 the period for public comment and the
 objection was of central relevance to the
 outcome of the rule. This notice also
 ri-sponds to certain procedural issues
 raised by the Environmental Defense
 Fund (EOF). It should be noted that the
 Natural Resources Defense Council
 (XRDC) H!ed a July 9,1979, letter in
 which they concurred with the
 procedural issues raised by EDF.
 DATES: Effective February 6,1980.
   Interested persons may advise the
 Agency of any technical orrors by
 March'7.  1980.
 ADDRESSES: EPA invites information
 from interested persons. This
 information should be sent to: Mr. Don
 R.  Goodwin, Director, Emission
 Standards and Engineering Division
 (MD-13). Environmental Protection
 Agency, Research Triangle Park, North
Carolina 27711, telephone (919) 541-
0271.
  Docket Number OAQPS-78-1
contains all supporting materials used
by EPA in developing the standards,
including public comments and
materials pertaining to the petitions for
reconsideration. The docket is available
for public  inspection and copying
between 9:00 a.m. and 4:00 p.m., Monday
through Friday at EPA's  Central Docket
Section, Room 2903B, Waterside Mall.
401 M Street, SW., Washington, D.C.
20460.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711. telephone (919) 541-
5271.
SUPPLEMENTARY INFORMATION:

Background
  On September 19,1978, pursuant to
Section 111 of the Clean Air Act
Amendments of 1977, EPA proposed
revised standards of performance  to
limit emissions of sulfur dioxide (SOj).
particulate matter, and nitrogen oxides
(NOX) from new, modified, and
reconstructed electric utility steam
generating units (43  FR 42154). A public
hearing was held on December 12  and
13,1978. In addition, on December 8,
1978, EPA published additional
information on the proposed rule (43 FR
57834). In  this notice, the Administrator
set forth the preliminary results of the
Agency's analysis of the environmental,
economic, and energy impacts
associated with several  alternative
standards. This analysis was also
presented at the public hearing on the
proposed standards. The public
comment period was extended until
January 15,1979, to  allow for comments
on this information.
  After the Agency  had  carefully
evaluated the more  than 600 comment
letters and related documents, the
Administrator signed the final standards
on June 1,1979. In turn, they were
promulgated in the Federal Register on
June 11,1979.
  On June 1,1979, the Sierra Club  filed a
petition for judicial  review of the
standards with the United States Court
of Appeals for the District of Columbia.
Additional petitions were filed by
Appalachian Power Company, et al., the
Environmental Defense Fund, and the
State of California Air Resources Board
before the close of the filing period on
August 10,1979.
  In addition, pursuant to section
307(d)(7)(B) of the Clean Air Act, the
Environmental Defense Fund, Kansas
City Power and Light Company, Sierra
Club, Sierra Pacific Power Company and
Idaho Power Company. State of
California Air Resources Board, and
Utility Air Regulatory Group petitioned
the Administrator for reconsideration of
the revised standards.
  Section 307(d)(7)(B) of the Ant
provides that:
  Only an objection to a rule or procedure
which was raised with reasonable specificity
during the period For public comment
(including any public hearing) may be raised
during judicial review. If the parson raising
an objection can demonstrate to the
Administrator that it Wris impracticable to
raise such objection within such timt: or if Inn
grounds for such objection arose alter the
period for public comment (but within the
time specified for judicial review) and if siK.h
objection is of central relevance to the
outcome of the rula, the Administrator shall
convene a proceeding for reconsideration of
the rule and provide the snme proo-dnral
rights as would have been afforded h-id '.he
information 'men available Ht the iirr.e .V:
rule was proposed.  If th Administrator
refuses 'o convene such a proceeding, such
person may seek review of such refusal in the
United States Court of Appufils for the
appropriate circuit (as provided in subsection
(b))-
  The Administrator's findings and
responses to the issues raised by the
petitioners are presented in this notice.

Summary of Standards '

Applicability

  The standards apply to electric utility
steam generating units capable of firing
more than 73 MW (250 million Btu/hour)
heat input of fossil fuel, for which
construction is commenced after
September 18,178. Industrial
cogeneration facilities that sell less than
25 MW of electricity, or less than one-
third of their potential electrical output
capacity, are not  covered. For electric
utility combined cycle gas turbiif s.
applicability of the standards is
determined on the basis of the fossil-funl
fired to the  steam generator exclusive of
the heat input and electrical power
contribution of thejjas turbine.

SOi Standards
  The SOj standards are as follows:
  (1) Solid and solid-derived fuels
(except solid solvent refined coal): SO?
emissions to the atmosphere  at" limited
to 520 ng/J (1.20 Ib/million Btu) heat
input, and a 90 percent reduction in
potential SO2  emissions is requiied at all
times except when emissions !o the
atmosphere are less than 260 r.y/J (0.60
Ib/million Btu) heat input. When SO?
emissions are less than 260 ng/J (0.60 lb/
million  Btu) heat input, a 70 percent
reduction in potential emissions is
required. Compliance with the emission
                                                           E-2

-------
          Federal Register / Vol. 45, No. 26 / Wednesday, February 6, 1980 / Rules  and  Regulations    8211
limit and percent reduction requirements
is determined on a continuous basis by
ubing continuous monitors to obtain a
30-day rolling average. The percent
reduction is computed on the basis of
overall SO2 removed by all types of SO*
and sulfui removal technology, including
flue g-ht, lignite which has
been mined in :. 'i th Dakota, South
Dakota, or Montana;
  [5] Combustion of a fuel containing
mure than 25 percent, by weight, coal
refuse is exempt from the NO, standards
and monitoring requirements; and
  (6) 260 ng/J (0.60 Ib/million Btu) heat
input from the combustion of anthracite
coal, bituminous coal, or any other solid
fuel not specified under (3), (4), or (5).
  Continuous compliance with the NOT
standards is required, based on a 30-day
rolling average. Also, percent reductions
in uncontrolled NO, emission levels are
required. The percent reductions are not
controlling, however, and compliance
with the NO, emission limits will assure
compliance with the percent reduction
requirements.

Emerging Tec.linolo^ies
  The standards include provisions
which allow the Administrator to grant
commercial demonstration permits to
allow less stringent requirements for the
initial full-scale demonstration plants of
certain technologies. The standards
include the following provisions:
  (1) Facilities using SRC I are subject to
an emission limitation of 520 ng/J (1.20
Ib/million Btu) heat input, based on a
30-day rolling average, and an emission
reduction requirement of 85 percent,
based on a 24-hour average. However,
the percentage reduction allowed unchn-
a commercial demons!ration permit for
[he initial full-scale demonstration plant
using SRC I would ba 80 percent (based
on a 24-hour uvanye). The plant
producing ihe SIIC I would monitor to
ensure that the roquired percentage
reduction (24-hour uvera^.j) is achieved
and the power plant using the SRC I
would monitor to  ensure that the 520 ng/
} heat input limit (M-day rolling
average) is achiever':.
  (2) Facilities using fluidized bed
combustion i_FBC) or coal liquefaction
would be subject  to the sr~' i-^on
limitation and percentage reduction
requirement of the SO.- standard and to
the particulate matter and NOX
standards. Ho'vever, the reduction in
potential SO- emissions allowed under a
commercial demonstration permit for
the initial full-scale demonstration
plants using FBC would be 85 percent
(bssed on a 30-d.n -oiling average). The
NO* emission limitation altowed under a
commercial demonstration permii for
the initial full-scale demonstration
plants using coal liquefaction would be
300 ivj] (0.70 ib/million Btu) heat input,
b r-'-"1 <;n a 3-day rolling average.
  (3) No more tl-.a.t 15.000 MW
equivalent electrical capacity xvould be
alloUed for the purpose of commercial
d-.'Tonst'-ilion permits. The capacity
AM!! bi' aliur.ited '"> lo'lows:
                      utanl  capacity MW


                      SO,    fc.Cti -;.1GCO

                      SO,      -S
 fpf^sst' :>-'J)
Cca! licjuelart-on
SO,       4CO-1 200
NO.      7M-10 "CO
Compliance Pravisinns
  Continuous compliance with the SO;
and NOX standards is required and is to
bo determined with continuous emission
monitors. Reference methods or othur
approved procedures mu.st be used to
supplement the erosion data when the
                                                     E-3

-------
 8212     Federal Register /  Vol.  45, No. 26 /  Wednesday, February 6. 1980  /  Rules and Regulations
 c.'i itinuous emission monitors
 malfunction in order to provide emission
 data for at least 10 hours of each day for
 at least 22 days out of any 30
 consecutive days of boiler operation.
   A malfunctioning FGD system may be
 bypassed under emergency conditions.
 Compliance with the particulate
 standard is determined through
 pci formance tests. Continuous monitors
 ;ii"' required to measure and record the
 opacity of emissions. The continuous
 opacity data will be used to identify
 excess emissions to ensure that the
 p.irticulate matter control system is
 bo-ing properly operated and maintained.
 Issuer Raised in the Petitions for
 Reconsideration

 /. SOi Maximum Emission Limitation of
 j?0 ng/J (1.2 Jb/Million Btu) Heat Input
   The Er.vi".>iHnentul Defense Fund
 (F.DF). Sierrr-. Club, and State  of
 California A;r Resources Board (CARBJ
 requested that a proceeding be
 convened to reconsider the maximum
 SO= emission '.imitation of 520 ng/J (1.2
 Hi/million Btu) heat input. In their
 petition, EOF set forth several
 procedural questions as the basis for
 their request. First, they maintained  that
 they did not have thg opportunity to
 comment on curtain information  which
 was submiued to EPA by the  National
 CCM! Association at an April 5,1979,
 i"c?ting and In subsequent
 i.orrf-spondence. The information
 pf.-rtained to the Impacts  that  different
 emission limitations will have on coal
 production in the Midwest and Northern
 Appalachia. They argued that this
 information materially influenced the
 Administrator's  final decision. Further,
 they maintained that the
 Administrator's  decision in setting the
 emission limiiafion was based on ex
 parti? communications and improper
 congressional pressure.
   The Sierra Club also raised objections
 to information developed during the
 post-comment period. They cited the
 information supplied by the National
 Co'il Association, and the EPA staff
 analysis of the impact that different
 omission limitations would have on
 burnable noal rsserves. In addition, they
 challenged the .'^sumption that
 conservatism in ii'.ility perceptions of
- scrubber perforruaii'.,'.1 could create a
 significant disincentive against the
 burning of high-sulfur coal reserves.  The
 Sierra Club maintained that this
 information is of "central relevance"
 since it formed the basis of the
 I'stablishment of the final emission
 limitation and that the Sierra  Club was
 denied the opportunity to comment on
 this information. Finally, the Sierra Club
and CARD subscribed fully to arguments
presented by EOF concerning ex parte
communications.
Background
  The potential impact that the emission
limitation may have on high-sulfur coal
reserves did not arise for the first time in
the post-comment period. It was an
issue throughout the rulemaking. In the
proposal, the Agency stated that two
factors had to be taken into
consideration when selecting the
emission limitationFGD efficiency and
the impact of the emission limitation on
high-sulfur coal reserves (43 FR 42160,
middle column). The proposal also
indicated that, in effect, scrubber
performance determines the maximum
sulfur content of coals that can be fired
in compliance with emission  limitation
even uhen coal preparation is
employed. From (he discussion it is clear
that the Administrator recognized that
midwestern nigh-sulfur coal reserves
could be severely impacted if the
emission limitation was not selected
with care (43 FR 42160, middle column).
In addition, the Administrator also
specifically sought comment  on the
related question of new coal  production
as it pertained to consideration of coal
impacts in the final decision  (43 FR
42155, right column).
  At the December 1978 public hearing
on the proposed standards, the Agency
specifically sought to solicit information
on the impact that lower SO2 emission
limits (below 520 ng/J (1.2 Ib/million
Btu) heat input) would have on high-
sulfur coal reserves. In response to
questions from an EPA panel member
and the audience, Mr. Hoff Stauffer of
ICF, Inc. (an EPA consultant) testified
that the potential impact of lower
emission limitations on high-sulfur coal
reserves would be greater in  certain
states than was indicated by the results
of the macroeconomic analysis
conducted by his firm. He added further
that if the degree of reduction
achievable through coal  preparation or
scrubbers changed from  the values
assumed in the analysis  (35 percent for
coal preparation on high-sulfur coal and
90 percent for scrubbers) the coal
impacts would vary accordingly. That is,
if greater reduction could be  achieved
by either coal preparation or by
scrubbers the impacts would be
reduced. Conversely, if the degree of
reduction achievable by either coal
preparation or scrubbers was less than
the values assumed, the  impacts would
be more severe (public hearing
transcript, December 12,1978, pages 46-
47).
  The subject was broached  again when
Mr. Richard Ayres, representing the
Natural Resources Defense Council and
serving as introductory spokesperson for
other public health and environmental
organizations, was asked by the panel
what effect lowering the emission
limitation would have on local high-
sulfur coal reserves. Mr. Ayres
responded that a lower emission
limitation may have the effect of
requiring certain coals to be scrubbed
more than required by the standard. He
added that the utilities would have an
economic choice of either buying local
high-sulfur coal and scrubbing more or
buying lower-sulfur  coal which may not
be local and scrubbing less. He further
indicated that it was not clear that a
lower limitation would have the effect of
precluding any coal. In doing so, he
noted that the "conclusion depended
entirely on assumptions about the
possible emission efficiencies of
scrubbers," Finally,  Mr. Ayres was
asked whether as long as production in
a given region increased that the
requirement of the Act to maximize the
use of local coal was satisfied. He
responded that it was a "matter of
degree" and that he  would not say as
long as production in a given region did
not decline the statute was served
(public hearing transcript, Decemhpr 12.
1978, pages 77-80).
  Mr. Robert Rauch, repi esenti-   'he
Environmental Defense Fund, a:.-.o
recognized in his testimony  that
lowering the emission limitation to the
level recommended  by EDF (340 ng/J
(0.8 Ib/million Btu) heat input) would
adversely impact high-sulfur coal
reserves. In his testimony he stated
"Adoption of the proposed lower ceiling'
would result in the exclusion of certain
high-sulfur coal reserves from use  in
power plants subject to the revised
standard." He added that the use of
adipic acid and other ;!v-ry ndditivr"
would enhance scrubber performance,
thereby alleviating the impacts on  high-
sulfur coal (public hearing transcript,
December 13,1978, pages 189-191).
  Mr. Joseph Mullan of the National
Coal Association testified in response to
a question from the hearing  panel that
lowering the emission limitation from
520 ng/J (1.2 Ib/million Btu)  heat input
would preclude the use of certain high-
sulfur coals. He added that the National
Coal Association would furnish data on
such impacts (public hearing transcript,
December 13,1978, page 246).
  Turning now to the written comments
on the  proposed standard submitted
jointly by the Natural Resources
Defense Council and the Environmental
Defense Fund, we see that they carefully
assessed the potential impacts on high-  
sulfur coal reserves  that could result
                                                          E-4

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          Federal Register / Vol. 45, No.  25 / Wednesday,  February 6,  1980 / Rules and Regulations     8213
from -, :, 'otis emission limitations. They
concluded, "Generally, the higher the
percent removal lequirement, the
smaller the percentage of coal reserves
which are effectively eliminated for use
by utility generating units." They went
on to argue that if their recommended
standard of 'J5 percent reduction in
potential SO2 emission was accepted a
lower emission limitation could be
adopted without adverse impacts on
coal reserves (OAQPS-78-1, IV-D-631,
page V-128).
Rationale for the Maximum Emission
Limit
  The testimony presented at the public
hearing and the written comments
served to confirm the Agency's initial
position that scrubber performance and
potential impacts  on high-sulfur coal
reserves had to be carefully considered
when establishing the emission
limitation. Meanwhile, it became
apparent that the analysis performed by
EPA's consn'! i,:t on emission limits
below r^O ng/J (1.2 Ib/million Btu} heat
input might not fully reflect the impacts
on major high-sulfur coal production
areas. This finding was evident by study
of the consultant's report (OAQPS-73-1,
IV-A-5, Appendix D) which showed
th.ii the C'.udp! UbC'd to estimate coal
production in Appalachia and the
Midwest was relatively insensitive to
broad variations in the emission ceiling.
The Agency then concluded that the
macroeconomic model was adequate for
assessing national impacts on coal use,
but lacked the specificity to assess
potential dislocations in specific coal
production regions. In effect the analysis
tended to mask the impacts in specific
coa! producing regions through
aggregation. Concern was also raised as
to the validity of the modeling
assumption that a 35 percent reduction
in potential SO., emibaions can be
achieved by coal washing on all high-
sul'ur coal reserves.
  In view of these concerns,  EPA
concluded shortly after the close of the
comment period that additional analysis
was nf edrd to support the final
emission ! 'uitation. In February, EPA
began dr.alyzing the impacts of
alternative emission limits on local high-
sulfur coal reserves. To account for
actual and perceived efficiencies of
scrubbers, the staff assumed three levels
of scrubber control85 percent, 90
percent, ;ind 95 percent. In addition, two
levels of physical coal cleaning were
reflected. The first level was crushing to
1.5 inch top-size and the second was
crushing to %  inch top-size, both
followed by wet beneficiation. In
addition, by using seam-by-seam data
on coal reserves and their sulfur
reduction potential (developed For EPA's
Office of Research and Development) it
was possible to estimate the sulfur
content of the final product coal based
on reported chemical properties of coals
in the reserve base (OAQPS-78-1, IV-E-
12). Since this approach did not require
the staff to assume a single level of
sulfur reduction for all coal preparation
plants, it introduced a major refinement
to the analysis previously performed by
EPA's consultant. The analysis was
substantially completed in March 1979
(OAQPS-78-1, IV-B-57 and IV-B-72).
  The April 5,1979, meeting was called
to discuss coal reserve data and the
degree of sulfur removal achievable
with physical coal cleaning (OAQPS-
78-1, IV-E-10). The meeting gave EPA
the opportunity to present the results of
its analysis and to verify the data and
assumptions used with those persons
who are most knowledgeable on coal
production and coal preparation. EPA
sought broad representalion at the
nuot.ng. Invitees including not only the
National Coal Association but
representatives from the Environmental
Defense Fund, Natural Resources
Defense Council, Sierra Club, Utility Air
Regulatory Group, United Mine Workers
cf America, rtnd other interested parties.
'Jht; i..v'ilees were furnished copies of
the materials presented at the meeting,
subsequent correspondence from the
National Coal Association, and minutes
of the meeting.
  The meeting served to confirm that
the coal reserve and preparation data
developed independently by the EPA
staff were in close agreement with those
prepared by the National Coal
Association  (NCA). In addition, the
discussion led EPA to conclude that coal
preparation technology which required
crushing to %-inch top-size would be
unduly expensive, lead to unncceptable
energy losses, and pose coal handling
problems (OAQPS-78-1, IV-E-11). As a
result, the Administrator revised his
assessment of state-of-art coal cleaning
technology (44 FR 33506, left column).
  In an April 19,1979, leti.v to the
Administrator (OAQPS-/'-l, IV-D-763).
attorneys for the Environmental Defense
Fund and the Natural Resources
Defense Council submitted comments on
the information presented by the
National Coal Association at the April 5,
1979, meeting and in a subsequent NCA
letter to the Administrator dated April 6,
1979. In their comments, they were
critical of the National Coal
Association's assumptions concerning
scrubber performance and the removal
efficiencies of coal preparation plants.
They also noted that the Associaton's
data was based on a small survey of the
total coal rnservps in the Midwest and
Northern Appaiuchia. They argued
further that coal blending could serve to
redune the adverse impact on high-sulfur
coal caused by a lower emission limit. In
doing so, they recognized that the
application of coal blending would have
to be undertaken on a case-by-case
basis. Finally, they maintained that
there is no evidence that the coal
industry would be unable to meet
increases in coal demand even if the
National Coal Association's reserve
data on coal preclusions were accepted.
In conclusion, they noted that the
Association's data was of questionable
relevance since it was predicated on a
maximum rtmoval efficiency of 90
percent.
  Subsequent correspondence from the
National Coal Association served to
reaffirm a point that had been made
earlier in the rulemaking. That is,
utilities would have a choice of either
buying lower-sulfur coal and sr;tibbing
to meet the percent removal requirement
or buying higher-sulfur coal and
scrubbing more than required by the
standard in order to meet the emission
limitation. In addition, they cited the
conservative nature of utilities and
stressed that thia would be reflected in
their coal buying practices. As w.is
discussed at the public hearing and  in
the written comments such behavior by
utilities would result in adverse impacts
on the use of certain local high-sulfur
coals.
  In reaching final conclusions about
the impact of the SO standard on coal
production, the Administrator judged
that utilities would be inclined to select
coals that would meet the emission  limit
wilh no more than 90 percent reduction
in potential SO* emissions * (44 FR
33596, left column). With this
assumption, the analysis revealed that
an em's >;on limit of less than 520 ng/]
create a disincentive to burn a
significant portion of the coal reserves
in the Midwest and Northern
Appalachia (OAQP5-7B-1, IV-B-72). If
the cinission limit had been set at 430
ng/J (1.0 lb/tnillion Btu) heat input, 15
percent of the  total reserve base in the
Eastern Midwest (Illinois, Indiana, and
Western Kentucky) would have been
impacted. The impact  in Northern
Appalachia would be 6 percent and this
impact would have been concentrated in
the areas of Ohio  and  the northern part
of West Virginia. If only currently
  "The previous version of Ihe EPA analysis had
assumed either fl5 or 90 percenl control levels m
addition to codl washing. Thai approach
disregarded the fact that the net reduction in
potential SO3 emissions may have hw;n greater th:m
90 percent in some case's.
                                                   E-5

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15214
Federal  Register / Vol. 45, i\"o.  2Q / Wednesday,  February  6, 1980 / Rules  and  Regulations
o'.vned coal reserves are considered, up
to 19 percent of t'-.e high-sulfur coals in
tome regions would be impacted
(OAQPS-78-L IV-B-72). The
Administrator judged that such impacts
are unacceptable.
  TliB final point made by NCA was
that utility coal buying practice typically
incorporates a margin of safety to
ensure compliance with SO2 emission
limitations. Rather than purchasing a
high-sulfur coal that would barely
comply with the emission limit, the
prudent utility would adopt a more
conservative approach and purchase
coal that would meet the emission limit
with a margin of safety in order to
uccount for uncertainty in coal sulfur
variability. This approach, which
reflects sound engineering principles,
could result in the dislocation  of some
high-sulfur coal reserves.
  The Administrator determined that
consideration of a margin of safety in
coal buying practice was reasonable.
I'sing NCA's recommendation of an 8.5
percent margin (reported as "about 10
percent" in the preamble to
promulgation), coal impacts were
reanalyzed. This study showed
additional coal rmrket dislocations
(OAQPS-78-l, IV-B-72). For example, in
Illinois, Indiana, and V.'estern  Kentucky,
the impact on coal reserves by a 430 ng/
] (1.0 Ib/million Btu) heat input emission
limit increased from 15 percent without
the margin to 22 percent when the
margin was assumed. Considering only
currently owned reserves, the  impact
increased from 19 percent to 30 percent.
F.ven with the margin, the analysis
predicted no significant impact for a 520
ng/J (1.2 Ib/million Btu) heat input
standard.
  Having determined the extent of the
potential coal impacts associated with  a
lower emission limit, the Agency then
assessed the potential environmental
benefits. The assessment revealed that
by 1995 an emission limit of 430 ng/J (1.0
ill/million Btu) heat  input would reduce
national emissions by only 50  thousand
tnns per year relative to the 5 :0 ng/J (1.2
lb/million Btu) heat  input limit. That is,
trv projected emissions from new plants
would be reduced from 3.10 million tons
lu 
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          Federal  Register / Vol. 45, No. 26 / Wednesday, February 6, 1980 / Rules  and  Regulations
emission (tiling WHS not based on any
informal:;'-! not in the docket.
  Finally, it wa* not improper for the
Administrator to listen, to-and consider
the views of Senators and Congressmen,.
including Senator Byrd. Itisnotunusual
for members of Congress to express
their views on the-merits of Agency
rulemaking, and it is entirely proper for
the Administrator to consider those
views.
  EOF objecis particularly, to a meeting
the Administrator attended with Senator
Byrd on April 26,1979; arguing that the
contact was ex parte and improperly
influenced the Administrator's decision.
Neither contention is correct A
memorandum summarizing the
discussion at the meeting was pla^.-J in
the docket, and members of the public
have had the opportunity to comfc'.jui on
it, as EOF has done. No new information
was pi- seated to  the Administra''ir it
the mealing.
  Sena lor Byrd's comments at this
meeting -Jso did not improperly
influence the Administrator. Although
the Senator strongly urged the
Administrator to set the emission ceiling
at a level th?t would not preclude the
use of any significant coal reserves, !he
Admin;s?rator had already concluded
from i/;e 1977 Amendments to the Clean
Air Act that I'no revised standards
should not preclude significant reserves.
This view was based on the
Administrator's interpretation of the
legislative intent of the 1977
Amendments and was reflected in She
proposed emission ceiling of 520 ng/J
fl 2 ibs/niill'on Btu) beat input, as
discussed in the preamble  to the
proposed standards [43 F3 42160}
  This .  ., was reaffirmed in the final
rulemakir,;, based on the intent of the
1977 Amendments (44 FR 33595-3359bj.
Although the Administrator was aware
(as he   o"U have bet-n tv en in die-
absence ot : meeting) of Senator Byrd's
conce-i 1 .-.'. n cnMing lower then 520 ng/
J f! J ii.-''million 8tu}heat input would
in .nro.-tt-ifilcly preclude s'srificant coal
reserves, !> - Vli'iimstratur's decision
was not bus- ,i on Senator Byrd'*
expres.sicn of concern. The
Administrator had already concluded
that anv tiling more than a minima!
preclusion of the use of particular roa;
reserves would, in the absence of
significant resulting emission reductions.
be inconsistent with the intent of the
1977 Amendments. Because the
Agency's analysis showed that even :>.n
emission limit of 430 ng/J (1.0 Ibs/
million Bin) heat input could preclude
the use rf up to 22 percent of certain
coal reserves without significantly
reducing overall emissions, the
Adrninistr;>tor's judgment was that a
ceiling lower than 520 nj/'J (1.2 Ibs/
million Btu) heat input was not justified.
Thus, the views of Senator Byrd and
ojher members of Congress, at most,
served lo reinforce the Administra toe's
own judgment that the.proper level for
the standard  was 520 ng/J [1.2 Ibs/
million Btu). heat input. Even assuming,
therefore, that it was improper for the
Administrator to consider the views of
members of Congress, this procedural
"error" was not of central relevance to
the outcome of the rule..

//. SO, Minimum ControlLevel(70
Percent Reduction of Potential
Emissions)
  Th? Kansas City Power and Light
Company {KCPLj,*Sierra Club, and
Utility Air Regulatory  Croup (UARG)
requested th.1' a proceeding be
convened to reconsider the 70 percent
minimum control love! which-is-
applicable when burning- low-sulfur
coals. Both the Sierra Club ;md UAKG
maintauiBu ;hat they did not have an
opportunity to fuliy comment on.either
the find! regulatory analysis or dry SO*
scrubbing technology since the phase 3
irncroeconomic analysis of the standard
(44 FR 33603,  left column) and
supporting data wf.rp entered into th*
record after '^-> close of the public
comment period. Both  claimed that their
evaluation of this additional  information
provided insights which are of central
relevance to the Administrator's final
decision and  that reconsideration of the
standard is warranted. The KCPE,
petition did not allege  improper
admini.strative-procedures, but asked for
reconsideration based nn their
evaluation of the m<-ri:s of the standard.
  In seeking a more stringent minimum
reduction requirement, the Sierra Club
contended that dry SO., scrubbing is not
a demonslrati-u technology jnd.
therefore, no  basis exists for a variable
control standard. Alternatively, the
Sierra Club maintained th.it if dry
technology is considered demonstrated
the i->rurd supports a more stringent
n-.inimuni control !< vel. V, lib rt>s>pt*t,f :o
ihe regulatory analysis, the petition
c.bargf"! that faulty analytical
methodology and assumptions Id !ha
Agency to erroneous conclusions about
the impacts of the promulgated standard
relative to the more stringent uniform or
full control alternative1. They suggested
that analysis  perfoi.r.ad using proper
assumptions would support adoption of
a uniform standard.
  In support of a less stringent minimum.
reduction requirement, the UARG
petition presented o  rsgulatory analysis
which was prepared by their consultant.
National Economic Research AssociaU'3
(NERA). Based on this study, UARG
argued that a HO percent ruifiirman
requirement \vould be superior in terms
of emissions, costs, and energy i-npuus.
Finally, they argued that a low.-r percent
reduction would provide "renter
opportunity to develop dry SOj
scrubbing technology.
  In their petition KCPL sought either art
elimination of the percent reduction
requirement when emissions are 520
ng/J (1.2 Ib/million Btu) heat input or
less, ur, as  an altarnative, a reduction in
the 70 percent requirement In, support of,
thair request. KCFL set forth several
arguments. First, they cited, the.
economic and ene;gy impacts
associated  with the application of
scrubbing technology on low sulfur
coals. Second, they noted that a
significant  portion of sulfur in thy co^tl
they plan to burn will oa ra.'.ioved in the
fly ash. finally, they asserted thac health
,jn<; welfare considerdliu.ib do not
warrant scrubbing of lo'.v sulfur crals
?' ?.'-* thsir  uncontrolled SOj em: . . ,<...>
are lass than the emissions allowed lr-   '^
wra in'roducud i.o;' '.\Rrtt any nio
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8216     Federal Register  /  Vol.  45, Xo. 2(3 / Wednesday, February 6,  19HO / Rules and Regulations
v. i:h a 70 percent minimum control level.
hiiroduction of this option was
considered appropriate? since it raised
the same kind of economic, legal, and
technical policy issues as the earlier
analyses of 33, 50, and DO percent
minimum control options.
  Within this context, many of the
objections to the economic modeling  are
inappropriate grounds under section
307(d]f7J(B] for reconsideration since
they do not involve information on
which it was impracticable to comment
during the public comment period. For
example, the Sierra Club's comments
regarding modeling assumptions merely
restated those that had been
incorporated by reference into their
January 1979 comments (OAQPS-78-1,
1V-D-631 and IV-D-626). The only new
modeling issue raised during phase 3
'.vjs the application and cost of dry SO-.
scrubbing. These problems
notwithstanding each of the issues
raised by the various petitions were
evaluated carefully and are discussed
below.

Dr\ Scrubbing Technology
  The Sierra Club and LJARG both
raised issues concerning dry SO=
scrubbing technology in their petitions
for reconsidera'ion. While UARG
concurred with EPA's basic approach
with respect to dry scrubbing, they
maintained that thj Agency's objective
of developing the Full potential of this
t-'chnology would be bter served by a
50 percent minimum reduction
requirement. On the other hand,  the
Sierra Club was most critical of EPA's
consideration of dry scrubbing in the
rulemaking. They maintained that the
public was not afforded sufficient
opportunity to comment on dry
scrubbing technology. They  argued that
KPA. had not identified dry scrubbing as
a demonstrated tachnology nor had the
Agency set forth any regulatory'options
that embraced the technology. They also
cissprted that the treatment of dry
it,rubbing in the rulemaking was
inconsistent with Agsncy actions
CL'r.cerning other emerging technologies
such as  the establishment of commercial
demonstration permits for solvent
rctined coal and fluidized bed
combustion, and the rejection of
catalytic ammonia injection forNOx
cur.trol on the grounds that it had not
bet-n employed on a full-scale facility.
They also maintained that EPA had
shown little interest in dry scrubbing
prior to  the spring of 1979 and seized
upon it only af'.cr ths need arose to
justify a 70 percent minimum reduction
requirement. Finally, the Sierra Club
asserted that even if one assumed dry
scrubbing is adequately demonstrated.
the 70 percent reduction requirement is
too low. In doing so, they cited
information (Sierra Club petition, page
8) in the record that indicated that "up
to 90 percent reduction" can be
achieved with such systems.
  A review of the public record belies
these charges. The preamble  to the
proposed standards identified dry SO2
scrubbing, including spray drying, as an
alternative to wet FGD  systemc (43 FR
42160, left column). Subsequently, a
number of individuals and organizations
either submitted written comment or
presented testimony at  the public
hearing in support of a variable control
standard since it would not foreclose the
development of dry SO2 control
technology. For example, the spokesman
for the Public Service Company of
Colorado (PSCG) testified that his firm
wa= actively pursuing dry SO2 control
technology {dry injection of sodium-
based reagents upstream of a baghouse]
because it offered a number of
advantages compared to wet
technology. Advantages included lower
energy consumption,  fewer maintenance
problems, and simplified waste disposal
(public hearing transcript, December 13,
1978, pages 92-94). When questioned by
the hearing panel, PSCC testified that 70
percent removal is achievable with dry
scrubbing and that  they would pursue
the technology if a 70 percent
requirement was adopted (public
hearing transcript, December 13,1078,
page 102). Similarly, Northern States
Power testified that adoption of a sliding
scale would give impetus to their
examination of dry SO2 control systems
vhich  employ ;i spray absorber and a
fabric filter (public hearing transcript,
December 13,1978, page 226). Finally,
the Department of Public Utilities, City
of Colorado Springs testified that they
have a program to conduct on-site p'lot
tests of a spray-drying system for SOj
control. It was also noted that if a
sliding scale approach was adopted "we
feel there is no question but that dry
techniques would be used" (public
healing transcript, December 13, 1978,
pages 266-287).
  The  Air Pollution Control
Commission, Colorado  Department of
Health urged in their writtan comments
that the proposed emission floor be
raised to 172 ng/} (0.40  Ib/million Btu)
heat input in order to permit  the
development and application of dry
coniiol techniques such as the injection
cf dry  absorbents into a baghouse. They
noted that their recommendation would
require approximately 05 percent
reduction on a typical western low-
sulfur coal (OAQPS-78-1, IV-D-212).
The Washington Public Power Supply
System a'.so submitted wrii'sn
comments that affirmed the Agency's
finding on dry scrubbers as net-forth in
the proposal. They indicated that dry
scrubbing was superior to wet
technology when applied to western
low-sulfur coal. They noted that the
application of dry scrubbers would
result in lower capital, fuel, and
operation and maintenance costs, as
well as lower water use and simplified
waste disposal. They indicated further
that the uncertainty of being able to
achieve the proposed 85 percent
reduction requirement would foreclose
the installation of dry scrubbing
technology. Therefore, they
recommended that the proposed  
emission floor be raised to at least 210
ng/J (0.3 Ib/million Btu) heat input
(OAQPS-78-1, IV-D-330).
  Because of these commen's and the
public hearing testimony, the Agency
carried out additional investigations of
dry scrubbing technology during the
post-comment period. The  findings of
ihe analysis (-70-021, page 3-61} confirmed the
views of the cotnmenters that (he
adoption oi a uniform percentage
reduction requirement would have
constrained the development of dry
scrubbing technology. After carefully
reviewing the available pilot plant data
and information on the three full-scale
units that are under construction, it was
the Administrator's judgment that the
technology employing spray dryers
could achieve 70 percent reduction in
potential SO; emissions on both low-
sulfur alkaline and nonalkahne coals.
Data on higher emission reduction le've'.s
such as those noted by the Sierra Club
were discounted since they reflected
short-term removal efficiencies (not
representative of longer periods of
performance) and they were achiex ed
when high-alkaiine content coals were
fired. The Administrator's  judgment was
also tempered in this rpg;irtJ by the
public comments which  indicated that
rsmo' .il , or;'iiremen's higher th;m 70
pci'C'Mit would discourage  the continued
development  of the  technology.
Similarly, these .-iam^ commanter1?
c!c trly indicated that the techno'^jjv
we:, capable of exceeding  the 50 percent
reduction requirement du;;',:<.-=,tod by  tho
Utility Air Mediatory G'OV.
  The Sierra Club coinmc-nted that F.PA
was inconsistent in  its treatment of dry
scrubbing and catalytic ammonia
injection. In rejecting catalytic ammonia
injection for NOX control, the
Administrator note.I that it had not bewn
adequately dnmonstratad.  A review of
the record revc da ih.it the pnmcry
proponent of  this technology, the State
                                                       E-8

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         Federal Register /  Vol.  45,  No. 26  /  Wednesday. February 6, 19HO / Rules  and  Regulations    8217
of Ca'i.'uj'iiia Air Resources Board, also
recognized that it was not sufficiently
niivanccd at this time to be considered.
Instead, they merely recommended that
the standard require plants to set aside
space so that catalytic ammonia
injection could be added at some future
date (OAQPS-78-1, IV-D-268). In
comparison, dry scrubbing has
undergone extensive testing at pilot
plants, and there are three full-scale
facilities under construction that will
begin operation in the 1981-82 period.
  With respect to commercial
demonstration permits for solvent
refined coal and fluidized bed
combu-'ion, the standard merely allows
initial, f".ii-sca!e ^monstration units
some flexibility. Subsequent commercial
facilities will be required to meet the
final standards. In adopting this
provision, tho Administrator recognized
that initial full-scale demonstration units
often do not perform to  design
specification, and therefore some
ik'xibility was required if these capital
intensive, front-end technologies were to
be pursued. On the other hand, the
Agency concluded that  more
conventional devices such as dry
.scrubbers could be scaled up to
c:j:r.mercial-Mzed facilities with
reasonable assurance that the initial
facilities would comply with the
applicable requirements. In view of this,
the inclusion of dry scrubbing under the
commercial demonstration permit
provision was not appropriate.
  Finally, in a letter dated September 17,
1979, to the Administrator, the Sierra
Club submitted additional information
to buttress its argument that dry
scrubbing is not demonstrated
technology. This letter cited EPA's "FGD
quarterly Report" of Spring 1979. The
report indicates that the direct injection
of dry absorbents (such as nahcolite)
into the ,<^is stream may be a
breakthi-.~i!gh, yet it calls for further pilot
plant studies. The "inference the Sierra
Club drew from the article was that the
FPA technical staff does not believe dry
scrubbing is sufficiently developed to be
conside-ed in the rulemaking. The Sierra
Club failed to recognize that there are
several  different dry scrubbing
approaches in different stages of
development. The "FGD Quarterly
Report" doi's rot pertain to the
appioach employing a spray dryer and
baghouse with lime absorbent which
serves as the basis for the
Administrator's finding (EPA-450/3-70-
021 at 3-61).
  The Sierra Club also cited an article in
the Summer 1979 "FGD Quarterly
Report" on vendors' perspectives
toward dry scrubbing. In doing so, the
Sierra Club noted'that the article
indicates that vendors expressed an
attitude of caution toward dry scrubbing
which led the Sierra Club to conclude    
that the technology is not available. It ;
should be noted from the article that
only one of the vendors present was
actively engaged in dry scrubbing and
that firm was quite positive in their
remarks. Babcock and Wilcox, who had
conducted spray dryer pilot plant
studies and is pursuing contracts for
full-scale installations, commented that
"while the dry scrubbing approach is
new, the technology is proven."
Economic Modeling,
  The Agency's regulatory analysis
concluded that the v.iiiable control
standard with a 70 percent minimum
cor/1-;)' level would result in eqja! or
lower national sulfur dioxide emissions
thm tha uniform 90 percent standard
while having less impact on costs, waste
disposal, and oil consumption (44 FR
33607, middle column and 33608). The
Sierra Club petition charged that the
Agency used an unrealistic model and
faulty assumptions in reaching these
conclusions. The petition alleged that-'
utility behavior as predicted by the EPA
model is "incredible" and that this
incredible behavior leads to "ths
outlandish notion that stricter emission
controls will lead to more emissions."
The Administrator finds this allegation
to be without merit.
  The principle modeling concept being
challenged is whedier or not increased
costs of constructing and operating a
new plant (due to increased pollution
control costs) will affect the utility
operator's decisions on boiler retirement
schedules, the dispatching  of plants to
meet electrical demand, and the rate of
construction of new plants. The model
used for the analysis assumed that
utility companies over the long term will
make decisions that minimize the cost of
electricity generation. That is, (1) under
any demand situation utilities will first
operate their equipment with the lowest
operating costs, and (2) existing
generating capacity will be replaced
only if its operating costs exceed the
capital and operating costs of new
equipment. While political, financial, or
institutional constraints may bar cost-
minimizing behavior in individual cases,
tho Administrator continues to believe
that the assumption of such behavior is
the most sound method of analyzing the
impacts of alternative standards.
  Under this approach, the model
simultaneously adjusts both the
utilization of existing plants and the
construction schedule of new plants
(subject to Subpart Da) based on the
relative economics of generating
electricity under alternative standards.
Hence, average capacity factors for the
population of r..'-,-j plants may vary
among standards due to variations in
the mix of base and intermediate loaded
plants which are brought on line in any
one year. But this does not mean, as
concluded in the Sierra Club petition at
page 8, that the model predicted that
utilities would permit new base-loaded
units to remain idle while they continue
to build still more new units.
  The petition also alleged that this
modeling concept was introduced in the
phase 3 analysis, which Was completed
after the close of the public comment
period, and hence the modeling
rationale was not subject to public
review. The petition went on io criticize
some  of the assumptions in the model
ch,nging th&i they were not even
mentioned in the record.
  The Administrator finds no basis for
the Sierra Club's assertion that the
modeling methodology end input
assumptions were not exposed for
public review. First, the same model
was used for the phase 1, 2, and 3
analyses. The basic model logic was
explained in the preamble to the
September proposal and comments \\vrp
solicited specifically  on the use of a cost
optimization model for simulating utility
decisions (43 FR 
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                             /  Vol.
                              No. 26  /  Wrtdnesday. February fi, 1980 / Rules and Regulations
i:: 1079 OPEC price increase
which occurred after promulgation of
                               the standard. For the .sensitivity
                               analysis, the following oil prices in 1979
                               dollars were assumed:
                                           Assumed Oil Prices

                                            [Dull vs;?^ Barrel)
                                                       Sensitivity  Ptias* 3
                                                       analysis
1 '... .
1390 ....
1995  ...
                                                            25
                                                            30
                                                            08
                     20
                     26
                               These prices were obtained from
                               conversations with DOE's policy
                               analysis staff. The prices may appear
                               low in comparison to the example of
                               $41.00 per 'j,n rel spot market oil given in
                               the Sierra Club petition, but the Sierra
                               Club figure is misleading because
                               utilities seldom purchase spot market
                               c.l. The meaningful parameter is  the
                               average refiners' acquisition cost, which
                               was $21/barrel at the time of this
                               analysis. The original nuc'u.-ar capacity
                               assumptions were based on the
                               industry's announced plans for new
                               capacity. For sensitivity testing, these
                               estimates were modified by excluding
                               nuclear power plants in the early
                               planning stages while retaining those
                               now under construction or for which,
                               based on permit status, plans appear
                               fi.m. The following assumptions  of total
                               nuclear capacity resulted"
                 Table \.-Summary of 199s Impacts With Phase 3 Ass
                                             Level of control with 520 ny/J maximum'emission limit
                                             Current
                                            standards
                                          Variarie con-
                                           trol. 50 pet
                                           minimum
    VartatHe con-
     trol. 70 pet
      minimum
                                  Full
                                 control
   ior-al 3d E~ S
   Easi '-..
               S \ Til ,on tons)
    /.est S^.'-i Cen'rat    ..................
    West ..........       ...... ' .
 ..v- <"-nal Arn-ja.izso Cost loi'lions 19V8 S)
 -c-=--".ita< Cost ot SO, Peauction (t<378 S'to"t
 j< Co^st.mpHoo imriion bbi'day)
 ^. a' p'C
-------An error occurred while trying to OCR this image.

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J220     Federal Register / Vol. 45, No. 26 /  Wednesday,  February f>,  1980 /  Rules and Regulations
rt'i'.iion tons per year in (.orituibt to
;ibov.t J 5 million tons p-r ^ear under
!  ''i ;he phase 3 and the high oil price
s>-r.-.ilivity projections.
  V.'hile emission levels were roughly
the  r.ame as under the phase 3 energy
assumptions, the rtlative impacts  of the
nlternative standards changed
Mjrrif what. National emissions were
predicted to be 100,000 tons less under
Full Control than under the standard.
Relative to full control,  the standard
was still predicted to reduce emissions
by about 400,000 tons in the East, but on
a national basis this was offset by
e:v.-sion increases in the other regions.
\V!  h higher oil prices and less nuclear
 :ipacily, the environmental benefit of
IV.il t.ontrol in the West and West  South
Central was greater by  about 100.000
tons, but this impact is masked in Table
:i c'.- e to rounding. "I he variable standard
with a 50 percent minimum control level
'.suited in about 400,000 tons per  year
rr.cre emissions than fv.U control and
rib'.ii.t 300,000 tors per year more than
-'-.e i'andard.
  The total cost o' -ill the alternatives
..crpvised due to the increased coal
( j'i.'.'.\:y. Relative to the standard, the
cos* of che 50 percent variable control
btar.-'ard regained about the same. The
fail control standard, however, was
=' '^'ficantly more expensive. The
.T.a.'jr.nal cost of full control (relative to
the standard) increased from Sl.l billion
tr.'.'.er the phase 3 energy assumptions to
SI.i! billion.
  F.:-.ergy impacts were about the  same
as '.hose  predicted in the high oil price
'-t.T.sitivity runs. Oil consumption  was
h.'Il p;eJicted at r.bout  900.000 barrels
pur day under all alternative standards.
Ccv.l production under all alternatives
Increased by about 100 million tons per
'.car.
  L\ en considering the ur.c ertainty of
',/ure oil pnces and nuclear capacity,
tr'o Administrator found no basis for
c or.vening a proceeding on the modeling
iisue. The sensitivity runs did not show
^mficant changes in the jelative
i -lacts of the alternatives. Under the
^ Tiiitiuty test with bo'n high oil prices
 , ;d slowed nuclear growth, full control
'u~ '.he first time showed lower
 r".i fsary to protect our pristine
'>.r-.>;<.s and national parks (44 FR 33584.
left f.ol'jinn). As a result, the:
Administrator continues to believe thai
iht: flexibility offered by the standard
will lead to the best balance of energy,
environmental, and economic impacts
than either a uniform 90 percent
standard or a 50 percent variable
standard and hence better satisfies the
purposes of the Act.
  On the other side of the modeling
issue, L'ARG charged that the Agency's
regulatory analysis does not support a
70 percent minimum requirement. The
petition called the Agency's control cost
estimates unrealistic and presented a
macroeconomic analysis  which
concluded that a 50 percent minimum
requirement would result in a mure;
favorable balance of cost, energy, and
environmental impacts.
  Response to the UARG petition was
difficult because ihe UARG position wtis
presented in two separate reports
submitte 1 at different timea. and the two
reports reached different conclusions. In
the formal petition, UARG
recommended 50 percent minimum
co"!-o! and promised a detailed report
by  .",1'RA supporting their position.
\Vhen  the NERA report arrived six
weeks later, if recommended 30 percent
control. In light of this confusion, it was
decided to review each report
separ.-itely based  on its own merits, b;:t
devote primary attention to the 50
pei cent recommendation. After
reviewing UARG's macroeconomic
analysts, the Administrator finds no
convincing arguments for altering the
conclusion that the 70 percent minimum
removal requirement proviHes the best
balance of impacts. In  the formal
petition, UARG's conclusion that a 50
percent standard is superior was based
on  a N'ERA economic analysis which
ia ;',i.-.ed that  only wet scrubbing
ler.hnology was available to utilities. A
detailed analyst of the NERA results
was not possible  because only summary
outputs were supplied  in their
comments. But the results of this
analysis seem to coincide with the
Agency's conclusions that there are
energy, environmental, and economic
benefits, associated with standards that
pro\;r'.i> a lower cost control alternative
for lower sulfur coals. The problem with
the UARG initial  analysis is that it
overlooked the economic benefits of dry
scrub!, ing.
  In recognition of this shortcoming,
UARG presented their estimate of the
costs of dry scrubbing  made by Battelle
Columbus Laboratories (UARG petition.
page ^5) and then hypothesized without
supporting analysis that  "with realistic
cost assumptions the advantages of a
lower percent removal are likely to
increase evert further" (UAKG petition.
f'igf! 27}. Table; 4 compares U.ittellt1':;
t.osts to those used in Iht; EPA
regulatory analysis. Ihe two estimates
art: almost the same. More importantly.
the two estimates agree that the t.ost of
a 70 percent efficient dry system is not
significantly greater than the cost of a 50
percent efficient system, and this
conclusion had impuitant implications
in the specification of the standard.
Based on thsse comparisons, the
Administrator finds that the UARG
petition supports the Agency's uiy
scrubbing cost assumptions and the
finding that no significant cost benefit
will result from a standard  wish a 50
percer:! minimum control \: '-v SO,
        So:ub'jtr;: C.>.*.'.; ' f \W.X ,,-'O/
SO

70
0 BO
2 no
080
200
-' 1 <>H
'2 13
 1 '17
 ? 5-;
                                    20o
            CObls rar'j9 *p :o r) rr"'^ xxh
  - UAPG cosN t'a-.xl on T>5 p^fcenl rernrv n

  In their second report, UAKG
presented additional economic analyses
by NERA. In those analyes. the impacts
of r.O, 50, nd 70 percent minimum
cuiitrol standards wer t^st^d assuming
that both  .vet and dry scrubbing
technology were available. The analyses
were performed with three different sets
of control cost assumptionsI.l'A's
costs, Battelle's  costs, and an additional
set of costs specified by NEUA. The
report concluded that the 70 percent
standard is superior using LPA's  costs
but that under the other cost estimates
the 30 percent standard is better, '('he
i,ost effectiveness of alternative
standards (dollars per ton of pollutant
removed) was their principal basis of
evaluation. UARG then a'.leyed that KPA
overestimated the differences in cost
between wet and dry  r.rti'lHing and that
this error lei! :o  the wren > conclusion
about the impacts of the 70 percent
minimim ifnoval requirement. '\ In- Er'A
cost assumptions were cntir i/ed
primarily because different ;;.^ihods
\\ere used to estimate  dry and v,-,;t
sc.rubbing costs. To justify  their position.
UARG presented ost;r.itits of '.vet and
dry scrubbing costs daveloperl by
Battelle. UARG beeves that Jtaitc-Me
understand scrubber costs, but that
Battelle's relationship  b^r.v^en ivpt and
dry scrubbing costs is  more Mccura'e
than EPA's (UARG petition, pa^e 7). As
noted above, Battelie agreed with the
Agency's div scr;ibbir.a costs, but for
                                                            E-12

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                  Register / Vol.  45. No. 26 / Wednesday, February 6,  1980 / Rules and  Kf?,gu]a(ions     B221
wet scrubbing the Battelle costs were
substantially lower than the Agency's.
  Tyr- -"j;!y, when comparing results of
studies, the Agency has detailed
documentation with which to compare
the methods of costing and analysis. In
this case, the Administrator had
documentation for neither the NERA
costs nor the Battelle costs. The NERA
costs were unreferenced and supported
by neither engineering analysis nor
vendor bids. They assumed that the
capital cost of a dry scrubber is 10
percent less than that for a comparable
wet scrubber and that the operating
costs and energy requirements are the
same for the two systems. The UARG
petition promised a detailed report from
Battelle, but the report was not
delivered. Without a basis for
evaluation,  the Battelle and NERA costs
can only be considered as hypothetical
data sets for the purpose of sensitivity
testing of the economic analysis. They
cannot be considered as new
information on SO2 control costs.
  Tha EPA cost estimates, on the other
hand, have withstood several critical
tL'sts. Ihe PEDCo cost model for wet
scrubbers which was used by EPA was
th.>roiighly reviewed by Department of
Energy (DOE) consultants, and DOE
r.uncurrn ! ivith the F.PA estimates
through '.he interagency working group.
Later, the Agency's costs were again
reviewed in detail against wet scrubber
costs predicted by the Tennessee Valley
Authority's  scrubber design model.
While the two models initially seemed
to produce divergent results, careful
analysis of the respective costing
methodology showed that for similar
design soecifications the two models
produced costs that were very close, the
major difference stemming from
different assumptions about the
construction contingency fee (OAQPS-
78-1, IV-B-50). The Administrator
concluded from these cost comparisons
that  the Agency's flue gas
destilfui  J'ion cost assumptions are
reasonaM.j.
  Tn. ,  . A dry scrubbing costs were
based primarily un engineering studies
submi. ..-.id by electric utility companies
and equipment vendors for the full-scale
utili'y ;. stems now on order or under
cor.'.,ti':*;tion. Using these studies, the
EPA cost estinv-iifs were made in lull
cognizance  of the basic assumptions
used in  the PEDCo -.vet scrubbing model.
The result was that for economic
modeling purposes (OAQPS-78-1, IV-
A-2S, page 0-17} the dry scrubbing cost
estimates in the background document
(EPA 430/5-73-021, page 3-67) were
increased to reflect similar fuel
parameters, local conditions, and degree
of design conservatism as reflected in
the wet scrubbing costs. Since care was
taken in aligning these costs, the
Administrator does not accept UARG's
allegation that EPA's costs for wet and
dry scrubbing are invalid because they
were developed on an inconsistent
basis.
  Even if EPA accepted UARG's
unsubstantiated cost assumptions, the
NERA sensitivity analyses provided no
new insights nor did they materially
contradict the Agency's basic
conclusions about the standard. Using
the Battelle costs and NERA's
"alternative scrubber costs" as a range,
NERA predicted  that relative to 50
percent minimum control, a 70 percent
standaid would reduce national SOj
emissions by an additional 250 to 450
thousand tons per year compared to
aboat 100 thousand tons estimated by
EPA (Table 1). NERA predicted the
additional cos*s of a 70 percent
minimum standard relative to a 50
percent requirement would be between
$3C'0 million and $400 million per year
compared to $300 million predicted by
EPA. It \vas only in moving to 30 percent
control that the NERA results show .id a
distinct cost savings ($600 to SSCO
million] over the  70 percent level, but
(he 30 percent standard produced an
additional 700 ihuiu>and tons per year of
SO.- under both of their control cost
scenarios. The Administrator rejects the
30 percent standard advocated by
UARG because the potential cost
savings do not justify the potential
emission increases. In conclusion, the
trade-offs between costs and emissions
shown by UARG are generally similar to
those predicted by EPA in promulgating
the standard and therefore do i^ot
support a different standard from the 70
percent variable  standard adopted.

Other Issues
  Kansas City Power and Light
Company sought either an elimination of
the percent reduction requirement when
emissions are 520 ng/J (1.2 Ibs/miih'on
B" ,1 heat input or less or as an
...ornativs a reduction in Cut; 70percent
minimum control requirement. In their
aiguments, KCPL cited annualized
control costs for wet scrubbing of $11.4
Million and an energy penalty of 70
thousand tons of coal per year to
operate a scrubber. Second, they noted
that 14 percent of the potential SO,
emissions from the coal they plan to
burn will be removed by the fly ash.
Taking these two factors in account!
KCPL computed a cost effecth'eness
ratio for a hypothetical 650 MW unit to
be S j.OOO per ton of sulfur removed and
concluded that such control was too
expensive. Finally, they concluded that
scrubbing low-sulfur coals is not
warranted since uncontrolled SO* -
emissions from their new plants will be
less than the emissions allowed by the
standard for high-sulfur coals with 90
percent scrubbing.
  After careful review, the
Administrator finds that the KCPL
petition provided no legal or technical
basis for reconsidering the final rula.
First, the question of whether a plant
burning low-sulfur coal should be
required to meet the same percentage
reduction requirement as those burning
high-sulfur coal has been a central issue
throughout this decision-making. Since
this issue was raised in the proposul (43
PR 42155, left column), KCPL had ample
opportunity  to make their points during
the public comment period. In fact, it
was the recognition of this trade-off in
emissions between high-sulfur niid low-
sulfur coal that led the Administrator to
first consider the concept of variable
control standards (43 FR 42155, right
column). While sulfur removal by fly ash
does not represent best demonstrated
technology for SO> control, sulfur
removal by fuel pretreatment, fly ash,
and bottom ash may be credited toward
meeting the 70 percent requirement.
  Second, the KCPL petition does not
ii'lege the requisite procedural eiioi tii.it
the standard was based on information
on which they had no opportunity fo
comment. Their objections center
primarily on the economic and energy
impacts of wet SO, scrubbing on low-
sulfur coal. These issues were clearly
identified by the Agency in the
background  document supporting
proposal (OAQPS-78-1, 1II-B-3,
Chapters 5 and "). Furthermore, th
preamble to  proposal specifically
requested comments on the Agency's
assumptions for the regulatory analysis
(43 FR 42162, left column).
  Finally,  and more importantly, the
major points made by KCPL arc not of
central relevance to the outcoms of the
rule because ihe information presented
does not refute the Agency's data base
on wet j crabbing. Cun^uj'jr ihe
following comparisons to the
assumptions of the EPA regulatory
analysis.
  (a) The control cosis fj.iou'd by KCPL
for a 650 MW unit were Sol million in
capita! and $0.2 million in operating
expenses. The EPA assumptions applied
to a comparably sized unit result in $55
million in capital costs and S7 million in
operating expense.
  (b) KCPL quoted an energy impact of 8
tons of coal per hour to ope: ate the
scrubber.-Considering their operating
requirement  of 460 tons of coal per hour,
thr; energy penalty of SO2 control  is 1.7
                                                    E-13

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          Federal Register  /  Vol.  45,  No. 26 /  Wednesday, February 8, 1980  /  Rules auj Regulations
p" ,:e!it. The Agency's economic model
ci.i^-ned 2.2 percent.
  {'.) KCPL. computed cost effectiveness
of i'ne standard at S.'is>00 per ton of sulfur
i':"ioved. Th'.s Figure is based on a
misunderstanding of the application of
t'tu; fly ash removal credit toward the 70
percent removal requirement. According
to the standard, the scrubbing
requirement when assuming a 14 percent
SO2 removal in flyash is 65 percent
rather than 56 percent as calculated by
KCOL. At 65 percent scrubbing, the cost
pt.T ton of sulfur removed is $3100. This
converts to a cost of S1550 per ton of
sulfur dioxide removed which is similar
to the costs estimated by EPA for low-
=ijfur coal applications (OAQPS-78-T,
IU-8-3andiV-B-14).
  Thus,  the Administrator has already
concluded that energy and economic
costs greater than those cited by KCPL
are justified to achieve the emission
reductions - 'qv:.-;d by the standard.

Cr-rclusions on Minimum Control Level
  After carefully -,v?ighing the
.i.'gamfnts by 'he three petitioners, the
,\.-;rriirtist"ator-can find no new
information or ir.sights which are of
central relevance to his conclusions
about the benefits of a variable control
slandard with a 70 percent minimum
removal requirement. The Sierra Club
and UARG correctly point out that the
AjtM'jy's phase 3 analysis was
completed after tha ^lose of the public
c'j.T.ment period and (hot they were
therefore unable in comment on the final
step of the regulatory analysis. But in
assessing these comments it is important
to put the phase 3 analysis in proper
ci--.lext  with its role in the final
ck'O'oion. The Adminis'rator's
conclusions about the responses of the
utility industry to alternative standards
v\ers not based on phase 3 alone, but  a
series of economic studies spanning
more  than a year's effort. These
analyses were performed under, a range
of assumptions of -conomic conditions,
regulatory options, and flue gas
i'':>ulfurization parameters. The phase 3
analysis was merely a fine tuning of the
regulatory analysis to reflect dry
scrubbing technolc.i-y.  .
  No  new modeling concepts or
;. .sumptions were introduced in phase 3.
The fundamental modeling concept as
'.Produced in the September proposal
;~3 FS 42181, right column) has not
< ''longed. The model input assumptions
v.vre the sama as those of the phase 2
analysis presented on December 8,1978
(-44 FR 54834, middle column), and at the
December 12 and 13,  1978, public
ho.iring. Detailed consultants' reports on
t^p modeling analyses were available
"' comment before the close of the
public comment period. This public
record provided adequate opportunity
for the public to comment both on the
principal concepts and detailed
implementation of the regulatory
analysis before the close of the public
comment period.
  Even though new information was
added to the record after the close of the
comment period, none of the petitions
raised valid objections to this
information or cast any uncertainty that
is germane to the final decision. The
Administrator has very carefully
weighed the petitioners comments on
dry scrubbing and the UARG sensitivity
analysis on pollution control costs. Not
only did the UARG analysis generally
confirm the conclusions of the EPA
regulatory analysis, but it established
that even if dry scrubbing costs vary
substantially, the relative impacts  of a
50 versus 70 percent minimum removal
requirement change very little. The 70
percent standard was estimated to
produce lower emissions for only
slightly higher costs. Differences in cost
effectiveness, which UARG seem to
weigh most heavily, varied by only S2 to
a maximum of $50 per ton of SO3
removed across alternative cost
estimates. In the final analysis none of
the petitions repudiated the Agency's
findings on the state of development,
range of applicability, or costs of dry
SO- scrubbing. In light of these findings,
the Administrator finds the information
in the petitions not of central relevance
to the final rule and therefore denies the
requests to convene a proceeding to  .
reconsider the 70 percent minimum
removal requirement.
///. S02 Maximum Control Level (90
percent reduction of potential SO*
emissions)

  Petitions for reconsideration
submitted by the Utility Air Regulatory
Group (UARG) and the Sierra Club
questioned the basis  for the maximum
control level of 90 percent reduction in
potential SOj emissions, 30-day rolling
average. The  other petitions did not
address this issue. However, in a July 18,
1979, letter, the Environmental Defense
Fund (EDF) requested EPA to review
utilization of adipic acid scrubbing
additives as a basis for a more stringent
maximum control level. An additional
analysis by UARG was forwarded to
EPA on January 28,1980. Although it
was reviewed by EPA, a detailed  *
response could not be prepared in the
three days afforded EPA for comment
prior to the court's deadline of January
31, 1980, for EPA to respond to the
petitions. However, the only issue not
previously raised by  UARG (boiler load
variation) has been addressed by this
r'"--ponse.
  With their petition. UARG submitted u
statistical analysis of Hue gas
d'tsulfurizutioa [FCD) system test data
which purportedly revealed certain
flaws in the Agency's conclusions. The
UARG petition maintained that a
scrubber with a geometric mean
(median) efficiency of 92 percent could
not achieve the standard because of
variations in its performance. UARG
also maintained that the highest removal
efficiency standard that can be justified
by the Agency's data is 85 percent, 30-
day rolling average.  In the alternative.
they suggested that the 90 percent, 30-
day rolling average standard could be
retained if an adequate number of
exemptions were permit'ed during any
given 30-day averaging period. On '.he
other hand, the Sierra Club  questioned
why the standard had b^-en established
nt 90 percent when the Agency hdd
documented that well-designed,
operated, ' FGD system
alone. In short, UARG did not analyze
the promulgated standard (44 FR 33582,
center column). Furthermore. UARG
underestimated the minimum
performance capability of scrubbers by
assuming that future scrubbers would
no* yven achieve  ;hr! lev-;l of process
control demonstrated by the best
existing systems tested by EPA.
  EPA has prepared two reports whii.h
re-analyze the same KCi) test data
considered in UARG's analysis. One
report identified the important design
and operating differences in the I-GD
systems  tested (OAQPS-78-1. Vl-B-14)
by EPA and the second report provided
additional statistical analyses of these
data (OAQPS-78-1.  VI-B-13]. The
results of the EPA analyses showed that:
  1. I iue gas desulfuri.:cition systems
can achieve a 30-day rolling uverage
cfficiuncy between 88 percent and 8U
                                                        E-14

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          Federal Register / Vol. 45, No.  26 / Wednesday,  February  8,  1980 / Rules and Regulations    0223
peicent fbase loaded boilers) or
between 8b and 87 percent (peak loaded
boilers) with no improvements in
currently demonstrated process control.
  2. Even if a new FGD system attained
only 85 percent efficiency (30-day rolling
average], a 90 percent reduction in
potential SO2 emissions can be met
when sulfur  reduction credits are
considered.
  To clarify  the basis for the Agency's
conclusions, the following discussion
reviews the development of information
used to establish the final percent
reduction standard.  Initially, EPA
studied the application of FGD systems
for the control of SO3 emissions fro^
power plants. As part of that effort,
information which described the status
and performance of FGD systems in the
U.S. and Ja;.an was  inventoried and
evaluated. These evaluations included
the development of design information
on how to improve the median
efficiency of FGD systems based upon
an extensive testing program at the
Shawnee facility (OAQPS-7&-1, II-A-
75). The Shawnee test data and other
data (OAQPS-78-1.1I-A-71) on existing
FGD systems were generated by short-
term performance tests. These data did
not def.ne the e*Ducted performance
range (the miii."\..T. and maximum SO-
percent removci!) of  state-of-the-art FGD
systems.
  Because a  continuous compliance
standard was under consideration,
information about the process variation
of FGD systems was needed to project
the performance range of scrubber
efficiency around the median percent
removal level. For the purpose of
measuring process variation, several
existing FGD systems were monitored
with continuous measurement
instrumentation. The selection of FGD
systems to be tested was limited
princip.'My to the few FGD systems
available which were attaining 80 to 90
percent in- ,'i;'n reduction of high-sulfur
coal emissions. When examining the
rc!"lts of these tests, it should be
recognized thai they do not reflect the
performance of a new FGD system
specifically designed to attain a
continuous compliance standard.
  When the  percent reduction standard
was proposed. EPA projected the
performance of newly designed FGD
systems.  The projection, referred to as
the "line  of improved performance" in
the analysis, was principally based on
the information on how lo improve
median system performance (OAQPS-
78-1, III-B-4). The line showed that
compliance with the proposed standard
(85 percent reduction in potential SOj
emissions, 2-1-hour average) could be
attained with an FGD system if the only
improvement made n Ulive to an
existing FGD system was to increase the
median efficiency to 92 percent. The
"line of improved performance" did not
reflect the sulfur reduction credits that
could be applied towards compliance
with the proposed standard or the
improvements in process control (less
than 0.289 geometric standard deviation)
that could be designed into a new
facility. While these alternatives were
discussed in detail and included within
the basis for the proposed standard
(OAQPS-78-1, III-B-4), the purpose of
the ''line of improved performance" was
to show that even without credits or
process control improvements, the
proposed stand >rd could be met. Upon
proposal, the source owner was
provided a choice of complying with the
percent reduction standuta by (1) an
FGD system alone {85 percent reduction,
24-hour standard), or by (2) use of sulfur
reduction credits together with an FGD
system attaining !f>ss than 85 percent
reduction.
  After proposal, EPA continued to
analyze regulatory options for
establishing the final percent removal
recjuirement. On December 8,1978,
economic analyses of these additional
options were publibhfic! in the Federal
Register (43 FR 57834) for public
comment. In this notice EPA stated that:
  Reassessment of the assumptions made in
tha August anwhbis also revealed that (he
impact of the coal washing credit had not
been considered in the modeling analysis.
Other credits allowed by the September
proposal, such as, sulfur removed by the
pulverizers or in bottom ash and flyash, were
determined not to be .significant when viewed
at the national and regional levels. The coal
washing credit, on the other hand, was found
to have H significant effecl on predicated
emissions levels and, thereiure, was taken
into consideration in the results presented
here.

  This statement gave notice that the
effect of the coal washing credit on
emission levels for the proposed control
options had not been i -cp<.'Hy assessed
in previous modeling anayses. In the
economic analyses completed before
proposal, the environmental benefits of
the propc,.-.. d .J^ndard were opti'matte
because it w;>s assumed that ail high-
sulfur coal would bp washed, but a
corresponding reduction in the level of
scrubbing needed for compliance  was
not taken into account. This error
resulted in the analyses understimating
the amount of national and regional SOj
emissions that would have been allowed
by the proposed standard. This problem
was discussed at length at the public
hearing on December 12,1978 (OAQPS-
78-1, IV-F-l, p. 11, 22, 28, and 29).
  UARG addressed this question of coal
washing in comments submitted in
response to recommendations presented
ut the public hearing by the N.i'u.'.d
Resources Defense Council (OAQPS-/8-
1, IV-F-l, p. 65, 12-12-78) that the tinal
standards be based upon the removal of
sulfur from fuel to^f liter with the
removal of SO? from flue gases with a
FGD system. In their comments
(OAQPS-78-1, IV-D-725, Appendix A,
p. 23), UARG had three main objections:
  (1) All coals are not washable to the
same degree.
  (2) Coal cleaning may not be
economically feasible.
  (3) The Clean Air Act ar.r the
Resource Conservation and Recovery
Act may preclude the construction of
coal washing facilities al every mine.
  EPA has  reviewed these comments
again and does not find that they chan^,-
the Administrator':, conclusion thai
washed coal caft be used in conjunction
with FGD systems to attain a M percent
reduction in potential SO* emissions.
First, EPA realizes that all coal is not
equally washable. In the regulatory
analaysis, the degree of coal washing
was a function of the rank and sulfur
content of the coal. Moreow,, b.-c.Kise
of tha variable control sen!:; \.\. _-r->nt in
the standard, 75 percent of U.S coal
reserves would require  less than fiO
percent reduction in ; ulential SO?
emissions. The remaining 25 percent are
high sulfur coals or< which the highest
degree of sulfur removal by coal
washing are acheived. Second, the
washing assumptions used by the
Agency reflected the percentage of
sulfur removal currently being attained
by conventional coal wa>hin'^'p!ants in
the U.S. (OAQPS-78-1,  IV-D-755).
These* washing percentages were
therefore cost-feasible assumptions
bcc.Juse they are typical of current
washing practices. Finally, the A. 'jncy
does not believe that environment:'.!
regulations will prohibit the -.-leaning of
coal. The Clean Air Act and the
Resource Consrv.jiinn and Recovery
Act may impose curtain environmental
controls, but would  not prever.' the
routine construction of  coal wnslii. j;
plants. Thus, the Agency roncluded that
the basis for the promuUjatu': .star.dc
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B224
Federal  Register / Vol. 45. No. 26  /  Wednesday, February 6, 1980  /  Rules and Regulations
bo'tom ash are also applicable". Thus,
FGO systems toyeilittr with removal of
sulfur from the fuel was the basis for the
final standard. The standard prohibits
the emission of more than "10 percent of
ths potential combustion concentration
(90 percent reduction)." That is, the final
standard requires SO percent reduction
of the potential emissions {the
theoretical emissions that would result
from combustion of fuel in an uncleaned
state), not 90 percent removal by a
scrubber.
  Since UARG failed to take into
consideration sulfur reduction credits,
UARG analyzed a more stringent
standard than was promulgated.
Furthermore,- EPA's review revealed that
while the statistical methodology in the
UARG analysis was basically correct, it
was flawed by UARG's assumption
about the proceed \arL;tion of a new
FGD system. As a result, the statistical
anaysis was improperly used by UARG
to project the number of violations
expected by a new FGD system.
  To elaborate on the variability issue,
page 14 of the UARG petition states:
  The rjnye of efficiency variability values
resulting from this analysis represents the
r.inge of efficiency variabilities that can be
expocted to be encountered at future FGD
sites.
  This assumption artificially inflated
the amount of variability that would
reasonably be expected in a new FGD
system because it presumed that there
\\ere no major design and operational
differences in the existing FGD systems  -
tested and that the performance of new
systems would not improve beyond that
of systems tested by EPA. To estimate
process variability of new FGD systems,
UARG simply averaged together all data
from all systems tested including
malfunctioning systems (Conesville).
EPA's review of these data showed that
ihere were major design and operating
d-.fferences in the existing FGD systems
u-sted and that the process control could
he improved in new FGD systems
(OAQPS-78-1. VI-D-14). Therefore, not
all of the FGD systems tested by EPA
u'(:n> representative of best
i -monstrated technology for SOj
control.
  These major differences in the FGD
systems tested are app?rL>nt when the
tost reports are uxamined {OAQPS-78-1,
VI-D-14).One of the tests was
conducted when the FGD systems were
not operating properly [Conesville). Two
to Ms were conducted on regenerative
FGD systems (Philadelphia and
Chicago) which are not representative of
a lime or limestone FGD system.
Another test was on an adipic acid/lime
FGD system (Shawnee-venturi). None of
                              these tests were representative of the
                              process variation of well-operated, lime
                              or limestone FGD systems on a high-
                              sulfur coal application (OAQPS-78-1,
                              VI-B-14).
                               Only three systems were tested when
                              (1) the unit was operating normally, and
                              (2) pH control instrumentation was in
                              place and operational (Pittsburgh,
                              Shawnee-TCA, and Louisville). Only at
                              Shawnee did EPA purposely have
                              skilled engineering and technician
                              personnel closely monitor the operation
                              during the test (OAQPS-78-1, VI-B-14).
                              Data from these systems best describe
                              the process control performance of
                              existing lime/limestone FCD systems.
                                During the Pittsburgh test, there were
                              some problems with pH meters. The
                              data was separated into Test I (pH
                              meter inoperative) and Test II (pH meter
                              operative). During Test!. operators
                              measured pH hourly with a portable _
                              instrument (OAQPS-78-1, VI-D-14).
                              Analysis of these d_ata show low
                              process variation during each test period
                              (OAQPS-78-1, VI-B-13). Although the
                              process variation during the second test
                              WHS 10 percent lower, the difference
                              was not found to be statistically
                              significant. Data taken during each test
                              (I and U) are representative of control
                              attainable with pH controls only. Boiler
                              load was relatively stable during the
                              test. Average process variation as
                              described by the geometric standard
                              deviation was 0.21 and 0.23,
                              respectively.
                                At Shawnee, only pH controls were in
                              use, but additional attention was given
                              to controlling the process by technical
                              personnel. Boiler load was purposely
                              varied. Geometric standard deviation
                              was 0.18/which was similar to that
                              recorded at Pittsburgh. UARG
                              acknowledged that careful attention to
                              co.itrol of the FGD operation by skilled
                              personnel was an important factor in
                              cor.trol of the Shawnee-TCA scrubber
                              process (OAQPS-78-1. II-D-^40, page
                              3). It was at the Shawnee test that the
                              b jst control of FGD prea-ss variability
                              by an existing FGD system was
                              demonstrated iOAQPS-78-1, II-B-13).
                                The Louisville test appears to
                              represent a special case. The average
                              process variation was significantly
                              higher (0.30 and 0.34 for the two units
                              tested) than was recorded at the two
                              other tests (Pittsburgh and Shawnee).
                              A P. EPA contractor identified two
                              f-jctors which potentially could
                              adversely affect process control at
                              Louisville (OAQPS-78-1. VI-B-14). First.
                              they noted that Louisville was originally
                              designed in the 1960's and has had
                              significant retrofit design changes which
                              could affect process control. Second, the
                              degree of operator attention given to
process control is unknown. In addition.
UARG showed that an additional factor
which may affect the FGD process
control is boiler load changes. Unlike a
new boiler, the Louisville unit is an
older boiler which has been placed into
peaking service and therefore
experiences significant load changes
during the course of a day. As was the
case with Pittsburgh and Shawnee,
Louisville only uses pH controls to
regulate the process. The process
variation was analyzed and the
maximum process variation of the
Louisville system, at a 95 percent
confidence level, was determined to be
0.36 geometric standard deviation
(OAQPS-78-1, VI-B-13). This estimate
of process variation represents a "worst
case" situation since it ruiiects the
degree of FGD variability at a peaking
init ra-.her than on the more easily
controlled immediate- or base-loaded
applications.
  In addition to basing their projections
on nonrepresentative systems. UARG
has also ignored information in a
ba: ground information  document
(OAQ;'S-78-l, II-D-4. section 4.2.6) on
feasible process control improvements
which were currently used in Japan
(OAQPS-78-1, II-I-359).  An appraisal of
the degree of process instrumentation
and control in use at the  existing FGD
systems tested and a review of the
feasible process control improvements
which can be designed into new FGD
systems was also reviewed fOAQPS-
78-1, VI-B-14). As described in this
review, none of systems  tested had
automatic process instrumentation  .
control in operation. All  adjustments to
scrubber operation were made by
intermittent, manual adjustments by an
operator. Automatic process controls,
which provide immediate and
continuous adjustments, can reduce the
process control response time and the
magnitude of FGD efficiency variation.
Even the best controlled i'GD systems
tested (the Shawnee FGD system, which
was designed in the 1960's) employed
only feedback pH process control
systems [OAQPS-73-J, IV-J-20). None
of these existing FCD systems ,vere
designed with the feedforward proct;t,:>
control features now used in Japan
{OAQPS-78-1. 11-1-359) for the
automatic adjustment of scrubber make-
up in response to changing operating
conditions. These systems respond to
boiler load changes or the amount of
SO. in the flue gases to be cleaned
before they impact the; si-rubbing
system. The use of such systems would
improve the control of short-term FGD
efficiency variation. At the FGD systems
tested, the actual Hue gas SQ2
                                                         E-16

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          Federal Register / Vol. 45,  No. 26 / Wednesday, February 6, 1980 / Rules and Regulations    8225
concentration [affected by coal sulfur
content) and gas volume (affected by
boiler load) was not routinely monitored
by the FGD system operators for the
purpose of controlling the FGD
operation as is currently practiced in
Japan (OAQPS-78-1, II-I-C59). Thus,
even the best controlled existing
systems tested were not representative
of the control of process variation that
would be expected in the performance
of new FGD systems to be operated in
the 1960'3 (OAQPS-78-1, VI-B-14). For
the purpose of describing the range in
performance of an FGD system using
only feedback pH control and which are
known to have received-close attention
by operating personnel, the data .
recorded at these two existing FGD
systems (Pittsburgh, test fl and
Shawnee-TCA) have been used by EPA
to project the maximum process
variation that would result (0.23
geometric standard deviation)  at a 95
-, ' ent confidence interval for a base
loaded boiler. The data from Louisville
was used  to represent performance of a
peak loaded boiler (0.38 geometric
standard deviation at the 95 percent
confiden.cs lev;.'!). These values are
corner, -.live because the data collected
at :h= '^::sting FGD systems tested are
net representative of the lower process
variation that would be expected in
future FGD systems designed with
imo.-ov-rd process control systems
(GAQPS-73-4, VI-B-14).
  F.PA's statistical analysis of  scrubber
efficency is in close agreement with the
UARG analysis when the same process
variation and amount of autocorrelation
was assumed. EPA's analysis showed
about the  same autocorrelation effect  '
(the tendency for scrubber efficiency to
follow the previous day's performance)
as UARG's analysis. A "worst-case" 0.7
autocorrelation factor was used in both
arialyses even though a more favorable
0 n factT could have been used based
irion the measured autocorrelation of
the data at the Shawnee-TCA and
Pirt"v .:rrh '-:-'-is. A Comparison of the
minimum 30-day average performance
of ,1 FGD .system based upon EPA and
UARG process variation assumptions is
pi1, en H Tf.ble 5a.
  The EPA analysis (OAQPS-7S-1, VI-
B-13) summanz.?d in Tables 5a and 5b
shows the median scrubbing efficieny
required to ac> isve \ arious minimum 30-
day rolling average removal levels
(probability of 1 violation in 10 years).
The three  sals of estimates shown are
based on (1) the same process  control
demonstrated at Pittsburgh, test II and
loaded, well-operated existing  plant
( slams tested ftJAc3 i-a^sl
                        Average
                                          Maximo"
                                                                       -^0 431
                                                     , = <) i9]
90
89 	 _ 	
88 	
67
85 	
65 	

_ . .. 926
91 8
	 9t 1
903
	 89 S
888

929
'92-2
91.5
908
901
893

O.'S
629
922
31 6
909
90.3

94 9
844
938
933
9? 3
923

   
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B22S    Federal Register / Vol. 45, No.  2Q j Wednesday. February  6, 1980  /  Rules and Regulations
be substantial, ars summarized as
follows:
  1. Coal washing. On high-sulfur
iniciwestern coals that would be subject
to the 90 percent reduction requirement,
an average of 27 percent sulfur removal
was achieved by conventional coal
washing plants in 1978 (GAQPS-78-1),
IV-D-761). Even in Ohio where the
lowest average coal ivadhino reduction
was recorded, 20 percent reduction was
attained. These data represent current
industry practice and do not necessarily
represent full application of state-of-the-
art in coal cleaning technology.
  1. Coal pulverizers. Additional sulfur
reductions are abo attainable with coal
pulverizers used a? power plants. Coal is
typically pulverized at power plants
prior to combustion. Bv  seldctir.g a
specific type of coal pulverizer (one that
will reject pyrites from the pulverized
coal), sulfur can be removed. One utility
company reported to EPA that sulfur
reductions of 12?', to 33% (with 24%
average removal) had been obtained
(OAQPS-78-1. n-D-179) by the
palvizers alone vvhen a program had
been implemented to optimize the
rejection of pyrites by the pulverizer
equipment.
  3. Ash retention. One  utility company
has reported 0.4% to 5.1% sulfur removal
credit in bottom ash alone with eastern
and midwestern coals and 7.3% to 13.9%
removal with a western coal (OAQPS-
7S-1, II-R-72). To determine how much
sulfur is removed by the bottom ash and
fly a-sh combined, EPA conducted a
study in which numerous boilers were
tested. The amount of SO3 emitted was
compared to the potential SOa emissions
in the coal. For eight western coals and
six midwestern coals, an average sulfur
retention of 20 percent and 10 percent,
respectively, was found (OAQPS-78-1,
IY-A-6). Thus, an average of at least 10
percent SO-  reduction can be attributed
to sulfur retention in coal ash.
  These credits together with an FGD
system continuously achieving as little
as 85 percent reduction  are sufficient to
attain compliance with  the final SOi
percent reduction standard as is  shown
in Table 5:

Table .Impact of Sulfur Reduction Credits
  cn Required FGD Control Efficiencies to
  AKain 30 Percent Overall SO, Reduction
SO, removal rretfiod _

Cos) wasWng removal, caicent 
Pu'veriier, fly ash, snd bcrt'cx" ash
reduction, pwcarf- 	
FCO system refrovii. percent  ,-.
O\fall SO, rmixrteo m poter.Oal

Cwp'tance
A
27
10
85
90
B
20
4
87
90
Option
C
8
0
69
90
  Table 6 illustrates that even if the
FGD system attained only 85 percent-
reduction as UARG has claimed, the 90
percent removal standard would be
achieved (Option A] even if a coal
washing plant attained only 27 percent
reduction in 3ulfur (the average
reduction reported fay the National Coal
Association for conventional coal
washing plants, OAQPS-78-1, IV-D-
761). In addition, Table 8 illustrates that
less fuel credit is needed when the FGD
system attains more than 65 percent
reduction (Options B and C). For
example, even if the minimum amount of
coal washing  curently being achieved
(20 percent in Ohio)  is attained, only 87
percent FGD reduction would be
needed. Thus, less than average or only
average sulfur reduction credits (i.e.,
only 8-27% coal washing and 0-10%
pulverizer, bottom ash and fly ash
credits) would be needed to comply with
the 90 percent reduction standard even
if the FGD system alone only attained 85
to 83 percent control. Moreover, for 75
percent of the nation's coal reserves
which have potential emissions less
than 260 ng/J  (8.0 Ibs/million Bra) heat
input (OAQPS-78-1, IV-E-12, page 13),
less than SO percent reduction in
potential SO emissions would be
needed to meet the standard.
  The statistical analysis submitted by
UARG does not address the basis (FGD
and sulfur reduction credits) of the
standard and therefore does not alter
the conclusions regarding the
achievability  of the promulgated percent
reduction standard. The prescribed level
can be achieved at the individual plant
level even under the most demanding
conditions through the application of
scrubbers together with sulfur reduction
credits.
   Finally. UARG's petition (p. 15) states
that the final  standard was biased by an
error in the preamble (see table, 44 FR
33592) which  incorrectly referred to
certain FGD removal efficiencies as
"averages" rather than  as geometric
"means" (medians). These removal
efficiencies were properly referred to as
"means" in the EPA test reports. This
discrepancy had no bearing on EPA's
decision to promulgate a 90 percent SOj
standard. Even though UARG claims a
bias was introduced, their consultant's
report states (see Appendix B, Page 48):
   Therefore, even though EPA mistakenly
used the term "average SO, removal" in the
promulgation, it is obvious that when the
phrase "mean FGD efficiency" is used. EPA is
correctly referred to the mean [or median] of
the long-normal distribution of (1-efi).
Thus, even though Entropy (UARG's
consultant which prepared their
statistical analysis in Appendix B)
"discovered a discrepancy" as UARG
alleges, they did not reach a conclusion
as UARG has done, that a simple
transcription error in preparation of the
preamble undermined the credibility of
EPA's analysis of the test data. In fact,
the analysis of test data performed by
EPA (OAQPS-78-1. Il-B-4) used correct
statistical terminology.
  The Sierra Club also submitted a
petition that questioned the promulgated
90 percent, 30-day rolling average
standard. The petition asks "why the
final percentage of removal for 'full
scrubbing' was set at only 90 percent for
a 30-day average" in view of the
preamble to the proposal which
mentions a 92 percent reduction (43 FR
42159). The petition states that "EPA
indicated that 85 percent scrubbing on a
24-hour average was equivalent to 92
percent on a 30-day average." This
statement is a misquotation. The
preamble actually stated that "an FGD
system that could achieve a 92 percent
long-term (30 days or more) mean SOS
removal would comply  with the
proposed 85 percent (24-hour average)
requirement." The long-term mean
referred to is the median value
(geometric mean) of FGD system
performance,  not an equivalent
standard. Reference in the preamble
was made to the  background
information supplement {OAQPS-78-1,
III-B-4) which provided "a more
detailed discussion of these findings."
Tha 92 percent removal is described
therein as the median (geometric  mean)
of the statistical distribution defined by
the "line of improved performance" in
Figure 4-1. A median is the middle
number in a given sequence of numbers.
Thus for a sequence of 24-hour or 30-day
rolling average efficiencies, the median
SO, removal (92 percent) is a level at
which one-half of the 30-day rolling
averaf? FGD. system pffi pi awJaa would
be higher and one-half would be lower.
Since one-half of the expected removal
efficiencies would be lower than  the 92
percent median, a standard could not be
set al that level. The standard must
recognize the range of 30-day rolling
average FGD efficiencies that would be
expected. The petition is based upon a
misconception as to the meaning  of the
92 percent value (a median) and is
therefore not new information of  central
relevance to this issue.
   The Environmental Defense Fund
requested that EPA consider the
relevance of the lirne/limestone-adipic
acid tests at Shawnee to this
rulenjaking. Adipic acid has been found
to increase FGD system performance by
limiting the drop in pH that normally
occurs at the gas/liquid interface during
SOi absorption. Test runs at Shawnee
                                                   E-18

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I-'i!dera_l_Regiiter_/
                                                               February  6, 1980 / Rules and Regulations     8227
 sluj.^.'.l incre.i ,<.'! FCD performance (in
 or.*-: tijst rifiitis '.:
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Ji'228     Federal Register  /  Vol. 45,  No. 26  /  Wednesday, February 8, 1080 '/  Ru!*js and Regulations
!;>ss than one percent increase in
relation to utility operating costs. It
should be reported, however, that as a
result of corrective measures taken at
Harrington station since start-up, the
operating pressure drop reported by
UARG has been reduced. If the pressure
drop stabilizes at this improved level 2
kilcpascals (8 inches HjO) rather than
the 2.75 kilopa^cals (11 inches HjO)
suggested by UAKG the $191,000 cost
penalty would be reduced by some
530,000 per year (OAQPS-78-1, VI-B-11
and UARG petition, page 43).
  UARG also maintained that a period
longer than 180 days after start-up  is
required fo shake down new bahouse
installations, and that EPA should
;.,r.end 40 C1;R S0.8, which requires
compliance to be demonstrated within
180 days of start-up. UARG based  these
comments on the experience at the
Harrington and Monlicello Stations. It is
important to understand that 40 CFR
GO.8 only requires compliance with the
emission standards within 180 days of
start-i'p and  does not require, or even
suggest, that the operation of the facility
be optimized within that time period.
Optimization of a system is a continual
process based on experience gained
with time. On the other hand, a system
may be fully capable of compliance with
the .standard before it is fully optimized.
  In the case of the Harrington station
the initial performance test was
conducted by the utility during October
1978 (which was within four months of
start-up). The initial  test and a
subsequent one were found however, to
bj invalid due to testing errors and
therefore it was February 1979 before
valid test results were obtained for the
Harrington Unit (OAQPS-78-1, IV-B-1,
page 42). This tpst clearly demonstrated
achievement of the 13 ng/j (0.03 lb/
million Btu) heat input emission level.
"i he.se results were obtained even
'hough the unit was still undergoing
operation and maintenance refinements.
With respect to the Monticello station,
UARG reported that no actual
performance test data are available
(UARG petition, Appendix E, page 6).
  UARG also maintained that
l-ahouses are not suitable for peaking
uir'ts because of the  high energy penalty
associated with keeping the baghouse
above  the dew point. EPA recognizes
that baghouses may not be the best
control device i.jr all applications.  In
those instances where high energy
penalties may be incurred in heating the
f','ihouse above the dew point, the
utility would have the option of
employing an electrostatic precipitator.
However, some utilities will be using
b.'ighouses for peaking units. For
example, the baghouse control system
on four subbituminous, pulverized coal-
i'tred boilers at the Kramer Station have
been equipped with baghouse preheat
systems and that station will be placed
in peaking service in the near future
(OAQPS-78-1, VI-B-10).
  UARG also argued that it may be
necessary to install a by-pass system in
conjunction with a baghouse to protect
the baghouse  from damage during
certain operation modes. The use of
such a system during periods of start-up,
shutdown, or  malfunction is allowed by
the standard when in keeping with good
operating practice.
  The UARG  petition implied that the
test data base for electrostatic
prucipitator systems (ESP) is inadequate
for determining that such systems can
meet the standard. Contrary to  UARG's
position, the EPA data base for the
standard included test data obtained
under woist-case condition.-*, such as (1)
when high resistivity ash was being
collected, (2) during sootbiowmg, and (3)
when no additives to enhance ESP
performance were used (OAQPS-78-1,
III-B-1, page 4-11 and 4-12). E\ en when
all of the foregoing worst-case
conditions were incurred
simultaneously, particulate matter
omission levels were still less than the
standard. It should also be understood
that aone of the ESP systems tested
were larger than the mode! sizes used
for estimating the cost of control under
worst-case conditions.
  The UARG  petition also questioned
the Administrator's reasoning in failing
to evaluate the economic impact of
applying a 197 square meter per actual
cubic meter per second (1000 ft -/1000
ACFM) cold-side ESP to  achieve the
standard under adverse conditions such
as when firing low-sulfur coal. The
Administrator did not evaluate the
economic impact of applying a large,
cold-side ESP because a smaller, less
costly 128 square meter per actual cubic
u:i>U>r per second (650 tt ':/lGW ACFM)
hot-side ESP would typically be used.
The Administrator believed  that it
would have been non-productive  to
investigate the "'conomics of a cold-side
ESP when a hc-'-side ESP would achieve
the same level of emission control at a
lower cost.
  The UARG  petition aiso suggested
that hot-side ESP's are not always the
best choice for low-sulfur coal
applications. The Administrator agrees
with this position. In some case, low-
sulfur coals produce an ash wh;ch is
relatively easy to collect since flyash
resistivity is not a problem. Under such
conditions it would be less costly to
apply a cold-side ESP and therefore it
would be the  preferred nppronr h.
However, when developing cost impacts
of the standard, the Agency focused on
typical iow-sulfur coal applications
which represents worst case  conditions,
and therefore assessed only hot-side
precipitators.
  The UARG petition suggests that in
some cases the addition of chemical
additives to the flue gas  may be required
to achieve the standard with ESPs, and
the Agency should have fully assessed
the environmental impact of  using such
additives. The Administrator, after
assessing all available data,  concluded
that the use of additives to improve ESP
performance would not be necessary
{OAQPS-73-1. III-B-1, page 4-11).
Therefore, it was not incumbent upon
EPA to account for the environmental
imp.ict of the use of additives other than
to note that such additives could
increase SO3 or acid mist emissions. In
instances where a  utility elects to
employ  additives as a cost saving
measure, their potential  effect on the
environment can be assessed on a case-
by-case basis during the new source
review process.
  UARG also maintained that there are
bpeckil problems with some low-sulfur
r.oals that would preclude the use of hot-
side ESPs and attached Appendix F in
support of their position. Review of
Appendix F reveals that while the
author discussed certain problems
related to the application of hot-side
ESPs on some western low-sulfur coal,
he also set  forth effective techniques for
resolving these problems. The author
concluded,  "The evidence of more than
11 years of experience indicates that hot
precipitators are here to stay and very
likely their  use on all types of coal Will
increase."
  UARG also argued that the data base
in support of the final particulate
standard for oil-fired steam generaung
units was inadequate. The standard is
based on a  number of studies of
partiruldte  matter control for oil-fired
boilers. These studies were summarized
and referenced in the BID for the
proposed standard (OAQPS-78-1,11I-B-
1, page 4-39). These earlier studies
(Control ofPcr!;c-jia!e Matter from Oil
Burners end Boilers, April 1976, EPA-
;."0/3-76-^05; and Particulate Emission
Cc'V.'ro/ Systems for Oil-fired Boilers,
December 1974, EPA-430/3-74-063)
support the conclusion that ESP control
systems are applicable to oil-fired steam
generators and that such emission
control systems can achieve  the
standard. The achievability of the
standard ".vas also confirmed by the
Hawaiian Electric Company, a fiim that
would be significantly affected by the
strimKiid since virtually  all their new
                                                     E-20

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          Federal ! ;neir lot.a'ion. In '\\t~ir comments the
<,ompar.y ir.dicatfd, "li;iwaiian Electric
Com:) my supports the standards as
proposed in so far ui they impact upon
the ttlectr-.c: utilities In Hawaii"
(OAQPS-78-1, IV-D-159).
  UARG also argued that the
Administrator had little or no data upon
which So base n conclusion that the
particul.ite  standard is achievable For
iignite-'ired units. Ta making this
assertion, UARG failed to recognize that
the Agency had extensively analyzed
lignite-fired units in 197& and concluded
that they could employ the same types
of control systems as those used for
other noal types {EPA-450/2-76-030a.
page 11-29). Additionally, review of the
literature and other sources revealed no
new data that would  alter this finding
{Some of the data considered includes
OAQPS-73-1, H-I-59, II-I-312, and II-I-
3221 and ihs Agency continues to
believe uit 'he omission standards are
achievable  when firing all types of coal
including lignite coal. UARG has not
provided any information during the
comment period or in their petition
which would suggest any unique
problems associated with the control of
particuldte  matter from lignite-fired
units.
  The U \RC petition alleged that the
Administrator did not take into account
t'-o effect of NO, control in conjunction
with promulgation of the particulate
standard. In developing the NO,  
standard, the Administrator assessed '
the possibility that NO, controls may
increase ash combustibles and thereby
affect the mass and characteristics of
particulate  emissions. The
Administrator concluded, however, that
the NO., standard can be achieved
without iny increase in ash
combustibles or any significant change
in ash characteristics and therefore
there wc"ld be no impact on the
particulate  standard (OAQPS-78-1, III-
B-2. page 5-14).
  UARG also raised the issue of sulfate
carryover from the scrubber slurry and
its potential effuct on particulate
emissions. EPA initially addressed this
issue at proposal and concluded that
with prop-.T ri'st eliminator design and
maintenance, liquid entrainment can be
controlled to a a acceptable level (43 FR
52170, left column). Since that time, no
new information has  been presented
that would  lead the Administrator to
reconsider  that finding.
  In summary, UARG failed to present
any new information on particulate
matter control that is centrally relevant
la the outcome of the rule.
 V. i\'()jt Standards .
  Thn Utility Air Regulatory Group
(UARG) .sought reconsideration of the
NO, standards. They maintained that
the rocorr! -'id not support EPA's
findings that the final standards could
be achieved by all boiler types, on a
variety of coals, and on a continuous
basis without an unreasonable risk of
adverse side effects. In support of this
position, they argued that while EPA's
short-term emissions data provided
insight into NO, levels attainable by
utility boilers under specified conditions
during short-term periods, they did not
sufficiently .support EPA's standards
based on continuous compliance.
i'iirthar, they maintained that the
continuous monitoring data relied on by
the Agency does not support the general
conclusions that all boiler types can
mwt the standards on a  variety of coals
;..Kler all operating conditions. They
also argued that the Agency failed to
collect or adequately anah?.e. data on
the adverse side effects of low-NO,
operations. Finally, they contended (hat
vendor guarantees have  been shown not
to support the revised standards. The
cii^a'nents presented in the petition
were discussed in detail  in an
accompanying report prepared  by
L'ARG's consultant.
  In general,  the UARG petition merely
reiterated comments submitted in
January 1979. Their arguments
concerning short-term test data, the
potential adverse side effects of lovv-
NO, operation, and manufacturer's
guarantees did not reflect new
information nor were they substantially
different from those presented earlier.
For example, in their petition, UARG
asserted that new information received
at the close of comment period levealed
that certain data EPA relied upon to
conclude that low-NO, operations do
not increase the emissions of polycyclic
organic n-"tter (POM) are of
questionable validity (UARG petition,
page 56). This comment repeats the
position stated in UARG's January 15,
1979, submittal (OAQPS  73-1. IV-D-611.
attachmentKVB report, January 1979,
page 86). More importantly, UARG
failed to recognize that EPA did not rely
on the tests in question and that the
Agency noted in the BID for the
proposed standards (OAQPS-78-1. Ill- J
B-2, page 6-12) that the data were
insufficient to draw  any  conclusion on
the effects of modern, low-NO^ Babcock
and Wilcox burners on POM emissions.
Instead, EPA based  its conclusions in
regard to POM on its finding that
combustion efficiency would not
decrease during low-NOx operation and ,
therefore, there would not be an
incnvtie in POM omissions (4j FR 42171.
left column and OAQPS-70-1, IIi-B-2,
page 9-6).
  Similarly, UARG did not present any
new data in regard to boiler tube
corrosion. They merely restated the
arguments they had raised in their
January 1979 comments which
questioned EPA's reliance on corrosion
test samples (coupons). EPA-believes
that proper consideration has been
given to the corrosion issues arid
substantial data exist to support the
Administrator's finding that the final
requirements are achievable without
any significant adverse side effect (44
FR 33602, left column). In addition,
UARG also maintained that me Agency
should explain why it dismissed the 190
ng/J (0.45 Ib/million Bui) heat input NO,
emission limit, (44 FR 33602, right
column) applicable to power plants in
New Mexico. In dismissing the
recommendation that the Agency adopt
a 190 ng/j emission limit, the
Administrator noted that the only
support for such an emission limitation
was in the form of vendor guarantees.
  In relation to vendor guarantees,
UARG maintained in their January
comments and reiterate in their petition
that EPA should not rely on vendor
guarantees as support for the revised
standards. EPA cannot subscribe to
UARG's narrow position. While vendor
guarantees alone would not provide a
sufficient basis for a new source
performance standard, EPA believes
that consideration of vendor guarantees
when supported by other findings  is
appropriate. In this instance, the vendor
guarantees served to confirm.EPA
findings that the boiler manufacturers
possess the requisite technology to
achieve the final emission  limitations.
This approach was described by Foster
Wheeler in their January' 3,1970, letter
attachmentKVB report, January 1979,
page 119) that states. "When a
government regulation, which has a
major effect on steam generator design.
is changed it is unreasonable to judge
the capability of a manufacturer to meet
the new regulation by evaluating
equipment designed for the older less
stringent regulation."
  This observation is also germane to
the arguments raised by UARG with
respect to EPA data on short-term
emission tests and continuous
monitoring. In  essence. UARG
maintained that the EPA data base was
inadequate because boilers designed
and operated to meet the old 3CO ng/J
(0.7 Ib/million Btu) heat input limitation
under Subpart D have not been shown
to be in continuous compliance with the
                                                        E-21

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0230
Federal Register / Vol. 45, No. 26  /  Wednesday, February 6, 1980  /  Rules and Regulations
new standard under Subpart Da. While
this statement is true, these units, which
were designed and operated to meet the
o! J standard, incurred only five
exceedances of the new standards on a
monthly basis. Moreover, a review of
the available 34 months of  continuous
monitoring data from six utility boilers
revealed that they all operated well
below the applicable standard (OAQPS-
7S-1, V-B-1).
  In addition, UARG argued that the
available continuous monitoring data
demonstrated that the Agency should
not have relied on short-term test data.
Citing Colstrip Units 1 and  2, they noted
that less than one-third of the 30-day
average emissions fell below the units'
performance test levels of 125 ng/J (0.29
Ib/million Btu) heat  input and 165 ng/J
(0.3d !b/million Btu)  heat input,
respective'.1/ They further maintained
that ihis had not been considered by the
Agency. In fact, the Administraior
recognized at the time of promulgation
that emission values obtained on short-
term tests could not  be achieved
continuously because of potential
adverse side effects  and therefore
established emission limits well above
thrf values measured by such tests (44
PR 42171, left column). In addition, EPA
took into account the emission
variability reflected  by the available
continuous monitoring data when it
established a 30-day rolling average as
the basis of determining compliance in
the standards (44 FR 33586, left column).
  UARG also maintained in their
petition that EPA should not rely on the
Colstrip continuous  monitoring data
bt-cause it was obtained with uncertified
monitors. The Administrator recognized
that the Colstrip data should not be
relied on in absolute terms since
rionitors were probably biased high by
approximately 10 percent (OAQPS 7S-1.
IiI-B-2, page 5-7). EPA's analysis of
data revealed, however, that it would be
appropriate  to use the data to draw
conclusions  about variability in
emissions since the  shortcoming of the
Colstrip monitors did no! bias such
findings. This data together with data
obtained using certified continuous
monitors at h/e other facilities (OAQPS
78-1,  V-B-1, page 5-3) and the results
from 30-day test programs  (manual tests
performed about twice per day) at three
additional plants (OAQPS  78-1, II-B-62
and II-B-70) enabled the Administrator
to conclude  that emission variability
under low-jN*Ox  operating conditions
was small and therefore the prescribed
emission levels are achievable on a
continuous basis.
  UARG argued that since the only
continuous monitoring data available
                              was obtained from boilers manufactured
                              by Combustion Engineering and on a
                              limited number of coal tvpes, the
                              Agency did not have a sufficient basis
                              for finding that the standards can be
                              achieved by other manufacturers or
                              when other types of coals are burned.
                              The Administrator concluded after
                              reviewing all available information that
                              the other three major boiler
                              manufacturers can achieve the same .
                              level of emission reduction as
                              Combustion Engineering with a similar
                              degree of emission variability (43 FR
                              42171, left column and 44 FR 33586,
                              middle column). This finding was
                              confirmed by statements  submitted to
                              UARG and EPA by the other vendors
                              that their designs could achieve the final
                              standards, although they  expressed
                              some concern about tube wastage
                              potential (OAQPS-78-t, III-D-611.
                              attachment-KVB report, pages 116-121
                              and IV-D-30). EPA has considered tube
                              wastage (corrosion) throughout the
                              rulemaking and has determined that it
                              will not be a problem at the NO,
                              emission levels required by the
                              standards (44 FR 33602, left column).
                              With respect to different  coal types, the
                              Agency concluded from its analysis of
                              available data that NOX emissions are
                              relatively insensitive to differing coal
                              characteristics and therefore other coal
                              types will not pose a compliance
                              problem (43 FR 42171. left column and
                              OAQPS-78-1, IV-B-24). UARG did not
                              submit any data to refute this finding.
                                UARG also.argued that the continuous
                              monitoring data should have been
                              accompanied by data on  boiler
                              operating conditions. EPA noted that the
                              data were collected during extended
                              periods representative of normal
                              operations and therefore  it reflected all
                              operational transients that occurred. In
                              p.i, tJrular, at Colstrip units 1 and 2 more
                              than one full year of continuous
                              monitoring data was analyzed for each
                              unit. In view of this, EPA believes that
                              the data base accurately  reflects the
                              degree of emission variability likely to
                              be encountered under normal operating
                              conditions. UARG recognised this in
                              principle in their January 15 comments  .
                              (Part 4, page 15) when they stated that
                              "continuous monitors would measure all
                              variations in NO, emissions due to
                              operational transients, coal variability,
                              pollution control equipment degradation,
                              etc."
                                In their petition, UARG restated their
                              January 1979 comments that EPA's
                              short-term test data were not
                              representative and therefore should not
                              serve as a basis for the standard. As
                              noted earlier, EPA did not rely
                              exclusively on short-term test data in
setting the final regulations, in addition,
contrary to the UARG cljim, EPA
believes that the bo.lar test
configurations used to achieve low-NO,
operations reflect sound engineering
judgement and that the techniques
employed are applicable to modern
boilers. This is not  to say that the boiler
manufacturers may not choose other
approaches such as low-NO, burners to
achieve the standards. While
recognizing that EPA's test program was
concentrated on boilers from one
manufacturer, sufficient data was
obtained on the other major
manufacturers' boilers to confirm the
Agency's finding that they would exhibit
similar emission characterisMcs (44 FR
33300, left column). Therefore, in the
absence of new information, the
Administrator has no basu to
reconsider his finding that the
prescribed emission limitations are
achievable on modern boilers produced
by all four major manufacturers.
VI. Emission Measurement and
Compliance Determination
  The Utility Air Regulatory Group
(UARG) raised several issues pertaining
to the accuracy and reliability of
continuous monitors used to determine
compliance with the SO- and NO,
standards. UARG particularly
commented on the  data from the
Conesvilie Station. In addition, they also
maintained that the sampling method for
particulates was flawed. With respect to
compliance determinations, UARG
maintained that the method for
calculating the 30-day rolling averages
should be changed so that emissions.
before boiler outages are not included
since they might bias the results. In
addition, UARG argued that the
standards were flawed since EPA had
not included a statement as to how the
Agency would consider monitoring
accuracy in relation to compliance
determination. With the exception of the
method of calculating the 30-day rolling
average -ind thp comments on the
Conesvilie station, the petition merely
reiterated comments submitted prior to
the close of the public comment period.
  As to the reliability and durability of
continuous monitors, information in the
docket (OAQPS-70-1, II-A-88. IV-A-20,
IV-A-21, and IV-A-22) demonstrates
that on-site continuous monitoring
systems (CMS) are capable and have
operated on a long-term basis producing
data which meet or exceed the minimum
data requirements  of the standards.
  In reference to the Conesvilie project,
UARG questioned  why EPA dismissed
the continuous monitoring results since
it was the only long-term monitoring
effort by EPA to gain instrument
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                            /  Vol. 45.  No. 26  /  Wednesday. February  6, 1980 / Rules  and Regulations     8231
ope: i'\"-i experience. UARG maintained
;hcit this -.tudy showed monitor
diigrada'.io.'i over tiin i".  r-rroneous. EPA does not
consider the Conesville project adequate
for drawing conclusions about monitor
reliability because of problems which
occurred during the project.
  To bi-'gtn with, UARG is incorrect in
suggesting that the goyl of the project
was to obtain instrument operating
experience. The primary purpose of the
project was to obtain 90 days of
continuous monitoring data on FGD
system performance. Because of
intermittent operation of the steam
^en^rator and the FGD system, this
objective could not be achieved. As the
end of thd  90-day period approached, a
decision was  raade to extend the test
duration from :hree to six months. The
interrr.itient system operation continued.
As a result, .vhen the FGD outages were
deleted from the total project time of six
months, the actual test duration was
similar to those at the Louisville,
Pittsburgh, and Chicago tests and did
not. therefore, represent an extended
test prosjratn.
  EPA does not consider the Conesville
results to be representative of state-of-
the-art monitoring system performance.
necar.se of tho intermittent operation
throughout the test period (OAQPS-73-
1,1V-A-19, p'-ige 2), it became obvious
that the goals of the program could not
be met. As a result, monitoring system
maintenance Lapsed somewhat. For
exampV. .-\;i ineffective  sample
conditioning system caused differences
in  me n;>or ,;r.d reference method results
(OAQPS-78-1. IV-A-20, page 3-2). If the
t;PA contractor had performed more
rigorous quality assurance procedures,
such as a repetition of the relative
accuracy tests after monitor
maintenance more useful results of the
monitor'; performance would have been
obtained. Thus, the Conesvitle study re-
eniph.isized the need for periodic
comparisons of monitor and reference
method data and the inherent value of
sound quality assurance procedures.
  The UARG  petition suggested that the
standards  incorporate a statement as to
how EPA \-. ill consider monitoring
system accuracy during compliance
determination. More specifically, UARG
recommended that EPA define an error
band for continuous monitoring data
and explicitly state that the Agency will
take no enforcement action if the data
fy!! within the range of the error band.
The Agency believes that such a
provision is inappropriate. Throughout
this rulemaking, EPA recognized the
need tor continuous monitoring systems
to provide accurate and reproducible
data. EPA also recognized that the
fi.ur-'icy of a CMS is affected by basic
design principals of the CMS and by
operating and maintenance procedures.
For these reasons, the standards require
that the monitors meet (1) published
performance specifications (40 CFR Part
CO Appendix B) and (2) a rigorous
quality assurance program after they are
installed at a  source. The performance
specifications contain a relative
accuracy criterion which establishes an
acceptable combined limit for accuracy
and reproducibility for the monitoring
system. Following the performance test
.A the- CMS, the standards  specify
quality assurance requirements with
respett.to daily calibrations of the
instruments. As was noted in the
ralemaking (44 FR 33611, right column),
EPA has initiated laboratory and field
studies to further refine the performance
requirements  for continuous monitors  to
include periodic demonstration of
accuracy and reproducibility. In view of
the existing performance requirements
and EPA's program to further develop
quality assurance procedureSi the
Administrator believes that the issue of
continuous monitoring system accuracy
was appropriately addressed. In doing
so, he recognized that any  questions of
accuracy which may persist will have to
bo assessed on a case-by-case basis.
  The  UARG  petition  also raised as an
issue the calculation of the 30-day
rolling average emission rate. UARG
maintained that the use of emission data
collected before a boiler outage may not
be representative of the control system
performance after the  boiler regimes
operation. UARG indicated that boiler
outage could last from a few days to
several weeks and suggested that if an
outage extends for more than 15 days, a
new compliance period should be
initiated. UARG also suggested that if a
boi'-T outage  is less than "15 days
duration and  the performance of the
emission control system is significantly
improved following boiler start-up, a
new compliance period should be
initiated. UARG argued that the data
following start-up would be more
descriptive of the current system
performance and hence would provide a
better basis for enforcement.
  A basic premise of this rulemaking
was that the standard should encourage
not only installation of best control
sj'stems but also effective operating and
maintenance  procedures (44 FR 33595
center column, 33601 right column, and
33597 right  column). The 30-day rolling
average facilitates this objective. In
selecting this  approach, the Agency
 recognized that a 30-day average better
 reflects the engineering realities oi SO*
 and NO, control systems since it affords
 operators time to identify and respond
 to problems that affect control system
 efficiency. Daily enforcement [rolling
 average) was specified in order to
 encourage effective operating and
 maintenance procedures. Under this
1 approach, any improvement in emission
 control system performance following
 start-up will be reflected in the
 compliance calculation along with
 efficiency degradations occurring before
 the outage. Therefore, the 30-day rolling
 average provides an accurate picture of
 overall control system performance.
   On the other hand, the UARG
 suggestion would provide a distorted
 description of system performance since
 it would discount certain episodes of
 poor control system performance. That
 is, the system operator could allow the
 control system to degrade and then shut-
 down  the boiler before a violation of the
 standard occurred. After start-up and
 any required maintenance, a new
 compliance period would commence,
 thereby excusing any excursions prior to
 a shut-down. In addition, since a new
 averaging period  would be initiated the
 Agency would be unable to enforce the
 standard for  the first 29 boiler operating
 days after the boiler had resumed
 operation. In the face of this potential
 for circumvention of the standards, the
 Administrator rejects the UARG
 approach.
   UARG also reiterated their previous
 comments that EPA did not properly
 consider the accuracy and precision of
 Reference Method 5  for measuring
 particulate concentrations af or below
 13 ng/J (0.03 Ib/million Btu) heat input.
 EPA has recognized  throughout this
 rulemaking that obtaining accurate and
 precise measurements of very low
 cnncpntr?1tinrii nf nartiriilatp rnwttpr is
 difficult. In view of this, detailed and
 exacting procedures for the clean-up
 and analyses of the sample probe, filter
 holder, and the filter were specified in
 Method 5 to assure accuracy in
 determining the mass collected.
 Additionally, EPA has required that the
 sampling time be increased from 00
 minutes to 120 minutes. This will
 increase the total sample volume from a
 minimum of 30 dscf to 60 dscf, thus
 increasing the total mass collected to
 about  100 mg at a loading of 13 ng/J
 (0.03 Ib/million Btu)  heat input. EPA has
 concluded that measurement of mass at
 this level can be reproduced within 10
 percent.
   UARG also maintained that less than
 ideal sampling can cause particulate
 emission measurements to be inaccurate
                                                    E-23

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f:232     Federal  Register / Vol.  45,  No. 26  / Wednesday, February 6, 1980 / Rules and Regulations
;>:!s.,-a!ative locations
and the nuuioer 01 sampling points in
some detail in the reference methods
and appropriate subparts. These 
procedures were designed to assure
accurate-measurements. EPA has also
evaluated the effects of less than ideal
sampling locations and concluded that  .
g'jneraily the results would be biased .-
below actual emissions. Assessment of
the extent of possible biases in    ,   ,-j
measurement data, however, must be  .
nt.nde on a case-by-case basis.
  UARG raised again the issue of acid
mist generated by the FGD system being
collected in the Reference Method 5
sample, therefore rendering the emission
limit unachievable. EPA has recognized
this problem throughout the rulemaking.
In response to the Agency's own
findings and the public comments, the
standards permit determination of
p;i; ticulate emissions upstream of the
scrubber. In addition, EPA announced
that it is studying the effect of acid mist
or, particulate collection and is
developing procedures to correct the
collected mass for the odd mist portion.

VII. Applicability of Standards
  Sierra Pacific Power  Company and
Idaho Power Company (collectively,
"Sierra Pacific") petitioned the
Administrator to reconsider the
definition of "affected facility," asking
that Ihe applicability date of the
standards be established as the date of
promulgation rather than the date of
proposal. 40 CFR 60.40a provides:
  (a) The affected facility to which this
subpart applies is each electric utility steam
generating unit:
   * *
  (2) For which construction or modification
is commenced after September 18,1978.
  September 19,1978, is the date on
v.-hich the proposed standard was
published in the Federal Register. EPA
bri-sed this definition on sections
11 i(a)(2) and lll(b]fO) of the Act,
Section lll(a)(2) provides:
  The term "new source" moans any
sv.'ionary source, the construction or
r.odif'cation of which is commenced after the
puK'cation f.  , -"..'.aliens (or, if earlier,
proposed regulations) prescribing a standard
of performance under this section which will
be applicable to such sourre.
  Section lll(b](B) includes a similar
provision specifically drafted to govern
the applicability date of revised
standards for fossil-fuel burning sources
(of which this standard is the chief
example.) It provides:
  Any new or modified fossil fuel-fired
Stationary source which commences
construction prior to the date.of publication
of the proposed revised standards shall nut
be required to comply with such re\ised
standards.
  Sierra Pacific does not dispute that
the Agency's definition of affected
facility complies with the literal terms of
sections lll(a){2) and lll(b)(6). Sierra
Pacific maintains, however, that the
definition is unlawful, because the
standard was promulgated more than 6
months after the proposal, in violation of
sections lll(b)(l)(B) and 307(d)(10).
Section lll(b)(l)(B) provides that a
standard is to be promulgated within 90
days of its proposal. Section 307(d](10)
allows the Administrator to extend
promulgation deadlines, such as the 90-
day deadline in section lll(b)(l)(BJ, to
up to 6 months  after proposal. Sierra
Pacific argues that section lll(a)(2) does
not apply unless the deadlines in
sections lllfo)(l}(B) and 307(d)(10) are
met. In this cabe the final standard was
promulgated on June 11,1979,  somewhat
less than 9 months after proposal. (It
was announced by the Administrator at
a press conference on May 25,1979, and
signed by him on June 1,1979.)
  In the Administrator's  view, the
applicability i;ate is properly the date of
proposal. First, the plain  language of
section lll(a)(2] provides that the
applicability date is the date of
proposal. Second, the legislative history
of section 111 shows that Congress did
not intend :'iat  the applicability date
should be the date of proposal only
where a standard was promulgated
within 90 days  of proposal. Section
lll(a)(2) took its present form in the
conference committee bill that became
the 1970 Clean  Air Act Amendments,
whereas the 90-day requirement came
from the Senate bill, and there is no
Indication that  Congress intended to link
these two provisions.2
  Moreover, this  interpretation
represents longstanding Agency
practice. Even where responding to
public comments delays promulgation
more than 90 days,  or more than 6
months, after proposal, the applicability
dates of new source performance
standards are established as the date of
proposal. See 40 CFR Part 60, Subparts
D et seq.
  Sierra  Pacific argues that its position
has been adopted by EPA in
"analogous" circumstances under the
Clean Water Act. This is inaccurate.
Section 306 of the Clean Water Act
specifically provides that the date of
  *In any event, in the Administrator's view the 90-
day requirement in section lll(b)(l)(B) no lunger
governs the promulgation or revision of new source
standards. It has been replaced by procedures set
forth in section 111(f) enacted by the 1977
amendments.
proposal of a new source standard is the
applicability ddte only if the standard is
promulgated within 120 days of proposal
(section 306(a)(2). (b}(l)(B)).
  Sierra Pacific suggests that utilities
are "unfairly prejudiced" by the
applicability date, but does not submit
any information to support this claim. In
any event there does not seem to be
any substantial unfair prejudice. At the
time of proposal, the Administrator had
not decided whether a full or partial
control alternative should be adopted in
the final SO2 standard. As a result, the
Administrator proposed the full control
alternative stating (43 FR 42154, ce/iter
column):
  * *  * the Clean Air Act provides that new
source performance standards apply from the
date they are proposed and it would be easier
for power plants that start construction
during the proposal period to scale down to
partial control than to scale up to full control
should the final standard differ from the
proposal.

In fact, the final SOj standard was less
stringent than the proposed rule.
  In this case, utilities were on notice on
September 19,1978, of the proposed
form of the standard, and that the
standard would apply to facilities
constructed after that date. In March
1979, it became clear to the Agency that
it ivould not be possible to respond to
all the public comments and promulgate
the final standards by March 19, as
required by the consent decree in Sierra
Club v. Costle, a suit brought to compel
promulgation of the standard. (The
comment period had only closed on
January 15; EPA had received over 625
comment letters, totalling about 6,000
pages, and the record amounted to over
21,000 pages.) The Agency promptly
contacted the other parties to Sierra
Club v. Costle, and  all the parties jointly
filed a stipulation that the standand
should be sigusd by. Juno 1 ^.rsiJfeci Shs
Administrator should not seek "any
further extensions of time." This
stipulation was well-publicized (see, for
example,  9 Environment Reporter
Current Developments 2248, March 30,
1979). Thus utilities such as Sierra
Pacific had reasonable assurance that
the standard would be signed by June 1,
as it was.
  E\en assuming, as Sierra Pacific does,
that section 111  required the standard to
be promulgated  by March 19, utilities
had to wait only an additional period of
84 days to know the precise form of the
promulgated standard. This delay is not
substantial in light of the long lead times
required to build a utility boiler, and in
light of the fact that the pollution control
techniques required to comply with the
promulgated standard are substantially
                                                       E-24

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          fuderal Register / Vol. 45,  No. 'M  /  Wednesday, February  6. 1980 /  Rules  and  Regulation:?     8233
the ,.IRV  i, 'h'ise required by tru:
piopoaH':  '.i.iadard.
  S %:ra P scific's proposal that the'
appli'..dMk> dale be bhifted to the date
of p-om..Ration is also inconsistent with
Con^ret-s' clear desire that 'he revised
standard take effect promptly. See.
section m(b)(6).  '
  In cor.c.lu.iion. Sierra Pacific has
submitted no aexv information, has not
shown that i; has been prejudiced in any
way. and has simply presented jn
argument  that is incorrect as a matter of
law. Us objection is therefore not of
central relevance and its petition is
denied.
  Dated: j.i.uuiry 30, 1980.
Douglas M. CoMle.
Adr.-,r.::,uc>r>r.
IFR IV,. nfi-'j- :i K;li.(l 2-5-W) S.4J i,r|
BILLING CODE 65SO-OI-M
                                                  E-25

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                                    TECHNICAL REPORT DATA
                            (Please read Instructions on the reverse before completing)
  REPORT NO.
  EPA-450/3-80-009a

4,'TITLE AND SUBTITLE
                              2.
                                                             3. RECIPIENT'S ACCESSION NO.
  Proposed  Guidelines for  Determining Best Available
  Retrofit  Technology for  Coal-Fired Power Plants and
  Other Major Stationary Sources
             6. PERFORMING ORGANIZATION CODE
  AUTHOR(S)
                                                             8. PERFORMING ORGANIZATION REPORT NO.
               REPORT DATE

                 July 1980
9. PERFORMING ORGANIZATION NAME AND ADDRESS
  U.S. environmental Protection Agency
  Office  of Air Quality Planning and Standards
  Research  Triangle Park,  North Carolina  27711
                                                             10. PROGRAM ELEMENT NO.
             11. CONTRACT/GRANT NO.
12. SPONSORING AGENCY NAME AND ADDRESS
                                                             13. TYPE OF REPORT AND PERIOD COVERED
  DAA for  Air Quality Planning and Standards
  Office of Air, Noise,  and Radiation
  U.S.  Environmental Protection Agency
  Research Triangle Park,  North Carolina  27711
             14. SPONSORING AGENCY CODE
                EPA/200/04
15. SUPPLEMENTARY NOTES
16. ABSTRACT
        Guidelines for  the effectiveness  and costs of  retrofitting coal-fired power
  plants  and other major stationary sources for control  of particulates, NOX, and
  per  the provisions of  Section 169A of  the Clean Air Amendments of  1977.
17.
                                 KEY WORDS AND DOCUMENT ANALYSIS
                   DESCRIPTORS
                                                b.lDENTIFIERS/OPEN ENDED TERMS
                            c. COSATI Field/Group
   Air Pollution
   Particulate Matter
   Nitrogen Oxides
   Sulfur Dioxide
   Air Pollution Control and Costs
   Steam Generating  Units
  Air Pollution  Control
13-B
18. DISTRIBUTION STATEMENT
    Unlimited
                                                19. SECURITY CLASS (This Report)
                                                  Unclassified
                                                                            21. NO. OF PAGES
20. SECURITY CLASS (Thispage)

  Unclassified  	
                            22. PRICE
 EPA Form 2220-1 (Rev. 4-77)   PREVIOUS EDITION is OBSOLETE

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