EPA-R2-73-084a
(API Publication 4180}
June 1973
Environmental Protection Technology Series
 Field Investigation  of Emissions
 from  Combustion  Equipment
 for Space Heating
                            I
                            55
       \
        01
        CD
 American Petroleum Institute
 1801 K Street,  NW
 Washington, D.C.  20006
          Office of Research and Monitoring
          U.S. Environmental Protection Agency
          Washington, D.C.  20460

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                                              EPA-R2-73-084a
                                        (API Publication 4180)
Field  Investigation  of  Emissions
   from  Combustion  Equipment
           for  Space Heating
                      by

             R.E. Barrett, S.E. Miller,
                 and D.W. Locklin

           Battelle - Columbus Laboratories
                 505 King Avenue
               Columbus, Ohio  43201
              Contract No. 68-02-0251
             Program Element No. 1A2015

          EPA Project Officer:  Robert E. Hall

             Control Systems Laboratory
        .National Environmental Research Center
      Research Triangle Park, North Carolina 27711
                   Prepared for

          AMERICAN PETROLEUM INSTITUTE
                 1801 K STREET, NW
             WASHINGTON, D.C. 20006

                      and

        OFFICE OF RESEARCH AND MONITORING
      U.S. ENVIRONMENTAL PROTECTION AGENCY
             WASHINGTON, D.C. 20460

                   June 1973

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This report has been  reviewed  by  the Environmental Protection Agency  arid

approved for  publication,   Approval  does  not  signify that  the contents

necessarily reflect the views and policies  of the  Agency,  nor does

mention  of  trade  names  or  commercial  products constitute endorsement

or  recommendation for use.
                                AUTHORS' COMMENTS
           It has been brought  to the authors' attention  that some confusion  exists between the
       terms "emission factors"  and "emission standards". The values reported and suggested in this
       report are emission factors. Emission factors,  as developed in this study, are suitable for use in
       estimating mean emissions from a class of fuel burning equipment and jre useful in compiling
       areawide  emission inventories; they are not suitable for predicting emissions from any one unit
       or  as regulatory limits or emission standards. Use of emission factors .as omission standards
       would tend to place about 50 percent of the units in noncqmpliance.
                                            11

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                             TABLE OF CONTENTS

Chapter
   I.       SUMMARY	    1-1
                Objectives and Scope of Phase II	
                     Objectives	
                     Scope   	
                Residential Units	
                     Mix of Units	
                     Conditions Investigated	
                     Varied-Air Runs	
                     Cyclic Runs	
                     Summary of Residential Emissions and Comparison With
                       EPA Emission Factors	
                     Suggested  Emission Factors for Residential Units
                Conclusions for  Residential Investigation   ....
                Commercial Boilers	
                     Mix of Boilers	
                     Conditions and Fuels Investigated  .  . ,	
                     Base-line Condition	
                     Fuels	
                     Typical  Emission Trends	
                     Effects of Fuel	
                     Effect of Fuel Nitrogen on NOX	
                     Summary of Oil-Fired Commercial Boiler Emissions ....
                     Suggested  Emission Factors for Oil-Fired Commercial Boilers .
                                                                                  - 2
                                                                                  - 2
                                                                                  - 2
                                                                                  - 4
                                                                                  - 4
                                                                                  - 5
                                                                                  - 5
                                                                                  - 7

                                                                                  -10
                                                                                  -11
                                                                                  -11
                                                                                  -14
                                                                                  -14
                                                                                  -15
                                                                                  -15
                                                                                  -15
                                                                                  -15
                                                                                  -16
                                                                                  -19
                                                                                  -19
                                                                                  -19
                   Summary of Gas-Fired Boiler Emissions and Suggested
                    Emission Factors	    I -22
              Conclusions for Commercial Boiler Investigation	    I -23

II.      EMISSIONS FROM RESIDENTIAL UNITS	II -  1
              Units Included in the Phase II Investigation	11-1
                   Basis for Selection of Equipment	11-1
                   Selection of Equipment Mix and Individual Units	11-2
                   Description of Residential Units	11-2
              Procedures Used  in the Residential Field Investigation	11-4
                   Burner Conditions Investigated	11-4
                   Operating Conditions  Investigated	11-6
                   Emission Measurements - Instruments and  Techniques ....   11-9
              Emission Results for Cyclic Runs	II -13
                   Summary of Emission Data and Emission Factors	II -13
                   Effect of Tuning  and  Fuel	11-13
                   Comparison of Emissions for Different Equipment Features  .   .   II -18
                   Statistical Ranking of Equipment and Fuel  Variables  ....   II -23
                   Conclusions Related to Equipment Features and Fuel  ....   II -36
                   Measurements on Follow-Up Units	   II -36
                   Experiments on the Effect of Cycle	II -40
              Emission Results for Varied-Air Runs	   II -44
                   Emission Characteristics Related to Excess Air	II -44
                   Limits of Acceptable Adjustment	II -59
             Trial Correlations of Smoke Versus Particulate   .	11-59


                                   iii

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                           TABLE OF CONTENTS
                                (Continued)

Chapter

  III.      EMISSIONS FROM COMMERCIAL  BOILERS	Ill- 1
              Boilers Included in the Phase if Investigation	Ill- 1
                   Basis for Selection of Equipment    .        	Ill - 1
                   Selection of Equipment Mix and Individual Boiler	Ill - 1
                   Description of Commercial Boilers	Ill - 4
              Procedures Used in the Field Investigation      	Ill- 4
                   Conditions  Investigated	     	Ill- 4
                   Emission Measurements — Instruments and Techniques   ,   .  .   Ml - 7
              Emission Results  for Commercial Boilers	  .   Ill   8
                   Summary of Emission Data and Emission Factors	Ill - 8
                   Influence of Various Parameters on NOX Emissions    .  .   .     111-11
                   Influence of Operating Condition on Smoke. CO, and
                    HC Emissions   .       	Ill -27
                   Influence of Fual on Smoke Emissions     ...     ...     Ill -27
                   Factors Influencing Participate Emission	Ill -36
                   Trial Correlation of Smoke Versus Particuiate Emissions  .   .  .   Ill -39
                   Particle Si?e Measurements     	III-39
              Emission Factors	Ill -42
                   Emission Factors Related to API Gravity   ....    ...   Ill-42
                   Suggested Emission Factors for Commercial Boilers  ....     Ill -48


                               APPENDICES
   A.      BACKGROUND DATA  ON  RESIDENTIAL OIL-FIRED EQUIPMENT
           POPULATION	A - 1
   B.      BACKGROUND DATA  ON  COMMERCIAL-INDUSTRIAL BOILER
           POPULATION	B - 1
   C.      FUEL ANALYSES	C- 1
   D.      DETAILS OF FIELD PROCEDURES-	D- 1
   E.      SAMPLING AND ANALYTICAL PROCEDURES FOR GASEOUS
           EMISSIONS	E- 1
   F.      SAIWLING AND ANALYTICAL PROCEDURES FOR PARTICULATE
           AND SMOKE AND DETAILED PARTICULATE DATA	F - 1
   G.*     DATA  FOR RESIDENTIAL UNITS	G   1
   H.*     DATA  FOR COMMERCIAL BOILERS	H- 1
   I.*     CALCULATED EMISSION FACTORS FOR RESIDENTIAL UNITS           11
   J.*     CALCULATED EMISSION FACTORS FOR COMMERCIAL BOILERS        J-1
   K.      DETAILS OF EMISSION-FACTOR CALCULATIONS AND
           CONVERSION FACTORS	K _ 1
   L.      ERKATA TO PHASE I  REPORT     	L _ -,
  M.      REFERENCES	M _ .,
  "These appendices appear m tfip Data Supplement Volumb which is available as a separate report

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                                               ABSTRACT
       Information on  air-pollutant emissions from residential and commercial  heating equipment was developed
in  a 2-year field investigation conducted by the Battelle Columbus Laboratories. Emissions measured were CO,
HC, NOX,  SO2, particulate, and smoke. The program, jointly sponsored by the American Petroleum Institute and
the U.S. Environmental Protection Ayericy, covered emissions from 33  residential heating units and 13 commer-
cial boilers — including  effects of various combustion parameters and fuel-oil  compositions.
Residential Units

       Although performance similarities among units were noted during runs with  varied air adjustments, each
unit had unique emission characteristics.  For the representative cross section  of residential  units investigated,  it
was  found that the largest reduction in emissions could be  achieved by  replacing  pooriy performing unus, as
identified from  smoke  measurements made during service inspections. Tuning of the units  that were generally
performing well reduced  smoke  levels but produced  only slight  reductions in emissions  on a gravimetric basis,
Tuning  to  lower smoke by  increasing the air adjustment alone couid result in  sharply rising emissions of CO and
HC for  some units, unless established tuning practice is followed using field-type instruments  for smoke and CO*,
measurements.

       Burners equipped  with  flame-retention-type combustion heads produced lower emissions than those with
conventional heads, and newer  burners performed with lower emissions than did older burners.
Commercial Boilers

       For  the sample  of typical  commercial  boilers,  which ranged  from  40 to  600  boiler horsepower in
capacity, emissions were measured for 33 different combinations of boilers and fuels at various loads and excess
air  settings. Although some performance differences were noted, operating parameters within the normal range of
adjustment had minor effect on gaseous emissions.

       Fuels included in the investigation were natural gas and five grades of fuel oil, including a 1-percent-sulfur
residual  oil that was transported to each  boiler  site  for  use as a reference fuel. Fuel characteristics had  a
significant  effect on emissions, especially particulate and NOX. Particulate emissions with  the  1-percent-sulfur oil
averaged about 30  percent  of those for  conventional No. 6  oil; particulate emissions for No. 2 oil averaged  only
about 3  percent of that for No. 6 oil. NOX emissions were  lowest with gas  and the lighter grades of fuel oil and
increased with increasing fuel nitrogen content.
Emission  Factors

       On  the basis of this investigation, new emission factors are suggested for use in emission inventories and
in evaluating  control  strategies. Separate  emission  factors are suggested for residential  oil fired units  u,id frr
gas-fired and oil-fired commercial boilers, with a distinction between fuel-oil grades or types.

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                                    ACKNOWLEDGMENT
       The  authors  wish  to acknowledge  the assistance and  helpful comments  of the EPA
Project Officer, Robert E. Hall, and the API SS-5 Task Force during the course of this program.
Membership on the SS-5 Task Force was as follows:

         E. Landau (Chairman)	Asiatic Petroleum Corporation
         R. C. Amero	Gulf Research & Development Company
         S. P. Cauley	Mobil Oil Corporation
         H. E. Leikkanen	Texaco Inc.
         B. L. Mickel	American Oil Company
         R. E. Paterson	Chevron  Research Company
         C. W. Siegmund	Esso Research & Engineering Company
         R. A. Beals	National Oil Fuel Institute, Inc.
         J. R. Gould	American Petroleum Institute.

       The  assistance of the Commercial-Industrial Air Pollution Committee  of the American
Boiler  Manufacturers Association  is acknowledged for their  cooperation  in  the  selection of
commercial  units and assistance in defining appropriate test conditions. The authors also wish to
acknowledge the enthusiastic cooperation  of those manufacturers who  made  available their
commercial  boilers and plant facilities and who donated the services of skilled service technicians
to assist in the burner adjustments heeded to achieve the desired matrix of test conditions.

       Acknowledgment is made for the cooperation of the homeowners who granted permission
for the  field  team  to set  up  its battery  of instruments  and  for their patience  under the
inconvenience of having normal comfort control of their heating  system interrupted  during the
two or three days of measurements.

       Special  acknowledgment is  due W. H. Axtman, Assistant Manager of the American Boiler
Manufacturers Association,  and Margaret Mantho, Statistical Editor of Fueloil & Oil Heat, for
their assistance  in preparing the  equipment population questionnaires,  soliciting  replies, and
consolidating the statistical data.

       The  authors are also  indebted to numerous Battelle-Columbus staff members who partici-
pated in various aspects  of  the  program. Special adknowledgment is  made  to Technician J.  J.
Fancelli  and J. H.  Faught, who served on the field  team  making the measurements, and to
various  supporting staff;  to  R. D. Fischer, D.  R. Hopper, and R. E. Thomas, who advised or
assisted in  the computer and  statistical interpretations of data; to P.  R. Webb for particle-size
measurements;  to the secretaries who  assisted in the preparation  of  this report; and to R. B
Engdahl, L. J. Hillenbrand,  J. A.  Gieseke, and A. Levy, who advised on various sampling and
analytical aspects of the program.
                                       VI

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                      FIELD INVESTIGATION OF EMISSIONS FROM
                    COMBUSTION EQUIPMENT FOR SPACE HEATING

                                            to

                          AMERICAN PETROLEUM INSTITUTE
                                 Project SS-5  Task  Force „

                                           and

                        ENVIRONMENTAL PROTECTION AGENCY
                                Control Systems Laboratory

                                            by

                        R. E, Barrett, S.  E. Miller, and D. W.  locklin
                                       SUMMARY
       Information  on  air-pollutant emissions from  combustion equipment is essential  to
environmental quality  considerations - including development of emissions inventories,  control
strategies, and equipment design criteria. Under sponsorship of the American Petroleum Institute
and  the U.S. Environmental Protection Agency, the Battelle Columbus Laboratories has con-
ducted  a 2-year  investigation to develop more comprehensive and up-to-date information  on
emissions from  representative  residential and  commercial  fuel-burning equipment  for space
heating.

       The  American  Petroleum Institute  sponsored Phase  I of  the  investigation during the
1970-71  heating season, in which field measurements of gaseous and particulate emissions were
made on 20  oil-fired and 2 gas-fired residential units, plus 7  commercial boilers. Those findings
were reported in API Publication 40991.

       The Phase II investigation was conducted during the 1971-72 heating  season under the
joint sponsorship  of the American Petroleum Institute and the Environmental Protection Agency.
In the Phase II investigation, more  detailed  emissions measurements  were made  over a wider
range of conditions on  13  residential  units and  6 commercial  boilers. This report describes
procedures and .results  for  the Phase II  investigation  and  conclusions based on both the Phase I
and Phase II studies.

       This  Executive  Summary provides an overview of the finding;, and conclusions from both
Phases I and II.
1"A Field Investigation of Emissions from Fuel Oil Combustion for Space Heating", by A. Levy, S. E. Miller,
 k. b. Barrett, E. J. Schulz, R. H. Melvin, W. H. Axtmarj, and D. W. Locklin. API Publication 4099 (November 1,
 J971), available from  the API Publications Section, 1801 K Street, N.W., Washington, D. C. 20006.

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                                           1-2

OBJECTIVES AND SCOPE OF PHASE II


Objectives

       The  objectives of  the  Phase  II investigation were to develop additional information on
aii-pollutant emissions from combustion equipment used for residential and commercial heating,
including the effects of combustion parameters and fuel composition on emission levels.
Scope

       Measurements made on  the  13  residential units covered a range of excess-air adjustments
for both as-found and  tuned operating conditions. For the six  commercial boilers, combustion
parameters included  a range of loads and excess air levels; natural gas and three different grades
of fuel oil were fired in five of the commercial boilers to determine effects of fuel characteristics
on emissions,
       Emission Measurements.  The following gaseous pollutants were measured by continuous
 monitoring equipment sampling from the stack:

            • Carbon monoxide, CO

            • Total hydrocarbons, HC

            • Sulfur dioxide, SO2 (only for commercial boilers)

            • Nitrogen oxides, NOX  (NO + NO2)

 In  addition,  oxygen  and  carbon dioxide concentrations  were measured to define the  operating
 conditions in terms of excess-air levels,

       Particulate measurements were made on a gravimetric basis using the EPA sampling train,
 with a slight modification of procedures specified in EPA Method 52. The particulate emission so
 determined  is termed "filterable particulate" in  this Summary and report; the additional con-
 tribution of "condensable particulate" is discussed in the report and  in Appendix F.

       Smoke density measurements were made by  the Bacharach hand-pump smoke meter, the
 standard method used in the oil-burner industry. The smoke spots were evaluated photomet-
 rically  by a reflectance meter.

       Figure 1-1 shows the field instrumentation as set up for measurements  on a commercial
 boiler.  Details  of  measurement procedures for  both gaseous  and particulate  emissions are
 described  in Appendixes E and F of this report.
2"Standards of Performance for New Stationary Sources", Federal Register, Vol 36 No  139 Part II n
 24895, December 23, 1971.                                            '   '    '     "> PP

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                                1-3
Figure 1-1. Field Instrumentation Used for Measuring Emissions
           From Commercial Boilers

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                                            1-4

RESIDENTIAL UNITS
       A variety of residential oil-fired  heating units were selected for the investigation so that
the sample would be representative of the field population of equipment currently in service for
heating single-family homes in the United States. Criteria for this selection of units were:  type of
oil burner by atomizing method, burner capacity, type of combustion head for air-fuel  mixing,
burner age, and type of heating system or unit.
Mix of Units

       Table  1-1  shows the  mix  of residential  units  for  the total sample  of oil-fired  units
investigated in Phases I and II.
Table 1-1. Mix of Residential Oil-Fired Units in Sample
Number of
Units
By Burner Type


By Burner Capacity



By Burner
Combustion-head Type
(high-pressure burners
only)
By Burner Age



By System Type


High-pressure
Low-pressure
Other
1.0 gph or less
1,01-1.35 gph
1.36-2.00 gph
Above 2.00 gph
Conventional head
Flame-retention head
Shell head
5 years or less
6-iQ years
11-15 years
Older than 15 years
Warm-air furnace
Hot-water or steam boiler
Service water heater
29
1
1
6
15
3
7
18
9
2
17
1
7
6
12
18
1

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                                           1-5

Conditions Investigated

       Measurements of gaseous and particulate emissions, obtained with the heating equipment
operating on the homeowner's fuel  supply, were made in the as-found condition of adjustment
and the tuned condition.
       Tuning. Normal service and adjustment practices were followed in tuning, short of major
replacement  or renovation. Most units were  tuned  to  a  smoke level  below No. 2  on  the
Bacharach scale; the mean smoke was reduced from No. 3.2 for the  as-found condition to No.
1.3 for the tuned  condition.* Smoke was reduced for over half the units; for most of the others,
a  slight  sacrifice  in  smoke  level permitted  an  increase in CO2  for  higher  overall thermal
efficiency. As-found, the  mean CO2 level was 7.9 percent; this was increased to 8.1 percent on
tuning.
       Types of Runs. Two ypes of runs were made with the residential units in Phase II.

            1.  Varied-air runs (Phase  II only) - Gaseous emissions and smoke  were
               determined  during  steady-state  operation  for a range of excess-air
               settings and plotted against CO2  to  determine sensitivity of emissions
               to air adjustment.**

            2.  Cyclic runs (Phases I  and  II) — Gaseous  and particulate emissions
               and  smoke were measured during repeated cycles of 10 minutes on
               and 20 minutes off.
Varied-Air Runs

       Emission  characteristics  measured during the  varied-air runs  were generally similar  for
most of the residential  units. Figure  1-2 illustrates the smoke-vs-CO2 characteristics for steady-
state firing of a typical unit, as determined in the varied-air runs  for the as-found and tuned
conditions.  A distinct improvement in performance is noted on  tuning, because lower  smoke
levels could be achieved at the same CO2  (or excess-air setting).

       Figure 1-3 snows the gaseous  emissions for  this typical  unit in the  tuned condition,
leaving a low-emission operating range between about  7 and  9 percent CO2 (corresponding to a
range of  excess air from about 65  to  110 percent).  Although  each  unit yielded unique
characteristic  curves, these  curves  are typical  of burners  where a relatively wide  range  of
excess-air  levels could be achieved.  For this unit and several others,  CO and HC  emissions
increased sharply at low CO2 levels, while smoke levels remained low. This demonstrates that CO
and  HC emissions can be high if units are adjusted  by smoke criteria  alone. (NOX was not  highly
sensitive to air settings.)
 *These mean smoke values do not include units in need of replacement, as explained subsequently.
**This procedure was similar to ASTM-D2157-65, "Standard Method of Test for Effect of Air Supply on Smoke
  Density in Burning Distillate Fuel".

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                                                                                                                   E
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Figure 1-2. Typical Smoke Versus CO2 Curves for a

          Residential Unit in the As-Found and

          Tuned Conditions
      Figure 1-3.  Typical Smoke and Gaseous Emission Characteristics

                 for a Residential Unit in the Tuned Condition

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                                            1-7

Cyclic Runs

       Figures 1-4  and 1-5  show the distribution of emission factors and smoke levels measured
on both the Phase I and II residential  units for cyclic runs in the as-found and tuned conditions.
It  should be  noted that 3 units were in poor condition and in obvious need  of replacement;
these units  yielded oily  smoke  spots  and generally produced emissions of CO,  HC, and  partic-
ulate that were much higher than those  for the remaining units.*  The oily smoke spots  would
reveal these  units  as needing burner replacement; this  condition would  be detected  by an
experienced serviceman using  field-type instruments.


       Effect of Tuning on Emissions. While tuning generally resulted in lower  smoke levels, it
produced variable  effects from  unit to  unit  on gaseous and particulate  emissions  in the cyclic
runs, causing some pollutant emissions  to  increase and others to decrease.

       In terms of the mean emission  factors, this  investigation showed that the  major reduction
in CO, HC, and particulate  is achieved  by identifying and eliminating units  in poor condition
(those in need  of replacement or major repair). For the remaining units, tuning further reduces
mean smoke and CO emissions but has little effect  on the mean values of other pollutants.

       Table  1-2  summarizes  the  reduction in  mean pollutant  emissions that could  be accom-
plished by the following steps**:

            1.  Identifying and replacing the units obviously in poor condition.
            2.  Completing Step  1  and, in addition, tuning the remaining units.
                    Table 1-2.  Effect on Mean  Emissions of Identifying and
                               "Replacing" Residential Units in "Poor"
                               Condition and Tuning
                                              Reduction in Emissions, percent
                                        	Step 1	          Step 2
                                            Identifying and          "Replacement"
                     Pollutant            Replacing of Poor Units        Plus Tuning
Smoke
CO
HC
NOX
Filterable Particulate
-
>65
87
No Change
17
59
>81
90
No Change
24
 *For normally performing units (those not showing oil on smoke spots), CO and HC levels were very low. In fact,
  the family automobile that meets the 1975 EPA emissions standards (as of June 1973) and is driven an average
  of 12,000 miles would emit annually 25 times as much CO and HC as would be emitted by firing 1000 gallons
  of oil, a typical annual consumption for a residential unit.
**Values are based on distribution of "poor" units found in the Phase I and II studies - that is, 3 poor units in a
  total sample of 34 units.

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                         Figure 1-4. Distribution of Smoke, CO, and HC Emission for Residential Units

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       Figure 1-5. Distribution of CO2, NOX, and Filterable Particulate Emissions for Residential Units

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                                              no

       Follow-Up  Measurements. For four of the residential units, follow-up measurements were
made twice during the heating season at 2-month  intervals to investigate the effect  of operating
time since tuning.  Except for one unit which experienced nozzle clogging, only minor  shifts in
smoke,  NOX, and  particulates were noted during the 4-month operating period. Emissions of CO
and HC for one unit increased significantly  but not to serious levels.
Summary of Residential Emissions and
Comparison With EPA Emission Factors

       Table  1-3  provides a summary of mean emissions for each of the pollutants measured for
the residential units during cyclic runs, Mean values of emission factors*  for the  Phase I and II
investigations  are  shown. Also shown  for comparison  are the  emission  factors  published by
EPA3.


    Table 1-3.  Comparison of Mean Emissions for Cyclic  Runs on Residential Oil-Fired Units

                                      Units        IViaan       Mean Emission Factors, lb/100Q gal
                                        in        Smoke                               Filterable
         Units           Condition     Sample3      No.b      CO        HC     NOX    Particulate
    Mean Values From Phase I  and II  Battelle/API/EPA Investigation:
All units

All units, except
those in need of
reolacement
As-Found
Tuned
As-Found
Tuned
32
33
29
30
(c)
(c)
3.2
1.3
>22.1
>16.4
7.8
4.3
5.7
3.0
0.72
0.57
19.4
19.5
19.6
19.5
2.9
2.3
2.4
2.2
    Current EPA-Published Emission Factors:3

                                                             5.0     3.0      12.0       10.0
    Suggested Emission Factors:  For residential units in areas having regular service and inspection

                                                             10.0     1.5      20.0        2.5


    a One unit was a furnace installed in the laboratory and was not included in deriving the mean emissions values for
      the as-found condition.
    ^ Smoke data ai 5-minute point of on-cycle.
    c Oily smoke spots prevented valid mean values.
*Emission factors  represent average emission levels for a category of equipment  and  are used  in area emission
 inventories and in evaluating control strategies. Emission factors should not be confused with emission standards.

3"Compilalion  of  Air Pollutant Emission Factors", U. S. Environmental Protection Agency  Office of Air Pro
 grams Publ. No. AP42 (February 1972).

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                                          Ml

Suggested Emission Factors for Residential Units

       This investigation was conducted over two heating seasons  and comprised measurements
on 33  oil-fired residential units selected to be generally representative of the existing equipment
population.  Because this study has provided more extensive data than available at the time the
present EPA  compilation of emission factors  was  prepared, it is suggested that the emission
factors applying to oil-fired residential equipment be updated as  shown in Table 1-3.


CONCLUSIONS FOR RESIDENTIAL INVESTIGATION

       The  principal conclusions  reached  from this investigation on a representative sample of
oil-fired residential heating units are outlined  below, considering findings from both Phases 1 and
II.

       1.  Inspection and Tuning. Air pollutant emissions from oil-fired residential heat-
          ing units can be significantly reduced on  an area-wide basis by the  use of
           available service procedures.

          The  most effective step  in  reducing area-wide emissions is the  identification
           and replacement (or major renovation) of units in poor  condition. Such units,
          identified  by the  presence  of oil on  smoke measurement spots during  this
           investigation, were  found to be contributing a disproportionately large share
           of the CO, HC, and particulate emissions.

          Tuning  the  remaining  burners by use of good  service practices achieved  a
           significant further reduction  in  smoke and  CO emissions.  Mean  smoke levels
           were reduced in tuning from 3.2 to 1.3  Bacharach smoke  number  and mean
           CO values were reduced  from 7.8 to 4.3 lb/1000 gal. Tuning produced little
           change  in  NOX,  while  filterable  particulate  and  HC  emissions  decreased
           slightly.

          Tuning increased the overall thermal efficiency for 60 percent of the Phase II
          units: the average incremental  increase of overall efficiency  for all urtits  was
           1.7 percent. This has  the effect of decreasing total annual emissions  due to
          resulting savings in fuel input.

       2.  Range  of Emissions and  Their  Distribution. A broad range of emission levels
          was  observed  for  the entire sample  of units  in  the  cyclic runs, but  the
          distribution of emission levels was relatively uniform except for those units in
          need of replacement. NOX levels showed the least variability.

       3.  Emission Characteristics  of  Individual Burners.  Varied-air  runs  in  Phase II
          revealed that each  burner had  its  own unique' emission characteristics over a
          range of air settings. Similarities in pattern were noted, but the permissible
          operating ranges  for low  emissions and the adjustment sensitivity were widely-
          different among burners. For  some burners, an attempt  to  set a minimum

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                                    1-12

   smoke level by increasing the excess air would result in sharply increasing CO
   and  HC emissions. Hence, both smoke and CO2 measurements should be used
   in adjusting a burner to insure low smoke at a high CO2 level.

4.  Smoke Measurements as Indicator for CO and HC. The varied-air runs showed
   that low smoke readings were a good indicator of low CO and HC emissions
   when operating at the low-excess-air side  of the adjustment range;  however,
   smoke was not a good indicator  of these emissions  at the high-excess-air side
   of the range.

5.  CO  and  HC Levels.  Emissions of CO and  HC from  all  units (except those
   identified as requiring  replacement or major repair)  were  so low during cyclic
   runs as to be insignificant in terms of contribution to air pollution.

6.  Effect of Combustion  Head  and System Type. Burners  with flame-retention
   combustion heads operated with  lower mean values  of CO, HC, and  filterable
   particulates than did burners with conventional combustion heads. No  signif-
   icant trends were observed relative to other factors of burner or system type.

7.  Effect of  Burner  Age. Burner age had  a  significant influence on emissions,
   with newer burners yielding  lower emissions.  Newer burners produced  signif-
   icantly less CO and filterable particulate for the tuned condition and slightly
   lower levels of HC, NOXJ and smoke for all conditions. The greatest difference
   between  emission levels for new and old burners occurred between the burner
   age  groups divided at  15 years. (These observations  as to  the effect of burner
   age  are  believed  to   be  due to  improved burner  designs to meet higher
   performance goals recognized voluntarily  by  equipment manufacturers  in
   recent years, rather than to a deterioration in  service that cannot  be restored
   by competent tuning.)

8.  Effect of Operation Since Tuning. Follow-up measurements, made twice dur-
   ing the heating season  at 2-month intervals  for four units,  were not consistent.
   Emissions  remained  nearly  constant for  two  units.  CO and HC  emission
   increased  for  another  unit, while  other emissions remained constant. Smoke,
   CO, and HC increased for the fourth unit, which had malfunctioned  due  to
   improper tank filling.

9.  Smoke vs  Particulate.  Bacharach smoke readings taken at different points in
   the  firing  cycle typically showed that smoke density was greatest during the
   first minute and reduced as  the cycle  proceeded.  A  continuous-tape  smoke
   indicator confirmed that higher levels of smoke frequently occurred  on start-
   ing and shutdown for brief periods.

   Smoke readings taken  at relatively steady-state conditions during the  cyclic
   runs  were  not  a good measure of filterable particulate emissions which
   included  sampling during starting and shutdown transients. Smoke  measure-
   ments may be more indicative of emissions of fine particulates, which are the
   principal concern in health effects and atmospheric visibility. Additional labo-
   ratory investigations are planned  to  examine the relationship between smoke

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                                      1-13

    and particulate for steady-state and cyclic conditions over a range of excess-air
    settings.

10.  Suggested  Emission Factors. Emission factors for use in emission inventories
    and implementation plans were suggested on the basis of this investigation and
    are  shown in Table  1-3. Suggested  emission factors are  higher than  EPA-
    published  factors for CO and NOX,  but are substantially  lower for HC and
    filterable particulates.

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                                             1-14

COMMERCIAL BOILERS


       The  13  commercial boilers  sampled  in Phases I and II  were selected to be generally
representative of the commercial boiler population  in terms of boiler type, capacity, and burner
type. Boiler sites  were selected with  the aid  of a committee of the American  Boiler Manu-
facturers Association (ABMA) to ensure that boiler toad and burner adjustment conditions could
be controlled.  For Phase II,  another selection  criterion was the feasibility of  firing as many  as
four  different   fuels in  a given  boiler;  these  fuels  included natural gas,  No. 2 heating oil,
conventional grades of residual oil, and a  low-sulfur residual oil (1 percent sulfur) that was used
as a reference  fuel and transported  from  site to  site in a tank truck. A total of 33  boiler/fuel
combinations were sampled.


Mix  of Boilers

       Table 1-4 summarizes the mix of commercial boilers  covered in this investigation for both
Phases I and II.
                       Table 1-4.  Mix of Commercial Boilers in Sample
By Boiler Type



By Boiler Capacity
(Boiler Horsepower)8

By Oil-Burner Typeb


Scotch firetube
Firebox firetube
Cast iron
Watertube
10-100 BHP
101-300 BHP
301-600 BHP
Air atomizing
Pressure atomizing
Rotary atomizing
Number
of Boilers
8
2
2
1
5
6
2
8
4
1
                  a Boiler capacity rating; one boiler horsepower is equivalent to
                    approximately 33,500 Btu/hr output.
                    Seven of these boilers had dual-fuel burners capable of firing natural gas.

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                                            1-15

       Statistics developed in a special survey  conducted for this program in  cooperation  with
ABMA confirmed that the Phase II sample was reasonably representative of the current  field
population of commercial boilers. Detailed data  from the survey are presented in Appendix B.
Conditions and Fuels Investigated

       All measurements  on  the commercial boilers  were  made at steady-state conditions.
Gaseous  emissions and smoke were measured in Phase II  while  the boiler was operated at four
different  loads  and  at about Five excess-air levels at each load. Nominal loads were full, 80
percent,  50 to  60 percent, and low-fire setting,  which was generally  from 30  to 40 percent.
Because of the long sampling time required at each  setting, particulate emissions were measured
at only about five selected points for each boiler. (Phase  I measurements generally consisted of
gaseous emissions and smoke  measurements, at  four loads  and  particulate emission measurements
at two points.)
 Base-Line Condition

       To provide  a common  basis  for  comparing  emission  levels  from  various  boilers,  a
 "base-line condition" was defined after consultation with ABMA to identify a condition typical
 of  boiler operation  most  frequently  encountered in the  field.  This  base-line condition was
 defined nominally as 80  percent load with an air  setting  to achieve flue-gas compositions  of  12
 percent CO2 for oil firing and approximately  10 percent CO2 for gas firing. This corresponds  to
 the following excess-air levels: approximately 28 percent  for No. 6 oil, 25 percent for No. 2 oil
 or light residual oil, and  15  percent for natural gas.

       Measurements  of gaseous,  and  particulate  emissions  and  smoke were made for this
 base-line condition on all boilers in Phases I and II.
 Fuels

       Table  1-5 identifies the fuels fired in each of the boilers  for both Phases I  and II. The
 fuels normally used as "house fuels" are identified. LSR refers to the low-sulfur residual oil used
 as a reference fuel in Phase II; a similar fuel was fired in one boiler during Phase I.
Typical Emission Trends

       Each of  the  commercial  boilers generally  exhibited the  expected pattern  of emission
characteristics, with smoke sharply increasing as low excess-air settings were approached from the
normal operating range. Figures 1-6 and 1-7 illustrate typical curves of smoke and NOX emissions
vs excess air  for one boiler fired at  80 percent load with three fuel oils and natural gas. Botl
smoke density and NOX levels were  strongly influenced by fuel grade. Effects of load on smoke
and  NOX  were  relatively  minor. Emissions  of CO  and HC were  consistently  low  for  the
commercial boilers in normal operating ranges.

-------
                                                1-16
               Table 1-5.  Summary of Fuel  Types  Fired in Various Commercial Boilers
                          Boilers for both Phases I  and II  Listed in order of capacity.
Boiler Horsepower
and Type
40-hp Cast iron
60-hp Scotch
80-hp Scotch
80-hp Firebox
90-hp Cast iron
100-hp Scotch
125-hp Scotch
125-hp Firebox
150-hp Scotch
200-hp Scotch
300-hp Scotch
350-hp Scotch
600-hp Watertube
Burner
Atomizing
Type Phase
Pressure 1 1
Pressure I
Air I
Pressure II
Air II
Air II
Rotary I
Pressure I
Air I
Air I
Air II
Air I
Air II
Fuels Fired"
No. 2 No. 4 No. 5 No. 6 LSRb Gas
A _ _ _ _ •
A _ _ _ *
_ _ A _ _ _
. _ * _ • e
• * _ _ • •
• _ _ * •
A _ _
*•___— —
*• « BC
_ A _ _ _ _
• - - * m .
_ A _ _ _ _
• - - * • •
         a  Legend: ^ House fuel oil normally used.
                  • Alternate house fuel.
                  • Low-sulfur residual oil (Phase II reference oil),
         "  Low-sulfur residual oil commercially available on East Coast (1.0 percent sulfur content).
         c  A low-sulfur residual oil (0.5 percent sulfur) was fired in this unit in addition to the 1.0 percent sulfur oil.
 Effects of Fuel

        Significant  effects of  fuel  properties were  observed  in the investigation,  especially  as
related to paniculate and NOX emissions.
        Particulate Emissions, Particulate emissions and smoke increased with increasing fuel-grade
designations  when several fuel oils were fired in the  commercial boilers at  a  given excess-air
settingpthese emissions were consistently low when firing natural gas.

        The  effect of fuel grade on filterable particulate emissions is summarized in Figure 1-8 for
all  boilers from Phases I  and II firing oil at base-line conditions. Particulate is plotted against API
gravity as an indicator of burning characteristics and fuel grade - the  heaviest fuels having lowest
API gravity. Approximate ranges of API gravity for different fuel grades are shown.

-------
$
o
E
to
u
O
o
s^
o
o
CO
             10     20     30     40      50
                         Excess  Air,  %
50
70
 Figure 1-6.  Typical Characteristics of Smoke Versus
            Air for a Commercial Boiler Firing Different
            Fuels at 80-Percent Load

                     JQ
                     E
                     LU
                      x
                     O
                                                                           0.5
                                                                           0.4
                         0.3
                  0.2
                                                                            O.I
                                                                                              No. 6
                                     No. 2
                                                                                                  Gas
                                                                                                                   I
                                                                       I
10    20   30   40   50
           Excess  Air,  %
60    70    80
                    Figure 1-7. Typical NOX Emissions Versus Excess Air
                               for a Commercial Boiler Firing Different Fuels
                               at 80-Percent Load

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     IOO
  O

  P   75
  _
  .a
  o
      50
            f*- No. 5
                        No. 4
                No.2-~|
                           Fuel  Oil  Grades
           No. 6,
               Mo. 5
              15
20    25    30    35    40

  API Gravity
Figure 1-8.  Relation of Filterable Particulate and
           API Gravity for the Commercial Boilers
           Firing Different Fuels at Base-Line
           Conditions — Phases I and II
                                                 c
                                                 tu
                                                 D>
b

"cE

Q.

ro

o
                                                 
                                                 o
                                                 "in
                                                 en
                                                 "E
                                                 UJ
                                                 x
                                                 O
                                                                        450
                                                    400r-
                                                                        3501—
                                                    300
                                                                        250 H
             o   C2002
             x   C2003
             +   C2004
                 C2005
                 C2006
                                                                        200 f-
               0.1      0.2     0.3     0.4

                Nitrogen in  Fuel,  percent
                                                 Figure 1-9. Relation of NOX Emissions and Fuel Nitrogen
                                                            for the Commercial Boiler Firing Different
                                                            Fuels at Base-Line Conditions — Phase II

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                                            1-19

       Ash content tends to be higher for  fuels of low API gravity but is not sufficient to
account for higher particulate levels with heavier fuels. The band of ash content for the fuels in
this investigation is shown in Figure 1-8.

       The 1-percent sulfur  residual oil used as a reference fuel  was closer in performance to a
No. 4 or No. 5 oil; it yielded filterable particulate levels about equal to those  from No. 4 oil and
only one-third of those from the No. 6 oil.
Effect of Fuel Nitrogen on NOX

       Figure 1-9 shows the strong effect of fuel nitrogen on NOX emissions from the commer-
cial  boilers in  which  several fuel oils  were fired  at base-line conditions.  The  zero-nitrogen
intercept  is indicative  of NOX  formed  by  thermal fixation, which  is dependent upon flame
temperature and other combustion parameters influenced by  boiler/burner design.  The slope of
the curve of NOX versus fuel nitrogen reflects the conversion of fuel nitrogen to NOX.

       Both the thermal component of  NOX and the conversion of fuel nitrogen  to NOX vary
from boiler  to boiler. The equation  that  best  fits the  data  from  boilers in  which fuels of
different nitrogen content were fired  is NOX  (ppm at 3% O2) = 97 + 420-N0-6. This indicates that
about 62 percent of the fuel-bound  nitrogen was converted  to  NOX  for a 0.2 percent nitrogen
fuel,  47  percent for a 0.4 percent nitrogen  fuel,  and 38 percent for a 0.7  percent  nitrogen fuel.
Other investigators have reported conversion  of fuel nitrogen to NOX  in the same range.

       It should be  pointed out that other fuel properties,  such as gravity and viscosity, also
varied from fuel to  fuel in this program; thus,  the  NOX levels shown  in Figure 1-9 may hiclude
effects of factors other than fuel nitrogen.
Summary of Oil-Fired Commercial  Boiler Emissions

       Emissions for the commercial  boilers firing oil at the base-line conditions are summarized
in Table 1-6. Mean emission values are shown separately for  each grade of fuel;  the mean  fuel
properties  shown for each grade  of  fuel pertain to the fuels  fired in this  field investigation.
(Since broad ranges in properties exist within each grade, these values cannot be considered to be
representative of all fuels within these grade  designations.)
Suggested Emission Factors for Oil-Fired Commercial Boilers

       This investigation has included  emission measurements on 13 commercial boilers with 26
boiler/fuel-oil combinations and  with  a variety  of operating conditions.  The  emission levels
measured in  this investigation show sufficient effects of fuel properties to justify the conclusion
that emission factors intended for use  in compiling  emission inventories or in evaluating control
strategies should discriminate between fuel-oil grades  where these  are known.

       Accordingly, Table 1-7 presents suggested emission factors  by fuel grade.

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                                              1-20
                   Table 1-6.  Summary of Emissions from Commercial  Boilers
             Mean emissions by fuel-oil grade measured in Phases I and  11  at base-line
             conditions3 for 13 boilers ranging in capacity from 40 - 600  boiler hp.
Fuel
Oil
Grade
No. 2
No. 4
No. 5
No. 6
LSRb
Number of
Boilers
8
3
3
5
6
API
Gravity,
mean
35
22
19
16
23
Sulfur
%.
mean
0.2
1.7
1.8
1.9
1.0
Viscosity
SSU @ 100 F,
mean
34
120
220
3600
400
Smoke
No.,
mean
0.9
2.6
3.0
3.9
2.9
Mean Emission Factors, lb/1000 gal
CO
0.5
0.8
1.9
1.1
0.3
HC
0.15
0.15
0.22
0.30
0.27
NOX
18
73
54
78
49
SO2C
132-S
149-S
175-S
173-S
157-S
Filterable
Paniculate
1.5
7.1
T3.
38.
13.
a Base-line operating conditions: 80 percent load and air adjustment for 12 percent COj flue-gas concentration.
b Low-sulfur residual oil, typical of 1.0 percent sulfur residual oil being .marketed on the East Coast in 1971 - 1972.
0 S = multiplication factor equal to percent sulfur content of fuel.
        These  values  were derived from the findings of this investigation in such a way as to
 normalize the effects of fuel properties for the different grades of fuel that were "encountered"
 in  the field during the investigation but may have been atypical of that grade on  a national basis.
 The  procedure  used to  establish the  suggested  values in  Table 1-7 was to plot  CO, HC,  and
 participate emission  factors  for each  boiler/fuel combination  at  base-line conditions  vs API
 gravity as  an indicator of  fuel characteristics.  (Although not  a  universal index of emission
 performance,  API gravity has the practical  effect  of reflecting some of the  other important
 factors and is  one of the most commonly available fuel properties.)

        "Best  curves" were fitted by a least-squares technique;  Figure 1-8 shows  the curve for
 particulates. Emission factors were then obtained  from the curves by assuming API gravity values
 typical of the  various grades of fuel as follows:
                Distillate Oil

                Conventional Residual Grades




                Low-Sulfur Residual (1.0% S)
Fuel Grade

  No. 2

  No. 4
  No. 5
  No. 6

  LSR
   Typical
 API Gravity,
degrees @ 60 F

     34

     22
     17
     14

     23

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                                  1-21
     Table 1-7.  Suggested Emission  Factors for  Oil-Fired
                  Commercial Boilers and Comparison
                  With EPA-Published  Factors
Fuel
Oil
Grade3
Emission Factors, lb/1000 galb
CO HC NOXC SO2d

Filterable
Paniculate
Suggested  Emission Factors:  Based on Battelle/API/EPA Investigation5
No. 2
No. 4
No. 5
No. 6
LSRf
0.5
0.9
1.1
1.2
0.9
0.17
0.24
0.28
0.30
0.23
20 + 78-N0-6
20 + 85-N0-6
20 + 87-N° 6
20 + 89-N0-6
20 + 84-N0-6
142'S
154-S
159-S
162-S
153-S
1.2
14.0
27.0
36.0
12.0
Current  EPA-Published Emission  Factors3
Distillate
Residual
0.2
0.2
3.0
3.0
40 to 80
40 to 80
142-S
157'S
15.0
23.0
 a   These values are based on mean emission data for the identified fuel grades
    having typical API gravity as follows:  34 degrees API for No. 2; 22 for No. 4;
    17 for No. 5; 14 for No. 6; and 23 for LSR.  Where actual API gravity is
    known, interpolated values should be used.
    To convert to emission factors in lb/10^ Btu, multiply these values by 0.0069.
    (The actual multiplier varies slightly with fuel grade, being about 0.0071 for
    No. 2 fuel oil and 0.0066 for No. 6 fuel oil.)
 c   N = multiplication factor equal to percent nitrogen in fuel oil. If concentration
    is unknown, the following values are suggested:  0.01 percent for No. 2;
    0.2 percent for  No. 4; 0.3 percent for No. 5; 0.4 percent for No. 6; and
    0.2 percent for  LSR.
 d   S  = multiplication factor equal to sulfur content in fuel.
 e   Assuming steady-state base-line operating conditions:  80 percent load and  air
    adjustment for 12 percent CC>2 flue-gas concentration.
    LSR:  low-sulfur residual oil (1.0 percent S).

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                                             1-22

These  typical  values were estimated  considering values suggested  by API representatives and
average values  from  the field  fuels. The resulting emission factors are  shown in Table 1-7  as
"suggested emission factors".

       Suggested NOX emission factors are based on fuel nitrogen content and reflect decreasing
conversion  of  the fuel  nitrogen  to  NOX  as  fuel nitrogen levels increase. Emission  factors
recommended for SO2 are proportional to sulfur content of the fuel.

       For comparison,  Table 1-7 also shows the current EPA-published emission factors, which
distinguish between only two  categories of fuel oil: distillate and residual oil.
Summary of Gas-Fired Boiler Emissions
and Suggested Emission Factors

       Table 1-8 summarizes emissions  as measured from seven commercial boilers firing natural
gas and  gives  suggested  emission factors. The major changes suggested are to reduce emission
factors for HC and filterable particulates.
             Table 1-8. Suggested Emission Factors for Gas-Fired Commercial Boilers
                       With Comparison of EPA-Published Factors

                                                   Emission Factors, lb/106 cu ft3
                                                                             Filterable
                                           CO       HC     NOX      S02    Particulate
           Mean Emission From 7 Boilers:
            Battelle/API/EPA
            Investigation15                   16.7      3.7     105       Nil        5.7


           Suggested Emission Factors3        20.0      4.0     100       0.6        6.0
          Current EPA-Published
            Emission Factors3               20.0      8.0     100       0.6        19.0


          3 To convert to emission -factors in lb/106 Btu, multiply these values by 0.00098.
          b Base-line Operating Conditions: 80 percent load and air adjustment for approximately 10 percent
            CO2 flue-gas concentration.

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                                           1-23

CONCLUSIONS FOR COMMERCIAL BOILER INVESTIGATION

       Major conclusions from the findings of this investigation of emissions from a representa-
tive sample  of  commercial boilers are outlined below, based on the combined results of Phases I
and II.

       1. Emission Characteristics of Commercial Boilers. The varied-air runs with the
          commercial boilers  showed  that  the smoke curve generally was  flat  over a
          range  of excess-air  levels but  increased sharply as the combustion air  was
          reduced below normal  air settings. For  oil firing, smoke levels  tended to
          increase before CO  and HC increased. With gas firing, CO  and HC increased
          before the smoke density increased.

          To  adjust the air setting to  acceptable smoke  (or minimum  smoke for that
          boiler/fuel combination) would require combustion air settings as high as 30
          to  40 percent excess air for most  of the boilers operating with  the  heavier
          fuels.  It  was  possible to fire gas at 10 percent excess air without exceeding
          No. 1  smoke;  however,  20 percent excess air was required to  avoid  rapidly
          increasing CO emissions with gas. Smoke  increased slightly  at high excess air
          in only a few cases with oil firing  and in one case with gas firing.

          These observations  suggest that field-type instruments  for measuring  smoke
          and CO2 can be used satisfactorily in adjustments for oil firing to minimize
          CO  and  HC  as  well as smoke;  however,  a CO  indicator is needed  in  air
          adjustments  for  gas firing.  (CO  and HC levels at base-line conditions were
          generally low for all boilers firing either oil or gas.)

          NOX was relatively insensitive to air setting.

       2. Effect of Load. Load generally had little influence on emission levels, including
          NOX.  Smoke  and particulate increased with load on several boilers when firing
          No. 6  oil, suggesting that limitations in  mixing or combustion volume were
          being  reached at high load. (For minimum smoke  at low fire, some  boilers
          require  a higher  excess-air  setting at this  point, and this adjustment  is fre-
          quently made in  the field when setting the control  linkage.)

       3. Effect  of Boiler and/or  Burner Design  on  Emission  Levels. Considerable
          variation in emissions was  noted from boiler to boiler, even  when firing the
          same fuel at base-line conditions. Particulate emissions with the reference fuel
          varied by  a  factor of 4.4 from lowest to  highest.  Smoke varied  only by a
          factor of 1.4. Emission levels of CO and HC were judged to be  sufficiently
          low to be insignificant for all oil firing.

          NOX emissions for various boilers varied from lowest to  highest by a factor of
          1.3  at base-line conditions when firing the reference fuel. Boiler and/or burner
          design variables did  not show a consistent influence on NOX  emissions, even
          when firing low-nitrogen fuels.

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                                     1-24

    No attempt was made in this investigation to  optimize emission  performance
    by modification  of the burner  design  or atomizer; thus,  the data are not
    adequate to  indicate what minimum emission  levels might be  achieved by
    optimizing  burner design for a given boiler/fuel combination.

4.  Effect of Fuel Oil Properties on  Smoke and Paniculate. Fuel oil grade had an
    important bearing on smoke and particulate levels. For the boilers operating at
    base-line conditions, the heavier  fuels (i.e., lower API gravity)  yielded higher
    smoke  and particulate,  although the heavier grades were fired at  conditions
    used  in normal practice.

    A regression  analysis indicated that  the  single most important fuel property
    influencing  filterable particulate  at base-line  conditions was carbon  residue
    (correlation coefficient  of 0.68). API gravity also  had a  significant  effect
    (correlation coefficient of 0.55).  Viscosity at firing temperature was relatively
    insignificant (correlation coefficient of 0.25).

    An index combining carbon residue,  viscosity at  firing temperature,  carbon
    content, and API gravity yielded a good  correlation with filterable particulate
    (correlation coefficient of 0.86).

    The low-sulfur residual oil having 1-percent sulfur was closer to  a No. 4  or 5
    grade in viscosity, gravity, and other burning characteristics than to conven-
    tional No. 6  oil.  Particulate emissions with this  fuel averaged one-third those
    of the conventional No. 6 oil.

    NOX  levels  tended to be higher with the heavier fuels, but this is traceable to
    generally higher fuel-bound nitrogen with  the heavier grades.

5.  Effect of Fuel Nitrogen on NOX. NOX emissions  increased nearly  linearly  with
    increasing fuel nitrogen content when different fuel oils were fired in the same
    boiler.  The slope of NOX versus fuel  nitrogen curves indicated conversion of
    about 40 to 60  percent of the fuel nitrogen to  NOX.

    A combination  of other factors  influenced  thermal components of nitrogen
    fixation, but  a consistent pattern was not detected; firing rate did not  have as
    consistent an influence in Phase II as observed in  Phase I.

6.  Gas Firing  vs Distillate Oil,  Smoke and  particulate emission levels with gas
    firing were  generally lower than with  No. 2 oil when  firing the same boiler at
    base-line  conditions.  On a  Btu-input basis,  mean particulate  emissions at
    base-line conditions for gas firing were one-third of those for No..2 oil.

    Mean NOX  levels  with gas firing were three-fourths of those  for No. 2 oil. For
    half the boilers, gas fking yielded slightly higher NOX  levels than did No. 2 oil
    at base-line  conditions.

    CO and  HC emissions were higher for gas than No. 2 oil: CO over five times
    higher, and  HC about three times higher.

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                                     1-25

7.  Correlation of Smoke vs Particulate. For the commercial boilers operating at
    steady-state conditions, Bacharach smoke numbers showed consistent trends in
    relationship  to filterable particulate when  firing different fuels in  the same
    boiler.  This suggests that families of correlation curves may be possible, with
    each curve characteristic of a given boiler  firing a given fuel.  If this relation
    could be further defined for a  series of similar boiler designs, predictions of
    particulate performance could be made  using simpler field measurement tech-
    niques.

8.  Suggested Emission Factors. Because of the large differences in emission levels
    in commercial boilers due  to the effects of fuel  properties, separate emission
    factors should be used  for  different grades of fuel oil in emission inventories
    or  implementation  plans.  Suggested emission factors were  established by fuel
    grades  using  the trends identified  in  this investigation; these are shown in
    Table 1-7. Suggested emission factors for boilers firing natural gas are shown in
    Table 1-8.

    Other than to  account for  the  fuel-oil grade discrimination,  the major  sug-
    gested  changes  of EPA-published values are reductions in emission factors for
    HC  and  particulate from  firing  No. 2  oil. In addition,  it is  suggested  that
    emission  factors for NOX  be based partly on fuel nitrogen content. Suggested
    changes for  natural gas firing are reductions in  emission factors for HC and
    particulate.

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                                            II-l

                         EMISSIONS FROM RESIDENTIAL UNITS
       This chapter describes  the  Phase II investigation of emissions from  residential oil-fired
heating units. The principal effort  of Phase II was devoted to more detailed  field measurements
of emissions covering more conditions than was possible for the Phase I study. The discussion is
presented as follows:

            • Units Included in the Phase II Investigation
            • Procedures Used in the Field Investigation
            • Emission Results for Cyclic Runs
            • Emission Results for Varied-Air Runs
            • Correlation of Smoke and Particulate.

Where applicable, results of Phase I emission measurements have been included in the analyses of
the influence of various factors on emissions.


UNITS INCLUDED IN THE PHASE II INVESTIGATION

       The scope of equipment in the  Phase  II investigation included  13 oil-fired residential
heating units with firing rates from  0.6 to  1.75 gph.


Basis for Selection of Equipment

       Selection of residential oil-burning equipment installations to be studied in Phase II of
this  program was directed toward making the total sample of the Phase I and  II units reasonably
representative of the population of  equipment in service, considering such factors as

            • Burner type
              — atomizer type and combustion head

            • Capacity or firing rate

            • Installation type
              — matched unit (burner-boiler unit or burner-furnace unit) or conversion
                burner

            • Heating system type
              — hot water, steam,  or warm air

            • Age of installation.

Obviously, within the limits of a  program of  this size, it was not  possible to include a large
number of  units in each  category. However,  an attempt was made to include a distribution of
oil-fired units similar to the distribution of units now in service.

       As an initial step  in the selection of the residential units  to be included in the Phase II
investigation, a questionnaire on the existing oil-burner population was submitted to a number of

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                                             II-2

 burner service organizations, Replies to the questionnaires were slow in being returned, hence,
 the Phase II investigation was launched using previously published oil-burner population data for
 selection of residential units. Sources of information on oil-fired equipment that were consulted
 included Fueloil  & Oil Heat  magazine and  the National  Oil  Fuel  Institute.  This information,
 combined with  the  experience  background  of the  project team,  was  used in  establishing  a
 suitable mix of units. The Battelle-Columbus recommendations as to the general equipment mix
 were then examined and  approved by the EPA Project Officer and the API SS-5 Task Force.

        Results of the questionnaire  confirmed that the equipment mix  selected was  representa-
 tive of the existing equipment population.


 Selection of Equipment Mix and Individual Units

        Table II-l outlines the types of equipment included in the residential equipment mix and
 shows the number of units  of each  type included in this investigation for Phase II and the total
 for the  two phases.  The selected mix of units is compared with  the  distribution of the U.S.
 equipment population.

        Background  data obtained  from the questionnaires on residential  equipment mix  are
 shown in Appendix A. These data represent the best statistical data available covering detailed
 categories of equipment  now in service on a national basis. High-pressure gun-type burners  are
 clearly the  dominant burner  type  for residential heating.  Also, burners  of 1.35 gph or less
 account for nearly 70 percent of the residential heating units.

        Individual residential field  units  were  selected by the  Battelle field  team with the
 assistance of Consultant W. H.  Axtman and with  the aid of a qualified  oil-burner  servicing
 organization. The majority of the units investigated  were selected from the service contract files
 of the organization,  and the initial contact with the homeowner  was  made by the  servicing
 organization. The servicing  organization supplied a  skilled serviceman  to  tune  or  adjust the
 burners following the initial  measurements.
 Description of Residential  Units

       Table  II-2  shows the number designations for the residential  units which are used to
 identify  emission data elsewhere in this report for the specific  residential units. This table also
 includes  a brief  identification of burner type, firing rate, heating system type, and burner and
 system  age - including  whether  the installation is (1)  a  "matched" factory-designed  burner-
 furnace or burner-boiler unit or (2) a "conversion" installation where the burner has been added
 in the field to a basic furnace or boiler, possibly originally designed for coal  firing. (Nearly all
 furnaces  and boilers being installed today are matched units.)

       Twelve of the  units (Units 23 through 34) were field units in use for residential heating.
An additional unit, identified as Unit 35, was a new residential oil-fired  furnace which was set up
in the laboratory at Battelle-Columbus during  the Phase I  study  for the calibration  and  checkout
of instruments, sampling procedures,  and the operating-cycle timing. All thirteen of  the units
were  high-pressure  gun type; five  had flame-retention  combustion heads and one had  a Shell
combustion head.

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                                                II-3
        Table  11-1.  Mix of 31  Residential  Units in Sample Compared With Distribution
                     of U.S.  Equipment Population in Service
Units in Sample


By Burner Type
High-Pressure Gun
Low Pressure
Vertical Rotary
Wall-Flame
Vaporizing
By Burner Capacity, 9 gph
<1.0
1.01-1.35
1.36-1.65
1.66-2.00
2.01-3.0
>3.0
By Burner Combustion-Head Type
(High-Pressure only)
Conventional Head
Flame- Retention Head
Shell Head
By Burner Age, years
<5
6-10
11-15
16-20
>20
By System Type
Furnace
Boiler
Water Heater
Number
Phase II

13
0
0

0

4
7
1
1
0
0


7
5
1

9
0
1
3
0

9
4
0
of Units
Tota^

29
1
1

0

6
15
2
1
5
2


18
9
2

17
1
7
3
3

12
18
1
Percent
of Distribution of U.S. Equipment
Totala

94
3
3

0

20
49
6
3
16
6


62
31
7

55
3
22
10
10

39
58
3
Population, percent11

84
10
5

1

34
35
14
8
5
4


81
11
8

19
23
28
19
11

52
48
-
Including units from both Phases I and II.
From References 4 and 5 as follows:
   4  Fueloil and Oil Heat, "The Typical Oil Burner", Vol. 31, No. 6 (June 1972), pp 44-45.
   5  Fueloil and Oil Heat, Special Study, Vol. 30, No. 1  (January 1971), pp 22, 24.
These statistics are summarized in more detail in Appendix  A.

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                                            11-4
                     Table 11-2.  Description of Residential Units for Phase II
                                All units had high-pressure gun burners.
Burner Head
Unit Type
23
24d
25
26e
27
28
29
30
31
32
33
34
35
a
b
c
d
e
Flame retention0
Conventional
Flame retention0
Shell
Flame retention
Flame retention
Conventional
Conventional
Conventional
Conventional
Flame retention
Conventional
Conventional
Firing
Rate3,
gph
1.35
1.00
1.35
1.75
1.35
1.00
0./5
0.60
1.50
1.00
0.85
0.75
1.00
Heating-System Type11
Cl boiler, conversion, water
Steel forced-air furnace unit
Steel boiler unit, water
Cl boiler, conversion, steam
Steel boiler unit, steam
Steel forced-air furnace unit
Steel forced-air furnace unit
Steel forced-air furnace unit
Steel forced-air furnace unit
Steel forced-air furnace unit
Steel forced-air furnace unit
Steel forced -air furnace unit
Steel forced air furnace unit
Nominal firing rate or nozzle capacity as found, gph.
"Unit" describes "matched" burner-furnace or burner-boiler units engineered by
construction.
High-speed fan motor (3450-rpm).
Unit 12 from Phase I study.
Unit 16 from Phase 1 study.
Combustion
Chamber
Material
Firebrick
Metal
Ceramic felt
Firebrick
Hard refractory
Metal
Hard refractory
Hard refractory
Firebrick
Metal
Firebrick
Hard refractory
Ceramic felt
the manufacturer. Cl
Estimated
Burner
<1
4
<1
2
5
2
18
18
20
<5
3
11
2
Age, yr
System
21
4
<1
9
5
8
18
18
20
<5
15
11
2
denotes cast-iron
       Nine of the Phase II  oil-fired  units were warm-air furnaces and four were water or steam
boilers. Only two of the thirteen units investigated this  year were  conversion units. The ages of
the burners and heating systems ranged from less than 1 to about 20 years.


PROCEDURES USED IN THE RESIDENTIAL
FIELD  INVESTIGATION

       Measurements on residential heating units  were started in December,  1971, and,  except
for  the  last follow-up runs,  were completed in  February,  1972. The  investigation of  each
residential  unit required from 2 to 3 days, including instrument setup and measurements under
the test conditions. The measurements were made by a three-man field team supported by other
Battelle-Columbus staff and a consultant.
Burner Conditions Investigated

       Emissions from residential  units were monitored  during cyclic operation (repeated cycles
of 10 minutes on and 20 minutes off) and during steady-state operation while the excess air was
varied. Both cyclic and varied-air runs were made at three sets of burner conditions:

-------
                                            II-5

            A "As found condition" of burner adjustment using house fuel
            T "Tuned condition" using house fuel
            R "Reference fuel" run  under the  same  conditions  as  the tuned run  to
              provide a base line for comparison of units.

The letter designations (A, T, and R) are used elsewhere in this report to key the condition of
the runs.*
       Definition  of Tuned Condition.  Experience on  the first  few of the Phase  I units had
shown variability  among  servicemen in  their  criteria  for properly adjusted units.  For  the
remaining Phase I and II units, the tuned condition was defined as the best adjustment (in terms
of the  smoke-CO2  relationship)  that could  be achieved by  a skilled  serviceman with normal
cleanup, nozzle replacement, simple sealing, and adjustment procedures with the benefit of field
instruments. It did not include major repairs, modernization, or replacement of major parts that
would require  special charges  to  the homeowner (e.g.,  replacement of a combustion chamber).
Further details of  the adjustment procedure are presented in Appendix D.
       Influence of Tuning on Smoke  and CO2. Figure II-l  shows the influence of tuning on
smoke and CO2  levels  for the Phase  II  units, with unit numbers  identified. (Unit 35,  the
laboratory unit  at Battelle, is not included  in discussions of tuning, as it had no normal as-found
condition, but is  treated as a tuned unit in data tabulations.) Due to the generally low  smoke
levels in the as-found  condition, tuning  reduced smoke in only 6 of the 12 units. In 9 of the 12
units the CO2 setting was increased.

       Figure II-2 shows the distribution of smoke and CO2  levels for the 12 residential units
included in the  Phase II investigation together with the 20 oil-fired residential units included in
the Phase I investigation. For the Phase II units only, 75 percent operated with  a No. 2 smoke or
less  in  the as-found  condition and all  units operated  at No. 2  smoke  or  less in the tuned
condition. The  mean  smoke level for the  12 Phase II units was 1.5 for the as-found condition
and  0.6 for the tuned condition. The smoke levels measured during the Phase II investigation for
both the  as-found and tuned conditions were significantly below smoke levels measured  during
the Phase I study.**

       The average CO2  was 7.9 percent for the as-found and  8.5 for the tuned condition for
the  12 Phase II units that were tuned. The plot of CO2  values for the as-found condition for Phase
II data  were in  a  narrower range  (6.1 to 9.4) than for Phase I data (3.8 to 12.5); 75 percent of
the Phase II units  had CO2  levels of 7.9  to  9.9 in the  tuned condition.
 "The cold start condition investigated in the Phase I procedure was not included in Phase II because the gaseous
  emissions measured for these runs during Phase I did not differ appreciably from the emissions obtained after
  repeated cycles.
**Extensive inquiry of, the field team and study of the smoke spots and data have not revealed why the Phase II
  smoke data were lower than Phase I data.

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                                            II-6
c   8
   S;   6
  _Q
   E
   o   4
  to
  .c
   o
  _
   o
   a
  CD
                      Legend
                  •   As-found
                  o   Tuned
                                 C02 in  Flue  Gas,  percent
        Figure II-1.  Operating Conditions for 12 As-Found and Tuned Residential Units
       Reference Fuel  Condition. To obtain a base line or reference for the variety of burner
units, gaseous emissions and smoke were  measured  for each  residential unit during  cyclic and
varied-air  operation while firing a reference fuel in the tuned condition. This reference  fuel was
selected as a high-quality No. 2 hydrotreated fuel.

       Properties of all fuels fired in the residential units are tabulated in Appendix C, Tables
C-l and C-2.
Operating Conditions Investigated

       Emission measurements were made while the residential units were fired at two different
operating conditions or types of runs, as follows:

            1.  Cyclic Runs  -  Measurements  were made during repeated cycles  of 10
               minutes on/20 minutes off.

            2.  Varied-Air Runs - Measurements were made during steady-state operation
               for a range of excess air-settings and plotted against CO2  using procedures
               similar to ASTM D2157-656.
 6  "Standard Method of Test for Effect of Air Supply on Smoke Density in Burning Distillate Fuel" ASTM
    D2157-65(70).

-------
Oily
                 As found, Phase I
                 As found, Phase n
                 Tuned, Phase I
                 Tuned, Phase TJ
                                                oooo
                                          000
                                     OAO
                 , AA
                         ooooo
   0~     "20          40         60        80         lOO
   Percent of Units With Smoke Less Than or Equal to Stated Value
                                                                       o
                                                                       u
                                                                           0
                    Legend
               As  found,  Phase
               As  found,  Phase
               Tuned,  Phase I
               Tuned,  Phase TJ
                                                                                                            AOA
                                                                                                          >O.A*
                                                                                         A. °,2 20
                                                                                      _L
                                  I
"0         20         40         60         80         100
  Percent of Units  With COj Equal  to or Greater Than  Stated  Value
                     Figure II-2.  Distribution of Smoke and CO2. Levels as Measured in As-Found and
                                   Tuned Residential Units for Phases I and II

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                                            II-8

 Measurements of gaseous emissions and smoke were made for both cyclic and varied-air runs for
 the  as-found, A, tuned,  T, and reference-fuel, R, conditions. Particulate emission measurements
 were limited to cyclic runs.


       Selection  of Operating  Cycle. The same  operating  cycle  was used  for cyclic  runs in
 residential units  during  Phase  II as was used during Phase  I to provide a consistent operating
 mode for emission measurements. The cycle, 10 minutes on and 20 minutes off, was based on the
 following criteria:

             1. Emission data from different units could be compared on a common basis
               independent of the effects of outdoor weather on operating modes.

             2. The  field program would  not be seriously delayed  or  limited by warm
               weather  during  the normal heating season. (Normal  operation  during
               warm weather produces very infrequent firing.)

             3. Multiple  cycles  of controlled  operation  would allow  the  burner and
               combustion chamher to reach a repeatable  thermal condition.

            4. The  on-period  would be  much longer than the response time of  the
               monitoring equipment and  long  enough  to  allow  gaseous emissions to
               reach equilibrium values.

            5. A 10-minute on-time  is  longer  than  will be   encountered  with direct
               burner control  by a modern heat-anticipating room  thermostat, where 5
               cycles per hour at 50 percent on-time is the design basis but may be
               shorter than  encountered  for  a hydronic  system controlled by  the tem-
               perature  of a water circuit  or  by  steam pressure. A choice of 10 minutes
               is a reasonable compromise.

            6.  The  1/3  operating  time  or "load"  of the 10-minutes-on/20-minutes-off
               cycle represents a reasonable average load condition during the colder part
               of a heating season.

       The 10-minutes-on/20-minutes-off cycle is equivalent  to  2 cycles per hour at 33  percent
 on-time.  This cycle is typical of the average recorded for four units observed during a period of
 5  months  during the 1971-1972 heating  season. The  operational data for these four units are
 presented under "Measurements on Follow-Up Units" (page H-36).

       A limited investigation was made of the effect of cycle  length on emissions. These data
 are reported under "Experiments on the Effect of Cycle" (page 11-40).
       Varied-Air Operation, Gaseous emissions and smoke were measured at each of the three
burner conditions (A, _T, and R), while the excess air  level  was decreased  from the full-open
setting to a setting  producing about a No.  6  or 7 smoke. These data are intended  to  provide
information about the sensitivity  of emissions from the burners as related  to excess-air adjust-
ments in each  burner condition.

       The procedure for the varied-air runs was similar to  ASTM D2157-65(70)6.    Steps were
as follows:

-------
                                           II-9

            1. The burner air gate was set  at the full-open position  and emissions were
              measured.

            2. The air gate was closed and smoke was monitored until the knuckle of the
              smoke  curve  was reached (the point at which  smoke increased  sharply
              with small decreases in excess air), then emissions were measured.

            3. Emissions  were measured at several  points between  Points 1 and 2 by
              setting the air gate at intermediate positions.

            4. The air gate  was  closed  until a No.  5 to 7  smoke was obtained and
              emissions were measured.

            5. Emissions  were measured at  one ,or more points between Points 2 and 4.

Emissions were  measured at  about  six points for  each burner condition. Measurements were
made after  the  furnace had  been  firing for at least 30 minutes and had operated  at the test
condition for at  least  10 minutes or after the gaseous emission readings became constant.
       -Follow-Up Measurements. Follow-up  measurements were made on four residential units.
Three sets of measurements were made for these units at the following times:

                             Initial visit         — mid-December
                             1st follow-up visit  — mid-February
                             2nd follow-up  visit — late April.

The complete set of measurements, including gaseous and particulate emissions for the A, T, and
R conditions,  were made during the  initial visit.  For the  1st  follow-up visit, only gaseous
emissions were measured (firing both house  and reference fuels). During the 2nd follow-up visit,
gaseous emissions were measured  for house  and reference fuels and particulate emissions were
measured for the  reference  fuel  only. All  follow-up  measurements were made during cyclic
operation of the unit.
Emission Measurements — Instruments and Techniques

       Prior to measurements  in  the field, all the equipment and instruments required for the
investigation were standardized and checked  out in several runs on a residential oil-fired furnace
at Battelle-Columbus. Samp ling procedures and test sequences were also checked out at this time.

       An  established  set  of; operational  procedures was  routinely  followed  for each unit
investigated. Stack gases were sampled and supplied directly to continuous monitoring equipment
set up alongside the heating  unit.
       Gaseous  Emissions. Measurements were made  of  the  following gaseous emissions under
various  conditions of operation using the methods noted as follows (Details of instrumentation
and procedures for measuring gaseous emissions are described in Appendix E.):

-------
                                           11-10

                    Emission                       Measurement Method
              C02	NDIR (nondispersive infrared) and
                                              Fyrite

              O2	Amperometric and Fyrite

              CO	NDIR

              Hydrocarbons (total) ....  Flame ionization
              NOX   	Dry electrochemical (used for initial and
                                              1st follow-up visits)
                                             NDIR with converter (used for 2nd
                                              follow-up visit)

              NO	NDIR

       Smoke and Other Combustion Parameters. Smoke  was measured using the Bacharach
hand  pump smoke meter and the standard procedures adopted  by  ASTM7.    In  addition  to
these  measurements, other combustion conditions were measured, including

            • Firing rate, measured volumetrically

            • Stack  temperature,  measured in  the  flue at the  particulate   sampling
              location

            • Stack draft, measured in the  flue at the particulate sampling location.

       Particulate Emissions. Particulate emissions  were sampled using the EPA sampling .rig2-8.
This train is described in Appendix F. A special feature of this sampling  train is the  inclusion  of
two water impingers or bubblers (in an ice bath) downstream from the filter. The impingers were
originally  intended to collect any  condensable material (at 70 F) that would  exist as  vapor  at
filter  temperature and, thus,  pass  through  the filter and  also collect any solid particulate that
passes through the  filter. Later,  EPA abandoned  use of the impinger catch  in  determining
particulate  emissions  for stationary sources8  as  there was  indication that reactions  occur  in
the impinger to generate material that  is included in the weight measurement of particulate, even
though.the material does not exist as  particulate either in the flue gas or in the atmosphere9.

       To  insure that  the  most  meaningful  information was  obtained  from  the particulate
samples collected on this investigation, the  probe  wash, the filter catch, and the impinger wash
were  treated separately and particulate weights were recorded on each. In this report, particulate
data are reported as filterable (including the probe and filter catches) and total (combining the
filterable and the material found in the water impingers). However, it should be pointed out that
even the filterable catch obtained  using the EPA sampling train may not be directly comparable
to the particulate  catch obtained using other sampling  trains because of differences  in the
procedures for washing the probes  and  differences in sampling rates and volumes.
    "Standard Method of Test for Smoke Density in the Flue Gases from Distillate Fuels", ASTM D2156-65(70).
 o
    "Standards of Performance for New Stationary Sources", Federal Register Vol  36  No 139 Part II pp 15704-
    15722, August 17, 1971.
 9
    "Standards of Performance for New Stationary Sources", Federal Register, Vol. 37, No. 55, Part 1 pp 5767
    March 21, 1972.

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                                           II-11

       Previous  experience  at Battelle  suggests that acetone  washing may not be  adequate to
remove all particulate  from the probe.  Therefore, for this investigation two washing procedures
were used: (1) the EPA procedure and (2) a modified EPA procedure referred to as the MEPA
procedure  in  this report.  First,  the probe,  filter holder,  and  impingers  were washed using
procedures specified by EPA. Then the modified procedure was used wherein additional washings
were made  to insure  complete  removal of deposited particulate. The complete procedures  and
the resulting data are discussed further in Appendix F.
       Timing of Measurements for Cyclic  Runs.  Measurements of gaseous emissions were made
continuously over the  10-minute-on period of the cycle. Special tests of the response of the
sampling  system and  instruments to step changes  in  pollutant  concentrations showed a 90
percent response in less than  72 seconds  for all gaseous pollutants. All emission  factors were
based  on time-average values over the  10-minute-on  period, including peaks at starting but  not
including peaks at shutdown  —  when  the combustion  air flow  would be diminished  and  the
measured concentrations would not be meaningful.

       Bacharach smoke  measurements  were made at three points in the firing cycle:  at 1, 5,
and 9 minutes. The smoke numbers used in this  report are generally for  the 9-minutc point in
the  cycle, as  this  is  most  typical of the smoke that  servicemen  would normally  measure.*
However, in  the statistical comparisons including Phase I data the 5-minute smoke data are used,
as only that data were obtained on all Phase I units.

       Particulate sampling was conducted  during the 10-minutc-on period of the burner for six
consecutive cycles  beginning with  the  second cycle. The particulate  sampler  was started just
before burner start-up  and continued to just beyond shutdown for each cycle.
       Emission  Transients During  Cyclic Huns,  Figure  II-3 shows  typical profiles of gaseous
emission transients during cyclic  operation of residential oil burners. Peaks are generally  noted
for CO  and HC  at  starting  and shutdown  when  there is transient imbalance of the fuel-air
mixture  or flame temperatures are  low. For most  units, the HC  concentration in the flue gas
(after the start-up peak) was less than the ambient HC concentration. For NOX there is some lag
in sampling  and  NDIR analysis on  starting, but  the gradual rise in NOX  is more  likely due to
combustion chamber warm-up.

       Smoke  at starting and shutdown  follows a  similar transient effect as does CO and HC. On
ignition, an instantaneous over-rich  condition can occur which is compounded by  the fact that
fuel nozzle  delivery  rate is  generally  highest;  the nozzle is  relatively cool on starting. On
shutdown, a smoke puff can occur  if the fuel pump cut-off is not prompt. Smoke transients at
both start-up and shutdown tend to  vary widely from unit to unit.
       Emission  Data Used for Calculating Emission Factors, Emission factors  reported for the
cyclic  runs  of Phase II are the dose average for all gaseous pollutants. The dose average values
were obtained by dividing the integrated area under the  emission curve by the  cycle "on"-time.
*ASTM Standard D2157-65(70), "Standard Method of Test for Effect of Air Supply on Smoke Density in Burn-
 ing Distillate Fuels", states that the burner should operate for 15 minutes before the smoke measurements are
 begun.

-------
                                     11-12
o
o
CO
o
_c
O

O
O
                      CO
     Burner

      on time
o
o
cn
o
.c
O
                          CO,
      Burner-
      "on" time
 8
co
 o
J=
CJ
 o
jQ
                      HC
     Burner
     "on" time
o
CO

,    J
i_
o

o

 x
O
                            N0>
      Burner

      on  lime
                     Time
                      Time
      Figure II-3.  Typical Gaseous-Emission Profiles of Residential Units During
                  10-Minutes-On/20-Minutes-Off Cyclic Operation

-------
                                            11-13

       For  the Phase  I  study1,  lOth-minute readings were used for  data summaries  and for
calculating NOX  emission factors,  because the NOX monitors had slow response. However, the
response of the instruments used  for Phase II is sufficiently rapid  so that dose average  readings
are considered more representative of the  overall cyclic  operation. NOX  emission  factors for
Phase  I  units summarized  in  this  report  were  corrected to  the dose  average value  (from
lOth-minute  data)  by multiplying the lOth-minute data by the ratio  of dose average  data to
lOth-minute data obtained on Phase II units (about 0.96).
EMISSION RESULTS FOR CYCLIC RUNS

       The following section contains results.of emission and smoke measurements during cyclic
operation of residential units. Emission  data are compared for different burner conditions  and
burner and installation  design  features. Results of measurements during  cyclic runs on the four
follow-up units  are summarized to show the effect on emissions of operating time since  tuning.
In addition, the results of laboratory  experiments on the effect  of cycle on smoke and gaseous
emissions are presented.
Summary of Emission Data and Emission Factors

       Table  II-3 provides a comprehensive summary of emission measurements for the cyclic
runs  on the  13 residential units in Phase  II.* This table includes operational data defining
conditions,  measured  gaseous emissions in ppm, particulate loading, and  calculated emission
factors based on fuel input (Ib of pollutant per 1000 gallons of fuel).
Effect of Tuning and Fuel
        Tuning.  Table II-4  summarizes the tuning of the  12 Phase II field units,  showing the
changes in smoke, CO2, and efficiency and showing qualitative effects on emissions.

        All units were'tuned to a smoke level below 2.0, with the average  smoke reduced  from
1.5 to 0.6. Smoke was reduced for 6 of the 12 units; for  another three units,  smoke was increased
less than  0.5 while increasing CO2  for higher efficiency; CO2 was increased for nine units, with
the average shifting from  7.9 to 8.5 percent.

        Tuning  of the residential  units generally produced  an increase in unit efficiency**. The
average incremental  increase in  unit efficiency was 1.7 percent, with the efficiency increasing for
seven units,  decreasing for three  units,  and remaining essentially  unchanged for two  units. The
range  of   the  incremental  change  in efficiency  was from  +8.8  percent to -3.9  percent. An
incremental increase  in efficiency of 1.7  percent would reduce fuel  consumption by about 2.4
percent; hence, emissions  would be reduced by the same amount.
 *Follow-up measurements for Units 23 through. 26 are included separately in Table 11-10.
**Although the flue gas temperature was not measured at the breeching, as should be done for efficiency calcula-
  tions, approximate efficiency calculations were made using the gas temperature at the particulate sampling point.

-------
                                                                        11-14
                            Table 11-3.  Summary of Emissions end Emission Factors for Cyclic Runs - Phase 11 Residential Units
Unit and
Condition*
23
24


26


26


27


28


29


30


31


32


33


34


35

A
T
R
A
T
R
A
r
R
A
T
R
A
T
R
A
T
R
A
T
R
A
T
R
A
T
R
A
T
R
A
T'
R
A
T
R
T
R
C02.
9.2
9.9
9.4
7.1
8.9
9.2
9.4
9.4
8.5
7.1
8.7
8.8
9.1
8.2
8.1
6.6
7.4
7.7
9.4
7,9
7,7
7.5
7.1
6.9
7.9
9.9
9.6
7.0
8.7
8.6
6.1
6.5
6.6
9.4
9.8
10.1
8.8
93
°2.
%
9.1
7.8
8.2
12.0
9.0
8.5
9.0
7.3
8.3
11.1
9.1
8.8
B.I
9.4
9.5
11.9
10.3
9.8
7.1
9.7
9,1
10.3
11.1
11.4
10.B
7.9
8.0
11.4
9.4
9.3
12.6
12.2
12.1
7.4
8.0
7.3
8.7
7.5
Excess
Air.%
68
54
60
120
71
64
75
56
72
109
73
70
64
81
82
126
97
89
55
36
83
95
108
114
94
56
58
114
76
75
143
131
127
55
55
50
70
57
Smoke No.
at9Min
0.3
0.5
0.4
0.4
0.7
0,8
1.0
1.7
2.0
0.5
0.4
0.6
1.0
0.4
0.3
1.3
0.4
0.4
9.0
0.5
0.3
0,2
0.6
0.3
0.0
0.2
0.3
0.2
O.I
0.1
Oily
Oily
Oily
•2,1
1,0
1 9
02
0.2
Slack
Temperature,
°Fb
470
480
480
645
525
520
490
450
455
520
500
490
5SO
620
-
540
650
-
3/0
440
-
570
470
-
530
535
-
545
500
-
700
690
-
440
460
-
440
440
Firing
Rate,
gph
1.20
1.30
1.04
_
0.86
1,36
„
1.40
1.78
_
1.80
1.26
_
1.38
0.90
_
1.40
0.75
_
0.74
1.10
-
0.70
1.37
-
1.50
0.98
-
1.00
0.85

O.S5
0.60
~
070
0.99
0.99
Emiuion Data at 02 Level,
dose average ppm
CO
3.7
7.7
2.6
222.0
4.1
9.5
10.6
8.6
12.1
5.5
fl.O
10.7
11.6
12,5
11.1
162.0
8.6
3.9
24.7
12.3
13.6
11.7
>170.0
>200.0
36,1
64
47
2920
90,0
44,0
>1240.0
>1240X)
>1 240.0
19.6
14. B
18.2
2.5
3.8
HC
8.3
5.7
13
122
3.1
US
5.4
5.9
5.7
b.l
4.0
4.4
3.3
4.4
7.3
13.1
1.8
4.7
4.4
4.2
25.0
8.2
9.4
10.7
3,8
'2.4
2.4
12,6
2,8
4,2
_
221,0
166,0
5.4
3.9
5.1
5.5
9.6
NO
67
82
75
39
71
69
42
47
44
54
68
67
S6
58
62
31
60
61
31
63
64
63
44
37
61
83
85
31
63
62
9
20
22
62
58
63
77
84
NOX
35
89
79
78
7S
71
53
47
49
64
71
72
86
78
69
79
62
76
83
66
74
79
65
58
68
87
89
73
69
67
87
105
97
62
5G
62
85
91
Particular
Loading,
mg/sm3 e
Filterable
10.7
7.2
6.4
6.1
19.0
18.8
5.7
7.4
7.9
11.1
9.1
10,7
17.0
12.3
-
14.7
7.1
-
31.1
43.9
-
9.6
13.1
-
8.5
15.1
-
9.3
13.7
-
24.3
25.3
-
22.3
14.5
-'
17,7
13,7
Total
20.5
26.0
20.5
15.4
47.6
32.2
25.0
19.4
17.7
33.2
17.6
21.4
39,7
26.1
-
49.0
22.3
-
89.7
64.8
-
34.2
35.9
-
342
74,1
-
468
41,4
-
113.
119.
-
48.7
41.2
-
69 a
4.1.6
Emission Factors, lb/1000 gal
CO
0.61
1.17
0.41
42.28
0.69
1.53
1.83
1.32
2 05
1.13
1.02
1.78
1.39
2.26
1.98
31.6
1.68
1,65
3.78
2.26
2.43
2.26
>32.8
?38.5
6.97
1.00
0.73
62.63
15.84
7 57
>301.0
>285.0
>277 .0
2.96
2,24
2.68
0.42
0.59
HC
0,79
0.50
0.29
1.52
0.30
0.42
0.53
0.52
055
0.60
0.39
0.42
0.31
0.46
0.75
1.68
0.20
0.50
0.39
0.44
2.58
0.91
1.11
1.29
0.42
0.21
0.21
1,54
0,28
0,41
_
27 72
21.23
0,47
0,34
043
053
085
NO,
as NO2
231
22.2
205
27,9,
21.1
188
15.9
11.8
13.7
21.6
19.9
197
23.0
23.1
20.2
29.0
19.9
23.2
20 9
19.6
21.9
25.0
22.0
20.1
21.6
22.2
22,7
25.7
20.0
13.9
34.6
39.6
35.6
15.4
14,4
15.3
23.3
23.1
Paniculate0
Filterable Total
1.55
0.93
088
1.17
2.82
2,64
0.83
0.97
116
1.96
1.35
1,55
2.40
2.02
-
287
1 19
-
4 12
703

1 6?
2.37

1.43
2.04
-
1.80
2.13
-
5.12
5.04
-
2.94
1.9'.

2. 56
1.34
2.94
3.44
2.82
2.93
7.02
453
3.73
2.57
2,61
5.97
2.61
311
5.65
4.09
~
8.41
3.79
-
11 96
10.32
-
572
6.42

5 77
10.04

8 69
6.34

23.92
23.76

6.37
6.40
-
10.05
5.89
3 Units are described in Table 11-2.
bTemperalure measured at sampling point near end of lO-minuta-on period.
c Modified EPA procedure.

-------
         Table 11-4. Qualitative Summary of Tuning Effects on Emissions From Residential Units — Phase II Units
Smoke Number,
9th minute
Unit
23
24
25
26
27
28
29
30
31
32
33
34
As Found
0.3
0.4
1.0
0.5
1.0
1.3
9.0
0.2
0.0
0.2
Oily
2.7
Tuned
0.5
0.7
1.7
0.4
0.4
0.4
0.5
0.6
0.2
0.1
Oily
1.0
CO2,
percent
As Found Tuned
9.2
7.1
8.4
7.1
9.1
6.6
9.4
7.5
7.9
7.0
6.1
9.4
9.9
8.9
9.4
8.7
8.2
7.4
7.9
7.1
9.9
8.7
6.5
9.8
Change in Pollutant Emission Factor3
Incremental Change Particulate
in Efficiency, % CO HC NOX Filterable Total
+0.6 + +
+8.8 - + +
+2.6 + +
+3.1 + - +
-2.6 + +
-1.7 b
-3.9 - +
0 b + - +
+2.9 - - + + +
+4.3 - + -
+6.3 c b +
+0.1 -
+ and — indicate an increase or decrease exceeding 5 percent.
Change in emission factor not available due to absence of one measurement.
Change in emission not measureable; both values exceeded instrument range.

-------
                                   Table 11-5. Mean Emission Factors and Standard Deviations, for Cyclic Runs - Phases I and II
Emission Factors, lb/1000 gal
Units
All Units








All Unus
Except Those
in Need of
Replacement11






Condition Phase
A 1
II
1+ II
T 1
II
1 + II
R 1
II
1 + II
A 1
II
1 + II

T 1
II
1 + II
R 1
II
1 + II
Numbei
of Units
in
Sample
20
12
32
20
13
33
20
13
33
18
11
29

18
12
30
18
12
30
Bacharacha
Smoke No.
Mean
b
b
b
b
b
b
b
b
b
4.2
1.4
3.2

1.8
0.7
1.3
1.2
0.6
0.9
S.D.
b
b
b
b
b
b
b
b
b
2.2
2.4
2.6

1.0
0.5
1.0
0.6
0.6
0.6
Gaseous Emissions
CO
Mean
>11.9
>39.1
>22.1
> 9.1
>26.9
>16.4
> 8.8
>26.4
>15.7
3.2
153
7.8

3.5
>5.4
4.3
3.5
>5.5
4.3
S.D.
>27.8
>85.1
>56.8
>18.7
>78.1
>51.4
>17.3
>76.2
>49.3
4.5
22.5
15.2

5.2
>10.2
7.6
4.5
>11.8
8.1
HC
Mean
8.4
0.8C
5.7
3.3
2.5
3.0
1.8
2.3
2.0
0.65
0.83
0.72

0.67
0.44
0.57
0.85
0.73
0.80
S.D.
26.1
0.5
21.1
11.2
7.6
9.7
2.8
5.7
4.2
0.40
0.51
0.45

0.42
0.24
0.37
0.59
0.65
0.61
N0x(as
Mean
16.9
23.6
19.4
18.2
21.5
19.5
18,5
21.1
19.6
17.7
22.6
19.6

19.1
20.0
19.5
19.3
19.8
19.5
N02)
S.D.
4.3
5.4
5.7
4.7
6.4
5.6
4.6
5.2
4.9
3.3
4.3
4.4

3.6
3.5
3.5
4.0
3.0
3.6
Participate Emissions
EPA Procedure Modified EPA Procedure
Filterable Total Filterable
Mean S.D. Mean S.D. Mean
3.4
1.4 0.9 6.8 5.9 2.3
2.9
j_ _ _ 	 22
1.5 1.5 6.3 5.4 25
2.3
_____
_ _ _ _ -
_
2.7
1,2 0.7 5.2 2.5 2.1
2.4

2.2
1.4 1.5 50 2.8 2.3
2.2
	 	 	 _ 	
_____
— _ _ _ _
S.D.
4.0
1.3
3.1
1.7
1.7
1.7
_
-
-
3.0
1.0
1.3

1.7
1.6
1.6
_
_
~
Total
Mean
9.6
7.7
8.9
7.1
7.4
7.2
_
-
—
5.9
6.2
6,0

5.4
6.0
5.7
	
_
~
S.D.
12.3
5.7
10.2
6.8
5.6
6.2
_
-
-
3.2
2.7
3.0

2.3
2.9
2.5
_
-
~
3 Smoke data at 5-minute point.
b Oily smoke spots prevented obtaining meaningful averages.
c Value  low because no data were obtained for HC emissions from Unit 33 in Condition A.
d Units not included were Units 5, 20, and 33.

-------
                                            11-17

       The  effects of  tuning on the gaseous  emissions  were generally inconsistent. Tuning
reduced  CO, HC,  and  NOX  emissions for  about one-half of the units. Total particulate was
reduced  for eight units, but  filterable particulate was reduced for only six units.

       Both before and after tuning, raw oil was found on the smoke spot for Unit 33. Also,
this unit operated  with CO  in  excess  of the instrument scale limit  of 1240  ppm and with
extremely  high HC. Hence, this  unit  is  considered  to be  in  need of replacement or major
renovation and would  be so  identified by competent servicemen.  Because of the  distortion  of
average  emissions by the data from this unit,  these data are omitted from data  summaries and
statistical tabulations where  equipment  features are examined.  (This procedure was also followed
in Phase I, where 2  of the 20 units were identified to need replacement.)

       Table II-5 provides  a  comparison  of average emissions for Phase I and  II units in the
as-found and tuned condition. Separate summaries are presented showing (1) all units and (2)  all
units except those in need of replacement  or renovation (identified by the presence  of oil on the
smoke spots). Table II-6 shows the percentage reduction in emissions  obtained by (1)  replace-
ment of poor units and  (2) replacement of poor  units plus tuning of remaining units.* A large
reduction in average emissions of  CO, HC, and particulate is observed when the poorly perform-
ing  units are  eliminated from the  data.  Although  some  shifts are  noted with tuning  of the
remaining units, the overall  effect on emissions of tuning these units is  considered minor except
for smoke.
                        Table 11-6. Reduction of Mean Emissions Upon
                                   Replacement and Tuning of
                                   Residential Units

                                             Replacement      Replacement
                                                Only           Plus Tuning
Smoke
CO
HC
NOX
Filterable Particulateb
Total Partial lateb
_a
>65%
87%
No change
17%
33%
59%
>81%
90%
No change
24%
36%
                        Not meaningful, as smoke spots of units eliminated were identified
                        as "oily" and not evaluated numerically.
                        By modified EPA procedure.
       Fuel. Table  II-5 also shows  average emissions for the reference fuel runs. (Insufficient
particulate measurements  were  included  for  the reference  fuel runs  to  make  comparisons of
particulate emissions meaningful.) Only slight  shifts are noted by comparing the  averages for the
tuned  runs and reference fuel  runs. Thus,  the effect on emissions  of differences between the
house fuels and the reference fuel is considered minor.
* Values are based on the ctistribution of "poor" units found in the Phase I and II studies; that is, 3 poor units in
 a total sample of 32 oil-fired units.

-------
                                          11-18

Comparison of Emissions for Different
Equipment Features

       In order  to  determine whether  certain features of burner design  or of installation type
have an important  bearing on emissions characteristics,  several  comparisons were made using the
cyclic runs for Phase I and Phase II as the basis.

       The following tables show comparisons of mean emissions from gun-burner units  (excluding
units in  need  of replacement)  by equipment categories normally  of  interest  to the  oil-heating
industry:

            Table 11-7.   Matched Units Versus Conversion Units

            Table II-8.   Furnaces Versus Boilers

            Table 11-9.   Conventional Versus Flame-Retention  Combustion Heads

            Table 11-10.  Effect of Burner Age.

Pertinent  observations regarding each comparison  are noted below, especially for  the tuned or
reference runs.*
       Matched Units Versus Conversion Units. A matched unit is defined as a burner-furnace or
burner-boiler unit that is factory matched and  supplied as a combination, whereas a conversion
burner refers  to a furnace or boiler  installation  incorporating a burner other  than the model
supplied  by the factory. The comparison in Table 11-7 shows that the smoke  from matched units
was lower than from conversion units for the as-found condition (2.9 versus 3.7), but not for the
tuned condition. Conversion units had lower CO  emissions  for all conditions but had higher HC
emissions for  the tuned and reference-fuel conditions. Particulate emissions were  not significantly
different for the two types  of units.
       •Furnaces  Versus Boilers, Table II-8  shows that furnaces operated at slightly lower smoke
levels  than  boilers.  Conversely,  mean  CO  and particulate emissions for the 11  furnaces  were
consistently and  appreciably higher than for the 16 boilers; however, the mean CO levels for the
furnaces are not  considered excessive. The  higher CO level with furnaces is surprising, in view of
higher combustion chamber temperatures generally expected  for furnaces.  Mean NOX emissions
for the furnaces  were slightly but consistently higher than for the boilers. The higher NOX  levels
with furnaces probably reflects the higher combustion chamber temperatures.
       Conventional  Versus Flame-Retention Combustion Heads. The comparisons in Table 11-9
indicate higher mean emissions of smoke, CO, HC, and filterable particulate for the 16 burners
having conventional combustion  heads than for the eight burners having flame-retention heads.
Although  the  conventional burners showed the largest reduction in smoke upon tuning (from 3.7
to 1.2), filterable and total particulate emissions from these units showed only  a slight reduction
from the tuning. The three Shell head burners  had emissions similar to those of the flame-retention
heads.
*Particulate measurements for the reference-fuel condition were only done on the four follow-up units in Phase
 II; thus, particulate data from reference runs are not included in statistical tabulations.

-------
    Table 11-7.  Mean Emission Factors and Standard Deviations for Matched Units and Conversion Units for
                 Cyclic Runs, Phase 1 and !l Units3
Bacharach
Unit Type
and
Condition

Matched A
T
R

Conversion A
T
R
Number of
Units in
Sam pie

21
22
22

7
7
7
Smoke No.
at 5
Mean

2.Q
1.2
0.9

3.7
1.5
1.0
Win
S.D.

2.6
0.9
0.6

3.2
0.9
0.6
Emission Factors, lb/1000 gai
Gaseous Emissions
CO HC
Mean

9.8
4.4
4.3

1.0
2.9
3.3
S.D. Mean
Units
17.3 0.69
8.2 0.47
9.1 0.72
Units
0.8 0.65
5.8 0.75
4.4 0.90
S.D.

0.45
0.26
0.53

0.25
0.36
0.72
NGx(asPJO2)
Mean

20.1
19.5
19.7

19.0
20.2
20.1
S.D.

4.7
3.5
3.3

3.0
2.8
3.3
Particulate
Filterable
Mean S.D.

2.4 2.7
2.2 1.5
-

2.4 1.2
2.4 2.6
- —
Emissions12
Totai
Mean

6.4
5.8
-

5.1
5.6
-
S.D.

3.4
2.5
-

1.5
3.0
—
Excluding units in need of replacement.
Particulate by modified EPA procedure.

-------
      Table 11-8.  Mean Emission Factors and  Standard Deviations for Furnaces and Boilers for Cyclic Runs,
                  Phase I and II Units3
Bacharach
Unit Type
and
Condition
Number of
Units in
Sample
Smoke No.
at 5
Mean
Min
S.D.
Emission Factors, lb/1000 gal
Gaseous Emissions
CO
Mean
S.D.
HC
Mean
S.D.
Particulate Emissions^
NOX (as NO2) Filterable
Mean
S.D. Mean S.D.
Total
Mean S.D.
Furnaces
Furnaces A
T
R
11
12
12
2.7
1.0
0.8
3.0
0.8
C.6
17.2
8.5
7.9
21.5
10.7
11.7
0.86
0.43
0.83
0.52
0.25
0.66
22.6
20.5
20.5
4.1 3.4 3.6
2.8 2.6 1.8
2.4
7.2 3.5
6.8 2.6
-
Boilers
Boilers A
T
R
17
17
17
3.4
1.4
0.9
2.6
0.9
0.6
1.4
1.1
1.4
2.7
1.2
1.6
0.56
0.46
0.71
0.27
0.33
0.53
18.0
19.2
19.3
3.4 1.8 1.0
3.6 1.9 1.6
37 — —
5.3 2.5
4.9 2.3
— —
Excluding units in need of replacement.
Particulate by modified EPA procedure.
                                                                                                                                   to

-------
     Table 11-9.  Mean Emission Factors and Standard Deviations for Burners With Various Combustion-Head  Designs for
                  Cyclic Runs, Phase I and II Units3
Bacharach

Combustion
Head
Conventional
Shell
Flame retention
Conventional
Shell
Flame retention
Conventional
Shell
Flame retention


Condition
A
A
A
T
T
T
R
R
R
Number of
Units in
Sample
17
3
8
18
3
8
18
3
8
Smoke No.
at 5
Mean
3.7
2.8
2.1
1.3
1.7
1.0
0.9
1.0
0.8
Min
S.D.
3.0
2.9
1.9
o.g
1.2
0.6
0.6
0.6
0.6
Emission Factors, lb/1000 gal
Gaseous Emissions
CO
Mean
9.9
0.9
5.3
5.9
0.9
1.1
5.8
1.6
1.1
S.D.
17.7
0.9
12.5
9.3
0.8
0.9
10.0
0.3
0.7
HC
Mean
0.70
0.69
0.63
0.59
0.60
0.39
0.84
0.81
0.54
S.D.
0.42
0.12
0.48
0.33
G
0.18
0.69
0.39
0.18

NOX (as N02)
Mean
19.8
18.9
20.2
20.7
18.3
18.1
20.3
19.2
18.8
S.D.
4.2
3.8
5.0
2.9
3.1
3.8
3.4
4.0
2.9



Particulate Emissions0
Filterable
Mean
2.9
2.3
1.6
2.8
1.3
1.3
	
—
—
S.D.
3.1
0.6
0.8
1.9
c
0.6
	
—
—
Total
Mean
6.7
5.5
4.9
6.8
2.6d
3.9
	
—
—
S.D.
3.3
1.0
2.7
2.4
c
1.6
	
—
—
 Excluding units in need of replacement.
1 Particulate by modified EPA procedure.
 Less than three data available — standard deviation not meaningful.
 Based on only one data point.
                                                                                                                                                I
                                                                                                                                               to

-------
             Table 11-10. Mean  Emission  Factors and Standard Deviations by Burner Age, Phase I and II Units3
Bacharach
Number of Smoke No.
Burner Age,
years Condition
Units in
Sample
at 5
Mean
Min
S.D.
CO
Mean
Emission Factors, lb/1000 gal
Gaseous Emissions
HC
S.D.
Mean
S.D.
NOX (as NO2)
Mean
S.D.
Particulate Emissions13
Filterable Total
Mean S.D. Mean
S.D.
5-Year Cut
<5 A
>5 A
<5 T
>5 T
<5 R
^5 R

<15 A
>15 A
<15 T
>15 T
<15 R
>15 R
16
12
17
12
17
12

22
6
23
6
23
6
3.0
3.3
1.1
1.5
0.8
1.0

2.8
4.4
1.3
1.2
0.9
0.8
2.5
2.7
0.8
0.6
0.5
0.5

2.2
4.0
0.3
0.7
0.5
0.6
11.7
2.2
2.8
5.6
2.6
6.1
^ 5-Year
9.0
2.7
2.6
9.1
2.4
10.6
19.6
1.6
4.8
9.5
3.4
10.8
Cut
16.6
2.0
4.1
14.0
3.0
15.8
0.84
0.47
0.51
0.57
0.68
0.87

0.71
0.56
0.47
0.75
0.62
1.28
0.44
0.16
0.25
0.25
0.32
0.47

0.37
0.21
0.21
0.36
0.29
0.65
20.0
19.6
19.7
19.8
19.3
20.5

19.7
20.1
19.3
21.4
19.4
21.4
5.0
3.2
3.6
2.3
2.9
3.5

4.6
3.1
3.4
1.6
3.3
2.1
2.4 2.8 6.2
2.4 1.3 5.8
1.8 1.0 5.2
2.9 1.9 6.4
	 	 	
- — -

2.3 2.6 5.9
2.6 1.5 6.6
1.8 0.9 5.0
3.7 2.5 8.1
	 „_ _
— — —
3.6
1.9
2.5
1.7
	
-

3.1
2.6
2.2
2.2
_
—
Excluding units in need of replacement.
Paniculate by modified EPA procedure.

-------
                                          11-23

       Effect of Burner Age. Table II-10 summarizes emission by burner age. for two age cuts:  5
and  15  years. For the 5-year cut, it  compares mean emissions for 17 burners less than 5 years
old with 12  burners 5 years old or older. For the 15-year cut, it compares 23 burners less than
15 years old  with  6 burners 15  years  old  or older. Smoke was  consistently  lower for newer
burners, considering the 5-year cut; for  the  15-year cut, newer burners had lower smoke for the
as-found condition  only. For the  tuned  condition, mean CO and  particulate levels of the newer
burners were  consistently and appreciably less. Conversely, for the as-found condition, CO was
lower for the older burners. Mean HC emissions were generally lower for newer burners in the
tuned condition but higher for newer  burners in the as-found condition.
       Effect of Burner Age on Smoke and Particulate Emissions When Tuning. Figures II-4 and
II-5 show the change in smoke level, filterable particulate,  and total particulate upon tuning for
5-year increments  of burner  age. Table II-11 presents  the same data in the form of percent
reduction of  each of these emissions  for  the  tuned condition compared with  the as-found
condition.  These data show that tuning of the newer  burners  (those less  than  15  years old)
reduced  both smoke and  particulate emissions.  However, for the older burners (which showed
the greatest  reduction  in smoke),  the tuning  actually  resulted in art  increase  in particulate
emissions.
Statistical Ranking of Equipment
and  Fuel Variables

       In  addition  to  the statistical analysis of the data presented above, another statistical
treatment of the data was used to rank the influence of important variables on emissions.

       Basically, this technique  consists of separating the data into two sets for each variable
considered and then ranking the variables by the differences between the two sets. Where more than
one  division  of the data was possible (e.g., for continuous variables such as burner age), the data
are divided at  the point that  produces two sets with the maximum difference.  The sets of data
for each variable  are compared  primarily on  the basis  of mean values, but the calculation is
weighted by  the number of values in each set and the scatter of the data.

       The most  significant variables insofar as effecting the pollutant being considered  can  be
regarded as those that produce the largest differences when the  data are separated into two sets
on that variable.

       An analysis of this type was made on the emission data as follows:

            Emission Data

              Smoke
              CO
              HC
              NOX
              Filterable particulate (by modified EPA procedure)
              Total  particulate (by modified EPA  procedure)

-------
                         11-24
o
to
                 Condition
                   As  found
              II Tuned
         0-4       5-9       10-14     15-19       >ZO

                       Burner  Age, years

 Figure II-4.  Effect of Tuning on Smoke, by Burner Age
      Table 11-11.  Effect of Tuning on Smoke and
                   Particulate  Emissions, by Burner
                   Age
                                  •Change of Emissions
                                 Upon Tuning, percent3
Burner Age,
years
0-4
5-9
10-14
15-19
»20
Paniculate
No. of Units
17
2
4
4
2
Smoke
-64
-33
-18
-75
-69
Filterable
-24
-16
-29
+44
+43
Total
-16
-14
_ 7
+ 2
+82
  Minus indicates reduction of emission upon tuning; plus indicates an
       : in emissions upon tuning.

-------
                               11-25
         10
      en   6

      O
      o
     Q_
     "o   4
     I
      O)
                       Total  Particulate
                          As  found

                          Tuned
                       Filterable  Particulate
               0-4        5-9       10-14      15-19

                               Burner  Age, years
>20
Figure II-5. Effect of Tuning on Particulate Emissions by Burner Age

            Modified EPA Procedure.

-------
                                          11-26

           Conditions

              A — as found
              T - tuned
              R — reference runs
              A and T - together

           Variables

              Unit  type  - matched or conversion
              System type  —  furnace or boiler
              System age — by 5-year increments
              Burner type - conventional (CH), Shell head (SH), or flame-retention head
                (FRH)
              Burner age — by 5-year increments
              Firing  rate - by fixed increments, with breaks at 1.00, 1.35, 1.65, 2.00,
                and  3.00 gph
              Fuel API gravity - by  one degree API increments
              Condition - A  or T (this variable was only included  when all as-found and
                tuned data were considered together).

For this analysis the following units were not included:

           No. 21  and 22 —  These were gas-fired units.

           No. 19  and   20 — These were not gun burners,  and  the one of each type
              included  in  the  program was  not  considered sufficient  for  statistical
              analyses.

           No. 5,  20, and 33 — These were units in need of replacement, which would
              not reflect equipment and fuel variables properly.

           No, 35  for  Condition A - This was the lab  unit, which had no equivalent
              prior operation to define a normal "as-found" condition.

       Tables 11-12 through 11-15 list the results of the analyses described above for the A, T, R,
and A + T conditions, respectively. For each table and emission, the variables are listed in order
of their decreasing significance.

       A difficulty  is encountered in interpreting the results of this analysis for variables with
more  than two values, because the  analysis may split these  variables at different points when
considering the  different emissions.  For example, for  the as-found condition, the best split on
firing rate was at 1.35 gph for filterable particulate and at  1.00 gph for total particulate.
       As-Found  Conditions.  Table II-12 shows the  ranking  of variables in  terms of  their
significance in affecting emissions for the  as-found condition. Examination of this table permits
the following observations:

-------
                                           11-27

           • System  type and firing rate generally received  high  rankings as having  a
              major influence on most  emissions. Unit type  and system age generally
              ranked low.

           • The units having higher firing rates (with a split at 1.0 or 1.35 gph) had
              lower emissions of all pollutants except smoke.  The smoke data was split
              at 3.0 gph, with the smaller units outperforming  the two larger units.

           • High-turbulence combustion  heads  (flame-retention and Shell  heads)
              generally had lower emissions than conventional head burners. Exceptions
              to this  were NOX for flame-retention head units and HC for Shell head
              units.

           • Although  fuel  gravity appeared near the mid-point on each ranking (3rd,
              4th,  or  5th), the influence was varied. That is, lighter fuels (33.0 to 36.9
              API gravity) produced lower  smoke, CO, HC, and total particulate emis-
              sions, but  heavier fuels (30.0  to  32.9 API  gravity) produced lower NOX
              and  filterable particulate  emissions. Hence,  the overall influence  of fuel
              was interpreted as not  significant in affecting emissions  for units in the
              as-found condition.
       Tuned Condition.  Examination  of Table 11-13 showing the  ranking of variables for the
tuned condition shows that:

            • Burner age and system age generally appeared near the top of the lists as
              having the greatest influence on  emissions; unit type generally had a low
              influence on emissions.

            • Newer units (both burner age, and system age)  had lower emissions than
              older units. The  best splits on age  were at 10  years for smoke and 15
              years for other emissions.

            • High-turbulence  head  burners generally produced lower emissions than
              burners with  conventional  heads. However, smoke  emission from  Shell
              head  burners  was higher than from the conventional and flame-retention
              head burners.

            • Fuel gravity generally did not  have a high ranking and the  influence was
              varied. That is, units firing lower gravity fuels produced less smoke, CO,
              HC, and filterable particulate but more NOX  and total particulate.
       Reference Condition.  Table  11-14  showing the  ranking  of variables  for the reference
fuel runs (in the tuned condition) produced conclusions generally agreeing with  conclusions for
the tuned condition.
       Combined Data for the As-Found and Tuned Conditions. Table 11-15  shows the ranking
of variables when all  as-found and  tuned runs are combined and when unit condition (as-found

                                                             (Text continues on page 11-36.)

-------
                                11-28
Table 11-12. Statistical Ranking of Variables for the As-Found Condition
     Units for mean values and standard deviations are Ib/1000 gal.
Smoke
Variable Split
Firing Rate
<3.00 gph
>3.00 gph
System Age
<15 years
>15 years
Burner Type
FRH.SH
CH
Burner Age
<15 years
>1 5 years
Fuel Gravity
32.036.9
30.0-31.9
System Type
Furnace
Boiler
Unit Type
Matched
Conversion

Mean

2.9
6.3

2.6
4.3

2.3
3.7

2.8
4.4

2.6
3.9

2.7
3.4

2.9
3.7

S.D.

2.0
0.3

2.1
3.6

2.1
2.9

2.2
4.1

2.6
2.8

2.9
2.5

2.5
3.0
CO
Variable Split
System Type
Boiler
Furnace
Firing Rate
>1 .00 gph
<1.00gph
Burner Age
>5 years
<5 years
Fuel Gravity
33.0-36.9
30.0-32.9
System Age
>10 years
<10 years
Unit Type
Conversion
Matched
Burner Type
FRH.SH
CH

Mean

1.4
17.2

4.5
17.1

2.2
11.7

3.0
12.3

2.7
11.9

1.0
9.8

4.1
9.9

S.D.

2.6
20.5

10.5
21.9

1.9
19.0

3.4
20.9

4.9
20.2

0.7
16.9

10.7
17.2
HC
Variable Split
Burner Age
>5 years
<5 years
System Type
Boiler
Furnace
Fuel Gravity
33.0-36.9
30.0-32.9
Firing Rate
> 1.00 gph
<1.00gph
System Age
>10 years
<10 years
Burner Type
FRH
CH.SH
Unit Type
Conversion
Matched

Mean

0.47
0.84

0.56
0.86

0.57
0.79

0.62
0.86

0.68
0.77

0.63
0.70

0.65
0.69

S.D.

0.43
0.24

0.26
O.BO

0.27
0.49

0.34
0.52

0.29
0.48

0.45
0.39

0.23
0.44

-------
                                                11-29
Table 11-12. (Continued)

Variable
NOX
Split
Filterable Part icu late
Mean
S.D.
System Type

Boiler
•Furnace
Firing Rate



>1.35 gph
<1.35gph
18.0
22.6

17.9
21.3
3.3
4.0

3.2
4.5
Fuel Gravity


Unit Type


System Age


30.0-31.9
32.0-36.9

Conversion
Matched

<5 years
^5 years
18.2
20.9

19.0
20.1

19.2
20.2
4.2
4.1

2.8
4.5

5.0
3.8
Burner Type


Burner Age


SH
CH.FRH

3>10 years
<10 years
18.9
19.9

19.5
20.0
3.1
4.4

3.3
4.8
Variable Split
System Type
Boiler
Furnace
Firing Rate
>1.35 gph
<1.35gph
Burner Type
FRH.SH
CH
Fuel Gravity
30.0-32.9
33.0-36.9
Burner Age
<15 years
305 years
System Age
>5 years
<5 years
Unit Type
Conversion
Matched
Mean

1.8
'3.4

1.7
3.0

1.8
2.9

2.0
2.8

2.3
2.6

2.3
2.5

2.4
2.4
S.D.

0.9
3.4

1.1
3.0

0.8
3.0

1.0
3.3

2.6
1.4

1.1
3.4

1.1
2.6
Total Paniculate
Variable Split
Firing Rate
> 1.00 gph
< 1.00 gph
System Type
Boiler
Furnace
Burner Type
FRH.SH
CH
Fuel Gravity
34.0-36.9
30.0-33.9
Unit Type
Conversion
Matched
System Age
>5 years
<5 years
Burner Age
<15 years
>15 years
Mean

5.3
8.3

5.3
7.7

5.1
6.2

4.8
6.5

5.1
6.4

5.6
6.8

5.9
6.6
S.D.

2.8
2.7

2.2
3l3

2.3
3.2

1.2
3.3

1.4
3.3

2.2
4.0

3.1
2.8

-------
                               11-30
Table 11-13. StatisLical  Ranking of Variables for the Tuned Condition
    Units for mean values and standard deviations  are lb/1000 gal.
Smoke
Variable Split
System Age
<10 years
>10 years
Burner Age
<10 years
>10 years
System Type
Furnace
Boiler
Firing Rate
>1.35 gph
<1.35 gph
Fuel Gravity
30.0-34.9
35.0-36.9
Burner Type
CH.FRH
SH
Unit Type
Matched
Conversion

Mean

1.0
1.6

1.0
1.7

1.0
1.4

1.0
1.4

1.2
1.8

1.2
1.7

1.2
1.5

S.D.

0.7
1.0

0.8
1.0

0.8
0.9

0.5
1.0

0.9
0.9

0.9
1.0

0.9
0.8
CO
Variable Split
System Type
Boiler
Furnace.
Firing Rate
>1.00 gph
O.OOgph
Fuel Gravity
30.0-33.9
34.0-36.9
Burner Age
<15 years
>15 years
Burner Type
FRH.SH
CH
System Age
<15 years
>15 years
Unit Type
Conversion
Matched

Mean

1.1
8.5

1.7
8.9

2.2
8.9

2.6
9.1

1.0
5.9

2.9
6.3

2.9
4.4

S.D.

1.2
10.2

3.5
10.6

4.7
12.6

4.1
14.0

0.8
9.0

4.4
11.9

5.3
8.0
HC
Variable Split
System Age
<15 years
>15 years
Burner Age
<15 years
>15 years
Unit Type
Matched
Conversion
Fuel Gravity
30.0-30.9
31.0-36.9
Burner Type
FRH
CH.SH
Firing Rate
>1.35 gph
<1 35 gph
System Type
Furnace
Boiler

Mean

0.45
0.73

0.47
0.76

0.47
0.75

0.34
0.58

0.39
0.59

0.45
0.60

0.4S
0.56

S.D.

0.23
0.38

0.23
0.44

0.25
0.33

0.20
0.30

0.17
0.32

0.25
0.32

0.24
0.32

-------
                                                11-31
Table 11-13.  (Continued)
NOX
Variable Split
Burner Type
FRH.SH
CH
Fuel Gravity
35.0-36.9
30.0-34.9
System Age
<15 years
>15 years
Burner Age
<15 years
3*15 years
Firing Rate
>1.35 gph
<1.35gph
System Type
Boiler
Furnace
Unit Type
Matched
Conversion
Filterable Participate
Mean

18.2
20.7

16.5
20.1

19.0
21.3

19.3
21.4

18.8
20.4

19.2
20.5

19.5
20.2
S.D.

3.4
2.9

1.5
3.3

3.2
3.2

3.5
1.6

3.6
3.0

3.5
2.7

3.4
2.6
Variable Split
Burner Age
<15 years
>15 years
Burner Type
FRH,SH
CH
Firing Rate
>1.00 gph
< 1.00 gph
System Age
<15 years
>15 years
Fuel Gravity
30.0-30.9
31.0-36.9
System Type
Boiler
Furnace
Unit Type
Matched
Conversion
Mean

1.8
3.7

1.3
2.8

1.7
3.1

1.9
3.0

1.6
2.4

1.9
2.6

2.2
2.4
S.D.

1.0
2.7

0.5
1.9

1.4
1.8

1.0
2.6

0.4
1.9

1.6
1.7

1.5
2.2
Total Participate
Variable Split
Burner Type
FRH.SH
CH
Burner Age
<15 years
>15 years
System Type
Boiler
Furnace
System Age
<15 years
>15 years
Firing Rate
JM.OOgph
<1.00 gph
Fuel Gravity
32.0-36.9
30.0-31.9
Unit Type
Conversion
Matched
Mean

3.7
6.8

5.0
8.1

4.9
6.8

5.2
6.9

5.2
6.7

5.4
6.3

5.6
5.8
S.D.

1.6
2.3

3.1
2.3

2.2
2.5

2.3
3.0

2.5
2.3

2.6
2.4

2.7
2.5

-------
                                 11-32
Table 11-14.  Statistical Ranking of Variables for the Reference Condition
     Units for the mean values and standard deviations are lb/1000 gal.
Smoke
Variable Split
Burner Age
<10 years
>10 years
System Age
<10 years
>10 years
Burner Type
FRH
CH,SH
Firing Rate
>1.35 gph
<1.35 gph
System Type
Furnace
Boiler
Unit Type
Matched
Conversion

Mean

0.8
1.1

0.8
1.0

0.8
0.9

0.8
0.9

0.8
0,9

0.9
1.0

S.D.

0.5
0.7

0.5
0.6

0.5
0.6

0.5
0.6

0.6
0.5

0.6
0.6
CO
Variable Split
Burner Age
<15 years
5=15 years
Firing Rate
>1.00gph
<1.00 gph
System Type
Boiler
Furnace
Burner Type
FRH.SH
CH
System Age
<15 years
>15 years
Unit Type
Conversion
Matched

Mean

2.4
10.6

1.9
8.9

1.4
7.9

1.2
5.8

2.6
7.4

3.3
4.3

S.D.

3.1
16.2

1.8
12.4

1.6
11.2

0.7
9.7

3.3
13.7

4.0
8.9
HC
Variable Split
Burner Age
<15 years
^15 years
System Age
<1f years
>15 years
Firing Rate
>1.35 gph
<1.35 gph
Burner Type
FRH
CH,SH
Unit Type
Matched
Conversion
System Type
Boiler
Furnace

Mean

0.62
1.28

0.59
1.12

0.51
0.95

0.54
0.84

0.72
0.90

0.71
0.83

S.D.

0.31
1.15

0.29
0.86

0.27
0.68

0.17
0.65

0.52
0.67

0.51
0.63

-------
                                                       II-33
Table 11-14.  (Continued)
Variable      Split      Mean   S.O.

System Age
          <5 years     18.6     2.5
          >5 years     20.6     3.5

Burner Age
          <10 years     19.2     2.9
          >10 years    21.0     3.9

Burner Type
           FRH,SH      18.9     3.1
           CH          20.3     3.3

System Type
           Bailer       19.3     3.6
           Furnace     20.5     2.3

Firing Rate
          >2.00 gph    18.9     2,5
          <2.00 gph    20.0     3.7

Unit Type
           Matched     19.7     3.3
           Conversion   20.1     3.0

-------
                                          11-34
Table 11-15. Statistical Ranking of Variables for the As-Found and Tuned Conditions Combined
               Units tor mean values and standard deviations are  lb/1000 gal.
Smoke
Variable Split
Condition
T
A
Firing Rate
<3.00 gph
>3.00 gph
System Age
<10 years
>10 years
Burner Age
<10 years
^10 years
Burner Type
FRH
CH.SH
Fuel Gravity
32.0-36.9
30.0-31.9
System Type
Furnace
Boiler
Unit Type
Matched
Conversion

Mean

1.3
3.1

2.0
4.5

1.7
2.7

1.9
2.7

1.6
2.4

1.9
2.6

1.8
2.4

2.0
2.6

S.D.

0.9
2.7

2.1
2.5

1.8
2.5

2.0
2.5

1.4
2.4

2.0
2.5

2.2
2.1

2.1
2.5
CO
Variable Split
System Type
Boiler
Furnace
Firing Rate
>1.00 gph
<1 .00 gph
Burner Type
SH.FRH
CH
Unit Type
Conversion
Matched
System Age
>5 years-
<5 years
Condition
T
A
Burner Age
>5 years
<5 years
Fuel Gravity
33.0-36.9
30.0-32.9

Mean

1.2
12.9

3.1
12.5

2.6
7.9

1.9
7.1

4.2
8.7

4.0
7.6

3.9
7.3

4.4
7.2

S.D.

2.1
16.8

8.0
17.0

7.6
13.9

3.9
13.5

8.4
16.5

7.4
15.1

7.4
14.5

7.3
15.6
HC
Variable Split
Burner Age
>5 years
<5 years
Condition
T
A
Firing Rate
>1.35 gph
<1.35 gph
Burner Type
FRH
CH,SH
Fuel Gravity
33.0-36.9
30.0-32.9
System Age
<15 years
3»15 years
System Type
Boiler
Furnace
Unit Type
Matched
Conversion

Mean

0.52
0.67

0.53
0.68

0.52
0.67

0.51
0.64

0.55
0.67

0.57
0.69

0.56
0.67

0.58
0.69

S.D.

0.31
0.38

0.29
0.40

0.27
0.41

0.36
0.35

024
0.46

0.37
0.34

0.29
0.43

0.37
0.29

-------
                                              11-35
Table 11-15.  (Continued)
NOX
Variable Split
System Type
Boiler
Furnace
Firing Rate
>1.35 gph
<1.35 gph
Fuel Gravity
35.0-36.9
30.0-34.9
Burner Type
SH.FRH
CH
Burner Age
<15 years
>15 years
System Age
<15 years
>15 years
Unit Type
Conversion
Matched
Condition
T
A
Filterable Paniculate
Mean

18.6
21.5

18.3
20.8

17.5
20.0

19.0
20.2

17.9
20.7

19.4
20.5

19.6
19.8

19.7
19.8
S.D.

3.5
3.5

3.4
3.8

2.7
3.8

4.0
3.5

8.8
2.4

4.0
3.2

2.8
4.0

4.2
3.3
Variable Split
Burner Type
SH.FRH
CH
System Type
Boiler
Furnace
Firing Rate
>1.35gph
<1.35gph
Burner Age
<15 years
>15 years
Fuel Gravity
30.0-30.9
31.0-36.9
System Age
<15 years
>15 years
Condition
T
A
Unit Type
Matched
Conversion
Mean

1.6
2.9

1.9
3.0

1.7
2.8

2.1
3.2

1.7
2.5

2.1
2.7

2.2
2.4

2.3
2.4
S.D.

0.7
2.5

1.3
2.7

1.3
2.4

2.0
2.2

0.6
2.3

2.1
1.9

1.6
2.3

2.1
1.7
Total Paniculate
Variable Split
Burner Type
SH.FRH
CH
Firing Rate
>1.00gph
<1.00gph
System Type
Boiler
Furnace
Burner Age
<15 years
>15 years
Fuel Gravity
34.0-36.9
30.0-33.9
System Age
<15 years
>15 years
Unit Type
Conversion
Matched
Condition
T
A
Mean

4.5
6.7

5.3
7.4

5.1
7.0

5.5
7.4

4.9
6.2

5.7
6.4

5.3
6.1

5.7
6.1
S.D.

2.1
2.8

2.6
2.6

2.3
3.0

2.7
2.6

1.6
3.1

2.8
2.7

2.0
2.9

2.6
3.0

-------
                                           11-36

or  tuned)  is considered as a variable. The interesting point in this table is the ranking of unit
condition relative to other variables. Observations from this table show that:

            •  Unit condition generally appeared low in the ranking except for smoke
              and HC.  Unit  condition would be expected to appear high on the smoke
              list, because tuning  was based on a  smoke criteria.  HC  emissions  were
              always low, so  the  high  ranking of  condition  for  this emission is not
              significant.  Hence, these results confirm the earlier observation that tuning
              does not greatly 'influence emissions from generally well-performing units.

            •  Firing  rate  and  burner type  generally  appeared  high in the  rankings;
              system age, unit type, and  fuel  gravity generally  appeared low in the
              ranking.

            •  Units  with  lower firing rates produced higher emissions except for smoke.
              The data usually split at 1.0 to 1.35 gph.

            •  High-turbulence  combustion  heads produced lower emissions except for
              smoke and  HC, where  Shell head units did not significantly outperform
              conventional units.
Conclusions Related to Equipment Features and  Fuel

       Examination of results reported above (where emissions are  compared  for various equip-
ment features and fuels) does not reveal firm guidelines for the industry to follow with regard to
equipment design, service requirements,  or fuel.  Most variables (such as design features, tuning,
and fuel gravity) had little effect on emissions.

       The major influence on  emissions from  oil-fired industrial  units was  found  to be the
elimination (by replacement or major  overhaul) of the very poorly performing  units. Eliminating
these units  (9  percent  of  the  units in  this  limited sample) reduced emissions of the  total
population of oil-fired units by  about 50 percent.  It  was found that these poorly  performing
units were characterized  by the appearance of oil on the smoke spot. This characteristic should
readily be recognized  by burner servicemen.  Hence,  an annual inspection and cleanup (already
recommended by many  oil-heating organizations) that  includes a smoke spot  evaluation should
identify units producing  excessive emissions.  Tuning the remaining units to any specified smoke
level, as has been proposed in some localities as an air pollution-control measure, does not appear
to have   any additional  benefit  insofar as  reducing  the  mass  of emissions.  In fact, smoke
measurements can yield a low smoke  reading and, at the same time, show evidence of oil - the
telltale sign of high emissions.

       Apart from replacing poor units, the most significant feature  insofar  as its  impact on
emissions  was the generally superior performance of units equipped with flame-retention combus-
tion  heads. Fortunately, the industry has largely adopted  flame-retention head burners as the
preferred  modern burner design. As  these  units replace older conventional   gun burners, the
oil-heat industry will be moving in the  direction of lower average emissions.
Measurements on Follow-Up Units

       Measurements made in the Phase I program were .on a spot basis only, with a single
follow-up visit made only to two  units. This approach  was extended in Phase II by observing

-------
                                           11-37
emission levels  for four units during the heating season to determine the effect of time since the
initial tuning. Two follow-up checks were made on Units 23, 24, 25, and 26 after approximately
2 and 4 months of operation during the heating season.

       These units, selected to provide a cross section of burner types, were as follows:
       Unit
Burner Type
        23    High-pressure gun, FRH*,
                3450 rpm
        24    High-pressure gun

        25    High-pressure gun, FRH*,
                3450 rpm
        26    High-pressure gun, Shell
                head
Burner
 Age

 < 1

    4

 < 1

    2
  System Type

Water, CI boiler

Forced stored  air,
  steel furnace
Water, steel boiler

Steam, CI boiler
Domestic Hot
 Water Coil

     No

     No

     Yes

     Yes
The burners were equipped  with operating time clocks and cycle counters to record  operating
experience between visits.

       For these follow-up checks, gaseous emissions were measured  for the as-found condition
using both  the house fuel and the reference fuel. Particulate measurements  were included for
these units  as part  of the initial  measurements and at the end of the season  with the reference
fuel.

       Table 11-16  shows  complete measurements and emission factors for the initial runs and
the two  subsequent follow-up checks. Also shown in this table are emissions for Units 12 and 16
from Phase I. Emissions from these units were measured during Phase II and reported as Units 24
and 26, respectively.

       Table 11-17  provides a summary of the average emission factors for the follow-up units.
Emission averages are 'shown for  the four units and for three units not including Unit 25, which
had unusual nozzle  clogging problems.**

       For the four follow-up  units over the 4-month operating period, only minor shifts were
noted  in  CO and  NOX.  Smoke increased  by 90 percent, HC increased by  200 percent,  and
filterable and total particulate  increased by 131 and 76 percent, respectively. However, if the
data from  Unit  25 are omitted, the  average particulate emissions  do  not increase over the
4-month period. The increase in HC emissions was primarily associated with Units 24 and 25. As
stated  earlier, Unit  25 had unusual problems, which were responsible for increased  emissions
from that unit. The increase in HC emissions between the 1st and 2nd follow-up visits for Unit
24 has not been explained.

       Examination of the operating and emissions data for the two  units that were included in
both the Phase I and II  studies showed that these  units performed about the same for both
years. Unit  12-24 had a tendency to have somewhat high CO and HC  emissions; this was  evident
on each visit.
 *Flame retention head.
**See explanation in Table 11-19.

-------
                                      Table 11-16.  Summary of Emissions and Emission  Factors for Cyclic Runs on  Follow-Up Units
Operational Data
Unit and
Condition8
23


23.1

232

12d


24d


24.1

24.2

25


25.1

25.2e

16'


26'


26.1

26.2

A
T
R
T
R
T
R
A
T
R
A
T
R
T
R
T
R
A
T
R
T
R
T
R
ft
T
R
A

P
"
R
T
R
C02,
9.2
99
94
ea
8.4
87
88
7.4
7.2
6.7
7.1
8.9
9.2
8.8
9.0
7.8
8.6
84
9.4
S.B
108
10.9
91
il). 1
6.7
69
69
7,1
8.7
88
9.4
94
9.2
9.0
*
9.1
7.8
8.2
9.1
9.3
9.0
8.8
10.3
10.5
10.6
12.0
9.0
8.5
9.0
8.3
10.5
9.2
9.0
7.3
8.8
6.6
6.5
3.4
7.0
•11.3
11.1
11.2
11.1
9.1
8.8
8.2
8.0
8.2
B.6
Excess
Air. %
68
54
60
72
77
73
70
97
102
111
120
71
64
/2
65
95
74
75
56
72
42
41
64
49
118
112
111
109
73
70
62
59
62
66
Smoke No.
at 9 Min»
0.3
0.6
0.4
0.1
0.1
0.0
0.0
3.0
1.0
1.0
0.4
0.7
0.8
0.2
0.1
0.2
0.7
1.0
1.7
2.0
0.4
0.1
4.1
5.8
2.0
1.5
1.0
0.5
0.4
0.5
0.2
0.2
0.5
0.4
Stack
Temperature,
F
470
480
480
-
-
435
445
690
600
-
645
520
520
-

610
605
490
450
455
-
-
500
485
520
-
-
520
500
490
-
-
510
510
Firing
Rata,
gph
1.20
-
1.30
-
1.28
-
1.30
0.96
098
-
1.04
-
0.86
-
0.95
-
1.02
1.35
-
1.40
-
1.38
-
1.59
1.60
1.75
-
1.78
-
1,80
-
1 79
-
1 80
D
"CO
3.7
7.7
2.6
7.0
a. 7
4,5
2.9
66.4
76.9
76.1
222 0
4.1
9.5
20.1
18.3
41.4
19.9
10.6
8.6
12.1
15.5
14.7
10.3
11.8
17.0
17.1
17.5
5J5
6.0
10.7
6.9
7.0
55
5.2
Emission Data,
osa Average, ppm
HC
8.3
6.7
3.2
6.8
7.7
8.3
4.8
9.4
5.5
11.7
12.2
3.1
4.5
5.3
11.7
28.7
21.0
5.4
5.9
5,7
8.6
5.9
22.7
22.0
6.8
6.7
6.7
5.1
4.0
4.4
6.8
6.1
7.8
7.2
NO
67
82
75
86
76
85
91
_
-
-
39
71
69
59
62
56
64
42
47
44
49
54
38
37
_
-
-
54
68
67
69
69
66
66
NOx
85
89
79
84
77
85
97
69
78
62
78
76
71
60
64
58
64
56
47
49
47
48
36
39
51
60
60
64
71
72
74
73
68
67
Emission Factors, lb/1000 gal
Paniculate
Loading, mg/sm3 '
Filterable
10.7
7.2
6.4
-
-
_
12.6
10.4
7.0
-
6.1
19.0
13.8
-

-
8.8
5.7
7.4
7.9
-

-
78.8
9.7
-
-
11.1
9.1
10.7
-
-
-
9.1
Total
20.5
26.0
20.5
-
-
_
24.8
33.2
16.9
-
15.4
47.6
32.2
-

-
26.6
25.0
19.4
17.7
-

-
lOOS
22.7
-
-
33.2
17.6
21.4
-
-
-
18.2
CO
0.61
1.17
0.41
1.20
1.51
0.78
0.4B
10.96
13.37
13.90
48.28
0.69
1.53
3.38
2.96
8.07
3.41
1.83
1.32
2.05
2.17
2.03
1.66
1.72
1.68
1.62
1.69
1.13
1 02
1.78
1.09
1.10
0.88
0.85
Paniculate0
NOX
HC |as N02)
0.79
0.50
0.29
0.67
0.77
0.82
0.46
1.86
0.63
1.39
1.62
0.30
0.42
0.61
1.08
3.20
2.06
0.53
0.55
0.55
0.69
0.47
2.10
154
0.84
0.80
0.80
0.60
0.39
0.42
0.62
0.55
071
0.67
23.1
22.2
20.5
24.3
22.0
24.1
266
22.4
25.5
21.5
27.9
2T1
18.8
16.6
17.0
186
18.0
15.9
118
13.7
11.2
12.3
10.1
9.4
20.5
20.4
23.0
21.6
19.9
19.7
19.2
18.8
17.8
18.0
Filterable
1.55
0.93
0.83
-

-
1.82
1.74
1.23
-
1.17
2.83
2.64
-
_
-
1.31
0.83
0.97
1.16
-

-
9.99
1.82
-
-
1.96
1.35
1.55
_
-
_
1.29
Total
294
3.44
2.82
-

-
3.59
5.67
2.98
-
2.93
7.02
4.53
-
-
-
1.27
3.73
2.57
2.61
-
-
-
12.69
4.31
-
-
5.97
2.61
3.11
-
-
_
2.58
                                                                                                                                                                                              00
8 Decimals (.1 and .2) refer to 1st and 2nd follow-up visits.
D Smoke data for Units 12 and 16 are obtained at the 5-minute point.
c Modified EPA procedure.
^ Unit  12 from Phase 1 and Unit 24 from Phase II were the same unit.
e Unit  25 was adjusted between measurements due to the nozzle clogging problem described in Table 11-19.
' Unit  16 from Phase I and Unit 26 from Phase II were the same unit.

-------
                                             11-39
                     Table  11-17. Average Emissions for  Follow-Up Units
Mean Emission Factors, lb/1000 gal
Units
Four Follow-up Units
(Units 23, 24, 25, & 26)
Initial Visit
1st Follow-up
2nd Follow-up
Three Follow-Up Units
(Units 23, 24, & 26)
Initial Visit
1st Follow-up
2nd Follow-up
Emission Ratios Based on
(Units 23, 24, 25, & 26)
1st Follow-up
Initial Visit
2nd Follow-up
Initial Visit
Emission Ratios Based on
(Units 23, 24, & 26)
1st Follow-up
Initial Visit
2nd Follow-up
Initial Visit
Bacharach
Gaseous Emissions Particulate Emis-
Smoke Number,
Condition 9th minute CO

A
T
R
T
R
T
R

A
T
R
T
R
T
R
Four Units
R
R
Three Units
R
R

0.6
0.8
0.9
0.2
0.1
1.2
1.7

0.4
0.5
0.6
0.2
0.1
0.2
0.4

0.1
1.9

0.2
0.7

13.0
1.05
1.44
1.96
1.90
2.85
1.62

16.7
0.96
1.24
1.89
1.86
3.24
1.58

1.32
1.13

1.50
1.27
NO, sions3
HC (or NO2) Filterable

0.86
0.43
0.42
0.62
0.72
1.71
1.26

0.97
0.40
0.38
0.60
0.80
1.58
1.06

1.71
3.00

2.11
2.79

22.1 1.38
18.8 1.62
18.2 1.56
17.8
17.5
17.7
18.0 3.60

24.2 1 .56
21.1 1.70
19.7 1.69
20.0
19.3
20.2
20.9 1.47

0.96
0.99 2.31

0.98
1.06 057
Total

3.89
3.91
3.27
-
5.78

3.95
4.36
3.49
-
3.48

-
1.76


1.00
3 Modified EPA procedure.

-------
                                           11-40

       The general lack of any large increase  in emissions for Units 23, 24, and 26 during the
Phase II  study supports the finding reported earlier that tuning  of units  that  are  generally
performing  satisfactorily does  not result in a large reduction in  emissions. However, periodic
servicing should identify problems such as those experienced by Unit 25 and permit correction of
these problems. The high smoke level measured during the last visit to this unit would identify
existence of a problem, using equipment and techniques presently available to burner servicemen.

       The incremental changes in  efficiency  of the follownip units  between the first and last
visits were  as follow:

                                 Unit 23    + 0.4 percent
                                 Unit 24    - 2.8 percent
                                 Unit 25    +0.1 percent
                                 Unit 26    + 0.5 percent.

Hence,  except for  Unit 24, the incremental change in  efficiency was  insignificant. The incre-
mental  increase in  efficiency upon  tuning  during  the initial visit  for Unit 24 was 8.8 percent.
Apparently, during  the 4-month interval between the initial visit (and tuning) and the last visit,
performance of this unit had begun to deteriorate. However, its performance (efficiency) was still
superior to that in the as-found  condition.

       Table 11-18  and 11-19 provide information on the operating cycles and service history of
the units during the follow-up  period. Degree-days during the approximate 4-month period was
4100, indicating an average outdoor temperature of 34 F. Table 11-18  shows that the load factor
of the four units was remarkably similar, ranging  from 30 to 38 percent on time (compared with
33 percent chosen for the cyclic runs). The-average cycles per hour ranged from 1.2 to 4.7 for
the four units  (compared with 2 cycles per hour for the cyclic runs).  The steam boiler operated
with longer cycles characteristic  of this type of unit.
Experiments on the Effect of Cycle

       A series of experiments were  made to investigate the effect of cycle with Unit 35, which
was  operated  in  the laboratory  at  Battelle-Columbus. This is a forced-air furnace unit with a
high-pressure gun burner  a conventional combustion head,  and a  ceramic felt  combustion-
chamber liner. Gaseous emissions were measured while the unit was operated in the  following
cycles:

                Min. On/Min. Off    Cycles/Hour     Percent Time On
                   Equilibrium             -                100
                   10/20*                 2                 33
                   10/5                   4                 67
                   7.5/7.5                 4                 50
                   5/10*                  4                 33
                   1.5/13.5                4                 10
                   6.7/3.3                 6                 67
                   3.3/6.7                 6                 33
                   1/9                     6                 10
                     *Runs made with and without a solenoid oil valve.

-------
                     11-41
Table 11-18. Operational Data on  Follow-Up Units

Unit
(System Type)
23
(Water)


24
(Warm Air)















25
(Water)









26
(Steam)















a Cycle used in




Dates
Month
12-10 -
1-10-
2-16-
1-10-
12-13-
1-10 •
1-17 •
1-22 -
1-25 -
1-29-
2-4 -
2-9
2-15 •
2-21 -
2-26-
3-10-
3-18 -
3-26 -
4-9 -
4-16 -
1-10 -
12-16 -
1-10-
1-17 -
1-22 -
1-31 -
2-15 -
3-3 •
3-10 -
3-24 -
4-15 -
1-10 -
12-18
12-26 -
•2
-10 -
-14 -
-24-
-30 -
25 -
2-11 -
2-14 -
2-24 -
3-11 -
3-18 -
3-25 -
4-10 •
4-22 •
1-10-
Day
1-10
2-16
4-26
4-26
-10
•17
-22
-26
-29
2-4
2-9
2-15
2-21
2-26
3-10
3-18
3-26
4-9
4-16
4-25
4-25
1-10
1-17
1-22
1-31
2-15
3-3
3-10
3-24
4-15
4-24
4-24
12-16
1-2
1-10
1-14
1-24
1-30
2-5
2-11
2-14
2-24
3-11
3-18
3-25
4-10
4-22
4-27
4-27
measurements was:






Burner Operation
Hours
221
306
462
768
234
68
41
22
45
59
72
64
66
64
122
76
75
116
39
38
965
175
52
34
66
139
136
62
109
144
36
778
72
55
84
22
105
60
72
78
22
108
127
57
57
123
50
20
901
Cycles
_
4644
7521
12127
,
330
276
165
240
353
289
377
334
306
692
459
460
757
294
292
5624
	
644
437
803
1555
1600
668
1233
1915
571
9426
	
-
-
138
322
152
152
166
87
279
479
154
182
433
356
156
3056

Average On
Time, mina
_
4.0
3.7
3.8
	
12.3
9.0
8.1
11.3
10.0
15.0
10.1
11.8
12.6
10.5
9.9
9.7
9.2
8.0
7.9
10.3
	
4.8
4.7
4.9
5.4
5.1
5.6
5.3
4.5
3.8
5.0
	
-
-
9.6
19.5
23.6
28.3
28.3
15.1
23.1
15.9
22.2
18.8
17.1
8.5
7.8
17.7
Average
Percent
On Timea
30
34
28
30
35
40
34
31
47
41
60
44
46
53
39
40
39
35
23
18
38
29
31
28
31
39
33
37
32
27
17
31
38
33
44
23
44
42
50
54
31
45
33
34
34
32
17
17
35
Average
Cycles
per Houra
	
52
45
4.7
	
2.0
2.3
2.3
2.5
2.5
2.4
2.6
2.3
2.6
2.2
2.4
2.4
2.3
1.8
1.4
2.2
	
3.8
3.6
3.7
4.3
3.9
4.0
3.7
3.6
2.6
3.7
_
-
—
1.4
1.3
1.1
1.1
12
12
12
12
09
1.1
1.1
1.2
1.3
1.2
On Time, min = 10
Percent On
Cycles per
Time - 33
Hour - 2.0







-------
                                               11-42
                    Table 11-19.  History of Follow-Up Units Between Visits
        Unit 23.      No servicing or adjustments of any kind were made on this unit between visits.

        Unit 24.      On February 4, 1972, a no-heat service call was made to this unit. The
                     serviceman diagnosed the trouble as a burned out burner motor, which was
                     replaced without making any other adjustments to the unit.

        Unit 25.      A new shipment of oil (376 gal) was delivered to this unit on January 26, 1972.
                     Because of prior problems associated with oil deliveries, the burner on this
                     unit is normally turned off and the oil company has specific  instructions
                     for a slow-fill.  On the date in question no one was home -and a new driver,
                     not having been duly informed, fast-filled the tank. The fast-fill stirred up
                     sediment in the tank and clogged the nozzle, causing shutdown; the home
                     owner cleaned the nozzle and adjusted the air to achieve good combustion.

                     Additional problems were .encountered with this unit on February 16, 1972.
                     Following the conclusion of the series of emission  measurements on the
                     first follow-up visit, the burner would not ignite.  The trouble was diagnosed
                     as a clogged filter and a partially blocked fuel line. The old filter was
                     replaced and the fuel line from the filter to the tank was blown out with
                     C02'cartridges.  This corrected the problem and the unit was set to the same
                     CO2 as for the tuned condition of the initial visit and was  left on this setting.

        Unit 26.      No servicing or adjustments of any kind were made on this unit between visits.
        Table 11-20 shows the  emissions measured by  the procedure  used for the cyclic runs in
the  field,  plus  equilibrium  operation for comparison.  As might be  expected from  combustion
temperature considerations,  runs with shorter "on" time generally yielded slightly higher CO and
HC  and' lower NOX. (Particulates were not measured during these runs.) Improved  cutoff at
shutdown  with the addition of a solenoid oil valve resulted in slightly lower HC emissions where
comparable cycles were run  with and without the solenoid.

        The temperature  of the  lightweight, highly insulating combustion-chamber liner in this
unit would be expected to  respond rapidly to transient operations. A unit with a dense, highly
conductive refractory liner would be expected to  have a slow response and, thus, to show larger
cyclic effects on emissions.

-------
                                           Table 11-20.  Effect of Cycle on  Emissions
Cycle
"On", min/"Off". min
Steady state (2 hr)
10/20
10/20
10/5
7.5/7.5
5/10
5/10
1.5/13.5
6.7/3.3
3.3/6.7
1/9
Operating Conditions3
Percent
On Time
100
33
33
67
50
33
33
10
67
33
10
C02b,
%
10.3
10.1
10.1
10.3
10.3
10.2
10.3
10.1C
10.3
10.2
9.6C
°2b-
%
6.8
7.3
7.2
6.9
6.9
7.0
7.1
7.5C
6.7
7.0
8.4C
Stack Temperature
Just Before Shutoff
488
481
486
478
470
441
448
323
467
405
245
Solenoid
in Use
-
No
Yes
No
No
No
Yes
No
No
No
No
Dose Average Emissions Data, ppm
CO
11.0
13.3
13.3
13.6
13.8
14.5
14.4
16.8
13.6
15.0
17.0
HC
4.0
15.3
14.8
9.8
11.7
11.7
9.9
18.7
8.8
13.5
26.7
NO
77
72
73
77
79
76
74
70.5C
76
74
66C
IMOX
76.5
71
74
76
78
76
74
74.5
76.5
74
66.5C
All smoke readings (made 1 minute after lightoff and just before shutdown) were 0.4 or less on the Bacharach scale.
Average values over "on" period.
Values recorded at end of "on" cycle, as the on-time was too short to obtain meaningful average  values.

-------
                                          11-44
EMISSION RESULTS FOR VARIED-AIR RUNS
       The purpose of the varied-air runs was to characterize the sensitivity of emissions to air
adjustment for the various residential units. These runs were made at steady-state conditions and
the only adjustment made between points was to reposition the air gate.

       This section contains a summary of gaseous emissions and smoke measurements for the
varied-air runs on the residential units. Particulate emissions were not measured for the varied-air
runs.

       Appendix G of the Data Summary Volume contains tabulated emission data and plots of
emissions  versus  excess  air (in  terms  of CO2  reading)  for varied-air runs at all  operating
conditions (as-found, tuned, and reference-fuel runs). Appendix I reports the same data in terms
of emission factors.
Emission Characteristics Related to Excess Air

       Gaseous emissions and smoke were  measured at about six steady-state conditions repre-
senting a range of excess air settings between the wide open setting of the air gate and a setting
which gave  a  smoke level  of  5  to 7.  Plots of emissions versus excess  air or C02  provide an
indication of the operating range  producing low gaseous emissions or smoke. Figure II-6 is an
example plot showing the variation of smoke and gaseous emissions with CO2 for one unit.

       Figures  II-7 through 11-19 show summary  curves  of smoke, CO,  and HC, for  all 12
residential units —  comparing  as-found (A), tuned (T), and reference-fuel (R) conditions. NOX
was not  highly sensitive to air setting and  is not summarized in  these curves. Individual  data
points are tabulated and plotted against CO2 for each condition in the Data Supplement Volume.

       Examination of Figures  II-7 to 11-19  show that each of these units is  unique in its
combustion  characteristics.  In  fact, it is quite difficult to select any one of these units as having
combustion  characteristics  which are typical of the group of units. Some units exhibited  very
sharp  breaks in the smoke  curves;  others had broad, sweeping curves. Tuning generally improved
the smoke  curve  (moved it toward higher CO2 values), but, as tuning was  primarily oriented
toward reducing smoke, this was not surprising. Most units had very low CO and HC emissions
over the normal range  of operation in the as-found condition, so  that significant  improvement
upon tuning was not possible.

       The  most significant point that can be made from these data is that smoke is a good
indicator of low CO and HC  emissions at high CO2 levels but not at low CO2 levels. That is,
almost without exception, as excess air is gradually decreased  from the  normal operating range,
the smoke  level begins to  increase sharply  before  the  CO and HC emissions show significant
increases. However, as  excess  air is increased, CO and HC emissions increase quite rapidly while
smoke levels remain low. Hence, at high CO2 levels low smoke is  a fairly good indicator that  a
burner is adjusted  for low CO and HC emission levels. Conversely,  smoke is not a good measure
of low CO  and HC production  in the low CO2  range, and adjustment based on smoke alone
could lead to high CO and HC  emissions.


                                                            (Text continues on Page  11-59.)

-------
                             11-45
cu
.0

E   6
   o
 o
 k_
 o

 o   3
 o   °
CO
       0
               CO
32-
                                                      28-
                                                      24-
                                                      20-
                                                      12-
                                                       Q _-..
                                                       4-
                                                       160
     140
     120
     100
                                                          80
     60
                                                          40
     20
                                                               E
                                                               Q.
                                                               D.
                                                               O
                                                               O
                       7      8      9     10     II     12

                           C02,  percent
Figure II-6,  Typical Smoke and Gaseous Emission Characteristics for a

            Residential Unit
           Unit 24 in tuned condition firing house fuel.

-------
s
i
CO
                                 9      10
                             percent









E
a
o"
0









leu
170
160
150
140
130
120
no
100

90

BO

70
60
50
40
30
20
10
n

-
-
-
-
-
-
-
	

_

_

-
-
-
-
-
-
-














CO-R





CO-A
HC-R/N"






CO



-7

-
-
-
-
-
-
-
—

_

—

-

-T —



^C-T -

3D
34
J2
30
28
26
24
22
20

18

16

14
12
10
8
6
4
2

8       9
COZ, percent
                               Figure 11-7.  Emissions for Residential Unit 23 as Function of CO2
                                          Lables on curves refer to pollutants (CO or HC) and/
                                          or burner condition (A,  T, or R).

-------
Figure II-8.  Emissions for Residential Unit 24 as Function of CO2

-------
 8        9
C02, uercenl
                                              180

                                              170

                                              160

                                              150

                                              140

                                              130

                                              120

                                              no

                                              IOO

                                              90

                                              80

                                              70

                                              60

                                              50

                                              40

                                              '30

                                              20

                                              10

                                               0
36

34

32

30

28

26

24

22

20

18

16

!4

12

10

8
00
      Figure II-9.  Emissions for Residential Unit 25 as Function of CO2

-------
 8        9
CO^, percent
                                             ISO

                                             70

                                             160

                                             150

                                             140

                                             ISO
                                             120

                                             no

                                             100

                                             90

                                             80
                                             70
                                             60
                                             50

                                             40
                                             30

                                             20
                                             10
                                              0
                                  36

                                  34

                                  32

                                  30

                                  28

                                  26

                                  24

                                  22

                                  20

                                  18

                                  16

                                  14

                                  12

                                  10

                                  8

                                  6

                                  4

                                  2

                                  0
C02, percent
    Figure H-10.  Emissions for Residential Unit 26 as Function of CO2

-------
-789
        COj, percent
                                                       ISO

                                                       I TO

                                                       60

                                                       150

                                                       140

                                                       1301

                                                       12O

                                                       no

                                                       IOO

                                                       90

                                                       80

                                                       70

                                                       60

                                                       50

                                                       40

                                                       30

                                                       20

                                                       10

                                                        0
       \CO-A
HC-A
                                           36

                                           34

                                           32

                                           30

                                           2B

                                           26

                                           24

                                           32

                                           20
              Figure 11-11.  Emissions for Residential Unit 27 as Function of CO2

-------
I
z
8
I
8  '
                              a        9

                             COj, percent
   ISO



   170



   160



   ISO



   140



   130



   120



   110



 1  100

I

°-  90



3  80



   TO



   60



   50



   40



   30



   20



   10



    0
                                                                                 HC-A
36



34



32



30



28



26



34



22



20



18



16



14



12



10



8



6



4



2



0
                             C02, percent
                                  Figure 11-12.  Emissions for Residential Unit 28 as Function of CO,

-------
         I
8       9

C02, percent
          I
                10
                                    d
                                    Q.



                                    O
                                                               C02, percent


Figure 11-13.  Emissions for Residential Unit 29 as Function of CO2
                                                                                                                  Ul
                                                                                                                  to

-------

-------
                                 !
170


160


ISO


140


130


120


110


100


90



80


70


60


5O



40


30



20


10


 0
                                                                                             34


                                                                                             32


                                                                                             30


                                                                                             ?8



                                                                                             26


                                                                                             24



                                                                                             22


                                                                                             20
                                                                                                 O
                                                                                                 I
                                                                                  CO-A
                                                                                      CO-T —

Figure 11-15.  Emissions for Residential Unit 31 as Function of CO9

-------
04-
S
CD
ISO


170


160


150


140


130


120


110


100


90


80


70


60


50


40


30


20


10


 0
                                                                                  HC-A
36



34


32



30



28



26


24



2?



20


18



16


14


12


10



8


6



4


2
                                                                                                      e       9

                                                                                                     C0?, percent
                                    Figure II-16.  Emissions for Residential Unit 32 as Function of CO2

-------
         I
             I
CO,
    9
percent
                 10
                                            I
                                        ISO

                                        170

                                        160

                                        150:

                                        I4o'

                                        130

                                        120

                                        110

                                        100

                                         90

                                         80

                                         70

                                         60

                                         50

                                         10

                                         30

                                         20

                                         10

                                          0
                                                                                     CO-R
                                                              CO-A and  HC-T off scnle
                                                         I
                                                                   C02, percent
Figure II-17.  Emissions for Residential Unit 33 as Function of CO2
                                                                                                       36

                                                                                                       34

                                                                                                       32

                                                                                                       SO

                                                                                                       28

                                                                                                       26

                                                                                                       21

                                                                                                       22

                                                                                                       20

                                                                                                       18

                                                                                                       16

                                                                                                       14

                                                                                                       12

                                                                                                       10

-------
8        9
C02, percent
                                                ISO

                                                170

                                                160

                                                150

                                                140

                                                130
                                                120

                                                NO

                                                100

                                                90

                                                80

                                                70
                                                60

                                                50

                                                40
                                                30

                                                20

                                                 10
                                                 0
                                                    I
                                                                                              HC-R
                                                                                          HC-T
I   HC-A  |
36

34

32

30

28

26

24

22

20

18

16

14

12

10

a

6

4

2

0
                                                                   C02, percent

Figure H-18.  Emissions for Residential Unit 34 as Function of CO2

-------
s
                     789
                            C02, percent
                                        170

                                        ISO

                                        150

                                        140

                                        130

                                        120

                                        110

                                        100

                                        90

                                        80

                                        70

                                        60

                                        50

                                        40'

                                        30

                                        20

                                        10
                                                                  C02, percent

Figure 11-19.  Emissions for Residential Unit 35 as Function of CO2
36

34

32

30

28

26

24

22

20

IB

ie

M

12

10

8

6

4

2
                                                                                                                                     12
                                                                                                                                                     00

-------
                                            II-59

       In view of these observations, the tuning procedure adopted for this program and used by
many experienced servicemen for normal adjustments appears to be as good a means of achieving
low  overall  emissions  as can be devised  using  field instruments  for smoke  and CO2 measure-
ments. A knowledge of the smoke-versus-CO2 curve for a particular burner permits adjusting the
burner to a  low smoke-high CO2 level to both minimize emissions and operate efficiently.

       Figure II-20 shows smoke versus  CO2  curves  for all units  in  the as-found  and tuned
conditions, respectively. These figures further illustrate the wide range of combustion character-
istics exhibited by the  individual units.

       For  some burners,  the adjustment  limits for low-emission  operation were very narrow.  In
several cases,  the fan capacity limited the operating range such that CO2  levels could not be set
below 8  or 9 percent.
 Limits of Acceptable Adjustment

       Table  II-21 shows a summary  of the  acceptable operating ranges for the various units,
 based on the following criteria without regard to CO, HC, or NOX emissions:

            • Minimum C02:8 percent  (8  percent CO2 was arbitrarily selected  as the
              minimum CO2  desired to achieve acceptable efficiency)

            • Maximum CO2 :air adjustment for No. 2 smoke.

 The acceptable  operating range by these criteria  averaged  1.26 percent  CO2  and exceeded 3
 percent in two cases,  but many units yielded negative values, which indicated that No. 2 smoke
 was exceeded at 8.0 percent CO2.
TRIAL CORRELATIONS OF SMOKE VERSUS PARTICULATE

       In the Phase I program, the possible correlation of steady-state Bacharach smoke numbers
with  cyclic  particulate emissions  was investigated, but  no direct  relationship was found.*  The
Phase II residential data exhibit the same lack of correlation, as will be seen by several plots.

       Figures 11-21 and  11-22 show the attempted smoke versus particulate emission correlation
for all Phase I and II data combined. No relation was found, considering either filterable or total
particulate.

       Figures II-23 and 11-24 show the effect  of tuning on the  smoke-part'iculate relationship
for Phase II  units.  A consistent slope of the  connecting lines for the different units would suggest
characteristic curves for individual burners, but even this  relation was  not observed.

       One  explanation  for  the  lack of correlation between smoke (at 5 or  9 minutes)  and
particulate (integrated  over the cycle) may  be the particulate associated with start-up. Although
data are not available  to  determine the  contribution  of particulate generated during start-up to
* Limited Phase I data  indicated a correlation between the carbon content  of the particulate filter catch and
 smoke up to about No. 7 smoke, where the smoke spot apparently became "overloaded".

-------
                                                                                                       ON
                                                                                                       o
Figure II-20.  Emissions for Residential Units Firing House Fuels

-------
                                    11-61

             Table 11-21.  Evaluation of Unit Performance
Unit
23


24


25


26


27


28


29


30


31


32


33"


34


35

Average


All
Condition
A
T
R
A
T
R
A
T
R
A
T
R
A
T
R
A
T
R
A
T
R
A
T
R
A
T
R
A
T
R
A
T
R
A
T
R
T
R
A
T
R
All
CO2 Level at Which
No. 2 Smoke Occurs, %
9.2
10.5
10.1
8.3
9.3
9.8
9.4
10.0
10.0
10.5
10.6
10.5
9.4
9.7
8.2
7.0
9.1
9.0
6.9
8.0
7.7
8.2
7.4
7.6
9.9
10.7
10.7
8.3
11.0
10.1
6.9
8.2
8.2
9.0
10.5
10.2
11.1
10.6
—
—
-
-
Acceptable Range of
Operation, % CO2a
1.2
2.5
2.1
0.3
1.3
1.8
1.4
2.0
2.0
2.5
2.6
2.5
1.4
1.7
0.2
None
1.1
1.0
None
0.0
None
0.2
None
None
1.9
2.7
2.7
0.3
3.0
2.1
None
0.2
0.2
1.0
2.5
2.2
3.1
2.6
0.85
1.75
1.50
1.26
a Acceptable Range of Operation = CC>2 at which No. 2 smoke occurs -8.0.
b All smoke spots from this unit appeared to include raw fuel.

-------
l*f
12
o
0
O
0 10
.0
*"
g 8
"58
E
UJ
o, 6
J5
o
CD
0
£ 2
(z
n
Legend
"o Phase I o
_A Phase n

1
-
—
- A
_ O

0 0
t
~ £" ^ ^
feo°° ° 8
»§ o 8
1,1,1,1
     "02
     Bacharach  Smoke  Number at 5 Minutes
                                                                        12
                                                                     o
                                                                     en
                                                                        ,0
                                                                     o
                                                                      ~   8
                                                                     O
                                                                     a>
                                                                     5
                                                                     3
                                                                     o
                                                                     Q-
                                                                         0
                                                                              Legend      °
                                                                            o Phase  I
                                                                          _A Phase  n
                                                                          A A
                                                                           -  A
                                                                                          1
       02468
     Bacharach  Smoke Number at 5 Minutes
                                                                                                                           Ox
Figure 11-21. Relation of Smoke Number and Filterable
            Particulate Emissions — Phase I and II
            Residential Data
            "Modified EPA Procedure.
Figure 11-22. Relation of Smoke Number and Total
            Particulate Emissions — Phase I and II
            Residential Data
            *Modified EPA Procedure.

-------
8
 c
 o
 in
 tn

'£
UJ
 o
Q_
 D


 O)
               2468


          Bochorach  Smoke  Number  at 5 Minutes
Figure 11-23.  Effect of Tuning on Smoke and Filterable

             Particulate Emissions for Individual —

             Phase II Residential Units


             *Modified EPA Procedure.
                                                                        14
                                                                        12
                                                                                      Legend


                                                                                    •   As-found

                                                                                    o   Tuned
                                                                                                         I
              2468


        Bacharach  Smoke  Number at 5  Minutes



Figure 11-24.  Effect of Tuning on Smoke and Total

             Particulate Emissions for Individual —

             Phase II Residential Units


             *Modified EPA Procedure.

-------
                                            11-64

the particulate integrated over the whole cycle,  examination of the smoke readings taken at the
1,5,  and 9-minute points of the "on" cycle (these data are reported in Table 11-22) suggests that
emissions may be extremely high during the first minute or two of firing.

       Bacharach  smoke  samples,  generally  taken during essentially steady-state operation near
the end  of a  cycle,  do not include starting  and shutdown as do the particulate samples. These
transients show as peaks on gaseous  monitors, as "smoke puffs" on the Von Brand continuous
tape smoke meter,  and as  high  smoke  reading at the  1-minute point in Table 11-22.  These
transients vary widely in degree for different units. The  variation can be due partly to ignition
delay and fuel pump cutoff characteristics, with the latter believed to be the most critical.

       It should be  recognized that only one particulate measurement was taken on each unit
for  each condition (as found and  tuned),  so there  was  no  opportunity to determine if a
correlation might  exist between smoke and either steady-state or cyclic particulate for individual
units without  other changes.

       Among the aspects which  may  be significant in the lack  of correlation  already observed
between particulate  weight and Bacharach smoke are  particle size, density, and light reflection
characteristics. It  is  hoped  that  particle-size measurements planned  for  a residential unit as
follow-on to this program will help to clarify this aspect.

       The planned experimental  program will  include particulate measurements  taken during
both  cyclic  and  steady-state  operation  and may provide  additional insight  on  the  relation
between smoke and these particulate levels for residential units.

-------
                  11-65
Table 11-22.  Smoke Reading at 1, 5, and 9
            Minutes for Cyclic Runs on
            Residential Units
Bacharach Smoke
Unit
23


23.1

23.2

24


24.1

24.2

25


25.1

25.2

26


26.1

26.2

27


28


29


Condition
A
T
R
T
R
T
R
A
T
R
T
R
T
R
A
T
R
R
R
T
R
A
T
R
T
R
T
ft
A
T
R
A
T
R
A
T
R
1 Min
0.7
0.6
0.4
_
-
_
—
0.4
3.0
2.5
—
-
_
-
2.1
1.7
1.6
_
-
_
—
0.9
0.9
0.6
_
-
_
-
1.8
0.8
0.4
1.8
1.1
1.0
9.0
2.3
2.9
5 Min
0.3
0.5
0.3
0.1
0.2
0.0
0.0
0.3
0.7
1.4
0.3
0.2
0.5
0.7
1.2
1.4
0.7
0.7
0.2
4.1
5.7
0.4
0.6
0.4
0.2
0.2
0.5
0.3
1.1
0.4
0.4
0.6
0.4
0.4
9.0
0.7
0.6
Number
9 Min
0.3
0.5
0.4
0.1
0.1
0.0
0.0
0.4
0.7
0.8
0.2
0.1
0.2
0.7
1.0
1.7
2.0
0.4
0.1
4.1
5.8
0.5
0.4
0.5
0.2
0.2
0.5
0.4
1.0
0.4
0.3
1.3
0.4
0.4
9.0
0.5
0.3

-------
         11-66






Table 11-22.  (Continued)
Eacharach Smoke Number
Unit
30


31


32


33


34


35

Condition
A
T
R
A
T
R
A
T
R
A
T
R
A
T
R
T
R
1 Min
0.4
2.0
2.5
0.2
0.3
0.3
0.7
0.2
0.1
Oily
Oily
Oily
3.0
1.7
1.7
0.3
0.2
5 Min
0.2
1.1
0.4
0.0
0.2
0.3
0.1
0.1
0.1
Oily
Oily
Oily
2.6
1.5
1.6
0.2
0.2
9 Min
0.2
0.6
0.3
0.0
0.2
0.2
0.2
0.1
0.1
Oily
Oily
Oily
2.7
1.0
1.9
0.2
0.2

-------
                                            HI-1

                        EMISSIONS FROM COMMERCIAL BOILERS
       This  chapter  describes the Phase II investigation of emissions from commercial boilers.
 The principal effort of the Phase II program was on conducting a more detailed investigation of
 the effect of fuel,  load, and  excess air on  emissions than was possible during the Phase I study.
 The discussion is presented as follows:

            •  Boilers Included in the Phase II Investigation

            *  Procedures used in the Field Investigation

            •  Emission  Results for Commercial Boilers.

 Where applicable, results of Phase I emission measurements1 have been included in  the analyses
 of the influence of various factors on emissions.
 BOILERS INCLUDED IN THE PHASE II INVESTIGATION

       The  scope  of  boilers  in  the  Phase II investigation included six  commercial  boilers
 ranging in size  from 40 to 600 boiler horsepower firing various grades of fuel oils and  natural
 Basis for Selection of Equipment

        A survey of the commercial boiler population was  initiated to form the basis for the
 selection of a representative mix of commercial boilers. A survey form (developed by the Battelle
 project team and  project consultant W. H. Axtman) was distributed by the American Boiler
 Manufacturers  Association  (ABMA) to veteran  observers in the  commercial-industrial boiler
 industry. The results of this  survey, summarized by W. H. Axtman, are contained in Appendix B.
 Selection of Equipment Mix and Individual Boiler

       The selection of the Phase II  boiler mix and specific boiler type/size combinations was
 made by the Battelle-Columbus project team after reviewing results of the survey.

       Boilers  selected for inclusion in  the  Phase II study were intended to make the Phase II
 sample representative  of the  existing  boiler population.  (Phase  I boilers did not  weigh  in this
 consideration due to the limited data obtained on these  units.) It was decided that the Phase II
 study of commercial boilers was to provide  so much more detailed information about emissions
 at various operating conditions, that the Phase II selections alone should be representative of the
 existing  boiler  population. The  selection of  the equipment mix  and specific boiler type/size
 combinations was approved by the EPA Project Officer  and the API SS-5 Task Force Steering
 Committee.

       Table HI-1  outlines  the mix of commercial boilers included  in  the  Phase I  and II
investigations as representative of commercial heating boilers in the field.

-------
                                                 III-2
               Table 111-1.  Mix of Commercial Boilers Sampled in Phases I and
Distribution of
Sample by
Phases

Total, all boilersb
By Boiler Size
10-50 bhp
51-100 bhp
101-300 bhp
301 -600 bhp
By Boiler Type
Scotch
Firebox firetube
Cast iron
Watertube
Miscellaneous firetube
By Burner Type
Air atomizing
Pressure atomizing
Rotary atomizing
Natural gas
By Fuelb
No. 2 oil
No. 4 & 5 oilsc
No. 6 oil
Natural gas
1
7

0
2
4
1

6
1
0
0
0

4
2
1
1

2
4
2
1
II
6

1
3
1
1

2
1
2
1
0

4
2
0
6

6
5
3
6
Total
13

1
5
5
2

8
2
2
1
0

8
4
1
7

8
g
5
7
Percentage
Phase II
-

17
50
17
17

33
17
33
17
0

67
33
0
100

100
83
50
100
Total
-

8
38
38
15

62
15
15
8
0

62
31
8
54

62
69
38
54
Distribution of
U.S. Commercial
Boiler Population,
percent3
-

47
24
29
—

21
27
33
6
13

15
22
15
56

38
8
4
56
Commercial boilers are defined as between 50 and 300 bhp.
Numbers total more than "Total, all boilers" because some boilers were fired with more than one fuel.
Including Phase II reference fuel.

-------
                                             III-3

        After review of the data obtained on boiler population and sales, it was determined that
the six boilers be selected according to the size ranges of the survey:  10 to 50 bhp, 51  to 100
bhp,  and 101  to  300 bhp. It was further decided that the two boilers selected in each size range
be representative  of the most common types for the size range. Hence, a tentative selection was
made as follows:

             • Size, 10 to 50 bhp
                 Cast iron
                 Firebox firetube

             • Size, 51 to 100 bhp
                 Cast iron
                 Packaged Scotch

             « Size, 101  to 300  bhp
                 Packaged Scotch
                 Firebox firetube.

These boiler selections were believed to be generally representative of boilers in the field today,
within the limits placed by the size of the sample.

        Another factor in  the selection of the boilers was their capability  for  firing more than
one fuel. The program plan was  to fire each boiler with fuels as follows:

             » No. 2 fuel oil

             • A low-sulfur (1.0 percent) residual fuel oil typical of that being marketed
               on the East Coast

             • Conventional No.  5 or No. 6 residual fuel oil

             • Natural gas.

        It was difficult to locate small boilers capable of firing heavier fuels; in  fact,  the smallest
cast-iron  boiler that was available could not be fired satisfactorily with fuels heavier than No. 2
grade fuel oil, in  spite of several attempts by  the  manufacturer to successfully  fire heavier fuels
by  switching burners.  The larger cast-iron  boiler could  not fire  conventional  No. 5 and No. 6
grades of fuel oil but could fire  No. 4 fuel oil and the low-sulfur residual fuel.

        Midway in  the  program, it was learned that the  tentatively selected 40-bhp  firebox
firetube boiler  could not be fired with fuels  heavier  than No. 2  fuel oil.  At  that  point, a
substitution was made of a 600-bhp watertube boiler for the 40-bhp firebox firetube boiler. Thus,
the scope of the  boilers actually measured was expanded in both boiler size and boiler types.
The EPA Project  Officer and the API SS-5 Task Force Steering Committee concurred with this
substitution.

       For purposes of this investigation, it was important to select boilers for which load could
be controlled at a  desired level for extended  periods to  provide  stable conditions for emission
measurements. This  requirement was met,  through  the  cooperation of ABMA,  by choice of
equipment installed as house boilers or test boilers in plants of boiler manufacturers.* In addition,
competent personnel  already  familiar  with the specific  equipment were available  to adjust the
boilers to the desired operating  conditions. Normally, these boilers were in  day-to-day operation
*Boiler C2003 was an exception. It was a newly constructed unit that had been fired for manufacturers tests
 only. Emission measurements were made prior to its delivery by the manufacturer.

-------
                                            ni-4

 to  supply  steam,  to  provide  service  training,  or to provide  a burner test facility for the
 manufacturing plants. These boilers did not appear to have received any better service attention
 than would be reasonably typical of similar boilers in commercial or industrial applications.
 Description of Commercial Boilers

        Table III-2 shows the number designation for each commercial boiler, with identification
 of boiler type and size, burner type, fuel grades, and other descriptive data.
 PROCEDURES USED IN THE FIELD INVESTIGATION

        The principal effort of Phase II of this investigation  was devoted to more detailed field
 measurements of emissions covering more conditions than was  possible for the Phase I study.
 Phase  II was  conducted during the heating season of 1971-72. The measurements were made by
 a three-man field team supported by other Battelie-Columbus staff.

        Commercial boiler measurements were conducted in April through June 1972, with each
 boiler monitored for approximately 5 to 10 days, depending on conditions and fuels run.

        The commercial boilers were  all  sampled in  the  as-found  condition; i.e., no  cleaning
 (except for the .exhaust stacks) or  other servicing of the units was done prior to  measurements.
 Wherever practical, the  exhaust stacks were  thoroughly cleaned prior to sampling to minimize
 collection of previously deposited material during particulate sampling.
 Conditions Investigated

       Emission data  from each of the commercial units were obtained under steady-state firing
 conditions at several excess air levels, generally while firing each of four fuels at four different
 load levels.
       Load and Excess Air Conditions.  Figure III-l shows  the matrix of runs that was the
general plan  or target for measurements on  each boiler-fuel combination. A base-line condition,
the operating condition most  typical of normal boiler operating conditions, was defined as  80
percent load  and 12 percent CO2 (10 percent CO2 for gas firing)*. The target loads were

            R - rated load

            H — 80 percent of load, considered the normal high-fire condition for
                 boilers in  use

            M - an intermediate load

            L - the normal low-fire setting.

Boiler  C2001, a  relatively small cast-iron  boiler, normally operated strieilj  In  the on-off mode;
hence,  intermediate  loads could only be achieved by changing  nozzle sizes. The remaining boilers
were modulated  to the desired  loads.
The base-line condition was defined during the Phase I study cftur  discussion with the  ABMA Commercial-
 Industrial Air Pollution Committee.

-------
                                    Table 111-2. Description of Commercial Boilers Included in Phase II Study
Boiler
C2001
C2002
C2003
C2004
C2005
C2006
Boiler
Horsepower
and Type
40-hp
Cast I ron
90-hp
Cast Iron
300-hp
Scotch
80-hp
Firebox
100-hp
Scotch
600-hp
Watertube
Burner
Type
Pressure
Atomizing
Air
Atomizing
Air
Atomizing
Pressure
Atomizing
Air
Atomizing
Air
Atomizing
Normal
Fuel Other
Grade Fuels3
No. 2 Gas
No. 4 No. 2, CR, Gas
No. 6 No. 2, CR, Gas
No. 5 No. 2, CR, Gas
No. 6 No. 2, CR, Gas
No. 6 No. 2, CR, Gas
Rated
Input,
gph
11.35
26.1
33.5
22.5
28.0
165.2
Output
Rating,
MBtu/hr
1258
3000
10043
3341
3348
25000
Method of
Control
LFSC
on/off
Modulating
Modulating
LFSC
on/off
Modulating
Modulating
Operating
Pressure,
psig
15
15
150
15
15
150
Number
of Flue
Passes
2d
2d
3
3
4
2d
Furnace
Volume,
cult*"
19.7
50.3
86.7
40.8
25.4
413.4
a  CR used to designate 1 percent sulfur reference fuel fired in commercial boilers.
b  Manufacturer's data; volume may .include turn-around volume at rear of first pass.
c  Lorn-fire start.
^  Conventional flue pass definition not appropriate. These values were selected as the best approximation for these units.

-------
                                              III-6
                                             M
 H

1

Excess
Air





i
-
G

G
(b)
G+P

G
1
Low
Fire
1

G

G

G

G
1
Int.
Load
i
G
G

G

G+P
(Baseline
condition )
G
1
80%
Load

-
G

G

G

G
1
Rated
Load
                                            M
H
R
                                                Load
                                                                             12%
                                                                             CO,
               Figure III-l.  Matrix of Measurement Points for Commercial Boilers3
                            a.  G = Gaseous measurements, plus smoke
                               P = Particulate measurements.
                            b.  Particulate was run at low load for normal house fuel only.

        Air adjustments were made after disconnecting the air-fuel proportioning linkage. To assure
 a steady-state  condition, the boilers were operated  for at least 30 minutes at  each load setting
 before sampling was started. Particulate samples  were obtained  for each boiler-fuel combination
 at the base-line condition. Additional particulate samples were obtained at the low-fire setting for
 each  boiler while  firing the normal fuel  for the boiler.  Gaseous emission measurements were
 obtained for each boiler-fuel combination at each load.
        Fuels.  As listed in Table III-2, each boiler was fired with the "house fuel" normally fired
 in  the boiler,  No.  2 fuel  oil, a  1-percent  sulfur  East Coast  residual oil designated CR* (for
 "commercial reference" oil),  and natural gas.  The  commercial  reference  oil was typical of the
 current commercially  available  East Coast  fuels  at  this  sulfur level.  It  was  purchased in
 Connecticut and transported from site to site in a 6000-gallon, steam-traced tank truck.

        Properties  of all fuel oils fired in commercial boilers are tabulated  in Appendix C, Tables
 C-3 and C-4.

        Boiler  C2001, a small  cast-iron boiler which  could not fire heavy fuel oils, was fired with
 only No. 2 fuel  oil and natural gas.
*The designation CR is used to denote the particular fuel oil used as the commercial reference fuel in this study.
 LSR is used elsewhere  in this report as a designator for the general class of low-sulfur residual fuel oils (1 per-
 cent sulfur) produced to meet local air pollution regulations^

-------
                                          III-7

Emission Measurements — Instruments and Techniques

       The instrumentation and emission measurement techniques employed for the commercial
units were similar to those used for the residential units.

       An  established  set of  operational  procedures  was routinely followed for  each  boiler
investigated. Stack gases were sampled and supplied directly to continuous monitoring equipment
set up alongside the heating unit.
       Gaseous Emissions.  Measurements were made  of the following  stack emissions  under
various conditions of operation using the methods noted as follows.  (Details of instrumentation
and measurement procedures are described in Appendixes E and F.)

                   Emission                    Measurement Method
              CO2	NDIR (nondispersive infrared) and
                                          Fyrite

              O2	Amperometric and Fyrite

              CO	NDIR

              Hydrocarbons (total)  .  .   ,  Flame ionization

              SO2   	Dry electrochemical

              NOX	Dry electrochemical and NDIR with
                                          converter

              NO	NDIR

              Particulate	EPA sampling train.


       Smoke and  Other Combustion Parameters. Smoke was measured using  the  Bacharach
hand pump  smoke  meter and  the  standard procedures adopted  by ASTM7.  In  addition  to
these measurements, other combustion conditions measured included:

           •  Firing rate, by weight measurement

           •  Stack temperature, measured in the flue at the particulate sampling location

           •  Stack draft, measured in the flue at the particulate sampling location.

-------
                                            III-8

       Paniculate Emissions. Participate emissions were sampled using the  EPA  sampling rig2'8.
This train is described in Appendix F. A special feature of this sampling train is the inclusion of
two water  impingers  or bubblers (at 70 F) downstream  from the filter. The impingers  were
originally intended to collect any condensable material (at 70 F) that exist as vapor at  filter
temperature and,  thus, pass through  the filter and  any solid particulate  that pass through the
filter. Recently, EPA has abandoned use of the impinger catch in determining particulate  emis-
sions  for power  plants8  as  there was indication  that reactions  occur in  the  impinger to
generate material  that is included in  the weight measurement of particulate,  even though the
material does not exist as particulate either in the flue gas or in the atmosphere9.

       To  insure that  the most meaningful information was obtained  from the particulate
samples  collected  on this investigation, the probe wash, the filter catch, and the impinger  wash
were treated separately, and particulate weights were recorded for each. In this report, particulate
data are reported as filterable (including the  probe and filter catches) and total (combining the
filterable and the material found in the water impingers). However, it should be pointed out that
even the filterable catch obtained using the  EPA sampling train may not be directly comparable
to  the  particulate catch obtained using other  sampling trains because  of  differences  in the
procedures for washing the probe and differences in sampling rates and volumes.

       Previous experience at Battelle suggests that  acetone washing  may not  be adequate to
remove all particulate from the  probe. Therefore, for this investigation two washing procedures
were used:  (1) the EPA procedure and (2) a modified EPA procedure referred to as the MEPA
procedure. First,  the probe, filter holder, and impingers were washed using procedures specified
by  EPA. Then a  modified procedure was used wherein additional washings were made to insure
complete removal of deposited  particulate.  The complete procedures  and  the resulting data are
discussed further in Appendix F.
EMISSION RESULTS FOR COMMERCIAL BOILERS

       This  section  summarizes  the  results  obtained  from  measurements  of gaseous  and
particulate emissions  and smoke made  on six commercial boilers during the Phase II investiga-
tion. Measurements were made on each boiler at several excess air levels at each of several loads;
most were fired with four fuels. Results for the base-line  condition (80 percent load and 12 per-
cent CO2) and  analyses of the effect  of important variables on emissions are presented in this
section. Complete data for all runs for each boiler, each fuel, each load, and each excess air level
are tabulated in  Appendix H of the Data Supplement Volume.

       In addition to the  emission results, this section contains correlations  showing  the  in-
fluence of various parameters (such as load, excess air, or fuel properties) on emissions.


Summary of Emission Data and  Emission  Factors

       Table III-3 contains a  summary of emission data  for the commercial boilers. Table HI-4
shows  emissions in lb/1000 gal  oil  for the gaseous pollutants (CO, HC, NOX, and SO2)  and for
particulate for each boiler-fuel combination at the base-line condition.

-------
                      Table 111-3.  Summary of Emissions From Commercial  Boilers at the Base-Line Conditions3
Operational Data
Commercial Fuel
Boilerb Grade
C2001 No. 2
Gas
C2002 No. 2
No. 4
CR
Gas
C2003 No. 2
CR
No. 6
Gas
C2004 No. 2
CR
No. 5
Gas
C2005 No. 2
CR
No. 6
Gas
C2006 No. 2
CR
No. 6
Gas
Fuel
Temp,
F

-
_
_
195
-
88
143
208
-
_
118
120
-
85
110
206
-
70
127
212
—
Firing
Rate,
gphc
9.3
1.26
21.6
20.6
20.4
3.04
71.5
66.0
65.5
10.0
19.2
18.3
18.4
2.40
23.6
22.5
21.8
3.21
142
143
139
20.1
Load,
%
80
81
78
78
78
82
80
77
79
83
81
82
85
76
76
77
77
77
79
84
84
83
CO2,
%
12.1
9.1
11.9
12.3
12.1
10.0
12.1
12.0
11.9
10.0
12.0
12.1
12.0
10.0
12.0
12.1
12.1
10.0
11.9
12.0
12.1
9.8
02.
%
4.4
5.0
5.3
4.3
4.4
3.3
4.9
4.5
5.0
3.2
4.5
4.2
4.8
3.6
4.3
4.5
5.3
3.0
3.8
4.0
4.1
2.4
Excess
Air,
%
26
27
30
25
26
16
27
27
30
16
26
25
30
17
26
26
31
16
25
25
27
15
Bacharach
Smoke No.
2.4
0.2
0.6
2.3
3.0
0.1
2.0
3.1
4.2
0.0
0.2
2.9
5.0
0.0
0.0
2.5
3.8
0.1
0.4
3.4
4.1
0.0
Emissions
Gases, ppm
CO
14
51e
4.0
2.0
0
1.0
0
2.0
9.0
5.0
0
0
0
8.0
0
0
5.0
67
0
0
0
0
HC
1.5
35e
0.5
—
-
0.3
3.0
1.2
3.2
1.0
1.8
5.3
3.7
3.0
2.6
1.0
1.0
8.0
4.7
6.2
4.2
3.2
NO
61
71e
75
247
257
93
70
189
250
113
103
251
291
47
125
238
29?
63
IH 4
210
283
95
NOX
62
75e
74
251
257
94
70
190
250
116
104
249
295
50
127
243
301
65
123
208
266
95
S02
142
Oe
140
900
520
0
86
520
1150
0
102
500
1160
0
180
550
930
0
86
520
660
2
Paniculate",
mg/sm3
Filterable
11.0
5.2e
11.3
39.9
106
4.8
15.9
292
738
10.0
15.8
73.7
144
7.7
10.8
49.0
108
8.1
6.6
71.0
246
7.2e
Total
50.1
18.0e
22.7
57.5
122
15.5
29.6
313
762
24.5
24.9
110
210
13.4
43.1
74.6
160
23.0
20.8
99.9
297
14.8e
(a) Base-line condition is 80 percent and 12 percent C02 (10 percent CO2 for gas firing).
(b) See Table 111-2 for descriptions of boilers.
(c) Firing rate is 10^ cfh for gas firing.
(dl Paniculate by modified EPA procedure.
(e) Emission data at 9.0 percent CCb.

-------
                                                   111-10
           Table 518-4.  Summary of Emission Factors for Commercial Boilers
Emission Factors, ib/1000 gal°
Commercial
Boiler b
C2001

C2002



C2003



C2004



C2005



C2006



Fuel
Grade
No. 2
Gas
No. 2
No. 4
CR
Gas
No. 2
(CR
No. 6
Gas
No. 2
CR
No. 5
Gas
No. 2
CR
No. 6
Gas
No. 2
CR
No. 6
Gas
Bacharach
Smoke No.
2.4
0.2
0.6
2.3
3.0
0.1
2.0
3.1
4.2
0.0
0.2
2.9
5.0
0.0
0.0
2.5
3.8
0.1
0.4
3.4
4.1
0.0
Gaseous Emissions
CO
1.7
6.6e
0.5
0.3
0.0
0.1
0.0
0.3
1.3
0.6
0.0
0.0
0.0
1.0
0.0
0.0
0.7
7.8
0.0
0.0
0.0
0.0
HC
0.11
2.606
0.04
-
-
0.02
0.21
0.09
0.25
0.07
0.13
0.40
0.29
0.2C
0.18
0.08
0.08
0.54
0.33
0.46
0.33
0.21
NOX
12.5
16.0s
15.7
53.2
55.3
18.2
14.4
41.2
56.9
22.4
21.0
53.7
67.0
9.8
25.6
52.4
70.2
12.5
24.6
44.9
59.2
18.1
SO2
40.0
O.O6
40.8
265.6
155.8
0.0
24.6
156.8
364.3
0.0
28.6
148.9
366.8
0.0
50.4
165.2
301.8
0.0
23.8
154.6
?'"* 6
0.0
Participated
Filterable
1.2
0.6e
1.3
4.5
12.1
0.4
1.7
33.6
89.1
1.0
1.7
8.4
17.3
0.7
1.2
5.6
13.3
0.9
0.8
8.0
29.1
0.8e
Total
5.4
1.9e
2.5
6.5
13.9
1.5
3.2
35.9
92.1
2.5
2.7
12.5
25.3
1.3
4.6
8.5
19.8
2.2
1.4
11.3
35.1
1.6e
(a)  Base-line condition is 80 percent load and 12 percent CO2 (10 percent CO2 for gas firing).
(b)  See Table 111-2 for descriptions of boilers.
(c)  Emission factors for gas firing are given as an equivalent tharmal basis to Ib/1000 gal of oil.e.i., in lb/(145 x 108 Btu).
(d)  Paniculate by modified EPA procedure.
(e)  Emission factor at 9.0 percent C02-

-------
                                           III-l 1

        CO and HC emissions are generally low except for occasional gas-fired runs, particularly
 for Boilers C2001  and C2005. The reason for these occasional  high emissions  is  not evident
 and it is not reflected in smoke  number, as the smoke was very low for all gas runs listed in this
 table. SO2 emissions  are  related  directly to  fuel sulfur and are relatively unaffected by combus-
 tion conditions.

        The emissions that are  affected by  boiler design or  operation  (namely,  NOX, smoke,
 and particulate) are of prime interest and are discussed separately below.

 Influence of Various Parameters
 on NOX  Emissions

        NOX emissions from combustion sources are known to be generated by two processes —
 oxidation of organic  nitrogen bound  in  the  fuel  and  by thermal  fixation of nitrogen in the
 combustion air  in the furnace environment.  Hence, NOX  emissions  are related to nitrogen
 content  of the fuel1 °'11, combustion  temperature, and the relative competition for oxygen atoms
 (i.e., whether conditions are oxidizing or reducing and to what extent12. Therefore, it is useful
 to examine the influence on NOX  emissions of fuel nitrogen  and the  major  factors which
 influence combustion temperature and oxygen  availability (such as load and  excess  air). The
 effect of these factors on NOX  emissions was investigated in this  program and the results are
 discussed below.

        In addition to considering the influence of the obvious parameters on  NOX emissions, a
 regression analysis  was  used  to determine  the best equation relating  the NOX  data for the
 base-line condition to additional fuel and equipment variables. Variables included in this analysis
 were as  follows:
             Fuel Variables                                     Boiler Variables
     Fuel nitrogen, N                              Firing rate
     N1 /2                                         Combustion volume
     API gravity                                   Combustion intensity, CI
     Specific gravity                                (firing rate per  unit combustion volume)

     Carbon residue (Ramsbottom)
     Viscosity at firing temperature, V (SSU)
     Carbon content;  C
     Hydrogen content, H
     C
     H
     C
     N
       C
     H+N
       , G. B., and Berkau, E. E., "An Investigation of the Conversion of Various Fuel Nitrogen Compounds
  to Nitrogen Oxides in Oil  Combustion", presented at AIChE Meeting, Atlantic City, N.J., August 30,  1971.
^Turner, D. W.,  Andrews,  R. L., and Siegmund, C. W., "Influence of Combustion Modification and- Fuel
  Nitrogen Content on Nitrogen Oxides Emissions From Fuel Oil Combustion", presented at AIChE Meeting,
  San Francisco, November 28-December 2, 1971.
12Bartok, W., Crawford, A. R., Cunningham, A. R., Hall, H. J., Manny, E. K., and Skopp, A., "Systems Study of
  Nitrogen Oxide Control Methods for Stationary Sources", Final Report, Esso Res. & Engrg. Co., November  20,
  1969, NAPCA Contract PH-22-68-55.

-------
                                           Ill- 12

The best equations that could be fit to the NOX data using these variables were as follows:

       Using only one variable
              NOX (ppm at 3 percent O2) = 89.97 + 834.7-N (percent)

       Using more than one variable
              NOX (ppm at 3 percent O2) = 9.10 + 579.2-N (percent) + 0.373-V (SSU) + 101.3-CI
              (Btu/ft3).

The correlation  of  NOX  with one variable,  N, was 0.81. The correlation  coefficient  obtained
using the three variables listed in the above equation was 0.85.

       Correlation coefficients with  NOX emissions obtained when each  of the above  listed
variables was considered are as follows:

                                                            Correlation Coefficient
                          Variable                              (Absolute Value)
       Fuel nitrogen, N                                               0.81
       Ny"                                                            0.79
       API Gravity                                                    0.77
       Specific gravity                                                0.77
       Carbon residue, Rarnsbottom                                    0.73
       Hydrogen content, H                                           0.71

       I                                                             °-70

                                                                     °-69
                                                                     °-63
       Viscosity at firing temperature, SSU                             0.62
       Carbon content, C                                             0.45
       Firing rate per unit combustion chamber volume                 0.42
       Firing rate                                                     0.10
       Combustion chamber volume                                    0.07

 It  should be  noted  that  the correlation coefficients were  higher  for  all the  fuel variables
 considered than for the boiler-related variables. Thus, either the fuel  is the significant factor in
 NOX formation (which is  certainly true for NOX  formed  from  fuel nitrogen) or  the  most
 appropriate boiler variables  were not considered (true  to  the extent that flame  characteristics
 were not available).
        NOX  and Fuel Nitrogen, Due to the complexity of NOX  emissions (with the therm al NOX
 varying  from boiler to boiler and the fuel NOX  varying  from fuel to fuel), several different
 approaches were used to examine the relationship of. NOX and fuel nitrogen.

        Figure III-2 shows  the measured  NOX emissions  plotted against  fuel nitrogen for all
 Phase I and II runs firing fuel oils in  commercial boilers at the base-line conditions (80 percent

-------
                                   111-13
600
500
400
30O
200
100
            0-1
                       02        0.3       04        0.5
                          Nitrogen in Fuel,weight percent
                                                               0.6
                                                                         0.7
  Figure HI-2.  Relation of NOX to Fuel Nitrogen for Phases I and II,
                Commercial Boilers Fired at Base-Line Conditions

-------
                                          Ill-14

load and  12 percent excess air). Except for a few  data points,  a strong relationship is evident
between NOX emissions and fuel nitrogen. The curve obtained from  the regression analysis (with
one  variable  term)  described  above  is  also  shown  in  Figure  II1-2.  This curve has  a slope
equivalent to a 65 percent conversion of fuel nitrogen to NOX.*

       Figure HI-3 shows the relationships between  NOX emissions and fuel nitrogen  for each of
the six boilers included in the Phase I and II studies  that were  fired with more than one fuel.
The slopes of these curves are generally similar to the slope of the line showing a conversion rate
of 60  percent of the fuel nitrogen  to NOX. No correlation is evident between the  shapes of the
curves and/or the zero-fuel-nitrogen  intercepts and  the boiler variables, such as firing rate  or
combustion intensity.

       To  obtain a better understanding of the influence of fuel  nitrogen on NOX emissions, the
following  analysis was performed using data for boilers in which No. 2  fuel oil  (a low nitrogen
fuel)  and heavier  oils were fired. The  thermal NOX for each boiler was estimated by assuming
100 percent conversion of all fuel nitrogen from firing of No. 2 fuel oil and subtracting this fuel
nitrogen term from the NOX measured when  firing No.  2 fuel  oil. The fuel nitrogen term for
each boiler and fuel combustion was estimated  by subtracting the  thermal NOX term for that
boiler  from  the measured  NOX value.  The fuel  nitrogen components were plotted against fuel
nitrogen, see Figure HI-4, and a curve was drawn to fit the data by eye. The best  curve to fit the
data was  of the form NOX (ppm)  = Thermal NOX  + 420-N0 -6.  The overall thermal NOX term
was estimated by averaging  the thermal NOX terms for each boiler: the average value is 97 ppm.
Hence, the  best estimate of NOX from the  Boilers C2001  through C2006 (the boilers in which
No. 2  and heavier fuel oils were fired was:

                                NOx, ppm=  97 +420 N°-6

(In the range of fuel nitrogen from 0.0 to 0.06  percent, this equation predicts  NOX from fuel
nitrogen that exceed 100 percent conversion of fuel nitrogen but  the maximum error is about  10
ppm,  less than the variation in thermal NOX from one boiler to another.)
       NOX and Excess Air. Figures III-5 through III-10 show the sensitivity of NOX emissions
to excess air for all fuels and boilers at 80 percent load, NOX emissions are expressed in lb/106
Btu for these figures, as this is the most meaningful value  when comparing widely varying fuels:
e.g., natural gas and No. 6 fuel oil.

       Examination of the relationship of NOX  to excess air, shown in  Figures III-5 to 111-10,
suggests  that NOX tends  to be  relatively  constant  or increases  slightly  with  excess  air.
Apparently, the increase in oxygen concentration promotes NOX  formation to a greater degree
than the increased  excess air tends to cool the flame. In nearly all cases, the  variation  of NO
with excess air within  the normal range of excess air — 15 to 30  percent  — was 12 percent or
less. (The exceptions were firing No. 4 fuel oil  and  the CR  reference fuel in Boiler C2002, where
the variation of NOX with excess air was large inthe 15 to 20 percent excess air range.)

       It is interesting to  compare the NOX emission shown  in Figures III-5 to III-10 with the
EPA standards for NOX emission from new fossil-fuel  power plants2. These  standards  permit
NOX emissions of 0.20 lb/106 Btu for gas-fired boilers and 0.30 lb/106 Btu for oil-fired boilers.
From the commercial  boilers and fuels examined, these .standards were met  in each case for
No. 2 fuel oil and gas  firing. Conversely, for each boiler the NOX emission standard for oil firing
could not be  met  when firing conventional No. 5 or  6 fuel oils. When  firing the commercial

*One percent fuel nitrogen converted to NOX yields about 1280 ppm of NOX at 3 percent O2.

-------
                               111-15
    450
    400h
    350h
 
-------
                                       Ill-16
400
             O.I
                         0.2
 0.3        0.4         0.5
Fuel Nitrogen,percent
                                                                      0.6
                                                                                 0.7
 Figure 1H-4.  Relationship of NOX from Fuel Nitrogen to Fuel Nitrogen for Boilers
              Firing No. 2 and Heavier Fuel Oils

-------
o*

-. 025
c
o
3
u>

m 0 20
                           Gas
                          I	I	I	I	I	I
            10      2O      30
                                 40      50
                               Excess Air, percent
                                                                      00 0.35
                                                                      "o
^ 0.30
a.
3

B 025


I

6 0.20

ox
                                                                                                        CR Oil
                                                                                              Gas
                                               60      70     80     90      0      10     20     30
                                                                                                             J	I
                                                                                                                                  J	I
                                40     50     60
                                   Excess Alr.percent
                                                                                                                           70     80     90     100
          Rgure III-5.  Relation of NOX  Emissions to Excess Air for
                        Boiler C2001 at 80 Percent Load
          Figure III-6.  Relation of NOX  Emissions to Excess Air for
                        Boiler C2002 at 80 Percent Load
                        40-bhp Cast Iron Boiler.
                        90-bhp Cast Iron Boiler.

-------
  0.60
i 0 30
(A
S

£
S 0.25
                               NO. 6 Oil
  005
                               Gas
            10     20     30
                                10     50     60
                               Excess Air,percent
                                                     70      80     90
                                                                          :, 035
                                                                         S
0* 030
                                                                                                           No. 5 Oil
                                                                                                   CROil
                                                                                                   No, 2 Oil
                                                                                     10      20      3O
                                 40     50
                               Excess Air, percent
                                                                                                                                                  00
                                                                                                                              TO     8O     90
       Figure III-7.  Relation of NOX  Emissions to Excess Air for
                     Boiler C2003 at 80 Percent Load
    Figure III-8. Relation of NOX Emissions to Excess Air for
                 Boiler C2004 at 80 Percent Load
                     300-bph Scotch Boiler.
                  80-bhp Firebox Boiler.

-------
  040

S
•a
  0,5
 e

 .a
          J	L
                           No. 6 Oil
                      30    «    50     SO

                          Excess Air, percent
                                             J	L
                                              70     80    §0
                                                                           lit
                                                                           o"
                                                                                                   No. 6 Oil
                                                                                                      J	L
                                                                                                                        J	L
            10     20     30     <*O     50    50    70    60    90
                           Excess Air, percent
     Figure III-9.  Relation of NOX  Emissions to Excess Air for
                   Boiler C200S at 80 Percent Load
Figure 111-10.  Relation of NOX Emissions to Excess Air for
               Boiler C2006 at SO Percent Load
                   100-bhp Scotch Boiler.
               600-bhp Watertube Boiler.

-------
                                          HI-20

reference fuel, CR,  the  standard could be attained at  low excess air levels in some boilers but
could not be attained in  other boilers.
       NOX  and  Load.  Figures  III-l 1  through 111-16  show  the  relationship  between  NOX
emissions and load for each boiler and  each  fuel for the nominal  12 percent CO2  condition.
Load does not seem to be a critical factor influencing NOX emissions. For most boilers, the NOX
emissions were relatively constant over the  range of load investigated. Boilers C2002 and C2003
exhibited a trend  of NOX  increasing with load for the heavier fuels. NOX emissions from Boiler
C2005 were quite  high at low load.
       NOX  for Gas Firing. As expected, gas firing of the commercial boilers produced relatively
low NOX  emissions. The NOX emissions from boilers fired along the East Coast (Boilers C2001,
C2002, and C2003 were located in New England and Eastern Pennsylvania) averaged 99 ppm at
3  percent  O2. NOX emissions from  boilers in the Midwest (Boilers C2004, C2005, and  C2006
were located within 200 miles of Chicago) averaged 70 ppm.

       It  is interesting  to compare NOX emissions for gas firing with those for firing with No.  2
fuel oil, as shown in Table III-5. For the boilers located in the East,  the NOX from gas firing
exceeded  that from No. 2 fuel  oil. Conversely,  in  the boilers located in  the Midwest, the NOX
from firing No.  2 fuel oil exceeded that from gas.  The fuel nitrogen levels of the No. 2 fuel  oils
fired in the Midwest were  slightly higher than those for oils fired  in the East. However,  the
difference would only account for 3 ppm at a conversion efficiency of 100 percent.
                Table 111-5. NOX Emissions for Phase II Boilers Firing Natural
                           Gas and No. 2 Fuel Oil
                                  NOX Emissions, equivalent ppm at 3 percent
                                          Oj and 80 percent load
Boiler
C2001
C2002
C2003
C2004
C2005
C2006
Gas
84
95
117
51
65
95
No. 2 Fuel Oil
67
85
77
114
138
134
N Content
No. 2 Oil, percent
0.0084
0.0084
0.0078
0.0113
0.0124
0.0086
       The  relative differences in NOX emissions from gas- and  oil-fuel boilers in the  East and
Midwest  may be  attributable to different burner adjustment practices in the two regions or some
other subtle variable(s).

-------
                                             111-21
    O.60
    0.55
    0.50
    0.45
 S  0.40
"o
 O™ 0.35
 z
 (A
 2,

 §  0.30
 jj
 (A*
 .2  0.25

 1
 UJ
 o" 0.20
    0.15
     0.10
    0.05
                                                                Gas (9 % COZ)
                                                               _     c
                                              I
                                                     I
               10
                      20
                              30
                                     40
 50     60
Lood, percent
                                                            70
                                                                    80
                                                                           90
                                                                                  100
                                                                                          no
    Figure III-ll.  Relation of NOX Emissions to Load for Boiler C2001 at  12 Percent CO2

                   40-bhp Cast Iron BoUer.

-------
                                             111-22
    0.60
    0.55
    0.50
    045
 £  0.40

"Q
 -^
 d* 0.35
§  030
-Q

tf>
'E
bJ
O  0.20
z

    0.15


    0,10


    0.05
               10
                                                                    4 Oil
                                                                 Gas (10% C02)
                                                                      No. 2 Oil
                                                      1
                       20     30
                                      40
                                              50      60
                                              Load, percent
                                                             70
                                                                    80      90      100     110
    Figure III-12.  Relation of NOX Emissions to Load for Boiler C2002 at 12 Percent CO2
                   90-bhp Cast Iron Boiler.

-------
                                             111-23
    0.60
    0.55
    0.50
    0.45
 S  0.40

"2
 "•x

 5- 0.35
 §  0.30
 .0
 %  0.25
 .<£
 €
 LU

 C? 0.20
    0.15
    0.10
    0.05
   No. 6 Oil
                                                            Gas (a1 10% C02)
I
                                       I
                                               I
I
                                                              I
I
I
                                                                                 This point at
                                                                                 13.2% C0e
I
               10     20     30     40      50      60      70     80      90      100     110
                                             Load, percent
   Figure 111-13. Relation of NOX Emissions to Load for Boiler C2003 at 12 Percent CO2

                  300-bhp Scotch Boiler.

-------
                                         111-24
   0.60


   0.55


   0.50


   0.45


£ 0.40

C
O* 0.35
8
g 0.30
.o
vt
I 025
.<£
LJ
cT 0.20


    0.15


   0.10


   0.05
                                                         No.  5 Oil
                                                     No. 2 Oil
                                                      Gas(otlO%C02)
                                          I
                                                J
           10      20      30
                                 40
                                         50     60
                                       Load, percent
                                                           70      80      90     100     110
Figure 111-14.  Relation of NOX Emissions to Load for Boiler C2004 at 12 Percent CO2
               80-bhp Firebox Boiler.

-------
                                           111-25
    0.60
    0.55
    0.50
    0.45
 £  0.40
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    0.10
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               I
                                                     No. 2 Oil
Gas (at 10% C02)
                                     J	I	I	I
                  J	I
I
       0      10      20      30     40      50     60      70     80      90     100     110
                                            Load, percent


   Figure 111-15.  Relation of NOX Emissions to Load for Boiler C2005 at 12 Percent CO2

                  100-bhp Scotch Boiler.

-------
                                            111-26
    0.60







    0.55







    0.50







    0.45







 £  0.40


"o



 &  0.35


 tn
 _D



 §  0.30

 -O





 •I  0.25
UJ
   0.20
    0.15
    0.10
   0.05
               I
                                                         No. 6 Oil
                                                         CR Oil
                                                        No. 2 Oil
                             J	I
                                                    J	I
                                                                    I
                                                                                   I
              10      20     30      40     50      60     70     80      90     100     110

                                           Load, percent
   Figure 111-16.  Relation of NOX Emissions to Load for Boiler C2006 at 12 Percent COa



                  600-bhp Watertube Boiler.

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                                          IH-27

Influence of Operating Condition on
Smoke. CO, and  HC Emissions

       In this  program, two parameters were  examined that  defined operating conditions  -
excess air and  load. The following discussion presents results showing the influence of each of
these parameters  on smoke, CO, and HC emissions. (Their influence on NOX emissions was
described earlier.)

       Excess Air. Figures III-17 through 111-22 show the relation of smoke and CO emissions to
excess air for each fuel fired hi each boiler at 80 percent load. HC emissions are not shown on
these figures, as they were nearly always low; when high HC emissions were measured, the CO
emissions were also high. Hence, CO  was selected to illustrate emission trends for both CO and
HC.

       Figures 111-17 through  111-22  show  that  about  30 percent excess air is required to fire
most fuel oils hi  the Phase II boilers to avoid smoke levels above about Bacharach No. 2 or 3. In
a few cases (No.  6 fuel oil in boiler C2003 and No.  5 fuel oil  in boiler C2004), the smoke
remained high even at excess air levels above 30 percent.

       Gas  could generally be fired at 10 percent excess air  without exceeding a No. 1  smoke
level. However, 20 percent excess air  generally was required  to avoid high levels of CO emissions.

       Smoke Number as an Indicator of CO and HC Emissions.  Examination of the curves of
smoke, CO,  and  HC  emissions plotted  against  excess  air* shows that,  as the  excess air was
decreased for  oil-fired  boilers, the  smoke level tended to  increase before  the CO and HC
emissions increased. However,  as the excess ah- was decreased for  gas-fired boilers, the CO and
HC emissions generally increased before the smoke level increased. Hence, setting the excess air
for an oil-fired boiler by smoke number  will tend to keep CO and HC emissions at a minimum.
Conversely,  setting the excess  air level by  smoke number  for  gas-fired boilers does  not insure
minimum CO and HC emissions.

       Load. Generally, load did not significantly influence emissions of CO  and HC. For two
boilers (C2003 and C2004), smoke tended to increase as load  was decreased at constant  CO2.
For the remaining boilers, changes in load did not significantly affect smoke.

       Based on  conversations  with commercial boiler/burner specialists - namely, members of
the ABM A Commercial-Industrial Air Pollution Committee -  it  was determined that commercial
boilers generally operate most of the time at one  of two loads  — a high load of about 80 percent
of rated load and  a low fire condition.  Once a boiler is in service,  the serviceman is likely to
adjust the burner to produce low smoke at these two normal operating conditions. Hence, the
influence of load on smoke (and to a lesser extent, CO and HC) may be  an indication of how
that  particular burner  was adjusted, rather than a general measure of the  capabilities of the
boiler/burner combination. Burners  frequently are adjusted to operate at higher excess air  levels
at low load than at the normal  high load.
Influence of Fuel on Smoke Emissions

       Notwithstanding the fact that this study has been the most extensive field investigation
ever conducted of  emissions from  residential units and commercial boilers,  there are relatively
"These curves — for each boiler, fuel, and load — are presented in Appendix H as the Data Supplement Volume.

-------
I
2  4
s
g

-------
                                                                    .2  0.150
                                                                    in
                                                                    'i
                                                                          0    10   ZO   50
                     Excess Air.percent
                                                                                             40   50   60
                                                                                               Excess Air.perccnt
                                                                                                            70   90   90   100
Figure 111-18. Relation of Smoke and CO Emissions to Excess Air for Boiler C2002 at 80 Percent Load


               90-bhp Cast Iron Boiler.

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           10       20
                            30       40
                           Excess Air,percent
                                                     60       70
                                                                      0.300
                                                                      0.250 —
                                                                    •£ 0 150

                                                                    I
                                                                    UJ

                                                                    g 0.125
                                                                                          No.6 Oil
                                                                                                  No. 2 Oil all values
                                                                                                  were zero
10    20    30    40    50
          Excess Air.percent
Figure 111-19.  Relation of Smoke and CO Emissions to Excess Air for Boiler C2003 at 80 Percent Load


                300-bhp Scotch Boiler.
                                                         1=1
                                                         T1

                                                         O

-------
                                                                 •fe 0.173

                                                                 XI



                                                                 0 0-150



                                                                 E
                                                                 Ul
                                                                 _ 0-125
                     40       30

                   Excess Air,percent
10    20    30   4O    50    6O    70    80   90    IOO

                 Excess Air,p«rcent
Figure 111-20.  Relation of Smoke and CO Emissions to Excess Air for Boiler C2004 at 80 Percent Load


                80-bhp Firebox Boiler.

-------
                                                                    0    10    2O   30   40   50   6O    7O
                                                                               Excess Air, percent
                          30      40
                        Excess Air, percent
                                                       TO
Figure ffl-21.  Relation of Smoke and CO Emissions to Excess Air for Boiler C2005 at 80 Percent Load

               100-bhp Scotch Boiler.

-------
                         30     40

                      Excess Air, percent
u.^uv
O.275
O.25O
0.225
0.200
3
£
"g 0-175
« 0.150
.a
1 0125
8
0.100
O.075
0.050
0.025
0
-
-
-
	
-
Gas
i
_
CROil





No. Z Oil


1 No. 6 Oil
W\ 1, .0 . • . 1, 1
                                                                            10    20    30   40

                                                                               Excess Air, percenl
                                                                                                                            UJ
                                                                                                                            OJ
Figure 111-22.  Relation of Smoke and CO Emissions to Excess Air for Boiler C2006 at 80 Percent Load


               600-bhp Watertube Boiler.

-------
                                          111-34

few  data available from  this program,  considering the  large number of variables  that might
influence emissions.  However, examination of the  relationship  to emissions of the fuel variable
considered most likely to correlate with emissions was valuable. It was decided that API gravity
is probably the best readily available single property by which the combustion characteristics of
fuel  oils can be classified. Therefore, several  trials were made at  correlating emissions with API
gravity of the fuels.


       Figures  IH-23 and 111-24 show relationships between Bacharach smoke number and API
gravity. Figure  IH-23 summarizes data for all Phase I and  II boilers for runs at the base-line
condition.  Figure  111-24 shows the relationship separately  for each Phase II boiler. Both figures
reveal  that  smoke generated at the 80 percent load,  12 percent CO2 base-line firing condition
increased as the API gravity of the fuel decreased.
           8
                      Legend
                o Phase I boilers
                A Phase H boilers
                                  20                     30
                                   API Gravity at 60 F
40
        Figure IH-23.  Relation of Fuel Gravity and Smoke Number for the Commercial
                      Boilers Operating at 80 Percent Load and 12 Percent CC>2

                      Phases I and II Boilers.

       Figures III-17  through 111-22 show that the heavier  fuel oils generally tended to produce
greater smoke over the entire range of CO2 investigated.

       All  smoke spots obtained from  firing the reference fuel, CR,  were yellow in appearance.
The  coloration was not  attributable to unburned fuel,  but was assumed to result  from com-
pounds formed from trace metals in the fuel.

-------
                                     111-35
                                                           •  Boiler CI002
                                                           o  C2002
                                                           x  C2003
                                                           +  C2004
                                                           A  C2005
                                                           A  C2006
O
E
.
o
o
o
o
o
m
                                                         C2003
                             I
    10
15
20          25
    API Gravity at 60 F
                                                     30
                                                 35
40
       Figure 111-24. Relation of Bacharach Smoke No. and API Gravity for Oil Firing
                   of Phase II Commercial Boileis for 80 Percent Load and
                   12 Percent CO2

-------
                                           111-36

 Factors Influencing Particulate Emission

       A regression analysis was used to determine the best equation relating filterable emissions
 to  the same fuel and  boiler characteristics  as considered for the NOX  correlation (see page
 111-12). The  equation that resulted was

       Filterable   particulate  (lb/1000  gal)   =  884.6  +  9.099  Carbon  residue  (percent,
       Ramsbottom) - 0.120 • Viscosity (SSU) - 10.88 • Carbon content (percent) +  1.77 • API
       gravity

 This   equation  gave  an  0.86  correlation with  the  filterable  particulate  data.   Correlation
 coefficients  with  particulate emissions obtained when each variable was considered separately are
 as follows:

                                                       Correlation Coefficient
                             Variable                     (Absolute Value)

                 Carbon residue, Ramsbottom                    0.68
                 Fuel nitrogen, N                                0.62
                 N%                                            0.57
                 Specific gravity                                0.55
                 API gravity                                     0.55
                 Carbon content, C                              0.52
                 Hydrogen content, H                           0.44

                 g                                             0.43

                 H                                             0.40

                   C                                            0.33
                 H+N
                 Viscosity at firing temperature, SSU            0.25
                 Firing rate                                    0.21
                 Firing rate per unit combustion                 0.14
                   chamber volume
                 Combustion chamber volume                   0.05
Figure 111-25  shows the filterable particulate emissions plotted  against carbon residue and the
curve that  correlated at the  0.68 level. As for the NOX emissions, filterable particulate emissions
correlated better with fuel  characteristics than with boiler characteristics.

       Figure 111-26 shows the relationship  of  filterable and total  particulate to API gravity for
each of the Phase II boilers at 80 percent load  and 12 percent CO7. As might be expected, each
Phase II boiler showed increasing particulate emissions for heavier fuels. However, the range  of
emissions obtained when firing fuels of similar gravities in different  boilers was large. Thus,  boiler
and/or  burner characteristics  may  have as  much or  more  influence on emissions  than fuel
properties.

-------
  too
                                            111-37
•8 «o
                                                                                    10       II
       Figure 111-25.  Correlation of Filterable Particulate Emissions With Carbon Residue




                      Participate Emissions by Modified EPA. Procedure.

-------
S 50
                 20      25      30      35     40
                     API , groi/ily
                                                           S.



                                                           I.
20      25
    API, gravity
                                                                                          3O      55      40
    Figure 111-26. Relation of Participate Emissions to Fuel API Gravity for Base-Line Conditions

                  Particulate emissions by modified EPA procedure.
                                                                                                                             00

-------
                                           111-39

       Relation of Particulate Emissions  to Load. Figure 111-27 shows the change in filterable
particulate emissions with load for each Phase I and  II boiler and  fuel where data at two loads
are available.  In  general, increasing load  did not significantly affect filterable particulate emis-
sions, except for firing of No. 6  fuel oil. For the four boilers fired with No. 6  fuel oil, emissions
showed a substantial increase with increasing load. Particulate emissions increased  from 0.15 to
1.3 lb/1000 gal for each 1 percent increase in load over the range for which data are available.
Trial Correlation of Smoke Versus
Particulate Emissions

       Figure  111-28  shows  the relationship  of filterable  particulate  (as  determined by the
modified EPA procedures) to  smoke number for each Phase II boiler at the base-line condition.
It must  be pointed out that the  fuel varies for each point on each boiler curve. Hence, several
variables are  included in these  plots and the relationship of particulate emissions to smoke should
be examined further.

       These data appear to  provide  a better correlation between smoke number and particulate
for  the  commercial boilers than the residential unit  data in  that, for each boiler, particulate
emissions increased with smoke number. This may relate to larger spread in particulate emissions
for  the  commercial  boilers or,  more  likely, to the  fact that the particulate samples for the
commercial boilers were taken under steady-state conditions, whereas the samples for residential
units included start-up and shutdown during cyclic operation.
 Particle Size Measurements

       Emission samples were collected from  Boilers C2005 and C2006 during operation with
 the low-sulfur reference fuel (CR) at 12.1 percent CO2, 78 percent load and  12 percent CO2, 80
 percent load, respectively.
       Procedure.  Sampling was  performed isokinetically at the center of each stack using the
 Battelle  cascade impactor. The impactor classifies particles in the range of 0.25 — 16.0 microns
 into 7  size categories. For the sampling done for this study, a 5/8-inch-diameter sample probe
 about  20 inches in length (from probe tip to impactor inlet) was used. It had a 90 degree, 6-inch
 radius bend such  that the probe  tip pointed upstream. The impactor was operated  horizontally
 and was heated  to stack gas  temperature (about 400 F) prior to probe insertion in the stack.
 Sampling at  12.5  liters per minute  was initiated  immediately on probe insertion into the stack.
 Sampling times for Boiler C2005 were 0.5, 1,  2,  5, or 10 minutes and for Boiler C2006 were 1
 and 2 minutes. After sampling, the impactor  slides  were removed immediately and returned to
 the laboratory for weighing.

       The impactor  slides were covered with a disk of silver membrane material so that the
 entire  glass slide  did  not have to  be weighed. The possibility of weight  change of the  silver
 membrane filters by reaction during the sampling operation was calibrated by baseline measure-
 ments  made with an all-glass  filter placed in-line ahead of the impactor. In these calibration runs
 no  particles were  collected  in  the impactor and the small weight changes of the silver substrates
 provided corrections for use during particle size measurements.

-------
60
50
                     Fuel

                   O  No. 2

                   X  No. 4

                   +  No. 5

                   •  No. 6
                                          111-40
                                    40       50       60
                                      Boiler Load, percent
          Figure 111-27.  Effect of Load on Filterable Particulate Emissions From
                        Phases I and II Commercial Boilers
                        Particulate Emissions by Modified EPA Procedure.

-------
                                m-4i
IOO
 90
• C200I
O C2002
X C2003
+ C2004
A C2005
  C2006
                                3        4
                            Bacharock Smoke Number
   Figure 111-28.  Relation of Filterable Particulate and Smoke Numbers
                 for Commercial Boilers

                 Particulate Emissions by Modified EPA Procedure.

-------
                                           \ll-42

       Results.  The  weights  of particles collected  on  each stage provided the basis for size
distribution determinations, and the total particulate weight collected in the impactor provided a
measure  of the  particulate emission rate. The small  quantities of particulate collected  indicated
that sampling times of five  minutes or more were  required for reliable  results. This situation
resulted  in  discarding the 1  and  2-minute  samples  for  Boiler C2005 and both samples (1 and
2-minute) taken from Boiler C2006.

       The results for particule size distributions measured for the 5  and  10-minute sampling
periods for Boiler C2005 are  shown in Figure 111-29. It  can  be  seen  that the agreement for the
two samples is reasonably good with the mass mean size of the particulate emissions estimated to
be  about 0.5 micron  for both. As the particle  masses  collected were  near  the lower limit of
sensitivity  for the balance, these  data must be  considered  as approximate. Improved weighing
techniques based on the experience gained in achieving these  approximate results would be likely
to produce data in which more confidence could be placed.

       The total weight of particulate collected in the impactor was used to estimate the mass
concentration of particles in  the effluent stack  gas. On this basis,  the particulate loadings for
Boiler C2005 were  calculated to be 38.4 and 43.1  mg/sm3 for the 5  and  10-minute sampling
periods,  respectively. These compare  reasonably  well  with the emission concentration of 44.6
mg/sm3  as determined independently with the EPA sampling  procedures.
 EMISSION FACTORS
       Emission  factors  published  by  EPA3  do  not provide  discrimination  relative  to  fuel
properties. Generally,  EPA fuel  categories are limited  to  "distillate oil"  and "residual  oil"  as
classes. Many industry observers believe that a finer discrimination of fuel properties needs to be
considered.  For example, the present  practice would include in the same  "residual" category
both  No. 6 fuel oil with 3 percent sulfur (API gravity about 15) and the newer low-sulfur heavy
oils being marketed on  the East Coast  (API  gravity about 24). However,  it is well known  that
these low-sulfur fuels are much easier to  fire (about like No.  4 fuel oil) and generally give much
cleaner combustion.
Emission Factors Related to API Gravity

       In recognition of the need  for finer discrimination  of fuel oils when  considering their
emission potential, a correlation was made of emissions relative to API gravity of fuels. Figures
111-30 to 111-33  show Phase I and II boiler-emission data at  the base-line conditions (80 percent
load and  12 percent C02) plotted against fuel gravity for CO,  HC, filterable particulate, and
total particulate  emissions.  These figures also show  the "best  curve" that could be fit to these
data by  a  polynominal  regression analysis  that utilizes least square procedures.*  It  is suggested
that, although considerable  scatter exists in the data, emission factors based on the API gravity
and  the curves shown  in  Figures  111-30  to  111-33 give the  best  available estimate of  likely
emissions from any one boiler firing any one fuel.
 *The curves were limited to second-order polynomials to avoid negative values and peaks.

-------
                                         III-43
en
c.
_

»•
_O
1
O
  99
  98

  95
  90

  80
  70
  60
  50
  40
  30
  20

  10
   5

   2
    I
 0.5
 0.2
 O.I
0.05
  0.01
                                     O 5 min  sample
                                     A 10 min  sample
     0.2   0.3  0.4
                       0.6 0.8   I           234
                               Particle Diameter, microns
                                                                    8   10
                                                                                 20
        Figure 111-29.  Particle Size Distributions for Boiler C2005 Firing the Commercial
                     Reference Fuel

-------
                                         111-44
   4.0
   3.5
   3.0
B  2.5


8
o
•v.
-O
§  2.0

in
in
O
U
   1.5
   1.0
   0.5
                                 4 points
                                           25

                                      API,gravity
                                                       30
35
                                                                                  30
                                                                                  25
                                                                                       CM

                                                                                      O
                                                                                  20
                                                                                      to


                                                                                      o

                                                                                      E
                                                                                      Q.
                                                                                      Q.
                                                                                   IE
                                                                                      D"

                                                                                      UJ

                                                                                      in


                                                                                      O

                                                                                      in
                                                                                      in
                                                                                   10
40
       Figure 111-30.  Relation of CO Emissions to API Gravity for Commercial Boilers
                     Equation for curve:  CO = 1.572-0.0278 (API)-O.OOOIS (API)2.

-------
                                           111-45
   1.4
   1.2
   1.0
§>
o
Q 0.8
in

O
£ 0.6
UJ

u
I
   0.4
                                                                                   20
                                                                                   ,5
                                                                                       c
                                                                                       4)
                                                                                       U
                                                                                       l_
                                                                                       0>
                                                                                       o.

                                                                                      ro
                                                                                       o

                                                                                       E
                                                                                       Q.
                                                                                       O.

                                                                                   10  -
                                                                                       a>
                                                                                       o
                                                                                       cr
                                                                                       c
                                                                                       o
                                                                                      O
                                                                                      I
   0.2
      10
                   15
                              1
                               20
     25          30
API, gravity
                                                                     35
40
       Figure 111-31.  Relation of HC Emissions to API Gravity for Commercial Boilers


                      Equation for curve:  HC = 0.439-0.0110 (API) + 0.00009 (API)2.

-------
                                        HI-46
            100
             90
             80
             70
          O
          O
          O
             60
          E
          LJ

          V
          •S  50
             40
                                            25
                                        API .gravity
Figure 111-32.  Relation of Filterable Participate Emissions (by Modified EPA Procedure)
              to API Gravity for Commercial Boilers
              Equation for curve = Filterable Participate = 100.5-5.75 (API) +

              0.0832 (API)2. This curve does not apply at API gravities above 34.5.

-------
                                    ni-47
        100
         90
         80
         70
         60
      £
      o
         50
         30
         20
         10
           10
                     15
20        25        30

      API, gravity
                                                            35
                                                                      40
Figure ffl-33.  Relation of Total Particulate Emissions (by Modified EPA Procedure)

              to API Gravity for Commercial Boileis
              Equation for curve:  Total Particulate = 106.2 - 4.96 (API) +

              0.0597 (API)2.

-------
                                           111-48

Suggested Emission Factors for
Commercial Boilers

       The curves presented  in  Figures HI-30  through HI-33  can form  the basis  for recom-
mended  emission factors to be used  in  emission inventories, where an  average emission level is
needed for developing total emissions  for oil-fired commercial boilers based on fuel usage.

       To establish values  for API gravity which  are  typical of different grades,  results  of an
informal survey of fuel  specialists on the API Task Force were combined with average values for
fuels encountered in this field investigation. The resulting values are as follows:

                                                           Typical
                                                        API Gravity,
                              Fuel Grade               degrees at 60 F

                      Distillate oil          No. 2             34
                      Conventional resid.    No. 4             22
                                           No. 5             17
                                           No. 6             14
                      New low-sulfur                          23
                       residual (1.0% S)
       Oil-Fired Boilers. Table III-6  shows the resulting emission factors which are suggested for
use in emission inventories applying to oil-fired commercial boilers. These factors are based on
emission measurements of 27 combinations of boilers and fuels, a fairly broad cross section of
conditions encountered in  the  field.  They should  be updated  as more comprehensive  data
become available, particularly to keep up with trends in fuels.
       Gas-Fired Boilers. Table HI-7 shows average  emission  factors obtained from firing seven
commercial boilers with natural gas.
       Emission  Factor  for  /VOX. Assuming  that  the  single variable  relating best  to  NOX
emissions was fuel nitrogen, it was determined that NOX emissions should not be  expressed  in
terms of API gravity. (However, for many fuel oils there is a  fairly strong relationship between
fuel  nitrogen and API gravity.) Hence, using the equation relating NOX to fuel nitrogen described
earlier (Page HI-14), NOX  emission factors were  calculated  for fuels  of various API gravities.
These results are included in Table  I1I-6.

       When fuel nitrogen data are lacking, the following values are suggested:

                            Fuel         Fuel Nitrogen, percent

                            No. 2                0.01
                            No. 4                0.2
                            No. 5                0.3
                            No. 6                0.4
                            LSR                  0.2

-------
                                                111-49
     Table 111-6.  Suggested Emission  Factors for Oil-Fired Commercial Boilers3
                                          Emission Factors, lb/1000 galb
 Fuel Grade3
 CO
               HC
                               NO..
                                                                    SO,
                                                 Filterable
                                                Participate
Suggested Emission Factors From This Study9
 No. 2
 Nq. 4
 No. 5
 No. 6
 LSRf
0.45
0.89
1.06
1.15
0.85
0.17
0.24
0.28
0.30
0.23
20 + 78 N°-6
20 + 85 N°-6
20 + 87 N°-6
20 + 89 N°-6
20+.84N0-6
142 S
154 S
159S
162S
153S
EPA Published Emission Factors3
  1,2
14.0
27.0
36.0
12.0
Distillate Oil
No. 2 0.20 3.00
Residual Oil
Nos. 4,5,6 0.20 3.00

40 to 80

40. to 80

142 S

157S

15.0

23.0
a These values are based on average emission data for the identified fuel grades having typical API gravity
  as follows: 34 degrees API for No. 2, 22 for No. 4, 17 for No. 5, 14 for No. 6, and 23 for LSR. Where
  actual API gravity is known, interpolated values should be used.
  To convert these values to emission factors in lb/10" Btu, multiply values shown by 0.0069. (The
  actual multiplier varies slightly with fuel grade, being about 0.0071 for No. 2 fuel oil and 0.0066 for
  No. 6 fuel oil.)
c N = multiplication factor equal to percent nitrogen in fuel.
  S = multiplication factor equal to percent sulfur in fuel. These emission factors were determined by
  calculation.  Measured S02 emission factors were within 10 percent of these values.
  Based on firing at 80 percent load and 12 percent COo-
  LSR:  low-sulfur residual oil (1.0 percent SI.
                     Table II1-7.  Suggested  Emission Factors for Gas-Fired
                                   Commercial Boilers
Emission Factors, lb/106 cu ft3
CO
HC NOX SO2
Filterable
Particulate
                            Suggested Emission Factors From This Studyb
                    17.7          3.7         103.          Nil            5.6

                                   EPA Published Emission Factors3

                                  8           100          0.6
20
                                                     19
                    a                                             fi
                      To convert these values to emission factors in lb/10  Btu,
                      multiply these values by 0.00098.
                      Based on firing at 80 percent load and 10 percent COj.

-------
                                           A-l

                                      APPENDIX A
     BACKGROUND DATA ON RESIDENTIAL OIL-FIRED EQUIPMENT POPULATION
       This appendix presents information on the current field population of oil-fired residential
heating equipment in the  United States by important characteristics, including firing rate, burner
and heating system type, and age of burner and heating system.
RESIDENTIAL OIL-BURNER EQUIPMENT SURVEY

       In the selection of residential units  for this investigation, pertinent historical data were
reviewed, including information compiled previously by Fueloil & Oil Heat magazine. To obtain
more comprehensive information not previously recorded in the industry, a questionnaire was
submitted to a large number of oil-burner service organizations through the statistical editor of
Fueloil & Oil Heat. The same questionnaire also was submitted directly to the members of the
API  SS-5  Task Force  and to a number of servicing  companies in major cities. The pertinent
portion of the questionnaire is reproduced as Table A-l.
Profile of Residential Oil heating
Equipment Population

       Tables A-2 through A-9  present information on the profile of oilheating equipment by
type, age, and geographic distribution.  The information was compiled and later published  by
Fueloil & Oil Heat4.

       The summary is organized in tables as follows:

           Table A-2 Firing Rates of Oil Burners in Use

           Table A-3 Oil Burners in Use, by Type

           Table A-4 Average Age of Oil Burners in Use, by Type

           Table A-5 Types of  Central Oilheating in Use, by System Type

           Table A-6 Average Age of Central Oilheating Equipment in Use, by System Type

           Table A-7 Combustion Chambers of Oil Burners in Use, by Type

           Table A-8 Oil Burners With Solenoid Valves

       A number of general observations and trends in residential oilheating equipment that can
be noted from these data include the following:

           •  Smaller size  burners, with firing  rates  of 1.35 gph and below, make
              up the majority (about 70 percent) of residential units.

           •  Gun  burners  (with conventional,  Shell, or  flame-retention heads)
              represent  a large majority of burners (about 84 percent).

-------
                                            A-2

            • High-turbulence  combustion  leads   (Shell  and   flame  retention)
              represent less than 20 percent of all gun burners.

            • The average age of all oil burners is  slightly over 12 years, about the
              same as for gun burners with conventional combustion heads. Average
              age of burners with high-turbulence combustion heads is only about 6
              years, while other types of burners (low-pressure, rotary, and vaporiz-
              ing units) average nearly 17 years.

            • Warm-air  furnace  and hydronic  systems (hot water and steam) are
              about equal in number.

            • In  spite  of the  increased popularity  of ceramic  fiber combustion
              chambers in recent years, refractory  brick combustion  chambers still
              outnumber the ceramic fiber  chambers by about four to one.

These  findings  are  familiar qualitatively to  those of  long-time observers  of the  oilheating
industry;  however, the statistics  contained  in this appendix provide more quantitative informa-
tion than  available previously.
Residential Unit Selection for Phase II

       Due to delays in receiving replies to the questionnaire, this information was not complete
in time for planning the details of the Phase II residential equipment investigation. Thus, to keep
this program on schedule it was necessary to rely on the previously published data to select units
for Phase II of this program,  as outlined in Chapter II.

       The composition  of the field sample, chosen  prior  to  the  comprehensive survey,  is
compared in  Chapter II to this profile of the  total field  population. The mix of units chosen for
the combined  program  of  Phases  I and II was generally  representative of the  total  U.S.
population of oil-fired residential  equipment.

-------
                                                   A-3

                                 Table A-1.  Sample Questionnaire
Battelle is doing some work for API and the Government on emissions of residential oilburners, and have asked
your help on sizes and  types of equipment in the field.  Please give us your best estimates or guesses about the
burners on your customer list.

     What percent of your residential No. 2 burners are fired at less than 1.0 gph	%; 1.0 to
     1.35 gph	%; 1.36 to 1.65 gph	%;  1.60 to 2.0	%; 2.01 to 3.0 gph	%;
     over 3.1 gph	%
     To further profile these existing burners, please fill in as much of the following data as possible:
                                                   Less than      1.0 to       Average
                                                    1.0 gph      3.0 gph         Age
           High Pressure*
                Conventional combustion head       	%     	%     	 years
                Shell  head                         	       	       	
                Flame retention head	
           Low Pressure**	
           Rotary Wall Flame	
           Vaporizing                               	       	       	
                                                    100%         100%
                    'Pressure atomizing (100 psi or greater!.
                   **Air atomizing.

     What percent of your customers have furnaces?	% What percent have gravity hot water?       '
     Have forced hot water with a tankless coil?	%  Forced  hot water without tankless coil?	"/,
     Have steam heat with tankless coil?	%; steam without tankless coil?	%

     What would you  guess would be the average age of your customers' furnaces?	years. What is
     the average age of your customers' boilers?	years.  What percent of your customers have space
     heaters?        %
                       Table A-2.   Firing Rates of Oil Burners in Use4





<1.0

1.0 to
1.35
Firing
1.36 to
1.65
Rate, gph
1.66 to
2.0

2.01 to
3.0

Over
3.0
Percent of Total
New England
Mid-Atlantic
South Atlantic
Midwest
West
19.6
24.3
51.8
44.6
75.4
43.9
39.7
29.8
27.1
14.2
12.8
17.8
9.3
12.8
5.9
8.9
8.6
5.7
8.8
3.3
7.0
5.7
1.6
4.4
0.9
7.8
3.9
1.8
2.3
0.3
        All Sections        34.6       34.7        13.9           8.0           4.9         3.9

-------
                                                A-4
                            Table A-3.  Oil Burners in Use  by Type
                                                                    13


High Pressure
Shell
Conventional Head

Retention
Head
Low
Pressure
Rotary
Vaporizing
Percent of Total
Less Than 1.0 gph
New England
Mid-Atlantic
South Atlantic
M idwest
West
All Sections

New England
Mid-Atlantic
South Atlantic
Midwest
West
All Sections
44.9
66.3
74.8
63.0
80.3
63.1

61.4
69.0
89.4
73.3
80.3
71.2
7.2
8.4
1.9
9.4
0.6
7.2

7.9
5.2
2.3
13.1
0,6
6.9
14.7
3.8
13.0
13.1
5.2
9.1
1.0 to
13.6
8.2
7.3
6.2
2.9
8.3
26.4
10.6
0.8
5.6
8.1
11.5
3.0 gph
9.0
10.7
0.8
6.0
13.2
8.6
5.8
8.5
0.1
8.6
0.5
6.6

7.6
6.8
0.2
1.3
1.8
4.7
1.0
2.4
9.4
0.3
5.3
2.5

0.5
0.1
-
0.1
1.2
0.3
All Oil burners up to 3.0 gph
All Sections
68.3
13 Private communication: to D. W.
data were published in Reference


Table A-4.

7.0
8.6
9.6
5.4
Locklin, Battelle-Columbus, from Margaret Mantho, Fueloil & Oil Heat,
4.
Average Age of
High Pressure
Shell
Conventional Head
Oil Burners

Retention
Head
in Use, by Type'
Low
Pressure
l
Rotary
1.1
May, 1972. Similar

Vaporizing
Years
New England
Mid -Atlantic
South Atlantic
Midwest
West
13.1
12.4
10.1
14.1
12.7
9.5
8.9
7.0
8.8
7.0
4.1
4.2
3.0
3.7
3.7
14.4
16.2
19.3
17.8
16.6
16.8
17.7
-
17.8
—
_
15.6
13.7
17.0
16.7
All Sections
12.6
8.7
3.9
                                                                 16.5
                                                                             17.5
                                                                                            15.9

-------
                                  A-5
Table A-5.  Types of Central Oilheating Equipment in Use, by System Type4
Forced Hot Water
With Without



New England
Mid-Atlantic
South Atlantic
Midwest
West
All Sections

Furnaces

35.6
36.3
74.1
70.9
91.4
51.9
Gravity
Hot Water

2.4
2.7
1.5
0.8
-
1.9
Tankless Tankless
Coil
Percent of Total
39.4
36.9
12.9
6.9
1.7
25.5
Coil

2.2
9.0
4.8
6.8
5.5
6.5
Steam
With
Tankless
Coil

17.1
9.2
1.5
12.0
0.5
10.0
Without
Tankless
Coil

3.3
5.9
5.2
2.6
0.9
4.2
       Table A-6. Average Age of Central Oilheating Equipment in Use,
                 by System Type4



New England
Mid-Atlantic
South Atlantic
Midwest
West

Furnaces

14.9
14.7
11.1
14.1
13.0

Boilers

18.0
17.4
17.1
17.0
16.5
Combined
Boilers/Furnaces
Years
16.9
16.4
12.5
14.9
13.3

Burners

11.9
12.4
9.5
13.0
12.8
 All Sections
                      13.8
                                   17.5
                                                  15.6
12.2

-------
                                         A-6
         Table A-7. Combustion Chambers of Oil Burners in Use, by Type14
Firing Rate
Below 1.0 gph


Refractory
Brick
Ceramic
Fiber

Steel
1.
Refractory
Brick
0 to 3.0 gph
Ceramic
Fiber


Steel
Percent of Total
New England
Mid-Atlantic
South Atlantic
Midwest
West
All Sections
61
66
44
61
38
60
19
22
13
25
27
22
20
12
43
14
35
18
78
84
63
61
66
74
12
12
7
31
10
16
10
4
30
8
24
10
14  "Combustion Chambers by Types", Fueloil &ON Heat, Vol. 31, No. 5, March 1972, p. 94.
                 Table A-8.  Oil Burners in Use With Solenoid Valves4



New England
Mid-Atlantic
South Atlantic
Midwest
West
Firing Rate
Below 1.0 gph
Percent of Total
9
25
34
34
6

1.0 to 3.0 gph

21
34
35
35
4
           All Sections
23
                                                                   29

-------
                                            B-l

                                       APPENDIX B


       BACKGROUND DATA ON COMMERCIAL-INDUSTRIAL BOILER POPULATION


       This appendix  presents information on the profile of commercial and industrial boilers,
 with  distributions and  trends by  boiler type, capacity, and burner and fuel types,  which were
 used in selecting the equipment mix for this investigation.

       Boiler  industry statistics  frequently  combine  commercial  and industrial  boilers;  the
 distinction is  sometimes  based on  application and  sometimes on  size. (For  purposes of  this
 investigation, the  "commercial" range was  defined  as  sizes  between 10 and  300 boiler  horse-
 power, or approximately  0.3 to 10 million  Btu/hr output.) Thus, to discriminate in considerable
 detail on aspects  which are common to the  two major boiler size categories, both  commercial
 boilers  and industrial  boilers  up to  500  million  Btu/hr output  are  included in  the profile
 presented in this appendix.
 BOILER SURVEY

       As  an initial  step in the survey of commercial-industrial  boilers,  available data were
 reviewed. These  data were obtained from

            1. "Systematic Study  of Air Pollution from  Intermediate-Size Fossil-
              Fuel Combustion Equipment", J. R. Ehrenfeld, et al., Final Report
              on Contract No.  EPA 22-69-85, July, 1971.

            2. "Stationary Watertube Steam and Hot Water Generator Sales, 1970",
              American Boiler Manufacturer's Association (ABMA).

            3. Fueloil & Oil  Heat

            4. Various other sources.

 Although these publications contained data  on  the boiler population and/or sales, data were not
 available with the detailed distributions of size, boiler type, fuel type, etc., as needed  for this
 study.

       Therefore,  through the assistance of ABMA, a  questionnaire  was submitted to members
 of the ABMA Air Pollution Committee and  a number of other  key persons  in the boiler
 industry. Additionally, the same questionnaire  was submitted to  the members of the API SS-5
 Task  Force.  The  questionnaire  was designed   to  solicit percentage estimates of the  present
 population  of boilers and of boiler sales trends over the last 40 years  by  pertinent boiler, burner,
 and fuel characteristics.
Summary of Boiler Survey

       Tables  B-l  through B-8  summarize the  replies  to the questionnaire and the boiler
population  study; they represent  composite data from the various replies and are presented here

-------
                                             B-2

as the "best estimate" of the population as determined from the various sources. The summary is
organized in tables as follows:

       Current Equipment Population

            Table B-l.  By Boiler Type

            Table B-2.  By Fuel Capability (including oil type)

            Tab]., ?-3.  By Burner Type (for oil and coal)

       Trends in Sales (by Years for '30, '50, '70, and Forecast for '90)

            Table B-4.  By Boiler Type

            Table B-5.  By Fuel Capability (including oil type)

            Table B-6.  By Burner Type (for oil and coal)

       Annual Usage Factor for Load Factor)

            Table B-7.  By Boiler Application

       Boiler and Burner Life Expectancy

            Table B-8.  By Boiler Type and Burner Type (for oil and coal).

       General observations  on the field  population statistics are as follows:

            • A high portion of smaller boilers are packaged boilers, while most of
              the larger boilers are field erected units.

            • Fire-tube and  cast-iron boilers are more prevalent in the smaller sizes
              and water-tube boilers are more prevalent in the larger sizes.

            • In  the  commercial-boiler size range, fire-tube boilers  are  the  most
              numerous  type, with cast iron being next  in popularity.  In the
              smaller commercial  sizes  (10-50  hp),  firebox  boilers  are  the  most
              numerous of  the fire-tube types  but are about equal in number with
              packaged Scotch boilers in the larger sizes (100-300  hp).

            • Smaller boilers mostly fire a single  fuel (gas or No. 2 fuel  oil), with
              an increasing  percentage of duel-fuel boilers uscu "or the larger sizes.

            • For oil-fired boilers, the smaller boilers are generally fired with No. 2
              fuel oil; the  grade  of fuel  fired generally increases with boiler size.

            • Pressure  atomizers  are most  common for  small,  oil-fired  boilers,
              rotary and air  atomizers for intermediate-size  boilers, and steam
              atomizers for  larger boilers.

            • Coal-fired boilers are rare in the commercial size range.

Boiler Selection for Phase  II

       Based on the estimates of the present boiler population presented in Tables B-l through
B-3, a selection of six boilers was made for inclusion in the Phase II studies. This selection was
discussed in Chapter II.

-------
 Table B-1. Population
          Breakdown by Boiler Types (Percentage Basis)
          All Commercial-Industrial Boilers Now in Service in U.S.
                                                                  Commercial •
                                                                                                                                 Industrial .
RATED
CAPACITY,
SIZE RANGE
                         Id6 Btu/hr or
                         1Q3 Ib stm/hr
                       Bailer Horsepower
                                                  10-50
                                                                    51-100
                                                                                                       10-16
                                                                                     101-300
                                                                                                      301-500
                                                                      17-100
                                                                                      101-250
                                                                                                           251-500
  WATER TUBE

     Industrial Type >104 # Steam/hr
       Packaged
       Field erected
     Commercial Type <104 # Steam/hr
       Coil
       Firebox
       Other
   FIRE TUBE
      Packaged Scotch
      Firebox
      Vertical
      Horizontal Return Tubular (HRT)
      Misc. (Locomotive type, etc.)
   CAST IRON
   MISC. (Tubeless, etc.)
   TOTAL
    COMMERCIAL-INDUSTRIAL
    BOILERS
                                                     (22)
15
15
 1
 5
 2
                                                    1

                                                  100%
20
25
 0.5
10
 3
                  33   -


                   0.5

                  100%
30
30
nil
15
  5
                  15


                  nil

                  100%
                                                                                                        100%
                                                                                                                          100%
                                                                                                                                            100%

-------
Table B-2. Population
          Breakdown by Fuel Capability (Percentage Basis)
          All Commercial-Industrial Boilers Now in Service

RATED
SIZE RANGE
FUELS
Oil Only
Gas Only
Coal Only
106 Btu/hr or
ID3 Ib stni/lir
Boiler Horsepower




Oil & Gas and Gas & Oil
Oil & Coal and Coal & Oil
Gas & Coal and Coal & Gas
Misc. Fuels

(alone or with alternate fuels)

OIL
Total

Distillate, No. 2
Resid
No. 4 and
Heavy No.


Light No. 5 (No preheat)
5 and No. 6 (Preheated)
Total Oil
•• 	 	 Commercial 	 "

10-50

42
50
2
5
'$(%%%%%(%%(%!>
M%%%%%%%f%%
1

100%

95
(5)
4.5
0.5
100%

51-100

42
50
1
6
mmm?//m

!

100%

85
(15)
14
1
100%

101-300

40
50
1
8
W///^///////?////.

!

100%

50
(50)
30
20
100%
— 	 Industrial 	 •-
10-16
301-500

35
45
3
16
^/////////////////,
w^imfr,
i

100%

10
(90)
20
70
100%
17-100


35
35
10
18

2

100%

2
(98)
2
96
100%
101-250


30
22
18
25
0.5
0.5
3

100%

2
(98)
nil
98
100%
251-500


22
22
22
23
3
3
5

100%

2
(98)
till
98
100%

-------
Table B-3.  Population
           Breakdown by Burner Type (Percentage Basis)
           All Commercial-Industrial Boilers Now in  Service in U.S.

RATED
CAPACITY,
SIZE RANGE
OIL BURNERS
106 Btu/hr or
1Q3 Ib stm/hr
Boiler Horsepower
(approx. gph)
Air Atomizing
Steam Atomizing
Pressure or Mechanical Atomizing
Rotary
Total Oil
COAL BURNERS (approx. Ib/hr)
Spreader
Underfeed
Overfeed
Pulverized
Other




Total Coal


10-50
3-15
15

70
15
100%
33-160
60
15
5
'•%%ffi^%%%%,
20
100%

51-100
15-30
35
im^^^^
25
40
100%
160-330
60
15
5

20
100%

101-300
30-90
40

20
40
100%
330-1000
55
20
5

20
100%
— 	 Industrial 	 • 	 — ••
10-16
301-500
90-150
40
20
10
30
100%
1000-1600
60
15
5
lillllllii
20
100%
17-100

150-900
15
70
10
5
100%
1600-10,000
45
15
5

35
100%
101-250

900-2250
5
85
10

100%
10,000-25,000
45
15
5
15
20
100%
251-500

2250-4500
1
94
5

100%
25,000-50.000
20
nil
nil
65
15
100%

-------
   Table B-4.  Estimated Trends of Boiler Types (Percentage Basis)
             All Commercial-Industrial Boilers Installed in Years Noted
                                                                - Commercial -
                                                                                                                                Industrial-
RATED
CAPACITY.
SIZE RANGE
                         106 Btu/hr or
                         103 Ib stm/hr
                      Boiler Horsepower
WATER TUBE

    Industrial Type > 104 # Steam/Hr
       Packaged
       Field erected

    Commercial Type <104 # Steam/Hr
       Coil
       Firebox
       Other
 FIRE-TUBE

     Packaged Scotch
    Firebox
    Vertical
    Horizontal Return Tubular !HRT)
    Misc. (Locomotive type, etc.)
  CAST IRON
  MISC (TUBELESS, ETC)
  TOTAL
   COMMERCIAL-INDUSTRIAL
   BOILERS
                                                   10-50
                                             30  '50   '70  '90
                                                              •30  '50   '70  '90
                                             nil  10  11  10
                                               b  11  18  20
                                               5666
                                               5   1 nil nil
                                               8532
                                              60  50  45  40
                                              3211
100  100 100  100
                                                                    51-100
                     I 14  22   26
                    20 15  17   23
                     3532
                     5  2 nil nil

                     5111
                                                               50  45  40   36
                                                                3   2    1  nil
                  100  100 100  100
                                                            10-16
                                                                                     101-300
                                                                                                       301-500
                                                                                 30  '50  '70  '90
                                                                                                   30  '50  '70  '90
                                                                                                   (25)(17)(19)(20)
                                                                                                    0    2   18   20
                                                                                                   25   15    10
 2  21  41  40
20  30  35  3D
 5   2 nil nil
60  25   1 nil

 852 nil
                                                                                 nil   5 10   15
                                                                                nil    111
                                     100  100  100  100
nil 35   40   45
 20 40   40   35
                                                      100  100  100  100
                                                                              17-100
                                                                                                                    30  '50  '70  '90
                                                                                                                    (94) (97) (94) (90) J.OO) (100) (100)(1O>) (LOO) (100) (100)(LOO
                                                                          0   8  80   89
                                                                         94  89  14    1
                                                                        100  100 100  100
                                                                                              101-250
                                                                                                                                      30  '50  '70  '90
                                                      0   0  80   90
                                                    100 100  20   10
                                                                                                                 251-500
                                                                                                                                                        •30  '50   '70  '90
                                                       001
                                                     100 100
                                                                                          100 100  100  100
                                                                                                            100  100  100  100

-------
Table B-5.   Estimated Trends by Fuel Capability (Percentage Basis)
            All Commercial-Industrial Boilers Installed in Years Noted,
            Including Conversions

RATED
CAPACITY,
SIZE RANGE


106Btu/hror
103 Ib stm/hr
Boiler Horsepower

FUEL CAPABILITY
Oil Only
Gas Only
Coal Only



Oil & Gas and Gas & Oil
Oil & Coal and Coal Be Oil
Gas & Coal and Coal & Gas
Misc. fuels
(alone or with alternate fuels)
Tota
OIL
Distillate, No
Resid


2

No. 4 & Light No. 5 (No preheat)
Heavy No. 5 & No. 6 (Preheated)
Total Oil
-« 	 Commercial 	 *•

10-50
'30 '50 '70 '90
20 40 30 15
10 30 45 50
65 20 5 nil
nil 5 18 25
liiiiiiiiiiiiP
^iitiiiiiiiii
5 5 2 10
100 100 100 100

40 50 70 100
(60) (501(30) (nil)
40 40 25 nil
20 10 5 nil
100 100 100 100

51-100
•30 '50 '70 '90
10 30 25 15
10 30 38 50
75 15 5 nil
nil 10 30 25
{%%%%%%%%%%?

5 5 2 10
100 100 100 100

20 30 40 70
(80) (70) (60) (30)
50 50 50 30
30 20 10 nil
100 100 100 100

101-300
•30 '50 '70 '90
10 40 30 30
5 25 30 30
80 10 5 nil
lil 20 30 30
%%%%!>:%%%%%

55 5 10
100 100 100 100

10 10 20 40
(90) (90) (80) (60)
30 40 30 5
60 50 50 55
100 100 100 100
-« 	 Industrial 	 *•]
10-16
301-500
'30 '50 '70 '90
17 43 30 30
5 20 30 30
75 10 5 nil
nil 25 30 30
^^^^^^.

32 5 10
100 100 100 100

5 2 10 30
(95) (98) (90) (70)
20 23 10 nil
75 75 80 70
100 100 100 100
17-100

'30 '50 '70 '90
13 30 30 25
10 30 30 25
75 30 5 nil
nil 5 30 35
iiiiiiiiiiiillf
^HHHHililtii
2 5 5 15
100 100 100 100

ill nil 10 20
(ioo) (too) (90) $o;
til 5 nil nil
100 95 90 80
100 100 100 100
101-250

'30 '50 '70 '90
5 20 24 20
5 20 24 20
90 38 15 nil
nil 10 25 40
nil 555
nil 5 55
nil 2 2 10
100 100 100 100

nil nil 5 10
(LOO) (100) (95) (90]
lil nil nil nil
LOO 100 95 90
100 100 100 100
251-500

•30 "50 '70 '90
5 15 20 10
5 15 20 10
90 60 20 10
nil 5 20 30
nil 3 10 20
nil 2 10 20
nil nil nil nil
100 100 100 100

nil nil 5 10
(1 00) (100) (95) (90)
nil nil nil nil
100 100 95 90
100 100 100 100

-------
Table B-6.   Estimated Trends by Burner Type (Percentage Basis)
            All Commercial Industrial Bailers Installed in Years Noted,
            Including Conversions
                                                                         - Commercial -
                                                                                                                                             Industrial
106 Btu/hr or
RATED W3 Ib stm/hr
SIZE RANGE Boiler Horsepower

OIL BURNERS
Air Atomizing
Steam Atomizing
Pressure or Mechanical Atomizing
Rotary
Total Oil

COAL BURNER
Spreader
Underfeed
Overfeed
Pulverized ;
Other
Total Coal

10-50
'30 '50 '70 '90

10 15 15 15

70 75 85 85
20 10 nil nil
100 100 100 100
% v.-.

nil nil nil nil
5 90 90 nil
nil 5 5 nil

95 5 5 nil
100 100 100 100

51-100
•30 '50 '70 '90

15 20 30 30
Wffiffiffiffiftffift
55 60 65 70
30 20 5 nil
100 100 100 100
%

lil nil nil nil
45 90 90 nil
555 nil

50 5 5 nil
100 100 100 100

101-300
•30 '50 '70 '90

20 30 55 60

50 40 40 40
30 30 5 nil
100 100 100 100
%

nil 5 5 nil
75 85 85 nil
20 5 5 nil

55 5 nil
100 100 100 100
10-16
301-500
•30 '50 '70 '90

10 20 35 40
30 30 35 40
25 20 20 20
35 30 10 nil
100 100 100 100
%

5 10 5 nil
75 75 85 90
15 10 5 5

5555
100 100 100 100
17-100

'30 '50 '70 '90

5321
75 80 88 90
15 14 10 9
5 3 nil nil
100 100 100 100
%

15 50 50 nil
50 35 35 85
30 10 10 10
vX£$//&2///%2&/'&%'
5555
100 100 100 100
101-250

'30 '50 '70 '90

2 1 nil nil
93 94 95 95
5555

100 100 100 100
%

15 40 40 nil
50 30 20 20
25 15 15 15
5 10 20 60
5555
100 100 100 100
261-500

'30 '50 '70 '90

2 1 nil nil
93 94 95 95
5555

100 100 100 100
%

15 30 20 nil
40 20 10 1.0
20 15 10 10
20 30 55 75
5555
100 100 100 100

-------
Table B-7. Typical Annual Usage Factor lor Load Factor)
                                                                                                ACTUAL FUEL USED PER YEAB X 100
For Commereial-lndustria. Boilers UM"~ ' """" ™>- ^AGE FOR YEAR AT CONSIAN! FULL LOA1> UKHAIMI
For Various Applications

RATED
SIZE RANGE
APPLICATION

106 Btu/hr or
103 Ib stm/hr
Boiler Horsepower

Commercial Heating
Commercial Processing
(Laundry, etc.)
Industrial Heating Only
Industrial Processing Only
General Industrial Use
(Heating, Processing, Power]
Industrial Power

Utility Power




10-60
%
50
80

60
85

/yyfflvvsysfflfflwwft
y///////////////
'Y/y////2s/Y/y//s


61-100
%
50
80

60
85


'<%MM//M///S



101-300
%
50
80

60
88

WT/m/y/mmWm.
'////////////////
w/Mw/y//,


10-16
301-500
%
50
80

60
85
mmm
nMwffiwMMWW.

85
17-100

%
60
80

60
85
85
WM%MM

90
101-250

%

80

60
90
90
95

95
251-500



80

60
90
90
95

95

-------
B-10
Table
B-8. Boiler and
A. Boiler Life Expectancy, Average
Boiler Type
Water Tube
industrial type
Packaged
Field erected
Commercial type
Coil
.
Firebox
Other

Fire Tube
Packaged Scotch
Firebox
Vertical
Horizontal return tubular
Misc.
Cast Iron
Misc.
Years


30
45

20

25
25


20
25
10
40
10-20
40
30
Burner Life Expectancy
B. Burner Life Expectancy, Average
Burner Type
Oil Burners
Air Atomizing
Steam Atomizing
Pressure/Mechanical Atomizing
Rotary

Coal Burners
Spreader
Underfeed
Overfeed
Pulverized
Other







Years

20
30
15
20


20
15
15
18
15






-------
                                            C-l

                                        APPENDIX C


                                      FUEL ANALYSES
Residential Fuels

       Table C-l  lists  properties of the  No. 2 oils fired in residential units  for  the Phase II
investigation.  The  reference fuel for  firing in  the residential  units  (designated  RR) was  a
high-quality hydrotreated fuel.

       Table C-2  reports results of chemical analyses for C,  H,  and N contents of the  fuels fired
in the residential units.
Commercial Fuels

       Table C-3  lists the generally reported properties for the fuel oils fired in the commercial
boilers. These include fuel grades Nos. 2,^4, 5, and 6.

       The reference fuel for firing in the commercial boilers (designated  CR) was a low sulfur
residual fuel typical of the 1.0 percent sulfur residual  oils being marketed to the East Coast in
March, 1972. It was purchased from a fuel oil supplier located in Connecticut.

       Table C-4  reports results of chemical analyses for C, H, and N contents of the fuel oils
fired in the commercial boilers.

-------
                                     Table C-1. Properties of Fuels Fired in Residential  Units3


Fuel Gravity,
Fired
in Unit
23
23 1
23.2
24
24.1
24.2
25
25.1
25.2
26
26.1
26.2
27
28
29
30
31
32
33
34
35
RRC
a Analyses
O Dificpl inr
API at
60 F
34.2
31.7
31.0
32.3
34.4
30.6
34.1
34.2
34.8
33.8
34.1
34.3
31.1
32.7
33.2
34.0
30.9
30.6
32.2
36.9
33.6
34.7
by E. W.
Ani
ipv = 	
Kinematic
Viscosity
at 100 F,
cs
2.23
242
2.23
2.20
2.47
2.19
2.45
2.31
2.17
2.41
2.42
3.12
2.45
2.39
2.54
2.59
2.46
2.44
2.42
2.34
1.82
2.71

Flash
Point,
F
150
152
144
144
148
138
154
150
158
150
152
154
152
156
156
154
152
156
148
160
152
142
Carbon
Residue,
Ramsbottom
(last 10%),%
0.23
0.24
0.22
0.23
0.14
0.25
0.16
0.15
0.15
0.19
0.12
0.16
0.23
0.22
0.21
0.18
0.24
0.23
0.24
0.14
0.28
0.15


Sulfur,
%
0.19
0.17
0.15
0.27
0.16
0.17
0.11
0.14
0.16
0.17
0.14
0.14
0.24
0.18
0.17
0.10
0.20
0.16
0.20
0.19
0.24
0.05

Aniline
Point,
%
133
130
122
124
140
119
139
139
140
139
141
139
129
132
135
142
133
124
129
150
118
148


Diesel
lndexb
45.5
41.2
37.8
40.1
48.2
36.4
47.4
47.5
48.7
47.0
48.1
47.7
40.1
43.2
44.8
48.3
41.1
37.9
41.5
55.4
39.6
51.4


IBP,
F
356
356
344
344
366
342
354
366
368
360
372
368
370
360
368
364
358
370
358
368
346
354


10%,
F
398
412
406
396
418
394
416
414
416
416
414
414
412
408
416
416
412
424
416
414
392
418
ASTM

50%,
F
490
498
490
490
500
486
498
496
484
494
500
502
504
492
502
510
506
510
504
490
468
504
Distillation

90%,
F
578
592
588
586
582
588
586
582
558
582
582
588
586
578
590
592
604
604
590
578
550
602
End
Point,
F
632
644
640
644
634
640
634
630
614
634
630
636
642
634
642
640
656
656
642
630
588
640

Recovery,
%
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
99.0
Saybolt and Company.
line point in F
x API gravity










Reference luel — high-quality hydrotreated fuel.

-------
                                  C-3
Table C-2. Chemical Analyses of Fuels Fired in Residential Units3
Fuel Fired in Unit
23
23.1
23.2
24
24.1
24.2
25
25.1
25.2
26
26.1
26.2
27
28
29
30
31
32
33
34
35

Cb
87.0
86.9
87.4
87.5
87.4
86.7
87.0
86.9
86.7
86.6
87.1
86.3
87.2
86.3
87.1
84.6
84.2
87.4
87.2
85.9
87.2
Weight Percent
Hb
12.8
12.5
12.4
12.4
12.3
12.2
12.7
13.1
13.2
12.7
12.0
13.2
12.3
12.5
12.8
12.5
11.8
12.6
12.8
13.4
12.6

Nc
0,006
0.006
0.007
0.008
0.011
0.009
0.006
0.003
0.003
0.007
0.011
0.005
0.010
0.006
0.005
0.005
0.009
0.008
0.007
0.003
0.007
    RRC
87.0
13.0
                                      0.005
 Analyses by Battelle-Columbus.
 Pregl method.
 Kjeldahl method.
 Reference fuel - a high-quality hydrotreated fuel.

-------
                                                             Table C-3. Properties of Fuels Fired in Commercial Boilers3

Fuel
Fired in
Boiler
C2001 &
C2002
C2002
C2003
C2003
C2004
C2004
C2005
C2005
C2006
C2006
CR"

Fuel
Grade
. No.
2

4
2
6
2
5
2
6
2
6

Gravity,
API at
60 F
(D-287)
34.6

23.5
34.8
17.3
36.4
16.6
35.4
14.7
36.2
16.9
23.5
Viscosity,
at 100 F,
SSU
(D-445)
34.5

101.7
35.0
2746.
34.9
291.
35.0
3982.
34.9
3053.
313.
Flash
Point,
F
(D-93I
145

186
153
176
157
265
159
224
163
199
205
Carbon
Residue


Ramsbottom,
%
(D-524)
0.07

3.18
0.07
9.66
0.04
7.47
0.20
8.44
0.06
6.78
5.49
Ash, %
(D-482)
0.001

0.019
<0.005
0.062
<0.005
0.021
<0.005
0.019
<0.005
0.017
0.032
Sulfur, %
(D-26221
0.27

1.59
0.16
2.19
0.23
1.93
0.3B
1.67
0 18
1.13
0.99
Nitrogen
(Kjeldahl),
%
(C-93)
0.0084

0.17
0.0078
0.37
0.0113
0.29
0.0124
033
0.0086
031
0.22
Aniline
Point,
F
(D-611)
145

-
153
-
157
-
159
-
163
-
-
ASTM Distillation (D 861

IBP.
F
336

376
357
362
366
400
364
332
380
328
368

10%,
F
398

502
419
482
417
485
417
560
429
510
507

50%,
F
489

671
498
677
494
657
494
660
49fi
660
677
End
90%. Point,
F F
586 630

(75% at 700 F
592 630
(60% at 685 F
580 520
(68% at 682 F
587 638
(70% at 680 F
584 629
(70% at 685 F
(78% at 695 F


Metals0
Recovery,
%
98.0

max)c -
98.0
max)c —
98.0
max)c —
98.0
max)0 -
98.0
max]c -
max)c -
V.
ppm
<1.0

130.
<1.0
320.
<1.0
120.
•CI.O
89.
•CI.O
54.
170.
Ni. Ma,
ppm ppm
<0.1 <5

23. <5
<0. 1 <5
74. 46.
<0.1 <5
41. <5
<0.1 <5
36. 23.
<0.1 <5
24. 32.
40. <5
a  Analyses by American Oil Company.
^  Emission spectroscopy, accuracy ±35 percerit.
c  Cracked.
^  Reference fuel for commercial bailers was 1 .0 percent -sulfur residual-fuel
                                                                                                                                                                                                     n
                                                                  oil currently being marketed in Connecticut.

-------
                                        C-5
     Table C-4. Chemical Analyses of Fuels Fired in Commercial Boilers8
Weight Percent
Fuel Fired in Boiler
C2001 & C2002
C2002
C2003
C2003
C2004
C2004
C2005
C2005
C2006
C2006
CRd
Fuel Grade
2
4
2
6
2
5
2
6
2
6
-
Cb
86.1
85,0
85.8
85.2
86.9
86.0
86.3
86.8
87.1
86.0
86.3
Hb
12.8
11.8
12.9
11.6
13.1
10.9
13.1
11.1
13.0
11.1
12.5
Nc
0.004
0.15
0.010
0.36
0.010
0.28
0.010
0.31
0.007
0.30
0.22
a  Analyses by BatteHe-Columbus.
b  Pregl method.
c  Kjeldahl method.
d  Reference fuel for commercial boilers was a 1.0 percent sulfur residual-fuel oil currently being
   marketed in Connecticut.

-------
                                            EM

                                       APPENDIX D


                            DETAILS OF FIELD PROCEDURES
RESIDENTIAL UNITS

       Prior to setting up the monitoring equipment in the field, each homeowner was visited by
a Battelle staff member in advance of the scheduled arrival of the field team. During this visit,
the heating unit was examined for accessibility,  space  requirements, and material needs for
rerouting the flue pipe to accommodate the particulate sampling.

       When the field team arrived to begin measurements, the monitoring instruments were set up
and recalibrated, and stack changes were made to permit installing a test section of duct (needed
for particulate  sampling)  in the stack.  The gaseous sampling  trains were set  up  and the
instruments checked out.  Stack  velocities  were  measured  with an  S-type  Pitot tube,  stack
pressures and temperatures were measured, and flue-gas flow rate and excess air were calculated.
After making the  as-found  run,  the  fuel line was  broken  and the fuel  rate was determined
volumetrically by connecting the pump suction line to a calibrated container and measuring fuel
consumption over a convenient time interval.*
Measurements

       Measurements were made  of the following gases  and stack emissions  under various
conditions of operation:

            • CO2
            • 02

            • CO
            • Hydrocarbons (total)

            • NOX and NO
            • Particulate loading.

In addition  to these measurements, the combustion  conditions normally observed by servicemen
were measured.  These conditions  included: draft (over-fire  and stack) and flue-gas temperature
(at  the particulate  sampling point which was  several  feet from  the  breeching) - plus smoke,
CO2,  and O2 as measured by standard field-type  instruments. Details of instrumentation and
measurement procedures  are given in Appendixes E and F.
*Measuring fuel consumption required breaking the fuel line. Thus, some air may have entered the fuel line, caus-
 ing the cutoff to become somewhat more sluggish than normally expected for subsequent tuned and reference-
 fuel runs.

-------
                                            D-2

 Conditions Investigated

       Emissions from residential units were  monitored under the following sets of conditions:

            • Cyclic and varied-air runs

              - The as-found condition, A

              — A tuned condition, T

              - Firing a No. 2 hydrotreated  reference fuel in the tuned condition, R

            • Cyclic runs only

              - Follow-up checks (Units 23 to 26).
       Cyclic Runs.  Cyclic  runs refer  to  measurements taken at a  fixed  air setting  during
operation on  a  10-minute-on and 20-minute-off cycle,  as controlled by a timer overriding the
thermostat.  For the cyclic runs, gaseous-emission measurements were made for the entire period,
including both the on and off portion of the cycles. Particulate measurements were started at the
beginning of  the second  or  third cycle and measured during each 10-minute firing portion of
four or five additional cycles. A total of 50 to 60 minutes of firing time (about 3 hours' elapsed
time) was required for the particulate sampling to accumulate sufficient material for accurate
weighing.
       Varied Air Runs. Varied air runs refer to measurements made during steady-state opera-
tion of the  unit to investigate the effect on emissions of excess-air setting. Gaseous emissions and
smoke were measured  as the excess  air adjustment was varied  over the range from full open to
approximately a  No. 5 to 7 smoke. The varied air  runs were  made with the house  fuel in  the
as-found condition and with the house  and reference fuels for the tuned condition.
       As-Found Condition. The initial measurements on  the  heating unit were  made  in  the
"as-found" condition, i.e., no servicing or changes were made except for the rerouting of the flue
pipe. Measurements were made during both cyclic and varied air runs.
       Tuned Condition,  Following the test  run in  the "as-found" condition,  the  serviceman
cleaned and tuned the burner.  This was not an "eyeball" adjuc^nent, but was intended to be a
tuning that a skilled serviceman would achieve with normal procedures of good practice with the
benefit of instrument readings  of draft, CO2,  and smoke, The following steps were included in
the serviceman's procedure to establish the tuned  conditions:

           • Cleaning and adjusting the electrodes
           • Cleaning the blast tube and blower wheel

           * Cleaning or replacing the nozzle (even by a  different size or spray
              pattern if it were better suited to the installation)

           • Cleaning or replacing the oil filter

-------
                                           D-3

            • Simple sealing of air leaks at inspection door, around blast tube, or in
              other easily accessible location

            • Change  in draft-regulator setting (replaced regulator when  necessary)

            • Change in combustion air adjustment.

The following items, being major repairs or modernization requiring special charges  to the home-
owner, were not included in the tuning procedure.

            • Replacement of the combustion  chamber or liner

            • Sealing  of air leaks that  would require  disassembly of the boiler or
              furnace jacket.

Replacement of the combustion head generally was not done. However, the burner for Unit 27
was intended to include a flame-retention combustion head which apparently had been removed.
To  return this unit to its normal operating condition, a  flame-retention head was installed during
the tuning.

       The  field team  developed  a rough CO2-smoke  curve  as part  of defining the well-tuned
conditions.  The  air adjustment was  then made just  off the  "knuckle" of this curve.  The
instructions  for adjusting to the tuned condition consisted of these steps:

            (1)  Compare the  CO2  level  in the stack with that obtained in sampling
                by traversing  above the  fire using a simple averaging  procedure. An
                appreciable difference  between stack and over-fire CO2 is indicative
                of air  infiltration  through leaks; easily accessible leaks  are  to be
                repaired.

            (2)  Establish a smoke-CO2  curve by use of the continuous CO2 reading
                and the Bacharach smoke  spot reading  (with only enough points to
                define  the general shape, and particularly  the location of  the
                "knuckle").

            (3)  If No.  1 or less Bacharach smoke  can  be  achieved with air adjust-
                ment alone,  adjust the burner  to  the maximum CO2 for No. 1
                smoke, but allow a cushion no nearer the "knuckle" than 0.5 to
                1.0  percent CO2.  (It would be  expected  that a well-tuned burner
                should operate with at least 8 percent CO2.)

            (4)  If Step (3) cannot be  accomplished to  reach  a No.  1 smoke, carry
                out  any  of the specific tuning steps listed above to achieve that
                performance,  or approach it as closely as  possible. In  this pro-
                cedure, first priority should be given to "reducing  smoke level to at
               least No. 2, and second priority to maintaining high  CO2  (with 0.5
               to 1.0 percent cushion  from the "knuckle"). The smoke-CO2  curve
               should be repeated to  define the burner performance and to locate
               the desired setting for the tuned test run.

-------
                                            D-4

        All  the residential  units in  the  Phase  II program were  tuned according to the above
 tuning  steps; adjustments for  each  unit are shown in Table D-l. Following the tuning,  gaseous
 and particulate emissions and  smoke were  measured for the "tuned" condition while  firing the
 house fuel.
        Reference Fuel Condition. After completing the tests for the  as-found and  tuned condi-
 tions,  each residential unit  was operated  on a reference fuel, a high-quality No. 2 hydrotreated
 fuel. The purpose of the reference fuel measurements was to provide a baseline in comparing the
 variety of burner units on a common fuel basis and, thus, to remove the effect of randomness in
 the  quality  of  house fuels.  Gaseous emissions and  smoke were measured  while  firing the
 reference fuel.  In addition, particulate emissions were measured for Units 23 to 26.
        Follow-Up Checks. To  examine the effect of seasonal operation, four installations (Units
 23 to 26) were  selected for visits at  three times during  the course of the heating season — an
 initial measurement series plus two follow-up checks. The initial measurements were made in
 mid-December, the first follow-up in  mid-February, and  the  second follow-up  the last week in
 April. For the first follow-up,  gaseous emissions were measured for the as-found condition using
 both the house  fuel  and the reference fuel. Similar gaseous emission measurements  were made
 during  the second  follow-up and,  in  addition, particulate emissions were measured while firing
 the reference fuel for comparison with the particulate measurements made during the initial visit.

        These  four  burners were  equipped with  operating time clocks  and cycle  counters to
 record operating  experience between the first and last visits.
COMMERCIAL BOILERS

       Although the instrumentation  techniques and the emission measurements  used for the
commercial boilers were similar to those employed  for the residential units, the conditions under
which the measurements were made were  quite  different.  In  addition,  SO2  emissions  were
measured for the commercial boilers.

       The commercial boilers were all investigated  in the as-found  condition, i.e., no cleaning or
other servicing of th'e boiler  was done  prior to testing.  The exhaust stack from the breeching
through  the sampling section  was replaced with new stack on all units except Unit C2006. For
this unit the particulate sampling was  done from the roof and  it was not economically feasible to
replace the entire stack; however, a short section of stack was replaced with a section containing
particulate sampling ports.

       The commercial measurements were  conducted in late spring, 1972 (March 20 through
June  8), near the end of the heating  season. Visual inspection of  the units showed  the normal
quantities of soot and ash one would expect to accumulate  over a typical heating season. (Unit
C2003 was a new boiler that had  only been  fired briefly as a part  of the manufacturer's
checkout operation. Hence, it  was essentially  clean.)

       Gaseous emissions and smoke  measurements were  obtained  for several excess air settings
at each  of four  loads and  for several fuels to yield a fairly complete  picture of the various
operating parameters.

-------
                                    Table D-1.  Information on Condition and Tuning of Residential Units
Atomizing Nozzle
Unit
23C

24°
25



26

27
28C

29

30


31C
32C

33C

34
35
Size,"
gph Cleaned
1.35

1.00
1.35 X



1.75

1.35 X
1.00

0.75

0.60


1.50
1.00

0.85

0.75
1.00
Pressure, psi
Replaced
X

X




X


X

X

X


X
X

X

X
X
As- Found
100

91
100



100

110
95

90

88


100
99

106

80
100
Tuned
100

100
100



100

100
100

100

100


100
100

90

90
100
Normal
Cleaning &
Electrode
Adjustment
X

X
X



X

X
X

X

X


X
X

X

X
X
Other Steps
_

Replaced fuel pump
Replaced fuel pump filter; heat exchanger
baffle plates cleaned


Replaced strainer and line filter; installed
check valve in fuel line
Installed new flame retention head
Replaced strainer; increased nozzle size
to 1 .35 gph
Replaced strainer; soot cleaner used in
cleaning heat exchanger
Replaced fuel pump, strainer, and two
line filters; increased nozzle size to
0.75 gph
Replaced strainer
Replaced line filter

Replaced strainer; resealed door and
burner assembly
Replaced line filter
-
Remark:6
Good condition; delay valve not working
properly
Average condition
Good condition; 447 gallons of fuel oil
delivered between initial visit and first
follow-up; stirred up sediment in tank
and created nozzle clogging problems
Good condition

Average condition; nozzle 1 month old
Average condition; winds gusting to
65 mph during tuned and reference runs
Average condition; unit had a No. 9 smoke
in spite of servicing only 3 days earlier
Poor condition; original nozzle had been
drilled by homeowner

Good condition
Poor condition; occasional puff, possibly
due to air leak in very old fuel line
Very poor condition

Average condition
Good condition
a  Nozzle size, as found.  Replacement nozzles were same size except as noted.
b  Serviceman's estimate of condition.
c  Owner has service contract, thus unit probably received an annual cleanup and tuning.

-------
                                            D-6

       The four load levels at which emission data were obtained for commercial boilers were:

            R — rated load

            H — a high load for normal operation (selected as 80 percent of rated load)

            M — an intermediate load

            L — normal low-fire setting.

Boiler C-2001 was fired with a burner having a fixed firing rate and therefore was only operated
at three loads:  100,  82, and  61 percent.  The different loads  were obtained by changing the
nozzle size.

       For the  oil-fired boilers, 12  percent  CO2  was  used  at  the baseline excess-air condition
(after  discussions with  the ABMA  Commercial-Industrial Air  Pollution  Committee).  Gaseous
emission measurements  were made  at  several excess  air levels,  generally between  9  and  14
percent CO2.  For gas-fired  runs, 9  to  10 percent CO2  was used as the baseline, representing
an  excess   air  level   typical of  normal  boiler  operation.  Because  particulate measurements
required extensive sampling times  (approximately 80 minutes at each load setting), particulate
emissions were measured for only  one excess-air level (12 percent CO2  for oil firing and 9 or 10
percent CO2 for gas firing) at one or two loads for each fuel fired  in each boiler.

       To  assure the attainment of steady-state conditions when changing load or excess air, the
boilers were operated  at the new setting for  30 minutes before particulate sampling was begun.

       Each boiler (except C-2001) was fired  with four  different fuels: the typical house fuel, an
additional fuel oil ranging  from No. 2 through No. 6 grades, a 1-percent sulfur reference residual
oil, and natural  gas. A sample of each fuel oil was obtained for analysis of its  physical properties
    chemical composition.

-------
                                           E-l

                                      APPENDIX E
        SAMPLING AND ANALYTICAL PROCEDURES FOR GASEOUS EMISSIONS
Sampling

       Selection of installations with adequate space and accessibility made it possible to sample
the gaseous emissions from stacks directly  through sampling probes into the monitoring equip-
ment (avoiding grab-bag  sampling  techniques). Direct  sampling  with the shortest possible lines
rninimized losses by condensation, reaction,  and/or adsorption.

       A schematic  drawing of the sampling  train used  in  monitoring gaseous  emissions from
both residential and commercial units is shown  in Figure E-l.
     Stack
 HC(high temp)
             NO
    N02to NO
    converter -
1 _
1 r

L

co"\°2"\c°27 rs°2/~HC
-------
                                              E-2

and  a Dry Ice-cooled  water trap. When the high-temperature hydrocarbon  analyzer  was used, a
third probe was employed  which consisted of a  1/4-in. heated Teflon line connected directly to
the analyzer.
Analytical Methods

       It is generally  recognized that  monitoring equipment  with 100  percent reliability is still
lacking,  especially for field  measurements. Therefore, special care was taken in checking out,
tuning, and  calibrating all instruments  prior to each run. Zero and appropriate upscale span gases
were used for calibration.

       The monitoring techniques used in the field  on this program are listed in Table E-l. The
choice  of  techniques  was  based primarily  on  the  emission range  anticipated,  interference-
correction requirements,  and ease of use in the field.
                 Table E-1. Gaseous Emission Instrumentation Used in Field Survey
Pollutant       Instrument
                       Range a     Principle of Operation
                                                                              Comments
CO       BeckmanModel215A    0-1250       NDIR
                                                        Continuous, portable; water and
                                                         CO2 interference can be
                                                         accommodated
Total HC  Beckman Model 109A
          Beckman Model 402
                      0-120,000    Flame ionization
                      0-120,000    Flame ionization
                                  Continuous, fast response, portable
                                  Selectable elevated temperature
                                   sampling line and oven
NO
Beckman Model 315L
0-750
NDIR
Continuous, portable; water and
 CO2 interference can be
 accommodated
NOX      Faristor
          Beckman Model 315L
                      0-2500      Electrochemical (dry)
                      0-750       NDIR with  N02 to
                                    NO converter
                                  Continuous, fast response, portable;
                                   SO2 interference can be
                                   accommodated
                                  Continuous, portable, water and
                                   C02 interference can be
                                   accommodated;
                                   CO interference in converter can-
                                   not be accommodated
SO2       Faristor
C02      Beckman Model 215A
                      0-2500      Electrochemical (dry)
                      0-20%       NDIR
                                  Continuous, fast response, portable;
                                    no N02 interference

                                  Continuous, portable; water inter-
                                    ference can be accommodated
          Beckman Model 715
                      0-25%       Amperometric
                                                                   Continuous, portable
(a) Ppm except as noted.

-------
                                            E-3

       Carbon Monoxide.  Carbon  monoxide was  continuously monitored  by  nondispersive
infrared using a Beckman Model 215A analyzer.  The instrument  has two ranges, 0 to 250 and 0
to 1250 ppm. The sensitivity is 0.5 percent of full scale with an accuracy of ±1 percent.


       Hydrocarbons,  Total  hydrocarbons  were measured  by  flame ionization  using two
Beckman  analyzers  - Model  109A  and Model  402. The operation of  the two analyzers is
basically  the  same,  the  primary  difference being  that  the  Model 402 utilizes  a selectable
elevated-temperature sampling line and analyzer oven. Sampling at elevated temperatures (200 to
400 F)  minimizes  the loss of  higher molecular-weight hydrocarbons. Both analyzers  are usable
over a wide range of concentrations and have excellent response time and sensitivity. The most
sensitive range obtainable is 0 to 10 ppm carbon, while the least sensitive range is about 0  to
120,000 ppm carbon.


       Nitrogen Oxide. Three techniques were used  to continuously measure the nitrogen oxide
concentrations.

            • NO by NDIR analyzer

            • NOX by NDIR + converter

            • NOX by an electrochemical analyzer.

The  nondispersive infrared (NDIR) analyzer, a Beckman Model 315L, has three ranges (0-150,
0-450, and 0-750 ppm). The unit in actuality measures  nitric oxide (NO). However, when used in
conjunction with  a NO2 to NO converter, it can also  be used for measuring NOX.

       The NO2  to NO thermal converter is a 6-ft-long coil of l/8-in.-diameter No. 316 stainless
steel tubing which  is resistance heated to 650-700 C. A bypass valve on  the converter permits
rapid switching between NO (bypassing the converter) and NOX modes. The internal  surface of
the  converter  heater  coil is  stabilized when delivered;  however,  periodic  reconditioning  is
necessary.  This is accomplished by passing NO or NO2/air through  the converter for approxi-
mately 15 minutes while in the NOX mode.

       The Faristor, an electrochemical analyzer, operates  on  the principle of a fuel cell. When
sample  gas is  passed through the detector, an electrochemical process  within  the detector
generates an electrical signal proportional to  the NOX  concentration in the gas sample. This signal
is amplified and then displayed on a meter having a 0 to 100 linear scale. Two range settings are
possible -  0 to 500 ppm for the low range  and 0  to 2500 ppm for the high range.


       Sulfur Dioxide.  The Faristor electrochemical cell was also used to measure  SO2. The
Series NS-200 SO2/Nitrogen Oxide Analyzer is bimodular,  using  two Faristor plug-in  detectors,
Type N76H2 for measuring NOX and Type S64H2 for measuring SO2.  Two analog outputs are
available on the Faristor permitting simultaneous monitoring of both gases.

-------
                                          E-4

       Carbon  Dioxide.  Nondispersive infrared  was also  used in monitoring CO2.  The instru-
ment,  a  Beckman Model 215A,  has  two ranges (0 to 5  percent and 0 to 20 percent CO2 by
volume). The sensitivity is 0.5 percent of full scale with an accuracy of ±2 percent.
       Oxygen.  The Beckman  Model  715 Process  Oxygen Analyzer was  used  to continuously
monitor gaseous oxygen. The analyzer has ranges of 0 to 5 percent and 0 to 25  percent oxygen.
Accuracy  is ±1 percent of full  scale at a  given sample temperature and  ±6 percent of full scale
for sample temperature variations within the temperature range of 32 to 110 F.

       The amperometric  oxygen  sensor  contains a gold cathode  and silver  anode. The  two
electrodes  are separately  mounted within the PVC body  and are electrically  connected  by a
potassium chloride electrolyte.  A gas-permeable Teflon membrane separates the  electrodes  from
the process sample and fits firmly against the gold cathode. Oxygen from the sample diffuses
through the membrane and is reduced at  the  gold cathode. The resultant electrical current flow
between the electrodes is proportional to the partial pressure of oxygen in the sample.
Response Times

       Response  times (to 90 percent for step changes of gaseous composition) for the various
gases and instruments (including the sampling probe and train) were as follows:

                                                          90 Percent Response Time,
            Gas             Analysis Technique                      seconds
         CO              NDIR                                     63
         Total HC          Flame-ionization detector                       3
         NO              NDIR                                     60
         SO2              Electrochemical cell                          72
         CO2              NDIR                                     57
         O2               Amperometric                               65

-------
                                           F-l

                                       APPENDIX F
            SAMPLING AND ANALYTICAL PROCEDURES FOR PARTICIPATE
                   AND SMOKE AND DETAILED PARTICULATE DATA
Participate Sampling

       The particulate sampling rig used in this investigation was the EPA sampling train2 -8, with
modifications for oil burner emissions measurements.  Figure F-l shows the particulate sampling
train. For the residential runs,  the sampling probes used were  a combination  nozzle and probe,
15 inches long,  extending out  of the  top of the heated chamber of the sampling  train.  The
cyclone included in the EPA rig was  not used and the probe was connected directly to the filter.
For  the commercial runs, a 36-inch combination probe and nozzle was used and the cyclone was
used. The rest of the train was as shown in Figure F-l, and the procedures of operation (except
probe and impinger washing) were those specified by EPA.

       Velocities in the stacks were measured with a  S-type  Pitot tube. As the firing of the
residential units was  relatively  constant  from cycle to cycle,  S-type  Pitot tube  measurements
were made during the cycle preceding  the beginning of sampling. For sampling from commercial
boilers,  the  S-type Pitot tube and  thermocouple were- attached to the probe and  positioned
adjacent to the sampling nozzle.

       For residential units, it  was not always possible to get reliable  velocity pressure readings,
as some flue gas velocities were so low that the Pitot tube velocity pressures were in the range of
0.002 to  0.005  inch of water.  Hence,  to insure isokinetic  sampling, the  fuel-oil firing rate  was
measured, excess ah"  was determined, and  the flue-gas volume and average velocity were  calcu-
lated and compared with the Pitot tube measurements. (For the as-found runs, the fuel rate  was
measured  after the  run  as a check on isokinetic sampling. For the tuned and reference-fuel runs,
this measurement was made before the run.)

       Traversing was not done during particulate sampling from residential units. In cases where
the velocity profile  across the duct was relatively uniform, the sample was collected by isokinetic
sampling at a velocity about equal to the average velocity. Sampling at the average velocity  was
not possible where velocity profiles were not uniform.

       For particulate sampling from commercial boilers, two traverses were made  at 90° angles.
Sampling was done at four points on  each traverse.

       The sampling  rig was operated in accord with the EPA recommendation,  i.e., the filter
was kept at  a temperature between 230 and 250 F and the impingers were immersed in an ice
bath. The first two impingers contained 100ml of double-dis-tilled water each,  the third impinger
was initially  dry, and the fourth impinger contained about 175 grams of Drierite, Moisture  was
collected in the  impingers  and in the Drierite. The  volume of dry  flue gas sampled for  the
particulate collection run was measured by a dry  gas meter.

-------
                                             F-2
                Probe
        Impingers
                                                                                             13
 1.  Stainless steel, buttonhook-type probe tip
 2.  Stainless steel coupling
 3.  Probe body, 5/8-inch OD, medium-wall
    Pyrex tube logarithmically wound with
    25 feet 26 ga, nickel-chromium wire
 4.  Cyclone and flask (not used for residential
    units)
 5.  Fritted-glass filter holder
 6.  Electrically heated enclosed box
 7.  Ice bath containing four impingers
    connected in series
 8.  The Greenburg-Smith type impinger with
    tip removal
 9.  Second impinger with tip
10.  Third impinger with tip removed
11.  Fourth impinger with tip removed and
    containing approximately 175 grams of
    accurately weighed dry silica gel
12.  Pressure gauge
13.  Check valve
14.  Flexible-rubber vacuum tubing
15.  Vacuum gauge
16.  Needle valve
17.  Leakless vacuum pump
18.  By-pass valve
19.  Dry-gas meter
20.  Calibrated orifice
21. Draft  gauge
22.  5-type pilot tube
                       Figure F-l.  EPA Particulate Sampling Train

-------
                                             F-3

       Before  the sampler was put in operation, it was leak checked to see  that all  the joints
were  tight. The nozzle was plugged with a rubber stopper and  10 inches of vacuum was drawn
on  the system. With this vacuum, no more than 0.02 cfm leakage was permitted; checks showed
that actual leakage usually was much less than this value.

       Silver membrane filters were  used.*  The  filter  for  the residential unit was  a 3-inch-
diameter  silver  membrane  with  a pore size  of 0.8  micron.  Because of the  higher particulate
loadings  expected  when  firing  heavier  fuels in the commercial  boilers,  a 5-inch-diameter silver
membrane filter with a pore size of 0.8 micron was used for those runs.

       For the residential  units, particulate sampling was initiated just  before the start of the
10-minute "on"  cycle and was stopped just  after the  "on" cycle was  completed.  During the
20-minute "off  cycle, there was no particulate sampling. Particulate  was sampled for six firing
cycles to  collect sufficient particulate for weighing.
PARTICULATE ANALYSIS
Moisture Content of Flue Gas

       After  the particulate run was  completed, the moisture content of the  sampled gas was
determined by weighing the Drierite to determine the gain in weight and measuring the amount
of  moisture in  each of the  impingers. These  measurements were used to calculate  the  total
quantity of water in the sample volume and the  moisture content of the flue gas.
Particulate Loading

       The silver membrane filters were dried  and the tare weight obtained before the run was
started.  After  the run, the filter was  removed, dried, desiccated,  and weighed to obtain the
quantity of material collected on the filter.

       As a result of earlier particulate sampling at Battelle-Columbus, questions have arisen as
to whether the EPA  procedure washes all particulate  out of the probe. Hence, the particulate
sampling  for this  project  was designed to  permit samples to be obtained  by both  the  EPA
method  and a modified-EPA  method (MEPA) which included more thorough  washing of the
probe and impingers.**

       Table F-l  shows the steps involved in washing  the probe and impingers  and storing the
samples  for later drying and weighing.  The washing which generated the samples in Containers
2B and 5B were the additional washings not required by EPA.
 *This is a departure from the glass-fiber filters specified by EPA2, but silver filters are superior for detailed
  chemical analysis and are not hydioscopic, a characteristic of glass-fibei filters.
**The modified method is similar to the procedure used in Phase 1 (prior to publication of the EPA procedure).

-------
                                                F-4
                    Table F-1.  Procedures for Recovery of Participate Catches
                           Sample Recovery  From Particulate Sampler.
Container No. 1. Remove the filter from its holder, place in this container, and seal.

Container No. 2A.  Place loose participate matter and acetone washings from all sample-exposed surfaces prior to
the filter (probe and front half of filter) in this container and seal. Use a razor blade, brush, or rubber  police-
man to loosen adhering particles.

Container No. 2B.a  Wash the probe and the front half of the filter holder successively with:
           1. Methylene chloride
           2. Water
           3. Acetone.
Place the washings in this container and seal.

Container No. 3. Measure the volume of water from the first three impingers and place the water in this con-
tainer.  Place water rinsings of all sample-exposed surfaces between the filter and fourth impinger in this con-
tainer prior to sealing.

Container No. 4. Transfer the silica gel from the fourth impinger to the original container and seal.  Use a
rubber policeman as an aid in removing silica gel from the impinger.

Container No. 5A.  Thoroughly rinse all sample-exposed surfaces between the filter and fourth  impinger with
acetone (but do not wash fourth impinger), place the washings in this container, and seal.

Container No. 5B.a  Thoroughly rinse all sample-exposed surfaces between the filter and fourth impinger suc-
cessively with methylene chloride and acetone, place the washings in this container, and seal.

(a)  These  steps are not included in the EPA procedure but were included in this investigation.
        Figures F-2 and F-3 show the drying procedure followed  for  each container obtained in
the  washing  procedure. The weights recorded as "EPA-Probe" and "EPA-Impinger" correspond
to the conventional  EPA  procedure  for obtaining particulate weights.  The weights recorded as
"MEPA-Probe" and "MEPA-Impinger" include the  material  obtained by the additional washing;
they were not a part of the conventional EPA procedure.

        In each step, washing and drying, the above procedures were designed to follow the EPA
procedure first and then to add any additional  steps recommended by  the Battelle staff. Hence,
the additional steps in no way interfered with the EPA  procedure.
RESULTS

        Tables F-2 and F-3 present summaries of the results obtained using the above procedures
for both EPA procedures (EPA) and modified EPA procedures (MEPA).  These tables include:
             • Probe catch
             • Filter catch
             • Impinger catch

-------
                                        F-5
FILTER
                  J   Dry at 212 F

                  J   Oessicate  24 hr
                      Weigh; record as EPA-I
                  7   Seal; lable ; store in refrigerator
PROBE
        EPA probe wash
         Additional
         probe wash
                                              V    I  Clean empty dish; dry at 212 F; dessicate 24 hr



                                              y    I   Weigh; record tare weight
                  f"^   1  Add acetone wash; dry at
                            TT    water        \	
                          PT^\     1
                           \/           \o
w               y-
J<^e1hyle/,        \  I
u ^	-< ?/>,     \ T
                                                     ambient temperature
                                                     Dessicate 24 hr
                         Weigh; record as EPA-2
                                              V   I  Add organic extract; dry at 212 F

                                                I
                                              \   I  Dessicate 24 hr

                                                I
                                              y   7  Weigh ; record as MEPA - 2

                                                I
                                              V   I Cover; lable; store in refrigerator


  Figure F-2.  Procedures for Drying Filter and Probe Portions of Particulate Samples

-------
                                      F-6
JMPINGER


     Water \vOs/,
Chloroform     Ethyl ether
               Chloroforms
               extract —A
                                                  ^   J   Clean; dry at 212 F, dessicate 24 hr

                                                     I
                                                  V   7   Weight; record tare weight

                                                     *__,
                                                           Add water portion;  dry at 212 F
                                                           Oessicale 24 hr
                                                      T

                                                   \     1   Weigh; record as EPA-3B
                                                           Add organic portion; dry at
                                                           ambient temperature
                                                           Dessicate 24 hr
                                                   V    1   Weigh, record os EPA- 3 A
                                                           Add acetone wash; dry at
                                                           ambient temperature
                                                           Dessicate 24 hr
                                                      »

                                                   ^   7  Weigh; record as EPA-5

                                                    .  \
                                                   \    7  Add remaining wash, dry at
                                                   V   /   ambient temperature


                                                   y   7  Dessicate 24 hr



                                                   ^   I  Weigh; record as  MEPA-5

                                                      *
                                                   \   ~7  Cover; lable; store in  refrigerator
   Figure F-3.  Procedures for Drying Impinger Portions of Particulate Samples

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                                           Table F-2.  Summary of Paniculate Emission Data for Residential Units9
Mats of Paniculate Collected, mg
Probe Wnh
Unit
23A
23T
23R
23.2 R
24A
24T
24R
24.2R
2SA
25T
2SR
2S.2R
26A
26T
26 H
26. 2R
27A
27T
28A
28T
29A
29T
30A
30T
31A
31T
32A
32T
33A
33T
34A
34T
35T
3SR
EPA
3.9
1.6
1.3
2.0
1.3
3.7
1.7
SB
1.4
3.4
3.1
6.3
1.6
3.8
2.5
1.9
2.0
2.3
2.1
1.7
3.3
2.7
2.3
2.0
2.1
3.1
2.6
2.6
4.0
3.7
2.3
2.5
2.8
1.4
MEPA
9.8
6.2
5.2
10.1
5.3
9.4
9.7
5.1
5.6
6.4
6.8
22.4
5.8
6 .8
8.2
7.1
11.0
11.1
7.6
6.3
10.0
11.5
6.9
10.2
6.2
7.6
7.8
6.7
14.7
15.4
6.3
6.4
I8.G
13.7
Filter

3.1
1.9
2.6
6.1
3.1
11.0
14.4
5.6
0.4
1.1
1.6
67.8
6.0
4.5
4.8
3.4
8.8
4.5
8.7
2.1
2.5
39.3
4.3
5.1
2.7
3.7
3.6
9.8
14.4
11.3
20.0
9.2
2.1
1.9
Impinger Wash
EPA
9.3
19.1
15.6
21.6
10.8
29.2
10.7
20.6
21.0
11.3
9.0
36.5
26.8
9.7
12.1
13.6
27 S
10.1
26.5
12.3
24.9
23.7
28.8
25.1
26.7
46.6
440
31.8
118.6
101.4
32.8
31.0
59.4
39.5
MEPA
11.8
21.8
17.0
23.9
12.9
30.5
17.3
22.9
21.1
12.5
10.5
40.5
27.7
10.6
13.0
15.6
26.6
16.1
31 .6
18.1
23.7
23.8
29.9
26.2
27.1
44.3
43.1
32.6
106.8
99.3
30.8
29.5
59.7
33.9
Totals, mg
EPA
Filterable
7.0
3.5
3.9
8.1
4.4
14.7
16.1
9.4
1.8
4.5
4.7
74.1
7.6
8.4
7.3
5.3
10.8
6.8
10.8
3.8
5.8
42.0
7.1
7.1
4.8
6.8
6.2
12.4
18.4
15.0
22.3
11.7
4.9
3.3
Total
16.3
22.6
19.6
29.7
15.2
43.9
26.8
30.0
22.8
15.8
13.7
110.6
34.4
18.1
19.4
18.9
38.6
16.9
37.3
16.1
30.7
65.7
35.9
32.2
31.5
53.4
50.2
44.2
137.0
116.4
55.1
42.7
64.3
42.8
MEPA
Filterable
12.9
81
7.8
16.2
84
20.4
24.1
10.7
6.0
7.5
8.4
90.2
13.8
11.3
13.0
10.5
19.8
15.6
16.3
8.4
12.5
50.8
11.7
15.3
8.9
11.3
11.4
16.5
29.1
26.7
26.3
15.6
20.7
15.6
Total
24.7
29.9
24.8
32.0
21.3
S0.9
41.4
32.3
27.1
20.0
18.9
114.6
41.5
21.9
26.0
20.9
46.4
31.7
47.9
26.5
36.2
74.6
41.6
41.5
36.0
55.6
54.5
49.1
135.9
126.0
67.1
4S.1
80.4
49.5
Percent
Filterable
EPA
43
15
20
27
23
33
SO
31
8
28
34
67
22
46
38
28
28
40
29
24
19
64
20
22
15
13
12
28
13
13
40
27
8
8
MEPA
52
27
31
51
39
40
58
33
22
38
44
79
33
52
50
60
43
49
34
32
35
68
28
37
25
20
21
34
21
21
46
35
26
32
Grain Loading
EPA Procedure,
mg/sm3
Filterable
5.8
3.1
3.2
6.3
3.2
13.7
12.5
7.7
1.7
4.4
4.4
647
6.1
6.7
6.0
4.6
9.3
5.6
9.7
3.2
14.4
36.3
5.8
6.1
4.6
9.1
5.3
10.5
15.4
14.1
18.9
10.9
4.2
2.9
Total
13.5
19.7
16.1
23.0
11.0
41.0
20.9
24.6
21.0
15.3
12.8
96.6
27.4
14.5
16.0
16.4
33.1
13.9
33.6
13.5
76.0
56.8
29.5
27.8
30.0
71.2
42.9
37.3
114.3
109.7
46.8
38.9
55.2
37.6
Emission Factor, lb/1000 gal
EPA Procedure
Filterable Total
0.84
0.40
0.44
0.91
0.61
2.03
1.76
1.15
0.25
0.58
0.65
8.21
1.08
1.00
0.87
0.65
1.31
0.88
1.90
0.54
1.91
5.81
0.9B
1.10
0.77
1.23
a.98
1.60
3.24
2.83
2.49
1.44
0.61
0.39
1.94
2.60
2.22
3.33
2.09
6.05
2.93
3.97
3.14
2.03
159
12.25
4.91
2.16
2.32
2.33
4.70
2.18
6.55
2.30
10.13
9.09
4.94
4.98
5.05
9.64
8.00
5.71
24.11
21.95
6.15
5.11
8.04
509
MEPA Procedure
Filterable Total
1.56
0,93
0.8B
1.82
1.17
2.82
2.64
1.31
0.83
0.97
1.16
9.99
1.96
1.35
1.55
1.29
2.40
2.02
2.87
1.19
4.12
7.03
1.62
2.37
1.43
2.04
1.80
2.13
5.12
5.04
2.94
1.92
2.58
1.84
2.94
3.44
2.82
3.E9
2.93
7.02
4.53
4.27
3.73
2.57
2.61
12 89
5.97
2.61
3.11
2.58
5.65
4.09
8.41
3.79
11.95
10.32
5.72
6.42
5.77
10.04
8.69
6.34
23.92
23.76
6.37
5.40
10.05
5.89
Bacharach
Smoke No.
at 9Mln
0.3
0.5
0,4
0.0
0.4
0.7
0.8
0.7
1.0
1.7
0.9
5.8
0.5
0.4
0.5
0.4
1.0
0.4
1.3
0.4
9.0
0.5
0.2
0.6
00
0.2
0.2
0.1
1.5
1.8
2.7
1.0
0.2
0.2
a  EPA refers to EPAProcedure specified in Reference 2.   MEPA refers to "Modified EPA Procedure" described in text.

-------
                                                  Table F-3. Summary of Paniculate Emission Data for Commercial Boilers3
(Mass of Particulate Collected
Probe Wash
Boiler
C2001
C2001
G2001
C2002
C2002
C2002
C2002
C2002
C2003
C2003
C2003
C2003
C2003
C2004
C2004
C2004
C2004
C2004
C2005
C2005
C2005
C2005
C2005
C2006
C2006
C2006
C2006
C2006
Fuel
No. 2
No. 2
Gas
No. 2
No. 4
No. 4
CR
Gas
No. 2
CR
No. 6
No. 6
Gas
No. 2
No. 2
CR
No. 5
Gas
No. 2
CR
No. 6
No. 6
Gas
No. 2
CR
No. 6
No. 6
Gas
Load
H
L
H
H
H
L
H
H
H
H
H
L
H
H
L
H
H
H
H
H
H
L
H
H
H
H
L
H
EPA
2.4
2.4
1.5
4.6
1.6
1.2
4.7
3.6
7.8
95.6
205.6
53.1
3.7
7.3
2.4
16.8
38.3
1.4
1.3
2.4
19.7
6.2
1.7
0.8
22.7
76.1
20.8
3.4
MEPA
12.6
11.2
6.6
9.0
8.9
10.5
12.8
8.9
14.0
102.8
225.4
66.2
10.5
14.0
7.1
23.6
48.7
6.9
6.2
6.3
24.7
11.8
7.1
7.1
27.6
83.9
22.0
8.4
Filter

5.4
9.2
4.2
16.5
34.1
0
228.9
2.0
6.6
261.6
695.3
95.6
0.7
1.9
12.2
58.3
97.4
1.0
4.0
41.6
76.1
40.8
0.9
6.2
50.5
93.1
19.5
4.5
Impinger Wash
EPA
68.9
17.0
25.4
23.0
15.4
55.8
32.2
21.4
14,1
24.5
27.0
70.9
11.6
7.2
42.3
40.5
68.6
4.3
31.8
23.5
50.4
sa.o
13.5
30.8
29.8
38.3
83.4
11.8
MEPA
66.4
20.5
27.7
25.6
19.9
61.1
36.1
25.5
17.5
27.2
30.1
67.9
15.2
9.0
42.0
40.9
66.3
6.2
32.4
25.7
49.3
49.2
13.7
30.8
31.6
37.1
67.8
13.4
EPA
Filterable
7.8
11.6
5.7
21.1
35.7
1.2
233.6
5.6
14.4
357.2
900.9
148.7
4.4
9.2
14.6
75.1
13B.7
2.4
5.3
44.0
95.8
47.0
2.6
7.0
73.2
169.2
40.3
7.9
Totals, mg
MEPA
Total
76.7
28.6
31.1
44.1
51.1
57.0
265.8
27.0
28.5
381.7
927.9
219.6
16.0
16.4
56.9
115.6
204.3
6.7
37.1
67.5
146,2
97.0
16.1
37.8
103.0
207.5
123.7
19.7
Filterable
18.0
20.4
10.8
25.5
43.Q
10.5
241.7
10.9
20.6
364.4
920,7
161.8
11.2
15.9
19.3
81.9
146.1
7.9
10.2
47.9
100.8
52.6
8.0
13.3
78.1
177.0
41.5
129
Total
84.4
40.9
38.5
51.1
62.9
71.6
277.8
36.4
38.1
391.6
950.8
229.7
26.4
24.9
61.3
122.8
212.4
14.1
42.6
73.6
150.1
101.8
21.7
44.1
109.7
214.1
109.3
263
Percent
Filterable
EPA
10
41
18
48
70
2
88
21
51
94
97
68
28
56
26
65
66
36
14
65
66
48
16
19
71
82
33
40
MEPA
21
50
28
50
68
15
87
30
54
93
97
70
42
64
31
67
69
56
24
65
67
52
37
30
71
83
38
49
Grain Loading,
EPA Procedure,
mg/sm3
Filterable
4.6
9.2
2.6
9.6
32 .8
1.4
103.
2.4
11.2
286.
722.
207.
4.0
9.3
6.5
67.6
134.
2.2
5.4
44.6
102.
40.9
2.7
3.3
66.6
235
73.5
45
Total
45.5
227
14.2
20.0
46.9
64.1
117.
11.4
22.2
305.
744.
306.
14.7
166
25.2
104.
202.
6.2
37.5
68.5
156.
84.3
16.7
17.8
93.7
288
226.
11.1
Emission Factor, lh/1000 g
EPA Procedure
Filterable
0.5
1.0
0.3
1.1
3.7
0.2
11.7
0.2
1.2
32.9
87.2
27.0
0.4
1.0
0.8
7.7
16.1
0.2
0.6
6.1
12.6
5.0
0.3
0.4
7.5
27.8
8.6
0.5
Total
4.9
2.4
1.5
2.2
5.3
7.2
13.3
1.1
2.4
36.0
89.9
39.9
1.5
1.8
3.0
11. a
24.3
0.6
4.0
7.8
19.3
10.3
1.6
1.2
10.6
340
26.4
1.2
al»
MEPA Procedure
Filterable
1.2
1.8
0.6
1.3
4.5
1.8
12.1
0.4
1.7
33.6
89.1
29.4
1.0
1.7
1.1
8.4
17.3
0.7
1.2
6.6
13.3
5.6
0.9
0.8
8.0
29.1
8.9
0.8
Total
5.4
3.4
1.9
2.5
6.5
90
13.9
1.5
3.2
35.9
92.1
41.7
2.5
2.7
3.2
12.5
25.3
1.3
4.6
8.5
19.8
10.8
2.2
1.4
11.3
35.1
23.3
1.6
Bacharach
Smoke
No.
2.4
2.8
0.2
0.6
2.3
2.8
3.0
0.1
2.0
3.1
4.2
5.7
0.0
0.2
3.4
2.9
5.0
0.0
0.0
2.5
3.8
3.4
0.1
0.4
3.4
4.1
5.2
0.0
                                                                                                                                                                                     71
                                                                                                                                                                                     DO
a  EPA refers to EPA Procedure specified in Reference 2.   MEPA refers to "Modified EPA Procedure" described in text.
b  Emission factor for gas firing for this table is lb/(145 x  106 Btu), about the same on a Btu basis as lb/1000 gal for oil firing.

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                                             F-9

            •  Filterable catch, probe plus filter

            •  Total catch

            •  Percent filterable

            •  Grain loading

            •  Emission factor

            •  Smoke number,  Bacharach.

       The results of Tables F-2 and  F-3 show  that the revised washing procedure (used in the
"modified" EPA method) did wash  more  material  from the probe than was obtained using
standard  EPA washing  procedures.    Comparative results obtained by  using  the two  washing
procedures are as follows:

                                            Participate Emission Factors, lb/1000 gal
     Average for residential units
     Average for commercial boilers
      firing No. 2
     Average for commercial boilers
      firing No. 4 CR
     Average for commercial boilers
      firing No. 5 and No. 6
Filterable
EPA
1.51
0.83
MEPA
2.43
1.35
Difference
+0.92
+0.52
EPA
5.88
2.74
Total
MEPA
6.76
3.30

Difference
+0.88
+0.56
 9.83    10.57
26.33    27.53
+0.74


+ 1.20
13.00   13.94

34.87   35.44
+0.94


+0.57
On  the average,  sufficient additional particulate was washed from the probe by  the extra
washings used in  the modified procedure to increase emission factors nearly 1.0 lb/1000 gal. The
additional waitings did not increase the particulate associated with the impinger catch.
Impinger Catch

       The filterable ft. otion of the total particulate catch averaged 28 percent (EPA procedure)
or 38 percent (MEPA procedure) for residential units and  54 percent  (EPA procedure)  or  58
percent  (MEPA  procedure) *br oil-fired boilers. Questions  arise as  to  the composition  of the
remainder  of  the total  partifilate  catch - that portion  associated with  the impinger. The
detailed  analyses that would be r.. quired to determine the exact nature of the impinger catch was
not  a part of this  study.  Howeve*  some analyses of impinger  samples were made during the
Phase I study.

       Analyses  of the  impinger samples,  for  C,  H, and N accounted for 11  percent  of the
impinger catch for samples  from  residential units and  33  percent  of  the  impinger catch for
samples  from oil-fired commercial boilers.  Sulfur analyses were made on impinger samples from
the commercial boilers.* These analyses identified sulfur present in quantities that represented  15
to 99 percent of the impinger catch. Assuming that  the sulfur is present as SO3  (possibly in
H2SO4 or  sulfates), the quantities of sulfur compounds present were calculated  to be 38  to 248
*One-half of the impinger catch was dried (within about 2 months of the sampling) to obtain the weight of the
 particulate catch. The remaining one-half of the impinger catch was analyzed for total sulfur about 6 months
 after the sampling.

-------
                                           F-10

percent of the impinger catch.  The problem associated with finding SO3 in quantities greater
than the mass of dried particulate illustrates the difficulties encountered in making sense out of
impinger catch data. Apparently, large quantities  of S02 are retained in the  impinger solutions
and, over a period  of  time, some of the SO2 is oxidized to S0315. It may have been that some
SO2 was driven off those portions of the samples used for  the particulate weight determinations
during the  drying  operation. However, during the interval about 4 months before the sulfur
analyses were made on the  remaining portions of the samples, additional SO2 may have oxidized.
Thus, the latter analyses gave sulfur quantities  higher than  the total particulate from the former
analyses.
SMOKE SAMPLING TECHNIQUES

       Two  techniques for sampling smoke were used. Use of the standard Bacharach hand-
pump smoke meter and ASTM Procedure D2156-657  was the primary method of smoke spot
sampling.  The ports for the gaseous measurements were  used  as sampling locations for  smoke
measurements. If conditions suggested erroneous readings due to greatly disturbed  air flow, the
sample was taken through the particulate  sampling  port. However,  in most cases  the gaseous
ports were adequate.

       For the residential units, Bacharach smoke readings were made at the  1-minute, 5-minute,
and  9-minute points of the "on"  cycle.  As expected, the smoke number usually decreased as the
cycle proceeded. The  decrease between the 1- and 5-minute points generally was much greater
than that  between the  5- and 9-minute points.

       To enable  the  field  team to monitor the  variations in  smoke during the cyclic runs, a
Von Brand continuous recording smoke meter was used. During a run, the vacuum pump was
started 15 seconds prior to ignition. This permitted observation .of smoke levels for the air in the
stack prior to firing of the burner.  Smoke levels were monitored continuously  throughout each
on-cycle until all evidence of smoke associated with  shutdown had ceased. This smoke persisted
from 1 second to 30 seconds. The smoke associated with burner startup and shutdown coincided
with the CO and HC peaks noted  for the gaseous emissions.

       A  Photovolt reflectometer with  tricolor  filter was used to obtain  numerical reflectance
values from the Bacharach smoke  spots according to ASTM standard procedures7.  This provided
a means  for  accurately reading the  smoke  spot while reducing the  possibility of human error
caused by inadequate lighting, colored material, or oil on the smoke spot.

       An attempt was made  to correlate reflectometer readings from the Bacharach  smoke
spots to similar  readings of the Von Brand tape traces. A good correlation was not obtained for
the low smoke levels of interest (below about a No. 3 or 4 Bacharach  smoke).
15   Hillenbrand, L. J., Engdahl, R. B., and Barrett, R. E., "Chemical Composition of Particulate Air Pollutants
     from Fossil Fuel Combustion Sources", Final Report on EPA Contract EHSD 71-29, March  1,  1973.

-------
                                           K-l

                                     APPENDIX K *
                   DETAILS OF EMISSION-FACTOR CALCULATIONS
                             AND CONVERSION FACTORS
       Emission factors are commonly defined in terms of the weight of pollutant emissions per
unit of fuel input - either weight, volume, or Btu heating value of the fuel. For purposes of this
report, emission factors for oil-fired equipment are expressed in terms of pounds of pollutant per
thousand gallons of fuel oil input, as this is the basis of the published emission factors compiled
by  EPA3,  and it  also is convenient in developing emission inventories.

       Calculation of the  emission  factors  requires data on  (1)  the  concentration of the
pollutant (e.g., ppm for gaseous pollutants or dust loading in mg/sm3 for particulate) and (2) the
rate of generation  of  flue gas.  This latter  quantity may be  determined by  one of several
approaches, depending on data available. Four  alternate approaches are  feasible, requiring the
following information:

           (1) Measurement of flue-gas flow rate, plus flue-gas analysis (used where
               fuel composition and firing rate  are unknown)

           (2) Measurement of flue-gas flow rate, plus fuel firing rate

           (3) Fuel firing rate, plus flue-gas  analysis (the most frequently used
               technique)

           (4) Fuel composition (C-H), plus flue-gas analysis.

Of  these approaches, the fourth was chosen as being consistently the most accurate  for the
conditions of the field investigation. This approach is outlined in the following section.
Combustion Calculations

       The combustion equation, assuming that all of the sulfur and nitrogen  from the  fuel
appear as SO2 and NO in the flue gas and that CO and HC in the flue gas are negligible, is

                       CHESFNG + (1.0 + 0.25E + F + 0.5G + X)O2

                           +[(1.0 + 0.25E + F + 0.5G + X) 3.77]N2 = CO2  + 0.5E-H2O

                           + F-SO2 + G-NO + X-O2

                           +[(1.0 + 0.25E + F + 0.5G + X) 3.77]N2

where E = ratio of hydrogen atoms to carbon atoms in the fuel,

(*) Appendices G through J are not included in this volume; they appear in
    the Data Supplement Volume which  is available as a separate report
    (EPA-R2-73-084b).

-------
                                           K-2

                               £ _ 12.01 • (wt% H in fuel)
                                   1.008 • (wt%Cinfuel)

F = ratio of sulfur atoms to carbon atoms in the fuel,

                               F= 12.01 - (wt%S in fuel)
                               r   32.06 • (wt%C in fuel)

and G = ratio of nitrogen atoms to carbon atoms in the fuel

                                    12.01 • (wt%N in fuel)
                                   14.008 (wt%C in fuel)

and X = ratio of percent O2 to percent CO2 in flue gas.

From this  equation, a predicted  CO2  and O2 concentration  for  the  dry  flue  gas  can  be
expressed as

                                                     i r\f\
              C02 in flue gas, percent = 4777T4777XT0.94E + 4.77F~l89G


               _  .  _             t   _ 100X    _
               02 in flue gas, percent = 4.77 + 4.77x + 0.94E +~4.77F + 2.89G

Solving each of these equations for X gives

                                        100 - CO,  [4.77 + 0.94E + 4.77F + 2.89G]
                                            -    ,    .      .
         X (based on CO2 measurement) = - ^77

                                          O2  [4.77 + 0.94E + 4.77F + 2.89G]
             X (based on O2 measurement) = --- J-QQ — , ,  ~~ — TT-^T -


where CO2 and O2  are the CO2 and O2 concentrations in the flue gas. Excess air (EA) in terms
of the above combustion equation is defined as


                          EA, percent = j;0 + 0.25E -TFT"a5G~


Thus, excess air can be calculated either based on CO2 or O2 readings from the flue-gas analysis
as

                                            100-XCo2    __
                        EAC02, percent   I.Q + Q.25E + F + 0.5G

or

                                            100- X0
EA02, percent = or^SE + F + 0.
                                                           5G.

-------
                                             K-3

Values for excess air calculated by these two routes did not always agree for this investigation.
(Usually, the difference was small, less than 10 percent). The reliability of the CO2  and O2 field
measurements were  considered and  judged to be similar.  Thus, an average value  was used to
define the actual excess air:
                             EA', percent =

Likewise,
                                              +X°2
       The weight (W) of dry flue gas generated  in  pounds per pound of fuel  fired at this
average excess air is


      W^(1.Q.44.01)+(F.64.06)+(G-30.01)+(X'.32.0)+[(1.0+Q.25E+F-K).5G+X')3.77-28.02]
                              (12.01)+(E.1.008)+(F-32.06)+(G. 14.01)


       The volume (V) of dry flue gas generated (standard cubic feet per pound of fuel fired) is

                                             W
                                        V =
                                            0.075  '
^12%  co   and V3% o, are defined as the volume of dry flue gas generated per pound of fuel
fired at 12% CO2 and at 3% O2 in the flue gas, respectively.


Emission  Factor Calculations,  lb/1000  gal

       Gaseous emission factors, EF, can now be calculated as


                    nr: /iu   11  +   W.nnn   if  n   V • PPM • MW •  FD
                    EFa (Ib pollutant/ 1000 gal fuel) = - 3g6 . 1000 -


where  PPM = concentration of pollutant in flue gas (dry)

        MW = molecular weight of pollutant

        FD = fuel density in Ib/gal.

Particulate emission factors, EF', can  be calculated as follows:


                       EF'a (Ib particulate/1000 gal fuel) =
where  GL = grain loading measured in sampled gas in mg per standard cubic meter (dry
             at 77 F).

-------
                                           K-4


Converting to Other Emission Factor Units


       Emission factors in lb/1000 gal can be converted to other units as follows:




       Gaseous Emissions.


           EFb  (kg pollutant/1000 liter fuel) = EFa .0.1198

                                            EFa
           EFC  (Ib pollutant/1000 Ib fuel)   = j^


                                                  EF
           EFd  (g pollutant/kg fuel)        = EFC = -^


                                                    EF,  • 1000
           EFe  (Ib pollutant/106  Btu)       = rr—	,    Cf  , /P+ <   n
              e                              Heating value  of fuel (Btu/gal)



It is sometimes convenient to express emissions in  ppm at some standard condition, for example:

                                            PPM • V
       EFf (ppm pollutant at  12% CO2!. dry) = ~	—
                                           v 1 2 % c o 2


                                           EFa • 386 • 1000

                                         = MW.FD.V12%C02


and

                                         PPM  • V
       EF. (ppm pollutant at 3% O5, dry) = r;	
         9                               V3%  o2



                                         EFa  • 386 • 1000
                                         MW.FD.V3%02




       Paniculate Emissions. Similarly for particulates, EFb', EFC', EFd', and EFB' follow from

EFg'. Additional emission factors are sometimes used for particulate emissions as follows:


                    EFh' (Ib particulate/106 scf flue gas at 12% CO2, dry)



                                ^ GL • 1000      V
                                    15800   'V12%C0
or
                                    EFar - 1000
                                  FD • V
                                        12% CO
                                               2

-------
                                           K-5

and EF,' (Ib particulate/106 scf Hue gas at 3% O2 dry)


                                    GL- 1000
                                     15>800   'V3%0.
                                   EF ' •  1000
                                   FD 'V3% o2
Conversion Factors for No. 2 Fuel Oil


       For a typical No. 2 fuel oil of 33 degrees API gravity,


            FD           =7.17 Ib/gal


            Heating value  = 139,900 Btu/gal


            Analysis      = 87.0% C
                           12.6% H
                           0.17% S
                           0.007% N


            Vi2%co2    = 243 cu ft/Ib fuel


            vs% o2       = 219 cuft/lb fuel.


Then


            EFC (Ib pollutant/ 1000 Ib fuel)        = 0.139 •  EFa


            EFd (g pollutant/kg fuel)             = 0.139-EFa


            EFC (Ib pollutant/ 106 Btu)            = 0.0071 5 -EFa

                                                 222-EF.
            EF, (ppm pollutant at 1 2% CO2 , dry)  = — jpy —


                                                 246 -EF
            EFg (ppm pollutant at 3% O2 , dry)
and
           EFh' (Ib particulate/106 scf flue gas
                at 12%C02)dry)                = 0.574-EFa'
           EF? (Ib particulate/106 scf flue gas
               at 3% O2, dry)                   = 0.637.EFa'

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                                            K-6

Conversion Factors for No. 6 Oil

       For a typical No. 6 fuel oil of 15 degrees API gravity,

            FD            = 8.05 Ib/gal

            Heating value  = 151,200 Btu/gal

            Analysis       = 86.8% C
                            11.1% H
                            1.70%S
                            0.30% N

            vi 2% co      = 243  cu ft/lb fuel

            vs% 02       = 214  cu ft/lb fuel

Then

            EFC (Ib pollutant/ 1000 Ib fuel)                      = 0.124 • EFa

            EFd (g pollutant/kg fuel)                           = 0.124 • EFa

            EFe (Ib pollutant/106 Btu)                          = 0.00661 • EFa

                                                                197-EF
            EF, (ppm pollutant at 12%  CO2, dry)                =
and
                                                                224-EF
            EFg (ppm pollutant at 3% O2 , dry)                  =
EFh' (Ib particulate/106 scf flue gas at 12% CO2, dry)= 0.511-EFa'



EF[ (Ib particulate/106 scf flue gas at 3% O2, dry)    = 0.580-EF,',
Emission Factor Calculations, Gas Firing

       Emission factors can be calculated for gas firing in  a similar manner  as  for oil firing
(although other calculation-procedures may be simpler for gas  firing, only). For example,
            EFr (Ib pollutant/1000 Ib fuel)

and
                                              V.GT
            EFr'(Ib paniculate/1000 Ib fuel)  =

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                                            K-7

Assuming

            Density gas   = 0.0458 Ib/ft3, standard conditions

            Heating value = 1020 Btu/ft3

            Analysis      = 75% C
                           25% H

            V3% o2      = 246 cu ft/lb fuel

Then

            EFS (lb pollutant/106 cu ft)       =45.81 •  EFr

or

                                            _ V-PPM.MW
                                               8430

likewise,

            EFj (lb particulate/106 cu ft)


and

           EFt (lb  pollutant/109  Btu)         = 44.91 •  EFr
or
                                           _ V-PPM-MW
                                                8590
likewise,

            EFt' (lb particulate/109 Btu)
and
                                             EF...386-1000
            EFU (ppm pollutant at 3% Cfe, dry) = „«,,-,	
                                             iVlW-V
or
                                             1570-EFr
                                                 MW~
                                             PPM-V
                                              246

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                                              K-8
and
                 (lb particulate/106 scf flue gas at 3% O2> dry) = ^-L

                                                                 '3% O2
                                              = 4.065 -EFr
or
                                                V-GL
                                                3890
Summary of Conversion Multipliers for Oil Firing

       Table K-l  summarizes  conversion  multipliers for  some  of the  common methods  of
expressing emission factors.
                     Table K-1.  Multipliers to Convert Emission Factors From
                                Lb/1000 Gal To Other Units
To Obtain Emission Factor
in These Units
Kg /1000 liter fuel
Lb/1000 lb fuel
Gm/kg fuel
Lb/106 Btu input
Gaseous pollutants'c)
ppm at 12% CO2
Ppm at 3% 02
Particulates
Lb/106 scf flue gas at 12% CO2
Lb/106 scf flue gas at 3% O2
Multiply Emission
lb/1000 Gal Fuel
No. 2 Oil's I
0.1198
0.139
0.139
0.00715
222
MW
246
MW
0.574
0.637
Factor in

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                                            L-l

                                       APPENDIX L



                              ERRATA TO PHASE 1 REPORT


       During the interval between the publication of the report  on Phase I of this study and
the present time, several points were identified where clarification or corrections are in order for
information contained in the Phase I  report1. The following sections discuss these points and
identify corrections as necessary.

       Wherever  Phase I results have  been incorporated in this Phase II  report,  the  corrected
values have been used.
CO Emission Data

       Emission values for CO in the  Phase I report (Tables IV-1 and VI-1) are high, as the raw
NDIR  data  were not corrected for CO2 interference. One percent of CO2 produces an equivalent
output from the CO NDIR as 1.25 ppm CO. Hence, about 10 percent CO2 produces CO readings
that are high by  12.5 ppm. Consequently, CO emission factors tabulated in Tables IV-3 and VI-4
are high by the ratio of CO uncorrected to CO corrected. The CO emission factors for oil-fired
residential units and commercial boilers are high by about 2.0 lb/1000 gal.
Table 1-3, Emission Factors From
Residential Furnaces

       The NOX  emission  factors reported in Table 1-3 for the APCO Research Laboratory
studies are incorrect. Correct values are as follows:

                   Modern burners, Reference 4      Average  16.1
                                                   Range    13.4-18.8

                   Modern burners, Reference 5      Average  12.5
                                                   Range     8.5  - 15.5

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                                            L-2
Table VI-7, Emission Factors for Gas-Fired
Commercial  Boilers
                     Table IV-1.  Corrected  Emission Factors for Phase I
                                 Gas-Fired Commercial Boilers


                                      Emission Factors,  lb/106 cu ft, natural gasa
Paniculate
Unit
C1004



Condition
H
M
L
Mean
CO
3.6
6.2
2.7
4.2
HC
0.6
0.5
0.6
0.6
SO2
40
38
47
42
IMOX
53
40
39
44
Filterable
•9
-
3
6
Total
19
-
17
IS
               Emission factor in lb/10^ Btu input.
Nitrogen in Distillate Fuel Oils

       Kjeldahl analyses of the No. 2 fuel oils fired in the residential units indicated consistently
lower values for fuel nitrogen for the Phase II fuels compared to the Phase I fuels. The Phase II
fuel nitrogen analyses were confirmed by a round-robin program, with analysis by five different
laboratories. Repeat analyses of two Phase I fuels produced fuel nitrogen levels that were lower
than those reported in the  Phase I report by a factor of about 5. Hence, it must be concluded
that fuel  nitrogen  analyses of the No. 2 fuel oils fired during Phase  I are high by a factor of
about 5.
Ratio of NO to NO2

       Measurements of NOX for the Phase  I study indicated that about 22 percent of the NOX
was  emitted as NO2.  Phase II measurements, which used improved methods for measuring  NO
and  NOX emissions, gave a  ratio of NO2 to NOX  of about 0.2.  However,  there is a possible
interference of CO with NOX measurement when large concentrations of CO are present. When
the Phase II data for units emitting less than  100 ppm of CO are considered, the ratio of NO2 to
NOX is only 0.09.  Hence, it is concluded that NO2  emissions are usually less than 10 percent of
the total NOX for residential furnaces.

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                                          M-l

                                     APPENDIX M

                                     REFERENCES

 1.  Levy, A., Miller, S.  E., Barrett, R. E.,  Schulz,  E.  J., Melvin, R. H., Axtman, W. H., and
    Locklin.  D. W., "A  Field Investigation of Emissions from Fuel Oil Combustion for Space
    Heating", API  Publication 4099 (November 1, 1971),  available from the API Publications
    Section,  1801 K Street, N.W., Washington, D. C. 20006.

 2.  "Standards of  Performance  for New Stationary Sources", Federal Register, Vol.  36, No.
    139, Part II, pp 24876-24895, December 23, 1971.

 3.  "Compilation of Air Pollutant Emission  Factors", U.  S. Environmental Protection Agency,
    Office of Air Programs Publ. No. AP-42 (February 1972).

 4.  "The Typical Oil Burner", Fueloil and Oil Heat, Vol. 31, No. 6 (June 1972), pp 4445.

 5.  Special Study, Fueloil and Oil Heat, Vol. 30, No. 1 (January  1971), pp 22, 24.

 6.  "Standard Method of Test for Effect of Air Supply on Smoke Density in Burning Distillate
    Fuel", ASTM D2157-65(70).

 7.  "Standard Method of Test for Smoke  Density in the Flue Gases from Distillate Fuels",
    ASTM D2156-65(70).

 8.  "Standards of  Performance  for New Stationary Sources", Federal Register, Vol.  36, No.
    139, Part II, pp 15704-15722, August 17, 1971.

 9.  "Standards of Performance for  New Stationary Sources", Federal Register, Vol. 37, No. 55,
    Part I, pp 5767, March 21, 1972.

10.  Martin, G. B., and  Berkau,  E. E., "An  Investigation  of the  Conversion of Various Fuel
    Nitrogen Compounds to Nitrogen Oxides in Oil Combustion",  presented at AIChE Meeting,
    Atlantic  City, N.J., August 30, 1971.

11.  Turner, D. W., Andrews, R. L., and Siegmund, C. W., "Influence of Combustion Modifica-
    tion and Fuel Nitrogen Content on Nitrogen Oxides Emissions  From Fuel Oil Combustion",
    presented at AIChE Meeting,  San Francisco, November 28-December 2, 1971.

12.  Bartok, W., Crawford, A.  R., Cunningham, A. R., Hall, H. J., Manny, E. K.,  and Skopp, A.,
    "Systems Study of Nitrogen  Oxide Control Methods for Stationary Sources", Final Report,
    Esso Res. & Engrg. Co., November 20, 1969, NAPCA Contract  PH-22-68-55.

13.  Private  communication:  to  D.  W. Locklin,  Battelle-Columbus,  from  Margaret  Mantho,
    Fueloil & Oil Heat, May, 1972.  Similar data were published in Reference 4.

14.  "Combustion Chambers by Types", Fueloil & Oil Heat, Vol. 31, No. 5, March 1972, p. 94.

15  Hillenbrand, L. J., Engdahl, R. B., and Barrett, R. E., "Chemical Composition of Particulate
    Air Pollutants from Fossil Fuel Combustion'Sources",  Final Report on EPA Contract EHSD
    71-29, March 1, 1973.

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      M-2
BIBLIOGRAPHIC DATA '• Report No.
SHEET EPA-R2-73-084a
Field Investigation of Emissions from Combustic
Equipment for Space Heating
7. Author(s)
R. E. Barrett , S. E. Miller , and D. W. Locklin
9. Performing Organization Name and Address
Battelle - Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
12. Sponsoring Organization Name and Address
EPA, Office of Research and Development
NERC-RTP, Control Systems Laboratory
Research Triangle Park, North Carolina 27711
15. Supplementary Notes
2- 3- Recipient's Accession No.
5- Report Date
m June 1973.
6.
8. Performing Organization Rept.
No.
10. Project/Task/Tork Unit No
11. Contract/Grant No.
68-02-0251
13- Type of Report & Period
Covered
Final
14.

is. Abstracts The report gives results of a 2-year field investigation of air-pollutant
emissions from 33 residential heating units and 13 commercial boilers. It includes
effects of combustion parameters and fuel-oil compositions, as well as measurements
of CO, HC, NOx, SO2, particulate , and smoke. The largest residential emissions
reduction resulted from replacing poorly perform ing units.
Burners with flame -retention combustion heads had lower overall emissions than those
with conventional heads; newer burners had lower emissions than older ones. Emissior
from commercial boilers (40-600 boiler hp) were measured for 33 combinations of
boilers and fuels at various loads and excess air settings. Generally, operating
parameters within the normal adjustment range had minor effect on emissions. Fuels
investigated were natural gas and five grades of fuel oil, including a 1%-S residual
oil. Fuel characteristics significantly affected emissions , especially particulate and
17. Key words and Document Analysis. 17a. Drscriprars
Air Pollution Nitrogen Oxides
Space Heating Nitrogen Oxide (NO)
Residential Buildings Nitrogen Dioxide
Commercial Buildings Particulate Composites
Combustion Smoke
Emission Carbon Monoxide
Burners Hydrocarbons
Boilers Sulfur Oxides
Furnaces Sulfur Dioxide
17b. [dencif iers/Open-Hnded Terms
Air Pollution Control No. 5 Oil
Stationary Sources No. 6 Oil
Emission Factors
No. 2 Oil
No. 4 Oil
17c. COSATI Field/Group 13B, 7C
18. Availability Statement
Unlimited
INUX. £or oil iiring, INUX
emissions increased nearly
linearly with fuel-N content.
Sulfur Trioxide
Natural Gas
Fuel Oil
19. Security Class (This 21- No, of Pages
Report) 1QQ
UNCLASSIFIED laa
20. Security Class (This 22. Price
Page
UNCLASSIFIED
•{[ G. P. O. 1974— 747-791 / 3AB. REGION NO. 4
                                                  USCOMM-DC 14952-P72

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