SELECTION OF AIR POLLUTION CONTROL TECHNOLOGIES FOR POWER PLANTS,

SELECTION OF AIR POLLUTION CONTROL TECHNOLOGIES FOR POWER PLANTS,
University of Pretoria etd, van Greunen L M (2006)
SELECTION OF AIR POLLUTION CONTROL
TECHNOLOGIES FOR POWER PLANTS,
GASIFICATION AND REFINING PROCESSES
By
Larey-Marié van Greunen
University of Pretoria etd, van Greunen L M (2006)
SELECTION OF AIR POLLUTION CONTROL
TECHNOLOGIES FOR POWER PLANTS,
GASIFICATION AND REFINING PROCESSES
By
Larey-Marié van Greunen
Submitted in partial fulfilment of the requirements for the degree
MASTER OF ENGINEERING
(Environmental Engineering)
in the
Faculty of Engineering, Built Environment and Information Technology
University of Pretoria
December 2005
University of Pretoria etd, van Greunen L M (2006)
Declaration by Student
I, LAREY-MARIÉ VAN GREUNEN, hereby declare that the work as contained in this
document was compiled and set out by myself and it has not been submitted to any
other university.
SIGNED ON THE ____________ DAY OF DECEMBER 2005.
LAREY-MARIÉ VAN GREUNEN
University of Pretoria etd, van Greunen L M (2006)
To Anna-Mart
Thank you for inspiring me
University of Pretoria etd, van Greunen L M (2006)
ACKNOWLEDGEMENTS
I would like to thank God, my heavenly Father, without Him I probably would have given
up long ago. Thank you for the privilege to learn and work in a field that gives me great
joy and for opening up my eyes to the greatness of your creation.
Thank you Mom and Dad, for your continuous support, encouragement and love over
the past six years. I would not be the person I am today or achieved what I have
achieved without your continuous input in my life.
Thank you Julian and Jacques, for always being there, and for your patience when I did
not always understand when you were trying to explain.
To all my friends, thank you for just being there and for the unknowing support that you
provided.
Lastly I would like to thank Francois for making this thesis possible and for always
reminding me that life is easy.
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University of Pretoria etd, van Greunen L M (2006)
Selection of air pollution control technologies for
power plants, gasification and refining processes
Author:
L van Greunen
Supervisor:
JFC Friend
Department:
Chemical Engineering
Degree:
MEng (Environmental Engineering)
SYNOPSIS
Air quality legislation in South Africa is entering a transformation phase, shifting the
concept of atmospheric emission control towards pollution prevention and emission
minimisation through a more integrated approach.
This transformation, along with
public pressure and increased foreign trade, is providing industries with incentives to
consider their effect on the environment and to take action where required. To assist
South African industries in determining what air pollution control technologies are best
suited to power plants, gasification and refining processes in South Africa; an
assessment of air pollution control technologies used in other countries was carried out.
This assessment concluded that the best available technologies for power plants to
control air emissions are electrostatic precipitators, low-NOx burners, selective catalytic
reduction systems and wet flue gas desulphurisation (limestone) systems.
For
gasification processes it was found that the main air pollution contributor is the gas
handling and treatment process. Releases from this process are controlled through
dust collection, wet scrubbing, conversion of sulphide compounds, sulphur recovery and
the incineration of final vent gases before release to the atmosphere.
For refining
processes the catalytic cracking unit is normally the largest single air emission source
and controlling emissions from this unit avoids controlling multiple minor sources.
Emissions from this unit are controlled via wet scrubbing, selective catalytic reduction
systems and carbon monoxide boilers.
An assessment of the financial effects
associated with air pollution control at power plants was conducted by completing a cost
analysis. This analysis demonstrated that by increasing capital expenditure on control
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technologies by R 1,7 billion, the external costs associated with producing electricity can
be reduced by almost R 3,4 billion.
Formulation of external cost factors for South
African conditions, and the development of a software database for the information
obtained from the different countries, will promote future technology selections.
KEYWORDS:
air pollution control technology, power plant, gasification process,
refining process, cost analysis, external costs
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TABLE OF CONTENTS
PAGE
ACKNOWLEDGEMENTS....................................................................................
i
SYNOPSIS……………………………………………………………………………..
ii
TABLE OF CONTENTS…………………………………..…..……………………...
iv
LIST OF TABLES…………………………..……………………….………………...
viii
LIST OF FIGURES……………………………………………..……………………..
x
ABBREVIATIONS..……………………..…………………………………………..…
xi
NOMENCLATURE…………………...………………………………………………..
xii
CHAPTER 1 Introduction………………………………………..………………….
1-1
CHAPTER 2 Literature Survey…………………………………..……………...…
2-1
2.1 AIR POLLUTION LEGISLATION IN SOUTH AFRICA………………………..
2-1
2.2 INDUSTRIAL AIR POLLUTION CONTROL IN THE EUROPEAN UNION…
2-2
2.3 INDUSTRIAL AIR POLLUTION CONTROL IN THE UNITED KINGDOM….
2-3
2.4 INDUSTRIAL AIR POLLUTION CONTROL IN THE USA…………...……….
2.5 AIR POLLUTANTS……………...………………………………………………..
2-4
2-6
2.5.1 Particulate matter……..…………………………………………………...
2-6
2.5.2 Sulphur oxides………………..……………………………………………
2-6
2.5.3 Nitrogen oxides……………………...……………………………………..
2-7
2.5.4 Volatile organic compounds…………..………………………………….
2-8
2.5.5 Carbon monoxide……………………………...…………………………..
2-8
2.6 AIR POLLUTION CONTROL TECHNOLOGIES………………………………
2-9
2.6.1 Fuel switching……………………………………..……………………….
2-9
2.6.2 Fuel cleaning…………………………………………...…………………..
2-9
2.6.3 Cyclones………………………………………………..…………………..
2-10
2.6.4 Fabric filters……………………………………………...…………………
2-11
2.6.5 Electrostatic precipitators…………………………………...…………….
2-14
2.6.6 Wet scrubbers………………………………………………...……………
2-16
2.6.7 Flue gas desulphurisation……………………………………..………….
2-19
2.6.7.1 Wet systems…………………………………………………….…
2-19
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PAGE
2.6.7.2 Semi-dry systems………………………………………………...
2-21
2.6.7.3 Dry systems……………………………………….………………
2-22
2.6.8 Combustion modifications…………………………………...……………
2-23
2.6.8.1 Modification of operating conditions………………….…………
2-23
2.6.8.2 Low-NOx burners………………………………………….………
2-24
2.6.9 Flue gas treatment techniques………………………...…………………
2-25
2.6.9.1 Selective catalytic reduction……………………….…………….
2-26
2.6.9.2 Selective non-catalytic reduction…………………….………….
2-26
2.6.9.3 Adsorption…………………………………………………………
2-27
2.6.9.4 Wet absorption…………………………………………….………
2-27
2.6.10 Flares………………………………………………………………...…….
2-27
2.6.11 Thermal incinerators…………...……………………………….…..……
2-30
2.6.12 Catalytic oxidisers……………………...……………………..….………
2-31
2.6.13 Regenerative thermal oxidisers…………………………………………
2-32
2.7 GENERIC POLLUTANT CONTROL TECHNOLOGY………………………...
2-34
2.7.1 Particulate matter control…………………………………………...……..
2-34
2.7.2 Sulphur oxides control……………………………………………………..
2-35
2.7.3 Nitrogen oxides control…………………………………………………….
2-35
2.7.4 Volatile organic compounds control…………………………………...…
2-37
2.8 INDUSTRY SECTOR AIR POLLUTION CONTROL..………………………...
2-37
2.8.1 Coal-fired power plant…...………………………………………………...
2-38
2.8.2 Coal gasification……………...…………………………………………….
2-42
2.8.3 Petroleum refining…………...……………………………………………..
2-46
CHAPTER 3 Technology Selection………………………..……………………...
3-1
3.1 SELECTION PROCESS………………………………………………………….
3-1
3.2 COAL-FIRED POWER PLANT………………...………………………………..
3-1
3.3 COAL GASIFICATION…………………………....……………………………...
3-3
3.3.1 Materials handling…………………...……………………………………..
3-5
3.3.2 Gasification………………………………………………………………….
3-5
3.3.3 Gas purification and conversion…………...……………………………..
3-6
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PAGE
3.3.3.1 Liquid quenching………………………….……………………….
3-6
3.3.3.2 Particulate matter removal…………….…………………………
3-6
3.3.3.3 Acid gas streams……….…………………………………………
3-6
3.4 PETROLEUM REFINING………………...………………………………………
3-8
3.4.1 General volatile organic compounds control…………………………….
3-8
3.4.2 Catalytic cracking unit……………………………………………...……...
3-9
3.4.3 Coke production unit……………………………………………………….
3-10
3.4.4 Bitumen production unit……………………………………………………
3-10
3.4.5 Visbreaking unit………………………………………………………...…..
3-11
3.4.6 Hydrogen fluoride alkylation unit………………………………………….
3-11
3.4.7 Sulphur recovery unit………………………………………………………
3-12
3.4.8 Distillation units……………………………………………………………..
3-12
3.4.9 Handling and storage of feedstock and products……………………….
3-13
CHAPTER 4 Cost Analysis………………………………………..………………..
4-1
4.1 BACKGROUND………...…………………………………………………………
4-1
4.2 THE EEGECOST MODEL…………………………………………..…………...
4-2
4.3 COST ANALYSIS PROCEDURE…………………………...…………………..
4-5
4.3.1 Equipment costs……...…………………………………………………….
4-8
4.3.1.1 Electrostatic precipitator…….……………………………………
4-8
4.3.1.2 Fabric filter……………………….………………………………...
4-9
4.3.1.3 Low-NOx burners…………………….……………………………
4-11
4.3.1.4 Selective catalytic reduction system………….…………………
4-11
4.3.1.5 Wet flue gas desulphurisation with limestone………….………
4-11
4.3.2 Life cycle assessment……...……………………………………………...
4-12
4.3.3 External costs……………………...……………………………………….
4-13
4.3.4 Other costs…………………………...……………………………………..
4-14
4.3.4.1 Insurance for environmental liabilities…….…………………….
4-14
4.3.4.2 Provisions for environmental management……………….……
4-15
4.3.4.3 Research and development………………………….…………..
4-15
4.3.4.4 General direct costs…………………………………….………...
4-15
4.4 COST ANALYSIS RESULTS…………………………………………………….
4-16
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PAGE
CHAPTER 5 Conclusion and Recommendations…………...………………….
5-1
References……………………………………………………………………………..
R-1
APPENDIX A Cost Calculations………………...……………………..…………..
A-1
EQUIPMENT COSTS………………..………………………………………………..
A-1
Electrostatic precipitator…………………………………………………………..
A-1
Fabric filter……………………………………………………………………..….
A-3
Low-NOx burners……………………………………………………………..…..
A-4
Selective catalytic reduction system………………………………………...….
A-5
Wet flue gas desulphurisation with limestone………………………………….
A-5
LIFE CYCLE ASSESSMENT………………………..……………………………….
A-6
EXTERNAL COSTS……………………………………...…………………………...
A-8
OTHER COSTS………………………………………………..………………………
A-9
Insurance for Environmental Liabilities………………………………...……….
A-9
Provisions for Environmental Management……………………………...…….
A-10
Research and Development……………………………………………………..
A-10
General Direct Costs……………………………………………………...……...
A-10
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LIST OF TABLES
Table 2.1
Summary of major air pollution control technologies.
Table 2.2
Once-through and regenerable FGD processes.
Table 2.3
Air pollution control technologies for the prevention and control of PM from
coal-fired power plants.
Table 2.4
Air pollution control technologies for the prevention and control of SOx
from coal-fired power plants.
Table 2.5
Air pollution control technologies for the prevention and control of NOx
from coal-fired power plants.
Table 2.6
Air pollution control technologies for the prevention and control of CO from
coal-fired power plants.
Table 2.7
Air pollution control technologies for the prevention and control of heavy
metals from coal-fired power plants.
Table 2.8
Air pollution control technologies for the prevention and control of
hydrogen chloride and hydrogen fluoride from coal fired power plants.
Table 2.9
Air emissions associated with gasification processes.
Table 2.10
Air pollution control technologies for the prevention and control of air
pollutants during raw materials, storage and handling (includes slag/ash
handling).
Table 2-11
Air pollution control technologies or methods for the prevention and control
of air pollutants from a gasification unit.
Table 2.12
Air pollution control technologies for the prevention and control of air
pollutants from a gas purification and conversion unit.
Table 2.13
Five categories of a general refinery.
Table 2.14
Significant refinery air emission sources and their associated air
pollutants.
Table 2.15
Air pollution control technologies for the prevention and control of VOC
emissions (General VOC controls).
Table 2.16
Air pollution control technologies for the prevention and control of air
pollutants from a catalytic cracking and a catalytic reforming unit.
Table 2.17
Air pollution control technologies for the prevention and control of air
pollutants from a coke production unit.
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Table 2.18
Air pollution control technologies for the prevention and control of air
pollutants from a bitumen production unit.
Table 2.19
Air pollution control technologies for the prevention and control of air
pollutants from a visbreaking unit.
Table 2.20
Air pollution control technologies for the prevention and control of air
pollutants from an HF alkylation unit.
Table 2.21
Air pollution control technologies for the prevention and control of air
pollutants from a sulphur recovery unit (SRU).
Table 2.22
Air pollution control technologies for the prevention and control of air
pollutants from distillation units.
Table 2.23
Air pollution control technologies for the prevention and control of air
pollutants from the loading, handling and storage of feedstocks and
products.
Table 4.1
Marshall and Swift equipment cost indices.
Table 4.2
Exchange rates on 3 November 2003.
Table 4.3
LCA data for one production year of a 3600 MW coal-fired power plant.
Table 4.4
Estimated damage costs in 1998 per ton pollutant emitted.
Table 4.5
Estimated damage costs in 2003 per ton pollutant emitted.
Table 4.6
Estimated damage costs for South Africa in Rand per ton pollutant
emitted.
Table A.1
Operating statistics for a 3600 MW power plant.
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LIST OF FIGURES
Figure 2.1
Schematic diagram of a typical cyclone.
Figure 2.2
Typical reverse-air baghouse.
Figure 2.3
Typical shaker baghouse.
Figure 2.4
Typical pulse-jet baghouse.
Figure 2.5
Schematic diagram of the side view of an electrostatic precipitator.
Figure 2.6
Schematic diagram of a spray chamber/tower.
Figure 2.7
Wet flue gas desulphurisation absorber tower.
Figure 2.8
Dry scrubber module.
Figure 2.9
Schematic diagram of a low-NOx burner.
Figure 2.10 Schematic flow diagram of a selective catalytic reduction system.
Figure 2.11 Steam-assisted elevated flare system.
Figure 2.12 Generalised flow diagram of a power plant and its associated processes.
Figure 2.13 An example of the gasification process during synthetic fuel refining and/or
chemical manufacturing.
Figure 2.14 Schematic flow diagram of an oil refinery process.
Figure 3.1
Schematic diagram of the selected control technologies for the control of
air pollution from a coal-fired power plant.
Figure 3.2
Gas treating units for coal gasification.
Figure 3.3
Schematic diagram summarising the selected air pollution control
technologies for petroleum refining.
Figure 4.1
Structure of the EEGECOST model.
Figure 4.2
Photo of a 3600 MW coal-fired power plant consisting of six 600 MW units.
Figure 4.3
Percentage contribution by cost type for a coal-fired power plant with
Control regime 1 in place.
Figure 4.4
Percentage contribution by cost type for a coal-fired power plant with
Control regime 2 in place.
Figure 4.5
Percentage contribution by cost type for a coal-fired power plant with
Control regime 3 in place.
Figure 4.6
Cost incurred by type for the three different control regimes.
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ABBREVIATIONS
APPA
Atmospheric Pollution Prevention Act
AQA
Air Quality Act
EU
European Union
BAT
Best Available Techniques
IPPC
Integrated Pollution Prevention and Control
BREF
Best Available Technique Reference
IPC
Integrated Pollution Control
EA
Environmental Agency
BATNEEC
Best Available Techniques Not Entailing Excessive Cost
UK
United Kingdom
PPC
Pollution Prevention and Control
USA
United States of America
CAA
Clean Air Act
USEPA
United States Environmental Protection Agency
CAAA
Clean Air Act Amendments
NSR
New Source Review
RACT
Reasonable Available Control Technology
BACT
Best Available Control Technology
LAER
Lowest Achievable Emission Rate
RBLC
RACT/BACT/LAER/ Clearinghouse
ESP(s)
Electrostatic precipitator(s)
FGD
Flue gas desulphurisation
LSFO
Limestone forced oxidation
LEA
Low-excess-air firing
FGT
Flue gas treatment
SCR
Selective catalytic reduction
SNCR
Selective non-catalytic reduction
FCC
Fluidised catalytic cracker
LDAR
Leak detection and repair programme
EEGECOST
Environmental Engineering Group environmental costing model
LCA
Life cycle assessment
TCA
Total cost assessment
DEC
Delivered equipment cost
TIC
Total installed cost
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NOMENCLATURE
PM
particulate matter
SOx
sulphur oxides
SO2
sulphur dioxide
SO3
sulphur trioxide
NOx
nitrogen oxides
N2
nitrogen
O2
oxygen
NO
nitrogen oxide
NO2
nitrogen dioxide
VOC(s)
volatile organic compound(s)
COx
carbon oxides
CO
carbon monoxide
NH3
ammonia
H2SO4
sulphuric acid
HCl
hydrogen chloride
HF
hydrogen fluoride
H2
hydrogen
H2O
water
COS
carbonyl sulphide
CS2
carbon disulphide
NaOH
sodium hydroxide
KOH
potassium hydroxide
A
nett plate area [m2 or ft2]
Q
volumetric gas flow rate [m3/min or ft3/min]
η
collection efficiency
we
drift velocity [m/min or ft/min]
P
purchase cost
a,b
constants used calculations
DEC
delivered equipment cost
TIC
total installed cost
CI
cost index
C
capacity of equipment
V
maximum filtering velocity [m/min or ft/min]
GCA
gross cloth area [m2 or ft2]
BBP
basic baghouse price
SSA
stainless-steel add-on
BP
bag price
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Chapter 1
Introduction
CHAPTER 1
Introduction
Since 1965 air pollution in South Africa was controlled according to the Atmospheric
Pollution Prevention Act (No 45 of 1965). This legislation had a source-based approach
to emission control that did not take into account the receiving environment and did not
sufficiently manage air quality; resulting in the development of air pollution hot spots,
amongst others. In order to address these shortcomings the new Air Quality Act (or
National Environment Management Act: Air Quality) was promulgated in 2005, thereby
effectively replacing the old Air Pollution Prevention Act. The new Air Quality Act will
present new challenges to South African companies, as the approach to air pollution
control is completely different from the previous Air Pollution Prevention Act, focusing
on ambient air quality rather than emission controls. Companies will therefore have to
consider how this new approach affects their planning for air pollution control on new
projects, as well as existing ones; as the new act will impose far stricter regulations on
companies and far heftier fines for noncompliance than have ever been in place before.
One problem faced in South Africa, when compared to developed countries where
similar air quality regulations have been imposed, is the lack of resources available to
the Government and Agencies responsible for air quality issues. However, even though
local government has done little in the way of monitoring air pollution or enforcing
legislation, South African industries are acquiring more foreign shareholders and are
trading more often on foreign markets.
Since these markets require certain
environmental standards, it provides incentives for South African industries to consider
their effect on the environment and to take action where required.
For South Africa to successfully implement the new act, it is important that knowledge is
gained from other countries on what practices have proven most successful and require
the least resources to implement, so that these can be adopted by South African
industries.
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Chapter 1
Introduction
The objectives of this investigation are to:
•
assess current literature available on Reasonable Available Control Technology
(RACT), Best Available Technique (BAT) and control technologies used by
industries in other counties;
•
identify the best available practices for power plants, gasification and refining
processes; and
•
conduct a cost benefit analysis for a power plant to assess the impact of
implementing selected air pollution control technologies on external costs associated
with power plants.
A literature study in Chapter 2 will critically evaluate RACT, BAT and control
technologies used by industries in the United States, the United Kingdom and other
European countries. The best practices that are related to power plants, gasification
and refining processes will be sourced out in Chapter 3, with a cost benefit analysis on
the identified practices for a power plant completed in Chapter 4. Final conclusions and
recommendations based on this investigation will be presented in Chapter 5.
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Chapter 2
Literature Survey
CHAPTER 2
Literature Survey
2.1 AIR POLLUTION LEGISLATION IN SOUTH AFRICA
The Atmospheric Pollution Prevention Act (Act No. 45 of 1965), also known as APPA,
has been used to control air pollution in South Africa since the mid 1960’s. APPA was
based on the 1915 British legislation (Groenewald, 2005) and used a source-based
approach to emission control (Mabalane, 2005). It exercised source control mainly on
industrial sources and was confined to the 72 scheduled processes listed in Schedule 2
of the act.
No formal ambient air emission limits or standards were established
(Kornelius, 2005) and there was a lack of compliance, enforcement mechanisms and
transparency during decision-making. APPA has also long been outdated in terms of
the roles of provincial and local government (Joubert, 2005).
With the publishing of a notice on 11 September 2005 in the Government Gazette, most
sections of the new National Environmental Management: Air Quality Act (AQA) are
brought into effect – exactly four years after its first draft was conceived (DEAT, 2005).
However, the most important sections have not yet been brought into effect.
AQA defines a new approach to air quality management in South Africa, shifting the
concept of atmospheric emission control towards pollution prevention, emission
minimisation, cross-media integration, vertical and horisontal integration in institutions
and spheres of Government, and the involvement of all sectors of society in air quality
management (Mabalane, 2005).
The AQA will impose far stricter regulations on
companies and far heftier fines for non-compliance than have ever been in place before
(Kornelius, 2005).
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Chapter 2
Literature Survey
AQA will present new challenges to South African companies, as the approach is
completely different from APPA. Companies will thus have to consider how this new
approach affects their planning for air pollution control on new projects, as well as
existing plants. (Kornelius, 2005)
2.2 INDUSTRIAL AIR POLLUTION CONTROL IN THE EUROPEAN UNION
In the European Union (EU) control of industrial air pollution is accomplished through
the use of Best Available Techniques (BAT), as recommended by the Integrated
Pollution Prevention and Control (IPPC) directive EC/96/61 (Hafker, Poot and
Quedeville, 2003).
The IPPC directive (EC/96/61) requires member states of the EU to issue operating
permits to certain installations carrying on industrial activities.
The purpose of the
directive is to introduce a more integrated approach to pollution control from industries.
The directive promotes the use of BAT for reducing emissions of specified pollutants
and is already in force for new installations, as well as for significant modifications or
upgrades.
However it does not apply to existing installations until October 2007.
(Hafker et al., 2003)
The directive states that to achieve the required level of protection of the environment,
Best Available Techniques (BAT) is to be used. BAT is not a fixed concept and in any
particular case, BAT has to be determined taking into account a number of factors,
including cost and benefit. (Hafker et al., 2003)
The directive requires that a process of information exchange takes place between the
main stakeholders. The outcome of this exchange is the production of a Best Available
Technique Reference (BREF) document for each major industrial sector.
These
documents are intended to give guidance to regulators on each sector and its
emissions, the levels of pollution abatement achievable, the cross-media implications,
energy use, costs, etc. (Hafker et al., 2003)
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Chapter 2
Literature Survey
Best Available Technique Reference documents for, inter alia, large power plants, large
volume organic chemical industries and mineral oil refineries are available from the
European IPPC Bureau (European IPPC Bureau, 2005b).
2.3 INDUSTRIAL AIR POLLUTION CONTROL IN THE UNITED KINGDOM
The Environmental Protection Act of 1990 established the Integrated Pollution Control
(IPC) regulations, which resulted in the formation of the United Kingdom’s
Environmental Agency (EA). The EA controlled industrial air pollution by using Best
Available Techniques Not Entailing Excessive Cost (BATNEEC), as described in the
Chief Inspectorate’s guidance notes (Kornelius and Munn, 2002). Currently the system
in the United Kingdom is undergoing considerable changes as a result of the directives
being issued by the EU that have to be adopted by member states.
At present an authorisation is required before an industrial plant can be operated.
When considering an application for authorisation, an EA inspector will take local
conditions into account before deciding on the applicable BATNEEC, whereafter the EA
is obliged to issue a permit/license if all of its technical requirements are met. (Kornelius
and Munn, 2002)
The Chief Inspector’s guidance notes are issued by the Chief Inspector of Her Majesty’s
Inspectorate of Pollution (HMIP) for processes prescribed by the IPC regulations. The
notes serve as a guide to inspectors on standards and techniques during their
assessment of an application for, or variation of, an authorisation. The notes provide
guidance on the best available techniques and standards without any consideration of
the site-specific issues. Guidance is given on the achievable release levels for new
processes, applying the best combination of techniques to limit environmental impacts.
(HMIP, 1995a)
In order to comply with the EU directive EC/96/61, the UK government passed the
Pollution Prevention and Control (PPC) regulations during 2000 (effective from 1 August
2000). These regulations are superseding the provisions of IPC sector-by-sector, using
a transitional timetable concluding in 2007. The PPC regulations relate to installations
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Chapter 2
Literature Survey
in England and Wales and create a coherent new framework to prevent and control
pollution from certain industrial activities and introducing the concept of BAT to
environmental regulations. As a consequence the Chief Inspector's guidance notes are
being gradually superseded by PPC guidance produced by the EA. (DEFRA, 2005)
Chief Inspector’s guidance notes are available from the United Kingdom’s
Environmental Agency for, inter alia, power plants, gasification and refining processes.
However, at present there is no final PPC guidance available for refineries or other
similar sectors. These PPC guidance documents are currently in a consultation phase.
Therefore, Chief Inspector’s guidance notes, based on the IPC regulations in these
sectors, are still in use. (Demain, 2005)
2.4 INDUSTRIAL AIR POLLUTION CONTROL IN THE USA
Industrial air pollution is controlled in the United States of America (USA) through the
Clean Air Act (CAA) of 1977 and its 1990 Amendments. The act is enacted through the
work of the United States’ Environmental Protection Agency (USEPA).
The 1990 Clean Air Act Amendments (CAAA), the first major revision of the 1977 CAA,
was signed in November 1990. One of the major breakthroughs of the 1990 CAA is a
permit programme for larger sources that release pollutants into the air. Permits are
issued by states or, when a state fails to carry out the CAA satisfactorily, by USEPA.
The permit includes information on which pollutants are being released, how much may
be released, and what kinds of steps the source's owner or operator is taking to reduce
pollution, including plans to monitor the pollution. Businesses seeking permits have to
pay permit fees, the money from the fees help pay for state air pollution control
activities. (USEPA, 1993a)
In passing the CAA in 1977, the USA congress included a "grandfathering" loophole
that allowed older power plants to avoid meeting the modern pollution control standards
that new facilities had to adopt. Such a loophole was permitted with the expectation
that these "grandfathered" facilities would soon retire and be replaced by cleaner, newer
plants. However, the majority of these older plants are still in operation today. In an
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effort to limit the abuse of the "grandfathering" loophole congress created a key
provision in the CAA known as "New Source Review" (NSR). This provision treats
"grandfathered" power plants as "new sources" when they expand or significantly
modify their facilities. It requires them to either prevent additional pollution by offsetting
any increases with reductions in other sources at the same plant site, or obtain a clean
air permit demonstrating that the best available pollution control technology has been
installed. The NSR is triggered only when plants expand capacity or significantly modify
their facilities. (Sierra Club, 2005)
The RBLC database, also known as the RACT/BACT/LAER clearinghouse database,
was established by the USEPA to provide a central database of air pollution control
technology information. The terms RACT, BACT and LAER are acronyms for different
programme requirements under the NSR provision and are defined as (USEPA, 2005a):
•
Reasonably Available Control Technology (RACT) is required on existing sources in
areas that are not meeting National Ambient Air Quality Standards (NAAQS) (nonattainment areas).
•
Best Available Control Technology (BACT) is required on major new or modified
sources in clean areas (attainment areas).
•
Lowest Achievable Emission Rate (LAER) is required on major new or modified
sources in non-attainment areas.
The RBLC database includes past RACT, BACT and LAER decisions contained in NSR
permits.
The RBLC database promotes sharing of information between permitting
agencies and assists in future permit determinations.
The RBLC permit database
contains over 5 000 determinations that assist in identifying technologies to mitigate
most air pollutant emission streams. (van der Walt, 2005; USEPA, 2005a)
Information available from the RBLC database is not as comprehensive as the
information from the EU and the UK, since the information in the database is not a
complete set of guidelines.
However, the information might be considered more
valuable as the database supplies actual records of identified air pollution control
technologies already used.
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2.5 AIR POLLUTANTS
There is a vast number of air pollutants associated with industries, each having certain
pollutants in higher concentration than others.
Air pollutants from industries vary
depending on the product, the process and even the geography of the particular
industry. The following air pollutants are discussed regardless of product or process, as
most major industries emit high amounts of these pollutants.
2.5.1 Particulate matter
Particulate matter (PM) are very-small-diameter solids or liquids, it includes dust, dirt,
soot, smoke and liquid droplets. PM-10 refers specifically to particulate matter less than
10 µm in diameter. PM are caused by either materials-handling processes, combustion
processes or through gas conversion reactions between other pollutants. Sources of
PM include industrial processes, power plants (oil-, gas- and coal combustion), motor
vehicles, unpaved roads and other smaller forms of fuel combustion. (Cooper and Alley,
2002; USEPA, 2005b)
PM can affect visibility (smog and haze), can cause damage to buildings and other
materials through erosion and corrosion, and can also lead to alterations in local
weather patterns. Scientific studies have also shown that PM could be responsible for a
wide variety of health problems, ranging from aggravated asthma, chronic bronchitis,
decreased lung function and premature death. (Cooper and Alley, 2002; USEPA,
2005b)
2.5.2 Sulphur oxides
Sulphur oxides (SOx) are formed when sulphur or any material containing sulphur is
combusted. Sources of SOx include fossil-fuel power plants, petroleum refining and
nonferrous metal smelting, with the greatest contributor being fossil-fuel combustion.
(Cooper and Alley, 2002; USEPA, 2005b)
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Sulphur dioxide (SO2) makes up the most part of SOx emissions but sulphur trioxide
(SO3) is also formed. Both SO2 and SO3 dissolve readily in water, and form acids when
hydrolysed with water. These acids can have serious effects on the environment such
as corrosion, damaged crops and forests, changes in soil makeup, and acidity of lakes
and rivers. Other effects include reduced visibility due to the formation of smog and
haze. SO2 is also associated with human health problems. Children, the elderly and
people with existing respiratory and heart disorders are more at risk from the effects of
SO2. The effects of SO2 are intensified in the presence of other pollutants like PM by
forming tiny sulphate particles - these particles are associated with increased
respiratory symptoms and disease, difficulty in breathing and premature death. (Cooper
and Alley, 2002; USEPA, 2005b)
2.5.3 Nitrogen oxides
Nitrogen oxides (NOx) are a group of gases containing nitrogen and oxygen in varying
amounts. NOx are formed at high temperatures when nitrogen (N2) and oxygen (O2),
both present in air, combine to form nitrogen oxide (NO) and nitrogen dioxide (NO2)
during the combustion of fuel in the presence of air. Organically bound nitrogen present
in fuels also contributes to total NOx emissions. Main sources of NOx include motor
vehicles, power plants, and other industrial, commercial and residential sources that
burn fuels. Bacterial processes present in soil can also contribute to total NOx. (Cooper
and Alley, 2002; USEPA, 2005b)
NOx emissions lead to smog formation and can damage crops and forests. Increased
NOx loading to water bodies can lead to chemical imbalances of nutrients present in
water, and the additional nitrogen also accelerates eutrophication. As with SOx, NOx
dissolve readily in water in the atmosphere to form acids, which fall to earth as rain, fog,
snow or dry particles. NOx also acts as a greenhouse gas. Human health effects
associated with NOx include problems associated with the respiratory system, damage
to lung tissue and premature death. Small particles penetrate deeply into sensitive
parts of the lungs and can cause or worsen respiratory diseases such as emphysema
and bronchitis, and aggravate existing heart disease. (Cooper and Alley, 2002; USEPA,
2005b)
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2.5.4 Volatile organic compounds
Volatile organic compounds (VOCs) are organic compounds with appreciable vapour
pressures, they are emitted as gasses from certain solids and liquids. VOCs make up a
large part of emitted air pollutants, it includes pure hydrocarbons, partially oxidised
hydrocarbons (organic acids, aldehydes, ketones), as well as organics containing
chlorine, sulphur, and nitrogen.
VOCs therefore represent a class of pollutants
consisting of hundreds of compounds.
Sources of VOCs include combustion
processes, solvent evaporation, refining and handling of petroleum, surface coating
operations and the paint and coating industry. (Cooper and Alley, 2002; USEPA, 2004)
Health effects will depend on the specific VOC compound exposure.
Symptoms
experienced shortly after exposure include headaches, dizziness, visual impairment and
eye and respiratory tract irritation. Long-term exposure could result in cancer, liver,
kidney and central nervous system damage. VOCs also play an important part in the
formation of photochemical oxidants such as ozone (O3). Photochemical oxidants are
formed in the ambient atmosphere by a complex series of reactions that involve NOx
and VOCs. Oxidants like O3 can lead to severe eye and respiratory tract irritation, and
the deterioration of paints, rubbers and other materials. Leaf discolouration and cell
collapse in plants are also associated with oxidant exposure. (Cooper and Alley, 2002;
USEPA, 2004)
2.5.5 Carbon monoxide
Carbon monoxide (CO) is a colourless, odourless, tasteless gas that is caused by the
incomplete combustion of any carbonaceous fuel. With power plants and other large
furnaces usually designed and operated to ensure near complete combustion, the major
source of CO is from the transportation sector. However, residential heating accounts
for a significant fraction of total CO emissions, as do certain industrial processes.
(Cooper and Alley, 2002)
CO is essentially inert to plants or materials but can have significant effects on human
health.
CO reacts with the haemoglobin in blood to prevent oxygen transfer.
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Depending on the concentration of CO and the time of exposure, effects on humans
range from slight headaches to nausea to death. (Cooper and Alley, 2002)
2.6 AIR POLLUTION CONTROL TECHNOLOGIES
2.6.1 Fuel switching
PM, SOx and NOx emissions can be reduced by switching to cleaner fuels. Sulphur
emissions are proportional to the sulphur content of the fuel and fuels containing
organically bound nitrogen can contribute over 50% of the NOx total emissions.
Natural gas used as fuel can emit 60% less NOx than coal and virtually no PM or SOx.
Burning either low-sulphur oil, or low-sulphur coal, can also effectively reduce SOx
emissions. Oil-based processes and low-ash fossil fuels emit significantly less PM than
coal-fired combustion processes with high ash content coal. Also, lighter distillate oilbased combustion results in lower levels of PM emissions than heavier residual oils.
(World Bank, 1999)
2.6.2 Fuel cleaning
The most significant option for reducing the sulphur content of fuel is called
beneficiation. Up to 70% of the sulphur in high-sulphur coal is in pyretic or mineral
sulphate form, not chemically bonded to the coal. Coal beneficiation can remove 50%
of pyretic sulphur and 20-30% of total sulphur (it is not effective in removing organic
sulphur). Beneficiation also removes ash responsible for particulate emissions. This
approach may in some cases be cost-effective in controlling emissions of SOx, but it
may generate large quantities of solid waste and acid wastewaters that must be
properly treated and disposed off. (World Bank, 1999)
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2.6.3 Cyclones
Cyclone separators are one of the most widely used of all industrial gas-cleaning
devices.
The main reasons for the widespread use of cyclones are that they are
inexpensive to purchase, they have no moving parts, and they can be constructed to
withstand harsh operating conditions.
Typically, a particulate-laden gas enters
tangentially near the top of the cyclone as shown schematically in Figure 2.1. Cyclones
operate by creating a double vortex inside the cyclone body. The gas flow is forced into
downward spiral simply because of the cyclone’s shape and the tangential entry.
Centrifugal force and inertia cause the particles to move outward, collide with the outer
wall, and then slide downward to the bottom of the device. Near the bottom of the
cyclone, the gas reverses its downward spiral and moves upward in a smaller, inner
spiral. The cleaned gas exists from the top and the particles exit from the bottom of the
cyclone. (Cooper and Alley, 2002; USEPA, 1998a; World Bank, 1999)
Cyclones by themselves are generally not adequate to meet stringent air pollution
regulations, they are however, ideal for use as precleaners for more expensive final
control devices such as baghouses or electrostatic precipitators.
Efficiency varies
greatly with particle size and with cyclone design. Some manufacturers have advertised
cyclones that routinely achieve 90% or greater efficiency for particles larger than 10
microns. The fine-dust-removal efficiency of cyclones is typically below 70%. Generally
as efficiencies increase, capital and operating costs increase. Cyclone collectors can
be designed for many applications, and they are typically categorised as either high
efficiency, conventional, or high throughput. (Cooper and Alley, 2002; USEPA, 1998a;
World Bank, 1999)
Advantages of using cyclones include (Cooper and Alley, 2002; USEPA, 1998a; World
Bank, 1999):
•
low capital cost,
•
ability to operate at high temperatures, and
•
low maintenance requirements because there are no moving parts.
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Disadvantages of using cyclones include (Cooper and Alley, 2002; USEPA, 1998a;
World Bank, 1999):
•
low efficiencies especially for very small particles, and
•
high operating costs due to pressure drop.
Figure 2.1 Schematic diagram of a typical cyclone.
(Source: USEPA, 1998b.)
2.6.4 Fabric filters
Fabric filtration is a well-known and accepted method for separating dry particles from a
gas stream. In fabric filtration, the dusty gas flows into and through a number of filter
bags placed in parallel, leaving the dust retained by the fabric. The fabric itself does
some filtering of the particles, however, the fabric is more important in its role as a
support medium for the layer of dust that quickly accumulates on it. The dust layer is
responsible for the highly efficient filtering of small particles for which baghouses are
known. Fabric filters are efficient (99,9% removal) for both high and low concentrations
of particles; but are suitable only for dry and free-flowing particles. Their efficiency in
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removing toxic metals such as arsenic, cadmium, chromium, lead, and nickel is greater
than 99%. (Cooper and Alley, 2002; USEPA, 1998a; World Bank, 1999)
The various types of filter media include woven fabric, needled felt, plastic, ceramic and
metal. The operating temperature of the baghouse gas influences the choice of fabric.
There are different ways of weaving them into various sizes of bags, different ways of
configuring bags in a baghouse, and different ways of flowing the air through the bags.
Extended operation of a baghouse requires that the dust be periodically cleaned of the
cloth surface and removed from the baghouse. The three common types of baghouses,
classified by the method used for cleaning the dust from the bags, are reverse-air
(Figure 2.2.), shaker (Figure 2.3), and pulse-jet (Figure 2.4) baghouses. (Cooper and
Alley, 2002; USEPA, 1998a; World Bank, 1999)
Advantages of using fabric filters include (Cooper and Alley, 2002; USEPA, 1998a;
World Bank, 1999):
•
very high collection efficiencies even for small particles,
•
operate on a wide variety of dust types,
•
modular in design, and modules can be pre-assembled at the factory,
•
operate over an extremely wide range of volumetric flow rates, and
•
require reasonably low-pressure drops.
Disadvantages of using fabric filters include (Cooper and Alley, 2002; USEPA, 1998a;
World Bank, 1999):
•
require large floor areas,
•
fabrics can be harmed by high temperature or corrosive chemicals,
•
cannot operate in moist environments, fabric can become “blinded”, and
•
have potential for fire or explosion.
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Figure 2.2 Typical reverse-air baghouse.
(Source: USEPA, 2002.)
Figure 2.3 Typical shaker baghouse.
(Source: USEPA, 2002.)
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Figure 2.4 Typical pulse-jet baghouse.
(Source: USEPA, 2002.)
2.6.5 Electrostatic precipitators
The process of electrostatic precipitation involves the ionisation of contaminated air
flowing between electrodes, the charging, migration, and collection of the contaminants
(particles) on oppositely charged plates, and the removal of the particles from the
plates.
The particles can either be dry dust or liquid droplets.
In an electrostatic
precipitator (ESP), air flows through the unit and the particles are left behind on the
plates (Figure 2.5). The particles are knocked off (rapped) or washed off the plates, and
collected at the bottom of an ESP. Electrostatic precipitators are unique among air
pollution control devices in that the forces of collection act only on the particles and not
on the entire air stream. This phenomenon typically results in high collection efficiency
with a very low air pressure drop. Modern ESPs have been designed for efficiencies
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greater than 99,9%. ESPs are especially efficient in collecting fine particulates and can
also capture trace emissions of some toxic metals with an efficiency of 99%. (Cooper
and Alley, 2002; USEPA, 1998a; World Bank, 1999)
Figure 2.5 Schematic diagram of the side view of an electrostatic precipitator.
(Source: Dayley and Holbert, 2003.)
Electrostatic precipitators are generally divided into two broad groups, dry ESPs and
wet ESPs. The distinction is based on what method is used to remove particulates from
the collecting electrodes. In addition to wet and dry options, there are variations of
internal ESP designs available. The two most common designs are wire-plate and wirepipe
collectors.
Electrostatic
precipitators
are
often
designed
with
several
compartments, to facilitate cleaning and maintenance. (Cooper and Alley, 2002;
USEPA, 1998a; World Bank, 1999)
Lower sulphur concentrations in the flue gas can lead to a decrease in collection
efficiency since it produces a high resistivity fly ash that is difficult to collect in an ESP.
Under these circumstances flue gas conditioning can be applied when ESPs are not
operating at design efficiencies. Flue gas conditioning can influence the electric field
strength, ion density, adhesive and cohesive properties of the fly ash, particle size and
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particle size distribution; all of which affects the collection efficiency of an ESP.
Common conditioning agents include sulphur trioxide (SO3), ammonia (NH3),
ammonium compounds, organic amines and dry alkalis. (Cooper and Alley, 2002;
USEPA, 1998a; World Bank, 1999)
Advantages of using ESPs include (Cooper and Alley, 2002; USEPA, 1998a; World
Bank, 1999):
•
very high efficiencies, even for very small particles,
•
can handle very large gas volumes with low pressure drop,
•
dry collection of valuable materials, or wet collection of fumes and mists,
•
can be designed for a wide range of gas temperatures, and
•
low operating costs, except at very high efficiencies.
Disadvantages of using ESPs include (Cooper and Alley, 2002; USEPA, 1998a; World
Bank, 1999):
•
high capital cost,
•
will not control gaseous emissions,
•
not very flexible, once installed, to changes in operating conditions,
•
large space requirements, and
•
might not work on particulates with very high electrical resistivity.
2.6.6 Wet scrubbers
Wet scrubbers are used in the control of particulates (see also Section 2.6.7) and rely
on direct and irreversible contact of a liquid (droplets, foam, or bubbles) with the
particulates.
Scrubbers can be very specialised and designed in many different
configurations. Wet scrubbers are generally classified by the method that is used to
induce contact between the liquid and the particulates, for example, spray, packed-bed
and plate scrubbers. Scrubbers are also often described as low-, medium-, or highenergy, where energy is often expressed as the pressure drop across a scrubber.
(Cooper and Alley, 2002; USEPA, 1998a; World Bank, 1999)
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The most common scrubber design is the introduction of liquid droplets into a spray
chamber (Figure 2.6), where the liquid is mixed with the gas stream to promote contact
with the particulates. In a packed-bed scrubber, layers of liquid are used to coat various
shapes of packing material that become impaction surfaces for the particle-laden gas.
Scrubber collection can also be achieved by forcing the gas at high velocities though a
liquid to form jet streams.
Liquids are also used to supersaturate the gas stream,
leading to particle scrubbing by condensation. (Cooper and Alley, 2002; USEPA, 1998a;
World Bank, 1999)
Figure 2.6 Schematic diagram of a spray chamber/tower.
(Source: USEPA, 2002.)
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The various wet scrubbers that can be used include (Cooper and Alley, 2002; USEPA,
1998a; World Bank, 1999):
•
spray chambers/towers,
•
packed-bed scrubbers,
•
impingement plate scrubbers,
•
mechanically-aided scrubbers,
•
venturi scrubbers,
•
orifice scrubbers,
•
condensation scrubbers,
•
charged scrubbers, and
•
fibre-bed scrubbers.
Advantages of using wet scrubbers include (Cooper and Alley, 2002; USEPA, 1998a;
World Bank, 1999):
•
can handle flammable and explosive dusts with little risk,
•
provides gas absorption and dust collection in a single unit,
•
can handle mists,
•
provide cooling of hot gases,
•
collection efficiency can be varied, and
•
corrosive gases and dusts can be neutralised.
Disadvantages of using wet scrubbers include(Cooper and Alley, 2002; USEPA, 1998a;
World Bank, 1999).:
•
high potential for corrosion problems;
•
effluent liquid can create water pollution problems;
•
protection against freezing required, off gas might require reheating to avoid visible
plume;
•
collected particulates may be contaminated and may not be recyclable; and
•
disposal of waste sludge may be very expensive.
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2.6.7 Flue gas desulphurisation
The flue gas desulphurisation (FGD) or SO2 scrubbing process typically uses a calcium
or sodium based alkaline reagent. The reagent is injected in the flue gas in a spray
tower or directly into the duct. The SO2 is absorbed, neutralised and/or oxidised by the
alkaline reagent into a solid compound, either calcium or sodium sulphate. The solid is
removed from the waste gas stream using downstream equipment. (USEPA, 2003a)
Scrubbers are classified as “once-through” or “regenerable”, based on how the solids
generated by the process are handled. Once-through systems either dispose of the
spent sorbent as a waste or utilise it as a by-product. Regenerable systems recycle the
sorbent back into the system. At present, regenerable processes have higher costs
than once-through processes, however, regenerable processes might be chosen if
space or disposal options are limited and markets for by-products (for example,
gypsum) are available. In 1998, approximately 3% of FGD systems installed in the USA
were regenerable.
Both types of systems, once-through and regenerable, can be
further categorised as wet, dry, or semi-dry (USEPA, 2003a).
2.6.7.1 Wet systems
In a wet scrubber system, flue gas is ducted to a spray tower/chamber where an
aqueous slurry of sorbent is injected into the flue gas (Figure 2.7). To provide good
contact between the waste gas and sorbent, the nozzles and injection locations are
designed to optimise the size and density of slurry droplets formed by the system. A
portion of the water in the slurry is evaporated and the waste gas stream becomes
saturated with water vapour. Sulphur dioxide dissolves into the slurry droplets where it
reacts with the alkaline particulates. The slurry falls to the bottom of the absorber where
it is collected.
Treated flue gas passes through a mist eliminator to remove any
entrained slurry droplets, before exiting the absorber. The absorber effluent is sent to a
reaction tank where the SO2-alkali reaction is completed forming a neutral salt. In a
regenerable system, the spent slurry is recycled back to the absorber. Once-through
systems dewater the spent slurry for disposal or use as a by-product. (USEPA, 2003a)
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Typical sorbent material is either limestone or lime. Limestone is very inexpensive but
control efficiencies for limestone systems are approximately 90%. Lime is easier to
manage on-site and has control efficiencies of up to 95%, but is significantly more
costly. (USEPA, 2003a)
Figure 2.7 Wet flue gas desulphurisation absorber tower.
(Source: Nolan, 2000.)
Oxidation of the slurry sorbent causes calcium sulphate (gypsum) scale to form in the
absorber.
Limestone forced oxidation (LSFO) is a newer process based on wet
limestone scrubbing that reduces scale. In LSFO, air is added to the reaction tank,
which oxidises the spent slurry to gypsum. The gypsum is removed from the reaction
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tank prior to the slurry being recycled to the absorber. The recycled slurry has a lower
concentration of gypsum and thus scale formation in the absorber is significantly
reduced. Gypsum can be commercially sold, eliminating the need for land filling of the
waste product. In addition to scale control, the larger size gypsum crystals formed in
LSFO settle and dewater more efficiently, reducing the size of the by-product handling
equipment. However, LSFO requires additional blowers, thereby increasing the capital
and operating costs of the system. (USEPA, 2003a)
Wet limestone/lime scrubbing has high capital and operating cost due to the handling of
liquid reagent and waste. Nonetheless, it is the preferred process for coal-fired power
plants burning coal due to the low cost of limestone and SO2 control efficiencies from
90% up to 98%. (USEPA, 2003a)
2.6.7.2 Semi-dry systems
Semi-dry systems, or spray dryers, inject an aqueous sorbent slurry similar to a wet
system, however, the slurry has a higher sorbent concentration. As the hot flue gas
mixes with the slurry solution, water from the slurry is evaporated. The water that
remains on the solid sorbent enhances the reaction with SO2. The process forms a dry
waste product that is collected with a standard particulate collection device, such as a
baghouse or electrostatic precipitator (ESP). The waste product can be disposed, sold
as a by-product or recycled to the slurry. (USEPA, 2003a)
Various calcium and sodium based reagents can be utilised as sorbent. Spray dry
chambers typically inject lime since it is more reactive than limestone and less
expensive than sodium based reagents. The reagent slurry is injected through either
rotary atomisers or dual-fluid nozzles, to create a finer droplet spray than wet scrubber
systems. (USEPA, 2003a)
The performance of a lime spray dry scrubber is more sensitive to operating conditions.
SO2 control efficiencies for spray dry scrubbers are slightly lower than wet systems,
between 80% and 90%. (USEPA, 2003a)
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2.6.7.3 Dry systems
Dry sorbent injection systems pneumatically inject powdered sorbent directly into either
the furnace, the economiser, downstream ductwork, or in a reaction chamber
(Figure 2.8). The dry waste product is removed using particulate control equipment
such as a baghouse or ESP. The flue gas is generally cooled prior to the entering the
particulate control device. Water can be injected upstream of the absorber to enhance
SO2 removal (USEPA, 2003a).
Figure 2.8 Dry scrubber module.
(Source: Nolan, 2000.)
Dry sorbent injection systems typically use calcium and sodium based alkaline
reagents.
A number of proprietary reagents are also available.
A typical injection
system uses several injection lances protruding from the furnace or duct walls. (USEPA,
2003a)
Dry scrubbers have significantly lower capital and operating costs than wet systems,
because they are simpler, demand less water and waste disposal is less complex. Dry
injection systems install easily and use less space, therefore, they are good candidates
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SO2 removal efficiencies are significantly lower than wet
systems, between 50% and 60% for calcium based sorbents.
Sodium based dry
sorbent injection into the duct can achieve up to 80% control efficiencies (USEPA,
2003a).
2.6.8 Combustion modifications
Combustion controls reduce NOx formation by one or more of the following strategies
(Cooper and Alley, 2002; World Bank, 1999):
•
reduced peak temperatures of the flame zone,
•
reduced gas residence time in the flame zone, and/or
•
reduced oxygen concentration in the flame zone.
The preceding changes to the combustion process can be achieved by either
modification of operating conditions on existing furnaces, or purchase and installation of
newly designed (low-NOx) burners and/or furnaces (Cooper and Alley, 2002; World
Bank, 1999).
2.6.8.1 Modification of operating conditions
•
Low-excess-air firing (LEA) is a very simple yet very effective technique. Owing to
less-than-perfect mixing of air and fuel, there must be some excess air present at all
times to ensure good fuel use and to prevent smoke formation. Currently, it is
possible to achieve full combustion for coal-fired units with less than 15-30% excess
air. (Cooper and Alley, 2002; World Bank, 1999)
•
Staged combustion (off-stoichiometric combustion) burns the fuel in two or more
steps. Staged combustion can be accomplished by firing some of the burners fuelrich and the rest fuel-lean, by taking some of the burners out of service and allowing
them only to admit air to the furnace, or by firing all the burners fuel-rich in the
primary combustion zone and admitting the remaining air over the top of the flame.
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Staged combustion techniques can reduce NOx emissions by 20-50%. (Cooper and
Alley, 2002; World Bank, 1999)
•
Flue gas recirculation is simply the rerouting of some of the flue gas back to the
furnace. Usually, flue gas from the economiser outlet is used, and so the furnace air
temperature and the furnace oxygen concentration are reduced simultaneously.
(Cooper and Alley, 2002; World Bank, 1999)
•
Gas reburning or reburning is when 75-80% of the furnace fuel input is burned in the
furnace with minimum excess air. The remaining fuel (gas, oil or coal) is added to
the furnace above the primary combustion zone. The secondary combustion zone is
operated substoichiometrically to generate hydrocarbon radicals that reduce the NOx
to N2. The combustion process is then completed by adding the balance of the
combustion air through an overfire air-port in a final burnout zone at the top of the
furnace. (Cooper and Alley, 2002; World Bank, 1999).
•
Reduced air preheat and reduced firing rates lower peak temperatures in the
combustion zone, thus reducing thermal NOx. This strategy, however, carries a
substantial energy penalty. Emissions of smoke and CO need to be controlled,
which reduces operational flexibility. (Cooper and Alley, 2002; World Bank, 1999)
•
Water injection (or steam injection) can be an effective means of reducing flame
temperatures, thus reducing thermal NOx. (Cooper and Alley, 2002; World Bank,
1999)
2.6.8.2 Low-NOx burners
New low-NOx burners (Figure 2.9) represent the most common equipment design
change for reducing NOx formation. Low-NOx burners are not only effective on new
power plants, but also can be readily applied to older facilities as retrofit projects. LowNOx burners limit the formation of NOx by controlling the mixing of fuel and air, in effect
automating low-excess-air firing or staged combustion.
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conventional burners, low-NOx burners reduce emissions of NOx by 40-60%. (Cooper
and Alley, 2002; World Bank, 1999)
Figure 2.9 Schematic diagram of a low-NOx burner.
(Source: NETL, 2004.)
2.6.9 Flue gas treatment techniques
Flue gas treatment (FGT) is more effective in reducing NOx emissions than are
combustion controls, although at a higher cost. FGT is also useful where combustion
controls are not appropriate.
FGT techniques are broadly classified as dry or wet
techniques, the dry techniques include catalytic reduction, non-catalytic reduction, and
adsorption, while the wet process is through absorption in a caustic scrubbing solution.
(Cooper and Alley, 2002; World Bank, 1999)
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2.6.9.1 Selective catalytic reduction
Selective catalytic reduction (SCR) is currently the most developed and widely used
applied FGT technology. In the SCR process (Figure 2.10), ammonia (NH3) is used as
reducing agent to convert NOx to nitrogen in the presence of a catalyst in a converter
upstream of the air heater.
The catalyst is usually a mixture of titanium dioxide,
vanadium pentoxide and tungsten trioxide. SCR can remove 60-90% of NOx from flue
gases.
Unfortunately, the process is very expensive, and the associated ammonia
injection results in an ammonia (NH3) slipstream in the exhaust. (Cooper and Alley,
2002; World Bank, 1999)
Figure 2.10 Schematic flow diagram of a selective catalytic reduction system.
(Adapted from Friend, 1995 and EPDC, 2004.)
2.6.9.2 Selective non-catalytic reduction
At temperatures of 900-1000ºC, NH3 will reduce NOx to N2 without a catalyst.
At
NH3:NOx molar ratios of 1:1 to 2:1, about 40-60% NOx reduction can be achieved.
Potential problems with selective non-catalytic reduction (SNCR) include incomplete
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mixing of NH3 with the hot flue gas and improper temperature control.
If the
temperature is too low, unreacted ammonia will be emitted, if the temperature is too
high, NH3 will be oxidised to NO. (Cooper and Alley, 2002; World Bank, 1999)
2.6.9.3 Adsorption
Several dry adsorption techniques have been proposed and demonstrated for
simultaneous control of NOx and SOx. One type of system uses activated carbon with
NH3 injection, simultaneously reducing the NOx to N2 and oxidising the SO2 to sulphuric
acid (H2SO4). The activated carbon bed must be operated in the temperature range of
220-230ºC and must be regenerated to remove the H2SO4. (Cooper and Alley, 2002;
World Bank, 1999)
Another adsorption system uses a copper oxide catalyst. The copper oxide adsorbs
SO2 to form copper sulphate. Both copper oxide and copper sulphate are reasonably
good catalysts for the selective reduction of NOx with NH3. (Cooper and Alley, 2002;
World Bank, 1999)
2.6.9.4 Wet absorption
Wet absorption or wet scrubbing processes usually remove SOx as well as NOx. The
main disadvantage of wet absorption of NOx is the low solubility of NO. Often the NO
must be oxidised to NO2 in the flue gas before a reasonable degree of absorption can
occur in water. (Cooper and Alley, 2002)
2.6.10 Flares
Flaring is a VOC combustion control process in which the VOC are piped to a remote,
usually elevated, location and burned in an open flame in the open air using a specially
designed burner tip, auxiliary fuel, and steam or air to promote mixing for VOC
destruction (>98%).
Completeness of combustion in a flare is governed by flame
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temperature, residence time in the combustion zone, turbulent mixing of the gas stream
components to complete the oxidation reaction, and available oxygen for free radical
formation. Combustion is complete if all VOC are converted to carbon dioxide and
water. Incomplete combustion results in some of the VOC being unaltered or converted
to other organic compounds such as aldehydes or acids. (USEPA, 2003b)
Flares are generally categorised in two ways: (1) by the height of the flare tip (that is
ground or elevated), and (2) by the method of enhancing mixing at the flare tip (for
example, either steam-assisted, air-assisted, pressure-assisted, or non-assisted).
Elevating the flare can prevent potentially dangerous conditions at ground level where,
for example, the open flame (an ignition source) is located near a process unit.
Elevating the flare also allows the products of combustion to be dispersed above
working areas to reduce the effects of noise, heat, smoke and objectionable odours. In
all combustion processes, good mixing and an adequate air supply are required to
complete combustion and minimise smoke. The various flare designs differ primarily in
their accomplishment of mixing. (USEPA, 2003b)
Steam-assisted flares are single burner tips, elevated above ground level for safety
reasons (Figure 2.11). They account for the majority of the flares installed for industrial
applications and are the predominant flare type found in refineries and chemical plants
(USEPA, 2003b). To ensure good mixing and an adequate air supply, this type of flare
injects steam into the combustion zone to promote turbulence for mixing and to
introduce air into the flame. (USEPA, 2003b)
Advantages of using flares include (USEPA, 2003b):
•
can be an economical way to dispose of sudden releases of large amounts of gas,
•
in many cases do not require auxiliary fuel to support combustion, and
•
can be used to control intermittent or fluctuating waste streams.
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Figure 2.11 Steam-assisted elevated flare system.
(Source: USEPA, 2002.)
Disadvantages of using flares include (USEPA, 2003b):
•
can produce noise, smoke, heat radiation and fugitive light (at night),
•
can be a source of SOx, NOx and CO,
•
cannot be used to treat waste streams with halogenated compounds, and
•
released heat from combustion is lost.
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2.6.11 Thermal incinerators
Incineration, or thermal oxidation, is the process of oxidising combustible materials by
raising the temperature of the material above its auto-ignition point in the presence of
oxygen, and maintaining it at high temperature for sufficient time to complete
combustion to carbon dioxide and water.
Time, temperature, turbulence, and the
availability of oxygen all affect the rate and the efficiency of the combustion process.
(USEPA, 2003c)
Thermal incinerators (also referred to as direct flame incinerators, thermal oxidisers, or
afterburners) operate through a nozzle-stabilised flame that is maintained by a
combination of auxiliary fuel, waste gas compounds and supplementary air, added
when necessary. Upon passing through the flame, the waste gas is heated from its
preheated inlet temperature to its ignition temperature. The ignition temperature varies
for different compounds and is usually determined empirically. (USEPA, 2003c)
The required level of VOC control of the waste gas that must be achieved, within the
time that it spends in the thermal combustion chamber, dictates the reactor
temperature. The shorter the residence time, the higher the reactor temperature must
be. Studies based on actual field test data show that commercial incinerators should
generally be run at 870ºC, with a nominal residence time of 0,75 seconds, to ensure a
98% destruction of non-halogenated organics. (USEPA, 2003c)
Advantages of using thermal incinerators include (USEPA, 2003c):
•
incinerators are one of the best proven methods for destroying VOCs, with
efficiencies up to 99,9999% possible, and
•
thermal incinerators are often the best choice when high efficiencies are needed.
Disadvantages of using thermal incinerators include (USEPA, 2003c):
•
thermal incinerator operating costs are relatively high due to supplemental fuel
costs,
•
they are not well suited to streams with highly variable flow (for example, increased
flow conditions result in reduced residence time and poor mixing; which decreases
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the completeness of combustion, causing the combustion chamber temperature to
fall and thus decreasing the destruction efficiency), and
•
incinerators are generally not recommended for controlling gases containing
halogen- or sulphur-containing compounds, because of the formation of highly
corrosive gases.
2.6.12 Catalytic oxidisers
Catalytic oxidisers (also referred to as catalytic incinerators or catalytic reactors)
operate very similar to thermal incinerators, with the primary difference that the gas,
after passing through the flame area, passes through a catalyst bed. The catalyst has
the effect of increasing the oxidation reaction rate, enabling conversion at lower reaction
temperatures than in thermal incinerator units.
Catalysts, therefore, also allow for
smaller incinerator size. Catalysts typically used for VOC incineration include platinum
and palladium.
Other formulations include metal oxides, which are used for gas
streams containing chlorinated compounds. (USEPA, 2003d)
Advantages of using catalytic oxidisers include (USEPA, 2003d):
•
lower fuel requirements,
•
lower operating requirements,
•
little or no insulation requirements,
•
reduced fire hazard,
•
reduced flashback problems, and
•
less volume/size required.
Disadvantages of using catalytic oxidisers include (USEPA, 2003d):
•
high initial cost,
•
catalyst poisoning possible,
•
particulates must often first be removed, and
•
spent catalysts that cannot be regenerated may need to be disposed off.
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2.6.13 Regenerative thermal oxidisers
Regenerative thermal oxidisers (also referred to as regenerative incinerators) use high
density media, such as a ceramic-packed bed still hot from a previous cycle, to preheat
an incoming VOC-laden waste gas stream. The preheated, partially oxidised gases
then enter a combustion chamber where they are heated by auxiliary fuel combustion to
a final oxidation temperature, typically between 760ºC and 820ºC. This temperature is
maintained in order to achieve maximum VOC destruction. However, temperatures of
up to 1 100ºC may be achieved, if required, for very high control efficiencies of certain
toxic VOCs. The purified, hot gases exit this chamber and are directed to one or more
different ceramic-packed beds cooled by an earlier cycle. Heat from the purified gases
is absorbed by these beds before the gases are exhausted to the atmosphere. The
reheated packed bed then begins a new cycle by heating a new incoming waste gas
stream. Typical regenerative incinerator design efficiencies range from 95% to 99%.
(USEPA, 2003f)
Regenerative incinerators offer many advantages for the appropriate application. High
flow, low concentration waste streams that are consistent over long time periods can be
treated economically. Pre-treatment to remove particulate matter may be necessary to
prevent the packed bed from clogging. (USEPA, 2003f)
Advantages of using regenerative thermal oxidisers include (USEPA, 2003f):
•
lower fuel requirements because of high energy recovery,
•
high temperature capability provides better destruction,
•
less susceptible to problems with chlorinated compounds, and
•
generally lower NOx emissions than thermal oxidation.
Disadvantages of using regenerative thermal oxidisers include (USEPA, 2003f):
•
high initial costs,
•
difficult and expensive installation,
•
large size and weight, and
•
high maintenance demand for moving parts.
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Table 2.1 is a summary of all the major air pollution control technologies, showing
efficiencies and availability/usage in South Africa.
Table 2.1 Summary of major air pollution control technologies.
Air pollution control technology
Removal efficiency of applicable
pollutant
Available in South Africa
Cyclone
10µm 90%
Fine dust 70%
Yes
Fabric filters
99,9%
toxic metals 90%
Yes
Electrostatic precipitator
99,9%
toxic metals 99%
Yes
Wet scrubbers
Depends on design or type used
Yes
FGD - Wet System
Limestone
90%-98%
Yes
Lime
95%
Yes
FGD - Semi-Dry Systems
Lime spray dryer
80%-90%
Yes
FGD - Dry Systems
Calcium based sorbent injection
50%-60%
Yes
Sodium based sorbent injection
80%
Yes
Combustion Modifications
Modifications of operating conditions
Depends on technique used
Yes
Low-NOx burners
40%-60%
Yes
Flue Gas Treatment
SCR
60%-90%
No
SNCR
40%-60%
No
Activated carbon adsorption
-
Yes
Copper oxide adsorption
-
Yes
Wet absorption
-
Yes
Incineration
Flares
>98%
Yes
Thermal incinerators
98%
Yes
Catalytic oxidisers
-
Yes
Regenerative thermal oxidisers
95%-99%
Yes
Data adapted from Howden Energy Systems (2004) and Burger (2005).
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2.7 GENERIC POLLUTANT CONTROL TECHNOLOGY
The selection of control technologies for a specific case requires consideration of many
different parameters, but generic pollutant control looks at non-specific air pollution
control. No consideration is given to industry type, process or product. The following
lists of technologies were sourced from literature to facilitate in the selection of
appropriate control measures according to the polluting species. The lists are in no way
exhaustive, but the technologies are well known, well used and well supported by
existing documentation.
2.7.1 Particulate matter control
The following air pollution control technologies, representing the most widely used and
referenced technologies, are available for the prevention and control of particulate
matter (World Bank, 1999; USEPA, 2002; Cooper and Alley, 2002; USEPA, 1998a;
European IPPC Bureau, 2003):
•
fuel switching,
•
fuel cleaning,
•
settling chambers,
•
cyclones,
•
fabric filters,
•
electrostatic precipitators, and
•
wet scrubbers.
Wet scrubbers can be further subdivided into the following types (World Bank, 1999;
USEPA, 2002; Cooper and Alley, 2002; USEPA, 1998a; European IPPC Bureau, 2003):
•
spray chambers/towers,
•
packed-bed scrubbers,
•
impingement plate scrubbers,
•
mechanically-aided scrubbers,
•
venturi scrubbers,
•
orifice scrubbers,
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•
condensation scrubbers,
•
charged scrubbers, and
•
fibre-bed scrubbers.
Literature Survey
During equipment selection consideration should be given to all the different parameters
that may affect the device, but generally for industrial applications the use of ESPs or
baghouses is recommended for the effective removal of particulates (or PM-10).
Cyclones and mechanical separators should be used only as precleaning devices
upstream of a baghouse or an electrostatic precipitator. (World Bank, 1999; USEPA,
2002; USEPA, 1998a)
2.7.2 Sulphur oxides control
There are two approaches to controlling sulphur oxides (SOx) emissions, either by
removing sulphur from the fuel before combustion (through fuel switching or cleaning),
or by removing SOx from the flue gasses. Different types of flue gas desulphurisation
(FGD) processes, also know as SO2 scrubbing, are presented in Table 2.2 (World Bank,
1999; Cooper and Alley, 2002; European IPPC Bureau, 2003). Although there are a
vast number of these processes available, only those that are well known, well
researched and well referenced are shown in Table 2.2.
2.7.3 Nitrogen oxides control
The following air pollution control technologies are available for the prevention and
control of nitrogen oxides (World Bank, 1999; USEPA, 2002; Cooper and Alley, 2002;
USEPA, 1993b; European IPPC Bureau, 2003):
•
fuel switching,
•
fuel cleaning,
•
combustion modifications, and
•
flue gas treatment.
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Table 2.2 Once-through and regenerable FGD processes.
Once-through processes
Regenerable processes
Wet
systems/scrubbing
Semi-dry systems
Dry systems
Wet systems
Dry systems
(for SOx and NOx)
Lime
Lime spray drying
Lime (calcium
based sorbent)
injection
Limestone
forced oxidation
Activated carbon
adsorption
Limestone
Limestone
spray drying
Sodium based
sorbent injection
Wellman-Lord
Copper oxide
adsorption
Dual alkali
Trona
Magnesium oxide
Magnesium
enhanced lime
Nahcolite
Citrate carbonate
Seawater
Circulating
fluidised bed
Sulphite
Combustion modifications are further subdivided into either low-NOx burners or some
form of modification of operating conditions.
Modification of operating conditions
include (World Bank, 1999; USEPA, 2002; Cooper and Alley, 2002; USEPA, 1993b;
European IPPC Bureau, 2003):
•
low-excess-air firing (LEA),
•
off-stoichiometric combustion/staged combustion,
•
flue gas recirculation (FGR),
•
gas reburning,
•
reduced air preheat/or reduced firing rates, and
•
water/steam injection.
Flue gas treatment for control of NOx are divided into either wet or dry techniques. Wet
techniques consist of absorption processes and dry techniques include the following
(World Bank, 1999; USEPA, 2002; Cooper and Alley, 2002; USEPA, 1993b; European
IPPC Bureau, 2003):
•
selective catalytic reduction (SCR),
•
selective non-catalytic reduction (SNCR), and
•
adsorption (using either activated carbon or copper oxide).
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2.7.4 Volatile organic compounds control
There is a wide variety of techniques available to control the emissions of volatile
organic compounds (VOCs), with the techniques focusing either on destruction or
recovery. Only techniques or methods that are well researched and referenced are
presented below, but the list is in no way exhaustive. Destructive techniques include
(USEPA, 2002; USEPA, 1995; European IPPC Bureau, 2003):
•
incineration,
catalytic incineration,
thermal oxidisers,
regenerative thermal incineration,
•
flares,
elevated flares,
grounded flares,
•
biofiltration, and
•
ultra D-tox system.
Recovery techniques can be divided into the following (USEPA, 2002; USEPA, 1995;
European IPPC Bureau, 2003):
•
selective membrane separation,
•
refrigerated condensation,
•
absorption,
•
adsorption (enhanced carbon adsorption), and
•
scrubbers.
2.8 INDUSTRY SECTOR AIR POLLUTION CONTROL
The industries discussed within this section are considered high air pollution
contributors that require specific attention. In each case a short overview is given of the
industry, followed by the recommended technologies from each country/union to reduce
air pollution from the relevant industry.
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2.8.1 Coal-fired power plant
In most large industrial facilities combustion plants (power plants) are applied according
to the owner’s demands or requirements as either large utility plants or industrial
combustion plants; providing electricity, steam or heat to industrial production
processes. For the purpose of this investigation the focus was on large utility plants
(power stations) that use coal in conventional steam-producing thermal power plants for
the generation of electricity.
An overview of all the different mass streams are
presented in the generalised flow diagram of a power plant and its associated
operations in Figure 2.12.
Power plants generate a number of residues, wastes and large amounts of emissions to
all environmental media. The most important emissions to air from the combustion of
coal are SOx, NOx, CO, particulates and greenhouse gases such as carbon dioxide
(CO2).
Other substances such as heavy metals, hydrogen fluoride (HF), hydrogen
chloride (HCl), halide compounds, unburned hydrocarbons, non-methane volatile
organic compounds and dioxins are emitted in smaller quantities. (HMIP, 1995a;
European IPPC Bureau, 2005a; USEPA, 2005a)
Table 2.3 to Table 2.8 show the possible technologies recommended by the United
Kingdom, European Union and the United States to reduce, prevent or abate
particulates, SOx, NOx, CO, heavy metals, HCl and HF. The technologies were sourced
from various references and the database discussed in Section 2.2 to Section 2.4.
Good combustion practices and good combustion control will aid in the prevention and
control of air pollution emissions, regardless of the type of fuel used, the combustion
method followed and the size of a facility (HMIP, 1995a; European IPPC Bureau,
2005a; USEPA, 2005a).
It should also be noted that the type of flue gas
desulphurisation (FGD) technique used for the prevention and control of SOx depends
on the type of combustion method, the output, and whether the plant is new or existing.
Similarly for the prevention and control of NOx a combination of combustion
modifications and flue gas treatment (FGT) can be used; depending on the output, the
fuel used and whether the plant is new or existing. (European IPPC Bureau, 2005a)
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Dust
"lift-off"
Fuel
storage
(Gas)
Sulphur trioxide
Ammonia
Limestone
Particulate
abatement
SCR
Flue gas
desulphurisation
Combustion Plant
(Boiler)
Milling
(Coal)
Fuel preparation
and blending
(Oil)
Flue-gas
Main stack
(if natural
gas fuel)
Water
Run-off
water
Treatment
chemicals
General site
drainage
Water treatment
(de-ionisation)
Furnace
bottom ash
(if oil
contaminated)
Fuel
Oil vapour
releases
Cooling
tower system
Settling
Fly ash
(silo)
Water/gypsum
separation
Natural water course/
sewerage system
Evaporation losses
Blowdown
Oil/water
separators
Waste water
treatment
(if uncontaminated)
Controlled
waters
Dry ash
Wet ash
Sludge
Sludge
Sludge
(for disposal) (for disposal) (for disposal)
Gypsum for offsite use/disposal
Fly ash for off-site
use/disposal
Figure 2.12 Generalised flow diagram of a power plant and its associated processes.
(Adapted from HMIP, 1995a.)
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Table 2.3
Air pollution control technologies for the prevention and control of PM from
coal-fired power plants.
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended through the
RBLC database by the
following permits¥
Switch fuel
Yes
-
VA-0268
Cyclones (pre-cleaners only)
Yes
Yes
MT-0027
Fabric filter (baghouse)
Yes
Yes
PA-0249, PA-0248, ND-0021, PA0247, PA-0182, AR-0074, OH0231, IA-0067, KS-0026, WY0057, PA-0183
ESP (wet and dry)
Yes
Yes
GA-0114, SC-0104, KY-0084,
PR-0007, KY-0084
Wet flue gas desulphurisation
(wet scrubber)
-
Yes
MT-0027
Semi-dry flue gas
desulphurisation - spray dryer
-
Yes
-
Flue gas desulphurisation sorbent injection
-
Yes
-
∗ Data adapted from HMIP (1995a).
§ Data adapted from European IPPC Bureau (2005a).
¥ Data from the RBLC database (USEPA, 2005a), searched for coal-fired fuel combustion processes.
Table 2.4
Air pollution control technologies for the prevention and control of SOx
from coal-fired power plants.
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended through the
RBLC database by the
following permits¥
Fuel switching
Yes
Yes
TX-0298, TX-0358, PR-0007,
VA-0268
Fuel cleaning
Yes
-
-
Wet flue gas desulphurisation
(specifically limestone)
Yes
Yes
SC-0104, KY-0084
Semi-dry flue gas
desulphurisation - spray dryer
(specifically limestone)
Yes
Yes
ND-0021, IA-0067, WY-0057,
KY-0086
Dry flue gas desulphurisation sorbent injection
(specifically limestone)
Yes
Yes
PA-0249, AR-0074, MT-0022,
KS-0026, PR-007, OH-0231¸PA0247, PR-007
Wet scrubbing
(specifically seawater)
Yes
Yes
SC-0104, MT-0027
∗ Data adapted from HMIP (1995a).
§ Data adapted from European IPPC Bureau (2005a).
¥ Data from the RBLC database (USEPA, 2005a), searched for coal-fired fuel combustion processes.
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Table 2.5
Air pollution control technologies for the prevention and control of NOx
from coal-fired power plants.
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended through the
RBLC database by the
following permits¥
Fuel switching
Yes
-
-
Combustion Modifications
Low-excess-air firing
Yes
-
-
Staged combustion
Yes
Yes
-
Flue gas circulation
Yes
-
-
Over-fire air
Yes
-
MT-0022, IA-0067, KS-0026
Gas reburning
Yes
Yes
-
Low NOx burners
Yes
Yes
SC-0104, AR-0074, MT-0022, IA0067, KY-0084, KS-0026, WY0057
Flue Gas Treatment
SCR
Yes
Yes
SC-0104, MT-0022, IA-0067, KY0084, KS-0026, WY-0057, MT0027
SNCR
Yes
Yes
PA-0248, PA-0247, PA-0182,
KY-0086, PA-0183, PR-0007,
ND-0021
∗ Data adapted from HMIP (1995a).
§ Data adapted from European IPPC Bureau (2005a).
¥ Data from the RBLC database (USEPA, 2005a), searched for coal-fired fuel combustion processes.
Table 2.6
Air pollution control technologies for the prevention and control of CO from
coal-fired power plants.
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Complete combustion
-
Yes
Good combustion
practices/control
-
Yes
Recommended through the
RBLC database by the
following permits¥
PA-0248, ND-0021, PA-0247,
GA-0114, SC-0104, TX-0298,
PA-0182, AR-0074, OH-0231, IA0067, TX-0358, KY-0084, KS0026, WY-0057, KY-0086, VA0268, PA-0183, PR-0007
∗ In some cases information could not be obtained from all three countries/unions for each industry.
§ Data adapted from European IPPC Bureau (2005a).
¥ Data from the RBLC database (USEPA, 2005a), searched for coal-fired fuel combustion processes.
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Table 2.7
Air pollution control technologies for the prevention and control of heavy
metals from coal-fired power plants.
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended through the
RBLC database by the
following permits¥
ESP (wet and dry)
Yes
Yes
SC-0104, KY-0084
Fabric filter (baghouse)
Yes
Yes
KY-0086
Wet scrubber
Yes
-
SC-0104, KY-0084
SCR
-
-
SC-0104
Low NOx burners
-
-
SC-0104
Activated carbon
-
-
IA-0067
∗ Data adapted from HMIP (1995a).
§ Data adapted from European IPPC Bureau (2005a).
¥ Data from the RBLC database (USEPA, 2005a), searched for coal-fired fuel combustion processes.
Table 2.8
Air pollution control technologies for the prevention and control of
hydrogen chloride and hydrogen fluoride from coal-fired power plants.
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended through the
RBLC database by the following
permits¥
Wet scrubber
-
Yes
SC-0104, PR-007
Spray dryer
-
Yes
PA-0249, ND-0021, IA-0067
∗ In some cases information could not be obtained from all three countries/unions for each industry.
§ Data adapted from European IPPC Bureau (2005a).
¥ Data from the RBLC database (USEPA, 2005a), searched for coal-fired fuel combustion processes.
2.8.2 Coal gasification
Gasification involves the reaction of a source of carbon (coal or biomass) with a source
of hydrogen and/or oxygen to yield a gas containing carbon monoxide, hydrogen,
carbon dioxide and methane in proportions dependent on the ratio of the reactants
utilised and on the reaction conditions. The carbonaceous feedstocks would normally
be coal, lignite or liquid hydrocarbons. Products from the gasification process can be
used in power generation, the chemical industry and in the production of synthetic fuels.
(HMIP, 1995b)
Gasification takes place through a complex set of reactions. In the simplest terms
gasification can be regarded as the reaction of carbon with the gasifying agent. Sulphur
and nitrogen in the feedstock react to produce hydrogen sulphide (H2S), carbonyl
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sulphide, smaller amounts of other sulphur compounds, ammonia (NH3), hydrogen
cyanide and other nitrogen compounds; which can be removed in subsequent purifying
stages. (HMIP, 1995b)
The main gasification processes available are catalytic gasification with steam, thermal
hydrogenation, and gasification with either oxygen and/or steam, or with air and steam
(HMIP, 1995b). Coal gasification with air and steam will be discussed in more detail as
part of this investigation.
Gasifiers generally operate at high temperatures, but some processes do operate at
lower temperatures. During gasification hydrocarbon feedstocks are reduced to low
molecular weight substances such as carbon monoxide and molecular hydrogen.
Numerous reactions take place within the gasifiers but essentially in an oxygen and
steam fed gasifier the reactions may be summarised as (HMIP, 1995b):
C+H2O → CO+H2
steam/carbon reaction, and
C+½O2 → CO
partial oxidation.
The composition of the synthetic gas, which is produced by a gasifier, will depend on
the feedstock, the steam to oxygen ratio and the temperature and pressure at which a
gasifier is operated. Although oxygen is fed into gasifiers, a reducing atmosphere exists
and as a result sulphur present in the relevant feedstock is converted to H2S, with
smaller amounts of carbonyl sulphide (COS), methyl mercaptan and carbon disulphide
being produced. Fuel-bound nitrogen will be converted mainly to molecular nitrogen,
but in the presence of hydrogen, some small quantities of ammonia and hydrogen
cyanide will be produced.
Table 2.9 shows various activities associated with the gasification process and the air
pollutants from these air emission sources.
An example of how gasification forms part of a synthetic fuel refining and/or chemical
manufacturing facility is illustrated in Figure 2.13. Table 2.10 to Table 2.12 show the
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Chapter 2
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possible technologies or methods recommended by the United Kingdom to reduce,
prevent or abate air pollutants from a gasification process (see Section 2.3).
Table 2.9 Air emissions associated with gasification processes.
Source
Pollutant
particulate matter (PM)
Raw materials, storage and handling
volatile organic compounds (VOCs)
particulate matter (PM)
sulphur oxides (SOx)
nitrogen oxides (NOx)
oxides of carbon (COx)
Gas handling and treatment
organic compounds
volatile organic compounds (VOCs)
hydrogen sulphide (H2S)
ammonia (NH3)
Data adapted from HMIP (1995b).
Table 2.10
Air pollution control technologies for the prevention and control of air
pollutants - raw materials, storage and handling (including slag/ash
handling).
Air Pollutant
General
Air Pollution Control
Technology
Recommend
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended
through the RBLC
database by the
following permits§
Unloading into
enclosed hoppers
Yes
-
-
Enclosed conveyors
Yes
-
-
Enclosed discharge
towers
Yes
-
-
Removal from stockpile
via bottom off-take
Yes
-
-
Use fixed conveyor
system
Yes
-
-
Use enclosed system
when working with
dusty materials
Yes
-
-
Bag or ceramic filters
for dust handling
Yes
-
-
Liquid feedstocks
stored in appropriate
roof tanks
Yes
-
-
Scrub or incinerate
vented gas
Yes
-
-
∗ Data adapted from HMIP (1995b).
§ In some cases information could not be obtained from all three countries/unions for each industry.
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Chapter 2
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Petrochemicals Production
Clean Fuel Gas
Syngas
Methanol
Hydrogen
Steam
Residues
Oxygen
Nitrogen
Air
Air Separation Unit
Gasification
and Associated
Gas Purification Plants
Oxygen
Feedstock
(coal or biomass)
Slag
Sulphur
Chemicals manufacture
Figure 2.13 An example of the gasification process during synthetic fuel refining and/or chemical manufacturing.
(Adapted from HMIP, 1995b.)
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Table 2-11
Literature Survey
Air pollution control technologies or methods for the prevention and control
of air pollutants from a gasification unit.
Air Pollutant
General
Air Pollution Control
Technology
Recommend
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended
through the RBLC
database by the
following permits§
Proper design,
operation and control
Yes
-
-
Coal charging via
double lock system
Yes
-
-
Gases released during
charging, should be reinjected or vented to
treatment system
Yes
-
-
Alternatively use wet
feed (slurry)
Yes
-
-
All process vents to
flare system
Yes
-
-
All pressure reliefs to
flare system
Yes
-
-
Proper design,
operation and control
of flare
Yes
-
-
∗ Data adapted from HMIP (1995b).
§ In some cases information could not be obtained from all three countries/unions for each industry.
2.8.3 Petroleum refining
The petroleum refining industry converts crude oil into multiple refined products,
including liquefied petroleum gas, gasoline, kerosene, aviation fuel, diesel fuel, fuel oil,
lubricating oil and petrochemical industry feedstock. Petroleum refining activities start
with receipt of the crude oil at the refinery, followed by multiple petroleum handling and
refining operations and terminate with the storage of the refined products prior to
transport. Figure 2.14 illustrates a schematic diagram for an oil refinery process, largely
determined by the composition of the crude oil feedstock and the petroleum products it
chooses to manufacture. (MIC, 2004; Rucker and Strieter, 2000)
In Table 2.13 the five categories of general refinery processes and associated
operations are shown (MIC, 2004; Rucker and Strieter, 2000):
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Table 2.12
Literature Survey
Air pollution control technologies for the prevention and control of air
pollutants from a gas purification and conversion unit.
Air Pollutant
Air Pollution Control
Technology
Recommend
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended
through the RBLC
database by the
following permits§
-
-
-
-
Liquid Quenching
General
Any gas/flash stream
arising on pressure let
down, routed to
treatment system or
combined with acid gas
stream and routed to
SRU
Yes
Particulate Matter Removal
General
Collected material
should be collected via
a lock hopper
Yes
Acid Gas Removal
General
Amine scrubbing to
remove H2S
Yes
-
-
Concentrated acid gas
treated in sulphur
recovery process eg
Claus kiln
Yes
-
-
Tail gases from Claus
kiln to thermal
incinerator or catalytic
oxidiser
Yes
-
-
Final vent gas should
be incinerated
Yes
-
-
Carbonyl sulphide,
methyl mercaptan and
other sulphur
containing constituents
removed by conversion
and forwarding to
Claus process
Yes
-
-
HCN and NH3 removed
by water scrubbing
Yes
-
-
CO2 released vie
appropriate chimney if
concentration is
adequately low
Yes
-
-
CO2 combustion only if
odour problem exists
Yes
-
-
Process vents to
incinerator/flare
Yes
-
-
Pressure reliefs to
incinerator/flare
Yes
-
-
∗ Data adapted from HMIP (1995b).
§ In some cases information could not be obtained from all three countries/unions for each industry.
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Fuel gases
Liquid petroleum gas (LPG)
Gas
Polimerisation
feed
Crude oil
Gas plant
Gas
separation
Light SR naphtha
Desalted crude oil
Polymerisation
n-butane
Alkylation
feed
Light crude oil
distillate
Desalting
Iso-naphtha
Light SR naphtha
Catalytic
reforming
HDS heavy naphtha
Gasoline
(naphtha)
sweetening
and blending
Catalytic
hydrocracking
SR middle distillate
Solvents
Light hydrocracked naphtha
Jet fuels
Hydrodesulphuri
sation/treating
HDS middle distillate
SR middle distillate
Light cat cracked naphtha
Light cat cracked distillate
Light vacuum distillate
Distillate
sweetening
treating
and
blending
Kerosene
Solvents
Distillate fuel oils
Diesel fuel oils
Catalytic
cracking
Vacuum
distillation
Automotive gasoline
Reformate
SR kerosene
SR gas oil
Heavy vacuum distillate
Heavy cat cracked distillate
Heavy vacuum distillate
Asphalt
Solid coke
Solvent
deasphalting
Coking
Visbreaking
Light thermal
cracked
distillate
Cat cracked clarified oil
Vacuum tower residue
Residual
treating
and
blending
Residual fuel oils
Thermally cracked
residue
Vacuum tower residue
Atmospheric tower residue
Lube
feedstock
Atmospheric tower residue
Aviation gasoline
Alkylate
Alkylation
Catalytic
isomerisation
Hydrodesulphuri
sation/treating
Heavy SR naphtha
Atmospheric
distillation SR kerosene
Polimerisation
naphtha
oil/feed streams
gas streams
Hydrotreating
Raffinate
Solvent
extraction
Solvent
dewaxing
Dewaxed oil (raffinate)
Deoiled wax
Hydrotreating
and
blending
Figure 2.14 Schematic flow diagram of an oil refinery process.
(Adapted from MIC, 2004.)
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Greases
Waxes
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Chapter 2
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Table 2.13 Five categories of general refinery processes and associated operations.
Separation
processes
Petroleum
conversion
processes
Petroleum treating
processes
Feedstock and
product handling
Auxiliary facilities
Desalting
Catalytic cracking
Hydrotreating
Storage
Steam boilers
Atmospheric
distillation
Thermal cracking
(visbreaking)
Chemical
sweetening
Blending
Waste water and
solid waste
treatment
Vacuum distillation
Alkylation
Acid gas removal
Loading
Hydrogen
production
Light ends
recovery/gas
processing
Polymerisation
Deasphalting
Unloading
Sulphur recovery
plant
Isomerisation
Asphalt blowing
Cooling towers
Reforming
Dewaxing
Blowdown system
Compressor
systems
Coking
Separation processes
Crude oil is a complex mixture of hydrocarbon compounds, including paraffinic,
naphthenic and aromatic hydrocarbons plus small amounts of some impurities including
salt, sulphur, nitrogen, oxygen and metals.
The first phase in petroleum refining
operations is the separation of crude oil into its major constituents using four
consecutive petroleum separation processes; namely desalting, atmospheric distillation,
vacuum distillation and light ends recovery - also known as gas processing). (MIC,
2004; Rucker and Strieter, 2000)
Desalting separates the salt from the crude oil by water addition to dissolve the salt,
followed by physical separation of the crude oil and water phases prior to distillation of
the crude oil. Atmospheric distillation involves the heating, vaporisation, fractionation
and condensation of different boiling point fractions of the crude oil at normal pressure.
Vacuum distillation repeats the process at reduced pressures in order to separate
higher boiling point fractions of the crude oil not accomplished by atmospheric
distillation.
Finally light ends recovery is the separation of non-condensable gases
(refinery fuel gas) from condensable hydrocarbons so that the fuel gas can be used as a
refinery energy source. (MIC, 2004; Rucker and Strieter, 2000)
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Conversion processes
Various crude oil components are converted to gasoline and other light hydrocarbon
fractions to meet the demands for high-octane gasoline, jet fuel and diesel fuel.
Processes such as catalytic cracking, thermal cracking (visbreaking – so called because
it reduces viscosity) and coking are used to break down large petroleum molecules into
smaller petroleum molecules. Catalytic cracking uses a catalyst and high temperature
in order to break apart long chain hydrocarbons to yield lower boiling point
hydrocarbons suitable for the production of gasoline or fuel oil. A fluidised catalytic
cracker (FCC) is normally used and during the process coke (carbon) is deposited on
the catalyst, which is then burnt off in the regenerator.
The exhaust gases of the
regenerator are sent to atmosphere, being the source of SO2 and NOx emissions from
the FCC process. Visbreaking, which is less commonly used, accomplishes the same
result using heat and high pressure, but without a catalyst. (MIC, 2004; Rucker and
Strieter, 2000)
Coking produces valuable volatile hydrocarbons from low volatility petroleum fractions
that are not valuable.
Distillation residues, for example, are heated to high
temperatures with limited oxygen being present to form solid coke and liquid
hydrocarbons. Polymerisation and alkylation processes are then used to combine small
petroleum molecules into larger molecules more suitable for use in gasoline production.
Polymerisation or alkylation requires a catalyst (phosphoric, hydrofluoric or sulphuric
acid) with pressure and/or heat to accomplish this. Finally, isomerisation and reforming
processes rearrange the structure of petroleum molecules in order to produce
molecules of similar molecular size to the original molecule but of higher value in the
final refined product.
A catalyst and heat are required in both isomerisation and
reforming processes. (MIC, 2004; Rucker and Strieter, 2000)
Treating processes
Petroleum treating processes stabilise and upgrade the petroleum products by
separating them from less desirable products and by removing objectionable elements.
Treating processes that are used in oil refineries include hydrotreating, chemical
sweetening, acid gas removal, deasphalting, asphalt blowing and dewaxing. (MIC,
2004; Rucker and Strieter, 2000)
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Hydrotreating employs a catalyst to react hydrogen, at high pressure and temperature,
with either the sulphur, nitrogen or oxygen in the crude oil to form hydrogen sulphide,
ammonia and water, respectively. Chemical sweetening employs caustic and air to
convert odorous mercaptans in the petroleum to less odorous disulphides. Acid gas
removal absorbs sulphur compounds into a solution in order to separate them from the
refinery fuel gas. (MIC, 2004; Rucker and Strieter, 2000)
Deasphalting is primarily used for the separation of asphaltenes and resins from
vacuum distillation residues by extraction with a solvent such as refinery propane.
Asphalt blowing is used primarily for polymerising and stabilising asphalt in order to
improve its weathering characteristics. This is accomplished by heating the asphalt in
the presence of a flowing air stream.
Dewaxing is used to remove any waxy
hydrocarbon components from lubricating oil base stocks. Dewaxing is done by either
selective hydrocracking over a zeolite catalyst or by solvent extraction. (MIC, 2004;
Rucker and Strieter, 2000)
Feedstock and product handling
The major refinery feedstock and product handling operations consist of unloading,
storage, blending and loading activities. Each of these is a critical step in the successful
operation of a petroleum refinery. (MIC, 2004; Rucker and Strieter, 2000)
Auxiliary facilities
A wide assortment of processes not always directly involved in the refining of crude oil
are used in functions vital to the operation of the refinery. Examples of these are steam
boilers, wastewater treatment or solid waste treatment units, hydrogen plants, sulphur
recovery plants, cooling towers, blowdown systems and compressor systems. (MIC,
2004; Rucker and Strieter, 2000)
Refinery process air emissions
The most significant air emission sources in oil refineries are catalytic or thermal
cracking units, catalytic reformer units, sulphur recovery plants, storage vessels, coking
units, equipment leaks, blowdown systems, vacuum distillation units, steam boilers,
process furnaces, process heaters, vessel loading and gasoline loading racks -
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specifically located at petroleum refineries. Table 2.14 identifies the air pollutants from
these air emission sources. (MIC, 2004; Rucker and Strieter, 2000)
Table 2.14 Significant refinery air emission sources and their associated air pollutants.
Refinery Process
Air Pollutant
Equipment leaks
volatile organic compounds (VOCs)
particulate matter (PM)
sulphur oxides (SOx)
Catalytic cracking (fluid bed)
nitrogen oxides (NOx)
carbon monoxide (CO)
volatile organic compounds (VOCs)
particulate matter (PM)
Coke production
sulphur oxides (SOx)
volatile organic compounds (VOCs)
particulate matter (PM)
sulphur oxides (SOx)
nitrogen oxides (NOx)
Bitumen production
carbon oxides (COx)
volatile organic compounds (VOCs)
hydrogen sulphide (H2S)
particulate matter (PM)
sulphur oxides (SOx)
nitrogen oxides (NOx)
Visbreaking
carbon oxides (COx)
volatile organic compounds (VOCs)
hydrogen sulphide (H2S) and mercaptans
particulate matter (PM)
sulphur oxides (SOx)
HF alkylation
carbon oxides (COx)
volatile organic compounds (VOCs)
sulphur oxides (SOx)
Sulphur recovery unit (SRU)
reduced sulphur (H2S, CS2, COS)
volatile organic compounds (VOCs)
Vacuum distillation
volatile organic compounds (VOCs)
Loading, handling and storage of
feedstocks and products
volatile organic compounds (VOCs)
Data adapted from MIC (2004), Rucker and Strieter (2000), van der Rest et al. (1999)
and HMIP (1995c).
Table 2.15 shows the possible technologies recommended by the United Kingdom,
European Union and the United States to reduce, prevent or abate VOC emissions from
various units within an oil refinery. (This table is discussed separately since these
control technologies apply all over an oil refinery. If the information within this table
applies to a specific unit, mentioned will be made of General VOC controls).
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Table 2.15
Literature Survey
Air pollution control technologies for the prevention and control of VOC
emissions (General VOC controls).
Air Pollutant
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended through
the RBLC database by
the following permits¥
Leak detection and
repair programme
(LDAR)
Yes
Yes
CA-0735, OK-0092, OK0095, TX-0269, TX0268, TX-0320, TX0340, TX-0361, TX0379, TX-0418
Low emission valve
stem packing on critical
valves
Yes
Yes
CA-0735
Low release valves
where gate valves are
not essential
Yes
Yes
CA-0735, CA-0744, CA0745
Balanced bellows type
relief valves
Yes
Yes
CA-0735
Minimise the number of
flanged connections
Yes
Yes
-
Canned pumps or
double mechanical
seals on conventional
pumps
Yes
Yes
CA-0735
End caps/plugs on
open ended lines
Yes
Yes
-
Relief valves emissions
vented to incineration
system
Yes
Yes
CA-0735, CA-0744
Optimise sampling
volume and frequency
Yes
-
-
Inspection and
maintenance
programme
-
-
CA-0711, CA-0712, MT0013
VOC
∗ Data adapted from HMIP (1995c).
§ Data adapted from European IPPC Bureau (2001).
¥ Data from the RBLC database (USEPA, 2005a), searched for fugitive and equipment leaks.
Table 2.16 to Table 2.23 show the possible technologies recommended by the United
Kingdom, European Union and the United States to reduce, prevent or abate air
pollutants from various units within an oil refinery. The information was sourced from
the various sources and the database discussed in Section 2.2 to Section 2.4. The
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RBLC database generally only had permit information for the major polluting units at an
oil refinery.
Table 2.16a Air pollution control technologies for the prevention and control of air
pollutants from a catalytic cracking.
Air Pollutant
PM
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended through
the RBLC database by
the following permits¥
Fuel cleaning
-
Yes
-
Cyclones
Yes
Yes
OK-0089, OK-0092
Fabric filters
-
Yes
-
ESP
Yes
Yes
-
Wet gas scrubber
Yes
-
AR-0061, IL-0079, LA0090, LA-0166, NJ-0057,
OK-0089, OK-0092, TN0153
Control and reuse of
catalyst fines
-
Yes
-
Fuel cleaning
Yes
Yes
OK-0089, OK-0092
DeSOx catalyst additive
Yes
Yes
-
Flue gas desulphurisation
SOx
Wet scrubbing
Yes
Yes
AR-0061, IL-0079, LA0166, NJ-0057, NM0045, OK-0089, OK0092, TX-0290, LA-0090
Dry and semi dry
scrubbing
Yes
Yes
-
Wet gas sulphuric acid
processes
Yes
Yes
-
∗ Data adapted from HMIP (1995c).
§ Data adapted from European IPPC Bureau (2001).
¥ Data from the RBLC database (USEPA, 2005a), searched for petroleum refining conversion processes and
fugitive and equipment leaks.
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Table 2.16b Air pollution control technologies for the prevention and control of air
pollutants from a catalytic cracking.
Air Pollutant
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended
through the RBLC
database by the
following permits¥
Fuel cleaning
-
Yes
OK-0089, OK-0092
Low NOx burners in
CO boilers
-
-
OK-0089, OK-0092, TX0341
Proper CO Boiler
operation to avoid hot
spots
Yes
Yes
LA-0090, LA-0171, WA0294
SNCR on regenerator
flue gas
-
Yes
TX-0346, WA-0294, WA0317
SCR on regenerator
flue gas
-
Yes
CA-0887, CA-0999, IN0101, TX-0290
LoTox technology
-
-
AR-0061, TX-0289
Proper operation and
control of full
combustion type
regenerators
Yes
Yes
AR-0061
CO Boiler
Yes
Yes
LA-0090, OK-0089, OK0092, TX-0346, TX0429, WA-0294, WA0317
High temperature
combustion
-
-
OK-0089, OK-0092
NOx
CO
VOC
General VOC controls (Table 2.15)
∗ Data adapted from HMIP (1995c).
§ Data adapted from European IPPC Bureau (2001).
¥ Data from the RBLC database (USEPA, 2005a), searched for petroleum refining conversion processes
and fugitive and equipment leaks.
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Table 2.17
Literature Survey
Air pollution control technologies for the prevention and control of air
pollutants from a coke production unit.
Air Pollutant
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended through
the RBLC database by
the following permits¥
Cyclones
Yes
Yes
-
Fabric filters
Yes
Yes
TX-0319, TX-0286
ESP
-
Yes
-
Partial and full
enclosures
Yes
Yes
TX-0319
Covered conveyers
-
Yes
TX-0319
Collect and recycle
coke fines
-
Yes
-
Fuel switching
Yes
Yes
OK-0089, OK-0092
PM
Flue gas desulphurisation
SOx
VOC
Wet scrubbing
-
Yes
AR-0061, IL-0079, LA0166, NJ-0057, NM0045, OK-0089, OK0092, TX-0290, LA-0090
Dry and semi dry
scrubbing
-
Yes
-
Wet gas sulphuric acid
processes
-
Yes
-
General VOC controls (Table 2.15)
∗ Data adapted from HMIP (1995c).
§ Data adapted from European IPPC Bureau (2001).
¥ Data from the RBLC database (USEPA, 2005a), searched for petroleum refining conversion processes and
fugitive and equipment leaks.
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Table 2.18
Literature Survey
Air pollution control technologies for the prevention and control of air
pollutants from a bitumen production unit.
Air Pollutant
General
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended through
the RBLC database by
the following permits¥
Oxidiser overheads
routed to scrubber prior
to incineration
Yes
Yes
-
Gases vented from
storage should be
vented to incinerator
and wet ESP to destroy
VOCs and odours
Yes
Yes
-
Incineration
temperature of at least
o
800 C and residence
time of 0,5 seconds
Yes
Yes
-
VOC
General VOC controls (Table 2.15)
∗ Data adapted from HMIP (1995c).
§ Data adapted from European IPPC Bureau (2001).
¥ In some cases information could not be obtained from all three countries/unions for each industry.
Table 2.19
Air pollution control technologies for the prevention and control of air
pollutants from a visbreaking unit.
Air Pollutant
General
VOC
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended through
the RBLC database by
the following permits¥
Sour gas treated by
amine scrubbing
Yes
Yes
-
Treated gas should be
recovered in products
or vented to RFG
Yes
Yes
-
General VOC controls (Table 2.15)
∗ Data adapted from HMIP (1995c).
§ Data adapted from European IPPC Bureau (2001).
¥ In some cases information could not be obtained from all three countries/unions for each industry.
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Table 2.20
Literature Survey
Air pollution control technologies for the prevention and control of air
pollutants from an HF alkylation unit.
Air Pollutant
General
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended through
the RBLC database by
the following permits¥
Alkaline scrubber to
remove HF from
incondensable gas
stream
-
Yes
-
Operate acid relief
neutraliser to reduce
HF in incondensable
gas stream
Yes
Yes
-
Flare vent gas
Yes
Yes
-
VOC
General VOC controls (Table 2.15)
∗ Data adapted from HMIP (1995c).
§ Data adapted from European IPPC Bureau (2001).
¥ In some cases information could not be obtained from all three countries/unions for each industry.
Table 2.21
Air pollution control technologies for the prevention and control of air
pollutants from a sulphur recovery unit (SRU).
Air Pollutant
General
VOC
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended through
the RBLC database by
the following permits¥
Amine scrubbing for
H2S capture
Yes
Yes
LA-0149
Furnace designed to
destroy NH3
Yes
Yes
-
Proper tail gas
treatment unit (thermal
incinerator, catalytic
oxidiser)
Yes
Yes
LA-0149, LA-0166
General VOC controls (Table 2.15)
∗ Data adapted from HMIP (1995c).
§ Data adapted from European IPPC Bureau (2001).
¥ Data from the RBLC database (USEPA, 2005a), searched for petroleum refining treating processes and
fugitive and equipment leaks.
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Table 2.22
Literature Survey
Air pollution control technologies for the prevention and control of air
pollutants from vacuum distillation units.
Air Pollutant
General
VOC
Recommended
Air Pollution Control
BATNEEC/BAT for
Technology
the UK∗
Recommended
BAT for the EU§
Recommended through
the RBLC database by
the following permits¥
Vacuum distillation
condensers vented to
heater or incinerator
Yes
Yes
-
Vacuum gaseous
streams vented to
amine scrubber,
before incineration
Yes
Yes
-
NH3 injection, where
applied, should be in
an enclosed system
Yes
Yes
-
De-coking vents need
suitable knock-out and
dust suppression
facilities
Yes
Yes
-
Pressure reliefs
vented to flare
-
Yes
MS-0032
General VOC controls
∗ Data adapted from HMIP (1995c).
§ Data adapted from European IPPC Bureau (2001).
¥ Data from the RBLC database (USEPA, 2005a), searched for petroleum refining separation processes and
fugitive and equipment leaks.
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Table 2.23
Literature Survey
Air pollution control technologies for the prevention and control of air
pollutants from the loading, handling and storage of feedstocks and
products.
Air Pollutant
PM
SOx
NOx
VOC
Air Pollution Control
Technology
Recommended
BATNEEC/BAT
for the UK∗
Recommended
BAT for the EU§
Recommended through
the RBLC database by
the following permits¥
Bottom loading of
container
Yes
-
CA-0641
Sprinkle stockpiles
-
-
TX-0322
Contain catalyst losses
to atmosphere
-
Yes
-
Use proper tank based
on vapour pressure at
storage temperature
Yes
Yes
LA-0166
Bottom loading of
container
Yes
-
-
Vapour
recovery/incineration
Yes
Yes
-
Closed-loop system
Yes
-
-
Use proper tank based
on vapour pressure at
storage temperature
Yes
Yes
-
Bottom loading of
container
-
-
CA-0641
Vapour
recovery/incineration
-
Yes
CA-0641
Use proper tank based
on vapour pressure at
storage temperature
Yes
Yes
-
Bottom loading of
container
Yes
-
CA-0641
Vapour
recovery/incineration
Yes
Yes
CA-0641, LA-0166
Closed-loop system
Yes
-
LA-0166, OK-0102
∗ Data adapted from HMIP (1995c).
§ Data adapted from European IPPC Bureau (2001).
¥ Data from the RBLC database (USEPA, 2005a), searched for petroleum refining feedstock blending,
loading, unloading and storage.
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CHAPTER 3
Technology Selection
3.1 SELECTION PROCESS
The various tables in Chapter 2 were compiled from information obtained from the
European union (EU), United States of America (USA) and the United Kingdom (UK).
The lists of technologies and techniques mentioned in the tables are not exhaustive, but
aim to represent the technologies and techniques most often used or recommended by
the various countries for preventing, abating and controlling air emissions from certain
industrial installations.
The lists were used to source out the best technologies or
techniques for the following industrial installations:
•
coal-fired power plant,
•
coal gasification, and
•
petroleum refining.
Technology selection was done by considering the frequency of use of a specific
technology or technique and the advantages and disadvantages of its use.
The
selection process weighed heavily on the experience gained in practise from other
countries. Little or no consideration was given to cross media implications of certain
technologies and to other limitations, such as floor space requirements and power
requirements.
3.2 COAL-FIRED POWER PLANT
The most important air emissions that have to be controlled from a coal-fired power
plant are particulate matter (PM), sulphur oxides (SOx), nitrogen oxides (NOx) and to a
lesser extent carbon monoxide (CO), certain heavy metals, hydrogen chloride (HCl) and
hydrogen fluoride (HF) (HMIP, 1995a).
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For the control of particulates from coal-fired power plants, electrostatic precipitators
(ESP) and/or fabric filters can be selected. Both of these control technologies provide a
removal efficiency of 99,9% for particulates, and removal efficiencies of 90% for heavy
metals such as arsenic, cadmium, chromium, lead and nickel (Cooper and Alley, 2002;
World Bank, 1999). Both ESPs and fabric filters are recommended technologies for
particulates and heavy metals removal by the UK and the EU and are in use in more
than 7 (ESPs) and 12 (fabric filters) records from the RBLC database (Table 2.3 and
Table 2.7). For final selection the electrostatic precipitator was chosen as the control
technology for particulates and heavy metals removal since the device is not as
sensitive to high temperatures as fabric filters, and since ESPs have been proven to
work effectively in South African power plants (Eskom Holdings Limited, 2002).
(Cyclones are also recommended for PM removal by the UK, EU and by records from
the RBLC database, but should only be used as pre-cleaners upstream of the primary
collection device; for example, an electrostatic precipitator, where dust loading is high).
Controlling SOx emissions from coal-fired power plants should, where possible and
economically feasible, be controlled first and foremost by switching or changing fuel.
This is recommended by the UK, EU and various RBLC records (Table 2.4). Flue gas
desulphurisation (wet, semi-dry and dry) is the most highly recommended control
technology for the control of SO2, being recommended by the UK and the EU and is in
use in more than 14 RBLC records (Table 2.4). Flue gas desulphurisation technologies,
such as spray dryers, can also effectively remove HCl and HF (Table 2.8). For final
selection wet flue gas desulphurisation with limestone was chosen as the control
technology for SO2 and possibly HCl and HF emissions from coal-fired power plants.
This control technology offers the highest removal efficiency (90-98%) (Cooper and
Alley, 2002) and is the preferred technology for coal-fired electric utility power plants
(USEPA, 2003a).
For the prevention and control of NOx a combination of combustion modifications and
flue gas treatment (FGT) can be used (European IPPC Bureau, 2005).
Low-NOx
burners were selected as the combustion modification to be used. Low-NOx burners
are recommended by the UK and the EU and are in use in more than 7 RBLC records
(Table 2.5). Low-NOx burners can reduce NOx emissions by 40-60% and can be used
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on both new and existing facilities (Cooper and Alley, 2002; World Bank, 1999). The
flue gas treatment that was selected is selective catalytic reduction (SCR). A SCR
system is the recommended control technology for the UK and the EU and is in use in
more than 7 RBLC records (Table 2.5). SCR systems are the most developed and
widely spread FGT technology and can remove 60-90% of NOx from flue gases (Cooper
and Alley, 2002; World Bank, 1999). Selective non-catalytic reduction (SNCR) systems
are also recommended to a great extent (Table 2.5) but the removal efficiency is lower
(40-60%), the operating temperature is higher (900ºC – 1 000ºC), and the technology is
not as well developed and wide spread as the SCR (Cooper and Alley, 2002; World
Bank, 1999).
Good combustion practises and control is the only way to reduce carbon monoxide
(CO) emissions from coal-fired power plants. Proper practises and control will ensure
complete or near complete combustion, which consequently reduces CO emissions
(Table 2.6).
Figure 3.1 shows the final technology selection that was made for control of air pollution
from a coal-fired power plant.
3.3 COAL GASIFICATION
During the gasification process various air pollutants are emitted, including PM, SOx,
NOx, VOCs, hydrogen sulphide (H2S) and ammonia (NH3).
The majority of these
pollutants are emitted during gas handling and treatment (Table 2.9). The techniques or
technologies used to control releases to air from a gasification process are discussed
according to the various processes associated with gasification, namely:
•
materials handling,
•
gasification, and
•
gas purification and conversion.
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Ammonia (NH3)
-
NOx
NH3
Cleaned
flue gas
+
NOx
Limestone
slurry
Catalyst
Mixture of
water and
limestone
N2
H 2O
Gypsum
Air
Flue
gas
Electrostatic
precipitator
Selective catalytic
reduction system
Wet limestone
absorber tower
Figure 3.1 Schematic diagram of the selected control technologies for the control of air pollution from a coal-fired power plant.
(Adapted from Friend, 1995 and EPDC, 2004.)
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3.3.1 Materials handling
Coal and other solid raw materials may create a dust problem during receipt and
subsequent handling and operations.
During unloading discharge should be into
purpose built enclosed hoppers, any transfers should take place, if possible, via
enclosed conveyors (Table 2.10). Where open stockpiles are used, transfer to these
from conveyors should be via enclosed discharge towers, this minimises freefall and
reduces wind whipping of fines (Table 2.10). Raw materials removal from stockpiles
should be by bottom off-take and use should be made of enclosed systems with
extraction and arrestment equipment when working with dusty materials (Table 2.10).
Bag or ceramic filters should be used for dust handling. Liquid feedstocks should be
stored in appropriate roofed tanks. Any vented gas should either be scrubbed or
incinerated (Table 2.10).
3.3.2 Gasification
Gasification will normally take place at high pressures and the toxic, offensive and
flammable nature of the gases contained in the gasifier requires high standards of
containment. Coal charging should be via a double lock system, whereby the gases
released from the reactor during charging are contained within the lock hopper. After
closure of the charge valve they are routed either to recompression for re-injection into
the crude gas stream or to a vent treatment system (Table 2.11). Alternatively, a wet
feed (slurry) system may be used with comparable features. All process vents and
pressure reliefs should be routed to a flare system.
Flares should be designed to
ensure destruction of combustible gases and impurities at all flow rates, including
pressure relief at full operating pressure (Table 2.11). Handling and disposal systems
for ash and slag should be designed and operated to prevent the emission of fine
particulate matter to atmosphere to the standards specified for materials handling
(Section 3.3.1).
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3.3.3 Gas purification and conversion
The diversity of crude gas purification and conversion options available prevents the
selection of detailed procedures for these processes, but the following general
procedures should be observed. They are by no means a full representation of the
options available and each case should be considered individually on its merits.
3.3.3.1 Liquid quenching
If a side stream of the aqueous liquor is removed to maintain process conditions, any
flash steam/gas arising on pressure let down should be totally contained and routed to
an appropriate treatment system or combined with the acid gas stream from later
treatment stages and routed to the sulphur recovery unit (Table 2.12).
3.3.3.2 Particulate matter removal
Where dry removal of particulate matter is carried out prior to purification or conversion,
the collected material should be removed from the system via a lock hopper
arrangement - designed to prevent the loss of process gases to atmosphere (Table
2.12).
3.3.3.3 Acid gas streams
Gas treating or sweetening is a term used to describe the various processes for removal
of certain contaminants, primarily H2S and carbon dioxide (CO2) from natural gas or
hydrocarbon liquids.
CO2 and H2S are also termed “acid gases” because when
absorbed in water, they form an acidic solution. In addition to H2S and CO2, the sulphur
acids, carbonyl sulphide (COS), carbon disulphide (CS2), and mercaptans, when
present in sufficient quantities, are also candidates for removal with specific amines.
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A number of proprietary regenerative absorption processes, commonly based on
amines (for example, sulfinol), are available and should be used to scrub H2S out of the
fuel gas. The acid gases are recovered in a concentrated gas stream and this stream
should be treated by a sulphur recovery process (for example, a Claus kiln), in which
the gases are partially oxidised and elemental sulphur recovered by catalytic treatment
(Table 2.12). The final vent gas from the relevant sulphur recovery process should be
incinerated (Table 2.12).
Carbonyl sulphide (COS), methyl mercaptan and other
sulphur containing minor constituents of the gas stream may be removed by conversion
and forwarding to the sulphur recovery process. Hydrogen cyanide and NH3 should be
removed from the gas stream by water scrubbing and can be routed to the sulphur
recovery process (Table 2.12).
CO2 should be released via an appropriate stack,
provided the concentration of the CO2 is adequately low (Table 2.12). All process vents
and pressure reliefs should be contained and routed to the incinerator or flare system
(Table 2.12).
Figure 3.2 gives an example of the gas treating units.
Desulphurisation
HCN/COS
conversion
Sulfinol
Clean fuel gas
Claus
Wet
cleaning
Tail gas
treatment
Raw gas
Dust
removal
Residual waste
gas firing
Sulphur
Figure 3.2 Gas treating units for coal gasification.
(Adapted from HMIP, 1995b.)
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3.4 PETROLEUM REFINING
Petroleum refining employs a variety of processes to manufacture multiple products. A
refinery’s processing flow scheme is largely determined by the composition of the crude
feedstock and the petroleum products it chooses to manufacture.
The various
processes emit different air pollutants at varying amounts (Table 2.14).
For many refineries, the catalytic cracking unit’s regenerator is the single largest air
emission source, contributing particulates, SOx, NOx and other hazardous air pollutants.
Because of the large gas volume involved, and the subsequent tons/year of pollutants
generated, controlling emissions from the catalytic cracking unit may allow the plant to
avoid having to control multiple minor sources (Confuorto, Weaver and Eagleson,
2000).
The other major contributor to air pollution from a refining facility is the process furnaces
or process heaters that are used for power generation. The same technologies that
were mentioned in Section 2.8.1 and selected in Section 3.2 can be used to control air
pollution from these units.
Although the abovementioned units are the major contributors to air pollution from a
refining facility, technologies or techniques to control air pollution from smaller units will
also be selected in order to follow an holistic approach.
3.4.1 General volatile organic compounds control
Volatile organic compounds (VOCs) are of concern over an entire refining facility,
therefore technologies and techniques for the prevention and control of VOCs were
discussed in Section 2.8.3 in a generic way, meaning applying to a refinery as a whole.
The following selected technologies or techniques should therefore be applied on the
entire refining facility. The most highly recommended technology is the implementation
of a leak detection and repair programme (LDAR), recommended by both the UK and
the EU and in use in more than 10 RBLC records (Table 2.15). There are various other
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technologies or techniques that are also recommended by all three information sources,
namely (Table 2.15):
•
use of low release valves where gate valves are not essential,
•
use of balanced bellows type relief valves,
•
use of canned pumps or double mechanical seals on conventional pumps, and
•
venting of relief valve emissions to incineration systems.
These technologies or techniques will essentially form part of or will result from a proper
LDAR. The final selection of a control technology to control VOCs emissions from a
refining facility was thus the implementation of a leak detection and repair programme.
3.4.2 Catalytic cracking unit
Particulate matter (PM) emissions in the catalytic cracking unit result from catalyst
escaping the catalytic cracking unit’s regenerator in the flue gas.
Cyclones are
recommended for the control of particulates by al three information sources (Table
2.16), but cyclones still allow a significant amount of fine catalyst to escape. Typically
uncontrolled catalyst emissions exiting cyclones range from 5 – 10 kg per 1 000 kg of
regenerator coke burn-off (Confuorto et al., 2000).
Electrostatic precipitators (ESPs) and wet scrubbers are the other technologies that are
in widespread use in catalytic cracking units for the control of particulates (Table 2.16).
Adding an ESP or wet scrubbing system to control particulates for environmental
compliance represents a significant investment in capital. By only adding particulate
control, the costs for installation and operation are not offset by increase in profits
(Confuorto et al., 2000). It should be noted that the incremental cost of adding SOx
control while adding particulate control is low. With the ability to control SOx, feed
sulphur content and unit capacity can possibly be increased (Confuorto et al., 2000).
Therefore, along with the information in Table 2.16 for final technology selection, a wet
scrubbing system was chosen for the control of PM and SOx emissions.
Controlling NOx emissions from a catalytic cracking unit can once again be obtained
through a combination of flue gas treatment and combustion controls (Table 2.16).
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Regenerator flue gas can be treated by either a SNCR or SCR system, according to the
recommendations by the EU and by more than 7 RBLC records (Table 2.16). For the
same reasons given in Section 3.2 the SCR was chosen during final technology
selection.
For the control of CO emissions from a catalytic cracking unit’s regenerator, the UK, EU
and more than 8 RBLC records (Table 2.16) recommend to either install a downstream
CO boiler, or to ensure proper operation of full combustion type regenerators. Table
2.16 gives the impression that downstream CO boilers are more often utilised, and was
therefore chosen during final technology selection.
If a downstream CO boiler is
installed it must be operated to the correct standards in order to avoid the formation of
hot spots, which could lead to the formation of NOx (HMIP, 1995c).
3.4.3 Coke production unit
During coke production PM may be released from the kiln gas cleaning system, rotary
cooler gas cleaning system, coke handling, and storage and loading operations. Fabric
filters are the recommended technology for the UK, the EU and is used by more than 2
RBLC records for the control of PM releases during coke production. A combination of
an appropriate cyclone with a fabric filter can be used to achieve suitable release levels
(HMIP, 1995c). The principal option, according to the UK, to reduce SOx releases is
through fuel switching. Although this is also recommended by the EU and by more than
2 RBLC records (Table 2.17), the technology or technique that seems to have the
highest frequency of use is wet scrubbing (Table 2.17). Therefore since selection is
based on the frequency of use, wet scrubbing was chosen during final technology
selection. Fuel switching should be considered as a supplementary technique.
3.4.4 Bitumen production unit
The major potential releases from bitumen production occur as releases to air from a
number of sources containing H2S, which can cause odour problems.
Potential
releases into air also include SOx, NOx, oxides of carbon (COx), smoke and particulates.
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Hydrocarbons and sulphur compounds may emanate from leakages, particularly on
overhead systems.
Therefore overheads from the oxidiser should be treated or
scrubbed to remove air pollutants, specifically sulphur compounds prior to incineration.
Gases vented during storage should be vented to an incinerator or other equivalent
arrestment equipment. This may include the use of a wet ESP, which has proven
capable of successfully removing the liquid element of the aerosol that is recovered
from storage vents. Incineration should take place in a purposely-designed incinerator
or a process heater at a temperature of at least 800ºC, and a residence time in the
combustion chamber of at least 0,5 seconds (Table 2.18).
3.4.5 Visbreaking unit
During visbreaking oil is heated to above its decomposition temperature.
The
hydrocarbon molecules break up by thermal cracking to give mixed products, typically
fuel gas, visbreaker naphtha and visbroken gas and fuel oils.
The gas form the visbreaking unit is usually sour, and should be sweetened, typically
amine scrubbing should be applied for the sweetening operation.
The treated gas
should be recovered, either into products or used as refinery fuel gas (Table 2.19). The
above-mentioned operations are not specific control technologies or techniques,
nevertheless they were still chosen during final technology selection to prevent or
control releases to air from a visbreaking unit.
3.4.6 Hydrogen fluoride alkylation unit
This process uses anhydrous, liquid hydrogen fluoride (HF) to catalyse the addition of
iso-butane to a butylene or propylene molecule. The reaction proceeds at moderate
temperatures and pressures and an alkylate is formed having a high octane number,
which is valuable in petrol blending.
It is recommended by the EU that a scrubber using an alkaline solution (NaOH or KOH)
should be used to remove HF from the incondensable gas. Both the EU and the UK
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recommend that an acid relief neutraliser should be operated to reduce HF in the
incondensable gas stream (Table 2.20). They both also recommend that the vented
gas should be passed to flare and not be used as refinery fuel gas, and that a dedicated
flare or stack is retained for this (Table 2.20). While the above are not specific control
technologies or techniques, they were still chosen during final technology selection to
prevent or control releases to air from an HF alkylation unit.
3.4.7 Sulphur recovery unit
Sulphur recovery systems are used on all major refineries as the means by which
sulphur is separated from products streams, captured and converted to a saleable byproduct; instead of being released into the environment.
Sulphur should be recovered from sour gasses by the application of appropriate
techniques to convert it to H2S. Amine scrubbing remains the best available technique
according to the UK and the EU and is in use in more than 1 RBLC record (Table 2.21).
A combination of common and individual scrubbers may be required for H2S removal.
After sulphur has been recovered in its elemental form via, for example a Claus kiln, tail
gases should be treated to remove any residual H2S.
Tail gas treatment can be
achieved through thermal or catalytic incinerators, as recommended by the UK and the
EU and more than 2 RBLC records (Table 2.21).
Thermal incinerators should be
operated at temperature of at least 800ºC with a residence time in the combustion
chamber of at least 0,5 seconds.
Catalytic incinerators should be operated at a
temperature in accordance with the catalyst used (HMIP, 1995c). Therefore for final
technology selection amine scrubbing with an appropriate tail gas incinerator was
chosen to prevent or control releases from a sulphur recovery unit.
3.4.8 Distillation units
The initial process in refineries is one of the most important and consists of distilling the
crude oil into fractions, or cuts, of various boiling ranges that then go forward as either
products to finishing processes, intermediates for conversion processes, or residual
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materials as fuels. Light and heavy cuts receive atmospheric pressure distillation alone
while bottoms, that is residues, are vacuum distilled as a prelude to conversion or
cracking.
Both the EU and the UK recommend that incondensables from vacuum distillation
column condensers should be vented to a process heater or incinerator (Table 2.22).
Further pollution reduction can be achieved if vacuum gaseous streams (vent gases)
are routed to an appropriate amine scrubbing unit prior to incineration. Furthermore,
both the EU and the UK recommend that where ammonia (NH3) injection is applied it
should be done in an enclosed system and de-coking vents must be provided with
proper knock-out and dust suppression facilities (Table 2.22).
While these are not
specific control technologies or techniques, they were still chosen during final
technology selection to prevent or control releases to air from distillation units.
3.4.9 Handling and storage of feedstock and products
Crude oil is normally shipped into refineries through marine terminals but can also arrive
via pipeline, rail or road. Unless properly handled, crude oil can easily give rise to
hydrocarbon releases to air. Similarly, to avoid such releases, intermediates and final
products should be handled and stored in appropriate equipment.
During handling and storage the most highly recommended technology or technique to
reduce or prevent particulate matter (PM) is bottom loading of containers (Table 2.23).
The use of proper tanks, based on the vapour pressure at storage temperature, is
recommended by the UK and the EU and by more than 1 RBLC record to prevent or
control SOx, NOx and VOC emissions during storage and handling operations (Table
2.23). Vapour recovery and incineration is further also recommended by the UK and
the EU and by more than 3 RBLC records to prevent or control NOx and VOC emissions
(Table 2.23).
Figure 3.3 summarises all the air pollution control technologies or techniques that were
selected for petroleum refining.
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Alkylation
Scrubber using an alkaline solution
(NaOH or KOH) to remove HF from
incondensible gas stream
Sulphur recovery
Operate acid relief neutraliser to minimise
HF in the incondensible gas stream
Amine scrubbing to recover sulphur
from sour gases
Vented gas to flare
Recover elemental sulphur from, for
example, a Claus kiln
Tail gas treatment with thermal or
catalytic incinerator
Handling and
storage of
products
Distillation
Catalytic cracking
Incondensibles from vacuum
distillation vented to process
heater or incinerator
Wet scrubbing system for
particulate and SOx control
Vacuum gaseous streams to
amine scrubbing prior to
incineration
Bottom loading and take-off from
containers
SCR for NOx control
Use proper tanks based on vapour
pressure
CO boiler for CO control
Vapour recovery and incineration
Ammonia injection in enclosed
system with proper knock-out and
dust suppression facilities
Coke production
Visbreaking
Fabric filters for particulate control
Amine scrub gas from
visbreaking
Wet scrubbing for SOx control
(fuel switching supplementary technique)
Treated gas recovered as
product or as fuel
Bitumen production
General VOC
control
Leak detection and repair
programme (LDAR)
Treat or scrub overheads before
incineration
Gases vented during storage vented
to incinerator
Incineration: 800oC and 0,5 seconds
Figure 3.3 Schematic diagram summarising the selected air pollution control technologies for petroleum refining.
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Chapter 4
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CHAPTER 4
Cost Analysis
4.1 BACKGROUND
With South African industries trading more often on foreign markets and acquiring more
and more foreign shareholders; they are now being provided with incentives to consider
their effect on the environment as these markets and shareholders require certain
environmental standards. Consequently, industries are becoming progressively more
aware of the environmental and social liabilities pertaining to their operations and
products, and the associated financial effects (USEPA, 2000).
The financial effects associated with applying the air pollution control technologies
selected in Chapter 3 can be assessed by using an environmental costing model. For
the cost analysis conducted in this chapter the EEGECOST environmental accounting
model (De Beer and Friend, 2005) was used to assist in expressing environmental and
social liabilities as environmental costs. Environmental costs are those costs that have
a direct financial impact on a company (internal costs), and costs to individuals, society
and the environment for which the company is not accountable (external costs)
(USEPA, 1996).
The cost analysis completed was for a coal-fired power plant only, since the final
technology selection for a power plant is clearly defined for the entire facility and since
information on this process is more readily available than for the other processes.
Similar cost analyses can be conducted for coal gasification and petroleum refining
should more information on these industries and their associated control technologies
become available.
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Chapter 4
Cost Analysis
4.2 THE EEGECOST MODEL
The EEGECOST model was developed to promote environmental accounting in South
Africa.
The EEGECOST model (Environmental Engineering Group environmental
costing model) is based on the principles of the total cost assessment (TCA)
environmental accounting system. The objective of the model is to fully understand the
cost significance of environmental and human health related decisions, activities and
consequences over the whole life cycle of a product or process. The structure of the
model is given in Figure 4.1 and consists of five steps for analysis (De Beer and Friend,
2005):
•
objective statement and scope of analysis,
•
life cycle assessment,
•
cost inventory,
•
impact assessment, and
•
document results and assumptions.
The model is a spreadsheet-based program and consists of pathways that the user
must follow in specific analysis. These different pathways depend on the objective
statement and scope of analysis, and the amount of data the user needs to acquire (De
Beer and Friend, 2005).
Compiling an objective is the first step of the EEGECOST model.
This entails a
background of the company and provides some informative value to the product or
process being considered. The scope of analysis determines the time frame that is
desired for the analysis and the type of cost comparison (De Beer and Friend, 2005).
The next step of the EEGECOST model is the life cycle assessment (LCA) of the
process or product being considered. The LCA is a procedure that is determined by a
company’s own specific guidelines. Therefore, the model does not support an LCA
procedure in itself, but only the output of a relevant LCA is used as input to the model
(De Beer and Friend, 2005). The LCA for environmental accounting systems entails
coupling a quantitative value to environmental impacts associated with a project by
(Little, 2000):
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Chapter 4
Cost Analysis
OBJECTIVE STATEMENT AND SCOPE OF ANALYSIS
company profile
product description
process description
basis of analysis
period of assessment
1
LIFE CYCLE ASSESSMENT
2
COST INVENTORY
3
MEDIA GROUPS
COST TYPES
air and climate
waste
wastewater
soil and groundwater
noise and vibration
biodiversity and
landscape
radiation
other
Internal
Type I
Type II
Type III
Type IV
External
Type V
IMPACT ASSESSMENT
4
BENEFITS
SUSTAINABILITY INDICATORS
Quantitative
energy efficient use
environmental impacts
social impacts
resource efficient use
financial integrity
cost benefit analysis
Qualitative
ecosystems
human health
DOCUMENT RESULTS AND ASSUMPTIONS
5
Figure 4.1 Structure of the EEGECOST model.
(Adapted from De Beer and Friend, 2005.)
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Chapter 4
•
Cost Analysis
compiling an inventory of relevant energy and material inputs and environmental
releases,
•
evaluating the potential environmental and social impacts associated with identified
inputs and releases, and
•
interpreting the results to make informed decisions.
Coupling a quantitative life cycle assessment to an environmental accounting system
provides a comprehensive view of the environmental impacts of a project and a more
accurate picture of the true environmental trade-offs, with associated financial effects
(USEPA, 2001).
During the third step of the EEGECOST model, output from the LCA of the process or
product is allocated to cost types to be used in the environmental cost inventory. The
model allocates environmental costs to the following cost types (De Beer and Friend,
2005):
•
Type I: site costs,
•
Type II: corporate costs,
•
Type III: impact costs,
•
Type IV: internal intangible costs, and
•
Type V: external costs.
Type I costs are further subdivided in Type I(a) non-recurring site costs and Type I(b)
recurring site costs.
After allocation to cost types, the output from the LCA is translated to an economic
value. Economic values are calculated by recording/entering all relevant present and
future environmental costs and revenues in cost inventory forms. These forms are
categorised into the following environmental media groups (De Beer and Friend, 2005):
•
air and climate,
•
waste,
•
wastewater,
•
soil and groundwater,
•
noise and vibration,
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University of Pretoria etd, van Greunen L M (2006)
Chapter 4
•
biodiversity and landscape
•
radiation, and
•
other costs.
Cost Analysis
Since only the financial effects associated with air pollution and air pollution control was
being considered in this cost analysis, use was only made of the air and climate
environmental media group.
The final report compiled by the EEGECOST model can be compiled according to a
company’s specific regulations, incorporating the reported values as given in the costs
incurred by type form, the cost types by year form and the cost report form of the model
(De Beer and Friend, 2005).
4.3 COST ANALYSIS PROCEDURE
The EEGECOST model was used to study the financial effects of controlling air
pollution from a coal-fired power plant.
The basis of the study was a hypothetical
3 600 MW (six 600 MW units) power plant (Figure 4.2), which is the average size of a
power plant in South Africa (Eskom Holdings Limited, 2003b). The analysis was done
over the time span of one production year, assuming 330 days of production, and it was
assumed the power plant operates at 85% capacity on average. It was further assumed
that the air pollution control technologies operated at their full design control efficiency
(see Table 2.1).
Three different control regimes were analysed with the aid of the EEGECOST model:
•
Control regime 1: Hypothetical power plant with only control of particulate matter
via an electrostatic precipitator (ESP) with 90% operating efficiency. This was done
in order to represent an older plant since older existing ESPs have operating
efficiencies between 90% and 99%, and newer ESPs between 99% and 99,9%
(USEPA, 2003e).
•
Control regime 2: Hypothetical power plant with only particulate matter control in
place in the form of a 99,9% efficient baghouse (fabric filter). This was done in order
to represent a newer plant with a baghouse employed for air pollution control.
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Chapter 4
•
Cost Analysis
Control regime 3: Hypothetical power plant with full pollutant control in place in the
form of the final selected control technologies (see Section 3.2):
99,9% efficient ESP,
60% efficient low-NOx burners,
90% efficient selective catalytic reduction (SCR) system, and
98% efficient wet flue gas desulphurisation (FGD) system with limestone.
Figure 4.2 Photo of a 3 600 MW coal-fired power plant consisting of six 600 MW units.
(Source: Eskom Holdings Limited, 2003a)
The purpose of the cost analysis was to show that the external costs or damage costs
would be greatly reduced if proper air pollution control technologies were utilised. Only
the financial effects associated with air pollution and air pollution control were
considered in the cost analysis.
Since the costs that were obtained for the cost analysis were not all in Rand (R) value
for the year 2005, the costs had to be adjusted to compensate for any price increases
due to inflation and other factors. Cost adjustments were done using the Marshall and
Swift equipment cost index (see Table 4.1) and the following equation (Cooper and
Alley, 2002):
P2003 = Px ×
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CI2003
CI x
(4.1)
University of Pretoria etd, van Greunen L M (2006)
Chapter 4
Cost Analysis
where P2003 = cost in 2003,
Px
= cost in relevant year x,
CI2003 = cost index for 2003, and
CIx
= cost index for relevant year x.
Table 4.1 Marshall and Swift equipment cost indices.
Year
Index*
1988
852
1992
943,10
1997
1056,80
1998
1061,90
1999
1068,30
2002
1104,20
2003
1123,60
* Data from Schweikart (2004) and Cooper and Alley (2002).
Since the most recent cost index available is for the year 2003, the cost analysis was
done by adjusting costs for 2003 and using the exchange rates for 3 November 2003
(see Table 4.2).
Table 4.2 Exchange rates on 3 November 2003.
Exchange Rate 3 November 2003*
Rand/Dollar
6,91
Rand/Euro
7,91
* Data from TSC (2004).
In some cases the capacity of a required piece of equipment differed in capacity of a
known piece of equipment with a known price. The following equation was used to
adjust costs where necessary (Cooper and Alley, 2002):
⎛C ⎞
P2 = P1 ⎜⎜ 2 ⎟⎟
⎝ C1 ⎠
where P1
= price of known equipment,
C1
= capacity of known equipment,
P2
= price of new equipment,
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a
(4.2)
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Chapter 4
Cost Analysis
C2
= capacity of new equipment, and
a
= an exponent (average of 0,6 in the chemical industry).
The following costs were obtained from various literature sources and, where required,
adjusted using Equation 4.1 and Equation 4.2. These costs were then inserted into the
EEGECOST model, following the sequential steps of the program.
4.3.1 Equipment costs
Equipment costs were obtained by sizing literature costs based on a 3 600 MW power
plant, using efficiencies as stated.
4.3.1.1 Electrostatic precipitator
For this cost analysis two different electrostatic precipitators (ESPs), an older ESP with
90% control efficiency and a new ESP with a control efficiency of 99,9%, were used.
The purchase cost of an ESP can be estimated as a function of the collection plate area
as follows (Cooper and Alley, 2002):
P = aA b
where P
= purchase cost [$, 1998],
A
= nett plate area [ft2], and
a,b
= constants, as follows:
(4.3)
for 10 000 ft2 < A < 50 000 ft2, a = 962 and b = 0,628
for 50 000 ft2 < A < 100 000 ft2, a = 90,6 and b = 0,843.
The nett plate area can be calculated by using Equation 4.4 (Cooper and Alley, 2002):
A=
−Q
ln(1 − η)
we
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(4.4)
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Chapter 4
where Q
Cost Analysis
= volumetric flow rate [ft3/min or m3/min],
we
= drift velocity [ft/min or m/min], and
η
= collection efficiency.
The delivered equipment cost (DEC) can be estimated with Equation 4.5 and the total
installed cost (TIC) can be estimated with Equation 4.6 (Cooper and Alley, 2002):
DEC = P × 1,18
(4.5)
TIC = DEC × 2,22
(4.6)
From Appendix A a nett plate area of 13 769 ft2 for a 90% efficient ESP and a nett plate
area of 41 308 ft2 for a 99,9% efficient ESP were calculated. Based on calculated
purchase costs of $ 382 307 and $ 762 158 for the 90% and the 99,9% electrostatic
precipitators respectively, the total installed costs for these units were (Appendix A):
•
90% efficient ESP
= R 44 million, and
•
99,9% efficient ESP
= R 100 million.
Based on the volume of flue gas treated the operating costs for both the 90% and the
99,9% ESP were calculated to be R 20 million (Appendix A).
4.3.1.2 Fabric filter
The purchase cost of a baghouse system (fabric filter) can be estimated as a function of
gross cloth area.
Equation 4.7 was used to calculate the gross cloth area of the
baghouse system (Cooper and Alley, 2002):
GCA =
where GCA = gross cloth area [ft2],
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Q
V
(4.7)
University of Pretoria etd, van Greunen L M (2006)
Chapter 4
Cost Analysis
Q
= volumetric gas flow rate [ft3/min], and
V
= maximum filtering velocity [ft/min].
From Appendix A a gross cloth area of 58 858 ft2 for a 600 MW unit was calculated.
Since the gross cloth area is greater than 30 000 ft2 but smaller than 70 000 ft2, a large
shaker baghouse was selected and Equations 4.8 to 4.10 used to estimate the
purchase cost of a baghouse (Cooper and Alley, 2002):
BBP = $ 96 230 + $ 3,33 × GCA
where BBP
(4.8)
= basic baghouse price [$ 1998], and
SSA = $ 51 280 + $ 1,43 × GCA
where SSA
= stainless-steel add-on [$ 1998].
INS = $ 26 330 + $ 0,57 × GCA
where INS
(4.9)
(4.10)
= insulation add-on [$ 1998].
The total purchase cost of the baghouse system is the baghouse price plus the cost of
the bags. Shaker loop top bags were selected and the bag price was estimated with
Equation 4.11 (Cooper and Alley, 2002):
BP = 0,63 × GCA
where BP
(4.11)
= bag price [$ 1998].
The delivered equipment cost (DEC) can be estimated with Equation 4.12 and the total
installed cost (TIC) can be estimated with Equation 4.13 (Cooper and Alley, 2002):
DEC = P × 1,18
(4.12)
TIC = DEC × 2,19
(4.13)
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Chapter 4
Cost Analysis
Based on the calculated purchase cost of $ 542 632, the total installed cost in 2003 was
R59 million (Appendix A).
Based on the estimates made for the ESPs operating costs the operating cost for the
baghouse system was calculated to be R 20 million (Appendix A).
4.3.1.3 Low-NOx burners
Low-NOx burners appear to be very cost effective, yielding 40%-60% reductions at a
capital cost of about 6-9 $/kW (STEP, 2005; Cooper and Alley, 2002).
Based on the calculated capital cost of $ 27 million, the capital cost in 2003 was
R 198 million (Appendix A).
4.3.1.4 Selective catalytic reduction system
The capital costs for selective catalytic reduction (SCR) and selective non-catalytic
reduction systems (SNCR) have significantly declined in the last 20 years, due to
improved designs and more familiarity with the technology (Cooper and Alley, 2002).
The capital cost of a SCR in 1997 was estimated at between 44-66 $/kW with a 70-80%
control efficiency (STEP, 2005; Cooper and Alley, 2002), and the operating cost of a
SCR system in 1997 was estimated between 1,60-3,25 $/MWh (STEP, 2005).
Based on the calculated capital cost of $ 198 million, the capital cost in 2003 was
R 1,5 billion and with the operating cost calculated at $ 59 million, the operating cost in
2003 was R 433 million (Appendix A).
4.3.1.5 Wet flue gas desulphurisation with limestone
The technology of flue gas desulphurisation (FGD) systems is now more advanced than
it was in the 1970s, and costs have decreased.
Nevertheless, FGD systems still
represent a huge investment, as much as 20% of the capital cost of a new coal-fired
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Chapter 4
Cost Analysis
power plant (Cooper and Alley, 2002). The capital cost for a FGD system can be
estimated at between 100-250 $/kW and the operating cost at between 20-50 $/kW
(USEPA, 2003a).
Based on the calculated capital cost of $ 630 million, the capital cost in 2003 was
R 4,4 billion and with the operating cost calculated at $ 126 million, the operating cost in
2003 was R 886 million (Appendix A).
4.3.2 Life cycle assessment
Life cycle assessment (LCA) data is specific to every plant and every situation.
However, since this analysis is based on a hypothetical 3 600 MW plant, use was made
of annual reported data representing a number of power plants. Typically life cycle data
is more complete, but for the purpose of this analysis the annual reported data given in
Table 4.3 was used to represent LCA data for the hypothetical plant. Other inputs to the
process, for example coal and electricity, were not available as intrinsic values and the
total cost spent on primary energy was used to determine these relevant costs (see
Section 4.3.4.4).
Table 4.3 Annual reported data used in the cost analysis to represent LCA data.
Input
Unit
Number of units
Water
ℓ/kWh
1,29
Output
Unit
Number of units
PM
g/kWh
0,28
SO2
g/kWh
8,22
NOx
g/kWh
3,62
CO2
g/kWh
0,9
Data from Eskom Holdings Limited (2003b).
The data shown in Table 4.3 was converted to mass values for one production year
(see Appendix A). In order to calculate the pollutants emitted for each control regime,
the yearly mass values were reduced according to the applicable removal efficiency of
the control technologies in place. For Control regime 1 no reductions were applied
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Chapter 4
Cost Analysis
since it was assumed that the data in Table 4.3 applies to a power plant with a 90%
efficient ESP already in place (see Appendix A).
4.3.3 External costs
External costs (also know as externalities) associated with coal-fired power generation
are the costs imposed on society, individuals and the environment that are not
accounted for by the producers and consumers of energy, that is, they are not included
in the market price. These costs include, for instance, damage to the natural and built
environment such as the effects of air pollution, occupational disease and accidents. A
research project of the European Commission, known as the ExternE Project,
attempted to use a consistent 'bottom-up' methodology to evaluate the external costs
associated with, inter alia, a coal-fired power plant (European Commission, 2001).
External costs were obtained from the ExternE project for the United Kingdom (UK),
since this country’s information was used throughout the investigation.
Although there is information available on the external cost per unit electricity, these
costs depend heavily on the specific technology in place and the site of the facility.
They are therefore hardly transferable between fuel sources, technologies and different
locations and can therefore be very much misleading. Use was thus made of damage
costs per unit pollutant emitted, since these costs can be used in a more general
context, as it does not depend on the fuel source and the abatement technologies in
place (Krewitt et al., 1999). Table 4.4 shows the 1998 estimated damage costs per ton
pollutant emitted in Euro’s, and Table 4.5 the 2003 estimated damage costs per ton
pollutant in Rands (see Appendix A).
Table 4.4 Estimated damage costs in 1998 per ton pollutant emitted.
Pollutant
€/ton of pollutant [1998]*
SO2
6 818
NOx
5 736
PM
14 0623
CO2
139
* Data from European Commission (2001).
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Chapter 4
Cost Analysis
Table 4.5 Estimated damage costs in 2003 per ton pollutant emitted.
Pollutant
R/ton of pollutant [2003]
SO2
57 091,35
NOx
48 029,68
PM
117 750,6
CO2
1 163,90
As no externalities data is available for South Africa, data for the United
Kingdom/Europe was used for the estimated damage costs shown in Table 4.5.
However, as the majority of power stations in the United Kingdom (UK) and Europe are
located much closer to towns and cities (even within cities) than in South Africa (Friend,
1995), it is anticipated that these values are much higher than can be expected for
similar data for South Africa. For this reason some modification to the UK/European
data is required to formulate data that is more applicable to South Africa (see Appendix
A). Using an adjustment factor (kLF) of 0,22 (Appendix A), the data from Table 4.5 was
adjusted for South African conditions and is shown in Table 4.6.
Table 4.6
Estimated damage costs adjusted for South African conditions in Rand per
ton pollutant emitted.
Pollutant
R/ton of pollutant [2003]
SO2
12 560,10
NOx
10 566,53
PM
25 905,13
CO2
256,06
4.3.4 Other costs
4.3.4.1 Insurance for environmental liabilities
Insurance for environmental liability includes the annual contribution to insurance
against traditional damage to persons, goods and biodiversity caused by dangerous and
potentially dangerous activities and, insurance for transportation of hazardous materials
(De Beer and Friend, 2005). An amount of R 12 million was allocated for pollution
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University of Pretoria etd, van Greunen L M (2006)
Chapter 4
Cost Analysis
control costs, rehabilitation and any future closures (see Appendix A) based on a
3 600 MW power plant for one production year. The EEGECOST model automatically
allocates insurance costs as Type II costs.
4.3.4.2 Provisions for environmental management
These costs include future expenses related to, for example, remedial activities,
equipment repairs and governmental and public hearings that can result due to an
accidental event; for example, air emission releases due to control equipment
breakdown (De Beer and Friend, 2005). An amount of R 84 million was allocated for
non-current liabilities (see Appendix A) like future pollution control costs and future
rehabilitation costs. This cost is based on a 3 600 MW power plant for one production
year. Any provisions are automatically allocated as Type III costs by the EEGECOST
model.
4.3.4.3 Research and development
Research and development accounts for extra expenses related to internal
environmental related research and development projects. Research and development
costs can be allocated as either Type I or Type II costs, based on the company’s own
regulations (De Beer and Friend, 2005). For the purpose of this cost analysis 40% was
allocated to Type I costs and 60% was allocated to Type II costs.
An amount of
R 2 million was allocated for research and development for a 3 600 MW power plant for
one production year (see Appendix A).
4.3.4.4 General direct costs
Direct costs represent direct capital outlay and include raw materials like primary energy
and water and any other auxiliary materials that become part of the product. Direct
costs can be allocated as either Type I or Type II costs, based on the company’s own
regulations (De Beer and Friend, 2005). For the purpose of this cost analysis 40% was
allocated to Type I costs and 60% was allocated to Type II costs.
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Chapter 4
Cost Analysis
An amount of R 94 million is paid annually for water and an amount of R 965 million is
paid annually for primary energy, which includes coal and electricity (see Appendix A).
A further amount of R 82 million is paid annually for other materials (Appendix A).
These costs were all based on a 3 600 MW power plant for one production year.
4.4 COST ANALYSIS RESULTS
The purpose of this cost analysis was to show specifically the financial effects of
controlling air pollution. This was done by inserting all aforementioned costs into the
EEGECOST model and consequently comparing the external costs (Type V) of the
different analyses. Special attention was paid to external costs since it was assumed
that, apart from the extra expenditure on control equipment; all other costs would stay
fairly constant for the different analyses. External costs are furthermore becoming more
and more relevant since these costs are not taken into account when making decisions
but are real to members of society (European Commission, 2001). Valuing external
costs therefore allows these values to be included and considered during decisionmaking (European Commission, 2001).
For Control regime 1, a hypothetical 3 600 MW power plant was analysed for one
production year. All the costs were inserted into the EEGECOST model and the model
automatically assigned the costs to the different cost types. In all analyses a discount
rate of 12% was used for Type I to IV costs, which are internal to the company, and a
discount rate of 3% for Type V costs, which are external to the company. It is important
to note that in the cost analysis attention was only on the financial effects of air pollution
and air pollution control.
The percentage contribution by cost type for a 3 600 MW coal-fired power plant for one
production year with Control regime 1 is shown in Figure 4.3. Type V costs (external
costs) contribute 74%, and Type II cost, which is mostly the capital cost of the control
equipment, contribute 14%. The external costs seem exaggerated since the only large
capital expenditure in the analysis is that of the ESP.
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Chapter 4
Cost Analysis
For Control regime 2 the same hypothetical 3 600 MW power plant was analysed, but in
this analysis the air pollution control device was a 99,9% efficient fabric filter (see
Figure 4.4). There is little difference between Control regime 1 and 2; with an external
cost reduction of only 1%. This can be contributed to the fact that the two control
devices are fairly similar in efficiency and capital expenditure.
In the last analyses the hypothetical 3 600 MW power plant was analysed with Control
regime 3 in place. All the major pollutants are being controlled to some extent, except
for carbon dioxide (CO2). Figure 4.5 shows the percentage contribution by cost type for
a 3 600 MW coal-fired power plant for one production year with Control regime 3. The
external costs are significantly reduced by 64% if all the major air pollutants are
controlled. However, it is also important to note that Type II cost have now increased to
73%.
V
74%
II
14%
I (b)
5%
Figure 4.3
I (a)
5%
Percentage contribution of the various cost types associated with a coalfired power plant controlling only particulate matter via an electrostatic
precipitator.
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Chapter 4
Cost Analysis
V
73%
III
2%
II
15%
I (b)
5%
Figure 4.4
I (a)
5%
Percentage contribution of the various cost types associated with a coalfired power plant controlling only particulate matter via a bag filter.
II
73%
III
3%
I (b)
7%
Figure 4.5
V
10%
I (a)
7%
Percentage contribution of the various cost types associated with a coalfired power plant controlling particulate matter, sulphur oxides and
nitrogen oxides.
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Chapter 4
Cost Analysis
From Figure 4.3 to Figure 4.5 the external costs were reduced by almost 64% by
controlling all the major air pollutants through increasing the capital expenditure on
control technologies with 58%. The percentage contribution of the external costs are so
high since these costs have to be carried by individuals, the environment and society
every year, while the capital expenditure on air pollution control technologies are
depreciated over their depreciable life. Furthermore, only the effect of air pollution and
controlling air pollution are included in the analyses.
Another way to illustrate the financial effects associated with applying air pollution
control technologies selected in Chapter 3 is shown in Figure 4.6.
There is little
difference between Control regime 1 and 2, since the control technologies control the
same pollutant to almost the same extent. However, the total cost of Control regime 3
is reduced by almost R 1,6 billion compared to the other two control regimes. The
external costs for Control regime 3 was reduced by almost R 3,4 billion by applying the
control technologies selected in Chapter 3. This reduction in external cost was brought
about by increasing the capital expenditure on control technologies by R 1,7 billion.
6000
Rand (millions)
5000
V
IV
III
II
I (b)
I (a)
4000
3000
2000
1000
0
Control Regime 1
Control Regime 2
Control Regime 3
Figure 4.6 Cost incurred by type for the three different control regimes.
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Chapter 5
Conclusions and Recommendations
CHAPTER 5
Conclusions and Recommendations
The future of air quality legislation in South Africa is standing on the verge of a major
transformation, shifting the concept of atmospheric emission control towards pollution
prevention and emission minimisation through a more integrated approach.
This
transformation, along with increased foreign trade, is providing industries with incentives
to consider their effect on the environment and to take action where required. The
knowledge and experience gained from other countries in this regard is a valuable asset
and was used to determine what technologies are best suited to power plants,
gasification and refining processes in South Africa.
Therefore, with the information sourced from other countries the following conclusions
were made regarding the best available technologies or techniques suited to power
plants:
•
an electrostatic precipitators for particulates and heavy metal control,
•
low-NOx burners for reducing nitrogen oxide formation in the boiler or furnace,
•
selective catalytic reduction systems for NOx control, and
•
wet flue gas desulphurisation with limestone for SOx control.
During the gasification process various air pollutants are emitted, including particulate
matter, SOx, NOx, VOCs, hydrogen sulphide and ammonia. The following conclusions
were made regarding the best available technologies or techniques used to control
releases to air from gasification processes:
•
the majority of pollutants are emitted during gas handling and treatment,
•
any gas/flash stream, arising from pressure let down during liquid quenching, should
be treated or combined with acid gas streams and routed to a sulphur recovery unit,
•
any material collected during particulate matter removal should be collected via a
lock hopper,
•
acid gases should be scrubbed in an amine scrubber to remove hydrogen sulphide,
5-1
University of Pretoria etd, van Greunen L M (2006)
Chapter 5
•
Conclusions and Recommendations
concentrated gases should be treated in a sulphur recovery process, for example a
Claus kiln,
•
any other sulphur containing constituents should be removed by conversion and
forwarded to the Claus process,
•
hydrogen cyanide and ammonia should be removed via water scrubbing,
•
carbon dioxide can be released via a stack if the concentration is adequately low,
and
•
all process vents, pressure reliefs and final vent gases should be routed to an
incinerator or flare.
During petroleum refining a variety of processes are used to manufacture multiple
products, determined largely by the composition of the crude feedstock and the
petroleum products manufactured; resulting in various air pollutant emissions.
The
following conclusions were made regarding the best available technologies or
techniques used to control releases to air from refining processes:
•
the catalytic cracking unit’s regenerator can be the largest single air emission source
during the refining process,
•
due to the large gas volume involved, controlling emissions from the catalytic
cracking unit may allow the plant to avoid having to control multiple minor sources,
•
a wet scrubbing system should be utilised to control particulates and SOx emissions
from the cracking unit, as it is not economically feasible to control the two pollutants
separately,
•
regenerator flue gases should be treated with a selective catalytic reduction system
to control NOx emissions, and
•
a CO boiler should be installed downstream of the furnace or boiler to control carbon
monoxide emissions.
It should be noted that the technologies and techniques that should be applied can vary
on a case-by-case basis; depending on the specific industry, the raw materials used,
the process and even the geography of the area. Technologies were selected based on
how frequently a technology or technique was recommended or used by other
countries.
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University of Pretoria etd, van Greunen L M (2006)
Chapter 5
Conclusions and Recommendations
A cost analysis conducted for a power plant with selected air pollution control
technologies in place demonstrated that the selected technologies worked well to
reduce the external cost associated with producing electricity by almost R 3,4 billion.
This reduction in external cost was brought about by increasing the capital expenditure
on control technologies by R 1,7 billion. Even though the cost of controlling air pollution
is high, it resulted in a considerable reduction in external cost that normally has to be
carried by the environment, society and individuals.
It is recommended that the same cost analysis procedure be applied to gasification and
refining processes in order to show what the associated financial effects will be of
applying the selected air pollution control technologies to these two industries.
It is further recommended that the kLF adjustment factor, used to estimate external cost
factors for South Africa, should be calculated more carefully by taking into account other
factors that could contribute to the variance of external cost factors for different
countries.
It is also recommended that further research be conducted in order to
estimate proper external cost factors for South Africa.
In order to aid in future selections, it is recommended that the information obtained from
the various countries for power plants, gasification and refining processes be combined
in a software based, user friendly database.
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University of Pretoria etd, van Greunen L M (2006)
References
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University of Pretoria etd, van Greunen L M (2006)
Appendix A
Cost Calculations
APPENDIX A
Cost Calculations
EQUIPMENT COSTS
Electrostatic precipitator
From Equation 4.4 (Chapter 4) the nett plate areas for the two ESPs were calculated
using a drift velocity of 6 m/min, and assuming the plant consisted of six 600 MW units,
each treating 200 000 m3/hr (3 333 m3/min) flue gas (Eskom Holdings Limited, 2003a):
A=
A 90% =
−Q
ln(1 − η)
we
− 3 333
ln(1 − 0,9) = 1 279,21 m2 = 13 769 ft2 per 600 MW unit, and
6
A 99.9% =
− 3 333
ln(1 − 0,999 ) = 3 873 64 m2 = 41 308 ft2 per 600 MW unit.
6
Since both the 90% and the 99,9% ESP’s nett plate areas are less than 50 000 ft2;
Equation 4.3, can be used to calculate the purchase costs with the relevant constants
(see Chapter 4) as follows:
P = 962 A 0,628
P90%
= $ 382 307 per 600 MW unit (1998), and
P99,9% = $ 762 158 per 600 MW unit (1998).
Using Equations 4.5 and 4.6, the total installed cost (TIC) for a 600 MW unit was
calculated:
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University of Pretoria etd, van Greunen L M (2006)
Appendix A
TIC90%
Cost Calculations
= DEC × 2,22 = P × 1,18 × 2,22
= $ 1 001 492 per 600 MW unit (1998), and
TIC99,9%
= $ 1 996 548 per 600 MW unit (1998).
For a 3 600 MW power plant the total installed cost (TIC) is:
TIC90%
= $ 1 001 492 × 6 = $ 6 008 953 (1998), and
TIC99,9%
= $ 1 996 548 × 6 = $ 11 979 287 (1998).
Adjusting the 1998 costs to 2003 values, Equation 4.1 was used:
P2003 = Px ×
TIC 90%,2003 = 6 008 953 ×
CI2003
CI x
1 123,60
= $ 6 358 094, and
1 061,90
TIC 99,9%,2003 = 11 979 287 ×
1 123,60
= $ 12 675 325.
1 061,90
The corresponding costs in 2003 in Rands were:
TIC90%
= $ 6 358 094 × R 6,91/$ = R 43 928 071,00 and
TIC99,9%
= $ 12 675 325 × R 6,91/$ = R 100 307 068,00.
Unfortunately estimates for operating costs for ESPs are not widely available. However,
one reference stated that the annual operating cost of a unit treating 1 416 m3/min gas
was $ 220 000 in 1988 (STEP, 2005.).
This cost was adjusted to a unit treating
200 000 m3/hr (3 333 m3/min) flue gas with Equation 4.2:
⎛C ⎞
P2 = P1 ⎜⎜ 2 ⎟⎟
⎝ C1 ⎠
Poperating
⎛ 3 333 ⎞
⎟⎟
= 220 000⎜⎜
⎝ 1 416 ⎠
a
0 .6
= $ 367 740 per 600 MW unit in 1988.
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University of Pretoria etd, van Greunen L M (2006)
Appendix A
Cost Calculations
Adjusting the 1988 operating cost to the 2003 value, Equation 4.1 was used:
Poperating,2003 = 367 740 ×
1 123,60
= $ 484 968 per 600 MW unit.
852
The corresponding operating cost in 2003 in Rands were:
= $ 484 968 × R 6,91/$ = R 3 350 644 per 600 MW unit.
Poperating
Therefore for the 3 600 MW power plant the annual operating costs for both the 90%
and the 99,9% ESP is:
= $ 3 350 644 × 6 = R 20 103 866,00.
Poperating
Fabric filter
From Equation 4.7 (Chapter 4) the gross cloth area was calculated using a maximum
filtering velocity of 2 ft/min (Cooper and Alley, 2002), and assuming the plant consisted
of six 600 MW units, each treating 200 000 m3/hr (117 716 ft3/min) (Eskom Holdings
Limited, 2003a):
GCA =
Q 117 716
=
= 58 858 ft2.
V
2
With the gross cloth area (GCA) available, the baghouse price was calculated with
Equations 4.8 to 4.11:
BBP = $ 96 230 + $ 3,33 × 58 858 = $ 292 226 per 600 MW unit in 1998,
SSA = $ 51 280 + $ 1,43 × 58 858 = $ 135 447 per 600 MW unit in 1998,
INS = $ 26 330 + $ 0,57 × 58 858 = $ 59 879 per 600 MW unit in 1998, and
BP = 0,63 × 58 858 = $ 37 080 per 600 MW unit in 1998.
The total baghouse purchase cost is:
P = BBP + SSA + INS + BP = $ 524 632 per 600 MW unit in 1998.
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University of Pretoria etd, van Greunen L M (2006)
Appendix A
Cost Calculations
Using Equations 4.12 and Equation 4.13, the total installed cost (TIC) for a 600 MW unit
was calculated:
TIC
= DEC × 2,19 = P × 1,18 × 2,19
= $ 1 355 755
Adjusting the 1998 cost to the 2003 value, Equation 4.1 was used:
TIC 2003 = 1 355 755 ×
1 123,60
= $ 1 434 528 per 600 MW unit
1 061,90
The corresponding TIC in 2003 in Rands was:
TIC
= $ 1 434 528 × R 6,91/$ = R 9 911 160 per 600 MW unit.
Therefore for the 3 600 MW power plant the TIC for the baghouse system is:
TIC
= $ 9 911 160 × 6 = R 59 466 961,00.
Unfortunately estimates for operating cost for baghouse systems are not widely
available. In order to include an operating cost in the analysis it was assumed that the
operating cost for a baghouse system would be closely related to that of an ESP. The
ESPs’ operating costs were on average 33% of the TIC, and this was used to estimate
the operating cost of the baghouse system:
Poperating = TIC × 0,33 = R 19 624 097,00.
Low-NOx burners
Using the average of the referenced capital cost (see Chapter 4), the capital cost of
installing low-NOx burners in 1997 = $ 7,5 × 3 600 000 kW = $ 27 000 000.
Adjusting the 1997 cost to the 2003 value, Equation 4.1 was used:
P2003 = 27 000 000 ×
1 123,60
= $ 28 706 662
1 056,80
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University of Pretoria etd, van Greunen L M (2006)
Appendix A
Cost Calculations
Therefore the corresponding capital cost in 2003 in Rands was:
P2003 = $ 26 792 884 × R 6,91/$ = R 198 334 325,00.
Selective catalytic reduction system
Using the average of the referenced capital cost (see Chapter 4), the capital cost of a
SCR system in 1997 = $ 55 × 3 600 000 kW = $ 198 000 000.
Adjusting the 1997 cost to the 2003 value, Equation 4.1 was used:
P2003 = 198 000 000 ×
1 123,60
= $ 210 515 519
1 056,80
Therefore the corresponding capital cost in 2003 in Rands was:
P2003 = $ 210 515 519 × R 6,91/$ = R 1 454 451 718,00.
Using the average of the referenced operating cost (see Chapter 4), the operating cost
of a SCR system in 1997 = $ 2,43 × 24 235 200 MWh = $ 58 891 536.
Adjusting the 1997 cost to the 2003 value, Equation 4.1 was used:
P2003 = 58 891 536 ×
1 123,60
= $ 62 614 051
1 056,80
Therefore the corresponding operating cost in 2003 in Rands was:
P2003 = $ 66 479 117× R 6,91/$ = R 432 600 483,00.
Wet flue gas desulphurisation with limestone
Using the average of the referenced capital cost (see Chapter 4), the capital cost of a
wet FGD system with limestone in 2002 = $ 175 × 3 600 00 kW = $ 630 000 000
Adjusting the 2002 cost to the 2003 value, Equation 4.1 was used:
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University of Pretoria etd, van Greunen L M (2006)
Appendix A
Cost Calculations
P2003 = 630 000 000 ×
1 123,60
= $ 641 068 647
1 104,20
Therefore the corresponding capital cost in 2003 in Rands was:
P2003 = $ 641 068 647 × R 6,91/$ = R 4 429 143 282,00.
Using the average of the referenced operating cost (see Chapter 4), the operating cost
of a wet FGD system with limestone in 2002 = $ 35 × 3 600 000 kW= $ 126 000 000.
Adjusting the 2002 cost to the 2003 value, Equation 4.1 was used:
P2003 = 126 000 000 ×
1 123,60
= $ 128 213 729
1 104,20
Therefore the corresponding operating cost in 2003 in Rands was:
P2003 = $ 128 213 729× R 6,91/$ = R 885 828 656,00.
LIFE CYCLE ASSESSMENT
Table A.1 shows the operating statistics of the hypothetical 3 600 MW power plant for
one production year.
Table A.1 Operating statistics for a 3 600 MW power plant.
Parameter
Value
Power plant output
3 600 MW
Production period
1 year
330 days
7 920 hours
Operating capacity
85%
Average output
= 3 600 MW × 0,85 = 3 060 MW
Yearly output
= 3 060 MW × 7 920 h = 24 235 200 MWh
24 235 200 000 kWh
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University of Pretoria etd, van Greunen L M (2006)
Appendix A
Cost Calculations
Using the values in Table A.1 and the annual reported data (Table 4.3, Chapter 4),
yearly mass values were calculated for the hypothetical power plant. The yearly mass
values below is for one production year of a 3 600 MW power plant with Control regime
1 in place.
•
Input
▪
Water = 1,29 ℓ/kWh (Eskom Holdings Limited, 2003b)
1,29 ℓ/kWh × 24 235 200 000 kWh = 31 263 408 000 ℓ = 31 263 kℓ
•
Outputs
▪
PM = 0,28 g/kWh (Eskom Holdings Limited, 2003b)
0,28 g/kWh × 24 235 200 000 kWh = 6 785 856 000 g = 6 786 ton
▪
SO2 = 8,22 g/kWh (Eskom Holdings Limited, 2003b)
8,22 g/kWh × 24 235 200 000 kWh = 199 213 344 000 g = 199 213 ton
▪
NOx = 3,62 g/kWh (Eskom Holdings Limited, 2003b)
= 3,62 g/kWh × 24 235 200 000 kWh = 87 731 424 000 g = 87 731 ton
▪
CO2 = 0,9 g/kWh (Eskom Holdings Limited, 2003b)
0,9 g/kWh × 24 235 200 000 kWh = 21 811 680 000 g = 21 812 ton
The yearly mass values below is for one production year of a 3 600 MW power plant
with Control regime 2 in place.
•
Input
▪
Water = 1,29 ℓ/kWh
1,29 ℓ/kWh × 24 235 200 000 kWh = 31 263 408 000 ℓ = 31 263 kℓ
•
Outputs
▪
PM = 6 786 – (0,099 × 6 786) = 6 114 ton
▪
SO2 = 199 213 – (0× 199 213) = 199 213 ton
▪
NOx = 87 731 – (0× 87 731 ton) = 87 731 ton
▪
CO2 = 21 812 – (0× 21 812 ton) = 21 812 ton
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University of Pretoria etd, van Greunen L M (2006)
Appendix A
Cost Calculations
The yearly mass values below is for one production year of a 3 600 MW power plant
with Control regime 3 in place.
•
Input
▪
Water = 1,29 ℓ/kWh
1,29 ℓℓ/kWh × 24 235 200 000 kWh = 31 263 408 000 ℓ = 31 263 kℓ
•
Outputs
▪
PM = 6 786 – (0,099 × 6 786) = 6114 ton
▪
SO2 = 199 213 – (0,98 × 199 213) = 3 984 ton
▪
NOx = 87 731 – (0,6 × 87 731 ton) = 35 093 – (0,9 × 35 093) = 3 509 ton
▪
CO2 = 21 812 – (0 × 21 812 ton) = 21 812 ton
EXTERNAL COSTS
Adjustment of United Kingdom’s estimated damage costs (Table 4.4, Chapter 4) using
Equation 4.1 and exchange rates from Table 4.2 (see Chapter 4):
PSO2, 2003 = 6 818 ×
1 123,60
= € 7 214,00
1 061,90
PNO x , 2003 = 5 736 ×
1 123,60
= € 6 069,00
1 061,90
PPM, 2003 = 14 063 ×
PCO2, 2003 = 139 ×
1 123,60
= € 14 880,00
1 061,90
1 123,60
= € 147,00
1 061,90
PSO2, 2003
= € 7 214 × R 7,91/€ = R 57 091,00
PNO x , 2003
= € 6 069 × R 7,91/€ = R 48 030,00
PPM, 2003
= € 14 880 × R 7,91/€ = R 117 751,00
PCO 2, 2003
= € 147 × R 7,91/€ = R 1 164,00.
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University of Pretoria etd, van Greunen L M (2006)
Appendix A
Cost Calculations
In order to formulate data that is more applicable to South Africa, an adjustment factor
(kLF) was estimated by comparing the size of the affected population of a United
Kingdom (UK) power plant to the affected population of a South African power plant,
using the following postulation:
The external costs obtained for the UK was based on a power plant in West Burton
(Nottinghamshire) with an output of 1 800 MW (Berry, 1998). Together with another
power plant in Nottinghamshire, Cottam Power Station with an output of 2 000 MW
(EDFE, 2005), these two power plants are comparable, based on output, to the Duvha
Power Station (3 600 MW) located near Witbank, South Africa (Eskom Holdings
Limited, 2003a). The population of Nottinghamshire is approximately 748 300 (NCC,
2002) and the population of Witbank is approximately 167 183 (Brinkhoff, 2005). It was
assumed that the two power plants in Nottinghamshire will affect the entire population to
some extent and it was also assumed that Duvha Power Station only affects the
population of Witbank. An adjustment factor, kLF, for the postulation above was thus
calculated as follows:
k LF =
167 183
= 0,22
748 300
This adjustment factor is a conservative estimate, as the population in Nottinghamshire
is exposed to more than just the two power stations used for this postulation (NCC,
2001).
OTHER COSTS
Insurance for Environmental Liabilities
Insurance for environmental liability = R 95 000 000 (Eskom Holdings Limited, 2003b).
This cost is based on a number of power plants, producing 196 980GWh in one
production year.
It was assumed that R 95 000 000 ÷ 1,9698 × 1011 kWh =
0,0048 R/kWh has been allocated for insurance.
Therefore for a 3 600 MW plant
operating at 85% capacity on average the cost allocated for insurance is:
A-9
University of Pretoria etd, van Greunen L M (2006)
Appendix A
Cost Calculations
0,0048 R/kWh × 24 235 200 000 kWh = R 11 688 212,00.
Provisions for Environmental Management
Provisions for environmental management = R 679 000 000 (Eskom Holdings Limited,
2003b). This cost is based on a number of power plants, producing 196 980 GWh in
one production year.
It was assumed that R 679 000 000 ÷ 1,9698 × 1011 kWh =
0,0034 R/kWh has been allocated for provisions.
Therefore for a 3 600 MW plant
operating at 85% capacity on average the cost allocated for provisions is:
0,0034 R/kWh × 24 235 200 000 kWh = R 83 539 957,00.
Research and Development
An amount of R 16 020 000,00 (representing 9% of the entire R 178 000 000,00 budget
for research and development) is set aside for research and development projects
pertaining specifically to the environment (Eskom Holdings Limited, 2003b). This cost is
based on a number of power plants, producing 196 980 GWh in one production year. It
was assumed that R 16 020 000 ÷ 1,9698 × 1011 kWh = 8,31 × 10-5 R/kWh has been
allocated for environmental research and development. Therefore for a 3 600 MW plant
operating at 85% capacity on average the cost allocated for research and development
is:
8,31 × 10-5 R/kWh × 24 235 200 000 kWh = R 1 971 002,00.
General Direct Costs
From the yearly mass values calculated from the annual reported data (Table 4.3,
Chapter 4), the total water used for a 3 600 MW power plant, operating at 85% capacity
on average, was 31 263 408 000 ℓ for one production year. The cost of water was
taken as R 0,003/ℓ (Kruger, 2005). Therefore the cost of water for one production year
is:
31 263 408 000 × R 0,003/ℓ = R 93 790 224,00.
An amount of R 7 847 000 000 has been allocated for primary energy, which includes
both coal and electricity (Eskom Holdings Limited, 2003b). This cost is based on a
A-10
University of Pretoria etd, van Greunen L M (2006)
Appendix A
Cost Calculations
number of power plants, producing 196 980 GWh in one production year.
It was
assumed that R 7 847 000 000 ÷ 1,9698 × 1011 kWh = 0,04 R/kWh has been allocated
for primary energy. Therefore for a 3 600 MW plant operating at 85% capacity on
average the cost allocated for primary energy is:
0,04 R/kWh × 24 235 200 000 kWh = R 965 446 311,00.
An amount of R 665 000 000 has been allocated for any other materials (Eskom
Holdings Limited, 2003b). This cost is based on a number of power plants, producing
196 980 GWh in one production year.
It was assumed that R 665 000 000 ÷
1,9698 × 1011 kWh = 0,0034 R/kWh has been allocated for other material costs.
Therefore for a 3 600 MW plant operating at 85% capacity on average the cost
allocated for other material costs is:
0,0034 R/kWh × 24 235 200 000 kWh = R 81 817 484,00.
A-11
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