AN EVALUATION OF CONTROL STRATEGIES
FOR STATIONARY FUEL BURNING SOURCES
IN THE THIRTY INNER CITIES AND TOWNS
OF THE METROPOLITAN BOSTON
INTRASTATE AIR QUALITY CONTROL REGION
Prepared under
Contract No. 68-02-0049
JUNE 1973
Prepared for
DEPARTMENT OF PUBLIC HEALTH
COMMONWEALTH OF MASSACHUSETTS
Boston, Massachusetts
and
ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF AIR PROGRAMS
Raleigh, North Carolina
.toward a better environment..
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AN EVALUATION OF CONTROL STRATEGIES FOR STATIONARY
FUEL BURNING SOURCES IN THE THIRTY INNER CITIES
AND TOWNS OF THE METROPOLITAN BOSTON
INTRASTATE AIR QUALITY CONTROL
REGION
Principal Author
Dr. Richard D. Siegel
Contributing Authors
Edward W. Rich
Paul Morgenstern
June 1973
Prepared for
Department of Public Health
Commonwealth of Massachusetts
Boston, Massachusetts
and
Environmental Protection Agency
Office of Air Programs
Raleigh, North Carolina
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Section
TABLE OF CONTENTS
Title
Paqe
I INTRODUCTION 1-1
A. Regulatory Background 1-1
B. Study Objecti ves 1-1
C. Methodology 1-5
II SUMMARY 2-1
A. Emission Reductions 2-2
B. Technical Feasibility 2-11
C. Economic Impact of Control Strategies 2-13
D. Administrative Requirements 2-16
E. Conclusions 2-16
F. Recommendations 2-19
III EMISSIONS AND EMISSIONS REDUCTION 3-1
A. Source and Fuel Inventory 3-1
B. Emission Factors 3-4
IV TECHNICAL FEASIBILITY 4-1
V CAPITAL AND OPERATING COSTS 5-1
VI ADMINISTRATIVE REQUIREMENTS 6-1
VII REFERENCES 7-1
APPENDIX A SOURCE AND FUEL USE INVENTORIES A-l
APPENDIX B EMISSION FACTORS B-l
LIST OF FIGURES
Figure No. Caption Page
1-1 Boundaries of the Survey Area with Massachusetts Plane
Coordinate System Overlay 1-4
1-2 Flow Schematic of Analysis Procedures 1-6
3-1 Subdivision of Total Fuel Use by User Categories and
Type of Use 3-2
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LIST OF TABLES
Table No. Title Paje
2-1 Particulate and S02 Emissions from Stationary Fuel Burn-
ing Sources in the 30 Cities 2-3
2-2 Fuel Consumption in 30 Cities 2-4
2-3 Particulate and S02 Emissions from Stationary Fuel Burn-
ing Sources in the 30 Cities when Natural Gas Particu-
late Emissions are Assumed to be Zero 2-6
2-4 1975 Particulate and S02 Emissions from Stationary Fuel
Burning Sources in the 30 Cities 2-8
2-5 1972 Particulate and S02 Emissions from Transportation
and Non-Fuel Burning Sources in the 30 Cities 2-9
2-6 1973 Base Case Particulate and S02 Emissions from Non-
Stationary and Non-Fuel Burning Sources in the 30
Cities 2-9
2-7 Total Particulate and S02 Emissions from All Sources
in the 30 Cities and Percent Reduction (From 1973
Base Case) 2-10
2-8 Total Particulate and S02 Emissions from All Sources
in the 30 Cities and Percent Reduction (Percent of
1973 Base Case) When Natural Gas Particulate Emissions
are Assumed to be Zero 2-12
2-9 Summary of Capital and Annual Operating Costs of Each
Control Strategy 2-14
4-1 Procedures for Control of Particulate Emissions from
the Stacks of the Boston Edi son Company 4-5
5-1 Summary of Capital and Annual Operating Costs of Each
Control Strategy 5-4
5-2 Wholesale Fuel Oil Prices in the 30 Cities (cents/
gallon) 5-6
5-3 Capital Cost of Electrostatic Precipitation Facility
which will Perform Fuel Washing 5-8
5-4 Capital Cost of a Waste Treatment Faci1ity 5-8
5-5 Operating (Electricity) Cost for an Electrostatic Pre-
cipitation Facility which Performs Fuel Washing 5-9
5-6 Capital Cost of Centrifugation Facility which will
Perform Fuel Washing 5-9
5-7 Steam Costs: Block Rate A 5-12
5-8 Demand Rate Cost of Steam 5-12
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LIST OF TABLES (continued)
Table No. Title Page
5-9 Retail Fuel Oil Prices in the 30 Cities 5-13
6-1 Annual Manpower Requirements for Strategy A (Conversion
to Distillate Fuel Oil by All Sources with a Heat Input
Less Than 10 MMBtu/hr) 6-2
6-2 Annual Budget Requirements for Strategy A (Conversion
to Distillate Fuel Oil by All Sources with a Heat In-
put Less Than 10 MMBtu/hr) 6-3
6-3 Annual Manpower Requirements for Strategy B (Annual
Inspect!on and Peri odic Mai ntenance) 6-5
6-4 Annual Budget Requirements for Strategy B (Annual In-
spection and Periodic Maintenance) 6-6
6-5 Annual Manpower Requirements for Strategy C (Fuel
Washing) 6-7
6-6 Annual Budget Requirements for Strategy C (Fuel
Washing) 6-8
6-7 Annual Manpower Requirements for Strategy E (Sources
with a Heat Input of Less Than 10 MMBtu/hr Switching
from Oil to Natural Gas) 6-10
6-8 Annual Budget Requirements for Strategy E (Sources with
a Heat Input of Less Than 10 MMBtu/hr Switching from Oil
to Natural Gas) 6-11
A-l Estimated 1972 Consumption of Natural Gas and Coal in
the 30 Cities A-2
A-2 Estimated 1972 Fuel Oil Consumption Inventory in the
30 Cities A-3
A-3 Estimated Number of Oil-Fired Boilers in the 30 Cities
in 1972 A-4
A-4 Estimated 1973 Base Case Consumption of Natural Gas
and Coal in the 30 Cities A-8
A-5 Estimated 1973 Base Case Fuel Oil Consumption Inventory
in the 30 Cities A-9
A-6 Estimated Number of Oil-Fired Boilers in the 30 Cities
in the 1973 Base Case A-10
A-7 Population and Economic Growth Figures A-l3
A-8 Estimated 1975 Consumption of Natural Gas and Coal in
the 30 Cities A-l3
A-9 1975 Fuel Oil Consumption Inventory in 30 Cities A-14
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LIST OF TABLES (continued)
Table No. Title Page
B-l EPA Emission Factors for Fuel Oil Combustion B-2
B-2 Emission Factors for Natural Gas and Coal Combustion ... B-3
B-3 Revised Emission Factors for Fuel Oil Combustion B-4
B-4 Emission Factors for Fuel 011 Combustion, Strategy B:
Inspection and Maintenance B-7
B-5 Procedures for Control of Particulate Emissions from
the Stacks of the Boston Edison Company B-9
B-6 Emission Factors for Fuel Oil Combustion, Strategy C:
Fuel Washing B-10
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ACKNOWLEDGMENTS
This work was supported under Contract No. 68-02-0049 by the Environ-
mental Protection Agency. Portions of the information used in this program
were provided by the following organizations. Their assistance and coopera-
tion are gratefully appreciated.
Bureau of Air Quality Control, Commonwealth of Massachusetts; Region
I Staff, Environmental Protection Agency; Boston Air Pollution Control
Commission; Maryland Bureau of Air Quality Control; Frank I. Rounds Co.;
Cleaver-Brooks; Combustion Service of New England; U.S. Carl in Company;
Atlantic Fuel Oil Co., Inc.; J. A. Marino Automatic Heating Company;
Packer Commercial Combustion Co., Inc.; Better Home Heat Council, Inc.;
Babcock and Mil cox Research Center; Combustion Engineering Inc.; New
England Fuel Institute; Atlantic Richfield Company; C. H. Sprague & Son
Company; Buckley and Scott Company; Gibbs Oil Company; Northeast Petroleum
Corp.; Quincy Oil Company; Union Oil Company; White Fuel Corp.; General
Electric Company; Long Island Power and Light Company; DeLaval Separator
Company; R. W. Beck & Associates; Environmental Protection Agency, Re-
search Triangle Park; Petrolite Corp.; Boston Edison Company; Commonwealth
Gas and Electric Company; Cambridge Steam Company; Edison Electric Insti-
tute; Department of Public Utilities, Commonwealth of Massachusetts;
American Gas Association Laboratories; Illinois Institute of Gas Tech-
nology; Bethlehem Steel Corp.; Mystic Valley Gas; Algonquin Gas Trans-
mission Company; Boston Gas Company; Harvard University, School of Public
Health; Combustion Engineering Associates; National Oil and Fuel Insti-
tute; Esso Research and Engineering Company; Battelle Memorial Institute;
Ralph Keys Assoc.; and New England Power Service Company.
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I. INTRODUCTION
A. REGULATORY BACKGROUND
The 1970 Amendments to the Clean Air Act specified that each of the
states must submit a plan to the Administrator of the Environmental Protec-
tion Agency by January 31, 1972 for the implementation, maintenance and en-
forcement of the national primary and secondary air quality standards. The
objective of these plans was to establish a set of procedures to achieve
the designated primary air quality standards by 1975 and the secondary air
quality standards "within a reasonable time." The Metropolitan Boston In-
trastate Air Quality Control Region was granted an eighteen month extension
for the development of a plan to attain secondary standards for total sus-
pended particulate matter and sulfur dioxide concentrations (Federal Regis-
ter, Vol. 37, No. 105, May 31, 1972 - 37CFR10846). Simultaneously, EPA
approved an extension of the deadline for achieving these standards in the
Region until eighteen months after the 1975 compliance date for the attain-
ment of the primary standards. However, a recent federal court interpreta-
tion of EPA's legal authority negated all such compliance extensions, neces-
sitating attainment of the mandated secondary standards by mid-1975.
B. STUDY OBJECTIVES
Wai den Research Corporation has been retained by the Environmental
Protection Agency to evaluate a number of emission control strategies spec-
ified by the EPA and the Commonwealth of Massachusetts Bureau of Air Quality
Control for fuel burning sources within 30 inner cities and towns of the
Metropolitan Boston Intrastate Air Quality Control Region. This project
was designed to provide information for the Bureau to assist them in the
development of a plan for attainment of the national secondary air quality
standards for particulates and sulfur dioxide. Although the strategies are
aimed at compliance by 1975, the year 1973 was selected as the base year*
*
By base year, we refer to the use of an adjusted 1973 source and fuel in-
ventory as the basis for our estimates of emission reductions, technical
feasibility, capital and operating costs, and administrative requirements
for each of the strategies.
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for analysis and evaluation since reliable growth factors were not readily
available (1) for projecting fuel combustion in the Boston area and (2) for
estimating contributions from other sources (solid waste incineration,
process losses, transportation) to the total participate and sulfur dioxide
emission burden in the area in 1975.
The objective of the program, as defined by EPA, was to determine
the emission reduction associated with each control strategy and to estab-
lish the technical feasibility, capital and operating costs, and administra-
tive requirements associated with each of the selected approaches. The
strategies included in the evaluation were:
(a) Conversion to distillate fuel oil by all sources
with a heat input of less than 10 MMBtu/hr,*
(b) Annual inspection and periodic maintenance pro-
gram for all sources to assure optimum combustion
conditions,
(c) Application of fuel washing techniques to remove
particulates from fuel,
(d) Purchase of steam from a local steam generating
station for heat, and
(e) Sources with a heat input of less than 10 MMBtu/hr
switching from oil to natural gas.
These control measures can be applied singly or in various combinations.
The combinations which were examined in addition to the basic strategies
were:
(f) Conversion to distillate fuel oil by all sources
with a heat input of less than 10 MMBtu/hr coupled
with an inspection and maintenance program on all
sources in order to achieve optimum combustion
conditions,
(g) Conversion to distillate fuel oil by all sources
with a heat input of less than 10 MMBtu/hr coupled
with application of a fuel washing process to re-
move particulates from the fuel,
*
MMBtu/hr is used throughout this report as an abbreviation for million
Btu/hr.
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(h) Sources with a heat input of less than 10 MMBtu/hr
switching from oil to natural gas coupled with an in-
spection and maintenance program on all sources in
order to achieve optimum combustion conditions,
(i) Sources with a heat input of less than 10 MMBtu/hr
switching from oil to natural gas coupled with a
fuel-washing process to remove particulates from
the fuel.
In addition, we also examined the strategy of:
(j) Sources with a heat input of less than 10 MMBtu/hr
switching from oil to electric heat.
The selected study area is shown in Figure 1-1 and contains the
bulk of the stationary fuel burning sources in the control region. The
cities and towns included in this region are:
Arlington Needham
Belmont Newton
Boston Peabody
Braintree Quincy
Brookline Revere
Cambridge Saugus
Canton Somerville
Chelsea Stoneham
Dedham Wakefield
Everett Waltham
Lynn Watertown
Maiden Weymouth
Medford Winchester
Mel rose Winthrop
Milton Woburn
Thirteen of these cities have been designated by the Bureau of Air Quality
Control as areas of critical concern and constitute the "core area." These
municipalities are:
Arlington Maiden
Belmont Medford
Boston Newton
Brookline Somerville
Cambridge Waltham
Chelsea Watertown
Everett
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550 660 670 630 690 700 710 720 730 740 750 760 770 700
570
560
550
540
530
520
510
500
490
480
470
460
450
=- 440
430
420
410
-»400
Figure 1-1. Boundaries of the Survey Area with Massachusetts
Plane Coordinate System Overlay.
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The remaining seventeen cities have been designated as the "outer cities"
in this study.
C. METHODOLOGY
Evaluation of the five basic strategies and the five combination
strategies included:
(a) Determination of the emission reduction that will
occur by implementation of each strategy.
(b) Determination of the technical feasibility of each
control strategy, including whether technical
capabilities and fuel supplies presently exist for
implementation.
(c) Determination of the capital and operating costs
for implementation of each strategy.
(d) Determination of the administrative requirements of
each strategy, including additional resources that
will be necessary.
Figure 1-2 is a flow schematic of our overall analysis procedure. The
methodology used to calculate emissions from stationary fuel-combustion
sources generally conformed with the survey techniques developed by the
EPA [1,2], In its simplest form, the basic plan of this approach consists
first of inventorying the consumption of fuels for generating power, for
space heating, and for industrial process and other needs. The pollutant
emissions arising from these sources is then estimated by the application
of appropriate emission factors in conjunction with selected fuel composi-
tion parameters.
The emission factors used with the fuel use inventory were developed
by analysis of the most recent test results on oil, gas, and coal combustion
in stationary sources. The factors were structured to represent local
rather than national conditions as much as possible and to give maximum
differentiation to burners by size and fuel use. The data currently avail-
able, however, were inadequate to develop statistically reliable emission
factors for different burner types (e.g., rotary cup, pressure atomizing).
The basic set of emission factors was supplemented with data to
reflect the effectiveness of various control techniques in the designated
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o
m
STRATEGY
REQUIREMENTS
p
w
EMISSION
FACTORS
TECHNICAL
FEASIBILITY
CRITERIA
COST
FACTORS
ADMINISTRATIVE
CRITERIA
SOURCE AND/OR
FUEL
INVENTORIES
EMISSIONS
TECHNICAL
FEASIBILITY
COSTS
MANPOWER
REQUIREMENTS
8
TO
70
Figure 1-2. Flow Schematic of Analysis Procedures.
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strategies. The emission factors were then applied to the relevant fuel
consumption inventory to yield estimated emissions for stationary fuel
burning sources for each of the selected strategies.
The economic impact of each strategy was determined by assessing
the capital and annual operating costs associated with implementation. The
cost figures were obtained by determination of the most significant param-
eters associated with each strategy and by applying differential and/or
absolute costs to the corresponding source and fuel inventories. Cost
figures are based on 1973 data, and do not reflect changes which will re-
sult from shifts in future supply and demand including those shifts which
will be a direct consequence of implementation of the strategies evaluated
in this report.
The technical feasibility of each control strategy was assessed
through an evaluation of two general criteria: were there any technical
or engineering obstacles that could delay implementation of the control
plan, and were there sufficient fuel supplies to cope with the increased
demands associated with the fuel switching strategies. Our procedure with
the first criteria involved a detailed analysis and interpretation of the
engineering requirements for each strategy. Evaluation of fuel supplies
was conducted by a review of local and national fuel availability reflect-
ing current and projected import oil and gas quotas.
Administrative requirements were established by an assessment of
the manpower requirements associated with the enforcement of each of the
control strategies. These requirements were translated further into
needed funding resources.
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II. SUMMARY
Ten strategies for the control of participate and sulfur dioxide emis-
sions from stationary combustion sources in the 30 inner cities and towns
of the Metropolitan Boston Air Quality Control Region have been evaluated
with respect to emission reduction, technical feasibility, capital and
operating costs, and administrative requirements. These strategies are:
A. Conversion to distillate fuel oil by all sources with a
heat input of less than 10 MMBtu/hr.
B. Annual inspection and periodic maintenance program for
all sources to assure optimum combustion conditions.
C. Application of fuel washing techniques to remove particu-
lates from fuel.
D. Purchase of steam from a local steam generating station
for heat.
E. Sources with a heat input of less than 10 MMBtu/hr
switching from oil to natural gas.
F. Conversion to distillate fuel oil by all sources with a
heat input of less than 10 MMBtu/hr coupled with an in-
spection and maintenance program on all sources in order
to achieve optimum combustion conditions.
G. Conversion to distillate fuel oil by all sources with a
heat input of less than 10 MMBtu/hr coupled with a fuel
washing process to remove particulates from the fuel.
H. Sources with a heat input of less than 10 MMBtu/hr
switching from oil to natural gas coupled with an in-
spection and maintenance program on all sources in order
to achieve optimum combustion conditions.
I. Sources with a heat input of less than 10 MMBtu/hr
switching from oil to natural gas coupled with a fuel
washing process to remove particulates from the fuel.
J. Sources with a heat input of less than 10 MMBtu/hr
switching from oil to electric heat.
Strategies A, E, F, G, H, and I share common requirements for changes
in the fuel burning patterns in the Metropolitan Boston area and for con-
version or replacement of existing burners or burner components. Strate-
gies B, F, and H require the practice of higher levels of service and
cleaning on the existing burner and boiler population. Strategies C, G,
and I relate to a technique known as fuel washing developed by the General
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Electric Company in Lynn, Massachusetts, to remove soluble corrosive salts
from residual fuels preparatory to their use in gas turbines. This process
has also t:en found effective in controlling particulate emissions from the
combustion of residual fuels by removing the majority of the sediment ash
related constituent of the particul ate effluent. Strategy D, purchase of
steam for space heating, also requires a change in the fuel burning pattern
in the core area. Its successful implementation is dependent on the con-
struction of additional generating facilities and distribution networks to
deliver the required steam. Strategy J, conversion to electric heat, also
requires a change in the fuel burning pattern, but was not evaluated quan-
titatively since preliminary calculations indicated that a net increase in
emissions would result from its implementation. This is a consequence of
the greater amount of fuel that would be required for utility-supplied
electric heating than for on-site fuel burning, and because residual oil,
with a higher emission factor, would replace the use of cleaner burning
distillate oil in many cases.
A. EMISSION REDUCTIONS
Determination of the emissions that would occur by implementation
of each strategy was accomplished by application of the appropriate set of
emission factors to the corresponding elements of the fuel use inventory.
Details of the development and results from the source and fuel use in-
ventory are presented in Appendix A; the emission factors used and their
basis are presented in Appendix B.
1. Emissions from Fuel Burning Sources
Table 2-1 summarizes the predicted emissions for the 1973 pre-
strategy base case and for each emission control strategy. The 1973 base
case represents an adjustment of the 1972 fuel consumption inventory by
accounting for programmed changes in fuel utilization due to existing air
pollution control regulations. This adjustment does not reflect any
Table 2-2 summarizes the fuel consumption in the area for 1972 and for the
1973 pre- and post-strategy cases.
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TABLE 2-1
PARTICULATE AND S02 EMISSIONS FROM STATIONARY
FUEL BURNING SOURCES IN THE 30 CITIES
Strategy
1972*
1972
1973 Base Case
1973 Strategy A
1973 Strategy B
1973 Strategy C
1973 Strategy D
1973 Strategy E
1973 Strategy F
1973 Strategy G
1973 Strategy H
1973 Strategy I
Parti culates (tons/yr)
13 Core 17 Outer Total
11,053
5,361
4,893
4,417
3,736
4,135
4,883
3,843
3,260
3,778
2,686
3,204
The EPA (AP-42) emission
with the emission factors
4,016
1,955
1 ,872
1,262
1,620
1,621
1,872
1,002
1,010
1,120
750
15,069
7,316
6,765
5,679
5,356
5,756
6,755
4,845
4,270
4,898
3,436
860 4,064
factors were used
from the present
so2
13 Core
52,195
51,950
47,707
44,056
47,707
47,707
47,658
31 ,839
44,056
44,056
31 ,839
31 ,839
in this case
study.
(tons/yr)
17 Outer Total
30,729
30,887
29,223
19,793
29,223
29,223
29,223
14,272
19,793
19,793
14,272
82,924
82,837
76,930
63,849
76,930
76,930
75,881
46,111
63,849
63,849
46,111
14,272 46,111
for comparison
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TABU 2-2
FUEL CONSUMPTION IN 30 CITIES
Source
Category
Residential
0-6 MMBtu
6-10 MMBtu
10-30 MMBtu
X 30-250 MMBtu
>250 MMBtu
(non-utility)
All Utility
TOTALS
1972
Number of
Oil Fired
Boilers
465,737
5,696
2,321
146
83
15
50
474 ,050
1972
Fuel Oil
Consumption
Distillate Residual
(1000 gal) (1000 gal)
698,608
66,617
27,248
1,219
3,205
796,897
228,437
231,588
39,356
94,191
117,943
743,482
1,453,997
1973
Base Case
Distillate
Changes
(1000 gal)
+167,545
+167,545
1973
Strategy A
Distillate
Changes
(1000 gal)
+60,892
+231 ,588
+292,480
1973
Strategy D
Residual
Changes
(1000 gal)
-8,707
+ 706
-1,646
1973
Strategy E
Gas
Changes
(million ft3)
+93,124
+39,371
+34,503
+166,998
% Change from
1972 Fuel
Consumption
+21%
+37%
Total 1972 gas consumption was 57,920 million ft3
+288%
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potential change in the total amount of fuel consumed in the area in 1973
due to growth, population shifts, and climatological factors. It is based
strictly on those changes which are scheduled to occur during calendar
1973, and which we have elected to apply on an annual basis. These changes
are:
(1) Conversion of the three principal coal users
(Boston Public School System) to distillate
oil.
(2) Conversion of the 3-6 MMBtu/hr size residual
oil burners in the 13 core cities to distil-
late oil.
(3) Closure of the Massachusetts Electric Power
Plant in Lynn.
Table 2-1 also includes emissions predictions for 1972 using
both our revised set of emission factors and the so-called "AP-42 Factors"
[3]. These latter factors were used by Waiden in a previous emission in-
ventory study for Metropolitan Boston [4] and reflect a national rather
than local mixture of burner-boiler types. It is highly significant that
the emission predictions using our revised factors indicate that the con-
tribution of particulates from stationary fuel burning sources to the
local paniculate emission inventory is less than half of that predicted
by the AP-42 factors. Any effort to determine the effect on ambient air
quality levels from control of stationary fuel burning sources on air
quality leads should recognize this factor and make use of the revised
fuel use inventory presented in this study.
As discussed in Appendix B, we suspect that even our revised
particulate emission factor for natural gas is conservatively high. There-
fore, in order to bracket the range, we have included another table of
emissions in which we assume that particulate emissions from combustion
of natural gas are zero; this result is presented in Table 2-3.
As previously discussed, it is desirable to consider the emis-
sion reductions that a strategy will achieve by mid-1975 since that is the
current deadline for meeting secondary standards. Emission factors were
applied to a projected 1975 inventory of fuel burning sources, described
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TABLE 2-3
PARTICIPATE AND S02 EMISSIONS FROM STATIONARY FUEL BURNING
SOURCES IN THE 30 CITIES WHEN NATURAL GAS PARTICULATE
EMISSIONS ARE ASSUMED TO BE ZERO
Strategy
Particulates (tons/yr)
13 Core 17 Outer Total
S02 (tons/yr)
13 Core 17 Outer Total
1972
5,189 1,895 7,084 51,950 30,887 82,837
1973 Base Case
4,721 1,812 6,533 47,707 29,223 76,930
1973 Strategy E 3,211 734 3,945 31,839 14,272 46,111
1973 Strategy H 2,054 482 2,536 31,839 14,272 46,111
1973 Strategy I 2,572 592 3,164 31,839 14,272 46,111
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In Appendix A, in order to develop a 1975 emissions inventory. These re-
sults are presented in Table 2-4. Note again that we did not extend our
analysis to total 1975 emissions in the region since we did not have an
adequate basis for estimation of 1975 emissions from non-stationary fuel
burning sources.
2. Emissions from Other Sources
In order to evaluate the effectiveness of each strategy in
reducing total particulate and S02 emissions, it is necessary to consider
the contributions from mobile and/or non-fuel burning sources. For the
purposes of this study, the information and emissions developed previously
for the 30 cities for the year 1970 [4], were used under the assumption
that these "other" emissions would not change significantly by 1972.
Three major sources are contained in this "other" category -- process
losses, transportation source emissions, and solid waste incinerator
emissions. A tabulation of the emission contributions from these sources
in 1972 is contained in Table 2-5.
Regulation 2.5.3 of the Commonwealth's Air Pollution Control
regulations will require all solid waste incinerating facilities to meet
specific particulate emission limitations by 1975. For the purpose of
this analysis, we have included the changes brought about by these regu-
lations in the 1973 emission estimates. The final 1973 base case emis-
sions from all "other" sources is shown in Table 2-6.
3. Total Emissions and Percent Reduction from All Sources (1973)
Particulate and S02 emissions from "other" sources (which are
described above) were added in each case to emissions from the stationary
fuel burning sources to obtain a total emissions estimate. These results
are given in Table 2-7 and show that the maximum reductions of the total
particulate and S02 burden in the area occurs with Strategy H (conversion
to gas, coupled with inspection and maintenance), producing a decrease of
27% and 372, respectively. Again, we include a tabulation of total emis-
sions when the natural gas particulate emissions are assumed to be zero;
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TABLE 2-4
1975 PARTICIPATE AND S02 EMISSIONS FROM STATIONARY
FUEL BURNING SOURCES IN THE 30 CITIES
Strategy
Particulates (tons/yr)
13 Core 17 Outer Total
S02 (tons/yr}
13 Core 17 Outer Total
1975
5,118 1,984 7,102 49,826 31,001 80,827
1975 Strategy A 4,604 1,325 5,929 45,883 20,817 66,700
1975 Strategy B 3,906 1,718 5,624 49,826 31,001 80,827
1975 Strategy C 4,319 1,716 6,035 49,826 31,001 80,827
1975 Strategy D 5,106 1,984 7,094 49,763 31,001 80,764
1975 Strategy E 4,021 1,056 5,077 33,361 15,077 48,438
1975 Strategy F 3,392 1,059 4,448 45,883 20,817 66,700
1975 Strategy G 3,933 1,175 5,108 45,883 20,817 66,700
1975 Strategy H 2,810 791 3,610 33,361 15,077 48,438
1975 Strategy I 3,351 906 4,257 33,361 15,077 48,438
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TABLE 2-5
1972 PARTICULATE AND SOg EMISSIONS FROM TRANSPORTATION
AND NON-FUEL BURNING SOURCES IN THE 30 CITIES
Emission Source
Process Losses
Solid Waste Incineration
Transportation
TOTAL
Participates
(tons/yr)
302
5,294
4.357
9 ,953
S02
(tons/yr)
1,604
637
4,865
7,106
TABLE 2-6
1973 BASE CASE PARTICULATE AND S02 EMISSIONS FROM
NON-STATIONARY AND NON-FUEL BURNING
SOURCES IN THE 30 CITIES
Emission Source
Process Losses
Solid Waste Incineration
Transportation
TOTAL
Parti culates
(tons/yr)
302
810
4.357
5,469
S02
(tons/yr)
1,604
637
4.865
7,106
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TABLE 2-7
TOTAL PARTICULATE AND S02 EMISSIONS FROM ALL SOURCES
IN THE 30 CITIES AND PERCENT REDUCTION
(FROM 1973 BASE CASE)
Strategy
1972* Emissions
1972 Emissions
1973 Base Case
1973 Strategy A
1973 Strategy B
1973 Strategy C
1973 Strategy D
1973 Strategy E
1973 Strategy F
1973 Strategy G
1973 Strategy H
1973 Strategy I
Parti culates (tons/yr)
-.-i Percent
lotal Reduction**
25,022
17,269
12,234
11,148
10,825
11,225
12,224
10,314
9,739
10,367
8,905
9,533
- 105%
- 41%
9%
12%
8%
'v 0
16%
20%
15%
27%
22%
S02 (tons/yr)
T-+.I Percent
lotal Reduction**
90,030
89,943
84,036
70,955
84,036
84,036
83,987
53,217
70,955
70,955
53,217
53,217
- 7%
- 7%
16%
'x/ 0
^ 0
'u 0
37%
16%
16%
37%
37%
The EPA (AP-42) emission factors were used in this case for comparison
with the emission factors from the present study.
**
A negative value indicates an increase.
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these figures constitute Table 2-8 and indicate an additional differential
emission reduction potential of 6% associated with the uncertainty in the
emission factor.
B. TECHNICAL FEASIBILITY
Our analysis of the technical feasibility associated with imple-
mentation of each of the designated control strategies fell into two gen-
eral categories:
(1) Were there any technical, i.e., engineering,
obstacles that could delay application of each
strategy,
(2) Were there sufficient supplies of distillate
oil, natural gas, or steam available to accom-
modate the proposed strategies.
In general, it is our judgment that there are no engineering reasons why
any of the strategies could not be implemented to control particulate and
SOp emissions from stationary fuel burning sources. However, our assess-
ment of Strategies A, F, and G (which include conversion to distillate oil
by all sources less than 10 MMBtu/hr) indicates a requirement for approxi-
mately 37%* more distillate oil for their implementation than the estimated
1972 consumption in the 30 cities and towns. This is in addition to the
21%* increased demand due to programmed changes such as the switching of
units 3-6 MMBtu/hr in the 13 core cities and towns from residual to distil-
late in July 1973. Similarly, our analysis of Strategies E, I, and J
(which include increased use of natural gas in sources less than 10 MMBtu/
hr) indicates a requirement for approximately 288%* more natural gas than
the estimated consumed in 1972 in the 30 cities and towns. Given .the ex-
isting uncertainty in the national oil import policy, our nationwide short-
age in petroleum refining capacity, and the widening national gap between
natural gas supply and demand, there is little likelihood that either fuel
could be supplied to the area by 1975 in sufficient quantity to satisfy the
*See Table 2-2.
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TABLE 2-8
TOTAL PARTICULATE AND S02 EMISSIONS FROM ALL SOURCES
IN THE 30 CITIES AND PERCENT REDUCTION (PERCENT
OF 1973 BASE CASE) WHEN NATURAL GAS
PARTICULATE EMISSIONS ARE
ASSUMED TO BE ZERO
Parti dilates (tons/yr)
Strategy
1972 Emissions
1973 Base Case
1973 Strategy E
1973 Strategy H
1973 Strategy I
A negative value
Total
17,037
12,002
9,414
7,981
8,612
indicates an
Percent
Reduction*
- 42%
22%
33%
28%
increase.
so2
Total
89,943
84,036
53,217
53,217
53,217
{tons/yr )
Percent
Reducti on*
- 7%
37%
37%
37%
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requirements of the foregoing control strategies. From this perspective,
Strategies A, F, G, E, I, and J are not feasible.*
C. ECONOMIC IMPACT OF CONTROL STRATEGIES
The estimated capital and operating costs of each strategy are
summarized in Table 2-9. In most cases, a set of high and low values are
provided to bracket uncertainties in the cost factors. Sources of the un-
certainty in the cost factors are described below.
Strategy A. Conversion to distillate fuel oil by all sources
with a heat input of less than 10 MMBtu/hr.
The low estimate of both capital and operating costs were obtained
by assuming 90% burner conversion and 10% replacement of units which cannot
be made to burn efficiently through minor adjustments from a combustion
point of view, the units must be replaced. The high estimates were obtained
by assuming 100% replacement of burners.
Note that the costs given for this strategy do not reflect the in-
crease in the price of distillate oil which would certainly result from its
implementation.
Strategy C. Application of Fuel washing techniques to remove par-
ti culates from fuel.
The higher of the two price estimates for this strategy in both
the capital cost and the operating cost change categories corresponds with
the use of the electrostatic precipitator method of fuel washing. The
other method considered, and the one to which the lower cost figures apply,
is the use of centrifugation in the process. Note that there is a signifi-
cant potential fuel saving in the operating cost which is associated with
a reduction in fuel consumption of up to 5% as a result of increased fuel
combustion efficiency. We have not combined the operating cost change fig-
ures because of the uncertainty involved with the exact amount of the fuel
*
The impact of the President's energy policy announcement of April 18, 1973
has not been considered in reaching this conclusion.
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TABLE 2-9
SUMMARY OF CAPITAL AND ANNUAL OPERATING COSTS
OF EACH CONTROL STRATEGY
Strategy
A
B
C
D
E
F
G
H
I
*
Due to Increased
**
A positive value
Capital Cost
(millions of dollars)
Low estimate 10.4
High estimate 23.6
0
Low estimate 6.5
High estimate 7.3
Potential saving*
Low estimate 0.01
High estimate 0.05
Low estimate 270
High estimate 450
Low estimate 10.4
High estimate 23.6
Low estimate 16.9
High estimate 30.9
Potential saving*
Low estimate 270
High estimate 450
Low estimate 277
High estimate 457
Potential saving*
combustion efficiency.
indicates an increase.
Annual Operating
Cost Change
(millions of
dollars per year)**
-3.9
+1.2
+0.6
+1.5
+1.8
-7.8
+0.36
+0.44
+9
-3.3
+1.8
-2.4
+3.0
-7.8
+9.6
+10.5
+10.8
- 7.8
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savings, but the net result is surely a net decrease or saving in annual
operating costs.
Strategy D. Purchase of steam from a local steam generating sta-
tion for heat.
About 224,000 Ib/hr of steam at peak loading is available in the
13 core cities* (actually, this is a reserve capacity that would not nor-
mally be sold). Because of the nature** of the emission factors and be-
cause of the fact that utilities primarily burn #6 oil, we have assumed
that all conversions will be sources using #6 oil in the size range 6 to
30 MMBtu/hr in the 13 core cities region. The low estimate of the capi-
tal cost was obtained by assuming that users of approximately 30 MMBtu/hr
size would switch to steam (five users). The high estimate of capital cost
reflects switching of 6 MMBtu/hr size (24 users). The low estimate of the
increase in operating cost was obtained for the case of 6 MMBtu/hr size
units switching while the high operating cost increase estimate corresponds
to switching by the 30 MMBtu/hr size units.
Strategy E. Sources with a heat input of less than 10 MMBtu/hr
switching from oil to natural gas.
The low estimate of capital cost was obtained by assuming 90%
conversion of oil burners and 10% replacement. The high estimate was
calculated by assuming 100% replacement of burners.
Strategies F. G. H, and I. Combination strategies.
The high and low estimates of capital and operating costs for
each of these strategies is equal to the sum of the respective high and
low cost estimates for each of the component strategies.
*
Currently, Cambridge and Boston are the only cities in the region with
steam distribution networks.
**
e.g., distillate and #4 oil factors are less than utility factors.
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D. ADMINISTRATIVE REQUIREMENTS
Administratively, we conclude that there is a common requirement
for the successful implementation of each of the strategies, i.e., completion
of the current source registration program, particularly for units in the
3 to 10 MMBtu/hr size range. This information will provide the Bureau of
Air Quality Control with essential data on source location and on their
emission characteristics, and forms the basis for surveillance and enforce-
ment of each of the control strategies. The registration should be com-
pleted as soon as possible to build the initial data base and should be
updated at least on an annual basis. On an individual basis, Strategy B
(inspection and maintenance) necessitates a substantial inspection program
by the Bureau to assure that the required maintenance program is conducted
by each fuel burning source.
We note that registration and inspection programs are currently a
part of the Bureau's operation. Due to the strong interactions of these
strategies with current agency programs, we have therefore only re-esti-
mated total administrative requirements under the assumption of a compre-
hensive enforcement plan.
E. CONCLUSIONS
Those strategies associated with alteration of the fuel burning
pattern in the Metropolitan Boston area offer the greatest potential for
reducing the particulate and sulfur dioxide emission burden due to sta-
tionary fuel burning sources in the region. However, the maximum reduc-
tion in total particulate and sulfur dioxide emissions in the 30 selected
cities and towns of the region are only 27% and 37%, respectively. Those
strategies which are not fuel dependent, i.e., Strategy B (inspection and
maintenance) and C (fuel washing) will only reduce the region's total par-
ticulate burden by 12 and 8 percent, respectively, and are totally ineffec-
tive in controlling S02 emissions.
Comparison of the predicted emissions for fuel burning sources in
the 30 cities and towns using the EPA "AP-42" and our revised sets of emis-
sion factors indicates (see Table 2-7) that the contribution of this source
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category to the total participate emissions in the area is significantly
less than originally predicted in Reference 4.* Hence, the potential re-
duction in air quality levels that can be achieved by further control of
these sources is considerably less than one might infer from our earlier
inventory report (i.e., Reference 4).
Those strategies associated with major changes in the fuel use
patterns in the area, i.e., strategies associated with additional use of
distillate oil or natural gas, appear to possess major obstacles to imple-
mentation projections of inadequate supplies of distillate oil and natural
gas in the Metropolitan Boston area through at least 1975. Current pro-
jections indicates an increasing inability on the part of local oil and
gas suppliers to cope with existing demands for these fuels both at the
present time, and in mid-1975 when secondary standards are to be achieved.
Reserve steam availability is also quite low and is projected to remain so
indefinitely unless and until a specific demand is placed on the existing
distribution systems. A minimum of three years will be required from the
time steam customers are signed to a contract until the necessary supply
capacity could be developed. Fuel supply (distillate, gas, and steam) is
thus the principal obstacle associated with implementation of each of the
strategies. There are no engineering obstacles that we could determine
to the implementation of each of the strategies.
We also note that there is uncertainty over the potential effec-
tiveness of a burner adjustment program (as opposed to outright burner
replacement). Many of the burner installers in the Metropolitan Boston
area insist that an oil burner originally designed to operate on residual
fuel will operate with poorer performance (i.e., high maintenance require-
ments, poor combustion performance) and higher emissions after conversion
to distillate oil. This is claimed to be especially true of the older
rotary cup burners prevalent in Greater Boston. The installers therefore
The emission predictions included in Reference 4 were for a different
year and a different fuel use pattern (e.g., high sulfur oils) than is
the current practice in Metropolitan Boston. The implication here is
that the former predictions, though valid for the prior design year,
cannot be applied today.
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maintain that the burners should not be adjusted, but should instead be
replaced with more efficient pressure atomizing units. There is even a
consensus of opinion on their part that replacement of old rotary units by
new pressure atomizing burners operating on residual oil would result in
almost as great a reduction in particulate emission as would exist if the
new units were also required to operate on distillate oil. A strategy as-
sociated with a ban on rotary burners and their replacement with residual
fired pressure atomizing burners would likely significantly relieve the
distillate oil supply problem discussed above. Unfortunately, we were not
able to resolve these uncertainties in order to quantitatively evaluate
such a strategy.
With respect to economic impact, Strategies B and C are the most
attractive. Strategy B, which involves a cleaning and maintenance program,
is attractive because there is no associated capital outlay and because its
implementation would yield an increase in burner efficiency which can be
directly translated to a lower fuel requirement for a given facility.
Strategy C, involving fuel washing, offers a potential long-range saving
since there also appears to be an increased combustion efficiency associ-
ated with washed fuel. Strategy A, conversion to distillate, and strat-
egies coupled with it, involve very significant capital costs due to burner
conversion or replacement. Strategy E, conversion to gas, and strategies
coupled to it, although offering significant emission reductions, have even
larger capital costs (associated with burner conversion and replacement)
due to the large number of sources that would have to be converted. Strat-
egy D, conversion to steam heat, does not appear economically attractive
because of its small impact on emissions. Thus, considering the only cost
and the availability of the required fuel supplies, Strategies B and C,
which are totally ineffective in controlling SO,, emissions, and relatively
ineffective in controlling particulates, are the only two strategies that
could be readily implemented to aid in the attainment of secondary air
quality standards in the Metropolitan Boston region.
Administratively, we have determined that completion of the
Bureau's source registration program, particularly for units in the 3 to
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10 MMBtu/hr size range, will be required for the successful implementation
of each of these strategies. This requirement does not represent an addi-
tion to the Bureau's already budgeted plans for financial and manpower
resources.
F. RECOMMENDATIONS
Our assessment of the feasibility of those strategies discussed
above that are dependent on alteration of the fuel burning pattern in the
Metropolitan Boston area indicated that there was an inadequate supply of
distillate fuel oil and natural gas available to implement said strategies
by the 1975 compliance deadline. However, these same strategies generally
are potentially the most effective of the evaluated strategies for con-
trolling particulate and sulfur dioxide emissions from stationary fuel
burning sources. We therefore recommend that a re-examination of the im-
plementation of these strategies at a different target date be undertaken
based on an examination of local fuel interconvertability and on projected
availability of alternative fuel supplies to the Boston area. It is our
considered opinion that, given a different time frame than that associated
with a 1975 compliance deadline, several of the strategies associated with
increased use of "cleaner fuels" might become the most feasible approaches
to controlling stationary source particulate and sulfur dioxide emissions.
Such a study was beyond the scope of our analysis but is certainly within
the scope of the problem of controlling stationary source emissions.
Our study, and all similar analyses of emissions due to station-
ary source fuel combustion, are strongly limited by the field data avail-
able for development of a reliable set of source emission factors. Con-
siderable emphasis in this study was given towards developing an appropri-
ate set of emission factors for use with our source and fuel use inven-
tories. Those factors that were developed are based on the most current
data available on fossil fuel combustion in stationary sources. In many
cases, however, our data base was severely limited and the factors do not
have a statistically sound basis. Consequently, we strongly recommend
that additional testing of burners/boilers be conducted both to validate
the finesse of our factors and to refine said factors to reflect
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parameters such as burner age, type, and geographic population. Such a
finesse will, for example, be particularly useful in performing a quanti-
tative assessment of the position adopted by burner installers in the
Metropolitan Boston area that installation of new residual oil fired
pressure atomizing burners will be almost as effective a means of reducing
particulate emissions as if said new units were also required to operate
on distillate oil.
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III. EMISSIONS AND EMISSIONS REDUCTION
All pollutant emissions can be broadly categorized as those from
stationary sources and those from non-stationary (transportation) sources.
The latter category includes all modes of combustion-powered transporta-
tion including automobiles, buses, trucks, trains, vessels, and aircraft.
The stationary sources include fuel combustion, solid waste disposal, and
process losses; fuel combustion sources may be further classified into
different user categories and type of use as illustrated in Figure 3-1.
The major categories of source types shown in this chart include domestic
(residential), commercial, institutions, manufacturing, and steam-electric
utilities. Most of these can be further classified as point sources which
represent individual establishments emitting relatively large quantities
of contaminants, as distinguished from area sources which represent, col-
lectively, a large number of smaller sources distributed over the survey
district. The basic structure for classifying fuel consumption shown in
Figure 3-1 was used in the current inventory. Aside from its general util-
ity, this system allows for a subsequent comparison of the survey results
with those completed in a similar manner for other control regions.
The methodology used to calculate emissions from combustion sources
generally conformed with the survey techniques developed by the Environ-
mental Protection Agency [1, 2]. In its simplest form, the basic plan
of this approach consists of first determining the consumption of fuels
for generating power, space heating, and other industrial process needs.
The emission of pollutants arising from these sources is then estimated
by the application of appropriate emission factors in conjunction with
selected fuel composition parameters. The key elements required for
calculation of the emissions from combustion sources are, therefore, a
source and fuel use inventory and a corresponding set of emission factors.
A. SOURCE AND FUEL INVENTORY
For the purpose of this study, we confined our inventory analysis
to stationary fuel combustion sources in the 30 inner cities and towns in
the Metropolitan Boston Air Quality Control Region. The basis for the in-
ventory is a set of survey forms submitted to the Commonwealth during 1970
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ANNUAL
STUDY AREA
USE Of EACH
Figure 3-1. Subdivision of Total Fuel Use by User
Categories and Type of Use.
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and 1971 for source inventory and in 1972 for registration purposes.
These forms represent the most comprehensive survey conducted to date and
constitute a size stratified sampling of the total number of emission
sources in the district.* Specifically, the inventory is most complete
for sources greater than 10 MMBtu/hr and becomes less comprehensive with
decreasing boiler size.
Our approach to completing the inventory in order to evaluate
the control strategies made use of 1971 Bureau of Mines statewide totals
of fuel oil consumption by grade and application. These data were then
refined using census data to yield estimates for consumption of the various
grades of oil in the 30 cities and towns. Census data was also used to
calculate consumption in the 13 core and 17 outer municipalities. A more
thorough description of this procedure is included in Appendix A. Natural
gas consumption for the region was obtained directly from the gas companies
serving the area.
The preceding treatment enabled us to compile a complete fuel
burning source inventory in the 30 cities and towns for calendar year
1971. Clearly, changes in fuel consumption have occurred during the
intervening months due to fluctuations in both population and climate
(e.g., 1972 was a milder year than 1971 requiring less fuel for space
heating applications). These two factors were found to have changed such
that the effect of one on fuel consumption cancelled the effect of the
other. Hence, we have determined that the 1971 inventory is represen-
tative of 1972 fuel consumption in the area. Projected population growth
in the 13 core and 17 outer cities and towns was used to estimate growth
of the domestic fuel inventory from the end of 1972 to the Commonwealth's
mid-1975 target date for achievement of the secondary air quality standards.
An assumed growth rate of 3% per annum was used to project point source
growth in the commercial and industrial categories; an average growth
Our source inventory was categorized by fuel type, unit size, and source
location within either the 13 core cities and towns (area of critical con-
cern) or within the 17 outer cities and towns of the region covered by this
study.
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factor representative of the distribution of electric power to its customers
(i.e., domestic, commercial and industrial sources) was used with the
utility inventory.*
B. EMISSION FACTORS
Computation of the pollutant emissions arising from the combus-
tion of fuel for each of the control strategies was performed by applica-
tion of appropriate emission factors to a corresponding source inventory.
The most widely-accepted set of factors are those assembled and published
by the Environmental Protection Agency in Reference 3. These factors
(referred to as AP-42 factors) are the ones which were used by Walden in
developing the emission inventory study for the Metropolitan Boston Air
Quality Control District [4] and reflect a national rather than local
mixture of burner-boiler types.
A close examination of the above factors for fuel oil combustion
revealed several significant areas for their improvement, especially with
regard to particulate emissions. For example:
(1) The factors are grouped according to application rather
than unit size, burner type, or other more fundamental
design characteristics.
(2) The factors do not take into account the various grades
of residual fuel oil (i.e., #4, #5, #6).
(3) The factors were developed for high sulfur fuels having
significantly different particulate emission character-
istics than the low sulfur fuels now in use.
(4) The relationship of the measurements used to develop the
particulate emission factors to hypothetical measurements
taken under identical conditions on identical units with
a newer EPA sampling system is unclear.
(5) The factors have occasionally been based on limited data
that are now subject to questions of accuracy and/or of
being representative.
Economic growth factors used in this analysis were provided by the
Harvard University School of Public Health and are based on an un-
published study of the economic growth in the Commonwealth.
WALDEN RESEARCH CORPOB
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For these reasons, we have conducted a thorough analysis of the most cur-
rent emission data available on fuel oil combustion and prepared a revised
set of emission factors for use with our source inventory. Sources of
this data include but are not limited to: The Environmental Protection
Agency, the Commonwealth of Massachusetts Bureau of Air Quality Control,
the American Petroleum Institute, the National Oil and Fuel Institute,
Battelle Memorial Institute, various manufacturers, vendors,;arid users
of the appropriate combustion equipment, public utilities, fuel oil
companies and local suppliers, and appropriate state and federal agency
personnel concerned with inspection and regulation of fossil fuel utili-
zation facilities. These new factors were structured to assure maximum
differentiation according to unit size and type and to reflect local
rather than national operating conditions. The new factors are pre-
sented in Appendix B together with a more comprehensive discussion of
their development.
The base-line emissions and the emission reduction associated
with each of the designated control strategies is detailed in Section
II-A and is not repeated here.
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IV. TECHNICAL FEASIBILITY
Our assessment of the technical feasibility of each of the control
strategies was determined from data gathered through a series of dis-
cussions with the same organizations and individuals contacted in our
evaluation of the source emission factors (Appendix B). Our objective
was to establish whether there were any potential obstacles and whether
the technical capabilities existed in the Metropolitan Boston area for
the implementation of each strategy. Analysis of the technical feasibility
of implementation of each of the designated control strategies fell into
two general categories:
(1) Were there any technical, i.e., engineering obstacles that
could delay application of each strategy.
(2) Were there sufficient supplies of distillate oil, natural
gas, or steam available to accomodate the proposed strategies.
In general, it is our judgment that there are no engineering reasons why
any of the strategies could not be implemented to control particulate and
S02 emissions from stationary fuel burning sources. However, inadequate
supplies of distillate oil and natural gas make those strategies associated
with their availability currently unfeasible. Furthermore, limited steam
supplies both now, and as projected to 1975, make conversion to that form
of space heating highly unattractive.
STRATEGY A. CONVERSION TO DISTILLATE FUEL OIL BY ALL SOURCES WITH
A HEAT INPUT OF LESS THAN 10 MMBtu/HR
Conversion of residual oil burning units to distillate
oil is accomplished by two general procedures:
(1) "Minor" adjustment of the existing burner
(2) Replacement of the existing burner
In the first case, conversion involves cleaning the fuel tank, discon-
necting the heating equipment on the tank and suction and return oil
lines (if in use), flushing the lines and inspecting them for leakage,
possible addition of a line filter and replacement of the filter basket
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with one of a finer mesh, replacement of the fuel pump or alteration of
its operating speed, elimination (or reduction) of the preheat supplied
to the oil for combustion, replacement of the atomizing cups in some
horizontally fired rotating cup burners, readjustment of the burners to
achieve proper C02 and smoke levels, bypassing of the cold oil inter-
lock control, and installation of required safety controls. After
these adjustments, an existing burner can be expected to fire success-
fully on distillate fuel [5, 6].
There is, however, much debate over the potential ef-
fectiveness of a burner adjustment program (as opposed to outright burner
replacement). Many of the burner installers in the Metropolitan Boston
area insist that an oil burner originally designed to operate on residual
fuel will operate with poorer performance (i.e., high maintenance require-
ments, poor combustion performance) and higher emissions after conversion
to distillate oil. This is claimed to be especially true of the older
rotary cup burners prevalent in Greater Boston. The installers, therefore,
maintain that the burners should not be adjusted, but should instead be
replaced with more efficient pressure atomizing units. There is even a
consensus of opinion on their part that replacement of old rotary units
by new pressure atomizing burners operating on residual oil would result
in almost as great a reduction in particulate emission as would exist
if the new units were also required to operate on distillate oil. Note
that a strategy associated with a ban on rotary burners and their replace-
ment with residual fired pressure atomizing burners would likely sig-
nificantly relieve the distillate oil supply problem discussed below.
Unfortunately, we were not able to obtain quantitative data to evaluate
the effectiveness of such a strategy. In either case (that is, if burners
are replaced or converted), the necessary technology and skills* exist in
the area to accomplish the proposed switchover to distillate oil.
A retraining program may be necessary for residual oil burner servicemen
so that they may apply their skills to distillate oil burners.
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A review of the oil resources available in the Metro-
politan Boston area indicates that there is an insufficient distillate
supply available to cope with the increased demand associated with imple-
mentation of the strategy. This lack of supply is principally associated
with the uncertainty in oil import quota allowances during both the near
term and foreseeable future (see Reference 7 for example). Discussions
with the major fuel oil suppliers in the Boston area have revealed that:
(1) A significant fraction of the available distil-
late oil is being blended with high sulfur
residual oils to satisfy low sulfur fuel regu-
lations.
(2) There is inadequate refining capacity within the
United States to meet currently projected needs
of light fuels such as distillate oil and gasoline
on a national level.
(3) An increasing amount of the available distillate
fuel is slated for consumption by public and private
utilities in gas turbine power generators.
(4) There is likely to be a distillate oil shortage
in the Boston area by the 1973-74 heating season
even if programmed changes (e.g., 3-6 MMBtu units
in the 13 core cities and towns switching to dis-
tillate) are not implemented.
It is our assessment that no certain projection of future supply of dis-
tillate heating oil in the Boston area can be made at this time. With
this consideration, it would appear that implementation of this strategy
in time to aid the achievement of the 1975 air quality standards in
Metropolitan Boston is unfeasible.*
STRATEGY B. ANNUAL INSPECTION AND PERIODIC MAINTENANCE PROGRAM FOR
ALL SOURCES TO ASSURE OPTIMUM COMBUSTION CONDITIONS
As discussed in previous sections, this strategy will be
most effective for sources greater than 30 MMBtu/hr heat input. Table 4-1**
The President's energy policy announcement of April 18, 1973, has not
been considered in reaching this conclusion since the impact of the
message on the Northeast U.S. fuel supply situation is quite uncertain.
**Table 4-1 is identical with Table B-5.
WALDEN RESEARCH CORPOR
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outlines an inspection and maintenance program under development by Boston
Edison. Note that the Edison program calls for more frequent cleaning
and maintenance than the annual period proposed by the strategy. It is
our judgment that maintenance of optimum combustion conditions in units
greater than 30 MMBtu/hr heat input will require a more frequent service
interval than annual; smaller units will probably require only annual
inspection and cleaning.
The major technical obstacle to implementation of a
maintenance and inspection program is the establishment of a satisfactory
time interval for cleaning. The Edison test program is designed to de-
termine the frequency necessary with their large units; a similar program
should be conducted with units outside the utility size range to estab-
lish an appropriate interval for these smaller (30-250 MMBtu) boilers.*
STRATEGY C. APPLICATION OF FUEL WASHING TECHNIQUES TO REMOVE
PARTICULATES FROM FUEL
This concept is based on results at the General Electric,
Lynn, Massachusetts industrial power plant. GE has been experimenting
with fuel treatment since early 1971 to remove sodium and other water-
soluble metallic salts from #6 fuel oil scheduled for use in their gas
turbine power generator. Their analysis indicates that much of this
matter is picked up during transit of the oil by barge or truck to their
facility; consequently, to extend the life of their turbomachinery they
must treat the fuel on site to remove all corrosive components. Treat-
ment consists of fuel washing by either an electrostatic precipitation
or centrifugation process.
Note that we include emission compliance testing as an integral part of
this strategy.
4-4 WALDEN RESEARCH CORPORATION
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TABLE 4-1
PROCEDURES FOR CONTROL OF PARTICULATE EMISSIONS
FROM THE STACKS OF THE BOSTON EDISON COMPANY
I. Frequent testing to maintain proper fuel/air ratio for combustion,
II. Purge cleaning of fuel-oil burning guns at each shutdown.
A. Routine disassembly and cleaning of fuel oil burning guns to
determine possible plugging of orifices.
B. Renew worn parts of fuel oil burning guns as soon as wear is
noted.
III. Complete overhaul and repair of all fuel oil burning equipment
and all flue gas passages of the boiler, during every annual
outage for inspection.
IV. Continuous sequential operation of soot blowers.
V. Fire sides of boilers, boiler duct work and ash hoppers are to
be cleaned at periodic intervals during the year.
The frequency of cleaning will be determined by the
results of the test program described in Item VI.
VI. A program of periodic testing of particulate emissions for rep-
resentative Boston Edison boilers is under development. The
object of this program is to determine the frequency of cleaning
necessary to maintain particulate emissions in compliance with
the Bureau of Air Quality Control's regulations.
4"5 WALDEN RESEARCH CORPO*
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With the precipitator, fuel is heated by steam to the
designated process temperature (250° T). A de-emulsifier is added in a
mixing chamber followed by water. The oil-water mixture is then passed
through a precipitator that is a slightly modified version of a com-
mercially-available refinery unit manufactured by the Petreco Division
of the Petrolite Corporation. A second mixing unit and precipitator
state are used to complete the washing process. Before introduction
into the power turbines, a vanadium inhibitor is added to the washed
fuel. Waste fluids are piped to a gravity separator and then to a water
treatment facility.
With the centrifugation process, two centrifuges ar-
ranged in parallel form each washing stage. The centrifuges are also
commercially-available separation units and are currently marketed by
the DeLaval Company.
6E has successfully operated with washed fuel in their
conventional power boilers and observed qualitative improvement (i.e.,
less glowing particulate matter in the fires) in combustion performance.
The boilers have also been shown to operate at higher loads without
smoking with washed fuels. The washing technique has been shown not to
alter oil viscosity and gravity properties and to reduce ash and sediment
content of typical 1% sulfur #6 fuels by approximately 70%. In short,
although the process was developed for elimination of soluble salts
from fuels slated for use in turbomachinery, it appears to be a practical
and feasible technique for reduction of ash related emissions in all
residual fuel oil burning installations.* The major significant obstacle
to the implementation of this strategy is the lack of a sufficient data
base (including stack emission tests) on the effectiveness of the washing
technique in reducing stack emissions.
Process technology is available through either Petreco or DeLaval.
4-6 WALDEN RESEARCH CORPORATION
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One problem that must be overcome in order to imple-
ment this strategy is to make certain that washing facilities are avail-
able to all local fuel suppliers. Most probably, power plants would
operate washing facilities on site to eliminate possible recontamination
during transit of the fuel by soluble salts that would be harmful to their
more sensitive turbomachinery. All other residual fuel users (i.e., those
operating conventional power boilers) can have their oil treated at their
supplier's terminal. Clearly, effective application of this strategy will
also require clean tanks and trucks for fuel storage and transit, respec-
tively. We do not consider this to be an obstacle to implementation.
STRATEGY D. PURCHASE OF STEAM FROM A LOCAL STEAM GENERATING
STATION FOR HEAT
The feasibility of this strategy is principally depen-
dent on the availability of steam during the peak demand winter heating
months. Currently, there is a maximum of 224,000 Ib of steam/hr com-
mercially available at peak load conditions within the existing Cambridge
and Boston Edison systems.* (Actually, this is a reserve capacity that
would not normally be sold.) This corresponds to an average capacity
of approximately 92,700 Ib/hr of steam, far short of that required to
significantly reduce emissions by application of this strategy (see
Table 5-3). Furthermore, we must incorporate a transmission loss in
the case of steam use (we assume 20%) in our estimate of steam avail-
ability. Note that we also have assumed an 88% efficiency for steam
boilers and a 60% efficiency for private boilers. On a longer term
basis (approximately 3 years), the projected increase in capacity in
Cambridge and Boston is already committed for current and future con-
struction. Historically, neither of these systems builds additional
steam capacity without having the supply already contracted to future
customers. Generation of additional steam capacity will take a minimum
of three years from the time customers and demand requirements are
Note that only Cambridge Gas and Electric and Boston Edison have steam
distribution systems. Thus, the geographic bounds placed on the ap-
plication of this strategy are the cities of Cambridge and Boston.
4-7 WALDEN RESEARCH CORPOR
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finalized. Note also that the 224,000 Ib steam/hr assumed to be cur-
rently available at peak load essentially represents the safety margin
with which Cambridge and Boston now operate.
Development of additional steam capacity must be ac-
companied by development of a distribution system to service the new
customers. Approximately six months is required for a small customer to
be tied in with the existing distribution system; time requirements for
development of an additional distribution network have not been estab-
lished.
The other technical requirements necessary to implement
this strategy involve connection of the utility steam line to the customer's
heating system and disconnection and removal of his boiler equipment, etc.
These are relatively simple tasks that can be handled by the existing
burner-boiler service industry.
STRATEGY E. SOURCES WITH A HEAT INPUT OF LESS THAN 10 MMBtu/HR
SWITCHING FROM OIL TO NATURAL GAS
Conversion of an oil-burning unit to natural gas can
be accomplished by the same general procedures associated with conversion
of residual oil burners to distillate oil; i.e., by burner conversion or
by burner replacement. As is the case with switching residual oil
burners to distillate fuel, considerable debate exists in the burner
service industry relative to the effectiveness of gas burner conversion.
In either case (that is, if burners are replaced or converted), the
necessary technology and skills exist in the Boston area to accomplish
the proposed conversion and to install the appropriate safety controls
associated with operation of gas-fired combustion units.
Implementation of this strategy also requires that
satisfactory gas distribution networks exist within each of the cities
and towns within the control district. Our discussions with the major gas
suppliers in the area indicate that within the 13 core cities and towns
between 95-99% of the potential users can be serviced with the existing
gas distribution network. In the 17 outlying cities and towns, this
figure is closer to 90%. It would thus appear that from the viewpoint
of distribution, implementation of this control strategy does not present
a significant technical problem.
4-8 WALDEN RESEARCH CORPORATION
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However, as in the case of distillate oil, the supply
of natural gas and of synthetic natural gas (SNG)* is inadequate to meet
current needs. On a national level, statistics indicate an ever widening
gap between supply and demand [8]; on a local level, many of the distri-
butors have already been forced to resort to peak shaving techniques over
the last heating season. Thus, considering the increased demand associated
with implementation of this control technique (290% more natural gas than
was consumed in the 30 cities and towns in 1972),** it would appear that
this strategy is not feasible, in both the short and long term, as viewed
from our current perspective of the local and national gas supply situation.
COMBINATION STRATEGIES F, G, H AND I
Strategies F, G, H and I represent coupling of the five
principal strategies discussed above (see page 1-3). The technical
feasibility of each of these strategies is the combined feasibility of
each of their component parts.
STRATEGY J. SOURCES WITH A HEAT INPUT OF LESS THAN 10 MMBtu/HR
SWITCHING FROM OIL TO ELECTRIC HEAT
As previously discussed, no quantitative assessment of
the effectiveness of this strategy has been conducted since our preliminary
calculations revealed a greater equivalent oil consumption by the utilities
than would be consumed by a given facility with an internal heating plant.
That is, the fuel oil necessary to generate a Btu of energy for space heat-
ing by electrical power is greater than the fuel oil necessary to provide
SNG is an important supply source in the Boston area since Boston Gas
is constructing an SNG plant in Everett to supplement its pipeline supply
of natural gas. The facility will have a production capacity of 40 million
ft3/day of SNG.
**
See Table 2-2.
4-Q
WALDEN RESEARCH CORPORl
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the same usable energy with an on-site heating plant.* Thus, given the
current fuel oil shortage, we judge this strategy not to be feasible at
this time. Should the situation change, the strategy should be re-evaluated
recognizing that the dispersion characteristics of a series of large ele-
vated point sources are considerably different than those from a series
of relatively small, low level sources. A study of the air quality impact
of electric heat, focussing on this latter consideration for sources in
the Metropolitan Boston area, is currently in preparation for the Energy
Policy Staff of the New England Regional Commission [9].
For residual oil users, the increase in oil consumption is enough to
offset the reduction in emission factors associated with such a switch.
Also, residual oil, with a higher emission factor, would replace the
use of cleaner-burning distillate oil in many cases. This too would
lead to higher emissions.
4-10 WALDEN RESEARCH CORPORATION
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V. CAPITAL AND OPERATING COSTS
An assessment was made of the capital and operating costs associated
with the implementation of each of the strategies based on a review of
data gathered during the course of the study. Costs that were considered
in assessing the economic consequences of the five basic strategies are:
STRATEGY A. CONVERSION TO DISTILLATE OIL BY ALL SOURCES OF LESS THAN
10 MMBtu/HR HEAT INPUT
I. Capital Costs
Burner replacement or burner conversion
II. Operating Costs
Differential fuel cost
Differential heating value of oils
Differential burner efficiency of distillate versus
residual oil
Line and tank heating costs eliminated with distil-
late oil
Differential maintenance costs for replaced and
converted units
STRATEGY B. ANNUAL INSPECTION AND PERIODIC MAINTENANCE PROGRAM FOR
ALL SOURCES TO ASSURE OPTIMUM COMBUSTION CONDITIONS
I. Capital Costs
None
II. Operating Costs
Periodic emission tests
Annual overhaul and cleaning of boilers (differential
beyond current level)
Replacement power (utilities only)
Gun maintenance
Periodic cleaning and inspection
Periodic testing to maintain proper fuel/air ratio
for combustion
Fuel saving due to increased efficiency
5-1
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STRATEGY C. APPLICATION OF FUEL WASHING TECHNIQUES TO REMOVE PARTICU-
LATES FROM FUEL
I. Capital Costs
Electrostatic precipitator system or configuration
system (including waste treatment units)
II. Operating Costs
Electrical energy consumption
Water supply
Inhibitor
Ftiel saving due to improved combustion efficiency
STRATEGY D. PURCHASE OF STEAM FROM LOCAL STEAM GENERATION STATION
FOR HEAT
I. Capital Costs
Installation cost to consumer
II. Operating Costs
Differential cost of current heating fuel versus
steam
Differential cost of decreased maintenance with
steam
Differential cost in annual overhaul requirements
STRATEGY E. SOURCES WITH A HEAT INPUT OF LESS THAN 10 MMBtu/HR
SWITCHING FROM OIL TO NATURAL GAS
I. Capital Costs
Burner replacement or burner conversion
II. Operating Costs
Differential fuel costs
Differential burner efficiency on gas versus oil
Differential maintenance costs for replaced and
converted units
Line and tank heating costs eliminated for residual
oil burners
5-2 WALDEN RESEARCH CORPORATION
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Evaluation of the capital and operating costs for combination strategies
(i.e., F through I) were calculated by summing the costs for the appropriate
basic strategies (e.g., F = A + B).
The estimated capital and operating costs of each stra-
tegy are summarized in Table 5-1.* In most cases, a set of high and low
values are provided to bracket uncertainties in the cost factors. These
cost factors and the estimated cost of implementation of each strategy
were obtained by the procedures described below.
STRATEGY A. CONVERSION TO DISTILLATE FUEL OIL BY ALL SOURCES WITH A
HEAT INPUT OF LESS THAN 10 MMBtu/HR
The low estimates of both capital and operating costs
were obtained by assuming 90% burner conversion and 10% replacement of
units which cannot be made to burn efficiently through minor adjustments
(from a combustion point of view the units must be replaced) [10 - 12].
The high estimates were obtained by assuming 100% replacement of burners.
A capital cost of $1550/burner (data ranged from $1250
to $1610) was used as the average conversion cost for all commercial and
industrial oil burning units less than 10 MMBtu/hr. The average cost of
replacement used was $3600/burner (data ranged from $4500 to $7500) for
the 6-10 MMBtu/hr size range.
In determining the increase in operating cost due to
the switch to use of a more expensive fuel, the differential fuel costs
given in Table 5-2 were used. These costs were developed from data ob-
tained from local fuel-oil suppliers. In estimating cost changes due to
the difference in heating value between distillate and residual oils, we
estimated a 3.5% lower heating value per gallon for #2 oil than for the
residual oils (estimate based on fuel oil inspection data supplied by
local and national fuel-oil suppliers). Improved combustion efficiency
with distillate fuel is expected to increase burner fuel efficiency by
*Table 5-1 is identical with Table 2-9.
5-3 WALDEN RESEARCH CORPOJ
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TABLE 5-1
SUMMARY OF CAPITAL AND ANNUAL OPERATING COSTS
OF EACH CONTROL STRATEGY
Strategy
A
B
C
D
E
F
G
H
I
Capital Cost
(millions of dollars)
Low estimate
High estimate
Low estimate
High estimate
Potential saving*
Low estimate
High estimate
Low estimate
High estimate
Low estimate
High estimate
Low estimate
High estimate
Potential saving*
Low estimate
High estimate
Low estimate
High estimate
Potential saving*
10.4
23.6
0
6.5
7.3
0.01
0.05
270
450
10.4
23.6
16.9
30.9
270
450
277
457
457
Annual Operating
Cost Change
(millions of
dollars per year)**
-3.9
+1.2
+0.6
+1.5
+1.8
-7.8
+0.36
+0.44
+9
-3.3
+1.8
-2.4
+3.0
-7.8
+9.6
+10.5
+10.8
- 7.8
Due to increased combustion efficiency.
**
A positive
value indicates an increase.
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about 5% (data ranged from 0-10%) in conversion units, and by 15% (data
ranged from 10-20%) in replacement units. We estimated a 3% (data ranged
from 1-5%) fuel consumption reduction in the case of the switch from #5
to #6 oils, because heating of lines and storage tanks is not required
with distillate oil. We further estimated that maintenance costs would
not change for converted burners, but an annual reduction of about $300/
burner (data ranged from $200-$350) would result from replacement of a
burner.
Note that the costs given for this strategy do not reflect
the increase in the price of distillate oil which would certainly result
from the increased demand associated with the strategy. We have also
assumed that the total fuel required for application of the strategy could
be obtained.
STRATEGY B. ANNUAL INSPECTION AND PERIODIC MAINTENANCE PROGRAM FOR
ALL SOURCES TO ASSURE OPTIMUM COMBUSTION CONDITIONS,
This strategy impacts upon all residual oil consumers
greater than 30 MMBtu/hr. There is no significant capital cost associated
with this strategy. The operating-cost-changes include the cost of
four emission tests per year per boiler, cleaning of all boilers four
times per year, and a 5% decrease in boiler efficiency. Evaluation of
the associated costs to local utilities were based on cost quotes
supplied by these facilities. For non-utility sources, a combination
of the utility data figures and information assembled from other sources
were used to generate average cost figures.
One of the utilities reported a cost of $3000/boiler/
emission test; we estimate a cost of $7500/boiler for cleaning. A
second utility spends $3500/boiler for an emission test; we estimate
a cost of $5500/boiler for cleaning.* For non-utility sources of size
No incremental cost for this strategy has been projected for Boston
Edison since their existing abatement plan (Table 4-1) has been taken as
the basis of the strategy for the utilities.
WALDEN RESEARCH CORPO«
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greater than 250 MMBtu/hr, an emission test cost of $2850/boiler was
used, along with a cleaning cost of $7500/boiler. For units of size
30-250 MMBtu/hr, we used an emission test cost of $2850/boiler and a
cleaning cost of $1500/boiler. These are all costs in excess of that
which is presently being expended by these sources.* The cost of fuel
oils which were used to estimate the savings in fuel expenditures are
contained in Table 5-2 and are based on data obtained from local fuel
oil suppliers. These are wholesale costs which would apply to the large
sources affected by this strategy.
TABLE 5-2
WHOLESALE FUEL OIL PRICES IN THE 30 CITIES (cents/gallon)
Maximum % Sulfur #2 #4 #5 #6
1/2
1
13.4
13.4
13.4
13.2
13.2
12.7
12.6
11.3
STRATEGY C. APPLICATION OF FUEL WASHING TO REMOVE PARTICULATES FROM
FUEL
The higher of the two price estimates for this strategy
in both the capital cost and the operating cost change categories corres-
ponds to the use of the electrostatic precipitator method of fuel washing.
The other method considered, and the one to which the lower cost figures
apply, is the use of centrifugation in the process. Note that there is
a significant potential fuel saving in the operating cost which corresponds
The principal basis for our estimates was cost data and current practice
information made available to us by Boston Edison, Cambridge Electric*
and Braintree Power and Light.
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to a reduction in fuel consumption of up to 5% as a result of increased
fuel combustion efficiency. We have not combined the operating cost
change figures because of the uncertainty involved with the exact
amount of the fuel savings, but the result is surely a net decrease or
saving in annual operating costs.
In calculating the capital cost, we assumed that each
large utility would buy and operate its own fuel-washing process and
waste treatment plant so that they could eliminate possible recontamina-
tion by soluble salts during transit. Furthermore, oil companies and/
or distributors would wash the oil for all other consumers; we assumed
that, in this case, six facilities would wash #4 and #5 oils, and that
12 facilities would wash #6 oil, making a total of 24 facilities. We
assume that all costs to the oil companies and utilities will be passed
on to consumers in the form of increased fuel and electricity (or steam)
prices.
The capital cost to a facility of fuel washing using
the electrostatic precipitation technique was determined using the in-
formation given in Table 5-3 and supplied by the Petreco Division of the
Petrolite Corporation and by the General Electric Company (Lynn, Massa-
chusetts). Added to this capital cost is the cost of a waste treatment
facility, which is given in Table 5-4, which was supplied by Petreco.
The cost of operating the electrostatic precipitation facility, which
is equivalent to the cost of the electricity needed to operate it, was
derived from the information given in Table 5-5, also supplied by
Petreco.
The capital cost of the centrifugation unit needed to
perform fuel washing was derived from the information given in Table
5-6 which was supplied by the DeLaval Company and the General Electric
Company. Added to this is the cost of the waste treatment facility
(Table 5-4). The operating cost change consists of cost of electricity
consumed, cost of water used, cost of inhibitor used, and the decrease
in fuel expenditures due to increased burner efficiency and decreased
5-7 WALDEN RESEARCH CORPOl
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TABLE 5-3
CAPITAL COST OF ELECTROSTATIC PRECIPITATION FACILITY
WHICH WILL PERFORM FUEL-WASHING
Facility Size
(gallons of oil processed
per hour)
1 ,000
3,000
6,000
12,000
24,000
50,000
Cost
(dollars)
156,000
169,500
200,000
253,000
343,500
477,500
TABLE 5-4
CAPITAL COST OF A WASTE TREATMENT FACILITY
Facility Size
(gallons of oil processed
per hour)
1,000
3,000
6,000
12,000
50,000
Cost
(dollars)
25,000
33,000
33,000
57,000
57,000
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TABLE 5-5
OPERATING (ELECTRICITY) COST FOR AN ELECTROSTATIC PRECIPITATION
FACILITY WHICH PERFORMS FUEL-WASHING
Facility Size Cost
(gallons of oil processed (Cents/1000 gal
per hour) of oil processed)
1,000 45
3,000 89
6,000 85
12,000 87
36,000 261
TABLE 5-6
CAPITAL COST OF CENTRIFUGATION FACILITY WHICH
WILL PERFORM FUEL-WASHING
Facility Size Cost
(gallons of oil processed (Dollars)
per hour)
1,000 33,333
3,000 100,000
6,000 200,000
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fuel consumption.
The cost of electricity used is 11.2 KWH* per 900
gallons per hour (gph) for a 900 gph or smaller size facility, and 26.1
KWH* per 3000 gph for facilities equal to or greater than 3000 gph in
size; interpolation was used between these size classes. A water cost
of $120 per million gallons was used. Inhibitor is consumed in the
amount of 300 parts per million parts oil, and it costs about $3 per
gallon. These data were supplied by DeLaval and General Electric.
STRATEGY D. PURCHASE OF STEAM FROM A LOCAL STEAM GENERATING STATION
FOR HEAT
The low estimate of the capital cost was obtained by
assuming that users of approximately 30 MMBtu/hr size would switch to
use ot steam (5 users). The high estimate of capital cost reflects
switching by users of 6 MMBtu/hr (24 users) size. All "new" users
were assumed to be located adjacent to existing steam lines such that
additional distribution lines would not have to be installed. The low
estimate of the increase in operating cost was obtained for the case of
6 MMBtu/hr size units switching, while the high operating cost increase
estimate corresponds to switching by the 30 MMBtu/hr size units.
We used $2000** as the average cost to a new customer
of installation of the equipment needed to use purchased steam. An
on-site boiler efficiency of 60$, an 88% efficiency for utility steam
boilers, and a 20% transmission loss, were assumed in estimating operating
cost expenditures. The steam availability at peak loading is 224,000
Ibs/hr, as discussed in Section IV of this report.**
The operating cost change contains the difference
between steam service and oil prices, the savings in oil burner main-
*
**
A KWH is assumed to cost 2.32£ [13].
Data supplied by the Cambridge Gas and Electric Co. and by the Boston
Edison Co.
5_1 o WALDEN RESEARCH CORPORATION
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tenance visits, the savings in cost associated with a decrease in time
requirements of on-site personnel, and the savings in annual cleaning of
oil burners.
The steam costs* given in Table 5-7 (Block Rate A) apply
to the less than 5,000-10,000 Ib steam/hr customers, and hence apply to
users of size 6 MMBtu/hr. Added to this is a charge of about $1/1O6 Btu/
month, which is dependent upon current labor and tax rates and current
fuel costs. The wholesale cost of oil (Table 5-2) applies to this size
category.
The steam costs* given in Table 5-8 (Demand Rate) apply
to steam customers of greater than 5,000-10,000 Ib steam/hr size, and
were applied to the 30 MMBtu/hr size steam users in this strategy. Added
to this is a $1/106 Btu/month charge (as in the case of 6 MMBtu/hr sources)
and a charge of about $150/1000 Ibs steam/hr which is computed using
the maximum load during the month under consideration. The wholesale
price of oil (Table 5-2) applies to this size grouping.
We assumed that 12 oil burner service visits were
required each year at an average cost of $40/visit (data ranged from
$30-$50). We also estimated that an on-site engineer who is being paid
$12,000/year spends 1/4 of his time adjusting and servicing the oil
burner, but that his time expenditure on the purchased steam equipment
is reduced to 1/4 of that spend on the oil burner. An annual cleaning
cost of $350 (data ranged from $150-$500) was assumed.
STRATEGY E. SOURCES WITH A HEAT INPUT OF LESS THAN 10 MMBtu/HR
SWITCHING FROM OIL TO NATURAL GAS
The low estimate of capital cost was obtained by assuming
90% conversion of oil burners and 10% replacement (See References 10-12).
Data supplied by the Cambridge Gas and Electric Co. and by the Boston
Edison Co.
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TABLE 5-7*
STEAM COSTS: BLOCK RATE A
[Applicable to Users of <(5000 to 10,000) Ib Steam/hr Size]
Rate Consumption
(Dollars/MMBtu/Month) (MMBtu/Month)
1.7 first 50
1.6 next 50
1.5 next 100
1.4 next 300
1.3 over 500
*
Cambridge Electric rates.
TABLE 5-8*
DEMAND RATE COST OF STEAM
[Applicable to Users of >(5000 to 10,000) Ib Steam/hr]
Rate Consumption
(Dollars/MMBtu/Month) (MMBtu/Month)
0.95 first 2000
0.90 next 3000
0.85 over 5000
Cambridge Electric rates.
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The high estimate was obtained by assuming 100% replacement of burners.
We used $500/burner (data ranged from $400 to $600) as the average cost
of replacement of such a burner. We used $1500/burner (no range - single
source) as the average cost of conversion of a 0-10 MMBtu/hr size com-
mercial and industrial unit. An average replacement cost of $3600/burner
(data range from $2250 to $4550) was used for 0-6 MMBtu/hr size non-
domestic units, and $6050/burner (data ranged from $5850 to $6250) for
6-10 MMBtu/hr size units.
The operating cost increase results from an effectively
higher cost of gas compared with oil. Gas burners have lower efficiencies
than oil burners, but heating of lines and storage tanks is no longer
required as in the case of #5 and #6 fuel oils; we have assumed that
these two factors cancel each other out. We have also assumed that there
are no differences in maintenance costs.
Average cost figures were obtained from regulated gas
company rate schedules; the average cost figures correspond to what we
found to be an average-size user in the domestic, commercial and indus-
trial sectors. This rate was then applied to the total consumption in
each sector by sources impacted upon by this strategy. The average prices
of gas are as follows: $1.45/103 ft3 for domestic users; $1.51/103 ft3
for commercial users; $1.24/103 ft3 for industrial users. Retail oil
prices (Table 5-9) were applied to domestic users and wholesale oil
prices (Table 5-2) were applied to the other sources less than 10 MMBtu/hr.
TABLE 5-9*
RETAIL FUEL OIL PRICES IN THE 30 CITIES
(cents/gallon)
Maximum % Sulfur
1/2
1
n
22.9
22.9
#4
14.0
14.0
15
13.8
13.5
#6
13.2
12.1
Data obtained from local fuel oil suppliers.
~1 3 WALDEN RESEARCH CORPORA^1
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Note that costs given for this strategy do not reflect
the large increase in the price of natural gas which would certainly re-
sult from implementation of this strategy. We have also assumed that the
supply required could be obtained.
STRATEGIES F, 6, H AND I. COMBINATION STRATEGIES
The capital and operating costs for these strategies
are the sum of the costs associated with their component parts.
STRATEGY J. SOURCES WITH A HEAT INPUT OF LESS THAN 10 MMBtu/HR
SWITCHING FROM OIL TO ELECTRIC HEAT
As indicated earlier, we did not quantitatively evaluate
the costs associated with this strategy because a preliminary analysis
showed that a net increase in emissions would result from implementation
of this strategy.
5-14 WALDEN RESEARCH CORPORATION
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VI. ADMINISTRATIVE REQUIREMENTS
Administration of the present control program by the Bureau of Air
Quality Control can be classified into engineering services, technical
services, field enforcement services, and management services. These
functions are currently performed within the different operating units
of the Bureau's organizational structure. Implementation of the new
strategies considered in this study will require a similar commitment
of resources in the form of manpower, facilities, and funds. These
needs can be satisfied through a combination of reassignment of re-
sources from current programs and/or the addition of new manpower and
funds. Because of this strong interaction with current agency programs,
identification of the differential resource requirements associated
with implementation of the new strategies cannot be readily assessed.
Instead, our approach has been based on estimating the total adminis-
trative requirements under the assumption of a comprehensive enforcement
plan.
The projected annual manpower requirements for implementation of
Strategy A, conversion of all sources with heat input less than 10 MMBtu/hr
to distillate oil, are given in Table 6-1. The principal activities asso-
ciated with this strategy are source registration and inspection to assure
compliance with air pollution control regulations. We have considered
that all sources require annual registration to update information and
maintain a current source reference file. The manpower estimates reflect
that a portion of this function is provided by the inspection visit.
Two time intervals for periodic inspection have been assumed. Sources
up to 10 MMBtu/hr are considered to be inspected once every five years,
hence, 20% of the total number are inspected during a single year. All
sources greater than 10 MMBtu/hr, including all utility facilities, are
inspected annually.
The estimated annual budget requirements for this control program
are shown in Table 6-2. These data include the administration and clerical
support required for the professional staff.
6-1 WALDEN RESEARCH CORPORATH
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CTl
I
O
m
33
m
TABLE 6-1
ANNUAL MANPOWER REQUIREMENTS FOR STRATEGY A (CONVERSION TO DISTILLATE FUEL OIL BY
ALL SOURCES WITH A HEAT INPUT LESS THAN 10 MMBtu/hr)
Activity
Source Registration
All Sources
Spot Inspection
3-10 MMBtu/hr
Scheduled Inspection
10-250 MMBtu/hr
>250 MMBtu/hr
Utilities
Administration
Clerical
Output Unit
Registration
Update
Inspection
Inspection
Inspection
Inspection
Per Employee
Per Employee
Number
Units
6570
1450
230
15
11
5.91
7.09
Units/Day
8
4
3
2
2
0.2 MY
0.2 MY
Man-Years
3.65
1.81
0.38
0.04
0.03
1.18
1.42
o
I
8
ya
s
TO
-------
I
o
m
TO
m
to
8
TO
s
ZJ
TABLE 6-2
ANNUAL BUDGET REQUIREMENTS FOR STRATEGY A (CONVERSION TO DISTILLATE FUEL OIL BY
ALL SOURCES WITH A HEAT INPUT LESS THAN 10 MMBtu/hr)
CO
Activity
Source Registration
Inspection
Administration
Clerical
Total
Manpower
Need
3.65
2.26
1.18
1.42
Employee Grade
Junior Engineer
Inspector
Senior Engineer
Clerk-Steno
Number
3.5
2.5
1.0
1.5
Salary
$11,800
8,400
13,000
6,500
Total
$41 ,300
21 ,000
13,000
9,750
$85,050
-------
The estimated manpower staff required to inspect all sources annually
associated with the maintenance program in Strategy B, is detailed in
Table 6-3, with the associated costs given in Table 6-4. The scheduled
inspection is considered to serve the joint function of update of source
registration information, and verification of compliance with applicable
control registrations.
An alternate administrative approach to implementing Strategy B,
which avoids the requirement for comprehensive inspection could be based
on a program of certified servicing reports. These reports would be used
to verify that an approved maintenance program was being conducted by the
facility. The manpower and funding requirements for such a plan would be
substantially reduced from those associated with a full inspection plan.
The estimated manpower requirements connected with the fuel washing
plan (Strategy C) are summarized in Table 6-5. We have considered that
implementation of this plan necessitates annual registration of all
sources, and a source inspection program similar to that in Strategy A
(i.e., annual inspection of all sources greater than 10 MMBtu/hr; 20%
inspection of all other sources). This plan is supplemented with a pro-
gram of quarterly inspection of fuel washing facilities (11 on-site facil-
ities and 24 at bulk storage terminals). Fuel samples obtained during
these inspections are subjected to proximate and ultimate analysis at
the state laboratories. The estimated cost for this control program is
given in Table 6-6.
The number of fuel burning sources which may be switched to steam
heat (Strategy D) was found to be extremely limited. We have estimated
that 24 locations with boilers rated at 6 MMBtu/hr (or 5 locations with
boilers rated at 30 MMBtu/hr) can be switched, based on the availability
of excess steam generating capacity. Consequently, the impact on admin-
istrative requirements from an assumed enforcement program consisting of
source registration and field inspection such as that associated with
Strategy A, conversion to distillate oil, would be negligible.
6_4 WALDEN RESEARCH CORPORATION
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TABLE 6-3
ANNUAL MANPOWER REQUIREMENTS FOR STRATEGY B (ANNUAL INSPECTION
AND PERIODIC MAINTENANCE)
o*>
1
Ul
0
§
Z
m
2
S
X
o
o
33
3
3)
H
a
Activity
Scheduled Inspection
3-6 MMBtu/hr
6-10 MMBtu/hr
10-30 MMBtu/hr
30-250 MMBtu/hr
>250 MMBtu/hr
Utilities
Administration
Clerical
Output Unit
Inspection
Inspection
Inspection
Inspection
Inspection
Inspection
Per Employee
Per Employee
Number
Units
5700
2320
145
85
15
11
1380
16.50
Units/Day
3
3
3
3
2
2
0.2 MY
0.2 MY
Man-Years
9.48
3.87
0.24
0.14
0.04
0.03
2.76
3.30
-------
TABLE 6-4
ANNUAL BUDGET REQUIREMENTS FOR STRATEGY B (ANNUAL INSPECTION
AND PERIODIC MAINTENANCE)
o>
1
o
Manpower
Activity Need Employee Grade
Scheduled Inspection 13.80 Inspector
Administration 2.76 Head Inspector
Clerical 3.30 Clerk-Steno
Total
Number Salary Total
14 $ 8,400 $117,600
2.5 11,500 28,750
3.5 6,500 22,750
$169,100
o
8
3)
I
O
-------
TABLE 6-5
ANNUAL MANPOWER REQUIREMENTS FOR STRATEGY C (FUEL WASHING)
I
o
m
z
TO
m
07
2
TO
O
8
TO
8
TO
Activity
Source Registration
All Sources
Source Inspection
Same as Strategy A
Fuel Facility Inspection
Fuel Washing Facilities
Laboratory
Fuel Analysis
Administration
Clerical
Output Unit
Registration Update
Inspection
Inspection
Fuel Analysis
Per Employee
Per Employee
Number
Units
6570
1706
129
140
6.75
8.10
Units/ Day
8
Same as Strategy A
3
1
0.2 MY
0.2 MY
Man-Years
3.65
2.26
0.22
0.62
1.35
1.62
-------
TABLE 6-6
ANNUAL BUDGET REQUIREMENTS FOR STRATEGY C (FUEL WASHING)
CTl
oo
1
o
m
f't
z
TO
§
TO
a
8
70
Activity
Source Registration
Source Inspection
Fuel Inspection
Laboratory
Administration
Clerical
Total
Manpower
Need
3.65
2.26
0.22
0.62
1.35
1.62
Employee Grade Number
Junior Engineer 3.5
Inspector 2.5
Inspector 0.5
Lab Technician 0.5
Senior Engineer 1.5
Clerk-Steno 1.5
Salary Total
$11,800 $ 41,300
8,400 21,000
8,400 4,200
9,000 4,500
13,000 19,500
6,500 9,750
$100,250
s
O
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Implementation of the control plan associated with conversion of
sources less than 10 MMBtu/hr from oil to natural gas use (Strategy E)
is based on annual source registration and annual inspection of all re-
maining oil burning sources greater than 10 MMBtu/hr. No inspection
has been budgeted for the sources less than 10 MMBtu/hr which have
switched from oil to natural gas use. The associated manpower require-
ments to implement this plan are shown in Table 6-7, while the annual
budget is given in Table 6-8.
6-9 WALDEN RESEARCH CORPORATION
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TABLE 6-7
ANNUAL MANPOWER REQUIREMENTS FOR STRATEGY E (SOURCES WITH A HEAT INPUT OF LESS
THAN 10 MMBtu/hr SWITCHING FROM OIL TO NATURAL GAS)
Activity
Output Unit
Number
Units
Units/Day
Man-Years
CTl
I
5
30
O
X
8
70
s
Source Registration
All Sources
Scheduled Inspection
Registration Update
8020
4.46
All Sources >10 MMBtu/hr
Administration
Clerical
Inspection
Per Employee
Per Employee
256
4.91
5.89
2-3
0.2 MY
0.2 MY
0.45
0.98
1.18
o
-------
m
TABLE 6-8
ANNUAL BUDGET REQUIREMENTS FOR STRATEGY E (SOURCES WITH A HEAT INPUT OF LESS
THAN 10 MMBtu/hr SWITCHING FROM OIL TO NATURAL GAS)
Activity
Source Registration
Inspection
Administration
Clerical
Total
Manpower
Need
4.46
0.45
0.98
1.18
Employee Grade
Junior Engineer
Inspector
Senior Engineer
Clerk-Steno
Number
4.5
0.5
1.0
1.0
Salary
$11,800
400
13,000
6,500
Total
$53,100
4,200
13,000
6,500
$76,800
8
TO
3
30
-------
VII. REFERENCES
1. Ozolins, G. and R. Smith, A Rapid Survey Technique for Estimating
Community Air Pollution Emissions, U.S. Dept. of HEW, PHS, Pub. No.
999-AP-29, Cincinnati, Ohio (October 1966).
2. Guide for Compiling a Comprehensive Emission Inventory, U.S. Environ-
mental Protection Agency, Publication APTD-1135, Research Triangle
Park, North Carolina (March 1973).
3. Compilation of Air Pollutant Emission Factors, EPA Office of Air
Programs, Publication No. AP-42, Research Triangle Park, N.C.
(February 1972).
4. Morgenstern, P., Parks, T.R., and Calcagni, J., Air Pollutant Emis-
sion Inventory for the Metropolitan Boston Air Pollution Control
District, Prepared by Walden Research Corporation, Cambridge, Mass.
(June 1972).
5. Personal Communication, Mr. R.A. Beals, Natural Oil and Fuel Insti-
tute, Inc., New York, New York, to Dr. Richard D. Siegel (February
1973).
6. Changing Burner Installations to Lighter Grade of Fuel Oil, Part I
Of NOFI Technical Publication Bulletin 68-103-50A, National Oil and
Fuel Institute, New York, New York.
7. Cummings, G.H. and Franklin, W.B., Declining Domestic Reserves -
Effect on Petroleum and Petrochemical Industry, AIChE Symposium
Series, 69 (127), New York, New York (1973).
8. lammartino, N.R., "Gas Pinch Plagues CPI," Chemical Engineering,
pp 34-36 (March 5, 1973).
9. Unpublished report by the Research Corporation of New England to
the Energy Policy Staff of the New England Regional Commission.
10. Levy, A., et al, A Field Investigation of Emissions from Fuel Oil
Combustion for Space Heating, Prepared by Battelle Columbus Lab-
oratories, Columbus, Ohio, American Petroleum Institute Publica-
tion 4099 (November 1971).
11. Cauley, S.P. and Siegmund, C.W., Updating Emission Factors for
Space Heating with Fuel Oil, Publication No. 29-72, Presented at
the 37th Midyear Meeting of the American Petroleum Institute's
Division of Refining, New York, New York (May 1972).
12. Unpublished report by Battelle Memorial Institute, Columbus, Ohio,
to the American Petroleum Institute and the EPA, A Field Investi-
gation of Emissions from Fuel Oil Combustion for Space Heating
(Year 2).
WALDEN RESEARCH CORPORATION
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13. Electric Utility Industry in New England Statistical Bulletin 1971,
Electric Council of New England, Burlington, Mass. (July 1972).
14. Diehl, J.M., "Sales of Fuel Oil and Kerosene in 1971", Mineral
Industry Surveys, Bureau of Mines, Arlington, Virginia (October
1972).
15. Ehrenfeld, J.R., et al, Systematic Study of Air Pollution From
Intermediate-Size Fossil-Fuel Combustion Equipment. Wai den Research
Corporation for Air Pollution Control Office, EPA, Contract No. CPA
22-69-85 (March 1971).
16. Shelton, E.M., Burner Fuel Oils, 1972, Bureau of Mines, Petroleum
Products Survey No. 76, Bartlesville, Oklahoma (July 1972).
7-2 WALDEN RESEARCH CORPORATION
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APPENDIX A
SOURCE AND FUEL USE INVENTORIES
An inventory of stationary fuel-burning sources was developed to
serve as a data base for evaluation of the various control strategies.
This inventory consists of an accounting of the amount of fuel used and
the number of fuel burning sources in the area classified by location,
size and type. An inventory was prepared for the years 1972, 1973, and
1975. This appendix contains a description of these inventories and
describes the procedures used in their development.
A-l. 1972 SOURCE AND FUEL USE INVENTORY
Consumption of natural gas and coal during 1972 in the 30 cities
and towns covered in this study is given in Table A-l. Gas consumption
data was obtained from reports of gas company sales, while consumption
of coal was compiled from data on file with the Bureau of Air Quality
Control. These data are categorized by region, viz., 13 core cities
and 17 outer cities.
Consumption of #2 distillate and #4, #5, and #6 residual fuel oils
during 1972 in the 30 cities is given in Table A-2. In this case, con-
sumption is categorized by region, user size, and oil type. These basic
data were derived from Bureau of Mines published information.
The estimated number of oil-fired boilers operating in the 30 cities
in 1972 is given in Table A-3. This information is categorized by region,
user size, and oil type. These estimates were derived from representative
population samples on file at the Bureau of Quality Control using proce-
dures described later in this Appendix.
A. NATURAL GAS CONSUMPTION
Consumption of natural gas in 1972 was obtained by a direct
survey of all of the gas companies serving the 30 cities and towns covered
WALDEN RESEARCH CORPORATION
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TABLE A-l
ESTIMATED 1972 CONSUMPTION OF NATURAL GAS AND
COAL IN THE 30 CITIES
Natural Gas (MMcf/year)
13 Core Cities 42,949
17 Outer Cities 14,971
Total 30 Cities 57,920
Coal (tons/year)
13 Core Cities 1,671
17 Outer Cities 0
Total 30 Cities 1,671
A-2 WALDEN RESEARCH CORPORATION
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TABLE A-2
ESTIMATED 1972 FUEL OIL CONSUMPTION INVENTORY IN THE 30 CITIES
(thou gal/year)
Industrial and Commercial
Fuel 0-6 6-10 10-30 30-250 >250
Type Domestic MMBtu/hr MMBtu/hr MMBtu/hr MMBtu/hr MMBtu/hr Utility Total
J>
co
WALDEN RESEAf
0
o
O
*>
#2 473,656
#4
#5
#6
#2 224,952
#4
#5
#6
51,141
24,969
69,155
73,421
15,476
6,431
18,535
35,926
18,915
8,636
13,765
128,840
8,333
4,951
9,549
65 ,847
13 Core Cities
845 2
2,155 1
2,484 2
23,115 83
17 Outer Cities
374
1,254
853
9,495 6
,932
,000
,378
,476
273
793
,544
547,489
36,760
1,933 89,715
56,438 621,939 987,229
249,408
12,636
29,730
59,572 121,543 298,927
s
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TABLE A-3
ESTIMATED NUMBER OF OIL-FIRED BOILERS IN THE 30 CITIES IN 1972
Industrial and Commercial
>
i
ik
1
O
m
RESEARCH CORPOR-
#2
#4
15
#6
Sub-Total
#2
#4
#5
#6
Sub-Total
Grand Total
0-6
Domestic MMBtu/hr
315,771 1,657
473
1 ,439
1,126
315,771 4,695
149,968 258
93
339
311
149,968 1,001
465,739 5,696
6-10
MMBtu/hr
13 Core
188
106
156
918
1,368
17 Outer
139
71
174
569
953
2,321
10-30
MMBtu/hr
Cities
7
8
15
75
105
Cities
1
5
4
31
41
146
30-250 >250
MMBtu/hr MMBtu/hr Utility
4
1
7 1
56 8 32
68 9 32
1
4
10 6 18
15 6 18
83 15 50
-------
in this study. This data was not categorized by user size since only a
single emission factor for gas (applicable to all source sizes) was avail-
able. However, gas consumption was classified by region - either 13 core
cities or 17 outer cities.
B. COAL CONSUMPTION
Only three significant sources, all Boston schools in the
0-6 MMBtu/hr size range, burned coal in 1972. This information was ob-
tained from the Bureau of Air Quality Control.
C. OIL CONSUMPTION AND NUMBER OF OIL-FIRED UNITS
Fuel oil consumption and number of oil-fired burners was deter-
mined by a combination of direct count and estimation methods.
1. Oil Consumption and Number of Boilers at Utilities
Fuel oil consumption by utilities was provided to us by the
Bureau of Air Quality Control. Wai den, however, conducted its own direct
survey to determine the number of boilers operated at each utility site in
1972.
2. Oil Consumption and Number of Units in the Commercial and
Industrial >10 MMBtu/Hr Size Range
Consumption of #2 distillate and #4, #5, #6 residual oils by
large industrial and commercial facilities of greater than 10 MMBtu/hr size,
and the number of such sources, was obtained from the source registration
and survey forms on file with the Bureau of Air Quality Control. Although
almost all of these forms contain 1970 or 1971 operating data, we have
assumed that 1972 consumption by these sources did differ significantly
from either of these earlier years.* We further assumed that the files
were essentially complete for sources in this size category.
Although population and other growth factors may have increased during the
period 1970-1972, the winter months of 1972 were mild, and thus required
less heating than those of 1970 or 1971. These two factors have been
determined to have approximately offset one another.
WALDEN RESEARCH CORPORATION
A-5
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3. Oil Consumption and Number of Sources in the Commercial and
Industrial 0-10 MMBtu/Hr Size Range
Consumption of fuel oils by industrial and commercial sources
in the size range 0-10 MMBtu/hr includes use by commercial, industrial, in-
stitutional, and governmental sources. The source registration and survey
forms on file with the Bureau of Air Quality Control constitute a repre-
sentative size-stratified sampling of the sources in the 3-10 MMBtu/hr
size range. Estimation of total consumption in this size range were made
using census figures and 1971 Bureau of Mines (BOM) data on fuel oil con-
sumption [14] to adjust the registration data sample. A more detailed
description of the procedures used follows.
a. Estimation of #2 Fuel Oil Consumption by 0-10 MMBtu/Hr
Size Industrial and Commercial
We have estimated that 10% of total Massachusetts #2
distillate heating oil, 100% of industrial distillate oil and 100% of oil
company distillate oil is consumed in the state by all industrial and com-
mercial sources (these figures are based on data gathered by Maiden in
previous studies). Consumption of #2 fuel oil in the 30 cities and towns
was then estimated from statewide totals by applying a proportioning factor
(based on commercial and industrial employment figures and adjusted to ac-
count for steam use in Boston and Cambridge). The amount consumed by the
greater than 10 MMBtu/hr sources (obtained from the state.s source regis-
tration and survey files) was subtracted from this regional total yielding
an estimate of fuel use by sources less than 10 MMBtu. The split between
consumption in the 13 core cities and that in the outer 17 was made by
again applying a proportioning factor based on commercial and industrial
employment (and adjusting it to account for steam use in the 13 core cities)
to the 30 cities total. The consumption by military sources in the 13 and
17 cities was added to this fuel inventory.
The final division between 0-6 MMBtu/hr and 6-10 MMBtu/hr
size sources, and the number of sources in each category, was made on the
basis of proportions developed from the source registration and survey data
available for less than 10 MMBtu sources.
WALDEN RESEARCH CORPORATION
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b. Estimation of #4 Fuel Oil Consumption by 0-10 MMBtu/Hr
Size Industrial and Commercial Sources
The procedure used in this case was the same as for #2
oil, except that the calculations were applied to 100% of the statewide
#4 heating oil use given in the BOM data.
c. Estimation of #5 Fuel Oil Consumption by 0-10 MMBtu/Hr
Size Industrial and Commercial Sources
The procedure used was the same as for #4 oil and applied
to 100% of the statewide #5 heating oil use given in the BOM data.
d. Estimation of #6 Fuel Oil Consumption by 0-10 MMBtu/Hr
Size Industrial and Commercial Sources
The procedure was the same as in the case of #4 and #5
fuel oil, and applied to 100% of statewide #6 heating oil use, 100% of
industrial residual oil use, and 100% of oil company residual oil use.
4. Oil Consumption by Domestic Sources
Previous Walden studies [15] have estimated that 100% of
total #1 heating oil and 90% of total #2 heating oil is consumed in Mas-
sachusetts by domestic sources. These were combined on an equal volume
basis because, although the #1 oil has a lower emission factor than the
#2, it also has a somewhat lower heating value and these two factors have
been determined to approximately counterbalance one another. We estimated
consumption of these fuels in the 30 communities by applying a proportion-
ing factor (based on 1970 population figures) to the state total. Similarly,
the split between the amount consumed in the 13 cities and that consumed
in the 17 cities was also obtained by application of a population-based
proportioning factor. The number of residential sources was estimated by
assuming 1500 gallons per year as an average consumption by a residential
unit for purposes of space heating, hot water heating, cooking, and other
domestic applications [4].
_ WALDEN RESEARCH CORPORATION
A-7
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A-2. PROJECTED 1973 CHANGES IN FUEL CONSUMPTION AND SOURCE INVENTORY
The 1972 fuel consumption and source inventory was adjusted to a
1973 basis by accounting for programmed changes in fuel utilization due
to existing regulations without adjusting the total amount of fuel con-
sumption. These changes are:
(1) Conversion of principal coal users in area to distillate oil
(2) 3-6 MMBtu/hr residual oil users in 13 core cities convert to
distillate oil
(3) Shutdown of Lynn power plant,
and are further described below. Thus, 1973 is a pre-strategy base case
and formed the basis for comparison of the effectiveness of each applied
control strategy. Although not all of the programmed changes will occur
at the beginning of 1973 and be in effect throughout that entire year, we
have elected to apply them on an annual basis.
Table A-4 shows consumption of natural gas and coal in the 1973
base case while Table A-5 presents the 1973 base case oil consumption
inventory. The number of oil consumers in the 1973 base case is given
in Table A-6.
TABLE A-4
ESTIMATED 1973 BASE CASE CONSUMPTION OF NATURAL GAS
AND COAL IN THE 30 CITIES
Natural Gas (MMcf/vert)
13 Core Cities 42,949
17 Outer Cities 14,971
Total 30 Cities 57,920
Coal (tons/year)
Total 30 Cities 0
A-8 WALDEN RESEARCH CORPORATION
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I
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30
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i
s
TABLE A-5
ESTIMATED 1973 BASE CASE FUEL OIL CONSUMPTION INVENTORY IN THE 30 CITIES
(thou gal/year)
Commercial and Industrial
Fuel 0-6 6-10 10-30 30-250 >250
Type Domestic MMBtu/hr MMBtu/hr MMBtu/hr MMBtu/hr MMBtu/hr Utility Total
#2 473,656 218,985
#4
#5
#6
1
18,915
8,636
13,765
128,840
13 Core Cities
845
2,155
2,484
23,115
2,932
1,000
2,378
83,476
715,333
11,791
1,933 20,560
56,438 626,398 918,261
17 Outer Cities
#2 224,952
#4
#5
#6
15,476
6,431
18,535
35,926
8,333
4,951
9,549
65,847
374
1,254
853
9,495
273
793
6,544
249,408
12,636
29,730
59,572 100,622 278,006
-------
TABLE A-6
ESTIMATED NUMBER OF OIL-FIRED BOILERS IN THE 30 CITIES IN THE 1973 BASE CASE
Commercial and Industrial
>
O
1
O
rn
TO
ESEARCH CORPOF
*v
O
Fuel
Type
#2
#4
#5
#6
Sub-Total
#2
#4
#5
#6
Sub-Total
Grand Total
0-6
Domestic MMBtu/hr
315,771 4,698
315,771 4,698
149,968 258
93
339
311
149,968 1,001
465,739 5,696
6-10
MMBtu/hr
13 Core
188
106
156
918
1,368
17 Outer
139
71
174
569
953
2,321
10-30
MMBtu/hr
Cities
7
8
15
75
105
Cities
1
5
4
31
41
146
30-250 >250
MMBtu/hr MMBtu/hr Utility
4
1
7 1
56 8 32
68 9 32
!
4
10 6 14
15 6 14
83 15 46
-------
A. COAL CONSUMPTION
The three principal remaining coal users (Boston schools) will
switch to #2 oil in 1973.
B. CONVERSION OF 3-6 MMBtu/hr SIZE RESIDUAL OIL USERS IN THE 13
CORE CITIES
The regulation requiring the 3-6 MMBtu/hr size residual oil
users in the 13 cities to switch to distillate oil is scheduled to go
into effect on July 1, 1973. Although hearings will soon be held to
determine whether the regulation will go into effect as previously planned,
the longest extension under consideration is about 1 year. This does not
change our rationale for including the implementation of this regulation
in with the other programmed changes. We have assumed 100% compliance
with this regulation when it becomes effective.
C. LYNN UTILITY
Massachusetts Electric Company in Lynn shut down operations in
December of 1972. The electricity which this company had previously sup-
plied is now being supplied by a power pool consisting of all New England
utilities, including those situated in the 30 cities covered in this
study. Therefore, adjustments have been made to take account of this
change in the 1973 inventory. It was assumed that the New England util-
ities would proportionately absorb the Lynn plant.s oil consumption based
on their respective shares of the total New England utility oil
consumption.
A-3. PROJECTED 1975 FUEL CONSUMPTION
Since secondary standards must be met by mid-1975, it is necessary
to determine the effectiveness of each of the strategies in reducing 1975
Data on utility oil consumption, name-plate capacity, etc., was taken
from Reference 13.
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emissions. For this reason, projected population and economic growth
figures were applied to the 1973 base case fuel inventory (Table A-5)
to obtain a 1975 fuel consumption inventory. A population growth factor
was applied to domestic fuel consumption, and to the amount of utility
fuel consumption which is used by the domestic sector on the assumption
that total fuel consumption will grow at the same rate as population.
An economic growth factor (which is an average GNP growth figure) was
applied to all other fuel consumption; here we have assumed that pro-
portional changes in fuel consumption in the predominantly commercial
and industrial sector are equal to the economic growth in that sector.
The projected population and economic growth figures that were
used to derive the 1975 fuel consumption inventory are given in Table A-7.*
The 1975 inventory for gas and coal consumption is contained in Table A-8,
while that for fuel oils is presented in Table A-9.
An estimate of the number of fuel burning sources was not prepared
for the year 1975.
Economic growth factors used in this analysis were provided by the Harvard
University School of Public Health and are based on an unpublished study
of the economic growth in the Commonwealth.
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TABLE A-7
POPULATION AND ECONOMIC GROWTH FIGURES
Population 1970 1975
13 Core Cities 1,356,495 1,309,388
17 Outer Cities 644,562 657,892
Population Growth Factor for Period 1973 to Mid-1975
(applied to domestic sources)
13 Core Cities 0.98
17 Outer Cities 1.01
Economic Growth Factor for Period 1973 to Mid-1975
(applied to all nondomestic sources)
30 Cities 1.08
TABLE A-8
ESTIMATED 1975 CONSUMPTION OF NATURAL GAS AND COAL
IN THE 30 CITIES
Natural Gas (MMcf/year)
13 Core Cities 44,555
17 Outer Cities 15,685
Total 30 Cities 60,240
Coal (tons/year)
Total 30 Cities 0
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TABLE A-9
1975 FUEL OIL CONSUMPTION INVENTORY IN 30 CITIES
(thou gal/year)
Commercial and Industrial
Fuel 0-6 6-10 10-30 30-250 >250
Type Domestic MMBtu/hr MMBtu/hr MMBtu/hr MMBtu/hr WBtu/hr Utility Total
13 Core Cities
#2 464,183 236,504 20,428 913 3,167 725,195
#4 --- --- 9,327 2,327 1,080 12,734
#5 14,866 2,683 2,568 2,088 22,205
#6 139,147 24,964 90,154 60,953 652,901 968,119
17 Outer Cities
#2 227,202 16,714 9,000 404 299 253,619
#4 6,945 5,347 1,354 13,646
#5 20,018 10,313 921 856 32,108
#6 38,800 71,115 10,255 7,068 64,338 106,017 297,593
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APPENDIX B
EMISSION FACTORS
As discussed in Section II of this report, the set of emission fac-
tors most widely applied to source inventories are those assembled and
published by the EPA [3]. The factors for oil burning sources are shown
in Table B-l;* those for natural gas and coal consumption are shown in
Table B-2. A review of these factors concluded that the factors for fuel
oil consumption:
1. are grouped too broadly for application to
our inventory;
2. do not recognize the difference in partic-
ulate emissions for various grades of fuel
oil;
3. were developed for high rather than low
sulfur fuel that is currently in use in the
Metropolitan Boston area;
4. were developed using sampling and measure-
ment techniques different from those cur-
rently accepted by EPA; and
5. are, occasionally, based on limited and/or
nonrepresentative data.
Consequently, a revised set of factors were developed based on examination
of recent data and on discussions with various government, commercial,
industrial, and professional groups. These factors are shown in Table B-3*
and reflect our evaluation of the best available data on fuel oil combus-
tion by stationary sources.
The major differences in the revised factors are for particulate
emissions. For residential units, and small commercial and industrial
units (0 to 10 MMBtu/hr), the factors are based on the results of a
series of tests performed for the API [10,11] and for the EPA [12] by
*Note that in our calculations S02 and S03 emission factors were coupled
to represent a total S0x emission factor (expressed as equivalent S02).
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TABLE B-l
EPA EMISSION FACTORS FOR FUEL OIL COMBUSTION
Pollutant
Parti oil ate
Sulfur Dioxide
Sulfur Trioxide
Type of Unit
Power Plant
(lb/103 gal)
8
157S*
2S
Industrial and Commercial
Residual
(lb/103 gal)
23
157S
2S
Distillate
(lb/103 gal)
15
142S
2S
Domestic
(lb/103 gal)
10
142S
2S
S equals percent by weight of sulfur in the oil.
B-2
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TABLE B-2
EMISSION FACTORS FOR NATURAL GAS
AND COAL COMBUSTION
Pollutant
Parti culates
S0x
Gas Fired (lb/106 ft3)
Coal Fired (Ib/Ton fuel)
Type of Unit
EPA Factors
Power Plant**
15
0.6
Industrial Process
Boiler**
18
0.6
Domestic/**
Commercial
Heating Units
19
0.6
Revised Factor
All Sources***
8
0.6
EPA Factor
Hand-Fired Units
Bituminous
20
38S*
00
I
co
**
ir
S equals percent by weight of sulfur in coal
Ir
EPA Factors from Reference 3
***
Wai den estimate
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TABLE B-3
REVISED EMISSION FACTORS FOR FUEL OIL COMBUSTION
(lb/lQ3 gallon)
CO
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m
250 MMBtu/hr
8
157S*
2S
Domestic
2.4
140S
2S
Industrial and Commercial
(0-30 MMBtu/hr)
Type Oil
n 2.4
I4-1/2XS 5
#4-US 5
#5-l/2%S 8
#5-1 %S 10
#6-1 /22S 9
16-1 XS 12
#6-high S 42
#2 140S
#4 149S
#5 157S
#6-1/2X5 149S
#6-1 XS 157S
#6-h1ghS 157S
All oils 2S
(30-250 MMBtu/hr)
8
157S
2S
.S equals percent by weight of sulfur in oil.
Q
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Battelle Memorial Institute on a total of 30 boilers in the 0 to 10 MMBtu
size range for a variety of fuel oils. Note that the Battelle tests with
#4 and #5 residual oils were with high sulfur fuels. The factors shown
in Table B-3 for 1/2 and 1 percent sulfur #4 and #5 oils were developed
using the Battelle results with distillate and low sulfur #6 oils as guide-
lines.* Factors for industrial units (10 to 30 MMBtu/hr) have been assumed
equivalent to those for commercial units since there are no suitable data
currently available on sources in this size range. (Note that a test pro-
gram on sources in this range has just been initiated by EPA.) An upper-
bound of 30 MMBtu/hr has been placed on this extrapolation since lower ex-
cess air levels, different residence times, and, therefore, different
emission characteristics are associated with units larger than about
30 MMBtu/hr. The emission factors for utilities and for industrial sources
larger than 30 MMBtu/hr have been assumed equal to the power plant factors
given by EPA [3] even though our analysis of Boston Edison test data in-
dicates that their power plants should currently be assigned higher fac-
tors. This decision reflects our judgment that the EPA factors are more
representative of the emissions associated with the entire spectrum of
sources greater than 30 MMBtu/hr than new factors based strictly on the
Edison tests would be. Furthermore, we were unable to obtain any other
data for sources in this size range than that contained in the original
references used to generate the EPA factors.
The EPA emission factors for natural gas combustion were also re-
viewed and the particulate emission factors modified as shown in Table B-2.
The basis for this adjustment was our conclusion that the basic data
used for the development of the EPA factors were taken with sampling and
measurement apparatus that does not correspond with current EPA standard
procedures. In fact, when compared with the new factor for distillate
*The emission factor was correlated with API gravity. Typical fuel oil
inspection data was provided by local and national fuel oil distributors.
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fuel oil consumption (on a Ib/MMBtu basis), the EPA gas factor exceeds
that for oil. We do not believe this is to be justified. Our revised
factor is therefore based on limited new data from Battelle, Bethlehem
Steel, and Cleaver Brooks that were obtained using accepted sampling
and measurement procedures.* We feel that this data base is too narrow
to categorize gas emission factors by unit size or type; for this rea-
son we have developed one value for all gas combustion sources.**
The EPA emission factors for coal-burning sources were found suit-
able for use with our inventory. These factors are also presented in
Table B-2 for small hand-fired units operating with bituminous coal;
these are the only coal-burning sources included in our inventory of
fuel consumption in the Metropolitan Boston area.
The basic factors in Table B-2 were modified in our evaluation of
those strategies which involve technological changes that would affect
emissions to reflect the degree of emission control associated with each
procedure. These modifications are discussed below.
Strategy B. Annual inspection and periodic maintenance program
for all sources to assure optimum combustion con-
ditions
The factors developed to reflect the effect of periodic
oil burner maintenance on emissions are shown in Table B-4. Gas and coal
factors are assumed unchanged by the strategy and are contained in Table
B-2.
For sources smaller than 3 MMBtu/hr, the Battelle
studies indicate [10-12] that an increased inspection and maintenance
*Data range from 3-10 lb/106ft3
**
Emission calculations were also undertaken assuming the gas emission
factor to be zero. The rationale behind this decision is that the
factor shown in Table B-2 may still be too large; a zero value allows
us to calculate the maximum impact potentially achievable by con-
version to gas.
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TABLE B-4
EMISSION FACTORS FOR FUEL OIL COMBUSTION
Stategy B: Inspection and Maintenance
(All Factors in lb/103 gallon)
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Pollutant
Parti culates
so2
so3
Type of Unit
Power Plant and
Utility Sources
>250 MMBtu/hr
5
157S*
2S
Domestic
2.4
140S
2S
Industrial and Commercial
(0-30 MMBtu/hr)
Type Oil
#2 2.4
#4-l/2%S 5
#4 -US 5
#5-1/2X5 8
#5 -US 10
#6-1/2X5 9
#6 -US 12
#6-high S 42
#2 140S
#4 149S
#5 157S
#6-l/2%5 149S
#6-US 157S
#6-high S 157S
All oils 2S
(30-250 MMBtu/hr)
5
157S
2S
S equals percent by weight of sulfur in oil.
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program, one beyond that which already is in practice in the Boston area
with units in this size range, will do little to improve emission per-
formance. In those studies, the extent of existing annual inspection,
periodic maintenance, and service programs in a geographic area are param-
eters used to adjust emission factors for sources less than 3 MMBtu/hr.
Based on our discussions with burner/boiler service personnel in the
Boston area, it is our judgment that the current maintenance practices in
the area are such that these sources are already serviced at a frequency such
that their emission factor is at the low end of the range suggested by
Battelle and the National Oil & Fuel Institute. Sources between 3 and
30 MMBtu/hr are judged to also receive a high level of service; for this
reason no adjustment was made to the latter sources' set of emission
factors. For larger sources, i.e., sources >30 MMBtu/hr, a revised fac-
tor has been developed based on stack test data made available by the
Boston Edison Co. This factor reflects the effectiveness of their test-
ing and maintenance program outlined in Table B-5.* We consider this
program to also be representative of the requirements for nonutility
sources in this size range. Note that on the basis of our discussions
with boiler manufacturers and service personnel, it is our conclusion that
sources larger than 30 MMBtu/hr will require maintenance more frequently
than once a year; our factors (and the Edison program) are based on an
assumption of a quarterly frequency of cleaning of these units.
Strategy C. Application of fuel washing techniques to remove
particulates from fuel
The emission factors developed for this strategy for fuel
oil combustion are shown in Table B-6,** and are based on a series of tests
conducted at General Electric in Lynn, Massachusetts, on #6 oil samples be-
fore and after fuel washing by centrifugation and by electrostatic precipi-
tation. These tests show approximately a 70 percent reduction in ash and
**
*Table B-5 is identical with Table 4-1.
Gas and coal factors are unchanged from the baseline case; see Table B-2.
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TABLE B-5
PROCEDURES FOR CONTROL OF PARTICULATE EMISSIONS
FROM THE STACKS OF THE BOSTON EDISON COMPANY
I. Frequent testing to maintain proper fuel/air
ratio for combustion.
II. Purge cleaning of fuel-oil burning guns at
each shutdown.
A. Routine disassembly and cleaning of
fuel oil burning guns to determine
possible plugging of orifices.
B. Renew worn parts of fuel oil burning
guns as soon as wear is noted.
III. Complete overhaul and repair of all fuel oil
burning equipment and all flue gas passages of
the boiler, during every annual outage for
inspection.
IV. Continuous sequential operation of soot
blowers.
V. Fire sides of boilers, boiler duct work and
ash hoppers are to be cleaned at periodic
intervals during the year.
The frequency of cleaning will be de-
termined by the results of the test
program described in Item VI.
VI. A program of periodic testing of particulate
emissions for representative Boston Edison
boilers is under development. The object of
this program is to determine the frequency
of cleaning necessary to maintain particu-
late emissions in compliance with the Bureau
of Air Quality Control's regulations.
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TABLE B-6
EMISSION FACTORS FOR FUEL OIL COMBUSTION
Strategy C: Fuel Washing
(All Factors in lb/103 gallon)
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Pollutant
Particulates
S09
£
S03
Type of Unit
Power Plant and
Utility Sources
>250 MMBtu/hr
6.4
157S*
2S
Domestic
2.4
140S
2S
Industrial and Commercial
(0-30 MMBtu/hr)
Type Oil
n 2.4
#4-1/2X5 3.6
#4-1X5 3.6
#5-1/2X5 6.6
#5-1X5 8.6
#6-1 /2XS 7.4
#6-1X5. 10.4
#2 140S
#4 149S
#5 1 57S
#6-l/2%S 149S
#6-1X5 157S
#6-high S 157S
All oils 2S
(30-250 MMBtu/hr)
6 it
.4
157S
2S
*r
S equals percent by weight of sulfur in oil.
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sediment content by washing. The procedure was developed by General
Electric for reduction of the soluble salt content (e.g., sodium) of re-
sidual fuels used in a gas turbine heat recovery system at their Lynn
power plant. The emission factors in Table B-6 were developed from the
baseline data in Table B-3 by assuming a 70 percent reduction in the ash-
related* emissions of residual fuel oils currently in use in the 30
cities and towns. Typical ash and sediment inspections for fuels con-
sumed during the 1972-73 heating season were obtained from the major fuel
oil distributors in Greater Boston. Additional data was obtained from
the Bureau of Mines survey of 1972 burner fuel oils [16].
Strategy F. Conversion to distillate fuel oil by all sources
with a heat input of less than 10 MMBtu/hr coupled
with an inspection and maintenance program to
achieve optimum combustion conditions
The emission factors used to evaluate this strategy
are contained in Table B-4 for oil burning sources. Gas and coal emission
factors are included in Table B-2.
Strategy G. Conversion to distillate fuel oil by all sources
with a heat input of less than 10 MMBtu/hr coupled
with a fuel washing process to remove particulatesT
from the fuel ~~
The emission factors used to evaluate this strategy are
given in Table B-6 for oil burning sources and in Table B-2 for gas and
coal combustion sources.
Strategy H. Sources with a heat input of less than 10 MMBtu/hr
switching from oil to natural gas coupled with an
inspection and maintenance program to achieve op-
timum combustion conditions
The emission factor for sources consuming natural gas
is given in Table B-2. The emission factors for fuel oil combustion
*About 20 percent for #5 and #6 and 40 percent for #4 oils.
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(units greater than 10 MMBtu/hr heat input) are given in Table B-4;
these for coal combustion are also contained in Table B-2.
Strategy I. Sources with a heat input of less than 10 MMBtu/hr
switching from oil to natural gas coupled with a
fuel washing process to remove participates from
the fuel
The emission factor for sources consuming natural gas
is given in Table B-2. The emission factors for coal combustion are also
given in Table B-2. The factors for fuel oil combustion (units greater
than 10 MMBtu/hr heat input) are given in Table B-4.
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