LARGE COMBUSTION PLANTS (LCPs) - Environment Agency

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LCP BRef – BATc - UK Interpretational Guidance Nov 2019 v1.06 of 151

UK Interpretation Guidance and Permitting Advice on the Best Available Techniques (BAT)

Conclusions for:

LARGE COMBUSTION PLANTS (LCPs)

This guidance should be read in conjunction with the UK BATc General Interpretational Guidance and Permitting Advice

Bold Text The exact wording of each BAT Conclusion

Normal text Other parts of the BAT conclusions document

Italic text The guidance on each section

Green Highlighted Text Key Issues that are yet to be resolved or require specific discussion between Regulators

Purple text Permitting instructions that could be moved to a separate Annex

Yellow Highlighted Text Outstanding drafting requirement/cross references to be added

Comments To be removed from final document

Italic Blue Highlighted Text Position already agreed and published (Working document V1.1 09/05/2018)

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CONTENTS

INTRODUCTION ................................................................................................................................... 5

DEFINITIONS ...................................................................................................................................... 10

POLLUTANTS/PARAMETERS .............................................................................................................. 13

ACRONYMS ........................................................................................................................................ 15

GENERAL CONSIDERATIONS .............................................................................................................. 16

1 GENERAL BAT CONCLUSIONS .................................................................................... 21

1.1 ENVIRONMENTAL MANAGEMENT SYSTEMS ......................................................................... 21

1.2 MONITORING ......................................................................................................................... 24

1.3 GENERAL ENVIRONMENTAL AND COMBUSTION PERFORMANCE ........................................ 35

1.4 ENERGY EFFICIENCY ............................................................................................................... 39

1.5 WATER USAGE AND EMISSIONS TO WATER .......................................................................... 42

1.6 WASTE MANAGEMENT .......................................................................................................... 46

1.7 NOISE EMISSIONS .................................................................................................................. 47

2 BAT CONCLUSIONS FOR THE COMBUSTION OF SOLID FUELS ............................................... 49

2.1 BAT CONCLUSIONS FOR THE COMBUSTION OF COAL AND/OR LIGNITE ............................... 49

2.1.1 General environmental performance .................................................................................... 49

2.1.2 ENERGY EFFICIENCY ............................................................................................................... 49

2.1.3 NOX, N2O AND CO EMISSIONS TO AIR .................................................................................. 50

2.1.4 SOX, HCL AND HF EMISSIONS TO AIR ..................................................................................... 53

2.1.5 DUST AND PARTICULATE-BOUND METAL EMISSIONS TO AIR ............................................... 56

2.1.6 MERCURY EMISSIONS TO AIR ................................................................................................ 58

2.2 BAT CONCLUSIONS FOR THE COMBUSTION OF SOLID BIOMASS AND/OR PEAT .................. 60


2.2.2 NOX, N2O AND CO EMISSIONS TO AIR .................................................................................... 61

2.2.3 SOX, HCL AND HF EMISSIONS TO AIR .................................................................................... 63


2.2.5 MERCURY EMISSIONS TO AIR ................................................................................................ 68

3 BAT CONCLUSIONS FOR THE COMBUSTION OF LIQUID FUELS.............................................. 70

3.1 HFO- AND/OR GAS-OIL-FIRED BOILERS .................................................................................. 70


3.1.2 NOX AND CO EMISSIONS TO AIR ........................................................................................... 71

3.1.3 SOX, HCL AND HF EMISSIONS TO AIR ..................................................................................... 74


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3.2 HFO- AND/OR GAS-OIL-FIRED ENGINES ................................................................................. 78


3.2.2 NOX, CO AND VOLATILE ORGANIC COMPOUND EMISSIONS TO AIR .................................... 80

3.2.3 SOX, HCL AND HF EMISSIONS TO AIR .................................................................................... 82


3.3 GAS-OIL-FIRED GAS TURBINES ............................................................................................... 86


3.3.2 NOX AND CO EMISSIONS TO AIR ........................................................................................... 87

3.3.3 SOX AND DUST EMISSIONS TO AIR ........................................................................................ 88

4 BAT CONCLUSIONS FOR THE COMBUSTION OF GASEOUS FUELS ......................................... 90

4.1 BAT CONCLUSIONS FOR THE COMBUSTION OF NATURAL GAS ............................................. 90


4.1.2 NOX, CO, NMVOC AND CH4 EMISSIONS TO AIR .................................................................... 91

4.2 BAT CONCLUSIONS FOR THE COMBUSTION OF IRON AND STEEL PROCESS GASES ............ 100

4.2.1 ENERGY EFFICIENCY ............................................................................................................. 100

4.2.2 NOX AND CO EMISSIONS TO AIR ......................................................................................... 102

4.2.3 SOX EMISSIONS TO AIR ......................................................................................................... 105

4.2.4 DUST EMISSIONS TO AIR ...................................................................................................... 107

4.3 BAT CONCLUSIONS FOR THE COMBUSTION OF GASEOUS AND/OR LIQUID FUELS ON

OFFSHORE PLATFORMS ....................................................................................................... 109

5 BAT CONCLUSIONS FOR MULTI-FUEL-FIRED PLANTS .......................................................... 112

5.1 BAT CONCLUSIONS FOR THE COMBUSTION OF PROCESS FUELS FROM THE CHEMICAL

INDUSTRY ............................................................................................................................. 112

5.1.1 GENERAL ENVIRONMENTAL PERFORMANCE ...................................................................... 112



5.1.4 SOX, HCL AND HF EMISSIONS TO AIR .................................................................................. 116

5.1.5 DUST AND PARTICULATE-BOUND METAL EMISSIONS TO AIR ............................................. 120

5.1.6 EMISSIONS OF VOLATILE ORGANIC COMPOUNDS AND POLYCHLORINATED DIBENZO-

DIOXINS AND -FURANS TO AIR ............................................................................................ 121

6 BAT CONCLUSIONS FOR THE CO-INCINERATION OF WASTE ............................................... 124

6.1.1 GENERAL ENVIRONMENTAL PERFORMANCE ...................................................................... 125



6.1.4 SOX, HCL AND HF EMISSIONS TO AIR .................................................................................. 129

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6.1.5 DUST AND PARTICULATE-BOUND METAL EMISSIONS TO AIR ............................................. 130

6.1.6 MERCURY EMISSIONS TO AIR .............................................................................................. 133

6.1.7 EMISSIONS OF VOLATILE ORGANIC COMPOUNDS AND POLYCHLORINATED DIBENZO-

DIOXINS AND -FURANS TO AIR ............................................................................................ 134

7 BAT CONCLUSIONS FOR GASIFICATION ............................................................................... 137



7.1.3 SOX EMISSIONS TO AIR ......................................................................................................... 139

7.1.4 DUST, PARTICULATE-BOUND METAL, AMMONIA AND HALOGEN EMISSIONS TO AIR ....... 140

8 DESCRIPTION OF TECHNIQUES ............................................................................................ 142

8.1 GENERAL TECHNIQUES ............................................................................................... 142

8.2 TECHNIQUES TO INCREASE ENERGY EFFICIENCY ................................................................. 142

8.3 TECHNIQUES TO REDUCE EMISSIONS OF NOX AND/OR CO TO AIR .................................... 143

8.4 TECHNIQUES TO REDUCE EMISSIONS OF SOX, HCL AND/OR HF TO AIR ............................. 144

8.5 TECHNIQUES TO REDUCE EMISSIONS TO AIR OF DUST, METALS INCLUDING MERCURY,

AND/OR PCDD/F .................................................................................................................. 146

8.6 TECHNIQUES TO REDUCE EMISSIONS TO WATER ............................................................... 146

ANNEX 1 - REASONING AND CONSIDERATIONS RELATING TO SPECIFIC GUIDANCE POSITIONS .... 149

ANNEX II - PERMITTING GUIDANCE................................................................................................. 150

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UK Interpretational Guidance on the Best Available Techniques (BAT) Conclusions for

LARGE COMBUSTION PLANTS (LCP)

INTRODUCTION

The UK Regulators: The Environment Agency (EA), Scottish Environment Protection Agency (SEPA), Natural Resources Wales (NRW) and the Northern Ireland Environment Agency (NIEA) have, in consultation with industry, set our interpretation of the main issues raised in the Large Combustion Plant (LCP) BAT Reference Document (LCP BRef) Conclusions (BATc). The BATcs were published in the Official Journal on 17th August 2017[1]. This guidance is intended to inform the BATc review process at installations that will implement the BRef, and is intended to aid operators and Regulators in the process. This guidance addresses those issues that require clarification or interpretation. This is the UK Regulators definitive interpretation for all aspects of the LCP BRef. It is applicable to all types of large combustion plants, irrespective of the plant duty or sector, including the electricity supply industry, co-incineration plants, LCPs at chemical and iron and steel installations as well as integrated gasification combined cycle systems.

In each case, the actual text of the BATcs is repeated in this document in bold text. Relevant guidance is then provided (as applicable) at the end of each section or sub section of the BATcs. Guidance on the approach to permitting is also included where this is considered necessary and is included in each relevant section or Annex II. The reasoning/basis of some specific interpretational aspects is provided in Annex 1 to provide a record of the considerations leading to the guidance position. Where it is stated that “No interpretational guidance has been provided at this time”, if guidance is required please contact XXXXXXXXXXXX.

Further information on certain specific aspects of these BATcs that are common to all BATcs for other activities is given in the generic Regulators cross cutting BRef guidance[REF]. This covers aspects such as:

the approach to setting ELVs within the BAT-AEL range;

the approach to handling confidence levels for monitoring data;

when the requirement for BATc reviews are triggered by the publication of BATcs. This is addressed in IED Article 21(3) that sets out when a BATc document covering an activity at an installation that is not the main activity at the installation is published; there is no requirement as a consequence to review the permit(s) or parts of permits covering the activity that is not the main activity. As such, combustion plants at installations other than combustion installations will need to comply with these BATcs only within 4 years of the BATcs for the main activity of the installation.

1 https://eur-lex.europa.eu/legal-content/EN/TXT/?qid=1503383091262&uri=CELEX:32017D1442

https://eur-lex.europa.eu/legal-content/EN/TXT/?qid=1503383091262&uri=CELEX:32017D1442

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SCOPE

These BAT conclusions concern the following activities specified in Annex I to Directive 2010/75/EU:

1.1: Combustion of fuels in installations with a total rated thermal input of 50 MW or more, only when this activity takes place in combustion plants with a total rated thermal input of 50 MW or more.

1.4: Gasification of coal or other fuels in installations with a total rated thermal input of 20 MW or more, only when this activity is directly associated to a combustion plant.

5.2: Disposal or recovery of waste in waste co-incineration plants for non-hazardous waste with a capacity exceeding 3 tonnes per hour or for hazardous waste with a capacity exceeding 10 tonnes per day, only when this activity takes place in combustion plants covered under 1.1 above.

In particular, these BAT conclusions cover upstream and downstream activities directly associated with the aforementioned activities including the emission prevention and control techniques applied.

The fuels considered in these BAT conclusions are any solid, liquid and/or gaseous combustible material including:

solid fuels (e.g. coal, lignite, peat);

biomass (as defined in Article 3(31) of Directive 2010/75/EU);

liquid fuels (e.g. heavy fuel oil and gas oil);

gaseous fuels (e.g. natural gas, hydrogen-containing gas and syngas);

industry-specific fuels (e.g. by-products from the chemical and iron and steel industries);

waste except mixed municipal waste as defined in Article 3(39) and except other waste listed in Article 42(2)(a)(ii) and (iii) of Directive 2010/75/EU.

These BAT conclusions do not address the following:

combustion of fuels in units with a rated thermal input of less than 15 MW;

combustion plants benefitting from the limited life time or district heating derogation as set out in Articles 33 and 35 of Directive 2010/75/EU, until the derogations set in their permits expire, for what concerns the BAT-AELs for the pollutants covered by the derogation, as well as for other pollutants whose emissions would have been reduced by the technical measures obviated by the derogation;

gasification of fuels, when not directly associated to the combustion of the resulting syngas;

gasification of fuels and subsequent combustion of syngas when directly associated to the refining of mineral oil and gas;

the upstream and downstream activities not directly associated to combustion or gasification activities;

combustion in process furnaces or heaters;

combustion in post-combustion plants;

flaring;

combustion in recovery boilers and total reduced sulphur burners within installations for the production of pulp and paper, as this is covered by the BAT conclusions for the production of pulp, paper and board;

combustion of refinery fuels at the refinery site, as this is covered by the BAT conclusions for the refining of mineral oil and gas;

disposal or recovery of waste in: o waste incineration plants (as defined in Article 3(40) of Directive 2010/75/EU),

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o waste co-incineration plants where more than 40% of the resulting heat release comes from hazardous waste,

o waste co-incineration plants combusting only wastes, except if these wastes are composed at least partially of biomass as defined in Article 3(31)(b) of Directive 2010/75/EU,

as this is covered by the BAT conclusions for waste incineration.

Other BAT conclusions and reference documents that could be relevant for the activities covered by these BAT conclusions are the following:

Common Waste Water and Waste Gas Treatment/Management Systems in the Chemical Sector (CWW)

Chemical BREF series (LVOC, etc.)

Economics and Cross-Media Effects (ECM)

Emissions from Storage (EFS)

Energy Efficiency (ENE)

Industrial Cooling Systems (ICS)

Iron and Steel Production (IS)

Monitoring of Emissions to Air and Water from IED installations (ROM)

Production of Pulp, Paper and Board (PP)

Refining of Mineral Oil and Gas (REF)

Waste Incineration (WI)

Waste Treatment (WT)

GUIDANCE

1. This guidance and the LCP BRef in general (including these BATcs) cover combustion plant with capacity ≥ 50 MWth It does not apply to combustion installations subject only to Chapter II of the IED (i.e. those installations of ≥50 MWth capacity but where there are no combustion plant subject to Chapter III / Annex V of the IED).

2. The BATc define a combustion plant as:

Any technical apparatus in which fuels are oxidised in order to use the heat thus generated. For the purposes of these BAT conclusions, a combination formed of: — two or more separate combustion plants where the flue-gases are discharged through

a common stack, or separate combustion plants that have been granted a permit for the first time on or after 1 July 1987, or for which the operators have submitted a complete application for a permit on or after that date, which are installed in such a way that, taking technical and economic factors into account, their flue-gases could, in the judgment of the competent authority, be discharged through a common stack is considered as a single combustion plant. For calculating the total rated thermal input of such a combination, the capacities of all individual combustion plants concerned, which have a rated thermal input of at least 15 MW, shall be added together.

This means that:

Units of less than 15MWth capacity are excluded entirely from the scope of the BATcs. Units less than 15 MWth with separate flues will therefore not be counted for defining the thermal input of the LCP nor regulated as part of the combined plant, unless the flue gases are physically mixed with the flue gases of larger plant to such an extent that they cannot be regulated separately.

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Units between ≥15 MWth and <50 MWth are only subject to these BATcs if they are connected, or could be connected, to a common stack with an aggregate capacity ≥ 50 MWth, i.e., they are part of an LCP. Additional guidance on aggregation issues is available from the EC[2]

Units between ≥15 MWth and <50 MWth that do not meet this stack aggregation qualification are not subject to the LCP BREF, even if they are on an installation that has a site aggregated capacity of all combustion plants that is ≥50 MWth (which thereby qualifies for regulation under IED Chapter II).

3. Limited Lifetime Derogation (LLD). The EC has provided specific guidance[2] on some compliance options for such plant at the end of the LLD which have been addressed in this guidance. Operators of combustion plants that have opted for the 'limited life time derogation' (IED Article 33) do not have to comply with the BATcs applicable to the air pollutants that are subject to the LLD (or seek derogation under the terms of IED Article 15(4)) until having reached the maximum number of operating hours or the end date of the limited life derogation. All other provisions of these BATcs do apply (for instance on energy efficiency and monitoring requirements). LLD plant operators have the choice to:

stop operating before or after having reached the maximum number of operating hours or the end date of LLD, or,

if the operator intends to continue operation after this, they will need to meet the emission limit values set out in IED Annex V, part 2 (for new plant) as a minimum requirement (as they will need a new permit or variation to allow further operation). In such cases, the requirements of these BATcs will also apply from the date of the end of the limited life derogation. If a plant is upgraded to meet the requirements of IED Annex V and these BATc, the plant may be considered as a new plant under the terms of these BATcs if it is a complete replacement plant on the existing foundations of the original plant (see definitions below).

4. Small Isolated Systems (SIS). Issues associated with plant defined as SIS (under IED Article 34) are addressed below in section 3.2.

5. The UK does not have any LCPs subject to the IED Article 35 derogations ('district heating plants'), therefore guidance of these BATc that apply to district heating plants has not been developed.

6. Plant participating in the Transitional National Plan (TNP). The EC has provided some clarification on compliance options for plant subject to the a TNP[2,3]. UK regulators have considered this guidance and determined that:

• For LCPs subject to the TNP that represent the primary activity of an installation, that upgrade to meet IED Annex V requirements at the end of the TNP period and where this would be considered a substantial change under Article 20(3) of the IED, then the ELVs based on the BAT-AELs in these BATcs apply from 1st July 2020, unless derogated under Article 15(4). ELVs are based on site specific BAT

2 http://ec.europa.eu/environment/industry/stationary/ied/faq.htm#ch3 3 The EC Guidance in reference 2 addresses issues such as:

the application of less strict emission limit values for <1.500 hour plants (the calculation of the number of operating hours as a rolling average over a period of 5 years has to start on the date when the plant is no longer subject to the TNP (1 July 2020 the latest).

The applicability of Article 18 in all cases (requirements for more stringent permit conditions than specified in IED Chapter III/Annex V if local EQS are threatened)

http://ec.europa.eu/environment/industry/stationary/ied/faq.htm#ch3

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prior to this date.

• For LCPs subject to the TNP that represent the primary activity of an installation, that upgrade to meet IED Annex V requirements at the end of the TNP period and where this would NOT be considered a substantial change under Article 20(3) of the IED, then the ELVs based on the BAT-AELs in these BATcs apply by the 4th anniversary of the publication of this BREF, unless derogated under Article 15(4). ELVs are based on site specific BAT prior to this date.

• For LCPs subject to the TNP that do not represent the primary activity of an installation that upgrade to meet IED Annex V requirements within the TNP period, and where this would be considered a substantial change under Article 20(3) of the IED, then the ELVs based on the BAT-AELs in these BATcs apply from 1st July 2020, unless derogated under Article 15(4). ELVs are based on site specific BAT prior to this date.

• For LCPs subject to the TNP that do not represent the primary activity of an installation that upgrade to meet IED Annex V requirements within the TNP period, and where this would NOT be considered a substantial change under Article 20(3) of the IED, Annex V requirements (including any relevant flexibilities) will be imposed by permit from the 1st July 2020 (or sooner if the plant wishes to leave the TNP prior to July 2020). The requirements of these BATcs will be applied from the 4th anniversary of the publication of the relevant BATcs for the primary activity of the installation. Site specific BAT requirements (reflecting IED Annex V requirements as a minimum) will be imposed by permit in the interim period from the end of the TNP until the 4th anniversary of the publication of the relevant BATcs for the primary activity of the installation.

7. These BATcs do not apply to the gasification of fuels, when the resulting syngas is not combusted in an associated large combustion plant or when directly associated to the refining of mineral oil and gas (including in this case where the syngas is subsequently combusted). Otherwise large combustion plants combusting syngas from gasification of fuels are subject to these BATcs.

8. These BATcs do not apply to process furnaces or heaters, combustion in post combustion plants or flaring. Process heaters and furnaces and post combustion plant are defined in the definition section above.

9. These BATcs do not apply to recovery boilers and total reduced sulphur burners at pulp and paper installations. These two types of combustion systems have specific definitions. A recovery boiler is considered part of Kraft process of pulping wood which is used to combust black liquor from the Kraft process. A reduced sulphur burner is used for removing odorous gases from the Kraft process.4]. Other large combustion plants at pulp and paper installations not meeting these definitions are subject to these BATcs.

10. These BATcs do not apply to the combustion of refinery fuels at the refinery site. Other large combustion plants at refinery installations not using refinery fuels at the refinery site are subject to these BATcs.

11. The applicability of these BATcs to disposal or recovery of waste in waste co-incineration plants and to biomass combustion (as defined in Article 3(31) of Directive 2010/75/EU) is specifically addressed in section 6 below.

4 Source for sulphur burner definition(P&P Bref)

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12. For plants operating <1500 hours see additional guidance in each relevant section below and specifically in Paragraph XX. It should be noted that IED Annex V, part 1 (for existing plant) includes less stringent emission limit values for plants operating no more than 1500 hours per year as a rolling average over 5 years, while Annex V, part 2 (for new plant) does not include specific limit values for such plants. The term “no more than” is not comparable with the terms “<” or “less than” that are used in relation to 1,500 hour operational thresholds in these BATcs. In order to simplify matters, the UK Regulators have decided to take the more limiting/conservative terminology used in these BATcs even when applying the Annex V provisions.

DEFINITIONS

For the purposes of these BAT conclusions, the following definitions apply:

Term used Definition

Boiler Any combustion plant with the exception of engines, gas turbines, and process furnaces or heaters

Combined-cycle gas turbine (CCGT)

A CCGT is a combustion plant where two thermodynamic cycles are used (i.e. Brayton and Rankine cycles). In a CCGT, heat from the flue-gas of a gas turbine (operating according to the Brayton cycle to produce electricity) is converted to useful energy in a heat recovery steam generator (HRSG), where it is used to generate steam, which then expands in a steam turbine (operating according to the Rankine cycle to produce additional electricity). For the purpose of these BAT conclusions, a CCGT includes configurations both with and without supplementary firing of the HRSG

Combustion plant Any technical apparatus in which fuels are oxidised in order to use the heat thus generated. For the purposes of these BAT conclusions, a combination formed of:

two or more separate combustion plants where the flue-gases are discharged through a common stack, or

separate combustion plants that have been granted a permit for the first time on or after 1 July 1987, or for which the operators have submitted a complete application for a permit on or after that date, which are installed in such a way that, taking technical and economic factors into account, their flue-gases could, in the judgment of the competent authority, be discharged through a common stack

is considered as a single combustion plant. For calculating the total rated thermal input of such a combination, the capacities of all individual combustion plants concerned, which have a rated thermal input of at least 15 MW, shall be added together

Combustion unit Individual combustion plant

Continuous measurement Measurement using an automated measuring system permanently installed on site

Direct discharge Discharge (to a receiving water body) at the point where the emission leaves the installation without further downstream treatment

Flue-gas desulphurisation (FGD) system

System composed of one or a combination of abatement technique(s) whose purpose is to reduce the level of SOX emitted by a combustion plant

Flue-gas desulphurisation (FGD) system - existing

A flue-gas desulphurisation (FGD) system that is not a new FGD system

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Flue-gas desulphurisation (FGD) system - new

Either a flue-gas desulphurisation (FGD) system in a new plant or a FGD system that includes at least one abatement technique introduced or completely replaced in an existing plant following the publication of these BAT conclusions

Gas oil Any petroleum-derived liquid fuel falling within CN code 2710 19 25, 2710 19 29, 2710 19 47, 2710 19 48, 2710 20 17 or 2710 20 19. Or any petroleum-derived liquid fuel of which less than 65 vol-% (including losses) distils at 250 °C and of which at least 85 vol-% (including losses) distils at 350 °C by the ASTM D86 method

Heavy fuel oil (HFO) Any petroleum-derived liquid fuel falling within CN code 2710 19 51 to 2710 19 68, 2710 20 31, 2710 20 35, 2710 20 39. Or any petroleum-derived liquid fuel, other than gas oil, which, by reason of its distillation limits, falls within the category of heavy oils intended for use as fuel and of which less than 65 vol-% (including losses) distils at 250 °C by the ASTM D86 method. If the distillation cannot be determined by the ASTM D86 method, the petroleum product is also categorised as a heavy fuel oil

Net electrical efficiency (combustion unit and IGCC)

Ratio between the net electrical output (electricity produced on the high-voltage side of the main transformer minus the imported energy – e.g. for auxiliary systems' consumption) and the fuel/feedstock energy input (as the fuel/feedstock lower heating value) at the combustion unit boundary over a given period of time

Net mechanical energy efficiency Ratio between the mechanical power at load coupling and the thermal power supplied by the fuel

Net total fuel utilisation (combustion unit and IGCC)

Ratio between the net produced energy (electricity, hot water, steam, mechanical energy produced minus the imported electrical and/or thermal energy (e.g. for auxiliary systems' consumption)) and the fuel energy input (as the fuel lower heating value) at the combustion unit boundary over a given period of time

Net total fuel utilisation (gasification unit)

Ratio between the net produced energy (electricity, hot water, steam, mechanical energy produced, and syngas (as the syngas lower heating value) minus the imported electrical and/or thermal energy (e.g. for auxiliary systems' consumption)) and the fuel/feedstock energy input (as the fuel/feedstock lower heating value) at the gasification unit boundary over a given period of time

Operated hours The time, expressed in hours, during which a combustion plant, in whole or in part, is operated and is discharging emissions to air, excluding start -up and shutdown periods

Periodic measurement Determination of a measurand (a particular quantity subject to measurement) at specified time intervals

Plant - existing A combustion plant that is not a new plant

Plant - new A combustion plant first permitted at the installation following the publication of these BAT conclusions or a complete replacement of a combustion plant on the existing foundations following the publication of these BAT conclusions

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Post-combustion plant System designed to purify the flue-gases by combustion which is not operated as an independent combustion plant, such as a thermal oxidiser (i.e. tail gas incinerator), used for the removal of the pollutant(s) (e.g. VOC) content from the flue-gas with or without the recovery of the heat generated therein. Staged combustion techniques, where each combustion stage is confined within a separate chamber, which may have distinct combustion process characteristics (e.g. fuel to air ratio, temperature profile), are considered integrated in the combustion process and are not considered post-combustion plants. Similarly, when gases generated in a process heater/furnace or in another combustion process are subsequently oxidised in a distinct combustion plant to recover their energetic value (with or without the use of auxiliary fuel) to produce electricity, steam, hot water/oil or mechanical energy, the latter plant is not considered a post-combustion plant

Predictive emissions monitoring system (PEMS)

System used to determine the emissions concentration of a pollutant from an emission source on a continuous basis, based on its relationship with a number of characteristic continuously monitored process parameters (e.g. the fuel gas consumption, the air to fuel ratio) and fuel or feed quality data (e.g. the sulphur content)

Process fuels from the chemical industry

Gaseous and/or liquid by-products generated by the (petro-)chemical industry and used as non-commercial fuels in combustion plants

Process furnaces or heaters Process furnaces or heaters are: combustion plants whose flue-gases are used for the thermal treatment of objects or feed material through a direct contact heating mechanism (e.g. cement and lime kiln, glass furnace, asphalt kiln, drying process, reactor used in the (petro-)chemical industry, ferrous metal processing furnaces), or combustion plants whose radiant and/or conductive heat is transferred to objects or feed material through a solid wall without using an intermediary heat transfer fluid (e.g. coke battery furnace, cowper, furnace or reactor heating a process stream used in the (petro-)chemical industry such as a steam cracker furnace, process heater used for the regasification of liquefied natural gas (LNG) in LNG terminals). As a consequence of the application of good energy recovery practices, process heaters/furnaces may have an associated steam/electricity generation system. This is considered to be an integral design feature of the process heater/furnace that cannot be considered in isolation

Refinery fuels Solid, liquid or gaseous combustible material from the distillation and conversion steps of the refining of crude oil. Examples are refinery fuel gas (RFG), syngas, refinery oils, and pet coke

Residues Substances or objects generated by the activities covered by the scope of this document, as waste or by-products

Start-up and shut-down period The time period of plant operation as determined pursuant to the provisions of Commission Implementing Decision 2012/249/EU of 7 May 2012, concerning the determination of start-up and shut-down periods for the purposes of Directive 2010/75/EU of the European Parliament and the Council on industrial emissions

Unit - existing A combustion unit that is not a new unit

Unit- new A combustion unit first permitted at the combustion plant following the publication of these BAT conclusions or a complete replacement of a combustion unit on the existing foundations of the combustion plant following the publication of these BAT conclusions

Valid (hourly average) An hourly average is considered valid when there is no maintenance or malfunction of the automated measuring system

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GUIDANCE

13. For the purposes of these BATcs, the definitions provided in the BATCs will be used where relevant. Where reference is made to terms that are defined in the IED, the IED definitions will be adopted in preference to any definitions that are included in domestic UK legislation. This is important primarily for waste co-incineration issues. Only where terms are not defined in these BATcs or the IED will the definitions in domestic UK statutes will be applied. In many cases, specific guidance provided in this document to aid in the interpretation of undefined terms.

POLLUTANTS/PARAMETERS

Acronym Definition

As The sum of arsenic and its compounds, expressed as As

C3 Hydrocarbons having a carbon number equal to three

C4+ Hydrocarbons having a carbon number of four or greater

Cd The sum of cadmium and its compounds, expressed as Cd

Cd+Tl The sum of cadmium, thallium and their compounds, expressed as Cd+Tl

CH4 Methane

CO Carbon monoxide

COD Chemical oxygen demand. Amount of oxygen needed for the total oxidation of the organic matter to carbon dioxide

COS Carbonyl sulphide

Cr The sum of chromium and its compounds, expressed as Cr

Cu The sum of copper and its compounds, expressed as Cu

Dust Total particulate matter (in air)

Fluoride Dissolved fluoride, expressed as F-

H2S Hydrogen sulphide

HCl All inorganic gaseous chlorine compounds, expressed as HCl

HCN Hydrogen cyanide

HF All inorganic gaseous fluorine compounds, expressed as HF

Hg The sum of mercury and its compounds, expressed as Hg

N2O Dinitrogen monoxide (nitrous oxide)

NH3 Ammonia

Ni The sum of nickel and its compounds, expressed as Ni

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Acronym Definition

NOX The sum of nitrogen monoxide (NO) and nitrogen dioxide (NO2), expressed as NO2

Pb The sum of lead and its compounds, expressed as Pb

PCDD/F Polychlorinated dibenzo-p-dioxins and -furans

RCG Raw concentration in the flue-gas. Concentration of SO2 in the raw flue-gas as a yearly average (under the standard conditions given under General considerations) at the inlet of the SOX abatement system, expressed at a reference oxygen content of 6 vol-% O2

Sb+As+Pb+Cr+Co+Cu+Mn+Ni+V The sum of antimony, arsenic, lead, chromium, cobalt, copper, manganese, nickel, vanadium and their compounds, expressed as Sb+As+Pb+Cr+Co+Cu+Mn+Ni+V

SO2 Sulphur dioxide

SO3 Sulphur trioxide

SOX The sum of sulphur dioxide (SO2) and sulphur trioxide (SO3), expressed as SO2

Sulphate Dissolved sulphate, expressed as SO42-

Sulphide, easily released The sum of dissolved sulphide and of those undissolved sulphides that are easily released upon acidification, expressed as S2-

Sulphite Dissolved sulphite, expressed as SO32-

TOC Total organic carbon, expressed as C (in water)

TSS Total suspended solids. Mass concentration of all suspended solids (in water), measured via filtration through glass fibre filters and gravimetry

TVOC Total volatile organic carbon, expressed as C (in air)

Zn The sum of zinc and its compounds, expressed as Zn

GUIDANCE

14. BAT-AELs for oxides of sulphur are generally set on the basis of emissions of SO2. However, the description of available emission reduction techniques are generally expressed in terms of techniques for reducing emissions of SOx. In most cases SO3 emissions only form a small percentage of total SOx emissions. However, the exact percentage depends on factors such as the overall level of sulphur emissions, flue gas temperature and dew point, and the presence of other substances. In some cases elevated emissions of SO3 may be expected, for instance for plant using SCR or SO3 conditioning to help improve the performance of ESPs or for plant with specific stack configurations. To ease the regulatory burden on operators, UK regulators will take a general position that total SOx emissions are synonymous with SO2 emissions unless there are recognised site specific factors that need to be taken into account. In such cases, operators will be expected to quantify SO3 emissions from all typical operating conditions and derive a suitable factor to estimate total SOx emissions which can then be derived from routine monitoring or derivations of SO2 emissions.

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ACRONYMS

For the purposes of these BAT conclusions, the following acronyms apply:

Acronym Definition

ASU Air supply unit

CCGT Combined-cycle gas turbine, with or without supplementary firing

CFB Circulating fluidised bed

CHP Combined heat and power

COG Coke oven gas

COS Carbonyl sulphide

DLN Dry low-NOX burners

DSI Duct sorbent injection

ESP Electrostatic precipitator

FBC Fluidised bed combustion

FGD Flue-gas desulphurisation

HFO Heavy fuel oil

HRSG Heat recovery steam generator

IGCC Integrated gasification combined cycle

LHV Lower heating value

LNB Low-NOX burners

LNG Liquefied natural gas

OCGT Open-cycle gas turbine

OTNOC Other than normal operating conditions

PC Pulverised combustion

PEMS Predictive emissions monitoring system

SCR Selective catalytic reduction

SDA Spray dry absorber

SNCR Selective non-catalytic reduction

GUIDANCE

15. No interpretational guidance has been provided at this time.

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GENERAL CONSIDERATIONS

Best Available Techniques

The techniques listed and described in these BAT conclusions are neither prescriptive nor exhaustive. Other techniques may be used that ensure at least an equivalent level of environmental protection.

Unless otherwise stated, the BAT conclusions are generally applicable.

Emission levels associated with the best available techniques (BAT-AELs)

Where emission levels associated with the best available techniques (BAT-AELs) are given for different averaging periods, all of those BAT-AELs have to be complied with.

The BAT-AELs set out in these BAT conclusions may not apply to liquid-fuel-fired and gas-fired turbines and engines for emergency use operated less than 500 h/yr, when such emergency use is not compatible with meeting the BAT-AELs.

BAT-AELs for emissions to air

Emission levels associated with the best available techniques (BAT-AELs) for emissions to air given in these BAT conclusions refer to concentrations, expressed as mass of emitted substance per volume of flue-gas under the following standard conditions: dry gas at a temperature of 273.15 K, and a pressure of 101.3 kPa, and expressed in the units mg/Nm3, μg/Nm3 or ng I-TEQ/Nm3.

The monitoring associated with the BAT-AELs for emissions to air is given in BAT 4.

Reference conditions for oxygen used to express BAT-AELs in this document are shown in the table given below.

Activity Reference oxygen level (OR)

Combustion of solid fuels

6 vol-% Combustion of solid fuels in combination with liquid and/or gaseous fuels

Waste co-incineration

Combustion of liquid and/or gaseous fuels when not taking place in a gas turbine or an engine

3 vol-%

Combustion of liquid and/or gaseous fuels when taking place in a gas turbine or an engine

15 vol-%

Combustion in IGCC plants

The equation for calculating the emission concentration at the reference oxygen level is:

𝐸𝑅 = 21 − 𝑂𝑅

21 − 𝑂𝑀 × 𝐸𝑀

Where:

ER: emission concentration at the reference oxygen level OR;

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OR: reference oxygen level in vol-%;

EM: measured emission concentration;

OM: measured oxygen level in vol-%.

For averaging periods, the following definitions apply:

Averaging period Definition

Daily average Average over a period of 24 hours of valid hourly averages obtained by continuous measurements

Yearly average Average over a period of one year of valid hourly averages obtained by continuous measurements

Average over the sampling period Average value of three consecutive measurements of at least 30 minutes each (1)

Average of samples obtained during one year

Average of the values obtained during one year of the periodic measurements taken with the monitoring frequency set for each parameter

(1) For any parameter where, due to sampling or analytical limitations, 30-minute measurement is inappropriate, a suitable sampling period is employed. For PCDD/F, a sampling period of 6 to 8 hours is used.

BAT-AELs for emissions to water

Emission levels associated with the best available techniques (BAT-AELs) for emissions to water given in these BAT conclusions refer to concentrations, expressed as mass of emitted substance per volume of water, and expressed in μg/l, mg/l, or g/l. The BAT-AELs refer to daily averages, i.e. 24-hour flow-proportional composite samples. Time-proportional composite samples can be used provided that sufficient flow stability can be demonstrated.

The monitoring associated with BAT-AELs for emissions to water is given in BAT 5

Energy efficiency levels associated with the best available techniques (BAT-AEELs)

An energy efficiency level associated with the best available techniques (BAT-AEEL) refers to the ratio between the combustion unit's net energy output(s) and the combustion unit's fuel/feedstock energy input at actual unit design. The net energy output(s) is determined at the combustion, gasification, or IGCC unit boundaries, including auxiliary systems (e.g. flue-gas treatment systems), and for the unit operated at full load.

In the case of combined heat and power (CHP) plants:

the net total fuel utilisation BAT-AEEL refers to the combustion unit operated at full load and tuned to maximise primarily the heat supply and secondarily the remaining power that can be generated;

the net electrical efficiency BAT-AEEL refers to the combustion unit generating only electricity at full load.

BAT-AEELs are expressed as a percentage. The fuel/feedstock energy input is expressed as lower heating value (LHV).

The monitoring associated with BAT-AEELs is given in BAT 2.

Categorisation of combustion plants/units according to their total rated thermal input

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For the purposes of these BAT conclusions, when a range of values for the total rated thermal input is indicated, this is to be read as 'equal to or greater than the lower end of the range and lower than the upper end of the range'. For example, the plant category 100–300 MWth is to be read as: combustion plants with a total rated thermal input equal to or greater than 100 MW and lower than 300 MW.

When a part of a combustion plant discharging flue-gases through one or more separate ducts within a common stack is operated less than 1500 h/yr, that part of the plant may be considered separately for the purpose of these BAT conclusions. For all parts of the plant, the BAT-AELs apply in relation to the total rated thermal input of the plant. In such cases, the emissions through each of those ducts are monitored separately.

GUIDANCE

16. In all cases in these BATcs, where plant capacity is defined in terms of MW (thermal input) this is taken to mean the net rated thermal input based on the net CV of the fuel (or lower heating value).

17. Throughout these BATcs the nominal BAT-AELs ranges provided under each numbered BAT item can be amended by the application of specific qualifications, caveats or criteria. This is mostly achieved by the use of footnotes. The precise wording of the footnotes varies throughout the document and needs to be considered carefully in each case. The wording of the footnote can significantly alter the way in which the specific amendments to the BAT-AEL ranges need to be considered and/or applied within the permit.

18. In particular regard must be given to the position established by the EC[5] in 2016. In this case, the EC considered that the terms “may be” and “may not apply” should not be read as providing an extension to the BAT-AEL range. Such terms were to be regarded as merely complementary information for Competent Authorities which could be considered when granting derogation under IED Article 15(4.

19. There are only 3 instances in these LCP BRef BATcs where this “may” qualification occurs in relation to a specific BAT-AEL range where a specific IED Article 15(4) derogation may be applicable (once in the case of FGD water emissions and twice for BAT-AELs for iron/steel systems). These cases are specifically addressed in each relevant section of the guidance below.

20. Similarly, BAT-AEEL/BAT-AEPL/monitoring provisions can also be amended by the application of specific qualifications, caveats or criteria given in footnotes. There are far more cases where a BAT-AEEL range “may be” amended than for BAT-AELs. However, as a formal derogation under IED Article 15(4) is not required for any deviation from the stated BAT-AEELs/AEPLs or monitoring provisions, the amendments to the specified requirements need to be specifically addressed by the required BAT justification and will be considered by the UK Regulators when determining BAT.

21. Measurement uncertainty. This issue is addressed by the Cross-cutting BRef: The term “Valid (hourly averages)” is defined above as relating to hourly average data where no CEM malfunction or maintenance was apparent. This is a subtle but different definition to the term “validated” used with the IED (Annex V, Part 3, section 9). The IED term “validated” relates to hourly average data that are “valid” (i.e. with no CEMS malfunction or maintenance) that have been further corrected by the subtraction of a specified

5 Letter from EC DG Environment (Directorate C - Quality of Life, Water & Air, ENV.C.4 - Industrial

Emissions) to Ministry of Environment and Food of Denmark regarding Large Combustion Plants within Refineries Ref. Ares (2016)1181153 - 08/03/2016

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confidence level. These BATcs do not adopt the term “validated” but do make reference to valid averages (where no subtraction of confidence level has been undertaken). Confidence Intervals are the recognised approach to dealing with the uncertainty associated with monitoring techniques. Usually an agreed level of uncertainty is subtracted from measured data for the purpose of reporting against emission limit values and verifying whether compliance has been achieved. Confidence intervals are recognised and described in the revised final draft Joint Research Council Reference Report on Monitoring of emissions to air and water (ROM), although there is no specific guidance on whether they should be applied to BRef BAT-AELs. In addition, Annex V to the Industrial Emission Directive (IED) sets ELVs for sulphur dioxide, oxides of nitrogen and dust form large combustion plants and sets out the confidence intervals that should be subtracted from the measured values when reported against the ELVs. The BAT-AELs in the LCP BAT conclusions were derived from “as measured” data i.e. the confidence interval was not subtracted so we must determine how to apply the BAT-AELs as ELVs in installation permits and how to require the operator to report against them. The BRef is silent on this. The key issue is that, should monitoring data indicate that an ELV has been exceeded, no enforcement action can be taken unless there is legal certainty of the breach. We have therefore concluded that Confidence Intervals will be taken into account when reporting against ELVs set to implement the BAT conclusions. In practice this means that for:

CEMS. The confidence intervals set out in Annex V of the IED will be subtracted from data reported from CEMS for CO, SO2, NOx, and dust. For other species (eg HCl) the values set out in Annex VI will be used. Where the IED does not specify a confidence interval we will use agreed values. Confidence intervals will be applied to annual averages as it has been demonstrated that systematic and calibration uncertainties are of a similar order to those for short term averages.

Periodic monitoring. The as measured data will be reported together with the confidence level and the confidence interval will be used by the Regulator to assess compliance with the ELV.

22. The BRef sets out AELs based on daily averages and as an annual mean of hourly averages (the latter only for existing combustion plant operating >1500hpa and all new plant operating >500hpa). The IED however, sets ELVs as hourly (95%ile over a year), daily and monthly averages. The IED ELVs must still be met but, on the whole, the BRef AELs are tighter. Therefore where both the BRef and the IED require an ELV over the same averaging period (e.g. daily), only the tighter value will be set in the permit.

23. ‘Indicative’ Emission Levels’. The terms “indicative“ or the text “as an indication” are used throughout these BATcs in two ways:

when defining the applicability of certain BAT-AEL ranges to specific plant and/or fuel types for a number of pollutants. For example the BAT conclusions state throughout that the BAT-AELs are indicative for plant which operate <500hpa.

when indicating the anticipated emission level from a plant, where an BAT-AEL was not considered appropriate but demonstration of control of emission was considered important. Typically this was because of the inter-relationship between some species in some combustion systems, e.g. In the case of CO, due to the inter-relationship between CO and NOx emissions in some combustion systems, deviation from CO indicative emission levels may be accepted where an appropriate BAT assessment shows that the CO indicative emission level cannot be achieved when meeting a mandatory NOx BAT AEL.

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24. Emission levels that are indicative of BAT should be met as a principle but there is no requirement to use an IED Article 15(4) to derogate from an indicative EL. Instead an appropriate BAT justification would be required for deviation from the EL. Any IED Chapter III requirements will still apply.

25. The UK Regulators will determine whether there is a need for a numeric permit condition or other conditions to ensure compliance with an indicative BAT-AEL. In England and Wales it is expected that a permit ELV will normally be set to reflect an indicative BAT-AEL unless there are exceptional circumstances not to do so. In Scotland and Northern Ireland, the need to set a permit ELV to reflect an indicative BAT-AEL will be determined on case by case basis.

26. Further detailed guidance on the approach to energy efficiency and emissions to water is given in sections 1.4 and 1.5 below. See also the cross cutting BRef guidance[XX] for further information on the generic approach to emissions to water and energy efficiency.

27. The UK regulators interpret the term “net energy output” to relate to the actual useful energy produced by a plant after accounting for all auxiliary power requirements of the plant (and any abatement equipment).

28. Further detailed guidance on the applicability of, and UK regulators approach to the BAT-AELs (that may not apply to liquid-fuel-fired and gas-fired turbines and engines for emergency use operated less than 500 h/yr, when such emergency use is not compatible with meeting the BAT-AELs) is given in section 3 and 4 below. This BAT-AEL applicability is NOT one of the three instances in these LCP BATcs where the qualification “may not apply” is subject to further consideration. See guidance point XX above. In this case UK Regulators consider that the EC position would not apply as this does not represent the specific and unique circumstances when a site specific derogation under IED Article 15(4) is being considered. The qualification can apply to generic amendments to BAT-AEL ranges that may apply generically to various plant types or fuels.

29. BATcs generally specify that one or more specific techniques need to be adopted to control specific pollutants from specific technologies or fuel types (or efficiency improvement measures. The UK regulators have concluded that there is no requirement to implement all of the techniques listed and that BAT is to use an appropriate combination of techniques that may include some of the techniques listed. Indeed, these BATc include a statement declaring that the techniques listed are neither prescriptive nor exhaustive in describing techniques for controlling emissions. Similarly, the BATcs provide no indication of priority or hierarchy of the techniques listed. Different installations may be able to comply with the associated BAT-AELs by applying different techniques or combinations of techniques. During BATc reviews, justification will be required that all appropriate techniques have been identified and implemented to achieve BAT or discounted.

30. Each individual BAT conclusion is presented using a standard structure that includes a clear environmental objective. The presence of this clear objective provides the focus for Regulators when reviewing a permit, and suggests the possible need for permit conditions, although a permit condition is not necessarily required to address each BAT conclusion. There is an expectation that many (if not all) relevant BATc will be addressed in the decision document for the review to demonstrate that the BATc document has provided the reference for setting permit conditions.

31. 1500 hour issues and definitions

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The BAT Conclusions refer to plants operating <1500 hours per year and plants operating ≥ 1500 hours per year. (eg for compliance with the annual average of hourly values). UK Regulators have decided to use the same definition as used in the IED, namely that plant operating <1500hours per year meet the criterion if they operate <1500hours per year over a 5 year rolling average. This is set out in guidance6. In addition, UK Regulators have agreed that any plant which does not operate ≥1500 hours in a given calendar year does not need to report against the annual average for that year.

The further clarification in the BATcs for plant operating <1,500 hours per year

needs to be considered carefully as some BAT-AELs throughout these BATcs are

set at different levels for such plant compared to base load plant. This also applies

to any individual combustion unit (forming part of a large) combustion plant which

can be considered separately. This clarification means that, in a multi-unit plant

one unit (or more) could operate for more than 1500 hours/year and be subject to

the applicable BAT conclusions for that level of operation while the remaining units

could operate for less than 1500 hours/year and be subject to different BAT-AELs

(where specified) that apply to this lower level of operation.

1 GENERAL BAT CONCLUSIONS

The fuel-specific BAT conclusions included in Sections 2 to 7 apply in addition to the general BAT conclusions in this section.

1.1 ENVIRONMENTAL MANAGEMENT SYSTEMS

BAT 1

BAT 1 In order to improve the overall environmental performance, BAT is to implement and adhere to an environmental management system (EMS) that incorporates all of the following features:

(i) commitment of the management, including senior management;

(ii) definition, by the management, of an environmental policy that includes the continuous improvement of the environmental performance of the installation;

(iii) planning and establishing the necessary procedures, objectives and targets, in conjunction with financial planning and investment;

(iv) implementation of procedures paying particular attention to: (a) structure and responsibility (b) recruitment, training, awareness and competence (c) communication (d) employee involvement (e) documentation (f) effective process control

6 1500 Limited Hours Derogation Guidance

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(g) planned regular maintenance programmes (h) emergency preparedness and response (i) safeguarding compliance with environmental legislation;

(v) checking performance and taking corrective action, paying particular attention to: (a) monitoring and measurement (see also the JRC Reference Report on Monitoring

of emissions to air and water from IED-installations — ROM) (b) corrective and preventive action (c) maintenance of records (d) independent (where practicable) internal and external auditing in order to

determine whether or not the EMS conforms to planned arrangements and has been properly implemented and maintained;

(vi) review, by senior management, of the EMS and its continuing suitability, adequacy and effectiveness;

(vii) following the development of cleaner technologies;

(viii) consideration for the environmental impacts from the eventual decommissioning of the installation at the stage of designing a new plant, and throughout its operating life including; (a) avoiding underground structures (b) incorporating features that facilitate dismantling (c) choosing surface finishes that are easily decontaminated (d) using an equipment configuration that minimises trapped chemicals and facilitates

drainage or cleaning (e) designing flexible, self-contained equipment that enables phased closure (f) using biodegradable and recyclable materials where possible;

(ix) application of sectoral benchmarking on a regular basis.

Specifically for this sector, it is also important to consider the following features of the EMS, described where appropriate in the relevant BAT:

(x) quality assurance/quality control programmes to ensure that the characteristics of all fuels are fully determined and controlled (see BAT 9); 17.8.2017 L 212/12 Official Journal of the European Union EN

(xi) a management plan in order to reduce emissions to air and/or to water during other than normal operating conditions, including start-up and shutdown periods (see BAT 10 and BAT 11);

(xii) a waste management plan to ensure that waste is avoided, prepared for reuse, recycled or otherwise recovered, including the use of techniques given in BAT 16;

(xiii) a systematic method to identify and deal with potential uncontrolled and/or unplanned emissions to the environment, in particular: (a) emissions to soil and groundwater from the handling and storage of fuels,

additives, by-products and wastes (b) emissions associated with self-heating and/or self-ignition of fuel in the storage

and handling activities;

(xiv) a dust management plan to prevent or, where that is not practicable, to reduce diffuse emissions from loading, unloading, storage and/or handling of fuels, residues and additives;

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(xv) a noise management plan where a noise nuisance at sensitive receptors is expected or sustained, including; (a) a protocol for conducting noise monitoring at the plant boundary (b) a noise reduction programme (c) a protocol for response to noise incidents containing appropriate actions and

timelines (d) a review of historic noise incidents, corrective actions and dissemination of noise

incident knowledge to the affected parties;

(xvi) for the combustion, gasification or co-incineration of malodourous substances, an odour management plan including: (a) a protocol for conducting odour monitoring (b) where necessary, an odour elimination programme to identify and eliminate or

reduce the odour emissions (c) a protocol to record odour incidents and the appropriate actions and timelines (d) a review of historic odour incidents, corrective actions and the dissemination of

odour incident knowledge to the affected parties.

Where an assessment shows that any of the elements listed under items x to xvi are not necessary, a record is made of the decision, including the reasons.

Applicability The scope (e.g. level of detail) and nature of the EMS (e.g. standardised or non-standardised) is generally related to the nature, scale and complexity of the installation, and the range of environmental impacts it may have.

GUIDANCE

32. It is anticipated that all permits for IED installations already contain an EMS requirement. This may be included as reference to standard conditions, with verification likely to be by inspection. Implementation of an EMS is expected across all IED Installations and further guidance can be found in the generic Regulators cross cutting interpretational guidance[insert cross ref].

33. However, these BATcs also contain some specific issues that need to be addressed for combustion plant as listed below. Further detailed guidance on the specific technical issues relating to each of the requirements listed is available on the websites of each UK Regulator[7] and addresses issues such as:

quality assurance/quality control programmes to ensure that the characteristics of all fuels are fully determined and controlled (see BAT 9);

a management plan in order to reduce emissions to air and/or to water during other than normal operating conditions, including start-up and shutdown periods (see BAT 10 and BAT 11);

a waste management plan to ensure that waste is avoided, prepared for reuse, recycled or otherwise recovered, including the use of techniques given in BAT 16;

a systematic method to identify and deal with potential uncontrolled and/or unplanned emissions to the environment. Further information on self-ignition of fuels at large solid fuel plant is also available[8]:

7 https://www.gov.uk/guidance/energy-efficiency-standards-for-industrial-plants-to-get-

environmental-permits 8 Best Available Techniques for Pulverised Combustion of Wood Pellets in Power Plant V1.0

September 2013 – available from the Environment Agency on request.

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a dust management plan to prevent or, where that is not practicable, to reduce diffuse emissions from loading, unloading, storage and/or handling of fuels, residues and additives];

a noise management plan where a noise nuisance at sensitive receptors is expected or sustained; and

for the combustion, gasification or co-incineration of malodourous substances, an odour management plan.

1.2 MONITORING

BAT 2

BAT 2 BAT is to determine the net electrical efficiency and/or the net total fuel utilisation and/or the net mechanical energy efficiency of the gasification, IGCC and/or combustion units by carrying out a performance test at full load(1), according to EN standards, after the commissioning of the unit and after each modification that could significantly affect the net electrical efficiency and/or the net total fuel utilisation and/or the net mechanical energy efficiency of the unit. If EN standards are not available, BAT is to use ISO, national or other international standards that ensure the provision of data of an equivalent scientific quality.

(1) In the case of CHP units, if for technical reasons the performance test cannot be carried out with the unit operated at full load for the heat supply, the test can be supplemented or

substituted by a calculation using full load parameters.

GUIDANCE

34. See guidance point XX in section 1.4 below relating to energy efficiency considerations.

35. The results of efficiency testing during commissioning (or from the latest available set of testing following plant modification) will be taken into account during the determination of these aspects of BAT during the permit review. Performance tests should be undertaken at full load according to EN standards. If this data is not available then operators will be expected to undertake an efficiency test during the permit review or application period and submit the results to the relevant Regulator. Regulators will take a view on a case by case basis of the extent of testing required (or whether desk based estimates are sufficient using current plant operating data) taking into account the nature, lifetime and operational duty of each plant. Further details of the established approach is presented in the IED Protocol and TNP Guidance [9,10,11].

36. The testing requirements set out in BAT 2 will be required even if BAT-AEELS do not apply to any given plant. This approach is established to ensure that the efficiency of each plant is at least quantified and provides a benchmark to ensure degradation in energy efficiency over time is not unduly significant.

37. The types of modification that are considered to significantly affect the efficiency of a plant and would therefore require additional efficiency quantification to be undertaken could include (but are not limited to):

9 IED Protocol section 3.3.2 10 TNP Guidance section reference – Appendix C on CHP issues applies in England only. 11 IED Chapter III EXTERNAL FAQ section 18

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A change in fuel type or fuel composition (such as moving to natural gas from refinery fuel gas);

Installation or changes to abatement systems that could alter the overall plant efficiency

Installation of energy efficiency improvements (e.g. economiser replacement or air heater upgrades);

Turbine re-blading or power turbine replacements.

BAT 3

BAT 3. BAT is to monitor key process parameters relevant for emissions to air and water including those given below.

Stream Parameter(s) Monitoring

Flue-gas

Flow Periodic or continuous determination

Oxygen content, temperature, and pressure Periodic or continuous

measurement

Water vapour content (1)

Waste water from flue-gas treatment Flow, pH, and temperature Continuous measurement

(1) The continuous measurement of the water vapour content of the flue-gas is not necessary if the sampled flue-gas is dried before analysis.

GUIDANCE

38. For accurate mass release estimates continuous flow monitoring is normally carried out in conjunction with continuous emissions monitoring. However, specific flow monitoring may not required if continuous emission monitoring systems are already in place. In such cases flow rate determination will be required using the techniques and principles established generically under the IED[12] and for plant within the TNP[13]. This is subject to the overarching position regarding no backsliding. The relevant standard for flow rate determination is EN ISO 16911. If a plant runs in a stable pattern continuous flow monitoring is not required if the monitoring of emissions is required on a periodic basis.

39. Oxygen monitoring is always required (either continuously or during periodic monitoring periods). Oxygen monitoring is not required to be undertaken in its own right when monitoring for other substances is not required. The measurement of the water vapour content of the flue-gas is not necessary if the sampled flue-gas is dried before analysis.

40. Further guidance is given in section 1.5 below on emissions to water.

BAT 4

BAT 4. BAT is to monitor emissions to air with at least the frequency given below and in accordance with EN standards. If EN standards are not available, BAT is to

12 Section 6.6.1. Jep13sgg14: “Electricity Supply Industry – IED Compliance Protocol for Utility

Boilers and Gas Turbines (Update December 2015)”. 13 TNP Regulatory Guidance V8.0 December 2015 – WORKING DRAFT

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use ISO, national or other international standards that ensure the provision of data of an equivalent scientific quality.

Substance / Parameter

Fuel/Process/ Type of combustion plant

Combustion plant total rated thermal input

Standard(s) (1)

Minimum monitoring frequency (2)

Monitoring associated with

NH3 When SCR and/or SNCR is used

All sizes Generic EN standards

Continuous (3) (4)

BAT 7

NOX Coal and/or lignite

including waste co-incineration

Solid biomass and/or peat including waste co-incineration

HFO- and/or gas-oil-fired boilers and engines

Gas-oil-fired gas turbines

Natural-gas-fired boilers, engines, and

turbines

Iron and steel process gases


IGCC plants


Continuous (3) (5)

BAT 20 BAT 24 BAT 28 BAT 32 BAT 37 BAT 41 BAT 42 BAT 43 BAT 47 BAT 48 BAT 56 BAT 64 BAT 65 BAT 73

Combustion plants on offshore platforms

All sizes EN 14792 Once every year (6)

BAT 53

N2O Coal and/or lignite in circulating fluidised bed boilers

Solid biomass and/or peat in circulating fluidised bed boilers


BAT 20 BAT 24

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Standard(s) (1)



CO Coal and/or lignite including waste co-incineration




Natural-gas-fired boilers, engines, and turbines



IGCC plants


Continuous (3) (5)

BAT 20 BAT 24 BAT 28 BAT 33 BAT 38 0 BAT 49 BAT 56 BAT 64 BAT 65 BAT 73

Combustion plants on offshore platforms


BAT 54

SO2 Coal and/or lignite including waste co-incineration


HFO- and/or gas-oil-fired boilers

HFO- and/or gas-oil-fired engines



Process fuels from the chemical industry in boilers

IGCC plants

All sizes Generic EN standards and EN 14791

Continuous (3) (8) (9)

BAT 21 BAT 25 BAT 29 BAT 34 BAT 39 BAT 50 BAT 57 BAT 66 BAT 67 BAT 74

SO3 When SCR is used All sizes No EN standard available

Once every year —

Gaseous chlorides, expressed as HCl

Coal and/or lignite


All sizes EN 1911 Once every three months (3) (10) (11)

BAT 21 BAT 57

Solid biomass and/or peat


Continuous (12) (13)

BAT 25

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Standard(s) (1)





Continuous (3)(13)

BAT 66 BAT 67

HF Coal and/or lignite


All sizes No EN standard available

Once every three months (3) (10) (11)

BAT 21 BAT 57



Once every year BAT 25



Continuous (3)(13)

BAT 66 BAT 67

Dust Coal and/or lignite


HFO- and/or gas-oil-fired boilers



IGCC plants

HFO- and/or gas-oil-fired engines


All sizes Generic EN standards and EN 13284-1 and EN 13284-2

Continuous (3)(14)

BAT 22 BAT 26 BAT 30 BAT 35 BAT 39 BAT 51 BAT 58 BAT 75


All sizes Generic EN standards and EN 13284-2

Continuous BAT 68 BAT 69

Metals and metalloids except mercury (As, Cd, Co, Cr, Cu, Mn, Ni, Pb, Sb, Se, Tl, V, Zn)

Coal and/or lignite



All sizes

EN 14385 Once every year (15)

BAT 22 BAT 26 BAT 30


< 300 MWth EN 14385 Once every six months (10)

BAT 68 BAT 69

≥ 300 MWth EN 14385 Once every three months (16) (10)

IGCC plants ≥ 100 MWth EN 14385 Once every year (15)

BAT 75

Hg Coal and/or lignite including waste co-

< 300 MWth EN 13211 Once every three months (10) (17)

BAT 23

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Standard(s) (1)



incineration ≥ 300 MWth Generic EN standards and EN 14884




BAT 27

Waste co-incineration with solid biomass and/or peat

All sizes EN 13211 (10) Once every three months

BAT 70

IGCC plants ≥ 100 MWth EN 13211 Once every year (20)

BAT 75

TVOC HFO- and/or gas-oil-fired engines


All sizes EN 12619 Once every six months (10)

BAT 33 BAT 59

Waste co-incineration with coal, lignite, solid biomass and/or peat


Continuous BAT 71

Formaldehyde Natural-gas in spark-ignited lean-burn gas and dual fuel engines


Once every year BAT 45

CH4 Natural-gas-fired engines

All sizes EN ISO 25139 Once every year (21)

BAT 45

PCDD/F Process fuels from the chemical industry in boilers


All sizes EN 1948-1, EN 1948-2, EN 1948-3

Once every six months (10) (22)

BAT 59 BAT 71

(1) Generic EN standards for continuous measurements are EN 15267-1, EN 15267-2, EN 15267-3, and EN 14181. EN standards for periodic measurements are given in the table. (2) The monitoring frequency does not apply where plant operation would be for the sole purpose of performing an emission measurement. (3) In the case of plants with a rated thermal input of <100 MW operated <1500 h/yr, the minimum monitoring frequency may be at least once every six months. For gas turbines, periodic monitoring is carried out with a combustion plant load of >70%. For co-incineration of waste with coal, lignite, solid biomass and/or peat, the monitoring frequency needs to also take into account Part 6 of Annex VI to the IED. (4) In the case of use of SCR, the minimum monitoring frequency may be at least once every year, if the emission levels are proven to be sufficiently stable. (5) In the case of natural-gas-fired turbines with a rated thermal input of < 100 MW operated <1500 h/yr, or in the case of existing OCGTs, PEMS may be used instead. (6) PEMS may be used instead. (7) Two sets of measurements are carried out, one with the plant operated at loads of >70% and the other one at loads of <70%. (8) As an alternative to the continuous measurement in the case of plants combusting oil with a known sulphur content and where there is no flue-gas desulphurisation system, periodic measurements at least once every three months and/or other procedures ensuring the provision of data of an equivalent scientific quality may be used to

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Standard(s) (1)



determine the SO2 emissions. (9) In the case of process fuels from the chemical industry, the monitoring frequency may be adjusted for plants of <100 MWth after an initial characterisation of the fuel (see BAT 5) based on an assessment of the relevance of pollutant releases (e.g. concentration in fuel, flue-gas treatment employed) in the emissions to air, but in any case at least each time that a change of the fuel characteristics may have an impact on the emissions. (10) If the emission levels are proven to be sufficiently stable, periodic measurements may be carried out each time that a change of the fuel and/or waste characteristics may have an impact on the emissions, but in any case at least once every year. For co-incineration of waste with coal, lignite, solid biomass and/or peat, the monitoring frequency needs to also take into account Part 6 of Annex VI to the IED. (11) In the case of process fuels from the chemical industry, the monitoring frequency may be adjusted after an initial characterisation of the fuel (see BAT 5) based on an assessment of the relevance of pollutant releases (e.g. concentration in fuel, flue-gas treatment employed) in the emissions to air, but in any case at least each time that a change of the fuel characteristics may have an impact on the emissions. (12) In the case of plants with a rated thermal input of <100 MW operated <500 h/yr, the minimum monitoring frequency may be at least once every year. In the case of plants with a rated thermal input of < 100 MW operated between 500 h/yr and 1500 h/yr, the monitoring frequency may be reduced to at least once every six months. (13) If the emission levels are proven to be sufficiently stable, periodic measurements may be carried out each time that a change of the fuel and/or waste characteristics may have an impact on the emissions, but in any case at least once every six months. (14) In the case of plants combusting iron and steel process gases, the minimum monitoring frequency may be at least once every six months if the emission levels are proven to be sufficiently stable. (15) The list of pollutants monitored and the monitoring frequency may be adjusted after an initial characterisation of the fuel (see BAT 5) based on an assessment of the relevance of pollutant releases (e.g. concentration in fuel, flue-gas treatment employed) in the emissions to air, but in any case at least each time that a change of the fuel characteristics may have an impact on the emissions. (16) In the case of plants operated <1500 h/yr, the minimum monitoring frequency may be at least once every six months. (17) In the case of plants operated <1500 h/yr, the minimum monitoring frequency may be at least once every year. (18) Continuous sampling combined with frequent analysis of time-integrated samples, e.g. by a standardised sorbent trap monitoring method, may be used as an alternative to continuous measurements. (19) If the emission levels are proven to be sufficiently stable due to the low mercury content in the fuel, periodic measurements may be carried out only each time that a change of the fuel characteristics may have an impact on the emissions. (20) The minimum monitoring frequency does not apply in the case of plants operated <1500 h/yr. (21) Measurements are carried out with the plant operated at loads of >70%. (22) In the case of process fuels from the chemical industry, monitoring is only applicable when the fuels contain chlorinated substances.

GUIDANCE

41. IED Article 16 (in reference to IED Article 14(c)) requires that monitoring provisions specified in permits must be based, where applicable, on the monitoring requirements specified in BATcs[14]. In this case, “where applicable” is taken to mean when monitoring requirements for a specific pollutant or specific plant type are specified in these BATcs. It should be noted that, the current requirements of the IED[15] have been revised such that only these smaller plant that operate for <1,500 hours / year are exempt from continuous monitoring requirements. The monitoring provisions in BAT 4 are therefore considered mandatory and take precedence over IED Annex V requirements. However, there are some exceptions to this general position as noted below.

14 IED Article 14(c) requires that permits include suitable monitoring provisions addressing the

monitoring method, frequency and monitoring evaluation procedures. 15 IED Annex V, Part 3, paragraph 1 does not require continuous monitoring for smaller plant

<100MWth input regardless of operating regime

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The requirement to monitor in accordance with BAT 4 will apply unless there is no applicable BAT-AEL (and no permit ELVs are imposed). The monitoring specified within BAT4 is equally applicable for indicative BAT-AELs but only where a permit ELV is set to reflect the indicative BAT-AEL.

Site specific BAT may already require additional or alternative monitoring provisions

which will be maintained (no backsliding) using BAT 4 as a general reference. This

no backsliding position also applies to frequency of existing monitoring provisions.

Some large combustion plant are greater than 100MWth due to the aggregation of

smaller combustion plant (which individually are greater than 15MW th but less than

100 MWth). The LCP BRef requires the use, for certain pollutants, of continuous

emissions monitoring (CEMs) where the combustion plant is 100MW th. There is a

concern that this may be disproportionate where there are a number of small but

similar or identical combustion plant discharging through individual flues in a

common stack, and/or where the operation of such combustion plant may be on a

limited basis (in terms of operational hours).

The UK Regulators view is that where the main LCP stack has CEMs, where there

are also individual flues associated with each of the individual combustion units,

every these individual flues may not need not also to apply CEMs. for each flue.

Where each of the flues already have CEMs, then these would be retained (unless

the operating regime does not allow implementation of the quality assurance

requirements without operating specifically for that purpose). This decision will be

made on a plant specific basis and will take into account the number and size of

flues, types of fuel used and whether a representative flue may be used to apply

CEMS.

In addition, where part of the combustion plant, which discharges through a

common stack, but which operates for less than 1,500 hours/year then there are no

specific requirements for CEMs to be applied to the flue for that part of the plant, as

allowed under paragraph 2 of “Categorisation of combustion plants/units according

to their rated thermal input” in the LCP BRef, although periodic monitoring may be

expected:

UK Regulators also need consider whether other relevant considerations are

applicable to the nominal monitoring provisions specified by BAT 4 or whether

additional monitoring provisions are required. This includes cases where monitoring

may be required to provide relevant information for the calculation of mass emissions

or to assess compliance with an ELV set to protect a relevant EQS or to provide a

demonstration that any relevant abatement systems are functioning appropriately.

Other relevant considerations that may be applicable to imposition of specific

monitoring provisions are detailed in section 4.3 of the ROM[XX].

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In certain cases, BAT4 requires specific monitoring to be undertaken for a specific environmental reason even though no BAT-AEL is set (e.g. N20 monitoring from CFBC plant or metal emissions from solid fuel firing). In such cases the requirement for monitoring will be established on a cases by case basis.

Where continuous monitoring was not required under the IED (when the 10,000 hours exemption listed in Annex V, Part 3, paragraph 2(a) applied) this will be maintained. However, this is subject to the plant in question being low utilisation with a significant proportion of the original 10,000 life time hours exemption remaining. No new exemptions specified in Annex V, Part 3, paragraph 2(a) will be sanctioned where BAT 4 dictates specific continuous monitoring requirements.

In relation to dust and SO2 monitoring for gas fired plant that occasionally use liquid fuels for standby or emergency provisions (see BAT XX and guidance paragraph XX below) the relevant monitoring provisions stated in BAT 4 above will be adopted unless no relevant permit ELV has been imposed. In such cases, we will require that the provisions of Part 3 of IED Annex V are maintained, including any relaxations.

When a BAT-AEL is not applicable (as a plant is operating below a time period threshold), this time period threshold will be used in place of any time thresholds specified as a relaxation in Part 3 of IED Annex V. The BAT-AEL operating time threshold is likely to be reflected as a permit condition as well as any time thresholds specified as a derogation in Part 3 of IED Annex V .

When relaxations from certain BAT 4 provisions are specified in the footnotes, these will be applied when applicable. When BAT 4 does not require monitoring (or no permit ELV is set) mass emissions should be estimated from recognised emission factors.

Will not require a plant to start up or operate just for the purposes of monitoring (as specified by footnote 2 to BAT 4). However, we believe that monitoring can still be scheduled on low use plant to coincide with other planned maintenance activities that require the plant to operate or where the plant is required to operate after maintenance to demonstrate availability.

42. Other procedures for the provision of data of an equivalent scientific quality summarise

EA SO2 document…….are documented in guidance paragraph XX and in other

Regulator guidance[20].

43. If NOx and CO emissions are subject to continuous monitoring for fuels other than natural gas then UK regulators consider that the derogation to allow periodic SO2 monitoring for new plants for fuels with unstable sulphur contents may not be applicable given the relatively small incremental costs of installing continuous SO2 monitoring in combination with the existing monitoring for other substances. This will necessarily be a site specific BAT consideration.

44. A summary of the above monitoring provisions is presented for each BAT-AEL in each relevant section below together with specific interpretational guidance for each monitoring provision (where required).

45. In cases where a plant uses multiple fuels (either simultaneously or in different time periods), the BAT 4 monitoring provisions above for each fuel/substance will be applied. In the case of plant fitted with CEM systems, these should be used and maintained during the operation on all fuel types (or during co-firing). It is not considered BAT to have a monitoring system installed and working but not used.

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46. There are relaxations from continuous monitoring requirements for NOx and CO for both new and existing natural gas-fired turbines but only for turbines with a rated thermal input of < 100 MW operated < 1,500 hours pa. However, PEMS can be adopted instead and there is an expectation that PEMS should be adopted in most cases. No continuous monitoring provisions for NOx and CO other than PEMS are specified for existing natural gas fired OCGTs of any size or in any duty (BAT 4 Table, footnote 5). Note that the provision for PEMS does not apply to CCGTs in such cases. The calibration requirements of the PEMS by periodic monitoring would normally be expected at least annually for most plant except low use systems. In such cases periodic monitoring requirements will be set on a case by case basis.

47. Monitoring of mercury emissions to air from combustion plant using solid fuels >300MWth shall be continuous. [However, noting footnote 13 that states that if the emission levels are proven to be sufficiently stable, periodic measurements may be undertaken at least once every six months34 or each time that a change of fuel …. [occurs]…. that may have an impact on the emissions. In the case of coal fired plant “sufficiently stable” emission levels will be demonstrated through compliance with the Trace Species Protocol16. This will be carried out in advance of the implementation of the emission monitoring requirements and utilise accepted retention factors along with a calculated demonstration that BRef BAT conclusions are being met for each category of plant. In the case of biomass plant, this will be determined on a site specific basis. Once this demonstration has been made, the following will be required:

Plant operating <500 hours per annum should not be run for monitoring purposes alone, for either measurement or calibration. We will require emissions to be reported based on estimation techniques using either site-specific or generic factors based on fuel content.

For plant operating >500hpa periodic monitoring is required at least once in every six month period. In addition, fuel Hg content will be recorded monthly and reported quarterly.

48. HCl and HF monitoring of emissions to air from combustion plant using solid fuels of all sizes [add comments about biomass plant, waste co-incinerators and chemical fuels] is required to be carried out every 3 months unless the emission levels are proven to be sufficiently stable, in which case periodic measurements may be carried out at least once a year or each time that a change of fuel …..[occurs].…that may have an impact on the emissions. In such cases “sufficiently stable” emissions will be demonstrated through quarterly reporting of monthly Cl and F fuel content. This will be carried out in advance of the implementation of the emission monitoring requirements and utilise accepted retention factors along with a calculated demonstration that BRef BAT conclusions are being met for each category of plant. Once this demonstration has been made, the following will be required:

Plant operating <500 hours per annum should not be run for monitoring purposes alone, for either measurement or calibration. We will require emissions to be reported based on estimation techniques using either site-specific or generic factors based on fuel content.

16 JEP18EMC02: PROTOCOL FOR LCP BREF COMPLIANCE WITH TRACE SPECIES MONITORING REQUIREMENTS AT COAL FIRED POWER PLANT

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For plant operating >500hpa periodic monitoring is required at least once per annum, noting that the AEL applied will correspond to >1500hpa or <1500hpa operation.

BAT 5

BAT 5. BAT is to monitor emissions to water from flue-gas treatment with at least the frequency given below and in accordance with EN standards. If EN standards are not available, BAT is to use ISO, national or other international standards that ensure the provision of data of an equivalent scientific quality.

Substance/Parameter Standard(s) Minimum monitoring frequency


Total organic carbon (TOC) (1) EN 1484

Once every month

BAT 15

Chemical oxygen demand (COD) (1)

No EN standard available

Total suspended solids (TSS) EN 872

Fluoride (F-) EN ISO 10304-1

Sulphate (SO42-) EN ISO 10304-1

Sulphide, easily released (S2-) No EN standard available

Sulphite (SO32-) EN ISO 10304-3

Metals and metalloids As Various EN standards available (e.g. EN ISO 11885 or EN ISO 17294-2)

Cd

Cr

Cu

Ni

Pb

Zn

Hg Various EN standards available (e.g. EN ISO 12846 or EN ISO 17852)

Chloride (Cl-) Various EN standards available (e.g. EN ISO 10304-1 or EN ISO 15682)

—

Total nitrogen EN 12260 —

(1) TOC monitoring and COD monitoring are alternatives. TOC monitoring is the preferred option because it does not rely on the use of very toxic compounds.

GUIDANCE

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49. At the time of writing this guidance there is uncertainty over the applicability of appropriate monitoring techniques for sulphide, this will be addressed through improvement conditions on a site specific basis..

50. See also section 1.5 below and guidance points XX and XX.

1.3 GENERAL ENVIRONMENTAL AND COMBUSTION PERFORMANCE

BAT 6

BAT 6. In order to improve the general environmental performance of combustion plants and to reduce emissions to air of CO and unburnt substances, BAT is to ensure optimised combustion and to use an appropriate combination of the techniques given below.

Technique Description Applicability

a. Fuel blending and mixing

Ensure stable combustion conditions and/or reduce the emission of pollutants by mixing different qualities of the same fuel type

Generally applicable

b. Maintenance of the combustion system

Regular planned maintenance according to suppliers' recommendations

c. Advanced control system

See description in Section 8.1 The applicability to old combustion plants may be constrained by the need to retrofit the combustion system and/or control command system

d. Good design of the combustion equipment

Good design of furnace, combustion chambers, burners and associated devices

Generally applicable to new combustion plants

e. Fuel choice Select or switch totally or partially to another fuel(s) with a better environmental profile (e.g. with low sulphur and/or mercury content) amongst the available fuels, including in start-up situations or when back-up fuels are used

Applicable within the constraints associated with the availability of suitable types of fuel with a better environmental profile as a whole, which may be impacted by the energy policy of the Member State, or by the integrated site's fuel balance in the case of combustion of industrial process fuels. For existing combustion plants, the type of fuel chosen may be limited by the configuration and the design of the plant

GUIDANCE

51. See guidance point XX in the general considerations section above on how to address BAT requirements for the application of one, or more, of the techniques specified above.

52. Note the BAT objective is to improve the general environmental performance of the combustion plant and reduce emissions to air of CO. Therefore an operator needs to demonstrate the techniques used at the installation will achieve this objective, and the

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regulator will record (or reference other locations) in the decision document the techniques employed by the operator, and assess whether these techniques are BAT. This may include the techniques listed above, and may involve other techniques. Detail of the suitability of the technique, the design duty, operating methods and maintenance should all form part of the assessment of BAT.

BAT 7

BAT 7. In order to reduce emissions of ammonia to air from the use of selective catalytic reduction (SCR) and/or selective non-catalytic reduction (SNCR) for the abatement of NOX emissions, BAT is to optimise the design and/or operation of SCR and/or SNCR (e.g. optimised reagent to NOX ratio, homogeneous reagent distribution and optimum size of the reagent drops).

BAT associated emission levels

The BAT associated emission level (BAT-AEL) for emissions of NH3 to air from the use of SCR and/or SNCR is <3–10 mg/Nm3 as a yearly average or average over the sampling period. The lower end of the range can be achieved when using SCR and the upper end of the range can be achieved when using SNCR without wet abatement techniques. In the case of plants combusting biomass and operating at variable loads as well as in the case of engines combusting HFO and/or gas oil, the higher end of the BAT-AEL range is 15 mg/Nm3.

GUIDANCE

53. The extension to the BAT-AEL range for ammonia emissions in BAT 7 above applies only to biomass plant that operate at variable loads (as well as engines combusting HFO and/or gas oil). In the case of biomass plants seeking this relaxation demonstration that the plant is or will be subject to variable loading will be required.

BAT 8

BAT 8. In order to prevent or reduce emissions to air during normal operating conditions, BAT is to ensure, by appropriate design, operation and maintenance, that the emission abatement systems are used at optimal capacity and availability.

GUIDANCE


BAT 9

BAT 9. In order to improve the general environmental performance of combustion and/or gasification plants and to reduce emissions to air, BAT is to include the following elements in the quality assurance/quality control programmes for all the fuels used, as part of the environmental management system (see BAT 1):

i. Initial full characterisation of the fuel used including at least the parameters listed below and in accordance with EN standards. ISO, national or other international standards may be used provided they ensure the provision of data of an equivalent scientific quality;

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ii. Regular testing of the fuel quality to check that it is consistent with the initial characterisation and according to the plant design specifications. The frequency of testing and the parameters chosen from the table below are based on the variability of the fuel and an assessment of the relevance of pollutant releases (e.g. concentration in fuel, flue-gas treatment employed);

iii. Subsequent adjustment of the plant settings as and when needed and practicable (e.g. integration of the fuel characterisation and control in the advanced control system (see description in Section 8.1)).

Description Initial characterisation and regular testing of the fuel can be performed by the operator and/or the fuel supplier. If performed by the supplier, the full results are provided to the operator in the form of a product (fuel) supplier specification and/or guarantee.

Fuel(s) Substances/Parameters subject to characterisation

Biomass/peat LHV

Moisture

Ash

C, Cl, F, N, S, K, Na

Metals and metalloids (As, Cd, Cr, Cu, Hg, Pb, Zn)

Coal/lignite LHV

Moisture

Volatiles, ash, fixed carbon, C, H, N, O, S

Br, Cl, F

Metals and metalloids (As, Cd, Co, Cr, Cu, Hg, Mn, Ni, Pb, Sb, Tl, V, Zn)

HFO Ash

C, S, N, Ni, V

Gas oil Ash

N, C, S

Natural gas LHV

CH4, C2H6, C3, C4+, CO2, N2, Wobbe index

Process fuels from the chemical industry (1)

Br, C, Cl, F, H, N, O, S

Metals and metalloids (As, Cd, Co, Cr, Cu, Hg, Mn, Ni, Pb, Sb, Tl, V, Zn)


LHV, CH4 (for COG), CXHY (for COG), CO2, H2, N2, total sulphur, dust, Wobbe index

Waste (2) LHV

Moisture

Volatiles, ash, Br, C, Cl, F, H, N, O, S

Metals and metalloids (Cd, Tl, Hg, Sb, As, Pb, Cr, Co, Cu, Mn, Ni, V, Zn)

(1) The list of substances/parameters characterised can be reduced to only those that can reasonably be expected to be present in the fuel(s) based on information on the raw materials and the production processes. (2) This characterisation is carried out without prejudice of application of the waste pre-acceptance and acceptance procedure set in BAT 70(a), which may lead to the characterisation and/or checking of other substances/parameters besides those listed here.

GUIDANCE

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55. Guidance on BAT 9 is available in the document17 agreed between Regulators and the Joint Environmental Programme

BAT 10

BAT 10. In order to reduce emissions to air and/or to water during other than normal operating conditions (OTNOC), BAT is to set up and implement a management plan as part of the environmental management system (see BAT 1), commensurate with the relevance of potential pollutant releases, that includes the following elements:

appropriate design of the systems considered relevant in causing OTNOC that may have an impact on emissions to air, water and/or soil (e.g. low-load design concepts for reducing the minimum start-up and shutdown loads for stable generation in gas turbines);

set-up and implementation of a specific preventive maintenance plan for these relevant systems;

review and recording of emissions caused by OTNOC and associated circumstances and implementation of corrective actions if necessary;

periodic assessment of the overall emissions during OTNOC (e.g. frequency of events, duration, emissions quantification/estimation) and implementation of corrective actions if necessary.

GUIDANCE

56. BAT specifically allows for the OTNOC plan to be incorporated into the EMS although each specific provision of BAT 10 must be addressed. It has been agreed that the list of examples of OTNOC in s3.1.16 of the BRef is appropriate (reproduced below) but that any known further site specific examples of OTNOC should be included in the EMS:

periods related to malfunction or breakdown of the abatement techniques;

testing periods (e.g. commissioning periods, periods after modifications to the combustion

chamber, testing periods of new/repaired abatement techniques or of the combustion of a new

fuel);

periods corresponding to the use of emergency fuels for a very short period due to the lack of

availability of normally used fuels (serious shortage or sudden interruption) or to disturbances in

fuel feeding;

periods of exceptional low-load operations due to unplanned malfunction of plant system(s);

periods related to sudden major combustion failures;

periods related to malfunction of the auxiliary or monitoring systems (e.g. malfunctioning of

the analysis instrument or data transfer related to the process control);

periods of calibration of monitoring systems requiring measurement points outside the range

corresponding to normal operating conditions;

extraordinary/unforeseeable variations in fuel quality whereby the installation/equipment

performance cannot be guaranteed by the manufacturer (outside design specifications) and/or

where there is a failure in the application of the fuel quality check procedures;

in the case of bypass of control equipment or a process, when the bypass is unavoidable,e.g. to

prevent loss of life or personal injury.

17 JEP19EMB01 & JEP19EMC01:CHARACTERISATION OF POWER PLANT FUELS FOR COMPLIANCE WITH LCP BREF CONCLUSION BAT 9

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BAT 11

BAT 11. BAT is to appropriately monitor emissions to air and/or to water during OTNOC.

Description: The monitoring can be carried out by direct measurement of emissions or by monitoring of surrogate parameters if this proves to be of equal or better scientific quality than the direct measurement of emissions. Emissions during start-up and shutdown (SU/SD) may be assessed based on a detailed emission measurement carried out for a typical SU/SD procedure at least once every year, and using the results of this measurement to estimate the emissions for each and every SU/SD throughout the year.

GUIDANCE

57. Guidance will be required here on the extent of monitoring during SUSD is considered relevant and also on during breakdown and other abnormal operating periods.

58. Where a plant does not monitor or has not monitored during specific OTNOC periods and in cases where no additional information on such periods has been provided no allowance for such operational periods will be provided for in the permit.

1.4 ENERGY EFFICIENCY

BAT 12

BAT 12. In order to increase the energy efficiency of combustion, gasification and/or IGCC units operated ≥1500 h/yr, BAT is to use an appropriate combination of the techniques given below.


a. Combustion optimisation See description in Section 8.2. Optimising the combustion minimises the content of unburnt substances in the flue-gases and in solid combustion residues


b. Optimisation of the working medium conditions

Operate at the highest possible pressure and temperature of the working medium gas or steam, within the constraints associated with, for example, the control of NOX emissions or the characteristics of energy demanded

c. Optimisation of the steam cycle

Operate with lower turbine exhaust pressure by utilisation of the lowest possible temperature of the condenser cooling water, within the design conditions

d. Minimisation of energy consumption

Minimising the internal energy consumption (e.g. greater efficiency of

Commented [BA1]: UK regulators will need to determine in which cases (plant type or plant duty) detailed emission measurement should be carried out for a typical SU/SD procedure at least once every year In addition definition of what a typical SUSD is needs be included

Commented [CR2R1]: This ought to be part of the compliance protocol

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the feed-water pump)

e. Preheating of combustion air

Reuse of part of the heat recovered from the combustion flue-gas to preheat the air used in combustion

Generally applicable within the constraints related to the need to control NOX emissions

f. Fuel preheating Preheating of fuel using recovered heat Generally applicable within the constraints associated with the boiler design and the need to control NOX emissions

g. Advanced control system See description in Section 8.2. Computerised control of the main combustion parameters enables the combustion efficiency to be improved

Generally applicable to new units. The applicability to old units may be constrained by the need to retrofit the combustion system and/or control command system

h. Feed-water preheating using recovered heat

Preheat water coming out of the steam condenser with recovered heat, before reusing it in the boiler

Only applicable to steam circuits and not to hot boilers. Applicability to existing units may be limited due to constraints associated with the plant configuration and the amount of recoverable heat

i. Heat recovery by cogeneration (CHP)

Recovery of heat (mainly from the steam system) for producing hot water/steam to be used in industrial processes/activities or in a public network for district heating. Additional heat recovery is possible from:

flue-gas

grate cooling

circulating fluidised bed

Applicable within the constraints associated with the local heat and power demand. The applicability may be limited in the case of gas compressors with an unpredictable operational heat profile

j. CHP readiness See description in Section 8.2. Only applicable to new units where there is a realistic potential for the future use of heat in the vicinity of the unit

k. Flue-gas condenser See description in Section 8.2. Generally applicable to CHP units provided there is enough demand for low-temperature heat

l. Heat accumulation Heat accumulation storage in CHP mode

Only applicable to CHP plants. The applicability may be limited in the case of low heat load demand

m. Wet stack See description in Section 8.2. Generally applicable to new and existing units fitted with wet FGD

n. Cooling tower discharge The release of emissions to air through a cooling tower and not via a dedicated stack

Only applicable to units fitted with wet FGD where reheating of the flue-gas is necessary before release, and where the unit cooling system is a cooling tower

o. Fuel pre-drying The reduction of fuel moisture content before combustion to improve combustion conditions

Applicable to the combustion of biomass and/or peat within the constraints associated with spontaneous combustion risks (e.g.

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the moisture content of peat is kept above 40% throughout the delivery chain). The retrofit of existing plants may be restricted by the extra calorific value that can be obtained from the drying operation and by the limited retrofit possibilities offered by some boiler designs or plant configurations

p. Minimisation of heat losses

Minimising residual heat losses, e.g. those that occur via the slag or those that can be reduced by insulating radiating sources

Only applicable to solid-fuel-fired combustion units and to gasification/IGCC units

q. Advanced materials Use of advanced materials proven to be capable of withstanding high operating temperatures and pressures and thus to achieve increased steam/combustion process efficiencies

Only applicable to new plants

r. Steam turbine upgrades This includes techniques such as increasing the temperature and pressure of medium-pressure steam, addition of a low-pressure turbine, and modifications to the geometry of the turbine rotor blades

The applicability may be restricted by demand, steam conditions and/or limited plant lifetime

s. Supercritical and ultra-supercritical steam conditions

Use of a steam circuit, including steam reheating systems, in which steam can reach pressures above 220.6 bar and temperatures above 374°C in the case of supercritical conditions, and above 250 – 300 bar and temperatures above 580 – 600°C in the case of ultra-supercritical conditions

Only applicable to new units of ≥ 600 MWth operated > 4000 h/yr. Not applicable when the purpose of the unit is to produce low steam temperatures and/or pressures in process industries. Not applicable to gas turbines and engines generating steam in CHP mode. For units combusting biomass, the applicability may be constrained by high-temperature corrosion in the case of certain biomasses

GUIDANCE


60. This BATc only applies to combustion, gasification and/or IGCC units if operated ≥1500 h/yr. See guidance point XX in the general considerations section above on plants operating < 1500 h/yr.

61. For England and Wales, the relationship between this guidance and other energy efficiency provisions (such as IED Article 9) is set out in section 4 of the DEFRA/Welsh Goverment Part A guidance [XX]. For Scotland…………..PPC Reg 17 repeats Article 9……. For Northern Ireland……………… Is this also set out in the cross cutting guidance…….?????? Additional information on the generic permitting approach for

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energy efficiency considerations is available on the relevant website for each UK Regulator[18].

62. The energy efficiency provisions of these BATCs apply in addition to the existing requirements of the Energy Efficiency Directive [19] for new plant and existing plant that have been substantially refurbished.

63. As general position (see cross cutting BRef guidance) BAT conclusions for associated environmental performance levels and associated energy efficiency levels (AEPLs and AEELs) have been interpreted to mean there is a clear expectation the AEPL/AEEL will be met. An appropriate BAT justification must be made for any deviation from the range. However, a formal derogation under Article 15(4) is not required where it is proven that alternative values can be regarded as BAT.

64. UK Regulators will only set permit conditions that reflect BAT-AEELs where there are site-specific reasons for doing so. Monitoring requirements for BAT-AEELs are addressed in section 1.2 above. UK Regulators expect an operator to make provisions with the manufacturer/supplier for equipment that fails to meet design targets once built and on commissioning to rectify the situation and ensure the equipment achieves the design specification.

65. UK Regulators will address means to minimise degradation of efficiency over time (as plant ages) as part of the periodic review of reported efficiency data. In cases where significant degradation is evident, UK Regulators will expect Operators to take action to monitor the situation and take steps to maximise (or at least maintain) efficiency within the range determined by site specific BAT.

66. In some cases it may be appropriate to consider wider system efficiency and load matching measures which can be applied across a wider fleet of inter-related plant. These type of issues should be specifically addressed when considering the BAT-AEELs for each fuel type discussed below.

1.5 WATER USAGE AND EMISSIONS TO WATER

BAT 13

BAT 13. In order to reduce water usage and the volume of contaminated waste water discharged, BAT is to use one or both of the techniques given below.


a. Water recycling Residual aqueous streams, including run-off water, from the plant are reused for other purposes. The degree of recycling is limited by the quality requirements of the recipient water stream and the water balance of the plant

Not applicable to waste water from cooling systems when water treatment chemicals and/or high concentrations of salts from seawater are present

18 https://www.gov.uk/guidance/energy-efficiency-standards-for-industrial-plants-to-get-

environmental-permits 19 EED Reference Article 14

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b. Dry bottom ash handling Dry, hot bottom ash falls from the furnace onto a mechanical conveyor system and is cooled down by ambient air. No water is used in the process.

Only applicable to plants combusting solid fuels. There may be technical restrictions that prevent retrofitting to existing combustion plants

GUIDANCE


BAT 14

BAT 14. In order to prevent the contamination of uncontaminated waste water and to reduce emissions to water, BAT is to segregate waste water streams and to treat them separately, depending on the pollutant content.

Description

Waste water streams that are typically segregated and treated include surface run-off water, cooling water, and waste water from flue-gas treatment.

Applicability

The applicability may be restricted in the case of existing plants due to the configuration of the drainage systems.

GUIDANCE


BAT 15

BAT 15. In order to reduce emissions to water from flue-gas treatment, BAT is to use an appropriate combination of the techniques given below, and to use secondary techniques as close as possible to the source in order to avoid dilution.

Technique Typical pollutants prevented/abated Applicability

Primary techniques

a. Optimised combustion (see BAT 6) and flue-gas treatment systems (e.g. SCR/SNCR, see BAT 7)

Organic compounds, ammonia (NH3) Generally applicable

Secondary techniques (1)

b. Adsorption on activated carbon

Organic compounds, mercury (Hg) Generally applicable

c. Aerobic biological treatment

Biodegradable organic compounds, ammonium (NH4+)

Generally applicable for the treatment of organic compounds.

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Technique Typical pollutants prevented/abated Applicability

Aerobic biological treatment of ammonium (NH4+) may not be applicable in the case of high chloride concentrations (i.e. around 10 g/l)

d. Anoxic/anaerobic biological treatment

Mercury (Hg), nitrate (NO3-), nitrite

(NO2-)


e. Coagulation and flocculation

Suspended solids Generally applicable

f. Crystallisation Metals and metalloids, sulphate (SO42),

fluoride (F-) Generally applicable

g. Filtration (e.g. sand filtration, microfiltration, ultrafiltration)

Suspended solids, metals Generally applicable

h. Flotation Suspended solids, free oil Generally applicable

i. Ion exchange Metals Generally applicable

j. Neutralisation Acids, alkalis Generally applicable

k. Oxidation Sulphide (S2-), sulphite (SO32-) Generally applicable

l. Precipitation Metals and metalloids, sulphate (SO42),

fluoride (F-) Generally applicable

m. Sedimentation Suspended solids Generally applicable

n. Stripping Ammonia (NH3) Generally applicable

(1) The descriptions of the techniques are given in Section 8.6

The BAT-AELs refer to direct discharges to a receiving water body at the point where the emission leaves the installation.

Table 1: BAT-AELs for direct discharges to a receiving water body from flue-gas treatment

Substance/Parameter BAT-AELs Daily average

Total organic carbon (TOC) 20–50 mg/l (1) (2) (3)

Chemical oxygen demand (COD) 60–150 mg/l (1) (2) (3)

Total suspended solids (TSS) 10–30 mg/l

Fluoride (F-) 10–25 mg/l (3)

Sulphate (SO42-) 1.3–2.0 g/l (3) (4) (5) (6)

Sulphide (S2-), easily released 0.1–0.2 mg/l (3)

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Substance/Parameter BAT-AELs Daily average

Sulphite (SO32-) 1–20 mg/l (3)

Metals and metalloids

As 10–50 μg/l

Cd 2–5 μg/l

Cr 10–50 μg/l

Cu 10–50 μg/l

Hg 0.2–3 μg/l

Ni 10–50 μg/l

Pb 10–20 μg/l

Zn 50–200 μg/l

(1) Either the BAT-AEL for TOC or the BAT-AEL for COD applies. TOC is the preferred option because its monitoring does not rely on the use of very toxic compounds. (2) This BAT-AEL applies after subtraction of the intake load. (3) This BAT-AEL only applies to waste water from the use of wet FGD. (4) This BAT-AEL only applies to combustion plants using calcium compounds in flue-gas treatment. (5) The higher end of the BAT-AEL range may not apply in the case of highly saline waste water (e.g. chloride concentrations ≥ 5 g/l) due to the increased solubility of calcium sulphate. (6) This BAT-AEL does not apply to discharges to the sea or to brackish water bodies.

GUIDANCE


70. Flue Gas Desulphurisation Waste Water Treatment for Limestone/Gypsum plant. Limestone-gypsum FGD WWTP should be monitored for BAT-AEL compliance at an appropriate WWTP discharge point either within the installation, or at the installation boundary or final mixed discharge location. The exact location should be justified on a site-specific basis, taking into account current performance compared to the BAT-AELs There should be no backsliding in standards/techniques will be permitted by the UK regulators from current ELVs without appropriate justification. Where monitoring for BAT-AEL compliance purposes takes place upstream of the final discharge point the monitoring value corresponding to BAT-AEL compliance may differ from the numeric value in the BRef and will need to be set reflecting the specific installation arrangements. ELVs more stringent than those derived from the BAT-AELs may be required to ensure compliance with an environmental quality standard in the receiving water body or to ensure target potential/status for Water Framework Directive compliance. Background concentration and intake loads should be considered if explicitly indicated in the BAT conclusions (i.e. TOC) or where the discharge returns the abstracted water to the same water body and the background concentration or intake load is significant in comparison to the effluent discharge. In these circumstances the BAT-AEL concentration should be regarded as relating to differential concentration.

71. Flue Gas Desulphurisation Waste Water Treatment for Seawater FGD plant. BAT-AEL implementation for SWP FGD will be determined on a site-specific basis taking into account the principles set out above for limestone-gypsum FGD plant.

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72. Footnote 5. This BAT-AEL applicability is one of the three instances in these LCP BATcs

where the qualification “may” is used in relation to modification of a BAT AEL range and

where further consideration is required. See guidance point XX above. The EC consider

that the term “may not apply” should not be read as providing an extension to the BAT-

AEL range. Such terms are regarded as merely complementary information for

Competent Authorities which could be considered when granting derogation under IED

Article 15(4). In this case UK regulators will consider any relaxation of the BAT-AEL

range for sulphate on a case by case basis.

73. Footnote 1. This decision should be made on a site specific basis in consultation with Regulator Water Quality experts

1.6 WASTE MANAGEMENT

BAT 16

BAT 16. In order to reduce the quantity of waste sent for disposal from the combustion and/or gasification process and abatement techniques, BAT is to organise operations so as to maximise, in order of priority and taking into account life-cycle thinking:

a. waste prevention, e.g. maximise the proportion of residues which arise as by-products;

b. waste preparation for reuse, e.g. according to the specific requested quality criteria;

c. waste recycling; d. other waste recovery (e.g. energy recovery),

by implementing an appropriate combination of techniques such as:


a. Generation of gypsum as a by-product

Quality optimisation of the calcium-based reaction residues generated by the wet FGD so that they can be used as a substitute for mined gypsum (e.g. as raw material in the plasterboard industry). The quality of limestone used in the wet FGD influences the purity of the gypsum produced

Generally applicable within the constraints associated with the required gypsum quality, the health requirements associated to each specific use, and by the market conditions

b. Recycling or recovery of residues in the construction sector

Recycling or recovery of residues (e.g. from semi-dry desulphurisation processes, fly ash, bottom ash) as a construction material (e.g. in road building, to replace sand in concrete production, or in the cement industry)

Generally applicable within the constraints associated with the required material quality (e.g. physical properties, content of harmful substances) associated to each specific use, and by the market conditions

c. Energy recovery by using waste in the fuel mix

The residual energy content of carbon-rich ash and sludges generated by the combustion of coal, lignite, heavy fuel oil, peat or

Generally applicable where plants can accept waste in the fuel mix and are technically able to feed the fuels into the combustion chamber

Commented [BA3]: UK Regulators to derive

Commented [CR4R3]: In the EA this will be a decision made by consultation with WQ and will be site specific

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biomass can be recovered for example by mixing with the fuel

d. Preparation of spent catalyst for reuse

Preparation of catalyst for reuse (e.g. up to four times for SCR catalysts) restores some or all of the original performance, extending the service life of the catalyst to several decades. Preparation of spent catalyst for reuse is integrated in a catalyst management scheme

The applicability may be limited by the mechanical condition of the catalyst and the required performance with respect to controlling NOX and NH3 emissions

GUIDANCE


1.7 NOISE EMISSIONS

BAT 17

BAT 17. In order to reduce noise emissions, BAT is to use one or a combination of the techniques given below.


a. Operational measures These include:

improved inspection and maintenance of equipment

closing of doors and windows of enclosed areas, if possible

equipment operated by experienced staff

avoidance of noisy activities at night, if possible

provisions for noise control during maintenance activities


b. Low-noise equipment This potentially includes compressors, pumps and disks

Generally applicable when the equipment is new or replaced

c. Noise attenuation Noise propagation can be reduced by inserting obstacles between the emitter and the receiver. Appropriate obstacles include protection walls, embankments and buildings

Generally applicable to new plants. In the case of existing plants, the insertion of obstacles may be restricted by lack of space

d. Noise-control equipment This includes:

noise-reducers

equipment insulation

enclosure of noisy equipment

soundproofing of buildings

The applicability may be restricted by lack of space

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e. Appropriate location of equipment and buildings

Noise levels can be reduced by increasing the distance between the emitter and the receiver and by using buildings as noise screens

Generally applicable to new plants. In the case of existing plants, the relocation of equipment and production units may be restricted by lack of space or by excessive costs

GUIDANCE


76. Further information on noise assessment and control can be found on NRW, NIEA, EA and SEPA webpages.

Commented [BA5]: Links to be added

https://www.gov.uk/government/publications/environmental-permitting-h3-part-2-noise-assessment-and-control

https://www.sepa.org.uk/media/156907/ppc_noise_guidance.pdf

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2 BAT CONCLUSIONS FOR THE COMBUSTION OF SOLID FUELS

2.1 BAT CONCLUSIONS FOR THE COMBUSTION OF COAL AND/OR LIGNITE

Unless otherwise stated, the BAT conclusions presented in this section are generally applicable to the combustion of coal and/or lignite. They apply in addition to the general BAT conclusions given in Section 1.

2.1.1 General environmental performance

BAT 18

BAT 18. In order to improve the general environmental performance of the combustion of coal and/or lignite, and in addition to BAT 6, BAT is to use the technique given below.


a. Integrated combustion process ensuring high boiler efficiency and including primary techniques for NOX reduction (e.g. air staging, fuel staging, low-NOX burners (LNB) and/or flue-gas recirculation)

Combustion processes such as pulverised combustion, fluidised bed combustion or moving grate firing allow this integration


GUIDANCE

77. No interpretational guidance has been provided at this time

2.1.2 ENERGY EFFICIENCY

BAT 19

BAT 19. In order to increase the energy efficiency of the combustion of coal and/or lignite, BAT is to use an appropriate combination of the techniques given in BAT 12 and below.


a. Dry bottom ash handling Dry hot bottom ash falls from the furnace onto a mechanical conveyor system and, after redirection to the furnace for reburning, is cooled down by ambient air. Useful energy is recovered from both the ash

There may be technical restrictions that prevent retrofitting to existing combustion units

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reburning and ash cooling

Table 2: BAT associated energy efficiency levels (BAT-AEELs) for coal and/or lignite combustion

Type of combustion unit BAT-AEELs (1) (2)

Net electrical efficiency (%) (3) Net total fuel utilisation (%) (3) (4) (5)

New unit (6) (7) Existing unit (6) (8) New or existing unit

Coal-fired, ≥1000 MWth 45 – 46 33.5 – 44 75 – 97

Lignite-fired, ≥1000 MWth 42 – 44 (9) 33.5 – 42.5 75 – 97

Coal-fired, <1000 MWth 36.5 – 41.5 (10) 32.5 – 41.5 75 – 97

Lignite-fired, <1000 MWth 36.5 – 40 (11) 31.5 – 39.5 75 – 97

(1) These BAT-AEELs do not apply in the case of units operated <1500 h/yr.

(2) In the case of CHP units, only one of the two BAT-AEELs 'Net electrical efficiency' or 'Net total fuel utilisation' applies, depending on the CHP unit design (i.e. either more oriented towards electricity generation or towards heat generation).

(3) The lower end of the range may correspondent to cases where the achieved energy efficiency is negatively affected (up to four percentage points) by the type of cooling system used or the geographical location of the unit.

(4) These levels may not be achievable if the potential heat demand is too low.

(5) These BAT-AEELs do not apply to plants generating only electricity.

(6) The lower ends of the BAT-AEEL ranges are achieved in the case of unfavourable climatic conditions, low-grade lignite-fired units, and/or old units (first commissioned before 1985).

(7) The higher end of the BAT-AEEL range can be achieved with high steam parameters (pressure, temperature).

(8) The achievable electrical efficiency improvement depends on the specific unit, but an increase of more than three percentage points is considered as reflecting the use of BAT for existing units, depending on the original design of the unit and on the retrofits already performed.

(9) In the case of units burning lignite with a lower heating value below 6 MJ/kg, the lower end of the BAT-AEEL range is 41.5%.

(10) The higher end of the BAT-AEEL range may be up to 46% in the case of units of ≥600 MWth using supercritical or ultra-supercritical steam conditions.

(11) The higher end of the BAT-AEEL range may be up to 44% in the case of units of ≥600 MWth using supercritical or ultra-supercritical steam conditions.

GUIDANCE

78. See guidance paragraph XX above for the general position for BAT conclusions for associated environmental performance levels and associated energy efficiency levels (AEPLs and AEELs).

2.1.3 NOX, N2O AND CO EMISSIONS TO AIR

BAT 20

BAT 20. In order to prevent or reduce NOX emissions to air while limiting CO and N2O emissions to air from the combustion of coal and/or lignite, BAT is to use one or a combination of the techniques given below.


a. Combustion optimisation See description in Section 8.3. Generally used in combination with


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other techniques

b. Combination of other primary techniques for NOX reduction (e.g. air staging, fuel staging, flue-gas recirculation, low-NOX burners (LNB))

See description in Section 8.3 for each single technique. The choice and performance of (an) appropriate (combination of) primary techniques may be influenced by the boiler design

c. Selective non-catalytic reduction (SNCR)

See description in Section 8.3. Can be applied with 'slip' SCR

The applicability may be limited in the case of boilers with a high cross-sectional area preventing homogeneous mixing of NH3 and NOX.

The applicability may be limited in the case of combustion plants operated <1500 h/yr with highly variable boiler loads

d. Selective catalytic reduction (SCR)

See description in Section 8.3 Not applicable to combustion plants of <300 MWth operated <500 h/yr. Not generally applicable to combustion plants of <100 MWth.

There may be technical and economic restrictions for retrofitting existing combustion plants operated between 500 h/yr and 1500 h/yr and for existing combustion plants of ≥300 MWth operated <500 h/yr

e. Combined techniques for NOX and SOX reduction

See description in Section 8.3 Applicable on a case-by-case basis, depending on the fuel characteristics and combustion process

Table 3: BAT associated emission levels (BAT-AELs) for NOX emissions to air from the combustion of coal and/or lignite


(MWth)

BAT-AELs (mg/Nm3)

Yearly average Daily average or average over the sampling period

New plant Existing plant (1) New plant Existing plant (2) (3)

<100 100–150 100–270 155–200 165–330

100–300 50–100 100–180 80–130 155–210

≥300, FBC boiler combusting coal and/or lignite and lignite-fired PC boiler

50 – 85 <85 – 150 (4)(5) 80 – 125 140 – 165 (6)

≥300, coal-fired PC boiler

65 – 85 65 – 150 80 – 125 < 85 – 165 (7)

(1) These BAT-AELs do not apply to plants operated <1500 h/yr.

(2) In the case of coal-fired PC boiler plants put into operation no later than 1 July 1987, which are operated <1500 h/yr and for which SCR and/or SNCR is not applicable, the higher end of the range is 340 mg/Nm 3.

(3) For plants operated <500 h/yr, these levels are indicative.

(4) The lower end of the range is considered achievable when using SCR.

(5) The higher end of the range is 175 mg/Nm3 for FBC boilers put into operation no later than 7 January 2014 and for lignite-fired PC boilers.

(6) The higher end of the range is 220 mg/Nm3 for FBC boilers put into operation no later than 7 January 2014 and for lignite-fired PC boilers.

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(7) In the case of plants put into operation no later than 7 January 2014, the higher end of the range is 200 mg/Nm3 for plants operated ≥1500 h/yr, and 220 mg/Nm3 for plants operated <1500 h/yr.

As an indication, the yearly average CO emission levels for existing combustion plants operated ≥1500 h/yr or for new combustion plants will generally be as follows:

Combustion plant total rated thermal input (MWth) CO indicative emission level (mg/Nm3)

<300 <30–140

≥300, FBC boiler combusting coal and/or lignite and lignite-fired PC boiler

<30–100 (1)

≥300, coal-fired PC boiler <5–100 (1)

(1) The higher end of the range may be up to 140 mg/Nm3 in the case of limitations due to boiler design, and/or in the case of fluidised bed boilers not fitted with secondary abatement techniques for NO X emissions reduction.

GUIDANCE

79. Notwithstanding the specific guidance points below, see guidance point XX in the general considerations section above on how to address BAT requirements for the application of one, or more, of the techniques specified above.

80. BAT 20 states that the applicability of SNCR to coal and biomass boilers may be limited in the case of boilers operating <1500hpa and with highly variable loads. An operator would need to provide justification regarding the operating hours and the variability of the load. This may need to be in conjunction with request for any IED Article 15(4) derogation should not installing SNCR affects the plant’s ability to meet emission limit values that do not exceed the BAT-AEL. Where secondary abatement is already installed, the concept of no reduction/diminution in standards/techniques will be permitted by the UK regulators would apply.

81. Selective Catalytic Reduction on coal and biomass plants. BAT 20 makes a statement regarding SCR on certain coal and biomass boilers including retrofitting to combustion plants >300MWth operated between 500 and 1500hpa. The UK regulators’ approach here is the same as paragraph XX above.

82. See guidance point XX in the general considerations section above on application of footnotes relating to < 1500 h/yr.


84. Footnote (1): The yearly average BAT-AELs for NOx do not apply to existing plants operated < 1500 h/yr. Daily/periodic BAT-AELs still apply, subject to footnote (2).

85. Footnote (2): The daily or periodic BAT-AELs for NOx are only indicative for existing plant operating <500 h/yr. For <500 h/yr plant a BAT demonstration that the plant is operating to BAT and emission limit values may still be set to reflect BAT and provide environmental protection where required.

86. In the case of coal-fired plant the UK Regulators consider that an indicative upper range for CO emissions from existing combustion plants operated ≥1500 h/yr or for new combustion plants will generally be 400 mg/Nm3 as an annual average. The basis for this value is detailed in Annex 1.

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87. Where the BAT-AEL for NOx applies the corresponding monitoring requirement is:


Standard Minimum monitoring frequency

All sizes Generic EN standards (1)

Continuous (3)

(1) Generic EN standards for continuous measurements are EN 15267-1, EN 15267-2, EN 15267-3, and EN 14181.

(3) In the case of plants with a rated thermal input of <100MW operated <1500 h/yr, the minimum monitoring frequency may be at least once every six months.

88. Where a permit ELV is set reflecting the indicative BAT-AELs for CO the corresponding monitoring requirement is:




Continuous (3)



89. BAT-AELs for ammonia for plant using SNCR or SCR are given in BAT 7 and guidance point XX above.

90. In the case of coal and solid biomass firing in circulating fluidised bed boilers the requirement for monitoring of N20 will be determined on a case by case basis (see BAT 4 above).

2.1.4 SOX, HCL AND HF EMISSIONS TO AIR

BAT 21

BAT 21. In order to prevent or reduce SOX, HCl and HF emissions to air from the combustion of coal and/or lignite, BAT is to use one or a combination of the techniques given below.


a. Boiler sorbent injection (in-furnace or in-bed)

See description in Section 8.4 Generally applicable

b. Duct sorbent injection (DSI)

See description in Section 8.4.

The technique can be used for HCl/HF removal when no specific FGD end-of-pipe technique is implemented

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c. Spray dry absorber (SDA) See description in Section 8.4.

d. Circulating fluidised bed (CFB) dry scrubber

e. Wet scrubbing See description in Section 8.4.

The techniques can be used for HCl/HF removal when no specific FGD end-of-pipe technique is implemented

f. Wet flue-gas desulphurisation (wet FGD)

See description in Section 8.4 Not applicable to combustion plants operated <500 h/yr.

There may be technical and economic restrictions for applying the technique to combustion plants of <300 MWth, and for retrofitting existing combustion plants operated between 500 h/yr and 1500 h/yr

g. Seawater FGD

h. Combined techniques for NOX and SOX reduction

Applicable on a case-by-case basis, depending on the fuel characteristics and combustion process

i. Replacement or removal of the gas-gas heater located downstream of the wet FGD

Replacement of the gas-gas heater downstream of the wet FGD by a multi-pipe heat extractor, or removal and discharge of the flue-gas via a cooling tower or a wet stack

Only applicable when the heat exchanger needs to be changed or replaced in combustion plants fitted with wet FGD and a downstream gas-gas heater

j. Fuel choice See description in Section 8.4.

Use of fuel with low sulphur (e.g. down to 0.1 wt-%, dry basis), chlorine or fluorine content

Applicable within the constraints associated with the availability of different types of fuel, which may be impacted by the energy policy of the Member State. The applicability may be limited due to design constraints in the case of combustion plants combusting highly specific indigenous fuels

Table 4: BAT associated emission levels (BAT-AELs) for SO2 emissions to air from the combustion of coal and/or lignite


(MWth)

BAT-AELs (mg/Nm3)

Yearly average Daily average Daily average or average over the sampling period

New plant Existing plant (1) New plant Existing plant (2) (3)

<100 150–200 150–360 170–220 170–400

100–300 80–150 95–200 135–200 135–220 (3)

≥300, PC boiler 10–75 10–130 (4) 25–110 25–165 (5)

≥300, Fluidised bed boiler (6)

20–75 20–180 25–110 50–220

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(3) In the case of plants put into operation no later than 7 January 2014, the upper end of the BAT-AEL range is 250 mg/Nm3.

(4) The lower end of the range can be achieved with the use of low-sulphur fuels in combination with the most advanced wet abatement system designs.

(5) The higher end of the BAT-AEL range is 220 mg/Nm3 in the case of plants put into operation no later than 7 January 2014 and operated <1500 h/yr. For other existing plants put into operation no later than 7 January 2014, the higher end of the BAT-AEL range is 205 mg/Nm3.

(6) For circulating fluidised bed boilers, the lower end of the range can be achieved by using high -efficiency wet FGD. The higher end of the range can be achieved by using boiler in-bed sorbent injection.

For a combustion plant with a total rated thermal input of more than 300 MW, which is specifically designed to fire indigenous lignite fuels and which can demonstrate that it cannot achieve the BAT-AELs mentioned in Table 4 for techno-economic reasons, the daily average BAT-AELs set out in Table 4 do not apply, and the upper end of the yearly average BAT-AEL range is as follows:

(i) for a new FGD system: RCG x 0.01 with a maximum of 200 mg/Nm3;

(ii) for an existing FGD system: RCG x 0.03 with a maximum of 320 mg/Nm3; in which RCG represents the concentration of SO2 in the raw flue-gas as a yearly average (under the standard conditions given under General considerations) at the inlet of the SOX abatement system, expressed at a reference oxygen content of 6 vol-% O2.

(iii) If boiler sorbent injection is applied as part of the FGD system, the RCG may be adjusted by taking into account the SO2 reduction efficiency of this technique (ηBSI), as follows: RCG (adjusted) = RCG (measured) / (1-ηBSI).

Table 5: BAT associated emission levels (BAT-AELs) for HCl and HF emissions to air from the combustion of coal and/or lignite

Pollutant Combustion plant total rated thermal input (MWth)

BAT-AELs (mg/Nm3)

Yearly average or average of samples obtained during one year

New plant Existing plant (1)

HCl <100 1–6 2–10 (2)

≥100 1–3 1–5 (2)(3)

HF <100 <1–3 <1–6 (4)

≥100 <1–2 <1–3 (4)

(1) The lower end of these BAT-AEL ranges may be difficult to achieve in the case of plants fitted with wet FGD and a downstream gas-gas heater.

(2) The higher end of the BAT-AEL range is 20 mg/Nm3 in the following cases: plants combusting fuels where the average chlorine content is 1000 mg/kg (dry) or higher; plants operated <1500 h/yr; FBC boilers. For plants operated <500 h/yr, these levels are indicative.

(3) In the case of plants fitted with wet FGD with a downstream gas-gas heater, the higher end of the BAT-AEL range is 7 mg/Nm3.

(4) The higher end of the BAT-AEL range is 7 mg/Nm3 in the following cases: plants fitted with wet FGD with a downstream gas-gas heater; plants operated <1500 h/yr; FBC boilers. For plants operated <500 h/yr, these levels are indicative.

GUIDANCE


OFFICAL


92. Where the BAT-AEL for SO2 applies the corresponding monitoring requirement is:



All sizes Generic EN standards(1)

Continuous (3) (8)

(1) Generic EN standards for continuous measurements are EN 15267-1, EN 15267-2, EN 15267-3, and EN 14181. (3) In the case of plants with a rated thermal input of <100MW operated <1500 h/yr, the minimum monitoring frequency may be at least once every six months. (8) As an alternative to the continuous measurement in the case of plants combusting oil with a known sulphur content and where there is no flue-gas desulphurisation system, periodic measurements at least once every three months and/or other procedures ensuring the provision of data of an equivalent scientific quality may be used to determine the SO2 emissions.

93. Other procedures for the provision of data of an equivalent scientific quality are

documented in guidance paragraph XX and in other Regulator guidance[20].

94. Where the BAT-AEL for HCl and/or HF applies the corresponding monitoring requirements are:

Substance Combustion plant total rated thermal input


Gaseous chlorides, expressed as HCl

All sizes EN 1911 Once every three months (3) (10)

HF All sizes No EN standard available

Once every three months (3) (10)

(3) In the case of plants with a rated thermal input of <100MW operated <1500 h/yr, the minimum monitoring frequency may be at least once every six months. (10) If the emission levels are proven to be sufficiently stable, periodic measurements may be carried out each time that a change of the fuel and/or waste characteristics may have an impact on the emissions, but in any case at least once every year. For co-incineration of waste with coal, lignite, solid biomass and/or peat, the monitoring frequency needs to also take into account Part 6 of Annex VI to the IED.

95. See guidance point XX in the general considerations section above on how to address “sufficiently stable”.

2.1.5 DUST AND PARTICULATE-BOUND METAL EMISSIONS TO AIR

BAT 22

BAT 22. In order to reduce dust and particulate-bound metal emissions to air from the combustion of coal and/or lignite, BAT is to use one or a combination of the techniques given below.


a. Electrostatic precipitator (ESP)


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b. Bag filter

c. Boiler sorbent injection (in-furnace or in-bed)

See descriptions in Section 8.5.

The techniques are mainly used for SOX, HCl and/or HF control

d. Dry or semi-dry FGD system

e. Wet flue-gas desulphurisation (wet FGD)

See applicability in BAT 21

Table 6: BAT associated emission levels (BAT-AELs) for dust emissions to air from the combustion of coal and/or lignite


(MWth)

BAT-AELs (mg/Nm3)



New plant Existing plant (2) (3)

<100 2–5 2–18 4–16 4–22 (3)

100–300 2–5 2–14 3–15 4–22 (4)

300–1000 2–5 2–10 (5) 3–10 3–11 (6)

≥1000 2–5 2–8 3–10 3–11 (7)

(1) These BAT AELs do not apply to plants operated < 1500 h/yr.

(2) For plants operated < 500 h/yr, these levels are indicative.

(3) The higher end of the BAT-AEL range is 28 mg/Nm3 for plants put into operation no later than 7 January 2014.





GUIDANCE


97. In the case of coal and solid biomass firing the requirement for monitoring of metal species will be determined on a case by case basis (see BAT 4 above).

98. Where the BAT-AEL for dust applies the corresponding monitoring requirement is:



OFFICAL


All sizes Generic EN standards(1) and EN 13284-1 and EN 13284-2

Continuous (3)

(1) Generic EN standards for continuous measurements are EN 15267-1, EN 15267-2, EN 15267-3, and EN 14181. (3) In the case of plants with a rated thermal input of <100MW operated <1500 h/yr, the minimum monitoring frequency may be at least once every six months.

2.1.6 MERCURY EMISSIONS TO AIR

BAT 23

BAT 23. In order to prevent or reduce mercury emissions to air from the combustion of coal and/or lignite, BAT is to use one or a combination of the techniques given below.


Co-benefit from techniques primarily used to reduce emissions of other pollutants


See description in Section 8.5

Higher mercury removal efficiency is achieved at flue-gas temperatures below 130°C.

The technique is mainly used for dust control


b. Bag filter See description in Section 8.5.

The technique is mainly used for dust control

c. Dry or semi-dry FGD system



d. Wet flue-gas desulphurisation (wet FGD)


e. Selective catalytic reduction (SCR)


Only used in combination with other techniques to enhance or reduce the mercury oxidation before capture in a subsequent FGD or dedusting system.

The technique is mainly used for NOX control


Specific techniques to reduce mercury emissions

f. Carbon sorbent (e.g. activated carbon or


Generally used in combination with an


OFFICAL


halogenated activated carbon) injection in the flue-gas

ESP/bag filter. The use of this technique may require additional treatment steps to further segregate the mercury-containing carbon fraction prior to further reuse of the fly ash

g. Use of halogenated additives in the fuel or injected in the furnace

See description in Section 8.5 Generally applicable in the case of a low halogen content in the fuel

h. Fuel pretreatment Fuel washing, blending and mixing in order to limit/reduce the mercury content or improve mercury capture by pollution control equipment

Applicability is subject to a previous survey for characterising the fuel and for estimating the potential effectiveness of the technique

i. Fuel choice See description in Section 8.5 Applicable within the constraints associated with the availability of different types of fuel, which may be impacted by the energy policy of the Member State

Table 7: BAT associated emission levels (BAT-AELs) for mercury emissions to air from the combustion of coal and lignite


(MWth)

BAT-AELs (μg/Nm3)



coal lignite coal lignite

<300 <1–3 <1–5 <1–9 <1–10

≥300 <1–2 <1–4 <1–4 <1–7

(1) The lower end of the BAT-AEL range can be achieved with specific mercury abatement techniques.

GUIDANCE


100. Where the BAT-AEL for mercury applies the corresponding monitoring requirement is:



< 300 MWth EN 13211 Once every three months (10) (17)

≥ 300 MWth Generic EN standards(1) and EN 14884


(1) Generic EN standards for continuous measurements are EN 15267-1, EN 15267-2, EN 15267-3, and EN 14181. (10) If the emission levels are proven to be sufficiently stable, periodic measurements may be carried out each time that a change of the fuel and/or waste characteristics may have an impact on the emissions, but in any case at least once every year. For co-incineration of waste with coal, lignite, solid biomass and/or peat, the monitoring frequency needs to also take into account Part 6 of Annex VI to the IED. (13) If the emission levels are proven to be sufficiently stable, periodic measurements may be carried out each time that a change of the fuel and/or waste characteristics may have an impact on the emissions, but in any case at least once every six months. (17) In the case of plants operated <1500 h/yr, the minimum monitoring frequency may be at least once every year.

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(18) Continuous sampling combined with frequent analysis of time-integrated samples, e.g. by a standardised sorbent trap monitoring method, may be used as an alternative to continuous measurements.

101. See guidance point XX in the general considerations section above on how to address

“sufficiently stable”.

2.2 BAT CONCLUSIONS FOR THE COMBUSTION OF SOLID BIOMASS AND/OR PEAT

Unless otherwise stated, the BAT conclusions presented in this section are generally applicable to the combustion of solid biomass and/or peat. They apply in addition to the general BAT conclusions given in Section 1.

GUIDANCE

102. Biomass is defined in Article 3(31) of Directive 2010/75/EU. The extent that the scope of these BATcs apply to plant co-incinerating biomass is discussed under the scope section above.


Table 8: BAT associated energy efficiency levels (BAT-AEELs) for the combustion of solid biomass and/or peat


Net electrical efficiency (%) (3) Net total fuel utilisation (%) (4) (5)

New unit (6) Existing unit New unit Existing unit

Solid biomass and/or peat boiler

33.5 to >38 28–38 73–99 73–99



(3) The lower end of the range may correspond to cases where the achieved energy efficiency is negative ly affected (up to four percentage points) by the type of cooling system used or the geographical location of the unit.



(6) The lower end of the range may be down to 32% in the case of units of <150 MWth burning high-moisture biomass fuels.

GUIDANCE

103. Table 8 Footnote (2): In the case of CHP plants the orientation of the plant towards either electricity or heat generation will need to be determined. This will then identify which of the two BAT-AEELs will be applied. In most cases the orientation will be self-evident although this is necessarily a case by case assessment. When a plant can alternate between modes (electricity or heat generation) then the UK regulators will assess the plant performance against the criteria of each mode noting that, in some cases, electricity only generation may only be achievable for limited periods of time. In this case, electricity only generation will be therefore be limited in the permit to the short periods assessed.

OFFICAL


104. Table 8 Footnote (6): We define “high-moisture” as typically >30%.

105. Table 8 Footnote (3): It is important to note that in cases where the relaxation (of up to four percentage points) to the lower end of the BAT-AEEL ranges for existing plants is only relevant in the consideration of BAT for any deviations from the stated BAT-AEELs. This is not subject to the additional information provided by the EC on the extension/relaxation of BAT-AEL ranges as discussed in guidance point XX.


2.2.2 NOX, N2O AND CO EMISSIONS TO AIR

BAT 24

BAT 24. In order to prevent or reduce NOX emissions to air while limiting CO and N2O emissions to air from the combustion of solid biomass and/or peat, BAT is to use one or a combination of the techniques given below.


a. Combustion optimisation See descriptions in Section 8.3 Generally applicable

b. Low-NOX burners (LNB)

c. Air staging

d. Fuel staging

e. Flue-gas recirculation

f. Selective non-catalytic reduction (SNCR)


Can be applied with 'slip' SCR

Not applicable to combustion plants operated < 500 h/yr with highly variable boiler loads.

The applicability may be limited in the case of combustion plants operated between 500 h/yr and 1500 h/yr with highly variable boiler loads.

For existing combustion plants, applicable within the constraints associated with the required temperature window and residence time for the injected reactants

g. Selective catalytic reduction (SCR)


The use of high-alkali fuels (e.g. straw) may require the SCR to be installed downstream of the dust abatement system

Not applicable to combustion plants operated < 500 h/yr.

There may be economic restrictions for retrofitting existing combustion plants of < 300 MWth.

Not generally applicable to existing

OFFICAL


combustion plants of < 100 MWth

Table 9: BAT associated emission levels (BAT-AELs) for NOX emissions to air from the combustion of solid biomass and/or peat


(MWth)

BAT-AELs (mg/Nm3)


New plant Existing plant (1) New plant Existing plant (2)

50–100 70–150 (3) 70–225 (4) 120–200 (5) 120–275 (6)

100–300 50–140 50–180 100–200 100–220

≥300 40–140 40–150 (7) 65–150 95–165 (8)

(1) These BAT-AELs do not apply to plants operated < 1500 h/yr.

(2) For combustion plants operated < 500 h/yr, these levels are indicative.

(3) For plants burning fuels where the average potassium content is 2000 mg/kg (dry) or higher, and/or the average sodium content is 300 mg/kg or higher, the higher end of the BAT-AEL range is 200 mg/Nm3.



(6) For plants put into operation no later than 7 January 2014 and burning fuels where the average potassium content is 2000 mg/kg (dry) or higher, and/or the average sodium content is 300 mg/kg or higher, the higher end of the BAT-AEL range is 310 mg/Nm3.



As an indication, the yearly average CO emission levels will generally be:

<30–250 mg/Nm3 for existing combustion plants of 50–100 MWth operated ≥1500 h/yr,

or new combustion plants of 50–100 MWth;

<30–160 mg/Nm3 for existing combustion plants of 100–300 MWth operated ≥1500

h/yr, or new combustion plants of 100–300 MWth;

<30–80 mg/Nm3 for existing combustion plants of ≥300 MWth operated ≥1500 h/yr, or

new combustion plants of ≥ 300 MWth.

GUIDANCE




110. Footnote (1): The yearly average BAT-AELs for NOx do not apply to existing plants operated < 1500 h/yr. Daily/periodic BAT-AELs for NOx still apply, subject to footnote (2).

111. Footnote (2): The daily or periodic BAT-AELs for NOx are only indicative for existing plant operating <500 h/yr. Where this footnote is applied, a BAT demonstration that the

OFFICAL


plant is operating to BAT may still be required and emission limit values may still be set to reflect BAT and provide environmental protection as site specific BAT.





Continuous (3)



113. For plant using SNCR or SCR BAT-AELs for ammonia given in BAT 7 apply, see guidance point XX above.

114. Where the BAT-AEL for ammonia applies the corresponding monitoring requirement is:




Continuous (3) (4)



(4) In the case of the use of SCR, the minimum monitoring frequency may be at least once every year, if the emission levels are proven to be sufficiently stable.


116. Where a permit ELV is set reflecting the indicative BAT-AEL for CO the corresponding monitoring requirement is:




Continuous (3)



117. In the case of coal and solid biomass firing in circulating fluidised bed boilers the requirement for monitoring of N20 will be determined on a case by case basis (see BAT 4 above).


OFFICAL


BAT 25

BAT 25. In order to prevent or reduce SOX, HCl and HF emissions to air from the combustion of solid biomass and/or peat, BAT is to use one or a combination of the techniques given below.


a. Boiler sorbent injection (in-furnace or in-bed)

See descriptions in Section 8.4 Generally applicable

b. Duct sorbent injection (DSI)

c. Spray dry absorber (SDA)

d. Circulating fluidised bed (CFB) dry scrubber

e. Wet scrubbing

f. Flue-gas condenser

g. Wet flue-gas desulphurisation (wet FGD)


There may be technical and economic restrictions for retrofitting existing combustion plants operated between 500 h/yr and 1500 h/yr

h. Fuel choice Applicable within the constraints associated with the availability of different types of fuel, which may be impacted by the energy policy of the Member State

Table 10: BAT associated emission levels (BAT-AELs) for SO2 emissions to air from the combustion of solid biomass and/or peat


(MWth)

BAT-AELs for SO2 (mg/Nm3)



<100 15–70 15–100 30–175 30–215

100–300 <10–50 <10–70 (3) <20–85 <20–175 (4)

≥300 <10–35 <10–50 (3) <20–70 <20–85 (5)



(3) For existing plants burning fuels where the average sulphur content is 0.1 wt -% (dry) or higher, the higher end of the BAT-AEL range is 100 mg/Nm3.

(4) For existing plants burning fuels where the average sulphur content is 0.1 wt-% (dry) or higher, the higher end

OFFICAL


of the BAT-AEL range is 215 mg/Nm3.

(5) For existing plants burning fuels where the average sulphur content is 0.1 wt -% (dry) or higher, the higher end of the BAT-AEL range is 165 mg/Nm3, or 215 mg/Nm3 if those plants have been put into operation no later than 7 January 2014 and/or are FBC boilers combusting peat.

Table 11: BAT associated emission levels (BAT-AELs) for HCl and HF emissions to air from the combustion of solid biomass and/or peat


(MWth)

BAT-AELs for HCl (mg/Nm3) (1) (2) BAT-AELs for HF (mg/Nm3)


Daily average or average over the sampling period

Average over the sampling period

New plant Existing plant (3) (4)



<100 1–7 1–15 1–12 1–35 < 1 < 1.5

100–300 1–5 1–9 1–12 1–12 < 1 < 1

≥300 1–5 1–5 1–12 1–12 < 1 < 1

(1) For plants burning fuels where the average chlorine content is ≥ 0.1 wt -% (dry), or for existing plants co-combusting biomass with sulphur-rich fuel (e.g. peat) or using alkali chloride-converting additives (e.g. elemental sulphur), the higher end of the BAT-AEL range for the yearly average for new plants is 15 mg/Nm3, the higher end of the BAT-AEL range for the yearly average for existing plants is 25 mg/Nm3. The daily average BAT-AEL range does not apply to these plants.

(2) The daily average BAT-AEL range does not apply to plants operated <1500 h/yr. The higher end of the BAT-AEL range for the yearly average for new plants operated < 1500 h/yr is 15 mg/Nm 3.


(4) The lower end of these BAT-AEL ranges may be difficult to achieve in the case of plants fitted with wet FGD and a downstream gas-gas heater.


GUIDANCE



120. See guidance point XX in the general considerations section above on application of footnotes relating to <500 h/yr.

121. Table 10 Footnote (1): The yearly average BAT-AELs for SO2 do not apply to existing plants operated <1500 h/yr. Daily/periodic BAT-AELs for SO2 still apply, subject to footnote (2).

122. Table 10 Footnote (2): The daily or periodic BAT-AELs for SO2 are only indicative for existing plant operating <500 h/yr. Where this footnote is applied, a BAT demonstration that the plant is operating to BAT may still be required and emission limit values may still be set to reflect BAT and provide environmental protection as site specific BAT.

123. Where this BAT-AEL for SO2 applies, the corresponding monitoring requirement is:



OFFICAL



Continuous (3)



124. Table 11 Footnote (1): For the fuels specified in this footnote the higher end of the yearly average BAT-AEL range for HCl is extended to 15 mg/Nm3 for new plant and 25 mg/Nm3 for existing plant and the daily average BAT-AEL for HCl does not apply.

125. Table 11 Footnote (5): The periodic BAT-AELs for HF are only indicative for existing plant operating <500 h/yr. Where this footnote is applied, a BAT demonstration that the plant is operating to BAT may still be required and emission limit values may still be set to reflect BAT and provide environmental protection as site specific BAT.

126. Where this BAT-AEL for HCl applies, the corresponding monitoring requirement is:






(12) In the case of plants with a rated thermal input of <100MW operated between 500 h/yr, the minimum monitoring frequency may be at least once every year. In the case of plants with a rated thermal input of <100 MW operated between 500 h/yr and 1500 h/yr, the monitoring frequency may be reduced to at least once every six months.

(13) If the emission levels are proven to be sufficiently stable, periodic measurements may be carried out each time that a change of the fuel and/or waste characteristics may have an impact on the emissions, but in any case at least once every six months.


128. Where this BAT-AEL for HF applies, the corresponding monitoring requirement is given below noting that for plant co-incinerating waste the minimum requirements for HF monitoring specified in IED Annex VI will apply.




Once every year


BAT 26

BAT 26. In order to reduce dust and particulate-bound metal emissions to air from the combustion of solid biomass and/or peat, BAT is to use one or a combination of the techniques given below.

OFFICAL





b. Bag filter

c. Dry or semi-dry FGD system

See descriptions in Section 8.5




e. Fuel choice See description in Section 8.5 Applicable within the constraints associated with the availability of different types of fuel, which may be impacted by the energy policy of the Member State

Table 12: BAT associated emission levels (BAT-AELs) for dust emissions to air from the combustion of solid biomass and/or peat


(MWth)

BAT-AELs for dust (mg/Nm3)



<100 2–5 2–15 2–10 2–22

100–300 2–5 2–12 2–10 2–18

≥300 2–5 2–10 2–10 2–16



GUIDANCE


BAT requirements for the application of one, or more, of the techniques specified above.

Bag filters are only generally used on biomass plants covered by Chapter IV of the IED

due to the different abatement systems used on such plant (e.g. injection of lime and

activated carbon that are used to reduce acid gas and heavy metal emissions.). Bag

filters are not necessarily BAT for dust abatement for plants that are not covered by

Chapter IV of the IED and/or that do not use relevant additional abatement systems.


131. See guidance point XX in the general considerations section above on application of

footnotes relating to <500 h/yr.

OFFICAL


132. Footnote (1): The yearly average BAT-AELs for Dust do not apply to existing plants operated <1500 h/yr. Daily/periodic BAT-AELs for Dust still apply, subject to footnote (2).

133. Footnote (2): The daily or periodic BAT-AELs for Dust are only indicative for existing

plant operating <500 h/yr. Where this footnote is applied, a BAT demonstration that the plant is operating to BAT may still be required and emission limit values may still be set to reflect BAT and provide environmental protection as site specific BAT.

134. Where the BAT-AEL for dust applies, the corresponding monitoring requirement is:




Continuous (3)



135. In the case of coal and solid biomass firing the requirement for monitoring of metal species will be determined on a case by case basis (see BAT 4 above).


BAT 27

BAT 27. In order to prevent or reduce mercury emissions to air from the combustion of solid biomass and/or peat, BAT is to use one or a combination of the techniques given below.


Specific techniques to reduce mercury emissions

a Carbon sorbent (e.g. activated carbon or halogenated activated carbon) injection in the flue- gas

See descriptions in section 8.5 Generally applicable

b Use of halogenated additives in the fuel or injected in the furnace

Generally applicable in the case of a low halogen content in the fuel

c Fuel choice Applicable within the constraints associated with the availability of different types of fuel, which may be impacted by the energy policy of the Member State

OFFICAL


Co-benefit from techniques primarily used to reduce emissions of other pollutants

d. Electrostatic precipitator (ESP)


The techniques are mainly used for dust control


e. Bag filter

f. Dry or semi-dry FGD system



g. Wet flue-gas desulphurisation (wet FGD)


The BAT associated emission level (BAT-AEL) for mercury emissions to air from the combustion of solid biomass and/or peat is <1–5 μg/Nm3

as average over the sampling period.

GUIDANCE


137. Where this BAT-AEL for Hg applies, the corresponding monitoring requirement is:




(19) If the emission levels are proven to be sufficiently stable due to the low mercury content in the fuel, periodic measurements may be carried out only each time that a change of the fuel characteristics may have an impact on the emissions.


OFFICAL


3 BAT CONCLUSIONS FOR THE COMBUSTION OF LIQUID FUELS

The BAT conclusions presented in this section do not apply to combustion plants on offshore platforms; these are covered by Section 4.3

3.1 HFO- AND/OR GAS-OIL-FIRED BOILERS

Unless otherwise stated, the BAT conclusions presented in this section are generally applicable to the combustion of HFO and/or gas oil in boilers. They apply in addition to the general BAT conclusions given in Section 1.

GUIDANCE

139. Heavy Fuel Oil (HFO) and Gas oil are defined in the BATC.

140. These BATCs only apply to Boilers which are defined as “any combustion plant with the exception of engines, gas turbines, and process furnaces or heaters” and. do not apply to combustion plants on offshore platforms.


Table 13: BAT associated energy efficiency levels (BAT-AEELs) for HFO and/or gas oil combustion in boilers


Net electrical efficiency (%) Net total fuel utilisation (%) (3)

New unit Existing unit New unit Existing unit

HFO- and/or gas-oil-fired boiler

>36.4 35.6–37.4 80–96 80–96

(1) These BAT-AEELs do not apply to units operated <1500 h/yr.



GUIDANCE


142. Table 13 Footnote (1): Both BAT-AEELs only apply to units operated ≥1500 h/yr. See guidance point XX in the general considerations section above on application of footnotes relating to < 1500 h/yr.

143. Although Footnote (1) specifies that the BAT-AEELs do not apply to plants operating <1500 h/yr and the net total fuel utilisation may not apply where the potential heat demand is too low, the operator will need to demonstrate that the plant is operating to BAT and emission limit values may still be set to reflect BAT.

OFFICAL


144. Table 13 Footnote (2): In the case of CHP plants the orientation of the plant towards either electricity or heat generation will need to be determined. This will then identify which of the two BAT-AEELs will be applied. See guidance in section 2.2.1 (guidance poont XX). As indicated by the footnote, the 'Net electrical efficiency' or 'Net total fuel utilisation' will be applied dependant on the CHP unit design.

145. The operator will need to justify that the potential heat demand is too low to achieve the net total fuel utilisation under the terms of footnote (3). See guidance point XX above on low heat utilisation.

3.1.2 NOX AND CO EMISSIONS TO AIR

BAT 28

BAT 28. In order to prevent or reduce NOX emissions to air while limiting CO emissions to air from the combustion of HFO and/or gas oil in boilers, BAT is to use one or a combination of the techniques given below.


a. Air staging See descriptions in Section 8.3


b. Fuel staging

c. Flue-gas recirculation

d. Low-NOX burners (LNB)

e. Water/steam addition Applicable within the constraints of water availability

f. Selective non-catalytic reduction (SNCR)

Not applicable to combustion plants operated < 500 h/yr with highly variable boiler loads.

The applicability may be limited in the case of combustion plants operated between 500 h/yr and 1500 h/yr with highly variable boiler loads


Not applicable to combustion plants operated <500 h/yr.

There may be technical and economic restrictions for retrofitting existing combustion plants operated between 500 h/yr and 1500 h/yr.

Not generally applicable to combustion plants of <100 MWth

h. Advanced control system Generally applicable to new combustion plants. The applicability to old combustion plants may be constrained by the need to retrofit the combustion system and/or control command system

i. Fuel choice Applicable within the constraints associated with the availability of different types of fuel, which may be

OFFICAL


impacted by the energy policy of the Member State

GUIDANCE

146. The objective is to minimise NOx emissions, further guidance is given in guidance point XX.


148. The relaxation of the applicability of Selective non-catalytic reduction (SNCR) requirements for <500 h/yr plant is limited to plant with highly variable boiler loads. Therefore, justification for this relaxation would be expected on the variability of plant load. This may need to be in conjunction with any IED Article 15(4) derogation should this affect the plants ability to meet emission limit values that do not exceed the BAT-AEL. This limitation may also apply for 500 – 1,500 h/yr plant, so the similar approach to the above would be expected.

149. Selective catalytic reduction (SCR). It should be noted that there are no rated thermal input limitations for this technique although in the UK it is considered that this technique is not readily applicable for plant <100MWth. The technical and economic restrictions for retrofitting existing combustion plant operated between 500 h/yr and 1500 h/yr will require a BAT justification. This may need to be in conjunction with any IED Article 15(4) derogation should this affect the plants ability to meet emission limit values that do not exceed the BAT-AEL.

BAT 28 (cont.d)

Table 14: BAT associated emission levels (BAT-AELs) for NOX emissions to air from the combustion of HFO and/or gas oil in boilers


(MWth)

BAT-AELs (mg/Nm3)



<100 75–200 150–270 100–215 210–330 (3)

≥100 45–75 45–100 (4) 85–100 85–110 (5) (6)



(3) For industrial boilers and district heating plants put into operation no later than 27 November 2003, which are operated < 1500 h/yr and for which SCR and/or SNCR is not applicable, the higher end of the BAT-AEL range is 450 mg/Nm3.

(4) The higher end of the BAT-AEL range is 110 mg/Nm3 for plants of 100–300 MWth and plants of ≥ 300 MWth that were put into operation no later than 7 January 2014.

(5) The higher end of the BAT-AEL range is 145 mg/Nm3 for plants of 100–300 MWth and plants of ≥ 300 MWth that were put into operation no later than 7 January 2014.

(6) For industrial boilers and district heating plants of > 100 MWth put into operation no later than 27 November 2003, which are operated < 1500 h/yr and for which SCR and/or SNCR is not applicable, the higher end of the BAT-AEL range is 365 mg/Nm3.


OFFICAL


10-30 mg/Nm3 for existing combustion plants of <100 MWth operated ≥1 500 h/yr, or new combustion plants of <100 MWth;

10–20mg/Nm3 for existing combustion plants of ≥100 MWth operated ≥1 500 h/yr, or new combustion plants of ≥100MWth.

GUIDANCE

150. See guidance point 29 in the general considerations section above on how to address BAT requirements for the application of one, or more, of the techniques specified above.

151. See guidance point XX in the general considerations section above and in paragraph XX relating to BAT 28 techniques above on application of footnotes relating to < 500 h/yr. Where plant were put into operation no later than 27 November 2003, the higher end of the relevant BAT-AEL is 450mg/Nm3 (daily average) for plant <100MWth (footnote 3), or 365mg/Nm3 (daily average) for plant >100MWth operating between 500 and < 1500 h/yr. (footnote 6). [Note, the footnote states >100MWth, although this has been interpreted to mean greater than or equal to given the parameter this refers to in Table 14].

152. Footnote (1): The yearly average BAT-AELs for NOx do not apply to existing plants operated <1500 h/yr. Daily/periodic BAT-AELs for NOx still apply, subject to footnote (2).

153. Footnote (2): The daily or periodic BAT-AELs for NOx are indicative only for existing plant operating <500 h/yr. Where this footnote is applied, a BAT demonstration that the plant is operating to BAT may still be required and emission limit values may still be set to reflect BAT and provide environmental protection as site specific BAT.

154. Carbon monoxide BAT-AELs are set out as indicative. See guidance point XX above on indicative BAT AELs.





Continuous (3)


(3) In the case of plants with a rated thermal input of <100MW operated <1500 h/yr, the minimum monitor ing frequency may be at least once every six months.

156. For plant using SNCR or SCR the BAT-AELs for ammonia given in BAT 7 apply, see guidance point XX above.





Continuous (3) (4)


(3) In the case PF plants with a rated thermal input of <100MW operated <1500 h/yr, the minimum monitoring frequency may be at least once every six months.


OFFICAL



159. Where a permit ELV is set based on the BAT-AEL for CO, the corresponding monitoring requirement is:




Continuous (3) (5)




BAT 29

BAT 29. In order to prevent or reduce SOX, HCl and HF emissions to air from the combustion of HFO and/or gas oil in boilers, BAT is to use one or a combination of the techniques given below.


a. Duct sorbent injection (DSI)

See description in Section 8.4


b. Spray dry absorber (SDA)

c. Flue-gas condenser


There may be technical and economic restrictions for applying the technique to combustion plants of <300 MWth.



e. Seawater FGD There may be technical and economic restrictions for applying the technique to combustion plants of <300 MWth.



f. Fuel choice Applicable within the constraints associated with the availability of different types of fuel, which may be impacted by the energy policy of the Member State

OFFICAL


GUIDANCE


161. See also guidance point XX above on FGD processes. A justification for any technical and economic restrictions for not applying Wet flue-gas desulphurisation (wet FGD) or Seawater FGD to plant <300MWth or plant operated between 500 h/yr and 1500 h/yr is required.

BAT 29 (cont.d)

Table 15: BAT associated emission levels (BAT-AELs) for SO2 emissions to air from the combustion of HFO and/or gas oil in boilers


(MWth)




<300 50–175 50–175 150–200 150–200 (3)

≥300 35–50 50–110 50–120 150–165 (4) (5)



(3) For industrial boilers and district heating plants put into operation no later than 27 November 2003 and operated <1500 h/yr, the higher end of the BAT-AEL range is 400 mg/Nm3.


(5) For industrial boilers and district heating plants put into operation no later than 27 November 2003, which are operated <1500 h/yr and for which wet FGD is not applicable, the higher end of the BAT-AEL range is 200 mg/Nm3.

GUIDANCE



164. Footnote (1): The annual BAT-AEL do not apply to existing plants operated <1500 h/yr. Daily/periodic BAT-AELs still apply, but these are considered indicative for plant operating <500 hours/year (as specified by footnote (2)). Where this footnote is applied, a BAT demonstration that the plant is operating to BAT may still be required and emission limit values may still be set to reflect BAT and provide environmental protection as site specific BAT.

165. Where industrial boilers and district heating plants plant were put into operation no later than 27 November 2003, the higher end of the relevant BAT-AEL is 400mg/Nm3 (daily average) for plant <100MWth (footnote 3) or 200mg/Nm3 for plant ≥300MWth for which wet FGD is not applicable (footnote 5).

166. In order to apply any of the extended ranges to the BAT-AEL ranges for industrial boilers and district heating plants in footnote (5), a robust justification for why wet FGD is not applicable must be documented. In this context “industrial boilers” is not taken to include large utility boilers operating in the Electricity Supply Industry.

OFFICAL






Continuous (3) (8)



(8) As an alternative to the continuous measurement in the case of plants combusting oil with a known sulphur content and where there is no flue-gas desulphurisation system, periodic measurements at least once every three months and/or other procedures ensuring the provision of data of an equivalent scientific quality may be used to determine SO2 emissions.




BAT 30

BAT 30. In order to reduce dust and particulate-bound metal emissions to air from the combustion of HFO and/or gas oil in boilers, BAT is to use one or a combination of the techniques given below.




b. Bag filter

c. Multicyclones See description in Section 8.5.

Multicyclones can be used in combination with other dedusting techniques

d. Dry or semi-dry FGD system


The technique is mainly used for SOX, HCl and/or HF control





f. Fuel choice See description in Section 8.5 Applicable within the constraints associated with the availability of

20 MCPD plant monitoring guidance. Insert final link.

OFFICAL


different types of fuel, which may be impacted by the energy policy of the Member State

GUIDANCE


BAT 30 (cont.d)

Table 16: BAT associated emission levels (BAT-AELs) for dust emissions to air from the combustion of HFO and/or gas oil in boilers


(MWth)




<300 2–10 2–20 7–18 7–22 (3)

≥300 2–5 2–10 7–10 7–11 (4)





GUIDANCE



172. Footnote (1): The annual BAT-AELs do not apply to existing plants operated < 1500 h/yr. Daily/periodic BAT-AELs still apply, subject to footnote (2).

173. Footnote (2): The daily or periodic BAT-AELs are only indicative for existing plant operating <500 h/yr. Where this footnote is applied, a BAT demonstration that the plant is operating to BAT may still be required and emission limit values may still be set to reflect BAT and provide environmental protection as site specific BAT.

174. The approach to monitoring for gas fired boiler plant using liquid fuels as a standby provision only is given in guidance paragraph ?? above.

175. Where this BAT-AEL for dust applies, the corresponding monitoring requirement is:




Continuous (3)

OFFICAL




176. In the case of HFO and/or gas oil firing the requirement for monitoring of metal species will be determined on a case by case basis (see BAT 4 above).

3.2 HFO- AND/OR GAS-OIL-FIRED ENGINES

Unless otherwise stated, the BAT conclusions presented in this section are generally applicable to the combustion of HFO and/or gas oil in reciprocating engines. They apply in addition to the general BAT conclusions given in Section 1.

As regards HFO- and/or gas-oil-fired engines, secondary abatement techniques for NOX, SO2 and dust may not be applicable to engines in islands that are part of a small isolated system (1) or a micro isolated system (2), due to technical, economic and logistical/infrastructure constraints, pending their interconnection to the mainland electricity grid or access to a natural gas supply. The BAT-AELs for such engines shall therefore only apply in small isolated system and micro isolated system as from 1 January 2025 for new engines, and as from 1 January 2030 for existing engines.

GUIDANCE

177. Heavy Fuel Oil (HFO) and Gas oil is defined in these BATC.

178. Note that the specific BATcs in section 3.2 apply to engines only. However, the SIS derogation is applicable to all types of plant. The EC has provided specific guidance[2] on some compliance options for plant at the end of the SIS derogation which have been addressed in this guidance. Operators of those combustion plants being subject to IED Article 34 ('small isolated systems') do not have to comply with these BATcs until the end date of the derogation. However this only applies for those certain air pollutants[2] that are subject to the SIS derogation. Therefore all other provisions of these BATcs do apply (for instance on energy efficiency and monitoring requirements). The provisions relating to LLD plant to operation after the derogation end date apply equally to SIS plant noting that from 1 January 2020, SIS plant must meet Emission Limit Values (ELVs) in Annex V, part 1 as a minimum.


BAT 31

BAT 31. In order to increase the energy efficiency of HFO and/or gas oil combustion in reciprocating engines, BAT is to use an appropriate combination of the techniques given in BAT 12 and below.


OFFICAL


a. Combined cycle See description in Section 8.2 Generally applicable to new units operated ≥ 1500 h/yr.

Applicable to existing units within the constraints associated with the steam cycle design and the space availability.

Not applicable to existing units operated < 1500 h/yr

GUIDANCE


BAT 31 (cont.d)

Table 17: BAT associated energy efficiency levels (BAT-AEELs) for the combustion of HFO and/or gas oil in reciprocating engines

Type of combustion unit BAT-AEELs (1)

Net electrical efficiency (%) (2)

New unit Existing unit

HFO- and/or gas-oil-fired reciprocating engine – single cycle

41.5–44.5 (3) 38.3–44.5 (3)

HFO- and/or gas-oil-fired reciprocating engine – combined cycle

> 48 (4) No BAT-AEEL

(1) These BAT-AEELs do not apply to units operated < 1500 h/yr.

(2) Net electrical efficiency BAT-AEELs apply to CHP units whose design is oriented towards power generation, and to units generating only power.

(3) These levels may be difficult to achieve in the case of engines fitted with energy-intensive secondary abatement techniques.

(4) This level may be difficult to achieve in the case of engines using a radiator as a cooling system in dry, hot geographical locations.

GUIDANCE


181. It is not considered that dry, hot geographical locations exist on the UK mainland or in Northern Ireland. Therefore, it is unlikely that Footnote (4) will be considered in any BAT assessment for plant located in these areas.

182. As noted by footnote (3) in some cases these BAT-AEELs cannot be achieved for plant with some types of the secondary abatement. This should be recognised in the required BAT assessment. The assessment should quantify the energy use in relevant abatement systems and provide a reasoned justification for why this is considered energy intensive

OFFICAL


3.2.2 NOX, CO AND VOLATILE ORGANIC COMPOUND EMISSIONS TO AIR

BAT 32

BAT 32. In order to prevent or reduce NOX emissions to air from the combustion of HFO and/or gas oil in reciprocating engines, BAT is to use one or a combination of the techniques given below.


a. Low-NOX combustion concept in diesel engines



b. Exhaust-gas recirculation (EGR)

Not applicable to four-stroke engines

c. Water/steam addition Applicable within the constraints of water availability.

The applicability may be limited where no retrofit package is available




Retrofitting existing combustion plants may be constrained by the availability of sufficient space

GUIDANCE


BAT 33

BAT 33. In order to prevent or reduce emissions of CO and volatile organic compounds to air from the combustion of HFO and/or gas oil in reciprocating engines, BAT is to use one or both of the techniques given below.


a. Combustion optimisation Generally applicable

b. Oxidation catalysts See descriptions in Section 8.3 Not applicable to combustion plants operated <500 h/yr.

The applicability may be limited by the sulphur content of the fuel

GUIDANCE

OFFICAL



BAT 33 (cont.d)

Table 18: BAT associated emission levels (BAT-AELs) for NOX emissions to air from the combustion of HFO and/or gas oil in reciprocating engines

Combustion plant total rated thermal input (MWth)

BAT-AELs (mg/Nm3)



New plant Existing plant (2)(3)

≥50 115–190(4) 125–625 145–300 150–750

(1) These BAT-AELs do not apply to plants operated < 1500 h/yr or to plants that cannot be fitted with secondary abatement techniques.

(2) The BAT-AEL range is 1150–1900 mg/Nm3 for plants operated <1500 h/yr and for plants that cannot be fitted with secondary abatement techniques.


(4) For plants including units of < 20MWth combusting HFO, the higher end of the BAT-AEL range applying to those units is 225 mg/Nm3.

As an indication, for existing combustion plants burning only HFO and operated ≥1500 h/yr or new combustion plants burning only HFO,

the yearly average CO emission levels will generally be 50–175 mg/Nm3;

the average over the sampling period for TVOC emission levels will generally be 10–40 mg/Nm3.

GUIDANCE



187. Footnote (1): The annual BAT-AELs do not apply to existing plants operated < 1500 h/yr or to plants that cannot be fitted with secondary abatement techniques. Daily/periodic BAT-AELs still apply, subject to footnote (3).

188. Footnote (3): The daily or periodic BAT-AELs are only indicative for existing plant operating <500 h/yr. Where this footnote is applied, a BAT demonstration that the plant is operating to BAT may still be required and emission limit values may still be set to reflect BAT and provide environmental protection as site specific BAT.

189. Footnote (2): For plants that cannot be fitted with secondary abatement techniques the BAT-AEL range is 1150-1900 mg/Nm3. In order to apply the extension to the BAT-AEL range in this footnote a robust justification for why no secondary abatement techniques can be applied must be supplied by the operator. Emission limit values may still be set to reflect BAT and provide environmental protection where required.


OFFICAL





Continuous (3)



191. For plant using SNCR or SCR the BAT-AELs for ammonia given in BAT 7 apply, see guidance point Error! Reference source not found. above.

192. Where this BAT-AEL for ammonia applies, the corresponding monitoring requirement is:




Continuous (3) (4)





194. Where a permit ELV is set based on the BAT-AEL for CO, the corresponding monitoring requirement is:




Continuous (3)




BAT 34

BAT 34. In order to prevent or reduce SOX, HCl and HF emissions to air from the combustion of HFO and/or gas oil in reciprocating engines, BAT is to use one or a combination of the techniques given below.


a. Fuel choice See descriptions in Section 8.4 Applicable within the constraints

OFFICAL


associated with the availability of different types of fuel, which may be impacted by the energy policy of the Member State

b. Duct sorbent injection (DSI) There may be technical restrictions in the case of existing combustion plants

Not applicable to combustion plants operated <500 h/yr

c. Wet flue-gas desulphurisation (wet FGD)

There may be technical and economic restrictions for applying the technique to combustion plants of < 300 MWth.



GUIDANCE


BAT 34 (cont.d)

Table 19: BAT associated emission levels (BAT-AELs) for SO2 emissions to air from the combustion of HFO and/or gas oil in reciprocating engines


(MWth)




All sizes 45–100 100–200 (3) 60–110 105–235 (3)



(3) The higher end of the BAT-AEL range is 280 mg/Nm3 if no secondary abatement technique can be applied. This corresponds to a sulphur content of the fuel of 0.5 wt-% (dry).

GUIDANCE



198. Although the BAT-AELs do not apply to plants operating < 1500 h/yr and are only indicative for plant operating <500 h/yr, the operator will still need to demonstrate that

OFFICAL


the plant is operating to BAT and emission limit values may still be set to reflect BAT and provide environmental protection where required.

199. In order to apply the extension to the BAT-AEL range in footnote (3) a robust justification for why no secondary abatement techniques can be applied must be supplied by the operator.

200. Although footnote (3) specifies an extension to the BAT-AEL range is possible for certain plant, this must be subject to a demonstration that no secondary abatement technique can be applied. In this context the applicability of relevant secondary abatement techniques listed in BAT 34 must be considered as well as other site specific and/or economic considerations.





Continuous (3) (8)




160. Other procedures for the provision of data of an equivalent scientific quality are addressed in guidance paragraph XX and in other UK guidance[20].


BAT 35

BAT 35. In order to prevent or reduce dust and particulate-bound metal emissions from the combustion of HFO and/or gas oil in reciprocating engines, BAT is to use one or a combination of the techniques given below.


a. Fuel choice See descriptions in Section 8.5

Applicable within the constraints associated with the availability of different types of fuel, which may be impacted by the energy policy of the Member State

b. Electrostatic precipitator (ESP)

Not applicable to combustion plants operated <500 h/yr

c. Bag filter

OFFICAL


GUIDANCE


BAT 35 (cont.d)

Table 20: BAT associated emission levels (BAT-AELs) for dust emissions to air from the combustion of HFO and/or gas oil in reciprocating engines


(MWth)




≥50 5–10 5–35 10–20 10–45



GUIDANCE



205. Although the BAT-AELs do not apply to plants operating < 1500 h/yr and are only indicative for plant operating <500 h/yr, the operator will still need to demonstrate that the plant is operating to BAT and emission limit values may still be set to reflect BAT and provide environmental protection where required.





Continuous (3)



207. In the case of HFO and/or gas oil firing the requirement for monitoring of metal species will be determined on a case by case basis (see BAT 4 above).

OFFICAL


3.3 GAS-OIL-FIRED GAS TURBINES

Unless stated otherwise, the BAT conclusions presented in this section are generally applicable to the combustion of gas oil in gas turbines. They apply in addition to the general BAT conclusions given in Section 1.

GUIDANCE

208. Gas oil is defined in the BATC.


BAT 36

BAT 36. In order to increase the energy efficiency of gas oil combustion in gas turbines, BAT is to use an appropriate combination of the techniques given in BAT 12 and below.


a. Combined cycle See description in Section 8.2 Generally applicable to new units operated ≥ 1500 h/yr.

Applicable to existing units within the constraints associated with the steam cycle design and the space availability.

Not applicable to existing units operated < 1500 h/yr

Table 21: BAT associated energy efficiency levels (BAT-AEELs) for gas-oil-fired gas turbines

Type of combustion unit BAT-AEELs (1)

Net electrical efficiency (%) (2)

New unit Existing unit

Gas-oil-fired open-cycle gas turbine

>33 25–35.7

Gas-oil-fired combined cycle gas turbine

>40 33–44


(2) Net electrical efficiency BAT-AEELs apply to CHP units whose design is oriented towards power generation, and to units generating only power.

GUIDANCE

209. See guidance paragraph Error! Reference source not found. above for the general position for BAT conclusions for associated environmental performance levels and associated energy efficiency levels (AEPLs and AEELs).

OFFICAL


210. See guidance point XX above on the application of footnote 2.



BAT 37

BAT 37. In order to prevent or reduce NOX emissions to air from the combustion of gas oil in gas turbines, BAT is to use one or a combination of the techniques given below.


a. Water/steam addition See description in Section 8.3 The applicability may be limited due to water availability

b. Low-NOX burners (LNB) Only applicable to turbine models for which low-NOX burners are available on the market

c. Selective catalytic reduction (SCR)




GUIDANCE


BAT 38

BAT 38. In order to prevent or reduce CO emissions to air from the combustion of gas oil in gas turbines, BAT is to use one or a combination of the techniques given below.


a. Combustion optimisation See description in Section 8.3 Generally applicable

b. Oxidation catalysts Not applicable to combustion plants

OFFICAL


operated < 500 h/yr.


As an indication, the emission level for NOX emissions to air from the combustion of gas oil in dual fuel gas turbines for emergency use operated <500 h/yr will generally be 145–250 mg/Nm3 as a daily average or average over the sampling period.

GUIDANCE


214. The 145-250 mg/Nm3 NOx BAT-AEL range for gas-oil use in dual fuelled gas turbines operated <500 hours/year is indicative and thus not a BAT-AEL. Consequently, the Regulators may choose not to include an ELV in a permit. A BAT justification for any departure from this range is required, however, no Article 15(4) derogation will be required for deviation from this range.

215. For plant using SNCR or SCR the BAT-AELs for ammonia given in BAT 7 apply, see guidance point XX above.





Continuous (3) (4)





3.3.3 SOX AND DUST EMISSIONS TO AIR

BAT 39

BAT 39. In order to prevent or reduce SOX and dust emissions to air from the combustion of gas oil in gas turbines, BAT is to use the technique given below.


a. Fuel choice See description in Section 8.4 Applicable within the constraints associated with the availability of different types of fuel, which may be

OFFICAL


impacted by the energy policy of the Member State

Table 22: BAT associated emission levels for SO2 and dust emissions to air from the combustion of gas oil in gas turbines, including dual fuel gas turbines

Type of combustion plant BAT-AELs (mg/Nm3)

SO2 Dust

Yearly average (1)

Daily average or average over the sampling period (2)

Yearly average (1)

Daily average or average over the sampling period (2)

New and existing plants 35–60 50–66 2–5 2–10



GUIDANCE








Continuous (3) (8)






OFFICAL


4 BAT CONCLUSIONS FOR THE COMBUSTION OF GASEOUS FUELS

4.1 BAT CONCLUSIONS FOR THE COMBUSTION OF NATURAL GAS

Unless otherwise stated, the BAT conclusions presented in this section are generally applicable to the combustion of natural gas. They apply in addition to the general BAT conclusions given in Section 1. They do not apply to combustion plants on offshore platforms; these are covered by Section. 4.3.


BAT 40

BAT 40. In order to increase the energy efficiency of natural gas combustion, BAT is to use an appropriate combination of the techniques given in BAT 12 and below.


a. Combined cycle See description in Section 8.2 Generally applicable to new gas turbines and engines except when operated < 1500 h/yr.

Applicable to existing gas turbines and engines within the constraints associated with the steam cycle design and the space availability.

Not applicable to existing gas turbines and engines operated < 1500 h/yr.

Not applicable to mechanical drive gas turbines operated in discontinuous mode with extended load variations and frequent start-ups and shutdowns.

Not applicable to boilers

Table 23: BAT associated energy efficiency levels (BAT-AEELs) for the combustion of natural gas


Net electrical efficiency (%)

Net total fuel utilisation (%) (3)(4)

Net mechanical energy efficiency (%) (4)(5)


Gas engine 39.5–44 (6) 35–44 (6) 56–85 (6) No BAT-AEEL.

Gas-fired boiler 39–42.5 38–40 78–95 No BAT-AEEL.

Open cycle gas turbine, ≥50 MWth

36–41.5 33–41.5 No BAT-AEEL 36.5–41 33.5–41

Combined cycle gas turbine (CCGT)

CCGT, 50–600 MWth 53–58.5 46–54 No BAT-AEEL No BAT-AEEL

OFFICAL


CCGT, ≥600 MWth 57–60.5 50–60 No BAT-AEEL No BAT-AEEL

CHP CCGT, 50–600 MWth 53–58.5 46–54 65–95 No BAT-AEEL

CHP CCGT, ≥600 MWth 57–60.5 50–60 65–95 No BAT-AEEL

(1) These BAT-AEELs do not apply to units operated <1500 h/yr.

(2) In the case of CHP units, only one of the two BAT-AEELs 'Net electrical efficiency' or 'Net total fuel utilisation' applies, depending on the CHP unit design (i.e. either more oriented towards electricity generation or heat generation).

(3) Net total fuel utilisation BAT-AEELs may not be achievable if the potential heat demand is too low.


(5) These BAT-AEELs apply to units used for mechanical drive applications.

(6) These levels may be difficult to achieve in the case of engines tuned in order to reach NOX levels lower than 190 mg/Nm3.

GUIDANCE


224. See guidance on general considerations (guidance point XX) and energy efficiency (section 1.5) above. These BAT-AEELs do not apply to gas fired plant operating <1,500 hours as specified in footnote 1. Consequently, no BAT assessment is required.

225. See guidance point XX in the general considerations section above on how to address BAT requirements for the application of one, or more, of the techniques specified above. It should be noted that combined cycle operations are not generally applicable for either new or existing gas turbines or engines when operated <1,500 hours/yr.


227. Table 23 Footnotes (4) & (5): The net mechanical energy efficiency BAT-AEELs do not apply to plants generating only electricity or used for mechanical drive applications.

228. Table 23 Footnote (6). UK Regulators note the need to tune engines to reach NOx

emission levels of lower than 190 mg/Nm3 and that this can compromise efficiency.

However, the BAT-AELs specified in Table 25 below will be imposed as permit ELVs

and the BAT justification for any departure from the stated BAT-AEELS needs to

demonstrate that the emission level is selected is optimised with respect to efficiency

considerations.

229. Table 23 Footnote (2): In the case of CHP plants the orientation of the plant towards either electricity or heat generation will need to be determined. This will then identify which of the two BAT-AEELs will be applied. See guidance in section 2.2.1 (guidance paragraph XX).

4.1.2 NOX, CO, NMVOC AND CH4 EMISSIONS TO AIR

BAT 41

OFFICAL


BAT 41. In order to prevent or reduce NOX emissions to air from the combustion of natural gas in boilers, BAT is to use one or a combination of the techniques given below.


a. Air and/or fuel staging See descriptions in Section 8.3.

Air staging is often associated with low-NOX burners


b. Flue-gas recirculation See description in Section 8.3

c. Low-NOX burners (LNB)

d. Advanced control system See description in Section 8.3.

This technique is often used in combination with other techniques or may be used alone for combustion plants operated < 500 h/yr

The applicability to old combustion plants may be constrained by the need to retrofit the combustion system and/or control command system

e. Reduction of the combustion air temperature

See description in Section 8.3 Generally applicable within the constraints associated with the process needs

f. Selective non–catalytic reduction (SNCR)

Not applicable to combustion plants operated <500 h/yr with highly variable boiler loads.

The applicability may be limited in the case of combustion plants operated between 500 h/yr and 1500 h/yr with highly variable boiler loads



Not generally applicable to combustion plants of <100 MWth.


GUIDANCE


BAT 42

BAT 42. In order to prevent or reduce NOX emissions to air from the combustion of natural gas in gas turbines, BAT is to use one or a combination of the techniques given below.

OFFICAL



a. Advanced control system See description in Section 8.3.

This technique is often used in combination with other techniques or may be used alone for combustion plants operated < 500 h/yr


b. Water/steam addition See description in Section 8.3 The applicability may be limited due to water availability

c. Dry low-NOX burners (DLN) The applicability may be limited in the case of turbines where a retrofit package is not available or when water/steam addition systems are installed

d. Low-load design concept Adaptation of the process control and related equipment to maintain good combustion efficiency when the demand in energy varies, e.g. by improving the inlet airflow control capability or by splitting the combustion process into decoupled combustion stages

The applicability may be limited by the gas turbine design

e. Low-NOX burners (LNB) See description in Section 8.3 Generally applicable to supplementary firing for heat recovery steam generators (HRSGs) in the case of combined-cycle gas turbine (CCGT) combustion plants

f. Selective catalytic reduction (SCR)

Not applicable in the case of combustion plants operated < 500 h/yr.

Not generally applicable to existing combustion plants of < 100 MWth.

Retrofitting existing combustion plants may be constrained by the availability of sufficient space.


GUIDANCE


232. The qualifications relating to the technical and economic restrictions for retrofitting SCR to existing combustion plant operated between 500 h/yr and 1500 h/yr and those plants constrained by the availability of sufficient space need to be fully justified in relevant BAT assessments. This may need to be in conjunction with any Article 15(4) derogation

OFFICAL


should this affect the plants ability to meet emission limit values reflecting the BAT-AEL ranges.

233. See section XX for guidance on DLN operational thresholds.

234. For gas turbine plants operating in open cycle running <1500 h/yr (and less than 500 h/yr) SCR is unlikely to be applicable. However, a BAT justification on a case by case basis for this general position is required as the interpretation does allow for the use of SCR on open cycle gas turbines. If this justification is sound and robust, such plant will then be conditioned in the permit to limit operational hours to the relevant value.

BAT 43

BAT 43. In order to prevent or reduce NOX emissions to air from the combustion of natural gas in engines, BAT is to use one or a combination of the techniques given below.


a. Advanced control system See description in Section 8.3.

This technique is often used in combination with other techniques or may be used alone for combustion plants operated <500 h/yr


b. Lean-burn concept See description in Section 8.3.

Generally used in combination with SCR

Only applicable to new gas-fired engines

c. Advanced lean-burn concept See descriptions in Section 8.3

Only applicable to new spark plug or other ignited engines


Retrofitting existing combustion plants may be constrained by the availability of sufficient space.



GUIDANCE


BAT 44

OFFICAL


BAT 44. In order to prevent or reduce CO emissions to air from the combustion of natural gas, BAT is to ensure optimised combustion and/or to use oxidation catalysts. See descriptions in Section 8.3.

Table 24: BAT associated emission levels (BAT-AELs) for NOX emissions to air from the combustion of natural gas in gas turbines

Type of combustion plant Combustion plant total rated thermal input

(MWth)

BAT-AELs (mg/Nm3) (1) (2)

Yearly average (3) (4) Daily average or average over the sampling period

Open-cycle gas turbines (OCGTs) (5)(6)

New OCGT ≥50 15–35 25–50

Existing OCGT (excluding turbines for mechanical drive applications) — All but plants operated <500 h/yr

≥50 15–50 25–55 (7)

Combined-cycle gas turbines (CCGTs) (5) (8)

New CCGT ≥50 10–30 15–40

Existing CCGT with a net total fuel utilisation of <75%

≥600 10–40 18–50

Existing CCGT with a net total fuel utilisation of ≥75%

≥600 10–50 18–55 (9)

Existing CCGT with a net total fuel utilisation of <75%

50–600 10–45 35–55

Existing CCGT with a net total fuel utilisation of ≥75%

50–600 25–50 (10) 35–55 (11)

Open- and combined-cycle gas turbines

Gas turbine put into operation no later than 27 November 2003, or existing gas turbine for emergency use and operated <500 h/yr

≥50 No BAT-AEL 60–140 (12)(13)

Existing gas turbine for mechanical drive applications – All but plants operated < 500 h/yr

≥50 15–50 (14) 25–55 (15)

(1) These BAT-AELs also apply to the combustion of natural gas in dual-fuel-fired turbines.

(2) In the case of a gas turbine equipped with DLN, these BAT-AELs apply only when the DLN operation is effective.

(3) These BAT-AELs do not apply to existing plants operated <1500 h/yr.

(4) Optimising the functioning of an existing technique to reduce NOX emissions further may lead to levels of CO emissions at the higher end of the indicative range for CO emissions given after this table.

(5) These BAT-AELs do not apply to existing turbines for mechanical drive applications or to plants operated <500 h/yr.

(6) For plants with a net electrical efficiency (EE) greater than 39%, a correction factor may be applied to the higher end of the range, corresponding to [higher end] x EE / 39, where EE is the net electrical energy efficiency or net mechanical energy efficiency of the plant determined at ISO baseload conditions.

(7) The higher end of the range is 80 mg/Nm3 in the case of plants which were put into operation no later than 27 November 2003 and are operated between 500 h/yr and 1500 h/yr.

(8) For plants with a net electrical efficiency (EE) greater than 55%, a correction factor may be applied to the higher end of the BAT-AEL range, corresponding to [higher end] x EE / 55, where EE is the net electrical efficiency of the plant determined at ISO baseload conditions.

(9) For existing plants put into operation no later than 7 January 2014, the higher end of the BAT-AEL range is 65 mg/Nm3.

OFFICAL




(12) The lower end of the BAT-AEL range for NOX can be achieved with DLN burners.

(13) These levels are indicative.



As an indication, the yearly average CO emission levels for each type of existing combustion plant operated ≥1500 h/yr and for each type of new combustion plant will generally be as follows:

New OCGT of ≥50 MWth: < 5–40 mg/Nm3. For plants with a net electrical efficiency (EE) greater than 39%, a correction factor may be applied to the higher end of this range, corresponding to [higher end] x EE / 39, where EE is the net electrical energy efficiency or net mechanical energy efficiency of the plant determined at ISO baseload conditions.

Existing OCGT of ≥50 MWth (excluding turbines for mechanical drive applications): <5–40 mg/Nm3. The higher end of this range will generally be 80 mg/Nm3

in the case of existing plants that cannot be fitted with dry techniques for NOX reduction, or 50 mg/Nm3

for plants that operate at low load.

New CCGT of ≥50 MWth: <5–30 mg/Nm3. For plants with a net electrical efficiency (EE) greater than 55%, a correction factor may be applied to the higher end of the range, corresponding to [higher end] x EE / 55, where EE is the net electrical energy efficiency of the plant determined at ISO baseload conditions.

Existing CCGT of ≥50 MWth: <5–30 mg/Nm3. The higher end of this range will generally be 50 mg/Nm3 for plants that operate at low load.

Existing gas turbines of ≥50 MW th for mechanical drive applications: <5–40 mg/Nm3. The higher end of the range will generally be 50 mg/Nm3

when plants operate at low load.

In the case of a gas turbine equipped with DLN burners, these indicative levels correspond to when the DLN operation is effective.

GUIDANCE



238. A summary Table of applicable ELVs based on the BAT-AELS has been provided in

Annex II. There are numerous possibilities dependant on operating hours, turbine size

etc. The ELVs imposed in the permit will reflect only one type of operational mode. The

applicable monitoring provisions of BAT 4 and / or IED Annex V are also summarised

in this table

239. The BAT-AELs set for gas turbine operation are set from the point at which the dry low NOx system (DLN) becomes effective. Chapter III of the IED however, requires compliance with the Annex V ELVs from 70% load. For many (although not all) plant, the UK regulators have also applied a daily ELV from the end of start-up (MSUL) (and

OFFICAL


start of shut down-MSDL). In order to avoid having 3 sets of ELVs we have decided to apply the BRef AELs from a site specific effective DLN load value and continue to apply the daily value from MSUL/SD. Should an operator of a GT request a DLN value >70% then this will be addressed on a site-specific basis to ensure that the IED ELV is still met.

240. The above table specifies indicative BAT associated emission levels (BAT-AELs) for NOX emissions to air from the combustion of natural gas in gas turbines put into operation no later than November 2003, or existing gas turbine for emergency use and operated <500h/yr. Footnote 13 states that these levels are indicative. As emergency GTs are not subject to the BATc(see para XX below) these indicative AELs are applicable to pre 2003 GTs operating as non emergency plant for <500hpa

241. The section on General BAT Considerations (see guidance paragraph ??? above) state that the BAT-AELs set out in these BAT conclusions may not apply to liquid-fuel-fired and gas-fired turbines and engines for emergency use operated less than 500 h/yr, when such emergency use is not compatible with meeting the BAT-AELs. The UK regulators have interpreted this to apply to a generator operated for the sole purpose of maintaining a power supply at a site during an on- site emergency and during a black start. Where combustion plant are operating to support the Grid, indicative BAT applies. BAT will be determined in response to the Reg 61 notices. Reporting against BAT will be through the use of monitoring or emission factors, as appropriate, every 1500 operating hours.

242. For non-emergency GTs operating <500hpa we will apply a benchmark elv. This is purely a reference point in order for the operator to define a maintenance schedule. Ie the maintenance schedule is set up on the basis of maintaining that benchmark. It is not intended to be applied as a concentration limit which will require monitoring against for compliance.

243. Annex II summarises the BAT-AELs that apply to different types of boilers in different modes of operation. There are 9 different possibilities dependant on operating hours, and boiler size etc. The ELVs imposed in the permit will reflect only one type of operational mode Insert

244. Regulators may apply the energy efficiency modification (footnote 6) to the higher end of the BAT-AEL range. In such cases information on the net electrical energy efficiency or net mechanical energy efficiency determined at ISO baseload conditions will need to be assessed. This BAT-AEL applicability is NOT considered to be one of the three instances in these LCP BATcs where further consideration of the qualification “may be” is required. See guidance point XX above. In this case, UK Regulators will apply (where applicable) the previously established amendments under IED Annex V in the case of adjustments to NOx BAT-AELs for gas turbines based on plant efficiency.

245. The higher end of the BAT-AEL range (footnote 7) will be taken as 80mg/Nm3 for existing plants put into operation no later than 27 November 2003 and operated >500 h/y and ≤1,500 h/y.

246. Regulators may apply the energy efficiency modification to the higher end of the BAT-AEL range for combined cycle gas turbines (CCGTs) (footnote 8). Where relevant, information on the net electrical energy efficiency determined at ISO baseload conditions will need assessed as part of the BAT determination. This BAT-AEL applicability is NOT considered to be one of the three instances in these LCP BATcs where further consideration of the qualification “may be” is required. See guidance point XX above. In this case, UK Regulators will apply (where applicable) the previously established amendments under IED Annex V in the case of adjustments to NOx BAT-AELs for gas turbines based on plant efficiency.

OFFICAL


BAT 44 (cont.d)

Table 25: BAT associated emission levels (BAT-AELs) for NOX emissions to air from the combustion of natural gas in boilers and engines

Type of combustion plant BAT-AELs (mg/Nm3)

Yearly average (1) Daily average or average over the sampling period


Boiler 10–60 50–100 30–85 85–110

Engine (4) 20–75 20–100 55–85 55–110 (5)

(1) Optimising the functioning of an existing technique to reduce NOx emissions further may lead to levels of CO emissions at the higher end of the indicative range for CO emissions given after this table.



(4) These BAT-AELs only apply to spark-ignited and dual-fuel engines. They do not apply to gas-diesel engines.

(5) In the case of engines for emergency use operated <500 h/yr that could not apply the lean-burn concept or use SCR, the higher end of the indicative range is 175 mg/Nm3.


<5–40 mg/Nm3 for existing boilers operated ≥1500 h/yr;

<5–15 mg/Nm3 for new boilers;

30–100 mg/Nm3 for existing engines operated ≥1500 h/yr and for new engines.

GUIDANCE

247. These BAT-AELs apply to spark-ignited and dual-fuel engines only and boilers. They do not apply to compression ignition (diesel) engines. The definitions of different engine types is not given in these BATcs but is documented in the MCPD[21]. See guidance paragraph XX above in respect of engine tuning effects and efficiency levels.

248. The annual average BAT-AEL ranges do not apply for existing plant operating <1,500 hours/yr. Daily average BAT-AEL ranges are indicative for existing plant operating <500 hours/yr.

249. A summary Table of applicable ELVs for boilers based on the BAT-AELS has been

provided in Annex II. There are 9 different possibilities dependant on operating hours,

plant size etc. The ELVs imposed in the permit will reflect only one type of operational

mode. The applicable monitoring provisions of BAT 4 and / or IED Annex V are also

summarised in this table.

250. Where the BAT-AEL for NOx for engines applies the corresponding monitoring requirement is:



21 Article 3 of Directive 2015/2193 of the European Parliament and of the Council of 25 November

2015 on the Limitation of Emissions of Certain Pollutants into the Air from Medium Combustion Plants

OFFICAL



Continuous (3)



251. For plant using SNCR or SCR BAT-AELs for ammonia for engines given in BAT 7 apply, see guidance point XX above.





Continuous (3) (4)





254. Where a permit ELV is set reflecting the indicative BAT-AEL for CO for engines the corresponding monitoring requirement is:




Continuous (3)



BAT 45

BAT 45. In order to reduce non-methane volatile organic compounds (NMVOC) and methane (CH4) emissions to air from the combustion of natural gas in spark-ignited lean-burn gas engines, BAT is to ensure optimised combustion and/or to use oxidation catalysts.

See descriptions in Section 8.3. Oxidation catalysts are not effective at reducing the emissions of saturated hydrocarbons containing less than four carbon atoms.

Table 26: BAT associated emission levels (BAT-AELs) for formaldehyde and CH4 emissions to air from the combustion of natural gas in a spark-ignited lean-burn gas engine

Combustion plant total rated BAT-AELs (mg/Nm3)

OFFICAL


thermal input (MWth) Formaldehyde CH4


New or existing plant New plant Existing plant

≥50 5–15 (1) 215–500 (2) 215–560 (1)(2)

(1) For existing plants operated <500 h/yr, these levels are indicative.

(2) This BAT-AEL is expressed as C at full load operation.

GUIDANCE

255. The term “lean burn” is explained in section 8.3 of these BATcs below.

256. Note that BAT AEL ranges for methane are expressed as carbon. ELVs set in permits will be adjusted to express the BAT-AEL on a methane basis (to reflect typical UK practices). BAT AEL ranges for formaldehyde will be expressed as carbon.

257. Where the BAT-AEL for formaldehyde applies the corresponding monitoring requirement is:




Once every year

258. Where the BAT-AEL for methane applies the corresponding monitoring requirement is:



All sizes EN ISO 25139 Once every year (21)

(21) Measurements are carried out with the plant operated at loads of >70%.

259. BAT4 footnote 21 makes it clear that monitoring should be undertaken at >70% MCR and therefore permit ELVs will be set to reflect the BAT-AEL range for all operations over 70% MCR.

4.2 BAT CONCLUSIONS FOR THE COMBUSTION OF IRON AND STEEL PROCESS GASES

Unless otherwise stated, the BAT conclusions presented in this section are generally applicable to the combustion of iron and steel process gases (blast furnace gas, coke oven gas, basic oxygen furnace gas), individually, in combination, or simultaneously with other gaseous and/or liquid fuels. They apply in addition to the general BAT conclusions given in Section 1.


BAT 46

OFFICAL


BAT 46. In order to increase the energy efficiency of the combustion of iron and steel process gases, BAT is to use an appropriate combination of the techniques given in BAT 12 and below.


a. Process gas management system

See description in Section 8.2 Only applicable to integrated steelworks

Table 27: BAT associated energy efficiency levels (BAT-AEELs) for the combustion of iron and steel process gases in boilers



Existing multi-fuel firing gas boiler

30–40 50–84

New multi-fuel firing gas boiler (4) 36–42.5 50–84

(1) These BAT-AEELs do not apply in the case of units operated < 1500 h/yr.



(4) The wide range of energy efficiencies in CHP units is largely dependent on the local demand for electricity and heat.

Table 28: BAT associated energy efficiency levels (BAT-AEELs) for the combustion of iron and steel process gases in CCGTs



CHP CCGT >47 40–48 60–82

CCGT >47 40–48 No BAT-AEEL




GUIDANCE

260. See guidance paragraph XX above for the general position for BAT conclusions for associated environmental performance levels and associated energy efficiency levels (AEPLs and AEELs)

OFFICAL



BAT 47

BAT 47. In order to prevent or reduce NOX emissions to air from the combustion of iron and steel process gases in boilers, BAT is to use one or a combination of the techniques given below.


a. Low-NOX burners (LNB) See description in Section 8.3.

Specially designed low-NOX burners in multiple rows per type of fuel or including specific features for multi-fuel firing (e.g. multiple dedicated nozzles for burning different fuels, or including fuels premixing)


b. Air staging See descriptions in Section 8.3

c. Fuel staging

d. Flue-gas recirculation

e. Process gas management system

See description in Section 8.2. Generally applicable within the constraints associated with the availability of different types of fuel

f. Advanced control system See description in Section 8.3.

This technique is used in combination with other techniques


g. Selective non-catalytic reduction (SNCR)

See descriptions in Section 8.3 Not applicable to combustion plants operated <500 h/yr

h. Selective catalytic reduction (SCR)


Not generally applicable to combustion plants of <100 MWth.

Retrofitting existing combustion plants may be constrained by the availability of sufficient space and by the combustion plant configuration

GUIDANCE


OFFICAL


BAT 48

BAT 48. In order to prevent or reduce NOX emissions to air from the combustion of iron and steel process gases in CCGTs, BAT is to use one or a combination of the techniques given below.


a. Process gas management system

See description in Section 8.2 Generally applicable within the constraints associated with the availability of different types of fuel

b. Advanced control system See description in Section 8.3.

This technique is used in combination with other techniques


c. Water/steam addition See description in Section 8.3.

In dual fuel gas turbines using DLN for the combustion of iron and steel process gases, water/steam addition is generally used when combusting natural gas

The applicability may be limited due to water availability

d. Dry low-NOX burners(DLN) See description in Section 8.3.

DLN that combust iron and steel process gases differ from those that combust natural gas only

Applicable within the constraints associated with the reactiveness of iron and steel process gases such as coke oven gas.

The applicability may be limited in the case of turbines where a retrofit package is not available or when water/steam addition systems are installed

e. Low-NOX burners (LNB) See description in Section 8.3 Only applicable to supplementary firing for heat recovery steam generators (HRSGs) of combined-cycle gas turbine (CCGT) combustion plants

f. Selective catalytic reduction (SCR)


GUIDANCE


263. See section ?? for guidance on DLN operational thresholds.


OFFICAL


BAT 49

BAT 49. In order to prevent or reduce CO emissions to air from the combustion of iron and steel process gases, BAT is to use one or a combination of the techniques given below.



b. Oxidation catalysts Only applicable to CCGTs.

The applicability may be limited by lack of space, the load requirements and the sulphur content of the fuel

Table 29: BAT associated emission levels (BAT-AELs) for NOX emissions to air from the combustion of 100 % iron and steel process gases

Type of combustion plant O2 reference level (vol-%)

BAT-AELs (mg/Nm3) (1)


New boiler 3 15–65 22–100

Existing boiler 3 20–100 (2) (3) 22–110 (2) (4) (5)

New CCGT 15 20–35 30–50

Existing CCGT 15 20–50 (2) (3) 30–55 (5) (6)

(1) Plants combusting a mixture of gases with an equivalent LHV of >20 MJ/Nm3 are expected to emit at the higher end of the BAT-AEL ranges.

(2) The lower end of the BAT-AEL range can be achieved when using SCR.

(3) For plants operated < 1500 h/yr, these BAT AELs do not apply.

(4) In the case of plants put into operation no later than 7 January 2014, the higher end of the BAT-AEL range is 160 mg/Nm3. Furthermore, the higher end of the BAT-AEL range may be exceeded when SCR cannot be used and when using a high share of COG (e.g. >50%) and/or when combusting COG with a relatively high level of H 2. In this case, the higher end of the BAT-AEL range is 220 mg/Nm3.


(6) In the case of plants put into operation no later than 7 January 2014, the higher end of the BAT-AEL range is 70 mg/Nm3.


<5–100 mg/Nm3 for existing boilers operated ≥1500 h/yr;

<5–35 mg/Nm3 for new boilers;

<5–20 mg/Nm3 for existing CCGTs operated ≥1500 h/yr or new CCGTs.

GUIDANCE


OFFICAL


266. The BAT-AELs contained in Table 29 are stated to apply to the combustion of 100% iron

and steel process gases. When other fuels are burned at the same time as process

fuels, UK Regulators will apply the approach set out in IED Article 40 for multi-fuel firing

plant when deriving permit ELVs. We interpreted the specified requirements to mean

that the BAT-AEL ranges in Table 29 represent the emission limit value for iron and steel

process gases and that the emission limits for other fuels will reflect the BAT-AELs

ranges for those fuels specified in these BATcs (or the relevant IED Annex V

requirements where no BAT-AELs are specified).

267. Footnote 4. This BAT-AEL applicability is one of the three instances in these LCP BATcs where the qualification “may be” is used and is subject to further consideration. See guidance point XX above. The EC consider that the term “may be” should not be read as providing, in this case, an extension to the BAT-AEL range. This term is therefore regarded as merely complementary information for UK Regulators which could be considered when granting derogation under IED Article 15(4). As such, a derogation under Article 15(4) is required for any cases where the higher end of the BAT-AEL range of 220 mg/Nm3 is proposed in cases when SCR cannot be used (when using >50% COG and/or when combusting COG with a relatively high level of H2). In this case, any request for derogation must specifically address why SCR cannot be used and demonstrate that the fuel mixture meets the specified criteria.





Continuous (3) (5)

(1) Generic EN standards for continuous measurements are EN 15267-1, EN 15267-2, EN 15267-3, and EN 14181. (3) In the case of plants with a rated thermal input of <100 MW operated <1500 h/yr, the minimum monitoring frequency may be at least once every six months. For gas turbines, periodic monitoring is carried out with a combustion plant load of >70%. For co-incineration of waste with coal, lignite, solid biomass and/or peat, the monitoring frequency needs to also take into account Part 6 of Annex VI to the IED. (5) In the case of natural-gas-fired turbines with a rated thermal input of < 100 MW operated <1500 h/yr, or in the case of existing OCGTs, PEMS may be used instead.

269. Where a permit ELV is set reflecting the indicative BAT-AELs for CO the corresponding monitoring requirement is:




Continuous (3)



4.2.3 SOX EMISSIONS TO AIR

BAT 50

Commented [BA6]: Regulators to note and consider. Consultation with the EA of iron and steel sector lead may be required

Commented [CR7R6]: Ongoing

OFFICAL


BAT 50. In order to prevent or reduce SOX emissions to air from the combustion of iron and steel process gases, BAT is to use a combination of the techniques given below.


a. Process gas management system and auxiliary fuel choice


To the extent allowed by the iron- and steel-works, maximise the use of:

a majority of blast furnace gas with a low sulphur content in the fuel diet;

a combination of fuels with a low averaged sulphur content, e.g. individual process fuels with a very low S content such as:

o blast furnace gas with a sulphur content <10 mg/Nm3;

o coke oven gas with a sulphur content <300 mg/Nm3;

and auxiliary fuels such as:

o natural gas;

o liquid fuels with a sulphur content of ≤0.4% (in boilers).

Use of a limited amount of fuels with a higher sulphur content

Generally applicable within the constraints associated with the availability of different types of fuel

b. Coke oven gas pretreatment at the iron- and steel-works

Use of one of the following techniques:

desulphurisation by absorption systems;

wet oxidative desulphurisation

Only applicable to coke oven gas combustion plants

Table 30: BAT associated emission levels (BAT-AELs) for SO2 emissions to air from the combustion of 100% iron and steel process gases

Type of combustion plant O2 reference level (%)


Yearly average(1) Daily average or average over the sampling period (2)

New or existing boiler 3 25–150 50–200 (3)

New or existing CCGT 15 10–45 20–70

(1) For existing plants operated <1500 h/yr, these BAT AELs do not apply.

(2) For existing plants operated <500 h/yr, these levels are indicative.

(3) The higher end of the BAT-AEL range may be exceeded when using a high share of COG (e.g. >50%). In this case, the higher end of the BAT-AEL range is 300 mg/Nm3.

GUIDANCE


BAT requirements for the application of one, or more, of the techniques specified above.

OFFICAL


271. See guidance point XX above in respect of the derivation of permit ELVs using the

approach set out in IED Article 40 for BAT-AELs that apply to 100% iron and steel

process gases.

272. Footnote 3. This BAT-AEL applicability is one of the three instances in these LCP BATcs

where the qualification “may be” is used. See guidance point XX above. The EC

consider that the term “may be” should not be read as providing, in this case, an

extension to the BAT-AEL range. This term is regarded as merely complementary

information for UK Regulators which could be considered when granting derogation

under IED Article 15(4). As such, a derogation under Article 15(4) is required for any

cases where the higher end of the BAT-AEL range of 300 mg/Nm3 is proposed in cases

where >50% COG is used. In this case, the application must specifically demonstrate

that the fuel mixture meets the specified criteria.

273. Where the BAT-AEL for SO2 applies the corresponding monitoring requirement is:



All sizes Generic EN standards(1) and EN 14791

Continuous (3) (8)

(1) Generic EN standards for continuous measurements are EN 15267-1, EN 15267-2, EN 15267-3, and EN 14181. (3) In the case of plants with a rated thermal input of <100 MW operated <1500 h/yr, the minimum monitoring frequency may be at least once every six months. For gas turbines, periodic monitoring is carried out with a combustion plant load of >70%. For co-incineration of waste with coal, lignite, solid biomass and/or peat, the monitoring frequency needs to also take into account Part 6 of Annex VI to the IED. (8) As an alternative to the continuous measurement in the case of plants combusting oil with a known sulphur content and where there is no flue-gas desulphurisation system, periodic measurements at least once every three months and/or other procedures ensuring the provision of data of an equivalent scientific quality may be used to determine the SO2 emissions.



4.2.4 DUST EMISSIONS TO AIR

BAT 51

BAT 51. In order to reduce dust emissions to air from the combustion of iron and steel process gases, BAT is to use one or a combination of the techniques given below.


a. Fuel choice/management Use of a combination of process gases and auxiliary fuels with a low averaged dust or ash content

Generally applicable within the constraints associated with the availability of different types of fuel

OFFICAL


b. Blast furnace gas pretreatment at the iron- and steel-works

Use of one or a combination of dry dedusting devices (e.g. deflectors, dust catchers, cyclones, electrostatic precipitators) and/or subsequent dust abatement (venturi scrubbers, hurdle-type scrubbers, annular gap scrubbers, wet electrostatic precipitators, disintegrators)

Only applicable if blast furnace gas is combusted

c. Basic oxygen furnace gas pretreatment at the iron- and steel-works

Use of dry (e.g. ESP or bag filter) or wet (e.g. wet ESP or scrubber) dedusting. Further descriptions are given in the Iron and Steel BREF

Only applicable if basic oxygen furnace gas is combusted

d. Electrostatic precipitator (ESP)

See descriptions in Section 8.5 Only applicable if basic oxygen furnace gas is combusted

e. Bag filter Only applicable to combustion plants combusting a significant proportion of auxiliary fuels with a high ash content

Table 31: BAT associated emission levels (BAT-AELs) for dust emissions to air from the combustion of 100% iron and steel process gases

Type of combustion plant BAT-AELs for dust (mg/Nm3)

Yearly average (1) Daily average or average over the sampling period (2)

New or existing boiler 2–7 2–10

New or existing CCGT 2–5 2–5

(1) For existing plants operated < 1500 h/yr, these BAT-AELs do not apply.

(2) For existing plants operated < 500 h/yr, these levels are indicative

GUIDANCE


276. Where the BAT-AEL for dust applies the corresponding monitoring requirement is:




Continuous (3)(14)

(1) Generic EN standards for continuous measurements are EN 15267-1, EN 15267-2, EN 15267-3, and EN 14181. (3) In the case of plants with a rated thermal input of <100 MW operated <1500 h/yr, the minimum monitoring frequency may be at least once every six months. For gas turbines, periodic monitoring is carried out with a combustion plant load of >70%. For co-incineration of waste with coal, lignite, solid biomass and/or peat, the monitoring frequency needs to also take into account Part 6 of Annex VI to the IED. (14) In the case of plants combusting iron and steel process gases, the minimum monitoring frequency may be at least once every six months if the emission levels are proven to be sufficiently stable.

OFFICAL



approach set out in IED Article 40 for BAT-AELs that apply to 100% iron and steel

process gases.

4.3 BAT CONCLUSIONS FOR THE COMBUSTION OF GASEOUS AND/OR LIQUID FUELS ON OFFSHORE PLATFORMS

Unless otherwise stated, the BAT conclusions presented in this section are generally applicable to the combustion of gaseous and/or liquid fuels on offshore platforms. They apply in addition to the general BAT conclusions given in Section 1.

BAT 52

BAT 52. In order to improve the general environmental performance of the combustion of gaseous and/or liquid fuels on offshore platforms, BAT is to use one or a combination of the techniques given below.


a. Process optimisation Optimise the process in order to minimise the mechanical power requirements


b. Control pressure losses Optimise and maintain inlet and exhaust systems in a way that keeps the pressure losses as low as possible

c. Load control Operate multiple generator or compressor sets at load points which minimise emissions

d. Minimise the 'spinning reserve'

When running with spinning reserve for operational reliability reasons, the number of additional turbines is minimised, except in exceptional circumstances

e. Fuel choice Provide a fuel gas supply from a point in the topside oil and gas process which offers a minimum range of fuel gas combustion parameters, e.g. calorific value, and minimum concentrations of sulphurous compounds to minimise SO2 formation. For liquid distillate fuels, preference is given to low-sulphur fuels

f. Injection timing Optimise injection timing in engines

OFFICAL


g. Heat recovery Utilisation of gas turbine/engine exhaust heat for platform heating purposes

Generally applicable to new combustion plants. In existing combustion plants, the applicability may be restricted by the level of heat demand and the combustion plant layout (space)

h. Power integration of multiple gas fields / oilfields

Use of a central power source to supply a number of participating platforms located at different gas fields / oilfields

The applicability may be limited depending on the location of the different gas fields / oilfields and on the organisation of the different participating platforms, including alignment of time schedules regarding planning, start-up and cessation of production

GUIDANCE

278. Is guidance required?

BAT 53

BAT 53. In order to prevent or reduce NOX emissions to air from the combustion of gaseous and/or liquid fuels on offshore platforms, BAT is to use one or a combination of the techniques given below.


a. Advanced control system See descriptions in Section 8.3


b. Dry low-NOX burners (DLN) Applicable to new gas turbines (standard equipment) within the constraints associated with fuel quality variations.

The applicability may be limited for existing gas turbines by: availability of a retrofit package (for low-load operation), complexity of the platform organisation and space availability

c. Lean-burn concept Only applicable to new gas-fired engines

d. Low-NOX burners (LNB) Only applicable to boilers

GUIDANCE


280. See section ?? for guidance on DLN operational thresholds.

281. Detailed guidance to be provided by BEIS for offshore installations.

OFFICAL


BAT 54

BAT 54. In order to prevent or reduce CO emissions to air from the combustion of gaseous and/or liquid fuels in gas turbines on offshore platforms, BAT is to use one or a combination of the techniques given below.



b. Oxidation catalysts Not applicable to combustion plants operated < 500 h/yr.

Retrofitting existing combustion plants may be constrained by the availability of sufficient space and by weight restrictions

Table 32: BAT associated emission levels (BAT-AELs) for NOX emissions to air from the combustion of gaseous fuels in open-cycle gas turbines on offshore platforms

Type of combustion plant BAT-AELs (mg/Nm3) (1)


New gas turbine combusting gaseous fuels (2) 15–50 (3)

Existing gas turbine combusting gaseous fuels (2) <50–350 (4)

(1) These BAT-AELs are based on >70 % of baseload power available on the day.

(2) This includes single fuel and dual fuel gas turbines.

(3) The higher end of the BAT-AEL range is 250 mg/Nm3 if DLN burners are not applicable.

(4) The lower end of the BAT-AEL range can be achieved with DLN burners.

As an indication, the average CO emission levels over the sampling period will generally be:

<100 mg/Nm3 for existing gas turbines combusting gaseous fuels on offshore platforms

operated ≥1500 h/yr;

<75 mg/Nm3 for new gas turbines combusting gaseous fuels on offshore platforms.

GUIDANCE

282. Detailed guidance to be provided by BEIS for offshore installations.

OFFICAL


5 BAT CONCLUSIONS FOR MULTI-FUEL-FIRED PLANTS

5.1 BAT CONCLUSIONS FOR THE COMBUSTION OF PROCESS FUELS FROM THE CHEMICAL INDUSTRY

Unless otherwise stated, the BAT conclusions presented in this section are generally applicable to the combustion of process fuels from the chemical industry, individually, in combination, or simultaneously with other gaseous and/or liquid fuels. They apply in addition to the general BAT conclusions given in Section 1.

GUIDANCE

283. Process fuels from the chemical industry are defined in the definition section of these BATcs above.

284. It should be noted that some requirements refer to the combustion of “100% process fuels” (i.e. burning process fuels on their own) and other requirements relate to “process fuels” (i.e. process fuels on their own or in mixtures or in combination with other fuels). There are differences to how we derive permit ELVs from the BAT-AELs in each case which is addressed in each relevant section below.

5.1.1 GENERAL ENVIRONMENTAL PERFORMANCE

BAT 55

BAT 55. In order to improve the general environmental performance of the combustion of process fuels from the chemical industry in boilers, BAT is to use an appropriate combination of the techniques given in BAT 6 and below.


a. Pretreatment of process fuel from the chemical industry

Perform fuel pretreatment on and/or off the site of the combustion plant to improve the environmental performance of fuel combustion

Applicable within the constraints associated with process fuel characteristics and space availability

GUIDANCE


286. This BATc only applies to the combustion of process fuels from the chemical industry in boilers. A boiler being defined as ”any combustion plant with the exception of engines, gas turbines, and process furnaces or heaters”.

OFFICAL



Table 33: BAT associated energy efficiency levels (BAT-AEELs) for the combustion of process fuels from the chemical industry in boilers


Net electrical efficiency (%) Net total fuel utilisation (%) (3) (4)


Boiler using liquid process fuels from the chemical industry, including when mixed with HFO, gas oil and/or other liquid fuels

>36.4 35.6–37.4 80–96 80–96

Boiler using gaseous process fuels from the chemical industry, including when mixed with natural gas and/or other gaseous fuels

39–42.5 38–40 78–95 78–95


(2) In the case of CHP units, only one of the two BAT-AEELs 'Net electrical efficiency' or 'Net total fuel utilisation' applies, depending on the CHP unit design (i.e. either more oriented towards generation electricity or towards heat generation).

(3) These BAT-AEELs may not be achievable if the potential heat demand is too low.


GUIDANCE

287. See guidance paragraph Error! Reference source not found. above for the general position for BAT conclusions for associated environmental performance levels and associated energy efficiency levels (AEPLs and AEELs)

288. These BAT-AEELs apply to the combustion of process fuels from the chemical industry in boilers. A boiler being defined as: ”Any combustion plant with the exception of engines, gas turbines, and process furnaces or heaters”.


290. Table 8 Footnote (2): In the case of CHP plants the orientation of the plant towards either electricity or heat generation will need to be determined. This will then identify which of the two BAT-AEELs will be applied. See guidance in section 2.2.1 (guidance point XX).

291. Table 33 Footnote (3): See guidance point XX on low heat demand.


BAT 56

OFFICAL


BAT 56. In order to prevent or reduce NOX emissions to air while limiting CO emissions to air from the combustion of process fuels from the chemical industry, BAT is to use one or a combination of the techniques given below.


a. Low-NOX burners (LNB) See descriptions in Section 8.3 Generally applicable

b. Air staging

c. Fuel staging See description in Section 8.3.

Applying fuel staging when using liquid fuel mixtures may require a specific burner design

d. Flue-gas recirculation See descriptions in Section 8.3 Generally applicable to new combustion plants.

Applicable to existing combustion plants within the constraints associated with chemical installation safety

e. Water/steam addition The applicability may be limited due to water availability

f. Fuel choice Applicable within the constraints associated with the availability of different types of fuel and/or an alternative use of the process fuel

g. Advanced control system The applicability to old combustion plants may be constrained by the need to retrofit the combustion system and/or control command system

h. Selective non-catalytic reduction (SNCR)

Applicable to existing combustion plants within the constraints associated with chemical installation safety.


The applicability may be limited in the case of combustion plants operated between 500 h/yr and 1500 h/yr with frequent fuel changes and frequent load variations

i. Selective catalytic reduction (SCR)

Applicable to existing combustion plants within the constraints associated with duct configuration, space availability and chemical installation safety.


There may be technical and

OFFICAL


economic restrictions for retrofitting existing combustion plants operated between 500 h/yr and 1500 h/yr.

Not generally applicable to combustion plants of < 100 MWth

Table 34: BAT associated emission levels (BAT-AELs) for NOX emissions to air from the combustion of 100 % process fuels from the chemical industry in boilers

Fuel phase used in the combustion plant

BAT-AELs (mg/Nm3)



Mixture of gases and liquids 30–85 80–290 (3) 50–110 100–330 (3)

Gases only 20–80 70–100 (4) 30–100 85–110 (5)

(1) For plants operated <1500 h/yr, these BAT AELs do not apply.


(3) For existing plants of ≤500 MWth put into operation no later than 27 November 2003 using liquid fuels with a nitrogen content higher than 0.6 wt-%, the higher end of the BAT-AEL range is 380 mg/Nm3.



As an indication, the yearly average CO emission levels for existing plants operated ≥1500 h/yr and for new plants will generally be < 5–30 mg/Nm3.

GUIDANCE


293. BAT XX apply to the combustion of any process fuels individually or in combination with other fuels in the chemical industry.

294. The BAT-AELs contained in Table 34 are considered to only apply to the combustion of process fuels from the chemical industry in boilers only (not other combustion systems). A boiler being defined as “any combustion plant with the exception of engines, gas turbines, and process furnaces or heaters”.

295. The BAT-AELs contained in Table 34 are stated to apply to the combustion of 100%

process fuels from the chemical industry. When other fuels are burned at the same time

as process fuels, UK Regulators will apply the approach set out in IED Article 40 for

multi-fuel firing plant when deriving permit ELVs. We interpreted the specified

requirements to mean that the BAT-AEL ranges in Table 34 represent the emission limit

value for process fuels from the chemical industry and that the emission limits for other

fuels will reflect the BAT-AELs ranges for those fuels specified in these BATcs (or the

relevant IED Annex requirements where no BAT-AELs are specified).

296. Table 34 Footnote (1): The yearly average BAT-AELs do not apply to existing plants operated < 1500 h/yr. Daily/periodic BAT-AELs still apply, subject to footnote (2).

OFFICAL



298. Table 34 Footnote (2): The daily or periodic BAT-AELs are only indicative for existing plant operating <500 h/yr. Where this footnote is applied, a BAT demonstration that the plant is operating to BAT may still be required and emission limit values may still be set to reflect BAT and provide environmental protection as site specific BAT.


300. Table 34 Footnote (3): For existing plants ≤ 500 MWth put into operation no later than 27 November 2003 using liquid fuels with a nitrogen content higher than 0.6 wt%, the higher end of the BAT-AEL ranges for both the yearly average and daily average/periodic are extended to 380 mg/Nm3. In order for this relaxation to apply both criteria need to be applicable (operation before 27 November 2003 and fuels nitrogen content >0.6 wt%).





Continuous (3)



302. For plant using SNCR or SCR the BAT-AELs for ammonia given in BAT 7 apply, see guidance point Error! Reference source not found. above.





Continuous (3) (4)





305. For guidance on the interpretation of indicative CO levels see section XX.


BAT 57

OFFICAL


BAT 57. In order to reduce SOX, HCl and HF emissions to air from the combustion of process fuels from the chemical industry in boilers, BAT is to use one or a combination of the techniques given below.


a. Fuel choice See descriptions in Section 8.4 Applicable within the constraints associated with the availability of different types of fuel and/or an alternative use of the process fuel

b. Boiler sorbent injection (in-furnace or in-bed)

Applicable to existing combustion plants within the constraints associated with duct configuration, space availability and chemical installation safety.

Wet FGD and seawater FGD are not applicable to combustion plants operated <500 h/yr.

There may be technical and economic restrictions for applying wet FGD or seawater FGD to combustion plants of <300 MWth, and for retrofitting combustion plants operated between 500 h/yr and 1500 h/yr with wet FGD or seawater FGD

c. Duct sorbent injection (DSI)

d. Spray dry absorber (SDA)

e. Wet scrubbing See description in Section 8.4.

Wet scrubbing is used to remove HCl and HF when no wet FGD is used to reduce SOX emissions

f. Wet flue-gas desulphurisation

(wet FGD)


g. Seawater FGD

Table 35: BAT associated emission levels (BAT-AELs) for SO2 emissions to air from the combustion of 100 % process fuels from the chemical industry in boilers

Type of combustion plant BAT-AELs for SO2 (mg/Nm3)

Yearly average (1) Daily average or average over the sampling period (2)

New and existing boilers 10–110 90–200

(1) For existing plants operated <1500 h/yr, these BAT-AELs do not apply.

(2) For existing plants operated <500 h/yr, these levels are indicative

Table 36: BAT associated emission levels (BAT-AELs) for HCl and HF emissions to air from the combustion of process fuels from the chemical industry in boilers


(MWth)

BAT-AELs (mg/Nm3)

HCl HF

Average of samples obtained during one year


<100 1–7 2–15 (2) <1–3 <1–6 (3)

≥100 1–5 1–9 (2) <1–2 <1–3 (3)

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(2) In the case of plants operated <1500 h/yr, the higher end of the BAT-AEL range is 20 mg/Nm3.

(3) In the case of plants operated <1500 h/yr, the higher end of the BAT-AEL range is 7 mg/Nm3.

GUIDANCE


307. BAT 57 only applies to the combustion of process fuels in the chemical industry in boilers (and not other forms of combustion appliance). A boiler is defined as “any combustion plant with the exception of engines, gas turbines, and process furnaces or heaters”.


approach set out in IED Article 40 for BAT-AELs that apply to 100% process fuels.

309. The BAT-AELs contained in Table 36 apply to the combustion of any process fuels from the chemical industry in boilers i.e. process fuels combusted on their own or in mixtures with other fuels without adjustment.

310. Unless indicated otherwise, ELVs reflecting both a yearly average and a daily average/periodic will be included in permits.

311. Table 35 Footnote (1): The yearly average BAT-AELs for SO2 do not apply to existing plants operated < 1500 h/yr. Daily/periodic BAT-AELs for SO2 still apply, subject to footnote (2).


313. Table 10 Footnote (2): The daily or periodic BAT-AEL for SO2 are only indicative for existing plant operating <500 h/yr. Where this footnote is applied, a BAT demonstration that the plant is operating to BAT may still be required and emission limit values may still be set to reflect BAT and provide environmental protection as site specific BAT





All sizes Generic EN standards(1) and EN 14791

Continuous (3) (8) (9)



(8) As an alternative to the continuous measurement in the case of plants combusting oil with a known sulphur content and where there is no flue- gas desulphurisation system, periodic measurements at least once every three months and/or other procedures ensuring the provision of data of an equivalent scientific quality may be used to determine the SO2 emissions.

(9) In the case of process fuels from the chemical industry, the monitoring frequency may be adjusted for plants of < 100 MWth after an initial characterisation of the fuel (see BAT 5) based on an assessment of the relevance of pollutant releases (e.g. concentration in fuel, flue-gas treatment employed) in the emissions to air, but in any case at least each time that a change of the fuel characteristics may have an impact on the emissions.

OFFICAL


316. Other procedures for the provision of data of an equivalent scientific quality are documented in guidance paragraph XX and in other Regulator guidance[20].

317. Footnote (9) needs to be considered alongside the stated approach to defining when fuel concentration values are considered to be sufficiently stable to allow certain relaxation in monitoring requirements. This is discussed in guidance point XX above. This guidance also addresses when monitoring may be required on a change of the fuel characteristics that may have an impact on the emissions.

318. Table 36 Footnote (1): The BAT-AELs for HCl & HF are only indicative for existing plant combusting process fuels from the chemical industry in boilers operating <500 h/yr. Where this footnote is applied, a BAT demonstration that the plant is operating to BAT may still be required and emission limit values may still be set to reflect BAT and provide environmental protection as site specific BAT.

319. Where this BAT-AEL for HCL applies, the corresponding monitoring requirement is:



All sizes EN 1911 Once every three months (3) (10) (11)


(10) If the emission levels are proven to be sufficiently stable, periodic measurements may be carried out each time that a change of the fuel and/or waste characteristics may have an impact on the emissions, but in any case at least once every year.

(11) In the case of process fuels from the chemical industry, the monitoring frequency may be adjusted after an initial characterisation of the fuel (see BAT 5) based on an assessment of the relevance of pollutant releases (e.g. concentration in fuel, flue-gas treatment employed) in the emissions to air, but in any case at least each time that a change of the fuel characteristics may have an impact on the emissions.


“sufficiently stable”.

321. Footnote (11) needs to be considered alongside the stated approach to defining when

fuel concentration values are considered to be sufficiently stable to allow certain

relaxation in monitoring requirements. This is discussed in guidance point XX above.

This guidance also addresses when monitoring may be required on a change of the fuel

characteristics that may have an impact on the emissions.

322. Where this BAT-AEL for HF applies, the corresponding monitoring requirement is:




Once every three months (3) (10) (11)



(11) In the case of process fuels from the chemical industry, the monitoring frequency may be adjusted after an initial characterisation of the fuel (see BAT 5) based on an assessment of the relevance of pollutant releases (e.g. concentration in fuel, flue-gas treatment employed) in the emissions to air, but in any case at least each time that a change of the fuel characteristics may have an impact on the emissions.

OFFICAL



324. Footnote (11) needs to be considered alongside the stated approach to defining when

fuel concentration values are considered to be sufficiently stable to allow certain

relaxation in monitoring requirements. This is discussed in guidance point XX above.

This guidance also addresses when monitoring may be required on a change of the fuel

characteristics that may have an impact on the emissions.


BAT 58

BAT 58. In order to reduce emissions to air of dust, particulate-bound metals, and trace species from the combustion of process fuels from the chemical industry in boilers, BAT is to use one or a combination of the techniques given below.



See descriptions in Section 8.5 Generally applicable

b. Bag filter

c. Fuel choice See description in Section 8.5.

Use of a combination of process fuels from the chemical industry and auxiliary fuels with a low averaged dust or ash content

Applicable within the constraints associated with the availability of different types of fuel and/or an alternative use of the process fuel

d. Dry or semi-dry FGD system See descriptions in Section 8.5.




Table 37: BAT associated emission levels (BAT-AELs) for dust emissions to air from the combustion of mixtures of gases and liquids composed of 100 % process fuels from the chemical industry in boilers


(MWth)




< 300 2–5 2–15 2–10 2–22 (3)

≥ 300 2–5 2–10 (4) 2–10 2–11 (3)

OFFICAL


(1) For plants operated <1 500 h/yr, these BAT-AELs do not apply.


(3) For plants put into operation no later than 7 January 2014, the higher end of the BAT-AEL range is 25 mg/Nm3.

(4) For plants put into operation no later than 7 January 2014, the higher end of the BAT-AEL range is 15 mg/Nm3.

GUIDANCE


326. BAT XX applies to the combustion of any process fuels individually or in combination with other fuels in the chemical industry in boilers. A boiler being defined as ”Any combustion plant with the exception of engines, gas turbines, and process furnaces or heaters”.


approach set out in IED Article 40 for BAT-AELs that apply to 100% process fuels.

328. Table 37 Footnote (1): The yearly average BAT-AELs for dust do not apply to existing plants operated <1500 h/yr. Daily/periodic BAT-AELs for dust still apply, subject to footnote (2).


330. Table 10 Footnote (2): The daily or periodic BAT-AELs for dust are indicative for existing plant operating <500 h/yr.






Continuous (3)



5.1.6 EMISSIONS OF VOLATILE ORGANIC COMPOUNDS AND POLYCHLORINATED DIBENZO-DIOXINS AND -FURANS TO AIR

BAT 59

BAT 59. In order to reduce emissions to air of volatile organic compounds and polychlorinated dibenzo-dioxins and -furans from the combustion of process

OFFICAL


fuels from the chemical industry in boilers, BAT is to use one or a combination of the techniques given in BAT 6 and below.


a. Activated carbon injection See description in Section 8.5 Only applicable to combustion plants using fuels derived from chemical processes involving chlorinated substances.

For the applicability of SCR and rapid quenching see BAT 56 and BAT 57

b. Rapid quenching using wet scrubbing/flue-gas condenser

See description of wet scrubbing/flue-gas condenser in Section 8.4



The SCR system is adapted and larger than an SCR system only used for NOX reduction

Table 38: BAT associated emission levels (BAT-AELs) for PCDD/F and TVOC emissions to air from the combustion of 100 % process fuels from the chemical industry in boilers

Pollutant Unit BAT-AELs Average over the sampling period

PCDD/F(1) ng I-TEQ/Nm3 < 0.012–0.036

TVOC mg/Nm3 0.6–12

(1) These BAT-AELs only apply to plants using fuels derived from chemical processes involving chlorinated substances.

GUIDANCE


334. The techniques specified in BAT 59 apply to the combustion of any process fuels individually or in combination with other fuels in the chemical industry in boilers. A boiler being defined as “Any combustion plant with the exception of engines, gas turbines, and process furnaces or heaters”.


approach set out in IED Article 40 for BAT-AELs that apply to 100% process fuels in

Table 38.

336. The BAT-AELs only apply to plant using fuels derived from chemical processes involving chlorinated substances. Whether these BAT-AELs apply or not may be demonstrated through the fuel characterisation carried out under BAT 9. Table 1 footnote 22 suggests that no de-minimis values apply. A reasoned justification on a case by case basis is required to confirm that fuels do not contain chlorinated substances.

337. Where this BAT-AEL for PCDD/F applies, the corresponding monitoring requirement is:



All sizes EN 1948-1, EN 1948-2, EN

Once every six months (10) (22)

OFFICAL


1948-3


(22) In the case of process fuels from the chemical industry, monitoring is only applicable when the fuels contain chlorinated substances.


339. See guidance point XX above on the applicability of monitoring to fuels containing chlorinated substances.

OFFICAL


6 BAT CONCLUSIONS FOR THE CO-INCINERATION OF WASTE

Unless otherwise stated, the BAT conclusions presented in this section are generally applicable to the co-incineration of waste in combustion plants. They apply in addition to the general BAT conclusions given in Section 1.

When waste is co-incinerated, the BAT-AELs in this section apply to the entire flue-gas volume generated.

In addition, when waste is co-incinerated together with the fuels covered by Section 2, the BAT-AELs set out in Section 2 also apply (i) to the entire flue-gas volume generated, and (ii) to the flue-gas volume resulting from the combustion of the fuels covered by that section using the mixing rule formula of Annex VI (part 4) to Directive 2010/75/EU, in which the BAT-AELs for the flue-gas volume resulting from the combustion of waste are to be determined on the basis of BAT 61.

GUIDANCE

340. See also general guidance on scope in section XX above and Annex I and Annex II below.

SIGNIFICANT TEXT AND FLOW CHARTS TO BE ADDED ONCE WI BRef SCOPE AMENDMENTS (ARTICLE 13 Forum) ARE FINALISED

OFFICAL


6.1.1 GENERAL ENVIRONMENTAL PERFORMANCE

BAT 60

BAT 60. In order to improve the general environmental performance of the co-incineration of waste in combustion plants, to ensure stable combustion conditions, and to reduce emissions to air, BAT is to use technique BAT 60 (a) below and a combination of the techniques given in BAT 6 and/or the other techniques below.


a. Waste pre-acceptance and acceptance

Implement a procedure for receiving any waste at the combustion plant according to the corresponding BAT from the Waste Treatment BREF. Acceptance criteria are set for critical parameters such as heating value, and the content of water, ash, chlorine and fluorine, sulphur, nitrogen, PCB, metals (volatile (e.g. Hg, Tl, Pb, Co, Se) and non-volatile (e.g. V, Cu, Cd, Cr, Ni)), phosphorus and alkali (when using animal by-products).

Apply quality assurance systems for each waste load to guarantee the characteristics of the wastes co-incinerated and to control the values of defined critical parameters (e.g. EN 15358 for non-hazardous solid recovered fuel)


b. Waste selection/limitation

Careful selection of waste type and mass flow, together with limiting the percentage of the most polluted waste that can be co-incinerated. Limit the proportion of ash, sulphur, fluorine, mercury and/or chlorine in the waste entering the combustion plant.

Limitation of the amount of waste to be co-incinerated

Applicable within the constraints associated with the waste management policy of the Member State

c. Waste mixing with the main fuel

Effective mixing of waste and the main fuel, as a heterogeneous or poorly mixed fuel stream or an uneven distribution may influence the ignition and combustion in the boiler and should be prevented

Mixing is only possible when the grinding behaviour of the main fuel and waste is similar or when the amount of waste is very small compared to the main fuel

d. Waste drying Pre-drying of the waste before introducing it into the combustion chamber, with a view to maintaining the high performance of the boiler

The applicability may be limited by insufficient recoverable heat from the process, by the required combustion conditions, or by the waste moisture content

e. Waste pre-treatment See techniques described in the Waste Treatment and Waste Incineration BREFs,

See applicability in the Waste Treatment BREF and in the

OFFICAL


including milling, pyrolysis and gasification Waste incineration BREF

GUIDANCE


342. Waste pre-acceptance and acceptance. The Waste Treatment BREF states that BAT for these aspects includes …………????..... The waste characterisation requirements need to be considered alongside the fuel specification monitoring requirements of Section 1.2 above.

343. Waste selection/limitation. The exception relating to the constraints of each Member State’s waste management policy in this context includes considerations relating to……………????.....in England/Wales and requirements of Regulation 28 to 31 of the PPC2012 Regulations in Scotland which require that:

no separately collected waste capable of being recycled is co-incinerated, and

where practicable, no waste including non-ferrous metals or hard plastics is co-incinerated, and

the incineration of waste industrial and automotive batteries is prohibited (subject to specific provisions); and

waste oils having different characteristics are not mixed, and

waste oils are not mixed with other kinds of waste or substances, if such mixing would impede their treatment.

344. These requirements will be reflected in the permits for each relevant installation on a case by case basis.

345. Waste mixing with the main fuel. The caveats included in these BATcs requirements relating to mixing and the grinding behaviour of the main fuel and waste only apply to specific installations where fuel is milled prior to combustion (such as large pulverised fuel boilers).

346. Waste drying. In some cases this can be a key technique for efficiency improvement and the BATcs requirements above should be read alongside the BATcs relating to energy efficiency in section XX. In most cases, a BAT assessment will have already completed on fuel pre-treatment options (see next point below) and this may need to be reviewed in detail in cases where local circumstances regarding waste heat use of changed or fuel mixes and types may have changed since the time of the original assessment.

347. Waste pre-treatment. Waste Treatment and Waste Incineration BREFs note that the following considerations need to be assessed and taken into account……………????...…., including milling, pyrolysis and gasification……????...

BAT 61

BAT 61. In order to prevent increased emissions from the co-incineration of waste in combustion plants, BAT is to take appropriate measures to ensure that the emissions of polluting substances in the part of the flue-gases resulting from waste co-incineration are not higher than those resulting from the application of BAT conclusions for the incineration of waste.

OFFICAL


GUIDANCE

348. See section 6 introductory guidance above.

BAT 62

BAT 62. In order to minimise the impact on residues recycling of the co-incineration of waste in combustion plants, BAT is to maintain a good quality of gypsum, ashes and slags as well as other residues, in line with the requirements set for their recycling when the plant is not co-incinerating waste, by using one or a combination of the techniques given in and/or by restricting the co-incineration to waste fractions with pollutant concentrations similar to those in other combusted fuels.

GUIDANCE

349. The typical “good” quality criteria for the common co-incineration residues (including gypsum, ashes and slags) is presented below. This is based on……????..….

Parameter Flue gas treatment Residues

Others?? Bottom ash Flyash Gypsum

Moisture

Ammonia ??????

Lime content

pH

Etc

…????..…

Etc

350. It will need to be demonstrated that such specifications can be met under normal operating conditions subject to any specific market or site specific considerations that may apply. This should include a comparison to the specification of reside that can be achieved when the plant is not co-incinerating waste. Any restrictions on the co-incineration of waste quantity or types that are required to limit residue pollutant concentrations similar to those in other combusted fuels should be assessed and quantified and may need to be reflected in the permit.


BAT 63

BAT 63. In order to increase the energy efficiency of the co-incineration of waste, BAT is to use an appropriate combination of the techniques given in BAT 12 and BAT 19, depending on the main fuel type used and on the plant configuration.

The BAT associated energy efficiency levels (BAT-AEELs) are given in Table 8 for the co-incineration of waste with biomass and/or peat and in Table 2 for the co-incineration of waste with coal and/or lignite.

Commented [BA8]: Suggested references would be welcome

OFFICAL


GUIDANCE

351. See guidance paragraph Error! Reference source not found. above for the general position for BAT conclusions for associated environmental performance levels and associated energy efficiency levels (AEPLs and AEELs).

352. The requirements of BAT 12 and BAT 19 in section 1.4 need to be addressed. Note that the applicability of the specified techniques may be further restricted depending on the waste co-incineration plant configuration and the types of fuel and waste used. The BAT associated energy efficiency levels (BAT-AEELs) are given in Table 2 and in Table 8 above.

353. The current plant performance should be assessed (noting the definitions and explanations of efficiency calculations presented in section 1.4 above) and compared to the values above. It is important that all relevant caveats included in the footnotes to the specified tables are considered and/or addressed. Section 1.4 above addresses situations where discrepancies are evident.


BAT 64

BAT 64. In order to prevent or reduce NOX emissions to air while limiting CO and N2O emissions from the co-incineration of waste with coal and/or lignite, BAT is to use one or a combination of the techniques given in BAT 20 in section 2.1.3.

GUIDANCE

354. See guidance point 29 in the general considerations section above on how to address BAT requirements for the application of one, or more, of the techniques specified above. This should be applied in addition to the specific guidance on SCR/SNCR applicability in this section.

BAT 65

BAT 65. In order to prevent or reduce NOX emissions to air while limiting CO and N2O emissions from the co-incineration of waste with biomass and/or peat, BAT is to use one or a combination of the techniques given in BAT 24 in section 2.2.4.

GUIDANCE

355. See guidance point 29 in the general considerations section above on how to address BAT requirements for the application of one, or more, of the techniques specified above. This should be applied in addition to the specific guidance on SCR/SNCR applicability in this section.

356. In cases where SNCR (or SCR) is adopted to meet the specified BAT-AELs, a justification of the expected / anticipated emission levels of all of the above pollutants needs to be provided such that, if applicable, the permit ELV can be set to reflect the emission level associated with BAT for each individual plant. .

OFFICAL


357. See guidance points Error! Reference source not found. and Error! Bookmark not defined. on how to address BAT requirements for emissions of ammonia from SNCR/SCR systems (if applicable).

358. See guidance on the techniques to be adopted in relation to BAT 20 and BAT 24 in sections 2.1.3 and 2.2.2 above. BAT-AELs for ammonia for solid fuels (coal and lignite and biomass/peat) plant using SNCR or SCR are given in BAT 7 and guidance point Error! Reference source not found. above.

359. No specific BAT-AELs are adopted for co-incineration systems burning coal/lignite or biomass/peat. As detailed above, the lowest of the following BAT-AEL ranges should therefore be adopted.

For solid fuel co-incineration, the range of BAT-AELs specified in section 2 above; or

Existing ELVs (no backsliding in standards/techniques will be permitted by the UK regulators) - see section 6 above; or

The range of BAT-AELs derived using the mixing rule Annex VI (part 4) of the IED when adopting Cproc values based on the BAT-AELs for each fuel specified in these BATcs and the Cwaste values based on the BAT-AELs from current draft of the Waste Incineration BATcs (repeated in the table below at various oxygen reference conditions). Note that this does not apply to emissions of N2O where the BAT-AEL that should be based only on the range of BAT-AELs specified in section 2 above.

Substance Plant type Daily average BAT-AEL range (mg/Nm3 at 11% Oxygen, dry, STP)

Equivalent BAT AEL range (mg/Nm3 at 6% Oxygen, dry, STP)


NOX New plants (1) 50 – 120 75 - 180 90 - 216

NOX Existing plants (1) 50 – 150 (2) 75 - 225 90 – 270

CO All plants 10 - 50 15 – 75 18 - 90

NH3 All plants (3) 3 - 10 (4) 5 - 15 5 - 18

Notes: (1) The lower end of the BAT-AEL range can be achieved when using SCR. (2) The higher end of the BAT-AEL range is 180 mg/Nm3 (11% oxygen reference) where SCR is not applicable. (3) The lower end of the BAT-AEL range can be achieved when using SCR. (4) For existing plants fitted with SNCR without wet abatement techniques, the higher end of the BAT-AEL

range is 15 mg/Nm3 (11% oxygen reference)


BAT 66

BAT 66. In order to prevent or reduce SOX, HCl and HF emissions to air from the co-incineration of waste with coal and/or lignite, BAT is to use one or a combination of the techniques given in BAT 21.

GUIDANCE

360. See guidance point 29 in the general considerations section above on how to address BAT requirements for the application of one, or more, of the techniques specified above

OFFICAL


BAT 67

BAT 67. In order to prevent or reduce SOX, HCl and HF emissions to air from the co-incineration of waste with biomass and/or peat, BAT is to use one or a combination of the techniques given in BAT 25.

GUIDANCE

361. See guidance point 29 in the general considerations section above on how to address BAT requirements for the application of one, or more, of the techniques specified above. See guidance on the techniques to be adopted in relation to BAT 21 and BAT 25 in sections 2.1.4 and 2.2.3 above.

362. No specific BAT-AELs for these substances are adopted for co-incineration systems burning coal/lignite or biomass/peat. As detailed above, the lowest of the following BAT-AEL ranges should therefore be adopted.

363. For solid fuel co-incineration, the range of BAT-AELs specified in section 2 above; or

364. Existing ELVs (no backsliding in standards/techniques will be permitedpermitted by the UK regulators) - see section 6 above; or

365. The range of BAT-AELs derived using the mixing rule Annex VI (part 4) of the IED when adopting Cproc values based on the BAT-AELs for each fuel specified in these BATcs and the Cwaste values based on the BAT-AELs from current draft of the Waste Incineration BATcs (repeated in the table below at various oxygen reference conditions).

Substance Plant type Daily average BAT-AEL range (mg/Nm3 at 11% Oxygen, dry, STP)



SOx New Plants 10 – 30 15 – 45 18 - 54

Existing Plants 10 - 40 15 – 60 18 - 72

HCl New Plants(1) 2 – 6 3 – 9 4 - 11

Existing Plants(1) 2 - 8 3 – 12 4 - 14

HF All plants <1 <2 <2

Notes: (1) The lower end of the BAT-AEL range can be achieved when using a wet scrubber; the higher

end of the range may be associated with the use of dry sorbent injection.


BAT 68

BAT 68. In order to reduce dust and particulate-bound metal emissions to air from the co-incineration of waste with coal and/or lignite, BAT is to use one or a combination of the techniques given in BAT 22.

Table 39: BAT associated emission levels (BAT-AELs) for metal emissions to air from the co-incineration of waste with coal and/or lignite

OFFICAL



(MWth)

BAT-AELs Averaging period

Sb+As+Pb+Cr+Co+Cu+Mn+Ni+V

(mg/Nm3)

Cd+Tl

(μg/Nm3)

<300 0.005–0.5 5–12 Average over the sampling period

≥300 0.005–0.2 5–6 Average of samples obtained during one year

GUIDANCE

366. See guidance on the techniques to be adopted in relation to BAT 22 in section 2.1.5 above. See guidance point 29 in the general considerations section above on how to address BAT requirements for the application of one, or more, of the techniques specified above.

367. There are no specific BAT-AELs for dust from co-incineration with coal/lignite detailed in this section. As detailed above, the lowest of the following BAT-AEL ranges should therefore be adopted.

For coal/lignite co-incineration, the range of BAT-AELs specified in section 2 above; or


The range of BAT-AELs derived using the mixing rule Annex VI (part 4) of the IED when adopting Cproc values based on the BAT-AELs for each fuel specified in these BATcs and the Cwaste values based on the BAT-AELs from current draft of the Waste Incineration BATcs (repeated in the table below at various oxygen reference conditions).

Substance Daily average BAT-AEL range (mg/Nm3 at 11% Oxygen, dry, STP)



Dust 2 – 5 (1) 3 - 8 4 - 9

Notes: (1) The higher end of the BAT-AEL range is 7 mg/Nm3 (11% oxygen reference conditions) for existing plants

where a bag filter is not applicable.

368. The BAT-AELs for heavy metal emissions should be adopted in accordance with the generic guidance in section 6. As specified above, the lowest of the following BAT-AEL ranges should therefore be adopted.


Existing ELVs (no reduction/diminution in standards/techniques will be permited by the UK regulators) - see section 6 above; or

The BAT-AELs above (Table 39) for heavy metals and for Cd & Tl emissions from coal or lignite firing; or

For heavy metals, the range of BAT-AELs based on BAT-AELs form the Waste Incineration BATcs summarised below (with no mixing rule adjustment).

Substance BAT-AEL range (mg/Nm3 at 11% Oxygen, dry,

Equivalent BAT AEL range (mg/Nm3 at 6%

Equivalent BAT AEL range (mg/Nm3 at 3%

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STP) (1) Oxygen, dry, STP) Oxygen, dry, STP)

Sb+As+Pb+Cr+Co+Cu+Mn+Ni+V 0.01 – 0.02 0.015 – 0.04 0.018 – 0.036

Cd and Tl 0.05 - 0.3 0.075 – 0.45 0.09 – 0.54

Notes:

(1) For heavy metal emissions the ELV is specified as an average over the sampling period .

BAT 69

BAT 69. In order to reduce dust and particulate-bound metal emissions to air from the co-incineration of waste with biomass and/or peat, BAT is to use one or a combination of the techniques given in BAT 26.

Table 40: BAT associated emission levels (BAT-AELs) for metal emissions to air from the co-incineration of waste with biomass and/or peat

BAT-AELs (average of samples obtained during one year)

Sb+As+Pb+Cr+Co+Cu+Mn+Ni+V (mg/Nm3) Cd+Tl (μg/Nm3)

0.075–0.3 <5

GUIDANCE

369. See guidance on the techniques to be adopted in relation to BAT 26 above. See guidance point 29 in the general considerations section above on how to address BAT requirements for the application of one, or more, of the techniques specified above.

370. There are no specific BAT-AELs for dust from co-incineration with biomass/peat detailed in this section. As detailed above, the lowest of the following BAT-AEL ranges for dust from biomass/peat firing should therefore be adopted:

for biomass/peat co-incineration, the range of BAT-AELs specified in section 2 above; or

existing ELVs (no backsliding in standards/techniques will be permitted by the UK regulators) - see section 6 above; or

the range of BAT-AELs derived using the mixing rule Annex VI (part 4) of the IED when adopting Cproc values based on the BAT-AELs for each fuel specified in these BATcs and the Cwaste values based on the BAT-AELs from current draft of the Waste Incineration BATcs (repeated in the table below at various oxygen reference conditions).

Substance Daily average BAT-AEL range (mg/Nm3 at 11% Oxygen, dry, STP)



Dust 2 – 5 (1) 3 - 8 4 - 9

Notes:

(1) The higher end of the BAT-AEL range is 7 mg/Nm3 (11% oxygen reference conditions)for existing plants where a bag filter is not applicable..

371. For heavy metal emissions, the BAT-AELs should be adopted in accordance with the generic guidance in section 6. As specified above, the lowest of the following BAT-AELs should therefore be adopted:

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for biomass/peat co-incineration, the range of BAT-AELs specified in section 2 above; or


the BAT-AELs above (Table 40) for heavy metals and for Cd & Tl emissions from biomass/peat; or

for heavy metals, the range of BAT-AELs based on BAT-AELs from the Waste Incineration BATcs summarised below (with no mixing rule adjustment).

Substance BAT AEL range (at 11% Oxygen, dry, STP) (1)

Equivalent BAT AEL range (at 6% Oxygen, dry, STP)

Equivalent BAT AEL range (at 3% Oxygen, dry, STP)

Sb+As+Pb+Cr+

Co+Cu+Mn+Ni+V

0.05 – 0.3 mg/Nm3 0.08 – 0.45 mg/Nm3 0.09 – 0.54 mg/Nm3

Cd and Tl 10 – 20 µg/Nm3 15 – 30 µg/Nm3 18 – 36 µg/Nm3

Notes:

(1) For heavy metal emissions the ELV is specified as an average over the sampling period.


BAT 70

BAT 70. In order to reduce mercury emissions to air from the co-incineration of waste with biomass, peat, coal and/or lignite, BAT is to use one or a combination of the techniques given in BAT 23 and BAT 27.

GUIDANCE

372. See guidance on the techniques to be adopted in relation to BAT 23 and BAT 27 in sections 2.1.6 and 2.2.5 above. See guidance point 29 in the general considerations section above on how to address BAT requirements for the application of one, or more, of the techniques specified above.

373. There are no specific BAT-AELs for mercury emissions from co-incineration with coal/lignite or biomass/peat detailed in this section. As detailed above, the lowest of the following BAT-AEL ranges for Hg should therefore be adopted:

the range of BAT-AELs specified in section 2 above; or


the range of BAT-AELs from current draft of the Waste Incineration BATcs with no mixing rule adjustment (repeated in the table below at various oxygen reference conditions).

Substance Plant Type

BAT-AEL range (µg/Nm3 at 11% Oxygen, dry, STP)(1)(2)

Equivalent BAT AEL range (µg/Nm3 at 6% Oxygen, dry, STP)

Equivalent BAT AEL range (µg/Nm3 at 3% Oxygen, dry, STP)

Hg New 5 - 20 8 - 30 9 – 36

Existing 5 - 25 8 – 38 9 – 45

Notes: (1) Daily average, Long-term sampling average, or Average over the sampling period

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(2) The lower end of the BAT-AEL ranges can be achieved when using fixed-bed adsorption or a wet scrubber enhanced with the use of oxidants; the higher end of the BAT-AEL ranges can be achieved when using dry sorbent injection.

374. Note that the sampling average period is not simply specified as “average of the sample period). In this case several options are given. However, in order to minimise the administrative burden on operators and Regulators alike, the UK regulators will adopt the approach of requiring compliance with permit ELVs that are based on the BAT-AEL ranges derived above based only as an average over the sample period (as for current permit compliance requirements)[22].

6.1.7 EMISSIONS OF VOLATILE ORGANIC COMPOUNDS AND POLYCHLORINATED DIBENZO-DIOXINS AND -FURANS TO AIR

BAT 71

BAT 71. In order to reduce emissions of volatile organic compounds and polychlorinated dibenzo-dioxins and -furans to air from the co-incineration of waste with biomass, peat, coal and/or lignite, BAT is to use a combination of the techniques given in BAT 6, BAT 26 and below.


a. Activated carbon injection See description in Section 8.5.

This process is based on the adsorption of pollutant molecules by the activated carbon


b. Rapid quenching using wet scrubbing/flue-gas condenser

See description of wet scrubbing/flue-gas condenser in Section 8.4



The SCR system is adapted and larger than an SCR system only used for NOX reduction

See applicability in BAT 20 and in BAT 24

Table 41: BAT associated emission levels (BAT-AELs) for PCDD/F and TVOC emissions to air from the co-incineration of waste with biomass, peat, coal and/or lignite

Type of combustion plant

BAT-AELs

PCDD/F (ng I-TEQ/Nm3) TVOC (mg/Nm3)


Yearly average Daily average

Biomass-, peat-, coal- and/or lignite-fired combustion plant

<0.01–0.03 <0.1–5 0.5–10

GUIDANCE

22 As specified in BAT 27 for mercury emissions from biomass/peat combustion

Commented [BA9]: To be confirmed

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375. See guidance on the techniques to be adopted in relation to BAT 6 and BAT 26 in sections 1.3 and 2.2.4 above. Further guidance on the applicability of SCR techniques given in BAT 20 and BAT 24 in sections 2.1.3 and 2.2.2 above. See guidance point 29 in the general considerations section above on how to address BAT requirements for the application of one, or more, of the techniques specified above.

376. For biomass/peat and coal/lignite waste co-incineration, for PCDD/F and PCDD/F + dioxin like PCBs, as specified above, the lowest of the following BAT-AEL ranges should be adopted.



The BAT-AELs above (Table 41); or

For PCDD/F and PCDD/F + dioxin like PCBs, the range of BAT-AELs specified in the Waste Incineration BATcs as summarised below (with no mixing rule adjustment).

Substance Plant Type BAT-AEL range (ng/Nm3 at 11% Oxygen, dry, STP)(1)(2)

Equivalent BAT-AEL range (ng/Nm3 at 6% Oxygen, dry, STP)


PCDD/F

(ng I-TEQ/Nm3)

New < 0.01 – 0.04 <0.015 – 0.06 <0.018 – 0.072

Existing < 0.01 – 0.06 <0.015 – 0.09 <0.018 – 0.108

PCDD/F + dioxin-like PCBs

(ng WHO-TEQ/Nm3)

New <0.01 – 0.06 <0.015 – 0.09 <0.018 – 0.108

Existing < 0.01 – 0.08 <0.015 – 0.12 <0.018 – 0.144

Notes: 1 For PCDD/F emissions, the BAT-AEL range is specified as an average over the sampling

period or long term sampling average. 2 Either the BAT-AEL for PCDD/F or the BAT-AEL for PCDD/F + dioxin-like PCBs applies

377. Qualifications provided to these BAT AELs note that either the BAT-AEL for PCDD/F or the BAT-AEL for PCDD/F + dioxin-like PCBs applies. In the UK, Regulators have determined that operators can opt to specify which ELV will apply. However, it should be noted that the existing requirements for monitoring of dioxin-like PCBs (imposed directly by Regulation) will still apply, if applicable).

378. Note that the sampling average period is not simply specified as “average of the sample period”. In this case, another option is given to apply the BAT-AEL over a long-term sampling average. However, in order to minimise the administrative burden on operators and Regulators alike, the UK regulators will adopt the approach of requiring compliance with permit ELVs that are based on the BAT-AEL ranges derived above based only as an average over the sample period (as for current permit compliance requirements).

379. For VOCs, as specified above, the lowest of the following BAT-AEL ranges should be adopted.


Commented [BA10]: UK Regulators may opt to impose both limits as a matter of course as existing provisions for PCB like dioxins still apply

Commented [BA11]: In Scotland this is Regulation 29(2) of the PPC 2012 Regulations

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The BAT-AELs above (Table 41); or

The range of BAT-AELs derived using the mixing rule Annex VI (part 4) of the IED when adopting Cproc values based on the BAT-AELs for each fuel specified in these BATcs and the Cwaste values based on the Waste Incineration BATcs (repeated in the table below).

Substance Plant Type Daily Average BAT-AEL range (ng/Nm3 at 11% Oxygen, dry, STP)(1)(2)



VOCs New and existing

3 - 10 5 - 15 6 - 18

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7 BAT CONCLUSIONS FOR GASIFICATION

Unless otherwise stated, the BAT conclusions presented in this section are generally applicable to all gasification plants directly associated to combustion plants, and to IGCC plants. They apply in addition to the general BAT conclusions given in Section 1.


BAT 72

BAT 72. In order to increase the energy efficiency of IGCC and gasification units, BAT is to use one or a combination of the techniques given in BAT 12 and below.


a. Heat recovery from the gasification process

As the syngas needs to be cooled down to be cleaned further, energy can be recovered for producing additional steam to be added to the steam turbine cycle, enabling additional electrical power to be produced

Only applicable to IGCC units and to gasification units directly associated to boilers with syngas pretreatment that requires cooling down of the syngas

b. Integration of gasification and combustion processes

The unit can be designed with full integration of the air supply unit (ASU) and the gas turbine, with all the air fed to the ASU being supplied (extracted) from the gas turbine compressor

The applicability is limited to IGCC units by the flexibility needs of the integrated plant to quickly provide the grid with electricity when renewable power plants are not available

c. Dry feedstock feeding system

Use of a dry system for feeding the fuel to the gasifier, in order to improve the energy efficiency of the gasification process

Only applicable to new units

d. High-temperature and -pressure gasification

Use of gasification technique with high-temperature and -pressure operating parameters, in order to maximise the efficiency of energy conversion

Only applicable to new units

e. Design improvements Design improvements, such as:

modifications of the gasifier refractory and/or cooling system;

installation of an expander to recover energy from the syngas pressure drop before combustion

Generally applicable to IGCC units

Table 42: BAT associated energy efficiency levels (BAT-AEELs) for gasification and IGCC units

Type of combustion unit configuration

BAT-AEELs

Net electrical efficiency (%) of an Net total fuel utilisation (%) of a new or

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IGCC unit existing gasification unit

New unit New unit

Gasification unit directly associated to a boiler without prior syngas treatment

No BAT-AEEL >98

Gasification unit directly associated to a boiler with prior syngas treatment

No BAT-AEEL >91

IGCC unit No BAT-AEEL 34–46 >91

GUIDANCE




BAT 73

BAT 73. In order to prevent and/or reduce NOX emissions to air while limiting CO emissions to air from IGCC plants, BAT is to use one or a combination of the techniques given below.


a. Combustion optimisation See description in Section 8.3 Generally applicable

b. Water/steam addition See description in Section 8.3.

Some intermediate-pressure steam from the steam turbine is reused for this purpose

Only applicable to the gas turbine part of the IGCC plant.

The applicability may be limited due to water availability

c. Dry low-NOX burners (DLN)

See description in Section 8.3 Only applicable to the gas turbine part of the IGCC plant.

Generally applicable to new IGCC plants.

Applicable on a case-by-case basis for existing IGCC plants, depending on the availability of a retrofit package. Not applicable for syngas with a hydrogen content of >15%

d. Syngas dilution with waste nitrogen from the air supply unit (ASU)

The ASU separates the oxygen from the nitrogen in the air, in order to supply high-quality oxygen to the gasifier. The waste nitrogen from the

Only applicable when an ASU is used for the gasification process

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ASU is reused to reduce the combustion temperature in the gas turbine, by being premixed with the syngas before combustion

e. Selective catalytic reduction (SCR)

See description in Section 8.3 Not applicable to IGCC plants operated <500 h/yr.

Retrofitting existing IGCC plants may be constrained by the availability of sufficient space.

There may be technical and economic restrictions for retrofitting existing IGCC plants operated between 500 h/yr and 1500 h/yr

Table 43: BAT associated emission levels (BAT-AELs) for NOX emissions to air from IGCC plants

IGCC plant total rated thermal input

(MWth)

BAT-AELs (mg/Nm3)


New plant Existing plant New plant Existing plant

≥ 100 10–25 12–45 1–35 1–60

As an indication, the yearly average CO emission levels for existing plants operated ≥1500 h/yr and for new plants will generally be < 5–30 mg/Nm3.

GUIDANCE



384. Summary of Monitoring requirements from BAT 4

7.1.3 SOX EMISSIONS TO AIR

BAT 74

BAT 74. In order to reduce SOX emissions to air from IGCC plants, BAT is to use the technique given below.


a. Acid gas removal Sulphur compounds from the feedstock of a gasification process are removed from the syngas via acid gas removal, e.g. including a

The applicability may be limited in the case of biomass IGCC plants due to the very low sulphur content

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COS (and HCN) hydrolysis reactor and the absorption of H2S using a solvent such as methyl diethanolamine. Sulphur is then recovered as either liquid or solid elemental sulphur (e.g. through a Claus unit), or as sulphuric acid, depending on market demands

in biomass

The BAT associated emission level (BAT-AEL) for SO2 emissions to air from IGCC plants of ≥100 MWth is 3–16 mg/Nm3, expressed as a yearly average.

GUIDANCE

385. Summary of Monitoring requirements from BAT 4

7.1.4 DUST, PARTICULATE-BOUND METAL, AMMONIA AND HALOGEN EMISSIONS TO AIR

BAT 75

BAT 75. In order to prevent or reduce dust, particulate-bound metal, ammonia and halogen emissions to air from IGCC plants, BAT is to use one or a combination of the techniques given below.


a. Syngas filtration Dedusting using fly ash cyclones, bag filters, ESPs and/or candle filters to remove fly ash and unconverted carbon. Bag filters and ESPs are used in the case of syngas temperatures up to 400 °C


b. Syngas tars and ashes recirculation to the gasifier

Tars and ashes with a high carbon content generated in the raw syngas are separated in cyclones and recirculated to the gasifier, in the case of a low syngas temperature at the gasifier outlet (< 1100 °C)

c. Syngas washing Syngas passes through a water scrubber, downstream of other dedusting technique(s), where chlorides, ammonia, particles and halides are separated

Table 44: BAT associated emission levels (BAT-AELs) for dust and particulate-bound metal emissions to air from IGCC plants

IGCC plant total rated thermal input

(MWth)

BAT-AELs

Sb+As+Pb+Cr+Co+ Cu+Mn+Ni+V (mg/Nm3)

(Average over the sampling period)

Hg (μg/Nm3)

(Average over the sampling period)

Dust (mg/Nm3)

(yearly average)

≥ 100 < 0.025 < 1 < 2.5

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GUIDANCE

386. Summary of Monitoring requirements from BAT 4 including provision for annual mercury monitoring even though no BAT-AEL is set


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8 DESCRIPTION OF TECHNIQUES

GUIDANCE


8.1 GENERAL TECHNIQUES

Technique Description

Advanced control system The use of a computer-based automatic system to control the combustion efficiency and support the prevention and/or reduction of emissions. This also includes the use of high-performance monitoring.

Combustion optimisation Measures taken to maximise the efficiency of energy conversion, e.g. in the furnace/boiler, while minimising emissions (in particular of CO). This is achieved by a combination of techniques including good design of the combustion equipment, optimisation of the temperature (e.g. efficient mixing of the fuel and combustion air) and residence time in the combustion zone, and use of an advanced control system.

8.2 TECHNIQUES TO INCREASE ENERGY EFFICIENCY


Advanced control system See Section 8.1

CHP readiness The measures taken to allow the later export of a useful quantity of heat to an off -site heat load in a way that will achieve at least a 10% reduction in primary energy usage compared to the separate generation of the heat and power produced. This includes identifying and retaining access to specific points in the steam system from which steam can be extracted, as well as making sufficient space available to allow the later fitting of items such as pipework, heat exchangers , extra water demineralisation capacity, standby boiler plant and back-pressure turbines. Balance of Plant (BoP) systems and control/instrumentation systems are suitable for upgrade. Later connection of back-pressure turbine(s) is also possible.

Combined cycle Combination of two or more thermodynamic cycles, e.g. a Brayton cycle (gas turbine/combustion engine) with a Rankine cycle (steam turbine/boiler), to convert heat loss from the flue-gas of the first cycle to useful energy by subsequent cycle(s).

Combustion optimisation See Section 8.1

Flue-gas condenser A heat exchanger where water is preheated by the flue-gas before it is heated in the steam condenser. The vapour content in the flue-gas thus condenses as it is cooled by the heating water. The flue-gas condenser is used both to increase the

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energy efficiency of the combustion unit and to remove pollutants such as dust, SOX, HCl, and HF from the flue-gas.

Process gas management system

A system that enables the iron and steel process gases that can be used as fuels (e.g. blast furnace, coke oven, basic oxygen furnace gases) to be directed to the combustion plants, depending on the availability of these fuels and on the type of combustion plants in an integrated steelworks.

Supercritical steam conditions

The use of a steam circuit, including steam reheating systems, in which steam can reach pressures above 220.6 bar and temperatures of >540°C.

Ultra-supercritical steam conditions

The use of a steam circuit, including reheat systems, in which steam can reach pressures above 250–300 bar and temperatures above 580–600°C.

Wet stack The design of the stack in order to enable water vapour condensation from the saturated flue-gas and thus to avoid using a flue-gas reheater after the wet FGD.

8.3 TECHNIQUES TO REDUCE EMISSIONS OF NOX AND/OR CO TO AIR


Advanced control system See Section 8.1

Air staging The creation of several combustion zones in the combustion chamber with different oxygen contents for reducing NOX emissions and ensuring optimised combustion. The technique involves a primary combustion zone with sub-stoichiometric firing (i.e. with deficiency of air) and a second reburn combustion zone (running with excess air) to improve combustion. Some old, small boilers may require a capacity reduction to allow the space for air staging.

Combined techniques for NOX and SOX reduction

The use of complex and integrated abatement techniques for combined reduction of NOX, SOX and, often, other pollutants from the flue-gas, e.g. activated carbon and DeSONOX processes. They can be applied either alone or in combination with other primary techniques in coal-fired PC boilers.

Combustion optimisation See Section 8.1

Dry low-NOX burners (DLN) Gas turbine burners that include the premixing of the air and fuel before entering the combustion zone. By mixing air and fuel before combustion, a homogeneous temperature distribution and a lower flame temperature are achieved, resulting in lower NOX emissions.

Flue-gas or exhaust-gas recirculation (FGR/EGR)

Recirculation of part of the flue-gas to the combustion chamber to replace part of the fresh combustion air, with the dual effect of cooling the temperature and limiting the O2 content for nitrogen oxidation, thus limiting the NOX generation. It implies the supply of flue-gas from the furnace into the flame to reduce the oxygen content and therefore the temperature of the flame. The use of special burners or other provisions is based on the internal recirculation of combustion gases which cool the root of the flames and reduce the oxygen content in the hottest part of the flames.

Fuel choice The use of fuel with a low nitrogen content.

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Fuel staging The technique is based on the reduction of the flame temperature or localised hot spots by the creation of several combustion zones in the combustion chamber with different injection levels of fuel and air. The retrofit may be less efficient in smaller plants than in larger plants.

Lean-burn concept and advanced lean-burn concept

The control of the peak flame temperature through lean-burn conditions is the primary combustion approach to limiting NOX formation in gas engines. Lean combustion decreases the fuel to air ratio in the zones where NOX is generated so that the peak flame temperature is less than the stoichiometric adiabatic flame temperature, therefore reducing thermal NOX formation. The optimisation of this concept is called the 'advanced lean-burn concept'.

Low-NOX burners (LNB) The technique (including ultra- or advanced low-NOX burners) is based on the principles of reducing peak flame temperatures; boiler burners are designed to delay but improve the combustion and increase the heat transfer (increased emissivity of the flame). The air/fuel mixing reduces the availability of oxygen and reduces the peak flame temperature, thus retarding the conversion of fuel-bound nitrogen to NOX and the formation of thermal NOX, while maintaining high combustion efficiency. It may be associated with a modified design of the furnace combustion chamber. The design of ultra-low-NOX burners (ULNBs) includes combustion staging (air/fuel) and firebox gases' recirculation (internal flue-gas recirculation). The performance of the technique may be influenced by the boiler design when retrofitting old plants.

Low-NOX combustion concept in diesel engines

The technique consists of a combination of internal engine modifications, e.g. combustion and fuel injection optimisation (the very late fuel injection timing in combination with early inlet air valve closing), turbocharging or Miller cycle.

Oxidation catalysts The use of catalysts (that usually contain precious metals such as palladium or platinum) to oxidise carbon monoxide and unburnt hydrocarbons with oxygen to form CO2 and water vapour.

Reduction of the combustion air temperature

The use of combustion air at ambient temperature. The combustion air is not preheated in a regenerative air preheater.

Selective catalytic reduction (SCR)

Selective reduction of nitrogen oxides with ammonia or urea in the presence of a catalyst. The technique is based on the reduction of NOX to nitrogen in a catalytic bed by reaction with ammonia (in general aqueous solution) at an optimum operating temperature of around 300–450°C. Several layers of catalyst may be applied. A higher NOX reduction is achieved with the use of several catalyst layers. The technique design can be modular, and special catalysts and/or preheating can be used to cope with low loads or with a wide flue-gas temperature window. 'In-duct' or 'slip' SCR is a technique that combines SNCR with downstream SCR which reduces the ammonia slip from the SNCR unit.

Selective non-catalytic reduction (SNCR)

Selective reduction of nitrogen oxides with ammonia or urea without a catalyst. The technique is based on the reduction of NOX to nitrogen by reaction with ammonia or urea at a high temperature. The operating temperature window is maintained between 800°C and 1000°C for optimal reaction.

Water/steam addition Water or steam is used as a diluent for reducing the combustion temperature in gas turbines, engines or boilers and thus the thermal NOX formation. It is either premixed with the fuel prior to its combustion (fuel emulsion, humidification or saturation) or directly injected in the combustion chamber (water/steam injection).

8.4 TECHNIQUES TO REDUCE EMISSIONS OF SOX, HCL AND/OR HF TO AIR

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Boiler sorbent injection (in-furnace or in-bed)

The direct injection of a dry sorbent into the combustion chamber, or the addition of magnesium- or calcium-based adsorbents to the bed of a fluidised bed boiler. The surface of the sorbent particles reacts with the SO2 in the flue-gas or in the fluidised bed boiler. It is mostly used in combination with a dust abatement technique.

Circulating fluidised bed (CFB) dry scrubber

Flue-gas from the boiler air preheater enters the CFB absorber at the bottom and flows vertically upwards through a Venturi section where a solid sorbent and water are injected separately into the flue-gas stream. It is mostly used in combination with a dust abatement technique.

Combined techniques for NOX and SOX reduction

See Section 8.3

Duct sorbent injection (DSI) The injection and dispersion of a dry powder sorbent in the flue-gas stream. The sorbent (e.g. sodium carbonate, sodium bicarbonate, hydrated lime) reacts with acid gases (e.g. the gaseous sulphur species and HCl) to form a solid which is removed with dust abatement techniques (bag filter or electrostatic precipitator). DSI is mostly used in combination with a bag filter.

Flue-gas condenser See Section 8.2

Fuel choice The use of a fuel with a low sulphur, chlorine and/or fluorine content

Process gas management system

See Section 8.2

Seawater FGD A specific non-regenerative type of wet scrubbing using the natural alkalinity of the seawater to absorb the acidic compounds in the flue-gas. Generally requires an upstream abatement of dust.

Spray dry absorber (SDA) A suspension/solution of an alkaline reagent is introduced and dispersed in the flue-gas stream. The material reacts with the gaseous sulphur species to form a solid which is removed with dust abatement techniques (bag filter or electrostatic precipitator). SDA is mostly used in combination with a bag filter.

Wet flue-gas desulphurisation (wet FGD)

Technique or combination of scrubbing techniques by which sulphur oxides are removed from flue-gases through various processes generally involving an alkaline sorbent for capturing gaseous SO2 and transforming it into solids. In the wet scrubbing process, gaseous compounds are dissolved in a suitable liquid (water or alkaline solution). Simultaneous removal of solid and gaseous compounds may be achieved. Downstream of the wet scrubber, the flue-gases are saturated with water and separation of the droplets is required before discharging the flue-gases. The liquid resulting from the wet scrubbing is sent to a waste water treatment plant and the insoluble matter is collected by sedimentation or filtration.

Wet scrubbing Use of a liquid, typically water or an aqueous solution, to capture the acidic compounds from the flue-gas by absorption.

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8.5 TECHNIQUES TO REDUCE EMISSIONS TO AIR OF DUST, METALS INCLUDING MERCURY, AND/OR PCDD/F


Bag filter Bag or fabric filters are constructed from porous woven or felted fabric through which gases are passed to remove particles. The use of a bag filter requires the selection of a fabric suitable for the characteristics of the flue-gas and the maximum operating temperature.

Boiler sorbent injection (in-furnace or in-bed)

See general description in Section 8.4. There are co-benefits in the form of dust and metal emissions reduction.

Carbon sorbent (e.g. activated carbon or halogenated activated carbon) injection in the flue-gas

Mercury and/or PCDD/F adsorption by carbon sorbents, such as (halogenated) activated carbon, with or without chemical treatment. The sorbent injection system can be enhanced by the addition of a supplementary bag filter.

Dry or semi-dry FGD system See general description of each technique (i.e. spray dry absorber (SDA), duct sorben injection (DSI), circulating fluidised bed (CFB) dry scrubber) in Section 8.4. There are co-benefits in the form of dust and metal emissions reduction.

Electrostatic precipitator (ESP)

Electrostatic precipitators operate such that particles are charged and separated under the influence of an electrical field. Electrostatic precipitators are capable of operating under a wide range of conditions. The abatement efficiency typically depends on the number of fields, the residence time (size), catalyst properties, and upstream particle removal devices. ESPs generally include between two and five fields. The most modern (high-performance) ESPs have up to seven fields.

Fuel choice The use of a fuel with a low ash or metals (e.g. mercury) content.

Multicyclones Set of dust control systems, based on centrifugal force, whereby particles are separated from the carrier gas, assembled in one or several enclosures.

Use of halogenated additives in the fuel or injected in the furnace

Addition of halogen compounds (e.g. brominated additives) into the furnace to oxidise elemental mercury into soluble or particulate species, thereby enhancing mercury removal in downstream abatement systems.

Wet flue-gas desulphurisation (wet FGD)

See general description in Section 8.4. There are co-benefits in the form of dust and metals emission reduction.

8.6 TECHNIQUES TO REDUCE EMISSIONS TO WATER


Adsorption on activated carbon

The retention of soluble pollutants on the surface of solid, highly porous particles (the adsorbent). Activated carbon is typically used for the adsorption of organic compounds and mercury.

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Aerobic biological treatment The biological oxidation of dissolved organic pollutants with oxygen using the metabolism of microorganisms. In the presence of dissolved oxygen – injected as air or pure oxygen – the organic components are mineralised into carbon dioxide and water or are transformed into other metabolites and biomass. Under certain conditions, aerobic nitrification also takes place whereby microorganisms oxidise ammonium (NH4

+) to the intermediate nitrite (NO2-), which is then further oxidised

to nitrate (NO3-).

Anoxic/anaerobic biological treatment

The biological reduction of pollutants using the metabolism of microorganisms (e.g. nitrate (NO3

-) is reduced to elemental gaseous nitrogen, oxidised species of mercury are reduced to elemental mercury).

The anoxic/anaerobic treatment of waste water from the use of wet abatement systems is typically carried out in fixed-film bioreactors using activated carbon as a carrier.

The anoxic/anaerobic biological treatment for the removal of mercury is applied in combination with other techniques.

Coagulation and flocculation Coagulation and flocculation are used to separate suspended solids from waste water and are often carried out in successive steps. Coagulation is carried out by adding coagulants with charges opposite to those of the suspended solids. Flocculation is carried out by adding polymers, so that collisions of microfloc particles cause them to bond thereby producing larger flocs.

Crystallisation The removal of ionic pollutants from waste water by crystallising them on a seed material such as sand or minerals, in a fluidised bed process

Filtration The separation of solids from waste water by passing it through a porous medium. It includes different types of techniques, e.g. sand filtration, microfiltration and ultrafiltration.

Flotation The separation of solid or liquid particles from waste water by attaching them to fine gas bubbles, usually air. The buoyant particles accumulate at the water surface and are collected with skimmers.

Ion exchange The retention of ionic pollutants from waste water and their replacement by more acceptable ions using an ion exchange resin. The pollutants are temporarily retained and afterwards released into a regeneration or backwashing liquid.

Neutralisation The adjustment of the pH of the waste water to the neutral pH level (approximately 7) by adding chemicals. Sodium hydroxide (NaOH) or calcium hydroxide (Ca(OH)2) is generally used to increase the pH whereas sulphuric acid (H2SO4), hydrochloric acid (HCl) or carbon dioxide (CO2) is generally used to decrease the pH. The precipitation of some pollutants may occur during neutralisation.

Oil-water separation The removal of free oil from waste water by gravity separation using devices such as the American Petroleum Institute separator, a corrugated plate interceptor, or a parallel plate interceptor. Oil-water separation is normally followed by flotation, supported by coagulation/flocculation. In some cases, emulsion breaking may be needed prior to oil-water separation.

Oxidation The conversion of pollutants by chemical oxidising agents to similar compounds that are less hazardous and/or easier to abate. In the case of waste water from the use of wet abatement systems, air may be used to oxidise sulphite (SO3

2-) to sulphate (SO4

2-).

Precipitation The conversion of dissolved pollutants into insoluble compounds by adding chemical precipitants. The solid precipitates formed are subsequently separated by sedimentation, flotation or filtration. Typical chemicals used for metal

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precipitation are lime, dolomite, sodium hydroxide, sodium carbonate, sodium sulphide and organosulphides. Calcium salts (other than lime) are used to precipitate sulphate or fluoride.

Sedimentation The separation of suspended solids by gravitational settl ing.

Stripping The removal of purgeable pollutants (e.g. ammonia) from waste water by contact with a high flow of a gas current in order to transfer them to the gas phase. The pollutants are removed from the stripping gas in a downstream treatment and may potentially be reused.

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ANNEX 1 - REASONING AND CONSIDERATIONS RELATING TO SPECIFIC GUIDANCE

POSITIONS

Section 1 – Scope and General Considerations

AI.1 IED Article 15(3) of the IED requires that emission limit vales be set to ensure compliance with the BAT conclusions, it goes on to say that different averaging periods may be applied as long as they ensure compliance with the BAT conclusions. Should such an approach be adopted, then the Regulator must assess the results of the emission monitoring at least annually to ensure that the BAT conclusion is met. IED Article 15(3)b allows the use of alternative averaging periods to those specified in the BRef conclusions and the BRef includes an example of how a monthly average could be set as a surrogate for the annual average of hourly values. A study was carried out by the Joint Environmental Programme (JEP) on CCGTs which concluded that a monthly average of 110% of the annual value would ensure compliance. We have considered this but do not support the findings on the grounds that:

The study was based on the average ratio between annual and monthly compliance over a number of CCGTs, some of which would not have been in compliance

The Regulator would be tasked with an annual assessment of ensuring compliance and any non-compliance would then be deemed to be retrospective. Any compliance methodology should transparent.

We therefore conclude that compliance with the annual average should be demonstrated through setting an ELV as the average of the hourly values over the year

Definitions

AI.2 For the purposes of these BATcs, the definitions provided in the BATCs will be used where relevant. Where reference is made to terms that are defined in the IED, the IED definitions will be adopted in preference to any other definitions. This position is important primarily for waste co-incineration issues where some definitions in these BATcs do not match IED definitions.

Coal/Lignite Plants

Basis or 400 mg/Nm3 annual average CO BAT level for coal plant

Reasoning for CO monitoring derogation on coal plant

Section 6 – Co-incineration

389. It should be noted that biomass co-incinerators with a thermal input of less than 50 MW which burn a mixture of wastes( that are subject to the incineration requirements of IED Chapter IV - referred to as Chapter IV wastes) and non-Chapter IV biomass will not fall within the scope of the WI BRef, nor the LCP BRef.

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ANNEX II - PERMITTING GUIDANCE

AII.1 Aggregation rules for LCP capacity determination (section 1 definitions)

insert NRW aggregation slides

AII.1 Environmental Management Systems (Section 1.1)

It is important that the permit decision record addresses how the operator’s management system specifically addresses the requirements listed in guidance point XX above and, if any of the elements listed are not necessary or applicable, that a record is made of this decision, including the reasons.

AII.2 BAT AEL Ranges

AII.3 GT ELV tables (BAT 44)

Include NRW tables

AII.4 Boiler ELV tables (BAT 45)

Include EA tables

AII.? Section 6.1 Co-incineration

390. Where the mixing rule formula is adopted, all emission limit values shall be calculated at a temperature of 273.15 K, a pressure of 101,3 kPa and after correcting for the water vapour content of the waste gases. The mixing rule is based on the weighted heat release rates from the fuels and waste concerned i.e. the proportion of waste to fuel is based on the calorific value of each waste/fuel and not on the mass input rate.

391. The ELVs for Cwaste should be corrected from the 11% oxygen reference conditions specified in the Waste Incineration BATcs to the appropriate reference oxygen content for the main fuel used (either 6% oxygen for solid fuels or 3% for liquid / gaseous fuels) prior to calculation in the mixing rule formula. This avoids have to adjust the calculated overall emission limit values derived by the mixing calculation from a separately calculated oxygen reference condition (also derived from the mixing rule). The BAT-

Commented [BA12]: This could be considered permitting guidance and could be moved to Annex II

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AEL ranges in the WI BATcs have been repeated in each relevant section below and the results corrected to 3% or 6% oxygen for ease of reference.

392. All BAT-AELs in this guidance are expressed on either a daily average or annual average basis. However, it is likely that the BAT-AEL ranges on the Waste Incineration BATcs will be expressed either as a daily average or as an average over a sampling period (for periodic monitored species such as heavy metals) and no annual average values are specified. Therefore, only the daily average values should be used in the mixing rule calculation to derive an appropriate overall daily average emission limit value. Annual average ELVs will be set, but will be based solely on any BAT-AELs expressed as an annual average in these BATcs. In all cases, the annual average BAT AEL ranges should be documented alongside each of the three sets of potential BAT-AEL ranges discussed above. Where average emission limit values are set for heavy metals and dioxins etc these are expressed as an average over a sampling period of a minimum of 30 minutes and a maximum of 8 hours. Note that no mixing rule adjustment is applicable to BAT-AELs for heavy metals and dioxins and the relevant ELV for these substances specified in Waste Incineration BATcs (without adjustment) should be applied.

Commented [BA13]: As these values may change on publication of the WI Bref we could consider removing these tables.

Commented [BA14]: This is the latest SEPA position

LARGE COMBUSTION PLANTS (LCPs) - Environment Agency

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