spri combustion guidance 2013

8/10/2019 SPRI Combustion Guidance 2013

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SPRI Combustion Guidance 2013

Page 1 of 35Published December 2013

Scottish Pollutant Release Inventory Reporting

Combustion Guidance Note

December 2013


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SPRI Combustion Guidance 2013 Page 1 of 35Published December 2013

CONTENTS

1 Introduction 2

1.1

Scope of the guidance note 2

1.2 Release estimation techniques (RETs) 21.2.1 Uncertainty 41.2.2

Limits of detection 4

1.3 Access to further information 41.4

Disclosing information you provide 4

1.5 Feedback 4

2 Emissions to air 5

2.1

Relevant pollutants 5

2.2 Emission sources 6

2.2.1

Point source emissions 62.2.2 Fugitive emissions 6

2.3 Quantification of emissions 62.3.1

Sampling data 6

2.3.2 Using continuous emission monitoring systems (CEMS) data 72.3.3

Emission factors 9

2.3.4 Fuel analysis data 192.3.5 Fugitive emissions 222.4 Substances reported as 22

3 Emissions to water and waste water 24

3.1

Relevant pollutants 24

3.2

Emission sources 24

3.3 Quantification of emissions 243.4

Substances reported as 26

3.5 If no emission factors or other RETs are available 27

4 Off-site waste transfers 28

4.1 Relevant wastes 284.2 Transboundary shipments of hazardous waste 28

5 References and further information 29

Appendix ANormalisation of emission concentrations 31Appendix BConversion factors 33

Appendix CGlossary 34


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1 Introduction

This Guidance Note provides information to assist you in preparing submissions to the ScottishPollutant Release Inventory (SPRI). It has been developed through a process of consultation

between industry stakeholders and ourselves. It is part of a range of guidance and tools producedto assist in the completion of the annual SPRI return. Information on the range of guidance notesis available on the SPRI website1.

By providing a series of guidance notes, we seek to ease the burden on industry and to raise thequality of SPRI data. In addition, the increasing use of SPRI data in policy-making and forcomparisons on a sector and national basis has led to a need for increased consistency in SPRIdata and an improved understanding of uncertainty.

1.1 Scope of the guidance note

This Note covers activities that are regulated as Combustion Activities under the Pollution

Prevention and Control (Scotland) Regulations 2000 (as amended) (PPC). Included within thescope are Part A prescribed/listed activities regulated under Section 1.1 of the PPC Regulations2.

Following the guidance in this note, in conjunction with the General SPRI Guidance Note 2013 3,will ensure that you meet the reporting requirements of the E-PRTR Regulation4. The General Noteincludes a more prescriptive indication of methods of measurement and calculation which shouldbe applied to produce a SPRI data return. Data on transboundary shipments of hazardous andnon-hazardous waste taking place during the reporting year must also be reported to meet the E-PRTR requirements.

Note that you are not required to include any emissions due to historic activities (for example, fromcontaminated land) in your SPRI return, unless the original contamination is related to an ongoingactivity.

Emissions reported relate to operations of the activity (direct emissions from point and fugitivesources) and from unauthorised or unplanned events termed accidental emissions (e.g. resultingfrom equipment failure).

For accidental emissions you should not include any emissions resulting from routine maintenance,such as the release associated with recharging cooling fluids, as these releases will be includedwithin the total mass reporting within the SPRI return

1.2 Release estimation techniques (RETs)

This Note provides information on RETs for the SPRI substances relevant to this industry sector.Emphasis has been placed on providing information on the most common emissions from thesector. However, the absence of an RET for a substance in this Note does not imply that anemission should not be reported to the SPRI. The obligation remains to report on all relevantemissions.

In general, there are four types of RETs that may be used to evaluate emissions:

1http://www.sepa.org.uk/spri

2

http://www.legislation.gov.uk/ssi/2000/323/contents/made3http://bit.ly/uuRWwH

4http://prtr.ec.europa.eu/.
http://www.sepa.org.uk/air/process_industry_regulation/pollutant_release_inventory.aspxhttp://www.sepa.org.uk/air/process_industry_regulation/pollutant_release_inventory.aspxhttp://bit.ly/uuRWwHhttp://bit.ly/uuRWwHhttp://prtr.ec.europa.eu/http://prtr.ec.europa.eu/http://bit.ly/uuRWwHhttp://www.sepa.org.uk/air/process_industry_regulation/pollutant_release_inventory.aspx


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Sampling or direct monitoring;

Emission factors;

Fuel analysis or other engineering calculations; and

Mass balance.

Depending on the particular site, pollutant or process, each of the above techniques may be themost appropriate to use. You should have an understanding of the factors that lead to theselection of the most appropriate RET and be able to justify why the technique has been selected.You should always select the RET based on the application for which it has been designed.

However, there are cases where mandatory RETs exist, such as when reporting emissions underEuropean Union (EU) Directives or in accordance with authorisation or permit conditions.Examples of this are the reporting requirements under the Large Combustion Plant Directive(LCPD)5 and the European Union Emissions Trading System (EU ETS) for greenhouse gases(GHGs)6. For consistency, you should also consider extending the use of such methods toadditional parts of the installation that are not subject to the mandatory requirement, but that have

SPRI reporting obligations. At a minimum the SPRI data should match other reporting obligations,where there are common reportable substances, such as carbon dioxide emissions.

In the absence of a mandatory methodology, you should use methods that have been agreed withSEPA for your industrial sector, where available. An example of this is the UK Electricity SupplyIndustry (ESI) methodology7that is developed for all pulverised coal, large-scale oil and gas-firedCombined Heat and Power (CHP) power generation plant. A summary is contained in relevantsections of this Note for use on similar types of plant.

Mandatory or industry methodologies should be used where available and site specific data in theform of monitored emission concentrations or mass balance techniques should be used whereappropriate. Measured emission concentrations should be ideally based on data obtained using

appropriately certified equipment, and/or accredited services. Continuous monitoring data shouldnormally be used in preference to periodically sampled data. Sections 2.3.1 and 2.3.2 containguidance on the use of sampling data for determination of emissions to air.

Where emission factors are used, preference should be given to the use of site-specific emissionfactors over those developed from other representative plant. However, in order to develop a site-specific emission factor, it is necessary to relate the level of emissions to an activity within theprocess. This is normally obtained from sampling data, or can be obtained from manufacturersinformation or by calculation. In the absence of such information, UK or international emissionfactors can be used. UK factors are presented in this Note and have been termed generic factors.

The RETs presented in this Note relate principally to representative operating conditions.However, it is important to recognise that emissions resulting from significant operating deviations(e.g. failure of abatement plant) and/or accidental events (e.g. spills) also need to be estimated. Inthe case of air emissions from spillage events, it may be necessary to make an estimate of theamount of substances released as vapour. For all spills, the additional emission is the netemission, i.e. the quantity of the SPRI reportable substance spilled, less the quantity recovered orconsumed during clean-up operations. Further information on RETs is available from the SPRIdocument entitled SPRI Operator Guidance on Release Estimation Techniques (RET)8.

5http://www.dhttp://www.defra.gov.uk/environment/quality/industrial/eu-international/lcpd/ .

6

http://ec.europa.eu/clima/policies/ets/index_en.htm.7See section 5 References and further information.

8http://bit.ly/u2MaLa.
http://www.defra.gov.uk/environment/quality/industrial/eu-international/lcpd/http://ec.europa.eu/clima/policies/ets/index_en.htmhttp://www.sepa.org.uk/air/process_industry_regulation/pollutant_release_inventory/operator_guidance.aspxhttp://www.sepa.org.uk/air/process_industry_regulation/pollutant_release_inventory/operator_guidance.aspxhttp://ec.europa.eu/clima/policies/ets/index_en.htmhttp://www.defra.gov.uk/environment/quality/industrial/eu-international/lcpd/


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1.2.1 Uncertainty

The level of uncertainty of a determination is important in judging whether a change in reportedemissions is important or not. For example, if the level of reported emissions from one year to the

next increases by 10%, this may not be a real increase if the level of uncertainty in themeasurement is 20%. In this case, two different values are reported but the actual emissionscould be the same.

The guidance given in this Note is aimed at reducing the variability and uncertainty in emissiondetermination.

1.2.2 Limits of detection

If the best available information indicates that a substance is not released from your process, report n/a forthat substance. Where a substance may be released but at a release concentration that is below the limit ofdetection, you also need to report n/a unless an alternative release estimation technique, such as mass

balance, produces an applicable result. By limit of detection we mean the lowest concentration which can bemeasured by the analytical method prescribed in the Permit, or such other method as we approve.

We recognise that there may be circumstances where some analyses in a series do not detect a substancebut others do. Provided that no more than 5% of the readings show a positive value, and the values obtainedare not more that 20% above the accepted limit of detection, you can treat them as if they were also reportedas below the limit of detection. In any other case, use the values obtained and make the assumption thatwhere the substance is reported as not detected it is present at 50% of the LOD. In these cases, you need tomultiply each concentration (that is, those measured at above the LOD as measured and those measured atbelow the LOD as of the LOD) by the total flow during the period that the measurement relates to in orderto determine the mass emission.

In some cases we may have agreed a different methodology with you for a particular substance or process.

If so, use this in place of the procedure above.If as a result of this methodology a positive result is obtained that is below the reporting threshold(BRT), it should be reported as Below Reporting Threshold (BRT) rather than n/a.

1.3 Access to further information

This Note does not provide detailed information on suggested measurement and monitoringtechniques as this is dealt with extensively in other guidance documents that we publish.References to monitoring guidance and other sources of reference information are included inSection 5 of this document.

1.4 Disclosing information you provide

The General SPRI Guidance Note provides information relating to commercial confidentiality.

1.5 Feedback

In order to improve the quality of our guidance, we would like to receive feedback from you on yourexperiences in using this Note. Such feedback will be taken into account in the preparation ofother guidance notes in this series, and in the updating of this document.

Feedback should be submitted to the SPRI team by email:

Email:[email protected]
mailto:[email protected]:[email protected]:[email protected]:[email protected]


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2 Emissions to air

2.1 Relevant pollutants

The combustion of fossil fuels will almost always lead to releases to air of CO2, CO, NOx andParticulates. Other pollutants will be released dependent on the fuel and combustion technologyused, particularly SO2. Smaller quantities of pollutants such as trace metals, hydrogen halides, un-burnt hydrocarbons, non-methane volatile organic compounds (NMVOCs) and dioxins may also beemitted, but they may have a significant influence on the environment due to their toxicity or theirpersistence.

Pyrolysis and gasification can be used to pre-treat fuels in order to remove impurities or to producefuel that can be combusted more readily. The fuels can be either pre-cleaned before combustionor directly combusted. The pollutants emitted from the process are therefore critically dependenton the fuel used and the nature of the process.

The following table illustrates the likely pollutants emitted from different types of fuel. The tableshould be taken as a guide only, and you should verify that there are no other pollutants emittedfrom your process.

Table 1 Guide of main pollutants emitted by combustion activities to air

Fuel type Inputs Potential air emissions

Solid Coal NOx, CO, CO2, SOx, particulate matter(including PM10), fugitive dust, trace metals,PCBs and PAHs, hydrogen halides,methane, NMVOCs, dioxins, N2O

Biomass+ NOx, CO, CO2, SOx (low), particulate matter

(including PM10), CH4, NMVOCs, tracemetals (from sewage sludge)

Liquid Fuel oil NOx, CO, CO2, SOx, particulate matter(including PM10), PCBs and PAHs, hydrogenchloride, trace metals, and dioxins

Gaseous Natural gas NOx, CO, CO2, CH4

Secondary fuels Solid, liquid or gaseous NOx, CO, CO2, SOx, particulate matter(including PM10), PCBs and PAHs, hydrogenhalides, trace metals, NMVOCs, H2S,

ammonia and dioxins+The percentage proportion of the total CO2 attributable to biomass (non-fossil fuel) can berecorded within Section C of the SPRI reporting form, within the Carbon Dioxide substance. Thisis the percentage of the total CO2emissions attributable to biomass fuels. Where you recordBRT you can still enter a percentage figure within the Biomass Percentage box. If youcalculate you are above the reporting threshold enter the total CO2 figure which should includeboth fossil fuel emissions as well as biomass-derived emissions.

Subsidiary or substitute fuels may contain other pollutants that will require reporting.


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2.2 Emission sources

2.2.1 Point source emissions

These emissions are exhausted via a stack or vent, i.e. a single point source into the atmosphere.Abatement equipment, e.g. an electrostatic precipitator (ESP) or fabric filter (bag house) can beincorporated into the exhaust system prior to discharge to atmosphere. Point source emissions willbe the most significant emission source for combustion activities.

2.2.2 Fugitive emissions

Fugitive emissions are those that are not released from a point source such as a stack. Examplesof fugitive emissions include dust from coal and ash stockpiles and entrainment of pollutants duringmaterial handling. Leaks from valves and flanges are also examples of fugitive emissions. Withappropriate management and control, these emission sources are generally minor for the

combustion sector. Only fugitive emissions that leave the site need to be reported to the SPRI.Whilst contained spills would therefore not need to be reported, you should report vapouremissions that may have dispersed.

2.3 Quantification of emissions

2.3.1 Sampling data

In order to use sampling data to estimate emissions, information is required on both the flowrateand pollutant concentration. In order to accurately determine annual emissions, sampling for SPRIreporting should be performed under conditions representative of annual operations and ideally in

accordance with methods or standards that we have approved.

Care should be taken with relying on the results of one spot sample in order to report annualemissions, unless you are certain that the process conditions are representative of annual averageoperations. Where a process has a number of steady state conditions, it may be necessary to takesamples under each operating condition and average the result according to the length of time theprocess operates at each condition. Similarly, where process conditions at the time of the spotsampling are uncertain, it may be necessary to take several samples and to average the results inorder to provide the final annual emission estimate. Good engineering judgement should be usedin order to select the most appropriate sampling time and data to use. You should be able to justifythe sampling programme selected.

Sampling as part of a permit condition may require that the monitoring be undertaken at maximumload (i.e. higher than annual operating conditions) and this should be taken into account in theannual emission estimates. When in doubt, the proposed sampling protocols should be confirmedby us.

In order to estimate annual emissions from sampling data, the first step is to multiply the measuredemission concentrations by the volumetric flowrates of the emission source at the time of the test.Assuming that representative sampling has been undertaken, these emission rates are thenaggregated together for the annual operating time.

Care should be taken to ensure that the emission concentration and flowrate are compatible, e.g.normalised emission concentrations should be multiplied by normalised volumetric flowrates or

actual, measured emission concentrations multiplied by actual, measured volumetric flowrates.Normalised emission rates are quoted in terms of a standard oxygen concentration, and are


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usually dry gas, at a temperature of 273K and a pressure of 101.3 kPa. It is always good practiceto confirm the basis of measured data. Formulae for conversion between normalised and actualemission concentrations are contained in Appendix A of this Note.

Sampled emission concentrations are also often reported in parts per million (ppm). In order toestimate annual emissions, these need to be converted to mg/m3at the emission temperature atwhich the volumetric flowrate is measured. Formulae for converting ppm to mg/m3are containedin Appendix B.

The following section shows how to calculate emissions based on stack sampling data expressedin mg/m3. An example involving PM10 emissions is included, although the same generalmethodology is applicable for the majority of the substances listed in the SPRI.

E = C x Q x 0.0036 x [Op Hours] (1)

Where: E = emission rate of pollutant (kg/yr)

C = pollutant concentration (mg/m3

)Q = volumetric flowrate of the emission (m3/s)0.0036 = the conversion factor from mg/s to kg/hrOp hours = the operating hours of the activity per year

Where the pollutant concentration is consistent over the averaging period (i.e. one year), equation1 can be written as:

E = C x M x V x 10-6 (2)

Where: E = emission rate of pollutant (kg/yr)C = average pollutant concentration (mg/m3)

M = mass of fuel burnt in one year (te dry fuel)V = standard volume of flue gas per tonne of fuel (m3/te dry fuel)

Example 1

The following example is for PM10emissions from combustion activities using equation 1.

Operating hours = 24 hours/day, 280 days per yearPM10 emissionconcentration

= 50 mg/m3(normalised to 273K, dry, 3% oxygen)

Emission volumetricflowrate

= 10 m3/s (normalised to 273K, dry, 3% oxygen)

E = C x Q x 0.0036 x 24 x 280= 50 x 10 x 0.0036 x 24 x 280= 12,096 kg/yr

The use of continuous emission monitoring systems (CEMS) is considered below, which inessence, follows the same principles as using spot sampling data.

2.3.2 Using continuous emission monitoring systems (CEMS) data

The revised LCPD contains requirements for the installation of CEMS for the measurement of SO2,

NOx and PM emissions., for certain combustion plants Knowledge of the corresponding volumetricflowrate is required in order to determine mass emissions.


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In general, you should use CEMS data that are from appropriately calibrated instrumentationoperating within stated tolerances. Although CEMS can report real-time emissions over a varietyof time periods automatically, it may be necessary to manually determine annual emissions fromsuch data, especially for periods where data may be out of tolerance. In any case, where annualemissions are calculated within the software of a CEMS, it is good practice to manually check thedata in order to ensure that the automatic calculations are accurate.

For the Electricity Supply Industry, it may not be possible to obtain valid CEMS data during start-upand shut-down. In these circumstances, for the purposes of reporting to the SPRI, for example, analternative approach using emission factors, can be used by agreement.

The Waste Incineration (WID) and LCP Directives require subtraction of confidence intervals (asspecified in the appropriate Directive) from CEM average values, to provide "validated" averagesthat are compared against the given ELVs for compliance purposes. This is acceptable forrelatively short-term average periods, but not long-term periods (such as a whole year and SPRI

returns) when positive and negative errors (random errors) would be increasingly expected tocancel each other out. Therefore, confidence intervals must not be subtracted from the averagevalues generated from the raw emissions data, prior to calculation of annual mass emissions(unless part of an over-riding written agreement with SEPA).

Prior to using CEMS to determine emissions, it is preferable to agree the methodology forcollecting and averaging the data with us.

The basic equation for determining emissions is equation 1, adjusted for the appropriate timeperiod of the measurement. It must be applied for each time period for which emissionmeasurements are available in the year, following the guidance given in Section 2.3.1. Normally,the measurement time periods are the same, such that it is possible to simply multiply the average

emission rate by the operating time per year to obtain the annual emission. However, it may bethat the measurement time periods vary and then equation 3 should be used.

E = 1n (Eix t) (3)

Where: E = emission rate of pollutant (kg/yr)Ei = emission rate of pollutant over time period (t)t = time period for emission measurementn = number of time periods in the year

Example 2

This example shows how SO2 emissions can be calculated using equation 3 based on theaverage CEMS data for 6 days of a week. In the case of the example, it is assumed that theprocess operates for 24 hours per day, 48 weeks per year and that the CEMS data isrepresentative of annual operations.

E1 = 13.2 kg/hr E4 = 12.2 kg/hrE2 = 12.6 kg/hr E5 = 14.0 kg/hrE3 = 11.2 kg/hr E6 = 13.4 kg/hr

E = [(13.2 x 24) + (12.6 x 24) + (11.2 x 24) + (12.2 x 24)+ (14 x 24) + (13.4 x 24)] x48 (t)

= 88,243 kg/yr


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2.3.3 Emission factors

(a) General

Emission factors can be used to estimate emissions to the environment. In this Note, theyrelate the quantity of substances emitted from a source to some common activityassociated with those emissions. General emission factors have been developed from avariety of sources, but this guidance draws upon UK information in particular.

Provided that unit operations remain consistent, representative monitoring data can beused to generate site-specific emission factors. The emission factor will be the ratio of themeasured or calculated pollutant emission to the process activity (e.g. fuel flowrate). Site-specific emission factors should be periodically verified to ensure their continued validity,especially where fuel quality varies throughout the year. Where different fuels are used, theemission when using each fuel separately should be determined, and the results added

together.

Where an emission factor or other RET is not available for a particular substance, then youmay review published information or use the emission factors listed in this Note. However,care needs to be taken in selecting appropriate emission factors to ensure that theconditions under which the emission factor has been determined are representative of thesites operations.

Emission factors are usually expressed as the weight of a substance emitted multiplied bythe unit mass, volume, distance, or duration of the activity emitting the substance. In somecases, and particularly in the case of SO2, the emission factor is based on fuel analysisdata (see Section 2.3.4).

Emission factors are used to estimate an activitys emissions by the general equation:

E = [A x Op hours] x EF (4)

Where: E = emission rate of pollutant (kg/yr)A = activity rate of process (te/hr or m3/hr)Op hours = operating hours per year of activity (hr/yr)EF = controlled emission factor of pollutant per activity (kg/te or

kg/m3)

Within equation 4 it is important to note that EF is the emission factor for the pollutant released toatmosphere, i.e. after the emission has been abated.

Depending on the availability of information, equation 4 can be rewritten as:

E = M x EF (5)

Where: E = emission rate of pollutant (kg/yr)M = activity rate in terms of mass of fuel burnt in the year (te/yr)EF = controlled emission factor of pollutant per activity (kg/te dry fuel)


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The following example shows how to estimate annual emissions using equation 4.

Example 3

Estimating carbon monoxide (CO) emissions from light fuel oil combustion serves as an exampleof the simplest use of emission factors. Consider an industrial boiler that burns 4,000 litres of oilper hour and operates for 300 days per year. The CO emission factor given is assumed to be0.6 kg of CO per 1000 litres of oil burned.

A = 4,000 litres per hour (4 m3/hour)Op hours = 24 hours per day, 300 days per yearEF = 0.6 kg/m

E = 4 x 24 x 300 x 0.6= 17,280 kg/yr

Emission factors developed from measurements for a specific location can sometimes beused to estimate emissions at other sites provided that the processes are comparable insize and operation. As previously mentioned, it is advisable to have an emission factorreviewed and approved by SEPA prior to its use for SPRI submissions.

In the case of new or modified processes, initial emission factors can be obtained frommanufacturers data with sampling undertaken during commissioning to confirm theassumed values.

(b) Carbon dioxide factors

The European Commission has established guidelines for the monitoring and reporting of

Green House Gasses pursuant to European Directive 2003/87/EC establishing the EUETS9. The European guidance sets out the approved methodology for estimating CO 2emissions based on emissions from regular operations and abnormal events, includingstart-up and shut-down and emergency situations over the reporting period.

Under the EU ETS guidelines, the Commission has put monitoring and reporting into aEuropean level regulation, to bring harmonisation across Europe. The Monitoring andReporting Regulation (MRR) is defined within the Commission Regulation (EU) No.601/2012 of 21 June 2012 on the monitoring and reporting of greenhouse gas emissionspursuant to Directive 2003/87/EC of the European Parliament and of the Council.

Information and guidance of the change in reporting can be found:http://ec.europa.eu/clima/policies/ets/monitoring/documentation_en.htm

(c) Solid fuel combustion factors

(i) Electricity supply industry (ESI)

The emission factors contained in this Section (and in d(i) and e(i)) represent currentlyagreed factors for electricity generating stations. They have been developed frommeasurements on large electricity generating stations (greater than 300 MW th) and are

9http://www.sepa.org.uk/climate_change/solutions/eu_emissions_trading_system/monitoring_and_reporting.aspx
http://ec.europa.eu/clima/policies/ets/monitoring/documentation_en.htmhttp://ec.europa.eu/clima/policies/ets/monitoring/documentation_en.htmhttp://www.sepa.org.uk/climate_change/solutions/eu_emissions_trading_system/monitoring_and_reporting.aspxhttp://www.sepa.org.uk/climate_change/solutions/eu_emissions_trading_system/monitoring_and_reporting.aspxhttp://www.sepa.org.uk/climate_change/solutions/eu_emissions_trading_system/monitoring_and_reporting.aspxhttp://ec.europa.eu/clima/policies/ets/monitoring/documentation_en.htm


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regularly updated. Further detail on these emission factors is contained in the ESImethodology.

Also included in Table 2 are estimates of the amount of as received coal that would needto be burnt in a year in order to exceed the reporting thresholds. A value for the tonnes ofcoal that will need to be burnt for SO3has not been provided, as it will be reported with SO2(which is either normally estimated from CEMS or fuel analyses in accordance with Section2.3.4). ESI plant burning less than the indicated tonnage of coal should therefore reportemissions as BRTfor that particular pollutant provided that there are no other sources ofthe pollutant on site.

Emissions of NOx from ESI coal-fired power plants that do not use CEMS for annual massemissions can be calculated from the fuel burn and NOxfactors which have been agreedwith us on a station-specific basis.

Particulate matter concentrations are normally measured by CEMS for ESI plant. The

annual mass emission should be calculated from the instantaneous measuredconcentration multiplied by the instantaneous volumetric emission, as in equation 1. Whereload and abatement performance is constant, the average concentration and flowrate canbe used (equation 2). For ESI plant it is generally assumed that each tonne of coalgenerates 9,000 m3of flue gas normalised at 6% oxygen concentration.

The SPRI return requires the total, PM10and PM2.5fractions of the particulate matter to bereported. For ESI coal-fired plant, the PM10and PM2.5 fractions are assumed to be 80%and 40% respectively of the total particulate matter emitted. You can also use these factorswhen burning peat or biomass.

Emissions of hydrogen chloride, chlorine and inorganic compounds as HCl and fluorine

and inorganic compoundsas HF are normally estimated from fuel analysis, as shown inSection 2.3.4.


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Table 2 UK ESI PI emission factors for large combustion plant

Pollutant Species Emission factor (kg/tonneas received coal burnt) for

pulverised coal plant withor without FGD

[te coal burnt forabove reporting

threshold]

Dioxins and furans (expressed as I-TEQ)++

1.5 x 10-11 [666,667]

Dioxins and furans (expressed asWHOTEQ)++

1.6 x 10-11 [625,000]

PCB (expressed as WHOTEQ) 1.8 x 10-10 [55,556]

PCB (expressed as total mass) 9.9 x 10-8 [1,010,101]

Benzo(a)pyrene (BaP) 9.0 x 10-7 [1,111,111]

Anthracene 2.7 x 10-7 [BRT]*

Benzo(b)fluoranthene 5.4 x 10-7

[1,851,852]Benzo(g,h,i)perylene 5.4 x 10-7 [1,851,852]

Benzo(k)fluoranthene 5.4 x 10-7 [1,851,852]

Chrysene 3.6 x 10-7 [BRT]*

Fluoranthene 4.5 x 10-7 [2,222,222]

Indeno(1,2,3-cd)pyrene 5.4 x 10-7 [1,851,852]

Naphthalene 4.9 x 10-5 [2,040,816]

Methane 1.4 x 10-2 [714,286]

Non-methane volatile organic

compounds

2.7 x 10-2 [370,370]

Carbon monoxide 1.1 [90,909]

SO3(reported as part of sulphur oxidesSO2and SO3as SO2)

6.3 x 10-2 -

Nitrous oxide 2.6 x 10-2 [384,615]

* - These emissions should always be reported as below the reporting threshold given therequired fuel burn.++ - Where possible I-TEQ should be reported in preference to WHO-TEQ (although reporting ofboth is acceptable).

Generic factorsIn the absence of other information, generic emission factors based on currently achievableemission rates from various combustion plants can be used. The generic emission factors in thisSection (and in d(ii) and e(ii)) have been taken from existing UK regulatory guidance forcombustion appliances10, 11, 12, 13 supplemented with Local Authority Guidance14,15.

10HMSO. Process Guidance Note IPC S3 1.01 Combustion processes Supplementary Guidance Note November 1995.

11HMSO Process Guidance Note S2 1.01 Combustion processes: large boilers and furnaces 50MW(th) and over November 1995.

12HMSO. Process Guidance Note S2 1.03 Combustion processes: gas turbines September 1995.

13HMSO. Process Guidance Note IPR 1/2 Combustion processes: gas turbines September 1994.

14Local Authority Unit. Assessment for second revision of PG1/4, Process Guidance Note for Part B. Gas turbines 20-50 MW rated

thermal input.

15

Local Authority Unit. Assessment for second revision of PG1/4, Process Guidance Note for Part B. Gas turbines 20-50 MW ratedthermal input.


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The existing UK regulatory guidance contains achievable emission data post-abatement in terms ofmg/MJ of net thermal input together with the equivalent normalised emission concentrations(mg/m3). Therefore, if you know the normalised emission concentration of your combustionappliance, you can calculate the equivalent emission factor in terms of mg/MJ and use equation 7below. The relevant mg/MJ and mg/m3values from the guidance are listed in Table 3, Table 5 andTable 7 for each fuel category. The generic emission factors (EFi) for coal-firing are presented inTable 3 below and are expressed in terms of the net heat input into the combustion appliance. Inorder to calculate the annual emission for the SPRI return, a variant of equation 4 should be used:

E = Aex EF x 10-6 (7)

Where: E = emission of pollutant(kg/yr)Ae = annual energy consumption(MJ/yr)EF = energy emission factor of pollutant (mg/MJ)

The emission factors also enable an estimate to be made of the size of combustion plant thatwould need to be operated in order for the emission to be above the reporting threshold values.These estimates are also included in Table 3 in terms of the average MWthnet thermal input of theplant, assuming that the combustion appliance operates for 100% of the year. If the combustionplant operates for less than 100% of the year, the calculated MW ththreshold can simply be dividedby the percentage operating time to provide the appropriate MWth threshold. For singlecombustion appliances that are rated less than the indicated MW ththreshold, a BRTreturn can bemade. However, if you have more than one combustion appliance on site, your aggregateemission may be above the threshold value.

Table 3 Solid fuel-firing generic emission factors (net basis)Technology Emission

factorParticulatematter

NOx CO

mg/MJ mg/m3 mg/MJ mg/m3 mg/MJ

mg/m3

Stoker boiler, in-furnacedesulphurisation*

EF 9 25 105 300 50 150

ThresholdBRT (Wth)

35 30 63

CFBC, in-beddesulphurisation*

EF 9 25 70 200 50 150

Thresholdfor BRT(MWth)

35 45 63

PFBC, in-beddesulphurisation andSNCR*

EF 9 25 21 60 10 30


35 151 315

PF boiler, dry lime injection,low-NOx burners**

EF 9 25 225 650 35 100


35 14 91

PF boiler, wet limestonescrubbing, low-NOx burners

EF 5 15 87 250 35 100


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Technology Emissionfactor

Particulatematter

NOx CO

mg/MJ mg/m mg/MJ mg/m mg/MJ

mg/m

and re-burn*** Thresholdfor BRT(MWth)

63 36 91

PF boiler, wet limestonescrubbing, low-NOx burnersand SCR***

EF 5 15 70 200 35 100


63 45 91

Boiler, 20-50MWth, stokerfiring****

EF 108 300 160 450 50 150

Threshold

for BRT(MWth)

2 20 63

Boiler, 20-50MWth, otherfiring****

EF 108 300 225 650 50 150


2 14 63

Note:*- Use reference document 12.** - Use reference document 13.*** - Use reference document 11.**** - Use reference document 15,

For coal-fired plants incorporating Selective Catalytic Reduction (SCR), an emission factor of 4mg/MJ (10 mg/m3) for ammonia can be used.

Plant employing Selective Non-catalytic Reduction (SNCR) could also release ammonia andnitrous oxide. In the absence of other information, emission factors for SNCR for ammonia andnitrous oxide releases can be assumed to be 2 mg/MJ (5 mg/m 3) and 21 mg/MJ (60 mg/m3)respectively.

For unabated emissions of coal, peat or biomass powered plant the PM10 fraction can beassumed to be 40% of the total particulate matter emitted, rising to 80% for plant with ESPs or bag

filters and dry FGD and 95% for plant with ESPs or bag filters and wet FGD.

(d) Emission factors for liquid fuel combustion

(i) Electricity Supply Industry (ESI)

In a similar manner to Section 2.3.3 c(i), the UK ESI emission factors are listed in Table 4for heavy fuel oil-fired plant. Further detail on these emission factors is contained in theESI methodology.

Also included in Table 4 are estimates of the amount of oil that would need to be burnt inorder to exceed the reporting thresholds given the listed emission factors. A value for the

tonnes of oil that will need to be burnt for SO3has not been provided, as it will be reportedwith SO2. ESI plant burning less than the indicated tonnage of oil should therefore report


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emissions as BRT for that particular pollutant provided that there are no other sources ofthe pollutant on site.

Table 4 UK ESI PI emission factors for large combustion plantPollutant Species Emission factor (kg/tonne

oil burnt) for heavy oil-fired plant

[te oil burnt for abovethe reportingthreshold]

Dioxins and furans (expressed as I-TEQ)++

2.1 x 10-11 [497,512]

Dioxins and furans (expressed asWHOTEQ)++

2.1 x 10-11 [497,512]

PCB (expressed as WHOTEQ) 2.4 x 10-10 [41,667]

PCB (expressed as total mass) 1.3 x 10-7 [769,231]

Benzo(a)pyrene (BaP) 1.2 x 10-6 [833,333]

Anthracene 3.6 x 10-7 [BRT]***

Benzo(b)fluoranthene 7.2 x 10-7 [1,388,889]

Benzo(g,h,i)perylene 7.2 x 10-7 [1,388,889]

Benzo(k)fluoranthene 7.2 x 10-7 [1,388,889]

Chrysene 4.8 x 10-7 [BRT]***

Fluoranthene 6.0 x 10-7 [1,666,667]

Indeno(1,2,3-cd)pyrene 7.2 x 10-7 [1,388,889]

Naphthalene 6.5 x 10-5 [1,538,462]

Methane 1.8 x 10-2 [555,556]

Non-methane volatile organic

compounds

3.6 x 10-2 [277,778]

Carbon monoxide 1.5 [6,667]

SO3(reported as part of sulphur oxides- SO2and SO3as SO2)

4.2 x 10-2*

1.08**

[-]

[-]

Nitrous oxide 3.5 x 10-2 [285,714]

Note:* - for plant with Mg(OH)2 flue gas conditioning.** - for plant without Mg(OH)2 flue gas conditioning.*** - These emissions should always be reported as below the reporting threshold given therequired fuel burn.++ - Where possible I-TEQ should be reported in preference to WHO-TEQ (although reporting ofboth is acceptable).

Emissions of NOx from ESI oil-fired power plants that do not use CEMS for determining annualmass emission can be calculated from the fuel burn and NOxfactors that have been agreed with uson a station-specific basis.

Particulate matter concentrations are normally measured by CEMS for ESI plant. The annualmass emission should be calculated from the instantaneous measured concentration multiplied bythe instantaneous volumetric emission, as in equation 1. Where load is constant, the averageconcentration and flowrate can be used (equation 2). For ESI plant it is generally assumed thateach tonne of oil generates 12,000m3of flue gas normalised at 3% oxygen concentration.


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The SPRI return requires the total, PM10 and PM2.5 fractions of the particulate matter to bereported. For ESI oil-fired plant, the PM10and PM2.5.5 fractions are assumed to be 71% and 52%respectively of the total particulate matter emitted.

(ii) Generic factors

In a similar manner to Section 2.3.3 c(ii), and based on the same referenced informationsources, emission factors based on achievable emission rates from various liquid-firedcombustion plant can be used in equation 7. Relevant emission factors for liquid-fired plantare given in Table 5 (in terms of net heat input), and the same methodology should be usedas that outlined in Section 2.3.3 c(ii).

Table 5 Liquid fuel-firing generic emission factors (net basis)


Particulatematter

NOx CO

mg/MJ mg/m3 mg/MJ mg/m3 mg/MJ mg/m3

Gas turbine (after1994)*

EF 0 0 105 125 50 60


- 30 63

Gas turbine (pre-1994)*

EF 0 0 140 165 84 100


- 23 38

Boilers, 20-50MW,L/M/H fuel oilfiring**

EF 42 150 125 450 42 150

Threshold

for BRT(MWth)

8 25 75

Boilers, 20-50MW,distillate firing**

EF 28 100 55 200 42 150


12 58 75

Compression ignitionengine, SCR***

EF 40 50 125 150 125 150


8 25 25

Note:*- Use reference document 14.

** - Use reference document 15.

***- Use reference document 13.

For liquid fuel-fired plants incorporating SCR, an emission factor of 3 mg/MJ (10 mg/m3) forammonia can be used.

For unabated emissions, the PM10 fraction can be assumed to be 45% of the total particulatematter emitted, rising to 80% for plant with ESPs or bag filters and dry FGD and 90% for plant withESPs or bag filters and wet FGD.


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(e) Emission factors for natural gas combustion

(i) Electricity Supply Industry (ESI)

In a similar manner to Section 2.3.3 c(i), the UK ESI emission factors are listed in Table 6for natural gas-fired plant. Further detail on these emission factors is contained in the ESImethodology.

Also included in Table 6 are the approximate GJ of energy that would be required toexceed the reporting thresholds given the listed emission factors and burning only naturalgas.

Table 6 UK ESI PI emission factors for large combustion plant

Pollutant Species Emission factor(g/GJ gas burnt) forgas firing (based on

GCV)

[GJ of energy giving rise tonumerical reported value]

Dioxins and furans (expressed as I-TEQ)

0 [-]

Dioxins and furans (expressed asWHO-TEQ)

0 [-]

PCB (expressed as WHO-TEQ) 0 [-]

Benzo(a)pyrene (BaP) 0 [-]

Anthracene 0 [-]

Benzo(b)fluoranthene 0 [-]

Benzo(g,h,i)perylene 0 [-]

Benzo(k)fluoranthene 0 [-]

Chrysene 0 [-]

Fluoranthene 0 [-]

Indeno(1,2,3-cd)pyrene 0 [-]

Naphthalene 0 [-]

Methane 3.7 [2,702,700]

Non-methane volatile organiccompounds

0.9 [11,111,000]

Carbon monoxide 13 [7,692,300]

SO3(reported as part of sulphuroxides - SO2and SO3as SO2)

0 [-]

Nitrous oxide 0.5 [20,000,000]

NOxemissions from CCGT and gas-fired plant are generally calculated from continuous monitors.

For the combustion of natural gas, the ESI PI methodology advises a revised emission factor of0.80 g/GJ (GCV) or 0.89 g/GJ (NCV) for particulate matter from gas turbine plant.

For gas turbines running on distillate fuel, for example during start-up, the emission factors given inTable 5 can be used, and 100% of the particulate matter emission assumed to be PM10 and 50%PM2.5. Note that from 2009, the ESI proposes that they will assume that 100% of particulate matteris PM2.5, as a conservative estimate.

(ii) Generic factors

In a similar manner to Section 2.3.3 c(ii), and based on the same referenced informationsources, emission factors based on achievable emission rates from various natural gas-


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fired combustion plant can be used in equation 7. Relevant emission factors for naturalgas-fired plant are given in Table 7 (in terms of net heat input), and the same methodologyshould be used as that outlined in Section 2.3.3 c(ii). Note that the emission factors arebased on net calorific values (NCV).

Table 7 Natural gas fuel-firing generic emission factors (net basis)


Particulatematter

NOx CO

mg/MJ mg/m3 mg/MJ mg/m

3 mg/MJ mg/m

3

Gas turbine, after 1994* EFi (mg/MJ) 0 0 50 60 50 60


- 63 63

Gas turbine, pre-1994*

EFi (mg/MJ) 0 0 105 125 84 100


- 30 38

Boilers, 20-50MW, Fluegas recirculation (FGR)**

EFi (mg/MJ) 1 5 39 140 30 100


317 81 106

Dual fuel compressionignition engine,

SCR***

EFi (mg/MJ) 15 20 85 100 375 450


21 37 9

Dual fuel compression

ignition engine, leanburn***

EFi (mg/MJ) 15 20 125 150 125 150


21 25 25

Spark ignition engine,SCR***

EFi (mg/MJ) 0 0 85 100 125 150


- 37 25

Spark ignition engine,lean burn, exhaust gasrecirculation (EGR)***

EFi (mg/MJ) 0 0 125 150 125 150


- 25 25

Note: * Use reference document 14.** Use reference document 15.*** Use reference document 11.

For both compression ignition engines and spark ignition engines, a factor of 170 mg/MJ (200mg/m3) can be used for NMVOCs. For natural gas-fired plants incorporating SCR, an emissionfactor of 8 mg/MJ (10 mg/m3) for ammonia can be used.

Apart from mercury, trace metallic elements in natural gas are assumed to be zero. For mercury,an emission factor of 1 x 10-4 mg/m3 of gas burnt can be used to calculate mercury vapouremissions. In this case, greater than 1 x 1010m3of gas would need to be burnt in a year to exceedthe reporting threshold.


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The PM10and PM2.5 fractions can be assumed to be 100% of the total particulate matter emitted

when burning natural gas.

2.3.4 Fuel analysis data

(a) General

The use of fuel analysis data to determine emissions is similar to the use of emissionfactors.

The basic equation used in fuel analysis emission calculations is:

E = Qfx [Op hours] x [PCf/100] x (MWp/ EWf) (8)

Where: E = emission of pollutant (kg/yr)Qf = fuel use (kg/hr)

PCf = pollutant concentration in the fuel (%)Op hours

= operating hours per year (hr/yr)

MWp = molecular weight of pollutant as emitted after combustion

EWf = elemental weight of pollutant as present in fuel

Equation 8 is the method usually used for calculating SO 2 emissions where it is normallyassumed that all of the sulphur in the fuel is converted to SO2. However, when using theequation for coal-fired plant, it is assumed that 5% of the sulphur is retained in the ash.

Where the pollutant concentration in the fuel is consistent over the averaging period (i.e.

one year), equation 8 can be written as:

E = M x [PCf/100] x (MWp/ EWf) (9)

Where: E = emission rate of pollutant in (kg/yr)M = mass of fuel burnt in one year (kg/yr)PCf = pollutant concentration in the fuel (%)MWp = molecular weight of pollutant as emitted after combustionEWf = elemental weight of pollutant as present in fuel


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Example 4

This example shows how SO2 emissions can be calculated from oil combustion, basedon fuel analysis results and fuel flow information. It is assumed that the facility operates using oilfor 150 hours per year and that abatement of SO2 does not occur.

Qf = 2000 kg/hrPCf = 1.17%MWp = 64EWf = 32Op hours = 150 hr/yr

E = Qf x PCf x (MWp / EWf) x [Op hours]

= [(2000) x (1.17 / 100) x (64/32) x 150] kg/yr= 7.0 x 103kg/year

Equation 8 can also be used for volatile elements such as fluorine and chlorine as well astrace metallic pollutants, although some of these species are retained in the plant, either inthe ash or in abatement equipment (see below).

When using equations 8 or 9, you should be aware that the amount of pollutants present inthe fuel can vary significantly. For UK ESI plant, the trace element concentration in the coalis calculated as a yearly weighted mean average for each plant, based on the deliveredtonnage of coal. Where coals have not been analysed for trace element content, then youshould use an average value for coals from a similar geographic region.

(b) Solid fuel analysis

For elements that are effectively captured in either bottom ash or fly ash, equation 8 canresult in the overestimation of emissions. In addition, emission quantities of volatile andsemi-volatile components will greatly depend on the emission temperature and abatementcollection efficiency as volatile and semi-volatile substances can condense on fineparticulate matter. Increasing the emission temperature may significantly increase thepollutant release rate of volatile components. Any changes to the process conditions thatmay affect pollutant partitioning or capture should be taken into account in emissioncalculations by the determination of site-specific retention and enrichment factors (seebelow).

Mass emissions of trace metallic elements from coal combustion can be calculatedindirectly from the amount of particulate matter emitted, corrected by factors representingthe concentration of the trace element in the coal and how much of the element ischemically present in the ash, using the following equations. The total emission is the sumof the emission from the non-volatile and volatile phases:

Non-volatile phase:

Env = PCcoal x (100 / AA) x F x R x PM (10)


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Volatile phase:

Ev = PCcoal x (1F) x CB (11)

Where: Env = non-volatile pollutant emission (kg/yr)Ev = volatile pollutant emission (kg/yr)PCcoal = trace element weight fraction in the coalAA = average ash mass percentage in coal (%)F = retention factor in ash (-)R = enrichment factor (-)PM = particulate matter emission (kg/yr)CB = coal burned (kg/yr)

Common enrichment and retention factors that are used across UK coal-fired ESI plant aretabulated in Table 8. These factors are appropriate for exhaust gas temperatures of less

than approximately 130oC. For higher exhaust gas temperatures the factors may differ,especially for the more volatile elements, and you should therefore use site-specific factors.

The use of Flue Gas Desulphurisation (FGD) will lead to the retention of sulphur from theemission, but it will also lead to the retention of soluble acid halides such as HCl and HF.In the absence of site specific data for FGD, retention factors for HCl and HF should betaken as 98% and 72% respectively. The additional factors given in Table 8 for FGD arefor wet limestone/gypsum systems.

Table 8 2009 UK ESI PI coal combustion factors

Pollutant Element Retention factor(F)

Enrichment factor(R)

FGD retentionfactor (vapour)

Arsenic 1 3.4 -

Selenium 0.8 9.0 0.65

Lead 1 2.9 -

Antimony 1 3.6 -

Nickel 1 1.9 -

Chromium 1 1.7 -

Copper 1 2.0 -

Manganese 1 1.7 -

Vanadium 1 1.4 -

Zinc 1 4 -Cadmium 1 4.5 -

Mercury 0.5 4.0 0.5

In order to use equations 10 and 11, it is necessary to know the composition of the coal interms of the percentage of trace metallic elements present. As coal composition can varysignificantly depending on the source of the fuel, you should obtain information on the traceelements from the supplier, or have specific coal analysis carried out.

Fuel composition should also be taken into account in determining pollutant emissions fromsubsidiary or substitute fuels. In the absence of other data, for fuels such as biomass thathave a low ash content, the enrichment and retention factors given above can be used.


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(c) Liquid fuel analysis

Equation 11 can be used to calculate trace metallic emissions from oil-fired plant. As agenerality within the ESI methodology it is assumed that for large, heavy fuel oil plant withparticulate or grit arrestors a retention factor of 0.75 can be used for trace elements.Appropriate retention factors should be determined for other abatement plant. In theabsence of abatement, the retention factor would be zero.

As with coal, information on the composition of the trace elements in the fuel should beobtained from the supplier or be measured.

Emissions of halogens from oil-fired plant can be assumed to be zero.

(d) Natural gas analysis

As indicated in Section 2.3.3 e(ii), apart from mercury, natural gas supplies in the UK are

currently assumed to have zero trace metal content. Emissions of halogens from naturalgas-fired plant are also assumed to be zero.

Where no specific gas analysis is available and in order to calculate emissions from gasventing, natural gas should be assumed to comprise 1% CO2, 1% nitrogen, 92% CH4and6% NMVOCs.

2.3.5 Fugitive emissions

For solid fuel plant, particulate matter emissions can occur by dust blown from coal stocks and ashstorage areas. However, these can be assumed to be low in comparison to stack emissionsunless specific events have occurred which are known to have released significant quantities of

material off-site.

Techniques for estimating fugitive emissions from the surface of stockpiles are limited. Optionsinclude measuring ambient dust levels upwind and downwind of the source of interest and/orapplying predictive mathematical models.

CH4and other hydrocarbon emissions from coal stocks and oil tank filling can be assumed to besmall in relation to emissions through the stacks. For natural gas-fired plant, where gas is ventedto atmosphere for operational and maintenance purposes, the mass emissions of CO2, CH4andNMVOCs should be calculated from the gas composition.

2.4 Substances reported as

Certain substances on the SPRI return are required to be reported as the main constituent, e.g.Nitrogen oxides, NO and NO2 as NO2. When a conversion needs to be made, the emissionconcentration or emission rate should be multiplied by the molecular weight of the reported assubstance, and divided by the molecular weight of the emitted substance. This is illustrated in thefollowing example.


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Example 5

Assume a discharge concentration of NO is 50 mg/m

3

. Using the molecular weights of NO andNO2, the equivalent discharge concentration of NO2can be determined.

MW of NO = 30MW of NO2 = 46

Concentration of NO asNO2

= 50 x 46 / 30

= 76.7 mg/m

The mass of NO2released can then be determined in accordance with equation 1.

Further guidance on reporting emissions, including dioxin and other organic substance congenersis given in the General SPRI guidance document.


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3 Emissions to water and waste water

Emissions of substances to water can be either direct to controlled waters or indirect, followingtransfer to off-site effluent treatment plant.

If your wastewater is treated by an Independently-operated Wastewater Treatment Plant(IOWWTP) covered by Section 5 of the Pollution Prevention and Control (Scotland) Regulations,then this waste stream should be recorded as a transfer in tonnes/year within Section D WasteTransfers. Any transfers of liquid waste from the SPRI-reporting site by road tanker or other liquidcontainer should also be reported within Section DWaste Transfers.

Guidance on what constitutes an emission or a transfer is contained in the General SPRI Guidancedocument3.

3.1 Relevant pollutants

A variety of substances need to be considered when reporting emissions to water or transfers inwastewater to sewer. The main ones are illustrated in Table 9. The table should be taken as aguideonly, and you should verify that there are no other pollutants emitted from the process. Thesignificance of each parameter depends on the specific plant configuration and the processapplied, which also determines the type and amount of pollutant present in the wastewater prior totreatment.

Table 9 Guide on main reportable substances likely to be emitted to water

Substance Substance

Arsenic Zinc

Cadmium Iron

Chromium (Cr III and Cr VI) Ammonia

Copper Nitrogen (total as N)

Lead Phosphorus (total as P)

Mercury Chlorides

Nickel Fluorides

3.2 Emission sources

Emissions to water generally arise from the following sources:

Cooling water system;

Demineralised water treatment plant;

Boiler blow down;

FGD wastewater treatment plant;

Ash transport wastewater;

Surface water run-off from storage areas (e.g. fuel, ash, FGD material);

Cleaning water.

Notwithstanding the above, you should consider all emission sources to water and characterise theflows and emission concentrations from each source.

3.3 Quantification of emissions

There is less choice in the techniques to use for the determination of emissions to water than foremissions to air. The most appropriate method is to use direct measurement. However, you may


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use other RETs, particularly mass balances or site-specific emission factors where these areappropriate. Mass balances can often be used when emissions to water are very complex anddifficult to quantify with other approaches. However, a mass balance calculation is still likely torequire direct measurement of emissions from some of the water pathways in order to verify thecalculations. Site-specific emission factors are determined from the ratio of the measured orcalculated pollutant emission to the water discharge flow rate.

Within this Note, advice is given on the use of direct measurement techniques as these are likely tobe applicable to the majority of Operators.

Using the direct measurement technique requires information on both the flow rate and pollutantconcentration. Measurement of flows and pollutant concentrations should be undertaken at thesame time during representative operating conditions. Particular care should be taken whenrelying on the results of one spot sample in order to report annual emissions unless you can becertain that the process conditions are representative. Where a process has a number ofoperating conditions, it may be necessary to take samples at each condition and average the result

according to the length of time the process operates at each condition. Similarly, where processconditions at the time of the spot sampling are uncertain, then it may be necessary to take severalsamples and the results averaged in order to provide the final annual emission estimate.

The frequency of sampling will depend on the variability of the data. Initially, it may be necessaryto take several samples and average the results to yield an annual result. If, however, the resultsindicate that a concentration and flow are reasonably constant, then the frequency of samplingmay be reduced to a practical minimum of once per year. You should be able to justify thesampling regime selected and this should be supported by a history of previous measurements.

The background load of a reportable substance in water may be taken into account. For example,if water is collected at the site of the installation from a neighbouring river, lake or sea for use as

process or cooling water which is afterwards released from the site of the facility into the sameriver, lake or sea, the release caused by the background load of that substance can besubtracted from the total release of the installation. The measurements of pollutants in collectedinlet water and in released outlet water must be carried out in a way that ensures that they arerepresentative of the conditions occurring over the reporting period. If the additional load resultsfrom the use of extracted groundwater or drinking-water, it should not be subtracted since itincreases the load of the pollutant in the river, lake or sea.

It may also be necessary to take account of the fact that evaporation of water from the process willlead to an increase in the pollutant concentration. This can be done by using the followingequation:

PC = (OC[IC x VF]) (12)

Where: PC = the pollutant emission concentration due to the process (mg/l)OC = the measured pollutant concentration in the discharge (mg/l)IC = the measured pollutant concentration in the feed water (mg/l)VF = the ratio of volume of water extracted to volume of water discharged

In order to estimate the mass emission to water, the appropriate pollutant concentration is thenmultiplied by the flow rate for that particular discharge point. These representative discharge ratesare then aggregated together based on the time for which the water is discharged at that rate.

For emission points fitted with continuous monitors, calculations of mass emissions from aparticular discharge point can be made automatically. However, for cooling water it may also be


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necessary to adjust the measured data to take account of input pollutant concentrations asdescribed above, and it is good practice to manually check automatic calculations to ensure thatthey are accurate.

Example 6 below shows how to estimate annual mass flow of a substance from cooling waterdischarges taking into account water evaporation in the plant.

Example 6

Suppose the chromium discharge concentration [OCcr] and annual volume flows from threeseparate discharge points are found to be:

[OCcr]1 = 2.2 x 10- mg/m V1 = 4.2 x 10 m

[OCcr]2 = 1.2 x 10-3mg/m3 V2 = 36 x 10

6m3[OCcr]3 = 4.5 x 10

-3mg/m3 V3 = 21 x 106m3

Chromium inlet concentration [ICcr] = 0.12 x 10-3

mg/m3

Volume of water extracted during testingperiod

= 15,000 m3

Volume of water discharged during testingperiod

= 14,300 m3

The volume factor = 15,000/14,300 = 1.05From equation 12 above, the following average process concentrations are therefore:

[PC]1 = {2.2 x 10-3[0.12 x 10-3x 1.05]} = 2.07 x 10-3mg/m3

[PC]2 = {1.2 x 10-3[0.12 x 10-3x 1.05]} = 1.07 x 10-3mg/m3

[PC]3 = {4.5 x 10-3[0.12 x 10-3x 1.05]} = 4.37 x 10-3mg/m3

Total annual chromium mass emission = {[PC]1x V1} + {[PC]2x V2} + {[PC]3x V3}

= {2.07 x 10-3x 4.2 x 106} + {1.07 x 10-3x 36 x 106} + {4.37 x 10-3x 21 x 106} mg

= 139g which is below the reporting threshold

3.4 Substances reported as

Certain substances on the SPRI return are required to be reported as the main constituent, e.g.Chlorides total as Cl. For instances when a conversion needs to be made, the emissionconcentration should be multiplied by the molecular weight of the main constituent and divided bythe total molecular weight of the substance. This is illustrated in the following example.

Further guidance on reporting emissions of specific compounds is given in the General SPRIGuidance document.


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Example 7

Let the measured concentration of sodium chloride be 50 mg/l and the total volume released is1,000 m3.

Relative Atomic Mass ofsodium

= 23

Relative Atomic Mass ofchlorine

= 35

Molecular Weight of sodiumchloride

= 58

Concentration of sodium chloride aschloride

= 50 x 35 / 58

= 30.2 mg/l = 30.2 g/m3

The mass of chloride released is (30.2 x 10-3) x 1000 = 30.2 kg which is below the reportingthreshold.

3.5 If no emission factors or other RETs are available

If an emission factor or other release estimation technique is not available then you should contactSEPA.

3.6 Units

In completing the SPRI return, care should be taken with the units of the substances reported. Achecklist of unit prefixes is included in Appendix B to aid in this process.


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4 Off-site waste transfers

In this section you are asked to report waste or tankered liquid waste removed from the site. Allsites are likely to produce some waste and should address this issue.

You are required to report waste transfers from your site where the reporting thresholds of 2tonnes/yrfor hazardous wasteand/or 2,000 tonnes/yrfor non-hazardous wasteare exceeded.

Any transfer of waste off-site to a third party is covered by the Duty of Care provisions of theEnvironmental Protection Act 1990. This includes the requirement to describe the waste andrecord the quantity. You should therefore use data generated in compliance with Duty of Carerequirements to complete the SPRI return.

If tankered waste is to be further processed, such as, dewatering of oily waste by a specialistwaste contractor, it should be recorded within this Section. However, where tankered waste isdestined to be treated at an Urban Waste Water Treatment Plant (UWWTP) outwith your site it

should be recorded with Section CWaste Water

4.1 Relevant wastes

Typical wastes and by-products generated in this sector are:

Bottom ash and/or boiler slag;

Fly-ash;

Fluidised bed ash;

Flue gas desulphurisation residues and by-products;

Special wastes (e.g. solvents);

Metallic wastes;Chemical wastes;

Waste oils;

General waste.

4.2 Transboundary shipments of hazardous waste

For transboundary movements of hazardous waste (outwith the United Kingdom), the name andaddress of the recoverer or the disposer of the waste and the actual recovery or disposal site haveto be reported


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5 References and further information

1. Scottish Pollutant Release Inventory website.http://www.sepa.org.uk/air/process_industry_regulation/pollutant_release_invento

ry.aspx

2. The Pollution Prevention and Control (Scotland) Regulations 2000 (as amended)SSI 2000 No. 323.http://www.legislation.gov.uk/ssi/2000/323/contents/made

3. SPRI General Guidance Note.http://www.sepa.org.uk/air/process_industry_regulation/pollutant_release_inventory/operator_guidance.aspx

4. European Pollutant Release and Transfer Register (E-PRTR) website.http://prtr.ec.europa.eu/

5. Directive 2001/80/EC of the European Parliament and of the Council of 23October 2001. Limitation of emissions of certain pollutants into the air from largecombustion plants.http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2001:309:0001:0001:EN:PDF

6. EU ETS Directivehttp://ec.europa.eu/clima/policies/ets/index_en.htm

7. Joint Environment Programme. Electricity Supply Industrys Pollution InventoryMethodology, 2009 (Revised February 2012, next revision due Spring 2012).Available from: The Library, Power Technology, Ratcliffe on Soar Power Station,

Ratcliffe on Soar, Nottingham NG11 OEE.

8. SPRI Guidance Note on Release Estimation Techniques (RET).http://www.sepa.org.uk/air/process_industry_regulation/pollutant_release_inventory/operator_guidance.aspx

9. EU ETS Monitoring and Reporting Guidelines.http://www.sepa.org.uk/climate_change/solutions/eu_emissions_trading_system/monitoring_and_reporting.aspx

10. EU ETS Country Specific Factors.http://www.decc.gov.uk/en/content/cms/what_we_do/change_energy/tackling_clima/emissions/eu_ets/euets_phase_ii/monitoring/monitoring.aspx

11. HMSO. Process Guidance IPC S3 1.01 Combustion processes SupplementaryGuidance Note, November 1995 ISBN 0-11-310183.

12. HMSO. Process Guidance Note S2 1.01 Combustion processes: large boilersand furnaces 50MW(th) and over, November 1995 ISBN 0-11-753206-1.

13. HMSO. Process Guidance Note S2 1.03 Combustion processes: gas turbines,September 1995 ISBN 0-11-753166-9.

14. HMSO. Process Guidance Note IPR 1/2 Combustion processes: gas turbines,

September 1994 ISBN 0-11-752954-0.
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15. Local Authority Unit. Assessment for second revision of PG1/3, ProcessGuidance Note for Part B. Boilers and furnaces with a net rated thermal input of2050 MWth.http://www.defra.gov.uk/publications/files/env-permitting-general-guidance-b.pdf

16. Local Authority Unit. Assessment for second revision of PG1/4, ProcessGuidance Note for Part B. Gas turbines 2050 MWth rated thermal input.http://archive.defra.gov.uk/environment/quality/pollution/ppc/localauth/pubs/guidance/notes/pgnotes/documents/PG1_04.pdf
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Appendix ANormalisation of emission concentrations

In many cases, pollutant emission concentrations to air are reported as normalised concentrations,the actual measured emission concentration having been adjusted to a normalised temperature

(273K), oxygen, pressure and/or water vapour concentration. In calculating mass emissions to air,it is important that either the actual release concentration is multiplied by the actual volumetric flowrate, or the normalised concentration is multiplied by the normalised volumetric flow rate. In manycases, emission concentrations and volumetric flow rate are quoted in different ways, and youshould ensure that the measurements are multiplied together on a consistent basis.

The following equations can be used to correct measured concentrations and flow rate fortemperature, oxygen, pressure and water vapour content. It should be noted that the equations forcorrecting concentrations and volumetric flow rate are simple inversions of each other.

Concentrations

To correct for moisture concentration to dry (0% oxygen)

Cd= Cmx (100/(100 -%H20))

Where Cdis the dry concentrationCmis the measured concentration%H20 is the measured water vapour percentage

To correct the % oxygen to dry basis (if requiredmay already be measured dry)

O2(dry) = O2mx (100/(100 -%H20))

Where O2(dry) is the dry oxygen percentageO2mis the measured oxygen percentage

To correct to normalised oxygen concentration

Ccorr= Cdx (20.9 - O2norm)/(20.9 - O2(dry))

Where Ccorris the corrected concentration for oxygen concentrationO2normis the stated normalised oxygen percentage

To correct for temperature

CnormT= Ccorrx ((273 + Tm)/273)

Where CnormTis the normalised concentration for temperatureTmis the measured temperature in degrees centigrade

To correct for pressure

Cnorm= CnormTx (101.3/Pm)

Where Cnormis the normalised concentrationPmis the measured pressure in kPa


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Volumetric flow rates

To correct for moisture concentration to dry (0% oxygen)

Qd= Q

mx ((100 -%H

20))/100)

Where Qdis the dry volumetric flowrateQmis the measured volumetric flowrate%H20 is the measured water vapour percentage

To correct the % oxygen to dry basis (if requiredmay already be measured dry)

O2(dry) = O2mx (100/(100 -%H20))

Where O2(dry) is the dry oxygen percentageO2mis the measured oxygen percentage

To correct to normalised oxygen concentration

Qcorr= Qdx (20.9 - O2(dry))/(20.9 - O2norm)

Where Qcorris the corrected volumetric flowrate for oxygen concentrationO2normis the stated normalised oxygen percentage

To correct for temperature

QnormT= Qcorrx (273/(273+ Tm))

Where QnormTis the normalised volumetric flowrate for temperatureTmis the measured temperature in degrees centigrade

To correct for pressure

Cnorm= CnormTx (Pm/101.3)

Where Cnormis the normalised volumetric flowratePmis the measured pressure in kPa


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Appendix BConversion factors

ppm to mg/m3air

The conversion between ppm and mg/m

3

is dependent on both the molecular weight of thesubstance and the temperature at which the conversion is made. The assumption is that thepollutant behaves as an ideal gas and as such, 1 mole of the substance occupies 22.4 litres atstandard temperature (273K) and pressure (101.3 kPa). This is consistent with normalisedconcentrations, and it is therefore not normally necessary to take account of the temperature orpressure difference in the conversion. However, when converting ppm to mg/m3 at actualdischarge conditions, it is important to take account of the necessary factors.

To convert from ppm to mg/m3, the following formula should be used:

mg/m3= ppm x (MW/22.4) x (273/T) x (P/101.3)

Where MW is the molecular weight of the substance (in grams)T is the temperature at which the conversion is to be made (degrees Kelvin)P is the pressure at which the conversion is to be made (kPa)

To convert from mg/m3to ppm, the following formulae should be used:

ppm = mg/m3x (22.4/MW) x (T/273) x (101.3/P)

ppm to mg/lWater

The conversion between ppm and mg/l for water is straightforward in that it is normally assumedthat water has a density of 1000 kg/m3. On this basis, 1 ppm = 1 mg/l = 1 g/m3= 1 mg/kg.

Metric prefixes

The following prefixes are given for the metric system as an easy reference guide.

Factor by which unit ismultiplied

Prefix Symbol

10 yotta Y

1021

zetta Z

1018

exa E

10 peta P

10 tera T

10 giga G10

6 mega M

103 kilo k

10 hecto h

10 deca da

10-

deci d

10-

centi c

10-3

milli m

10-6

micro

10-

nano n

10-

pico p

10-

femto f

10

-18

atto a10-21 zepto z

10-24 yocto y


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Appendix CGlossary

BaP Benzo(a)pyreneBAT Best Available Techniques

BRT Below Reporting ThresholdCEMS Continuous Emission Monitoring SystemCCGT Combined Cycle Gas TurbineCH4 MethaneCHP Combined Heat and PowerCF Conversion FactorCO Carbon MonoxideCO2 Carbon DioxideCOD Chemical Oxygen DemandCr ChromiumD&R Disposal and RecoveryEU ETS European Union Emissions Trading System

EF Emission FactorEGR Exhaust Gas RecirculationELV Emission Limit ValueE-PRTR European Pollutant Release and Transfer RegisterESI Electricity Supply IndustryESP Electrostatic PrecipitatorETP Effluent Treatment PlantEWC European Waste CatalogueFGD Flue Gas DesulphurisationFGR Flue Gas RecirculationGCV Gross Calorific ValueGHG Greenhouse Gas

HCl Hydrogen ChlorideHF Hydrogen FluorideHFO Heavy Fuel OilH2S Hydrogen SulphideIOWWTP Independently-operated Wastewater Treatment PlantIPC Integrated Pollution ControlIPPC Integrated Pollution Prevention and ControlI-TEQ International Toxicity Equivalents of DioxinsJEP Joint Environment ProgrammeLCPD Large Combustion Plant DirectiveLOD Limit of DetectionMg(OH)2 Magnesium HydroxideMCERTS (Environment Agencys) Monitoring Certification SchemeNCV Net Calorific ValueNOx Oxides of nitrogen (mixture of NO and NO2)N2O Nitrous OxideNMVOCs Non-methane Volatile Organic CompoundsPAHs Polycyclic Aromatic HydrocarbonsPCBs Polychlorinated BiphenylsPCDDs Polychlorinated DibenzodioxinsPCDFs Polychlorinated DibenzofuransPF Pulverised FuelPFBC Pulverised Fuel Bed Combustion

PM Particulate MatterPM10 Particulate Matter (< 10 m aerodynamic diameter)

PM2.5 Particulate Matter (< 2.5 m aerodynamic diameter)


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PPC Pollution Prevention and Control (Scotland) Regulations 2000(as amended)

ppm Parts per millionRET Release Estimation TechniqueSCR Selective Catalytic ReductionSNCR Selective Non-catalytic ReductionSOx Oxides of Sulphur (mixture of SO2and SO3)SO2 Sulphur DioxideSO3 Sulphur TrioxideSPRI Scottish Pollutant Release InventoryTOC Total Organic CarbonTPM Total Particulate MatterUNECE United Nations Economic Commission for EuropeUWWTD Urban Wastewater Treatment DirectiveUSEPA United States Environmental Protection AgencyVOCs Volatile Organic Compounds

WHO World Health OrganisationWHO-TEQ WHO Toxicity of DioxinsWID Waste Incineration Directive

spri combustion guidance 2013

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