FINAL REPORT
ON THE
U. S. NATIONAL REPORT TO THE O.E.C.D.
JOINT ON AIR POLLUTION FROM FUEL COMBUSTION
[N STATIONARY SOURCES
S% ORDER NO. 19
CONTRACT NO. CPA 70-1
OCTOBER, 1972
PREPARED FOR
DIVISION OF CONTROL
U. S. ENVIRONMENTAL PROTECTION
RESEARCH TRIANGLE PARK,
SUBMITTED BY
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND
CINCINNATI, OHIO
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EPA-R2-73-241 AIR POLLUTION FROM FUEL COMBUSTION
October 1972 IN STATIONARY SOURCES
FINAL REPORT
ON THE
U. S, NATIONAL REPORT TO THE O.E.C.D.
JOINT GROUP ON AIR POLLUTION FROM FUEL COMBUSTION
IN STATIONARY SOURCES
Task Order No. 19
Contract No. CPA 70-1
October 1972
Prepared for
Division of Control Systems
U. So Environmental Protection Agency
Research Triangle Park, North Carolina
Submitted by
PROCESSES RESEARCH, INC.
Industrial Planning and. Research
Cincinnati, Ohio
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Page ii
TABLE OF CONTENTS
Section Title
Abstract
Foreword
I Scope and Methodology
II Results and Discussion
III Conclusions
IV U. S. National Report To The O.E.C.D.
Joint Group On Air Pollution From
Fuel Combustion In Stationary Sources
Appendix
I The U. S. Strategy and SOX Abatement
II Costs for Oil Desulfurization
III Electrostatic Precipitator Costs
Page
1
2
4
7
20
22
97
102
106
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ABSTRACT
This report documents the preparation of the U. S. National Report to the
Organization for Economic Cooperation and Development - Joint Group on Air
Pollution from Fuel Combustion in Stationary Sources. The report contains
estimates of past (1960 and 1970) and future (1980) fuel consumption in stationary
combustion sources and associated quantities of the air pollutants - sulfur
oxides, nitrogen oxides, and particulate - emitted to the atmosphere from the
combustion of these fuels. Abatement stragegies to control the 1980 level of
pollutant emissions to the alternative target levels, as obtained in 1960 and
1970 cases, were formulated and impressed on the 1980 situation.
The study found that the projected emissions of sulfur and nitrogen oxides
could be expected to approximately double the 1968 levels of pollution without
implementation of new controls. Those of particulate emissions would be expected
to increase some tenfold without continuing the application of best control
practice.
The 1980 emissions can be controlled to the targeted levels through imple-
mentation of control and fuels management practices. The estimated costs for
achieving control are appreciable, approaching a total estimated capital
expenditure of about $13 billion (cumulative through 1980) and an annual
operating cost climbing to $2.8 billion in 1980 (1970 dollar estimates).
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FOREWORD
This report is the final documentation covering the preparation of the
U. S. National Report to the Joint Group on Air Pollution from Fuel Combustion
in Stationary Sources. The Joint Group is an ad hoc committee of the Organiza-
tion for Economic Cooperation and Development (of which the United States is a
member) constituted to study and report on possible approaches and estimated
costs for the control of such air pollution by 1980 in the various member
countries.
The U. S. National Report as submitted to the O.EoC.D. is presented in
Section IV. It was prepared to meet the requirements for submission to the
O.E.C.D. and should not be taken as an "official policy" document, particularly
with respect to the assumptions related to control strategy, which were in some
cases arbitrary or dictated by the study format. At the time this report was
prepared, the best available cost data (in 1969-1970) were used. In retrospect
from the time of completion and issuance, it is noted that better cost data,
especially in regard to costs for fine gas scrubbing, are now available. For
this reason it is recommended that the cost data contained in this report be
used only after careful consideration of its appropriateness and state of d^vel-
development.
The results presented in the report are considered valid for their intended
purpose, but should not be construed as an attempt either to forecast the means
by which air pollution, will be controlled in 1980, or to predict the level of
control which will be attained by that time through the implementation of
officially adopted strategies.
The study scope and the methodology for preparing the report are presented
in Section I with a brief identification of the more important factors and
assumptions governing the preparation of the estimates. A discussion of the re-
sults is found in Section II with the conclusions drawn presented in Section III.
While the present study was quite modest in scope and effort, some aspects
of the investigation were conducted in greater depth than for previous studies.
In addition, tailoring the approach to meet the needs of the O.E.C.D. study
format required some modifications to previously exercised approaches. Conse-
quently, some new insights were gained into the nature of the problem of air
pollution from fuel combustion. These are discussed in Section II as "Issues
Arising From the Study."
During the compilation of the various national reports into the O.E.C.D.
report, certain questions were raised concerning the U. S. National Report.
These questions dealt with the U. S. strategy for sulfur oxides abatement,
costs for oil desulfurization, and electrostatic precipitator costs. These
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items were re-examined, and more detailed explanations of their derivations were
prepared for the O.E.C.D. These derivations are included in this report as
Appendices I through III, respectively„
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SECTION I - SCOPE AND METHODOLOGY
The object of the study was to develop an estimate of the nature of the
abatement strategies and costs of their implementation to achieve control to a
predetermined quantity of emission on a national scale for the three major pollutants
from fuel combustion: particulate, sulfur oxides, and nitrogen oxides. The U. S.
report presents the situations for control of the 1980 emissions to the levels exist-
ing in 1970 and 1960. Briefly these steps were taken to arrive at the estimates
presented in the report (Section IV):
(a) using historical data, develop a picture of the fuel quantities and fuel
qualities employed in the various consuming sectors.
(b) using historical data for emissions after application of control equipment,
develop emission factors appropriate to the degree of control practiced
in the target years.
(c) calculate estimates for the total national emissions of the three pol-
lutants by fuel type and consuming sector for 1960 and 1970.
(d) using the historical data developed previously for fuel consumption and
information relating to normal practice in the various sectors, develop
predictions of the fuel utilization patterns for 1980.
(e) using the most current data for emissions resulting after application of
best control practice, develop emission factors by fuel type and consuming
sector.
(f) estimate the quantity of emissions likely to exist on the national level
on the basis of the projected fuel utilization patterns and the degree of
control likely to be practiced if no special steps to abate air pollution
are implemented.
(g) formulate an abatement strategy to accomplish emission control to the two
chosen target levels.
(h) calculate the costs of implementation of these control strategies based
on both total capital costs from present through 1980 and the 1980 annual
operating costs.
Planning of the control strategy was predicated on numerous simplifying as-
sumptions. These related to matters such as which control methods would be used,
the rate at which different control methods could be introduced, etc. The assump-
tions were not intended to be a prediction of things to come, but an attempt was
made to relate them to what appears, from the information available, to be a
reasonable approach. They were intended to provide a rational basis for calculating
estimated costs for the specified levels of control.
Of the three pollutants considered, sulfur oxides present the most difficult
control problem - hence the primary thrust of the strategy was control of sulfur
oxides. First a strategy was developed to produce the two levels of sulfur oxide
control to be used as a basis for subsequent calculation of costs, i.e., control to
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1960 levels of emission in 1980 and control to 1970 levels of emission in 1980.
Any incidental benefits in NOX and particulate control produced by the control
application assumed for sulfur oxide control were factored into subsidiary sup-
plemental strategies assumed for NO^ «md particulate control, e.g., some NOX control
was assumed to result incidentally from scrubbing of flue gas for sulfur oxide
removal. The additional reduction required to give the levels of control of NOX
for 1980 was assumed to come from application of techniques for modification of
combustion systems.
It was further assumed that no single control method could be considered as
a total solution for sulfur control over the next ten years. Sulfur reductions
from power stations were assumed to come from increased mining of low sulfur coal,
Increased use of mechanically cleaned coal, application of flue gas cleaning systems,
and increased use of desulfurization to produce low sulfur residual fuels. Slight
increases for power station consumption of natural gas were assumed, but demand
from other industries where control techniques for sulfur and nitrogen oxides are
uneconomical was assumed to cause most of the projected increase in natural gas
production to go to the "Other Industries" sector. Control in the third major
sector, "Domestic and Commercial," was assumed to come from increased use of low
sulfur oil.
Consideration of this methodology reveals certain important limitations one
must consider in discussion or in drawing conclusions based on the data presented
here or in using the data for other purposes. First, there is the matter of the
abatement strategy. At the time the basic work for this report was undertaken,
ambient air quality standards either had not been formulated or implemented in most
of the participating nations. Also the U. S. had not yet set the standards of
performance for new sources. For this reason the "roll-back" procedure was util-
ized to determine the amount of emission reduction required in 1980. The control
strategy which seemed plausible from the state-of-the-technology and at the same
time satisfied the study format was developed.
The strategy thus developed contains certain simplifying assumptions, the
implications of which are discussed in detail in Section III. However, the most
important implication is that it is not necessary to control all pollution sources
to achieve the targeted emission level. This situation arises primarily because
the targeted level is based on a national emission inventory and not ambient air
quality.
The second critical aspect is the method used in arriving at the estimated
fuel demands for the various consuming sectors in 1980. The estimates were made
by assuming continued prevalence of the present trend of fuel consumption existing
in 1970 where special steps for air pollution abatement had not been taken. In
certain areas of the country steps have already been taken to abate air pollution
by substitution of clean fuels for coal. The trends established in these areas
are discounted for the purposes of the 1980 base case so that the abatement strategy
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and costs formulated for the report would be independent of localized practices
and reflect only the results of the formulated strategies. No attempt? was made
to establish an estimate of fuels availabilities as this was beyond the scope of
the study.
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SECTION II - RESULTS AND DISCUSSION
During the next decade energy demand will continue overwhelmingly to be
met by the use of fossil fuels. Based on established utilization trends, natural
gas and coal will account for an estimated 82 percent of the stationary combustion
source energy requirements in 1980, with gaseous fuels contributing 53 percent and
coal 29 percent of the total. The demand for liquid fuels for stationary combustion
sources will also increase from a 1968 level of 189 million tons to 337 million tons
in 1980. While the absolute amounts of fuels required by the various sectors will
increase, the relative distributions will change. These changes in the pattern of
fuel consumption by sector, and within sectors, may somewhat influence abatement
policies. Fuel demand for power stations and industry will increase considerably
more than for domestic and commercial uses. These latter uses which represented
27 percent of the total demand in 1968 will drop to 17 percent in 1980. On the
basis of the estimates for energy demand and those abatement procedures practiced
nationally (i.e. reference date 1968), the projected emissions of sulfur and ni-
trogen oxides are expected to approximately double during the period 1968 to 1980.
This increase in energy demand coupled with the technology and fuels available for
satisfying this demand dictates that abatement of air pollution arising from the
combustion of fossil fuels will be needed to prevent the further deterioration of
the environment.
From the standpoint of pollution from combustion, sulfur oxides from the com-
bustion of coal have been recognized as of dominant importance in the present and
projected picture; and the coal burning power stations are by far the most impor-
tant single source of pollution. This is illustrated by Figure 1 which shows types
of fuels used in each consuming sector in 1968. Power station coal greatly exceeds
all other fuel use categories except for natural gas and oil, largely distillate
fuels, used in the domestic and commercial sector, and these latter categories are
"clean" fuels which produce relatively small amounts of pollution. Because of the
dominant importance of coal as a fuel and power stations as a user, primary con-
sideration was given to ways that projected electrical requirements might be met
without exceeding the pollutant emission limits prescribed by the study guidelines.
Even after control, it is estimated that total coal combustion will account for
83 percent of the total sulfur oxides pollution, with power station coal combustion
contributing 74 percent of the total.
The 1980 fuel use patterns which would result from applying the assumed con-
trol methods is shown in Figure 2 where data are presented on the same basis as
Figure 1 to permit direct comparisons by fuel type and fuel use category to 1968
consumption. The results of the assumed control strategy on sulfur balance are
shown by Figure 3 where sulfur emissions by fuel type and use category are repre-
sented by blocks in the top half of the figure and sulfur which is not emitted as
a result of the assumed use of control methods are represented by the blocks in
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FIGURE
1968 FOSSIL FUEL
-
SITUATION
DISTRIBUTION 4 CONSUMPTION BY SECTOR
24-
—
22-
cc ~
5 20-
>~
cc 18-
LU —
CL
_j 16-
\- ~~
if) _
"9 12-
z 10-
o _
o. 8 ~~
__
to 6-
O
o 4-
2-
o-
POWER STATIONS
*
I
0
i IRON & STEEL
I
^m
^^^H
^^H
r"^^^^^^^^F~^
0 20 30
rRFF 1 MF R
r\c. r i IN c r\
1
f
Y
OTHER INDUSTRY
i r i ~~r
4
DOMESTIC
* &
OTHER
ii ii
40 50 60 70 30
//// A
111
i i~~^
D NATURAL GAS
SOIL
• COAL
90 100
DISTRIBUTION C % OF TOTAL ENERGY)
rn
CD
-------
CSL
<
LU
>-
cc
Q.
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GO
tO
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v_^
z
o
h-
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W
O
FIGURE 2
I960 FOSSIL FUEL SITUATION
DISTRIBUTION & CONSUMPTION BY SECTOR
REFINERY
IRON iSTEEL—i
POWER STATIONS T
-OTHER INDUSTRIES
DOMESTIC
i & •
OTHER
ZO 30 40
DISTRIBUTION
50 60 70 80
OF TOTA1 ENERGY 3
DNATURAL GAS
• COAL
100
"D
o
rn
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the lower half of the .figure. The irregular..line for emissions associated with
oil..and natural gas is intended to represent the unknown quantity of emissions
.which results from, flaring of waste gases in gas fields and refineries.
Emissions in this,category were, because of lack of.data, omitted from the study.
This problem is discussed with other issues arising from the study under Section
II B which follows; it is important, however, to recognize at this point that the
sulfur balance represented by Figure 3 would, if data were available, have some
.incremental amounts of sulfur distributed in the fuel oil and natural gas
-categories.
The strategies.for nitrogen oxides emission,.control and particulate emis-
sion control involve application of combustion process modification to supplement
NOx control., achieved ..incidental to SOx control and application of electrostatic
precipitators as necessary to give particulate emission reductions beyond those
assumed to result from coal cleaning and application of flue gas cleaning to
power station emissions. The results of the application of the assumed control
strategy on emission levels for NOx and particulate are shown in Figures 4 and 5.
Control of the.sulfur oxides situation in, 1980 will depend principally on
the .development..and..implementation of flue gas cleaning and coal cleaning pro-
cesses, in addition to, the requirement for natural gas and natural low sulfur
coal mining. The, present .prospects for control of. nitrogen oxides depend on
the.development, and.implementation of improved combustion technology. There is
some: evidence that .this-.technology is now becoming available for gaseous and
liquid fuels. The, technology for control of particulate emissions is available
now, although there is, some disagreement on the efficiency of control which can
be realized with the existing practices. Naturally occurring low sulfur fuels
will be in great demand by all industrialized countries and available in short
supply. Substitution of low sulfur fuels derived.from natural supplies cannot
alone alleviate the sulfur emission problem.
The prospects, for, meeting the targeted control ..levels are keyed to fuel
supply: and .implementation of control technology. Adequate reserve capacities
.for-the; required .fuels, at .the quality levels called for by the abatement strategy
must be available, to meet, consumer demands. The control technologies for the
pollutants must be developed, demonstrated, and utilized in sufficient magnitude
before 1980 to have ,a meaningful impact on the future situation. These include,
in various phases of development, oil desulfurization processes, flue gas
desulfurization processes, coal cleaning, nitrogen oxides combustion control
techniques, and advanced, particulate control equipment. The projected require-
ment? for desulfurized heavy oil is about 1.2 billion (10^) barrels for 1980.
This;indicates a need for some 150 new, hydrogen treating plants integrated with
major petroleum refining complexes of some 31,500 bpsd. A highly intensive
construction program .will be needed to meet this requirement by 1980 if indeed
such a goal is attainable at this starting date. Similar problems exist in the
case of solid fuels,. Mining of low sulfur coals requires the opening of new
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T EMITTED TO THE AIR AS A RESULT
TONS S02 PER YEAR MILLIONS OF TONS S02 PER YEAR
iTiTiTitiTiTTiTitiTiTiTiTifififi?
a ? o '2~
o —
III'"-
3^z 1
J. fr-
ie-
ZC—
UNTREATED BITUMINOUS COAL
| C
POWER STATIONS ^
• IRON A STEEL 0.7% SULFUR j.
' OTHER INDUSTRIES 1
DOMESTIC & COMMERCIAL [ T
1.0% SULFUR
POWER STATIONS ONLY
I
ii
i!
.... iL.i
AN AMCUNT CF SULFUR
IS LEFT AT THE MINE
EQU VALENT TC THE
DIFFERENCE IN BUP.NINC
LOW SULFUft CCAL IN
PLACE OF HIGH SULFUR
CCAL
LIMESTONE SCRUBBING OF FLUE
GASES FROM BURNING Z.7%SULFUR
COAL 90% REMOVAL POWER
STATIONS ONLY
;
J
SC2 IS TIED
UP AS CASQi
-CASOjWITH
FLY ASH IN
SCRUBBER
SLUDGE
T
TO 1.0% SULFUR
OTHER INDUSTRIES ONLY
\
r 1
AN AMOUNT
OF SULFUft
S LEFT AT
THE POINT
OF COAL
CLEANING
EQUIVALENT
TC REPLAC-
ING HIGH
SULFUR CCAl
WITH LOW
SULFUR CCAl
FUEL OILS >
RESIDUAL FUEL OILS
<0.67% SULFUR
£
U» u
S £ 5
1 1 g |~-
lu tt z £ u
* _j O I *
p - a >- o
£ o — o a
• vr • •
f
1
j
DISTILLATE FUELCHL
<0.3as SULFUR
_j
<
2 2
yj i
p^St- o
fi
111
I'll
•III
jili
TC ELEMENTAL SULFUR RECOVERED
FRCM WASTE GASES WITH CLAU5
« PLANTS IN REFINERIES »
* NATU RA L G A S •
z INDETERMINANT SOv EMISSIONS EflOM OIL
2 AND GAS FIELD FLARING OF SULFUROUS
f TO PETROLEUM PRODUCTION *
^1^ I
i
L j.
: i
; :
1
s "
e v
: '
: :
; i
NOTE
-------
4.0-
3.6-
< 34-
LJ
>- 3.2-
o: 3,0-
UJ
Q. 2.6-
O
I— 1.6-
-I 0.6-
-- BITUMINOUS COAL
UNTREATED BITUMINOUS COAL
AVERAGE Z.7% SULFUR
POWER STATIONS ONLY
PS IS 01 DC
Jill
FUEL OIL —
. HYDROGEN TREATED .
RESIDUAL FUEL OILS
<0.87* SULFUR
\TJ
YDROGEN TREATED
STILLATE FUEL
OILS
<0.3% SULFUR
'JH
w
- NATURAL GAS
LU
> 0.6-
CC o.B-
LJ
Q- i.o-
o ^ 3.2-
"T 3..-
3.6-
3.8-
4.O-
FIGURE 4
PROJECTED I960 SITUATION
DISTRIBUTION OF FOSSIL FUELS AND ASSOCIATED NITROGEN OXIDE EMISSIONS
TO ACHIEVE THE 1970 TARGET LEVEL OF AIR POLLUTION
L15END
PS-POWER STATIONS
IS-IRON 4 STEEL
01-OTHER INDUSTRIES
DC-DOMESTIC & COMMERCIAL
OR-OIL REFINERIES
-------
»-
0-3.2-
< 2.8-
K. . .
< ' '
I*- , >
O '•
W '•'
2 i H
O
H- 1.2-
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0.8-
C/5
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n- 0-|
DC -
LU
Q.
CC
CL
U-
O
to
O
I—
L.
O _
AVERAGE 2.7* SULEUR
POWER STATIOHS ONLY
^ ^ae
O it "•
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-1 0
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PS IS DC
1
5
^
V
E?
. RESIDUAL FUEL 0
<0.87% SULFUR
OILS
LS >
PS 0«,SO, OC
II
•
DISTILLATE FUEL
OILS<0.3*SULFUR
PS
/
//
3 2 4 6 6 10 12 14 6 16 20 2J2 24 26 2 «
I 1
1 '
. |
1 1
1 .. |
L J ' '
i
i
i
i
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i
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OR
IS
01
i
42 44 4Ji 48 50 52 54 5,6 5Je ' «P ¥
T
64 6,6 6(S 7C
LjGEJjp
riftiiDF =,
1 S - 1R
01 -OT
OR -01
3N A STEEL
PROJECTED I960 SITUATION
DISTRIBUTION OF FOSSIL FUELS AND ASSOCIATED PARTICULATE EMISSIONS
TO ACHIEVE THE 1970 TARGET LEVEL OF AIR POLLUTION
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mines at sufficient rate to meet capacity goals... Flue.,gas,.cleaning for sulfur
oxides must be implemented on a large scale and,the waste disposal problems
must be solved satisfactorily.
The possibility of implementing the abatement strategy for limiting pollu-
tant emissions is dependent not only on technological; developments and practical
demonstration of.their .full-scale feasibility but also, to a considerable extent,
on:the rate of implementation which can be attained in practice and also the
timely"solution of the new or alternative environmental problems introduced by
such implementation:. . The social and economic consequences resulting from the
changes in various industrial practices required by large scale implementation
of abatement strategies, are not defined in the study,, but such changes will
obviously occur. .The industries most affected .will in particular be power
generation, petroleum.:refining, sulfur production, and industrial engineering
and construction. The estimated total investment required to accomplish the
abatement strategies for the two target levels 1970 and 1960 respectively are
(billions of 1970 dollars): particulate - 1.3 and 0.72; nitrogen oxides 2.8 and
2.8; sulfur oxides - 8.6 and 9.9; total - 12.7 and 13.5.
All methods of controlling sulfur oxide and,.to. a large degree, particulate
air pollutants have .one.aspect in common - in one way or another some form of
the pollutant is eventually returned to the .natural environment. Desulfuriza-
tion:processes - both those that remove sulfur .compounds from fuel before
combustion or from flue gas after combustion - produce sulfur compounds which
mayi-.be further processed ..to either recover sulfur in various forms for use in
the industrial or,.agricultural systems or for release into or storage in some
suitable: form in.the. natural environment. In any event these pollutants normally
re-enter the natural, environment after recovery and use since there is no con-
servation cycle. A satisfactory long term solution, to the problem of handling
the:.large amount..of. wastes generated through application of non-regenerable
processes, on a large scale has not yet been demonstrated.
Clean fuels will.not be available in sufficient .quantities to satisfy all
demands* The limited:supply of clean fuels as well as questions of security of
supply and rational.use of natural resources make.fuels management an important
aspect .in~pollution control practices. Clearly this-calls for some means of
allocation of clean fuels at local and national levels.
Non-combustion .sources of energy production will play a considerable role
in. the long term, but require assessment of environmental impact before wide-
spread implementation. The use of nuclear power plants-has been offered as a
solution to meeting the ever-increasing demands, for:electrical energy. However,
the-impact on the .ecology of the number and capacity of such installations which
will be required to satisfy the needs, has not been established. Also assoc-
iated with nuclear .power production are the two problems of fuel production and
waste disposal and .the ecological consequences of these two activities. In
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addition to the analysis of long-term environmental effects, catastrophe risk
must also be factored into the overall feasibility analyses.
B. Issues Arising From the Study
As indicated earlier the present study has Identified a number of issues
which appear to deserve more attention than they have been given in the course
of this or predecessor studies. Those considered of most importance are listed
below.
1) Pollution Consequences of Energy Consumption
More complete definition of the sources and amounts of pollution
from combustion is needed. This applies for all three major pollutants:
sulfur oxides, nitrogen oxides, and particulates. Even for sulfur
oxides which have been the subject of considerable study important
emissions which are associated with the production of fuels have not
been included in inventories of emissions which have dealt exclusively
with burning of fuels. Consequently sulfur emitted from processes
which clean natural gas prior to transport and from processes which
remove sulfur from distillate and residual fuels have not been included
in estimates of national emissions. In attempting to evaluate these
sources for the present study it was found that the necessary data for
reliable estimates could not be obtained within the scope of the study.
The information which was found suggests that sulfur oxide emissions
from fuel production may be one of our major sources.
In a recent parallel study of natural gas processed for sulfur
removal before pipeline transmission, it was determined that for about
10 percent of the annual production quantity of gas, approximately
700,000 long tons per year of sulfur are accounted for in recovery
plants in the gas fields. In addition, this same gas quantity, which
contains above-average sulfur as it comes from the well, accounts for
about 3,400,000 tons per year of SOx including both that which is
generated through field processing and that which is generated through
final use. These emissions are not included in the inventories pre-
pared for the U. S. National Report.
For nitrogen oxides and fine particulates the overall picture is
even more incomplete. For example, the nitrogen oxides produced in
combustion.processes is dependent both on combustion conditions and
on the amount of nitrogen in the fuel. Data on the relative roles of
each are almost nonexistent. For fine particulates, lack of data on
the fractional efficiency of control methods, coupled with poor
knowledge of the relative amounts of fine particulate produced by
different combustion systems, makes resultant estimates subject to a
possible wide variation.
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2) Fuel Use Patterns
More detailed information is needed to define fuel consumption by
industry. ..Some areas where little is known about the nature of the
consuming processes can be identified from Table 1 and 2. For all
fuels the "others" category is a balance.derived.by subtracting spec-
ific industry estimates from estimates for total consumption. This
category.represents a significant percentage,of the total consumption.
For gas, over one third of the total is expected to be consumed by
processes.which are undefined as far .as. their potential for pollution
possibility for control, etc., are concerned. Until better information
is developed it will be impossible to begin accurate assessment of
possibilities for optimizing national fuel consumption practices to
assure that energy demands are met in a way that prevents excessive
increases, in pollution and minimizes the costs for environmental pro-
tection which will be required when projected energy consumption
increases become a reality.
3). Combustion. Process Equipment
More.detailed information on types of equipment used to burn
:fuels are also:needed. Many types of combustion equipment, e0g., pack-
age boilers, .dryers, kilns, space heaters,, and .water heaters may
present, the .same,.pollution control problems in many industries. Better
information:on the character of the polluting hardware and the ways it
is used would..permit logical development of standards and regulations.
Also it would permit identification of classes of polluting equipment
.which are. in widespread use and would, identify the best opportunities
for reduction.of emissions and suggest the kind of R and D needed for
.improved control.capability. This is especially true for nitrogen
oxides which are,;, produced in quantities .dictated primarily by the
nature of the .hardware burning the fuel:.and are generally not amenable
to control, except through modification of the combustion system.
Collection of the needed data could begin with a study in which exist-
ing, information, on the kind and amount of fuel burned by specific types
of equipment is correlated with relative.contributions to air pollution.
Much of the..information necessary to complete such a project would not
be presently., available but it should, be: possible to accumulate existing
data in.a matrix.which would identify certain areas of importance and
show where more data are needed. Even.while such a problem definition
study is..underway .specific studies of problem areas already shown to be
important could begin. For example, over 95 percent of the distillate
fuel..consumed, in 1968 was burned by users in the "Domestic and
Commercial" or "Others" categories. It seems probable that the equip-
ment in these groups can be classified and:the different types evaluated
with respect.to.their possible importance as area sources. The result-
ing, information, .should be useful in development of more effective
control programs.
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4) Cost For Control.of.Pollution From Combustion
The present,study has preliminarily,estimated: part of the cost
which could be anticipated if a control strategy of the type assumed
was applied. The estimated capital requirement of $12.0 to $13.0
billion between now and 1980 is considered an order of magnitude figure
.which includes ..only investment directly assignable to control emissions
from those..processes currently burning ."dirty" fossil fuels. It does
not include, .estimates for the substantial .expenditures which will be
required for production facilities to meet.,the increased demand for
gas, distillate.fuels, or low sulfur .coal even though much of this
demand for. such fuels will result from pressure to control air pollution.
Further, the estimate is considered.conservative in that it was based on
the latest published figures, some of which are now considered ready for
revision because.they are unrealistically .low. The annual operating
cost figures, of .almost $3.0 billion per year are also considered to be
very rough ..estimates which do not reflect a true cost for control on a
national basis. The calculations are also based on the best information
available, but do not because of limitations imposed by data quality and
report guidelines include important, costs.such as the incremental costs
for premiums on low sulfur fuel. It is recognized that the estimated
costs reported here are higher than those.reported earlier and felt.
that this is attributable to our increasing understanding of the :problem.
It is.believed..,that more definitive .studies are urgently needed to pro-
vide better.estimates.
5) Ultimate Disposal ..of .Collected Pollutant
The problem of ultimate disposal of potential pollutants from
combustion., processes is one of great national importance which has in
the past not. received the attention it warrants. The planned control
of pollution..from..combustion will produce..either .vast quantities of
calcium.sulfate..sludge and fly ash .from "throwaway" processes and/or
large quantities, of sulfur or sulfuric acid produced by by-product pro-
cesses installed in the gas fields, refineries and on power stations.
The magnitude of the problem can be. illustrated by the following
examples..from.present study. From Figure 3 it can be seen that under
the assumed study about 6 million tons of sulfur oxide would be collected
using limestone scrubbing processes. For this quantity, controlled with
limestone scrubbing, it would be necessary to mine and ship to power
plant sites about 20 million tons of limestone„ Also it would be neces-
sary to dispose of almost 90 million tons per year of fly ash-calcium
sulfate sludge which is contaminated with soluble nitrate compounds
having potential for pollution of streams and ground water.
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Recovery of sulfur values as a by-product for marketing is also
a solution of limited applicability. A study of future world sulfur
supply and demand has predicted a continuing surplus of sulfur from
conventional sources until 1985. Abatement derived sulfur will not
be required until about 1990 to balance supply and demand0*
Even cleaning coal with available mechanical methods, an approach
which offers the potential for reduction of most sulfur at least cost,
is not without problems from the standpoint of ultimate disposal. For
the assumed strategy it was calculated that 2.25 million tons of sulfur
would! not be emitted to the atmosphere. This would require that an
estimated 21 million tons of coal cleaning refuse be stored using
methods that will prevent the piles from becoming future sources of
acid water drainage or air pollution from burning culnu There seems
to be little question that disposal of ash and sulfur near the mine
site is more economical than collection and disposal after combustion
of the fuel but significant costs are still involved.
6) Meeting Future Energy Requirements
The problem of containment of air pollution from combustion pro-
cesses is only one part of the greater problem of finding ways to meet
future energy requirements without producing massive environmental
insult. Again, reference to Figure 3 provides some indication of the
potential impact of air pollution control on the problem of meeting
future energy requirements. The control strategy assumes that 8.7
million tons of sulfur oxides will be prevented from entering the at-
mosphere by mining low sulfur coal. This means that an estimated 245
million tons of high sulfur coal which otherwise would be mined will
not be mined in the year 1980 alone. This amounts to a significant
new restraint being imposed on ways for meeting the 1980 fuel require-
ments. Costs will be incurred in opening new mines for low sulfur coal.
Additional cost would doubtless be incurred because of increases in the
cost to transport fuels to market. Further, the restraint in freedom
to exploit our most significant source of domestic fuel will increase
our degree of dependence on foreign fuels and will cause corresponding
increases in the cost of fuels we import.
Figure 3 also shows that 6.6 million tons of sulfur oxides will
be prevented from entering the atmosphere through the use of residual
fuels desulfurized to an average of ,87 percent sulfur. Production
of desulfurized residual fuels would require large expansion in exist-
ing U. S. desulfurization capacity. Also it would require better than
a 100 percent increase in our consumption of residual fuels which by
1980 would, if present trends continue, come almost exclusively from
foreign sources.
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7) Need for National Fuels Management
Planned allocation of available clean fuel supplies is essential to
accomplishing the desired reduction in emissions. It is feasible to con-
trol certain emitting sectors only by substitution of low polluting fuels
and improved combustion technology. Those sectors, the domestic, com-
mercial and certain industry activities which consist of a large number of
small consumers each individually emitting near ground level can be con-
trolled only through use of clean, non-polluting fuels and sound combustion
practice. These consumers require large amounts of fuel, about 50 percent
of the total energy requirements. The stimulation of the selected use of
clean fuels is an important abatement practice already applied in many
major localities. However, there are some such practices which are open to
question regarding consumption of clean fuels by sectors more amenable to
the application of other abatement practices in view of the limited avail-
ability of clean fuels.
The practice of consuming large quantities of low polluting fuels for
which there are inadequate long-term reserves by high demand, large capacity
users is questionable. For example, the use of natural gas to produce
electricty with subsequent transmission and reconversion to heat in the
home results in a loss of about 70 percent of the total chemical heat energy
of the gas. The energy of the gas, if burned directly in the home to pro-
duce heat, can be recovered with some 20 percent loss in efficiency of
conversion process. Thus, we can conserve some 50 percent of the energy
of natural gas if converted from chemical to heat energy on site rather than
going through the intermediate steps required to convert this energy to
electricity and then back to heat. The increasing use of air conditioning
and electrical heating in domestic and commercial sectors aggravate this
problem. This practice requires closer examination and consideration in the
framework of an energy management policy and activity.
8) The Impact of Fine Particle Emissions
It is important to bear in mind that with more widespread application
of control techniques the relative proportion of fine participate matter
(less than 10 microns in size) emitted, compared with the larger sized par-
ticulates will increase. The impact of this relative increase in the pro-
portion of fine particulate emissions cannot be estimated upon the existing
data base.
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SECTION III - CONCLUSIONS
While the present study was modest in scope and was accomplished using
only data which were available from the literature, it nevertheless has
served to illustrate the complexity of the interrelated problems of pollu-
tion control and energy production. Further, certain conclusions,
independent of the accuracy of the data available and assumptions, can be
drawn.
It can be concluded that potential for pollution from fuels combustion
is increasing rapidly. Projected sulfur oxide emissions are expected, on
the basis of estimated energy demand to be about twice the 25 million tons
emitted in 1968 unless widespread application of control technology is
practiced. A similar situation exists for nitrogen oxides, and in the case
of particulates, only the continuing use of effective particulate control
prevents drastic increases (approximately 10 fold) in particulate emissions.
It is also apparent that avoiding massive environmental insult will be
expensive. The cost to control sulfur oxides, nitrogen oxides and particu-
late emissions from fuel combustion to levels approximating those now
existing will amount to billions of dollars per year.
It is also apparent that meeting future demand for "clean" fuel will
seriously complicate the already serious problems associated with meeting
future energy requirements for the U. S. National planning will be required
to assure that the needed mix of fuels is available at any price. Our most
abundant fuel, coal, is usually high in sulfur which often is not amenable
to removal prior to combustion. It is apparent that we will be required to
use all available means including desulfurization of fuels where possible,
substitution of low sulfur fuels where available, and stack gas cleaning
where necessary to meet energy demands without undesirable levels of pollu-
tion, unacceptable economic impact or dependence on foreign supplies of fuel.
The problem is not limited to potential pollution from power generation.
Containment of pollution from burning of fuels for domestic, commercial and
industrial purposes other than power production will require management of
the production and consumption of low sulfur fuels, particularly gas and
distillate fuels.
Meeting 1980 demand for the distillate fuels which will be required to
minimize pollution calls for planned expansions of refinery facilities and
consideration of adjustment to fuel regulation policies, particularly those
relating to import regulations, to assure that necessary facilities can be
available by 1980 without unnecessary investment abroad.
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It is also clear that action is needed now to assure that technology
which will be needed in the immediate future is made available. Many of
the techniques which will be needed to control pollution from combustion
in 1980 and beyond are still under development. Stack gas cleaning systems
and processes for conversion of coal to "clean" fuel are the most important
examples of technology which must be developed, demonstrated and utilized
in the shortest possible time to meet future needs. Means for controlling
nitrogen oxides from combustion systems must be developed to a much higher
degree before significant reductions in national emissions will be possible.
Also our present capability for control of very fine particulates and par-
ticulates which are emitted with offensive co-contaminants is inadequate
for future needs.
Further it is apparent that better data and more sophisticated methods
for forecasting, planning, and managing our fuels production and consumption
practices are needed. Many examples can be cited. We are still in doubt
as to the relative importance of urban, rural and global effects and the
relative importance of area sources and point sources is understood only in
a qualitative way. This lack of understanding leads to difficulties in
setting meaningful priorities for emission control. We are also faced with
many anomolies in the present practices of fuel utilization.
At a time when natural gas needs to be conserved regulatory and price
control practices encourage consumption and act to discourage exploration
to identify new reserves. We are facing possible power shortages yet
utilities continue to encourage higher consumption. We continuously strive
for increases in the efficiency with which we use fuels and at the same
time we burn gas to produce electricity and use electricity to heat homes
when direct use of gas for heating would prevent a 50 percent loss of the
energy in the gas. At a time when it is apparent that great national
savings could be realized by using available technology to remove large
amounts of ash and sulfur at the mine we continue to pay unnecessary
penalties for transport of ash, overdesign of boilers to accomodate lower
quality fuel, and in the form of higher costs to remove the larger quantities
of particulates and sulfur oxides from the products of power station
combustion.
It is apparent that great changes in the traditional approaches to
production and consumption of fuels can be expected between now and 1980.
Nationally, our expectations for a clean environment are in conflict with
our ambitions for continued economic growth... changes in fuels management
practices will be the key to reaching a satisfactory compromise.
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Page 22
SECTION IV
U. S. NATIONAL REPORT TO THE
JOINT GROUP ON AIR POLLUTION FROM
FUEL COMBUSTION IN STATIONARY SOURCES -
ORGANIZATION FOR ECONOMIC COOPERATION AND DEVELOPMENT
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Page 23
THE U. S. NATIONAL REPORT TO THE O.E.C.D.
JOINT GROUP ON AIR POLLUTION
FROM
FUEL COMBUSTION
JUNE 11, 1971
REVISED NOVEMBER 1971
Prepared For
Office of Air Programs
Environmental Protection Agency
Prepared By
Processes Research, Inc.
Cincinnati, Ohio
Under Contract CPA 70-1
Task Orders No, 7 and 19
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24
TABLE OF CONTENTS
Page No.
Chapter I
Chapter II
Chapter III
Chapter IV
Chapter V
Annex I
Annex II
Annex III
Annex IV
Annex V
Annex VI
Annex VII
Annex VIII
Annex IX
Annex X
Annex XI
PREFACE
POLLUTANT EMISSIONS FROM BURNING FOSSIL
FUELS '
ALTERNATE POLLUTION ABATEMENT TECHNIQUES
POLLUTANT ABATEMENT STRATEGY FOR THE UNITED STATES
THE PROJECTED SITUATION FOR 1980
BASIS FOR COSTING OF POLLUTION CONTROL IN 1980
List of Publications and Source Material
Referred to In This Report
Description of Fossil Fuels Used in the United
States
Description of the Industry Sectors
Basis for Predicting Fuel Consumption in 1980
Factors for Calculating Emission Rates of
Pollutants
Fuel Cleaning
Advances in Combustion Technology
Flue Gas Cleaning
Costs of Cleaning Coal
Cost of Desulfurizing Oil
Costs of Combustion Control
1
9
14
15
21
27
31
34
38
41
47
50
53
55
57
60
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Page No.
Annex XII Costs of Flue Gas Cleaning 64
Annex XIII Waste Disposal 67
Table 1 United States Fossil Fuel Consumption in I960 4
Table 2 Consumption of Fuel and Resulting Stack Gas
Emissions 1960 5
Table 3 United States Fossil Fuel Consumption in 1968 6
Table 4 United States Fossil Fuel Consumption in 1970 7
Table 5 Consumption of Fuel and Resulting Stack Gas
Emissions 1970 8
Table 6 United States Fossil Fuel Consumption in 1980 16
Table 7 Consumption of Fuel with Uncontrolled Flue Gas
Emission 1980 17
Table 8 Consumption of Fuel with Flue Gas Emissions
Controlled to 1970 Level 19
Table 9 Consumption of Fuel with Flue Gas Emissions
Controlled to 1960 Level 20
Table 10 Calculated Investment Costs of Abatement Strategy
in the United States for Control of 1980
Pollutant Emissions to 1970 Level 23
Table 11 Calculated Investment Costs of Abatement Strategy
in the United States for Control of 1980
Pollutant Emissions to 1960 Level 24
Table 12 Yearly Operating Costs for Reducing 1980 Air
Pollutants to 1970 Levels in the United States 25
Table 13 Yearly Operating Costs for Reducing 1980 Air
Pollutants to 1960 Levels in the United States 26
ii
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Page No.
Table 14 Large Volume Natural Gas Utility Sales
to Other Industry Sector 37
Table 15 Emission Factors, Power Stations A3
Table 16 Emission Factors, Industrial Boilers 44
Table 17 Emission Factors, Domestic and Commercial 45
Table 18 Emission Factor for NOX, Refineries 46
iii
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Page 27
AIR POLLUTION FROM FOSSIL FUEL
COMBUSTION IN STATIONARY SOURCES
IN THE UNITED STATES
PREFACE
1. This report has been prepared to conform to the criteria established
by O.E.C.D. in "A Report on Air Pollution from Fuel Combustion in Stationary
Sources as A Guideline for National Reporting".
2. The rates of emission of the specific air pollutants NOX, SOX>
and particulates that result from burning fossil fuels have been cal-
culated for the years 1960 and 1970. The emissions have been calculated
from the most recent data on how much of these pollutants the various
fuels produce under varying conditions of burning. These data show how
the pollutant picture has changed in the last decade in the United
States.
3. Fossil fuel consumptions have been predicted for 1980, and from
these predictions, the uncontrolled pollutant emissions have been determined
using the same methodology as 1960 and 1970. Therefore, each fuel and
industry sector can be considered for its effect on air pollution.
4. An overall strategy for reducing the pollution of various sectors
has been presented. This strategy has been applied to show means for
reducing pollutant emissions to either 1970 levels (a 42 percent reduction
in potential emissions for NOX and a 54 percent reduction in projected
emissions for SOX) or 1960 levels (a 67 percent reduction in projected
levels for NOX and a 63 percent reduction in projected SOX emissions). The
state of the technology is sufficiently well developed that the strategy
can be regarded as technically feasible. The situation in the United
States for establishing and accomplishing air quality goals is in a
rapidly evolving state at this time. The concept of National Emission
Standards and Standards of Performance for certain industrial segments
was instituted by the Clean Air Act of 1970. Because the situation has
been rapidly changing, even during the preparation of the U. S. National
Report, it is not possible to indicate how well the estimates contained
in the National Report will truly represent the future picture as dictated
by the mechanisms finally adopted for achieving clean air.
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One of the formidable problems encountered was the rationalization
for and selection of the targeted emission levels. Because such levels
are only now being established through the basis of the Clean Air Act
of 1970, i.e., basis of best demonstrated control, the level of emission
control could not be based on permissible emission factors or on ambient
air quality guides. Target goals are based on control to 1960 and 1970
levels to provide at least some order-of-magnitude estimate for total
national control.
5. Costs have been developed to estimate some of the important
national costs for holding 1980 emissions to the levels estimated for
1960 and 1970.
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CHAPTER I
POLLUTANT EMISSIONS FROM BURNING FOSSIL FUELS
1. A modern industrial society consumes large quantities of fossil
fuel, converting it to energy by burning. Sulfur oxides, nitrogen oxides,
and particulates (unburned carbon and nonburnable ash) are the main pol-
lutants emitted by stationary fuel combustion sources. Other pollutants
emitted from these stationary sources are carbon monoxide, cyanides,
hydrocarbons, and trace minerals, as well as waste heat. This report
deals only with NOX, SOX, and particulates emitted in the United States.
2. The stationary sources of pollution from burning fossil fuels
have been divided into various user-oriented categories. These categor-
ies per O.E.C.D. guidelines are:
(a) Power stations
(b) Oil and gas production
(c) Oil refineries
(d) Coke ovens
(e) Iron and steel
(f) Cement
(g) Other industries
(h) Domestic and commercial
The use of these categories gives groupings of similar pollution sources.
It permits air pollution due to operation of a specific process (such as
iron oxides from steel furnaces) to be cataloged separately from the air
pollution which emanates from the fossil fuel. Also, it permits quanti-
fication of emission contributions from various sectors, e.g., homes
burning gas produce one-fourth as much NOX as power stations burning gas
(Tables 6 and 8).
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3. In some situations certain operations overlapped more than one
sector as defined by O.E.C.D. For example in 1967 in the "iron and steel"
sector 28 percent of the electricity was self-generated and 72 percent
was purchased from the "power stations" sector. For reporting purposes,
the 28 percent was reported with the power station category. This same
situation of part purchase and part generation is found in many other areas
such as chemicals, cement, and commercial buildings and was handled in
the same way. Another closely coupled interrelation is between coking
ovens and iron and steel (see Annex III-2) where coke oven gas predom-
inantly goes into steel plants and blast furnace gas predominantly goes
into coke ovens (References 8, 10). For reporting purposes, emissions
from combustion of coke oven gases were included with iron and steel
while emissions from combustion of blast furnace gas was assigned to
the coke ovens sector.
4. Using the fuel consumption rate for a given sector, the SOX emitted
can be assigned to that sector as a whole. This can be seen in Tables 6,
7, and 8. These figures give the total SOX for the United States with one
exception. Natural gas is produced in the oil fields and gas fields and
generally contains hydrogen sulfide. This is removed before the gas is
put into pipelines for use. Much of the hydrogen sulfide is burned to SOX
in the fields, along with natural gas, to get energy to run the collection
system. In this way the clean gas burned in the power stations and homes
creates SOX in the fields. These emissions which by the guidelines supplied
should be charged to the oil refineries sector, could not be accounted for
despite the fact that they may represent a significant percent of the total
now and in the future.
5. It should be noted that less is known about nitrogen oxides con-
cerning how they pollute and how they are formed. If nitrogen compounds
are present in fuel, some of them will appear in the combustion gases (see
Annex V-5). In addition, high temperature combustion in air causes NOx to
form from the nitrogen in the air; this is a situation usually present with
high excess air (Reference 11). Coal is the only major fuel for which
nitrogen oxide emission data are generally available; emission factors for
gas and oil firing are less reliable so that an unquantified bias may be
present in the data.
6. For purposes of the report all emissions were tabulated under the
industry in which the fuel was burned and when costs to control were calcu-
lated, it was done on the basis of cost to remove sulfur at the point in
the production-consumption cycle dictated by the control strategy. As a
result, it was not possible to break costs down by industry, and national
totals are shown.
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7. The consumption of fossil fuels in the various sectors in the
United States for I960 is shown in Table 1. The pollutant emissions for
1960 were calculated by using emission factors of Tables 15, 16, 17, and
18.
8. Stack gas emissions from burning fossil fuels in 1960 are sum-
marized in Table 2. For this table, all the rates "have been converted
into metric units. The fuel oil equivalent for all those fuels was cal-
culated on the basis that 1 million metric tons of heavy oil had a
higher heating value of 41.91 x lO*2 Btu.
9. Fuel rates for 1968 are shown in Table 3 and the rates for 1970
are shown in Table 4, O.E.C.D. has chosen 1968 for a base year, but for
convenience in preparation of this report 1970 has been selected as a
base year. The pollutant emissions for 1970 are shown in metric units
in Table 5.
10. Since 1966, virtually all new, large, coal-fired boilers and
furnaces have been erected with either a high efficiency wet scrubber
or an electrostatic precipitator as an integral component (References 6,
14, 15, 16, 17; 18). This has come about due to legislation and com-
petitive pressures as well as improved technology.
11. The 1980 participate emissions controlled to 1970 and 1960 levels
are on an assumed strategy basis which is achievable. It is anticipated
that high efficiency electrostatic precipitators will be installed on the
majority of plants by 1980. This would result in total particulate
emissions being reduced below the levels controlled to 1960 shown in this
report (Table 9).
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TABLE 1
UNITED STATES FOSSIL
FUEL CONSUMPTION
1960
POWER
STATION
COKE
OVEN
OIL
REFINERY
OIL
PRODUCT.
IRON &
STEEL
CEMENT
OTHER
DOMES!.
& COMC'L.
NATURAL
GAS
1723. x 109
ft.3
5 x 109
ft.3
77-S. x 109
ft.3
2122 x 109
ft.3
378 x 10*
ft.3
171.3 x 109
ft.3
5528 x 109
ft.3
4122 x 109
ft.3
MANUFAC
TURED
GAS
£7.63 x 109
; ft.3
302.7 x 109
ft.3
380.2 x 109
ft.3
0.7 x 109
ft.3
n.a.
27.64 x 109
ft.3
BLAST
FURNACE
GAS '
337.7 x 109
ft.3
n.a.
REFINERY
GAS
L.P.G.
7.96 x 106
Gals.
199. x 106
Gals.
1950. x 106
Gals.
HEAVY
FUEL OIL
95.4 x 106
Bbls.
45.05 x 106
Bbls.
49.50 x 106
Bbls.
4.035 x 106
Bbls.
115.8 x 10e
Bbls.
125.0 x 106
Bbls.
FUEL OIL
4.746 x 106
Bbls.
8.34 x 106
Bbls.
34.25 x
Bbls.
438. x 106
Bbls.
BROWN
COAL
2.289 x 10*
Tons
HARD
COAL
172. x 106
Tons
7.57 x 106
Tons
8.27 x 106
Tons
82.90 x 106
Tons
40.25 x 106
Tons
COKE
n.a.
n.a.
n.a.
n.a. = data not available.
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Regional Group - United States
TABLE 2
CONSUMPTION OF FUEL
AND RESULTING STACK GAS EMISSIONS
(DERIVED FROM TABLE 1 DATA)
Year 1960
Original OECD Figures
and million tons oil
equivalent
Sectors
Public power stations
Blast furnace gas and
B.K.B. not applicable
Refineries
Coke-ovens
Coke not consumed as
a fuel
Iron and steel
Coke not consumed as
a fuel
Other industries
Blast furnace gas,
Brown coal and B.K.B.
not applicable
Domestic and others
Blast furnace gas,
B.K.B., patent fuel,
coke end brown coal
not applicable
GRAND TOTAL
Type of Fuel
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
Brown coal
Coke
Total
Natural gas
Light fuel oil
Heavy fuel oil
Total
Blast furnace gas
Manufactured gas
Natural Gas
Total
Natural gas
Manufactured gas
Blast furnace gas
Heavy fuel oil
Light fuel oil
Hard coal
L.P.G.
Total
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
L.P.G.
Total
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
L.F.G.
Total
Fuel
Units
Teal
"
thousand metric tons
it ii ii
it ii ii
ti ii ii
ti ti ii
Teal
thousand metric tons
Teal
tl
It
Teal
ti
ti
thousand metric tons
it tt ii
M tt tt
II II II
Teal
11
thousand metric tons
ti it ii
n ii tt
M II II
Teal
II
thousand metric tons
tt tl M
II II ft
tt tl tl
Fuel
Rate
457.8 x 1012
3.79 x 1012
660.0
12,850.
96,900.
1,090.
n.a.
675.0 x 1012
1,160.
6,780.
-
8.06 x 10*2
41.77 x 101Z
1.26 x 1012
-
99.28 x 1012
52.54 x 1012
n.a.
7,450.
20.
4,260.
18.
-
1,451.0 x 1012
n.a.
4,760.
17,420.
46,700.
450.
-
1,082. x 101217
3.79 x 10J
60,900.
18,800.
22,680.
4,440.
NO*
Millions of
Metric Tons
0.305
0.003
0.010
0.190
1.560
0.021
n.a.
2.089
0.825
0.011
0.057
0.893
0.004
0.015
neg.
0.019
0.036
0.019
n.a.
0.068
neg.
0.069
neg.
0.192
0.552
n.a.
0.047
0.068
0.069
0.004
0.740
0.140
0.001
0.354
0.100
0.146
0.035
0.776
4.709
SOx
Millions of
Metric Tons
0.001
0.018
0.005
0.741
8.020
0.040
n.a.
8.825
0.001
0.007
0.350
0.358
neg.
0.194
neg.
0.194
neg.
0.245
n.a.
0.386
neg.
0.354
neg.
0.985
0.002
n.a.
0.028
0.930
4.230
neg.
5.190
0.001
0.018
0.356
0.971
1.968
neg.
3.314
18.866
Par ticu late
Millions of
Metric Tons
0.012
neg.
0.001
0.015
2.675
0.035
n.a.
2.738
0.236
0.004
0.017
0.257
0.003
0.003
neg.
0.006
0.003
0.003
n.a.
0.019
neg.
0.236
neg.
0.261
0.047
n.a.
0.013
0.045
2.830
0.001
2.936
0.035
neg.
0.083
0.024
0.365
0.006
0.513
6.710
Fuel Rate
Million Metric Tons
Oil equivalent
43.5
0.36
0.66
12.85
96.90
1.09
n.a.
155.36
63.22
1.16
6.78
71.16
0.766
3.97
0.12
4.856
9.435
4.99
n.a.
7.45
0.02
4.26
0.018
26.155
137.9
a. a.
4.76
17.42
46.7
0.45
207.23
102.8
0.36
60.9 !
18.8
22.68
4.44 ;
209.98
674.741
n.a.
neg.
« data not available
« less than 0.001
-------
TABLE 3
UNITED STATES FOSSIL
FUEL CONSUMPTION'
1968
POWER
STATION
COKE
OVEN
OIL
REFINERY
OIL
PRODUCT.
IRON &
STEEL
CEMENT
OTHER
DOMES!.
& COMC'L.
NATURAL
GAS
3148 x 109
ft.3
0.94 x 109
ft.3
1.59 x 1012
ft.3
1.07 x 10
ft.3
12
509 x
ft.3
202.9 x 109
ft.3
6.69 x
ft.
6.25 x 1012
ft.3
MANUFAC
TURED
GAS
91.9 x 109
ft.3
331.8 x 109
ft.3
904 x 109
ft.3
22.15 x 109
ft.3
14.84 x 10*
ft.3
BLAST
FURNACE
GAS
552 x 10-
ft<-
3.99 x 1012
ft.3
REFINERY
GAS
L.P.G.
14.61 x 10°
Gals
n.a.
n.a.
HEAVY
FUEL OIL
185 x 10°
Bbls.
39.3 x 106
Bbls.
23.85 x 106
Bbls.
5.76 x 106
Bbls.
114.4 x 106 174.3 x 106
Bbls.
Bbls.
FUEL OIL
8.51 x 10°
Bbls.
9.97 x 106
Bbls.
8.02 x 106
Bbls.
49.3 x 106
Bbls.
>10.7 x 106
Bbls.
BROWN
COAL
6 x 106
Tons
HARD
COAL
297.8 x 106
Tons
6.62 x 106
Tons
9.5 x 106
Tons
84.43 x 106
Tons
19.97 x 106
Tons
COKE
9.16 x 106
Tons
n.a. « data not available,
-------
TABLE 4
UNITED STATES FOSSIL
FUEL CONSUMPTION
1970
POWER
STATION
COKE
OVEN
OIL
REFINERY
OIL
PRODUCT.
IRON &
STEEL
CEMENT
OTHER
DOMES!.
& COMC'L.
NATURAL
GAS
3.45 x 1012
ft.3
1.09 x 109
ft.3
1.029 x 1012
ft.3
691. x 109
ft.3
497.5 x 109
ft.3
213.7 x 109
ft.3
10.83 x 10
ft.:
i;
7.00 x 10*2
ft.3
MANUFAC
TURED
91.3 x 109
ft.3
329.5 x 109
ft.3
883. x 109
ft.3
22.0 x 109
ft.3
14 x 109
ft.3
BLAST
FURNACE
GAS
547.5 x 109
ft.3
3.898 x 10J
REFINERY
GAS
5?
8
tt
L.P.G.
14.29 x 106
Gals.
n.a.
n.a,
HEAVY
FUEL OIL
309 x 106
Bbls.
39.1 x 10°
Bbls.
23.33 x 106
Bbls.
6.08 x 106
Bbls.
106. x 106
Bbls.
190 x 106
Bbls.
FUEL OIL
14.0 x 106
Bbls.
13.23 x 106
Bbls.
7.835 x 106
Bbls.
42.12 x 106
Bbls.
575 x 106
Bbls.
BROWN
COAL
7.51 x 10C
Tons
HARD
COAL
316.0 x 10*
Tons
6.46 x 106
Tons
10 x 106
Tons
133.8 x 106
Tons
20.0 x 106
Tons
COKE
9.16 x 106
Tons
n.a. = data not available.
-------
Regional Group - United States
TABLE 5
CONSUMPTION OF FUEL
AND RESULTING STACK GAS EMISSIONS
(DERIVED FROM TABLE 4 DATA)
Year 1970
Original OECD Figures
and million tons oil
eqlova;emt
Sectors
Public power stations
Blast furnace gas and
B.K.B. not applicable
Refineries
Coke-ovens
Coke not consumed as
a fuel
Iron and steel
Coke not consumed as
a fuel
Other industries
Brown coal and B.K.B.
not applicable
Domestic and others
Blast furnace gas,
B.K.B., patent fuel,
coke, and brown coal
not applicable
GRAND TOTAL
Type of Fuel
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
Brown coal
Coke
Total
Natural gas
Light fuel oil
Heavy fuel oil
Total
Blast furnace gas
Manufactured gas
Natural gas
Total
Natural gas
Manufactured gas
Blast furnace gas
Heavy fuel oil
Light fuel oil
Hard coal
L.P.G.
Total
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
L.P.G.
Total
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
L.P.G.
Total
Fuel
Units
Teal
M
thousand metric tons
n ti it
n it it
n ti it
ti ii ti
Teal
thousand metric tons
ii n n
Teal
II
It
Teal
n
it
thousand metric tons
M tl tl
II II II
11 II tl
Teal
ti
thousand metric tons
tt it H
n ti ii
ii ti M
Teal
II
thousand metric tons
ii ii n
it ii H
n H it
Fuel
Rate
906. x 1012
12.63 x 1012
1,770.
46,480.
178,000.
2,975.
4,810
441.0 x 1012
1,670.
5,880.
-
13.07 x 1012
45.51 x 10j;
0.28 x 101
-
130.6 x lo}2
120.8 x 101,
95.04 x 101
3,512.
989.
3,660.
36.
2,898. x 10 !-2
3.05 x 10 w
5,315.
16,870.
81,050.
n.a.
-
1,837. x 10-2
1.90 x LO"
72,600.
28,580.
11,260.
n.a.
-
-
Nox
Millions of
Metric Tons
0.608
0.008
0.028
0.617
2.866
0.068
0.084
4.279
1.090
0.017
0.050
1.157
neg.
0.016
neg.
0.016
0.047
0.044
neg.
0.032
0.011
0.059
neg.
0.193
1.073
neg.
0.058
0.153
1.306
n.a.
2.590
0.231
neg.
0.463
0.152
0.073
n.a.
0.919
9.154
S°x
Millions of
Metric Tons
0.001
0.059
0.013
2.403
14.690
0.130
0.158
174454
0.001
0.011
0.305
0.317
0.005
0.212
neg.
0.217
neg.
0.563
neg.
0.181
0.006
0.299
neg.
1.049
0.003
0.018
0.034
0.872
6.675
n.a.
7.602
0.003
0.009
0.468
1.478
0.934
n.a.
2.892
29.531
Particulate
Millions of
Metric Tons
0.024
0.001
0.002
0.047
4-. 900
0.117
0.142
5.233
0.014
0.005
0.015
0.034
0.004
0.003
neg.
0.007
0.005
0.007
neg.
0.009
0.003
0.200
neg.
0.224
0.091
neg.
0.016
0.044
4.835
n.a.
4.986
0.061
neg.
0.109
0.036
0.181
n.a.
0.387
10.871
Fuel Rate
Million Metric Tons
Oil equivalent
86.16
1.20
1.77
46.48
178.0
2.975
4-. 81
321.395
42.92
1.67
5.88
50.470
1.243
4.328
0.027
5.598
12.42
11.58
9.036
3.512
0.989
3.66
0.036
41.233
275.5
0.29
5.315
16.87
81.05
n.a.
379.025
174.6
0.18
72.60
28.58
11.26
n.a.
287.22
1084.941
n.a. - data not available
neg. = less than 0.001
-------
Page 37
CHAPTER II
ALTERNATE POLLUTION ABATEMENT TECHNIQUES
12. Many methods for pollution abatement are under investigation and
in various stages of development. An attempt is made herein to give a
brief description of those more suitable.for large scale application in
the immediate future.
13. The rate at which technology under development can be made op-
erational on a significant scale must be considered before deciding on a
control strategy to be applied in the next 10 years. Processes in advanced
development now can have significant impact by 1980. A process for cata-
lytic oxidation of SC>2 and C^ in the flue gases to produce SO3 which reacts
with H£0 to produce H2SO^ is being scaled up to control a full scale boiler.
Also at present, limestone-based processes are processes being studied on
full scale equipment. On the basis of this work, it is assumed that flue
gas cleaning would be used along with fuel substitution to achieve the
desired level of control. For simplicity in developing costs, all flue
gas cleaning will be limestone scrubbing even though other processes may be
in service in 1980.
1A. Methods of pollution abatement that are suitable for use will vary
with the size of the installation. Intermediate sized commercial and in-
dustrial boilers have the least number of options available of all the
stationary pollutant emitters, due primarily to their small size and non-
standard installations. Being small, owners frequently cannot negotiate
long-term contracts for any particular fuel. With the government regula-
ting gas distribution to ensure that it gets to dometic and service users
(such as hospitals), they cannot readily use alternate fuels. Their small
size makes any stack scrubbing system very costly.
15. Obviously, processes that reduce pollution loads for all three of
the major pollutants simultaneously are desirable. Methods to achieve
simultaneous reductions are described below.
(a) Nuclear energy is air pollution free with respect to the
three major pollutants under consideration. It does, how-
ever, present other problems, such as thermal pollution,
air contamination from radioactive gases, and contamination
from radioactive solid and liquid wastes and pollution which
results from fuel reprocessing. The rate of increase in
-------
Page 38
nuclear generating capacity in the next nine years will not
be great enough to prevent large increases in fossil fuel
pollution (Reference 37).
(b) Tall stacks have been widely used to dispense pollutants<,
Furthermore, the criterion of tall stacks is inherent in
many local laws restricting the sulfur content of fuels
burned. However, if pollution from combustion is to be
considered as a problem which should not be passed on with-
out consent to neighboring countries, this approach cannot
be considered as a satisfactory solution to international
problems.
(c) Fuel substitution is the most direct and simplest method of
reducing air pollution from any stationary source. This
can consist of using a higher quality fuel of the same type,
e.g., low sulfur coal instead of high sulfur coal; or of
changing the type of fuel, e.g., using natural gas instead
of coal. The extent of fuel substitution which is possible
in the United States is seriously limited by the size and
accessibility of reserves of low pollution fuels.
(d) Gas turbines have become significant factors in power genera-
tion in the last few years. They are low cost units generating
electricity from a gas and emitting little in the way of air
pollutants (see Tables 15 and 18). However, they have low
efficiency (References 20, 22) operating at 24 percent com-
pared to a steam electric plant using gas at 33 percent. If
the government did not regulate prices, their economic ad-
vantages would be materially decreased. The main impact they
have on pollution is that turbines consume more of a clean
fuel to generate a given quantity of electricity than does a
steam plant. Since natural gas is in short supply, widespread
use of gas turbines in power generation is not desirable on
a long-term basis except as they may be adapted for use with
gas produced from coal or residual oil. Where they can be
used with cleaned gas produced from residual oil or coal in
combined gas-steam cycles they are believed to offer potential
efficiency which will offset significant portions of the
cost to control pollution beyond 1980.
10
-------
Page 39
(e) Fluid bed combustion, in which the burning fuel is combined
with a bed consisting mainly of limestone particles, offers
a potential method for reduction of sulfur oxide and nitro-
gen oxides. This process is in early development stages,
and it is consequently not possible to establish what pollu-
tion reductions can be attained and what the engineering
design parameters are for full scale operation. There is
little likelihood that it can be used to any great extent
by 1980. (Reference 32)
(f) Coal can be converted to a low calorific value gas suitable
for power generation by gasification with air. The sulfur
and participates can be removed from the smaller volume of
gas much more economically than they can from the larger
volumes of combustion flue gas. This gas must be produced
at the site where it is to be used because pipeline trans-
portation costs are excessive for a low heating value gas.
Coal gasification to make a substitute natural gas with a
high heating value is also technically feasible, but time
required for necessary development and construction of pro-
cesses makes it unlikely that this approach will contribute
to control of pollution in the next nine years.
>. For the control of sulfur oxides, specifically, the following
ithods can be utilized:
(a) Fuel substitution by mining more low sulfur coal to replace
some of the high sulfur coal being used. There are large re-
serves of low sulfur coal, particularly in the western United
States. However, their use has been restricted because their
location is remote from users so that use in the east would
result in high transportation cost. With the pressing need
for low sulfur fuels, mining of more of this coal can be
justified.
(b) The mechanical desulfurization of coal is one of the cheapest
ways to reduce SOX. Coal preparation or coal washing has
been a standard commercial practice for many years. In most
instances the coal was cleaned to reduce the ash content of
the coal. Until recently, little attention was paid to the
special problem of sulfur reduction by coal preparation.
Studies of coal seams have shown that there are large re-
serves of coal which can be deep cleaned to less than 1 per-
cent pyritic sulfur content.
11
-------
Page 40
(c) Desulfurization of residual fuel oil to I percent sulfur, or
less, is commercially feasible and is practiced to a limited
extent. Most of the processes are in the development stage,
and costs are high. Research to achieve better catalysts
and catalyst life, higher throughput, lower operating tem-
peratures and pressures, and reduction in hydrogen consump-
tion, should result in reduced costs.
(d) There are a number of flue gas cleaning processes in various
stages of development. These are classified as either
throw-away processes, with SOX removed as a waste product, or
by-product recovery, with recovery of sulfur or sulfuric acid.
The most promising of the throw-away processes are limestone
injection and wet scrubbing or lime scrubbing. These have
been under development for some time, but remain to be proved
reliable on a commercial scale. The large quantities of
sludge formed present a disposal problem. Other throw-away
processes are sodium bicarbonate dry injection and ammonia
scrubbing with recovery of ammonia. The former presents
the problem of disposing of water-soluble sodium sulfate,
and the latter presents a solid waste disposal problem. By-
product recovery processes, such as magnesium oxide scrubbing,
potassium sulfite, and catalytic oxidation have yet to be
demonstrated on a commercial scale.
17. The control of NOX as an air pollutant is in need of further re-
search. Any high temperature combustion process using air as a source of
oxygen forms NOX from the nitrogen in the air. Any fuel containing nitro-
gen will also form NOX by oxidizing of the nitrogenous material. Fieldwork
on full scale boilers has shown that by various combinations of techniques,
NOX can be held down to 200 ppm in the stack gas as discussed in Annex VII.
The three most practicable methods in terms of technology today are:
(a) Low excess air. A low proportion of air above the stoichio-
metric amount to oxidize the fuel, in the order of about 10
percent by volume, permits fuel combustion to take place with
a low formation of NOV.
A
(b) Flue gas recirculation. Returning about 10 percent of the
stack gas back into the flame zone of a boiler or furnace has
a measureable effect on NOX formation, as pointed out in
Annex VII.
12
-------
Page 41
(c) Two-stage combustion which employs a lower temperature reduc-
ing atmosphere section, i.e., less than stoichiometric air,
followed by a second oxidizing atmosphere section. The design
is highly specialized, and since the technology has not be-
come widespread, this was not considered in the strategy.
f
19. Fluid bed combustion has come to the fore as a promising technique
of burning coal in a fluidized bed of limestone. The limestone effectively
ties up the sulfur to materially reduce SOX emissions but its benefits on
NOX depend on the fuel. This is currently confined to the pilot plant
stage, and therefore was not considered part of the abatement strategy.
20. A side benefit of SOX reduction using wet alkali scrubbing of
stack gases is some reduction in the NOX. A 20 percent removal was
assumed for calculation of emissions. The effectiveness is lower for
NOX than for SOX, so its benefit is incidental. The benefit is shown
in Table 9 compared to Table 8 where the 1960 level emissions are lower
than the 1970 level emissions as a result of more extensive scrubbing
to reduce SOX. The strategy for combustion control in 1970 control is
the same as in 1960, but the lower NOX is due to more limestone scrubbing.
21. Control of particulate emission is the area where technology is
the most advanced and widespread. In the United States the trend to
control has been almost universal for all industry sectors, and coal-
fired furnaces have installed, since 1966, either electrostatic preci-
pitators or high energy wet scrubbers. By 1980 it is projected that all
coal-fired equipment will have particulate collection equipment. The
potential for emissions is shown in Table 7 (over 73 million tons). It
is anticipated that the actual emissions for 1980 will be well below the
1960 level of 6.7 million tons.
13
-------
Page 42
CHAPTER III
POLLUTANT ABATEMENT STRATEGY FOR THE UNITED STATES
22. Because sulfur oxide control is the most important consideration
in control of pollution from combustion, the control strategy which was
developed was aimed primarily at maximum reduction in this pollutant. In-
cidental benefits in NOX and particulate control resulting from application
of SOX control technology were factored into subsidiary programs for NOX
and particulate control. Details of assumed strategies are discussed in
Chapter IV.
23. No single approach for control of SOX can be considered practical
within the next ten years. Fuel substitution is limited by the supplies
of clean fuels. Flue gas scrubbing, even with well developed technology,
presents other problems such as disposal of large quantities of sludge and
possible water pollution. For purpose of this report, tall stacks are not
to be considered as a positive control measure for pollutant capture. The
strategy in the O.E.C.D. Guideline report of limiting the sulfur content
of oil and substituting low sulfur oil for coal has been ruled out because
existing legislation already limits the sulfur content of oil in many areas.
In addition, the total available quantity of oil in 1980 is not expected to
be sufficient to allow its complete substitution for coal.
24. The strategy proposed includes a combination of four methods for
the control of SOX. These are:
(a) Increased mining of low sulfur coal,
(b) Mechanical desulfurization of coal as described in Annex VI.
(c) Residual oil desulfurization as described in Annex VI.
(d) Flue gas cleaning by wet limestone scrubbing as discussed
in Annex VIII.
25. For control of NOX, the only known means likely to be implemented
on a large scale by 1980 is improved combustion techniques for lowering
operating temperatures. This is discussed in Annex VII.
26. -,.'• Particulates are expected to be controlled by the increased use of
electrostatic precipitators, following current trends, in addition to the
stack scrubbers used for SOX control.
14
-------
Page 43
CHAPTER IV
THE PROJECTED SITUATION FOR 1980
27o The consumption of fossil fuels in 1980 was predicted as described in
Annex IV and as listed in Tables 6 and 7.
28. The uncontrolled emission of pollutants was calculated from the fuel
consumption and the emission factors discussed in Annex V and listed in Tables
15, 16, 17, and 18,
29. The emission levels which would result from applying controls to limit
potential emissions for 1980 to about the level estimated for 1970 are shown
in Table 5. Results of a similar exercise limiting potential emissions for
1980 emissions to 1960 levels are shown in Table 2.
30. For the control of potential SOX emissions for 1980 to the estimated
1970 level, the control technology was assumed available as follows.
(a) Increased mining of low sulfur coal (0.7 percent S average) to
the extent that it comprises 28 percent of the total coal
production in 1980 for fuel usageo Approximately 35 percent of
this will come from the large reserves of low sulfur'coal in the
western United States, and 65 percent from the low sulfur reserves
in the eastern United States.
(b) Mechanically deep clean approximately 14 percent of the total
coal usage to less than 1 percent sulfur content. (0.7 per-
cent S average)
(c) Install limestone flue gas scrubbers on 25 percent of the power
station capacity using high sulfur coal. This is equivalent to
scrubbing the flue gas produced from about 14.6 percent of all coal
burned. The remaining 75 percent of the high sulfur coal-fired
power stations emit their SO uncontrolled.
X
(d) The remaining about 4308 percent of all coal used in 1980 will be
burned in power stations with no control for SOX emission.
(e) Desulfurize all residual fuel oil to be used in 1980 to 0.87
percent sulfur content as discussed in Annex VI.
(f) There will be 150 new hydxotreating plants installed to meet
the total capacity demands of heavy oil which is above the
projected demands for light oil.
15
-------
TABLE 6
UNITED STATES FOSSIL
FUEL CONSUMPTION
1980
NATURAL
GAS
MANUFAC
TURED
GAS
BLAST
FURNACE
GAS
REFINERY
GAS
L.P.G.
HEAVY
FUEL OIL
FUEL OIL
BROWN
COAL
HARD
COAL
COKE
POWER
STATION
5.186 * 1012
ft.3
106.9 x 109
ft.3
^^
^
708 x 106
Bbls.
35.2 x 106
Bbls.
10.3 x 106
Tons
682. x 106
Tons
5.7 x 106
Tons
COKE
OVEN
1.09 x 109
ft.3
386. x 109
ft.3
640 x 109
ft.3
^^
/^
^^
^^
^^
^^
OIL
REFINERY
1362. x 109
ft.3
^^
^^
^^
33.9 x 106
Bbls .
19.05 x 106
Bbls.
^^
^^
/
OIL
PRODUCT.
992. '« 109
ft.3
^^
^^
^^
^^
^^
^^
^^
^
IRON &
STEEL
689.5 x 109
ft.3
1.225 x 1012
ft.3
5.AO x 1012
ft.3
^^
7.71 x 106
Bbls.
33.1 x 106
Bbls.
^^
9.0 x 106
Tons
^^
CEMENT
283.1 x 109
ft.3
^^
^^
^^
8.06 x 106
Bbls.
^^
^^
L3.28 x 106
Tons
^
OTHER
21.18 x 1012
ft.3
27.6 x 109
ft.3
^^
^^
126.5 x 106
Bbls.
A7.0 x 106
Bbls.
^^
L58.3 x 106
Tons
^^
DOMES! .
& COMC'L.
5.94 x 1012
ft.3
13.8 x 109
ft.3
^^
^^
288.6 x 106
Bbls.
682.0 x 106
Bbls.
^^
9.92 x 106
Tons
^^
-------
Regional Group - United States
TABLE 7
CONSUMPTION OF FUEL
WITH UNCONTROLLED FLUE CAS EMISSION
(DERIVED FROM TABLE 6 DATA)
Year 1980
Original OECD Figures and
Billion ton* oil equivalent
Sectors
Public power stations
Blast furnace gas and
B.K.B. not applicable
Refineries
Coke-ovens
Coke not consumed as
a fuel
Iron and steel
Coke not consumed as
a fuel
Other industries
Blast furnace gas,
brown coal and B.K.B.
not applicable
Domestic and others
Blast furnace gas, B.K.B.
patent fuel, coke and
brown coal not applicable
GRAND TOTAL
Type of Fuel
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
Brown coal
Coke
Total
Natural gas
Light fuel oil
Heavy fuel oil
Total
Blast furnace gas
Manufactured gas
Natural gas
Total
Natural gas
Manufactured gas
Blast furnace gas
Heavy fuel -oil
Light fuel oil
Hard coal
L.P.G.
Total
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
Total
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
Total
Fuel
Units
Teal
ft
thousand metric tons
If II M
tt n n
it n n
it ti ti
Teal
thousand metric tons
M M II
Teal
tt
II
Teal
II
It
thousand metric tons
it H M
it M it
tt ti n
Teal
tl
thousand metric tons
ti n M
n n it
Teal
ti
thousand metric tons
ti n ti
it tt n
Fuel
Rate
1,362.5 x 1012
14.76 x 1012
4,436.
106,500.
384,300.
4,000.
3,810.
.
618. x 1012
2,400.
5,100.
-
15.26 > 1012
52.35 x 1012
0.28 x 1012
-
180.8 x lO}2
169.0 x 10"
128.9 x 101Z
1,160.
4,173.
5,070.
41.
-
5,640. x 1012
3.79 x 1012
6,550.
20,250.
89,800.
-
1,558. x 1012
1.89 x 1012
43,420.
86,000.
5,590.
-
-
NO*
Millions of
Metric Tons
0.798
0.010
0.072
1.415
6.185
0.094
0.052
8.626
1.445
0.025
0.440
1.910
neg.
0.019
neg.
0.019
0.065
0.062
0.049
0.011
0.045
0.082
neg.
0.314
2.078
neg.
0.064
0.183
1.543
3.868
0.200
neg.
0.546
0.230
0.036
1.012
15.749
S°x
Millions of
Metric Tons
0.002
0.069
0.032
5.504
31.750
0.178
0.099
37.634
0.001
0.015
0.263
0.279
0.006
0.245
neg.
0.251
neg.
0.789
neg.
0.060
0.026
0.417
neg.
1.292
0.006
0.018
0.038
1.043
7.99
9.095
0.002
0.009
0.549
2.231
0.463
3.254
51.805
Particulate
Millions of
Metric Tons
0.035
0.001
0.006
0.117
58.880
0.889
0.493
60.421
0.019
0.072
0.013
0.104
0.005
0.004
neg.
0.009
0.006
0.010
0.044
0.003
neg.
0.630
neg.
0.693
0.172
neg.
0.018
0.051
12.05
12.291
0.051
neg.
0.130
0.055
0.090
0.326
73.844
Fuel Rate
j Million Metric Tons
; Oil equivalent
1
j 129.5
I 1.403
4.436
106.5
384.3
4.0
3.81
633.949
58.75
2.40
5.10
66.25
1.45
5.07
0.027
6.547
17.19
16.07
12.25
1.16
4.173
5.07
0.041
55.954
536.0 ^
0.36
6.55
20.25
89.8
652.96
148.20
0.18
95.0
86.0
5.59
334.97
1750.63
n.a.
neg.
data not available
less than 0.001
17
-------
Page 46
(g) All coal burning power stations not equipped with limestone
flue gas scrubbers are assumed to be equipped with electro-
static precipitators operating at 90 percent participate
removal efficiency on a continuous basis.
31. The calculated emissions, incorporating the above controls, are
listed in Table 8.
32. For control of reduction of 1980 emissions to the 1960 level, the
technological requirements are: .
(a) Increased mining of low sulfur coal (0.7 percent S) to the
extent that it comprises 28 percent of the total coal pro-
duction in 1980. Approximately 35 percent of this will
come from the large reserves of low sulfur coal in the western
United States, and 65 percent from the low sulfur reserves in
the eastern United States.
(b) Mechanically deep clean approximately 14 percent of the total
coal usage to less than 1 percent sulfur content.
(c) Install limestone flue gas scrubbers on 75 percent of the
power stations using high sulfur coal. This is equivalent to
scrubbing the flue gas from 44 percent of all coal burned.
(d) The remaining 14 percent of all coal will be burned in power
stations, uncontrolled for SOX.
(e) Desulfurize all residual fuel oil to 0.87 percent sulfur content
as discussed in Annex VI.
(f) All coal burning power stations not equipped with limestone
flue gas scrubbers are assumed to be equipped with electro-
static precipitators operating at 90 percent particulate
removal efficiency on a continuous basis.
33. The calculated emissions, incorporating these controls, are listed
in Table 9.
34. NOX is controlled for both the above cases utilizing combustion
control by flue .gas recirculation and Ipw excess air to the maximum extent.
In addition, NOX is removed together with SOX in the limestone scrubbing.
The difference between 1970 and 1960 levels of NOX removal is solely due
to more limestone scrubbing application in the control to 1960 level.
18
-------
Regional Group - United States
TABLE 8
CONSUMPTION OF FUEL
WITH FLUE GAS EMISSIONS CONTROLLED TO 1960 LEVEL
(DERIVED FROM TABLE 6 DATA)
Year 1980
Original OECD Figures and
million tons oil equivalent
Sectors
Public power stations
Blast furnace gas and
B.K.B. not applicable
Refineries
Coke-ovens
Coke not consumed as
a fuel
Iron and steel
Coke not consumed as a
fuel
Other industries
Blast furnace gas, brown
coal and B.K.B., not
Domestic and others
Blast furnace gas, B.K.B.,
patent fuel, coke and
brown coal not applicable
GRAND TOTAL
Type of Fuel
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
Brown coal
Coke
Total
Natural gas
Light fuel oil
Heavy fuel oil
Total
Blast furnace gas
Manufactured gas
Natural gas
Total
Natural gas
Manufactured gas
Blast furnace gas
Heavy fuel oil
Light fuel oil
Hard coal
L.F.G.
Total
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
Total
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
Total
Fuel
Units
Teal
It
thousand metric tons
ii ti • H
II H If
It II II
If II II
Teal
thousand metric tons
H it M
Teal
it
ii
Teal
ii
M
thousand metric tons
ii ii ii
ii M ii
H ii n
Teal
n
thousand metric tons
n M n
it n n
Teal
ii
thousand metric tons
ii it ii
n it M
i
Fuel
Rate
1,362.5 x 1012
14.76 x 1012
4,436.
106,500.
384,300.
4,000.
3,810.
-
618.0 x 1012
2,400.
5,100.
-
15.26 x 10J2
52.35 x 1012
0.28 x 1012
-
180.8 x 1012
169.0 x 1012
128.9 x 1012
1,160.
4,173.
5,070.
41.
-
5,640. x 1012
3.79 x 101Z
6,550.
20,250.
89.800.
-
1,558. x 101212
1.89 x 101*
43,420.
86,000.
5,590.
-
-
N°x
Millions of
Metric Tons
0.328
0.003
0.028
0.566
2.974
0.047
0.026
3.972
1.445
0.025
0.044
1.514
0.006
0.019
neg.
0.025
0.065
0.062
0.049
0.011
0.045
0.082
neg.
0.314
0.540
neg.
0.016
0.054
0.479
1.089
0.200
neg.
0.546
0.230
0.036
1.012
7.936
SO,
Millions of
Metric Tons
0.002
0.069
0.032
1.850
20.960
0.178
0.098
23.189
neg.
0.015
0.088
0.103
neg.
0.245
neg.
0.245
neg.
0.789
neg.
0.020
0.026
0.108
neg.
0.943
0.005
0.018
0.038
0.348
2.068
2.477
0.002
0.009
0.549
0.749
0.120
1.429
28.386
Farticulate
Millions of
Metric Tons
0.035
0.001
0.005
0.108
4.891
0.089
0.049
5.178
3.019
3.073
0.013
0.105
0.005
0.004
neg.
9.009
0.005
0.010
0.044
0.005
neg.
0.113
neg.
0.177
0.175
neg.
0.018
0.048
1.551
1.792
0.051
neg.
0.130
0.055
0.090
3.326
7.587
Fuel Rate
Million Metric Tons
Oil equivalent
129.5
1.403
4.436
106.5
384.3
4.0
3.81
633.949
58.75
2.40
5.10
66.25
1.45
5.07
0.027
6.547
17.19
16.07
12.25
1.16
4.173
5.07
0.041
55.954
536.0
0.36
6.55
20.25
89.8
652.96
148.20
0.18
95.0
86.0
5.59
334.97
1750.630
19
n.a
neg. = Less than 0.001
-------
Regional Group - United States
TABtE 9
CONSUMPTION CF FUEL
WITH FLUE GAS EMISSIONS CONTROLLED TO 1960 LEVEL
(DERIVED FROM TABLE 6 DATA)
Year 1980
Original OECD Figures and million tons
oil equivalent
Sectors
Public power station
Blast furnace gas and
E.K.B. not applicable
Refineries
Coke-ovens
Coke not consumed as
a fuel
Iron and steel
Coke not consumed as
a fuel
Other industries
Blast furnace. gas,
brown coal and B.K.B.
not applicable
Domestic and others
Blast furnace gas, B.K.B.,
patent fuel, coke and brown
coal not applicable
GRAND TOTAL
Type of Fuel
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
Brown coal
Coke
Total
Natural gas
Light fuel oil
Heavy fuel oil
Total
Blast furnace gas
Manufactured gas
Natural gas
Total
Natural gas
Manufactured gas
Blast furnace gas
Heavy fuel oil
Light fuel oil
Hard coal
L.P.G.
Total
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
Total
Natural gas
Manufactured gas
Light fuel oil
Heavy fuel oil
Hard coal
Total
Fuel
Units
Teal
II
thousand metric tons
M M tt
if ii ii
ti ii ii
» ii ii
Teal
thousand metric tons
ti ii ii
Teal
H
ii
Teal
Teal
tf
thousand metric tons
it ti ii
ti n H
it it 11
Teal
ti
thousand metric tons
it ii tt
ii M it
Teal
ii
thousand metric tons
M II II
II II II
Fuel
Rate
1,362.5 x 1012,,
14.76 x 1012
4,436.
106.500.
384,300.
4.000.
3,810.
-
618.0 x 1012
2,400.
5,100.
-
15.26 x 1012
52.35 x 1012
0.28 x 1012
-
180.8 x 1012
169.0 x 1012
128.9 x 1012
1,160.
4,173.
5,070.
41.
-
5,640. x 1012
3.79 x 101Z
6,550.
20,250.
89,800.
-
1,558. x 101212
1.89 x 10
95,000.
86,000.
5,590.
-
-
NOx
Millions of
Metric Tons
0.328
0.003
0.028
0.566
2.749
0.047
0.026
3.747
1.445
0.025
0.044
1.514
0.006
0.019
neg.
0.025
0.065
0.062
0.049
0.011
0.046
0.082
neg.
0.315
0.540
neg.
0.016
0.054
0.479
1.089
0.200
neg.
0.546
0.230
0.036
1.012
7.702
SO,
Millions of
Metric Tons
0.002
0.069
0.032
1.850
10.240
0.178
0.098
12.469
neg.
0.015
0.088
Q.103
neg.
0.245
neg.
0.245
neg.
0.789
neg.
0.020
0.026
0.108
neg.
0.943
0.005
0.018
0.038
0.348
2.068
2.477
0.002
0.009
0.549
0.748
0.120
1.428
17.665
Particulate
Millions of
Metric Tons
0.035
0.001
0.005
0.108
2.915
0.089
0.049
3.202
0.019
0.073
0.013
0.105
0.005
0.004
neg.
0.009
0.005
0.010
0.044
0.005
neg.
0.113
neg.
0.177
0.175
0.018
0.048
1.551
1.792
0.051
neg.
0.130
0.055
0.090
0.326
5.611
Fuel Rate
Million Metric Tons
Oil equivalent
129.5
1.403
4.436
106.5
384.3
4.0
3.81
633.949
58.75
2.40
5.10
66.25
1.45
5.07
0.027
6.547
17.19
16.07
12.25
1.16
4.173
5.07
0.041
55.954
536.0
0.36
6.55
20.25
89.8
652.96
148.20
0.18
95.0
86.0
5.59
334.97
1750.630
n.a.
neg.
Data not available
Less than 0.001
20
-------
Page 49
CHAPTER V
BASIS FOR COSTING OF POLLUTION CONTROL IN 1980
34. The pollution abatement strategies outlined in Chapters III and IV
and discussed in Annexes VI, VII and VIII were selected after consideration
of ways that pollution control might be accomplished at minimum cost using
methods which are expected to be commercially available by 1980. Where no
presently proven technology was available the most promising method under
development was considered and probable costs were assumed. It must be
borne in mind that many technical problems remain to be worked out (see
Annex XIII and that the costs on these are highly uncertain at this
time.
35. All costs are calculated on 1970 prices.
36. The costs which have been developed are considered reasonable order-
of-magnitude estimates useful for demonstrating the magnitude of the cost to
be expected for control of pollution from combustion. It is impossible to
evaluate the effect of many economic factors which can strongly affect the
ultimate cost of control, e.g., the assumed application of limestone scrub-
bing would require doubling of limestone production within eight years. It
seems certain that prices will escalate. Also, the capital cost estimates
for application of limestone scrubbing are considered very optimistic in
light of latest results from development programs. Many other factors could
be cited to show that the costs as developed will prove to be very low for
the level of control which was assumed.
37. The cost estimated for particulate control is the cost for applica-
tion of control equipment that would be expected if past and current trends
in increased rates of application of control technology continue. The cost
for all new equipment to be installed in the 1960-1980 period is included.
The cost for equipment installed prior to 1960 is excluded even though
their contribution is included for the total amount of particulate collected.
38. Nitrogen oxide emission control is assumed to be achieved princi-
pally through combustion control (see Annex XI). There is additional 20
percent NOg reduction due to flue gas scrubbing for S0£ control as discussed
in Annexes VIII-4 and XIII-5, but no costs are assigned because this benefit
is an integral part of SOX reduction by scrubbing, for which costs are
assigned. The total investment is estimated to be $2.8 x 109 with an
annual operating cost of $580 million.
21
-------
Page 50
39. The sulfur oxide reduction is assumed to come from four techniques:
Hydrotreating heavy fuel oil to an average of 0.87 percent sulfur (the
equivalent of 0.54 percent sulfur coal), opening new low sulfur coal mines
in both the eastern part and the western part of the United States, clean-
ing eastern coal down to 0.7 weight percent sulfur, and using limestone
scrubbing on some coal-burning furnaces to get the total SOX emissions
down to desired levels. The two cases for which costs are developed assume
the reduction of projected 1980 emissions to the 1970 level, and the re-
duction of the 1980 projected emissions to the 1960 level.
40. Capital costs for control to the 1970 level of emissions are esti-
mated to be almost $12.7 x 109, as shown in Table 10. The corresponding
operating costs are shown in Table 12.
41. Capital costs for controlling to the 1960 level of emissions are
estimated to be $13.5 x 10^, as shown in Table 11. The corresponding
operating costs are shown in Table 13.
42. The foregoing tables show that cleaning of heavy fuel oil is a high
cost item compared to scrubbing flue gas stacks. However, it is not
practicable to attempt to substitute one for the other. The heavy oil is
burned in hundreds of thousands of small units. The cost of installing
scrubbers in these would be prohibitive, and the problem of disposing of
the waste sludge would be almost impossible to solve (see Annex XIII).
Furthermore, hydrptreating is commercially available, and limestone scrub-
bing is in the development status.
43. These tables assume the logical course of events where regulations
imposed to reduce pollutants will cause the most workable systems to be
installed first. As the problem continues and as costs rise, other abate-
ment techniques will be developed to lower costs.
44. It should be noted that no attempt was made to estimate the cost
to fuel users for switching to low sulfur coal or gas. Nor was any cost
estimated for items such as additional transportation or the cost of
opening mines included, consequently, the costs estimated according to
O.E.C.D. guidelines should not be taken to represent total national costs.
22
-------
Page 51
TABLE 10
ESTIMATED INVESTMENT AFFECTING COSTS
OF ABATEMENT STRATEGY IN THE UNITED STATES
FOR CONTROL OF 1980 POLLUTANT EMISSIONS TO 1970 LEVEL
Control Investments (a)
Particulate emissions $ 1,330,000,000
NOV emissions
Jx
Power stations 826,000,000
Other industries 1,998,000,000
SOX emissions
Flue gas scrubbing 428,000,000
Fuel oil desulfurization 7,730,000,000
Coal cleaning 420.000.000
Total $12,732,000,000
(a) Costs in 1970 dollars
23
-------
Paee 52
TABLE 11
ESTIMATED INVESTMENT AFFECTING COSTS
OF ABATEMENT STRATEGY IN THE UNITED STATES
FOR CONTROL OF 1980 POLLUTANT EMISSIONS TO 1960 LEVEL
Control Investments (a)
Particulate emissions $ 720,000,000
NOX emissions
Power stations 826,000,000
Other industries 1,998,000,000
SOX emissions
Flue gas scrubbing 1,790,000,000
Fuel oil desulfurizatlon 7,730,000,000
Coal cleaning 420.000.000
Total $13,484,000,000
(a) Costs in 1970 dollars
24
-------
Page 53
TABLE 12
ESTIMATED YEARLY OPERATING COSTS
FOR REDUCING 1980 AIR POLLUTANTS
TO 1970 LEVELS IN THE UNITED STATES
Control Operating Costs (a)
Particulate emissions $ 220,000,000
NOX emissions
Power stations 213,000,000
Other industries 366,000,000
SO emissions
X
Flue gas cleaning 118,000,000
Sludge hauling 72,000,000
Fuel oil desulfurization 1,437,000,000
Coal cleaning 87.000.000
Total $2,813,000,000
(a) Costs in 1970 dollars
25
-------
Page 54
TABLE 13
ESTIMATED YEARLY OPERATING COSTS
FOR REDUCING 1980 AIR POLLUTANTS
TO 1960 LEVELS IN THE UNITED STATES
Control Operating Costs (a)
Particulate emissions $ 118,000,000
NOX emissions
Power stations 213,000,000
Other industries 366,000,000
SO emissions
Flue gas cleaning 396,000,000
Sludge hauling 240,000,000
Fuel oil desulfurization 1,437,000,000
Coal cleaning 87.000.000
Total $2,857,000,000
(a) Costs in 1970 dollars
26
-------
Page 55
ANNEX I
LIST OF PUBLICATIONS AND SOURCE MATERIAL
"REFERRED TO IN THIS REPORT
1. "Minerals Yearbook 1961", Bureau of Mines Publication.
2. "Minerals Yearbook 1968", Bureau of Mines Publication.
3. "Gas Facts 1966", Bureau of Mines Publication.
4. "Statistical Abstracts 1970", Bureau of Mines Publication.
5. "Air Pollutant Emission Factors" (Draft), M. J. McGraw,
August, 1970, U. S. Dept. H.E.W.
6. "Basis for Projected Air Pollution from Combustion of Fossil
Fuels in the United States", J. P. Earhart, June, 1970, U.S.
Dept. H.E.W.
7. "Inventory of and Pollutant Emissions from Intermediate Size
Boilers for 1967, 1975, 1980, 1985 and 1990. Phase I, II, III
Report - Systematic Study of Air Pollution from Fossil-Fuel
Combustion Equipment" by Ehrenfeld, Goldish, Bernstein and Carr,
December, 1970, Waiden Research Corporation.
8. "Evaluation of Process Alternatives to Improve Control of Air
Pollution from Production of Coke" (Contract No. PH 22-68-65).
31 January, 1970, to N.A.P.C.A., U. S. Dept. H.E.W. by Batelle
Memorial Institute.
9. "The Mechanical Desulfurization of Coal - Major Considerations
for S02 Emission Control Vol I" (Preliminary Draft). Contract
No. F 19628-68-C-0365 to N.A.P.C.A. by The Mitre Corporation.
10. "A Systems Analysis Study of the Integrated Iron and Steel In-
dustry" (Contract No. PH 22-68-65). 15 May, 1969, to N.A.P.C.A.
Dept. of H.E.W. by Batelle Memorial Institute.
11. "Systems Study of Nitrogen Oxide Control Methods for Stationary
Sources - Vol. II", Bartok et al, 20 November, 1969, (Contract
No. PH 22-68-55) for N.A.P.C.A. by Esso Research and Engineering Co.
27
-------
Page 56
12. "Availability of Residual Fuel Oil" (Draft) C. J. Royce,
31 December, 1970, (Contract No. CPA 70-68) to Environmental
Protection Agency by M. W. Kellogg Co.
13. "Energy Demand and Supply in United States, Appendix A" (Draft)
by Air Pollution Control Office.
14. "1966 Energy Systems Design Survey" Staff of Power Magazine,
McGraw-Hill Publ. Co.
15. "1967 Energy Systems Design Survey" by Staff of Power Magazine,
McGraw-Hill Publ. Co.
16. "1968 Energy Systems Design Survey" by Staff of Power Magazine,
McGraw-Hill Publ. Co. ,
17. "1969 Energy Systems Design Survey" by Staff of Power Magazine,
McGraw-Hill Publ. Co.
18. "1970 Energy Systems Design Survey" by Staff of Power Magazine,
McGraw-Hill Publ. Co.
19. "Electrical World Directory of Electric Utilities, 79th Edition
1970 - 1971", McGraw-Hill Publishing Co.
20. Gas Turbines in Utility Power Generation. Staff report pp 18-31,
January-February 1971, Gas Turbine International.
21. Gas Turbines for Peaking and Steam Turbine Support, Boyce and
Castley, pp 14-16, January-February 1971, Gas Turbine International.
22. The Year of the Gas Turbine, Staff report pp 29-33, November 1970,
Power Engineering; • . .
23. A. Cantrell "Annual Refining Survey1!, pp 93-124, 22 March, 1971,
Oil and Gas Journal.
24. 1971 Forecast/Review. Staff report pp 109-132, 25 January, 1971,
Oil and Gas Journal.
25. James, D. W., "Coping with NOX: A Growing Problem", pp 41-47,
February, 1971, Electrical World.
28
-------
Page 57
26. Paradis et al "Isomax Desulfurization of Residium and Whole
Crude Oil", February 28 - March 4, 1971, A.I.Ch.E. Preprint,
Houston, Texas.
27. Moritz et al "Esso/Union Fuel Oil Hydrodesulfurization Pro-
cesses", February 28 - March 4, 1971, A.I.Ch.E. Preprint,
Houston, Texas.
28. Mounce et al "H-Oil Desulfurization of Residual Oil",
February 28 - March 4, 1971, A.I.Ch.E. Preprint, Houston, Texas.
29. Schlinger and Slater "Application of the Texaco Synthesis Gas
Generation Process Using High Sulfur Residual Oils as Feedstock".
24 July 1970, E.C.E. Seminar on the Desulphurization of Fuels
and Combustion Gases, Geneva.
30. Van Ginneken "The Desulphurization of Residual Fuel Oils from
Middle East Crude Oils", 2 October, 1970, Preprint E.C.E.
Seminar on the Desulphurization of Fuels and Combustion Gases,
Geneva.
31. Brodsky et al "Removal of Sulphur Oxides from Combustion Gases
by Dry and Wet Methods", 22 October, 1970, Preprint E.C.E.
Seminar on the Desulphurization of Fuels and Combustion Gases,
Geneva.
32. Jonke et al "Anti-Pollution Aspects of Fluidized-Bed Combustion",
5 September, 1970, Preprint E.C.E. Seminar on the Desulphuri-
zation of Fuels and Combustion Gases, Geneva.
33. R. E. Harrington "Control of Sulphur Oxide Emission by Lime-Based
Scrubbing Process", 24 September, 1970, Preprint E.C.E. Seminar
on the Desulphurization of Fuels and Combustion Gases, Geneva.
34. "Survey of Processes and Costs for SOX Control on Steam-Electric
Power Plants" (Draft) N.A.P.C.A., Div. of Process Control
Engineering, August, 1970.
35. Pollack et al "Removal of Sulfur Dioxide and Fly Ash from Coal
Burning Power Plant Flue Gases", 1 September, 1967, A,S.MoE.
Preprint.
29
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36. Minton, J. M. "Dark Cloud on Sulfur's Horizon" pp 25-36,
10 February, 1971, Chemical Week.
37. Van Dyke, L.F. "Nuclear Plants to Hog Big Slice of U. So Energy
Pie" pp 17-20, 1 March, 1971, Oil and Gas Journal.
38. Smith, H. L. "Changing Generation Patterns" pp 47-51, November,
1970, Power Engineering.
39. Sliger and O'Donnell "Economics of Metal Oxide Processes for
Flue Gas Desulphurization", 8 September, 1970, Preprint E.C.E.
Seminar on the Desulphurization of Fuels and Combustion Gases,
Geneva.
40. Editor "Southern California Edison Limits NOX with Firing Modi-
fications, Dispatching Technique", pp 32-35, 1 November, 1970,
Electrical World.
41. Moritz and Weissman "Hydrodesulphurization of Heavy Fuel Oils",
26 August, 1970, Preprint_E.C.E. Seminar on the DeBulphuri-
zation of Fuels and Combustion Gases, Geneva.
42. "An Electrostatic Precipitator System Study", Third Quarterly
Report to N.A.P.C.A., Southern Research Institute, Birmingham,
Alabama, 19 January, 1970.
43. "Handbook of Emissions, Effluents, and Control Practices for
Stationary Particulate Pollution Sources", Report to N.A.P.C.A.,
Midwest Research Institute.
44. "Removal of Particulate Matter from Gaseous Wastes - Electrostatic
Precipltators", 1961, American Petroleum Institute, New York,
New York.
30
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ANNEX II
DESCRIPTION OF FOSSIL FUELS USED IN THE UNITED STATES
1. Data have been assembled to show the rates at which fossil fuels
were consumed in stationary users in the United States in 1960
and 1970 and projections for the expected use of fossil fuels in
1980. The breakdown of these rates has been along the pattern
as set out in "A Report on Air Pollution from Fuel Combustion in
Stationary Sources as a Guideline for National Reporting" for the
O.E.C.D,
2. Six sectors of stationary sources have been established:
1. Power stations
2, Refineries
3. Coke ovens
A. Iron and steel
5. Other industries
6. Domestic and commercial
3. The fossil fuels consumed in these six sectors by O.E.C.D. iden-
tification, are as follows:
1. Natural gas
2. Manufactured gas
3. Blast furnace gas
4. Refinery gas
5. Fuel oils
6. L. P. Gas
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7. Patent fuel
8. Brown coal
9. Hard coal
10. Coke
11. B. K. B.
4. Since the fuel categories in the United States do not exactly fit
the categories suggested by O.E.C.D., some adjustments had to be made.
The following table details the fuels used in this country and the
O.E.C.D. designation to which it compares. For purposes of the 0,E,C.1>.
report, all fuel is reported as metric tons of heavy oil with
41.8 x 1012 Btu per million metric ton.
HEAT VALUE
U. S. FUEL O.E.C.D. EQUIVALENT . U. S. UNITS BTU /UNIT WEIGHT % S
Natural gas Natural gas Standard cu.ft. 1,045
Coke oven gas Manufactured gas Standard cu.ft. 550
Blast furnace Blast furnace gas Standard cu.ft. 95
Natural gas Refinery gas Standard cu.ft. 1,045
Light fuel oil Fuel oil Barrel 5,827,000 0.30
Heavy fuel oil
Coal tar
L. P. G.
Lignite
Bituminous
Coal
Fuel oil or
heavy fuel
Heavy fuel
L. P. G.
Brown Coal
Hard coal
Barrel
Barrel
Gallon
Ton
Ton
6,300,000
6,300,000
95,500
16,600,000
23,600,000
2,60 ayg.
2.60
1.00
2.70 avg.
32
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5. Wood, bark, municipal refuse, process wastes and the like have
not been included among the fuels in this report which deals
only with fossil fuels.
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ANNEX III
DESCRIPTION OF THE INDUSTRY SECTORS
1. Power Stations — Power stations have been assumed for this report
to include fossil-fuel-fired stationary electric generating installations,
including those of public utilities, municipal and government utilities.
It does not include the electric generating facilities which have been in-
cluded as part of industrial and commercial operations associated with
other industry sectors specified by O.E.C.D. guidelines. In addition,
this category does include internal combustion engine and gas turbine
generators which are employed to generate electricity.
2. Coke Ovens - Approximately 90 percent of the coke ovens are an in-
tegrated part of the iron and steel industry in the United States. By
1968 almost 100 percent of the coke was made in slot ovens and most of
those were underfire'd (Reference 2). Because of this relationship, coke
oven gases and blast furnace gases are used when available to supply the
heat for making coke; where such fuels are not available, natural gas is
used.
3. Further, the petroleum industry has become the source of many
chemicals which would otherwise come from coking coal. This has also
contributed to the coking industry being incorporated with iron and steel
leaving only a small quantity of coke to be burned as fuel in boilers.
4. Approximately 36 percent of the coke oven gas is consumed in the
coking ovens, the rest is sold. Only about 9 percent finds its way into
power stations or gas mains for burning by "others". This is essentially
the only manufactured gas used in the United States.
5. Refineries --•• The sector called refineries has been defined to in-
clude the United States oil refineries, oil fields (or wells), gas fields
(or wells),gas cohdensate plants,and gas pipeline transmission. By and
large, these industries run on natural gas with light and heavy oils as
supplemental fuels.
6. A good portion of the fuel is used to generate heat in process
boilers and direct-fired heaters. Additional amounts are burned in internal
combustion engines and gas turbines to generate mechanical or electrical
power.
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7. Significant quantities of fuel are consumed by the refinery pro-
cesses (hydrogen generation and ethylene generation, for example) and
these quantities are separated out since they do not directly contribute
to air pollution.
8. The movement of natural gas from the fields, through the conden-
sate plants and the cross-country pipelines, is powered by the energy
obtained from burning natural gas in internal combustion engines and gas
turbines. This fuel usage is added in with the uses for refineries
proper.
9. Iron and Steel - This sector is taken to be industry which makes
iron and steel from iron ore and scrap steel and includes the integration
of products for sale such as sheets and structural shapes. The fabrica-
tion of these forms into products for resale as finished objects is done
by the sector "other" industries.
10. Fossil fuels are consumed as such in high temperature heating by
direct firing, in building and process heat, in the generation of steam
for heat and electricity. The quantities of coke consumed by ore reduc-
tion in furnaces is not considered fuel combustion for purposes of this
report because the pollutants in the coke, ash and sulfur compounds leave
the plant in the slag, not in the air.
11. Other Industries - Table 14 lists some of the major industries in-
cluded in the "other" sector. The complexity of this category is dis-
cernable by noting that in 1960 only 30 percent of the fuel used by
other industries was accounted for by this table, which shows large volume
gas sales by utilities.
12. The total marketed fuels, such as natural gas and coal, are avail-
able for 1960 and 1970. The fuels used by the individual sectors "power
stations", "refineries", "coke ovens", "iron and steel", and "domestic
and commercial" are also available. By subtracting these from the total
national fuel, the amounts used by "other" was determined. No data
sources are available which permit adding individual uses and coming up
with an accounting for the 70 percent not accounted for in Table 14.
13. After reviewing the list, it was decided to consider that all the
fuels used in the "other" sector were burned for heat value and this basic
use is in boilers and furnaces. While this may be in error, it was deemed
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reasonable since this procedure separated process pollutants from fossil
fuel pollutants.
14. Domestic and Commercial - The use of fuels in this sector is
assumed to be for space and building heat and consumed in furnaces and
boilers. The statistics are essentially government statistics from
the Bureau of Mines yearbooks which* listed the fuels actually sold or
used by this sector.
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TABLE 14
LARGE VOLUME NATURAL GAS UTILITY SALES
TO OTHER INDUSTRY SECTOR
Agriculture, forestry
Other mining
Food and kindred products
Textile, clothing, fabrics
Furniture and wood products
Paper and allied products
Carbon black
Chemicals
Rubber products
Glass products
Clay products
Cement
Stone products
Transportation equipment
Fabricated machinery
Ordnance
Other manufacturing
1960
Cu. Ft.*
10.27 x
42.82
160.70
21.60
22,10
185.0
14.35
497 ,0
16.0
138.40
162.40
162
29
62.25
106.0
13.5
32,4
1,676.69
.5
,4
1965
Cu. Ft.*
109 11.50 x 109
66.90
232.20
41.8
50.0
256.0
40.2
617.0
37.20
177.0
142.1
175.7
65.10
106.40
259.0
20.30
60.50
2,139.90
* Data converted to cubic feet from Therms as reported in "Gas Facts
1966" using natural gas at 1045 Btu per cubic foot.
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Page 66
ANNEX IV
BASIS FOR PREDICTING FUEL CONSUMPTION IN 1980
1. To arrive at a fuel usage breakdown for 1980 from which to cal-
culate the pollutant emissions of SOX, NOX and particulates, it was
necessary to obtain or develop projections to 1980. This was done for
each previously discussed sector of stationary users and a fuel break-
down made along the trends established during the past few years. The
objective was to project what the fuel use would be and to assume no
fuel substitution for abatement.
2. Although it is obvious that SOX and particulate emissions can be
reduced by substitution of a "clean" fuel for a "dirty" one, low sulfur fuel
availability is less than the projected uses by 1980 so that such sub-
stitution is only a theoretical solution. The projections were made
upon the most recent equipment and fuel patterns since it seems reason-
able to suppose that these trends will continue rather than to suppose
that entirely new and different patterns will emerge and become dominant
in the next nine years.
3. 1980 Power Stations - It is projected that in 1980 there will be
3.325 x 1012 kwh of electricity generated (Reference 4). Of this,
2.392 x 1012 kwh will be developed from fossil fuels. The balance will
be supplied by hydroelectric and nuclear power plants (References 6, 27).
4. Fossil fuel for the 2.392 x 1012 kwh will be basically coal, oil
and natural gas with coke oven gas, blast furnace gas, lignite and coke
also used in minor amounts. Coke and lignite projections were arrived at
by assuming the growth rates of each would be the same as in the past
five years. Coke oven gas and blast furnace gas were assumed to be that
left over from the steel and coke oven uses. Natural gas usage is assumed
to have a growth of about 4.2 percent per year. Oil projections were cal-
culated at 8.8 percent per year or about one-half those of References 13 and 39,
5. All of these fuels were converted to kwh equivalents and subtracted
from the projected electricity needs and the balance assumed to be sup-
plied by coal. As a cross-correlation all other uses of gas were added
and their sum subtracted from the total natural gas projected to be avail-
able in 1980. Since increased gas supplies will come as a result of much
38
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higher prices, it is assumed that this fuel will be less attractive to the
utility industry and that long-term coal supplies will fill the gap of
needed fuel. Furthermore, natural gas is a nonpolluting fuel from the
standpoint of SOX and participate emissions and the cost of add-on abate-
ment steps will not be practicable for the small and intermediate
stationary users whereas a higher price for the clean fuel might be.
High sulfur high ash will be lower cost and therefore used by large con-
sumers who can justify add-on abatement devices.
6. This rationale for projecting fuels for the power stations depends
upon the competition from the "other" industries sector and the "domestic
and commercial" users for fuel. They have been and will probably continue
to be larger fuel users than the utility sector.
7. 1980 Oil Refineries - The production of oil and gas has been pro-
jected separately (References 23, 24), and this projection was used to
calculate the use of fuel to refine oil and natural gas for markets on
a unit consumption basis. The unit consumptions of 1970 have been as-
sumed to be valid for 1980. The important fuels are natural gas, light
fuel oil and residual fuel oil with the others of minimal significance.
8. Natural gas is a regulated fuel in the United States. However,
as the price is allowed to rise the incentives to drill more wells will
make more available. Therefore, we have assumed a growth at the same
annual rate that this industry has experienced in the last ten years.
It makes little difference whether the gas is imported or supplied from
fields in the United States. The fuel used to refine and distribute the
products will go up in proportion to the total gas.
9. 1980 Coke Ovens - The production of coke and its by-products is
closely tied to the production of steel. Predictions have been made for
1980 (Reference 8) and these were used to calculate the consumptions of
coal and natural gas. The utilization of oven gas and blast furnace gas
in 1970 was assumed to hold for 1980. This applied to the amount of coke
oven gas that was sent into other users as well.
10. 1980 "Other" - From the data of Table 4 a growth rate of 4.90 per-
cent per year is developed. From Tables 1 and 3 a growth rate of 3.92
percent is calculated. Since the nature of the "other" sector is so
varied it is difficult to accurately determine its growth rate. For the
sake of this study a rate of approximately 4.0 percent per year was used.
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11. It is worth noting the large amounts of fuels consumed by "other".
Small percentage influences on this sector could greatly offset the
national total.
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Page 69
ANNEX V
FACTORS FOR CALCULATING EMISSION RATES OF POLLUTANTS
1. An emission factor Is the quantity of a particular pollutant
emitted from a certain process, such as combustion or industrial pro-
duction, for a given quantity of fuel or production, e.g., pounds of
S02 per ton of coal burned. For this report a deliberate effort has
been made to isolate the fuel pollutants from any process emanating
pollutants. Consequently, any practicable substitution of fuels could
be made freely. It is recognized in some cases the process pollutants
are much greater than those from the fossil fuel but these are outside
the scope of this report.
2. Once an emission factor has been determined for a given process,
the total quantity of pollutant emitted from processes of the same type
over a certain time period can be readily computed by multiplying this
factor by the units of fuel burned or production during the period.
3. The latest available data on emission factors is contained in
Reference 5. Most of the required emission factors for S02, NO2 and
particulates were taken from this book with the following exceptions:
Coke oven gas, S02 - Reference 8.
Coke oven gas, N02 and particulates, used same factors as for
natural gas.
Blast furnace gas, S02, assumed negligible.
Blast furnace gas, N02 and particulates, assumed same as for
natural gas.
Refineries, N02 - Reference 11.
4. Reference 5 cited above includes accuracy ratings for the emission
factors on each type of fuel. These consist of a letter designation A,
B, C, D, or E, with the following definitions:
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A - Excellent, based on field measurement of a large number of
sources.
B - Above average, based on a limited amount of field measure-
ments .
C - Average.
D - Below average.
E - Poor.
These rating designations, where given, are included in the tables
of emission factors as a letter following the fuel type.
5. It must be remembered that emission factors are averages and can
vary widely for particular installations, depending on type, size, opera-
ting conditions, etc. For instance, the NC>2 emission from the combustion
of coal is believed to be a function of temperature and excess air, af-
fecting the amount of nitrogen oxidized to nitric oxide. However, tests
have indicated (Reference 32) that a good deal of the NO2 is formed from
nitrogen compounds in the coal. 'This could have an effect of undetermined
magnitude on the control of N02 from coal combustion.
6. The emission factors for each type of fuel of interest are listed
in Tables 15, 16, 17, and 18.
7. One fuel that has received special treatment is refinery fuel.
This fuel is primarily natural gas with varying contents of hydrogen
sulfide and ammonia. Due to the wide range of content, it was treated
as natural gas, although this is known to be in error.
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TABLE 15
EMISSION FACTORS. POWER STATIONS
SO,
NOr
Particulates
NATURAL GAS (B)
BOILERS
GAS TURBINES
COKE OVEN GAS
FUEL OIL (A)
RESIDUAL OIL (A)
BROWN COAL
HARD COAL (A)
COKE
.6///Million Ft.3
.6///Million Ft.3
Equiv. to 1.6% S
Coal on Btu Basis
157 x % S ///1000
Gal.
157 x % S if/1000
Gal.
Same as Hard Coal
38 x % S ///Ton
Sane as Hard Coal
390///Million Ft.3
200//.Million Ft.3
Same as Natural
Gas on Btu Basis
105///1000 Gal.
105///1000 Gal.
Same as Hard Coal
20///Ton
Same as Hard Coal
15///Million Ft.?.
15///Million Ft.
Same as Natural
Gas
8///1000 Gal.
8///1000 Gal.
Same as Hard Coal
16 x % Ash ///Ton
Same as Hard Coal
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TABLE 16
EMISSION FACTORS. INDUSTRIAL BOILERS
NATURAL GAS (B)
COKE OVEN GAS
BLAST FURN. GAS
LPG (C)
FUEL OIL (A)
RESIDUAL OIL
(A)
HARD COAL (B)
so2
.61/MLllion Ft.3
Equlv. to 1*6% S
Coal on Btu Basis
NIL
.3 x Gr. of S per 100 Ft.3
1000 Gal.
142 x % S #/1000 Gal.
157 x % S #71000 Gal.
38 x % S #/1000 Ton
N02
214#/Million Ft.3
Same as Natural
Gas on Btu Basis
Same as Natural
Gas on Btu Basis
40///1000 Gal.
720/1000 Gal.
72///1000 Gal.
20#/Ton
Particulates
18#/Million Ft»3
Same as Natural
Gas
Same as Natural
Gas
6///1000 Gal.
15-23///1000 Gal.
15-23///1000 Gal.
13 x % Ash #/Ton
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TABLE 17
EMISSION FACTORS. DOMESTIC AND COMMERCIAL
NATURAL GAS (B)
COKE OVEN GAS
LPG (C)
FUEL OIL (A)
RESIDUAL OIL
(A)
HARD COAL (A)
so2
.6#/Million Ft.3
Equlv. to 1.6% S Coal
on Btu Basis
.3 x Gr. of S per 100 Ft.3
1000 Gal.
142 x % S #/1000 Gal.
157 x % S #/1000 Gal.
38 x % S #/ Ton
N02
50-100#/Million Ft.3
Same as Natural
Gas on Btu Basis
20-35#/1000 Gal.
12-72///1000 Gal.
12-72#/1000 Gal.
8#/Ton
Farticulates
19#/Million Ft,3
Same as Natural
Gas
6#/1000 Gal.
10#/1000 Gal.
10#/1000 Gal.
20#/Ton
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TABLE 18
EMISSION FACTOR FOR N0<. REFINERIES
Oil and Gas Production
Natural Gas
Heaters and Boilers
Gas Engines
Pipelines
Natural Gas
Gas Engines
Gas Turbines
Refining
Natural Gas
Heaters and Boilers
Gas Engines
Gas Turbines
Oil
Heaters and Boilers
.2#/1000 Ft.3
.77///1000 Ft.3
7c3#/1000 Ft.3
,2#/1000 Ft,3
.21///1000 Ft.3
4.35///1000 Ft.3
.2///1000 Ft,3
2.8#/Barrel
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ANNEX VI
FUEL CLEANING
1. Fuel cleaning for 1980 in the United States is restricted to
hydrotreating residual or heavy fuel and deep cleaning of high sulfur
coal to remove primarily sulfur or sulfur compounds.
2. Desulfurization of oil - Current trends in legislation are to
restrict sulfur content of heavy oil to less than 1.0 weight percent
and in some localities to less than 0.5 weight percent (Reference 41).
It is assumed that by 1980 the average of all heavy fuel oil will be
0.87 weight percent, which is equivalent to coal at 0.54 weight per-
cent on a higher heating value (HHV) basis or 0.46 pounds sulfur per
million Btu.
3. Variability of oils and of their sulfur content are wide, and
it is assumed that the low-sulfur heavy fuel oils will be catalyti-
cally hydrogenated in the United States and the resulting product oils
blended into the overall stocks for sale. Although some hydrotreated
oils will probably be imported, the costs, blending stocks, and market
patterns favor domestic production using imported oils.
4. The presence of metals such as nickel and vanadium in hydro-
treated feedstock contributes to short catalyst life by poisoning the
catalyst (Reference 28). Heavy or residual oils are high in coke pre-
cursors which break down in the reactor bed and deposit coke on the
catalyst, resulting in further poisoning. Both of these harmful con-
stituents of oil are greatly reduced by using fractionated oils. The
heavy, nonvolatile, poisonous materials stay with the bottoms oil and
yield oils which may be hydrotreated with greater ease and longer cata-
lyst life.
5. Refining trends in the United States are to produce less residual
or heavy fuel oil per barrel of crude and less heavy fuel oil in total.
To supply the increased demand for heavy fuel oil in 1980, the projection
has been made that a major portion of the oil supply will have to be
imported.
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6. 1971 capacity for hydrorefined oils is 195,800,000 barrels per
year, and most of this consists of light fuel oils. To achieve the
total capacity of 1,173,000,000 barrels per year of heavy oil, hydro-
treating capacity above the light oil production will require an intensive
construction program. Building 150 new hydrotreating plants with a capac-
ity of 31,500 B.P.S.D. appears to be the limit of practicability by 1980.
7. Although light oil hydrotreating is widely practiced in the
United States, the hydrotreating of heavy oils and residuals has not
been widely practiced. To date only three processes have been operated
on a large scale (References 26, 27, 28).
8. A by-product of hydrogen treating is an off-gas stream contain-
ing hydrogen sulfide and ammonia mixed with light ends of hydrogen,
methane and ethane. By alkaline scrubbing, the hydrogen sulfide can be
recovered from this off-gas. Hydrogen sulfide can be converted to sul-
furic acid or to elemental sulfur. It is easier to store and to sell
sulfur, so this is usually done. Ammonia is generally burned in the
refinery gas stream. This is an unknown NOX emission which is of minor
significance.
9. A second by-product of heavy oil desulfurization is middle dis-
tillate or fuel oil. This is of good quality, being low in sulfur and
having good combustion properties.
10. This multiproduct nature of hydrotreating creates problems which
are best handled by having the hydrotreater as part of a refinery com-
plex. Hydrogen is needed in large quantities, and the most economic
source is off-gas from a naphtha reformer which must be integrated into
an oil refinery. The additional problems of disposing of waste gas,
supplying steam, the needs for tankage and quality control, and finally
marketing and distribution, are all common to refinery. However, in
1971 there are only 36 refineries of sufficient size (100,000 B.P.S.D.
or over) to absorb such units (Reference 23).
11. Coal cleaning - Mechanical cleaning of coal involves the separa-
tion of coal from waste products such as shale, pyrite, and roof-slate
by utilizing differences in the physical properties of the materials.
The practice of mechanically cleaning coal has existed for many years but,
until recently, the purpose has been to remove shale, which is the major
impurity. In 1968, approximately 65 percent of the total United States
coal production was mechanically cleaned to remove shale and dust.
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12. The differences in specific gravity between coal and its impuri-
ties form the basis of the conventional coal cleaning processes. The
specific gravity of coal is about 1.3, of shale about 2.5, and of pyrite
about 5.0.
13. The mechanical removal of pyritic sulfur involves crushing the
coal to release the pyrite and then the specific gravity separation of
the pyrite from the coal. In many coal beds, the pyrite particles are
so small and so intimately mixed with the coal that finer crushing is
required than the 3/8 inch to 1-1/2 inch top size used in many conven-
tional coal cleaning plants. As the pyrite particle size becomes smaller,
removal becomes more difficult and costly.
14. The principal types of coal cleaning processes are cyclone separa-
tion, froth flotation, heavy media separation, jigging, launder-type
washers, pneumatic washers, hydraulic tabling, and combinations of these.
15. It is estimated (Reference 9) that 44 x 106 tons of the 1968 coal
production for utility use in the Appalachian coal region of the United
States was cleanable to a 1 percent sulfur content. This is based on
crushing to 3/8 inch sizes. With pulverizing, the cleanable quantity is
increased to 60 x 10*> tons.
16. The estimated reserves (Reference 9) of coal cleanable to 1 percent
sulfur in the Appalachian region are as follows:
Mine Reserves Recoverable Reserves
3/8 inch size 880 x 106 tons 23,000 x 106 tons
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Page 78
ANNEX VII
ADVANCES IN COMBUSTION TECHNOLOGY
1. Power plant emission of nitrogen oxides will become more and more
of a problem in future years. Power plant boilers can produce up to 1000
ppm of NOX in stack gas emissions.
2. Some techniques for boiler firing have been developed, however,
that make reduction to 250 ppm possible today. Further development may
make it possible in the future to limit emissions to 100 ppm or even 50
ppm for oil and gas firing (References 25, 40).
3. It has been established that NO is the only nitrogen-oxygen' com-
pound that can form, be stable, and exist in significant quantities in
the high temperature portions of a utility boiler system (Reference 1).
Present methods, therefore, are aimed at minimizing the amount of NO that
is formed in the boiler furnace.
4. Present methods with their applicability and limitations are out-
lined below:
£. Low Excess Air Combustion. The theory of low excess air com-
bustion predicts a reduction in NOX emissions by limiting the
availability of one reactant, oxygen. Actual operating data
are still limited on this type of operation. Low excess air
operation may be difficult, if not impossible, to apply to
pulverized coal installations.
b_. Burning Equipment Modifications. The principal aim here is to
slow the rate at which fuel and air mix. Thus, more heat is
removed from the gas before combustion is complete. This re-
sults in a lower peak flame temperature of the combustion gases
and a reduction in the amount of NOX that is formed in the
furnace. This method has the following drawbacks which may
limit its application:
(i) Burner turndown is sacrificed.
(ii) Combustion process can become unstable.
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(ill) Furnace rumble or vibration may become a problem.
(iv) Incomplete combustion may result.
£. Lower Combustion Air Inlet Temperature
(i) This results in lower peak flame temperatures of the
combustion gases with the attendant reduction in NOX
formation in the furnace.
(ii) This method is not too good because the reduction in
NOX generation is small and the overall plant thermal
efficiency is reduced.
ji. Two-stage Combustion. In this process, the amount of air in-
troduced into the primary combustion zone with the fuel is
reduced below the theoretical requirement. Then, several feet
above the top row of burners, the final combustion air is in-
troduced into the combustion area, and the combustion process
is completed. This process is effective in that both peak
and average flame temperatures are reduced and thus NOX forma-
tion is reduced (Reference 40). The process also limits the
available oxygen for NOX formation in the.first stage and re-
duces the residence time for NOX formation at peak flame tem-
perature in the second stage.
«s. Flue Gas Recirculation. This process diverts a portion of
flue gas back to the furnace combustion chamber. This has the
effect of decreasing peak flame temperature and diluting the
combustion air and resultant flue gases. NOX emission is re-
duced because the flame temperature is lower, because the con-
centration of oxygen in the combustion gases is reduced, and
because the residence time is reduced due to a higher mass
flow rate.
5. Combination techniques - By using combinations of the above tech-
niques, such as low excess air firing plus flue gas recirculation, or, two-
stage combustion plus flue gas recirculation, it is felt that NOX emissions
can be reduced below 100 ppm and may even approach 50 ppm (Reference 40).
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However, before these low emission levels can be approached, much addi-
tional development work will be required. The control methods discussed
above have been applied with measureable success or appear to have appli-
cation in limiting the NOX formed in the furnaces of oil and gas-fired
boilers. The methods discussed above do not, however, appear to be
generally applicable to coal-fired boilers. Thus new developments are
required so that NOX emissions from coal-fired units can be controlled.
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ANNEX VIII
FLUE GAS CLEANING
1. An alternative to using clean fuel In a boiler or furnace Is to
Install, a stack scrubbing system after the boiler. Several processes
have been advanced for this purpose and a few of them have been carried
through to pilot plant demonstration (Reference 33). For this study we
have concentrated on the one that has the greatest chance of being a
commercial success - limestone Injection and wet scrubbing.
2. Three main problems must be surmounted on this system:
_a. How Is the fly ash to be handled? The United States Govern-
ment-sponsored work now underway will determine if it is
possible to eliminate the electrostatic precipitators and
collect the ash in the scrubber.
b_. How will the scaling due to CaSO^ and its hydrates be over-
come? It has been reported that adding the stone into a
delay tank after absorption helps to reduce this problem.
£. How will the tonnages of waste solids be disposed of? Up to
now there are no known markets for this material (see
Annex XIII).
3. Since this system has four units of commerical size under develop-
ment, it has been decided to use this system in the control strategy.
4. Pulverized limestone can be injected directly into the boiler.
The limestone is calcined and partially reacts with S02 in the boiler.
The partially sulfated lime, fly ash and most of the remaining sulfur
dioxide plus some N02 are washed from the flue gas by contact with a re-
circulated lime slurry. The problem of scale formation and erosion still
requires developmental work.
5. Reaction products, mostly calcium sulfite and sulfate, plus fly
ash buildup in the aqueous slurry and are removed by settling. The
supernatant liquid is returned to the process. The sludge is disposed of
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in a. settling pond or by transporting, after further concentration, to a
landfill site. The treated flue gas is reheated and discharged to the
atmosphere.
6. The limestone can also be added directly to the scrubber circuit
instead of to the boiler, although this needs to be more fully demon-
strated. The scrubbing efficiency is decreased and a greater quantity
of limestone is required, but this method is the one considered in this
report because the heat requirements of calcining calcium carbonate de-
crease the boiler efficiency and cause other problems which would not
be encountered in ah add-on system.
7. From Reference 33, the sludge from all the scrubbing units is
estimated to be 347,000,000 tons per year. From Reference 31, it is
estimated that 292,000,000 tons of sludge per year are produced. Further-
more, the sludge is a complicated mixture of the carbonates, sulfites,
sulfates, nitrites,and nitrates of calcium. The assumption has been made
that the sludge will be moved to some disposal site, but the nature and
definition of this site will .require additional research and development
work.
8. The sulfites and nitrites have an appreciable COD and liquid
which require converting these anions to sulfates and nitrates. This
conversion step has not been included in this report (see Annex XIII).
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ANNEX IX
COSTS OF CLEANING COAL
1. Capital costs for typical coal cleaning plants are given in
Reference 9 as follows:
£. Type - Simple plant, coals being prepared are easily
cleanable and require a minimum of crushing and prepara-
tion.
Size - 500 tons input per hour.
Cost - $3300 per hourly ton of capacity.
b_. Type - Medium to maximum plants. These coals require
crushing to smaller top sizes with maximum effort in
preparation of fine coal sizes to obtain maximum pyrite
separation.
Size - 500 tons per hour.
Cost - $8000 - $14,000 per hourly ton of capacity.
2. In order to provide coal with less than 1 percent sulfur, a
high quality plant such as type b_. will be required with sizes ranging
between 500 and 1400 tons per hour.
3. The yearly requirement of cleaned coal is 118 x 10& tons based
on a heating value of 11,800 Btu per pound. For cleaned coal having a
10 percent increase in heating value and a cleaning plant operating
4000 hours per year at 80 percent yield, the total hourly input is:
118 x 106 x _1_ = 33 500 tons per hour
4000 x 0.8 1.1
Total capital cost would be (33,500 x 14,000 » $470,000,000).
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4. This program calls for 30 new coal cleaning plants to be built in
the next nine years, with an average capacity of 1000 tons per hour which
seems to be the technically feasible limit.
5. Another source (Reference 34) gives the capital cost for coal
cleaning as $12 per kw. This is based on a 1000 ton per hour plant with
the sulfur content reduced from 2.5 percent to 1 percent, and is inde-
pendent of plant load factor. For a plant heat rate of 10,300 Btu per
kwh, the total electrical output is:
118 x 106 x 2°°?0X3oV00 - 270 x 109 kwh
if = 310 x 106 kw
365 x 24
On this basis, the capital cost would be (310 x 106 x 12 =
$370,000,000).
6. Using the average of the capital costs obtained from the two
sources gives a total capital cost for coal cleaning plants of
$420,000,000.
7. Operating costs for coal cleaning plants are given in Reference 34
as 0.32 mils per kwh.
0.32 x 270 x 109 x • $87,000,000 per year
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ANNEX X
COST OF DESULFURIZING OIL
1. It is assumed that by 1980 there will be 150 new, integrated
hydrogen treating plants constructed in the United States, and each of
these will be associated with a major oil refining complex. Each new
installation will have a crude distillation system, a reforming plant,
a hydrogen purification plant, a hydrogen desulfurization unit, a
hydrogen sulfide recovery and elemental sulfur plant, and a production
fractionator (Reference 26). The combined facilities will produce
low-sulfur, heavy fuel oil at the annual rate of 1,173,000,000 barrels.
2. With anticipated yields of 80 percent heavy oil, each hydrotreating
plant will have a capacity of 31,500 B.P.S.D. at 0.88 load factor. The
units will be heavy oil treaters of the H-Oil or RDS Isomax type, and
sulfur removal is assumed at 75 percent.
3. Hydrogen treating consumes large quantities of hydrogen to satisfy
the simultaneous reactions of desulfurization, saturation, and cleavage.
A good portion of this hydrogen will be supplied by off-gas from a naphtha
reformer. The balance of the hydrogen must be supplied by other off-gas
streams from the associated refinery. At an average consumption of 500
standard cubic feet per barrel, each plant will need 16,000,000 standard
cubic feet per day. An accompanying light oil treating plant will take
an additional 2,000,000 standard cubic feet.
4. By 1980, natural gas will either be too costly or too rare to be
considered as a source of hydrogen. Any additional sources will probably
be from heavy oil steam reforming which will help dispose of high sulfur
stocks.
5. The sulfur removed from the heavy oil feed of each system amounts
to 86 long tons of sulfur each day. The average hydrogen sulfide recovery
and sulfur plant will be sized for 100 long tons per day.
6. The simultaneous products and the need for ancillary facilities are
the reasons the assumption was made that the facilities would be associated
with a complete refinery.
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7. Investment and operating costs for each of the heavy fuel oil
treating units are taken from the recent report by Paradis et al
(Reference 26), and scaled by the 0.6 power to the appropriate size
ratio.
Size
31,500 B.P.S.D.
32,000 B.P.S.D.
71,000 B.P.S.D.
18,000,000 scf/d
18,000 B.P.S.D.
100 Lt/d
22,000 B.P.S.D.
80 Investment Costs
Unit
RDS Isomax
Product distillation
Crude fractionation
Hydrogen plant
Reformer
H2§ and sulfur plants
Light oil hydrotreater
Other
Off-site investment
Contingency
Total investment
9. Operating Costs
Steam ($1.60/M Ib)
Cooling water ($0.02/M gal)
Power ($0.0175/kwh)
Fuel ($3.00/bbl)
Catalysts and chemicals
Labor
Maintenance
Overhead
Taxes and insurance
Contingency
Total operating fixed costs
Capital depreciation (20 yr str. line)
Total operating cost
Capital Cost
$10,800,000
1,800,000
5,300,000
A,600,000
$22,500,000
24,300,000
4.700.000
$51,500,000
$ 589,000
125,000
745,000
1.765.000
$ 3,224,000
$ 517,000
200,000
990,000
517,000
1,040,000
517.000
$ 3,781,000
$ 7,005,000
$ 2.575.000
$ 9,580,000
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10. To supply 1,173,000,000 barrels per year of low-sulfur heavy
fuel oil will require an additional capital outlay of $7,730,000,000,
and a yearly operating cost of $1,437,000,000.
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ANNEX XI
COSTS OF COMBUSTION CONTROL
1. In order to establish a basis for estimating the cost to control
NOX emissions in 1980, a summary of boiler plant sizes in 1970 was under-
taken to establish the average boiler size in 1970. Of 806 surveyed
coal-fired boilers installed and operating in 1970, the average size was
105 raw. Of A56 surveyed oil or gas-fired boilers installed and operating
in 1970, the average size was 77 raw.
2. For purposes of this cost estimate, we have made the following
assumptions:
a. By 1980, the average size of all boilers, whether coal gas, or
oil-fired, will grow to 120 raw.
b_. By 1980, technology will have advanced to where NOX emission
control can be achieved in coal-fired boilers, using methods
which are applicable to oil and gas-fired units.
It is projected that by 1980 the installed United States fossil-
fueled generating capacity will be approximately 496,000 raw. This will
be divided, according to Bartok, et al, 67.7 percent coal-fired and 32.3
percent oil or gas-fired units (Reference 11). Therefore in 1980, there
will be 336,000 raw of coal-fired capacity and 160,000 raw of oil or gas-
fired capacity.
3. Based upon the above stated average size of 120 raw for all fossil-
fueled boilers in 1980, there will then be a total of 2800 coal-fired and
1330 oil or gas-fired boilers operating in 1980.
4. Using the data of Bartok, et al, regarding costs of installing and
operating combustion modification controls, the total capital expenditure
by 1980 and the operating cost in 1980 can be estimated. Consideration
will be limited to the case of a combination of low excess air firing and
flue gas recirculation.
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The list below summarizes the data taken from Bartok, et al,
concerning the costs (Reference 11).
Combustion Modification Costs
Low Excess Air Plus Flue Gas Recirculation
Plant Size - 120 Mw
Load Factor - 4820 Hours Per Year
Fuel
Coal
Gas
Oil
Fixed Costs Operating
Capital
Equipment
208
183
183
Capital
Charges
29
26
26
Maintenance
Supplies and
Overhead
44
39.6
39.6
Costs
Other
Operating
Costs
-17.6
-8.8
-35.2
Total
Costs
Per
Year
55.4
56.8
30.4
All costs in $1000
Thus the capital investment required to install control equipment
in coal-fired plants will be $208,000 x 2800 plants or $5.82 x 108.
Likewise, the capital required for oil and gas-fired plants will be
$183,000 x 1330 plants or $2.44 x 108. Thus, the total capital cost in-
volved to install control devices for NOx emissions from all fossil-fueled
plants by 1980 is $8.26 x 108.
5. The annual operating costs for NOX emission control by combustion
modifications in coal-fired plants operating an equivalent of 4820 hours
per year is $55,400 x 2800 plants or $1.55 x 108. Similarly, taking the
average from the table, the annual operating costs in oil or gas-fired
units will be $43,600 x 1330 plants or $5.8 x 107-
6. Thus, annual operating costs to control NOX emissions from fossil-
fueled generating plants in 1980 will be $2.13 x 108.
7.
Costs for controlling NOX emissions from industrial boilers are
given in Reference 11 as follows:
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Size of Boiler
Lb/hr of Steam
a..
b.
£.
d.
27,700
144,500
36,100
187,500
Fuel
Gas or Oil
Gas or Oil
Coal
Coal
Capital Operating Cost
Cost Per Hour
$11,000
$106,500
$17,200
$140,500
$2,600
$16,800
$3,840
$22,480
The unit costs based on the above, in dollars per pound of steam
per hour, are:
Unit Capital Unit Operating
Cost Cost
Gas or oil
a. $0.40 $0.094
b^ $0.74 $0.116
Average $0.57 $0.105
Coal
£. $0.48 $0.106
d. $0.75 $0.120
Average $0.62 $0.113
8. The basis for determining the total steam capacity of industrial
boilers is:
Steam pressure 150 psig
Feed water temperature 200F
Boiler efficiency ' 75 percent
Heat input percent - H96-168 . 1370 Btu per pound of steam
• 75
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9. The total steam output is calculated as follows:
Fuel usage in metric tons of oil equivalent:
Gas and Oil 555 x 106
Coal 90 x 106
Steam production:
Gas and Oil 555 * 41'9 * 1()6 = 17.0 x Ifl" Ib/yr
Coal 90 x 10 x 41.9 x 10 D 2.75 x 1Q12 lb/
1370
The total hourly rate, using a 65 percent load factor is:
Gas and Oil 17.0 x 1012 . 2.98 x 109 Ib/hr
8800 x .65
10. The costs for NOX control on industrial boilers are:
Capital Cost:
Gas and Oil 2.98 x 109 x .57 = $1700 x 106
Coal .48 x 109 x .62 - $298 * 10f|
$1998 x 10°
Operating Cost:
Gas and Oil 2.98 x 109 x .105 - $312 x 106
.43 x 10' x .113
11. The total costs for NOX control on power stations and industrial
boilers are:
Capital Cost = $2,824,000,000
Operating Cost • $579,000,000
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ANNEX XII
COSTS OF FLUE GAS CLEANING
1. The cost of limestone scrubbing depends on a number of factors,
such as sulfur content of the coal, cost of limestone, degree of grinding,
power plant size and location, and excess limestone used.
2.
The following cost data were obtained from Reference 33:
Basic plant - 200 raw power plant, existing, 3.5 percent S in coal,
limestone injection and scrubbing, limestone cost $2.05 per ton, reheat
to 240F, 95 percent S0£ removal, 99.5 percent dust removal nonrecycle of
sluice water.
Capital cost - $13.05 per kw of capacity.
Operating cost - 0.49 mils per kwh.
3. For differences from the basic plant, the costs are given as
follows:
Capital
Difference from Cost
Basic Plant $/kw
2 percent S 11.70
5 percent S 14.30
Limestone @ $l/ton
Limestone @ $4/ton
200F reheat 10.52
170F reheat 9.47
Sluice water recycled
Addition of limestone
to scrubber circuit 13.80
500 raw plant 10.85
1000 raw plant 8.21
1000 mw plant with
addition of limestone
to scrubber circuit 8.82
1000 mw, new, electrostatic
precipitator eliminated 6.32
Operating
Costs
Mils/kwh
0.39
0.59
0.44
0.59
0.42
0.40
0.50
0.53
0.41
0.34
0.37
0.29
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4. For the purposes of this estimate, the conditions for the basic
plant are assumed same as paragraph 2 above, except for the size of in-
stallations on new power plants which is assumed to be 300 mw capacity.
5. For control to 1970 level assume scrubbers only on new power
plants with an average size of 300 mw. All other conditions are the
same as for the basic plant.
Capital Cost Operating Cost
$/kw Mils/kwh
200 mw existing 13.05 0.49
1000 mw existing 8.21 0.34
1000 mw new 6.32 0.29
For 200 mw new:
Capital cost » 13.05 x |^|r- " $10.00/kw
o .21
2Q
Operating cost = .49 x -^ = .42 mils/kwh
For 300 mw new:
Capital cost - 10.00- I (l'0.0-6.32) = $9.50/kw
8 i
Operating cost = .42- 1. (.42-.29) = 0.40/mils/kwh
8
Coal usage = 128 x 106 tons (approximately 20 percent of 1980 coal-
fired plants) 128 x 1Q6 * 200° * 11'800 = 294 x 10* kwh
10,300
With 75 percent load factor:
294 * 1Q9 45 x 106 kw
365 x .24 x .75
Capital cost = 45 x 10& x 9.50 - $428,000,000
Operating cost = 294 x 109 x .40 = $118,000,000/yr
1000
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6. For control to 1960 level assumptions: 40 percent of the
scrubbers on new power plants and 60 percent on existing power plants.
An average size of 300 raw is used for the new power plants and 200 raw
for the existing power plants.
Capital Cost Operating Cost
$/kw Mils/kwh
300 mw, new 9.50 0.40
200 mw, existing 13.05 0.49
Average capital cost - .4 x 9.50 + .6 x 13.05 - $11.60/kw
Average operating cost - .4 x .40 + .6 x .49 - 0.45 mils/kwh
Coal usage - 383 x 106 tons (approximately 60 percent of 1980
coal-fired power plants) :
383 x 106 x 2000 x 11.800 0 880 109 kwh
10,300
With 65 percent load factor:
880 x 1Q _ 0 154 x 106 kw
365 x 24 x .65
Capital cost - 154 x 106 x 11.6 - $1,790,000,000
Operating cost - 880 x 109 x .45 - $396, 000, 000 /yr
1000
7. The prices assumed for limestone are conservative. The impact of
a new market for 66,000,000 tons of limestone in the next nine years
cannot be determined.
8. The movement of sludge (see Annex VIII- 7) will add an additional
$240,000,000 per year if it is hauled an average of 50 miles at a cost
of $0.016 per ton mile (Reference 13).
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ANNEX XIII
WASTE DISPOSAL
1. Disposing of the waste or by-products which are created by re-
ducing air pollution from burning fossil fuels will present serious
problems.
2. A major part of this report is directed at reducing the amount
of SOX in the air. While it is possible to set up a plan (see Chapter
III) to lower 1980 SOX emissions to the 1960 level, the result will be
37,000,000 tons of SOX per year or 16,600,000 long tons of sulfur not
put into the air (see Tables 12 and 14). Of this reduction, 3,700,000
long tons of sulfur will be left in the ground in coal or left on the
ground as tailings from the coal cleaning operations. 11,100,000 long
tons will be scrubbed out of the flue gases and combined with limestone
to produce gypsum and 3,000,000 long tons will be removed from heavy
fuel oil and vill be available for sale. The elemental sulfur market
in the United States in 1980 is expected to be 14,000,000 to 15,000,000
long tons (Reference 36). Because other potential sources of sulfur,
e.g., smelters and sour gas are expected to grow at a high rate, a cost
estimate which assumes a substantial credit for sulfur sales seems un-
realistic except in unusual circumstances.
3. The relative costs and the state of the art indicates that it is
more likely the sulfur from oil will get to the market before sulfur
from flue gas (References 30, 39). Thus it would appear that throw-
away processes will be favored unless use of sludge removal or other
economic factors to make them economically unreasonable.
4. The sludge containing fly ash, unreacted calcium carbonate, pre-
cipitated calcium sulfite and calcium sulfate, and a lot of water containing
calcium nitrite and calcium nitrate in solution, must be disposed of. For
scrubbing 570,000,000 tons per year of coal, sludge will be formed at the
rate of 300,000,000 tons per year. (60 percent solids, 40 percent water.,)
I
5. Scrubbing 25,000,000 tons of SOX out of flue gases is calculated
to scrub out an accompanying NOX and to form 3,000,000 tons of calcium
nitrite and calcium nitrate. The disposal of this very soluble salt is a
major problem of some magnitude if it is to be kept out of streams, ponds
and rivers.
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6. Twenty-three million tons of refuse, trash, iron sulfides, and
the like, would result from the preparation of 90,000,000 tons of deep
cleaned coal. The techniques for handling the process water and rain-
water runoff from such a quantity of waste cannot be overlooked.
7. Natural gas has been assumed to be a clean fuel. As it comes
from the wells in the fields it contains varying quantities of hydrogen
sulfide. This hydrogen sulfide must be removed, and disposed of, because
of its toxicity. Historically, much of it has been burned to SOx from
small, lean sources. When sources were rich enough, the hydrogen sulfide
was converted to sulfur for sale. By 1980, it must be assumed that all
hydrogen sulfide is converted to sulfur, if pollution abatement is to be
a reality. The question arises, what are Canada and Venezuela to do with
their sour gas? By 1980, Canada will produce 21,000,000 long tons of
sulfur through their gas fields alone (Reference 36).
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APPENDIX I
i
THE U. S, STRATEGY AND SOX ABATEMENT
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THE U. S. STRATEGY AND SOX ABATEMENT
The Uo S. control strategy synthesized for the purpose of the O.E.C.D.
study is presented on pages 15 and 18 of the U. S. National report. The
1980 situation is presented in Table 7 for the no control case and in
Table 8 for the case where the stated strategy is employedo Comparison of
the data in these tables for SOX emissions show the desired reduction is
accomplished by changes impressed on the practices in using heavy fuel oil
and hard coal, with the great bulk in the reduction owing to the changes
in the hard coal category.
The method used for arriving at the 1980 fuel requirements is
described in Annex IV of the U. S. National report. During this phase of
the report preparation, it was necessary to make certain assumptions con-
cerning the availability of fuels to the respective sectors. Basically the
large amount of coal is allocated to the electric power industry on the
basis of the amount of kwh equivalents required to furnish the projected
electricity needs not covered by other fuel sources. Because of the cost
premium, natural gas and heavy fuel oil supplies were allocated to satisfy
all other sector demands before power stations. It is felt that the large
power station will have a cost advantage in applying fuel gas cleaning
systems over paying a fuel premium.,
SOy Emissions Table*
(1) 1980 (2) 1980 (3)
1970 Actual No Control Cont. 1970
Resid Coal Resid Coal Resid
Power Stations 2=40 14.69 5.50 31.75 1.85
Other Industry 0.87 6.68 1.04 7.99 0.35
Total for these
Sectors 24.64 46.08 25.23
Grand Total 29.53 51.80 28.39
*SOX emissions are expressed as millions of metric tons. (These data are
from The U. S. National report: (1) Table 5, (2) Table 8, and (3) Table 9).
Although the data do not permit an exact calculation of all sulfur
removed, those presented for the two sectors of power plants and other
industry satisfy the large percentage of sulfur units.
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Consumption of hard coal and heavy fuel oil (resid) for these sectors is
given in Table 4 and 6 of the U. S. National report. These numbers yield the
amounts of SOX emissions given above when converted with the appropriate emis-
sion factorso Note that the resid assumed available is 2.6 percent sulfur and
is desulfurized to 0<.87 percent as per the stated strategy.
The tables in the U, S. National report give the fuel requirements and
projected emissions for all fuels and source categories. The projected total
SOX emissions for the year 1980:
51.80 MMT without control
28.38 MMT with application of stated control strategy
23.42 MMT reduction in SOg emissions required in 1980 to control
to 1970 level
Since the calculation of- the total situation is very complex and the
bulk of the SOX emissions can be seen to occur from the combustion of hard
coal in the public power sector, a detailed analysis of this combination of
fuel and sector only will be presented for the sake of brevity.
The assumptions applied in the formulation of the strategy pertinent to
using hard coal in public power stations led to the following structure:
(a) Concentration of industrial'activity supplied by coal is much more
heavy in the eastern than western U. S. Therefore all demands for
low sulfur coal will be supplied by natural low sulfur eastern coal
or mechanically deep cleaned high sulfur eastern coal. Since
cleaned coal provides about a 30 percent ash reduction, this portion
will be allocated to industrial sectors.
(b) The portion of natural low sulfur eastern coal not allocated to
industry will be used in power stations.
(c) All western coal is used in power stations.
(d) The remaining power plant capacity is left with only high sulfur
eastern coal. A sufficient capacity of this remainder is required
to implement flue gas cleaning to accomplish the desired reduction;
the remaining capacity is uncontrolled.
The total hard coal required to meet all energy demands in 1980 is .....
mst = million short tons ..................... 872.5 mst
(Table 6, page 16). Of this amount, power stations require. . . . 682.0 mst
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The strategy calls for implementation of steps to accomplish the desired
reduction of sulfur emissions for hard coal burning by applying technology
which is judged most feasible within the time constraints and degree of
development.
Use low sulfur western coal (1 percent sulfur) to account
for 10 percent of the total coal demand and allocate to
power plants . . , 87.3 mst
Use natural low sulfur eastern coal (0.7 percent sulfur)
to account for 18 percent of the total coal demand ........ 157.0 mst
Deep clean 15 percent of the high sulfur eastern coal to
0.7 percent sulfur, reduce ash, and allocate to all sectors
other than power plants (equals 13.5 percent or approximately
14 percent of all coal) 118.0 mst
Total low sulfur coal available to all sectors other than
power plants 275.0 mst
Total low sulfur coal required by all sectors other than
power plants 190.5 mst
Low sulfur coal available to power stations from natural
low sulfur eastern coal « 84.5 mst
Total low sulfur coal available to power stations from both
eastern and western sources .... 171.8 mst
Total high sulfur coal required to furnish balance of demand
for power stations 510.2 mst
Employ flue gas scrubbing on 127.7 mstons capacity of
2.7 percent sulfur coal reducing by 90 percent 127.7 mst
Remainder of high sulfur coal capacity not controlled ...... 382.5 mst
The sulfur oxide emission situation after control in 1980 is then:
Power Plant
From low sulfur eastern coal
84.5 x 38 x 0.7 x 1/2000 <* 1.13 mst SOX
From low sulfur western coal
87.3 x 38 x 1.0 x 1/2000 = 1.66 mst SOX
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From flue gas cleaning
127.7 x 38 x 0.1 x 2.7 x 1/2000 - 0.66 mst SOX
From high sulfur eastern coal
382.5 x 38 x 2.7 x 1/2000 - 19.65 mst SOX
23.10 mst SOX
Total - 20.96 MMT SOX
The total required reduction in all sectors is 23.4 MMT to control the
1980 situation to the 1970 level (actually this is better than the 1970 case
as estimated). This value of 20.96 MMT of SOX emissions is that presented
in Table 8 of the U. S. National report. Similar calculations for all other
fuel - sector combinations have been performed to give the figures presented
in the U. S. National report, which show that the control of potential 1980
emission to the 1970 levels are possible with the stated strategy.
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Page 102
APPENDIX II
COSTS FOR OIL DESULFURIZATION
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PROCESSES RESEARCH. INC.
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COSTS FOR OIL DESULFURIZATION
In regard to the cost of residual desulfurization, I have examined
several references for information on various RDS processes. From this
data, I have developed the table below.
PROCESS
CHEVRON RDS - ISOMAX
SCALED TO 0.6 POWER
FOR U. S. REPORT
ESSO RES ID FINING
HYDROCARBON RESEARCH
H-OIL
IFF
UOP RCD - ISOMAX
GULF HDS
SIZE
BPSD
50,000
31,500
—
40,000
50,000
40,000
35,000
INVESTMENT $
MILLIONS
16.7
12.6
—
8.4
13.1
9.7
15.0
$ PER BPSD
335
400
200-500
210
262
243
429
As can best be determined from the various references (copies appended
here), these costs account only for these RDS units - the reactor, separators,
and product distillation. No costs are included for the required increase in
the capacities of the hydrogen, sulfur and H£S plant or ancillary equipment.
Recalculating the costs for the U. S. case using these figures and the
assumptions behind them may show greater agreement with those cost figures
presented by other national reports.
From the U. S. National report, Annex X, we have the investment costs
for desulfurization of:
REPORT BASE SITE
RDS - ISOMAX 31,500 BPSD 10.8 10.8
PRODUCT DISTILLATION 1.8 1.8
HYDROGEN PLANT 5.3
H2S & SULFUR PLANT 4.6 _
22.5 12.6
OFFSITE 24.3
CONTINGENCY 4.7
TOTAL INVESTMENT 51.5
$400 bpsd
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.y
PROCESSES RESEARCH. INC.
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Page 104
Then applying the following figures for the total residual oil
desulfurization capacity,
1173 x 106 bbl/yro required of oil
.88 load factor
1335 x 106 bbl/yr. capacity for desulfurization
3.67 x 106 bpsd total capacity
cost range is $200-$500/bpsd for plants from 30K to 50K bpsd
Minimum cost =* $200 x 3.67 x 10 = $7.34 x 108
Maximum cost =» $500 x 3.67 x 1Q6 = $18.35 x 1Q8
These figures represent only the base minimal investment then for the
RDS operation - they do not include the provisions for increased capacities
of the hydrogen plant, l^S and sulfur plants, and other ancillaries nor
factors for off-site investment or contingency.
The O.E.C.D. draft consolidated report given capital costs for resid
desulfurization on page 22 (bis) table 11 ranging from $380 to $500 per
annual ton of sulfur removal capacity for the U. K« and the Netherlands.
This figure for the U. S. case, if recalculated on the basis of the foregoing
discussion, is obtained - $200 to $500 range. This range is calculated as
follows:
Assume the average sulfur content of the resid fuel is at 2.7 percent
sulfur and the resid is desulfurized to a level of 0.87 percent sulfur.
1980 resid demand 1173 x 106 bbl/yr.
1173 x 106 bbl/yro x 42 gal/bbl x 7.92 Ib/gal x ton/2000 Ibs -
195 x 106 tons resid/yr.
5<>3 mst at 2.7 percent sulfur
1.7 mst at 0,87 percent sulfur
Therefore 3.6 million short tons of sulfur are removed from the resid
oil. For the capital cost range previously calculated, i.e., minimum cost =
$7.34 x 108 and maximum cost a $18.35 x 10°, we have as range of from $200
to $510 per ton of sulfur removal capacity.
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PROCESSES RESEARCH. INC.
NEW YORK CINCINNATI CHICAGO
Page 1Q5
I would like to call to your attention, then, that a comparison of
these cost figures to those presented in the U. S. National report for
desulfurization are very much the same when adjusted to this basis, i«e.,
the desulfurization unit, the separators and product distillation unit,
without off-site investment and contingency factors.
Certainly differences arise concerning the inclusion of costs for
components such as the hydrogen and H2S - sulfur plants which are utilized
also by other of the refinery operations. While it is not legitimate to
assign the whole of these costs to the operations involved to remove sulfur
from fuels to achieve control of sulfur oxides, it is likely that a consid-
erable investment in such components will be necessary if the required
quantities of desulfurized resid are to be made available.
The questions which now arise are: What basis is assumed by each
national report in the calculation of the oil desulfurization costs;
what basis should be used?
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NEW YORK CINCINNATI CHICAGO
Page 106
APPENDIX III
ELECTROSTATIC PRECIPITATOR COSTS
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NEW YORK CINCINNATI CHICAGO
Page 107
ELECTROSTATIC PRECIPITATOR COSTS
The following discussion covers the subject of electrostatic
precipitators (ESP) and provides the modified estimates as requested.
From the Southern Research Institute report (copies attached as
Annex IV), we have data which indicate a total installed 1970 ESP capacity
for 358 x 10^ acfm of flue gases from coal combustion. Based on the con-
version factor of 2.0 cfm of flue gas per ton of coal fired per year (for
a 0.55 load factor), we estimate the total ESP power station capacity
requirement for 1980 to be:
554 mst x 2.0 = 1108 x 106 acfm
The ESP capacity required to be added between 1968 and 1980 is then
the difference, i.e.,
1108 x 106 - 358 x 106
or 750 x 106 acfm additional capacity
If we want to include replacement of all units over 30 years old by
1980 (i.e., units having a design efficiency of less than 95 percent) we
must account for an additional 78.5 x 10& acfm capacity, bringing the
new capacity figure to:
838 x 106 acfm
We then must furnish ESP capacity to handle 838 x 10*> acfm or for a
capacity of 419 x 10& tons per year of coal for public power stations.
ESP HISTORY STATUS
Year 1950 1968 1980
Coal burned 91.8 298 554 (power stations)
(mst) 191 (other sectors)
Total gas volume 184 596 1108
106 acfm
Volume equipped
with ESP 78.5 358 1108
106 acfm
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PROCESSES RESEARCH. INC.
NEW YORK CINCINNATI CHICAGO
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The trend data for conversion efficiency shows that about 0.87 Ibs of
coal are required for each kilowatt-hour. Applying this factor and a load
factor of 0.55, a total capacity of 2.2 x 108 KW is calculated. At the
cost basis of $5.00/KW installed, we then have a total cost of 1.1 x 109
for power plants.
The situation is more difficult for costing the industrial units
because we lack detailed data of the nature on-hand for power plants. We
have chosen to apply the cost for ESP units for power plants on the gas
handling basis.
For 191 x 106 tons/yr. of coal fired and a 0.8 load factor, it is
estimated that a total volume rate of 2.9 x 108 acfm of gas is to be
cleaned. Further take the unit size to be 10^ acfm with a resultant unit
cost (from figures in attachment) of $90,000. This analysis yields a total
cost of $257,000,000.
The total costs for all electrostatic precipitator capacity is then
estimated at $1.36 Billion (i.e., $1.36 x 109) for the U. S. case - a
figure not in significant disagreement with that in the U. S. National
report.
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Table 15.5
Fly Ash Precipitator Installations
Pptr
Contract
Year
1923
1926
1927
1928
1929
1930
1931
1932
1933
1934
1935
1936
1937
1938
1939
1940
1941
1942
1943
1944
19-15
1946
1947
1943
1949
1950
1951
1952
1953
1954
1955
1958
1957
1958
1959
1960
1961
I9C2
1963
1964
1965
1966
1967
1068
1969
Grand
Totals
No.
of
Installations
1
2
2
1
4
6
2
1
2
2
2
13
IS
1
8
22
31
9
1
8
13
22
28
22
20
19
28
19 ,
23
9
23
22
26
13
23
17
12
IS
IS
19
33
48
55
46
40
741
No.
of
Pptr«
3
3
11
2
20
10
3
2
4
4
5
23
29
1
17
36
52
29
3
11
17
39
59
40
23
35
61
25
37
IS
36
37
43
19
37
26
16
28
21
27
49
80
117
106
67
1331
(1)
Total
Gas Vol
Millions
acfm
0.80
1.35
3.59
0.22
2.62
1.43
0.46
0.37
0.63
0.52
0.79
3.59
4.71
0.25
3.34
5.42
7.84
3.37
0.96
2.69
2.78
6.12
12.67
9.97
5.33
6. 88
14.12
7.60
9.27
4.48
14.04
26.57
17.40
7.55
5.41
11.09
7.56
17.07
12.54
19.84
27.17
57.24
72.51
58.78
42.93
531.9
Five (5) Yr Periods
No. AvgVol/Yr Pptr
of Total Gas Vol During Period Operation
Installations 10* acfm 10° acfm Year
1925
1928
10 8.58 1.72 1929
1930
1931
1932
1933
13 3.46 0.69 1934
1935
1936
1937
1938
39 12.68 2.54 1939
1940
1941
1942
1943
71 20.28 4.06 1944
. _ . 1945
1946
1947
1943
105 56.87 7.37 1643
1950
1951
1952
1953
98 42.35 8.47 1954
1955
1956
1957
1958
107 1 80.97 16.19 1959
I960
1961
4 1962
1963
76 68.10 13.62 1964
1965
1S36
1967
1008
221 297.61 ,. 51.52 1969
1970
1971
741
Accumul
Gas Vol
With Pptra
10° acfm
0.80
2.15
5.74
5.96
8.58
10.01
10.47
10.84
11.52
12.04
12.83
16.42
21.13
21.38
24. 72
30.14
37.98
41.35
42.31
45.00
47.78
53.90
66.57
76.54
81.87
88.75
102. 87
110.47
119.74
124.22
138.26
164.83
182.23
189.78
205.19
216.28
223.84
240.91 •
253.45
273.29
300.46
357. 70
430.21
488.97
531.90
Coal
Burned
10° tons
per year
35.6
38.0
41.8
40.3
36.1
28.0
28.5
31.4
32.7
40.1
42.9
38.4
44.5
51.5
62.6
66.2
77.3
80.1
74.7
72.2
89.5
99.6
83.9
91.8
105.7
107.1
115.9
118.4
143.8
158
162
-
-
176.2
-
-
211
-
244.8
166.5
274.0
-
-
-
•
(2)
Total Gas
Vol Calculated
From Coal
Burned
10* acfm
53.4
58
62.8
60.5
54.2
42.0
42.8
47.0
49.0
60.0
64.5
57.6
6C.8
77.3
94.0
99.3
116.0
120. 0
112.0
108.3
134.0
149.5
126.0
138.0
159.0
161.0
174.2
178.0
216 *
237.5
244
-
-
265
-
•
J17
-
368
401
412
-
-
-
~
Percent of
Total Vol
with
Pptrs
1.5
3.7
9.1
9.9
15.8
23.8
24.5
23.1
23.5
20.1
19.9
28.5
*i.€
27.7
20. 3
30.4
32.7
34.5
37.8
41.6
35.7
36.1
52.8
55.5
51.5
55.1
59.1
62.1
55.4
52.3
56.7
-
-
71.6
-
-
70.6
-
68.9
68.2
72.9
•
•
-
*
•
"0
o
JO
Q
(1) Includes all fly aih precipttators except rebuilds.
(2) Based on an 80% load factor.
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