COUNTDOWN ACID RAIN
FUTURE ABATEMENT STRATEGIES
APRIL 1991
Ç Environment
Environnement
Ontario
| > LS
ISBN 0-7729-5986-2
COUNTDOWN ACID RAIN
FUTURE ABATEMENT STRATEGIES
Summary Report
Report prepared for:
Air Resources Branch
Ontario Ministry of the Environment
APRIL 1991
Co
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COUNTDOWN ACID RAIN
FUTURE ABATEMENT STRATEGIES
Summary Report
Report prepared by:
SENES Consultants Limited
52 West Beaver Creek Road
Unit No. 4
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APRIL 1991
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DISCLAIMER
The conclusions, opinions and recommendations expressed in this
report are those of the consultant and do not necessarily represent
the views of the Ontario Ministry of the Environment. In addition,
the consultant is solely responsible for the accuracy of data and
estimates presented in this report.
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FOREWORD
This report presents a study of SO, and NO, emission sources in
Ontario and proposed emission control strategies to achieve
further reductions of SO, and NO, after 1993. The report
consists of a summary document supported by three
appendices.
Summary The summary document describes the findizgs of 3
phases of the study and draws conclusions on
abatement strategies.
Appendix 1 The Phase 1 Report sets out a 1985 base year
emission inventory for SO, and NO,, examires past
trends, and outlines five basic future scenarios.
Appendix 2 The Phase II Report identifies the sostis! (of
reducing SO, and NO, using alternative emission
control technologies required to meet the emission
targets identified in the Phase I Report.
Appendix 3 The Phase III Report develops alternative COSES
effective abatement strategies that achieve
pre-specified aggregate emission targecs. The
computer model developed for the foregoinz work is
described.
This This document describes the Summary.
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Summary Report
Countdown Acid Rain
Future Abatement Strategies
to control emissions that cause acid rain
The overall objective of this study is to evaluate the cost effectiveness of alternative
emission control technologies for sulphur dioxide (SO2) and nitrogen oxides (NOx)
emissions in Ontario. This study is an initial examination which points the way to
further investigations. It is part of a larger effort by the Government of Ontario to
determine how and where to control emissions that cause acid rain and other damaging
effects.
4 reports
Four reports make up the documentation for this study. The "Phase 1 Report" sets out a
1985 emission inventory for SO2 and NOx by major point sources, industrial sectors
and area sources. The "Phase 2 Report" identifies the costs and contaminant removal
capabilities of alternative emission control technologies. The "Phase 3 Report" outlines
alternative cost effective abatement strategies and sets out the user-friendly modelling
framework for changing the assumptions and allowing for technological changes. This
"Summary Report" presents an overview of findings contained in the preceding
documents, draws conclusions and recommends an implementation plan.
4 major SO2 Emitters
In 1985 SO2 emissions in Ontario totaled 1.458 million tonnes. Of this volume
non-ferrous smelters contributed 53 per cent followed by electric utilities at 23 per cent,
ferrous smelters at 10 per cent and area sources at 4 per cent (refer to Figure 1).
Figure 1
Total SO2 Emission
1985
Sources
7.30% Others
Non-Ferrous
52.90%
The 15 largest SO2 point source emitters are set ou
Hydro, Algoma Ore and Falconbridge stand out as
these INCO is the leader by a wide margin.
Table 1
9.70% Ferrous
3.80% Area
Sources
Electric
23.00%
3:09 Utilities
3.30% Petroleum
Refineries
tin Table 1. Of these INCO, Ontario
the dominant emitters and among
15 Major Point Sources of SO2 in Ontario
(1985)
INCO (Sudbury)
Ontario Hydro
Algoma (Wawa)
Falconbridge (Sudbury)
Imperial Oil (Sarnia)
Shell Canada (Corruna)
Lake Ontario Cement (Picton)
Algoma (Sault Ste. Marie)
Stelco (Nanticoke)
Courtauld's Canada Ltd. (Cornwall)
Petrosar Ltd. (Corruna)
James River Marathon (Marathon)
Texaco Canada (Nanticoke)
Dofasco Inc. (Hamilton)
Kerr Addison (Virginiatown)
The largest area emitters as illustrated below are vehicles and industrial/commercial
Tonnes/Year
695,008
336,633
115,890
74,352
19,595
16,103
7,748
7,419
6,920
6,517
6,260
6,225
6,210
6,126
5,144
1,316,150
heating. Together they emit 3.80 per cent of the total SO2 in Ontario.
Figure 2
SO2 Area Sources
1985
Other Trans 1.40% Other Sources
12.50%
Licensed Vehicles
Marine 32.80%
11.80%
Res Heating
15.90%
25.60%
Comnvind Heating
Figure 3 shows that between 1980 and 1985 SO2 emissions from industrial sources
declined by 17 per cent while emissions from area sources fell by 29 percent. The trend
between 1982 and 1985 shows an increase in SO2 emissions.
Figure 3
SO2 Emissions Trends
1980-1985
1,800,000 g——~
1,600,000
1,400,000
1,200,000
1,000,000
800,000
600,000
400,000
200,000
0 PS HS
1980 1981 1982 1983 1984 1985
Year
Æ- Industry Sources
©- Area Sources
‘B- Aggregate
oor 3 © a4
area sources generate majority of anthropogenic NOx
NOx emissions in 1985 amounted to 612 kilotonnes. Of this total, transportation and
area sources dominate at 71.1 per cent. Electric utilities are next at 15.4 per cent,
followed by space heating at 6.8 per cent, non-ferrous / ferrous smelters at 3 per cent,
refineries at 2.9 per cent, marine at 1.2 per cent and others at 7.5 per cent ( refer to
Figure 4 ).
Figure 4
Total NOx Emission Sources
1985
Others 7 54% Non-Ferrous
3.00% / Ferrous
15.42% Electric
Utilities
Vehicles
53 45% 2 90% Petroleum
Refineries
Other Area
17.72% Sources
The 10 largest point source emitters for NOx are identified in Table 2. Ontario Hydro
is the dominant generator.
Table 2
10 Major Point Sources of NOx in Ontario
1985
Tonnes/Y ear
Ontario Hydro 94,437
Stelco (Hamilton) 5,567
Petrosar Ltd. (Corunna) 9925
INCO (Sudbury) 4,893
Imperial Oil (Sarnia) 3,629
Algoma Steel Corp (Sault Ste. Marie) 3,207
Dow Chemical (Sarnia) 3,080
Esso Chemicals (Sarnia) 2,920
Stelco (Nanticoke) 2,602
Gulf Canada Ltd. (Mississauga) 2,238
128,098
Among area sources, vehicles and other transportation account for 91.2 per cent of the
emissions while heating accounts for 6.8 per cent, marine for 1.2 per cent and other
sources for .8 per cent ( refer to Figure 5 ).
Figure 5
NOx Area Sources
1985
Other Sources 0.80% Other
16.10% Transportation
1.20% Marine
6.80% Heating
NOx emissions between 1980 and 1985, from all sources as shown in Figure 5,
revealed a decline of 2 per cent from industrial sources and a growth of 8.5 per cent
from area sources. The aggregate emissions between 1980 and 1985 showed an
increase of 5.3 per cent excluding emissions from forest fires.
Figure 6
NOx Emission Trends
1980-1985
Resa coe case GP,
600,000 = = 3
500,000
©
400,000 Oe Oe
©- Area Sources
300,000
ere M- Aggregate
100,000 ee
0
1980 1981 1982 1983 1984 1985
Year
Æ- Industry Sources
oo 3 3 © 4
1994 emission targets specified for major point sources
In recognition of the serious environmental damage being caused by acid rain, the
Government of Ontario recognized in 1985 that SO2 and NOx emissions must be
reduced. Accordingly they encouraged all emitters to utilize abatement equipment and
procedures and they legislated that the four major point sources, INCO, Ontario
Hydro, Algoma and Falconbridge, must meet prescribed minimum emission limits for
SO? and NOx by 1994. These limits are set out below.
Table 3
Company Regulation 1985 Emissions 1994 Emission Limits
SO2 NOx SO2 SO2+NOx
(Kilotonnes) (Kilotonnes)
INCO 660/85 695.0 4.9 265.0 -
Falconbridge 661/85 74.4 0 100.0 -
Ontario Hydro 281/87 336.6 94.4 17520 215
Algoma (Wawa) 663/85 115.9 O0 125.0 -
* Estimated
10 industrial sectors emit large quantities of SO2 and NOx
There are ten industrial sectors that give rise to the majority of SO2 and 13.4 per cent of
NOx emissions. These are:
+ Primary Metals
+ Transportation Equipment *
+ Non Metallic Mineral Products
+ Chemicals and Chemical Products
+ Food and Beverages
¢ Textile Industries
+ Metal Fabricating
+ Paper and Allied Products
+ Others - includes municipal and sewage sludge incinerators, commercial
enterprises and institutions such as hospitals and universities
* Rubber and Plastics - SO2 emissions only
* Does not not include vehicles
many potential abatement technologies but only a few are well proven
A wide variety of abatement technologies is available to control SO2 and NOx
emissions. Thirty-eight systems were identified and discussed during the course of this
study. In the end it was concluded that only a few were proven and acceptable. The
other technologies may be used, but those examined in this Study can serve as
Surrogates, setting benchmark costs which would be incurred. Chief among the
systems examined for SO2 were flue gas desulphurization, petroleum fuel
desulphurization and fuel switching. For NOx control, the preferred means of
abatement included catalytic converters for mobile sources, and for point sources, low
NOx burners, lower excess air, selective non-catalytic reduction and selective catalytic
reduction.
fuel desulphurization, fuel switching and flue gas desulphurization for SO2
9 né 22 EPR AON JOT 1907
As the name implies petroleum fuel desulphurization is accomplished by lowering the
sulphur content of fuel oils. Fuel switching as used in this study involves changing
from coal and oil to natural gas. In the case of flue gas desulphurization there are two
basic types of systems - wet and dry. Wet scrubbing systems absorb SO? from the gas
stream into a slurry of an alkaline chemical forming a sulphate. The most widely used
Systems employ lime or limestone as the alkaline reactant. Dry scrubbing systems have
not been used the same length of time as wet systems, but they are becoming prevalent
with power utilities, industries and municipalities. In these systems, adsorption of SO2
and other acid gases takes place when the flue gas comes in contact with a sprayed dry
or slurry sorbent.
Sulphur dioxide emissions are primarily generated by general industry during the use
of boilers and in some processes. In the case of boilers the means of emission
abatement that hold most promise are flue gas desulphurization and fuel changing to
low sulphur fuel oils or natural gas. Abatement of SO2 emissions from industrial
Processes appears to be best accomplished through the use of flue gas desulphurization
technologies.
low NOx burners, lower excess air, selective non-catalytic and catalytic
reduction for NOx
Low NOx burners are seen to hold significant promise as a means for reducin g NOx
emissions. They are designed to control the air/fuel ratio in the burner area thereby
retarding the formation of NOx from fuel bound nitrogen. Lower excess air involves
8
reducing NOx concentrations by lowering combustion air rates so that exhaust gases
have a oxygen content of approximately 3 per cent. Both selective non-catalytic
reduction and selective catalytic reduction are post combustion controls. The former
reduces NOx through the addition of ammonia and very high temperatures. The latter
relies on ammonia in the presence of a catalyst to reduce NOx to N2 and water vapour.
Nitrogen oxide emissions generated by general industry through the use of boilers can
best be controlled by making changes to fuel burners or by modifying the actual boiler
furnace operations. In the latter case the most commonly used technology is low
excess air which involves reducing the amount of air supplied to the burner system. In
the case of production processes, NOx abatement is best achieved through catalytic
reduction technologies.
Small incremental fuel switching for NOx is not usually carried out. However, when
fuel is switched to reduce SO2 by substituting natural gas there is a benefit in that lower
NOx emissions are produced as a result of the elimination of fuel nitrogen in the
substituted natural gas.
catalytic convertors for mobile sources
NOx emissions are dominated by mobile source emissions ( which are now subject to
Federal regulation ). Control options are (1) a catalytic convertor required on new cars
by federal regulation limiting emission to one gram of NOx per mile and (2) a more
efficient catalytic convertor that exceeds the federal requirement and reduces NOx
emissions to 0.4 grams per mile.
abatement controls considered by the model as illustrations for the 4 major
point sources
The four major point sources have been investigating a variety of abatement options in
order to exceed their prescribed emission limits by 1994. The following processes
appear to hold the most promise.
Falconbridge does not currently exceed the 1994 target emission limits for either SO2
or NOx. According to the model used in this study further reductions are possible if
separate streams of exhaust gases are treated by dry lime injection using a spray-dryer.
Implementation of this form of abatement control could reduce annual SO2 emissions
by 50 kilotonnnes.
9
At INCO the remaining gas streams to be controlled involve a vast number of low
strength sources. Despite what INCO is actually doing, for the purposes of this Study it
was assumed they could be controlled at a single emission point by limestone scrubbing
and that a suitable location for the resultin g limestone sludge could be found on the
company property.
In the case of Algoma the abatement process that seems best suited to further lowering
SO? emissions is wet flue gas desulphurization using limestone.
The most cost effective technology for controlling SO? from Ontario Hydro generating
Stations appears to be a high efficiency wet flue gas desulphurization process using
limestone. NOx emissions might be cost-effectively controlled by installing selective
catalytic reduction units at suitable locations.
abatement controls: How effective? How costly?
The cost effectiveness of selected SO? and NOx abatement technologies applied to the
four major point sources and the nine significant industrial sectors are briefly explained
below.
In their 1988 Progress Report, INCO estimates that an annual production of 240
million pounds of nickel will allow them to achieve their 1994 emission limit for SO.
À further 10 percent reduction below this limit would involve an annualized cost of
$752 per tonne of SO2 removed (Appendix 2, Table 4-1). If a 50 per cent reduction is
pursued, economies of scale come into play and an annualized cost of $362 per tonne
of SO2 removed would be incurred.
Ontario Hydro's coal and oil fired generating stations have a total rated generating
capacity of 99.4 million megawatt hours per annum. Assuming full output from these
Stations, the utility would face an annualized Cost per tonne of SO2 removed of
$848 if prescribed emission targets is exceeded by 10 per cent and $847 if itis
surpassed by 50 per cent ( source Appendix 2,Table 4-1). For NOx the annualized
amount would be approximately $446 per tonne in both cases ( source Appendix 2,
Table 4-3).
Based on a nickel production rate of 88 million pounds per year, Falconbridge will
incur an annualized cost of $1,158 dollars per tonne for a further 10 per cent reduction
10
in SO2 emissions and a $1,566 per tonne annualized cost for a further 50 per cent
reduction (Appendix 2, Table 4-1) .
Based on approximately 1.0 million tonnes of iron ore sinter production per year,
Algoma will incur an annualized cost of $110 per tonne of SO2 removed given a 20 per
cent reduction, and $835 for a 50 per cent reduction (Appendix 2, Table 4.1).
The annualized costs per tonne of SO2 removed in the nine industrial sectors which are
significant emitters of SO2 and NOx show a considerable range from one sector to
another. For SO2, costs range from $147 per tonne in the Chemical and Petroleum
Products sector to $99,873 in Other Groups ( source Appendix 2, Table 4-2). The
corresponding figures for NOx vary between annualized savings of $20,985 per tonne
removed in the Non-Metallic Mineral Products sector to a cost of $21,551 per tonne in
the Other Groups sector ( Appendix 2, Table 4-4). Cost effectiveness considerations
would lead firms to choose abatement technologies in the lower cost range of those
indicated above. These cost effective technologies are discussed in the next section.
the implications of "what if for SO2"
In order to determine the most cost-effective strategy for SO2 abatement across all
sectors and point sources, a series of "what if scenarios" was formulated and tested.
Three scenarios examined the impact of different removal targets on the overall cost of
SO2 abatement strategies. The three emission reduction scenarios that were examined
included lowering an existing 1994 base case emission target of 900,885 tonnes by 10,
30 and 50 per cent ( scenarios 1,2,3 respectively).
It should be noted that Ontario will meet SO2 emission limits of 885,000 tonnes per
year in 1994. The higher value of 900,885 tonnes per year arises from the implicit
assumption that Algoma Steel Corp. ( Wawa ) and Falconbridge will increase
emissions to their maximum acceptable levels.
Four other scenarios looked at the effect on base case conditions given the unlikely
event that either INCO or Ontario Hydro fail to meet their 1994 emission targets.
These scenarios included the following:
+ INCO fails to meet the 1994 regulated target and remains at its 1985 emission
level (Scenario 4 ).
+ INCO only gets half way towards the 1994 regulated target (Scenario 5 ).
11
+ Ontario Hydro fails to meet the 1994 regulated target and remains at its 1985
emission level (Scenario 6 ).
+ Ontario Hydro only gets half way towards the 1994 regulated target (Scenario 7).
Figure 7 sets out the tonnes of SO2 that would be emitted on an annual basis under
each scenario. The same figure also shows the costs that would be incurred over 15
years to meet these emission levels.
Figure 7
Projected SO2 Emission Levels and Associated Costs
For Alternative Scenarios
(Source: Appendix 3, Table 4.1-4.4)
Emissions Present Value Costs
(Kilctonnes) (] F (M 1987 $)
$5,000
Bese Case
EL arget $4,000
$3,000
$2,000
UE DE eee
at nl a at Bal :
Scenarios
Based on the data contained in Figure 7, it is apparent from the first three scenarios that
there is a disproportionately higher cost associated with successively greater levels of
emission control. Reducing S02 by 50 per cent from 1994 levels would cost 30 times
more than reducing by 10 per cent from 1994 levels. Similarly going from a 30 per cent
cut to a 50 per cent cut escalates control costs 6 times.
If INCO fails to reduce its emissions and remains at its 1985 emission level, maximum
costs are imposed on all other emitters and overall abatement costs are 5.6 times beyond
those incurred in Scenario 2 and the 1994 base case emission target is exceeded by 13
per cent. If INCO meets 50% of its 1994 regulated emission target the cost burden
12
lincurred by other sectors to achieve the 1994 emission target is considerably reduced
relative to Scenario 4.
A failure by Ontario Hydro to meet its 1994 targeis has implications which are less
severe although still costly. If Ontario Hydro fails to reduce its emissions and remains
at 1985 emission levels (Scenario 6), the 1994 targets can be achieved by other sectors
at a cost of $321 million . If Ontario Hydro achieves half of its 1994 regulated
reductions (Scenario 7), other sectors incur a cost of $78 million.
the implications of "what if for NOx"
Similar to SO, a series of "what if scenarios" were formulated and tested for NOx to
determine the most cost-effective across the board strategy for abatement. Scenarios 1,2
and 3 examined the impact of lowering an existing base case emissions/target of
578,135 tonnes per year by margins of 10, 30 and 50 per cent. Another two
scenarios, 4 and 5 respectively examined what would happen if Ontario Hydro failed to
reduce emissions below the 1985 levels and if it only reduced emissions by 50 per cent
of the 1994 regulated target. Figure 8 shows the annual emissions and the costs that
would be incurred for each scenario.
Figure 8
Projected NOx Emission Levels and Associated Costs
(Source: Appendix 3, Table 4.6-4.8)
Emissions Present Value Costs
(Kilotonnes) i
(M 1987 $)
$8,000
$7,000
$6,000
$8,000
$4,000
$3,000
2,000
$1,000
Base Case
Emission Target
$78
13
For the first three scenarios the results show that the costs of removal escalate
dramatically as emission targets become lower. The 30 per cent NOx removal specified
in Scenario 2 costs 5.5 times as much as the 10% cut specified in Scenario 1. Scenario
3 costs 30 times as much as Scenario 1 for a 50 per cent level of NOx removal.
The scenarios which look at total and partial failure of Ontario Hydro to meet its 1994
regulated emission targets reveal that the effects are readily offset by federally mandated
mobile source controls which are now in effect for new vehicles.
conclusions
A failure on the part of either INCO or Ontario Hydro to achieve regulated SO?
emission levels has significant implications for province wide emission control costs. If
INCO emissions remain at 1985 levels, the $4,933 million expenditure by other sectors
will leave the province at an emission level of 1.01 million tonnes per year or 13 per
cent above the 1994 target. Failure by Ontario Hydro to reduce emissions below 1985
levels would cost other sectors $321 million but the 1994 targets would be met.
In the case of NOx, mobile emission control is the critical factor. Should Ontario
Hydro, the major point source of NOx not reduce emissions below 1985 levels mobile
reductions would more than compensate for the shortfall.
Provided INCO and Ontario Hydro meet their 1994 targets, the Province can tum to
regulating further reductions across the board or by specific point source and industry
sector. Based on the Scenarios that were run for both SO2 and NOx a 10 per cent
reduction incurs a relatively low cost. A reduction of 30 per cent increases costs five
and a half times over those for the ten per cent reduction. Further control measures
which would reduce emissions from the sectors to 50 per cent of the 1994 tar
get levels would increase the costs to about 30 times those for the 10 per cent reduction.
Based on the progress made by the regulated companies in the past three years, we
expect that the four major point sources in Ontario will be able to meet their 1994 SO?
and NOx emission targets.
Switching from other fuels to natural gas may reduce fuel costs and reduce SO? and
NOx emissions. However, supply limitations due to pipeline capacity constraints
preclude the widespread application of this abatement method.
14
Conservation was not examined.
Other assumptions not covered in this study can be easily added to the model to
provide the policy-maker with new scenarios based on technological advances, changes
in costs, or calculations based on social costs instead of private costs. The model itself
has been revised to run on a P.C.
future issues
1. Investigate implications of switching fuel sources to natural gas.
2. Consider implications of more stringent emission limits on mobile sources, eg.
transportation vehicles.
3. The incremental costs of further SO2 reductions at the four major point sources
should be examined in detail.
4. Explore implications of significant modal changes (eg. from automobile to public
transit) on NOx emissions.
COUNTDOWN ACID RAIN
FUTURE ABATEMENT STRATEGIES
Phase I
For the
Ministry of the Environment
Air Resources Branch
SENES Consultants Limited
52 West Beaver Creek Road
Unit No. 4
Richmond Hill, Ontario
L4B 1G5
March 1989
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DISCLAIMER
The conclusions, opinions and recommendations expressed in this
report are those of the consultant and do not necessarily represent
the views of the Ontario Ministry of the Environment. In addition,
the consultant is solely responsible for the accuracy of data and
estimates presented in this report.
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This report presents a study of SO; and NO, emission sources in
Ontario and proposed emission control strategies to achieve
further reductions of SO, and NO, after 1993. The report
consists of a summary document supported by three
appendices.
Summary The summary document describes the findings of 3
phases of the study and draws conclusions on
abatement strategies.
Appendix 1 The Phase 1 Report sets out a 1985 base year
emission inventory for SO, and NO,, examines past
trends, and outlines five basic future scenarios.
Appendix 2 The Phase II Report identifies the costs of
reducing SO; and NO, using alternative emission
control technologies required to meet the emission
targets identified in the Phase I Report.
Appendix 3 The Phase III Report develops alternative cost-
effective abatement strategies that achieve
pre-specified aggregate emission targets. The
computer model developed for the foregoing work is
described.
This This document describes Phase I, Appendix 1.
Document
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TABLE OF CONTENTS
EXECUTIVE SUMMARY
INTRODUCTION
SO, EMISSIONS
74 ol
Zire
SO5 Emission in 1985
SO; Trends from 1980 to 1985
NO, EMISSIONS
3.1
Sine
NO, Emission in 1985
NO, Trends from 1980 to 1985
SO; AND NO, REGULATIONS
BASIC EMISSION SCENARIOS
5.1
5.2
5.3
5.4
5.5
5.6
Introduction
Status Quo Scenario
Major Economic Upturn
Major Change in Industrial Feedstock
Significant New Emission Source
Large Source Not Meeting Legislative
Control
REFERENCES
LIST OF TABLES
Table # Name Follows Page
a 15 Major Sources of S0, in Ontario 24
(1985)
2 Ontario SO, Emissions from Industrial 2=2
Sources from 1980 to 1985
3 Ontario SO; Area Emission from 1980 2-2
to 1985
4 10 Major Point Sources of NO, in Ontario 3-1
(1985)
5 Ontario NO, Emissions from Industrial 34
Sources from 1980 to 1985
6 Ontario NO, Area Emission from 1980 32
to 1985
7 Legislative Control Annual SO, and NO, 4-1
Emissions
Status Quo Scenario - Option 1 5=2
Status Quo Scenario - Option 2 5-2
10 Annual Growth Rate 5-2
Figure #
OU Pm WD H
LIST OF FIGURES
Name
S0, Provincial Total (1985)
SO, Area Emissions (1985)
Total so, Emissions (1980-1985)
NO, Provincial Total (1985)
NO, Area Emissions (1985)
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EXECUTIVE SUMMARY - PHASE I
This report is Phase I (Emission Inventory Updates) of the project entitled
"Countdown Acid Rain Future Abatement Strategies". The information from Phase
I will be used in Phase II (Alternative Technologies) and Phase III (Abatement
Strategy Assessment). The overall objective of the study was to evaluate the
cost effectiveness of alternative emission control technologies for SO, and
NO, emissions.
The objective of Phase I was to develop an appropriate emission inventory of
sulphur dioxide (SO5) and nitrogen oxides (NO,). The report presents
summarized so, and NO, emission data for the major point sources of SO, and
NO, for industrial sectors and area sources in Ontario for 1985, which is the
new reference year for acid rain studies. "Area sources" include
transportation and fuel combustion.
Sulphur dioxide emissions decreased from 1980 to) 1985: The total
anthropogenic (man-made) so, emissions in 1985 amounted to 1.458 million
tonnes; a decrease of 16.6% from the 1980 emission levels. The Inco smelter
was the largest contributor to the reduction. The largest emission sources
in 1985 were non-ferrous smelters, 53%, electric utilities, 23% and ferrous
smelters, 10%. Area sources accounted for approximately 4% of the total
so, emissions; within this group, marine and residential heating dropped by
over half, while vehicle emissions increased by 15%.
Nitrogen oxide emissions increased from 1980 to 1985. Approximately 0.612
million tonnes of anthropogenic NO, were emitted in 1985, an approximate
increase of 6% from the 1980 emission levels. The largest contributors were
vehicles, 53% and electric utilities, 15%. Vehicle emissions increased by
17.6%. Ontario Hydro dominates the industrial sector, and its emissions
fluctuated during 1980-1985. Low NO, burners have helped to reduce emissions.
Legislated limits under the Count Down Acid Rain Programme are forcing
emission reductions for the four major point sources. The schedules are
shown. Five scenarios were developed with assumptions about future emissions,
and will be employed in Phase II and Phase III to assess the effect of various
strategies on the cost and employment of abatement methods and technologies.
1.0 INTRODUCTION
This report is Phase I (Emission Inventory Updates) of the project entitled
"Countdown Acid Rain Future Abatement Strategies". The objective of Phase I
is to develop an appropriate emission source inventory for sulphur dioxide
(SO) and nitrogen oxides (NO, ) - The inventory incorporates data from the
1985 Ontario Emission Inventory System (OEIS), a computerized data management
system and a previous MOE study, MOE 1986a.
The overall objective of the report is to use data from previously inventoried
sources to evaluate various abatement scenarios in terms of the reduction in
so, and NO, emissions versus cost.
The report summarizes:
é the SO, and NO, emissions for the major point sources, industrial
sectors and area sources in Ontario for 1985,
4 the trend in so, and NO, emissions during the period 1980 to 1985,
A the status quo inventory based on industries achieving regulated
limits,
- and several emission inventories based on a large source not being
able to meet legislative control, a major economic upturn, a major
change in industrial feedstock, and a significant new emission
source.
The data presented in this report refer to emissions from anthropogenic (man-
made) origins. The emissions of nitrogen oxides (NO) are calculated as
nitrogen dioxide in the inventory and in this report. It should be noted that
the regulation applying to Ontario Hydro refers to nitric oxide (NO).
2.0 SO: EMISSIONS
2.1 So, Emissions in 1985
The total 1985 so, emissions in Ontario were approximately 1,458 kilotonnes.
Figure 1 presents the breakdown of SO, emissions in terms of industrial
sectors and area sources. Non-ferrous smelters accounted for the largest
source of emissions (53%), followed by electric utilities (23%), and ferrous
smelters, 10%.
In the following sections, point sources are defined as industrial facilities,
electric utilities and institutions. Area sources include transportation
equipment (vehicles, railroad, aircraft and marine), heating (residential,
commercial, industrial and institutional) and incineration.
Point Sources
Table 1 presents the 15 largest point sources of so, emissions in 1985; the
selection criteria was >5000 tonnes/year SO, . These sources account for 90.3%
of the provincial total. The largest emitter was INCO with an annual emission
rate of 695 kilotonnes. Ontario Hydro, i.e. cumulative sum from thermal
generating stations, was second with an annual emission rate of 336.6
kilotonnes.
The top four point sources on Table 1 accounted for 84% of the total
provincial emissions. Facility specific legislative control, described in
Chapter 4.0, has been placed on each of these sources.
Area Sources
Figure 2 presents the 1985 SO, emissions from area sources which account for
3.8% of the provincial total. The largest area source of so; emissions was
vehicles, 32.8%, and industrial/commercial heating, 25.6%.
FIGURE |
SO; PROVINCIAL TOTALS
(1985)
Others (7.3%)
Ferrous (9.7%)
Area Sources (3.8%)
Non-Ferrous (52.9%)
Electric Utils. (23.0%)
Petroleum (3.3%)
FIGURE 2
SO2 AREA EMISSIONS
(1985)
Other Sources (1.4%)
Other Trans. (125%)
Licensed Vehicles (32.8%)
Marine (11.8%)
Resid. Heating (15.9%)
Comm/Ind. Heating (25.8%)
NOTE:
FIGURE 2 IS A BREAKDOWN OF 3.8 % SO; AREA SOURCES FROM FIGURE |
Table 1
15 MAJOR POINT SOURCES OF 80, IN ONTARIO* (1985)
Source
i LINCO (Sudbury)
2. Ontario Hydro**
3. Algoma Ore Div. (Wawa)
4. Falconbridge Nickel Mines (Sudbury)
5. Imperial Oil (Sarnia)
6. Shell Canada (Corunna)
7. Lake Ontario Cement (Picton)
8. Algoma Steel Corp. (Sault Ste. Marie)
9. Stelco (Nanticoke)
10. Courtauld’s Can. Ltd. (Cornwall)
11. Petrosar Ltd. (Corunna)
12. James River Marathon (Marathon)
13. Texaco Canada (Nanticoke)
14. Dofasco Inc. (Hamilton)
15. Kerr Addison (Virgniatown)
Note:
* Criteria >5000 tonnes/year SO
** Ontario Hydro includes: Nanticoke
Lambton
Lakeview
Thunder Bay
Atikokan
Reference:
MOE, 1988.
SO»
(tonnes/year)
695,008
336, 633
115,890
74,352
19,595
16,103
7,748
7,419
6,920
6,517
6,260
6,225
6,210
6,126
5,144
1,316,150
90.3% of total SO;
emissions from area
and point sources
169,000
118,000
43,800
4,740
1,040
2,2 SO, Trends from 1980 to 1985
Point Sources
Table 2 presents the SO, emissions from industrial point sources for the
period 1980 to 1985. Non-ferrous and ferrous smelters, i.e. iron ore (Wawa)
and iron & steel, show depressed emissions during 1982/1983; a period of
economic recession. Electric utilities, however, showed an inverse
relationship to the aforementioned trend, i.e. peak production during 1982 and
1983. In 1982, electric utilities were the major source of so, emissions.
The decrease in SO, emissions during the period of 1983 to 1985 may be at
least partially attributable to the Pickering "B" nuclear generating station
coming on line.
Emissions from petroleum refineries have steadily decreased since 1980. This
may be due primarily to a reduction in the sulphur content of feed stock and
some conversion to natural gas as a fuel at some refineries.
The total annual emissions of SO, from point sources during the review period
(1980-85) are presented on Figure 3. During the period of 1980 to 1982,
emission levels dropped significantly, approximately 36% compared to 1980.
Overall, a 17% reduction occurred between the period 1980 and 1985; the most
significant source of reduction is in emissions from non-ferrous smelters, in
particular INCO.
The 1984 data for so, emissions are presently unavailable. The MOE is
currently processing this data, the 1985 data was processed before the 1984
data because it is the base year for the Countdown on Acid Rain study.
Area Sources
The Ontario area source emissions of SO, from 1980 to 1985 are presented in
Table 3. Significant decreases have occurred, in marine, 57%, and residential
heating, 56% during this period. Total vehicle emissions have increased 15%
since 1980.
Table 2
ONTARIO SO, EMISSIONS FROM INDUSTRIAL SOURCES
FROM 1980 TO 1985”
(TONNES /YEAR)
Category 1980 (1) 1981 (1 1982 (1 1983(1) 198542) **
Non-Ferrous Smelters 9357451 836,172 388,773 538,007 769,360
Electric Utilities 396,194 417,658 450,368 437,630 336,738
Iron Ore (Wawa) 160,583 132,337 70, 690 81,827 115,890
Petroleum Refineries 73, 627 72,348 64,785 59,465 59,698
Iron & Steel 29,909 25,143 21,910 21,760 26,028
Other Sources 90,887 91,611 90,508 84,643 95,056
TOTAL 1,686,651 1,575,269 1,087,034 1,223,332 1,402, 770
Note:
1984 data is presently unavailable.
1985 is the base year for planning future acid rain controls
in Canada and U.S.A.
Reference:
(1) MOE, 1986a.
(2) MOE, 1988; OEIS System.
CL
XAG”
(1980 - 1985)
CC
XW *
CL :
VV *
VU
FIGURE 3
TOTAL SOz EMISSIONS
Table 3
ONTARIO SO, AREA EMISSIONS FROM 1980 TO 1985"
(TONNES / YEAR)
Category 1980 (1) 1981 (1) 1982 (1) 1983(1) 1985(2)**
License Vehicles 15,808 15,102 15,576 15,256 18,174
Off-Hwy. Engines 3,517 3,592 3,055 3,154 37335
Railroad 4,564 4,809 4,525 4,580 3,448
Aircraft 1973 173 165 163 188
Marine 15,360 12,299 8,714 11,429 6,530
Residential Heating 20,272 15,294 13,604 8,574 8,825
Comm./Inst./Indust. 16,910 18,870 10,704 10,880 14,183
Heating
Waste Incineration 646 642 611 609 671
TOTAL 77,250 70,781 56,954 54,645 55,354
Note:
à 1984 data is presently unavailable.
*
3 1985 is the base year for planning future acid rain controls
in Canada and U.S.A.
Reference:
(1) MOE, 1986a.
(2) MOE, 1988; OEIS System.
The total Ontario emissions of SO, from area sources have decreased from 77.3
kilotonnes to 55.3 kilotonnes, a reduction of 28%.
3.0 NOy EMISSIONS
JL NO, Emissions in 1985
The total 1985 NO, anthropogenic emissions for Ontario were approximately 612
kilotonnes. Figure 4 presents a breakdown of NO, emissions in terms of
industrial sectors and area sources. In 1985, the largest contribution to NO,
emissions was area sources, 71.1%, with electric utilities contributing 15.4%.
Point Sources
ae SOUrces:
Table 4 presents the ten highest point sources of emission of NO, in Ontario.
These sources account for 21% of the provincial total.
The largest source of industrial emissions of NO, was Ontario Hydro with a
cumulative total from its thermal generating plants of 94,437 tonnes.
Area Sources
Sees Ces
Figure 5 presents the 1985 NO, emissions from area sources. The largest area
Sources were licensed vehicles, 75.1%. Other forms of transportation
accounted for 16.1%.
Sree NO, Trends from 1980 to 1985
SS Se ees bee
Point Sources
==2r sources
Table 5 presents the Ontario NO, emissions from industrial sources for the
period 1980-1985. Since 1985 is the basis for Planning future acid rain
controls in Canada, the 1985 inventory has been finalized; the 1984 inventory
will be finalized later. The sector with the greatest change was petroleum
refineries which decreased NO, emissions from 23,214 tonnes to 17,730 tonnes
during the period of 1980 to 1985, a 24% reduction, a reduction which may be
FIGURE 4
NO, PROVINCIAL TOTALS
(1985)
Others (75%)
Non-Ferrous/Ferrous (3.0%)
Electric Utils. (15.4%)
Refineries (29%)
Area Sources (71.1%)
FIGURE 5
NO, AREA EMISSIONS
(1985)
Other Sources (0.8%)
Other Trans. (16.1%)
Marine (1.2%)
Heating (6.8%)
Total Vehicles (75.1%)
NOTE:
FIGURE 5 IS A BREAKDOWN OF 71.1 % NO, AREA SOURCES FROM FIGURE 4
Table 4
10 MAJOR POINT SOURCES OF NO; IN ONTARIO* (1985)
Source
1. Ontario Hydro**
2. Stelco (Hamilton)
3. Petrosar Ltd. (Corunna)
4. INCO (Sudbury)
5. Imperial Oil (Sarnia)
6. Algoma Steel Division
(Sault Ste. Marie)
7. Dow Chemical (Sarnia)
8. ESSO Chemicals (Sarnia)
9. Stelco (Nanticoke)
10. Gulf Canada Ltd. (Mississauga)
Note:
*
criteria >2000 tonnes/year NO,
** Ontario Hydro Includes:
Reference:
MOE, 1988, OEIS System.
Nanticoke
Lambton
Lakeview
Thunder Bay
Atikokan
NO,
(tonnes/year)
94,437
5,567
5,225
4,893
3, 629
3,207
3,080
2,920
2,602
2,238
128,098
21% of total NO, emissions
from point and area sources
59,799
18,400
13, 646
2,147
445
Table 5
ONTARIO NO, EMISSIONS FROM INDUSTRIAL SOURCES
FROM 1980 TO 1985"
Electric Utilities
Petroleum Refineries
Iron & Steel
Non-Ferrous Smelters
Other Sources
TOTAL
100, 976
23,214
12,118
2,530
36,192
175,030
(TONNES / YEAR)
1981(1) 1982(1) 1983(1) 1985(2)
108,992
19,380
15,705
2,930
39,131
186,138
1984 data is presently unavailable.
123,549
19/3815
15, 705
2,930
38,786
200,285
118,426
17,449
11,309%
2,930
35,202
185,316
1985 is the base year for planning future acid rain controls
in Canada and U.S.A.
Reference:
(1) MOE, 1986a.
(2) MOE, 1988; OEIS System.
94,437
17,730
13,676
4,914
45,929
176,686
xk
attributed to the conversion to natural gas as a fuel source within some
refineries.
As was the case with SO, emissions, the NO, emissions from electric utilities
were highest during 1982 and 1983. The installation of low NO, burners at
Nanticoke generating station and Pickering "B" nuclear generating station
coming on line in 1985 accounts for some of the NO, reduction.
The total NO, emission levels from industrial sources increased slightly in
1985, (176,686 tonnes) from the 1980 level (175,030 tonnes), i.e. an increase
of 1%.
Area Sources
Table 6 presents the Ontario area source emissions of NO, from 1980 to 1985.
The NO, emissions from licensed vehicles has increased significantly, a 17.6%
increase, from 277,836 tonnes in 1983 to 326,603 tonnes in 1985.
The overall area NO, emissions in 1985 has increased by 2.4% over the 1980
value. If fires are excluded, however, a much larger increase in NO,
emissions, 8.7%, occurred for the same period.
Category
Anthropogenic:
Licensed Vehicles
Off-Hwy. Engines
Railroad
Aircraft
Marine
Residential Heating
Commercial Heating
Industrial Heating
Waste Incineration
Sub Total
Non-anthropogenic:
Forest & Structural
Fires
TOTAL
Note:
*
Table 6
ONTARIO NO, AREA EMISSIONS FROM 1980 to 1985"
1980 (1)
277,836
49,191
29,533
1,679
8,449
18,626
10,007
2,187
2,662
400,170
25,151
425,321
(TONNES / YEAR)
1981(1) 1982(1)
265,866 279,421
50,584 42,360
31107 29,282
1,681 1,592
7,039 5,825
172297 16,837
11772 10,549
2,005 1,145
2,643 2,593
389,944 389,604
8,396 707
398,340 390,311
1984 data is presently unavailable.
1983 (1)
272,495
43,847
29, 633
1,576
7,702
14,711
10,210
2,356
2,580
385,109
20,073
405,182
1985 is the base year for planning future acid rain controls
in Canada and U.S.A.
Reference:
(1) MOE, 1986a.
(2) MOE, 1988; OEIS System.
1985 (2) **
326, 603
46,140
22,308
1,828
5,435
15,556
9,629
4,574
2,743
434,816
508
435,324
4.0 SO> AND NO, REGULATIONS
Table 7 presents the four major sources, their 1985 emission rates and the
1994 emission limits. In order to achieve the 1994 emission limits, INCO and
Ontario Hydro must reduce their emissions from 1985 rates by 61.9% (SO,) and
50% (SO, and NO), respectively. Because 1985 emission levels for Algoma
Steel Corp (Wawa) and Falconbridge were below their 1994 SO, emission limits,
further reductions would not be required for these sources.
In order for INCO to achieve the legislative control, the annual emission rate
from its Sudbury operations must be reduced 61.9% from the 1985 rate to 265
kilotonnes SO, .
Ontario Hydro, however, has several thermal generating stations which emit SO,
and NO, - The criteria employed by Ontario Hydro for the selection of
preferred candidate sites for installing Flue Gas Desulphurization (FGD)
equipment includes (Ontario Hydro, 1988):
5 sulphur content of coal that the station is designed to burn;
= expected future use of the station; and
: station size, remaining operating life, and expected reliability
The number of FGD units required to achieve the 1994 emission limit will be
discussed in Phase II (Alternative Technologies) and Phase III (Abatement
Strategy Assessment). For Phase I, it has been assumed that Ontario Hydro
will meet the Regulation by emitting 175 kilotonnes So; and 40 kilotonnes NO
(61.3 kilotonnes NO, ) -
Company
INCO
Ontario Hydro
Algoma (Wawa)
Falconbridge
* Estimated
Reference:
MOE, 1986b.
Table 7
LEGISLATIVE (1994) CONTROL
ANNUAL SO, AND NO, EMISSIONS (KILOTONNES)
Current (1985) Emission (1994) Limits
Regulation wer NO, S02 SO, + NO,
660/85 695.0 4.9 265 -
281/87 336.6 94.4 175 215
663/85 11519 053% 125 -
661/85 74.4 <0). 5* 100 -
5.0 BASIC EMISSION SCENARIOS
51e Introduction
Five basic emission scenarios were developed for the Phase I study:
- Status Quo
- Major Economic Upturn
Major Change in Industrial Feedstock
- Significant New Emission Sources
nO BP W N FF
!
- Large Source Not Meeting Legislative Control
These scenarios will be employed during Phases II and III to assess the effect
of various abatement strategies.
In Phases II and III, the first four inventories will be evaluated under the
following two scenarios:
C All industries reducing SO» and NO, emissions by 10%, 30% and 50%.
The emissions of the four largest SO, sources meeting current
regulatory constraints while other industries reduce So; and NO,
emissions by 10%, 30% and 50%.
The last scenario, scenario 5, will be evaluated by assuming that INCO will
reduce SO, emissions to 525,000 tonnes per year and maintain NO, emissions at
4900 tonnes per year. The SO, and NO, emissions from all other industries
will be reduced to achieve overall reductions of 10%, 30% and 50%.
5.2 Status Quo Scenario
Two potential options exist for the status quo scenario. Under the first
option, Ontario Hydro would comply with the regulation by reducing So,
emissions to 175,000 tonnes per year and NO, emissions to 40,000 tonnes NO per
year. Regulation 281/87 also suggests a second new NO, scenario where Ontario
Hydro would probably double its NO, emissions to 80,000 tonnes NO per year,
but complies with the regulation by reducing SO, emissions by additional
scrubbing of 40,000 tonnes per year.
The status quo scenario utilizes emission data for the four largest so;
emission sources, 11 industrial sectors and four area sources (see Table 8).
The emission rates for the four largest sources are those required by the
specific regulations, (see Chapter 4.0). The industrial sectors are as
defined by Statistics Canada (1983,1984, and 1985)
The first two area sources represent major transportation regions in Ontario.
The marine sources were isolated because fuel used for lake freighters is not
covered by provincial jurisdiction.
The total SO, emissions in the status quo scenario exceeds the Provincial
objective, 885,000 tonnes/yr after 1993, by 15,862 tonnes/yr. In the status
quo scenario, it is implicitly assumed that Algoma Steel Corp. (Wawa) and
Falconbridge Nickel Mines will increase emissions from the 1985 level to their
maximum acceptable levels as stated in the regulations, (see Section 4.0) even
though this may not occur.
In option 2, Ontario Hydro would emit 80 kilotonnes of NO and 135 kilotonnes
of SO, per year. Table 9 presents the status quo scenario for option 2.
5.3 Major Economic Upturn
Table 10 presents an estimate of growth in the various industrial sectors,
derived from the forecast Manufacturing Gross Domestic Product at Factor Cost
data for the period 1994 to 2000 in Ontario (Informetrica, 1987). It has been
assumed that industrial emissions of SO, and NO, will increase linearly with
these growth terms to evaluate the effect of a major economic upturn in the
economy.
STATUS QUO SCENARIO - OPTION 1
Source SO; NO,
(tonnes/year) (tonnes/year)
INCO 265,000 4,900
Ontario Hydro 175,000 61,333
Algoma Ore Division (Wawa) 125,000 260
Falconbridge Nickel Mines 100,000 20
Industrial Sectors:
Food/Beverage/Tobacco 1,647 2,881
Rubber Plastics 185 386
Leather/Textile/Clothing Tp 309 1,254
Paper Products & Allied Industries. 30,621 12,179
Primary Metals 14,219 672
Metal Fabricating/Machinery Industries 29,038 14,662
Transportation Equipment Industries 1,801 2,099
Non-Metallic Mineral Products 20,249 9,756
Chemical & Petroleum Products 69,902 27,892
Misc. Manufacturing 192 267
Other Major Groups 5,318 4,250
Industry Sub Total 845,531 142,811
Area Sources:
Metro Toronto area 18,603 101,812
Niagara-Hamilton-Toronto Corridor 24,154 202,954
Balance of Ontario 6,067 125,124
Marine Sources 6,530 5,434
Area Source Sub Total 55,354 435,324
TOTAL 9300, 665" 578,135
Reference:
MOE, 1988; OEIS System
à Ontario will meet SO, emission limits of 885,000 tonnes/year
in 1994. The higher value, 900,885 tonnes/year arises from
the implicit assumption that Algoma Steel Corp. (Wawa) and
Falconbridge Nickel Mines will increase emissions to their
Table 9
STATUS QUO SCENARIO - OPTION 2
Source so, NO,
(tonnes/year) (tonnes/year)
INCO 265,000 4,900
Ontario Hydro 135,000 122, 666
Algoma Ore Division (Wawa) 125,000 260
Falconbridge Nickel Mines 100,000 20
Industrial Sectors:
Food/Beverage/Tobacco 1,647 2,881
Rubber Plastics 185 386
Leather/Textile/Clothing 7,359 1,254
Paper Products & Allied Industries. 30,621 12,179
Primary Metals 14,219 672
Metal Fabricating/Machinery Industries 29,038 14, 662
Transportation Equipment Industries 1,801 2,099
Non-Metallic Mineral Products 20,249 9,756
Chemical & Petroleum Products 69,902 27,892
Misc. Manufacturing 192 267
Other Major Groups 5,318 4,250
Industry Sub Total 805,531 204,144
Area Sources:
Metro Toronto area 18,603 101,812
Niagara-Hamilton-Toronto Corridor 24,154 202,954
Balance of Ontario 6,067 1257124
Marine Sources 6,530 5,434
Area Source Sub Total AE 435,324
TOTAL 860,885 639,468
Reference:
MOE, 1988; OEIS System
Table 10
ANNUAL GROWTH RATE
Average Annual
Industrial Sector Growth Rate
(%)
Food/Beverage 2.4
Rubber & Plastics 3.5
Leather/Textile/Clothing 2.6
Paper and Allied Industries 3:20
Primary Metals 336
Metal Fabricating/Machinery Industries 6-1
Transportation Equipment (manufacturing) 3.4
Non-Metallic Mineral Products 4.2
Chemical & Petroleum Products 30 0
Misc. Manufacturing So
Note:
Based on Forecasted Growth from 1994 to 2000.
Reference:
Informetrica Limited, 1987
Production data for Ontario in 1982, 1983 and 1984, a period of high growth
following the 1982 recession, was also examined but yielded very high and
perhaps unrepresentative growth rates in some industrial sectors, i.e. primary
metals (Statistics Canada, 1983, 1984 and 1985).
5.4 Major Change in Industrial Feedstock
The desulphurization of petroleum products was assumed as the major change in
industrial feedstock. Changes which would only affect the top four SO,
emitters, e.g. the use of low sulphur coal from western Canada by Ontario
Hydro, will not be examined as specific methods by which these companies
choose to meet legislative control are not critical to this study.
Ses) Significant New Emissions Source
In this scenario, the effect of a significant new emission source or sources
will be assessed. All of the new sources with significant SO,/NO, emissions
will be assumed to have Best Available Control Technology (BACT). The
source(s) will be treated separately from the existing inventory and with
BACT, are assumed to emit no more than 5% of the overall industrial So;
(42,276 tonnes) and NO, (8796 tonnes) emissions shown in the Status Quo
Inventory, Option 1.
5.6 Large Source Not Meeting Legislative Control
In order to assess the impact on total emissions if a currently legislated
source can not meet legislative control, it will be assumed for the purposes
of this study that INCO will not be able to meet the 1994 legislative control,
but is able to reach a level of 525 kilotonnes So, per year.
The aforementioned assumptions are for the purpose of assessing large changes
in SO, emissions and are not meant to reflect the current status of INCO’s or
any other abatement program.
REFERENCE
Informetrica Limited, 1987. "Informetrica Limited - Post II - 87, Reference
Forecast", April.
Ministry of the Environment (MOE), 1986a. "Inventoried Air Pollution
Emissions of Sulfur Dioxide, Nitrogen Oxides and Volatile Organic
Compounds for the Province of Ontario (1980-1983)", Report No. ARB-187-
86-AQM, May.
Ministry of the Environment (MOE), 1986b. "Countdown Acid Rain: Ontario’s
Acid Gas Control Program for 1986-1994."
Ministry of the Environment (MOE), 1988. "Ontario Emission Inventory Source
(OEIS) Database." Air Quality Management, Air Resources Branche
Ontario Hydro, 1988. "Flue Gas Desulphurization Program: Environmental
Assessment". February.
Statistics Canada, 1983. "Manufacturing Industries of Canada: Sub-Provincial
Areas (1983)", Statistics Canada, Ministry of Supply and Services.
Statistics Canada, 1984. "Manufacturing Industries of Canada: Sub-Provincial
Areas (1984)", Statistics Canada, Ministry of Supply and Services.
Statistics Canada, 1985. "Manufacturing Industries of Canada: Sub-Provincial
Areas (1985)", Statistics Canada, Ministry of Supply and Services.
Re I I I eee
COUNTDOWN ACID RAIN
FUTURE ABATEMENT STRATEGIES
PHASE II
For the
Ministry of the Environment
Air Resources Branch
SENES Consultants Limited
52 West Beaver Creek Road
Unit No. 4
Richmond Hill, Ontario
LAB 1L9
DISCLAIMER
The conclusions, opinions and recommendations expressed in this
report are those of the consultant and do not necessarily represent
the views of the Ontario Ministry of the Environment. In addition,
the consultant is solely responsible for the accuracy of data and
estimates presented in this report.
renee ed) Re L
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Jrsns 141 vLtrsunavtt Jon où bin'dnsyivencs ait 19 4
nolsibbe nt .dheayoezivas eds to yrse wis oiresad ;
bis stab Jo yosTuaos at A0 Sldiadogamt yleloa et
sacgos «tf? xt be
This
report presents a study of SO, and NO, emission sources in
Ontario and proposed emission control strategies to achieve
further reductions of SO; and NO, after 1993. The report
consists of a summary document supported by three
appendices.
Summary The summary document describes the findings of 3
phases of the study and draws conclusions on
abatement strategies.
Appendix 1 The Phase 1 Report sets out a 1985 base year
emission inventory for SO, and NO,, examines past
trends, and outlines five basic future scenérios.
Appendix 2 The Phase II Report identifies the costs of
reducing SO; and NO, using alternative emission
control technologies required to meet the emission
targets identified in the Phase I Report.
Appendix 3 The Phase III Report develops alternative cost-
This
effective abatement strategies that achieve
pre-specified aggregate emission targets. The
computer model developed for the foregoing work is
described.
This document describes Phase II, Appendix 2.
Document
The numerical information contained in the Tables o£ this
Phase II document differ slightly from the data in Tatbies 8
and 9 (Scenario 1 and 2) of the Phase I document. When
detailed cost estimates were being made it was found that
some entries in the emission inventory were assigrei to
incorrect ST. Cr Codes). They were reallocated for cSsting
purposes and the total emissions for each sector were
correspondingly adjusted for this report.
TABLE OF CONTENTS
EXECUTIVE SUMMARY
1.0 INTRODUCTION
a Sal
2.0 ALTERNATIVE EMISSION CONTROL TECHNOLOGY
2-1
2e 2
Overall Objective
Introduction
Industrial Sectors
Zee S0, Control
Zi line NO, Control
Major Point Sources
2-93. Falconbridge
2-32 IENCO
2.3.3 Algoma Ore Division
2.3.4 Ontario Hydro
3.0 SELECTION AND COSTING PROCEDURES
SU
See
Introduction
Industrial Sectors
3.2.1 Boilers
3.2.2 Processes
3.2.3 Specific Sectors
Major Point Sources
323.1 Falconbridge
3-32 /INCO
3.3.3 Algoma
3.3.4 Ontario Hydro
2510
2-14
2=14
2215
215
2-17
Table of Contents (Continued)
4.0 COST OF EMISSION CONTROL AND DISCUSSION
4.1
4.2
REFERENCES
APPENDIX A:
APPENDIX B:
APPENDIX C:
APPENDIX D:
Introduction
Industrial Sectors
4.2.1 Industrial Sector Costs
4.2.2 Petroleum Fuel Desulphurization
Major Point Sources
4.3.1 Falconbridge
43:2 NCO
4.3.3 Algoma
4.3.4 Ontario Hydro
COST ESTIMATES
COSTING PROCEDURES, FUEL DATA,
QUALITY OF INFORMATION ON CONTROLS
GLOSSARY
EXAMPLES OF COMPUTER PRINTOUTS
Page #
LIST OF TABLES
Follows Page
2.1A Available Abatement Controls - SO; 2-1
2.1B Available Abatement Controls - NO, 2-1
4.1 Summary of Sulphur Dioxide Reductions 4-1
: for Major Sources
4.2 Summary of Sulphur Dioxide Reductions 4-1
for Industry Class
4.3 Summary of Nitrogen Dioxide Reductions 4-1
for Major Sources
4.4 Summary of Nitrogen Dioxide Reductions 4-1
for Industry Class
4.5 Control Technologies and Their Technical 4-2
Characteristics
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EXECUTIVE SUMMARY - PHASE II
This report is Phase II (Alternative Technology Inventory and Costs) of the
project entitled "Countdown Acid Rain Future Abatement Strategies". The
information collected in Phase II will be used in Phase III (Abatement
Strategy Assessment) to evaluate the cost/effectiveness of selected
alternative emission control technologies for SO, and NO, emissions.
The objective of Phase II is to identify and determine the costs and
contaminant removal Capability of alternative emission control technologies.
The gross cost data presented includes Capital, Operating, and annualized
costs. The costs are approximate estimates which can vary by a factor of two
Or more depending on the specific design needs, installation costs and
operating mode.
The emissions from industrial sectors and large point sources are subdivided
into process and boiler emissions. For the large point sources, the
alternative abatement technologies presented are specific for the process
emissions. With the exception of Ontario Hydro, the technologies for the
boilers are generic. Alternative abatement Strategies for the industrial
sectors are generic.
Costs for the control technologies applied to each sector have been estimated
by calculating costs for a representative unit and multiplying that cost by
the number of sources which might be controlled by the technology used. The
programmes used to develop costs were based on algorithms and procedures which
have been verified by use in other studies.
The costs for SO, removal vary over such a wide range that the application of
Some technologies would not be practical. The high costs in certain
Situations point out the site-specific nature of the problem. Costs were
found to range from $110 to $99,873 per tonne of SO, removed. At the other
extremem, an apparent saving would result from the replacement of sulphur
bearing fuels with Natural gas, although practical and marketing problems
S-1
prevent a wide spread application of the approach. In general the least
costly strategies result from control of high SO, content from high volume
sources.
Costs for the control of NO, were found to vary between a savings of $20,985
and a cost of $21,551 per tonne removed. The least costly methods are those
which require combustion process changes and result in low removal
efficiencies.
1.0 INTRODUCTION
1.1 Overall Objective
This report presents the results of Phase II work in the project entitled
"Countdown Acid Rain Future Abatement Strategies". It identifies the gross
costs and performance effectiveness of alternative emission control
technologies for post 1994 SO, and NO, abatement in Ontario.
Although transportation is a key source of NO, emissions in the Province, it
is not dealt with in this document. A separate report that looks at abatement
technologies and costs associated with emission reduction in this sector is
being prepared independently. When complete, the results of the
transportation study and this document will be combined in Phase III to
present an aggregate picture of abatement strategies for SO, and NO, in
Ontario.
Three chapters follow. They respectively present:
2.0 . alternative emission control technologies for SO, and NO, emissions
from large point sources and industrial sectors
3.0 . descriptions of the costing procedures used for sources of NO, and SO,
emissions
4.0 - estimates of the operating and capital costs associated with
alternative emission control technologies
The analyses contained in this document are founded on three assumptions.
These are:
1) Ontario Hydro will achieve its 1994 emission limits, and potentially
additional reductions of SO, and NO, by adding flue gas desulphurization
(FGD) and selective catalytic reduction (SCR) abatement equipment to its
fossil fuel fired generation facilities.
2)
3)
INCO, Falconbridge and Algoma will achieve their 1994 SO, emission limits
by employing process changes and abatement technology, but will need to
employ different technology to achieve additional reductions of so, after
1994.
Individual industrial sectors will achieve reductions in SO, and NO,
emissions as a result of an increasing number of companies utilizing the
selected abatement equipment.
2.0 ALTERNATIVE EMISSION CONTROL TECHNOLOGY
2.1 Introduction
This chapter sets out alternative control technologies for SO, and NO,
abatement in a generic form for broad-industrial sectors and in a specific
context for the four largest SO, emission sources namely INCO, Ontario Hydro,
Falconbridge and Algoma.
The control technologies which have been examined by the four largest so,
emitters will enable them to comply with 1994 targets prescribed in government
regulations.
Alternative emission control technologies presented in this chapter and
throughout the remainder of the text refer to both process changes and the
installation of control equipment.
Tables 2-1 (A and B) present an inventory of SO, and NO, emission control
technologies and respectively indicate which are applicable to industry in
general and each of the four largest emitters. (The text which follows
provides a general description of these technologies.)
2.2 Industrial Sectors
The Phase I inventory data base contained eighteen sectors giving rise to so,
and NO, emissions. The emissions from eight of these sectors amount to less
than 1% of the total No, and So; emissions and were excluded from the study.
In addition, the Rubber and Plastics Industry sector was included only with
respect to SO, emissions. The sectors of concern are:
Included Excluded
Primary Metals Tobacco Industries
Transportation Equipment Leather Industries
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Chemicals and Chemical Products Machinery Industries
Food and Beverages Printing and Publishing
Textile Industries Wood Industries
Metal Fabricating Electrical Production
Paper and Allied Products Miscellaneous Manufacturing
Other Major Groups?
LES
Rubber and Plastics
The sector listed as other major groups includes municipal and sewage
sludge incinerators,commercial enterprises and institutions such as
hospitals and universities.
ee SO, emissions only
22-71 SO; Control
Pre-Combustion Control
Coal cleaning, petroleum fuel desulphurization, fuel Switching, ore
beneficiation and process and operating changes (see p. 2-4) are pre-
combustion control methods of reducing SO, emissions. The techniques of
petroleum fuel desulphurization and fuel switching are the methods of control
considered in this report.
Coal Cleaning
The use of coal cleaning although a viable option on the large scale is
not a relevant option for Ontario, except perhaps for its use by Ontario Hydro.
The costs are comparable to the increased cost of purchasing lower sulphur
coal but both are very dependent on the availability of suitable coals under
the existing marketing and purchasing conditions. In turn both are comparable
to the costs of wet scrubbing of flue gases (which are sensitive to specific
site conditions) . Efforts to distinguish between the costs of these three
techniques would be subject to errors which would be equal to or greater than
2-2
the estimated differences in costs (See also MOE Source Book 1983 and an MOE
internal study (Barrow - Air Resources Branch).
Since the flue gas cleaning technologies are suitable for use on a wide
variety of sources, these methods have been selected for the purposes of this
study. These technologies can also be used to achieve a range of sulphur
removal efficiencies and are more flexible than either coal switching or coal
cleaning. Costs for coal switching are difficult to estimate and cannot be
considered on a long-term basis.
Petroleum Fuel Desulphurization
Petroleum fuel desulphurization would likely be achieved by regulating the
sulphur content of fuel oils. The necessary increased availability of low
sulphur fuels would be achieved, in practice, by refinery fuel
desulphurization. The cost of switching to low sulphur oils would be very
dependent on market forces and difficult to assess. The costs of fuel
desulphurization can be more directly evaluated, and has been selected as the
more reliable method of estimating costs. As a side benefit low sulphur
diesel fuels would also increase engine life and achieve some cost savings.
In this report the costs of fuel desulphurization are based on a study by MGH
International (1983) (see Section 3.2.1) which describes technologies to treat
crude oil to obtain a sulphur level of 0.3% in Light Fuel Oils (LFO) and 0.5%
in a reduced output of Heavy Fuel Oils (HFO). Of a number of studies on fuel
desulphurization, including studies by MHG and number of studies related to
sections of refineries, the selected study was chosen as being directly
applicable to Canadian refineries. It encompassed all of the refinery
operations. The above specifications were assumed to be achieved by the
following processes:
fixed bed hydrotreating followed by an amine treatment plant and sulphur
recovery unit
residual thinning of atmospheric and vacuum still bottoms
2-3
. desulphurization of middle distillate to 0.3% sulphur
residual oil desulphurization using H-oil or equivalent process.
Fuel Switching
Fuel switching from coal or oil to natural gas would achieve a major reduction
in SO, emissions and costs have been estimated for this method of emission
reduction. As noted later in Chapter 3 (Section 3.2.1), the method has severe
practical limitations and the possibility of its widespread use needs careful
consideration.
Ore Beneficiation
Techniques similar to those employed for coal cleaning can be used for the
reduction of SO, emissions from metallurgical processes. These are
beneficiation processes which result in the removal of unwanted sulphur
bearing compounds from the ores, before they are subjected to the various
smelting, sintering and refining processes. They are currently being used at
the nonferrous smelters and could be of value at the Algoma plant in Wawa.
Costs have been estimated for this process in Section C.3.3.
Process and Operating Changes
Process changes are specific not only to the types of processes in use, but to
actual process details. They may affect product quality as well as process
costs. Except for those combustion modifications to boiler operations which
have been identified and to refinery operations influenced by fuel
desulphurization it has not been possible to determine the costs of process
changes because of limited process information in the inventory.
Combustion Control
A number of methods have been proposed for the introduction of chemicals into
the fuels or onto the grates for the control of SO, emissions. These may
generally be defined as low efficiency systems. They are described below.
Fuel Additives
Additives, usually intended to possess catalytic qualities, have for many
years been used to reduce fouling problems, promote combustion, and ensure the
complete oxidation of some heavy metals, such as vanadium, so that the
volatile compounds or elements are converted to nonvolatile forms which remain
in the boiler rather than being emitted as fly ash.
In recent years it has been claimed by some suppliers that these materials
will serve to convert SO, to SO3 which will react with the fly ash and be
retained in the particulate emission control system. Examination of
supporting data indicates that the SO, containment is directly related to
reaction with the additive.
These additives are intended for addition at rates of under 0.1% of the fuel
rate. At these rates they are ineffective for SO, control. If they are used
in quantities that are effective the cost of the additive becomes extremely
high and expanded particulate emission collection systems will also be
required. SO; may have to be used as an additive to maintain high ESP
particulate removal efficiency when low sulphur western (Canadian) coal is
used as fuel. It is not however used to reduce So, directly.
Dry Lime Addition to the Fuel
Tests have been made of adding lime to solid fuels in coal boilers and
incinerators. Efficiencies of above 20% have been recorded but the problem of
distributing the lime evenly amongst the fuels and ensuring that the necessary
intimate mixing of lime and fuel is achieved result in variable and generally
poor efficiency of control.
Lime Injection Modified Burners
Furnace injection is a developmental process in which limestone, or hydrated
lime, is injected directly into the furnace of a coal-fired boiler. The
reagent is calcined to calcium oxide (CaO) which reacts with sulphur dioxide
to form calcium sulfate (CaSO,). The unreacted lime (CaO), CaSO,, and fly ash
are then collected together in a fabric filter or electrostatic precipitator.
Ontario Hydro and others have programs underway to further develop this
process.
The drawback to the process is that it has limited SO, removal efficiency.
Its main advantage is that it can easily be retrofitted to existing plants at
relatively low cost. A number of problems exist which require to be resolved
for each installation. These include the possibilities of fusion of the lime,
deposition of the lime on furnaces walls and deposition on boiler tubes. This
method of control is therefore not yet suitable for consideration as a
generally applicable process.
Some of the problems associated with the addition of lime to fuel beds have
been partly overcome, for pulverized coal burners, by the addition of lime to
the fuel at modified burners. The lime is thus introduced directly into the
flame zone, resulting in improved removal efficiencies of above 20%. Ontario
Hydro has achieved between 40 and 50 percent so, removal in full scale testing
and there seems to be potential for even higher efficiencies.
Fluidized Bed Systems
These systems burn solid fuels in a heated bed of sand which is agitated by a
stream of air applied in such a manner as to maintain the bed in a semi-
fluidized state. The fuel is injected into the bed of sand where it is burnt
in the air stream. Although the fluidized bed needs to be preheated with a
gaseous or liquid fuel, the heat of combustion of the solid fuel maintains the
bed temperature during its normal operations. The agitated bed serves to
grind the ash and other noncombustibles preventing clinker formation in the
bed.
These systems are also used for the incineration of solid wastes. However,
operating costs are high, and although the injection of lime to reduce
emissions of SO, has been shown to be feasible the ash carryover rate is high
and a high efficiency of ash removal is necessary.
A change to a fluidized bed boiler would require a complete change of the
furnace involving high capital and operating costs. Some reduction in costs
might be obtained by the use of pressurized units, which would be smaller and
more efficient but considerable development work remains before these systems
become commercially viable.
The fluidized bed systems are therefore considered to be of value when new
installations are contemplated but too expensive for the reduction of existing
emissions since a complete boiler replacement would be required.
Emission Controls
Wet Flue Gas Desulphurization (FGD)
Wet scrubbing FGD systems absorb the SO, from the gas stream into a solution
or a slurry of an alkaline chemical forming a sulphate. The most widely used
systems employ lime or limestone as the alkaline reactant. Other processes
use magnesium, sodium or ammonia (Cominco process) to react with the SO>-
Once a salt has been formed the material can be discarded (throwaway
processes) or a recoverable product can be obtained. This may take the form
of SO, (regenerative processes), sulphur or another sulphur containing
material.
The processes resulting in a recovery of the sulphur are generally more costly
than the majority of the throw away processes since they require additional
treatment stages and often use more expensive chemicals. They are normally
economically better than the systems which discard the product only if: waste
disposal costs are significant; the recovered material can be used, on-site,
to reduce the purchase of a raw material; or if a ready and economically
favourable market for the product is available.
2-7
Unfortunately the markets for sulphur, sulphuric acid and other products are
cyclical and volatile in their activities. To remain economically preferable
to the throwaway systems a firm contract for purchase of the product must be
obtained or else the storage costs of holding the product, until a suitable
market opportunity, arises become uncertain or prohibitive. On the other
hand, the cost of acceptable waste disposal has increased significantly and is
likely to increase further in the future; leachate from inadequately
constructed landfill may allow hazardous trace metals such as lead solubilized
by alkali in the ash to reach the environment. Stringent new waste disposal
measures would significantly increase costs. This issue has not been
considered in the process costing.
Apart from the use of recovery processes at locations such as pulp mills,
(where the recovered so, can be used in the process), and the nonferrous
smelters, (which produce emissions with an So, content above >2.5% suitable
for making sulphuric acid) the use of throw away systems has been identified
as the most suitable wet control method for SO, reduction.
These processes use slurries of lime or limestone and the problems of scaling
corrosion and erosion, originally associated with them, have been amenable to
variety of process improvements. Within the accuracy of the estimates, the use
of one or other of the reactants cannot be demonstrated to be economically
preferable. This study has therefore used the more widely applied limestone
process as a basis of the cost estimates for the throw away systems. They are
capable of over 95% removal of SO, although they are generally designed for
operation at that efficiency.
Special processes such as the Pearson-Peck process (MOE 1983) have been
proposed for specific applications but their requirements of minerals as
absorbents limits their usefulness for general application. The costs of
installing and operating these processes can only be assessed for specific
locations. They have not been evaluated for this study.
a
Tail gas cleaning is employed at petroleum refineries and steel mills.
Several proprietary processes (including the Beavon, Bureau of Mines Citrate
and Scot processes) are available, but their application for the purposes of
this study would require a more detailed identification of the sources and the
existing operation at the various plants being considered than is available
from the inventory. These processes have therefore been excluded from the
options being considered.
Dry FGD Systems
Dry scrubbing FGD systems have not been used the same length of time as wet
systems, but, they are becoming prevalent with power utilities, industries and
municipalities. In these systems, absorption of SO, and other acid gases
takes place when the flue gas comes in contact with a sprayed dry or slurry
sorbent. The water content of the slurry evaporates and the mixed salts and
flyash are removed in a particulate collector downstream. If a baghouse is
used to collect the particulate some additional chemical reaction between
collected dusts and unreacted acid gases may take place, thereby further
enhancing acid gas removal.
For the dry spray systems both sodium and calcium-based sorbents can be used.
Common sorbent materials include nahcolite (natural sodium bicarbonate), trona
(sodium sesquicarbonate), synthetic carbonate/bicarbonate mixtures, and
pressure hydrated lime. Compared to wet systems, the advantages of dry spray
systems include simplicity, increased reliability, lower cost and and easier
retrofit.
A process for the absorption of so, on phosphate rock is available in the
U.S.A. The process, known as the Poli-process (MOE 1983), has been suggested
for use at Algoma. The absorbed So, is regenerated and converted to SO, which
3
can then be used to produce sulphuric acid or to form a phosphate fertilizer.
The fertilizer is not considered to be suitable for use in Ontario, and the
costs are similar to those for wet scrubbing FGD systems. Its economic
applicability is also related to the availability of cheap phosphate rock. It
2=9
can therefore only be considered as suitable for use at locations adjacent to
phosphate deposits. It has not been considered in this study.
Irradiation technologies, using a variety of particle and ultra-violet
radiations, have been investigated for the conversion of SO, and NO, emissions
to solid compounds in the presence of ammonia. The chemistry is not well
established but ammonium sulphate and ammonium nitrate are two of the
products. Large scale applications of these processes still needs to be
demonstrated before adequate design and cost information is available.
2272 NO, Controls
Pre-Combustion Controls
Fuel Switching
The use of nitrogen free fuels such as natural gas or distillate oils results
in reduced emissions of NO, by eliminating the fuel derived component of the
emissions. The thermally produce NO, would still be formed. The high flame
temperature obtained using these fuels would offset some of the reduction if
coal or residual oil were to be replaced by these fuels.
Conversion of combustion sources to natural gas could be carried out for some
sources, but the province wide conversion of all sources is impracticable due
to logistical problems and the economic impacts, which would follow.
Switching from residual oil to distillate oils could be accomplished by the
desulphurization of refinery fuels. The conversion of coal burning units to
oil burners would require major changes to the units.
Fuel Modifications
In addition to the fuel modifications obtained by refinery fuel
desulphurization treatment, processes exist for the conversion of coals to
liquid or gaseous fuels. These processes require complex and large plants;
2-10
they cannot therefore be applied to the smail commercial and industrial
sources individually.
Ontario Hydro could conceivably install such a plant but the costs and the
reliability of these processes have not been well established on the
intermediate scale required for a power generating station.
Combustion Control
In combustion, two mechanisms are at work creating NO, "Thermal" NO, is
created when atmospheric oxygen and nitrogen combine at the very high flame
temperatures. "Fuel" NO, is produced by a second mechanism, the reaction of
fixed fuel nitrogen and oxygen in the combustion air.
Each of these NO, producing mechanisms requires somewhat different methods of
control. Thermal NO, production rates are affected by the flame temperature,
the amount of excess oxygen available and the residence time in the peak flame
zone. Fuel NO, production is more dependent upon the amount of fixed nitrogen
in the fuel, the amount of oxygen available for oxidation of the fixed fuel
nitrogen and on the presence of local oxygen-rich pockets within the fuel/air
mixture. Unlike thermal NO,, fuel NO, is not very dependent upon flame
temperature.
Combustion modifications can reduce NO, emissions by: limiting the residence
time in the primary flame zone; reducing the flame temperature, and by
reducing the rapid mixing of fuel and secondary air. Several combustion
modification methods are available and these are described below.
Lower Excess Air (LEA)
One method of reducing NO, concentrations involves lowering excess air rates
to result in about 1 percent O5 in the exhaust gas. To date this method has
not been as effective as two-stage combustion; it also increases the risk of
explosions. For practical reasons the cost studies have used 3% excess 9,
(15% excess air)
Low NO, Burners
Low NO, burners hold promise as a means for significantly reducing NO,
emissions. They are designed to control the air/fuel ratio in the burner area
thereby retarding the formation of NO, from fuel bound nitrogen and partly
reducing thermal NO, . Their use under the most advantageous conditions permits
NO, emission reduction of up to 60 percent without compromising burner
efficiency. They are relatively easy to retrofit and existing burners can be
modified or replaced without major changes to a furnace. However, their
effectiveness is dependent on boiler configuration and generalizations are
difficult to make.
Staged Combustion (SCA)
An effective NO, -reducing method applied to steam generators involves the
splitting of combustion air. With this method, only 90 to 95 percent of the
combustion air requirement is injected at the burner while the remaining air
is introduced a few feet downstream. This delayed air introduction is found to
reduce NO, concentrations in flue gases by 40 to 50 percent. Staged
combustion has been limited to large sources. It has not been demonstrated on
small units.
Flue Gas Recirculation (FGR)
In order to reduce the concentration of oxygen and to lower the temperature in
the combustion zone of boilers and incinerators a side stream of the flue
gases is recirculated to the combustion air inlet ports. This results ina
reduction in the quantity of NO, produced by thermal reactions. The efficiency
is dependent on the boiler or incinerator configuration but is in the range of
10-30%. Costs are also dependent on the specific installation. When other
control techniques are applied its effectiveness is diminished; it is
therefore used only when other methods are not applicable.
Emission Controls
SPESS TON CONELOLS:
Numerous flue gas (post combustion control systems) NO, control processes have
been developed but only two have reached commercial development - selective
catalytic reduction (SCR) and selective non-catalytic reduction (SNCR).
Selective Non-catalytic Reduction (SNCR)
The SNCR (thermal deNno,) Process relies on NO, reduction by ammonia addition
and the application of high temperatures (1600°F to 2000°F). It is a good
method for reducing NO, beyond the range achievable by combustion
modifications. Its advantages include the fact that control equipment does
not become fouled when dirty fuel is used, there is no catalyst which can be
poisoned by dirt and sulphur compounds, boiler changes are not required and
there is no increase in the incidence of tube corrosion or incomplete
combustion.
Compared to SCR, SNCR has a lower NO, removal efficiency because of lower
selectivity and greater sensitivity to furnace load changes. SNCR has a lower
capital cost than SCR.
Selective Catalytic Reduction (SCR)
The SCR process relies on ammonia, in the presence of a catalyst, to reduce
NO, to N, and water vapour. Its reactions are basically the same as for SNCR,
however, there are many more process variations due to the effects of
different amounts of flyash in the process equipment. Compared to SNCR, SCR
attains higher NO, removal but is more costly, is affected by dirty fuels and
is more difficult to retrofit.
Combined NO, and SO, Control
The FGD systems which result in the removal of SO, generally will result in
the simultaneous reduction of NO, emissions. Unfortunately studies of these
systems have been confined to the measurement of SO, reduction efficiencies
and the NO, removal capabilities have not usually been publicly reported.
This study has therefore not used combined SO,/NO,, technologies but a brief
description is given for one of these technologies.
Fluidized-bed Copper Oxide Process
The U.S. Department of Energy has developed a fluidized-bed copper oxide
process for cleaning SO, and NO,. It involves passing hot flue gases into a
fluidized bed containing a thin layer of copper oxide supported on aluminum
oxide pellets. The copper oxide reacts with the sulphur in the gas stream,
trapping it as a copper sulfate in the pellets. Regeneration permits
elemental sulphur to be recovered and nitrogen oxides are destroyed by
reacting them with ammonia injected into the combustion gases. Water and
nitrogen are the primary by-products.
Other Technologies
Combined SO,/NO, control methods include the use of lime injection, lime
addition to the fuel and the use of fuel additives. Primarily aimed at SO,
control their efficiencies for NO, removal have not been recorded although
lime injection through the burners may have some effect by absorbing NO, as it
is formed. The reactivity is low and these methods are not considered to be
suitable for NO, reductions.
2.3 Major Point Sources
2.3.1 Falconbridge
In the late 1970’s, Falconbridge undertook a major smelter modernization with
2-14
associated pollution control components. As of 1985, the company so,
emissions were below the 1994 Ontario Regulation of 100 kilotonnes per year.
SO, Controls
The methodology proposed for sulphur dioxide abatement by Falconbridge Limited
includes:
increased degrees of roasting in fluid bed roasters to produce additional
sulphuric acid
converter slag cleaning
increased pyrrhotite rejection in the Strathcona Mill
The methods for control of future SO, emissions at this location are described
in section 3.3. They would be based on throwaway or regenerable FGD
technology.
NO, Emissions
The major sources of NO, emissions at Falconbridge in 1987 were reverberatory
furnaces and converters.
The company currently employs electric furnaces and hence its NO, emissions
have been reduced by approximately 64 percent. Therefore no additional
controls were considered for this source.
2.3.2 INCO
SO, Controls
The regulated 1994 emission level for Inco is 265 kilotonnes. To achieve this
limit the proposed methodologies for SO, reduction include:
increased pyrrhotite rejection
oxygen flash smelting/matte processing
vf is)
- the capture of fluidized bed roaster off-gases
upgrading of the existing acid plant or building a new acid plant
The methods available for control of SO, emissions to below the 1994 target
level are described in section 3.3.2. They would be based on throwaway or
regenerable FGD treatments.
NO, Controls
The largest sources of NO, emissions at INCO are reverberatory furnaces which
account for approximately 86% of the total. The remaining sources of NO,
emissions are boilers.
INCO is proposing the use of oxygen flash furnaces in place of reverberatory
furnaces. With the implementation of this proposal furnace generated NO,
emissions would virtually be eliminated.
2.3.3 Algoma
According to the company progress report filed with the MOE in 1985, Algoma
identified five control technologies which would help reduce its SO,
emissions. At the time of filing this report however, the company noted that
unless there was a major change in its economic circumstances the most likely
method of achieving 1994 abatement requirements would be either reducing
Production capacity or utilizing alternative ore sources. However, the
following technologies were reviewed in terms of post 1994 reductions.
So; Control
Pre-combustion, process changes and emission controls were considered. Of
these ore beneficiation was used in this study but process changes were not
because of limited information. Most of the emission controls shown in Table
2.1, including:
. Limestone flue gas desulphurization
. Bureau of Mines Citrate Process
. Pearson-Peck Process
. Poli Process; and
. Cominco Process
were considered. Limestone flue gas desulphurization was selected because it
is a well established, proven technology for which there is good data. As
discussed in Section 2.2.1, Emission Controls this system is appropriate for
large emitting sources and has an efficiency upwards of 90 percent. The prime
reason for not selecting regenerative systems was a lack of information on
markets for the by-products.
NO, Control
The sinter strand process can be controlled for NO, emissions by the use of
catalytic and non-catalytic reduction processes. Since the flue gases are
exhausted through an electro-static precipitator, the likelihood of the
catalyst being fouled by particulate matter, which has been experienced with
catalytic processes, is reduced.
Process modification such as partial recycling of the flue gases has very
limited value for a process such as this which is only partially enclosed.
Algoma’s sintering plant at Wawa is not one of the major NO, emitters in
Ontario. The costs of control have therefore not been included in this study.
2.3.4 Ontario Hydro
so, Control
Several alternative Flue Gas Desulphurization (FGD) technologies are currently
being considered by Ontario Hydro. These include:
. Wet Limestone Slurry Process
Limestone Dual Alkali Process
Lime Spray Dryer Process
. Lime Injection Modified Burners (LIMB)
At the moment process selection studies are being conducted by Ontario Hydro
along with an environmental assessment report on flue gas desulphurization.
These processes are the same as those described in sub-section 2.2.1, Emission
Controls, and are not repeated here.
NO. Control
ER Vos
In coal-fired boilers, fuel generated NO, predominates over thermal NO, . NO,
control strategies of potential value to Ontario Hydro are outlined below.
Detailed discussions of these strategies are presented in Section 2.2.2 and
will not be repeated here.
Pre-combustion control techniques which may be used for fuel modification
include fuel switching, fuel additives, and fuel denitrification. All of
these are somewhat experimental at the moment and are not as yet proven to be
effective.
Several combustion modification techniques may also be used singly or in
combination on coal-fired utility boilers. These include low excess air (LEA)
firing; staged or off-stoichiometric combustion (SCA); low NO, burners (LNB) ;
and flue gas recirculation (FGR). At present Ontario Hydro has replaced all
burners at Nanticoke thermal power station with low NO, burners. Low NO,
burners are also considered for Lambton and Lakeview generating stations.
Of the two flue gas treatment processes (SNCR and SCR) the choice for Ontario
Hydro will be dependent on the relative costs of controlling fewer sources
using the more efficient SCR process and the cost of controlling more sources
with the SNCR process. The various costs will be dictated by the increased
degree of control which can be achieved at each of the power stations. Site
2-18
specific conditions at the stations will have a significant bearing on the
costs. Such a degree of sophistication is not possible under the terms of
reference of this study and costs have been developed on a more generalized
basis of using the more efficient SCR technology applied at 500 MW units. In
part this decision was also influenced by the availability of cost
information, which was more readily available for this technology and unit
size.
By controlling the emissions from individual units any desired level of
control can be achieved up to the maximum obtainable reduction of about 90%,
if all units are controlled by the use of SCR at high efficiency (SRI
International 1980).
3.0 SELECTION AND COSTING PROCEDURES
321) . Introduction
The procedures used in the estimation of control costs, which will be
described in this chapter, have been derived from several sources. The basic
programs have followed the general procedures shown in the U.S. EPA Economic
Analysis Branch (EAB 1987) report, but the factors and exponents used have
been modified to follow those in Calvert & Englund (1984) and Radian
Corporation (1984). Where the data appeared to be inconsistent or lacking,
comparisons were made with generalized information available in the
literature. Use was made of AP 42 (1985) for comparing emission rates and flow
quantities and Perry & Chilton (1984) and Fryling (1967) for information about
fuel heating values and sulphur content.
Capital and operating costs were estimated and annualized costs calculated for
a per tonne basis of SO, and NO, - The algorithms used for estimating the
costs of control are given in Appendix B.
3.2 Industrial Sectors
For the purposes of this study sources which emitted less than 10 tonnes per
year of the pollutants were excluded from the assessments. In addition, some
sectors which contained only small sources of a pollutant were eliminated from
the study for that pollutant. Less than two percent of the emissions were
thereby left out of the study’s evaluations.
To establish costs for an industrial sector the types of processes and boilers
were sorted into representative groups within each sector. The geometric
means of the emissions from the groups were determined and a representative
flow rate was estimated from the available data and was augmented by use of
the EPA emission factors. The costs of control of this representative source
were obtained and the overall costs for the group obtained by multiplying
those cost by the number of sources in the group.
31
The costs for the industrial sector were then obtained by addition of the
costs of the groups within the sector.
In identifying suitable groupings, the boilers were separated from the process
sectors and were subdivided according to the fuel used. The process sources
were grouped in accordance with either the processes to be controlled or the
methods of control which could be applied to the process.
Some identified costing methods include the cost of retrofitting the
technology, e.g. for combustion modifications on boilers no additional
retrofit factors were used. In other cases retrofit factors are not included
in the direct estimates. A factor of 1.2 was applied in these cases except
that of Selective Catalytic Reduction for NO, control. This technology, which
operates at about 800° C requires the installation of a large catalyst bed in
the exhaust gas stream between a boiler and any downstream heat recovery or
cooling system. To install this bed it is necessary to divert the gas flow
from its normal duct to the catalyst bed and then return the treated gases to
the normal channel. In the case of process streams the exhaust gases will
generally need to be heated to the required catalyst operating temperatures.
The costs for these modifications could be large. A retrofit factor of 1.4
has therefore been applied to these situations.
3.2.1 Boilers
Sulphur Dioxide
In addition to the use of flue gas desulphurization methods, the so, emissions
from boilers can be reduced by changes to the fuels used and by injecting
lime directly into the furnace. Two cases of fuel changes have been assessed;
switching to natural gas and the use of low sulphur oil fuels to replace coal
and high sulphur oils.
The use of low sulphur fuel oils has been assumed to be achieved by means of
3=2
fuel oil desulphurization at the petroleum refineries since, as described
earlier, widespread demands for low sulphur fuels would require that the
refineries responded in the proposed manner or a similar one. The costs for
each case have been allocated to the sectors on the basis that the emissions
presently inventoried, when ratioed to the total emissions from the oils now
produced by the refineries, result in the fractions of the total so,
reductions (Table A-4.11) which can be applied to the sector. The cost to the
sector can then be obtained from the cost/tonne so, removed (Table A.4.12).
The cost equation used for HFO being changed to light fuel oil under case 6
is:
Cost = Emissions from sector (HFO) x SO, reduction for x Cost
total emissions from (HFO) Saleable (HFO) tonne SO, removed
[TABLE A.4.11] [TABLE A.4.11] [TABLE A.4.12)
= Emissions from sector (Residual) x 123,426 x 510.1
139,323
The costs to the refineries are based on the reduction at the refineries (Table
A.4.12) multiplied by the cost per tonne SO, removed. It should be noted that
some of the costs of the overall reduction in emissions may be borne by sales
outside the Province.
The study from which the cost data were taken assumed a nominal 0.3% sulphur
content for the light fuel oil fraction currently produced. Although the
present situation is that oils containing up to 0.5% sulphur are being
produced, the refineries are capable of supplying 0.3% sulphur contents and
this value has been used in this study and, in the past, by MOE when it was
necessary to estimate emissions, from oil consumption, for inclusion in the
inventory. The costs developed by MHG have therefore been used for this
section of the study. It should be noted that in Case 5 the study by MHG
indicates a slight increase in the sulphur content of LFO, due to increased
loading of the H-Oil process.
Although it is not considered to be feasible for widespread application, costs
have been developed for fuel switching to natural gas based on the fuel used
and heat content of the fuel (Appendix B). An additional benefit of this
substitution would be somewhat lower NO, emissions for the sources considered
because of the elimination of fuel nitrogen. The annualized costs generally
indicate that the switch can be made at an overall surplus. However this
indication is based on general fuel costs for 1987 supplied by the fuel
industries (Appendix B). The actual value or cost of switching could be
Significantly different if fuel prices change either under external market
forces or because of the direct impact of a regulated change of fuel on the
markets or on the distribution costs of the fuels. The supply of natural gas
in the quantities needed for a province wide change would require a major
increase in the distribution pipeline system.
The FGD systems used in the evaluation have been dry lime scrubbing, spray dry
lime scrubbing and wet scrubbing with limestone using the algorithms shown in
Appendix B.
Nitrogen Oxide
Reductions in emissions of NO, can be achieved by changes to the boiler
furnace operations or to the fuel burners. The simplest to install are burner
changes from the older systems to the more efficient low excess air burners.
This change is limited in its application to gas and oil burners, it cannot be
applied to coal, wood or refuse burning installations. However reductions in
the amount of excess air supplied to the system can be made in all cases and
the emissions reduced thereby. In order to carry this out, some changes need
to be made to the boiler control system and costs apply to these
modifications. The extent of the emission reduction will be dependent on the
boiler type, the assumed levels are shown in the table below:
Boiler type Original Modified
Excess Air Excess Air
Natural gas 40% 15%
Fuel oil 40% 15%
Coal (pulverized) 50% 30%
Coal (stoker boilers) 50% 35%
Modifications to the combustion chamber and the manner in which the combustion
air is introduced to the burning area can be applied to all types of boilers
and involves the redistribution of the air between the ports and in most cases
a change in the position of the ports. It may also include the use of flue gas
recirculation. The costs are therefore extremely variable between the
different boilers which exist. A generalized boiler design was used in the
estimates which was based on the heat input to the boilers, average heating
values of the fuels, and the excess air levels shown above. These values in
turn were based on the data from the inventory, where it was available, or on
estimates based on those values which were inventoried. In making these
estimates reliance was placed on the use of normal heat and mass balance
calculations and "emission estimates" from the U.S. EPA (1985).
It has been assumed that none of the existing boilers have been upgraded and
the cost estimates include changes for all of the boilers within the
appropriate groupings. For this purpose the boilers within each sector were
grouped according to the fuels used.
Tail end control systems for boilers which were examined included SCR, SNCR,
copper oxide and carbon catalyzed systems. Since they have been sufficiently
well tested for reasonably good cost estimating procedures to be developed,
the SCR and SNCR processes were used for this study.
The cost models used for estimating SNCR and SCR costs were based on
algorithms given by SRI International (1980). The input to the calculation
rather than on the directly available information. Flow rates or heat input
were used to obtain equivalent MW capacities and the costs were then prorated
from the SRI report.
The approach taken did not vary between the sectors, hence although errors may
exist in the estimates, direct comparisons between the sectors should be
valid. The algorithm used is given in Appendix B.
3.2.2 Processes
Sulphur Dioxide
The process sectors emitting sulphur dioxide are frequently combustion sources
using waste gases from the process sectors for process heating or steam
Production. In those cases assumptions have been made based on reported
compositions, heat contents (Appendix B) and fuel usage rates calculated from
the SO, emissions. Fuel switching has not been used nor has the use of
natural gas for the process streams since the impacts on the Process
operations could not be readily assessed. FGD processes have been used for
control of process emissions throughout this part of the study. Regenerative
so, scrubbing has been applied to the pulp and paper sulphite mills where the
liquors can be collected and reused in the pulping process. Throwaway
Scrubbing processes have been applied to all other sources. The algorithms for
these control technologies are shown in Appendix B.
Nitrogen Oxides
NO, emissions from Processes arise mainly from combustion sources, but can in
a few instances occur as a result of chemical reactions. The combustion
emissions from boilers. The major difficulty in estimating the costs of
controls arises from a lack of information about the manner in which the
combustion is carried out and the heat content of the fuel used for
combustion. The sources are varied, and the emissions may occur as the result
of using normal fuels or fuels produced in the processes. The combustion of
coke oven gas, CO gas and the incineration of wastes all result in emissions
of NO,. It was not always possible to identify the source of the fuel used
directly from the inventory and in many cases the exact composition of the
fuel could not be established.
In order to indicate the assumptions made and the accuracy of the estimates
more clearly the industry sectors will be described separately in the
following segments of this section.
3.2.3 Specific Sectors
Primary Metals
Sulphur dioxide emissions from these sources arise as a result of the
reduction of ore by combusting the metal sulphides. In view of the high
emission rates which such processes give rise to, an efficient control method
will be needed if acceptable levels of SO, are to be achieved. The lack of
detailed knowledge of the processes involved and the complex nature of the
metallurgical operations prohibited the evaluation of process changes being
used to control the emissions. Wet limestone scrubbing was therefore costed
as the means of achieving the desirable emission control efficiency.
The only source of NO, listed under this category was Kidd Creek Mines Ltd.,
which, although recorded as emitting 669.5 tonnes/ year has instituted
controls and is now considered to be a negligible source of this pollutant.
Food, Beverages and Textiles
Sulphur dioxide emissions arose from only one process source, Canada Malting
(Tor) Ltd. which used residual oil for its barley malting heat source.
Only two significant process sources of NO, emissions were listed in the
inventory for this sector. These both used fuels for drying foodstuffs, they
were therefore treated as if the emissions were from boilers and were
subjected to the same NO, control systems.
A large inventory of boilers gave rise to NO, and SO, sources. There were 24
sources using natural gas 4 using distillate oil and 14 which employed
residual oil.
One other source of so, and NO, was included in this inventory, probably due
to a coding error, which appears to be anomalous. Cyanamid of Canada which
was recorded as using CO gas is included in the NO, boiler tables as the
source using "other" fuels. Cyanamid was omitted from consideration in
costing SO, controls.
Rubber and Plastics
There were no process sources which emitted sulphur dioxide. Hence the only
sources emitting this pollutant were the two oil consuming boilers.
The sources in this sector have no processes which give rise to NO, emissions
and only four boilers of significance. Two of the boilers used natural gas as
a fuel, one used residual fuel oil, the fourth used distillate.
Textile Industries
Of the 11 boilers in this sector which emitted 10 or more tonnes/year so, ten
were using residual oil the other used distillate.
There were only eight of these boilers which gave rise to 10 or more
tonnes/year NO, emissions. Seven used residual oil and the other used natural
gas.
The processes which emitted SO, were viscose rayon sources, while NO, was emitted
from a nitric acid plant.
Paper and Allied Products
The processes used in this industry were entirely from Pulp and Paper mill
operations. Nitrogen oxides arose from the recovery boilers and the lime
kilns while So; was also emitted from the digesters, black liquor treatment
plants, absorption towers and smelt dissolving tanks. Each type of source was
treated individually, in particular the sulphite mill emissions from the lime
kiln and the digester blow pits were assumed to be recoverable for return to
the process and were controlled by wet scrubbing using caustic soda scrubbing.
A number of "Miscellaneous" sources of So, were assumed to be treatable by
non-regenerable FGD technologies.
In addition to the use of natural gas and oil, the boilers in this sector used
coal and wood wastes as sources of fuel. For the coal sources, the fuel was
assumed (as it was throughout this study) to have a heating value of 30218
kJ/kg (13,000 BTU/1b) and 2.8% sulphur content. Wood waste properties were
assumed to be 10,228 kJ/kg (4,400 BTU/1b) as fired and 0.05% sulphur.
Metal Fabricating
The processes in this sector were primarily those from which emissions
occurred as a result of the combustion of fuels used to heat the metals, or
ores. A major exception are the coke oven emissions where the process is a
partial combustion of coal from which the coke is produced. The fuels are
varied, and frequently are gases arising from other stages of the operations.
These include coke oven gas and blast furnace gas. The fuel heat contents
used in preparing data for estimating control costs were based on literature
references and on the ratios of SO,/NO, emissions. The fuel characteristics
used are listed in Appendix B.
Transportation Equipment
No processes were found for this sector in the emission inventory. The
boilers used natural gas, oil, and coal. In total there were 19 sources
emitting 10 or more tonnes/year. Ten NO, and nine so, sources are of
concern.
Non-Metallic Mineral Products
This industry sector included 23 processes which emitted NO, and 16 sources of
SO, in excess of the 10 tonnes/year levels. These were mostly cement kilns
but included melting furnaces and cupolas, as well as two asphalt plants.
Since these were high temperature sources similar to boilers they were
assumed to be adaptable to the same type of control technologies as were the
boilers. The 16 boilers assessed included one which burned coal and one using
coke as its fuel.
Chemical and Chemical Products
Comprising mostly petroleum refineries, the process emissions from this sector
were mainly from the combustion of fuels used for process heating. In
addition there were emissions from the sulphur plants and carbon black
manufacture which gave rise to emissions of both pollutants and two nitric
acid plants which emitted only NO, -
The sector used a variety of fuels for the boilers most of which were
identified in the inventory. In other cases it was possible to establish that
Process off gases had been used. Where the fuel source of the emissions was
listed as undetermined, it was assumed that the fuels were oil fuels which
were categorized into residual or distillate in accordance with the relative
3-10
levels of the SO and NO, emissions.
Other Major Groups
/
Incinerators and wood waste boilers were the components of this industrial
sector which gave rise to process emissions. Included amongst them were
municipal, sewage sludge, industrial waste and hospital incinerators.
In many cases the emissions of NO, and SO, were too small to be included in
the cost estimates, either because the installations were small or the
emissions were already being controlled.
The boiler emissions included heating plants at hospitals, major commercial
institutions and universities as well as the emissions from boilers associated
with the incinerators.
3.3 Major Point Sources
3.3.1 Falconbridge
SO, Emissions
Although the proposed process changes may reduce the SO, emissions to below
100 kilotonnes/year, it has been assumed, for the purpose of costing further
staged reductions of S05, that a reduction from 100 ktonnes/year will be
required. The needed reductions have been costed on the assumption that it
will be possible to treat separate streams of the exhaust gases by dry lime
injection, using a spray-dryer, in order to finally achieve an overall
reduction to 50 tonnes/year. For estimating costs it was assumed that
concentrations of SO, in the exhaust gases, which range between 1% and 3%,
would average 2.5% and the flow rate be that which would result in this
concentration.
Sell
NO, Emissions
The modifications proposed for the reduction of SO, emissions at Falconbridge
will also result in the reductions of oxides of nitrogen to below 10
tonnes/year. Further reductions, of unknown extent, will also accrue
from the installation of any control equipment which may be installed to
reduce the SO, emissions to below the regulated levels. No further control of
NO, has therefore been proposed.
353 2mEINCO
so, Emissions
The remaining gas streams to be controlled at INCO are low strength sources
ranging from acid plant tail gas to many sources of fugitive emissions. The
task of identifying the conditions for the control of the individual streams
was considered to be intractable within the bounds of this study. The sizes
of the effluent streams and the length of the ductwork needed to capture
fugitive emissions and direct them to a control system would have required an
extensive study. For costing purposes the gas streams were treated as being
the same as if they all arose from a power generating station and would be
controlled by limestone scrubbing. A concentration of 25,000 ppm was assumed
for this purpose. The estimation of operating costs included the assumption
that a suitable location for sludge disposal could be found on the company
property: the costs of transport and disposal of the sludges were therefore
relatively low.
NO, Emissions
As in the case of the Falconbridge operations, emissions of NO, will be
minimal after the changes at the INCO smelter are completed. No further
control is proposed for this plant.
3.3.3 Algoma
so, Emissions
Although numerous methods of controlling SO, emissions have been proposed for
the Algoma sinter plant at Wawa, including the Cominco, Mag-Ox and the
Pearson-Peck processes they are more costly than the limestone scrubbing
process and or involve problems of disposing of the recovered products.
Limestone wet scrubbing is efficient and cost estimates (MOE, 1983) indicate
that, within the error of the estimates, it can be used at Wawa as cost
effectively as the other processes.
For the purpose of this study a high degree of control was not necessary as
reductions of up to 50% of the "status quo" emissions were required to be
costed. Scrubbing half of the exhaust gas using the lime spray drying method
was selected as the most suitable method of removing SO, for achieving an
emission reduction of up to 30%. Scrubbing of the full stream would be needed
to achieve higher degrees of control.
For low efficiency reductions in emissions, ore beneficiation is the most
attractive method. Costs for this process were estimated from published costs
of coal treatment plants, on the assumption that similar degrees of
beneficiation could be achieved on ore and on coal. The coal cleaning process
uses similar methods of treatment, viz. crushing, screening, flotation dense
media separation and oil agglomeration, as those used in the metallurgical
mining processes.
NO, Emissions
Iron ore sintering at the plant is not considered to be a major source of NO,
emissions. Therefore, no further control is proposed for this plant in this
study.
3.3.4 Ontario Hydro
so; Emissions
After all options for conservation have been exhausted, the options for
reducing emissions of SO, lie between fuel switching to lower sulphur coals
and the increased use of nuclear power to various flue gas desulphurization
techniques. The costs of fuel Switching on the scale needed for Ontario Hydro
are dependent on the contracts which can be established for the supply of the
lower sulphur content fuels. These costs cannot readily be established until
the necessary negotiations have been virtually completed, neither can the
quality of the coals be identified. This option has therefore not been
considered for Ontario Hydro, neither has a switch to nuclear power been
considered since the time frame to build more stations far exceeds the study
period.
FGD systems can be based on scrubbing many units at low efficiencies or fewer
units at high efficiency. A quick review of the options has indicated that
the higher capital and operating costs associated with many units makes the
use of low efficiency Systems undesirable.
A single technique of control, using limestone scrubbing, was selected for the
reduction of emissions to regulated levels as well as for further reductions
to 50% of those levels.
NO, Emissions
SS eee
Reductions of emissions to the regulated levels were estimated on the basis of
3-14
of SCR units being installed at suitable locations. Further step-wise
reductions, to a level of 50% of the regulated quantity, were assessed using
the most efficient reduction method of installing SCR units on an additional
500 MW of generating capacity.
4.0 COST OF EMISSION CONTROL AND DISCUSSION
4.1 Introduction
Cost estimates for the industrial sector sources have been estimated for
various groupings of the companies within each of the eleven selected
industrial sectors (section 2.2). The groups were chosen by selecting
processes which were controllable by one emission control method. In each
group overall costs were estimated by first determining the geometric mean of
the emissions within the group, estimating the cost for control of a source
exhibiting the mean emission rate and then multiplying the cost of
controlling a source with the mean emission rate by the number of sources
within the group. By the use of this procedure one or more methods of control
were costed for every source in the eleven sectors with emissions of SO, and
NO, of 10 tonnes per year or more. Sources from which the emissions were less
than 10 tonnes constitute less than 2% of the total emissions from the
selected industrial sectors and were not considered. The detailed list of
sources was provided in the emission inventory which forms part of Interim
Report No. 1. This inventory differs from the ones used for other similar
studies related to the CAP program in that the SIC codes are different,
estimates made for those studies were based on information obtained from
industrial source and were extended on the basis of employment statistics
applicable to the sectors being studied.
The cost of controls on the four major industrial sources have been derived
from information in the MOE "Source Book" (1983) and the Report of the
Ontario/Canada Task Force (1982). This information has been supplemented by
studies carried out by Ontario Hydro (1987, 1988) and the Progress reports on
their abatement studies issued by INCO (1988) and Falconbridge (1988). Costs
have been estimated for further emission reductions which might be achieved.
Cost summaries are shown in Table 4.1 to 4.4 for the major sources and the
industry sectors. These are derived from data shown in the Tables of Appendix
A.
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TABLE 4-2
SUMHARY OF SOLPHOR DIOXIDE REDUCTION BY INDUSTRY CLASS
D Total Annualized Costs!
H Control 50x Capital Operating Annualized Auount of per tonne =!
' Option Kniseions 1 Cost Cost Cost 502 Removed S02 Bemoved !
1 Source (¥) (Tonnes/year) Reduction (million $) (million $) (million $) (T/yr) ($/tonne) }
i Primary 14219 1985 Level - - - = a
iMetals i
: 2-P 725 94.9 Za 722 1.47 13493.83 554 |
‘Food/Beverage 1421 1985 Level :
1-P 1401 1.4 0.4 0.2 0.28 19.89 14266 |
H 2-B 614 56.8 161.2 50.1 71.29 806.90 88349 !
4 5-B 570 59.9 11.9 52 6.76 850.94 7948 |
x 1-P 420 70.4 0.6 -4.5 -4.43 1000.10 -4425 !
‘Textile 7359 1985 Level à
i 1-B 4894 33.5 9.2 3.1 4.30 2465.27 1743 |
' 2-B 4621 37.2 90.8 28.2 40.17 2737.55 14675 |
' 5-B 4460 39.4 0.3 -3.2 -3.18 2899. 45 -1097 |
‘ 1-P 3569 51.5 8.1 1.8842 2.95 3789.89 178 !
iPaper Products 30516 1985 Level -
and Allied 3,4-P 29173 4.4 14.4 1.5 3.39 1342.70 2527 |
Products 2-P 22673 25.1 104.4 32.1 45.84 1842.61 5845 ;
: 2-B 18371 39.8 565.5 165.4 239.72 12145.37 19738 |
+ 1-B 18828 38.3 16.6 5.4 1.59 11687.63 650 |
1-P 17547 42.5 6.2 1.8681 2.68 12969.30 207 |
| 5-B 16784 45.0 0.6 -8.3 -8.25 13732.20 -601 |
iNetal 29480 1985 Level - - - = =
iFabrication 1-B 26326 10.7 18.0 7.0 9.36 3154.35 2966 ;
h 2-B 26149 11.3 215.6 67.0 95.36 3331.23 28626 |
à 5-B 25765 12.6 0.8 -6.1 -6.00 3714.47 -1615 |
' 1-P 19663 33.3 41.6 10.2 15.71 9816.81 1601 }
| Transportation 1801 1985 Level - - - = =
; Equipment 2-B 281 84.4 268.9 18.4 113.73 1520.04 74820 |
i Industries 1-B 279 84.5 6.9 2.4 3.35 1521.85 2198 }
i 5-B 1! 99.4 0.3 -2.1 -2.62 1790.19 -1462 |
St VOS
(3) CONTROL OPTIONS: 1) Line Spray Dryer
2) Linestone Flue Gas Desulphurisation
3,4) Wet Processes - Caustic Absorption/Scrubbing
5) Fuel Switch to Natural Gas
B) Control on Boilers
P) Control on Process
TABLE 4-2 cont‘d
SUMMARY OF SOLPHOR DIOXIDE REDUCTION BY INDUSTRY CLASS
d Total Annualized Costs!
: Control SOX Capital Operating Annualized Anount of per tonne |}
: Option Enissions 1 Cost Cost Cost 502 Bepoved S02 Renoved |
: Source (*) (Tonnes/year) Reduction (million $) (million $) (million $) (T/yr) ($/tonne) }
SS a a
Non-Metallic 20248 1985 Level ;
iNineral 1-B 19478 3.8 8.4 3.6 4.70 177.92 6038
Products 2-B 19397 4.2 187.8 56.6 81.33 843.00 96475 |
} 5-B 19337 4.5 0.4 -1.8 -1.72 911.16 -1886 ;
: 1-P 4029 80.1 21.1 Ta 11.39 16218.57 702 !
iCherical & 69384 1985 Level i
iPetroleur 1-P 53009 23.6 3.3 2.0 2.41 16374.62 147 !
Products 2-B 49887 28.1 209.1 65.2 92.69 19496 90 4754 !
i 1-B ~ 45238 34.8 30.4 10.7 14.65 24145.63 607 !
: 5-B 41006 40.9 1.4 -36.2 -36.00 28378. 06 -1263 ;
: 2-P 35108 49.4 246.9 79.0 111.42 34275.70 3251 ;
Other 4805 1985 Level i
{Groups 2-B 1552 67.7 750.4 226.2 324.86 3252.71 99873
' 1-B 1158 15.9 40.9 17.2 22.59 3646.69 6196 |
5-B 168 89.2 2.0 -1.9 -1.67 4285.70 -390 |
(3) CONTROL OPTIONS: 1) Line Spray Dryer
2) Linestone Flue Gas Desulphurisation
3,4) Wet Processes - Caustic Absorption/Scrubbing
5) Fuel Switch to Natural Gas
B) Control on Boilers
P) Control on Process
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TABLE 4-4
SUMMARY OF NITROGEN DIOXIDE REDOCTIONS BY INDUSTRY CLASS
: Annualized Cost |
4 Control NOx Overall Operating Annualized Anount of per tonne :
1 Source Option Knissions x Capital Cost Cost Cost NOx Bemoved KNOx Regoved !
4 (+) (Tonnes/year) Reduction (million $) (million $) (million $) (T/yr) ($/tonne) :
iFood/Beverage 2873 1985 Level A - - |
} ! 2729 5 0.6 -1.3 -1.2 144.21 -847!
i 2 2585 10 389 0.8 193 288.14 4343 |
1 3 1255 56 30.0 6.6 10.5 1607.62 6555 |
4 595 19 137.1 24.! 42.1 2277.56 18496 |
Bubber & 386 1985 Level - - i
iPlastics 1 343 il 0.1 -0.4 0.4 43.11 -19113 |
i 2 390 22 0.7 0.1 0.2 86.25 2324 }
3 154 60 4.) 0.9 1.4 231.54 6109 |
4 58 85 18.9 359 5.8 328.02 titel:
Textile 1180 1985 Level - = - = =
i 1 1058 10 0.1 -0.4 -0.4 121.65 29120
2 937 21 1.8 0.1 0.3 243.30 1299 |
3 508 57 Sat 0.8 1.3 671.84 1926 |
i 4 228 81 eZ 3.0 5.3 951.71 5552 |
‘Paper Products 11429 1985 Level - - - - = À
and Allied 1 10225 il 1.5 -2.8 -2.6 1203.44 -2179 |
\Products 2 9021 21 5.0 2.0 2.6 2408.03 1075 |
; 3 4682 59 88.4 19.4 31.0 6746.36 4601 |
h 4 1871 84 413.5 72.1 127.1 9557.82 13297 |
Metal 14812 1985 Level - - - 0.0 = À
Fabrication 1 14207 4 189 -4.3 -4.0 605.83 -6669 |
: 2 13602 8 8.3 1.3 2.3 1210.17 1898 |
: 3 6328 57 76.5 16.8 26.9 8484.54 3166 ;
« 4 2792 81 273.4 48.1 84.0 12020. 26 6990 |
a, eee eee eee
() CONTROL OPTIONS 1) Low Excess dir
2) Staged Combustion
3) Selective Kon-Catalytic Reduction
4) Selective Catalytic Reduction
TABLE 4-4 cont‘d
SUMMARY OF HITROGEN DIOXIDE REDUCTIONS BY INDUSTRY CLASS
Annualized Cost !
: Control NOx Overall Operating Annualized Amount of per tonne }
i Industry Option Enissions 1 Capital Cost Cost Cost NOx Removed NOx Benoved |
1 Class (x) (Tonnes/year) Reduction (million $) (million $) (million $) (T/yr) ($/tonne) !
transportation 2099 1985 Level - - - 0.99 ou
\Squipeent 1 1972 6 0.3 -2.4 -2.3 127.63 -18219 |
‘Industries 2 1844 i 9.9 0.7 1.8 255.26 6944 |
: 3 860 59 13.9 3.1 4.9 1239.37 3944 |
; § 343 84 65.2 11.5 20.9 1755.77 11411 |
Non-Metallic 9826 1985 Level - - 0.00 ‘
‘Mineral l 9406 4 0.8 -8.9 -8.8 429.57 -20985 |
Products 2 8986 9 Jel 2.5 2.9 840.16 3471 ;
} 3 4523 54 46.9 10.6 16.! 5303.31 3031 |
4 2313 16 315.5 56.7 93.8 1513.27 12490 |
Chenical & 28587 1985 Level - - - 0.00 =
iPetroleus l 27149 5 ja -17.6 -17.3 1437.90 -12061 |
Products 2 25708 10 8.6 5.0 6.0 2878.66 2085 |
; 3 12958 55 95.3 20.9 33.5 15628.24 2141 |
' 4 6446 77 437.7 17.0 134.5 22140.24 6076 }
‘Other 4298 1985 Level - - - 0.00 =;
:Groups l 3814 1! 31 -5.4 -5.1 483.90 -10489 |
1 2 3330 23 9.1 1.6 2.1 967.37 2749 |
3 2285 47 65.8 14.4 23.1 2012.09 11481 }
4 1447 66 196.6 35.6 61.4 2850.53 21551 |
(*) CONTROL OPTIONS 1) Low Ercess Air
2) Staged Combustion
3) Selective Non-Catalytic Reduction
4) Selective Catalytic Reduction
4.2 Industrial Sectors
4.2.1 Industrial Sector Costs
For the purposes of this study specific control methods were applied to
selected source types; these choices would not necessarily be those chosen by
the companies should controls be imposed by regulatory action.
The technologies used for costing purposes are listed in Table 4.5 which also
indicates their characteristics. The technologies imposed were those
considered to be the most suitable for the types of process being assessed,
based on the level of detail available from the inventory data. The costs are
approximate estimates which can vary by a factor of two or more depending
on the specific design needs, installation costs and operation mode.
Sulphur Dioxide Control
Sulphur dioxide control costs are summarized in Table 4.1 for the major point
sources and Table 4.2 for the industrial sectors. The data from which these
tables were derived are displayed in Appendix A. Table A-4.1 indicates the
sources and the quantities of emission for each sector.
The types of industrial processes and the number of sources of each type are
identified in Table A-4.3.0 while Tables A-4.4.2 to A-4.4.5 present the costs
for control methods for the specific processes listed in Table A-4.3.0. These
costs are summarized for all processes in Table A-4.4.1. Capital costs are
listed in the top section of the tables and operating costs are in the lower
section. The costs of applying selected technologies to boilers are shown
Similarly in Tables A-4.4.6 to A-4.4.8.
Tables, A-4.5.1 to A-4.5.6, present capital, operating and annualized costs,
as well as the the quantities of SO, removed, removal efficiencies and the
cost of removal per tonne for each sector. The overall summary of these
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estimates is displayed in Table A-4.2 which also shows the costs for achieving
various levels of control for each sector.
Nitrogen Oxide Control
The costs for controlling NO, are summarized for major sources in Table 4.3
and for industrial sectors in Table 4.4. Tables A-4.7.1 to A-4.7.4 contain
the costs for the control of processes and Tables A-4.7.5 to 8, the costs for
boilers by four different methods; SCR, SNCR, combustion modifications and the
use of a low excess air supply. The costs for each process and fuel type
within each industrial sector are shown for the four methods and the total
for each sector is given in the last column of these tables. The totals for
each industry were then transferred to Tables A-4.8.1 to A-4.8.4, in which the
annualized costs and the costs per tonne of NO, removed are calculated, also
shown are the total tonnes of NO, removed and the efficiency of removal.
The most effective methods of control, as shown by the overall efficiencies of
78.7% (Table 4.8.4) and 55.5% (Table 4.8.3), are the SCR and SNCR processes,
although the costs per tonne removed are higher than the costs for combustion
modification and low excess air. These two emission reduction methods are,
however applicable to a wider range of sources than the combustion control
methods.
4.2.2 Petroleum Fuel Desulphurization.
The costs of fuel desulphurization vary with the method of obtaining the lower
sulphur content fuels and the extent to which the desulphurization is carried
out. The basis of the costs used in this study is the unpublished report by
MHG International Ltd. (1983).
The MHG (1983) report considers six cases of sulphur reduction, which may
briefly be described as:
Case 1. Sulphur in Light Fuel Oil (LFO) reduced to 0.3%.
4-3
Case 2. Sulphur in LFO reduced to 0.1%.
Case 3. Sulphur in LFO limited to 0.3%, with a reduction in the
quantity of Heavy Fuel Oil (HFO) as 66% of the vacuum column bottom
stream treated in an H-Oil unit to produce LFO.
Case 4. Asis ‘Casey 3: except that the LFO is limited to 0.1%
sulphur.
Case 5. As Case 3. except that 90% of the vacuum bottoms are
converted in the H-Oil unit.
Case 6. As Case 4. except that 90% of the vacuum bottoms are
converted in the H-Oil unit.
Although the MHG study indicates that Case 1 can be met, under current
refinery operating practices, it is noted that the refineries do produce
distillate oil with sulphur content in excess of 0.3%. However, when it is
necessary, for inventory purposes, to estimate SO, emission from other
available data, MOE (telephone communication between S. Wong and B. Powers) in
the past have assumed 0.3% sulphur content for distillate consuming boilers
and heaters. For the purposes of the current study it has been assumed that
the 0.3% sulphur content could be achieved with no extra capital expenditure,
and Case 1 is therefore the base case. The costs of carrying out the other
five cases are displayed at the bottom of Table 4.1. The lowest cost per
tonne of so, removed ($304.7) is a result of applying Case 2, but the
reduction in emissions amounts to only 5% (10,040 T/yr). The major reduction
of 20% of the total emissions would cost $510.1/tonne and remove 36,920 tonnes
per year of emissions.
The overall reductions in the emissions by industry and from the refineries
are shown in Table A-4.11 which, based on the process heat requirements, also
shows how the fuels produced would be distributed between consumption in the
4-4
refinery itself and sales to consumers. The impact of these changes on the
industrial sectors has been determined by ratioing the costs to the fraction
of the total SO, emissions in the province which arise from the oil consuming
processes and boilers in the specified sectors. The emission reduction
resulting from use of the fuels by the industrial sectors, and the allocated
costs are given in Table A-4.10 and A-4.11, respectively. The costs per tonne
so; removed are listed in Table A-4.12.
4.3 Major Point Sources
4.3.1 Falconbridge
The costs of controlling emissions from the major point sources are summarized
in Tables 4.1 and 4.3.
Sulphur Dioxide Control
The estimates are based on the decision that reductions should be achieved by
the use of dry lime scrubbing on all or part of the remaining emissions. The
sources, residual emissions from processes, contain over 2% SO, and therefore
do not require wet processes to ensure high removal efficiency. The use of
wet scrubbing technologies are more costly unless recovery of the sulphur
values is practicable. At the low SO, concentrations the cost of recoveries
generally will outweigh the value of the product. The wet processes have
therefore not been costed for Falconbridge.
Annualized costs for these additional controls range from $11.6 million for a
reduction of 10% to $78.3 million for a 50% reduction in emissions. These
costs are mainly due to operating the control equipment. Because of the low
quantities of emissions being controlled the costs per tonne of SO, range from
$1160 to $1566.
4.3.2 INCO
Sulphur Dioxide Control
Since the requirement in this case is to control relatively weak tail gases
from the acid plants and from high flow fugitive emissions it has been assumed
that wet limestone scrubbing is the preferred control technology. This method
is capable of up to 95% recovery efficiency. Costs per tonne of pollutant
removed varies with the concentration of the source gases and the gas flow
rate. The capital, operating and annualized costs for specific reduction
amounts are presented in Table A.4.1. Annualized costs for these additional
controls range from $20 million for a reduction of 10% to $48 million for a
50% reduction in emissions. About 70% of these costs are for operating the
control equipment. Because of the quantities of emissions being controlled
the costs per tonne of SO, range from $752 to $362.
4.3.3 Algoma
Sulphur Dioxide Control
Reductions in SO, emissions of up to 20% at Wawa could be obtained by ore
beneficiation. Based on cost estimates of coal cleaning and making allowance
for the size of the operation and the extent of ore cleaning required to
produce a 10% reduction it is estimated that capital costs of $13,400,000 and
operating costs of $90,000 would be required and result in annualized costs of
$1,660,000 and a cost of $133/tonne removed.
For a reduction of 20% the capital expenditure would need to be raised to
$22,500,000 and operating expenses would increase to $111,000 per year. The
cost per tonne removed would be $110.
Further reductions would need to be made by the use of flue gas cleaning. It
would be necessary to scrub one half of the exhaust gases from the sinter
Strands in order to carry out an effective reduction program rather than scrub
4-6
all of the stream to a lower efficiency. This procedure was estimated to
require $21,940,000 of capital with operating costs of $35,600,000 for an
annualized cost of $38,140,000. It would remove 37,500 tonnes at a cost of
$1,020 per tonne. A 50% reduction would result in operating costs of
$48,000,000 and a capital expenditure of $27,200,000 for an annualized cost of
$51,200,000 and remove 61,250 tonnes a year at a cost of $835.8 per tonne of
SO, .
Nitrogen Oxide Control
This operation is not a major source of NO, emissions and the sintering
process is not readily amenable for NO, control.
4.3.4 Ontario Hydro
Sulphur Dioxide Control
Ontario Hydro has carried out detailed studies on the use of limestone
scrubbing for the control of its acid gas emissions. The costs developed have
been used in these estimates after comparison with estimates made by MOE and
others who have indicated that they are acceptable for this purpose.
In order to meet the requirements of the Ontario Regulation 281/87 a capital
expenditure of $560,000,000 will be required. With operating costs of
$42,000,000 per year this results in annualized costs of $133,000,000.
As shown in Table 4.1, further reductions of up to 50% require capital
expenditures of 62.3 to 311.5 million dollars, and annualized costs of 14.8 to
74.1 million dollars. The costs per tonne of SO, removed range from $845 to
$848, compared with $573 per tonne for the initial approach to the target
emission level. Although it was assumed that further reductions would be
achieved by the installation of a similar technology, the variations arise
from the overall size of the installations and the number and size of the
scrubbing units required in the different circumstances.
4-7
Nitrogen Oxide Control
Costs for the control of nitrogen oxides at Ontario Hydro have been based on
the costs of controls, using Selective Catalytic Reduction at generating
stations in the United States. The effectiveness of SCR is such that it
permits the required overall removal efficiencies with the least number of
installations.
Costs have been developed for this study based on the data for 36 generating
stations in the U.S.A., with overall collection efficiencies ranging from 8
tO 40 % (Calvert and Englund, 1984).
From the list the fourteen stations which reduced emissions by 40% were
selected and the average costs for these stations were developed. The average
capital costs amounted to $856.2 (US, 1980)/ton removed, this equates to
$1442/tonne removed (Cdn.1986) for a plant which has no controls installed.
The annual operating costs were equivalent to $215 (Cdn. 1986) tonne removed.
These costs appear to be low when compared with costs developed by many
authors, for specific generating stations or for a detailed but generalised
design of station. However it was felt that the actual experience of a number
of stations would be the most suitable for use in this current study where the
explicit details of designs could not be developed in the absence of details
about the existing state of controls at any one station.
The emissions from the Ontario Hydro stations will have been reduced from
94,400 tonnes/year (current conditions) to 61,330 tonnes/year in 1994 (Base
case). At that emission rate capital costs are estimated to be $13,000,000 or
$1337/tonne for the removal of 10% of the emissions while annual operating
costs, after making an allowance for increased Canadian labour and materials
costs would be $2,500,000. The annualised cost then becomes $4,210,000/year
based on a 25 year plant life and 12.5% interest on capital for a cost of
$687./tonne NO, removed.
It has been assumed that further reductions will be achieved by the
installation of modular units of equal size and the costs per tonne of removal
will be constant. Capital costs will then range from $13,000,000 for a 10%
reduction in emissions from 61,330 tonnes/year to 55,197 tonnes/yr. Operating
costs will amount to $2,500,000/year and the annualised costs will be
$4,210,000/year. For each additional reduction of 6,133 tonnes costs will
increase proportionately until at a reduction of 59.4%, the annualised costs
will amount to $77,100,000/year (Table 4-3)
The use of combustion modifications has not been addressed in this study. The
experimental work at Nanticoke has indicated that NO, reduction of up to 60%
may be achievable, however results have not been fully assessed and published.
The technologies covered are dependent on the boiler design and are unlikely
to be applicable to the same degree at other stations. Further confirmation
of the effectiveness and the cost is desirable before these modifications can
be considered in this study for the large Ontario Hydro boilers.
REFERENCES
Calvert, C. and Englund, H.M. (eds). "Handbook of Air Pollution Technology."
John Wiley & Sons, Inc., 1984.
Economic Analysis Branch (EAB). "EAB Control Cost Manuals." 3rd Edition.
EPA 450/5-87-001A, February 1987.
Falconbridge Limited. "Progress Report No. 4 SO, Abatement Program: Period
July - December, 1987." January 1988.
Pryling, iGsR. (ed). "Combustion Engineering." Revised Edition, The
Riverside Press, 1967.
INCO. "Progress Report, INCO Limited Sudbury Smelter Complex, SO, Emission
Control -Regulation 660/85 - 12 December 1985." January 1988.
MHG International Ltd.. "Study on Petroleum Fuel Desulphurization in the
Petroleum Industry. Volume 1 of aan Prepared for Environment Canada,
DSS File 5355.KE145-2-0734, 1983.
Ontario Hydro. "Production and Statistics Manual." Thermal and Hydraulic
Generation Division, TG 09101, March 1987.
Ontario/Canada Task Force for the Development and Evaluation. of Air Pollution
Abatement Options for Inco Limited and Falconbridge Nickel Mines, Limited
in the Regional Municipality of Sudbury, Ontario, Fall 1982.
Ontario Hydro. "Flue Gas Desulphurization Program Environmental Assesment."
February 1988.
Ontario Ministry of the Environment (MOE) . "Source Book." Revision D. Air
Resources Branch, March 1983.
Perry, R.H. and Chilton, C.H. (eds). "Chemical Engineers’ Handbook." 6th
ed., McGraw-Hill, 1984.
Radian Corporation. "Industrial Boiler SO, Cost Report." Prepared for the
U.S. Environmental Protection Agency, EPA-450/3-85-011, November 1984.
SRI International. "Nitrogen Oxides: Reduction in Flue Gases." Prepared for
the Engery Technology Economics Program, Report No. 17, October 1980.
U.S. Environmental Protection Agency (USEPA). "Compilation of Air Pollutant
Emission Factors, volumn 1: Stationary point and Area Sources." 4th
ed., AP-42. EPA, September 1985.
Woods Gordon Management Consultants. "Petroleum Refinery Sector Profile."
Prepared for the Policy and Planning Branch, M.I.S.A., Ontario Ministry
of the Environment, 1987.
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APPENDIX A
COST ESTIMATES
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APPENDIX A - LIST OF TABLES
Sulphur Dioxide Emissions - 1985 Level
Nitrogen Dioxide Emissions - 1985 Level
Process Identification for Sulphur Dioxide Sources
SO; Reduction Costs
Control Strategies
SO; Reduction Costs
Spray Dryer
SO, Reduction
FGD
SO, Reduction
Absorption
SO; Reduction
Scrubbing
SO; Reduction
SO; Reduction
SO; Reduction
Natural Gas
SO, Removal
SO, Removal
SO, Removal
Natural Gas
SO; Removal
Spray Dryer
SO, Removal
SO, Removal
Costs
Costs
Costs
Costs
Costs
Costs
for Process Streams
for
for
for
for
for
for
for
Process
Process
Process
Process
Boilers
Boilers
Boilers
Streams
Streams
Streams
Streams
All
Lime
Limestone
Caustic
Caustic
- Lime Spray Dryer
- Limestone FGD
- Fuel Switch to
Costs
Costs
Costs
Costs
Costs
Costs
for
for
for
for
for
for
Boilers
Boilers
Boilers
Process
Process
Process
- Lime Spray Dryer
- Limestone FGD
- Fuel Switch to
Streams - Lime
Stream - Limestone FGD
Stream - Wet Scrubbing
Identification for NO, Process Streams
NO, Reduction Costs for Process Streams - Low
Excess Air
NO, Reduction Costs for Process Streams - Staged
Combustion
APPENDIX A -
A-4.
A-4.
A-4.
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LIST OF TABLES,
Reduction Costs
Reduction Costs
Reduction Costs
Reduction Costs
Reduction Costs
Reduction Costs
continued
for Process
for Process
for Boilers
for Boilers
for Boilers
for Boilers
Streams - SNCR
Streams - SCR
Removal Costs for All Streams
Removal Costs for All Streams
Removal Costs for All Streams
From Fuel Usage
A-4.12 Per Tonne Cost of Fuel Oil Desulphurization
== Removal Costs for All Streams
Costs of Fuel Oil Desulphurization
Low Excess Air
Staged Combustion
SNCR
SCR
- Low Excess Air
- Staged Combustion
- SNCR
= OCR
Effects of Fuel Oil Desulphurization on SO, Emissions
Estimated Overall Emissions Reduction of SO;
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APPENDIX B
COSTING PROCEDURES, FUEL DATA
QUALITY OF INFORMATION ON CONTROLS
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APPENDIX B - LIST OF TABLES
Quality of Information on Controls - So;
Quality of Information on Controls - NO,
Annualized Cost Equation
Nomenclature Used in Cost Algorithms
Capital Cost Components
Operating and Maintenance Costs Components
Calculations Common to Cost Algorithms
Cost Equations for Low Excess Air Applied to
Industrial Boilers
Cost Equations for Staged Combustion Air Applied
to Pulverized Coal-Fired Boilers
Cost Equations for Staged Combustion Air Applied to
Residual Oil-Fired Boilers
Cost Equations for Lime Spray Drying FGD Systems with
PM Removal
Cost Equations for Sodium Scrubbing FGD Systems
General Design Specifications for FGD System for
SO; Control
Estimated Capital Investment for Selective Catalytic
Reduction
Estimated Operating Costs for Selective Catalytic
Reduction
Estimated Capital Investment for Selective Non-Catalytic
Reduction
Estimated Operating Costs for Selective Non-Catalytic
Reduction
Costing Algorithm for SCR/SNCR
Fuel Switching Cost Algorithm
Limestone Flue Gas Desulphurization Algorithm
Fuel Characteristics
Characteristics of "Unconventional" Fuels
APPENDIX B: COSTING PROCEDURES, FUEL DATA,
QUALITY OF INFORMATION ON CONTROLS
B.1 Introduction
Costing algorithms and fuel characteristics used in the economic analysis of
control strategies are presented in this Appendix. With the exception of the
fuel switching algorithm, basic cost equations follow those outlined by the
Radian Corporation (1984) and SRI International (1980). The quality of
information respecting various control technologies is summarized in Tables
Bea. and Baw. 2:.
Algorithms in this Appendix are grouped according to source with those
developed by the EPA used for costing both NO, and SO, control strategies,
those based on SRI International (1980) on ETEP strictly for NO, control, and
fuel switching for so, control only. All costs are converted to 1987 Canadian
dollars based on Statistics Canada escalation factors. The calculation of
annualized costs is shown in Table B.1.3.
B.2 Radian Corporation Costing Algorithms
Cost correlations developed by the Radian Corporation (1980) consist of a set
of generic equations common to all control strategies and empirical
relationships developed on a process by process basis. Nomenclature is common
throughout all algorithms and is summarized in Table B.2.1.
Generic cost equations are outlined in Tables B.2.2 and B.2.3 and summarized
algebraically in Table B.2.4. Process specific algorithms are summarized in
Tables B.2.5 to B.2.9 for the following control processes:
low excess air, coal, oil and gas boilers (NO, control)
low excess air, pulverized coal (NO, control)
staged combustion (NO, control)
sodium scrubbing FGD system (SO, control)
. spray drying/dry scrubbing (SO, and particulate control)
General design specifications for FGD systems are shown in Table C.2.10..
B.3 SRI International Costing Algorithms
Costing algorithms for NO, control by selective catalytic reduction (SCR) and
selective noncatalytic reduction (SNCR) are based on data by SRI (1980). A
power law correlation of the form:
2 O27
COST, = COST, er x | capacity, |
capacityper
was used to calculate capital and operating costs for facilities. For costing
purposes, volumetric flowrate was chosen as a representative measure of
capacity with a value of 1.8 million acfm calculated for the reference
facility.
Cost estimates as developed by SRI for the reference facility are shown in
Tables B.3.1 and B.3.2 for SCR and Tables B.3.3 and B.3.4 for SNCR controls
respectively. The algorithms used for costing purposes are shown in Table
BeSeo. This table also summarizes estimates of operating costs component
costs according to the equation:
component cost = OC; i |
where
OC; = operating cost of facility being costed;
CCREr = component cost of reference facility, and
OCper = operating cost of the reference facility
B.4 Fuel Switch Algorithm
Capital costs for fuel switching were estimated using the Radian Corporation’s
"Cost Equations for Low Excess Air Applied to Industrial Boilers" as presented
in Table B.2.5.- Capital costs were calculated based on a natural gas feed
rate which provides an equivalent heat input as the process under evaluation.
The calculated capital cost was then multiplied by a factor of 1.5 to account
for equipment modification costs.
Operating costs, calculated using the algorithm outlined in Table B.4.1,
represent the savings (increase) in fuel costs resulting from the fuel switch.
All other operating costs were assumed constant.
The costs, of the fuels, used were obtained from suppliers and industry
associations by telephone conversations. The values represent the best
estimates which could be made from the ranges of costs disclosed by those
sources. None of the information sources were prepared to quote firm costs
unless a specific situation was under consideration.
B.5 Fuel Characteristics
Data pertaining to fuel characteristics are shown in Tables B.3.1 and B.3.2
for conventional and unconventional fuels respectively. Heat and sulphur (S
or S05) content data were used to calculate heat inputs and/or gas flowrates
required in the costing algorithms.
QUALITY OF INFORMATION ON CONTROLS - SO»
Tech-
SO, Control Rating+ nology” Cost?
Coal cleaning NA
Ore beneficiation G T; Cy
Fuel switching G Ty Cy
Petroleum fuel desulphurization G T; Cy
Raw material change NA
Operating changes NA
Equipment changes NA
Fuel additives P T3 C3
Dry lime addition to fuel P To C3
Lime injection modified burners F Ty Cy
Lime/limestone scrubbing G Ty Cy
Duel alkali scrubbing G Ty Cy
Sodium carbonate scrubbing G Ty Cy
Major process changes F T; Cy
Wellman-Lord process G Ty Cy
Cominco process G T, Cy
Citrate & Stauffer process G Ti Cy
Pearson-Peck process F To Co
Tail gas cleaning G Ty C1
Irradiation technology E T3 C3
Dry lime injection G T; Cy
Spray drying process G Ty Cy
Poli process F To Cy
1. Rating: G - Good; F - Fair; P - Poor, NA - Not Available.
2. Technology: T, - Proven; T> - Tentative; T3 - Unproven.
Se Cost: C1 - Established; Cz - Approximate; C3 - Unknown.
+QuVLiS D,1.4
QUALITY OF INFORMATION ON CONTROLS - NOx
Tech-
NO, C 1 Rating? logy? 2
x Contro ating nology Cost
Fuel switching G T Cy
Fuel modification NA (except refineries)
Low excess air G T; Cy
Flue Gas recirculation G T; Cy
Staged combustion G T; Cy
Low NO, Burners G Ty Cy
Lime injection modified burner F To Co
Dry lime addition to fuel P T3 C3
Fuel additives P T3 C3
Selective catalytic reduction G T; Cy
Selective non-catalytic reduction G T; Cy
Copper oxide absorption = T3 C3
Irradiation technology E T3 C3
Other combined technologies P T3 C3
aks Rating: G - Good; F - Fair; P - Poor, NA - Not Available.
van Technology: T, - Proven; T> - Tentative; T3 - Unproven.
Se Cost: C, - Established; Cy - Approximate; C3 — Unknown.
ANNUALIZED COST EQUATION
CRF = i (1 + ij”
eh Ce ae Ba
Clone t)) gt
AC = OC + CRF * CC
annualized cost
capital cost
capital recovery factor
interest rate, assumed to be 10%
yearly Operating costs
control system life
TABLE B-2.1 NOMENCLATURE USED IN COST ALGORITHMS
1. Capital Costs (1978 dollars)
EQUP = Equipment
INST = Installation
TD = Total Direct
IND = Indirect (Engineering, Field, Construction, Start-up,
and other miscellaneous costs)
TOI = Total Direct and Indirect
CONT = Contingencies
TK = Turnkey
LAND = Land
WC = Working Capital
TOTL = Total Capital
2. Operation and Maintenance Costs (1978 dollars/year)
DL = Direct Labor
SPRY = Supervision Labor
MANT = Maintenance Labor
SP = Spare Parts
ELEC... = ÆElectricitye
UC = Utilities and Chemicals
WTR = Water
SW = Solid Waste Disposal
SLG = Sludge Waste Disposal
LW = Liquid Waste Disposal
SC = Sodium Carbonate
LMS = Limestone
LIME = Lime
FUEL = Fuel
TOOM = Total Direct Operation and Maintenance
OH = Overhead
TOTL = Total Operation and Maintenance
3. Annualized Costs (1978 dollars/year)
CR = Capital Recovery
WCC = Working Capital Charges
MISC = Miscellaneous (G & A, Taxes, Insurance)
TCC = Total Capital Charges
TOTL = Total Annualized Charges
nn
TABLE B-2,1 (Continued)
a eee
4. Boiler Soecifications
17 UEC IT ICAtIONS
Q = Thermal Input (106 Btu/hr) wi)?
FLW = Flue Gas Flowrate (acfm) (m”/s)
GF = Capacity Factor (-)
BCRF = Capital Recovery Factor for Boiler System
5 Fuel Scecifications
ae SECC TICaCions
FC = Fuel Cost ($/10° Btu) (sm)?
H = Heating Value (Btu/1b) (kJ/kg)
S = Sulfur Content (percent by weight)
A = Ash Content (percent by weight)
Fuel Nitrogen Content (percent by weight)
O\
SO, Control Soecifications
ee EET ications
UNCSO2 = Uncontrolled $0, Emissions (1b/10° 8tu) (ng/g)?
CTRSO2 = Controlled SO, Emissions (1b/10° Btu) (ng/J)
EFFSO2 = SO, Removal Efficiency (percent)
CRFSO2 = Cafital Recovery Factor for SO, Contro! System
The PM Control Soecifications
——— ec irications
UNCPM = Uncontrolled PM Emissions (1b/06 Btu) (ngyy)?
CTRPM = Controlled PM Emissions (1b/10" Btu) (ng/J)
EFFPM = PM Removal Efficiency (percent)
CRFPM = Capital Recovery Factor for PM Control System
8. Cost Rates
ELEC = Electricity Rate §$/kw-hr) 3.b
WIR = Water Rate ($/10 gal) {S/m )
ALIME = Lime Rate ($/ton) ($/kg) b
ALS = Limestone Rate ($/ton) ($/kg) b
SASH = Sodium Carbonate Rate ($/ton) (S/kg
= SLOG = Sludge Disposal Rate ($/ton) ($/kg) b
SHD = Solid Waste Disposal Rate ($/ton} ($/kg) ue
LWD = Liquid Waste Disposal Rate ($/10 gal) ($/m~)
OLR = Direct Labor Rate ($/man-hr)
SLR = Supervision Labor Rate ($/man-hr)
AMLR = Maintenance Labor Rate ($/man-hr)
ee ee
TABLE B-2.1 (Continued)
9. Miscellaneous
$1 = Heat Specific Sulfur Removal (kg S/1000 MJ)
$2 = Time Specific Sulfur Removal (kg S/hr)
LF = Labor Factor (-)
10. NO Control Specifications
FFAC = F-Factor (dscf/10° Btu)
UNCEA = Uncontrolled Excess Air (%)
CTREA = Controlled Excess Air (2%)
PRCT = Percent Flame Extension Due to Staging
DELT = Change in the “lue gas exit temperature due to the
elimination of the air preheater or a reduction
in its effectiveness.
CRFNO = Capital Recovery Factor for NO. Control System
cost categories are not mutually exclusive. For example, some costing
routines include electricity and waste cost in the utilities category
while other calculate these cost separately.
Deco algorithms use metric units.
ce) factor presented as fraction not as percent.
enw ee dt te © de
CAPITAL COST COMPONENTS@
(1) Direct Costs
Equipment
+ Installation
= Total Direct Costs
(2) Indirect Costs
Engineering (10% of total direct costs)
+ Construction and Field Expenses (10% of total direct costs)
+ Construction Fees (10% of total direct costs)
+ Start Up Costs ( 2% of total direct costs)
+ Performance Costs ( 1% of total direct costs)
= Total Indirect Costs
(3) Contingencies = 20% of (Total Indirect + Total Direct Costs)
(4) Total Turnkey Cost = Total Indirect Cost + Total Direct Cost
+ Contingencies
(5) Working Capital
(6) Total Capital Cost = Total Turnkey + Working Capital
Boiler and each control system costed separately; factors
the engineering cost for the SO, control system is 10% of
apply to cost of boiler or control system considered; i.e.,
the direct cost of the SO; control system.
TABLE B-2.3 OPERATING AND MAINTENANCE COSTS COMPONENTS®
(1). Direct Operating Costs
Operating Labor
Supervision
Maintenance Labor, Replacement Parts and Supplies
Electricity
Water
Steam
Waste Disposal
Solids (Fly ash and bottom ash)
Sludge
Liquid
+ Chemicals
Total Non-Fuel O&M
+ Fuel
+ + + + + +
= Total Direct Operating Cests
(2) Indirect Operating Costs (Overhead)
Payroll (30% Operating Labor)
+ Plant (26% of Operating Labor + Supervision + Maintenance Costs
+ Replacement Parts)
(3) Total Annual Operating and Maintenance Costs = Total Direct +
Total Indirect Costs
*Boilers and control systems are costed separately; factors apply to boiler
or control system being considered, (i.e., payroll overhead for FGD system
is 30% of the labor requirement for the FGD system).
~V~ Om mom. 3
CALCULATIONS COMMON TO COST ALGORITHMS
1. Capital Costs
TD EQUP + INST
IND = 0.333 * TD?
TDI = TD + IND
CONT = 0.20 * TDI
WC© = 0.25 * TDOM
TK = EQUIP + INST + IND
TOTL = TK + WC
2. Operation and Maintenance Costs
FUEL = CF * Q * FC * 8760
TDO = Sum of all O&M Costs other than OH
OH 0.30 * DL + 0.26 * (DL + SPRV + MANT + SP)
TOTL = TDOM + OH
i}
3. Annualized Costs
CR = CRF * TK
WCC = 0.10 * WC
MISC 0.04 * TK
TCC = CR + WCC + MISC
TOTL TCC + TOTL O&M Costs
4. Labour Factors
Eee) = 1 ifiCr > 0.7
LF = 0.5 + 2.5 * (CF - 0.5) if 0.5 < CF < 0.7
Ee = 0.5 if CF < 0:5
Note:
= Feb system cost algorithms compute TD without prior computation of EQUP
and INST.
b Some algorithms compute IND explicitly as a function of
boiler and/or control device specifications.
Assumes 3 months of direct annual operating costs.
TABLE B-2.5 COST EQUATIONS FOR LOW EXCESS AIR
APPLIED TO INDUSTRIAL BOILERS
—_e_—_____—
ee ee ee
Routine Code: LEA
Capital Costs:
Coal: EQUIP = 46.22(Q) + 6496
INST and IND = 21.50(Q) + 1123
Oil and Gas: EQUIP = 31.38(Q) + 5185
INST and IND = 11.37(Q) + 1161
Annual Costs:
sp?
FUEL
O05; (M
-.00055
K)
(FC)(Q)(CF)(FFAC)(UNCEA - CTREA)
ee eo
algorithm assumes a flue gas temperature of 400°F and ‘he ambient air
temperature to be 77°F,
Ospare parts costs consist of the costs for spare parts, maintenance labor,
and maintenance materials.
TABLE B-2.6 COST EQUATIONS FOR STAGED COMBUSTION AIR
APPLIED TO PULVERIZED COAL-FIRED BOILERS
i
Routine Code: SCA
Caoital Cos+s:
EQUIP = 65 (Q) + 13000
INST and IND = 66 (Q) + 2000
Annual Costs:
RE USTES"
SP? = 0.05 (TK)
ELEC = 105 (Q)(CF)
FUEL = 21.9 (FC)(Q)(CF)
à =? A : L
Spare parts costs consist of the costs for spare parts, maintenance labor,
and maintenance materials.
TABLE B-2.7 COST EQUATIONS FOR STAGED COMBUSTION AIR
APPLIED TO RESIDUAL OIL-FIRED BOILERS (fuel N >0.23 wt. percent)
(30 - 250 x 10° Btu/hr)
Routine Code: SCA
Capital Costs:
TK = 1000 [(Q)(PRCT) 0.0536 + 2.56 (PRCT)]
where:
PRCT = 30; when N >0.6
PRCT = 81.1(N) - 18.7 when 0.23 <N <0.6
Annual Costs:
sp? = 0.05 (TK)
ELEC = 102 (Q)(CF)
FUEL = 21.9 (FC)(Q)(CF)
OC err nw
a , ;
Spare parts costs consists of the costs for spare parts, maintenance labor,
and maintenance maerials.
TABLE B-2.8 COST EQUATIONS FOR LIME SPRAY DRYING
FGD SYSTEMS WITH PM REMOVAL
oO
Routine Code: DS
Capital Costs: PȢ
TD
Cl + C2 + C3 + C4
55,600 (FLW)0-51
32,900 (52)0-40
18,400 + 8,260 (FLW) + 6,420 (FLy)0+50
256,320 [u1 + w2]?-6
Q * S/H * [0.626 EFFSO2 - 79.9 1n (1-EFFS02/100) - 10.1]
3.96 x 107° (UNCPM - CTRPM)
1.48 TD + 110,400 if Q < 58.6
1.60 TD if Q > 58.6
Annual Costs, $/Year
"ts, _3/ 1ear
OL
SPRV
MANT
M1
M2
ELEC
WTR
SW
W3
Wa
LIME
8,760 * DLW * LF
1,314 * SPRV * LF
(0.08 [55,600 (FLW)°-°! + 32,900(s2)9-40) 4 m1 + m2 * Le
834 FLW
MANT * (4.04 FLW + 1,086)
8,760 CF * ELEC [6.14 (FLW)°-82]
8,760 CF * WTR [0.144 FLW]
8,760 CF * SUD [W3 + WA]
(Q S/H) * [569 EFFSO2 - 72,700 In (1-EFFS02/100) - 9,230]
3.6 x 10799 (UNCPM - CTRPM)
ue * ALIME * (-48,500) * Q * S/H * [in (1-EFFS02/100) +
0.127
àFG0 algorithms use metric units as noted in Table p-2.]
Sl = S * EFFSO2 * 100/H.
ES = SI g + 3:6.
TABLE B-2.9 COST EQUATIONS FOR SODIUM SCRUBBING FGD SYSTEMS
—SsSsSsSs0@9e@0<_«S—s Ooo
Routine Code: sop? "©
Capital Costs:4
TK, = 39,900 (FLW)-985 + 1,370 (52)0-727
TK = 26,500 s, 0-39
w 2
TK = Ke tk
S W
Annual Costs
DL = 1,100*DLY
SPRY = 165*SPRV
MANT = 0.08*TK
ELEC = Si 760*CF*ELSC (3.61 (ELN) - 2215]
ELEC = 8760*CF*ELEC [0.23(S2) + 1.32]
ELEC = ELEC, + ELEC,
WTR = 8760*CF*UTR [0.600(FLW) - 2.08] [0.527(S1) + 0.364]
SC = 8760*CF*SASH [3.33(S2) + 0.082]
LH = 8760*CF*LHD [0.0616(S2) + 0.298]°
8A11 FGD algorithms are in metric units as noted in Table B-2.1
PS1 = S*EFFSO,*100/H
“s2 = $1*Q*3.6
The Subscript "s" denotes scrubber costs and the subscript "w" denotes
wastewater costs.
SThis equation assumes that the wastewater stream has a total
dissolved solids concentration (TDS) of 5%.
; me CERN CR Ce OR Ou
D ut nm ss SO OS ‘us
— ~ 2h 0
TABLE B-2.10 GENERAL DESIGN SPECIFICATIONS FOR FGD SYSTEM FOR so, CONTROL
Control Device lteu Specification
a —_—_—_—_——
Sodium eran Fe Scrubber type, Spray baffle
y
$0, removal on Pressure drop O tu. te 0,
ob) L/G 40 yal/{0? acf
Disposal method Oxldation and screrage
Dry Scrubbing (spray Halerlal of construction Carbon stee) spra dryer and fabric
drying, 50, and PH fllter Cinsutated)
renwoval)
(0s) Reagent Pluie; with sollds recycle at 2 kg
recycle sollds/ky fresh lime feed
Fabric filter Pulse Jet; alr-lo-cloth ratio of
4 aclu/ft
Pressure drop? 6 In. 11,0
L/G 0.3 yal/acf
‘Sullds disposal Trucked Lo off-site landf111
lectrice pow
Aa Pressure drofs'refer to yas side pressure drop across entire contro) systew.
TABLE B-3.1
ESTIMATED CAPITAL INVESTMENT FOR SELECTIVE CATALYTIC REDUCTION
Basis: 500-MW net grass-roots unit firing bituminous coal.
0.54 1b NOj/million Btu before SCR treatment.
Millions of
Capital Investment 1979 Dollars
Plant facilities investment
Reactors 9.10
Ducts, dampers, and expansion joints 1.98
Incremental FD fan cost 0.03
Incremental ID fan cost 0.91
Ammonia injection 1.26
Ammonia storage 0.81
General facilities 0.42
Paid-up royalties 0.11
Total plant facilities investment 14.62
+
Interest during construction 2515
Organization and start-up costs 0:73
Korking capital 0.49
Initial catalyst 6.50
Total capital investment 24.49
*
For nonregulated financing.
TABLE B-3.2
ESTIMATED OPERATING COSTS FOR SELECTIVE CATALYTIC REDUCTION
Basis: 500 MW net unit, 0.54 1b NO2/million Btu before SCR treatment,
1.05 average stoichiometric ratio, 6,132 h/y.
First-Year Operating Costs
(1979 dollars) Million $/y
Raw materials
Ammonia at $130/st 0.41
Catalyst 3525
Maintenance materials 0.29
Total raw materials 3495
Labor
Operating labor 0.00
Operating labor supervision 0.00
Maintenance labor 0:22
Administrative and support labor 0.04
Payroll burden 0.09
Total labor 0.35
Electric power 0.49
Fixed costs
G&A costs 0.29
Property taxes and insurance 0.37
Plant depreciation 0.58
Total fixed costs 1.24
Total operating costs 6.03
TABLE B-3.3
ESTIMATED CAPITAL INVESTMENT FOR
SELECTIVE NON-CATALYTIC REDUCTION
Basis: 500-MW net grass-roots unit firing bituminous coal.
0.54 lb NO, /million Btu before SNR treatment,
Capital Investment
Plant facilities investment
Air compressor
Incremental ID fan cost
Ammonia storage
Double-grid injector system
General facilities
Paid-up royalties
Total plant facilities investment
Interest during construction”
Organization and start-up costs
Working capital
Total capital investment
*
For nonregulated financing.
Millions of
1979 Dollars
TABLE B-3.4
ESTIMATED OPERATING COSTS FOR SELECTIVE NON-CATALYTIC REDUCTION
Basis: 500-MW net unit, 0.54 1b NOy/million Btu before SNR treatment,
1.2 average stoichiometric ratio, 6,132 h/y.
First-Year Operating Costs
(1979 dollars) Million $/y
Raw materials
Ammonia at $130/st 0.48
Maintenance materials (rg Ho)
Total raw materials 0.58
Labor
Operating labor 0.00
Supervision 0.00
Maintenance labor 0.07
Administrative and support labor 0.02
Payroil burden 0.03
Total labor 0.12
Electric power 0.48
Fixed costs
G&A costs 0.10
Property taxes and insurance 0.13
Plant depreciation 0.20
Total fixed costs 0.43
Total operating costs 1.61
SCR
Capcst
Opcost
Totlab
Elpwr
Mtce
Ammcst
Fixcst
SNCR
Capcst
Cpcost
Totlab
Elpwr
Mtce
Ammcst
Fixcst
=
+Qnut DeI- DT
COSTING ALGORITHM FOR SCR/SNCR
24.49E6 * (Q/1,800,000) : ?
6.03E6 * (Q/1,800,000) : ?
Opcost
Opcost
Opcost
Opcost
Opcost
6.11E6
1.61E6
Opcost
Opcost
Opcost
Opcost
Opcost
where Q = flow rate
*
*
*
*
*
*
*
*
*
-351/00-03
.49 / 6.03
.29 / 6.03
.41 / 6.03
1.24 / 6.03
(9/1, 800,000) : ?
(0/1,800, 000): ?
bags /1:61
Meet" 1.61
ae fod. 61
38) 1.61
£430/61.61
(acfm)
FUEL SWITCHING COST ALGORITHM
Operating cost of change
= Q(49Sgry) x Cost of new ($/:068ru) —2Cost'of old ($/:068ru)
Fuel Costs (obtained from suppliers)
Natural Gas 15 #/m = 0.4248 ¢/ft?
= $4.248/10° Bru
= $4.0304/10° g
Distillate 23.6 ¢/L = $6.868/10° BTU
= $6.516/10° J
Residual 31.75 ¢/L = $8.6573/10° Bru
= $8.214/109 g
Coal $55/T delivered
= $1.89/10° Bru
= $1.793/10° g
Refuse $45/T = $1.546/10° Bru
= $1.467/109 J
,
|
tt
un
FixCh
Elec
Water
Direct
Super
Labmat
Supply
Plant
Pay
Overhd
Labor
Mntce
Uta)
Sludge
Rawmat
ESO2
TABLE B-4.2
Flue Gas Desulphurisation.
8025 * S + 248600
4794 * S + 32816
16050 * S + 375000
11640 * S + 4000 * N + 30500
4588 * S + 16630 * SQRT(S) * N +234 * S* (2/3)
4.2824 * TotG
0.53 * TotG
SL
02 * TotG + 24000 * N
0.089 * TotG + 108.6 * SQRT (N * TotG)
0.360 * TotG + 25100 * N
417.6 * SQRT(N * TotG) * DF
0.268 * TotG
37475 * SORT (3.14 * s1 + AR)
23540 * S + 7496 * AR + 310400
236.48 * (3.14 * g + AR)" (2/3) + 1618.6 *
1582 * S + 22000
0.0184 * TotG + 3600 * S + 1146 * AR + 12000
64155 * SQRT((3.14 * § + AR) * Cr 1000 BLRY)
1883 * S + 22000
30000 * N
Conv + Silo + Ball + PandML + Stge
Abs + FandMA + PandMA + Tank + Heat + Soot +
Duct + Valv
Clar + VacF + TandM + Fixstr + PandMS + Spond+
Mob + RR
18747 * S * LSCO * CF
29200 * (3.14 * § + AR) * CF
0.04 * TotG * ELCO * CF
0.049 * (0.129 * TotG + 2520 * S) * ELCO * CF
17520 * LBCO
0.15 * Direct
0.04 * GrandTotal
0.006 * GrandTotal
0.5 * (Direct + Super + Labmat + Supply)
0.2 * (Direct + Super)
Plant + Pay
Direct + Super
Labmat + Supply
Elec + Water
(3.14 * S + AR) * 29200 * TMGE * cr
LS + FixCh
Sfctr * (100 - LSE) / 100
(3.14 * See AR) * (1/3)
TABLE B-4.2 FLUE GAS DESULPHURIZATION (CONT’D)
Depr = GrandTotal / BLRY
Interim = 0.0035 * GrandTotal
Taxes = 0.04 * GrandTotal
Insur = 0.003 * GrandTotal
CapCh = 0.15 * GrandTotal
TotOp = Rawmat + Util + Labor + Mntce + Overhd
TotFix = Depr + Interim + Taxes + Insur + Capch
OVERALL CAPITAL COSTS,
Total = At Bo =5C
Ad jDC = Esc * | Total
IndCst = 0.5125 * aAdjpCc
Cont = 0.2 * (AdjDC + IndCst)
TOTANN = Totop + Totfix + Sludge
GrandTotal = 1.2 * (AdjDC + IndCst)
FUEL CHARACTERISTICS
Fuel
Distillate oil
Residual oil
Coal
Wood waste (dry)
Municipal waste
Coke
Natural gas
Heat Cont.
KJ/kg
(BTU/1b)
45,300
(19,500)
43,000
(18,500)
30,200
(13,000)
18,600
(8,000)
11, 600
(5,000)
33,700
(14,500)
37,200 KJ/m°
-—~ ewe
(1,000 BTU/£t3)
S-Content
%
Excess
40
40
50
100
100
10
Lo
LEA
15
15
30
50
50
LS
FCCU gas (no CO boiler)
FCCU gas (regenerated)
CHARACTERISTICS OF "UNCONVENTIONAL" FUELS
with CO boiler
Black liquor
Coke oven gas
Refinery gas
Propane
(1)
(2)
Reference:
Calvert & Englund
Fryling (1967).
i<anie 5.9.4
Heat Content
6,210 BTU/1b
dry solids
550 BTU/£t>
14,430 BTU/1b
1,200 BTU/£t>
86,560 KJ/m°
LHV 2,322 BTU/ft>
(1984).
SO; Content
1,000 (v/v) ppm
1,350 (v/v) ppm
250 v/v ppm
2% v/v
Ref.
(1)
(1)
(2)
(2)
(2)
(2)
APPENDIX C
GLOSSARY
i. Qe, —— auf me a EE D” em mme NC > See cae of a ay
APPENDIX C:
ACID GASES
ANNUALIZED COST
BAGHOUSE
BLAST FURNACE GAS
— BF GAS
CAPITAL RECOVERY FACTOR
= CRE
COKE OVEN GAS
- CO GAS
DRY SCRUBBING
FLUE GAS
GLOSSARY
gaseous emissions which are acidic
or through chemical reactions, may
Produce acidic compounds,
e.g. SO,, HCl
the yearly cost of a system including
both direct and indirect operating
costs and an amortized portion of
the initial capital cost of the
system
a large chamber in which bag filters
used to remove particulate from a
gas stream are housed
the gas product from iron ore
smelting when hot air Passes over
coke in blast furnaces; contains
carbon dioxide, carbon monoxide,
hydrogen and nitrogen
a factor which when multiplied by
the initial capital cost yields
an annualized charge which "spreads"
the cost of initial investment over
the life of a project
2 gas produced during carbonization
Of coal to form coke
a process in which SO, and other
acid gases are removed from a gas stream
by adsorption onto a sprayed dry or
Slurry sorbent, and subsequent removal
of the sorbent bound SO, ina
downstream particulate filter
gaseous products from a combustion
process
FLUE GAS DESULPHURIZATION
= EGD
FLUE GAS RECIRCULATION
= EGR
FLUIDIZED BED
FLY ASH
FUEL NO
x
LIME
LIME INJECTION MODIFIED
BURNER
LIME SPRAY DRYER
LIMESTONE
LOW NO, BURNER
a process by which sulphur is
removed from a gas stream. The two
basic methods of desulphurization
are wet and dry scrubbing. Processes
can be further classified as either
saleable or throwaway depending
upon whether sulphur compounds are
recovered or discarded
a thermal NO, reduction strategy
whereby a portion of the flue gas
is recirculated to the air inlet
ports. The process is designed
to reduce the oxygen concentration
and temperature in the combustion
zone
an operation in which a bed of fine
particles is held in suspension
by an upward flowing gas stream
fine noncombustible particulate
matter found in combustion gases
nitrogen dioxide produced from the
reaction of fuel bound nitrogen
and oxygen in the combustion
gas
calcium oxide (CaO)
a burner which has been redesigned
to allow the direct injection of
lime at the burner port of a coal
fired boiler with the objective of
providing a precombustion method
of minimizing SO, generation
a dry scrubbing process in which
lime is used as the SO, removal
agent
calcium carbonate (Caco3)
burners designed to control the air
fuel and mix in the burner area with
the objective of retarding formation
of fuel NO,
SELECTIVE CATALYTIC a post-combustion process in which
REDUCTION NO, in a gas stream is converted to
-SCR nitrogen by reduction with ammonia
in the presence of a catalyst. The
advantage over the SNCR Process is
a less restrictive range on
operating temperatures.
SELECTIVE NON-CATALYTIC a post combustion process in which
REDUCTION NO, in a gas stream is converted
— SNCR to nitrogen by reduction with
ammonia
STAGED COMBUSTION a NO, reduction Strategy in which a
SCA Ù portion of combustion air is
injected at the burner with the
remainder introduced downstream
of the burner
THERMAL NO, nitrogen dioxide derived from the
combination of atmospheric nitrogen
and oxygen during combustion processes
carried out at high flame temperatures
WET SCRUBBER a device which uses a liquid to
clean a gas. In this report the
term refers to a device in which
SO, is removed from a gas stream
by absorption into an alkaline
solution or slurry, typically of
lime or limestone
Ve Gas war phon! pa ] i
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2 ‘boise 002 eh ha are oi = it
PEN everett ss! i a ich ri mi à
oa es 7 » +
” ,
es dote Gs soove? ey ALI à spline LED =
2 a Ar i FN ‘yo RE. L
"is ; erate Sts Vay 223" if A2
1 mAvrie mit Boge os ds i ¥Hi wast
. 1 teased’ at? A
,
¢
1
i
1: aoe nevi eh lee bp We," se 2
al pos Isa oise a Sa no ae
“ado id: cos saute aise vou:
| gosutaxsqgmrs em : D Se Jo bei 7s
= eneie? 400-8 Beik Anvoess Of JA
aAifetio 06 OS, Y PEL EL) Re |
“a, to Ylin er wae “A Vw ete
tie te . rear Bae teendt à wed
a
: + e
5 a .
La ae
ae 1
ot ad
» &
LA 2
pe 7 |
pb on. |
7 é a
oF
à de
=> <a s 47 k
à ?
¢ \#e6b
APPENDIX D
EXAMPLES OF COMPUTER PRINTOUTS
c KUGUIe UA
OTCOTuMERE BaTyaMey a Barvanws
WN BF OH WD FE
APPENDIX D - LIST OF TABLES
Lime Spray Dryer
Limestone Flue Gas Desulphurization
Caustic Absorption
Fuel Switch to Natural Gas
Low Excess Air and Staged Combustion
Selective Non-Catalytic Reduction
Selective Catalytic Reduction
TABLE D-1.1: LIME SPRAY DRYER
St Input—— Name— Output— Unit— Comment——————_—___ ———— —
Lime spray dryer with TSP removal
File :- LSD-FF.TK
13 sept. 1988
Food & Bev. -Boilers
Resid. Oil
2 Tyre number Type of fuel : Pulv. coal=1, other=2
Program calculates in metric units
2722 F Flue gas rate Nm 3/min
Flw .74393162 m 3/sec Flue gas flow rate
4.46 Q 1E6 BTU/h Thermal input
19000 H BTU/1b Heating value of fuel
Sd S 4 Sulphur content of fuel %
.93 À % Ash content of fuel
75 ELzSo2 % Efficiency of £02 removal
. 005 -C&:am ng/J Controlled TSP emisesicns
1 Uncem ng/J Uncontrolled TSP emisssions
.85 CF fraction Capacity factor
LF 1 number Labour factor
14 Air $1933 Maintenance labour rate S/man.hour
14 Sprv S1983/hr Labour zupervigicn rate
12 Dir 51983/hr Direct iabour rate
.0165 Sud 31983,kg Solid vaste disposal rats 3/kg
.018 Alime 51983/kg Lime rate 3 / xg
.02 Elec $1983/kWh Electricity rate
.96 Wtr $1983/m°3 Water rate S/m ©
gat Crf $1983 Capital recovery factor
Capital costs
TD 229137 .92 $1983 Total direct costs
Ind 76302.927 $1983 Indirect costs
Tdi 305440.85 $1983 Total direct and indirect costs
TK 449524.12 $1983 Turnkey cost
Cont 61088.169 $1983 Contingencies costs
aC 41542.446 $1983 Working capital
Operating and Maintenance costs
Totop 236972.7 $1983 Total operating costs inc. Overheads
T 166169.78 $1983 Total direct Cp. & Mtce costs
SPRV 18396 $1983 Labour Supervision costs
DL 105120 $1983 Direct labour costs
Mant 27510.599 31983 Maintenance labour costs
ELEC 717.42825 $1983 Annual Electricity cost
WTR 56.305506 $1983 Annual water cost
SW 9292.5793 $1983 Solid waste disposal costs
Lime 5076.3706 $1983 Annual lime supply costs
OH 70802.916 $1983 Overhead
Annualised costs.
Total 304060.32 $1983 Total Annualised Costs
Totann 304C060.32 $1983 Total annualized charges
CR 44952.412 $1983 Capital recovery cost
TABLE D-1.1:
4154.2446 $1983
17980.965 $1983
67087 .621 $1983
47814.171 $1983
97736.865 $1983
30082.22 $1983
53504.564 31983
15.210947
- 08316158
1.7575E-5
. 94736842
620.43897
15246.077
75.620154
.01597572
Working capital charges
Miscellaneous costs ( taxes ins. etc.)
Total Capital charges
Intermediate
Intermediate
Intermediate
Intermediate
Intermediate
Intermediate
Intermediate
Intermediate
Intermediate
intermediate
Intermediate
Intermediate
LIME SPRAY DRYER (CONT’D)
value
value
value
value
value
value
value
value
value
value
value
value
TABLE D-1.2 LIMESTONE FLUE GAS DESULPHURIZATION 4
St Input Name—— Output—— Unit Comment
Flue Gas Desulphurisation - Limestone
File :- FGDLS1.TK
13 Sept 1988
Food & Bev. Ind
Boilers-Reeid oil
95 LSE % Efficiency of L/S scrubber
ESO2 .000015 1b/MBTU Allowable SO2 rate - 1b/10°6 BTU(39*S)
WAR 4 LBCO $1988 Labour wages $/hr
18:75 LSCO $1988 Limestone cost $ / ton
15 TMGE miles Sludge trucking distance
179 Esc number Escalation factor to current date
49.5 ELCO Mills Electricity cost mills/ kWh
50 DF ft Estimated Duct run
20 BLRY yr Average boiler life remaining. =<
S .00036765 ton/hr SO2 removal rate - ton /hr
AR . 14989095 ton/hr Ash removal rate ton - /hr
MCR 200 MW Plant maximum continuous rating
Gtot 960 acfm Total actual gas flow from plant
TotG 1586.087 cfm300 Plant flue gas rate - cfm at 300 F
CF 96 number Average capacity factor
a N number Total number of trains needed
Sfetr .0003 ton/ton SO2 emission rate from plant -
OUTPUT Units Description
GrandTo 7465551.5 $1988 Grand Total of costs
TOTANN 2783090.4 $1988 Total Annual costs
Total 2164869.2 $1980 Total system cost
AdjDC 4113251.5 $1988 Adjusted direct cost (escalated to dat:
IndCst 2108041.4 $1988 Indirect cost (Int., Eng. spares etc.)
Cont 1244258.6 $1988 Contingency allowance
Conv 248602.95 $1980 Conveyor cost
Silo 32817.763 $1980 Storage Silo cost
Ball 375005.9 $1980 Ball mill cost
Stge 2.8876747 $1980 Storage tank cost
PandML 30504.279 $1980 Pumps and motors cost for L-S preparat
A 686933.78 $1980 Total L-S preparation cost
Abs 6792.2588 $1980 Absorbers cost
FandMA $1980 Fans and motors cost for absorbers onl:
FandMV 1336.2783 $1980 Fans & motors cost for abs. with ventu:
PandMA 367.97217 $1980 Pumps and motors cost
Tank 141.16174 $1980 Tank cost
Soot 571.78435 $1980 Sootblower cost
Duct 0 $1980 Ducting cost
Valv 425.0713 $1980 Valves cost |
TABLE D-1.2
LIMESTONE FLUE GAS DESULPHURIZATION (CONT’ D)
B
Clar
VacF
TandH
Fixetr
PandMS
Spond
Mob
RR
9634.5266
14564.492
311532.24
929.07348
10940.582
12196.573
1092533.7
22000.692
0
1464697 .3
124.06202
4234.1038
3316.3175
47.857644
0
213744
298622.06
44793.309
294610.49
32061.6
49161.12
940714.92
3364.1751
245805.6
343415.37
343771.61
373277.58
26129.43
298622.06
| 22396.655
1119832.7
1840258.5
2117.0519
$1980
$1980
$1980
$1980
$1980
$1980
$1980
$1980
$1980
$1980
$1988
$1988
$1988
$1988
$1983
$1988
$1988
$1988
$1988
$1988
$1988
$1988
$1988
$1988
$1988
$1988
$1988
$1988
$1988
$1988
$1988
$1988
$1988
Total SO2 scrubbing cost
Clarifiers cost
Vacuum filters cost
Tanks and mixers cost
Fixation chemical storage cost
Sludge pumps and motors cost
Sludge pond cost
Mobile equipment cost
RR siding roads etc
Total sludge handling euipment cost
Total Limestone cost
Fixation chemical cost
Total electricity cost
Total cost of water
Flue gas reheating cost
Direct labour cost
Labour and materials cost
Cost of supplies
Plant overheads
Supervisory costs
Payroll overheads
Total operating cost
Total utilities cost
Total labour cost
Total maintenance cost
Total overhead cost
Depreciation
Interim replacement costs
Cost of taxes
Cost of insurance
Capital Charges
Total fixed costs
Sludge trucking costs
TABLE D-1.3:
VARIABLE SHEET
CAUSTIC ABSORPTION
St Input—— Name—— Output— Unit— Comment— x c—
coves cc [JT =)
468300
"07e
62.4
.1428504
160
.225
. 90002
ve
n
CLR
2080
.0203
3741
nn
“ee
13.45
eles
.125
1.9
=
a)
2402 .5783
133. 47657
.25
43.24
1
5224. 4898
ft°3/hr
number
1b/z% 3
(Spee
ose CE
lost* 3
1b/£2 3
1b/£*.hr
lb/hr
lb.mol/hr
in
1b/ft°2
Caustic Absorption
June 1 1988
Paper & Allied - Process
Lime Kiln
Gage rate acin
Temperature of gas
ppm at inlet (base)
ppm at outlet (top)
thimber of Transi=r "Inits required
Mol Wt of gas (air = 20)
Density of Liguid
Liquid visessisy
Liquid vismeity at bac-
Density of gas at hase
Density of liquid az Lace
Viscosity of gas(Alr =.):312cpee @ 200)
Packing factor (= 2/8 2}
Dizzsivisy en air (Assim:
Diffus y in H20 (assum = 22-5)
Slope cf equilibrium curve
Acceleranicn due to. gravity
Operating f2cssr hr. vr
Unis ost :2 2lactricisy
Coss of water $/1000 gai
Cost/hr of operator
Cost/hr of maint=nabcs
Fraction of shif* zorked by operator
Erac*ion of shift worked by engineering
Factor for overheads
Factor to Keep ls flooding (.6 -.8)
Liquid flow at base of solum
Liquid rate lb.mole/hr at base
Plate thickness
Functicn of zeight /ft°2 of mtal
used for plate. 43.24 for 1/4 plate
Function of metal of column see below
Pump pressure: ‘lozsle press. + head
Length of piping
Cost / 100 % of pifing see below
PI
Packing type
Constant for packing typs
Constant for packing typs
Constant for packing type
Constant for packing
Constant for packing
Constant for packing
Constant for packing
NEC Ge pene ee | Sa | Sa dl se a
sdb ss tpl a Gill etfs Mf 5)
J
EUGENE
TABLE D-1.3:
a Ni
1D ETES NE
he
20
. 0808
. 468300
37823.98
1304.2752
25153 .878
4.5297663
22.648822
5.3125363
3.6616417
45.014552
1304.2752
1297 . 4377
37325 .98
123293046
- 43207905
. 06344743 !
26322159
.Q0229572
. 42302659
2.8293968
. 28381596
- 15044568
-00013045
-90010001
1.0001E-7
3.535498
2426:12€
14585.041
348.411075
9566. 4064
1.2060977
2.2995889
801.28205
25.601378
29676.517
5870.5005
11642.718
32935 .613
33.7
8910
1697. 1391
1795.68
149.64
149.64
448.92
886 .33545
11.538217
15.36931
8.230631
893.36173
2446.6171
6041.62
5644.3
117991.51
. $124.3431
1b/ft°3
ft 3/Mr
lb/hr
CAUSTIC ABSORPTION (CONT’D)
Density of gas
Gas rate at standard temp and pressure
Gas flow at base of colum
lb.mol/hr Gas rate lb.mole/hr at bage
lb/hr
ft
£t
ft
in. vater
lb/ft 2
mol/hr
mol/hr
lb/hr
ft
$1986
$1986
$1986
$1986
$1986
$1986
Liquid rate lb/nr
Overall gas tranefer unit
Height of packed tower
Diameter of column
Column pregsure drop (in. vater)
Colum pressure drop {lb/ft°2)
Gag rate lb.mle-hr
Liquid rate ib.nole/hr
Gas rate lb/hr
Intermediate factor £ir cep of colum
Superficial mage gas velocity
Useful superficial gas velocity
Colum cross sectional area at top
Intermdiate facter for base .:£ column
Superficial masz gas velocity at base
Column cross sectiznal area at base
Useful superficial gas velecity at base
Holes at inlet (base)
Moles at cutlet (top)
Mol ratio SOC, ‘air at inlet (bac=)
Hol ratio 2,25 at cutler ‘ten?
Gas ‘ransfer :mitz
Intermediate facter
Intermediate factor (alternative!
Intermediate factor
Intermediate factor (altemative)
Liquid transfer coefficient
Overall columm eight
Basic cost of column shell + grids etc.
Weight of column
Cost of laddere and platforms
Cost of packirg
Cost/ ft°3 of packing
Coss of pipe sork
Cost of pump
Cost of fan
Cost of pump motor
Cost of fan motor
Cost of motor starters
Vol. of recire.tank (appr. 2.5hr hold up)
Volume of metal in, tank
Fan HP needed
Pump HP needed
Total coset of electricity
Cost of water to scrubber
Cost of Labour
Cost of ntce.
Intermediate cost
Cost of recirculating sank
TABLE D-1.3:
CAUSTIC ABSORPTION (CONT’D)
Totcost 131142.53 51986 Total overall costs
Totopes
$1986 Total operating cost
Function of metal = fm
S/S 304
S/S 316
Monel 400
Inconel 600
Titanium
0 0 nt nt nt
— © CG 19
NOM —
TABLE D-1.4:
FUEL SWITCH TO NATURAL GAS
St Input—— Name— Output— Unit—— Coment——___
1G.
1271.5182
1635 . 2695
2166. 1572 :
2059. 1428
1328.2772
11714.901
2665 .7624
2655.7624
352.32127
17046.425
-5093.763
-115153.2
960.79104
29237."
4989.72
MBTU/hr
BTU/1b
number
fraction
S/MBTU
of st et
dscf,/MBTU
$1987
$1987
$1987
$1987
$1987
$1987
$1987
$1987
$1987
$1987
Low Excess air costs
File :- LEAOIL.TK
Fuel Switch Calculations
09 Sept. 1988
Food & Bev. - Boilers
Resid oil
Thermal input - 10°6 BTU/hr
Fuel heating value
Enter 0 1£ not LEA, 1 for LEA
Capacity factor
For socal = 1, for 511 or gas = 2.
Fuel cost 3/METU in 51991
Nitrogen content of fuel
Uncentrellad sxcese air - vos bleu
Controlled excess air - se beiew
Fuel factor
LEA = 15% excess air (oil or gas)
LEA = 35% excess air (stoker)
LEA = 39% excess air (palverised)
Non-LEA = 40% excese air (oi) or gaz)
Non-LEA = 50% sxcece air tonal)
ffac :- Natural Gas = 9000
Efac == O11°= 9393
fac :- Coal = 9260
Percent flame extension due to etaging
Flue gas flow rate for natural £22
Fluegas flowrate for oil
Eluegas flowrate for stoker boiler
Flue gas flow rate for Pulverised soal
Flue gas flow rate for FEC
Equipment cost
Installation cost
Indirect cost
Spars parts costs
Turnkey cost
LOW EXCESS AIR
Annual fuel cost
STAGED COMBUSTION (OI1)
Turnkey cost for staged combustion
Electricity cost ser annum
“STAGED COMBUSTION (Pulverised coal)
Equipment cost (pulverised coal)
Inetallation cost ( pulverised coal)
TABLE D-1.4: FUEL SWITCH TO NATURAL GAS (CONT’D)
Indp 4988.72 $1987
SPP 852.32127 $1987
ELECP 989.0496 $1987
FuelP 863.72571 $1987
FUELSCO 863.72571 $1987
Indirect costs (pulverised coal)
Spare parts (pulverised coal)
Electricity cost (pulverised coal)
Fuel costs (pulverised coal)
Fuel costs staged combustion
memes VARIABLE SHEET
Name—— Output—— Unit
St Input
TABLE D-2.1:
Uncea
Corcea
Ffac
PRCT
FLW
FLAO
FLAC
FLWP
FLAFB
Equip
Inst
Ind
SP
TK
FUEL
TKSC
ELEC
Equipp
Instp
Indp
30
29060.
24927.
33261
31789.
24147.
17004.
772
493
3973
101
246
439
4582.3351
4582.3351
1308.4555
26169.109
-170362.7
455788.61
17466.578
40194.
15102:
15102:
MBTU/hr
BTU/1b
number
fraction
$/HBTU
d
scf,/MBTU
it
acfn
acin
actn
acfn
acfm
$1987
$1987
$1987
$1987
$1987
$1987
$1987
$1987
$1987
$1987
31987
LOW EXCESS AIR AND STAGED COMBUSTION
Low Excegs air costs
File :- LEAOIL.TK
09 Sept. 1983
Metal Fab- Boilers
Resid. oil
Thermal input - 10°6 BTU/hr
Fuel heating value
Enter 0 if not LEA,
Capacity factor
Foricoal = 1%, £Zor ot] or gas = 2.
Fuel cost $5/MBTU in 5:981
Nitrogen content of fuel
Uncontrolled <z5esz air - ges below
Controlled =“c¢s2 air - see below
1 for LEA
Fuel factor
LEA = 15% excess air (ofl or gas)
LEA = 35% excess air (stoker)
LEA = 30% excess air (pulverised)
Non-LEA = 40% excess air (oil or gas)
Non-LiA = 59% excees air (<oal)
Brac =CNasural Gas = 9000
Ney 9 Or LOB 90295
Sac: Soak = 925C
percent Zlame #xtenzion due to staging
Flue gas flow rate for natural gas
Fluegas flowrate for oil
Fluegas flowrate for stoker boiler
Flue gas flow rate for pulverised coal
Flue gas flow rate for FBC
Equipment cost
Installation cost
Indirect cost
Spare parts costs
Turnkey cost
LOW EXCESS AIR
Annual fuel sost
STAGED COMBUSTION (OI1)
Turnkey cost for staged combustion
Electricity cost per annum
“STAGED COMBUSTION (Pulverised coal)
Equipment cost (pulyerised coal)
TInetallation cost ( pulverised coal)
indirect costs (pulverized coal)
TABLE D-2.1:
SPP 1308.4555 $1987
ELECP 17980.301 $1987
FuelP 28887.614 $1987
FUELSCO 28887.614 $1987
LOW EXCESS AIR AND STAGED COMBUSTION (CONT’D)
Spare parts (pulverised coal)
Electricity cost (pulverised coal)
Fuel costs (pulverised coal)
Fuel costs staged combustion
TABLE D-2.2: SELECTIVE NON-CATALYTIC REDUCTION
VARIABLE SHEET -excex:
St Input Name—— Output—— Unit Comment
NOx Removal - SNCR.
09 Sept. 1988
Metal & Fab- Boilers
Resid oil
16270 Qn Ncfm Flue gas volume Ncfn
175 aly C Flue gas temperature
Q 26699.487 acfm Flue gas flou rate - acfm
Capezst 705220.91 $1987 Capital cost
Opcost 185827.44 $1987 Total Operating costs
Totlab 13850.493 31987 Labour costs
Elpwr 55401.97 $1987 Electricity cost
Mtcs 11542.077 $1987 Maintenance cost
Anmcst 43859.893 $1987 Ammonia cost
Fixest 49630.932 $1987 Fixed operating cost
279 san K Normal Temperatura
TABLE D-2.3:
St Input
16270
175
Name—— Output—— Unit
Qn
T
Q
Capest
Opcost
Totlab
Elper
mice
Annest
Fixes*%
15023.59
1890002.2
465561.92
27011.057
37815.479
2233059
J1F641.52
95696.315
Ncfm
Cc
acfm
$1987
$1987
$1987
51937
$1937
$1937
31987
K
Comment
SELECTIVE CATALYTIC REDUCTION
NOx Removal - SCR
09 Sept
Metal F
Resid o
Flue ga
Flue ga
Flue ga
Capital
1988
ab- boilers
il
s volume Ncfn
¢ temperature
s flow rate - acfn
cost
Total Operating costs
Labour costz
Electricity cogs
Maintenance cost
Ammonia
cost
Fixed operating cost
Normal
temperature
COUNTDOWN ACID RAIN
FUTURE ABATEMENT STRATEGIES
PHASE III
"Abatement Strategy Assessment"
Prepared by:
ECOLOGISTICS LIMITED
Waterloo, Ontario
Prepared for:
SENES CONSULTANTS LTD.
Richmond Hill, Ontario
rAges 3 ai IVARCREET (He a
contingent BRIE SATE.
0? logt e tt —_ S+ttut mi: (oe
TL rit Va | Me
de -e TETE v
7 ¢ Pe è a E
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n > at ae 7
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HTML) EAU
cea? ootanw
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TE EVA TAUENUN ELA
do ANH hou
DISCLAIMER
The conclusions, opinions and recommendations expressed in this
report are those of the consultant and do not necessarily represent
the views of the Ontario Ministry of the Environment. In addition,
the consultant is solely responsible for the accuracy of data and
estimates presented in this report.
TABLE OF CONTENTS
2.0 METHODOLOGY
3.0 PREPARATION OF DATA INPUTS
LIST OF FIGURES
Development of an Abatement Cost Curve
Development of a Convex Abatement Cost Curve
Aggregate Abatement Cost Curve
Flow Chart for "COMPARE AND CHECK" Procedure
12
18
Table
Table
Table
Table
Table
Table
Table
Table
Table
Table
Table
Table
Table
LIST OF TABLES
Sector and Sources Considered for Abatement Strategies
Base Case Emissions Status Quo Scenario - Option 1
SO, Emission Control Cost Data
Emission Control Cost Data
Primary SO, Abatement Strategy Scenarios
SO. Abatement Strategies for 30%, 10% and 50% Emission
ctions
SO, Abatement Strategies with INC Not Meeting 1994
Regulated Reductions
SO, Abatement Strategies with Hydro Not Meeting 1994
Regulated Reductions
SO, Equity-Based Abatement Strategy
Primary NO, Abatement Strategy Scenarios
Abatement Strategies for 30%, 10% and 50% Emission
ctions
Abatement Strategies with Hydro Not Meeting 1994
Regulated Reductions
NO, Equity-Based Abatement Strategy
st
FORWARD
This report presents a study of SO, and NO; emission
sources in Ontario and proposed emission control strategies
to achieve Ontario's commitment for SO, and NO, reductions
after 1993.
The report consists of a summary document
supported by three appendices.
Summar
Appendix 1
Appendix 2
Appendix 3
This Document
The summary document describes the
findings of 2 phases of the study and
draws conclusions on abatement
strategies.
The Phase I Report sets out a 1985
base year emission inventory for SO,
and NO, examines past trends, and
outlines five basic future scenarios.
The Phase II Report identifies the
costs of reducing SO, and NO,
emissions using alternative emission
targets identified in the Phase I
Report.
The Phase III Report develops
alternative cost-effectiveness
abatement strategies that achieve
pre-specified aggregate emission
targets. The strategies are based on
control technologies, described in
Phase II, that are presently
considered suitable for SO, and NO,
emission control. The computer model
developed for the foregoing work is
described.
This document describes Phase III,
Appendix 3.
PHASE III
EXECUTIVE SUMMARY
abatement strategies.
Emission controls for the following sources were used in the analysis:
SECTOR or SOURCE So,
SCENARTOS SCENARTOS
TT SCERIOS SCENARIO
Primary Metals Yes No
Food and Beverages Yes Yes
Rubber and Plastics No Yes
Leather, Textile and Clothing Yes Yes
Paper and Allied Products Yes Yes
Metal Fabrication Machinery Industries Yes Yes
Transportation Equipment Industries Yes Yes
Non-Metallic Mineral Products Yes Yes
Chemical and Petroleum Products Yes Yes
Other Groups Yes Yes
INCO Yes No
Ontario Hydro Yes Yes
Falconbridge Yes No
Algoma Yes No
Mobile Sources No Yes
Note: No, emissions for Falconbridge and Algoma were judged not to be
significant for purposes of this study.
These data were incorporated into a computer spreadsheet model designed to
identify the least cost combination of control options that will achieve a
pre-specified level of Provincial emission reductio - Only existing
iv
The starting point in formulating alternative abatement strategies was
assumed to be the level of provincial emissions that will remain in 1994
after the implementation of emission controls mandated by Regulations
covering the major point sources: INO, Ontario Hydro, Algoma and
Falconbridge.
Only two or three discrete control technologies were considered for each
major point source or sector, and no interpolations of the data were made
to allow for emission control reduction levels falling between the levels
corresponding to these technologies. Due to the discrete nature of the
emission control data, aggregate emission reduction levels developed with
the model may exceed or be lower than target reduction levels for specific
scenarios.
Summary results from the analysis are provided in Tables 1 and 2.
Emission control costs and resulting emission reductions in these tables
represent province-wide aggregates covering all controllable sources.
Emission control cost estimates in these tables do not include those costs
that must be incurred to satisfy the 1994 emission targets mandated by the
regulations for INO, Hydro, Falconbridge and Algoma Steel at Wawa.
NO, Seulseone are doniret en DNS POS ee eee
ject to Federal regulation. Federally mandated controls for new
vehicles can readily make up for any failure on the part of Ontario Hydro
to achieve its 1994 Regulation levels for NO,. The maximum potential
emission reduction is 267,000 tonnes at a present value cost of
$6,476 M. Mobile source controls account for 64% of this reduction.
SO, emissions on the other hand are dominated by the large point
sources. For example, the scenario involving a failure by INO to meet
1994 regulated SO, targets causes all other sources to be pushed to
maximim control levels. Target emission reductions for this scenario
exceed the achievable reductions by 118,000 tonnes.
Abatement costs rise rapidly with the degree of emission reduction.
Moving from the 10% reduction level to the 50% reduction level for either
SO, or (a five-fold increase), causes costs in both cases to
increase thirty -fold in present value terms.
It can be concluded that emission reductions at INC© are critical if
Ontario is to meet its SO, emission reduction commitments at a
reasonable cost. If INC does not reduce its emissions to 1994 target
levels, then the aggregate provincial targets may not be achievable even
if all other sources implement their maximm SO, control levels.
TABLE 1:
SUMMARY OF 505 ABATEMENT STRATEGIES
EMISSION CONTROL
ABATEMENT EMISSION CONTROL COSTS (M 1987 eee (1000’s_ TONNES/YR)
STRATEGY OPERATING CAPITAL TARGET MODELED
SCENARIO 1 rat REDUCTION 2 REDUCTION >
10% Reduction $12 $ 43 $ 159 90 103
30% Reduction S$ 63 $ 299 S$ 887 274 278
50% Reduction $342 $2,146 $5,338 450 445
Reduction to 1994 $307 $2,062 $4,933 430 319
target level,
INC remains at
1985 emission levels
Reduction to 1994 $ 57 $ 390 S927: 215 208
target level,
INO achieves 1/2
of its 1994 target
reduction
Reduction to 1994 $ 26 S 76 S 321 162 156
target level,
Hydro remains at
1985 emission levels
Reduction to 1994 $ 6 $ 26 $ 78 81 TF1
target level,
Hydro achieves 1/2
of its 1994 target
reduction
NOTES :
1. Percent reduction relates to 1994 base case emissions after Regulations are
met, which are 900,885 tonnes/yr. This figure exceeds the 1994 MOE
objective (885, 000 tonnes) because it assumes that Algoma and Falconbridge will
increase emissions to maximm acceptable levels.
2. “Target Reduction" is the percent reduction referenced in colum 1 or the
shortfall arising as a result of any failure to meet 1994 Regulations.
3. Discrepancies between target and modeled emission reduction levels are due
to discrete nature of the control options.
4. All sectors are at maximm emission control levels.
vi
TABLE 2: SUMMARY OF NO, ABATEMENT STRATEGIES
EMISSION CONTROL
ABATEMENT EMISSION CONTROL COSTS (M 1987 $) (1000's TONNES/YR)
STRATEGY OPERATING CAPITAL PRESENT TARGET MODELED
SCENARTO 1 VALUE REDUCTION 2 REDUCTION >
10% Reduction $ 15 Sad S$ 216 58 36
30% Reduction $ 15 $1,051 $1,190 173 189
50% Reduction $347 $3,236 $6,476 289 267 4
Reduction to 1994 Sune Sie 024: cn. HA 33 149 >
target level with
Hydro remaining at
1985 emission levels
NOTES :
Percent reduction relates to base case emissions after Regulations are met,
which are 578,135 tonnes/yr.
"Target Reduction" is the percent reduction referenced in colum 1 or the
shortfall arising as a result of any failure to meet 1994 Regulations.
Discrepancies between target and modeled emission reduction levels are due to
discrete nature of the control options.
All sectors are at maximm emission control levels.
A reduction of 149,000 tonnes NO, is achieved by means of Federally
mandated controls on mobile sources. Only a portion of these are actually
required to meet the 1994 Provincial emission reduction target for NO,.
Costs are for 3-way catalytic converters on mobile sources. Only capital cost
data were provided for this option (See Scenario 12 in Table 4.8 and
Appendix D of this report).
vii
ACKNOWLEDGEMENTS
The project study team included:
M. Fortin Ecologistics Limited
E.A. McBean University of Waterloo
S. Tang Ecologistics Limited
Senes Consultants Ltd. provided data used in the study and reviewed draft
reports. P. Complin, A. Deshpande, J. Donnan, and G. Endicott with the
Ontario Ministry of the Environment, also provided careful and thorough
reviews of draft reports.
viii
1.0 INTRODUCTION
1.1 Background
Extensive information has been developed regarding the causes and effects
of acid rain and the technologies available for reducing the emissions
responsible for acid rain. However, this knowledge by itself does not
solve the policy- ’s problem of determining the emission reduction
levels required at individual sources to achieve overall environmental
objectives. À
Many approaches exist to determine alternative abatement strategies for
acid rain, including, an emission-driven approach, a deposition-targeted
approach and a cost-effective or least-cost targeted approach [McBean et
al, 1985]. The latter two approaches relate the impact of controls at
emissions sources to sensitive receptor areas. A linear programing
screening model was developed by McBean et al [1985] that utilized a
source/receptor linkage. It reduces the total number of abatement
scenarios to be considered by identifying those strategies which are both
efficient in terms of minimizing control costs, and effective in terms of
achieving the desired deposition objectives.
This screening model provided valuable technical support in early
discussions of national and trans-national abatement requirements by
addressing the problem at a continental scale. Its particular strength
lay in its ability to evaluate emission control requirements at the
provincial/state level and at the national level.
The broad scale of this model however, had two major implications: first,
only major sources could readily be accommodated within the model
structure, and second, detailed information was required related to source
inventories, abatement cost functions and long-range transport
relationships. As the provinces’ acid-rain control policy evolves, it
must focus increasingly, and in more detail, on the issues of how and
where to control emissions. A larger number of provincial sources must be
considered and greater attention must be paid to the cost implications of
alternative abatement strategies.
In keeping with these changing policy interests, the analytic approach
employed must also change. To this end, the Ministry of the Environment
has commissioned a study entitled "Countdown Acid Rain Future Abatement
Strategies". The first two Phases of this study produced an updated
inventory of emission control data describing the removal efficiencies and
associated costs of alternative control technologies for major point
sources and for industrial sectors which are also Significant in
aggregate. A parallel study by Maclaren Plansearch Ltd. (1988) produced
NO,, emission reduction and control cost data for mobile sources. The
third Phase, which is the subject of this report, incorporates this data
into an analytic framework for developing and evaluating alternative acid
rain abatement strategies.
1.2 Objectives of the Study
The objective of this third phase of the study was to develop alternative,
cost-effective abatement strategies that achieve pre-specified aggregate
emission targets. This objective entailed three primary tasks:
1) development of a simple and efficient approach to the analysis of
cost-effective acid-rain abatement strategies;
2) implementation of the approach as a computer model;
3) application of the model to a set of predetermined policy scenarios.
1.3 Scope
À number of features defined the Scope of this study, namely:
— only Ontario sources were to be considered;
1.4
the analysis addressed both SO, and NO, emission reduction
targets;
the impact of emission reductions on receptor deposition were not
addressed;
emission reductions considered here move the Province beyond those
emission reductions already required for 1994 by Regulations imposed
on Ontario Hydro, INOO, Falconbridge and Algama ;
only existing sources were to be considered (though the approach
should provide the opportunity to add new sources in subsequent
analyses) ;
emission controls are assumed to be implemented by 1994;
emission control cost data of a generic nature were used, and, with
the exception of those four major sources cited above, emission
sources were aggregated by sector.
Product
The principal end product of this phase of the "Countdown" study is a set
of abatement scenarios that evaluate the implication of future uncertainty
in the emission control performance of the four regulated sources. In
particular, an evaluation is made of the SO; and NO,, emission controls
required to move beyond the 1994 Regulation levels and of how these
requirements are affected if the 1994 Regulation levels are not achieved.
2.0 METHODOLOGY
2.1 Overview
Cost-effectiveness provides the underlying approach to strategy
development in this study. Each abatement strategy is based on a scenario
comprising:
- an emission reduction target,
- assumptions regarding the interest rate, the planning horizon and
starting or base case emission levels,
- constraints requiring that certain technologies or sectors be forced
into the strategy or conversely be left out.
A cost-effective abatement strategy is defined as one that conforms to the
requirements of a scenario while minimizing the total abatement cost to
the polluters.
Various approaches can be used to identify cost-effective abatement
strategies from among the complete set of strategies that would fulfill
the requirements of a scenario. The simplest involves generating every
conceivable strategy and then picking the least expensive one. This may
be feasible in very limited cases involving only a few control options,
but is not otherwise practical. At the other end of the spectrum, there
are sophisticated decision algorithms such as linear programming which go
further than required for this study.
The approach that was most reasonable, given the nature of the study
entailed an analysis of the incremental or marginal costs associated with
the alternative control technologies available at each source or in each
- sector. In essence, this approach simply requires that technologies be
sorted in order of increasing marginal cost; then, for any given scenario,
options must be selected progressively from this list until the aggregate
emission target is achieved.
This chapter goes on to describe how the marginal cost approach is
applied, moving progressively through the topics of total cost estimation,
abatement cost function development, strategy development and the
generation of scenarios. A numerical example is provided in the last
section to further clarify the discussion. The computer model developed
to implement this approach is documented in Appendix C.
Zee Total Costs
Abatement costs include both the capital costs associated with installing
control equipment and the recurrent annual operating costs for running and
maintaining that equipment. In this application, the cost data correspond
to distinct and mutually exclusive control options. Where two discrete
technologies, such as a fuel adjustment and a flue gas scrubbing system
can be used separately or in combination, the combination is therefore
identified as a third control option.
In order to place all cost data - both near-term capital expenditures and
future operating costs - on the same footing for purposes of comparison it
is necessary to express these in terms of dollar values in a single
reference year. A present value calculation is used to do this. This
calculation, in effect, expresses all capital and future operating costs
in terms of a capital fund that, if invested at prevailing market interest
rates in the first year of implementation of a control technology, would
completely finance that technology over the full planning horizon.*
* By assuming a market interest rate measured net of inflation, we are
measuring the cost of capital funds in the private sector. This cost
may vary from the social cost of capital funds due to taxation and
other factors that affect the market for capital funds. The analytic
approach described below enables the user to select market or social
values for the interest rate.
Present values are calculated using the following equation:
PV = CC + 0C,(1 + R) 1 + OC,(1 + R) 2 + ... + OC (1 + R) 7
SAT)
where
Present Value of Total Costs;
= Initial Capital Cost:
Operating Cost in year t;
= Real Interest Rate;
= time horizon in years.
ROUE
Il
Market interest rates incorporate a factor accounting for the impact of
inflation on the value of savings.
The real interest rate is measured net of this inflation factor and is
calculated as follows:
R= ((1 + i)/(1 + I))-1
.- (2)
where i = Nominal or Market Interest Rate:
Inflation Rate.
253 Abatement Cost Functions
Once abatement cost data are expressed in present value forn, it is
necessary to develop an abatement cost function for each discrete source
or sector. An abatement cost function describes the relationship between
total cost and removal efficiency over a range of removal efficiencies.
The feature that distinguishes the abatement cost function from a simple
schedule of all available control technologies is that any inefficient
control technologies are omitted from the abatement cost function. These
are technologies that are technically inferior because they offer a lower
removal efficiency at a higher total cost than alternative efficient
technologies (control technology 1 in Figure 2.1). Thus, when total costs
are plotted against removal efficiencies for all control technologies for
a given source or sector, the abatement cost function comprises the: lower
envelope of points representing the least cost alternatives - shown as
control technologies 2, 3, and 4 in Figure 2.1.
The marginal cost for a control technology on the abatement cost function
is defined as the increase in cost divided by the increase in emission
removals with increases measured relative to the next lower option. In
other words, it is the slope of the line segment joining a data point to
the next lower data point, or conversely it is the unit cost or average
cost per tonne removed defined over that line segment (see Figure 2.1).
In calculating marginal costs, the emission reductions must be expressed
in present value terms in order to be commensurate with the present value
cost data. To do otherwise (i.e. to divide by the simple sum of emission
removals over time) would entail mixing values with different time scales
and would produce meaningless unit cost data.
The total cost will always increase as one moves up an abatement cost
function, but the marginal cost may increase or decrease depending on
whether the slope of the function is increasing (a convex function) or
decreasing (a concave function). Typically, however, marginal costs
increase as removal efficiency increases for a given source since it is
usually more difficult, and consequently more costly, to remove increasing
amounts of a contaminant from an emission stream.
For reasons that will be developed in the next section, the use of an
algorithm based on marginal costs necessitates that all abatement cost
functions be either linear or convex. Thus, where a section of an
abatement cost function was found to be concave, the offending data point
was dropped and the line segment then connected to the next data point in
the function as with control technology 3 in Figure 2.2.
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2.4 Strategy Development
The abatement cost functions are the primary data inputs used in
developing an abatement strategy. The other prerequisite is the scenario
Which stipulates conditions to be satisfied by the strategy and
assumptions that modify the input data (see Section LES 1 I
The next step in the analysis essentially involves the development of an
aggregate abatement cost function for the entire province comprising all
of the individual source and sector control options sorted in order of
increasing marginal cost. Once sorted, the aggregate function is derived
as a schedule or plot of cumulative control option costs against
cumulative emission reductions. The values to be amulated are the
incremental costs and incremental emission reductions used to define
marginal costs for each control option.
Since control options are first sorted based on increasing marginal cost,
the slope of the aggregate function mist increase as total emission
reduction increases. The function is therefore also convex.
The abatement strategy is determined by selecting the discrete data point
on the aggregate abatement cost function that most closely matches the
target emission reduction for the scenario in question. (Since only
discrete control options are considered here, a continuous interpolation
between data points to provide an exact match to the target is not made.)
All control options represented by data points lying between a zero
reduction level and the selected control option on the aggregate function
mast then be evaluated in order to determine the emission reduction level
required for each source or sector. Any source or sector not represented
in this set of control options is obviously excluded from the strategy.
The analysis of included sources or sectors relies critically on the
convexity of their individual abatement cost functions. Due to this
convexity, data points from each of these individual curves will appear in
10
the aggregate abatement cost function in the same order as is found in the
individual curve (although individual data points may be separated by data
points drawn from other sources or sectors). This is the case because the
aggregate curve is also convex.
Thus, if only one point is found for a source or sector in the selected
set of data points, it mst be the first or lowest level control option
for that source or sector. If two or more data points for a single source
or sector occur in the selected set, however, these will represent
consecutive control options starting with the first. Since these are
mutually exclusive (see Section 2.3) it is the last or highest level
option that represents the required removal level for that source or
sector (see Figure 2.3).
2.5 Generation of Scenarios
As noted in Section 2.1, factors that define a scenario are:
- the aggregate emission reduction target,
- assumptions regarding interest and inflation rates, the planning
horizon and the base case emissions, and
- constraints related to controls for specific sources or sectors.
When the aggregate emission reduction target is increased, new emission
controls will be required. Depending on the size of the increase, changes
in removal levels may be required for all sources and sectors or for only
some of them. If the latter is the case, then the control technologies
and consequently the marginal costs will change only for those sources and
sectors for which higher removal levels are prescribed in the new
scenario.
When financial assumptions or base case emissions are changed, the costs
for individual control options change, in the former case due to a change
in the present value calculation and in the latter case as a result of a
all
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12
modelling assumption that operating and maintenance costs vary in direct
proportion to base case emission levels. These Changes in costs can cause
the abatement cost function for a source or sector to become concave.
Results mst therefore be reviewed carefully to identify problems with
concavity.
It is also possible to conduct a "what if" analysis focussing on
sector-specific contingencies. This entails pre-specifying a level of
control for a given source or sector. The options here include:
— excluding a specific source, sector or control option (causing data
points to be omitted when defining the aggregate abatement cost
function) ;
- forcing certain control options into the strategy (Corresponding SO,
or NO,, removals are subtracted from the provincial removal target and
the selection of remaining control options is based on this net figure) ;
— assuming that 1994 Regulatory emission reductions are not achieved by
the big four sources (the shortfall is manually added to the target and
must be made up by removals from other sectors).
2.6 Sample Calculations
A two sector example is used for Purposes of illustration here.
Base Case emissions for sector A and sector B are 2,099 Tonnes/yr and
14,821 Tonnes/yr, respectively and the data points for their abatement
cost functions are:
13
Sector A
Control Emission Emission Capital Cost Operating Cost
Option (Tonnes/yr) Reduction (million $) (million $)
Ne 7
BCE 2,099 0% 0 0
SNCR 860 59% $13.90 S3-10
SCR 335 84% $65.20 $11.46
Sector B
<<.
Control Emission Percent Capital Cost Operation Cost
Option (Tonnes/yr) Reduction (million $) (million $)
RE ee eee
BCE 14,821 0 0 0
SC 13,627 8 S "8:30 SH1530
SNCR 6,369 57 $ 76.50 $16.80
SCR 2,814 81 $273.40 $48.08
where: BCE = Base Case Emission for the Sector;
SC = Stage Combustion-Boiler;
SNCR = Selective Non-Catalytic Reduction-All Streams:
SCR = Selective Catalytic Reduction-All Streams.
The incremental or discrete contaminant removal for control option "A"
are calculated as:
DCR; = (RED; X BCE) - DCR;_,
where: DCR; = Discrete Contaminant Removal for jth technology ;
RED; = Percent Reduction for ith technology.
14
The marginal costs are calculated by employing the following equation:
MC; = (EV;- PV;_3)/ (DCR; Xx PF)
where MC; = Marginal Cost for it? technology;
j= Present Value of cost for jth technology;
PV;_, = Present Value of costs for i-1t technology;
DCR; = Discrete Contaminant Removal for i technology;
PF = Present Value factor.
(The denominator in this equation is the present value of emission
removals as described on page 7 above.)
The results for industrial sectors A and B are given as follows:
Industrial Sector A
eee
Control Present Value Discrete Removal Marginal Cost
Option (code) (million $) (Tomnes/yr) ($/Tonne)
8 —————— ee ee ae
BCE (A1) 0 0 ()
SNCR (A2) $ 42.00 1238 S3,170
SCR (A3) $172.27 525 $26,400
—_—_--eo
Industrial Sector B
— ee eee eS ee eee
Technologies Present Value Discrete Removal Marginal Cost
(million $) (Tonnes/yr) ($/Tonne)
SN CU SP Ee
BCE (B1) 0 0 0
sc (B2) $ 20.44 1185 $ 1,850
SNCR (B3) $233.42 7258 $ 3,140
SCR (B4) $722.48 3555 $14,700
eee
A nominal interest rate of 13%, an inflation rate of 6% and a time horizon
of 15 years were used in the above calculations.
15
The next step involves ranking the marginal costs from both sectors in
ascending order and summing the discrete removals:
Sorted Increasing Cumulative
Control Marginal Cost Discrete Removal Removals
Options ($/Tonnes) (Tomnes/yr) (Tonnes/yr)
eS
Al 0 0 0
Bl 0 | 0 0
B2 $ 1,850 1,185 1,185
B3 $ 3,140 7,258 8,443
A2 $3,170 1,238 9,681
B4 $14,700 3,555 13,236
A3 $26,400 525 13% 761
—————————————————]—_]_]_]__—_—_—_—_
The target removal (TR = 9500 Tonnes/yr) level is compared with the
cumulative removal using a "compare and check" procedure which is
summarized in a flow chart in Figure 2.4. The results are given as
follows:
Cummilative
Control Removals (S;)Is Summation Is abs(S;~TR) Model
Options (Tonnes/yr) less than TR? >abs (S;_,—TR) ? Selection
sd 15.
Al 0 YES NA IN
Bl 0 YES NA IN
B2 1,185 YES NA IN
B3 8,443 YES YES IN
A2 9,681 NO NO IN
B4 13,236 STOP = ==
A3 13761 — — —
where: abs (S;-TR) = absolute value of summation i - target removal;
abs (S; ,1-TR) = absolute value of summation i-1 - target removal;
NA Not Applicable.
16
Since only the technology with the highest removal efficiency in each
industrial sector is reported for that sector (see Section 2.4), the final
choice is:
Control Enission Model Is % reduction Final
Options Reduction Selection highest in the sector Choice
RS à RES
Al 0 IN NO —
Bl 0 IN NO —
B2 8% IN NO ==
B3 57% IN YES IN
A2 59% IN YES IN
B4 81% == = —
A3 84% = = —=
The abatement strategy includes technology B3 [SCR] for sector B and
technology A2 [SCR] for sector A based on the target removal of 9500
Tonnes/year. The aggregate emission removal level is equal to 9681 tonnes
per year (0 + 0 + 1185 + 7258 + 1238 = 9681).
ay
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3.0 PREPARATION OF DATA INPUTS |
3751 Base Case Emissions
There are ten major industrial sectors and four individual corporations
that are identified as significant sources of SO, and NO, emissions
(Table 3.1). Primary data describing base case emission levels, as well
as the costs and removal efficiencies of alternative control technologies
were generated by Senes Consultants Limited in Phase II of this study.
(See "Phase II - Countdown Acid Rain Future Abatement Strategies", Senes,
1989(b) .)
Detailed data tables for industrial sectors and major sources are provided
in the Phase I and II reports by Senes. Data extracted from this report
for Phase III work included emission levels, control technologies, removal
efficiencies and their capital and operating costs. Base case emissions
are indicated in Table 3.2.
Table 3.1 Sector and Sources Considered for Abatement Strategies
INCLUDED IN INCIUDED IN
CODE SECTOR or SOURCE SO, NOy
SCENARTOS SCENARTOS
A Primary Metals Yes No
B Food and Beverages Yes Yes
C Rubber and Plastics No Yes
D Leather, Textile and Clothing Yes Yes
E Paper and Allied Products Yes Yes
F Metal Fabrication Machinery Industries Yes Yes
G Transportation Equipment Industries Yes Yes
H Non-Metallic Mineral Products Yes Yes
I Chemical and Petroleum Products Yes Yes
J Other Groups Yes Yes
K INCO Yes No
L Ontario Hydro Yes Yes
M Falconbridge Yes No
N Algoma Yes No
O Mobile Sources No Yes
Note: No, emissions for Falconbridge and Algoma were not considered to
be significant for purposes of this study.
19
TABLE 3.2
BASE CASE EMISSIONS
STATUS QUO SCENARIO - OPTION 1
SOURCE OR SECTOR SO, NO,
(tonnes/year) (tonnes/year)
INCO 265,000 4,900
Ontario Hydro 175,000 61,333 2
Algoma Ore Division (Wawa) 125,000 260
Falconbridge Nickel Mines 100,000 20
Industrial Sectors:
Food/Beverage/Tobacco 1,647 2,881
Rubber Plastics 185 386
Leather/Textile/Clothing 7,359 1,254
Paper Products & Allied Industries 30,621 12,179
Primary Metals 14,219 672
Metal Fabricating/Machinery Industries 29,038 14,662
Transportation Equipment Industries 1,801 2,099
Non-Metallic Mineral Products 20,249 9,756
Chemical & Petroleum Products 69,902 27,892
Misc. Manufacturing 192 267
Other Major Groups 5,318 4,250
Industry Sub Total 845,531 142,811
Area Sources:
Metro Toronto area 18,603 101,812
Niagara-Hamilton-Toronto Corridor 24,154 202,954
Balance of Ontario 6,067 125,124
Marine Sources 6,530 5,434
Area Source Sub Total 55,354 435,324
TOTAL 900,885 578,135
Source: Senes, 1989(a). "Phase I Countdown Acid Rain Future Abatement
Strategies" (Table 8).
Note: 1. Equivalent to 40,000 tonnes of NO,/year as per Regulation
281/87
20
It should be noted that Ontario will meet SO; emission limits of 885,000
tonnes per year in 1994. The higher value of 900,885 tonnes per year
arises from the implicit assumption that Algoma Steel Corp. (Wawa) and
Falconbridge will increase emissions to their maximm acceptable levels.
302 Emission Control Costs
Data for the following emission control options are presented by Senes
(1989 (b) ) :
SO, Control technologies
- fuel oil cleaning (fuel desulfurization)
- fuel switching to natural gas
- lime spray dryer treatment of emissions
- limestone flue gas desulfurization (FGD) of emissions
NO, Control technologies
- low excess air feed to burners
- staged combustion in burners
- selective non-catalytic reduction of emissions
- selective catalytic reduction of emissions
- catalytic converters (mobile sources only)
Treatment processes for emissions are applied to boiler emissions, process
emissions or both.
Senes data for fuel oil cleaning and for fuel switching to natural gas
required some further refinement prior to being used in the analysis of
abatement strategies.
Desulfurization of fuel oil reduces SO; emissions from boilers while
increasing emissions of the petroleum refining sector. Data describing
desulfurization were provided by Senes in aggregate form for the
21
petroleum-refining industry. These data were converted into average costs
per net kilogram of sulfur removed and then distributed across the
individual sources and sectors using desulfurized fuel oil. In so doing,
it was assumed that desulfurized fuel oil could be supplied by the
petroleum industry in quantities corresponding to the demand from
individual manufacturing sectors and that an all or nothing conversion to
desulfurization by the refinery industry was not necessary. Two data
points were created with the desulfurization data, one for fuel
desulfurization alone and one for fuel desulfurization combined with
limestone flue gas desulfurization. Details of the fuel desulfurization
calculations are provided in Appendix B3.
In evaluating fuel switching from fuel oil to natural gas, Senes assumed
that there would be no bottle necks in the capacity to supply additional
natural gas. Given the short time frame to implementation by 1994, it is
likely that conversion will only be feasible along existing gas
pipelines. In the absence of specific information regarding access of
establishments in each sector or source to natural gas supply lines, it
was assumed that conversion to natural gas would be limited to 10% of the
maximm conceivable level (i.e. complete conversion).
In the case of NO, control options, the low excess air option is
estimated to actually reduce boiler operating and maintenance costs. The
cost savings are sufficient to suggest overall cost savings in net present
value terms after accounting for capital costs; however, removal
efficiencies are relatively modest with this option. In light of these
low removal efficiencies and in order to be conservative in the
assumptions regarding control costs, the low excess air option was not
incorporated into the final abatement cost functions used in the model.
NO,, controls for mobile sources, provided by Maclaren Plansearch (1988),
included two options, (1) a 3-way catalytic converter required on new cars
by federal regulation, and (2) a more effecient catalytic converter that
22
exceeds federal standards. Assumptions and calculations made to generate
control option data from the Maclaren results in the format required for
this study are documented in Appendix D.
Final data for S0, and NO, are provided in Tables 3.3 and 3.4. These
data were plotted and analyzed as discussed in Section 2.3 in order to
generate abatement cost functions. Control technologies included in the
abatement cost function are noted in Tables 3.3 and 3.4.
23
TABLE 3.3: SO2 EMISSION CONTROL COST DATA
Cost Emissions Emission Capital Operating Control
Source or Sector Function of S02 Reduction Costs Costs Technology
Code (T/yr) ---- (M 1987 $) ----- Code
PRIMARY METALS Al 14,129 0% $0.00 $0.00 0
A2 725 95% $2.10 $7.20 4
FOOD & BEVERAGE B1 1,421 0% $0.00 $0.00 0
out 1,401 1% $0.40 $0.20 2
out 1,364 4% $0.00 $0.46 6
B2 1,322 TX $0.06 $0.00 1
out 614 57% $161.20 $50.10 5
b3 570 60% $11.90 $5.20 3
bé 398 72% $161.20 $7.52 7
TEXTILE INDUSTRIES D1 7,359 0% $0.00 $0.00 0
D2 7,072 4% $0.03 $0.00 1
D3 5,004 32% $0.00 $1.31 6
out 4,894 33% $9.20 $3.10 3
out 4,621 37% $90.80 $28.20 5
out 4,489 39% $90.80 $3.38 7
D4 3,569 52% $8.10 $1.88 2
PAPER & ALLIED PRODUCTS E1 30,516 0% $0.00 $0.00 0
E2 29,143 5% $0.06 $0.00 1
out 22,673 26% $104.40 $32.10 4
out 18,828 38% $16.60 $5.40 3
out 18,371 40% $565.50 $165.40 5
out 17,547 43% $6.20 $1.87 2
out 16,601 46% $565.50 $29.77 7
E3 8,545 72% $0.00 $1.61 6
METAL FABRICATION Fi 29,480 0% $0.00 $0.00 0
F2 29,109 1% $0.08 $0.00 1
out 26,326 11% $18.00 $7.00 3
out 26,149 11% $215.60 $67.00 5
out 19,663 33% $41.60 $10.20 2
F3 19,162 35% $0.00 $1.50 é
F4 13,738 53% $215.60 $8.71 7
TRANSPORTATION EQUIPMENT G1 1,801 0% $0.00 $0.00 0
G2 1,622 10% $0.03 $0.00 1
G3 648 64% $0.00 $0.42 6
- out 281 84% $268.90 $78.40 5
G4 279 85% $6.90 $2.44 3
GS 50 97% $268.90 $12.50 7
NON-METALLIC MINERAL H1 20,248 0% $0.00 $0.00 0
PROOUCTS out 19,478 4% $8.40 $3.60 3
out 19,397 4% $187.80 $56.60 5
out 19,316 5% $187.80 $7.36 tl
H2 18,223 10% $0.00 $0.39 6
H3 4,029 80% $27.70 $7.70 2
(continued)
24
TABLE 3.3 (continued)
Cost Emissions Emission Capital Operating Control
Source or Sector Function of S02 Reduction Costs Costs Technology
Code (T/yr) ---- (M 1987 $) ----- Code
CHEMICAL & PETROLEUM 11 69,384 0% $0.00 $0.00 0
PRODUCTS 12 66,539 4% $0.14 $0.00 1
out 62,446 10% $0.00 $11.41 6
13 53,009 24% $3.30 $2.00 2
out 49,887 28% $209.10 $65.20 5
14 45,238 35% $30.40 $10.70 3
15 39,133 44% $209.10 $14.34 7
16 35,108 49% $246.90 $79.00 4
OTHER GROUPS J1 4,805 0% $0.00 $0.00 0
J2 4,377 % $0.20 $0.00 1
J3 2,595 46% $0.00 $1.75 6
out 1,552 68% $750.40 $226.20 5
Jé 1,158 76% $40.90 $17.20 3
J5 577 88% $750.40 $38.40 7
INCO K1 265,000 0% $0.00 $0.00 0
K2 238,500 10% $37.80 $13.90 4
K3 212,000 20% $52.40 $20.00 4
K4 185,500 30% $64.20 $25.20 4
K5 132,500 50% $83.70 $34.40 4
ONTARIO HYDRO L1 175,000 0x $0.00 $0.00 0
L2 157,500 10% $62.30 $4.70 5
L3 140,000 20% $124.60 $9.40 5
L4 122,500 30% $186.90 $14.10 5
LS 87,500 50% $311.50 $23.50 5
FALCONBRIDGE M1 100,000 0% $0.00 $0.00 0
M2 90,000 10% $14.30 $9.30 2
M3 80,000 20% $23.40 $22.20 2
M4 70,000 30% $30.30 $36.50 2
MS 50,000 50% $42.50 $71.40 2
ALGOMA N1 125,000 0% $0.00 $0.00 0
out 112,500 10% $13.40 $0.10 2
N2 100,000 20% $22.50 $0.10 2
out 87,500 30% $21.90 $35.60 2
N3 62,500 50% $27.20 $48.00 2
SOURCE: Adapted from Senes, 1989(b)
NOTES: Cost Function Codes:
out - Control option is not used in the cost function.
A1,A2,... - First, second,... point in the cost function for sector "A".
Control Technology Codes:
0 Base Case
1 Fuel Switched to Natural Gas -- Boilers
2 Lime Spray Dryer -- Process Stream
3 Lime Spray Dryer -- Boilers
4 Limestone Flue Gas Desulphurization -- Process Streams
5 Limestone Flue Gas Desulphurization -- Boilers
6 Fuel Desulphurization
7 Fuel Desulphurization Plus Limestone Flue Gas Desulphurization
25
TABLE 3.4: NOX EMISSION CONTROL COST DATA
Cost Emissions Emission Capital Operating Control
Source or Sector Function of NOX Reduction Costs Costs Technology
Code (Tyr) wee ee (MH 1987 $) ----- Code
ee eee
FOOD & BEVERAGE B1 2,873 0% $0.00 $0.00 0
C B2 2,729 5% $0.60 ($1.30) 1
B3 2,585 10% $3.90 $0.80 2
out 1,265 56% $30.00 $6.60 3
B4 595 79% $137.10 $24.10 4
RUBBER & PLASTIC c1 386 0% $0.00 $0.00 0
PRODUCTS out 343 11% $0.10 ($0.40) 1
c2 300 22% $0.70 $0.10 2
c3 154 60% $4.00 $0.90 3
C4 58 85% $18.90 $3.33 4
TEXTILE INDUSTRY D1 1,180 0% $0.00 $0.00 0
out 1,058 10% $0.10 ($0.40) 1
D2 937 21% $1.80 $0.10 2
D3 508 57% $3.70 $0.80 3
Dé 228 81% $17.20 $3.00 6
PAPER & ALLIED PRODUCTS E1 11,429 0% $0.00 $0.00 0
out 10,225 11% $1.50 ($2.80) 1
E2 9,021 21% $5.00 $2.00 2
E3 4,682 59% $88.40 $19.40 3
E4 1,871 84% $413.50 $72.70 4
METAL FABRICATION Fi 14,812 0% $0.00 $0.00 0
out 14,207 4% $1.90 ($4.30) 1
Four 13,602 8% $8.30 $1.30 2
F3 6,328 57% $76.50 $16.80 3
F4 2,792 81% $273.40 $48.10 4
TRANSPORTATION EQUIPMENT Gi 2,099 0% $0.00 $0.00 0
out 1,972 6% $0.30 ($2.40) 1
out 1,844 12% $9.00 $0.70 2
G2 860 59% $13.90 $3.10 3
G3 343 84% $65.20 $11.50 4
NON-METALLIC MINERAL H1 9,826 0% $0.00 $0.00 0
PROOUCTS out 9,406 4% $0.80 ($8.90) 1
out 8,986 9x $3.10 $2.50 2
H2 4,523 54% $46.90 $10.60 3
H3 2,313 76% $316.50 $56.70 4
2
(continued)
26
TABLE 3.4 (continued)
Cost Emissions Emission Capital Operating Controt
Source or Sector Function of NOX Reduction Costs Costs Technology
Code (T/yr) ---- (M 1987 $) ---- Code
RE eee a ee
CHEMICAL & PETROLEUM 11 28,587 0% $0.00 $0.00 0
PRODUCTS out 27,149 5% $1.70 ($17.60) 1
out 25,708 10% $8.60 $5.00 2
12 12,958 55% $95.30 $20.90 3
13 6,446 77% $437.70 $77.00 4
OTHER GROUPS Ji 4,298 0% $0.00 $0.00 0
out © 3,814 11% $3.10 ($5.40) 1
J2 3,330 23% $9.10 $1.60 2
J3 2,285 47% $65.80 $14.40 3
J4 1,447 66% $196.60 $35.60 4
ONTARIO HYDRO L1 61,333 0% $0.00 $0.00 0
L2 55,200 10% $13.00 $2.50 4
L3 49,066 20% $26.10 $5.00 4
L4 42,933 30% $39.10 $7.50 4
L5 30,667 50% $65.10 $12.50 4
L6 24,884 59% $77.10 $14.90 4
MOBILE SOURCES 01 244,952 0% $0.00 $0.00 0
02 95,531 61% $974.37 $0.00 5
03 73,486 70% $1,282.91 $0.00 5
En eee, eS ee 4
SOURCE: Adapted from Senes, 1989(b) and MacLaren Plansearch, (1988).
NOTES: Cost Function Codes:
out - Control option is not used in the cost function.
Al,A2,... - First, second,... point in the cost function for sector "
Control Technology Codes:
0 Base Case
1 Low Excess Air
2 Staged Combustion
3 Selective Non-Catalytic Combustion
4 Selective Catalytic Reduction
5 Catalytic Converter
27
4.0 ANALYSIS OF ABATEMENT STRATEGIES
4.1 Overview
This chapter discusses the modelling results for the "Phase III -
Countdown Acid Rain Future Abatement Strategies" exercise.
The first set of results, generated by the SO, abatement strategy model,
comprise seven principal SO, emission reduction scenarios. The second
set of results, generated by the NO, abatement strategy model, comprises
five principal NO, emission reduction scenarios.
These SO; and the NO, emission reduction scenarios show:
1) The impact of different removal targets on the abatement strategies;
2) The impact when large sources (such as INO and Hydro) fail to fulfill
their 1994 regulated targets for abatement;
Additional analyses investigated the impact of forming a more equitable
distribution of emission reductions across sectors and of alternative
assumptions regarding variables like the interest rate.
4.2 650, Abatement Strategies
The primary analysis of SO, abatement scenarios concerned the
implications of reducing total emissions from the base case 1994 level of
900,885 t/yr (from Table 3.2). A range of conditions were examined
including different levels of reduction as well as higher initial starting
emission levels resulting from a failure to meet 1994 targets; these are
outlined in Table 4.1. Additional scenarios examine the implications of
Changing financial variables and of forcing all emitters to cut back by
the same percentage (an equity scenario). These analyses are briefly
summarized below.
28
The first three scenarios reveal how sensitive overall emission control
costs are to the required level of reduction (Table 4.2). The 30%
reduction, representing a reference case, entails a total cost, measured
in present value terms, of $887 M. A third of this is for start-up
investments. Dropping the target reduction by 20 points to 10%
(Scenario 2), reduces total costs by 82% to $159 M, while a comparable
increase to a 50% targeted reduction increases overall costs six-fold to
$5,338 M.
Table 4.1 Primary 505 Abatement Strategy Scenarios
eee
SO, Starting Emission Reduction From Target Remaining
Scenario level 1994 Base Case Reduction Emissions
Number É level it 12
1 900,885 30% 270,266 630,619
2 900,885 10% 90,089 810,796
3 900,885 50% 450,443 450,442
122 : 1,330,885 0% 430,000 900,885
132 1,115,885 0% 215,000 900,885
143 1,062,518 0% 161,633 900,885
153 981,702 0% 80,817 900,885
eee
NOTES:
1 The 1994 base case emission is 900,885 tonnes/yr.
2 INO fails to meet its 1994 target and remains at its 1985 emission
level (Scenario 12) or achieves 1/2 of its 1994 reduction
(Scenario 13). It does not contribute to reduction beyond 1994.
3 Hydro fails to meet its 1994 target and remains at its 1985 emission
level (Scenario 14) or achieves 1/2 of its 1994 reduction
(Scenario 15).
29
TABLE 4.2: SO2 ABATEMENT STRATEGIES FOR 30%, 10% AND 50% EMISSION REDUCTIONS
Control Option Percent Capital Cost Operat’g Cost Present Value Marginal Cost S02 Removal
Reduct’n --------------- (M 1987 $) --------------- (1987 $/T) (T/yr)
SCENARIO 1 - 30% REDUCTION
(Target reduction = 270,266 tonnes/yr)
À - FGD(process) 94.9% $2.10 $7.20 $69.35 $550 13,494
B - Lime Spray Dry(process) 6.9% $0.06 $0.00 $0.06 $65 99
D - Fuel Clean’g 32.0% $0.00 $1.31 $12.24 $632 2,355
E - FGD(process) 72.0% * $0.00 $1.61 $15.04 $78 21,972
F - Lime Spray Dry(boilers) 35.0% $0.00 $1.50 $14.01 $150 10,318
G - Fuel Clean’g 64.0% $0.00 $0.42 $3.93 $429 1,153
H - Lime Spray Dry(boilers) 10.0% $0.00 $0.39 53.64 $193 2,025
I - Fuel Clean’g 23.6% $3.30 $2.00 $21.98 $173 16,375
J - N.Gas 8.9% $0.20 $0.00 $0.20 $50 427
K - FGD(process) 50.0% $83.70 $34.40 $405.01 $327 132,500
L - FGD(boilers) 30.0% $186.90 $14.00 $317.66 $650 52,500
N - Lime Spray Dry(process) 20.0% $22.50 $0.10 $23.43 $100 25,000
TOTAL $298.76 $62.93 $886.55 278,217
SCENARIO 2 - 10% REDUCTION
(Target reduction = 90,089 tonnes/yr)
B - Lime Spray Dry(process) 6.9% $0.06 $0.00 $0.06 $65 99
D - N.Gas 3.9% $0.03 $0.00 $0.03 $11 287
E - FGD(process) 72.0% $0.00 $1.61 $15.04 $78 21,972
F - Lime Spray Dry(boilers) 35.0% $0.00 $1.50 $14.01 $150 10,318
G - N.Gas 9.9% $0.03 $0.00 $0.03 $18 179
H - Lime Spray Dry(boilers) 10.0% $0.00 $0.39 $3.64 $193 2,025
I - Fuel Clean’g 23.6% $3.30 $2.00 $21.48 $173 16,375
J - N.Gas 8.9% $0.20 $0.00 $0.20 $50 427
K - FGD(process) 10.0% $16.74 $6.88 $81.00 $327 26,500
N - Lime Spray Dry(process) 20.0% $22.50 $0.10 $23.43 $100 25,000
TOTAL $42.86 $12.48 $159.43 103,181
me
(cont inued)
30
TABLE 4.2 (continued)
a
Control Option Percent Capital Cost Operat’g Cost Present Value Marginal Cost SO2 Removal
Reduct‘ni) i-----=<-<<<--<= CHIN987/'S)) cee SES SE (1987 $/T) (T/yr)
i
SCENARIO 3 - 50% REDUCTION
(Target reduction = 450,443 tonnes/yr)
A - FGD(process) 94.9% $2.10 $7.20 $69.35 $550 13,494
B - N.Gas 72.0% $161.20 $7.52 $231.44 $106,421 1,023
D - Lime Spray Dry(boilers) 51.5% $8.10 $1.88 $25.66 $1,002 3,790
E - FGD(process) 72.0% $0.00 $1.61 $15.04 $78 21,972
F - FGD(boilers) 53.4% $215.60 $8.71 $296.95 $5,585 15,742
G - Lime Spray Dry(boilers) 97.2% $268.90 $12.50 $385.65 $166,157 1rai
H - FGD(boilers) 80.1% $27.70 $7.70 599.62 $724 16,219
1 - Lime Spray Dry(boilers) 49.4% $246.90 $79.00 $984.78 $17,070 34,276
J - Lime Spray Dry(boilers) 88.0% $750.40 $38.40 $1,109.07 $167,231 4,228
K - FGD(process) 50.0% $83.70 $34.40 $405.01 $327 132,500
L - FGD(boilers) 50.0% $311.50 $23.40 $530.06 $650 87,500
M - Lime Spray Dry(process) 50.0% $42.50 $71.40 $709.40 $1,810 50,000
N - Lime Spray Dry(process) 50.0% $27.20 $48.00 $475.54 $1,291 62,500
TOTAL $2,145.80 $341.72 $5,337.57 444,994
a
NOTE: Total base case provincial SO2 emissions assumed for this analysis are
900,885 tonnes/year. Total percentage reduction is calculated with this
as a reference value.
Additional assumptions include:
15 yr equip. life 6% inflation; and 13% interest rate.
Sector designations are as follows:
A Primary Metals H Non-Metallic Products
Food & Beverage 1 Chem. & Petroleum Products
Rubber & Plastic Products J Other Groups
Textile Industries K INCO
Paper & Allied Products L Ontario Hydro
M
N
Metal Fabrication Faconbr idge
DO nmOon
Transportation Equipment Algoma
31
These results indicate a strong non-linear response with higher reduction
targets forcing reliance on removal technologies having higher costs per
tonne of SO, removed. This is shown by the marginal costs data in
Table 4.2 which increase by four orders of magnitude for some sectors as
removal levels increase. The only exceptions to this are the marginal
costs for INC and Hydro - these are constant as removal efficiencies
increase (see Table 4.2). Their cost functions display constant average
and marginal costs over the range of removal efficiencies considered here.
Without INGO emission control options the maximm attainable reduction in
emissions is 312,500 tonnes/yr at a present value cost of $4,933 M. If
INCO remains at 1985 emission levels (Scenario 12) this limit is reached
and the 1994 reduction targets can not be achieved (Table 4.3). In fact,
if Scenario 12 becomes reality, the $4,933 M expenditure will leave the
province at an emission level of 1.01 M tonnes/yr. This exceeds the 1994
base case emission level by 13%. Partial (50%) success in controlling
INGO emissions (Scenario 13, Table 4.3) can considerably alleviate the
cost burden incurred by other sectors, and makes it possible to achieve
the 1994 SO, target.
A failure by Hydro to meet its 1994 targets (Scenarios 14 and 15) has
implications which are less severe though still costly. If Hydro fails to
act at all, remaining therefore at 1985 emission levels, the 1994 targets
can be achieved by other sectors at a cost of $321 m (Table 4.4). If
Hydro achieves half of its 1994 regulated reductions, other sectors incur
a cost of $78 M.
Variations in the financial assumptions had no effect on the choice of
control options for the four major emitters unless a very high capital
cost scenario was chosen (25% interest rate, 5 year planning horizon). In
this scenario Hydro control options, having the highest capital costs, are
dropped in favour of additional controls by INOCO, Algoma and some of the
smaller sectors. Among the smaller sectors, variations in financial
variables cause some switching among control options.
32
TABLE 4.3: SO2 ABATEMENT STRATEGIES TO ACHIEVE 1994 EMISSION REDUCTION TARGETS WITHOUT INCO
a
Control Option Percent Capital Cost Operat’g Cost Present Value Marginal Cost S02 Removal
Reduct’/n --------------- (M 1987 $) ------------. - (1987 $/T) (Tyr)
SCENARIO 12 - INCO REMAINS AT ITS 1985 EMISSION LEVEL (ALL other sectors are at their maximum control levels.)
(Target reduction = 430,000 tonnes/yr)
A - FGD(process) 94.9% $2.10 $7.20 $69.35 $550 13,494
B - N.Gas 72.0% $161.20 $7.52 $231.44 $106,421 1,023
D - Lime Spray Dry(boilers) 51.5% $8.10 $1.88 $25.66 $1,002 3,790
E - FGD(process) 72.0% $0.00 $1.61 $15.04 $78 21,972
F - FGD(boilers) 53.4% $215.60 $8.71 $296.95 $5,585 15,762
G - Lime Spray Dry(boilers) 97.2% $268.90 $12.50 $385.65 $166,157 1,751
H - FGD(boilers) 80.1% $27.70 $7.70 $99.62 $724 16,219
1 - Lime Spray Dry(boilers) 49.4% $246.90 $79.00 5984.78 $17,070 34,276
J - Lime Spray Dry(boilers) 88.0% $750.40 $38.40 $1,109.07 $167,231 4,228
L - FGD(boilers) 50.0% $311.50 $23.40 $530.06 $650 87,500
M - Lime Spray Dry(process) 50.0% $42.50 $71.40 $709.40 $1,810 50,000
N - Lime Spray Dry(process) 50.0% $27.20 $48.00 $475.54 $1,291 62,500
TOTAL $2,062.10 $307.32 $4,932.56 312,494
SCENARIO 13 - INCO ACHIEVES ONE HALF OF ITS 1994 REGULATED REDUCTION
(Target reduction = 215,000 tonnes/yr)
A - FGD(process) 94.9% $2.10 $7.20 $69.35 $550 13,494
B - Lime Spray Dry(process) 6.9% $0.06 $0.00 $0.06 $65 9
D - Lime Spray Dry(boilers) 51.5% $8.10 $1.88 $25.66 $1,002 3,790
E - FGD(process) 72.0% $0.00 $1.61 $15.04 $78 21,972
F - Lime Spray Dry(boilers) 35.0% $0.00 $1.50 $14.01 $150 10,318
G - Fuel Clean’g 64.0% $0.00 $0.42 $3.93 $429 1,153
H - FGD(boilers) 80.1% $27.70 $7.70 599.62 s724 16,219
I - Fuel Clean’g 23.6% $3.30 $2.00 $21.98 $173 16,375
J - Fuel Clean’g 46.0% $0.00 $1.75 $16.35 $970 2,210
L - FGD(boilers) 50.0% $311.50 $23.40 $530.06 $650 87,500
M - Lime Spray Dry(process) 10.0% $14.30 $9.30 $101.17 $1,083 10,000
N - Lime Spray Dry(process) 20.0% $22.50 $0.10 $23.43 $100 25,000
TOTAL $389.56 $56.86 $920.66 208,128
NOTE: Total base case provincial SO2 emissions assumed for this analysis are
900,885 tonnes/year. Target reductions are based on achieving this Level
in 1994 without the full participation of INCO.
Additional assumptions include:
15 yr equip. life 6% inflation; 13% interest rate.
Sector designations are as follows:
A Primary Metals H Non-Metallic Products
B Food & Beverage I Chem. & Petroleum Products
C Rubber & Plastic Products J Other Groups
D Textile Industries K INCO
E Paper & Allied Products L Ontario Hydro
F Metal Fabrication M Faconbridge
G Transportation Equipment N Algoma
TABLE 4.4: SO2 ABATEMENT STRATEGIES TO ACHIEVE 1994 EMISSION REDUCTION TARGETS WITHOUT HYDRO
Control Option Percent Capital Cost Operat’g Cost Present Value Marginal Cost S02 Removal
Reduct’n -------------.- (M 1987 $) ------------..- (1987 $/T) (T/yr)
SCENARIO 14 - HYDRO REMAINS AT ITS 1985 EMISSION LEVEL
(Target reduction = 161,633 tonnes/yr)
B - Lime Spray Dry(process) 6.9% $0.06 $0.00 $0.06 $65 9
D - N.Gas 3.9% $0.03 $0.00 $0.03 $11 287
E - FGD(process) 72.0% $0.00 $1.61 $15.04 $78 21,972
F - Lime Spray Dry(boilers) 35.0% $0.00 $1.50 $14.01 $150 10,318
G - N.Gas 9.9% $0.03 $0.00 $0.03 $18 179
H - Lime Spray Dry(boilers) 10.0% $0.00 $0.39 $3.64 $193 2,025
I - Fuel Clean’g 23.6% $3.30 $2.00 $21.98 $173 16,375
J - N.Gas 8.9% $0.20 $0.00 $0.20 $50 427
K - FGD(process) 30.0% $50.22 $20.64 $243.00 $327 79,500
N - Lime Spray Dry(process) 20.0% $22.50 $0.10 $23.43 $100 25,000
TOTAL $76.34 $26.24 $321.43 156,181
SCENARIO 15 - HYDRO ACHIEVES ONE HALF OF ITS 1994 REGULATED REDUCTION
(Target reduction = 80,817 tonnes/yr)
B - Lime Spray Dry(process) 6.9% $0.06 $0.00 $0.06 $65 99
) - N.Gas 3.9% $0.03 $0.00 $0.03 $11 287
= - FGD(process) 72.0% $0.00 $1.61 $15.04 $78 21,972
* - Lime Spray Dry(boilers) 35.0% $0.00 $1.50 $14.01 $150 10,318
3 - N.Gas 9.9%x $0.03 $0.00 $0.03 $18 179
1 - Lime Spray Dry(boilers) 10.0% $0.00 $0.39 53.64 $193 2,025
| Fuel Clean’g 23.6% $3.30 $2.00 $21.98 $173 16,375
| - N.Gas 8.9% $0.20 $0.00 $0.20 $50 427
| - Lime Spray Dry(process) 20.0% $22.50 $0.10 $23.43 $100 25,000
TOTAL $26.12 $5.60 $78.43 76,681
NOTE: Total base case provincial so2 emissions assumed for this analysis are
900,885 tonnes/year. Target reductions are based on achieving this level
in 1994 without the full Participation of Hydro.
Additional assumptions include:
15 yr equip. life 6% inflation; 13% interest rate.
Sector designations are as follows:
A Primary Metals H Non-Metallic Products
B Food & Beverage 1 Chem. & Petroleum Products
C Rubber & Plastic Products J Other Groups
D Textile Industries K INCO
E Paper & Allied Products L Ontario Hydro
F Metal Fabrication M Faconbridge
G Transportation Equipment N Algoma
34
TABLE 4.5: SO2 EQUITY-BASED ABATEMENT STRATEGY
control Option Percent Capital Cost Operat’g Cost Present Value Marginal Cost SO2 Removal
Reductini-<o-< cen "°°° CHINS8 72S) hewn wn nnn nnn (1987 $/T) (T/yr)
SCENARIO 18 - 30% REDUCTION WITH UNIFORM CONTROL LEVELS IN EACH ESCTOR
(Target reduction = 270,266 tonnes/yr)
A - (extrapolated) 32% n.a. n.a. $23.37 $550 4,550
3 - (extrapolated) 32% n.8. n.a. $28.66 $8,601 455
) - Fuel Clean'g 32% $0.00 $1.31 $12.24 $632 2,355
= - (extrapolated) 32% n.8. n.a. $6.17 $78 9,765
F - Lime Spray Dry(boilers) 35% $0.00 $1.50 $14.01 $150 10,318
3 - (extrapolated) 32% n.a. n.a. $1.62 $429 576
H - (extrapolated) 32% n.a. n.8. $33.76 $724 6,479
| - Lime Spray Dry(process) 35% $30.40 $10.70 $130.34 $1,493 24,146
J - (extrapolated) 32% n.8. n.a. $10.26 $970 1,537
K - FGD(process) 30% $50.22 $20.64 $243.00 $327 79,500
. - FGD(boilers) 30% $186.90 $14.00 $317.66 $650 52,500
4 - Lime Spray Dry(process) 30% $30.30 $36.50 $371.22 $1,504 30,000
N - (extrapolated) 32% n.8. n.a. $204.30 $1,291 40,000
TOTAL n.a. n.8. $1,396.62 262, 182
NOTE: Total base case provincial SO2 emissions assumed for this analysis are
900,885 tonnes/year. Total percentage reduction is calculated with this
as a reference value.
Additional assumptions include:
15 yr equip. life 6% inflation; and 13% interest rate.
Sector designations are as follows:
A Primary Metals H Non-Metallic Products
B Food & Beverage I Chem. & Petroleum Products
C Rubber & Plastic Products J Other Groups
D Textile Industries K INCO
E Paper & Allied Products L Ontario Hydro
F Metal Fabrication M Faconbridge
G Transportation Equipment N Algoma
The equity-based scenario (Table 4.5) reveals that uniform across the
Poard cuts in emissions entail higher overall costs due to a failure to
take full advantage of low cost control options that are available in
Certain sectors. In the case of the 30% targeted reduction, the total
cost of $1,397 M includes a $510 M penalty over the cost-effective
scenario cost of $887 M (Scenario 1, Table 4.2)
4.3 NO, Abatement Strategies
Considering alternative levels of reduction, failures to meet 1994
regulation levels, the impact of financial variables and the implications
of an equity-based Strategy. The base case emission level is 578,135
tonnes/yr (Table 3.2). The main scenarios are described in Table 4.6
Table 4.6 Primary NO, Abatement Strategy Scenarios
er a Bes ee
Starting Emission Reduction From Target Remaining
Level
NO,
Scenario 1994 Base Case Reduction Emissions
Number (t/yr) Level (t/yr) (t/yr)
1 578,135 30% 173,441 404,694
2 578,135 10% 57,814 520,321
3 578,135 50% 289,068 289,067
122 611,239 0% 33,104 578,135
132 594, 687 0% 16,552 578,135
ni Lois
NOTES :
D De 1994 base casc-emission level is 578,135 tonnes/yr.
2 Hydro fails to meet its 1994 target and remains at its 1985 emission
level (Scenario 12) or achieves 1/2 of its 1994 reduction
(Scenario 13).
36
With all sectors engaged, the maximm potential NO,, emission reduction is
266,677 tonnes/yr (46% of the base case). This level of reduction costs $6,476
M in present value terms (Scenario 3, Table 4.7). Moreover, 64% of the
emission reduction comes from control of mobile sources.
AS was seen for the SO, abatement strategies, NO,, removal costs increase
rapidly at the higher levels of emission control. The maximm reduction level
(Scenario 3) costs 5.4 times more than a 30% reduction and 30 times more than a
10% reduction (Scenarios 1 and 2, Table 4.7). The lowest cost options are
point source controls for Hydro and 3-way catalytic converters for mobile
sources (see Scenario 1 marginal costs). The mobile source controls, required
by Federal regulation on new vehicles after 1987, reduce emissions by 80% from
5.0 g NO,/mile to 1.0 g NO,/mile. NO, emissions will fall progressively
over time with this regulation as new cars replace old cars. The reduction
levels considered here for mobile sources are expected to occur by 1994.
A partial or total failure on the part of Hydro to achieve its 1994 regulation
level is readily offset by federally mandated mobile source controls which are
now in effect for new vehicles (Scenario 12, Table 4.8). With the mobile
source control option, emission reductions far exceed the target reduction
level due to the modelling approach that precludes interpolations of the data
to reflect partial implementation of options.
Variations in financial variables have minimal impact on Hydro and other
sectors even with very high capital cost assumptions (see Appendix A for
detailed results).
Scenario 1 requires that emission controls be implemented by only mobile
sources and Hydro. Forcing all sectors into an equity-based scenario at an
approximately uniform level of performance in order to meet the 30% reduction
target, brings nine new sectors into the strategy and raises overall costs from
$1,191 M to $2,275 M (Table 4.9).
37
TABLE 4.7: NOX ABATEMENT STRATEGIES FOR 30%, 10% AND 50% EMISSION REDUCTIONS
Control Option Percent Capital Cost Operat’g Cost Present Value Marginal Cost NOx Removal
: Reduct'n --------------- (M 1987 $) --------------- (1987 $/T) (T/yr)
SCENARIO 1 - 30% REDUCTION
(Target reduction = 173,441 tonnes/yr)
L - Selective Catalytic Reduc’n 59% $77.10 $14.90 $216.27 $636 36,432
O - Catalytic Converter 61% $974.37 $0.00 5974.37 $698 149,421
TOTAL $1,051.47 $14.90 $1,190.64 185,853
SCENARIO 2 - 10% REDUCTION
(Target reduction = 57,814 tonnes/yr)
L - Selective Catalytic Reduc’n 59% $77.10 $14.90 $216.27 $636 36,432
SCENARIO 3 - 50% REDUCTION (ALL sectors are at their maximum control levels.)
(Target reduction = 289,068 tonnes/yr)
B - Selective Catalytic Reduc’n 79% $137.10 $24.10 $362.21 543,838 2,238
C - Selective Catalytic Reduc’n 85% $18.90 $3.33 $49.99 $41,860 329
D - Selective Catalytic Reduc’n 81% $17.20 $3.02 $45.44 $12,953 972
E - Selective Catalytic Reduc’n 84% $413.50 $72.73 $1,092.78 $30,845 9,823
F - Selective Catalytic Reduc’n 81% $273.40 $48.08 $722.48 $14,729 11,903
G - Selective Catalytic Reduc’n 84% $65.20 $11.46 $172.27 $26,402 1,801
H - Selective Catalytic Reduc’n 76% $316.50 $56.66 $845.75 $34,661 7,325
I - Selective Catalytic Reduc’n 77% $437.70 $76.97 $1,156.66 $14,745 21,580
J - Selective Catalytic Reduc’n 66% $196.60 $35.60 $529.12 $43,109 2,809
L - Selective Catalytic Reduc’n 59% $77.10 $14.90 $216.27 $636 36,432
O - Catalytic Converter 70% $1,282.91 $0.00 $1,282.91 $1,498 171,466
TOTAL $3,236.11 $346.86 $6,475.87 266,677
ee des
NOTE: Total base case provincial NOx emissions assumed for this analysis are
578,135 tonnes/year. Total percentage reduction is calculated with this
as a reference value.
Additional assumptions include:
15 yr life time: 6% inflation; 13% interest rate.
Sector designations are as follows:
B Food & Beverage H Non-Metallic Products
C Rubber & Plastic Products I Chem. & Petroleum Products
D Textile Industries ! Other Groups
E Paper & Allied Products L Ontario Hydro
F Metal Fabrication O Mobile Sources
G Transportation Equipment
38
TABLE 4.8: NOX ABATEMENT STRATEGIES TO MEET 1994 REGULATED REDUCTION TARGETS WITHOUT HYDRO
Control Option Percent Capital Cost Operat’g Cost Present Value Marginal Cost NOx Removal
Reduct’n --------------- CM 1987 $) --------------.- (1987 $/T) (T/yr)
SCENARIO 12 - HYDRO REMAINING AT ITS 1985 EMISSION LEVEL
(Target reduction = 33,104 tonnes/yr)
0 - Catalytic Converter 61% $974.37 $0.00 5974.37 $698 149,421
NOTE: Total base case provincial NOx emissions assumed for this analysis are
578,135 tonnes/year. Total percentage reduction is calculated with this
as a reference value.
Additional assumptions include:
15 yr Life time: 6% inflation; 13% interest rate.
Sector designations are as follows:
B Food & Beverage H Non-Metallic Products
C Rubber & Plastic Products 1 Chem. & Petroleum Products
D Textile Industries J Other Groups
E Paper & Allied Products L Ontario Hydro
F Metal Fabrication O Mobile Sources
G Transportation Equipment
39
TABLE 4.9: NOX EQUITY-BASED ABATEMENT STRATEGY
Control Option Percent Capital Cost Operat’g Cost Present Value Marginal Cost NOx Removal
Reduct’n --------------- (M 1987 $) --------------- (1987 $/T) (T/yr)
SCENARIO 18 - 30% REDUCTION WITH UNIFORM CONTROL LEVELS IN EACH SECTOR
(Target reduction = 173,441 tonnes/yr)
B - Selective Non-Cat’tic Comb’n 56.0% $30.00 $6.60 $91.65 $6,503 1,609
C - (extrapolated) 50.0% n.8. n.8. $9.47 $7,845 193
D - Selective Non-Cat’tic Comb’n 57.0% $3.70 $0.80 $11.17 $2,127 673
E - Selective Non-Cat’tic Comb’n 59.0% $88.40 $19.40 $269.60 $6,062 6,738
F - Selective Non-Cat’tic Comb’n 57.0% $76.50 $16.80 $233.42 $3,142 8,388
G - Selective Non-Cat’tic Com/n 59.0% $13.90 $3.10 $42.86 $3,705 1,238
H - Selective Non-Cat’tic Comb’n 54.0% $46.90 $10.60 $145.91 $2,944 5,310
1 - Selective Non-Cat’tic Comb’n 55.0% 595.30 $20.90 $290.51 $1,978 15,838
J - Selective Non-Cat’tic Comb’n 47.0% $65.80 $14.40 $200.30 $18,292 2,026
L - Selective Catalytic Reduc’n 50.0% $64.90 $12.54 $182.05 $635 30,667
O - (extrapolated) 50.0% n.a. n.a. $798.43 $698 122,476
TOTAL n.a. n.a. $2,275.37 195,155
——_ oe
NOTE: Total base case provincial NOx emissions assumed for this analysis are
578,135 tonnes/year. Total percentage reduction is calculated with this
as a reference value.
Additional assumptions include:
15 yr life time: 6% inflation; 13% interest rate.
Sector designations are as follows:
B Food & Beverage K Non-Metallic Products
C Rubber & Plastic Products I Chem. & Petroleum Products
D Textile Industries J Other Groups
E Paper & Allied Products L Ontario Hydro
F Metal Fabrication O Mobile Sources
G Transportation Equipment
40
REFERENCES
E.A. McBean and Associates Ltd., 1983. "Linear Programming Screening
Model for Development and Evaluation of Acid Rain Abatement
Strategies" Prepared for the Ontario Ministry of the Environment.
Maclaren Plansearch, 1988. "Projected Emission Reductions and Costs of
From Mobile Sources In Ontario: A Preliminary Report to the
Ministry of the Environment."
Senes Consultants Ltd., 1989(a) . "Phase I - Countdown Acid Rain Future
Abatement Strategies." Prepared for Ontario Ministry of the
Environment.
Senes Consultants Ltd., 1989(b) . "Phase II - Countdown Acid Rain Future
Abatement Strategies." Prepared for Ontario Ministry of the
Environment.
APPENDIX A
SO, AND NO, ABATEMENT STRATEGIES - DETAILED RESULTS
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APPENDIX B
FUEL DESULFURIZATION CALCULATIONS
= (D ae — dont et er ihe
FIGURE B.1
LFGD+FD Removal Efficiency
Calculations :
The removal efficiency for LFGD+FD
control is calculated by using the following
Squauons ©:
ee Jeo JLFep
| ue
a
‘Uncontrolled Y
Por Sireamseue
NOTES” 2) Fp ED Removal Efficiency;
Ateneo LFGD Removal Efficiency.
Total emission = (1—/))[(1-/) )x+y] + P
FD LFGD
. loralSEelss ion
% Reduction (J) = (1 oats ane
CPV OG ca ees (Ga
DOTE SEE SAMPLE CALCULATIONS FOLLOWS
B-1
SAMPLE CALCULATIONS
* Using equations B.3.1 & B.3.2;
* All H ard LFGD used in the following calculations are tabulated
in Table B.1 and B
Consider Transportation Equipment:
Total emission after FD + LFGD =
(1 - 0.84) [1 - 0.95)1600 + 197.45] + 5.4
= 49.79 Tonnes/year
% reduction = (1 - 49.70/1801) x 100 = 97.2%
FD + LFGD
Consider Metal Fabrication:
(1 — .84)[(1 - 0.95) 350 + 14134.07] + 11864.9
Total emission = 13725.1 tonnes/year
% Reduction = (1 - 13725.1/29480) x 100 = 53.4%
Consider Non-Metallic Products:
(1 - 0.87)] [(0.05) 887.4 + 53.43] + 19308.3
= Total emission = 19321 tonnes/year
% red. = (1 - 19321/20248) x 100 = 4.6%
Consider Chemical & Petroleum Products:
(1 - 0.78) [ (0.05) (20533.7) + 12820.83] + 36073.3
= Total emission = 39119.75 |
% red. = (1- 39119.75/69384) x 100 = 43.6%
Consider Other Groups: |
‘Coal Sl ae X 3423.9 + 982.16] + 404.3
= 600.37 tonnes/year
% red. a — 600.37/4805) x 100 = 87.5%
ee
1 - 0.85) [0.05 x 849.2 + 219.2] + 353.6
Total E = 392.849
(
$ r= (1 - 392.849/1421) x 100 = 72.35%
Consider Textile Industries:
(1 - 0.88) [0.05 x 2882.7 + 24.6] + 4454.5
= Total E = 4474.748
% r = (1 - 4474.748/7359) x 100 = 39.2%
Consider Paper & Allied Products
(f— 0282) [0205 %.12772.5:+ 1561.25) .+ 16201.1
Total E = 16597.0775
% r = (1 - 16597.0775/30516) x 100
= 45.6%
TABLE B.1: REMOVAL EFFICIENCIES FOR FUEL DESULFURIZATION
Total so2 Total $02 $02 so2 Overall
Boiler Emission Controlled Removal Control Control
(T/yr) (T/yr) (T/yr) Efficiency Efficiency
Transportation Equipment 1,795 983 825 84% 46%
Metal Fabrication 17,615 3,401 2,997 87% 10%
Non-Metallic Products 940 879 767 87% 4%
Chem. & Petroleum Products 33,311 28,638 22,362 78% 32%
Other Groups 4,400 4,132 ‘ 3,440 83% 72%
Food & Beverage 1,067 1,067 905 85% 64%
Textile Industries 2,904 2,904 2,568 88% 35%
Paper & Allied Products 14,315 3,829 3,158 82% 10%
TABLE B.2: REMOVAL EFFICIENCIES FOR FLUE GAS DESULFURIZATION
Total SO2 Total SO2 S02 Uncon- SO2 Process so2
Boiler Emission Controlled trolled Emission Control
(T/yr) (T/yr) (T/yr) (T/yr) Efficiency
Transportation Equipment 1,795 1,600 197 5 95%
Metal Fabrication 17,615 3,504 14,134 11,895 95%
Non-Metallic Products 940 887 53 19,308 95%
Chem. & Petroleum Products 33,311 20,534 12,821 36,073 95%
Other Groups 4,400 3,424 982 404 95%
Food & Beverage 1,067 849 219 354 95%
Textile Industries 2,904 2,883 25 4,855 95%
Paper & Allied Products 14,315 12,773 1,561 16,201 95%
FIGURE B.2
LBGD+FD Cost Calculations :
Assuming the capital cost is the same
as the LFGD and operating cost is to
tonnes of SO2 (controlled load).
(B) ep LFSD
Boiler Controlled
In X
FD LFGD
Uncontrolled Y
Process Streams (P
Operating Cost = RUE Operating cost of
(FD+LFGD) Rene
Nema) Cost = Operating cost + Capital cost
(FD+LFGD) (FD+LFGD) (LFGD)
ER |
None Ch) —— FD Removal Biricrency.
4 icy ——— LFGD Removal Efficiency.
B-5
APPENDIX C
MODEL DOCUMENTATION
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COMPUTER PROGRAM DEVELOPMENT AND USE
Model Structure
The marginal cost based algorithm was implemented as a computer model, The
Simple Acid Rain Model (SARM), using Lotus 1-2-3 software. It is a menu
operated and macro driven program made up of three separate modules, each
module comprising a separate Lotus worksheet. The three worksheets are
the input worksheet, the calculation worksheet and the output worksheet.
These worksheets are interconnected; thus, one worksheet can call up
another worksheet by invoking a call macro. There are three temporary
files generated during these calling processes. These files serve to
transmit information between the three worksheets. The flow and structure
of SARM are shown in Figure C.1.
General discussions on the structure of the model and the use of the model
are given in the following sections. The discussion pertains to both the
S0, model and the NO, model which are basically the same.
Input Worksheet
The input worksheet (Table C.1) is the first interface between the user
and the model. There are three main options available to the user here:
the "Input/Edit" option, the "Save" option and the "Cal" option.
The "Input/Edit" option allows the user to input new data and/or edit old
data. The user should input the data in the following format:
1) Colum 1 (Source) -
i) Enter - Name of emitter
ii) Format - Label
iii) Example - Hydro
iv) Note - These labels are not used in subsequent displays and
are entered as a guide in using this worksheet.
2) Colum 2 (Technologies) -
i) Enter - Technology index
ii) Format - Label
iii) Example - Al
iv) Note - Indices should identify both the source and the
technology. For instance, Al designates the base case for
source A. Integer portions of the code should be sequential
(1, 2, 3, ...) and should correspond to control options with
successively higher removal efficiencies.
3) Colum 3 (Contaminant Emissions) -
i) Enter - Emissions for sources in tonnes/year
ii) Format - Numeric
iii) Example - 12345.22
iv) Note - Data is entered without commas and digits can be entered
after the decimal but will not be displayed (i.e. 12,345).
C-1
TABLE C.1: SO2 "INPUT" WORKSHEET DATA LISTING
So2 Operating Idexing Growth
Emissions % Capital Cost Cost 0 - Not incl’d Rate
Source Technology (Tonnes/year) Reduction (million $) (million $) 1 - Included (%)
A ——_—
Dummy Source (not app.) 0 0.0% $0.00 $0.00 0 0
(not app.) 0 0.0% $0.00 $0.00 0
(not app.) 0 0.0% $0.00 $0.00 0 0
Primary Metal Products Al 14,219 0.0% $0.00 $0.00 0
A2 725 94.9% $2.10 $7.20 0
Food & Beverage Prod’s B1 1,421 0.0% $0.00 $0.00 0
B2 1,322 6.% $0.06 $0.00 0
B3 570 59.9% $11.90 $5.20 0
B4 398 72.0% $161.20 $7.52 0
Leather/Textile Prod’s Di 7,359 0.0% $0.00 $0.00 0
D2 7,072 3.9% $0.03 $0.00 0
D3 5,004 32.0% $0.00 $1.31 0
D4 3,569 51.5% $8.10 $1.88 0
Paper & Allied Prod’s E1 30,516 0.0% $0.00 $0.00 0
E2 29,143 4.5% $0.06 $0.00 0
E3 8,545 72.0% $0.00 $1.61 0
Metal Fabrication F1 29,480 0.0% $0.00 $0.00 0
F2 29,109 1.3% $0.08 $0.00 0
F3 19,162 35.0% $0.00 $1.50 0
F4 13,738 53.4% $215.60 $8.71 0
Transportation Equip’t G1 1,801 0.0% $0.00 $0.00 0
G2 1,622 9.9% $0.03 $0.00 0
G3 648 64.0% $0.00 $0.42 0
G4 279 84.5% $6.90 $2.44 0
GS 50 97.2% $268.90 $12.50 0
Non-metallic Products K1 20,248 0.0% $0.00 $0.00 0
H2 18,223 10.0% $0.00 $0.39 0
H3 4,029 80.1% $27.70 $7.70 0
Chem. & Petro. Prod’s 11 69,384 0.0% $0.00 $0.00 0
12 66,539 4.1% $0.14 $0.00 0
13 53,009 23.6% $3.30 $2.00 0
14 45,238 34.8% $30.40 $10.70 0
15 39,133 43.6% $209.10 $14.34 0
16 35,108 49.4% $246.90 $79.00 0
Other Groups Ji 4,805 0.0% $0.00 $0.00 0
J2 4,377 8.9% $0.20 $0.00 0
J3 2,595 46.0% $0.00 $1.75 0
Jé 1,158 75.9% $40.90 $17.20 0
J5 577 88.0% $750.40 $38.40 0
INCO Ki 265,000 0.0% $0.00 $0.00 0
K2 238,500 10.0% $16.74 $6.88 0
K3 212,000 20.0% $33.48 $13.76 0
K4 185,500 30.0% $50.22 $20.64 0
KS 132,500 50.0% $83.70 $34.40 0
C-2
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4)
5)
6)
7)
Column 4 (% Reduction) -
i) Enter - Contaminant removal efficiency
ii) Format - Numeric (0.0 to 1.0)
iii) Example - 0.1
iv) Note - For base case, users should enter 0.0. Data are
displayed in percentage format (i.e. 0.10 appears as 10%).
Column 5 (Capital Cost) -
i) Enter - Capital cost in millions of 1987 dollars
ii) Format - Numeric
iii) Example - 13.90
iv) Note - Data are displayed in currency format (i.e. $13.90).
Column 6 (Operating Cost) -
i) Enter - Operating cost in millions of 1987 dollars
ii) Format - Numeric
iii) Example - 3.10
iv) Note - Currency are displayed in currency format (i.e. $3.10) .
Colum 7 (Indexing) -
i) Enter - 0 for excluded, 1 for included and blank if model is to
make the selection
ii) Format - Numeric
iii) Example - Technology Indexing
Al 0
A2 1
A3 0
Bl
B2
B3
C1 0
C2 O
C3 0
D1
D2
D3
iv) Note - users can force one or more of the technologies
into an abatement strategy by entering 1’s in
column 7, or can exclude any of the technologies
from the solution by entering 0’s in this column.
For the colum entries left blank, the model
evaluates corresponding technologies based on the
marginal cost ranking process.
In the example, technology A2 is forced into the
solution and technologies Cl, C2 and C3 are
excluded from the selection. The rest of the
technologies (i.e. Bl, B2, B3, D1, D2 and D3) are
Passed into the "calculation" worksheet and the
model will make a selection from among these based
on the marginal ranking procedure and the target
removal. Note that the target removal used when
certain control technologies are forced into the
abatement strategy is equal to the target removal
input by the user minus the contaminant removed by
the pre-selected technologies (this calculation is
done by the model automatically). Only one
technology per sector can be forced into the
solution. In other words, after one of the
technologies is forced into the solution; the rest
of the technologies within the sector must be
excluded from the solution by assigning zero’s to
these in Colum 7.
8) Column 8 (Growth Rate) -
i) Enter - Growth rate in percent
ii) Format - Numeric
iii) Example - 10
iv) Note - Growth rate factors are used to change the
emission level and corresponding operating costs
for a sector. For the example above, emission
levels and costs would be multiplied by the value
(1 + 10/100). A negative entry would correspond
to an assumed reduction in sector emissions by
1994. Note that this growth rate causes a one
time change in level rather than an annual change
continuing over the planning horizon.
Individual growth rates must be assigned to each
control technology. Within a sector these should
be the same though they can vary across sectors.
It is assumed that any increase in emissions
stipulated using the growth rate factor is within
the capacity limits of the control technology.
For this reason, capital costs are not adjusted.
The next major option available to the user is "Save". It contains three
sub-options; they are "Create", "Save" and "Quit". The "Create"
sub-option creates two temporary files. The first file contains the
user’s selected technologies and it is passed to the output worksheet.
The second file contains the technologies which are passed to the
calculation worksheet for selection based on the marginal cost ranking
procedure and the target removal. After making changes with "Input/edit",
"Create" must be executed before passing control over to the "Cal"
worksheet. The "Save" sub-option allows the users to save the input
worksheet. The "Quit" sub-option allows the user to go back to the main
menu.
The last major option available to the users is "Run". It allows the
users to save the input worksheet and calls up the calculation worksheet
for model execution.
model selected technologies. The users Should keep these dummy entries as
they appeared in the example file (they do not interfere with the
Calculation Worksheet
There are five major options available to the users in this module. They
are the "Input" option, the "Edit" option, the "Run" option, the "Print"
option and the "Quit" option.
The "Input" option allows the user to input "model parameters", such as
the inflation rate, the nominal interest rate, the target removal level
and the planning horizon.
The "Edit" option allows the user to Save the calculation worksheet and
call up the input worksheet to edit the input data.
The "Run" option performs the selection based on the marginal cost ranking
procedure.
The "Print" option saves the results from a model "Run" in a temporary
file which is passed to the output module. Furthermore, this option also
Saves the calculation worksheet and calls up the output worksheet.
The "Quit" option allows the users to quit macros and go back to the Lotus
control menu. In other words, this option allows the users to edit the
macros which were developed by the author.
Output Worksheet
The "Output" worksheet automatically generates the final table reporting
control options for a scenario (see Table C.2). Once this table is
Prepared, there are four major Options available to the user. They are
the "Browse" option, the "Print" option, the "Edit" option and the
"Calculation" option.
The "Browse" option allows the users to examine the results on screen
before printing.
The "Print" option permits the users to print the results directly to the
printer. Just prior to print, the user is prompted to enter a table
title. For instance, the user can enter a scenario ID number for a run.
C-6
TABLE C.2: SO2 "OUTPUT" WORKSHEET DATA LISTING
TARGETED SO2 REMOVAL LEVEL (T/yr) 270,266
Control Options Emission Capital Operating Present Total SO2 $02 Emiss- Comment
Chosen by Model Reduct’n Costs (M$) Cost (M $) Value (M$) Removal(T/yr) ions(T/yr)
Si ee ee ee ee pe
Al 0% $0.00 $0.00 $0.00 0 14,219 OUT
A2 95% $2.10 $7.20 $69.35 13494 725 IN
B1 0% $0.00 $0.00 $0.00 0 1,421 OUT
B2 Th $0.06 $0.00 $0.06 99 1,322 IN
B3 60% $11.90 $5.20 $60.47 0 570 OUT
B4 72% $161.20 $7.52 $231.44 0 398 OUT
D1 0% $0.00 $0.00 $0.00 0 7,359 OUT
D2 4% $0.03 $0.00 $0.03 0 7,072 OUT
D3 32% $0.00 $1.31 $12.24 2355 5,004 IN
D4 52% $8.10 $1.88 $25.66 0 3,569 OUT
E1 0% $0.00 $0.00 $0.00 0 30,516 OUT
E2 4% $0.06 $0.00 $0.06 0 29,143 OUT
E3 72% $0.00 $1.61 $15.04 21972 8,545 IN
F1 0% $0.00 $0.00 $0.00 0 29,480 OUT
F2 1% $0.08 $0.00 $0.08 0 29,109 OUT
F3 35% $0.00 $1.50 $14.01 10318 19,162 IN
F4 53% $215.60 $8.71 $296.95 0 13,738 OUT
G1 0% $0.00 $0.00 $0.00 0 1,801 OUT
G2 10% $0.03 $0.00 $0.03 0 1,622 OUT
G3 64% $0.00 $0.42 $3.93 1153 648 IN
G4 85% $6.90 $2.44 $29.69 0 279 OUT
GS 97% $268.90 $12.50 $385.65 0 50 OUT
H1 0% $0.00 $0.00 $0.00 0 20,248 OUT
H2 10% $0.00 $0.39 53.64 2025 18,223 IN
H3 80% $27.70 $7.70 $99.62 0 4,029 OUT
11 0% $0.00 $0.00 $0.00 0 69,384 OUT
12 4% $0.14 $0.00 $0.14 0 66,539 OUT
13 24% $3.30 $2.00 $21.98 16375 53,009 IN
14 35% $30.40 $10.70 $130.34 0 45,238 OUT
15 44% $209.10 $14.34 $343.04 0 39,133 OUT
16 49% $246.90 $79.00 $984.78 0 35,108 OUT
J1 0% $0.00 $0.00 $0.00 0 4,805 OUT
J2 9% $0.20 $0.00 $0.20 427 4,377 IN
J3 46% $0.00 $1.75 $16.35 0 2,595 OUT
J4 76% $40.90 $17.20 $201.55 0 1,158 OUT
J5 88% $750.40 $38.40 $1,109.07 0 577 OUT
K1 0% $0.00 $0.00 $0.00 0 265,000 OUT
K2 10% $16.74 $6.88 $81.00 0 238,500 OUT
K3 20% $33.48 $13.76 $162.00 0 212,000 OUT
KS 30% $50.22 $20.64 $243.00 0 185,500 OUT
K5 50% $83.70 $34.40 $405.01 132500 132,500 IN
L1 0% $0.00 $0.00 $0.00 0 175,000 OUT
L2 10% $62.30 $4.70 $106.20 0 157,500 OUT
L3 20% $124.60 $9.30 $211.47 0 140,000 OUT
L4 30% $186.90 $14.00 $317.66 52500 122,500 IN
5 50% $311.50 $23.40 $530.06 0 87,500 OUT
TABLE C.2 (continued)
TARGETED SO2 REMOVAL LEVEL (T/yr) 270,266
Control Options Emission Capital Operating Present Total SO2 SO2 Emiss- Comment
Chosen by Model Reduct’n Costs (M$) Cost (M $) Value (M $) Removal(T/yr) ions(T/yr)
M1 0% $0.00 $0.00 $0.00 100,000 OUT
0
M2 10% $14.30 $9.30 $101.17 0 90,000 OUT
M3 20% $23.40 $22.20 $230.76 0 80,000 OUT
M4 30% $30.30 $36.50 $371.22 0 70,000 OUT
M5 50% $42.50 $71.40 $709.40 0 50,000 OUT
N1 0% $0.00 $0.00 $0.00 0 125,000 OUT
N2 20% $22.50 $0.10 $23.43 25000 100,000 IN
N3 50% $27.20 $48.00 5475.54 0 62,500 OUT
Sub-Totals : $298.76 $62.93 $886.55 278,217 466,015
TARGETED SO2 REMOVAL LEVEL (T/yr) 270,266
Pre-specified Percent Capital Operating Present Total SO2 S02 Emiss- Comment
Control Options Reduction Costs (M$) Cost (M$) Value (M$) Removal (T/yr ions (T/yr)
re es eee eee eee
(not app.) 0% $0.00 $0.00 $0.00 0 0 OUT
(not app.) 0% $0.00 $0.00 $0.00 0 0 OUT
(not app.) 0% $0.00 $0.00 $0.00 0 0 OUT
Sub-Totals : $0.00 $0.00 $0.00 0 0
TOTALS: $298.76 $62.93 $886.55 278,217 466,015
Notes: Nominal interest rate (%) 13
Inflation rate (%) = 6
Time horizon (yr) = 15
C-8
The "Edit" option saves the output worksheet and calls up the input
worksheet for editing the data.
The "Calculation" option saves the output worksheet and calls up the
calculation worksheet. After the calculation worksheet is called up by
the output worksheet; the user can change the model parameters and rerun
the model with these new parameters.
Getting Started
This software requires that the user possess an IBM or 100% IBM compatible
PC, XT or AT machine and the Lotus 1-2-3 software version 2.0 or above by
Lotus Development Corporation. For further instructions regarding the
installation of the Lotus 1-2-3 program, the user should refer to the
1-2-3 reference manual.
Prior to running the model, the user should back up the original disks.
If you have a hard disk system, SARM can be copied onto the hard disk.
Running SARM from the hard disk speeds up the program operation.
& Diawtavté
AIORTATS po AMVOs LITLON
APPENDIX D
MOBILE SOURCE NOy CONTROLS
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The interpretation of control option data for mobile sources presented
particular problems. Status quo emissions for 1994 from this source,
amounting to 435,324 tonnes NO,, are based on estimates of 1985
emissions (Senes, 1989(a)) and do not incorporate existing Federal
regulations requiring 3-way calalytic converters on passenger vehicles
which took effect in 1987 (Maclaren, 1988).
This treatment differs from the treatment of regulations facing the large
point source emitters. The control option data from Maclaren (1988)
describe a do nothing case assuming pre 1987 conditions (their Case C),
the Federal regulation case (Case A) and a case involving even stricter
controls (Case C). Control option capital cost and emission reduction
data are presented as a time series extending from 1984 to 2002 showing
progressive reductions in emissions as new vehicles equipped with
catalytic converters replace old vehicles. Thus the format of control
option data for mobile sources did not conform to that of other sources
which had initial start-up capital costs and recurring operating costs.
Finally there were discrepancies in emissions data that could not be
reconciled. The status quo emissions for licensed vehicles is given
by Senes (1989(a), Table 6) as 326,603 tonnes but the corresponding value
from MacLaren (1988, Table 1) is either 250,066 tonnes for 1985 or 212,701
tonnes for 1994. Maclaren’s (1988) emission estimates for passenger
vehicles in 1994 appear not to be reconciled, being given as 95,468 tonnes
in Table 1 and 177,805 tonnes in Table 2.
Given the above noted difficulties, control option data were derived for
mobile sources by making the following assumptions:
. emission control efficiencies were based on percentage reductions
implied by data for 1994 from Maclaren (1988, Table 2):
Case A = 61%, Case B = 70%
. these emission reduction efficiencies were applied to the percentage of
Senes’ base case emissions for licenced vehicles representing passenger
vehicles in 1985 (percentage figures based on Maclaren 1988, Table 1):
326,603 tonnes x 75% = 244,952
- cost data were based on the following information from Maclaren (1988):
1987 cost/vehicle: Case A = $313 (updated from 1985 $)
Case B = $413
Emissions: Case C= 5.0g NO,/mile
Case A=1.0g NO,,/mile
B= 0.4 g N0,,/mile
Assuming a vehicle use rate of 12,000 miles/year, total capital cost
data per tonne of NO, removed annually are:
Case A $313/(12,000 mi x 4.0 g/mi x 10 6 g/t) = $6,521/T
Case B $413/(12,000 mi x 4.6 g/mi x 10~© gt)
$7,482/T
Final emission control data for mobile sources are:
Se
Emission Capital
Emissions Reduction Reduction Cost
(tonnes) Level (tonnes) (M $ 1987)
— eee
Base Case 244,952 = - =
Case A 95/7531: 61% 149,421 $ 974.37
Case B 73,486 70% 171,466 $1,282.91
a
Note that, when treated in this manner, there are no annual operating
costs; thus the present value of cost for mobile sources will be just the
Capital cost and this will not change with changes in interest rates or
the planning horizon. This is Clearly not an accurate way in which to
treat costs for this option but the treatment is adequate for purposes of
this study. Moreover it overcomes problems associated with the direct use
of Maclaren figures which do not lend themselves to a direct comparison
with Senes cost data.
The "life time" figures assumed for development of scenarios in Chapter 4
are not related to any vehicle life time assumptions made by Maclarens.
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