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                          2. .INTRODUCTION





     Standards of performance are proposed following a detailed investigation



of air pollution control methods available to the affected industry and the



impact of their costs on the industry.  This document summarizes the informa-



tion obtained from such a study.  Its purpose is to explain in detail the



background and basis of the proposed standards and to facilitate analysis of



the proposed standards by interested persons, including those who may not be



familiar with the many technical aspects of the industry.  To obtain additional



copies of this document or the Federal Register notice of proposed standards,



write to EPA Library (MD-35), Research Triangle Park, North Carolina 27711.



Specify Electric Utility Steam Generating Units - Background Information for



Proposed Particulate Matter Emission Standards, report number EPA-450/2-78-006a,



when ordering.



2.1  AUTHORITY FOR THE STANDARDS



     Standards of performance for new stationary sources are established



under section 111 of the Clean Air Act (42 U.S.C. 7411), as amended, hereafter



referred to as the Act.  Section 111 directs the Administrator to establish



standards of performance for any category of new stationary source of air



pollution which "... causes or contributes significantly to air pollution



which may reasonably be anticipated to endanger public health or welfare."
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     The Act requires that standards of performance for stationary
sources reflect, ".  . . the degree of emission limitation achievable
through the application of the best technological system of continuous
emission reduction . . . the Administrator determines has been
adequately demonstrated."  In addition, for stationary sources whose
emissions result from fossil fuel combustion, the standard must also    :
include a percentage reduction in emissions.  The Act also provides
that the cost of achieving the necessary emission reduction, the
nonair quality health and environmental impacts and the energy
requirements all be taken into account in establishing standards of
performance.  The standards apply only to stationary sources, the
construction or modification of which commences after regulations are
proposed by publication in the Federal Register.
     The 1977 amendments to the Act altered or added numerous provisions
which apply to the process of establishing standards of performance.
     1.  EPA is required to list the categories of major stationary
sources which have not already been listed and regulated under
standards of performance.   Regulations must be promulgated for these
new categories on the following schedule:
     25 percent of the listed categories by August 7, 1980
     75 percent of the listed categories by August 7, 1981
     100 percent of the listed categories  by August 7, 1982
A governor of a .State may apply to the Administrator to add a category
which is not on the list or to revise a standard of performance.
     2.  EPA is required to review the standards  of performance every
four years, and if appropriate, revise them.
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      3.  EPA is  authorized  to promulgate  a design,  equipment, work



 practice,  or operational  standard when an emission  standard  is not



 feasible.




      4.  The term "standards  of performance"  is  redefined and a new



 term "technological  system  of continuous  emission reduction" is defined.



 The  new definitions  clarify that the  control  system must be  continous



 and  may include  a low-polluting or non-polluting process or  operation.



      5.  The time between the proposal and promulgation of a standard



 under section 111 of the  Act  is extended  to six  months.




      Standards of performance,  by thanselves, do not guarantee protection



 of health  or welfare because  they are not designed  to achieve any  specific



 air  quality  levels.   Rather,  they are designed to reflect the degree of



 emission limitation  achievable  through application  of the best



 adequately demonstrated technological system  of  continuous emission



 reduction, taking into consideration  the  cost of achieving such emission



 reduction, any nonair quality health  and  environmental impact and  energy



 requirements.





      Congress had several reasons for  including  these requirements.



First, standards with a degree of uniformity are needed to avoid



 situations where  some States may attract  industries by relaxing standards



 relative to  oilier  States.  Second,  stringent standards enhance the



potential  for  long term growth.  Third, stringent standards may help



achieve long-term cost savings by avoiding the need for more expensive



retrofitting when  pollution ceilings may be reduced in the future.



Fourth, certain types of standards  for coal burning sources can



adversely affect the coal market by driving up the price of low-sulfur




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 coal or effectively excluding certain coals from the reserve base
 because their untreated pollution potentials are high.  Congress does
 not intend that new source performance standards contribute to  these
 problems.   Fifth,  the standard-setting process  should create incentives
 for improved  technology.
     Promulgation  of standards of performance does not prevent  State or
 local agencies from adopting more stringent emission limitations for the
 same sources.   States are  free under  section 116 of  the Act to  establish
 even more  stringent emission limits than those established .under section
 111  or  those necessary to  attain  or maintain the national ambient air
 quality standards  (NAAQS)  under section 110.  Thus, new sources may in
 some cases be  subject to limitations morn stringent  than standards of
 performance under  section  111, and prospective owners and operators of
new  sources should be aware of this possibility  in planning for such
 facilities.
     A  similar situation may arise when a major  emitting facility is to
 be constructed in  a geographic area which falls  under the prevention of
 significant deterioration  of air  quality provisions of Part C of the
 Act.  These provisions  require, among other things,  that major emitting
 facilities to  be constructed in such areas  are to be  subject to best
 available conlrol.  technology.  The term "best available control tech-
nology" (BACT), as defined in the Act, means ".  . .an emission
 limitation based on  the maximum degree of reduction of each pollutant
 subject to regulation under this Act emitted from or which results from
any major emitting facility, which the permitting authority,  on a
case-by-case basis, taking into account energy, environmental,  and.
economic impacts and other costs,  determines is achievable for  such

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 facility through application of production processes and available
 methods, systems,  and techniques,  including fuel cleaning or treatment
 or innovative fuel combustion techniques for control of each such
 pollutant.   In no  event  shall application of 'best  available control
 technology'  result in emissions of any  pollutants which, will exceed the
 emissions allowed  by  any applicable standard established pursuant  to
 section  111  or 112 of this Act."
     Although standards  of performance  are normally  structured in  terms
 of numerical emission limits where  feasible, alternative approaches are
 sometimes necessary.   In some cases physical measurement  of emissions
 from a new source may be impractical or exorbitantly expensive.  Section
 lllCh) provides that  the Administrator may promulgate a design or
equipment standard in those cases where it is not feasible to prescribe
or enforce a standard of performance.  For example,  emissions of
 hydrocarbons from  storage vessels  for petroleum  liquids are  greatest
 during tank  filling.   The nature of the emissions, high concentrations
 for short periods  during filling, and low concentrations  for  longer
 periods .during storage,  and  the configuration of storage  tanks make
 direct emission measurement  impractical.  Therefore, a more practical
 approach to  standards of performance for  storage vessels  has been
 equipment specification.
     In  addition,  section lll(h) authorizes  the Administrator to grant
 waivers  of compliance to permit a source  to use  innovative continuous
 emission control technology.  In order  to grant  the waiver, the
Administrator must find:  (1) a substantial likelihood that the technology
will produce greater  emission reductions  than the standards require,  or
 an equivalent reduction at lower economic, energy^or environmental cost;
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 (2) the proposed system has not been adequately demonstrated; (3) the
 technology will not cause or contribute to an unreasonable risk to public
 health, welfare or safety; (4) the governor of the State where the source
 is located consents; and that, (5) the waiver will not prevent the
 attainment or maintenance of any ambient standard.  A waiver may have
 conditions attached to assure the source will not prevent attainment of
 any NAAQS.  Any such condition will have the force of a performance
 standard.   Finally,  waivers have definite end dates and may be terminated
 oarlior if the condition..; arc not met  or if the .system fails to poriomi
 as expected.   In such a case,  the source may be given up to three years
 to meet the standards,  with a mandatory progress schedule.

 2.2 SELECTION OF CATEGORIES  OF STATIONARY SOURCES
     Section  111  of  the Act directs  the Administrator to list  categories
 of stationary sources which have not been  listed before.  The
 Administrator,  ".  .  .  shall include  a  category of  sources in such list  >
 if in his  judgment it  causes,  or contributes  significantly  to, air
 pollution which may reasonably be anticipated to endanger public health
 or welfare."  Proposal  and  promulgation of standards of performance are
 to follow while adhering to the schedule referred  to earlier.
     Since passage of the Clean Air Amendments of 1970,  considerable
 attention  has been given to the development of a system for assigning
 priorities  to various  source  categories.   The approach specifies  areas
 of interest by considering  the broad strategy of the Agency for
 iitiplementing  the Clean  Air Act.  Often, these "areas"  are actually      :
 pollutants which are emitted by stationary sources.  Source categories
which emit these pollutants were then evaluated and ranked by a process
 involving such factors as (1) the level of emission control  (if any)
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 already required by StaLo regulations; (2) estimated levels of control
 that might be required from standards of performance for the source
 category; (3) projections of growth and replacement of existing
 facilities for the source category; and (4) the estimated incremental
 amount of air pollution that could be prevented, in a preselected future
 year,  by standards of performance for the source category.   Sources for
 which new source performance standards were promulgated or  are under
 development during 1977 or earlier, were  selected on these  criteria.
      The Act amendments of August,  1977,  establish specific criteria
 to be used in determining priorities for  all source categories not  yet
 listed by EPA.   These are
      1)  the quantity of air pollutant emissions which  each such
 category will emit, or will be designed to emit;
      2)  the extent to which each such pollutant may reasonably be
 anticipated  to endanger public health  or welfare;  and
     3)  the mobility and competitive  nature of  each such category  of
 sources and  the  consequent need for nationally applicable new  source
 standards  of performance.
     In some cases, it may not be feasible  to immediately develop a
 standard for a source category with a high priority.  This might happen
when a  program of research is needed to develop control techniques or
because techniques for sampling and measuring emissions may require
refinement.   In the developing of standards, differences in the time
required to complete the necessary investigation for different source
categories must also be considered.   For example, substantially more
time may be necessary if numerous pollutants must be investigated  from
a single source category.  Further,  even late in the development
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 process the schedule for completion of a standard may change.  For
 example,  inability to obtain emission data from well-controlled  sources
 in time to pursue the development process in a  systematic  fashion may    •
 force'a change  in scheduling.  Nevertheless, priority ranking is, and
 will continue to  be,  used to establish the order  in which  projects are
 initiated and resources  assigned.
     After the  source category has been chosen, determining the  types of
 facilities within the source category to which  the standard will.apply
 trust be decided.   A source category may have several  facilities  that cause
 air pollution and emissions  from some of these  facilities  to be
 insignificant or  very expensive  to control.  Economic studies of the
 source  category and of applicable  control technology  may show that air
 pollution control is  better  served by applying standards to  the more
 severe  pollution  sources.  For this reason, and because there 'is no
 adequately demonstrated  system for controlling emissions from certain
 facilities, standards often do not apply  to all facilities at a source.   ',
For the same reasons,  the standards may not apply to  all air pollutants
emitted.  Thus,  although a source  category may be selected to be covered
by a standard of performance, not  all pollutants or facilities within
that source category may be covered by the standards.                    '.

2.3  PROCEDURE FOR DEVELOPMENT OF STANDARDS OF PERFORMANCE               ;
     Standards  of performance must (1) realistically  reflect
best demonstrated control practice;  (2) adequately consider the cost,
and the nonair  quality health and  environmental impacts and energy require-
ments of  such control; (3) be applicable  to existing  sources that are    ;
modified  or reconstructed as well  as new  installations; and  (4) meet these
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 conditions  for  all variations  of  operating  conditions .being considered
 anywhere  in the country.
     The  objective of a program for development of  standards is to identify
 the  best  technological system  of  continuous emission reduction which has
 been adequately demonstrated.   The legislative history of section 111 and
 various court decisions make clear that the Administrator's judgment of
 what is adequately demonstrated is not limited to systems that are in
 actual routine  use.  The search may include a technical assessment of
 control systems  which have been adequately  demonstrated but for which
 there is  limited operational experience.  In most cases, determination of
 the  "... degree of emission,  reduction achievable  . . ." is based on
 results of tests of emissions  from well controlled existing sources.   At
 times, this has  required the investigation  and measurement of emissions
 from control systems found in other industrialized countries
 that have developed more effective systems  cf control than those
 available in the United States.
     Since the best demonstrated systems of emission reduction may not
 be in widespread use, the data base upon which standards are developed
may be somewhat limited.   Test data on existing well-controlled sources
 are obvious starting points in developing emission limits for new
 sources.  However, since the control of existing sources generally
 represents retrofit technology or was originally designed to meet an
 existing  State or local regulation, new sources may be able to meet
 more stringent emission standards.  Accordingly, other information must
 be considered before a judgment can be made as to the level at which
 the emission standard should be set.
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      A proc-csK  lor Lhc> dcvelopm,.,)!. of. a standard has evolved which Lakes
 into account the following considerations.
      1.  Emissions from existing well-controlled sources as measured.
      2.  Data on emissions from such sources are assessed with considera-
 tion of such factors as: (a) how representative the tested source is in
 regard to feedstock,  operation,/size, age, etc.; (b) age and maintenance .
 of the control equipment tested;  (c) design uncertainties of control
 equipment being considered;  and (d) the"degree of uncertainty that new
 sources will be able  to achieve similar levels of control.
      3.   Information  from pilot and prototype installations,  guarantees
 by vendors of control equipment, unconstructed but contracted projects,  ;'
 foreign technology, and published  literature are also considered during
 the  standard development process.   This  is especially important for
 sources where "emerging" technology appears to be a significant alternative.
     4.  Where possible,  standards  are developed which permit the use of
more than  one control technique or  licensed process..
     5.  Where possible,  standards  are developed to encourage or permit
the  use of process modifications or new processes as a method of control  :
rather than  "add-on"  systems of air pollution  control.
     6.  In  appropriate cases, standards are developed to permit  the use
of systems capable of controlling more than one  pollutant.  As an example,'
a scrubber can remove both gaseous and purticulate emissions, but an      :
electrostatic precipitator is specific to particulate matter.
      7.   Where appropriate,  standards for visible emissions are developed
 in conjunction with concentration/mass  emission standards.   The opacity
 standard  is established at a level  that will require proper operation and
maintenance of the  emission  control system installed to meet  the
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 concentration/mass standard on a day-to-day basis.   In some cases,.however,
 it is not possible to develop concentration/mass standards,  such as with
 fugitive  sources  of emissions.   In these  cases,  only opacity standards may
 be developed  to limit emissions.

 2.4  CONSIDERATION OF COSTS
      Section  317  of the Act requires, among other things, an economic .
 impact assessment with respect  to any standard of performance established
 under section 111 of the Act.   The assessment is required to contain an
 analysis  of:
      (1)   the costs of compliance with the regulation and standard
 including  the extent  to which the cost of compliance varies depending
on  the effective; date of the standard or regulation and the development
of  less expensive or more efficient methods of compliance;
      (2)   the potential inflationary recessionary effects of the
standard or regulation;
      (3)   Lho ei fcc.-ts on competition of the standard or regulation with
respect to small business;
      (4)  the effects of the standard or regulation on consumer cost,  and,
      (5)  the effects of the standard or regulation on energy use.
      Section  317  requires that  the  economic  impact assessment be as
 extensive  as  practible, taking  into account  the  time and resources
 available  to EPA.
      The  economic impact of a proposed  standard  upon an industry is usually
 addressed both in absolute  terms and by comparison with the control costs
 that would be incurred as n result of compliance with typical existing State
 control regulations.  An incremental approach  is taken since both new and
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   exlstlng plants ^u be requiml t
   the absence of a Federal standard of performance.  Ihis approach
   requires a detailed analysis of the  ipact uf» the industry resulting
   ft. the cost differentia!  that exists betKeen a standard of perforce
  and the typical State standard.
       The costs for contro, of air
  Tota, env,ron,,ental costs fcr «,ntrol  of wate_
  pollutants are analyzed wherever possible.
       A thorough study of «„ profitaMmy and price_setting        ^;    -
           is  essent,-a, to the ana,ysis so  that an accurate estate „    .
           adverse  ec0nomfc  i.pacts can De made.  It 1s a,so essentia,  to  ^
    e capna, ..ul^ents  placed  on p,ants ,„ the absence of Fedel-al  standards
  of perfo™ance so  that the additiona, capita, requl>ements  necessitated Dy
  these standards can be p.aced In the proper perspective.  „»,„  ,t 1s
  necessary to recognize any constraints  on capita, avai,aM1ity ,,ithin m   '
  mdustry, as  this factor also  influences the ability of new plant, to generate
 the cartel required for installation of additional  control equips
 needed to meet  the  standards of performance
 2.5  CONSIDERATION OF ENVTRONMEfflM, IMPACTS
      Section 102(2)  (C) of the Nationa! Environmental Policy Act  (NEPA) of
 1969 requires Federal agencies to prepare detailed environment^ impact
 statements on proposals for legislation and other major Federal actions
 significantly affecting the quality of the ho™ environs.  The objective
of KPA is to build  into the decision^aking process  of Federal agencies  a
careful consideration of all environs! aspects of proposed actions.
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      In a number of legal challenges to standards of performance for
 various industries,  the Federal Courts of Appeals have held that
 environmental  impact statements need not be prepared by the Agency for
 proposed actions under section 111 of the Clean Air Act.  Essentially, the
 Federal Courts of Appeals have determined that "... the best system of  '
 emission reduction, .  .  . requlre(s) the Administrator to  take into account
 counter-productive environmental  effects of a proposed standard, as well
 as  economic costs to the  industry .  .  ."  On this basis, therefore, the
 Courts  ".  . .  established a narrow exemption from NEPA for EPA determination
 under section  111."
      In addition to these judicial  determinations,  the Energy  Supply and  '
 Environmental  Coordination  Act  (ESECA)  of 1974 (PL-93-319)  specifically
 exempted proposed  actions  under the  Clean Air Act from NEPA requirements.
 According  to section 7(c)(l), "No action  taken under the Clean  Air Act
 shall be deemed  a  major Federal action  significantly affecting  the  quality
 of the  human environment within the meaning  of the  National  Environmental
 Policy Act  of  1969."
     The Agency has'concluded, however, that  the  preparation of environmental
 impact statements  could have beneficial effects on  certain  regulatory actions.
 Consequently, while  not legally required to do  so by section 102(2)(C) of
NEPA, environmental  impact statements will be prepared for various regulatory
actions, including standards of performance developed under section 111  of
 the Act.  This  voluntary preparation of environmental impact statements,
however, in no  way legally subjects the Agency to NEPA requirements.
     To  implement  this policy, a  separate  section is  included in  this
 document which is  devoted solely  to an analysis of  the potential  environmental
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 impacts associated with the proposed standards.   Both adverse and bene-
 ficial impacts in such areas as air and water pollution,  increased  solid
 waste disposal,  and increased energy consumption are identified and     ;
 discussed.

 2.6   IMPACT ON EXISTING SOURCES
      Section 111 of the Act defines a new source as  ".  .  . any stationary
 source,  the construction or modification  of which is commenced ..."
 after the proposed standards are published.   An  existing  source becomes
 a new source if  the source  is modified  or is  reconstructed.  Both
 modification and reconstruction are defined in amendments to the general ;
 provisions  of Subpart A of  40 CFR Part  60 which were promulgated in the
 Federal  Register on December 16, 1975 (40 FR  58416).  Any physical  or
 operational change to an existing facility which  results  in an increase
 in the emission  rate of any pollutant for which a standard applies  is
 considered  a modification.   Reconstruction, on the other hand, means the
 replacement of components of an existing  facility to the  extent that the
 fixed capital  cost exceeds  50 percent of  the  cost of constructing a
 comparable  entirely new source and  that it be technically and economically
 feasible to meet the applicable standards.  In such  cases, reconstruction
 is equivalent  to new construction.
     Promulgation of a  standard of performance requires States to establish
 standards of performance for existing sources  in  the  same industry under
 section  lll(d) of  the Act if  the standard for new sources limits  emissions
 of a designated pollutant (i.e. a pollutant for which air quality criteria
have not been  issued under  section 108 or which has not been listed as a
hazardous pollutant under section 112).   If a State does not act,  EPA must
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establish such standards.   General provisions outlining procedures for
control of existing sources under section lll(d) were promulgated on
November 17, 1975,  as Subpart B of 40 CFR Part 60 (40 FR 53340).
2.7  REVISION  OF STANDARDS OF PERFORMANCE
     Congress  was  aware that the.level  of  air  pollution  control  achievable
by any  industry may improve with technological  advances.  Accordingly,
section 111  of the Act provides that the Administrator ".  .  . shall, at
least every  four years, review and, if  appropriate,  revise  ..."  the
standards.   Revisions are  made to assure that  the  standards  continue to
reflect the  best systems that become available  in  the future.   Such
revisions will not be retroactive but will apply to  stationary  sources
constructed  or modified after the proposal of  the  revised'standards.
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      3.  THE FOSSIL FUEL STEAM ELECTRIC UTILITY INDUSTRY

3.1  GENERAL                                                         .
3.1.1  Description and Uses of Large Steam Generators
     A large fossil fuel-fired steam generator is a unit of more than 73
megawatts (250 X 106 BTU/Hr) heat input.  A 73 megawatt (250 X 106
BTU/Hr) steam generator produces enough steam to generate approximately 25
meqawatts of electric oower.
                            1,2
The largest fossil fuel-fired steam
generators in the United States produce enough steam to generate 1300
meqawatts.   As shown by Table 3-1, nearly all large fossil fuel-fired
steam generators are sold to the electric utility industry for generation
                  4
of electric power.   A few large steam generators are sold to produce
steam for industrial use.
3.1.2  Electric Uti1ity Industry Statistics
     At the end of 1975, the total capacity of fossil fuel-fired steam
                                          3
generator power units was 347.7 gigawatts.   Table 3-2 shows statistics on
              1 '  •     3
1975 fuel consumption.   As shown, 60 percent of the thermal energy was
supplied by coal and the remainder was about equally split between gas and
oil.
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                           TABLE 3-1
      COMPARISON OF ANNUAL SALES OF WATERTUBE GENERATORS4
                 TO UTILITIES AND TO ALL USERS
CAPACITIES >31.5 KILOGRAMS OF STEAM PER SECOND (250,000 Ib/hr)
Year
              Total Steam CapacitygSold
          Megagrams,per Second (10  Ib/hr)
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
To All Users
13.02 (103.3)
10.05 (79.8)
14.92 (118.4)
18.85 (149.6)
24.03 (190.7)
22.43 (178.0)
26.11 (207.2)
25.14 (199.5)
27.00 (214.3)
31.08 (246.7).
18.60 (147.6)
21.31 (169.1)
33.30 (264.3)
37.16 (294.9)
13.37 (106.1)
7.17 (56.9)
To Utilities
12.40 (98.4)
9,69 (76.9)
13.94 (110.6)
16.93 (134.4)
21.37 (.169.6)
20.69 (.164.2)
24.99 (198.3)
23.89 (189.6)
24.99 (198.3)
29.74 (236.0)
17.83 (.141.5)
19.35 (153.6)
30.47 (241.8)
34.41 (273.1)
11.37 (90.2)
6.27 (49.8)
TOTAL
343.54 (2726.4)
318.33 (2526.3)
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                          TABLE 3-2
     FOSSIL FUEL CONSUMPTION FOR POWER GENERATION 1975^
Fossil Fuel
Coal
Oil

Gas
        Consumption
        366.1  x lO^Kilograms
        (403.6 x 10° tons)
        72.50  x 106,-Cubic Metres
        (456.0 x 10D Bbl)
        8.38 x 101?9Cubic Metres
        (2.96  x lO1^ Ftd)
               Percent of Total  Heat Input
                         60.0

                         19.2

                         20.8
     Table 3-3 shows 1974 United States total electric utility energy
           c
generation.   Additional electrical energy is generated by industry,
remote domestic units, and by automobiles, aircraft, construction
equipment, locomotives, and vessels.  As shown in Table 3-3, about 79
percent of the 1974 electric utility energy was generated from fossil
fuels.  About 16 percent was generated by hydropower systems and about
6- percent was generated by nuclear power plants.
                           TABLE 3-3
    1974 UNITED STATES ELECTRIC UTILITY POWER GENERATION5
Type

Fuel Burning
Nuclear
Hydropower
TOTAL
(a)
Power Generation
   Exajoules
  (10s Kw Hr).
    5.23
   (1466)
     .40
   (110)
    1.05
   (291)
    6.73
   (1867)
 Percent

 78.5
  5.9
 15.6
10.0.0
(a I
     Includes oil and gas turbines
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      Table 3-4 shows  use of 1974 electric  utility generated  energy by
 consuming sector.   As  shown,  about 58  percent of the  total  electrical
 energy was used for domestic or commercial  purposes.   About  42  percent
 was  used  by the industrial  sector.   Transportation uses  very little of
 the  electrical  energy generated by  power plants  because  it is more
 practical  to  equip  mobile units with internal  generating systems.

                            TABLE 3-4
            UNITED  STATES USE  OF ELECTRICAL ENERGY5
                  BY  CONSUMING  SECTOR    1974
Sector
Household and Commercial
Industrial
Transportation^
     TOTAL
(a)
ExajouJes Used
  (IP15 Btu)
     3.89
    (3.69)
     2.81
    (2.67)
     0.02
    (.016)
     6.72
    (6.37)
     Does not include electrical  energy generated by
     transportation equipment,  such as automobile
     generators,  etc.
                                                             Percent
 57.9
 41.8
  0.3
100.0
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      Table 3-5 shows total United States energy consumption by consuming
 sector and energy source5.  As shown, United States energy is derived
 primarily from fossil fuels with small percentages derived from nuclear,
 hydropower, and geothermal energy sources.   About 46 percent is furnished
 by petroleum, 30 percent by natural  gas, and 18 percent by coal.
 About 27 percent of United States energy is used for electric power
 generation.  About the same proportion is used by the industrial  and
 transportation sectors.   Household and commercial  sectors  use about 19
 percent of the total  energy.   Most of the coal  is  used for electric
 power generation with other large use by the industrial  sector.   The
 transportation sector uses more  than  one-half of petroleum derived
 energy.   Household and commercial,  industrial,  and  electrical  generation
 sectors  use other large  quantities of petroleum derived  energy.   As
 shown by Table 3-5, about  one-half of the energy used  by industry
 other than  electrical  energy comes from  natural  gas.   Household and
 commercial  and electrical  generation  sectors  also use  large volumes  of
 natural  gas.   Little  natural gas  is used by  the  transportation sector.
 3.1.3     New  Source  Growth Projections
      For  new source growth projections, see  "Review of New Source
 Standards for  S02  Emissions From Coal-Fired Utility Boilers, Volume 1,
 Non Air-Quality  Impact Assessment," Teknekron,  Inc., Emission Standards
 and Engineering Division, Office of Air Quality Planning and Standards,
 U. S. Environmental Protection Agency, Research Triangle Park, North
Carolina, 1978.
                                    3-5

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-------
3.2  FACILITES, FUELS, AND EMISSIONS
3.2.1  Facilities and Fuels
     Large fossil fuel-fired steam generators are classified in several
different ways as follows:
     Fuel
     Firing Method
     Physical state of ash
     Fluid flow
     Draft
     Manufacture
3.2.1.1  Common Characteristics
     Figure 3-1 shows a typical large fossil fuel-fired steam generator
system.  Although there is a wide difference among pulverized coal-
fired steam generators, they have common characteristics.  A common
design objective is to produce the required quantity and quality of
steam at minimum cost.  Air preheated to as much as 315°C (600°F) by
the combustion gases is introduced into the combustion chamber with
the fuel through multiple burners strategically arranged to promote
optimum combustion conditions.  In the combustion chamber, the combustible
matter reacts with the oxygen of the air to release thermal  energy at
temperatures exceeding 1100°C (2000°F).6  The walls of the combustion
chamber are lined with water-filled tubes which absorb thermal  energy
and generate steam.  The water tubes are filled with liquid or vapor,
depending on pressure and temperature conditions.  Heat transfer in
the combustion chamber cools the combustion gases to about 1100°C
(2000°F).
                                    3-7

-------
        Figure 3-1




Typical pulverized coal fired boiler




            3-8

-------
     The  cooler  combustion  gases  flow  from  the combustion chamber to the
 superheat and  reheat  sections of  the steam  generator where further heat
 transfer  and gas  cooling occur.   Steam superheat and reheat are necessary
 for  thermodynamic efficiency and  also  to prevent steam condensation
 which would damage the  blades of  the steam  turbines which turn the
 electric  power generators.  Modern steam electric power generation
 systems use steam at  pressures ranging from 13.8 to 27.6 megapascals
 (2000-4000 PSI) at-a  minimum temperature of about 540°C (1000°F).  Steam
 turbines  are designed in stages so that steam is sent back to the steam
 generator for  reheat  between stages.   Most  modern systems are designed
 with a superheat  stage  followed by a reheat stage.  Some systems are
 designed  with  more  than one reheat stage.   The most efficient fossil
 fuel-fired-steam-electric system generates  3.6 megajoules (one kilowatt
 hour) of  electrical energy from 9.2 megajoules (8714 Btu) of gross
 thermal energy input.   Most modern systems generate 3.6 megajoules
 (one kilowatt  hour) of electrical  energy from less than 10.60 megajoules
 (10,000 Btu) heat Input.   Because of  the thermal  energy losses of the
 steam turbine  thermodynamic cycle and  the heat losses from the steam
 generator, less than  40 percent of the thermal energy of the fuel  is
converted to electrical  energy.   About 12 to 20 percent of the gross
 heat input is lost in the steam generation system and the remainder is
lost in the steam turbine system,  mostly as latent heat in the turbine
condenser.
     Combustion gases from the superheat and reheat  sections  flow  to the
economizer section where heat is  transferred to  the  steam generator
                                    3-9

-------
   feedwater.   Combustion gas  temperature out  of the  economizer  ranges  from
   315°C to  480°C  (600-900°F).   Combustion gases  from the  economizer flow
   to  the air  preheater.   When  hot-side electrostatic  precipitators are
   used  for  fly ash collection,  the dust  collection system is located       '.
   between the economizer  and air preheater.  With cold-side electrostatic
   precipitators, the dust collection system and flue gas desulfurization   ;
  system, if any,  are located after the air preheater and before the
  induced draft fan and stack.   Baghouses and  scrubbers are always installed
  after the  air preheater.  The air preheater  heats  the air flowing to the
  steam generator  combustion chamber  to as much as 315°C (600'F).   Combustion
  gas  temperature  out  of the air preheater ranges from 120°C  to  200°C
  (250-400°F).
      To minimize heat  loss, large steam generator air  preheaters  are
  designed to  reduce stack temperature to  the lowest level which does not
  cause  corrosion problems.  Corrosion will occur in and after the air
  preheater if the combustion gas temperature falls  below the dew point of
 sulfuric acid mist.   Consequently, air preheaters  are designed for
 higher outlet temperatures  when high sulfur fuels are fired than  when
 low sulfur  fuels  are  burned.   Heat losses from the  steam generation
 system  are  also minimized by  insulating  hot surfaces  and  by  minimizing    ,
 the quantity  of combustion  air.
 3.2.1.2  Fuels
      Large  fossil fuel-fired steam generators  are designed to fire
 either  coal, oil, or gas  or a combination of these fuels.  Since no new
 large oil or gas-fired steam generators are planned for the future, no
data are reported for oil or gas fuels.8'9'10-"  Table 3-6 shows  selected
                                   3-10

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                                                                               3-11    .

-------
  properties of a variety of United States coals.6  As shown, the Western
  coals usually have low sulfur content, high moisture content, and low
  heating value.   Eastern coals contain less moisture and have a higher
  heating value.   The sulfur content of Eastern coal  ranges  from less than
  1  percent to  more than 4 percent.3
  3.2.2  Emissions
  3.2.2.1   General
       Emissions  from large  fossil  fuel-fired  steam generators  include
  particulates, sulfur oxides,  oxides of nitrogen, carbon monoxide, halogens,
  trace metals and  hydrocarbons, including polycyclic organic matter.  The
  discussion of this  section is limited  to particulates, primarily particulates
  from pulverized coal-fired steam generators.                            :
 3.2.2.2  Nationwide Particulate Emissions
      Table 3-7 gives a summary of 1976 estimated particulate emissions
                  TO
 from all sources.    As shown, particulate emissions from stationary
 combustion sources were 4.6 teragrams  (5.1  X 106 tons} per  year as
 compared with  13.4 teragrams  (14.9 X 106  tons) per year from all
 sources  and were about  34 percent  of all  particulate emissions.
      Table 3-8 shows estimated 1976 particulate emissions from stationary
 combustion sources.12  As  shown, estimated  1976 particulate  emissions
 from  the large fossil fuel-fired generators  used by  the electric utility
 industry were 3.24 teragrams  (3.57  x 106  tons  per year); as compared with
 4.34  teragrams (4.78 x  106  tons) per year from  all stationary  source
 combustion or about  three-quarters  of combustion particulate emissions.
As shown,  nearly all of the particulates from electric utility sources
were emitted from coal-fired units.
                                  3-12

-------
                               TABLE 3-7    ...

           NATIONWIDE PARTICULATE EMISSION ESTIMATES  1976  12
                   Teragrams  Per Year (TO6 tons/yr)
 Source  Category
 Transportation
   Highway
   Non-Highway
  1.2  (1.3)
  0.8  (0.9)
  0.4  (0.4)
 Stationary  Fuel  Combustion
   Electric  Utilities
   Other
 4.6  (5.1)
 3.2  (3.6)
 1.4  (1.5)
 Industrial Processes
  Chemicals
  Petroleum Refining
  Metals
  Mineral Products
  Other
 6.3
 0.3
 0.1
 1.3
 3.2
    (7.0)
    (0.3)
    (0.1)
    (1.5)
    (3.5)
1.4 (1.6)
Incineration
 0.4 CO.5)
Miscellaneous
Forest Wildfires
Forest 'Managed Burning
Agricultural Burning
Coal Refuse Burning
Structural Fires
0.9 (1.0)
0.5 (0.6)
0.1 (0.1)
0.1 (0.1)
0.1 CO.!)
0.1 CO.!)
Total
13.4 (14.9)
                              3-13

-------
                            TABLE  3-8
          SUMMARY  OF  1976  NATIONWIDE PARTICIPATE  EMISSIONS12              '
             FROM STATIONARY FOSSIL  FUEL COMBUSTION SOURCES
                        Particulate  Emissions = Teragrams Per Year  (TO6 Tons/Yr)
                           Coal        Oil       Gas           Total
Electric Utilities
Industry Except Light
Industry
Residential -Commercial
and Light Industry
Total
3.2.2.3 Uncontrolled
3.10
(3.42)
0.71
(0.78)
0.15
(0.16)
3.96
(4.36)
Emissions
, 0.13
(0.14)
0.07
(0.08)
0.10
(0.11)
0.30
(0.33)
From Coal
0.01
(0.01)
0.04
(0.04)
0.04
(0.04)
0.09
(0.09)

3.24
(3.57)
0.82
(0.90)
0.28
(0.31)
4.34
(4.78)

     Although  the mass  emission  of  particulates  cannot  be  predicted
exactly, a conservative value can be estimated by assuming that about
80 percent of  the ash of coal is entrained in the combustion gases of
pulverized coal-fired steam generators13.  Consequently, high ash
coals generate more particulates than low ash coals.
     When the heating value and ash content of coal  is known,
uncontrolled particulates can be estimated in terms  of mass per unit
heat input according to the following equation:2'13
     Where:
       Em =  Emission  rate -  micrograms  per joule
                                    3-14

-------
        A = Ash content - percent
       Qm = Gross heating value - megajoules per kilogram
     or, in English units:
               E  = 8000 A
                e.  Qi
     Where:
       Ee = Emission rate - lbs/10  Btu
        A = Ash content - percent
       Qe = Gross heating value - Btu/lb

     The foregoing equations are useful for estimating control
efficiency requirements when particulate regulations are given in
terms of mass per unit heat input.
     The mass concentration of uncontrolled particulates in the
combustion gases of pulverized coal-fired steam generators can be
estimated by using the following equations:2'13"14
          CT  =  24.30A
            m    Qm
and       Cn  =  20.95A
            m    Qm
Where:
    = Particulate concentration at air preheat inlet -
      grams per dry standard cubic metre
    = Particulate concentration at air preheat outlet -
      grams per dry standard cubic metre
Qm  = Gross heating value - megajoules per kilogram
       m
       m
                                    3-15

-------
       A  = Ash content - percent
      or in English units:
      CT  = 4562A
        e   Qe
 and  Cn  = 3933A
        e   Qe
      Where:
      Cj   =  Particulate concentration at air preheat inlet -
        e
             grains per dry standard cubic foot
      CQ   =  Particulate concentration at air preheat outlet -
        e
             grains per dry standard cubic foot
      A  = Ash  content -  percent
      Qm  = Gross  heating  value  -  Btu  per pound

      These equations assume:
      1.   263.36 dry standard cubic  millimetres per joule  (9820 DSCF/
           C                               ~ *
          10  Btu)  at 0  percent  excess air.
      2.  25 percent excess air  at the air  preheat inlet, and2
      3.  45 percent excess air  at the air  preheater outlet.2
     The foregoing values are also  useful  for estimating gas flow at
the air preheater  inlet and outlet.   Actual volumes will usually be
less than the volumes calculated using these assumptions.
     When emission test results  are given in terms of mass per unit
volume, these values can be converted to units of mass per unit heat
input when the percent oxygen at the sampling location is  known.2'14
                                     3-16

-------
     Metric Units

     Nanograms per joule = 263.36 (Participate concentration  (20.9     )
                                  in grams per dry standard   (20.9-% 0?)
                                  cubic metre)

     English Units

     Pounds per million Btu = 1.4029 (Particulate concentration  (20.9	)
                                     in grains per dry           (20.9 -% 0?)
                                     standard cubic foot)

3.2.2.4  Uncontrolled Emissions From Residual Oil Combustion

     Uncontrolled particulate emissions from residual oil combustion are

estimated as follows:
     Residual  Oil Grade    Uncontrolled Particulate Emissions
           No. 6


           No. 5


           No. 4
1.25S + 0.38 kilograms per thousand litres
(IDS + 3 pounds per thousand .gallons)

1.25 kilograms per. thousand litres
(10 pounds per thousand gallons)

0.88 kilograms per thousand litres
(.7 pounds per thousand gallons)
                                     3-17

-------
                   REFERENCES  FOR CHAPTER  3

 1.  Steam Electric Plant Factors 1975, National Coal Association,
     Washington, D.C., January 1976.
 2.  Unpublished calculations or data, Emission Standards and
     Engineering Division, Office of Air Quality Planning and
     Standards, U.  S.  Environmental  Protection Agency, Research
     Triangle Park, North Carolina.
 3.  Steam Electric Plant Factors 1976,  National  Coal  Association,
     Washington,  D.C.,  1977.
 4.  Stationary Watertube Boiler  Sales  1976,  American  Boiler
     Manufacturers  Association, Arlington,  Virginia, January  1977.
 5.  United States  Energy Through The Year'2000  (Revised), U. S.
     Department of  the  Interior,  Washington,  D.C., December 1975.
 6.   Steam, Thirty-Eighth Edition, Babcock and Nil cox  Company,
     New York,  New  York,  1975.
7.  Steam Electric Plant Construction Cost and Annual Production
    Expenses 1973,  Federal Power Commission, Washington, D.C.,  1975.
8.  Memorandum, J.  Copeland to 6. B. Crane, Meeting with Riley  Stoker
    Corporation,  February 5,  1976,  Emission Standards  and Engineering
    Division, Office of Air Quality  Planning and Standards,  U.  S.
    Environmental Protection  Agency, Research Triangle Park,  North
    Carolina, March 29,  1976.
                                    3-18

-------
9.   Memorandum, J. Cope!and to G. B.  Crane, Trip Report - Meeting
     with Foster Wheeler Energy Corporation of February 6, 1976,
     Emission Standards and Engineering Division, Office of Air Quality
     Planning and Standards, U. S. Environmental  Protection Agency,
     Research Triangle Park, North Carolina, March 25, 1976.
10.  Memorandum, J. Copeland and G.  B. Crane to S. T.  Cuffe, Trip
     Report - Meeting with Combustion  Engineering, Incorporated,
     February 19, 1976, Emission Standards and Engineering Division,
     Office of Air Quality Planning  and Standards, U.  S. Environmental
     Protection Agency, Research Triangle Park, North  Carolina, April  1976.
11.  Memorandum, J. Copeland and G.  B. Crane to S. T.  Cuffe, Meeting
     with Babcock and Wilcox Company,  February 18, 1976, Emission
     Standards and Engineering Division, Office of Air Duality Planning
     and Standards, U. S. Environmental  Protection Agency, Research
     Triangle Park, North Carolina,  April 15, 1976.
12.  Unpublished data, National Air  Data Branch,  Monitoring and
     Data Analysis Division, Office  of Air Quality Planning and
     Standards, U. S. Environmental  Protection Agency, Research
     Triangle Park, North Carolina,  July 1976.
13.  Supplement No. 6 for Compilation  of Air Pollutant Emission Factors,
     Second Edition, AP-42, U. S.  Environmental Protection Agency,
     Research Triangle Park, North Carolina, April 1976.
14.  Subpart D, Part 60,  Title 40, Code of Federal Regulations.
                                     3-19

-------

-------
  4.   PARTICULATE CONTROL TECHNOLOGY FOR COAL-FIRED STEAM GENERATORS
 4.1   GENERAL
      The  device  most commonly used  for high efficiency removal  of
 participates  from the combustion  gases of coal-fired  steam generators  is
 the  electrostatic precipitator.   The use of baqhouses for high  efficiency
 particulate control  is  becoming more widespread,  especially for cases
 where  the coal ash is difficult to  collect in  an  electrostatic  ore-
 cipitator.    When flue  gas  desulfurization systems  are required,  particulate
 scrubbing is  often incorporated into the air pollution control  system.
     Mechanical  collectors  such as  cyclones and settling  chambers are
 not  efficient enough  to  reduce particulate emissions  from pulverized
 coal-fired steam  generators to the  levels  required  by current new source
 performance standards.
 4.2  ELECTROSTATIC PRECIPITATOR (ESP)  SYSTEMS
 4.2.1  Description
     Figure 4-1 shows a cutaway of a typical ESP system applied to
 pulverized coal-fired steam generators.  The ESP system serves the
 function of particle  charging, particle  collection, removal of the
material from the collection electrodes, and disposal  of the collected
ash.
                               4-1

-------
   Ml RAPPERS
. HT CABLE  FROM-
 RECTIFIER "
SHELL
                 HT SUPPOR
                 FRAME
                 CORONA
                                                            HOPPERS
                                                 WIRE-TENSIONING
                                                 WEIGHTS
                                             HOPPER  BAFFLES
   Figure  4-1.    Major  design  features of a  common  ESP.
                                        4-2

-------
     Primary electric power is usually 240 or 480 volt 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 10S000 to 40,000 volts depending upon particulate
and gas characteristics.
     Rapoing systems are designed to dislodge the collected ash by
striking the collecting surface with metal hammers.  Rapping systems are
equipped with controls which permit adjustment of the frequency and
intensity of rapping.  This controls the build up of dust on the
collection surfaces.  High efficiency ESP systems are equipped with
multiple hoppers and baffles which minimize the tendency for gases to
bypass the electrical field Csneakage).
4.2.2  Performance Factors
     ESP performance is affected by several  factors such as:
     1.   Coal ash characteristics
     2.   ESP size
     3.   Grounded collection surface spacing
     4.   Power control  design
     5.   Gas flow distribution
     6.   Rapping control  design
     7.   Fly ash handling sytem design
     8.   Thermal  expansion design
     9.   Discharge electrode failure
    10.   Maintenance practices and
    11.   Gas conditioning
                              4-3

-------
       All of these factors can be related by the following equations:1
       (1)
       Fm = 100  In  100
        m
             Wm
TOO-E
       Where F  = ESP plate area -  square metres  per actual  cubic
                  metre per second
             Wm  = Particle  drift velocity -  centimetres  per  second
             E  = Particle  collection  efficiency  -  percent
 or expressed in English Units
       (2)
      F  = 16.67  In  100
       6   ~FT^~      W-E
 where
      Fe - ESP plate area - square feet per 1000 actual cubic feet per
           minute                                                  "
      Wfi = Particle drift velocity - feet per second
      E  = Particle collection efficiency - percent
      Although the foregoing equations might make it appear that pre-
 dicting 'the  performance of an ESP system is simply a matter of sub-
 stituting numbers for  W and E and then calculating the size required
 (F),  predicting  ESP  performance  is  actually very difficult.   This  is
 because  W and E  are  a  function of numerous  factors  such as  the  eleven
 factors  previously named.   Even with  the most comprehensive  data base it
 is not possible  to exactly  quantify the effect of these factors on
 performance.  Consequently, the designer usually applies conservative
safety factors or provides  for the installation of additional collecting
surface area should the original  installation fail to perform according
to design expectations.
                              4-4

-------
     Coal ash characteristics vary.  Some coal  ash is relatively easy
to collect and other coals produce an ash which requires much larger
            2
ESP systems.   When designing new ESP systems,  the best data base for
predicting size requirements is performance data on a full scale
ESP system applied to a coal-fired steam generator firing the same
coal that will be fired in the new steam generator.  This data is
available for plants which are adding another steam generator which
will fire the same coal as that fired in existing units or for entirely
new plants which will purchase coal supplies from the same mine as
another operating plant.  When the existing data base is for the same
coal and the same efficiency as the design requirements of the new
ESP system, ESP size requirements can be predicted more accurately
than if these factors are not known.
     For situations where there is no experience with the particulate
to be handled, coal ash analyses provide valuable data for selecting
the size and types of ESP required to achieve the desired efficiency.
Ash analyses include measurement of chemical composition and resistivity
measurements.  Chemical composition of ash includes Li02, Na20, K^O,
                                                                    2
MqO, CaO, Fe203, A1203, Si02, Ti02, P205, S03, and loss on ignition.
Ash resistivity is measured at temperatures ranging from 70°C to 500°C
(150-900°F) and a resistivity versus temperature curve is plotted such
                                   2
as the one simulated in Figure 4-2.
     Ash resistivity is a major factor affecting the size of an ESP
       2
system.   Although low resistivity can make it difficult to collect
oarticulates in an electrostatic precipitator, the resistivity of
coal ash is characteristically above the range where low resistivity
                               4-5

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  problems  occur.   Consequently,  coal  ash  resistivity problems  are  largely
  limited to  coals  which  produce  a  high  resistivity  ash.
       Figure 4-2 shows a typical resistivity-temperature  curve  for a  high
  resistivity ash.  As shown, there  is a temperature  where resistivity is
  maximum.  For high resistivity  ash, collection in an electrostatic
  precipitator is the most difficult at maximum resistivity.  For high
  resistivity ash coals,  the temperature at maximum resistivity usually
  lies in the same range  as the temperature of the gas out of the steam
  generator air preheater (cold side).   The resistivity of the ash entering
 the air preheater (hot side) is much  less at temperatures ranging from
 315-480°C (600-900°F).   Consequently, high resistivity coal  ash is
 easier to  collect  on  the hot side  than  on the  cold  side.   However, this
 does not  always  mean  that a  smaller ESP can be applied on the  hot side
 than on the  cold side because  gas  volume  is greater on the  hot side.
 The designer decides  if  a hot  side or a cold side ESP is  less  costly  by
 taking into  account the  following  factors:2
      1.  The temperature-resistivity  characteristics of the  ash
      2.  Specific  collection area  requirements
      3.  Differences  in  gas volume  caused by temperature  differences
      4.  Differences  in  gas volume  caused by air leakage  into the
         air preheater and
                                          /
      5.  Differences in  construction requirements caused  by
         temperature differences.
At times even the most expert designers  differ on whether a hot side
or a cold  side ESP is  the least costly for a given application.
      Although grounded collecting  surface area spacing has  an
important  effect on the performance of an  ESP system, it is  better
                              4-6

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                               4-7

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  to rely on the judgment of the vendor rather than to set specifications.
  Most vendors  space grounded collecting surface areas 25 centimetres  (9
  in.)  apart.   All  vendors center the  discharge electrodes between  the
                      •j
  collecting surfaces.
       The  ESP  power control  system  regulates  the  power to the  discharge
  electrodes  to  provide  the  optimum.current and voltage conditions  for
  maximum collection  efficiency.   The  power controls are  usually adjusted
  by the vendor  after activation  of  the  unit.   Numerous separate power
  control systems on  a single  ESP  unit provide  a safety factor  in case of
  an electrical  failure  in one part  of the ESP  system.  Separate power
  controls also  improve  the efficiency of collection because the separate
 controls can be adjusted to compensate for different electrical input
 requirements as the gases flow from the inlet to the outlet of the
 system.  The instrumentation for modern designed ESP systems includes
 instruments which indicate: (1) primary current, (2)  secondary current,
 (3) primary voltage, (4) secondary voltage,  and (5) spark rate for each
 separate power control  system.   For large ESP systems there are several
 hundred separate indicating devices and at  times, more than 100 separate
 control  systems.2
      Poor  gas  flow distribution cap seriously impair  the performance of
 an  ESP system.   With poor distribution, the  gases flow at high velocity
 through  some parts  of the system and  at low  velocity,  through  other
 parts.   Both mathematical  analysis  and  field  performance tests  show that
 poor  gas flow  distribution  reduces  collection  efficiency.2  Gas flow
 distribution is  the  best  when small scale shop models  are studied prior
 to construction  and  when  gas  flow distribution adjustments are made
 under  cold conditions in  the  field.  Technology is not developed for
measuring gas flow distribution when the electrical system of an ESP is
energized.
                              4-8

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     When the ash is removed from the collecting surface there is
reentrainment as the material falls to the hopper below.  Reentrainment
is less when the deposits fall as a sheet to the hopper.  If the deposit
becomes too thick, this interferes with collection efficiency because of
the increased resistance of the deposit.  Control of rapping involves
rapping the collecting surfaces with sufficient intensity without
damaging the surfaces to remove the maximum proportion of deposit while
minimizing reentrainment.  These parameters are usually controlled
automatically and are adjusted in the field.  The use of separately
controlled rapping systems is beneficial because the amount and char-
acteristics of the ash deposits vary from the inlet to the outlet.
Larger amounts of ash and coarser ash are collected at the inlet.
     At times an otherwise well designed ESP system may fail to function
properly because of problems with fly ash handling.  If the ash is not
removed from the hoppers at at least the rate of accumulation, ash will
fill the hopper.  When this happens, ash will fill the space between the
collecting surfaces and will touch the discharge electrodes.  This
shorts out the affected sections, thereby destroying the effectiveness
of the ESP system.  Common causes of ash buildup are:
     1.  Sticky ash or an inadequate system for rapping the sides
         of the hopper.
     2.  Undersized outlet openings.
     3.  Undersized star feeders or other sealing devices.
     4.  Undersized ash conveying systems.
     5.  Mechanical and/or electrical failures.
                              4-9

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      Failure to provide properly for thermal expansion can also cause
 otherwise well designed ESP systems to function improperly.  Unequal
 expansion can cause buckling of collecting surfaces.  This changes the
 distance between the discharge electrodes and the collecting surfaces
 and destroys the effectiveness of the affected sections.  Unequal
 expansion can also rupture the ESP housing.  When this happens, air
 leaks into the ESP system.  This disturbs flow volumes and patterns and
 causes  ash reentrainment.   The increased gas volume caused by leakage
 also reduces the efficiency of the ESP system.2
      Discharge electrode failures  are not unusual.   Failures  of the
 insulators which minimize  current  leakage to ground are usually caused
 by dust deposits or cracks in  the  insulator.   Provision for minimizing
 these types  of problems  are incorporated  in the original  design.   If the
 discharge electrode wires  become too  thin at any point,  the wires  will
 break and will  ground out  on the collecting surfaces.   When weights  are
 used for suspension, the weights will  fall  to the hopper  below.   This
         *                          O
 can  block fly  ash  handling systems.
      Wire breakage  is controlled in a stepwise  manner.  When  breakage
 occurs,  loose ends  are trimmed off at the  earliest opportunity.  This  is
 usually  done during a short term shutdown.  Because  there are many
 discharge electrodes in each electrical section, cutting off a few wires
 has  little measurable effect on  the ESP system performance.  Eventually,
 the wires are replaced when the  unit is shut  down for long term main-
 tenance, such as where there is a week or more shutdown for maintenance
                                     f\
of the entire steam generator system.
                              4-10

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     Although gas conditioning is not developed to the state where it is
certain beneficial results will always ensue, this technique has promise
for improving, the collection characteristics when high resistivity ash
                 234
coals are fired.  ' '   If ash collection characteristics are improved
by gas conditioning, smaller ESP systems can be used to achieve the
desired emission control limits.  The most common conditioning agents
are acidic sulfur compounds such as S03 or H2$04 or compounds which
release these substances.3'4  Other compounds such as particulate
agglomerating compounds are also used.   Although these agents are added
in concentrations which do not significantly increase total S02 emissions,
it is possible that sulfate or sulfuric .acid mist emissions could be
increased.  Data on these latter potential sulfur oxide effects are not
           2                                                             ?
conclusive.   Ammonia and steam have also been used for gas conditioning.
4.3  BAGHOUSE SYSTEMS
4.3.1  Description
     In a baghouse system dust laden gas is passed through a fabric in
such a manner that dust particles .are retained on the upstream or
dirty-gas side of the fabric thereby cleaning the gas.  Figure 4-3 shows
a cutaway of one type of baghouse system.  For this type of system, the
dirty gases flow into the housing, upward through the bags, and then out
of the clean gas outlet.  The gases are moved by a fan installed at the
outlet of the baghouse.  The system shown in Figure 4-3 is designed for
inside-out filtration.   Consequently, the pressure differential inflates
the bags.  Some systems are designed for outside-in filtration.1  In
this case, it is necessary to use stiffening devices to prevent bag
collapse during filtration.
                              4-11

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CLEAN AIR
 OUTLET
DIRTY AIR
  INLET

CLEAN AIR
  SIDE
                                                            FILTER
                                                             BAGS
                                                           CELL PLATE
         V
                                Figure  4-3

   .A Simple  Two Cell Inside Out  Baghouse Equipped"for~Shake~cTeahlng

                                    4-12

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     Baghouse systems are divided into separate compartments or cells.
This allows one compartment to be cleaned while the others are in service.
At times, baghouse systems are designed so that bags can be inspected and
replaced in one compartment while the other compartments are in service.
Figure 4-4 shows a multicell baghouse with one set of bags removed for
inspection.  The entire system included within a single housing is called
a baghouse module.  Large baghouse systems can be designed as one module
or as several modules.  With several modules, one module can be taken out
of service for maintenance without affecting the operation of the other
modules.  If enough modules or isolated compartments are provided, even
the largest pulverized coal-fired steam generators can be kept on line at
full load while necessary maintenance is performed.
     Common methods employed for cleaning the ash from the bags of fabric
filter systems of coal-fired steam generators are reverse air and pulse
jet cleaning.  These techniques may be employed with or without shake
assist.  Figure 4-5 shows one type of reverse air cleaning cycle.  With
reverse air cleaning the clean gas outlet of an individual compartment is
shut off from the main gas stream.  During this period the other compartments
handle the dirty gas load.  After the outlet is closed, a reverse air fan
is used to reverse the flow through the.bags.  Usually the reverse air
fan circulates cleaned combustion gas.  When the baghouse is designed for
inside-out filtration, the reverse flow will collapse the bag unless
stiffening devices are employed.  The reverse flow dislodges the ash
collected on the bags and causes the ash to fall to the hopper below.
The dirty reverse air gas flows into the dirty gas stream and is cleaned
by the bags in other compartments of the baghouse.  With jet pulse cleaning,
                               4-13

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4-14

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                        b
            EXHAUST
   REPRESSURING
      VALVE
                        7t
      SIDE VIEW

FILTERING
         SIDE VIEW

COLLAPSING
                Operating Cycle for Reverse Air Cleaning

                          Inside-Out Filtration

                               Figure 4-5
                                                                        INLET
                                                                        VALVE
                                                                 SIDE VIEW

                                                           CLEANING
                   JET
  UNI-BAG
INSIDE OUT.
FILTERING^
                         SIDE VIEW
                                                             COMPRESSED AIR
#

* \



i *
,\
\
*\
\
\
i

                                           \
                                                       i|U__jJ
                                   ^^^.
                                                            OUTSIDE IN
                                                            FILTERING
                                                          SIDE VIEW
                 Operating Cycle for Pulse Jet Cleaning
                  Inside gut and Outside In Filtration

                               Figure 4-6
                                  4-15

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  as shown in Figure 4-6, individual  bags are exposed to short blasts of
  clean air.   The duration of the blasts is usually less than one second.
  The blasts  cause ripples in the bag fabric which dislodge the ash.
  Either reverse  air or pulse jet cleaning techniques can be combined
  with  mechanical  shaking techniques.   Mechanical  shaking causes  ripples
  in  the fabric which  dislodge the  ash.   Some baghouses  are designed  for
  either or both  reverse  air  and  pulse  jet cleaning.
  4.3.2   Performance Factors
      Baghouse performance is affected  by  several factors,  such as
      1.  Bag material
      2.  Bag construction
      3.  Bag treatment
      4.  Baghouse size.
      5.  Baghouse configuration and  control
      6.  Cleaning techniques
      7.  Tube sheet construction
      8.  Process characteristics
      9.   Maintenance  practices
      Bag material,  construction, and treatment are  very important
factors  which affect  baghouse performance.   The permeability of the
fabric must be high enough to minimize  pressure drop while  at  the
•same time effectively filtering out the fly  ash from the gas stream.
Frazier  permeability is expressed in English units of actual cubic
foot of  air passing through a square foot of cloth at 0.5 inches of
 water pressure drop.5  Frazier permeability can be converted from
English units to metric units of cubic metres per minute per square

                              4-16

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metre  by multiplying  the  English  Frazier units  by a  factor of 0.305.
Table  4-1  shows  the differences in  air permeability  for  new,  used,  and
used-vacuum  cleaned bags.   As shown,  the air permeability for used
bags was much  lower than  the  air  permeability of new or  used- vacuum
cleaned bags.
     The bag fabric must  be resistant  to the  effects of  chemical  attack,
abrasion,  and  temperature.  Glass fabrics are used for most modern
baghouses  installed on  coal-fired steam generators.   Glass  bag finishes
such as silicones, resins, graphite, and Teflon''*' are used for improve-
ment of abrasion resistance.  Other types of  synthetic fabrics are  also
employed and are specified by fabric filter system vendors.
     Unlike  electrostatic precipitator  systems,  where undersizing does
not affect the capacity of the steam generator,  but  does affect the
effectiveness of the emission control system, the  penalty  for un'der-
sizing a baghouse is loss of boiler capacity.   Full  load pressure drops
range from 0.75 to 2.5 kilopascals ('3-10  in.  H20),   Section 4.5
discusses air to cloth ratios, effectiveness, and  pressure  drops for
operating baghouses.
     Baghouse configuration and control  have  a significant  effect on
baghouse performance in the field.  For  baghouses designed  for  cleaning
the bags off line, multi-cell  construction is a necessity.''  Multi-cell
construction also has  several  other advantages.   Athough there  is no
specific criteria for  the number of bags per cell, the number of bags is
usually small enough  to facilitate rapid location of worn or leaky bags
or other leakage once  a faulty cell  is  identified.^  In cases  where bags
                              4-17

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                               Table 4-1

      AIR PERMEABILITY OF NEW,  USED, AND USED-VACUUM CLEANED BAGS5
 Condition
 New Bag
Used Bag 1
Used Bag 2
Used-Vacuum Cleaned Bag 1


Used-Vacuum Cleaned Bag 2
       Frazier Permeability
Metres per Minute @er Square Metre
	(CFM/FtZ)
      16.6    (54.3)


       0.335  (1.1)


       0.488  (1.6)


       9.30    (30.5)


      12.2     (40.0)
                             4-18

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are cleaned off line, the number of cells per baghouse are designed to
minimize the increase in pressure drop when one cell is off line for
cleaning.
     Controls often include provision for remote control of the inlet
and outlet valves for each cell.  With this type of control, faulty
cells can be located by shutting off various sections of the baghouse
while observing the opacity of the plume.  Some baghouses are designed
for isolation of faulty cells to permit repairs within a cell while the
rest of the baghouse is in service.  If there are numerous cells and
the baghouse is properly sized, baghouses can be serviced without loss
of power generating capacity.
     The fabric filter system controls usually provide for automatic
cleaning with provisions for adjusting the frequency and duration of
cleaning.  The baghouse can be equipped so that cleaning can be imple-
mented either by a time cycle or by pressure drop.  With timing control,
the cells of a baghouse are cleaned at predetermined intervals which
keep the pressure drop below 1.25 kilopascals (5 in. of fLO).  With
pressure control, a predetermined cleaning cycle is initiated each time
the pressure drop across the baghouse exceeds 1.25 kilopascals (5 in.
of H20).   With the foregoing types of controls and multi-cell design,
even the largest steam generator can be operated without downtime for
repairs or maintenance of the particulate control  system.1   When the
boiler is operated at low loads, it is  often necessary to shut off part
of the baghouse to keep gas temperature high enough to prevent acid
attack.
                              4-19

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      A  variety  of techniques  are  used  for  cleaning  filtered particulates
  from the  bags.  The  prime methods used are:   (1) shake,  (2) pulse jet,
  and (3) reverse air  cleaning.  Sometimes more than  one of the foregoing
  cleaning  techniques  are used  in combination or the  baghouse is designed
  so that the operator can select operation  in either a single cleaning
 mode or in a combination cleaning mode.  One baghouse described in
 Section 4.5 is  designed so that the operator can operate the baghouse
 with (1) pulse jet cleaning,  (2} reverse air cleaning, or (3)  both pulse
 jet and reverse air cleaning.   Providing for multiple cleaning capa-
 bilities provides  a safety factor in case particulate characteristics
 differ from design expectation.
     With  shake cleaning,the bags  are cleaned in  a  manner similar to
 shaking  a  rug.   Too violent  shaking  damages the  bags.   Too  gentle shaking
 can fail to remove enough  particulate causing pressure drop  to exceed
 design specifications.   Consequently,  controls are  needed to permit
 adjustment of the  intensity, frequency, and duration of shaking.
     With  pulse  jet cleaning,  each individual  bag is subjected to a  high
 intensity  blast  of air.  Pulse jet cleaning air is supplied at about  690
 kilopascals  (100 psi) and pulse time  is about 0.1 second.1 Pulse jet  units
 are usually designed  so that pulse time, the interval  between pulses, the
 number of  pulses,  and the frequency of cleaning can  be adjusted.   Pulse
 jet cleaning causes ripples in the bags which dislodge the filtered
 particulate.  Pulse jet cleaning can be accomplished either while the bag
 is filtering combustion gases or with the cell off line.
     For combustion sources,  most reverse air cleaning systems  actually
operate with cleaned combustion gas instead of air.   Multi-cell  baghouse
                              4-20

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design is a necessity when reverse air cleaning is employed. With reverse
air cleaning, the clean gas outlet of a cell or a bank of cells is shut
off.  Then cleaned combustion gas from a separate reverse air fan is
forced from the clean side to the dirty side of the bag in a reverse
direction.  This dislodges collected particulates. The dirty gas from the
cleaning operation flows in a reverse direction through the open dirty
side inlet of the cell being cleaned to the dirty side inlets of other
cells within the baghouse which are operating in the normal filtration
mode.  Thus, any particulates entrained by reverse air cleaning are
filtered from the gas before the gases flow to the stack.
     For a small reverse air type baghouse, normal cleaning involves
cleaning one cell at a time.  For baghouses with the large numbers of
cells, banks of cells are cleaned in common.  This leaves the other
compartments in the normal filtration mode while the one or one bank of
cells being cleaned are off line.  For a ten cell system, the available
cloth area is reduced by ten percent during cleaning.  The cleaning
controls are sometimes set so that compartments are continuously cleaned
on  a cyclic basis, one at a time.  Another cleaning option when particulate
loadings are low is to initiate a cleaning cycle on a time basis. For
example, a baghouse might be operated forty minutes without cleaning at
which time a cleaning cycle would be initiated.  During cleaning each
cell is cleaned separately during a total time period of, perhaps, five
minutes.  Then forty more minutes of filtration elapses without cleaning.
With the latter type of reverse air cleaning, it is possible to shut down
the reverse air fan during the forty minute periods between cleaning.
Well designed reverse air type baghouses are equipped for adjusting
reverse air flow, the frequency of cleaning, and duration of cleaning.
                               4-21

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 Too much  reverse  air  can  impair  the efficiency of  filtration.  Too
 little reverse air or  infrequent cleaning can cause operating pressures
 to exceed 1.25 kilopascals  (5 in. H20).6
      When outside in filtration  is employed, each  bag must be fitted
 with a anti-deflation  device.  Some manufacturers  sew metal rings into
 the bags to prevent collapse during outside in gas flow.6  Other manu-
 facturers fit the bags over wire cages to prevent  collapse.1  With
 inside out filtration, no anti-deflation device is needed during filtration
 since gas pressure inflates the bag.   However, manufacturers usually
 equip inside out bags with anti-deflation devices to prevent collapse
 if reverse air cleaning is employed.
      Baghouses have  tube sheets  which  prevent the leakage of dirty gas
 to the clean gas  side of the bags.   The bags are  secured to fittings on
 the tube  sheet as  shown in Figure 4-7.1  Because  of the  change  in
 velocity  and direction of gas  flow when gases  enter the  bag in  inside
 out filtration, turbulence is  great at the inlet.   This  turbulence can
 cause  excessive bag wear at  the  inlet.1   Consequently, several manu-
 facturers  use  metal tubular  extensions  at the point where  the gases
 enter  the  bag.   Other  manufacturers design  for outside  in  filtration
 to minimize wear caused by turbulence.1
     Maintenance is a key element affecting  the performance of baghouses.
 Since there are usually no visible emissions from baghouses installed  on
 coal-fired steam generators, the opacity of  the plume is a good indicator
of the need for maintenance.  Any visible emissions exceeding five percent
opacity are an indicator that maintenance is  required.   For well  designed
baghouses equipped for  isolation of individual cells, trouble spots can
                              4-22

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        Clean gas
 Region of turbulent
 How patterns ol dirty
 gjs nexl (o bag
          Bag —f
                       Dirty gas
Figure  4-7.  Typical  Flow  at Tube Sheet -  Inside Out  Filtrati
on
                          4-23

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  be located by shutting off various sections and observing the stack.
  Once a faulty cell  is identified,  visual  or fluorescent tracer techniques
  are used to locate  faulty bags  or  tube sheet leaks.1   Detailed records
  of bag replacements  and periodic checks on  used bag fabric  characteristics
  are helpful  for  determining  the optimum time for replacing  an entire
  set of bags.   By staggering  replacement schedules  on  a  cell by cell
  basis,  all  of  the bags  can be replaced without  shutting down  a steam
  generator.
  4.4  SCRUBBERS
      Scrubbers are not commonly used for control of particulates from
  coal-fired steam generators unless the source is equipped for  flue gas
 desulfurization  (F6D).  The venturi scrubber is the most common type of
 scrubber applied for scrubbing particulates from coal-fired steam
 generators.  Figure  4-8 shows a  venturi scrubber located ahead of a FGD
 spray tower.  As  shown,  liquor from the hold tank is  circulated to both
 the spray tower and  the  venturi. Sometimes  FGD scrubber systems are
 designed with separate particulate  and  sulfur dioxide  (S02)  liquor
 systems.   Figure  4-9  shows a  FGD system designed for both  S02  and
 particulate removal using a single  venturi scrubber system.  Figure 4-
 10  shows  a  FGD  system designed for  simultaneous  particulate  and S02
 removal  in  a  moving bed  absorber.   Pressure  drops across the foregoing
 systems  range from 2.5 to  5 kilopascals (10-20 in.  H20).7  Some FGD
 systems are equipped with  ESP systems ahead  of the  scrubber systems.
The ESP can be  designed to achieve full particulate removal or  in
other cases, partial  particulate removal with the remainder being
removed in the S02 scrubber system.
                              4-24