10 CONCLUSIONS FOR LARGE COMBUSTION PLANTS...

Chapter 10

TL/JFF/EIPPCB/Revised LCP_Draft 1 April 2015 1

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10 BEST AVAILABLE TECHNIQUES (BAT) CONCLUSIONS FOR LARGE COMBUSTION PLANTS

Scope

These BAT conclusions concern the following activities specified in Annex I to

Directive 2010/75/EU, namely:

1.1: Combustion of fuels in installations with a total rated thermal input of 50 MWth

or more, only when this activity takes place in combustion plants with a total rated

thermal input of 50 MWth or more, including plants composed of aggregated units

of 15 MWth or more including plants composed of aggregated units of 15 MWth or

more.

1.4: Gasification of coal or other fuels in installations with a total rated thermal

input of 20 MWth or more, only when this activity is directly associated to a

combustion process.

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 taking

place in combustion plants covered under 1.1 above. with a total rated thermal input

of 50 MWth or more.

In particular, these BAT conclusions cover the following processes and activities:

o combustion;

o gasification associated to a combustion process;

o upstream and downstream activities directly associated to the abovementioned activities

including as well as the emission prevention and control techniques applied.

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

material including:

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

biomass (as defined in Article 3(31) of Directive 2010/75/EU) (e.g. wood, sawdust,

bark, straw) and wood waste not contaminated by halogenated organic compounds

or metals;

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

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

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other industry-specific fuels (production residues and e.g. by-products from

chemical and iron and steel industries);

waste except for excluding unsorted municipal waste.

These BAT conclusions do not address the following activities:

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

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 processesactivities not directly associated to

combustion or gasification processesactivities;

combustion in process furnaces or heaters;

combustion in post-combustion plants;

flaring;

combustion in coke battery ovens;

combustion in cowpers;

combustion in recovery boilers and total reduced sulphur burners within

installations for the production of pulp and paper; this is covered by the BAT

reference document for the Production of Pulp, Paper and Board;

combustion of refinery fuels; this is covered by the BAT reference document for the

Refining of Mineral Oil and Gas;

disposal or recovery of waste in:

o waste incineration plants (as defined in IED Article 3(40) of Directive

2010/75/EU),

o and in waste co-incineration plants where more than 40 % of the resulting

heat release comes from hazardous waste other than combustion plants, and

in

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) (i)

to (iv) of Directive 2010/75/EU;

this is covered by the BAT reference document for Waste Incineration.

Other reference documents which are relevant for the activities covered by these BAT

conclusions are the following:

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Reference document Subject

Common Waste Water and Waste Gas

Treatment/Management Systems in the

Chemical Sector (CWW)

Waste water and chemical waste gas

treatment/management systems

Economic and Cross-Media Effects (ECM) Economic and cross-media effects of techniques

Emissions from Storage BREF (EFS) Storage and handling of fuels and additives (prevention of

unplanned emissions, including to soil and groundwater)

Energy Efficiency BREF (ENE)

GeneralIntegrated energy efficiency at installation level

and energy efficiency in energy-using systems, processes,

activities or equipment

Industrial Cooling Systems BREF (ICS) Indirect cooling with water Cooling systems

Iron and Steel Production (IS) I&SPretreatment of iron and steel process fuelsgases

pretreatment

Chemical BREFs series (LVOC, …) Chemical process fuels pPretreatment of process fuels from

the chemical industry

Monitoring of Emissions to Air and Water

from IED-installations (ROM) General

Principles of Monitoring (MON)

Monitoring of emissions to air and water Emissions and

consumptions monitoring

Waste Incineration (WI) Abatement of pollutants from waste incineration

Waste Treatments Industries (WT) Waste (pre-)acceptance procedures, waste handling /

storage

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.

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Definitions

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

Term used Definition

Combustion plant

Any technical apparatus in which fuels are oxidised in order to use the heat thus

generated, or, where the flue-gases of two or more such apparatuses are mixed,

and then treated before release, the combination formed by such apparatuses. For

the purposes of these BAT conclusions, a combination formed by separate

combustion units discharging their flue-gases through a common stack shall be

considered as a single combustion plant. For calculating the total rated thermal

input of such a combination, the capacities of all combustion units concerned,

which have a rated thermal input of at least 15 MW, shall be added.

New plant

A combustion plant first permitted (pursuant to the provisions in Articles 4 and 5

of Directive 2010/75/EU) at the installation following the publication of these

BAT conclusions or a complete replacement of a combustion plant on the

existing foundations of the installation following the publication of these BAT

conclusions

Existing plant A combustion plant which is not a new plant

Net electrical

efficiency

(combustion plant

and IGCC)

Ratio between the net electrical output (produced electricity produced at

alternator terminals minus imported energy) and the fuel/feedstock energy input

(as the fuel/feedstock lower heating value) at the combustion plant boundaryies

over a given period of time

Net total fuel

utilisation

(combustion plant)

Ratio between the net produced energy (electricity, hot water, steam, mechanical

energy produced minus imported electrical and/or thermal energy) and the fuel

energy input (as the fuel lower heating value) at the combustion power plant

boundaryies over a given period of time

Net total fuel

utilisation

(gasification plant)

Ratio between the net produced energy (electricity, hot water, steam, mechanical

energy produced, syngas (LHV basis) minus imported electrical and/or thermal

energy) and the fuel/feedstock energy input (as the fuel/feedstock lower heating

value) at the gasification plant boundary over a given period of time

Recoverable heat

The difference between the fuel energy input (fuel and imported electrical and

thermal energy for the operation of the combustion plant and its auxiliary

systems) and the sum of net electrical output and net mechanical thermal output.

Net outputs are calculated as gross outputs minus the energy used in the

combustion plant with its auxiliary systems (material unloading/handling, flue-

gas treatment facilities, fans, compressors, etc.).

Residues Substances generated by the activities covered by the scope of this document, as

waste or by-products

Boiler

Any combustion plant with the exception of engines and gas turbines, process

furnaces or heaters. This includes when the HRSG of a CCGT is operated with its

own burners without the gas turbine being in operation (i.e. supplementary firing)

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, CCGT includes configurations both

with and without supplementary firing of the HRSG. Should the supplementary

firing of the HRSG operate alone, the HRSG is then considered to be a boiler

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, chemical

reactor used in the (petro-)chemical industry), or

combustion plants whose radiant and/or conductive heat is transferred to the

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 steam

cracker furnaces).

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It should be noted that, As a consequence of the application of good energy

recovery practices, some of the process heaters / furnaces may have an associated

steam / electricity generation system. This is considered to be an integral design

feature of athe process heater / furnace that cannot be considered in isolation

Post-combustion

plant

System designed to purify the flue-gases by combustion which is not operated as

an independent combustion plant, such as thermal oxidiser equipment (i.e. tail

gas incinerator), used for the removal of pollutant (e.g. VOC) content from the

flue-gas with or without the recovery of the heat generated therein. Staged

combustion techniques, where each stage is confined within a separate chamber,

which may have distinct combustion process characteristics (e.g. fuel / air ratio,

temperature profile), are considered integrated in the combustion process and are

not considered post-combustion plants. Just the same, when gases generated

produced in a process heater / furnace or in another other combustion process

plant 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

Maximum

continuous rating

(MCR)

The maximum output (in MWel or MWth) that a combustion plant is capable of

producing continuously under normal operating conditions over a given period of

time

Emergency-load

plant / mode

Combustion plant operation ing for less than 500 h/yrhours every year for a given

fuel. This mode also includes the situation when a combustion plant uses back-up

fuels alone or simultaneously with the main fuels for less than 500 h/yrhours

every year

Peak-load plant /

mode

Combustion plant operation ing between 500 and 1500 h/yrhours every year for a

given fuel

Mid-merit plant /

mode

Combustion plant operation ing between 1500 and 4000 h/yrhours every year for

a given fuel

Baseload plant /

mode

Combustion plant operation ng for more than 4000 h/yrhours every year for a

given fuel

Equivalent full load

factor

Calculated for a given year as the fuel energy input divided by the total operating

time under normal operating conditions and then divided by the total rated

thermal input of the combustion plant (i.e. the sum of all the combustion units)

Light fuel oil

Gas oil

A group of oil products corresponding to light and middle distillates, which

distillates in the range of approximately 30 ºC to 380 ºC

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 % by volume

(including losses) distils at 250 °C and of which at least 85 % by volume

(including losses) distils at 350 °C by the ASTM D86 method

Heavy fuel oil (HFO)

A mixture of predominantly gas oil and fuel oil which distils in the range of

approximately 380 ºC to 540 ºC.

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 % by volume (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 likewise categorised as a heavy fuel oil

Chemical industry

gaseous and/or liquid

Process fuels from

the chemical industry

The Gaseous and/or liquid by-products and residues generated by the

(petro-)chemical installationsindustry and used as non-commercial fuels in

combustion plants in boilers within the installation itself.

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

CH4 Methane

C3 Hydrocarbons having a carbon number equal to three

C4+ Hydrocarbons having a carbon number of four or greater

CO Carbon monoxide

COD Chemical oxygen demand. Amount of oxygen needed for the total oxidation of

the organic matter to carbon dioxide.

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

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acadmium and its compounds, expressed as Cd;

bthallium and its compounds, expressed as Tl

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-

HCN Hydrogen cyanide

HCl All inorganic gaseous chlorine compounds, chlorides expressed as HCl

HF All inorganic gaseous fluorine compounds, fluorides expressed as HF

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

H2S Hydrogen sulphide

NH3 Ammonia

N2O Dinitrogen monoxide (nitrous oxide)

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

NO2

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

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

PCDD/F Polychlorinated dibenzo-dioxins and -furans

Sulphide, easily

released

The sum of dissolved sulphide and of those undissolved sulphides that are easily

released upon acidification, expressed as S2-

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

SO2 Sulphur dioxide

SO3 Sulphur trioxide

Sulphite Dissolved sulphite, expressed as SO32-

Sulphate Dissolved sulphate, expressed as SO42-

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

a. antimony and its compounds, expressed as Sb;

b. arsenic and its compounds, expressed as As;

c. lead and its compounds, expressed as Pb;

d. chromium and its compounds, expressed as Cr;

e. cobalt and its compounds, expressed as Co;

f. copper and its compounds, expressed as Cu;

g. manganese and its compounds, expressed as Mn;

h. nickel and its compounds, expressed as Ni;

i. vanadium and its compounds, expressed as V;

j. manganese and its compounds, expressed as Mn

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

Continuous

measurement

Measurement using an 'automated measuring system' (AMS) or a 'continuous

emission monitoring system' (CEM) permanently installed on site

Periodic

measurement

Determination of a measurand (a particular quantity subject to measurement) at

specified time intervals using manual or automated reference methods. A

periodic measurement of emissions to air is the average over 3 consecutive

measurements of at least half an hour). A periodic measurement of emissions to

water is a flow-proportional composite sample over 24-hour.

Predictive emissions

monitoring system

(PEMS)

Predictive Emissions Monitoring Systems: 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/fuel ratio)

and fuel or feed quality data (e.g. the Ssulphur content)

Direct discharge Discharge to a receiving water body at the point where the emission leaves the

installation without further downstream treatment

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 of the European Parliament and the Council on industrial emissions

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Valid

(hourly average)

An hourly average is considered valid when there is no maintenance or

malfunction of the automated measuring system

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

Acronyms Definition

AMS Automated measuring system

ASU Air supply unit

BFB(C) Bubbling fluidised bed (combustion)

BFG Blast furnace gas

CCGT Combined cycle gas turbine, with or without supplementary firing

CEM Continuous emission monitoring system

CFB(C) Circulating fluidised bed (combustion)

CHP Combined heat and power

COG Coke oven gas

COS Carbonyl sulphide

DF Pilot fuel ignited

DSI Duct dry sorbent injection

FBC Fluidised bed combustion

FGD Flue-gas desulphurisation

GD Gas diesel

HFO Heavy fuel oil

HRSG Heat recovery steam generator

IGCC Integrated gasification combined cycle plant

LFO Light fuel oil

LHV Lower heating value

LNB Low-NOX burner

NA No BAT-AEL

NC (fuel) Non-conventional (fuel)

ND Not determined

MDEA Methyl diethanolamine

OCGT Open-cycle gas turbine

PC Pulverised combustion

PEMS Predictive emissions monitoring system

PFB(C) Pressurised fluidised bed (combustion)

QA/QC Quality Assurance/Quality Control

SCR Selective catalytic reduction

SDS Flue-gas desulphurisation by using a spray dryer

SG Spark ignited

SNCR Selective non-catalytic reduction

WFGD Wet flue-gas desulphurisation

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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, these BAT conclusions are generally applicable.

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

for emissions to air

Unless stated otherwise, Emission levels associated with the best available techniques (BAT-

AELs) for emissions to air given in these BAT conclusions refer to concentrations, are

expressed: as either mass of emitted substances per volume of waste flue-gas under the

following standard conditions: dry gas, temperature of 273.15 K, pressure of 101.3 kPa (273.15

K, 101.3 kPa), after deduction of water vapour content (dry gas), and expressed in the units

g/Nm3, mg/Nm

3, µg/Nm

3 or ng I-TEQ/Nm

3.

at a standardised O2 content of:

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

table given below.

Activity Oxygen reference conditions Combustion of solid fuels

6 % 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 %

Combustion of liquid and/or gaseous fuels

when taking place in a gas turbine or an

engine 15 %

Combustion in IGCC plants

o 6 % for solid fuels, waste co-incineration, multi-fuel firing of solid fuel with

gaseous and/or liquid fuels;

o 3 % for combustion plants, other than gas turbines and engines combusting

liquid and/or gaseous fuels;

o 15 % for gas turbines and engines combusting liquid and/or gaseous fuels, and

for multi-fuel fired IGCC plants.

without subtraction of uncertainty.

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

ER = 21 – OR

21 – OM × EM

where

ER (mg/Nm3) = emission concentration at the reference oxygen level OR;

OR (vol-%) = reference oxygen level;

EM (mg/Nm3) = measured emission concentration;

OM (vol-%) = measured oxygen level.

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Where emission levels associated with the best available techniques (BAT-AELs) are given for

different averaging periods, all of those BAT-AELs apply.

Unless stated otherwise, BAT-AELs for emissions to water given in these BAT conclusions are

given without subtraction of uncertainty as mass of emitted substances per volume of waste

water, expressed in the units g/l, mg/l or µg/l.

Unless stated otherwise, the techniques identified in these BAT conclusions are generally

applicable.

For averaging periods, the following definitions apply:

Averaging period Definition

Daily average

Emissions to air: maximum over one year of the Averages over a period

of 24 hours of valid hourly averages obtained given by a continuous

measurements

Yearly average Emissions to air: Average over a period of one year of valid hourly

averages obtained by a 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 (for periodic

measurements)

Emissions to air: Average of the values obtained during one year of the

periodic measurements taken with the monitoring frequency set for each

parameter

Emissions to water: average (weighted according to the daily flows)

over one year of the periodic measurements taken with the monitoring

frequency set for the relevant parameter (1) For any parameter where, due to sampling or analytical limitations, 30-minute sampling is inappropriate, a suitable

sampling period is employed.

Emission levels associated with the best available techniques (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

substances per volume of water, and expressed in µg/l, mg/l, or g/l. The BAT-AELs refer to 24-

hour flow-proportional composite samples, taken with the minimum frequency set for the

relevant parameter and under normal operating conditions. Time-proportional sampling can be

used provided that sufficient flow stability is demonstrated.

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 plant's net energy output(s) and the plant's fuel/feedstock energy input.

The net energy output(s) is determined at the combustion, gasification, or IGCC plant

boundaries and for the plant operated at maximum continuous rating (MCR) conditions. In the

case of combined heat and power (CHP) plants, the net total fuel utilisation BAT-AEEL refers

to the combustion plant being operated at full load simultaneously for both heat and power, and

the net electrical efficiency BAT-AEEL refers to the combustion plant generating only

electricity at MCR. The net mechanical energy efficiency refers to the integral (over a given

period of time) of the differential of pressure (in Pascal) multiplied by the corresponding

volumetric flow rate of the gas/liquid (in cubic metre per second) driven.

BAT-AEELs are expressed as a percentage of the fuel/feedstock energy input (as lower heating

value, LHV).

For averaging periods, the following definitions apply:

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Averaging period Definition

Yearly average

For net electrical efficiency: ratio between the net electrical output

(electricity produced at alternator terminals minus imported energy) and

fuel/feedstock energy input (as the fuel/feedstock lower heating value)

at the combustion plant boundary over a period of one year.

For net total fuel utilisation: ratio between the net produced energy

(electricity, hot water, steam, mechanical energy produced minus

imported electrical and/or thermal energy) and fuel energy input (as the

fuel lower heating value) at the combustion plant boundary over a

period of one year

Categorisation of combustion plants according to their total rated thermal input

For the purpose 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 MWth

and lower than 300 MWth.

NOTE to the TWG: whilst cross-references are provided to other parts of this document in

order to aid the work of the TWG, they will not be included in the final BAT conclusions

themselves. Such cross-references are displayed in brackets and italics.

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10.1 General BAT conclusions

Unless otherwise stated, the BAT conclusions presented in this section are generally applicable.

The processfuel-specific BAT conclusions included in Sections 10.2 to 10.7 apply, in addition

to these general BAT conclusions mentioned in this section.

10.1.1 Environmental management systems

BAT 1. In order to improve the overall environmental performance of large combustion

plants, 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 of an environmental policy that includes the continuous improvement of the

installation by the management;

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 efficient process control

(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 reference document on the

General Principles of Monitoring 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 of the EMS and its continuing suitability, adequacy and effectiveness by senior

management;

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 drain-down or cleaning;

(e) designing flexible, self-contained equipment that enables phased

closure;

(f) using biodegradable and recyclable materials where possible;

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ix. application of sectoral benchmarking on a regular basis.

Specifically for this large combustion plants sector, it is also important to consider the following

potential features of the EMS, described in the relevant BAT where appropriate:

x. identify proper risk points for fuels subject to self-ignition and survey accordingly the

fuel storage areas.

xi. quality assurance/quality control programmes to ensure that the characteristics of all

fuels are fully determined and controlled (see BAT 5);

xii. a management plan in order to minimise the occurrence and duration of other than

normal operating condition periods, including start-up and shutdown periods (see BAT 6

and BAT 6 bis).

xiii. a waste management plan to ensure that waste is avoided, prepared for reuse, recycled or

otherwise recovered, including the use of techniques in BAT 13;

xiv. environmental and safety management system to identify and plan to prevent and deal

with 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) due to the risk of self-heating and/or self-ignition of fuel in the storage

and handling activities;

xv. a dust management plan to prevent or where not practicable, to reduce diffuse emissions

from loading, unloading, storage and/or handling of fuels, residues and additives;

xvi. 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 (see techniques in BAT 14);

(c) a protocol for response to noise incidents containing appropriate actions

and timelines;

(d) a review of historic noise incidents, remedies and dissemination of

noise incident knowledge to the affected parties;

xvii. For the combustion 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, remedies and the dissemination to

the affected parties of odour incident knowledge.

Where an assessment shows any of the abovementioned plans 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.

10.1.2 Monitoring

BAT 2. BAT is to monitor emissions to:

a. air, after all the flue-gas treatment steps, and before mixing with

other flue-gases and releasing;

b. water, at the point of discharge,

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for the pollutants given in each BAT-AEL table of these conclusions, with at least the

frequency indicated in the same table 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.

BAT 3. BAT is to monitor the net electrical efficiency and/or the net total fuel

utilisation and/or the net mechanical energy efficiency of the gasification and/or

combustion plants by periodically carrying out performance tests at full load, according to

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. A performance tests is carried out in particular after the commissioning of the

plant 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

plant.

Applicability

Monitoring of the net electrical efficiency applies only to plants generating only power, to CHP

and to IGCC plants. Monitoring of the net total fuel utilisation applies only to plants generating

only heat, to CHP and to gasification plants (including IGCC plants). Monitoring of the net

mechanical drive efficiency only applies to plants used for mechanical drive applications.

In order to ensure general good environmental and combustion performance, BAT is

to monitor the process parameters and the additional environmental parameters given

below.

Parameter Applicability Point of

measurement

Monitoring

frequency

Energy output

(power, heat,

mechanical output)

All combustion

plants

At

plant/installation

boundaries

Continuous

Waste generation All combustion

plants

At

plant/installation

boundaries

Waste water flow All combustion

plants

Before discharge

to receiving

Noise level All combustion

plants

At

plant/installation

boundaries

3 times/yr

Sb, As, Pb, Cr, Co,

Cu, Mn, Ni, V, Cd,

and Tl emissions to

air

Combustion plants

using coal, lignite,

biomass, peat, HFO

After all the flue-

gas treatment,

steps, and before

mixing with other

flue-gases and

releasing

3 times/yr

Zn emissions to air

Combustion plants

co-incinerating

sewage sludges

After all the flue-

gas treatment

steps, and before

mixing with other

flue-gases and

releasing

3 times/yr

N2O emissions to

air

biomass- and peat-

fired CFB boilers

After all the flue-

gas treatment

steps, and before

mixing with other

flue-gases and

releasing

Twice /yr

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{This BAT conclusion is based on information given in Sections 5.1.4.4, 5.5.3.6, 6.1.3.2 and

6.1.3.3}

BAT 3……bis. BAT is to monitor key process parameters relevant for emissions to air and

water including continuous or periodic measurement of flow, oxygen content, and

temperature in the case of flue-gas streams as well as continuous measurement of flow,

pH, and temperature in the case of waste water streams from flue-gas treatment.

BAT 3 ter. …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 use

ISO, national or other international standards that ensure the provision of data of an

equivalent scientific quality.

Substance/

Parameter Fuel/Process

Combustion

plant total

rated thermal

input

Standard(s) (

1)

Minimum

monitoring

frequency

Monitoring

associated

with

NH3 When SCR and/or

SNCR is used All sizes

Generic EN

standards

Continuous

(2) (

3)

BAT 4 bis

NOX

Coal and/or lignite

including waste co-

incineration plants Solid biomass

and/or peat

including waste co-

incineration plants 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

Process fuels from

the chemical

industry in boilers

IGCC plants

All sizes Generic EN

standards

Continuous

(2) (

4)

BAT 19,

BAT 26,

BAT 32,

BAT 36,

BAT 41,

BAT 46, 0,

BAT 48,

BAT 52,

BAT 53,

BAT 65,

BAT 74,

BAT 75,

BAT 83

OCGT on offshore

platforms All sizes EN 14792

At least once

every year

(5)

BAT 60

N2O

Coal and/or lignite

in circulating

fluidised bed boilers

Solid biomass

and/or peat in

circulating fluidised

bed boilers

All sizes EN 21258

At least once

every year

(6)

BAT 19,

BAT 26

CO

Coal and/or lignite

including waste co-

incineration

Solid biomass

and/or peat

including waste co-

incineration

HFO- and/or gas


engines

Gas oil-fired gas


standards

Continuous

(2) (

4)

BAT 19,

BAT 26,

BAT 32,

BAT 37,

BAT 42,

BAT 49,

BAT 54,

BAT 65,

BAT 74,

BAT 75,

BAT 83

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Substance/


Combustion

plant total

rated thermal

input

Standard(s) (

1)

Minimum

monitoring

frequency

Monitoring

associated

with

turbines

Natural gas-fired

boilers, engines, and

turbines

Iron and steel

process gases

Process fuels from

the chemical

industry in boilers

IGCC plants

OCGT on offshore

platforms All sizes EN 15058

At least once

every year

(5)

BAT 61

SO2

Coal and/or lignite

including waste co-

incineration

Solid biomass

and/or peat

including waste co-

incineration

HFO- and/or gas


engines

Iron and steel

process gases

Process fuels from

the chemical

industry in boilers

IGCC plants


standards

Continuous

(2)

BAT 21,

BAT 28,

BAT 33,

BAT 38,

BAT 56,

BAT 66,

BAT 76, 0,

BAT 84

Gas oil-fired gas

turbines All sizes EN 14791

At least once

every three

months (7)

BAT 43

SO3 When SCR is used All sizes

No EN

standard

available

At least once

every year —

HCl

Coal and/or lignite

Process fuels from

the chemical

industry in boilers

All sizes EN 1911

At least once

every three

months (2)

(8)

BAT 21,

BAT 66

Solid biomass

and/or peat All sizes

Generic EN

standards

Continuous

(2) (

9)

BAT 28

Waste co-

incineration in coal,

lignite, solid

biomass and/or peat

combustion plants


standards

Continuous

(9)

BAT 76, 0

HF

Coal and/or lignite

Process fuels from

the chemical

industry in boilers

All sizes

No EN

standard

available

At least once

every three

months (2)

(8)

BAT 21,

BAT 66

Solid biomass

and/or peat All sizes

No EN

standard

available

At least once

every year BAT 28

Waste co-


lignite, solid

biomass and/or peat


standards

Continuous

(9)

BAT 76, 0

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Substance/


Combustion

plant total

rated thermal

input

Standard(s) (

1)

Minimum

monitoring

frequency

Monitoring

associated

with

combustion plants

Dust

Coal and/or lignite

including waste co-

incineration

Solid biomass

and/or peat

including waste co-

incineration

HFO- and/or gas

oil-fired boilers

Iron and steel

process gases

Process fuels from

the chemical

industry in boilers

IGCC plants

All sizes

Generic EN

standards

and

EN 13284-2

Continuous

(2)

BAT 22,

BAT 29,

BAT 34,

BAT 58,

BAT 67,

BAT 78,

BAT 79,

BAT 85

HFO- and/or gas

oil-fired engines All sizes

Generic EN

standards

and

EN 13284-2

Continuous

(7) (

10)

BAT 39

Gas oil-fired gas

turbines All sizes EN 13284-1

At least once

every three

months (7)

—

Metals and

metalloids

except

mercury

(As, Cd, Co,

Cr, Cu, Mn,

Ni, Pb, Sb,

Se, Tl, V,

Zn)

Coal and/or lignite

Solid biomass

and/or peat

HFO- and/or gas


engines

All sizes EN 14385

At least once

every year

(11

)

BAT 22,

BAT 29,

BAT 34,

BAT 39

Waste co-


lignite, solid

biomass and/or peat

combustion plants

< 300 MWth EN 14385

At least once

every six

months (7)

(8) BAT 78,

BAT 79

≥ 300 MWth EN 14385

At least once

every three

months (7)

(8)

IGCC plants ≥ 100 MWth EN 14385

At least once

every year

(11

)

BAT 85

Hg

Coal and/or lignite

including waste co-

incineration

< 300 MWth EN 13211

At least once

every three

months (8)

(13

) BAT 23

≥ 300 MWth

Generic EN

standards

and

EN 14884

Continuous

(9)

Solid biomass

and/or peat All sizes EN 13211

At least once

every year

(13

)

BAT 30

Waste co-

incineration in solid

biomass and/or peat

combustion plants

All sizes EN 13211

At least once

every three

months (8)

BAT 80

IGCC plants ≥ 100 MWth EN 13211

At least once

every year

(13

)

BAT 85

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Substance/


Combustion

plant total

rated thermal

input

Standard(s) (

1)

Minimum

monitoring

frequency

Monitoring

associated

with

TVOC

HFO- and/or gas

oil-fired engines

Process fuels from

the chemical

industry in boilers

All sizes EN 12619

At least once

every six

months (8)

BAT 37,

BAT 69

Waste co-


lignite, solid

biomass and/or peat

combustion plants

All sizes

Generic EN

standards

and EN ISO

13199

Continuous

(9)

BAT 81

Formaldehy

de

Natural gas in

spark-ignited lean-

burn gas (SG) and

dual fuel (DF)

engines

All sizes

No EN

standard

available

At least once

every year BAT 50

CH4 Natural gas-fired

engines engines All sizes

EN ISO

25139

At least once

every year

(6)

BAT 50

PCDD/F

Process fuels from

the chemical

industry in boilers

Waste co-


lignite, solid

biomass and/or peat

combustion plants

All sizes

EN 1948-1,

EN 1949-2,

EN 1948-3

At least once

every six

months (8)

(12

)

BAT 69,

BAT 81

(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) In the case of plants with a rated thermal input of < 100 MWth operated in emergency-load mode, the monitoring

frequency may be reduced to at least once every year. In the case of plants with a rated thermal input of < 100 MWth

operated in peak-load mode, the monitoring frequency may be reduced to at least once every six months.

(3) In the case of combined use of dedusting and wet abatement techniques (e.g. wet FGD or flue-gas condenser), the

monitoring frequency may be reduced to at least once every year, if it is demonstrated that the emission levels are

consistently within the BAT-AELs set.

(4) In the case of natural gas-fired turbines with a rated thermal input of < 100 MWth operated in emergency- or peak-

load modes, or in the case of existing OCGTs, PEMS may be used alternatively.

(5) PEMS may be used alternatively.

(6) The measurement is performed with a combustion plant load of > 70 %.

(7) In the case of plants operated in emergency-load mode, the monitoring frequency may be reduced to at least once

every year. In the case of plants operated in peak-load mode, the monitoring frequency may be reduced to at least

once every six months.

(8) The monitoring frequency may be reduced if it is demonstrated that the emission levels are consistently within the

BAT-AELs set. In these specific cases, periodic measurements could 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.

(9) The monitoring frequency may be reduced if it is demonstrated that the emission levels are consistently within the

BAT-AELs set. In these specific cases, periodic measurements could 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.

(10) The monitoring frequency may be reduced if it is demonstrated that the emission levels are consistently within

the BAT-AELs set due to the fuel used. In these specific cases, periodic measurements could be carried out each time

that a change of the fuel characteristics may have an impact on the emissions, but in any case at least once every three

months for plants not operated in emergency- or peak-load modes.

(11) The list of pollutants monitored and the monitoring frequency may be adjusted after an initial characterisation of

the fuel (see BAT 5) based on a risk assessment of the load of pollutants 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 process fuels from the chemical industry, monitoring is only applicable when the fuels contain

chlorine compounds.

(13) The monitoring frequency does not apply in the case of plants operated in peak- or emergency-load modes.

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BAT 3 quater. 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

Monitoring

associated with

Total organic carbon

(TOC) EN 1484

At least once every

month

BAT 11

Chemical oxygen demand

(COD) 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


(e.g. EN ISO 12846 or

EN ISO 17852)

Chloride (Cl-)


(e.g. EN ISO 10304-1 or

EN ISO 15682)

—

Total nitrogen EN 12260 —

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10.1.3 General environmental and combustion performance

BAT 4. In order to improve the general environmental performance of combustion

plants and to reduce their emissions to air of CO and unburnt substances, BAT is to

ensure an optimised complete combustion through stable combustion conditions 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 (e.g. biomass)

Generally applicable

b. Fuel choice

Select or switch totally or partially

to another fuel(s) with a better

environmental profile (with e.g. low

S or Hgsulphur and/or mercury

content) amongst the available fuels

Applicable within the constraints

given by the energy policy of the

Member State. Applicable within

the constraints associated with the

availability of different types of

fuel with a better environmental

profile as a whole, which may be

impacted by the energy policy of

the Member State.

For existing plants, the type of fuel

chosen may be limited by the

configuration and the design of the

plant

c. Multi-fuel firing

Replace part of a fuel by another

fuel with a better environmental

profile (e.g. use coal and syngas

from biomass gasification instead

of coal only)

Ratio of replaced fuel may be

limited by configuration of the

existing plant and its associated

achieved level of performance

d. Advanced computerised

control system

See description in Section 10.8

Use of advanced computerised

control system to enable the good

performance of the boiler with

improving combustion conditions

to support the reduction of

emissions. This also includes

high-performance monitoring

Generally applicable to new

plants. The applicability to old

plants may be constrained by the

need to retrofit the combustion

and/or control command system(s)

e. Good design of the

combustion equipment

Good design of furnace,

combustion chambers, burners,…

and associated devices

Generally applicable to new plants

f.

Good design and

operation of the ammonia

injection system

Good design and operation of the

ammonia injection system to enable

the achievement of a homogenous

NH3/NOX mixture that favours the

NOX reduction reaction while

limiting the NH3 slip

Only applicable to plants using

SNCR and/or SCR techniques

g. Maintenance of the

combustion system


Regular planned maintenance

according to suppliers'

recommendations


{This BAT conclusion is based on information given in Section 5.1.4.2}

BAT 4 bis. 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 and homogeneous distribution of the reagent/NOX ratio,

optimum size of the reagent drops, stable operating conditions).

BAT-associated emission levels

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The BAT-associated emission level (BAT-AEL) for emissions of NH3 to air from the use of

SCR and/or SNCR is < 5–10 mg/Nm3 as a yearly average or average over the sampling period.

The lower end of the range may correspond to the combined use of SCR with wet abatement

techniques (e.g. wet FGD or flue-gas condenser), and the upper end of the range may

correspond to the use of SNCR without wet abatement techniques.

The associated monitoring is in BAT 3 ter.

BAT 5. In order to improve the general environmental performance of combustion and

/or gasification plants and to reduce emissions to air, BAT is to ensure include the

following elements in the QA/QC programmes for all the fuels used includes the following

elements , as part of the environmental management system (see BAT 1):

i. An initial full characterisation 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.

ii. Periodic control of the fuel quality to ensure it is within the criteria of the

characterisation and the plant design. 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 risk of pollutant releases (e.g. concentration in fuel, flue-gas treatment

employed).

iii. Integration of the results in the advanced control system (See description in

Section 10.8).

Description

Characterisation and QA/QC testing can be performed by the operator and/or the fuel supplier.

If performed by the supplier, the full results are provided to the operator through a product

(fuel) supplier specification and/or guarantee.

Fuel(s) Sampling frequency

Analysis and Characterisation

Substances/Parameters subject to

characterisation

Biomass/peat

representative daily biomass fuel samples LHV

moisture

A monthly composite sample which is

created using the daily composite samples

Ash, metals

C, Cl, F, N, S

metals and metalloids (As, Cd, Co, Cr,

Cu, Hg, Mn, Ni, Pb, Sb, Tl, V, Zn)

Coal/lignite

once / week

LHV,

moisture,

volatiles, ash, fixed carbon, C, H, N, O,

S

once / month and at each change of

coal/lignite origin Br, Cl, F

3 times / year, of the fuel that is combusted

when the periodic measurements of metal

emissions to air take place and at each change

of coal/lignite place of origin

metals and metalloids trace species (As,

Cd, Co, Cr, Cu, Hg, Mn, Ni, Pb, Sb, Tl,

V, Zn)

Gas oil/HFO At each fuel delivery Ash, metals

C, S, N, Ni, V

LFO At each fuel delivery Ash, metals

N, C, S content

Natural gas monthly (provided by the fuel supplier)

LHV

C2H6 8, C3, C4, CH4, CO2, H2, H2S, N2,

Wobbe índex

Non-

commercial

fuels

inProcess

fuels from the

chemical

At each change of production mode that leads

to a change in the by-product residues used as

fuel

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

metals and metalloids trace species (As,

Cd, Co, Cr, Cu, Hg, Mn, Ni, Pb, Sb, Tl,

V, Zn)

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plantsindustry

(1)

Iron and steel

process gases

LHV, C2H6 , C3, C4, CH4, CO2, H2, N2,

H2S, COS, dust, Wobbe índex

Wastes To be defined in the (pre)-acceptance

procedure

LHV,

moisture,

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

metals and metalloids trace species (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.

{This BAT conclusion is based on information given in Sections 5.2.1.2 and 5.2.3.2}

BAT 6. In order to minimise the emissions during start-up and shutdown periods,

BAT is to shorten those periods to the minimum time necessary to meet the consumer (e.g.

the grid) requirements use one or a combination of the techniques in BAT 4 (e.g. fuel

choice) during those periods and/or to reduce the occurrence and duration of those

periods by setting up and implementing a management plan as part of the environmental

management system (see BAT 1 and BAT 6 bis), with a special focus on start-up and

shutdown periods, including unplanned shutdown periods. This plan may include the

reduction of the minimum start-up and shutdown loads for stable generation, as defined in

the Commission Implementing Decision 2012/249/EU (using e.g. low load design concepts

in gas turbines).

BAT 6 bis. In order to reduce emissions to air during other than normal operating

conditions (OTNOC), BAT is to minimise the occurrence and duration of those periods by

setting up and implementing a management plan as part of the environmental

management system (see BAT 1), that includes all of the following elements:

risk assessment of OTNOC;

appropriate design of the systems considered relevant in generating OTNOC that may

have an impact on emissions to air, water and/or soil;

specific preventive maintenance action plan of these relevant systems;

corrective actions, recording, review of OTNOC and update of the risk assessment if

necessary.

BAT 6 ter. BAT is to monitor emissions to air and/or to water during OTNOC,

providing that the monitoring system is not involved in the occurrence of the OTNOC.

BAT 6 quater. In order to prevent or reduce emissions to air during normal

operating conditions (NOC), BAT is to ensure, by appropriate design, operation and

maintenance, that the emission abatement systems are used at optimal capacity and

availability.

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10.1.4 Energy efficiency

BAT 7. In order to increase the energy efficiency of combustion plants that are not

operated in peak- and/or emergency-load modes, BAT is to use an appropriate

combination of the techniques given below.


a. Ultra-supercritical

steam conditions

Use of a steam circuit, including double or

triple steam reheat systems, in which steam

can reach pressures of about 300 bar and

temperatures of about 600°C

Applicable to new baseload

plants > 300 MWth.

b.

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 baseload

plants of ≥ 600 MWth.

Not applicable when the purpose

of the combustion plant 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 combustion plants burning

biomass, the applicability may

be constrained by high-

temperature corrosion in the

case of certain biomasses

Applicable for existing plants

> 1000 MWth.

Applicability may be limited for

existing plants < 1000 MWth

when the steam turbine cannot

be adapted for the

implementation of a double

reheat cycle (e.g. material not

resistant enough for supporting

such pressure / temperature).

c.

Optimisation of the

working medium

conditions

Operate withat the highest possible

pressure and temperature of the working

medium gas or steam, within the

constraints associated with e.g. the control

of NOX emissions or the characteristics of

energy demanded


d. Optimisation of the

steam cycle

Operate with the highest possible pressure

drop in the low pressure end of the steam

turbine through utilisation of the lowest

possible temperature of the cooling water

(fresh water cooling)

Operate with lower turbine exhaust

pressure through utilisation of the lowest

possible temperature of the condenser

cooling water, within the design conditions


e. Heat recovery by

cogeneration (CHP)

Recovery of heat (mainly from the steam

cooling system) for producing hot water /

steam which isto be used in industrial

processes/activities or in district heating.

Additional heat recovery is possible from:

flue-gas

grate cooling

circulating fluidised bed

Generally aApplicable within

the constraints given

byassociated with the local

power and heat demand.

The applicability may be limited

in the case of gas compressors

with an unpredictable

operational heat profile

f. Regenerative feed-

water heating

Preheat water coming out of the steam

condenser in the steam circuit with

Generally applicable to new and

existing combined-cycle plants

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Feed-water

preheating using

recovered heat

recovered heat from the plant, before

reusing it in the boiler

Only applicable to steam circuits

and not to hot boilers.

Applicability to existing plants

may be limited due to

constraints associated with the

plant configuration and the

amount of recoverable heat

g. Preheating of

combustion air

Preheating combustion air byThe reuseing

of part of the recovered heat recovered

from the combustion flue-gas to preheat

the air used in combustion

Generally aApplicable within

the constraints related to the

need to control given by the

needs of NOX emissions control

h. Steam turbine

upgrades

This includes techniques such as

iIncreaseing temperature and pressure of

medium-pressure steam, addition of a low-

pressure turbine, modifications of theblade

geometry of the turbine rotor blades

Generally applicable The

applicability may be restricted

by demand/steam conditions

and/or limited plant lifetime

i.

Advanced

computerised

control system

See description in Section 10.8.

The computerised control of the main

combustion parameters enables, in order to

improve the combustion efficiency





and/or control command

system(s)

Applicable to new and existing

plants

j. Cooling tower

discharge

The release of Dischargeemissions to air

through a cooling tower and not via a

dedicated stack

Only applicable to plants fitted

with wet FGD where reheating

of the flue-gas is necessary

before release, and where the

combustion plant cooling

system is a cooling tower

Applicable when the cooling

tower is selected as the cooling

system. Applicable to existing

plants subject to existing

material and location design

constraints

k. Wet stack

The dDesign of the stack in order to enable

water vapour condensation from the

saturated flue-gas and thus to avoid the

need to use a flue-gas reheatergas-gas

heater after the wet FGD

Generally applicable to new and

existing plants fitted with wet

FGD

l. Fuel predrying

The rReduction of fuel moisture content

before combustion to improve combustion

conditions

Applicable to the combustion of

biomass and/or, peat, andor to

the combustion of lignite within

the constraints given

byassociated with

autospontaneous combustion

risks (e.g. the moisture content

of peat is kept above 40 %

throughout the delivery chain

during transport to the plant).

Applicable on a-case-by-case

basis for the gasification of

biomass depending on the

gasification process

The retrofit of existing

combustion or gasification

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

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configurations

m. Fuel preheating Preheating of fuel by using recovered heat

Generally applicable within the

constraints related to the boiler

design and to the need to control

NOX emissions given by the

needs of NOX emissions control

n. Combustion

optimisation


Optimising the combustion minimises

Minimising the content of unburnt

substances in the flue-gases and in solid

combustion residues


o. Heat accumulation Heat accumulation storage in CHP mode

Only Applicable to CHP plants.


in the case of low heat load

demand

p. Advanced materials

Use of advanced materials proven to be to

reachcapable of withstanding high

operating temperatures and pressures and

thus to achieve increased steam /

combustion process efficiencies

Only applicable to new plants

q. Minimisation of

heat losses

Minimising residual heat losses, e.g.

through the slag and by isolating insulating

radiating sources

Only applicable to solid-fuel-

fired combustion plants and to

gasification / IGCC plants

r. Minimisation of

energy consumption

Minimising the internal energy

consumption by, e.g. scarification of the

evaporator, (greater efficiency of the feed

water pump), etc.


s. Flue-gas condenser

The flue-gas condenser is a heat exchanger

recovering heat, where water is heated by

the flue-gases before it is heated in the

steam condensers. The vapour content in

the flue-gases thus condense as it is cooled

by the heating waterSee description in

Section 10.8

Generally applicable to CHP

plants provided there is enough

demand for low-temperature

heat

t. CHP readiness See description in Section 10.8

Only applicable to new plants

where there is a realistic

potential for the future use of

heat in the vicinity of the plant

when immediate opportunities

for heat supply at the time of

building are unavailable

{This BAT conclusion is based on information given in Section 3.3.4}

10.1.5 Diffuse emissions from unloading, storage and handling of fuel and additives

BAT 8. In order to reduce VOC emissions to air from the storage of liquid fuels, BAT

is to use in storage tanks one of the techniques given below.

a. Sealing roof

The storage tanks are fitted with

floating roofs equipped with high

efficiency seals or a fixed roof tank

connected to a vapour recovery

system. High efficiency seals are

specific devices for limiting the

losses of vapour

Applicable to liquid-fuel-fired

combustion plants

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b. Closed-loop system

For internal inspections, tanks have

to be periodically emptied, cleaned,

and rendered gas-free. This cleaning

includes dissolving the tank bottom.

Closed-loop systems that can be

combined with end-of-pipe mobile

abatement techniques prevent or

reduce VOC emissions

Applicable to liquid-fuel-fired

combustion plants

BAT 9. In order to reduce diffuse emissions to air, including odorous substances, from

the unloading, storage and handling of fuels, waste and additives, BAT is to:

a. capture emissions nearest to the source;

b. abate the captured pollutants;

c. optimise the capture efficiency and subsequent cleaning;

d. use the techniques given below.


k.

Minimise the

height of the fuel

drop

Use loading and unloading equipment that

minimises the height of the fuel drop to the

stockpile (e.g. when storing fine wood

material and dry peat)

Applicable to solid-fuel-fired

combustion plants

l. Storage water

spray systems

Use water spray systems in storage areas

and/or stockpiles

Applicable in sites where

freezing does not occur. Not

applicable to fuels with high

surface moisture content

m. Cover stockpiles Cover stockpiles (e.g. of petroleum coke)

Generally applicable to

solid-fuel-fired combustion

plants

n.

Grass over long-

term storage

areas

Grow grass over long-term storage areas Applicable when dusty fuel is

supplied and handled

o.

Direct transfer

of extracted

fuels

Apply the transfer of extracted fuels via

closed belt conveyors or trains directly to

the on-site fuel storage area

Applicable to plants located

near to mines providing the

fuel

p.

Use cleaning

devices for

conveyor belts

Use cleaning devices for conveyor belts Applicable to solid-fuel-fired

combustion plants

q. Optimise on-site

transport

Rationalise on-site transport systems to

minimise movements Generally applicable

r.

Enclosed

conveyors and

protected

transfer points

Use enclosed conveyors, pneumatic

transfer systems, silos with well-designed,

robust extraction, and filtration equipment

on delivery, conveyor, and transfer points

of dusty materials, e.g. dry peat, dusty

biomass, coal, lignite, waste, lime, and

limestone

Not applicable to fuels with

high surface moisture content

s. Leak detection

systems Use leak detection systems and alarms

Applicable when natural gas is

supplied and handled

t.

Air treatment of

sewage sludge

storages

Apply suction plants and subsequent

cleaning devices to silos bunkers and

hoppers storing sewage sludge. For

abatement, the odorous air can be led

directly to the combustion chamber or

burner, where it can be used as combustion

air

Applicable to plants storing

sewage sludge before co-

incineration

The BAT reference document on Emissions from Storage (EFS BREF) contains BAT

conclusions that are of relevance for combustion plants storing fuels, waste and additives.

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10.1.6 Water usage and emissions to water and water consumption

BAT 10. In order to reduce water usage consumption and the volume of contaminated

waste water discharged into receiving waters, BAT is to use one or a combination of the

techniques given below.


a. Avoid the use of

potable water

Avoid the use of potable water for

processes and abatement techniques Generally applicable

b.

Use water and

drainage systems

segregating

contaminated

water streams

Design of an industrial site with optimised

water management, where each

(potentially) contaminated water stream

(from e.g. wet abatement, run-offs, etc.) is

collected and treated separately, depending

on the pollution content

Applicable to new plants.

Applicable to existing plants

within the constraints given by

the configuration of the water

circuits

c.

a.

Maximise

internal Water

recycling

Increase the number and/or capacity of

water recycling systems when building new

plants or modernising/revamping existing

plants, e.g. implementing the reuse of

cleaned waste water for FGD limestone

slurry preparation Residual aqueous

streams 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





circuits Not applicable to waste

water from cooling systems

operated with seawater or in

once-through mode

d.

Segregate/reuse

non-contaminated

water streams

(e.g. once-

through cooling

water, rain water)

Design of an industrial site in order to

avoid sending non-contaminated water to

general waste water treatment system and

to reuse as much as possible collected

water internally for industrial/sanitary

purpose in substitution of other raw water.





circuits

b Evaporation

Water is transferred to the gas phase using

heat. This is typically carried out in vapour-

compression evaporation systems. The

water vapour is condensed and reused (after

further treatment, if needed). The

concentrated waste water requires further

treatment (e.g. crystallisation or spray-

drying) and/or disposal

Not applicable to plants where

the additional energy

consumption offsets the

environmental benefits

c Dry ash handling Ash is conveyed to the silos with systems

using vacuum and/or pressure Generally applicable


BAT 10 bis. 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 include surface water run-off, 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.

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BAT 11. In order to reduce the emission of pollutants contained waste water discharged

into receiving waters, combustion plants fitted with wet abatement techniques for

controlling their emissions to air, BAT is to use a combination of the techniques given

below.


a. Mechanical

treatment Sedimentation, filtration, oil separation. Generally applicable

b.

Physico-

chemical

treatment

Removal of fluoride, sulphide, COD,

particulates by adding chemicals to cause

the solids to settle, and removal of metals

by increasing the pH (precipitation,

flocculation, coagulation, sedimentation,

neutralisation)


c. Zero liquid

discharge (ZLD)

Precipitation, softening, crystallisation,

evaporation

Applicable only to plants

discharging to very sensitive

receiving waters, where techniques

(a) and (b) do not enable meeting

the environmental quality

standards

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BAT 11 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 4) and flue-gas treatment

systems (e.g. SCR/SNCR, see

BAT 6 quinquies)

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. 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-)


g. Filtration (e.g. sand filtration,

microfiltration, ultrafiltration) Suspended solids Generally applicable

h. Flotation Suspended solids, free

oil Generally applicable

i. Ion exchange Metals Generally applicable

j. Neutralisation Acids, alkalis Generally applicable

k. Oil/water separation Free oil Generally applicable

l. Oxidation Sulphide (S

2-), sulphite

(SO32-

) Generally applicable

m. Precipitation

Metals and metalloids,

sulphate (SO42-

),

fluoride (F-)


n. Sedimentation Suspended solids Generally applicable

o. Stripping Ammonia (NH3) Generally applicable

(1) The descriptions of the techniques are given in Section 10.8.6.



The BAT-associated emission levels (BAT-AELs) to receiving waters are given in Table 10.1.

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

emission leaves the installation. WORKIN

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Table 10.1: BAT-AELs for emissions to water from combustion plants fitted with wet abatement

techniques

Parameters Unit

BAT-AEL Monitoring

frequency Average of samples

obtained during one year

COD(2)

mg/l

30–150

Periodic

measurement:

once/month

Suspended solids 5–30

Fluoride as F (3)

1–15

Chloride as Cl (3)

500–1000

Sulphate as SO4 (3)

300–1500 (1)

Sulphide as S 0.01–0.1

Sulphite as SO3 1–5

Total N 1–50

THC 1–10

Sb+As+Pb+Cr+Co+Cu+Mn+Ni+V 0.01–1

Cd+Tl 0.01–0.25

Hg 0.001–0.015

Zn 0.01–0.5 (1) The lower end of the ranges is achieved by plants where other streams than just the stream from the wet abatement

techniques, are mixed before discharging into receiving waters.

(2) Due to difficulties in monitoring COD emissions in the case of high levels of chlorides in waters, TOC is directly

measured instead of COD when chloride concentration exceeds 1000 mg/l, and COD concentration is then estimated

through a plant-specific correlation pattern.

(3) BAT-AELs not applicable when using salty water e.g. for seawater WFGD

Table 10.1: 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)

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

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

Fluoride (F-) 10–25 mg/l

Sulphate (SO42-

) 1.3–2.0 g/l (2) (

3)

Sulphide (S2-

), easily released 0.1–0.2 mg/l

Sulphite (SO32-

) 1–20 mg/l

Metals and metalloids

As 10–50 µg/l

Cd 2–5 µg/l

Cr 10–50 µg/l

Cu 10–50 µg/l

Hg 0.5–5 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

monitoring is the preferred option because it does not rely on the use of very

toxic compounds.

(2) The BAT-AEL only applies to plants using calcium compounds in flue-gas

treatment.

(3) The upper end of the range may not apply in the case of high salinity of the

waste water (e.g. chloride concentrations ≥ 5 g/l) due to the increased solubility

of calcium sulphate.

The associated monitoring is in BAT 3 quater.

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10.1.7 Waste, by-products and residuesWaste management

BAT 12. In order to prevent or, where it is not practicable, to reduce waste generation,

BAT is to adopt and implement a waste management plan that ensures that waste is, in

order of priority, avoided, reused, recycled, recovered or safely disposed of. For specific

waste streams, deviations from the order of priority may be justified based on life-cycle

thinking taking into account the overall impacts of the generation and management of

such waste.

BAT 13. In order to reduce the quantityies of wastes sent for disposal from the

combustion process and abatement techniques sent for disposal, BAT is to organise

operations on the site so as to maximise, in order of priority and taking into account life-

cycle thinking:

a. the proportion of residues which arise as by-products;

b. waste reuse according to the specific requested quality criteria;

c. waste recycling;

d. other recovery,

by implementing an appropriate combination of on-site and/or off-site technical

measurestechniques such as:


e.

Regeneration

of spent

catalysts

On-site Catalyst regenerations (e.g. up to 4four

times for SCR catalysts) restores some or all of the

original performances, extending the service life

of the catalyst to several decades. Regeneration is

integrated in a catalyst management scheme


applicability may be limited by

the mechanical condition of the

catalyst and the required

performance with respect to

controlling NOX, and NH3

emissions

f.

Energy

recovery by

reusing waste

reuse in the

fuel mix

The residual energy content of ash and sludges

generated by the combustion of coal, lignite,

heavy fuel oil, peat, or biomass can be recovered

on site and/or off site when the waste has a

residual calorific value. Energy recovery by

on-site reuse in a fuel mix is possible, e.g. for

sludge and carbon-rich ash

Generally aApplicable to plants

that can accept waste in the fuel

mix, and subject to the technical

possibility of feeding the fuels

into the combustion chamber

g. Reuse of the

FGD gypsum

Off-site reuse of the gypsum generated by the wet

abatement of SOXFGD as a substitute for

rawmined gypsum (e.g. as fillers in the

plasterboard industry). The amount quality of

limestone used in the wet FGD influences the

purity of the gypsum

Generally aApplicable within the

constraints given by associated

with the required gypsum quality,

andthe health demand

requirements associated to a

specific use, and by the market

conditions

h.

Reuse of

residues in the

construction

sector

Off-site Reuse of residues (of e.g. from the residue

of semi-dry desulphurisation processes, fly ash,

bottom ash) as a construction material (e.g. in road

constructionbuilding, in concrete production – to

replace sand -, or in the cement industry)

Generally aApplicable within the

constraints given by associated

with the required material quality

(e.g. physical properties, content

of harmful substances) associated

to each specific use, and by the

market conditions

{This BAT conclusion is based on information given in Sections 3.1.11 and 3.3.6}

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10.1.8 Noise emissions

BAT 14. In order to reduce noise emissions from relevant sources in combustion plants

(e.g. boiler soot blowers, cutting-straw hammer-mills, fuel pneumatic transport to the

burner), BAT is to use one or a combination of the techniques given below.


a.

Strategic planning of

the 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 aApplicable to new

plants. In the case of existing

plants, the relocation of equipment

and production units may be

restricted by the lack of space or by

excessive costs

b. Noise-reduction

programme

The noise-reduction programme

includes identification of sources and

affected areas, calculations and

measurements of noise levels,

identification of the most cost-

effective combination of techniques,

their implementation, and monitoring


c.

Operational measures

and management

techniques in buildings

containing noisy

equipment

This includes:

improved inspection and

maintenance of equipment to

prevent failures;

closing of doors and windows of

covered enclosed areas, if

possible;

equipment operated by

experienced staff;

avoidance of noisy activities

during at night-time, if possible;

provisions for noise control

during maintenance activities


d. Low-noise equipment

This potentially includes

compressors, pumps and disks.

compressors with ≤ 85 dB(A);

speed-controlled pumps;

avoidance of punched disks

Generally applicable when the to

new equipment is new or replaced

e. Noise-reducers Installation of noise-reducers on

equipment and ducts Generally applicable

f. Vibration insulation

Vibration insulation of machinery

and decoupled arrangement of noise

sources and potentially resonant

components


g. Enclose noisy

equipment

Enclosure of noisy equipment in

separate structures such as buildings

or soundproofed cabinets where

internal-external lining is made of

impact-absorbent material


h. Soundproof buildings

This potentially includes:

sound-absorbing materials in

walls and ceilings;

sound-isolating doors;

double-glazed windows


i. Noise abatement

Noise propagation can be reduced by

inserting obstacles barriers between

the emitter and receiver. Appropriate

obstacles barriers 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 the lack of space

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j. Noise-control

equipment

This includes:

i. noise-reducers

ii. vibration or acoustic

insulation, or vibration isolation

iii. enclosure of noisy

equipment

iv. soundproofing of buildings

The applicability may be restricted

by lack of space


10.1.9 Prevention of soil and groundwater contamination

BAT 15. In order to prevent soil and groundwater contamination from the

unloading, storage and handling of solid fuels and additives, BAT is to implement

prevention measures including: a. Storing fuels on sealed surfaces with drainage and drain collection and water treatment by

settling-out

b. Collecting and treating before discharge:

i. any leakages from the point of generation, collection, handling, storage, and

transport of waste;

ii. surface run-off (rainwater) from fuel storage areas that washes fuel particles away

(i.e. the settling-out portion is treated).


10.1.10 Design and decommissioning

BAT 16. In order to prevent pollution upon decommissioning, BAT is to use the

following techniques for new plants.

Design considerations for end-of-life plant decommissioning:

a. considering the environmental impact from the eventual decommissioning of the installation

at the stage of designing a new plant, as forethought makes decommissioning easier, cleaner

and cheaper;

b. considering the environmental risks for the contamination of land (and groundwater) and

the generation of large quantities of solid waste; preventive techniques are process-specific

but general considerations may include:

i. avoiding underground structures;

ii. incorporating features that facilitate dismantling;

iii. choosing surface finishes that are easily decontaminated;

iv. using an equipment configuration that minimises trapped chemicals and

facilitates drain-down or cleaning;

v. designing flexible, self-contained units that enable phased closure;

vi. using biodegradable and recyclable materials where possible.

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10.2 BAT conclusions for the combustion of solid fuels

10.2.1 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 10.1.

10.2.1.1 General environmental performance

BAT 17. In order to improve the general environmental performance of the combustion

of coal and/or lignite, and in addition to BAT 4, BAT is to use the technique given below.


a.

Integrated combustion process

assuring ensuring a high boiler

efficiency and including

primary measurestechniques to

reduce the generation of NOX

emissions, such as air and fuel

staging, advanced low-NOX

burners and/or reburning, etc.

Combustion processes such as

pulverised combustion, fluidised

bed boilerscombustion or moving

grate firing allow this integration



10.2.1.2 Energy efficiency

BAT 18. In order to increase the energy efficiency of coal and/or lignite combustion, BAT

is to use a combination of the techniques described in BAT 7 and of the technique given

below.


a. Lignite pre-drying

Reduction of lignite moisture

content before combustion to

improve combustion

conditions

Applicable to new and existing

lignite-combustion plants

b. Dry bottom ash handling

Ash is conveyed to the silos

with systems using vacuum

and/or pressure thereby

allowing a significant amount

of energy to be recovered and

the boiler efficiency to be

increased by recirculating the

air used to cool the ash



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BAT-associated environmental performance levels

The BAT-associated energy efficiency levels for coal and/or lignite combustion are given in

Table 10.2.

Table 10.2: BAT-associated environmental performance energy efficiency levels (BAT-AEELs)

for energy efficiency offor coal and/or lignite combustion

Combustion plant total

rated thermal input

(MWth)

BAT-AEEPLs (yearly average – LHV basis) (7)

Net electrical efficiency (%) (1) (

8)

Net total fuel utilisation

(%) (1) (

6) (

9)–- CHP

mode

New plants (2) (4) Existing plants (2) (3) New plant or and

existing plants

> ≥1000 MWth coal-fired

whose main purpose is

electricity production

39 to above42

45–46 (2)

33.5–44 42 (2) (

3) 75–97

> ≥ 1000 lignite-fired 42–44 (5) 33.5–42.5 75–97

< 1000 MWth coal-fired

whose main purpose is

electricity production

36.5–to above 40 (2) 32.5–41.5 40 (

2) (

3) 75–97

< 1000 lignite-fired 36.5–40 31.5–39.5 75–97

< 1000 MWth whose main

purpose is heat production - - 75–97

(1) Within the given BAT-AEEL ranges, the achieved energy efficiency can be negatively affected (up to 4four

percentage points) by the type of cooling system used or the geographical location of the combustion plant and the

load variations.

(2) The lower end of the BAT-AEEL ranges is achieved in the case of unfavourable climatic local conditions, low-

grade lignite-fired plants, plants operated in peak or mid-merit modes and and/or older plants (first commissioned

before 1985).

(3) The achievable improvement of thermal efficiency depends on the specific plant, but an incremental improvement

of more than 3three percentage points is seen as associated with the use of BAT for existing plants, depending on the

original design of the plant and on the retrofits already performed.

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

(5) In the case of plants burning lignite with a lower heating value below 6 MJ/kg, the lower end of the BAT-AEEL

range is 41.5 %.

(6) These levels may not be achievable in the case of excessively low heat demand.

(7) These BAT-AEELs do not apply in the case of plants operated in peak- or emergency-load modes.

(8) Net electrical efficiency BAT-AEELs apply to CHP plants and to plants generating only power.

(9) Net total fuel utilisation BAT-AEELs apply to CHP plants and to plants generating only heat.

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10.2.1.3 NOX, N2O, NH3 and CO emissions to air

BAT 19. In order to prevent and/or reduce NOX emissions to air while limiting CO and

N2O and NH3 (if SNCR or SCR techniques are used) emissions to air from the combustion

of coal and/or lignite, BAT is to use one or a combination of the techniques given below.

Plants < 100 MWth


a. Complete combustion


CFB boilers allow achieving a good

combustion performance while

limiting NOX emissions to air,

sometimes without the need for an

additional technique


b.

Combination of primary

techniques (air staging

including boosted

overfire air, fuel

staging, flue-gas

recirculation, LNB) for

NOX reduction

See descriptions in Section 10.8 for

each single technique.

Primary techniques are used in

combination, alone for lignite-fired PC

boilers, sometimes in combination

with SNCR in fluidised bed boilers

and grate-firing, and possibly in

combination with SNCR or SCR in

coal-fired PC boilers.


c. SNCR


Sometimes applied in addition to

primary measures at coal PC or grate-

firing plants

Applicable to coal PC

plants

d. SCR



primary measures at coal PC plants

Applicable to coal PC

plants


Plants 100 MWth – 300 MWth


c Complete combustion


Generally used in combination with

other techniques included in this table


d

Combination of primary

techniques (air staging

including boosted overfire

air, fuel staging, flue-gas

recirculation, LNB) for

NOX reduction

See description in Section 10.8 for

each single technique. Primary

techniques are used in combination,

alone for lignite-fired PC boilers,

sometimes in combination with SNCR

in fluidised bed boilers, and in

combination with SNCR or sometimes

SCR in coal-fired PC boilers.


e SNCR


Applied alone or in combination with

primary measures in coal-fired PC

boilers, and sometimes in fluidised-

bed boilers together with primary

measures


f SCR



primary measures in coal PC plants


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g Combined techniques for

NOX and SOX reduction

See description in Section 10.8. Not

very common, they can be applied

either alone or in combination with

other primary techniques in coal-fired

PC boilers

Applicable on a case-by-

case basis, depending on

the fuel characteristics

and combustion process


Plants > 300 MWth


a. Complete combustion

Combustion optimisation


Generally used in combination

with other techniques included

in this table


b.

Combination of other

primary techniques for

NOX reduction (e.g. air

staging including boosted

overfire air, fuel staging,

flue-gas recirculation,

LNB) for NOX reduction


for each single technique.

Primary techniques are used in

combination, alone for lignite-

fired PC boilers, sometimes in

combination with SNCR in

fluidised bed boilers, and

almost always with an

additional SCR in coal-fired PC

boilers.The choice and

performance of appropriate

(combination of) primary

techniques may be influenced

by the boiler design


c. Selective non-catalytic

reduction (SNCR)


SNCR is applied either alone or

in combination with other

primary techniques in fluidised-

bed boilers Can be applied with

a 'slip' SCR system


applicability may be limited in

the case of boilers

of ≥ 300 MWth with a high

cross-sectional area preventing

a homogeneous mixing of NH3

and NOX.

The applicability may be

limited in the case of

combustion plants operated in

emergency- or peak-load

modes with highly variable

boiler loads

d. Selective catalytic

reduction (SCR)


SCR is applied either alone or

in combination with other

primary techniques. in coal-

fired PC boilers


Not applicable to combustion

plants of < 300 MWth operated

in emergency-load mode.

Not generally applicable to

combustion plants of

< 100 MWth.

There may be technical and

economic restrictions for

retrofitting existing plants

operated in peak-load mode

and existing plants of

≥ 300 MWth operated in

emergency-load mode

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e. Combined techniques for



Not very common, They can be

applied either alone or in

combination with other primary

techniques in coal-fired PC

boilers

Applicable on a case-by-case

basis, depending on the fuel

characteristics and combustion

process



The BAT-associated emission levels for NOX, NH3 and CO are given in Table 10.3.

Table 10.3: BAT-associated emission levels (BAT-AELs) for NOX, NH3 and CO emissions to air

from the combustion of coal and/or lignite

Combustion

plant total

rated

thermal

input

(MWth)

BAT-AELs (mg/Nm3)

Monitoring

frequency

Yearly average

Daily average or

average over the

sampling period

Yearly

average

Yearly

average

New

plants

Existing

plants (4)

New

plants

Existing

plants

New or

existing

plant

<100 100–

200 100–270

ND

155–240

ND

165–330 10–140 100 < 5

Continuous

measurement

100–300 100–

150 100–180

ND

130–175

ND

155–210 10–140 100 < 5

> ≥ 300 FBC

boiler

combusting

coal and/or

lignite (coal-

lignite) and

lignite-fired

PC boilerPC

lignite firing

50–85

150 50–180 80–125 140–220

12 < 5–100

(7) 80

< 1–3.5

> ≥300 coal-

fired PC

boilercoal

firing

65–85

100

65–150

180 80–125

80–220

200 (6)

1 < 5–100 (7)

55 < 1–3.5

(1) Ammonia emissions are associated with the use of SCR and SNCR.

(4) These BAT-AELs do not apply when plants operate in peak- or emergency-load modes.

(6) In the case of plants operated in peak- or emergency-load modes, the higher end of the range is 220 mg/Nm3.

(7) The higher end of the BAT-AEL range can be as high as 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 NOX emissions

reduction.

NB: NA = not applicable; ND = not determined


BAT 20. In order to prevent or reduce N2O emissions to air from the combustion of coal

and lignite in circulating fluidised-bed boilers, BAT is to apply BAT BAT 4 and the

technique given below.


a. Combustion temperature

control

Control of the combustion

temperature enables achieving

balanced emissions to air of N2O

and NOX




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The BAT-associated emission levels for N2O in circulating fluidised bed boilers NOX, NH3 and

CO are given in Table 10.4. Table 10.6.

Table 10.4: BAT-associated emission levels (BAT-AELs) for N2O emissions to air from the

combustion of coal and/or lignite in circulating fluidised bed boilers

Combustion plant Pollutant

BAT-AELs (mg/Nm3)

Monitoring frequency Average over the

sampling period of

samples obtained

during one year

CFBC boiler N2O 20–150 twice/yr


10.2.1.4 SOX, HCl, and HF emissions to air

BAT 21. In order to prevent and/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. Fuel choice

Use of fuel with low Ssulphur

(e.g. down to 0.1 weight % - dry

basis), chlorine or fluorine

contentCl-, F-coal/lignite

content. Often used in

combination with other end-of-

pipe techniques for combustion

plants of > 50 MWth


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 plants combusting highly

specific indigenous fuels

b. Boiler sorbent injection

(in-furnace or in-bed)


Applied in combination with a

downstream dedusting

devicesystem


c. DSI (Duct Dry sorbent

injection) (DSI)


Generally Mostly used in


< 300 MWth, in combination

with a dedusting devicesystem

(ESP, Fabricbag filter). Can be

used for HCl/HF removal when

no specific FGD end-of-pipe

technique is implemented


d. Circulating fluidised bed

(CFB) dry scrubber See description in Section 10.8 Generally applicable

e. Spray-dry absorber (SDA)


Generally Mostly used in

combustion plants of < 1500

MWth for the combustion of

fuels with low and moderate

sulphur content

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f. Wet flue-gas desulphurisation

(Wet FGD) See description in Section 10.8


plants operated in emergency-

load mode.



applying the technique to


< 300 MWth, and for retrofitting

existing plants operated in peak-

load mode

Applicable to plants > 300 MWth g. Seawater FGD See description in Section 10.8

h. Combined techniques for



Not very common, they can be

applied either alone or in

combination with other primary

techniques in coal-fired PC

boilers

Applicable on a case-by-case

basis, depending on the fuel

characteristics and combustion

process

i. Wet scrubbing


The techniques cCan be used for

HCl/HF removal when no

specific FGD end-of-pipe

technique is implemented


j.

Retrofit Replacement of the

gas-gas heater located

downstream of the wet FGD

or SDA

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 to

combustion plants is fitted with a

wet FGD system and a

downstream gas-gas heater or

SDA, when the heat exchanger

needs to be changed or replaced



The BAT-associated emission levels for SO2 SOXare given in Table 10.5.

Table 10.5: BAT-associated emission levels (BAT-AELs) for SO2 SOX emissions to air from the

combustion of coal and/or lignite with S content < 3 %

Combustion

plant total rated

thermal input

(MWth)

BAT-AELs (mg/Nm3)

Monitoring

frequency

Yearly average Daily

average

Daily

average or

average

over the

sampling

period

New plants Existing

plants (3)

New

plants

Existing

plants

> 50–<100 150–200 150–360 400 ND NA ND 170–

400

Continuous

measurement (

2)

100–300 80–150 80–200 ND NA ND 135–

250

> ≥300

(Pulverised

combustion)PC

boiler

10–75 10–130 25–110 25–205 220

(4)

> ≥ 300

(Fluidised bed

boilers) (1)

20–150 20–180 25–185 50–220

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(1) For circulating fluidised bed boilers, the lower end of the range can be achieved by using a high efficiency wet

FGD system. The higher end of the range can be achieved by using boiler in-bed sorbent injection.

(2) SO2 is continuously measured, while SO3 is only periodically measured (e.g. during calibration of the SO2

monitoring system).


(4) The higher end of the BAT-AEL range is 220 mg/Nm3 in the case of plants operated in peak- or emergency-load

modes.

NB: NA = No BAT-AEL

For a plant with a total rated thermal input of more than 300 MWth, which is specifically

designed to fire indigenous fuels and which can demonstrate that it cannot achieve the BAT-

AELs mentioned in Table 10.5 for techno-economic reasons, the upper end of the yearly BAT-

AEL range may be as follows:

(i) existing PC boiler: [130 + (RCG – 4350) * 0.03] mg/Nm3 with a maximum of 400 mg/Nm

3;

(ii) new PC boiler: [75 + (RCG – 5000) * 0.015] mg/Nm3 with a maximum of 270 mg/Nm

3;

(iii) existing fluidised bed boiler: [180 + (RCG – 6000) * 0.03] mg/Nm3 with a maximum of

400 mg/Nm3;

(iv) new fluidised bed boiler: [150 + (RCG – 10000) * 0.015] mg/Nm3 with a maximum of

270 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 % O2.

In these cases the daily BAT-AELs set out in Table 10.5 do not apply.


The BAT-associated emission levels for HCl and HF are given in Table 10.6.

Table 10.6: 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)

Monitoring

frequency

Average of samples obtained during

one year

BAT-AELs

(average of

samples

obtained during

one year -

mg/Nm3)

New plant

BAT-AELs

(average of

samples obtained

during one year -

mg/Nm3)

Existing plant (1)

HCl ≥ 100 < 1–3 5 < 1–5 (

2)

4 times/yr < 100 < 1–6 10 2–10

HF ≥ 100 < 0.1–2 < 0.1–3 2 (

3)

< 100 < 0.1–3 0.2–5 (1) The lower end of these BAT-AEL ranges may be difficult to achieve in the case of plants fitted with a wet FGD

system and a downstream gas-gas heater.

(2) In the case of CFB boilers and in the case of plants operated in peak- or emergency-load mode, the higher end of

the range is 10 mg/Nm3.

(3) In the case of plants operated in peak- or emergency-load modes, the higher end of the BAT-AEL range is

6 mg/Nm3.


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10.2.1.5 Dust and particulate-bound metal emissions to air

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 Cyclones


Only used as a pre-cleaning stage

in the flue-gas path, in

combination with other

technique(s) listed in this table


b Electrostatic precipitator (ESP)


At least a two-fields ESP is used

for smaller plants


c Bag filter See description in Section 10.8 Generally applicable

d Boiler sorbent injection (in-

furnace or in-bed)


Generally used in fluidised bed

boilers sized 50–100 MWth in

combination with an ESP/bag

filter

Generally applicable when

the technique is mainly used

for SOX, HCl and/or HF

abatement

e Dry or semi-dry FGD system

(e.g. SDA, DSI)

See descriptions in Section 10.8.

Generally used in fluidised bed

boilers sized 100–300 of up to

800 MWth in combination with

an ESP/bag filter




abatement

Applicable to plants

> 100 MWth

f WFGDWet flue-gas

desulphurisation (FGD)


Generally used in combustion

plants of ≥ 300 MWth in

combination with an ESP/bag

filter




abatement

Applicable to plants

> 300 MWth

{This BAT conclusion is based on information given in Sections 5.1.4.4 and 9.4.4}


The BAT-associated emission levels for dust emissions to air are given in Table 10.7.

Table 10.7: BAT-associated emission levels (BAT-AELs) for dust emissions to air from the

combustion of coal and/or lignite

Combustion

plant total

rated

thermal

input

(MWth)

Unit

BAT-AELs (mg/Nm3)

Monitoring

frequency

Yearly average (1)

Daily average or average

over the sampling period

New plants Existing

plants New plants

Existing

plants

> 50–<100

mg/Nm3

2–15 2–20 4–20 ND 4–28

Continuous

measurement

100–300 2–10 2–20 3–20 ND 4–25

300–1000 < 2–5 1 2–15 3–10 ND 4 3–20

≥ 1000 < 2–5 3 < 1 2–10 4 3–10 4 3–16 20 (1) These BAT-AELs do not apply when plants operate in peak- or emergency-load modes.


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10.2.1.6 Mercury emissions to air

BAT 23. In order to reduce mercury emissions to air from the combustion of coal and/or

lignite, BAT is to use an appropriate combination of the techniques given below.


Co-benefit from measures techniques primarily used taken for to reduce emissions of other

pollutants

a. Bag filter

See description in

Section 10.8. See BAT

BAT 22


b. Electrostatic precipitator

(ESP)

See description in


BAT 22.

Better mercury removal

efficiency is achieved at

flue-gas temperatures

below 130°C


c. Selective catalytic reduction

(SCR)

See description in


BAT 19.

Only used in

combination with other

techniques to enhance or

reduce the mercury

oxidation before capture

in a subsequent FGD or

dedusting unitsystem,

depending on the

selected strategy

Generally applicable to plants > 300

MWth

Applicable to coal-fired PC boilers for

plants < 300 MWth

Not applicable to combustion plants of

< 300 MWth operated in emergency-load

mode.

Not generally applicable to combustion

plants of < 100 MWth.

There may be technical and economic

restrictions for retrofitting existing plants

operated in peak-load mode and existing

plants of ≥ 300 MWth operated in

emergency-load mode

d.

Flue-gas desulphurisation

(FGD) technique (e.g. wet

limestone scrubbersFGD,

spray- dryer

scrubbersabsorber or ductdry

sorbent injection)

See descriptions in


BAT 221

Generally applicable when there is a

need to reduce SOX content in emissions

to air

Applicable when the technique is mainly

used for SOX, HCl and/or HF abatement.

Wet FGD is not applicable to


emergency-load mode.


restrictions for applying wet FGD to

combustion plants of < 300 MWth, and

for retrofitting existing combustion

plants operated in peak-load mode

Specific measurestechniques to reduce for mercury reductionemissions

e. Fuel choice

SelectUse coal and/or

lignite fuels with low

Hgmercury content < 25

µg/kg



different types of fuel, which may be

impacted by the energy policy of the

Member State

f.

Carbon sorbent

(e.g. activated carbon)

injection in the flue-gas

See description in

Section 10.8.

Generally used in

combination with an

ESP/bag filter. The use

of this technique may

require additional


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treatment steps to further

segregate the mercury-

containing carbon

fraction prior to further

reuse

g.

Use of halogenated additives

toin the fuel or injected in the

furnace

Addition of halogens

(e.g. brominated

additives) into the

furnace to oxidise the

flue-gaselemental

mercury into a soluble or

particulate species,

thereby enhancing

mercury removal in

downstream control

devicesabatement

systems

Generally aApplicable in the case of a

low halogen content in the fuel, within


control of halogen emissions to air and

within the constraints associated with the

corrosion potential of equipment

h. Fuel pretreatment

Fuel washing, blending

and mixing in order to

limit/reduce the

Hgmercury 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

{This BAT conclusion is based on information given in Section 5.1.4.4.}


The BAT-associated emission levels for mercury are given in Table 10.8 and

Table 10.8: BAT-associated emission levels (BAT-AELs) for mercury emissions to air

from the combustion of coal (anthracite and bituminous)


rated thermal input

(MWth)

BAT-AELs (µg/Nm3) (

1)

Averaging

period Monitoring frequency New

plants

Existing

plants

< 300 0.5 < 1–5 < 1–9 10

Average of

samples obtained

during one year

Periodic measurement four

times/yr

≥ 300 0.2 < 1–2 0.2 < 1–4 6 Yearly average Continuous measurement

(1) These BAT-AELs do not apply in the case of plants of < 300 MWth operated in peak- or emergency-load modes.

Table 10.9: BAT-associated emission levels (BAT-AELs) for mercury emissions to air from the

combustion of sub-bituminous coal and lignite


rated thermal input

(MWth)

BAT-AELs (µg/Nm3) (

1)

Averaging period Monitoring frequency New plants

Existing

plants

< 300 < 1–7 10 2–10 20

Average of samples

obtained during one

year

Periodic measurement

times/yr

≥ 300 0.5 < 1–4 5 0.5 < 1–10 Yearly average Continuous measurement

(1) These BAT-AELs do not apply in the case of plants operated in peak- or emergency-load modes.


10.2.2 BAT conclusions for the combustion of solid biomass and/or peat

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to the combustion of solid biomass and/or peat, in addition to the general BAT conclusions

given in Section 10.1.

10.2.2.1 General environmental performance


of solid biomass and/or peat, BAT is to use a combination of the techniques given in BAT 4

and below.


a. Fuel classification based on

size and quality

The storage systems control and

hold the biomass fuel according

to quality and size

Applicable to biomass-fired

plants



BAT 25. In order to increase the energy efficiency of the combustion of solid biomass

and/or peat, BAT is to use an appropriate combination of the techniques given in BAT 7

and to reduce the moisture content of the fuel by either or both of the techniques given

below.


a

Fuel specification in the

supplier contract or internal

document

The fuel supplier or the internal

management adheres to the

moisture (and size) specification in

the contract or internal document

Applicable within the

constraints given by the safe

transportation of fuel (e.g.

minimum moisture content of

peat)

b Press, steam or flue-gas

drying See description in Section 10.8 Generally applicable


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The BAT-associated energy efficiency levels are given in Table 10.10.

Table 10.10: BAT-associated energy efficiency levels (BAT-AEELs) for the combustion of solid

biomass and/or peat

Type of combustion plant Parameter Unit BAT-AEPL

Yearly average (LHV basis)

Generating only heat or

CHP plants whose

recoverable heat generation

does not exceed the heat

demand

Existing Net total

fuel

utilisation

%

80 – 102

New 95 – 102

Generating only power or

CHP plants whose


exceeds the heat demand

Existing Net

electrical

efficiency

28 to above 34

New 31 to above 34

Type of plant

BAT-AEEPLs (1)

(yearly average – LHV basis)

Net electrical efficiency (%) (2)

Net total fuel utilisation (%) (

3) (

4)

New plant Existing plant New plant Existing plant

Solid biomass and/or peat

boiler

31 to above 34

33.5– > 38

28 to above 34

28– 38

95–102

73–99

80–102

73–99 (1) These BAT-AEELs do not apply in the case of plants operated in peak- or emergency-load modes.


(3) Net total fuel utilisation BAT-AEELs apply to CHP plants and to plants generating only heat.

(4) These levels may not be achievable in the case of an excessively low potential heat demand.

10.2.2.3 NOX, N2O, NH3 and CO emissions to air


N2O and NH3 emissions to air from in 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 10.8.


b. (Advanced) lLow-NOX

burners (LNB) Generally applicable

c. Air staging combustion Generally applicable

d. Fuel staging (reburning)

e. Flue-gas recirculation Applicable to pulverised combustion and

FBC boiler plants Generally applicable

f. Selective catalytic reduction

(SCR)

See description in

Section 10.8. The use of

high-alkali fuels (e.g.

straw) may require

installing SCR after the

dust abatement system

Not applicable in the high-dust

configuration when using high-alkali fuel

(e.g. straw)

Not applicable in the case of plants

operated in emergency-load mode.



operated in peak-load mode.

Not generally applicable to plants of

< 100 MWth

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g. Selective non-catalytic

reduction (SNCR)

See description in

Section 10.8


Not applicable to combustion plants

operated in emergency-load mode with

highly variable loads.

The applicability may be limited in the

case of combustion plants operated in

peak-load mode with highly variable

boiler loads

{This BAT conclusion is based on information given in Sections 5.2.3.4 and 9.4.4}


The BAT-associated emission levels for NOX, NH3 and CO are given in Table 10.11.

Table 10.11: BAT-associated emission levels (BAT-AELs) for NOX, NH3 and CO emissions to air

from the combustion of solid biomass and/or peat

Combustion

plant rated

thermal input

(MWth)

Pollutant Unit Monitoring

frequency

BAT-AEL

New plant Existing plant

Yearly

average

Daily

average

Yearly

average

Daily

average

50–100

NOX

mg/Nm3

Continuous

measurement

70–200 120–260 70–250 120–310

100–300 50–130 100–220 50–140 100–220

> 300 40–130 65–150 40–140 95–150

All NH3 (

1) 1–5 ND 1–5 ND

CO 4–80 ND 4–80 ND

(1) Ammonia emissions are associated with the use of SCR and SNCR

Combustion

plant total

rated thermal

input

(MWth)

BAT-AELs (mg/Nm3)

Monitoring

frequency

NOX CO (2) NH3 (

1)

Yearly average

Daily average or

average over the

sampling period Yearly

average

Yearly

average New

plants

Existing

plants (2)

New

plants

Existing

plants

50–< 100 70–200 70–250 120–260 120–310 4 20–250

80

1–5 Continuous

measurement 100–300

50–140

130

50–180

140

100–200

220 100–220

4 15–160

80

> ≥ 300 40–140

130

40–160

140 65–150

95–200

150 4 5–50 80




BAT 27. In order to prevent or reduce N2O emissions to air from the combustion of solid

biomass and peat in circulating fluidised bed boilers, BAT is to apply BAT 4 and the

technique given below.


a. Combustion temperature

control

Control of the combustion

temperature enables achieving

balanced emissions to air of N2O and

NOX



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10.2.2.4 SOX, and HCl and HF emissions to air

BAT 28. In order to prevent and/or reduce SOX, HCl and HF emissions to air infrom the

combustion of solid biomass and/or peat, BAT is to use one or a combination of the



a. Fuel choice

By switching to a different biomass

fuel (e.g. lower sulphur, or lower

fluorine and/or chlorine fuel), the

corresponding emissions are reduced

The applicability is limited by the





Member State

b. Flue-gas condenser

See descriptions in Section 10.8

Applicable to plants serving a district

heating network


c.

Wet flue-gas

desulphurisation

(Wet FGD)

Applicable to plants using higher

sulphur fuel




restrictions for retrofitting existing


d.

Boiler sorbent

injection (in-furnace

or in-bed)

Not applicable if an alkali sorbent

substance is already contained in the

fuel


e.

DSI (Duct Dry

sorbent injection)

(DSI)

See descriptions in Section 10.8. The

technique is used in combination

combined with a dust abatement

technique


f. Spray-dry absorber

(SDA) See descriptions in Section 10.8 Generally applicable



The BAT-associated emission levels for SO2 SOX, HCl, and HF are given in Table 10.12.

The BAT-associated emission levels for HCl and HF are given in Table 10.12.-bis.

Table 10.12: BAT-associated emission levels (BAT-AELs) for SO2X, HCl, and HF emissions to air

from the combustion of solid biomass and/or peat

Fuel

(% in LHV basis)

Pollutan

t Unit

Monitorin

g

frequency

BAT-AEL

Average of

samples

obtained

during one

year

Yearly average

Daily

averag

e

Biomass or biomass /

peat with peat % < 20

SOX mg/N

m³

Continuous

measureme

nt (1)

- 1–50 8–70

Peat or biomass / peat

with peat % ≥ 70 - 100–165 ND

20 peat % < 70

Intermediate,

within the

ranges given in

the two lines

above

ND

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Biomass or biomass /

peat (with peat % <

20), including straw

with straw % < 25

HCl

- 0.3–8 < 14

Straw 100% - < 18 ND

25 straw % < 100 -

Intermediate,

within the

ranges given in

the two lines

above

ND

All HF

Periodic

measureme

nt

4 times/yr

< 0.01–0.8 - -

ND: Not Derived

(1) Only SO2 is continuously measured, SO3 is periodically measured (e.g. during calibration)

Combustion plant total rated

thermal input

(MWth)

BAT-AELs for SO2 (mg/Nm3) (

1)

New

plant

Existing plant

(2)


Yearly average Daily average or average over the

sampling period

< 100 15–70 15–100 30–175 30–215

100–300 <10–50 <10–70 <20–85 <20–175

≥ 300 <10–35 <10–50 <20–70 <20–85 (1) For existing plants burning 100% peat, the higher end of the BAT-AEL range for yearly average is 100 mg/Nm3

and the higher end of the BAT-AEL range for daily average is 215 mg/Nm3.


Table 10.12-bis: BAT-associated emission levels (BAT-AELs) for HCl and HF emissions to air from

the combustion of solid biomass and/or peat

Combustion plant

total rated thermal

input

(MWth)

BAT-AELs for HCl (mg/Nm3) (

1)

BAT-AELs for HF

(mg/Nm3)


(2) (

3)

New

plant

Existing

plant

New

plant

Existing

plant

(3) (

4)

Yearly average or average

of samples obtained during

one year

Daily average or

average over the

sampling period

Average over the

sampling period

< 100 < 0.3–7 0.3–15 1–12 1–35 < 0.01–1 < 0.01–1.3

100–300 0.3–5 0.3–9 1–12 1–12 < 0.01–

0.8 < 0.01–1

≥ 300 0.3–5 0.3–5 1–12 1–12 < 0.01–

0.3 < 0.01–0.5

(1) For existing plants burning 100 % high Cl content biomass such as straw, the higher end of the BAT-AEL range

for yearly average is 20 mg/Nm3 and the higher end of the BAT-AEL range for daily average is 35 mg/Nm3.


(3) The lower end of these BAT-AEL ranges may be difficult to achieve in the case of plants fitted with a wet FGD

system and a downstream gas-gas heater.

(4) In the case of plants operated in peak- or emergency-load modes, the BAT-AEL range is 0.01–1.3 mg/Nm3.


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10.2.2.5 Dust and particulate-bound metals emissions to air

BAT 29. In order to reduce dust and particulate-bound metals emissions to air in from

the combustion of solid biomass and/or peat, BAT is to use one or a combination of the



a. Fuel choice

By switching to a different fuel or

by modulating the fuel blending

(e.g. fuel with lower sulphur or

lower chlorine ash content fuel), the

corresponding emissions are

reduced




be impacted by the energy policy of

the Member State

b. Bag filter See description in Section 10.8


given by space availability


c.

High-performance

Eelectrostatic

precipitator (ESP)



given by space availability.


d. Dry, semi-dry or wet

FGD system See description in Section 10.8

Generally applicable when the

technique is mainly used for SOX,

HCl and/or HF abatement



The BAT-associated emission levels for dust are given in Table 10.13.


combustion of solid biomass and/or peat

Type of

plant Pollutant Unit

Monitoring

frequency

BAT-AEL

Daily average Yearly average

New Dust mg/Nm³

Continuous

measurement

2–12 < 1– 3

Existing 2–20 < 1–10

Combustion plant total rated

thermal input

(MWth)

BAT-AELs for dust (mg/Nm3)

New

plant

Existing

plant (1)


Yearly average Daily average or average over the

sampling period

< 100 2–5 2–15 2–20 2–24

100–300 2–5 2–12 2–16 2–18

≥ 300 2–5 2–10 2–10 2–18 (1) These BAT-AELs do not apply when plants operate in peak- or emergency-load modes.


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BAT 30. In order to prevent or reduce mercury emissions to air in 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. Fuel choice See descriptions in

Section 10.8





Member State

b. Activated carbon duct

injection Generally applicable

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

c. Bag filter

See descriptions in

Section 10.8

Generally applicable for new plants.

Applicable within the constraints given

by space availability in existing plants

Only applicable when the technique is

mainly used for dust abatement

d. Electrostatic precipitator

(ESP)

Only applicable when the technique is

used for dust abatement

e. Dry, semi-dry or wet FGD

system

Applicable when the technique is

mainly used for SOX, HCl and/or HF

abatement.








The BAT-associated emission levels for mercury are given in Table 10.14.

Table 10.14: BAT-associated emission levels (BAT-AELs) for mercury emissions to air from the

combustion of solid biomass and/or peat

Pollutant Unit

BAT-AELs for Hg (1)

Monitoring

frequency Average of samples obtained during one

year over the sampling period

Mercury µg/Nm3 < 1–5

Periodic

measurement 1

time/yr

(1) These BAT-AELs do not apply in the case of plants operated in peak- or emergency-load modes.


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10.3 BAT conclusions for the combustion of liquid fuels

10.3.1 HFO- and/or LFO gas oil-fired boilers


to the combustion of HFO and/or LFO gas oil in boilers,. They apply in addition to the general

BAT conclusions given in Section 10.1.


BAT 31. In order to increase the energy efficiency of the HFO and LFO combustion in

boilers, BAT is to use an appropriate combination of the techniques given in BAT 7 and

below:


a. Preheating of fuel by using waste heat

See descriptions in

Section 10.8

Generally applicable to HFO-fired

boiler combustion plants

b. Regenerative feed-water heating by

using recovered heat

Generally applicable for new plants,

but plant-specific for existing plants

c. Supercritical steam parameters Applicable to new boilers > 300MWth

d. Preheating of combustion air by using

recovered heat

See description in

Section 10.8. If the preheating

temperature is higher than

150 ºC, NOX emissions tend

to increase




The BAT-associated energy efficiency levels of the combustion offor HFO and/or LFO gas oil

combustion in boilers are given in Table 10.5

Table 10.15: BAT-associated energy efficiency levels (BAT-AEELs) in the combustion offor HFO

and/or LFO gas oil combustion in boilers


(yearly average, LHV basis)

Generating only heat

or

CHP plants whose

recoverable heat

generation does not

exceed the heat

demand

New

Net total fuel

utilisation

%

> 90

Existing 80 to above 96

Generating only power

or CHP plants whose

recoverable heat

generation exceeds the

heat demand

New Net electrical

efficiency

above 38

Existing 30 to above 38 WORKIN

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Type of plant

BAT-AEEPLs (1)




3) (

4)


HFO- and/or gas oil-fired

boiler

above 38

> 37.4

30 to above 38

35.6–37.4

> 90

80–96

80 to above 96

80–96



(3) Net total fuel utilisation BAT-AEELs apply CHP plants and to plants generating only heat.

(4) These levels may not be achievable in the case of an excessively low potential heat demand.


10.3.1.2 NOX, NH3 and CO emissions to air

BAT 32. In order to prevent and/or reduce NOX emissions to air while limiting NH3 and

CO emissions to air from the combustion of HFO- and/or gas oil-fired in boilers, BAT is to

use one or a combination of the techniques given below.


a. Fuel choice See description in Section 10.8





Member State

b. Water/sSteam addition

injection See description in Section 10.8


Applicable within the constraints of

water availability

c. Air staging See description in Section 10.8 Generally applicable

d. Fuel staging (reburning) See description in Section 10.8 Generally applicable

e. Flue-gas recirculation See description in Section 10.8 Generally applicable

f. Dry lLow-NOX burners

(LNB) See description in Section 10.8 Generally applicable

g. Advanced computerised

process control system See description in Section 10.8


The applicability to old plants may be

constrained by the need to retrofit the

combustion and/or control command

system(s)

h. Selective catalytic reduction

(SCR) See description in Section 10.8

Not applicable to in the case of plants




plants operated in peak-load mode.


plants of < 100 MWth

i. Selective non-catalytic

reduction (SNCR) See description in Section 10.8



operated in emergency-load mode with

highly variable loads.


case of combustion plants operated in

peak-load mode with highly variable

boiler loads


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The BAT-associated emission levels for NOX, NH3 and CO emissions to air from the

combustion of HFO and/or LFO gas oil in boilers that are not emergency plants are given in

Table 10.16.

Table 10.16: BAT-associated emission levels (BAT-AELs) for NOX NH3 and CO emissions to air

from the combustion of HFO and/or LFO gas oil in boilers

Type of combustion plant Pollutant Unit Monitoring

frequency

BAT-AEL

Yearly average Daily average

< 100 MWth Existing

NOX

mg/Nm3

Continuous

measurement

75–270 ND

New 75–200 ND

≥ 100 MWth Existing 45–110 85–145

New 45–75 85–100

All NH3 (

1) < 1–5 ND

CO 1–20 ND

N.D. not determined

(1) Ammonia emissions are associated with the use of SCR or SNCR

Combustio

n plant

total rated

thermal

input

(MWth)

BAT-AELs (mg/Nm3)

Monitorin

g

frequency

NOX CO

BAT-AELs for

NH3 (1) (mg/Nm

3)

Yearly average

Daily average

or average

over the

sampling

period

Yearly average

(2)

New

plants

Existing

plants

(2)

New

plant

s

Existin

g

plants

All-

New

or

existin

g plant

All-

daily

averag

e

All-

yearly

averag

e

All-

daily

average

< 100

MWth

75–

200

75 150–

270

ND

100–

215

ND

210–

365

1–30

20 ND

< 1 –5

ND

Continuou

s

measurem

ent ≥ 100

MWth 45–75 45–110

85–

100 85–145 1–20




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10.3.1.3 SOX, HCl and HF emissions to air

BAT 33. In order to prevent and/or to reduce SOX, HCl and HF emissions to air from the

combustion of HFO- and/or LFOgas oil-fired boilers, BAT is to use one or a combination

of the techniques given below.






be impacted by the energy policy

of the Member State

b. Flue-gas condenser See description in Section 10.8 Applicable to plants serving a

district heating network


c.

Wet flue-gas

desulphurisation (Wet

FGD)


Applicable to plants > 100 MWth.


economic restrictions for applying

the technique to combustion




load mode.





d.

Duct sorbent injection

(DSI) (Dry in-duct

sorbent injection)


Commonly used in plants below

300 MWth, in combination with a

dedusting device (ESP, fabric filter)

The technique is combined with a dust

abatement technique


e. Spray-dry absorber

(SDA) See description in Section 10.8

Generally applicable to the

combustion of fuels with a low or

moderate sulphur content

f. Seawater FGD See description in Section 10.8

Applicable to plants of

≥ 100 MWth.


economic restrictions for applying

the technique to combustion




load mode.






Note to TWG: please provide information on end-of-pipe technique other than WFGD applied

in plants

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The BAT-associated emission levels for SO2 SOX from the combustion of HFO and/or LFOgas

oil in boilers are given in Table 10.17.


combustion of HFO and/or LFOgas oil in boilers

Type of

combustion

plant


frequency

BAT-AEL


average

Existing SOX mg/Nm³

Continuous

measurement (1)

50–110 (2) < 150–170

New < 70 < 120

(1) Only SO2 is continuously measured, SO3 is periodically measured (e.g. during calibration).

(2) The low end of the range (e.g. < 50 mg/Nm

3) is achieved by combustion plants using LFO.

Combustion

plant total rated

thermal input

(MWth)

BAT-AELs for SO2x (mg/Nm3)

Monitoring

frequency

Yearly average

Daily average or average


New plants Existing

plants (3)

New

plants

Existing

plants

< 300 < 70

50–175

50–110 (2)

50–175

< 120

150–200

< 150–170

150–200 Continuous

measurement (1)

≥ 300

< 70

35–50

50–110 (2)

50–110

< 120

50–120

< 150–170

150–175


(2) The low end of the range (e.g. < 50 mg/Nm

3) is achieved by combustion plants using LFO.





combustion of HFO- and/or LFOgas oil-fired in boilers, BAT is to use one or a








Member State.

b. Electrostatic precipitator

(ESP) See description in Section 10.8 Generally applicable to new plants.

Applicable to existing plants within

the constraints given by space

availability

c. Bag filter See description in Section 10.8

d. ESP + Wet FGD See description in Section 10.8

e. Multicyclones See description in Section 10.8


f. Dry, semi-dry or wet FGD

system See description in Section 10.8


technique is mainly used for SOX,

HCl and/or HF abatement.


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The BAT-associated emission levels for dust from the combustion of HFO and/or LFOgas oil in

boilers are given in Table 10.18.


combustion of HFO and/or LFOgas oil in boilers

Type of combustion

plant Pollutant Unit

BAT-AEL

Monitoring frequency Yearly

average Daily average

New

Dust mg/Nm3

< 1–6 ND

Continuous measurement Existing, all but

emergency plants < 1–10 (

1) 7–15

N.D. not determined

(1) The low–end of the range (e.g. < 1) is achieved by combustion plants using low-ash LFO

Combustion

plant total rated

thermal input

(MWth)


Monitoring

frequency

Yearly average Daily average or average


New plants

Existing

plants, all but

emergency

plants (2)

New plants

Existing

plants, all

but

emergency

plants

< 300 < 1–6

2–15

< 1–10 (1)

2–20 ND 7–18 7–2515 Continuous

measurement ≥ 300 < 12–6 < 1 2– 10 (

1) ND 7–10 7–15

N.D. not determined

(1) The low–end of the range (e.g. < 1) is achieved by combustion plants using low-ash LFO



10.3.2 HFO- and/or gas oil-fired engines


to the combustion of HFO and/or gas oil in reciprocating engines, in addition to the general

BAT conclusions given in Section 10.1.

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BAT 35. 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 7 and below.


a. Preheating of fuel using waste

heat See description in Section 10.8 Generally applicable

b. Preheating of combustion air

using waste heat

See description in Section 10.8. If preheating temperature is

higher than 150 ºC, NOX

emissions tend to increase


c. Combined cycle See description in Section 10.8

Generally applicable to new plants

except when operated in emergency- or

peak-load modes.

Applicable for existing base load plants

within the constraints given by the plant

configuration

Applicable to existing engines within


steam cycle design and the space

availability.

Not applicable to existing engines

operated in emergency- or peak-load

modes


The BAT-associated energy efficiency levels offor the combustion of HFO and/or gas oil in

reciprocating engines are given in Table 10.19.

Table 10.19: BAT-associated energy efficiency levels (BAT-AEELs) infor the combustion of HFO

and/or gas oil in reciprocating engines


(Yearly average, LHV basis)

Generating only

power or CHP plants

whose recoverable

heat generation

exceeds the heat

demand

Existing

Net electrical

efficiency %

40 – 48

New 45 to above 48

Type of combustion

plant

BAT-AEEPLs (1)




HFO- and/or gas oil-fired

reciprocating engine

45 to above 48

> 48

40–48

39.4–48




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10.3.2.2 NOX, NH3, CO and unburnt carbon volatile organic compounds' emissions to air

BAT 36. In order to prevent and/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 described in BAT 7 and given below.


a. Good maintenance of

the engine Generally applicable

b.

Low-NOX combustion

concept in diesel

engines

See description in Section 10.8 Generally aApplicable to new

plants

c. Water/steam addition

injection See description in Section 10.8

Not applicable during water

shortages

Applicable within the constraints of

water availability.

The retrofit to existing engines may

be constrained due to major

modifications to the fuel injection

system

d. Humid air injection

(HAM) See description in Section 10.8 Generally applicable

e. Selective catalytic

reduction (SCR) See description in Section 10.8

Not applicable to in the case of

plants operated in emergency-load

mode plants.



retrofitting existing plants operated

in peak-load mode.

Retrofitting existing plants may be

constrained by the availability of

sufficient space

f. Exhaust-gas

recirculation (EGR) See description in Section 10.8

Not applicable to four-stroke

engines


BAT 37. In order to prevent and/or reduce emissions of CO and volatile organic

compounds unburnt carbon emissions to air from the combustion of HFO and/or gas oil in

reciprocating engines, BAT is to ensure complete combustion by using use one or a

combination of the techniques given in BAT 4 and below.


a. Good engine design See description in Section 10.8 Applicable to new plants

b. Good maintenance of the

combustion system See description in Section 10.8 Generally applicable

c. Process control techniques

Process control techniques, based

on accurate monitoring and well-

optimised system to reduce

emissions of CO and NOX

Applicable to new plants

d. Oxidation catalysts See description in Section 10.8



load mode plants

e. Combustion optimisation See description in Section 10.8 Generally applicable


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The BAT-associated emission levels for NOX, NH3, CO and unburnt carbons (as TVOC)

emissions to air from the combustion of HFO and/or gas oil in reciprocating engines that are not

emergency plants are given in Table 10.20.

Table 10.20: BAT-associated emission levels (BAT-AELs) for NOX, NH3 and CO and TVOC

emissions to air from the combustion of HFO and/or gas oil in reciprocating engines

Type of engine Pollutant Unit Monitoring

frequency

BAT-AEL

Yearly

average

Daily

average

Average of

samples

obtained

during one

year

All but

emergency

plants

Existing NOX

mg/Nm3

Continuous

measurement

90–250 ND -

New < 140 < 150 -

All but emergency plants

NH3 (1) < 5 ND -

CO 50–100 ND -

TOC Periodic

measurement - - 10–40

(1) Ammonia emissions are associated with the use of SCR.

Combustion

plant total

rated

thermal

input

(MWth)

BAT-AELs (mg/Nm3)

Monitoring

frequency

NOX CO NH3 (1) TVOC

Yearly average

Daily average or

average over the

sampling period

Yearly

average

(2)

Yearly

average

Average

of

samples

obtained

during

one year

over the

sampling

period

New

plants

Existing

plants

(2)

New

plants

Existing

plants

(3)

New or existing plants

All sizes but

emergency

plants

115–

< 140

90 125–

625 250

120

145–

160

260

120

150–750

310

50–175

100

1–< 5

10–40

Continuous

measurement

(1) Ammonia emissions are associated with the use of SCR.


(3) The BAT-AEL range for plants operating in emergency- or peak-load modes is 1150–1900 mg/Nm3.


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combustion of HFO and/or gas oil in reciprocating engines, BAT is to use one or a



a. Fuel choice

See description in

Section 10.8.

Low-ash, low-asphaltene and

low-sulphur fuel

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. Process control See description in

Section 10.8. Generally applicable.

c.

Duct sorbent

injection (DSI) with

bag filter

See description in

Section 10.8. The technique

is used in combination with a

dust abatement technique

Not applicable to emergency plants


d.

Wet flue-gas

desulphurisation

(Wet FGD)

See description in

Section 10.8.

Not applicable to combustion plants operated







The BAT-associated emission levels for SO2 SOX from the combustion of HFO and/or gas oil in



combustion of HFO and/or gas oil in reciprocating engines

Type of engine Pollutant Unit Monitoring

frequency

BAT-AEL


average

All but

emergency

plants

Existing SOX mg/Nm³

Continuous

measurement

(1)

100–200 ND

New < 100 < 110

(1) Only SO2 is continuously measured, SO3 is periodically measured (e.g. during calibration)

Combustion

plant total rated

thermal input

(MWth)

BAT-AELs for SO2x (mg/Nm3)

Monitoring

frequency



New plants Existing

plants (2)

New plants Existing

plants

All sizes but

emergency

plants

< 45–100 100–200 < 60–110 ND

105–235

Continuous

measurement (1)




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BAT 39. In order to prevent or reduce dust and particulate-bound metals emissions from

the combustion of HFO and/or gas oil in reciprocating engines, BAT is to use one or a



a. Fuel choice

See description in

Section 10.8.

Low-ash, low-asphaltene and

low-sulphur fuel

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. Process control See description in

Section 10.8 Generally applicable

c. Bag filter See description in

Section 10.8 Generally applicable. to new plants

Not applicable to combustion plants operated

in emergency-load mode plants. Applicable

to existing plants within the constraints given

by space availability d.

Electrostatic

precipitator (ESP)

See description in

Section 10.8

e. Multicyclones See description in

Section 10.8


f. Dry, semi-dry or

wet FGD system

See descriptions in

Section 10.8

Generally applicable when the technique is

mainly used for SOX, HCl and/or HF

abatement



The BAT-associated dust emission levels for dust from the combustion of HFO and/or gas oil in



combustion of HFO and/or gas oil in reciprocating engines

Type of engine Pollutant Unit

BAT-AEL

Monitoring frequency Yearly

average Daily average

New

Dust mg/Nm3

1–5 6–12

Continuous measurement Existing, all but

emergency mode 1–10 ND

Combustion

plant total rated

thermal input

(MWth)


Monitoring

frequency



New plants

Existing

plants, all but

emergency

plants (1)

New

plants

Existing

plants, all

but

emergency

plants

All sizes but

emergency

plants

1–5

2–7

1–10

2–20 6–12 15 ND 6–40

Continuous

measurement



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10.3.3 LFOGas oil-fired gas turbines

Unless stated otherwise, the BAT conclusions presented in this section are generally applicable

to the combustion of LFOgas oil in gas turbines,. They apply in addition to the general BAT

conclusions given in Section 10.1.


BAT 40. In order to increase the energy efficiency of the LFOgas oil combustion in gas

turbines, BAT is to use an appropriate combination of the techniques given in BAT 7 and

below.


a. Double reheat See description in Section 10.8 Generally applicable to new gas turbines

b. Combined cycle (CCGT) See description in Section 10.8

Generally Aapplicable to new gas

turbines except when operated in

emergency- or peak-load modes.

Applicable to existing gas turbines within

the constraints associated with the steam

cycle design and the space availability.

Not applicable to gas turbines operated in

emergency- or peak-load modes



The BAT-associated energy efficiency levels offor the combustion of LFOgas oil in gas turbines

that are not emergency plants are given in Table 10.23.

Table 10.23: BAT-associated energy efficiency levels (BAT-AEELs) offor existing baseload and

mid-merit LFOgas oil-fired gas turbines

Type of gas turbine Parameter Unit BAT-associated environmental

performance levels

Open

cycle

Existing

Net electrical efficiency %

25 to above 31

New above 31

Combined

cycle


New above 40

Type of combustion plant

BAT-AEEPLs (1)




Gas oil-fired open-cycle gas

turbine above 31

> 35.7

25 to above 31

25–35.7

Gas oil-fired combined

cycle gas turbine

above 40

>44

33 to above –44

33–44



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BAT 41. In order to prevent and/or reduce NOX emissions to air from the

combustion of LFO gas oil in gas turbines, BAT is to use one or a combination of the



a. Water/or steam

addition

See description in

Section 10.8

Not applicable during water shortages in dry

areas

The applicability may be limited due to

water availability

b.

Advanced lLow-NOX

burners (LNB) for

liquid fuels

See description in

Section 10.8

Only Aapplicable to turbine models for

which the low-NOX burners are available on

the market

c. Selective catalytic

reduction (SCR)

See description in

Section 10.8

Not applicable to in the case of plants

operated in emergency-load mode. plants

Applicable within the constraints given by

space availability.


constrained by the availability of sufficient

space.





BAT 42. In order to prevent and/or reduce carbon monoxide (CO) emissions to air from

the combustion of LFO gas oil in gas turbines, BAT is to achieve complete combustion by

applying use one or a combination of the techniques given in BAT 4 and below.


a. Oxidation catalysts See description in

Section 10.8


operated in emergency-load mode plants.

Applicable within the constraints given

by space availability



sufficient space

b. Combustion optimisation See description in




The BAT-associated emission levels for NOX, NH3 and CO emissions to air from the

combustion of LFO in gas turbines that are not emergency plants are given in WORKIN

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Table 10.24: BAT-associated emission levels for NOX, NH3 and CO emissions to air from

LFO-fired gas turbines

Type of gas turbine Pollutant Unit Monitoring frequency

BAT-AEL

Yearly

average

Daily

average

All but

emergency

mode

New NOX

mg/Nm³ Continuous

measurement

20–40 ND

Existing < 90 30–250

All NH3 (

1) < 1–5 ND

CO 6–60 ND

(1) Ammonia emissions are associated with the use of SCR technique.

10.3.3.3 SOX and dust emissions to air

BAT 43. In order to prevent and/or reduce SOX and dust emissions to air from the

combustion of LFO gas oil in gas turbines, BAT is to use the techniques given belowin

BAT 4.


a. Fuel choice See description in

Section 10.8

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


BAT-associated emissions levels

The BAT-associated emission levels for SO2SOX and dust from the combustion of LFO gas oil

in gas turbines that are not emergency plants are given in Table 10.25.

Table 10.25: BAT-associated emission levels for SO2SOX and dust emissions to air from the

combustion of LFOgas oil in gas turbines

Type of gas turbine Pollutan

t Unit Monitoring frequency

BAT-AEL

Yearly average

All but

emergency

mode

Existing dust

mg/Nm³

Continuous measurement 1–4

SOX Continuous measurement (1) 1–35

New Dust Continuous measurement 1–2

SOX Continuous measurement (1) 1–20

(1) Only SO2 is continuously measured, SO3 is periodically measured (e.g. during calibration). Continuous monitoring

fuel sulphur content and correlating it with SOX emissions is an alternative monitoring method possible if only

primary techniques are implemented.

Combustion

plant total rated

thermal input

(MWth)

BAT-AELs (mg/Nm3)

Monitoring

frequency

SO2x Dust

Yearly

average (2)

Daily average

or average

over the

sampling

period

Yearly

average (2)

Daily average

or average

over the

sampling

period

New plants or existing plants New plants or

existing plants

All sizes but

emergency

plants

1–20 / 1–35

35–60 50–66

1–2 / 1–4

2–5

2–10

Continuous

measurement (1)

(1) Only SO2 is continuously measured, SO3 is periodically measured (e.g. during calibration). Continuous monitoring

fuel sulphur content and correlating it with SOX emissions is an alternative monitoring method possible if only

primary techniques are implemented.


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10.4 BAT conclusions for the combustion of gaseous fuels

10.4.1 BAT conclusions for the combustion of natural gas


to the combustion of natural gas,. They apply in addition to the general BAT conclusions given

in Section 10.1.


BAT 44. In order to increase the energy efficiency of natural gas combustion, BAT is to

use one or a combination of the techniques described in BAT 7 and of the techniques given

below.


a. CHP readiness See description in Section 10.8 Applicable to new gas

turbines, including CCGTs

b.

Regenerative feed-

water

heating


The regenerative stream can be generated by

the boiler or the steam turbine


c.

Combined cycle

(CCGT)


Energy efficiency optimisation refers to the

efficiency of the total combined cycle and not

only to the gas turbine

Generally aApplicable to

new gas turbines and

engines except when

operated in emergency- or

peak-load modes.

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 in emergency- or

peak-load modes.

Not applicable to boilers

and to existing baseload

open-cycle gas turbines

operated in mid-merit load

or baseload modes ,

provided there is enough

available space

{[This BAT conclusion is based on information given in Section 7.1.4.2}

BAT 45. In order to use energy efficiently, BAT is to use expansion turbines to recover the

energy content of the pressurised supplied fuel gasesnatural gas.

Description

An expansion turbine (or turbo expander) is an apparatus that can be installed on the natural gas

supply line (instead of a throttling expansion valve) to generate power from the expansion of the

high-pressure natural gas to the supply pressure of the gas turbine. The throttling valve is kept

as back-up, in case the expansion turbine is not available.

Applicability

The applicability of the technique may be limited by the amount of recoverable energy.

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The BAT-associated energy efficiency levels for the combustion of natural gas are given in

Table 10.26.

Table 10.26: BAT-associated environmental performance energy efficiency levels (BAT-AEELs)

for the energy efficiency of the combustion of natural gas fired combustion plants


BAT-AEELs for energy efficiency (yearly average) (3)

Net electrical efficiency

(%) (1)

Net total

fuel

utilisation

(%) (2) (

4)

Net mechanical energy

efficiency (%) (5)

New

plants

Existing

plants New plant

Existing

plant

Gas engine

Gas engine (1)

42–46.5

to above

46.5

35–44 56–85 NA NA

CHP gas engines (2) - - 56–78 -

Gas-fired boiler

Gas-fired boiler only

producing electricity and

CHP gas-fired boilers

whose recoverable heat

generation exceeds the heat

demand

40–42.5

to above 42 38–40 78–95 NA NA

Gas–fired boiler only

producing heat and CHP

gas-fired boilers whose


does not exceed the heat

demand

- - 78–95 -

Open-cycle gas turbine

Gas turbine ≥ 50 MWth 36–41.5

to above 41

33–41.5

28–39 NA 36.5–41 33.5–41

Combined cycle gas turbine (CCGT)

CCGT ≥ 50 MWth for

electricity generation only

(3)

57–60.5

48.5 to

above 58

47–60

45 –58 NA NA NA

CHP CCGT plant (50–600

MWth) whose recoverable

heat generation exceeds the

heat demand

57–60.5

42 to above

46

47–60

40–46

67–95

60–95 NA NA

CHP CCGT plants (50–600


heat generation does not

exceed the heat demand (2)

- - 60–95 -

CHP CCGT plant (> ≥ 600


heat generation exceeds the

heat demand

57–60.5

50–51

47–60

44–51 80–95 NA NA

CHP CCGT plants (>




- - 80–92 -

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(1) Electrical efficiency applies for plants producing power only and for plants whose recoverable heat generation

exceeds the heat demand. Net electrical efficiency BAT-AEELs apply to CHP plants and to plants generating only

power.

(2) The energy efficiencies in CHP plants are very much dependent upon the specific situation and the local demand

of electricity and heat. Net total fuel utilisation BAT-AEELs may not be achievable in the case of an excessively low

heat demand.

(3) These BAT-AEELs do not apply to plants operated in peak- or emergency-load modes. Not applicable for plants

(< 500 h/yr).

(4) These BAT-AEELs apply to CHP combustion plants and to combustion plants generating only heat.

(5) These BAT-AEELs apply to combustion plants used for mechanical drive applications.

NB: NA = no BAT-AEL

10.4.1.2 NOX, CO, NMVOC and CH4 emissions to air


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 10.8.

Air staging (over fire air) is often

associated with low-NOX burners


b. Flue-gas recirculation See description in Section 10.8 Generally applicable

c.

(Ultra-) Low-NOX burners

(LNB)

((U)LNB)


Retrofit may be limited for older

plants due to boiler design

constraints Generally applicable

d.

Selective catalytic reduction


Not applicable for in the case of


emergency-load mode plants.

Not generally applicable to

combustion plants of < 100 MWth.



significant space.

For peak-load plants, the

economic viability may depend on

the energy market conditions





e.

Selective Nnon-Ccatalytic

Rreduction (SNCR) See description in Section 10.8

Not applicable to emergency-

plants



mode with highly variable loads.


in the case of combustion plants

operated in peak-load mode with

highly variable boiler loads

f.

Advanced computerised

process control system


This technique is often used in

combination with other techniques or

may be used alone for very well-

tuned plants operated in emergency-

load mode plants



combustion plants may be

constrained by the need to retrofit

the combustion and/or control

command system(s)

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g. Reduction of the combustion

air temperature See description in Section 10.8



process needs



natural gas in gas turbines while limiting NH3 slip in the case of SCR use, BAT is to use

one or a combination of the techniques given below.


a. Dry low-NOX burners (DLN) See description in Section 10.8

The aApplicability may be limited in

the case of very old turbines

(retrofitting package not available) or

when steam/water injection systems

are installed

b.



Not applicable in the case of

combustion plants operated in to




significant sufficient space.

For peak-load plants, the economic

viability may depend on the energy

market conditions


economic restrictions for retrofitting

existing plants operated in peak-load

mode

c.

Water/steam addition

Water or steam injection


This technique is uUsed in existing

gas turbines and when a DLN retrofit

DLN package is not available


The applicability may be limited due

to water availability

d.







tuned emergency plants operated in

emergency-load mode


The applicability to old combustion




e. Low-load design concept

Adaptation of the process control and

related equipment to maintain for

keeping good combustion efficiency

when the demand in energy is

varying varies, e.g. by improving the

inlet airflow control capability or by

splitting the combustion process in

decoupled combustion stages

Applicable depending on the gas

turbines design

f. Low-NOX burners (LNB) See description in Section 10.8

Generally applicable to

supplementary firing for heat

recovery steam generators (HRSG)

in the case of combined cycle gas

turbine (CCGT) combustion plants

(CCGTs)


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natural gas in engines, BAT is to use one or a combination of the techniques given below.


a. Lean-burn concept


Generally used in combination with

SCR

Only aApplicable to new gas-fired

engines

b. Advanced lean-burn concept See description in Section 10.8

Applicable to new gas-fired engines

but not to spark ignited engines

Only applicable to new spark plug

or other ignited (SG)-type engines

c.






Not applicable in the case of

combustion plants operated in to


For peak-load plants, the economic

viability may depend on the energy

market conditions




load mode

d.







tuned emergency combustion plants

operated in emergency-load mode







BAT 49. In order to prevent and/or reduce CO emissions to air from the combustion of

natural gas, BAT is to use one or both a combination of the techniques given below.


a. Complete Combustion optimisation See description in Section 10.8

1. Good furnace/combustion

chamber design

Applicable to new plants

2. Use of high performance

monitoring


3. Maintenance of the

combustion system


b. Well optimised system to reduce

emissions of NOX


c. Advanced automated process

control See description in Section 10.8 Generally applicable

d

. Application of Oxidation catalysts See description in Section 10.8 Generally applicable


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The BAT-associated emission levels for NOX and CO emissions to air from the combustion of

natural gas are given in Table 10.27 (for gas turbines) and in Table 10.28 (for boilers and

engines).

Table 10.27: BAT-associated emission levels (BAT-AELs) for NOX and CO emissions to air from

the combustion of natural gas in gas turbines

Type of gas turbine

Combustion

plant total

rated

thermal

input

(MWth)

BAT-AELs (mg/Nm3) (

3)

Monitoring

frequency

NOX CO

Daily

average or

average over

the sampling

period

Yearly

average

(7) (

14)

Yearly

average

(7) (

14)

Open-cycle gas turbines (OCGTs)

New OCGT gas turbines

(1)

≥ 50 7–50 (13

) 6–35 (13

) 3 < 5–40

(13

)

Continuous

measurement

Existing OCGT gas

turbines (excluding

turbines for mechanical

drive applications) – All

but emergency-load

mode

≥ 50 7–55 75 (5) 6–50

3 < 5–40

(6) (

9)

Continuous

measurement or

PEMS

Existing gas turbines for

mechanical drive – All

but emergency mode

7–85 6–60 3–40

Continuous

measurement or

PEMS

Existing gas turbines –

Emergency mode

(2)

NA 44–125 5–80

Continuous

measurement,

or PEMS

Combined cycle gas turbines (CCGTs) (11

) (15

)

New dual fuel CCGT –

Natural gas mode 15–25 9–20 1–5

Continuous

measurement

Existing dual fuel CCGT

– Natural gas mode 15–55 10–50 1–50

Continuous

measurement

New single fuel CCGT

> 600 MWth ≥ 50

18–35

15–40 (12

)

10–30 (12

)

25

1–15

< 5–30 (12

)

Continuous

measurement

Existing single fuel

CCGT

> 600 MWth with a net

total fuel

utilisation < 75 %

≥ 600 18–50 10–40 35 1 < 5–30

(9)

Continuous

measurement

Existing CCGT

with a net total fuel

utilisation ≥ 75 %

≥ 600 18–65 10–50 < 5–30 (9)

New single fuel CCGT

50–600 MWth 15–35 10–25 1–15

Continuous

measurement


CCGT 50–600 MWth


utilisation of < 75 %

50–600 35– 55 10–45 1–15

< 5–30 (9)

Continuous

measurement


CCGT 50–600 MWth


utilisation of ≥ 75 %

50–600 35–80 85 25–55 (

10)

75

1 < 5–30

(9)

Continuous

measurement

Open- and combined cycle gas turbines

Existing gas turbines –

Emergency-load mode

(2)

≥ 50 NA

60–140 NA 44–125 NA 5–80

Continuous

measurement or

PEMS

Existing gas turbines for

mechanical drive

applications – All but

emergency-load mode

≥ 50 7–65 85 6–60 3 < 5–40

(9)

Continuous

measurement or

PEMS

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Existing/New dual fuel

gas turbine combusting

liquid fuels in

emergency-load mode

≥ 50 145–250 NA NA

(1) The higher end of the ranges is achieved when the plants operate on peak mode.

(2) The lower end of the BAT-AEL NOX range for NOX can be achieved with water injection or dry low-NOX premix

burners.

(3) These BAT-AELs also apply to the combustion of natural gas in dual-fuel-fired turbines.

(5) The higher end of the range is 80 mg/Nm3 in the case of plants operated in peak-load mode.

(6) The higher end of the range is 80 mg/Nm3 in the case of existing plants that cannot be fitted with dry techniques

for NOX reduction.

(7) These BAT-AELs do not apply in the case of plants operated in peak-load mode.

(9) The higher end of the range is 50 mg/Nm3 when plants operate at low load (e.g. with an equivalent full load factor

below 60 %).

(10) Where it can be demonstrated that it is not possible to further retrofit a plant operated in peak-load mode due to

techno-economic reasons, the higher end of the range is 75 mg/Nm3.

(11) These BAT-AELs do not apply to turbines for mechanical drive applications or to plants operated in emergency-

load mode.

(12) 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 energy efficiency of the plant determined at ISO baseload conditions.

(13) 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 of the plant determined at ISO baseload conditions.

(14) Optimising the functioning of an existing technique to reduce further NOX emissions may lead to levels of CO

emissions at the higher end of the BAT-AEL range for CO.

(15) When the boiler of a CCGT operates alone (i.e. the gas turbine does not operate), the BAT-AELs that apply are

those related to boilers (see Table 10.28).

NB: NA = No BAT-AEL



the combustion of natural gas in boilers and engines


BAT-AELs (mg/Nm3)

Monitoring

frequency

NOX CO

Daily average or

average over the

sampling period

Yearly average

(3) (

4)

Yearly

average (3) (

4)

Boilers

New boilers NA < 85 10–60 1–5

< 5–15

Continuous

measurement

Existing boiler 85–110 50–100 1–15

< 5–40

Continuous

measurement

Gas eEngines (1)

New gas engine NA 20–75 30–100 Continuous

measurement

Existing gas engines NA 55–110 (2) 20–100 30–100

Continuous

measurement (1) These BAT-AELs only apply to SG- and DF-type engines. They do not apply to GD-type engines.

(2) In the case of engines operated in emergency-load mode that could not apply the lean-burn concept or use an SCR

system for techno-economic reasons, the higher end of the range is 175 mg/Nm3.


(4) Optimising the functioning of an existing technique to reduce further NOX emissions may lead to levels of CO

emissions at the higher end of the BAT-AELs for CO.

NB: NA = No BAT-AEL


The BAT-associated emission level for NH3 slip when using SRC is less < 3

as yearly average based on continuous measurement*.

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BAT 50. 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 (SG) and dual fuel (DF) engines, BAT is to ensure complete an optimised and

stable combustion conditions and/or to apply oxidation catalysts.

The BAT-associated emission levels for formaldehyde NMVOC and CH4 are presented given in

Table 10.29.

Table 10.29: BAT-associated emission levels (BAT-AELs) for NMVOC formaldehyde and CH4

emissions to air from the combustion of natural gas in an SG or DF engines

Pollutant

BAT-AELs (mg/Nm3)

Monitoring frequency Aaverage over the sampling period of

samples obtained during one year -

NMVOC

Formaldehyde

4–40

2–15

Periodic measurements:

4 times/yr

CH4 200–400

185–500 (1)

Periodic measurements:

4 times/yr (1) This BAT-AEL applies only to an SG-type engine and is expressed as C at maximum continuous

rating (MCR)



10.4.2 BAT conclusions for the combustion of iron and steel process gases


to the combustion plants combusting of iron and steel process gases (e.g. blast furnace, coke

oven, basic oxygen furnace gases), alone individually, in combination, or simultaneously, or in

combination with other gaseous and/or liquid and/or solid commercial fuels,. They apply in

addition to the general BAT conclusions given in Section 10.1.


BAT 51. In order to increase the energy efficiency for of the combustion of iron and steel

process gases in boilers and CCGTs, only or in combination with other gaseous, liquid

and/or solid fuels, BAT is to use one or a combination of the techniques listed in BAT 7

and of the technique given below.


a.

Process gases

management system See description Section 10.8

Only aApplicable to

integrated Iron and Steel

steelworks



The BAT-associated energy efficiency levels for the combustion of iron and steel process gases

only or in combination with other gaseous and/or liquid fuels are presented are given in Table

10.30.

The BAT-associated energy efficiency levels for the combustion, in CCGTs, of iron and steel

process gases and natural gas are presented are given in Table 10.31.

The BAT-associated energy efficiency levels for the combustion of iron and steel process gases

in combination with coal and possibly other gaseous and/or liquid fuels are the ones given in

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Table 10.30: BAT-associated environmental performance levels for energy efficiency levels (BAT-

AEELs) offor the combustion of iron and steel process gases in a boilers alone or in

combination with other gaseous and/or liquid fuels

Combustion pPlant type

BAT-AEELs (% - yearly average) (2)

Net electrical efficiency (3)


(4)

(CHP plants)

Existing multi-fuel firing gas–

boilers producing power only

and multi-fuel firing gas–

boilers whose recoverable

heat generation exceed the

heat demand

32.5–40

25–40 50–84

New multi-fuel firing gas–

boilers producing heat only

and multi-fuel firing gas–

boilers whose recoverable



40–42.5 50–84

(1) The wide range of energy efficiencies in CHP plants is very much largely dependent on the specific situation and

the local demand of for electricity and heat.


(3) These BAT-AEELs apply to CHP plants and to plants generating only power.

(4) These BAT-AEELs apply to CHP plants and to plants generating only heat.

Table 10.31: BAT-associated environmental performance levels for energy efficiency levels (BAT-

AEELs) of for the combustion of iron and steel process gases and natural gas in a

CCGTs

Combustion pPlant type Parameter Unit BAT-AEELs

(yearly average, LHV basis)

CHP CCGTs whose recoverable

heat generation does not exceed

the heat demand

Net total fuel

utilisation

%

60–82

CCGT Ggenerating

only power or CHP

CCGTs whose

recoverable heat

generation exceeds the

heat demand

Existing

plant Net electrical

efficiency

43–48

38.5–45

New

plant

> 47 above 44

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10.4.2.2 NOX and CO emissions to air


iron and steel process gases in boilers only or in combination with other gaseous fuels

and/or liquid fuels, BAT is to use one or a combination of the techniques given below.


a. Specially designed Low-

NOX burners (LNB)

See description Section 10.8.

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 description in Section 10.8 Generally applicable

c. Fuel staging See description in Section 10.8 Generally applicable

d. Flue-gas recirculation See description in Section 10.8 Generally applicable

e.





mode.

Not generally applicable to plants

of < 100 MWth.


constrained by significant the

availability of sufficient space

availability and by the combustion

plant configuration.



retrofitting existing plants operated

in peak-load mode.

f.

Selective non-catalytic

reduction (SNCR) See description in Section 10.8




mode.

The applicability may be limited in

the case of combustion plants

operated in peak-load mode with

frequent fuel changes and frequent

load variations

g.




This technique is used in

combination with other techniques







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iron and steel process gases and natural gas in CCGTs, BAT is to use one or a



a. Dry low-NOX burners (DLN)


DLN that combust iron and steel

process gases differ from the ones

that combust natural gas only


associated with the reactiveness of

iron and steel process gases such as

coke oven gas.

The applicability may be limited in

the case of a very old turbine

(retrofitting package not available)

or when steam/water injection

systems are installed

b. Low-NOX burners (LNB) See description in Section 10.8.

Generally Only applicable to

supplementary firing for heat

recovery steam generators (HRSG)

of combined cycle gas turbine

(CCGT) combustion plants

c.











load mode

d. Water/steam addition

Water or steam injection


In dual fuel gas turbines using DLN

for iron and steel process gases

combustion, water/steam addition is

generally used when combusting

natural gas



due to water availability

e.




This technique is used in

combination with other techniques







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iron and steel process gases, only or in combination with other gaseous fuels and/or liquid

fuels, BAT is to applyuse one or a combination of the following techniques given below.


a. Complete Combustion optimisation See description in Section

10.8 Generally applicable

b. Good furnace/combustion chamber design Applicable to new plants

1. Use of high performance monitoring Generally applicable

2.Maintenance of the combustion system Generally applicable

c. Advanced computerised process control See description in Section

10.8 Generally applicable

d. Well optimised system to reduce emissions of NOX Generally applicable

e. Oxidation catalysts See description in Section

10.8

Only applicable to

CCGTs.


limited by lack of space,

the load requirements

and the sulphur content

of the fuel


The BAT-associated emission levels for NOX and CO concentrations associated with BAT from

the combustion of iron and steel process gases are given in Table 10.32.


the combustion of iron and steel process gases, only or in combination with other

gaseous fuels and/or liquid fuels in boilers, or, with natural gas in CCGTs

Combustion

pPlant type

O2

reference

level (%)

BAT-AELs (mg/Nm3) (1)

Monitoring

frequency

NOX CO

Daily average or

average over

the sampling

period

Yearly average

(4)

Yearly average

(4)

New boilers 3 22–100 (5)(9) 15–65 < 5–35

1–25

Continuous

measurement

Existing boiler 3 22–160 (5) (6) 20–100 1 < 5–100 Continuous

measurement

New CCGT 15 30–50 20–35 < 5–20

Existing CCGTs 15 30–70 (8) 120 20–50 100 (7) 1 < 5–20 Continuous

measurement

(1) Emissions from pPlants 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.

(4) These BAT-AELs do not apply to plants operated in peak- or emergency-load modes.

(5) The higher end of the BAT-AEL range may be different on days when auxiliary liquid fuels are used. In this case,

the higher end of the BAT-AEL range may correspond to the higher end of the BAT-AEL range reported in the BAT

conclusions that apply to the combustion of the corresponding (auxiliary) fuel and to the case of plants operated in

peak- or emergency-load modes.

(6) The higher end of the BAT-AEL range may be exceeded a few days every year in the case of plants not fitted with

SCR when using a high share of COG and/or combusting COG with a relatively high level of H2. In this case the

higher end of the BAT-AEL range is 220 mg/Nm3.

(7) The lower end of the BAT-AEL range can be achieved when using SCR.

(8) In the case of plants operated in emergency- or peak-load modes, the higher end of the BAT-AEL range is

80 mg/Nm3.


BAT 55. In order to prevent and reduce NOX emissions to air from the combustion of iron

and steel process gases (alone or with other gaseous and/or liquid fuels) in combination

with coal, BAT is to use one or a combination of the techniques described in BAT 19 and

of the following technique, depending on the fuels combusted:

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a. Specially designed low-NOX

burners

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)

Generally applicable with specific

features depending on the type of

multi-fired fuels and on their range

of variability


The CO, NOX and NH3 emission levels associated with BAT are given in

Table 10.33.

Table 10.33: BAT-associated emission levels for NOX, NH3 and CO emissions to air from the

combustion of iron and steel process gases (alone or with other gaseous and/or liquid

fuels) in combination with coal

BAT-AEL for NOX

(yearly average -

mg/Nm3)

BAT-AEL for NOX

(daily average -

mg/Nm3)

BAT-AEL

for CO

(yearly

average -

mg/Nm3)

BAT-AEL

for NH3 (1)

(yearly

average -

mg/Nm3)

New

plants

Existing

plants

New

plants

Existing

plants

< 100 100–

200 100–270 ND 10–100 < 5

Continuous

measurement

100–300 100–

150 100–180 ND 10–100 < 5

> 300 FBC

(coal-lignite)

and PC firing

50–150 50–180 140–220 12–80 < 1–3.5

> 300 PC

coal firing 65–100 65–180 80–125 80–220 1–55 < 1–3.5


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10.4.2.3 SOX emissions to air

BAT 56. In order to prevent and/or reduce SOX emissions to air from the combustion of

iron and steel process gases in boilers, only or in combination with other gaseous fuels

and/or liquid fuels, BAT is to use a combination of the techniques given below.


a. Coke oven gas pretreatment at

the iron- and steel-worksfacility

Use of one of the following techniques:

desulphurisation by absorption systems;

wet oxidative desulphurisation

Generally

aApplicable to

integrated plants

b. Process gas management system

and auxiliary fuel choice


Use, as much as the iron- and steel-works

allow it, of:

a majority of blast furnace gas with low

sulphur content in the fuel diet;

a combination of fuels with averaged

low sulphur content, e.g. individual

process fuels with very low S content

such as:

o BFG with Ssulphur content

< 10 mg/Nm3;

o coke oven gas with Ssulphur

content < 300 mg/Nm3;

and auxiliary fuels such as:

o natural gas;

o liquid fuels with Ssulphur content

of ≤ 0.4 % (in boilers).

Use of a limited amount of fuels with

containing higher Ssulphur content

Generally

applicable, within

the constraints

associated with

the availability of

different types of

fuel



The BAT-associated emission levels (BAT-AELs) for SO2X emissions to air concentrations

associated with BAT from the combustion of iron and steel process gases, only or in

combination with other gaseous fuels and/or liquid fuels in boilers, or with natural gas in

CCGTs, are given in Table 10.34.

Table 10.34: BAT-associated emission levels (BAT-AELs) for SO2 SOX emissions from the

combustion of iron and steel process gases, only or in combination with other gaseous

fuels and/or liquid fuels in boilers, or with natural gas in CCGTs

Type of

combustion

plant

Pollutant O2 reference

level (%)

Monitoring

frequency

BAT-AELs for SO2 (mg/Nm3)

Daily average

or average

over the

sampling

period

Yearly average

(4)

Boiler SOX 3 Continuous

measurement (1)

50–200

(2)(

3) 25–150

CCGT SOX 15 Continuous

measurement (1)

20–70 60 10–45 35


(2) Higher levels can be expected when HFO/LFO or other non-conventional liquid fuels with high sulphur content

are combusted.





(4) These BAT-AELs do not apply when plants operate in peak-load or emergency-load modes.


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BAT 57. In order to reduce SOX emissions to air from the combustion of iron and steel

process gases (alone or with other gaseous and/or liquid fuels) in combination with coal,

BAT is to use one or a combination of the techniques described in BAT BAT 21.


The BAT-associated emission levels for SOX from the combustion of iron and steel process

gases in combination with coal and possibly other gaseous and/or liquid fuels are given in

Table 10.35.

Table 10.35: BAT-associated emission levels for SOX emissions to air from the combustion of iron

and steel process gases (alone or with other gaseous and/or liquid fuels) in

combination with coal with S content < 3 %

Combustion

plant rated

thermal input

(MWth)

BAT-AEL (mg/Nm3)

Monitoring

frequency

New plants

(yearly

average)

Existing

plants (yearly

average)

New

plants

(daily

average)

Existing

plants

(daily

average)

50–100 150–200 150–400 ND ND

Continuous

measurement (2)

100–300 80–150 80–200

> 300 (Pulverised

combustion) 10–75 10–130 25–110 25–220

> 300 (Fluidised

bed boilers) (1)

20–150 20–180 ND

(1) The lower end of the range is achieved by high efficient wet FGD system. The higher end can be achieved by a

boiler / in-bed sorbent injection.


10.4.2.4 Dust emissions to air

BAT 58. In order to reduce dust emissions to air from the combustion of iron and steel

process gases, only or in combination with other gaseous, liquid, and/or solid fuels, 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 low

averaged low dust or ash

content, as much as the

iron- and steel-works

allow it

Generally applicable, within the


availability of different types of

fuel

b. Blast furnace gas pretreatment at

the iron- and steel-works plant

Use of one or a

combination of dry

dedusting devices

primary (e.g. deflectors,

dust catchers, cyclones,

electrostatic precipitators)

and/or subsequent dust

abatement secondary

dedusting techniques

(cyclones, venturi

scrubbers, hurdle-type

scrubbers, venturi

scrubbers, annular gap

scrubbers, wet

electrostatic precipitators,

disintegrators)

Generally Only applicable if blast

furnace gas is combusted

c.

Basic oxygen furnace gas

pretreatment at the iron- and steel-

works plant

Use of dry (e.g. ESP or

bag filter) or wet (e.g.

wet ESP or scrubber)

Generally Only applicable if

basic oxygen furnace gas is

combusted

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dedusting one or a

combination of dedusting

techniques (e.g.

deflectors in combination

with venturi-type

scrubbers or dry or wet

ESP). Further description

is given in the Iron and

Steel BREF

d. Electrostatic precipitator (ESP)

See descriptions in

Section 10.8. Can be

combined with WFGD

for enhanced dust

reduction

Only applicable to plants

combusting auxiliary fuels with

high ash content in a significant

proportion coal and to plants

combusting liquid fuels in a

significant proportion (> 10–15%

of the yearly fuel input) with high

ash content

e. Bag filter



The BAT-associated emission levels (BAT-AELs) for dust emissions to air from the

combustion of iron and steel process gases are given in Table 10.36.


combustion of iron and steel process gases, or multi gaseous fuel combustion,

including iron and steel process gases

Combustion

plant type Fuel diet


(

1)

O2

reference

level (%)

Monitoring

frequency

Daily

average

or

average

over the

sampling

period

Yearly

average

Average of

samples

obtained

during one

year

Boiler Iron and steel

process gas(es),

alone or in

combination

with other

gaseous fuels

2–15 (3) < 1–7 - 3

Continuous

measurement

CCGT < 2–5 NA < 1–4 15

Periodic

measurement:

4 times/yr

Boiler

Iron and steel

process gas(es)

with liquid fuels,

alone or in

combination

with other

gaseous fuels

8–45 (1) 2–15 - 3

Continuous

measurement

Iron and steel

process gas(es)

with coal, alone

or in

combination

with other

gaseous and

or/liquid fuels

4–25 1–15 - 6 Continuous

measurement

(1) The upper end of the range (15–45 mg/Nm3) is expected to be achieved when firing liquid fuels.

(3) The upper end of the BAT-AEL range may be higher on days when auxiliary liquid fuels are used. In this case, the

higher end of the BAT-AEL range may correspond to the higher end of the BAT-AEL range reported in the BAT



NB: NA = No BAT-AELs

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10.4.3 BAT conclusions for the combustion of gaseous and/or liquid fuels on offshore platforms


to the combustion of gaseous and/or liquid fuels on offshore platforms,, They apply in addition

to the general BAT conclusions given in Section 10.1.


of gaseous and/or liquid fuels on offshore platforms, BAT is to use one or a combination of

the techniques given below.

Techniques Description Applicability

a. Minimise the 'spinning

reserve'

When running with spinning

reserve for operational reliability

reasons, the number of additional

turbines is minimised, except in

exceptional circumstances


b. 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


c. Load control

Operate multiple generator or

compressor sets at load points

which minimise pollution


d. Control pressure losses

Optimise and maintain inlet and

exhaust systems in a way that keeps

the pressure losses as low as

possible


e. Process optimisation

Optimise the process in order to

minimise the mechanical power

requirements


f. Heat recovery

Utilisation of gas turbine / engine

exhaust heat for platform heating

purposes


plants.

In existing plants, the

applicability may be

restricted by the level of heat

demand and the combustion

plant layout (space)

g. Injection timing Optimise injection timing in

engines

Generally applicable for

engines

h. Power integration of multiple

gas/oil fields

Use of a central power source to a

number of participating

installations platforms located at

different gas/oil fields


limited dependings on the

location of the different

gas/oil fields and on the

organisation of the different

participating installations

platforms, including

alignment of time schedules

regarding planning, start-up

and cessation of production

{This BAT conclusion is based on information given in Sections 7.4.4.1, 7.4.4.2 and 3.3.4}

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gaseous and/or liquid fuels on offshore platforms, BAT is to use one or a combination of

the techniques given below.


a. Dry low-NOX burners

(DLN) See description in Section 10.8

Applicable to new gas turbines

(standard equipment) within the

constraints associated with the fuel

quality variations.

The applicability may be limited for

existing gas turbines by: availability of

retrofitting package (for low load

operation), complexity of the platform

organisation and space availability

b. Lean-burn concept See description in Section 10.8 Only Generally applicable to new gas-

fired engines

c. Low-NOX burners See description in Section 10.8 Generally Only applicable to boilers

d. Advanced computerised

process control system See description in Section 10.8



plants may be constrained by the need

to retrofit the combustion and/or

control command system(s)



gaseous and/or liquid fuels in gas turbines on offshore platforms, BAT is to use one or a

combination of the techniques listed in BAT 42 and BAT 49.


The BAT–associated emission levels for NOX and CO emissions to air are presented given in

Table 10.37.


the combustion of gaseous and/or liquid fuels in open-cycle gas turbines on offshore

platforms

Plant type

BAT-AELs (mg/Nm3) (

2)

Monitoring

frequency

NOX NOX (yearly

average) CO

Daily average

Average over the

sampling period

(yearly

average

Average over

the sampling

period

New gas turbines

combusting gaseous fuels

(3)

5 7–50 (4) 6–40 < 75 50

Continuous

measurement or

PEMS

Existing gas turbines(1)

combusting gaseous fuels

(3)

ND < 50–290

(1)

6–125 < 100

Continuous

measurement or

PEMS

Existing/New dual fuel

gas turbine combusting

liquid fuels

145–250 < 100

(1) The lower end of the BAT-AEL range iscan be achieved with last generation of DLN burners.

(2) These BAT-AELs are expressed for a turbine load of > 70 % when using DLN burners and about 70 % when not

using DLN burners when the monitoring is performed periodically.

(3) This includes single fuel and dual fuel gas turbines.

(4) The higher end of the BAT-AEL range is 250 mg/Nm3 if DLN burners cannot be used, e.g. due to poor quality

fuels.


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10.5 BAT conclusions for multi-fuel-fired plants

10.5.1 BAT conclusions for the combustion of process fuels from the chemical industry industrial process fuels produced by the chemical industry

, in addition to the general BAT conclusions given in Section 10.1


apply in addition to the general BAT conclusions given in section 10.1 are generally applicable

to combustion plants using process fuels from gaseous and/or liquid process fuels in the

chemical industry, individually, in combination, or simultaneously including their mixture with

other gaseous and/or liquid fuels.

10.5.1.1 General environmental performance in the combustion of chemical process fuels


plants using of process fuels from the chemical industry in boilers process fuels, including

the mixture with other fuels, BAT is to ensure stable and increased combustion conditions

by use a combination of the techniques in BAT 4 and listed below.


a.

NC fuel Pretreatment of

process fuel from the

chemical industry

Perform fuel pretreatment at the chemical

installation on and/or off the site of the

combustion plant to improve the

environmental performances of fuel

combustion


b. Advanced computerised

control system See description in Section 10.8 Generally applicable

c. Process control Combination of primary measures Generally applicable



plants using chemical industry process fuels, including the mixture with other fuels, BAT

is to perform fuel characterisation and ultimate analysis with the frequency and elements

indicated in BAT 5. BAT is to integrate the outcome of the characterisation and analysis

into the advanced computerised process control system.

Description

The fuel analysis and characterisation describe the chemical composition and physical

characteristics of fuel, e.g. it gives the low heating value and identifies the substances that

can lead to the formation of the pollutants covered in these BAT conclusions.

Applicability

Applicable within the constraints given by the load variations needed to meet all the

chemical installation operations.


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BAT 64. In order to increase the energy efficiency of the combustion plants using

chemical industry process fuels, including mixtures with other fuels, BAT is to use one or a

combination of the techniques given in BAT 7 and below.


a Heat recovery by

cogeneration (CHP) See description in Section 10.8 Generally applicable



The BAT-associated energy efficiency levels infor the combustion of process fuels from the

chemical industry in boilers industrial process fuels, including their mixture with other fuels are

given in Table 10.38.

Table 10.38: BAT-associated energy efficiency levels (BAT-AEELs) in the for the combustion

plants using of process fuels from the chemical industry in a boiler process fuels,

including their mixture with other fuels

Type of plant Parameter Unit

BAT-AEPL

(yearly average,

LHV basis)

Generating only heat or

CHP plants whose recoverable heat generation

does not exceed the heat demand

New Net total fuel

utilisation

%

> 90


Generating only power or CHP plants whose

recoverable heat generation exceeds the heat

demand

New Net electrical

efficiency

above 38


Type of combustion

plant

BAT-AEEPLs (1)




3) (

4)


Boiler using liquid

process fuels from the

chemical industry,

including when mixed

with HFO, gas oil and/or

other liquid fuels

above 38

>37.4

30 to above 38

35.6–37.4

> 90

80–96

80 to above 96

80–96

Boiler using gaseous

process fuels from the

chemical industry,

including when mixed

with natural gas and/or

other gaseous fuels

40–42.5

to above 42 38–40 78–95 78–95


(2) These BAT-AEELs apply to CHP combustion plants and to combustion plants generating only power.

(3) These BAT-AEELs apply to CHP combustion plants and to combustion plants generating only heat.

(4) These BAT-AEELs may not be achievable in the case of an excessively low potential heat demand.

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BAT 65. In order to prevent and/or reduce NOX emissions to air while limiting NH3 and

CO emissions to air from combustion plants using process fuels from the chemical

industry process fuels, including the mixtures with other fuels, BAT is to use one or a

combination of the techniques given below:.


a. (Advanced) lLow-NOX

burners (LNB)

See description in


b. Air staging combustion See description in

Section 10.8


Applicable to existing plants within the

constraints given by furnace size and

design.

c. Fuel staging (reburning)

See description in

Section 10.8.

Applying fuel staging when

using liquid fuel mixtures

may require a specific burner

design


d. Flue-gas recirculation See description in

Section 10.8



constraints given byassociated with

furnace size and design, chemical

installation safety

e. Selective non-catalytic

reduction (SNCR)

See description in

Section 10.8.



constraints given byassociated with

furnace size and design, chemical

installation safety.




case of plants operated in peak-load

mode with frequent fuel changes and

frequent load variations

f. Selective catalytic

reduction (SCR)

See description in

Section 10.8.



constraints given byassociated with duct

configuration, space availability, as well

as chemical installation safety.





plants operated in peak-load mode.


plants of < 100 MWth

g. Fuel choice See description in

Section 10.8



different types of fuel

h. Water/steam addition See description in

Section 10.8


water availability

i. Advanced control system See description in


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The BAT-associated emission levels for NOX, NH3 and CO from combustion plants using

process fuels from the chemical industry, including the mixtures with other fuels are presented



combustion plants using process fuels from the chemical industry process fuels,

including the mixtures with other fuels

Fuel Pollutant Unit

BAT-AEL Monitoring

frequency Yearly average Daily

average

Mixture of gases and/or

liquids

NOX

mg/Nm3

70–200 (1)(2)

90–250 (1)(2)

Continuous

measurement NH3 < 1–5

(3) ND

CO < 1–20 ND

(1) The lower end of the range is associated with the use of gas-prevailing fuel blends (H2 up to 72 % vol in gases).

(2) With the exception of nitrogen-rich liquid-prevailing fuel blends (N up to 24 % w/w in liquids) where the upper

end of the yearly average range is 380 mg/Nm3 and no value is determined for daily average.


Fuel phase

BAT-AELs (mg/Nm3)

Monitoring

frequency

NOX CO

Yearly average

Daily average or

average over the

sampling period

Yearly

average

New plant Existing plant New

plant

Existing

plant

New or

existing

plant

Mixture of gases and liquids 30–85 80–290 (1) 50–110

100–

330 (1)

< 1–30 Continuous

measurement Gases only 20–80 70–180 30–100 85–210 < 1–30

(1) For existing plants of < 100 MWth using fuels with a nitrogen content higher than 0.6 % (w/w), the higher end of

the BAT-AEL range is 380 mg/Nm3.


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BAT 66. In order to reduce SOX, HCl and HF emissions to air from the combustion plants

using of process fuels from the chemical industry process fuels in boilers, including their

mixtures with other fuels, BAT is to use one or a combination of the techniques given

below.


a.

Wet flue-gas

desulphurisation

(Wet FGD)

See description in

Section 10.8



constraints given byassociated with duct

configuration, space availability, as well

as and as well chemical installation

safety.

Wet FGD and seawater FGD are not

applicable to combustion plants operated



restrictions for applying wet FGD or

seawater FGD to combustion plants of

< 300 MWth, and for retrofitting

combustion plants operated in peak-load

mode with wet FGD or seawater FGD

b. Wet scrubber

See description in

Section 10.8.

The wWet scrubbing is used

to removes HCl and HF when

no Wet FGD is used to

removereduce SOX emissions

c.

Furnace Boiler sorbent

injection (in-furnace or

in-bed)

See description in

Section 10.8

d.

Duct sorbent injection

(DSI) (Dry in-duct

sorbent injection)

See description in

Section 10.8. The technique

is used in combination with a

dust abatement technique

e. Spray-dry absorber

(SDA)

See description in

Section 10.8

f. Seawater FGD See description in

Section 10.8

g. Fuel choice See description in

Section 10.8



different types of fuel


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The BAT-associated emission levels for SO2 SOX, HCl and HF emissions from the combustion

plants of process fuels from the chemical industry in boilers process fuels, including when

mixed with other fuels, are given in

Table 10.40 (for SO2) and 10.41 (for HCl and HF).

Table 10.40: BAT-associated emission levels (BAT-AELs) for SO2 SOX, emissions to air from the

combustion plants using of process fuels from the chemical industry in a boiler

process fuels, including the mixtures with other fuels

Pollutant Unit Monitoring frequency

BAT-AELs (mg/Nm3)

Yearly average (1)

Daily average or

average over the

sampling period

(2)

SOXSO2 mg/Nm³ Continuous measurement 10–110 90–200

(1) The yearly BAT-AELs do not apply to plants operated in peak- or emergency-load modes.



conclusions that apply to the combustion of the corresponding auxiliary fuel and to the case of plants operated in


Table 10.41: BAT-associated emission levels (BAT-AELs) for HCl and HF emissions to air from the


process fuels, including the mixtures with other fuels

Pollutant Unit Monitoring frequency

BAT-AEL

Average of samples taken during

one year

HCl

mg/Nm³ Periodic measurements

4times/yr

< 1–8

HF < 0.1–2

Combustion

plant total

rated

thermal

input

(MWth)

BAT-AELs (mg/Nm3)

Monitoring

frequency

HCl HF

Average over the sampling period

New plant Existing plant New plant

Existing plant

< 100 < 1–10 2–15 < 0.1–4 0.2–10 Continuous

measurement ≥ 100 < 1–5 < 1–9 (1) < 0.1–2 < 0.1–5 (

2)

(1) In the case of plants operated in peak- or emergency-load modes, the BAT-AEL range is 2–15 mg/Nm3.

(2) In the case of plants operated in peak- or emergency-load modes, the BAT-AEL range is 0.2–10 mg/Nm3.


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BAT 67. In order to reduce emissions to air of dust, particulate-bound metals, and trace

species from the combustion plants using of process fuels from the chemical industry in

boilers process fuels, including the mixtures with other fuels, BAT is to use one or a



a. Fuel choice


By switching to a different fuel or

modulating the fuel blending, the

corresponding emissions are reduced. Use of a combination of process fuels

from the chemical industry and auxiliary

fuels with low averaged dust or ash

content



availability of different types

of fuel, which may be

impacted by the energy policy

of the Member State.

b. Bag filter See description in Section 10.8 Generally applicable


constraints given by space

availability. c.

High-performance

electrostatic

precipitator (ESP)


d. Dry, semi-dry or wet

FGD system See description in Section 10.8


technique is mainly used for

SOX, HCl and/or HF

abatement



The BAT-associated emission levels emissions of dust as well as particulate-bound metals and

trace species from the combustion plants using of process fuels from the chemical industry in

boilers process fuels, including mixtures with other fuels, are given in

Table 10.42 and

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Table 10.43.

Table 10.42: BAT-associated emission levels (BAT-AELs) for dust emission to air from the


process fuels, including mixtures with other fuels

Combustion

plant total rated

thermal input

(MWth)


Monitoring

frequency



New plant Existing

plant New plant

Existing

plant

All sizes < 1 2–5 < 1 2–15 10 ND 2–10

(1)

< 20 2–25 (1)

Continuous

measurement (1) The upper end of the BAT-AEL range may be higher on days when auxiliary liquid fuels are used. In this case, the

higher end of the BAT-AEL range may correspond to the higher end of the BAT-AEL range reported in the BAT




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Table 10.43: BAT-associated emission levels for particulate-bound metals and trace species

emissions to air from the combustion plants using chemical industry process fuels,

including mixtures with other fuels

Pollutant Unit BAT-AEL Monitoring

frequency average of samples obtained during one year

Sb+As+Pb+Cr+

Co+Cu+Mn+Ni

+V

mg/Nm3 0.05–0.2

Periodic

measurement: 4

times/yr


BAT 68. In order to reduce mercury emissions to air from the combustion plants using

chemical industry process fuels, including the mixtures with other fuels, BAT is to use one

or a combination of the techniques given below.


a. Bag Filter See description in Section

10.8


Applicable to existing plants within

the constraints given by duct

configuration, space availability, as

well as chemical installation safety.

b. ESP See description in Section

10.8

c. SCR See description in Section

10.8

d.

FGD technique (e.g. wet

limestone scrubbers, spray

dryer scrubbers or dry

sorbent injection)

See descriptions in Section

10.8

e.

Carbon sorbent

(e.g. activated

carbon) injection in the flue-

gas

See description in Section

10.8

f. Fuel pretreatment

Fuel washing, blending and

mixing in order to reduce

the Hg content

Applicability requires previous survey

for characterising the fuel and for

estimating the potential effectiveness

of the technique



The BAT-associated levels for mercury emissions to air from the combustion plants using

chemical industry process fuels, including mixtures with other fuels, are given in Table 10.44.

Table 10.44: BAT-associated emission levels for mercury from the combustion plants using

chemical industry process fuels, including mixtures with other fuels

Pollutant Unit

BAT-AEL Monitoring


year

Mercury µg/Nm3 0.1–8

Periodic

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10.5.1.7 Emissions of volatile organic compounds and polychlorinated dibenzo-dioxins and -furans TOC, dioxins and furans emissions to air

BAT 69. In order to reduce emissions to air of volatile organic compounds and

polychlorinated dibenzo-dioxins and -furans TOC, dioxins and furans emissions to air

from the combustion plants using of process fuels from the chemical industry in boilers

process fuels, including the mixtures with other fuels, BAT is to use one or a combination

of the techniques given in BAT 4 and below.


a. Activated carbon injection /

reactor See description in Section 10.8

Only applicable to combustion

plants using fuels derived from

chemical processes involving

chlorinated substances.

Generally applicable for to new

plants.


within the constraints given

byassociated with duct

configuration, space availability,

as well as chemical installation

safety

b. Selective catalytic reduction

(SCR)


The SCR system is adapted and

larger in comparison with an

SCR system only used for NOX

reduction

c.

Rapid quenching through wet

scrubbing / FGflue-gas

condenser

See description of wet scrubbing

/ FGflue-gas condenser in

Section 10.8



The BAT-associated emission levels for PCDD/F and TVOC dioxins and furans from the

combustion plants using of process fuels from the chemical industry in boilers process fuels,

including the mixtures with other fuels, are given in Table 10.45.

Table 10.45: BAT-associated emission levels (BAT-AELs) for PCDD/F and TVOC emissions to air

dioxins and furans from the combustion plants of chemical industry process fuels

from the chemical industry in a boilerthe mixtures

Pollutant Unit

BAT-AELs

Monitoring frequency Average of samples obtained

during one year Average over the

sampling period

Dioxins and furans

PCDD/F (1)

pg I-TEQ/Nm3 1–100


2 times/yr

TVOC mg/Nm3 1–24 10


2 times/yr

(1) These BAT-AELs only apply to combustion plants using fuels derived from chemical processes involving

chlorinated substances.


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10.6 BAT conclusions for the waste co-incineration of waste


to combustion plants firingco-incinerating wasteas part of the combusted feedstock,. They apply

in addition to the general BAT conclusions given in Section 10.1.

Unless otherwise stated, the BAT-AELs in this section apply when waste is co-incinerated.

When co-incinerating waste, the BAT-AELs set out in the fuel-specific sections apply in

relation to those fuels, as well as in relation to the mix of those fuels and the waste co-

incinerated, and taking into account BAT 70 bis.

10.6.1.1 General environmental performance in waste co-incineration


plants co-incinerationg of wastes in combustion plants, to ensure stable combustion

conditions, and to reduce emissions to air, BAT is to use a combination of the techniques

listed in BAT 4 and of the techniques given 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 Industries BREF. Acceptance

criteria are set for critical parameters such as

heating value, water content, ash content,

chlorine and fluorine content, sulphur

content, nitrogen content, PCB, metals

(volatile (Hg, Tl, Pb, Co and Se) and non-

volatile (e.g. V, Cu, Cd, Cr, Ni)) and

phosphorus and alkaline content (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


b. Waste choice

Careful selection of waste type and mass

flow, together with limiting the percentage

of the most polluted waste that can be co-

incinerated. Limit Hgmercury and chlorine

entering the combustion process as elevated

proportions components of the waste


c. Waste drying

On-site or off-site pre-drying of the waste

before introducing it into the combustion

chamber, with a view to maintaining the high

performance of the boiler

The Aapplicability may be

limited by insufficient

recoverable heat from the

process, by the required

combustion conditions, or by

the waste moisture content

d. Waste

pretreatment

See techniques described in the Waste

Treatment Industries and Waste Incineratiorn

BREFs, including milling, pre-combustion in

fluidised bed boilers, pyrolysis, gasification,

etc.

The Aapplicability may depend

on the combustion plant size

and configuration, on the type

of waste, and on the space

availability

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e. Waste mixing

with the main fuel

Effective mixing between waste and the

main fuel, as an heterogeneous or poorly

mixed fuel stream or an uneven distribution

may influence the ignition and combustion in

the boiler and has to should be prevented

Mixing is only possible when

the grinding behaviour of the

main fuel and waste are similar

more or less the same or when

the amount of waste is very

small compared to the main fuel

flow

{This BAT conclusion is based on information given in Sections 9.1, 9.4.2 and 9.4.3}

BAT 70 bis. 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 defined in the WI BREF.

BAT 71. In order to reduce diffuse emissions to air and odorous substances from the

storage and handling of waste to be co-incinerated, BAT is to use a combination of the

techniques listed in BAT 9 and of the related BAT in the Waste Treatment Industries

BREF.

{This BAT conclusion is based on information given in Sections 9.4.1}

BAT 72. In order to minimise the impact on by-product and residues recycling from the

waste co-incineration of waste in combustion plants, BAT is to maintain the a good quality

of gypsum, ashes and slags andas well as other residues and by-products at the same level

as those occurring without the co-incineration, 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 listed in BAT 70 and/or by restricting the co-incineration to waste fractions

with pollutant concentrations similar to those in other combusted primary fuels.

{This BAT conclusion is based on information given in Sections 9.4.6}


BAT 73. In order to increase the energy efficiency of the co-incineration of combustion

plants co-incinerating waste, BAT is to use one or a combination of the techniques listed in

BAT 7, and BAT 18, BAT 24, BAT 25, and BAT 82 depending on the main fuel type(s)

combusted used and on the plant configuration.


The BAT-associated energy efficiency levels (BAT-AEELs) are the ones given in Table 10.10

for the co-incineration of waste with biomass- and/or peat-fired combustion plants co-

incinerating waste, and the ones given in Table 10.2 for the co-incineration of waste with coal-

and/or lignite-fired plants co-incinerating waste.



NH3 emissions from waste co-incineration in coal- and lignite-fired combustion plants,

BAT is to use one or a combination of the techniques given in BAT 19 and of the technique

below.


a Circulating fluidised bed

boiler See description in Section 10.8

Applicable for new plants and

when firing waste that can be

fragmented to the fraction size

necessary to create a fluidised bed


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The BAT-associated emission levels (BAT-AELs) for NOX and CO and NH3 are given in Table

10.46. Table 10.46: BAT-associated emission levels for NOX, CO and NH3 emissions to air from waste co-

incineration in coal- and lignite- fired combustion plants

Combustion

plant rated

thermal

input

(MWth)

BAT-AEL for NOX

(yearly average -

mg/Nm3)

BAT-AEL for NOX

(daily average -

mg/Nm3)

BAT-AEL

for CO

(yearly

average -

mg/Nm3)

BAT-AEL

for NH3 (1)

(yearly

average -

mg/Nm3)

Monitoring

frequency New

plants

Existing

plants

New

plants

Existing

plants

< 100 100–

200 100–270 ND 10–100 < 6

Continuous

measurement

100–300 100–

150 100–180 ND 10–100 < 6

> 300 FBC

(coal-lignite)

and PC

lignite firing

50–150 50–180 140–220 12–80 < 6

> 300 PC

coal firing 65–100 65–180 80–125 80–220 1–55 < 6



NH3 emissions from the waste co-incineration in biomass- and peat-fired combustion

plants, BAT is to use one or a combination of the techniques given in the BAT 26 and of

the technique given below.


a. Circulating fluidised bed

boiler See description in Section 10.8

Applicable for new plants and

when firing waste that can be

fragmented to the fraction

necessary to create fluidised bed


The BAT-associated emission levels for NOX, CO and NH3 are given in Table 10.47.

Table 10.47: BAT-associated emission levels for NOX from the co-incineration of waste in biomass-

and peat-fired combustion plants

Combustion

plant rated

thermal input

(MWth)


frequency

BAT-AEL


Yearly

average

Daily

average

Yearly

average

Daily

average

50–100

NOX

mg/Nm3

Continuous

measurement

70–200 120–260 70–250 120–310

100–300 50–130 100–220 50–140 100–220

> 300 40–130 65–150 40–140 95–150

All NH3 (

1) < 1–7 ND

CO 4–80 ND


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waste co-incineration of waste with in coal- and/or lignite-fired combustion plants, BAT is

to apply one or a combination of the techniques listed in BAT 21 and of the technique

given below.


a. Waste selection / limitation

Selection of waste streams with

low S, Cl, Fsulphur, chlorine

and/or fluorine content.

Limitation of the amount of

waste to be co-incinerated



types of waste to be co-

incinerated, which may be

impacted by the waste

management policy of the local /

national competent authority


The BAT-associated emission levels for SOX are the ones given in Table 10.48. Table 10.48: BAT-associated emission levels for SOX emissions to air from waste co-incineration in

coal- and lignite-fired combustion plants with coal and lignite S content < 3 %

Combustion

plant rated

thermal input

(MWth)

BAT-AEL (mg/Nm3) (

3)

Monitoring

frequency

New plants

(yearly

average)

Existing

plants (yearly

average)

New

plants

(daily

average)

Existing

plants

(daily

average)

50–100 150–200 150–400 ND ND

Continuous

measurement (2)

100–300 80–150 80–200

> 300 (Pulverised

combustion) 10–75 10–130 25–110 25–220

> 300 (Fluidised

bed boilers) (1)

20–150 20–180 ND

(1) Lower end of the range is achieved with a highly efficient wet FGD system. The higher end can be achieved with

boiler / in-bed sorbent injection.


(3) When low-S waste is co-incinerated, the lower SOX emissions should be expected, e.g. a plant co-incinerating

more than 30 % (LHV basis) low-S waste emits at the lower end of the given ranges.

The BAT-associated emission levels for halogens are given in

Table 10.49.

Table 10.49: BAT-associated emission levels for halogen emissions to air from waste co-

incineration in coal- and lignite-fired combustion plants

Pollutant BAT-AEL (mg/Nm3) Monitoring frequency

HCl < 1–5 Continuous measurement

HF < 0.1–2 Continuous measurement

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BAT 77. In order to prevent and/or reduce SOX, HCl and HF halogen emissions to air

from the waste co-incineration of waste with in biomass and/or peat-fired combustion

plants, BAT is to use one or a combination of the techniques listed in BAT 28 and of the



a. Waste selection / limitation

Selection of waste streams with

low S, Cl, Fsulphur, chlorine

and/or fluorine content.

Limitation of the amount of

waste to be co-incinerated



types of waste to be co-

incinerated, which may be

impacted by the waste

management policy of the

Member State local / national

competent authority

b. Semi-dry absorber (SDA) See description in Section 10.8 Generally applicable



The BAT-associated emission levels for SOX, HCl, and HF are given in

Table 10.50.

Table 10.50: BAT-associated emission levels for SOX, HCl, and HF emissions to air from the co-

incineration of waste in biomass- and peat-fired combustion plants

Fuel

(% in yearly and

LHV basis)

Pollut

ant Unit

Monitoring

frequency

BAT-AEL

Yearly

average

Daily

average

Peat % in the fuel-

waste feed < 20%

SOX

mg/N

m³

Continuous

measurement (1)

1–50 8–70

Peat % in the fuel-

waste feed ≥ 70 % 100–165 ND

20 Peat % in the

fuel-waste feed <

70

Intermedia

te, within

the ranges

given in

the two

lines above

ND

Straw % in the

fuel-waste feed <

25 %

HCl

1–8 3–12

Straw % in the

fuel-waste feed

100%

< 18 ND

25 Straw % in

the fuel-waste feed

< 100

Intermedia

te, within

the ranges

given in

the two

lines above

ND

All HF < 0.01–0.8 ND


BAT 78. In order to reduce dust and particulate-bound metals emissions to air from the

waste-co-incineration of waste with in coal and/or lignite-fired combustion plants, BAT is

to use one or a combination of the techniques listed in BAT 22.


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The BAT-associated emission levels for dust emissions to air are the same as the ones given in

Table 10.7.

The BAT-associated emission levels for metals emissions are given in

Table 10.51.

Table 10.51: BAT-associated emission levels (BAT-AELs) for metals emissions to air from the

waste co-incineration of waste with in coal- and/or lignite-fired combustion plants

BAT-AEL (average of samples obtained during one year) Monitoring

frequency Sb+As+Pb+Cr+Co+Cu+Mn+Ni+V

(mg/Nm3)

Cd+Tl (µg/Nm3)

0.025–0.2 0.1–6

Periodic

measurements: 4

times/yr

Combustion plant

total rated thermal

input (MWth)

BAT-AELs (1)

Averaging period Monitoring

frequency

Sb+As+Pb+Cr+

Co+Cu+Mn+Ni

+V (mg/Nm3)

Cd+Tl

(µg/Nm3)

< 300 0.025–0.2

0.004–0.5 0.1 0.4–6 12

Average over the

sampling period

of samples obtained

during one year

Periodic

measurement

4 times/yr

≥ 300 0.025–0.2

0.0025–0.2 0.1–6 8

Average of samples

obtained during one

year Yearly average

Periodic

measurements

4 times/yr



waste co-incineration of waste with in biomass- and/or peat-fired combustion plants, BAT

is to use one or a combination of the techniques in BAT 29 and of the technique given

below.


d. Fuel / waste choice

By switching to a different fuel/waste

or modulating the fuel/waste blending

(e.g. lower ash or lower chlorine

fuel/waste) the corresponding

emissions can be reduced



different types of fuel/waste,

which may be impacted by the

energy and waste management

policies of the Member State

e. Bag filter See description in Section 10.8


given by space availability f.

High-performance

electrostatic

precipitator


g. Activated carbon

injection / reactor See description in Section 10.8

Applicable for further metal

reduction

h. Wet FGD See description in Section 10.8

Applicable in combination with

other dedusting devices (e.g. bag

filter or ESP), when used for

desulphurisation



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The BAT-associated emission levels for dust are presented in Table 10.13.

The BAT-associated emission levels for metals are presented given in Table 10.52.

Table 10.52: BAT-associated emission levels (BAT-AELs) for particulate-bound metal emissions to

air from the waste co-incineration of waste with in biomass and/or peat-fired

combustion plants

BAT-AELs

(average of samples obtained during one year) Monitoring

frequency Sb+As+Pb+Cr+Co+Cu+Mn+Ni+V

(mg/Nm3)

Cd+Tl

(µg/Nm3)

0.075–0.3 0.8–5 22 (1)

Periodic

measurements:

4 times/yr (1) The higher end of the range is achieved when co-incinerating waste containing high levels

of Cd+Tl (e.g. 5–6 mg/kg) in a high share (e.g. > 60 % - LHV basis)



BAT 80. In order to reduce mercury emissions to air from the waste co-incineration of

waste with in biomass-, peat-, coal- and/or lignite-fired combustion plants, BAT is to use

one or a combination of the techniques listed in BAT 23 and of the technique given below.


a. Waste stream control

Selection of waste with a low

Hgmercury content, blended with

the fuel in order to obtain a

homogeneous mixture, and in a

limited amount in order to avoid

additional Hgmercury emissions


associated with the waste

management policy of the

Member State strategy agreed at

the local / national level


The BAT-associated emission levels for mercury in coal- and/ lignite-fired combustion plants

co-incinerating waste are the ones given in Table 10.8 and in Table 10.9.

Table 10.53: BAT-associated emission levels for mercury emissions to air from waste co-

incineration in biomass- and peat-fired combustion plants

Pollutant Unit

BAT-AELs Monitoring


year

Mercury µg/Nm3 0.2–10

Periodic

measurements: 4

times/yr

10.6.1.7 Emissions of volatile organic compounds and polychlorinated dibenzo-dioxins and -furans TOC, dioxins, and furans emissions to air

BAT 81. In order to reduce emissions of volatile organic compounds and polychlorinated

dibenzo-dioxins and -furans TOC, dioxins, and furans emissions to air from the waste-co-

incineration of waste with in biomass-, peat-, coal- and/or lignite-fired combustion plants,

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BAT is to use a combination of the techniques listed in BAT 4 and of the techniques given

below.


a Activated carbon

injection / reactor See description in Section 10.8

Generally Aapplicable to

biomass- and peat-fired

combustion plants

b Selective catalytic

reduction (SCR)

See description in Section 10.8. The

SCR system is adapted and larger in

comparison with an SCR system only

used for NOX reduction


c

Rapid quenching

through wet scrubbing /

FGflue-gas condenser

See description of wet scrubbing /

FGflue-gas condenser in Section 10.8 Generally applicable



The BAT-associated emission levels for PCDD/F dioxins and furans and TVOC emissions to air

are given in Table 10.54.

Table 10.54: BAT-associated emission levels (BAT-AELs) for TOC PCDD/F, dioxins and furans

and TVOC emissions to air from the waste co-incineration of waste with in biomass-,

peat-, coal- and/or lignite-fired combustion plants

Type of

combustion plant Pollutant Unit BAT-AELs Averaging

period

Monitoring

frequency

Biomass-, peat-,

coal- and/or

lignite-fired

combustion plant

PCDD/F ng I-

TEQ/Nm3

< 0.002–0.03

Periodic

measurement

Average over the

sampling period

Periodic

measurements

2 times/yr

Biomass-, peat-,

coal- and/or

lignite-fired

combustion plant

TVOC mg/Nm3

< 0.1–3 5 Yearly average Continuous

measurement 0.5–4.5 15 Daily average


10.7 BAT conclusions for gasification and IGCC plants


to all gasification plants directly associated to combustion plants, including IGCC plants. They

apply in addition to the general BAT conclusions given in Section 10.1.

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BAT 82. In order to increase the energy efficiency of the IGCC and gasification plants,

BAT is to use one or a combination of the techniques described in BAT 7 and of the



a.

Heat recovery from the


As the syngas needs to be

cooled down to be further

cleaned, energy can be

recovered for producing

additional steam to be added

to the steam turbine cycle,

enabling additional electrical

power to be produced

Only aApplicable to IGCC plants

and to gasification plants

connecteddirectly associated to

boilers with syngas pretreatment

requiring cooling down of the

syngas temperature

b.

Integration of gasification and

combustion processes blocks

The plant can be designed

with full integration of the

air supply unit (ASU) and

the gas turbine, all the air

fed to the ASU being

supplied (extracted) from

the gas turbine compressor

The aApplicability is limited to

IGCC plants by the flexibility

needs of the integrated plant to

quickly provide the grid with

electricity when the renewable

power plants are not available is

shutting down

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


Only aApplicable to new plants

d.

High temperature and pressure

gasification

Use of gasification

technique with high

temperature and pressure

operating parameters, in

order to enable the

maximum carbon

conversion ratemaximise the

efficiency of energy

conversion

Only aApplicable to new plants

e. Design improvements

Design improvements, such

as:

geometry modification

of the draught tube dip

tube;

modification of the

system attack serpentine

cooling of the process

burners;

geometry modification

of the neck and throat

gasifier refractory;

installation of an

expander to recover

energy from the syngas

pressure drop before

combustion

Generally applicable to existing

IGCC plants

{This BAT conclusion is based on information given in Sections 4.3.4, 4.3.1.1 and 3.3.4}


The BAT-associated net electricalenergy efficiency levels for gasification and IGCC plants are


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Table 10.55: BAT-associated environmental performance levels for the energy efficiency levels

(BAT-AEELs) of for gasification and IGCC plants

Type of combustion

plant configuration

BAT-AEPLAEELs (yearly average – LHV basis)

Net electrical efficiency (%) of thean IGCC

plant


(%) of thea gasification

plant – New and or

existing plants New plants Existing plants

Gasification plant

connecteddirectly

associated to a boiler

without prior syngas

treatment

NA NA > 98

Gasification plant

connecteddirectly

associated to a boiler with

prior syngas treatment

NA NA > 91

IGCC plants NA 34–46 > 91

NB: NA = No BAT-AELs

10.7.1.2 NOX, and CO emissions to air

BAT 83. 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.

Dry low-NOX burners

(DLN) for the combined-

cycle gas turbine

See description in

Section 10.8

Only applicable to gas turbines.


Applicable and on a case-by-case basis for

existing plants, depending on the

availability of a retrofittableing package.

Not applicable for H-syngas content of

> 25 %

b.

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 ASU is reused to cool

down reduce the

combustion temperature

in the gas turbine, by

being premixed with the

syngas before

combustion

Only applicable when an ASU is used for

the gasification process

c.


Steam injection in the

gas turbine combustion

chamber

See description in

Section 10.8. Some

intermediate pressure

steam from for the steam

turbine is reused for this

purpose


Only applicable to gas turbines.


water availability

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d. Selective catalytic

reduction (SCR)

See description in

Section 10.8

Generally applicable to new and existing

coal PC plant > 100 MWth, in combination

with other primary techniques

Not applicable in the case of combustion

plants operated in emergency-load mode.


constrained by the availability of sufficient

space.




e.


Complete combustion,

along with good furnace

design, the use of high-

performance monitoring

and automated process

control techniques, and

maintenance of the

combustion system.

See description in




The BAT-associated emission levels for NOX and CO are presented given in Table 10.56.


IGCC plants

Combustion

plant total

rated thermal

input

(MWth)

BAT-AELs (mg/Nm3)

Monitoring

frequency

NOX

(yearly average)

NOX

(daily average or average

over the sampling period)

CO

(yearly

average)

New

plants

Existing

plants

New

plants

Existing

plants

New or

existing

plant

≥ 100 10–25 12–45 1–35 1– 60 < 1–5 Continuous

measurement


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10.7.1.3 SOX emissions to air

BAT 84. In order to prevent and/or reduce SOX emissions to air from IGCC plants, BAT

is to use the technique given below.


a. Acid gas removal (AGR)

Sulphur compounds from the

feedstock of a gasification

process are removed from the

syngas via an AGR, e.g.

including a (HCN/)COS

hydrolysis reactor and the

absorption of H2S using a solvent

such as MDEA amine. 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 the case of biomass IGCC

plants due to the very low

sulphur content in biomass



The BAT-associated emission levels (BAT-AELs) for SO2 SOX emissions to air are 3–

16 mg/Nm3, expressed as a yearly averages. Only SO2 is continuously measured, SO3 is

periodically measured (e.g. during calibration).


10.7.1.4 Dust, particulate-bound metals, ammonia and halogen emissions to air

BAT 85. In order to prevent or reduce dust, particulate-bound metals, ammonia and

halogen emissions to air from IGCC plants, BAT is to use one or a combination of the



a. Syngas filtration

Dedusting using Filters used are 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

Generally applicable for dust

removal. Bag filters and ESP are

applicable for syngas temperature

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 low syngas temperature at

the gasifier outlet (<1100°C)

Generally applicable for dust

removal, in the case of a low

syngas temperature at the gasifier

outlet (1100 ºC)

c. Syngas washing

Syngas passes through a water

scrubber, downstream of other

dedusting technique(s), where

chlorides, ammonia, particles and

halides are separated

Generally applicable, downstream

of other dedusting technique(s)


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The BAT-associated emission levels for dust and particulate-bound metal emissions to air are


Table 10.57: BAT-associated emission levels (BAT-AELs) for dust and particulate-bound metals

emissions to air from IGCC plants

Combustion plant

total rated

thermal input

(MWth)

BAT-AELs

Monitoring

frequency

Sb+As+Pb+Cr+C

o+Cu+Mn+Ni+V

(mg/Nm3)

(Average over the

sampling period

of samples

obtained during

one year)

Hg (µg/Nm3)

(Average over the

sampling period

of samples

obtained during

one year)

Dust (mg/Nm3)

(yearly average)

≥ 100 < 0.025 < 1

< 0.12 0.4– < 2.5

Dust: continuous

measurement

Metals: periodic

measurements

once/yr


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10.8 Description of techniques

10.8.1 General techniques

Technique Description

Fuel choice

By switching to a different biomass The use of fuel with a low content

of potential pollution-generating compounds (e.g. lower sulphur, ash,

nitrogen, mercury, fluorine or chlorine content in the fuel), the

corresponding emissions are reduced

Multi-fuel firing

The replacement of part of a fuel with another fuel with a better

environmental profile (e.g. syngas from biomass gasification instead of

coal)

Process 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

Combination of primary measures: complete combustion, along with

good furnace design, fuel choice, multi-fuel firing, the use of high

performance monitoring and automated process control techniques, and

maintenance of the combustion system

Complete combustion


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/or use of advanced control system

Complete combustion, going along with good furnace design, the use of

high-performance monitoring and automated process control techniques,

and maintenance of the combustion system

10.8.2 Techniques to increase energy efficiency


Ultra-supercritical steam

parameters

The uUse of a steam circuit, including double or triple steam reheat

systems, in which steam can reach pressures about 300 above 250–

300 bar and temperatures about 600 above 580–600 °C

Supercritical steam parameters

The uUse of a steam circuit, including steam reheating systems, in

which steam can reach pressures above 220.6 bar and temperatures of

above 374 > 540°C

Heat recovery by cogeneration

(CHP)

Recovery of heat mainly from the steam cooling for producing hot

water/steam which is used in industrial activities or in district heating.

Additional recovery are possible from:

flue-gas

grate cooling

circulating bed

CHP readiness

A CHP-ready plant will includeThe provisionmeasures 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 when compared to the separate generation of the heat and

power produced. ItThis 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 systems and control/instrumentation

systems are suitable for upgrade. Later connection of back-pressure

turbine(s) is also possible

Regenerative feed-water heating Preheating water in the steam circuit with recovered heat from the

plant

Preheating of combustion air Preheating combustion air by reusing part of the recovered heat

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Steam turbine upgrades Increased temperature and pressure of medium-pressure steam,

addition of low-pressure turbine, modification of blade geometry

Advanced computerised control

system

See Section 10.8.1

Computerised control of the main combustion parameters in order to

improve the combustion efficiency and completeness

Cooling tower discharge Air emission release through a cooling tower and not via a dedicated

stack

Wet stack

The dDesign 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

Fuel specification in supplier

contract or internal document

The fuel supplier or the internal management adheres to the moisture

(and size) specification in the contract or internal document

Fuel drying (lignite, biomass,

peat)

The moisture is reduced by means of recovered heat (steam or

flue-gas) or mechanical means (Press) to the level required (e.g. 40–

45 %) to achieve the optimal functioning of equipment (boiler, ESP),

improve combustion conditions, increase the overall energy efficiency

and avoid VOC direct emissions from the dryer

Fuel preheating (gaseous, liquid

fuels) Preheating of fuel by using recovered heat

Flue-gas condenser

The flue-gas condenser is aA heat exchanger where water is preheated

by the flue-gases before it is heated in the steam condensers. The

vapour content in the flue-gases thus condenses as it is cooled by the

heating water. The flue-gas condenser is used both to increase the

energy efficiency of the combustion plant and to remove dust and SOX

from the flue-gas

Steam double reheat Improved plant performance is possible by employing a double, rather

than single, steam reheat cycle

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)

Process gases management

system

Process gas managementA systems that enables directing the fuel 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

Combustion optimisation See Section 10.8.1

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10.8.3 Techniques to reduce emissions of NOX and/or CO to air


Fuel choice The useChoice of a fuel with low Nnitrogen content

Combustion

optimisation See Section 10.8.1

Air staging (OFA)

The cCreation of several combustion zones in the combustion chamber with

different oxygen contents for controllingreducing NOX emissions and

ensuring complete an optimised combustion. The technique involves

sub-stoichiometric firing (i.e. with deficiency of air) into a primary

combustion zone and a second reburn combustion zone (running with excess

air) the addition of the remaining air or oxygen into the furnace to complete

improve combustion. Some old small boilers may require a capacity reduction to

allow the space for air staging. Boosted OFA systems such as high pressure or multi-direction injection

systems enhance the effect of this technique by preventing the formation of

stratified laminar flow and enabling the entire furnace volume to be used

more effectively for the combustion process

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 flame

temperature and limiting the O2 content for nitrogen oxidation, thus limiting

the NOX generation. It implies the reinjection supply of waste 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

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 complete 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- or advanced-low-NOX burners (ULNB) includes combustion staging

(air/fuel) and flue-gas recirculation. Dry low-NOX burners (DLN) are used in

gas turbines The performance of the technique may be influenced by the

boiler design when retrofitting old plants

Dry low-NOX burners

(DLN)

Gas turbine burners that include the pre-mixing 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

Low-NOX combustion

concept in diesel

engines

The technique consists of a combination of internal engine modifications, e.g.

combustion and fuel injection optimisation (In diesel engines, the central

element of the ‘low NOX combustion’ concept is the very late fuel injection

timing in combination with early inlet air valve closing), cycle

optimisation.turbo-charging or Miller cycle

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/air ratio in the zones where NOX is

producedgenerated so that the peak flame temperature is less than the

stoichiometric adiabatic flame temperature, therefore suppressingreducing

thermal NOX formation. The optimisation of this concept is called 'advanced

lean-burn concept' and is still not applicable to dual fuel engines due to

misfiring problems

Fuel staging

(reburning)

The technique is based on the reduction of the flame temperature or localised

hot spots by creation of several combustion zones in the combustion chamber

with different injection levels of fuel and air. The retrofit may be less efficient

in the case of smaller plants than in larger plants : a low impulse primary

flame is developed in the port neck; a secondary flame covers the root of the

primary flame reducing its core temperature

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Combination of

primary techniques for

NOX reduction

Combination of primary techniques: e.g. air staging including boosted

overfire air, fuel staging, flue-gas recirculation, LNB

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 One or two

layers of catalyst may be applied. A higher NOX reduction is achieved with

the use of higher amounts of catalystseveral layers of catalyst (two layers).

The technique design can be modular, special catalyst can be used and/or

preheating can be used to cope with low loads or with a broad flue-gas

temperature window. 'In-duct' or 'slip' SCR is a technique that combines

SNCR with downstream SCR which reduces ammonia slip from the SNCR

unit

Selective non-catalytic

reduction (SNCR)

Selective reduction of nitrogen oxides with ammonia or urea without 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 900850 °C and 10501000 °C for optimal reaction

Combined SNCR +

SCR Combination of the SNCR and SCR techniques


Water or steam is are used as a diluents for reducing the combustion

temperature in gas turbines, engines or boilers and the thermal NOX

formation, either by being premixed with the fuel prior to its combustion (fuel

emulsion, humidification or saturation) or directly injected in the combustion

chamber (water/steam injection)

Low excess air

The technique is mainly based on the following features:

minimisation of air leakages into the furnace

careful control of air used for combustion

modified design of the furnace combustion chamber

Combined techniques

for NOX and SOX

reduction

The uUse of complex and integrated abatement techniques for combined

reduction of NOX, SOX, and often other pollutants, from the flue-gas, e.g.

activated carbon, DESONOX processes

Advanced

computerised process

control system

See Ssection 10.8.2

Low-NOX combustion

concept in engines

In diesel engines, the central element of the ‘low NOX combustion’ concept is

the very late fuel injection timing in combination with cycle optimisation, e.g.

thanks to late exhaust valve closing in new two-stroke engine

Oxidation catalysts

The uUse of catalystscatalytic converter (that contain precious metals in

general such as palladium or platinum) where anto oxidising reaction converts

oxidise carbon monoxide (CO) and unburnt hydrocarbons (HC) with oxygen

to form CO2 and water vapour, using the O2 contained in the flue-gas

Circulating fluidised

bed boiler (CFB

boilers)

Fluidised bed combustion takes place with the injection of fuel into a hot

turbulent bed, where combustion air has also been injected from the bottom of

the fluidised bed boiler by fluidisation of the bed. The bed (sand) of particles,

including fuel (between 1 and 3 % of the bed material), ash and sorbents, is

fluidised by upwards flowing air in a furnace, and the bed temperature allows

the fuel to burn. Due to the combustion temperatures of about 750–950 ºC

and the long residence time, the burnout of the fuel is very high and,

therefore, the related emissions of combustion products are relatively low. In

CFB boilers, the small size of the bed particles induces their transportation

through the furnace to the second pass of the boiler. These particles exiting

the furnace are separated from the flue-gas flow by a cyclone or by other

separation methods, and recirculated back to the fluidised bed

Reduction of the

combustion air

temperature

Use combustion air at ambient temperature. The combustion air is not

preheated in a regenerative air preheater

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10.8.4 Techniques to reduce emissions of SOX, HCl and/or HF to air


Fuel choice The useChoice of a fuel with low S, Cl and F sulphur, chlorine and/or

fluorine content

Multi-fuel firing

The rReplacement of part of a fuel with another fuel with a better

environmental profile (e.g. coal – biomass, coal – syngas from

biomass gasification, instead of coal only)

Boiler sorbent injection

(in-furnace or in-bed)

Boiler sorbent injection consists of tThe direct injection of a dry

sorbent into the gas stream of the combustion chamber, or of the

adjunction 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

Duct Dry sorbent injection

(DSI)

The injection and dispersion of a dDry powder sorbent is introduced

and dispersed in the flue-gas stream. The materialsorbent (e.g. trona,

sodium bicarbonate, hydrated lime) reacts with acid gases (e.g. the

sulphur gaseous sulphur species, HCl) to form a solid which has to be

is removed by filtration (bag filter or electrostatic precipitator)

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 within the flue-gas

stream

Spray-dry absorber (SDA)

A suspension/solution of alkaline reagent is introduced and dispersed

in the flue-gas stream. The material reacts with the sulphur gaseous

sulphur species to form a solid which has to beis removed by filtration

(bag filter or electrostatic precipitator)

Wet flue-gas desulphurisation

(Wet FGD)

Technique or ensemblecombination of scrubbing techniques where by

which sulphur is removed from flue-gases through various processes

generally involving an alkaline sorbent for capturing SO2 and

transforming it into solid sulphur. 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 thea separation of the droplets

is required before discharging the flue-gases. The resulting liquid has

to be is treated by a waste water process and the insoluble matter is

collected by sedimentation or filtration

Seawater FGD

A specific non-regenerative type of scrubbing using the alkalinity of

the seawater as a solvent where a large amount of seawater is

available. Requires Generally requires an upstream abatement of dust

Combined techniques for NOX

and SOX reduction

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, DESONOX processes

Wet scrubbing Use of a liquid, typically water or a water-based solution, to capture

the acidic gas by absorption from the flue-gas

Retrofit gas/gas heater

Replacement of the gas-gas heater downstream of the wet FGD by a

multi-pipe heat extractor in order to avoid SOX leakage, or remove it

and discharge the flue-gas via a cooling tower or a wet stack

Flue-gas (FG) condenser See Section 10.8.2

Process gas management system See Section 10.8.2

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10.8.5 Techniques to reduce emissions of dust and/or metals including mercury to air


Fuel choice The useChoice of a fuel with low ash or metals (e.g. mercury) content

Cyclones Dust control system using gravitational forces and which is able to

process all types of flue-gases, in dry conditions

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.

Abatement efficiency may depend on the number of fields, residence time

(size), catalyst properties, and upstream particle removal devices. They

include in general between two to five fields for an improved efficiency.

Most modern (high-performance) ESPs have up to seven fields

Bag of Fabric filter

Bag or fabric filters are constructed from porous woven or felted fabric

through which gases are flowed passed to remove particles. The use of a

bag filter requires a fabric materialthe selection of a fabric suitable

adequate to for the characteristics of the flue-gas and the maximum

operating temperature

Activated carbon injection

This process is based on the adsorption of pollutant molecules by the

activated carbon. When the surface has adsorbed as much as it can, the

adsorbed content is desorbed as part of the regeneration of the adsorbent

Boiler sorbent injection See general description in Section 10.8.4. There are Cco-benefits in the

form of dust/ and metals emissions reduction

Dry or semi-dry FGD system

(e.g. SDA, DSI)

See general description in Section 10.8.4. There are Cco-benefits in the


Wet flue-gas

desulphurisation (FGD)

Wet FGD (WFGD)

See general description in Section 10.8.4. There are Cco-benefits in the


Carbon sorbent (e.g.

activated carbon) injection in

the flue-gas

Mercury absorption by carbon sorbents, such as activated carbon, with or

without chemical treatment. The sorbent injection system can be

enhanced by the addition of a supplementary bag filter

10.8.6 Techniques to reduce emissions to water


Adsorption on activated carbon

The removal of soluble substances (solutes) from the waste water by

transferring them to the surface of solid, highly porous particles (the

adsorbent). Activated carbon is typically used for the adsorption of

organic compounds and mercury

Aerobic biological treatment

The biological oxidation of dissolved organic substances 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, water or 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

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Coagulation and flocculation

Flocculation, sedimentation,

precipitation, neutralisation

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

The suspended matter can consist of large solids, settleable by gravity

alone without any external aids, and non-settleable material, often

colloidal in nature. Removal is then generally accomplished by

coagulation, flocculation, and sedimentation. Precipitation is the

formation of insoluble substances from dissolved matter and the

chemicals added

Crystallisation Softening,

evaporation, crystallization

The removal of ionic pollutants from waste water by crystallising them

on a seed material such as sand or minerals, working in a fluidised bed

process. Some combustion plants use crystallisation after evaporation

(see BAT 10)

Evaporation of waste water is a distillation process where water is the

volatile substance, leaving the concentrate as bottom residue to be

disposed of. Crystallisation is closely related to precipitation. In

contrast to precipitation, the precipitate is not formed by chemical

reaction in the waste water, but is produced on seed material such as

sand or minerals, working in a fluidised-bed process

Filtration

The separation of solids from waste water by passing them 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

Flotation techniques are used to separate large flocs or floating

particles from the effluent by bringing them to the surface of the

suspension

Ion exchange

The removal of ionic pollutants from waste water and their

replacement by more acceptable ions by transferring them to 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 used to decrease the pH. The precipitation of some

substances may occur during neutralisation

Oil/water separation

The removal of free oil from waste water by mechanical treatment

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 (SO32-

) to sulphate (SO42-

)

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. If

necessary, this may be followed by microfiltration or ultrafiltration.

Typical chemicals used for metal precipitation are lime, dolomite,

sodium hydroxide, sodium carbonate, sodium sulphide and

organosulphides. Calcium salts (other than lime) are used to

precipitate sulphate or fluoride

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Sedimentation

The separation of suspended solids by gravitational settling

Sedimentation is a solid-liquid separation technique that utilises

gravity to separate the insoluble metal complexes and solid particles

from the liquid effluent

Stripping, precipitation

The removal of volatile pollutants (e.g. ammonia) from waste water by

bringing them into 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

reusedWaste water stripping is an operation in which waste water is

brought into contact with a high flow of a gas current in order to

transfer volatile pollutants from the water phase to the gas phase. The

pollutants are removed from the stripping gas so it can be recycled into

the process and reused

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