JOINT ENVIRONMENTAL PROGRAMME

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2 JOINT ENVIRONMENTAL PROGRAMME This report has been produced by the Joint Environmental Programme ( the JEP ). The JEP supports a programme of research into the environmental impacts of electricity generation funded by nine of the leading producers in the UK. The objective of the R&D programme is to understand and increase knowledge of the environmental science and impacts associated with the production of electricity from fossil fuels. The main drivers for the programme come from the national and international legislative and regulatory initiatives which now address the full range of emissionsrelated impacts. The JEP takes a forward look at trends in legislative and regulatory thinking, identifies any gaps and major uncertainties in the scientific knowledge raised by such new proposals together with the modelling, data and other research requirements that arise. This ensures that the representative companies are well placed to make a constructive contribution to national and European debate from initial concepts right through to the practicalities of implementation. Close liaison is maintained, through regular meetings, with UK Regulatory bodies to ensure the correct focus for the programme and JEP members are representatives on a number of European advisory bodies. The major areas of current activity cover: Air Quality the contribution power stations make to air quality both locally and more widely across the UK in relation to other sources Pollution and Health the relationships between power station atmospheric emissions and human health effects Pollution and the Natural Environment effects of pollutant deposition on the ecosystem Understanding Emissions reporting on emission levels and assessing their significance Aquatic Environment impact of water usage by power stations and effects on groundwater, of chemical releases from waste material disposal, and the associated methods of assessment The work is undertaken either by in-house experts within the member companies or through contracts with leading environmental consultancies and universities. To facilitate open and informed debate on key environmental issues related to electricity production, the results from the JEP research studies are widely disseminated wherever possible through external publications and in more detailed monograph reviews (listed overleaf) which summarise many years of work on a specific topic. JEP Companies: RWE Generation UK, E.ON UK, Drax Power Ltd, Scottish & Southern Energy, EDF Energy, Engie, Centrica, Eggborough Power Ltd and Scottish Power

3 Some Recent Reports and Publications from the JEP External Reports Pollution Inventory 2014 Electricity Supply Industry Methodology Predicted and measured SO 2 concentrations presented in air quality management plan annual reviews Further analysis of costs of mercury abatement for coal fired power stations and comparison with damage costs Implications of latest DECC and EC Energy projections for future environmental legislation Evaluation of ADMS5 for Air Quality Management Plan dispersion modelling ESI-IED compliance protocol for utility boilers and gas turbines Support during the revision of LCP BREF: Analysis of full dataset of reference plants Monograph Reviews Ashes to Assets? Studies of the usefulness and environmental management of ash from coal fired power stations. The Acid Tests? Studies of the ecological effects of atmospheric pollutants Crumbling Heritage? Studies of the effect of acid rain on historic buildings Flying Chemistry? Studies of the long range atmospheric transport of pollutants Generating Emissions? Studies of the local impact of gaseous power station emissions Using Water Well? Studies of Power Stations and the aquatic environment Borne on the Wind? Understanding the dispersion of power station emissions Copies of these monographs and more details on the current JEP programme can be obtained from the JEP secretary by sending your request in an to jepsec4@gmail.com JEP Companies: RWE Generation UK, E.ON UK, Drax Power Ltd, Scottish & Southern Energy, EDF Energy, Engie, Centrica, Eggborough Power Ltd and Scottish Power

4 Technology Centre ETG/15/ERG/CT/1343/R Issued: December 2015 JEP13SGG14: ELECTRICITY SUPPLY INDUSTRY IED COMPLIANCE PROTOCOL FOR UTILITY BOILERS AND GAS TURBINES (UPDATE DECEMBER 2015) By D P Graham & G Salway

5 Neither E.ON, nor any person acting on its behalf, makes any warranty, express or implied, with respect to the use of any information, method or process disclosed in this document or that such use may not infringe the rights of any third party or assumes any liabilities with respect to the use of, or for damages resulting in any way from the use of, any information, apparatus, method or process disclosed in the document. E.ON Technologies (Ratcliffe) Limited 2015 No part of this publication may be reproduced, stored in a retrieval system or transmitted, in any form or by any means electronic, mechanical, photocopying, recording or otherwise, without the written permission of the Head of Business Control UK, E.ON Technologies (Ratcliffe) Limited, Technology Centre, Ratcliffe on Soar, Nottingham, NG11 0EE.

6 Executive Summary The main objective of this document is to define a clear and unambiguous methodology for the Quality Assurance and calibration of Continuous Emission Monitoring Systems (CEMs) at power plant with 50MW or more aggregated thermal input. The guidance specifies the monitoring, reporting and compliance requirements of Directive 2010/75/EU on industrial emissions, and national legislation, for the Electricity Supply Industry. This update (December 2015) modifies the protocol as follows: a) introduces revised reporting forms and thermal input reporting; b) clarifies the status of boilers when on stand-by; c) clarifies compliance arrangements for auxiliary firing of heat recovery steam generators; d) clarifies the arrangements for the use of stand-by fuel when natural gas supplies are interrupted; e) defines the five-year rolling average for plant under the Limited Hours Derogation and f) modifies the Quality Assurance requirements (QAL2 factors must now be applied). Minor changes are made to the calculation of flue gas moisture content and the arrangements for malfunction and breakdown of abatement equipment (gas turbines only).

7 CONTENTS Page 1 INTRODUCTION OBJECTIVES AND SCOPE REGULATORY FRAMEWORK Over-view of the Industrial Emissions Directive (IED) Large Combustion Plant Aggregation Rules Mandatory ELVs Process Description Start-up and Shut-down Malfunction or Breakdown of Abatement Equipment MONITORING REQUIREMENTS When to Monitor What to Monitor Where to Monitor How to Monitor QUALITY ASSURANCE Quality Assurance Level 1 (QAL1) - Fitness for Purpose Quality Assurance Level 2 (QAL2) In-situ Validation Quality Assurance Level 3 (QAL3) Drift Checking EMISSIONS REPORTING Over-view Correction to mg/m 3 at the Reference Temperature and Pressure Correction to Reference Conditions Validated Hourly Averages Daily and Monthly Average Concentrations Mass Emissions Reporting (Normal Operation) Mass Emissions Reporting (Start-up and Shut-down) FGD Removal Efficiency CEM Invalidity Reporting of Compliance Data REFERENCES APPENDICES Appendix A: Appendix B: Appendix C: Appendix D: Appendix E: Glossary of Terms The Types of Equipment which are Included and Excluded from the Malfunction and Breakdown Arrangements Start-up and Shut-down Considerations Calculating Start-up and Shut-down Emissions from Fuel Consumption IED Reporting Forms

8 TABLES Table 1: IED Compliance routes for existing Large Combustion Plant... 6 Table 2: IED Emission Limit Values for large utility boilers... 7 Table 3: IED mandatory ELVs for existing gas turbine plant... 9 Table 4: Declared SU-SD thresholds Table 5: Alternative SU-SD thresholds Table 6: Emission Limit Values and certification ranges Table 7: Cross-interference ranges tested during certification Table 8: Functional tests Table 9: Control chart limits utility boilers Table 10: Control chart limits gas turbines Table 11: Conversion factors Table 12: Moisture content of flue gas Table 13: Flue gas fuel factors Table 14: Example efficiency calculation using operational data Table 15: IED Reporting Forms FIGURES Figure 1: IED mandatory ELVs for existing gas turbine plant... 8 Figure 2: Illustration of Gas Turbine Compliance with daily Emission Limit Values Figure 3: Schematic illustration of Malfunction and Breakdown Figure 4: Quality Assurance requirements Figure 5: Malfunction and Breakdown calculation procedure Figure 6: Generated efficiency based on a station heat balance, a fixed gradient and a fixed operating point... 58

9 1 INTRODUCTION The participants in the Joint Environmental Programme (JEP) of the Electricity Supply Industry (ESI) have developed this guidance specifically for their operations 1. Whilst these companies are content to allow others to use the document for developing their own monitoring, reporting and verification arrangements, they do not accept any liability for accuracy or for applicability to any other installation. The content has been agreed with the Competent Authorities in England, Wales, Scotland and Northern Ireland, noting that there are differing legal and regulatory positions defined in the participating administrations. The cost of meeting environmental emission limits has a significant impact on the commercial position of power stations. It is clearly desirable that there is a uniform standard for monitoring emissions and the demonstration of compliance with emission limit values. The guidance is suitable for utility boilers, i.e., large water tube boilers used to raise steam for power generation, and gas turbines firing gaseous and liquid fuels in Combined Cycle Gas Turbine (CCGT) installations, Open Cycle Gas Turbine (OCGT) installations or large Combined Heat and Power (CHP) installations. The guidance applies to installations, containing Large Combustion Plant, with a total net aggregated thermal input 50MW. This guidance may also apply to large combustion plant outside of the Electricity Supply Industry, at the discretion of the Competent Authority. There are additional provisions for auxiliary plant and small combustion units within large aggregated installations. These provisions are specific to installations within the Electricity Supply Industry but certain aspects may be applicable to other installations at the discretion of the Competent Authority. The Emission Limit Value (ELV) for a given pollutant is crucially important for determining monitoring requirements and for the Quality Assurance (QA) of Continuous Emission Monitoring Systems (CEMs) which are also referred to as Automated Measuring Systems (AMS). ELV reference conditions for utility boilers are 6% O 2 for solid fuels and 3% O 2 for liquid or gaseous fuels. The reference condition for gas turbines is 15% O 2. In all cases, this is on a dry flue gas basis, at K and kPa. These reference conditions are used for concentrations throughout this guidance document unless stated otherwise. 2 OBJECTIVES AND SCOPE The main objective of this document is to define a clear and unambiguous methodology for the Quality Assurance and calibration of CEMs at power plant. The guidance is intended to address the monitoring requirements of the Industrial Emissions Directive (IED) [1] which applies to new plant from 7 January 2013 and existing large combustion plant from 1 January 2016, with general permitting requirements applying from 7 January This is enacted by the Environmental Permitting Regulations (EPR) in England & Wales [2] and the Pollution Prevention and Control Regulations in Scotland [3]. This document applies from 1 January 2016 and covers all existing Large Combustion Plant within the Electricity Supply Industry, regardless of when they were first permitted. 1 JEP member companies are Centrica, Drax Power, EDF Energy, Eggborough Power, E.ON UK, International Power (GDF Suez), RWE Generation UK, Scottish Power and Scottish and Southern Energy. 1

10 The IED requires compliance with CEN standards relating to the Quality Assurance (QA) of CEMs. For utility boilers, this guidance document relates principally to the measurement of nitrogen oxides (NO x ), sulphur dioxide (SO 2 ) and dust. For gas turbines, and all other gas fired plant, NO x and carbon monoxide (CO) are regulated under the IED. This document describes an approved general methodology for emissions monitoring for the purposes of compliance at new and existing power plant. Whilst this document has been prepared using the best information available, it is recognised that the document will need to be reviewed periodically in order to take account of: operational experience; the results of JEP research and development programmes, further guidance from the Competent Authorities, updated BAT Reference (BREF) documents and BAT conclusions. Individual power station operators will additionally provide site-specific information which will include calibration data and the physical layout of the discharge ductwork. Site specific issues will be addressed by each plant operator. Reference to regulatory guidance and Health & Safety notes should be to the latest versions of these documents which are subject to periodic review. In the case of CEN standards, the appropriate Environment Agency Method Implementation Documents (MIDs) should also be consulted, where applicable. MCERTS accredited monitoring laboratories are always required to follow these MIDs by UKAS whenever and wherever they perform MCERTS testing. However, with regard to Environment Agency guidance generally, this is considered to be mandatory in England only and is regarded as a useful summary of best practice elsewhere. A brief glossary of terms is given in Appendix A. The regulatory requirements are first reviewed in order to explain why monitoring is undertaken, what has to be monitored and when this is required. The plant Emission Limit Values (ELVs) are crucially important for defining the Quality Assurance (QA) requirements which are then considered in detail in order to provide a framework for the detailed monitoring requirements. It is assumed, throughout, that the key aspects of emissions monitoring and reporting are incorporated as documented procedures and work instructions into the local Environmental Management System. 3 REGULATORY FRAMEWORK 3.1 Over-view of the Industrial Emissions Directive (IED) Chapter III of the Industrial Emissions Directive applies to existing power plant from 1 January 2016, i.e., those permitted before 7 January 2013 or those with a full permit application before this date that are put into operation before 7 January The IED applies to new plant from 7 January Exceptions 2 are given in Appendix A). The setting and updating of ELVs is based on the Best Available Techniques (BAT) and their Associated Emission Levels, as defined in the BAT reference document (BREF) for Large Combustion Plant [4] and summarised within BAT Conclusions. BAT conclusions are to be used as the reference for setting Permit conditions with compliance normally required within four years of the publication of the BAT Conclusions 3. 2 Subject to the exclusions listed in the IED, Chapter III, Article IED Article 21(3) establishes the requirement to revise the Permit and implement the conditions within 4 years of the publication of the BAT Conclusions. The IED Recital (22) notes that Competent Authorities may set a longer time period within permit conditions where this is justified on the basis of the criteria laid down in the Directive. Where this is provided for in a permit, a justified Article 15(4) derogation will be required between the period of expiry of the 4 year period and the implementation of the permit conditions that apply BAT in compliance with the BAT conclusions. 2

11 Aside from providing a basis for compliance, ELVs are also important in the application of Quality Assurance standards. In the case of large combustion plant, minimum requirements are defined under the special provisions laid down in IED Chapter III and mandatory maximum ELVs are defined in Annex V, noting that BAT requirements may lead to the application of lower ELVs than these mandatory values. Mandatory ELVs cannot be exceeded even if a site specific assessment can be used to justify emission levels higher than BAT 4. Every three years, starting from 7 January 2016, the Commission will review the need to update the minimum requirements for ELVs, and the monitoring and compliance rules, based on the BAT Conclusions adopted within the previous three year period. This will take account of environmental impacts and the state of implementation of BAT across the EU 5. A number of derogations apply to old plant with limited running higher ELVs for NO x and SO 2 are defined within Annex V for plant that operate for less than 1500h per annum as a rolling five year average. Any gas fired plant, when firing standby fuel for individual periods of 10 days, due to a sudden interruption of the gas supply, shall be exempt from ELV compliance for those periods 6, subject to informing the Competent Authority of each specific instance of using this derogation. Each of the periods for which such a derogation is granted shall not exceed 10 days except where there is an over-riding need to maintain energy supplies (by agreement with the Competent Authority). Plant of any age, destined for closure, are exempt from Annex V ELVs under a Limited Lifetime Derogation (LLD) that requires operation to be limited to a total of 17,500h between 1 January 2016 and 31 December Combustion plant permitted prior to 27 November 2002 may instead comply by means of diminishing annual mass emission caps, under a Transitional National Plan (TNP), in the period from 1 January 2016 to 30 June The TNP may be optionally applied to SO 2, NO x and dust individually. For gas turbines, the TNP is only available for NO x and an ELV approach applies to CO 7. However, in all circumstances, plant must comply at least with the permitted ELVs that are applicable on 31 December , noting that the daily ELV may be applied as an annual 95 th percentile for plant in the TNP or LLD. An over-view of IED compliance routes is given in Table 1 which lists the main provisions, the time period when these apply, the qualifying requirements and any exclusions or conditions. Common provisions are described at the bottom of the table. It should be noted that rules for ELV compliance 9 require that no validated monthly average exceeds the defined ELV, no validated daily average exceeds 110% of the ELV and 95% of the validated hourly averages over the year do not exceed 200% of the ELV. A validated average is determined by correcting the hourly average raw concentration value to the appropriate reference conditions, in order to obtain a valid hourly average, and then subtracting the defined confidence interval as specified in Section 6. For ELV compliance, a valid hourly average is obtained only during periods of normal operation, excluding Start-up and Shut-down periods (subject to the constraints described in Section 3.5) and abatement Malfunction and Breakdown periods (subject to the constraints described in Section 3.6). For mass emissions reported under the TNP, and for the IED inventory, Start-up and Shut-down periods are excluded and abatement Malfunction and Breakdown periods are included. For reporting against site specific NO x limits, and for the Pollution Inventory, mass emissions include both Start-up and Shut-down periods (where 4 IED Article 15(4) & Article 30(2) 5 IED Article 73(1) 6 IED Article 30(6) 7 IED Article 32(1) 8 TNP - IED Article 32(2). LLD - Article 33(1c) 9 Article 39 requires compliance with Part 4 of Annex V 3

12 emission data may be either measured or calculated) and abatement Malfunction and Breakdown periods. 3.2 Large Combustion Plant Aggregation Rules A Large Combustion Plant (LCP) is any combustion plant with a rated net thermal input 50MW, noting that gas turbines and gas engines used on offshore platforms are excluded from the scope 10 of Chapter III of the IED along with a number of other specific cases (Appendix A). Multiple combustion units that discharge to atmosphere from a common stack are considered to be part of a single combustion plant with a combined thermal input 11. A common stack can contain multiple individual flues. A utility boiler with multiple flues within a common windshield or supporting structure is therefore part of a larger, single, combustion plant and the emissions from the multiple flues need to be combined for compliance purposes. Note that individual units of less than 15MW thermal input are not counted for defining the thermal input of the LCP nor for the purposes of ELV determination and monitoring requirements 11. However, the thermal input and mass emissions of the <15MW units will be included in the LCP for inventory reporting purposes. Where the flue gases from the <15MW units are physically mixed with the flue gases of the larger unit(s), the LCP ELV will apply to the <15MW units. Where the <15MW units discharge through separate flue(s), ELV setting and compliance arrangements will be determined by the Competent Authority. In the case of one or more units taking a 1500h ELV derogation, the derogated unit(s) and the remaining unit(s) shall be regarded as two separate Large Combustion Plant for monitoring and compliance purposes (including the determination of operating hours) 12. Combustion units with individual stacks, permitted on or after 1 July 1987, may also be considered to be a single LCP if their flues could have been routed through a common stack, in the judgement of the Competent Authority, taking into account technical and economic factors 11. Multiple gas turbine units that are flued within a common wind-shield, or through a common Heat Recovery Steam Generator (HRSG) flue, or a common flue associated with a steam/hot water raising system, are therefore also considered to comprise a single LCP. However, for reasons of practicality and cost, a gas turbine is usually supplied to a unitised design with one stack serving one gas turbine unit which shall be considered to be a single large combustion plant for compliance purposes unless a different determination is arrived at by the Competent Authority 13. Similarly, a single gas turbine that exhausts through multiple flues shall be regarded as a single large combustion plant. Supplementary and auxiliary firing of the HRSG (>15MW thermal input), within a combined cycle, or within a steam/hot water raising system, shall be regarded as part of the same large combustion plant as the gas turbine. Emission Limit Values for an LCP, as defined in Annex V of the IED, depend on the size of the plant and the ELVs are based on the aggregated thermal input of the LCP (including the HRSG or associated steam/hot water raising system) and are applied to the common stack emission 14. For the case of HRSG auxiliary firing, the boiler ELV, for the auxiliary firing mode, and the gas turbine ELV, for the GT firing mode, will be respectively based on the auxiliary firing thermal input alone and the gas turbine thermal input alone. For the case of HRSG supplementary firing, the gas turbine ELV will be determined based on the combined total of the gas turbine and supplementary firing thermal inputs. The ELV can then be adjusted using the approach given below. For the case of HRSG auxiliary firing, this shall be regarded as part of the 10 IED Article IED Article Protocol for IED Annex V 1500 Limited Hours Derogation, Energy UK, EnvC WGEREG 08/15 13 IED Article 29 (2) 14 IED Article 30(4) 4

13 supplementary firing combustion system, noting that the auxiliary firing performance is technically constrained by the supplementary firing design parameters. For auxiliary firing, the oxygen reference condition for reporting and the boiler ELV reference shall therefore also be increased to 15% O 2 15 (for short periods when the gas turbine is unavailable). The boiler ELV is taken to be the same numerical value as that applied at 3% O 2. However, in these situations, the Operator shall provide a credible recovery plan for the gas turbine to the Competent Authority and agree a course of action. When a credible recovery plan cannot be agreed, or is not appropriate, then the auxiliary firing then needs to comply with the original boiler ELV at 3% O 2 (for convenience this ELV can be divided by 3 if reporting continues at 15% O 2 ). Notwithstanding the exclusion of units less than 15MW thermal input when determining LCP status, there is no lower limit on the unit size for aggregation with regards to applying BAT and permitting requirements 16. That is, all combustion units, of any size, and of different technology types, are aggregated together and are regulated as a combustion activity of 50MW thermal input. An installation of more than 50MW thermal input may therefore be comprised entirely of small combustion units to which Chapter III and Annex V of the IED do not apply. 15 IED Annex V Part 2(1) 16 IED Annex I (1.1) as implemented in the following national regulations: England & Wales: The Environmental Permitting (England and Wales) (Amendment) Regulations 2013, ISBN ;Scotland: Schedule 1, Part 1, Chapter 1, Section 1.1 Part A of the Pollution Prevention and Control (Scotland) Regulations 2012 (SSI 2012: 360); Northern Ireland: The Pollution Prevention and Control (Industrial Emissions) Regulations (Northern Ireland) 2013 (SSI 2013:No 160).. 5

14 Table 1: IED Compliance routes for existing Large Combustion Plant IED Compliance Routes for Existing Large Combustion Plant (permitted before 7-Jan-2013) ELV Compliance [Article 30] Limited Running [Article 30(4)] Transitional National Plan (TNP) [Article 32] Limited Lifetime Derogation (LLD) [Article 33] From To 01-Jan Applicant: Operator Application to MS by: 01-Jan-2016 Description: Default ELVs apply to all large combustion plant [Annex V Part 1]. Coal: SO 2 200; NO x 200; Dust 20 mg/m 3 at 6% O 2 Gas Turbines: NO x 50*/ 90/120 mg/m 3 at 15% O 2 for Nat Gas/Distillate/Other Gas * 75 mg/nm 3 for CCGT > 55% η, CHP > 75% η and 50η / 35 for OCGT (w here η = ISO base load efficiency) BAT ELVs required 4 years after BAT Conclusions published [Article 15(3)]. Expected From To 01-Jan Applicant: Operator Application to MS by: 01-Jan-2016 Description: Higher ELVs apply for plant that are limited to 1,500 hours per year as a five year rolling average [Annex V Part 1]. Coal: SO mg/m 3 ; NO x 450 mg/m 3 at 6% O 2 Gas Turbines: NO x 150 mg/m 3 (natural gas) 200 mg/m 3 (other gases & liquid fuels) From To 01-Jan Jun-2020 Applicant: Member State Application to EU by: 01-Jan-2013 Description: Annual mass emission allowances for selected pollutants. These decrease linearly, year-on-year, based on a linear decrease in ELVs between 2016 (LCPD) and 2019 (IED Annex V). The exceptions are NO x for coal fired boilers and gas turbines (the ELVs are the same). The allowances are also based on average operation (annual average flue gas volume) from 2001 to 2010 [Article 32 (3)]. From To 01-Jan Dec-2023 Applicant: Operator Application to MS by: 01-Jan-2014 Description: Exemption from ELVs and TNP subject to a limit on operating hours of 17,500 in the above time period [Article 33(1a)]. The Operator must apply by 01-Jan-2014 [Article 33(1c)]. The Member State shall submit a list of LLD plant by 1-Jan-2016 stating rated thermal input, fuel types, and the applicable ELVs for NO x, SO 2 and Dust [Article 33(2)]. Applies to: Large Combustion Plant [Ch III] permitted before 7-Jan-2013 or with a complete permit submission by that date and operating no later than 7-Jan-2014 [Article 30(2)]. Exclusions: Coal fired plant. i) Plant firing high sulphur indigenous solid fuel comply with 96% FGD removal efficiency [Article 31 & Annex V Part 5(1)] ii) Max. 6 month derogation for SO 2 for plant relying on low sulphur fuel due to a severe shortage of such fuel [Article 30(5)]. Gas fired plant. i) Gas turbines for emergency use that operate less than 500 h per year are excluded. ii) Max. 10 days interruption of gas supply: Backup fuel, that would otherwise require abatement plant, does not need to meet ELVs. [Article 30(6)]. MS to immediately inform the Commission when primary fuel unavailable for both coal and gas. Applies to: Large Combustion Plant [Ch III] permitted before 27-Nov-2002 or with a complete permit submission by that date and operating no later than 27-Nov-2003 [Annex V Part1]. This can apply to individual units within a Large Combustion Plant [Article 30(4)]. The SO 2 provision applies to all plant sizes. The NO x provision applies to plant >500MWth permitted before 1 Jul Exclusions: Gas turbines and gas engines for emergency use that operate less than 500 operating hours per year. Applies to: Large Combustion Plant [Ch III] permitted before 27-Nov-2002 or with a complete permit submission by that date and operating no later than 27-Nov-2003 [Article 32 (1)]. Does not apply to individual units within a plant [Annex to Implementing Decision]. Applies to NO x and/or SO 2 and/or Dust (not CO for gas turbines) [Article 32 (1)]. Exclusions: Limited Lifetime Derogation plant [Article 33(1)]; Exempt district heating plant [Article 35]; Opted-out plant under LCPD [Article 32(1)]; Co-incineration plant [Annex of Implementing Decision]. Applies to: Large Combustion Plant [Ch III] permitted before 7-Jan-2013 or with a complete permit submission by that date and operating no later than 7-Jan-2014 [Article 33 (1)]. Exclusions: Plant >1,500 MW th, with first operation before 31-Dec-1986, firing indigenous solid fuel with specific properties [Article 33 (4)] - operating hours are increased to 32,000h. Plant that are part of an isolated system on 6-Jan-2011 have 18,000h from 1-Jan-2020 to 31-Dec [Article 33(3)]; Opted-out plant under LCPD [Article 33(1d)]. Conditions: BAT is always required. Permits will be reviewed from 7-Jan-2014 when the general IED permitting requirements come into force. This is important for other options that rely on Permit values that are applicable on 31-Dec Conditions: Operation is restricted to 1,500 per year as a rolling average over a period of 5 years. Conditions: The Permit ELVs applicable on 31- Dec-2015 shall at least be maintained [Article 32(2)]. Allowances from retired plant cannot be transferred to remaining plant [Article 32(3)]. Provisions for eventual compliance with BAT ELVs shall be specified [Article 32(4)]. Conditions: The Permit ELVs applicable on 31- Dec-2015 shall at least be maintained [Article 33(1c)]. The Operator annually submits the cumulative operating hours from 1-Jan-2016 [Article 33(1b)] and the Member State submits these to the Commission [Article 33(2)]. Common provisions. Interim site specific BAT conditions apply from 1-Jan-2016 for all compliance pathways. Annual inventory and operating hours reporting. For each Large Combustion Plant, the MS obtains the following data in order to establish an annual inventory of pollutant mass emissions: the total rated thermal input (MW); the type of combustion plant (boiler, gas turbine, gas engine, diesel engine, other); the operating start date; the total annual emission (tonnes per year) of SO 2, NO x and Dust (as TSP); the number of operating hours; the total energy consumption (TJ per year), and calorific value, by fuel (coal, lignite, biomass, peat, other solid fuels, liquid fuels, natural gas, other gases. The annual inventory data is made available to the Commission on request and summarised every three years.[article 72(3)]. The following data are reported annually by the MS to the Commission: i) the number of operating hours per year for plant with a 1,500h per year provision; ii) for plant firing high sulphur indigenous solid fuel, the monthly fuel sulphur content and removal efficiency and, for the first year in which this applies, the technical justification for not complying with ELVs [Article 72(4)]. Common provisions. ELV compliance. Compliance with Annex V ELVs is based on meeting the requirements of Part 4 of Annex V as required by Article 39. That is, no validated monthly average exceeds the defined ELV, no validated daily average exceeds 110% of the ELV and 95% of the validated hourly averages over the year do not exceed 200% of the ELV. 6

15 3.3 Mandatory ELVs Utility Boilers Annex V of the IED contains mandatory ELVs for existing and new utility boilers, for SO 2, NO x and dust, noting that an ELV of 100 mg/m 3 is also specified for CO for gas fired boilers. In broad terms, the ELVs for existing solid fuel firing plant are 200 mg/m 3 SO 2, 200 mg/m 3 NO x and 20 mg/m 3 dust, representing a roughly 50% reduction of the limit values applicable prior to 1 January Table 2: IED Emission Limit Values for large utility boilers IED Annex V (>300 MW th ) Existing Plant (Part 1) New Plant (Part 2) Solid fuel Liquid fuel Natural gas Solid fuel Liquid fuel Natural gas SO , NO x Dust Ref. O 2 dry 6% 3% 3% 6% 3% 3% Notes to this table mg/m 3 if operating <1500h/year (5 year rolling average) for unit or LCP (permitted before 27 Nov 2002). 2 Alternatively, 96% removal efficiency for indigenous solid fuel subject to techncial justification for not meeting ELV mg/m 3 if operating <1500h/year (5 year rolling average) for unit or LCP (permitted before 27 Nov 2002). 4 Different limits for other fuel gases mg/m 3 if operating <1500h/year (5 year rolling average) for unit or LCP (>500MW e permitted before 1 Jul 1987) mg/m 3 if operating <1500h/year (5 year rolling average) for unit or LCP (>500MW e permitted before 27 Nov 2002). 7 Natural gas only. Other gases 200 mg/m 3 or 300 mg/m 3 (<500MW e permitted before 27 Nov 2002) mg/m 3 for biomass and peat. The IED includes a derogation for combustion plants using indigenous solid fuel which cannot comply with SO 2 ELVs due to the fuel characteristics 17. In these cases the member state may apply the minimum desulphurisation rates given in Table 2. For existing plant >300MW th this is a 96% removal rate applied as a monthly average value. It follows that plant operating under this derogation do not have to comply with SO 2 ELVs and compliance is determined based on the monthly FGD removal efficiency and fuel sulphur content alone 18. In the first year, a technical justification for not complying with the ELVs is required Gas Turbines Annex V of the IED contains mandatory (maximum) limits of 50 mg/m 3 for NO x and 100 mg/m 3 for CO for both new and existing gas turbines using natural gas as a fuel. For existing plant, there are provisions for higher NO x ELVs at higher overall plant efficiency (at ISO base load conditions), for natural gas firing, and higher limit values for light and middle distillate fuel oil and other gases, as shown in Figure 1 and Table 3. Natural gas is defined as naturally occurring methane with not more than 20% (by volume) of inerts and other constituents. For new plant, the NO x limit of 50 mg/m 3 and a CO limit of 100 mg/m 3 apply for all fuel types and plant types, with the exception of natural gas fired OCGTs which have NO x limits which depend on efficiency in the same way as existing OCGTs. 17 IED, Article 31(1) and Annex V Parts 5 & 6 18 IED, Article 72(4a) 7

16 For a gas turbine (CCGT or OCGT), the ISO base load net plant efficiency is the performance value established by acceptance testing following commissioning, as agreed for the UK TNP allocations [5]. Whilst this one-off determination, which has already been declared for plant applying for the TNP, does not take account of subsequent in-service performance degradation, it does have the advantage of simplicity and provides a comparable approach to a new plant. Alternatively, if more recent performance testing has been undertaken, an updated efficiency value can be used. For CHP, the equivalent efficiency definition for the whole plant is used, i.e., the overall thermal efficiency of the process, taking into account the generation of both electricity and heat as verified by performance testing at handover or, alternatively, during later evaluations if these are available. Otherwise, the average of the available CHPQA certificates for the TNP qualifying period ( ) shall be used, although this will be lower due to degradation and inclusion of the whole operating cycle and auxiliary plant. If the status of the CHP plant changes substantially, e.g., such that heat is no longer exported and the installation has become a merchant power plant, then the efficiency used for the ELV determination will be determined, and justified, on a case-by-case basis that will depend on the continuing CHP readiness of the plant and the plant efficiency in the new configuration. 125 NOx ELV (mg/m 3 ) OCGT: NOx = 50 * η / 35 CCGT CHP OCGT Mech Drive Fuel oil Other gas Efficiency (%) Figure 1: IED mandatory ELVs for existing gas turbine plant Taking the example of a 50 mg/m 3 NO x limit, the compliance approach in the IED requires that: - no monthly validated averages are higher than the ELV (50 mg/m 3 ); - no daily validated averages are higher than 110% of the ELV (55 mg/m 3 ); - 95% of the validated hourly average values over the year do not exceed 200% of the ELV (100 mg/m 3 ). 8

17 Table 3: IED mandatory ELVs for existing gas turbine plant GAS TURBINE PLANT NO x Comment Natural gas mg/m 3 Combined Cycle Gas Turbine (CCGT) 50 / 75 Step increase from 50 to 75 at 55% efficiency Combined Heat & Power (CHP) 50 / 75 Step increase from 50 to 75 at 75% efficiency Open Cycle Gas Turbine (OCGT) Linear increase above 35% efficiency Mechanical Drive (Mech. Drive) 75 Fuel oil 90 Other gas 120 There are additional provisions for old plant, i.e., those permitted before 27 November 2002 or those with a full permit application submitted before this date that were put into operation no later than 27 November For plant firing natural gas, with operating hours not exceeding 1,500 per annum, based on a five year rolling average, a NO x ELV of 150 mg/m 3 applies (for oil and other gaseous fuels this is 200 mg/m 3 under the same conditions) 19. The IED states that Start-up and Shut-down periods shall not be considered for compliance purposes 20 and only applies NO x limits for gas turbines above 70% load 19 when firing natural gas since it becomes progressively more difficult to maintain base load emissions performance at lower loads. For the same reasons, this provision shall also apply to fuel oil firing, although this is not explicitly stated in the IED, since the operational characteristics of the gas turbine that limit performance are essentially the same when firing fuel oil (especially the compressor characteristics and combustion air flow rates). The emission limit values do not apply to gas turbines for emergency use that operate for less than 500h per annum 21. Supplementary firing (SF) in gas turbine (GT) exhausts is a special case due to the combustion technology employed. The fuel is usually introduced through an array of simple fuel injectors within the hot turbine exhaust gas. A NO x benefit is often associated with supplementary firing, related to the open flame structure of these fuel injectors and the reduction in oxygen content within the exhaust gas; typically the exhaust O 2 drops from 15% to 9% for a supplementary heat input equal to the gas turbine heat input. It is not usually necessary to modify the NO x ELV for modest levels of supplementary firing, i.e., the gas turbine NO x ELV generally continues to apply for ESI plant. However, if this approach does not adequately take account of SF, the Operator may propose, for agreement by the Competent Authority, an approach in which a weighted NO x ELV is defined, in mg/mj, based on the gas turbine and supplementary firing heat inputs, in order to accommodate the installed supplementary firing technology [6]. This is based on the Maximum Continuous Ratings (MCR) of the GT and SF, in MW net thermal input, and the respective GT and SF NO x ELVs, in mg/mj, as follows: LLL NN x EEE mm MM = [EEE GG MMM GG ] + [EEE SS MMM SS ] [MMM GG + MMM GG ] The GT ELV is defined by regulation and BAT considerations. The SF ELV has been previously defined as 70 mg/mj for gas SF and 100 mg/mj for oil SF [7]. The adjustment factor, A, 19 IED Annex V Part 1(6) 20 IED Article 15(3) & Annex V Part 4(1) 21 IED Annex V Part 1&2, (5) & (6) 9

18 depends on BAT considerations and, in practice, on the relative NO x contribution of the GT and the SF. The adjustment factor is usually in the range 0.15 to 1.0 [6]. It should be noted that the conversion factor from mg/m 3 to mg/mj depends on the flue gas O 2 concentration. NO x ELVs must first be converted to mg/m 3 at 15% O 2 dry, then multiplied by m 3 /MJ (natural gas firing) or m 3 /MJ (gas oil firing) in order to obtain mg/mj. Alternatively, divide ELVs in mg/mj by the same conversion factors to obtain ELVs in mg/m 3 at 15% O 2 for permitting purposes. Note that ELVs can also be entered as mg/m 3, at reference conditions, in the weighting formula, in order to obtain a combined ELV in mg/m 3. When the SF fuel is the same as the GT fuel, this is exactly equivalent to the mg/mj approach. When the SF fuel is different to the GT fuel, there is minimal loss in accuracy. Supplementary firing technology also generally results in higher CO emissions and the ELVs for such plant shall therefore not be reduced below 100 mg/m 3. The reference conditions for ELV setting and emissions reporting, for supplementary firing, are identical to the gas turbine reference conditions, i.e., 15% O 2, dry, unless otherwise agreed with the Competent Authority. It is sometimes also appropriate to use the same reference condition for auxiliary firing on the same boiler (Section 3.2). For gas turbine operation below 70% load, it becomes progressively more difficult to achieve base load NO x and CO ELVs on turndown and there is a danger that plant flexibility could be overly compromised. The EU Implementing Decision on Start-up and Shut-down (Section 3.5) specifies how abnormal operation is defined, based on a Minimum Start Up Load (MSUL) and a Minimum Shut Down Load (MSDL), and simply refers to the IED Annex V with regards to ELV compliance. Although the IED requires ELVs to be applied during normal operation, this is limited, for gas turbines, to greater than 70% load in Annex V. Ultimately, the approach to operation below 70% load is subject to a site specific BAT determination and an air quality assessment. However, the following general guidance is given here, with compliance based on a daily ELV only for the part load operation: a) Base load ELVs apply to emissions in the load range 70% to base load; b) Part load ELVs apply to emissions in the load range MSUL to base load. In each case, the hourly average emission concentrations and the daily averages are calculated in the usual way, as described in Section 6, using the two different load thresholds (MSUL and 70%). The base load ELVs apply to operation above 70% of ISO base load. The part load ELVs apply to all operation from MSUL to base load and then back to MSDL, although MSDL is normally the same as MSUL for gas turbines. Part load operation is therefore included in the total emissions performance above MSUL since it is difficult to calculate and report emissions during short periods between MSUL and 70% load. This also allows additional operational flexibility since emissions from part load hours are averaged with emissions from base load hours. For example, when considering over-night operation, the higher night-time emissions from low load operation are combined with the lower day-time base load emissions to meet the part load ELVs. Alternatively, the GT could be run below 70% load continuously and would not have to meet IED ELVs, but must meet the part load ELVs directly. 10

19 This is illustrated in Figure 2 in which CO emissions are plotted against relative load. The load range from 70 to 100% ISO base load (and above) is subject to the IED compliance regime of monthly and daily ELVs and an annual 95 th percentile ELV for hourly averages. Only the daily base load ELV (50 mg/m 3 ) is shown in Figure 2, applying in the 70 to 100% load range. The load range from MSUL to 100% ISO base load (and above), incorporating part load operation, is subject to a higher absolute daily ELV only (100 mg/m 3 ), as shown in in Figure 2, from 45% to 100% load in this example. Example A, in Figure 2, indicates that continuous daily operation below 70% load is subject to the higher daily ELV only. Since there are no operating hours above 70% load, the emissions from this day do not contribute to the monthly, daily and percentile ELVs that apply to the high load range. These emissions are reportable against the part load daily ELV only. Example B, in Figure 2, with mixed load operation between day time (18 hours) and night-time (6 hours), indicates that two daily averages will be reported for this day. The day time emissions, above 70% load, are included in the base load daily, monthly and percentile averages. Both the day-time and the night time emissions are included in a second daily average that is assessed against the part load ELV. In this case, the higher emissions at MSUL are averaged with the low base load emissions to achieve compliance with the daily part load ELV. 250 CO (mg/m 3 ) Example A: Continuous Part Load Operation Example B: Night-time - Day-time Operation CO emission Part load ELV (100 mg/m 3 ) Base load ELV (50 mg/m 3 ) 0 40% 50% 60% 70% 80% 90% 100% MSUL Relative Gas Turbine Load (%) Figure 2: Illustration of Gas Turbine Compliance with daily Emission Limit Values Since CO is a product of incomplete combustion, if a part load CO ELV higher than 100 mg/m 3 is proposed, the BAT assessment and any associated environmental impact assessments must specifically address emissions of other species associated with incomplete combustion, i.e., methane and formaldehyde For the purposes of this assessment, methane and formaldehyde 11

20 emissions are considered to be acceptable if the daily CO ELV is 440 mg/m 3 but a site specific assessment is always required if the effective stack height is less than 30m 22. ELVs for SO 2 and dust are not specified in the IED for gas turbines but are specified for boilers. Standby liquid fuel (gas oil) contains less than 0.1% by mass of sulphur as required by the Sulphur Content of Liquid Fuels Regulations [11][12] and is equivalent to about 55 mgso 2 /Nm 3 in dry flue gas at 15% oxygen and about 165 mgso 2 /Nm 3 at 3% oxygen for boiler applications [9]. Natural gas is almost sulphur free; the residual sulphur in natural gas supplied through the high pressure grid equates to a flue gas SO 2 concentration of about 0.09 mg/nm 3, at 15% O 2 in the dry flue gas, and this rises to about 0.24 mg/nm 3 for odorised gas (multiply by 3 to obtain the concentrations at 3% O 2 ) [13]. Natural gas is ash free and gas fired plant do not, therefore, emit dust at a concentration that can be measured meaningfully using reference methods. In the case of gas fired installations, the dust emission is therefore considered to be zero, although this may be revised at a later date subject to the requirements of the UK Pollution Inventory methodology which is updated annually [9]. An emission factor approach shall therefore be used to estimate emissions of both SO 2 and dust from gas turbine and boiler plant [9]. The IED defines natural gas as naturally occurring methane with not more than 20% (by volume) of inerts and other constituents 19 and defines alternative NO x limits for these other gases. In these cases, fuel sulphur limits or SO 2 emission limit values may be defined by the Competent Authority whilst recognising that the Commission is required to review the need for additional measures 23 for this fuel category. 3.4 Process Description Utility Boilers Solid fuel fired power stations typically apply the following techniques for emission control, noting that different techniques may be applied on units comprising a Large Combustion Plant in order to achieve the required performance levels. For the control of NO x, a combination of primary techniques, with Selective Catalytic Reduction (SCR), or Selective Non-Catalytic Reduction (SNCR), are used where appropriate. Ammonia or urea is injected into the flue gas within an acceptable flue gas temperature window that depends on the technique. The injection process is carefully controlled such that excess ammonia is minimised. Ammonia slip in the flue gas, beyond that absorbed by the ash, is therefore minimal during normal operation and is controlled by monitoring the ammonia in ash levels and/or process measurement of ammonia immediately downstream of the reaction zone. For the control of SO 2, Flue Gas Desulphurisation (FGD) using a wet limestone-gypsum or seawater scrubbing process, combined with ultra-low sulphur fuel firing, are used where appropriate. Note that the FGD unit removes other, highly soluble, acid gases, such as HCl and HF, with a very high removal efficiency [9]. For the control of dust, good combustion control with Electrostatic Precipitators (ESPs), combined with wet FGD scrubbers, are used where appropriate. 22 Horizontal Guidance Note H1:Annex F Air Emissions 23 IED Article 30 (9)(c) 12

21 Mercury (Hg), in both oxidised and elemental forms, both vapour phase and particle bound, is absorbed in the ash and the FGD unit. Conservative removal rates of 50% with ESP only and 75% in combination with an FGD unit are assumed within the Pollution Inventory [9]. Mercury shall not be monitored continuously but is subject to an annual manual reference method test to measure total mercury, for combustion plant firing coal or lignite, under the IED Gas Turbines BAT and associated emission levels are defined in the Combustion BREF and are summarised in the Combustion BAT Conclusions. For NO x and CO, dry low NO x (DLN) combustion is combined with good combustion control. Fuel is well mixed with a large excess of air before combustion takes place. These lean premix systems produce substantial reductions in NO x emissions, due to the overall reduction in flame temperature, but they operate much closer to the lean stability limit and can be prone to damaging high amplitude pressure fluctuations (combustion dynamics) which can result in serious damage to the combustor, and other GT components, in addition to reducing operational life and availability. Both NO x and CO tend to increase on turndown due to higher pilot fuelling and increasing air:fuel ratio. Note that water or steam injection into the combustor is an alternative means of flame temperature and NO x reduction on older gas turbines. It is important to recognise that a number of factors need to be taken into account when setting ELVs and obtaining commercial guarantees from gas turbine manufacturers, such as: - Fuel quality (variability) - Ambient conditions (range) - Degradation in performance between outages - Operational envelope (part load running and flexibility). For the purposes of illustration, the IED mandatory NO x and CO ELVs are assumed throughout this guidance document. 3.5 Start-up and Shut-down General Considerations Emission limits apply during normal operation only. Start-up and Shut-down (SU-SD) periods are specifically excluded from emission compliance requirements 20. SU-SD periods are also excluded when determining operating hours 25 for compliance or reporting purposes. The European Commission is mandated to establish implementing rules for determining SU-SD periods under the IED 26. These implementing rules [14] define a Minimum Start-Up Load (MSUL), for stable generation, and a Minimum Shut-down Load (MSDL), for stable generation, below which the combustion unit cannot safely and reliably deliver its output to the grid or industrial site 27. MSUL and MSDL are the minimum declared load thresholds, below which the plant will not generate commercially and above which environmental reporting is active. MSUL refers to the 24 IED Annex V Part 3(4) 25 IED Article 3(27) 26 IED Article 41(a) 27 SU-SD Implementing Rules Article 2 13

22 point at which Start-up has completed and MSDL refers to the point at which Shut-down has commenced. MSUL and MSDL may be declared differently and use other plant parameters in addition to load in their definitions, as described below. MSDL may be lower than MSUL due to, for example, the thermal state of the plant. The relationships between these minimum load thresholds, the technical characteristics of the plant and the thresholds associated with electricity trading are described in detail in Appendix C. Unlike MSUL and MSDL, these technical and commercial thresholds can vary depending upon the state of the plant, the fired fuel and the ambient conditions. Alternatively, and often more conveniently, for either combined cycle or open cycle operation, reporting for gas turbines can be based on burner mode switching, that is, reporting commences on switch-over to lean premix combustion mode, as allowed under the Implementing Rules 28, 29. This allows greater plant flexibility to be achieved since the plant can be run with acceptable emissions performance from the lowest load condition possible which varies, to some extent, depending on ambient conditions. The Implementing Rules then require three criteria to be defined with SU-SD established if any two of the three criteria are satisfied. Standard criteria can be defined, as described in Appendix C, using exemplary additional parameters given in the Annex of the Implementing Rules. However, equivalent criteria and inputs can be defined 30, such as bypass damper position, steam valve position, gas turbine in tuning mode, etcetera. When additional parameters are employed, the MSUL load threshold shall be specified as one of these parameters in order to ensure that emissions are reported if, for example, the combustion system fails to switch to lean premix mode. The Implementing Rules require that the criteria used to determine Start-up and Shut-down periods shall be transparent and externally verifiable 31. The IED requires that the permit considers the measures taken in relation to SU-SD 32, including measures to minimise SU-SD periods 33 and measures to ensure that all abatement equipment is brought into operation as soon as is technically practicable. These conditions shall be satisfied by declaration of the relevant load thresholds in the Permit 34. A justification for the selection of MSUL and MSDL shall be provided to the Competent Authority, noting that the Operator may adapt the generic information in Appendix C for these purposes. Since the time taken to achieve SU-SD is highly dependent on the plant configuration, and is also dependent upon the state of the plant (duration of Shut-down) and the ambient conditions, the use of time limits in relation to Start-up and Shut-down shall be avoided since this is considered to be impractical, both from an operational and a regulatory viewpoint. Time limits are not specified in the Implementing Decision on Start-up and Shut-down [14] Operating Hours For the purposes of calculating operating hours 35, an LCP comprised of multiple flues is considered to start running when the first unit to operate passes the MSUL threshold and stops 28 SU-SD Implementing Rules Annex 29 SU-SD Implementing Rules Article 4(1)(a) 30 SU-SD Implementing Rules Article 9(2) 31 SU-SD Implementing Rules Article 3(1) 32 IED Article 14(f) 33 SU-SD Implementing Rules Article 4(1)(b) 34 SU-SD Implementing Rules Article 6(3) 35 IED Article 3(27) 14

23 running when the last operational unit falls below the MSDL threshold. Operating hours are calculated to the nearest minute and, for limited life time derogations, these are reported as the cumulative total from 00.00h 1 January 2016 to two decimal places. All plant must report total operating hours annually under the IED 36. For a plant subject to the Limited Lifetime Derogation, or a 10,000h monitoring derogation, the cumulative operating hours accrued from 1 Jan 2016 are therefore also reported annually (Section 6.10). For plant subject to the 1500h derogation 12, the hours accrued within the 1500h derogation within a given calendar year must be reported annually 37. However, the five year rolling annual average is calculated by averaging the cumulative unit operating hours, starting from the beginning of the month in which the derogation commences, and then updated on a monthly basis, for a period of five years. This rolling average is reported separately each year (Section 6.10). After this, a true running five year average is established, i.e., the first year of operation is dropped, the sixth year is included, and so on. If a plant leaves the 1500h derogation in-year to enter the 500h emergency plant derogation (no ELV), then the emergency hours are not included in the 1500h total but the 500h allowance is pro-rated to reflect the remaining available operating time in that year, e.g., entry on 1 July (half way through the year) results in 50% of the allowance, that is, 250h. If a plant re-enters the 1500h derogation from the 500h regime then the 5-year running average is started afresh but the 500h allowance is again pro-rated 38, Working to Operational Thresholds Grid demands may result in changing operating patterns and technical issues may require a temporary increase to the commercially applicable minimum operating points described in Appendix C. Therefore, emissions reporting shall always be determined by the declared permit values of Minimum Start-Up Load (MSUL) and Minimum Shut-Down Load (MSDL) which shall be set as low as practicable such that start up and shut down periods are minimised, noting that MSDL may be set to the same value as MSUL. Half-hourly demand information is publicly available so any unusual operating patterns are instantly visible and can actively be tracked from a commercial and regulatory perspective. It is important that the application of the operational thresholds is transparent, equitable and verifiable. The EU Decision requires MSUL and MSDL values to be stated in the Permit as a percentage of the rated electrical output 34, i.e., the Maximum Continuous Rating (MCR). The thresholds declared in the Permit shall follow the format given in Table 4 for each combustion unit. In the case of CCGT, a separate declaration for open cycle operation may be required, as indicated in the footnotes to Table 4. The Operator may only declare a Stable Export Limit value lower than MSUL/MSDL when conducting short-term trials to investigate the possibility of lowering the declared threshold values. Gas turbine tuning activities (required to ensure system integrity as well as emissions performance) are also exempt. These shall be regarded as other than normal operating conditions IED Article 72 (3)(e) 37 IED Article 72 (4)(b) 38 It should be noted that this pro-rating of the 500h period does not apply to a CCGT that is temporarily operating in open cycle mode. In this case, the 500h relates to open cycle operation which can be undertaken without restriction throughout the year. 39 Protocol for IED Annex V 500 Limited Hours Derogations, Energy UK, EnvC WGEREG 17/15. 15

24 Table 4: Declared SU-SD thresholds Boiler/CCGT 2 /OCGT 3 MW (Generated/Sent Out/Thermal) 1 % of (delete as applicable) (delete as applicable) MCR MCR 100 MSUL MSDL Notes 1 The unit generated load (before subtraction of works power) may optionally be used to define SU-SD. The thermal output may be used for boilers that generate heat only and this may be specified as a steam or hot water flow rate rather than MW thermal output. 2 For CCGT, MSUL is normally the combined cycle plant load and MCR is the total combined cycle plant load associated with the gas turbine operating at ISO Base Load rating, expressed on a consistent basis. Alternatively, MSUL may be specified as the measured or indicated gas turbine load with MCR equal to the ISO Base Load gas turbine rating. This alternative approach may be i) required for multi-shaft plant with a range of output configurations and ii) preferred for combined cycle plant that also operate in open cycle mode such that only one load threshold needs to be declared (provided that the indicated gas turbine load is accurate and reliable). For Open Cycle mode on a CCGT, an additional separate declaration, based on GT load, must be provided if the combined cycle plant MCR and MSUL are used to define combined cycle operation. 3 For OCGT the gas turbine load is always directly available and MCR is the ISO Base Load rating. For utility boilers, in order to take account of aborted runs of short duration, in which the unit cannot achieve stable conditions due to, for example, coal mill failure(s), at least 3 hours of reportable data are required to qualify a daily average, although these are still reported within the monthly average and annual percentile. At least 3 days of reportable data are required to qualify a monthly average (Section 6) in line with previous arrangements. This is intended to address situations in which the plant is operating sporadically, for example, the plant is only called on for two (separate) days in the month and could fail on monthly compliance due to problems on one day. For CCGT plant, in order to take account of aborted runs of short duration, in which the unit cannot achieve stable conditions due to, for example, steam cycle issues, at least 2 hours of reportable data are required to qualify a daily average (Section 6). This provision is not available for open cycle operation. At least 2 days of reportable data are required to qualify a monthly average. This is intended to address situations in which the plant is operating sporadically. Note that only one occurrence of aborted operation is allowed per day and no more than the specified number of hours of reportable data can be excluded from the daily average. These aborted run provisions are based on historic BAT considerations and can be considered to be other than normal operating conditions with regards to the IED 40. If additional parameters are used to define SU-SD, the specified criteria and the specified threshold values for operational parameters shall additionally be stated in the permit along with a description of the control philosophy. MSUL is included as a safe-guard reporting parameter, e.g., reporting begins when the lean premix burner mode is activated on a gas turbine but, if this does not activate, reporting will always then begin at MSUL. A suitable template for submitting this information is provided in Table 5, noting that a total of three processes or parameters is required (delete those that are not applicable or change to more suitable parameters and add justification). At least two out of three of the selected criteria must be satisfied. One of the three parameters must be an output value defined as either an electricity output for electricity 40 IED Article 14 (1) (f) 16

25 generating plant or as a Thermal Output (heat flow, steam flow or hot water flow) for heat generating plant. Table 5: Alternative SU-SD thresholds Process or Parameter (delete items as applicable ) Electricity generating plant Electrical output (MW) Lean premix combustion mode (-) Shaft speed (rpm) Heat generating plant Thermal Output (MW) Steam or hot water flow rate (kg/s) Fuel flow (kg/s and %MCR) Flue gas O 2 (%) Flue gas temperature ( C) Steam temperature ( C) Steam pressure ( C) Threshold value Value ON Idle speed Justification Required (Fail-safe parameter). Low emissions mode activated. Turbine has started operation. Heat flow or steam flow or hot water flow or fuel flow is required as a Failsafe parameter. Indicates normal combustion conditions have been established. Steam availability. For auxiliary and stand-by boiler plant, the Start-up and Shut-down criteria are similar to electricity generating plant but thermal output thresholds replace the electricity output thresholds. These are defined as fixed percentages of the rated thermal output of the combustion plant 41. The rated thermal output in Table 4 may be defined as a steam flow rate, a hot water flow rate or an energy flow rate depending on i) the units in which the Maximum Continuous Rating is specified and ii) the measured quantities available for reporting purposes. As with electricity generating plant, three processes or parameters may alternatively be used to define normal operation 29. These additional parameters include, for example: fuel flow rate, specified as a percentage of the rated fuel flow capacity; flue gas O 2 content and temperature; heat flow rate; steam or hot water flow rate; steam temperature and pressure 28. Note that certain boilers must remain in a state of readiness for operational purposes, e.g., standby boilers at CHP plant. These units are required to maintain steam or hot water quality by sporadic firing of the boiler burners for short periods; a practice known as banking. Since the purpose of this, unpredictable, firing is to make up heat losses, rather than the production of useful heat, then banking shall not be counted as normal operation for regulatory purposes, instead being regarded as part of the Start-Up process. Conversely, the production of useful stored heat for hot water accumulators, for example, shall be regarded as normal operation for regulatory purposes, in line with the EU Implementing Decision Malfunction or Breakdown of Abatement Equipment Definitions Operators of Large Combustion Plant (LCP) are required under the IED to meet certain conditions regarding the Malfunction or Breakdown of the abatement equipment. These provisions are required to be included in LCP permits by every Member State SU-SD Implementing Rules Article 7 42 IED Article 37 (1) 17

26 This section outlines the various requirements when dealing with these conditions, based on a previous protocol applying during the period from 1 January 2008 to 1 January 2016 [15]. In particular it defines Breakdown, Malfunction, and Unabated Operation. These provisions apply to all plant under the IED, including those with TNP, LLD and 1,500h derogations but not emergency plant operating for less than 500h per annum 21. The provisions apply to each pollutant individually. The provisions laid down in this section apply when the LCP fails to comply with the daily Emission Limit Value across the stack due to the Malfunction or Breakdown of part or all of the abatement equipment. For multi-unit LCP and in keeping with the definition of an LCP, the provisions are determined on a stack basis rather than for individual units. It allows some inherent flexibility to offset a modest Malfunction in the abatement equipment for one unit by compensatory measures on other flue gas streams exiting the same stack. The provisions apply to all abatement equipment fitted on LCP for SO 2 (mainly by limestone/gypsum or seawater process FGD), NO x (SCR and SNCR) and dust (ESPs and FGD). An outline of the types of abatement equipment that are included in/excluded from these arrangements is given in Appendix B. Injecting water or steam into a gas turbine combustion system, in order to reduce flame temperature and hence NO x emissions, is not generally classed as an abatement technique within this protocol. However, since this approach is commonly regarded as an abatement measure, and an external injection system, with an additional fluid stream, is used to accomplish the emissions reduction, the Malfunction and Breakdown provisions for abatement systems, given below, will apply. However, the daily ELV approach potentially restricts these provisions to operation greater than 70% load. For this specific case, Malfunction and Breakdown can optionally be determined by counting and excluding the hours in which the abatement has failed (e.g., steam or water flow rate is below the required level of injection). The term unabated operation refers to the situation when the abatement equipment is not operating because it has broken down. The term Breakdown means that all of the abatement equipment fitted to an LCP has broken down and hence the plant is unabated. This occurs when the LCP would fail to comply with the daily LCP ELV and when all of the operational abated units would fail to meet the daily LCP ELV individually. Breakdown provisions are subject to an annual cap of 120h. The term Malfunction means that part of the abatement equipment fitted to an LCP has broken down and hence the plant is partially abated. This occurs when the LCP would fail to comply with the daily LCP ELV and when at least one of the operational abated units would meet the daily LCP ELV individually. In every other respect, the breakdown provisions apply to periods of Malfunction. Malfunction provisions are subject to an annual cap of 120h Detailed Provisions Malfunction and Breakdown are defined in relation to the daily ELV, as noted above. For plant where the daily ELV is expressed as an annual percentile of daily averages, a daily Concentration Threshold is defined, specifically for the purposes of determining Malfunction or Breakdown, as the daily ELV plus 20%. This Concentration Threshold is then used in place of the daily ELV for the purposes of determining if Malfunction or Breakdown has occurred. For plant that are not subject to daily average ELVs, i.e., those plant <100MW thermal input for which continuous monitoring is not required, then Malfunction and Breakdown provisions will be determined on a site specific basis. 18

27 The start time of the Malfunction or Breakdown is deemed to be 24:00 on the day during which the daily LCP ELV (or the Concentration Threshold) would not be complied with, noting that the Operator needs to take measures to rectify the situation as soon as it is apparent that the daily ELV would be exceeded. In particular, action should be taken as soon as it is apparent that it will not be possible to rectify a persistent problem before the end of the day. However, the defined start time determines the timing of the notification to the Competent Authority (within 48h) and the timing of: return to normal operation; reduced operation; closure or firing of low sulphur fuels (within 24 hours) 43. Note that subsequent operation on low sulphur fuel that would give rise to further potential daily ELV exceedances is also counted as a period of Malfunction or Breakdown. The IED requires that periods of Malfunction and Breakdown are excluded from the reportable concentration averages for the purposes of compliance with ELVs 20, as described in Section 6.5. Malfunction or Breakdown data are therefore removed by ranking the hourly LCP concentration averages and removing the highest values until the daily LCP ELV is complied with. The number of hours of Malfunction or Breakdown equals the number of hours of excluded data. Breakdown hours are reported monthly against an annual Breakdown cap defined as 120h (5 days) within a 12 month rolling period. Malfunction hours are also reported monthly against an annual Malfunction cap defined as 120h within a 12 month rolling period. The first 12 month period, commencing 1 January 2016, is fixed until a true rolling average can be established. This rolling average is then updated and reported on a monthly basis. Figure 3 is a schematic illustration of a Malfunction or Breakdown occurrence that shows a scenario in which an initial problem is rectified but then reoccurs later in the day, leading to a potential exceedance of the daily ELV. The exclusion of 8 hours of emissions data ensures compliance, in this example, and this number of hours is removed from the relevant 120h annual cap. Figure 3: Schematic illustration of Malfunction and Breakdown 43 IED Article 37 (2) 19

28 The excluded Malfunction or Breakdown data are to be provided to the Competent Authority separately as soon as reasonably possible, and within 10 calendar days, along with a basic air quality risk assessment to indicate the severity of any impacts. This may be based on previous dispersion modelling studies. A suitable form for reporting excluded hourly concentrations and a template for an air quality risk assessment are provided in Appendix D. Note that operation on low sulphur fuel continues to be subject to these provisions if compliance with the daily ELV cannot be achieved. That is, the Malfunction or Breakdown data continues to be excluded and the breakdown hours continue to increase. Note that all concentration data during periods of Malfunction or Breakdown, without exclusion, are used for calculating the total mass emissions release Legal Basis Article 37 of the IED requires that the LCP permit issued by the Competent Authority should contain procedures relating to the Malfunction or Breakdown of the abatement equipment 42 although this may be by reference to the national regulations related to IED permitting 44. In the case of Breakdown these must require that the operator: reduces or closes down operations if a return to normal operations is not achieved within 24 hours; or to operate the plant using low polluting fuels. This requirement is also linked to Malfunction of the abatement equipment in the Recital 45. The Operator must notify the Competent Authority within 48 hours after the Malfunction or Breakdown of the abatement equipment. The cumulative duration of unabated operation in any 12-month period must not exceed 120 hours. The Competent Authority may grant a derogation to the time limits of 24 and 120 hours in one of the following cases: there is an overriding need to maintain energy supplies; or the combustion plant with the Breakdown would be replaced for a limited period by another plant, which would cause an overall increase in emissions Implementation The Malfunction and Breakdown conditions shall be enforced for all LCP from 1 January Therefore conditions will be included in the permit by reference to the IED requirements, or as given in Section below, or as subsequently modified by the Competent Authority in response to, for example, public consultation on the permit conditions. It will be for the Competent Authority to define an overriding need to maintain energy supplies, i.e., the Environment Agency in England; the Scottish Environment Protection Agency in Scotland, Natural Resources Wales in Wales and the Northern Ireland Environment Agency in Northern Ireland. For LCP fitted with FGD based on limestone gypsum or sea water scrubbing, biomass or coal with an average as-received sulphur content of less than 0.4% by mass 46, are considered low polluting fuels for the purposes of the 24-hour criterion. Compliance is demonstrated by means 44 In Scotland the PPC Regulations 2012 have automatically inserted provisions in relation to Malfunction and Breakdown. 45 IED Recital (33) with reference to Article For Aberthaw Power Station, due to restrictions imposed by the firing technology, coal with an average as-received sulphur content of less than 0.5% by mass shall be considered a low sulphur fuel for the purposes of the 24h criterion. 20

29 of directly sampling either the stock of low sulphur fuel, or the fuel as it is sent to stock, in order to obtain the mass weighted average sulphur content for comparison with the low sulphur fuel requirement. For situations in which a plant with a breakdown of the abatement equipment would be replaced by other plant causing an overall increase in emissions, this would only be considered for breakdowns of limestone-gypsum or seawater scrubbing FGD and/or SCR. A written detailed case would have to be made to the Head of Industry Regulation at the Competent Authority (the Director of Operations at SEPA or the Director of Operations North or South at NRW), based on the situation in the electricity generating market at the time. (Normally via the site inspector but out-of-hours contact can be made through the Incident Hotline for England, Scotland and Wales) Permit Conditions From 1 January 2016, the following Permit conditions are applicable to large combustion plant within a given administration, at the discretion of the Competent Authority 44, where there is a Malfunction or Breakdown of any abatement equipment: 1. The operator shall, unless notification of a breach of an emission limit value has already been made, notify the Competent Authority within 48 hours of any such Malfunction or Breakdown. 2. In the case of a Malfunction or Breakdown and unless otherwise agreed in writing by the Competent Authority: (a) (b) (c) if a return to normal operation is not achieved within 24 hours, the operator shall reduce or close down operations, or shall operate the plant using low polluting fuels; and the cumulative duration of Breakdown in any twelve-month period shall not exceed 120 hours the cumulative duration of Malfunction in any twelve-month period shall not exceed 120 hours. 3. The emission values measured during periods referred to in points 1 and 2 above shall be disregarded for compliance purposes. 4 MONITORING REQUIREMENTS 4.1 When to Monitor General Requirements The IED generally requires that CEMS are installed on plant larger than 100MW thermal input 47 and these must be validated and maintained within the framework of CEN Quality Assurance standards 48. Reporting must be based on continuous monitoring, during normal operation (excluding Start-up and Shut-down). Emission Limit Values (ELVs) are generally applied to individual gas turbine stacks and to common stacks for utility boilers which may contain multiple flues that are monitored individually (Section 3.2). As noted previously, the following 47 IED Annex V Part 3(1) 48 IED Annex V Part 3(5)&(8) 21

30 arrangements, including those applicable to auxiliary boilers, apply to the Electricity Supply Industry only. As a general rule, when it is difficult to schedule monitoring activities due to infrequent or unpredictable operation, the Operator should aim to test annually as opportunity allows, e.g., when the plant is run-up to perform safety checks. Whilst it is not best practice to start a plant simply in order to either prove a continuous monitoring system or to perform periodic monitoring, the required testing must at least be undertaken after 4380 hours (six months) of operation or every two years, whichever is sooner, unless otherwise agreed in writing with the Competent Authority. This satisfies the IED requirement for periodic monitoring every six months unless alternative procedures are agreed by the Competent Authority. In the case of plant that are required to report emissions by calculation, every 4380h, using an emission factor approach, this requirement is also satisfied by submitting a return every six (calendar) months. Faults causing emissions above the ELV are reportable in accordance with permit notification conditions. Plant with emissions above the ELV require intervention as soon as the fault is identified. The approach to monitoring compliance shall be documented in the plant management system Reduced Life-time Plant The IED allows the Competent Authority to grant derogations from continuous monitoring for plant with lifetimes less than 10,000h 49. Where an operator considers this situation as applicable to their own combustion plant, the Operator shall therefore nominate the plant to the Competent Authority. The monitoring shall be fit for purpose, so that a plant that expected to run at, or close to, full capacity over a sustained period at the beginning of the 10,000h would be required to continue monitoring continuously. A plant that is expected to run sporadically for its remaining lifetime would be permitted to make use of this derogation. The requirement to then perform six-monthly discontinuous measurements 50 is difficult to fulfil for plant operating sporadically, for reasons of cost and practicality, related to the timing of plant operations and the inappropriateness of operating the plant for the sole purpose of testing although, if it is possible to schedule testing within planned operations, the opportunity shall be taken. However, periodic monitoring must at least be undertaken after 4380 hours (six months 50 ) of operation or every two years, whichever is sooner, unless otherwise agreed in writing with the Competent Authority. Alternatives to continuous monitoring, in this situation, are specified 51. In the case of utility boilers, an emission factor approach shall be adopted: SO 2 emissions derived from average fuel sulphur content for the reporting period; NO x emissions based on historic data; dust emissions based on continuous indicative monitoring using a historic calibration. In the case of natural gas fired plant that are subject to this derogation, the Operator will report using emission factors and will use indicative process measurements to verify that the CO emissions remain below the applicable ELV, as an alternative to six monthly periodic measurements using an accredited Test Laboratory. The results will be held on site for inspection. An emission factor approach will be used for NO x reporting based on historic emissions data. 49 IED Annex V Part 3(2)(a) 50 IED Annex V Part 3(3) 51 IED Annex V Part 3(5) 22

31 4.1.3 Low Load Factor Plant In the case of low utilisation plant, with installed CEMs, the calibration requirements for the CEMs are particularly onerous and difficult to achieve, for reasons of cost and practicality. It is inappropriate to operate the plant for the sole purpose of calibrating the CEMs. Hence, the QA requirements shall be deferred until the plant is scheduled to operate at a higher load factor (> 500h per year) and such that at least three hours of operation per day can be scheduled in advance for stack testing. Functional tests shall be performed annually (Section 5.2.3). As noted above, periodic monitoring must at least be undertaken after 4380 hours (six months 50 ) of operation or every two years, whichever is sooner, unless otherwise agreed in writing with the Competent Authority Gas Turbines for Emergency Use ELV compliance is not required for gas turbines for emergency use that operate for less than 500 hours per year 21. By agreement with the Competent Authorities, this definition incorporates all gas turbines operating for less than 500 hours per year including black-start gas turbines at solid fuel fired power stations. For these plant, the total period of operation, associated with <500h per annum operation, is expected to be less than 10,000h and so routine monitoring is not required 49. Formal notification of 10,000h status is not required but the annual and cumulative operating hours shall be reported. In the eventuality of extended operation, beyond 10,000h total operation, due to unforeseen circumstances, the Operator shall review the need for continuous monitoring with the Competent Authority. Reporting is based on an emission factor approach, as a preference, using data collected for guarantee test purposes or a specific emissions measurement campaign, for example. Alternatively, emissions data from the gas turbine manufacturer can be used with sufficient justification Bypass Stacks on Gas Turbine Plant Depending on a CCGT plant design, there may be a bypass stack that is used on Start-up. When installed, bypass operation is required during Start-up, Shut-down and gas turbine optimisation (tuning) exercises. These tuning activities are not regarded as normal operation for reporting and compliance purposes. Monitoring of the bypass stack shall not be required unless the plant operates commercially in open cycle mode, since this complicates the emissions sampling arrangements and potentially reduces monitoring availability. It is also often impractical to apply full QA checks to CEMs in this mode of operation but functional tests shall be performed if instruments are installed on the bypass stack. However, it should be noted that monitoring in the gas turbine exhaust duct covers all plant operational modes Auxiliary Boilers Monitoring shall not be required for stand-alone auxiliary boilers that operate only during Start-up and Shut-down of the main plant. Monitoring shall not be required for auxiliary boilers <50MW thermal input that raise steam for auxiliary plant consumption, e.g., for gland sealing. Routine monitoring shall not be required for auxiliary plant that aggregate to form part of an LCP and that operate intermittently such that their total operation is expected to be less than 10,000h 49. For these plant, formal notification of 10,000h status is required, for boilers with a 23

32 thermal input greater than 100MW, and the annual and cumulative operating hours shall, in any case, be reported. In the eventuality of extended operation, beyond 10,000h total operation, due to unforeseen circumstances, the Operator shall review the need for continuous monitoring with the Competent Authority. Compliance with the relevant BAT/IED ELVs shall be demonstrated using either an emission factor approach, as a preference, or data from the boiler manufacturer with sufficient justification. Otherwise, periodic monitoring shall be required for auxiliary boilers in the range 50 to 100MW thermal input and continuous monitoring above 100MW thermal input. Auxiliary package boilers at CHP plant, that are operated to provide a back-up steam capability, shall not be required to monitor continuously even if they are individually LCP or part of an LCP aggregating to above 100MW thermal input. Routine monitoring shall not be required for these auxiliary plant that operate intermittently such that their total operation is expected to be less than 10,000h 49. For these plant, formal notification of 10,000h status is required, for boilers with a thermal input greater than 100MW, and the annual and cumulative operating hours shall, in any case, be reported. In the eventuality of extended operation, beyond 10,000h total operation, due to unforeseen circumstances, the Operator shall review the need for continuous monitoring with the Competent Authority. This type of auxiliary boiler is intended to cover the main steam raising duty during gas turbine outages only, typically for less than 100 hours per year, or during a gas turbine breakdown. Reporting and compliance with the relevant BAT/IED ELV shall be demonstrated using emissions factors derived from either historic data obtained by an accredited Test Laboratory or from the boiler manufacturer. In the eventuality of extended operation, beyond 500h per annum, due to unforeseen circumstances, the Operator shall measure and report NO x and CO on a monthly basis, using an instrument with a suitable MCERTS certification, for the duration of the outage CEM Availability The IED requires that any calendar day in which more than three hourly average values are lost, during normal operation, due to Malfunction or maintenance of the CEMs, shall be invalidated 52 and shall not be considered with regards to ELV compliance. If this occurs for more than ten days within a calendar year, for a given CEM or the whole system, this shall therefore be reported to the Competent Authority, when the ten day limit is exceeded, so that an action plan to improve the reliability of the CEMs can be agreed 52. However, even when a full day is counted towards the total CEM unavailability, the remaining good data within that day shall be reported in order to maintain overall data capture rates. The above requirement is equivalent to a minimum daily availability of 97.3%. The Operator should investigate and rectify faults after every failure, especially where this results in a missing short-term daily average. It is good practice to inform the Competent Authority of a persistent CEM failure of longer than 3 consecutive invalidated days and the measures in progress to deal with it. A CEM result is invalidated if it cannot deliver a reportable value for compliance purposes. This may result, for example, from the breakdown of an analyser component or a fault in the data acquisition system (if the data cannot be retrieved from a back-up system). A less serious Malfunction of the CEM, in which the system is not performing according to its design specification, should be discussed with the Competent Authority in order to determine if i) 52 IED Annex V Part 3(10) Para.2 24

33 corrections to reportable data are required (where possible) and ii) if further invalidation periods need to be declared. Regular zero and span checks required by QA standards can normally be completed in less than 20 minutes within a given hour. Up to 40 minutes duration can be accommodated by starting the checking sequence in the final 20 minutes of a given hour and completing the sequence within the first 20 minutes of the following hour. CEM data capture is therefore normally unaffected. However, mandatory functional tests associated with the QA process will not count towards the 10 days availability allowance. Discretionary performance checks must never be undertaken in more than 5 operating hours in any one 24h period or more than one quarter of the overall valid hours when operating for less than 24 hours, subject to the over-arching constraints of the IED, described above. If the CEM characteristics are such that the above guidelines cannot be applied exactly then changes to these arrangements shall be agreed with the Local Inspector. Discretionary checks include QA checks and maintenance actions which should be spread out as much as possible to preserve data availability. 4.2 What to Monitor Compliance Species Nitrogen Oxides (NO x ) NO x is measured continuously at all large combustion plant. NO x is defined as the sum of the two oxides of nitrogen commonly found in combustion products, that is, nitrogen monoxide (nitric oxide) and nitrogen dioxide (NO + NO 2 ). NO x is always reported as mg/m 3 of NO 2 equivalent. Further reference to NO assumes that it is always expressed as NO 2 equivalent. The individual components can be measured and summed to obtain the total NO x or a converter can be used to convert NO 2 to NO, prior to the total NO x being measured directly as NO. For utility boilers, the NO 2 content is low and can be, optionally, taken into account using a correction factor applied to the measured NO concentration (Section 6.2). Sulphur Dioxide (SO 2 ) SO 2 is measured continuously at solid fuel fired plant. However, this may not be required at biomass fired plant provided that the sulphur content of the fuel is always low enough to prevent a breach of the ELV 53, not taking into account inherent or additional abatement. Compliance may then be demonstrated by fuel sulphur determination, rather than periodic flue gas monitoring, based on at least a monthly composite fuel sample (noting that 0.01% sulphur by mass, as received 33 mg/m 3 SO 2 at 6% O 2 dry). Such an approach must be agreed with the Competent Authority so that the methodology for maintaining a sufficiently low fuel sulphur content can be assessed. SO 2 emissions from natural gas firing 54 shall be reported on the basis of the fuel sulphur content [9] without continuous or periodic monitoring 51 since only trace quantities of sulphur are present in UK natural gas (Section 3.3.2). 53 IED Annex V Part 3(2)(d) 54 IED Annex V Part 3(2)(b) 25

34 SO 2 emissions from oil firing 55 shall be reported on the basis of the fuel sulphur content [9] without continuous or periodic monitoring 51 since the fuel sulphur content shows little variation and is controlled by regulation [11][12]. Dust Dust is measured continuously at large solid fuel fired plant. Dust is generally monitored continuously at large liquid fuel fired plant. However, in the case of liquid back-up fuel at gas fired plant, for either the gas turbine or for auxiliary and supplementary firing of the HRSG, continuous monitoring is not required, for such back-up periods, provided that the instances of fuel oil firing, due to gas supply interruption, are no more than 10 days 6. Dust emissions from liquid fuel firing shall then be reported on the basis of emission factors [9] without continuous or periodic monitoring. Dust emissions from natural gas firing 56 shall be reported on the basis of emission factors [9] without continuous or periodic monitoring 51. Natural gas is an ash-free fuel and high efficiency combustion does not generate additional particulate matter. The fuel gas is always filtered and, in the case of gas turbines, the inlet air is also filtered resulting in a lower dust concentration in the flue than in the surrounding air. Carbon Monoxide (CO) Continuous CO monitoring is required for all gas fired plant with > 100MW thermal input under the IED 47. This shall not apply in cases where ELV compliance is not required, e.g., gas turbines for emergency use that operate for less than 500h per year. Continuous monitoring may also not be required for plant with a declared limited life-time of less than 10,000h (Section 4) Peripherals Peripheral measurements are required in order to correct measured concentrations to the reporting reference conditions for the process 57. Oxygen measurement is always required 57 and this is the only parameter needed to correct gaseous emissions that are measured on a dry basis, normally the case at gas turbine plant. Stack temperature and absolute pressure measurement are required by the IED 57. However, since these parameters are only needed for dust emissions correction, they shall only be required in these circumstances. Water vapour concentration measurement is mandatory when measuring gas concentrations on a wet basis 57. Continuous dust monitoring is always on a wet basis but, if the moisture is not measured for the gas species, it shall be acceptable to calculate the moisture content as specified in Section 6.3.2, provided that the calculated values are checked by the Test Laboratory. Periodic dust monitoring is based on a collected mass of dust associated with a dry gas volume which then needs to be corrected to the same duct conditions as the continuous measurement. It should be noted that the oxygen correction factor is much more significant 55 IED Annex V Part 3(2)(c) 56 IED Annex V Part 3(2)(b) 57 IED Annex V Part 3(7) 26

35 than the water vapour correction, especially at the high O 2 levels typical of gas turbine operation Flue Gas Flow Rate Mass emissions reporting is required for inventory purposes [9] and for compliance purposes for plant within the Transitional National Plan. A calculated stack gas flow rate, based on fuel consumption, is normally used to calculate the mass release from the measured emission concentration [9]. The calculation shall be performed using the methodology defined in EN ISO Part 1 (Annex E), as described in Section 6.6, and verified using the manual reference methods described in Part 1 of the standard using the approach defined in Part 2 of the standard. 4.3 Where to Monitor General Guidance The requirement to extract samples from locations that are positioned so that they accurately represent the system as a whole is central to good monitoring practice. Technical Guidance Note M1 (TGN M1) [16] considers the location of CEMs in relation to flow disturbances, such as bends and branches. Guidance is based on EN 15259, noting that the IED requires the use of CEN standards 58 and the Competent Authority is required to determine the sampling location 59. CEMs should ideally be installed with at least five straight pipe hydraulic diameters upstream and at least two diameters of straight pipe downstream of the CEM (rising to five downstream diameters when the disturbance is the chimney exit). It is not always possible to meet these recommendations, even at new gas turbine plant as noted below, in which case every effort is required to meet the specified flow criteria at the sampling plane. It should be noted that the layout of pre-existing ductwork on ageing power plant often prevents compliance with the recommendation to locate sampling points and planes at a specified separation distance from flow disturbances (e.g., bends, support struts and diffusers). The Operator shall identify non-compliances and agree these with the Competent Authority. Similarly, it may not be possible to meet the general requirement, on existing plant, that the SRM should be located within three hydraulic diameters of the CEM [17], bearing in mind that the two systems must not be so close as to interfere with one another and the restrictions imposed by large diameter ducts and platform availability. TGN M1 [16] simply states that, where possible, the CEM and sampling port should be in close proximity. TGN M20 [18] states that the CEM location should be representative and the CEM and manual sampling ports should not interfere. In any case, the suitability of a given location is now assessed by means of a flow survey, for dust and flue gas flow rate measurements, and a concentration survey for gas components on all large combustion plant. This is a one-off homogeneity test, required under EN 15259, provided that there are no changes to the plant that could cause a change in the distributions. A traverse is undertaken, at specified sample point locations, and the results are compared with those from a fixed reference probe. 58 IED Annex V Part 3(8) 59 IED Article 38(3) 27

36 The relevant standards highlight safety issues associated with undertaking extractive testing on operating plant. Power plant sites operate comprehensive personnel safety and permit systems, which the test personnel must understand and follow. Under Health and Safety Regulations a full risk assessment must be carried out before testing work is carried out. This assessment will include consideration of safe access and that adequate numbers of properly trained staff are employed. In situations where external platforms are required, various standards and guidance documents provide detailed guidelines concerning platform dimensioning, the provision of hand-rails and access to the platform. Further information is available in TGN M1 [16] and the Risk Assessment Guide provided by the Source Testing Association [19] and the relevant standards and legislation upon which these are based, e.g., EN and the Working at Heights Regulations Duct Surveys The determination of the degree of homogeneity at a given monitoring location, and the most representative sampling point for a CEM at a new plant, is prescribed by BS EN 15259:2007 [20], the application of which is clarified by Method Implementation Document MID EN [21]. It is recognised that it is not always possible for existing plant to fully comply with the requirements, in which case best endeavours are required, as discussed below. Note that the MID places a responsibility on the Test Laboratory to inform the Operator that the EN testing is required. It is then the Operator s responsibility to commission the testing. The Operator is obliged to provide a copy of the latest platform inspection report and a copy of the Permit to the Test Laboratory. The EN standard requires that a homogeneity test is performed at the sampling location; taking grid measurements of concentration within the duct whilst simultaneously sampling with a fixed probe. The measurement of gas velocity and temperature, in order to determine a flowweighted concentration for the SRM, is not required unless the testing is being conducted to determine the best location of a new gas CEM, not yet installed, or for a dust or flow measurement. Generally, homogeneity tests are not required for ducts with an area of <1.0m 2 [21]. By applying statistical tests it can be demonstrated that the sample plane is homogeneous. That is, there is little stratification and sampling will be representative. If the duct is homogeneous, then sampling from any point is satisfactory for the continuous monitoring. If there is moderate stratification, a single specified point (determined by the standard) may be used, provided that the uncertainty associated with the stratification is less than half of the confidence interval defined in the IED: (half of 20% of ELV for SO 2 and NO x, 10% of ELV for CO and O 2, noting that an ELV for O 2 is defined later (Section 5). It should be noted that the best sampling point for CEMs identified by this procedure may not be acceptable for reasons of practicality. For example, the procedure may identify a point in one corner of a rectangular duct that is difficult to instrument and provides very little benefit if the distribution is fairly uniform. Similarly, the procedure may result in different monitoring points being selected for different gas species, when only a single probe is to be installed. In situations where the standard does not give a practicable determination of the best sampling location, the Operator will need to demonstrate that the chosen solution gives a representative sampling location to the satisfaction of the Competent Authority. 28

37 For utility boilers, the survey is required for NO (or NO x ), SO 2 and O 2. For gas turbine plant, the survey is required for total NO x (since the NO 2 content is above 10%), CO and O 2. The duct survey is not required if the concentration of the species of interest is less than 30% of ELV [21]. At very low concentrations, small absolute differences can result in a fail of the statistical tests which are then regarded as not statistically meaningful. This is normally the case for CO during gas turbine base load operation. However, it is recommended here that CO is included in the test, to demonstrate the low concentration levels and their uniformity, whilst any subsequent failure of EN is classed as not statistically significant by the Test Laboratory. Similarly, very stable readings from both the traverse and reference probes can lead to a failure of the statistical tests. In these circumstances, it shall be sufficient to demonstrate that all of the traverse concentrations are within 5% of the average concentration. If stratification is significant, when judged against the required criteria, permanent grid sampling is required for the CEM, e.g., a gas sample rake installed in a gas turbine exhaust duct. In these circumstances, a velocity survey is also required, meeting the additional criteria specified in EN Monitoring Location New Plant In normal circumstances, it is expected that a single measurement point is suitable on a new power plant flue, following the general guidelines described earlier, and the monitoring location should conform to all of the recommendations and provisions of EN A fully compliant sample platform can be used for both concentration measurement and flow measurement using any flow reference method. However, HRSG flues at gas turbine plant are typically 7 to 9m diameter on large plant and the flues are squat, due to overall design constraints (the base of the flue is situated at the top of the HRSG and is already elevated). It is often not practical, from a health and safety perspective, to work to the general guidelines but this is not a problem since the gaseous components are usually well mixed in the stack. In these circumstances, it is recommended that the monitoring location meets at least the EN homogeneity requirements and there is sufficient access to perform the required concentration survey at, for example, the base of the stack. The location must therefore be clear of flow straighteners or rain dampers that might restrict probe access. Provided that the Operator is only required to measure gas concentrations, and the location is demonstrated to be homogeneous for gases, simpler monitoring arrangements are acceptable (Section 6 of TGN M1 [16]). Besides the cost savings that can be achieved, it is also much better for monitoring personnel to be able to work from ground level. Flue gas flow rate verification can be undertaken using tracer injection methods or a 20 point velocity traverse (if the chosen sampling plane allows for a meaningful velocity average to be determined, noting that it is not necessary for the flow criteria specified in EN to be fully satisfied provided that a suitable velocity reference method is used and there is neither flow recirculation nor very localised effects caused by struts and dampers). This provision is based upon the validation studies associated with EN ISO [22]; Annex G notes that representative bulk velocity averages were obtained from non-uniform velocity profiles. For a circular flue, four manual sampling ports must be installed at a 90 spacing for the duct survey and an additional port for the reference measurement. For large CCGT flues, since this is normally a one-off test, it may not be practical, cost-effective, or aesthetically acceptable, to 29

38 build fully compliant sampling platforms that are wide enough to accommodate the length of probes that are required to conduct the duct survey. This can be addressed by constructing a narrower platform and then using sectional probes that can be extended as they are inserted into the stack, provided that these are leak checked in accordance with the relevant standards. An alternative for CCGT plant, particularly if significant open cycle operation is anticipated, is to install a multi-point sampling rake in the gas turbine exhaust, upstream of the bypass damper (if installed). This must meet the requirements of EN for large ducts, i.e., at least twenty sample points at centres of equal area. The rake must be capable of withstanding the high exhaust temperature of 500 to 600 C, noting that the duct is at a positive gauge pressure. A full array of test ports is then not required since an EN15259 sampling arrangement is already installed. However, a single test port for an independent reference measurement must be provided. For subsequent QAL2 and AST testing the Test Laboratory may take their representative sample from the permanent sampling rake. The turbine exhaust location is not an option if there is supplementary or auxiliary firing of the HRSG. During normal operation, the gases in the turbine exhaust are, in any case, expected to be homogeneous since: a) the fuel is gaseous and is well mixed with air prior to, or during, combustion; b) the firing system is optimised to give uniform combustion conditions (for low emissions performance) and uniform outlet temperature profiles (to maintain turbine blade integrity); c) the gases pass from the combustor through multiple turbine stages rotating at high speed (corresponding to a shaft speed of 3000 rpm). Existing Plant A fully compliant sample platform can always be used for both concentration measurement and flow verification measurements using any flow reference method. For a location that is not fully compliant for flow, flue gas flow rate verification can be undertaken using tracer injection methods, or a 20 point velocity traverse, if the chosen sampling plane allows for a meaningful velocity average to be determined. It is not essential for the flow criteria specified in EN to be fully satisfied provided that a suitable velocity reference method is used and there is neither flow recirculation nor very localised effects caused by struts and dampers). This provision is based upon the validation studies associated with EN ISO [22]; Annex G notes that representative bulk velocity averages were obtained from non-uniform velocity profiles. If the existing access platform is too narrow to accommodate the required survey probe length, sectional sampling probes can be employed. If platform access extends around the flue, and there are insufficient sample ports, new test ports shall be fitted to ensure full compliance. Otherwise, the survey may be limited to two sampling radii at 90, or a single full diameter, provided that at least 20 sample points are defined. If testing can only be undertaken at a location upstream of the flue; demonstrating homogeneity, and the feasibility of flow measurements, requires a site specific assessment based on the technical and economic feasibility and best endeavours. If it is impractical to conduct a full duct survey at the CEM location then reference sampling in the flue, or at the nearest accessible location, in the case of a shared stack, may be the only available alternative to demonstrate representativeness. However, it must be confirmed that the reference location is, itself, representative of the mean concentration for both gas components and dust measurement, as appropriate. Provided that the stratification does not change between ASTs, the QAL2 can be used to correct for non-uniformity, assuming that the SRM receives a representative sample. 30

39 If it is not possible to conduct a meaningful duct survey or the survey indicates that grid sampling is required due to stratification, but it is impractical to relocate the existing CEM or to install a grid sampling system, due to Health & Safety considerations or restricted access, for example, the Operator shall consider alternative solutions with the Competent Authority. For example, the use of a downstream non-compliant test location that is expected to be homogeneous or the use of an historic stratification factor obtained from temporary platforms (not easily repeatable at reasonable cost). 4.4 How to Monitor Monitoring Methods Environment Agency Technical Guidance Note M2 [23] lists the options for continuous emissions monitoring of gases and dust. In-situ probes, to obtain a wet gas measurement, or extractive sampling systems with various approaches to sample drying, are used for gas concentrations at utility boiler plant. Both SO 2 and NO 2 are partially soluble, so the water removal mechanism must therefore minimise the loss of these gases. Infra-red techniques are generally sufficient. However, the lower NO x concentrations at gas turbine plant often require UV or chemiluminescence detectors. For gas turbines, total NO x must be measured since the NO 2 content of the overall NO x emission is typically 20% of total NO x, as noted above. NO 2 is a very reactive and soluble gas component, so great care needs to be taken with sample transport and handling. Above 250 C, stainless-steel and other metal alloys cause conversion of NO 2 to NO. The total NO x remains constant but the NO 2 /NO x ratio can be reduced. This should be remembered when sampling from gas turbine exhausts (circa 500 C) using metal probes since the NO 2 /NO x split may be affected without altering the total NO x measurement. Comparisons must therefore be based on total NO x. For dust measurement, in-situ, cross-duct opacity meters, in-situ light scatter probes and extractive light scatter systems are used within the power industry. Opacity meters have been used for many years for monitoring particulate emissions from plant without FGD units. Under most circumstances the instruments give a reasonably accurate indication of the particulate emissions but they are particularly sensitive to dust particles of less than 10µm diameter. A correlation must therefore be established between the gravimetric dust burden and the opacity reading. To obtain a gravimetric dust sample, isokinetic samples are drawn from multiple points across the stack cross-section and the particulate matter is collected on a filter within the probe body. The gas flow rate, drawn through the probe, is measured across the test duration, so that the dust concentration, in mg/m 3, can be calculated. Although there are circumstances under which this correlation is not consistent, due to variable particle size, the opacity meter remains the most effective device available for power stations not fitted with FGD. Availability of these types of instrument is very good with operators reporting better than 99% (excluding outages for planned maintenance and calibration). Light scatter devices are generally required for measuring the lower dust burden levels produced by utility boilers fitted with FGD and for auxiliary oil firing. Extractive heated scatter devices are usually employed for wet stacks to prevent cross-interference from liquid droplets. Since the particle size is small, scattering occurs in multiple directions and either forward-scatter or back-scatter devices can be used for FGD applications. Low range opacity meters installed in ducts with large path lengths may also have a sufficiently low detection limit. Light scatter 31

40 instruments are also somewhat sensitive to dust particle size but the dust characteristics downstream of FGD absorbers are very stable Quality Assurance The IED, in common with a number of other European Directives, specifies a hierarchy of standards that must be adhered to in order of priority: CEN Standards > ISO Standards > National Standards. The main QA standards of relevance to power plant are BS EN 14181:2014 [17] and an additional standard for the gravimetric calibration of dust monitors where appropriate (BS EN 13284:2 [24]). Further guidance on the implementation of these QA standards is provided by the Competent Authorities, for example, [18][25][26] *. In short, EN14181 defines three Quality Assurance Levels - QAL1, QAL2 and QAL3 and an Annual Surveillance Test (AST). The basic structure of the QA process is shown in Figure 4. Figure 4: Quality Assurance requirements The Operator has the following general responsibilities: Installation of compliant equipment (QAL1) In-situ validation/calibration using an accredited test laboratory (QAL2) Annual check of the validation using an accredited test laboratory (AST) Performing ongoing zero and span checks (QAL3) Submission of QAL2 and AST reports and ongoing maintenance of records Checking of hourly averages against the valid calibration range (weekly). Permit requirements for the keeping of records shall be complied with. In general terms, detailed records should be maintained for at least 6 years, as required by the Permit, or the period between successive QAL2s (whichever is longer). QAL2, AST and QAL3 audit reports should be held for the lifetime of the plant. It should be noted that the site permit may specify the minimum length of time that operators have to keep records, which would include the above reports. * This guidance, including the contents of Quick Guides, has recently been consolidated into a single guidance document (TGN M20). 32

41 The EN14181 evaluation of a CEM system is based on the ELV for each measured component, noting that the Operator is required to provide a copy of the Permit to the Test Laboratory. QAL1 requires an assessment of the suitability of the CEM equipment. New analysers must be certified, with a suitable certification range, under the Competent Authority s certification scheme, e.g., MCERTS. However, these schemes now comply with a common European standard, EN ([27] to [29]), so an instrument with an alternative certification may be acceptable to the Competent Authority. It is recommended that the certification field trials have been carried out on a similar combustion process with similar abatement systems. The monitoring equipment must also be placed so that a representative reading can be obtained. QAL2 requires calibration of the monitors against analytical methods - standard reference methods (SRMs) - applied by a Test Laboratory accredited to ISO for both EN testing and the specified SRMs. Note that the QAL2 calibration should not be confused with the process by which the analysers are occasionally adjusted using a reference material - a span gas or an optical or gas-filled filter equivalent to a known concentration. The straight line relationship established between the CEM and the SRM test data is obtained by taking at least 15 pairs of measurements obtained across at least 3 days of operation. Any scatter in the data comparison is assumed to be caused by the plant monitor and this scatter must be below a specified threshold, related to the required measurement uncertainty, in order to pass. However, there is no requirement to identify and correct the root cause of a difference between the CEM and the SRM. It is good practice to investigate and rectify such differences, if they are considered to be significant, before applying the calibration factor. Prior to a QAL2 calibration, or an AST, various functional tests of the gas analysers must be performed by an experienced testing laboratory that has been recognised by the Competent Authority [17]. The Competent Authority recognises that this may be the Manufacturer, the Test Laboratory, the Operator or any other competent party (audited and preferably witnessed by the Test Laboratory) [18]. Temperature and pressure sensors must be traceable to national standards when these parameters are required for correcting emissions to reportable conditions. The Operator must also perform a weekly check of the reported emissions data to determine if this lies outside of the Valid Calibration Range, established during the test campaign. Since the plant must be operated normally during calibration, the Valid Calibration Range may be extended using reference materials (e.g., span gas readings) in order to prevent a noncompliance that would trigger a costly repeat calibration. QAL2 is intended to take account of any bias caused by the particular monitoring equipment or the sampling location and must be conducted every 5 years or following a significant change to the CEM, the combustion or abatement process or the fuel mix. The statistical tests used in the data analysis take account of the uncertainty requirements, defined in the IED as a 95% confidence interval (20% for NO x and SO 2, 10% for CO and 30% for dust). In the case of CO, a higher confidence interval of 20% can be used for QA purposes. The Competent Authority defines a confidence interval of 10% for O 2 and 30% for H 2 O. Annual Surveillance Tests (ASTs) are intended to validate the calibration established under QAL2 by, again, employing an accredited Test Laboratory to take at least five pairs of measurements across at least one day of normal operation. The tolerance applicable to the data scatter is widened but an additional test compares the mean deviation from the calibration line with a tolerance based on the above uncertainty intervals. Failure of the AST results in a repeat QAL2. 33

42 QAL3 is intended to provide an audited check of ongoing performance by conducting regular zero and span checks of the monitors and comparing the measured drift against pre-defined warning and action limits. The detailed requirements of EN14181 are considered in later sections Auditing The Competent Authority may audit the Operator s monitoring systems. For example, in England, the Environment Agency operates an Operator Monitoring Assessment (OMA) programme. The aim is to identify monitoring shortfalls and potential areas for improvement. Certain elements are considered to be critical to monitoring and are of particular importance: sampling provisions; measurement methods and standards; provisions for monitoring and location of CEMs; and calibration methods [30]. The Operator needs to be able to demonstrate an acceptable level of knowledge and competency in monitoring [31], conducting sample audits of the Test Laboratory s Site Specific Protocol (SSP), their on-site testing and their test reports. The Operator is expected to monitor the trends in the reported data with a view to identifying both deterioration in emissions performance and opportunities for improvement, as evidenced by management meeting minutes, for example. The use of control charts is recommended by the Competent Authority for reviewing emissions data. The Data Acquisition and Handling System (DAHS) used for emissions correction and reporting is also considered. Sampling facilities are a critical element within the OMA programme. The minimum score of 3 for this element can be obtained if it is demonstrated that the monitoring locations are technically the best available and provide representative samples. Based on the above considerations, existing plant with limited access, using the best available sampling ports, may not be able to fully comply with the various standards and guidance documents. In these circumstances, best endeavours will be used to demonstrate that the sampling is representative, e.g., comparison with stack sampling or reference to historic duct survey information, as noted above Outline of Detailed Provisions The remainder of this document describes the detailed implementation of EN14181 and the reporting of emissions concentrations for compliance purposes. Section 5.1 considers the selection, suitability (QAL1) and placement of CEMs. Section 5.2 describes how to define, apply and report the straight line calibration relationship that links the CEM readings to those of the Test Laboratory (QAL2) and how to conduct the required annual check that this relationship continues to hold (AST). Section 5.3 defines a simple control chart approach for monitoring the ongoing performance of the CEMs by means of regular zero and span checks (QAL3) having first considered the requirement for the Operator to check that the reported data lie within the valid calibration range of the CEM on a weekly basis. Reporting to standard reference conditions is considered in Section 6. 5 QUALITY ASSURANCE 5.1 Quality Assurance Level 1 (QAL1) - Fitness for Purpose QAL1 is intended to establish that the CEMs are fit for purpose and operate with a measurement uncertainty within the limits established by the IED. The Emission Limit Value 34

43 (ELV) must be known in order to apply the QA standards. This is generally the daily ELV. The IED confidence interval, evaluated at the daily ELV, is described as the Maximum Permissible Uncertainty in EN14181:2014. For example, a plant with a daily NO x ELV of 100 mg/m 3 would have a MPU of 20 mg/m 3. Table 6 gives illustrative values of daily ELVs for use in subsequent QA assessments, based on typical mandatory IED ELVs discussed in Section 3. The reduction in ELVs under the IED may lead to the certification ranges of existing instruments becoming inadequate. Under these circumstances, if the instruments are not replaced, the Operator shall demonstrate continuing fitness for purpose by passing all of the remaining QA requirements, noting that the statistical tests within the QA process become tighter as the ELV is reduced, i.e., it becomes harder to pass the remaining requirements. In the event that the certification expires, then existing CEMs fitted before a defined date are still considered to be MCERTS certified. The analysers shall be certified under EN [27][28][29]. The concentration range quoted on the certificate shall be less than 2.5*ELV as a minimum, noting that the lower the certified range the better. The required certified ranges are also shown in Table 6 for the IED Annex V example. This calculation must be performed for the actual IED Permit ELVs. Table 6: Emission Limit Values and certification ranges Utility boiler CCGT Component NO x SO 2 Dust NO x CO mg/m 3 mg/m 3 mg/m 3 mg/m 3 mg/m 3 Emission Limit Value (Daily) Required certification range <550 <550 <55 <138 <275 Uncertainty at ELV (mg/m 3 ) MPU Uncertainty (95% confidence) 20% 20% 30% 20% 10% Note: A confidence interval of 20% for CO can be used for QA purposes. Representative ELVs for O 2 and H 2 O, suitable for power plant shall also be required [37]. An ELV of 6% by volume is appropriate for QA purposes, for both O 2 and H 2 O, in power plant, implying a required certification range of 15% and a span value of 12%. The exception is O 2 at gas turbine plant for which an ELV of 10% is appropriate with a certification range of 25% and a span value of 21% (ambient air). Higher certification ranges are acceptable if the instruments pass the required functional tests, and other QA requirements, using the specified ELVs. Note that the declared certification range for O 2 is often 25% and, for H 2 O, 25-40% by volume. For direct NO 2 measurement, it should be noted that the NO 2 concentration, in power plant emissions, is typically less than 10 mg/m 3. A certification range of 25 mg/m 3 is therefore more appropriate, for NO 2 analysers, than the NO x certification ranges given in Table 6. If it is not possible to meet this lower certification requirement, the measurement of NO x, as NO+ NO 2, continues to be acceptable provided that the instrument passes all of the EN14181 requirements for total NO x. For dust measurement, at utility boiler plant, using opacity meters certified in units of optical density (OD), rather than in mg/m 3, the certified range shall be less than 0.05 OD units since it can be demonstrated that this is roughly equivalent to 22 mg/m 3 for power station applications. 35

44 For dust measurement monitors, on HRSGs firing oil as the main fuel, the lowest available certification range (currently 15 mg/m 3 ) shall be selected, noting that it is not practical to mount dust monitors at high temperature gas turbine exhaust locations. For CO measurement, at gas turbine plant, the instrument shall also be capable of measuring peak CO concentrations during Start-up and Shut-down. This may require dual sensors or dual measurement ranges and outputs. However, additional certification ranges shall not be required since these are not normal operating conditions. EN requires that instruments are field trialled during certification and the plant type used for this field trial is quoted on the certificate, e.g., a gas turbine, a waste incinerator or a coal fired boiler. For QAL1 purposes, the installed instrument should have been trialled on a similar process to the application being considered. Particular attention should therefore be paid to the certification field trial and to the manufacturer s reference experience at similar installations. This should include an assessment of the concentration ranges (both NO and NO 2 when measuring separate NO x components) and also the sampling system. For example, probes installed at gas turbine exhaust locations must be able to withstand the maximum expected gas temperature (450 to 650 C depending on the gas turbine model). Certification testing now covers the entire CEM system including the sampling system and this will be specified on the certificate. The sampling system installed with the CEM must not deviate from that certified, though some flexibility is allowed in practice [18]. The certification may incorporate the use of a particular type of NO x converter combined with a given CEM for NO measurement. CEMs specified for natural gas firing are also suitable for dual-fuel firing with gas oil since the SO 2 concentration is always below 200 mg/m 3 when firing gas oil in either the turbine or the HRSG. The SO 2 concentration is therefore always below the lowest range tested for crossinterference during certification. 5.2 Quality Assurance Level 2 (QAL2) In-situ Validation General Requirements QAL2 is intended to establish that the CEMs are working properly when installed at the monitoring location on a specific process plant. This requires calibration of the CEM using data obtained by an accredited Test Laboratory that employs Standard Reference Methods (SRMs) to obtain parallel emission measurements; the SRM test results are plotted against the CEM results as hourly averages of raw (uncorrected) concentration data. The Test Laboratory must be accredited to ISO [32], with appropriate accreditations for the required test methods, and must also be accredited to perform testing to EN The test instruments must also have an appropriate certification as described under QAL1 above. If the Test Laboratory uses a converter for total NO x measurement, it must be demonstrated that the conversion efficiency is greater than 95% in accordance with the CEN standard for the SRM. The statistical tests that assess the acceptability of the data scatter, and the absolute deviation of AST data from the original QAL2 results, are based on the ELVs described under QAL1 above. The Annual Surveillance Test (AST) is performed in order to check the continuing validity of the calibration established under QAL2 and consists of a scaled down test campaign. 36

45 The use of chillers for water removal prior to analysis is not permitted for the NO x SRM when the NO 2 content is higher than 10% [33] and this is the case for gas turbines. However, this does not apply if a converter is used upstream of the chiller since the soluble NO 2 is first converted to the insoluble NO. Alternatively, the Test Laboratory may use a chiller that has been MCERTS certified for a similar process application, noting that a 5% loss of NO 2 in the chiller is equivalent to only 1% loss of total NO x for a typical gas turbine application. The calibration can be implemented within either the plant DCS system and/or external software but it is recommended that the raw CEM output and peripheral measurements are also recorded by the DCS, preferably also with a back-up at the CEM location. Prior to test work commencing, the Test Laboratory must visit the site, survey and agree the monitoring locations and agree the test objectives with the Operator. A measurement plan is then recorded and agreed (the Site Specific Protocol) and this must include: the anticipated plant operating conditions; the time and location of the measurements; the test methods to be used; the measurement sections/sites/measurement points; the test personnel and the reporting arrangements. This process is defined in EN15259 [20] Frequency of Calibration A QAL2 must be conducted at least every 5 years, for large combustion plant. A QAL2 is also required following a significant change to the process, the fuel and the CEMs. A QAL2 is also required if the reported CEM concentrations fall outside of the valid calibration range defined in EN 14181, although this can be extended using reference materials. Also, following the failure of an Annual Surveillance Test (AST) or if consistently poor QAL3 performance demonstrates the need for a QAL2. Circumstances under which an AST may replace a QAL2 are defined by the Competent Authority, for example, in TGN M20 in England & Wales [18]. Regarding the significance of a process or fuel change - if a permit variation is required, the significance of the anticipated changes in emission levels shall be assessed. In broad terms, if the proposed change potentially results in a movement outside of the concentration ranges already established under previous QAL2 testing, or if the ranges of cross-interferents fall outside of those specified in EN (Table 7), then the calibration should be checked. An AST may then be used to indicate whether or not a full QAL2 is required [18]. Note that the PASS/FAIL statistical tests are dependent upon the ELV and it therefore becomes harder to pass QAL2s and ASTs as the ELV is reduced. 37

46 Table 7: Cross-interference ranges tested during certification Species Min Max SO 2 mg/m NO mg/m NO 2 mg/m O 2 % 3 21 H 2 O % 1 30 CO 2 % 0 15 CO mg/m CH 4 mg/m HCl mg/m NH 3 mg/m N 2 O mg/m Note: SO 2 is reduced to 200 mg/m 3 for abated installations Installation of an abatement unit is a significant process change resulting in a large reduction in both the raw pollutant concentrations and potential interferents. A QAL2 shall therefore be required for all of the regulated pollutants when FGD, SCR or SNCR are installed. An upgrade of the electrostatic precipitator (ESP) used for particulate abatement at a utility boiler plant, or some other change to the abatement equipment that could cause a change in mean particle size of the emitted dust, would be regarded as a significant change, requiring a demonstration that the dust calibration relationship has not changed. For example, adding an FGD absorber reduces the total dust burden and also removes a greater proportion of the coarse particulate in the gas stream, causing the mean particle size to decrease. Installation of low NO x combustion systems does not change the stack gas matrix significantly and a QAL2 shall not be required, provided that the QAL1 certification range is acceptable for the new ELV. If this is not the case, and the CEM is not replaced, an AST shall be conducted, in the first instance, extending to a QAL2 if this is not acceptable. For solid fuels, normal variations in fuel sulphur and nitrogen content are not considered to be significant changes with regard to the stack gas matrix, provided that the certified range of the analyser remains within 2.5* the appropriate ELV and the fuel sulphur content is within the Permit limits. This also applies to alternative solid and liquid fuels, fired at coal and oil fired power stations, provided that the fuel analysis indicates no significant changes to the crossinterference species listed in EN (Table 6). This may be confirmed by the environmental testing that is often required when applying for a permit variation. In any case, co-firing of alternative fuels shall not be considered significant when firing for less than 10% of thermal input, on an annual basis. Otherwise, a change of one fuel type (solid, liquid or gaseous) to another is considered to be significant and will require an AST, in the first instance, to demonstrate that the existing calibration relationship is acceptable. This requirement is related to changes in the stack gas matrix, e.g., CO 2 and moisture levels, and the emitted dust characteristics. However, the suitability of the CEMs should also be reviewed with regard to certified ranges and the revised ELVs. If the change of fuel is for a short period only (<10% of the time during a year or <10% of thermal input), the change shall not be considered to be significant. 38

47 There will be situations when a CEM is replaced either temporarily or permanently with a new CEM. Replacement with a different make and model requires a full QAL2. Alternative provisions for stand-by instruments and like-for-like swaps are defined by the Competent Authority, for example, in TGN M20 in England & Wales [18]. In general terms it is recommended that QAL2/ASTs for alternative instruments are performed at the same time as the main instrument Functional Tests The Test Laboratory is responsible for informing the Operator that various functional tests are required prior to undertaking either a QAL2 or an AST, as shown in Table 8. These must be performed by an experienced testing laboratory that has been recognised by the Competent Authority [17]. The Competent Authority recognises that this may be the Manufacturer, the Test Laboratory, the Operator or any other competent party (and audited and preferably witnessed by the Test Laboratory). The Operator is responsible for ensuring that the functional tests take place, typically not more than one month before the parallel reference tests in the QAL2 or AST. The Test Laboratory may use either the traceable on-site working gas mixtures or their own ISO accredited gas mixtures for the functional tests. Functional tests are required on both ELV CEMs, back-up CEMs, gas turbine bypass CEMs and peripheral CEMs for all gas components, including NO 2 if measured directly. For water vapour, functional tests conducted by the service provider, at the most recent service, are acceptable due to the difficulty of generating suitable wet gas concentrations. This is acceptable provided that the difference between the CEM and SRM readings in the AST/QAL2 is within the uncertainty allowed in TGN M20, i.e., within 30% of the ELV - equivalent to about ± 2% H 2 O. If a meaningful QAL2 calibration cannot be obtained, which is frequently the case for CO at gas turbine plant since base load concentrations are very low, the linearity data from the functional tests may then be used to check the internal adjustment of the instrument. In these circumstances an accredited gas shall be used for the linearity test or the difference between the accredited gas and the working gas mixture standard must be within the combined uncertainty of the two gas mixtures. If the specified level of agreement is not achieved, consideration should be given to adjusting the CEM using the Test Laboratory gas and reporting the gas quality issue to the Operator so that the Span gas can be replaced. The Test Laboratory has overall responsibility for reporting the results of the functional tests and for verifying the overall quality and level of compliance. The Test Laboratory is also responsible for checking that the Operator has developed and applied a documented QAL3 procedure and is required to audit the annual zero and span drift data (QAL3), including a cross-check of site test gas concentrations that are used for instrument adjustment and/or QAL3. Also, for auditing the system documentation and records and the system serviceability. The latter requires reference to a valid platform inspection certificate. The Test Laboratory produces the QAL2 and AST reports. The Operator is required to audit these for accuracy and completeness. If a Test Laboratory cannot be present when functional tests are performed by the Operator or Manufacturer there must be traceable evidence to show the tests were performed. Note that the tests may be carried out by an approved service representative of the Manufacturer. It should be remembered that the main purpose of the audit is to establish that the CEM performance continues to be acceptable prior to QAL2 or AST testing. For a new plant, this checks that the CEMs are stable prior to testing. 39

48 Table 8: Functional tests QAL2 & AST Activity Extractive In-situ Alignment & cleanliness Required Sampling system Required Leak test Required N/A Zero & span check Required Required Linearity Required Required Response time Required Required NO x converter efficiency check (Crossinterference) QAL2 Testing Comment Service Report Service Report N 2 or Span Gas (check that O 2 < 0.2%). Check process O 2 before and after test. May not be appropriate for extractive dust monitors with internal purge air or eductors. Consult manufacturer. Check Zero is within 2.5% ELV. Check Span is within 5% ELV (2.5% for NO 2 ). Check Zero and Span are within 0.2% O 2 for O 2. [Dry ambient/instrument air (20.95% O 2 ) is a suitable Span gas but, for zirconia sensors, Zero is typically 2% O 2 in N 2 ] Span = 2.ELV Nominal Range = 2.5.ELV. Actual range high enough to avoid data flat-lining. 5 point linearity: 0/40/80/120/160% ELV. Dust: fewer points are acceptable using built-in filters; different linearity points are acceptable using fixed filter values, off or on-stack. SO 2 : include higher concentrations to cover unabated operation (to suit the anticipated fuel diet). NO x : include higher concentrations to cover unabated operation (when SCR fitted). CO: include higher concentrations to cover Start-up/Shutdown. It shall be sufficient to use a single measurement at each point, following the full test method only if a fail is obtained. < 200s via probe (deduct an estimate of the transit time from the analyser to the probe as appropriate). Not applicable to dust analysers but check that internal averaging/smoothing period is set to <200s. Required N/A Service Report or Test Laboratory check > 95% Optional Optional Not required unless the certification did not consider the range of interferents present in the stack gases. This section describes how the QAL2 calibration is established but the details of the data analysis are not considered since this is the primary responsibility of the Test Laboratory and these aspects are described in EN14181 [17][25] and TGN M20 [17][18]. SRM Location The SRM test ports should be situated so that representative concentration levels are obtained, in accordance with EN15259, as discussed in Section 4.3. This is critically important for obtaining a) a meaningful measurement and b) a successful QAL2 calibration. EN14181 also requires that the CEM and SRM measurement points are separated by less than three hydraulic duct diameters but that the measurements do not interfere with one another. This may not always be possible and it is more important to demonstrate representativeness according to EN15259 [20]. 40

49 Basic Approach Following the installation of a new CEM, a QAL2 should be conducted as soon as practicable following the installation of the CEM and the commencement of QAL3 checks to establish the basic functionality of the instruments, noting that this time period should not exceed six months and the Environment Agency recommends 3 months of QAL3 before the QAL2 is performed [18]. The QAL2 straight line calibration relationship between the CEM and the SRM is established by taking at least 15 valid pairs of measurements (hourly averages) obtained across at least 3 days of operation. A reduced number of measurements is allowed under certain circumstances at the discretion of the Competent Authority, e.g., TGN M20 in England & Wales [18]. From a technical viewpoint, it is preferable to test on three separate days but, given the cost and complexity of test campaigns at large power stations, three or more consecutive test days is more feasible and is allowed by the standard. The measurements should also be well spaced within a given test day and, for gases, each sampling period shall be of one hour duration for large combustion pant. A similar number of measurements should be performed during each day of testing. Operating conditions should be steady during each sampling period. The AST requires at least 5 valid pairs of parallel measurements obtained across at least 1 day of operation, applying the sampling constraints described above. A reduced number of measurements is allowed under certain circumstances at the discretion of the Competent Authority, e.g., TGN M20 in England & Wales [18]. For low concentration dust monitoring with light scatter devices, the factor recommended by the Manufacturer for the given process type may provide an acceptable calibration. For identical instruments, with identical monitoring locations, fitted to FGD units of the same design, historical data indicates that it can be appropriate to pool the data from individual units in order to obtain a more representative overall calibration for the plant since the dust characteristics downstream of FGD absorbers are relatively consistent and stable. This avoids the problem of a considerable variation in the slopes of the calibration lines between individual units, caused by low concentration data clusters; it makes most sense to pool the data to obtain a common calibration. If the average SRM dust concentration is greater than the SRM uncertainty, that is 30% of ELV, then a single point average value can also be used to calibrate the CEM [18]. These approaches shall be allowed subject to a) justification based on a review of the existing test data and b) no reduction in the required number of test points on each unit. However, a calibration must always be supplied for a power plant, noting that the provision to simply set the dust monitor to a high gain setting is not considered to be acceptable. For dust monitoring during short periods of operation without FGD, using the same outlet dust monitor or an upstream opacity meter, it shall be sufficient to use historic calibration data or, where this is unavailable, industry average values corrected to the appropriate path length (for opacity meters [34]) or an appropriate calibration factor from the manufacturer (for light scatter dust meters). After the removal of outliers, using methods specified by the Competent Authority, caused, for example, by a problem with the SRM, or an unexpected variation in fuelling or plant operation, it is recommended that at least the minimum number of data pairs for a QAL2 and an AST, are obtained, not counting any zero or span data points that are included in the calibration. Selection of Test Conditions Deliberately changing the process to increase emissions, in order to obtain a wide spread of emissions data, is not allowed, although the process may be altered in order to temporarily 41

50 reduce emissions. The data should ideally be spread over at least 50% of the ELV. However, if this is not possible due to operational constraints, then other approaches can be used to deal with a cluster of points generated at base load. A full QAL2 approach is generally not required for the peripheral measurements of oxygen content and water (if measured). Data Recording It is crucially important that the data recorded and displayed by the plant system is consistent with the data transmitted or displayed by the analyser locally. Although this aspect is not included within the scope of EN 14181, it is key to a successful QAL2. As a minimum, the local and remote displays/recordings should be cross-compared when passing zero and span gases through the analysers, in addition to cross-comparisons obtained during the test periods. Valid Calibration Range (VCR) The Valid Calibration Range (VCR) is nominally taken to be 110% of the maximum expected SRM concentration (the calibrated CEM reading) obtained from the QAL2 CEM data, at standard reference conditions. The Operator is required to check, on a weekly basis, that the emission measurements taken during that week fall within the VCR according to criteria specified in EN This test is performed on the emissions values prior to deduction of the confidence interval. Reporting shall be by exception, i.e., the Competent Authority is informed if there is a non-compliance which would normally trigger a new QAL2. If the plant is not operated continuously then the percentage of hourly averages that exceeds the VCR may be calculated based on operating hours, rather than calendar hours. That is, the previous 168 operational hours (representing one week in operation). Due to the process variability at power stations, the VCR can be extended to the short-term (hourly) percentile ELV using linearity data, provided that the level of agreement between the linearity data and the QAL2 calibration line is within the confidence interval, at the ELV, specified in the IED. This extension improves confidence in the quality of the reportable data and is also used for the purposes of the weekly data check. In some situations, e.g., temporary failure of abatement equipment or during a combustion fault, a wider extension may be required, again subject to the stated uncertainty requirements being fulfilled. This is especially the case for SO 2 emissions from coal fired plant when the abatement system is off-line and for high CO emissions from gas turbine plant during abnormal operation. In this case, the higher reference points provide additional confidence in the reportable data but shall not be used for the purpose of extending the VCR. Instead, the frequency of occurrence of high concentrations can be assessed using the weekly data check. However, a new QAL2 is not required under these circumstances which are classified as an abatement or combustion plant failure for the purposes of EN The linearity data, from the functional tests, shall be plotted on the QAL2 graph and the agreement at all points shall be within the 95% confidence interval determined at the ELV. Additional confidence in this approach can be demonstrated by reviewing historic AST data. If there is a difference of more than half the confidence interval at the ELV, then further investigation is warranted. When plotting linearity data on the QAL2 graph, the Test Laboratory should enter the expected concentration level as the SRM data (y-axis). Since test gases are dry and do not contain oxygen it is not appropriate to convert linearity data to duct or standard conditions when making this check. 42

51 Given the general difficulties associated with dust measurement, the use of optical surrogates (for span and zero values) represents the only practical means of addressing VCR extension. In this case, the CEM values from the linearity test are expressed in the same way as for the QAL2, i.e., as a mg/m 3 instrument value, or as the primary optical measurement (light scatter units), or as a ma output. The calibration function is then applied to convert the CEM linearity data into an expected dust reading in mg/m 3. By definition, the linearity points then fall on the calibration line and agree perfectly so it is meaningless to apply a tolerance. Physically, this extrapolation for dust only holds true if the particle characteristics do not change as the concentration level increases. This is a reasonable assumption for FGD outlet dust. The combustion control and low emission combustion systems on gas turbines generally give rise to stable emissions with low process variability. However, medium to long term variations can be significant. Turbine operating conditions and therefore emissions performance are sensitive to ambient conditions and can therefore change across the calendar year, sometimes requiring re-tuning of the combustion system. Degradation between outages is also important, e.g., increased air leakage through combustor seals causing a reduction of combustion air and a decrease in air:fuel ratio, in turn causing an increase in flame temperature and NO x. These variations can easily exceed 10%, noting that, at an IED NO x ELV of 50 mg/m 3, the extension is only 5 mg/m 3 or 2.5 ppm. Therefore, the same range extension provisions shall apply to gas turbine plant. Regarding QAL2s for NO x, a range of options are available to deal with different measurement approaches: NO CEM only - calibrate against NO and calculate NO x using a standard factor (at solid fuel fired plant); NO CEM only - calibrate against total NO x ; NO and NO 2 measured separately - calibrate against total NO x ; total NO x measured as NO (using a converter) - calibrate against total NO x [35]. If NO 2 is measured by both the CEM and the SRM, either directly or by difference using a converter, and the CEM is calibrated for total NO x, QAL2 plots may also be produced for the individual components, for information only. However, it should be noted that the proportion of NO 2 measured by the CEM and the SRM may be different due to differences in sampling and analysis whilst the total NO x should always be comparable. For a utility boiler, the NO CEM readings may also be corrected using a calculated NO 2 content, (Section 6.2) prior to comparison with a total NO x SRM. For a gas turbine, if a secondary backup NO x measurement is provided using an additional NO detector, this can be corrected to match the total NO x of the primary instrument using the ratio of the back-up NO to the primary NO x (or the SRM NO x if this produces acceptable agreement). A QAL2 plot of oxygen may also be presented for information only. If the average difference between the SRM and CEM O 2 concentrations is greater than 0.3% O 2, then further investigation is warranted. In the first instance, the CEM and SRM concentration data can be corrected to reference conditions using the respective O 2 measurements and no further action is required if the corrected concentrations are closer than the raw values since this indicates that the differences in O 2 are real. 43

52 As a general rule, if the CEM fails the QAL2 tests due to issues with the operator s peripheral measurements, then the SRM peripheral measurements may be used instead. If the CEM then passes the QAL2 tests, then the operator must fix the peripheral monitoring equipment as soon as possible and verify performance with additional QAL2 exercises. QAL2 Implementation If a QAL2 calibration factor (gradient) of less than 0.9 is applied then the Operator must investigate and provide an explanation of the low calibration factor to the Competent Authority, having at least considered, and having corrected deficiencies in, the following aspects: i) the reference method implementation used by the Test Laboratory (is this reading low?); ii) lack of homogeneity at the sampling plane (stratification?); iii) quality of the reference gas standards used for calibration of the CEM and the SRM (calibration bias?); iv) the QAL3 control limits (do the limits need to be tightened to prevent excessive drift)?; v) successive functional test results (is the analyser performance degraded?). The criteria for verifying flue gas flow rate calculations are specified in EN ISO : 2013; in broad terms, flow rate agreement is expected to be within 5%. For the purposes of a QAL2 flow verification, the QAL2 variability test, the R 2 linearity test and the AST validity test must all be passed. Annual Surveillance Test (AST) There is no formal requirement for the Test Laboratory to use the same SRMs as for the QAL2. However, since the test data are assumed to be correct, with any scatter attributed to the CEM, continuity of approach is recommended. QAL2 and AST Reporting The reporting formats shall be compliant with ISO 17025/MCERTS requirements and reports shall be audited by the Operator in line with available guidance. A template for the production of QAL2/AST reports is provided in [25] and checklist for auditing is provided in [36]. 5.3 Quality Assurance Level 3 (QAL3) Drift Checking General Approach Several control chart approaches are defined in the standard. The power industry generally prefers a Shewhart chart approach [37] and this is defined in detail within EN and TGN M20 which also describes the alternatives. The QAL3 procedure is applied to compliance species and the peripheral measurements used for correction to reference conditions. It is recommended that QAL3 checks are continued when the plant is Shut-down in order to ensure the correct functioning of the instruments on Start-up. The QAL3 procedure is generally not applied to water vapour (if measured) due to the difficulties associated with producing traceable water vapour concentrations. It is sufficient to rely on checks conducted at the normal service interval and the AST. However, internal check cycle results, using surrogates, can be used if available and it is recommended that alarms are set to indicate if the measured process water vapour or oxygen become physically unrealistic. It is recommended that QAL3 reference gas is injected at the sample location unless this causes the QAL3 procedure to take longer than 20 minutes due to the increased response time. Otherwise, the gas can be injected using the normal span port of the instrument, preferably upstream of the sample gas chiller (if installed). In these circumstances, additional leak checks can be conducted periodically by injecting nitrogen or span gas at the sample probe. 44

53 5.3.2 Control Charts The standard Shewhart chart approach specifies control limits based on the instrument uncertainty, represented by a standard deviation of the measurement, S ams. The Warning limit is set at 2*S ams and the Action limit at 3*S ams. TGN M20 describes various ways of obtaining this uncertainty (S ams ) from either the manufacturer s performance data or from repeatability measurements using test gases. It is recommended that the repeatability of the Zero and Span measurements is determined to give an indication of the best performance of the analyser, prior to initiating the QAL3 analysis. In general, the power industry prefers a very simple approach, initially setting control limits as a proportion of the ELV combined with subsequent adjustment based on experience. For consistency with the general Shewhart approach, an equivalent S ams value is defined. However, this is an arbitrary value that gives the desired Warning and Action limits when the above multipliers are applied. The Action limit cannot be higher than 50% of MPU [17]. It should be recognised that the recommended values given below are a starting point and the control limits should be reviewed periodically in order to assess the need for adjustment. In general, the closer the emission to the ELV, the tighter the required tolerances for both operational and compliance purposes. Utility Boilers For utility boilers, S ams can be initially set such that the alarm (action) limits for gases are ±7.5% of ELV and the warning limits are set at ±5% of ELV for both Span and Zero drift, noting that modern instruments often perform frequent automated zero adjustments. Illustrative values are shown in Table 9 which also quotes the assumed ELVs. The S ams for oxygen is set at 0.25% O 2, giving an action limit of 0.75% O 2, resulting in an uncertainty of 5% in the NO x /SO 2 correction. The combined uncertainty in the corrected NO x /SO 2 emission is then about 10% (half of the IED confidence interval). Table 9: Control chart limits utility boilers Species ELV %ELV for S ams Warning Action Action SPAN mg/m 3 S ams mg/m 3 mg/m 3 mg/m 3 % ELV NO x & SO % % Dust % % 'ELV' %ELV for S ams Warning Action Action %O 2 S ams %O 2 %O 2 %O 2 %NO x ELV O % % For dust monitors, the S ams can be set to give a Warning at 1.3 mg/m 3 and an Action limit of 2 mg/m 3. Experience with both light scatter and opacity monitors indicates that their performance is robust and genuine QAL3 failures are rare. The type of Zero and Span check using optical surrogates depends on the operating principle and manufacturer of the dust monitor. The Span value is typically set at 70% of the range of the instrument. 45

54 Since dust monitors usually self-correct for optical contamination very frequently, only the check result equivalent to the maintenance interval of the instrument, as given in the MCERTS certificate, needs to be recorded and plotted, although more frequent QAL3 data can be extracted from the regular check cycle results if these are readily available. Drift may be plotted in any consistent units, such as ma or concentration units, provided that the control limits are expressed on the same basis. Gas Turbines A gas turbine example is shown in Table 10 which also quotes the assumed ELVs. In this case, the control limits are more constrained due to the increased importance of the oxygen correction at the higher oxygen reference condition. For O 2, an S ams value of 0.1% O 2 gives an action limit of just ±0.3% O 2 (3% of the O 2 ELV ). This is equivalent to an uncertainty in the NO x correction of ±5%. When this is combined with the specified Action limit for gases, the overall uncertainty is about 10%. The S ams values for the Zero control chart are identical except, perhaps for CO, which could be halved since base load levels of CO are generally very low. Table 10: Control chart limits gas turbines Species ELV %ELV for S ams Warning Action Action SPAN mg/m 3 S ams mg/m 3 mg/m 3 mg/m 3 % ELV CO % % NO x % % 'ELV' %ELV for S ams Warning Action Action %O 2 S ams %O 2 %O 2 %O 2 %NO x ELV O % % For an instrument that measures NO and NO 2 as separate components, the QA tolerances can be partitioned between the two components to give the same overall result, bearing in mind that the NO 2 content is typically only 20% of the total NO x Action to be Taken when Failing a QAL3 If an individual QAL3 test fails during execution, the reasons for the failure should be investigated, corrective action taken, documented and the test repeated. Spurious data points shall then be removed from the QAL3 record. An individual QAL3 drift check may fail for many reasons that are easily rectified, for example, because the gas cylinder is closed or empty or a solenoid valve has jammed. If the problem cannot be resolved, the manufacturer should be consulted and called in, if necessary. The Operator must also examine the control chart after each QAL3 and assess if action is required. Under normal circumstances, if the QAL3 has a PASS status, it is preferable that the instrument is not adjusted. However, if, for example, the drift is close to the Warning limit during a service visit, the Operator may request an adjustment of the analyser to improve reporting accuracy and to avoid a subsequent call-out. EN14181 defines circumstances in which the Operator is required to intervene. In broad terms: no action is taken provided that the drift is below the warning limits; 46

55 investigation is undertaken when the drift is outside of the warning limits; action is always taken if the alarm limit is breached. Additional criteria for assessing QAL3 performance may be provided by the Competent Authority as an example of how to respond to trends in analyser performance [18]. The Operator s approach to a QAL3 fail shall be documented in the Environmental Management System. Analyser adjustment is preferably undertaken by the manufacturer. However, this may be undertaken by the Operator using suitably trained staff. The adjustment should be documented in all cases Reference Materials Test Laboratories must use ISO Accredited Gas Standards (AGS), with better than ±2% uncertainty at 95% confidence, for QAL2 and AST testing, noting that functional tests may be conducted using the Operator s site gases. Operators may use either binary AGS standards or multi-component Working Gas Mixture Standards (WGMS). However, if the site gases are not accredited, and are used for instrument adjustment or QAL2 verification using linearity data, the Test Laboratory must check the site gases using AGS. The required level of agreement must be within the combined uncertainty of the site gas and the test gas. If there is poor agreement, the Test Laboratory should report this and decide on the best course of action with the Operator. For example, there may be sufficiently close agreement for QAL2/AST purposes and the quality of the site gas can be investigated at a later stage. However, if the QAL2/AST is jeopardised then the CEMs may need to be adjusted using the Test Laboratory AGS and a new site gas ordered. In the case of direct measurement of NO 2, a reference gas with a known NO 2 concentration is required. This may be supplied as a mixture containing the oxygen Span concentration. However, in this case, QAL3 performance may be affected by the stability of NO 2 gas standard. Interpretation of the results, and decisions about corrective action, can therefore be more difficult. When changing gas cylinders, due to the uncertainty of the reference gas concentration, there will normally be a shift in the measured Span concentration. The QAL3 base-line therefore needs to be adjusted and a procedure for comparing the concentration readings, before and after a gas cylinder change, is provided by the Competent Authority [18]. This also provides an opportunity to check that the gas concentrations agree to within their specified uncertainties. In cases where this is not possible, due to a leakage of Span gas, for example, the QAL3 baseline shall simply be adjusted to the new gas concentration. For instruments fitted with internal filters or gas filled reference cells, these may be used for QAL3 purposes provided that they were certified under EN as QAL3 compliant. Filters or diffusers are always used for dust CEMs QAL3 Reporting The Test Laboratory annually audits and reports on the QAL3 records as part of the QAL2/AST. If the Test Laboratory identifies a problem with the QAL3 results or procedures, this may be reported as corrective action in the AST report. The Test Laboratory reporting formats shall be compliant with any applicable ISO 17025/MCERTS requirements and Test Laboratory reports shall be audited by the Operator in line with available guidance [36]. 47

56 6 EMISSIONS REPORTING 6.1 Over-view This section considers emissions reporting to meet IED requirements. The building block for reporting is the valid hourly average concentration. This is obtained by calculating the hourly average of the raw pollutant concentration, in mg/m 3 at K and kpa, and then correcting to the reporting reference conditions using the measured oxygen content and the measured (or calculated) water vapour content. The confidence interval is then subtracted to obtain the validated hourly average from which the daily and monthly validated averages are calculated and also the annual percentile concentrations of the hourly averages. The reference conditions are 3% O 2 for gas and liquid fuel fired boilers, 6% O 2 for solid fuel fired utility boilers, 15% O 2 for gas turbine plant, all on a dry basis. The calculation of annual mass emissions is also considered for both inventory reporting and compliance purposes, without subtraction of the confidence interval. In situations where discontinuous monitoring is permitted, the results of the periodic testing must be reported. 6.2 Correction to mg/m 3 at the Reference Temperature and Pressure Gas components There is an expectation that conversion of measurement units is embodied in the calibration relationship defined by EN However, if this is not the case, the conversion from ppm to mg/m 3 can be performed as follows: mg/m 3 = ppm. MM/MV Where ppm = measured molar concentration, parts per million by volume MM = molecular mass of the component, kg/kmol MV = molar volume of ideal gas at normal conditions = 1 kmol occupies m 3 at K, kpa The values of MM and MV and the resulting conversion factors (MM/MV) are tabulated below for the relevant gas components. Table 11: Conversion factors Species MM MV MM/MV kg/kmol Nm 3 /kmol kg/nm 3 NO SO CO Note that conversion to mg/m 3 includes the correction to the reference temperature and pressure (273.15K, kpa); the direct measurement of concentration in ppm is not a function of the gas temperature and pressure at the measurement location. 48

57 The NO 2 conversion factor is applicable to the direct conversion of either the measured NO in ppm or NO 2, in ppm, to mg/m 3 NO 2 equivalent as required by environmental legislation. Total NO x is defined as NO+NO 2 and is expressed as NO 2 for compliance purposes, and consistency with air quality assessments, since NO is oxidised fairly rapidly in the atmosphere to give NO 2. If NO is already expressed as mg/m 3 of NO, this can be converted to mg/m 3 of NO 2 equivalent, for reporting purposes, as follows: mgno 2 /m 3 = * mgno/m 3. For solid fuel fired utility and industrial boilers, the NO 2 content is low and can be, optionally, taken into account using a correction factor applied to the measured NO concentration. The NO 2 is about 5% of total NO x (unabated plant) or 2.5% of total NO x (plant with wet FGD systems). The NO value is therefore divided by 0.95 (unabated) or (abated) to obtain the NO x concentration. For gas turbines, total NO x must be measured since the NO 2 content within the overall NO x emission is typically 20% of total NO x at base load. Dust Dust concentration is based on calibration against a gravimetric determination and the measurement is conducted in-situ. In these circumstances, the QAL2 calibration is expressed at actual duct conditions and hence temperature and pressure corrections must be applied to obtain mg/m 3 at the reference conditions. To convert the concentration measured at a temperature, T (K) and absolute pressure, P (kpa), to the concentration at the reference conditions, multiply by: T P For an extractive dust monitor, the temperature and pressure are those at the measurement volume inside the CEM. Whilst it is best practice to monitor these continuously, the temperature controller setting and a nearby duct pressure measurement, or an ambient pressure measurement can be used with minimal loss of accuracy. In situations where the temperature and pressure are monitored by a gas sampling probe, and the readings of temperature and pressure are compromised due to purge probing or scheduled maintenance or Quality Assurance of the gas system, it is acceptable to substitute default values of temperature and pressure during these periods. Similarly, if the temperature and pressure are not available due to sensor failure, it is acceptable to substitute default values of temperature and pressure for up to 5% of the time. A default pressure value of kpa is acceptable. The default temperature can be the normal base load flue gas temperature (circa 130 C for plant without FGD and C for plant fitted with FGD, dependent upon the FGD design). 6.3 Correction to Reference Conditions Correction to the Reference Oxygen Concentration The following standard expression is used to correct measured dry concentrations to the required reference oxygen concentration [23]. The dry gas concentration is multiplied by the following factor: 49

58 (20.95 %O 2rrr ) (20.95 %O 2 ) where %O 2ref = reference oxygen level, dry, % by volume %O 2 = measured oxygen, dry, % by volume For in-situ wet measurements, both the pollutant concentration and the wet O 2 concentration must first be converted to a dry basis, as detailed below, before correcting for the oxygen content. The oxygen correction is non-linear and can be a significant source of error when the process oxygen reading is high, as is the case for gas turbines, during normal operation, and for all plant during Start-up and Shut-down. If the oxygen CEM fails, the NO x and SO 2 readings may be corrected, temporarily, using a default oxygen reading. For utility boilers, this may be derived from previous plant readings but it is often sufficient to assume 6% O 2 at base load, rising linearly to 10% O 2 at MSG. For gas turbines, a correlation between the measured O 2 vs gas turbine load relationship may be developed Correction to Dry Basis If a concentration is measured on a wet basis, this must first be corrected to dry conditions. The wet gas concentration is multiplied by the following factor: 100 (100 %H 2 O) Where %H 2 O = water vapour content, % by volume Water vapour concentration measurement is mandatory when measuring gas concentrations on a wet basis [1]. Dust monitoring is always on a wet basis but, if the moisture is not measured, it shall be acceptable to calculate the moisture content as specified below. The following approach shall be used for correction purposes subject to QAL2 verification. Plant with FGD The water vapour content - typically about 12% by volume - is calculated from the average gas temperature downstream of the absorber, prior to reheat, assuming saturation. The vapour pressure of water (the partial pressure) is first calculated from the average absorber outlet gas temperature using a suitable correlation, e.g., the Sonntag relationship: lll e P v = T T T lll e T where P v = vapour pressure of water (Pa) and T = gas temperature (K). P v, so obtained, is divided by the absolute duct pressure, P T (Pa) to give the water vapour concentration: %H 2 O = 100. P v P T 50

59 Plant without FGD The moisture content of the flue gas is calculated from the stoichiometric flue gas parameters, given in Table 12, as follows. 1. Calculate the excess air factor, λ, from the dry O 2 reading: λ = 1 + CCC s %O 2. AAA s (20.95 %O 2 ) Where CFR s is the ratio of dry combustion products to fuel and AFR S is the ratio of dry combustion air to fuel, both at stoichiometric conditions (Table 12). 2. Calculate the actual air:fuel ratio from the air factor and the stoichiometric air:fuel ratio: AAA = λ. AAA s 3. Calculate the water:fuel ratio of any additional moisture associated with the combustion air, W a FR, using the moisture volume fraction of the combustion air, y w, noting that ISO air (60% relative humidity at 15 C) contains 1% by volume of water vapour (y w = 0.01): W a FF = AAA 1 y w 1 The assumed value of y w is acceptable under most circumstances. However, y w can be calculated from the ambient conditions of temperature, t ( C), fractional relative humidity, RH (-), and pressure, p (mbar absolute), of the inlet combustion air as follows [43]: y w = RR t ( t) p 4. Calculate the water content of the flue gas knowing the ratio of combustion derived water:fuel at stoichiometric conditions (WFR s ) from Table 12. If water or steam injection is used for NO x control or power augmentation, then also take account of the water:fuel ratio of injected water/steam (W i FR in Nm 3 /kg). Note that the injection is often specified as a water:fuel mass ratio in kg water /kg fuel, with a typical value of 1.0. This can be multiplied by to obtain W i FR in Nm 3 /kg. [WWW s + W a FF + W i FF] %H 2 O = 100 [CCC s + WWW s + (λ 1). AAA s + W a FF + W i FF] 51

60 Table 12: Moisture content of flue gas Stoichiometric conditions 3%O 2 dry 6%O 2 dry 15%O 2 dry Fuel CFR s AFR s WFR s H 2 O H 2 O H 2 O m 3 /kg m 3 /kg m 3 /kg %w et %w et %w et Coal % 7.0% 3.5% Biomass % 12.4% 5.9% HFO % 9.1% 4.4% Gas Oil % 10.0% 4.8% Natural Gas % 14.9% 7.1% The stoichiometric data in Table 12 are taken from standard combustion handbooks for solid and liquid fuels [38] and North Sea natural gas [39]. The parameters for coal are based on Rank 702 which closely matches the flue gas moisture content of coals fired in the UK and is consistent with previous guidance. The coal parameters are acceptable for biomass co-firing levels up to 10% by mass since the additional moisture is broadly within the uncertainty associated with the coal. The parameters for biomass are based on wood at 15% fuel moisture, by mass [38]. For biomass moisture contents above 20% by mass, the biomass parameters shall be corrected for different fuel moisture contents as follows. For every 10% increase in fuel moisture, subtract from CFR s, subtract from AFR s and add to WFR s (pro-rate these values to match the change in moisture content). For illustrative purposes, Table 12 also gives standard values of flue gas moisture at different oxygen reference conditions. 6.4 Validated Hourly Averages Primary data are generally obtained as an electrical analogue signal (usually 4-20 ma) or a digital signal and then converted to concentration units (e.g., mg/m 3 ) as described above. The maximum time period that can be represented by any one instantaneous sample is 10 seconds. These instantaneous samples may comprise the stored first level data average (FLD), or they may be averaged to give an FLD, with a maximum period of one minute. The hourly short term average (STA) is the average of the FLD data. Valid data is collected when the unit is operating under normal operating conditions (excluding Start-up and Shut-down). A valid hour is obtained when the plant is above the Minimum Start Up Load for more than 40 minutes, and at least 40 minutes of CEM data are available, within a fixed one hour clock period. For ELV compliance, periods of Malfunction and Breakdown are also excluded. For mass emissions reporting, periods of Malfunction and Breakdown are included. In normal circumstances, there should be complete CEM data capture across a one hour period. However, this is not always possible since the CEM will be subject to Zero and Span checks and ongoing maintenance. Discarding of data points within a one hour period is allowed only when the CEM cannot be operated, e.g., due to a CEM Malfunction, Quality Assurance checks, discretionary zero and span checks, and when the unit is in Start-up/Shutdown. Discretionary maintenance and checking of the CEM must never be undertaken in more than 5 operating hours in any one 24 hour period or more than one quarter of the overall valid hours when operating for less than 24 hours. The valid STA data are corrected to standard reference conditions prior to determining the validated hourly average by subtraction of the confidence 52

61 interval (CI). Validation is normally achieved by multiplying the valid concentration by (100 CI)/100. Many Large Combustion Plant (LCP) comprise more than one unit, each with one or more CEMs per pollutant. Since reporting is on an LCP basis, the unit valid hourly averages are combined to give an LCP validated hourly average, taking into account variations in stack gas flow rate between the flues. The LCP emission concentration is the stack flow weighted average of the CEM concentrations from those units that are operating normally (excluding Start-up and Shut-down periods). This provides the best estimate of the concentration of the combined stack gases. C LLL = [C i F i ] F i (i = 1, N) Where C LCP = LCP validated hourly average concentration (mg/m 3 ) C i = Validated hourly average concentration for Unit i (mg/m 3 ) N = Number of Units firing above MSUL/MSDL (-) F i = Hourly average stack flow when firing between MSUL/MSDL for Unit i (m 3 /s). The derivation of the Unit flue gas flow is described in Section As an alternative, for utility boilers, the concentration can be simply load weighted since this provides a very close approximation to the stack flow weighting. In this case, F i is replaced by O i in the above equation, where O i is the average hourly Unit load, when firing between MSUL/MSDL, in MW e. As stated previously, the LCP must comply with specified concentration limit values by direct comparison with the validated monthly, daily and hourly averages. The IED requires compliance with percentile emission limit values for the hourly concentration averages across the calendar year: 95% of the hourly average concentrations must be less than 200% of the monthly ELV. To calculate the 95 th percentile value of a data set, the data are sorted from highest to lowest concentration and the highest 5% of the sorted samples are identified. If the highest 5% of samples is not an integer number, the number of samples identified will correspond to the integer below the 5% value. The samples identified are discarded and the 95 th percentile is the highest concentration value of those remaining. The number of discarded samples will be less than (or equal) to 5% of the total number of samples. For compliance purposes, hourly average concentrations that are excluded due to Malfunction or Breakdown are also excluded from the percentile determination. 6.5 Daily and Monthly Average Concentrations Long term averages (LTAs) are taken to be the arithmetic average of the short term (hourly) averages (STAs). The daily average for reporting purposes is therefore simply the mean of the validated hourly averages. Within a given reporting period, the maximum daily average in the period is reported against the daily ELV. The daily average is the fixed calendar period starting at 00:00:00 on the day under consideration. Most data acquisition systems use local time rather than GMT. This results in one 23h period and one 25h period each year arising from the change to and from BST. Either local time or standard time may be used. For utility boilers, a daily average is reported if it contains more than the qualifying period of three validated hourly averages. For 53

62 gas turbines operating in combined cycle, a daily average is reported if it contains more than the qualifying period of two validated hourly averages. If the daily ELV is specified as an annual percentile then the percentile approach applicable to hourly averages (Section 6.4) shall be applied to the daily averages. The IED Malfunction and Breakdown provisions, described in Section 3.6, require the exclusion of hourly average concentrations for ELV compliance purposes when the daily ELV threshold would be exceeded due to Malfunction or Breakdown. The number of hours of Malfunction or Breakdown is equal to the number of excluded hourly averages, subject to a rolling annual cap of 120h. In mixed technology plant, this requires a flag to be set to indicate if a unit is fitted with abatement. The procedure for exclusion of hourly average concentrations, associated with Malfunction or Breakdown, is shown in Figure 5, which is applicable to all operational abated units. That, is the flow chart applies when there is at least one abated unit operating. Breakdown occurs when the LCP validated daily average exceeds the daily LCP ELV threshold and all of the operational abated unit validated daily averages individually exceed the daily LCP ELV threshold. Malfunction occurs when the LCP validated daily average exceeds the daily LCP ELV threshold and any (but not all) of the operational abated unit validated daily averages individually exceed the daily LCP ELV threshold. The Malfunction and Breakdown reporting is therefore based solely on exceedance of the daily ELV and does not require any other indication of the physical condition of the abatement equipment 60. Note that, if the Malfunction or Breakdown cap is exceeded, there is no data exclusion and exceedance of the daily ELV is reported as a breach. If the daily ELV is specified as an annual percentile, for the purpose of determining Malfunction or Breakdown, the daily ELV threshold is replaced by a Concentration Threshold equivalent to 1.2*daily ELV. The validated monthly average is similarly calculated from the validated hourly averages (also excluding the hourly averages related to M&B). For utility boilers, a monthly average is reported if it contains more than the qualifying period of three validated daily averages. For gas turbines operating in combined cycle, a monthly average is reported if it contains more than the qualifying period of two validated daily averages. 60 In the case of steam or water injection on a gas turbine, Malfunction and Breakdown can optionally be determined by counting and excluding the hours in which the abatement system has failed (the steam or water flow rate is below the required level of injection). 54

63 Figure 5: Malfunction and Breakdown calculation procedure 55

64 6.6 Mass Emissions Reporting (Normal Operation) The IED requires LCP to report annual tonnage of the qualifying pollutants 61. When CEMs are used to determine mass emissions, the tonnage is determined from the valid concentration, i.e., the confidence interval is not subtracted. Mass emissions are calculated from an emission concentration multiplied by a calculated flue gas flow rate expressed at the same reference conditions. Determination of the LCP emission concentrations is described above and the determination of the LCP stack flow rate is described below. The LCP hourly flow rate is then simply the sum of the unit hourly average flow rates (defined below): F LLL = F i (i =, N) The hourly emission in tonnes, T LCP, is then: T LLL = C LLL. F LLL The monthly tonnage is calculated as the sum of the hourly tonnages within the reporting period. This tonnage is then corrected to account for missing CEM data by dividing by the LCP fractional data capture for that month. Hence it is necessary that the number of unit hourly average flows included in the calculation of F LCP is consistent with unit valid hours used to calculate LCP fractional data capture. The annual tonnage is then the sum of the corrected monthly tonnages. The data capture for the LCP shall be determined by the availability of the CEM(s) on the remaining operational Units, i.e., the average of the CEMs readings from the other operational units will be used where possible. This parallels the situation where there are multiple CEMs serving one Unit - the reported concentrations are taken to be the average of the remaining CEM outputs and the data capture is based on the availability of the remaining CEM(s). The data capture for the LCP is determined as follows: d = H (H + H ) where d = fractional data capture, (-) H = sum of invalid hours caused by CEM unavailability, - H = sum of valid hourly averages, - The invalid hours, data capture and subsequent correction of mass emission may be performed using either a unit approach, with corrections then being summed into the LCP emission, or an LCP approach. The correction of LCP mass emissions data to account for missing data should be done on a monthly basis. Annual emissions are then calculated from the corrected monthly LCP mass emissions. For Pollution Inventory purposes, tonnage estimates are needed when operating below MSUL/MSDL. These estimates will normally be determined from emission factors and fuel burn using the appropriate methodology. However, an Operator may elect to use CEMs for the 61 Article 72(3) 56

65 concentration determination upon demonstrating their fitness for purpose when firing below MSG/SEL (Section 6.7) Utility Boilers The Unit hourly flue gas flow rate is determined from the Unit electrical output and efficiency [40] as follows, on a net calorific value (NCV) basis throughout: F i = O i η i. S Where F i = Unit hourly average stack gas flow rate at 6% O 2 dry (m 3 /s) O i = Unit average generated electrical output (MW e ) η i S = Unit average generated efficiency on a net CV basis (-) = Fuel factor NCV basis, (m 3 /MJ) The Unit load (O i ) is the generated output for the Unit in MW e. The generated output is less sensitive to differences in works power consumption. Unit load is a high quality, continuously available, measurement that is used for fiscal accounting. In the unlikely event of the unit load signal being unavailable, for flue gas flow rate calculation, a load value based on other operational parameters will be substituted, e.g., load calculation based on flue oxygen content. The fuel factor, S, must be given at the same reporting condition as the associated concentration averages. Default fuel factors, S, at 0% O 2, dry, K and kpa are now defined in Annex E of EN ISO [22]. These are given at the relevant oxygen reference conditions in Table 13. Table 13: Flue gas fuel factors m 3 /MJ at K, kPa at: 0% O 2 3% O 2 6% O 2 15% O 2 Coal Heavy Fuel Oil Gas Oil Natural Gas m 3 /MJ at 6% O 2 dry at fuel moisture: 30% M 40% M 50% M 60% M Biomass Alternatively, fuel specific factors can be derived from heating value or fuel composition as described in the standard. If the Operator elects to adopt this more detailed approach for a given year, the fuel factors and net CVs should then be updated on a monthly basis. If other fuels are co-fired with coal during normal operation, the mean fuel factor is determined as follows: S = S CCCC. (1 T A ) + S A. T A Where S COAL = Coal fuel factor, (m 3 /MJ) S A = Co-fired (alternative) fuel factor, (m 3 /MJ) T A = Fractional thermal input of co-fired fuel, (-) 57

66 The generated efficiency, η i, varies slightly between Minimum Start Up Load (MSUL) and Maximum Continuous Rating (MCR) for a coal fired Unit and this can be approximated as a linear relationship, as shown in the below graph, in which the normalised load (O' i ) is now expressed as a fraction of MCR (again defined on a gross generated basis). The average Unit or Station efficiency is a fixed point, denoted by (O' f, η f ), also shown in the graph. This is used to define the straight line efficiency-load relationship as follows, in which the gradient (m), is taken to be 0.05 for coal fired units: η i = m O i O f + η f Figure 6: Generated efficiency based on a station heat balance, a fixed gradient and a fixed operating point Since the EU Greenhouse Gas Emissions Trading Scheme requires the annual reporting of audited fuel burn and net calorific value (NCV) data, this is used to derive the average efficiency point, as follows: Convert the reported fuel burn to energy input (GJ in ) using the reported NCVs Determine the annual generated electrical output as energy (GJ out = GWh*3,600) Calculate the average efficiency (η f = GJ out /GJ in ) Calculate the average generated normalised load (O' f = GWh / Σ (H i. MCR i )). where H i and MCR i are the Unit generating hours and maximum continuous ratings, respectively. If required, the Station efficiency point should be updated annually on 1 April, in normal circumstances, immediately following submission of the verified EU ETS return. If there is an inyear change that substantially affects Station or Unit efficiencies, alternative arrangements may be agreed with the Competent Authority. For multi-unit sites, the same approach may be applied on a Unit basis, using Heat Accountancy data, provided that the sum of the Unit energy totals is the same as the Station totals - although, in many cases, the unit-to-unit variations are small. This approach may also be required for Stations with more than one LCP. 58

67 An example of this approach, applied to a JEP coal fired Station, using 2006 operating data, is given in the table below. This is a Station (also an LCP) with four Units, each rated at 500MW e generated. The LCP efficiency is 0.37 at an average load point of The efficiency line is given in Figure 6. The Unit average efficiencies and load points are also shown in the table, for comparison. Table 14: Example efficiency calculation using operational data The above approach includes Start-up and Shut-down data which should not be present in the analysis since emissions compliance applies above MSG only. The calculated efficiency will therefore be slightly too low and the reported stack flow slightly too high. In many instances, this can be ignored. However, a correction may be applied, to account for Start-up and Shutdown, using one of the following methods: Correction up to synchronisation. Subtract the fuel used pre- and post-synchronisation (up to zero load) from the heat input (GJ in ) and recalculate the efficiency (η f ). The electrical generation (GJ out ) and the load factor (O' f ) are unchanged. This presynchronisation off-load heat is already available within many Heat Accountancy systems. Correction up to MSG. Following correction up to synchronisation, subtract an estimate of the additional fuel used between zero load and MSG from GJ in. Subtract the generation between zero load and MSG from the total generation (GJ out ) and calculate the efficiency. Re-calculate the average load factor (O' f ), taking into account the Start-up/Shut-down time and generation (from zero load to MSG). An Operator may optionally define a more exact efficiency-load relationship that takes into account the slight non-linearity in the upper load range. This can be a simple polynomial but a logarithmic relationship can represent the efficiency vs load curve from synchronisation upwards. A relationship of the form: {η = A * ln (MW e ) + B} or {η = MW e / (A + B * MW e )} can be adopted provided that the validation described above is retained Gas Turbines An output based approach, as defined above, can also be employed for gas turbine plant using a pre-defined efficiency vs load curve or an efficiency value calculated from performance software, subject to the usual verification by means of flue gas testing. This approach must incorporate a means of estimating the thermal input prior to synchronisation. However, the Unit hourly flue gas flow rate can be determined from the fuel flow rate and calorific value as follows: 59