Emissions of the use of biomass fuels in stationary ... · A considerable amount of data on NEC...

ECN-BKM-2008-81

Emissions of the use of biomass fuels in stationary applications

A first inventory within the framework of the Beleidsgericht Onderzoeksprogramma

Lucht en Klimaat (BOLK) 2008-2009

ECN: A. Boersma, J. Pels, M. Cieplik, R. van der LindenTNO: W. Hesseling, D. Heslinga

MAY 2008

2 ECN-BKM-2008-81

Acknowledgement/PrefaceThis study has been performed for the Netherlands Environmental Assessment Agency/Milieu en Natuur Plan Bureau (contact: Pieter Hammingh) within the framework of the BOLK program(Beleidsgericht Onderzoeksprogramma Lucht en Klimaat) 2008-2009 for the Dutch Ministry of Housing, Spatial Planning and Environment (VROM). The project is registered at ECN under project number 8.20392. This study has been performed by ECN and TNO.

AbstractThis study provides a first inventory of available emission factors associated with the use of biomass fuels in stationary sources. The study is performed within the BOLK program (Beleidsgericht Onderzoeksprogramma Lucht en Klimaat) 2008-2009 for the Ministry of Housing, Spatial Planning and Environment (VROM) of the Netherlands. We conclude the following:

Operators and suppliers are often stating that they comply with the required regime, but actual emission data are not often made accessible, making it difficult to retrieve reliable emission factors.

Emissions are dependent of fuel (type and composition), installation (type, scale and operation) and installed emission reduction measures. As a result, the emission factors presented in this study are very diverse and show a large spread. It is not easy to give one typical emission factor to be representative, even within one category.

Upper emissions limits are well defined for medium and large installations and installations fired on waste and are therefore are well predictable and well controlled.

The limited flue gas cleaning for smaller installations can result in relatively large emissions factors. Also the monitoring of emissions (e.g. continuous measurement of emission of pollutants) is less. The Emission registration only covers installations larger then 50 MWth input. Official, centralized emission registration for smaller scale installations is currently absent. National emissions for smaller installations are estimated using emission factors and activity levels.

The effect on emissions as a result of the transition from fossil fuels to biomass fuels will depend on the type of biomass and the fuel it is substituting (gas, oil or coal):

o Transition from coal to biomass at large scale installations: due to existing extensive flue gas cleaning emissions will in general be the same or improve.The influence on NOx emissions is unclear.

o Transition from gas to biomass at small scale installations: due to limited emission reduction measures for these installations and clean character of natural gas combustion emissions will deteriorate.

The data presented in this study is not sufficient for a quantitive conclusion on the effects of the use of biomass. More information will be needed on the substitution of fossil fuels by biomass fuels. The integration will take place in the second phase of BOLK.

Industries where the use of biomass is directly linked to the product quality (glass, brick industry) will not switch to the use of biomass if this has a negative influence on product quality.

ECN-BKM-2008-81 3

Contents

1. Introduction 111.1 Background 111.2 Problem Definition 111.3 Objective 121.4 Approach 121.5 Result 121.6 Demarcation 121.7 Remarks for Interpreting Emission Factors 131.8 Reading Instructions 13

2. Emission Regimes 14

3. Costs of Emission Reduction Measures 18

4. Emission Data per Type of Biomass Conversion Installation 204.1 Coal-fired Power Plants 204.2 Gas-fired Power Plants 234.3 Waste Incinerators 244.4 Sewage Sludge Incinerators 264.5 Cement Kilns 274.6 Glass Industry 284.7 Brick Industry 294.8 Medium Scale Biomass Conversion Installations in the Energy Sector

and Industry (> 20 MW th) 304.9 Small-scale (Industrial) Installations (<20 MW th) 344.10 Digesters with Boiler or Gas Engine 39

5. New Biomass Pre-treatment Processes 425.1 Introduction 425.2 Substitute Natural Gas from Biomass (Bio-SNG) 425.3 Torrefaction 435.4 Pyrolysis (Pyros process) 445.5 Hydrothermal Upgrading 46

6. Discussion and Conclusions 48

7. Abbreviations 53

8. References 54

Appendix A Decision Tree BEES/BVA 56

Appendix B Measurement Methods 58B.1 Measurement Methods BEES A 58B.2 Measurement Methods BEES B 59B.3 Measurement Methods BVA 60B.4 Measurement Methods NeR F7 63

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List of tables

Table 1-1 Reported (ranges of) emission factors in this study, based on lower heating value of the (wet) input fuel ...................................................................................7

Table 1-2 General Effects of Replacing Fossil Fuel by Modern Biomass Combustion Technologies [Scotland, 2006] ..............................................................................8

Table 2-1 Applicable Emission Regimes [Infomil, 2004] (in Dutch).....................................14Table 2-2 Simplified overview proposed NOx emission limits [Kroon, 2008].......................15Table 2-3 Summary emission limits for biomass conversion installations in mg/Nm3

[Infomil, 2008; Coenen, 2008; Hesseling, 2008]..................................................16Table 3-1 Overview of specific cost of emission reduction measures for biomass

combustion installations at 1 MWth [Meulmans, 2000].........................................18Table 3-2 Estimated NOx reduction costs expressed in Euro/kg NOx removed from flue gas

[EMIS, 2002] ......................................................................................................19Table 3-3 Estimated SOx reduction costs expressed in Euro/kg SOx removed from flue gas

[EMIS, 2002] ......................................................................................................19Table 4-1 Emission factors for fuel mix of pulverized coal-fired installations for direct co-

firing (measured and estimated values) [Cieplik, 2008] .......................................21Table 4-2 Ammonia emission factors for coal and biomass-fired power plants and

industrial combustion used in the RAINS model [Klimont, 2004] in mg/MJ..........21Table 4-3 Measured and reported emission factors gas-fired power station with no gas

cleaning ..............................................................................................................23Table 4-4 Estimated emission factors in mg/MJ of Dutch Waste to Energy Plants...............25Table 4-5 Emission factors for sewage sludge combustion in mg/MJ fuel (dry sludge and

2% natural gas....................................................................................................26Table 4-6 Emission data from ENCI [ENCI, 2007]..............................................................27Table 4-7 Typical emissions in g/MJ (or mg/MJ) fuel input for the glass industry (fossil

emissions) ...........................................................................................................28Table 4-8 Estimated Emission factors in mg/MJ of Dutch brick industry [IPPC, 2006]........29Table 4-9 Emission factors BEC Cuijck (24 MWee) in mg/MJ...............................................31Table 4-10 Emission factors of coffee grind installation Sara Lee..........................................32Table 4-11 Summary of emission factors for large (over 50 MWth) bio-electricity plants in

mg/MJ [Scotland, 2006] ......................................................................................32Table 4-12 Emission factors of combustion of waste wood in 45 MWth installation in

mg/MJ [IPPC, 2005] ...........................................................................................32Table 4-13 Emission factors (mg/MJ) of straw fired installations in the range 50-70 MWth

[IPPC, 2005] ......................................................................................................33Table 4-14 Emission factors of CFB biomass gasifier with IGCC (in mg/MJ; presumed 6%

O2) of 18 MWth....................................................................................................33Table 4-15 Average values industrial combustion installations from IEA countries

(Norway, Switzerland, Finland, UK and Denmark) [Skreiberg, 1994]..................34Table 4-16 Emissions from small industrial wood chips combustion applications in the

Netherlands range 30 to 320 kWth on wood chips [Sulilatu, 1992]........................35Table 4-17 Emission data from the wood combustion installation in Schijndel [De Vries,

1999] ..................................................................................................................35Table 4-18 Average values both domestic and industrial combustion installations from IEA

countries (Norway, Switzerland, Finland, UK and Denmark) [Skreiberg, 1994] ..36Table 4-19 Emission ranges from industrial installations fired particle board, wood chips,

MDF and bark [Obernberger, 1997] ...................................................................36Table 4-20 Emission data of wood industry in Belgium [VITO, 2001] ...................................36Table 4-21 Summary of Corinair default emission factors for advanced wood combustion

technologies [Scotland, 2006] .............................................................................37

ECN-BKM-2008-81 5

Table 4-22 Emissions factors (mg/MJ) for wood and other solid biofuels in stoves, small boilers and small commercial installations [De Wilde, 2006] ..............................37

Table 4-23 Typical emission factors for wood chip firing for district heating [Videncenter, 1999] ..................................................................................................................37

Table 4-24 Emission factors for diesel engines on PPO .........................................................38Table 4-25 Emission factors of biogas installation Sara Lee [mg/MJ of fuel mix], 6%

biogas .................................................................................................................39Table 4-26 Emission factors from Denmark...........................................................................40Table 4-27 Emission factors for land fill gas in a gas engine .................................................40Table 5-1 Estimated emission factors for SNG production for clean wood (combustion

step) ....................................................................................................................43Table 5-2 Estimated emission factors for torrefaction..........................................................44Table 5-3 Expected emission factors in mg/MJ of biomass input (sulphur and nitrogen

poor) of future PyRos-plant .................................................................................45Table 5-4 Expected emission factors in mg/MJ biomass input (sulphur and nitrogen poor)

of future HTU-plant.............................................................................................46Table 6-1 Reported (ranges of) emission factors in this study, based on the lower heating

value thermal input of the (wet) fuel.....................................................................49Table 6-2 General Effects of Replacing Fossil Fuel by Modern Biomass Combustion

Technologies [Scotland, 2006] ............................................................................50

List of figures

Figure 5-1 Scheme of the pyRos process ..................................................................................45

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Summary

Recently a lot of attention is given to the effects on the environment and the sustainable nature of the use of biomass for energy purposes. The aim of this study is to collect easy accessibleavailable data on the (stack) emissions associated with the (future) use of biomass in the Netherlands, especially on NEC-pollutants (NOx, SOx, NH3, NMVOS and dust) from stationary sources with a special focus on smaller scale installations. The study has been performed for the BOLK program (Beleidsgericht Onderzoeksprogramma Lucht en Klimaat) 2008-2009 for the Ministry of Housing, Spatial Planning and Environment (VROM) of the Netherlands. Next to emission factors, data has been gathered on the cost of gas cleaning, emission regime and missing data has been identified. The data presented in this study has been gathered from available national and international literature and contacts. The results presented here provide a range of expected emissions. The data serves as input for the second phase of the BOLK program, where all data of the different sub-projects of BOLK will be integrated. The subjects of the other sub-projects are CCS (University of Utrecht/TNO), use of bio-fuels in road vehicles (TNO/CE) and impacts of extraction, production and transport of bio-fuels and biomass(ECOFYS).

A considerable amount of data on NEC emissions related to the use of biomass fuels in stationary applications is retrieved in this study. The amount of emitted pollutants is strongly dependent on the type biomass, the used combustion technology and the applied process conditions, and the used emission reduction measures. The data presented is mainly based on data found in literature. NOx and dust data is well available, but SOx data less. NH3 and NMVOS are often not published as these pollutants are normally released in very low concentrations during biomass combustion processes.

Table 1-1 summarizes the data retrieved in this study. Especially the small combustion installations show relatively high emission factors and large ranges.

CategoriesThe expectations of the influence on NEC emissions of increased use of biomass for different types of installations researched in this study are indicated below:

Existing technologieso Coal-fired power plants: use of biomass will reduce emissions of SOx. NOx is

however less clear and contradictions exist, as well as for NH3. For NMVOS no data is available.

o Gas-fired power plants: use of biomass will increase emissions of SOxcompared to natural gas. If more or less NOx, NH3, NMVOS will be emitted depends on operating conditions and type of installation.

o Waste incinerators (AVI’s) and sewage sludge incineration plants: This type of installations is already fired (partially) on biomass. No large changes are expected in this category

o Glass and brick industry: these industries have no plans to switch to biomass due to its expected negative influence on product quality. Therefore no effect on emissions is expected.

o Cement industry: a maximum of renewable fuels is already used. No large changes are foreseen.

o Medium scale biomass conversion: this category is rapidly growing, but has well controlled emissions. Additional use of biomass will in general increase emissions if it substitutes natural gas.

ECN-BKM-2008-81 7

o Small-scale biomass combustion: this category is characterized by a broad range of installations (scale, fuel, emission reducing measures). In general,additional use of biomass will increase emissions if it substitutes natural gas.

o PPO-fired diesel engines: only data on small diesel engines was available. NOxand dust emission factors were found to be relatively high compared to other biomass fuel applications.

o Digesters with boiler or gas engine: NOx emissions were found to be relatively high compared to other biomass fuel applications.

New technologies (SNG, (flash) pyrolysis, torrefaction, HTU): all these technologies focus on the production of an intermediate fuel with high energy efficiency. Most polluting effects are expected when their products are converted during their end-use.

Table 1-1 Reported (ranges of) emission factors in this study, based on lower heating value of the (wet) input fuel

NOx

[mg/MJ]SOx

[mg/MJ]NH3

[mg/MJ]Dust

[mg/MJ]NMVOS[mg/MJ]

Basis/Remarks

Existing technologiesCoal-fired power stations

Direct co-firing (10% biomass)

99(56-130 for 100% coal)

11.2(19 for

100% coal)

100% Biomass:

1-5 (no de-NOx)

5-10 (SCR)21 (SNCR)100% coal:

3-13

0.3-0.5(1-2 for

100% coal)

No data Fuel mix, 10% biomass

Indirect co-firing (gasification)

No data 5 No data 2 No data Assuming flue gases pass FGC in coal plant

Gas-fired power stations, directly

66(46 for

100% gas)

4(1 for 100%

gas)

No data 12 No data Bio-oil

Waste Incineration 60 2 0.1 0.5 0.9 (VOC) Fuel mixSewage Sludge Incineration

22.6 2 2.5 1.2 0.6 (VOC) Fuel mix, including 3% natural gas

Cement Industry 416 118 25 5 No data Fuel mix (47%renewable)

Brick Industry 55 12 Nihil 5 10.3 (VOC) Based on fossil fuels, no BM used

Glass Industry 310-700 190-220 Nihil 0.4-20 Nihil (VOS) Based on fossil fuels, no BM used

Medium scale biomass application

Combustion 48-219 0.3-108 1-5 (no de-NOx)

5-10 (SCR)21 (SNCR)

1-10 1.5-1.8 (VOC)

Gasification (IGCC)

34-87 5-10 No data 0-2 0-1 (CxHy)

Small-scale biomass combustion

29-420 10-50 5-9 (residential, commercial)

6-170 20-250

PPO-fired diesel engines

630-1020 No data No data 25-29 No data

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NOx

[mg/MJ]SOx

[mg/MJ]NH3

[mg/MJ]Dust

[mg/MJ]NMVOS[mg/MJ]

Basis/Remarks

Digestion Gas engine on biogas

540(168

(Danish data, see

remarks) for 100% gas, or 13 with

catalyst (Dutch data)

19 No data(0.11 for 100% gas and with catalyst

(Dutch data)

2.6(0.76 for

100% gas)

14(117 for

100% gas)

Danish data, no gas cleaning factors based on energy content of the gas, probably no catalyst/SCR

Gas engine land-fill gas

211 27 No data 1.4 12 Factors based on energy content of the gas

New technologies Numbers do not include final use of product and based on estimates

Bio-SNG 19 6 No data 1 0.03 (VOS) Based on maximum emission limit.

Torrefaction 1 2 No data No data No dataFlash Pyrolysis 4 0 0 0.8 0 Based on maximum

emission limit. HTU 0.3 0 0 0.1 0.02 (VOS) Based on maximum

emission limit,

Expected emission effectsTable 6-2 gives a qualitative overview of replacing of fossil fuels with biomass used in modern biomass combustion systems. Although the table is valid for small to medium scale for the Scottish situation and effects will be smaller for large scale applications due to more extensive emission reduction measures, it gives an indication of the expected effects of transition from fossil fuels to bio-fuels.

Table 1-2 General Effects of Replacing Fossil Fuel by Modern Biomass Combustion Technologies [Scotland, 2006]

Advantage '+' or disadvantage '-' from change to modern biomass technology (wood) from fossil fuel

Pollutant

Gas Oil Coal

SO2 -- ++ +++

NOX - - +

PM/ PM10 / PM2.5 --- -- +

NH3 No data No data No data

NMVOC - - +

CO - - +

Trace elements -- + +

PAH -- - +

PCDD/F -- - +

ECN-BKM-2008-81 9

Overall conclusions Operators and suppliers are often stating that they comply with the required regime, but

actual emission data are not often made accessible, making it difficult to retrieve reliable emission factors.

Emissions are dependent of fuel (type and composition), installation (type, scale and operation) and installed emission reduction measures. As a result, the emission factors presented in this study are very diverse and show a large spread. It is not easy to give one typical emission factor to be representative, even within one category.

Upper emissions limits are well defined for medium and large installations and installations fired on waste and are therefore are well predictable and also well controlled.

The limited flue gas cleaning for smaller installations can results in relatively large emissions factors. Also the monitoring of emissions (e.g. continuous measurement of emission of pollutants) is less. The Emission registration only covers installations larger then 50 MWth input and therefore official, centralized emission registration for smaller scale installation is currently absent. The European commission has however sent a first proposal in December 2007 to integrate several directives into the IPPC directive. This can have consequences for the emission registration as the lower limit can be set at 20 MWth, but also the emission limits may change for the range 20-50MWth. As it is a first proposal, the consequences are still uncertain.

The regular unit for emissions is mg/Nm3 dry flue gas at certain oxygen content, while emission factors are in mg/MJLHVwet. In contrast to fossil fuels, biomass can contain a large amount of moisture. If the moisture content is unknown, assumptions are needed to convert emissions into emission factors. This is a possible source of errors, but the error seems to be limited.


o Transition from coal to biomass at large scale installations: due to existing extensive flue gas cleaning emissions will be the same or improve.


The data presented in this study is not sufficient for a quantitive conclusion of the emission effects of the use of biomass fuels. More information will be needed on the substitution of fossil fuels by biomass fuels.


Missing Data In general there is a lack on data on NMVOS and NH3, as they are expected to be

formed in only very low concentrations during the combustion process. There are also no emissions limits on these pollutants so there is no reason to measure them. For small scale installations on clean biomass also SOx data is often missing as there are no limits sets to this pollutant. The sub-division of dust (PM10, PM2.5) is frequently absent.

Dutch data on small and medium scale installations is scarce and it is difficult to asses how representative the retrieved data in this study is for the Dutch situation.

Up-to-date cost data of reduction measures is scarce. Available data is at least several years old. Steel prices have been rising rapidly lately which will have a cost-increasing effect.

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Recommendations for further research Modelling

Estimate the impact of increased use of biomass on NEC ceiling emissions and air quality differentiating between small and larger applications using a diversity of scenarios.

Comparison of the effectiveness of emissions e.g. based on emissions of kWh. Research on data:

NOx and NH3 emissions are rather complex and there are contradictions in literature. An extensive literature review is recommended.

Perform an in-depth literature search on biomass installations with the focus on emission factors to retrieve missing data or obtain more reliable data. If possible, emission vectors can be identified (fuel → emission factor with reduction technology → emission factor with reduction technology), which can be used for a scenario analysis and compare them with e.g. IIASA emission vectors.

Make an inventory of all types of biomass installations in the Netherlands and try to correlate them to data in available literature.

Retrieve the emission factors for fossil fuels, for large and small scale to make a good comparison possible.

Measure especially NMVOS and NH3 emissions, if considered to be relevant, on a number of installations to verify that low amounts are emitted.

Update available cost data. Identify what emissions are related to alternative use of biomass stream

necessary for a good assessment of the effect of the use of bio-fuels, e.g.composting, decay on land etc.

ECN-BKM-2008-81 11

1. Introduction

1.1 BackgroundThe use of biomass for energy uses is an important part of a future, more renewable energy supply. The production of biomass in the Netherlands will be of minor importance. It is therefore expected that import of biomass will be significant in the future. Biomass-fuels (liquid, gaseous or solid) can be used in non-stationary (liquids, gaseous) for transport and stationary (solids, gaseous and solids). This report focuses on the stationary application of biomass-fuels.

It is expected that the use of biomass will increase as a result of a more favourable climate policy. Biomass is already of great importance for power generation, especially for co-firing in coal-fired power plants and the use of biogenic fraction in waste in waste incineration plants. The emissions are relatively well known: these installations have extensive flue gas cleaning and the emissions are registered. There are questions however about the emissions if the percentage of co-firing is increasing.

Extra stimulation of the small-scale usage of biomass is foreseen. As advantages of small-scale applications are given:

More possibilities of the use of heat compared to large-scale power plants (higher overall fuel efficiency)

Advantages with respect to grid (‘netbeheer’) as a result of decentralised production and use of power

Less transport of biomass and local application A solution for residues that were waste

Possible disadvantages are possible higher costs.

This report focuses on the emissions of NEC-pollutants (NOx, SOx, NH3, NMVOS, dust) of stationary installations that convert biomass into heat, power and/or bio gas. Possible effects within the production chain are without the scope of this report. It is of importance to have in insight in the possible emissions because:

It is an important element in the assessment of the environmental effects of small scale biomass application

To make the right choices in setting emission limits and directions of technological development.

It is an element in the more integral assessment of the use of biomass. It is an element in the economic considerations of the policy of renewable energy, CO2-

reduction and the reduction of NEC-pollutants.

1.2 Problem DefinitionA significant growth of the use of biomass fuels in the Netherlands is expected. A general overview of the impact on NEC air emissions of this renewable fuel is unavailable but necessary for policy makers within the framework of the program BOLK (Beleidsgericht Onderzoeksprogramma Lucht en Klimaat).

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1.3 ObjectiveThe objective of this research is to present an overview of available national and international emission data on biomass installations and relevant measurement protocols and regimes. The data serves as input for the second phase of the BOLK program, where all data of the different sub-projects of BOLK will be integrated. The subjects of the other sub-projects are CCS (University of Utrecht/TNO), use of bio fuels in road vehicles (TNO/CE) and impacts of extraction, production and transport of bio-fuels and biomass (ECOFYS).

1.4 ApproachTo obtain quick results, in the first phase of the project data is obtained from already available literature and reports, expertise at ECN and TNO, current research and contacts with relevant research institutes and market parties. For new technologies, that are expected to be commercially available within ten years, estimates will be done. The study has the character of a quick scan for fast accessible data.

The types of studied biomass installations are:

Coal-fired power plants (co-firing of solid bio-fuels) Gas-fired power plants (co-firing of liquid, vegetable oil) Waste (AVI) and sludge incinerators Digesters with coupled boilers or gas engines Cement industry Glass industry Brick industry Medium-sized heat and/or power plants in the energy sector and industry Small-scale installations Digesters (gas engines, bio-gas boilers, bio diesel engines) Upgrading installations for new biomass-technologies:

o Substitute Natural Gas from Biomass (Bio-SNG)o Torrefactiono Pyrolysiso Hydro Thermal Upgrading (HTU)

1.5 ResultThe project results in a brief overview of the available, easy accessible, national and international data on NEC emissions to air as a result of the use of biomass. Also a inventory is done which measurement protocols and regimes are relevant. If possible, the use of biomass and it’s effect on emissions is researched. On this basis, the effects on emissions are determined and missing data is identified. The missing data is the basis for possible measurement campaigns/research in a next phase of BOLK. The focus of this study is on possible large emission effects. The emphasis of the inventory is therefore on the small-scale installations. For the completeness also available data on power stations and waste incinerators are included.

1.6 DemarcationThis study will result in a presentation of available data of biomass conversion technologies. Due to the screening character and limited lead time of this study no extensive market survey and in-depth literature search has been performed, as well as extensive modelling of emissions. An inventory of the classification, the number of biomass installations, their fuel consumption and saved fossil fuels as well as consequences and recommendations for emission policy are not part of this study. The system boundary is the conversion installation itself (stack emissions). Possible emissions from e.g. biomass transport as well as fuel pre-treatment are therefore not included.

ECN-BKM-2008-81 13

1.7 Remarks for Interpreting Emission FactorsBiomass is not a standardized fuel. It has a very broad range of shapes and compositions. It ranges from clean wood (low nitrogen, ash and sulphur) to RDF/waste streams (high ash, sulphur, nitrogen and heavy metals). The type of conversion installation (and way of operating it), combined with optional gas cleaning equipment (and the way it is operated) all influence the final stack emissions, especially for small installations with no or limited gas cleaning and/or primary measures. All these parameters make it difficult to interpret emission data, as these parameters are in general not published together with the emission data. This makes it complicated to asses whether international data is applicable for the Dutch situation or not. In most cases it not defined what measurement method was used to determine the concentration of a pollutant.

In general emission data and limits are presented in mg of pollutant per dry nm3 at a certain oxygen content in the flue gas. The thermal capacity of biomass conversion installations is normally expressed on the lower heating value on wet fuel basis. Most data is in this study is also presented on lower heating value on wet fuel basis (LHVwet basis) of the fuel input, meaning that the fuel is usually assumed to contain moisture, which is realistic in the case of use of biomass fuels, except for vegetable oils and biogas. Typical moisture contents are 10 wt% (pellets) to 50 wt% (fresh wood chips) on a wet basis. This in contrast to fossil fuels, which normally contain no or relatively low amounts of moisture1. Assumptions were done to convert emission concentrations into emission factors on the moisture content and amount of flue gas.This is a possible source of errors, but the effect is limited, around 10-15% difference between 10 and 50 % moisture for clean, low ash biomass.

The emission factors do not take into account the efficiency towards e.g. electricity or heat of the installation. This can however be useful to compare the ‘efficiency’ of the emissions with other CO2 reducing options.

1.8 Reading InstructionsThe structure of this report is as follows:

Chapter 2 describes the Dutch emission regimes applicable for stationary biomass applications;

Chapter 3 lists data on costs of emission reduction measures; In Chapter 4 the selected, existing biomass applications are documented while in

Chapter 5 the new biomass technologies are described; Finally, in Chapter 6 the conclusions of this study are presented and recommendations

for further research are done.

1 To convert the emission per mg/Nm3 into mg/MJ assumptions have to be made about the amount of dry flue gas originating from one kg of wet fuel, assuming a certain moisture, ash content and fuel composition (mainly carbon, oxygen, hydrogen). These two numbers multiplied provide the amount of pollutant in mg per kg of wet fuel (in mg/kg wet fuel). To convert this into an emission factor in mg/MJ, this number has to be divided by the Lower heating value on wet basis of the fuel (in MJLHV/kg wet fuel).

14 ECN-BKM-2008-81

2. Emission Regimes

The applicable emission regime (BVA, BEES A, BEES B or NeR) depends on fuel type (clean/non-clean biomass), size, type of conversion equipment and date of permit of the installation. It is therefore complicated to determine what specific limit is valid for a specific conversion installation. Information can be found on www.infomil.nl [Infomil, 2008]. Of main importance is if the biomass is considered as a white list fuel or yellow list [Infomil, 2008]. White list fuels of fuels that are considered clean are (see for more details the Infomil website):

Products of agriculture and forestry; Vegetable waste from agriculture and industry; Vegetable waste from food processing industry if the heat as a result of the thermal

treatment will be recovered; Fibrous materials originating from raw pulp of production of paper from pulp, if the

wastes are thermally treated at the place of origin and the heat is recovered; Waste originating from wood that has not been treated with halogenated organic

compounds of heavy materials; Cork waste.

For all other fuels (wastes), the BVA applies. Table 2-1 provides a summary of applicable regimes as can be found at Infomil, but it should be mentioned that the Circulaire [VROM, 2002] is officially not valid and is integrated in the BEES/BVA and that the BEES B is actualized at the moment to set the limits corresponding to application of BAT. VROM wants to have the same stringent emission limits for small installations. Momentarily (April 2008) Infomil is processing the consequences of the ‘Activiteiten Besluit’. To reduce the administrative cost of installations, limited enforcement is announced for installations below 20kW of thermal capacity (non-waste). The information in this table is therefore not completelyup-to-date. More information will be available mid 2008 according to Infomil. Appendix A contains a decision tree to select the appropriate regime [Infomil, 2008].

Table 2-1 Applicable Emission Regimes [Infomil, 2004] (in Dutch)

AutoriteitKetel < 0,9

MWthProvincie/ Gemeente

Ketel > 0,9 MWth

Provincie/ Gemeente

GT/Gti > 1 MWth

Provincie/ Gemeente

WKK-zuigermotor Provincie/ Gemeente

Kachel Provincie/ Gemeente (< 20 kW)

Kachel Provincie/ Gemeente (> 20 kW)

Gas door vergisting van stoffen op witte lijst

Typekeur Bees A/Vergunning conform Bees

A

Bees A/Aansluiting

bij Bees A3

Bees A/Bees B1, 3

Circulaire Circulaire

Gas door vergisting van stoffen op gele lijst

Typekeur2 Bees A/Vergunning conform Bees

A2

Bees A/Aansluiting bij Bees A2, 3

Bees A/Bees B1, 2,3

Circulaire Circulaire

Gas door vergassing van schone plantaardige afvalstoffen (Bva art.2a:1–5)

Typekeur Bees A/Vergunning conform Bees

A

Bees A/Bees A3

Bees A/Bees B1, 3

NeR/NeR NeR/NeR

Gas door vergassing van overige afvalstoffen

Bva/Bva Bva/Bva Bva/Bva Bva/Bva Bva/Bva Bva/Bva

Verbranden schoon resthout

NeR F7/NeR F7

Bees A/NeR F7 –/– –/– No limits NeR F7/NeR F7

ECN-BKM-2008-81 15

AutoriteitKetel < 0,9

MWthProvincie/ Gemeente

Ketel > 0,9 MWth

Provincie/ Gemeente

GT/Gti > 1 MWth

Provincie/ Gemeente

WKK-zuigermotor Provincie/ Gemeente

Kachel Provincie/ Gemeente (< 20 kW)

Kachel Provincie/ Gemeente (> 20 kW)

Verbranden snoeihout/schoon hout

Aansluiting bij NeR F7/ Aansluiting bij NeR F7

Bees A/Aansluiting

bij Bees A3

–/– –/– -/- Aansluiting bij NeR

F7/Aansluiting bij NeR F7

Verbranden vervuild hout en andere afvalstoffen

Bva/Bva Bva/Bva –/– –/– Bva/Bva Bva/Bva

1Voor niet-WKK motoren in vergunning aansluiting zoeken bij Bees. 2 Eventueel andere eisen dan NOx, SO2 en stof op basis van de circulaire. 3 Let op: in specifieke situaties is Bees A niet van toepassing bij minder dan 1500 kg afval per uur (zie Bees A art 1 onder B).

The specific limit values are given in Table 2-3. The standards and procedures for emission measurements are defined in the measurement methods for each regime. The measurement frequency is dependent on fuel, type of installation and present emission reduction measures and is given in Appendix B [Infomil, 2008].

Revision BEES BThe main items in the proposed revision of BEES are that SO2 emission limits are the same for all conversion installations and set at 200 mg/Nm3 (at 6% oxygen) and that fuel, gaseous and liquid, made from biomass are included in this emission regime. For new kettles dust emissions are set at 5 mg/Nm3 (new installations) or 20 mg/Nm3 (existing) for solid and liquid fuels. For gas turbines 5 mg/Nm3 (new) or 30 mg/Nm3 (existing) are proposed.Table 2-2 summarizes the new emission limits for NOx.

Table 2-2 Simplified overview proposed NOx emission limits [Kroon, 2008]Emission limit NOx

Installation Type FuelCurrent in

mg/Nm3Current in

mg/MJProposal in

mg/MJ

Kettle New Solid Biomass - - 35Kettle Existing Solid Biomass - - 35

per 1-1-2015Kettle New Liquid 120 35 35Kettle Existing Liquid 120-450 35-131 35

per 1-1-2015Kettle New Gaseous 70 20 15Kettle Existing Gaseous 70-200 20-58 20

per 1-1-2015Gas turbine New Gaseous / liquid 77 65 30Gas turbine Existing Gaseous / liquid 77-235 65-200 45-65

per 1-1-2015Piston engine New Liquid 464 400 130 and after

six years 40Piston engine Existing Liquid 464-1392 400-1200 400

per 1-1- 2015Piston engine New Gaseous 165 140 30Piston engine Existing Gaseous 165-948 140-800 30

per 1-1-2015

16 ECN-BKM-2008-81

Table 2-3 Summary emission limits for biomass conversion installations in mg/Nm3 [Infomil, 2008; Coenen, 2008; Hesseling, 2008]Waste Combustion White list Combustion PPO Digestion Brick

IndustryCement Industry

Glas industry Small scale combustion of

clean woodRegime BVA BEES A1) BEES B BEES A/B NeR

Brick industryBVA NeR

Glass industryNeR F7

Reference Infomil, 2008 Infomil, 2008

Infomil, 2008 Infimil, 2008 Coenen, 2008 Coenen, 2008 Coenen, 2008 Coenen, 2008 Coenen, 2008 Coenen, 2008 Hesseling, 2008

Hesseling, 2008

Hesseling, 2008

Infomil, 2008

Percentage oxygen

11% 6% solid fuel

3% liquid or gaseous

fuel

6% 6% 6% 6% 3% 3% 3% 3% 10% 8% 11%

Fuel Industrial and municipal

waste

Non-clean biomass

(not biomass as defined in BVA art. 2. 1-5º) 2)

Solid biomass(white list)

Liquid biomass

(white list)

PPO PPO Manure, co-digestion,

100% vegetable digestion

Manure, co-digestion,






Clean wood residues

Configuration/prime mover

Stand alone(Table A)

Co-Firing(Table B)

Boiler Piston engine Piston Engine Gas Turbine + boiler

Boiler Gas Turbine

NOx P > 20 MWth: 200

P < 20 MWth and

efficiency > 40%: 400

P < 20 MWth and

Efficiency < 40%: 200

(100% daily averages)

P > 300 MWth: 200

(M)P < 300

MWth: 100 (M)

P > 500 MWth: 200

300 < P < 500 MWth: 200;

P< 300 MWth: 100

200 (combustion

plant)

120 < 50 kWe: 400 mg/MJ *

1/30 * efficiency> 50 kWe:

1200 mg/MJ * 1/30 *

efficiency

140 mg/GJ *1/30 *

efficiency

65 mg/GJ * 1/30 *

efficiency

70 65 mg/GJ * 1/30 *

efficiency

30/50 mg/m3ind

500 Flat glass: 3.35 kg/ton

Packaging glass: 1.62

kg/tonSpecial glass:

2.54

No limit, unless material is combusted

with more then 80-90%

hardboard: then limit is

400

SO2 50 P > 300 MWth: 200

(M)

P> 300 MWth :200

100 < P < 300: 200

50 < P < 100 MWth: 200

P < 50 MWth: 700

P > 300 MWth: 200;

100 < P < 300 MWth: 400 –

200 linear;50 < p < 100 MWth: 850;

P , <50 MWth: 1700

1700 1700 35 1700 1700 1700 20 mg/m3ind 50 1 kg/ton

NH3

NMVOS

Dust 5 Permit before

15/09/1992: 30;

20 50 < P < 100 MWth: 50

P > 100 MWth: 50

5 5 5 5/20/50 mg/m3ind

15 5-30 P < 0.5 MWth: 100

0.5 < P < 1.5 MWth: 50

17 ECN-BKM-2008-81

Waste Combustion White list Combustion PPO Digestion Brick Industry

Cement Industry

Glas industry Small scale combustion of

clean woodRegime BVA BEES A1) BEES B BEES A/B NeR

Brick industryBVA NeR

Glass industryNeR F7

Other: 20 (M)

< 50 MWth: no limit

1,5 < P < 5.0 MWth: 25

CxHy/TOC 10 (M) 10 P < 1.5 MWth: no limit (but

good requirement of

good combustion)1.5 < P < 5 MWth: 50

CO 50 (M) P < 1.5 Mwth: no limit (but

good requirement of

good combustion)1.5 < P < 5 MWth: 250

PAK No limit (but good

requirement of good

combustion)

HCl 10 30 (M) 30 mg/m3 ind 10 30

HF 1 10 (M) 1 5 (15 for fibre glass)

Hg 0.05 input limit: <10 m%: 0.4 mg/kg

dry>10%:

(3,5/mass%+0.05)

mg/kg dry

0.05

Cd+ Tl 0.05 0.015 0.05

Dioxines and furans

0.1 ng/Nm3 0.1 ng/ Nm3

0.1

Sb,As, Cr, Co, Cu, Pb, Mn, Ni,

V

0.5

Se, Co, As, Ni, Cr (VI)

1

Sb, Pb, Cr (III), Cu. Mn, V, Sn

5

1) Only new permits are shown, higher limits may be applicable for older installations; (M) = mixing rule

18 ECN-BKM-2008-81

3. Costs of Emission Reduction Measures

The cost of reduction measures is dependent of a number of factors e.g. fuel type/composition, type of installation, primary measures taken, scale, retro-fit or new. Table 3-1 shows several reduction measures and their cost for medium scale combustion installations [Meulmans, 2000]. The data presented here are not up-to-date. No specific data on flue gas desulphurisation for small scale was available, as FGD is normally not necessary for biomass application. Further data can be found at Infomil [Infomil, 2008b]. Also estimated cost data and extensive description of NOx and SOx reduction measures are available from EMIS [EMIS, 2002]. These data are listed in Table 3-2 and Table 3-3 and are not specific for biomass applications.

Table 3-1 Overview of specific cost of emission reduction measures for biomass combustion installations at 1 MWth [Meulmans, 2000]

Technology Investment at 1 MWth, 1900

Nm3/hr[kEuro, 2000]

Power Consumption

[kJ/Nm3]

Chemicals Efficiency

Fabric filter 68 2.5 1)

ESP 84 3.0 (99.5% removal)

0 1)

Wet ESP 157 3.0 Water, 4,6 m3/hr 1)

RDS 27 2.2 4,6 m3/hr steam 1)

Cyclone 14 0.75 0 1)

Multi cyclone 27 1.5 0 1)

Ceramic filter 73 2.5 0 1)

Wet scrubber 52 15 0.3 m3 water / Nm3 80% NH3, 5% HCN

SCR 68 1.8 0.5 kg NH3/kg NOx 90% NOx

SNCR 45 0.5 1 mole urea/mole NOx = 55%

2 mole urea/mole NOx = 82%

Dependent of amount of

urea/ammonia

Flue gas recirculation 14 3.0 0 50% dust (also NOx)

Catalytic after burner 4.5 3.6 0 50% dust

Flue gas condensation 68 10% of energy production

0.03 m3 water / Nm3/hr

85% dust

Re-burning 45 0 0 50% NOx

FGD No data1) Depends on particle size distribution

ECN-BKM-2008-81 19

Table 3-2 Estimated NOx reduction costs expressed in Euro/kg NOx removed from flue gas [EMIS, 2002]

Table 3-3 Estimated SOx reduction costs expressed in Euro/kg SOx removed from flue gas [EMIS, 2002]

20 ECN-BKM-2008-81

4. Emission Data per Type of Biomass Conversion Installation

This chapter gives the retrieved emission data for each type of biomass application. Each paragraph gives the available information on the application of biomass fuels, applicable emission regime, emission factors, emission reduction measures, missing data, relevant research and conclusions.

4.1 Coal-fired Power Plants

4.1.1 Use of BiomassIn coal-fired power plants biomass can be co-fired. In the most common application it is directly fired in the boiler without any thermal pre-treatment in existing burners. Biomass is mixed with coal and reduced in size in existing coal mills. The fuel mix (biomass and coal) is burned in conventional burners. Not all biomass fuels are however suitable for this application, mainly due to lack of grindability. Therefore in some power plants the biomass is separately milled and fed to special burners. In both cases all constituents, organic and inorganic, enter the boiler and can influence the quality of fly ash and flue gas. On the long term, a separate conversion step of biomass can be advantageous, especially for specific less clean biomass streams, to separate the coal stream from the biomass stream and prevent influences of the usage of biomass on especially fly ash quality or boiler. This conversion step can be e.g. a separate combustion of gasification step to prevent the entering of biomass ash components in the coal boiler (e.g. Amer power station).

The biomass fuels can range within the whole biomass spectrum, from imported clean wood pellets, to agro-food residues and sewage sludge.

4.1.2 Emission RegimeIn case of clean biomass, the BEES A will be valid. For contaminated waste stream the BVA will be valid. BEES A will put limits on NOx, SOx and dust, while the BVA has a more extended list of emission limits. See Table 2-3 for emission limits.

4.1.3 Emission FactorsThe amounts of contaminants in the flue gas leaving the boiler (before flue gas cleaning) is strongly dependent of the used biomass. The relative amount is however relatively low compared to the amount originating from the combustion of coal. In general biomass fuels are lower in sulphur, nitrogen and ash compared to coal, with exception of specific waste streams. In general there is only limited public data available with respect to actual emissions of coal-fired power stations. Normally there is only officially communicated that the power station complies to the emission regime. The emission data presented here are based on measured values by ECN during several projects. The uncertainty is quite large in the presented data (estimated at 10%) due to the fact during the measuring campaigns it is not communicated by the operators what is exactly the coal mix that they are using. This coal mix can also include scaling and sewage sludge from the waste water treatment plant.

Recent studies suggest that SO2 and NOx emissions are reduced, while particulate emissions may increase slightly but remain within permitted limits [Scotland, 2006]. The sulphur content of woody biomass is lower than for coal and hence a reduction in SO2 emission of boilers can be expected. Many wood biomasses have a lower nitrogen and higher volatile matter content than coal and this is reported to lead to a reduction in NOX formation. Reductions of up to 10% have been reported but are dependent on the biomass and combustion system. No measurement data is available on NMVOS and NH3.

ECN-BKM-2008-81 21

In Table 4-1 the emission factors are shown as measured by ECN during recent campaigns. For the data a fixed LHV of 27 MJ/kg is assumed. The presented emission factors are expressed per MJ of fuel mix.

Table 4-1 Emission factors for fuel mix of pulverized coal-fired installations for direct co-firing (measured and estimated values) [Cieplik, 2008]

Fuel(ratio % w/w)

Country Emission Reduction Measures 2) Emission Factor

[mg/MJ] 7)

NOx (measured) 1,3)

Coal (100%) NL Low-NOx/OFA SCR/ESP/FGD 56.6Coal (100%) NL Low-NOx/OFA SCR/ESP/ROI 127Coals/wood/coffee husk pellets (55/35/10%) NL Low-NOx/OFA /ESP/FGD 99.1

SOx (estimated)Coal (1% w/w sulphur) NL Low-NOx/OFA SCR/ESP/FGD 18.5Coal/wood (60/40 w/w, 1% vs. 0.1% S) NL Low-NOx/OFA/SCR/ESP/FGD 11.8

NH3 (estimated) 4)

Kolen (100%) NL Low-NOx/OFASCR/ESP/FGD 0.27

NMVOSNo data

Dust (measured) 5, 6)

Coal/MBM/wood (90/8/2%) NL Low-NOx/OFA/ESP/FGD 0.3Coal (100%) D Low-NOx/OFA/SCR/ESP/FDG 0.6Coal/sewage sludge (95/5%) D Low-NOx/OFA/SCR/ESP/FGD 0.5Coal (100%) GB 8) ESP 9Coal/grain/residue (93/7%) GB 8) ESP 6Remarks:

1. NOx as NO2. stack emissions after reduction3. with Low-NOx burners i.c.w. OFA 4. stack emissions NH3 estimated at 2 ppm (insiders info), regardless of NOx concentration 5. The definitions of PM10 emissions is here total dust, because the major part of the particles measured after the ESP has

a smaller diameter then 10 μm. 6. The order of magnitude of the dust emissions for coal as well as biomass combustion correspond with the following

relation: (emitted dust %) = (fuel flow)*(fuel ash %)*(fly ash %)*(1-ηESP)*(1- ηFGD). The dust separation efficiencies (η) of the ESP en FGD are respectively 99.7 and 95%.

7. A fixed LHV of 25 MJ/kg is used for conversion from mg/kg to g/GJ.8. Emission standards for installations in UK are less strict then for installations in the Netherlands and Germany.

Ammonia emission factors that are reported in literature [Klimont, 2004] are given in Table 4-2.These numbers indicate a higher emission factor of ammonia if biomass is fired, in contradiction to the lower expected NOx formation. Typically, quoted values for ammonia slip are 5-10 ppm for SCR and 20-30 ppm for SNCR systems.

Table 4-2 Ammonia emission factors for coal and biomass-fired power plants and industrial combustion used in the RAINS model [Klimont, 2004] in mg/MJ

Fuel Old/new installation

No control SCR SNCR

Coal (100%) Old 0.01 6.2 12.6New 0.01 3.1 No data

Biomass (100%) Old 5.0 10.3 20.9New 1.0 5.1 No data

22 ECN-BKM-2008-81

For co-firing by gasification the emission factors estimations are reported [De Wilde, 2006]: 5 gSO2/GJ and 2 g dust/GJ biomass, assuming that the flue gases pass the flue gas cleaning of the power plant.

For power stations only fired on coal the average emission factors for the Netherlands in 2004 is 95 mg/MJ for NOx and 41 mg/MJ SOx. [Seebregts, 2005].

4.1.4 Emission Reduction MeasuresIn general, coal-fired power stations have extensive flue gas cleaning facilities, consisting of (wet) flue gas desulphurization, de-NOx and de-dust (ESP) due to the nature of the combusted coal (high sulphur, high ash) and the combustion conditions. Key issues within the industry are however the decrease of performance of particulate collection systems and SCR systems. The chemical composition of biomass ash differs largely from that of most coals. Some of its components may possibly interact with the SCR catalyst in such a way that the activity of the catalyst may decrease. The elements of concern are mainly phosphorus and (earth)alkalis, however also trace metals (e.g. Zn, Pb) contained in some polluted biomass streams, may be of importance. In a recent in-boiler study undertaken by KEMA within the EC project “Minortop”, several samples of commercial SCR catalysts have been exposed over a period of 14,000 hrs to flue gas of a 600 MWe Dutch power plant, co-firing ~10 % w/w of biomass (a.o. meat-and-bone-meal and wood pellets). The activity of all investigated catalysts decreased, with an average of 17 % (e.g. retaining 87 % of their initial reactivity. For coal-only situation, only a 10 % w/w decrease in reactivity over the same period of time was observed. Due to lack of the suitable data for higher co-firing rates, it is assumed that the decrease of the activity is in linear dependence with the biomass share in the blend. However, the economical repercussions of the said decreased activity in the investigated 600 MWe unit, were estimated to be minor: 30-70 k€/year and ~300 k€/year for 10 and 35 % w/w co-firing. It should also be noted here, that the possible decrease in primary NOx outputs thanks to biomass co-firing have not been taken into consideration in the said investigation.

4.1.5 Current Research“BOFCOM” (EU-RFCS project RFCR-CT-2006-00010): biomass/coal (co-)firing under oxyfuel conditions with the focus on the NOx/SOx and particulate formation and emissions.

“BIOASH” (EU-FP6 project SES6-CT-2003-502679): ash formation and deposition during biomass (co-)firing, with the focus on aerosols emissions and their health aspects.

“BIOMAX” (NL Min. of Econ. Affairs project 2020-01-13-14-013): maximisation of biomass co-firing ratios with the focus on fly ash quality as well as minimisation of the emissions.

“MINORTOP” (EU-RFCS project RFC-PR-02004): NOx emission reduction and operational aspects of coal and biomass co-firing under deep air-staging conditions.

“TOMERED” (EU-FP6 project ENK5-CT-2002-00699): fine particulate matter formation and emissions with the focus on trace elements speciation and emissions, under biomass co-firing conditions.

EOS-LT Biomass co-firing consortium, sub-project “Spoorelementen speciatie” (NL Min. of Econ. Affairs project): fine particulate matter formation and emissions with the focus on trace elements speciation and emissions, under biomass co-firing conditions.

4.1.6 Missing DataThere is data missing on the emission of NH3 and NMVOS.

ECN-BKM-2008-81 23

4.1.7 ConclusionThe effect of the combustion of biomass in coal-fired power plants on emission is expected to be limited due to the composition of the fuel (usually low in sulphur and nitrogen compared to coal) and the extensive flue gas cleaning that is presently installed. For clean, woody biomass NOx (under low-NOx conditions) and SOx emissions are expected to decrease. However there is lack of data on NMVOS and NH3 emissions. NH3 can be of importance in the case of ammoniaslip when using a de-NOx and is reported to be lower compared to coal due to lower NOxformation when firing biomass. However there are contradictions in the literature. Under good combustion conditions the emissions of NMVOS are expected to be low. The emissions are well predictable due to the emission regimes and (mostly continuous) control of emissions. The allocation of emissions is difficult as there can be an interaction between the biomass and coal during combustion, causing non-linear effects.

4.2 Gas-fired Power Plants

4.2.1 Use of BiomassIn the Netherlands there is about 10 GWe of installed capacity in natural gas-fired power stations. Biomass firing can be done in two ways: a) firing on a steam boiler or b) firing on a gasturbine. Both can be done with bio-oil or gas from biomass gasification as long as the installation specifications allow it. Only firing on a steam boiler with bio-oil is currently done in the Netherlands (Harculo power station, 350 MWe, Electrabel and Claus power station (low NOxburners), 1280MWe, Essent).

In gas-fired power plants biomass fuels mainly vegetable oils (palm oil) are used. Only data on standard steam boilers was available. In 2004 0.4 PJ of oil was fired in the Harculo power station and 3.1 PJ in the Claus power station.

4.2.2 Emission RegimeIn case of clean biomass, the BEES A will be valid. For contaminated waste stream the BVA will be valid. BEES A will put limits on NOx, SOx and dust, while the BVA has a more extended list of emission limits. See Table 2-3 for the values.

4.2.3 Emission FactorsTable 4-3 shows the available emission factors on gas-fired power stations.

Table 4-3 Measured and reported emission factors gas-fired power station with no gas cleaning

Reference Data type

NOx[mg/MJ]

SOx[mg/MJ]

NH3[mg/MJ]

NMVOS[mg/MJ]

Dust (PM10)

[mg/MJ]Oil (palm) Seebregts,

2005Measured 66.5 4.4 No data No data 12.2

Oil (palm)/gas (70/30)

Seebregts, 2005

Measured 53.8 2.6 No data No data 7.2

Remarks: From conversion from mg/kg to mg/MJ a fixed LHV of 39 MJ/kg is assumed, NOx as NO, Stack emissions

For power stations only fired on natural gas the average emission factors for the Netherlands in 2004 is 46 mg/MJ for NOx and 1 mg/MJ SOx [Seebregts, 2005]. The dust emission appears to be relatively high compared to coal-fired power plants.

24 ECN-BKM-2008-81

4.2.4 Emission Reduction MeasuresLow-NOx burners are installed to reduce NOx emissions when firing on natural gas. Currently no dust removal technologies (ESP, bag house filters) are installed, but technically it should be possible to install this.

4.2.5 Current ResearchECN: no specific projectsTNO: -

4.2.6 Missing DataNo data is available on NH3 and NMVOS.

4.2.7 ConclusionsDue to the limited amount of data, it is difficult to have a good prediction of the influence of firing biomass in gas-fired power stations. The expectation is however that the emissions are well predictable and controllable as a result of the emission regime. As relatively clean biomass is used as fuel, influences on emissions are expected to be minor, but dust emissions appear to be relatively high compared to coal-fired power plants.

4.3 Waste Incinerators

4.3.1 Use of BiomassIn the Netherlands 11 waste to energy plants are in operation. Together they have a capacity of ca 5.5 million tonnes of waste a year (2005). In 2004 these plants produced 3.100 GWh ofelectricity and 979 GWh (=3.5 PJ) of heat. Some additional lines were commissioned since 2004.

Only part of the fuel of waste incinerators is considered as renewable. The fraction renewable is around half of the total fuel.

4.3.2 Emission RegimeThe BVA is valid. See Table 2-3 for the emissions limits.

4.3.3 Emission Reduction MeasuresMeasures can be taken in the combustion zone to improve residence time, combustion temperature and mixing of the flue gasses (integrated process optimization) with several technologies, like flue gas recirculation (NOx-reduction), staged combustion (NOx-reduction), air preheating, advanced furnace geometry etc.

Additional there are typically many end of pipe processes to reduce emissions to the permit levels. The waste incinerators have the strictest limits and therefore the best flue gas cleaning systems available. In the plants, the flue gas treatment sections use more space than the combustion section. A short overview of these processes is:

Wet process Semi wet process Dry process

Several techniques within these processes can be combined to other complete flue gas treatment systems.

ECN-BKM-2008-81 25

4.3.4 Emission FactorsIn Table 4-4 estimates on emission factors are presented. These numbers refer to the stack emissions.

Table 4-4 Estimated emission factors in mg/MJ of Dutch Waste to Energy PlantsPollutant NOx SO2 VOC NH3 DustEmission Factor 35.0 1.7 0.9 0.9 0.5

The numbers apply to the total input of waste. There is no effort done to attribute specific emissions to specific fractions of the input waste.

The factors are based on the following references: Environmental annual reports of several Dutch plants, Dutch “Emissieregistratie”, and Information of Dutch Waste Association

4.3.5 Current ResearchECN: Research focuses on ash quality, corrosion and fouling. Flue gas compositions are

included in this research but typically provided by the installation owners. TNO: No information received.

4.3.6 Missing DataAll emission data of waste incineration plants are known and public. Missing are:

separation of VOC into methane and non-methane-VOC split of dust between PM10 and other dust

In addition, it could become relevant to attribute certain emissions to certain fractions of the input waste. However, since the flue gas composition is determined by the emission control measures this is perhaps not a sensible issue to pursue.

4.3.7 ConclusionsWaste incineration is among the most closely watched thermal processes. The following can be concluded about their emissions:

The emissions, both volume and composition, are highly predictable and can be expected to comply with BVA limits. This not only applies to the 11 big installations, but also to special waste incinerations, e.g. hospital waste (ZAVIN in Dordrecht) and rendering plants (Rendac in Son).

Waste incineration without emission measures and outside the BVA regulations is not allowed.

As a result of the transition from fossil fuels to biomass fuels, the operation and emissions of waste incineration plants are not likely to change. Emission factors can be safely applied to the coming decades. Possibly, the fraction renewable will slowly increase in the waste, but this cannot be responsible for any significant change in emission factors.

26 ECN-BKM-2008-81

4.4 Sewage Sludge Incinerators

4.4.1 Use of BiomassIn the Netherlands, there are two sewage sludge incinerators: SNB (Moerdijk) and DRSH (Dordrecht). These installations process about half of the sewage sludge produced in the Netherlands (about 1.5 million ton dewatered sludge).2 Initially, the sludge contains about 25% dry matter and is dried up to 55% dry matter before it is introduced into the boiler. The dried sewage sludge is combusted in fluidized beds to produce steam. The steam is mainly used to dry the wet sludge, a small amount of the energy is used to produce electricity in a steam engine. Some natural gas (2%) is used during the process. The installations are equipped with advanced flue gas cleaning systems.

4.4.2 Emission RegimeThe sludge incinerators must comply with the BVA regulations. For emission limits, see Table2-3.

4.4.3 Emission FactorsIn Table 4-5, NEC emission factors are listed. The calculation is done by dividing the annual loads of the NEC emissions by the energy content of the annual input (dry sludge and 2% natural gas). The numbers are the average of the two installations. The sludge granulates combusted elsewhere is not taken into account

Table 4-5 Emission factors for sewage sludge combustion in mg/MJ fuel (dry sludge and 2% natural gas

Pollutant NOx SO2 VOS NH3 dustAverage Emission Factor 22.6 2.0 0.6 2.5 1.2

Information is obtained from the web sites of the incinerator operators [DRSH, 2008; SNB, 2008].

4.4.4 Emission Reduction MeasuresThe incineration is done in bubbling fluidized bed, which ensures a low NOx formation and good burnout. The sludge incinerators are equipped with a complete train of flue gas cleaning equipment, including ESP filters, de-NOx and activated carbon beds.

4.4.5 Current ResearchECN: no current researchTNO: no information received

4.4.6 Missing DataAll emission data of sludge incineration plants are known and public. Missing are:

separation of VOC into methane and non-methane-VOC split of dust between PM10 and other dust

4.4.7 ConclusionsSludge incineration is among the most closely watched thermal processes. The following can be concluded about their emissions:

The emissions, both volume and composition, are highly predictable and can be expected to comply with BVA limits.

2 The other half is dried to sludge granulates, which are used in cement kilns (ENCI) or fired in German power plants.

ECN-BKM-2008-81 27

As a result of the transition from fossil fuels to biomass fuels, the operation and emissions of sludge incineration plants are not likely to change. Emission factors can be safely applied to the coming decades.

4.5 Cement Kilns

4.5.1 Use of Biomass For a great part, the Dutch cement industry has already switched to non-fossil fuels and emissions are regulated. It is not expected that the volume of non-fossil fuels will change. The largest cement production facility is the ECNI in Maastricht. The same company has smaller installations in Rotterdam and IJmuiden. The ENCI uses at the moment also pulverized brown coal and natural gas (10% of total). The intention is to stop using brown coal and to minimize the amount of natural gas. A number of alternative fuels (wastes) are used to provide the process with heat. Part of these fuels can be characterized as non-fossil, e.g. sewage sludge, paper sludge, MBM, PPDF sludge (a mixture of paper and plastic). The percentage renewable is 47% in 2006.

4.5.2 Emission RegimeThe BVA will be valid (Table C). See Table 2-3 for emission limits.

4.5.3 Emission FactorsDuring cement production the main emissions are not originating from the fuels:

NOx is mainly formed from the nitrogen in the air (thermal NOx). The SO2 is coming from the raw material (pyrite). The sulphur from the fuels is bound

by the fuel (Ca- rich) The TOC (represented as CH4) originates from the organic components in the raw

material (mainly ‘mergel’). The organic component in the fuel combusts completely. The ammonia is coming from the de-NOx installation. The ammonia does not react

completely with the NOx. The dust is coming form the dry ‘mergel’ from the drying with a small amount of

recirculation dust from the oven.

It can therefore be misleading to present these emissions per MJ of fuel input. Table 4-6 shows the emission data for the fuel mix made available by the ENCI [ENCI, 2007].

Table 4-6 Emission data from ENCI [ENCI, 2007]Component Total emissions per year

[ton/year]Emission factor (including fossil)

[mg/MJ LHV wetNOx 1.293 416SO2 368 118NH3 78 25TOC (as CH4) 36 12NMVOS No data No dataDust 16 5.2

4.5.4 Emission Reduction MeasuresAt the ENCI Maastricht dust removal has been installed.

4.5.5 Missing DataThere is no data available on NMVOS and NH3.

28 ECN-BKM-2008-81

4.5.6 Current ResearchTNO: process optimizationECN: none

4.5.7 ConclusionsA maximum of alternative fuels is already used (90%) of which almost half is renewable. Allocation of emissions is however difficult as the cement also contributes to the emissions. As the amount of the use of biomass fuels is not expected to change, large effects on additional emissions of originating from biomass fuels are not foreseen.

4.6 Glass Industry

4.6.1 Use of BiomassIn the Netherlands about twenty-five glass furnaces are in operation. They produce around 1.6 million ton molten glass per annum. There are several types of ovens operation:

Oxyfuel (oxygen enriched air with 92-99.9% oxygen instead of air) Regenerative ovens (heat exchanger with refractory) Recuperative ovens (metal heat exchanger for air and flue gas)

For melting the glass in the Netherlands 92% of all energy is obtained by combusting natural gas. The remaining 4% is coming from the combustion of low-sulphur oil and electrical heating.

The use of biomass in the glass sector is not foreseen. The sector is expecting a deterioration of the product quality.

4.6.2 Emission RegimeThe NeR is valid, see Table 2-3 for the emissions limits.

4.6.3 Emission FactorsThe most important emissions of the glass industry are:

NOx (high flame temperature above the glass bath) SO2 (from glass batch, and sometimes fuel oil) Dust (by evaporation from melt and condensation of flue gases Also metals and CO, depending on the kind of glass

Typical emission factors for NOx, SOx, CxHy (VOS), NH3 and PM10 in the glass industry, converted into MJ input fuel, are given in Table 4-7. The data is originating from TNO measurements and benchmarks studies on the energy consumption of glass oven [Hesseling, 2008a].

Table 4-7 Typical emissions in g/MJ (or mg/MJ) fuel input for the glass industry (fossil emissions)

Process/product

NOx

[mg/MJ]SOx

[mg/MJ]CxHy (VOS) NH3 PM10

[mg/MJ]flat 710 220 nihil nihil 0.4-2package 310 190 nihil nihil 1-8special 390 200 nihil nihil 5-20

ECN-BKM-2008-81 29

4.6.4 Emission Reduction MeasuresSeveral methods for reducing emissions are used. They can be divided into process integrated and flue gas technologies:

Process integrated: Oxyfuel Low NOx design of the oven Use of gas instead of fuel oil (with sulphur) Less sulphate additions

Flue gas technologies Dry scrubber (removal of SO2, HCl, HF, SO2) ESP Wet scrubber Fabric filter Semi dry scrubber with fabric filter SCR (Selective Catalytic Reduction) has not been applied in the Dutch glass industry.

4.6.5 Current ResearchTNO: process optimization, emission reduction and energy saving ECN: no research

4.6.6 Missing DataNot relevant, as no use of biomass is foreseen.

4.6.7 ConclusionAs no biomass usage is presently taken place or foreseen, the evaluating the use of biomass is not interesting from emission point of view.

4.7 Brick Industry

4.7.1 Use of Biomass FuelsIt is expected that the brick industry will not use bio-fuels in the future. The branch fears a negative influence on the quality (colour) of the bricks.

4.7.2 Emission RegimeThe NeR is applicable for the brick industry. See Table 2-3 for the limits.

4.7.3 Emission FactorsAccording IPPC [IPPC, 2006] the specific energy use per kg brick should be 3,35 MJ/kg (2003), which is considered to be very high . The specific emission factors mentioned in the IPPC are presented in Table 4-8.

Table 4-8 Estimated Emission factors in mg/MJ of Dutch brick industry [IPPC, 2006]Brick Industry NOx SO2 VOC *) NH3 DustEmission Factor 54.9 11.8 10.3 0.0 5.3*) Volatile Organic Compounds

30 ECN-BKM-2008-81

4.7.4 Emission Reduction MeasuresIn the heating zone of the raw material a lot of sulphur and fluor in the flue gases is captured by the limestone in the raw material (clay). With several technologies this process is stimulated like flue gas recirculation and smart brick configuration. With these measures a lot of emission reduction can be performed (integrated process optimization). NOx emission reduction is in practice obtained by reducing the average flame temperatures by staged combustion.

End of pipe technologies reducing emission levelsMost big tunnel kilns are equipped with a limestone reactor (kalk split reactor). This reactor consists of a big layer of limestone pellets to clean the flue gasses of the tunnel kiln. Flue gas components like SO2 en HF, SO2 en HCl are captured by the limestone and chemical converted to CaF2, CaSO4 en CaCl. These pellets are constantly refreshed and for the largest part pre-treated for use in the raw material. As mentioned before this reactor causes dust emissions higher than 5 mg/m3.

The NOx and SO2 emission guidelines are very stringent to the Dutch Brick Industry. The most common technology for the brick industry is tunnel kilns. They are mostly fired with natural gas, resulting in NOx emissions. The raw materials of the brick industry contain sulphur and fluor resulting in emissions of SOx and HF. The raw materials like clay are normally bought in batches. This means in practice that the companies have to select the batches, based on composition. A high level of sulphur and fluor will lead to problems with emission levels and environmental permits. Dust emissions are mainly formed in raw material handling units and preparation processes and the firing process. The typical dust emission levels after tunnel kilns are just above approx. 5 mg/Nm3 and are mainly caused by the limestone in the Crust Lime reactor (kalksplit installatie), also used to clean the flue gasses.

4.7.5 Current ResearchNot relevant as no biomass use is foreseen.

4.7.6 Missing DataNot relevant as no biomass use is foreseen.

4.7.7 ConclusionsAs no biomass usage is presently taken place or foreseen, the evaluating the emission of additional use of biomass is not interesting from emission point of view.

4.8 Medium Scale Biomass Conversion Installations in the Energy Sector and Industry (> 20 MW th)

4.8.1 Use of BiomassThe medium scale biomass installations are smaller than the full-size power plants, but still large enough to play a role in emission trading and to be included in the emission registration (Emissieregistratie). This category (over 20 MWth) includes only a limited number of installations today. Rapid developments are taking place and soon a substantial number of installations will be available. At HVC Alkmaar, Twence Hengelo, AVR Rozenburg and DEP Moerdijk installations are being built or have just become operational for a total of 80 MWe. There are serious plans for more plants, in total up to 300 MWe.

Installation owners are reluctant to provide information that can be traced back to their installations. In particular, those who are just in operation do not want to get numbers out before they are confident that these are reliable and representative for their installation. The reliability of these numbers will become better when they are operating for multiple years. The fact that

ECN-BKM-2008-81 31

these installations have to report their emissions to the Emissieregistratie makes it easier to determine emission factors, but it still requires a tedious process of getting data from different sources and verifying that these numbers are reliable and representative.

The installations use mainly clean wood chips and demolition wood as a fuel.

In this chapter, two biomass-installations Dutch installations are presented:

BEC Cuijk; Co-firing of spent coffee grinds and natural gas at SaraLee/DE.

In addition international data has been compiled.

4.8.2 Emission RegimeIn the case of waste combustion the BVA will apply. In other cases BEES A/B will apply.

4.8.3 Emission factors

For ammonia emission factors for biomass combustion is referred to Table 4-2.

BEC CuijkThe best-known stand-alone biomass installation of the Netherlands is the Biomassa Energiecentrale BEC Cuijk, where clean biomass is combusted (85 MWth) in a bubbling fluidized bed (BFB) for the production of electricity (24 MWe). The BEC Cuijk has a flue gas cleaning system composed of an electrostatic precipitator (ESP) and de-NOx by means of ammonia injection and catalyst (SCR). Emission factors can be calculated using the annual environmental report (Essent, 2005). Values are given in Table 4-9.

Table 4-9 Emission factors BEC Cuijck (24 MWee) in mg/MJSO2 NOx Dust0.3 48 3.1

Source: ECN report ECN-C--06-010

The emission factor of SO2 varies between 0 and 2 mg/MJ. This is caused by the fluctuations of the sulphur content of the fuel. Typically, woody clean biomass has a very low sulphur content, which results in the often registered 0 mg/MJ. Occasionally, other clean fuels are used resulting in much higher emission factors. The highest reported value was about 6 mg/MJ.

The emission factor for ammonia (NH3) has not been determined. It can be expected to be small and representative for installations equipped with SCR with some ammonia slip. Emissions of volatile organic components can also be expected to be small.

The BEC Cuijk can be regarded as a good example of the mid-sized installations that will be built in the coming decades. The only major reservation is that it is fired with domestic clean wood, while the supply of this fuel is limited. Similar installations are likely to be fired using imported wood chips (of a more constant quality than the fuel of BEC Cuijk) or with waste materials (waste wood, demolition wood or agricultural waste products). It is unclear what the consequences are for the primary formation of NEC emissions. However, it is most likely that the stack emissions will be determined by the flue gas cleaning system.

32 ECN-BKM-2008-81

Sara Lee / DE In Joure, Sara Lee / DE operates a 8 MWth installation that fires spent coffee grinds together with some natural gas. The emission factors of this installation are presented in Table 4-10. Emissions of SOx, ammonia, dust (PM10) and NMVOS have not been reported. The NOxmeasurements have been done according to NEN-ISO 10849. De CxHy was done according to NEN-EN 12619.

Table 4-10 Emission factors of coffee grind installation Sara LeePollutant Value

[mg/MJ]NOx as NO2 228CxHy as C (VOS) 1.5Source: memo ECN, 29/2/2008

Two Scottish installationsIn Scotland, two plants with an electrical output of 40-50 MWe are under construction (Lockerbie) or in planning (Tullis Russell). These combustion plant installations are larger than 50 MWth (typically larger than 15 MWe power generation) and fall within the scope of IPPC regulations. The emission factors are given in Table 4-11. The Scottish expect that actual emissions are lower than the benchmark emission limits. The emission value of NH3 seems to low compared to the value given in Table 4-2, which is a factor five higher.

Table 4-11 Summary of emission factors for large (over 50 MWth) bio-electricity plants in mg/MJ [Scotland, 2006]

Pollutant ValuePM 7.2NOx 72SO2 108CO 9.0VOC 1.8N2O 43 (fluidized bed plant)NH3 1.8 (only when SRC is used)

Other installationsIn a reference document of the IPPC [IPPC, 2005], emissions of two boilers (45 MWth) are listed, fired with waste wood from a chip board manufacturer, see Table 4-12. The installations are equipped with pulsing bag filters. The steam is partially used to make electricity. The same document also lists emission factors from combustion of straw. See

ECN-BKM-2008-81 33

Table 4-13.

In Table 4-14, emission data of the Värnamo Project (Babu, 2002) are cited, a small van 18 MWth gasifier. The technology quoted in this option is a circulating fluidized bed gasifier in combination with an IGCC. Since, these installations are still under development; emission numbers of the other emissions are not available.

Table 4-12 Emission factors of combustion of waste wood in 45 MWth installation in mg/MJ [IPPC, 2005]

Pollutants Valuedust 1.1SO2 0.9NOx 91.3CO 59.0Source: ECN report ECN-C--06-010

34 ECN-BKM-2008-81

Table 4-13 Emission factors (mg/MJ) of straw fired installations in the range 50-70 MWth

[IPPC, 2005]Capacity 13 MWth 21 MWth 20 MWth

Filter Baghouse ESP Baghouse13 21 20

CO 65 24 17107 81 73

Dust 4.8 7.1 0.24.8 9.5 0.7

NOx 180 111 84219 151 108

SO2 53 45 5457 56 65

Source: ECN report ECN-C--06-010

Table 4-14 Emission factors of CFB biomass gasifier with IGCC (in mg/MJ; presumed 6% O2) of 18 MWth

Low High AverageNOx 34 87 60.5SO2 5 10 7.5CO 20 80 50CH 0 1 0,5Dust 0 2 1Source: ECN report ECN-C--06-010

4.8.4 Gas cleaningAll common flue emissions reduction measures can be applied (de-dust, de-NOx).

4.8.5 Current ResearchECM: No specific current research is undertaken in this field by ECN.TNO: -

4.8.6 Missing DataMissing data include:

In many cases, emissions of VOC and ammonia are missing. If they are not mandatory they are typically not available. Often the measurements have not been done at all.

Reports do not separate VOC into methane and non-methane-VOC. Reports do not split dust between PM10 and other dust. Data from more than one plant in the Netherland are missing. In particular, emissions

from the newly built installations using demolition wood are missing. The overall problem is the large variety of installations and the large variation of fuels

that is used. Not only between plants, but also from day to day in one plant. An additional problem is that based on the fuel source “witte lijst” versus “gele lijst”,

flue gas treatment is mandatory, while some “witte lijst” may contain considerable amounts of sulphur. This issue is very well visible in the emission data of the BEC Cuijk.

Very limited data on NH3.

4.8.7 Conclusions The medium-scale biomass combustion installations are represented with a large variety

of techniques, each having its own characteristic set of emissions. Overall numbers may be calculated by using averages, but you can question yourself

why this is useful. These installations have to comply with emission limits (BVA and BEES) so the emissions are predictable.

ECN-BKM-2008-81 35

When the objective is to create policies besides imposing emission limits, it would be much more useful to have emission factors per technology (installation type).

The number of installations in the Netherlands is relatively small and when the installation type or the power (MW) is listed, it becomes easy to identify individual plants. Cooperation that goes beyond mandatory data (Emissieregistratie) becomes increasingly difficult.

With the rapid growth of the number of stand alone installations (400 MWe in planning) that combust biomass for power and heat, more emission data will become available. The data will become more reliable when these installations are in operation for multiple years.

General observationThere are large differences between the emission factors of the installations. Partly these are due to the fuel composition, partly due to the installation type. Also, the presence or absence of flue gas cleaning has a large impact. E.g., PM10 emissions for small wood furnaces vary from 2 to over 100 mg/MJ. It would be too short sighted to adopt a default average value of 10-20 mg/MJ without knowing the exact installation type and the fuel used. When they are fired using straw, the dust emissions are typically 100 tot 150 mg/MJ. Also NOx emissions are much higher for straw fired installations.

The Handbook of Biomass Combustion [Van Loo, 2002] contains a table with emissions for domestic and industrial emission installations, reproduced in Table 4-15. It is unclear to which size range these numbers apply, but given the description of the techniques, it should be fairly large installations. This table mainly illustrates the enormous effect on the installation type on emission factors.

Table 4-15 Average values industrial combustion installations from IEA countries (Norway, Switzerland, Finland, UK and Denmark) [Skreiberg, 1994]

NOx as NO2

[mg/MJ]

SOx

[mg/MJ]VOC

[mg/MJ]NH3

[mg/MJ]Particles[mg/MJ]

CO[mg/MJ]

UHC as CH4

[mg/MJ]

PAH[μg/MJ]

Cyclone furnaces 333 No data 2.1 No data 59 38 No data No dataFluidised bed boilers

170 No data No data No data 2 0 1 4

Pulverized fuel burners

69 No data No data No data 86 164 8 22

Grate plants 111 No data No data No data 122 1846 67 4040

The general conclusion is that in this category, medium-sized installations, the diversity is too high to calculate generalized emission factors but maximum factors are set by the emission regime.

4.9 Small-scale (Industrial) Installations (<20 MWth)

4.9.1 Use of BiomassThis category contains a large range of installation ranging from stoves of several kWth range to several tens of MWth scale for heat and at a larger scale also power production. Their main application is in the wood processing industry (wood, cork and reed processing and furniture industry) for the combustion of waste material. The operation of such installations is usually not the core-business of the operators.Also diesel engines running on PPO are within this category. These are considered as a special sub-category and can exist of several parallel engines with steam cycle. For usage in maritime diesel engines good palm oil is necessary and phosphor has to be removed, which is important for NOx-removal [De Wilde, 2006].

36 ECN-BKM-2008-81

4.9.2 Emission RegimeFor small scale combustion installations it will depend on the kind of material (white list vs. yellow list) that is combusted, size and authority (province or municipality). Small scale combustion of clean wood will have the NeR F7 applicable (< 5 MWth) and limits are set within the NeR F7 on NOx and SOx. Only larger installations will fall under BEES-A (>1500 kg/hr of waste wood) or BVA regime (waste, non-white list). For (clean, not contaminated with fossil oil) PPO-fired diesel engines the BEES A/B will be applicable. Clean wood boilers are currently not covered within the BEES-B, but in the upcoming revision this they will probably be.

4.9.3 Emission FactorsSmall-Scale Biomass Combustion InstallationsThis category is characterized by a large diversity in fuel, combustion and gas cleaning technology, scale and age of technology. In general the available data is not of recent date. Emissions of NMVOC, total organic carbon (TOC) and particulate matter from modern wood boilers and pellet burners for example can be over 100 times lower than for old low-efficiency residential heating systems [Johansson, 2004]. The emission factors therefore show a large bandwidth. In Table 4-16 to Table 4-22 data of this category is listed. The amount of data is quite extensive, but the interpretation is difficult as the background (fuel, specific process, operating conditions, flue gas cleaning, etc., etc.) of the data is in most cases unknown. Because the diversity of this category, all available data is presented in the tables below to give an impression of the range of emission factors related to the type of installations that can be expected. A distinction is made between Dutch data and international data.

Dutch DataTable 4-16 presents Dutch data on small industrial wood chips combustion.

Table 4-16 Emissions from small industrial wood chips combustion applications in the Netherlands range 30 to 320 kWth on wood chips [Sulilatu, 1992]

Manual/ automatic operation

Combustion Principle

Draught Control

Cap.[kW]

NOx[mg/MJ]

SO2[mg/MJ]

NH3[mg/MJ]

CxHy[mg/MJ]

CO[mg/MJ]

Dust[mg/MJ]

Efficiency[%]

Natural, uncontrolled 36 68 No data No data 54 1041 9 85

34.6 75 No data No data 57 1503 13 83.5Manually Horizontal grate Forced,

uncontrolled 30 79 No data No data 9 286 145 90

40 52 No data No data 1 29 35 85.4Automat.

operatedUnderstoker Forced,

controlled 320 81 No data No data 2 14 22 89.1

Remarks: assumptions: 7.8 Nm3 flue gas per kg wet fuel at 11% O2, fuel moisture content of 20 wt% on wet basis, LHV of 14.4 MJ/kgwet

Table 4-17 shows the emissions of the combustion installation in Schijndel, operating on wood residues. The installation has an ESP to remove dust and secondary air to minimize emissions.

Table 4-17 Emission data from the wood combustion installation in Schijndel [De Vries, 1999]Pollutants[mg/MJ_LHV_wet]

Permit Contract Measurement at nominal capacity (1 MWe)

Measurement at peak capacity (1.1 MWe)

NOx <170 <68 38 66SO2 No data No data No data No dataCxHy <34 <34 <1.4 <1.4NH3 No data No data No data No dataCO <272 <272 176 183Dust <17 <17 5.4 6.1Remarks: assumptions: 4.9 Nm3

dry flue gas per kg wet fuel at 11% O2, fuel moisture content of 50 wt% on wet basis, LHV of 8 MJ/kgwet

ECN-BKM-2008-81 37

International DataFor domestic and residential combustion ammonia emission factors are reported to be between 5.0 and 9.1 mg/MJ [Klimont, 2004]. Table 4-18 to Table 4-22 show the available international data on emissions factors for small and scale biomass applications.

Table 4-18 Average values both domestic and industrial combustion installations from IEA countries (Norway, Switzerland, Finland, UK and Denmark) [Skreiberg, 1994]NOx as

NO2[mg/MJ]

SOx

[mg/MJ]VOC

[mg/MJ]NH3

[mg/MJ]Particles[mg/MJ]

Tar[mg/MJ]

CO[mg/MJ]

UHC as CH4

[mg/MJ]

PAH[μg/MJ]

Stoker burners 98 No data No data No data 59 No data 457 4 9

Wood boilers 101 No data No data No data No data 499 4975 1330 30

Modern wood-stoves

58 No data No data No data 98 66 1730 200 26

Traditional wood-stoves

29 No data 671 No data 1921 1842 6956 1750 3445

Fireplaces No data No data 520 No data 6053 4211 6716 105

Table 4-19 Emission ranges from industrial installations fired particle board, wood chips, MDF and bark [Obernberger, 1997]

Pollutants Emission range[mg/MJ]

Number of observations

Min Max UnknownNOx 88 184 4SO2 10 41 UnknownNH3 No data No dataCxHy 3 7 25CO 68 1090 25PAH 0.00003 0.03 UnknownParticles 20 170 22Cl 0.5 5.4 12F 0.1 0.1 UnknownRemarks: assumptions: 7.8 Nm3

dry flue gas per kg wet fuel, fuel moisture content of 20 wt% on wet basis, LHV of 14.4 MJ/kgwet

Table 4-20 shows the results of a measurement campaign in the wood industry during the period 1994-1998 in Belgium. Except for dust removal, no further gas cleaning was installed.

Table 4-20 Emission data of wood industry in Belgium [VITO, 2001]Pollutant[mg/MJ_LHVwet]

Treated wood, not dangerous Untreated wood residues

NOx 260 420SO2 43 37NH3 No data No dataNMVOS No data No dataDust 141 150CO 870 520PCDD/F 1.3 0.20HCL 1.3 0.1HF 0.8 0.5Remarks: assumptions: 7.8 Nm3 flue gas per kg wet fuel, fuel moisture content of 20 wt% on wet basis, LHV of 14.4 MJ/kgwet

38 ECN-BKM-2008-81

Table 4-21 shows the default emission factors for wood combustion as used in the Corinair program for different types of installations.

Table 4-21 Summary of Corinair default emission factors for advanced wood combustion technologies [Scotland, 2006]

Emission factors, mg/MJPollutantsAdvanced

stovePellet stove

Manual boiler

Automatic boiler

Aggregate factor

SO2 30 30 30 30 30NOX (as NO2 ) 150 150 150 150 150PM 450 130 250 80 122PM10 400 120 230 70 108PM2.5 400 120 230 70 108CO 3000 500 3000 300 590NMVOC 250 20 250 20 43

mg GJ-1

As 0.5 0.5 1 0.5 0.5Cd 1 0.5 0.3 0.5 0.55Cr 8 3 2 4 4.3Cu 2 1 3 2 1.9Hg 0.5 0.5 1 0.5 0.5Ni 2 2 200 2 2Pb 30 20 10 20 21Se 0.5 - - - 0.05Zn 80 80 5 80 80PAH 400 50 150 40 77

ITEQ ng/ GJPCDD/F 300 50 300 50 75

%Fuel use for aggregate factor, %

10 10 0 80 100

Table 4-22 shows emission factors used in European emission inventarisations. In the reference is however not defined which European inventarisation.

Table 4-22 Emissions factors (mg/MJ) for wood and other solid biofuels in stoves, small boilers and small commercial installations [De Wilde, 2006]

Pollutants Build environment

Stoves in household

Biolers in household <

50 kWth

Boilers50 kWth –1 MWth

Biolers1 MWth-50 MWth

Small commercial installations

NOx 80 50 150 150 150 150SO2 20 10 50 50 30 40NH3 No data No data No data No data No data No dataNMVOS No data No data No data No data No data No dataDust 800 900 500 250 50 200PM10 700 800 440 220 40 180PM2,5 700 800 440 220 40 180

Table 4-23 shows some typical emission factor for wood chip firing for district heating applications. It is reported that the figures vary very much in practice, even beyond the numbers listed in this table [Videncenter, 1999].

Table 4-23 Typical emission factors for wood chip firing for district heating [Videncenter, 1999]

Pollutant Unit Typical Value Typical VariationsSOxas SO2 mg/MJ 15 5-30NOx as NO2 mg/MJ 90 40-140Dust, multicylcone mg/Nm3 300 200-400Dust, flue gas condensation mg/Nm3 50 20-90

ECN-BKM-2008-81 39

PPO-fired diesel engines Table 4-24 shows the emission factors for several engines on PPO. The observed NOx emissions are relatively high.

Table 4-24 Emission factors for diesel engines on PPOPower[kWe]

Reference NOx[mg/MJ]

SOx[mg/MJ]

NH3[mg/MJ]

NMVOS[mg/MJ]

CxHy[mg/MJ]

Dust[mg/MJ]

Engine 1 110 De Wilde, 2006

912 No data No data No data 4 25


1024 No data No data No data 8 29


632 No data No data No data 1.4 29

Engine 4 300 Van der Linden,

2008

22821) No data No data No data No data No data

1) Emission limit according to BEES B: 524 mg/MJ, no gas cleaning present

4.9.4 Reduction Measures

Small-Scale Biomass Combustion InstallationsA large number of gas cleaning technologies is available for the components that can be present in the flue gas. The amount of contaminants will be dependent on a) the fuel composition (of even compositions if more than one fuel is used, b) the conversion technology, c) operating conditions, including taking primary measures. The choice of gas cleaning technology will depend on these factors and the required emission limits. Combustion installations above 4 MWth often have ESP’s or flue gas condensation installations (abroad) in addition to a cyclone, common to smaller installations. To meet the proposed NOx limits of 35 mg/MJ in the revisedBEES B [Kroon, 2008] it will be necessary to install an SCR.

PPO-Fired Diesel EnginesAn ESP or soot filter can be installed for dust removal for these types of engines. A de-NOx will be necessary for prevent NOx emissions.

4.9.5 Current ResearchECN: no current researchTNO: unknown

4.9.6 Missing DataPublic emission data is scarce and at least several years old. Most data is obtained from literature and it not possible to track the origin of the data. It is therefore not easy to judge if the presented data is representative for the Dutch situation. Missing information:

Up-to-date emission data with full set of back ground data (fuel, composition, moisture content, installation type, way of operating, emission reduction measures, age, and scale).

Emission data on NMVOS and NH3, subdivision of dust. Background and of emission data and if they are representative for the Dutch situation.

4.9.7 ConclusionsThe category described in this paragraph is special interest because it contain small scale installation with a limited - and often less stringent - emission limits, no or limited gas cleaning and less emission monitoring and enforceability. From the presented data it is clear that the band width is large. For solid biomass combustion NOx concentrations from 29 to 420 mg/MJ are reported, for SOx this is 10-50 mg/MJ and dust 6-170 mg/MJ. For NMVOS little data is

40 ECN-BKM-2008-81

available. Factors are reported from 20-250 mg/MJ, but these are default values of Corinair, and it is unknown if these numbers are based are measurements or estimations. To meet the new BEES B limits on NOx a de-NOx (SCR) will be necessary. If emissions will change if biomass is used will strongly depend on the fuel that is substituted. Increasing emissions are to be expected if natural gas is replaced by biomass.

4.10 Digesters with Boiler or Gas Engine

4.10.1 Use of BiomassA small contribution to the use of biomass comes from digesters. There are about 64 digesters in the Netherlands [SenterNovem, 2007]. Most of them are small (< 1 MWth); the largest is about 5 MWth. In the digesters, microbial processes convert wet organic material, like manure, sludge and organic waste to biogas, which is a mixture of methane and carbon dioxide. In many installations chopped maize or other agricultural products are co-digested. The biogas is subsequently combusted in a boiler, a turbine or a gas engine.

Data from gas engines running on biogas have been collected before and are presented in the next section. Also, data from a boiler co-firing biogas with natural gas are presented. Data from boilers firing pure biogas were not found.

4.10.2 Emission RegimeIn general BEES B will be applicable for engines fired on natural gas and/or bio-gas. When the gas is combustion in a CHP mainly the NOx-limit from BEES B is of importance. Because H2S has to be removed because of engine specifications no additional limits of SO2 are necessary [Infomil, 2008]. There are no limits to NH3 of CxHy as these are assumed to be converted during the combustion process.

4.10.3 Emission Factors

Sara Lee / DE boilerThe largest boiler operated by Sara Lee / DE in Joure co-fires biogas with natural gas; total 15 MWth. The exact distribution is variable, but on average about 6% biogas is co-fired. The calorific value of the average fuel is 31.1 MJ/m0

3. Emission factors are listed in Table 4-25. The measurement of NOx was done according to NEN-EN 14792. The measurement of SO2 has been done according to ISO 7935.

Table 4-25 Emission factors of biogas installation Sara Lee [mg/MJ of fuel mix], 6% biogasNOx as NO2 37.8 SO2 6.8

Emissions of ammonia, dust (PM10) and NMVOS have not been reported. There is no need to do this from combustion in a boiler, because emissions of these can be expected to be very low.

Danish gas engine dataEmission factors from gas engines running on biogas have been published in the ECN report on emission factors of dust. It includes a table with information on biogas gas engines in Denmark, compiled by the Danish Gas Institute (reproduced in Table 4-26). The data are from digesters on manure, sludge and from fermentation. For comparison the emission factors of gas engines and of gas turbines are given as well. Unfortunately, ammonia is not included.

Land fill gases are essentially also the product of microbial activity and composed of methane, carbon dioxide, but also of air. Emission factors are known for gas engines running on land fill gas, see Table 4-27. For comparison, the data of one engine that is co-firing 6% diesel is also given. The data are in reasonable agreement with the data from Denmark

ECN-BKM-2008-81 41

Table 4-26 Emission factors from DenmarkEmission in [mg/MJ] Gas engine on natural gas Gas engine on biogas Gas turbine on

natural gasNOx 168 540 124SO2 No data 19 No dataNH3 No data No data No dataVOC 485 254 <2.3 CH4 520 323 <1.5

NM-VOC 117 14 <1.4Total dust 0.76 2.63 0.1 PM10 0.19 0.45 0.061 PM2.5 0.16 0.21 0.051 PM1 0.14 0.13 0.038CO 175 >273 6N2O 1.3 0.5 2.2Source: ECN report ECN-C--06-010

Table 4-27 Emission factors for land fill gas in a gas engineEmissions in [mg/MJ] Gas engine (average of 7) Dual fuel diesel engine, using 6% diesel

fuelSOx 27 42NOx 211 523CO 421 521Particulates 1,4 8,9NMVOS 12 25CH4 516 1904Source: ECN report ECN-C--06-010

4.10.4 Emission Reduction MeasuresOn engines fired on natural gas SCR technology is commonly applied, but as far as known this technology is scarcely applied for engines on biogas. The presence of trace elements in the flue gas is claimed by Euromot (branch organization) to be damaging the oxidation catalyst [Kroon, 2008] but in coal-fired power plants SCR installations are commonly applied, also with high concentrations of heavy metals.

4.10.5 Missing DataMissing data include:

Emission data of ammonia are missing. There is a good reason for the lack of data, because ammonia is not expected to be emitted in relevant quantities. This applies to some other missing data as well.

For combustion of biogas in boilers, only NOx and SOx have been found of one plant. There must be more data available.

New data from Dutch installations could not be obtained during the project period. When asked for emission data, installation owners tell you that they comply with the regulations and refer you to manufacturers. These are extremely busy at the moment because many new installations are being planned and built, since SDE subsidies have become available in this time period.

An overall problem is the large variety of installations.

4.10.6 ConclusionsThe emission factors from digesters are determined by the emissions from the combustion facility that is burning the biogas. The three types of installations (boiler, gas engine and gas turbine) have largely different emission factors. In particular, the emissions of NOx and NM-

42 ECN-BKM-2008-81

VOS of gas engines exceed those of gas turbines and boilers. Fine dust and ammonia are less of an issue. Often it is not even required to measure these, because the predicted emissions are well below the limits. The emissions of SO2 are determined by the sulphur content of the biogas and sulphur capture.

An overall problem is the large variety of installations, but the composition of biogas from digestion, land fill, etc. is relatively uniform. Only the amount of sulphur can vary significantly with the amount of S in the feed.

Additional emissions may originate from digestion of biomass when the processing of digestate (the wet remains that leave the digester) is included. Typically, this material is spread on farmland as fertilizer. The situation gets even more complex when emissions are taken into consideration that would have been formed when instead of digestate other fertilizers had been used. This kind of considerations adds to the complexity of the use of biomass for energy production.

For a follow-up project it would be relevant to do measurements at representative installations. A good number of them are co-operative but simply too busy to spend much time on it.

ECN-BKM-2008-81 43

5. New Biomass Pre-treatment Processes

5.1 IntroductionThis chapter gives the available background information about biomass pre-treatment processes that are currently under development. As they are not commercialized yet, emission data are roughly estimated. The processes are:

Substitute Natural Gas from Biomass (Bio-SNG) Torrefaction Hydrothermal Upgrading (HTU) Pyrolysis

Fermentation for the production of bio-ethanol is not described in this report, but can be considered as emissions coming from a combustion CHP plant when burning the solid residue (mainly lignin) and comply to BVA or BEES emission limits, depending on the composition of the residue. This type of installation is described in previous paragraphs. The emission factors expressed per MJ input are relatively low, due to the fact that these technologies are pre-treatment technologies aimed at a high yield of product (fuel). It is expected that most emission effects will occur during the end-use of these products. Emissions related to the use of electricity are not included in these emission factors.

5.2 Substitute Natural Gas from Biomass (Bio-SNG)

5.2.1 Use of BiomassSubstitute Natural Gas from biomass (Bio-SNG) is a green replacement of natural gas. It is produced by indirect gasification of biomass and a catalytic reaction. The process is currently in bench-scale status. The technology is expected to be commercially available within 5-10 years and it is foreseen at a larger scale (several 100-1000 MWth) in the Netherlands. The technology is currently under development at ECN.

As the foreseen scale is large, the biomass feedstock will mainly be imported clean wood.

5.2.2 Emission RegimeFor clean wood the emission regime for the installation is expected to be BEES A.

5.2.3 Emission FactorsAs no commercial installation is existent, the data presented in Table 5-1 are estimations. Only emissions from the combustion step (necessary to supply the gasification step with heat) are taken into consideration. These are the most important expected emissions. The emissions from sulphur from the sulphur removal are not taken into account. The energy efficiency from biomass to SNG is taken at 70% on LHV basis wet fuel basis, assuming 25% moisture in the feedstock3. The emissions of SOx and NOx will increase when fuels are used with higher sulphur and nitrogen content but limited by the emission regime. The conversion efficiency of the product during end-use will be approx. the same as for natural gas.

3 No net power production during the SNG process is assumed. Al generated power is used internally.

44 ECN-BKM-2008-81

Table 5-1 Estimated emission factors for SNG production for clean wood (combustion step)Biomass input basis SNG output basis

mg/MJ LHV mg/MJ/HHV mg/MJ LHV mg/MJ/HHVVOS 0.03 0.03 0.05 0.04SOx

1) 6 5 9 8NOx

2) 19 17 27 24NH3 3) No data No data No data No dataDust 4) 1 1 2 1Remarks:

1) Too low to be measurable during experiment, estimated value, for SO2 is assumed that 10% of the sulphur in the fuel will be in the flue gas of the combustor.

2) Without de-NOx3) No data in literature and never measured, expectations lower then NOx4) Bag house filter assumed, limit 20 mg/Nm3

5.2.4 Gas CleaningFor the flue gas cleaning conventional technologies can be applied. A dust removal step (baghouse filter) is foreseen to meet the emission limits.

5.2.5 Missing DataThe process is not commercially available and is in the development phase. The available Therefore information is limited. Missing data is:

Emission data at full scale Specific data on NH3 and NMVOS emissions Emissions from sulphur processing

5.2.6 Current ResearchECN: currently the development of the bio-SNG process is ongoing. Half 2008 the pilot scale indirect gasifier MILENA will be in commissioned (800 kWth). New emission data will be available when is this installation is operating.

5.2.7 ConclusionsSNG will be produced at a large scale and relatively low emissions per MJ product are expected during production of SNG. The product is a fuel with the same or comparable combustions and emission properties as natural gas, which can be an advantage from an emission point of view.

5.3 Torrefaction

5.3.1 Use of BiomassTorrefaction is a pre-treatment technology for (relatively dry) biomass and waste streams. By heating the material, the material becomes more brittle (and therefore easier to mill) and hydrophobic. Besides it increases the energy density of the material. Torrefied material is easier to use than non-torrefied material for co-firing in pulverized coal power plants and entrained flow gasification: two applications where a small particle diameter is required. The process is at the pilot scale phase and demo projects are under development. Pollutants can be emitted from the combustion process (torrefaction gas combustion), necessary to provide the drying and torrefaction step with heat. Most emissions will be released during the end-use of the product.The product will pelletized to make transport over long distances (e.g. overseas) possible. Production can take place in the Netherlands as well as abroad. The energy efficiency is reported to be 90%LHV based on wood chips with 50% moisture content [Bergman, 2005]. The conversion efficiency of the product during end-use will be approx. the same as for other solid fuels.

ECN-BKM-2008-81 45

For a commercialized process both clean and non clean biomasses (waste streams) can be processed.

5.3.2 Emission RegimeNo data available.

5.3.3 Emission FactorsAs the technology is in the development stage, full-scale data is not available. The torrefaction pilot plant is under commissioning and measurements are planning in the course of 2008. The data is presented in Table 5-2 on a mg/MJ dry feedstock basis.

Table 5-2 Estimated emission factors for torrefactionComponent Emission Factor

[mg/MJ dry feedstock]NOx

1) 1SOx

2) 2NMVOS No data, expected to be lowNH3 No data, expected to be lowDust No data, expected to be lowRemarks

1) 20 ppmV NOx measured during commissioning of pilot plant2) 20% release of S assumed in gas phase

5.3.4 Emission Reduction MeasuresConventional gas cleaning technology can be applied. As the temperature conditions during torrefaction are low (max. 300ºC) it is expected that most nitrogen and sulphur will remain in the solid product and not in the torrefaction gas this is combusted in the torrefaction process.

5.3.5 Missing DataFull scale information is not available and emissions measurements have not been performedyet for the pilot-scale installation at ECN.

5.3.6 Current ResearchECN is currently developing a torrefaction process. More emission data will be available in the course of 2008.

5.3.7 ConclusionsThe emissions associated with a torrefaction process seem to be limited as most polluting elements remain in the product phase. When the burner of the torrefaction gas is operated under the right operating conditions, limited emissions are expected. Due to the size of the installation and especially when treating waste streams the emission limits will be strict. More data will come available in the course of 2008. Most emissions will occur during end-use.

5.4 Pyrolysis (Pyros process)

5.4.1 Use of BiomassIn the PyRos-process the pyrolysis is implemented in a cyclonic reactor with an integrated hot gas filter (the rotational particle separator: RPS). In this way a particle free bio-oil can be produced. The biomass and the inert heat carrier are introduced as particles into the cyclone (PyRos reactor). By centrifugal force the particles are moved to the periphery of the cyclone where the pyrolysis process takes place. Evolved vapours are transported rapidly to the centre of the cyclone and leave the cyclone by a rotating filter that removes remaining very small particles. The hot vapours containing pyrolysis oil in vapour phase are quenched with cooled pyrolysis oil and the condensed oil is separated from the gas in a second RPS. Part of the oil is

46 ECN-BKM-2008-81

separated and cooled for the quench, while rest of the oil is available as product. The remaining gases and char can be used either as heat source of the process itself or as external fuel. It is expected that char will be used for the production of process energy in the fluidized bed combustor as can be seen in Figure 5-1 and thus resulting in emissions to the air.

There is no commercial process available. PyROS process will need fuels of a small particles size and limited moisture content to enable fast heating of the particles to produce oil.

Figure 5-1 Scheme of the pyRos process

5.4.2 Emission RegimeBEES A is assumed for solid fuels. See Table 2-3 for emission limits.

5.4.3 Emission FactorsThe emission factors are estimated based on the maximum allowable emission according to BEES A limits

Table 5-3 Expected emission factors in mg/MJ of biomass input (sulphur and nitrogen poor) of future PyRos-plant

HTU emission compound NOx SO2 VOC *) NH3 DustEmission Factor 4.0 0.0 0.0 0.0 0.8

*) Volatile organic Compounds

5.4.4 Emission Reduction MeasuresConventional biomass combustion emission reduction measures can be taken (e.g. ESP, de-NOx).

5.4.5 Missing DataNo information available

ECN-BKM-2008-81 47

5.4.6 Current ResearchECN: no researchTNO: model research

5.4.7 ConclusionsThe emissions per MJ fuel input are limited. Most emissions will however occur during end-use.

5.5 Hydrothermal Upgrading

5.5.1 Use of BiomassHTU (Hydrothermal Upgrading) is a process for liquefaction of biomass. The goal of hydrothermal conversion is to produce liquid fuel (Biocrude) from biomass with a continuously and relatively simple process with high energy efficiency. Biomass is compressed to 120 – 200 bar with a temperature of 300-350ºC. With this conditions with liquid water during 5 – 15 minutes a liquid fuel is formed, which looks like crude from fossil oil. This bio-crude has a relative high heating value and does not mix with water. This product of the HTU-process can be transferred into diesel fuel with addition of hydrogen. During this process also CO2 is formed together with other volatile components. The heat for the process can be generated by a furnace fired with residue gasses of HTU-process and biogas from digesting of sewage sludge.Based on the test results, calculations are made for a design of a future standard HTU- plant with a typical capacity of 130,000 ton of dry biomass a year. Therefore the capacity of the furnace for additional energy for the process is estimated at 15 MWth. This capacity can be reached with mainly own residue bio-gasses and some of the produced bio-crude. This combustion process has been considered as the only source of emissions to the air. Because of the presence of methane, it is assumed that the emissions levels should be more or less comparable with the combustion of natural gas. If the input materials are sulphur or nitrogen rich, the fuel of the furnace will also contain sulphur and nitrogen, resulting in additional emissions. A special feature of the HTU-process is the suitability for conversion of wet biomass into bio crude.

5.5.2 Use of Biomass FuelsIt is experimental demonstrated that the process is suitable for a large number of biomass streams like wood, organic residues of food industry, agro-industry and switch grass and kitchen and garden waste.

5.5.3 Emission RegimeThe regime for combustion plants for liquid fuels (art. 12 BEES A) is assumed. See Table 2-3for limit values.

5.5.4 Emission FactorsTable 5-4 a rough estimation is presented of emissions to the air from a typical future HTU-plant per MJ of biomass input, based on the expected emissions guidelines for combustion plants (liquid fuel), being NOx 120 mg/Nm3, SO2 1700 nmg/Nm3 and dust 50 mg/Nm3.

Table 5-4 Expected emission factors in mg/MJ biomass input (sulphur and nitrogen poor) of future HTU-plant

HTU emission compound NOx SO2 VOC *) NH3 DustEmission Factor 0.26 0 0.02 0 0.11

*) Volatile Organic Compounds

The NOx value is low compared to the Pyros process due to differences in internal fuel consumptions to provide the processes with energy.

48 ECN-BKM-2008-81

5.5.5 Emissions Reduction MeasuresConventional biomass combustion emission reduction measures can be taken (e.g. ESP, de-NOx).

5.5.6 Missing DataNo information available.

5.5.7 Current ResearchNo data supplied.

5.5.8 ConclusionsThe reported emission factors are very low, which is explained by the internal consumption of product for process progress. Most emissions will occur during end-use.

ECN-BKM-2008-81 49

6. Discussion and Conclusions

Quality and quantity of the available dataA large amount of data on NEC emissions related to the use of biomass fuels in stationary applications is retrieved in this study. The amount of emitted pollutants is strongly dependent on the type biomass, the used combustion technology, the applied process conditions and the used emission reduction measures. This makes it difficult to assess emission data, especially for smaller scale installations as often background information of the reported data is missing. Thisstudy is aimed to be a first inventory of emission factors.

Observations on data on NEC-pollutants

NOx: NOx data is generally well available for a wide range of installations. The emission factor is strongly dependent on the type of installation and emission reduction measures.

SOx: due to the relatively low sulphur content of most biomass fuels relatively low SOxemissions are expected compared to coal firing. A point of attention can be white list fuels that can have a relatively high sulphur content compared to woody materials, like straw.

NH3: NH3 emissions are generally very low (a few ppm for fluidized bed combustion) [Saario, 2008] when biomass is combusted as a result of incomplete conversion of ammonia, formed during pyrolysis or gasification, into NOx. Emissions of NH3 can behowever expected when a de-NOx installation with addition of urea of ammonia is installed (slip) at a biomass combustion installation. In that case the NH3 emissions areeven reported higher then for coal-fired installations.

NMVOS: there is almost no data available as no or little NMVOS is expected to be formed. Most data is VOS including methane and often no specific methane emission is reported.

Dust: Dust is often measured and well available, but specific dust fractions are often missing. Although biomass fuels often have low ash contents, emissions of dust can especially increase for small scale installations and use in oil-fired engines (soot).

CategoriesThe observations of increased use of biomass for different types of installations are indicated below:

Existing technologieso Coal-fired power plants: use of biomass will reduce emissions of SOx,

compared to coal. There are contradictions about the NOx and NH3 emission factors For NMVOS no data is available.

o Gas-fired power plants: use of biomass will increase emissions of SOxcompared to natural gas. If more or less NOx, NH3, NMVOS will be emitted depends on operating conditions and type of installation.

o Waste incinerators and sewage sludge incineration plants: this type of installations already is fired (partially) on biomass. No large change is expected in this category.

o Glass and brick industry: these industries have no plans to switch to biomass due to its expected negative influence on product quality. There for no effect on emissions is expected.

o Cement industry: a maximum of renewable fuels is already used. No large changes are foreseen.

50 ECN-BKM-2008-81

o Medium scale biomass conversion: this category is rapidly growing, but has well controlled emissions. Additional use of biomass will in general increase emissions if they substitute natural gas.

o Small-scale biomass combustion: this category is characterized by a broad range of installations (scale, fuel, emission reduction measures). Additional use of biomass will in general increase emissions if they substitute natural gas.

o PPO-fired diesel engines: only information on small diesel engines was available. NOx and dust emission factors were found to be relatively high compared to other biomass fuel applications.

o Digesters with boiler or gas engine: NOx emissions were found to be relatively high compared to other biomass fuel applications.

New technologies (SNG, (flash) pyrolysis, torrefaction, fermentation, HTU): all these technologies focus on the production of an intermediate fuel with a high energy efficiency. Most polluting effects are expected when their products are converted during their end-use.

Table 6-1 summarizes the data retrieved in this study. Especially the small combustion installations show relatively high emission factors and large ranges.

Table 6-1 Reported (ranges of) emission factors in this study, based on the lower heating valuethermal input of the (wet) fuel

NOx

[mg/MJ]SOx

[mg/MJ]NH3

[mg/MJ]Dust

[mg/MJ]NMVOS[mg/MJ]

Basis/Remarks

Existing technologiesCoal-fired power stations

Direct co-firing (10% biomass)

99(56-130 for 100% coal)

11.2(19 for

100% coal)

100% coal: 3-13100%

Biomass:1-5 (no de-

NOx)5-10 (SCR)21 (SNCR)

0.3-0.5(1-2 for

100% coal)

No data Fuel mix, 10% biomass

Indirect co-firing (gasification)

No data 5 No data 2 No data Assuming flue gases pass FGC in coal plant.

Gas-fired power stations, directly

66(46 for

100% gas)

4(2 for 100%

gas)

No data 12 No data Bio-oil

Waste Incineration 60 2 0.1 0.5 0.9 (VOC) Fuel mixSewage Sludge Incineration

22.6 2 2.5 1.2 0.6 (VOC) Fuel mix, including 3% natural gas.

Cement Industry 416 118 25 5 No data Fuel mix (47% renewable).

Brick Industry 55 12 Nihil 5 10.3 (VOC) Based on fossil fuels, no BM used.

Glass Industry 310-700 190-220 Nihil 0.4-20 Nihil (VOS) Based on fossil fuels, no BM used.

Medium scale biomass application

Combustion 48-219 0.3-108 1-5 (no de-NOx)

5-10 (SCR)21 (SNCR)

1-10 1.5-1.8 (VOC)

Gasification (IGCC)

34-87 5-10 No data 0-2 0-1 (CxHy)

Small-scale biomass combustion

29-420 10-50 5-9(residential, commercial)

6-170 20-250

PPO-fired diesel engines

630-1020 No data No data 25-29 No data

ECN-BKM-2008-81 51

NOx

[mg/MJ]SOx

[mg/MJ]NH3

[mg/MJ]Dust

[mg/MJ]NMVOS[mg/MJ]

Basis/Remarks

Digestion Gas engine on biogas

540(168

(Danish data, see

remarks) for 100% gas, or 13 with

catalyst (Dutch data))

19 No data(0.11 for 100% gas and with catalyst

(Dutch data)

2.6(0.76 for

100% gas)

14(117 for

100% gas)

Danish data, no gas cleaning factors based on energy content of the gas, probably no catalyst/SCR

Gas engine onland-fill gas

211 27 No data 1.4 12 Factors based on energy content of the gas.

New technologies Numbers do not include final use of product and based on estimates.

Bio-SNG 19 6 No data 1 0.03 (VOS) Based on maximum emission limit.

Torrefaction 1 2 No data No data No dataFlash Pyrolysis 4 0 0 0.8 0 Based on maximum

emission limit. HTU 0.3 0 0 0.1 0.02 (VOS) Based on maximum

emission limit.

Expected emission effectsTable 6-2 gives a qualitative overview of replacing of fossil fuels with biomass with modern biomass combustion systems. Although the table is valid for small to medium scale for the Scottish situation and effects will be smaller for large scale applications due to more extensive emission reduction measures, it gives an indication of the expected effects of transition from fossil fuels to bio-fuels.

Table 6-2 General Effects of Replacing Fossil Fuel by Modern Biomass Combustion Technologies [Scotland, 2006]

Advantage '+' or disadvantage '-' from change to modern biomass technology (wood) from fossil fuel

Pollutant

Gas Oil CoalSO2 -- ++ +++NOX - - +PM / PM10 / PM2.5 --- -- +NH3 No data No data No dataNMVOC - - +CO - - +Trace elements -- + +PAH -- - +PCDD/F -- - +

Overall conclusions Operators and suppliers are often stating that they comply with the required regime, but

actual emission data are not often made accessible, making it difficult to retrieve reliable emission factors. If registered, the emission data should be however public available in agreement with the Treaty of Aarhus (2005) (VROM, 2008).

Emissions are dependent of fuel (type and composition), installation (type, scale and operation) and installed emission reduction measures. As a result, the emission factors

52 ECN-BKM-2008-81

presented in this study are very diverse and show a large spread. It is not possible to give one typical emission factor to be representative, even within one category.

Upper emissions limits are well defined for medium and large installations and installations fired on waste and are therefore are well predictable and also well controlled.

The limited flue gas cleaning for smaller installations can results in relatively large emissions factors. Also the monitoring of emissions (e.g. continuous measurement of emission of pollutants) is less. The Emission registration only covers installations larger then 50 MWth input and therefore official, centralized emission registration for smaller scale installation is missing. The European commission has however sent a first proposal in December 2007 to integrate several directives into the IPPC directive. This can have consequences for the emission registration as the lower limit can be set at 20 MWth, but also the emission limits may change for the range 20-50 MWth. As it is a first proposal, the consequences are still uncertain.

The regular unit for emissions is mg/Nm3 dry flue gas, while emission factors are in mg/MJLHV, wet. In contrast to fossil fuels, biomass can contain a large amount of moisture. If the moisture content is unknown, assumptions are needed to convert emissions into emission factors. This is a possible source of errors, but the relative error is limited.


o Transition from coal to biomass at large scale installations: due to existing extensive flue gas cleaning emissions will be the same or improve.


The data presented in this study is not sufficient for a quantitive conclusion. More information will be needed on the substitution of fossil fuels by biomass fuels. This work can be performed during the integration phase of BOLK.


Missing Data In general there is a lack on date on NMVOS and NH3, as they are expected to be

formed in low concentrations. There are also no emissions limits on these pollutants so there is no reason to measure them. For small scale installations on clean biomass also SOx data is often missing as there are no limits sets to this pollutant. The sub-division of dust (PM10, PM2.5) is frequently absent.

Data on small and medium scale installations is scarce and it is difficult to asses how representative the retrieved data in this study is for the Dutch situation.

Up-to-date cost data of reduction measures is scarce. Available data is at least several years old. Steel and energy prices have been rising rapidly lately which might have acost-increasing effect.

The information on current research is limited in this study.

Recommendations for further research Modelling

Estimate the impact of increased use of biomass on NEC ceiling emissions and air quality differentiating between small and larger applications using a diversity of scenarios.

Take into account the efficiency of emissions e.g. based on emissions per kWhor useful heat instead of based on fuel input.

Research on data:

ECN-BKM-2008-81 53

NOx and NH3 emissions are rather complex and there are contradictions in literature. An extensive literature review is recommended.

Perform an in-depth literature search on biomass installations with the focus on emission factors to retrieve data missing in this study. If possible emission vectors can be identified (fuel → emission factor without reduction technology → emission factor with reduction technology), which can be used for a scenario analysis and compare them with IIASA emission vectors.

Information on current research in this study is limited. Further research is needed on this subject.

Make an inventory of all types of biomass installations in the Netherlands and try to correlate them to data in available literature.

Retrieve the emission factors for fossil fuels, for large and small scale to make a good comparison possible.

Measure especially NMVOS and NH3 emissions, if considered to be relevant,on a number of installations to verify that low amounts are emitted.

Update available cost data. Identify what emissions are related to alternative use of biomass stream

necessary for a good assessment of the effect of the use of bio fuels, e.g.composting, decay on land etc.

54 ECN-BKM-2008-81

7. Abbreviations

AVI Afval Verbrandings Installatie

BEC Biomassa Energy Centrale

BEES Besluit Emissies Stookinstallaties

BOLK Beleidsbericht Onderzoeksprogramma Lucht en Klimaat

BVA Besluit Verbranden Afvalstoffen

CBS Centraal Bureau voor de Statistiek

FGD Flue Gas Desulpherisation

HHV Higher Heating Value

HTU Hydrothermal Upgrading

IGCC Integrated Gasification and Combined Cycle

IIASA International Institute for Applied Systems Analysis

LHV Lower heating value

NEC National Emissions Ceiling

NeR Nederlandse Emissie Richtlijn

NMVOS Non Methane Volatile Organic Species

PPO Pure Plant Oil

RDF Refuse Derived Fuel

SCR Selective Catalytic Reduction

SNCR Selective Non Catalytic Reduction

SNG Substitute Natural Gas

ECN-BKM-2008-81 55

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Johansson, 2004 Johansson L.S., Leckner B., Gustavsson L., Cooper D., Tullin C. and Potter A., Emission characteristics of modern and old-type residential boilers fired with wood logs and wood pellets. Atmospheric Environment 38:4183-4195, 2004

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Kroon, 2008 Kroon, P., Wetzels, W., Onderbouwing actualisatie BEES B (draft report), ECN, Petten, 2008

Meulman, 2000 Meulman, P.D.M, et al. Technologische perspectieven voor reductie van NOx en stofemissie bij kleinschalige energie opwekking uit schoon (resthout), SenterNovem/TNO, 2000

Obernberger, 1997 Obernberger, I., Stand und Entwicklung der Verbrennungstechnik, VDI

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Saario, 2008 Saario, A., Oksanen, A., Comparison of Global Ammonia Chemistry Mechanisms in Biomass Combustion and Selective Noncatalytic Reduction Process Conditions, Energy & Fuels, Vol. 22, pp. 297-305, 2008

Scotland, 2006 Review of Greenhouse Gas Life Cycle Emissions, Air Pollution Impacts and Economics of Biomass Production and Consumption in Scotland, Government of Scotland, 2006

Seebregts, 2004 Seebregts, A.J. et al., Monitoring Nederlandse Energiecentrales 2000-2004, ECN, 2005

SenterNovem, 2007 Statusdocument Bio-energie 2007, SenterNovem, 2007

Skreiberg, 1994 Skreiberg, O., Saanum, O., Comparison of Emission Levels of Air Pollution Components from Various Biomass Combustion Installation in the IEA Countries, IEA, 1994

SNB, 2008 http://www.snb.nl/nieuws.html

Solutatu, 1992 Kleinschalige verbranding van schoon resthout in Nederland, NOVEM, 1992

Van der Linden, 2008 Van der Linden, R., internal memo BOLK, ECN, 2008

Van Loo, 2003 Van Loo, S., Koppejan, J., Handbook Biomass Combustion and Co-firing, Twente University Press, 2003

Van Rompay, 2000 Emissies van dioxines en PAK’s door gebouwenverwarming met vaste brandstoffen, Vito, december 2000

Videncenter, 1999 The Centre for Biomass Technology, Wood for Energy Production, Denmark, 1999

VITO, 2001 Thermische verwerking: kleine of middelgrote stookinstallaties voor hout, BBT-kenniscentrum, VITO, 2001

VROM, 2002 Circulaire: Emissiebeleid voor energiewinning uit biomassa en afval, VROM, 2002

VROM, 2008 VROM, Openbaarheid milieu-informatie, http://www.vrom.nl/pagina.html?id=19807, 2008

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Appendix A Decision Tree BEES/BVA

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ECN-BKM-2008-81 59

Appendix B Measurement Methods

B.1 Measurement Methods BEES AIn hoofdstuk 4 van Bees A is het meetregime aangegeven. De overige voorschriften betreffende meten zijn te vinden in de Regeling meetmethoden. Hoofdstuk 4 van het Bees A is als volgt opgebouwd:

Artikelen 30a, 30b en 30c

de kwaliteitseisen die aan metingen op grond van Bees A, worden gesteld

Artikelen 31 tot en met 36

meting van SO2-emissies van installaties die niet in raffinaderijen zijn opgesteld

Artikel 37 meting van SO2-emissies van installaties bij raffinaderijen

Artikelen 38 en 38a meting van NOx-emissies bij ketels en procesfornuizen

Artikelen 39 tot en met 42

meting van NOx-emissies bij gasturbine(-installatie)s en WKK-zuigermotoren

Artikel 43 meting van stofemissies

Artikel 43a, 43b en 44 registratie, rapportage en opslag van meetgegevens

In de betreffende artikelen is onder meer vastgelegd in welke gevallen een continue meting en in welke gevallen een niet-continue (afzonderlijke) meting moet worden uitgevoerd.

Continue metingen

Een continue meetverplichting is voorgeschreven voor: de SO2-, NOx- en stofemissie van stookinstallaties met een thermisch vermogen van tenminste 100 MW; de NOx-emissie van gasturbines en gasturbine-installaties wanneer ter bestrijding van de NOx-emissie injectie van stoom, water of een andere inert materiaal wordt toegepast ; de NOx-emissie van gecombineerde stookinstallaties in elektriciteitsproductiebedrijven, waarvan het thermische vermogen van de gasturbine kleiner is dan 40% van het totaal thermisch vermogen en ter bestrijding van de NOx-emissie injectie van stoom, water of een andere inert materiaal wordt toegepast.

(Indien op een andere wijze ten genoegen van het bevoegd gezag kan worden aangetoond dat de emissie-eis niet overschreden zal worden, is continue meting niet verplicht. Dit geldt bijvoorbeeld voor gasturbines, waarvoor kan worden aangetoond dat continu de stoominjectie voldoende is om overschrijding van de emissie-eis te voorkomen). de NOx-emissie van de meeste stookinstallaties waarin in de inrichting zelf gegenereerde brandstoffen worden gestookt (zie artikel 38 lid 2). Er geldt een uitzondering op de continue meetverplichting voor:

de SO2-, NOx- en stofemissie van stookinstallaties met een thermisch vermogen tussen de 100 en 300 MW die na 27 november 2002 niet meer dan 10.000 uur in bedrijf zijn;

de SO2- en stofemissie van stookinstallaties die op aardgas worden gestookt; de SO2-emissie van stookinstallaties zonder rookgasontzwaveling die op olie worden

gestookt waarvan het zwavelgehalte bekend is; de SO2-emissie van stookinstallaties zonder rookgasontzwaveling die op biomassa

worden gestookt waarvan het zwavelgehalte niet leidt tot een overschrijding van de emissiegrenswaarde ;

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de stofemissie van stookinstallaties gestookt op gasvormige brandstoffen die gezien de herkomst niet kunnen leiden tot een overschrijding van 10% van de emissie-eis.

Afzonderlijke metingen Voor emissies van stookinstallaties waarvoor geen continue meetverplichting geldt, moet door middel van afzonderlijke metingen worden aangetoond dat de emissie-eis niet wordt overschreden. Afzonderlijke metingen moeten worden uitgevoerd binnen vier weken na het van toepassing worden van een emissie-eis en vervolgens:

NOx SO2 stofketelinstallaties en procesfornuizen > 50 MW elk half jaar1 elk half jaar1 elk half jaar1

ketelinstallaties en procesfornuizen < 50 MW geen geen geengasturbine(-installatie)s > 50 MW, vergund op of na 27 november 2002

elk half jaar1 elk half jaar1 elk half jaar1

gasturbine(-installatie)s < 50 MW, vergund voor 27 november 2002

elke vier jaar elk half jaar1 elk half jaar1

gasturbine(-installatie)s < 50 MW elke vier jaar geen geenzuigermotoren > 50 MW elke vier jaar elk half jaar1 elk half jaar1

zuigermotoren < 50 MW elke vier jaar geen geen1)Indien een installatie meer dan een half jaar per jaar aaneengesloten uit bedrijf is, mag de halfjaarlijkse afzonderlijke meting beperkt worden tot eens per jaar. Dit geldt bijvoorbeeld voor installaties in campagnebedrijven, zoals suikerfabrieken.

Uitzonderingen op het bovenstaande: afzonderlijke metingen hoeven niet te worden uitgevoerd voor:

SO2, NOx en stof indien er geen emissie-eis van toepassing is; SO2, NOx en stof indien er een continue meting plaats vindt; SO2, bij stookinstallaties zonder ontzwavelingsinstallatie, indien uitsluitend

brandstoffen worden gestookt die overschrijding van de emissie-eis uitsluiten; SO2 voor de in artikel 37 lid 2 nader gespecificeerde stookinstallaties in raffinaderijen

indien de SO2-emissie van een installatie uitsluitend bepaald wordt door het zwavelgehalte van de ingezette brandstoffen en hiervan een register wordt bijgehouden;

NOx indien uitsluitend typekeur branders zijn geïnstalleerd in een installatie voor het verhitten van water en stoom met een thermisch vermogen kleiner dan 7,5 MW, waarbij geen luchtvoorverwarming plaats vindt en de stoomdruk niet hoger is dan 1 MPa;

NOx voor aardgasgestookte zuigermotoren waarvoor een typekeur is afgegeven door een door de Minister van VROM aangewezen instantie en waarvan het onderhoud conform de bedrijfsvoorschriften van de leverancier wordt uitgevoerd (een dergelijk keurmerk is tot op heden niet afgegeven);

Stof indien de installatie wordt gestookt op aardgas of andere gasvormige brandstof die gezien de herkomst niet kan leiden tot een overschrijding van 10% van de emissie-eis.

B.2 Measurement Methods BEES B

In het kader van Bees B wordt bijna altijd afzonderlijk gemeten. Continue meting is alleen verplicht wanneer bij een gasturbine of gasturbine-installatie water, stoom of een ander inert materiaal geïnjecteerd wordt ter bestrijding van de emissie van NOx (art. 10.3.10, onder a).

Afzonderlijke metingIn de meeste gevallen kan volstaan worden met een afzonderlijke meting. Bij kolengestookte ketelinstallaties dient onderscheid gemaakt te worden in metingen van SO2, NOx en stof. Kolengestookte ketelinstallaties komen echter nauwelijks voor in inrichtingen die onder Bees B vallen. In nagenoeg alle gevallen gaat het dus uitsluitend om NOx. Bij ketelinstallaties moet de afzonderlijke meting eenmaal worden uitgevoerd, tenzij een nieuwe emissie-eis op de

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ketelinstallatie van toepassing wordt. In dat geval moet opnieuw worden gemeten, opdat vastgesteld kan worden dat deze installatie ook aan de nieuwe emissie-eis voldoet. De meting wordt zo spoedig mogelijk na het van toepassing worden van de emissie-eis, doch uiterlijk binnen vier weken nadien verricht (voor SO2 en stof geldt een termijn van 12 maanden).De meting moeten worden verricht bij een belasting van meer dan 60%.

Bij gasturbines, gasturbine-installaties en zuigermotoren wordt de afzonderlijke meting telkens wanneer een emissie-eis van toepassing wordt, zo spoedig mogelijk, doch uiterlijk binnen vier weken nadien verricht en vervolgens iedere keer na afloop van een periode van drie jaar. Daarnaast geldt voor bestaande zuigermotoren waarvoor met ingang van 1 januari 2000 eisen gaan gelden dat de eerste afzonderlijke meting vóór 1 maart 2000 moet zijn verricht.De meting moet geschieden bij de hoogste belasting waarbij de gasturbine of zuigermotor kan worden bedreven.

Continue metingSlechts in één geval is continue meting op grond van Bees B verplicht. Het betreft de situatie waarin in een gasturbine of gasturbine-installatie ter bestrijding van de uitworp van NOx injectie van water of stoom, dan wel een inert materiaal wordt toegepast.Behalve rechtstreeks continue meting van de concentratie van NOx in het rookgas, kan ook gekozen worden voor continue meting van relevante parameters van de uitworpkarakteristiek van NOx in rookgas. De keuze van de parameters dient zo te zijn dat de concentratie van NOx in rookgas daarmee steeds ondubbelzinnig kan worden vastgesteld. In overige gevallen zal continue meting voorkomen indien de vergunninghouder hiervoor kiest. In dat geval zijn alle bepalingen inzake continue meting van toepassing.

Keurmerk ‘GASTEC QA Low NOx’De meetverplichting vervalt als het keurmerk ‘GASTEC QA Low NOx’ is verleend. Het certificaat kan door GASTEC (voorheen VEG gasinstituut) worden afgegeven voor:- branders, die worden geïnstalleerd in met aardgasgestookte ketelinstallaties met een thermisch vermogen van 7,5 MW of minder, die uitsluitend worden gebruikt voor het verhitten van water of stoom, bij een druk niet hoger dan 1 MPa, zonder dat daarbij luchtvoorverwarming wordt toegepast- zuigermotoren, waarin uitsluitend aardgas wordt gestookt.Indien uitsluitend branders met het genoemde keurmerk zijn geplaatst in een ketelinstallatie, of indien voor een gasmotor een keurmerk is verstrekt, wordt deze ketelinstallatie of gasmotor geacht te voldoen aan de emissie-eis van Bees B en vervalt de meetverplichting. Bij gasmotoren dient de juiste afstelling in ieder geval tijdens onderhoudsbeurten te worden gecontroleerd, hetgeen dient te blijken uit de daarvan gemaakte rapportage.In het handboek Gastec Certification, wordt gepubliceerd voor welke toesteltypen het keurmerk GASTEC QA Low NOx’ is verleend. Het handboek wordt 3x per jaar geactualiseerd. Het energiebedrijf beschikt over een exemplaar van het handboek. Op dit moment, juli 1998, zijn er nog geen gasmotoren met het keurmerk op de markt.

B.3 Measurement Methods BVA§ 2. Meetvoorschriften2.11. Meetapparatuur wordt geïnstalleerd en technieken worden gebruiktter bewaking van de parameters, de omstandigheden en de massaconcentraties,die relevant zijn voor het verbrandingsproces van een verbrandingsinstallatie.Bij regeling van Onze Minister kunnen met betrekking tot de inStaatsblad 2004 97 15de eerste volzin bedoelde meetapparatuur en technieken nadere regelsworden gesteld.2. De ter controle van een emissie-eis geïnstalleerde automatische

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apparatuur voor de bewaking van de emissies in de lucht functioneertgoed, tenzij er sprake is van technisch onvermijdelijke storingen ofstilleggingen van die apparatuur of technisch onvermijdelijke defectenaan die apparatuur. Er wordt jaarlijks een verificatietest op die apparatuuruitgevoerd door middel van parallelmetingen. Om de drie jaar wordt dieapparatuur door middel van parallelmetingen gekalibreerd.

2.21. In de rookgassen van de verbrandingsinstallatie worden de volgendecomponenten continu gemeten:a. zwaveldioxide, gasvormige en vluchtige organische stoffen, zoutzuuren het totaal aan stofdeeltjes;b. koolmonoxide en stikstofoxiden, mits eisen gelden voor de emissiesin de lucht van die stoffen;c. waterstoffluoride, tenzij voor zoutzuur behandelingsstappen wordengevolgd die waarborgen dat de in voorschrift 1.1. voor zoutzuur opgenomenemissiegrenswaarden niet worden overschreden.2. In het geval voor zoutzuur behandelingsstappen worden gevolgd dievoldoen aan het bepaalde in het eerste lid, onder c, wordt periodiekgemeten.3. In afwijking van het eerste lid, aanhef en onderdelen a en c, kan hetbevoegd gezag in de vergunning toestaan dat voor zoutzuur, waterstoffluorideof zwaveldioxide periodieke metingen worden verricht, indiendegene die de desbetreffende inrichting drijft, kan aantonen dat deemissie van de desbetreffende stof in de lucht nooit hoger kan zijn dan dedaarvoor in dit besluit opgenomen emissiegrenswaarde.

2.3In de rookgassen van de verbrandingsinstallatie worden de volgendestoffen periodiek gemeten: antimoon, arseen, cadmium, chroom, kobalt,koper, kwik, lood, mangaan, nikkel, thallium, vanadium, dioxinen enfuranen.

2.41. De volgende procesparameters worden continu gemeten:a. de temperatuur van de verbrandingskamer;b. de zuurstofconcentratie;c. de druk;d. de temperatuur van het rookgas;e. het waterdampgehalte van het rookgas, tenzij de als monstergebruikte rookgassen worden gedroogd alvorens de emissies in de luchtworden geanalyseerd.De temperatuur van de verbrandingskamer wordt dicht bij de binnenwandgemeten. De overige parameters worden gemeten nabij de plaatswaar de emissiemetingen worden verricht.2. In afwijking van het eerste lid kan het bevoegd gezag in de vergunningtoestaan dat de temperatuur van de verbrandingskamer wordtgemeten op een ander door het bevoegd gezag daarin bepaald representatiefpunt.

2.5De verblijftijd, de minimumtemperatuur en het zuurstofgehalte van derookgassen worden op passende wijze gecontroleerd:a. binnen één maand nadat de verbrandingsinstallatie in werking isgesteld, en

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Staatsblad 2004 97 16b. binnen zes maanden nadat de verbrandingsinstallatie in werking isgesteld onder de krachtens artikel 8, onder c, in de vergunning aangegevenslechtst denkbare bedrijfsomstandigheden.

2.61. Halfuurgemiddelden en 10-minutengemiddelden worden bepaaldbinnen de tijd dat de verbrandingsinstallatie in werking is, met uitzonderingvan de voor de inwerkingstelling en stillegging van de verbrandingsinstallatiebenodigde tijd indien gedurende die tijd geen afvalstoffenwaarop dit besluit van toepassing is, worden verbrand.2. Maandgemiddelden en daggemiddelden worden bepaald op basisvan halfuurgemiddelden en 10-minutengemiddelden.3. Bij de bepaling van het daggemiddelde worden ten hoogste vijfhalfuurgemiddelden wegens defecten of onderhoud van het systeem voorcontinue metingen buiten beschouwing gelaten. Per kalenderjaar wordenten hoogste tien daggemiddelden wegens defecten of onderhoud van hetsysteem voor continue metingen buiten beschouwing gelaten.4. Bij toetsing aan de emissiegrenswaarde worden van gemiddelden alsbedoeld in het eerste en tweede lid de waarden van het betrouwbaarheidsinterval,bedoeld in voorschrift 2.9, afgetrokken.

2.71. Periodieke metingen als bedoeld in de voorschriften 2.2, tweede lid,en 2.3 worden gedurende de eerste twaalf maanden dat een verbrandingsinstallatiein werking is ten minste één maal in de drie maanden verrichten vervolgens ten minste twee maal per kalenderjaar verricht.2. Een periodieke meting als bedoeld in het eerste lid bestaat uit eenserie van ten minste drie deelmetingen.3. In afwijking van het eerste lid kan het bevoegd gezag toestaan datperiodieke metingen van antimoon, arseen, chroom, kobalt, koper, lood,mangaan, nikkel en vanadium eenmaal in de twee jaar plaatsvinden enperiodieke metingen van dioxinen en furanen eenmaal per jaar plaatsvindenindien:a. de emissies in de lucht minder dan 50% bedragen van de vantoepassing zijnde emissiegrenswaarden, enb. de criteria, bedoeld in artikel 11, zevende lid, eerste alinea, van deafvalverbrandingsrichtlijn in werking zijn getreden en door degene die dedesbetreffende inrichting drijft worden nageleefd.4. Bij de toetsing aan de emissiegrenswaarde worden van de meetwaarde,bepaald door metingen als bedoeld in het eerste lid, de waardenvan het door een rechtspersoon als bedoeld in voorschrift 2.8, derde lid,aangetoond 95%-betrouwbaarheidsinterval afgetrokken.

2.81. Ter bepaling van de concentratie van stoffen in de rookgassenwaarvoor bij of krachtens dit besluit emissie-eisen zijn gesteld, wordenrepresentatieve metingen verricht, tenzij het een concentratie vanwaterstoffluoride betreft waarvoor geen verplichting als bedoeld invoorschrift 2.2, eerste lid, geldt. Bij regeling van Onze Minister kunnenregels worden gesteld omtrent de representativiteit van metingen.2. De bemonsteringen, analyses en metingen van de parameters dienodig zijn voor de bepaling van de concentraties, bedoeld in het eerste lid,alsmede de andere metingen en berekeningen die in dit besluit verplichtzijn gesteld, worden uitgevoerd volgens CEN-normen, dan wel, bij het

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ontbreken daarvan, volgens andere normen die waarborgen dat gegevensvan een gelijkwaardige wetenschappelijke kwaliteit worden verstrekt. Bijregeling van Onze Minister kunnen normen worden aangewezen die inieder geval worden aangemerkt als normen die voldoen aan het bepaaldein de eerste volzin. De eerste volzin vindt geen toepassing voorzoverzodanige normen in strijd zijn met andere bepalingen van dit besluit.Staatsblad 2004 97 173. Het uitvoeren van de periodieke metingen en de parallelmetingengeschiedt door een rechtspersoon die:a. voor deze verrichtingen geaccrediteerd is door een algemeenaanvaarde nationale accreditatie-instelling of een vergelijkbare buitenlandseinstelling die erkend is door een staat, aangesloten bij de MultilateralAgreement on European Accreditation of Certification, ofb. voor deze verrichtingen de CEN-normen inzake de onafhankelijkheiden de competentie van laboratoria aantoonbaar tot uitvoering brengt.4. Een in het tweede of derde lid bedoelde CEN-norm heeft betrekkingop de laatst uitgegeven norm met de daarop uitgegeven aanvullingen encorrectiebladen. Een uitgegeven norm, aanvulling, onderscheidenlijkcorrectieblad, wordt eerst van toepassing één jaar na de datum vanuitgifte.5. Onze Minister doet van de uitgifte van CEN-normen als bedoeld inhet tweede en derde lid alsmede van de uitgifte van aanvullingen encorrectiebladen met betrekking tot zodanige normen zo spoedig mogelijkna de uitgifte daarvan mededeling door kennisgeving in de Staatscourant.

B.4 Measurement Methods NeR F7

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