UNITED STATES - CANADA
MEMORANDUM OF INTENT
ON
TRANSBOUNDARY AIR POLLUTION
ENGINEERING, COSTS AND EMISSIONS
INTERIM REPORT
FEBRUARY 1981
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This is an Interim Report prepared by a U.S./Canada Work Group in
accordance with the Memorandum of Intent on Transboundary Air Pollution
concluded between Canada and the United States on August 5, 1980.
This is one of a set of four reports which represent an initial
effort to draw together currently available information on transboundary air
pollution, with particular emphasis on acid deposition, and to develop a
consensus on the nature of the problem and the measures available to deal with
it. While these reports contain some information and analyses that should be
considered preliminary in nature, they accurately reflect the current state of
knowledge on the issues considered. Any portion of these reports is subject to
modification and refinement as peer review, further advances in scientific
understanding, or the results of ongoing assessment studies become available.
More complete reports on acid deposition are expected in mid 1981 and
early 1982. Other transboundary air pollution issues will also be included in
these reports.
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January 15, 1981
David G. Hawkins Raymond M. Robinson
Assistant Administrator Assistant Deputy Minister
for Air, Noise & Radiation Environmental Protection
U.S. Environmental Protection Agency Service
Washington, D.C. 20460 Environment Canada
K1A 1C8
Dear Messrs. Hawkins and Robinson:
We are pleased to submit the interim report from Work Group 38 for your
submittal to the Coordinating Committee. I understand that this report will
be reviewed by the Coordinating Committee at its meeting on January 29, 1981.
The interim report is an initial effort by Work Group 3B to fulfill its
terms of reference. The more extensive report to follow in May 1981 is
intended to provide information in support of the negotiations as called for
in the Memorandum of Intent.
With the completion of this report, Work Group 38 is in a good position
to begin activities in Phase II.
Sincerely yours,
Kurt W. Riegel Martin E. Rivers
Associate Deputy Assistant Director General
Administrator Air Pollution Control
Office of Environmental Engineering Directorate
and Technology CRD-681) Environmental Protection
U.S. Environmental Protection Agency Service
Environment Canada
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WORK GROUP 3B
ENGINEERING, COSTS AND EMISSIONS
INTERIM REPORT
JANUARY 15, 1981
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PREFACE
The Emissions, Costs, and Engineering Assessment Subgroup (Work Group 3B)
was established under the MEMORANDUM OF INTENT in order to provide support to the
development of the control element of the bilateral agreement on transboundary air
pollution. Work Group 3B is also charged with preparing proposed work under the Applied
Research and Development element of the agreement.
The purpose of this Phase I report is to respond to the Terms of Reference
identified in the MEMORANDUM OF INTENT and to the tasks set forth in the group's
approved work plan. During Phase I, Work Group 3B has devoted its efforts to:
a. Preparing a work plan for Phase I and Phase II
b. Identifying control technologies and associated costs for source categories of major
concern
c. Reviewing historical emission trends
d. Determining current emission rates from the source regions
e. Projecting future emission rates under varying control and economic conditions
f. Preparing the Phase I report
During Phase II, the group will:
a. Prepare a work plan for Phase III .
b. Conduct a series of iterative analyses in order to evaluate different pollution
control scenarios
c. Prepare the Phase II report
Due to time and resource constraints, it has not been possible to treat all
emissions and source categories equally. Although some source categories have been
covered only lightly, we have attempted to treat intensively those source categories
thought to be major contributors to transboundary air pollution problems. Some work
remains in order to reconcile our results with those of the other work groups, especially
Work Group 2. During Phase I, the emphasis has been placed on compiling as much
information as possible on the major precursors of acid precipitation (i.e., sulphur and
nitrogen oxides) and the primary sources of these emissions. A major effort will be
undertaken during Phase II to upgrade the information presented in this document and to
analyze various emission control strategies for the sources of acid deposition.
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11
The first chapter of this report summarizes the major findings and conclusions
in terms of the major analytical elements: emissions, technology for control, and costs.
The remainder of the report is structured to closely follow the Terms of Reference for
Work Group 3B. Chapter B presents data and information on emission control
technologies and associated costs for all major source categories. Chapter C analyzes the
historical emission trends for the United States and Canada while Chapter D presents data
on current emissions for the two countries. Chapter E projects U.S. and Canadian
emissions for various source categories through the year 2000. The final chapter of this
report lays out the future course of action for Work Group 3B and suggests some future
R&D needs.
This document is only the Phase I report and is expected to undergo substantial
revision in succeeding phases. In its current form, the report is a good "strawman" for the
Work Group's future efforts, and ultimately in its final form (at the conclusion of Phase II)
will provide the technical basis for negotiations between the United States and Canada for
an agreement covering the major aspects of transboundary air pollution.
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Ill
TABLE OF CONTENTS
Page
PREFACE i
LIST OF TABLES vi
LIST OF FIGURES ix
A. SUMMARY OF FINDINGS AND CONCLUSIONS 1
A.I INTRODUCTION 1
A.2 THERMAL POWER - CONTROL TECHNOLOGY SUMMARY 2
A.3 NON-FERROUS SMELTING SUMMARY 7
A.4 MOBILE SOURCES SUMMARY 8
A.5 INDUSTRIAL, COMMERICAL, RESIDENTIAL FUEL
COMBUSTION 9
A.6 EMISSIONS SUMMARY 12
B. SOURCE SECTORS OF CONCERN 17
B.I THERMAL POWER 18
B.I.I Description 18
B.I.2 Control Technologies 25
B.I.2.1 Technologies In use 37
B.I.2.2 Available Technologies 38
B.I.2.3 Emerging Technologies 38
B.I.3 Alternative Production Processes 39
B.2 NON-FERROUS SMELTERS 40
B.2.1 Description of the Non-Ferrous Smelting Sector 40
B.2.2 Control Technology 40
B.2.2.1 Control Technology In Use 46
B.2.2.2 Control Technology Available 50
B.2.2.3 Emerging Control Technology 52
B.2.3 Alternative Production Processes 54
B.2.4 Preliminary Cost of Control for Eastern Canadian Smelters 55
B.3 MOBILE SOURCES 57
B.3.1 Description of Sector 57
B.3.2 Control Technologies 57
B.3.2.1 United States - New Vehicles 57
B.3.2.1.1 Light Duty Vehicles 57
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IV
Page
B.3.2.1.2 Light Duty Trucks 59
B.3.2.1.3 Heavy Duty Trucks 59
B.3.2.1.4 Cost of U.S. FMVCP 59
B.3.2.2 United States - In Use Vehicles 60
B.3.2.2.1 Inspection and Maintenance 60
B.3.2.2.2 Transportation Control Measures 61
B.3.2.3 Canada - New Vehicles 62
B.3.2.4 Canada - In Use Vehicles 62
B.4 PETROLEUM REFINING 63
B.4.1 Canadian Petroleum Refineries 63
B.4.1.1 Production Processes 63
B.4.1.2 Separation 63
B.4.1.3 Conversion 63
B.4.1.4 Treating 63
B.4.1.5 Blending 63
B.4.1.6 Emissions 63
B.4.2 United States Petroleum Refining 64
B.5 INDUSTRIAL, RESIDENTIAL AND COMMERCIAL
FUEL COMBUSTION 65
B.5.1 Industrial Combustion Units 65
B.5.2 NOX and SO2 Control Technologies Available 66
B.5.3 Residential and Commercial Combustion Units 66
B.6 INCINERATORS 70
B.7 PULP AND PAPER INDUSTRY 72
B.7.1 United States Pulp and Paper Industry 72
B.7.2 Canadian Pulp and Paper Industry 72
C HISTORICAL EMISSION TRENDS 73
C.I INTRODUCTION 73
C.2 IN THE UNITED STATES 74
C.3 IN CANADA 83
D. PRESENT EMISSION RATES 89
D.I IN THE UNITED STATES 89
D.2 IN CANADA 103
E. PROJECTED EMISSIONS 112
E.I IN THE UNITED STATES 112
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Page
E.2 IN CANADA 128
E.2.1 Projected Emissions-Thermal Power 128
E.2.2 Projected Emissions from Copper-Nickel Smelter
Complexes 13*
E.2.3 Projected Emissions - Mobile Sources 1*2
F. CONSTRAINTS ON AND BOUNDARIES OF
ANALYSIS 1*3
G. RECOMMENDATIONS FOR FUTURE APPLIED
R & D ACTIVITIES 1**
APPENDIX 1 1*7
APPENDIX 2 153
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VI
LIST OF TABLES
Page
A.2.1 CONTROL TECHNOLOGIES FOR SO2 REDUCTION *
A.6.1 CURRENT NATIONWIDE EMISSIONS OF SOX AND NOX
IN THE U.S. AND CANADA 1*
A.6.2 PROJECTED EMISSIONS OF SOX AND NOX IN
CANADA « 15
A.6.3 SOX PROJECTED EMISSIONS USING COMBINED
MODELS (UNITED STATES) 16
A.6.4 NOX PROJECTED EMISSIONS USING COMBINED
MODELS (UNITED STATES) 16
B.I.I COMPARISON OF GENERATING CAPACITY MIX,
BY PROVINCE, 1977 and 1989 (PER CENT) 19
B.1.2 COMPARISON OF GENERATION MIX, BY PROVINCE,
1977 and 1989 (PER CENT) 20
B.I.3 U.S. ELECTRIC UTILITY GENERATION BY ENERGY
SOURCE (1979) 21
B.1.4 SUMMARY OF CAPACITY AND GENERATION FOR
FOSSIL-FUEL-FIRED PLANTS BY STATE AND REGION, 1978 23
B.1.5 TYPICAL UNCONTROLLED EMISSIONS OF POLLUTANTS 26
B.2.1 GENERAL DESCRIPTION OF NON-FERROUS SMELTER
SECTOR - PRESENT CONDITIONS 41
B.2.2 GENERAL DESCRIPTION OF NON-FERROUS SMELTER
CONTAMINANT - SO2 42
B.2.3 PRIMARY COPPER SMELTERS, 1979 (UNITED STATES) 44
B.2.4 COST OF FIXING SULPHUR AS SULPHURIC ACID
FROM SMELTER GASES USING SINGLE CATALYSIS
ACID PLANT 47
B.2.5 COST OF RECOVERING LIQUID SULPHUR
DIOXIDE FROM SMELTER GASES 48
B.2.6 COPPER/NICKEL SMELTER SO2 CONTROL SYSTEMS 50
B.2.7 COST OF SULPHUR FIXATION WITH NEUTRALIZATION
AND GYPSUM IMPOUNDING 51
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vu
Page
B.3.1 COST OF COMPONENTS IN A THREE-WAY PLUS
OXIDATION CATALYST SYSTEM 58
B.3.2 TOTAL ANNUAL COST OF THE FMVCP IN 1987 60
C.2.1 SUMMARY OF NATIONWIDE TOTAL EMISSION
ESTIMATES 75
C.2.2 ESTIMATED NATIONWIDE EMISSIONS, 1940 76
C.2.3 SOX EMISSIONS 78
C.2.4 HISTORICAL TRENDS IN SO2 EMISSIONS 79
C.2.5 HISTORICAL TRENDS IN NOX EMISSIONS 80
C.3.1 HISTORICAL EMISSIONS OF SO2 AND
NOX - CANADA 84
C.3.2 HISTORICAL EMISSIONS OF SO2 AND NOX
- EASTERN CANADA 85
D.I.I CURRENT (1978) EMISSIONS OF SO2 AND
NOX - U.S. 91
D.I.2 1978 SO2 AND NOX EMISSIONS BY STATE 92
D.I.3 1977 U.S. EMISSIONS - UTILITIES 93
D.I.4 1977 U.S. EMISSIONS - INDUSTRIAL BOILERS 95
D.1.5 1977 U.S. EMISSIONS - INDUSTRIAL PROCESSES 97
D.1.6 1978 U.S. EMISSIONS - TRANSPORTATION 99
D.1.7 1978 U.S. EMISSIONS - COMMERCIAL/RESIDENTIAL 100
D.1.8 1977 U.S. EMISSIONS - SOLID WASTE DISPOSAL 101
D.2.1 CURRENT (1976-1980) EMISSIONS OF SO2
AND NOX - CANADA 104
D.2.2 CURRENT (1976-1980) EMISSIONS OF SO2
AND NOX - EASTERN CANADA 104
D.2.3 S02 EMISSIONS FROM DEFINED CANADIAN SOURCE
REGIONS - 1976-80 DATA BASE 107
D.2.4 SEASONAL VARIATIONS IN CANADIAN SO2
AND NOX EMISSIONS 107
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viii
Page
D.2.5 SUMMARY OF NATURAL EMISSIONS OF SULPHUR INTO
THE ATMOSPHERE IN CANADA 109
D.2.6 SUMMARY OF NATURAL EMISSIONS OF NITROGEN INTO
THE ATMOSPHERE IN CANADA 110
E.I.I NATIONAL SOX PROJECTED EMISSIONS USING
SEAS MODEL 113
E.1.2 NATIONAL NOX PROJECTED EMISSIONS USING SEAS
MODEL 113
E.I.3 NATIONAL SOX PROJECTED EMISSIONS USING
COMBINED MODELS 11*
E.I.4 NATIONAL NOX PROJECTED EMISSIONS UGING
COMBINED MODELS 11*
E.I.5 ICF SCENARIO RUNS 115
E.1.6 SCENARIO DESCRIPTION FOR TRI ANALYSIS 116
E.I.7 ENERGY CONSUMPTION COMPARISON
DOE/TRI/ICF 118
E.1.8 KEY ASSUMPTIONS 119
E.1.9 1990 FORECASTS FOR COMMON SCENARIOS 120
E.I.10 1990 FORECAST FOR CEUM RUNS 121
E.I.11 1990 FORECAST FOR USM/AIR TEST RUNS 122
E.I.12 USM COAL PRODUCTION ESTIMATES 123
E.I.13 NATIONAL ANNUAL UTILITY COSTS: 1985, 1990, 1995, 2000 12*
.E.2.1 COMPARISON OF GENERATING CAPACITY MIX,
BY PROVINCE, 1977 AND 1989 (PERCENT) 129
E.2.2 COMPARISON OF GENERATION MIX, BY PROVINCE,
1977 AND 1989 (PERCENT) 130
E.2.3 THERMAL POWER - PROJECTED SOX AND NOX EMISSIONS 133
E.2.* 502 EMISSION ESTIMATES BY OPERATION, 1980 135
E.2.5 PROJECTED SO2 EMISSIONS FROM COPPER-
NICKEL SMELTER COMPLEXES, ANNUAL TOTALS AND
5-YEAR AVERAGES, 1980-2000 138
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IX
LIST OF FIGURES
Page
A.5.1 FGD CAPITAL COSTS VERSUS UNIT SIZE 10
A.5.2 FGD ANNUALIZED COSTS VERSUS UNIT SIZE 11
B.2.1 PRIMARY U.S. NON-FERROUS SMELTING AND
REFINING LOCATIONS 43
B.5.1 FGD CAPITAL COSTS VERSUS UNIT SIZE 67
B.5.2 FGD ANNUALIZED COSTS VERSUS UNIT SIZE 68
D.2.1 DEFINED CANADIAN SOURCE REGIONS -
127 km x 127 km GRID 106
E.1.1 NATIONAL UTILITY SULPHUR DIOXIDE EMISSIONS
1980-2000 AS PROJECTED BY USM 125
E.I.2 PERCENTAGE CHANGE FROM BASE CASE NATIONAL
INVESTOR ELECTRICITY PRICES AS PROJECTED BY USM 126
E.2.1 SO2 EMISSION PROJECTIONS, ANNUAL AVERAGES,
1980-2000 136
E.2.2 S02 EMISSIONS FROM COPPER-NICKEL SMELTERS,
ACTUAL AND PROJECTED, FIVE YEAR AVERAGES,
1950-2000 139
E.2.3 PAST AND PROJECTED SO2 EMISSION DECREASES
EXPRESSED AS A PERCENTAGE OF PEAK EMISSIONS
IN 1965-69 (BASED ON SCENARIO II PROJECTION)
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1
A. SUMMARY OF FINDINGS AND CONCLUSIONS
A.1 INTRODUCTION
This is an interim report by Work Group 3B (Emissions, Costs and Engineering
Assessment) as part of the commitment in fulfillment of the requirements of the
MEMORANDUM OF INTENT signed by the United States and Canada on August 5, 1980.
The Terms of Reference and the membership for Work Group 3B can be found in
Appendix 1 of this report.
This report reviews, in detail, the technologies (process and control), costs of
application of controls for the reduction of 5O9 and NO emissions (for both new and
^ J\
retrofit installations; costs for retrofit installations are generally greater than for new
installations), and emissions (historical, present and projected) for the thermal power
industry sector (eastern U.S. and Canada), non-ferrous smelters (eastern Canada) and
mobile sources (U.S. and Canada). These sectors, together with industrial, residential and
commercial fuel combustion, account for the majority of the SO and NO emissions in
yv A
the eastern part of North America, and hence are judged to be the most important sources
in the acid precipitation problem. A more brief review is carried out for petroleum
refining, solid waste incineration and pulp and paper. These sectors are considered to be
of secondary importance to the acid precipitation problem since their emissions of SO
sv
and NO are considerably smaller in magnitude than those of the three primary sectors.
Note that all emissions in Chapter A are in short tons, while emissions in subsequent
chapters are partly in short tons and partly in tonnes (metric).
Included in this report are recommendations for future R&D activities and
conclusions and recommendations concerning the control of SO and NO emissions.
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2
A.2 THERMAL POWER - CONTROL TECHNOLOGY SUMMARY
SO Reduction
Control of SO- emissions has become a complex problem with several options
available and many factors involved in making the choice between them. One of the main
problems is that some of the factors are intangible in nature and are therefore difficult to
quantify.
Sulphur oxide emissions can be reduced by several methods
1) use of naturally occurring low-sulphur fuel
2) removal of the sulphur before combustion
3) reaction with an absorbent during combustion
4) removal of the sulphur after combustion
In rating the alternatives for SO- control, the major consideration is the
degree of control required. Some processes are capable of a very high removal efficiency
but are expensive; others cost much less but are limited to a relatively low level of
removal efficiency.
The following recommendations are made for process choice at different
required levels of emission reduction. It should be noted that these are only approximate
and that site-specific conditions could well change the ranking. The rankings are
judgmental in nature, based on a subjective evaluation of factors such as cost, commercial
viability, absorption efficiency, and process reliability. A more quantitative approach to
ranking does not seem feasible in view of all the uncertainties involved.
Removal efficiency level, % Process listing
Higher than 90% 1. Double alkali
2. Limestone scrubbing with promoters
3. Coal gasification (combined cycle)a
4. Regenerable scrubbing processes
90% 1. Limestone scrubbing with promoters
2. Limestone scrubbing
3. Double alkali
When and if developed.
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50-90% (high-sulphur coal)
50-90% (low-sulphur coal)
Below 50%
1. Limestone scrubbing (with physical
coal cleaning where upper limit on
SO- emission applies)
2. Fluidized-bed combustion3
3. Chemical coal cleaning
i*. Low-sulphur fuel substitution
(not a sulphur removal process)
5. Limestone injected through modified
burner'3
1. Spray drier process
2. Limestone scrubbing
1. Physical coal cleaning
2. Blending with low-sulphur coal
aWhen and if developed.
bUnder development.
Table A.2.1 summarizes the cost data available for sulfur oxide controls on
thermal power plants. Physical coal cleaning costs approximately $15 per ton of coal for
high-sulfur coals (i.e., approximately $0.22 per pound of sulfur removal). (For low-sulfur
coals the price is considerably higher i.e., around $1.88 per pound of sulfur removal).
The cost for flue gas desulphurization (FGD) ranges between $120 - $200 per
kilowatt of installed capacity. Using lime instead of limestone raises the costs. FGD
recovery processes, such as the dual alkali and Wellman-Lord processes, tend to be more
expensive than wet scrubbling. Dry scrubbers cost $120 - $140 per kilowatt of installed
capacity but the technology is still under development and the cost estimates are rising.
Generally, there is a wide range in the costs of FGD systems due to site-specific
variables.
NO Reduction
Several approaches can be used for NO control. Low-nitrogen fuel is one of
these but is not as effective as low-sulphur fuel is for SC>2 because part of the NOX comes
from the combustion air rather than the fuel. Combustion modification, the most cost-
effective method, is used to some degree. If flue gas treatment is required, injection of
ammonia to reduce NO to nitrogen is favoured. Use of a catalyst promotes the reaction
X
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Table A.2.1
CONTROL TECHNOLOGIES FOR SO2 REDUCTION
SYSTEM
Wet F.G.D.
Limestone
Lime
Dual
Alkali
Wellman
Lord
Dry Scrubber
Low-Sulphur
Fuel
Physical
Coal Cleaning
PERFORMANCE
Acceptable
Availability
(90% or >)
Acceptable
Availability
Limited experience
so far.
Limited experience
so far.
Effective up to
25% sulphur removal.
COST
Limestone:
$120-$200/kW
Lime:
~$200/kW
Actual
$80-$2<(2/kW
Actual
$259/kW
$120-$140/kW
including
e.s.p., but
rising
Coal
Cost
dependent
very much
on transport
distance Ic.
charges.
Oil
Adds $5 per
barrel
Can add
up to $15
per ton.
APPLICABILITY
All fuels
All fuels
All fuels
Low sulphur
fuels
Coal
Oil
Used for high
pyritic sulphur
coals.
UNCERTAINTY
Cost is a function
of size, sulphur
content, location,
redundancy of equip-
ment, whether ash
removal included.
Limited experience.
Uncertain market for
by-products.
Performance data
sparse.
Incremental costs,
availability of
supplies.
As above.
Coal variability
and expansion of
existing facilities
WASTE DISPOSAL
Preferably oxidized
to gypsum, otherwise
settling problems
in ponds and land-
fill, unless
chemically fixed.
As above.
Potential water
pollution problem.
Lime systems have
minimal problems,
whereas soda-based
units have potential
water pollution
problems.
No problem.
Water pollution
and solid waste
disposal.
PROBLEMS
Waste disposal
because of volumes.
Utilities sceptical
of costs and relia-
bility.
As above.
High Cost.
Waste disposal
involves large
volumes. Opera-
tional difficulties
with variations in
coal characteristics.
Boiler derating,
effects on
precipitator,
transportation,
logistics.
Energy losses,
maintaining quality
control.
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and is preferred over non-catalytic operation. Various wet scrubbing methods have been
developed but none seems very promising.
The situation for NO is the same as for other pollutants. The selection of
abatement method depends on the degree of control required. A rough ranking is as
follows:
Removal efficiency level, % Process listing
90% or higher 1. Catalytic reduction3 with more than
normal amount of catalyst, preceded
by combustion modifications
50-80% 1. As above, with normal amount of
catalyst
2. Combustion modifications (all types)
followed by non-catalytic reduction
(ammonia injection without catalyst)
3. Combustion modifications alone (for
low part of range so as to minimize
boiler problems)
4. Low-NOx burners
Below 50% 1. Staged combustion
2. Low-NO burners
h
3. Gas recirculation (except for coal )
a Technology has not been proven with respect to coal-fired boilers.
b Used in combination with others if necessary to achieve the required reduction
level.
The capital costs associated with the- use of combustion modification
techniques for the control of NO emissions from thermal power plants are estimated at:
J\
Techniques Capital Cost NO Emission Limit
X
Low Excess Air $0 0.9lb per 106 Btu
Staged Combustion $2-3/kW 0.7 Ib per 10$ Btu
(over-fired air)
Low-NOv Burners $2-$10/kW 0.4-0.5 Ib per 10^ Btu
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The capital cost estimates for NO control vary considerably due to site -
specific variables (e.g., boiler type). The uncertainity in the cost data ranges from -10
percent to +30 percent. Furthermore, the cost of flue gas treatment (FGT) processes for
NO control have not yet been determined.
yv
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7
A.3 NON-FERROUS SMELTING SUMMARY
The process technology in use varies from smelter to smelter. A majority of
the smelters use the roaster - reverberatory furnace - converter process which is not
amenable to a high degree of $©2 control, at reasonable cost, owing to the weak gas
streams produced. Some copper-nickel smelters utilize more modern process technology,
and in some cases SC^ emissions are controlled. (Level of control varies from smelter to
smelter.)
The most applicable control technology in use is the production of sulphuric
acid in a contact acid plant. Two constraints limit the use of this control technology:
weak SO- streams (under 4% SO-) are not suitable for contact acid plants and a
number of smelters do not have strong gas streams;
markets for sulphuric acid are limited, and it is possible that not all the acid
produced could be marketed.
For any major SO- control program to succeed it would be necessary to:
improve or replace existing process technology (with weak SO- streams) with new
process technology which produces higher-strength SOj streams (suitable process
technology is available in the majority of the cases); and
b) find markets for the sulphuric acid.
Two other problems areas are identified:
in many smelters, some weak gas streams will remain, even with new process
technology, and SO2 emission control technology for weak gas streams in this sector
is in the early development stages; and
the choice of smelter processes to handle dirty concentrates is limited, which in
turn may reduce the level of $©2 control achievable at smelters handling dirty
concentrates.
A preliminary cost estimate has been developed for eastern Canadian copper-
nickel smelters. The estimated cost of reducing eastern Canadian smelter $©2 emissions
(at capacity operations) from 2.97 million tons per year to 1.30 million tons per year is
$1.1 billion capital and $120-$ 150 million annualized costs (includes both capital and
incremental operating costs).
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MOBILE SOURCES SUMMARY
The mobile sources sector is a major source of NO emissions. SO emissions
A A
from this sector are small and have not been considered in the interim report. Control
technology is available for the control of NO emissions from mobile sources. The use of
A
the newer NO control technologies is being expanded and NO regulatory emission limits
A A
are gradually being reduced for new vehicles.
NO emissions from "in-use" vehicles are becoming a major part of the mobile
A
sources NO problem and new programs are addressing this problem by legislating
improved maintenance requirements for such vehicles. These programs, coupled with
more stringent new-vehicle NO emission limits, should reduce total NO emissions from
A A
mobile sources, despite the continuing increase in the total number of vehicles.
The technology for meeting the current automobile emission standards
employs the catalyst technology, coupled with a series of electronic and vacuum sensing
devices which detect and control selected engine operating parameters. A so-called
three-way catalyst (incorporating NO reduction as well) is being used on many of the
A
1980 production cars. The system costs approximately $300 per car. Including fuel and
maintenance savings, the cost of the U.S. Federal Motor Vehicle Control Program
(FMVCP) for cars, trucks, heavy-duty vehicles, motorcycles, and aircraft is estimated to
be $6.6 billion by 1987. The cost of the inspection and maintenance component of this
program is estimated at $400 million annually.
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9
A.5 INDUSTRIAL, COMMERCIAL, AND RESIDENTIAL FUEL COMBUSTION
Industrial, commercial and residential fuel combustion accounts for approxi-
mately 25 percent of combined U.S.-Canada SO- emissions and approximately 25 percent
of their combined NO emissions. The fuel use sector is characterized by a wide diversity
in boiler sizes (i.e., from 105 Btu/hr to greater than 250 x 106 Btu/hr), combustion
systems, and fuel characteristics. In addition, the technical expertise of the
owner/operator varies from the homeowner to the skilled technician. Industrial boilers
are the major concern in this sector.
Flue gas desulfurization can lower potential sulfur oxide emissions by up to 90
percent. Fluid bed combustion can achieve a 70-85 percent SO2 reduction at costs which
are competitive with flue gas desulfurization. The dual-alkali wet flue gas desulfurization
process is the dominant sulfur oxide control technology for industrial boilers. Sodium
once-through systems are used in industries which produce a sodium-containing waste
stream such as pulp and paper and textile mills (from de-ionizer recharging). There are
two commercial installations of the lime spray dryer SO- control process.
As in utility boilers, combustion modification is the principal method of
controlling NO emissions. In California, several thermal-NO (non-catalytic NO
control) installations have been purchased; however, none is in commercial operation at
this time. The NO emission limits that are achievable using combustion modification are
A
dependent upon the fuel type (oil, coal, gas) and firing method (for coal, pulverized coal,
chain-grate stoker, vibrating-grate stoker, and spreader stoker).
The cost of SO* control technology varies as a function of boiler size, load
factor, and fuel sulfur content. Thus the uncertainty in capital and annual costs can be
large. The capital costs and operating costs shown in Figures A.5.1 and A.5.2 can be in
error by as much as +40 percent. The cost of retrofitting industrial boilers is highly
uncertain since space limitations and other restrictions can cause significant variations.
Control technology for commercial and residential boilers has not progressed
as rapidly as for the larger boilers, primarily because of the considerably smaller emission
reduction potential for this sector. However, results of research indicate that some
emission reduction is economically possible for commercial and residential boilers.
Precise cost figures for these boilers are not available, but preliminary indications are.
that any increase in cost will be greatly offset by the fuel savings and increased thermal
efficiency.
-------
10
4OOO
3OOO
in
.2
"o
"o
« 2000
ID
0
u
5
'5.
O
1OOO
Wellman-Lord
Double Alkali
Limestone
Sodium Throwaway
_L
29.3 58.6 87.9
(10O) (2OO) (300)
Size in MWt (106Btu/hr)
117.2
(400)
FIGURE A.5.1
F6D CAPITAL COSTS VERSUS UNIT SIZE
(3.5% S coal, 9O% removal)
Source: Technical Assessment Report for Industrial Boiler Applications:
Flue Gas Desulfurization
Industrial Environmental Laboratory; USA E.P.A.
November 1979
-------
11
20oor
1500
2
a
"o
n
O
§ 10OO
u
•o
a
3
C
C
50O
Dual Alkali
Sodium Throwaway
29.3 58.6 87.9
(100) (200) (300)
Size in MWt (1O6 Btu/hr)
117.2
(400)
FIGURE A.5.2.
FQD ANNUALIZED COSTS VERSUS UNIT SIZE
(3.5% S coal, 9O% removal)
Source: Technical Assessment Report for Industrial Boiler Applications:
Flue Gas Desulfurization
Industrial Environmental Laboratory; USA E.P.A.
November 1979
-------
12
A.6 EMISSIONS SUMMARY
Historical, present, and projected emissions of the main acid precipitation
precursor pollutants in both Canada and the United States are assessed. The data have
been accumulated in a variety of formats and are presented in this interim report in the
form of tables and figures, on the basis of the sectors of the economy of most concern at
this time, at the state, regional, provincial and national levels, and on a grid array.
Confidence limits are put on some of the data, seasonal variations for some of the
emissions are assessed, and an insight into natural sources of emissions is provided.
Projected emissions are analyzed according to a variety of control scenarios.
Emissions of SO- in the eastern U.S. rose from close to 12 million tons in 1950
to about 25 million tons in 1965 before essentially stabilizing at that level up to the year
1978. In eastern Canada SO- emissions in 1979 were about 4.5 million tons, the same
level as in 1955, after having peaked in 1965 at close to 6 million tons. The southeast and
midwest states shared the bulk of the increase in U.S. emissions. In Canada the
fluctuation was largely due to significant changes in the copper-nickel smelting industry.
NO emissions in the eastern U.S. increased significantly in all areas over the
A
1950-78 period. The steady increase ranged from about a factor of two in the northeast
to over three in the south. Emissions which were at a level of 7 million tons in 1950
reached more than 19 million tons in 1978. In eastern Canada NO emissions have also
A
been rising significantly but from a level of less than 0.5 million tons in 1955 to a little
less than 1.5 million tons in 1977. In eastern North America as a whole the important
increases in NO emissions are attributed to power plant and transportation activities.
During the 1976-80 period, yearly $©2 emissions in eastern North America (i.e., both U.S.
and Canada) have amounted to close to 29 million tons. The ratio of U.S. to Canadian
SO 2 emissions in the east is 5.5 to 1.
Thermal power plants are the primary source and contribute about 60% of the
combined U.S.-Canada nationwide emissions. The second most important category of
emission sources, at about 25% of the combined nationwide emissions, is that which
includes industrial, commercial, and residential fuel combustion. Then at about 10% are
the emissions of SO- from non-ferrous smelters. The primary contributor to present
domestic SO^ emissions differs in the U.S. and Canada. In the U.S. about two-thirds of
total domestic emissions come from power plants, while in Canada about 40% come from
non-ferrous smelters. About 20 million tons of $©2 comes from American power plants,
-------
13
about 2 million tons of SO- comes from Canadian non-ferrous smelters. About 15% of the
SO7 generated in Canada comes from thermal power plants.
In the next two decades, U.S. SO- emissions from power plants are projected
to remain roughly constant (in fact, recent evidence suggests they may even decline). In
Canada, SO emissions from thermal power plants are expected to increase from 0.8
A
million tons (1980) to 1.* millions tons (2000) unless controls are instituted for thermal
power plants. With controls, Canadian SO- emissions from thermal power plants could
decrease.
In eastern North America present NO emissions amount yearly to almost
A.
21 million tons. The ratio of U.S. to Canadian emissions in the east is roughly 15 to 1, and
close to half of the combined emissions come from the transportation sector. One quarter
of combined U.S.-Canada NO emissions are contributed by power plants and another
quarter by other combustion processes (industrial, commercial, residential fuel
combustion).
With respect to NO discharges from power generating stations, an increase of
about 50% is projected by the year 2000 from U.S. units. In Canada, uncontrolled NO
X
tonnage is expected to rise from 330 kilotons per year to 700 kilotons by the end of 2000.
If lax controls were applied, to the same new and existing stations as considered above for
SO- reductions, emissions would decline by about 80 kilotons or 15%. If strict controls
were added, the reduction would be to 150 kilotons or 77%.
Transportation sector emissions in the U.S. in the next 15-20 years are not
expected to vary significantly from their present levels because of larger numbers of
lower-emitting vehicles, unless projected automobile regulations are relaxed. In Canada,
in the absence of further control action at either the design or in-use levels, NO
emissions in 1990 are projected to be 30 to 50% greater than present levels. If, however,
more stringent new-vehicle emission standards were adopted with the 1985 models, then
NO emissions in 1990 would be about 20% less than 1980 levels. In both countries the
J\
tampering rate might be reduced by an inspection program on in-use vehicles.
Projected $©2 emissions from Canadian copper-nickel smelting complexes to
the year 2000 indicate at worst the same level as in 1980, i.e., less than 2.0 million tons
per year, and at best a level of 0.8 million tons. The level attained will depend on the
implementation of additional environmental control and technological improvements. In
the U.S. the $©2 emissions come from copper smelters located in western and south-
western states and are therefore unlikely to play a significant role in the eastern
North America acid precipitation issue.
-------
14
SO2 emissions from industrial, commercial and residential fuel combustion are
projected to increase about 50 percent in the U.S. over the next two decades (i.e., from
7.3 million tons in 1980 to 10.9 millions tons in 2000). NO emissions from these sources
will also increase significantly (i.e., from 7.1 million tons in 1980 to 9.1 millions tons by
the year 2000). In Canada, SO9 and NO emissions from industrial, commercial and
£m A
residential fuel combustion will also increase but not significantly. For $©2 emissions,
the increase is from 1.1 million tons to 1.2 million tons (10 percent); for NO , the increase
is from 0.6 million tons to 0.7 million tons (20 percent).
Present SOX and NOX emissions data for the U.S. and Canada are presented in
Table A.6.1. Projected SOX and NOX emissions for the U.S. and Canada are presented in
Tables A.6.2 to A.6.4. These projections are based on "status quo" considerations and do
not include any major emission reduction resulting from significant control measures of
the acid precipitation program.
TABLE A.6.1 CURRENT NATIONWIDE EMISSIONS OF SOV AND NOV IN THE U.S.
- A J\
AND CANADA (106 tons)
U.S.A. (1980 Estimated) Canada 1979*
Utilities
Industrial Boilers/
Process Heaters/
Residential/Commercial
Non-ferrous Smelters
Transportation
Iron Ore Processing
Other
TOTAL
N0x
6.2
7.1
0.0
9.0
-
-
22.3
S0x
19.5
7.3
2.0
.9
-
-
29.7
N0x
0.3
0.6
0.0
1.1
-
0.2
2.2
S0x
0.8
1.1
2.2
0.1
0.2
0.9
5.3
Total
NOX
6.5
7.7
0.0
10.1
-
0.2
24.5
S0x
20.3
8.4
4.2
1.0
0.2
0.9
35.0
* Inco, Sudbury at 1980 emission rate.
-------
15
TABLE A.6.2 PRO3ECTED EMISSIONS OF SOx AND NOx IN CANADA (10$ tons)
NOx TRENDS
Utility Boiler
Industrial, Residential
and Commercial
Fuel Combustion
Non-ferrous Smelters (Cu/Ni)
Transportation
Other
TOTAL
SO TRENDS
A
Utility Boiler
Industrial, Residential
and Commercial
Fuel Combustion
Non-ferrous Smelters (Cu/Ni)
Transportation
Iron Ore Processing
Other
TOTAL
Year
1980
0.3
0.6
-
1.1
0.2
2.5
0.8
1.1
2.2
0.1
0.2
0.9
5.3
Source: Data Analysis Division, Air
Canada
Note: Based on a "status
1985
0.4
0.6
-
1.3
0.2
2.5
1.1
1.1
2.0
0.1
0.2
0.9
5.4
Pollution Control
1990
0.6
0.7
-
1.5
0.2
3.0
1.2
1.2
2.0
0.1
0.2
0.9
5.6
Directorate,
1995
0.6
0.7
-
1.6
0.2
3.1
1.3
1.2
2.0
0.1
0.2
0.9
5.7
Environment
2000
0.7
0.7
-
1.8
0.2
3.4
1.4
1.2
2.0
0.1
0.2
0.9
5.8
quo" scenario.
-------
16
TABLE A.6.3 SOx PROJECTED EMISSIONS USING COMBINED MODELS (UNITED
STATES) (106 tons)
Utility Boiler
Industrial
Boiler/Process Heat
Non-ferrous Smelters
Residential
Commercial
Transportation
TOTAL
1980
19.5
5.9
2.0
1.*
0.9
29.7
1985
17.9
5.7
0.77 .
1.*
0.9
26.7
1990
18.6
6.8
0.60
1.2
0.9
28.1
1995
19.0
8.6
0.56
0.9
0.9
30.0
2000
18.5
10.3
0.52
0.6
0.9
30.8
Source: These emissions estimates based on 1980 trends but projected with % change
of models (utility - TRI; industrial ICF; RES/COM - SEAS; Transportation Ann
Arbor), NF Smelters from an actual unit-by-unit survey.
TABLE A.6.4 NOx PROJECTED EMISSIONS USING COMBINED MODELS (UNITED
STATES) (106 tons)
Utility Boiler
Industrial
Boiler/Process Heat
Non-ferrous Smelters
Residential
Commercial
Transportation
TOTAL
Source: These emissions
1980
6.2
6.2
0.0
0.9
9.0
22.3
estimates based
1985
6.8
6.5
0.0
0.9
8.3
22.5
on 1980
1990
7.6
6.9
0.0
0.8
8.6
23.9
trends but proiec
1995
8.4
7.6
0.0
0.8
9.4
26.2
ted with % cl
2000
9.2
8.4
0.0
0.7
10.2
28.5
lanee
of models (utility - TRI; industrial ICF; RES/COM - SEAS; Transportation Ann
Arbor), NF Smelters from an actual unit-by-unit survey.
-------
17
B. SOURCE SECTORS OF CONCERN
This chapter describes the industry sectors that are major sources of SO and
A
NO , and the control technologies that are either currently available or will be in the near
future. The emission sources discussed are thermal power plants (fossil fuels), non-ferrous
smelters, mobile sources (transportation), pulp and paper, petroleum refining, industrial,
residential and commercial fuel combustion and incinerators. Other sectors, such as iron
ore processing plants, will be addressed in a subsequent report.
Each sector is described in terms of the production processes and capacities
and SO and NO emissions. This is followed by discussions of the control technologies in
X A
use, available or emerging for each industry sector. The control technologies are
analyzed in terms of performance, cost, applicability, technical uncertainty and
associated problems. Alternative production processes are also discussed where
applicable.
-------
18
B.I THERMAL POWER
B.I.I DESCRIPTION
The Canadian Sector
Canada's electrical generating capacity is expected to increase substantially
by 1990, exceeding 1977 capacity by over 60 percent (1). This expansion will be
noticeable in all three major types of generation: hydroelectric, nuclear, and conven-
tional thermal. Hydroelectric power will maintain its leading role in the utility sector,
nuclear power will grow by a factor of three, while thermal generation will increase to a
somewhat lesser degree, by about 50%.
Conventional steam-electric capacity, at 19 184 megawatts (MW) in 1977, is
expected to increase to approximately 28 900 MW by the end of 1989 (1). All announced
steam-unit additions by 1990 will be coal-fired. This added coal-burning capacity will
cause annual coal consumption to increase by 127 percent, from about 21 000 kilotonnes in
1977 to approximately 48 000 kilotonnes in 1989. The majority of the steam-unit
additions fall in the provinces of Alberta and British Columbia.
Table B.I.I shows each province's percentage distribution of installed capacity
by generation type for both 1977 and 1989. The type categories are standard: coal, oil,
gas, nuclear, hydro, gas turbine, and internal combustion.
The breakdowns for 1977 are from the reports of installed capacity; those for
1989 are from the schedule of expansion plans. The 1989 distributions do not ,include the
effects of any capacity penalties due to pollution control devices and therefore represent
the distributions that would occur in the case involving no active pollution control. The
changes in the distributions due to the imposition of pollution control penalties are not
great.
In Table B.I.2 the generation mix by province is presented for the two years
1977 and 1989. Note that Nova Scotia, Saskatchewan, Alberta, and British Columbia
substantially increase the share of their generation from coal units. In
Statistics Canada, Electric Power Statistics, vol. 1, Annual Electric Power Survey of
Capability and Load - 1979-1983 Forecast, 57-204 Annual (Ottawa, Ont.: Manu-
facturing and Primary Industries Division, Energy and Minerals Section, September
1979); Department of Energy, Mines and Resources, Electric Power in Canada - 1979
(Canada: Electrical Section - Energy Policy Sector, 1980); "Canada -Still Planning
for a Strong 1980," Electrical World 1980 Statistical Report, 5 March 1980.
-------
TABLE B.I.I
19
COMPARISON OF GENERATING CAPACITY MIX, BY PROVINCE, 1977
and 1989 (PERCENT)
Province
P.E.I.
1977
1989
Nfld.
1977
1989
N.S.
1977
1989
N.B.
1977
1989
Que.
1977
1989
Ont.
1977
1989
Man.
1977
1989
Sask.
1977
1989
Alta.
1977
1989
B.C.
1977
1989
NATIONAL
1977
1989
Coal
0.00
0.00
0.00
0.00
22.70
47.66
6.22
10.53
0.00
0.00
34.20
29.80
12.67
10.10
45.28
65.10
58.69
75.07
0.00
14.37
18.82
19.74
Oil
57.89
57.89
4.54
6.31
51.37
28.88
60.63
40.26
4.28
1.60
9.08
6.06
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
7.84
4.56
Gas
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
5.22
3.49
0.00
0.00
19.15
12.21
19.71
12.51
12.64
6.70
5.30
3.14
Nuclear
0.00
0.00
0.00
0.00
0.00
0.00
0.00
20.16
1.39
1.69
17.61
37.82
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
6.37
12.16
Hydro
0.00
0.00
92.01
90.05
11.14
15.15
31.81
28.16
92.66
85.03
31.74
21.38
86.00
88.84
28.04
17.89
16.10
8.66
82.13
75.72
58.40
54.80
Turbine
35.96
35.96
2.48
2.72
14.73
8.28
1.11
0.74
1.21
11.39
2.11
1.41
0.76
0.61
7.43
4.74
4.69
3.32
4.02
2.57
2.78
5.28
Internal
Combustion
6.14
6.14
0.96
0.92
0.07
0.04
0.24
0.16
0.46
0.29
0.05
0.03
0.57
0.46
0.10
0.06
0.81
0.43
1.20
0.64
0.47
0.31
-------
20
TABLE B.1.2 COMPARISON OF GENERATION MIX, BY PROVINCE, 1977 and 1989
(PERCENT)
Province
P.E.I.
1977
1989
Nfld.
1977
1989
N.S.
1977
1989
N.B.
1977
1989
Que.
1977
1989
Ont.
1977
1989
Man.
1977
1989
Sask.
1977
1989
Alta.
1977
1989
B.C.
1977
1989
Coal
0.00
0.00
0.00
0.00
10.40
49.48
7.56
10.04
0.00
0.00
18.90
12.19
5.50
3.41
55.72
71.05
61.51
81.94
0.00
7.28
Oil
66.84
43.36
0.67
0.82
58.64
8.51
33.48
10.97
0.00
0.00
0.98
0.62
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Gas
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.23
0.14
0.00
0.00
0.79
4.32
11.07
5.82
0.51
0.23
Nuclear
0.00
0.00
0.00
0.00
0.00
0.00
0.00
21.98
0.37
0.49
28.47
54.18
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Hydro
0.00
0.00
99.19
99.05
19.14
33.47
57.99
56.94
99.55
99.05
51.33
32.80
94.40
96.53
43.17
24.40
27.12
12.08
99.21
92.35
Turbine
32.37
48.97
0.07
0.07
11.81
8.54
0.94
0.04
0.04
0.44
0.09
0.06
0.03
0.02
0.30
0.17
0.21
0.12
0.16
0.09
Internal
Combustion
0.79
7.66
0.07
0.06
0.01
0.01
0.03
0.02
0.04
0.03
0.01
0.00
0.06
0.04
0.01
0.06
0.09
0.04
0.12
0.05
-------
21
Quebec, Manitoba, Newfoundland and British Columbia, hydro generation maintains its
dominant role, accounting for well over 90 percent of generation in each of these
provinces in both 1977 and 1989. Because of the expected rise in the price of gas and oil,
the utilization of steam units based on these fuels may fall considerably in some
provinces.
The U.S. Sector
Electric utility generation in the U.S. by energy source is summarized for the
year 1979 in Table B.I.3. Roughly 50 percent of the electricity generated in 1979 was
supplied by coal-fired units. The remaining 50 percent was supplied by oil, natural gas,
hydro and nuclear in roughly equal proportions. Total U.S. electric generation in 1979 was
2 248 billion kilowatt-hours, an increase of roughly 2 percent over the preceding year (1).
TABLE B.I.3 U.S. ELECTRIC UTILITY GENERATION BY ENERGY SOURCE
(1979)
Energy Source
Coal
Petroleum
Natural Gas
Hydro
Nuclear
Geothermal and Other*
Total
Generation
(billion kilowatt-hours)
1 075
304
330
280
255
4
2 248
% of Total
Generation
47.8
13.5
14.7
12.5
11.3
0.2
Source: Reference 1.
*Includes production from plants that consume wood, refuse, and other vegetable fuels.
Production of electricity by coal-fired units in the U.S. has been steadily
increasing since 1960*. Coal use in the utility sector has more than doubled since
1964 (1). The total amount of coal delivered to electric utility plants in the first six
months of 1980 was 295.4 million tons (2). Over 60 percent of this coal went to 11 states:
*With the exception of 1978, when coal use was roughly 1 percent less than in 1977.
-------
22
Ohio (26.1),*, Texas (22.0), Pennsylvania (20.9), Illinois (19.1), Indiana (18.2), West Virginia
(15.4), Tennessee (13.2), Kentucky (12.0), North Carolina (11.2), Michigan (11.1), and
Missouri (10.8) (2). Through a combination of policy initiatives instituted by the Federal
government, coal use in the U.S. utility sector is expected to increase substantially over
the next few years.
UTILITY GENERATION BY REGION
U.S. utility capacity and generating rate for fossil-fuel-fired power plants in
1978 is summarized by state and region in Table B.I.4. The percentage change in
generating rate (1977 vs. 1978) and percentage generation by fuel is also shown in
Table B.I.4. From this table it is evident that the greatest quantities of coal used in the
utility sector are in the following regions (in decreasing order): east north central, south
Atlantic, east south central, west north Central, and middle Atlantic states. U.S. totals
listed at the bottom of Table B.I.4 show that coal constitutes 61.2 percent of total
electric generation in fossil-fuel-fired plants (3) (47.8 percent when nuclear, hydro, and
geothermal are considered).
Electric generation by fossil-fuel plants is broken down by state and region in
Table B.I.4 for areas of the country close to the U.S./Canadian border. From this it can
be seen that the greatest amount of coal use occurs in the following states**: Ohio
(103.2), Pennsylvania (83.2), Illinois (63.4), and Indiana (59.5) (3). In each of these states,
coal accounted for more than 80 percent of the electricity generated in 1978.
* Numbers in brackets are million tons delivered to utility plants in each state.
** The numbers in brackets are thousand megawatt-hours of coal-fired electric
generation.
-------
TABLE B.1.4
23
SUMMARY OF CAPACITY AND GENERATION FOR FOSSIL-FUEL-
FIRED PLANTS BY STATE AND REGION, 1978 (3)
Fossil Generation
State/Region*
Connecticut
Maine
Massachusetts
New Hampshire
Rhode Island
Vermont
New England
Total
New Jersey
New York
Pennsylvania
Mid-Atlantic
Total
Illinois
Indiana
Michigan
Ohio
Wisconsin
East North
Central Total
Iowa
Kansas
Minnesota
Missouri
Nebraska
N. Dakota
S. Dakota
West North
Central Total
South Atlantic
Total
East South
Central Total
West South
Central Total
Mountain
State Total
Pacific
State Total
United States
Total
Capacity
(MW)
3 506
717
6 437
1 052
2<42
30
11 984
5 967
17 613
23 013
46 593
21 059
15 043
13 982
23 858
6 251
80 193
4 299
5 903
4 682
10 982
1 541
1 636
546
29 589
72 478
38 002
69 515
21 618
23 445
393,417
(1000 MW-H)
11 537
930
30 095
3 840
551
14
46 967
21 093
62 206
97 767
181 066
71 696
61 407
58 709
105 021
22 204
319 037
14 812
22 938
19 424
43 520
5 911
8 814
2 838
118 257
302 322
156 694
272 627
100 001
94 955
1,591,930
(% Change
Year Ago)
+4.4
+29.3
+4.0
-4.6
-1.1
-72.5
+3.6
-3.7
-3.3
+1.8
-0.7
+2.5
-1.7
+5.8
-2.9
-3.8
0
+8.0
+ 18.0
-6.3
-2.3
+2.2
+6.4
+ 15.3
+2.9
+0.2
-1.5
+7.4
-5.1
-22.2
-0.7
Coal
0
0
0
50.5
0
64.3
4.1
26.2
22.3
85.1
56.7
88.4
96.9
80.6
98.3
96.7
92.4
96.2
54.1
97.0
95.1
78.9
99.7
97.8
87.2
67.6
89.9
13.8
82.0
6.5
61.2
Oil
100
100
99.6
49.5
100
21.4
95.6
73.5
77.6
14.9
43.2
9.5
2.7
17.6
1.6
2.0
6.6
0.5
9.2
2.9
1.3
7.8
0.3
2.1
3.3
27.7
7.5
9.5
4.5
62.6
21.0
Gas
0
0
0.4
0
0
14.3
0.2
0.2
0.3
0.2
0
2.1
0.4
1.8
0.1
1.3
1.0
3.4
36.6
0.1
3.6
13.4
0
0
9.5
4.7
2.5
76.7
13.5
30.8
17.9
^Regions closest to the U.S./Canadian border are broken out by state
Source: Reference 3.
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REFERENCES
1. DOE's Energy Information Administration, "Annual Report to Congress, 1979",
Volume Two, Report No. DOE/EIA-0173(79)/2.
2. DOE's Energy Information Administration, "Energy Data Report: Coal Distribution,
January-June 1980", Report No. DOE/EIA-0125(80/2Q), October 20, 1980.
3. National Coal Association, "Steam Electric Plant Factors, 1979", National Coal
Association, 1130 Seventeenth St., Washington, D.C., 20036.
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25
B.1.2 CONTROL TECHNOLOGIES
TECHNOLOGIES FOR CONTROLLING EMISSIONS FROM THERMAL GENERATING
STATIONS
The emphasis in controlling emissions from fossil-fuel-fired power plants is
shifting somewhat from local considerations to regional concerns regarding problems such
as acid rain, visibility, and respirable particulates. In view of this, a reassessment of
abatement methods is needed, aimed at determining which of the processes are most
capable of accomplishing the degree of control needed from the regional viewpoint, from
the standpoints of both control efficiency and cost effectiveness.
In general, the optimum process for controlling a given pollutant depends on
the degree of control required. Processes that reduce emissions to an extreme degree are
quite expensive and are usually not implemented unless the high efficiency is considered
to be essential. On the other hand, techniques that cost less are not normally capable of a
high degree of control.
The pollutants of concern are sulphur oxides (SO- and SO,), nitrogen oxides
(NO and NO2> generally referred to as NO ), and solid material carried in the gas stream
(ash from the fuel, unburned carbon, and other non-gaseous particles—all generally
referred to as "particulate matter"). Most of these come from the fuel itself, by reaction
of sulphur and nitrogen compounds with oxygen supplied by the combustion air, and by
burning out the combustible compounds leaving the ash as small solid particles. In
addition, some NO is formed by reaction of nitrogen and oxygen in the combustion air.
X
The amounts of such pollutants vary with type of fuel, design and size of
boiler, and capacity factor. Typical data are given in Table B.I.5 for a 500 MW unit.
Although the tonnages listed are high, the concentrations in the flue gas are quite low
because of the very large flue gas volume, which is composed mainly of carbon dioxide
and water vapor; the 500 MW boiler in Table B.I.5 would produce about 60 000 tons of
flue gas per day, at full power; at 60% capacity factor, this is equivalent to 13 million
tons of flue gas per year.
The large amounts of pollutants evolved have led to regulations for reducing
emissions. As might be expected from Table B.I.5, the main emphasis in the past has
been on particulate matter, where coal is the fuel, because of the large amount involved;
devices to collect and remove particulates from the gas stream have been required for a
long time. Since 1971, sulphur oxide and nitrogen oxide emissions have been regulated in
the U.S.. In Canada, recommendations for emission controls have been submitted to the
provinces.
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26
TABLE B.1.5 TYPICAL UNCONTROLLED EMISSIONS OF POLLUTANTS3
Fuel
Natural gas
Oil (1.0% sulphur)
Coal
Low-sulphur (0.7%)
High-sulphur (4.0%)
a 500 MW boiler,
Pollutant (tons per year)
Sulphur oxides
-b
15000
15000
88000
60% load factor. Levels givei
Nitrogen oxides
4000
4800
8 200
8200
n are fairly typia
Particulates
-b
1 100
110 000
110 000
al; in practice they
vary over a wide range. Coal burned, about 1.1 million tons/year.
b Natural gas normally contains very little sulphur or ash.
Emphasis on nitrogen oxide control is just beginning, mainly in congested areas such as in
Japan and southern California in the United States.
Sulphur oxides and particulates are removed from the gas stream by a variety
of devices. (Sulphur oxide emissions can also be reduced by using low-sulphur fuel.) For
nitrogen oxides, the general practice has been to reduce emissions by altering combustion
conditions in the boiler in such a way as to reduce NO formation. Since this is only
partially effective, there has been some use in Japan of devices to remove NO from the
gas.
Emission Rates
In this sector, emission rates are routinely stated in terms relating to the heat
input to the boilers. The range of emissions for the three pollutants varies widely,
depending on the fuel characteristics and the boiler design.
S02 Canada 0 - 13 lb/106 Btu
U.S. 0 - 8 lb/106 Btu
NOV Canada/U.S. 0.5 - 1.0 lb/106 Btu
6
Particulates* Canada/U.S. 0.03 - 3.0 lb/10 Btu
*As presently controlled.
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27
Sulphur Dioxide controls can be broadly classified as follows:
Physical Coal Cleaning
Flue Gas Desulphurization
Low-Sulphur Fuel
Fuel Desulphurization - Oil
- Coal
Nitrogen Oxides controls can be classified as:
Burner Modification
Boiler Design and Operation
Flue Gas Treatment
Particulate control is achieved as follows:
Cyclonic cleaning
Electrostatic Precipitator
Baghouse
Definitions
"In use" technologies are those that have been demonstrated on a commercial scale and
for which orders have subsequently been placed. "Available" technologies are those that
have been demonstrated but not yet installed or ordered to any significant extent.
"Emerging" technologies are those in the research and development stages that have been
developed to the pilot-scale level.
A) Sulphur Dioxide Control
In the past, the main approach to sulphur oxide control in countries such as
Japan and the U.S. has been the use of naturally occurring low-sulphur fuel. This is still
the practice in Japan, but in the U.S. the recently enacted federal regulations now require
a reduction in uncontrolled emissions for all new boilers burning oil or coal — and pressure
is growing to require such reduction for existing units. Several approaches can be used to
attain the reduction, including fuel blending, fuel desulphurization, coal cleaning, coal
conversion, desulphurization during combustion, and flue gas desulphurization (FGD).
a) Physical Coal Cleaning
For coal, part of the sulphur can be removed at relatively low cost by physical
methods, that is, the coal is subjected to a treatment based on gravity differences to
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28
separate the crushed material. Since the heavier fractions contain much of the sulphur,
some 10-30% of the sulphur can be removed fairly easily depending on the sulphur
characteristics, among other things. A variety of methods are used, including washing,
shaking and mineral concentration methods.
If more than 10-30% removal of the sulphur is required, physical cleaning
becomes expensive. It can be combined with other methods to advantage if an
intermediate degree of removal is acceptable and if the original pyrite sulphur content is
extremely high. For 90% and higher removal of sulphur in the fuel, (10% or less left in
the coal), as now required in the U.S. for new plants, other methods are more cost
effective.
Cost: Physical coal cleaning is probably the most cost-effective method
available for reducing SO2 emissions if a high degree of reduction is not required. A TVA
study shows a cost of $0.22 per Ib of sulphur removed for cleaning and $0.237 per Ib for
limestone scrubbing (2000 MW, 3.5% S coal, 29-32% removal by cleaning, and 85% by
FGD). Within the limits of accuracy of the estimates, the costs are thus about the same.
There are certain more or less intangible benefits to cleaning, however, that are not
counted in this comparison, and that should make cleaning the clear choice if 10-30%
removal is acceptable.
For lower-sulphur coals, the cost of cleaning increases rapidly with decrease in
coal sulphur content. For example, at 0.7% sulphur, the cost per Ib of sulphur removed is
$1.88, as compared to $0.89 for FGD.
b) Chemical Desulphurization of Coal
A large amount of experimental effort has been expended on methods for
desulphurizing coal by chemical means. The process types vary widely, from simple
leaching by chemical solutions to methods that involve dissolution of the coal and
reconstitution of the solids. The last of these, generally called Solvent Refined Coal
(SRC), borders on a coal conversion process and is usually classed as such. However, it is
also a process for cleaning the coal of ash and sulphur and producing a clean solid fuel
with characteristics much like the original coal but with much reduced polluting potential.
Although much development work on chemical coal cleaning (CCC) has been
carried out, there is as yet no commercial use. SRC, sometimes called a synthetic fuel, is
probably the closest to commercializaton. One module of a commercial-size plant is to
be funded by the U.S. DOE, with final designs due by mid-1980 and start-up planned for
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29
The developers plan to expand the facility to commercial size and have it operating by
1990; the capacity will be 30 000 tons per day (five 6 000 tpd modules).
All the other CCC methods are only at the bench or pilot-plant scale of
development.
Process Evaluation; Chemical coal cleaning has the same problem as physical
cleaning—difficulty in getting a high degree of removal without incurring high cost.
Although most of the chemical cleaning methods will do better than physical cleaning
processes in removing both pyritic and organic sulphur, especially the latter, overall
removal is usually considered to be in the range of 60 to 75%. SRC does better than the
others because the hydrogenation promotes sulphur removal; the process probably can
make 85% removal at a cost competitive with wet scrubbing, but 90% or higher removal
of sulphur is a difficult objective.
Cost; Because of the chemical steps involved, chemical coal cleaning costs
considerably more than physical cleaning methods. The cost per Ib of sulphur removed
ranges from $0.253 to $0.44. In contrast, the estimated cost for FGD, which was assumed
to remove 85% of the SCU as compared to 59 to 73% for the CCC processes, is estimated
at $0.237 per Ib of sulphur.
Various cost estimates have been published for SRC. EPRI estimates indicate
a cost of about $4.50 per million Btu for SRC, which corresponds to about $113 per ton of
Eastern coal (at 12 500 Btu/lb). This is considerably higher than the levels estimated for
use of raw coal plus scrubbing, which are $25 to $30 per ton for the coal and $10 to $15
per ton for the scrubbing. However, SRC has several advantages such as low ash content
that give other savings, thus making the cost comparison quite complicated. At the best,
the process does not seem likely to be competitive with flue gas scrubbing at 90% and
higher removal requirement.
Reliability; It should be noted that the cost comparison between CCC and
FGD is affected in a major way by how the reliability problem is handled. CCC can be
considered completely reliable to the power plant operator on the basis that the CCC
plant will maintain a stockpile of product to assure an uninterrupted supply. For FGD,
however, full reliability cannot be assumed and in fact has not been attained in most
operating systems. The same criticism applies of course to all other components of the
power train, from fuel input to the generator output.
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30
c) Desulphurization of Oil
Oil desulphurization is a well-developed technology, used widely in several
countries. The method has been used extensively in Japan to reduce SC>2 emissions.
The residual sulphur in the treated oil is usually in the order of 0.2 to 0.5% but
a higher degree of desulphurization is feasible. The situation is similar to coal cleaning in
that the cost increases with the degree of desulphurizaton. Japanese data show an
increase from $16/kL to $27/kL when increasing from 70% to 97% sulphur removal,
compared to an equivalent increase from $16 to $19 for a similar improvement in
efficiency for flue gas desulphurization.
d) Flue Gas Desulphurization — Dry Processes
One of the newer developments is injection of a lime slurry into a spray drier
concurrently with the flue gas. The lime reacts with the SO- to form a dry, solid product
that is collected downstream in an electrostatic precipitator or fabric filter (usually
called a baghouse). The main advantages are relative simplicity of equipment, production
of a dry waste material rather than a wet sludge, lower energy requirement, and possibly
lower maintenance and better reliability. The drawbacks are need for lime (more
expensive that limestone) and difficulty in getting a high degree of removal. The latter
effectively limits the process to low-sulphur coal.
Only pilot plant data are available but enthusiasm for the process has led
utilities to contract for several installations in the U.S. There is some indication from
bidding situations that the process does not have as much cost advantage as expected.
Cost; Published cost estimates indicate a lower cost for the spray drier
process, in the order of 15% or so. Basin Electric, for example, estimated the capital cost
at Antelope Valley to be $129/kW (including particulate removal) for a dry system as
compared to $145/kW for wet scrubbing (limestone). At Laramie River, the estimates
were $100/kW and $121/kW, respectively. The capital costs of dry processes at this time
are uncertain. Because of the relative simplicity there may be some cost advantage.
Operating cost depends mainly on what is assumed for operating labor and
maintenance plus the amount of lime required and the price margin over limestone. TVA
estimates show lower direct costs (including absorbent) for wet scrubbing but when items
such as overhead and capital charges (which depend on capital cost) are added, the annual
revenue required may be less for dry processes than for wet systems.
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31
e) Flue Gas Desulphurization — Wet Scrubbing
Scrubbing the flue gas with a limestone slurry has become the basic FGD
process. It has been available commercially for over 10 years, limestone is the least
expensive sulphur absorbent available, and no competitive process has been demonstrated
to be more cost effective. The main drawbacks have been corrosion/erosion in the
scrubbers, unreliability of the very large slurry circulation pumps, and production of a
wet, difficult-to-handle sludge. Moreover, there has been in the past some trouble with
system availability, particularly with high-sulphur coal.
Progress has been made in all these areas but the problems in some plants are
still not completely resolved. Small amounts of promoters such as magnesium or adipic
acid are sometimes added to the reagent; tests have shown these to be often effective in
raising SO* removal efficiency. Spare equipment is being generally installed as a means
of ensuring reliability.
There is a wide range in capital costs owing to site-specific considerations,
and to variation in the bids from different vendors. Lime has some operating advantages
over limestone and is sometimes used.
Lime-limestone scrubbing is widely used in all areas — Japan, the U.S., and
West Germany — where SO- emission reduction is required. In the U.S., the capacity
currently operating on utility boilers is over 19 000 MW and 53 000 MW more is under
construction or planned. It is estimated that nearly 160 000 MW will be in operation by
1990.
One of the scrubbing process variations is the so-called "double alkali" process.
The advantages of the process are very high removal efficiency and better scrubber
operation because of the clear solution, avoiding scaling of the scrubber internals.
Sludge Disposal
Lime-limestone scrubbing produces waste solids (mainly calcium sulphite) with
very undesirable properties — difficult to dewater and incapable of supporting much
weight when placed in the waste disposal area. Moreover, potential leaching of
constituents is regarded by environmental agencies as a serious problem.
Dewatering and strength can be improved to a considerable extent by forced
oxidation — bubbling air through the scrubber slurry to oxidize calcium sulphite to
calcium sulphate (gypsum), a material that precipitates as large crystals easier to dewater
and stronger when placed in a waste pond or landfill. There is a current trend to
specifying forced oxidation when purchasing scrubber systems.
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32
The leaching problem is vague and ill-defined. Calcium sulphite and sulphate
are relatively innocuous but regulatory authorities express concern about the leaching of
metal compounds (selenium, arsenic, mercury, and others) from the residual fly ash
collected in the scrubber and present in the sludge.
f) Flue Gas Desulphurization — Recovery Processes
Recovery of the SO2 in power plant flue gases as a useful material has been a
research goal for several decades. Numerous companies have seen this as a promising
business venture and have expended large sums" in development. Various agencies and
institutes have also taken part, including TVA, EPA, DOE, and EPRI in the U.S., Bergbau
Forschung in Germany, and various groups in Japan.
The results of all this work have not been very promising. In Japan there are
only four installations on utility boilers, totalling a little over 500 MW. There are also
about 25 units on industrial boilers and other industrial operations with a total gas flow
equivalent to about 2 500 MW. In the U.S., two utilities have installed recovery processes
on a commercial basis; the total capacity is about 2 500 MW.
Process Description; There are dozens of recovery processes, in various stages
of development. Only the more significant ones will be summarized.
Wellman-Lord. The gas is scrubbed with sodium sulphite solution and the resulting
sodium sulphite-bisulphite heated to evolve a rich stream of SO2, convertible either
to sulphuric acid or elemental sulphur. The process is used by New Mexico Public
Service and NIPSCO in the U.S., and by Chubu Electric in Japan.
Magnesia scrubbing (Chemico, United Engineers). The gas is scrubbed with MgO
slurry to form Mg(HSO3)2 which is then treated with MgO to precipitate MgSOy
The sulphite is dried, calcined to evolve a rich stream of SO2, and the SO2
converted to sulphuric acid. Philadelphia Electric is installing the process at two
stations and TVA plans an installation at the Johnsonville station.
Rockwell. Sodium sulphite produced in a spray drying process is reduced to sodium
sulphide in a furnace and the resulting melt treated with water and carbon dioxide
to evolve a rich stream of H2S, convertible to sulphur by the Glaus process. The
method has the advantage that coal can be used as the reducing agent whereas the
other methods require either natural gas or expensive activated carbon. The process
is being tested in a 100 MW facility at Niagara Mohawk's Huntley station.
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33
Cost; A major drawback to recovery processes is relatively high cost.
Complicated process flowsheets, absorbent losses, and high energy requirements all
contribute to a high cost level.
One of the items contributing to high cost is the energy requirement. The
following levels have been reported.
Process
Wellman-Lord (sulphur as product)
Magnesia scrubbing
Limestone scrubbing
Energy requirement, % of boiler
energy input with no control
12-25
5-10
1.5-3
g)
Coal Gasification (Combined Cycle)
Another approach is production of low Btu gas by coal gasification, removing
ash and sulphur, and burning the clean gas in a combined-cycle operation (use of a gas
turbine and boiler in series to improve energy utilization). In this case, the increase in
energy efficiency is the major objective in addition to desuiphurization, and thereby
complicates estimation of the sulphur removal cost. Most estimates show a cost
reduction of 15% or so by the combined cycle route (based on cost per kW-h), compared to
a conventional boiler with FGD, but commercialization is probably 15 to 20 years away.
Moreover, the cost of new processes tends to go up as development work progresses.
h) Fluidized-Bed Combustion
The most promising method in emerging technology is fluidized-bed
combustion. In the fluid-bed process, air blown up through a bed of fine coal and
limestone burns the coal in a suspended state and produces steam in water tubes
submerged in the bed. The limestone absorbs the SOj. Capital cost for SO2 removal
should be low because no separate reactor is needed. The main drawback is difficulty in
reaching a high level of SO2 removal without using an inordinate amount of limestone and
hence much increased waste production. To get 90% removal, some two to four times as
much limestone is required compared to limestone wet scrubbing.
Estimation of sulphur control cost for fluidized-bed combustion is complicated
by the fact that reduced boiler cost is an objective as well as sulphur removal. Proponent
estimates generally show a saving of 10 to 15% per kW-h as compared to a conventional
power plant equipped with wet scrubbing; others show the two about even. Commercializ-
ation for use in power plants is probably 10 to 20 years away.
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34
Cost Factors; Like coal gasification, most cost estimates for FBC show some
10 to 15% lower cost as compared to a conventional system fitted with FGD. Most such
estimates have been published by proponents; in more recent cost comparisons by TVA, it
was concluded that although FBC (atmospheric and pressurized operation) shows a
potential saving of 9 to 14% "when uncertainties are included, the estimated cost of
electricity for the three alternatives is so close that all are considered to be within the
competitive range for further consideration."
It should be noted that the FBC approach was favored by some of the
assumptions in the TVA study, mainly the higher energy efficiency for FBC and the
relatively high energy penalties assigned to conventional systems plus FGD. For
example, it was assumed that atmospheric FBC has an energy efficiency of 35.8% as
compared to 31.8% for conventional boilers. In contrast, a British study shows 36.6% for
FBC and 37.1% for conventional boilers. The comparative cost of FBC and conventional
operation cannot be calculated accurately at the present time.
Process Choice; The recommendations in the following table are made for
process choice at different required levels of emission reduction. It should be noted that
these are only approximate and that site-specific conditions could well change the
ranking. The rankings are judgmental in nature, based on a subjective evaluation of
factors such as cost, commercial viability, control efficiency, and process reliability.
Removal efficiency level, % Process listing
Higher than 90% 1. Double alkali
2. Limestone scrubbing
with promoters
3. Coal gasification (combined cycle)a
4. Recovery processes
90% 1. Limestone scrubbing
with promoters
2. Limestone scrubbing
3. Double alkali
50-90% (high-sulphur coal) 1. Limestone scrubbing, (with
physical coal cleaning where
upper limit on SC>2 emissions
applies)
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35
2. Fluidized bed
combustion3
3. Chemical coal
cleaning
4. Low-sulphur fuel substitution
(not a sulphur removal process)
5. Limestone injection through
modified burner'3
50-90% (low-sulphur coal) 1. Spray drier process
2. Limestone scrubbing
Below 50% 1. Physical coal cleaning (highly
variable effectiveness due to
coal properties)
2. Blending with low-sulphur coal
aWhen and if developed.
Ranking due to current status of development.
B) Nitrogen Oxide (Ncy Control
The alternatives for nitrogen oxide control are boiler operation changes,
combustion equipment modifications to reduce NO formation, and flue gas treatment
A
(FGT) to remove it from the gas. Boiler operation changes introduce hazards especially
with coal, and are not popular. Combustion equipment modification is much less
expensive than FGT, and is used both in the U.S. and Japan. In situations where the
regulations have become so stringent that combustion modification is not capable of
achieving the required emission reduction, flue gas treatment is employed. It has been
used on full-scale Japanese oil-fired units, and is being evaluated at pilot scale on U.S.
coal-fired boilers.
a) Combustion Modifications; In the U.S. and Canada, combustion modification
(CM) is the most common method of NO reduction. NO can be reduced by injecting the
X X
combustion air in two stages, normally by reducing air flow to the burner and injecting the
remainder through "overfire" air ports in the side of the boiler. "Low-NO " burners that
accomplish staged conditions within the burner flame have also been developed.
Staged combustion is the most cost effective of the methods but normally only
reduces emission by 15-25%. Gas recirculation is more expensive but is quite effective
for gas or oil, giving an emission reduction up to 50%. Low-NO burners are effective and
s\
are often used in Japan in combination with the standard type of staged combustion and
with gas recirculation. Combustion modification has given very low NO emissions in
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36
Japanese tests, 100 ppm with coal and 50 ppm with oil ~ a reduction of 75 to 80%
compared to uncontrolled emissions. However, an advanced degree of combustion
modification can cause slagging in the boiler and corrosion of heat transfer surfaces.
Typical emission limits achievable using combustion modification techniques
and their associated capital costs are:
Low Excess Air 0.9 Ib NOX/106 Btu $0.
Staged Combustion 0.7 " $2-3/kW
Low-NOv Burner 0.4-0.5" $2-10/kW
A
Emissions are based on coal-fired units emitting 1.0 lb/106 Btu when
uncontrolled.
Since NOX emissions are complex functions of boiler design and operation, and
also fuel characteristics, emissions vary widely, (e.g., for wall-fired units, the range is
generally 0.7 to 1.3 Ib NOX per million Btu input). This wide range of uncontrolled
emissions leads to uncertainty on controlled emission rates when combustion modification
is employed.
The capital costs are dependent in part on site-specific variables, and the
accuracy of the costs quoted is not better than -10% to +30%.
b) Flue Gas Treatment; The leading method is injection of gaseous ammonia to
reduce NO to harmless nitrogen. Operation without a catalyst requires very high
temperature and removal is limited to about 35 - 40%. With a catalyst, 90% or higher is
feasible but 80% gives much less operating difficulty and may be the upper practicable
limit for high-sulphur coal.
c) Process Choice; The situation is similar to that for other pollutants — process
choice depends on the degree of control required.
removal efficiency level, % Process ranking
^" •• •""•• ™^
90% or higher 1. Catalytic reduction* with more than
the normal amount of catalyst, pre-
ceded by combustion modifications
50-80% 1. Catalytic reduction with a normal
amount of catalyst
2. Combustion modification (all
types) followed by non-catalytic
reduction (ammonia injection with-
out catalyst)
* This technology has not been proven on coal-fired boilers.
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37
3. Combustion modification alone (for
low part of range so as to minimize
boiler problems)
4. Low-NOx burners'3
Below 30% 1. Staged combustion3
_ *s
2. Low-NO. burners
3. Gas recirculation (except for
coal)a
Used in combination with others if necessary to achieve the required reduction level.
Under development.
C) Paniculate Matter Control
a) Precipitation and Filtration; Electrostatic precipitation is the basic method in
the power generation industry for removing particulates originating as ash in the fuel.
However, there is a trend toward using fabric filters (baghouses) in the U.S. as a means of
attaining the very stringent emission standard adopted recently for new boilers.
b) Wet Scrubbing; The limited ability of wet scrubbers to remove very fine
particulates makes their use questionable to meet the new regulations in the U.S., an
unfortunate situation because scrubbers can remove the bulk of the coarse particulates at
very low cost. In a new development, a wet precipitator after the scrubber removes the
fine particulates.
c) Process Choice; For the current new source performance standards in the U.S.
(0.03 lb/10 Btu), baghouses are probably superior for low-sulphur coal because the ash
does not precipitate easily. For high-sulphur fuel, the situation is not clear; more
experience with baghouses is needed. For a standard such as 0.1 lb/106 Btu, precipitators
are more cost effective.
B.I.2.1 Technologies in Use
SO2 Reduction
a) Physical coal cleaning
b) Blending with low-sulphur fuel
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38
c) Oil desulphurization
d) Flue gas desulphurization
NOX Reduction
a) Flue gas recirculation (FGR) (gas-fired units)
b) Low excess air
c) Staged combustion
B.I.2.2 Available Technologies (see definition in B.I.2)
SO2 Reduction
a) Magnesium oxide scrubbing remains to be demonstrated on a full-scale power station
with an acceptable degree of reliability. Anticipated costs are likely to be higher
than limestone, though experience is extremely limited.
b) Lime/limestone scrubbing with chemical promoters, e.g., adipic acid.
Nitrogen Oxide Reduction
a) Low-NO burners
b) Flue gas treatment (FGT)
Performance of NOX Reduction Techniques
FGR is used now for superheat control and has some beneficial effects on NO
]\
reduction. Generally, it is evidently not a favored technique. Its costs are indeterminate.
Low excess air may be applicable and costs nothing, but operators may resist it because of
safety problems with pulverized coal. Staged combustion is available but possibly may
cause corrosion problems.
Low-NO burners are available at $l-10/kW, depending on size and ease of
replacement of existing burners.
B.I.2.3 Emerging Technologies
SO2 Reduction
a) Fluidized-bed combustion
b) Fuel gasification
c) Gasification with combined cycle operation
d) Pressurized fluidized-bed combustion
e) Coal liquefaction, direct (SRCI and SRCII) and indirect (e.g., SASOL)
f) Limestone injection with multi-stage burner, (LIMB process)
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39
NOX Reduction
a) Ammonia injection
b) Advanced low-NO burners
Second generation low-NO coal burners, projected to be capable of
emission of 0.2-0.3 Ib per million Btu, will soon begin commercial demonstration. It is
projected that these advanced lowrNO burners may be commercially available in the
1983-85 period.
Flue gas treatment processes have been evaluated at pilot scale for coal
applications in Japan and the U.S. The results of the pilot-scale testing have shown that
the long-term NO removal may be affected by the nature of the fly ash. More effort to
yv
evaluate the impact of coal and fly ash type on the performance of flue gas treatment
processes is needed.
B.1.3 ALTERNATIVE PRODUCTION PROCESSES
1. Hydro
2. Nuclear
3. Magnetohydrodynamics
4. Tidal Power
5. Solar Power
6. Wind
The last four in this group are not thought likely to make any significant
contribution to commercial electric power production capacity in the next twenty years,
except in special circumstances for very limited markets.
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B.2 NON-FERROUS SMELTERS
B.2.1 Description of the Non-Ferrous Smelting Sector
Canada
The large smelter sources of 862 in Canada are estimated to emit about 2.7
million tonnes per year when operating at full capacity. In 1980, the emissions are
estimated to be only 2 million tonnes largely because of below capacity operations related
to depressed metal markets. A brief presentation of smelter statistics is given in Tables
B.2.1 and B.2.2. Two zinc smelters (CEZ at Valleyfield, Quebec and Texas Gulf at
Timmins, Ontario) and a lead smelter (Brunswick Mining and Smelting at Belledune, N.B.)
already control 85 to 90% of their sulphur input, and as a result are not considered major
emissions sources of SO2 for the purpose of this study.
United States
In the United States, two distinct situations exist regarding sulphur emissions
from non-ferrous metals production. There are 16 copper smelters, 6 lead smelters, and 8
zinc smelters (some of which have recently closed or are expected to close). In the
eastern U.S., there are four primary zinc smelters and two primary copper smelters.
These smelters have low SO- emissions because of the nature of the production processes
and controls employed and are not included as major emission sources of SO- for the
purpose of this study. The major non-ferrous smelting capacity is located in the western
U.S. with the largest concentration in the Arizona-New Mexico area (see Figure B.2.1 and
Table B.2.3). It is not known whether these sources contribute to the eastern acid rain
problem.
B.2.2 Control Technology
Introduction
Non-ferrous smelters are, in principle, amenable to SO- emission control using
technologies that are available. Acid plants and liquid SO- production are considered
proven and, in most cases, affordable control approaches for strong SO- off-gas streams.
The major issue here involves the availability of affordable technology for control of weak
stream SO- emissions. There are three approaches to solving the weak SO- problem:
flue gas scrubbing
-------
TABLE B.2.1
GENERAL DESCRIPTION OF NON-FERROUS SMELTER SECTOR - PRESENT
CONDITIONS
Smelter
Location
Processed Used
Capacity
SO- Emission Rates
Hudson Bay Mining
and Smelting Co.
Limited
INCO Limited
INCO Limited
Falconbridge Nickel
Mines Limited
Noranda Mines
Limited, Home
Division
Noranda Mines
Limited, Gaspe
Division
Flin Flon,
Manitoba
Thompson,
Manitoba
Copper Cliff,
Ontario
Sudbury,
Ontario
Noranda,
Quebec
Murdochville,
Quebec
Cu-roasting (multiple hearth
roasters), reverberatory
furnace smelting, converting,
anode casting
Zn-roasting (multiple-hearth
roasters), electrowinning
Ni-roasting (fluid-bed roast-
ers), electric furnace smelt-
ing, converting, refining
Ni-roasting (multiple-hearth
roasters), reverberatory
furnace smelting, converting,
refining
Cu-flash smelting, convert-
ing, refining
Iron Ore Processing-pyrrhotite
roasting (fluid-bed roast-
ers), leaching, sintering
Ni/Cu-roasting (fluid-bed
roasters) electric furnace
smelting, converting
Cu-green charged reverbera-
tory furnace smelting, con-
verting - Noranda continuous
smelting furnace - anode Cu
shipped to CCR, Montreal
Cu-roasting (fluid bed-roast-
ers), reverberatory furnace
smelting, converting, anode
furnace
ISO tonnes blister
Cu per day
230 tonnes refined
Zn per day
130 tonnes refined
Ni per day
430 tonnes Ni per
day in various
forms
400 tonnes per day
refined copper
2200 tonnes per
day iron ore, 20
tonnes per day Ni
130 tonnes per day
Ni, 70 tonnes per
day Cu
540 tonnes per day
Cu
230 tonnes anode
Cu per day
Current Manitoba
control order 800
tonnes per day average
monthly mean
Current Manitoba
control order 1130
tonnes per day
Current legislation
limits emission to
2270 tonnes per day
230 tonnes per day
under current
legislation
420 tonnes per day
under current
control order
1570 tonnes per
day
230 tonnes per day
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TABLE B.2.2 GENERAL DESCRIPTION OF NON-FERROUS SMELTER CONTAINMENT - SO-
Smelter
Hudson Bay Mining
and Smelting Co.
Limited
INCO Limited
INCO Limited
Location
Flin Flon,
Manitoba
Thompson,
Manitoba
Copper Cliff,
Ontario
Sulphur Containment Process
None installed
None installed
Liquid sulphur dioxide produced from
copper flash furnace in copper-nickel
smelter
SO2 Containment %
Nil
Nil
365 tonnes per day 1 1
INCO Limited
Falconbridge Nickel
Mines Limited
Noranda Mines Limited,
Home Division
Noranda Mines Limited,
Gaspe Division
Copper Cliff,
Ontario
Sudbury,
Ontario
Noranda
Quebec
Murdochville
Quebec
Sulphuric acid produced in contact
acid plants from the iron ore
recovery plant
Sulphurc acid produced in contact
acid plant from fluid-bed roasters
None installed
Sulphuric acid produced in contact
acid plant from fluid-bed roasters
1600 tonnes per day 85
525 tonnes per day 65
Nil
330 tonnes per day 60
1 Percent SO- contained (sulphur contained to total sulphur input)
-------
I i
WIOMIHC I
•T--J i
i.-r:^
\J ! ! 1 i
\ ; ! * i OUAH:--^___^:
-<._.
-------
TABLE B.2.3
PRIMARY COPPER SMELTERS, 1979 (United States)
Company
Location
Annual capacity3 (tonnes)
The Anaconda Company
ASARCO, Incorporated
Cities Service Company
Inspiration Consolidated
Copper Company
Kennecott Copper Corporation
Magma Copper Company
Phelps Dodge Corporation
Copper Range Company
TOTAL
Anaconda, Montana
El Paso, Texas
Hayden, Arizona
Tacoma, Washington
Copperhill, Tennessee
Miami, Arizona
Garfield, Utah
Hayden, Arizona
Hurley, New Mexico
McGill, Nevada
San Manuel, Arizona
Ajo, Arizona
Douglas, Arizona
Hidalgo, New Mexico
Morenci, Arizona
White Pine, Michigan
180 000
10* 000
163 000
91 000
20 000
136 000
25k 000
73 000
73 000
45 000
181 000
64 000
115 000
127 000
161 000
82 000
1 869 000
a Production of "blister" copper (99 percent Cu)
b Operations at this plant and the associated refinery at Great Falls, Montana were
discontinued in December, 1980
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upgrading roaster and reverberatory furnace operations to produce a strong
SO2 gas stream for acid plant control
alternative process technology which results in strong SO~ §as streams for
acid plant control or elimination of SOj formation.
In considering any approach, it is of paramount importance to consider the
unique nature of each smelter. This uniqueness factor is determined by the nature of the
ore concentrates and the metallurgy required to successfully treat these concentrates. It
is these aspects that govern the selection of a metallurgical process for metal winning,
and, in turn, the degree of sulphur containment. Each smelter requires an individual
technical and economic assessment of feasibility.
In the selection of the production and control processes the following factors
must be considered and evaluated:
a) amenability to SO- control
b) applicability of the production process to the concentrates to be treated (continuous
smelting not applicable to concentrates with high lead or arsenic contents)
c) energy consumption, including the types and qualities of the energy used
d) capital and operating costs
e) amenability to improved industrial hygiene conditions
f) flexibility to changing conditions such as fluctuating levels of production, changes in
composition of concentrates, etc.
g) creation and controllability of environmental problems whether air pollution, water
pollution or solid waste disposal
h) recovery of primary metals and by-products
The control process for SO- emissions must be evaluated against the factors
listed above, and must also include costs for pollution by-products disposal, whether as a
marketable or throwaway by-product.
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46
B.2.2.1 Control Techology In Use
The most common control method in use is conversion of SO- to marketable
sulphuric acid. The cost of fixing sulphur in this way is shown in Table B.2.4.
The fixing of sulphur as marketable liquid sulphur dioxide is also practised.
The cost is shown in Table B.2.5.
Both processes require a continuously-flowing gas of at least 4% SC^.
Therefore they are not normally applicable to gases from reverberatory furnaces or multi-
hearth roasters. Gases from Fierce-Smith converters can be treated in this way provided
that they can be scheduled to produce a fairly continuous stream or that a relatively large
continuous higher concentration stream is available for mixing with the converter gases.
Tight-fitting, water-cooled hoods would also have to be provided for the converter off-
gases.
The cost of retrofitting smelter strong gas streams with an acid plant would be
similar to that for new smelters except for the changes to existing metallurgical process
equipment (e.g., revision to converter hoods as mentioned above).
Uncertainty of data base
The non-ferrous smelter capacities and the maximum SO2 emission rates are
based on validated data and the uncertainty factor would be about + 5%. The costs of
control technologies do vary from smelter to smelter depending on location of smelter
(i.e., geographical remoteness), smelter configuration, age of smelter, availability and
cost of services and materials such as electrical power, fuel, chemicals, etc. Thus the
uncertainty of the capital and operating costs is greater and is estimated at + 20% for
capital costs and + 15% for operating costs.
Factors such as varying interest rates, monetary exchange rates and non-
technical constraints will further increase the cost uncertainties.
(i) Problems including waste disposal and energy aspects
A key problem that has to be addressed in any control action with regard to an
existing non-ferrous smelter, and in some cases a new smelter, is the compatibility of the
actual mineral concentrate to be smelted with the choice of smelting process and the
control technology. The ideal, which can sometimes be achieved, is a completely
contained or continuous smelting process which produces a reasonably steady flow of
concentrated SC^. The use of this ideal is currently limited to a few special cases where
the level of trace elements (such as lead and arsenic) does not require a batch converter
processing stage.
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TABLE B.2.4
47
COST OF FIXING SULPHUR AS SULPHURIC ACID FROM SMELTER GASES
USING SINGLE CATALYSIS ACID PLANT (EPS 3-AP-79-8)
($ CAN. June, 1979)
Basis for Estimates
Production: t/day 100% HjSO^
Gases:
Continuous smelter gas, i.e., from
roaster, flash furnace, % SO2
Variable gas, i.e., from converters,
%so2
CAPITAL COST ($, June 1979 cost level)
Single catalysis sulphuric acid plant
Contingency @ 25%
Auxiliary equipment and services
Total Capital Cost
PRODUCTION COST ($/t HjSO^)
Operating Cost:
Supervision
Operating labour
Utilities 3
Operating supplies
Maintenance^
Indirect cost
Subtotal
Contingency (§10%
Total operating cost
Capital Charges:
Amortization and Interest (§ 15 years
and 10%/yr
Total Production Cost
Continuous
Gas only
530
12
-
11 880 000
2 970 000
1 485 000
16 335 000
0.54
1.06
1.61
0.28
2.89
0.71
7.09
0.71
7.80
11.51
19.31
Variable
Gas only
530
_
5-8
19 499 000
4 875 000
2 437 000
26 811 000
0.54
1.06
2.86
0.28
4.74
0.71
10.19
1.02
11.21
18.88
30.09
Continuous Gas Base Load
with Variable Gases
530
12
5-8
14 799 000
3 700 000
1 850 000
20 349 000
0.54
1.06
2.01
0.28
3.59
0.71
8.19
0.82
9.01
14.33
23.34
1 070
12
5-8
22 363 000
5 591 000
2 795 000
30 749 000
0.26
0.60
1.97
0.28
2.73
0.37
6.21
0.62
6.83
10.82
17.65
1. Includes engineering and construction overhead costs.
2. Includes natural gas, water and electric power.
3. Includes limestone for weak acid neutralization and other operating supplies.
4. @ 3.3%/year of total capital cost.
5. Includes property taxes, insurance, legal and technical counsel, etc.
t = tonne
-------
TABLE B.2.5 COST OF RECOVERING LIQUID SULPHUR DIOXIDE FROM SMELTER
GASES (EPS-3 AP-79-8)
($ CAN. 3une, 1979)
Chemical Absorption Process Physical Recovery Process
Basis For Estimates (Asarco's Dimethyl Aniline Process) (Compression & Refrigeration)
Production:
160 t/day liquid SO-, corresponding to 56 000 t annually (assuming 350 operating days)
Gas processed:
smelter gases with 12% SO2, cleaned in hot electrostatic precipitator
CAPITAL COST ($June 1979 cost level)
Liquid SO- plant1 7 103 000 6 314 000
Contingency @ 25% 1 778 000 1 578 000
Total Capital Cost 8 881 000 7 892 000
PRODUCTION COST $/t SO2 $/t SO2
Operating cost
1.
2.
3.
4.
5.
6.
Supervision 0.75
Operating labour 3.45
Utilities* , 9.85
Operating supplies 3.83
Maintenance _ 7.13
Indirect costs 1.36
Royalties 0.63
Subtotal 27.00
Contingency (§10% 2.70
Total Operating Cost 29.70
Capital Charges
Amortization <5c interest
@ 15 years and 10%/year 20.43
Total Production Cost 50.13
Includes engineering and construction overhead costs.
Includes steam, water and electric power.
Includes chemicals and other operating supplies.
@ 4.6%/year of total capital cost.
Includes property taxes, insurance, legal and technical counsel, etc.
Royalties payable for proprietary process.
0.75
3.45
9.04
0.98
6.34
1.36
21.92
2.19
24.11
18.15
42.26
t = tonne
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The majority of the non-ferrous smelters currently controlling SO- emissions
produce sulphuric acid as a by-product. It is anticipated that this trend will continue for
some time. The disposal of the by-product sulphuric acid is likely to be a problem where
a) the smelter is remote from sulphuric acid markets or b) existing sulphuric acid markets
are already supplied with lower cost acid. In these cases the smelter acid can only be
marketed, at a loss, which increases with the distance from market and the cost of
competing acid. Non-market constraints such as international trade agreements, lack of
adequate transportation facilities, etc., may prevent sale of acid in some areas. The
marketing of the acid may impose costs on the smelter which increase the cost of control
to a point where smelter closure is considered.
A related problem is the high cost and environmental problems associated with
the neutralization of acid which cannot be marketed because of high cost or other
reasons. The costs and environmental factors depend largely on the availability and cost
of a reasonable source of limestone (not always close to smelter). The environmental
problems of disposal of the neutralized acid are similar to those for the thermal power
wastes.
Another factor in marketing smelter sulphuric acid is that the demand cycle
for sulphuric acid may not coincide with the demand cycle for metals, raising the issue of
the disposal of acid, that is excess to market demand at a time when metal demand is
high.
Another waste disposal problem concerns the sludge produced in the cleaning
of the SC^-containing gases for acid production. This sludge often contains toxic metals
which can create environmental problems if disposal measures are inadequate.
Energy Consumption
Energy consumption by SC^ control technology in use varies from smelter to
smelter. The increase in energy consumption due to sulphuric acid production is partly
dependent on the strength of the SO2 streams (the higher the SO2 concentration, the
lower the energy requirement) but is a small part of total smelter energy consumption.
Where new smelting processes are used to produce a gas amenable to SO-
control in an acid plant, a net reduction in energy consumption usually results. For
example, replacement of a multi-hearth roaster - reverberatory furnace operation with a
flash furnace can lead to a net energy reduction of up to 65% of the roaster smelting
system (including the acid plant energy increase).
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50
B.2.2.2 Control Technology Available
The control technology discussed in Section B.2.2.1 (sulphuric acid and liquid
sulphur dioxide plants) can be considered as available control technology for either new
smelters or for retrofitting existing smelters. A summary of Cu/Ni smelter SO2 control
systems is given in Table B.2.6.
For those plants where it is not practical or economical to market sulphuric
acid because of remote location or market saturation, the cost of acid neutralization and
gypsum impounding must be added. The operating costs for total fixation of the sulphur in
smelter gases are shown in Table B.2.7.
Technology for fixing sulphur as elemental sulphur is also available. However,
it is much more expensive ($129/tonne sulphur) than producing either sulphuric acid or
liquid SO2. A relatively concentrated SO- stream of low oxygen content is required
together with substantial quantities of reductant. Therefore it is not applicable to most
existing smelter gas streams.
TABLE B.2.7 COST OF SULPHUR FIXATION WITH NEUTRALIZATION AND
GYPSUM IMPOUNDING OF H,SO,. STREAM
(EPS-3 AP-79-8) ($ CAN. Junef 1979)
$/Tonne Sulphur Fixed
Double Single
Catalysis Catalysis
All Gases to Sulphuric Acid and Acid Neutralization
(1) 540 t/day H2SO^ 169 164
(2) 1 100 t/day H2SO^ 144 140
Liquid SO2> Acid Production and Acid Neutralization
(1) 160 t/day SO2 and 158- 163 155 -160
540 t/day H2SO^ to neutralization
Elemental Sulphur, Acid Production, and Acid Neutralization
(1) 270 t/day elemental sulphur and
540 t/day H2$O^ to neutralization 155 152
NOTE: Liquid SO2 and elemental sulphur are produced from high-grade continuous gas
streams. Lower-grade variable converter gases are processed to sulphuric
acid, which is neutralized and impounded.
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TABLE B.2.6 COPPER/NICKEL SMELTER SO2 CONTROL SYSTEMS
Smelter Process
Technology Cost
Multi-hearth roaster, Med.
reverb., converter
Multi-hearth roaster, Med.
reverb., converter
Fluid-bed roaster, Med.
reverb., converter
Fluid-bed roaster, Med.
reverb., converter
Fluid-bed roaster, Med.
reverb., converter
Fluid-bed roaster, High
electric furnace,
converter
Fluid-bed roaster, High
electric furnace,
converter
Direct furnace Low
smelting, con-
verter (Inco,
Outokumpu, Noranda)
Direct furnace Low
smelting, con-
verter (Inco,
Outokumpu, Noranda)
Technology
Availability
High
High
High
High
High
High
High
High1
High
Continuous Low+ Med.
smelting
(Mitsubishi,
Noranda)
Hydrometallurgy High
1 Unknown
2 Can be used only for
Low3
Energy
Consumption
High
High
High
High
High
Very
High
Very
High
Low
Low
Low
High to
Very High
SO2Control System
Technology
Non-regenerative
FGD
Regenerative
FGD + Acid
Acid plant on roaster
Acid plant on roaster
& non-regenerative FGD
on weak gas streams
Acid plant on roaster
& regenerative FGD on
weak gas streams & acid
plant
Acid plant on roaster,
electric furnace,
converter
Acid plant on roaster,
electric furnace, con-
verter plus FGD system
on weak gas streams
Acid plant on flash
furnace ic converter
Acid plant on flash
furnace plus FGD
system on weak gas
streams
Acid plant
?
SO,
Control %
To 85%
To 85%
To 45%
To 90%
To 90%
To 90%
To 95%
To 90%
To 95%
To 98%
To 99.5%
Availability Operating Energy
Cost Technology Reliability Consumption
High Low Low High
High Low Low High
Low High High Low
High Low Low High
High Low Low High
Low High High Low-
Med.
Med. Med. Med. Med.
Low High High Low
Med. Med. Med. Med.
Low High High Low
? ? ? ?
By-Product
Sulphur compound for
waste disposal
Sulphuric acid
Sulphuric acid
Sulphuric acid and
sulphur compound for
waste disposal
Sulphuric acid
Sulphuric acid
Sulphuric acid and
sulphur compound for
waste disposal
Sulphuric acid
Sulphuric acid and
sulphur compound for
waste disposal
Sulphuric acid
Elemental sulphur
clean copper concentrates.
3 Problems with precious metals recovery, limited operating experience; could be considered for some special cases
Source: Background document in preparation
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52
The uncertainties in the data base are similar to those discussed in
Section B.2.2.1 except that the capital cost uncertainty is estimated at + 25% and the
operating cost uncertainty is estimated at no greater than + 30%.
By-product disposal problems are basically the same as in those discussed in
Section B.2.2.1 since the technologies used are the same. The only exception is that the
problems are likely to be more frequent since the presently controlled smelters may have
already captured much of the existing sulphuric acid market. If elemental sulphur is
produced, the disposal problems are minimal, even if the sulphur has to be stockpiled.
The energy consumption is similar to that discussed in Section 2.2.1 except in
the case of elemental sulphur production, which is an energy-intensive process.
B.2.2.3 Emerging Control Technology
As previously mentioned, the most common mode of collecting SOj in the
smelting industry is to use a sulphuric acid plant. The gases from fluid-bed roasters and
converters (sometimes) are high enough in SO- concentration for direct processing in a
conventional acid plant. This is the lowest-cost approach and recovers a usable by-
product. However, the 0.5 to 1.5% SO- average concentration in reverberatory furnace
off-gas is not sufficiently high for direct processing of the gas in a conventional sulphuric
acid plant. For this reason, flue gas desulphurization (FGD) systems have been
incorporated at a few smelters under specific conditions. They may be classified as
regenerative and non-regenerative; the former produces $©2 as a more concentrated gas,
and the latter generally converts it to a throwaway by-product.
The non-regenerative systems essentially neutralize the SO- and place it in a
stable form which can be disposed of with minimal adverse effects on the environment.
Most regenerative systems absorb the SO- and then regenerate it as a more concentrated
stream which can then be used to make either liquid SO-, sulphuric acid, or sulphur. In
those cases where the sulphuric acid market is such that additional production is not
saleable, the non-regenerative systems would seem to be the logical choice for controlling
SO- from the smelter reverberatory furnace. In those cases where a usable by-product is
desired, then several possible concentration systems have been proven feasible at full-
scale operations on reverberatory furnace off-gases. The costs, however, are very high
and each retrofit system must be considered on an individual basis. Of the non-
regenerative throwaway systems, the one that has received the most use for collecting
SO2 is the lime/limestone gypsum system. Of all the potential regenerative
(concentration) systems that have been considered, the metallurgical gas experience
-------
53
has been with the MgO, ammonia and the cold water adsorption systems. The citrate
process has operated on a pilot-plant scale.
Each of the FGD scrubbing systems has seen application at only one smelter;
the MgO and lime/limestone at the Onahoma smelter in Japan, ammonia at Cominco,
Canada, dual alkali at Afton, Canada and cold water at Boliden, Sweden. Flakt and
Boliden are jointly developing a citrate system for smelter weak SC>2 which is in the pilot
stage. Currently the state-of-the-art is such that FGD by wet scrubbing can be
accomplished, but there are significant financial and technical risks in the selection,
design and application of such systems owing to lack of extensive pilot experience on
various types of concentrates. Because of the nature of the scrubbing processes, energy
consumption will generally be substantial and disposal of waste products will often create
environmental problems. Work underway will provide background information for these
aspects.
The costs (capital and operating) for these systems are being developed and
will be available for inclusion at a later date.
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54
B.2.3 ALTERNATIVE PRODUCTION PROCESSES
Processes that Provide Gases More Amenable for SO2 Control
Many existing smelters have equipment such as multiple-hearth roasters and
reverberatory furnaces which produce gases too low in SO- for direct processing to
sulphuric acid. The multiple-hearth roasters can be replaced by fluid-bed roasters, and
thus up to 45% of the sulphur can be produced in an SO2 concentration high enough for
sulphuric acid production. An even greater improvement can be achieved by replacing
both multiple-hearth roasters and reverberatory furnaces by flash smelting units which
can produce 60% or more of the sulphur as high-strength SO2 gas.
Conventional converting in most smelters is a batch operation that produces a
gas stream of variable SO2 content which is difficult to process into sulphur by-products.
Continuous smelting processes such as the Mitsubishi process and the Noranda process
produce a continuous high-strength gas. However, these processes have been proven only
for certain "clean" copper concentrates.
Processes That Eliminate SO2 Formation
Hydrometallurgical processing of nickel sulphide concentrates has been
practised by one Canadian company for 20 years and the hydrometallurgical processing of
copper and zinc concentrates are in various stages of research and development. While
these processes do not produce SO2 gas, they have not been widely used owing to factors
including high costs, problems with recovery of precious metals, high energy consumption
and lack of adequate development.
Processes that Reduce Sulphur Input to the Metallurgical Processes
In some cases, it is possible to modify the ore benefication processes to reject
a greater amount of sulphide minerals than normal. This is practised, for example, in the
nickel industry where part of the pyrrhotite is rejected in the milling and concentration
stage thus reducing the sulphur to metal ratio of the concentrate entering the smelter.
Some metal values (including nickel, cobalt, platinum, etc.) are lost with the rejected
pyrrhotite, and a compromise is made between metal values lost and sulphur rejected.
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55
B.2.4 PRELIMINARY COST OF CONTROLS FOR EASTERN CANADIAN SMELTERS
Preliminary costs have been developed for one level of SO2 emission control
for eastern Canadian non-ferrous smelters. The exact level varies from smelter to
smelter depending on the present level of control, concentrate characteristics and
production processes. The costs are based on preliminary estimates. Current work under-
way will provide more accurate costs for control to this level and also will provide cost
estimates for more stringent levels of control.
The costs include modifications and/or improvements to existing operations,
replacement of some production process unit operations, modifications to flues and flue
gas cleaning facilities, sulphuric acid plants, sulphuric acid storage, handling and
transportation facilities and sulphuric acid disposal. No control of weak gas streams is
included at this time.
The estimated capital cost to reduce SO- emissions (at smelter capacity) from
2.7 million tonnes per year to 1.17 million tonnes per year (a 57% reduction) is $1.1
billion. The net increase in annualized costs is estimated at $120 to $150 million. (Note:
includes major changes at four smelters and minor changes at two smelters).
The net increase in annualized costs is equivalent to 15<: to 20£ per Ib of nickel
and 5£ to 8£ per Ib of copper.
A number of factors may change these costs as a result of further work under-
way. The costs of acid sale/disposal may be low for the remote smelters it may be
necessary to neutralize some of the acid produced, etc.
The above costs include those identified in the preliminary feasibility study
which was carried out for the Inco copper-nickel smelter at Sudbury, Ont. The estimated
cost at capacity operations for a reduction of SOo emissions from 1.1* million tonnes per
year to 0.41 million tonnes per year (6*%) was $480 million. This reduction was based on
the installation of sulphuric acid plants and major process changes. The estimated net
increase in annualized costs was $60 to $65 million (includes capital and operating costs).
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56
REFERENCES
1. Environment Canada, Air Pollution Control Directorate, A Study of Sulphur Con-
tainment Technology in the Non-Ferrous Metallurgical Industry, Report EPS 3-AP-
79-8 (April 1980).
2. Weisenberg, I.J., et al., Feasibility of Primary Copper Smelter Weak Sulphur Dioxide
Stream Control, EPA-600/2-80-152, 3uly 1980.
3. Environment Canada, Air Pollution Control Directorate, The Nickel Industry,
background paper prepared for United Nations Environment Program (draft revised
October 1980).
4. Environment Canada, Air Pollution Control Directorate, Air Pollution Emissions and
Control Technology: Copper Smelting Industry (draft report in preparation,
December 1980).
5. Environment Canada, Air Pollution Control Directorate, A Preliminary Assessment
of Feasible SO^ Emission Reductions and Costs at INCO Copper-Nickel Smelter,
Sudbury, Ontario (May 1980).
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57
B.3 MOBILE SOURCES
B.3.1 Description of Sector
In the transportation sector gasoline and diesel-powered road vehicles account
for about 70% of NO emissions while a further 20% comes from non-highway applications
of gasoline and diesel engines. Thus, with federal design emission standards in both
countries for such vehicles (and/or engines), over 90% of the NO emission inventory is
already subject to controls of varying stringency at the new vehicle/engine level.
Emissions of SO from mobile sources are negligible (about 1.5% of man-made
emissions).
B.3.2 CONTROL TECHNOLOGIES
B.3.2.1 United States - New Vehicles
In the United States, tailpipe emission standards are in effect for a variety of
light- and heavy-duty vehicles, including motorcycles and airplanes.
In examining emissions of any pollutant from road vehicles one can divide the
subject neatly into two parts: the design performance of vehicles, usually covered under
new vehicle/engine emission regulations, and the actual emissions performance of vehicles
in consumers' hands, including both the amount and kind of use each vehicle sees.
B.3.2.1.1 Light-Duty Vehicles
Current emission standards are in effect for light-duty vehicles (LDV's) which
require a 90% reduction in hydrocarbons (HC) and carbon monoxide (CO), and a 75%
reduction in nitrogen oxides (NO ) as compared to 1970 model passenger cars.
J\
There have been a series of emission control devices on passenger cars since
the 1960's; however, beginning with the 1972 production models, emission control devices
began to bring about significant reductions in air pollutants. In 1975, the catalytic
converter was introduced on a large scale and has since become the primary system for
controlling HC and CO. The technology for meeting the current automobile emission
standards employs the catalyst technology coupled with a series of electronic and vacuum
sensing devices which detect and control selected engine operating parameters. A so-
called three-way catalyst (incorporating NO reduction as well) is being used on many of
A
the 1980 production cars.
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58
All the federal emission standards apply only to new production cars. Because
the standards themselves have changed over time, and because it takes 8 to 10 years for
an effective turnover of the vehicle fleet, it will still be a number of years before the
total potential of the federal emission standards for LDV's can be fully realized.
Table B.3.1 provides a breakdown of the cost of the individual components of a
typical three-way catalyst. As can be seen, the system (which controls all three
pollutants) is estimated to cost about $300 per car. The catalyst is expected to continue
to be the primary emission control technology for the foreseeable future.
TABLE B.3.1
COST OF COMPONENTS IN A THREE-WAY PLUS OXIDATION
CATALYST SYSTEM
Component
Throttle position sensor
PCV valve
HEI (less breaker point distributor)
TVS (spark)
Electric choke
EFE
EGR (backpressure)
TVS (EGR)
Stainless steel exhaust pipe
(less steel pipe)
Air injection system
Air switching system
Feedback carburetor
(less open loop carburetor)
Three-way plus oxidation
catalyst
ECU
Oj sensor
FUO temperature sensor
Inlet air temperature sensor
Engine speed sensor
Crank angle position sensor
EGR pintle position sensor
Evaporative system
TOTAL
Source: Lingren, LeRoy H. (Rath and
Cost (1979$)
Minimum
$ -
1.1
7.7
-
1.1
4.4
7.7
-
9.9
33.0
2.2
8.8
172.7
33.0
3.3
-
-
-
-
-
11.0
$295.9
Strong, Inc.).
Maximum
$ 2.2
1.1
7.7
2.2
1.1
4.4
7.7
2.2
9.9
33.0
2.2
8.8
172.7
33.0
3.3
2.2
2.2
2.2
2.2
2.2
11.0
$313.5
March 1978. "Cost
Estimation for Emission Control Related Components/Systems and Cost
Methodology Description." EPA-460/3-78-002.
-------
59
B.3.2.1.2 Light-Duty Trucks
Because light-duty trucks (LDT's) perform different functions than passenger
cars, it is difficult to achieve the same level of emission reduction even though the same
engines are interchangeably used in many cases. Consequently, the U.S. emission
standards for LTD's are somewhat less stringent than corresponding standards for
passenger cars. For comparison, emission standards (in grams/mile) for model year 1981
LDT's and LDV's are listed below:
HC CO NOV
• - - x
LDV's (1981) 0.* 3.* 1.0
LDT's (1981) 1.7 18.0 2.3
LDT's (1983) 0.8 10.0 2.3 (possibly 1.2)
Generally, the same basic technology is used for both LDT's and LDV's. However, some of
the electronic sensors or such add-on systems as the air pump may not be required. The
cost of the control system will be very similar to that previously presented for LDV's.
B.3.2.1.3 Heavy-Duty Trucks
Heavy-duty trucks are usually divided into two categories, gasoline-powered
and diesel-powered. Control technology for both categories is available. The Clean Air
Act Amendments of 1970 require that standards be established in the U.S. which will
provide a 90%, 90%, and 75% reduction in HC, CO, and NOX as compared to that produced
in 1973. For HC and CO, the technology is available to achieve these reductions;
however, the availability of technology for achieving the required reduction in NOX,
particularly for the diesel engine, is questionable.
B.3.2.1.* Cost of U.S. FMVCP
Table B.3.2 provides a summary of the estimated annualized cost of the
FMVCP in 1987. The table includes cost savings as the result of reductions in fuel and
maintenance which resulted from the installation of more sophisticated engine controls to
meet the stringent emission standards mandated by the FMVCP.
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60
TABLE B.3.2
TOTAL ANNUAL COST OF THE FMVCP IN 1987 (1979$ X 106)
Type of Vehicle
Annual Cost of Control
Passenger Cars (LDV's)
Hardware
Fuel economy
Unleaded gasoline cost
Operating and maintenance
Altitude controls
Sub-total
Light-Duty Trucks (LDT's)
Hardware
Fuel economy
Unleaded gasoline cost
Operating and maintenance
Altitude controls
Sub-total
Heavy-Duty Trucks (HDV's)
All costs
Motorcycles
All costs
Aircraft
All costs
TOTAL COST
$6006
(5130)a
2199
(1917)
834
1992
2220
0
1062
0
300
3582
862
92
92
$6620
a Negative costs
B.3.2.2 United States - In-Use Vehicles
B.3.2.2.1 Inspection and Maintenance
Although the FMVCP has achieved significant emission reductions, the overall
performance of the program has been somewhat less than desired. This is because the
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61
control systems have historically exhibited a high rate of deterioration, primarily due to
owner or mechanic tampering in an attempt to improve driveability. There have also been
indications that the use of leaded gasoline in about 10% of automobiles equipped with
catalytic converters has reduced the overall effectiveness of the FMVCP since lead
destroys the capability of the catalyst to perform its function.
To ensure that the control systems continue to function as designed, a number
of major urban areas have adopted or plan to adopt a system of frequently inspecting
automobiles, and requiring proper maintenance on those vehicles that fail to meet the
emission standards. Such programs automatically incorporate an allowance for deterior-
ation which is dependent upon vehicle age and is taken into account during the inspection.
This system is frequently referred to as Inspection and Maintenance (I&M) and is required
by the Clean Air Act Amendments of 1977 to be implemented in all areas that cannot
meet the national ambient air quality standards by 1982.
The effectiveness of an I&M program is dependent upon many factors,
including the degree of stringency, the frequency of inspections, the training of
inspectors, etc. However, an effective I&M program can provide between 10% and 25%
more emission reduction for HC and CO than possible through the FMVCP only.
Reductions for NO through I&M are somewhat lower but generally an estimated 5% to
A
10% improvement is possible.
Inspection costs run between $5 and $10 per car and the repair cost have
averaged just under $30 for each car that failed the inspection. Generally, systems in
operation at the current time have been designed around a 30% failure rate. The
annualized cost of an I&M program to meet current U.S. air quality standards by 1987 is
estimated to be around $400 million. Potential fuel savings as a result of maintaining
proper tuning of the cars may reduce this cost to approximately $250 million.
B.3.2.2.2 Transportation Control Measures
If emission reductions beyond those achievable with tailpipe standards are
required, transportation measures can be used. These measures involve a host of possible
alternatives ranging from simple cost-saving programs such as carpooling to extensive
major rerouting of traffic, gasoline rationing or mass transit systems. Because of the
variety of options, it is difficult to estimate the cost of such programs. However, there
are indications that the simple and inexpensive options do offer some emission reduction
potential (maybe 5%). Generally, these less expensive options also offer some form of
fuel savings.
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62
B.3.2.3 Canada - New Vehicles
In Canada new light-duty vehicles are currently subject to an emission
standard for NO of 3.1 grams per mile (gpm). Many of the vehicles, however, meet the
A
U.S. standard of 2 gpm for the late 70's models and, from 1981 on, 1 gpm. Thus the
weighted average design emission level would be about 5 gpm until 1973, 2.8 gpm to 1980
and 2.3 gpm thereafter. The current 3.1 gpm standard is under review and the decision on
the emission standard for 1985 and later models is expected within 18 months.
B.3.2.* Canada - In-Use Vehicles
The actual NO emissions from vehicles in consumers' hands are affected by a
A
large variety of factors including ambient temperature, individual driving style, state-of-
tune of the vehicle, mode of operation, and, recently discovered to be of major
importance, direct tampering with NO emission controls.
A
Investigations into tampering with EGR valves have indicated that the
tampering rate may well be as high as 30% rather than the 5 to 10% previously estimated.
Thus, we are no longer satisfied that our emissions model is accurate. With that caveat
our current estimate is that the average (whole fleet) emissions were in the neighborhood
of 4.5 gpm until 1975, about 3.5 from then until 1980 and, in the absence of further
investigation/control on the tampering rate, about 3 gpm thereafter.
A national guideline (I/M) for the control of excess emissions and fuel
consumption by in-use vehicles will soon be promulgated. It advocates a "phase-in"
approach, starting with new vehicles and using very stringent standards that would be
equivalent to a 75% failure rate on the U.S. program discussed in B.3.2.2.1. As a result a
mature program is expected to reduce CO emissions by 40 to 50%, HC emissions by 20%
and fuel consumption by 3 to 5% on the subject fleet. The dollar value of the gasoline
savings will exceed the total societal cost of the program.
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63
B.* PETROLEUM REFINING
B.4.1 Canadian Petroleum Refineries
Location; There are 33 operating refineries located across Canada, with k in
the Maritimes, 7 in Quebec, 8 in Ontario, 1 in the Northwest Territories and 13 in Western
Canada.
B.4.1.1 Production Processes
Refineries differ in their processing layout, depending on their capacity, type
of crude oil processed, complexity of the processes involved, product specifications, and
product requirements. Generally, the following processes are used in petroleum refining
after washing crude oil with water for salt removal (desalting).
B.4.1.2 Separation
(a) Atmospheric distillation, to separate light and/or heavy oil fractions
(b) Vacuum distillation,to separate heavy oil fraction into gas-oil, lube-oil, and residue
B.4.1.3 Conversion
(a) Catalytic cracking
(b) Catalytic naptha reforming
(c) Light hydrocarbon processing
(i) polymerization
(ii) alkylation
(d) Isomerization
(e) Coking
(i) Delayed
(ii) Fluid-bed
(g) Desulphurization of fuel oils
(h) Sulphur recovery by Claus Process
B.*.1.4 Treating; removal of r^S and mercaptans from light hydrocarbons by amine
and chemical treatment (sodium plumbite or copper chloride).
B.4.1.5 Blending; Blending of base stock to meet the applicable specifications.
B.4.1.6 Emissions; Annual emissions for this industry sector are
263 OOP tonnes/year SC (92 000 from refining processes; 171 OQQ from combustion
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64
processes) and 45 800 tonnes/year NO (4 400 from refining processes, 41 400 from
A
combustion processes). These emissions result from refinery process heaters and boilers,
sulphur recovery plants, fluid catalytic cracking units, incinerators and flares.
Available technologies could be installed to substantially reduce SC^ emissions
from fluid catalytic cracking (FCC) regenerators and sulphur plants on existing plants.
Emissions could also be reduced significantly if the refineries switched to low-sulphur
fuels in the refinery fuel system.
This industry sector is not presently being rigorously addressed. However, as
strategy options are developed, several major metropolitan areas that contain refineries
could be involved, necessitating a further assessment of this sector.
B.4.2 United States Petroleum Refineries
In terms of total mass emissions of SO and NO , petroleum refineries
A J\
contribute a relatively small percentage of the total U.S. emissions of these pollutants.
Specifically, refineries contribute 3.9% of the SO emissions and 0.85% of the NO
A A
emissions. Geographically, a majority of the U.S. refinery capacity is in the Gulf Coast
and West Coast areas of the United States, but a significant portion is in the north central
(2.4 x 106 BPD, 14%) and northeastern (1.8 x 106 BPD, 10%) parts of the country.
Existing fuel gas and sulfur plant regulations, anticipated regulations for sulfur oxides
from FCC units and anticipated regulations for industrial boilers indicate that any
increased refinery capacity will have the minimum emissions of SO and NO .
A A
No detailed assessment has been published on the contributions of SO and
A
NO emissions resulting from refinery fuels used in process heaters and boilers.
A
No grass-roots refinery capacity is expected to be added in the near future.
However, an indeterminate amount of refinery upgrading which includes FCC capacity is
expected to be added over the next few years. This upgrading may increase or decrease
SO and NO emissions depending on the extent to which new controlled processes replace
A A
old uncontrolled ones. There is no study available at this time that predicts what refinery
emissions will be as a result of the anticipated upgrading.
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65
B.5 INDUSTRIAL, RESIDENTIAL, COMMERCIAL FUEL COMBUSTION
Sulphur and nitrogen oxide emissions from non-utility fuel combustion in
Canada are about 1.1 million tons and 600 000 tons per year respectively. For the United
States, these sources account for some 7.3 million tons of SO2 emissions and 7.1 million
tons of NO emissions.These numbers include those emissions already identified in the
J\
fuel combustion portion of the larger industrial sectors. The vast majority of these
emissions are associated with heavy and light oil combustion and as a result are mainly
confined to the larger urban and industrial areas.
Control technology in this sector is size specific, with flue gas desulphuri-
zation and low-NO combustion modifications applicable to the larger-sized combustion
units of the industrial sector. Control technology in the commercial and residential
sector has not progressed as rapidly as with the larger boilers, primarily because of the
smaller emission reduction potential. However, it is known that some emission reduction
is economically possible in the commercial and residential sectors.
Oil desulphurization to reduce SO- emissions is a well-developed technology
although no facilities exist in Canada. Residual (heavy) oil can be readily desulphurized to
0.5%S and light oils to 0.3%S. The cost varies with the type of crude oil and increases
with the degree of desulphurization.
The main role for desulphurized oil with respect to the acid deposition problem
would be to reduce area emissions from large urban areas.
B.5.1 Industrial Combustion Units
As in the utility boiler sector, a variety of control strategies can be used to
reduce sulphur oxide emissions. These strategies include low-sulphur fuel, wet or dry flue
gas desulphurization and fluid-bed combustion. Low-sulphur coal and hydro desulphuriza-
tion of fuel oil can be used to reduce SO emissions to about 1.2 lb/10 Btu and 0.2 lb/10
Btu, respectively. Although flue gas desulphurization can lower potential sulphur oxide
emissions by up to 90%, there are no units in operation at present in Canada. Fluid-bed
combustion can achieve a 70-85% SO7 reduction and about a 70% reduction in NO at
£ A
operating costs competitive with flue gas desulphurization. The capital cost of the fluid-
bed boiler will exceed that of a conventional coal combustion system.
Combustion modification is the principal method of controlling NO emissions.
The NO emission limits achievable using combustion modification are dependent upon the
A
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66
fuel type (oil, coal, gas) and firing method. Studies are presently being done to delineate
the optimum methods available.
The cost of retrofitting industrial boilers is highly uncertain since space
limitations and other restrictions can cause significant variations.
B.5.2 NOX and SO2 Control Technologies Available
The dual-alkali wet flue desulphurization process is the dominant sulphur oxide
control technology for industrial boilers. Sodium once-through systems are used in
industries which produce a sodium-containing waste stream such as pulp and paper and
textile mills (from de-ionizer recharging). There are two commercial installations of the
lime spray dryer SO2 control process. The cost of SO2 control technology varies as a
function of boiler size, load factor, and fuel sulphur content. Thus the uncertainty in
capital and annual costs can be large. The capital costs and operating costs shown in
Figures B.5.1 and B.5.2 can be in error by as much as +40 percent.
Frequent operating or other scheduled shutdowns in some industries could
create problems in the operating reliability of some control processes. The disposal of
scrubber sludge also presents a problem.
Field trials are underway on retrofitting a coal-fuel unit to the low-NO firing
A
mode through burner modifications. Although these are being performed in a utility unit,
the technology is expected to be available to the larger-sized industrial coal-fired units.
Feasibility studies and modification scheduling are being conducted for the retrofitting of
an industrial coal-fired unit to Limestone Injection/Multi-stage Burners for the
simultaneous reduction of SO, and NO . This field trial is being performed on a military
£* A
base in New Brunswick and is expected to demonstrate this technology further, for use in
the large industrial and utility boiler sector.
The construction of a fluidized bed combustion unit is scheduled for early
spring 1981. The operation of this unit will provide data on reliability, costs and
performance of simultaneous sulphur and nitrogen oxide control from high-ash, high-
sulphur coals in addition to other coals presently available in eastern Canada.
B.5.3 Residential and Commercial Combustion Units
Control technology in these sectors has not progressed as rapidly as for the
larger boilers, primarily because of the considerably smaller emission reduction potential
for this sector. However, research has estimated that some emission reduction is
economically possible for commercial and residential boilers.
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67
400Or
3OOO
"5
•D
"o
c
« 2OOO
(0
0
U
5
"5.
a
o
1OOO
Wellman-Lord
Double Alkali
Limestone
Sodium Throwaway
29.3 58.6 87.9
(100) (200) (300)
Size in MWt (1O6Btu/hr)
117.2
(400)
FIGURE B.5.1.
FGD CAPITAL COSTS VERSUS UNIT SIZE
(3.5% S coal, 9O% removal)
Source:
Technical Assessment Report for Industrial Boiler Applications:
Flue Gas Desulfurization
Industrial Environmental Laboratory; U.S. E.P.A., November 1979
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68
2OOOr
1500
o
•o
n
O
u
•o
ID
N
"3
3
C
C
1OOO
50O
Dual Alkali
Sodium Throwaway
29.3 58.6 87.9
(100) (200) (300)
Size in MWf (1O8 Btu/hr)
117.2
(400)
FIGURE B.5.2.
F6D ANNUALIZED COSTS VERSUS UNIT SIZE
(3.5% S coal. 9O% removal)
Source:
Technical Assessment Report for Industrial Boiler Applications:
Flue Gas Desuifurization
Industrial Environmental Laboratory; U.S. E.P.A., November 1979
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69
Research by the U.S. Environmental Protection Agency has shown that proper
maintenance and operation of existing commercial and residential heating units are the
most economical means of reducing emissions from these sources. Such practices also
provide fuel savings which can potentially offset maintenance cost. Education of owners
and operators is the best means of achieving the desired maintenance and operating
practices.
In a recent study of home heating units, it was found that by identifying and
replacing untuneable units and by tuning the remaining units, smoke could be reduced by
50%, CO by 81%, HC by 90% and filterable particulate by 24%. A recent EPA study
indicates that by proper design of residential heating systems, it is possible to achieve a
65% reduction in NO emissions, and at the same time, to reach a steady state thermal
yv
efficiency of 70 to 80%. The fuel reduction potential was found to approximate 20
percent. The prototype version of the system has been field-tested, and the above results
are from this test.
Cost figures for this system are not available, but indications are that any
increase in cost will be greatly offset by the fuel savings and increased thermal
efficiency.
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70
B.6 INCINERATORS
Canada
Municipal incinerators emit significant amounts of particulate matter, and
lesser amounts of sulphur dioxide and nitrogen oxides to the atmosphere. A large
municipal incinerator (1000 tonnes per day), for example, emits 550 tonnes per year (tpy)
of particulates, 300 tpy of sulphur dioxide, and 350 tpy of nitrogen oxides (1). Emissions
per tonne of material incinerated tend to be equivalent or less than other types of
controlled incineration such as controlled air incinerators or sewage sludge incinerators.
Control techniques for particulate emissions from incinerators are fairly
advanced; however, little, if anything, has been done to reduce sulphur dioxide or nitrogen
oxide emissions. Given the relatively low concentration of sulphur in municipal refuse and
the low operating temperature of municipal incinerators and consequently low NO
production compared to fossil-fuel combustion, it would be impractical to achieve
significant reduction in these emissions. The EPA control techniques document for
nitrogen oxides suggests alternative disposal methods (e.g., landfill) as the only practical
control technique for nitrogen oxides from incineration.
Emissions of SO- and NO from incineration in Canada are 3 245 tpy and
£ A
5 094 tpy respectively. Large incinerators are located in Quebec City, Montreal, Toronto
and Hamilton. The emissions of SO- and NO are a small part of overall Canadian
£ A
emissions, and incineration is not considered to be of significance in the acid rain
problem.
There are no hazardous waste incinerators operating in Canada.
U.S. Solid and Hazardous Waste
As a generalization, much of the municipal solid waste incineration is centered
in the Great Lakes and New England areas while hazardous waste incineration is limited
by comparison but is likely to be more ubiquitous.
Estimated emissions of NO from solid waste disposal in the U.S. indicate a
decrease from about 0.6 million tpy in 1968 (AP-84), to 0.3 million tpy in 1970, to a
current level of about 0.1 million tpy (draft criteria document for NO , 6/79) because of a
A
reduction in the amount of waste burned. Air pollution control systems currently applied
to such incinerators or those likely to be required in the future do not generally remove
appreciable amounts of SO and NO .
** J\
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71
REFERENCES
1. EPA Publication AP-42, "Compilation of Air Pollutant Emission Factors", third
edition, August 1977.
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72
B.7 PULP AND PAPER INDUSTRY
B.7.1 United States Pulp and Paper Industry
It is estimated that total SO and NO emissions from process operations are
A A
approximately 157 000 and 45 000 tonnes per year respectively from about 400 mills. The
combustion of fossil fuels for the production of additional steam and power in this
industry sector contributes an additional 720 000 and 180 000 tonnes per year of SO and
NO respectively. There are no other significant acid rain precursor emissions or direct
A
acidic emissions from this industry sector. Since this industry is not expected to undergo
major expansions during the balance of this century, its relatively minor contribution to
the total transboundary air pollution problem is unlikely to be altered.
As regards the geographical distribution of pulp and paper facilities, about one
third are located in the northeastern region, about one quarter are in the Pacific
northwest, and the balance are widely dispersed. The low gross emissions of SO ,
A
together with the wide geographic distribution of the mills and the expectation that no
significant expansion of this industry will occur, indicate that transboundary transport of
acid rain precursor emissions from the pulp and paper industry is of secondary importance.
B.7.2 Canadian Pulp and Paper Industry
It is estimated that total SO and NO emissions from process operations are
A A
approximately 88000 and 13000 tonnes per year respectively from 114 mills. The
combustion of fossil fuels for the production of additional steam and power in this
industry sector contributes an additional 144 000 and 45 000 tonnes per year of SO and
yv
NOx respectively. These emissions are split roughly 80/20 between eastern Canada and
British Columbia. It is anticipated that a current federal-provincial modernization
program will reduce existing emissions. Similiar to the U.S., no significant expansion of
production capacity is anticipated in the near term. These factors indicate, as in the
U.S., that transboundary transport of acid rain precursor emissions from the pulp and
paper industry is of secondary importance.
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73
C HISTORICAL EMISSION TRENDS
C.1 INTRODUCTION
The primary objective in developing historicai emission trends is to recreate
the emission situation of several decades ago so that such data can be used in atmospheric
models to provide an insight into sulphur deposition rates for those periods. These rates
can then be compared to current deposition rates for an indication of the rate of
degradation of the environment with time.
Factors other than strict fluctuations in the magnitude of acid precipitation
precursor emissions, however, have also played a role in changes in deposition rates with
time and these should not be overlooked. For example, concurrent with increases in SO-
and NO emissions over the past 40 years has been a substantial increase (by a factor of
X
five) in the stack height for utility sources. Also, SO2 emissions from coal burning have
changed in most regions from a wintertime peak to a summertime peak in emission rate.
The importance of such factors has not been well determined at this time.
-------
C.2 IN THE UNITED STATES
Methodology: Emission calculations for the United States have been made on a
broad national scale as well as on a much more refined scale. Similar methodologies have
been employed in making these calculations.
Historically, data records on emissions and emission rates have been main-
tained only since the early 1970's. Consequently, in order to recreate such emissions, it is
necessary to use other information. One of the most accepted approaches to
retrospectively calculating emissions is to employ fuel use data. Records on these data
are available and provide an indication of how various type fuels have been consumed by
different type sources. Knowing the emission rates of various sources, the sulfur content
of the fuel, and the type of emission controls on a particular type source, it is possible to
estimate the emissions of various source categories.
Data Uncertainty: It is extremely difficult to provide an accurate estimate of
the data uncertainty in making the above calculations. Generally, the fuel use data on a
national scale are quite accurate. However, as one attempts to extrapolate fuel use to a
particular type, some errors of uncertain magnitude enter. Moreover, records on the
chemical analysis of the fuel were not maintained until the 1960s and therefore one must
make assumptions for such important factors as sulfur content of the fuel used.
Generally, it is felt that the emission estimates for the utility sector are
probably within 25% accuracy for the post-1965 years; however, no accuracy figures are
available for the pre-1965 estimates.
No attempt has been made to assess the accuracy of the calculations for other
sources, except to examine the general trends exhibited to determine areas where the
trends are well outside of what might be expected.
National Trends in Emissions: Table C.2.1 provides a summary of the
emissions of various air pollutants in the United States between the years 1940 and 1976.
The data in the table are the estimated total emissions throughout the United States for
the year of record indicated. Additional information on the total national emissions from
various sources along with an expanded discussion of the procedures for calculating these
emissions can be found in the publication "National Air Pollutant Emission Estimates
1940-1976", EPA-450/1-78-003, July 1978, available through the Office of Air Quality
Planning and Standards, U.S. EPA, Research Triangle Park, N.C. 27711. Table C.2.2
provides an indication of the information contained in the above references.
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75
TABLE C.2.1 SUMMARY OF NATIONWIDE TOTAL EMISSION ESTIMATES
Units of
measurement
106 tons
per year
10 tonnes
per year
Year
mo
1950
1960
1970
1971
1972
1973
1974
1975
1976
1940
1950
1960
1970
1971
1972
1973
1974
1975
1976
S0x
21.9
24.5
24.1
32.1
30.8
31.7
32.7
30.9
28.5
29.9
19.5
22.0
21.4
29.1
27.9
28.8
29.7
28.2
25.7
26.9
TSP
27.5
29.1
28.3
24.8
23.4
22.3
21.8
19.2
16.0
14.9
24.8
26.2
25.6
22.6
21.4
20.3
19.9
17.5
14.4
13.4
CO
86.7
96.6
111.0
109.9
110.2
112.3
108.2
100.7
95.3
96.6
78.3
87.0
100.0
99.8
100.2
102.0
98.3
91.5
85.9
87.2
HC
19.0
23.5
31.2
32.9
32.1
32.8
32.7
31.6
29.1
30.9
17.0
21.2
28.0
29.7
29.3
29.7
29.8
28.6
26.2
27.9
NOX
6.7
9.0
11.5
22.3
23.3
24.3
25.1
24.7
24.4
25.4
6.0
8.1
10.5
20.4
21.3
22.2
22.9
22.6
22.2
23.0
-------
76
TABLE C.2.2 ESTIMATED NATIONWIDE EMISSIONS, 1940e
Units of
measurement
106 tons
per year
Source
Transportation
Highway vehicles
Non-highway vehicles
Stationary fuel combustion
Electric utilities
Industrial
Residential, commercial,
institutional
Industrial processes
Chemicals
Petroleum refining
Metals
Mineral products
Oil and gas production
and marketing
Industrial organic
solvent use
Other processes
Solid waste
Miscellaneous
Forest wildfires and
managed burning
Agricultural burning
Coal refuse burning
Structural fires
Miscellaneous organic
solvent use
Total
S0x
0.7
0.0
0.7
16.8
2.9
9.3
4.6
3.9
0.1
0.2
3.2
0.2
0.0
0.0
0.0
0.0
0.5
0.0
0.0
0.5
0.0
0.0
21.9
TSP
0.5
0.2
0.3
9.6
2.0
6.2
1.4
11.0
0.4
0.0
3.7
4.4
0.0
0.0
2.5
0.6
5.8
3.8
1.6
0.4
0.0
0.0
27.5
CO
29.0
26.3
2.7
3.7
0.0
0.3
3.4
7.2
4.4
0.2
2.3
0.0
0.0
0.0
0.3
4.3
42.5
32.1
9.1
1.2
0.1
0.0
86.7
HC
6.0
5.4
0.6
0.8
0.0
0.3
0.5
3.5
1.5
0.5
0.1
0.0
1.2
0.1
0.1
0.9
7.8
5.5
1.9
0.2
0.0
0.2
19.0
NOX
1.8
1.5
0.3
3.5
0.6
1.9
1.0
0.1
0.0
0.1
0.0
0.0
0.0
0.0
0.0
0.1
1.2
0.9
0.2
0.1
0.0
0.0
6.7
A value of zero indicates emissions of less than 50 000 tons per year.
Historical Emission Trends on Regional Scale. To examine emission trends on
a regional basis in the United States, a data file has been constructed which also uses
historical fuel use figures to calculate emissions of SO9 and NO from various categories
£ J\
of sources. The basic file contains emissions at the individual state level for the following
source categories:
-------
77
Electric Utilities
Industrial
Commercial/Residential
Pipelines
Highway Vehicles
Gasoline-Powered
Diesel-Powered
Miscellaneous
Railroads
Vessels
Misc. Off-Highway Mobile
Chemicals
Primary Metals
Mineral Products
Petroleum Refineries
Others
The file currently contains data for 33 eastern states plus the District of Columbia.
Years on record for the file are 1950, 1960, 1965, 1970, 1975, and 1978.
For the electric utility sector, all power plants greater than 25 megawatts
have been identified and located by the appropriate county within each state for each
year of record. Emissions of SO2 and NO have been determined for each year for all
such power plants. Consequently, it is possible to identify power plant emissions on a
county-by-county level for each year of record for all 33 states. The file identifies each
power plant by name, size, county location, and SO, and NO emissions from coal, oil, and
£» X
natural gas consumption. The file also contains fuel use information and has some limited
data on stack height.
To distribute the non-power plant emissions to a county level, work is
underway using historical census data to assign the statewide emissions to the county
level. The technique to be used is to apportion the emissions to the county base on a
historical population basis. The Brookhaven National Laboratory is currently conducting
this work.
As an example of the information from this file, a sample state and county are
outlined below in Table C.2.3:
-------
78
TABLE C.2.3 SOV EMISSIONS (x 103 tons)
State of Kentucky
Non-PP
Power Plant
Total
County of Jefferson, Ky
Power Plant
Canal
Cane Run
Mill Creek
Paddy's Run
Waterside
Total PP
1950
34.5
28.6
637T
1950
1.9
7.4
0.9
10.2
1955
153.6
251.2
404.8
1955
1.5
3.0
10.4
0.8
15.7
1960
262.3
368.8
631.1
1960
11.4
9.4
20.8
1965
310.7
603.3
914.0
1965
17.0
4.1
21.1
1970
198.4
1082.5
1280.9
1970
27.1
3.5
30.6
1975
117.7
1349.1
1466.8
1975
22.4
17.8
0.7
40.9
1978
108.8
1221.2
1330.0
1978
19.1
21.0
2.3
42.4
Non-Power Plant - Jefferson County, Ky
Information not on - file
To assist in examining the historical emission trends on a regional scale, tables
have been prepared in which the states are grouped according to the appropriate EPA
regional offices (Regions I through V). Trends in SO and NO emissions for each state
yv A
along with a summary for each grouping of the states (by regional office) are shown in the
following tables (Tables C.2.4 and C.2.5). . To some extent, the regional office grouping
can be used to examine trends in the following broad geographical areas of the country:
Regions I and II - Northeast
Region III - Mid-Atlantic
Region IV - Southeast
Region V - Midwest
In the northeast, SO emissions appear to have decreased by about 40%.from
1955 to 1978. While the trend may be real, it should be noted that the data for 1950 and
1955 are less reliable than for the more recent years. Part of this
-------
79
TABLE C.2.4
HISTORICAL TRENDS IN SO2 EMISSIONS
x 103 tons
State
Conn.
Maine
Mass.
New Hamp.
Rhode Island
TOTAL
New York
New Jersey
TOTAL
Delaware
D.C.
Maryland
Penn.
Virginia
West Va.
TOTAL
Alabama
Florida
Georgia
Mississippi
Kentucky
North Carolina
South Carolina
Tennessee
TOTAL
1950
130.3
37.8
906.4
73.3
67.7
1215.5
847.0
* 1308. 8
*2155.8
105.4
32.4
398.9
* 970.2
157.2
243.5
*1907.6
139.5
225.5
119.9
46.9
113.1
306.1
44.5
97.3
1092.8
1955
139.1
45.6
956.7
89.7
80.2
1311.3
1126.0
*1486.2
*2612.20
136.0
31.0
515.5
2138.4
277 A
617.8
3716.1
522.7
350.5
163.6
43.3
404.8
347.4
84.3
369.2
2285.8
1960
EPA-
241.6
70.2
374.6
29.1
87.3
802.8
EPA-
1427.4
482.6
1965
REGION I
457.6
97.0
443.2
41.2
41.2
1080.2
REGION II
1645.4
623.4
1910.00 2268.8
EPA-
196.1
38.5
518.2
2362.2
171.4
529.7
3816.1
EPA-
613.5
341.1
198.2
41.1
631.1
232.4
115.9
731.2
2904.5
REGION III
217.8
47.9
588.1
2546.8
188.1
776.8
4365.5
REGION IV
892.3
501.6
303.0
44.6
914.0
294.4
121.7
771.5
3843.1
1970
317.3
82.0
584.4
95.9
60.1
1139.1
1455.0
590.2
2045.2
223.4
78.0
467.7
2245.7
475.2
979.7
4469.7
979.1
862.3
410.4
79.4
1280.9
533.2
185.4
988.1
5318.8
1975
191.0
67.8
362.2
75.4
24.3
720.7
1079.0
341.0
1420.0
193.6
27.1
322.3
2130.8
381.0
1220.0
4274.8
986.5
827.9
571.4
193.0
1466.8
500.5
202.3
1141.9
5890.3
1978
112
66
402.2
67.8
19.7
667.7
1041.1
323.7
1364.8
188.2
17.6
357.3
1900.0
359.9
1049.5
3872.5
762.1
685.9
707.0
264.3
1330.0
562.3
288.6
1162.8
5763.0
-------
80
TABLE C.2.4 HISTORICAL TRENDS IN SO2 EMISSIONS (Cont'd.)
x 103 tons
State
1950
1955
1960
1965
1970
1975
1978
EPA - REGION V
Illinois
Indiana
Mich.
Minn.
Ohio
Wise.
TOTAL
Arkansas
Iowa
Louisiana
Missouri
Texas
* 869.8
533.1
519.2
504.5
* 885.0
217.2
*3528.8
41.0
173.2
233.0
715.7
1011.7
2172.1
1174.2
702.7
536.4
2344.9
304.2
7234.5
36.7
258.0
261.2
*2155.1
1073.8
2452.9
1840.8
1085.5
391.8
2933.2
604.0
9308.2
OTHER
26.1
364.5
219.4
582.6
900.0
2791.4
2180.3
1521.7
419.8
3181.2
703.8
10798.2
STATES
29.9
440.8
268.7
674.9
1074.3
2506.5
1941.5
1520.9
450.7
3125.2
322.3
9867.1
37.0
370.2
318.0
1107.3
1136.8
1950.6
1980.0
1450.6
382.3
3271.2
166.6
9201.3
68.6
314.0
295.1
1174.3
1123.8
1747.2
1848.2
1117.8
379.0
3115.3
663.6
8871.1
121.6
385.0
359.0
1307.7
1244.8
*Questionable data
TABLE C.2.5 HISTORICAL TRENDS IN NO EMISSIONS
x 103 tons
State
Conn.
Maine
Mass.
New Hamp.
Rhode Island
TOTAL
New York
New Jersey
TOTAL
1950
85
44
164
18
33
346
493
281
775
.7
.6
.2
.2
.5
.2
.6
.5
.1
1955
100
46
195
22
32
397
. 606
319
925
.0
.7
.0
.6
.9
.2
.5
.1
.6
1960
EPA
152
49
254
31
45
"332
EPA
767
362
1129
1965
- REGION I
.6 169.
.1 60.
.9 303.
.1 39.
.2 36.
.9 608.
- REGION II
.0 919.
.7 439.
.7 1358.
0
2
4
7
4
7
1
1
2
1970
202.0
75.8
359.9
63.7
55.2
1000.3
538.3
1538.3
1975
182.
72.
340.
67.
44.
"7077
869.
462.
1331.
0
7
2
5
9
3
3
0
3
1978
183.0
76.7
364.3
66.9
42.4
733.3
908.9
494.4
1403.3
-------
81
TABLE C.2.5 HISTORICAL TRENDS IN NOv EMISSIONS (Cont'd.)
A
x 103 tons
State
Delaware
D.C.
Maryland
Penn.
Va.
West Va.
TOTAL
1950
19.8
30.8
108.9
479.1
183.8
118.9
941.3
1955
30.1
34.3
138.5
693.2
228.0
217.4
1341.5
1960
EPA-
51.2
35.0
222.9
1020.2
259.9
225.0
1814.2
1965
REGION III
61.1
38.1
292.5
1143.1
361.8
322.3
2218.9
1970
71.9
58.3*
298.8
1089.2
433.5
346.9
2298.6
1975
65.2
36.5
294.9
1093.1
420.8
470.8
2381.3
1978
70.6
33.5
313.9
1120.7
435.2
462.4
2436.3
EPA- REGION IV
Alabama
Florida
Georgia
Kentucky
Mississippi
N.C.
s.c.
Tenn.
TOTAL
Illinois
Indiana
Mich.
Minn.
Ohio
Wise.
TOTAL
172.6
206.8
170.8
145.4
97.1
192.0
87.4
164.9
1237.0
600.1
296.6
318.3
164.7
498.2
196.5
2074.4
367.0
263.4
198.9
208.0
80.8
210.7
125.4
232.7
1686.9
890.4
447.2
382.9
187.6
771.5
215.4
2895.0
308.6
321.5
226.9
279.1
151.2
290.0
150.2
335.9
2063.5
EPA-
895.9
584.9
587.3
240.1
960.5
296.6
3565.3
448.3
420.8
296.7
377.6
196.4
376.2
178.2
380.3
2674.5
REGION V
1063.7
555.2
746.4
275.5
1082.3
367.4
4090.5
416.1
552.1
398.1
497.2
304.5
546.4
237.3
467.1
3418.8
1119.8
576.4
846.6
331.3
1165.1
455.0
4494.2
580.8
733.2
520.5
567.3
243.5
568.0
253.7
615.5
4082.5
1129.1
631.7
840.7
370.0
1221.0
445.7
4638.2
473.0
777.4
548.8
563.0
272.8
591.0
300.2
592.9
4119.1
1129.9
600.6
843.1
399.6
1277.1
473.2
4723.5
OTHER STATES
Arkansas
Iowa
Louisiana
Missouri
Texas
112.6
167.2
283.5
198.1
876.5
122.9
203.6
330.2
251.0
933.1
115.9
216.4
535.8
294.6
1658.0
147.6
248.1
760.1
339.1
2044.6
193.2
309.6
1016.9
424.6
2551.3
171.4
308.8
1072.0
593.6
2833.9
217.9
321.0
1593.7
563.0
3309.5
*Questionable data
-------
82
apparent decrease may be due to errors in the data; however, it should be noted that a
38% reduction in SO emissions in the northeast also is observed between 1965 and 1978.
A
Therefore, SO emissions appear to have been significantly reduced in the northeast
A
during the past 28 years.
Contrary to the apparent reduction in SO emissions noted in the northeast,
the states in Region III (mid-Atlantic) have generally maintained about the same level of
SO emissions. There appears to have been a small steady increase between 1955 and
1970, and a small but steady decline between 1970 and 1978.
The southeastern states exhibit a sharp increase in SO emissions between
A
1950 and 1978 with the data suggesting that this increase may be as high as three to five-
fold.
In the midwest (Region V), there appears to have been a significant steady
increase in SO emissions between 1955 and 1965 and a steady decline in these emissions
since 1965. Levels today are about 25% higher than in 1955 in this area of the country.
The states of Arkansas, Iowa, Louisiana, Missouri, and Texas have exhibited a
steady increase in SO- emissions since 1950. NO emissions in Arkansas and Iowa appear
to have doubled since 1955, while Louisiana and Missouri appear to have experienced a
greater than 50% increase and Texas about 24%.
All the areas examined exhibit significant increases in NO emissions over the
time period studied. This increase ranges from about a factor of two in the northeast to
over three in the south. The trends also indicate that NO emissions have increased
A
steadily and did not peak in the mid-1960's as did SO2 emissions.
-------
83
C.3 IN CANADA
Data have been developed on historical long-term trends for Canadian sulphur
dioxide and nitrogen oxide emissions (1,2). Information on production and fuel consump-
tion on a provincial basis was obtained from other federal government departments for
the various sectors investigated. Supplemental data such as the names of specific plants
operating in 1955 and 1965 were obtained from internal files and various provincial
agencies. For area type sources, where necessary, census information specific to the
earlier time periods was used. In many cases, emission factors were applied to the basic
data derived from these information sources. The factors used were either from U.S.
EPA's data (3), the same factors adapted to Canadian conditions, or Canadian factors
developed by Environment Canada. Generally, the methodology adopted for developing
emissions for the earlier years closely followed that now being utilized for current
emissions (4), except that actual emission data extracted from plant files were utilized
for all copper-nickel smelter complexes (2), and for some power generating plants (1).
The years 1955, 1965, and 1976 were chosen to give a fair representation of
the trends in emissions over the past three decades. The data for 1955 and 1965 were
developed on a national, provincial, and census division basis for all of Canada and for
those sectors which, as a whole, are thought to contribute more than 90 percent of total
emissions of SCU and NO . The data for 1976 have been developed in many formats -
nationally, provincially, on a census division basis, on a 127 km x 127 km grid basis, and on
a major metropolitan area basis - and cover the full spectrum of point and area types of
emission sources (more than 70 sectors of the Canadian economy).
Total Canadian emissions of SO2 and NO for each of the years 1955, 1965,
and 1976 are presented in Table C.3.1 for the sectors of most concern at this time.
Table C.3.2 presents the same information but for eastern Canada only. Total SO2
emissions in Canada in 1976 were approximately 5.4 million tonnes, compared with 6.2
million tonnes in 1965 and 4.4 million tonnes in 1955. This fluctuation was largely due to
significant changes in the emissions from the copper-nickel smelting industry which
represented 65%, 62%, and 47% of total SO2 emissions in the years 1955, 1965, and 1976
respectively. Eastern Canada has always contributed the larger portion of national
emissions, this share being about 96%, 87%, and 83% in the years 1955, 1965, and 1976.
All copper-nickel smelting complexes are located in eastern Canada (including Manitoba).
Emissions of SO2 from power plants were at a negligible level of less than 0.1
million tonnes in 1955 before increasing to 0.2 million tonnes in 1965 and
-------
TABLE C.3.1
HISTORICAL EMISSIONS OF SO2 AND NOx - CANADA
Emissions (tonnes)
Sector
Cu-Ni smelters
Power plants
Other combustion*
Transportation * *
(gasoline-powered
motor vehicles)
Iron ore processing
Others
TOTAL
1955
so2
2 870 000
52 502
974 360
N/A
(4 687)
109 732
381 423
4 392 704
NOX«>
_
11 155
212 451
N/A
(63 447)
-
17 751
304 804
1965
so2
3 827 000
224 931
671 218
N/A
(9 938)
155 832
1 262 534
6 151 453
NO,'"
_
52 779
192 185
N/A
(208 681)
-
37 262
490 907
1976
so2
2 540 657
614 323
997 139
77 793
(19 469)
175 829
1 018 195
5 423 936
NOX«>
_
206 454
473 317
1 017 936
(506 691)
-
190 327
1 888 034
* Includes residential, commercial and industrial fuel combustion.
** Historical data for transportation sectors other than gasoline-powered motor vehicles have not yet been developed for 1955
(1)
and 1965.
^ ' NO expressed as NO?.
N/A Nofavailable
00
4=-
-------
TABLE C.3.2
HISTORICAL EMISSIONS OF SO, AND NO - EASTERN CANADA
£f A
Emissions (tonnes)
Sector
Cu-Ni smelters
Power plants
Other combustion*
Transportation* *
(gasoline-powered
motor vehicles)
Iron ore processing
Others
TOTAL
(% of the total Canada)
1955
so2
2 870 000
51 236
900 861
N/A
(3 449)
109 732
272 416
it 207 694
(96%)
NOX«>
_
7 870
172 952
N/A
(46 640)
-
11 905
239 367
(79%)
1965
so2
3 827 000
218 128
634 603
N/A
(7 239)
155 832
493 320
5 336 122
(87%)
NOX<"
_
42 485
149 764
N/A
(152 012)
-
27 002
371 263
(76%)
1976
so2
2 540 657
554 417
905 159
52 827
(13 237)
175 829
271 933
4 500 822
(83%)
NOX<'>
_
142 470
280 539
652 737
(347 294)
-
94 763
1 170 509
(62%)
* Includes residential, commercial and industrial fuel combustion.
** Historical data for transportation sectors other than gasoline-powered motor vehicles have not yet been developed for 1955
(1)
N/A
and 1965.
NO expressed as NO-
No^available
CO
-------
86
reaching 0.6 million tonnes in 1976. Close to 90% of this total was emitted within eastern
Canada.
Sulphur dioxide emissions from the combustion of fuels for industrial, commer-
cial, and residential purposes decreased from 1955 to 1965, largely because of the switch
away from coal as the primary fuel, before increasing and reaching in 1976 levels
comparable to those of 1955, i.e., about 1.0 million tonnes, because of greater activity in
the industrial market. In 1976, about 75% of other combustion emissions were from
industrial fuel combustion sources. In 1955 and 1965 this contribution was closer to
two-thirds of the total emissions. SO* emissions from transportation sources in 1976
were about equally due to gasoline-powered motor vehicles, diesel-powered engines, and
railroads. Emissions from gasoline-powered motor vehicles quadrupled from 1955 to the
mid-1970's.
The iron ore processing sector contributed close to 0.2 million tonnes of SO- in
1976, i.e., about twice the level of 1955. Such processing involves the mining and
beneficiation of the ore by sintering or pelletizing operations to produce a suitable blast
furnace feed. Other industrial processes, included under "others" in Tables C.3.1 and 2,
saw their SO2 emissions increase from 0.4 million tonnes in 1955 to 1.0 million tonnes in
1976 due largely to increased productivity in various sectors of the economy.
Three-quarters of these emissions came from western Canada.
It is difficult to measure the uncertainty of the $©2 inventories for 1955 and
1965. However, because of the source of the data used to estimate emissions from
copper-nickel smelter complexes (2), and the fact that this sector contributes signifi-
cantly to total emissions, the confidence level of the historical emissions inventory of SO2
is greatly increased. An analysis made of the 1976 inventory has indicated that the
overall $©2 inventory for Canada is accurate within + 30% of the true value at a 75%
confidence level (2).
A map of eastern Canada divided on the basis of 127 km x 127 km grid cells,
along with an indication of the magnitude of 1976 SC>2 emissions for each cell according
to five ranges of emissions, is presented in Appendix 2.
Total emissions of NO have increased significantly, from a level of 0.3
yV
million tonnes in 1955 to 1.9 million tonnes in 1976, due largely to increases in power
plant and transportation sector emissions. The increase in demand for power and
electricity has resulted in the building of more power plants, causing NO emissions to
reach a level of 0.2 million tonnes in 1976, compared to much less than 0.05 million tonnes
in 1955, and 0.05 million tonnes in 1965. Gasoline-powered motor vehicle NO emissions
-------
87
were about eight times greater in 1976 than in 1955, and were at an even level with other
transportation source emissions, the majority of which are attributable to diesel-powered
engines. NO emissions from other combustion sources have approximately doubled over
the period investigated.
The distribution of NO emissions between eastern and western Canada is
yv
more uniform than the distribution of SO2 emissions because of the nature of the sources
involved. Eastern Canada (including Manitoba) has contributed 79%, 76%, and 62% of
total NO emissions in 1955, 1965, and 1976 respectively. An uncertainty analysis has not
been carried out for NOx emissions for any of the years of investigation.
A map depicting NO emissions in eastern Canada in 1976 according to the
A
127 km x 127 km grid array is presented in Appendix 2.
-------
REFERENCES (SECTION C.3)
1. Environment Canada, Air Pollution Control Directorate, Data Analysis Division
(Unpublished Information) (December 1980).
2. Environment Canada, Air Pollution Control Directorate, Copper-Nickel Smelter
Complexes in Canada, SO0 Emissions (1950-2000), Report EPS 3-AP-80-5 (January
1981). -
3. EPA Publication AP-42, "Compilation of Air Pollutant Emission Factors", third
edition, August 1977.
4. Environment Canada, Air Pollution Control Directorate, A Nationwide Inventory of
Emissions of Air Contaminants (1976), Report EPS-3-AP-80-1 (January 1981).
5. Environment Canada, Air Pollution Control Directorate, National Inventory of
Natural Sources and Emissions of Sulphur Compounds, Report EPS 3-AP-79-2
(February 1980).
6. Environment Canada, Air Pollution Control Directorate, National Inventory of
Natural Sources and Emissions of Nitrogen Compounds, Report EPS 3-AP-80-4
(January 1981).
-------
89
D. PRESENT EMISSION RATES
This chapter provides estimates of current emissions of SO2 and NOX in both
the United States and Canada. The data for U.S. emissions are current as of 1978, while
the data for Canadian emissions are for various years. Canadian SO2 emissions are
current for 1979 with one major point source current for 1980. Canadian NOX emissions
are current for 1977. It is hoped that all emission estimates can be updated to 1979
values for the final version of this report.
D.I In the United States
The current emission rates reported here for the United States are based on
estimates of actual rates for numerous sectors of the economy. The values used in this
summary are taken from National Air Pollution Emission Estimates (U.S. Environmental
Protection Agency). Basically, the methodology for deriving these estimates uses an
inventory of sources, determination of fuel consumption, and air pollution emission
factors.
The inventory of sources, and associated fuel consumption rates, were taken
from the National Emissions Data System (NEDS). The data in NEDS were provided by
state agencies as an inventory of sources for each state. NEDS is constantly being
updated and the version used here reflects values in the system for February, 1980.
However, NEDS is not complete and some source categories are more accurate than
others. Estimates of the accuracy of this information are unavailable at this time.
The emission factors used in developing these emission estimates are from the
U.S. EPA data (1). The emission factor is an average estimate of the rate at which a
pollutant is released to the atmosphere as a result of some activity, such as combustion or
industrial production, divided by the level of that activity. The emission factors are
estimates based on source testing, process material balances, and engineering appraisals.
As a result, some emission factors are more accurate than others. In general, the
emission factors are more often applied to regional or national emission estimates, as in
this report, than to single source estimates where the inaccuracies would be considerable.
Total emissions of SO9 and NO for 1978 are shown in Table D.I.I, segmented
£ J\
for various categories of sources. Clearly, the largest source category of SO2 emission in
the United States is the utility category. Utilities account for approximately two-thirds
of the SO2 emissions. Other stationary sources contribute nearly one-third, with the
remainder from transportation sources. In terms of total NO emissions, the
A
-------
90
transportation sector is the primary source, contributing 40%, with utility and industrial
boilers emitting 52%.
SO2 and NOX emissions can be disaggregated on a state-by-state basis, as
shown in Table D.I.2. Only 33 states are represented in the table. Data for the 15
western states and Alaska and Hawaii are unavailable at this time. The values in
Table D.I.2 represent 80% of the SO2 and 76% of the NOX emissions for the entire United
States.
The emission estimates can be further disaggregated to show emissions by
source catagory for each state. Tables D.I.3 through D.I.8 show this information based
on 1977 data.
Information on natural sources of sulfur and nitrogen emissions in the United
States is not available at this time.
REFERENCES
1. EPA Publication AP-42, "Compilation of Air Pollutant Emission Factors", third
edition, August 1977.
-------
91
TABLE D.I.I CURRENT (1978) EMISSIONS OF SO2 AND NOX - U.S. (106 tonnes)
Category
Utilities
Industrial Boilers
Industrial Processes
Transportation
Residential/Commercial
Solid Waste Disposal
Miscellaneous
Total
S02(%
17.6
3.2
4.1
0.8
1.3
0.0
0.0
27.0
of total)
(65%)
(12%)
(15%)
(3%)
(5%)
(0%)
(0%)
(100%)
NOX
7.2
4.9
0.8
9.4
0.8
0.1
0.1
23.3
(% of total]
(31%)
(21%)
(3.5%)
(40%)
(3.5%)
(0.5%)
(0.5%)
(100%)
-------
92
TABLE D.1.2 1978 SO2 AND NOX EMISSIONS BY STATE (103tons)
State
Alabama
Arkansas
Connecticut
Delaware
District of Columbia
Florida
Georgia
Illinois
Indiana
Iowa
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
New Hampshire
New Jersey
New York
North Carolina
Ohio
Pennsylvania
Rhode Island
South Carolina
Tennessee
Texas
Vermont
Virginia
West Virginia
Wisconsin
SO2
762.1
121.6
112.0
188.2
17.6
685.9
707.0
17*7.2
18*8.2
385.0
1330.0
359.0
66.0
357.3
*02.2
1117.8
379.0
26*. 3
1307.7
67.8
323.7
10*1.1
562.3
3115.3
1900.0
19.7
288.6
1162.8
12**. 8
_
359.9
10*9.5
663.6
NOX
*73.0
217.9
183.0
70.6
33.5
777.*
5*8.8
1129.9
600.6
321.0
563.0
1593.7
76.7
313.9
36*. 3
8*3.1
399.6
272.8
563.0
66.9
*9*.*
908.9
591.0
1277.1
1120.7
*2.*
300.2
592.9
3309.5
_
*35.2
*62.*
*73.2
TOTAL 23957.2 19*20.6
or 21.73 million tonnes 17.62 million tonnes
-------
93
TABLE D.1.3 1977 U.S. EMISSIONS - UTILITIES (lO* tons)
National*
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
District of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
S02
19797
780
2.3
75
50
185
74
51
82
10
757
578
39
0.011
1369
1493
234
125
1526
59
10
228
143
9.2
175
179
1265
24
28
35
92
127
145
508
426
83
2688
3
0
1476
3.6
181
33
1091
249
44
NOX
7.284
213
6.0
136
34
174
75
42
28
8
211
140
21
0.024
602
462
83
146
346
183
3
77
88
230
81
53
315
34
33
87
36
83
118
262
195
48
529
101
0
391
2.6
97
23
229
490
24
-------
TABLE D.1.3 1977 U.S. EMISSIONS - UTILITIES (103 tons) (Cont'd)
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
SO2
0.007
259
18
1048
470
129
NOX
0.015
104
51
263
128
99
-------
95
TABLE D.1.4 1977 U.S. EMISSIONS - INDUSTRIAL BOILERS (1Q3 tons)
National*
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
District of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
SO2
3254.7
101
3
3
37
135
7
6
12
4
67
50
11
6
101
154
48
2
43
78
94
31
70
124
47
16
20
10
2
2
16
36
9
198
97
4
325
5
15
520
6
83
0
94
123
14
NOX
1846.4
41
3
4
20
98
3
6
4
2
38
25
2
14
51
123
27
14
17
217
23
21
51
69
21
15
8
6
5
3
3
33
5
52
32
2
125
5
38
84 .
2
33
0
53
232
8
-------
96
TABLE D.I.4 1977 U.S. EMISSIONS - INDUSTRIAL BOILERS (1Q3 tons) (Cont'd)
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
SO2
0.6
115
49
89
112
12
NOX
0.5
40
38
97
43
6
-------
97
TABLE D.I.5 1977 U.S. EMISSIONS - INDUSTRIAL PROCESSES (1Q3 tons)
National*
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
District of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
SO2
5636.8
108
0
1132
26
219
19
0.5
31
0
115
29
10
31
126
60
36
46
18
177
14
53
1
133
26
32
141
162
14
286
0.9
67
408
46
35
20
90
92
12
355
0
21
4
60
878
131
NOX
1020.5
24
0.4
4
2
129
4
0.1
3
0
24
12
3
.7
45
29
4
20
9
122
2
16
0
17
4
13
17
4
4
3
0.3
20
7
9
7
0.9
20
12
2
41
0
7
1
15
193
10
-------
98
TABLE D.1.5 1977 U.S. EMISSIONS - INDUSTRIAL PROCESSES (10^ tons) (Cont'd)
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
S02
0
24
171
58
41
21
NOX
0
14
23
12
47
5
-------
99
TABLE D.I.6 1978 U.S. EMISSIONS - TRANSPORTATION (tonnes)
National
Alabama
Arkansas
Connecticut
Delaware
Dist. of Columbia
Florida
Georgia
Illinois
Indiana
Iowa
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
New Hampshire
New Jersey
New York
North Carolina
Ohio
Pennsylvania
Rhode Island
South Carolina
Tennessee
Texas
Vermont
Virginia
West Virginia
Wisconsin
TSP
6 286 087
110 642
63 752
81 687
16 283
15 214
298 590
155 564
286 008
155 893
60 897
90 950
113 812
23 288
113 453
158 713
269 852
103 899
53 514
151 023
21 252
221 443
340 260
143 885
321 708
282 530
28 369
76 807
129 395
455 232
9 794
135 464
17 147
87 749
S0x
955 767
25 892
9 921
6 622
2 823
1 197
30 889
20 212
30 472
18 838
9 805
14 480
43 953
3 727
14 735
10 765
46 761
14 320
12 257
17 041
1 627
27 381
34 575
19 465
36 835
38 405
1 679
9 897
19 505
111 334
1 383
19 047
5 663
13 941
N0x
9 355 943
205 541
128 555
100 103
28 039
17 111
362 730
270 023
398 479
255 218
135 773
189 160
202 170
50 419
152 485
161 017
350 936
198 444
123 978
235 436
29 361
248 805
419 157
284 714
433 805
435 991
29 380
136 873
250 647
704 565
21 363
237 600
69 521
198 364
HC
12 549 131
241 841
144 749
152 975
35 773
24 236
557 336
323 335
518 854
320 855
157 697
204 932
240 994
59 136
207 733
278 951
482 683
254 163
129 197
306 040
41 446
375 900
634 875
334 094
507 312
531 822
53 827
173 858
274 032
897 667
22 453
286 300
51 699
231 296
CO
97 801 165
1 754 292
1 049 778
1 235 652
275 377
202 223
4 269 119
2 430 711
4 112 325
2 519 201
1 218 841
1 508 128
1 754 474
428 545
1 609 040
2 314 969
3 869 142
1 947 578
943 935
2 367 375
330 945
3 069 379
5 114 336
2 477 393
4 582 071
4 196 933
444 384
1 258 446
2 038 819
6 744 339
162 963
2 147 609
326 512
1 657 454
SOURCE: National Emissions Data System (NEDS).
-------
100
TABLE D.1.7 1978 U.S. EMISSIONS - COMMERCIAL/RESIDENTIAL (tonnes)
National
Alabama
Arkansas
Connecticut
Delaware
Dist. of Columbia
Florida
Georgia
Illinois
Indiana
Iowa
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
New Hampshire
New Jersey
New York
North Carolina
Ohio
Pennsylvania
Rhode Island
South Carolina
Tennessee
Texas
Vermont
Virginia
West Virginia
Wisconsin
TSP
353 760
8 504
4 249
3 202
640
612
65 291
7 298
16 606
12 438
8 324
5 927
5 739
2 719
3 806
7 794
19 415
11 634
6 360
10 158
1 836
10 063
16 216
11 169
21 098
4 473
1 187
7 676
9 366
12 820
1 479
6 786
3 947
11 907
S0x
23 406
407
259
131
53
179
1 126
445
1 186
877
634
398
287
182
257
420
2 508
426
339
429
123
2 074
1 453
865
13 046
1 291
48
390
507
784
95
590
237
995
NOX
100 672
2 314
1 375
686
229
214
1 870
2 646
2 981
3 718
2 134
2 192
1 723
776
1 351
1 501
15 557
2 211
1 831
2 100
505
3 348
4 718
4 106
4 789
1 531
208
2 230
2 601
3 539
444
2 547
1 434
3 208
HC
742 054
18 286
8 417
7 103
1 064
477
9 906
13 833
39 490
25 938
17 083
11 170
11 753
5 579
7 199
17 869
41 699
18 010
13 403
23 533
3 799
12 415
27 866
20 296
45 654
1 832
2 866
16 185
20 165
26 742
2 995
12 661
7 505
23 524
CO
2 152 169
18 285
23 968
20 738
29 089
7 482
28 251
39 126
116 353
75 007
49 374
32 107
33 316
16 072
20 439
52 370
115 990
52 287
38 451
68 831
10 965
33 673
79 280
57 248
132 856
15 499
8 403
46 695
59 487
76 609
8 690
35 788
21 235
67 860
SOURCE: National Emissions Data System (NEDS).
-------
101
TABLE D.I.8 1977 U.S. EMISSIONS - SOLID WASTE DISPOSAL (1Q3 tons)
National
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
District of Columbia
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
SO2
51
0.*
0.0
0.7
0.5
1.2
0.2
0.2
0.1
0.6
1.6
0.5
0.2
0.1
1.3
1.2
0.7
0.3
0.9
3.3
0.5
0.6
1.7
2.9
0.5
0.5
0.9
0.1
0.3
2.0
0.3
2.0
0.2
5.3
1.5
0.1
2.4
0.2
0.3
2.3
, 0.1
0.4
0.1
1.4
7.0
0.2
0.1
NOX
138
2.7
0.5
2.2
1.9
5.3
0.8
0.8
0.3
0.6
3.1
3.1
0.4
0.7
3.1
4.2
2.2
1.4
3.0
2.7
2.5
1.7
4.5
16.4
2.3
2.6
2.5
0.7
1.4
2.5
1.5
3.2
0.7
8.4
5.7
0.5
6.7
6.7
1.6
6.3
0.3
2.4
0.7
3.6
5.3
0.5
0.4
-------
102
TABLE D.1.8 1977 U.S. EMISSIONS - SOLID WASTE DISPOSAL (1Q3 tons) (Cont'd)
Virginia
Washington
West Virginia
Wisconsin
Wyoming
SO2
1.0
0.5
0.3
1.*
0.1
NOX
3.1
2.1
1.6
3.9
0.*
-------
103
D.2 IN CANADA
The Canadian data base includes estimates of actual emissions for more than
70 sectors of the economy. The methodology used to derive these estimates is described
in detail for each of the sectors investigated in Reference 1. Basically, for point source
types of emissions, substantial information is extracted from government surveys made of
individual plants or installations and often based on stack testing at the source. In other
cases where such firsthand information is not available, and for area source types of
emissions, the emission factor approach is used. In these instances, either U.S. EPA
emission factors (2), or these factors corrected for Canadian conditions, or emission
factors developed by Environment Canada are utilized. Information regarding production
and fuel consumption by the various sources comes from other federal government
departments and is supplemented by data from a number of industrial associations.
On a national basis the overall accuracy of the current Canadian SO*
emissions inventory is estimated to be + 30% at a 75% confidence level (3). The accuracy
of the information varies widely between each sector, and within each sector investi-
gated; it is far greater for the major point sources (e.g., Cu-Ni smelters), which together
represent more than half of Canadian emissions, than for less significant sources. An
uncertainty analysis has not been carried out for NO emissions, but as a first
approximation, the overall accuracy of the NO data base is less than that of the SO,
J\ £
data because the important contributors of such emissions (e.g., transportation sources)
are quite different.
The data base for present emission rates in Canada includes a mixture of data
covering the period 1976 through 1980. For sulphur dioxide all area source information
represents 1976 annual emission rates (1). Major point sources are at their 1979 annual
emission rates and the most important Canadian copper-nickel smelter complex, repre-
senting fully 20% of eastern Canada emissions, is shown at its 1980 emission rate (3). On
a weighted emissions basis, the aggregated SO2 data base closely represents actual
emissions for the year 1979.
For nitrogen oxides, all area source type emissions are from the 1976 base
year (1). Major point sources are at their 1979 annual emission rate (3). On a weighted
emission basis, the aggregated Canadian NO data base probably represents actual
emission rates in 1977.
Table D.2.1 gives the total national emissions for SO7 and NO prorated on the
ff A
basis of the usual five categories of emission sources. Roughly two-thirds of SO2
emissions in Canada are contributed by industrial processes; the other third results
-------
104
TABLE D.2.1 CURRENT (1976-1980) EMISSIONS OF SO2 AND NOx - CANADA
Emissions (tonnes)
Category SO, (% of total) NOV(1) (% of total)
£ A
Industrial processes 3 085 412 (63.4%) 38 213 (2.0%)
Fuel combustion/ 1 698 683 (34.9%) 693 675 (36.5%)
stationary sources
Transportation 77 793 (1.6%) 1 017 936 (53.5%)
Solid waste incineration 3 245 (0.1%) 5 094 (0.3%)
Miscellaneous - 147 020 (7.7%)
TOTAL 4 865 133 (100%) 1 901 938 (100%)
expressed as NO,.
TABLE D.2.2 CURRENT (1976-1980) EMISSIONS OF SO9 AND NO - EASTERN
CANADA * X
Emissions (tonnes)
SO2 (% of total)
Cu-Ni smelters
Power plants
Other combustion*
Transportation
(gasoline-powered
motor vehicles)
Iron ore processing
Others
2 021 201
641 638
905 159
52 827
(13 237)
198 480
271 933
(49.4%)
(15.7%)
(22.1%)
(1.3%)
(4.9%)
(6.6%)
NOV(1) (% of total)
J\
.
156 374
280 539
652 737
(347 294)
-
94 763
(13.2%)
(23.7%)
(55.1%)
(8.0%)
TOTAL 4 091 238 1 184 413
(% of total Canada) (84%) (62%)
* Includes residential, commercial and industrial fuel combustion.
( 'NO expressed as NO,.
-------
105
from the combustion of fuels in stationary sources. This latter category of sources is also
responsible for about one-third of the total NO emissions in Canada. Transportation
j\
sources account for more than half of NO emissions and close to 50% of this is due to the
A
gasoline-powered motor vehicle alone. From 1976 to 1979-80, there was a reduction of
about 10% in total Canadian SO- emissions which was largely due to a significant drop in
non-ferrous smelter emissions.
Table D.2.2 presents total emissions for eastern Canada only (east of the
Manitoba-Saskatchewan border) over the 1976-80 period for the sectors of most concern
at this time. Eastern Canada's emissions account for close to 85% of total SO2 emissions
and about two-thirds of NOX emissions. Close to half (49%) of the SO2 emissions in
eastern Canada are concentrated in six copper-nickel smelters located in Manitoba,
Ontario and Quebec. About one quarter of the SO2 emissions result from the combustion
of fuels for industrial, commercial, and residential purposes; the industrial source
contributes about 75% of these emissions (1). Power plants are responsible for a little
more than 15% of eastern Canada SO2 emissions and close to three-quarters of such
emissions come from power plants located in southern Ontario (1,3). Iron ore processing,
i.e., the mining and beneficiation of ores by sintering or pelletizing operations, is
responsible for close to 5% of eastern Canada SO* emissions.
A large part (55%) of eastern Canada's NOx emissions is contributed by
transportation sources. Here, gasoline-powered motor vehicles, diesel-powered engines
and railroads contribute about half, one-third, and 10%, respectively of such emissions (1).
The second major sector of NO emissions in eastern Canada is the combustion of fuels in
industrial, commercial, and residential applications. This sector contributes about one-
quarter of NO emissions (same contribution as for SO2 emissions); 59% of the sector's
emissions come from industrial fuel combustion sources (1). This is followed by power
plants, which generate about 13% of eastern Canada's NO emissions, two-thirds of which
X
are from southern Ontario installations (1,3).
The eastern Canada data are further prorated on a grid array of
127 km x 127 km squares, which is the basic dimension for the emissions and meteo-
rological data used in the Atmospheric Environment Service long-range transport model.
Total (point and area) emissions of SO2 and NO , for each of the grid cells in eastern
Canada, are listed in Appendix 2. Figure D.2.1 and Table D.2.3 present an aggregated
version of the SO2 data found in Appendix 2. Here, the geographical area representing
eastern Canada has been divided into 17 defined source regions, delineated by the
boundaries of the 127-km grid cells. These source regions have been defined to represent
-------
54
26
8O
O
a
FIGURE D. 2 .1
DEFINED CANADIAN SOURCE REGIONS - 127 km * 127 km GRID
REGIONS SOURCES CANADIENNES DEFINIES - GRILLE DE 127 km * 127 km
-------
107
TABLE D.2.3 SO2 EMISSIONS FROM DEFINED CANADIAN SOURCE REGIONS -
1976-80 DATA BASE
Source Region
Flin Flon, Manitoba
Thompson, Manitoba
Manitoba (excluding 1 & 2)
Northern Ontario (excluding 5 & 6)
Wawa, Ontario
Sudbury area, Ontario
Toronto region, Ontario*
Southern Ontario (excluding 7)
Noranda, Quebec
Montreal region, Quebec**
Southern Quebec (excluding 10)
Murdochville, Quebec
Northern Quebec (excluding 9 & 12)
New Brunswick
Nova Scotia
Prince Edward Island
Newfoundland and Labrador
TOTAL
Map Identifier
1
2
3
4
5
6
• 7
8
9
10
11
12
13
14
15
16
"17
Emissions (tonnes x 10 )
152.2
334.0
27.1
76.6
182.3
1 006.9
245.2*
440.6
540.7
292.5**
96.3
73.1
83.5
199.5
213.8
19.0
54.3
4 037.6
* Metro-Toronto only = 207.0 x 10- tonnes
** Metro-Montreal only = 261.1 x 10 tonnes
TABLE D.2.4 SEASONAL VARIATIONS IN CANADIAN SO, AND NOV EMISSIONS
£ yv
% of annual emissions
December-February March-May June-August September-November
Category
Industrial processes
Fuel combustion/
stationary sources
Transportation
Incineration
Miscellaneous
so2
27
34
22
25
-
N0x
25
34
24
25
-
so2
25
22
25
25
-
.x
25
22
25
25
21
:S02
23
18
27
25
-
NOX
25
19
26
25
77
so2
25
26
26
25
-
N0x
25
25
25
25
1
Total (weighted) 29 25 24 23 22 28 25 24
-------
108
either major point sources, areas comprising large metropolitan centres, or significant
geographic portions of provinces.
Seasonal variations data for use in detailed air quality analysis have been
developed for both SO- and NO emissions for all contributing sectors (3). In summary,
emissions are found to vary considerably from season to season for the fuel combustion
sectors, the winter (December - February) emissions being about 85% greater than the
summer (3une - August) emissions. The other categories show little variation; for
example, the overall winter emissions from industrial processes are about 15% greater
than the summer emissions. The national summary is presented in Table D.2.4
Nationwide inventories of natural emissions of sulphur and nitrogen compounds
into the atmosphere and an evaluation of their contribution to the overall sulphur and
nitrogen burden of ambient air have been carried out for Canada (4,5). Data on estimates
of natural emissions were obtained through a literature review of sulphur and nitrogen
release mechanisms normally associated with biological and other natural processes. Such
data are relatively sparse and in some cases contradictory, making some reported
estimates of source emissions quite speculative. The emission estimates are likely to be
accurate only to within an order of magnitude.
The principal sulphur compound emitted by biological processes into the
atmosphere is hydrogen sulphide. Others that have been identified include: carbon
disulphide, carbonyl sulphide, dimethyl disulphide and methyl mercaptan. Biogenic
sources include soils, water bodies, and vegetation. Forest fires emit sulphur dioxide
while sea and lake sprays release sulphates. The total emissions of sulphur from natural
sources in Canada are estimated at about 500 000 tonnes per year, (i.e., about 20% of
total anthropogenic emissions of sulphur dioxide). The greatest natural sulphur emissions
occur on the Atlantic and Pacific coasts and in Ontario and Quebec. Table D.2.5
summarizes this information.
Included in the more important nitrogenous compounds emitted to the atmos-
phere from natural sources are N2O, NO , NH,, and aliphatic amines. Principal emitting
sources are soils and marine waters for N-O, soils and lightning for NO , soils and animal
wastes for NH.,, and animal wastes for aliphatic amines. Nitrogen oxides emitted from
forest fires are less important. The total emissions of nitrogen from natural sources in
Canada are estimated at about 2 100 000 tonnes per year, (i.e., roughly three and one half
times the total anthropogenic emissions of nitrogen oxides (expressed as NO-)).
Table D.2.6 summarizes the information on emissions of natural nitrogen compounds in
Canada.
-------
TABLE D.2.5
SUMMARY OF NATURAL EMISSIONS OF SULPHUR INTO THE ATMOSPHERE IN CANADA (tonnes of S per
year)(1T
Biogenic Emissions
Province/Territory Soils Marine
Newfoundland 2 187
Prince Edward Island 72
Nova Scotia 609
New Brunswick 761
Quebec 23 888 36 692**
Ontario 65 672 4 381
Manitoba 47 860
Saskatchewan 17 217
Alberta 31 062
British Columbia 29 515 10 465
Yukon 4 950
Northwest Territories 22 770 92***
Canada 246 563 51 631
Canadian total - 509 406 tonnes
Other Natural Sources*
Lakes
203
-
102
100
1 471
3 543
2 650
2 434
654
810
11 967
Sea Salt
Vegetation SO^
138
200
226
278
1 772 101 200**
2 698
552
1 245
1 016
782 27 300
60 400***
8 907 188 900
Soil Forest
Dust Fires
81
3
5
60
55
203
164
64
500**** 171
194
500 1 000
* Does not include 7 tonnes from lake sulphate.
** Includes Atlantic Provinces and Quebec.
*** Includes Yukon and Northwest Territories.
**** Includes Saskatchewan, Alberta and British Columbia.
All
figures expressed as
S per year.
get the equivalent SO_ emissions, above
figures must be multiplied by 2 (for example, total Canadian natural sulphur emissions expressed as
S02 are 509 406 x 2 = 1 018 812 tonnes).
-------
TABLE D.2.6
SUMMARY OF NATURAL EMISSIONS OF NITROGEN INTO THE ATMOSPHERE IN CANADA
(tonnes of N per year)
Compound Class
Province/Territory
Newfoundland
Nova Scotia
Prince Edward Island
New Brunswick
Quebec
Ontario
Manitoba
Saskatchewan
Alberta
British Columbia
Yukon
Northwest Territories
Canada
N20
40 801
9 032
1 279
12 236
168 315
135 070
70 686
69 539
45 614
69 832
18 739
97 759
738 902
N0x
52 484
12 038
1 748
16 300
212 196
165 878
75 917
68 665
39 485
72 108
15 281
91 328
823 428
NH3
1 975
2 981
1 143
4 217
18 044
52 432
61 279
130 740
115 228
99 474
8 389
33 393
529 295
Amines
61
48
62
64
576
974
408
1 900
1 278
550
106
336
6 363
Total
95 321
24 099
4 232
32 817
399 131
354 354
208 290
270 844
201 605
241 964
42 515
222 816
2 097 988
must be multiplied by 46/14 (for example, total Canadian natural nitrogen emissions expressed as NO9 are
2 097 988 x 46/14 = 6 893 389 tonnes). ^
-------
Ill
References (Section D.2)
1. Environment Canada, Air Pollution Control Directorate, A Nationwide Inventory of
Emissions of Air Contaminants (1976), Report EPS-3-AP-80-1 (January 1981).
2. EPA Publication AP-42, "Compilation of Air Pollutant Emission Factors", third
edition, August 1977.
3. Environment Canada, Air Pollution Control Directorate, Data Analysis Division
(Unpublished Information) (December 1980).
4. Environment Canada, Air Pollution Control Directorate, National Inventory of
Natural Sources and Emissions of Sulphur Compounds, Report EP5-3-AP-79-2
(February 1980).
5. Environment Canada, Air Pollution Control Directorate, National Inventory of
Natural Sources and Emissions of Nitrogen Compounds, Report EPS-3-AP-80-4
(January 1981).
-------
112
E PROJECTED EMISSIONS
This chapter provides estimates of projected emissions of SO9 and NO for all
£* j{
sectors of concern in both the United States and Canada. Several models and scenarios
are used to depict a range of projected emissions to the year 1980 and/or 2000.
E.1 IN THE UNITED STATES
Emissions have been projected by the Department of Energy for all sectors
using the Strategic Environmental Assessment System (SEAS) model, and by the
Environmental Protection Agency using several models. Projected emissions are
presented in Tables E.I.I through E.I.4.
The results from these models differ somewhat, as would be expected, but
agree on the basic conclusion that electric utilities are, and will remain, the dominant
man-made emitters of both sulphur dioxide and nitrogen oxides in the United States.
Because of their impact on national emissions, more sophisticated models were
used to evaluate the impact of various hypothetical emission regulations for power plants.
(1) Description of Methodologies
Utility emissions were projected using two models: the Utility Simulation
Model (USM), developed and operated by Teknekron Research, Incorporated (TRI), and the
Coal and Electric Utilities Model (CEUM) developed and run by ICF Incorporated. Both
models are capable of projecting future energy use, by fuel type, for the electric utility
industry, given a baseline energy scenario. The models also calculate the cost of emission
controls, emissions and relative cost effectiveness of control, on a dollar per tonne of
collected pollutant basis.
The two models differ in basic design. CEUM uses representative units which
behave according to model constraints and optional economics. USM begins with a data
base including all existing power plant units in the continental U.S., and scales up to
future demand by simulating plant additions. Both models can simulate the choice of
different coal supply sources and concomitant transportation paths.
Each model was run to establish a benchmark "base case." This benchmark is
compliance with current air pollution regulations in State Implementation Plans (SIPS)
and, for newer plants, compliance with New Source Performance Standards (NSPS). The
analyses were made of various feasible pollution control scenarios. Except for three
common regulatory scenarios, different scenarios were assessed by each model, depending
on the strengths of the particular models. Analysis to date has focused on sulfur dioxide
emissions, although nitrogen oxide emissions will also be evaluated.
-------
113
TABLE E.1.1 NATIONAL SO PROJECTED EMISSIONS USING SEAS MODEL
(106 tons) x
Utility Boiler
Industrial
Boiler/Process Heat
Non-Ferrous Smelters
Other Energy
Transportation
TOTAL
Source: SEAS - NEP III
1975
20.2
3.6
2.1
1.6
0.6
28.1
Scenario, high energy supply.
TABLE E.I. 2 NATIONAL NO PROJECTED EMISSIONS
(106 tons) X
Utility Boiler
Industrial
Boiler/Process Heat
Non-Ferrous Smelters
Other Energy
Transportation
TOTAL
1975
6.3
2.5
-
1.0
8.5
18.3
1985
19.1
5.4
0.8
1.5
0.9
27.7
USING SEAS MODEL
1985
7.8
4.9
-
1.6
7.8
22.1
1990
19.8
5.5
0.8
0.4
1.1
27.6
1990
8.6
3.9
-
1.7
6.5
20.7
Source: SEAS - NEP III Scenario, high energy supply.
-------
TABLE E.I.3 NATIONAL SO PROJECTED EMISSIONS USING COMBINED MODELS
(106 tons) X
Utility Boiler
Industrial
Boiler/Process Heat
Non-Ferrous Smelters
Residential
Commercial
Transportation
TOTAL
Source: These emission
1980
19.5
5.9
2.0
1.4
0.9
29.7
estimates
1985
17.9
5.7
0.77
1.4
0.9
26.7
based on 1980
1990
18.6
6.8
0.60
1.2
0.9
28.1
trends but projec
1995
19.0
8.6
0.56
0.9
0.9
30.0
ted with % cl
2000
18.5
10.3
0.52
0.6
0.9
30.8
hange of
models (utility - TRI; industrial ICF; RES/COM - SEAS; Transportation Ann
Arbor), NF smelters from an actual unit-by-unit survey.
TABLE E.I.4 NATIONAL NO PROJECTED EMISSIONS USING COMBINED MODELS
(106 tons) x
Utility Boiler
Industrial
Boiler/Process Heat
Non-Ferrous Smelters
Residential
Commercial
Transportation
TOTAL
1980
6.2
6.2
0.0
0.9
9.0
22.3
1985
6.8
6.5
0.0
0.9
8.3
22.5
1990
7.6
6.9
0.0
0.8
8.6
23.9
1995
8.4
7.6
0.0
0.8
9.4
26.2
2000
9.2
8.4
0.0
0.7
10.2
28.5
Source: These emission estimates based on 1980 trends but projected with % change
of models (utility - TRI; industrial ICF; RES/COM - SEAS; Transportation Ann
Arbor), NF smelters from an actual unit-by-unit survey.
-------
115
The regulatory scenarios modeled by ICF and TRI are presented in Tables E.I.5
and E.I.6. Baseline energy scenarios are presented in Table E.I.7. Other key assumptions
are identified in Table E.I.8.
TABLE E.1.5 ICF SCENARIO RUNS
Run 1 — Base Case,
Run 2 — 10 percent rollback of emissions in the 31-state Acid Rain region,
Run 3 ~ 30 percent rollback of emissions in the 31-state Acid Rain region,
Run 4 -- 10 percent rollback of emissions in each of the 45 CEUM demand
regions,
Run 5 — 30 percent rollback of emissions in each of the 45 CEUM demand
regions,
Run 6 ~ 4.0 Ib SO.,/10 Btu emission cap, and
^ £
Run 7 — 2.0 Ib SO2/10 Btu emission cap.
Results from examination of seventeen hypothetical regulatory scenarios are
presented in Tables E.1.9-E.1.13. Tables E.I.9 and E.I. 10 present results on scenarios
examined by both models. Tables E.I. 11 through E.I. 13 are specific to each model. These
results should be considered preliminary in nature. They have not undergone intensive
review by the sponsoring agencies.
The results indicate that it is feasible to obtain reductions in power plant SO-
emissions in excess of 30% without increasing the nationwide average price of electricity
to consumers by more than about 2%. Significant reductions can be obtained for about
$200-300 per ton of SO2 removed.
The USM model results indicate that the 30% reduction could be achieved with
an expenditure of less than one billion dollars for capital (compare Table E.I. 13 and
Figure E.I.2 for scenarios S50, SC2 and RMR). The CEUM model forecasts capital costs
of three to seven billion dollars by 1990 for the same reduction in emissions, depending on
how efficiently the reduction is obtained (see Tables E.I.9 and E.I. 10). The most capital-
intensive approach analyzed, the 2 Ib cap, would cost about $10 billion by 1990, according
to CEUM.
The total use of coal does not appear to be affected by those control
strategies considered. However, some control strategies do appear to reduce the demand
-------
TABLE E.1.6
SCENARIO DESCRIPTIONS FOR TRI ANALYSIS
Scenario
Regulatory Strategy
Units Affected
BNC
BSC
BSS
set
SC2
S50
RMR
1979 status quo
SIP compliance
Strict SIP compliance
it Ib SO2/rnBtu Cap
2 Ib SO2/mBtu Cap
50% SIP Rollback
50% SIP Rollback and
50% minimum removal
R35
35 year lifetimes for
all fossil-fuel-fired units
all SIP units continue to emit SO- at the rate existing in 1979;
units with planned or operating scrubbers are allowed to do so
all SIP units are required to meet promulgated regulations by 1985;
compliance is determined by annual averaging of specified regulation
all SIP units are required to meet promulgated regulations by 1985;
compliance is determined by state specified periods of averaging time
all SIP units are required to meet promulgated regulations by 1985;
no SIP limit is allowed to exceed 4 Ib per million Btu
all SIP units are required to meet promulgated regulations by 1985;
no SIP limit is allowed to exceed 2 Ib per million Btu
all SIP units greater than or equal to 100 megawatts, on-line beginning
in 1950, are required to comply with their promulgated SIP limit
reduced by 50 percent (none to fall below 0.8 Ib/mBtu); all SIP
units less than 100 megawatts are required to comply with SIP limit
all SIP units greater than or equal to 100 megawatts, on-line beginning
in 1950, are required to comply with their promulgated SIP limit
reduced by 50 percent (none to fall below 0.8 Ib/mBtu), and remove
a minimum of 50 percent of the potential SO2/mbtu in the coal
entering utility boiler; all SIP units less than TOO megawatts are
required to comply with SIP limit; all oil-fired units meeting the first
criterion meet SIP limits reduced by 50 percent
all fossil-fuel-fired units (oil, gas, coal) are retired at 35 years of
age; baseline SIP compliance required
-------
TABLE E.1.6
SCENARIO DESCRIPTIONS FOR TRI ANALYSIS (Cont'd)
Scenario
Regulatory Strategy
Units Affected
LED
UCW
CWF
S30
Least Emissions Dispatch
Universal Coal Washing
Coal Washing Floors
30% SIP Rollback
(AIRTEST model only)
all units are dispatched according to SO-
rather than least operating cost; baselint
required
emission rate classes
SIP compliance
all SIP units are required baseline SIP compliance; if the unit is
complying as of 1979 status quo - it is still required to use physical
coal cleaning (level 1); if not complying as of 1979 - the unit is allowed
all compliance options, including fuel-switching, not including
scrubbing of raw coal or blending of raw coal; in all cases, in order for
cleaned coal to be chosen -it must contain at least a 10-percent
reduction in potential $©2 emissions relative to raw coal
all SIP units are required baseline SIP compliance; all coal above mine-
state specified SO2/mBtu floors is required to be cleaned to physical
coal cleaning level 1; coal use and compliance options are the same as
in the Universal Coal Washing scenario, with the omission of the
constraint requiring cleaned coal to be 10 percent lower than raw coal
in potential SO2 emissions
all SIP units greater than or equal to 100 megawatts, on-line beginning
in 1950, are required to comply with their promulgated SIP limit
reduced by 30 percent (none to fall below 0.8 Ib/mBtu); all SIP
units less than 100 megawatts are required to comply with SIP
RSC
NX7
1979 NSPS compliance
for SIP units
(AIRTEST model only)
0.7 Ib/mBtu NO limit
(AIRTEST mode? only)
all SIP units greater than or equal to 100 megawatts, on-line beginning
in 1950, are required to comply with the 1979 New Source
Performance Standards; all SIP units less than 100 megawatts are
required to comply with SIP limit
all SIP units are required SIP compliance and 0.7 Ib/mBtu NO limit
-------
TABLE E.I.7 ENERGY CONSUMPTION COMPARISON DOE/TRI/ICF/(QUADS)
Fuel
Oil
Gas
Total Oil
-------
119
TABLE E.I.8 KEY ASSUMPTIONS
Energy projections provided by DOE (attached)
Utility lifetimes
ICF - « Years for All
TRI - 45 Years for Coal
40 Years for Gas
35 Years for Oil, Nuclear
UOB plants converted to coal - must comply with existing coal SIP's
ICF constrained coal use by $2000/kW penalty for all new construction
Nuclear capacity factor 65% - TRI; 70% - ICF
SIP and strategy compliance by 1985
Annual average SIP's (defined by EPA)
Credit for
Overcomplying with SIP's
Sulfur Retention in Ash
Pollution control costs defined by EPA (with input from DOE)
for relatively high-sulfur coals in northern Appalachia and the midwest in comparison to
the base case. (See Tables E.1.9, E.I.10, and E.I.12).
Other model results, not reflected in these national summaries, include:
Most power plant emissions through 1995 come from existing power plants. More
stringent new source requirements will not significantly reduce SO2 emissions.
Additional SO2 control in the 31 eastern states is about an order of magnitude more
cost effective than controlling the western states. However, western coal is of such
high quality, some strategies (e.g., 4 Ib cap) did not affect the west at all.
Increasing the optimization area reduces nation control costs. That is, a 30%
reduction in the eastern states is about one-third cheaper if state boundaries are
ignored and the least expensive strategy is pursued, instead of obtaining the same
overall reduction by reducing emissions in each state by 30%.
Finally, it should be noted that NO control strategies and combined NO /SO,
A y\ £*
strategies will also be assessed. One strategy in particular, use of Limestone
-------
TABLE E.1.9
1990 FORECASTS FOR COMMON SCENARIOS
RUN DESCRIPTION
BASE CASE
SO- Emissions (10 tons/yr)
Annualized Costs ($1980 X 109/yr)
% Change over Base Case
Cost Effectiveness ($/ton removed)
Electricity Rate Increase (%)
Wet FGD (GW)
Dry FGD (GW)
Capacity Penalty (GW)
**Coal Production Changes (10 tons)
Northern Appalachia
Central and Southern Appalachia
Midwest
Western Northern Great Plains
Rockies and Southwest
Coal Use (1015 Btu/yr)
Total Capital Costs ($1980 X 109)
UMS
18.6
159.6
-
-
-
155.0*
1.8
135.0
151.0
114.0
163.0
73.0
18
NA
CEUM
18.9
110.6
-
-
-
53.0
28.0
2.1
209.0
340.0 '
174.0
260.0
152.0
17
308
4 Ib CAP
USM
16.7
159.9
+0.2
160.0
0.2
159.0*
1.8
-16.0
+21.0
-8.0
-1.0
+5.0
18
NA
CEUM
16.2
111.3
+0.6
254.0
0.4
67.0
27.0
2.2
+ 1.0
+2.0
-17.0
+4.0
+11.0
17
310
2 Ibs CAP
USM
13.0
160.8
+0.8
240.0
0.8
214.0*
2.0
-54.0
+44.0
-19.0
-7.0
+35.0
18
NA
CEUM
11.7
113.0
+0.3
342.0
1.3
78.0
48.0
2.5
-21.0
+33.0
-37.0
-3.0
+ 18.0
17
318
* Both wet and dry scrubbing are included.
** Coal nrnHiirtion rhanpp estimates fnr the I ISM moH*»l arp fr»r 19X5. Th«» ha
-------
TABLE E.1.10
1990 FORECASTS FOR CEUM RUNS
RUN NUMBER
SO2 Emissions (10 tons/yr)
Annualized Costs ($1980 X 109/yr)
% Change over Base Case
Cost Effectiveness ($/ton removed)
Electricity Rate Increase (%)
Wet FGD (GW)
Dry FGD (GW)
Capacity Penalty (GW)
*Coal Production Changes (10 tons)
Northern Appalachia
Central and Southern Appalachia
Midwest
Western Northern Great Plains
Rockies and Southwest
Rest of West
Coal Use (1015 Btu/yr)
Total Capital Costs ($1980 X 109)
No. 1
Base
18.9
110.6
-
-
-
53.0
28.0
2.1
209.0
340.0
174.0
260.0
152.0
116.0
17.0
308
No. 2
10% ARM
17.2
110.8
0.2%
115.0
0.1
54.0
29.0
2.1
-2.0
+8.0
-15.0
-3.0
+9.0
+ 1.0
17.0
319
No. 3
30% ARM
13.8
111.5
+0.8%
175.0
0.5
61.0
30.0
2.3
-20.0
+27.0
-25.0
-1.0
+ 17.0
+2.0
17.0
311
No. 4
10% Each
17.0
111.8
+ 1.0
628.0
0.6
54.0
31.0
2.1
-7.0
+6.0
-10.0
-4.0
+9.0
0.0
17.0
309
No. 5
30% Each
13.3
114.1
+32.0
618.0
1.9
63.0
52.0
2.4
-17.0
+22.0
-27.0
-5.0
+24.0
-2.0
17.0
316
No. 6
4 Pound
16.2
111.3
+0.6
245.0
0.4
67.0
28.0
2.2
+ 1.0
+2.0
-17.0
+4.0
+11.0
1.0
17.0
310
No. 7
2 Pound
11.7
113.0
+0.3
342.0
1.3
78.0
48.0
2.5
-21.0
+33. 0
-37.0
-3.0
+ 18.0
+2.0
17.0
318
Coal production change estimates for the USM model are for 1985. The base case production estimate for
CEUM includes all coal produced including that used by non-utility sources and that exported whereas USM
estimates only apply to production required to meet utility steam-coal requirements. Thus the absolute
numbers for the base case are not directly comparable.
-------
TABLE E.J.I I 1990 FORECASTS FOR USM/AIRTEST RUNS
RUN IDENTIFICATION
SO2 Emissions (10 tons/yr)
Armualized Costs ($1980 X 109/yr)
% Change over Base Case
Cost Effectiveness ($/ton removed)
Electricity Rate Increase (%)
FGD - Wet & Dry (GW)
Capacity Penalty (GW)
Coal Use (10 15 Btu/yr)
BNC
19.9
159.0
-0.4
-
-0.2
135.0
1.7
18
BSC
18.6
159.6
-
0.0
155.0
1.8
18
BSS
16.5
159.9
+0.2
140.0
0.2
169.0
1.8
18
SC4
16.7
159.9
+0.2
160.0
0.2
159.0
1.8
18
SC2
13.0
160.8
+0.8
210.0
1.1
214.0
2.0
18
S50
14.1
160.7
+0.7
240.0
0.9
220.0
2.0
18
PMR
12.7
161.2
+ 1.0
270.0
1.3
270.0
2.2
18
R35
17.7
163.9
+2.7
480.0
0.7
174.0
2.2
18
LED
16.1
160.4
0.5
320.0
0.6
155.0
1.8
18
UCW
17.3
159.8
O.I
150.0
0.2
151.0
1.8
18
CFW
16.2
NA
-
-
153.0
1.8
18
IJ
to
-------
TABLE E.I.12 USM COAL PRODUCTION ESTIMATES (106 tons)
SCENARIO RUNS FOR 1985
Northern Appalachia
Central and Southern Appalachia
Midwest
Western Northern Great Plains
Rockies and Southwest
1980
134
117
116
123
45
BASE
135
151
114
163
73
BNC
+7
-10
+9
+4
-8
BSS
-24
+28
-5
-3
+6
SC4
-16
+21
-8
-1
+5
SC2
-54
+44
-19
-7
+35
550
-42
+42
-12
-9
+ 18
RMR
-43
+47
-6
-15
+ 16
R35
0
+ 1
0
0
0
LED
-2
+7
-11
0
+ 11
UCW
-5
-6
+4
-1
0
CWF
-4
-5
0
-3
0
-------
TABLE E.I.13 NATIONAL ANNUAL UTILITY COSTS: 1985, 1990, 1995, 2000 ($ Billion - 1980)
1985:
Fuel
O&M
Capital
Total
1990:
Fuel
O&M
Capital
Total
1995:
Fuel
O<5cM
Capital
Total
2000:
Fuel
O&M
Capital
Total
BNC
62.0
19.4
49.7
131.1
73.5
24.9
60.5
159.0
82.5
30.2
66.2
178.9
88.9
35.3
76.2
200.3
BSC
62.2
19.5
49.7
131.3
73.7
25.1
60.8
159.6
82.6
30.3
66.4
179.3
89.0
35.4
76.1
200.5
BSS
62.2
19.6
49.9
131.6
73.7
25.2
60.9
159.9
82.6
30.5
66.5
179.6
89.1
35.5
76.2
200.8
SC4
62.3
19.6
49.8
131.6
73.8
25.2
60.9
159.9
82.7
30.4
66.4
179.6
89.2
35.4
76.2
200.8
SC2
62.5
19.9
50.3
132.7
74.2
25.5
61.3
160.8
83.1
30.8
66.7
180.6
89.5
35.8
76.2
201.5
S50
62.3
20.0
50.2
132.5
73.9
25.6
61.3
160.7
82.8
30.8
66.6
180.3
80.2
35.8
76.2
201.3
RMR
62.0
20.5
50.5
133.0
73.6
26.1
61.5
161.2
82.6
31.3
66.7
180.7
80.1
36.3
76.2
201.6
R35
62.2
19.5
50.6
132.2
73.1
25.4
65.5
163.9
80.6
39.9
73.1
184.5
86.5
36.0
82.4
204.8
LED
62.8
19.5
49.9
132. 1
74.4
25.2
60.8
160.4
83.5
30.5
66.4
180.4
90.3
35.7
76.1
202.1
UCW
62.4
19.4
49.7
134.5
74.0
25.0
60.8
159.8
82.9
30.3
66.4
179.6
89.4
35.3
76.2
200.8
N>
•C-
-------
125
oc
<
UJ
CM
o
20
19
18
17
16
15
14
13
12
11
10
9
S
7
6
5
4
3
2
1
1980
1985
1990
YEAR
1995
2000
FIGUREE.i.iNATIONAL UTILITY SULFUR DIOXIDE EMISSIONS 1980-2000
AS PROJECTED BY USM (MILLION TONS PER YEAR)
-------
126
R35
+ 1.0 -
-1.0 h
FIGUREE.1.2PERCENTAGE CHANGE FROM BASE CASE NATIONAL INVESTOR
ELECTRICITY PRICES AS PROJECTED BY USM
-------
127
Injection with Modified Burners (LIMB) might yield reduction of both NO and SO9
A £
at costs well below those for conventional scrubbers. However, this technology is in
the developmental stage and would not be available for installation until after 1985.
A few caveats should accompany any assessment of the model results.
Results are preliminary findings and can be viewed confidently as correctly
indicative of qualitative trends. Their quantitative accuracies have considerable
error margins, due largely to inexactness of many of the models input data, such as
the energy scenario.
Cost outputs should be used with great caution. They assume a utility will seek to
minimize overall costs and it is clear that some utilities do not choose to do this,
but instead minimize capital expenditures. For example, a utility may choose to use
low-sulfur coal to meet a requirement, even though capital investment in a scrubber
may be less expensive overall.
Costs to break existing contracts are not reflected in this analysis. This is
important because of the great reliance on cleaned or low-sulfur coal, which often
requires a change in coal source for a utility.
Costs for specific power plants are expected to vary markedly (up and down) from
the typical costs modeled in this study.
Artificial constraints on use of low-sulfur coal will increase the overall control cost
of a given strategy because low-sulfur coal tends to be less expensive than
scrubbing. Such constraints could be imposed to prevent loss of coal demand from
areas having predominantly high-sulfur cost (e.g., the midwest, northern
Appalachia).
The costs for FGD are low. FGD costs in CEUM are only slightly low, but FGD
costs in USM are significantly too low. Additional analyses with more accurate
costs are underway.
Certain costs may be overstated, for example, benefits from coal cleaning from
lower O/M costs and transportation costs were not included. More generally the
benefits from pollution control were not considered in the cost-effectiveness
measures.
-------
128
E.2 IN CANADA
E.2.1 PROJECTED EMISSIONS - THERMAL POWER
Canada's electrical generating capacity is expected to increase substantially
by 1990, exceeding 1977 capacity by over 60 percent. This expansion will be noticeable
in all three major types of generation: hydroelectric, nuclear, and conventional thermal.
Hydroelectric power will maintain its leading role in the utility sector, nuclear power will
grow by a factor of three, and thermal generation will increase to a somewhat lesser
degree.
Conventional steam electric capacity, which was 19 200 MW in 1978, may
increase to 29 000 MW by the end of 1989. ' All announced steam-unit additions by 1990
will be coal-fired. This added coal-burning capacity will cause annual coal consumption to
increase by 127 percent, from 21 100 kilo tonnes in 1977 to approximately
47 900 kilotonnes in 1989. The majority of the steam-unit additions are in the provinces
of Alberta and British Columbia.
Table E.2.1 shows each province's percentage distribution of installed capacity
by generation type for both 1977 and 1989. The type categories are standard: coal steam,
oil steam, gas steam, nuclear, hydro, gas turbine, and internal combustion.
The 1989 distributions do not include the effects of any capacity penalties due
to pollution control devices and therefore represent the distributions that would occur in
the case involving no active pollution control. The changes in the distributions due to the
imposition of pollution control penalties are not great.
In Table E.2.2, the generation mix by province is presented for the two years
1977 and 1989. Note that Nova Scotia, Saskatchewan, Alberta, and British Columbia
substantially increase their share of generation from coal units. In
Statistics Canada, Electric Power Statistics, Vol. 1, Annual Electric Power Survey
of Capability and Load - 1979-1983 Forecast, 57-204 Annual (Ottawa, Ont.: Manu-
facturing and Primary Industries Division, Energy and Minerals Section, September
1979); Department of Energy, Mines and Resources, Electric Power in Canada - 1979
(Canada: Electrical Section - Energy Policy Sector, 1980); "Canada -Still Planning
for a Strong 1980," Electrical World 1980 Statistical Report, 5 March 1980.
-------
TABLE E.2.1
129
COMPARISON OF GENERATING CAPACITY MIX, BY PROVINCE, 1977
and 1989 (PERCENT)
Province
P.E.I.
1977
1989
Nfld.
1977
1989
N.S.
1977
1989
N.B.
1977
1989
Que.
1977
1989
Ont.
1977
1989
Man.
1977
1989
Sask.
1977
1989
Alta.
1977
1989
B.C.
1977
1989
NATIONAL
1977
1989
Coal
0.00
0.00
0.00
0.00
22.70
47.66
6.22
10.53
0.00
0.00
34.20
29.80
12.67
10.10
45.28
65.10
58.69
75.07
0.00
14.37
18.82
19.74
Oil
57.89
57.89
4.54
6.31
51.37
28.88
60.63
40.26
4.28
1.60
9.08
6.06
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
7.84
4.56
Gas
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
5.22
3.49
0.00
0.00
19.15
12.21
19.71
12.51
12.64
6.70
5.30
3.14
Nuclear
0.00
0.00
0.00
0.00
0.00
0.00
0.00
20.16
1.39
1.69
17.61
37.82
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
6.37
12.16
Hydro
0.00
• 0.00
92.01
90.05
11.14
15.15
31.81
28.16
92.66
85.03
31.74
21.38
86.00
88.84
28.04
17.89
16.10
8.66
82.13
75.72
58.40
54.80
Turbine
35.96
35.96
2.48
2.72
14.73
8.28
1.11
0.74
1.21
11.39
2.11
1.41
0.76
0.61
7.43
4.74
4.69
3.32
4.02
2.57
2.78
5.28
Internal
Combustion
6.14
6.14
0.96
0.92
0.07
0.04
0.24
0.16
0.46
0.29
0.05
0.03
0.57
0.46
0.10
0.06
0.81
0.43
1.20
0.64
0.47
0.31
-------
TABLE E.2.2
130
COMPARISON OF GENERATION MIX, BY PROVINCE 1977, and 1989
(PERCENT)
Province
P.E.I.
1977
1989
Nfld.
1977
1989
N.S.
1977
1989
N.B.
1977
1989
Que.
1977
1989
Ont.
1977
1989
Man.
1977
1989
Sask.
1977
1989
Alta.
1977
1989
B.C.
1977
1989
Coal
0.00
0.00
0.00
0.00
10.40
49.48
7.56
10.04
0.00
0.00
18.90
12.19
5.50
3.41
55.72
71.05
61.51
81.94
0.00
7.28
Oil
66.84
43.36
0.67
0.82
58.64
8.51
33.48
10.97
0.00
0.00
0.98
0.62
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Gas
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.23
0.14
0.00
0.00
0.79
4.32
11.07
5.82
0.51
0.23
Nuclear
0.00
0.00
0.00
0.00
0.00
0.00
0.00
21.98
0.37
0.49
28.47
54.18
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Hydro
0.00
0.00
99.19
99.05
19.14
33.47
57.99
56.94
99.55
99.05
51.33
32.80
94.40
96.53
43.17
24.40
27.12
12.08
99.21
92.35
Turbine
32.37
48.97
0.07
0.07
11.81
8.54
0.94
0.04
0.04
0.44
0.09.
0.06
0.03
0.02
0.30
0.17
0.21
0.12
0.16
0.09
Internal
Combustion
0.79
7.66
0.07
0.06
0.01
0.01
0.03
0.02
0.04
0.03
0.01
0.00
0.06
0.04
0.01
0.06
0.09
0.04
0.12
0.05
-------
131
New Brunswick and Ontario, the nuclear share of generation rises considerably. In
Newfoundland, Quebec, Manitoba, and British Columbia, hydro generation maintains its
dominant role, accounting for well over 90 percent of generation in each of these
provinces in both 1977 and 1989. Because of the expected rise in the price of gas and oil,
the utilization of steam units using these fuels may fall in some provinces.
Emissions from Canadian thermal power plants can be viewed as originating in
two major geographic subdivisions: the east (all provinces east of and including Ontario);
and the west (all provinces west of and including the province of Manitoba). The eastern
provinces have historically burned high-sulphur coals. Nova Scotia and New Brunswick
have burned locally mined coals, while Ontario has burned high-sulphur coals from U.S.
Appalachian mines in West Virginia and Pennsylvania. Some blending of these coals with
low-sulfur sub-bituminous western Canadian coals is carried out in Ontario. Power plants
in northwestern Ontario burn low-sulphur western coals. Except for British Columbia, the
western provinces (predominantly Alberta) will probably continue their current practices
of burning low-sulphur sub-bituminous coals and lignites mined within the region.
British Columbia will burn lignites.
Present Emissions
With the exception of particulate matter, there are no controls applied to
emissions from Canadian thermal power stations, other than those which occur
fortuitously, i.e., some SO2 is retained when certain western coal and lignite are burned,
if the fuel ash contains enough calcium or sodium compounds to bind part of the oxidized
sulphur during combustion. Similarly, some boilers utilize flue gas recirculation as
superheat control, which has a beneficial effect on NO suppression.
A
Thus the emissions of SC>2 an<* particuiate pollutants are ascertained by simple
calculation for each unit in provincial utility systems, given the fuel tonnage fired, and its
ash and sulphur content. The estimates for NO are less realistic, being made by the
application of a factor to the tonnage of fuel fired to any given boiler.
The historical data show that nationally in 1976:
SO2 emissions were some 553 000 tonnes
NO emissions were about 185 000 tonnes
Particulate emissions were about 168 000 tonnes
-------
132
Feasible Reductions
It needs to be accepted that it is not feasible to reduce the present emissions
from all emitters, since many units are old, or under-utilized, or lack the space to install
control equipment, or have no hope of obtaining alternative fuels.
Future emissions may increase from their present values for many existing
units, because they will be utilized to a greater degree, or they could be using fuel of
greater polluting potential. The overall national thermal generating capacity is also
increasing, and the new capacity will fire solid fuel exclusively. In addition, some eastern
oil-fired stations are very likely to be converted to coal, possibly producing greater
pollution than existed prior to conversion.
To calculate the projected emissions, it has been necessary to make
assumptions for capacity growth and generation growth in all provinces for all types of
generation. Further assumptions have had to be made on the probable degrees of control
of the various emissions that will be politically acceptable, and technically practicable for
different fuels. Most important, it has been assumed that new stations will be controlled
wherever built, but that existing units will only be controlled where they are either large
in themselves, or form part of large stations.
Table E.2.3 shows what is regarded as technologically feasible.
-------
133
TABLE E.2.3
THERMAL POWER - PROJECTED SOv AND NOV EMISSIONS
A A
(degree of stringency
varies with fuel)
Year
S0x
kilotonnes/yr
N0x
kilotonnes/yr
"Business as Usual"
(No
"Str
controls)
ingent" Controls
1983
1985
1990
1995
2000
1990
830
940
1050
1160
1280
350
330
373
470
520
570
335
-------
134
E.2.2 PROJECTED EMISSIONS FROM COPPER-NICKEL SMELTER COMPLEXES
A report recently prepared by Environment Canada provides an insight into
projected levels of SO- emissions from the Canadian copper/nickel smelting sector (1).
The projections are based on various assumptions which are considered to be the most
probable for future emissions. While based on expert analysis and current information,
they could be considerably altered by several variables. Historically, strikes, recessions,
market prices, shutdowns, etc., have all affected emission levels. Such variables are
obviously too difficult to predict very far into the future.
The last decade has reflected the effects of environmental pressures being
brought to bear on the non-ferrous smelting industry. Emissions from this sector have
decreased almost continuously since 1970 and can be attributed to process improvements,
production cutbacks, and the closure of a smelter. Throughout this period, the decrease in
total SO2 emissions was augmented by increased pyrrhotite rejection at the Inco
(Thompson), Inco (Sudbury area) and Falconbridge (Sudbury area) smelters; furthermore,
the expansion of the acid plants at Inco's iron ore recovery plant (IORP) (Sudbury area),
the addition of acid plants at the Gaspe (Murdochville) and Falconbridge smelters,
coupled with the plant modernization completed at Falconbridge, combined to reduce
emissions even more. Overall, SO* emissions from Canadian copper/nickel smelters
decreased from a level of 3.7 million tonnes in 1970 to 2.5 million tonnes in 1977, or about
32%, while at the same time nickel production decreased by about 16% and copper
production increased by close to 5% (1).
The total emission levels for 1978 (1.7 million tonnes) and 1979 (1.6 million
tonnes) were not indicative of what might have been expected on an annual basis because
of a severe 81/2 month strike which spanned both years and which served to artificially
reduce emissions at Inco's complex in the Sudbury area from approximately 1.14 million
tonnes in 1977 to about 0.54 million tonnes in each of 1978 and 1979. However, under a
new Ontario government regulation, Inco emissions at its Copper Cliff complex are
restricted to approximately 0.87 million tonnes per year starting in 1980. This level has
been chosen as the base level assumption to estimate future emissions.
Based on the historical pattern of emissions to date (1950-1980) (1), and on
current economic conditions which indicate an impending recession, it is not appropriate
to project production increases for the near future. Therefore, based on these facts and
the following assumptions:
-------
135
a recovery to normal levels of emissions at the Gaspe smelter following
the six-month strike in 1979,
a recovery at Inco's Copper Cliff smelter to the maximum allowable
emission level as established by the Ontario government.
the emission levels at each smelter in 1980 are estimated to be as indicated in
Table E.2.4. This being the case, the total SO2 emissions for this sector would be
approximately 2.04 million tonnes in 1980. These estimates form the base figures for all
subsequent projections.
TABLE E.2.4 SO2 EMISSION ESTIMATES BY OPERATION, 1980
Operation
Noranda - Home
- Gaspe
Falconbridge
Hudson Bay Mining
and Smelting
Million
tonnes
0.54
0.07
0.15
0.19
Operation
Inco- Thompson
- Copper Cliff
- IORP
OVERALL TOTAL
Million
tonnes
0.23
0.80
0.07
2.04
Scenario I
The validity of this scenario is dependent upon the existence of a status
quo with respect to production capacity, pollution control and technological innovation
and implementation. In essence, this unlikely situation disregards the future short-term
effects of recessions, booms, or labor problems, and the long-term effects of pressures
from environmental quarters to improve the existing situation.
Assuming that emission levels will remain unchanged throughout this period
provides a ceiling level for emissions. Therefore, it is projected that the worst case would
be approximately 2.0 million tonnes of SO^ emitted annually from this sector in the year
2000 (see Figure E.2.1).
-------
3OOO
27 5O
250O
^^
r>
o
T-
X 2250
ui
Z
Q 20OO
h-
*—.'
Z 1750
g
0)
2 15OO
111
$ 1250
10OO
75O
1 I I I I I T
1 I I I I I I I I I I I
1980
I I I I I I
I I I I I
1985
199O
YEAR
1995
SCENARIO I
a\
SCENARIO III
SCENARIO II
200O
HGURE E 2 1 S02 EMISSION PROJECTIONS, ANNUAL AVERAGES, 1980-2000
-------
137
Scenario II
This scenario denotes the "best case" effect. It incorporates changes
attributable to both technological improvements and environmental pressures. It assumes
that short-term fluctuations due to recessions, booms, or labor problems will be averaged
out on the long-term basis.
Based on expert analysis, several changes are predicted at the various
smelters. Generally, the reductions can be attributed directly to conformity with control
orders, process improvements, acid plant construction, and industrial hygiene pressures.
This scenario assumes that any production growth at the various smelters
already in existence will be negligible or, if any occurs, process improvements would
negate the consequences with respect to emissions. The Texas Gulf smelter is the only
one for which capacity increases are forecast, and emissions have been duly increased to
account for this.
Based on this analysis, five-year averages of emissions would decrease
continuously from recent emission levels (1975-1979) of 2.17 million tonnes to 0.87 million
tonnes by the end of the century. This represents an optimistic decrease of 60% without
sacrificing production output (see Figure E.2.1 and Table E.2.5).
Scenario III
The third scenario does not provide a projection but rather suggests a
figure somewhere within the range established by I and II. It is probably the most likely
situation since it accounts for the large amount of uncertainty associated with the other
projections.
While Scenario I assumes a pessimistic outlook that technological improve-
ments and pollution control will not occur or at least will not be implemented, Scenario II
assumes optimistically that improvements will be implemented at all smelters. Neither
situation in highly probable. This is evident on examining past performance with respect
to events that should have (theoretically at least) the highest degree of probability of
occurrence. One would assume that compliance with control orders would have a high
degree of certainty. However, economic situations and political pressures dictate not
only changes to the magnitude of the figures involved, but also the time frames originally
referenced. Since economic conditions are at best difficult to predict and political
pressures, being dependent on expediency, are impossible to forecast, the probability of
compliance with any specified time frame or specific emission level is low.
-------
TABLE E.2.5
138
PROJECTED SO-, EMISSIONS FROM COPPER-NICKEL SMELTER
COMPLEXES, ANNUAL TOTALS AND 5-YEAR AVERAGES,
1980 - 2000
Year
Emission
Year
Emission
Year
Emission
Year
Emission
1980
2.04
1985
1.77
1990
1.08
1995
0.87
1981
1.99
1986
1.55
1991
1.08
1996
0.87
Million
tonnes
1982
1.96
1987
1.55
1992
0.87
1997
0.87
1983
1.86
1988
1.23
1993
0.87
1998
0.87
1984
1.86
1989
1.23
1994
0.87
1999
0.87
5-year
averages
1.94
1.47
0.95
0.87
Thus, Scenario III assumes that some environmental control and technological
improvements will occur in this sector, that production will be near or at capacity, and
that the resulting emissions will be somewhere between 2.04 million tonnes and
0.87 million tonnes by the year 2000 (see Figure E.2.1).
It should be noted that under present conditions the environmental conscience
of society has been aroused by an awareness of the dangers posed by acid rain. This
arousal should, in all probability, ensure that some action will be taken to reduce
emissions and hence Scenario III would tend to be in the more optimistic range.
As indicated in Figure E.2.2, it is anticipated that future emissions will be at
least lower than in any of the previous periods examined. Should the most optimistic
scenario prove valid, emissions by the year 2000 will have decreased approximately 75%
from the peak levels recorded in the 60's. It is of note that levels have diminished close
to 40% since the 1960's, so that a goodly portion of the reduction is still to come as
indicated in Figure E.2.3.
-------
(0
4OOO
3750 —
195O-54 1955-59 196O-64 1965-69 197O-74 1975-79 198O-84
FIVE-YEAR AVERAGE PERIOD
1985-89 199O-94 1995-2OOO
HGURE E.2.2
SO? EMISSIONS FROM COPPER/NICKEL SMELTERS, ACTUAL
AND PROJECTED, FIVE YEAR AVERAGES, 1950-2000
-------
**\JU\J
s**\
r>
o
*• 3OOO
X
(TONNES
10
O
O
O
Z
O
(0
5 1000
UJ
04
o
n
-
-
-
.;.;.;.;.;
>;Xv!
I
i?i£i
iwiii;
^=K
•:•:•:•:•:
•jijiig
38%
-
•i'i'?;-
•jig!
58%
•••VH
%g
-
75% _
-
-
1965-69 1975-79 1985-89
FIVE-YEAR AVERAGE PERIOD
1995-99
riGURE E.2.3
PAST & PROJECTED SO? EMISSION DECREASES EXPRESSED AS
A PERCENTAGE OF PEAK EMISSIONS IN 1965-69 (BASED ON
SCENARIO II PROJECTION)
-------
REFERENCES
1. Environment Canada, Air Pollution Control Directorate, Copper-Nickel Smelter
Complexes in Canada, SO0 Emissions (1950-2000). Report EPS 3-AP-80-5
(January 1981).
-------
E.2.3 PROJECTED EMISSIONS - MOBILE SOURCES
Assuming normal growth rates in both numbers of cars (3%) and annual miles
travelled by each car (3%) and in the absence of further control action at either the
design or in-use levels, total NO emissions from motor vehicles can be projected to
increase by 30 to 50% between 1980 and 1990.
If more stringent new vehicle emission standards become effective with the
1985 models, (which will result in catalytic control of NO with a corresponding reduction
A
in the number of vehicles fitted with EGR valves) conceivably the actual emissions could
be reduced (as a weighted average of the whole fleet) to the neighborhood of about
1.3 grams per mile in 1990. Total emissions would then be reduced about 20% from 1980
levels in spite of the assumed increases in car numbers and mobility.
In the absence of more stringent new vehicle standards it is conceivable that
the tampering rate (with EGR valves - discussed elsewhere) might be beneficially affected
by an inspection program on in-use vehicles. At the present time, however, we know of no
effective test procedure let alone the actual quantitative benefits on NO emissions that
might result from such an inspection program.
-------
F. CONSTRAINTS ON AND BOUNDARIES OF ANALYSIS
This interim report addresses the initial concern, acid rain precursor emissions
and sources only. The information presented in this report is predominantly for the
eastern part of North America, i.e. roughly east of a north-south line running along the
Manitoba-Saskatchewan border in Canada and the Mississippi River in the United States.
A detailed review of the following major sectors is included:
a) Thermal Power for SO and NO
A A
b) Non-Ferrous Smelters for SO
A
c) Mobile Sources for NOX
Other pollutants are mentioned in these sectors but have not been reviewed in
detail.
Technology for the control of these pollutants is reviewed on a general basis
but no site-specific assessments have been made.
Costs of control are also reviewed, in general terms, but no detailed site-
specific assessments have been made.
A brief review of the following sectors is included:
a) Petroleum refining for SO and NO
A A
b) Industrial, residential and commercial fuel combustion for SO and NO
A A
c) Incinerators for SO and NO
A A
d) Pulp and paper for SOx and NOX
No detailed review or assessment of control technology and costs has been
made for these sectors.
SO and NO emissions are presented for all source sectors but no review of
A A
control technology or costs has been carried out, except as listed above.
Information on other pollutants, such as photochemical oxidants may be
included in future reports if it is determined that they play a significant role in the
transformation of SO and NO to acid-causing species.
A A
-------
G. RECOMMENDATIONS FOR FUTURE APPLIED R & D ACTIVITIES
A number of future applied R & D activities have been identified in this
interim report for consideration. Future reports will address this activity in greater
detail.
Recommendations
1. Development of improved lower energy consuming reliable FGD systems for thermal
power, especially regenerative types.
2. Process/control technology development for the reduction of SO emissions from
non-ferrous weak strength gas streams.
3. Research on methods, products and markets to reduce cost and energy consumption
and improve environmental acceptability for the disposal of sulphur by-products.
b. Development of improved control technology for NO .
5. Development of systems/technology to accelerate the reduction of NO emissions
A
from the existing transportation fleets.
6. An intensive R&D effort is required to characterize U.S. and Canadian coal
resources in terms of their "cleanability" and to develop improved, less expensive
methods of coal cleaning.
7. A long-term commitment to develop cleaner less expensive methods of coal
combustion, such as coal gasification, should be made.
8. Improved estimates of current United States and Canadian emissions are needed. In
particular, total U.S. emissions need refinement and disaggreation on a smaller
geographic scale than is currently available. In addition, research is needed on
seasonal variations in emissions and on primary emissions of sulfates.
9. An improved data base on NO emissions is required.
10. A long-term demonstration project on coal-limestone pellets using large stoker-fired
boilers should be undertaken.
11. A near-term R&D project to demonstrate the emissions reductions achievable with
and the economics of spray dryer FGD processes applied to high sulfur coals is
required.
-------
145
12. A long-term demonstration project on advanced low NO coal burners using
A
pulverized coal should be funded.
13. Bench scale, pilot scale, and demonstration scale projects are needed to test
limestone injection/multistage burner control technology.
14. Research is needed on advanced particulate control concepts that will lower the
capital cost and operating costs associated with spray dryer SC^ control.
15. SO- add-on control for smelters need to be studied, especially alternative acid plant
configurations.
16. Innovative technologies for smelting operations need to be tested and demonstrated.
-------
146
-------
1*7
APPENDIX I
-------
1*8
-------
APPENDIX I
1 TERMS OF REFERENCE
The Terms of Reference contained in the Memorandum of Intent are:
This Work Group will provide support to the development of the "Control"
element of an agreement. It will also prepare proposals for the "Applied Research and
Development" element of an agreement.
In carrying out its work, the Subgroup will:
identify control technologies, which are available presently or in the near future,
and their associated costs;
review available data bases in order to establish improved historical emission trends
for defined source regions;
determine current emission rates from defined source regions;
project future emission rates from defined source regions for most probable
economic growth and pollution control conditions;
project future emission rates resulting from the implementation of proposed
strategy packages, and associated costs of implementing the proposed strategy
packages; and
prepare proposals for the "Applied Research and Development" element of an
agreement.
Work Plans, for this Work Group, have been submitted to Work Group 3A. The
Work Plans will be modified as directed in Work Group 3A and to address problems
identified in this Interim Report.
-------
150
U.S. MEMBERS OF WG3B
Kurt W. Riegel (Chairman of WG3B)
Associate Deputy Assistant Administrator
Office of Environmental Engineering and Technology (RD-681)
U.S. Environmental Protection Agency
Lowell Smith
Director, Program Integration and Policy Staff
Office of Environmental Engineering and Technology (RD-7681)
U.S. Environmental Protection Agency
Robert Statnick
Office of Environmental and Engineering and Technology (RD-681)
U.S. Environmental Protection Agency
Bruce Jordan
Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency
Conrad Kleveno
Office of International Activities (A-106)
U.S. Environmental Protection Agency
Robin Porter
Office of Canadian Affairs
U.S. Department of State
Jack Blanchard
Office of Environment and Health
U.S. Department of State
Peter House (Vice Chairman WG3B)
Director
Office of Environmental Assessments
U.S. Department of Energy
Dick Harrington
Morgantown Energy Technology Center
U.S. Department of Energy
Douglas Carter
Regulatory Analysis Division
Office of Environment
U.S. Department of Energy
John Burckle
Industrial Environmental Research laboratory
Office of Research and Development
U.S. Environmental Protection Agency
-------
151
CANADIAN MEMBERS OF WG3B
Chairman
Vice-Chairman
Members
H.A. Bambrough
E.T. Barrow
3., Knight
A. Castel
P.J. Choquette
W. Craigen
T.W. Cross
G. Kowalski
W. Lemmon
P.J. Read
C.L. Warden
M.E. Rivers, Director General
Air Pollution Control Directorate
Environment Canada
L. Lapointe, Directeur
Assainissement de 1'Air
Environnement Quebec
Head of Thermal Power Generation Section
Abatement and Compliance Branch
Air Pollution Control Directorate
Environment Canada
Head, New Technology and Process Evaluation Unit
Air Resources Branch, Ontario Ministry of Environment
Director of Environment Services Branch
New Brunswick Department of Environment
Director, Program Planning and Evaluation Branch
Ontario Ministry of Environment
Chief, Pollution Data Analysis Division
Air Pollution Control Directorate
Environment Canada
Head, Engineering and Economic Evaluation
Canada Centre for Mineral and Energy Technology
Department of Energy, Mines and Resources
Director, Air Resources Branch
Ontario Ministry of the Environment
Senior Economic Analyst, Economic and Policy Analysis Sector
Department of Energy, Mines and Resources
Chief, Mining, Mineral and Metallurgical Division
Air Pollution Control Directorate
Environment Canada
Adviser, Supply and Utilization, Energy Policy Sector
Department of Energy, Mines and Resources
Policy Advisor, Metallic Minerals Section
Mineral Resources, Ontario Ministry of Natural Resources
-------
152
Liaison
R. Beauiieu United States Transboundary Relations Division
Department of External Affairs
A. Manson Programme Coordinator, Air Pollution Control Directorate
Environment Canada
-------
153
APPENDIX 2
-------
-------
155
APPENDIX 2
CONTENTS
Magnitude and Distribution of Eastern Canada SO2 emissions - 1976 data base
(map)
Magnitude and Distribution of Eastern Canada NO emissions - 1976 data base
(map) x
Listing of Eastern Canada SO2 emissions on the 127 km x 127 km grid -1976/80
data base
Listing of Eastern Canada NO emissions on the 127 km x 127 km grid -
1976/80 data base
-------
52
54
56
58
BO
MAGNITUDE AND DISTRIBUTION OF EASTERN CANADA S02 EMISSIONS 1976 DATA BASE ON 127 km * 127 km GRID
IMPORTANCE ET REPARTITION DES EMISSIONS DE SQ2 DANS L'EST DU CANADA DONNEES DE 1976 SUR GRILLE DE 127 km x 127 km
-------
54
56
58
60
62
64
66
68
72
74
46
42
38
36
34
32
30
28
\
2
2
3
2
,3-i
3
4
\
,iv
2
3
2
3
3
2
3
Li-Vft
Qi
2
3
COORDONNEE X COORDINATE r
42
4O
38
36
34
32
3O
28
in
-Nl
52
56
58
60
62
64
66
68
7O
72
76
78
MAGNITUDE AND DISTRIBUTION OF EASTERN CANADA NOX (EXPRESSED AS N02) EMISSIONS 1976 DATA BASE ON 127 km x 127 km GRID
IMPORTANCE ET REPARTITION DES EMISSIONS DE NQX (EXPRIMEES EN N02) DANS L'EST DU CANADA DONNEES DE 1976 SUR GRILLE DE 127 km * 127 km
-------
158
LISTING OF EASTERN CANADA SO2 EMISSIONS ON THE 127 km x 127 km GRID
CANADIAN EMISSIONS DATA - 1976
(PRELIMINARY) (IN TONNES)
(y coord.)
47
46
45
44
43 84
42 152 226
41 522
40 123
39 40 262
38 187 568
37 150 6 073
36 15
35
34
33
32
31
30
29
28
51 52
SOX (as S02)
THROUGH 1980 - ANNUAL ESTIMATES
2 6
2
59 16 334 019 48
13 62 14
10 1 13
49 10 5
167 124 6 10
13 618 4 115 29 240
508 230 1 498 959
866 193
53 54 55 56
(x coord.)
27
1
1
2
1
1
34
937
67
57
-------
159
CANADIAN EMISSIONS DATA - 1976
(PRELIMINARY) (IN TONNES)
(y coord.)
47
46
45
44
43
42
41
40
39 32
38 17
37 92
36 24 8
35 583 581
34. 6 897
33
32
31
30
29
28
58 59
SOX (as SO2)
THROUGH 1980 - ANNUAL ESTIMATES
1
1 45
18 1 1
233 227 5 296 398
557 182 264 13 4 873
1 190 33 36
2 765 1 411 1 006 890
79 250
19 593 4 721
200 212 182 485
7 415 4 115 213
60 61 62 63
(x coord.)
1
16
105
90
83
1
133
540 695
1 140
6 060
1 299
35 656
210 026
64
-------
160
CANADIAN EMI:
(PRELIMINARY)
(y coord.)
47
46
45
44
43
42
41
40
39
38
37
36
35 1
34 2
33
32
31
30 7
29
28
5SIONS DATA - 1976
(IN TONNES)
16
26
1
1 1
049 78
929 24
11 31
997 2 214
723 20 565
037 14 291
65 66
SOX (as S02)
THROUGH 1980 - ANNUAL ESTIMATES
5
10
1
747
226
51
219
7 615
17 442
67
2
4 4
21
321
1 1 289
1 1 46
1 27
3 019 514 875
1 907 27 876 5 750
6 540 46 899 3 263
149 096 15 323 3 147
143 356 8 932
68 69 70
(x coord.)
55
1 507
1 417
4 059
13 017
7 320
1 570
71
-------
161
CANADIAN EMI!
(PRELIMINARY)
(y coord.)
47
46
45
44
43
42
41
40
39
38
37
36 73
35 10
34 16
33 14
32 5
31
30
29
28
5SIONS DATA - 1976
(IN TONNES)
4
10
108
81 241
107 889
229 6 332
963 12 322
549 45 808
539 95 557
288 5 321
88
72 73
S0x (as S02)
THROUGH 1980 - ANNUAL
3
493
1
1
44
12 603
12 841
18 882
4 745
134
74
21
1
61
618
6 387 34
31 031 37
68 080
75
(x coord.) .
ESTIMATES
17
50 260
281 299
185 826
5601 5.412
830 657
218
578 107
501
0
76 77
55
94
4 935
363
309
78
-------
162
SOX (as S02)
CANADIAN EMISSIONS DATA - 1976 THROUGH 1980 - ANNUAL ESTIMATES
(PRELIMINARY) (IN TONNES)
(y coord.)
47
46
45
44
43
42
41
40
39 25
38 2 188 419
37 11 404 19 870
36 1 949 444
35
34
33
32
31
30
29
28
79 80
(x coord.)
-------
163
LISTING OF EASTERN CANADA NOX EMISSIONS ON THE 127 km x 127 km GRID
CANADIAN EMISSIONS DATA - 1976
(PRELIMINARY) (IN TONNES)
(y coord.)
47
45
44
43
42 670
41 1 052
40 1 004
39 204 1 561
38 963 2 846
37 821 10 127
36 88
35
34
33
32
31
30
29
28
51 52
NOX (as N02)
THROUGH 1980 - ANNUAL
618
715
624
355
673
961
40 121
2 257
53
(x
41
413
635 1
748
208
310
857
7 813 1
1 360 1
1
54
coord.)
ESTIMATES
14 7
271
949 625
489 579
543 461
408 40
873 858
237 1 459
678 2 317
500 1 026
55 56
182
55
156
57
23
622
1 031
1 368
1 430
427
57
-------
164
CANADIAN EMISSIONS DATA - 1976
(PRELIMINARY) (IN TONNES)
(y coord.)
47
46
45
44
43
42
41
40 9
39 23 18
38 274 25
37 1 330 842
36 1 093 1 261
35 1 831 1 703
34 6 717
33
32
31
30
29
28
58 59
NOX (as NO2)
THROUGH 1980 - ANNUAL ESTIMATES
2
5
18
345
316 207 1
1 637 1 288 2 119 1
1 484 1 687 1 403 4
1 626 1 436 1
5 264 3 183 10
200
1 100 9
34 691 93
13 481 7 855
60 61 62
(x coord.)
1
24
18
279
412
841
911
469
764
748
286
019
533
63
1
63
50
162
537
645
3 543
2 397
5 154
4 056
67 084
172 391
64
-------
165
CANADIAN EMISSIONS
(PRELIMINARY) (IN TC
(y coord.)
47
46
45
44
43
42
41
40
39
38
37
36 -
35
34
33
32
31
30
29
28
l
15
37
12
76
191
914
2 729
183
2 646
2 623
13 072
65
NOX (as N02)
i DATA - 1976 THROUGH 1980 - ANNUAL ESTIMATES
)NNES)
86
191
225
190
187
2 181
34 266
14 938
66
3
17
143
677
345
225
361
6 092
13 616
67
1
3
1
125
191
191
1 488
1 380
4 421
71 366
105 327
68
(x coord.)
33
19
163
125
29
562
10 939
29 720
11 994
6 761
69
3
206
354
144
183
833
4 944
3 051
2 653
70
17
733
1 137
561
7 328
4 407
920
71
-------
166
CANADIAN EMISSIONS
(PRELIMINARY) (IN TC
(y coord.)
47
46
45
44
43 22
42
41
40
39
38
37
36
35
34
33
32
31
30
29
28
483
93
921
4 515
2 668
8 178
2 652
151
72
NOX (as N02)
i DATA - 1976 THROUGH 1980 - ANNUAL ESTIMATES
)NNES)
213
674
899
786
19
229
865
3 424
6 720
11 053
19 919
3 297
67
73
311
599
1 877
639
191
106
6 822
7 008
11 303
2 300
71
74
124
899
311
202
563
1 366
11 952
24 161
75
(x coord.)
14
121
485
421
1 388
1 043
243
19 805
11 146
76
374
803
1 497
3 416
1 105
59
0
77
110
3 717
1 280
344
78
-------
167
NOV (as NO,)
J\ £~
CANADIAN EMISSIONS DATA - 1976 THROUGH 1980 - ANNUAL ESTIMATES
(PRELIMINARY) (IN TONNES)
(y coord.)
47
46
45
44
43
42
41
40
39 37
38 2 461 294
37 3 942 11 200
36 1 400 448
35
34
33
32
31
30
29
28
79 80
(x coord.)
------- |