BAT Large Combustion Plants

Large Combustion Plants, CARDS 2004 project Further Approximation of Croatian Legislation with the Environmental Acquis

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BAT GUIDANCE NOTE – LARGE COMBUSTION PLANTS


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Contents

1 INTRODUCTION...................................................................................3

BACKGROUND TO THE GUIDANCE NOTES...........................................................................................3

2 PROCESS DESCRIPTION...................................................................5

3 ENVIRONMENTAL ISSUES.................................................................6

4 EMISSION LIMITS, MONITORING AND OTHER REQUIREMENTS..6

5 OTHER TECHNIQUES.......................................................................13

6 ENVIRONMENTAL QUALITY............................................................15

7 MANAGEMENT ..................................................................................16

8 PARTICULAR ISSUES THAY AFFECT CROATIAN LARGE COMBUSTION PLANTS 17

CONTROL OF EMISSIONS TO AIR FROM LIQUID FUEL-FIRED BOILERS ............................................. 17

9 DEFINITIONS......................................................................................21

10 REFERENCES....................................................................................45

11 AKNOWLEDGEMENTS .....................................................................46

Tables

Contents ...................................................................................................................................................2 Table 5: BAT for the reduction of particulate emissions from some combustion plants ..........................7 Table 1: BAT for the reduction of SO2 emissions from some combustion plants ....................................8 Table 2: BAT for the reduction of NOX from coal-and lignite-fired combustion plants .............................9 Table 3 BAT for the reduction of NOX from peat, biomass and liquid fuel-fired combustion plants.........9 Table 4: BAT for the reduction of NOX and CO emissions from gas-fired combustion plants ...............10 Table 5: Some BAT conclusions for storage and handling of fuel and additives ...................................13 Table 6: Levels of thermal efficiency associated with the application of BAT measures for coal and lignite fired combustion plants ................................................................................................................14 Table 7: Thermal efficiency levels associated with peat and biomass fired combustion plants ............15 Table 8: Efficiency of gas-fired combustion plants associated to the use of BAT..................................15


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1 INTRODUCTION

Background to the Guidance Notes

• This is one of a series of notes describing the Best Available Techniques (BAT) conclusions for industry sectors. The notes are all aimed at providing a strong framework for consistent and transparent regulation of processes and installations. A number of Guides reporting on horizontal issues have been prepared and the Horizontal Guide on Assessing BAT is document number xxxxxxxx and this should be referred to when setting permit conditions.

• When determining BAT for a new installation, the BAT conclusions given in the BREFs, or more advanced techniques where applicable should be used. The BAT Associated Emission Levels (BATAELs) should not be exceeded when emission limit values are set at a local level and the lower value of any range should be used.

• When determining BAT for an existing installation it is possible to decide on a derogation that takes into account the environmental costs and benefits and set slightly more relaxed limit values at a local level. A range of factors may be taken into consideration when deciding the most appropriate techniques to provide the best protection for the environment as a whole. The objective is to set permit conditions in order that the installation shall approach as closely as possible the standards that would be set for a new plant, but taking into account the cost-effectiveness, time-scale and practicality of making changes to the existing plant. Annex IV to the IPPC Directive lists the considerations to be taken into account when determining BAT at a local level.

• When assessing the applicability of the BAT or the associated emission levels for an existing installation, departures or derogations may be justified which are either stricter or less strict than BAT as described in the BREFs. The most appropriate technique depends upon local factors and a local assessment of the costs and benefits of the available options may be needed to establish the best option. The justification for departing from the BREF conclusions must be robust and must be recorded.

• Departures may be justified on the grounds of environmental costs and benefits and local conditions such as the technical characteristics of the installation concerned, its geographical location and the local environmental conditions but not on grounds of individual company profitability.

• All processes are subject to BAT. In general terms, what is BAT for one process in a sector is likely to be BAT for a comparable process; but in each case it is in practice for regulators (subject to appeal) to decide what is BAT for the individual process and the regulator should take into account variable factors (such as configuration, size and other individual characteristics or the process) and the locality (such as proximity of particularly sensitive receptors. Ultimately what constitutes BAT is site specific but this guidance note comprises guidance for the generality of processes in the sector and careful regard should be had to it, in order to maximise consistency of permits as appropriate.

• This guidance is for: o regulators: who must have regard to the guidance when determining

applications and reviewing extant authorisations and permits, o Operators: who are best advised also to have regard to it when making

applications, and in the subsequent operation of their process, o members of the public: who may be interested to know what is considered to

be appropriate conditions for controlling emissions for the generality of processes in this particular industry sector.

• The guidance is based on the state of knowledge and understanding at the time of writing of:


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o Large Combustion Plant processes, o their potential impact on the environment, and o what constitutes BAT for preventing and reducing emissions.

• This note is based on the BAT conclusions from the BREF for the Large Combustion Plant Sector. This BREF provides a lot of additional information to that contained here and if there are any doubts about the contents and conclusions from this document then the BREF should be consulted.

• In addition to the BREFs, Guidance published by other Countries has been used and these Guidance Notes may also provide additional information.

• The note may be amended from time to time in order to keep abreast with developments in BAT: including improvements in techniques, and new understanding of environmental impacts and risks. Such changes may be issued in a complete revision of this document, or in separate additional guidance notes which address specific issues.

• The following Croatian Guidelines should also be consulted to give a full understanding of the issues:

• BAT Assessment

• Energy Efficiency

• Monitoring Techniques

• Noise

• Decommissioning

• Waste Minimisation

• Environmental Management Systems

• Contaminated Land Assessment

• Fugitive Emissions

• Wastewater/waste gas treatment

• Cooling Systems

• Waste Gas, Waste Water Treatment


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2 PROCESS DESCRIPTION 2.1 This Note refers to combustion installations with a rated thermal input exceeding

50MW, revision of the IPPC Directive will lower this threshold to 20 MW. This includes the power generation industry and those industries where ‘conventional’ (commercially available and specified) fuels are used and where the combustion units are not covered within another sector BREF. Coal, lignite, biomass, peat, liquid and gaseous fuels (including hydrogen and biogas) are regarded as conventional fuels. Incineration of waste is not covered, but co-combustion of waste and recovered fuel in large combustion plants is addressed.

2.2 The Note covers not only the combustion unit, but also upstream and downstream activities that are directly associated to the combustion process. Combustion installations which use process-related residues or by-products as fuel, or fuels that cannot be sold as specified fuels on the market as well as combustion processes which is an integrated part of a specific production process are not covered by this Note.

2.3 Power generation in general utilises a variety of combustion technologies. For the combustion of solid fuels, pulverised combustion, fluidised bed combustion as well as grate firing are all considered to be BAT under the conditions described in this document.

2.4 For liquid and gaseous fuels, boilers, engines and gas turbines and dual fuel applications, BAT is described in this document. In particular for Croatia attention is drawn to the conclusions about abatement plant that is applicable for heavy fuel oil firing.

2.5 The choice of system employed at a facility is based on economic, technical,

environmental and local considerations, such as the availability of fuels, the operational requirements, market conditions, network requirements. Electricity is mainly generated by producing steam in a boiler fired by the selected fuel and the steam is used to power a turbine which drives a generator to produce electricity. The steam cycle has an inherent efficiency limited by the need to condense the steam after the turbine.

2.6 Some liquid and gas fuels can be directly fired to drive turbines with the combustion

gas or they can be used in internal combustion engines which can then drive generators. Each technology offers certain advantages to the operator especially in the ability to be operated according to variable power demand.

2.7 BAT associated levels might become legally binding once the IPPC and LCP Directives are revised and LCP emissions might be required to meet more stringent standards by 2016. The proposed, draft standards are included in the guideline.


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3 ENVIRONMENTAL ISSUES

3.1 Most combustion installations use fuel and other raw materials taken from the earth’s natural resources, converting them into useful energy. Fossil fuels are the most abundant energy source used today. However, their burning results in a relevant and, at times, significant impact on the environment as a whole. The combustion process leads to the generation of emissions to air, water and soil, of which emissions to the air are considered to be one of the main environmental concerns.

3.2 The most important emissions to air from the combustion of fossil fuels are SO2, NOX, CO, particulate matter (PM10) and greenhouse gases, such as N2O and CO2. Other substances such as heavy metals, halide compounds, and dioxins are emitted in smaller quantities. Dilution of the gases or wastewater is not considered to be acceptable.

4 EMISSION LIMITS, MONITORING AND OTHER REQUIREMENTS.

4.1.1 Conditions of measurement

The BAT associated emission levels are based on daily average, standard conditions of temperature and pressure and an O2 level of 6% for solid fuels, 3% for liquid and gaseous fuels and 15% for gas turbines, which represents a typical load situation. For peak loads, start up and shut down periods as well as for operational problems of the flue-gas cleaning systems, short-term peak values, which could be higher, have to be considered. Sampling or measuring should take place only during the operation of the process and dilution air should be excluded.

4.1.2 Particulate matter (dust) emissions

Particulate matter (dust) emitted during the combustion of solid or liquid fuels, arises almost entirely from their mineral fraction. During combustion of liquid fuels, poor combustion conditions lead to the formation of soot. Combustion of natural gas is not a significant source of dust emissions. The emission levels of dust, in this case, are normally well below 5 mg/Nm3 without any additional technical measures being applied. For dedusting off-gases from new and existing combustion plants, BAT is considered to be the use of an electrostatic precipitator (ESP) or a fabric filter (FF), where a fabric filter normally achieves emission levels below 5 mg/Nm3. Cyclones and mechanical collectors alone are not BAT, but they can be used as a pre-cleaning stage in the flue-gas path. The BAT conclusion for dedusting and the associated emission levels are summarised in Table 5. For combustion plants over 100 MWth, and especially over


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300 MWth, the dust levels are lower because the FGD techniques, which are already a part of the BAT conclusion for desulphurisation, also reduce particulate matter.

Dust emission level (mg/Nm3) BAT to reach these levels

Coal and lignite Biomass and peat Liquid fuels for boilers Capacity

(MWth) New plants

Existing plants

New plants

Existing plants

New plants

Existing plants

50 – 100 5 – 20* 5 – 30* 5 – 20 5 – 30 5 – 20* 5 – 30* ESP or FF

100 – 300 5 – 20* 5 – 25* 5 – 20 5 – 20 5 – 20* 5 – 25*

>300 5 – 10* 5 – 20* 5 – 20 5 – 20 5 – 10* 5 – 20*

ESP or FF in combination FGD (wet, sd or dsi) for PC ESP or FF for FBC

Notes: ESP: Electrostatic precipitator) FF: Fabric filter FGD(wet): Wet flue-gas desulphurisation FBC: Fluidised bed combustion) sd: semi dry dsi: dry sorbent injection * Some split views appeared in these values and are reported in Sections 4.5.6 and 6.5.3.2 of the main document.

Table 5: BAT for the reduction of particulate emissions from some combustion plants

4.1.3 Heavy metals The emission of heavy metals results from their presence as a natural component in fossil fuels. Most of the heavy metals considered (As, Cd, Cr, Cu, Hg, Ni, Pb, Se, V, Zn) are normally released as compounds (e.g. oxides, chlorides) in association with particulates. Therefore, BAT to reduce the emissions of heavy metals is generally the application of high performance de-dusting devices such as electrostatic precipitators (ESPs) or fabric filters (FFs). Hg and Se are partly present in the vapour phase. Mercury has a high vapour pressure at the typical control device operating temperatures, and its collection by particulate matter control devices, is highly variable. For ESPs or FFs operated in combination with FGD techniques, such as wet limestone scrubbers, spray dryer scrubbers or dry sorbent injection, an average removal rate of Hg is 75 % (50 % in ESP and 50 % in FGD) and 90 % in the additional presence of a high dust SCR can be obtained.

4.1.4 SO2 emissions Emissions of sulphur oxides mainly result from the presence of sulphur in the fuel. Natural gas is generally considered free from sulphur. This is not the case for certain industrial gases and desulphurisation of the gaseous fuel might then be necessary. In general, for solid and liquid-fuel-fired combustion plants, the use of low sulphur fuel and/or desulphurisation is considered to be BAT. However, the use of low sulphur fuel for plants over 100 MWth can, in most cases, only be seen as a supplementary measure to reduce SO2 emissions in combination with other measures. Besides the use of low sulphur fuel, the techniques that are considered to be BAT are mainly the wet scrubber (reduction rate 92 – 98 %), and the spray dry scrubber


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desulphurisation (reduction rate 85 – 92 %), which already has a market share of more than 90 %. Dry FGD techniques such as dry sorbent injection are used mainly for plants with a thermal capacity of less than 300 MWth. The wet scrubber has the advantage of also reducing emissions of HCl, HF, dust and heavy metals. Because of the high costs, the wet scrubbing process is not considered as BAT for plants with a capacity of less than 100 MWth.

SO2 emission level (mg/Nm3)

Coal and lignite Peat Liquid fuels for boilers Capacit

y (MWth) New plants

Existing plants

New plants

Existing plants

New plants

Existing plants

BAT to reach these levels

50 – 100 200 – 400* 150 – 400* FBC)

200 – 400* 150 – 400* FBC)

200 – 300

200 – 300

100 – 350*

100 – 350*

100 – 300

100 – 200

100 –250*

200 – 300 150 – 250 (FBC)

200 – 300 150 -300(FBC)

100 – 200*

100 – 250*

>300

20 – 150* 100 – 200 (CFBC/ PFBC)

20 – 200*

100 –200* (CFBC/ PFBC)

50 – 150 50 – 200(FBC)

50 – 200 50 – 150* 50 – 200*

Low sulphur fuel or/and FGD (dsi) or FGD (sds) or FGD (wet) (depending on the plant size). Seawater scrubbing. Combined techniques for the reduction of NOx and SO2. Limestone injection (FBC).

Notes: FBC: Fluidised bed combustion CFBC: Circulating fluidised bed combustion PFBC: Pressurised fluidised bed combustion FGD(wet): Wet flue-gas desulphurisation FGD(sds): Flue-gas desulphurisation by using a spray dryer FGD(dsi): Flue-gas desulphurisation by dry sorbent injection

Table 1: BAT for the reduction of SO2 emissions from some combustion plants

4.1.5 NOX emissions The principal oxides of nitrogen emitted during the combustion are nitric oxide (NO) and nitrogen dioxide (NO2), referred as NOx. For pulverised coal combustion plants, the reduction of NOX emissions by primary and secondary measures, such as SCR, is BAT, where the reduction rate of the SCR system ranges between 80 and 95 %. The use of SCR or SNCR has the disadvantage of a possible emission of unreacted ammonia (‘ammonia slip’). For small solid fuel-fired plants without high load variations and with a stable fuel quality, the SNCR technique is also regarded as BAT in order to reduce NOX emissions. For pulverised lignite and peat-fired combustion plants, the combination of different primary measures is considered as BAT. This means, for instance, the use of advanced low NOx burners in combination with other primary measures such as flue-gas recirculation, staged combustion (air-staging), reburning, etc. The use of primary measures tends to cause incomplete combustion, resulting in a higher level of unburned carbon in the fly ash and


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some carbon monoxide emissions. In FBC boilers burning solid fuel, BAT is the reduction of NOX emissions achieved by air distribution or by flue-gas recirculation. There is a small difference in the NOX emissions from BFBC and CFBC combustion. The BAT conclusion for the reduction of NOX emissions and the associated emission levels for various fuels are summarised in Tables 8, 9 and 10.

NOX emission level associated with BAT (mg/Nm3) Capacity

(MWth) Combustion technique New

plants Existing plants Fuel

BAT options to reach these levels

Grate-firing 200 – 300* 200 – 300* Coal and lignite Pm and/or SNCR

PC 90 – 300* 90 – 300* Coal Combination of Pm and SNCR or SCR CFBC and PFBC 200 – 300 200 – 300 Coal and

lignite

50 – 100

PC 200 – 450 200 – 450* Lignite Combination of Pm

PC 90* – 200 90 – 200* Coal Combination of Pm in combination with SCR or combined techniques

PC 100 – 200 100 – 200* Lignite Combination of Pm 100 – 300 BFBC, CFBC and PFBC

100 – 200 100 – 200* Coal and Lignite Combination of Pm together with SNCR

PC 90 – 150 90 – 200 Coal Combination of Pm in combination with SCR or combined techniques

PC 50 – 200* 50 – 200* Lignite Combination of Pm >300 BFBC,CFBC and PFBC 50 – 150 50 – 200 Coal and

Lignite Combination of Pm

Notes: PC: Pulverised combustion BFBC: Bubbling fluidised bed combustion CFBC: Circulating fluidised bed combustion PFBC: Pressurised fluidised bed combustion Pm: Primary measures to reduce NOx SCR: Selective catalytic reduction of NOx SNCR: Selective non catalytic reduction of NOx The use of anthracite hard coal may lead to higher emission levels of NOX because of the high combustion temperatures

Table 2: BAT for the reduction of NOX from coal-and lignite-fired combustion plants

NOX -emission level (mg/Nm3) Biomass and Peat Liquid fuels

Capacity (MWth)

New plants

Existing plants

New plants

Existing plants

Techniques to reach these levels

50 – 100 150 – 250 150 – 300 150 – 300 150 – 450 Combination of Pm

100 – 300

150 – 200 150 – 250 50 – 150 50 – 200

>300

50 – 150 50 – 200 50 – 100 50 – 150

SNCR/ SCR or combined techniques

Notes: Pm: Primary measures to reduce NOx SCR: Selective catalytic reduction of NOx

Table 3 BAT for the reduction of NOX from peat, biomass and liquid fuel-fired combustion plants

For new gas turbines, dry low NOX premix burners (DLN) are BAT. For existing gas turbines, water and steam injection or conversion to the DLN technique is BAT. For gas-fired stationary engine plants, the lean-burn approach is BAT analogous to the dry low NOX


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technique used in gas turbines. For most gas turbines and gas engines, SCR is also considered to be BAT. Retrofitting of an SCR system to a CCGT is technically feasible but is not economically justified for existing plants. This is because the required space in the HRSG was not foreseen in the project and is, therefore, not available.

Emission level associated with BAT (mg/Nm3) Plant type

NOx CO

O2 level (%)

BAT options to reach these levels

Gas turbines New gas turbines 20 – 50 5 – 100 15 Dry low NOx premix burners or SCR DLN for existing gas turbines 20 – 75 5 – 100 15 Dry low NOx premix burners as retrofitting

packages if available Existing gas turbines 50 – 90* 30 – 100 15 Water and steam injection or SCR Gas engines

New gas engines 20 – 75* 30 – 100* 15 Lean-burn concept or SCR and oxidation catalyst for CO

New gas engine with HRSG in CHP mode 20 – 75* 30 – 100* 15 Lean-burn concept or SCR and oxidation

catalyst for CO Existing gas engines 20 – 100* 30 – 100 15 Low NOx tuned Gas-fired boilers New gas-fired boilers 50 – 100* 30 – 100 3

Existing gas-fired boiler 50 – 100* 30 – 100 3 Low NOx burners or SCR or SNCR

CCGT New CCGT without supplementary firing (HRSG)

20 – 50 5 – 100 15 Dry low NOx premix burners or SCR

Existing CCGT without supplementary firing (HRSG)

20 – 90* 5 – 100 15 Dry low NOx premix burners or water and steam injection or SCR

New CCGT with supplementary firing 20 – 50 30 – 100 Plant

spec. Dry low NOx premix burners and low NOx burners for the boiler part or SCR or SNCR

Existing CCGT with supplementary firing 20 – 90* 30 – 100 Plant

spec.

Dry low NOx premix burners or water and steam injection and low NOx burners for the boiler part or SCR or SNCR

SCR: Selective catalytic reduction of NOx SNCR: Selective non catalytic reduction of NOx DLN: dry low NOX HRSG: heat recovery steam generator CHP: Cogeneration CCGT: combined cycle gas turbine

Table 4: BAT for the reduction of NOX and CO emissions from gas-fired combustion plants

4.1.6 CO emissions

Carbon monoxide (CO) always appears as an intermediate product of the combustion process, BAT for the minimisation of CO emissions is complete combustion, which goes along with good furnace design, the use of high performance monitoring and process control techniques, and maintenance of the combustion system. Some emission levels associated to the use of BAT for different fuels are present in the BAT sections, however in this executive summary only the ones from gas-fired combustion plants are reported.

4.1.7 Water contamination Besides the generation of air pollution, large combustion plants are also a significant source of water discharge (cooling and waste water) into rivers, lakes and the marine environment.


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Any surface run-off (rainwater) from the storage areas that washes fuel particles away should be collected and treated (settling out) before being discharged. Small amounts of oil contaminated (washing) water cannot be prevented from occurring occasionally at a power plant. Oil separation wells are BAT to avoid any environmental damage. The BAT conclusion for wet scrubbing desulphurisation is related to the application of a waste water treatment plant. The waste water treatment plant consists of different chemical treatments to remove heavy metals and to decrease the amount of solid matter from entering the water. The treatment plant includes an adjustment of the pH level, the precipitation of heavy metals and removal of the solid matter. The full document contains some emission levels.

4.1.8 Waste and residues A lot of attention has already been paid by the sector to the utilisation of combustion residues and by-products, instead of just depositing them in landfills. Utilisation and re-use is, therefore, the best available option and has priority. There are many different utilisation possibilities for different by-products such as ashes. Each different utilisation option has different specific criteria. It has not been possible to cover all these criteria in this BREF. The quality criteria are usually connected to the structural properties of the residue and the content of harmful substances, such as the amount of unburned fuel or the solubility of heavy metals, etc. The end-product of the wet scrubbing technique is gypsum, which is a commercial product for the plant in most EU countries. It can be sold and used instead of natural gypsum. Practically most of the gypsum produced in power plants is utilised in the plasterboard industry. The purity of gypsum limits the amount of limestone that can be fed into the process.

4.1.9 Co-combustion of waste and recovered fuel Large combustion plants, designed and operated according to BAT, operate effective techniques and measures for the removal of dust (including partly heavy metals), SO2 NOx, HCl, HF and other pollutants as well as techniques to prevent water and soil contamination. In general, these techniques can be seen as sufficient and are, therefore, also considered as BAT for the co-combustion of secondary fuel. A higher input of pollutants into the firing system can be balanced within certain limits by adaptation of the flue-gas cleaning system or by limitation of the percentage of secondary fuel that can be co-combusted. Regarding the impact of co-combustion to the quality of the residues, the main issue is maintaining the quality of gypsum, ashes, slag and other residues and by-products at the same level as those occurring without the co-combustion of secondary fuel for the purpose of recycling. If co-combustion leads to significant (extra) disposal volumes of by-products or residues or extra contamination by metals (e.g. Cd, Cr, Pb) or dioxins, additional measures need to be taken to avoid this. The following issues need to be taken into account when waste is used as a fuel: The emission limit values need to be calculated in accordance with the requirements of the Waste Incineration Directive which imposes the incineration limits pro-rata to the thermal input of waste.

The use of secondary fuels in a combustion plant needs to be included in a permit. A permit is normally only granted after demonstration trials are undertaken to establish the


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performance and emissions with the fuel mixture and to decide on the percentage substitution so that emission limit values and other permit conditions can be set taking account of the BREF on waste incineration, (on the technical requirements, operational conditions of waste incineration and technological emission limits of waste incineration) and also BAT requirements for protection of the environment as a whole.

Secondary fuels can be used in a number of ways depending on their thermal and physical characteristics. Combustion plants are operated at lowest reasonable excess oxygen factors in order to keep heat losses at minimum. This requires highly uniform and reliable fuel metering as well as the fuel being present in a form, which allows for easy and complete combustion (fuel preparation process and fuel storage). These conditions are fulfilled by all conventional or alternative fuels provided they are pulverised, liquid or gaseous fuels. The main fuel input introduced via the main burner has therefore to be of this type.

Gaseous, liquid, and finely pulverised alternative fuels can be fed to the plant system via any of the normal feed points. Coarse crushed and lump fuels can (with some exceptions) be fed to the mills. All of this should be subject to representative demonstration trials prior to setting permit conditions.

Liquid fuels are easier to handle and burn and can lead to more stable kiln conditions, (e.g. switching some of the solid fuel burning to secondary liquid fuels at some sites has resulted in reductions of NOX due to improved flame characteristics).

The type and amounts of constituents of the fuel, which contribute to pollutant emissions, should be assessed and substitutions made to minimise emissions e.g.:

• Low sulphur content to minimise fuel SO2 emissions.

• Low metal content. Metal content has two main effects. Volatile metals, such as mercury, tend to pass out of the kiln in the exhaust gases so any increases in fuel mercury content may be reflected in increased emissions.

BAT Requirements for co-incineration BAT will be the appropriate selection of raw material analysis and blending, process control, fuel, kiln design and abatement plant to minimise emissions. All of these issues should be dealt with during the demonstration trials.


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5 OTHER TECHNIQUES 5.1.1 Unloading, storage and handling of fuel and additives Some techniques for preventing releases from the unloading, storage and handling of fuels, and also for additives such as lime, limestone, ammonia, etc. are summarised in Table 1.

Particulate matter

• the use of loading and unloading equipment that minimises the height of fuel drop to the stockpile, to reduce the generation of fugitive dust

• in countries where freezing does not occur, using water spray systems to reduce the formation of fugitive dust from solid fuel storage (solid fuels)

• placing transfer conveyors in safe, open areas aboveground so that damage from vehicles and other equipment can be prevented (solid fuels)

• using enclosed conveyors with well designed, robust extraction and filtration equipment on conveyor transfer points to prevent the emission of dust (solid fuels)

• rationalising transport systems to minimise the generation and transport of dust on site (solid fuels)

• the use of good design and construction practices and adequate maintenance (all fuels)

• storage of lime or limestone in silos with well designed, robust extraction and filtration equipment (all fuels)

Water contamination

• having storage on sealed surfaces with drainage, drain collection and water treatment for settling out (solid fuels)

• the use of liquid fuel storage systems that are contained in impervious bunds that have a capacity capable of containing 75 % of the maximum capacity of all tanks or at least the maximum volume of the largest tank. Tank contents should be displayed and associated alarms used and automatic control systems can be applied to prevent the overfilling of storage tanks (solid fuels)

• pipelines placed in safe, open areas aboveground so that leaks can be detected quickly and damage from vehicles and other equipment can be prevented. For non-accessible pipes, double walled type pipes with automatic control of the spacing can be applied (liquid and gaseous fuels)

• collecting surface run-off (rainwater) from fuel storage areas that washes fuel away and treating this collected stream (settling out or waste water treatment plant) before discharge (solid fuels)

Fire prevention • surveying storage areas for solid fuels with automatic systems, to detect fires, caused by self-ignition and to identify risk points (solid fuels)

Fugitive emissions

• using fuel gas leak detection systems and alarms (liquid and gaseous fuels)

Efficient use of natural resources

• using expansion turbines to recover the energy content of the pressurised fuel gases (natural gas delivered via pressure pipelines) (liquid and gaseous fuels)

• preheating the fuel gas by using waste heat from the boiler or gas turbine (liquid and gaseous fuels).

Health and safety risk regarding ammonia

• for handling and storage of pure liquefied ammonia: pressure reservoirs for pure liquefied ammonia >100 m3 should be constructed as double wall and should be located underground; reservoirs of 100 m3 and smaller should be manufactured including annealing processes (all fuels)

• from a safety point of view, the use of an ammonia-water solution is less risky than the storage and handling of pure liquefied ammonia (all fuels).

Table 5: Some BAT conclusions for storage and handling of fuel and additives


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5.1.2 Fuel pre-treatment

Fuel pre-treatment of solid fuel mainly means blending and mixing in order to ensure stable combustion conditions and to reduce peak emissions. To reduce the amount of water in peat and biomass, drying of fuel is also considered to be part of BAT. For liquid fuels, the use of pre-treatment devices, such as diesel oil cleaning units used in gas turbines and engines, are BAT. Heavy fuel oil (HFO) treatment comprises devices such as electrical or steam coil type heaters, de-emulsifier dosing systems, etc.

5.1.3 Thermal efficiency Prudent management of natural resources and the efficient use of energy are two of the major requirements of the IPPC Directive. In this sense, the efficiency with which energy can be generated is an important indicator of the emission of the climate relevant gas CO2. One way to reduce the emission of CO2 per unit of energy generated is the optimisation of the energy utilisation and the energy generating process. Increasing the thermal efficiency has implications on load conditions, cooling system, emissions, use of type of fuel and so on. Cogeneration (CHP) is considered as the most effective option to reduce the overall amount of CO2 released and is relevant for any new build power plant whenever the local heat demand is high enough to warrant the construction of the more expensive cogeneration plant instead of the simpler heat or electricity only plant. The BAT conclusion to increase efficiency and the BAT associated levels are summarised in Tables 3 to 5. In this sense, it should be noted that HFO fired plants are considered to have similar efficiencies than coal fired plants.

Unit thermal efficiency (net) (%) Fuel Combined

technique New plants Existing plants

Coal and lignite Cogeneration (CHP) 75 – 90 75 – 90

PC (DBB and WBB) 43 – 47

FBC >41 Coal

PFBC >42 PC (DBB) 42 – 45 FBC >40

Lignite PFBC >42

The achievable improvement of thermal efficiency depends on the specific plant, but as an indication, a level of 36* – 40 % or an incremental improvement of more than 3 % points can be seen as associated with the use of BAT for existing plants

PC: pulverised combustion DBB: dry bottom boiler WBB: wet bottom boiler FBC: fluidised bed combustion PFBC: pressurised fluidised bed combustion

Table 6: Levels of thermal efficiency associated with the application of BAT measures for coal and lignite fired combustion plants

Unit thermal efficiency (net) (%) Fuel Combined technique Electric efficiency Fuel utilisation (CHP)


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Grate-firing Around 20 Spreader-stoker >23 Biomass FBC (CFBC) >28 – 30

Peat FBC (BFBC and CFBC) >28 – 37

75 – 90 Depending on the specific plant application and the heat and electricity demand

FBC: fluidised bed combustion CFBC: circulating fluidised bed combustion BFBC: bubbling fluidised bed combustion CHP: Cogeneration

Table 7: Thermal efficiency levels associated with peat and biomass fired combustion plants

No specific thermal efficiency values were concluded when using liquid fuels in boilers and engines. However, some techniques to consider are available in the LCP BREF.

Electrical efficiency (%) Fuel utilisation(%) Plant type New plants Existing

plants New and existing plants

Gas turbine Gas turbine 36 – 40 32 – 35 - Gas engine Gas engine 38 – 45 - Gas engine with HRSG in CHP mode >38 >35 75 – 85

Gas-fired boiler Gas-fired boiler 40 – 42 38 – 40 CCGT Combined cycle with or without supplementary firing (HRSG) for electricity generation only

54 – 58 50 – 54 -

Combined cycle without supplementary firing (HRSG) in CHP mode

<38 <35 75 – 85

Combined cycle with supplementary firing in CHP mode <40 <35 75 – 85

HRSG: heat recovery steam generator CHP: Cogeneration

Table 8: Efficiency of gas-fired combustion plants associated to the use of BAT

6 ENVIRONMENTAL QUALITY

6.1.1 In areas where air quality standards or objectives are being breached or are in serious risk of breach and it is clear from the detailed review and assessment work under a local air quality management action plan that the process itself is a significant contributor to the problem, it may be necessary to impose tighter emission limits. If the emission limit that is in danger of being exceeded is not an EC Directive requirement, then industry is not expected to go beyond BAT to meet it. Decisions should be taken in the context of a local air quality management action plan. The following advice is relevant to local air quality management plans:

“The approach from local authorities to tackling air quality should be an integrated one, involving all strands of local authority activity which impact on air quality and underpinned by a series of principles in which local authorities should aim to secure improvements in the most cost-effective manner, with regard to local environmental needs while avoiding unnecessary regulation. Their approach should seek an appropriate balance between controls on emissions from domestic, industrial and


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transport sources and draw on a combination and interaction of public, private and voluntary effort.”

7 MANAGEMENT

7.1.1 Important elements for effective control of emissions include: • proper management, supervision and training for process operations; • proper use of equipment; • effective preventative maintenance on all plant and equipment concerned with the

control of emissions to the air; and • it is good practice to ensure that spares and consumables are available at short

notice in order to rectify breakdowns rapidly.

Spares and consumables- in particular, those subject to continual wear – should be held on site, or should be available at short notice from guaranteed local suppliers, so that plant breakdowns can be rectified rapidly.

7.1.2 Effective management is central to environmental performance; It is an important component of BAT and of achieving compliance with permit conditions. It requires a commitment to establishing objectives, setting targets, measuring progress and revising the objectives according to results. This includes managing risks under normal operating conditions and in accidents and emergencies. It is therefore desirable that processes put in place some form of structured environmental management approach, whether by adopting published standards (ISO 14001 or the EU Eco Management and Audit Scheme [EMAS]) or by setting up an environmental management system (EMS) tailored to the nature and size of the particular process. Process operators may also find that EMS will help identify business savings. A Horizontal Guide on Management has been prepared and is document number xxxxxxxx.

Regulators should use their discretion, in consultation with individual process operators, in agreeing the appropriate level of environmental management. Simple systems which ensure that considerations are taken account of in the day-to-day running of a process may well suffice, especially for small and medium-sized enterprises.

7.1.3 Staff at all levels need the necessary training and instruction in their duties relating to control of the process and emissions to air. In order to minimise risk of emissions, particular emphasis should be given to control procedures during start-up, shut down and abnormal conditions. Training may often sensibly be addressed in the EMS referred to in paragraph 7.1.2.

Training of all staff with responsibility for operating the process should include: • awareness of their responsibilities under the authorisation / permit; in

particular how to deal with conditions likely to give rise to emissions, such as the event of spillage for example.

• minimising emissions on start up and shut down; • action to minimise emissions during abnormal conditions.

The operator should maintain a statement of training requirements for each operational post and keep a record of the training received by each person whose actions may have an impact on the environment. These documents should be made available to the regulator on request.


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7.1.4 Effective preventative maintenance should be employed on all aspects of the process including all plant, buildings and the equipment concerned with the control of emissions to air. In particular:

A written maintenance programme should be provided to the regulator with respect to pollution control equipment; and

A record of such maintenance should be made available for inspection.

8 PARTICULAR ISSUES THAY AFFECT

CROATIAN LARGE COMBUSTION PLANTS

When using heavy fuel oil (HFO), emissions of NOX and SOX which lead to air pollution, arise from the sulphur and, to a certain extent, from the nitrogen contained in the fuel. Particulates originate mainly from the ash content and marginally from heavier fractions of the fuel. The presence of particulates can also lead to economic costs to the operators, from losses due to unburned fuel and from deposits in combustion facilities, if the equipment is not well maintained.

Control of emissions to air from liquid fuel-fired boilers 8.1.1 Abatement of particulate emissions Particulate emissions from the combustion of heavy oils may contain two major fractions: 1. Material arising from the organic content of the fuel and its failure to complete the burnout process: • unburned hydrocarbons (smoke) • particulates formed via gas phase combustion or pyrolysis (soot) • cenospheres produced from cracked fuel or carbon along with ash (coke). 2. Ash from the inorganic content of the fuel: Smoke may arise from unburned fractions of hydrocarbon fuel exhausted in the form of a fine spray. Such hydrocarbon fractions are the remainders of reactions frozen by thermal quenching. Emissions of unburned hydrocarbons are highest at high equivalence ratios (fuel rich conditions). Their main environmental effect is their reactions in the atmosphere with NOX and sunlight to form photochemical smog. Soot is formed in gas-phase reactions of vaporised organic matter in a complex process involving fuel pyrolysis, polymerisation reactions, nucleation, particle growth and burn-out. Fuel droplets burning in envelope flames are subjected to very high temperatures, leading to fuel evaporation and thermal cracking of the large molecular structures, thus resulting in species of higher C/H ratio than the fuel source. Soot is most likely to be formed in fuel rich conditions, and is normally fully burned as it mixes with air at a very high temperature in highly oxidising zones, e.g. as secondary air is injected into the combustion chamber of a gas turbine. Coke particulates are formed in liquid-phase processes, and contain all the non-soot carbon and also part of the ash material. Such particles are nearly spherical, hollow and porous, and they range in size from 1 to 100 µm.


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Ash fouling and corrosion are major problems when burning heavy oils. Vanadium and sodium are the most harmful elements, forming vanadium pentoxide (V2O5) and sodium sulphate (Na2SO4) respectively. Ash deposits jeopardise heat transfer to metallic surfaces and cause corrosion of the combustion hardware, thus decreasing the equipment lifetime. Values given in the literature show that a mere 0.32 cm thick deposit can cause a 10 % decrease in turbine power. Solid particulates cause corrosion, erosion and abrasion, all of which reduce the lifetime of the hardware. Carbon particulates may also increase the radiative power of the flame, causing damage to the combustion chamber materials. In addition, there is an economic loss from losing unburned material to the air, which therefore means a decrease in fuel efficiency. Because of the effects mentioned above optimum combustion conditions are important for the minimisation of particle and ash production. Viscous fuel must be preheated before atomising. Additives combine with fuel constituents and combustion products to form solid, innocuous products that pass harmlessly through the combustion equipment and may be used to support the optimum combustion conditions. Additives could largely reduce the amount of unburned carbon to a value as low as 5 % in weight in the collected ashes. Regarding the content of unburned carbon in ash, the target is to achieve the best burnout possible in order to achieve an optimum efficiency or fuel utilisation. However, according to technical and fuel characteristics, a higher content of unburned carbon in ash may happen in HFO firing. Ashes with high content carbon are black while those with low carbon content are yellow or grey. In older oil-fired boilers, burners with mechanical atomisation were installed. The improved design of burners with steam atomisation gives a more efficient combustion of HFO, and results in lower particulate emissions. PM emission concentrations in the raw gas (before dedusting) of lower than 100 mg/Nm3 may be achieved, though this depends greatly on the ash content of the HFO. Particulate emissions are normally reduced by ESPs. Particles are generally collected in an ESP in a dry form, which can then be landfilled in controlled landfills. Ash resulting from fuel oil combustion could have a large amount of carbon content and, in this case, it can be incinerated. However, under good combustion conditions of liquid fuel, low carbon content ash (lower than 20 %) is obtained and it should be landfilled in controlled landfills. Fly ash from oil firing installations is regarded as hazardous waste. 8.1.2 Abatement of SO2 emissions Sulphur is usually found in hydrocarbon fuels, normally up to a maximum of 3 % by weight, and mostly in organic form, although it also exists as inorganic compounds. Heavy fuel oils usually contain higher amounts of S than other petroleum products, as it tends to concentrate in the residue along with asphaltenes during the refining processes. At the high temperatures and oxygen concentrations typical of combustion, sulphur combines with carbon, hydrogen and oxygen to form SO2, SO3, SO, CS, CH, COS, H2S, S and S2. Under such circumstances, almost all of the sulphur is in the ‘+4’ oxidation state, hence SO2 is the predominant sulphur compound formed in combustion. Even with a 20 % air deficiency, 90 % of the sulphur is in the form of SO2 and as little as 0.1 % is as SO3; with SO accounting for the remainder of the sulphur. At a lower oxygen concentration (40 % deficiency), H2S, S2 and HS are also present in significant proportions, while SO3 is negligible. During combustion, these species are in super-equilibrium concentrations. As the gases cool, their rates of consumption decrease


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and equilibrium may be ‘frozen’ before the products reach room temperature. In oxygen rich and in stoichiometric flames which are very close to normal operations in boilers, SO2 and a very little amount of SO3 are present. SO3 has to be as low as possible to minimise H2SO4 formation. Sulphuric acid is responsible for corrosion in the coldest sections of the boiler. Switching to low-sulphur oil might be a technique which can make a significant contribution to SO2 emissions reduction. A decrease of 0.5 % in the oil sulphur content leads to a decrease in the emission value by about 800 mg/Nm3 at 3% of oxygen in the waste gas. Co-combustion, i.e. simultaneously burning of liquid and gaseous or liquid fuel and biomass might also be a technique which could make significant contributions to SO2 emission reduction with an important effect on the local air pollution. Co-combustion could take place in the same burner or in different burners located in the same combustion chamber. To reduce SO2 emissions from liquid fuel-fired boilers, especially those burning HFO, some plants apply wet scrubbers. Wet scrubbing with gypsum as the end-product is the best performing process for desulphuration. Nevertheless, due to economic and operational constraints, it might not be applicable to small and medium sized boilers. For that size boilers, waste gas desulphuration could be carried out with lime or limestone dry processes, lime semi-dry processes, activated carbon processes, or soda and sodium carbonate processes. Dry desulphuration could be improved by managing an ‘open pass’ on the inside of the boiler that increases the contact time at a constant of temperature between sorbant and waste gases. The choice between the above processes depends on the required yield of desulphuration and of local considerations, i.e. mainly utilisation or landfilling of desulphuration by-products and residues. 8.1.3 Abatement of NOX emissions With conventional fuels, the NOX formation rate very much depends on the gas temperature and the amount of nitrogen in the fuel. Both characterise the most important routes for the formation of NOX. Thermal NOX can be controlled through a reduction of the flame peak temperature (e.g. limited combustion chamber load). The NOX concentration in the exhaust of an oil-fired boiler indicates that the NOX concentration decreases with excess air. The boiler size also plays an important role in the concentration of NOX in the flue-gases. Factors such as the method of firing have little influence. For oil-fired boilers, the usual excess air is in the range of 2 – 4 % O2 (in flue-gas). A low excess air combustion will be characterised by 1 – 2 % O2. This technique is rarely used alone, but is very often used in combination with ‘low NOX burners’ or ‘overfire air’. Flue-gas recirculation is more often used in oil- or gas-fired boilers than in coal-fired ones. This technique is often used in combination with low NOX burners and/or OFA, together achieving a 60 – 75 % reduction from the original NOX emission baseline level. Amongst all the air-staging techniques, the most commonly used in oil-fired boilers are ‘burners out of service’ (BOOS) and ‘Overfire Air’ (OFA). With modern OFA designs (optimised nozzle design, separated and swirled air flux), the NOx reduction can be as high as 60 % in tangential firing units.


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Flue-gas recirculation type burners are used in oil-fired boilers, matched with the various types of low NOX burners (LNB) and achieves a corresponding NOX emission reduction of 20 %. The key point in designing efficient oil LNB is to ensure a good oil atomisation coupled with the burner aerodynamics, so as not to increase the carbon-in-ash level while decreasing NOX. Modern LNB designs with a proper oil atomisation system can reach a 50 % NOX reduction. For oil-fired plants in general, the NOX emission reduction limits with low NOX burners are 370 - 400 mg/Nm3 (at 3 % O2). In oil-fired boilers, reburning can be implemented with gas or oil as the reburning fuel. Gas is more commonly used than oil. Reburning is interesting for new power plants but is less adapted to existing units. Many existing oil-fired boilers have been equipped with gas/oil reburning during recent years (e.g. Italy has units from 35 to 660 MWe). It is important to note that these units have all been equipped with at least OFA and flue-gas recirculation at the same time, and some of them with low NOX burners. The share of the reburning fuel is 10 to 20 % of the total thermal input. The corresponding NOX reduction is 50 - 80 % from the original NOX baseline level for oil reburning and 65 – 80 % for gas reburning. Secondary measures such as SNCR and SCR systems have been applied to a number of oil-fired combustion plants. In Europe, SCR systems are applied, in particular, in Austria, Germany, Italy and the Netherlands, whereas outside Europe they are mostly applied in Japan. The SCR technology has proven to be successful for liquid fuel-fired power plants. SNCR processes can be applied to any size oil fired boilers. SNCR processes include liquid NH3, gaseous NH3, and liquid urea and solid urea as reduction agents. One of these reduction agents is injected into the boiler chamber in areas where the temperature is around 900 °C. SNCR need a good knowledge of temperature distribution in the combustion chamber at all rates, and a good control of the amount of injected products. Control can be achieved by NH3 or NOX monitoring, NOX reduction could reach 60 % with a NH3 slip lower than 10 ppm.


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9 DEFINITIONS

GENERAL TERMS AND SUBSTANCES

TERM

MEANING

Acid

proton donor. A substance that, more or less readily, gives off hydrogen ions in a water solution.

activated sludge process

a sewage treatment process by which bacteria that feed on organic wastes are continuously circulated and put in contact with organic waste in the presence of oxygen to increase the rate of decomposition.

Aeration

the act of mixing a liquid with air (oxygen).

Alkali

proton acceptor. A substance that, more or less readily, takes up hydrogen ions in a water solution.

Anaerobic

a biological process which occurs in the absence of oxygen.


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TERM

MEANING

biodegradable

that can be broken down physically and/or chemically by micro-organisms. For example, many chemicals, food scraps, cotton, wool and paper are biodegradable.

Brayton cycle

see Annex

Carnot cycle

see Annex

Cheng cycle


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TERM

MEANING

Claus plant

sulphur recovery unit. For more information refer to the Refinery BREF.

cross-media effects

the calculation of the environmental impacts of water/air/soil emissions, energy use, consumption of raw materials, noise and water extraction (i.e. everything required by the IPPC Directive).

diffuse emission

emissions arising from direct contact of volatile or light dusty substances with the environment (atmosphere, under normal operating circumstances). These can result from: • inherent design of the equipment (e.g. filters, dryers, etc…) • operating conditions (e.g. during transfer of material between

containers) • type of operation (e.g. maintenance activities) • or from a gradual release to other media (e.g. to cooling water or

waste water). Fugitive emissions are a subset of diffuse emissions.


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TERM

MEANING

diffuse sources

sources of similar diffuse or direct emissions which are multiple and distributed inside a defined area.

Dolomite

type of limestone, the carbonate fraction of which is dominated by the mineral dolomite, calcium magnesium carbonate (CaMg(CO3)).

Effluent

physical fluid (air or water together with contaminants) forming an emission

emerging techniques

name of a standard chapter in BREFs


25

TERM

MEANING

Emission

the direct or indirect release of substances, vibrations, heat or noise from individual or diffuse sources in the installation into the air, water or land


26

TERM

MEANING

emission and consumption levels associated with the use of BAT

see generic introduction to BAT sections


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TERM

MEANING

emission limit values

the mass, expressed in terms of certain specific parameters, concentration and/or level of an emission, which may not be exceeded during one or more periods of time.

‘end-of-pipe’ technique

a technique that reduces final emissions or consumptions by some additional process but does not change the fundamental operation of the core process. Synonyms: ‘secondary technique’, ‘abatement technique’. Antonyms: ‘process-integrated technique’, ‘primary technique’ (a technique that in some way changes the way in which the core process operates thereby reducing raw emissions or consumptions).


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TERM

MEANING

existing installation

an installation in operation or, in accordance with legislation existing before the date on which the Directive is brought into effect, an installation authorised or in the view of the competent authority the subject of a full request for authorisation, provided that that installation is put into operation no later than one year after the date on which IPPC Directive is brought into effect.

fugitive emission

emission caused by non-tight equipment/leak: emission into the environment resulting from a gradual loss of tightness from a piece of equipment designed to contain an enclosed fluid (gaseous or liquid), basically caused by a difference of pressure and a resulting leak. Examples of fugitive emissions: leak from a flange, a pump, sealed or tightened equipment, etc…

immission

occurrence and level of polluting substance, odour or noise in the environment.


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TERM

MEANING

installation

a stationary technical unit where one or more activities listed in Annex I of the IPPC Directive are carried out, and any other directly associated activities which have a technical connection with the activities carried out on that site and which could have an effect on emissions and pollution.

Lurgi CFB

particular SOx and NOX reduction process.

monitoring

process intended to assess or to determine the actual value and the variations of an emission or another parameter, based on procedures of systematic, periodic or spot surveillance, inspection, sampling and measurement or other assessment methods intended to provide information about emitted quantities and/or trends for emitted pollutants.

multi-media effects

see cross-media effects.


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TERM

MEANING

naphthenes

hydrocarbons containing one or more saturated rings of 5 or 6 carbon atoms in their molecules, to which paraffinic-type branches are attached (adjective: napthenic).

operator

any natural or legal person who operates or controls the installation or, where this is provided for in national legislation, to whom decisive economic power over the technical functioning of the installation has been delegated.

Otto cycle

four stroke engine.

pollutant

individual substance or group of substances which can harm or affect the environment.


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TERM

MEANING

primary measure/technique

a technique that in some way changes the way in which the core process operates thereby reducing raw emissions or consumptions (see ‘end-of-pipe technique’)

Rankine cycle

see Annex Pogreška! Izvor reference nije pronađen..


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TERM

MEANING

secondary measure/technique

see ‘end-of-pipe technique’

specific emission

emission related to a reference basis, such as production capacity, or actual production (e.g. mass per tonne or per unit produced).


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TERM

MEANING

spinning reserve

excess power capacity.

Thermie programme

EC energy programme.


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LIST OF ABBREVIATIONS

Abbreviation Meaning AF arch-fired AFBC atmospheric fluidised bed combustion AFBG atmospheric circulating fluidised bed gasifier AGR advanced gas reburn AOX adsorbable organic halogen compounds. The total

concentration in milligrams per litre, expressed as chlorine, of all halogen compounds (except fluorine) present in a sample of water that are capable of being adsorbed on activated carbon.

API American Petroleum Institute ASTM classification developed in the US for coal BAT best available techniques BBF biased burner firing BFB bubbling fluidised bed BFBC bubbling fluidised bed combustion BFG blast furnace gas BOD biochemical oxygen demand: the quantity of dissolved oxygen

required by micro-organisms in order to decompose organic matter. The unit of measurement is mg O2/l. In Europe, BOD is usually measured after 3 (BOD3), 5 (BOD5) or 7 (BOD7) days.

BOOS burner out of service BREF BAT Reference document BTEX benzene, toluene, ethylbenzene, xylene CC combined cycle CCGT combined cycle gas turbine CCP coal combustion products CEC California Energy Commission CEM continuous emission monitoring CEMS continuous emission monitoring system CETF combustion and environmental test facility CFB circulating fluidised bed CFBC circulating fluidised bed combustion CHAT cascade humidified air turbine CHP combined heat and power (co-generation) CIS countries from the ex-soviet union COD chemical oxygen demand: the amount of potassium

dichromate, expressed as oxygen, required to chemically oxidise at approx. 150 °C substances contained in waste water.

daf dry and ash free basis DBB dry bottom boiler DENOX denitrification DESONOX a particular SOX and NOX reduction technique DESOX a desulphurisation technique DF dual fuel DH district heating DLE dry low emission premix combustion chamber for gas turbines DLN dry low-NOX, e.g. DLN burner DLN dry low-NOX premix combustion chamber for gas turbines DM/dm dry matter DS/ds dry solids content. The mass of a material remaining after

drying by the standard method of test. DS burner drall swirl burner DSI direct sorbent injection DWI direct water injection EDTA ethylenediamine tetraacetic acid EIPPCB European IPPC Bureau EGR exhaust gas recirculation


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ELV emission limit value EMAS European Community Eco-Management and Audit Scheme EMS environment management system EO energy output EOR enhanced oil recovery EOP end-of-pipe EOX extractable organic halogens EPER European pollutant emission register ESP electrostatic precipitator EUF energy utilisation factor EUR EURO – common unit of currency in many EU-15 countries EU-15 15 Member States of the Euopean Union FBC fluidised bed combustion FBCB fluidised bed combustion boiler FF fabric filter FEGT furnace exit gas temperature FGC flue-gas clean-up FGD flue-gas desulphurisation FRB coal classification developed in the UK FGR flue-gas reburn GDP gross domestic product GF grate firing GRP glass reinforced plastic GT gas turbine GTCC gas turbine combined cycle GWP global warming potential HAT humidified air turbine HFO heavy fuel oil Hardgrove Grindability Index (HGI)

number to define the hardness of coal.

HHV higher heating value Hu lower heating value HRSG heat recovery steam generator HP high pressure IEA International Energy Agency IEF Information exchange forum (informal consultation body in the

framework of the IPPC Directive). IEM Internal electricity market (Directive (96/92/EC) IGCC integrated gasification combined cycle IPC UK integrated pollution control law IPPC integrated pollution prevention and control IPP independent power producers I-TEQ unit of the dioxin concentration based on toxicity aspects JBR jet bubbling reactor JRC Joint Research Centre LCP large combustion plant LFO light fuel oil (lighter than HFO) LHV lower heating value LNB Low NOX burner LOI loss-on-ignition LP low pressure LPGs liquid petroleum gas LVOC large volume organic chemicals (BREF) LIMB limestone injection multistage burner MCR micro carbon residue MDF middle-density fibre board MEA monoethanolamine MMBtu Million of Btu (British thermal unit) MP medium pressure


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n.a. not applicable OR not available (depending on the context). n.d. no data. NMHC non-methane hydrocarbons NMVOC non-methane volatile organic compounds NOXSO combined technique for the reduction of NOX and SOX. More

information in Section Pogreška! Izvor reference nije pronađen.

OECD Organisation for Economic Co-operation and Development OFA overfire air PAH polyaromatic hydrocarbons PC pulverised combustion PAC powdered activated carbon PFBC pressurised fluidised bed combustion PCB polychlorinated benzenes PCDD polychlorinated-dibenzo-dioxins PCDF polychlorinated-dibenzo-furans PEMS parametric emission modelling system PFF polishing fabric filter PI process-integrated Pm primary measures PM (PM10 and PM2.5) particulate matter POM particulate organic matter POPs persistent organic compounds PPFBC pressurised fluidised bed combustion PRV pressure reducing value PSA pressure swing adsorption QF quality factors RDF refuse derived fuel REF recovered fuel R&D research and development SC spray cooling SCONOX particular NOX reduction process for gas turbines SCR selective catalytic reduction SD spray dryer SDA spray dry absorber SDS spray dry scrubber SS suspended solids SF secondary fuel SG steam generator SME small to medium sized enterprise SNCR selective non catalytic reduction SNRB Combined SOx-NOX reduction technique ROX-Box process SRU sulphur recovery unit STIG steam injected gas SWTP seawater treatment plant TDS total dissolved solids TEF toxic equivalency factor TEQ toxic equivalent quantity TOPHAT humidified air turbine where the air is injected in the

compressor TS total solids TSA thermal swing adsorption TSS total suspended solids TWG technical working group UHC unburned hydrocarbons UHV upper heating value ULNTF ultra low NOX tangential firing UN ECE United Nations Economic Commission for Europe USEPA United States Environment Protection Agency


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VGB Vereinigung der Großkrftwerksbetreiber VI viscosity index VOCs volatile organic compounds waf water free WSA SNOX a particular SOx and NOX reduction process WBB wet bottom boiler WHB waste heat boiler WHRU waste heat recovery unit WI waste incineration (typically refers to WI BREF) WS whirl-swirl WT waste treatment (typically refers to WT BREF) WWTP waste water treatment plant


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10 PROPOSAL FOR ANNEX 5 TO THE REVISED DIRECTIVE ON INDUSTRIAL EMISSIONS (INTEGRATED POLLUTION PREVENTION AND CONTROL)

TECHNICAL PROVISIONS RELATING TO LARGE COMBUSTION PLANTS

V1. Emission limit values for existing plants All emission limit values are expressed in mg/Nm3. The standardized O2 content is 6% for solid fuels, 3% for liquid and gaseous fuels and 15% for gas turbines and gas engines. In case of combined cycle gas turbines (CCGT) with supplementary firing, the standardized O2 content may be defined by the competent authority, taking into account the specific characteristics of the installation concerned. Table 9: Emission limit value (mg/Nm3) for SO2 for boilers using solid and liquid fuels.

Rated thermal input (MWth)

Coal and lignite Biomass Peat Liquid fuels

50-100 MWth 400 200 300 350

100-300 MWth 250 200 300 250

> 300 MWth 200 200 200 200

By way of derogation from the above emission limit value for SO2 plants using solid fuel which were granted a permit before 1 July 1987, shall be subject to an emission limit value for SO2 of 800 mg/Nm3 provided that they do not operate more than 1500 hours a year (rolling average over a period of five years) from 1 January 2016 on. Table 10: Emission limit value (mg/Nm3) for SO2 for boilers using gaseous fuels

In general 35

Liquefied gas 5

Low calorific gases from coke oven 400

Low calorific gases from blast furnace 200

Table 11: Emission limit value (mg/Nm3) for NOx for boilers using solid and liquid fuels


Coal and lignite Biomass and peat

Liquid fuels

50-100 300

450 in case of pulverised lignite combustion

300 450

100-300 200 250 200

> 300 200 200 150


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By way of derogation from the above emission limit value for NOx plants using solid fuels which were granted a permit before 1 July 1987, shall be subject to an emission limit value for NOx of 450 mg/Nm3 provided that they do not operate more than 1500 hours a year (rolling average over a period of five years) from 1 January 2016 on. Until 1 January 2018 in the case of plants in the 12 month period ending on 1 January 2001 operated on, and continue to operate on, solid fuels whose volatile content is less than 10% an emission limit value for NOx of 1200 mg/Nm3 shall apply. Table 12: Emission limit value (mg/Nm3) for NOx and CO for gas fired combustion plants

NOx CO

Gas fired boilers 100 100

Gas turbines (including combined cycle gas turbines (CCGT))(1)

Natural gas 50

Other fuel 90

100

100

Gas engines 20 30 (1) Natural gas is naturally occurring methane with not more than 20% (by volume) of inerts and other consti. (2) 75 mg/Nm3 in the following cases, where the efficiency of the gas turbine is determined as ISO base load conditions: - gas turbines, used in combined heat and power systems having an overall efficiency greater than 75% - gas turbines used in combined cycle plants having an annual average overall electrical efficiency greater then 55% - gas turbines for mechanical drives.


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V.2 Emission limit values for new plants

All emission limit values are expressed in mg/Nm3. The standardized O2 content is 6% for solid fuels, 3% for liquid and gaseous fuels and 15% for gas turbines and gas engines. In case of combined cycle gas turbines with supplementary firing, the standardized O2 content may be defined by the competent authority, taking into account the specific characteristics of the installation concerned. Table 13: Emission limit value (mg/Nm3) for SO2 for boilers using solid and liquid fuels


Coal and lignite Biomass Peat Liquid fuels

50-100 MWth SO2

400

150 in case of fluidized bed combustion

200

300

350

Dust 30 30 30 30

100-300 MWth SO2

200

200

300

250 in case of fluidized bed combustion

200

Dust 25 20 20 25

> 300 MWth SO2

150

100 in case of circulating or pressurized fluidized bed combustion

150 150

150

Dust 20 20 20 20

Table 14: Emission limit value (mg/Nm3) for SO2 for boilers using gaseous fuels

In general 35

Liquefied gas 5

Low calorific gases from coke oven 400

Low calorific gases from blast furnace 200


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Table 15: Emission limit value (mg/Nm3) for NOx for boilers using solid and liquid fuels


Coal and lignite* Biomass and peat

Liquid fuels

50-100 MWth 300

400 (pf lignite) 250 300

100-300 MWth 200 200 150

> 300 MWth 150

200 (pf lignite) 150 1000

* in case of pulverised hard coal combustion: emission limit value of 90 mg/Nm3. Table 16: Emission limit value (mg/Nm3) for NOx and CO for gas fired combustion plants

(1) For gas turbines using light and middle distillates as liquid fuels, these emission limit values for NOx and for Co also apply. (2) For single cycle gas turbines having an efficiency greater than 35% - determined at ISO base load conditions - the emission limit value for NOx shall be 20*η/35 where η is the gas turbine efficiency expressed as a percentage (and at ISO base load conditions). For gas turbines (including CCGT), the above NOx and CO emission limit values apply only above 70% load. Gas turbines for emergency use that operate less than 500 hours per year are excluded from the above limit values. The operator of such plants is required to record the used time.

NOx CO

Gas fired boilers 100 100

Gas turbines (including combined cycle gas turbines (CCGT))(1)

50(2) 100

30 in case supplementary firing (heat recovery steam generator) is used

Gas engines 75 100


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Table 17: Emission limit value (mg/Nm3) for dust for boilers

Solid fuels 20

Liquid fuels 10

Gaseous fuels (in general) 5

Blast furnace gas 10

Gases produced by the steel industry which can be used elsewhere 30

V.3 Monitoring 1. Competent authority shall require continuous measurements of concentrations of SO2, NOx, and dust from waste gases from each combustion plant with a rated thermal input of 100 MW or more. For gas fired combustion plants, continuous measurement of CO in waste gases from combustion plants with a rated thermal input of 100 MW or more shall also be required. By way of derogation from the first subparagraph, continuous measurements may not be required in the following cases: - for combustion plants with a life span of less than 10000 operational hours; - for SO2 and dust from natural gas burning boilers or from gas turbines firing natural gas; - for SO2 from gas turbines or boilers firing oil with known sulphur content in cases where there is no desulphurisation equipment; - for SO2 from biomass firing boilers if the operator can prove that the SO2 emissions can under no circumstances be higher than the prescribed emission limit values. 2. Where continuous measurements are not required, discontinuous measurements of SO2, NOx, dust and, for gas fired plants, also for CO shall be required at least every six months. For coal and lignite fired combustion plants, the emissions of total mercury shall be measured at least every year. As an alternative, appropriate determination procedures, which must be verified and approved by the competent authority, may be used to evaluate the quantity of the above mentioned pollutants present in the emissions. Such procedures shall use relevant CEN standards as soon as they are available. If CEN standards are not available ISO standards, national or international standards which will ensure the provision of data of an equivalent scientific quality shall apply. 3. The competent authority shall be informed of substantial changes in the type of fuel used or in the mode of operation of the plant. They shall decide whether the monitoring requirements laid down in paragraph 1 are still adequate or require adaptation. 4. The continuous measurements carried out in compliance with paragraph 1 shall include the relevant process operation parameters of oxygen content, temperature, pressure and water vapour content. The continuous measurement of the water vapour content of the exhaust gases shall not be necessary, provided that the sampled exhaust gas is dried before the emissions are analysed.


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Representative measurements, i.e. sampling and analysis, of relevant pollutants and process parameters as well as the quality assurance of automated measuring systems and the reference measurement methods to calibrate them shall be carried out in accordance with CEN standards. If CEN standards are not available, ISO standards, national or international standards which will ensure the provision of data of an equivalent scientific quality shall apply. Continuous measuring systems shall be subject to control by means of parallel measurements with the reference methods at least every year. The operator shall inform the competent authority about the results of the checking of the automated measuring equipment. 5. The values of 95% confidence intervals of a single measured result shall not exceed the following percentages of the emission limit values:

Carbon monoxide 10%

Sulphur dioxide 20%

Nitrogen oxides 20%

Dust 30%

The validated hourly and daily average values shall be determined from the measured valid hourly average values after having subtracted the value of the confidence interval specified above. Any day in which more than three hourly average values are invalid due to malfunction or maintenance of the continuous measurement system shall be invalidated. If more than ten days over a year are invalidated for such situations the competent authority shall require the operator to take adequate measures to improve the reliability of the continuous monitoring system.


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V.4 Assessment of compliance with the emission limit values 1. In the event of continuous measurements, the emission limit values set out in part A of Annexes V.1 and V.2 shall be regarded as having been complied with if the evaluation of the results indicates, for operating hours within a calendar year, that: (a) no validated monthly average value exceeds the relevant figures set out in Annexes V.1 to V.2, and daily not more than 110% of monthly (b) 95 % of all the validated hourly average values over the year do not exceed 200 % of the relevant figures set out in Annexes V.1 to V.2. The "validated average values" are determined as set out in point 4 of Annex V.3. The periods referred to in Article 31(3)-(5) as well as start-up and shut-down periods shall be disregarded. 2. In cases where only discontinuous measurements or other appropriate procedures for determination are required, the emission limit values set out in Annexes V.1 to V.2 shall be regarded as having been complied with if the results of each of the series of measurements or of the other procedures defined and determined according to the rules laid down by the competent authority do not exceed the emission limit values. The periods referred to in Article 31(3)-(5) as well as start-up and shut-down periods shall be disregarded


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11 REFERENCES 1. BREF for Large Combustion Plant

2. Re-cast of the IPPC, LCP etc Directives


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12 AKNOWLEDGEMENTS

European IPPC Bureau, Seville http://eippcb.jrc.es

Some energy and environmental measures can increase industry profits. Envirowise (Reports on some energy and environmental measures that can can increase industry profits) www.envirowise.gov.uk

Environment Agency for England and Wales, www.environment-agency.gov.uk/

www.aeat.co.uk/netcen/airqual/info/labrief.htm the Department of the Environment, Transport and the Regions; Local Air Pollution Policy team have more information about LAPC and LAPPC.

Scottish Environmental protection Agency www.sepa.org.uk

Web addresses that may be useful are included.

Documents

BAT Large Combustion Plants